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Home My WebLink About224-140CAUTION: 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:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: Injector PAVE 3-1 (PTD #2241400) OAP bleed Date:Monday, December 1, 2025 9:02:07 AM Attachments:PAVE3-1.pdf From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Sunday, November 30, 2025 3:56 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; Bo York <byork@hilcorp.com>; PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Subject: Injector PAVE 3-1 (PTD #2241400) OAP bleed Mr. Wallace, Operations recently bled Injector PAVE 3-1 (PTD #2241400) OA pressure. After the bleed, the well was shut-in on 11/29 for a Schmoo-B-Gone pump job. Once the well was back online, the IA & OA pressures did not have the recommended differential. We are going to increase the IA pressure to establish recommended differentials and monitor. If there is any indication the IA and OA are communicating, we will shut-in the well and notify you per the AA. Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity andrew.ogg@hilcorp.com P: (907) 659-5102 M: (307) 399-3816 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. TREE V1E-LHEAD = ACIUAIUN= INITIAL KB. E-EV = BF. AEV = co127' KOP= 480' zo• ND, Max Angle = 65" 0 9621' 135#, L-80 Datum MD = Datum TVD= 8800'SS 13-3/8' CSG, 68#, L-80 BTC, D = 12.415' 4608' Minimum ID = 5.625" @ 11845' 7" HES R NIPPLE 7-5/8' TBG, 29.7#, L-80 JFEBEA R SC90, 11767' .0459 bpf, ID = 6.875' .0383 bpf, ID = 6.276' 9-5/8" CSG, 47#, L-80 BTC, D = 8.681" 13745' PERFORATION SUNWRY REF LOG: _ ON )OWOUXX ANGLEAT TOP PER 44" @ 13899' Note: Refer to Production DB for historical pert data SIZE SPF INTERVAL Opn/Sgz SHOT SOZ 4.625" 5 13899 -13936 0 W29125 4.625" 5 13899 -13943 0 05/29/25 4.625" 5 13943 - 14075 0 05/28/25 4.625" 5 14075 - 14207 0 05I27/25 4.625" 5 14207 - 14339 O 05/26/25 4.625" 5 14339 - 14427 0 05/25/25 4.625" 5 14427 - 14515 0 05I24/25 4.625" 5 14515 - 14559 0 05/23/25 PAVE 3-1 SAFETY NOTES: IPBTD 14628' 7- LNR, 29#, L-80 VAM TOP , 14674' .0371 bpf, ID = 6.184' -O/O A, AU, u=o.lul- 2489' 7- HES R NIP, D = 5.963' 2496' 7' X 75/8- XO, D = 6.551 1767' 1-17-5/8- X 7- XO, D = 6.180• 1778' 7- HES R NIP, D = 5.963- 11806' —j9-5/8- X 7- TNT PKR. ID = 5.900- 11846' 7- HES R NIP, D = 5.625- 1 11892' 1 DATE REV BY COMUNTS DATE REV BY COMVEITS 01/25/25 P-273 INITIAL COMPLETION 02/07/25 JM) UPDATED N/BS PER TALLIES 02/14/25 JLIJMJ RNALIZED 06/02/25 RBIJM) ADPERFS (05/29/25) 06/05/25 JNJJMJ CORISCTEDADPERFS F' X 9-518• SLZXP LTP w/ TIEBACK SLV, D = 6.190• PRIDHOE BAY LINT WELL: PAVE 3-1 PERIWT No 224-140 AR No: 50-029-23806-00 T11 N, R14E, 3419 FSL & 4591' FE- BP Exploration (Alaska) Imo m Imo xwo zm Imo � Imo za IIm mg Imo zmo zmo 2m zmo Va zing zmo m zwo n Z. Im m' H zIW e zmo m Imo 1°0= Iwo M IV &tl IV t� I10 lAm p Im p m t.tm m tmo moMg m m m m mo igg w wo m mg m in Im ama reeves omm remm rezms town VnIn tmvn town tlmtn tl.un »nom Ilnn Iemm no cln +Tubing —On ■ Ehual + opx.m. + Mnog.r ♦ VMx Evel y—Men. IA —� Men. oA Men. COA Men. TWA �— Men.. 7. If perforating: 1. Type of Request: 2. Operator Name: 3. Address: 4. Current Well Class:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Property Designation (Lease Number):10. Field: Abandon Suspend Plug for Redrill Perforate New Pool Perforate Plug Perforations Re-enter Susp Well Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown What Regulation or Conservation Order governs well spacing in thes pool? Will perfs require a spacing exception due to property boundaries?Yes No 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): PRESENT WELL CONDITION SUMMARY Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 12. Attachments: 14. Estimated Date for Commencing Operations: 13. Well Class after proposed work: 15. Well Status after proposed work: 16. Verbal Approval: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal. Proposal Summary Wellbore schematic BOP SketchDetailed Operations Program OIL GAS WINJ WAG GINJ WDSPL GSTOR Op Shutdown Suspended SPLUG Abandoned ServiceDevelopmentStratigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other Conditions of Approval: Post Initial Injection MIT Req'd?Yes No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER PBU PAVE3-1 Acid Liner Wash Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 224-140 50-029-23806-00-00 341J ADL 0028309 14676 Conductor Surface Intermediate Production Liner 8771 70 4461 13700 2782 14628 20" 13-3/8" 9-5/8" 7" 8748 48 - 118 47 - 4508 45 - 13745 11892 - 14674 2470 48 - 118 47 - 3533 45 - 8221 7102 - 8770 None 2260 4760 7020 None 5020 6870 8160 13899 - 14559 7-5/8" 29.7# x 7" 26# L-80 43 - 118968338 - 8715 Structural 7" HES TNT Packer 7" A1 SSSV 11805, 7061 2489, 2343 Date: Bo York Operations Manager Jerry Lau jerry.lau@hilcorp.com 907.564.5280 PRUDHOE BAY 9/5/2025 Current Pools: PRUDHOE OIL Proposed Pools: PRUDHOE OIL Suspension Expiration Date: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 8:39 am, Aug 25, 2025 Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2025.08.25 08:16:29 - 08'00' Bo York (1248) 325-510 WCB 9-5-2025 , ADL 028307, ADL 028306 SFD Increased acid volumes were approved via email on 9-8-2025. **Final pump schedule followed must be submitted in the 10-404 along with the normally reported WSR.** -WCB DSR-8/26/25SFD 8/27/2025 CDW 08/25/2025 9/5/2025 10-404 JLC 9/8/2025 Gregory C Wilson Digitally signed by Gregory C Wilson Date: 2025.09.09 07:06:41 -08'00'09/09/25 RBDMS JSB 090925 PAVE 3-1 Liner Wash PTD:224-140 API: 50-029-23806-00-00 Well Name:PAVE 3-1 Permit to Drill Number 224-140 Estimated Start Date:9/5/25 API Number:50-029-23806-00-00 Regulatory Contact:Abbie Barker 907-777-8400 (O)Abbie.Barker@hilcorp.com Operations Engineer Jerry Lau 907-360-6233 (C)Jerry.Lau@hilcorp.com Second Call Engineer:Dave Bjork (907) 440-0331 (M) Current Bottom Hole Pressure:3,250 psi @ 8,800’ TVD 7.3 PPGE | Max.Expected BHP:3,350 psi @ 8,800’ TVD 7.4 PPGE | Max. Anticipated Surface Pressure:2,470 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:2,350 psi on 7/13/25 Min ID 5.625” R-Nip Max Angle:65° Deg @ 9,621’ Brief Well Summary: PBU PAVE 3-1 is being drilled as a big bore PWI injector. The well is a part of the PAVE (Pressure and Vaporization Enhancement) program to increase rate and reserves at PBU by partially redirecting disposal injection into the Ivishak and partially redirecting waterflood injection into the gas cap. The well was placed on injection in June ’25 and has stabilized at 65,000 bwpd of PWI. Slickline tagged fill 173’ above the bottom perf. Sample analysis results indicate that some rust, scale, and sand from the surface piping network deposited downhole, which is impacting injectivity. The solids are roughly 50% soluble in HCL. We plan to perform a fluff n’ stuff fill clean out to reduce fill across the perfs followed by an HCL liner wash to dissolve acid soluble solids. The pump schedule includes a diesel/solvent pre wash to remove organics followed by two stages of jetting HCL across perfs. Stages will be displaced by PWI injection and/or 1% KCL. Objectives: Perform coiled tubing HCL liner wash Coiled Tubing Procedure: 1. MIRU with well on injection. 2. Work with ops to bring well to minimum injection. They will have a plan to cycle min injection on and off as needed to assist in overflushing acid treatment stages. 3. RIH w/ jetting nozzle BHA 4. Perform flush ‘n stuff FCO across perf interval from 13899’ to 14559’ by jetting 1% KCL. Shut in injection if needed to reach target depth. 5. With injection off, reciprocate across perfs while jetting diesel 6. Park above top perf and place well back on min injection for 30 minutes 7. With injection shut in, reciprocate across perfs while jetting 50 bbls of 15% HCL 8. Allow HCL to soak for 30 minutes. 9. Park above top perf and place well back on min injection for 30 minutes 10. With injection shut in, reciprocate across perfs while jetting 50 bbls of 15% HCL 11. Allow acid to soak for 2 hours while POOH, Ops to place back on min injection. 12. Ops to maintain min injection until well support rigs down hardline and the tree cap is installed. Attachments: 1. Pump Schedule 2. Wellbore Schematic 3. Sundry Change Form Slickline tagged fill 173’ above the bottom perf. Sample analysis results indicate that some rust, scale, and sand from the surface piping network deposited downhole, which is impacting injectivity. PAVE 3-1 Liner Wash PTD:224-140 API: 50-029-23806-00-00 Liner Wash Pump Schedule ťÍČô >īŪĖî IĲĤôèťĖĺĲ ŽĺīŪıô ͐>īŪċċώĲДώťŪċċ ͐҇ώX[iĲ " ͑ĺīŽôĲťώ®ÍŜē "ĖôŜôī iċċ ͔͏ώææī ͒iŽôŘċīŪŜē ®I iĲ ͒͏ώıĖĲ ͓èĖîώ®ÍŜē ͔͐҇ώFī iċċ ͔͏ώææī ĺÍħ iċċ ͒͏ώıĖĲ ͔iŽôŘċīŪŜē ®I iĲ ͒͏ώıĖĲ ͕èĖîώ®ÍŜē ͔͐҇ώFī iċċ ͔͏ώææī ĺÍħ iċċ ͑ώēŘŜ ͖iŽôŘċīŪŜēώϯώôıÍĖĲώĺĲώĖĲĤôèťĖĺĲ ®I iĲ PAVE 3-1 Liner Wash PTD:224-140 API: 50-029-23806-00-00 173 ft = 6.4 bbl fill PAVE 3-1 Liner Wash PTD:224-140 API: 50-029-23806-00-00 Changes to Approved Sundry Procedure Date: Subject: Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change. Step Page Date Procedure Change HNS Prepared By (Initials) HNS Approved By (Initials) AOGCC Written Approval Received (Person and Date) Operations Manager Date Operations Engineer Date 1 From:Boman, Wade C (OGC) Sent:Monday, September 8, 2025 8:43 AM To:Jerry Lau Cc:Wallace, Chris D (OGC); Lau, Jack J (OGC) Subject:RE: PBU PAVE 3-1 (PTD #224-140) Change in pump schedule Jerry, I’ve conferred with Chris Wallace. You’re free to proceed with the intervention using the increased pump volumes you list below. As a COA, I’ll type into the 10-403 that the Ʊnal pump schedule must be submitted on the 10-404 (in addition to the normal WSR), for clarity’s sake. Thanks. -Wade Wade Boman Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave, Anchorage, AK 99501 wade.boman@alaska.gov office: 907-793-1238 cell: 907-687-4468 From: Jerry Lau <jerry.lau@hilcorp.com> Sent: Friday, September 5, 2025 12:10 PM To: Boman, Wade C (OGC) <wade.boman@alaska.gov> Cc: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: PBU PAVE 3-1 (PTD #224-140) Change in pump schedule Hi Wade, Following our discussion regarding the “currently under review” sundry program, I propose increasing the total 15% HCl volume pumped into PAVE3-1 from 100 bbls to 200 bbls. This can be achieved either by doubling the acid stage volume or by increasing the number of stages. We want to utilize the entire acid transport in volume while CT is on the well. Please let me know if you’d like to review the options in more detail or if you have any concerns. Regards, Jerry Lau Hilcorp North Slope – Prudhoe Bay East FS3 Operations Engineer (DS 06,07,13,14,15) Cell: (907) 360-6233 Office: (907) 564-5280 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 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 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. 1 From:Jerry Lau <jerry.lau@hilcorp.com> Sent:Friday, September 5, 2025 12:10 PM To:Boman, Wade C (OGC) Cc:Wallace, Chris D (OGC) Subject:PBU PAVE 3-1 (PTD #224-140) Change in pump schedule Hi Wade, Following our discussion regarding the “currently under review” sundry program, I propose increasing the total 15% HCl volume pumped into PAVE3-1 from 100 bbls to 200 bbls. This can be achieved either by doubling the acid stage volume or by increasing the number of stages. We want to utilize the entire acid transport in volume while CT is on the well. Please let me know if you’d like to review the options in more detail or if you have any concerns. Regards, Jerry Lau Hilcorp North Slope – Prudhoe Bay East FS3 Operations Engineer (DS 06,07,13,14,15) Cell: (907) 360-6233 Office: (907) 564-5280 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. 1 From:Jerry Lau <jerry.lau@hilcorp.com> Sent:Friday, September 5, 2025 11:05 AM To:Boman, Wade C (OGC) Cc:Wallace, Chris D (OGC); Lau, Jack J (OGC); Rixse, Melvin G (OGC) Subject:RE: [EXTERNAL] PBU PAVE 3-1 (PTD #224-140) Wade, The 10” injection line routed PWI from FS3 to PAVE3-1 is ~4500’ in length. More than half of the total length is comprised of a previously out of service SWI injection line. The line was inspected and hydrotested, however, some residual solids and scale were swept from the line and deposited downhole when the well was placed on injection at start up. The line was pigged prior to placing on injection with returns taken back to the facility, however, not all solids were flushed/swept out at that point. With confidence, I believe that the solids issue is a one-time occurrence and did not originate from within the FS3 PWI injection system. FS3 does not have a history of these types of solids within its injection network. The well has been pigged again since startup and all indications suggest that the solids problem has been resolved. Regards, Jerry Lau Hilcorp North Slope – Prudhoe Bay East FS3 Operations Engineer (DS 06,07,13,14,15) Cell: (907) 360-6233 Office: (907) 564-5280 From: Boman, Wade C (OGC) <wade.boman@alaska.gov> Sent: Thursday, September 4, 2025 1:32 PM To: Jerry Lau <jerry.lau@hilcorp.com> Cc: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: [EXTERNAL] PBU PAVE 3-1 Hi, Jerry. With such a new well, what are your thoughts on why so much fill has occurred? 173’ in 7” tubulars seems like a lot, intuitively. You mention rust, scale, and sand from the surface piping network. Are your thoughts that the sand is from the injection water itself? As sand been found in neighboring injectors as well? Are there plans in place to keep this from reoccurring? Feel free to give me a call. Thanks. -Wade 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 Wade Boman Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave, Anchorage, AK 99501 wade.boman@alaska.gov office: 907-793-1238 cell: 907-687-4468 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. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, July 24, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Josh Hunt P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC PAVE 3-1 PRUDHOE BAY UNIT PAVE 3-1 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/24/2025 PAVE 3-1 50-029-23806-00-00 224-140-0 W SPT 7077 2241400 2050 1954 1960 1957 1957 535 645 621 618 INITAL P Josh Hunt 6/21/2025 This is the Initial MIT-IA for this well. Required by AIO 4G.018. To be tested to the maximum anticipated injection pressure. Very solid test. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UNIT PAVE 3-1 Inspection Date: Tubing OA Packer Depth 1439 2700 2685 2684IA 45 Min 60 Min Rel Insp Num: Insp Num:mitJDH250622104101 BBL Pumped:2.4 BBL Returned:2 Thursday, July 24, 2025 Page 1 of 1            MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Monday, July 21, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Sully Sullivan P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC PAVE 3-1 PRUDHOE BAY UNIT PAVE 3-1 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/21/2025 PAVE 3-1 50-029-23806-00-00 224-140-0 N SPT 7077 2241400 3000 1004 1486 1482 1481 95 395 387 385 OTHER P Sully Sullivan 5/4/2025 Pre inj MIT-IA to 3000psi per Sundry 325-269 , MIT-T on related inspection 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UNIT PAVE 3-1 Inspection Date: Tubing OA Packer Depth 472 3160 3142 3139IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSTS250505141904 BBL Pumped:4.2 BBL Returned:4.1 Monday, July 21, 2025 Page 1 of 1           AIO 4G-018 mitSTS250505135616 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Monday, July 21, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Sully Sullivan P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC PAVE 3-1 PRUDHOE BAY UNIT PAVE 3-1 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/21/2025 PAVE 3-1 50-029-23806-00-00 224-140-0 N SPT 7061 2241400 3000 1003 3163 3133 3123 84 144 147 151 OTHER P Sully Sullivan 5/4/2025 Pre inj MIT-T to 3000psi per Sundry 325-269 , MIT-IA on related inspection 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UNIT PAVE 3-1 Inspection Date: Tubing OA Packer Depth 488 993 990 989IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSTS250505135616 BBL Pumped:4.4 BBL Returned:4.5 Monday, July 21, 2025 Page 1 of 1         (mitSTS250505141904) AIO 4G.018   RUSH By Grace Christianson at 4:13 pm, Apr 29, 2025 Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2025.04.29 16:02:35 - 08'00' Bo York (1248) 325-269 A.Dewhurst 01MAY25 DSR-4/29/25 * AOGCC to witness of MIT-IA to 3000 psi before perforating if not witnessed after initial packer setting. * AOGCC witness of MIT-IA to 2500 psi within 10 days of stabilized injection. MGR01MAY25 10-404 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.01 09:57:23 -08'00' 05/01/25 RBDMS JSB 050125 PAVE 3-1 Post Rig 10-403 PTD: 224-140 API: 50-029-23806-00-00 Well Name:PAVE 3-1 Permit to Drill Number 224-140 Estimated Start Date:5/5/25 API Number:50-029-23806-00-00 Regulatory Contact:Joseph Lastufka 907-777-8400 (O) joseph.lastufka@hilcorp.com Operations Engineer Jerry Lau 907-360-6233 (M) Jerry.lau@hilcorp.com Second Call Engineer:Dave Bjork 907 440-0331 (M) Current Bottom Hole Pressure:3,250 psi @ 8,800’ TVD 7.3 PPGE | Max. Expected BHP:3,350 psi @ 8,800’ TVD 7.4 PPGE | Max. Anticipated Surface Pressure:2,470 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:New Drill Min ID 5.625” R-Nip Max Angle:65° Deg @ 9,621’ Brief Well Summary: PBU PAVE 3-1 was drilled as a big bore PWI injector. The well is a part of the PAVE (Pressure and Vaporization Enhancement) program to increase rate and reserves at PBU by partially redirecting disposal injection into the Ivishak and partially redirecting waterflood injection into the gas cap. The well was originally designed to be a slotted liner completion but has been modified to be a cement and perf solid liner completion. The modification was made to provide an additional barrier over the previously leaky stage cementing tool on the 9-5/8” CSG string. We plan on placing the well on injection when surface pipeline tie-in work and hydrotesting is completed in May ’25. Under the original 10-403 post rig procedure, we successfully set the Packer. We plan to carry over the conditions of approval from sundry 325-079. Objectives: 1. Complete post rig scope to pressure test, perforate, and flowback debris. 2. Perform pre-injection integrity and regulatory testing. Detailed Procedure: Fullbore Pumping 1. MIT-IA to 3000 psi with Diesel. Pass to 3000 psi. Max Applied Pressure is 3150 psi.AOGCC Witnessed. 2. MIT-T to 3000 psi with Diesel. Test the entire wellbore that includes the TBG and LNR. Testing prior to perforating allows us to test the CSG and LNR beneath the high-set injection packer without the need for a LNR plug. Pass to 3000 psi. Max Applied Pressure is 3150 psi.AOGCC Witnessed. Slickline Drift for Perf Guns. Max swell is 4.887”. E-line Using 4-5/8” RockJet guns, perforate the following intervals working from the bottom up. The intervals may vary slightly to ensure we use up the entire gun inventory. All perforations will be contained within the Ivishak zones 2, 3 and 4. We do not plan to perforate the Sag. PAVE 3-1 Post Rig 10-403 PTD: 224-140 API: 50-029-23806-00-00 IĲťôŘŽÍī ĺŕ ťı ôŘċώ>ĺĺťÍČô ͐ ͓͔͐͒͏ ͓͕͐͑͑ ͑͘ ͑ ͐͒͗͐͘ ͓͔͔͐͐ ͕͓͑ ĺťÍī ͖͕͐ Well Testers 1. MIRU portable test separator to take returns to production via adjacent well flowline to production. a. The objective is to flowback perf debris. b. Ops engineer will evaluate gas rates and fluid returns to ensure wellbore is cleaned up. We are anticipating 12-48 hrs of flowback time. Slickline Set A1 injection valve in SVLN. DHD Perform AOGCC Witnessed MIT-IA to 2500 psi within 10 days of stabilized injection. Attachments: 1. Wellbore Schematic 2. Proposed Wellbore Schematic 3. Sundry Change Form PAVE 3-1 Post Rig 10-403 PTD: 224-140 API: 50-029-23806-00-00 Current Wellbore Schematic PAVE 3-1 Post Rig 10-403 PTD: 224-140 API: 50-029-23806-00-00 Proposed Wellbore Schematic PAVE 3-1 Post Rig 10-403 PTD: 224-140 API: 50-029-23806-00-00 Changes to Approved Sundry Procedure Date: Subject: Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change. Step Page Date Procedure Change HAK Prepared By (Initials) HAK Approve d By (Initials) AOGCC Written Approval Received (Person and Date) Operations Manager Date Operations Engineer Date Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 2/20/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250220 Well API #PTD #Log Date Log Company Log Type AOGCC ESet # BCU 18RD 50133205840100 222033 1/27/2025 AK E-LINE Patch BRU 223-24 50283201830000 221072 1/26/2025 AK E-LINE Perf CLU 10RD 50133205530100 222113 11/2/2024 YELLOWJACKET PLUG GP 03-87 50733204370000 166052 12/16/2024 AK E-LINE Plug/Cement IRU 44-36 50283200890000 193022 1/22/2025 AK E-LINE Perf KU WD-01 50133203450000 181107 10/15/2024 YELLOWJACKET PERF MPI 1-29 50029216690000 186181 1/29/2025 AK E-LINE Perf MPU C-39 50029228490000 197248 1/27/2025 AK E-LINE TubingCut MPU E-20A 50029225610100 204054 2/1/2025 READ CaliperSurvey MPU K-33 50029227290000 196202 2/8/2025 AK E-LINE TubeCut MPU S-08 50029231680000 203123 2/6/2025 AK E-LINE CmtRtr/Punch MRU A-13 50733200770000 168002 2/6/2025 AK E-LINE TubingPunch MRU M-02 50733203890000 187061 1/22/2025 AK E-LINE Perf MRU M-32RD2 50733204620200 217091 2/10/2025 AK E-LINE TubingPunch NCIU A-09 50883200290100 222024 1/31/2025 AK E-LINE Perf NCIU A-16 50883201270000 208098 1/30/2025 AK E-LINE Perf NCIU A-21 50883201990000 224086 1/15/2025 AK E-LINE Plug, Perf NK-41A 50029227780100 197158 1/6/2025 HALLIBURTON Coilflag PAVE 3-1 50029238060000 224140 1/4/2025 YELLOWJACKET CBL PBU P1-13 50029223720000 193074 12/3/2024 HALLIBURTON PPROF PTM P1-07A 50029219960100 204037 12/31/2024 YELLOWJACKET PPROF Please include current contact information if different from above. T40127 T40128 T40129 T40130 T40131 T40132 T40133 T40134 T40135 T40136 T40137 T40138 T40139 T40140 T40141 T40142 T40143 T40144 T40145 T40146 T40147 PAVE 3-1 50029238060000 224140 1/4/2025 YELLOWJACKET CBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.20 14:09:18 -09'00' By Grace Christianson at 11:06 am, Feb 14, 2025 Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2025.01.15 11:44:59 - 09'00' Bo York (1248) 325-079 DSR-2/14/25 RUSH 10-404 - AOGCC to witness MIT-IA to 3000 psi. AOGCC to witness MIT-T to 3000 psi. - AOGCC to witness MIT - T to 2500 psi when 7" retrievable bridge plug set in 7" casing to 2500 psi - AOGCC to witness MIT-IA to 2500 psi after 10 days of stabilized injection. SFD 2/14/2025MGR14FEB24*&: 2/18/2025 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.18 08:06:15 -09'00' RBDMS JSB 021825 _____________________________________________________________________________________ Created By: JJL 1/13/2025 PROPOSED SCHEMATIC Prudhoe Bay Unit Well: PAVE 3-1 Last Completed: TBD PTD: 224-140 GENERAL WELL INFO API: 50-029-23806-00-00 Completed: TBD PERFORATION DETAIL Top (MD) Btm (MD) Top (TVD) Btm (TVD) CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 118’ N/A 13-3/8” Surface 68 / L-80 / BTC 12.415” Surface 4,508’ 0.1497 9-5/8” Intermediate 47 / L-80 / BTC 8.681” Surface 13,745’ 0.0758 7” Solid Liner 26 / L-80 / VamTop 6.276” ~11,900’ ~14,657’ 0.0383 TUBING DETAIL 7" Tubing 26 / L-80 / VamTop 6.276” Surface ~117’ 0.0383 7-5/8” Tubing 29.7 / L-80 / JFE Bear 6.875” ~117’ ~2,500’ 0.0459 7" Tubing 26 / L-80 / VamTop 6.276” ~2,500’ ~2,545’ 0.0383 7-5/8” Tubing 29.7 / L-80 / JFE Bear 6.875” ~2,545’ ~11,779’ 0.0459 7" Tubing 26 / L-80 / VamTop 6.276” ~11,779’ 11,904’ 0.0383 TD =14,657’(MD) / TD =8,747’(TVD) 13-3/8” KB Elev: = 73.99’ / GL Elev: = 27.0’ 2 5 6 4 1 HES Stg Tool @12224’ 9-5/8” 7” PBTD =14,577’(MD) / PBTD =8,708’(TVD) 3 7-5/8” OPEN HOLE / CEMENT DETAIL 42” 17 yds Concrete 16” Lead – 2104 sx / Tail – 599 sx 12-1/4” Stg 1 – Tail 631 sx Class G Stg 2 – Lead Not Pumped Squeeze #1 – 267 sx Class G Squeeze #2 - 267 sx Class G 8-1/2” Tail – 400 sxs JEWELRY DETAIL No Depth ID Item 1 ~11,900’ Liner Hanger/LTP 2 ~11,904’ 6.276” WLEG 3 ~11,845’ 5.625” R-Nipple 4 ~11,810’ 5.900” Packer 5 ~11,779’ 5.963” R-Nipple 6 ~2,500’ 5.963” R-Nipple for check valve WELL INCLINATION DETAIL KOP @ 480’ Max Angle 65 deg @ 9,621’ TREE & WELLHEAD Tree Wellhead We plan to perforate all pay within the Ivishak reservoir (inbetween TSAD and BSAD). PAVE 3-1 Post Rig 10-403 PTD: 224-140 API: 50-029-23806-00-00 Well Name:PAVE 3-1 Permit to Drill Number 224-140 Estimated Start Date:1/25/25 API Number:50-029-23806-00-00 Regulatory Contact:Joseph Lastufka 907-777-8400 (O) joseph.lastufka@hilcorp.com Operations Engineer Jerry Lau 907-360-6233 (C) Jerry.lau@hilcorp.com Second Call Engineer:Dave Bjork (907) 440-0331 (M) Current Bottom Hole Pressure:3,250 psi @ 8,800’ TVD 7.3 PPGE | Max. Expected BHP:3,350 psi @ 8,800’ TVD 7.4 PPGE | Max. Anticipated Surface Pressure:2,457 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:New Drill Min ID 5.625” R-Nip Max Angle:65° Deg @ 9,621’ Brief Well Summary: PBU PAVE 3-1 is being drilled as a big bore PWI injector. The well is a part of the PAVE (Pressure and Vaporization Enhancement) program to increase rate and reserves at PBU by partially redirecting disposal injection into the Ivishak and partially redirecting waterflood injection into the gas cap. The well was originally designed to be a slotted liner completion but has been modified to be a cement and perf solid liner completion. The modification was made to provide an additional barrier over the previously leaky stage cementing tool on the 9-5/8” CSG string. Hilcorp would like to use the state approval process of this sundry to document the plan forward for testing requirements of this well. We do not plan on placing the well on injection until surface pipeline tie-in work and hydrotesting is completed in May ’25. Objectives: 1. Perform post rig scope to set packer, perforate, and pump mud acid 2. Perform pre-injection integrity and regulatory testing. Detailed Procedure: 1. Valve Shop a. Install injection Tree b. Pull BPV 2. Slickline a. PT to 4000 psi b. Set 6-5/8" PR Plug in 5.625" R nipple below the packer. c. Set 7" x 9-5/8" TNT PKR per HES rep. Max Pressure is 4000 psi.AOGCC Witnessed d. MIT-T to 3000 psi AOGCC Witnessed e. MIT-IA to 3000 psi AOGCC Witnessed f. Pull 6-5/8” PR Plug from 5.625” R nipple. 3. E-line a. Set 7” retrievable bridge plug in 7” CSG at 13,745’ MD +/- 25’. b. MIT-T to 2500 psi.AOGCC Witnessed. This pressure test envelope includes the barrier between top of the Prudhoe Oil Pool and packer to prevent misinjection above the pool. This test is required prior to initial injection and will be required every two years (biennially). c. Pull 7” retrievable bridge. PAVE 3-1 Post Rig 10-403 PTD: 224-140 API: 50-029-23806-00-00 4. E-line a. Perforate intervals of high permeability formation within the Ivishak using 3-1/8” guns or larger. Geo to pick final intervals after reviewing logs post drill. 5. Fullbore Pumping a. Pump Mud Acid stimulation using Hilcorp best practices to remove formation damage from drilling. Target intervals will be contained within Ivishak interval of production hole. Tentative pump schedule and fluid recipes in attachments. Final volumes will be based on the perforated footage from step 4. The sag will not be perforated or acidized. i. RU to tree cap ii. PT to 4000 psi iii. Ensure OE is on the slope or available on the phone for job iv. Pressure up IA to 500 psi and monitor throughout job v. Fluid pack wellbore with NH4Cl. Max treating pressure is 2800 psi until NH4CL hits perfs, then reduce max treating pressure to 1500 psi. vi. Pump Acid schedule. Max rate is 9 bpm. Max treating pressure is 1500 psi throughout job to ensure the treatment is a matrix stimulation and fracture gradient is not exceeded. vii. If well were to lockup, do not exceed 4000 psi for wellbore integrity purposes. 6. E-line a. Perforate the remainder of pay within the Ivishak using 3-1/8” guns or larger. Geo to pick final intervals after reviewing logs post drill. 7. Slickline a. Set A1 injection valve in SVLN 8. DHD a. Perform AOGCC Witnessed MIT-IA to 2500 psi within 10 days of stabilized injection. Attachments: 1. Proposed Wellbore Schematic 2. Tentative Mud Acid Pump Schedule and Fluid Recipes 3. Sundry Change Form PAVE 3-1 Post Rig 10-403 PTD: 224-140 API: 50-029-23806-00-00 Tentative Mud Acid Pump Schedule Final volumes to be determined based on the perforated footage Fluid Recipes PAVE 3-1 Post Rig 10-403 PTD: 224-140 API: 50-029-23806-00-00 Changes to Approved Sundry Procedure Date: Subject: Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change. Step Page Date Procedure Change HAK Prepared By (Initials) HAK Approve d By (Initials) AOGCC Written Approval Received (Person and Date) Operations Manager Date Operations Engineer Date 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: 02/11/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: Well: PBU PAVE3-1 PTD: 224-140 API: 50-029-23806-00-00 FINAL LWD FORMATION EVALUATION LOGS (12/01/2024 to 01/18/2025) x ABG & BaseStar Gamma Ray, ResiStar and StrataStar Resistivity, LithoStar Density & Porosity (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey SFTP Transfer – Main Folders: Please include current contact information if different from above. 224-140 T40073 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.12 07:58:34 -09'00' Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.01.14 13:29:54 - 09'00' Sean McLaughlin (4311) By Grace Christianson at 2:24 pm, Jan 14, 2025 325-014 Increased monitoring and 2 yr MITT will require an administrative approval prior to injection. DSR-1/16/25 10-407 MGR14JAN25 * BOPE test to 3500 psi. Annular to 2500 psi. * 24 hour notice to AOGCC for opportunity to witness initial MIT-IA post packer set. * MIT-IA to be witnessd by AOGCC to 2500 psi after 10 days of stabilized injection. CDW 01/14/2025 SFD 1/17/2025*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.01.17 11:43:39 -09'00'01/17/25 RBDMS JSB 012425 _____________________________________________________________________________________ Created By: JJL 1/13/2025 PROPOSED SCHEMATIC Prudhoe Bay Unit Well: PAVE 3-1 Last Completed: TBD PTD: 224-140 GENERAL WELL INFO API: 50-029-23806-00-00 Completed: TBD PERFORATION DETAIL Top (MD) Btm (MD) Top (TVD) Btm (TVD) CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 118’ N/A 13-3/8” Surface 68 / L-80 / BTC 12.415” Surface 4,508’ 0.1497 9-5/8” Intermediate 47 / L-80 / BTC 8.681” Surface 13,745’ 0.0758 7” Solid Liner 26 / L-80 / VamTop 6.276” ~11,900’ ~14,657’ 0.0383 TUBING DETAIL 7" Tubing 26 / L-80 / VamTop 6.276” Surface ~117’ 0.0383 7-5/8” Tubing 29.7 / L-80 / JFE Bear 6.875” ~117’ ~2,500’ 0.0459 7" Tubing 26 / L-80 / VamTop 6.276” ~2,500’ ~2,545’ 0.0383 7-5/8” Tubing 29.7 / L-80 / JFE Bear 6.875” ~2,545’ ~11,779’ 0.0459 7" Tubing 26 / L-80 / VamTop 6.276” ~11,779’ 11,904’ 0.0383 TD =14,657’(MD) / TD =8,747’(TVD) 13-3/8” KB Elev: = 73.99’ / GL Elev: = 27.0’ 2 5 6 4 1 HES Stg Tool @12224’ 9-5/8” 7” PBTD =14,577’(MD) / PBTD =8,708’(TVD) 3 7-5/8” OPEN HOLE / CEMENT DETAIL 42” 17 yds Concrete 16” Lead – 2104 sx / Tail – 599 sx 12-1/4” Stg 1 – Tail 631 sx Class G Stg 2 – Lead Not Pumped Squeeze #1 – 267 sx Class G Squeeze #2 - 267 sx Class G 8-1/2” Tail – 400 sxs JEWELRY DETAIL No Depth ID Item 1 ~11,900’ Liner Hanger/LTP 2 ~11,904’ 6.276” WLEG 3 ~11,845’ 5.625” R-Nipple 4 ~11,810’ 5.900” Packer 5 ~11,779’ 5.963” R-Nipple 6 ~2,500’ 5.963” R-Nipple for check valve WELL INCLINATION DETAIL KOP @ 480’ Max Angle 65 deg @ 9,621’ TREE & WELLHEAD Tree Wellhead Page 8 Prudhoe Bay East PAVE 3-1 Ivishak Injector 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. BOPs shall be tested at (2) week intervals during the drilling and completion of PBU PAVE 3-1. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. The initial and subsequent tests of BOP equipment will be to 250/3,500 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. 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 14 day BOP test. All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. 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 Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. 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 9 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure AOGCC Regulation Variance Requests: 1)20 AAC 253412 (b):“A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured depth above the top of the perforations, unless the commission approves a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone.” A variance is requested to set the completion packer > 200’ from the top-most planned perforated interval. Due to the 7” cemented injection liner overlapping of the 9-5/8” stage tool at ~12,224’ MD, the tubing packer is proposed to be set at ~ 11,800’ MD. A pressure test will be performed to test the integrity of the annulus space between the tubing packer and 7” liner top. This test will be performed before injection and, subsequently, every 2 years as a MIT-T to 2,500psi with a plug set in the 7” liner, above the perforations. Summary of Parker 273 BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 16”21-1/4” 2M Annular BOP w/ 16” diverter line Function Test Only 12-1/4” 13-5/8” x 5M Annular BOP 13-5/8” x Double Gate o Blind ram in btm cavity Mud cross w/ 3-1/8” x 5M side outlets 13-5/8” x Single ram 3” x 5M Choke Line 2” x 5M Kill line 3” x 5M Choke manifold Standpipe, floor valves, etc Initial Test: 250/3,500 Annular: 250/2,500 Subsequent Tests: 250/3,500 Annular 250/2,500 8-1/2” 13-5/8” x 5M Annular BOP 13-5/8” x Double Gate o Blind ram in btm cavity Mud cross w/ 3-1/8” x 5M side outlets 13-5/8” x Single ram 3” x 5M Choke Line 2” x 5M Kill line 3” x 5M Choke manifold 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. 20 AAC 25.412 (b) High set packer with increased testing variance is approved. An administrative approval to the AIO will need to be requested prior to injection. CDW 01/14/2025 Page 10 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure Required AOGCC Notifications: Well control event (BOPs utilized to shut in the well to control influx of formation fluids). 24 hours notice prior to spud. 24 hours notice prior to testing BOPs. 24 hours notice prior to casing running & cement operations. 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 42 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 19.0 Run 7” Injection Liner 19.1 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: With 7” joint across BOP: P/U & M/U the 5” safety joint (with 7” crossover installed on bottom, TIW valve in open position on top, 7” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 7” liner. Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW. Proceed with well kill operations. 19.2 R/U 7” liner running equipment. Ensure 7” 26# VT x XT50 crossovers are on rig floor and M/U to FOSVs. Ensure all casing has been drifted on the deck prior to running. Be sure to count the total # of joints on the deck before running. Keep hole covered while R/U casing tools. Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 19.3 Run 7” injection liner Use Vam approved thread compound. Dope pin end only w/ paint brush. Wipe off excess. Utilize a collar clamp until weight is sufficient to keep slips set properly. Use lift nubbins and stabbing guides for the liner run. See data sheet on the next page for MU torque for the 7” liner connections. Centralization: 1 centralizer every joint on all 7” slotted liner 19.4 Run 7” slotted injection liner as follows: 7” Float Shoe 1 joint – 7”, 2 Centralizers 10’ from each end w/ stop rings 7” Float Collar 1 joint – 7”, 1 Centralizer free floating 7” landing collar for liner wiper plug 1 joint – 7”, 1 Centralizer mid joint w/ stop ring 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 43 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure Page 44 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 19.5 Ensure hanger/pkr will not be set in a 9-5/8” connection. 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 at ~11,900’ MD. This will place the liner hanger above the 9-5/8” stage tool and ensure the liner hanger and the tubing packer are set where there is logged cement in the 9-5/8” annulus. Do not place liner hanger/packer across 9-5/8” connection. 19.6 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. 19.8 M/U Baker SLZXP liner top packer to 7” liner. Circulate 2 liner volumes to clear string and allow for PAL mix to set 19.9 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. 19.10 RIH with liner no faster than 30 ft/min – Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. Ensure 5” DP has been drifted Fill drill pipe on the fly. Monitor FL and if filling is required due to losses/surging. 19.11 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. 19.12 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. 19.13 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. 19.14 Break circulation. Begin circulating at ~0.5 – 1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating for risk of prematurely setting liner hanger. Note all losses. Confirm all pressures with Baker. Page 45 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 20.0 Cement 7” Injection Liner 20.1 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. How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. Positions and expectations of personnel involved with the cementing operation. Extra hands in the pits to strap during the cement job to identify any losses Review test reports and ensure pump times are acceptable. Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 20.2 Document efficiency of all possible displacement pumps prior to cement job. 20.3 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. 20.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom drillpipe darts to ensure done in correct order. 20.5 Fill surface cement lines with water and pressure test. 20.6 Pump remaining spacer. Drop bottom dart. This is a multi-plug job with liner wiper plugs ahead and behind the cement. 20.7 Cement volume based on annular volume + 40% open hole excess. Job will consist of tail slurry, TOC brought to top of liner. Estimated Total Cement Volume: Page 46 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure Cement Slurry Design: 20.8 Wash up lines back to the cement unit. This will help reduce risk of cement stringers in the liner. Drop upper drillpipe dart and displace with perf pill before swapping to 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. 20.9 Displace cement at max rate of 7 bbl/min. Reduce pump rate to 2-3 bpm prior to latching DP darts into bottom and top liner wiper plugs. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point. 20.10 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. 20.11 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 HRDE release pressure). Hold pressure for 3-5 minutes. 20.12 Slack off 20K lbs on the SLZXP liner hanger/packer to ensure the HRDE running 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. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 20.13 Bleed DP pressure to 0 psi and check floats. Pick up to expose rotating dog sub without pulling out of sleeve packoff and set down 50K. Pick back up without pulling out of sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 20.14 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). Tail Slurry Density 15.3 lb/gal Yield 1.24 ft3/sk Mix Water 5.56 gal/sk Page 47 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 20.15 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. 20.16 Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 20.17 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. 20.18 Change upper rams from 7” fixed to 2-7/8” x 5” VBRs and test with 2-7/8” and 5” test joints. If not completed in the previous BOP test, test the lower VBRs with 2-7/8” and 5” test joints. 20.19 Pressure test casing and liner to 250 psi low / 3,000 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. Page 48 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 21.0 Run Upper Completion/ Post Rig Work 21.1 Well control preparedness: In the event of an influx of formation fluids while running the upper completion, the following well control response procedure will be followed: With 7” tailpipe joint across BOP: P/U & M/U the 5” safety joint (with 7” crossover installed on bottom, TIW valve in open position on top, 7” handling pup above TIW). This joint shall be fully M/U and available prior to running the first joint of 7” tailpipe. With 7-5/8” joint across BOP: P/U & M/U the 5” safety joint (with 7-5/8” crossover installed on bottom, TIW valve in open position on top, 7-5/8” handling pup above TIW). This joint shall be fully M/U and available prior to running the first joint of 7-5/8” tubing. Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW. Proceed with well kill operations. 21.2 RU to run 7” 26#, L-80 Vam Top x 7-5/8”, 29.7#, L-80 JFE Bear tubing. Ensure wear bushing is pulled. Ensure 5”, L-80, 29.7#, JFE Bear x XT50 crossover is on rig floor and M/U to FOSV. Ensure all tubing has been drifted in the pipe shed prior to running. Be sure to count the total # of joints in the pipe shed before running. Keep hole covered while RU casing tools. Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info. Monitor displacement from wellbore while RIH. 21.3 PU, MU and RH with the following 7” completion jewelry (tally to be provided by Operations Engineer): Torque Turn All Connections Tubing Jewelry to include (top to bottom): 1x ‘R’ Nipple 1x ‘R’ Nipple 1x Production Packer 1x ‘R’ Nipple 1x WLEG All tubing jewelry assemblies and tubing tail are 7”, 26#, L-80, VamTop and crossed over to the 7-5/8” tubing Tubing is 7-5/8”, 29.7#, L-80, JFE Bear Page 49 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 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 7-5/8” 29.7/# L-80 JFE Bear – Make up Torque Casing OD Minimum Optimum Maximum 7-5/8” 7,470 ft-lbs 8,300 ft-lbs 9,130 ft-lbs Page 50 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure Page 51 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure Page 52 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 21.4 PU and MU the 7” tubing hanger. 21.5 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 21.6 Land the tubing hanger and RILDS. 21.7 Circulate well over to completion brine. Do not exceed 4 bpm when circulating. 21.8 Lay down the landing joint. Install 6” CIW Type J TWC. ND BOP. 21.9 NU the tubing head adapter and NU the tree. 21.10 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 21.11 Pull TWC. Line up to the IA and reverse circulate 165 bbls diesel freeze protect. Hook up jumper line to the tree and allow freeze protect to u-tube. Volume to freeze protect down to 2,500’ MD. 21.12 Set BPV in wellhead in preparation for RDMO. 21.13 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 21.14 RDMO Parker 273 i. POST RIG WELL WORK (sundry to follow) 1. Slickline/Fullbore a. Pull BPV. b. Set plug in tubing tail and set production packer. c. Test Tubing to 250 psi low for 5 min, 3,000 psi high for 30 min d. Test IA to 250 psi low for 5 min, 3,000 psi high for 30 min e. Pull plug from tubing tail. From:Rixse, Melvin G (OGC) To:Frank Roach Cc:Joseph Lastufka; Lau, Jack J (OGC) Subject:20250104 1058 APPROVAL CBL PAVE 3-1 Intermediate Cement Job and Forward Plan (PTD 221-140) Date:Saturday, January 4, 2025 10:54:15 AM Frank, Cement bond shows adequate cement for injection. AOGCC approves the plan forward below. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Joe Lastufka, Jack Lau From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Saturday, January 4, 2025 8:27 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: RE: [EXTERNAL] RE: PAVE 3-1 Intermediate Cement Job and Forward Plan (PTD 221-140) Mel, Please see the attached CBL from this morning. Since yesterday’s update: Drilled out stage tool and RIH to the baffle plate (top of shoetrack). Plugs on depth Circulated & conditioned mud Attempted a pressure test at the shoetrack (unsuccessful) POOH & LD cleanout assembly RU and ran CBL from 13,600’ up to TOC CBL shows cement from 13,600’ up. There are a couple spots of poor coverage, but there’s good cement over the following intervals (from bottom to top): 13,600’ – 12,750’ (850’ MD, ~595’ TVD) CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 12,510’ – 12,150’ (360’ MD, ~174’ TVD) 12,020’ – 11,600’ (420’ MD, ~200’ TVD) Overall, we have greater than 250’ TVD coverage of cement. Plan Forward: MU test packer. RIH to ~13,600’. Set packer and test from above to 4,000psi for 30 charted minutes. Release packer. POOH & LD test packer BHA. MU 8-1/2” Drilling BHA. Now back on plan. 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 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Friday, January 3, 2025 09:08 To: Frank Roach <Frank.Roach@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: RE: [EXTERNAL] RE: PAVE 3-1 Intermediate Cement Job and Forward Plan (PTD 221-140) Frank, Thanks. Will review CBL tomorrow. I am in town. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. cc. Joe, Jack From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Friday, January 3, 2025 9:06 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: RE: [EXTERNAL] RE: PAVE 3-1 Intermediate Cement Job and Forward Plan (PTD 221-140) Mel, Appreciate the heads-up. I’m not expecting the CBL to be run until early tomorrow (Saturday) morning and hoping to have results before noon. Quick recap and status of the rig from yesterday: Ran in with our cleanout BHA. Tagged cancellation plug on the stage tool right at the 6:00a report time. Stacked out string weight and saw a response in hookload, indicating the sleeve had shifted closed. Performed an assurance test to 2,000psi to confirm stage tool is closed (good). Currently drilling up the cancellation tool and stage tool sleeve. Plan forward: Finish drill out of the stage tool. RIH and tag plugs. Circ and condition mud POOH & LD BHA RU & Run CBL to determine stage 1 cement location. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Friday, January 3, 2025 08:26 To: Frank Roach <Frank.Roach@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: [EXTERNAL] RE: PAVE 3-1 Intermediate Cement Job and Forward Plan (PTD 221-140) 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. Frank, I am looking for an update, as I am working away from the office today so am in and out. When do you think you will have the CBL for review? I have my cell phone so you should be able to get in touch with me, but I want to be sure we are not holding you up. Please copy Jack Lau on our correspondence too. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Wednesday, January 1, 2025 2:48 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: PAVE 3-1 Intermediate Cement Job and Forward Plan (PTD 221-140) Mel, We just finished the stage 1 cement job on PAVE 3-1. The displacement/shut-off plug did not bump. Indications are we are pumping past the displacement/shut-off plug. Stage 1 cement volume does provide >250’ TVD coverage above the reservoir for isolation requirements. As such, we do not want to jeopardize this first stage cement job for reservoir isolation. High-level plan forward is the following: Perform BOPE Test RIH with cancellation plug to shift inner sleeve of the stage tool shut. This will prevent unplanned functioning and potential leak path through the stage tool. Drill out stage tool and tag stage 1 plugs above baffle plate/shoetrack Run cement evaluation log on stage 1 cement to determine if coverage is adequate or if remedial work is required. We’ll update as we get more information. 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 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, 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. 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 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. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PRUDHOE BAY UNIT PAVE 3-1 JBR 01/30/2025 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:2 5" test joint used for testing. The H2s detector on the rig floor failed. It was replaced and tested good. The blinds failed and were actuated and retested for a pass. Test Results TEST DATA Rig Rep:John King/Kaleo EnfielOperator:Hilcorp North Slope, LLC Operator Rep:S. Barber/S. Carter Rig Owner/Rig No.:Parker 273 PTD#:2241400 DATE:12/8/2024 Type Operation:DRILL Annular: 250/3500Type Test:INIT Valves: 250/3500 Rams: 250/3500 Test Pressures:Inspection No:bopGDC241207055425 Inspector Guy Cook Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 5 MASP: 2457 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 P Lower Kelly 1 P Ball Type 2 P Inside BOP 1 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13 5/8" 5000 P #1 Rams 1 2 7/8"x5" VB P #2 Rams 1 Blinds FP #3 Rams 1 2 7/8"x5" VB P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8"5000 P HCR Valves 2 3 1/8"5000 P Kill Line Valves 2 2 1/16",3 1/8"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P2000 200 PSI Attained P16 Full Pressure Attained P62 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P14@2350 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P FPH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P28 #1 Rams P7 #2 Rams P7 #3 Rams P6 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P2 9999 9 9 9 9 9 9 9 9 FPH2S Gas Detector #2 Rams Blinds FP H2s detector on the rig floor failed blinds failed 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, Prudhoe Oil Pool, PBU PAVE 3-1 Hilcorp Alaska, LLC Permit to Drill Number: 224-140 Surface Location: 3419' FSL, 4591' FEL, Sec 34, T11N, R14E, UM, AK Bottomhole Location: 2593' FNL, 126' FWL, Sec 23, T11N, R14E, 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, Jessie L. Chmielowski Commissioner DATED this 21st day of November 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.11.21 10:34:42 -08'00' By Grace Christianson at 9:06 am, Nov 07, 2024 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2024.11.06 16:35:31 - 09'00' Sean McLaughlin (4311) * Bi-weekly BOPE pressure test to 3500 psi. Annular to 2500 psi. * MIT-IA to be witnessed by AOGCC to 2500 psi within 10 days of stabilized injection. * Variance to 20 AAC 25.412 (b) may be approved for packer placement @ ~13,500 MD after review of 12-1/4" OH LWD logs by AOGCC staff to assure packer will be placed within upper confining zones of the PB oil pool. * CBL log to AOGCC upon completion. * Post rig MIT-IA to 4000 psi, 24 hour notice for AOGCC to witness. MGR20NOV2024 50-029-23806-00-00 A.Dewhurst 13NOV24 DSR-11/20/24 224-140 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.11.21 10:34:59 -08'00' 11/21/24 11/21/24 RBDMS JSB 112524 «(ϙ͒ϱ͐ϙi•īīϙſôīīŜϙťēÍťϙŕôĲôťŘÍťôϙťēôϙĺŕϙÍČϙϼŘŪîēĺôϙÍƅϙiĖīϙĺĺīϽϙŜēĺſĲϙſĖťēϙŕĖĲħϙ@ϙıÍŘħôŘϟ•@ŘôôĲϙſôīīϙŕÍťēŜϙŘôŕŘôŜôĲťϙÍèťĖŽôϙſôīīæĺŘôŜϟ•@ŘôƅϙſôīīϙŕÍťēŜϙŘôŕŘôŜôĲťϙĖĲÍèťĖŽôϙſôīīæĺŘôŜϟ•͐ϯ͓ϱıĖīôϙŘÍîĖŪŜϙÍŘĺŪĲîϙ«(ϙ͒ϱ͐ϙſôīīæĺŘôϙċŘĺıϙ@ϙťĺϙ"ϟ«(ϙ͒ϱ͐ϙ@ήϱıĖīôϙŘÍîĖŪŜ Well Name PTD API StatusTop of Oil Pool(TSGR, MD)Top of Oil Pool(TSGR, TVD)Top of Cmt (MD) Top of Cmt (TVD)ZonalIsolationCommentsPBU 15-10PBU 15-10A1800881800855002920501000050029205010100LTSI Producer(Secured)9,223 8,203 7,651 6,676 YesThe 15-10 parent bore reservoir is P&A'd.The current bore, 15-10A, is secured witha tubing tail plug due to IAxOA comm. The9-5/8" CSG is confining for 15-10/15-10A.No issues reported with cementoperation. 103 bbls of 15.8 PPG Class GCMT were pumped. A CBL was performedon 15-10A to evaluate the production LNRcement job, but does not provide detailon 9-5/8" TOC.PBU 15-11PBU 15-11A1811321982485002920653000050029206530100P&A'd 10,314 8,222 9,539 7,725 YesThe 15-11 parent bore reservoir is P&A'd.The 9-5/8" CSG primary cement isconfining for 15-11/15-11A. 51.5 bbls15.8 ppg class G. No issues reported withcement operation.PBU 15-11BPBU 15-11CPBU 15-11CPB1204146210163210163500292065302005002920653030050029206537000OperableProducer10,391 8,236 9,463 7,674 Yes15-11B 7" CSG primary cement isconfining for 15-11B/15-11C/15-11CPB1.7" CSG was cemented without issues. 43bbls of 15.8 ppg class G were pumpedwith 5 bbls of cement returns above topof 7" CSG. TOC picked as top as base of 7"window out of 9-5/8" CSG.PBU 15-25PBU 15-25APBU 15-25APB1PBU 15-25B18808019908619908620802450029218420000500292184201005002921842700050029218420200OperableProducer8,827 8,222 6,321 6,120 Yes15-25 7-5/8" CSG primary cement isconfining for 15-25/15-25A/15-25APB1. 7-5/8" CSG was cemented without issues.130 bbls of 15.8 ppg class G werepumped. Two CBLs were perfomed on 15-25 to evaluate the production LNRcement job, but does not provide detailon 9-5/8" TOC. A CBL was performed on15-25A to evaluate the 15-25A CTD LNRlap, but does not provide detail on 9-5/8"TOC. A CBL was performed on 15-25B CTDLNR, but does not provide detail on 9-5/8" TOC.PBU 15-31PBU 15-31APBU 15-31B192087202102205086500292228500005002922285010050029222850200OperableProducer8,872 8,278 3,670 3,669 Yes15-31 9-5/8" CSG primary cement isconfining for 15-31/15-31A/15-31B. 9-5/8" CSG was cemented without issues.383 bbls of 15.8 ppg class G werepumped. Extra volume was pumped sincethere were some losses on the 12.25"hole, however,no losses were reportedduring the cement job.Area of Review PBU PAVE 3-1Note: Wells are grouped together in the same row when sharing the same confining cement isolation. For the case of 15-11B, another row was created since the 15-11/15-11A wellbores had a differentpenetration through top of Prudhoe Oil Pool than the 15-11B rig sidetrack. For all other cases, wells in a row share the same penetration through the top of the Prudhoe Oil Pool. Prudhoe Bay East (PBU) PAVE 3-1 Drilling Program Version 0 11/01/2024 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 ............................................................................................... 7 8.0 Mandatory Regulatory Compliance / Notifications ................................................................. 8 9.0 R/U and Preparatory Work .................................................................................................... 11 10.0 N/U 21-1/4” 2M Diverter System ............................................................................................ 12 11.0 Drill 16” Hole Section ............................................................................................................. 14 12.0 Run 13-3/8” Surface Casing ................................................................................................... 17 13.0 Cement 13-3/8” Surface Casing .............................................................................................. 20 14.0 ND Diverter, NU BOPE, & Test ............................................................................................. 23 15.0 Drill 12-1/4” Intermediate Hole Section ................................................................................. 24 16.0 Run 9-5/8” Intermediate Casing ............................................................................................. 29 17.0 Cement 9-5/8” Intermediate Casing ....................................................................................... 34 18.0 Drill 8-1/2” Production Hole Section ...................................................................................... 38 19.0 Run 7” x 6-5/8” Injection Liner .............................................................................................. 42 20.0 Run Upper Completion/ Post Rig Work ................................................................................ 48 21.0 Parker 273 Rig Diverter Schematic ........................................................................................ 53 22.0 Parker 273 Rig BOP Schematic .............................................................................................. 54 23.0 Wellhead Schematic ................................................................................................................ 55 24.0 Days Vs Depth ......................................................................................................................... 56 25.0 Formation Tops & Information.............................................................................................. 57 26.0 Anticipated Drilling Hazards ................................................................................................. 60 27.0 Parker 273 Rig Layout............................................................................................................ 66 28.0 FIT Procedure ......................................................................................................................... 67 29.0 Parker 273 Rig Choke Manifold Schematic ........................................................................... 68 30.0 Casing Design .......................................................................................................................... 69 31.0 12-1/4” Hole Section MASP .................................................................................................... 70 32.0 8-1/2” Hole Section MASP ...................................................................................................... 71 33.0 Spider Plot (NAD 27) (Governmental Sections) ..................................................................... 72 34.0 Surface Plat (As Built) (NAD 27) ............................................................................................ 73 Page 2 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 1.0 Well Summary Well PBU PAVE 3-1 Pad Prudhoe Bay DS-07 Planned Completion Type 7” x 7-5/8” Injection Tubing Target Reservoir(s) Ivishak Sands Planned Well TD, MD / TVD 14,657’ MD / 8,747’ TVD PBTD, MD / TVD 14,657’ MD / 8,747’ TVD Surface Location (Governmental) 3,419' FSL, 4,591' FEL, Sec 34, T11N, R14E, UM, AK Surface Location (NAD 27) X= 676,906.30, Y= 5,949,080.87 Top of Productive Horizon (Governmental)2,015' FSL, 181' FEL, Sec 22, T11N, R14E, UM, AK TPH Location (NAD 27) X= 681,081.50, Y= 5,958,337.49 BHL (Governmental) 2,593' FNL, 126' FWL, Sec 23, T11N, R14E, UM, AK BHL (NAD 27) X= 681,372.15, Y= 5,959,016.50 AFE Number 241-00153 AFE Drilling Days 34 AFE Completion Days 3 Maximum Anticipated Pressure (Surface) 2457 psig from the BCGL Maximum Anticipated Pressure (Downhole/Reservoir) 3321 psig from the 22P Work String 5” 19.5# S-135 XT-50 Parker 273 KB Elevation above MSL: 26.4 ft + 46.95 ft = 73.35 ft GL Elevation above MSL: 26.4 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 2.0 Management of Change Information Page 4 Prudhoe Bay East PAVE 3-1 Ivishak Injector 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 BTC 6,870 4,760 1,086 8-1/2” 7” 6.276 6.151 7.656 26 L-80 VamTop 7,240 5,410 604 6-5/8” 5.921 5.796 7.277 24 L-80 JFEBear 7,440 5,760 555 Tubing 7-5/8” 6.875 6.750 8.111 29.7 L-80 JFEBear 6,890 4,790 683 Tbg Tail 7” 6.276 6.151 7.656 26 L-80 VamTop 7,240 5,410 604 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 PAVE 3-1 Ivishak Injector Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. 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 mmyers@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 mmyers@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 mmyers@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 Jerry Lau 907.564.5280 jerry.lau@hilcorp.com Geologist Russ Edge 907.564.4780 russell.edge@hilcorp.com Reservoir Engineer Josh Wilcox 907.564.4331 joshua.wilcox@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: FVR 11/5/2024 PROPOSED SCHEMATIC Prudhoe Bay Unit Well: PAVE 3-1 Last Completed: TBD PTD: TBD GENERAL WELL INFO API: TBD Completed: TBD SLOTTED LINER DETAIL Top (MD) Btm (MD) Top (TVD) Btm (TVD) 6-5/8” ~13,870’ ~14,657’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 80’ N/A 13-3/8” Surface 68 / L-80 / BTC 12.415” Surface ~4,463’ 0.1497 9-5/8” Intermediate 47 / L-80 / BTC 8.681” Surface ~13,743’ 0.0758 7” Solid Liner 26 / L-80 / VamTop 6.276” ~13,593’ ~13,880’ 0.0383 6-5/8” Slotted Liner 24 / L-80 / JFE Bear 5.921” ~13,880’ ~14,657’ 0.0341 TUBING DETAIL 7" Tubing 26 / L-80 / VamTop 6.276” Surface ~117’ 0.0383 7-5/8” Tubing 29.7 / L-80 / JFE Bear 6.875” ~117’ ~2,500’ 0.0459 7" Tubing 26 / L-80 / VamTop 6.276” ~2,500’ ~2,545’ 0.0383 7-5/8” Tubing 29.7 / L-80 / JFE Bear 6.875” ~2,545’ ~13,469’ 0.0459 7" Tubing 26 / L-80 / VamTop 6.276” ~13,469’ 13,594’ 0.0383 TD =14,657’(MD) / TD =8,747’(TVD) 13-3/8” KB Elev: = 73.35’ / GL Elev: = 26.40’ 6-5/8” 2 5 7 6 4 1 ES Cementer 9-5/8” 7” PBTD =14,657’(MD) / PBTD =8,747’(TVD) 3 7-5/8” OPEN HOLE / CEMENT DETAIL Driven 16” Lead – 2079 sx / Tail – 595 sx 12-1/4”Stg 1 – Tail 611 sx Stg 2 – Lead 885 sx 8-1/2” Slotted JEWELRY DETAIL No Depth ID Item 1 ~13,880’ 5.500” 6-5/8” RN-Nipple 2 ~13,590’ Liner Hanger/LTP 3 ~13,594’ 6.276” WLEG 4 ~13,535’ 5.625” R-Nipple 5 ~13,500’ 5.900” Packer 6 ~13,469’ 5.963” R-Nipple 7 ~2,500’ 5.963” R-Nipple for check valve WELL INCLINATION DETAIL KOP @ 350’ Max Angle 61deg @4,063’ TREE & WELLHEAD Tree Wellhead Page 7 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 7.0 Drilling / Completion Summary PAVE 3-1 is a grassroots injector planned to be drilled in the Ivishak sands. The directional plan is 16” surface hole and 13-3/8” surface casing set in the base of the SV3. A 12-1/4” section will be drilled and 9-5/8” intermediate casing set at TSGR. An 8-1/2” section will be drilled to BSAD. A 7” x 6-5/8” slotted injection liner will be run in the open hole section. The well will be completed with 7-5/8” injection tubing, with the packer setting and testing being performed pos-rig. Parker 273 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately December 10, 2024, pending rig schedule. Surface casing will be run to 4,850’ MD / ~3,500’ TVD and cemented to surface. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. 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 Innovation Rig to well site 2. N/U & Test 21-1/4” Diverter and 16” diverter line 3. Drill 16” hole to TD of surface hole section. Run and cement 13-3/8” surface casing 4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test 5. Drill 12-1/4” to TD of intermediate hole section. Run and cement 9-5/8” intermediate casing 6. Drill 8-1/2” hole to TD 7. Run 7” x 6-5/8” slotted injection liner 8. Run CBL to evaluate 9-5/8” cement job 9. Run Upper Completion 10. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface Hole: No mud logging. Remote Ops geologist. LWD: GR + Res 2. Intermediate Hole: No mud logging. Field Ops geologist for casing pick. LWD: GR + Res 3. Production Hole: No mud logging. Field Ops geologist. LWD: Triple-Combo (For geo- steering) Page 8 Prudhoe Bay East PAVE 3-1 Ivishak Injector 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 (2) week intervals during the drilling and completion of PBU PAVE 3-1. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial and subsequent tests of BOP equipment will be to 250/3,500 psi for 5/5 min (annular to 50% rated WP, 2,500 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 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 9 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure AOGCC Regulation Variance Requests: 1)20 AAC 253412 (b):“A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured depth above the top of the perforations, unless the commission approves a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone.” A variance is requested to set the completion packer > 200’ from the top-most planned perforated interval. Traditional Prudhoe Bay Ivishak/Sadlerochit well design has the 9-5/8” intermediate casing topsetting the Sag River formation, in order to isolate the HRZ/Kingak shales from the depleted Sag/Shublik/Ivishak sands. The tubing packer is proposed to be set at ~ 13,500’ (~250’ above the 9-5/8” casing shoe), while the shallowest portion of slotted liner is proposed at ~13,880’ MD. Summary of Parker 273 BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 16”x 21-1/4” 2M Annular BOP w/ 16” diverter line Function Test Only 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: 250/3,500 Annular: 250/2,500 Subsequent Tests: 250/3,500 Annular 250/2,500 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 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 10 Prudhoe Bay East PAVE 3-1 Ivishak Injector 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 11 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 9.0 R/U and Preparatory Work 9.1 PAVE 3-1 will utilize a newly set 20” conductor on DS-07. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and R/U. 9.6 Rig mat footprint of rig. 9.7 Ensure any necessary wellhead equipment is staged prior to MIRU. A slip-loc starting head should also be staged in the cellar in the event that surface casing must be set using emergency slips. 9.8 MIRU Parker 273 Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.9 Mix spud mud for 16” surface hole section. Ensure mud temperatures are cool (<80qF). 9.10 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 12 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 10.0 N/U 21-1/4” 2M Diverter System 10.1 N/U 21-1/4” diverter (Diverter Schematic attached to program). x N/U 20” riser to BOP Deck x N/U 20”, 5M diverter “T”. x NU Knife gate & 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 ft from nearest ignition source 10.2 Notify AOGCC. Function test diverter. x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018 section 12.6.2 for packing element ID greater than 20”) 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. Page 13 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 14 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 11.0 Drill 16” Hole Section 11.1 P/U 16” directional drilling 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 Ensure TF offset is measured accurately and entered correctly into the MWD software. x Consider running a UBHO sub for wireline gyro.GWD will be the primary gyro tool. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill string will be 5” 19.5# S-135. x Run a solid float in the surface hole section. 11.2 Begin drilling out from conductor at reduced flow rates to avoid broaching the conductor. x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 16” hole section to section TD above the top of the SV2. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well, targeting the shale package in the base of the SV3. x Monitor the area around the conductor for any signs of broaching. If broaching is observed, stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. If a DLS < 6 deg / 100 is measured, immediately backream stand to knock down severity. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 400-600 gpm, staying between 400 and 450 gpm through the permafrost. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Avoid sliding when drilling across the prognosed base of permafrost, top SV6, and the EOCU to prevent high dogleg severity. x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen x Slow in/out of slips and while tripping to keep swab and surge pressures low x Ensure shakers are functioning properly. Check for holes in screens on connections. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. x Adjust MW and viscosity as necessary to maintain hole stability,ensure MW is at a 9.0 at base of perm and at TD. x Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand drilled. Page 15 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure x In PBE hydrates are not present. However, continue to drill using hydrate mitigation measures: x Keep mud temperature as cool as possible, Target 60-70°F x Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as cold premade mud on trucks ready x Drill through hydrate sands and quickly as possible, do not backream. x Monitor returns for hydrates, checking pressurized & non-pressurized scales x Take MWD and GWD surveys every stand until magnetic interference cleans up. After MWD surveys show clean magnetics, only take MWD surveys. x Surface Hole AC: x There are no wells with a clearance factor of <1.0 16” hole mud program summary: x Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.0+ ppg Depth Interval MW (ppg) Surface –Base Permafrost 8.8+ Base Permafrost - TD 9.0+ x PVT System: 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, and mud loggers office. x Rheology: MI-Gel should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. x Fluid Loss: PolyPac Supreme UL should be used for filtrate control. Background LCM (10 ppb total) can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. x Wellbore and mud stability:Additions of SKREENKLEEN are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of BUSAN 1060 MUST be made to control bacterial action. x Casing Running:Reduce system YP with DESCO and SAPP as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). Page 16 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure System Type:8.8 – 9.5 ppg Pre-Hydrated MI-Gel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 – 9.5 75-300 20 - 40 25-45 <10 8.5 – 9.0 70 F System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M-I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 PolyPac Supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 gal dm 0.5 11.4 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem sweeps and lower viscosity. Drop mud temp as low as possible as well. 11.5 RIH to bottom, proceed to BROOH to HWDP x Pump at full drill rate (400-600 gpm), and maximize rotation. x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.6 TOOH and LD BHA 11.7 No open hole logging program planned. Page 17 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 12.0 Run 13-3/8” Surface Casing 12.1 R/U Weatherford 13-3/8” casing running equipment (CRT & Tongs) x Ensure 13-3/8” CDC x XT50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x R/U of CRT if hole conditions require. x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 12-1/4” on the location prior to running. x Note that 68# drift is 12.259” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.2 P/U shoe joint, visually verify no debris inside joint. 12.3 Continue M/U & thread locking 120’ shoe track assembly consisting of: 13-3/8” Float Shoe 1 joint – 13-3/8” BTC, 2 Centralizers 10’ from each end w/ stop rings 1 joint –13-3/8” BTC, 1 Centralizer mid joint w/ stop ring 1 joint – 13-3/8” BTC, 1 Centralizer mid joint w/ stop ring 13-3/8” Float Collar 1 joint –13-3/8” BTC, 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 components. 12.4 Continue running 13-3/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every joint to ~ 2500’ MD from shoe x 1 centralizer every other joint to ~ 200’ below surface x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 13-3/8” 68/# L-80 BTC MUT – Make up to Mark 10 jts Take Average Casing OD Minimum Optimum Maximum 13-3/8” 27,540 ft-lbs Mark 33,660 ft-lbs Page 18 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure Page 19 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 12.5 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.6 Slow in and out of slips. 12.7 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.8 Lower casing to setting depth. Confirm measurements. 12.9 Have slips staged in cellar, along with necessary equipment for the operation. 12.10 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 20 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 13.0 Cement 13-3/8” Surface Casing 13.1 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. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 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. 13.4 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. 13.5 Fill surface cement lines with water and pressure test. 13.6 Drop first bottom plug – HEC rep to witness. Pump spacer. 13.7 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. 13.8 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 + open hole excess (400% for lead above base permafrost and 40% for all cement below base permafrost). Job will consist of lead & tail, TOC brought to surface. Page 21 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: 13.8 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. 13.9 After pumping cement, drop top plug – HEC rep to witness, and displace cement with spud 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. 13.10 Ensure rig pump is used to displace cement. 13.11 Displacement calculation is in the Stage 1 Table in step 13.7. 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±9.0 bbls before consulting with Drilling Engineer. 13.14 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 Lead Slurry Tail Slurry System ArcticCem HalCem Density 11.0 lb/gal 15.8 lb/gal Yield 2.54 ft3/sk 1.16 ft3/sk Mix Water 12.22 gal/sk 4.98 gal/sk Page 22 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.15 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. 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. Ensure to report the following on wellez: 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 23 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 14.0 ND Diverter, NU BOPE, & Test 14.1 ND the diverter T, knife gate, diverter line & NU 13-5/8” 5M casing spool. 14.2 NU 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 14.3 RU MPD RCD and related equipment 14.4 Run 5” BOP test plug 14.5 Test BOP to 250/3,500 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Test with 5” test joint in both upper and lower rams 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 14.6 RD BOP test equipment 14.7 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.8 Mix 10.0 ppg LSND fluid for intermediate hole. 14.9 Set wearbushing in wellhead. 14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.11 Ensure 5-3/4” liners in mud pumps. Page 24 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 15.0 Drill 12-1/4” Intermediate Hole Section 15.1 MU 12-1/4” Cleanout BHA (Milltooth Bit & 1.22° PDM) 15.2 TIH w/ 12-1/4” cleanout BHA to float equipment. Note depth TOC tagged on AM report. 15.3 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5020 / 2 = ~2510 psi, but max test pressure on the well is 2,500 psi as per AOGCC. 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 15.4 Drill out shoe track and 20’ of new formation. 15.5 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to clean up debris 15.6 Conduct LOT. Chart test. Ensure test is recorded on same chart as the casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. x 12.5 ppg provides >25 bbls based on 11.0 ppg MW +0.5ppg intensity, 10.2 ppg PP 15.7 POOH & LD Cleanout BHA 15.8 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. * Email casing test and FIT digital data to AOGCC upon completion of FIT. - mgr Page 25 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 15.9 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:10.0 – 11.0 ppg LSND drilling fluid Properties: Interval Density PV YP API FL HPHT Drill Solids MBT Hardness ~4,463’ – ~11,198’ Shoe –CM2 10.0 – 10.5 5 – 20 15 – 30 < 8 N/A <6% <12 <200 ~11,198’ – ~13,218’ CM2 –THRZ 10.5 – 10.7 5 – 20 15 – 30 < 6 N/A <6% <20 <200 ~13,218’ – TD THRZ – TD 10.7 – 11.0 5 – 20 15 – 30 < 6 <10 <6% <20 <200 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 Page 26 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 15.10 Displace wellbore to 10.0 ppg LSND drilling fluid 15.12 Obtain initial ECD benchmark readings prior to drilling ahead. 15.13 Drill 12-1/4” hole section from 13-3/8” shoe to ~ 11,000’ MD (~200’ MD above CM2) per Geologist and Drilling Engineer Utilizing the following parameters: x Flow Rate: 700-900 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 Overpressure is expected in the UG1 through WS2 from PWDW 3-2 disposal. While the disposal well is over 1.5 miles away, the higher than normal planned mud weight across this interval is to account for the active disposal. x 12-1/4” Hole Section A/C: x There are no wells with a CF < 1.0 15.14 Toward the end of the above interval, begin to weight up from 10.0 ppg to 10.5 ppg. Ensure mud is a consistent 10.5 ppg ~200’ before entering the CM2. x If using a spike fluid to weight up, ensure the fluid is heated to avoid shocking the formation and inducing losses/breathing 15.15 Drill 12-1/4” hole section from ~11,000’ MD to ~ 13,020’ MD (~200’ MD above HRZ) per Geologist and Drilling Engineer Utilizing the following parameters: x Flow Rate: 700-900 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 Page 27 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 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. Good hole cleaning practices now reduces time needed to cleanup prior to running casing. x Target ROP is as fast as we can clean the hole without having to backream connections x MPD will be utilized to monitor pressure build up on connections. x 12-1/4” Hole Section A/C: x There are no wells with a CF < 1.0 15.16 Toward the end of the above interval, begin to weight up from 10.5 ppg to 10.7 ppg and addition of black product for HRZ stability. Ensure mud is a consistent 10.7 ppg ~200’ before entering the HRZ. 15.17 Prior to entering the HRZ, perform a wiper trip back to the shoe. 15.11 Install MPD RCD prior to RIH and entering the HRZ 15.18 Drill 12-1/4” hole section from ~13,020’ MD to section TD (projected at ~13,743’ MD) per Geologist and Drilling Engineer Utilizing the following parameters: x Flow Rate: 700-900 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 < 120 FPH. On the final 3 stands, control drill with WOB, RPM, and flow rate to indicate when transitioning into the TSGR “rabbit ears” x MPD will be utilized to hold pressure on connections to minimize ECD cycling on formation x 8-1/2” Hole Section A/C: x There are no wells with a CF < 1.0 15.19 Reference:Intermediate Casing Pick procedure x Control drilling is key! Recognizing when the ROP changes is critical in knowing when to call TD before getting too deep into the Sag River formation and going on losses. x Drill through HRZ and LCU into the Kingak. Once the LCU and TJA are identified, use prognosed thickness to establish first stop point. x Stop drilling and CBU if one of the three occur: x Reverse drilling break observed (drill additional 5’ MD before CBU) x Sand identified in return samples x Reach above established stop point Page 28 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure x If Sag River sand is not confirmed in samples, drill additional 5’ and CBU. x Repeat above steps until Sag River sand is confirmed in samples. 15.20 At TD, CBU at least 3 times at max gpm and max RPM. Pump tandem sweeps if needed x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary x Obtain BHCT from MWD tools and provide to Halliburton cementers. 15.21 Short trip to the previous trip point x Pump and pull until above HRZ to limit swab effect on the HRZ/Kingak shales x If tight hole is encountered, RIH 2-3 stands and CBU. If tight spot is at the same depth, begin backreaming. x If backreaming operations are commenced, continue backreaming to the shoe x Monitor pressure, ECD, torque, and return flow to indicate potential packing off. x If backreaming is initiated, utilize MPD to close on connections while BROOH. x CBU minimum two times at trip point. 15.22 RIH to TD on elevators and circulate hole clean. 15.23 POOH and LD BHA. x Pump and pull until above HRZ to limit swab effect on the HRZ/Kingak shales 15.24 Change out upper rams to 9-5/8” fixed-bore rams and test with 9-5/8” test joint. * Open hole LWD field logs to AOGCC for determination of minimum packer setting depth. Page 29 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 16.0 Run 9-5/8” Intermediate Casing 16.1 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. 16.2 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. 16.3 P/U shoe joint, visually verify no debris inside joint. 16.4 Continue M/U & thread locking 80’ 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 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint –9-5/8”, 1 Centralizer free floating 9-5/8” HES Baffle Adaptor x Ensure bypass baffle is correctly installed on top of float collar. 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. This end up. Bypass Baffle Page 30 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 16.5 Float Equipment and Stage Tool equipment drawings: Page 31 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 16.6 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 ES Cementer x 1 centralizer every joint from ES Cementer to 1,000’ above ES Cementer x 1 centralizer every 2 joints from 1,000’ above ES Cementer to 13-3/8” shoe x Verify formation depths with geologist for ES Cementer placement 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 See data sheets on the next page for MU torque for the 9-5/8” casing connection. 16.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 500’ MD above THRZ. x Stage tool needs to be a minimum of 500’ MD above THRZ to ensure stage tool is out of the shales. x Install hinged centralizers over couplings on 5 joints below and 5 joints above stage tool. x Do not place tongs on ES cementer, this can cause damage to the tool. x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. 9-5/8” 47/# L-80 BTC MUT – Make up to Mark 10 jts Take Average Casing OD Optimum 9-5/8” To Mark Page 32 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 16.8 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.9 Slow in and out of slips. 16.10 RIH with 9-5/8” intermediate casing to 13-3/8” shoe at ~4,460’ MD. CBU and establish PU and SO weights prior to exiting shoe. Page 33 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 16.11 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 THRZ: 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 THRZ to TD: Do not circulate. Fill pipe only 16.12 P/U hanger and landing joint and M/U to casing string. Casing shoe +/- 5’ from TD. 16.13 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 2 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 34 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 17.0 Cement 9-5/8” Intermediate Casing 17.1 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. 17.2 Document efficiency of all possible displacement pumps prior to cement job. 17.3 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. 17.4 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. 17.5 Fill surface cement lines with water and pressure test. 17.6 Pump remaining spacer. 17.7 Drop bottom plug – HEC rep to witness. Mix and pump cement per below calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached. 17.8 Cement volume based on annular volume + 40% open hole excess. Job will consist of tail, TOC brought to the ES Cementer, ~1,500’ above the 9-5/8” shoe. Estimated Total Cement Volume: Superceded 8.8 125.9 707.2 609.7 - mgr .0732 X 997 49.4 8.681 ID .0732 Page 34 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 17.0 Cement 9-5/8” Intermediate Casing 17.1 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. 17.2 Document efficiency of all possible displacement pumps prior to cement job. 17.3 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. 17.4 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. 17.5 Fill surface cement lines with water and pressure test. 17.6 Pump remaining spacer. 17.7 Drop bottom plug – HEC rep to witness. Mix and pump cement per below calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached. 17.8 Cement volume based on annular volume + 40% open hole excess. Job will consist of tail, TOC brought to the ES Cementer, ~1,500’ above the 9-5/8” shoe. Estimated Total Cement Volume: Page 35 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure Cement Slurry Design: 17.9 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. 17.10 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. 17.11 Displacement calculation is in the Table in step 17.8. x Ensure spacer is left behind the stage tool to prevent contamination of cement in the annulus. 17.12 Monitor returns closely while displacing cement. Adjust pump rate if losses or packing off are seen at any point during the job. 17.13 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. 17.14 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, this is to ensure the stage tool is not prematurely opened. 17.15 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 17.16 While a small volume and long circulation, 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. Tail Slurry System HalCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mix Water 4.98 gal/sk Page 36 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure Second Stage Intermediate Cement Job: 17.17 Prepare for the 2 nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety meeting. 17.18 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 17.19 Fill surface lines with water and pressure test. 17.20 Pump remaining spacer. 17.21 Mix and pump cmt per below recipe for the 2 nd stage. 17.22 Cement volume based on annular volume + 40% open hole excess. Job will consist of lead only (tail cement pumped in stage 1), TOC brought to ~500’ above UG1. Estimated Total Cement Volume: Cement Slurry Design: 17.23 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 17.24 Displacement calculation is in the Table in step 17.22. 17.25 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. 17.26 Set packoff and test per wellhead tech. Lead Slurry System EconoCem Density 12.0 lb/gal Yield 2.35 ft3/sk Mix Water 13.92 gal/sk Superceded Page 36 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure Second Stage Intermediate Cement Job: 17.17 Prepare for the 2 nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety meeting. 17.18 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 17.19 Fill surface lines with water and pressure test. 17.20 Pump remaining spacer. 17.21 Mix and pump cmt per below recipe for the 2 nd stage. 17.22 Cement volume based on annular volume + 40% open hole excess. Job will consist of lead only (tail cement pumped in stage 1), TOC brought to ~500’ above UG1. Estimated Total Cement Volume: Cement Slurry Design: 17.23 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 17.24 Displacement calculation is in the Table in step 17.22. 17.25 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. 17.26 Set packoff and test per wellhead tech. Lead Slurry System EconoCem Density 12.0 lb/gal Yield 2.35 ft3/sk Mix Water 13.92 gal/sk Page 37 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 17.27 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 x Ensure total injection volume injected down the annulus (including mud used to keep annulus open) doesn’t exceed 110% of the 13-3/8” x 9-5/8” annular volume. 17.28 Change upper rams from 9-5/8” casing rams to 2-7/8” x 5” VBRs and test to 250 psi low, 3,500 psi high for 5/5 minutes with 5” test joint. Ensure to report the following on wellez: 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 38 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 18.0 Drill 8-1/2” Production Hole Section 18.1 M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM) 18.2 TIH w/ 8-1/2” cleanout BHA and tag stage tool. Note depth stage tool tagged on morning report. Drill out stage tool. 18.3 Continue to RIH and tag TOC on baffle adapter. Note depth TOC tagged on morning report. 18.4 RU and test casing 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. 18.5 Drill out baffle plate and shoe track to within 10’ of the float shoe. 18.6 Displace LSND to 8.8ppg production drilling fluid. 18.7 Drill out remaining shoe track and 20’ of new formation. 18.8 CBU and condition mud for FIT. 18.9 Conduct FIT to 10.8 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 10.8 ppg desired to cover shoe strength for expected ECDs. A 10.1 ppg FIT is the minimum required to drill ahead x 10.1 ppg FIT provides >>25bbls based on 9.1 ppg MW +0.5ppg kick intensity, 7.50 ppg EMW PP 18.10 POOH & LD cleanout BHA 18.11 MU 8-1/2” 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 5” 19.5# S-135 XT50. x Run a solid float in the production hole section. * Email Casing test and FIT digital data to AOGCC upon completion of FIT. - mgr Page 39 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 18.12 8-1/2” hole section mud program summary: x Density: 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. 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 > 8.5 (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:8.5 – 9.1 ppg FloPro drilling fluid Properties: Interval Density PV YP API FL Drill Solids pH MBT Hardness Production 8.5-9.1 <8 10 –20 <10 <6 9.0 –10.0 <8.0 <100 System Formulation: 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 Page 40 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 18.13 TIH with 8-1/2” directional assembly to bottom. 18.14 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 18.15 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM x RPM: 120+ 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 cross all Ivishak sands and TD beneath BSAD. x Limit maximum instantaneous ROP to < 200 FPH. The formations will drill faster than this, but when drilling through Zone 3 conglomerate and Zone 2 with areas of chert, cutter damage can occur if not control drilled. x Target ROP is as fast as we can clean the hole without having to backream connections x MPD will be utilized to monitor pressure build up on connections. x 8-1/2” Hole Section A/C: x 15-31 has a 0.917 CF. This well has been reservoir P&A’d. 18.16 At TD, CBU at drilling rate and max rotation. Pump sweeps if needed x Monitor BU for increase in cuttings 18.17 Perform wiper trip to the 9-5/8” casing shoe 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 18.18 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 18.19 Trip back to TD and CBU 2x or until well cleans up, whichever comes later. Page 41 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 18.20 POOH and LD BHA. Rabbit DP that will be used to run liner. Only LWD open hole logs are planned for the hole section. There will not be any additional logging runs conducted. Page 42 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 19.0 Run 7” x 6-5/8” Injection Liner 19.1 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 With 6-5/8” joint across BOP: P/U & M/U the 5” safety joint (with 6-5/8” crossover installed on bottom, TIW valve in open position on top, 6-5/8” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 6-5/8” liner. x With 7” joint across BOP: P/U & M/U the 5” safety joint (with 7” crossover installed on bottom, TIW valve in open position on top, 7” 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. 19.2 R/U 7” solid x 6-5/8” slotted liner running equipment. x Ensure 7” 26# VT x XT50 and 6-5/8” 24# JFE Bear crossovers are on rig floor and M/U to FOSVs. 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. 19.3 Run 6-5/8” slotted injection liner x Use JFE 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 See data sheet on the next page for MU torque for the 6-5/8” liner connections. x Centralization: x 1 centralizer every joint on all 6-5/8” slotted liner 19.4 Run 6-5/8” slotted injection liner as follows: 6-5/8” ported bullnose Shoe 1 solid joint –6-5/8”, 2 Centralizers 10’ from each end w/ stop rings 6-5/8” 24/# L-80 JFE Bear – Make up Torque Casing OD Minimum Optimum Maximum 6-5/8” 11,200 ft-lbs 12,440 ft-lbs 13,690 ft-lbs Page 43 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure Page 44 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 19.5 Change over the remaining handling equipment to run 7”. 19.6 Run 7” injection liner x Use Vam approved thread compound. Dope pin end only w/ paint brush. Wipe off excess. x If still pipe-light, 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 See data sheet on the next page for MU torque for the 7” liner connections. x Install 7” R-Nipple profile before picking up last joint of 7” liner x Centralization: x 1 centralizer every joint to ~ 50’ MD from 9-5/8” shoe 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 45 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure Page 46 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 19.7 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. 19.8 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. 19.8 M/U Baker SLZXP liner top packer to 7” liner. Circulate 2 liner volumes to clear string and allow for PAL mix to set 19.9 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. 19.10 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. 19.11 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. 19.12 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. 19.13 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. 19.14 Break circulation. Begin circulating at ~0.5 – 1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating for risk of prematurely setting liner hanger. Note all losses. Confirm all pressures with Baker. 19.15 Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 19.16 Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 19.17 Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SZXP 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. Page 47 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 19.18 Bleed DP pressure to 0 psi. 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. 19.19 PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 19.20 Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 19.21 PU pulling running tool free of the packer and displace at max rate to wash the liner top. Pump sweeps as needed. 19.22 POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. 19.23 RU E-Line and RIH w/7” PR-Plug and prong. Set plug in 7” R-Nipple profile in liner. 19.24 C/O e-line tools and RIH w/CBL to top of liner. Log 9-5/8” intermediate casing from top of 7” liner to 13-3/8” shoe depth to confirm TOC prior to running upper completion. RD e-line after successful log of interval. * CBL log to AOGCC upon completion of logging. - mgr Page 48 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 20.0 Run Upper Completion/ Post Rig Work 21.1 Well control preparedness: In the event of an influx of formation fluids while running the upper completion, the following well control response procedure will be followed: x With 7” tailpipe joint across BOP: P/U & M/U the 5” safety joint (with 7” crossover installed on bottom, TIW valve in open position on top, 7” handling pup above TIW). This joint shall be fully M/U and available prior to running the first joint of 7” tailpipe. x With 7-5/8” joint across BOP: P/U & M/U the 5” safety joint (with 7-5/8” crossover installed on bottom, TIW valve in open position on top, 7-5/8” handling pup above TIW). This joint shall be fully M/U and available prior to running the first joint of 7-5/8” tubing. x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW. Proceed with well kill operations. 21.2 RU to run 7” 26#, L-80 Vam Top x 7-5/8”, 29.7#, L-80 JFE Bear tubing. x Ensure wear bushing is pulled. x Ensure 5”, L-80, 29.7#, JFE Bear x NC50 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. 21.3 PU, MU and RH with the following 7” completion jewelry (tally to be provided by Operations Engineer): x Torque Turn All Connections x Tubing Jewelry to include (top to bottom): x 1x ‘R’ Nipple x 1x ‘R’ Nipple x 1x Production Packer x 1x ‘R’ Nipple x 1x WLEG x All tubing jewelry assemblies and tubing tail are 7”, 26#, L-80, VamTop and crossed over to the 7-5/8” tubing x Tubing is 7-5/8”, 29.7#, L-80, JFE Bear Page 49 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 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 7-5/8” 29.7/# L-80 JFE Bear – Make up Torque Casing OD Minimum Optimum Maximum 7-5/8” 7,470 ft-lbs 8,300 ft-lbs 9,130 ft-lbs Page 50 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure Page 51 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure Page 52 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 21.4 PU and MU the 7” tubing hanger. 21.5 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 21.6 Land the tubing hanger and RILDS. 21.7 Circulate well over to completion brine. Do not exceed 4 bpm when circulating. 21.8 Lay down the landing joint. Install 6” CIW Type J TWC. ND BOP. 21.9 NU the tubing head adapter and NU the tree. 21.10 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 21.11 Pull TWC. Line up to the IA and reverse circulate 165 bbls diesel freeze protect. Hook up jumper line to the tree and allow freeze protect to u-tube. x Volume to freeze protect down to 2,500’ MD. 21.12 Set BPV in wellhead in preparation for RDMO. 21.13 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 21.14 RDMO Parker 273 i. POST RIG WELL WORK (sundry to follow) 1. Slickline/Fullbore a. Pull BPV. b. Set plug in tubing tail and set production packer. c. Test Tubing and IA to 250 psi low for 5 min, 4,000 psi high for 30 min d. Pull plug from tubing tail. e. Pull PR plug from nipple profile in 7” solid pipe in injection liner. *AOGCC to be notified of MIT-IA to 4000 psi. 24 hour notice. - mgr Page 53 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 21.0 Parker 273 Rig Diverter Schematic Page 54 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 22.0 Parker 273 Rig BOP Schematic Page 55 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 23.0 Wellhead Schematic Page 56 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 24.0 Days Vs Depth Page 57 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 25.0 Formation Tops & Information Page 58 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure Page 59 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure Page 60 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 26.0 Anticipated Drilling Hazards 16” Hole Section: 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. Gas Hydrates/Free Gas Gas hydrates have NOT been seen on DS-07. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Well Specific A/C: x There are no wells with a clearance factor of <1.0 Wellbore stability (Faults): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. Page 61 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure H2S: DS-07 is an H2S location. Treat every hole section as though it has the potential for H2S. PBU DS-07 and DS-15 have a history of H2S in their wells. 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 07-22A 18 ppm 8/10/2024 #2 Closest SHL Well H2S Level 07-35A 24 ppm 6/10/2023 #1 Closest BHL Well H2S Level 15-31B 28 ppm 12/18/2023 #2 Closest BHL Well H2S Level 15-11C 26 ppm 9/10/2024 Max. Recorded H2S on nearest Pad/Facility 07-13A 150 ppm 7/21/1993 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 62 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 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-07 is an H2S location. Treat every hole section as though it has the potential for H2S. PBU DS-07 and DS-15 have a history of H2S in their wells. 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 07-22A 18 ppm 8/10/2024 #2 Closest SHL Well H2S Level 07-35A 24 ppm 6/10/2023 #1 Closest BHL Well H2S Level 15-31B 28 ppm 12/18/2023 #2 Closest BHL Well H2S Level 15-11C 26 ppm 9/10/2024 Max. Recorded H2S on nearest Pad/Facility 07-13A 150 ppm 7/21/1993 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 PAVE 3-1 Ivishak Injector 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: PWDW 1-2 is Flow Station 1’s disposal well. Expected pore pressure when drilling through UG4 and UG3 is 9.5 ppg. Ensure mud is at least 9.8 ppg prior to drilling through. 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. 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. Put River Sand: The western Put River Lobe is located below DS-15, between the HRZ and LCU/Kingak and can be seen in some DS-07, DS-15, and DS-18 wells. The proposed PAVE 3-1 directional plan crosses close to the eastern edge of the lobe and therefore may be seen while drilling. Pore pressure is expected to be below the mud weight planned for holding back the HRZ/Kingak shales, but be prepared for a brief increase in ROP when drilling through the sand. 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. 12.25” Hole Section Specific AC: x There are no wells with a CF < 1.0 Page 64 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 8-1/2” 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 > 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: 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-07 is an H2S location. Treat every hole section as though it has the potential for H2S. PBU DS-07 and DS-15 have a history of H2S in their wells. 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 07-22A 18 ppm 8/10/2024 #2 Closest SHL Well H2S Level 07-35A 24 ppm 6/10/2023 #1 Closest BHL Well H2S Level 15-31B 28 ppm 12/18/2023 #2 Closest BHL Well H2S Level 15-11C 26 ppm 9/10/2024 Max. Recorded H2S on nearest Pad/Facility 07-13A 150 ppm 7/21/1993 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 PAVE 3-1 Ivishak Injector 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: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. 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” Hole Section Specific AC: x 15-31 has a 0.917 CF. This well has been reservoir P&A’d. p 15-31 has a 0.917 CF. This well has been reservoir P&A’d. Page 66 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 27.0 Parker 273 Rig Layout Page 67 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 28.0 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 68 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 29.0 Parker 273 Rig Choke Manifold Schematic Page 69 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 30.0 Casing Design Page 70 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 31.0 12-1/4” Hole Section MASP Page 71 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 32.0 8-1/2” Hole Section MASP Page 72 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 33.0 Spider Plot (NAD 27) (Governmental Sections) Page 73 Prudhoe Bay East PAVE 3-1 Ivishak Injector Drilling Procedure 34.0 Surface Plat (As Built) (NAD 27) 6WDQGDUG3URSRVDO5HSRUW 1RYHPEHU 3ODQ3$9(ZS +LOFRUS1RUWK6ORSH//& 3UXGKRH%D\ 3ODQ3$9( '6)63$9( 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000True Vertical Depth (1500 usft/in)0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 Vertical Section at 25.55° (1500 usft/in) PAVE 3-1 wp02 tgt1 PAVE 3-1 wp02 tgt3 PAVE 3-1 wp02 tgt5 13 3/8" x 16" 9 5/8" x 12 1/4" 7" x 8 1/2" 500 1 0 0 0 1 5 0 0 2 0 0 0 250 0 300035004000450050005500600065007000750080008500900095001000010500110001150012000125001300013500140001450014657PAVE 3-1 wp08 Start Dir 1º/100' : 350' MD, 350'TVD Start Dir 2º/100' : 750' MD, 749.68'TVD End Dir : 3342.74' MD, 2922.52' TVD Start Dir 3º/100' : 3867.81' MD, 3217.89'TVD Start Dir 4º/100' : 4062.54' MD, 3319.95'TVD End Dir : 4072.53' MD, 3324.78' TVD Start Dir 4º/100' : 12687.93' MD, 7482.04'TVD End Dir : 13216.7' MD, 7815.95' TVD Start Dir 4º/100' : 13748.52' MD, 8223.35'T9' End Dir : 14248.52' MD, 8543.11' TV' Total Depth : 14656.99' MD, 8747.35' T9' BPRF SV6 SV5 SV4 SV3 SV2 SV1 UG4 UG3 UG1 WS2 WS1 CM3 CM2 CM1 THRZ TPTR LCU TSGR TSHU TSAD BSAD Hilcorp North Slope, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: PAVE 3-1 26.40 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 5949080.87 676906.30 70° 15' 59.1612 N 148° 34' 10.1423 W SURVEY PROGRAM Date: 2024-09-26T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 46.95 1700.00 PAVE 3-1 wp08 (DS-07 FS3-PAVE) GYD_Quest GWD 1700.00 4462.59 PAVE 3-1 wp08 (DS-07 FS3-PAVE) 3_MWD+IFR2+MS+Sag 4462.59 13742.84 PAVE 3-1 wp08 (DS-07 FS3-PAVE) 3_MWD+IFR2+MS+Sag 13742.84 14656.99 PAVE 3-1 wp08 (DS-07 FS3-PAVE) 3_MWD+IFR2+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 1931.35 1858.00 1991.11 BPRF 2086.35 2013.00 2171.11 SV6 2731.35 2658.00 3027.70 SV5 2822.35 2749.00 3172.04 SV4 3360.35 3287.00 4146.24 SV3 3584.35 3511.00 4610.45 SV2 4019.35 3946.00 5511.93 SV1 4475.35 4402.00 6456.94 UG4 4817.35 4744.00 7165.69 UG3 5306.35 5233.00 8179.08 UG1 5903.35 5830.00 9416.29 WS2 6109.35 6036.00 9843.20 WS1 6323.35 6250.00 10286.68 CM3 6763.35 6690.00 11198.53 CM2 7474.35 7401.00 12671.99 CM1 7817.35 7744.00 13218.53 THRZ 8024.35 7951.00 13488.75 TPTR 8028.35 7955.00 13493.97 LCU 8219.35 8146.00 13743.30 TSGR 8248.35 8175.00 13781.48 TSHU 8318.35 8245.00 13877.59 TSAD REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: PAVE 3-1, True North Vertical (TVD) Reference:PAVE 3-1 as staked rkb @ 73.35usft Measured Depth Reference:PAVE 3-1 as staked rkb @ 73.35usft Calculation Method:Minimum Curvature Project:Prudhoe Bay Site:07 Well:Plan: PAVE 3-1 Wellbore:DS-07 FS3-PAVE Design:PAVE 3-1 wp08 CASING DETAILS TVD TVDSS MD Size Name 3513.00 3439.65 4462.59 13-3/8 13 3/8" x 16" 8219.00 8145.65 13742.84 9-5/8 9 5/8" x 12 1/4" 8747.35 8674.00 14656.99 7 7" x 8 1/2" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 46.95 0.00 0.00 46.95 0.00 0.00 0.00 0.00 0.00 2 350.00 0.00 0.00 350.00 0.00 0.00 0.00 0.00 0.00 Start Dir 1º/100' : 350' MD, 350'TVD 3 750.00 4.00 40.00 749.68 10.69 8.97 1.00 40.00 13.52 Start Dir 2º/100' : 750' MD, 749.68'TVD 4 3342.74 55.77 28.39 2922.52 1098.17 618.85 2.00 -12.22 1257.69 End Dir : 3342.74' MD, 2922.52' TVD 5 3867.81 55.77 28.39 3217.89 1480.08 825.23 0.00 0.00 1691.26 Start Dir 3º/100' : 3867.81' MD, 3217.89'TVD 6 4062.54 61.00 25.33 3319.95 1628.00 900.00 3.00 -27.26 1856.96 Start Dir 4º/100' : 4062.54' MD, 3319.95'TVD 7 4072.53 61.15 24.91 3324.78 1635.92 903.71 4.00 -68.26 1865.71 End Dir : 4072.53' MD, 3324.78' TVD 8 12687.93 61.15 24.91 7482.04 8480.15 4081.59 0.00 0.00 9411.25 Start Dir 4º/100' : 12687.93' MD, 7482.04'TVD 9 13216.70 40.00 24.52 7815.95 8848.99 4251.57 4.00 -179.31 9817.34 End Dir : 13216.7' MD, 7815.95' TVD 10 13748.52 40.00 24.52 8223.35 9160.01 4393.44 0.00 0.00 10159.13 PAVE 3-1 wp02 tgt3 Start Dir 4º/100' : 13748.52' MD, 8223.35'TVD 11 14248.52 60.00 24.52 8543.11 9506.72 4551.59 4.00 0.00 10540.15 End Dir : 14248.52' MD, 8543.11' TVD 12 14656.99 60.00 24.52 8747.35 9828.57 4698.40 0.00 0.00 10893.84 PAVE 3-1 wp02 tgt5 Total Depth : 14656.99' MD, 8747.35' TVD 0 550 1100 1650 2200 2750 3300 3850 4400 4950 5500 6050 6600 7150 7700 8250 8800 9350 9900 South(-)/North(+) (1100 usft/in)0 550 1100 1650 2200 2750 3300 3850 4400 4950 5500 6050 6600 7150 West(-)/East(+) (1100 usft/in) PAVE 3-1 wp02 tgt5 PAVE 3-1 wp02 tgt3 PAVE 3-1 wp02 tgt1 13 3/8" x 16" 9 5/8" x 12 1/4" 7" x 8 1/2" 1000 1750 2250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6250 6500 6750 7000 7250 7500 7750 8000 8250 8500 8747 PAVE 3-1 wp08 Start Dir 1º/100' : 350' MD, 350'TVD Start Dir 2º/100' : 750' MD, 749.68'TVD End Dir : 3342.74' MD, 2922.52' TVD Start Dir 3º/100' : 3867.81' MD, 3217.89'TVD Start Dir 4º/100' : 4062.54' MD, 3319.95'TVD End Dir : 4072.53' MD, 3324.78' TVD Start Dir 4º/100' : 12687.93' MD, 7482.04'TVD End Dir : 13216.7' MD, 7815.95' TVD Start Dir 4º/100' : 13748.52' MD, 8223.35'TVD End Dir : 14248.52' MD, 8543.11' TVD Total Depth : 14656.99' MD, 8747.35' TVD CASING DETAILS TVD TVDSS MD Size Name 3513.00 3439.65 4462.59 13-3/8 13 3/8" x 16" 8219.00 8145.65 13742.84 9-5/8 9 5/8" x 12 1/4" 8747.35 8674.00 14656.99 7 7" x 8 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7200 8000 8800 9600 10400 11200 12000 12800 13600 14400 15200Measured Depth (1600 usft/in)07-2207-3307-3507-3615-1115-3115-31B15-31A15-4215-10FS-3 10k wp0207-34ANo-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: PAVE 3-1 NAD 1927 (NADCON CONUS)Alaska Zone 0426.40+N/-S +E/-W Northing Easting Latittude Longitude0.000.005949080.87676906.3070° 15' 59.1612 N148° 34' 10.1423 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: PAVE 3-1, True NorthVertical (TVD) Reference: PAVE 3-1 as staked rkb @ 73.35usftMeasured Depth Reference:PAVE 3-1 as staked rkb @ 73.35usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-09-26T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool46.95 1700.00 PAVE 3-1 wp08 (DS-07 FS3-PAVE) GYD_Quest GWD1700.00 4462.59 PAVE 3-1 wp08 (DS-07 FS3-PAVE) 3_MWD+IFR2+MS+Sag4462.59 13742.84 PAVE 3-1 wp08 (DS-07 FS3-PAVE) 3_MWD+IFR2+MS+Sag13742.84 14656.99 PAVE 3-1 wp08 (DS-07 FS3-PAVE) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 800 1600 2400 3200 4000 4800 5600 6400 7200 8000 8800 9600 10400 11200 12000 12800 13600 14400 15200Measured Depth (1600 usft/in)07-2207-3507-3607-2107-34A07-34B07-34GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference46.95 To 14656.99Project: Prudhoe BaySite: 07Well: Plan: PAVE 3-1Wellbore: DS-07 FS3-PAVEPlan: PAVE 3-1 wp08CASING DETAILSTVD TVDSS MD Size Name3513.00 3439.65 4462.59 13-3/8 13 3/8" x 16"8219.00 8145.65 13742.84 9-5/8 9 5/8" x 12 1/4"8747.35 8674.00 14656.99 7 7" x 8 1/2" 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. PRUDHOE OIL 224-140 PBU PAVE 3-1 PRUDHOE BAY WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT PAVE 3-1Initial Class/TypeSER / PENDGeoArea890Unit11650On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2241400PRUDHOE BAY, PRUDHOE OIL - 640150NA1 Permit fee attachedYes ADL028309, ADL028306, and ADL0283072 Lease number appropriateYes3 Unique well name and numberYes PRUDHOE BAY, PRUDHOE OIL - 640150 - governed by 341J4 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 waitYes14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes15 All wells within 1/4 mile area of review identified (For service well only)No16 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" 129.5# X-52 driven to 8018 Conductor string providedYes 13-3/8" L-80 68# to top of SV219 Surface casing protects all known USDWsYes Fully cemented 500% excess across the permafrost20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes 9-5/8" casing cemented from TSAG to 7500' MD. No other DPZs in intermediate hole.22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes Parker 273 rig has adequate tankage and good trucking support24 Adequate tankage or reserve pitNA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan shows no close approaches with HSE risk.26 Adequate wellbore separation proposedYes 16" Diverter >75'' in length27 If diverter required, does it meet regulationsYes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack tested to 3500 psi.29 BOPEs, do they meet regulationYes 13-5/8" , 5000 psi stack tested to 3500 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"31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes PBU DS 7 is an H2S Pad. Monitoring required.33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)No DS 07 wells are H2S-bearing. H2S measures are required.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected reservoir pressure is 7.36-7.6 ppg EMW36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate11/13/2024ApprMGRDate11/20/2024ApprADDDate11/12/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 11/21/2024