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205-099
Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 2/4/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20260204 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 223-34T 50283202060000 225059 12/31/2025 AK E-LINE Perf T41308 BRU 244-27 50283201850000 222038 1/2/2026 AK E-LINE Perf T41309 CLU 11RD 50133205590000 225013 1/2/2026 YELLOWJACKET SCBL T41310 CLU 11RD 50133205590000 225013 12/19/2025 YELLOWJACKET SCBL T41310 END 1-25A 50029217220100 197075 11/7/2025 HALLIBURTON COILFLAG T41311 END 1-25A 50029217220100 197075 12/26/2025 READ PressTempSurvey T41311 END 2-40 50029225270000 194152 12/18/2025 READ PressTempSurvey T41312 END 2-52 50029217500000 187092 12/24/2025 HALLIBURTON MFC40 T41313 END 2-56A 50029228630100 198058 1/1/2026 HALLIBURTON COILFLAG T41314 END 2-56A 50029228630100 198058 1/19/2026 READ CaliperSurvey T41314 KALOTSA 3 50133206610000 217028 1/14/2026 YELLOWJACKET PERF T41315 KALOTSA 3 50133206610000 217028 1/9/2026 YELLOWJACKET PERF T41315 KALOTSA 8 50133207050000 222003 12/18/2025 YELLOWJACKET PERF T41316 KBU 44-06 50133204980000 200179 12/22/2026 YELLOWJACKET CBL T41317 KBU 44-06 50133204980000 200179 11/12/2025 YELLOWJACKET PLUG T41317 KU 24-07RD 50133203520100 205099 1/6/2026 AK E-LINE CBL T41318 KU 24-07RD 50133203520100 205099 1/6/2026 AK E-LINE Plug/Cement T41318 KU 24-07RD 50133203520100 205099 1/1/2026 AK E-LINE Plug/Cement/TubingPunch T41318 MPI-36 50029236770000 220047 1/19/2026 READ CaliperSurvey T41319 MPI-36 50029236770000 220047 1/19/2026 READ LeakDetectLog T41319 NCIU A-19 50883201940000 224026 1/7/2025 AK E-LINE Perf T41320 NFU 42-35 50231200460000 214170 1/8/2026 YELLOWJACKET PERF T41321 NIK OI24-08 50029234570000 211130 1/19/2026 HALLIBURTON COILFLAG T41322 ODSN-04 50703206700000 213037 1/20/2026 HALLIBURTON LDL T41323 ODSN-22 50703207080000 215054 12/20/2025 READ LeakDetection T41324 PBU 15-11D 50029206530400 225112 1/18/2026 HALLIBURTON RBT-COILFLAG T41325 PBU 15-43 50029226760000 196083 12/21/2025 HALLIBURTON RBT T41326 PBU B-30B 50029215420200 225009 1/24/2026 HALLIBURTON RBT-COILFLAG T41327 PBU C-33B 50029223730200 225096 12/16/2025 HALLIBURTON RBT-COILFLAG T41328 T41318KU 24-07RD 50133203520100 205099 1/6/2026 AK E-LINE CBL T41318KU 24-07RD 50133203520100 205099 1/6/2026 AK E-LINE Plug/Cement KU 24-07RD 50133203520100 205099 1/1/2026 AK E-LINE Plug/Cement/TubingPunch Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.05 09:10:43 -09'00' 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: PBU D-26B 50029215300200 206098 12/20/2025 HALLIBURTON ISAT T41329 PBU D-26B 50029215300200 206098 12/19/2025 BAKER SPN T41329 PBU F-21A 50029219490100 225019 1/18/2026 HALLIBURTON RBT-COILFLAG T41330 PBU J-21A 50029217050100 225106 1/21/2026 HALLIBURTON RBT-COILFLAG T41331 PBU L-291 50029237790000 224002 12/26/2025 HALLIBURTON RBT T41332 PBU L-291 50029237790000 224002 12/9/2025 YELLOWJACKET RCBL T41332 PBU S-107A 50029220440200 225083 12/8/2025 HALLIBURTON RBT-COILFLAG T41333 PBU S-201A 50029229870100 219092 1/21/2026 HALLIBURTON WFL-TMD3D T41335 PBU S-24B 50029220440200 203163 12/22/2025 HALLIBURTON RBT T41334 PBU S-24B 50029230230100 203163 12/23/2025 HALLIBURTON WFL-TMD3D T41334 SRU 223-15 50133207410000 225123 1/29/2026 YELLOWJACKET GPT-PERF T41336 SRU 223-15 50133207410000 225123 1/20/2026 YELLOWJACKET SCBL T41336 SRU 233-10 50133207400000 225113 12/30/2026 AK E-LINE CBL T41337 SRU 233-10 50133207400000 225113 1/10/2026 YELLOWJACKET SCBL T41337 SRU 233-10 50133207400000 225113 1/6/2026 YELLOWJACKET SCBL T41337 SRU 34-28 50133101580000 163007 1/7/2026 YELLOWJACKET Gamma Ray T41338 SU 32-16 50133207380000 225095 1/17/2026 YELLOWJACKET GPT-PLUG-PERF T41339 SU 32-16 50133207380000 225095 11/22/2025 YELLOWJACKET SCBL T41339 SU 43-10 50133207390000 225107 12/10/2025 YELLOWJACKET SCBL T41340 TBU A-12RD 50883200320100 171029 1/2/2026 AK E-LINE StripGun T41341 TBU D-24A 50733202240100 174064 12/4/2025 AK E-LINE TubingPunch T41342 Please include current contact information if different from above. Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.05 09:11:00 -09'00' 1 Gluyas, Gavin R (OGC) From:McLellan, Bryan J (OGC) Sent:Tuesday, January 6, 2026 12:42 PM To:Zachary Browning - (C) Cc:Cody Dinger Subject:RE: Sundry 325-705 Hilcorp well KU-24-07RD CBL and CIBP Variance Request Zach, This variance request is approved. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Zachary Browning - (C) <zachary.browning@hilcorp.com> Sent: Tuesday, January 6, 2026 12:26 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Cody Dinger <cdinger@hilcorp.com> Subject: Sundry 325-705 Hilcorp well KU-24-07RD CBL and CIBP Variance Request Bryan, See attached CBL log from the 9-5/8” Casing on KU-24-07RD. TOC is seen at 1998’ MD. Variance request to regulation 25.112.(c)(2)(C) We propose to set the CIBP at 3422’ MD (35’ above the TOL tagged at 3457’MD). Per regulation CIBP is to be set within 25’ of the TOL/Casing stub, but this depth allows us to avoid a troublesome spot in the casing at 3439’MD, worked through with the scraper, and stay above a collar logged at 3432’ MD. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 Thanks, Zach Browning Drilling Engineer C: 208-301-0767 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. 1 Gluyas, Gavin R (OGC) From:McLellan, Bryan J (OGC) Sent:Thursday, December 18, 2025 12:22 PM To:Zachary Browning - (C) Cc:Cody Dinger; Stefan Reed; Regg, James B (OGC) Subject:RE: KU 24-07RD Variance Request Zach, Hilcorp has approval to test the lower ram after pulling tubing, but before RIH with whipstock, as long as the remaining BOP rams, (upper pipe ram sized for the tubing, blind ram and annular) are successfully tested before pulling tubing. Hilcorp should provide this email to the inspector that witnesses the initial BOP test. This is a change to sundry number 325-705. I don’t believe any change to the PTD application is required because the tubing will be out of hole before the PTD becomes eƯective. Let me know if you believe the PTD will also be impacted by this change. We usually require a wellhead diagram in RWO and decompletion sundries, but I missed it in this one. Please include in future sundries. Thank you Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Zachary Browning - (C) <zachary.browning@hilcorp.com> Sent: Thursday, December 18, 2025 8:21 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Cody Dinger <cdinger@hilcorp.com>; Stefan Reed <Stefan.Reed@hilcorp.com> Subject: KU 24-07RD Variance Request Bryan, On the upcoming sidetrack, we plan to rig up the full BOP (11” x 5M annular BOP/11” x 5M double ram /11” x 5M mud cross/11” x 5M single ram) for the de-complete and re-drill but overlooked the fact that 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. 2 spacer spool would be required due to the interference between the hanger neck and lowest ram cavity (see drawing below and attached). The spacer spool will not fit with the full stack due to the wellhead height of 1’ above grade. Can we receive a variance to use the full BOP stack as planned, but not test the lower single gate valve until after pulling the completion? (The lower ram is treated as a spacer spool until the completion is pulled and it is tested). MASP=1414psi. Let me know if you would like a 403 for this change or if this is something that can be noted with the PTD approval? Thanks, Zach Browning Drilling Engineer C: 208-301-0767 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. Kenai Gas Field KU 24-07RD-Current 12/29/2024 Valve, Master, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Upper master, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Swab, WKM-M 4 1/16 5M FE, HWO, EE trim Adapter, Cactus-EN-6.25'’, 11 5M stdd x 4 1/16 5M stdd top, w/ 2- 1'’npt control line exits 13 3/8'’ 9 5/8'’ Tubing head, Cactus-C29L, 13 5/8 3M x 11 5M, w/ 2- 2 1/16 5M SSO, w/ 9 5/8 HPS bottom 4 ½’’ Tubing hanger, Cactus-EN- CCL, 4 ½ EUE 8rd lift and susp x w 6 ¼ od ext neck, 4'’ type H BPV profile, DD-NL material Valve, Wing, WKM-M, 3 1/8 5M FE, HWO, DD trim Casing head, CIW-WF, 13 5/8 3M FE top x 13 3/8 SOW btm, w/ 2- 2 1/16 5M EFO Kenai Gas Field KU 24-7RD 13 3/8 x 9 5/8 x 4 1/2 Tree cap, Otis, 4 1/16 5M FE X 6 ½ Otis Quick Union 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:Daniel Taylor To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Subject:KU 24-17RD (PTD: 205-099) MIT-IA Date:Friday, October 3, 2025 3:05:09 PM Attachments:MIT KU 24-7RD 9-29-2025.xlsx Please see the attached MIT. Regards, Daniel Taylor, P.E. Well Integrity O: 907-777-8319 C: 907-947-8051 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. .HQDL8QLW5' 37' Submit to: OOPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 205-099 Type Inj N Tubing 763 766 722 720 Type Test P Packer TVD 3578 BBL Pump IA 470 2204 2197 2194 Interval O Test psi 2200 BBL Return OA 34 102 107 107 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: Class I Disposal Well - Annual MIT with EPA witnessing. Test result: PASS. EPA requires test to 2200 psi. BBL Return not recorded as part of EPA test procedure. Notes: Hilcorp, Alaska LLC Kenai Gas Field / Kenai / 41-18 Pad Jason Hobart 09/29/25 Notes: Notes: Notes: Notes: 24-7RD Form 10-426 (Revised 01/2017)2025-0929_MIT_KU_24-7RD 9 9 9 9 999 99 9 9 9 9 -5HJJ 1. 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: 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): 4,800 4,410' (Fish) Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 3,810psi Liner 5,410psi 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: Contact Email: Contact Phone: 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 WDSP 1.2 zachary.browning@hilcorp.com 208-301-0767 Drilling Manager Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Zach Browning AOGCC USE ONLY 7,240psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 390821 205-099 50-133-20352-01-00 Hilcorp Alaska, LLC Proposed Pools: 12.6# / N-80 TVD Burst 4,343 6,330psi 1,849 Size 179 2,003 MD 7" 3,728 - 3,839 3,090psi 179179 2,003 December 24, 2025 4,8001,323 4-1/2" 4,024 3,814 Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit 24-07RDEPA Permit # AK-1I018-A Same 3,2759-5/8" 1414 3,814 N/A Length ZXP Pkr / Premier Removable Pkr & N/A 3,457 (MD) 3,006 (TVD) / 4,338 (MD) 3,670 (TVD) & N/A 4,023 4,415 3,728 Kenai Gas Field Undefined WDSP 20" 13-3/8" 4,415 - 4,560 m n P s tc N 66 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 Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.11.17 16:44:46 - 09'00' Sean McLaughlin (4311) 325-705 By Grace Christianson at 8:07 am, Nov 18, 2025 X Submit CBL to AOGCC within 24 hrs of obtaining results. A.Dewhurst 19NOV25 BOP test to 2500 psi 10-407 X DSR-11/19/25 CDW 11/20/2025 11/24/2030 BJM 11/24/25 11/24/25 RWO Well: KU 24-07RD Well Name:KU 24-07RD API Number:50-133-20352-01 Current Status:Class I Disposal Well Permit to Drill Number:205-099 First Call Engineer:Zach Browning (208) 301-0767 Second Call Engineer:Sean Mclaughlin (907) 223-6794 Well Status:Class I Disposal Well Brief Well Summary KU 24-07RDis a G&I disposal well for injecting ClassIwaste into the Sterling sands that is governed byEPApermit #AK-1I018-A. The well was reclassified from a Class II well to EPA Class I well inSeptember of 2021. In September of 2024 a CTCO was attempted, but failed due to an obstruction encountered in the well, which resulted in part of a coil milling BHA being left in hole. In December of 2024 a rig workover was done to replace tubing/packer and attempted fish coil tools and clean out well. The rig was unable to retrieve coil fish or clean out the well and the new tubing and packer were run with fish/fill still in well. Due to the obstructions in well and inability to clean out the well the injection pressures have maintained near the regulatory limits. The objective of this sundry is to remove the 4-1/2 tubing and packer and prepare the well for sidetrack. Workover Procedure: 1.0 R/U and Preparatory Work (Sundry ) 1. Level pad and ensure enough room for layout of rig footprint and R/U. 2. Layout Herculite on pad to extend beyond footprint of rig. 3. R/U Hilcorp Rig #147, spot service company shacks, spot & R/U company man & toolpusher offices. 4. After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 5. 8-1/2 hole section mud program summary. Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the drillers console, Co Man office, and Toolpusher office. Ensure fluids are topped off and adequate lost circulation material is on location in anticipation of losses in hole section. RWO Well: KU 24-07RD System Type:8.8 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 2300- 4704 8.8 9.5 40-53 15-25 15-25 8.5-9.5 11.0 System Formulation:6% KCL / EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for 8.8 9.5 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 6. Install 5-1/2 liners in mud pumps. HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2 liners. 2.0 BOP N/U and Test 1. Load well with kill weight fluid (8.4ppg freshwater). 2. Install BPV. 3. N/D Tree and adapter. Install blanking sub. 4. N/U 11 x 5M BOP as follows: BOP configuration from Top down: 11 x 5M annular BOP/11 x 5M double ram /11 x 5M mud cross/11 x 5M single ram Double ram should be dressed with 7 fixed bore rams in top cavity, blind ram in bottom cavity. Single ram should be dressed with 2-7/8 x 5 variable bore rams N/U bell nipple, install flowline. Install (2) manual valves & a check valve on kill side of mud cross. Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 5. Test BOPE. Test BOP to 250/2500 psi for 5/10 min. RWO Well: KU 24-07RD 7 test joint required for FBR Test VBRs with 4-1/2 test joint Test annular to 250/2500 psi for 5/10 min with a 4-1/2 test joint Ensure to leave side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Pull blanking sub and BPV after successful test. 6. Rack back as much 4-1/2 DP in derrick as possible to be used while drilling the hole section. 3.0 Decomplete 1. PU short joint to engage hanger. 2. Overpull tubing 50klbs to release packer. 3. Pull and lay down 4-1/2 12.6# L-80 IBT-M Tubing a. Inspect tubing to be re-run. 4. RU Eline and perform following: a. Drift and tag top of fill for correlation w/ ~5.7 GR/Junk Basket b. Set 7 CIBP @ ~4340 (Not more than 50 above top of fill/fish). c. Drift & tag top of plug. Pressure test to 1500psi. i.Provide AOGCC 24hrs notice to witness tag and PT. d. Dump bail a minimum of 35 of cement (~56gals) on plug. e. Drift 9-5/8 casing w/ ~7.71 GR/Junk Basket f. Log CBL in 9-5/8 casing. g. Set 9-5/8 CIBP @ ~ 3452 (25ft above the 7 TOL) h. Drift and tag top of plug. Pressure test to 3165psi. i.Provide AOGCC 24hrs notice to witness tag and PT. ii. AOGCC requirement is 50% of burst. 9 5/8 43.5# N-80 burst is 6330 psi / 2 = 3165 psi. i. Dump bail a minimum of 35 of cement (~108gals) on plug. j. RD Eline 4.0 Set Whipstock / Mill Window Operation Steps: 1. Pull TWC. Set wear bushing in wellhead. Ensure ID of wear bushing > 8.5. 2. Make up the WIS hydraulic-set whipstock. Submit CBL to AOGCC within 24 hrs of obtaining results. g p p g p Provide AOGCC 24hrs notice to witness tag and PT.TT Be prepared to circulate higher density kill fluid. 9.4 ppg brine was required to kill the well during 10/2024 rig workover. -bjm RWO Well: KU 24-07RD 3. TIH with DP to the whipstock setting depth. Exercise caution when RIH / setting slips with whipstock assembly Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly. Avoid sudden starts and stops while running the whipstock. Recommend running in the hole at a maximum of 90-120 seconds per stand taking care not to spud or catch the slips. Ensure running string is stationary prior to insertion of the slips and that slips are removed slowly when releasing the work string to RIH. These precautions are required to avoid any weakening of the whipstock shear mechanisms and / or to avoid part / preset on the packer. 4. Orient whipstock as directed by the directional driller. The directional plan (wp2) specifies 30 deg LOHS. 5. Set the top of the whipstock at ~2300 MD Confirm exact set depth with 9-5/8 collar location from Eline logs to avoid milling a collar. Mill Window under permit to drill. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. BOP Diagram 1 2 Lease: State: Country:USA (TVD) Dated Completed: 41 ° @ 3,777' Perforations (MD): Kenai Peninsula Borough 4,415' - 4,560' Revised By:DMA Last Revison Date:1/21/2025 Completion Fluid:9.4ppg NaCl Well Name & Number:KU 24-7RD Kenai Gas Field Angle/Perfs: AlaskaCounty or Parish: 3,728' - 3,838' Angle @ KOP and Depth: KU 24-7RD Pad 41-18 728' FNL, 748' FEL Sec. 18, T4N, R11W, S.M. Drive Pipe: 20" 94ppf H-40 Top Bottom MD 0' 179" TVD 0' 179' Surface Casing: 13 3/8" 61ppf K-55 Top Bottom MD 0' 2,003' TVD 0' 1,849' 17-1/2" Hole cmt w/1,225 sks 9 5/8" 47# N-80 Csg Window @ 3,777 ' - 3,814' Tubing Detail 4 1/2" 12.6#, N-80 IBT Mod Tubing 1. Tripoint DHL Hydratrieve Packer @ 4,217' (50K shear to release) 2. XN nipple @ 4,223' ID=3.725" Liner 7" 26 ppf N-80 mod butt Top Bottom MD 3,477' 4,800' TVD 3,023' 4,023' 8-1/2" Hole cmt w/ 200sx class "G" Liner hanger w/ ZXP Packer @ 3,457' Permit #:205-099API #: 50-133-2035201 Property Des: A-028142 KB Elevation: 87' (21' AGL) WBS #: Latitude: Longitude: X: 275,057.001 Y:2,356,013.0011 Spud:06/24/2005 (sidetrack)TD: 06/22/2005 Rig Released: Tbg Hanger: 27' TD 4,800' MD 4,023' TVD Production Casing: 9-5/8" 43.5 & 47ppf N-80 Top Bottom MD 0' 3,814' (Window) Perforations: 3-3/8" HSC 6spf (7/20/05); Pool 3 MD TVD A10 4,415' - 4,485' 3,728' - 3,781' A11 4,530' - 4,560' 3,816' - 3,839' PBTD 4,701' MD 3,947' TVD Tubing Hanger (12/20/24) Hgr w/4-1/2" EUE 8RD lift & suspend 4" Type "H" BPV profile Fisha. Coil Milling motor - 2.43" tapered mill w/ broken 2-1/8" motor - 11.34' long - See Wellfile @ 4410'b. overshot assembly - 3.63" OD x 4.36" long See Wellfile @ 4405'c.Tortilla chip shoe 5-7/8" OD x 2.29' long @ 4364'. See wellfile Notes: (12/20/24) Suspected damaged casing at 4351' KB, trouble spot during workover. 1 Lease: State: Country:USA (TVD) Kenai Peninsula Borough 4,415' - 4,560' 3,728' - 3,838' Angle @ KOP and Depth: Revised By:DMA Last Revison Date:1/21/2025 Completion Fluid:9.4ppg NaClDated Completed: Well Name & Number:KU 24-7RD Kenai Gas Field Angle/Perfs: AlaskaCounty or Parish: 41 ° @ 3,777' Perforations (MD): KU 24-7RD Pad 41-18 728' FNL, 748' FEL Sec. 18, T4N, R11W, S.M. Decomplete Proposal Drive Pipe: 20" 94ppf H-40 Top Bottom MD 0' 179" TVD 0' 179' Surface Casing: 13 3/8" 61ppf K-55 Top Bottom MD 0' 2,003' TVD 0' 1,849' 17-1/2" Hole cmt w/1,225 sks 9 5/8" 47# N-80 Csg Window @ 3,777 ' - 3,814' Liner 7" 26 ppf N-80 mod butt Top Bottom MD 3,477' 4,800' TVD 3,023' 4,023' 8-1/2" Hole cmt w/ 200sx class "G" Liner hanger w/ ZXP Packer @ 3,457' Permit #:205-099API #: 50-133-2035201 Property Des: A-028142 KB Elevation: 87' (21' AGL) WBS #: Latitude: Longitude: X: 275,057.001 Y:2,356,013.0011 Spud:06/24/2005 (sidetrack)TD: 06/22/2005 Rig Released: Tbg Hanger: 27' TD 4,800' MD 4,023' TVD Production Casing: 9-5/8" 43.5 & 47ppf N-80 Top Bottom MD 0' 3,814' (Window) Perforations: 3-3/8" HSC 6spf (7/20/05); Pool 3 MD TVD A10 4,415' - 4,485' 3,728' - 3,781' A11 4,530' - 4,560' 3,816' - 3,839' PBTD 4,701' MD 3,947' TVD Fisha. Coil Milling motor - 2.43" tapered mill w/ broken 2-1/8" motor - 11.34' long - See Wellfile @ 4410'b. overshot assembly - 3.63" OD x 4.36" long See Wellfile @ 4405'c.Tortilla chip shoe 5-7/8" OD x 2.29' long @ 4364'. See wellfile Notes: (12/20/24) Suspected damaged casing at 4351' KB, trouble spot during workover. For Decomplete: 1. Set Whipstock @ ~ 2,300' MD 2. CIBP @ 3432' MD and dump 35' of cmt on plug 3. CIBP @ 4340' MD and dump 35' of cmt on plug 1 2 3 RWO Well: KU 24-07RD RIG 147 BOP Schematic Sundry Application Well Name______________________________ (PTD _________; Sundry _________) Plug for Re-drill Well Workflow This process is used to identify wells that are suspended for a very short time prior to being re-drilled. Those wells that are not re-drilled immediately are identified every 6 months and assigned a current status of "Suspended." Step Task Responsible 1 The initial reviewer will check to ensure that the "Plug for Redrill" box in the upper left corner of Form 10-403 is checked. If the "Abandon" or "Suspend" boxes are also checked, cross out that erroneous entry and initial it on the Form 10-403. Geologist 2 If the Abandon box is checked in Box 15 (Well Status after proposed work) the initial reviewer will cross out that checkbox and instead, check the "Suspended" box and initial those changes. Geologist The drilling engineer will serve as quality control for steps 1 and 2. Petroleum Engineer (QC) 3 When the RA2 receives a Form 10-403 with a check in the "Plug for Redrill" box, they will enter the Typ_Work code "IPBRD" into the History tab for the well in RBDMS. This code automatically generates a comment in the well history that states "Intent: Plug for Redrill." Research Analyst 2 4 When the RA2 receives Form 10-407, they will check the History tab in RBDMS for the IPBRD code. If IPBRD is present and there is no evidence that a subsequent re-drill has been completed, the RA2 will assign a status of SUSPENDED to the well bore in RBDMS. The RA2 will update the status on the 10-407 form to SUSPENDED, and date and initial this change. If the RA2 does not see the "Intent: Plug for Redrill" comment or code, they will enter the status listed on the Form 10-407 into RBDMS. Research Analyst 2 5 When the Form 10-407 for the redrill is received, the RA2 will change the original well's status from SUSPENDED to ABANDONED. Research Analyst 2 6 The first week of every January and July, the RA2 and a Geologist or Reservoir Engineer will check the "Well by Type Work Outstanding" user query in RBDMS to ensure that all Plug for Redrill sundried wells have been updated to reflect current status. At this same time, they will also review the list of suspended wells for accuracy and assign expiration dates as needed. Research Analyst 2 Geologist or Reservoir Engineer KU 24-7RD 325-705 A.Dewhurst 19NOV25 A.Dewhurst 19NOV25 205-099 1 McLellan, Bryan J (OGC) From:McLellan, Bryan J (OGC) Sent:Monday, November 24, 2025 2:15 PM To:'Zachary Browning - (C)' Cc:'Joleen Oshiro' Subject:RE: [EXTERNAL] KU 24-07RD (PTD 205-099) plug for redrill sundry Zach, Thanks for the call. I understand that the kill weight uid density will be dependent on how long the injector has been shut in prior to the decompletion. During a 10/2024 RWO, 9.4 ppg uid was required to kill the well. I am planning to sign o on the sundry based on the understanding that Hilcorp will be prepared to weight up as needed to kill the well prior to pulling tubing. No further reply is necessary at this time. Thank you Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: McLellan, Bryan J (OGC) Sent: Monday, November 24, 2025 8:42 AM To: 'Zachary Browning - (C)' <zachary.browning@hilcorp.com> Cc: Joleen Oshiro <Joleen.Oshiro@hilcorp.com> Subject: RE: [EXTERNAL] KU 24-07RD (PTD 205-099) plug for redrill sundry Zach, thanks for the Wellhead pressure data. Hi Joleen. Is there a way to estimate the reservoir pressure in the disposal injection zone at this injection well? During the workover performed on this well last year, 9.4 ppg brine was required to kill the well. At one point on 10/6/24, Hilcorp calculated a 14.3 ppg EMW based on uid in the well and WHP. Zachs estimate of 550 psi at 3816 TVD seems very low given what they saw during the RWO. The decompletion sundry application calls for fresh water to be used as kill weight uid. Will fresh water be adequate to maintain overbalance in this well? 2 Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Zachary Browning - (C) <zachary.browning@hilcorp.com> Sent: Friday, November 21, 2025 9:54 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Joleen Oshiro <Joleen.Oshiro@hilcorp.com> Subject: RE: [EXTERNAL] KU 24-07RD (PTD 205-099) plug for redrill sundry Bryan, See attached injection log data from KU 24-7RD. This shows the injection volume and tubing pressure over time starting in 2013 until Jan 2025. You can see the WHP bleeds to zero if given time. Ive also copied Joleen, who is the RE on the project. Thanks, Zach From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, November 20, 2025 3:31 PM To: Zachary Browning - (C) <zachary.browning@hilcorp.com> Subject: RE: [EXTERNAL] KU 24-07RD (PTD 205-099) plug for redrill sundry Zach, Do you have any bottomhole pressure survey or WHP/uid level data for this or other wells injecting into this disposal zone? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 3 From: Zachary Browning - (C) <zachary.browning@hilcorp.com> Sent: Thursday, November 20, 2025 2:49 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] KU 24-07RD (PTD 205-099) plug for redrill sundry Thank you sir! The 450-550psi expected pressure comes from RFT pressure data taken in 2020 in the A-11 sand in o set wells KU 42-12 and KU 24-32 showing pressures of 461 and 507psi. I understand your concern about the injection zone increasing in pressure, but due to the size of the sterling tank, we expect it to still be depleted in comparison with our maximum pressure planned at TD. Feel free to call me directly if this doesnt answer your question. Thanks, Zach Browning Drilling Engineer C: 208-301-0767 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, November 20, 2025 12:49 PM To: Zachary Browning - (C) <zachary.browning@hilcorp.com> Subject: RE: [EXTERNAL] KU 24-07RD (PTD 205-099) plug for redrill sundry Hey Zach. Welcome back to Alaska. The reservoir pressure in the current wellbore, 450-550 psi @ 3728 TVD seems super low, especially for an injection zone. How was that pressure determined? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 4 From: Zachary Browning - (C) <zachary.browning@hilcorp.com> Sent: Thursday, November 20, 2025 12:42 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] KU 24-07RD (PTD 205-099) plug for redrill sundry Bryan, Hey man, good afternoon! Hope you are doing well. See my answers below in blue. Thanks, Zach From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, November 20, 2025 11:50 AM To: Zachary Browning - (C) <zachary.browning@hilcorp.com> Subject: [EXTERNAL] KU 24-07RD (PTD 205-099) plug for redrill sundry Zach, Im reviewing the plug for redrill sundry. A couple question: 1. What is the current reservoir pressure and TVD used to determine max anticipated surface pressure in this well? A reservoir pressure of 1766psi at TD of 4013ft TVD was used for our max anticipated surface pressure. Note this is a max anticipated pressure at the TD of the planned drill. The expected pressure at the current perforations in KU 24-7RD in the A10/A11 sands is much lower at ~450-550psi (3728/3816 TVD). 2. How will the results of the 9-5/8 CBL impact the planned sidetrack? What decisions are to be made based on results? The only CBL we have of the 9-5/8 casing was from 5/25/82, 2 days after the primary cement job. The log quality is marginal, and we would expect some of the lead cement would have still been building compressive strength at that time. That said, the log indicates there is cement isolation above our planned KOP. The planned CBL is to con rm cement isolation at the kicko point and collar location. This will inform us if there is any need to adjust our whipstock depth to target higher quality cement at the window and likewise avoid milling a collar. Thanks Bryan McLellan CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 5 Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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: 10/16/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251016 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# END 2-36 50029220140000 190024 9/17/2025 BAKER SPN T40994 END 2-74 50029237850000 224024 9/22/2025 HALLIBURTON PATCH T40995 KU 12-17 50133205770000 208089 9/23/2025 YELLOWJACKET TEMP-CALIPER T40996 KU 24-7RD 50133203520100 205099 9/24/2025 YELLOWJACKET TEMP-CALIPER T40997 M-25 50733203910000 187086 8/31/2025 YELLOWJACKET CALIPER T40998 MPC-22A 50029224890100 195198 10/4/2025 READ CaliperSurvey T40999 MPF-61 50029225820000 195117 9/27/2025 READ CaliperSurvey T41000 MPU H-16 50029232270000 204190 10/6/2025 HALLIBURTON COILFLAG T41001 NIK SI17-SE2 50629235120000 214041 9/23/2025 HALLIBURTON IPROF T41002 NS-19 50029231220000 202207 9/8/2025 HALLIBURTON COILFLAG T41003 NS-19 50029231220000 202207 9/15/2025 HALLIBURTON COILFLAG T41003 ODSN-26 50703206420000 211121 10/7/2025 HALLIBURTON MFC24 T41004 PBU 01-25A 50029208740100 225056 9/13/2025 BAKER MRPM T41005 PBU 01-25A 50029208740100 225056 9/13/2025 HALLIBURTON RBT-COILFLAG T41005 PBU 01-31A 50029216260100 225070 9/22/2025 BAKER MRPM T41006 PBU 01-31A 50029216260100 225070 9/23/2025 HALLIBURTON RBT-COILFLAG T41006 PBU 05-09A 50029202540100 199014 9/18/2025 READ ArcherVIVID T41007 PBU 07-16A 50029208560100 201153 9/20/2025 HALLIBURTON RBT T41008 PBU 07-23C 50029216350300 225043 7/4/2025 BAKER MRPM T41009 PBU 13-24B 50029207390200 224087 9/18/2025 HALLIBURTON RBT T41010 PBU 15-11C 50029206530300 210163 9/6/2025 HALLIBURTON RBT T41011 PBU 15-49C 50029226510300 215129 9/10/2025 HALLIBURTON RBT T41012 PBU H-07B 50029202420200 225064 9/30/2025 HALLIBURTON RBT-COILFLAG T41013 PBU P19 L1 50029220946000 212056 10/3/2025 HALLIBURTON RBT T41014 PBU S-14A 50029208040100 204071 9/25/2025 HALLIBURTON RBT T41015 PBU V-105 50029230970000 202131 9/30/2025 HALLIBURTON RMT3D T41016 Please include current contact information if different from above. KU 24-7RD 50133203520100 205099 9/24/2025 YELLOWJACKET TEMP-CALIPER Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.20 13:17:06 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: CTCO Development Exploratory 3. Address:Stratigraphic Service 6. API Number: WDSP 1.2 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic and printed data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 4,800 feet N/A feet true vertical 4,023 feet See Schematic feet Effective Depth measured 4,364 feet 3,457; 4,217 feet true vertical 3,690 feet 3,006; 3,579 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / N-80 4,223' MD 3,583' TVD ZXP Pkr; 3,457' MD 3,006' TVD Packers and SSSV (type, measured and true vertical depth)Tript DHL Hydratrieve Pkr; N/A 4,217' MD 3,579' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:See attached report 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL I&II Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: measured Packer Plugs Junk measured Length 3,810psi 3,090psi 6,330psi 2,003'1,849' Burst Collapse 1,540psi measured true vertical Production Liner 3,814' 1,323' Casing Structural 3,275' 7" 3,814' 4,800'4,023' 179'Conductor Surface 2,003' TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 205-099 50-133-20352-01-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA022330; FEDA028142 Kenai Gas Field / Undefined WDSP Kenai Unit (KU) 24-7RD Gas-Mcf MD 360 Size 179' 450 4620 0 3600 881 7,240psi 9-5/8" Intermediate 20" 13-3/8" 179' chelgeson@hilcorp.com 907-777-8405 Chad Helgeson, Operations Engineer 324-480 & 324-535 Sr Pet Eng: 5,410psi Sr Pet Geo:Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 See attached report Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 p k ft t Fra O s 6. A G P W G , O Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 3:11 pm, Jan 31, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.01.31 14:29:08 - 09'00' Noel Nocas (4361) DSR-1/31/25BJM 3/17/25 SFD 2/27/2025 RBDMS JSB 040125 Page 1/2 Well Name: KEU KU 24-07RD Report Printed: 1/21/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:8/27/2024 End Date: Report Number 1 Report Start Date 9/3/2024 Report End Date 9/4/2024 Last 24hr Summary PTW, JSA. MIRU Fox Energy CTU 8 with 1.75" coil. Spot fluid tanks and support equipment. Presssure test BOPE as per Sundry and AOGCC requirement of 250/3500 psi. SITP 1300 psi. RIH to 3000'. Perform pre FCO injection test. 1.5 bbls/min 1535 psi, 2.0 bbls/min 2000 psi, 3.0 bbls/min 1800 psi. Dry tag Previous obstruction noteed on schematic at 4420 CTMD (4415 on schematic). Wash thourgh interval multiple times and perform two bottoms up from 4420'. POOH to surface. Perform post FCO injectivity test. No change from pre FCO test. N2 coooled down. blow reel dry and RDMO. Report Number 2 Report Start Date 9/11/2024 Report End Date 9/12/2024 Last 24hr Summary Prepare equipment. Mobe to location. PTW, JSA. MIRU Fox Energy CTU 8 with 1.75" coil. Spot fluid tanks and support equipment. Presssure test BOPE as per Sundry and AOGCC requirement of 250/3500 psi. SITP 1487 psi. Witness waived by JIm Regg on 9/11/2024. Report Number 3 Report Start Date 9/12/2024 Report End Date 9/13/2024 Last 24hr Summary Complete RU of CT equipment. RIH w/ 1.75'' slick tool string w/1.75'' jetting nozzle. Tag at 4421' CTM. Made several attempts to pass by obstruction, no success. POH, discuss with town on next run. RIH with 2.76'' Parabolic mill. Tag at 4410', mill and pass through tight spot. Tag up at 4421' and mill on obstruction. No progress made. Report Number 4 Report Start Date 9/13/2024 Report End Date 9/14/2024 Last 24hr Summary RIH w/ 2.43'' taper mill. Tag at 4410', w/400 psi differential pressure and 800 lbs on mill. At 4411', saw differential pressure loss to 50 psi below circulating pressure. Continue down slowly and pass through tight spot, tag up at 4419'. No indication of motor working. POH to surface, motor broke off at top sub. Wait on slickline, RIH w/3.62'' LIB, tag up at 4373'. POH, RIH 2.25'' LIB, tag up at 4373'. SDNF. Report Number 5 Report Start Date 9/14/2024 Report End Date 9/15/2024 Last 24hr Summary SL continued with bailer runs getting fill and metal shavings with 5 runs, until tagged hard. Ran a centralized LIB and got impression of fish. RIH w/ baited series 70 overshot to 4382'. Could not latch, spangs stuck. replaced spangs. POOH without overshot. RIH w/ GR, but unable to latch OS, no spang action with 2 runs. SDFN. will continue fishing in the morning. Report Number 6 Report Start Date 9/15/2024 Report End Date 9/16/2024 Last 24hr Summary SL made multiple attempts to latch or fish YJ overshot @ 4390'. Unable to latch. Had no spang action on any runs. Ran decentralized LIB got partial Impression of baitsub on overshot at 10:30. Report Number 7 Report Start Date 9/16/2024 Report End Date 9/16/2024 Last 24hr Summary PTW/PJSM. RU Fox CT unit and RIH with 3.5" wash nozzle on 1.75" CT. Tag TOF @ 4,403' CTM. CBU 2x and pump 15 bbl gel sweep to surface. CBU holding 200 psi backpressure and POOH. RU Pollard Slickline. RIH w/ 3.5" LIB 2x with no marks. RIH w/ 3" bailer 2x and getting course sand/gravel. SDFN. Report Number 8 Report Start Date 9/17/2024 Report End Date 9/17/2024 Last 24hr Summary PTW/PJSM. RU Pollard Slickline. RIH w/ 3" bailer and bail fill from 4,387'-4,390' and fell past fish. RIH w/ 3.5", 2.64", and 3" LIB's on multiple tool configurations- only getting small impression on outer edge. RIH w/ 3" GR pulling tool (3 runs) with multiple tool configurations. Tag fish @ 4,387', work tools but not latching. SDFN. Report Number 9 Report Start Date 9/18/2024 Report End Date 9/18/2024 Last 24hr Summary PTW/PJSM. RU Pollard Slickline. RIH w/ 3" bailer 2X to clear fill from top of fish. RIH w/ LIB's on multiple tool configurations to identify fish- 5 runs, no luck. Perform injectivity test and were able to inject 213 bbls @ 4 BPM and 2037 psi. RIH w/ 3" LIB centralized and tag @ 4,385'. OOH- good indication of fish. SDFN. Report Number 10 Report Start Date 9/19/2024 Report End Date 9/19/2024 Last 24hr Summary PTW/PJSM. RU Pollard Slickline. RIH w/ 3" GR pulling tool (3 runs) with no luck fishing. Tagging fish higher each run. RIH w/ 3" bailer and tag @ 4,381', WT and came back full of fine mud. RD Pollard. RU Fox CT for BOP test. Test BOPE to 250/3500 psi - good test. Test witness waived by Jim Regg (9/18 @ 07:33). SDFN. Report Number 11 Report Start Date 9/20/2024 Report End Date 9/20/2024 Last 24hr Summary PTW/PJSM. RU Fox CT. SITP 1400 psi. PT lubricator and stripper to 250/3500 psi- good test. RIH w/ GS spear on hydraulic centralizer while injecting @ 2 BPM. Tag fish @ 4,401' CTM, PU and set down 3x. POOH- no fish. RIH w/ 3" LIB while injecting, tag fish @ 4,402' CTM. POOH- fish indication on outer edge of LIB. RIH w/ 3.685" overshot/grapple while injecting, tag fish and slip off. Make multiple attempts to engage fish at different rates with no luck. POOH- no fish. SDFN. Field: Kenai Gas Field Sundry #: 324-480 State: ALASKA Rig/Service: Coil #8Permit to Drill (PTD) #:205-099Permit to Drill (PTD) #:205-099 Wellbore API/UWI:50-133-20352-01-00 Page 2/2 Well Name: KEU KU 24-07RD Report Printed: 1/21/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 12 Report Start Date 9/21/2024 Report End Date 9/21/2024 Last 24hr Summary PTW/PJSM. RU Fox CT. SITP 1560 psi. G&I injecting 1.2-2.0 BPM, maintaining 2200psi. RIH w/ 3.5" LIB on a mechanical centralizer. Tag TOF @ 4,402' CTM. POOH- good indication of overshot fish slightly off center. RIH w/ 3.685" overshot (2.75" grapple) on a mechanical centralizer. Tag @ 4,407' with pumps off. PU 20', pumps on @ 1 BPM show 150 psi increase. Tag @ 4,407' 3X (pumps on) and POOH. OOH- no fish. Decision to RD coil. RD coil, secure well, SDFN. Report Number 13 Report Start Date 9/22/2024 Report End Date 9/22/2024 Last 24hr Summary PTW/PJSM. MIRU Pollard slickline. SITP 1550 psi. PT lubricator to 250/2000 psi - good test. G&I injecting 2 BPM @ 2200 psi. RIH w/ 3.45" LIB and decentralizer, tag @ 4,386' slm and POOH - slight indication of fish on outer edge of LIB. RIH w/ same on bowspring centralizer, tag same with same result on LIB. RIH w/ 3" bailer, tag @ 4,385', WT and no progress, POOH- empty. RIH w/ 3.45" LIB, BS, and KJ- tag same with same result. RIH w/ 3" GR pulling tool (3 runs) with multiple tool configurations. Tag @ 4,391' slm (5' deeper), WT at multiple depths, no fish. RD Pollard and secure well. Field: Kenai Gas Field Sundry #: 324-480 State: ALASKA Rig/Service: Coil #8 Page 1/4 Well Name: KEU KU 24-07RD Report Printed: 1/15/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:9/25/2024 End Date: Report Number 1 Report Start Date 10/1/2024 Report End Date 10/2/2024 Last 24hr Summary Prep and move rig from KU 12-17. Lay down pit liner. Spot equipment, base beam, and rig. Raise, scope, and secure mast. Bled Tbg from 1700 psi to zero (14 bbls). Cont. RU misc equipment and circulating lines. Bled IA from 500 psi to zero. Held open bleed additional 2 hours. Shut-in Tbg and IA. Monitor for build-up. Both Tbg and IA built positive pressure over 1 hour. Resume open bleed on both. Report Number 2 Report Start Date 10/2/2024 Report End Date 10/3/2024 Last 24hr Summary Continue to bleed and monitor Tbg and casing. No flow. Positive pressure after bleeds are shut-in. Weight up pits w/ NaCl to 9.4 ppg. RU AK EL. Ran 2" OD Tbg punch and tagged in 4-1/2 Tbg @ 3728' (600' above packer). Ran 1-11/16" tools and tag same depth. RD EL and RU Pollard SL. RIH w/ 3-1/2" bailer. Tag @ 3603' WLM (3624' MD) Recovered sandy slurry. Multiple runs w/ 2-1/2" bailer. Tag @ 3720' and work to 3723' WLM (3744' MD) Recovered sandy slurry and small to 1" solids. Stopped getting much back in bailer. Ran spear to break up solids. RU to bullhead. Report Number 3 Report Start Date 10/3/2024 Report End Date 10/4/2024 Last 24hr Summary Bullhead 17 bbls in attempt to clear solids from tubing. Final pressure 1800 psi @ .6 bpm. Shut down monitor. SITP stabilized @ 1750 psi. Slickline ran 3.70" gauge ring to 4391' MD (EOT @ 4354') Did not tag. POH and stand back Slickline. Slowly bled tbg from 1750 psi to zero in 3 hours w/ 4.1 bbls returned. Maintain open bleed. RIH w/ 3.70" gauge ring. Tagged fill @ 4256' WLM (4277 MD) Resume bailing. Recovering ~3 gallons of slurry with ~3 cups of solids each run. Made no noticeable footage. On bailer run #7, tagged 18' higher @ 4237' WLM (4258 MD) Continue bailing - same recovery. Losing some hole. Current depth 4228'. No pressure noted or gain in bleed tank. Report Number 4 Report Start Date 10/4/2024 Report End Date 10/5/2024 Last 24hr Summary Continue bailing slurry/solids 4220 - 4226'. Bullhead 79 bbls FW to clear tbg 1 bpm @ 1800 psi. Drift out EOT w/ 3.70" gauge ring. . RD SL. MIRU YJ EL. MU and RIH w/ 1-9/16" Tbg Punch (3/8") 2' loaded @ 4 SPF. Punch in 6' pup just above packer @ 4326 - 4328'. Attempt to circulate and reverse. No flowpath. MU and RIH w/ 1-9/16" Tbg Punch (3/8") 3' loaded @ 4 SPF. Punch in bottom of 1st full joint above packer @ 4319 - 4322'. Attempt to pump into casing to 2400 psi. No flowpath. Pump down tbg and bleed casing to zero. Break circulation. Pump into casing w/ FW @ 1.5 bpm. Returns from tbg lined up to closed choke. Initial pressures Casing 1930, Tbg 1800 psi. Start dropping tbg pressure in 50 psi increments to slowly bleed off formation and circulate solids to surface. At 04:30 the tbg pressure is @ 1525 psi. Pumping 1.4 bpm and returning 1.6 to 2 bpm. Total of 299 away and 321 bbls returns Report Number 5 Report Start Date 10/5/2024 Report End Date 10/6/2024 Last 24hr Summary Continue pumping down casing 1.8 bpm taking returns from Tubing to circ out solids. Drop Tbg pressure from 1425 psi gradually to 150 psi. Big slug of solids. Hold ~400 psi on choke while clearing Tbg. After solids mostly cleared, graduallly drop tbg pressure to 150 psi. Minimal solids returning but gaining ~30 bbls/hr from formation. Pump 15 bbl gel sweep. Slight increase in solids when sweep to surface. Suspect Tbg tail plugged. RIH w/ slickline and tag fill @ Tbg punch holes @ 4326' MD. Attempt to bullhead to clear tubing. Locked up @ 2275 psi w/ 1.7 bbls away. RIH w/ slickline. Tag fill @ 4326' MD work down to 4329' MD. POH. Report Number 6 Report Start Date 10/6/2024 Report End Date 10/7/2024 Last 24hr Summary Monitor Tbg pressure. Built up to 1122 or 14.3 EMW. RIH w/ SL 2.5" bailer. Tag @ 4299' WLM (4316 MD) Circulate down casing w/ returns from Tbg until clean @ 1300 psi. Tag @ 4301' WLM. Bailed to 4315' in 3 runs (4336 KB). Start RD to move to Steelhead M-25. Blow down and RD. Transfer 330 bbls 9.4 NaCl from rig to storage tank on the pad. Scope and layover mast. Continue to prep for trucks. Report Number 7 Report Start Date 10/7/2024 Report End Date 10/8/2024 Last 24hr Summary Continue prep for truck loads, break down berming, load trailers, Pull rig eq off liner, move to Middle pad, Roll up liner. Dem obe Crews. Report Number 8 Report Start Date 10/10/2024 Report End Date 10/10/2024 Last 24hr Summary Bail From 4331' RKB to 4353' RKB Approx 22' Last run do not Pressure up Lub - See Pressure Drop from 1640 to 1200 Tag 1' Higher at 4352' RKB- Bailing Debries Included Large chucks of Coal, Rocks, Fine Silt Sand Report Number 9 Report Start Date 10/14/2024 Report End Date 10/14/2024 Last 24hr Summary PTW/PJSM. MIRU Pollard Slickline. SITP/IA= 1300 psi. RIH w/ 3" bailer and tag @ 4,348', WT and no progress, bailer full of fine mud. RIH w/ same and tag @ 4,340', WT and no progress, bailer full of fine mud. RIH w/ 3.5" bailer and tag @ 4,332', WT to 4,334', bailer full of fine mud and large gravel. SITP and IA now 0 psi. RIH w/ same (4 runs) and bail from 4,339'-4,346', and got stuck near XN. WT and ~15 jar licks and came free. RIH w/ 3" bailer and WT to 4,347'. POOH, secure well, and SDFN. Report Number 10 Report Start Date 10/15/2024 Report End Date 10/15/2024 Last 24hr Summary Bail fill from 4346' to 4355'kb lose spangs every runs attempt to set pxn pug Field: Kenai Gas Field Sundry #: 324-535 State: ALASKA Rig/Service: 401Permit to Drill (PTD) #:205-099Permit to Drill (PTD) #:205-099 Wellbore API/UWI:50-133-20352-01-00 Sy Continue to bleed and monitor Tbg and casing. No flow. Positive pressure after bleeds are shut-in )qp g p Both Tbg and IA built positive pressure over 1 hour. Resume open bleed on both. Page 2/4 Well Name: KEU KU 24-07RD Report Printed: 1/15/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 11 Report Start Date 10/16/2024 Report End Date 10/17/2024 Last 24hr Summary Brush packer & xn nipple attemt to set pxn plug-had issues getting thru packer Report Number 12 Report Start Date 10/31/2024 Report End Date 11/1/2024 Last 24hr Summary Move in and tie in bleed back tank. T/IA/OA 650/650/50 psi. Bleed off tbg slowly to 0 psi. Monitor T/IA. Shut in T/IA. Monitor PBU on T/IA overnight to 100 psi. Report Number 13 Report Start Date 11/3/2024 Report End Date 11/4/2024 Last 24hr Summary PJSM/PTW. MIRU Slickline unit. Bleed off T/IA to 0 psi from 200 psi. PT lub to 2500 psi. RIH w/3''x 6' DD bailer. Tag at 4323' SLM/4344' KB. POH to surface, bailer 1/2 full of mud and a few pieces of small chunks. Decision made to RDMO to Cannery Loop. Report Number 14 Report Start Date 11/12/2024 Report End Date 11/12/2024 Last 24hr Summary Set well house Report Number 15 Report Start Date 11/24/2024 Report End Date 11/25/2024 Last 24hr Summary Disconnect & Pull wellhouse, lay liner, set carrier to well center. Continue mobe rig eq. from HVB pad. Raise and scope derrick, secure. Set remaining rig support equipment. Run electrical. R/u circulating lines. Install berming around liner. Offload necessary equipment from trailers and stage. Winterize equipment. Report Number 16 Report Start Date 11/25/2024 Report End Date 11/26/2024 Last 24hr Summary Finalize rig up and winterization. Organize and clean. Cover equipment in preparation for crews going on days off. Report Number 17 Report Start Date 12/4/2024 Report End Date 12/5/2024 Last 24hr Summary BAIL DOWN PAST NIPPLE - TAG NIPPLE - BRUSH PACKER Report Number 18 Report Start Date 12/6/2024 Report End Date 12/7/2024 Last 24hr Summary Crew arrive on location, warm up equipment. Run hoses to circulate well and fill pits w/ 9.4ppg brine. Circulate STS, pumping brine down tubing and up IA. Well static after circulating. Set BPV, nipple down tree. prep wellhead, install test blanking sub. Nipple up BOPE. Test BOPE with 3-1/2" and 4-1/2" test joints as per AOGCC's and Hilcorps expectations, 250/3000psi. Test witnessed by AOGCC inspector Josh Hunt. Test sensors and gas alarms. Report Number 19 Report Start Date 12/7/2024 Report End Date 12/8/2024 Last 24hr Summary Finish testing BOPE with 3-1/2" and 4-1/2" test joints as per AOGCC's and Hilcorps expectations, 250/3000psi. Test witnessed by AOGCC inspector Josh Hunt. Test sensors and gas alarms and perform koomey drawdown test. 1 fail pass on BOP misc. for not having whip check on choke line. R/d test eq. Pull BPV. Circulate a tubing volume w/ 9.4 brine, well static. R/u YJ EL, M/u Landing jt. BOLDS, p/u and unseat hanger at 55k. Picked up 30k over and set pipe in slips. M/u 2.5" RCT, RIH tag 4348', not enough depth to log packer, POOH. RIH with CCL tag 4348', logged pass of packer. RIH with 2.5" RCT, tied in and cut packer across cut zone at 4336'. POOH. Picked up on pipe, attempt to work pipe to free packer, no luck. RIH with 2.5" RCT, tied in and cut packer across cut zone at 4335.5'. POOH. Work pipe trying to free packer, no luck. E-line m/u 3.5" jet cutter, RIH, make cut at 4325'(1' below collar on pup above packer). Good cut. R/d e-line. Pull hanger to surface, 50k p/u wt. and l/d. Prep to l/d tubing. POOH laying down 4-1/2" 12.6# N-80 IBT tubing from 4325' to 1288'. Report Number 20 Report Start Date 12/8/2024 Report End Date 12/9/2024 Last 24hr Summary POOH Lay down 4-1/2" IBT f/1288' t/surface. L/d 102jts and 1' cut joint. Cleaned and cleared rig floor. R/u power swivel, hung in derrick. Tally 3-1/2" PH6 wk string, layout and strapped fishing tools. M/u milling BHA w/ 6"OD 4 7/8"ID Burn Shoe. RIH with Milling BHA, tagging TOF at 4321' (joint 137). L/d joint 137. R/u power swivel and rotating head. M/u joint 137 and RIH. Run hoses to reverse circulate. Get power swivel parameters, rot p/u wt 52k, rot s/o wt 40k, 60rpm, off btm tq 1k, 3bpm, 350 psi. Dress off tubing stump at 4321'. Work down to packer at 4326'. Pressure climbing when trying to burn over packer while reverse circulating. Switch circulating directions and continue burning over packer. Report Number 21 Report Start Date 12/9/2024 Report End Date 12/10/2024 Last 24hr Summary Cont burning over packer f/4326' t/4327'. Pickup off fish, rev CBU returns with metal shavings. Cont burning over packer f/4327' t/4331'. Lost torque, tried several parameters to regain torque no luck, packer appears to be spinning free. P/u off fish and rev circ 2x bottoms up until retruns were clean. Recovered metal shaving, rubber and coil. R/d swivel and changed out handing eq. Pooh w/ milling shoe BHA. L/d milling shoe BHA. Shoe has some wear, boot baskets have a couple cups of shavings, no big chunks. M/u 3-1/4" spear w/ 3.958" grapple BHA. RIH w/ spear BHA to 4321'. P/u wt 44k, s/o wt. 32k. Engage fish down to 4323'. P/u seeing overpull, straight pull to 75 over, no luck. Jar on fish staging up to max 66k over jar licks to straight pull of 86k over. Report Number 22 Report Start Date 12/10/2024 Report End Date 12/11/2024 Last 24hr Summary Continue jarring on fish, not seeing any movement. Discussed with OE, released spear off fish. POOH f/4323' t/surface. M/u milling BHA w/ 6"OD 4 7/8"ID Burn Shoe. RIH with milling BHA. M/u adaptor spool and rotating head on annular. R/u power swivel. Get swivel parameters. Notices leak on swivel, getting part coming from rig tenders. Mechanics repair leak. RIH and tag packer at 4328', seeing torque on btm between 1500-3000 ft-lbs. Not getting any wt. back, torque is rhythmic and not seeing it bite. Mess with parameters but not seeing any change, still tagging fish at same depth. Inform OE, get the ok to POOH. P/u off fish and reverse circulate 1.5 bottoms up. Recovered minimal metal on magnets. R/d power swivel. POOH with milling BHA f/ 4328' to 75'. Start laying down milling BHA. Field: Kenai Gas Field Sundry #: 324-535 State: ALASKA Rig/Service: 401 Test witnessed by AOGCC inspector Josh Hunt. Page 3/4 Well Name: KEU KU 24-07RD Report Printed: 1/15/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 23 Report Start Date 12/11/2024 Report End Date 12/12/2024 Last 24hr Summary L/d milling BHA, no wear on the face or inside of burn shoe, fish is spinning downhole. Wait on yellow jacket to dress a wavy bottom burn shoe. Housekeeping and maintenance while waiting. M/u milling BHA w/ 6"OD x 4 7/8"ID Wavy bottom Burn Shoe. RIH with milling BHA on 3-1/2" to 4320'. R/u power swivel. Get parameters: rot p/u wt 42k, rot s/o wt 38k, neutral wt 40k, free tq 1800 ft-lbs, 60 rpm, 2.5 bpm, 250 psi. Run in w/ mill, tagging packer at 4328'. Mill on packer w/ 1- 6k WOB, tq 1500-3000 ft-lbs fluctuating tq, trying to work past spinning lower cone. Alter parameters trying to get mill to bite. shut pump off and dry drill, reverse circulating bottoms up occasionally. Report Number 24 Report Start Date 12/12/2024 Report End Date 12/13/2024 Last 24hr Summary Continue dry milling on lower cone in packer, ROT 120rpm, stage WOB to 10k. Not seeing torque, cone is still spinning. Turn pump on to circulate and found wash pipe packing leaking on swivel. Install new wash pipe and packing on swivel. Circulate bottoms up to test out packing, no leaks. Resume dry milling on lower cone in packer. Max Rotation, stage up to 15k down on mill. Circulating 5bbls every hour to keep swivel cool. Seeing erratic spikes in torque every so often. Change up parameters occasionally, seeing if something will change. Report Number 25 Report Start Date 12/13/2024 Report End Date 12/14/2024 Last 24hr Summary Continue milling on lower cone in packer, no movement. Picked up 5' leaving shoe over tbg stump. R/d swivel, prep for EL. R/u e-line.RIH w/ 4' string shot set down in BHA at 4284', (Log shows btm boot basket). Couldn't work through. R/u circ eq. Circulated tbg volume to try and clear. RIH with string shot set down same spot, couldn't work through POOH. R/d EL. POOH w/milling BHA and l/d. Drift all components of BHA w/ 2.13" drift. Found upset in boot basket drift wouldn't pass. M/u 4-3/4"ID x 5-3/4"OD cut lip overshot w/ mesh and 4-1/2" grapple BHA. RIH tag TOF at 4321'. R/u power swivel. Dress off stump, engage fish w/ overshot grapple. Beat down trying to free packer. Neutral wt 40k. Max p/u 140k, s/o 30k. No movement seen. Report Number 26 Report Start Date 12/14/2024 Report End Date 12/15/2024 Last 24hr Summary Continue beating down trying to free packer. No movement down. Fired jar, pickup 20k over, packer moved up hole. R/d swivel. POOH, singling out until past 7" liner top, stand back remaining. Pulled OS to surface. Recovered tbg stump, packer, pup jt, XN nipple, pup jt and muleshoe. Prep to test BOPE. Preformed Shell test with 3-1/2" test joint. Found leak on door seal for the bilnd and pipe rams. Replaced door seals. Fluid pack and test seals, no leaks. Test BOPE with 3-1/2" and 4-1/2" test joints as per AOGCC's and Hilcorps expectations, 250/3000psi. All tests passed no fails. Test witness waived by AOGCC's Jim Regg. Gas detection tested on 12/7/24. R/d from testing, r/u slick line. Slick line make 9 runs w/ 3-1/2"x7' DD bailer initial tag at 4349' KB deepest 4368', Bailer full of slurry. add knuckle jar when string started to stick, spangs are getting gummed up in slurry and don't always hit. Seeing some coal and a couple cunks of rubber on last couple runs. Report Number 27 Report Start Date 12/15/2024 Report End Date 12/16/2024 Last 24hr Summary Slick line continue bailing, unable to make it past 4370' KB. Run LIB getting impression of sand and metal marks on side. RDSL. R/u handling equipment. M/u cleanout BHA w/ 4.5" Mule Shoe. RIH with cleanout BHA to 3268'. Strap and tally pipe on skate. Single in, tagging at 4378', p/u seeing 10k overpull, l/d joint. R/u power swivel, wash pipe leaking, r/d power swivel. M/u kelly on stump. wash down to 4355' at 4 bpm, 600psi. Reverse same until clean. Continue washing down until tagging at 4367' w/ 2k down, weight not washing off. Circulate surface to surface, getting back small pieces of coal and dirty water at BU. Prep to POOH. Report Number 28 Report Start Date 12/16/2024 Report End Date 12/17/2024 Last 24hr Summary POOH standing back work string f/4367' t/surface. L/d 4-1/2" mule shoe and pup. Metal marks and bottom of the mule shoe. MIRU slick line. Slick line RIH with 4.75" LIB, tag at 4358', impression of fill. RIH w/ 2-1/2" bailer w/bow spring centralizers multiple times, tagging at 4376' w/t to 4378', getting back coal, rubber and thick slurry. RIH w/ 3.5" bailer, unable to pass 4366, bailer full of fluid. RIH w/ GR to 4383', no bite. Run GR w/ centralizers, get friction bite w/ 400# overpull at 4382', seeing 100-200# overpull at 4366'. Run 3.5" LIB to 4380' , impression inconclusive. Last run w/ GR tool, no bite. R/d SL. M/u fishing shoe BHA w/ 5-7/8"x3- 1/2" tortilla chip shoe. RIH on PH6 workstring to 2365'. NOTE: possible compromised casing @ 4366'kb having issues w/ length vs. O.D. Report Number 29 Report Start Date 12/17/2024 Report End Date 12/18/2024 Last 24hr Summary Continue RIH wi wk string, tagged at 4351' with 4k down. Picked up with 20k over to pull free. R/u power swivel. Online with pump 3bpm and found swivel leaking from washpipe packing. Replaced packing. Get swivel parameters, worked down starting see tq at 4346 ' working down to 4352', stalled and pick up 20k over. Continued trying to work passed 4352', trying different parameters with no luck, POOH. Pull wash pipe and shoe. 1.26' of shoe remaining out of 3.55' (2.29' left in hole). Shoe looks to have fractured across cut windows. Discuss options with OE. decision made to run tapered mill. M/u BHA w/ 3.35" to 5.45" tapered mill. RIH w/ tapered mill tagging at 4343'. Work to engage fish trying to get friction bite w/ mill. Fish gets pushed past tight spot. Chase fish down to 4364'. Stack 20k down, p/u. Acting like fish is on, seeing slight over pull. Report Number 30 Report Start Date 12/18/2024 Report End Date 12/19/2024 Last 24hr Summary POOH f/4363' t/BHA. See min drag coming off bottom. No fish recovered, few metal markers on mill. M/u BHA w/ 2.75" to 4.75" tapered tap. RIH with BHA on 3- 1/2" wk string. Tag at 4351', able to work through tight spot, tagging again at 4364'. R/u power swivel. Put 2k down, put a few turns into pipe and get weight back, repeat once more total travel 3', putting tapered tap at 4367'. P/u seeing initial overpull of 32k, broke over, seeing a little drag while picking up. R/d power swivel completely. Single out of hole, l/d 40 joints, placing bottom of BHA at 3131' (7" liner top at 3477'). P/u 9-5/8" storm packer, run packer in hole on 1 stand, set packer. Test packer to 3000psi for 5 minutes, good test. R/d equipment in order to swap out tubing spool. Pull tubing spool. Field: Kenai Gas Field Sundry #: 324-535 State: ALASKA Rig/Service: 401 ,g gpgpp P/u 9-5/8" storm packer, run packer in hole on 1 stand, set packer.pyg , j ,p g ( p ) Test packer to 3000psi for 5 minutes, good test. R/d equipment in order to swap out tubing spool. Pull tubing spool. Page 4/4 Well Name: KEU KU 24-07RD Report Printed: 1/15/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 31 Report Start Date 12/19/2024 Report End Date 12/20/2024 Last 24hr Summary Wellhead hands dressed off 9-5/8" csg stump. Installed new tubing head and N/u BOP stack. Welder had to modify cross beam for grating to Install 2-1/16" IA valve. Hooked up remaining BOP components. PT BOP breaks 250-3000psi, chart for 5mins good test. M/u stinger for 9-5/8" storm packer, RIH with 1 stand, m/u to packer, open bypass, monitor well, well static. Pull packer and L/d. POOH l/d wk string f/3131' t/BHA. L/d BHA, no fish on tapered tap, see wear on one side on top of tap ~1" wide by 8" long. R/u YJ e-line. E-line RIH w/caliper logging tool to 4353' ELM (zeroed tool at rig floor). Log up from 4353' to surface. R/d e-line. Lay out 4-1/2" IBT completion. Strap, tally, and number. Dress out handling equipment for 4-1/2". Start picking up and putting away equipment that is not needed. Report Number 32 Report Start Date 12/20/2024 Report End Date 12/21/2024 Last 24hr Summary Pick up 7" Hydratrieve packer w/tail pipe assy, RIH p/u 4 1/2" L-80 12.6# IBT mod tubing. t/4192', M/U hanger, rih land hanger placing tubing tail @4223'. RILD pins, drop ball & rod. Pressure up t/3900psi setting packer @4217', start pressure 3900, 15 min 3810, 30 min 3800 good. R/u on IA. MIT-IA to 2500psi for 30 minutes charted. Initial pressure 2760 psi, 15 minutes 2755 psi, 30 minutes 2755 psi, good test. Set BPV. R/d floor, n/d BOP. Prep wellhead, N/u tree. Pull BPV install TWC. Test void and hanger neck seals to 5000psi for 10 minutes, good test. Fill tree w/ 9.4 brine and test to 5000psi, good test. Pull TWC and secure well. R/d auxiliary equipment. Prep to lay over mast, scope down and lay over mast. Continue loading equipment and baskets on trailers. Start removing berming in preparation to truck equipment to KU 13-06A. Report Number 33 Report Start Date 12/31/2024 Report End Date 1/1/2025 Last 24hr Summary Completed MIT-IA with AOGCC Witness (Bob Noble) and remote witness via Teams by EPA (Tim Mayers) to 2000 psi. Passed. SL MIRU and pulled RHCP plug. RDMO turn over to ops. Field: Kenai Gas Field Sundry #: 324-535 State: ALASKA Rig/Service: 401 Sy Completed MIT-IA with AOGCC Witness (Bob Noble) and remote witness via Teams by EPA (Tim Mayers) to 2000 psi. Passed. SL MIRU and pulled RHCP plug.p RDMO turn over to ops. 1 2 Lease: State: Country:USA (TVD) Dated Completed: 41 ° @ 3,777' Perforations (MD): Kenai Peninsula Borough 4,415' - 4,560' Revised By:DMA Last Revison Date:1/21/2025 Completion Fluid:9.4ppg NaCl Well Name & Number:KU 24-7RD Kenai Gas Field Angle/Perfs: AlaskaCounty or Parish: 3,728' - 3,838' Angle @ KOP and Depth: KU 24-7RD Pad 41-18 728' FNL, 748' FEL Sec. 18, T4N, R11W, S.M. Drive Pipe: 20" 94ppf H-40 Top Bottom MD 0' 179" TVD 0' 179' Surface Casing: 13 3/8" 61ppf K-55 Top Bottom MD 0' 2,003' TVD 0' 1,849' 17-1/2" Hole cmt w/1,225 sks 9 5/8" 47# N-80 Csg Window @ 3,777 ' - 3,814' Tubing Detail 4 1/2" 12.6#, N-80 IBT Mod Tubing 1. Tripoint DHL Hydratrieve Packer @ 4,217' (50K shear to release) 2. XN nipple @ 4,223' ID=3.725" Liner 7" 26 ppf N-80 mod butt Top Bottom MD 3,477' 4,800' TVD 3,023' 4,023' 8-1/2" Hole cmt w/ 200sx class "G" Liner hanger w/ ZXP Packer @ 3,457' Permit #:205-099API #: 50-133-2035201 Property Des: A-028142 KB Elevation: 87' (21' AGL) WBS #: Latitude: Longitude: X: 275,057.001 Y:2,356,013.0011 Spud:06/24/2005 (sidetrack)TD: 06/22/2005 Rig Released: Tbg Hanger: 27' TD 4,800' MD 4,023' TVD Production Casing: 9-5/8" 43.5 & 47ppf N-80 Top Bottom MD 0' 3,814' (Window) Perforations: 3-3/8" HSC 6spf (7/20/05); Pool 3 MD TVD A10 4,415' - 4,485' 3,728' - 3,781' A11 4,530' - 4,560' 3,816' - 3,839' PBTD 4,701' MD 3,947' TVD Tubing Hanger (12/20/24) Hgr w/4-1/2" EUE 8RD lift & suspend 4" Type "H" BPV profile Fisha. Coil Milling motor - 2.43" tapered mill w/ broken 2-1/8" motor - 11.34' long - See Wellfile @ 4410'b. overshot assembly - 3.63" OD x 4.36" long See Wellfile @ 4405'c.Tortilla chip shoe 5-7/8" OD x 2.29' long @ 4364'. See wellfile Notes: (12/20/24) Suspected damaged casing at 4351' KB, trouble spot during workover. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Monday, January 27, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Bob Noble P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC 24-7RD KENAI UNIT 24-7RD Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 01/27/2025 24-7RD 50-133-20352-01-00 205-099-0 N SPT 3670 2050990 2200 312 602 597 593 28 102 102 101 OTHER P Bob Noble 12/31/2024 Class 1 well. Yearly MIT-IA to 2200 psi required. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:KENAI UNIT 24-7RD Inspection Date: Tubing OA Packer Depth 994 2422 2417 2415IA 45 Min 60 Min Rel Insp Num: Insp Num:mitRCN250101154043 BBL Pumped:1 BBL Returned:1 Monday, January 27, 2025 Page 1 of 1 9 9 9 9 9 9 9 99 999 99 9 9 9 Class 1 well James B. Regg Digitally signed by James B. Regg Date: 2025.01.27 11:08:31 -09'00' 2024-1207_Rig_Hilcorp401_W-O _compliance_KU_24-7RD_jh Page 1 of 4 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO:Jim Regg DATE:12-8-2024 P. I. Supervisor FROM:Josh Hunt SUBJECT:Compliance Inspection Petroleum Inspector Hilcorp Rig 401 Kenai Unit 24-07RD Hilcorp Alaska LLC PTD 2050990; Sundry 324-535 12-7-2024:I traveled to location and met with Brad Whitten representing Hilcorp. They weren’t quite ready to test BOPE yet, so I decided to ask him about some of the compliance requirements set for Hilcorp workover operations. An email dated 10/21/2015 established conditions for restart of rig workover operation following an AOGCC-directed safety shutdown (10/1/2015) – copy attached; focus is on rig and rig staffing items. Wellsite (Rig) Supervision. There are different rig supervisors per work shift as well as with the rig crew supervisors. Stop Work Authority. Everyone I spoke to about this seemed aware of the policy, but it was not posted anywhere in the office or around the rig anywhere that I could find, nor could they produce the document (this was around 01:00 in the morning). They made some calls and emails to locate the document. Laminated copies were posted around the rig and in the office before I departed the rig. Management of Change. When asked about the workover specific management of change process for this rig, they initially had no idea. Some calls and emails were made and eventually found this document as well. Wade Hudgens (on-coming Wellsite Supervisor) arrived at the rigsite, and he remembered the 2015 incidents and the management of change document. He said it use to be attached to the sundries, but he hadn’t seen it in quite a while. Training. I spoke with several of the rig crew individually, several of them have their well control training and seem to be very rig wise. They’d all been through Hilcorp’s orientation program and were trained in the Stop Work Authority policy, the rig alarm system, and rig safety systems. 9 9 9 9 9 9 9 9 gp copy attached James B. Regg Digitally signed by James B. Regg Date: 2025.01.02 12:03:27 -09'00' 2024-1207_Rig_Hilcorp401_W-O _compliance_KU_24-7RD_jh Page 2 of 4 Rig Winterization. Rig crew and supervisors were asked about a rig specific BOPE testing procedure for sub-freezing weather and were able to produce this document. As I went around the rig, I noticed they’ve done a lot of work to this rig for winterization, including: - A large Dragon fire heater to heat under the subbase and the cellar. - The pits, choke, and mud pump were all enclosed and had their own individual heaters - enclosures were very warm inside. - The cellar was enclosed by insulated walls which were hanging from the bottom of the rig floor and seemed to work well and provide extra heat for the guys on the rig floor. - Most of the lines coming from the mud pump, the pits, and the choke are insulated. - There is a new aluminum doghouse for the driller which is also heated and houses the remote BOP controls. - No-slip fiberglass grating is used on the Herculite footprint used for the rig to help prevent slipping. I feel like they have made significant weatherization improvements since I first worked around this rig. There were ZERO freezing issues while testing BOPE. There is a Hilcorp Mechanic on location to keep everything running smoothly and keep up on maintenance. Attachments: Photos (4) Rig Workover Restart Conditions (email dated 10/21/2015) 9 9 9 2024-1207_Rig_Hilcorp401_W-O _compliance_KU_24-7RD_jh Page 3 of 4 Workover Rig Compliance – Hilcorp 401 Kenai Unit 24-7RD (PTD 2050990) Photos by AOGCC Inspector J. Hunt 12/7/2024 2024-1207_Rig_Hilcorp401_W-O _compliance_KU_24-7RD_jh Page 4 of 4 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KENAI UNIT 24-7RD JBR 01/30/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:2 This is the second time I showed up to location and the high pressure whip checks weren't hooked up on the choke and kill lines in the cellar. Last time I mentioned it and they were hooked up. This time they went ahead and started testing prior to anyone checking them or hooking them up. Tested with 3-1/2" & 4-1/2" Test joints. F/P on Annular, functioned and passed. F/P on BOP Misc for high pressure whip checks on choke and kill lines in cellar. Test Results TEST DATA Rig Rep:Ryan Chabre/Tyson ReOperator:Hilcorp Alaska, LLC Operator Rep:Wade Hudgens / Brad Whitt Rig Owner/Rig No.:Hilcorp 401 PTD#:2050990 DATE:12/7/2024 Type Operation:WRKOV Annular: 250/3000Type Test:INIT Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopJDH241208141025 Inspector Josh Hunt Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 7.5 MASP: 2200 Sundry No: 324-535 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 0 NA Lower Kelly 0 NA Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 8 PNo. Valves 2 PManual Chokes 0 NAHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13-5/8" 5K FP #1 Rams 1 2-7/8"x 5" V P #2 Rams 1 Blinds P #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 4-1/16" 5K P HCR Valves 1 4-1/16" 5K P Kill Line Valves 3 2-1/16, 4-1/16 P Check Valve 0 NA BOP Misc 1 Whip check FP System Pressure P3000 Pressure After Closure P2100 200 PSI Attained P21 Full Pressure Attained P90 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P6@1700 ACC Misc NA0 NA NATrip Tank P PPit Level Indicators NA NAFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA Annular Preventer P17 #1 Rams P9 #2 Rams P7 #3 Rams NA0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill NA0 99999 9 9 9 9 9 9 9 FPAnnular Preventer BOP Misc Whip check FP second time I showed up to location and the high pressure whip checks weren't hooked up on the choke and kill lines F/P on Annular F/P on BOP From:Regg, James B (DOA) To:David Wilkins (dwilkins@hilcorp.com); John Barnes; Bo York Cc:Foerster, Catherine P (DOA); Seamount, Dan T (DOA); Schwartz, Guy L (DOA); DOA AOGCC Prudhoe Bay Subject:Restart of Hilcorp Rig Workovers Date:Wednesday, October 21, 2015 5:25:30 PM Conditions for Hilcorp to restart rig workover (RWO) ops: -Establish a single Hilcorp person responsible for RWO’s; this individual would be the signature authority that certifies info provided in a workover Sundry application is true, work will be conducted in accordance with AOGCC regulations, orders, and conditions of approval, and that the Sundry information will not be altered except as approval by AOGCC -Provide detailed operations procedures in the Sundry applications -Sundry applications that have pumping operations as part of the rig workover must include proposed piping/fluid path diagrams (include valve positions) and list of all fluids to be pumped -Prior written approval from AOGCC is required for changes to an approved Sundry -Develop and provide a documented management-of-change process applicable to rig workovers -There must be a different Wellsite (Rig) Supervisor per work shift on all Hilcorp-operated rigs -Train rig personnel in hazard identification, rig safety systems and their capabilities, proper response to potentially hazardous conditions, and Hilcorp’s “Stop Work Authority”; provide documentation of training materials and list of who has been trained -Post at appropriate locations in rig modules Hilcorp’s “Stop Work Authority” policy and procedure -Provide Hilcorp’s current RWO schedule for Cook Inlet and North Slope rigs (include rig; well; start date; simple description of the type of workover – e.g., replace ESP; prep for sidetrack; etc.); provide the updated schedule at least monthly -Workover rigs not currently working will be inspected by AOGCC prior to commencing work with a focus on winterization (equipment suitable to reliably operate under the range of weather conditions that may be encountered at the location); written rig-specific BOPE testing procedures that account for subfreezing conditions; operations and property maintenance conducted in a safe and skillful manner in accordance with good oilfield engineering practices Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 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 Jim Regg at 907-793-1236 or jim.regg@alaska.gov. 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: 12/05/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241217 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 12A 50133205300100 214070 8/17/2024 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 9/26/2024 YELLOWJACKET PERF-GPT BCU 24 50133206390000 214112 8/19/2024 YELLOWJACKET PERF BCU 25 50133206440000 214132 9/27/2024 YELLOWJACKET PLUG-PERF BLOSSOM 1 50133206480000 215015 9/30/2024 YELLOWJACKET GPT-PLUG-PERF HV B-17 50231200490000 215189 9/23/2024 YELLOWJACKET GPT KU 24-7 50133203520100 205099 10/3/2024 YELLOWJACKET PERF KU 13-06A 50133207160000 223112 12/5/2024 AK E-LINE Plug Setting KU 22-6X 50133205800000 208135 12/8/2024 AK E-LINE Perf KU 23-07A 50133207300000 224126 12/7/2024 AK E-LINE CBL MPU L-17 50029225390000 194169 10/5/2024 YELLOWJACKET PERF MPU R-103 50029237990000 224114 10/14/2024 YELLOWJACKET CBL MPU C-23 50029226430000 196016 11/29/2024 AK E-LINE Plug/cement MPU D-01 50029206640000 181144 11/26/2024 AK E-LINE Perf PBU 13-24B 50029207390200 224087 9/26/2024 YELLOWJACKET CBL PBU 06-07A 50029202990100 224043 9/29/2024 BAKER MRPM PBU 06-18B 50029207670200 223071 10/1/2024 BAKER MRPM PBU 07-32B 50029225250200 204128 10/28/2024 BAKER SPN PBU 14-32B 50029209990200 224073 10/12/2024 BAKER MRPM PBU H-13A 50029205590100 209044 10/23/2024 BAKER SPN PBU L2-20 50029213760000 185134 10/7/2024 BAKER SPN PBU L3-22A 50029216630100 219051 10/9/2024 BAKER PEARL 10 50133207110000 223028 9/25/2024 YELLOWJACKET GPT-PERF PEARL 11 50133207120000 223032 8/29/2024 YELLOWJACKET GPT-PLUG-PERF SRU 241-33 50133206630000 217047 8/23/2024 YELLOWJACKET PERF Please include current contact information if different from above. T39863 T39864 T39865 T39868 T39869 T39870 T39871 T39872 T39873 T39875 T39874 T39867 T39866 T39876 T39877 T39880 T39878 T39879 T39881 T39882 T39883 T39884 T39885 T39886 T39887 KU 24-7 50133203520100 205099 10/3/2024 YELLOWJACKET PERF Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.18 08:35:44 -09'00' CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Noel Nocas To:Regg, James B (OGC); Chad Helgeson; McLellan, Bryan J (OGC) Cc:Donna Ambruz; Wade Hudgens Subject:Re: [EXTERNAL] RE: KU 24-07RD (PTD# 205-099) Sundry #324-535 tubing head swap Date:Friday, December 6, 2024 10:57:56 AM Attachments:KU 24-7RD Rolling Test Procedure 2024.pdf Jim, Please see attached rolling test procedure. Chad is travelling so may be in and out of communication. Thank you, Noel ---- Noel Nocas Hilcorp Alaska, LLC noel.nocas@hilcorp.com From: Regg, James B (OGC) <jim.regg@alaska.gov> Sent: Friday, December 6, 2024 9:47 AM To: Chad Helgeson <chelgeson@hilcorp.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Wade Hudgens <Wade.Hudgens@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: [EXTERNAL] RE: KU 24-07RD (PTD# 205-099) Sundry #324-535 tubing head swap Hilcorp’s rolling test contingency was not included in approved Sundry 324-535; please provide procedure for the well file. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Friday, December 6, 2024 6:51 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Regg, James B (OGC) .HQDL8QLW5' 37' rolling test procedure Sundry #324-535 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. <jim.regg@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Wade Hudgens <Wade.Hudgens@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: KU 24-07RD (PTD# 205-099) Sundry #324-535 tubing head swap Bryan, We are finally starting on the workover on KU 24-07RD (Sundry #324-535), and we cannot get the tubing hanger to test on 24-07RD. We may need a rolling BOP test this weekend if it is the hanger body seals. We will also need to replace the tubing head on the well, which will require us to set a storm packer and ND the BOP stack and NU a new tubing head. Attached is the new wellhead diagram for this well with the new tubing hanger. The new steps to the procedure are: 16. PU storm packer 17. RIH and set storm packer, test packer to 2000 psi 18. ND BOP 19. Install new tubing hanger for 4-1/2” tubing 20. NU BOP and test break, function test the rest of the BOP stack Please let us know if you have any questions or need additional information on these requests. Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Rolling BOP Test Procedure Hilcorp Alaska, LLC – Rolling BOP Test Procedure for 24-07RD (Dec 2024) Rolling BOP Test procedure a. Utilize BPV/TWC and test sub at the hanger per normal operations. b. Rolling Test a. Need to station hands in cellar going over all connections on the BOPs looking for the slightest leak. Also need a man stationed at IA monitoring for flow (fluid packed well) b. Test the remaining BOPE components while continuing to pump, (Continue to monitor the surface equipment for leaks to ensure that there is zero leaking anywhere at surface.) c. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. (250psi low / 3000psi High) d. Once the targeted BOPE components have been tested with this rolling procedure, test any remaining components of the BOPE system following the normal test procedure (floor valves, gas detection, etc.…) c. Pull test joint and test sub d. Verify well is still dead with 0psi on tubing and inner annulus e. Continue per sundry. f. Any BOPE components that could only be tested initially via the rolling test should be retested following the normal test procedure as soon as practical during operations. 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Chemical Treatment Development Exploratory 3. Address: Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 4,800 feet N/A feet true vertical 4,023 feet 4,415 (fill)feet Effective Depth measured 4,415 feet 3,457; 4338 feet true vertical 3,728 feet 3,006; 3,670 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / N-80 4,343' MD 3,674' TVD ZXP Pkr; 3,457' MD 3,006' TVD Packers and SSSV (type, measured and true vertical depth)Premier Removeable Pkr; N/A 4,338' MD 3,670' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: See attached report 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: measured Packer Plugs Junk measured Length 3,810psi 3,090psi 6,330psi 2,003' 1,849' Burst Collapse 1,540psi measured true vertical Production Liner 3,814' 1,323' Casing Structural 3,275' 7" 3,814' 4,800' 4,023' 179'Conductor Surface 2,003' TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 205-099 50-133-20352-01-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA022330; FEDA028142 Kenai Gas Field / Undefined WDSP Kenai Unit (KU) 24-7RD Gas-Mcf MD 437 Size 179' 0 3490 0 5200 658 7,240psi 9-5/8" Intermediate 20" 13-3/8" 179' casey.morse@hilcorp.com 907-777-8322 Casey Morse, Integrity Engineer 324-277 Sr Pet Eng: 5,410psi Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 See attached report Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 2:59 pm, Jun 05, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.06.05 10:55:06 - 08'00' Noel Nocas (4361) Page 1/1 Well Name: KEU KU 24-07RD Report Printed: 5/15/2024www.peloton.com Alaska Weekly Report - Operations Jobs Actual Start Date: End Date: Report Number 1 Report Start Date 5/12/2024 Report End Date 5/13/2024 Last 24hr Summary MIRU HAK hot oil turck and Xylene ISO. PT lines 250/2500 psi. G&I pre flush 200 bbls of hot water at 158*F. Pumped 75 bbls of xylene down tubing with hot oil truck. Post flush with 25 bbls of produced water. Soak for 15 minutes. G&I pump continue as per procedure with 2x 25 bbl hot water pump and soak for 15. Pumped remaining xylene at 72 bbls. Displace with 16 bbls of water. Turn back over to G&I to finish displacment . G&I had recorded spreadsheet with rates pressures and times. Field: Kenai Gas Field Sundry #: 324-277 State: ALASKA Rig/Service:Permit to Drill (PTD) #:205-099Permit to Drill (PTD) #:205-099 Wellbore API/UWI:50-133-20352-01-00 Lease: State: Country:USA (TVD) 3,728' - 3,838' Angle @ KOP and Depth:41 ° @ 3,777' Perforations (MD): Revised By:DMA Last Revison Date:1/19/2024 Completion Fluid:6% KCLDated Completed: Well Name & Number:KU 24-7RD Kenai Gas Field Angle/Perfs: AlaskaCounty or Parish:Kenai Peninsula Borough 4,415' - 4,560' KU 24-7RD Pad 41-18 728' FNL, 748' FEL Sec. 18, T4N, R11W, S.M. Drive Pipe: 20" 94ppf H-40 Top Bottom MD 0' 179" TVD 0' 179' Surface Casing: 13 3/8" 61ppf K-55 Top Bottom MD 0' 2,003' TVD 0' 1,849' 17-1/2" Hole cmt w/1,225 sks 9 5/8" 47# N-80 Csg Window @ 3,777 ' - 3,814' Tubing Detail 4 1/2" 12.6#, N-80 Tubing 1. Premier Removable Packer @ 4,338' 2. XN nipple @ 4,343' ID=3.725" Liner 7" 26 ppf N-80 mod butt Top Bottom MD 3,477' 4,800' TVD 3,023' 4,023' 8-1/2" Hole cmt w/ 200sx class "G" Liner hanger w/ ZXP Packer @ 3,457' Permit #:205-099 API #: 50-133-2035201 Property Des: A-028142 KB Elevation: 87' (21' AGL) WBS #: Latitude: Longitude: X: 275,057.001 Y:2,356,013.0011 Spud:06/24/2005 (sidetrack) TD: 06/22/2005 Rig Released: Tbg Hanger: 27' TD 4,800' MD 4,023' TVD Production Casing: 9-5/8" 43.5 & 47ppf N-80 Top Bottom MD 0' 3,814' (Window) Perforations: 3-3/8" HSC 6spf (7/20/05); Pool 3 MD TVD A10 4,415' - 4,485' 3,728' - 3,781' A11 4,530' - 4,560' 3,816' - 3,839' PBTD 4,701' MD 3,947' TVD SCHEMATIC Obstruction @ 4,415' 12/23/23 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: CTCO Development Exploratory 3. Address:Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic and printed data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 4,800 feet N/A feet true vertical 4,023 feet 4,415 (fill)feet Effective Depth measured 4,415 feet 3,457; 4338 feet true vertical 3,728 feet 3,006; 3,670 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / N-80 4,343' MD 3,674' TVD ZXP Pkr; 3,457' MD 3,006' TVD Packers and SSSV (type, measured and true vertical depth)Premier Removeable Pkr; N/A 4,338' MD 3,670' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: measured Packer Plugs Junk measured Length 3,810psi 3,090psi 6,330psi 2,003'1,849' Burst Collapse 1,540psi measured true vertical Production Liner 3,814' 1,323' Casing Structural 3,275' 7" 3,814' 4,800'4,023' 179'Conductor Surface 2,003' TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 205-099 50-133-20352-01-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA028142 Kenai Gas Field / Undefined WDSP Kenai Unit (KU) 24-7RD Gas-Mcf MD 852 Size 179' 0 5520 0 20760 1376 7,240psi 9-5/8" Intermediate 20" 13-3/8" 179' chelgeson@hilcorp.com 907-777-8405 Chad Helgeson, Operations Engineer 323-679 Sr Pet Eng: 5,410psi Sr Pet Geo:Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov Chris Kanyer, Asset Team Lead 907-777-8377 for Noel Nocas By Grace Christianson at 12:37 pm, Jan 22, 2024 Digitally signed by Chris Kanyer (1235) DN: cn=Chris Kanyer (1235) Date: 2024.01.22 11:58:58 - 09'00' Chris Kanyer (1235) DSR-1/26/24 RBDMS JSB 013024 Page 1/1 Well Name: KEU KU 24-07RD Report Printed: 1/19/2024www.peloton.com Well Operations Summary Jobs Actual Start Date:12/21/2023 End Date: Report Number 1 Report Start Date 12/21/2023 Report End Date 12/22/2023 Operation Hold JSA/Safety meeting. MIRU Fox Energy CTU #8 with 1.75" CT Rig up CTU, Fluid pump, Return and supply tanks. Install BOPE on wellhead. Make up 1502 hard iron and fluid supply hoses. Spot auxillary equipment, heater, light plant, triplex. Test witness waived by Jim Regg via email. Test BOPE 250/3500 psi. Issues with pump while filling reel. Found cement stuck in suction valve seat. Continue with BOPE test. Test results passed. Pop off well. Make up CTC, DFCV, Stinger, Down jet nozzle. All 2.125" OD. 8' in length. Stab on well. PT stack 250/3500 psi. RIH Initial WHP 1300 psi , Dry tag at 4137' CTMD. Pick up and establish pumping parameters. 1.5 bbls/min 2400 psi. Start FCO. Power outage on the Kenai Peninsula, Not able to source fluids from water well. Get 100 bbl load from Rig 169. At 4254' Having issues with skid pump. Losing depth after wiper trip. Rig down skid pump/rig in Fox double pumper. Found inline filter screen plugged with solids. Having pump issues with Fox double pumper as well. Not able to achieve lockup. Max rate 1.3 bbls/min. Continue to troubleshoot pump for circulating. Continue FCO. Gel sweep bottoms up plugged up 1502 fittings on return lines. Reroute and clear solids. Max depth achieved 4411' CTMD. POOH at 80% displacement while chasing last gel sweep. Tagged up at surface. Shut in well. 0 psi on tubing. Cooled down N2. Blow reel dry. Rack back injector head. Hold tailgate meeting and discuss proper procedure to secure intervention equipment and isolate from G&I process. G&I will pump a test run of 300 bbls at max allowable rate. Location walk around completed. SD. Turn well over to G&I. 330 bbls pumped. Returned estimated 400 bbls. +70 bbls flowed from formation. This estimate may be off due to pump issues. Report Number 2 Report Start Date 12/22/2023 Report End Date 12/23/2023 Operation Fox crews arrive onsite, clean and prep equipment. Cruz vac truck arrives and transfers fluids to G&I. Equipment staged and ready for cleanout tomorrow. Report Number 3 Report Start Date 12/23/2023 Report End Date 12/24/2023 Operation Arrive on location. Complete PTW w/Ops. Spot pumps (skid and cement unit - for pump). Pick up injector head & PCE. Stab on well w/2-1/8" CTC, DFCV, Stinger, DJN. BHA = 7' OAL Pumped 1.5 bbl neet MeOH pill and begin filling reel w/ warm FW from Swanson. Swap pumps from skid mount to cement unit. Fill reel and PT PCE to 250 psi low / 3500 psi high. RIH w/Cleanout BHA = DJN. 2500ft get PU weight = 12K. 4000' ctm, PUW 15k. RIHW 8k. Tagged fill @ 4,156' ctm. Online w/pump 1.9 bpm, establish 1:1 returns and cleanout 4,156' - 4,415' ctm. RIH 50' and pulling up 100' in bites to 4,415'. Tagged obstruction @ 4,415' ctm. Pump 60 bbl bottums up 1.9 bpm, Annular Velocity = 155 fpm. PUH to 4,300' ctm, off pump, dry tag @ 4,400' ctm. Wash down to obstruction @ 4,416' ctm. PUH to 4,368' ctm. Pumped 60 bbls bottoms up. Shut in CTBS, Injectivity Test Down Coil: 1 bpm @ 1468 psi, 1.5 bpm @ 1488 psi. POOH w/BHA pumping 1.9 bpm taking returns. In lubricator w/BHA. Contact production and line up for step rate injection test. 1 bpm / 1400 psi , 2 bpm / 1407 psi, 3 bpm / 1545 psi, 4 bpm / 1617 psi, 5 bpm / 1692 psi. Shut swab valve and secure well. Blow down reel w/N2. RDMO Fox Coil Tubing & support equipment. Release crews and equipment. API: 50-133-20352-01-00 Field: Kenai Gas Field Sundry #: 323-679 State: ALASKA Rig/Service:Permit to Drill (PTD) #:205-099 Lease: State: Country:USA (TVD) 3,728' - 3,838' Angle @ KOP and Depth:41 ° @ 3,777' Perforations (MD): Revised By:DMA Last Revison Date:1/19/2024 Completion Fluid:6% KCLDated Completed: Well Name & Number:KU 24-7RD Kenai Gas Field Angle/Perfs: AlaskaCounty or Parish:Kenai Peninsula Borough 4,415' - 4,560' KU 24-7RD Pad 41-18 728' FNL, 748' FEL Sec. 18, T4N, R11W, S.M. Drive Pipe: 20" 94ppf H-40 Top Bottom MD 0' 179" TVD 0' 179' Surface Casing: 13 3/8" 61ppf K-55 Top Bottom MD 0' 2,003' TVD 0' 1,849' 17-1/2" Hole cmt w/1,225 sks 9 5/8" 47# N-80 Csg Window @ 3,777 ' - 3,814' Tubing Detail 4 1/2" 12.6#, N-80 Tubing 1. Premier Removable Packer @ 4,338' 2. XN nipple @ 4,343' ID=3.725" Liner 7" 26 ppf N-80 mod butt Top Bottom MD 3,477' 4,800' TVD 3,023' 4,023' 8-1/2" Hole cmt w/ 200sx class "G" Liner hanger w/ ZXP Packer @ 3,457' Permit #:205-099 API #: 50-133-2035201 Property Des: A-028142 KB Elevation: 87' (21' AGL) WBS #: Latitude: Longitude: X: 275,057.001 Y:2,356,013.0011 Spud:06/24/2005 (sidetrack) TD: 06/22/2005 Rig Released: Tbg Hanger: 27' TD 4,800' MD 4,023' TVD Production Casing: 9-5/8" 43.5 & 47ppf N-80 Top Bottom MD 0' 3,814' (Window) Perforations: 3-3/8" HSC 6spf (7/20/05); Pool 3 MD TVD A10 4,415' - 4,485' 3,728' - 3,781' A11 4,530' - 4,560' 3,816' - 3,839' PBTD 4,701' MD 3,947' TVD SCHEMATIC Obstruction @ 4,415' 12/23/23 1. 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: 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): 4,800 4,410' (Fish) Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 3,810psi Liner 5,410psi 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: Contact Email: Contact Phone: 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 WDSP 1.2 chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY 7,240psi Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA022330; FEDA028142 205-099 50-133-20352-01-00 Hilcorp Alaska, LLC Proposed Pools: 12.6# / N-80 TVD Burst 4,343 6,330psi 1,849 Size 179 2,003 MD 7" 3,728 - 3,839 3,090psi 179179 2,003 September 26, 2024 4,8001,323 4-1/2" 4,024 3,814 Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit 24-07RDEPA Permit # AK-1I018-A Same 3,2759-5/8" ~2200psi 3,814 N/A Length ZXP Pkr / Premier Removable Pkr & N/A 3,457 (MD) 3,006 (TVD) / 4,338 (MD) 3,670 (TVD) & N/A 4,023 4,415 3,728 Kenai Gas Field Undefined WDSP 20" 13-3/8" 4,415 - 4,560 m n P s t N 66 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 9:26 am, Sep 20, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.09.18 11:58:23 - 08'00' Noel Nocas (4361) 324-535 Provide 24 hrs notice for AOGCC opportunity to witness MIT-IA to 2000 psi WDSP 1.2 Class I and II 10-404 BOP test to 3000 psi. Annular test to 2500 psi. EPA Class I permit conditions apply. CDW 09/23/2024 DSR-9/25/24SFD 9/20/2024BJM 9/24/24 X X *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.26 08:09:51 -08'00'09/26/24 RBDMS JSB 100124 Well Prognosis Well: KU 24-07RD Well Name: KU 24-07RD API Number: 50-133-20352-01 Current Status: Class I Disposal Well Permit to Drill Number: 205-099 First Call Engineer: Chad Helgeson (907) 777-8405 (907) 229-4824 (C) Second Call Engineer: Scott Warner (907) 830-8863 (C) Maximum Expected BHP: 1724 psi @ 3,947’ TVD (Assume 8.4 lb/gal water to kill well) Max. Potential Surface Pressure: 2200 psi (Permit limit, pump shutdown pressure) Well Status: Class I Disposal Well Brief Well Summary KU 24-07RD is a G&I disposal well for injecting Class I waste into the Sterling sands that is governed by EPA permit # AK-1I018-A. The well was reclassified from a Class II well to EPA Class I well in September of 2021. The well has seen increased injection pressures and coil cleanouts have not remedied the pressure increases. The objective of this sundry is to remove tubing and current packer, fish coil mill, and use rig to mill restriction in well to cleanup perfs and recover injectivity, reperf if able to get wireline to depth. Workover Procedure 1. Current pressure on well is 0 psi, bleed pressure from well or pump kill weight fluid if well pressures up 2. MIRU 401 workover rig 3. Install TWC, ND tree, 13-5/8” BOPs w/ VBRs 4. Test BOPE ¾ Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. (Notify AOGCC 24 hours in advance of test to allow them to witness test). ¾ If the BOP is used to shut in on the well in a well control situation or if BOP equipment could be compromised, ALL BOP components utilized for well control or compromised must be tested prior to the next trip into the wellbore. ¾ BOPs will be closed as needed to circulate the well during this workover. 5. Pull TWC 6. Pick up on hanger with short joint 7. MIRU E-line 8. Cut inner mandrel from upper packer at ~4,338’ 9. RDMO Eline 10. Pull and lay down 4-1/2” 12.6# L-80 IBT-M/BTC tubing 11. PU 3-1/2” PH6 workstring and OS to fish coil tools 12. RIH and fish 2.125” motor with 2.46” tapered mill 13. Once fish is removed, PU 7” milling assembly (~ 6” mill with string mill to keep rigid and straight) 14. RIH and mill cleanout restriction from 4410’ to ~4430’ (or deeper till get injectivity @ 4 bpm @ <1500 psi) 15. POOH and LD mill assembly 16. PU new 4-1/2” packer assembly (~30-45ft long) and new 4-1/2” 12.6# IBT tubing 17. RIH with new completion and hydraulicly set packer at 4215ft 18. Pressure test casing to 2500psi, hold for 30 minutes 19. ND BOP, NU Tree 20. RDMO Rig 401 21. MIRU E-line, PT lubricator to 2500 psi 22. Perforate Sterling sands between 4415’ – 4485’ & 4530-4560’ as necessary to get desirable injection rates for disposal. Well Prognosis Well: KU 24-07RD 23. RDMO Eline 24. Complete post workover MITs to 2000 psi prior to injection for EPA and AOGCC. a. Provide notice to witness to EPA and AOGCC (24hrs notice) b. EPA must provide authorization prior to resuming injection 25. Restart injection Attachments: 1. Actual Schematic 2. Proposed Schematic 3. 401 Workover Rig 13-5/8” BOP Diagram 4. Fish Diagrams (Coil & SL tool strings) EPA must provide authorization prior to resuming injection Lease: State: Country:USA (TVD) Well Name & Number:KU 24-7RD Kenai Gas Field Angle/Perfs: AlaskaCounty or Parish: 3,728' - 3,838' Angle @ KOP and Depth:41 ° @ 3,777' Perforations (MD): Kenai Peninsula Borough 4,415' - 4,560' Revised By:C Helgeson Last Revison Date:9/17/2024 Completion Fluid:6% KCLDated Completed: KU 24-7RD Pad 41-18 728' FNL, 748' FEL Sec. 18, T4N, R11W, S.M. Drive Pipe: 20" 94ppf H-40 Top Bottom MD 0' 179" TVD 0' 179' Surface Casing: 13 3/8" 61ppf K-55 Top Bottom MD 0' 2,003' TVD 0' 1,849' 17-1/2" Hole cmt w/1,225 sks 9 5/8" 47# N-80 Csg Window @ 3,777 ' - 3,814' Tubing Detail 4 1/2" 12.6#, N-80 IBT Mod Tubing 1. Premier Removable Packer @ 4,338' 2. XN nipple @ 4,343' ID=3.725" Liner 7" 26 ppf N-80 mod butt Top Bottom MD 3,477' 4,800' TVD 3,023' 4,023' 8-1/2" Hole cmt w/ 200sx class "G" Liner hanger w/ ZXP Packer @ 3,457' Permit #:205-099 API #: 50-133-2035201 Property Des: A-028142 KB Elevation: 87' (21' AGL) WBS #: Latitude: Longitude: X: 275,057.001 Y:2,356,013.0011 Spud:06/24/2005 (sidetrack) TD: 06/22/2005 Rig Released: Tbg Hanger: 27' TD 4,800' MD 4,023' TVD Production Casing: 9-5/8" 43.5 & 47ppf N-80 Top Bottom MD 0' 3,814' (Window) Perforations: 3-3/8" HSC 6spf (7/20/05); Pool 3 MD TVD A10 4,415' - 4,485' 3,728' - 3,781' A11 4,530' - 4,560' 3,816' - 3,839' PBTD 4,701' MD 3,947' TVD SCHEMATIC Obstruction @ 4,410' 12/23/23 Lease: State: Country:USA (TVD) Revised By:CAH Last Revison Date:9/17/2024 Completion Fluid:Water AlaskaCounty or Parish: 3,728' - 3,838' Angle @ KOP and Depth:41 ° @ 3,777' Perforations (MD): Kenai Peninsula Borough 4,415' - 4,560' Dated Completed: Well Name & Number:KU 24-7RD Kenai Gas Field Angle/Perfs: KU 24-7RD Pad 41-18 728' FNL, 748' FEL Sec. 18, T4N, R11W, S.M. Drive Pipe: 20" 94ppf H-40 Top Bottom MD 0' 179" TVD 0' 179' Surface Casing: 13 3/8" 61ppf K-55 Top Bottom MD 0' 2,003' TVD 0' 1,849' 17-1/2" Hole cmt w/1,225 sks 9 5/8" 47# N-80 Csg Window @ 3,777 ' - 3,814' Tubing Detail 4 1/2" 12.6#, N-80 IBT Mod Tubing 1. Tripoint DHL Removable Packer @ 4,215' 2. XN nipple @ 4,225' ID=3.725" Liner 7" 26 ppf N-80 mod butt Top Bottom MD 3,477' 4,800' TVD 3,023' 4,023' 8-1/2" Hole cmt w/ 200sx class "G" Liner hanger w/ ZXP Packer @ 3,457' Permit #:205-099 API #: 50-133-2035201 Property Des: A-028142 KB Elevation: 87' (21' AGL) WBS #: Latitude: Longitude: X: 275,057.001 Y:2,356,013.0011 Spud:06/24/2005 (sidetrack) TD: 06/22/2005 Rig Released: Tbg Hanger: 27' TD 4,800' MD 4,023' TVD Production Casing: 9-5/8" 43.5 & 47ppf N-80 Top Bottom MD 0' 3,814' (Window) Perforations: 3-3/8" HSC 6spf (7/20/05); Pool 3 MD TVD A10 4,415' - 4,485' 3,728' - 3,781' A11 4,530' - 4,560' 3,816' - 3,839' PBTD 4,701' MD 3,947' TVD PROPOSED The picture can't be displayed.The picture can't be displayed.The picture can't be displayed.The picture can't be displayed. 13-5/8"Spherical Annular Height: 46" Weight: 12,806 13-5/8"LWS Double BOP Height: 37" Width: 93" Weight 9,900 lbs. TOP RAMS 2-7/8" TO 5-1/2" MULTI- RAMS BOTTOM RAMS BLIND RAMS 13-5/8"Mud Cross W/ 4- 1/16" outlets Height:28.5" Width 31" Dual 4-1/16" Manual Gate valves W/ DSA to 2-1/16" 4-1/16" Manual Gate valve & 4-1/16" HCR W/ DSA to 2-1/16" Full Mud Cross Assy. width w/ valves installed Width: 98.5" Weight: 2200 lbs. Kill side Choke side Height Addition for Ring Gaskets: 0" BOP Total Height: 111.5" BOP Total weight: 24,906 lbs. 13-5/8" 5m BOP Package W/ 4-1/16" Valves Date: 9-13-2024 Well: KU 24-07RD ID Drift Length NA NA 10.00' NA NA 1.34' BHA OAL: 11.34' 1 1/2" MT Pin Tapered Mill 2.43" 1 1/2" MT BxB Motor 2.13" LIH BHA B.H.A. Picture DESCRIPTION OD Book1 Date: 9-13-2024 Well: KU 24-07RD ID Drift Length 1.00" NA 0.50' 1.00" NA 0.48' 1.00" NA 1.30' NA NA 2.08' BHA OAL: 4.36' 2 7/8" Pac Box 2 1/16" Grapple (Test Fitted to Fish) OverShot Assy 3.63" Cross Over 3.13" 2 3/8" Pac Box X 2 7/8" Pac Pin Cross Over 2.76" 1 1/2" MT Box X 2 3/8" Pac Pin Bait Sub 2.70" 3" G-Profile (2.31") x 1 1/2" MT Pin OverShot Assy B.H.A. Picture DESCRIPTION OD Book2 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:McLellan, Bryan J (OGC) To:Chad Helgeson; Wallace, Chris D (OGC) Cc:Donna Ambruz Subject:RE: KU 24-07RD (PTD# 205-099) Sundry Number 324-480 Coil cleanout with N2 Date:Thursday, September 12, 2024 8:30:00 AM Chad, Hilcorp has approval to repeat the CTCO using nitrogen to assist in lifting the solids as proposed in your email below under the existing sundry 324-480. Original conditions of approval on that sundry still apply. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Wednesday, September 11, 2024 5:03 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: KU 24-07RD (PTD# 205-099) Sundry Number 324-480 Coil cleanout with N2 Bryan/Chris, Last week we cleaned out our G&I disposal well KU 24-07RD with coil tubing and didn’t see much improvement. The sundry is still open, and we are going to try it again, this time we would like to pick up a motor and mill to try and get through the restriction in the casing at 4410. We last milled down to this restriction in 2017 and the well started taking fluid again pretty good, so we stopped at that time. If we do not get very far with the milling plan, our backup option on Friday may be to N2 foam cleanout to get additional underbalance to try and clear up the perfs better. We did not include the N2 as part of our procedure in the approved sundry. We are requesting to use foam to cleanout as a contingency if the milling operations do not go as we hope. Please let us know if we have authorization to use N2 in our cleanout, per our standard N2 procedures (attached). Thanks Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C 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 delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 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:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: KU 24-07RD (PTD# 205-099) Coil Sundry request Date:Monday, August 26, 2024 8:04:09 AM Attachments:KU 24-07RD AOGCC 10-403 PTD 205-099 Submitted 08-20-24.pdf From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Friday, August 23, 2024 2:10 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Casey Morse <Casey.Morse@hilcorp.com> Subject: KU 24-07RD (PTD# 205-099) Coil Sundry request We submitted a Sundry request earlier this week for a coil cleanout on KU 24-07RD (one of our Class 1 Disposal wells) at Kenai Gas Field. Both of our G&I wells at Kenai Gas Field are struggling and will be submitting a workover for the other disposal well to move the packer uphole in the next few weeks. I know Bryan is on some time off, so wanted to get it on the radar that we are hoping to get approval for this coil cleanout before next Thursday (Aug 29), which is when we expect to have the equipment ready to start this cleanout. Thanks for any help you can provide us. If you have any questions or need more information on this, please let me know. Thanks Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C 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 responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. 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: CTCO 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): 4,800 4,415 (fill) Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 3,810psi Liner 5,410psi 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: Contact Email: Contact Phone: 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 ZXP Pkr / Premier Removable Pkr & N/A 3,457 (MD) 3,006 (TVD) / 4,338 (MD) 3,670 (TVD) & N/A 4,023 4,415 3,728 Kenai Gas Field Undefined WDSP 20" 13-3/8" 4,415 - 4,560 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit 24-07RDEPA Permit # AK-1I018-A Same 3,2759-5/8" ~2200psi 3,814 N/A Length August 26, 2024 4,8001,323 4-1/2" 4,024 3,814 Perforation Depth MD (ft): 7" 3,728 - 3,839 3,090psi 179179 2,003 Size 179 2,003 MD Hilcorp Alaska, LLC Proposed Pools: 12.6# / N-80 TVD Burst 4,343 6,330psi 1,849 Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA022330; FEDA028142 205-099 50-133-20352-01-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY 7,240psi Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s t N 66 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 Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.08.20 15:31:58 - 08'00' Noel Nocas (4361) Well Prognosis Well Name: KU 24-07RD API Number: 50-133-20352-01 Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 205-099 First Call Engineer: Chad Helgeson (907) 777-8420 (O) (907) 229-4824 (M) Second Call Engineer: Scott Warner (907) 830-8863 (C) Maximum Expected BHP: ~ 3,962 psi @ 3,947’ TVD (Assume 10.0 lb/gal slurry) Max. Potential Surface Pressure: 2,250 psi (Pressure relief valve setpoint) Current Surface Pressure: 2,160 psi (Current injection pressure) Well Status: Class I Disposal Well Brief Well Summary KU 24-07RD is a G&I disposal well for injecting Class I waste into the Sterling sands that is governed by EPA permit # AK-1I018-A. The well was reclassified from a Class II well to EPA Class I well in September of 2021. The well has seen increased injection pressures and a recent slickline tag has shown fill covering the perforations. Tagged at 4341’ on 8/19/24. The objective of this sundry is to increase injectivity by removing fill over the existing perforations. Open Perforations Sterling A-10 4415-4485’ MD 3728-3781’ TVD Sterling A-11 4530-4560’ MD 3816-3839’ TVD Permitted Injection Interval: 3600’ – 4200’ TVD Procedure 1. Review approved COAs 2. Provide 24hrs notice to AOGCC of BOP test 3. MIRU Coiled Tubing, PT BOPE to 3500 psi Hi 250 Low 4. RIH with coil tubing nozzle or mill, clean out as deep as possible 5. Pump injectivity test with coil pump 6. RDMO CTU 7. Return well to operations Attachments: 1. Actual Schematic 2. Coil Tubing BOP Diagram Lease: State: Country:USA (TVD) 3,728' - 3,838' Angle @ KOP and Depth:41 ° @ 3,777' Perforations (MD): Revised By:DMA Last Revison Date:1/19/2024 Completion Fluid:6% KCLDated Completed: Well Name & Number:KU 24-7RD Kenai Gas Field Angle/Perfs: AlaskaCounty or Parish:Kenai Peninsula Borough 4,415' - 4,560' KU 24-7RD Pad 41-18 728' FNL, 748' FEL Sec. 18, T4N, R11W, S.M. Drive Pipe: 20" 94ppf H-40 Top Bottom MD 0' 179" TVD 0' 179' Surface Casing: 13 3/8" 61ppf K-55 Top Bottom MD 0' 2,003' TVD 0' 1,849' 17-1/2" Hole cmt w/1,225 sks 9 5/8" 47# N-80 Csg Window @ 3,777 ' - 3,814' Tubing Detail 4 1/2" 12.6#, N-80 Tubing 1. Premier Removable Packer @ 4,338' 2. XN nipple @ 4,343' ID=3.725" Liner 7" 26 ppf N-80 mod butt Top Bottom MD 3,477' 4,800' TVD 3,023' 4,023' 8-1/2" Hole cmt w/ 200sx class "G" Liner hanger w/ ZXP Packer @ 3,457' Permit #:205-099 API #: 50-133-2035201 Property Des: A-028142 KB Elevation: 87' (21' AGL) WBS #: Latitude: Longitude: X: 275,057.001 Y:2,356,013.0011 Spud:06/24/2005 (sidetrack) TD: 06/22/2005 Rig Released: Tbg Hanger: 27' TD 4,800' MD 4,023' TVD Production Casing: 9-5/8" 43.5 & 47ppf N-80 Top Bottom MD 0' 3,814' (Window) Perforations: 3-3/8" HSC 6spf (7/20/05); Pool 3 MD TVD A10 4,415' - 4,485' 3,728' - 3,781' A11 4,530' - 4,560' 3,816' - 3,839' PBTD 4,701' MD 3,947' TVD SCHEMATIC Obstruction @ 4,415' 12/23/23 1. 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: CTCO 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): 4,800 4,415 (fill) Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 3,810psi Liner 5,410psi 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: Contact Email: Contact Phone: 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 ZXP Pkr / Premier Removable Pkr & N/A 3,457 (MD) 3,006 (TVD) / 4,338 (MD) 3,670 (TVD) & N/A 4,023 4,415 3,728 Kenai Gas Field Undefined WDSP 20" 13-3/8" 4,415 - 4,560 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit 24-07RDEPA Permit # AK-1I018-A Same 3,2759-5/8" ~2200psi 3,814 N/A Length August 26, 2024 4,8001,323 4-1/2" 4,024 3,814 Perforation Depth MD (ft): 7" 3,728 - 3,839 3,090psi 179179 2,003 Size 179 2,003 MD Hilcorp Alaska, LLC Proposed Pools: 12.6# / N-80 TVD Burst 4,343 6,330psi 1,849 Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA022330; FEDA028142 205-099 50-133-20352-01-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY 7,240psi Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s t N 66 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 Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.08.20 15:31:58 - 08'00' Noel Nocas (4361) 324-480 By Grace Christianson at 9:49 am, Aug 21, 2024 SFD 8/21/2024 CDW 08/26/2024 EPA Class I permit conditions apply. AOGCC Class II DIO 11 and 11.001 conditions apply. DSR-8/21/24 WDSP1,2 SFD MGR27AUG2024 * BOPE test to 3500 psi. 24 hour notice for AOGCC to witness. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.28 13:46:25 -08'00' 08/28/24 RBDMS JSB 082924 Well Prognosis Well Name: KU 24-07RD API Number: 50-133-20352-01 Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 205-099 First Call Engineer: Chad Helgeson (907) 777-8420 (O) (907) 229-4824 (M) Second Call Engineer: Scott Warner (907) 830-8863 (C) Maximum Expected BHP: ~ 3,962 psi @ 3,947’ TVD (Assume 10.0 lb/gal slurry) Max. Potential Surface Pressure: 2,250 psi (Pressure relief valve setpoint) Current Surface Pressure: 2,160 psi (Current injection pressure) Well Status: Class I Disposal Well Brief Well Summary KU 24-07RD is a G&I disposal well for injecting Class I waste into the Sterling sands that is governed by EPA permit # AK-1I018-A. The well was reclassified from a Class II well to EPA Class I well in September of 2021. The well has seen increased injection pressures and a recent slickline tag has shown fill covering the perforations. Tagged at 4341’ on 8/19/24. The objective of this sundry is to increase injectivity by removing fill over the existing perforations. Open Perforations Sterling A-10 4415-4485’ MD 3728-3781’ TVD Sterling A-11 4530-4560’ MD 3816-3839’ TVD Permitted Injection Interval: 3600’ – 4200’ TVD Procedure 1. Review approved COAs 2. Provide 24hrs notice to AOGCC of BOP test 3. MIRU Coiled Tubing, PT BOPE to 3500 psi Hi 250 Low 4. RIH with coil tubing nozzle or mill, clean out as deep as possible 5. Pump injectivity test with coil pump 6. RDMO CTU 7. Return well to operations Attachments: 1. Actual Schematic 2. Coil Tubing BOP Diagram Lease: State: Country:USA (TVD) 3,728' - 3,838' Angle @ KOP and Depth:41 ° @ 3,777' Perforations (MD): Revised By:DMA Last Revison Date:1/19/2024 Completion Fluid:6% KCLDated Completed: Well Name & Number:KU 24-7RD Kenai Gas Field Angle/Perfs: AlaskaCounty or Parish:Kenai Peninsula Borough 4,415' - 4,560' KU 24-7RD Pad 41-18 728' FNL, 748' FEL Sec. 18, T4N, R11W, S.M. Drive Pipe: 20" 94ppf H-40 Top Bottom MD 0' 179" TVD 0' 179' Surface Casing: 13 3/8" 61ppf K-55 Top Bottom MD 0' 2,003' TVD 0' 1,849' 17-1/2" Hole cmt w/1,225 sks 9 5/8" 47# N-80 Csg Window @ 3,777 ' - 3,814' Tubing Detail 4 1/2" 12.6#, N-80 Tubing 1. Premier Removable Packer @ 4,338' 2. XN nipple @ 4,343' ID=3.725" Liner 7" 26 ppf N-80 mod butt Top Bottom MD 3,477' 4,800' TVD 3,023' 4,023' 8-1/2" Hole cmt w/ 200sx class "G" Liner hanger w/ ZXP Packer @ 3,457' Permit #:205-099 API #: 50-133-2035201 Property Des: A-028142 KB Elevation: 87' (21' AGL) WBS #: Latitude: Longitude: X: 275,057.001 Y:2,356,013.0011 Spud:06/24/2005 (sidetrack) TD: 06/22/2005 Rig Released: Tbg Hanger: 27' TD 4,800' MD 4,023' TVD Production Casing: 9-5/8" 43.5 & 47ppf N-80 Top Bottom MD 0' 3,814' (Window) Perforations: 3-3/8" HSC 6spf (7/20/05); Pool 3 MD TVD A10 4,415' - 4,485' 3,728' - 3,781' A11 4,530' - 4,560' 3,816' - 3,839' PBTD 4,701' MD 3,947' TVD SCHEMATIC Obstruction @ 4,415' 12/23/23 1. 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: Chemical Treatment 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): 4,800 4,415 (fill) Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 3,810psi Liner 5,410psi 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: Contact Email: Contact Phone: 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 ZXP Pkr / Premier Removable Pkr & N/A 3,457 (MD) 3,006 (TVD) / 4,338 (MD) 3,670 (TVD) & N/A 4,023 4,415 3,728 Kenai Gas Field Undefined WDSP 20" 13-3/8" 4,415 - 4,560 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit 24-07RDEPA Permit # AK-1I018-A Same 3,2759-5/8" ~2200psi 3,814 N/A Length May 15, 2024 4,8001,323 4-1/2" 4,024 3,814 Perforation Depth MD (ft): 7" 3,728 - 3,839 3,090psi 179179 2,003 Size 179 2,003 MD Hilcorp Alaska, LLC Proposed Pools: 12.6# / N-80 TVD Burst 4,343 6,330psi 1,849 Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 205-099 50-133-20352-01-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Casey Morse, Integrity Engineer AOGCC USE ONLY 7,240psi Tubing Grade: casey.morse@hilcorp.com 907-777-8322 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s t N 66 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 1:32 pm, May 07, 2024 SFD 5/7/2024 DSR-5/7/24 SFDFEDA022330, 10-404 BJM 5/9/24 X -bjm JLC 5/9/2024 Well Prognosis Well Name: KU 24-07RD API Number: 50-133-20352-01-00 Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 205-099 First Call Engineer: Casey Morse (907) 777-8322 (O) (603) 205-3780 (M) Second Call Engineer: Chad Helgeson (907) 777-8420 (O) (907) 229-4824 (M) Maximum Expected BHP: ~ 3,400 psi @ 3,728 TVD (~1700 psi treating with water) Max. Potential Surface Pressure: 2,200 psi (Permit limit, pump shutdown pressure) Well Status: Class I Disposal Well Brief Well Summary KU 24-07RD is a G&I disposal well for injecting Class I waste into the Sterling sands that is governed by EPA permit # AK-1I018-A. The well was reclassified from a Class II well to EPA Class I well in September of 2021. The well has seen increased injection pressures and historical injection records and prior unsuccessful treatments suggest organic solids may be the cause. The objective of this sundry is to increase injectivity by dissolving and pushing organic solids away from the wellbore through the existing perforations. Open Perforations Sterling A-10 4415-4485 MD 3728-3781 TVD Sterling A-11 4530-4560 MD 3816-3839 TVD Permitted Injection Interval: 3600 4200 TVD Procedure 1. MIRU hot oil truck and pump. 2. Heat and stage produced water for initial flush. 3. Tie in xylene transport (approx. 147 bbls total) 4. Isolate well and pressure test lines to 2500 psi a. Ensure tubing pressure transducer is able to measure pressures throughout the job b. Make note of all injection volumes to include in FDC entry per guidance of G&I operations 5. Using G&I injection pump, pump 200 bbl of hot (produced) water at 150+ degrees if possible a. Target injection rate ~1-2 bpm b. Frac pressure is approx. 1700 psi (try to avoid fracs during this treatment) c. Max allowable surface pressure is 2200 psi per EPA permit DO NOT EXCEED 6. Swap to hot oil truck. Pump 75 bbl of xylene (tubing volume is 66 bbl). Displace with 25 bbl produced water to flush pump and lines. Stop pump and wait 15-20 minutes. Pump another 25 bbls produced water and wait 15-20 minutes. Pump additional 25 bbls produced water and wait 15-20 minutes. All xylene should be cleared from tubing. 7. Repeat step 6 with remaining xylene (approx. 72 bbl), stage with 25 bbl water increments same as above. 8. Swap back to G&I pump. Over-flush with 200 bbl of hot produced water. 9. Return well to operations. Attachments: 1. Current Schematic 2. Xylene SDS well was reclassified from a Class II well to EPA Class I well in September of 2021 Lease: State: Country:USA (TVD) 3,728' - 3,838' Angle @ KOP and Depth:41 ° @ 3,777' Perforations (MD): Revised By:DMA Last Revison Date:1/19/2024 Completion Fluid:6% KCLDated Completed: Well Name & Number:KU 24-7RD Kenai Gas Field Angle/Perfs: AlaskaCounty or Parish:Kenai Peninsula Borough 4,415' - 4,560' KU 24-7RD Pad 41-18 728' FNL, 748' FEL Sec. 18, T4N, R11W, S.M. Drive Pipe: 20" 94ppf H-40 Top Bottom MD 0' 179" TVD 0' 179' Surface Casing: 13 3/8" 61ppf K-55 Top Bottom MD 0' 2,003' TVD 0' 1,849' 17-1/2" Hole cmt w/1,225 sks 9 5/8" 47# N-80 Csg Window @ 3,777 ' - 3,814' Tubing Detail 4 1/2" 12.6#, N-80 Tubing 1. Premier Removable Packer @ 4,338' 2. XN nipple @ 4,343' ID=3.725" Liner 7" 26 ppf N-80 mod butt Top Bottom MD 3,477' 4,800' TVD 3,023' 4,023' 8-1/2" Hole cmt w/ 200sx class "G" Liner hanger w/ ZXP Packer @ 3,457' Permit #:205-099 API #: 50-133-2035201 Property Des: A-028142 KB Elevation: 87' (21' AGL) WBS #: Latitude: Longitude: X: 275,057.001 Y:2,356,013.0011 Spud:06/24/2005 (sidetrack) TD: 06/22/2005 Rig Released: Tbg Hanger: 27' TD 4,800' MD 4,023' TVD Production Casing: 9-5/8" 43.5 & 47ppf N-80 Top Bottom MD 0' 3,814' (Window) Perforations: 3-3/8" HSC 6spf (7/20/05); Pool 3 MD TVD A10 4,415' - 4,485' 3,728' - 3,781' A11 4,530' - 4,560' 3,816' - 3,839' PBTD 4,701' MD 3,947' TVD SCHEMATIC Obstruction @ 4,415' 12/23/23 1. 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: CT Operations 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): 4,800 N/A Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 3,810psi Liner 5,410psi 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: Contact Email: Contact Phone: 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 ZXP Pkr / Premier Removable Pkr & N/A 3,457 (MD) 3,006 (TVD) / 4,338 (MD) 3,670 (TVD) & N/A 4,023 4,410 3,724 Kenai Gas Field Undefined WDSP 20" 13-3/8" 4,415 - 4,560 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit 24-07RDEPA Permit # AK-1I018-A Same 3,2759-5/8" 1910 3,814 N/A Length December 22, 2023 4,8001,323 4-1/2" 4,024 3,814 Perforation Depth MD (ft): 7" 3,728 - 3,839 3,090psi 179179 2,003 Size 179 2,003 MD Hilcorp Alaska, LLC Proposed Pools: 12.6# / N-80 TVD Burst 4,343 6,330psi 1,849 Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 205-099 50-133-20352-01-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY 7,240psi Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s t s N 66 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 Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.12.20 11:55:08 - 09'00' Noel Nocas (4361) 323-679 By Grace Christianson at 2:11 pm, Dec 20, 2023 X December 22, 2023 BJM 12/20/23 2200 -bjm SFD 12/20/2023 Dec 20, 2023 BOP test to 3500 psi 10-404 Yes 12/20/23 Bryan McLellan *&: Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.12.21 10:05:59 -09'00'12/21/23 RBDMS JSB 122623 Well Prognosis Well Name: KU 24-07RD API Number: 50-133-20352-01 Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 205-099 First Call Engineer: Chad Helgeson (907) 777-8420 (O) (907) 229-4824 (M) Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (M) Maximum Expected BHP: ~ 3,962 psi @ 3,947’ TVD (Assume 10.0 lb/gal slurry) Max. Potential Surface Pressure: 2,200 psi (Permit limit, pump shutdown pressure) Well Status: Class I Disposal Well Brief Well Summary KU 24-07RD is a G&I disposal well for injecting Class I waste into the Sterling sands that is governed by EPA permit # AK-1I018-A. The well was reclassified from a Class II well to EPA Class I well in September of 2021. The well has seen increased injection pressures and recent slickline tags have shown fill covering the perforations. The objective of this sundry is to increase injectivity by removing fill over the existing perforations. Open Perforations Sterling A-10 4415-4485’ MD 3728-3781’ TVD Sterling A-11 4530-4560’ MD 3816-3839’ TVD Permitted Injection Interval: 3600’ – 4200’ TVD Procedure 1. Review approved COAs 2. Provide 24hrs notice to AOGCC of BOP test 3. MIRU Coiled Tubing, PT BOPE to 3500 psi Hi 250 Low 4. RIH with coil tubing nozzle or mill, clean out as deep as possible 5. Pump injectivity test with coil pump 6. RDMO CTU 7. Return well to operations Attachments: 1. Current Schematic 2. Coil Tubing BOP Diagram Reservoir pressure is normally pressured. WHP bleeds to 0 psi with a column of water, per Chad Helgeson. -bjm Lease: State: Country:USA (TVD) Well Name & Number:KU 24-7RD Kenai Gas Field Angle/Perfs: Alaska Revised By:DMA Last Revison Date:5/1/2023 Completion Fluid:6% KCL County or Parish:Kenai Peninsula Borough Dated Completed: 4,415' - 4,560' 3,728' - 3,838' Angle @ KOP and Depth:41 ° @ 3,777' Perforations (MD): KU 24-7RD Pad 41-18 728' FNL, 748' FEL Sec. 18, T4N, R11W, S.M. Drive Pipe: 20" 94ppf H-40 Top Bottom MD 0' 179" TVD 0' 179' Surface Casing: 13 3/8" 61ppf K-55 Top Bottom MD 0' 2,003' TVD 0' 1,849' 17-1/2" Hole cmt w/1,225 sks 9 5/8" 47# N-80 Csg Window @ 3,777 ' - 3,814' Tubing Detail 4 1/2" 12.6#, N-80 Tubing 1. Premier Removable Packer @ 4,338' 2. XN nipple @ 4,343' ID=3.725" Liner 7" 26 ppf N-80 mod butt Top Bottom MD 3,477' 4,800' TVD 3,023' 4,023' 8-1/2" Hole cmt w/ 200sx class "G" Liner hanger w/ ZXP Packer @ 3,457' Permit #:205-099 API #: 50-133-2035201 Property Des: A-028142 KB Elevation: 87' (21' AGL) WBS #: Latitude: Longitude: X: 275,057.001 Y:2,356,013.0011 Spud:06/24/2005 (sidetrack) TD: 06/22/2005 Rig Released: Tbg Hanger: 27' TD 4,800' MD 4,023' TVD Production Casing: 9-5/8" 43.5 & 47ppf N-80 Top Bottom MD 0' 3,814' (Window) Perforations: 3-3/8" HSC 6spf (7/20/05); Pool 3 MD TVD A10 4,415' - 4,485' 3,728' - 3,781' A11 4,530' - 4,560' 3,816' - 3,839' PBTD 4,701' MD 3,947' TVD SCHEMATIC Obstruction @ 4,410' 4/26/23 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: 11/30/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20231130 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 11/13/2023 YELLOW JACKET GPT BCU 13 50133205250000 203138 10/5/2023 YELLOW JACKET PERF KBU 13-08 50133203040000 177029 10/16/2023 YELLOW JACKET CALIPER KU 12-17 50133205770000 208089 10/4/2023 YELLOW JACKET CALIPER/TEMP KU 24-7RD 50133203520100 205099 10/4/2023 YELLOW JACKET CALIPER MPU B-32 50029235700000 216151 9/20/2023 YELLOW JACKET RCT MPU L-47 50029235500000 215117 10/25/2023 YELLOW JACKET CUT NS-05 50029232440000 205009 9/9/2023 YELLOW JACKET PERF NS-16A 50029230960100 206141 9/12/2023 YELLOW JACKET PERF NS-20 50029231180000 202188 9/11/2023 YELLOW JACKET PERF NS-24 50029231110000 202164 9/10/2023 YELLOW JACKET PATCH PTM P1-13 50029223720000 193074 10/24/2023 YELLOW JACKET PL Please include current contact information if different from above. T38164 T38164 T38165 T38166 T38167 T38168 T38169 T38170 T38171 T38172 T38173 T38174 12/1/2023 YELLOW KU 24-7RD 50133203520100 205099 10/4/2023 JACKET CALIPER Kayla Junke Digitally signed by Kayla Junke Date: 2023.12.01 10:42:44 -09'00' 1 Regg, James B (OGC) From:Casey Morse <Casey.Morse@hilcorp.com> Sent:Monday, November 6, 2023 4:58 PM To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Subject:MIT - KU 24-7RD (EPA Class 1 Disposal Well) 10/24/2023 Attachments:MIT KU 24-07RD 10-24-23.xlsx Follow Up Flag:Follow up Flag Status:Completed AƩached is the report of successful EPA witnessed MIT performed on the KU 24‐7RD Class 1 Disposal Well on 10/24/23. This test was conducted per EPA Underground InjecƟon Control Permit No. AK‐1I018‐A and followed EPA test procedures. Casey Morse Well Integrity Engineer Hilcorp Alaska, LLC (907) 777‐8322 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Kenai Unit 24-07RDPTD 2050990 Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2050990 Type Inj N Tubing 1049 1067 1061 1047 Type Test P Packer TVD 3670 BBL Pump 1.7 IA 1110 2207 2204 2202 Interval O Test psi 1500 BBL Return OA 5 102 103 103 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: Hilcorp Alaska, LLC Kenai Gas Field / Kenai / 41-18 Pad Paul Merveldt 10/24/23 Notes:Class I Disposal Well - Annual MIT with EPA witnessing. Test result: PASS. EPA requires test to 2200 psi. BBL Return not recorded as part of EPA test procedure. Notes: Notes: Notes: 24-7RD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Form 10-426 (Revised 01/2017)2023-1024_MIT_KU_24-07RD J. Regg; 3/12/2024 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: CTCO Development Exploratory 3. Address: Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 4,800 feet N/A feet true vertical 4,023 feet 4,410 (fill)feet Effective Depth measured 4,410 feet 3,457; 4338 feet true vertical 3,724 feet 3,006; 3,670 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / N-80 4,343' MD 3,674' TVD ZXP Pkr; 3,457' MD 3,006' TVD Packers and SSSV (type, measured and true vertical depth)Premier Removeable Pkr; N/A 4,338' MD 3,670' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: Jake Flora, Operations Engineer 323-245 Sr Pet Eng: 5,410psi Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 jake.flora@hilcorp.com 907-777-8442 N/A Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 429 Size 179' 0 5060 0 9080 2073 7,240psi 9-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 205-099 50-133-20352-01-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA028142 Kenai Gas Field / Undefined WDSP Kenai Unit 24-7RD Plugs Junk measured Length measured true vertical Production Liner 3,814' 1,323' Casing Structural 3,275' 7" 3,814' 4,800' 4,023' 179'Conductor Surface Intermediate 20" 13-3/8" 179' 2,003' TVD 3,810psi 3,090psi 6,330psi 2,003' 1,849' Burst Collapse 1,540psi measured Packer p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Kayla Junke at 3:15 pm, May 05, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361), ou=Users Date: 2023.05.05 14:58:21 -08'00' Noel Nocas (4361) Rig Start Date End Date CTU 4/25/23 4/26/23 Attempt to inject with water from G&I. Unable to inject. Flow well back to return tank. Flow back ~ 2 bbls and well died. Attempt to inject again with water from G&I. Unable to inject. RDMO. 04/25/2023 - Tuesday Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 24-07RD 50-133-20352-01-00 205-099 04/26/2023 - Wednesday Fox Coil and Cruz Construction arrive on location. Hold TBT and approve PTW. Spot coil equipment. Pick and move wellhouse with crane. Lift coil reel into coil unit. Mobilize manlift and field tri-plex to location. NU coil BOP's on tree. Function test rams. RU hard line from BOP's to choke skid and coil reel. Test BOPE to 250 psi low / 3000 psi high. Jim Regg with AOGCC waived witness via email on 12:04 pm on 4/25/23. Yellow Jacket mud pump arrive on location. RU hard line from pump to coil and to flow cross to pump down backside. MU roll on coil connect, 2-1/8" straight bar, 2-1/8" wash nozzle. Fill coil with water and PT to 250/3000 psi. Open well and RIH. Dry tag at 4265' ctmd. Online with pump at 1.3 bpm and CTP = 2441 psi. Jet down taking 50' bites and pulling uphole ~ 100' each time. Hard tag at 4408' ctmd. Reciprocate off bottom and pump 2 bottoms up (110 bbls). POOH at 70 ft/min pumping water at 1.3 bpm and chase returns to surface. Pump injectivity test down tubing with water. Pump at 0.5 bpm and seen tubing pressure breakover at 2780 psi. Tubing pressure steady at 1507 psi. 1.0 bpm = 1528 psi tubing pressure 2.0 bpm = 1572 psi tubing pressure 2.5 bpm = 1641 psi tubing pressure 3.0 bpm = 1678 psi tubing pressure 4.0 bpm = 1735 psi tubing pressure 4.5 bpm = 1760 psi tubing pressure 5.0 bpm = 1802 psi Pump total of 87 bbls during injectivity test. Offline with pump. Breakdown wash nozzle and laydown lubricator. ND BOP's and install tree cap. RD Coil equipment and yellow jacket pump. Lease: State: Country:USA (TVD) Well Name & Number:KU 24-7RD Kenai Gas Field Angle/Perfs: Alaska Revised By:DMA Last Revison Date:5/1/2023 Completion Fluid:6% KCL County or Parish:Kenai Peninsula Borough Dated Completed: 4,415' - 4,560' 3,728' - 3,838' Angle @ KOP and Depth:41 ° @ 3,777' Perforations (MD): KU 24-7RD Pad 41-18 728' FNL, 748' FEL Sec. 18, T4N, R11W, S.M. Drive Pipe: 20" 94ppf H-40 Top Bottom MD 0' 179" TVD 0' 179' Surface Casing: 13 3/8" 61ppf K-55 Top Bottom MD 0' 2,003' TVD 0' 1,849' 17-1/2" Hole cmt w/1,225 sks 9 5/8" 47# N-80 Csg Window @ 3,777 ' - 3,814' Tubing Detail 4 1/2" 12.6#, N-80 Tubing 1. Premier Removable Packer @ 4,338' 2. XN nipple @ 4,343' ID=3.725" Liner 7" 26 ppf N-80 mod butt Top Bottom MD 3,477' 4,800' TVD 3,023' 4,023' 8-1/2" Hole cmt w/ 200sx class "G" Liner hanger w/ ZXP Packer @ 3,457' Permit #:205-099 API #: 50-133-2035201 Property Des: A-028142 KB Elevation: 87' (21' AGL) WBS #: Latitude: Longitude: X: 275,057.001 Y:2,356,013.0011 Spud:06/24/2005 (sidetrack) TD: 06/22/2005 Rig Released: Tbg Hanger: 27' TD 4,800' MD 4,023' TVD Production Casing: 9-5/8" 43.5 & 47ppf N-80 Top Bottom MD 0' 3,814' (Window) Perforations: 3-3/8" HSC 6spf (7/20/05); Pool 3 MD TVD A10 4,415' - 4,485' 3,728' - 3,781' A11 4,530' - 4,560' 3,816' - 3,839' PBTD 4,701' MD 3,947' TVD SCHEMATIC Obstruction @ 4,410' 4/26/23 1. 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 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? Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field: Current Pools: Kenai 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 4,800 4,410 (fill) Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 3,810psi Liner 5,410psi 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: Jake Flora Contact Email:Jake.Flora@hilcorp.com Contact Phone:(907) 777-8442 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: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 4,023 3,724 1910 20"179 MD 179 179 Length Size 6,330psi3,2753,814 7,240psi4,800 4,024 1,849 Perforation Depth MD (ft): 3,814 7"1,323 9-5/8" 13-3/8"2,003 2,003 Proposed Pools: TVD Burst PRESENT WELL CONDITION SUMMARY N/A4,410 3,090psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 205-099 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-133-20352-01-00 Hilcorp Alaska, LLC Kenai Unit 24-7RD Undefined WDSP Same N/A 5/5/2023 ZXP Pkr / Premier Removable Pkr & N/A 3,457 (MD) 3,006 (TVD) / 4,338 (MD) 3,670 (TVD) & N/A 4,415 - 4,560 3,728 - 3,839 4-1/2" Other: CTCO 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY Operations Manager Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: 12.6# / N-80 4,343 Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 323-245 By Kayla Junke at 11:15 am, Apr 21, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361), ou=Users Date: 2023.04.20 16:51:29 -08'00' Noel Nocas (4361) DSR-4/26/23 Yes 4/24/23 Bryan McLellan MDG 4/24/2023 BJM 4/27/23 X BOP test to 3000 psi. 10-404 JLC 4/28/2023 04/28/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.04.28 10:22:07 -08'00' RBDMS JSB 050123 Well Prognosis Well Name: KU 24-07RD API Number: 50-133-20352-01 Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 205-099 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (M) Second Call Engineer: Chad Helgeson (907) 777-8420 (O) (907) 229-4824 (M) Maximum Expected BHP: ~ 3,962 psi @ 3,947’ TVD (Assume 10.0 lb/gal slurry) Max. Potential Surface Pressure: 2,250 psi (Pressure relief valve setpoint) Current Surface Pressure: 1,910 psi Well Status: Class I Disposal Well Brief Well Summary KU 24-07RD G&I disposal well for injecting Class I and Class II waste into the Sterling sands that is governed by DIO No. 11.001. The well has seen increased injection pressures and recent slickline tags have shown fill covering the perforations. The objective of this sundry is to increase injectivity by removing fill over the existing perforations. Last Downhole Operation: 04/18/23 2.5” DDB to 4298 02/14/23 2.5” DDB to 4388’ 01/31/17 Coil cleanout to 4410’, unable to get deeper, possible hard fill or obstruction Open Perforations Sterling A-10 4415-4485’ MD 3728-3781’ TVD Sterling A-11 4530-4560’ MD 3816-3839’ TVD Permitted Injection Interval: 3600’ – 4200’ TVD Procedure 1. Review approved COAs 2. Provide 48hrs notice to AOGCC of BOP test 3. MIRU Coiled Tubing, PT BOPE to 3000 psi Hi 250 Low 4. RIH with coil tubing nozzle or mill, clean out as deep as possible 5. RDMO CTU 6. Return well to operations Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Coil Tubing BOP Diagram Lease: State: Country:USA (TVD) Revised By:JMF Last Revison Date:4/19/2023 County or Parish:Kenai Peninsula Borough Dated Completed: 4,415' - 4,560' 3,728' - 3,838' Angle @ KOP and Depth: 41 ° @ 3,777' Completion Fluid:6% KCL Perforations (MD): Well Name & Number:KU 24-7RD Kenai Gas Field Angle/Perfs: Alaska KU 24-7RD Pad 41-18 728' FNL, 748' FEL Sec. 18, T4N, R11W, S.M. Drive Pipe: 20" 94ppf H-40 Top Bottom MD 0' 179" TVD 0' 179' Surface Casing: 13 3/8" 61ppf K-55 Top Bottom MD 0' 2,003' TVD 0' 1,849' 17-1/2" Hole cmt w/1,225 sks 9 5/8" 47# N-80 Csg Window @ 3,777 ' - 3,814' Tubing Detail 4 1/2" 12.6#, N-80 Tubing 1. Premier Removable Packer @ 4,338' 2. XN nipple @ 4,343' ID=3.725" Liner 7" 26 ppf N-80 mod butt Top Bottom MD 3,477' 4,800' TVD 3,023' 4,023' 8-1/2" Hole cmt w/ 200sx class "G" Liner hanger w/ ZXP Packer @ 3,457' Permit #: 205-099 API #: 50-133-2035201 Property Des: A-028142 KB Elevation: 87' (21' AGL) WBS #: Latitude: Longitude: X: 275,057.001 Y: 2,356,013.0011 Spud: 06/24/2005 (sidetrack) TD: 06/22/2005 Rig Released: Tbg Hanger: 27' TD 4,800' MD 4,023' TVD Production Casing: 9-5/8" 43.5 & 47ppf N-80 Top Bottom MD 0' 3,814' (Window) Perforations: 3-3/8" HSC 6spf (7/20/05); Pool 3 MD TVD 4,415' - 4,485' 3,728' - 3,781' 4,530' - 4,560' 3,816' - 3,839' PBTD 4,701' MD 3,947' TVD 1/31/17 CT FCO: Tag 4402', milled 4402- 4410', unable to go deeper 2/14/23 2.5" DDB to 4388' 4/18/23 2.5" DDB to 4298' KB PROPOSED Lease: State: Country:USA (TVD) Alaska Angle @ KOP and Depth: 41 ° @ 3,777' Completion Fluid:6% KCL Perforations (MD): Well Name & Number:KU 24-7RD Kenai Gas Field Angle/Perfs: Revised By:JLL Last Revison Date:4/20/2023 County or Parish:Kenai Peninsula Borough Dated Completed: 4,415' - 4,560' 3,728' - 3,838' KU 24-7RD Pad 41-18 728' FNL, 748' FEL Sec. 18, T4N, R11W, S.M. Drive Pipe: 20" 94ppf H-40 Top Bottom MD 0' 179" TVD 0' 179' Surface Casing: 13 3/8" 61ppf K-55 Top Bottom MD 0' 2,003' TVD 0' 1,849' 17-1/2" Hole cmt w/1,225 sks 9 5/8" 47# N-80 Csg Window @ 3,777 ' - 3,814' Tubing Detail 4 1/2" 12.6#, N-80 Tubing 1. Premier Removable Packer @ 4,338' 2. XN nipple @ 4,343' ID=3.725" Liner 7" 26 ppf N-80 mod butt Top Bottom MD 3,477' 4,800' TVD 3,023' 4,023' 8-1/2" Hole cmt w/ 200sx class "G" Liner hanger w/ ZXP Packer @ 3,457' Permit #: 205-099 API #: 50-133-2035201 Property Des: A-028142 KB Elevation: 87' (21' AGL) WBS #: Latitude: Longitude: X: 275,057.001 Y: 2,356,013.0011 Spud: 06/24/2005 (sidetrack) TD: 06/22/2005 Rig Released: Tbg Hanger: 27' TD 4,800' MD 4,023' TVD Production Casing: 9-5/8" 43.5 & 47ppf N-80 Top Bottom MD 0' 3,814' (Window) Perforations: 3-3/8" HSC 6spf (7/20/05); Pool 3 MD TVD A10 4,415' - 4,485' 3,728' - 3,781' A11 4,530' - 4,560' 3,816' - 3,839' PBTD 4,701' MD 3,947' TVD 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:McLellan, Bryan J (OGC) To:Chad Helgeson Subject:Re: KU 24-07RD (PTD# 205-099) Sundry Date:Monday, April 24, 2023 2:51:17 PM Hilcorp has verbal approval to perform the fill cleanout per the submitted sundry. Bop test to 3000 psi. Bryan McLellan Sent from my iPhone On Apr 24, 2023, at 5:26 PM, Chad Helgeson <chelgeson@hilcorp.com> wrote: Bryan, Attached is the sundry that was submitted last week for the coil cleanout of the disposal well. Thanks Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C 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. <10-403 Kenai Unit 24-7RD PTD 205-099 nan.pdf> 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Wednesday, November 23, 2022 11:18 AM To:Josh Allely - (C) Cc:Regg, James B (OGC) Subject:RE: MIT - KU 24-07RD (EPA Class I Disposal Well) - 10/19/2022 Attachments:MIT KU 24-07RD 10-19-22 Revised.xlsx Josh, Attached is a revised report adding additional remarks. Please review and update your copy. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907 793 1242 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From:Josh Allely (C) <Josh.Allely@hilcorp.com> Sent:Wednesday, November 2, 2022 12:39 PM To:Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject:MIT KU 24 07RD (EPA Class I Disposal Well)10/19/2022 Attached is the official report of the successful EPA witnessed MIT, performed on KU 24-07RD (Class I Disposal Well) on 10/19/22. Test was conducted per EPA Underground Injection Control Permit No. AK-1I018-A and followed EPA test procedures. Josh Allely Well Integrity Engineer Kenai Hilcorp Alaska 907-777-8505 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, 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. revised report Submit to: OPERATOR: FIELD /UNIT /PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2050990 Type Inj N Tubing 590 810 810 810 Type Test P Packer TVD 3670 BBL Pump 1.1 IA 330 2212 2207 2205 Interval O Test psi 1500 BBL Return 1.1 OA 5 102 103 103 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 Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Hilcorp Alaska, LLC Kenai Gas Field / Kenai / 41-18 Cody Hamman 10/19/22 Notes:Class I Disposal Well - Annual MIT with EPA witnessing. Test result: PASS. EPA requires test to 2200 psi. AOGCC Waived. Well is also covered under DIO 11 which requires testing on a 4 year cycle. Notes: Notes: Notes: 24-7RD Form 10-426 (Revised 01/2017)2022-1019_MT_KU_24-07RD Class I Disposal Well EPA requires test to 2200 psi. Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 1/11/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 24-7RD (PTD 205-099) Caliper-Temperature 10/25/2021 Please include current contact information if different from above. 37' (6HW Received By: 01/12/2022 By Abby Bell at 12:36 pm, Jan 11, 2022 1 Guhl, Meredith D (CED) From:Wallace, Chris D (CED) Sent:Tuesday, September 28, 2021 8:57 AM To:Regg, James B (CED); Roby, David S (CED); Davies, Stephen F (CED); Boyer, David L (CED); AOGCC Records (CED sponsored) Subject:Fwd: Issuance of UIC Class I Permit AK-1I018-A, Kenai Gas Field, Alaska Attachments:AK1I018A Fact Sheet Final.pdf; AK1I018A Permit Final signed.pdf; Kenai Gas Field AE Letter signed.pdf From: Gross, Ryan <Gross.Ryan@epa.gov> Sent: Friday, September 24, 2021 3:47:26 PM To: apeloza <apeloza@hilcorp.com> Cc: Chuck Wheat <cwheat@hilcorp.com>; Wallace, Chris D (CED) <chris.wallace@alaska.gov>; Bentley, Marc H (DEC) <marc.bentley@alaska.gov> Subject: Issuance of UIC Class I Permit AK‐1I018‐A, Kenai Gas Field, Alaska Dear Ms. Peloza, The U.S. Environmental Protection Agency (EPA) is issuing UIC Permit AK‐1I018‐A to Hilcorp Alaska, LLC. The permit and fact sheet are attached to this email. This permit authorizes Hilcorp Alaska to operate wells KU 12‐17 and KU 24‐7RD at the Kenai Gas Field as UIC Class I non‐hazardous industrial injection wells. The permit limits injection to only specified waste streams and into only specified geological intervals. EPA received one comment during the public comment period for this permit. That comment supported the permit issuance. EPA received no comments at the virtual public meeting for this permit. This email constitutes service of notice under 40 CFR §124.19(a). The permit becomes effective on the date signed, September 24, 2021, and remains effective until September 24, 2031. Any appeal to this permit must follow the requirements of 40 CFR §124.19. Information about the administrative appeal process may be obtained at www.epa.gov/eab or by contacting the Clerk of the Environmental Appeals Board at 202‐233‐0122. EPA is also approving, concurrently but in a separate action, an aquifer exemption for portions of the aquifers in the injection zones surrounding these wells. A letter describing the aquifer exemption is attached to this email. If you have questions about this permit or aquifer exemption, please contact me at gross.ryan@epa.gov or 206‐553‐ 6293. Sincerely, Ryan J. Gross Ryan Gross, P.E. (he/him) US EPA Region 10 ‐ Groundwater & Drinking Water Section 1200 Sixth Ave, Suite 155, MS 19‐H16, Seattle, WA 98101 ph. 206‐553‐6293 WATER DIVISION UNITED STATES ENVIRONMENTAL PROTECTION AGENCY REGION 10 1200 Sixth Avenue, Suite 155 Seattle, WA 98101 September 24, 2021 Reply to: Gross.Ryan@epa.gov Ms. Amy Peloza Environmental Manager Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, Alaska 99524-4027 Re: Aquifer exemption for Underground Injection Control (UIC) Class I injection wells KU 12-17 and KU 24-7RD at the Kenai Gas Field near Kenai, Alaska Dear Ms. Peloza, The U. S. Environmental Protection Agency (EPA), Region 10, is issuing an exemption from the Safe Drinking Water Act in response to a request by Hilcorp Alaska LLC (Hilcorp) for portions of aquifers at the Kenai Gas Field near Kenai, Alaska. EPA issues this exemption in response to a request from Hilcorp dated March 12, 2019. EPA exempts certain portions of the aquifer underlying the Kenai Gas Field from protection as an underground source of drinking water based on the review of the information provided by Hilcorp and research conducted by EPA, and pursuant to the authority of 40 CFR §144.7. Specifically, the exempted portions are: •The interval between 3600-4200 feet vertical depth and within a ¾ mile radius of the wellbore of KU 12-17 and •The interval between 3720-3960 feet vertical depth and within a ¾ mile radius of the wellbore of KU 24-7RD. EPA finds that the portions of aquifers identified above meet the aquifer exemption criteria under 40 CFR §146.4. Specifically, the portions of the aquifers meet the criteria of: •40 CFR §146.4(a): The portions of aquifers proposed for exemption are not used as a drinking water source. Hilcorp submitted a map and a list showing the location and depth of all drinking water wells within the aquifer exemption area. The map submitted by Hilcorp shows five private drinking water wells within a one-mile radius of the two injection wells. The deepest of the drinking water wells is less than 300 feet deep. Therefore, these drinking water wells draw from an aquifer that is separated from the aquifer at issue in this exemption request by the impermeable layers of coal and shale in the upper confining layer and by over 3000 vertical feet. •40 CFR §146.4(b) (2&3): The portions of the aquifers are situated at a depth or location which makes recovery of water for drinking water purposes economically or technologically impractical or are so contaminated that it would be economically or technologically impractical to render that water fit for human consumption. Hilcorp estimated the cost for nearby public water systems to access, treat, and distribute water from the aquifer. Hilcorp based this estimate on information gathered from the two largest neighboring public water systems, the City of 2 Kenai and the City of Soldotna, and on knowledge of the aquifer water quality. The analysis, which EPA reviewed, shows that both public water systems have adequate water supplies for the foreseeable future and that using water from the aquifer requested for exemption would increase the cost of water per resident dramatically. For any smaller public or private water systems, the per resident cost increase would be greater. EPA issued UIC permit AK-1I018-A to authorize the operation of wells KU 12-17 and KU 24-7RD as UIC Class I non-hazardous wells. The permit was issued separately but concurrently with this aquifer exemption. EPA provided notice to the public of the proposed aquifer exemption and permit issuance and opportunity for public comment. EPA received one comment, but it did not impact the actions considered in this letter. If you have any questions, please contact Ryan Gross of my staff at gross.ryan@epa.gov or by telephone at (206) 553-6293. Sincerely, Daniel D. Opalski Director cc: Christopher Wallace Alaska Oil and Gas Conservation Commission Anchorage, Alaska Marc Bentley Alaska Department of Environmental Conservation Anchorage, Alaska ISSUANCE DATE AND SIGNATURE PAGE U.S. ENVIRONMENTAL PROTECTION AGENCY UNDERGROUND INJECTION CONTROL PERMIT: CLASS I Permit Number AK-1I018-A In compliance with provisions of the Safe Drinking Water Act (SDWA), as amended, (42 U.S.C. 300f 300j 9), and attendant regulations incorporated by the U.S. Environmental Protection Agency (EPA) under Title 40 of the Code of Federal Regulations (CFR), Hilcorp Alaska, LLC (Permittee) is authorized to inject non-hazardous industrial waste utilizing two underground injection control (UIC) Class I injection wells (KU 12-17 and KU 24- 7RD) at the Kenai Gas Field, located south of Kenai, Alaska, in accordance with conditions set forth herein. This permit does not authorize injection of hazardous waste as defined under the Resource Conservation and Recovery Act, as amended, (42 USC 6901) or radioactive wastes (other than naturally occurring radioactive material from pipe scale). The EPA has exempted portions of the aquifer into which these wells inject from protection as an underground source of drinking water (USDW) under the SDWA. This aquifer exemption action is taken concurrently with but separately from this permit issuance. The exempted portions of the aquifer are those that are within ¾ miles of the KU 12-17 wellbore between 3600 and 4200 feet total vertical depth (TVD) and within ¾ miles of the KU 24-7 wellbore between 3720 and 3960 f eet TVD. This permit shall become effective at midnight on the issuance date below in accordance with 40 CFR § 124.15. This permit and the authorization to inject shall expire ten years from the day it is signed at midnight, unless terminated on a prior date. Figures and appendices are referenced to the Kenai Gas Field UIC Class I Permit Application dated July 31, 2019. Issuance date: Mathew J. Martinson CAPT, USPHS Branch Chief, Permits, Drinking Waters, and Infrastructure U.S. Environmental Protection Agency Region 10 (M/S: 19-H16) 1200 Sixth Avenue, Suite 155 Seattle, WA 98101 U.S. EPA Underground Injection Control Class I Permit AK-1I018-A Page 2 TABLE OF CONTENTS ISSUANCE DATE AND SIGNATURE PAGE ........................................................................................... 1 PART I GENERAL PERMIT CONDITIONS ............................................................................................. 4 A. EFFECT OF PERMIT ...................................................................................................................................... 4 B. PERMIT ACTIONS ......................................................................................................................................... 4 1. Modification, Re-issuance or Termination ............................................................................................................... 4 2. Transfer of Permits ................................................................................................................................................... 4 C. SEVERABILITY .............................................................................................................................................. 4 D. CONFIDENTIALITY ...................................................................................................................................... 4 E. GENERAL DUTIES AND REQUIREMENTS ............................................................................................... 5 1. Duty to Comply ........................................................................................................................................................ 5 2. Penalties for Violations of Permit Conditions .......................................................................................................... 5 3. Continuation of Expiring Permits ............................................................................................................................. 5 4. Need to Halt or Reduce Activity Not a Defense ....................................................................................................... 5 5. Duty to Mitigate ....................................................................................................................................................... 5 6. Proper Operation and Maintenance .......................................................................................................................... 5 7. Property Rights ......................................................................................................................................................... 6 8. Duty to Provide Information ..................................................................................................................................... 6 9. Inspection and Entry ................................................................................................................................................. 6 10. Records ..................................................................................................................................................................... 6 11. Reporting Requirements ........................................................................................................................................... 7 12. Twenty-Four Hour Reporting ................................................................................................................................... 8 13. Other Noncompliance ............................................................................................................................................... 8 14. Reporting Corrections............................................................................................................................................... 8 15. Signatory Requirements ........................................................................................................................................... 8 F. PLUGGING AND ABANDONMENT ............................................................................................................ 9 1. Notice of Plugging and Abandonment ...................................................................................................................... 9 2. Plugging and Abandonment Report .......................................................................................................................... 9 3. Cessation Limitation ................................................................................................................................................. 9 4. Cost Estimate for Plugging and Abandonment ......................................................................................................... 9 G. FINANCIAL RESPONSIBILITY .................................................................................................................. 10 PART II WELL SPECIFIC CONDITIONS ................................................................................................ 11 A. CONSTRUCTION ......................................................................................................................................... 11 1. Casing and Cementing of Wells ..............................................................................................................................11 2. Tubing and Packer Specifications ............................................................................................................................11 3. New Wells in the Area of Review (AOR) ...............................................................................................................11 B. CORRECTIVE ACTION ............................................................................................................................... 12 C. WELL OPERATION...................................................................................................................................... 12 1. Requirements Prior to Commencing Injection .........................................................................................................12 2. Mechanical Integrity ................................................................................................................................................12 3. Injection Zone ..........................................................................................................................................................14 4. Injection Pressure Limitation ...................................................................................................................................14 5. Annulus Pressure Limitation ...................................................................................................................................15 6. Injection Fluid Limitation ........................................................................................................................................15 D. MONITORING .............................................................................................................................................. 15 1. General Monitoring Requirements ..........................................................................................................................15 2. Monitoring Continuous Waste Injection ..................................................................................................................15 3. Monitoring Batch Waste Injection ...........................................................................................................................15 4. Alarms and Operational Modifications ....................................................................................................................16 E. REPORTING REQUIREMENTS .................................................................................................................. 16 1. Quarterly Reports ....................................................................................................................................................16 2. Annual Reports ........................................................................................................................................................16 3. Report Certification .................................................................................................................................................17 U.S. EPA Underground Injection Control Class I Permit AK-1I018-A Page 3 APPENDIX A REPORTING FORMS....................................................................................................... 18 U.S. EPA Underground Injection Control Class I Permit AK-1I018-A Page 4 PART I GENERAL PERMIT CONDITIONS A. EFFECT OF PERMIT The Permittee is authorized to engage in underground injection in accordance with the conditions of this permit. Notwithstanding any other provisions of this permit, the Permittee must not conduct any underground injection activity in a manner that allows the movement of fluid containing any contaminant into a USDW, if the presence of that contaminant may cause a violation of any primary drinking water regulation under 40 CFR Part 141 or may otherwise adversely affect the health of persons. Any underground injection activity not specifically authorized in the permit is prohibited. Compliance with this permit during its term constitutes compliance for purposes of enforcement with Part C of the SDWA. Such compliance does not constitute a defense to any action brought under Section 1431 of the SDWA, or any other common or statutory law. Issuance of this permit does not authorize any injury to persons or property, any invasion of other private rights, or any infringement of State or local law or regulations. This permit does not authorize any above ground generating, handling, storage, or treatment facilities. B. PERMIT ACTIONS 1. Modification, Re-issuance or Termination This permit may be modified, revoked and reissued, or terminated for cause as specified in 40 CFR §§ 144.39 and 144.40. In addition, the permit can undergo minor modifications for cause as specified in 40 CFR § 144.41. The filing of a request for a permit modification, revocation and reissuance, or termination, or the notification of planned changes, or anticipated noncompliance on the part of the Permittee does not stay the applicability or enforceability of any permit condition. 2. Transfer of Permits This permit is not transferable to any person except after notice to the EPA Region 10 Water Division Director (the Director) on APPLICATION TO TRANSFER PERMIT (EPA Form 7520-7) and in accordance with 40 CFR § 144.38. The Director may require modification or revocation and reissuance of the permit to change the name of the Permittee and incorporate such other requirements as may be necessary under the SDWA. Upon request, email submittal may be approved by an EPA authorized representative. C. SEVERABILITY The provisions of this permit are severable, and, if any provision of this permit or the application of any provision of this permit to any circumstance is held invalid, the application of such provision to other circumstances, and the remainder of this permit, shall not be affected thereby. D. CONFIDENTIALITY In accordance with 40 CFR Part 2 and 40 CFR § 144.5, any information submitted to the EPA pursuant to this permit may be claimed as confidential by the submitter. Any such claim must be asserted at the time of submission in the manner prescribed in 40 CFR § 2.203 and on the application form or instructions, or, in the case of other submissions, by stamping the words “confidential” or “confidential business information” on each page containing such information. If no claim is made at the time of submission, the EPA may make the information available to the public without further notice. If a claim is asserted, the validity of the claim will be assessed in accordance with the procedures in 40 CFR Part 2 (Public Information). Claims of confidentiality for the following information will be denied: U.S. EPA Underground Injection Control Class I Permit AK-1I018-A Page 5 a. The name and address of the Permittee. b. Information which deals with the existence, absence, or level of contaminants in drinking water. E. GENERAL DUTIES AND REQUIREMENTS 1. Duty to Comply The Permittee must comply with all conditions of this permit. Any permit noncompliance constitutes a violation of the SDWA and is grounds for enforcement action; for permit termination, revocation and reissuance, or modification; or for denial of a permit renewal application; except that the Permittee need not comply with the provisions of this permit to the extent and for the duration such noncompliance is authorized in an emergency permit under 40 CFR § 144.34. 2. Penalties for Violations of Permit Conditions Any person who violates a permit requirement is subject to civil penalties and other enforcement action under the SDWA. Any person who willfully violates permit requirements may be subject to criminal prosecution. 3. Continuation of Expiring Permits a. Duty to Reapply: If the Permittee wishes to continue an activity regulated by this permit after the expiration date of this permit, the Permittee must apply for and obtain a new permit. To be timely, a complete application for a new permit must be received at least 180 calendar days before this permit expires. b. Permit Extensions: The requirements of an expired permit continue in force and effect, in accordance with 5 USC § 558(c), until the effective date of a new permit, if: (1) The Permittee has submitted a timely and complete application for a new permit; and (2) The EPA, through no fault of Permittee, does not issue a new permit with an effective date on or before the expiration date of the previous permit. 4. Need to Halt or Reduce Activity Not a Defense It shall not be a defense for the Permittee in an enforcement action that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of this permit. 5. Duty to Mitigate The Permittee must take all reasonable steps to minimize or correct any adverse impact on the environment resulting from noncompliance with this permit. 6. Proper Operation and Maintenance The Permittee must, at all times, properly operate and maintain all facilities and systems of treatment and control (and related appurtenances) which are installed or used by the Permittee to achieve compliance with the conditions of this permit. Proper operation and maintenance includes: effective performance, adequate funding, adequate operator staffing and training, and adequate laboratory and process controls, including appropriate quality assurance procedures. This provision requires the operation of back-up or auxiliary facilities or similar systems only when necessary to achieve compliance with the conditions of this permit. De-characterized waste may be appropriately disposed in a Class I non-hazardous well [refer to 40 CFR § 148.1(d)]. U.S. EPA Underground Injection Control Class I Permit AK-1I018-A Page 6 7. Property Rights This permit does not convey any property rights or mineral rights of any sort, or any exclusive privilege. 8. Duty to Provide Information The Permittee must provide to the Director any information that the Director may request to determine whether cause exists for modifying, revoking and reissuing, terminating this permit, or to determine compliance with this permit. The Permittee must also provide to the Director, upon request, copies of records, that are retained under the conditions of this permit. 9. Inspection and Entry The Permittee must allow the Director or an EPA authorized representative(s), upon the presentation of credentials and other documents as may be required by law, to: a. Enter upon the Permittee's premises where a regulated facility or activity is located or conducted, or where records are kept under the conditions of this permit; b. Have access to and copy, at reasonable times, any records (including logging data) that are retained under the conditions of this permit; c. Inspect and photograph, at reasonable times, any facilities, equipment (including monitoring and control equipment), practices, or operations regulated or required under this permit; and d. Sample or monitor, at reasonable times, for the purposes of assuring permit compliance or as otherwise authorized by SDWA, any substances or parameters at any location. 10. Records a. The Permittee must retain records and all monitoring information, including all calibration and maintenance records and all original strip chart recordings for continuous monitoring instrumentation, copies of all reports required by this permit and records of all data used to complete this permit application for a period of at least five years from the date of the sample, measurement, report or application. These periods may be extended by request of the Director at any time. The Permittee may retain these records in hard copy or electronic format. b. The Permittee must retain records concerning the nature and composition of all injected fluids for three years after the completion of plugging and abandonment. At the conclusion of the retention period, if the Director so requests, the Permittee must deliver the records to the Director. The Permittee must continue to retain the records after the three-year retention period unless the Permittee delivers the records to the Director or obtains written approval from the Director to discard the records. The Permittee may retain these records in hard copy or electronic format. c. Records of monitoring information must include: (1) The date, exact place, and time of sampling or measurements; (2) The name(s) of the individual(s) who performed the sampling or measurements; (3) The date(s) analyses were performed; (4) The name(s) of the individual(s) who performed the analyses; (5) The analytical techniques or methods used; and (6) The results of such analyses. U.S. EPA Underground Injection Control Class I Permit AK-1I018-A Page 7 d. Monitoring of the nature of injected fluids must comply with applicable analytical methods cited and described in 40 CFR § 136.3, in Appendix I of 40 CFR Part 261, or, in certain circumstances, by other methods that have been approved by the Director. e. As part of the Completion Report for any new, sidetracked, or converted well, the Permittee must submit a Waste Analysis Plan (WAP) that describes the procedures to be carried out to obtain detailed chemical and physical analysis of representative samples of the waste including the quality assurance procedures used including the following: (1) The parameters for which the waste will be analyzed and the rationale for the selection of these parameters; (2) The test methods that will be used to test for these parameters; and (3) The sampling method that will be used to obtain a representative sample of the waste to be analyzed. At the request of the Permittee and upon approval of the EPA, the WAP submitted with the permit application may be incorporated by reference to satisfy the WAP submittal requirement. f. The Permittee must require a written manifest for each batch load of waste received for injection of waste streams that are not hard-piped and continuous. The manifest must contain a description of the nature and composition of all injected fluids, date of receipt, source of material received for disposal, name and address of the waste generator, a description of the monitoring performed and the results, a statement describing whether the waste(s) is exempt from regulation as hazardous waste as defined by 40 CFR § 261.4, and any information on extraordinary occurrences. For waste streams that are hard-piped continuously from the source to the wellhead, the Permittee must retain: (1) Continuous measurement of the discharge rate, (2) A description of the nature and composition of all injected fluids, and (3) A hazardous waste determination as defined by 40 CFR § 261.4. g. The Permittee must note dates of most recent calibration or maintenance of gauges and meters used for monitoring required by this permit on the gauge or meter. Earlier records of calibration and maintenance must be available through a computerized maintenance history database. 11. Reporting Requirements a. Planned Changes: The Permittee must give notice to the Director, as soon as possible, of any planned physical alterations or additions to the permitted facility or changes in type of injected fluid(s). b. Anticipated Noncompliance: The Permittee must give notice to the Director of any significant planned changes in the permitted facility or activity that may result in noncompliance with permit requirements at least 5 business days before the change is performed. The Permittee must send this notification by email. c. Compliance Schedules: The Permittee must submit reports of compliance or noncompliance with, or any progress reports on, interim and final requirements contained in any compliance schedule of this permit to the Director no later than 30 calendar days following each schedule date contained in the compliance schedule. U.S. EPA Underground Injection Control Class I Permit AK-1I018-A Page 8 12. Twenty-Four Hour Reporting a. The Permittee must report to the Director or an EPA authorized representative any noncompliance that may endanger health or the environment within 24 hours from the time the Permittee becomes aware of the information, including the following: (1) Indication or other information that any contaminant may cause an endangerment to a USDW or may otherwise adversely affect human health. (2) Noncompliance with a permit condition. (3) Malfunction of the injection system. b. The Permittee must provide to the Director or an EPA authorized representative a written submission (in electronic format for release to the public) within five calendar days of the time the Permittee becomes aware of the circumstances. The written submission must contain a description of the noncompliance and its cause(s); the period of noncompliance including exact date and times; the anticipated timeframe the noncompliance is expected to continue, and steps taken or planned to reduce, eliminate, and prevent recurrence of the noncompliance. The Permittee must provide email notice to affected stakeholders, such as Tribal Governments, if warranted as determined by an EPA authorized representative. 13. Other Noncompliance The Permittee must include in the monitoring reports information regarding all instances of noncompliance not otherwise reported. The reports must contain the information listed in Permit Condition Part I E.12.b. 14. Reporting Corrections When the Permittee becomes aware that it failed to submit any relevant facts or submitted incorrect information in a permit application or in any report to the Director, the Permittee must submit such facts and/or information to EPA within 10 calendar days. 15. Signatory Requirements a. All permit applications, reports required by this permit, and other information requested by the Director must be signed by a principal executive officer of at least the level of vice-president, or by a duly authorized representative of that person, in accordance with 40 CFR § 144.32. A person is a duly authorized representative only if: (1) The authorization is made in writing by a principal executive of at least the level of vice-president. (2) The authorization specifies either an individual or a position having responsibility for the overall operation of the regulated facility or activity, such as the position of plant manager, operator of a well or a well field, superintendent, or position of equivalent responsibility. A duly authorized representative may thus be either a named individual or any individual occupying a named position. (3) The written authorization record is retained on-site and a copy is submitted by email to the Director. Upon request, the original is submitted to the Director or an EPA authorized representative. b. Changes to Authorization: If an authorization under paragraph 15.a. of this section is no longer accurate because a different individual or position has responsibility for the overall operation of the facility, a new authorization satisfying the requirements of paragraph 15.a. of this section U.S. EPA Underground Injection Control Class I Permit AK-1I018-A Page 9 must be submitted to the Director. The Permittee may submit this authorization with any reports, information, or applications to be signed by an authorized representative. c. Certification: Any person signing a document under paragraph 15.a. of this section must make the following certification: “I certify under the penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted. Based on my inquiry of the person or persons who manage the system, or those persons directly responsible for gathering the information, the information is, to the best of my knowledge and belief, true, accurate, and complete. I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment for knowing violations.” F. PLUGGING AND ABANDONMENT 1. Notice of Plugging and Abandonment The Permittee must notify the Director no later than 45 calendar days before conversion or abandonment of the well. 2. Plugging and Abandonment Report The Permittee must plug and abandon the well as provided in the Plugging and Abandonment Plan (7520-6 Attachment E) of UIC Class I Permit Application submitted by the Permittee, which is hereby incorporated as a part of this permit. Within 60 calendar days after plugging any well, the Permittee must submit a report to the Director in accordance with 40 CFR § 144.51(p). The EPA reserves the right to change the manner in which the well will be plugged if the well is not proven to be consistent with EPA requirements for construction and mechanical integrity. The Director may require the Permittee to update the estimated plugging cost periodically. 3. Cessation Limitation After a cessation of operations of two years, the well is considered to be in temporarily abandoned status. The Permittee must permanently plug and abandon the well in accordance with the approved plan and 40 CFR § 144.52(a)(6) within one year of entering temporarily abandoned status, unless the Permittee: a. Provides notice to the Director no later than two years and one month after cessation of operations, and b. Provides information that, to the Director’s satisfaction, demonstrates the Permittee’s intent to use the well in the future; or c. Describes actions or procedures, satisfactory to the Director, which the Permittee will take to ensure that the well will not endanger USDWs during the period of temporarily abandonment. These actions and procedures must include compliance with the technical requirements applicable to active injection wells unless waived by the Director. 4. Cost Estimate for Plugging and Abandonment a. The Permittee is required in the permit application to estimate the per well cost of plugging and abandonment of the permitted Class I UIC well(s). Please refer to the permit application (7520-6 attachment E) for the per well plugging and abandonment cost estimates(s) for the year the application is submitted. Such estimates must be based upon costs that a third party would incur to plug the wells. U.S. EPA Underground Injection Control Class I Permit AK-1I018-A Page 10 b. The Permittee must submit financial assurance and a revised estimate prior to April 30 of each year. The estimate must be made in accordance with 40 CFR § 144.62. The Director or an EPA authorized representative may approve email submittal of this requirement provided the Permittee retains the original and submits the original upon request. c. The Permittee must keep the latest plugging and abandonment cost estimate at the Facility or at the Permittee’s central files in Alaska during the operating life of the Facility. d. When the cost estimate changes, the Permittee must amend the financial assurance instrument submitted under condition G of this permit to ensure that appropriate financial assurance for plugging and abandonment is maintained continuously. G. FINANCIAL RESPONSIBILITY The Permittee must demonstrate and continuously maintain financial responsibility and resources sufficient to close, plug, and abandon the underground injection operation as provided in the Plugging and Abandonment Plans and consistent with 40 CFR §144 Subpart F, which the Director has chosen to apply. The Permittee must not substitute an alternative demonstration of financial responsibility for that which the Director has approved, unless it has previously submitted evidence of that alternative demonstration to the Director and the Director notifies the Permittee that the alternative demonstration of financial responsibility is acceptable. Consistent with 40 CFR § 144.63 and regarding incapacity of owners or operators, guarantors, or financial institutions, the Permittee must notify the Director by registered mail of the commencement of a voluntary or involuntary proceeding under Title 11 (Bankruptcy), U.S. Code, naming the owner or operator as debtor, within 10 business days after the commencement of the proceeding. Furthermore, an owner or operator must notify the Regional Administrator by certified mail of the commencement of a voluntary or involuntary proceeding under Title 11 (Bankruptcy), U.S. Code, naming the owner or operator as debtor, within 10 business days after the commencement of the proceeding. Prior to beginning construction of any new well, conversion to an injection well, or sidetracking of an existing injection well, the Permittee must demonstrate to the EPA that financial responsibility has been established for such planned activity. The value of this financial assurance must meet the requirements in Part I.F.4 of this permit. The Permittee must not begin construction of any new well, conversion to an injection well, or sidetracking of an existing injection well without first receiving approval from the Director or an EPA authorized representative. U.S. EPA Underground Injection Control Class I Permit AK-1I018-A Page 11 PART II WELL SPECIFIC CONDITIONS A. CONSTRUCTION 1. Casing and Cementing of Wells The Permittee must ensure that injection occurs only into the approved injection interval through wells that are cased and cemented (see Part II.C.3., below). The Permittee must install casing and cement in accordance with a casing and cement program approved submitted by the Permittee for approval by the Director and in accordance with EPA UIC Class I well construction practices (40 CFR § 146.12) and all applicable State of Alaska laws and regulations. For any future Class I wells to be drilled under this permit (including replacement or sidetrack wells), in addition to the above requirements, the Permittee must provide not less than 30-calendar days advance notice to the Director or an EPA authorized representative to witness all cementing operations. The Director or an EPA authorized representative may increase or decrease the duration of the advance notice requirement. The Permittee must cement the surface casing of each well back to the surface. If primary cement returns to surface are not observed, the Permittee must notify the Director or an EPA authorized representative as to the nature of any augmented testing proposed to ensure the integrity of the cement bond and adequacy of any Top Job procedure. The intermediate casing (i.e., long string casing) must be cemented from the casing shoe to at least 200 feet above the upper confining zone as identified in the Fact Sheet. During construction activities that involve the emplacement of cement, the Permittee must run Cement Bond/Ultrasonic Imaging or other logs and pressure tests (e.g., leak off test and/or formation integrity test) for both the surface and production casings to confirm zonal isolation and verify casing integrity. The Permittee must provide final logs to the Director or an EPA authorized representative with the Completion Report. The casing, cementing and well construction must comply with the procedures outlined in proposed well construction plan contained in the permit application. Should a change(s) be required to the previously approved casing and cementing program due to unanticipated conditions, the Permittee must notify the Director or an EPA authorized representative in writing (hard copy or email) as to the nature of the change(s) and the unanticipated conditions requiring the change. The Permittee must not construct the proposed change without approval from the Director or an EPA authorized representative. 2. Tubing and Packer Specifications The Permittee must inject fluids through wells containing tubing with a packer. The Permittee must install tubing and packer in accordance with the procedures in the well construction plan submitted by the Permittee to the Director or an EPA authorized representative. In the event that a packer needs to be set or reset at a revised depth at a later date, the Permittee must perform a mechanical integrity test, submit the necessary information as determined by an EPA authorized representative, and obtain authorization from the Director or an EPA authorized representative prior to resuming injection. The Permittee must set the packer no more than 200 feet measured depth above the top of the injection interval unless an alternative placement is specified and authorized by the Director or an EPA authorized representative. The EPA hereby approves the packer placement in well KU 12-17 and well KU 24-7RD as of the issuance date of this permit. 3. New Wells in the Area of Review (AOR) The EPA has set a 3/4 mile radius as the AOR for this Class I UIC permit. If any development or service wells are drilled in the future that penetrate the injection interval within the AOR, these wells U.S. EPA Underground Injection Control Class I Permit AK-1I018-A Page 12 must have casing cemented to the formation throughout the entire section from 200 feet TVD below to 200 feet TVD above the (proposed, revised or updated) injection zone as identified in the permit application. B. CORRECTIVE ACTION The Permittee identified 22 wells that may intersect the injection interval within the 3/4 mile AOR of injection wells KU 12-17 and KU 24-7RD. The Permittee provided records for wells in the AOR. These records show that casings of all of these wells are cemented to the formation through the injection zone. Therefore, EPA requires no corrective action to prevent injected fluids from moving above the confining zone. If the Permittee later discovers that a well or wells within the AOR require(s) corrective action to prevent fluid movement, then the Permittee must inform EPA upon such discovery and provide a corrective action plan for the Director or an EPA authorized representative to review and approve. If EPA or the Permittee discovers that fluids have moved above the upper confining zone along a wellbore within the AOR, then the Permittee must cease injection until the fluid movement problem can be diagnosed and corrected. C. WELL OPERATION 1. Requirements Prior to Commencing Injection Unless the well has previously (within the last 180 calendar days) fulfilled the requirements of Part II C.1. of this permit, prior to commencing injection into a newly constructed, converted, or sidetracked injection well, the Permittee must fulfill the requirements listed in parts Part II.C.1 (a), (b) and (c). a. The Permittee must submit the COMPLETION FORM FOR INJECTION WELLS (EPA Form 7520-18) with logging data; and either: (1) The Director or an EPA authorized representative will inspect or otherwise review the newly constructed, converted, or sidetracked injection well and find it complies with the conditions of the permit; or (2) The Permittee has not received notice from the Director or an EPA authorized representative of intent to inspect or otherwise review the new, converted, sidetrack or replacement injection well within 13 business days of receipt of the Completion Report, in which case the EPA waives prior inspection or review. b. The Permittee must demonstrate that the well has mechanical integrity as described in Part II.C.2., to the satisfaction of the Director or an EPA authorized representative. The Permittee must notify the EPA at least 10 business days prior to conducting the initial mechanical integrity test so that an EPA authorized representative may witness the test. c. The Permittee must conduct a step-rate injection test and submit to EPA a preliminary report that summarizes the results. Upon approval by the Director or an EPA authorized representative, the Permittee may submit the results of a previously conducted step-rate injection test to satisfy this requirement. The Permittee submitted step-rate injection test results in support of the permit application that satisfy this requirement. 2. Mechanical Integrity a. Standards The injection well must have and maintain mechanical integrity pursuant to 40 CFR § 146.8. b. Prohibition without Demonstration of Mechanical Integrity U.S. EPA Underground Injection Control Class I Permit AK-1I018-A Page 13 This permit prohibits injection operations at the permitted wells after the effective date of this permit unless the Permittee has demonstrated mechanical integrity by conducting the following tests and submitted the results to the Director: (1) The Permittee must demonstrate there is no significant leak in the casing, tubing or packer by conducting a mechanical integrity test of the tubing/casing inner annulus (MITIA). To start the test, the Permittee must bring the annulus to a starting pressure of at least 2200 pounds per square inch (psi), but not to exceed 70% of the minimum yield strength of the casing. The Permittee must observe the pressure in the tubing, inner annulus, and (if present) outer annulus of the well for the duration of the test. The results of the test must satisfy either (i) or (ii) below: i. the inner annulus pressure does not decline by more than 10% of the starting pressure during the test period and the loss in the second half of the test period is less than 50% of the loss in the first half of the test period, or ii. the inner annulus pressure does not decline by more than 2% of the starting pressure during the test period and the loss in the second half of the test period is less than the loss in the first half of the test period. If the well fails to satisfy (i) or (ii) during the first 30-minute test period, the test may be extended by an additional 30 minutes to demonstrate stabilization. The Permittee must notify the Director or an EPA authorized representative 30 calendar days prior to commencement of the MITIA. After the initial test, the Permittee must conduct an MITIA annually if the well is active and once every two years if the well is inactive until expiration of the permit. The Director or an EPA authorized representative may extend the due date for the MITIA up to three months. Also, the Director or an EPA authorized representative may revise (either increase or decrease) the frequency with which the Permittee must conduct the MITIA. (2) The Permittee must conduct an approved fluid movement test to detect fluid migration outside of the permitted injection intervals at an injection pressure at least equal to the average continuous injection pressure observed at the well in the previous six months. Approved fluid movement test methods include, but are not limited to: tracer surveys, temperature survey logs (conducted after a 12-hour shut-in, at a minimum, unless otherwise authorized by the EPA authorized representative), noise logs, oxygen activation/water flow logs, borax pulse neutron logs, or other equivalent logs. The Permittee must notify the Director or an EPA authorized representative 30 calendar days prior to commencement of the fluid movement test and request approval for any testing procedure not previously used to satisfy this requirement. The Permittee must initially conduct a fluid movement test and submit the logs of this test upon completion of the well and prior to initiation of injection at a new, converted, sidetracked well. After the initial test, the Permittee must conduct a fluid movement test and submit test logs and results every two years while the well is active until expiration of the permit. The Director or an EPA authorized representative may extend the due date of this testing requirement up to three months. Also, the Director or an EPA authorized representative may revise (either increase or decrease) the frequency with which the Permittee must conduct a fluid movement test. (3) The Permittee must conduct tubing inspection tests to monitor condition, thickness, and integrity of the downhole tubing. The Permittee must notify the Director or an EPA authorized representative 30 calendar days prior to commencement of the tubing inspection test and request approval for any testing procedure not previously used to satisfy this requirement. The Permittee must conduct a tubing inspection test and submit test logs and results every two years while the well is active until expiration of the permit. The Director or an EPA authorized representative may extend the due date for the tubing inspection up to U.S. EPA Underground Injection Control Class I Permit AK-1I018-A Page 14 three months. Also, the Director or an EPA authorized representative may revise (either increase or decrease) the frequency with which the Permittee must conduct the tubing inspection test. c. Terms and Reporting (1) The Permittee must submit a copy of the log(s) and a descriptive and interpretive report of the mechanical integrity tests identified in Part II. C. 2. b. (2) and (3) to EPA within 45 calendar days of completion in hard copy or electronic format, unless waived by an EPA authorized representative. Immediately after well logging activities, the Permittee must submit a copy of any log(s) to an EPA authorized representative, if requested. This includes logging events associated with construction activities and mechanical integrity testing. (2) The Permittee must demonstrate mechanical integrity by the MITIA in Part II. C. 2. b. (1) prior to resuming injection if, at any time, the tubing is removed from the well or a loss of mechanical integrity becomes evident during operation. The Permittee must report the results of such tests within 45 calendar days of completion of the tests. (3) The Director will notify the Permittee of the acceptability of the mechanical integrity demonstration within 10 business days of receipt of the results of the mechanical integrity tests. The Permittee may continue to inject during this review period. If the Director does not notify the Permittee within 10 business days, the Permittee may continue to inject. (4) In the event that the well fails to demonstrate mechanical integrity during a test or a loss of mechanical integrity occurs during operation, the Permittee must halt injection immediately and must not resume injection until the Director or an EPA authorized representative gives approval to resume injection. (5) The Director may, by written notice, require the Permittee to demonstrate mechanical integrity at any time. 3. Injection Zone The Permittee may only inject fluid into the designated injection zone for each permitted well. For well KU 12-17, the injection zone includes the A10, A11, B1 and B2 sands of the Sterling Formation Pool 3 and Pool 4. For well KU 24-7RD, the injection zone includes the A10 and A11 sands of the Sterling Formation Pool 3. These injection zones are described in the Fact Sheet and depicted in the Completion and Type Log in the permit application. The Permittee may not inject at a pressure that causes the propagation of fractures in the injection zone or the confining zones. EPA exempts the portions of the aquifers in the injection zones of wells KU 12-17 and KU 24-7RD within ¾ miles of the wellbore from protection as a USDW under SDWA. The aquifer exemption is separate from, but concurrent with, this permit issuance. 4. Injection Pressure Limitation The Permittee must not inject at a pressure that initiates new fractures or propagates existing fractures in the injection zone or the upper confining zone, as described in the Fact Sheet. The Permittee must not inject at a pressure exceeding the maximum injection pressure of 2200 psi, measured at the wellhead, except as follows: a. If a plant is shut-down or outage (unrelated to fluid injection activities) occurs. U.S. EPA Underground Injection Control Class I Permit AK-1I018-A Page 15 b. If a well stimulation is required. In such instances, the Permittee must notify the Director or an EPA authorized representative by telephone or email within 24 hours of the initial exceedance of 2200 psi and must submit a written incident report not later than 10 calendar days thereafter. The Permittee must never inject above the working pressure for which the well components are rated. 5. Annulus Pressure Limitation The Permittee must fill the tubing-casing annulus with a corrosion inhibiting solution. The Permittee must not allow the positive surface pressure in the tubing-casing annulus to exceed 2000 psi. The difference between the annulus pressure and the injection pressure must be sufficient to easily detect pressure communication. EPA does not intend the authorization of up to 2000 psi on the inner annulus to allow the Permittee to continue to injection in the event of a loss of mechanical integrity or if pressure communication exists between the inner annulus and the tubing or outer annulus. 6. Injection Fluid Limitation This permit authorizes the Permittee to inject only wastes identified in the permit application that are not characterized as hazardous. De-characterized waste must be disposed of appropriately (refer to 40 CFR § 148.1(d)). The Permittee may dispose of waste generated from construction, repair, operation and maintenance of Class I injection wells and associated injection well piping in this Class I non- hazardous injection well. This permit does not authorize injection of radioactive wastes, other than naturally occurring radioactive material (NORM) from pipe scale and/or radioactive tracer beads. If third party wastes are accepted, the third party must certify the wastes are eligible for injection pursuant to the terms of this permit. Furthermore, this permit authorizes the Permittee to inject only common oil and gas industry-related wastes. The common oil and gas industry-related waste streams listed in Exhibit 2 of the “Wells KU 12-17 and KU 24-7RD Class I Disposal Waste Analysis Plan (WAP)” submitted by Hilcorp with the UIC Class I permit application and in Appendix A of the Fact Sheet. D. MONITORING 1. General Monitoring Requirements The Permittee must ensure that all wells authorized by this permit are monitored 24 hours per day by trained and qualified personnel while injection is occurring. Samples and measurements collected for the purpose of monitoring must be representative of the monitored activity. 2. Monitoring Continuous Waste Injection The Permittee must install, maintain, and use monitoring devices to continuously monitor injection pressure and rate for those waste streams that are hard-piped and continuous, and to monitor the pressure of non-freezing solution in the tubing-casing annulus. Calculated flow data or periodic monitoring are not acceptable except as a back-up system if the primary continuous injection rate device malfunctions or power outage occurs. 3. Monitoring Batch Waste Injection The Permittee must continuously staff and visually monitor batch waste injection operations at the well site. During these operations, the Permittee must maintain a chronological record of injected wastes, including the time and date, description of waste, volume, injection pressure, injection rate, U.S. EPA Underground Injection Control Class I Permit AK-1I018-A Page 16 waste generating company and location, transport company/driver, and Hilcorp official confirming Class I eligibility. 4. Alarms and Operational Modifications The Permittee must install, continuously operate, and maintain alarms to notify operators when injection or annular pressure is outside of the normal operating range. These alarms must be sufficient to alert operators in all operating spaces including, but not limited to, the control room. The Permittee must install and maintain an emergency shutdown system stop injection if there is a loss of mechanical integrity in the inner annulus. The Permittee must submit plans and specifications for the alarms to the Director or an EPA authorized representative prior to the initiation of injection. E. REPORTING REQUIREMENTS 1. Quarterly Reports The Permittee must submit quarterly reports by email to the Director or an EPA authorized representative. The reports must include the following information: a. Monthly average, maximum, and minimum values for injection pressure, rate, and volume must be reported on INJECTION WELL MONITORING REPORT (EPA Form 7520-8). b. Daily or hourly monitoring data in electronic spreadsheet format approved by the Director or EPA authorized representative. This data must include average and maximum values for: injection pressure, inner annulus pressure, and injection rate. c. Graphical plots of continuous injection pressure, inner annulus pressure, and injection rate. d. Physical, chemical, and other relevant characteristics of the injected fluid. e. A list of all batch injections. The list must show time and date, description of waste, volume, waste generating company and location, and Hilcorp official confirming Class I eligibility. f. Descriptions of any well workover or other significant maintenance of downhole or injection- related surface components. g. Results of all mechanical integrity tests performed since the previous report, including any maintenance-related tests and “practice” tests. h. Reports of changes in annular pressures in any wells in the AOR that could be indicative of pressure communication between those wells and the UIC Class I injection wells authorized by this permit. i. Results of any other tests required by the Director. 2. Annual Reports The Permittee must submit to the Director an annual performance report for the period of October 1 through September 30. This report must be submitted by November 30 of each year. (For example, injection data from October 1, 2019, through September 30, 2020, should be reported by November 30, 2020). The annual performance report must include, but not be limited to: a. Rate and pressure performance. b. Surveillance logging and results. c. Fill depth. U.S. EPA Underground Injection Control Class I Permit AK-1I018-A Page 17 d. Volumetric analysis of the disposal storage. e. Annual or cumulative injection volumes. f. Estimated fracture growth and any updates to fracture model analyses. g. Indications of communication between the injection wells and other wells in the AOR. h. Updates of operational plans. i. An overview of the commercial activities for the year. j. A list of companies with whom Hilcorp has a facility user agreement or a road use agreement. Some information may not be available every year, if those activities did not take place during the reporting period (examples: surveillance logging, fill depth, and survey results). 3. Report Certification All reports and notifications required by this permit must be signed and certified in accordance with Part I.E.15; stored and maintained in electronic format at the Permittee’s Facility or company headquarters; submitted by email to the Director or an EPA authorized representative; and, upon request by the Director or an EPA authorized representative, submitted as a hard copy to the following address: U.S. Environmental Protection Agency Region 10 Ground Water and Drinking Water Section, UIC Program (19-H16) 1200 Sixth Avenue, Suite 155 Seattle, Washington 98101-3140 U.S. EPA Underground Injection Control Class I Permit AK-1I018-A Page 18 APPENDIX A REPORTING FORMS PDF copies of following forms are available on the EPA’s web site at: https://www.epa.gov/uic/underground-injection-control-reporting-forms-owners-or-operators 7520-7 APPLICATION TO TRANSFER PERMIT 7520-8 INJECTION WELL MONITORING REPORT 7520-18 COMPLETION REPORT FOR INJECTION WELLS US Environmental Protection Agency April 2021 Fact Sheet for Proposed Issuance of Underground Injection Control (UIC) Permit AK-1I018-A What action does this fact sheet describe? A company, Hilcorp Alaska, LLC (Hilcorp), has applied to construct and operate two Class I non-hazardous injection wells at the Kenai Gas Field (KGF) near Kenai, Alaska. The U.S. Environmental Protection Agency (EPA) proposes to permit this activity. In this fact sheet, EPA sets forth the principal facts considered in drafting this permit. This document also describes EPA’s proposed exemption of a portion of the aquifer surrounding the proposed injection zone associated with these wells. What is proposed in the permit? This permit would allow Hilcorp to inject non-hazardous waste into subsurface geologic formations underneath the KGF. It would not allow Hilcorp to inject wastes determined to be hazardous under the Resource Conservation and Recovery Act (RCRA). Will new wells be drilled? No. The permittee has proposed to inject waste through two existing wells that have been used to inject similar fluids into the same geologic formation for over ten years. Past injection was permitted by Alaska Oil and Gas Conservation Commission (AOGCC) under its UIC Class II program. Fluid injection of some kind has been performed at this field for over 25 years. Why does the EPA propose to exempt this aquifer from status as a source of drinking water? The EPA may exempt aquifers or portions of aquifers from status as an underground source of drinking water (USDW) under the Safe Drinking Water Act (SDWA). This may occur if the aquifers do not currently serve as a source of drinking water and cannot in the future serve as a source of drinking water. The permittee has shown it would be technically and economically impractical to use these portions of the aquifer as a drinking water source because of its depth and quality, and because of the availability of alternative drinking water sources. Does this injection endanger drinking water or environmental resources? No. The injection zone is located more than 3000 feet below the ground surface. It is separated from surface waters and other subsurface drinking water aquifers by several impermeable geological layers. These confining impermeable layers have trapped oil and gas for millions of years, demonstrating their ability to prevent the upward migration of fluids. What will be injected into the well? Injected waste will include: liquids associated with the operation and maintenance of an oil and gas facility, storm water, snow melt, domestic waste water, drilling cuttings and muds, and produced water. How can I comment and/or request a hearing? The EPA will accept public comments and public hearing requests related to the draft permit and draft aquifer exemption beginning on July 20, 2020 at 9 AM Alaska Time and ending on August 20, 2020 at 5 PM Alaska Time. If you would like to make a comment or request a hearing, see the Public Comment section at the end of this Fact Sheet or go to www.epa.gov/publicnotices. For more information, contact Ryan Gross (gross.ryan@epa.gov, 206-553-6293). Fact Sheet: UIC Class I Permit AK-1I018-A April 2021 US Environmental Protection Agency Page 2 of 3 A. Proposed Action EPA proposes to issue UIC Permit AK-1I018-A to Hilcorp to operate two UIC Class I non-hazardous industrial waste injection wells (KU 12-17 and KU 24-7RD). EPA also proposes to exempt a portion of the aquifer into which these wells inject from status as a USDW under the SDWA. B. Background Hilcorp submitted an application to EPA on July 30, 2019, for a permit to operate two UIC Class I non- hazardous industrial waste injection wells at the KGF. The permit would allow Hilcorp to inject fluid through two wells currently permitted by the AOGCC as UIC Class II wells. The KGF is located approximately eight miles south of the city of Kenai on the eastern shore of the Cook Inlet. The Unocal Corporation discovered natural gas at the KGF in 1959. Unocal constructed and operated the first production wells at the field in 1961. In 1994, Marathon Oil Company assumed full ownership and operation of the field. Hilcorp assumed full ownership and operation of the field from Marathon Oil Company in 2012. There are 98 wells at the KGF, including 42 producing wells and 13 storage wells. Since production began, more than 2.4 trillion cubic feet of gas have been produced at the KGF. These wells produce gas from the Tyonek and Sterling formations. Underground injection at the KGF under Class II permit issued by AOGCC began in 1986. Since AOGCC issued these permits, over 13 million barrels of fluid have been injected at the field. AOGCC requires the permittee to test the mechanical integrity of the wells every two years. The most recent tests, witnessed by AOGCC in April 2019, successfully demonstrated mechanical integrity of both wells at issue in this action. In 1984, EPA issued an aquifer exemption for the aquifer underlying the KGF from status as a USDW in the Code of Federal Regulations (CFR) at 40 CFR §147.102. This aquifer exemption allows only UIC Class II injection into the aquifer. Hilcorp is currently using four UIC Class II injection wells in the field, two of which would be converted to UIC Class I injection wells by the permitting action currently being considered. The Class II wells currently in use are permitted by AOGCC. Class II wells differ from Class I wells in the construction, operation and monitoring requirements, as well as the type of fluid that may be injected. The wells at issue in this action inject into previously hydrocarbon-bearing formations now experiencing water encroachment. Figure 1. Area Map Fact Sheet: UIC Class I Permit AK-1I018-A April 2021 US Environmental Protection Agency Page 3 of 4 C. Regulatory Framework The EPA UIC program is authorized by Part C of the SDWA for the principal purpose of protecting USDWs from endangerment by injection wells. A USDW is an aquifer which currently serves as a source of potable water or which, by its potential productivity and natural water quality, could serve as a public water supply. It is defined in the CFR at 40 CFR §144.3. Primary responsibility for implementing the SDWA UIC program in Alaska is shared between EPA and AOGCC. EPA regulates Class I injection wells, which are used to dispose of hazardous or non- hazardous waste beneath the lowermost USDW. Class I non-hazardous wells may only inject materials defined as non-hazardous by RCRA and materials exempted from RCRA classification because they originate from oil and gas exploration and production. AOGCC regulates Class II injection wells. Class II wells are those which dispose of waste brought to the surface from oil and gas production operations, enhance recovery of oil and gas, or store hydrocarbons which are liquid at standard temperature and pressure (40 CFR § 144.6). Class II wells cannot inject hazardous fluids, or those that are not associated with hydrocarbon production activities as described above. Applicable regulations concerning injection well requirements can be found in 40 CFR §144 and §146. Criteria and standards applicable to Class I wells are found at 40 CFR §146 Subpart B. For more information on injection well classes, see: www.epa.gov/uic/underground-injection-control-well-classes. D. Project Overview 1. Well Construction The permit currently being considered for issuance by EPA will allow Hilcorp to operate two UIC Class I non-hazardous injection wells, KU 12-17 and KU 24-7RD. i. Injection Well KU 12-17 Construction of injection well KU 12-17 began on June 21, 2008. The well reaches a vertical depth of 5786 feet. The length of the wellbore is 6585 feet and deviates from top-hole to bottom-hole in an east- southeast direction. This well is constructed of three layers of pipe extending to different depths. The pipe is cemented to the formation to prevent migration of fluid upward along the outside of the pipe. A packer is installed between the tubing and the casing at a depth of 3865 feet true vertical depth (TVD) to prevent migration of fluid upward between the tubing and casing of the well. The injection zone for KU 12-17 is in the A10, A11, B1, and B2 sands of the Sterling Pool 3 and Pool 4, found at 3600-4200 feet TVD. The well is perforated at three locations within the interval 4066-4140 feet TVD to allow the injected fluids to enter the formation. ii. Injection Well KU 24-7RD Injection well KU 24-7RD was drilled as a sidetrack of well KU 24-7 on June 24, 2005. Well KU 24-7 was previously used as an injection well for cuttings disposal into the Sterling Formation (Pools 3 and 4). KU 24-7 was sidetracked to resolve mechanical integrity issues. The original wellbore was plugged. KU 24-7RD reaches a vertical depth of 4023 feet. The total length of the wellbore is 4800 feet and deviates from top-hole to bottom-hole in a northwest direction. The well is constructed of four layers of pipe extending to different depths. The pipe is cemented to the formation to prevent migration of fluid upward along the outside of the pipe. A packer is installed between the tubing and the casing just above the injection zone at a depth of 3701 feet TVD to prevent migration of fluid upward between the tubing and casing of the well. Fact Sheet: UIC Class I Permit AK-1I018-A April 2021 US Environmental Protection Agency Page 4 of 5 The injection zone for KU 24-7RD is in the A10 and A11 sands of the Sterling Pool 3, found at 3720- 3960 feet TVD. The well is perforated at four locations within the interval 3728-3954 feet TVD to allow the injected fluids to enter the formation. Figure 2. Aerial map with surface trace of wellbores of injection wells KU 12-17 and KU 24-7RD 2. Well Operations and Waste Streams Well KU 12-17 has been used since 2009 to inject a total of 3.1 million barrels of fluid. Well KU 24- 7RD has been used since 2005 to inject a total of 2.5 million barrels of fluid. The primary types of waste injected over this period are produced water, drilling cuttings, and various drilling muds. Upon conversion to Class I non-hazardous injection wells, Hilcorp plans to inject both Class II fluids, like those mentioned above, and other non-hazardous wastes. In addition to large volumes of produced water generated in the field, there are several smaller waste streams generated at the facility that are not brought to the surface in connection with hydrocarbon production, including but not limited to: storm water from tank containments, water used for testing equipment integrity, miscellaneous rinse water, air compressor condensation, and unused non-hazardous drilling and/or well fluids. Table 1 shows the volumes of major waste streams injected in 2019, along with estimated future injection volumes for the period 2021-2041. Note that non-hazardous fluids were not injected in 2019 and are proposed for injection under this proposed SDWA UIC Class I permit. Fact Sheet: UIC Class I Permit AK-1I018-A April 2021 US Environmental Protection Agency Page 5 of 6 Table 1. Current and Estimated Future Injection Waste Stream Volumes for wells KU 12-17 and KU 24-7RD Waste Stream Injected Volume, barrels 2019 2021-2041 Produced Water 113,550 2,271,000 Liquids/Mud 184,000 3,680,000 Solids/Cuttings 30,000 600,000 Non-hazardous Fluids None ~2,000,000 Total 327,550 ~8,551,000 This proposed permit would authorize only the disposal of waste which is RCRA non-hazardous or exempt from RCRA classification. This proposed permit would not allow the injection of any listed hazardous wastes. All listed hazardous wastes must be collected, stored, and transported to a RCRA- approved hazardous waste treatment or disposal facility. Under this proposed permit, wastes that are hazardous due to a characteristic other than toxicity (i.e. ignitability, corrosivity, reactivity) may be treated to remove that characteristic, after which this waste can be injected into a UIC Class I non- hazardous well. The only radioactive substance which may be injected under the proposed permit is naturally occurring radioactive material (NORM) from sludge or pipe scale (a mineral precipitate deposited during production). This proposed permit would authorize only the disposal of common oil and gas industry waste streams. The complete list of common oil and gas waste streams was listed in the waste analysis plan submitted by Hilcorp with its permit application and is found in Appendix A of this fact sheet. Upon issuance of this permit, the permittee is authorized to inject any waste stream that is listed in Appendix A. If the permittee proposes to inject a waste stream that is not included in Appendix A, the permit must be modified to include the proposed waste and published for public notice and comment. The permittee must document all waste transported to the facility for injection must be documented on the Hilcorp Kenai-Cook Inlet Manifest. The permittee must maintain these manifests, according to the requirements of the permit, for at least three years after the well is plugged and abandoned. 3. Well Integrity Testing Regular testing of well integrity ensures that waste is injected only into the designated injection zone and does not enter any USDW. In this permit, EPA requires the permittee to conduct three types of tests: • The permittee must conduct a pressure test of the inner annulus every year to verify there are no leaks in the tubing, casing, packer, or wellhead. The inner annulus is the space between the tubing and production casing above the packer. • The permittee must conduct a fluid movement test every two years to verify that there is no migration of injected fluid outside of the approved injection zone along the outside of the well casing. • The permittee must inspect the injection tubing every two years to verify that the injection tubing is in good condition and is not likely to develop a leak due to corrosion or erosion. EPA may grant an extension of up to three months to the required testing date to accommodate for logistical delays. Previously, AOGCC has witnessed mechanical integrity testing of the inner annulus in wells KU 12-17 and KU 24-7RD every two years. Neither well has ever failed a mechanical integrity test. Fact Sheet: UIC Class I Permit AK-1I018-A April 2021 US Environmental Protection Agency Page 6 of 7 4. Environmental Justice and Endangered Species EPA evaluated the impacts of this proposed permit action as it relates to environmental justice considerations. This evaluation did not identify any disproportionately high and adverse human health or environmental effects on minority populations or low-income populations. EPA also evaluated the impacts of activities associated with this proposed permit on species listed under the Endangered Species Act or on critical habitats on which those species depend. EPA determined that the impacts of the activities associated with this proposed permit will have no effect on the listed species or their habitats. E. Geologic Setting 1. Deposition/Lithology/Stratigraphy The KGF is a broad north-south trending four-way anticlinal trap that has a lateral extent of approximately 8 1/2 miles by 5 1/2 miles. Oil and gas are found in this area because the hydrocarbon fluids migrate up from the source rock to the middle of the trap where the confining sedimentary layers are higher than on the edges. This trap has demonstrated its ability to prevent the upward flow of hydrocarbons out of these formations for millions of years. The KGF is bound to the west by a large thrust fault. Gas is produced from the Sterling, Beluga, and Tyonek formations of the Tertiary-aged Kenai Group. The members of the Kenai Group are listed in Table 2. Table 2. Kenai Group Geological Formations with approximate depths Formation Lithology Depth (feet) Thickness (feet) Alluvium Sandstone 0 - 550 550 Glacial Conglomerate 550 - 2000 1,450 Sterling Interbedded sandstone, shale, coal 2000 - 4500 2500 Beluga Interbedded sandstone, siltstone, shale, coal 4500 - 7200 2700 Tyonek Interbedded sandstone, siltstone, shale, coal, conglomerate 7200 – 13200 6000 The Sterling, Beluga, and Tyonek formations were deposited by river and stream systems that migrated across the basin, resulting in a thick section of interbedded sand, silt, mudstone, and coal. Reservoir quality and continuity vary considerably within these formations. The high-quality reservoirs in the Sterling and Tyonek formations have proved to be prolific gas sands, whereas the sands of the Beluga formation are thinner, tighter, and laterally discontinuous. In general, the Sterling sands are quite laterally continuous, vary greatly in thickness (30-200 feet) and show connectivity over large areas due to their amalgamated (stacking of channels) nature of deposition. The dominant lithology of the Sterling sands are primarily quartz, feldspars, and volcanic rock fragments from the north/northwestern magmatic arc of the Alaska Range. The sand grains themselves show variable sorting (fine to coarse grained sandstone) and rounding (sub-angular to rounded) that one would expect from a rapidly changing fluvial (river/stream) environment. The reservoir quality of the sands is excellent, containing little to no cementation and have porosity ranging from 20-30% and permeability ranging from 400- 2,000+ millidarcy (mD). Fact Sheet: UIC Class I Permit AK-1I018-A April 2021 US Environmental Protection Agency Page 7 of 8 Coals and mudstone beds were deposited on the floodplain outside of the area where stream and river channels deposited sands. Coal and mudstone beds are the confining layers that prevent fluid flow and pressure communication vertically throughout the Sterling sands. The Sterling formation contains the shallowest gas producing intervals in the KGF, which have been designated as Pools 3, 4, 5.1, 5.2 and 6. Natural gas production and reserve recovery of the gas-bearing Sterling Pools are not affected by injection operations in this area of the field. 2. Injection Zone Injection wells KU 12-17 and KU 24-7RD inject into the sands of the Sterling formation. The target sand intervals range 3400-4200 feet below sea level across the two injection wells. Within the injection zone, porosity ranges up to 28% and permeability ranges up to 1000 millidarcies. Permeabilities and porosities were measured in core samples taken from the formation. The reservoir properties are presented in Table 3. The vertical permeability of these sands is likely much lower than the measured horizontal permeability. The permeability of the formation in the confining zones is considerably less than in the injection zone. Table 3. Sterling Formation sand characteristics in the project area, including the injection zone and the upper and lower confining zones. Zone Sand Name Formation Thickness (feet) Reservoir Sand Thickness (feet) Permeability (mD) Upper Confining A8 44 5 10-50 A9 21 3 10-50 Injection A10 74 28 40-1100 A11 78 25 40-1100 B1 85 21 100-2000 B2 40 32 100-2000 Lower Confining B3 60 27 100-2000 B4X 21 0 10-50 There are no known transmissive faults in the area around wells KU 12-17 and KU 24-7RD that would allow injected fluid to migrate upward out of the injection zone. In Well KU 12-17, the injection zone is found at 3760-4051 vertical feet below sea level, in the A10, A11, B1 and B2 sands. These sand intervals have a total reservoir thickness of 125 feet, with effective porosities between 15-28% and permeabilities between 90-1000 mD. In Well KU 24-7RD, the injection zone is found at 3639-3749 vertical feet below sea level, in the A10 and A11 sands. These sand intervals have a total reservoir thickness of 100 feet with effective porosities between 15-28% and permeabilities between 90-1000 mD. 3. Confining Zones There are many discontinuous impermeable beds that occur between the injection sands in the form of interlaminated mudstones, siltstones, sandstones and coals. The upper confining zone contains the shales and coals in the Sterling Formation A7, A8 and A9 sands (see Table 3). These layers are approximately 105 feet thick. A thick (>50 feet) shale and coal layer is identified immediately above the injection interval in the geological logs. This sequence extends laterally across the entire field, based on geological logs from nearby wells. Past operating experience, fracture modeling, and monitoring of Fact Sheet: UIC Class I Permit AK-1I018-A April 2021 US Environmental Protection Agency Page 8 of 9 outer annulus pressures in existing disposal wells have shown that the upper-confining layers effectively prevent migration of the injected fluid beyond the defined aquifer exemption. Lower confinement is provided by a laterally continuous shale and coal layer. The lowermost confining beds are made of the B3 shale and coals, which are approximately 70 feet thick. 4. Subsurface Fracturing The injection well operators were allowed to inject fluids at pressures that caused fractures in the injection zone while this well was operated under an AOGCC UIC Class II permit. This proposed EPA UIC Class I permit will not allow fracturing of the injection zone. The permittee submitted the results of subsurface fracture modeling, which used historical injection data (i.e., rate, pressure, and fluid composition data) for the KU 11-17 (another injection well on the same pad) and KU 24-7RD injection wells to estimate the extent of the fractures. The permittee proposes that the results of the fracture modeling for these two wells can also be applied to KU 12-17 because all three wells inject into the same formation at the same depth. All three wells also inject very similar fluids and will continue to inject similar fluids in the future. For these reasons, the EPA concurs that the fracture modeling for KU 11-17 and KU 24-7RD may be applied to KU 12-17. The fracture modeling results submitted by the permittee predict that most probable growth of injection- relate fractures is approximately 200 feet upward and 4000 feet laterally from the well perforations over the duration of the wells’ operation under a UIC Class II permit. Therefore, neither the upper nor lower confining layers have been fractured by injection through KU 12-17 or KU 24-7RD. 5. Seismicity The KGF is in a very high seismic hazard area, according to the United States Geological Service. Though earthquakes of a high magnitude occur in this region, oil wells are not frequently damaged. Deep injection wells have been linked to increased seismic activity in cases when the injection occurs at a depth near the top of the crystalline basement rock. In this Kenai Peninsula region, the sedimentary formations overlying the crystalline basement is estimated to be 25,000 feet thick. Therefore, there is not a high risk of increased seismicity associated with injection into these wells. F. Subsurface Aquifers and Aquifer Exemption A USDW is defined as an aquifer which is currently serving as a potable water source or which, by its potential productivity and natural water quality, could serve as a public water supply (40 CFR § 144.3). Federal regulations at 40 CFR §§ 144.7 and 146.4 allow an aquifer to be exempted from status as a USDW if it does not currently serve as potable water source and could not, in the future, serve as a public water supply. EPA proposes to exempt a portion of the aquifer underlying the KGF, specifically the interval between 3600-4200 feet TVD for KU 12-17 and 3720-3960 feet TVD for KU 24-7RD and within a ¾ mile radius from the wellbore. This proposal is based on information submitted by Hilcorp in its aquifer exemption request dated March 12, 2019. To demonstrate that the aquifer requested for exemption is not currently used as a source of drinking water, Hilcorp submitted a map and a list showing the location and depth of all drinking water wells within the aquifer exemption area. The map submitted by Hilcorp shows five private drinking water wells within a one-mile radius of the two injection wells. The deepest of the drinking water wells is less than 300 feet deep. Therefore, these drinking water wells draw from an aquifer that is separated from the aquifer at issue in the exemption request and injection zone by the impermeable layers of coal and shale in the upper confining layer and by over 3000 vertical feet. Fact Sheet: UIC Class I Permit AK-1I018-A April 2021 US Environmental Protection Agency Page 9 of 10 To demonstrate that use of the aquifer requested for exemption as a public water supply in the future is impractical, Hilcorp estimated the cost for nearby public water systems to access, treat, and distribute water from the aquifer. Hilcorp based this estimate on information gathered from the two largest neighboring public water systems, the City of Kenai and the City of Soldotna, and on knowledge of the aquifer water quality. The analysis, which was reviewed by the EPA, shows that both public water systems have adequate water supplies for the foreseeable future and that using water from the aquifer requested for exemption would increase the cost of water per resident by about 2000%. For any smaller public or private water systems, the per resident cost increase would be even greater. G. Plugging and Abandonment Cost Estimate and Financial Assurance Federal regulations require that the permittee provide cost estimates for the plugging and abandonment from an independent entity capable of performing this work. Additionally, the permittee must demonstrate it has the financial resources necessary for the plugging and abandonment of the permitted disposal wells. Hilcorp submitted cost estimates from ASRC Energy Services Alaska, Inc. and a Surety Performance Bond issued by Travelers Casualty and Surety Company of America. The bond is equal in value to the total estimate submitted for plugging and abandoning both wells on the proposed permit. Hilcorp has also submitted an associated trust agreement. H. Specific Permit Conditions The following summary briefly describes the proposed permit conditions not discussed elsewhere in this fact sheet. These conditions, modeled on the federal UIC requirements established in 40 CFR §§ 144 and 146, are meant to ensure the protection of USDWs from endangerment. 1. Financial Responsibility (Part I. G.) The permittee must meet the financial assurance requirements pursuant with 40 CFR 144.52(a)(7). EPA has chosen to apply the criteria found at 40 CFR Part 144 Subpart F in the evaluation of financial assurance instruments submitted in fulfillment of the financial responsibility requirement. The permittee submitted information in its permit application showing that the company satisfies the requirements of 40 CFR § 144.63(c). 2. Construction (Part II. A.) The permittee must notify the Director of the EPA Region 10 Water Division or an EPA authorized representative before any cementing operations. This notice allows the EPA the opportunity to witness the construction procedures and determine regulatory compliance. 3. Corrective Action (Part II. B.) The area of review for the wells at issue in the proposed permit is defined as the portion of the injection zone that lies within ¾ miles of the wellbore. There are several oil and gas production wells and injection wells that penetrate the area of review. The permittee has submitted cementing records for all of these wells. After reviewing the records, EPA has verified that all wells that penetrate the area of review have been properly cemented. Therefore, no corrective action plan is required. 4. Well Operation (Part II. C.) EPA has set operational limits for the injection wells at issue in the proposed permit to ensure that the wells operate in a safe and environmentally protective manner. The maximum allowable injection pressure is 2200 psi. At this pressure, the permittee can use the injection well safely, without fracturing the injection zone or the confining zone that prevents fluids Fact Sheet: UIC Class I Permit AK-1I018-A April 2021 US Environmental Protection Agency Page 10 of 11 injected into the wells at issue in this proposed permit from travelling upward. This pressure limitation is based on the formation testing results. The maximum allowable annular pressure is 2000 psi. This annular pressure allows for sudden and temporary pressure increases due to changes in the temperature of the injected fluid while not damaging the tubing, casing, or packer. The difference between the annular pressure and the injection pressure must be sufficient to easily detect pressure communication between the injection tubing and the inner annulus. 5. Monitoring, Record Keeping, and Reporting (Part II. D. and E.) The permittee must continuously monitor injection pressures and rates for those waste streams that are hard-piped and continuous. The permittee must also monitor the pressure of the annulus between the tubing and the casing above the packer. The permittee must characterize waste prior to injection to ensure that only wastes that are RCRA non-hazardous or exempt from RCRA characterization are injected. If injection operations exceed the limits of the permit, the permittee must notify the EPA verbally within 24 hours and in writing within five calendar days. For all waste streams that are not hard-piped and continuous, the permittee must require a manifest and a determination for each batch load of wastes received that certifies the wastes are RCRA non-hazardous or exempt from RCRA characterization. These conditions assure that the permittee will monitor and characterize all injected fluids prior to injection. 6. Injection Fluid Limitation (Part II. C. 7.) This proposed permit would authorize only the disposal of common oil and gas industry waste streams. The complete list of common oil and gas waste streams was listed in the waste analysis plan submitted by Hilcorp with its permit application and is found in Appendix A of this fact sheet. If the permittee proposes to inject a waste stream that is not included in Appendix A, the permit must be modified to include the proposed waste and published for public notice and comment. I. Public Comment 1. Aquifer Exemption To submit a comment on this proposed aquifer exemption, such comments must be submitted during the public comment period beginning on April 29, 2021, at 9:00 AM Alaska Time and ending on May 31, 2021, at 5:00 PM Alaska Time. Because of the COVID-19 pandemic, access to the Region 10 EPA building is limited. Please submit all comments on EPA’s proposed aquifer exemption via email to gross.ryan@epa.gov. If you are unable to submit comments via email, please call 206-553-6293 between 1:00 PM and 4:00 PM, Monday through Friday, to submit your comment over the phone. EPA will hold a virtual hearing for this action. The hearing will be held on May 31, 2021, at 9:00 AM Alaska Time. To attend the meeting, please call 1-206-800-4483 and enter conference code 789 711 382# when prompted. To help ensure that enough phone lines are available, please register for the virtual hearing by contacting Ryan Gross at gross.ryan@epa.gov or 206-553-6293. Your registration should include your name and whether you would like to speak during the hearing. After the public comment period ends and all comments have been considered, the Director of the EPA Region 10 Water Division will make a final decision regarding this aquifer exemption. If no substantive comments are received, the aquifer exemption will become final, and the aquifer exemption will become effective upon issuance. If substantive comments are received, EPA will address the comments and determine whether to issue the proposed aquifer exemption. The aquifer exemption will become Fact Sheet: UIC Class I Permit AK-1I018-A April 2021 US Environmental Protection Agency Page 11 of 12 effective upon issuance unless an appeal is submitted. An aquifer exemption approved by EPA is a final agency action that may be challenged under Section 1448(a)(2) of the SDWA (42 USC300j-7(a)(2)). The statute of limitations for the right of appeal regarding any determination made related to the aquifer exemption request described above is controlled by 40 CFR 23.7 in concert with SDWA Section 1448(a)(2). 2. UIC Class I Permit To submit a comment this proposed permit, such comments must be submitted during the public comment period beginning on April 29, 2021, at 9:00 AM Alaska Time and ending on May 31, 2021, at 5:00 PM Alaska Time. Because of the COVID-19 pandemic, access to the Region 10 EPA building is limited. Please submit all comments on EPA’s proposed permit via email to gross.ryan@epa.gov. If you are unable to submit comments for public hearings via email, please call 206-553-6293 between 1:00 PM and 4:00 PM, Monday through Friday, to submit your comment over the phone. EPA will hold a virtual hearing for this action. The hearing will be held on May 31, 2021, at 9:00 AM Alaska Time. To attend the meeting, please call 1-206-800-4483 and enter conference code 789 711 382# when prompted. To help ensure that enough phone lines are available, please register for the virtual hearing by contacting Ryan Gross at gross.ryan@epa.gov or 206-553-6293. Your registration should include your name and whether you would like to speak during the hearing. After the public comment period ends and all comments have been considered, the Director of the EPA Region 10 Water Division will make a final decision regarding permit issuance. If no substantive comments are received, the conditions in the proposed permit will become final, and the permit will become effective upon issuance. If substantive comments are received, EPA will address the comments and determine whether to issue the proposed permit. The permit will become effective upon issuance unless an appeal is submitted. Appeals regarding the SDWA UIC Class I permit should be submitted to the Environmental Appeals Board within 30 days of issuance pursuant to 40 CFR § 124.19. Fact Sheet: UIC Class I Permit AK-1I018-A April 2021 US Environmental Protection Agency Page 12 of 13 Appendix A Table 4. Common oil and gas industry waste streams that may be injected under the proposed UIC Class I permit. Waste Description Acid Used widely as cleaning fluid in well work and chemical process. Low pH. Air compressor condensation Fresh water vapor that is condensed from the compressor air intake. Boiler blowdown water Fresh water typically mixed with corrosion inhibitor used in boilers, commonly used to make steam for drilling rigs. It is collected when the boiler is taken out of service. Caustic fluid A wide range of high-pH materials normally generated by cleaning operations, as off specification chemical compounds, or as the result of chemical combinations. Clean-up fluids (washwaters) Predominantly water which has been contaminated in the process of washing down an area, engine, etc. Commercial product Products left over, spilled, outdated, off-specification, or no longer usable; drilling mud and additives that have not been circulated downhole, gel, barite, calcium carbonate, polymers; fresh or seawater rinsate with product residual. Contaminated snow/ponded water Water, possible traces of hydrocarbon or chemicals if there have been spills. Condensate Effluent from the normal process separation of oil, water, and gas. Collected from drain sumps, blow case discharge, and knockout pots. Diesel Diesel wastes may be generated as contaminated fuel, solvent, workover fluid, or freeze protection fluid. May be contaminated with small amounts of chemicals or water. Could be hazardous if not from downhole or other production related operations. Domestic wastewater Originally potable water; comes from the kitchen, showers, lavatories, laundry, toilets, and any camp floor drains. Drilling cuttings and muds Primary drilling and production operations, drilling rigs, well cellars, formation solids. Drilling fluids Excess non-hazardous fluids that were not used and did not go downhole. Facility wash water Water, possible traces of hydrocarbon, chemicals, detergent. Fire control test water Water used to test the fire water system. This includes pumps piping and if deemed necessary the sprinkler and manual hose and nozzle systems. Glycol / heat exchange media An alcohol that is widely used in circulating fluid systems to prevent freezing. May be contaminated with water, hydrocarbons, or solids. May also be used to dehydrate wet gas streams, etc. Glycol (triethylene glycol [TEG], propylene). Hydrotest fluid Water, glycol, possible product residual in existing lines, traces of chlorine or other biocide. Lubricating oils and hydraulic fluids Produced as wastes from engines and power transmission systems. Contain small amounts of metal and chemical additives to enhance their properties. Fact Sheet: UIC Class I Permit AK-1I018-A April 2021 US Environmental Protection Agency Page 13 of 13 Waste Description Methanol Light alcohol used widely as a freeze prevention fluid. May be used in combination with other materials, such as glycol. Can be hazardous if not used downhole or in relation to production operations Miscellaneous wastes Includes stormwater, snowmelt, and fresh water which are not considered as clean-up fluid. May contain small amounts of hydrocarbons and/or contaminants. Natural gas liquids Petroleum products (propane, butane, etc.) which are disposed of as wastes when they become contaminated with water, solids or some other hydrocarbon. Ignitable. Photo processing fluids Spent developer solution from x-ray equipment (corrosion tests, medical), after passing through silver recovery unit. Produced water Brine produced from the oil or gas reservoirs. Recovered during the production process. Production chemicals Broad category that includes chemicals used in production or transportation of crude to achieve certain desirable effects. Examples include corrosion inhibitors, emulsion breakers, foam suppressants, and proprietary compounds used in drilling fluids, muds, and cleaning products. Radioactive tracer Fluid containing a low-level, short half-life radioactive substance used downhole for periodic mechanical integrity tests. This process is not considered disposal - it is part of the well operation. Solvents A wide range of products that may be contaminated with grease, solids, and/or water. All solvents must be carefully evaluated for disposal options - only those classified as non-hazardous will be accepted for disposal. Source water Subsurface water produced from saline aquifers or alternately filtered sea water. Potentially used for making drilling mud and flushing the disposal well. Spill clean-up Water, snow, soil, with hydrocarbon or chemical products. Characterization depends on product spilled. Stimulation fluids Chemical compounds which are injected into producing or injector zones to enhance the productivity or injectivity of a well. May contain various chemicals to enhance its properties. Primarily from flowbacks. Sump fluids Water, grit, possible traces of hydrocarbon. Tank cleaning / drum rinsate Water, possible traces of hydrocarbons, chemical residues, glycol, unused drilling products Transformer oil Used as a non-conducting medium in electrical power transformers. Discarded when the equipment is abandoned. Turbine wash water Water, detergent, sometimes methanol. Used oil Hydrocarbon Workover fluids Wastes from the maintenance of a hydrocarbon production well. Predominantly water; may contain small amounts of chemicals and minor solids. Also present during well flowbacks. MEMORANDUM TO: JimRPgg IC,,.a P.1. Su ervisor - w< FROM: Jeff Jones Petroleum Inspector Well Name KENAI UNIT 24-7RD Insp Num: mitJJ210422085923 Rel Insp Num: NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, April 27, 2021 SUBJECT: Mechanical Integrity Tests Rflcmp Alaska, LLC 24-7RD KENAI UNIT 24-7RD Sre: Inspector Reviewed By: P.I. Sup" Comm API Well Number 50-133-20352-01-00 Inspector Name: Jeff Jones Permit Number: 205-099-0 Inspection Date: 4/16/2021 - Packer Dept Well 24-7RD Type lnj I N'TVD 3670 PTD 2050990 jType Test I SPT ITest psi '500 BBL Pumped: 1 1.7 BBL Returned: 1.6 Interval OTHER P/F P Notes: 2 year test cycle. One well inspected, no exceptions noted Pretest Initial 15 Min 30 Min 45 Min 60 Min Tubing 1460 1460 1460 1460 - 1A 89 1964 - 1957 - 1955 ' OA 0 0s z0s - 0s - Tuesday, April 27, 2021 Page I of I MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim ReggDATE: 4/Z'((7 Monday, April 29, 2019 P.I.Supervisor SUBJECT: Mechanical Integrity Tests HILCORP ALASKA LLC 24-7111) FROM: Guy Cook KENAI UNIT 24-7RD Petroleum Inspector Ste: Inspector Reviewed By: P.I. Supry �� NON -CONFIDENTIAL Comm Well Name KENAI UNIT 24-7RD Insp Num: mitGDC190423171539 Rel Insp Num: API Well Number 50-133-20352-01-00 Inspector Name: Guy Cook Permit Number: 205-099-0 Inspection Date: 4/15/2019 Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 24-71ZD Typelnj N TVD 3670 Tubing 0 0 0 0 PTD 2050990 Type Test sr"r Test psi 1500__- IA 611 nov - 1704 1702 BBL Pumped: I BBL Returned: I OA 0 16 Is is Interval OTHER P/F r Notes: 2 year cycle for SI disposal. Testing performed with a triplex pump and calibrated gauges. Monday, April 29, 2019 Page I of I • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday,May 02,2017 TO: Jim Regg c 14 I P.I.Supervisor � � l t7 SUBJECT: Mechanical Integrity Tests HILCORP ALASKA LLC 24-7RD FROM: Guy Cook KENAI UNIT 24-7RD Petroleum Inspector Src: Inspector Reviewed By: P.I.Suprv � NON-CONFIDENTIAL Comm Well Name KENAI UNIT 24-7RDAPI Well Number 50-133-20352-01-00 Inspector Name: Guy Cook Permit Number: 205-099-0 Inspection Date: 4/24/2017 Insp Num: mitGDC170427103027 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 24-7RD • Type Inj N- TVD 3670 • Tubing 1260 1270 - 1250 . 1250 . 1 PTD 2050990 ' Type Test SPT Test psi 1500 - IA 530 1750 .. 1750 _ 1750 . BBL Pumped: 1 • BBL Returned: 0.7 - OA 0 120 1 120 120 Interval OTHER P/F P V Notes: 2 year testing. - SCANNED AUG 2 4 2017 Tuesday,May 02,2017 Page 1 of 1 RECEIVED STATE OF ALASKA . ANSKA OIL AND GAS CONSERVATION CO ISSION MAR 6 2017 REPORT OF SUNDRY WELL OPERATIONS AOGCC 1.Operations Abandon U Plug Perforations U Fracture Stimulate U Pull Tubing U Operations shutdown Lf Performed: Suspend ❑ R i4ei teH Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ =rforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: CTCO Q 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: n''ILL Name: Hilcorp Alaska,LLC Development ❑ Exploratory ❑ 205-099 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic Service ❑✓ 6.API Number: Anchorage,AK 99503 50-133-20352-01 7.Property Designation(Lease Number): 8.Well Name and Number: FEDA028142 Kenai Unit 24-7RD 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Kenai Gas Field/Undefined WDSP 11.Present Well Condition Summary: Total Depth measured 4,800 feet Plugs measured N/A feet true vertical 4,023 feet Junk measured 4,410(fill) feet Effective Depth measured 4,410 feet Packer measured 3,457;4338 feet true vertical 3,724 feet true vertical 3,006;3,670 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 179' 20" 179' 179' Surface 2,003' 13-3/8" 2,003' 1,849' __..- -3i(39ppsi 1,540psi Production 5,801' 9-5/8" 5,801' 4,862' 6,330psi 3,810psi Production 37' 9-58" 3,814' 3,275' 6,870psi 4,760psi Liner 1,323' 7" 4,800' 4,023' 7,240psi 5,410psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic SCANNED Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/N-80 4,343'MD 3,674'TVD ZXP Pkr; 3,457'MD 3,006'TVD Packers and SSSV(type,measured and true vertical depth) Premier Removeable Pkr;N/A 4,338'MD 3,670'TVD N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 2195 Subsequent to operation: 0 0 0 0 1019 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations LI Exploratory❑ Development❑ Service Q Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas ❑ WDSPL 2 Q Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 316-571 Contact Taylor Nasse-777-8354 Email tnasse(a�hilcorp.com Printed Name Chad Helgeson Title Operations Manager /H4Signature Phone 907-777-8405 Date 3/C/17 7/et 10-404 Revised 5/2015 ��/3`J � 0 ' p $ Submit Ori lnal Only • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KU 24-07RD CTU 50-133-20352-01 205-099 1/26/17 1/30/17 Daily Operations: 01/26/2017-Thursday Obtain PTW. Hold safety meeting.RU SLB CTU 12.24 BQPE test witness notification sent 1/24/17 @ 1153. Witness waived by Jim Regg on 1/24/17 @ 1218. Start BOPE test. Function test BOPE. Test rams and valves to 250/4,500 psi. Test complete. 2.5 hrs.Pick injector head. Stab 10'lubricator. Make up slim BHA. 1.5"OD CC,1.5"OD DFCV,2 x 1.5"OD straight bar,2.5"OD jet swirl nozzle.Stab on well.Pt stack 250/4,500 psi. Bleed down to 1,500 psi. Open well. Bleed down to open top. Online 2 bbls/min. RIH to 30'and back up to wash across tree to prep for camera run. Continue in hole at 2 bbls/min washing and taking returns.Returns dark grey/black with trace of debris.Tag top of restriction at 4,402.5'. Pick up and re-tag same depth.Bottoms up is 55 bbls. Volume counter at 226 bbls. BBL counter at 391. 3x bottoms up complete. Samples collected at each bottoms up. Clean returns.Close choke. Attempt to inject. Pressured up to 2,750 psi. No break over. Leave pump in gear. 800 psi WHP while POOH to surface. Tagged up at surface.Close master and swab valve. Bleed down/blow down stack. Pop off well. Break down tools. Rig back. Install night cap. All ground valves closed. Locations secure. 01/27/2017-Friday Hold safety meeting. Fire equipment. Pick injector head and stab 10'lubricator. Make up EV down hole camera. 13' long 2.5"OD shroud. Stab on well. Pt stack 250/4,500 psi.Open well and RIH pumping at 1.5 bbls/min. IA pressure 800 psi. Wellhead 450 psi. Park at 2,000'and calibrate EVdhv camera. Run 100'. Confirm counters are calibrated. Continue RIH pumping at 1.5 bbls/min of filter fresh water due to grey returns. Park at 4,330'waiting for camera to turn on. RIH at 25'/min slow down to 15'min tagged up at 4,399'.15'recording interval stopped. Camera shut down for 1 hr. Circulating 2.5x bottoms up. Picking up to tubing tail and back down. 200 bbls pumped returns clean. Camera started. Pick up 20'at 1.5 bbls/min stack back down. Drop rate to 1 bbl/min. Pick up 20'and back down on restriction. Drop rate to.75 bbls/min. Pick up 20'. Drop back down to restriction. Drop rate to.5 bbls/min. Pick up 20' drop back down. Pick up 20'. Shut down pumps and drop back down on restriction. Solid tags on restriction at 4,400'. Camera 30 minute run finished.POOH to surface,keeping hole full. 280 bbls pumped. Tagged up at surface. Close master swab. Pop off well. Break down camera. Download data. Confirmed data recovered. Perform full download of data.Download and review data. Transfer data to 0 drive. SLB drop pig to blow down coil with N2. Online down tubing. Attempting to pressure up to 4,000 psi. .75 bbls/min at 3,100'pressure broke over to 300 psi. Continued pumping and increased rate to 3.2 bbls/min. 750 psi injection pressure. Pump for 5 minutes then shut down. IA pressure increased to 950 psi. Shut down pump. Close master and swab. Blow down pump iron and return iron. Location secure. May possibly run camera on a-line tomorrow. 01/30/2017-Monday Obtain PTW. Hold safety meeting.Discuss job procedure. Review making up heavy DH tools.Fill suppy tank with 435 bbls of fresh water.Pick injector head.Stab 25'of lubricator.Start making up tools.Install coil connector,DFCV, Disconnect.Online for fluid pack and PT. 15 bbls pumped and pressure increased to 4,000 psi. Shut down pump and bleed down back side. Remove tools. Stab on well.Cover coil with parachute and install heater. Ice plug moving. Good returns to tank. Pop off well. MU Weatherford BHA. 2.875"OD HD motorhead assembly,pressure test 250/3,500 psi. Continue making up BHA, 3.125"x over,3.125"daily fishing jar,3.125"x over,2.875"motor,3.625" excalibur mill.Total BHA length=24.0'.Stab on well. Fluid pack to tank PT stack 250/4,500 psi.Open well 23.5 turns. 318 psi WHP. RIH WT chk @ 4,286'13K.RIH dry tag at 4,373.8'. Pick up online down motor at 1 bbl/min. Pass through prey tag.Free spin at 2.2 bbls/min 4,000 psi. 200 psi motor work at 4,400'. Start milling at.5 ft/min.Made it to 4,409.2'.Start stacking weight.4,200 psi CT pressure(200psi motor work).PU to tubing tail. Clean weight.RIH from 4,324'. Stack weight at 4,410'.Multiple attempts to pass 4,410'. Dry attempt,1 bbl/min 1.5 bbl/min,2.2 bbl/min. Stacking 2K,5K,10K,12K,15K down. Saw 200 psi motor work. Could never get weight to break back or motor work to fall off. Not able to stall motor. Indicating weight being transferred somewhere else on BHA.POOH to check mill and rupture disk.POOH at surface. Close master swab. Pop off well. Mill wear on outside edges of mill body. Looks to be spinning on metal. Missing carbides and circular gouges in outside mill edges.,Called town to discuss running without jar for shorter BHA length and possibilities of running rock bit. Remove jar. Run same Excaliber mill. Rupture disk intact. Stab on well. Pt stack 250/4,500 psi. Bleed down. Open well 23.5.RIH @ 100 ft/min. Dry tag at 4,410'. Pick up and establish free spin. 3,900 psi @ 2.1 bbls/min. Slack off at 4,410' 200 psi motor work. Wait for 10 minutes.No weight breaking back or motor work falling off.Continue to stack in 2,000 lb increments to-10K. Not making any hole. Not able to stall motor. Attempt to RIH and mill at different rates. RIH at 60 ft/min and stack-12K. No luck.Pick up pulling heavy 25K over string weight. Break free, Attempt to RIH stack weight and mill at 4,410'. Weight not breaking back. Pick up over pull 25K. Pop free. POOH to surface. Unable to make hole.Pump fresh water down CT and backside choke shut. Injection test. 3.5 bbl/min at 650 psi. Increase rate to 4.5 bbls/min 820 psi for 50 bbls. Tagged up. Close well. Pop off and break down tools. Weatherford tool hand released. Stab on well. Drop foam pig. Blow down CT reel with N2 bottle racks. Pop off well. Recovered pig. Start rigging down CTU.435 bbls of freshwater pumped. SITP 0 psi. • KU 24-7RD • , 'Permit#: 205-099 Pad 41-18la API#: 50-133-2035201 Property Des: A-028142 728' FNL, 748' FEL KB Elevation: 87' (21'AGL) Sec. 18, T4N, R11 W, S.M. Hilcorp Alaska WBS#: Latitude: Longitude: Drive Pipe: X: 275,057.001 20" 94ppf H-40 Y: 2,356,013.0011 Top Bottom iiii'i Spud: 06/24/2005 MD 0' 179" TD: 06/22/2005 TVD 0' 179' Riq Released: Surface Casing: 7 13 3/8" 61 ppf K-55 Top Bottom MD 0' 2,003' TVD 0' 1,849' •. 17-1/2"Hole cmtw/1,225 sks Production Casing: I 9 5/8" 43.5&47ppf N-80 Jti Top Bottom MD 5,801' ' TVD 4,862' 12-1/4"Hole cmtw/1,900 sks Tubing Hanger @ 27.68' Liner ,' 7" 26 ppf N-80 mod butt ° Top Bottom Liner hanger w/ZXP Packer @ 3,457' MD 3,477 4,800' TVD 3,023' 4,023' � TX 1/2"Hole cmt w/200sx class"G" 9 5/8" 47# N-80 4 Csg Window @ 3,777'-3,814' , Production Tubing Detail Injection String:4 1/2"12.6#,N-80 Tubing 1.Premier Removable Packer©4,338' = - 2.XN nipple©4,343' 11)=3.725" Perforations: - 3-3/8"HSC 6spf(7/20/05); Pool 3 MD TVD 4,415'-4,485' 3,728'-3,781' ' 4,530'-4,560' 3,816'-3,839' 1l CT cleanout to 4410' 1/30/17 t41k TD PBTD 4,800'MD 4,701 MD 4,023'TVD 3,947'TVD Well Name&Number: KU 24-7RD Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 4,415'-4,560' (TVD) 3,728'-3,838' Angle/Perfs: Angle @ KOP and Depth: 41 °@ 3,777' Dated Completed: Completion Fluid: 6%KCL Revised By: T. Nasse Last Revison Date: 2/14/2017 • PV or Tit, 110 w I ,�� THE STATE Alaska Oil and Gas 0,;,s� � of ee T eeL13S Conservation Commission __ �1 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 ' Main: 907.279.1433 O�ALAs�� Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager Hilcorp Alaska, LLC � ��� � 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Undefined WDSP Pool, KU 24-7RD Permit to Drill Number: 205-099 Sundry Number: 316-571 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, ,40 Daniel T. Seamount, Jr. Commissioner DATED this).?day of November, 2016. RBDMS w SUV L 8 2016 • • RECEWED ` STATE OF ALASKA ' ALASKA OIL AND GAS CONSERVATION COMMISSION NOV 0 3 2016 APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 AOGCC 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate El Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate Q • Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: CTCO ' n 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number: FGD Exploratory ❑ Development ❑ 205-099 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic LiService Q , 6.API Number: Anchorage,Alaska 99503 50-133-20352-01 - 7.If perforating: 8,Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? N/A,DIO 11.001 Kenai Unit 24-7RD - Will planned perforations require a spacing exception? Yes ❑ No ❑✓ 9.Property Designation(Lease Number): 10.Field/Pool(s): FEDA028142 • Kenai Gas Field/Undefined WDSP • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 4,800' • 4,023' • 4,410' 3,724' 2,250 psi N/A 4,410'(fill) Casing Length Size MD ND Burst Collapse Structural Conductor 179' 20" 179' 179' Surface 2,003' 13-3/8" 2,003' 1,849' 3,090psi 1,540psi Intermediate Production 5,801' 9-5/8" 5,801' 4,862' 6,330psi 3,810psi Production 37' 9-5/8" 3,814' 3,275' 6,870psi 4,760psi Liner 1,323' 7" 4,800' 4,023' 7,240psi 5,410psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 4-1/2" 12.6#/N-80 4,343' Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): ZXP Pkr;Premier Removeable Pkr;N/A 3,457'MD/3,006'ND;4,338'MD/3,670'ND;N/A-WA 12.Attachments: Proposal Summary Q Wellbore schematic D 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Q Exploratory ❑ Stratigraphic ❑ Development❑ Service Q - 14.Estimated Date for 15.Well Status after proposed work: November 16,2016 Commencing Operations: OIL ❑ WINJ ❑ WDSPL 2 Q • Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR El SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Taylor Nasse-777-8354 Email tnasseehilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature /y�r Phone 907-777-8405 Date Jt/Z/r C,. // COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. Plug Integrity ❑ BOP Test _Mechanicaall IntegrityIn' Test ❑ Location Clearance El .if 50v /IS; 84" /c;.S ( C c_T ) F ti IR Ill.. Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ Nod Subsequent Form Required: /0.- ! 0 Li RBDIVIS L/-/ NOV 2 8 2016 / APPROVED BY Approved by:,, % COMMISSIONER THE COMMISSION Date: /`4 77/0 ' SubmiForm and Form 10-403 Revised 11/20 5 OPft1tcfAvjfor 12 e from the date of approval. ��ttachments inDuplicate aki iIISi201L '/// / // Yd . > ,/,,,„./4, • Eir Well Prognosis Well: KU 24-07RD Hilcorp Alaska,is Date: 11/02/2016 Well Name: KU 24-07RD API Number: 50-133-20352-01 Current Status: G&I Injection Well Leg: N/A Estimated Start Date: November 16th, 2016 Rig: Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 205-099 First Call Engineer: Taylor Nasse (907) 777-8354 (0) (907)903-0341 (C) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907) 229-4824(C) AFE Number: Maximum Expected BHP: — 3,962 psi @ 3,947' TVD (Assume 10.0 lb/gal slurry) Max. Potential Surface Pressure: 2,250 psi (Pressure relief valve setpoint) Current Surface Pressure: 1,910 psi Brief Well Summary KU 24-07RD is a G&I disposal well for injecting Class II waste into the Sterling sands that is governed by DIO No. 11.001. The purpose of this work/sundry is to perform a coiled tubing cleanout in order to remove hard fill currently • covering the open perforation intervals and reperforate/add perforations. Notes Regarding Wellbore Condition • Slickline tagged at 4,404'and wasn't able to drive bailer into fill on 10/31/16. _.(�� -lis®``J S Coiled Tubing Procedure: /Uc?( ` j .r, kJ. 11 1. MIRU Coiled Tubing, PT BOPE to 4,500 psi Hi 250 Low. �. 2. RIH w/2-1/4"jet nozzle BHA.Tag fill and come online with produced water,taking returns to tank. a. If unable to make progress with jet nozzle, RIH w/3.75" motor/mill BHA and mill through hard fill to+/-4,675' MD. 3. POOH w/coil. LD BHA. i 4. RD Coiled Tubing. 5. Turn well over to production. E-line Procedure: 1. MIRU E-line, PT lubricator to 3,000 psi Hi 250 Low. ,tiitix 2. Perforate the Sterling sands with 2-7/8" 6 SPF 60 deg phased perf guns. All intervals are • planned for 12 SPF so each zone may be shot twice. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. • ll • • Well Prognosis Well: KU 24-07RD liilcor'Alaska,LL Date: 11/02/2016 Proposed Perforated Intervals Zone Sands Top (MD) Btm (MD) FT Sterling A10 ±4,430' ±4,460' 30 Sterling All ±4,530' ±4,560' 30 Sterling 131 ±4,629' ±4,649' 20 Sterling B2 ±4,690' ±4,710' 20 3. RD E-line. 4. Turn well over to production. Attachments: 1. Actual and Proposed Well Schematic 2. Coil BOPE Schematic 3. Wellhead Diagram . KU 24-7RD Permit#: 205-099 Pad 41-18 API#: 50-133-2035201 Property Des: A-028142 728' FNL, 748' FEL KB Elevation: 87' (21'AGL) Sec. 18, T4N, R11 W, S.M. Hilcorp Alaska WBS#: Latitude: Longitude: X: 275,057.001 ji Drive Pipe: Y: 2,356,013.0011 20" 94ppf H-40 Spud: 06/24/2005 Top Bottom TD: 06/22/2005 MD 0' 179" TVD 0' 179' Rip Released: Surface Casing: 13 3/8" 61ppf K-55 Top Bottom MD 0' 2,003' TVD 0' 1,849' • 17-1/2"Hole cmt w/1,225 sks Production Casing: 9-5/8" 43.5&47ppf N-80 , : I . Top Bottom MD 5,801' TVD 4,862' 12-1/4"Hole cmtw/1,900 sks Tubing Hanger @ 27.68' Liner 7" 26 ppf N-80 mod butt Liner hanger w/ZXP Packer @ 3,457' Top Bottom MD 3,477' 4,800' TVD 3,023' 4,023' 8-1/2"Hole cmt w/200sx class"G" 9 5/8" 47# N-80 Csg Window@ 3,777'-3,814' . Production Tubing Detail Injection String:4 1/2"12.6#,N-80 Tubing • it1.Premier Removable Packer @ 4,338' „ 2.XN nipple @ 4,343' ID=3.725" Perforations: E { Tagged fill 2" DD Bailer 4410' 5/26/11 3-3/8"HSC 6spf(7/20/05);Pool 3 MD TVD 4,415'-4,485' 3,728'-3,781' . 4,530'-4,560' 12,815'-3,838' TD PBTD 4,800'MD 4,701'MD 4,023'TVD 3,947'TVD Well Name&Number: KU 24-7RD Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 4,415'-4,560' (TVD) 3,728'-3,838' Angle/Perfs: _ Angle @ KOP and Depth: 41 °@ 3,777' Dated Completed: Completion Fluid: 6%KCL Revised By: Mike Sulley Last Revison Date: 6/1/2011 i KU 24-7RD 0 Permit#: 205-099 Pad 41-18 API#: 50-133-2035201 Property Des: A-028142 728' FNL, 748' FEL KB Elevation: 87' (21'AGL) Sec. 18, T4N, R11 W, S.M. Hilcorp Alaska WBS#: Latitude: Longitude: Drive Pipe: X: 275,057.001 20" 94ppf H-40 Y: 2,356,013.0011 Top Bottom Spud: 06/24/2005 MD 0' 179" Il , TD: 06/22/2005 Rig Released: TVD 0' 179' Surface Casing: 133/8" 61ppf K-55 Top Bottom MD 0' 2,003' TVD 0' 1,849' 17-1/2"Hole cmtw/1,225 sks Production Casing: 9-5/8" 43.5&47ppf N-80 Tom Bottom MD 5,801' TVD 4,862' 12-1/4"Hole cmt w/1,900 sks Tubing Hanger @ 27.68' Liner if 4___ '________________[' 7" 26 ppf N-80 mod butt Liner hanger w/ZXP Packer @ 3,457' Top Bottom MD 3,477' 4,800' TVD 3,023' 4,023' 8-1/2"Hole cmt w/200sx class"G" 9 5/8" 47# N-80 Csg Window @ 3,777'-3,814' i Production Tubing Detail Injection String:4 1/2"12.6#,N-80 Tubing 1.Premier Removable Packer @ 4,338' 2.XN nipple @ 4,343' ID=3.725" Perforations: 3-3/8"HSC 6spf(7/20/05); Pool 3 - MD ND 4,415'-4,485' 3,728'-3,781' 1.' 4,530'-4,560' 3,816'-3,839' Tagged fill 2" DD Bailer 4410' 5/26/11 z. Perforations: 2-7/8"6spf(Proposed);Pool 3 MD ND 4,430'-4,460' 3,740'-3,762' t'r' f '.7.' r* - 4,530'-4,560' 3,816'-3,839' - i 4,629' 4,649' 3,892'-3,907' /�i" � � . � `ia2r/ .? 4,690'-4,710' 3,939'-3,954' 21(j 7/0 P.,40.--4," r. O `._r,s y= TD PBTD 5 - 610 4,800'MD 4,701'MD 4,023'TVD 3,947'TVD Well Name&Number: KU 24-7RD Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 4,415'-4,560' (ND) 3,728'-3,838' Angle/Perfs: Angle @ KOP and Depth: 41 °@ 3,777' Dated Completed: Completion Fluid: 6%KCL Revised By: Mike Sulley Last Revison Date: 6/1/2011 • •• Kenai Gas Field COIL BOPE KU 24-07RD 11/02/2016 Hilr..,rl. tla.l..,.1.1.1. KU 24-07RD 20X 133/8 X 9 5/8 X 7 X 4-1/2 Coil Tubing BOP I3 Lubricator to injection head > 0 1.75"Tandem Stripper kl•',I. Blind/Shea 1/16 30M�iBlind/Shear ■IiI. Irlima= inMEM �_— —: •'.I,I Blind/Shear � • Blind/ShearIIIII.[,� _ — —_ Slip MileSlip i.i.i.i: Ella IIIII - 1IiIuI Pipe -1. Milli Mg Pipe �IiI.°' /16 10M X 4 1/16 10M iii Elm- Outlet w/2-2 1/16 10M full . opening FMC valves 0 I O 1 NI . S I O lIl, Manual Manual Manual Manual 2 1/16 10M 2 1/16 10M iii nit 2 1/16 10M 2 1/16 10M Crossover spool - i 4 1/16 10M X 4 1/16 5M • Kenai Gas Field . 11 KU 24-07RD 11/03/2016 nar,rri, ‘Ii,.kn.11.1.t: Kenai Gas Field Tubing hanger,CIW-DCB- KU 24-7RD FBB,11"x 4 34 EUE lift and 13 3/8 x 9 5/8 x4 1/2 susp,w/4 type H BPV profile Tree cap,Otis,4 1/16 5M FE X 614 Otis Quick Union N lei uillei MI m 1101 11111 Valve,Swab,VG-M, 4 1/16 5M FE,HWO,DD trim 0 0 uL �� n • — ,.._. • G Irl•1_ 111111 1111$ - Or Valve Wing,WKM-M, 'Z•• -,• �ZF m Valve,Wing,WKM-M, 2 1/16 5M FE,HWO,DD trim ik /:7 II • 31/8 5M FE,HWO,DD trim I LUJIuI I_II I Valve,master,VG-M, ni 4 1/16 5M FE,HWO,DD trim r.110 `., v U Mimi 1 Ifr LU _ I_ iL� Valve,master,VG-M, u 4 1/16 5M FE,HWO,DD trim nr • tlYiT FRI i 1 SII ,I i ----111/150 e■anrliMMII •MM■ITIin Tubing head,CIW-DCB, 13 5/8 3M x 11 5M,w/2- Valve,CIW,2 1/16 5M,HWO 2 1/16 5M SSO,X bottom - 144 prep ■ lCr ° 1 r 1 •• .,�— ,-�4 - Casing head,CIW-WF, {I it r 13 5/8 3M FE top x 13 3/8 �_ a_b Valve,CIW-F,2 1/16 3M, o SOW btm,w/2-2 1/16 5M HWO EFO \ f ■ 3 = 1 1 it J , 113 3/8" — 9 5/8" 434" Disposal Injection Order No. 11 Page 1 of 4 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: The REQUEST OF MARATHON )Disposal Injection Order No. 11 OIL COMPANY to dispose of ) Class II oil field fluids by )Kenai Unit Well No. 11 underground injection in the )Kenai Unit Kenai Unit 24-7 well November 21, 1996 IT APPEARING THAT: 1. Marathon Oil Company by correspondence dated September 16, 1996 made application to the Alaska Oil and Gas Conservation Commission (AOGCC) for authorization to inject Class II waste fluids into the Kenai Unit No 24-7 (KU 24-7) well. 2. The AOGCC requested a modification to the original application on September 25, 1996. Marathon Oil Company provided the requested information on October 17, 1996. 3. Notice of an opportunity for public hearing was published in the Anchorage Daily News on October 26, 1996. 4. Marathon Oil Company provided revised operational parameters for the proposed disposal project and additional information regarding potential fracture development on November 6, 1996. 5. No protest or request for a public hearing was timely filed. FINDINGS: 1. Cook Inlet Region Inc. and Salamantof Village are surface owners within a one-quarter mile radius of the KU 24-7 and have been duly notified of the proposed plans. 2. Marathon Oil Company is the operator of the Kenai Unit. There are no other operators present within a one-quarter mile radius of the proposed KU 24-7 disposal injection project. 3. The Kenai Unit No. 33-7 (KU 33-7) well penetrates the proposed injection zone within a one-quarter mile radius of the KU 24-7 well. 4. KU 33-7 has 13 3/8-inch surface casing set at 2025' measured depth and cemented to surface. Production casing is 9 5/8-inch pipe set at 6529' measured depth and cemented up to 3950' measured depth equivalent to 3515' TVD subsea. yoz3' rVI http://doa.alaska.gov/ogc/orders/dio/dioll.htm 11/15/2016 . Disposal Injection Order No. 11 Page 2 of 4 • • 5. KU 24-7 was drilled to a total measured depth of 5820', equivalent to 4796' true vertical depth. 6. The Sterling Formation consists of Pliocene aged, massively bedded, predominately coarse grained, fluvial deposits and is present within the KU 24-7 from above the surface casing shoe at 2003' measured depth to total depth. 7. The proposed disposal injection zone consists of three highly porous and permeable, and pressure depleted sandstones that are present from 4400' to 4710' measured depth A (approximately 3720' to 3960' true vertical depth) in KU 24-7. of 3 siz — cis-411 T►lb 8. The production and Class II disposal injection history of Kenai Unit Sterling Formation gas reservoirs similar to the 4400' to 4710' measured depth interval in KU 24-7 indicates the sandstones are highly permeable. 9. 40 CFR 147.102(b) (1) (c) exempts all underground sources of drinking water (USDWs) at depths greater than 1300' below ground level and extending one quarter-mile beyond the boundaries of the Kenai Unit, 10. Approximately 2400 true vertical feet of Sterling Formation sediments separate the proposed disposal injection zone in KU 24-7 from the base of the non-exempt USDWs in the Kenai Unit. This interval contains an aggregate thickness of more than 450 true vertical feet of impermeable confining zone shale lithologies. 11. KU 24-7 has 13 3/8-inch surface casing string set at 2003' measured depth and cemented to the surface. 12. The production string in KU 24-7 consists of 9 5/8-inch casing set at 5801' measured depth, cemented to at least 3250' measured depth. 13. KU 24-7 will meet the test requirements of 20 AAC 25.030 and 20 AAC 25.412 prior to initiating disposal injection. 14. Two strings of three and 1/2-inch tubing are installed in KU 24-7 with a dual packer set at 4313' and a single packer set at 4679' measured depth. 15. Cement evaluation tools run in KU 24-7 indicate good to excellent cement bond from total depth to at least 3250' measured depth. 16. The operator will demonstrate mechanical integrity pressure testing KU 24-7 prior to initiating disposal operations. 17. Disposal fluids will consist of fluids associated with drilling, production, and workover operations. Typical fluids will include, produced fluid, drilling and completion fluids, equipment wash water, drilling mud, cuttings, and NORM scale. 18. Well KU 24-7 will be operated intermittently, as needed, on a weekly basis. The operator expects to run the operation 5 days per week, approximately 12 hours per day under normal conditions. 19. Maximum injection rates are expected to be as high as 7200 barrels per day. Average injection rates are estimated to be 1000 barrels per day. http://doa.alaska.gov/ogc/orders/dio/dioll.htm 11/15/2016 . Disposal Injection Order No. 11 Page 3 of 4 • 20. Estimated average surface injection pressure will be 1600 psi. and maximum will be less than 2400 psi, limited by pump working pressure and safety relief valve pressure. 21. The estimated injection pressure parameters for KU 24-7 are based on previous disposal well tests and their nominal performance during disposal operations. 22. A three-dimensional hydraulic fracture simulation with a 500,000 barrel disposal volume using operational parameters and fluid types described in the application, predicted the proposed KU 24-7 disposal project will induce a fracture up to 650' high (approximately to 3200' TVD, 3850' MD) 1900' below the base of the nonexempt aquifer in the Kenai Unit. Over 265' of confining above the fracture are expected to prevent movement of disposal fluids into nonexempt aquifers. 23. The operator will monitor disposal performance using instantaneous shut in pressure plots versus cumulative disposal, well head pressure trends, and disposal rates. These data will be evaluated relative to modeling results to qualitatively track fracture height and disposal placement. 24. The operator will monitor the casing-tubing annulus pressure on the disposal well and report the results on the Monthly Injection Report. Production wells annuli are monitored routinely to confirm integrity. CONCLUSIONS: 1. The approval of disposal injection operations at KU 24-7 will not jeopardize correlative rights. 2. Permeable strata which reasonably can be expected to accept injected fluids are present in the interval from 4400' to 4710' measured depth in KU 24-7. 3. The disposal interval, 4400' to 4710' measured depth, in KU 24-7 is approximately 2420 true vertical feet below the base of the deepest non-exempt USDW in the Kenai Unit. 4. More than 450 vertical feet of impermeable confining zone lithologies are present in KU 24-7 between the top of the proposed disposal injection zone and the base of the deepest non-exempt USDW. 5. Disposal fluids injected at KU 24-7 will consist exclusively of Class II waste generated from drilling, completion, and production operations. 6. KU 24-7 is constructed in conformance with the requirements of 20 AAC 25.030 and complies with 20 AAC 25.412. 7. Well integrity will be demonstrated in KU 24-7 in accordance with 20 AAC 25.412. 8. Operational parameters will be monitored routinely at the KU 24-7 for indications of abnormal pressure and rate conditions. 9. Disposal injection operations in the KU 24-7 will cause fracturing of some of the low stress depleted sands and shales above the disposal interval. Over 350' of confining shales and numerous sands will prevent movement of disposal fluids into nonexempt aquifers. http://doa.alaska.gov/ogc/orders/dio/dioll.htm 11/15/2016 Disposal Injection Order No. 11 Page 4 of 4 10. Cement evaluation logs and well records demonstrate the KU 24-7 well and the adjacent KU 33-7 well have adequate cement behind casing to properly contain fluids within the disposal injection zone; neither well should serve as a conduit to the surface. 11. The requirements of 20 AAC 25.252 have been met. NOW, THEREFORE, IT IS ORDERED THAT: Rule 1 Authorized Injection Strata for Disposal. Class II oil field fluids may be injected in conformance with Alaska Administrative Code Title 20, Chapter 25, for the purpose of disposal into the Sterling Formation interval from 4400' to 4710' measured depth in KU 24-7. Rule 2 Demonstration of Tubing/Casing Annulus Mechanical Integrity The tubing/casing annulus must be tested prior to the start of injection and at least every four years thereafter for mechanical integrity in accordance with 20 AAC 25.412. The Commission must be notified at least 24 hours prior to these tests so they may witnessed. Rule 3 Well Integrity Failure Whenever disposal rates and/or operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval of a plan for corrective action and obtain Commission approval to continue injection. Rule 4 Administrative Action Upon request, the Commission may administratively revise and reissue this order upon proper showing that any changes are based on sound engineering practices and will not result in an increased risk of fluid movement into an underground source of drinking water. DONE at Anchorage, Alaska and dated November 21, 1996 David W. Johnston, Chairman Alaska Oil & Gas Conservation Commission Tuckerman Babcock, Commissioner Alaska Oil & Gas Conservation Commission Disposal Order Index http://doa.alaska.gov/ogc/orders/dio/dioll.htm 11/15/2016 • • ADMINISTRATIVE APPROVAL NO. DIO 11.001 Mr. Ben Schoffmann Operations Superintendent Marathon Oil Company P.O. Box 196168 Anchorage,AK 99519-6168 Re: Request to amend Disposal Injection Order("DIO") 11, by replacing well KU 24- 07 (PTD 182-016)with sidetrack well KU 24-7rd(PTD 205-099). Dear Mr. Schoffman: The Alaska Oil and Gas Conservation Commission ("Commission") grants the request of Marathon Oil Company ("MOC") to amend DIO 11 by replacing well KU 24-07 with sidetrack well KU 24-7rd. By Application for Sundry Approvals (Form 10-403) dated June 21, 2005 and application for Permit to Drill (Form 10-401) dated June 22, 2005, MOC proposed to abandon well KU 24-07 (PTD 182-016) and replace it with sidetrack well KU 24-7rd (PTD 205-099). During an attempted workover operation approved by the Commission on February 17, 2005 (Sundry Approval No. 305-034), MOC deter- mined that KU 24-07 was damaged beyond repair. The Commission finds as follows: 1. KU 24-7rd was drilled to a bottom-hole location approximately 170 feet away from KU 24-07's bottom-hole location; 2. during an attempted workover operation,MOC determined that KU 24-07 was ir- reparably damaged; 3. KU 24-07 and KU 24-7rd penetrate common subsurface strata; 4. MOC proposes to utilize well KU 24-7rd as a replacement for the now abandoned well KU 24-07, for injection in the Kenai Unit; DIO 11.001 February 7,2006 Page 2 of 2 5. KU 24-7rd's area of review ("AOR") encompasses no wells that are not already within KU 24-07's AOR, and 6. Replacing well KU 24-07 with sidetrack well KU 24-7rd is based upon sound engineering practices and will not result in an increased risk of fluid movement into an underground source of drilling water. It is therefore ordered that DIO 11 is amended by replacing well KU 24-07 with sidetrack well KU 24-7rd. As provided in AS 31.05.080,within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is consid- ered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. DONE at Anchorage,Alaska and dated February 7, 2006. John K.Norman Daniel T. Seamount, Jr. Cathy P. Foerster Chairman Commissioner Commissioner MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg �7 �j l ii DATE: Monday,May 04,2015 P.I.Supervisor �efq SUBJECT: Mechanical Integrity Tests HILCORP ALASKA LLC 24-7RD FROM: Jeff Jones KENAI UNIT 24-7RD Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry�� NON-CONFIDENTIAL Comm Well Name KENAI UNIT 24-7RDAPI Well Number 50-133-20352-01-00 Inspector Name: Jeff Jones Permit Number: 205-099-0 Inspection Date: 4/21/2015 Insp Num: mitJJ150501080447 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min 24-7RD N 3670 40 92 - 68 - 57 ' i5oo Tubing - Type Inj TVD PTD TYPe TestI (Test psi I— PTD 2050990 SPT 410 1860 = 1840 1-- 'y 1 L — L Interval [OTHER p� P OA 10 40 40 40 Notes: 2 year MIT < 1 BBL methanol pumped 1 welll inspected,no exceptions noted • SNE© MAY 2 2 2015 Monday,May 04,2015 Page 1 of 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg ----)� � l 13 DATE: Friday,May 03,2013 �� � P.I.Supervisor �. t SUBJECT: Mechanical Integrity Tests HILCORP ALASKA LLC 24-7RD FROM: Bob Noble KENAI UNIT 24-7RD Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry 6 V2---" NON-CONFIDENTIAL Comm Well Name KENAI UNIT 24-7RD API Well Number 50-133-20352-01-00 Inspector Name: Bob Noble Permit Number: 205-099-0 Inspection Date: 5/1/2013 Insp Num: mitRCNl30502110501 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 24-7RD - Type Inj N TVD j 3670 ' IA 293 1670 , 1662 - 1660 1659 • Type 1500 I 0 60 65 67 67 Test psi OA PTD 2050990__ _ 1 T e Test Interval ,OTHER P/F P 1 Tubing o I o 0 0 0 y ear MIT 2 Notes: SItkfl ti( i nj c'C;rz SCANNED FEB 2 0 2014 Friday,May 03,2013 Page 1 of 1 ► • • AOGCC Docket 10 -12 MIT Test Anniversary Dates Marathon Oil Company �� :: w q {i it Request Dated May 26, 2010 Background Marathon requested changing the anniversary dates of eight Kenai Peninsula injection wells to allow the mechanical integrity test (MIT) required by regulation/order to be performed during 1 summer months. Marathon proposed the wells be adjusted to show a September 1 anniversary date. Action Marathon's email request dated May 26, 2010 followed several telephone discussions between Kevin Skiba (Marathon; 907 - 283 -1371) and Jim Regg (AOGCC; 907 - 793 - 1236). Subsequent to the email request, telephone discussions were held on June 1, 2010, February 7, 2011 and February 8, 2011. Mr. Skiba was told that the following during discussions: - MIT due date can be changed by simply scheduling the test during the summer months; - Tests must be completed in advance of the next due date; - Make sure to give AOGCC Inspectors the required advance notice to allow for opportunity to witness; AOGCC witness is required to adjust the anniversary date; - Industry Guidance Bulletin 10 -002 provides details about testing injectors for mechanical integrity. Marathon was told the proposed September 1 anniversary date would not work for all wells since some MITs would be performed later than the currently required anniversary date. Resulting from the guidance provided to Marathon, the anniversary date for each of the eight injection wells has been changed based on successful, witnessed MITs as shown below: Well PTD MIT Completed Next MIT Due Beaver Creek Unit 2 1670260 5/4/2011 5/4/2015 Kenai Beluga Unit 23x -6 1841090 5/25/2011 5/25/2015 Kenai Unit 11 -17 1811760 5/3/2011 5/3/2013 Kenai Unit 12 -17 2080890 5/3/2011 5/3/2013 Kenai Unit 24 -07RD 2050990 5/3/2011 5/3/2015 Kenai Unit 31 -7X 2001480 5/25/2011 5/25/2015 Kenai Unit WD -1 1811070 5/3/2011 5/3/2015 Sterling Unit 43 -09 1630110 5/4/2011 5/4/2015 With MITs completed on these wells during May 2011, Docket 10 -12 can be closed. James B. Regg / I October 6, 2011 • • Colombie, Jody J (DOA) From: Regg, James B (DOA) Sent: Wednesday, May 26, 2010 11:25 AM To: Colombie, Jody J (DOA) Subject: FW: MIT tests anniversary date setup Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907 - 793 -1236 From: Skiba, Kevin J. [mailto:kskiba @marathonoil.com] Sent: Wednesday, May 26, 2010 11:10 AM To: Regg, James B (DOA) Subject: MIT tests anniversary date setup Jim, Below is a list of Marathon Alaska's injection well MIT dates. Well Last test Frequency Next test BC -2 1/15/08 4 -year 1/15/12 KBU 23x -6 6/4/07 4 -year 6/4/11 KU 11 -17 5/12/10 1 -year 5/12/11 KU12 -17 8/27/09 2 -year 8/27/11 KU 24 -7RD 2/12/10 2 -year 2/12/12 KU 31 -7x 8/8/07 4 -year 8/8/11 SU 43 -9 5/13/09 2 -year 5/13/11 WD -1 5/12/10 4 -years 5/12/14 As per our telephone conversation, we would like to set up an anniversary date for the MIT tests on these wells. As stated, the anniversary date would allow us to complete the MIT tests in the summer months without having the forward movement affect on the test dates. With that said, we are interested in a September 1 date as the anniversary date. Please let me know if you need any additional information concerning this request. • Thanks again, Kevin Skiba Regulatory Compliance Representative Marathon Alaska Production LLC 1 Office (907) 283 -1371 • Cell (907) 394 -1880 Fax (907) 283 -1350 2 • 411/11 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Friday, May 27, 2011 TO: Jim Regg 0 j� ' P.I. Supervisor N ? 7 ' i t SUBJECT: Mechanical Integrity Tests MARATHON OIL CO 24 -7RD FROM: John Crisp KENAI UNIT 24 -7RD Petroleum Inspector Src: Inspector Reviewed By:�� P.I. Supry -`Yt NON - CONFIDENTIAL Comm Well Name: KENAI UNIT 24 -7RD API Well Number: 50- 133 - 20352 -01 -00 Inspector Name: John Crisp Insp Num: mitJCr110505134538 Permit Number: 205 - 099 - Inspection Date: 5/3/2011 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. wal T 2 4 -7RD yp e Inj . w 3670 ' 1 IA 330 1590 ' 1580 1580 TVD P.T.D1 2050990 iTypeTest 1 SPT 1 Test psi 1 1500 - O 1 0 72 70 1 65 Interval °TAR p/F P • Tubing 160 _ 240 360 1 440 Notes: 80/20 methanol pumped for pressure test. This well has not had injection recently. Cold water injection started approximately 20 minutes prior to IA PT. The IA pressure was 550 psi & OA pressure approximately 70 psi prior to starting cold water injection down tubing. The IA pressure immediately started dropping during cold water injection & the OA went on VAC. We watched the annulus pressure try to stabilize at 330 psi before pumping into IA for MIT. Jim Regg will make final determination of pass /fail. Per Jim Regg, test is a pass. Wellbore schematic along with injection graph will be attached to report. DIO 11 requires MIT every 4 years. . I 2..- a NED JUN 0 k 20111 Friday, May 27, 2011 Page 1 of 1 . KU 24 -7RD • s .r Pad 41 -18 M ARATMIDM 714d : A428142 728' FNL, 748' FEL . ,� � � (i Sec. 18, T4N, R11W, S.M. P 2 05- (9 till koi 1 Drive Pipe: ... e y O01 . . w ` } r 20" 94ppf H -40 2 1; tit 41 : Top Bottom "V, d B,�y i :p. `kI._ MD 0' 179 6 i ., " TVD 0' 179' ®C tl -a- . ( + �,. " Surface Casing: ° 13 3/8" 61 ppf K -55 Iiy,„ 4 Top Bottom 1 " M D 0' 2,0 ' - U 'i`,' 17 -1/2" Hole cmtw /1,225 sks a Liner 14,17i' °. 7" 26 ppf N -80 mod butt r Top Bottom �, ' MD 3,477' 4,800' TVD 3,023' 4,023' s e kt 8-1/2" Hole cmt w/ 200sx class "G" y Tubing Hanger © 27.68' t i. 4 Production Casing: • 4 9 - 5/8" 43.5 & 47ppf N -80 e Liner hanger w/ ZXP Packer © 3,457' tg ' � MD 5,801' k t t ' Top Bottom t,,,,,,e �'.; TVD 4,862' 12 -1/4" Hole cmtw /1,900 sks 9 5/8" 47# N -80 ' Csg Window @ 3,777 ' - 3,814' , + � 3 } Production Tubing Detail Injection String: 4 1/2" 12.6 #, N -80 Tubing 1. Premier Removable Packer © 4,338' 2. XN nipple @ 4,343' ID= 3.725" Perforations: r r 3 -3/8" HSC 6spf (7/20/05); Pool 3 MD TVD 4,415' - 4,485' 3,728' - 3,781' 4,530' - 4,560' 2,815' - 3,838' h TD PBTD 4,800' MD 4,701' MD 4,023' TVD 3,947' TVD Well Name & Number: KU 24 -7RD Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska 1 Country:I USA Perforations (MD): 4,415' - 4,560' (TVD)I 3,728' - 3,838' Angle /Perfs: Angle @ KOP and Depth: 41 ° @ 3,77T Dated Completed: Completion Fluid: 6% KCL Revised By: Nancy Henry Last Revison Date: 6/5/2009 KU G.1 /"c) ,,,t5 ,u11 I2:04',., AN 5f, p•1 " • • • (4/19/2011 12:27:34 AM) 506 psi -1 psi (62 days, 23:18 :00; 2000 1 tli 0 0 2/1/2011 2/19/2011 3/9/2011 3/27/2011 4/14/2011 5/2/2011 12:18:34 PM 12:06:34 PM 11:54:34 AM 12:42:34 PM 12:30:34 PM 12:18:34 PM • Tag Marne 1 Description I saver color :nits 1 Minimun I Ma imtrn 110 Address I The Offset I - III ■ 41 -18 Wel 24 -7RO Casing Psi KGFR5969 psi 0 1000 Wk¢rs960\V1EWITagN... 0:00:00.... 0 M A4118 Wef 247RD_InjPsi 41 -18 Wel 24 -7RD Inj. Psi KGFR5969 psi 0 2000 11kgfrs960\VIEW ITagN.., 0:00:00.... ' ® A4118_WeM 247RD 5Jn}Psi 41 -18 Well 24 -7RD Outer Casing Psi KGFR5969 psi 0 1000 l\kgfrs960\VIEW ITa N... 0:00:00.... 2CS - d 1 • MEMORANDUM • State of Alaska Alaska Oil and Gas Conservation Commission DATE: Friday, May 27, 2011 TO: Jim Regg i\ 5177[1 P.I. Supervisor t SUBJECT: Mechanical Integrity Tests MARATHON OIL CO 24 -7RD FROM: John Crisp KENAI UNIT 24 -7RD Petroleum Inspector Src: Inspector Reviewed By: P.I. Supry ,- NON- CONFIDENTIAL Comm Well Name: KENAI UNIT 24 -7RD API Well Number: 50- 133 - 20352 -01 -00 Inspector Name: John Crisp Insp Num: mitJCr110505135847 Permit Number: 205 - 099 - Inspection Date: 5/3/2011 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well l 24 -7RD Type Inj. N TVD 3670 - IA 1530 1540 " 1550 P.T.D' 2050990 TypeTest ' i Test psi 1500 OA 65 64 I 63 Interval OTHER P/F P - Tubing I 400 340 320 Notes: This test was just a 30 minute test continued from the MIT that was conducted while the well was on injection. I asked the Operator to monitor the well for 30 minutes with no tubing injection to verify thermal changes to IA without tubing flow of cold water. This may have no value for pass /fail determination but highlights thermal pressure changes. Jim Regg determined test was a pass. 4 year MIT per DIO 11. - Friday, May 27, 2011 Page 1 of 1 Marathon & commercial disposal~ough G&I facility F Maunder, Thomas E (DOA) From: Stebbins, Tiffany A. [tastebbins@marathonoil.com] Sent: Tuesday, March 09, 2010 9:27 AM To: Maunder, Thomas E (DOA) Cc: Regg, James B (DOA) Subject: RE: Marathon & commercial disposal through G&I facility Tom, Page 1 of 2 `~cb ~\ Thanks for responding to the subject. If we do begin third party disposal, I will add a line item to capture the volumes on our annual DIO reporting. C'J ti~~a~r~, C~7 ~,eb~b~ Regulatory Compliance Representative Marathon Oil Corporation Phone 907-565-3043 _ Ce11907-529-0522 "-~~~ Y~~iri ~~ ~~ I Fax 907-565-3076 From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Monday, March 08, 2010 2:03 PM To: Stebbins, Tiffany A. Cc: Regg, James B (DOA) Subject: RE: Marathon & commercial disposal through G&I facility Tiffany, Commission Disposal Injection Orders (DIOs) authorize the Operator to dispose of Class II waste. We have not made any distinction regarding whether the injected waste is solely produced by the Operator or results from some third party's well operations. If third party waste is accepted, it is incumbent on Marathon to be satisfied that the waste is indeed Class II and meets the requirements of the DIO. In your annual report it may be appropriate to have a third party line item where such volumes can be listed. Call or message with any questions. Tom Maunder, PE AOGCC From: Regg, James B (DOA) Sent: Monday, March 08, 2010 11:45 AM To: Maunder, Thomas E (DOA) Subject: FW: Marathon & commercial disposal through G&I facility Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 3/9/2010 Marathon & commercial disposal~ough G&I facility ~ Page 2 of 2 907-793-1236 From: Stebbins, Tiffany A. [mailto:tastebbins@marathonoil.com] Sent: Monday, March 08, 2010 11:00 AM To: Regg, James B (DOA) Subject: Marathon & commercial disposal through G&I facility Hi Jim, We are considering commercial disposal. Would we need to convert our current disposal permit to a commercial disposal permit even if we intend to only dispose of approved Class II exempt wastes. Thanks, C'Jti~~.t~, ~~i.~%i.ru~, Regulatory Compliance Representative Marathon Oil Corporation Phone 907-565-3043 Cell 907-529-0522 Fax 907-565-3076 3/9/2010 C Maratf'f011 MARATHON OII pa19~/ October 25, 2007 Alaska Oil & Gas Conservation Commission Attn: Howard Okland 333 W. 7`" Avenue, Suite 100 Anchorage, AK 99501 RE: Marathon KU #24-7RD -API 50-133-20352-01 CONFIDENTIAL Dear Mr. Okland: Fed Ex Enclosed is one CD containing confidential digital well data for the above referenced well, as described on the attached CD Contents document. Please indicate your receipt of this data by signing below and returning one copy to my attention at the letterhead address or fax to 713-235-6322. Thank you, '~,~ C, ~ ~~~~ Courtney McElmoyl V3C ~05-d~°- ~E t5 fo35' Enclosures Received by: Date: _ ~~, .7 ~ y ~~ :. ~~-~ Alaska Asset Team United States Production Operations P.O. Box 3128 Houston, TX 77253 Telephone 713-296-3597 Fax 713-235-6322 o~ ~~ DATA SUBMITTAL COMPLIANCE REPORT 7/19/2007 Permit to Drill 2050990 Well Name/No. KENAI UNIT 24-7RD Operator MARATHON OIL CO API No. 50-133-20352-01-00 MD 4800 TVD 4023 Completion Date 7/20/2005 Completion Status WDSP2 Current Status WDSP2 UIC Y REQUIRED INFORMATION Mud Log No Samples No Directional Survey Yes DATA INFORMATION Types Electric or Other Logs Run: Temp, CBL w/Gamma. (data taken from Logs Portion of Master Well Data Maint Welt Log Information: Log/ Electr S Data Digital Dataset Log Log Run Interval OH / Type Med/Frmt Number Name Scale Media No Start Stop CH Received Comments Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments ADDITIONAL INFORM~ACTI~ON Well Cored? Y /.ply Daily History Received? /~,, ~~ N Chips Received? ~- Formation Tops V" N Analysis Received? Comments: i ` C I~.~ e~ ~i..r~~ V~ st~l~,aJ~ ~i~ ~ d-~ ~ C /v~u.~ t Compliance Reviewed By: Date: cs~T ~`"a~'~~1~ Okland, Howard D (DOA • From: Okland, Howard D (DOA) Sent: Wednesday, October 24, 2007 11:21 AM To: 'cmcelmoyl@marathonoil.com' Subject: Kenai Unit 24-7RD Courtney, Greetings. How is it going? we are in the long slide "down" into winter and (optimistically) the slide "up" to spring. Been going over the data submitted for Kenai Unit 24-7RD ( API 50-133-20352-01 ) and it seems that we are missing some data. Because its is a waste disposal well we need a paper copy of the CBL log. Also we need a copy of the digital logging data and a graphics file of the log. A digital copy of the directional survey (surface to TD) would be helpful also. This well released to the public on the 20th of Aug. TNX Howard 1 G&I Disposal Question ~ ~ Page 1 of 1 Regg, James B (DOA) From: Regg, James B (DOA) ~~ ~ ~,~ (~ + 0 7 Sent: Friday, September 14, 2007 2:15 PM ~ l To: 'Hamilton, Kimber A.' Subject: RE: G&I Disposal Question ' Wastes generated from transportation lines would not be eligible for Class 11 disposal injection, regardless of the nonhazardous characterization and mixing criteria outlined in RCRA. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 phone: 907-793-1236 fax: 907-276-7542 From: Hamilton, Kimber A. [mailto:khamilton@marathonpetroleum,com] Sent: Thursday, September 13, 2007 11:19 AM To: Regg, James B (DOA) Subject: G&I Disposal Question Jim, hank you or speaking with me on the phone earlier the G&I facility. This water is from a tank that inadve (approximately a gallon) mixed with the truck rinsate tested non-hazardous. Per the RCRA rules, this fluid injection would still be acceptable per AOGCC. The it was a transmission pipeline. l appreciate your consideration of this issue. . As discussed my question regards water from one of our tanks at rtently received a small amount of non-exempt pipeline sludge (approximately 10 bbls). We have a total of 20 bbls of water that has would still be considered exempt. However we want to verify that pipeline that generated the sludge in not from production operations, Kimber Hamilton HES Professional -Alaska Asset Team Marathon Oii Company Office 907-565-3038 Cellular 907-529-0433 Fax 907-565-3076 9/14/2007 X05 -O"h~ fte: KU~`l4-U"/Kll Mfl ., Subject: Re: KU 24-07RD MIT From: Jeff Jones <jeff_jones aadmn.state.ak.us> Date:. Sat, 7 8 Feb 2006 09:41:.05 -0900 ~~ ~~, ~~j~~ ~ Ta: James Regg <jirr~_regg~7a,admin.state.ak.us> k`-, James Regg wrote: You witnessed an MIT on KU 24-07RD 2/2/06 (inspection # mitjj060204150006) - see attached. j The OA pressure appears unusually high; was there an explanation? Jim Jim, on my arrival at KU 24-07 RD for the test I was told that they had already pressured up the IA the previous day and held it overnight at 1100 psi and the chart recorder verified this. I looked the well over & checked the line up of their test equipment and realized immediately that they were lined up on the OA, not the IA. I had them verify that was the case and then had them swap the test equipment to the IA. In retrospect I should have also had them bleed the OA prior to the MITIA. The pre-test IA pressure was zero and the OA held 1100 psi (charted) for several hours. If you like, I can witness another MIT test with the OA at a lower pressure value. Thanks, Jeff 1 of r 2/21/2006 8:53 AM ,. n MEMORANDUM TO: Jim Regg ~~ ~` ~"~ ~ ~~~'~ P.I. Supervisor FROM: Jeff Jones Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: Monday, February 13, 2006 SUBJECT: Mechanical Integrity Tests MARATHON OIL CO ~ ~~~ 24-7RD ICENAI UMT 24-7RD ~~ Src: Inspector NON-CONFIDENTIAL Reviewed By-•~-~ ~J t~--- P.I. Suprv Comm Well Name• KENAI UNIT 24-7RD Insp Num: mitJJ060204150006 Rel Insp Num: APj Well Number s0-133-20352-01-00 Permit Number: 205-049-0 Inspector Name• Jeff Jones Inspection Date: 21212006 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 2471 Type Inj. I TVD 4338 IA o 1600 1560 is60 p.T, zoso9vo TypeTest SPT Test psi 1084.5 QA 1100 12s0 1250 1250 Interval ~T~- P/F P Tubing 3so zoo 3so 3so NOtes Post workover initial MIT. 1 BBL 50150 methanol pumped. i well house inspected; no exceptions noted. Monday, February l3, 2006 Page 1 of 1 ':e: Final reports for MITS Subject: Re: Final reports for MITS From: James Regg <jim_reggCadmin.state.ak.us> Dater Wed,. 25 Jan 2006 14:21:57 -0900 1 ~2~ (~~ ~~~ To: "C'isseil, ~Vavne t-." -~~~~e.cisscll~u!il7arathonoiLcom~.> CC: Lc>uis R Grimaldi <=ioEi ~~rin~aldii~rad~~lin.siat~.ak.us- MIT for Kenai Unit 11-17 is attached as witnessed by Jeff Jones. ~{~i Ij~ )ni-I~~) re: Kenai Unit 24-7RD, I checked the Operations Summary Report provided with the Well Completion Report - it says Lou witnessed a passing MIT (TxIA) at 0400 hrs 6/30/2005. I do not ~ have a copy of that test from Marathon or Lou. I spoke with Lou this afternoon - he did witness an ~~.,~;~~ unsuccessful test done around 11:00 pm b/2912005 but was not available for the test reported as passing -Lou was in the Anchorage office all day 6/30/2005 for inspection meetings. Since your passing test was not witnessed and prior to perforating the well; we would like to do a witnessed MIT with stable well conditions. Please coordinate scheduling with me. Thank you. Jim Regg AOGCC Cissell, Wayne E. wrote: On 247RD the MIT was done on June 29th, 2005 at 1700 hours. It was pressured up to 1500 psig. On wail 11-17 I believe that Jeff Jones witnessed the MIT around the 2nd week in June. Wayne Cissell From: James Regg [mailto:jim_ regg(a~adminstate.ak.us] Sent: Wednesday, January 25, 2006 8:34 AM To: Cissell, Wayne E. Subject: Re: Final reports for MITS Dates for MITs? Cissell, Wayne E. wrote: Jim, was reviewing our well files and could not find a copy of the MITS for 11-17 or 24-7RD. I found the report when the Rig did the MIT and Lou Grimaldi witnessed but I cannot put my hands on a format report. Is there a web site we can access to obtain a copy? Wa~~~~e 1~. C:`i~sell Maratl~an Oil C;ornpany ~1c~rtl~ern .E:~usiness unit f1AT 1~clvanced Engineel•ing Technician 1 of 2 1/25/2006 2:22 PM fie: Final reports for MITS ~ } Wecissell(~i.Maratl~ouoil. corn cI{17-253-131)8. 3~3~1-2 3? 4 '2005-0525 MIT_KU_11-17~jj.pdf • Content-Type: application/pdf Content-Encoding: base64 2 of 2 1/2512006 2:22 PM Marathon KU 24-7RD Cuttings Disposal Project Evaluation R. D. Barree Barree & Associates LLC January 24, 2006 Rev#1: Extension to 2MM bbls In 1996 a model was constructed to forecast the fracture growth resulting from injection of cuttings slurry in the KU 24-7 well. That model was updated in 2004 to reflect the disposal operations up to that time. The injection project continued through mid 2005 when the original wellbore was replaced by a re-drill. Alook- back model evaluation using the actual observed surface pressures from the injection into the re-drill well was requested by Ben Schoffmann and Gary Laughlin of Marathon Oil Company, Anchorage. This report documents the results of that analysis. It provides an estimate of the fracture geometry resulting from the cutting slurry injected up to this time (approximately 224,000 barrels). The revised report includes extension of the model to 2 million barrels of total injection. 1~'~ // Ur~ ~ ~ 2~5- oR9 1 • • { ~- .~ KU 24-7 Processed ~~ - rt- ~.W, ~ ., .. ~-1 ~= __: Log Data (used for 24-07RD) ®_ ~ ~- - - ~~- ~= - 1- - - _ Perforated Interval ®m ~_ _...~,: For Disposal B&A 2004 Digital log data for the KU 24-7 well were processed and used as input to the updated fracture growth model. Because the re-drill BH location is very close to the original wellbore, the same log data have been used. Perforations used for injection are shown on the figure as the tan blocks at right. The perforations are listed on the following figure. Major coal seams are shown on the log in black. The coals are expected to provide substantial height containment through high in-situ stress and fracture blunting. 2 • • „~ KU24-07RD Wellbore Diagram ,.- A Drwe Pipe: M O 20' 94p M-00 ~ t]B' ', 13 3/8' 61N K-55 Cesinp KU 24.7RD @ zoos' ~ Pad 41-18 i Kenai AK ;~ Tbp Henper ~ 2].68' Liner hangar wl7XP Pxker®305T '1 9 5l8' 6]b N-BO Cap W ntlow @ 3]TTJB10' Tubing Datall ' ' 0 T ~~ Iniec4on Sbinp .4 1/2 12.68. N-8 ubinb 1. Prcmwr Removable Packer ~ 6]36' 2. XN niDDle (.d 6]50' ID~1.125' Perbratlona: 3J/B' HSC 6epf (]/20I05~ A 1*' Pool ] - 6615'J685' 6530'-0560 Liner T 26 ppf. N-80, motl buU 34]T aeoa cm1 wl zoos. cl•sa •c• Copyright B&A 2004 The re-drill wellbore diagram, as configured for injection, is shown in the figure. Injection is through a 4.5" tubing string. 3 • • KU 24-7RD Injection Project ,ti ~ =---- Pool 3 Sterling Sands Perfs • A10: 4415-4485' MD . A11: 4530-4560' MD .Injection from 8/20/2005 -present Average rate while. pumping = 6.8 bpm Average solids loading = 11-14% Solids pass through 50-mesh screen B&A 2004 The cuttings disposal in the KU24-07RD well is only into the Pool 3 Sterling sands. Perforation locations for the injection zones are specified in the figure. While pumping cutting slurry, the average rate was 6.8 bpm. The slurry was composed of 11-14% solids by volume and the solids were ground to pass through a 50-mesh screen. Between cuttings slurry injections water was injected a low rate (approximately 0.5 bpm). Data from the wellsite were used to derive an injection history for the well. 4 • Copyright B&A 2004 The available pressure data from the project are plotted as a function of calendar time. The "Pump Discharge" pressure curve shows the measured pressure at the water discharge pump. The "Long String" pressure represents the wellhead injection pressure. When the well was used for cutting slurry injection the water discharge pump was isolated from the wellhead by a wing- valve. During water injection the water discharge pressure and the wellhead pressure are equivalent. The "SISP" pressure represents observed static shut- in surface pressures independently reported. After the end of October the sharp spikes in the "Long String" pressure are thought to be caused by freezing in the stainless-steel lines leading from the wellhead to the pressure transmitter. These spikes over 1500-2000 psi are not considered to be valid representations of the injection pressure. KU 24-7RD Injection Disposal History G81 2005 24-07RD (SCADA) ~« : 101 ~ m O I i4 ~ . F , W l i it ~ s ~ ... ~~? _ u~c ~ ~ Ca C l ~ T , ~ , > t~', t ~1( C ~ ~ ` S ` ,i ` 1 • Jf •~ 'ilE 1 F ~ ti F F i 't I 61( 1 ~1 •f- '~, ' k t ' . ~ ^A ~ ~ yA ~R ,~A ryA ,~ ~r ~" sd b ~+ ~ ~8 ,~ .Y > ~ ~ A 3' ~d a a e .•un~urcnq~rr-~rpmnq ~s. rsr~wrwsr w~r~ 5 • • ,~ KU24-07RD Rate History 3500 50 45 3000 40 2500 35 a P ai ~ 2000 30 a N - 250 ~WHP o. °m 1500 c Inl Rate 0- _t 2 20 u v i 1000 • •• h'• ~ 15 ~ . '' . • • • ~ • •• ~ • 10 . . , ` . . 500 i • ~ . • .~1r t 0 0 0 500 1000 1500 2000 2500 3000 3500 4000 Hours on Injection Copynght B&A 2004 Pressure data were available at a frequency of 1/6 minutes. Rate data were reported based on daily injection volumes. It is therefore nearly impossible to derive a direct relationship between actual rate and pressure. To simulate the injection history the following method was used to estimate rates for each day: When a cuttings slurry injection volume was specified fora 24 hours period, the time required to inject the specified volume at 6.8 bpm was calculated. It was assumed that water injection was halted during the slurry injection. The remaining hours in the day (24-slurry inject time) were used to estimate the average water injection rate by dividing the specified water injection volume by the available time. By converting the pressure data (given by calendar time and date) to cumulative time, and summing up the total injection time, a relationship between time, pressure, and rate was derived. The plot shows the final estimate of injection rate and pressure as a function of total injection time. The validity of these assumptions cannot be accurately checked. 6 • • ~- KU 24-7RD Injection History Model ~,,.._ n ., .,.. 3500 250000 3000 ~ 200000 I 2500 -- I o 150000 ;; 2000 - - n --~-- w .WHP d • Cum BBLs x m 1500 -,.-.__--_ -~~it __. _. _. E 100000 U ~ ~~ ~ ~. 1000 --- ; - - 1~ f ~ ~ • 1 .. 50000 500 __ . ____ _...__...-.. -__ ___._._..- C M•~ 1 • .~.• . . ~ ` ~ ~ ~ 0 0 0 500 1000 1500 2000 2500 3000 3500 4000 Cum Hours Injecting Coav'ioht B&a -00a The plot shows the estimated WHP and total volume of water and slurry injected as a function of time. These data are internally consistent and have been used in the model. They may not be properly synchronized to the actual pressure data. Pressures used in the model have been taken from 1-hour averages of the 6-minute data. 7 • • Marathon Oil Company : KU 24-7RD WinGOHFER Input Data ~~,..,, ~ ,.:..~.4, r - ~~- -- ~~-~~ -rte- J ~--- ~ r ,®r----; ~ ~~ ~~ - ~ rt - i - -- - . w~nvarse vemon 2oos.o.19 Genera[ea Ip U2oo6 u:a9:a~ nn Copyright B&A 2004 The processed log data from KU24-07 were imported to the 3-D fracture simulator GOHFER. The perforation intervals are shown in the figure. The geologic and stress model derived from the log data was used with the injection history to estimate the resulting fracture geometry. The log data were averaged over a 30' node height for the model. The final in-situ stress profile that controls fracture growth is shown in the track at far right. Slide Generated using WINPARSE Version 2005.0.19 Data Taken From the following WinGOHFER Output file: C:\GohWin_Data\MOC_KU24-7 Disposal\KU24-07RD PJM.bin 8 • • _~ Final Model Pressure Results .~w~ „ ., ...,.. B A ,Wellhead Pressure lpsil A SlurnRate lbpnU -- li GOHFER Siufacr Pressure lpsi) A Time eaA zooa The rate history was input to the model and the pressure history shown in the plot was generated by the interaction of injection and fracture propagation. While the match is not exact, some characteristic features are represented. When the slurry rate is increased to 6.8 bpm a rise in injection pressure to 1000- 1250 psi is initially observed. During water injection at much lower rate the pressure falls to about 250 psi. The model reasonably represents the cyclic injection and pressure response up until 12/29/2005. After this time the model predicts a higher injection pressure than observed. Fracture growth through even one additional bounding coal cold account for this difference in pressure response. 9 • • The fracture geometry profile at the end of the injection period is shown in the figure. The fracture height is predicte3 to remain contained between the major bounding coals around the perforated interval. The fracture half-length is estimated to be 1500 feet or more. In the field it is possible that the fracture may have penetrated the upper coal. This amount of growth would account for the lower late-time treating pressure. Slide Generated using WINPARSE Version 2005.0.19 Data Taken From the following WinGOHFER Output file: C:\GohWin Data\MOC KU24-7 Disposal\KU24-07RD PJM.bin Elapsed Job Time (min) 217809.0000 Delta Time (min) 738.3564 Surface Pressure (psi) 1420.3140 Bottom Hole Pressure (psi) 2674.7060 Injected Prop Conc. (lb/gal) 0.0000 Clean Fluid Rate (bpm) 0.5670 Slurry Rate (bpm) 0.5670 Avg. Prop Conc. (#/ft"2) 2.1543 Efficiency (fraction) -0.0541 Frac Length Created (ft) 1860.0000 Frac Height (ft) 360.0000 Injected Prop Volume (fraction): 0.0000 Fracture Volume (ft"3) 12424.2100 Leakoff Rate (ft"3/sec) 32.2519 Avg. Frac Width (in) 0.2761 Max. Frac Width (in) 0.9683 Cum. Clean Volume (gal) 9405904.0000 Cum. Slurry Volume (gal) 9434466.0000 Cum. Fluid Lost (gal) 9944874.0000 Cum. Proppant (lb) 597902.6000 10 • • Extension of Model to 2 Million 3 Barrels Total Injection Assume injection rate constant at 6.8 bpm Worst case solution for leakoff and fracture growth Assume constant slurry properties with no flushes Model predicts stable treating- pressure: at less than 1350 psi surface pressure Copyright B&A 2004 The model used to history-match the observed injection was extended to a total disposal volume of 2 million barrels. For the forward model a constant injection rate of 6.8 bpm was assumed with constant slurry properties. With no water sweeps or shut-ins, this mode provides a "worst case" solution for fracture growth but allows the model to run more quickly. With constant fluid properties and injection rate the model treating pressure is nearly constant at 1300-1350 psi for the remaining injection period. 11 • • Fracture Geometry vs. Slurry Volume Injected 2500 2500000 2000 _,__. zooooo0 _XF - IiE GhT ~~ ~~ Com eBLS '. '~ 1500 .500000 v 0 E v - ~ 1000 --- ~------ 1000000 m 500 - SCOCGO 0 0 1000 2000 3000 4000 5000 6000 7000 8000 5000 Hours of Injection Copyright B&A 2004 The model predicts that the bounding coals should restrict fracture height growth to approximately 300-400 feet. The top of the predicted fracture is at 4350' MD and the bottom at 4730' MD. This result is similar to the model results from the 1996 study and the 2004 update. Coals in the Kenai area have repeatedly been shown to provide substantial barriers to fracture height growth and may cause fracture blunting, re-direction, and even formation of horizontal fractures. The model represents the fracture primarily as a vertical planar fracture, but accounts for slurry volume stored in "transverse" fracture components. The model predicts the establishment of a stable fracture height and continued length growth to an ultimate half-length of 2000 feet. At the end of the current injection period, of about 224,000 bbls, the frac half-length is estimated to be 1900 feet. After that time the additional stored volume is primarily taken up in transverse fractures and secondary fractures with the result that the apparent frac length and height stabilize. This late-time injection appears to be in what has been called the "disposal domain" of multiple fractures. 12 • Fracture Geometry vs. Log Slurry ,!_~ Volume Injected (2MM bbls) 2500 -- 2000 -- - - ~ ___..-._- 1500 0 D v Y+ 1000 500 0 =XF HEIGHT 100 1000 10000 100000 1000000 10000000 Cumulative Barrels Injected CoOYngh[B&A 2004 The model-predicted fracture geometry is shown as a function of total slurry volume injected, on a logarithmic scale. The breaks in the growth rate are caused by spatial variations in rock properties, especially discrete coals. When the fracture is not growing in length or height, the width may be changing or secondary "transverse storage" fractures may be dilating. An average exponential growth rate can be estimated from the overall trend and used for approximate predictions of fracture geometry with continued injection. Linear tend lines for length and height are suggested on the plot. 13 • • KU 24-7RD Disposal Project f ~ Conclusions ~~~~~ ~~x~~~ t __ ~ The current "look-back" model glues similar. results to the pre- injection model study conducted in 1996 and the 2004 study of the original 24-07 well j ~ The fracture height is expected to be contained by a series of substantial coal seams above and below the perforated interval ~ A current fracture height of 300-400 feet is expected, with a j length of 1500-1900 feet ~ Extension of the injection volume up to 2 million barrels should not result in excessive growth in fracture length or height ~ Data used to constrain the model are incomplete and the results presented here are based on general trends of the observed m7ection pressure and may not be accurate ~ Direct measurement of fracture geometry or growth using microseismic mapping or tilt-meters may enhance the accuracy of the model and future predictions B&A 2004 The results of the model are as accurate as can be expected based on the available data. In-situ stresses and rock properties are based on digital log data, with poorly defined estimates of original and current pore pressures in the disposal zones and surrounding rocks. No direct measurements of frac geometry or growth have ever been made to help constrain the model. Within these limitations, the current model predictions give results similar to the previous model study. Fracture height is predicted to be dominated by bounding coals. Continued injection of up to 1.8 million barrels of slurry is not predicted to substantially alter the current fracture geometry. More direct diagnostic measurement of fracture geometry, using either borehole tiltmeters or microseismic monitoring, could improve the modeling of fracture geometry. 14 • • M Marathon MARATHON Oil Company December 27, 2005 Mr. Steve Davies Alaska Oil & Gas Conservation Commission 333 W 7t" Ave Anchorage, Alaska 99501 Reference: KU 24-7RD SurFace Location Dear Mr. Davies: Alaska Business Unit Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 Marathon well KU 24-7RD was recently sidetracked. Upon completing the sundry forms, some surface location inconsistencies were brought to my attention. Our historical well files give the following slot location for KU 24-7: 728'FNL, 748'FEL, Sec 18, T4N, R11 W, S.M. which appears on several old sundries and other forms. With new advances in technology and some correction to the originatedatum, the actual surface location is as follows: 607' FNL, 796' FEL, Sec. 18, T4N, R11W, S.M. This is the surface location that was printed in the permit to drill and should be considered the official updated surface location for abandoned well KU 24-7 as well as for the sidetracked KU 24-7RD. The physical location of the tree remains unchanged for the historic wellbore and for the sidetrack. If you need any additional information or have questions please contact our Drilling Engineer, Will Tank by phone at 713-296-3273 or by a-mail at wjtank@marathonoil.com. Sincerely, Denise M. Titus Production Engineer ~~~ V C~ ~~c ~ X005 ~~ask~ Oii 8e Gay Cans. Cammissinn Anchora~~ r1 ~J M Marathon MARATHON Oil Company November 1, 2005 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: KU 24-7RD Completion Report PTD# 205-099 Dear Mr. Aubert: Alaska Business Unit Domestic Production P.O. Box 196168 Anchorage, AK 9951.9-6168 Telephone 907/561-5311 Fax 907/564-6489 ~.~~Fy >, ~. `t ~r~., a v < ~; j,. ~ ~J A ,;l>` Enclosed is the 10-407 Well Completion or Recompletion Report and Log for a sidetrack on disposal well KU 24-7. This well is a Class II disposal well permitted under DIO 11. The well was taken out of service due to observed lack of pressure integrity in the annulus. A workover was approved to fish the existing completion and recomplete with new equipment. During the workover, we encountered casing damage severe enough to require a sidetrack. The existing wellbore was plugged back. The attached Operation Summary Report details the kickoff drilling and the new completion. The new completion consists of a 7" liner section and 4-1l2" tubing to the perfs. If you need any additional information or have questions, I can be reached by phone at 907-283- 1333 or by a-mail at dmtitus@marathonoil.com. Sincerely, ~,,~ , Denise M. Titus Production Engineer Enclosures: 10-407 Sundry Operations Summary Report Well Schematic Directional Survey STATE OF ALASKA i ~ -..-~ R ~ e Q ,. ALASKA AND GAS CONSERVATION COMMIS ~,, ~U '' - ~ '-}l; -l WELL COMPLETION OR RECOMPLETION REPORT AND LO 1a. Well Status: Oil Gas Plugged Abandoned 2oEwc2s.~o8 GINJ^ WINJ^ WDSPL~ No. of Completions 1 Suspended WAG 2oar+c2s.~~o Other 1b. Well Class: Development ^ Exploratory^ Service 0 StratigraphicTest^ 2. Operator Name: MARATHON OIL COMPANY 5. Date Comp., Susp., or Aband.: N/A 12. Permit to Drill Number: 205-099 3. Address: P. O. Box 196168, Anchorage, AK 99519-6168 6. Date Spudded: June 24, 2005 13. API Number: 50-133-20352-01 4a. Location of Well (Governmental Section): Surface: 728' FNL, 748' FEL, Sec 18, T4N, R11W, S.M. 7. Date TD Reached: June 26, 2005 14. Well Name and Number: KU 24-7RD Top of Productive Horizon: 11' FSL, 2552' FWL, Sec 7, T4N, R11W, S.M. 8. KB Elevation (ft): 67.7' GL-MSL 15. Field/Pool(s): Kenai Gas Field, Sterling Pool 3 & 4 Total Depth: 397' FSL, 1718' FWL, Sec 7, T4N, R11 W, S.M. 9. Plug Back Depth(MD+TVD): 4701'MD / 3947'TVD 4b. Location of Well (State Base Plane Coordinates): Surface: x- 275057 y- 2356013 Zone- 4 10. Total Depth (MD +TVD): 4800'MD / 4023'TVD 16. Property Designation: A-028142 TPI: x- y- Zone- Total Depth: x- 272954 y- 2357042 Zone- 4 11. Depth Where SSSV Set: N/A 17. Land Use Permit: N/A 18. Directional Survey: Yes ~ No 19. Water Depth, if Offshore: N/A feet MSL 20. Thickness of Permafrost: NIA 21. Logs Run: .Temp, CBL w/ Gamma. 22. CASING, LINER AND CEMENTING RECORD CASING WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT FT TOP BOTTOM TOP BOTTOM PULLED 20" 94 H-40 0 179' 0 179' Driven N/A 13-3/8" 61 K-55 0 2003' 0 1849' 17-1/2" 1225 sx 9-5/8" 43.5 & 47 N-80 0 5801' 0 4862' 12-114" 1900 sx 7" 26 N-80 3477' 4800' 3023' 4023' 8-112" 200 sx 23. Perforations open to Production (MD +TVD of Top and Bottom 24. TUBING RECORD Interval, Size and Number; if none, state "none"): SIZE DEPTH SET (MD) PACKER SET (MD) 4-1 /2" 4354' 4338' MD TVD 4415'-4485' 3728'-3781' 3-3/8" HSC 6spf 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 4530'-4560' 3815'-3838' 3-3/8" HSC 6spf DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 26. PRODUCTION TEST Date First Production: First Injection-8/20/05 Method of Operation (Flowing, gas lift, etc.): Cuttin s/ roduced water dis osal Date of Test: 8/20/2005 Hours Tested: 5:00 Production for Test Period Oil-Bbl: 0 Gas-MCF: 0 Water-Bbl: 7 bpm Choke Size: Gas-Oil Ratio: Flow Tubing Press. 1100 Casing Press: 0 Calculated 24-Hour Rate --~ Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity -API (corr): 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". Fluvial sandstone with quartz-rich matrix. High porosity and permeability. South dip of < 10 degrees with no known fracturing. No core chips. ~~ '~ ~.! Form 10-407 Revised 12/2003 CONTINUED ON REVERSE ®~ ~' ., 28. GEOLOGIC MARKER 29. RMATION TESTS NAME MD TVD Include and briefly sum a test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state Pool 3: "None". A-8 4247 3601 None A-9 4309 3647 A-10 4326 3660 A-11 4424 3735 Pool 4: B-1 4484 3781 30. List of Attachments: 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Denise M. Titus Printed Name: Denise M. Titus Title: Producti on Engineer o Signature: v'~ ~/ "' Phone: ,«` ~ I ~~ a " (? '"~~~ Date: ~~ t G 5 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhoie Item 1a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with prod Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional in Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 27: If no cores taken, indicate "none". Item 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 • • Marathon Oil Company Page 1 of 1' Operations Summary Report Legal Well Name: KENAI UNIT 24-7 Common Well Name: KENAI UNIT 24-7 Spud Date: 5/12/1982 Event Name: RE-ENTRY Start: 6/24/2005 End: Contractor Name: GLACIER DRILLLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours 'Code ` C de Phase Description of Operations 6/24/2005 06:00 - 07:00 1.00 TRIP_ DP_ SIDET Cont RIH bridge plug on 5" DP to 3800 ft 07:00 - 07:30 0.50 SETREL PLUG SIDET PJSM, set EZ drill bridge plug at 3800 ft, set do 35000 Ibs, confirm set 07:30 - 09:30 2.00 TRIP_ DP_ SIDET POH 5" DP to run tool 09:30 - 10:00 0.50 TRIP_ BHA_ SIDET Lay do plug running tool, release HOWCO 10:00 - 11:00 1.00 PULD_ DP_ SIDET Lay do excess DP / DCs from mast 11:00 - 12:00 1.00 CLEAN_ RIG_ SIDET Clear rig floor, prepare for whipstock 12:00 - 12:30 0.50 SAFETY MTG_ SIDET Safety meeting, all crews 12:30 - 17:00 4.50 TRIP, BHA_ SIDET M/U whipstock !mill !MWD asst', orient whipstock 40 deg right to highside, RIH, surface test same 17:00 - 20:00 3.00 TRIP_ DP_ SIDET Follow BHA with 5" DP to tag up at 3797 ft 20:00 - 20:30 0.50 SETREL TOOL SIDET Set whipstock 3797 ft, confirm set 20:30 - 05:00 8.50 MILL_ WNDW SIDET Commence mill window 9 518 csg 3777 - 3829 ft Window top 3777, btm 3814 ft, work !string mill window. 05:00 - 06:00 1.00 CIRC_ MUD_ SIDET Circ sweep (metal shavings initially, clean at shaker) Cont circ / cond for displacement /LOT 6/25/2005 06:00 - 06:30 0.50 CIRC_ MUD_ SIDET Cont circ sweep, shaker clean 06:30 - 07:30. 1.00 CIRC_ MUD_ SIDET Displace well to Flo-Pro system 07:30 - 08:30 1.00 TEST_ LOT_ PR1 DRL Perform FIT at 3829 MD / 3295 TVD 550 psi surface press = 12.21 EMW Fluid pumped .7 bbl, Fluid bled .6 bbl 08:30 - 10:00 1.50 TRIP_ DP_ PR1 DRL POH 5" DP for dretnl BHA 10:00 - 15:00 5.00 TRIP_ BHA_ PR1 DRL Lay do BHA #1, handle BHA #2, M/U motor !MWD asst', 8 1/2 bit, surface test, RIH same 15:00 - 17:30 2.50 TRIP_ DP_ PR1 DRL Follow BHA with 5" DP to btm at 3829 ft, csg window free, no drag. 17:30 - 00:00 6.50 DRILL_ ROT_ PR1DRL Drill ahead 8 1/2 hole dretnl, 3829 - 4096 ft ART = 1 hr, AST = 2 hrs D0:00 - 00:30 0.50 TRIP_ DP_ PR1 DRL POH to shoe for top drv. 00:30 - 03:00 2.50 REPAIR RIG_ PR1DRL Repair top drv (Hyd motor) 03:00 - 03:30 0.50 TRIP_ DP_ PR1 DRL RIH 5" DP, no do drag /fill 03:30 - 06:00 2.50 DRILL_ ROT_ PR1 DRL Drill ahead 8 1/2 hole dretnl 4096 - 4285 ft ART = 1.7 hrs, AST = .5 No gain /loss, conn's free i 6/26!2005 06:00 - 15:30 9.50 DRILL_ ROT_ PR1 DRL Drill ahead 8 112 hole dretnl 4285 - 4800 ft (TD) Gonn's free, no torque 1 drag, no gain 1 loss ART = 7.9 hrs, AST = 0 hrs i 15:30 - 16:30 1.00 CIRC_ MUD_ PR1 DRL Circ Hi Vis sweep, approx 10% increase in cuttings return Cont circ clean at shaker, no gain /loss Fluid caliper = 100% correct stroke count, no wash out. 16:30 - 17:30 1.00 TRIP_ DP, PR1 DRL Flow check, PJSM, POH wiper trip to window. No drag /gain /loss. Correct hole fill. 17:30 - 18:30 1.00 TRIP_ DP! PR1 DRL Flow check, RIH wiper trip, no fill /gain /loss. I Correct displacement. 18:30 - 19:30 1.00 CIRC_ MUD_ PR1DRL Circ Hi Vis sweep, no increase cuttings return. I Fluid caliper = 100% correct stroke count, no wash out. 19:30 - 22:30 3.00 TRIP_ DP_ PR1DRL Flow check, PJSM, POH to BHA for 7" liner. ~ No drag /gain /loss. Correct hole fill. 22:30 - 02:00 3.50 TRIP_ BHA_ PR1 DRL Flow check, lay do dretnl BHA. Printed: 11/1/2005 2:22:06 PM ~ • Marathon Oil Company Page i of 4 Operations- Summary ;Report Legal Well Name: KENAI UNIT 24-7 Common Well Name: KENAI UNIT 24-7 Event Name: ORIGINAL COMPLETION Contractor Name: GLACIER DRILLLING Rig Name: GLACIER DRILLING Date From - To Hours Code code Phase 6/26/2005 02:00 - 02:30 0.50 RUNPU WBSH PR1CSG 02:30 - 04:30 2.00 RURD_ CSG_ PR1CSG 04:30 - 06:00 1.50 RUN CSG PR1CSG 6(27!2005 06:00 - 13:00 7.00 RUN CSG PR1 CSG 13:00-14:00 1.00 CIRC_ MUD_ PR1CSG 14:00 - 15:30 1.50 PUMP CMT PR1CSG Spud Date: 5/12/1982 Start: 6/29/2005 End: Rig Release: Group: Rig Number: 1 Description of Operations Re-install wear bshg (pulled with BHA) PJSM, prepare floor, rig up csg crew /equip. PJSM, assemble shoe track, thread lock al! coon's Shoe, two jts csg, float collar, 1 jt csg, Indg collar. 7", 26 ppf, L80, BTC. RIH same, check floats. Follow shoe track with jts 7" csg. 200ft at 0600 hrs. Coot RIH 7" liner, M/U hgr, change bails /elevators, M/U plug drop hd, resume RIH 7" on 5" DP to 4793 ft. Attempt wash to btm (4800 ft) no success. circ / cond for cmt. No gain !loss, wellbore clean. PJSM, place BJ equip rig floor, R!U same. Commence cmt 7" liner: Pump 3 bbls H2o, test lines 4500 psi Pump MCS-4 sweep at 9.5 ppg Mix i pump 200 sks "G", 2% KCL, 22% LW6, 5% MPA1 .9°l° BA10A, .6% CD32, .15% A2, .1 % R3, 1 gps FP6L 12.5 ppg, 68 bbls slurry Wash lines, drop plug, confirm plug dropped. Displace with 102 bbls drlg mud Bump plug correct displacement, build to 3600 psi Hold 3600 psi / 10 min as csg test, test successful Bleed /check floats 100% returns during job, ICP = 236, FCP = 3 bpm 1200 psi Plug bumped ! cmt in place 1537 hrs 15:30 - 16:00 0.50 SETREL LNR_ PR1 CSG Build to 3800 psi, set hgr. Release from hgr for circ. 16:00 - 17:00 1.00 CLNOU CSG_ PR1 CSG Circ cmt from TOL, 25 bbls dense returns, cunt circ clean 17:00 - 19:00 2.00 TRIP_ DP_ PR1 CSG PJSM, set pkr with 35000 do wt, confirm pkr set POH 5" DP to BHA 19:00 - 20:00 1.00 TRIP_ BHA_ PR1 CSG Lay do liner run BHA /run tools. 20:00 - 22:30 2.50 LOG_ GSG_ PR1EVL Attempt run Temp log, results incomplete, plans to run after WOC 22:30 - 01:00 2.50 PULD DP_ PR1CSG Lay do excess DP / HWDP from mast. 01:00 - 06:00 5.00 PULD_ DP_ PR1 CSG Prepare /rack /strap 4" DP /BHA. RIH 250 ft 4" DP at 0600 hrs 6/28/2005 06:00 - 08:00 2.00 TRIP_ DP_ PR1 CSG Cont RIH 5" DP to Idg collar at 4659 ft 08:00 - 10:00 2.00 DRILL_ CMT_ CLNOUT Drill Idg collad cmt to float collar 4659 - 4701 ft Dense cmt, no voids. 10:00 - 13:00 3.00 CIRC MUD_ CLNOUT Circ / cond fluids, pump Hi Vis sweep, displace with KCL 13:00 - 16:00 3.00 TRIP DP_ CLNOUT PJSM, POH for E-logs 16:00 - 21:00 5.00 LOG CSG_ PR1 EVL Run temp / CBL log 4700 - 3456 ft, exc bond entire liner Lay do E-log equip, release unit 21:00 - 23:00 2.00 TRIP_ DP_ CLNOUT PJSM, RIH 7" scraper assy to 4701 ft, no do drag. 23:00 - 00:00 1.00 CIRC_ CFLD CLNOUT Displace well with Conqor 303 00:00 - 01:00 1.00 SLPCUT DLIN CLNOUT Slip /cut drlg line 01:00 - 01:30 0.50 TEST_ CSG_ PR1CSG PJSM, test liner lap 1500 psi / 30 min, test successful 01:30 - 06:00 4.50 PULD_ DP_ PR1GSG PJSM, POH lay do 5" ! 4" DP 6/29/2005 06:00 - 07:00 1.00 PULD_ DP_ PR1 CSG Cont lay do 5" DP ! 7" scraper BHA 07:00 - 13:30 6.50 RUNPU TBG_ CMPRUN PJSM, move trailer loads 4 1/2 tbg to well site, rack /strap /tally same, place Weatherford equip rig floor, - RU same, prepare floor for completion. 13:30 - 14:30 1.00 PULD_ PKR_ CMPRUN PJSM, MU Baker "Premier, 598-387" 4 1/2 X 7" pkr. 14:30 - 18:00 3.50 RUNPU TBG_ CMPRUN Follow PKR with 4 112, 12.6#, L-80, IBT MOD tbg to Printed: 11/1/2005 2:19:20 PM • Marathon Oil-Company < Page 2 of 4 Operations Summary Report Legal Well Name: KENAI UNIT 24-7 Common Well Name: KENAI UNIT 24-7 Event Name: ORIGINAL COMPLETION Contractor Name: GLACIER DRILLLING Rig Name: GLACIER DRILLING Date From-To Hours Code Code! Phase Spud Date: 5!12!1982 Start: 6/29/2005 End: Rig Release: Group: Rig Number: 1 Description of Operations 6/29/2005 14:30 - 18:00 3.50 RUNPU TBG_ CMPRUN hgr. 18:00 - 18:30 0.50 RUNPU TBG_ CMPRUN PJSM, MU Cameron 4 1/2 tbg hgr, land out same. 18:30 - 20:00 1.50 TEST_ EOIP CMPRUN PJSM, close BOP, test top tbg hgr (no test port in tbg hd) 4500 psi / 15 min. 20:00 - 21:30 1.50 SETREL PKR_ CMPRUN Drop bar, confirm seated, press tbg to 1500 psi / 30 min as tbg test. Test successful. i 21:30 - 00:00 2.50 TEST_ CSG_ CMPRUN Attempt test 4 1/2 X 9 5/8 annulus, tbg hgr pumps out of tbg hd bowl, failed test. i 00:00 - 04:00 4.00 NUND BOPE CMPRUN PJSM, nipple do BOPE, raise stack for hgr inspection. Lock do screws incorrect type for application. Modify LD screws, re-dress failed "O" rings, nipple up BOPE. 04:00 - 05:00 1.00 TEST_ CSG_ CMPRUN PJSM, test hgr top 3000 psi ! 15 min, test 4 1/2 X 9 5!8 ann 1500 psi / 30 min (AOGCG Lou Grimaldi) all tests successaful. 05:00 - 06:00 1.00 CLEAN_ RIG_ CMPRUN Clear rig floor, prepare for nipple do BOPE. 6/30/2005 06:00 - 08:00 2.00 NUND ROPE CMPRUN PJSM:N/D Bop equipment and load on truck 08:00 - 12:00 4.00 NUND TREE CMPRUN PJSM:N/U Tree and test void to 5000 psi. 12:00 - 14:00 2.00 TEST_ TREE CMPRUN PJSM: Test tree to 500!4500 psi. for 15 min. (OK} Pull TWC and set BPV. 14:00 - 15:30 1.50 RURD_ RIG_ RC)MO PJSM: Clean pits and FUD Top drive. 15:30 - 19:30 4.00 REPAIR RIG_ RDMO PJSM: Change out topdrive Hydraulic motor. 19:30 - 00:00 4.50 RURD_ RIG_ RDMO PJSM:R/D Topdrive slide, UD Torque tube, R/D gas buster, Cuttings tank, desilter, pop off lines, dresser sleeves , R/D floor. 00:00 - 06:00 6.00 RURD_ RIG_ RDMO PJSM: Scope down derrick mast, lower beaver slide, and prep for crane to set out and load rig components. 7/1/2005 06:00 - 12:00 6.00 RURD_ RIG_ RDMO PJSM: R!D and load out rig .Rig released @ 1200 hrs. 6/30/2005 7/6/2005 07:30 - 08:00 0.50 SAFETY MTG_ CNIPPRF Sign in at office, hold safety meeting 08:00 - 08:30 0.50 SAFETY MTG_ CNIPPRF Hold location safety meeting with G&I personnel 08:30 - 10:00 1.50 RURD_ ELEC CMPPRF Rig up Expro perforating equipment. 10:00 - 11:30 1.50 TAG_ PKR_ CMPPRF RIH, unable to pass 4354'. Ball rod is still in place in tubing nipple 11:30 -13:00 1.50 RURD_ ELEC CMPPRF RD equipment, plan to have slickfine pull ball rod when available. 7/7/2005 07:00 - 07:30 0.50 SAFETY MTG_ CMPPRF Arrive, sign in, hold safety meeting. 07:30 - 07:45 0.25 SAFETY MTG_ CMPPRF Hold location safety meeting 07:45 - 08:45 1.00 RURD_ SLIK CMPPRF RU slickfine to well 08:45 - 11:00 2.25 PULL_ ECtIP CMPPRF RIH, latch ball rod w! 2" JDC pulling tool. Unable to pull rod after repeated jarring to 18001bs. 11:00 - 12:00 1.00 RURD_ ELEC CMPPRF Decide to attempt to pull with electric line. Rig back slickfine and rig up electric line. 12:00 - 13:30 1.50 PULL_ EOIP CMPPRF RIH, latch fishing neck and attempt to pull. Pull up to 30001bs w/ no luck. 13:30 - 14:00 0.50 RURD_ ELEC CMPPRF RD electric line. Plan to bring out braided line unit in AM 7/8/2005 07:00 - 07:30 0.50 SAFETY MTG_ CMPPRF Arrive, sign in, and issue work permit. 07:30 - 07:45 0.25 SAFETY MTG_ CMPPRF Hold location safety meeting 07:45 - 09:45 2.00 RURD_ SLIK CMPPRF RU braided line unit 09:45 - 13:30 3.75 PULL_ EClIP CMPPRF RIH w! 2" JDC pulling tool to 4354' KB. Latch ball rod and jar, but not able to pull. Shear off of tool and POOH. Moved tool uphole about 4'. 13:30 - 14:00 0.50 PULD_ EOIP CMPPRF PU additional 10' of weighted stem. 14:00 - 16:20 2.33 PULL_ EOIP CMPPRF Latch plug, but still unable to pull with 40001b jarring. Tool moved additional 4' and sheared off. 16:20 - 17:00 0.67 RURD_ SLIK CMPPRF RD braided line equipment. 7/13/2005 07:30 - 07:45 0.25 SAFETY MTG_ CMPPRF Sign in and permit braided line crew 07:45 - 08:00 0.25 SAFETY MTG_ CMPPRF Hold location safety meeting Printed: 1171/2005 2:19:20 PM • • Marathon Oil Company Page 3 of 4 Operations Surnmary Report Legal Well Name: KENAI UNIT 24-7 Common Well Name: KENAI UNIT 24-7 Spud Date: 5/12/1982 Event Name: ORIGINAL COMPLETION Start: 6/29/2005 End: Contractor Name: GLACIER DRILLLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date. From -T© Hours Code Code.. Phase Descrip#ion of Operations 7/13/2005 08:00 - 09:00 1.00 RURD_ SLIK CMPPRF RU braided line unit 09:00 - 10:30 1.50 TAG_ BOTM CMPPRF RIH w/ custom shoe w/ 3.75" OD designed to tag ball rod centralizer (3' beneath fishing neck). RIH and drive down. Make 4' easily to 4332' KB . Not able to move further down. Shear off and POOH. Inspect tool and see thick mud and markings which indicate tool shoe was on centralizer. 10:00 - 10:30 0.50 SAFETY MTG_ CMPPRF Sign in electric line and hold job sight safety meeting. Issue permit. 10:30 - 11:30 1.00 RURD_ ELEC CMPPRF Rig up electric line truck. 11:30 - 12:00 0.50 LOG CSG_ CMPPRF RIH w/ CCL to determine depth of plug top. Find plug top at 4332' correlated to packer pup collars. Bar rod tool fishing neck is 3' into the packer. 12:00 - 13:30 1.50 RURD_ ELEC CMPPRF RD electric line. 13:30 - 17:00 3.50 JAR_ FISH CMPPRF PU open ended bailer and attempt to lift mud around tool. See minimal solids in bailer. PU bailer with bottom and pull sample. See muddy, wet slurry. Rerun bailer and capture more muddy slurry. RIH w/ pulling tool while solids are suspended. Jar and pull for 2hrs w/ only 1' progress. Shear off and POOH. 17:00 - 18:00 1.00 RURD_ SLIK CMPPRF RD braided line unit and clear location for CTU. 7/14/2005 08:00 - 08:30 0.50 SAFETY MTG_ CLNOUT Arrive at gas field, obtain permit, hold safety meeting. 08:30 - 10:00 1.50 MOB RIG_ CLNOUT Scan area and spot equipment. Wait for crane operator to complete orientation. Move flowback iron from pad 34-31 to pad 41-18. 10:00 - 10:30 0.50 SAFETY MTG_ CLNOUT Hold job sight safety meeting w! G&I plant foreman. Fill out JSA. 10:30 - 16:30 6.00 RURD_ COIL CLNOUT RU CT equipment, MOC flowback w/ buster and BJ choke, and source water tanks (vertical). Pig pipe to flowback tank. 16:30 - 18:30 2.00 TEST_ ROPE CLNOUT Function and pressure test CT BOPS. 18:30 - 19:30 1.00 PULD_ BHA_ CLNOUT MU Baker CT connector, pull test to 15k and pressure test. 19:30 - 20:00 0.50 SECUR WELL CLNOUT Rig back equipment and secure well for night. 7/15!2005 06:00 - 06:30 0.50 SAFETY MTG_ CLNOUT Arrive on location, sign in, and issue permit. Hold brief safety meeting. 06:30 - 07:00 0.50 SAFETY MTG_ CLNOUT Hold location safety meeting. 07:00 - 09:00 2.00 RURD_ COIL CLNOUT RU equipment. PU injector head and +/1 30' lubricator. Fill freshwater tank from well. PU 30bb1 used flo-pro from drilling rig. 09:00 - 09:30 0.50 PULD_ BHA_ CLNOUT PU Baker fishing BHA including CT connector, dual flapper, Bowen up/dn jar, hyd disconn, 3.17' 2-7/8" shoe w/ 3 tattle tails, and various XOs. 09:30 - 10:00 0.50 TEST_ BOPE CLNOUT Body test connections to 3000psi. 10:00 - 11:30 1.50 RUNPU COIL CLNOUT RIH w/BHA pumping minimum rate to xxxx' 11:30 - 13:15 1.75 CLNOU CSG_ CLNOUT CBU at 2.25bpm. Circulate 10bb1 flo-pro sweep. CBUx2. 13:15 - 14:00 0.75 RUNPU COIL CLNOUT PUH circulating at 1.5bpm. 14:00 - 14:20 0.33 PULD_ BHA CLNOUT At surface, LD wash shoe, PU JDC pump off pulling tool. 14:20 - 16:00 1.67 RUNPU COIL CLNOUT RIH w/JDC. Latch tool (2x to verify) at 4345'. POOH w/JDC. 16:00 - 16:20 0.33 PULD BHA_ CLNOUT At surface, break lubricator. Ball rod not in tool. JDC engaged, but disconnected. Had tool, but somehow pumped off. Reset pulling tool. 16:20 - 18:00 1.67 RUNPU COIL CLNOUT RIH w/JDC. Tag at 4345'. Begin pumping down kill line to fill backside. Pinch returns choke to hold pressure on backside preventing any fluid from falling out of CT while POOH. 18:00 - 18:20 0.33 PULD_ BHA_ CLNOUT At surface. Close swab valve and bleed pressure off of lubricator to tank. Break lubricator spilling --10ga1 freshwater (5 in containment). Recovered 6' ball-rod. Tool undamaged, but has some mud packed around centralizer. Breakout JDC and PU 3.5" Hyd GS spear to pull RHC plug from XN nipple. 18:20 - 20:00 1.67 RUNPU GOIL CLNOUT RIH w/ GS. Obtain PU weights and begin circulating at 1 bpm just above plug. Set down on plug and stop pumps. Engage plug and PU w/ slight overpull (-20001bs). Line up pumps to kill line and ensure hole Printed: 11/1/2005 2:19:20 PM • • Marathon Oil Company 'Page 4 of 4 Operations Summary Report Legal Well Name: KENAI UNIT 24-7 Common Well Name: KENAI UNIT 24-7 Spud Date: 5/12/1982 Event Name: ORIGINAL COMPLETION Start: 6/29/2005 End: Contractor Name: GLACIER DRILLLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date ` Frorn - To Hours Code Sub Phase. ' Description of Operatior-s Code _. 7/15/2005 18:20 - 20:00 1.67 RUNPU COIL CLNOUT is loaded. Pinch choke to maintain pressure on CT flapper to avoid disconnecting hyd. spear. POOH to surface. 20:00 - 20:30 0.50 PULD_ BHA_ CLNOUT At surface. Bleed down lubricator to flowback tank. Open packoff to break vacuum to avoid spilling and wait for lubricator to drain. Break lubricator spilling 3 gal freshwater. Recoverd all tools including RHCP. Break out and LD tools. 20:30 - 21:15 0.75 BLOWD COIL CLNOUT Pump N2 to clear CT taking returns to tank. 21;15 - 23:00 1.75 RURD_ COIL CLNOUT RD CT and depart location 7/20/2005 07:30 - 08:00 0.50 SAFETY MTG_ GMPPRF Arrive on location, sign in and fill out work permit. Told to stand down for mandatory safety meeting 08:00 - 12:30 4.50 SAFETY MTG_ GMPPRF Wait on security measures. Hold PJSM. 12:30 - 14:00 1.50 RURD_ ELEC GMPPRF Rig up electic line unit. Hold pre-perforating safety meeting. 14:00 - 15:00 1.00 RUNPU ELEC GMPPRF Arm guns and RIH w/ 30' 3-3/8" HSC guns w/ PX1 safe firing head. Correlate on depth using CBL and OH logs from original wellbore. 15:00 - 15:05 0.08 PERF_ CSG_ GMPPRF Perforate A-11 4530'-4560' w/ positive indications in wireline unit. 15:05 - 15:45 0.67 RUNPU ELEC GMPPRF POOH w/ gun. Detect well on a vacuum. i 15:45 - 16:00 0.25 PULD_ PGUN GMPPRF LD 30' gun and PU 35' gun assy. Encountered fluid level at 35'. 16:00 - 16:55 0.92 RUNPU ELEC GMPPRF RIH w! 3-38" HSC gun. Correlate CCL to CBL. 16:55 - 17:00 0.08 PERF_ CSG_ GMPPRF Perforate with positive indications 4450'-4485'. 17:00 - 17:30 0.50 RUNPU ELEC GMPPRF POOH w/ perforating gun. ~ 17:30 - 17:40 0.17 PULD_ PGUN GMPPRF At surface. LD fired 35' gun and PU new 35' gun. ~ ~ 17:40 - 18:30 0.83 RUNPU ELEC GMPPRF RIH w/ 35' gun. Correlate depth w/ CCL on bottom. Perforate ~ 4415'-4450' and POOH. i 18:30 - 19:30 1.00 RURD_ ELEC GMPPRF RD electric line. Turn in permit and depart location. Printed: 11/1/2005 2:19:20 PM • M MARATMOM KU 24-7RD Pad 41-18 Kenai AK K6=21' Tbg Hanger @ 27.68' jJ 9 5/8" 47# N-80 Csg Window @ 3777'-3814' . Drive Pipe: 20" 94# H-40 @ 178' w~ r 13 3/8" 61# K-55 Casing @ 2003' Liner hanger w/ ZXP Packer @ 3457' Tubing Detail Infection String: 4 1/2" 12.6#. N-80 Tubing 1. Premier Removable Packer @ 4338' 2. XN nipple @ 4354' ID=3.725" Perforations: 3-3/8" HSC 6spf (7/20/05) Pool 3 4415'-4485' 4530'-4560' _iner 7" 26 ppf, N-80, mod butt 3477'-4800' cmt w/ 200sx class "G" Well Name & Number: KU 24-7RD Lease: Kenai Gas Field County or Parish: Kenai Pen. Borough State/Prov. AK Country: USA Perforations (MD) See Above (TVD) See Above Angle/Perfs Angle @ KOP and Depth BHP: BHT: -80 F Completion Fluid: Dated Completed: ~~~ Company: Marathon Oil Company Job Number: 925281 Calculation Method: Minimum Curvature Field: Kenai Gas Field Magnetic Decl.: 19.69° Proposed Azimuth: 295.21° Borough Kenai Peninsula Grid Corr.: n/a Depth Reference: RKB INTEQ Well Name: KU 24-7ST Total Survey Corr.: 19.69° Tie Into: Surface MARATHON Rig: Inlet Drilling / Glacier#1 Target Info: No. Tool Type Survey Depth (ft) Incl (°) Azimuth (°) Course Lgth (ft) TVD (ft) VS (ft) Coord N/S ft inates E/W (ft Closure Dist (ft) An °) DLS (°/100') Build Rate °/100') Walk Rate (°/100') Tool Face 1 Tie in 3777 41.0 293.0 3246.52 1697.21 573.24 N 1606.01 W 2 MWD 4042 41.0 310.6 265 3447.14 1868.52 664.11 N 1752.58 W 1874.19 290.75 4.35 -0.01 6.64 97 R 3 MWD 4105 41.5 311.6 63 3494.51 1908.47 691.41 N 1783.88 W 1913.19 291.19 1.31 0.79 1.59 53 R 4 MWD 4168 41.5 312.5 63 3541.69 1948.42 719.37 N 1874.88 W 1952.25 291.62 0.95 0.00 1.43 90 R 5 MWD 4231 41.3 310.8 63 3588.95 1988.38 747.06 N 1846.01 W 1991.44 292.03 1.81 -0.32 -2.70 101 L 6 MWD 4294 41.2 312.4 63 3636.32 2028.23 774.64 N 1877.07 W 2030.63 292.43 1.68 -0.16 2.54 96 R 7 MWD 4356 40.7 310.9 62 3683.15 2067.20 801.64 N 1907.43 W 2069.03 292.80 1.78 -0.81 -2.42 118 L 8 MWD 4419 40.7 311.2 63 3730.91 2106.72 828.62 N 1938.41 W 2108.09 293.15 0.31 0.00 0.48 90 R 9 MWD 4482 40.4 311.8 63 3778.78 2146.03 855.76 N 1969.08 W 2147.00 293.49 0.78 -0.48 0.95 128 R 10 MWD 4544 40.2 311.7 62 3826.06 2184.47 882.46 N 1999.00 W 2185.12 293.82 0.34 -0.32 -0.16 162 L 11 MWD 4607 39.9 311.0 63 3874.29 2223.41 909.24 N 2029.43 W 2223.80 294.13 0.86 -0.48 -1.11 124 L 12 MWD 4670 39.3 310.5 63 3922.83 2262.10 935.46 N 2059.85 W 2262.31 294.42 1.08 -0.95 -0.79 152 L 13 MWD 4734 39.3 311.2 64 3972.36 2301.14 961.97 N 2090.51 W 2301.22 294.71 0.69 0.00 1.09 90 R 14 Projection 4800 39.3 311.2 66 4023.43 2341.32 989.51 N 2121.97 W 2341.34 295.00 0.00 0.00 0.00 0 • u 1of1 • • MD Inc Azi TVD TVD(SS) VS N!-S E/-W DLS Northing Easting (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (deg/100ft) (ft) (ft) -9.00 0.00 0.00 -9.00 -97.00 0.00 0.00 0.00 0.00 2356013.00 275057.00 91.00 0.00 360.00 91.00 3.00 0.00 0.00 0.00 0.00 2356013.00 275057.00 191.00 0.50 297.70 191.00 103.00 0.44 0.20 -0.39 0.50 2356013.21 275056.62 291.00 1.00 318.75 290.99 202.99 1.67 1.06 -1.35 0.56 2356014.09 275055.67 391.00 4.00 302.77 390.88 302.88 5.93 3.61 -4.86 3.05 2356016.70 275052.21 491.00 6.00 288.85 490.50 402.50 14.58 7.18 -12.74 2.33 2356020.42 275044.40 591.00 8.00 290.88 589.75 501.75 26.72 11.35 -24.19 2.01 2356024.81 275033.04 691.00 10.25 286.02 688.48 600.48 42.44 16.29 -39.24 2.38 2356030.03 275018.08 791.00 12.00 282.18 786.60 698.60 61.36 20.94 -57.96 1.90 2356035.03 274999.45 891.00 14.25 285.25 883.98 795.98 83.62 26.37 -80.00 2.35 2356040.88 274977.52 991.00 17.25 285.43 980.22 892.22 110.37 33.55 -106.17 3.00 2356048.55 274951.49 1091.00 20.00 286.72 1074.97 986.97 141.91 42.42 -136.85 2.78 2356058.00 274920.99 1191.00 23.00 286.93 1168.00 1080.00 178.17 53.03 -171.92 3.00 2356069.27 274886.12 1291.00 26.00 287.17 1258.99 1170.99 219.22 65.19 -211.56 3.00 2356082.18 274846.72 1391.00 29.25 287.45 1347.58 1259.58 265.15 78.99 -255.82 3.25 2356096.81 274802.73 1491.00 32.75 287.80 1433.28 1345.28 316.21 94.59 -304.90 3.50 2356113.34 274753.96 1591.00 33.25 288.72 1517.15 1429.15 370.28 111.66 -356.62 0.71 2356131.38 274702.58 1691.00 35.00 288.07 1599.93 1511.93 425.99 129.36 -409.85 1.79 2356150.08 274649.69 1791.00 37.00 288.30 1680.82 1592.82 484.34 147.70 -465.69 2.00 2356169.48 274594.21 1891.00 38.00 288.38 1760.16 1672.16 544.78 166.86 -523.47 1.00 2356189.72 274536.80 1991.00 40.75 288.67 1837.45 1749.45 607.80 187.02 -583.62 2.76 2356211.01 274477.05 2091.00 39.50 288.50 1913.91 1825.91 671.82 207.56 -644.70 1.25 2356232.70 274416.37 2191.00 38.00 288.33 1991.90 1903.90 733.98 227.33 -704.09 1.50 2356253.59 274357.37 2291.00 36.50 288.97 2071.50 1983.50 794.12 246.68 -761.43 1.55 2356274.02 274300.40 2391.00 35.00 288.80 2152.65 2064.65 852.20 265.59 -816.71 1.50 2356293.98 274245.49 2491.00 35.00 288.77 2234.57 2146.57 909.21 284.06 -871.02 0.02 2356313.47 274191.55 2591.00 34.00 289.40 2316.98 2228.98 965.53 302.58 -924.54 1.06 2356332.99 274138.39 2691.00 34.00 290.20 2399.89 2311.88 1021.21 321.52 -977.15 0.45 2356352.92 274086.14 2791,00 34.00 290.18 2482.79 2394.79 1076.92 340.82 -1029.64 0.01 2356373.21 274034.04 2891.00 34.00 289.32 2565.69 2477.69 1132.59 359.71 -1082.27 0.48 2356393.10 273981.78 2991.00 35.00 291.02 2648.11 2560.11 1189.01 379.25 -1135.43 1.39 2356413.64 273929.00 3091.00 38.75 291.23 2728.09 2640.09 1248.87 400.88 -1191.39 3.75 2356436.32 273873.46 3191.00 41.00 290.60 2804.83 2716.83 1312.80 423.76 -1251.27 2.29 2356460.32 273814.02 3291.00 41.00 292.10 2880.30 2792.30 1378.26 447.64 -1312.37 0.98 2356485.36 273753.39 3391.00 41.00 292.83 2955.77 2867.77 1443.79 472.71 -1373.00 0.48 2356511.57 273693.25 3491.00 41.00 293.58 3031.24 2943.24 1509.36 498.56 -1433.30 0.49 2356538.55 273633.45 3591.00 41.25 293.57 3106.57 3018.57 1575.11 524.86 -1493.58 0.25 2356565.99 273573.68 3691.00 41.25 292.78 3181.75 3093.75 1641.00 550.81 -1554.19 0.52 2356593.08 273513.57 3777.00 41.03 292.77 3246.52 3158.52 1697.53 572.72 -1606.36 0.25 2356615.96 273461.83 4042.00 41.00 310.60 3447.16 3359.16 1868.82 663.27 -1753.08 4.41 2356709.27 273316.85 4105.00 41.50 311.60 3494.53 3406.52 1908.75 690.58 -1784.38 1.31 2356737.16 273286.08 4168.00 41.50 312.50 3541.71 3453.71 1948.69 718.53 -1815.38 0.95 2356765.70 273255.62 4231.00 41.30 310.80 3588.97 3500.97 1988.63 746.22 -1846.51 1.81 2356793.97 273225.02 4294.00 41.20 312.40 3636.34 3548.34 2028.46 773.80 -1877.57 1.68 2356822.13 273194.49 4356.00 40.70 310.90 3683.16 3595.16 2067.42 800.80 -1907.93 1.78 2356849.70 273164.64 4419.00 40.70 311.20 3730.93 3642.93 2106.92 827.78 -1938.91 0.31 2356877.26 273134.18 4482.00 40.40 311.80 3778.80 3690.80 2146.22 854.92 -1969.58 0.78 2356904.97 273104.02 4544.00 40.20 311.70 3826.08 3738.08 2184.64 881.62 -1999.50 0.34 2356932.24 273074.62 4607.00 39.90 311.00 3874.31 3786.31 2223.57 908.40 -2029.93 0.86 2356959.59 273044.70 4670.00 39.30 310.50 3922.85 3834.85 2262.24 934.62 -2060.35 1.08 2356986.37 273014.78 4734.00 39.30 311.20 3972.38 3884.38 2301.26 961.13 -2091.01 0.69 2357013.46 272984,63 4800.00 39.30 311.20 4023.45 3935.45 2341.43 988.67 -2122.47 0.00 2357041.58 272953,70 RE: KU 24-7RD Sundry • • Subject: RE: KU 24-7RD Sundry From: "Titus, Denise M." <dmtit;us a,lnarathonoil.com> Date: Tue, 08 Nov 2005 16:1336 -0900 ~~ --~~~ "To: "Berea. Pete" =pkbcr«~,ti~.maratt~oni~il.com-~, Robert t~~lcckcn~tein bob fleckenstein~u.~rimin.staic.al:.us= So it sounds like updates need to be made to the 10-407. The State Base Plane Caardinates were in agreement between the two documents and will remain unchanged on the °10-407. Bab, What is the best way for me to go about making the corrections to Governmental Location on the form you have? Thanks, Denise From: Berga, Pete Sent: Tuesday, November 08, 2005 3:51 PM To: Titus, Denise M.; 'Robert Fleckenstein' Subject: RE: KU 24-7RD Sundry Unocal's original PTD and a follow up sundry had different surface locations{they didn't match each other). The surface location has since been surveyed in using GPS. Using that and the protracted township section corners we come up with more accurate distances from section lines. The AOGCG and BLM usually prefer that we use the most accurate information and that is what is on the sidetrack permit to drill. From: Titus, Denise M. Sent: Tuesday, November 08, 2005 1:40 PM To: Robert Fleckenstein Cc: Berga, Pete Subject: KU 24-7RD Sundry Bob, In this morning's phone call, you pointed out a large difference in our KU 24-7rd PTD and 10-407 surface locations. I have done some preliminary digging into our KU 24-7RD files. I am still waiting to confirm, but it appears that incorrect surface locations were submitted on the PTD. What actions would be required to ammend the PTD? I will call you as soon as I get to the bottom of the descrepancy to discuss how to make the corrections. Thanks, Denise i of 1 11/9/2005 7:06 AM r ~ ~ ~ ~ ~ ALA,$SA OIL A1QD GAS CO1~T5ERQATIOIQ COMMI5SIOI~T P.K. Berga Drilling Superintendent Marathon Oil Company P.O. Box 3128 Houston, Texas 77253 a FRANK H. MURKOWSKf, GOVERNOR 333 W. 7"' AVENUE, SUITE 100 ~' ANCHORAGE, ALASKA 99501-3539 ;~ PHONE (907) 279-1433 FAX (907) 276-7542 Re: Kenai KU24-7RD Marathon Oil Company Permit No: 205-099 T4N R11W, S.M. Surface Location: 604' FNL, 796' FEL, SEC. 18, , Bottomhole Location: 393' FSL, 2060' FWL, SEC. 7, T4N, Rl 1W, SM Dear Mr. Berga: Enclosed is the approved application for permit to redrill the above service well. This permit to redrill does not exempt you from obtaining additional permits or approvals 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 Commission 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 Commission 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 a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Please provide at least twenty- four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's petro m field inspector at (907) 659- 3607 (pager) . ~~ DATED this~3day of June, 2005 cc: Department of Fish 8v Game, Habitat Section w/ o encl. Department of Environmental Conservation w/ o encl. M Marathon MARATHON Oil Company June 22, 2005 Mr. John Norman Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Reference: Field: Kenai Gas Field Well: KU 24-7RD (Disposal well) Permit No.: 182-016 Regarding: Request to sidetrack KU 24-7 Dear Mr. Norman Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/565-3076 Enclosed please find the PERMIT TO DRILL application, along with the associated attachments. This permit is being requested because the fishing operations during the / workover of this well were unsuccessful and a sidetrack of the original wellbore is necessary to re-establish a completion in the Sterling reservoir. Please note that Marathon is requesting a waiver for 20 ACC 25.035 (e)(1)(b) requiring a two ~ pipe ram stack. If you require further information, I can be reached at 907-565-3032 or by a-mail at pkberga@marathonAciom. ~4~ Sincerely, ~ ~~ ~,,,~ ai,~f-v'~ h-°~'%~~`~`~ Oz ~~~ P. K. Berga Drilling Superintendent io (2~ ~ ?.d n s Enclosure • ~ ~ y ~' , ~ ~~l 1"t STATE OF ALASKA AL~.~ OIL AND GAS CONSERVATION CO ~SION PERMIT TO DRILL ~n anc ~~ nn~ t -_ ~. v ~;; 1a. Type of Work: Drill Redrill ~ 1b. Current Well Class: Exploratory DevelopmerttF3~ '' MulCple Zorn ^ Re-entry ~ Stratigraphic Test ~ Service -' Q Development Gas Single zone 2. Operator Name: 5. Bond: Blanket ~ Single Well 11. Well Name and Number: Marathon Oil Company Bond No. 5194234 ~' KU 24-7RD 3. Address: 6. Proposed Depth: 12. Field/Pool(s): P.O. Box 3128, Houston, TX 77253 MD: 4,800 TVD: 4,017 Kenai Gas Field 4a. Location of Well (Governmental Section): 7. Property Designation: Sterling Surface: 604' FNL, 796' FEL, Sec. 18, T4N, R11W, S.M. A-028142 Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 227' FSL, 2,236' FWL, Sec. 7, T4N, R11W, S.M. June 23, 2005 Total Depth: 9. Acres in Property: 14. Distance to Nearest 393' FSL, 2,060' FWL, Sec. 7, T4N, R11 W, S.M. 2,560 Property: 5,750 ft e 4b. Location of Well (State Base Plane Coordinates): 10. KB Elevation 15. Distance to Nearest Well Surface: x - 275,057.001 y - 2,356,013.0011 ~ Zone - 4 (Height above GL): (21' AGL) 87 feet Within Pool: 1,900 ft. 16. Deviated wells: Kickoff depth: 3,777 feet -' 17. Maximum Anticipated Pressures in psig (see 20 25.035) Maximum Hole Angle: 41 degrees ' Downhole: 991 `° Surface: 61 ' 18. Casing Program: Setting Depth Quantity of Cement Size Specifications Top Bottom c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 0' 0' 0' 0' 0' 0' 8 1/2" 7" 26 N-80 BTC 1323' 3477' 3023' 4800' 4017' 138 sacks 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): 5820' 4796' 4678' Casing Length Size Cement Volume MD TVD Structural 178' 20" Driven 178' 178' Conductor Surface 2003' 13 3/8" 1100 2003' 1844' Intermediate Production 5801' 9 5/8" 1400 5801' 4782 Liner Perforation Depth MD (ft): 4410'-4925' Perforation Depth TVD (ft): 3723'-4112' 20. Attachments: Filing Fee ~ BOP Sketch ~ Drilling Program ~ Time v. Depth Plot Shallow Hazard Analysis Property Plat ~ Diverter Sketch ~ Seabed Report ~ Drilling Fluid Program ~ 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name P.K. Berga Title Drilling Superintendent Signature C , Phone 907-565-3032 Date June 22, 2005 Commission Use Only Permit to Drill ~ ~~ ~- ~ ~ N b API Number: _ ~ ~ ~ "~~` ~ ~ ~ ~ ~ ~ Permit Approval ~ ~~'~~~ See cover letter for other requirements um er: 50- ~ Date: . Conditions of approval Sa r quired Yes ~ No ~ Mud log required Yes ~ No ro sulfide measures Yes ~ No ~ Directional survey required Yes ~ No Other:.~_ ,L. ~ ~ ~ n ~~ C? n$~.s . /~ ~ T, C$.w`~./~."~` ~ ~ Gv i~ G~ tt.L Y'G ~ , ~ C ~ APPROVED /1 / ~ A Approved by: THE COMMISSION Date. (l/ ~ (/ Form 10-40 vised 06/2004 a '~ ° .~ Submit inDuplicate MARATHON • Marathon Oil Company KU 24-7RD Kenai Gas Field, Pad 41-18 Sidetrack/Completion Procedure History: Well KU 24-7 was previously a 3-1/2" dual string Poo13 and Poo14 Sterling well used for cuttings disposal.`Sundry approval was recently obtained to recomplete the Pool 3 disposal zone to remediate mechanical integrity problems. While working over the well, excessive casing damage has created various fishing problems across the perfs in Poo13. In order to restore cuttings disposal, the well will need to be sidetracked. The short string and the dual packer have been removed during the fishing operation. Objective: Abandon and sidetrack the well above the damaged casing to restore access to disposal permitted Poo13 sands. The new bottom hole location will remain within 500' of the original location to maintain the existing Disposal Injection Order. f Procedure: 1) PU test packer and pressure test casing to 1500psi to verify casing integrity to 4350'. 2) Abandon Poo13 and Poo14 perfs per approved procedure. (will consist of CIBP and pre-/ determined cement volume) 3) PU 9-5/8" bridge plug and set just above casing collar at ~3800'MD as a base for the/ whipstock. 4) PU combination whipstock/mill assembly. Orient and set whipstock and mill out window at 3777'. After exiting the 9-5/8" casing, PU drilling assembly with 8-1/2" bit ~ and drill to TD at approximately 4800' MD. 5) Prepare to run the following 7" casing completion (26 ppf, L-80 mod but): a. 7" float shoe b. 2 jts 7", 26ppf, L-80mod but csg c. 7" landing collar d. 1250' of 7", 26ppf, L-80 modified buttress casing. e. 7" x 9 5/8" liner hanger, ZXP liner hanger packer and tie back extension on hydraulic setting tool with 5" drill pipe to surface. f. Cement head with plug drop assembly. 6) Run assembly to TD with liner packer at 3477' MD. 7) MIRU BJ Services to cement liner in place. Pump cement per BJ program. a. Reciprocate liner while pumping cement, and bump plug. 8) With cement in place, set liner hanger. • • a. Apply required pressure to drillpipe to set liner hanger. b, Sting out of liner hanger assembly and CBU looking for cement returns. • Perform cement top job if indications of lost cement returns. c. Set ZXP packer per procedure once cement is in place. d. POOH laying down excess 5" drill pipe. 9) PU 4" drill pipe and clean out liner to bottom. Displace mud with inhibited completion fluid. POOH laying down drill pipe. 10) Run completion as follows: a. PU packer assembly (all to bepre-bucked) including: • wireline entry guide w/ 4-1/2" IBT box • 10' 4-1/2" IBT pin x box • XN nipple (with Pollard RHCP plug installed and pressure tested) 4-1/2" IBT pin X box • 4' 4-1/2" IBT pup joint w/ 4-1/2" IBT pin x 4-1/2" TCII box • 7"Baker Premier packer w/ 4-1/2" 12.6 TCII pin X box • 6' 4-1/2" IBT pup jt w/, 4-1/2" TCII pin x 4-1/2" IBT box b. MU 4-1/2" IBT tubing string (strapped, numbered, and rabbited) and RIH to ~4445'MD. c. Space out as needed to land packer at 4400'. d. Land tubing in hanger with 4-1/2" landing jt. e. MU Vetco to 'ng hanger spool (cut with 4-1/2" IBT threads). Install packoff and pressure tes to SOO/4500psi. ~~~ 11) Prepare to set packer a. Circulate completion fluid. b. Drop Ball rod configured to seat in RHCP plug. c. Pressure up packer to 4200psi to set (may see a few shears prior to setting). 12) Pressure test the asi g to 1500psi w/ no pressure on the tubing. ND BOP stack, NU tree and test to si. RDMO GD #1 S -P~ ~cQ ~~ 13) Reconnect surface flow lines and control lines. To comply with Conservation Order No. 533, retrofit outer annulus and inner annulus valves to permit above-ground installation ` of pressure gauges/transmitters. Also, install tubing pressure gauge and ensure tree is compliant with 20 AAC 25.200. 14) RU wireline unit to pull plug in tubing string. 15) Perforate Poo13 zones identified by Geology. 16) Resume cuttings injection. ~ A M naww-rNON KU 24-7 Proposed Redrill Pad 41-18 Kenai AK RT=O' Tbg Hanger @ 27.68' Drive Pipe: 20" 94# H-40 @ 178' 13 3/8" 61# K-55 Casing @ 2003' Liner hanger w/ ZXP Packer @ 3477' Abandoned Section: -Otis XA Slidir;g Sleeve @ 4639' {ID=2.75"j `PX plug (set 9115;031 -Pvtodel S-2 Prodn Packer @ 4679' locator Sub @ 4677' Top of 13.72' Seal Asst' !cv 4678' ..Otis X Nipple @ 4G92' . - -4694` Cut tbS {7126!88} j ~ ~ Perf Record Date Interval 5182 4410'-4490' A-10 5.'82 4525'-4560' A-1': 5182 4410'-4490' Reperf Isahted: 7 ;88.4696'.- 4.7.Og s...6-2... 53 82-4890'-49x.5:...6-4- :~82-49fl-r4~25--8-4- ~Gz'd-7:88 ETD c~ 4678' TOF ~v7 4848' {a0' lubirtg) 9 5/8" 47# N-80 Csg Exit @ 3777' Tubing Detail Infection String: 4 1/2" 12.6#, N-80 Tubing ~ 1. Premier Removable Packer @ -4400' 2. XN nipple @ -4445' Perforations Pool3 TBD Q a 0 ' 7" 26 ppf, N-80, mod butt Liner 3477'-4800' Well Name & Number: KU 24-7 Lease: Kenai Gas Field County or Parish: Kenai Pen. Borough State/Prov. AK Country: USA Perforations (MD) See Above (TVD) See Above Angle/Perfs Angle @ KOP and Depth BHP: BHT: -80 F Completion Fluid: Dated Completed: • • MARATHON MARATHON OIL COMPANY DRILLING PROGRAM KU 24-7RD Original 6/22/05 Originator: P. K. Berqa Drilling Superintendent: P.K. Berqa Drilling Manager: B. J. Roy Page 1 of 10 • General Well Data .............................................. Geologic Program Summary .............................. Summary of Potential Drilling Hazards ............... Formation Evaluation Summary ......................... Drilling Program Summary ................................. Casing Program .................................................. Casing Design .................................................... Maximum Anticipated Surface Pressure ............ BOPE Program ................................................... Wellhead Equipment Summary ......................... Directional Program Summary ........................... Directional Surveying Summary ......................... Drilling Fluid Program Summary ........................ Drilling Fluid Specifications ................................. Solids Control Equipment ................................... Cement Program Summary ................................ Bit Summary ....................................................... Hydraulics Summary .......................................... Formation Integrity Test Procedure .................... Table of Contents ............................ Page 2 of 10 • ............................................................................3 ............................................................................3 ............................................................................4 .............................................................................4 .............................................................................4 .............................................................................5 .............................................................................5 ............................................................................. 5 ............................................................................. 6 ............................................................................. 6 .............................................................................7 .............................................................................7 .............................................................................7 .............................................................................8 .............................................................................9 .............................................................................9 ...........................................................................10 ...........................................................................10 ...........................................................................10 • • General Well Data Well Name KU 24-7RD Lease/License Surface Location 604' FNL, 796' FEL, Sec. 18, T4N, R11W r WBS Code W0.05.11615.EXP SlotlPad 41-18 Field Kenai Gas Field Spud Date 6/24/05 KB Elev. 87 Borough Kenai Peninsula API No. Ground Level Elev. 66 State /Country Alaska Well Class Disposal P rrrri. Datum KB Total MD 4,800' Rig Contractor Glacier Drilling V~ater Depth N/A Total TVD 4,017" Rig Name #1 Water Protection Depth (casing in place) Comments: Geologic Program Summary Formation MD -RKB (ft) TVD -RKB (ft) Pore Pressure (psi) Pore Pressure (ppg) Lithology Possible Fluid Content Sterling A-10 4410 3723 968 5 Sandstone Drilling fluids/water Sterling A-11 4525 3810 991 5 Sandstone Drilling fluids/water Comments: Surface Location Coordinates From Lease/Block Lines 604' FNL, 796' FEL, Sec. 18, T4N, R11 W Latitude 60° 26' 35.2092" N Longitude 151 ° 14' 43.9502" W UTM North (Y) 2,356,013.0011' UTM East (x) 275,057.0016' Tolerance Horizontal '~I Depth Displacement (ft) I~ MD TVD N/S E/W Tolerance Target (ft) {ft) Location (Y) (X) (ft) Sterling A-10 4,410 3,723 UTM 2,356,880.72' N, 273,129.95' E 822 -1923 Circle 25' radius Well TD 4,800 " 4,017 ~ UTM 2,357,050.53' N, 272,957.37 E 998 -2119 Circle 25' radius Comments: Page 3 of 10 • • Summary of Potential Drilling Hazards Hazard Event Discussion Lost Circulation Control losses by using sufficient sized LCM. Comments: Potential Hazards Statement To comply with state regulations the Potential Hazards section and the well shut-in procedures must be posted in the drillers dog house. The man on the brake (driller or relief driller) is responsible for shutting the well in (BOPE or diverter as applicable) as soon as warning signs of a kick are detected and an influx is suspected or confirmed. A copy of the approved permit to drill must be kept on location and be readily available to the AOGCC or BLM inspector. This well's primary objective is the A-10 and A-11 sterling sands that have been used for fluids and cuttings disposal. No gas and no oil -'` sands are expected to be encountered. No HZS is anticipated. ~` r Sands will be encountered from +/- 3777' MD/3249' TVD to total depth of the well. These sands will be depleted and lost circulation and differential sticking are potential hazards. The FLOPRO mud system that will be used to drill the well will help reduce these risks and lost circulation materials will be on location. No well interference hazards exist. Formation Evaluation Summary Interval LWD Electric Logs Mud Logs Surf/Inter (existing) None None None Sidetrack (openhole) None None None Sidetrack (cased hole) None None None Coring Requirements: None Comments: Drilling Program Summary 1. The drilling rig is already on the well, with the BOP stack installed and tested. Set wear bushing 2. Abandon existing perforations according to program to be filed with AOGCC and the BLM. 3. RIH and set CIBP at +/- 3800' md. Test plug and casing to 1500 psi. ~ 4. MU and RIH with bottom trip whipstock. Set whipstock for 45° north of high side orientation using MWD. Cut window and ensure that all mills are worked thru window. Displace hole to new flopro mud. Test shoe. (- 12.0 ppg anticipated). 5. Drill an 8-1/2" hole to 4,800' MD/ 4,017' TVD per the attached directional program. Backream each stand. Lost circulation is / possible throughout this interval. Maintain sized CaCOs LCM to prevent losses in the low pressure injection zones as per the mud prognosis. Monitor torque and drag to indicate hole cleaning problems. 6. At TD, circulate the hole clean(pump caliper). Short trip to shoe. TIH and circulate the hole clean(pump caliper). POOH. Pull wear bushing. 7. Locate casing swage and safety valve. Function safety valve and place on rig floor. Record function test in IADC book. RU j and run 7" casing liner. 8. Circulate and pump fluid calipers. Cement casing as per the attached cementing program, while reciprocating liner. Bump plug and set liner. 9. Pull out of liner hanger and circulate cement clean. Set liner hanger packer. Pull out of hole with setting tool. % 10. Clean out liner. Test casing, liner and liner lap to 1500 psi. ~ 11. Prepare for completion. A separate completion procedure will be developed. Page 4 of 10 • • Casing Program MD (ft) Connection API Ratings Casing Size (in) op ottom Weight (Ibs/ft) rade ype O. D. (in) Makeup Torque (ft-Ibs) Hole Size (in) r- m fl- a~ fl, r- U a o ~, ~ °' 7 3477 4800 26 L-80 BTC-M 7.656 8.5 7240 5410 604 Comments: The make up of the buttress connection will be to the proper mark. Casing Design Casing Shoe Safety Factors Casing Size (in) eight (Ib/ft) rade Setting Depth (TVD) Mud Wt When Set (Ib/gal) Frac. Grad (Ib/gal) Form Press (Ib/gal) Maximum Surface Pressure (psi) 3 m ~ a f6 0 U ~ o ~N ~ ~ 9 5/8 47 N-80 4782 Existing Casing String 7 26 L-80 4017 9.2 12.0 5.0 610 2.8 2.32 2.2 Comments: The 13 3/8" and 9 5/8" strings are existing casings. A casing exit will be made in the 9 5/8" casing below the 13 3/8" surface casing shoe. The 7" liner to be put in place will be new tubulars. Maximum Anticipated Surface Pressure Casing Size (in) Setting Depth TVD (ft) MAWP * (psi) MASP ** (psi) Mud/Gas Ratio 13 3/8 1,844 Not Applicable, 9 5/8" Intermediate is already in place. 9 5/8 3,249*** 610 610 0/100 7 4,889 610 610 0/100 * MAWP =Maximum anticipated wellhead pressure ** MASP =Maximum anticipated surface pressure *** 9 5/8" casing exit depth. Comments: The Maximum Anticipated Surface Pressure (MASP) for the intermediate casing is based on the highest exposed pore pressure less the hydrostatic pressure of gas. The MASP for the production liner is MASP for the 9 5/8" casing. 9 5/8" intermediate casing (Pore pressure from Sterling A-11 - 991 psi @ 3,810' TVD) MASP= PP - (GG * TVDf) MASP=991 psi - (.1 "3810') Page 5 of 10 • • MASP= 610 psi 7" Production Liner MASP =MASP for 9 5/8" Intermediate = 610 psi BOPE Program Casing Test Test Casing Test Fluid Pressure Size MAWP MASP Press Density BOPS LowlHigh Casing (in) (psi) (psi) (psi) (Ib/gal) Size & Rating (psi} (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram (1) 13 5/8" 5M blind ram Intermediate 9 5/8 610 610 1,500 9,2 250/3000 (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets (1) 13-5/8" 5M annular Intermediate (1) 13-5/8" 5M pipe ram with (1) 13 5/8" 5M blind ram 7 610 610 1,500 9.2 250/3000 Production (1) 13-5/8" 5M drilling spool with 3-1/8" 5M Liner outlets Comments: Blowout Preventers The blowout preventer stack will consist of a 13-5/8" x 5000 psi annular preventer, a 13-5/8" x 5000 psi double gate ram type preventer ~ with blind rams in the bottom and pipe rams in the top and a 13-5/8" x 5000 psi drilling spool (mud cross) with 3-1/8" x 5000 psi outlets. The choke manifold will be rated 3-1/8" x 5000 psi. It will include a remote hydraulic actuated choke and a hand adjustable choke. Also included is a poor-boy gas buster, and avacuum-type degasser. A flow sensor will be installed in the flowline and the mud pits will contain sensors to measure the volume of fluid in the surface mud system. Both sensors will contain readouts convenient to the drillers console. Casing Test Pressures Casing test pressures are based on the lesser of (1) MASP, or (2) 70% of rated burst pressure of the casing adjusted for the mud weight used during the test less a 8.3 ppg back-up unless otherwise noted. Wellhead Equipment Summary Component Description Casing Hanger Type Casing Head Casing Spool 12", 3,000 psi flange top X 13 3/8", 3,000 psi WF bottom Slip Tubing Head 10", 5,000 psi flange top X 12", 3,000 psi flange bottom Hanger Comments: Page 6 of 10 • • Directional Program Summary Build Turn Coordinates Sec. No. Description MD (ft) TVD (ft) Rate (°/100') Rate (°/100') Dogleg (°/100') Inclination (deg) Azimuth (deg) N/S (ftj E/W (ft) VS (ft) 1 Surface 21 21 0 0 0 0 0 2 Kickoff Point 3777 3249 0.00 41.06 293 571 -1600 1691 3 3800 3266 3.0 42.76 296 577 -1615 1707 4 4100 3489 3.0 41.19 309 684 -1784 1905 5 4400 3716 41.02 313 817 -1928 2093 6 4600 3866 41.02 313 953 -2071 2217 7 4800 4017 41.02 313 998 -2119 2342 Comments: Potential Well Interference: Well Distance (ft) Depth (MD) No serious interference exists. See attached directional plan and anticollision analysis for more details. Directional Surveying Summary Interval MWD Survey Magnetic Multishot Gyro Multishot Comments 3777-4800 X Comments: Drilling Fluid Program Summary Interval - TVD Minimum Inventory From To Density Gel (ft) (ft) (Ib/gal) Fluid Description Additives Viscosifier Barite 3777 3800 8.6 Drill Water(milling fluid) Flo-Vis for sweeps Flo-Vis, DualFlo, KCI, Caustic, 3800 4800 9.0 9. f' 6% KCL FLOPRO System Lubetex, Asphasol D, SafeCarb F, ~- ' Conqor 404, Detergent Page7of10 • • Comments: See mud prognosis for details. Sized CaC03 (SafeCarb) will be used to control leakoff into the high perm, low pressure injection zones. Drilling Fluid Specifications Interva l - TVD From (ft) To (ft) Density (Ib/gal) Vis (seGgt) PV (cP) YP (Ib/100 ft2) Fluid Loss (cc) pH MBT (Ib/bbl} OiIM/ater Ratio 3777 3800 8.6 ~ 26 1 N/A N/A 7 3800 4800 9.0 - 9.2 ,~ 10 - 14 15 - 20 TBD 9.0 - 9.5 Comments: Page 8 of 10 ~ • Solids Control Equipment o ~ ~ ~ rn N ~ ~ LA ~ w ~ ~ U N a ~ _ ~ y •y 'a C ._ ._ O lnteNal ~ ~ ~ ~ U U U N Comments 3800 - 4800 X X X Item Equipment Specifications (quantity, design type, brand, model, flow capacity, etc) Shaker 2 -Derrick Model 2E48-90F-3TA Desander N/A Desilter 1 -Derrick Model 0522 Mud Cleaner N!A Centrifuge 2 - M{/Swaco units will not be used. Cuttings Dryer N/A Cuttings Injection Marathon G&I Facility Zero Discharge N/A Comments: The solids control equipment will consist of two flowline cleaners and a desilter. Included will be equipment to de-water the underflow from the mud processing equipment to allow for disposal of the cuttings and solids by slurrification and injection into the disposal well at the KGF. Cement Program Summary De pth Gauge Top of Cement Open Casing Hole Ann Vol Slurry WOC Hole Size MD TVD Size MD TVD To TOC Vol Time Excess (in) (ft) (ft) (in) (ft) (ft) (ft3) (ft3) (hrs) (%) 7 4800 4017 8.5 3477 3023 173 255 N/A 50 Mix Water Compressive Casing Size Density Qty Yield Slurry Vol TOC MD Qty WL FW Strength (Psi) (in) Slurry Cement Description (Ib/gal) (sx) (ft31sx) (ft3) (ft) . (gal/sx) Type (cc) (%) 12 hr 24 hr Lead 7 Taii Class "G" 13.5 138 1.84 255 3477 9.27 Fresh 10 0 300 820 Comments: See cement prognosis for details and spacer specifications. Page 9 of 10 • • Bit Summary Interval - MD Recommended Estimated From (ft) To (ft) Size (in) Type WOB (kips) RPM Rotating Hours ROP (ft/hr) 3777 3800 8.5 Window mill 5 / 25 150 3800 4800 8.5 Steel tooth roller cone 5 /30 200 - 300 Comments: See bit prognosis for details. Hydraulics Summary Rig mud pumps available are shown below. Max Press @ Displacement @ Liner ID Stroke 90% WP 95% eff Max Rate Hole Sections Used Qty Make Model (in) (in) (psi) (gal/stroke) (spm/gpm) pn 3 National Oil A600PT 5 8 2,597 2.04 175 / 357 All Sections We11 6 8 1,804 2.94 175 / 514 All Sections Tabulated below are the expected flow rates, standpipe pressures and nozzle sizes for each hole section. Hole Standpipe Min Nozzle Depth-MD Size Pump Rate Pressure AV ECD Size (ft) (in) (gpm) (psi) (fpm) (Ib/gal) (32"s) Remarks 4800 8.5 460 1250 190 9.5 3 - 18 Actual Data from KU 24-5RD Sidetrack Comments: Formation integrity Test Procedure Surface and Intermediate casing shoes will be tested to Leak-off. Prior to drilling out of casing strings, test BOPs and casing to the specified pressure listed in the BOP Program section. Plot test and record volume required on the drilling report. Leak-off tests (LOT) are to be conducted as described below: 1. Drill 20' to 25' of new formation below the casing shoe and condition the mud to the same properties in and out. 2. Pull drill string into the casing shoe and close ram preventer, and line up to the choke manifold with a closed choke. 3. Begin slowly pumping fluid down the drill string at 1/2 bpm while recording casing and drillpipe pressures at 1/2 bbl intervals. A running plot of pressure versus volume should be kept by the drilling foreman while the test is in progress. 4. Stop pumping when the pressure curve departs form a straight line sufficiently to indicate leakage into the formation. Record as ppg equivalent mud density in the IADC and morning reports. 5. Monitor and plot pressure drop and time after shut-in for 10 minutes or until the shut-in pressure stabilizes. Page 10 of 10 MARATHON ~ Oil Company ~, ~~ ~ BAKER Location: Kenai Peninsula, Alaska Slot: slot #KU24-7 NV~ES Field: Kenai Gas Field Well: KU24-7 INTEQ ' Installation: Pad #41-18 Wellbore: KU24-7 (3777) ST 'I MARATHON Scale 1 cm = 100 ft East (feet) -> -3000 -2800 -2600 -2400 -2200 -2000 -1800 -1600 -1400 -1200 1400 KU24-7 1200 ~~ A ~\ Nu31~i ~3]]T')6i D. 8 End of Hold - 4015.38 Tvd, 999.87 N 2124.13 W 1000 Z 800 End of Turn - 3562.55 Tvd, 729.11 N 1838.43 W ,..,,\ ~D rt Tie on - 3246.52 Tvd, 573.24 N 1606.01 W 600 ~ ~, - ~" KU24.) I 400 ~ i 200 ~ 2800 0 0 3000 U N ~ 3200 3400 d d 3600 >Z 3800 d t4 4000 w~ W ' 4200 d 3 L ~ 4400 V 4600 4800 5000 5200 Tie on - 41.04 Inc, 3777.00 Md, 3246.52 Tvd, 1697.21 VS End of Drop/Turn - 41.00 Inc, 4200.00 Md, 3562.55 Tvd, 1973.88 VS ~ ~ WELL PROFILE DATA I-JD. & End of Hold - 4015.38 Tvd, 999.87 N 2124.13 W %u3a-i (3T)T~ 6T Point MD Inc Azi TVD North East degl100ft V. Seet Tie on 3777.00 41.04 293.00 3246.52 ~ 573.24 -1606.01 0.00 ~I 1697.21 37.00 42.76 295.50 3261.41 578.73 -1618.18 12.00 1710.56 00.00 41.00 313.46 3562.55 729.11 -1838.43 3.00 ~ 1973.88 D0.00 41.00 313.46 4015.38 I 999.87 -2124.13 0.00 2347.70 Ref wellpath is KU24-7 (3777') ST. Coordinates are in feet reference slot #KU24-7. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: Glacier 1 Rig Datum to mean sea level. 88.00 ft. Plot North is aligned to TRUE North. 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 Scale 1 cm = 100 ft Vertical Section (feet) -> Azimuth 295.21 with reference 0.00 N, 0.00 E from slot #KU24-7 MARATHON Oil Company,slot #KU24-7 M Pad #41-18, MARATHON Kenai Gas Field,Kenai Peninsula, Alaska PROPOSAL LISTING Page 1 Wellbore: KU24-7 (3777') ST Wellpath: KU24-7 (3777') ST Date Printed: 21-Jun-2005 gg~~~~t' -iill Wellbore Name Created Last Revised KU24-7 377T ST 20-Jun-2005 21-Jun-2005 Well Name Government ID Last Revised KU24-7 21-Jun-2005 Slot Name Grid Northin Grid Eastin Latitude Lon nude North East slot #KU24-7 2356013.0011 ' 275057.0016 ' N60 26 35.2092 W151 14 43.9502 603.64S 795.61 W Installation Name Eastin Northin Coord S stem Name North Ali nment Pad #41-18 275863.8084 2356601.5130 AK-4 on NORTH AMERICAN DATUM 1927 datum True Field Name Eastin Northin Coord S stem Name North Ali nment Kenai Gas Field 270993.1910 2361975.0460 AK-4 on NORTH AMERICAN DATUM 1927 datum True seated By '` _ _ _~ omments All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Glacier 1 88.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 295.21 degrees Bottom hole distance is 2347.70 Feet on azimuth 295.21 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated • MARATHON Oil Company,slot #KU24-7 Pad #41-18, MARATHON Kenai Gas Field,Kenai Peninsula, Alaska PROPOSAL LISTING Page 2 Wellbore: KU24-7 (3777') ST Wellpath: KU24-7 (3777') ST Date Printed: 21-Jun-2005 ~~r R~ 1NTEQ Well ath G rid Re ort MD[ft] Inc[degj Azi[deg] TVD[ftj North[ft] East[ft] Dogleg de /100ft Vertical Section ft Easting Northing -9.00 0.00 0.00 -9.00 O.OON 0.00E 0.00 0.00 275057.00 "~ 2356013.00 ° 91.00 0.00 0.00 91.00 O.OON 0.00E 0.00 0.00 275057.00 2356013.00 191.00 0.50 298.00 191.00 0.20N 0.39W 0.50 0.44 275056.62 2356013.21 291.00 1.00 319.00 290.99 1.07N 1.34W 0.56 1.67 275055.68 2356014.09 391.00 4.00 303.00 390.88 3.63N 4.84W 3.05 5.93 275052.23 2356016.72 491.00 6.00 289.00 490.50 7.23N 12.71 W 2.33 14.58 275044.43 2356020.47 591.00 8.00 291.00 589.75 11.42N 24.15W 2.01 26.71 275033.07 2356024.88 691.00 10.25 286.00 688.48 16.37N 39.20W 2.38 42.44 275018.12 2356030.11 791.00 12.00 282.00 786.60 20.99N 57.92W 1.91 61.34 274999.49 2356035.08 891.00 14.25 285.00 883.98 26.33N 79.98W 2.35 83.58 274977.54 2356040.84 991.00 17.25 285.00 980.22 33.36N 106.20W 3.00 110.29 274951.46 2356048.36 1091.00 20.00 287.00 1074.97 42.20N 136.88W 2,82 141.82 274920.95 2356057.78 1191.00 23.00 287.00 1168.00 52.91 N 171.93W 3.00 178.09 274886.12 2356069.15 1291.00 26.00 287.00 1258.99 65.03N 211.58W 3.00 219.13 274846.70 2356082.02 1391.00 29.25 287.00 1347.58 78.59N 255.91 W 3.25 265.01 274802.63 2356096.41 1491.00 32.75 288.00 1433.28 94.09N 305.02W 3.54 316.05 274753.83 2356112.84 1591.00 33.25 289.00 1517.15 111.38N 356.67W 0.74 370.14 274702.52 2356131.10 1691.00 35.00 288.00 1599.93 129.17N 409.87W 1.84 425.85 274649.67 2356149.89 1791.00 37.00 288.00 1680.83 147.33N 465.76W 2.00 484.16 274594.13 2356169.11 1891.00 38.00 288.00 1760.16 166.14N 523.66W 1.00 544.55 274536.60 2356189.01 1991.00 40.75 289.00 1837.45 186.29N 583.81 W 2.82 607.55 274476.85 2356210.28 2091.00 39.50 289.00 1913.92 207.27N 644.74W 1.25 671.62 274416.32 2356232.41 2191.00 38.00 288.00 1991.90 227.13N 704.09W 1.63 733.78 274357.36 2356253.40 2291.00 36.50 289.00 2071.5 246.33N 761.50W 1.62 793.89 274300.33 2356273.68 2391.00 35.00 289.00 2152.66 265.35N 816.74W 1.50 851.97 274245.47 2356293.74 2491.00 35.00 289.00 2234.57 284.03N 870.97W 0.00 908.99 274191.60 2356313.43 2591.00 34.00 289.00 2316.98 302.47N 924.52W 1.00 965.30 274138.41 2356332.88 2691.00 34.00 290.00 2399.89 321.13N 977.23W 0.56 1020.94 274086.06 2356352.54 2791.00 34.00 290.00 2482.79 340.26N 1029.78W 0.00 1076.63 274033.89 2356372.65 2891.00 34.00 289.00 2565.70 358.92N 1082.49W 0.56 1132.27 273981.54 2356392.31 2991.00 35.00 291.00 2648.11 378.30N 1135.70W 1.51 1188.67 273928.71 2356412.70 3091.00 38.75 291.00 2728.09 399.81 N 1191.71 W 3.75 1248.51 273873.11 2356435.25 3191.00 41.00 291.00 2804.83 422.78N 1251.56W 2.25 1312.44 273813.71 2356459.35 3291.00 41.00 292.00 2880.30 446.82N 1312.60W 0.66 1377.91 273753.14 2356484.54 3391.00 41.00 293.00 2955.77 471.93N 1373.21 W 0.66 1443.44 273693.02 2356510.79 3491.00 41.00 294.00 3031.25 498.09N 1433.38W 0.66 1509.01 273633.36 2356538.08 3591.00 41.25 294.00 3106.57 524.84N 1493.46W 0.25 1574.77 273573.80 2356565.96 3691.00 41.25 293.00 3181.76 551.13N 1553.93W 0.66 1640.67 273513.84 2356593.39 3777.00 41.04 293.00 3246.52 573.24N 1606.01 W 0.25 1697.21 273462.19 2356616.48 3797.00 42.76 295.50 3261.41 578.73N 1618.18W 12.00 1710.56 273450.12 2356622.20 3800.00 42.74 295.63 3263.61 579.61 N 1620.02W 3.00 1712.60 273448.30 2356623.11 3900.00 42.05 299.96 3337.49 611.01 N 1679.64W 3.00 1779.92 273389.29 2356655.64 4000.00 41.52 304.39 3412.07 646.46N 1736.01 W 3.00 1846.02 273333.60 2356692.15 4100.00 41.17 308.90 3487.16 685.87N 1788.99W 3.00 1910.74 273281.38 2356732.54 4200.00 41.00 313.46 3562.55 729.11 N 1838.43W 3.00 1973.88 273232.77 2356776.71 4300.00 41.00 313.46 3638.02 774.24N 1886.05W 0.00 2036.19 273186.02 2356822.73 4400.00 41.00 313.46 3713.49 819.37N 1933.66W 0.00 2098.49 273139.26 2356868.75 4500.00 41.00 313.46 3788.97 864.49N 1981.28W 0.00 2160.79 273092.51 2356914.76 4600.00 41.00 313.46 3864.44 909.62N 2028.90W 0.00 2223.09 273045.76 2356960.78 4700.00 41.00 313.46 3939.91 954.75N 2076.52W 0.00 2285.40 272999.00 2357006.80 4800.00 41.00 313.46 4015.38 999.87N 2124.13W 0.00 2347.70 272952.25 2357052.81 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Glacier 1 88.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 295.21 degrees Bottom hole distance is 2347.70 Feet on azimuth 295.21 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated i MARATHON Oil Company,slot #KU24-7 Pad #41-18, MARATHON Kenai Gas Field,Kenai Peninsula, Alaska • PROPOSAL LISTING Page 3 Wellbore: KU24-7 (3777') ST Wellpath: KU24-7 (3777') ST Date Printed: 21-Jun-2005 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and 7VD's are from Rig (Glacier 1 88.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 295.21 degrees Bottom hole distance is 2347.70 Feet on azimuth 295.21 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ~~ 1NTEQ ARATHON Oil Comp y Location: Kenai Peninsula, Alaska Slot: slot #KU24-7 Field: Kenai Gas Field Well: KU24-7 Installation: Pad #41-18 Wellbore: KU24-7 (3777') ST Created by: Planner Date plotted : 21-Jun-2005 Plot reference is KU24-7 (3777') ST. Ref wellpath is KU24-7 (3777') ST. Coordinates are in feet reference slat #KU24-7. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: Glacier 7 Rig Datum to mean sea level: 88.00 k. Plot North is aligned to TRUE North. 290 zso z7o zso 250 Normal Plane Travelling Cylinder -Feet TRUE NORTH 350 0 10 340 20 70 ao so 100 110 190 180 170 All depths shown are Measured depths on Reference Well M~tRATt~ 200 160 ,• 3 BARE R- HiJ GHEE 1NTFQ ~~ Scale 1 cm = 50 ft East (feet) -> -2900 -2800 -2700 -2600 -2500 -2400 -2300 -2200 -2100 -2000 -1900 -1800 -1700 -1600 -1500 -1400 -1300 -1200 -1100 -1000 -900 -800 1800 1700 1600 1500 1400 1300 1200 .F ~ 1100 ... t C 1000 Z 900 800 700 600 0 ~~ 500 E U 400 U 4400 `. 4300 4200 `'~ 4100 ~'. 4000 O 1800 1700 1600 1500 . 1400 1300 1200 Z 1100 3 ~+~ 1000 ~ rt ... 900 800 700 600 n v m 500 n 3 400 n cn 0 -2900 -2800 -2700 -2600 -2500 -2400 -2300 -2200 -2100 -2000 -1900 -1800 -1700 -1600 -150D -1400 -1300 -1200 -1100 -1000 -900 -800 scale ~ cm = 5o ft East (feet) -> MARATHON Oil Company CLEARANCE LISTING Page 1 KU24-7 (3777') ST, KU24-7 (3777') ST Date Printed: 21~Jun-2005 ~ATt~N slot #KU24-7, Pad #41-18 Kenai Gas Field, Kenai Peninsula, Alaska Ellipse separations are reported ONLY if BOTH wells have uncertainty data Only Depth and Magnetic Reference Field error terms are correlated across tie points Proximities beyond ft with expansion rate of fU1000ft are not reported Cutoff is calculated on CENTRE to CENTRE distance Summary data uses Closest Approach clearance calculation for all minima Hole size/Casings are NOT included Hole sizelCasings are NOT subtracted from Centre-Centre distance Ellipses scaled to 2.OOstandard deviations. Closing Factor Confidence limit of 99.80% Errors on Ref start at Slot Permanent Datum (-9.00) Report uses Revised: (D-C)/E Factor Calculation BAKER Nt1GH~S ITT(;(} Wellbore_ _ _ _ _ __ __ Created ~ Last Revised 20-Jun-2005 ~ 21_-Jun-2005 - Well - - - - _ - -~ Government ID ~ Last Rewsed _ - _ -- - - _ -~_ _ _ 21-Jun-2005 Slot __- Nanie Grid Northin ~ Grid Eastin Latitude ~ Longitude ~ North East ~ r slot #KU24-7 2356013.0011 275057.0016 N60 26 35.2092 W151 14 43 9502 603.64S 795.61 W ~ - - Installation... _ -_ _ - ~ - - _ - Name Easti~, ~ Northing_ ~ _ Coord System. Name_ ~ North Al~nment _; ~ Pad #41-18 275863.8084 2356601.5130 I AK-4 on NORTH AMERICAN DATUM 1927 datum) True ~ Field K N Fi T n _ r ~ Coord System Name - -_ L North Alignment 1 ~ , e na Gas eld_ _ 270993 1910 - 75 0460 - AK-4 on NORTH AMERICAN DATUM 1927 datum, 23619 _ True _ - _ - - - - _ _- _ - Clearance Sum mar - ~ Offset Offset _ ~ Offset T Offse~ _ - T-- Minimum MD[ft] T Diverging __ _ _ Ellipse i Ellipse Clearance ~ Clearance WeIlName Wellbore Slot I Structure Distance From[ft] Separation MD[ft] Factor i MD(ftj - - - _ (itl _ _ ~ - -_I ~ftl - - - _~ - KU24-7 KU24-7 slot #KU24-7 Pad #41-18 0.01 3777.00 3777.00 KBU33-7 KBU33-7 slot Pad #41-18 1154.42 3777.00 3777.00 #KBU33-7 KU41-18 KU41-18 slot#KU41-1 Pad#41-18 1798.74 3777.00 3777.00 Tem All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Glacier 1 88.Oft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated • MARATHON Oil Company KU24-7 (3777') ST, KU24-7 (3777') ST MARATHON slot #KU24-7, Pad #41-18 • CLEARANCE LISTING Page 2 Date Printed: 21-Jun-2005 Kenai Gas Field, Kenai Peninsula, Alaska BAKER M~tGHES i'~TEt _ _ Clearan ~ Data_T _ - _ 9 _ ___- P - Reference TReference~ Reference ReferenceOffset Well ' Offset Offset i Offset Offset ~ An le Closest ~ Elli se ~ MD[ft] ND[ft] ! North[ft] East[ft] ~ MD[ft] ND[ft] North[ft] East[ft] From i Approach Separation Highside ~ Distance ~ [fl} 3777.00 - 3246.52 573.24N _ _. - _ _ I -_ 160601W KBU33-7 3569.53 3245.20 I 1152.40N _ ~deg~- 1 607.38W 119.5 1ft1 .. _ __ 1154.42 3791.00 3256.99 577.01N 1614.51W KBU33-7 3582.36 3256.27 1158.02N 610.63W 117.5 1159.90 3797.00 3261.41 578.73N 1618.18W KBU33-7 3587.86 3261.01 1160.43N 612.02W 116.7 1162.21 3891.00 3330.80 608.02N 1674.40W KBU33-7 3674.83 3335.89 1198.74N 634.14W 114.1 1196.30 3991.00 3405.33 643.11N 1731.08W KBU33-7 3768.92 3416.75 1240.40N 658.19W 111.1 1227.99 4091.00 3480.38 682.16N 1784.37W KBU33-7 3864.31 3498.72 1282.66N 682.59W 108.2 1254.93 4191.00 3555.76 725.07N 1834.13W KBU33-7 3960.7 3581.65 1325.33N 707.22W 105.3 1277.06 4200.00 3562.55 729.11N 1838.43W KBU33-7 3969.50 3589.16 1329.18N 709.45W 105.0 1278.82 4291.00 3631.23 770.18N 1881.76W KBU33-7 4060.58 3667.48 1369.41N 732.74W 105.6 1296.40 4391.00 3706.70 815.30N 1929.38W KBU33-7 4166.03 3758.26 1415.60N 760.03W 106.3 1315.45 4491.00 3782.17 860.43N 1976.99W KBU33-7 4262.92 3841.82 1457.64N 785.28W 107.0 1334.31 4591.00 3857.65 905.56N 2024.61 W KBU33-7 4368.35 3932.90 1503.02N 812.88W 107.6 1353.12 4691.00 3933.12 950.68N 2072.23W KBU33-7 4468.32 4019.37 1545.61N 839.39W 108.3 1371.60 4791.00 4008.59 995.81N 2119.85W KBU33-7 4533.75 4076.17 1573.51N 856.02W 108.7 1391.25 4800.00 4015.38 999.87N 2124.13W KBU33-7 4542.44 4083.74 1577.23N 858.12W 108.8 1393.13 All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Glacier 1 S8.Oft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated LJ CLEARANCE LISTING Page 3 Date Printed: 21-Jun-2005 Kenai Gas Field, Kenai Peninsula, Alaska ~I. BAKER Yi If_YCC" _.. _..,~ _ _ Clearance Data Offset ~ Offset ~ Angle ~ Closest T Ellipse Reference j Reference Reference Reference i Offset Well ~ Offset ~ Offset I ivwtnJ 777.00 ~ ivutttJ -- - 3246.52 rvonntttJ 73.24N tastlttJ -- -- 1606.01W I l KU41-18 ! MuittJ i 3256.52 ivuittJ 246.52 North~ttJ I 1 167.41S tast~ttJ - --I 33.17E From Highside I _Ldeg -178.3 I Approach Separation Distance [ftl II _Lft1 _ _ 1798.74 3791.00 3256.99 577.01N 1614.51W KU41-18 3266.99 3256.99 167.41S 33.17E 179.4 1808.04 3797.00 3261.41 578.73N 1618.18W KU41-18 3271.41 3261.41 167.41S 33.17E 178.4 1812.10 3891.00 3330.80 608.02N 1674.40W KU41-18 3340.80 3330.80 167.41S 33.17E 173.1 1875.39 3991.00 3405.33 643.11N 1731.08W KU41-18 3415.33 3405.33 167.41S 33.17E 167.6 1941.52 - - - - _ - - set a ore urve o0 ----- __. rog ra m s ~ Y - - ~ - ~---- ~- T _ _WeU Wellbore _ _~ Surv~Name _ ' _ ~ftJ _ _ _ Sury~ Tool _ _ Error Modet_- KU41-18 ~ KU41-18 (Temol ~ MSS <0-14721> ~ 14712n0 ~ Phntnmarhaniral Mannetir.~ Standarri All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Glacier 1 88.Oft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated • MARATHON Oil Company CLEARANCE LISTING Page 4 KU24-7 (3777') ST, KU24-7 (3777') ST Date Printed: 21 -Jun-2005 MARATHON slot #KU24-7, Pad #41-18 Kenai Gas Field, Kenai Peninsula, Alaska - - - - - - earanc,_ T _ T __ ~ _ _ _ e Data_ _ B1#iKER HUGHE'~ I~TEt~_ Reference ~I MD[ft] 3777.00 Reference ' TVD[ft] 3246.52 I Reference North[ft] i 573.24N Reference East[ft] i 1606.01 W Offset Well U24-7 Offset MD[ft] 3777.00 Offset TVD[ftj -- 3246.53 Offset North[ft] - -- 573.24N Offset I East[ft] -- - 1606.OOW Angle From ~Hi(de~)__~ -180.0 Closest ! Ellipse Approach Separation _ Dis~ft~e i [ft] ~ 0.01 3791. 00 3256.99 577.01 N 1614.51 W KU24-7 3791.00 3257. 08 576 .83N 1614 .46W -137.2 0.21 3797. 00 3261.41 578.73N 1618.18W KU24-7 3796.99 3261. 61 578. 38N 1618 .08W -139.3 0.41 3891. 00 3330.80 608.02N 1674.40W KU24-7 3890.87 3332. 46 602 .95N 1674 .55W -122.6 5.33 3991. 00 3405.33 643.11N 1731.08W KU24-7 3990.34 3407. 53 628. 98N 1734 .39W -111.4 14.68 4091. 00 3480.38 682.16N 1784.37W KU24-7 4089.13 3482. 09 654 .30N 1794 .06W -106.9 29.54 4191. 00 3555.76 725.07N 1834.13W KU24-7 4187.49 3556. 32 680. 01N 1853 .24W -105.8 48.94 4200. 00 3562.55 729.11N 1838.43W KU24-7 4196.56 3563. 17 682 .44N 1858 .67W -105.8 50.88 4291. 00 3631.23 770.18N 1881.76W KU24-7 4285.78 3630. 50 706. 71N 1911 .93W -103.4 70.27 4391. 00 3706.70 815.30N 1929.38W KU24-7 4383.79 3704. 73 733 .75N 1969 .95W -102.2 91.11 4491. 00 3782.17 860.43N 1976.99W KU24-7 4481.56 3778. 82 760. 71N 2027 .77W -101.5 111.95 4591. 00 3857.65 905.56N 2024.61 W KU24-7 4579.36 3852. 76 787. 76N 2085 .78W -100.8 132.82 4691. 00 3933.12 950.68N 2072.23W KU24-7 4677.14 3926. 71 814. 79N 2143 .75W -100.4 153.69 4791. 00 4008.59 995.81N 2119.85W KU24-7 4773.41 3999. 38 841. 10N 2201 .16W -100.0 175.02 4800. 00 4015.38 999.87N 2124.13W KU24-7 4782.20 4006. 01 843. 47N 2206 .41W -100.0 176.98 _ _- __ _ _ _ _ Well KU24-7 __ _ _ _ - _ _ _Wellbore KU24-7 -- - --- - - - _ Offset Wellbore Su_rv~_Tool Programs _ Survey Name ~ MDfftl ~ Survey Tool GMS <0-5820'> 5811.00 Level Rotor G ro - ~ - - Error Model Standard All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Glacier 1 88.Oft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated e ~~ FIFE • • Marathon Oil Company Well Name: KU 24-7 Sidetrack Location: Kenai, Alaska. INTEGRATED FLUIDS ENGINEERING PRO]ECT PLAN ~~ :HST, .~ k~. Prepared For: MARATHON OIL COMPANY Welf KU 24-7 Sidetrack Kenai Peninsula, Alaska Prepared by: Tony Tykalsky Reviewed by: Aal Martens Presented to: Pete Berga June 21, 2005 T7 ~ ~~ IFE~" • :.IFE Marathon Oil Company PO Box 190168 Anchorage, Alaska 99519 ATTN: Pete berga Pete: • Marathon Oil Company Well Name: KU 24-7 Sidetrack Location: Kenai, Alaska. Enclosed is the recommended drilling fluid program for the KU 24-7 sidetrack to be drill this week. The following is a brief synopsis of the program. Overview: KU 24-7 is a sidetrack of an injection well. The plan is to drill a 1023' - 8-1/2" interval out of the 9-518 casing and run and cement 7" liner. No logging is planned and formation damage is not an issue. Since this sidetrack follows within 100' of the existing injection well, wellbore stability, lost circulation and possibly well control maybe an issue. Abandonment & Milling: A plug will be set at +/- 3800' and cement pumped below this depth to abandon the existing perfs. A whipstock with be set at +/- 3777' MD and the 9-5/8" casing will be milled out. Milling fluid will consist of the existing fluid viscosified with F1oVis to insure adequate removal of metal cuttins. Ditch magnets will be used to aid in the removal of these cuttings. After milling out the casing and insuring the opening is clean, the well will be displaced to a Flo-Pro KCl fluid prior to performing aleak-off test. Sidetrack Interval: This fluid is the typical F1oPro fluid used in the Kenai Gas Field. Thirty pounds per barrel of sized SafeCarh will be maintained in order to combat lost circulation in the Sterling sands. Since this is an injection well, EMI 920 is the recommended lubricant if metal to metal torque is a problem. If torque becomes a problem further down the hole, then Lubetex would be recommended. As low a mud weight as possible. However, no plans have been made for the solids van to be used on this sidetrack. Completion: After a cleanout run to T.D. of the 7" liner, the well will be displaced to drillwater treated for corrosion control. Conqor 303A and Sodium Meta Bisulfate will be added to the water prior to running the 4-1/2" tubing. Tony Tykalsky Project Engineer /M-I SWACO NOTE: This program is provided as a wide only. Well conditions will always dictate fluid properties required. ~~ IFE ~,; • • ~~ Marathon Oil Company t~E Well Name: KU 24-7 Sidetrack Location: Kenai, Alaska. Project Summary Casing Hole Casing Depth ND Mud Mud Sum Interval Size Size Program System Weight Days Mud Cost (in) (in) (ft) (ft) Solids Control (ppg) 9-5/8" 12-1/4" 3777' 3249' Milling fluid 8.6 +/- 1 $12,938 7" 8-1/2" 4800' 4017' Flo-Pro w/SafeCarb 9. 5 $52,015 Screens 230 - 210 mesh Desilter 4-112" 8-1/2" Completion 4800' 4017' Drill water w/ Corrision Control 8.4 1 $2,516.70 - Insure magnets are in proper location prior to milling out of 9-5/8" casing. - Cost include 1% EMI 920 and 1% Lubetex concentration in the sidetrack interval. - Cost does not account for any losses of fluid to the formation. IFE ~~ • ~- ~ E '~' IF Marathon Oil Company Well Name: KU 24-7 Sidetrack Location: Kenai, Alaska. Estimated Product Usage Summary PRODUCT Milling 9-5/8" Csg Production 8-1/2" Completion 7" liner ' Total Usage ~ % of Total Cost M-I Bar 0 164 0 164 1.97 Soda Ash 0 8 0 8 0.19 Caustic Soda 0 8 0 8 0.44 Conqor 404 1 3 0 3 8.07 Sodium Meta Bisulfate 6 8 3 17 1.78 Bicarb 0 16 0 16 0.45 Conqor 303 0 0 3 3 2.30 FloVis 48 66 0 114 35.91 SP-101 0 33 0 33 5.56 KCl 0 345 0 345 6.94 SafeCarb 0 492 0 492 15.01 Lubetex 0 7 0 7 8.22 EMI 920 0 7 0 7 10.27 Citric Acid 0 4 0 4 0.63 Defoam X 7 9 0 16 2.26 Engineer Service 1 5 1 7 - ~ IFE • Marathon Oil Company Well Name: KU 24-7 Sidetrack Location: Kenai, Alaska. Interv~.l Summery -Milling +/- 3777' Drilling Fluid System Milling Fluid Ivey Products F1oVis / Caustic Sada / Conqor 404 /Sodium Meta Bisulfate Solids Control Shale Shakers / Ditch Magnets Recommended shaker screens - 180/1$0/150 mesh Potential Problems "Birds Nests" /Hole Cleaning /Metal in pit system Interval Drilling Fluid Properties Depth Mud Plastic LSRV API Metal Interval Weight Viscosity 1 min Fluid Loss MBT content (ft) (ppg} (cp.) (cps) (ml/30min) (%) +/- 3777 8.5 +/- 8 - 12 40,000+ N/A N/A 0 - Use pill pit to mill out of 9-5/8" casing. Clean other pits for drill-in fluid. - Prior to setting whipstock, viscosify pill pit with 2.5 - 3.0 PPB F1oVis. - After setting whipstock, circulate out of pill pit, begin milling when viscosified fluid reaches mill. Continue to add F1oVis to retuns until high viscosity is achieved throughout entire system. - Monitor shakers and magnets for metal cuttings returns. - Consider pumping fibrous pill (Mix II) to aid in cleaning wellbore of metal cuttings. - If high torque is a problem add 0.5 % EMI 920 to the milling fluid. - Estimated volume usage for interval - 300 + barrels. / - ~.IFE :1 E • Marathon Oil Company Well Name: KU 24-7 Sidetrack Location: Kenai, Alaska. Interval Summary -- 8-1i2" hole 3777 - 4800' Drilling Fluid System Flo-Pro Fluid Key Products Flo-Vis / SP-101 / KCl /SafeCarb 10 ! 40 ! 2501 MIBar / Caustic Soda / Conqor 404 /Sodium Meta Bisulfate Solids Control Shale Shakers / Desilter /Ditch Magnets? Recommended shaker screens - 210 - 230 mesh Potential Problems Lost circulation / wellbore stability /gas kick /tight hole conditions Interval Drilling Fluid Properties Depth Mud Plastic LSRV API Drill Interval Weight Viscosity 1 min Fluid Loss MBT Solids (ft) (ppg) (cp.) (cps) (ml/30min) (%) 3777 - 4800' 9.0 - 9.2 10 - 14 40,000+ 7 - 9 < 7.5 +/- 5% - While milling 9-5/8" casing using the pill pit, build FloPro fluid the remaining surface pits using the enclosed formula. - Maintain as light a weight as hole conditions allow. Use desilter if necessary. - If high torque is a problem inside the 9-5/8 casing, use EMI 920 for torque reduction. - If high torque or sliding in the open hole becomes difficult, use Lubetex as an additive. - Beware of lost circulation in the A10 & A11 Sterling sands. Ensure an adequate SafeCarb blend is in the system before drilling these zones (begins at +/- 4400' M.D.). - Estimated additional volume for interval - 821 barrels. - Estimated haul off volume -1208 barrels. - Condition mud prior to running 7' liner. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. IFE ~; ~. ~-- ~~ IFE • . Marathon Oil Company Well Name: KU 24-7 Sidetrack Location: Kenai, Alaska. Fluid Formula- 8-1/Z" Interval 8-I12" Interval from 3777 - 4800' Input Descri ton KU 24-7 Sidetrack Mud Wei ht 9.0 - 9.2 Preh drated Gel No Wei ht Material Code MI BaR Preh drated GeI Conc. Wei ht Material SG 4.2 KCI Wt% 6 Out ut - 1 bbl Order of Products Concentration Volume Product Addition Field, Ib Lab, m Field, bbl Lab, ml Usa e 1 Water 325.19 325.19 0.929 325.19 2 Soda Ash 0.25 0.25 0.000 0.10 Reduce Hardness 3 FloVis Plus 2.00 2.00 0.005 1.34 Viscosit 4 SP - 101 2.00 2.00 0.004 1.33 Fluid Loss Control 5a SafeCarb 10 5.00 7.50 0.006 1.89 Brid in A ent 5b SafeCarb 40 20.00 30.00 0.226 7.56 Brid in A ent 5c SafeCarb 250 5.00 7.50 0.006 1.89 Brid in A ent 6 Potassium Chloride 20.76 20.76 0.025 8.68 Inhibition 7 CONQOR 404 2.00 2.00 0.004 1.43 Corrosion Control 8 Caustic Soda 0.50 0.50 0.001 0.23 H Control 9 Sodium Meta Bisulfate 0.50 0.25 0.001 0.25 Ox en Scaven er If hi h for ue inside cas in becomes a roblem add 0.5 0 1.0 °I° of the followin 10 EM1920 3.50 3.50 0.011 3.50 Lubricit If high torque or sliding roblems ersists add 0.5 0 1.0 % of the followin 11 Lubetex 3.50 3.50 0.011 3.50 Lubricit Mix fluid in the order listed above. LTotal I 380.1 I 380.1 I estimated Volume Usage l _821 Barrels I Calculated Mud Weiaht 9.050 ~~ ---~- ~ ~_.~ IFE • ~~ Marathon Oil Company Well Name: KU 24-7 Sidetrack Location: Kenai, Alaska. Interval Summary -Completion Procedures Corrosion Control Additive in Casing Well KU 24-7 Sidetrack Volumes: Drillstring 5.00 x 4.126 x 3400 ft 4.000 x 3.24 x 1330 ft \~ 9.625 x 8.681 @ 3477 ft MD 7.000 x 6.184 @ 3477 6.184 x 4.00 @ 4730 ft MD Treatment Procedures. Total Annular Volume 245.32 Drill string Volume 69.82 Total Hole Volume 315.14 1. After the 7" liner has been cleaned out, displace well to drill water. Once clean returns surface, pump an additional 315 barrels of drillwater. 2. Add 1 drum of Conqor 303A and 1 sack of Sodium Meta Bisulfatefor each 105 barrels of drill water pumped (3 drums & 3 sacks total) 3. After the 315 barrels of drill water with treatment have been pumped downhole, POH & L/D drillstring. This procedure will place corrosion control in the entire wellbore. 5" DP 56.25 barrels 4" DP 13.57 Annular Volume Csg x D.S. 170.17 barrels Liner x D,S. 75.16 T7 IFE ~ • • Marathon Oil Company _ .-,' ^•E Well Name: KU 24-7 Sidetrack Location: Kenai, Alaska. HSE Issues HANDLING OF DRILLING FLUID PRODUCTS HEALTH AND SAFETY 1. Drilling crews should be instructed in the proper procedures for handling fluid products. 2. Personal Protective Equipment (PPE) charts should be posted in the pit room, the mud lab, and the office of the Drilling Forman. 3. PPE must be in good working order and be utilized as recommended by the PPE charts. 4. Product additions should be made with the intent to use complete unit amounts of products (sacks, drums, cans) as much as possible in order to minimize inventory of partial units. 5. Insure all MSDS sheets are up to date and readily available for workers to access for information. ENVIRONMENTAL 1. Insure that all product stored outside is protected from the weather. 2. Do not store partial units (sacks, etc) outside if possible. 3. Properly secure all products for shipment between job sites. 4. When transferring fluid and or cuttings from the rig to trucks, insure all hoses are properly secured. 5. When utilizing the centrifuge solids van, insure all. hoses and connections between the van and the rig are secure. 'IFE .* ~9 • • w}'~~ Marathon Oil Company Well Name: KU 24-7 Sidetrack Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS Product Function Health Fla~rraabili PPE M-I BAR Weighting Agent `; *1 ~ E M-I GEL Viscosity control *1 E GELEX Bentonite Extender 1 ') E FLOVIS Viscosifier ~ ` - E DUAL-FLO Modified Starch ,. ~ E POLYPAC Fluid Loss Reducer *1 E HEC Loss Circulation Material 1 ~ E Safe-Garb F,M,C Bridging and weighting agent *~ r . ~~ ` ~= ~ E Nut Plug Loss Circulation Material *~ ~.~.~' ~~~ E M-I Seal F, M, C Loss circulation Material *~ E Mix II F,M,C Loss circulation Material *~( ' , ~ E DESCO CF Dispersant ~ ~ E SALT (Solar) Densifier ~ E POTASSIUM CHLORIDE Shale Inhibitor ~ °~ E CAUSTIC SODA Alkalinity control 3 " X BORAX Inorganic Borate '~ r 7 ~, E SAPP Sodium Pyrophosphate *~ _r~- '~ E SODA ASH Alkalinity control ~ s ~ ~ ' ~~~~; E SODIUM BICARBONATE Alkalinity control ~ - ~ ~~~~ ~ ~..~. ~~ E CITRIC ACID pH Adjuster ~ E BIOBAN BP-PLUS Biocide *2 "``;~ ,~ r~~r. =~ e x~_ ~~ ~ GREEN CIDE 25G - Biocide ~' Q ~ DEFOAM X - Defoamer ~ ~ - ~ G-SEAL Sized graphite LCM ~ ' E EMI 920 Lubricant ~ °~ 9,,,~! ~ ~ ,~, ' ~ LOBE TEX Lubricant D-D CWT Detergent 2 s` ~ Concor 404 Corrosion Inhibitor ~ ryr ~~ ~ SAFEKLEEN Drilling fluid additive ~ ~ Asphasol Supreme Shale Inhibitor ~ '(. ~ Sodium Meta Bisulfate Oxygen Scavenger ~ ~° ~ IFE ~- IFE • Marathon Oil Company Well Name: KU 24-7 Sidetrack Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS HAZARDOUS MATERIALS IDENTIFICATION SYSTEM (HMIS) HAZARD RATINGS 4 -Severe hazard 3 -Serious hazard 2 -Moderate hazard 1 -Slight hazard 0 -Minimal hazard * An asterisk next to the health rating indicates that a chronic hazard is associated with the material. HMIS PERSONAL PROTECTIVE EQUIPMENT INDEX A -Safety Glasses B -Safety Glasses, Gloves C -Safety Glasses, Gloves, Synthetic Apron D -Face Shield, Gloves, Synthetic Apron E -Safety Glasses, Gloves, Dust Respirator F -Safety Glasses, Gloves, Synthetic Apron, Dust Respirator G -Safety Glasses, Gloves, Vapor Respirator H -Splash Goggles, Gloves, Synthetic Apron, Vapor Respirator I -Safety Glasses, Gloves, Dust and Vapor Respirator J -Splash Goggles, Gloves, Synthetic Apron, Dust and Vapor Respirator K -Air Line Hood or Mask, Gloves, Full Suit, Boots X -Consult your supervisor for special handling directions r:_~~ ~ • ±' FE Marathon Oil Company Well Name: KU 24-7 Sidetrack Location: Kenai, Alaska. Contacts Contact Title a-mail WOrk Cellular Pete Berga Drilling pkberga@marathonoil.com 907 565-3032 907 231-0663 Marathon Superintendent Will Tank Drilling Engineer wjtank@marathonoil.com 713 296-3273 713 203-8398 Marathon Tony Tykalsky Project Engineer ttykalsky@miswaco.com 907 274-5011 907 227-2412 MI SWACO Gus Wik Warehouse Manager gwik@miswaco.com 907 776-8722 907 776-8680 MI SWACO Michael Barry Senior Field gratefulmen@hotmail.com 907 260-4666 907 590-3636 MI SWACO Engineer (home) Locke Rooney Field Engineer rooneyl@alaska.net 907 235-0598 907 590-3636 MI SWACO (home) Roland Lawson / Drilling Foremen 907 283-1312 Larry Myers /Dave Morris Marathon Responsibilities - MI Project Engineer and will coordinate daily between the Marathon office, rig, warehouse, and the M-I field engineers. - Well progress will be monitored to look for any changes, which will improve the efficiency of the operation or avert trouble. - .Field Engineers will monitor and supervise product inventory to include re-palletizing any products for shipment to other locations at the end of the well. - Field Engineers will communicate with office personnel (Marathon & MI SWACO) for approval of any changes in the mud program (including introduction of new products). - Field Engineers will produce a recap at the end of the well based on daily activities. Recap should include any lessons learned that may be used to provide better service on future wells. Lessons learned can include changes in procedures, product additions, equipment usage, and/or utilization of any third party service. ~, ~ ~- : IFE v Marathon Oil Well KU 24-7RD BOP Stack 13 5/8" 5M Cross ~: ~ Marathon Oil Well KU 24-7RD Choke Manifold From BOP Stack • To Gas Buster To Blooey Line Bleed off Line to Shakers GLACIER DRILLING RIG #1 MUD PITS AND PUMP ROOM LAYOUT • b • • Surface Use Plan for Kenai Beluga Unit, well KU 24-7RD Surface location: Anticipated at 604' FNL, 796' FEL, Sec. 18, T4N, R11 W, S.M. ~ 1) Existing Roads Existing roads which will be used for access to KU 24-7RD are shown on the attached map. Kenai, Alaska is the nearest town to the site. 2) Access Roads to be Constructed or Reconstructed No new roads will be required to access KU 24-7RD. 3) Location of existing wells Well KBU 24-7RD will be drilled on Kenai Gas Field (KGF) pad 41-18. A pad drawing is enclosed that shows existing wells and the location of KU 24-7RD. 4) Location of existing andlor proposed facilities The locations of existing production facilities in the KGF pad 41-18 are shown on the enclosed pad drawing. 5) Location of Water Supply A water supply well exists on the pad that KU 24-7RD will be drilled from. This is shown on the pad drawing. 6) Construction Materials No construction is planned on the pad. 7) Methods of handling waste disposal; a) Mud and Cuttings Cuttings will be dewatered on location. The cuttings and excess mud will be disposed of into Well KU 11-17, a Class II disposal well (AOGCC Disposal Injection Order No.9, Permit #81-176) on pad 41-18. ' b) Garbage All household and approved industrial garbage will be hauled to the Kenai Peninsula Borough Soldotna Landfill. c) .Completion Fluids Clear fluids will be hauled to Pad 34-31 of the Kenai Gas field and injected in Well WD #1, ~ an approved disposal well (AOGCC Permit #7-194). d) Chemicals Unused chemicals will be returned to the vendors that provided them. Efforts will be made to minimize the use of all chemicals. e) Sewage Sewage will be hauled to the Kenai sanitation facility. 8) Ancillary Facilities • A minimal camp will be established on the pad to house various supervisory and service company personnel. Approximately four trailer house type structures will be required for this purpose. Bottled water will be used for human consumption. Potable water will be obtained from the existing water well on the pad. S & R will collect and transport sanitary wastes to their ADC approved disposal facility. No additional structures will be necessary. 9) Plans for reclamation of the surface KU 24-7RD will be drilled from an existing pad. Reclamation of the pad will occur after the abandonment of KU 24-7RD and the other existing wells on the pad. Approval of the plan of reclamation will be obtained from CIRI Native Corporation prior to any reclamation work beginning. 10) Surface ownership The surface owner of the land in the Kenai Beluga Unit is the CIRI Native Corporation. 11) Operator's Representative and Certification I hereby certify that I, or persons under my direct supervision, have inspected the proposed drill site and access route; that l am familiar with the conditions that currently exist; that the statements made in this plan are, to the best of my knowledge, true and correct; and that the work associated with operations proposed herein will be performed by Marathon Oil Company and its contractors and subcontractors in conformity with this plan and the terms and conditions under which it is approved. This statement is subject to the provisions of 18 U.S.C. 1001 for the filing of a false statement. Date: ~ ~- Z 2 - ~ ~ Name and Title: ~~ eter K. Berga Drilling Superintendent Marathon Oil Company P.O. Box 196168 Anchorage, Alaska 99519-6168 (907)565-3032 N.25 - ~ ~ 5 BGIT13' F r 2941.51' G L 0 %.276897.82 Y.2,J56,607.88 1/s tse w~Y ~c,P 1937 o 1 3 9 d n ~1 ~ o N P ~ ~ i ~ ~~ ~. m > AOQ55 ROAD a NaLNDm 2•-J' ~' ABOYE PAD PIFYATION NFBRE rt S Ex1ors PAD X=27192J.f9 Y=1,Yi,09ae8 3 7/4' 9 MOMIMENi~ ,I~. i~ i 1 ~~y''~ -' .x-"jxt 1 L Pe~E rEraE '. BUKDING CONTAWNO RkK TANKS 0-J K.u. 33-7 14d Y.=27a,07B.19 '01 • 1 `h2,368,057,11 °• ~--- NONIIOR NEIL'A' K=z769b.D Y.7,3~,841.7 TOP 8' RPE EL.BB.,f TOP Y RPC EL=86A PAD LINTS ,, r K.u, z4-7 1/11 MF1L2~7~ } a 1 Y-2.J56,013.69 'HATER MF11 'o 1 ~U I M-Z7695&3 Y=23 6' 99a0 1 ' . , I i` ~ 1 EIECO EIECIRICAL SNITCIt BO% PANEL W/ 25'1(25' WAIe] RPE // ~~ t'~~/ 1 1 ~ i ~ ~ 1 ~ esKlao' i TANN A9F1 i v~ 1 i 1 t J 1 111 1 J PWE 1 WARD L' lA' • RAwtg Jed ~'y -~ K.U. 11-17 ~rTUSN w/ aN1a TANf B a, mJECnON K~275N~7A WASIEITAIFA rA1K A o, y~y Y-2,355,971.11 ~'" W,d TOP OAKMIAL %, ~i \ I ..~- i ~~ ~ ClDSEO RESEAYE RT i i ' II i III I K.U. 41-18 M°` raLAR ~NTA~ e' 11.0' MElI HWSE + • SW COR. E4+87.80' BLDG µ K-2TS,ns.e7 a I III w • Y-2,5,88200 % , 4 K.B.U. 13-8 12.d ~ 5.138.84 ~ 9~ ~Y 2,159,978.85 1EC0 w • 80101rK1 4 e, ~~ t T ~ O tHg 1 /' 11 ~~ 71 e~ o~PERAnai 11 I AREA 1 1 ~ 1 1 I I _ L~ ',i ~~ >% I ~~ TANK fi I K ~ ~ PAD UKIS i t2o' 'il~ '~ 8 w x term 5 BIDG et~E aaa t197! tmum xuTEa 6076. 9 j Y=2,359,200 Y=2.358,000 Y-2359,800 1 ~ I IIII MW 'C' I B Y.2,355,75a7 TOP e' ctSNC t1..9zAY LOP Y RPE LL•07.37 ~ >< ~1 6 ~~ MONRp8N0 NEIL ~ rrzrs,maz ' ' 31 32 33 34 i. ::.:,.R,~ ~ KENAI GLO r~IV Rttw ~ T4N 3 ss sTSS~7 '.':.' . 1 z ~ F1~D 6 tBJ7 .;W.. ~. 5 4 J , Z Y .Y:.' ~: p:::: 12 7 B 9 0:::: U:::: N .~ 3 78 ~ 17 i6 Lacetbn H-18 sDUt ,• . 1 twe VICINITY MAP GLO ument found ihia survey. 0 Rephced 1/2' mbar oa noted Found survey monument as deser6ed -0 Power Pole # Light Pde s Ezlethg wetl ohrietmas tree ' ~ Monitor Weil pd Ydve -0 Piping underground ~ Electricol switch boz 0 SCpf1C Vent AB O.H.E. BRENA710NS DVERHEAD ELECTRIC 0.H. P/W DVERHEAD PIPE WAY E.M. ELECTRIC METER •~~~ pF ~t~~l lH~~' ~tt ~~,:.IL~9COR / `~ '~~ ,ff i~k{l\\~, ,~ NOTES 1) Elsvatione of the top of pipe for monitoring wells were taken with cover 011 ar open. 2) Reference datum le mean sea laud= 0.D0' far devatbne shown 3) All bearings are grid unlen noted aihawiee 4j Baefa of Coordinotes is U.S.C. 6 G.S Tr( Stotion AUDRY in A.SP. Zone 4. Average convergence ai points shown: -01'04'58' 5) T.B.M. dev: 67.90' SW comer tap rdl tdlar KU 11-17 8j AUDRY lotatlon: Lat.: 8030'S0.559'N lang.; 151'i6'37.445'W x-269,888,75 Y=2,382,045.42 McLANE caNSUlnec DRW1P SOIDOINA, AUSNA 2 AWED TER 8flel UPDATED NEUS UNri AND RT (1D7) 285-4218 1 3 AOOEO NEROUID TANG, BIRDNOS, GATE ANO MOOIEFD SUR'rE,' CONTROL MTE OF 91MY:11 9 KMW N0.: _ ~° °~°° ~ Marathon WANNiG Na: 95PD4118 r.>d ~AMON 0 i t Company ANNJco R.gim WANK BY: PDD • °10N~'~10YK KENAI GAS FIELD PAD AS-BUILT SURVEY ~~ 8Y OAIE ~~ KENAI. GAS FIELD PAD 41-18 ~~' NSTAUN. F1E N0. MOD 31ST DNC Na N REV 1RCft 1' tl-18 5 0 W 0 W OOm I 0 i SIONIwA1kA BEAM (TYP.) c~ cc, • ~ ~~-~r~ Subject: KU 24-7 From: "Berga, Pete" <pkberga@marathonail.com> Date: Wed, 2.2 Jun 2005 11:05:59 -08C)0 To: Winton_aubert@admin.state.ak.us. Stan_Porhola(c~ak=a~im.gov I sent the Sundry Notices for the Abandonment of KU 24-7 and the Applications for Permits to Drill the sidetrack. They should be there by now. The rig has ended it's fishing operations and as soon as I get the approval I will do the abandonment. I hope you can both turn the dirlling permits out in a couple of days. You will notice that the drilling permit surface location is different from the past permits or sundrys. With more accurate surveying. instruments now I sure you have seen this before. My question is do you want to see this change or do you want to stick with the old surface location even if you know it's wrong? If either of you have questions on the permits please call me. 565-3032. Please let me know when we can proceed with the abandonment. ~`~tr-a~.i s'E u„-.. KU 24-7RD Redrilled Disposal Sterling Pool 2050990 Disposal wellbores shown as blue Confidential wells shown as red ~ Area of Review ~..~.._~ f ._.._..~ f ~ ~ .... I I K U 24-7R -5-, h; I) ~ 4~ti~ D~ 11 -17 SFD ~...~ I i i r..~..~ I T4N, R11W, S.M. I 1 Feei 0 1 ,000 2,000 3,000 4,004 Check No Check Date Bank Bank No v Marathon Oil Company Direct Inquiries to: ACCOUNTS PAYABLE DEPARTMENT Hndl g P. O. Box 22164 Accts Payable Contact Center 1179716 06/21/2005 NCBAS 7780 5001123 Tulsa, OK 74121-2t 64 phone: 918-925-6D97 Al Invoice Number 'Invoice Date Dtrcur+aeM (Ja Remit,COmmen, Z;iossRmount Dl$cpunE In~oiee/Pey Amount L 100.00 06/21 /2005 1900031757 100.00 100.0 TDTAL: 100.00 100.0 (FOLD ON PERFORATION BELOW AND DETACH CHECK STUB BEFORE DEPOSITING) DDi: d D ® ® D' ® 0 ~ ®° 'ORM 250, REV 5/00 _..__ w _~_~ _ _ _ ~. _ _..- -~... - ---- - 7780 Marathon Oil Company 56-3894,2 ACCOUNTS PAYABLE CHECK __ P O 60X.22164 CHECK DATE ci1E CK NUMBER - ~ Tulsa, OK 74121-2164 06/21/20nS 1179710 PAY TO THE ORDER CF COMMISSION 333 WEST 7TH AVE STE 100 ANCHORAGE, AK 99501 NATIONAL CITY BANK Ashland, Ohio VOID A~TFR'_°0 DAYS (..~'. T ands ,1 „ , , ^rA~ CH a,MOUNT IN WORDS WITHNUMBERS•. 3 a v ~ _.t, .~so-1~~'~ 191:~~®9'.~Ii`~~iri;.d~a`am ~~x'~1~~~'~~Iei®®6~ders~~~Te:i ~~~a1-1 ~7, : ® J: ' ®~ _ - '~itii[~i:i®J° ~ ~ . ~, II^000 L ~ 79? L611' x:04 L 203895: 0 i83~,84~i' • • TRANSMITAL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME ~~~ ~~~ ~~~~ CHECK WHAT ADD-ONS "CLUE" APPLIES (OPTIONS) MULTI The permit is for a new wellbore segment of LATERAL existing well , Permit No, API No. (If API number Production should continue to be reported as last two (2) digits a function of the original API number stated are between 60-69) above. PILOT HOLE In accordance with 20 AAC 25.005(f), all (p)~ records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 - 70I80) from records, data and logs acquired for well (name on permit). SPACING The permit is approved subject to full EXCEPTION compliance with 20 AAC 25.055. Approval to perforate and produce/infect is contingent upon issuance of a conservation order approving a spacing exception. (Comnanv Name) assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the SAMPLE Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Rev: 04/01/05 C\jody\transmittal_checklist WELL PERMIT CHECKLIST Fiekl & Pool KENAI, UNDEFINED WDSP G&I -448036 Well Name: KENAI UNIT 24-7RD Program SER Well bore seg ^ PTD#:2050990 Company MARATHON OIL CO Initial ClasslType SER / PEND GeoArea 820 Unit 51120 On/Off Shore On Annular Disposal Administration 1 Permit_fee aitached_ _ _ . - _ - . _ _ . _ _ - - Yes Sidetrack of existing G&I disposal well t_o re-estab_lish_Sterling_Fm. completion & restore disposal operations._ 2 Lease number appropriate____________________________ ___ ______,Yes_ . _ ____TDof24-7Rpwillbe_about325'EofcurrentT_D_ofwell._-___-_- -_._- - - 3 Unique well-name andnumbe[ -- -- -- -- - -- - Yes. ------ - - - - - - --------- ---- ---------- -- --- - -- - 4 Well IQCated in a-defned_pooi_ - - - Yes - _ . - _ _KENAI,UNDEFINED WDSP G&1-4480~6_goyerned_b Dis oral I_n'ection Order No..11._ - _ - _ - y p 1 5 Well located proper distance from drilling unit_boundary_ - _ Yes - _ - - _ Completion lies within Kenal Unit boundaries, _ _ _ - - _ . 6 Well located proper distance.from other wells- - - - - - - - - -- - - _ - -Yes - - - -Nearest well-is KBU 33-7:- closestapproach is X1,350 feet to NE, with_ TD of KBU_3.3,7_about 2,000' to NNE.. _ - 7 Sufficient acreageavail_ablein_drillingunit_-______ __________ _____-_..- Yes_ -_-_.____-_- -____ 8 If deviated,is_wellboreplat_included-_.___,___ __-_-_._Yes_ ___,-_-_____, 9 Operator only affected party_ - - - Yes - - - DI0,11 notes that CIRI and Salamantof Village are surface owners within_114 mile,of Kt124-7, & they - . - _ - 10 Operatorhas-appropriate. bond infprce_____________________ ____________Yes- -._.,-werenotifiedduringinitial1996-ordetprocedu[e,.-._,-.---___-.__-,,.__-__--_-.-.--.-.- 11 Permit_canbeissuedwithoutconserva_tionprder_______________ ____________Yes_ ___.___-__-_.-_-.._ - - - - Appr Date 12 Permit_canbeissuedwithoutadministrativ__e.appr_oval_____________ ____________Yes_ ___-___._-___,._.__,-.-._, SFD 6122/2005 13 Can permit be approved before 15-day wait Yes 14 Well located within area and_strata authprized by_ Injection Order # (put1O# in_comments)_(FQr_ Yes _ , _ DI_Q 1.1_ - . - - _ _ - _ - - - - - - - - - - - - - - _ _ _ - - _ _ , - - - - _ 15 Alf wells-within 1/4-mile area-of review identified (For service well only)- - - - - - - - - - - - - -Yes - . - , - , -None, DNR Water Righfs-GIS Sygtem shows nearest registered well to be X3,700' to the NNW-in _ . - - - - - - - - 16 Pre-produced injector; duration-of pre production Less than 3 months.(For service well only) _ NA_ - Sec. 12, T4N, R12W, S.M. _ - . .. - 17 ACMP_Finding of Consistency-has been issued. for this pro)ect. - - _ NA_ , _ _ . _ -Sidetrack well_ . _ , . Engineering 18 Conductor string,provided__________________- --.__ -_--_.--_-_ NA-_ ,_-_-_-_-_-_-_-.-_---_ 19 Surface casing-protectsall_knownU$DW&___________ _____ -__._.-.__-- NA_ ____ 20 CMT-voladequate.tocircul_ate.oncond_uctor&surf_csg__________ ____ ___-_, NA_- .-_-_-___.____-_____._ - - 21 CMT_voladeguatetotie-in long string tosurfcs9_-_-_-__.___._ ______ __-. NA_ ________________________________-__ -- - ------- 22 ,C_MT_willcoyerallkno_wnpro_ductivehorizon_s-__-___-_-_-_ _ ___-__-__--Yes_ __________________________ - - - - - - ------------ 23 Casing designs adequate f_or C, T, B &- permafrost- - - - - - Yes - - - - - 24 Adequatetankage,orreseryepit__._, -_-_______________ ____________Yes- ___GlacierRig#1.-_-_-_-_-.--- --__- 25 If_a-re-drill, has_a 10-4.03 for abandonment been approved . - . - _ _ - - - _ Yes _ - _ - _ - _' _ - _ _ , _ _ - _ _ _ - _ . - - _ _ - _ - _ _ 26 Adequatewellboreseparation_proposed--------------------- ------------Yes- ._---- 27 If_diverterrequired,doesitmeet.regulations__________________ ___.___-,._, NA._ ___._Sidetrack.-_-_-_-__,__- -_-_- - - - - - Appr Date 28 Drilling fluid-prQgramschematic-&equiplistadequate_.______ ,_-____ YeS- -___-_MaxMW 9,2ppg,___._._.______________________________,-___-_---_ WGA 6123120051 29 BOPEs,dotheymeetregulation_,----_ - -- Yes- ------------------------------------------------------------- ----- 1 30 _B_OPE_press rating appropriate; test to_(put psig in comments)- _ _ _ _ _ _ _ _ _ - _ _ _ Yes _ _ _ _ Test to 3000_ psi. -MSP 610,psi- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ . _ 1 31 Choke-manifold complies w/API,RP-53(May84)________________ ._-_._____Yes, __-___ - - ------------------------ 32 Work will occur. without operation shutdown___-__„__-__-_,_ .-_--__.--_Yes_ -__-_-__--.-_-__-__,_-_.______-.--___--_------------------- 33 Is presence.of N2S gas probable. - - - - N0- - - - - - - - - - 34~ MechanicalconditionofwellswithinAORuerified(Forservicewellon_ly)- ------------Yes_ ___-_-No wells within AOR,___,.-.-________----_-_.___--_--------______-__-._ Geology 135 Permit_canbeissuedwlohydrogen_sulfidemeasures___.,_, ___-____Yes_ _-____. __.-__.___ ____-__-_-__.____-.__-___------------ -_._- 36 Data-presented on-potential overpressure zones _ - - - - - - - - - - - - - - - - Yes Reservoir ina depleted gas.reservoir._ Pressure expected to be_ 5.0 ppg; will be drilled with-9.0 -9.2_ppg mud . , - Appr Date 37 Seismicanalysis_ofshallowgas.zones-_,___„__-__-____ ____,- - _-_ NA__ ____-_,_ - - - SFD 6/2212005 ~38 Seabed condition survey-(if off_-shore) . - - _ - , . - - N_A- - - - - - _ . . 39 Contack name/phone_for weekly pr9gress_reports [exploratory only)- _ NA_ - - Geologic Engineering Publi Commissioner: Date: Commissioner: Date Comm r Date • v
