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Home My WebLink About225-0971. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Convert to Injector 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 25,315' N/A Casing Collapse Conductor N/A Surface 2,260psi Intermediate 4,760psi Intermediate 3,090psi Slotted Liner 6,390psi Slotted Liner 8,540psi Sacrificial Liner 7,500psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Ryan Lewis Contact Email: Contact Phone: 303-906-5178 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Operations Manager Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 1,746' 4-1/2" 25,315' 4,048' 8,430psi MILNE PT UNIT R-111 MILNE POINT Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 4,049' 23,556' 4,094' 1,180 Subsequent Form Required: Suspension Expiration Date: 225-097 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23827-00-00 Hilcorp Alaska LLC C.O. 477B TVD Burst 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. AOGCC USE ONLY 9,020psi 903# / L-80 / EUE 8rd 12,142' 23,558'7,029' 3-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025509, ADL355018, ADL388235 & ADL390615 4,020' 4,257' 3,759' Length PRESENT WELL CONDITION SUMMARY Size Proposed Pools: 129' 129' SCHRADER BLUFF OIL N/A N/A MD N/A 5,750psi 5,020psi 6,870psi 2,287' 2,157' 80' 20" 13-3/8" 9-5/8" 4,209' 9-5/8"8,547' 3,715' 12,306' See Schematic 4,418' 4-1/2" See Schematic 4,061'5-1/2" Tubing Size: ryan.lewis@hilcorp.com 4,094' 9-5/8" SLZXP LTP and N/A 12,111 MD/ 3,999 TVD and N/A 16,529' Perforation Depth MD (ft): 7,740psi 3/20/2026 Authorized Name and Digital Signature with Date: Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Scott Pessetto (9864) DN: cn=Scott Pessetto (9864) Date: 2026.01.09 12:18:39 - 09'00' Scott Pessetto (9864) 326-019 By Grace Christianson at 2:17 pm, Jan 09, 2026 DSR-1/22/26MGR12JAN2025 * SSVs settings as per approved PTD. * MIT-IA to 2000 psi within 5 days of stabilized injection. CDW 01/20/2026 10-404 A.Dewhurst 26JAN26 01/26/26 Convert to injector Well: MPR-111 PTD: 225-097 API:50-029-23827-00-00 Well Name:MPU R-111 API Number:50-029-23827-00-00 Current Status:Operable - Producer Rig:Coil Tubing Estimated Start Date:3/20/2026 Estimated Duration:1 day Reg.Approval Reqd?Yes Date Reg. Approval Recvd:TBD Regulatory Contact:Tom Fouts Permit to Drill Number:225-097 First Call Engineer:Taylor Wellman 907-947-9533 Second Call Engineer:Ryan Lewis 303-906-5178 (M) AFE Number:951-00174.05.02.02 Current Bottom Hole Pressure:1,574 psi @ 3,940 TVD SBHP on 12/20/24 7.7 MWE Max. Proposed Surface Pressure:1,180 psi Gas Column Gradient (0.1 psi/ft) Min ID:2.813 @ 2,632 MD X Nipple Max Inc (in Tbg):82o @ 12,150 MD Brief Well Summary Milne Point R-111 was drilled as a horizontal Schrader OA injector in December of 2025. The well was approved as an injection well and has an extended flowback period. The PTD finalized the well as a production well. Notes Regarding Wellbore Condition 3-1/2x9-5/8 Annulus tested 12/6/2025 to 3,620 psi Objective Convert to Injection Sundried work: Coil Tubing- 1) MIRU CTU. PT PCE accordingly with respect to the coil weekly BOP testing schedule 2) RIH and pull JP from X-Nipple at 11,805 MD. 3) Pump 602 bbls CI Inhibited 1% KCl down the IA followed by 173 bbls (1,900 TVD) of diesel. a) IA Volume: 0.06393 bpf x 12,111 = 775 bbls 4) Shift SSD closed with HB-2 shifting tool. 5) Perform MIT-IA to 2,000psi. a) Contact OE for discussion if difficulty obtaining passing test due to large pumping volumes and thermal changes. 6) RDMO. Attachments: 1. Well Schematic Current 2. AOR _____________________________________________________________________________________ Edited By:AT 12/15/2025 SCHEMATIC Milne Point Unit Well: MPU R-111 Last Completed: 12/7/2025 PTD:225-097 TD =25,315(MD) / TD =4,048(TVD) 4 20 Orig.KB Elev.:63.72/ GL Elev.:16.8 9-5/8 5 8 13-3/8 1 3 See Slotted Liner Detail PBTD =23,557(MD) / PBTD =4,094(TVD) PB1: 13110 14158 7 5,6 3-1/2 3 2 4 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface 127 N/A 13-3/8 Surface 68 / L-80 / TXP 12.415 Surface 4,257 0.1497 9-5/8 Intermediate 47 / L-80 / TXP 8.835 Surface 3,769 0.0732 9-5/8 Intermediate 40 / L-80 / TXP 8.750 3,769 12,305 0.0758 5-1/2 Slotted Liner 17 / L-80 / JFE Bear 4.892 12,111 16,529 0.0232 4-1/2 Slotted Liner 13.5 / L-80 / Hyd 625 3,920 16,529 23,558 0.0149 4-1/2 Sacrificial Liner 12.6 / L-80 / BTC 3.958 23,569 25,315 0.0152 TUBING DETAIL 3-1/2" Tubing 9.3# / L-80 / EUE 8Rd 2.992 Surface 12,142 0.0087 OPEN HOLE / CEMENT DETAIL 42 20 yds Concrete 16" Lead 1208 sx / Tail 598 sx 12-1/4 Lead 1071 sx / Tail 573 sx 8-1/2 Uncemented Slotted Liner 8-1/2 Sacrificial Liner 576 sx WELL INCLINATION DETAIL KOP @ 380 90° Hole Angle = @ 12,678, Max = 93° TREE & WELLHEAD Tree Cameron 4-1/8" 5M w/ 4-1/8 5M Cameron Wing Wellhead FMC 13-5/8 5K bottom w/ (2) 2-1/16 5K outs GENERAL WELL INFO API: 50-029-23827-00-00 Completion Date: 12/7/2025 5-1/2 x 4-1/2 Slotted LINER DETAIL Top (MD) Top (TVD) Btm (MD) Btm (TVD) 5-1/2 12,397 4,026 16,529 4,060 4-1/2 16,571 4,061 23,519 4,093 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 2,632 X-Nipple, 2.813 2.813 2 11,698 Sliding Sleeve 2.813 3 11,751 Zenith Gauge Mandrel 2,813 4 11,805 XN Nipple, 2.813 2.813 5 12,131 No-Go 4.750 6 12,132 Bullet Seals Non Ported (Tie-Back Seal Length to No-Go = 9.66 4.250 Lower Completion 7 12,111 9-5/8 SLZXP Liner Top Packer 6.180 8 23,557 Shoe OLIKTOK POINT-02A L-03 NW MILNE 1 3R-10 3R-10A 3R-15 3R-14 L-15 F-25 F-13F-01 F-05 F-26 F-09 L-33 F-79 L-28 L-28A F-80 F-84 F-84A F-84B F-85 F-81 F-83 F-82 F-82A F-86 F-90 STATE-01 F-87 F-87A F-91 OP I-01 OP26-DSPO2 OP03-P05 F-96 OP04-07 OP23-WW02 OP08-04 2-01 OP05-06 OI07-04 OI06-05 OP21-WW01 10-09 16-03 OP18-08 13-03 OP22-WW03 9-T1N NIK-1NIK 4 NIK-3 SI29-S2 L-08 L-13 F-46 F-62 F-14 F-06 F-02 F-10 F-58 F-84APB1 F-82PB1 F-90PB1 3Q-03AL1 OP03-P05L1 OP08-04L1 OP05-06L1 OP10-09L1 4-S03L1 -S01L1 8-08L1 SP24-SE1 SP24-SE1L1 SI17-SE2 OP16-03 L1 SP12-SE3 SP12-SE3L1 SI07-SE4 SP04-SE5 SP04-SE5L1 SP01-SE7 SP01-SE7L1 F-106 F-107 F-108F-109F-110 NIK-3PB2 NIK-3 PB1 NIK-3 PB3 M-28 M-29 3R-111L1 3R-111 3R-105 3R-105L1 3R-112 SI02-SE6 M-27 M-31 M-30 L-13A L-13B F-10A M-32 M-33 M-60 M-63 M-64 M-62 M-61 MPF-89A F-10APB1 R-141 R-102 R-142 R-101 R-101PB1 102PB1 R-103 R-101PB1 R-104 NIK-04PB1 R-143 R-144 R-105R-106 R-107 R-108 R-109 R-110 R-111 LLSITE F OLIKTOK DRILL SITE ALASKA NORTH SLOPE: MPU R-111 AOR FEET 0 5,000 SYMBOL HIGHLIGHT WELL SYMBOLS Oil D&A Location Shut In Oil INJ Well (Water Flood) P&A Oil P&A Oil/Gas SWD J&A Plug Back Pilot Well Injector Location Producer Location Shut In INJ WATER SOURCE LEAD January 8, 2026 PETRA 1/8/2026 11:39:12 AM SBF OA Top Location Purple dashed lines represent 1/4 mile radius around R-111 PTD API WELL STATUSTop of SBOA (MD)Top of SBOA (TVD)Top ofCement(MD)Top ofCement(TVDss)Isolating Stages Method TOC Determined Losses ReturnsSchrader OAstatusComments223-016 50-029-23748-00-00 MPU M-63 Active Injector- Schrader 8668 4052 Surface Surface1st stage: 9-5/8" surfacecasingReturns to Surface9-5/8" cemented w/ 2 stagecement job.1st stage: 381bbls of 12ppgEconoCem Tyle I/II lead and82bbls of 15.8ppg class G tail.2nd stage: 384bbls 10.7ppg ArcticCem lead and 56bbls of 15.8ppgtail.1st stage: None2nd stage: None1st stage: 87bbls lead cement tosurface2nd stage: 246bbls cement tosurface.Open ES Cementer at 2312' MD.223-034 50-029-23753-00-00 MPU M-64 Active Producer - Schrader 8817 4074 Surface Surface1st stage: 9-5/8" surfacecasingReturns to Surface9-5/8" cemented w/ 2 stagecement job.1st stage: 393bbls of 12ppgEconoCem Tyle I/II lead and82bbls of 15.8ppg class G tail.2nd stage: 440bbls 10.7ppg ArcticCem lead and 56bbls of 15.8ppgtail.1st stage: 14bbls2nd stage: None1st stage: 50bbls lead cement tosurface2nd stage: 317bbls cement tosurface.Open ES Cementer at 2622' MD.210-080 50-029-23427-00-00 OP05-06 Active Producer - Schrader 8423 3805 6586 -3276 9-5/8" Intermediate CasingVolumetrics.The 9-5/8" was cemented with157bbls of 12.5ppg inside 12-1/4"hole.None. The drilling report does notmention any notes about losses orreturns.None. The drilling report does notmention any notes about losses orreturns.Open Assuming 30% washout, TOC is 6586' MD.213-115 50-029-23427-60-00 OP05-06L1 Active Producer - Schrader 8423 3805 6586 -3276 9-5/8" Intermediate CasingVolumetrics.The 9-5/8" was cemented with157bbls of 12.5ppg inside 12-1/4"hole.None. The drilling report does notmention any notes about losses orreturns.None. The drilling report does notmention any notes about losses orreturns.Open214-068 50-029-23513-60-00 SP12-SE3L1 Active Producer - Schrader 5493 4011 3421 -2923 9-5/8" Intermediate CasingVolumetrics.The 9-5/8" was cemented with79.5bbls of 12.5ppg LiteCRETElead and 49bbls of 15.8ppg ClassG tail inside 12-1/4" hole. The drilling and cementing reportsdo not mention any notes aboutlosses or returns. The drilling and cementing reportsdo not mention any notes aboutlosses or returns.Open Assuming 30% washout, TOC is 3421' MD.214-067 50-029-23513-00-00 SP12-SE3 Active Producer - Schrader 5493 4011 3421 -2923 9-5/8" Intermediate CasingVolumetrics.The 9-5/8" was cemented with79.5bbls of 12.5ppg LiteCRETElead and 49bbls of 15.8ppg ClassG tail inside 12-1/4" hole.The drilling and cementing reportsdo not mention any notes aboutlosses or returns.The drilling and cementing reportsdo not mention any notes aboutlosses or returns.Open Assuming 30% washout, TOC is 3421' MD.214-100 50-629-23519-00-00 SI07-SE4 Active Injector- Schrader 6182 4061 4380 -3178 9-5/8" Intermediate CasingVolumetrics.The 9-5/8" was cemented with135bbls of 12.5ppg LiteCRETEinside 12-1/4" hole.The drilling and cementing reportsdo not mention any notes aboutlosses or returns.The drilling and cementing reportsdo not mention any notes aboutlosses or returns.Open Assuming 30% washout, TOC is 4380' MD.225-062 50-029-23821-00-00 R-108 Active Producer - Schrader 12080 3990 4554 -2369 9-5/8" Intermediate Casing CBL - 08/14/2025 None Full returns OpenTBD 50-029-23822-00-00 R-109 Active Injector- Schrader 11539 3994 4800 -2428 9-5/8" Intermediate Casing CBL - 09/24/2025 7bbls (0.8% of job) 99% returns OpenTBD 50-029-23826-00-00 R-110 Active Producer - Schrader 11983 3997 6135 -2644 9-5/8" Intermediate Casing CBL - 10/24/2025 None Full returns OpenTBD 50-029-23827-00-00 R-111Active "Producer"- Schrader (Injector currentlyunder flowback)12280 4018 6630 -2741 9-5/8" Intermediate Casing CBL - 12/03/2025 11bbls (1% of job) 99% returns Open50-029-23786-00-00 R-141 Active Producer- Schrader 5645 4089 Surface Surface1st stage: 9-5/8" surfacecasingReturns to Surface9-5/8" cemented w/ 2 stagecement job.1st stage: 172bbls of 12ppgEconoCem Tyle I/II lead and82bbls of 15.8ppg class G tail.2nd stage: 360bbls 10.7ppg ArcticCem lead and 60bbls of 15.8ppgtail.1st stage: None2nd stage: None1st stage: 47bbls lead cement tosurface2nd stage: 300bbls cement tosurface.Open ES Cementer at 2485' MD.TBD TBD Future R-112TBD TBD Future R-113TBD TBD Future R-114Area of Review MPU R-111 SB OAN/A CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Bryan Lafleur - (C) To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Cc:Frank Roach; Brad Gorham; Taylor Wellman Subject:R-111 10-425 MIT- IA report. Date:Friday, December 5, 2025 8:30:55 AM Attachments:R-111 - 10-426 MIT Report Form 12-5-2025.xlsx All, Please find in attached, the MIT-IA report for MPU R-111. Bryan S. LaFleur Hilcorp Alaska, LLC Drilling Foreman Rig: Parker 273 Office: (907) 659.5673 Mobile: (337) 466.5485 Alternate: Brett Anderson brett.anderson@hilcorp.com 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. 0LOQH3RLQW8QLW5 37' Submit to: OOPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD2250970Type InjWTubing0000 Type TestP Packer TVD 4003 BBL Pump 11.5 IA 0 3700 3645 3620 Interval I Test psi 3500 BBL Return 11.5 OA 150 150 150 150 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Hilcorp Alaska MPU R-111 Bryan LaFleur 12/05/25 Notes:9-5/8" Casing x 3-1/2" Upper Completion w/ 6" Seal Assembly at 12,143' MD, 4003' TVD. MIT IA to 3500 psi. Witness Waived by Austin McLeod 12/4/2025. Notes: Notes: Notes: R-111 Form 10-426 (Revised 01/2017)2025-1205_MIT_MPU_R-111 9 9 9 9 9 99 9¾9 9 9 9 9 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: 12/22/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251222 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# END 1-35 50029216720000 186184 12/3/2025 READ PressTempSurvey T41215 END 2-36 50029220140000 190024 10/20/2025 YELLOWJACKET PLUG-PERF T41216 END 2-38 50029220900000 190129 11/14/2025 HALLIBURTON WFL-TMD3D T41217 END 2-38 50029220900000 190129 11/15/2025 HALLIBURTON WFL-TMD3D T41217 END 2-38 50029220900000 190129 11/22/2025 HALLIBURTON WFL-TMD3D T41217 END 2-48 50029226120000 195166 12/4/2025 READ PressTempSurvey T41218 END 2-60 50029223750000 193083 12/2/2025 READ PressTempSurvey T41219 MPU C-22A 50029224890100 195198 10/13/2025 YELLOWJACKET PERF T41220 MPU I-14 50029232140000 204119 10/15/2025 YELLOWJACKET CUT T41221 MPU R-111 50029238270000 225097 12/3/2025 YELLOWJACKET SCBL T41222 PBU 15-43 50029226760000 196083 11/25/2025 HALLIBURTON TMD3D-SiAct T41223 PBU 15-43 50029226760000 196083 11/23/2025 YELLOWJACKET CBL T41223 PBU C-32E 50029215590500 225102 11/20/2025 HALLIBURTON RBT T41224 PBU F-42A 50029221080100 207093 10/27/2025 YELLOWJACKET CBL T41225 PBU L-202 50029232290000 204196 10/23/2025 YELLOWJACKET RCBL T41226 PBU L-202 50029232290000 204196 10/30/2025 YELLOWJACKET RCBL T41226 PBU S-110C 50029230300300 225086 12/1/2025 HALLIBURTON RBT T41227 PBU S-24B 50029220440200 203163 11/19/2025 HALLIBURTON WFL-TMD3D T41228 Please include current contact information if different from above. MPU R-111 50029238270000 225097 12/3/2025 YELLOWJACKET SCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.12.23 08:27:35 -09'00' David Douglas Hilcorp Alaska, 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: Date: 12/15/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: WELL: MPU R-111 + PB1 PTD: 225-097 API: 50-029-23827-00-00 (MPU R-111) API: 50-029-23827-70-00 (MPU R-111PB1) FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (10/28/2025 to 11/23/2025) x ABG, AGR, DGR, EWR-M5, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs) x Pressure While Drilling x Final Definitive Directional Survey x Final Geosteering and EOW Report/Plots SFTP Transfer – Main Folders: FINAL LWD Subfolders: FINAL Geosteering Subfolders:g T41197 T41198 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.12.16 09:39:34 -09'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:Taylor Wellman Cc:Roby, David S (OGC) Subject:20251124 1627 APPROVAL 90 day flowback: MPR-111 (PTD #225-097) Flowback Duration Date:Monday, November 24, 2025 4:28:18 PM Taylor, Approved for a 90-day flowback on MPU R-111 (PTD 225-097). 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. Dave Roby From: Taylor Wellman <twellman@hilcorp.com> Sent: Monday, November 24, 2025 3:46 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: MPR-111 (PTD #225-097) Flowback Duration Mel, Milne Point well MPR-111 (PTD #225-097) was approved for a 30 day flowback period utilizing a reverse circulating jet pump. We would like to extend this flowback period to not exceed 90 days. The same approved safety set points and piping will be utilized during the duration. If you have any questions or would like further information please let me know. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC: Wells Manager – Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com 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. 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: Milne Point, Schrader Bluff Oil, MPU R-111 Hilcorp Alaska, LLC Permit to Drill Number: 225-097 Surface Location: 5159' FSL, 4214' FEL, Sec 7, T13N, R10E, UM, AK Bottomhole Location: 360' FNL, 1846' FEL, Sec 28, T14N, R09E, 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 th day of October 2025. By Grace Christianson at 1:17 pm, Sep 12, 2025 9/12/25Monty M Myers TS 10/8/25 50-029-23827-00-00 MGR03OCT2025 * BOPE pressure test to 3000 psi. Annular to 2500 psi. * MIT-IA to 3500 psi . 24 hour notice to AOGCC for opportunity to witness. * Approved for 30 days pre-production utilizing reverse circulating jet pump w/ SSV configured as described. * MIT-IA after 5 days of stabilized injeciton (post pre-production). AOGCC to witnees. DSR-9/12/25 225-097 10/08/25 10/08/25 PTD API WELL STATUSTop of SBOA (MD)Top of SBOA (TVD)Top ofCement(MD)Top ofCement(TVDss)Schrader OAstatusZonal Isolation223-016 50-029-23748-00-00 MPU M-63 Active Injector- Schrader 8668 4052 Surface Surface OpenThe 9-5/8" casing was cemented to surface via a 2 stage cement job with over 246bbls returned to surface.223-034 50-029-23753-00-00 MPU M-64 Active Producer - Schrader210-080 50-029-23427-00-00 OP05-06 Active Producer - Schrader 8423 3805 6586 -3276 OpenThe 9-5/8" was cemented with 157bbls of 12.5ppg inside 12-1/4" hole. The drillingreport does not mention any notes about losses or returns. Assuming 30% washout,TOC is 6586' MD.213-115 50-029-23427-60-00 OP05-06L1 Active Producer - Schrader 8423 3805 6586 -3276 OpenThe 9-5/8" was cemented with 157bbls of 12.5ppg inside 12-1/4" hole. The drillingreport does not mention any notes about losses or returns. Assuming 30% washout,TOC is 6586' MD.214-068 50-029-23513-60-00 SP12-SE3L1 Active Producer - Schrader 5493 4011 3421 -2923 OpenThe 9-5/8" was cemented with 79.5bbls of 12.5ppg LiteCRETE lead and 49bbls of15.8ppg Class G tail inside 12-1/4" hole. The drilling and cementing reports do notmention any notes about losses or returns. Assuming 30% washout, TOC is 3421' MD.214-067 50-029-23513-00-00 SP12-SE3 Active Producer - Schrader 5493 4011 3421 -2923 OpenThe 9-5/8" was cemented with 79.5bbls of 12.5ppg LiteCRETE lead and 49bbls of15.8ppg Class G tail inside 12-1/4" hole. The drilling and cementing reports do notmention any notes about losses or returns. Assuming 30% washout, TOC is 3421' MD.214-100 50-629-23519-00-00 SI07-SE4 Active Injector- Schrader 6182 4061 4380 -3178 OpenThe 9-5/8" was cemented with 135bbls of 12.5ppg LiteCRETE inside 12-1/4" hole. Thedrilling and cementing reports do not mention any notes about losses or returns.Assuming 30% washout, TOC is 4380' MD.225-062 50-029-23821-00-00 Future R-108TBD TBD Future R-109TBD TBD Future R-110TBD TBD Future R-111TBD TBD Future R-112TBD TBD Future R-113TBD TBD Future R-114Area of Review MPU R-111 SB OAn/a Milne Point Unit (MPU) R-111 Drilling Program Version 0 8/27/2025 Table of Contents 1.0 Well Summary................................................................................................................................ 2 2.0 Management of Change Information ........................................................................................... 3 3.0 Tubular Program:.......................................................................................................................... 4 4.0 Drill Pipe Information: .................................................................................................................. 4 5.0 Internal Reporting Requirements ................................................................................................ 5 6.0 Planned Wellbore Schematic ........................................................................................................ 6 7.0 Drilling / Completion Summary ................................................................................................... 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 N/U BOP and Test........................................................................................................................ 23 15.0 Drill 12-1/4 Hole Section ............................................................................................................ 24 16.0 Run 9-5/8 Intermediate Casing ................................................................................................. 28 17.0 Cement 9-5/8 Intermediate Casing ........................................................................................... 32 18.0 Drill 8-1/2 Hole Section .............................................................................................................. 36 19.0 Run 5-1/2 x 4-1/2 Injection Liner (Lower Completion) ........................................................ 41 20.0 Run 3-1/2 Tubing (Upper Completion) .................................................................................... 46 21.0 RDMO ........................................................................................................................................... 47 22.0 Post-Rig Work .............................................................................................................................. 48 23.0 Parker 273 Diverter Schematic................................................................................................... 50 24.0 Parker 273 BOP Schematic ......................................................................................................... 51 25.0 Wellhead Schematic ..................................................................................................................... 52 26.0 Days vs Depth ............................................................................................................................... 53 27.0 Formation Tops & Information .................................................................................................. 54 28.0 Anticipated Drilling Hazards ...................................................................................................... 57 29.0 Parker 273 Layout ....................................................................................................................... 62 30.0 FIT Procedure .............................................................................................................................. 63 31.0 Parker 273 Choke Manifold Schematic ..................................................................................... 64 32.0 Casing Design ............................................................................................................................... 65 33.0 12-1/4 Hole Section MASP ........................................................................................................ 66 34.0 8-1/2 Hole Section MASP .......................................................................................................... 67 35.0 Spider Plot (NAD 27) (Governmental Sections) ........................................................................ 68 36.0 Surface Plat (As-Staked) (NAD 27) ............................................................................................ 69 Page 2 Milne Point Unit R-111 SB Injector Drilling Procedure 1.0 Well Summary Well MPU R-111 Pad Milne Point R Pad Planned Completion Type 3-1/2 Injection Tubing Target Reservoir(s) Schrader Bluff Oa Sand Planned Well TD, MD / TVD 26,064 MD / 4,029 TVD PBTD, MD / TVD 26,063 MD / 4,029 TVD Surface Location (Governmental) 5,159' FSL, 4,124' FEL, Sec. 07, T13N, R10E, UM, AK Surface Location (NAD 27) X= 540,454.99 Y= 6,033,324.40 Top of Productive Horizon (Governmental)1,936' FSL, 341' FEL, Sec 35, T14N, R9E, UM, AK TPH Location (NAD 27) X= 533,756.30 Y= 6,040,626.31 BHL (Governmental) 360' FNL, 1,846' FEL, Sec 28, T14N, R9E, UM, AK BHL (NAD 27) X= 521,648.23 Y= 6,048,844.14 AFE Drilling Days 35 days AFE Completion Days 2 days Maximum Anticipated Pressure (Surface) 1361 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1762 psig Work String 5-1/2 21.9# S-135 Delta 544 KB Elevation above MSL: 46.95 ft + 16.8 ft = 63.75 ft GL Elevation above MSL: 16.8 ft BOP Equipment 13-5/8 x 5M Annular, (3) ea 13-5/8 x 5M Rams Page 3 Milne Point Unit R-111 SB Injector Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit R-111 SB 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 TXP 5,020 2,260 1,556 12-1/4 9-5/8 8.681 8.525 10.625 47 L-80 TXP 6,870 4,750 1,086 9-5/8 8.835 8.679 10.625 40 L-80 CDC 5,750 3,090 916 8-1/2 5-1/2 4.892 4.767 6.050 17 L-80 JFE Bear 7,740 6,290 397 8-1/2 4-1/2 3.960 3.795 4.714 13.5 L-80 H625 9020 8540 279 Tubing 3-1/2 2.992 2.867 4.500 9.3 L-80 EUE 8RD 9289 7399 163 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) Surface, INT, & Production 5-1/2 4.778 4.000 6.625 21.9 S-135 Delta 544 41,900 58,700 786klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit R-111 SB Injector Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellView. Report covers operations from 6am to 6am 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. Ensure time entry adds up to 24 hours total. Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates Submit a short operations update each work day to sean.mclaughlin@hilcorp.com, frank.roach@hilcorp.com,brad.gorham@hilcorp.com, and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update 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 Health and Safety: Notify EHS field coordinator. Environmental: Drilling Environmental Coordinator Notify Drilling Manager & Drilling Engineer on all incidents Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally Send final As-Run Casing tally to sean.mclaughlin@hilcorp.com,frank.roach@hilcorp.com, brad.gorham@hilcorp.com, and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com, frank.roach@hilcorp.com,brad.gorham@hilcorp.com, and joseph.lastufka@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Email Drilling Manager Sean McLaughlin 907.777.8300 sean.mclaughlin@hilcorp.com Drilling Engineer Frank Roach 907.777.8413 frank.roach@hilcorp.com Drilling Engineer Brad Gorham 907.263.3917 brad.gorham@hilcorp.com Completion Engineer Taylor Wellman 907.777.8449 twellman@hilcorp.com Geologist Graham Emerson 907.564.5242 graham.emerson@hilcorp.com Reservoir Engineer Pedro San Blas 907.564.4056 pedro.sanblas@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 _____________________________________________________________________________________ Edited By: FVR 9/12/2025 PROPOSED SCHEMATIC Milne Point Unit Well: MPU R-111 Last Completed: TBD PTD: TBD TD =26,064(MD) / TD =4,029(TVD) 4 20 Orig.KB Elev.:63.75/ GL Elev.:16.8 9-5/8 5 8 13-3/8 1 3 See Slotted Liner Detail PBTD =26,063(MD) / PBTD =4,029(TVD) 7 5,6 3-1/2 3 2 4 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface 80 N/A 13-3/8 Surface 68 / L-80 / TXP 12.415 Surface 4,332 0.1497 9-5/8 Intermediate 47 / L-80 / TXP 8.835 Surface ~2,500 0.0758 9-5/8 Intermediate 40 / L-80 / CDC 8.835 ~2,500 12,435 0.0758 5-1/2 Slotted Liner 17 / L-80 / JFE Bear 4.892 12,285 17,065 0.0232 4-1/2 Slotted Liner 13.5 / L-80 / Hyd 625 3.920 17,065 26,064 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3# / L-80 / 8Rd 2.992 Surface 12,350 0.0087 OPEN HOLE / CEMENT DETAIL 42 20 yds Concrete 16" Lead ~1168 sx / Tail ~599 sx 12-1/4 Lead ~1088 sx / Tail ~573 sx 8-1/2 Uncemented Slotted Liner WELL INCLINATION DETAIL KOP @ 375 90° Hole Angle = @ 14,039, Max = 94° TREE & WELLHEAD Tree Cameron 4-1/8" 5M w/ 4-1/8 5M Cameron Wing Wellhead FMC 13-5/8 5K bottom w/ (2) 2-1/16 5K outs GENERAL WELL INFO API: Completion Date: 5-1/2 x 4-1/2 Slotted LINER DETAIL Top (MD) Top (TVD) Btm (MD) Btm (TVD) 5-1/2 4-1/2 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 ~2,500 X-Nipple, 2.813 2.813 2 TBD Sliding Sleeve 2.810 3 TBD Zenith Gauge Mandrel 3.953 4 TBD XN Nipple, 2.813 2.813 5 TBD Locater Sub, 3.5 x 8.25 No Go (bottom of locator spaced out 3.78) 3.240 6 TBD Bullet Seals 7 H511 x Ratcheting Mule Shoe 6.160 Lower Completion 7 ~12,285 9-5/8 SLZXP Liner Top Packer 6.180 8 ~26,064 Shoe Page 7 Milne Point Unit R-111 SB Injector Drilling Procedure 7.0 Drilling / Completion Summary MPU R-111 is a grassroots injector planned to be drilled in the Schrader Bluff OA sand. R-111 is part of a multi well development program targeting the Schrader Bluff sand on R-pad. Hilcorp requests to pre- produce R-111 for up to 30 days. The directional plan is a horizontal well with 16 surface hole with 13-3/8 surface casing set in the SV1. A 12-1/4 intermediate hole with 9-5/8 intermediate casing set into the top of the Schrader Bluff sand. An 8- 1/2 lateral section will be drilled. An injection liner will be run in the open hole section. The Parker 273 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately October 25th, 2025, pending rig schedule. Surface casing will be run to ~4,332 MD / 2,283 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 be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point B pad G&I facility. General sequence of operations: 1. MIRU Parker 273 to well site 2. N/U & Test 21-1/4 Diverter and 16 diverter line 3. Drill 16 surface hole to TD of surface hole section. Run and cement 13-3/8 surface casing 4. N/D diverter, N/U & test 13-5/8 x 5M BOP. Install MPD Riser 5. Drill 12-1/4 hole to TD of intermediate hole section. Run and cement 9-5/8 surface casing 6. Drill 8-1/2 lateral to well TD. 7. Run 5-1/2 x 4-1/2 injection liner. 8. Run 3-1/2 tubing. 9. N/D BOP, N/U Tree, RDMO. Reservoir Evaluation Plan: 1. Surface Hole: No mud logging. Remote geologist. LWD: GR + Res 2. Intermediate Hole: No mud logging. Remote geologist. LWD: GR + Res 3. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering) Page 8 Milne Point Unit R-111 SB Injector Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that all drilling and completion operations comply with all applicable AOGCC regulations. Operations stated in this PTD application may be altered based on sound engineering judgement as wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. BOPs shall be tested at (2) week intervals during the drilling and completion of MPU R-111. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the PTD. 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 Milne Point Unit R-111 SB Injector Drilling Procedure AOGCC Regulation Variance Requests: 1) Hilcorp is requesting approval for a test period of pre-producing R-111 for up to 30 days via a forward circulating jet pump completion. This will allow us to measure skin and evaluate the benefits of pre- producing our injectors in the future. Section 22 details the steps required to make this happen. Note also that the MIT-IA has been changed from 2,000 psi to 3,500 psi. Page 10 Milne Point Unit R-111 SB Injector Drilling Procedure Summary of BOP Equipment & Notifications Hole Section Equipment Test Pressure (psi) 12 1/421-1/4 2M Diverter 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: 250/3000 Annular: 250/2500 Subsequent Tests: 250/3000 Annular 250/2500 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 Initial Test: 250/3000 Annular: 250/2500 Subsequent Tests: 250/3000 Annular 250/2500 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. 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 PTD. 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 Milne Point Unit R-111 SB Injector Drilling Procedure 9.0 R/U and Preparatory Work 9.1 R-111 will utilize a newly set 20 conductor on R-Pad. 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 MIRU Parker 273. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mix spud mud for 16 surface hole section. Ensure mud temperatures are cool (<80 F). 9.9 Ensure 6 or 6-1/4 liners in mud pumps. NOV 12-P-160 1,600 HP mud pump ratings: 6 Liners: 4,670 psi, 507 gpm @ 120 spm @ 96% volumetric efficiency. 6-1/4 Liners: 4,305 psi, 551 gpm @ 120 spm @ 96% volumetric efficiency. Page 12 Milne Point Unit R-111 SB Injector Drilling Procedure 10.0 N/U 21-1/4 2M Diverter System 10.1 N/U 21-1/4 Hydril MSP 2M Diverter System (Diverter Schematic attached to program). N/U 20 riser to BOP Deck N/U 20, 5M diverter T. NU Knife gate & 16 diverter line. Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). Diverter line must be 75 ft from nearest ignition source 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 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: A prohibition on vehicle parking A prohibition on ignition sources or running equipment A prohibition on staged equipment or materials Restriction of traffic to essential foot or vehicle traffic only. Page 13 Milne Point Unit R-111 SB Injector Drilling Procedure 10.4 Rig & Diverter Orientation: May change on location Page 14 Milne Point Unit R-111 SB Injector Drilling Procedure 11.0 Drill 16 Hole Section 11.1 P/U 16 directional drilling assembly: Ensure BHA components have been inspected previously. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. GWD and MWD tools will be in the BHA. Ensure TF offset is measured accurately and entered correctly into the MWD software. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Drill string will be 5-1/2 21.9# S-135. Run a solid float in the surface hole section. 11.2 Begin drilling out from 20 conductor at reduced flow rates to avoid broaching the conductor. 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, in the SV1. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. Efforts should be made to minimize dog legs in the surface hole. Do not exceed 5 deg / 100. If a DLS > 5 deg / 100 is measured, immediately backream stand to knock down severity. Do not exceed 80° inclination in interval. If survey shows inc > 80°, immediately backream stand to knock down inclination. Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. Hold a safety meeting with rig crews to discuss: Conductor broaching ops and mitigation procedures. Well control procedures and rig evacuation Flow rates, hole cleaning, mud cooling, etc. Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Mud rheology is the primary method of transporting cuttings. Keep mud as cool as possible to keep from washing out permafrost. 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. Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increases in pump pressure, or changes in hookload are seen Slow in/out of slips and while tripping to keep swab and surge pressures low Ensure shakers are functioning properly. Check for holes in screens on connections. 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. Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). Drill ahead using GWD. Take MWD surveys every stand as backup. Page 15 Milne Point Unit R-111 SB Injector Drilling Procedure Be ready for the dead zone around base permafrost and the formation horizons at and just below base permafrost. Can be in 100% slide and still lose angle in the dead zone. However, BHA can deflect (ie. high DLS) when drilling through formation horizons. Remember, the intermediate hole section has minimal directional work until the last ~300 so theres plenty of footage to get back on plan. Gas hydrates have not been seen on pads adjacent to R-Pad (F-Pad and L-Pad). However, be prepared for them. In MPU they have been encountered typically around 2100-2400 TVD (just below permafrost). Be prepared for hydrates: Gas hydrates can be identified by the gas detector and a decrease in MW or ECD Monitor returns for hydrates, checking pressurized & non-pressurized scales Do not stop to circulate out gas hydrates this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. AC: All wells have a clearance factor greater than 1.0 in the surface interval. 16 hole mud program summary: 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 9.2+ ppg. Depth Interval MW (ppg) Surface Base Permafrost 8.8+ Base Permafrost - TD 9.2+ PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the drillers console, Co Man office, and Toolpusher office. 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. 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. Wellbore and mud stability:Additions of SCREENKLEEN 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. Perform Page 16 Milne Point Unit R-111 SB Injector Drilling Procedure routine checks for bacterial growth in the mud. If treatment is needed, treat with BUSAN 1060 daily to control bacterial action. Casing Running:Attempt to maintain mud rheology until casing is on bottom. Reduce system YP with DESCO and SAPP as last resort 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). System Type:8.8 9.8 ppg Pre-Hydrated MI-Gel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 9.8 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; perform cleanup cycle, racking back 1 stand after every CBU. Utilize tandem sweeps to help remove cuttings. 11.5 RIH to bottom, proceed to BROOH to HWDP Prior to pulling off bottom, ensure GWD is configured in out-run mode Pump at full drill rate (400-600 gpm) and 40-60 rpm. Reduce pump rate (400-500 gpm) when backreaming through the permafrost. Pull slowly, 5 15 ft / minute. Monitor well for any signs of packing off or losses. Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.6 TOOH and LD BHA Page 17 Milne Point Unit R-111 SB Injector Drilling Procedure 12.0 Run 13-3/8 Surface Casing 12.1 R/U Parker Wellbore 13-3/8 casing running equipment (CRT & Tongs) Ensure 13-3/8 BTC x Delta 544 XO on rig floor and M/U to FOSV. Use API Modified thread compound. Dope pin end only w/ paint brush. R/U CRT Discuss circulation strategy with drilling engineer prior to running casing. Ensure all casing has been drifted to 12-1/4 on the location prior to running. Note that 68# drift is 12.259 Be sure to count the total # of joints on the location before running. Keep hole covered while R/U casing tools. Record ODs, IDs, lengths, S/Ns 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 Ensure proper operation of float equipment while picking up. Ensure to record S/Ns of all float equipment and stage tool components. 12.4 Continue running 13-3/8 surface casing Fill casing on the fly, through the CRT. Use API Modified thread compound. Dope pin end only w/ paint brush. Centralization: 1 centralizer every joint to ~ 2500 from shoe 1 centralizer every other joint to ~300 below surface Utilize a collar clamp until weight is sufficient to keep slips set properly. If casing run indicates poor hole conditions prior to reaching base permafrost, discuss washing down casing with the drilling engineer. 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 TXP Make-Up Torques: Casing OD Minimum Maximum Yield 13-3/8 27,540 ft-lbs 33,660 ft-lbs 103,300 ft-lbs Page 18 Milne Point Unit R-111 SB Injector Drilling Procedure Page 19 Milne Point Unit R-111 SB 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 MU last joint of casing and tag TD. Position the casing shoe +/- 10 from TD. Ensure casing is spaced out such that a collar is not in the wellhead slip area. 12.8 Lower casing to setting depth. Confirm measurements. 12.9 Have slips staged in cellar along with all 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. Rotate and reciprocate casing string while conditioning mud. Page 20 Milne Point Unit R-111 SB 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. 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 amount of water for mix fluid is heated and available in the water tanks. 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 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. 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). 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. Cement volume based on annular volume + open hole excess (175% 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 Milne Point Unit R-111 SB Injector Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: 13.9 Reciprocate and rotate 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. 13.10 Park string at set depth and slow pumps to 3 bpm when bottom plugs are calculated to land on float collar. Slowly increase pump rate to plan and start reciprocating again after plug burst. 13.11 After pumping cement, drop top plug HEC rep to witness, and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. a. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.12 Ensure rig pump is used to displace cement. 13.13 Displacement calculation is in the table in step 13.8. 13.14 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. 13.15 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. Lead Slurry Tail Slurry System ArcticCem HalCem Density 10.7 lb/gal 15.8 lb/gal Yield 2.885 ft3/sk 1.153 ft3/sk Mix Water 22.02 gal/sk 4.95 gal/sk Page 22 Milne Point Unit R-111 SB Injector Drilling Procedure 13.16 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. 13.17 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 diverter stack that may have come in contact with the cement. 13.18 Install slips and make initial cut on 13-3/8 casing as follows: PU Riser and speed head PU on casing with 100k over string weight and set slips per wellhead rep Set speed head back down and disconnect from riser. PU riser and make initial cut on 13-3/8 casing. Set riser back down on speed head and LD cut joint. Ensure to report the following on wellez: Pre flush type, volume (bbls) & weight (ppg) Cement slurry type, lead or tail, volume & weight Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid Note if casing is reciprocated or rotated during the job Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure Note if pre flush or cement returns at surface & volume Note time cement in place Note calculated top of cement 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, brad.gorham@hilcorp.com, and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 23 Milne Point Unit R-111 SB Injector Drilling Procedure 14.0 N/U BOP and Test 14.1 N/D the diverter T, knife gate, and diverter line. Dress off 13-3/8 casing stub. N/U 13-5/8 x 13-5/8 5M casing spool. 14.2 N/U 13-5/8 x 5M BOP as follows: 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 Double gate ram should be dressed with 3-1/2 x 5-1/2 VBRs or 5-1/2 solid body rams in top cavity,blind ram in bottom cavity. Single ram can be dressed with 3-1/2 x 5-1/2 VBRs N/U bell nipple, install flowline. Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve 14.3 Install BOP test plug 14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. Test 3-1/2 x 5-1/2 rams with the 3-1/2 and 5-1/2 test joints Confirm test pressures with PTD Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.5 R/D BOP test equipment 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix LSND fluid for intermediate hole. Ensure LSND mud weight matches the weight at TD of surface hole. 14.8 Set wearbushing in wellhead. 14.9 Rack back as much 5-1/2 DP in derrick as possible to be used while drilling the hole section. 14.10 Ensure 6 or 6-1/4 liners in mud pumps. Page 24 Milne Point Unit R-111 SB Injector Drilling Procedure 15.0 Drill 12-1/4 Hole Section 15.1 M/U 12-1/4 Cleanout BHA (Milltooth Bit & 1.50° 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 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5020 / 2 = ~2,510 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 FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as the casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. 12.0 ppg desired to cover shoe strength for expected ECDs. A 10.6 ppg FIT is the minimum required to drill ahead 10.6 ppg provides >25 bbls based on 9.2 ppg MW, 8.46 ppg PP (swabbed kick at 9.2 ppg BHP) 15.7 POOH & LD Cleanout BHA 15.8 P/U 12-1/4 RSS directional BHA. Ensure BHA components have been inspected previously. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. Ensure TF offset is measured accurately and entered correctly into the MWD software. Ensure MWD is R/U and operational. MWD cannot be the same tool used in the 16 surface BHA (independent verification of data). Ensure GWD is included in the BHA. Both gyro and HOC used cannot be the same tools used in the 16 surface BHA (independent verification of data). Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Drill string will be 5-1/2 21.9# S-135 Delta 544. Run float in the intermediate hole section. Float can be ported or non-ported. 15.9 12-1/4 hole section mud program summary: 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. Email casing test and FIT digital data to AOGCC upon completion of FIT. - mgr Page 25 Milne Point Unit R-111 SB Injector Drilling Procedure 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. 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 Run the centrifuge as needed while drilling the intermediate hole, this will help with solids removal. Dump and dilute as necessary to keep drilled solids to an absolute minimum. MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the drillers console, Co Man office, & Toolpusher office. System Type:8.9 9.8 ppg LSND drilling fluid Properties: Interval Density PV YP API FL Total Solids MBT Hardness Intermediate 8.9-9.8 5-20 - ALAP 15 - 30 <8 <10% <8 <200 15.10 TIH with 12-1/4 directional assembly to bottom 15.11 Displace wellbore to LSND drilling fluid 15.12 Begin drilling 12-1/4 hole section, on-bottom staging technique: Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 15.13 Drill 12-1/4 hole section to section TD per Geologist and Drilling Engineer. Flow Rate: 700-950 gpm. Target 950 GPM. AVs 194 ft/min, 950 gpm RPM: 120-180. Target 150-180rpm Utilize GWD surveys for entire 12-1/4 hole section Efforts should be made to minimize dog legs in the intermediate hole. Keep any directional work needed to maintain plan to DLS < 3 deg / 100. Any doglegs over 3 deg / 100 need to be addressed before drilling ahead. There is plenty of length in this hole section to get back on plan. Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Page 26 Milne Point Unit R-111 SB Injector Drilling Procedure 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. Ensure the scalper screens are 50s before drilling ahead Screen down to 100s before drilling Ugnu. Screen up as hole conditions allow to 170/200s. Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low Take MWD/GWD surveys every stand and more frequently if deemed necessary, ex: concretion deflection Monitor Torque and Drag with pumps on every 5 stands Monitor ECD, pump pressure & hookload trends for hole cleaning indication 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 sands for any extended period of time. When drilling through the Ugnu sections (UG4, UG4A, UG3, UG1), limit ROP to 150 fph. This is to handle the sand on the shaker screens at the high flow rate Ensure ScreenKleen concentration is between 1.5% and 2.5% before drilling Ugnu sands. Have additional ScreenKleen available in shaker room to pressure wash and scrub shaker screens during connections. Minimize the amount of water used on the screens. Clean with ScreenKleen instead. Ensure mud is warm before drilling Ugnu. Use steam lines in pits if needed. Watch for packoffs while drilling through UG2 and UG1 coals. These are the most problematic in the Ugnu formation. Once below the Ugnu, limit maximum instantaneous ROP to < 200 fph. The formations will drill faster than this, but if a concretion is hit closer to TD when drilling this fast, cutter damage can occur. Target ROP is as fast as we can clean the hole (under 200 fph) without having to backream connections Note depths of the Ugnu coals for ghost reamer crossings and post-TD backreaming awareness A/C: All wells have a clearance factor greater than 1.0 in the intermediate interval. 15.14 At TD, CBU (minimum 5-7X, more if needed) at max rate and rotation (120+ rpm). Pump tandem sweeps if needed Rack back a stand at each bottoms up and reciprocate a full stand in between (while circulating the BU). Keep the pipe moving while pumping. Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a consistent stream so circulate more if necessary Ensure lubricant concentration is at least 4.0% in and out before pulling off bottom. 15.15 BROOH with the drilling assembly to the 13-3/8 casing shoe. Circulate at full drill rate unless losses are seen. Rotate at maximum rpm that can be sustained. Target pulling speed of 5 10 min/std (slip to slip time, not including connections), but adjust as hole conditions dictate. Slow pulling speed when backreaming through coal depths seen when drilling. Page 27 Milne Point Unit R-111 SB Injector Drilling Procedure Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. Monitor returns during the backream for increase in cuttings. Cuttings in laterals will come back in waves and not a consistent stream so circulate more if necessary. 15.16 CBU 13-3/8 shoe (minimum 4x) and clean casing with high vis sweeps. Be prepared for the hole to unload. This may take 4-6 BU before clean. Pump an EP Mud Lube pill to coat the surface casing before POOH. 15.17 Monitor well for flow. 15.18 POOH and LD BHA. Be prepared to pump out of the hole until entering vertical section. If needing to pump out, continue until BHA enters vertical section. CBU to clean casing once BHA is in the vertical section. This may take several BU volumes to achieve. 15.19 Change upper rams from 3-1/2 x 5-1/2 VBRs to 9-5/8 casing rams and test to 250 psi low, 3,000 psi high for 5/5 minutes with 9-5/8 test joint. Provide AOGCC 24 hr notice for ram change and test Page 28 Milne Point Unit R-111 SB Injector Drilling Procedure 16.0 Run 9-5/8 Intermediate Casing 16.1 R/U Parker Wellbore 9-5/8 casing running equipment (CRT & Tongs) Ensure 9-5/8 BTC x Delta 544 XO on rig floor and M/U to FOSV. Use API Modified thread compound. Dope pin end only w/ paint brush. R/U CRT and ensure torque rings are installed prior to running casing. Fill casing on the fly through CRT Discuss circulation strategy with drilling engineer prior to running casing. Ensure all casing has been drifted to 8-1/2 on the location prior to running. Note that 40# drift is 8.679 Note that 47# drift is 8.525 Be sure to count the total # of joints on the location before running. Keep hole covered while R/U casing tools. Record ODs, IDs, lengths, S/Ns of all components w/ vendor & model info. 16.2 P/U shoe joint, visually verify no debris inside joint. 16.3 Continue M/U & thread locking 120 shoe track assembly consisting of: 9-5/8 Float Shoe 1 joint 9-5/8 BTC, 2 Centralizers 10 from each end w/ stop rings 1 joint 9-5/8 BTC, 1 Centralizer mid joint w/ stop ring 1 joint 9-5/8 BTC, 1 Centralizer mid joint w/ stop ring 9-5/8 Float Collar 1 joint 9-5/8 BTC, 1 Centralizer mid joint with stop ring 16.4 Continue running 9-5/8 surface casing Fill casing on the fly, through the CRT. Use API Modified thread compound. Dope pin end only w/ paint brush. Centralization: 1 centralizer every joint to ~ 3,000 MD from 9-5/8 shoe 1 centralizer every 2 joints to ~100 MD below 13-3/8 shoe Utilize a collar clamp until weight is sufficient to keep slips set properly. 9-5/8 40# L-80 CDC Make-Up Torque Casing OD Minimum Maximum Yield 9-5/8 17,000 ft-lbs 21,000 ft-lbs 30,900 ft-lbs 9-5/8 47# L-80 TXP Make-Up Torque Casing OD Minimum Maximum Yield 9-5/8 21,440 ft-lbs 26,200 ft-lbs 54,100 ft-lbs Page 29 Milne Point Unit R-111 SB Injector Drilling Procedure Page 30 Milne Point Unit R-111 SB Injector Drilling Procedure Page 31 Milne Point Unit R-111 SB Injector Drilling Procedure 16.5 CBU at 13-3/8 shoe, prior to entering open hole. 16.6 Continue to RIH with 9-5/8 intermediate casing to TD. Break circulation every 10 joints and wash down. Take special care when staging pumps up and down to avoid surging and breaking down the formation. If hookloads indicate excess drag or dirty hole, increase circulation frequency to every 5 joints. 16.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.8 Slow in and out of slips. 16.9 NOTE: The last ~2,500 will be 47# casing. This is to ensure enough weight to get casing string to bottom. 16.10 P/U landing joint/hanger assembly 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. 16.11 Lower casing and land hanger to confirm depth. Confirm measurements. 16.12 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. Reciprocate casing string while conditioning mud. Page 32 Milne Point Unit R-111 SB 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. How to handle unlikely 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 amount of water for mix fluid is heated and available in the water tanks. Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap pit levels 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. 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 all bottom plugs to ensure done in correct order. 17.5 Fill surface cement lines with water and pressure test. 17.6 Drop first bottom plug HEC rep to witness. Pump spacer. 17.7 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. 17.8 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. a. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead and tail cement, TOC brought to ~7,168 MD, 2,910 TVD. Depth chosen provides 250 TVD coverage above deepest freshwater intervals (<10,000 mg/L TDS), determined from MPU R-103 log data. That data shows deepest freshwater intervals~200 TVD above LA3 top. Depths and volumes to be confirmed with as-drilled log data. NOTE: If AEO-2A is approved before the cement job is performed, cement volumes will be adjusted to ensure cement 250 TVD above top of pool. Page 33 Milne Point Unit R-111 SB Injector Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: 17.9 Reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, If the hole gets sticky, cease pipe reciprocation, land hanger on profile, and continue with the cement job. 17.10 After pumping cement, drop top plug and displace cement with spud mud out of mud pits. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 17.11 Ensure rig pump is used to displace cement. 17.12 Displacement calculation is in the table in step 17.8. 17.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 17.14 Park string at set depth and slow pumps to 3 bpm when bottom plugs are calculated to land on float collar. Slowly increase pump rate to plan and start reciprocating again after plug burst. 17.15 If top 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. 17.16 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until Lead Slurry Tail Slurry System VersaCem SwiftCem Density 14.0 lb/gal 15.3 lb/gal Yield 1.519 ft3/sk 1.237 ft3/sk Mix Water 7.696 gal/sk 5.562 gal/sk Page 34 Milne Point Unit R-111 SB 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. 17.17 While unlikely, be prepared for cement returns to surface. Dump cement returns through 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 come in contact with cement returns. 17.18 Back off and LD landing joint. Install packoff and test per wellhead tech. 17.19 Freeze protect 13-3/8 x 9-5/8 casing annulus to ~2,500 MD with dead crude or diesel after cement tests indicate cement has reached 500 psi compressive strength. Freeze protect with ~150 bbls of dead crude/diesel Establish breakdown pressure and inject 5 bbls past breakdown to confirm annulus is clear Ensure total injection volume injected down the annulus (including mud used to keep annulus open) doesnt exceed 110% of the 13-3/8 x 9-5/8 annular volume. 17.20 Change upper rams from 9-5/8 casing rams to 3-1/2 x 5-1/2 VBRs and test to 250 psi low, 3,000 psi high with 3-1/2 and 5-1/2 test joints. Provide AOGCC 24 hr notice for ram change and test 17.21 Once cement is in place long enough to start building compressive strength, MU 8-1/2 Cleanout BHA. RIH and tag plugs. Circulate and condition mud. POOH & LD BHA. 17.22 If Halliburtons XBAT tool is not on location, RU e-line and RIH w/CBL on tractor. Log 9-5/8 casing from plugs up to confirm TOC for both freshwater protection and 250 TVD above top of pool (injector isolation). POOH and LD logging tools. RD e-line. If the cement job goes well with no indications of improper placement, the CBL may be run before running the upper completion. NOTE: If AEO-2A is approved before CBL is performed, log will be run to confirm cement 250 TVD above top of pool for injector isolation. Page 35 Milne Point Unit R-111 SB Injector Drilling Procedure Ensure to report the following on wellez: Pre flush type, volume (bbls) & weight (ppg) Cement slurry type, lead or tail, volume & weight Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid Note if casing is reciprocated or rotated during the job Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure Note if pre flush or cement returns at surface & volume Note time cement in place Note calculated top of cement 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, brad.gorham@hilcorp.com, and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 36 Milne Point Unit R-111 SB Injector Drilling Procedure 18.0 Drill 8-1/2 Hole Section 18.1 M/U 8.5 Cleanout BHA (Milltooth Bit & 1.50° PDM) If available, include Halliburtons XBAT LWD sonic tool in BHA. Tool to be run in memory mode. This is to serve as the cement evaluation log for the 9-5/8 intermediate cement job in step 17.22. 18.2 TIH to TOC above the float collar. Note depth TOC tagged on morning report. 18.3 R/U and test casing to 3,000 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi. 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. 18.4 Drill out shoe track and 20 of new formation. 18.5 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to clean up debris. 18.6 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 12.0 ppg desired to cover shoe strength for expected ECDs. A 10.1 ppg FIT is the minimum required to drill ahead 10.1 ppg provides >25 bbls based on 9.2ppg MW, 8.46ppg PP (swabbed kick at 9.2ppg BHP) 18.7 Pump EP Mud Lube Sweep. Dump sweep once back to surface. 18.8 POOH & LD Cleanout BHA 18.9 P/U 8-1/2 RSS directional BHA. Ensure BHA components have been inspected previously. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. Ensure TF offset is measured accurately and entered correctly into the MWD software. Ensure MWD is R/U and operational. Ensure GWD is included in the BHA Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. Drill string will be 5-1/2 21.9# S-135 Delta 544. Run two non-ported floats in the production hole section. Email casing test and FIT digital data to AOGCC upon completion of FIT. - mgr Page 37 Milne Point Unit R-111 SB Injector Drilling Procedure Schrader Bluff Bit Jetting Guidelines Formation Jetting TFA NB 6 x 14 0.902 OA 6 x 13 0.778 OB 6 x 13 0.778 18.10 8-1/2 hole section mud program summary: Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. 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. Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). 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 Run the centrifuge continuously while drilling the production hole, this will help with solids removal. Dump and dilute as necessary to keep drilled solids to an absolute minimum. MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the drillers console, Co Man office, & Toolpusher office. System Type:8.9 9.5 ppg FloPro drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 Page 38 Milne Point Unit R-111 SB Injector Drilling Procedure 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 18.11 TIH with 8-1/2 directional assembly to bottom 18.12 Install MPD RCD 18.13 Displace wellbore to 8.9 ppg FloPro drilling fluid 18.14 Begin drilling 8-1/2 hole section, on-bottom staging technique: Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U 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. Flow Rate: 350-550 gpm, target min. AVs 200 ft/min, 390 gpm RPM: 120+ Utilize GWD surveys for entire 8-1/2 hole section 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. Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection Monitor Torque and Drag with pumps on every 5 stands Monitor ECD, pump pressure & hookload trends for hole cleaning indication Surveys can be taken more frequently if deemed necessary. 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. Use ADR to stay in section. Page 39 Milne Point Unit R-111 SB Injector Drilling Procedure Limit maximum instantaneous ROP to < 200 fph. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter and/or tool damage can occur. Target ROP is as fast as we can clean the hole (under 200 fph) without having to backream connections Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up on connections Schrader Bluff OA Concretions: 4-6% Historically AC: All wells have a clearance factor greater than 1.0 in the surface interval. 18.16 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. If a known fault is coming up, put a slight kick-off ramp in wellbore ahead of the fault so we have a nice place to low side. Attempt to sidetrack low and right in a fast drilling interval where the wellbore is headed up. Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes. Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 18.17 At TD, CBU (minimum 5-7X, more if needed) at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump tandem sweeps if needed Rack back a stand at each bottoms-up and reciprocate a full stand in between (while circulating the BU). Keep the pipe moving while pumping. Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a consistent stream so circulate more if necessary If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum 18.18 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. Page 40 Milne Point Unit R-111 SB Injector Drilling Procedure 18.19 Displace 1.5 OH + Liner volume with viscosified brine. Proposed brine blend (aiming for an 8 on the 6 RPM reading) - KCl: 7.1bbp for 2% NaCl: 60.9 ppg for 9.4 ppg (Minimum weight to match drilling mud) Lotorq: 1.75% Lube 776: 1.75% Soda Ash: as needed for 9.5pH Busan 1060: 0.42 ppb Flo-Vis Plus: 1.25 ppb Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 18.20 BROOH with the drilling assembly to the 9-5/8 casing shoe. Note: PST test is NOT required. Circulate at full drill rate unless losses are seen (350 gpm minimum if on losses) Rotate at maximum rpm that can be sustained. Target pulling speed of 15 45 ft/hr (slip to slip time, not including connections), but adjust as hole conditions dictate. When pulling across any OHST depths, turn pumps off and rotary off to minimize disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct hole section, check with ABI compared to as drilled surveys 18.21 CBU minimum 3 times at 9-5/8 shoe and clean casing with high vis sweeps. Once clean, pump EP Mud Lube pill with spacers ahead and behind. Dump spacers and pill when returned to surface. 18.22 Monitor well for flow. Increase mud weight if necessary Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise If necessary, increase MW at shoe for any higher than expected pressure seen 18.23 Pull RCD Bearing and install trip nipple. 18.24 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Page 41 Milne Point Unit R-111 SB Injector Drilling Procedure 19.0 Run 5-1/2 x 4-1/2 Injection Liner (Lower Completion) 19.1 Well control preparedness: In the event of an influx of formation fluids while running the injection liner with slotted liner, the following well control response procedure will be followed: With 4-1/2 joint across BOP: P/U & M/U the 4-1/2 safety joint (with 4-1/2 crossover installed on bottom, FOSV valve in open position on top, 4-1/2 handling joint above FOSV). This joint shall be fully M/U and available prior to running the first joint of 4-1/2 liner. With a 5-1/2 joint across the BOP: P/U & M/U the 5-1/2 safety joint (with 5-1/2 crossover installed on bottom, FOSV valve in open position on top, 5-1/2 handling joint above FOSV). This joint shall be fully M/U and available prior to running the first joint of 5-1/2 liner. 19.2 Confirm VBRs have been tested to cover 3-1/2 and 5-1/2 pipe sizes to 250 psi low/3000 psi high. 19.3 R/U 4-1/2 liner running equipment. Ensure 5-1/2 JFE Bear and 4-1/2 Hydril 625 x Delta 544 crossovers are on rig floor and M/U to FOSV. Ensure the liner 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 ODs, IDs, lengths, S/Ns of all components w/ vendor & model info. 19.4 Run 5-1/2 x 4-1/2 injection liner. Injection liner will be a combination of slotted and solid joints. Every third joint in the open hole is to be a slotted joint. Confirm with OE. Uppermost ~4,300 will be 5-1/2. Use API Modified or equivalent thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the slots. Utilize a collar clamp until weight is sufficient to keep slips set properly. Use lift nubbins and stabbing guides for the liner run. If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each jt outside of the surface shoe. This is to mitigate sticking risk while running inner string. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm Page 42 Milne Point Unit R-111 SB Injector Drilling Procedure 4-1/2 13.5# L-80 H625 Casing OD Minimum Optimum Maximum Operating Torque 4.5 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Page 43 Milne Point Unit R-111 SB Injector Drilling Procedure 5-1/2 17# L-80 JFE Bear Casing OD Minimum Optimum Maximum Operating Torque 5.5 6,660 ft-lbs 7,400 ft-lbs 8,140 ft-lbs Page 44 Milne Point Unit R-111 SB Injector Drilling Procedure 19.5 Ensure that the liner top packer is set ~150 MD above the 9-5/8 shoe. AOGCC regulations require a minimum 100 overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 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. 19.7 M/U Baker SLZXP liner top packer with 6 lower sealbore extention to 4-1/2 x 5-1/2 liner. 19.8 Note: PU and SO of liner. Ensure SwivelMASTER is on top of the liner tunning tool before picking up drillpipe. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 19.9 RIH with liner no faster than 30 ft/min this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. Ensure 5-1/2 DP/HWDP has been drifted Fill pipe every 10-15 stands to make sure string is topped off. 19.10 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 19.11 Obtain up and down weights of the liner before entering open hole. 19.12 Every 5 stands, record SO weights both with and without drillpipe rotation. 19.13 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 19.14 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 19.15 Rig up to pump down the work string with the rig pumps. 19.16 Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker 19.17 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. 19.18 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. Page 45 Milne Point Unit R-111 SB Injector Drilling Procedure 19.19 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. 19.20 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. 19.21 PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 19.22 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. 19.23 PU pulling running tool free of the packer and displace at max rate to wash the liner top. Pump sweeps as needed. 19.24 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. Page 46 Milne Point Unit R-111 SB Injector Drilling Procedure 20.0 Run 3-1/2 Tubing (Upper Completion) 20.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). 20.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min. Ensure wear bushing is pulled. Ensure 3-½ EUE 8RD x XT39 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 R/U casing tools. Record ODs, IDs, lengths, S/Ns of all components w/ vendor & model info. Monitor displacement from wellbore while RIH. 3-1/2 9.3# L-80 EUE 8RD Casing OD Minimum Optimum Maximum Operating Torque 3.5 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs 3-½ Upper Completion Running Order 6 Baker Ported seal with mule shoe (stung into the tie back receptacle) 3 joints (minimum, more as needed) 3-½ 9.3#/ft, L-80 EUE 8RD tubing 3-½ XN nipple at TBD 1 joint 3-½ 9.3#/ft, L-80 EUE 8RD tubing 3-½ SGM-FS XDPG Gauge at TBD 1 joint 3-½ 9.3#/ft, L-80 EUE 8RD tubing 3-½ Sliding Sleeve at TBD 3-½ 9.3#/ft, L-80 EUE 8RD tubing 3-½ X nipple at ~2,500 (below base permafrost) 3-½ 9.3#/ft, L-80 EUE 8RD space out pups 1 joint 3-½ 9.3#/ft, L-80 EUE 8RD tubing Tubing hanger with 3-1/2 EUE 8RD pin down Page 47 Milne Point Unit R-111 SB Injector Drilling Procedure 20.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals engaged. 20.4 Bleed pressure and open annular. Space out the completion (+/- Neutral to 1 above No-Go). Place all space out pups below the first full joint of the completion. 20.5 MU tubing hanger and landing joint. 20.6 Freeze protect the tubing and IA to ~3000 MD with ±210 bbl of diesel. i. Contact Wellsite Supervisor or Wells Foreman to confirm if freeze protect is needed. 20.7 Strip in and Land hanger. RILDS and test hanger. 20.8 Continue pressuring up and test the annulus to 3,500 psi and test for 30 charted minutes. i. Note this test must be witnessed by the AOGCC representative. ii. Complete form 10-426 and submit to the required recipients. Copy frank.roach@hilcorp.com,brad.gorham@hilcorp.com, and twellman@hilcorp.com on the e-mail. 20.9 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and tree. 20.10 Pull BPV. Set TWC. Test tree to 5000 psi. 20.11 Pull TWC. Set BPV. Bullhead tubing freeze protect. 20.12 Secure the tree and cellar. 21.0 RDMO 21.1 RDMO Parker 273 Page 48 Milne Point Unit R-111 SB Injector Drilling Procedure 22.0 Post-Rig Work Operations-Convert well on surface with hard line to a jet pump producer. 22.1 MU surface lines from power fluid header to the IA. Rig up piping and instrumentation per Unmanned Injector Flowback Diagram. i. Pressure test lines at existing power fluid header pressure (3,500 psi) 22.2 MU surface lines from production header to tubing. Rig up piping and instrumentation per Unmanned Injector Flowback Diagram i. Pressure test to 3,500 psi. ii. SSV Pilot Settings: 1. Production SSV low pressure trip will be set to 25% of FTP or 50% of inlet separator pressure. 2. Production SSV high pressure trip will be set at 1100 psig. 3. Power fluid XV low pressure trip will be set to 50% of header pressure. 4. Power Fluid XV to be actuated if vertical run tubing SSV is actuated (within 2 minutes). iii. AOGCC will be notified for opportunity to witness before production begins. iv. Visual leak check by pad operator performed at least once per tower (i.e. ~ every 12 hours). v. SCADA screen available in control room for pressure and flow sensors on injection line and wells flow line. vi. Pilot trip pressures, both high and low, documented in permitting documents for Hilcorp pad operators and AOGCC inspectors. 22.3 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi. i. Contingency (if SL is unable to reach depth via pump down): Use RU coil tubing and pressure test to 250psi low / 3,000psi high. Use coil tubing to perform same runs as outlined below. 22.4 Shift Sliding sleeve open 22.5 Set 13B jet pump 22.6 RDMO Page 49 Milne Point Unit R-111 SB Injector Drilling Procedure SL/FB- After 30 days of production 22.7 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi. 22.8 FB circ IA with corrosion inhibited brine down to SS with a FP cap down to 2,000 on IA i. Contingency (if SL was unsuccessful in reaching depth): Use RU coil tubing and pressure test to 250psi low / 3,000psi high. Use coil tubing to perform same runs as outlined below. 22.9 Pull Jet Pump 22.10 Shift sliding sleeve closed 22.11 MIT-IA test to 2,000 psi 22.12 POI 22.13 After 5 days of stabilized injection MIT-IA to 2,000 psi (Charted and state witnessed) Page 50 Milne Point Unit R-111 SB Injector Drilling Procedure 23.0 Parker 273 Diverter Schematic Page 51 Milne Point Unit R-111 SB Injector Drilling Procedure 24.0 Parker 273 BOP Schematic Page 52 Milne Point Unit R-111 SB Injector Drilling Procedure 25.0 Wellhead Schematic Page 53 Milne Point Unit R-111 SB Injector Drilling Procedure 26.0 Days vs Depth Page 54 Milne Point Unit R-111 SB Injector Drilling Procedure 27.0 Formation Tops & Information TOP NAME TVD (FT) TVDSS (FT) MD (FT) Formation Pressure (psi) EMW (ppg) SV5 1,390 1,326 1,475 613 8.46 Base Permafrost 1,874 1,810 2,482 824 8.46 SV1 2,080 2,016 3,414 911 8.46 LA3 3,360 3,296 9,204 1481 8.46 UG_MF 3,846 3,782 11,402 1677 8.46 SB_Na 3,904 3,840 11,665 1695 8.46 SB_Oa 4,002 3,938 12,400 1746 8.46 Page 55 Milne Point Unit R-111 SB Injector Drilling Procedure L-Pad and F-Pad Data Sheets Formation Descriptions (Closest & Most Analogous MPU Pads to Moose Pad) Page 56 Milne Point Unit R-111 SB Injector Drilling Procedure Page 57 Milne Point Unit R-111 SB Injector Drilling Procedure 28.0 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 Gas hyrates have not been seen on Raven pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system. 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 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 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 a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well specific A/C: There are no wells with a CF < 1.0 Wellbore stability (Permafrost, running sands and gravel, conductor broaching): 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. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 58 Milne Point Unit R-111 SB Injector Drilling Procedure 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 59 Milne Point Unit R-111 SB Injector Drilling Procedure 12-1/4 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 Gas hyrates have not been seen on Raven pad. However, be prepared for them. While the likely depths for hydrates are in the surface interval, remain vigilant. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system. 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 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 hole. Ensure to clean the hole with rotation after slide intervals if motor is used. Do not out drill our ability to clean the hole. Anti-Collison: There are wells in close proximity and deviation from plan could have a trickle-down effect on the pattern for subsequent wells. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well specific A/C: There are no wells with a CF < 1.0 Wellbore stability (running sands, Ungu coals and hard streaks): Ugnu Coals in the UG3 and UG2 have proven challenging in the first Raven Pad wells. High TOH and RIH speeds, coupled with the high sail angle, can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Ensure ghost reamer is in the drillstring and located where it will have wiped the trouble coals prior to reaching TD. Maintain mud parameters and increase MW to combat running sand formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 60 Milne Point Unit R-111 SB Injector Drilling Procedure 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 61 Milne Point Unit R-111 SB Injector Drilling Procedure 8-1/2 Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up appropriately to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. Calculate clean-hole ECD at every mud check to ensure mud properties are in alignment and to gauge hole cleaning efficiency. 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 > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is one mapped fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a ramp in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, well need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. 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. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on R- Pad. 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. Well specific AC: There are no wells with a CF < 1.0 Page 62 Milne Point Unit R-111 SB Injector Drilling Procedure 29.0 Parker 273 Layout Page 63 Milne Point Unit R-111 SB Injector Drilling Procedure 30.0 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. Constant pump rate required. - mgr Page 64 Milne Point Unit R-111 SB Injector Drilling Procedure 31.0 Parker 273 Choke Manifold Schematic Page 65 Milne Point Unit R-111 SB Injector Drilling Procedure 32.0 Casing Design Page 66 Milne Point Unit R-111 SB Injector Drilling Procedure 33.0 12-1/4 Hole Section MASP Page 67 Milne Point Unit R-111 SB Injector Drilling Procedure 34.0 8-1/2 Hole Section MASP Map Date: 7/21/2025 4 Page 69 Milne Point Unit R-111 SB Injector Drilling Procedure 36.0 Surface Plat (As-Staked) (NAD 27) 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. MPU R-111 225-097 SCHRADER BLUFF OILMILNE POINT WELL PERMIT CHECKLISTCompany Hilcorp Alaska, LLCWell Name: MILNE PT UNIT R-111Initial Class/TypeSER / PENDGeoArea890 Unit 11328On/Off ShoreOnProgram SERWell bore segAnnular DisposalPTD#:2250970Field & Pool:MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYes; ADL3906152 Lease number appropriateYes3 Unique well name and numberYes MILNE POINT, SCHRADER BLFF OIL - 525140 - governed by CO 477B4 Well located in a defined poolNo Crosses from MPU to Nikaitchuq, however there is no change in ownership5 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 waitYes Area Injection Order No. 10-D14 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)Yes16 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 grouted to 80'18 Conductor string providedYes 13-3/8"L-80 68# to SV1 Shale19 Surface casing protects all known USDWsYes 13-3/8" fully cemented from SV1 to surface. Single stage cement job w/ lead and tail20 CMT vol adequate to circulate on conductor & surf csgNo21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes Three string casing design 13-3/8" X 9-5/8 x production liner with int_ landing in reservoir23 Casing designs adequate for C, T, B & permafrostYes Parker 273 rig has adquate 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 that violate sep criteria26 Adequate wellbore separation proposedYes 16" diverter ~120' in length27 If diverter required, does it meet regulationsYes All fluids overbalance to expected pore pressure28 Drilling fluid program schematic & equip list adequateNo 1 annular, 3 ram stack tested to 3000 psi29 BOPEs, do they meet regulationYes 13-5/8" BOPE tested to 3000 psi. Rated to 5M psi30 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 remote hydraulic choke31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes MPU R pad has not H2S history. Monitoring will be required33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticipated; however, rig will have H2S sensors and alarms.35 Permit can be issued w/o hydrogen sulfide measuresYes Anticipating normally pressured reservoir.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprTCSDate10/8/2025ApprMGRDate10/3/2025ApprTCSDate10/6/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 10/8/2025