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Home My WebLink About214-1731. 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: Pull SSSV, Rerun Cap String 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 data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 6,733 feet 4,750'feet true vertical 3,503 feet 6,570' (fish) feet Effective Depth measured 4,750 feet N/A feet true vertical 2,163 feet N/A feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Cap String 3/8" 3,600' MD 1,780' TVD Tubing (size, grade, measured and true vertical depth)3-1/2" 9.2 / L-80 6,481 MD 3,293 TVD Packers and SSSV (type, measured and true vertical depth)N/A N/A 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: Scott Warner, Operations Engineer N/A Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 485 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 scott.warner@hilcorp.com 907-564-4506 measured true vertical Packer 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 0 Size 80' 1 0879 0 788 92 measured TVD 5-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 214-173 50-133-20647-00-00 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: ADL0384372 / FEE-PRIVATE Ninilchik / Beluga-Tyonek Gas NINU Paxton 09 Plugs Junk measured Length Production Liner 6,723' Casing Structural 3,495'6,723' 80'Conductor Surface Intermediate 16" 9-5/8" 80' 2,291' 7,480psi 5,750psi 10,640psi 2,291' 1,401' Burst Collapse 3,090psi p k ft t Fra O s O 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 8:24 am, Jul 15, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.07.14 17:20:29 - 08'00' Noel Nocas (4361) BJM 9/25/25 Page 1/1 Well Name: NINU Paxton 09 Report Printed: 7/2/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50133206470000 Field Name:Ninilchik State/Province:ALASKA Permit to Drill (PTD) #:214173 Sundry #: Rig Name/No: Jobs Actual Start Date:12/20/2024 End Date: Report Number 2 Report Start Date 5/29/2025 Report End Date 5/29/2025 Last 24hr Summary PTW, JSA. MIRU cap string truck. Load spool. Install cap string into injector head. Move to well. Remove hanger assembly. Scope down . Open static pack offs and Pull on string. 1400 lbs up weight. Pull cap string OOH. 3710' tagged up at surface. Close swab 23 turns. Pop off well. Foot vavle recovered. RIg down pack off and spool and spot next to well. RDMO cap string truck. Report Number 3 Report Start Date 5/31/2025 Report End Date 5/31/2025 Last 24hr Summary Bail fill from 4591' to 4594'kb Report Number 4 Report Start Date 6/1/2025 Report End Date 6/1/2025 Last 24hr Summary Bail fill from 4585' to 4588'kb Report Number 5 Report Start Date 6/11/2025 Report End Date 6/11/2025 Last 24hr Summary PTW/PJSM. MIRU Pollard Slickline. PT lubricator to 250 psi low - 2500 psi high, good test. Shut in well. RIH w/ brush and clean SSSV profile @ 166' RKB. RIH w/ SLB 3SV SSSV on 3 1/2" C-setting tool and 7' prong to 120'. Purge control line and set SSSV in nipple @ 166'. Good set. RIH w/ 3 1/2" A-stop and set @ 162'. POOH and test SSSV- good test (function and pressure). Secure well, hand over well to production, and RDMO Pollard. Report Number 6 Report Start Date 6/18/2025 Report End Date 6/18/2025 Last 24hr Summary PT 500 psi low/2500 psi high- good. Pull A- Stop from Top of SSSV @147'SLM (163'KB) - Pull SSSV @150'SLM (166'KB) - Drift and Tag with 2.5"DD Bailer tagging @ 4742'SLM (4758'KB) - Rig down - Depart facility PTW, JSA. MIRU capillary tubing truck. Install 3/8" spool into craddle. Stab pipe into injector head. Install pack off assembly dressed for 3/8" tubing. MU foot valve opening pressure 1800 psi. Pressure test pack off assembly 250/3500 psi. RIH with cap string 400 lbs. PU clean at 3650'. Stop at 3600' and install hanger. Close manual lock down screws and apply 3000 psi to dynamic pack off and isolate. RDMO cap string truck. Updated by DMA 06-24-25 SCHEMATIC Ninilchik Unit Well: Paxton #9 PTD: 214-173 API: 50-133-20647-00-00 PBTD = 6,458 MD /3,273 TVD TD = 6,733 MD / 3,503 TVD RKB = 18.7 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16Conductor 109 / X-56 / Weld Surf 80 9-5/8'Surface 40 /L-80 / BTC 8.835Surf 2,291 5-1/2"Production 17 / P-110 / CDC 4.892Surf 6,723' TUBING DETAIL 3-1/2Tubing / Scab Liner 9.2# / L-80 / Supermax 2.992 Surf 6,481 3/8Capillary String Surface 3,600 06/18/25 9-5/8 cement Job: 12-1/4 hole. 137 bbls of 12.5 Type I lead and 65bbls 15.2# tail. 100% returns with cement to surface 5-1/2 cement job: 8-1/2 hole. 145 bbls of 13.5# class G lead, and 93 bbls of 15.7# class G tail. Full returns throughout job. Volumetric ToC at ~1450 MD assuming 10% openhole washout. 40 bbls spacer pumped, and 40 bbls back to surface (no cement seen) 3-1/2 Cement Job: 42bbls of 12ppg lead and 18bbls 15.3 tail. No losses throughout job (had losses pre-job). Good lift pressure, but cement must have fallen back after job. (had losses pre-job). . 2/18/21 Radial CBL:Solid cement up to ~4210 MD (base BEL_47C squeeze perfs). Patchy cement up to 1850 MD, free pipe at 890 MD. Post-squeeze CBL run on 4/7/21 shows new ToC at ~820MD 1 16 9-5/8 8-1/2 Hole 5.5 No. MD TVD ID Item 1 4,7502,163CIBP 11/10/22 2 6,570 3,367 Fish: Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) from 1/15/15. Tagged at 6586 CTMD 7/25/20 2 1450 ToC (volumetric) PERFORATION DETAILS Sands Top MD Btm MD Top TVD Btm TVD Ft Date Status Punches 2,401'2,405'1,434'1,436'4'3/19/2021 Squeezed (3/31/21) BEL_41U 3,645'3,676'1,792'1,80131'9/22/2021 Open BEL 41L 3,677 3,702 1,8011,808'259/22/2021 Open BEL_43 3,765'3,773'1,825'1,828'8'9/21/2021 Open BEL_44 3,832'3,857'1,845'1,852'25'9/21/2021 Open BEL_45 3,872'3,881'1,857'1,859'9'9/21/2021 Open BEL_45 3,928'3,936'1,873'1,875'8'9/22/2021 Open BEL_45 3,947'3,956'1,878'1,881'9'9/22/2021 Open BEL_46U 3,979'3,989'1,887'1,890'10'9/21/2021 Open BEL_47A 4,070'4,082'1,914'1,917'12'7/28/2020 Squeezed (2/15/21) BEL_47A 4,082'4,096'1,917'1,921'14'7/28/2020 Squeezed (2/15/21) BEL_47C 4,179'4,194'1,946'1,950'15'7/27/2020 Squeezed (2/15/21) BEL_47C 4,194' 4,209' 1,950' 1,955' 15' 7/26/2020 Squeezed (2/15/21) BEL_49U 4,362' 4,372' 2,005' 2,008' 10' 9/21/2021 Open BEL_49L 4,428' 4,451' 2,029' 2,038' 23' 9/20/2021 Open BEL_50 4,518' 4,543' 2,065' 2,076' 25' 9/20/2021 Open BEL_51 4,577' 4,582' 2,090' 2,092' 5' 9/20/2021 Open BEL_52U 4,642' 4,650' 2,117' 2,121' 8' 9/20/2021 Open BEL_52U 4,657' 4,679' 2,124' 2,133' 22' 9/19/2021 Open BEL_52L 4,707' 4,725' 2,145' 2,153' 18' 4/24/2021 Open Bel 53 4,790' 4,802'2,181 2,18612' 1/13/2015 Squeezed (2/15/21) Bel 53 4,802' 4,822'2,186 2,19520' 4/20/2015 Squeezed (2/15/21) Bel 53 4,819' 4,839'2,194 2,20220' 1/11/2020 Squeezed (2/15/21) Bel 53 4,839' 4,859'2,202 2,21120' 1/10/2020 Squeezed (2/15/21) Bel 53 4,863' 4,883'2,213 2,22220' 1/10/2020 Squeezed (2/15/21) Bel 53 4,883' 4,903'2,222 2,23120' 1/9/2020 Squeezed (2/15/21) BEL_56 5,083' 5,096' 2,316' 2,322' 13' 4/24/2021 Isolated BEL_58U 5,151' 5,161' 2,351' 2,356' 10' 9/19/2021 Isolated BEL_58L 5,166' 5,176' 2,359' 2,364' 10' 9/19/2021 Isolated BEL_58A 5,215' 5,242' 2,384' 2,399' 27' 4/24/2021 Isolated BEL_60 5,394' 5,414' 2,487' 2,499' 20' 4/23/2021 Isolated BEL_74U 5,673' 5,678' 2,665' 2,668' 5' 4/23/2021 Isolated BEL_74L 5,685' 5,691' 2,673' 2,677' 6' 4/10/2021 Isolated BEL_82L 5,840' 5,846' 2,783' 2,787' 6' 4/10/2021 Isolated BEL_83 5,870' 5,882' 2,805' 2,813' 12' 4/10/2021 Isolated 1 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: Install Cap String 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 data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 6,733 feet N/A feet true vertical 3,503 feet 6,570 feet Effective Depth measured 6,458 feet N/A feet true vertical 3,273 feet N/A feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.2 / L-80 6,481 MD 3,293 TVD 166 MD Packers and SSSV (type, measured and true vertical depth)N/A SLB WRDP WLSSSV 166 TVD 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: 7,480psi 5,750psi 10,640psi 2,291'1,401' Burst Collapse 3,090psi Production Liner 6,723' Casing Structural 3,495'6,723' 80'Conductor Surface Intermediate 16" 9-5/8" 80' 2,291' measured TVD 5-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 214-173 50-133-20647-00-00 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: ADL0384372 / FEE-PRIVATE Ninilchik / Beluga-Tyonek Gas NINU Paxton 09 Plugs Junk measured Length measured true vertical Packer 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 0 Size 80' 0 03034 0 1260 1179 Scott Warner, Operations Engineer 324-701 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 463 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 scott.warner@hilcorp.com 907-564-4506 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 1:14 pm, Jan 24, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.01.24 13:05:12 - 09'00' Noel Nocas (4361) A.Dewhurst 13FEB25 BJM 2/10/25 DSR-1/31/25 RBDMS JSB 012925 Page 1/1 Well Name: NINU Paxton 09 Report Printed: 1/15/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:12/20/2024 End Date: Report Number 1 Report Start Date 12/27/2024 Report End Date 12/28/2024 Last 24hr Summary MIRU capillary tubing truck. Load new spool of 3/8" capillary tubing into spooler. Stab 3/8" SS cap string into injector head and pack off assembly. Makue up new footvalve. 3/4" OD. Stab on well. Fluid pack wellhead connection above swab valve. Pressure test pack off assembly 250/3500 psi. Open swab valve RIH. Pick up in tension 800 lbs and set cap string at 3700'. Lock down pack off assebmly and install 3/8" cap string hanger. Remove injector head from tree. Set wooden spool next to wellhead. Ready for ops to hook up soap skid. RDMO. Field: Ninilchik Sundry #: 324-701 State: ALASKA Rig/Service:Permit to Drill (PTD) #:214173Permit to Drill (PTD) #:214173 Wellbore API/UWI:50133206470000 Updated by DMA 01-21-25 SCHEMATIC Ninilchik Unit Well: Paxton #9 PTD: 214-173 API: 50-133-20647-00-00 PBTD = 6,458 MD /3,273’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16”Conductor 109 / X-56 / Weld Surf 80’ 9-5/8'Surface 40 /L-80 / BTC 8.835”Surf 2,291’ 5-1/2"Production 17 / P-110 / CDC 4.892”Surf 6,723' TUBING DETAIL 3-1/2”Tubing / Scab Liner 9.2# / L-80 / Supermax 2.992” Surf 6,481’ 3/8”Capillary 0.049 duplex 2205 Surface 3,700’ 12/27/24 9-5/8” cement Job: 12-1/4” hole. 137 bbls of 12.5 Type I lead and 65bbls 15.2# tail. 100% returns with cement to surface 5-1/2” cement job: 8-1/2” hole. 145 bbls of 13.5# class G lead, and 93 bbls of 15.7# class G tail. Full returns throughout job. Volumetric ToC at ~1450’ MD assuming 10% openhole washout. 40 bbls spacer pumped, and 40 bbls back to surface (no cement seen) 3-1/2” Cement Job: 42bbls of 12ppg lead and 18bbls 15.3 tail. No losses throughout job (had losses pre-job). Good lift pressure, but cement must have fallen back after job. (had losses pre-job). . 2/18/21 Radial CBL:Solid cement up to ~4210’ MD (base BEL_47C squeeze perfs). Patchy cement up to 1850’ MD, free pipe at 890’ MD. Post-squeeze CBL run on 4/7/21 shows new ToC at ~820’MD 1 16” 9-5/8” 8-1/2” Hole 5.5” No.MD TVD ID Item 1 166’166’2.812”SSSV hydraulic nipple (SLB BP-6i)- SSSV removed for cap string 2 4,750’2,163’CIBP 11/10/22 3 6,570’3,367’Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) from 1/15/15. Tagged at 6586’ CTMD 7/25/20 3 1450’ ToC (volumetric) Perforation Data Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)Ft Date Status Punches 2,401'2,405'1,434'1,436'4'3/19/2021 Squeezed (3/31/21) BEL_41U 3,645'3,676'1,792'1,801’31'9/22/2021 Open BEL 41L 3,677 3,702 1,801’1,808'25’9/22/2021 Open BEL_43 3,765'3,773'1,825'1,828'8'9/21/2021 Open BEL_44 3,832'3,857'1,845'1,852'25'9/21/2021 Open BEL_45 3,872'3,881'1,857'1,859'9'9/21/2021 Open BEL_45 3,928'3,936'1,873'1,875'8'9/22/2021 Open BEL_45 3,947'3,956'1,878'1,881'9'9/22/2021 Open BEL_46U 3,979'3,989'1,887'1,890'10'9/21/2021 Open BEL_47A 4,070'4,082'1,914'1,917'12'7/28/2020 Squeezed (2/15/21) BEL_47A 4,082'4,096'1,917'1,921'14'7/28/2020 Squeezed (2/15/21) BEL_47C 4,179'4,194'1,946'1,950'15'7/27/2020 Squeezed (2/15/21) BEL_47C 4,194'4,209'1,950'1,955'15'7/26/2020 Squeezed (2/15/21) BEL_49U 4,362'4,372'2,005'2,008'10'9/21/2021 Open BEL_49L 4,428'4,451'2,029'2,038'23'9/20/2021 Open BEL_50 4,518'4,543'2,065'2,076'25'9/20/2021 Open BEL_51 4,577'4,582'2,090'2,092'5'9/20/2021 Open BEL_52U 4,642'4,650'2,117'2,121'8'9/20/2021 Open BEL_52U 4,657'4,679'2,124'2,133'22'9/19/2021 Open BEL_52L 4,707'4,725'2,145'2,153'18'4/24/2021 Open Bel 53 4,790'4,802'2,181’2,186’12'1/13/2015 Squeezed (2/15/21) Bel 53 4,802'4,822'2,186’2,195’20'4/20/2015 Squeezed (2/15/21) Bel 53 4,819'4,839'2,194’2,202’20'1/11/2020 Squeezed (2/15/21) Bel 53 4,839'4,859'2,202’2,211’20'1/10/2020 Squeezed (2/15/21) Bel 53 4,863'4,883'2,213’2,222’20'1/10/2020 Squeezed (2/15/21) Bel 53 4,883'4,903'2,222’2,231’20'1/9/2020 Squeezed (2/15/21) BEL_56 5,083'5,096'2,316'2,322'13'4/24/2021 Open BEL_58U 5,151'5,161'2,351'2,356'10'9/19/2021 Open BEL_58L 5,166'5,176'2,359'2,364'10'9/19/2021 Open BEL_58A 5,215'5,242'2,384'2,399'27'4/24/2021 Open BEL_60 5,394'5,414'2,487'2,499'20'4/23/2021 Open BEL_74U 5,673'5,678'2,665'2,668'5'4/23/2021 Open BEL_74L 5,685'5,691'2,673'2,677'6'4/10/2021 Open BEL_82L 5,840'5,846'2,783'2,787'6'4/10/2021 Open BEL_83 5,870'5,882'2,805'2,813'12'4/10/2021 Open 2 1 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: Install Cap String 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: Current Pools: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 6,733'6,570' Casing Collapse Structural Conductor Surface 3,090 psi Intermediate Production 7,480 psi Liner 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 See Schematic 6,726' N/A Length N/A; SLB WRDP WLSSSV N/A; 166' MD / 166' TVD 3,503'6,458'3,273' 16" 9-5/8" NINILCHIK UNIT PAXTON 9CO 701C Same 3,495'5-1/2" ~984 psi December 27, 2024 3-1/2" 6,723' Perforation Depth MD (ft): See Schematic 5,750 psi 80' 2,291' Size 80' 2,291' MD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0384372 / FEE-PRIVATE 214-173 50-133-20647-00-00 Hilcorp Alaska, LLC Proposed Pools: 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: Suspension Expiration Date: 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 Scott Warner, Operations Engineer 9.2# / L-80 TVD Ninichik Beluga-Tyonek Gas Pool Will perfs require a spacing exception due to property boundaries? scott.warner@hilcorp.com 907-564-4506 Noel Nocas, Operations Manager 907-564-5278 Burst 6,481' 10,640 psi 1,401' m n P s t g 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 Chad Helgeson for Noel Nocas Digitally signed by Chad Helgeson (1517) DN: cn=Chad Helgeson (1517) Date: 2024.12.13 12:56:29 - 09'00' Chad Helgeson (1517) By Grace Christianson at 1:12 pm, Dec 13, 2024 324-701 DSR-12/16/24 10-404 BJM 12/16/24 SFD 12/13/2024*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.18 08:14:44 -09'00'11/18/24 RBDMS JSB 121824 Well Prognosis Well Name: Paxton 9 API Number: 50-133-20647-00-00 Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 214-173 First Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8863 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Maximum Expected BHP (Beluga 56): ~1265 psi @ 2813’ TVD (Based on 0.45 gradient) Max. Potential Surface Pressure: ~984 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: NA Cap string only, no new perforations Shallowest Allowable Perf TVD: NA – No perforations to be added Well Status: Gas producer making ~1000 mcfd, 15 bwpd @ 74psi, loading and soap is not unloading the well. Brief Well Summary: Paxton 9 was drilled and completed in December 2014 as a grassroots well to target gas sands in the Beluga formation. In 2021 a RWO isolated all existing perforations and was selectively reperforated in multiple Beluga sands. The well has recently began loading up. The purpose of this work/sundry is to set a 3/8” stainless steel capillary string to inject liquid soap downhole and keep the well from slugging as the well tapers out below unloading rate. The WR-SSSV will be pulled and remain out of the well with the capillary string installed. Notes Regarding Wellbore Condition x Inclination o Max deviation of 75.6° @ 1877’ MD o Max DLS of 9.14°/100’ @ 1309’ MD Procedure: 1. RU Cap String Truck. 2. Stab 3/8” capillary line into wellhead pack-off assembly. Make up BHA components. Install pack-off and pressure test against swab valve to 1500 psi. 3. RIH with 3/8” capillary string to ±3700’ MD. 4. Install slips and connect tubing to chemical injection pump. 5. Set spool of remaining line near well 6. RD cap string Unit, and turn well over to production. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic Updated by DMA 11-11-22 SCHEMATIC Ninilchik Unit Well:Paxton #9 PTD: 214-173 API: 50-133-20647-00-00 PBTD = 6,458 MD /3,273’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16”Conductor 109 / X-56 / Weld Surf 80’ 9-5/8'Surface 40 /L-80 / BTC 8.835”Surf 2,291’ 5-1/2"Production 17 / P-110 / CDC 4.892”Surf 6,723' TUBING DETAIL 3-1/2”Tubing / Scab Liner 9.2# / L-80 / Supermax 2.992” Surf 6,481’ 9-5/8” cement Job: 12-1/4” hole. 137 bbls of 12.5 Type I lead and 65bbls 15.2# tail. 100% returns with cement to surface 5-1/2” cement job: 8-1/2” hole. 145 bbls of 13.5# class G lead, and 93 bbls of 15.7# class G tail. Full returns throughout job. Volumetric ToC at ~1450’ MD assuming 10% openhole washout. 40 bbls spacer pumped, and 40 bbls back to surface (no cement seen) 3-1/2” Cement Job: 42bbls of 12ppg lead and 18bbls 15.3 tail. No losses throughout job (had losses pre-job). Good lift pressure, but cement must have fallen back after job. (had losses pre-job). . 2/18/21 Radial CBL:Solid cement up to ~4210’ MD (base BEL_47C squeeze perfs). Patchy cement up to 1850’ MD, free pipe at 890’ MD. Post-squeeze CBL run on 4/7/21 shows new ToC at ~820’MD 1 16” 9-5/8” 8-1/2” Hole 5.5” No.MD TVD ID Item 1 166’166’2.812”SSSV hydraulic nipple (SLB BP-6i)- SLB 3-1/2” WRDP WLSSSV installed 10/5/21 with AA-stop directly above. 2 4,750’2,163’CIBP 11/10/22 3 6,570’3,367’Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) from 1/15/15. Tagged at 6586’ CTMD 7/25/20 3 1450’ ToC (volumetric) Perforation Data Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)Ft Date Status Punches 2,401'2,405'1,434'1,436'4'3/19/2021 Squeezed (3/31/21) BEL_41U 3,645'3,676'1,792'1,801’31'9/22/2021 Open BEL 41L 3,677 3,702 1,801’1,808'25’9/22/2021 Open BEL_43 3,765'3,773'1,825'1,828'8'9/21/2021 Open BEL_44 3,832'3,857'1,845'1,852'25'9/21/2021 Open BEL_45 3,872'3,881'1,857'1,859'9'9/21/2021 Open BEL_45 3,928'3,936'1,873'1,875'8'9/22/2021 Open BEL_45 3,947'3,956'1,878'1,881'9'9/22/2021 Open BEL_46U 3,979'3,989'1,887'1,890'10'9/21/2021 Open BEL_47A 4,070'4,082'1,914'1,917'12'7/28/2020 Squeezed (2/15/21) BEL_47A 4,082'4,096'1,917'1,921'14'7/28/2020 Squeezed (2/15/21) BEL_47C 4,179'4,194'1,946'1,950'15'7/27/2020 Squeezed (2/15/21) BEL_47C 4,194'4,209'1,950'1,955'15'7/26/2020 Squeezed (2/15/21) BEL_49U 4,362'4,372'2,005'2,008'10'9/21/2021 Open BEL_49L 4,428'4,451'2,029'2,038'23'9/20/2021 Open BEL_50 4,518'4,543'2,065'2,076'25'9/20/2021 Open BEL_51 4,577'4,582'2,090'2,092'5'9/20/2021 Open BEL_52U 4,642'4,650'2,117'2,121'8'9/20/2021 Open BEL_52U 4,657'4,679'2,124'2,133'22'9/19/2021 Open BEL_52L 4,707'4,725'2,145'2,153'18'4/24/2021 Open Bel 53 4,790'4,802'2,181’2,186’12'1/13/2015 Squeezed (2/15/21) Bel 53 4,802'4,822'2,186’2,195’20'4/20/2015 Squeezed (2/15/21) Bel 53 4,819'4,839'2,194’2,202’20'1/11/2020 Squeezed (2/15/21) Bel 53 4,839'4,859'2,202’2,211’20'1/10/2020 Squeezed (2/15/21) Bel 53 4,863'4,883'2,213’2,222’20'1/10/2020 Squeezed (2/15/21) Bel 53 4,883'4,903'2,222’2,231’20'1/9/2020 Squeezed (2/15/21) BEL_56 5,083'5,096'2,316'2,322'13'4/24/2021 Open BEL_58U 5,151'5,161'2,351'2,356'10'9/19/2021 Open BEL_58L 5,166'5,176'2,359'2,364'10'9/19/2021 Open BEL_58A 5,215'5,242'2,384'2,399'27'4/24/2021 Open BEL_60 5,394'5,414'2,487'2,499'20'4/23/2021 Open BEL_74U 5,673'5,678'2,665'2,668'5'4/23/2021 Open BEL_74L 5,685'5,691'2,673'2,677'6'4/10/2021 Open BEL_82L 5,840'5,846'2,783'2,787'6'4/10/2021 Open BEL_83 5,870'5,882'2,805'2,813'12'4/10/2021 Open 2 Updated by CAH 12-13-24 PROPOSED Ninilchik Unit Well: Paxton #9 PTD: 214-173 API: 50-133-20647-00-00 PBTD = 6,458 MD /3,273’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16”Conductor 109 / X-56 / Weld Surf 80’ 9-5/8'Surface 40 /L-80 / BTC 8.835”Surf 2,291’ 5-1/2"Production 17 / P-110 / CDC 4.892”Surf 6,723' TUBING DETAIL 3-1/2”Tubing / Scab Liner 9.2# / L-80 / Supermax 2.992” Surf 6,481’ 3/8”Capillary 0.049 duplex 2205 Surface ±3,700’ 9-5/8” cement Job: 12-1/4” hole. 137 bbls of 12.5 Type I lead and 65bbls 15.2# tail. 100% returns with cement to surface 5-1/2” cement job: 8-1/2” hole. 145 bbls of 13.5# class G lead, and 93 bbls of 15.7# class G tail. Full returns throughout job. Volumetric ToC at ~1450’ MD assuming 10% openhole washout. 40 bbls spacer pumped, and 40 bbls back to surface (no cement seen) 3-1/2” Cement Job: 42bbls of 12ppg lead and 18bbls 15.3 tail. No losses throughout job (had losses pre-job). Good lift pressure, but cement must have fallen back after job. (had losses pre-job). . 2/18/21 Radial CBL:Solid cement up to ~4210’ MD (base BEL_47C squeeze perfs). Patchy cement up to 1850’ MD, free pipe at 890’ MD. Post-squeeze CBL run on 4/7/21 shows new ToC at ~820’MD 1 16” 9-5/8” 8-1/2” Hole 5.5” No.MD TVD ID Item 1 166’166’2.812”SSSV hydraulic nipple (SLB BP-6i)- SSSV removed for cap string 2 4,750’2,163’CIBP 11/10/22 3 6,570’3,367’Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) from 1/15/15. Tagged at 6586’ CTMD 7/25/20 3 1450’ ToC (volumetric) Perforation Data Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)Ft Date Status Punches 2,401'2,405'1,434'1,436'4'3/19/2021 Squeezed (3/31/21) BEL_41U 3,645'3,676'1,792'1,801’31'9/22/2021 Open BEL 41L 3,677 3,702 1,801’1,808'25’9/22/2021 Open BEL_43 3,765'3,773'1,825'1,828'8'9/21/2021 Open BEL_44 3,832'3,857'1,845'1,852'25'9/21/2021 Open BEL_45 3,872'3,881'1,857'1,859'9'9/21/2021 Open BEL_45 3,928'3,936'1,873'1,875'8'9/22/2021 Open BEL_45 3,947'3,956'1,878'1,881'9'9/22/2021 Open BEL_46U 3,979'3,989'1,887'1,890'10'9/21/2021 Open BEL_47A 4,070'4,082'1,914'1,917'12'7/28/2020 Squeezed (2/15/21) BEL_47A 4,082'4,096'1,917'1,921'14'7/28/2020 Squeezed (2/15/21) BEL_47C 4,179'4,194'1,946'1,950'15'7/27/2020 Squeezed (2/15/21) BEL_47C 4,194'4,209'1,950'1,955'15'7/26/2020 Squeezed (2/15/21) BEL_49U 4,362'4,372'2,005'2,008'10'9/21/2021 Open BEL_49L 4,428'4,451'2,029'2,038'23'9/20/2021 Open BEL_50 4,518'4,543'2,065'2,076'25'9/20/2021 Open BEL_51 4,577'4,582'2,090'2,092'5'9/20/2021 Open BEL_52U 4,642'4,650'2,117'2,121'8'9/20/2021 Open BEL_52U 4,657'4,679'2,124'2,133'22'9/19/2021 Open BEL_52L 4,707'4,725'2,145'2,153'18'4/24/2021 Open Bel 53 4,790'4,802'2,181’2,186’12'1/13/2015 Squeezed (2/15/21) Bel 53 4,802'4,822'2,186’2,195’20'4/20/2015 Squeezed (2/15/21) Bel 53 4,819'4,839'2,194’2,202’20'1/11/2020 Squeezed (2/15/21) Bel 53 4,839'4,859'2,202’2,211’20'1/10/2020 Squeezed (2/15/21) Bel 53 4,863'4,883'2,213’2,222’20'1/10/2020 Squeezed (2/15/21) Bel 53 4,883'4,903'2,222’2,231’20'1/9/2020 Squeezed (2/15/21) BEL_56 5,083'5,096'2,316'2,322'13'4/24/2021 Open BEL_58U 5,151'5,161'2,351'2,356'10'9/19/2021 Open BEL_58L 5,166'5,176'2,359'2,364'10'9/19/2021 Open BEL_58A 5,215'5,242'2,384'2,399'27'4/24/2021 Open BEL_60 5,394'5,414'2,487'2,499'20'4/23/2021 Open BEL_74U 5,673'5,678'2,665'2,668'5'4/23/2021 Open BEL_74L 5,685'5,691'2,673'2,677'6'4/10/2021 Open BEL_82L 5,840'5,846'2,783'2,787'6'4/10/2021 Open BEL_83 5,870'5,882'2,805'2,813'12'4/10/2021 Open 2 1 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: Install Cap String 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: Current Pools: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 6,733'6,570' Casing Collapse Structural Conductor Surface 3,090 psi Intermediate Production 7,480 psi Liner 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 See Schematic 6,726' N/A Length N/A; SLB WRDP WLSSSV N/A; 166' MD / 166' TVD 3,503'6,458'3,273' 16" 9-5/8" NINILCHIK UNIT PAXTON 9CO 701C Same 3,495'5-1/2" ~984 psi December 27, 2024 3-1/2" 6,723' Perforation Depth MD (ft): See Schematic 5,750 psi 80' 2,291' Size 80' 2,291' MD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0384372 / FEE-PRIVATE 214-173 50-133-20647-00-00 Hilcorp Alaska, LLC Proposed Pools: 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: Suspension Expiration Date: 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 Scott Warner, Operations Engineer 9.2# / L-80 TVD Ninichik Beluga-Tyonek Gas Pool Will perfs require a spacing exception due to property boundaries? scott.warner@hilcorp.com 907-564-4506 Noel Nocas, Operations Manager 907-564-5278 Burst 6,481' 10,640 psi 1,401' m n P s t g 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 Chad Helgeson for Noel Nocas Digitally signed by Chad Helgeson (1517) DN: cn=Chad Helgeson (1517) Date: 2024.12.13 12:56:29 - 09'00' Chad Helgeson (1517) By Grace Christianson at 1:12 pm, Dec 13, 2024 324-701 DSR-12/16/24 10-404 BJM 12/16/24 SFD 12/13/2024*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.18 08:14:44 -09'00'11/18/24 RBDMS JSB 121824 Well Prognosis Well Name: Paxton 9 API Number: 50-133-20647-00-00 Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 214-173 First Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8863 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Maximum Expected BHP (Beluga 56): ~1265 psi @ 2813’ TVD (Based on 0.45 gradient) Max. Potential Surface Pressure: ~984 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: NA Cap string only, no new perforations Shallowest Allowable Perf TVD: NA – No perforations to be added Well Status: Gas producer making ~1000 mcfd, 15 bwpd @ 74psi, loading and soap is not unloading the well. Brief Well Summary: Paxton 9 was drilled and completed in December 2014 as a grassroots well to target gas sands in the Beluga formation. In 2021 a RWO isolated all existing perforations and was selectively reperforated in multiple Beluga sands. The well has recently began loading up. The purpose of this work/sundry is to set a 3/8” stainless steel capillary string to inject liquid soap downhole and keep the well from slugging as the well tapers out below unloading rate. The WR-SSSV will be pulled and remain out of the well with the capillary string installed. Notes Regarding Wellbore Condition x Inclination o Max deviation of 75.6° @ 1877’ MD o Max DLS of 9.14°/100’ @ 1309’ MD Procedure: 1. RU Cap String Truck. 2. Stab 3/8” capillary line into wellhead pack-off assembly. Make up BHA components. Install pack-off and pressure test against swab valve to 1500 psi. 3. RIH with 3/8” capillary string to ±3700’ MD. 4. Install slips and connect tubing to chemical injection pump. 5. Set spool of remaining line near well 6. RD cap string Unit, and turn well over to production. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic Updated by DMA 11-11-22 SCHEMATIC Ninilchik Unit Well:Paxton #9 PTD: 214-173 API: 50-133-20647-00-00 PBTD = 6,458 MD /3,273’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16”Conductor 109 / X-56 / Weld Surf 80’ 9-5/8'Surface 40 /L-80 / BTC 8.835”Surf 2,291’ 5-1/2"Production 17 / P-110 / CDC 4.892”Surf 6,723' TUBING DETAIL 3-1/2”Tubing / Scab Liner 9.2# / L-80 / Supermax 2.992” Surf 6,481’ 9-5/8” cement Job: 12-1/4” hole. 137 bbls of 12.5 Type I lead and 65bbls 15.2# tail. 100% returns with cement to surface 5-1/2” cement job: 8-1/2” hole. 145 bbls of 13.5# class G lead, and 93 bbls of 15.7# class G tail. Full returns throughout job. Volumetric ToC at ~1450’ MD assuming 10% openhole washout. 40 bbls spacer pumped, and 40 bbls back to surface (no cement seen) 3-1/2” Cement Job: 42bbls of 12ppg lead and 18bbls 15.3 tail. No losses throughout job (had losses pre-job). Good lift pressure, but cement must have fallen back after job. (had losses pre-job). . 2/18/21 Radial CBL:Solid cement up to ~4210’ MD (base BEL_47C squeeze perfs). Patchy cement up to 1850’ MD, free pipe at 890’ MD. Post-squeeze CBL run on 4/7/21 shows new ToC at ~820’MD 1 16” 9-5/8” 8-1/2” Hole 5.5” No.MD TVD ID Item 1 166’166’2.812”SSSV hydraulic nipple (SLB BP-6i)- SLB 3-1/2” WRDP WLSSSV installed 10/5/21 with AA-stop directly above. 2 4,750’2,163’CIBP 11/10/22 3 6,570’3,367’Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) from 1/15/15. Tagged at 6586’ CTMD 7/25/20 3 1450’ ToC (volumetric) Perforation Data Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)Ft Date Status Punches 2,401'2,405'1,434'1,436'4'3/19/2021 Squeezed (3/31/21) BEL_41U 3,645'3,676'1,792'1,801’31'9/22/2021 Open BEL 41L 3,677 3,702 1,801’1,808'25’9/22/2021 Open BEL_43 3,765'3,773'1,825'1,828'8'9/21/2021 Open BEL_44 3,832'3,857'1,845'1,852'25'9/21/2021 Open BEL_45 3,872'3,881'1,857'1,859'9'9/21/2021 Open BEL_45 3,928'3,936'1,873'1,875'8'9/22/2021 Open BEL_45 3,947'3,956'1,878'1,881'9'9/22/2021 Open BEL_46U 3,979'3,989'1,887'1,890'10'9/21/2021 Open BEL_47A 4,070'4,082'1,914'1,917'12'7/28/2020 Squeezed (2/15/21) BEL_47A 4,082'4,096'1,917'1,921'14'7/28/2020 Squeezed (2/15/21) BEL_47C 4,179'4,194'1,946'1,950'15'7/27/2020 Squeezed (2/15/21) BEL_47C 4,194'4,209'1,950'1,955'15'7/26/2020 Squeezed (2/15/21) BEL_49U 4,362'4,372'2,005'2,008'10'9/21/2021 Open BEL_49L 4,428'4,451'2,029'2,038'23'9/20/2021 Open BEL_50 4,518'4,543'2,065'2,076'25'9/20/2021 Open BEL_51 4,577'4,582'2,090'2,092'5'9/20/2021 Open BEL_52U 4,642'4,650'2,117'2,121'8'9/20/2021 Open BEL_52U 4,657'4,679'2,124'2,133'22'9/19/2021 Open BEL_52L 4,707'4,725'2,145'2,153'18'4/24/2021 Open Bel 53 4,790'4,802'2,181’2,186’12'1/13/2015 Squeezed (2/15/21) Bel 53 4,802'4,822'2,186’2,195’20'4/20/2015 Squeezed (2/15/21) Bel 53 4,819'4,839'2,194’2,202’20'1/11/2020 Squeezed (2/15/21) Bel 53 4,839'4,859'2,202’2,211’20'1/10/2020 Squeezed (2/15/21) Bel 53 4,863'4,883'2,213’2,222’20'1/10/2020 Squeezed (2/15/21) Bel 53 4,883'4,903'2,222’2,231’20'1/9/2020 Squeezed (2/15/21) BEL_56 5,083'5,096'2,316'2,322'13'4/24/2021 Open BEL_58U 5,151'5,161'2,351'2,356'10'9/19/2021 Open BEL_58L 5,166'5,176'2,359'2,364'10'9/19/2021 Open BEL_58A 5,215'5,242'2,384'2,399'27'4/24/2021 Open BEL_60 5,394'5,414'2,487'2,499'20'4/23/2021 Open BEL_74U 5,673'5,678'2,665'2,668'5'4/23/2021 Open BEL_74L 5,685'5,691'2,673'2,677'6'4/10/2021 Open BEL_82L 5,840'5,846'2,783'2,787'6'4/10/2021 Open BEL_83 5,870'5,882'2,805'2,813'12'4/10/2021 Open 2 Updated by CAH 12-13-24 PROPOSED Ninilchik Unit Well: Paxton #9 PTD: 214-173 API: 50-133-20647-00-00 PBTD = 6,458 MD /3,273’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16”Conductor 109 / X-56 / Weld Surf 80’ 9-5/8'Surface 40 /L-80 / BTC 8.835”Surf 2,291’ 5-1/2"Production 17 / P-110 / CDC 4.892”Surf 6,723' TUBING DETAIL 3-1/2”Tubing / Scab Liner 9.2# / L-80 / Supermax 2.992” Surf 6,481’ 3/8”Capillary 0.049 duplex 2205 Surface ±3,700’ 9-5/8” cement Job: 12-1/4” hole. 137 bbls of 12.5 Type I lead and 65bbls 15.2# tail. 100% returns with cement to surface 5-1/2” cement job: 8-1/2” hole. 145 bbls of 13.5# class G lead, and 93 bbls of 15.7# class G tail. Full returns throughout job. Volumetric ToC at ~1450’ MD assuming 10% openhole washout. 40 bbls spacer pumped, and 40 bbls back to surface (no cement seen) 3-1/2” Cement Job: 42bbls of 12ppg lead and 18bbls 15.3 tail. No losses throughout job (had losses pre-job). Good lift pressure, but cement must have fallen back after job. (had losses pre-job). . 2/18/21 Radial CBL:Solid cement up to ~4210’ MD (base BEL_47C squeeze perfs). Patchy cement up to 1850’ MD, free pipe at 890’ MD. Post-squeeze CBL run on 4/7/21 shows new ToC at ~820’MD 1 16” 9-5/8” 8-1/2” Hole 5.5” No.MD TVD ID Item 1 166’166’2.812”SSSV hydraulic nipple (SLB BP-6i)- SSSV removed for cap string 2 4,750’2,163’CIBP 11/10/22 3 6,570’3,367’Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) from 1/15/15. Tagged at 6586’ CTMD 7/25/20 3 1450’ ToC (volumetric) Perforation Data Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)Ft Date Status Punches 2,401'2,405'1,434'1,436'4'3/19/2021 Squeezed (3/31/21) BEL_41U 3,645'3,676'1,792'1,801’31'9/22/2021 Open BEL 41L 3,677 3,702 1,801’1,808'25’9/22/2021 Open BEL_43 3,765'3,773'1,825'1,828'8'9/21/2021 Open BEL_44 3,832'3,857'1,845'1,852'25'9/21/2021 Open BEL_45 3,872'3,881'1,857'1,859'9'9/21/2021 Open BEL_45 3,928'3,936'1,873'1,875'8'9/22/2021 Open BEL_45 3,947'3,956'1,878'1,881'9'9/22/2021 Open BEL_46U 3,979'3,989'1,887'1,890'10'9/21/2021 Open BEL_47A 4,070'4,082'1,914'1,917'12'7/28/2020 Squeezed (2/15/21) BEL_47A 4,082'4,096'1,917'1,921'14'7/28/2020 Squeezed (2/15/21) BEL_47C 4,179'4,194'1,946'1,950'15'7/27/2020 Squeezed (2/15/21) BEL_47C 4,194'4,209'1,950'1,955'15'7/26/2020 Squeezed (2/15/21) BEL_49U 4,362'4,372'2,005'2,008'10'9/21/2021 Open BEL_49L 4,428'4,451'2,029'2,038'23'9/20/2021 Open BEL_50 4,518'4,543'2,065'2,076'25'9/20/2021 Open BEL_51 4,577'4,582'2,090'2,092'5'9/20/2021 Open BEL_52U 4,642'4,650'2,117'2,121'8'9/20/2021 Open BEL_52U 4,657'4,679'2,124'2,133'22'9/19/2021 Open BEL_52L 4,707'4,725'2,145'2,153'18'4/24/2021 Open Bel 53 4,790'4,802'2,181’2,186’12'1/13/2015 Squeezed (2/15/21) Bel 53 4,802'4,822'2,186’2,195’20'4/20/2015 Squeezed (2/15/21) Bel 53 4,819'4,839'2,194’2,202’20'1/11/2020 Squeezed (2/15/21) Bel 53 4,839'4,859'2,202’2,211’20'1/10/2020 Squeezed (2/15/21) Bel 53 4,863'4,883'2,213’2,222’20'1/10/2020 Squeezed (2/15/21) Bel 53 4,883'4,903'2,222’2,231’20'1/9/2020 Squeezed (2/15/21) BEL_56 5,083'5,096'2,316'2,322'13'4/24/2021 Open BEL_58U 5,151'5,161'2,351'2,356'10'9/19/2021 Open BEL_58L 5,166'5,176'2,359'2,364'10'9/19/2021 Open BEL_58A 5,215'5,242'2,384'2,399'27'4/24/2021 Open BEL_60 5,394'5,414'2,487'2,499'20'4/23/2021 Open BEL_74U 5,673'5,678'2,665'2,668'5'4/23/2021 Open BEL_74L 5,685'5,691'2,673'2,677'6'4/10/2021 Open BEL_82L 5,840'5,846'2,783'2,787'6'4/10/2021 Open BEL_83 5,870'5,882'2,805'2,813'12'4/10/2021 Open 2 1 Kyle Wiseman Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/28/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20221128-2 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# PBU 01-14A 50029202810100 209129 11/2/2022 Halliburton PPROF PBU 01-20 50029208210000 182146 10/31/2022 Halliburton PPROF PBU 01-33 50029216170000 186122 11/1/2022 Halliburton PPROF PBU A-04 50029201150000 172006 11/9/2022 Halliburton PPROF PBU C-01B 50029201210200 212053 11/6/2022 Halliburton PPROF PBU L-200A 50029231910200 221077 10/27/2022 Halliburton PPROF PAXTON 9 50133206470000 214173 11/4/2022 Halliburton PPROF Please include current contact information if different from above. By Meredith Guhl at 11:18 am, Nov 29, 2022 T37324 T37325 T37326 T37327 T37328 T37329 T37330 PAXTON 9 50133206470000 214173 11/4/2022 Halliburton PPROF Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.11.29 11:30:55 -09'00' By Anne Prysunka at 3:20 pm, Nov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aSVL 1$ 0' SVL 3HUIRUDWLRQ'HSWK0'IW SVL P Q 3 V B W )RUP5HYLVHG$SSURYHGDSSOLFDWLRQYDOLGIRUPRQWKVIURPGDWHRIDSSURYDO6XEPLW3')WRDRJFFSHUPLWWLQJ#DODVNDJRY By Anne Prysunka at 10:44 am, Nov 08, 2022 'LJLWDOO\VLJQHGE\1RHO1RFDV '1FQ 1RHO1RFDV RX 8VHUV 'DWH 1RHO1RFDV %-0 6)' 6)' <HV %U\DQ 0FOHOODQ '65 *&: Jessie L. 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ϭϭϲϲ͛ϭϲϲ͛Ϯ͘ϴϭϮ͟^^^sŚǇĚƌĂƵůŝĐŶŝƉƉůĞ;^>WͲϲŝͿͲ ^>ϯͲϭͬϮ͟tZWt>^^^sŝŶƐƚĂůůĞĚϭϬͬϱͬϮϭ ǁŝƚŚͲƐƚŽƉĚŝƌĞĐƚůǇĂďŽǀĞ͘ Ϯ ϲ͕ϱϳϬ͛ ϯ͕ϯϲϳ͛ ^ĐŚůƵŵďĞƌŐĞƌƚĞŶƐŝŽŶƐƵď͕ƚĞůĞŵĞƚƌǇ͕;ϮͿƚƌĂĐƚŽƌƐ͕'Z͕ďƵŵƉĞƌƐƵď͕ŚŽůůŽǁ ĐĂƌƌŝĞƌ;ϳϯĨƚ͘ƚŽŽůůĞŶŐƚŚͿĨƌŽŵϭͬϭϱͬϭϱ͘dĂŐŐĞĚĂƚϲϱϴϲ͛dDϳͬϮϱͬϮϬ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚͬ'ƌĂĚĞͬŽŶŶ / dŽƉ ƚŵ ϭϲ͟ ŽŶĚƵĐƚŽƌ ϭϬϵͬyͲϱϲͬtĞůĚ ^ƵƌĨ ϴϬ͛ ϵͲϱͬϴΖ ^ƵƌĨĂĐĞ ϰϬͬ>ͲϴϬͬd ϴ͘ϴϯϱ͟ ^ƵƌĨ Ϯ͕Ϯϵϭ͛ ϱͲϭͬϮΗ WƌŽĚƵĐƚŝŽŶ ϭϳͬWͲϭϭϬͬ ϰ͘ϴϵϮ͟ ^ƵƌĨ ϲ͕ϳϮϯΖ dh/E'd/> ϯͲϭͬϮ͟dƵďŝŶŐͬ ^ĐĂď>ŝŶĞƌ ϵ͘Ϯηͬ>ͲϴϬͬ^ƵƉĞƌŵĂǆ Ϯ͘ϵϵϮ͟ ^ƵƌĨ ϲ͕ϰϴϭ͛ Ϯ ϭϰϱϬ͛dŽ ;ǀŽůƵŵĞƚƌŝĐͿ WĞƌĨŽƌĂƚŝŽŶĂƚĂ ^ĂŶĚƐ dŽƉ ;DͿ ƚŵ ;DͿ dŽƉ ;dsͿ ƚŵ ;dsͿ &ƚ ĂƚĞ ^ƚĂƚƵƐ WƵŶĐŚĞƐ Ϯ͕ϰϬϭΖ Ϯ͕ϰϬϱΖ ϭ͕ϰϯϰΖ ϭ͕ϰϯϲΖ ϰΖ ϯͬϭϵͬϮϬϮϭ ^ƋƵĞĞǌĞĚ;ϯͬϯϭͬϮϭͿ >ͺϰϭh ϯ͕ϲϰϱΖ ϯ͕ϲϳϲΖ ϭ͕ϳϵϮΖ ϭ͕ϴϬϭ͛ ϯϭΖ ϵͬϮϮͬϮϬϮϭ KƉĞŶ >ϰϭ> ϯ͕ϲϳϳ ϯ͕ϳϬϮ ϭ͕ϴϬϭ͛ ϭ͕ϴϬϴΖ Ϯϱ͛ ϵͬϮϮͬϮϬϮϭ KƉĞŶ >ͺϰϯ ϯ͕ϳϲϱΖ ϯ͕ϳϳϯΖ ϭ͕ϴϮϱΖ ϭ͕ϴϮϴΖ ϴΖ ϵͬϮϭͬϮϬϮϭ KƉĞŶ >ͺϰϰ ϯ͕ϴϯϮΖ ϯ͕ϴϱϳΖ ϭ͕ϴϰϱΖ ϭ͕ϴϱϮΖ ϮϱΖ ϵͬϮϭͬϮϬϮϭ KƉĞŶ >ͺϰϱ ϯ͕ϴϳϮΖ ϯ͕ϴϴϭΖ ϭ͕ϴϱϳΖ ϭ͕ϴϱϵΖ ϵΖ ϵͬϮϭͬϮϬϮϭ KƉĞŶ >ͺϰϱ ϯ͕ϵϮϴΖ ϯ͕ϵϯϲΖ ϭ͕ϴϳϯΖ ϭ͕ϴϳϱΖ ϴΖ ϵͬϮϮͬϮϬϮϭ KƉĞŶ >ͺϰϱ ϯ͕ϵϰϳΖ ϯ͕ϵϱϲΖ ϭ͕ϴϳϴΖ ϭ͕ϴϴϭΖ ϵΖ ϵͬϮϮͬϮϬϮϭ KƉĞŶ >ͺϰϲh ϯ͕ϵϳϵΖ ϯ͕ϵϴϵΖ ϭ͕ϴϴϳΖ ϭ͕ϴϵϬΖ ϭϬΖ ϵͬϮϭͬϮϬϮϭ KƉĞŶ >ͺϰϳ ϰ͕ϬϳϬΖ ϰ͕ϬϴϮΖ ϭ͕ϵϭϰΖ ϭ͕ϵϭϳΖ ϭϮΖ ϳͬϮϴͬϮϬϮϬ ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ >ͺϰϳ ϰ͕ϬϴϮΖ ϰ͕ϬϵϲΖ ϭ͕ϵϭϳΖ ϭ͕ϵϮϭΖ ϭϰΖ ϳͬϮϴͬϮϬϮϬ ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ >ͺϰϳ ϰ͕ϭϳϵΖ ϰ͕ϭϵϰΖ ϭ͕ϵϰϲΖ ϭ͕ϵϱϬΖ ϭϱΖ ϳͬϮϳͬϮϬϮϬ ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ >ͺϰϳ ϰ͕ϭϵϰΖ ϰ͕ϮϬϵΖ ϭ͕ϵϱϬΖ ϭ͕ϵϱϱΖ ϭϱΖ ϳͬϮϲͬϮϬϮϬ ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ >ͺϰϵh ϰ͕ϯϲϮΖ ϰ͕ϯϳϮΖ Ϯ͕ϬϬϱΖ Ϯ͕ϬϬϴΖ ϭϬΖ ϵͬϮϭͬϮϬϮϭ KƉĞŶ >ͺϰϵ> ϰ͕ϰϮϴΖ ϰ͕ϰϱϭΖ Ϯ͕ϬϮϵΖ Ϯ͕ϬϯϴΖ ϮϯΖ ϵͬϮϬͬϮϬϮϭ KƉĞŶ >ͺϱϬ ϰ͕ϱϭϴΖ ϰ͕ϱϰϯΖ Ϯ͕ϬϲϱΖ Ϯ͕ϬϳϲΖ ϮϱΖ ϵͬϮϬͬϮϬϮϭ KƉĞŶ >ͺϱϭ ϰ͕ϱϳϳΖ ϰ͕ϱϴϮΖ Ϯ͕ϬϵϬΖ Ϯ͕ϬϵϮΖ ϱΖ ϵͬϮϬͬϮϬϮϭ KƉĞŶ >ͺϱϮh ϰ͕ϲϰϮΖ ϰ͕ϲϱϬΖ Ϯ͕ϭϭϳΖ Ϯ͕ϭϮϭΖ ϴΖ ϵͬϮϬͬϮϬϮϭ KƉĞŶ >ͺϱϮh ϰ͕ϲϱϳΖ ϰ͕ϲϳϵΖ Ϯ͕ϭϮϰΖ Ϯ͕ϭϯϯΖ ϮϮΖ ϵͬϭϵͬϮϬϮϭ KƉĞŶ >ͺϱϮ> ϰ͕ϳϬϳΖ ϰ͕ϳϮϱΖ Ϯ͕ϭϰϱΖ Ϯ͕ϭϱϯΖ ϭϴΖ ϰͬϮϰͬϮϬϮϭ KƉĞŶ Ğůϱϯ ϰ͕ϳϵϬΖ ϰ͕ϴϬϮΖ Ϯ͕ϭϴϭ͛ Ϯ͕ϭϴϲ͛ ϭϮΖ ϭͬϭϯͬϮϬϭϱ ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ Ğůϱϯ ϰ͕ϴϬϮΖ ϰ͕ϴϮϮΖ Ϯ͕ϭϴϲ͛ Ϯ͕ϭϵϱ͛ ϮϬΖ ϰͬϮϬͬϮϬϭϱ ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ Ğůϱϯ ϰ͕ϴϭϵΖ ϰ͕ϴϯϵΖ Ϯ͕ϭϵϰ͛ Ϯ͕ϮϬϮ͛ ϮϬΖ ϭͬϭϭͬϮϬϮϬ ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ Ğůϱϯ ϰ͕ϴϯϵΖ ϰ͕ϴϱϵΖ Ϯ͕ϮϬϮ͛ Ϯ͕Ϯϭϭ͛ ϮϬΖ ϭͬϭϬͬϮϬϮϬ ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ Ğůϱϯ ϰ͕ϴϲϯΖ ϰ͕ϴϴϯΖ Ϯ͕Ϯϭϯ͛ Ϯ͕ϮϮϮ͛ ϮϬΖ ϭͬϭϬͬϮϬϮϬ ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ Ğůϱϯ ϰ͕ϴϴϯΖ ϰ͕ϵϬϯΖ Ϯ͕ϮϮϮ͛ Ϯ͕Ϯϯϭ͛ ϮϬΖ ϭͬϵͬϮϬϮϬ ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ >ͺϱϲ ϱ͕ϬϴϯΖ ϱ͕ϬϵϲΖ Ϯ͕ϯϭϲΖ Ϯ͕ϯϮϮΖ ϭϯΖ ϰͬϮϰͬϮϬϮϭ KƉĞŶ >ͺϱϴh ϱ͕ϭϱϭΖ ϱ͕ϭϲϭΖ Ϯ͕ϯϱϭΖ Ϯ͕ϯϱϲΖ ϭϬΖ ϵͬϭϵͬϮϬϮϭ KƉĞŶ >ͺϱϴ> ϱ͕ϭϲϲΖ ϱ͕ϭϳϲΖ Ϯ͕ϯϱϵΖ Ϯ͕ϯϲϰΖ ϭϬΖ ϵͬϭϵͬϮϬϮϭ KƉĞŶ >ͺϱϴ ϱ͕ϮϭϱΖ ϱ͕ϮϰϮΖ Ϯ͕ϯϴϰΖ Ϯ͕ϯϵϵΖ ϮϳΖ ϰͬϮϰͬϮϬϮϭ KƉĞŶ >ͺϲϬ ϱ͕ϯϵϰΖ ϱ͕ϰϭϰΖ Ϯ͕ϰϴϳΖ Ϯ͕ϰϵϵΖ ϮϬΖ ϰͬϮϯͬϮϬϮϭ KƉĞŶ >ͺϳϰh ϱ͕ϲϳϯΖ ϱ͕ϲϳϴΖ Ϯ͕ϲϲϱΖ Ϯ͕ϲϲϴΖ ϱΖ ϰͬϮϯͬϮϬϮϭ KƉĞŶ >ͺϳϰ> ϱ͕ϲϴϱΖ ϱ͕ϲϵϭΖ Ϯ͕ϲϳϯΖ Ϯ͕ϲϳϳΖ ϲΖ ϰͬϭϬͬϮϬϮϭ KƉĞŶ >ͺϴϮ> ϱ͕ϴϰϬΖ ϱ͕ϴϰϲΖ Ϯ͕ϳϴϯΖ Ϯ͕ϳϴϳΖ ϲΖ ϰͬϭϬͬϮϬϮϭ KƉĞŶ >ͺϴϯ ϱ͕ϴϳϬΖ ϱ͕ϴϴϮΖ Ϯ͕ϴϬϱΖ Ϯ͕ϴϭϯΖ ϭϮΖ ϰͬϭϬͬϮϬϮϭ KƉĞŶ hƉĚĂƚĞĚďǇ<KϭϭͲϬϳͲϮϮ WZKWK^^,Dd/ EŝŶŝůĐŚŝŬhŶŝƚ tĞůů͗WĂǆƚŽŶηϵ Wd͗ϮϭϰͲϭϳϯ W/͗ϱϬͲϭϯϯͲϮϬϲϰϳͲϬϬͲϬϬ Wdсϲ͕ϰϱϴDͬϯ͕Ϯϳϯ͛ds dсϲ͕ϳϯϯ͛Dͬϯ͕ϱϬϯ͛ds Z<сϭϴ͘ϳ͛ ^/E'd/> ^ŝǌĞdǇƉĞtƚͬ'ƌĂĚĞͬŽŶŶ/dŽƉƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌϭϬϵͬyͲϱϲͬtĞůĚ^ƵƌĨϴϬ͛ ϵͲϱͬϴΖ^ƵƌĨĂĐĞϰϬͬ>ͲϴϬͬdϴ͘ϴϯϱ͟^ƵƌĨϮ͕Ϯϵϭ͛ ϱͲϭͬϮΗWƌŽĚƵĐƚŝŽŶϭϳͬWͲϭϭϬͬϰ͘ϴϵϮ͟^ƵƌĨϲ͕ϳϮϯΖ dh/E'd/> ϯͲϭͬϮ͟dƵďŝŶŐͬ ^ĐĂď>ŝŶĞƌϵ͘Ϯηͬ>ͲϴϬͬ^ƵƉĞƌŵĂǆϮ͘ϵϵϮ͟ ^ƵƌĨ ϲ͕ϰϴϭ͛ ´FHPHQW-RE´KROHEEOVRI7\SH,OHDGDQGEEOVWDLOUHWXUQVZLWK FHPHQWWRVXUIDFH ´FHPHQWMRE´KROHEEOVRIFODVV*OHDGDQGEEOVRIFODVV*WDLO)XOOUHWXUQV WKURXJKRXWMRE9ROXPHWULF7R&DWa¶0'DVVXPLQJRSHQKROHZDVKRXWEEOVVSDFHUSXPSHGDQG EEOVEDFNWRVXUIDFHQRFHPHQWVHHQ ´&HPHQW-REEEOVRISSJOHDGDQGEEOVWDLO1RORVVHVWKURXJKRXWMREKDGORVVHVSUHMRE *RRGOLIWSUHVVXUHEXWFHPHQWPXVWKDYHIDOOHQEDFNDIWHUMREKDGORVVHVSUHMRE 5DGLDO&%/6ROLGFHPHQWXSWRa¶0'EDVH%(/B&VTXHH]HSHUIV3DWFK\FHPHQWXSWR ¶0'IUHHSLSHDW¶0'3RVWVTXHH]H&%/UXQRQVKRZVQHZ7R&DWa¶0' ϭϲ͟ ϵͲϱͬϴ͟ ϴͲϭͬϮ͟,ŽůĞ ϱ͘ϱ͟ EŽ͘Dds//ƚĞŵ ϭϭϲϲ͛ϭϲϲ͛Ϯ͘ϴϭϮ͟^^^sŚǇĚƌĂƵůŝĐŶŝƉƉůĞ;^>WͲϲŝͿͲ^>ϯͲϭͬϮ͟tZWt>^^^sŝŶƐƚĂůůĞĚ ϭϬͬϱͬϮϭǁŝƚŚͲƐƚŽƉĚŝƌĞĐƚůǇĂďŽǀĞ͘ ϮΕϱ͕ϭϭϬ͛Ϯ͕ϯϯϬ͛/W ϯϲ͕ϱϳϬ͛ϯ͕ϯϲϳ͛^ĐŚůƵŵďĞƌŐĞƌƚĞŶƐŝŽŶƐƵď͕ƚĞůĞŵĞƚƌǇ͕;ϮͿƚƌĂĐƚŽƌƐ͕'Z͕ďƵŵƉĞƌƐƵď͕ŚŽůůŽǁ ĐĂƌƌŝĞƌ;ϳϯĨƚ͘ƚŽŽůůĞŶŐƚŚͿĨƌŽŵϭͬϭϱͬϭϱ͘dĂŐŐĞĚĂƚϲϱϴϲ͛dDϳͬϮϱͬϮϬ ϯ ϭϰϱϬ͛dŽ ;ǀŽůƵŵĞƚƌŝĐͿ WĞƌĨŽƌĂƚŝŽŶĂƚĂ ^ĂŶĚƐdŽƉ ;DͿ ƚŵ ;DͿ dŽƉ ;dsͿ ƚŵ ;dsͿ&ƚ ĂƚĞ ^ƚĂƚƵƐ WƵŶĐŚĞƐϮ͕ϰϬϭΖϮ͕ϰϬϱΖϭ͕ϰϯϰΖϭ͕ϰϯϲΖϰΖϯͬϭϵͬϮϬϮϭ^ƋƵĞĞǌĞĚ;ϯͬϯϭͬϮϭͿ >ͺϰϭhϯ͕ϲϰϱΖϯ͕ϲϳϲΖϭ͕ϳϵϮΖϭ͕ϴϬϭ͛ϯϭΖϵͬϮϮͬϮϬϮϭKƉĞŶ >ϰϭ>ϯ͕ϲϳϳϯ͕ϳϬϮϭ͕ϴϬϭ͛ϭ͕ϴϬϴΖϮϱ͛ϵͬϮϮͬϮϬϮϭKƉĞŶ >ͺϰϯϯ͕ϳϲϱΖϯ͕ϳϳϯΖϭ͕ϴϮϱΖϭ͕ϴϮϴΖϴΖϵͬϮϭͬϮϬϮϭKƉĞŶ >ͺϰϰϯ͕ϴϯϮΖϯ͕ϴϱϳΖϭ͕ϴϰϱΖϭ͕ϴϱϮΖϮϱΖϵͬϮϭͬϮϬϮϭKƉĞŶ >ͺϰϱϯ͕ϴϳϮΖϯ͕ϴϴϭΖϭ͕ϴϱϳΖϭ͕ϴϱϵΖϵΖϵͬϮϭͬϮϬϮϭKƉĞŶ >ͺϰϱϯ͕ϵϮϴΖϯ͕ϵϯϲΖϭ͕ϴϳϯΖϭ͕ϴϳϱΖϴΖϵͬϮϮͬϮϬϮϭKƉĞŶ >ͺϰϱϯ͕ϵϰϳΖϯ͕ϵϱϲΖϭ͕ϴϳϴΖϭ͕ϴϴϭΖϵΖϵͬϮϮͬϮϬϮϭKƉĞŶ >ͺϰϲhϯ͕ϵϳϵΖϯ͕ϵϴϵΖϭ͕ϴϴϳΖϭ͕ϴϵϬΖϭϬΖϵͬϮϭͬϮϬϮϭKƉĞŶ >ͺϰϳϰ͕ϬϳϬΖϰ͕ϬϴϮΖϭ͕ϵϭϰΖϭ͕ϵϭϳΖϭϮΖϳͬϮϴͬϮϬϮϬ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ >ͺϰϳϰ͕ϬϴϮΖϰ͕ϬϵϲΖϭ͕ϵϭϳΖϭ͕ϵϮϭΖϭϰΖϳͬϮϴͬϮϬϮϬ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ >ͺϰϳϰ͕ϭϳϵΖϰ͕ϭϵϰΖϭ͕ϵϰϲΖϭ͕ϵϱϬΖϭϱΖϳͬϮϳͬϮϬϮϬ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ >ͺϰϳϰ͕ϭϵϰΖϰ͕ϮϬϵΖϭ͕ϵϱϬΖϭ͕ϵϱϱΖϭϱΖϳͬϮϲͬϮϬϮϬ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ >ͺϰϵhϰ͕ϯϲϮΖϰ͕ϯϳϮΖϮ͕ϬϬϱΖϮ͕ϬϬϴΖϭϬΖϵͬϮϭͬϮϬϮϭKƉĞŶ >ͺϰϵ>ϰ͕ϰϮϴΖϰ͕ϰϱϭΖϮ͕ϬϮϵΖϮ͕ϬϯϴΖϮϯΖϵͬϮϬͬϮϬϮϭKƉĞŶ >ͺϱϬϰ͕ϱϭϴΖϰ͕ϱϰϯΖϮ͕ϬϲϱΖϮ͕ϬϳϲΖϮϱΖϵͬϮϬͬϮϬϮϭKƉĞŶ >ͺϱϭϰ͕ϱϳϳΖϰ͕ϱϴϮΖϮ͕ϬϵϬΖϮ͕ϬϵϮΖϱΖϵͬϮϬͬϮϬϮϭKƉĞŶ >ͺϱϮhϰ͕ϲϰϮΖϰ͕ϲϱϬΖϮ͕ϭϭϳΖϮ͕ϭϮϭΖϴΖϵͬϮϬͬϮϬϮϭKƉĞŶ >ͺϱϮhϰ͕ϲϱϳΖϰ͕ϲϳϵΖϮ͕ϭϮϰΖϮ͕ϭϯϯΖϮϮΖϵͬϭϵͬϮϬϮϭKƉĞŶ >ͺϱϮ>ϰ͕ϳϬϳΖϰ͕ϳϮϱΖϮ͕ϭϰϱΖϮ͕ϭϱϯΖϭϴΖϰͬϮϰͬϮϬϮϭKƉĞŶ Ğůϱϯϰ͕ϳϵϬΖϰ͕ϴϬϮΖϮ͕ϭϴϭ͛Ϯ͕ϭϴϲ͛ϭϮΖϭͬϭϯͬϮϬϭϱ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ Ğůϱϯϰ͕ϴϬϮΖϰ͕ϴϮϮΖϮ͕ϭϴϲ͛Ϯ͕ϭϵϱ͛ϮϬΖϰͬϮϬͬϮϬϭϱ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ Ğůϱϯϰ͕ϴϭϵΖϰ͕ϴϯϵΖϮ͕ϭϵϰ͛Ϯ͕ϮϬϮ͛ϮϬΖϭͬϭϭͬϮϬϮϬ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ Ğůϱϯϰ͕ϴϯϵΖϰ͕ϴϱϵΖϮ͕ϮϬϮ͛Ϯ͕Ϯϭϭ͛ϮϬΖϭͬϭϬͬϮϬϮϬ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ Ğůϱϯϰ͕ϴϲϯΖϰ͕ϴϴϯΖϮ͕Ϯϭϯ͛Ϯ͕ϮϮϮ͛ϮϬΖϭͬϭϬͬϮϬϮϬ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ Ğůϱϯϰ͕ϴϴϯΖϰ͕ϵϬϯΖϮ͕ϮϮϮ͛Ϯ͕Ϯϯϭ͛ϮϬΖϭͬϵͬϮϬϮϬ^ƋƵĞĞǌĞĚ;ϮͬϭϱͬϮϭͿ >ͺϱϲϱ͕ϬϴϯΖϱ͕ϬϵϲΖϮ͕ϯϭϲΖϮ͕ϯϮϮΖϭϯΖϰͬϮϰͬϮϬϮϭKƉĞŶ >ͺϱϴhϱ͕ϭϱϭΖϱ͕ϭϲϭΖϮ͕ϯϱϭΖϮ͕ϯϱϲΖϭϬΖϵͬϭϵͬϮϬϮϭKƉĞŶ >ͺϱϴ>ϱ͕ϭϲϲΖϱ͕ϭϳϲΖϮ͕ϯϱϵΖϮ͕ϯϲϰΖϭϬΖϵͬϭϵͬϮϬϮϭKƉĞŶ >ͺϱϴϱ͕ϮϭϱΖϱ͕ϮϰϮΖϮ͕ϯϴϰΖϮ͕ϯϵϵΖϮϳΖϰͬϮϰͬϮϬϮϭKƉĞŶ >ͺϲϬϱ͕ϯϵϰΖϱ͕ϰϭϰΖϮ͕ϰϴϳΖϮ͕ϰϵϵΖϮϬΖϰͬϮϯͬϮϬϮϭKƉĞŶ >ͺϳϰhϱ͕ϲϳϯΖϱ͕ϲϳϴΖϮ͕ϲϲϱΖϮ͕ϲϲϴΖϱΖϰͬϮϯͬϮϬϮϭKƉĞŶ >ͺϳϰ>ϱ͕ϲϴϱΖϱ͕ϲϵϭΖϮ͕ϲϳϯΖϮ͕ϲϳϳΖϲΖϰͬϭϬͬϮϬϮϭKƉĞŶ >ͺϴϮ>ϱ͕ϴϰϬΖϱ͕ϴϰϲΖϮ͕ϳϴϯΖϮ͕ϳϴϳΖϲΖϰͬϭϬͬϮϬϮϭKƉĞŶ >ͺϴϯϱ͕ϴϳϬΖϱ͕ϴϴϮΖϮ͕ϴϬϱΖϮ͕ϴϭϯΖϭϮΖϰͬϭϬͬϮϬϮϭKƉĞŶ Ϯ 9ROXPHWULF7R&DWa¶0'DVVXPLQJRSHQKROHZDVKRXW CAUTION: This email originated from outside the State of Alaska mail system. 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From:Regg, James B (OGC) To:AOGCC Records (CED sponsored) Subject:FW: Paxton 9 (PTD: 214-173) SSSV Date:Monday, October 31, 2022 9:08:52 AM Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Regg, James B (OGC) Sent: Monday, October 31, 2022 9:04 AM To: Jacob Flora <Jake.Flora@hilcorp.com> Cc: Katherine O'Connor <Katherine.Oconnor@hilcorp.com>; Chad Ebenezer <cebenezer@hilcorp.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: Paxton 9 (PTD: 214-173) SSSV Request approved Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Friday, October 28, 2022 3:18 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Katherine O'Connor <Katherine.Oconnor@hilcorp.com>; Chad Ebenezer <cebenezer@hilcorp.com> Subject: FW: Paxton 9 (PTD: 214-173) SSSV Mr. Regg, I am following up on this request as Katherine is out of the office until after 11/1. As stated the Paxton 9 well saw water breakthrough and is making 200 bwpd. It’s currently flowing and under man watch to ensure the sand buster doesn’t clog up. We are unable to get a production log run until 11/15 and are requesting permission to leave the WR-SSSV out of the well until we can obtain this log. The ultimate goal is to pursue a water shut-off with a plug or patch. Please advise if you need any further data in this request. Greatly appreciated, Jake From: Katherine O'Connor Sent: Monday, October 24, 2022 10:31 AM To: Regg, James B (OGC) <jim.regg@alaska.gov> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Josh Allely - (C) <Josh.Allely@hilcorp.com> Subject: Paxton 9 (PTD: 214-173) SSSV Hi Jim Pax 9 has increased in water production significantly. The well is still flowing but it is more challenged with the water influx. We pulled the SSSV to do diagnostics on 10/18, and the first log we ran was not conclusive. Per the regs the SSSV will need to be reinstalled 11/1. We are not able to get a new suite of logging tools down to Kenai for another 7-10 days. May we leave the SSSV out of hole until 11/15 in order to complete diagnostics? Thanks Katherine O’Connor Kenai Operations Engineer Katherine.oconnor@hilcorp.com W: (907) 777-8376 C: (214) 684-7400 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 herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 6,733 feet N.A feet true vertical 3,503 feet 6,570 feet Effective Depth measured 6,458 feet N/A feet true vertical 3,273 feet N/A feet Perforation depth Measured depth See schematic feet True Vertical depth See schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.2 / L-80 6,481 MD 3,293 TVD 166 MD Packers and SSSV (type, measured and true vertical depth)N/A SLB WRDP WLSSSV 166 TVD 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 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: Contact Name: Contact Email: Authorized Title:Contact Phone: 321-439 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 975 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 0 103 Ryan Rupert ryan.rupert@hilcorp.com (907) 777-8503Dan Marlowe - Operations Manager measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 0 4122,306 0 85 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 80' 2,291' N/A 460 Structural TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 214-173 50-133-20647-00-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0384372 / FEE-PRIVATE Ninilchik Field / Beluga-Tyonek Gas Pool 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Paxton 09 Hilcorp Alaska, LLC Other: ______________________ measuredPlugs Junk measured N/A Length 80' 2,291' Size Conductor Surface Intermediate 16" 9-5/8" Production Liner 6,723' Casing 80' 1,401' 3,495'6,723'5-1/2"7,480psi 5,750psi 10,640psi Burst Collapse 3,090psi L G Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Samantha Carlisle at 4:34 pm, Nov 19, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.11.19 15:56:38 -09'00' Dan Marlowe (1267) RBDMS HEW 11/22/2021 BJM 12/15/21 DSR-11/22/21SFD 11/29/2021 Updated by JLL 11/19/21 SCHEMATIC Ninilchik Unit Well: Paxton #9 PTD: 214-173 API: 50-133-20647-00-00 PBTD = 6,458 MD /3,273’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ 9-5/8” cement Job: 12-1/4” hole. 137 bbls of 12.5 Type I lead and 65bbls 15.2# tail. 100% returns with cement to surface 5-1/2” cement job: 8-1/2” hole. 145 bbls of 13.5# class G lead, and 93 bbls of 15.7# class G tail. Full returns throughout job. Volumetric ToC at ~1450’ MD assuming 10% openhole washout. 40 bbls spacer pumped, and 40 bbls back to surface (no cement seen) 3-1/2” Cement Job: 42bbls of 12ppg lead and 18bbls 15.3 tail. No losses throughout job (had losses pre-job). Good lift pressure, but cement must have fallen back after job. (had losses pre-job). Good lift pressure, but cement must have fallen back after job. 2/18/21 Radial CBL: Solid cement up to ~4210’ MD (base BEL_47C squeeze perfs). Patchy cement up to 1850’ MD, free pipe at 890’ MD.Post-squeeze CBL run on 4/7/21 shows new ToC at ~820’MD 1 16” 9-5/8” 8-1/2” Hole 5.5” No. MD TVD ID Item 1166’166’2.812”SSSV hydraulic nipple (SLB BP-6i)-SLB 3-1/2” WRDP WLSSSV installed 10/5/21 with AA-stop directly above. 2 6,570’ 3,367’Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) from 1/15/15. Tagged at 6586’ CTMD 7/25/20 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16” Conductor 109 / X-56 / Weld Surf 80’ 9-5/8' Surface 40 /L-80 / BTC 8.835” Surf 2,291’ 5-1/2" Production 17 / P-110 / CDC 4.892” Surf 6,723' TUBING DETAIL 3-1/2”Tubing / Scab Liner 9.2# / L-80 / Supermax 2.992” Surf 6,481’ 2 1450’ ToC (volumetric) Perforation Data Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)Ft Date Status Punches 2,401' 2,405' 1,434' 1,436' 4' 3/19/2021 Squeezed (3/31/21) BEL_41U 3,645' 3,702' 1,792' 1,808' 57' 9/22/2021 Open BEL_43 3,765' 3,773' 1,825' 1,828' 8' 9/21/2021 Open BEL_44 3,832' 3,857' 1,845' 1,852' 25' 9/21/2021 Open BEL_45 3,872' 3,881' 1,857' 1,859' 9' 9/21/2021 Open BEL_45 3,928' 3,936' 1,873' 1,875' 8' 9/22/2021 Open BEL_45 3,947' 3,956' 1,878' 1,881' 9' 9/22/2021 Open BEL_46U 3,979' 3,989' 1,887' 1,890' 10' 9/21/2021 Open BEL_47A 4,070' 4,082' 1,914' 1,917' 12' 7/28/2020 Squeezed (2/15/21) BEL_47A 4,082' 4,096' 1,917' 1,921' 14' 7/28/2020 Squeezed (2/15/21) BEL_47C 4,179' 4,194' 1,946' 1,950' 15' 7/27/2020 Squeezed (2/15/21) BEL_47C 4,194' 4,209' 1,950' 1,955' 15' 7/26/2020 Squeezed (2/15/21) BEL_49U 4,362' 4,372' 2,005' 2,008' 10' 9/21/2021 Open BEL_49L 4,428' 4,451' 2,029' 2,038' 23' 9/21/2021 Open BEL_50 4,518' 4,543' 2,065' 2,076' 25' 9/20/2021 Open BEL_51 4,577' 4,582' 2,090' 2,092' 5' 9/20/2021 Open BEL_52U 4,642' 4,650' 2,117' 2,121' 8' 9/20/2021 Open BEL_52U 4,657' 4,679' 2,124' 2,133' 22' 9/19/2021 Open BEL_52L 4,707' 4,725' 2,145' 2,153' 18' 4/24/2021 Open Bel 53 4,790' 4,802' 2,181’ 2,186’ 12' 1/13/2015 Squeezed (2/15/21) Bel 53 4,802' 4,822' 2,186’ 2,195’ 20' 4/20/2015 Squeezed (2/15/21) Bel 53 4,819' 4,839' 2,194’ 2,202’ 20' 1/11/2020 Squeezed (2/15/21) Bel 53 4,839' 4,859' 2,202’ 2,211’ 20' 1/10.20 Squeezed (2/15/21) Bel 53 4,863' 4,883' 2,213’ 2,222’ 20' 1/10/2020 Squeezed (2/15/21) Bel 53 4,883' 4,903' 2,222’ 2,231’ 20' 1/9/2020 Squeezed (2/15/21) BEL_56 5,083' 5,096' 2,316' 2,322' 13' 4/24/1931 Open BEL_58U 5,151' 5,161' 2,351' 2,356' 10' 9/19/2021 Open BEL_58L 5,166' 5,176' 2,359' 2,364' 10' 9/19/2021 Open BEL_58A 5,215' 5,242' 2,384' 2,399' 27' 4/24/2021 Open BEL_60 5,394' 5,414' 2,487' 2,499' 20' 4/23/2021 Open BEL_74U 5,673' 5,678' 2,665' 2,668' 5' 4/23/2021 Open BEL_74L 5,685' 5,691' 2,673' 2,677' 6' 4/10/2021 Open BEL_82L 5,840' 5,846' 2,783' 2,787' 6' 4/10/2021 Open Superseded 2,356' 10' 9/19/2021 Open 364' 10' 9/19/2021 Open BEL_58U 5,151' 5,161' 2,351' BEL_58L 5,166' 5,176' 2,359' 2 p_ 4,362' 4,372' 2,005' 2,008' 10' 9/21/2021 Open ,428' 4,451' 2,029' 2,038' 23' 9/21/2021 Open 18' 4,543' 2,065' 2,076' 25' 9/20/2021 Open ' 4,582' 2,090' 2,092' 5' 9/20/2021 Open 4,650' 2,117' 2,121' 8' 9/20/2021 Open 4,679' 2,124' 2,133' 22' 9/19/2021 Open L_49U BEL_49L 4 BEL_50 4,5 BEL_51 4,577 BEL_52U 4,642' BEL_52U 4,657' BE 02' 1,792' 1,808' 57' 9/22/2021 Open 3,773' 1,825' 1,828' 8' 9/21/2021 Open 3,857' 1,845' 1,852' 25' 9/21/2021 Open 3,881' 1,857' 1,859' 9' 9/21/2021 Open 8' 3,936' 1,873' 1,875' 8' 9/22/2021 Open 947' 3,956' 1,878' 1,881' 9' 9/22/2021 Open 3,979' 3,989' 1,887' 1,890' 10' 9/21/2021 Open BEL_41U 3,645' 3,7 BEL_43 3,765' BEL_44 3,832' BEL_45 3,872 BEL_45 3,92 BEL_45 3 EL_46U B Rig Start Date End Date SL 9/18/21 Future 09/22/2021 - Wednesday PTW, JSA with crews. Pick injector head and make up lubricator. Make up guns and pt stack 250/2,500 psi. RIH with 1- 11/16" GG, 1-11/16" SS and 31' of 2-3/8" 5spf 60 degree phasing perf guns. Perforate BEL_41u from 3,645' - 3,676'. Good indication of guns firing. POOH. RIH with 1-11/16" GPT, 1-11/16" SS and 25' of 2" 6 spf 60 degree phasing perf guns. Log GPT down to 5,860' (did not tag). No solid fluid level noted. Perforate BEL_41L from 3,677'-3,702'. Good indication of guns firing. POOH. MU and RIH with 1-11/16" GG, 1-11/16" SS and 8' + 9+ of 2" 6 spf 60 degree phasing perf guns. Log tie-in correlation pass. Perforate BEL_45L and BEL_45m sand from 3,947' - 3,956' and 3,928' - 3,936'. Good indication of guns firing in both instances. POOH. OOH. Lay down guns and begin RDMO. SDFN. 09/20/2021 - Monday PTW, JSA with crews. Pick injector head and make up lubricator. Make up guns and pt stack 250/2,500 psi. RIH WITH 1- 11/16" GG, 1-11/16" SS AND 5' & 8' OF 2-3/8" RAZOR 5/60, GUN 4 PERFS - 4,642'-4,650', 17' FROM CCL TO TOP SHOT, GUN 4 CCL DEPTH = 4,625', GUN 5 PERFS BEL_51 - 4,577'-4,582', 10.5' FROM CCL TO TOP SHOT, GUN 5 CCL DEPTH = 4,566.5', BULL PLUG WET. Petrospec E coil shorted out on rope socket. Re head. 2 hrs NPT. RIH WITH 1-11/16" GG, 1- 11/16" SS and 25' (GUN 6) of 2-3/8" 5/60 RAZOR, , BEL_50 - PERF DEPTH = 4,518'-4,543', 12' FROM CCL TO TOP SHOT, CCL DEPTH = 4,506', SHOT - POOH - BULL PLUG. RIH WITH 1-11/16" GPT, 1-11/16" SS and 23' of 2-3/8" 5/60 RAZOR, LOGGED DOWN TO 5,887', BEL_49L - PERF DEPTH = 4,428'-4,451', 14.5' FROM CCL TO TOP SHOT, CCL DEPTH = 4,413.5' - SHOT - POOH. Stack down lubricator. SDFN. 09/19/2021 - Sunday PTW, JSA with crew. Spotted guns in cellar. Picked injector head ands stab lubricator. Rigged up on Petrospec E coil with 1-11/16" GPT, 1-11/16" SS and 22' of 2-3/8" 5/60 razor charges, Logged downt o 5,887'. 15' CCL to top shot. Park Coil at ccl depth 4,642'. Shoot BEL 52U from 4,657'-4,679'. POOH to surface. Made up next gun run. RIH to 1,589' and Petrospec E coil pulled out of rope socket. POOH . Re head E coil. 2 hours NPT. Run in hole with 2x 10' 2-3/8" guns loaded with Razor 5/60 charges. 21' CCL to top shot. Park coil at 5,145' CCL depth. Shoot BEL_58L from 5,166'-5,176'. PU park at 5,141.5' and shoot the BEL_58U from 5,151'-5,161'. POOH to surface. Increase of 280 MCFD@92 psi. Total flow 1357@90. 09/18/2021 - Saturday PTW, JSA. MIRU petrospec CTU 131 with 1.75" E coil. Spot choke skid, return tank. 24 hr BOPE test witness notification sent 9/17/21 @ 16:40. Witness waived via email from Jim Regg 9/17/21 @ 16:45 hrs. Start BOPE test. Perform accumulator draw down. Test BOPE combi 4.06' rams and valves 250/2,500 psi. SDFN. Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 Daily Operations: - PERF DEPTH = 4,518'-4,543', GUN 5 PERFS BEL_51 - 4,577'-4,582', Perforate BEL_41u from 3,645' - 3,676' Shoot BEL_58L from 5,166'-5,176' Missing daily ops report from 9/21/21. Recieved from Hilcorp 12/7/21 and attached. bjm Test BOPE combi 4.06' rams and valves 250/2,500 psi. S Shoot BEL 52U from 4,657'-4,679' - PERF DEPTH = 4,428'-4,451', Perforate BEL_41L from 3,677'-3,702' shoot the BEL_58U from 5,151'-5,161' GUN 4 PERFS - 4,642'-4,650', Perforate BEL_45L and BEL_45m sand from 3,947' - 3,956' and 3,928' - 3,936'. Rig Start Date End Date SL 9/18/21 Future Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 Daily Operations: Arrive at PWL shop start and warm equipment gather tools and crew travel to Paxton. Arrive on location do Permit and JSA - TGSM with Produciton- spot in Equipment. Rig up Slickline. P/T 2500 PSI - PASS- shut in well. RIH/w 2.5" x 5' DD bailer to 5,678' SLM (5,697' RKB with 19' kb) unable to fall anymore possibly due to Deviation. POOH OOH/w nothing in bailer full dry sand. RIH/w 3-1/2" Braided Brush x 4' long to 130' SLM brush to 170'. SLM 20 mins. POOH. OOH. Remove oil Jars. RIH/w 3-1/2" D-1 R/T/w Prong 6' w/ CSV Lock/w SSSV (serial# 001 ) to 100' stop and standby for producton to purge SSSV Control Line then continue to 145' SLM (166' RKB) w/t set test good pressure up to 4.500 psi w/t shear off up holding pressure pooh. OOH. Check TOOLS and Tattle tail good shear, standby for closure - bleed 327 psi down to 150 lose control line pressure sounds like valve came free and hit swab-discuss with Jake- Contact PWL Supervisor. RIH/w 3" JDC/w Prong to hanger set down hard w/t latch w/t POOH OOH/w jdc sheared- repin. RIH/w Same to Hanger unable to get prong inside fishing neck POOH- contact PWL Supervisor. RIH/w 3" JDC to 0' Hanger w/t can not latch POOH. RIH/w 2.65" LIB to hanger w/t 2 times. POOH. OOH/w what looks like an ok fishing neck but can not see one side well. RIH/w 3" JDC to Same w/t can not latch POOH. RIH/w 2.65" LIB to Same w/t impression looks ok. RIH/w 3" Split Skirt JDC to same w/t can not latch ooh egged split skirt getting over the valve. Confer with Jake. Lay down secure area and well for the night. 09/30/2021 - Thursday Arrive on location do Permit and JSA - TGSM- start and warm equipment. Rig up add 10' 4-1/2" LUB section below 3" WLV- add acclerator jars and oil jars to string make up fishing tools P/T lub and wlv 2,500 PSI PASS. RIH/w 2-1/2" RB w/ Baitsub /w 2-1/2" PRGS to top of SSSV set down at 0' Hanger w/t can not latch. POOH. OOH/w Serrated Dogs covered in sand. RIH/w 2-1/2" RB /w bait sub /w 2" Braided brush to hanger w/t fall 2' (length of brush ) brush inside of SSSV. POOH. RIH/w 2-1/2" RB (steel pin) /w bait sub/w 2-1/2" PRGS to 0 ' w/t latch w/t by hand 30 mins can not pull valve start jarring valve with Oil jars 2 licks at 300lbs overpull no movement then 5 at 500lbs overpull each lick moving tools slowly thru tree come free into 4-1/2" LUB. OOH with SSSV heavy damage to the fishing neck and lock, slight swelling on SSSV spring housing- contact PWL Slickline Supervisor and Jake to inform of damage. Rig down clean and secure area and wellhead prep to travel to PWL SHOP. Leave Location. 09/29/2021 - Wednesday Rig Start Date End Date SL 9/18/21 Future Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 Daily Operations: 10/05/2021 - Tuesday Rig up, bad wire test, cut 600' of wire. Check flange bolts. P/T. RIH W/ braided line brush, brush SSSV profile at 166' KB while pumping diesel, POOH, pump a few more gallons. RIH W/ D running tool and 3-1/2" SSSV W/ CS-Lock to 167' KB, W/T, pickup 400#, valve doesn't move shear off, POOH, pressure up valve, running tool tattle tail is sheared. RIH W/ 2.5” BB to 167' KB, tap down several times, POOH. RIH W/ 3' GS and 3 ½ AA-Stop to 167' KB, W/T, POOH stop is set. Stand by for SSSV closure test. Closure test passed, rig down. Crane PTO won't engage, standby for mechanic. Can't get PTO working, leave crane at Paxton, drop SL unit off at KGF, return to PWL shop. Updated by CRR 12/7/21 SCHEMATIC Ninilchik Unit Well: Paxton #9 PTD: 214-173 API: 50-133-20647-00-00 PBTD = 6,458 MD /3,273’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ 9-5/8” cement Job: 12-1/4” hole. 137 bbls of 12.5 Type I lead and 65bbls 15.2# tail. 100% returns with cement to surface 5-1/2” cement job: 8-1/2” hole. 145 bbls of 13.5# class G lead, and 93 bbls of 15.7# class G tail. Full returns throughout job. Volumetric ToC at ~1450’ MD assuming 10% openhole washout. 40 bbls spacer pumped, and 40 bbls back to surface (no cement seen) 3-1/2” Cement Job: 42bbls of 12ppg lead and 18bbls 15.3 tail. No losses throughout job (had losses pre-job). Good lift pressure, but cement must have fallen back after job. (had losses pre-job). Good lift pressure, but cement must have fallen back after job. 2/18/21 Radial CBL: Solid cement up to ~4210’ MD (base BEL_47C squeeze perfs). Patchy cement up to 1850’ MD, free pipe at 890’ MD.Post-squeeze CBL run on 4/7/21 shows new ToC at ~820’MD 1 16” 9-5/8” 8-1/2” Hole 5.5” No. MD TVD ID Item 1 166’166’2.812”SSSV hydraulic nipple (SLB BP-6i)-SLB 3-1/2” WRDP WLSSSV installed 10/5/21 with AA-stop directly above. 2 6,570’ 3,367’Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) from 1/15/15. Tagged at 6586’ CTMD 7/25/20 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16”Conductor 109 / X-56 / Weld Surf 80’ 9-5/8'Surface 40 /L-80 / BTC 8.835”Surf 2,291’ 5-1/2"Production 17 / P-110 / CDC 4.892”Surf 6,723' TUBING DETAIL 3-1/2”Tubing / Scab Liner 9.2# / L-80 / Supermax 2.992”Surf 6,481’ 2 1450’ ToC (volumetric) Perforation Data Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)Ft Date Status Punches 2,401' 2,405' 1,434'1,436'4'3/19/2021 Squeezed (3/31/21) BEL_41U 3,645' 3,676' 1,792' 1,801’31'9/22/2021 Open BEL 41L 3,677 3,702 1,801’1,808'25’9/22/2021 Open BEL_43 3,765' 3,773' 1,825'1,828'8'9/21/2021 Open BEL_44 3,832' 3,857' 1,845'1,852'25'9/21/2021 Open BEL_45 3,872' 3,881' 1,857'1,859'9'9/21/2021 Open BEL_45 3,928' 3,936' 1,873'1,875'8'9/22/2021 Open BEL_45 3,947' 3,956' 1,878'1,881'9'9/22/2021 Open BEL_46U 3,979' 3,989' 1,887'1,890'10'9/21/2021 Open BEL_47A 4,070' 4,082' 1,914'1,917'12'7/28/2020 Squeezed (2/15/21) BEL_47A 4,082' 4,096' 1,917'1,921'14'7/28/2020 Squeezed (2/15/21) BEL_47C 4,179' 4,194' 1,946'1,950'15'7/27/2020 Squeezed (2/15/21) BEL_47C 4,194' 4,209' 1,950'1,955'15'7/26/2020 Squeezed (2/15/21) BEL_49U 4,362' 4,372' 2,005'2,008'10'9/21/2021 Open BEL_49L 4,428' 4,451' 2,029'2,038'23'9/20/2021 Open BEL_50 4,518' 4,543' 2,065'2,076'25'9/20/2021 Open BEL_51 4,577' 4,582' 2,090'2,092'5'9/20/2021 Open BEL_52U 4,642' 4,650' 2,117'2,121'8'9/20/2021 Open BEL_52U 4,657' 4,679' 2,124'2,133'22'9/19/2021 Open BEL_52L 4,707' 4,725' 2,145'2,153'18'4/24/2021 Open Bel 53 4,790' 4,802' 2,181’ 2,186’12'1/13/2015 Squeezed (2/15/21) Bel 53 4,802' 4,822' 2,186’ 2,195’20'4/20/2015 Squeezed (2/15/21) Bel 53 4,819' 4,839' 2,194’ 2,202’20'1/11/2020 Squeezed (2/15/21) Bel 53 4,839' 4,859' 2,202’ 2,211’20'1/10/2020 Squeezed (2/15/21) Bel 53 4,863' 4,883' 2,213’ 2,222’20'1/10/2020 Squeezed (2/15/21) Bel 53 4,883' 4,903' 2,222’ 2,231’20'1/9/2020 Squeezed (2/15/21) BEL_56 5,083' 5,096' 2,316'2,322'13'4/24/2021 Open BEL_58U 5,151' 5,161' 2,351'2,356'10'9/19/2021 Open BEL_58L 5,166' 5,176' 2,359'2,364'10'9/19/2021 Open BEL_58A 5,215' 5,242' 2,384'2,399'27'4/24/2021 Open BEL_60 5,394' 5,414' 2,487'2,499'20'4/23/2021 Open BEL_74U 5,673' 5,678' 2,665'2,668'5'4/23/2021 Open BEL_74L 5,685' 5,691' 2,673'2,677'6'4/10/2021 Open BEL_82L 5,840' 5,846' 2,783'2,787'6'4/10/2021 Open BEL_83 5,870' 5,882' 2,805'2,813'12'4/10/2021 Open Rig Start Date End Date SL 9/18/21 10/5/21 09/22/2021 - Wednesday PTW, JSA with crews. Pick injector head and make up lubricator. Make up guns and pt stack 250/2,500 psi. RIH with 1- 11/16" GG, 1-11/16" SS and 31' of 2-3/8" 5spf 60 degree phasing perf guns. Perforate BEL_41u from 3,645' - 3,676'. Good indication of guns firing. POOH. RIH with 1-11/16" GPT, 1-11/16" SS and 25' of 2" 6 spf 60 degree phasing perf guns. Log GPT down to 5,860' (did not tag). No solid fluid level noted. Perforate BEL_41L from 3,677'-3,702'. Good indication of guns firing. POOH. MU and RIH with 1-11/16" GG, 1-11/16" SS and 8' + 9+ of 2" 6 spf 60 degree phasing perf guns. Log tie-in correlation pass. Perforate BEL_45L and BEL_45m sand from 3,947' - 3,956' and 3,928' - 3,936'. Good indication of guns firing in both instances. POOH. OOH. Lay down guns and begin RDMO. SDFN. 09/20/2021 - Monday PTW, JSA with crews. Pick injector head and make up lubricator. Make up guns and pt stack 250/2,500 psi. RIH WITH 1- 11/16" GG, 1-11/16" SS AND 5' & 8' OF 2-3/8" RAZOR 5/60, GUN 4 PERFS - 4,642'-4,650', 17' FROM CCL TO TOP SHOT, GUN 4 CCL DEPTH = 4,625', GUN 5 PERFS BEL_51 - 4,577'-4,582', 10.5' FROM CCL TO TOP SHOT, GUN 5 CCL DEPTH = 4,566.5', BULL PLUG WET. Petrospec E coil shorted out on rope socket. Re head. 2 hrs NPT. RIH WITH 1-11/16" GG, 1- 11/16" SS and 25' (GUN 6) of 2-3/8" 5/60 RAZOR, , BEL_50 - PERF DEPTH = 4,518'-4,543', 12' FROM CCL TO TOP SHOT, CCL DEPTH = 4,506', SHOT - POOH - BULL PLUG. RIH WITH 1-11/16" GPT, 1-11/16" SS and 23' of 2-3/8" 5/60 RAZOR, LOGGED DOWN TO 5,887', BEL_49L - PERF DEPTH = 4,428'-4,451', 14.5' FROM CCL TO TOP SHOT, CCL DEPTH = 4,413.5' - SHOT - POOH. Stack down lubricator. SDFN. 09/21/2021 -Tuesday RIH WITH 1-11/16" GG, 1-11/16" SS AND 10', 10' & 9' OF 2-3/8" RAZOR 5/60, GUN 8 PERFS - 4362'-4372', 32.5' FROM CCL TO TOP SHOT, GUN 8 CCL DEPTH =4329.5', GUN 9 PERFS - 3979-3989', 21' FROM CCL TO TOP SHOT, GUN 9 CCL DEPTH = 3958', GUN 10 PERFS 3872-3881, 9.5' FROM CCL TO TOP SHOT, GUN 10 CCL DEPTH = 3862.5 POOH - BULL PLUG WET. RIH WITH 1-11/16" GG, 1-11/16" SS AND 25' OF 2-3/8" 5/60, BEL_44 SAND 3832-3857, 10' FROM CCL TO TOP SHOT, CCL DEPTH = 3822', SHOT - POOH - BULL PLUG WET. RIH WITH 1-11/16" GG, 1-11/16" SS AND 8' OF 2-3/8" 5/60, BEL_43 SAND 3765'-3773', 9.5' FROM CCL TO TOP SHOT, CCL DEPTH = 3755.5', SHOT - POOH - BULL PLUG WET. Job Complete. RDMO. 09/19/2021 - Sunday PTW, JSA with crew. Spotted guns in cellar. Picked injector head ands stab lubricator. Rigged up on Petrospec E coil with 1-11/16" GPT, 1-11/16" SS and 22' of 2-3/8" 5/60 razor charges, Logged downt o 5,887'. 15' CCL to top shot. Park Coil at ccl depth 4,642'. Shoot BEL 52U from 4,657'-4,679'. POOH to surface. Made up next gun run. RIH to 1,589' and Petrospec E coil pulled out of rope socket. POOH . Re head E coil. 2 hours NPT. Run in hole with 2x 10' 2-3/8" guns loaded with Razor 5/60 charges. 21' CCL to top shot. Park coil at 5,145' CCL depth. Shoot BEL_58L from 5,166'-5,176'. PU park at 5,141.5' and shoot the BEL_58U from 5,151'-5,161'. POOH to surface. Increase of 280 MCFD@92 psi. Total flow 1357@90. 09/18/2021 - Saturday PTW, JSA. MIRU petrospec CTU 131 with 1.75" E coil. Spot choke skid, return tank. 24 hr BOPE test witness notification sent 9/17/21 @ 16:40. Witness waived via email from Jim Regg 9/17/21 @ 16:45 hrs. Start BOPE test. Perform accumulator draw down. Test BOPE combi 4.06' rams and valves 250/2,500 psi. SDFN. Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 Daily Operations: Rig Start Date End Date SL 9/18/21 10/5/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 Daily Operations: Arrive at PWL shop start and warm equipment gather tools and crew travel to Paxton. Arrive on location do Permit and JSA - TGSM with Produciton- spot in Equipment. Rig up Slickline. P/T 2500 PSI - PASS- shut in well. RIH/w 2.5" x 5' DD bailer to 5,678' SLM (5,697' RKB with 19' kb) unable to fall anymore possibly due to Deviation. POOH OOH/w nothing in bailer full dry sand. RIH/w 3-1/2" Braided Brush x 4' long to 130' SLM brush to 170'. SLM 20 mins. POOH. OOH. Remove oil Jars. RIH/w 3-1/2" D-1 R/T/w Prong 6' w/ CSV Lock/w SSSV (serial# 001 ) to 100' stop and standby for producton to purge SSSV Control Line then continue to 145' SLM (166' RKB) w/t set test good pressure up to 4.500 psi w/t shear off up holding pressure pooh. OOH. Check TOOLS and Tattle tail good shear, standby for closure - bleed 327 psi down to 150 lose control line pressure sounds like valve came free and hit swab-discuss with Jake- Contact PWL Supervisor. RIH/w 3" JDC/w Prong to hanger set down hard w/t latch w/t POOH OOH/w jdc sheared- repin. RIH/w Same to Hanger unable to get prong inside fishing neck POOH- contact PWL Supervisor. RIH/w 3" JDC to 0' Hanger w/t can not latch POOH. RIH/w 2.65" LIB to hanger w/t 2 times. POOH. OOH/w what looks like an ok fishing neck but can not see one side well. RIH/w 3" JDC to Same w/t can not latch POOH. RIH/w 2.65" LIB to Same w/t impression looks ok. RIH/w 3" Split Skirt JDC to same w/t can not latch ooh egged split skirt getting over the valve. Confer with Jake. Lay down secure area and well for the night. 09/30/2021 - Thursday Arrive on location do Permit and JSA - TGSM- start and warm equipment. Rig up add 10' 4-1/2" LUB section below 3" WLV- add acclerator jars and oil jars to string make up fishing tools P/T lub and wlv 2,500 PSI PASS. RIH/w 2-1/2" RB w/ Baitsub /w 2-1/2" PRGS to top of SSSV set down at 0' Hanger w/t can not latch. POOH. OOH/w Serrated Dogs covered in sand. RIH/w 2-1/2" RB /w bait sub /w 2" Braided brush to hanger w/t fall 2' (length of brush ) brush inside of SSSV. POOH. RIH/w 2-1/2" RB (steel pin) /w bait sub/w 2-1/2" PRGS to 0 ' w/t latch w/t by hand 30 mins can not pull valve start jarring valve with Oil jars 2 licks at 300lbs overpull no movement then 5 at 500lbs overpull each lick moving tools slowly thru tree come free into 4-1/2" LUB. OOH with SSSV heavy damage to the fishing neck and lock, slight swelling on SSSV spring housing- contact PWL Slickline Supervisor and Jake to inform of damage. Rig down clean and secure area and wellhead prep to travel to PWL SHOP. Leave Location. 09/29/2021 - Wednesday Rig Start Date End Date SL 9/18/21 10/5/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 Daily Operations: 10/05/2021 - Tuesday Rig up, bad wire test, cut 600' of wire. Check flange bolts. P/T. RIH W/ braided line brush, brush SSSV profile at 166' KB while pumping diesel, POOH, pump a few more gallons. RIH W/ D running tool and 3-1/2" SSSV W/ CS-Lock to 167' KB, W/T, pickup 400#, valve doesn't move shear off, POOH, pressure up valve, running tool tattle tail is sheared. RIH W/ 2.5” BB to 167' KB, tap down several times, POOH. RIH W/ 3' GS and 3 ½ AA-Stop to 167' KB, W/T, POOH stop is set. Stand by for SSSV closure test. Closure test passed, rig down. Crane PTO won't engage, standby for mechanic. Can't get PTO working, leave crane at Paxton, drop SL unit off at KGF, return to PWL shop. 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: 11/1/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL PAXTON 9 (PTD 214-173) GPT/PERF 09/19/2021 Please include current contact information if different from above. 11/01/2021 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: _N2 / Patch__ 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/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 6,733'6570' Casing Collapse Structural Conductor Surface 3,090 psi Intermediate Production 7,480 psi Liner 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 Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 Date: Conditions of approval: Notify Commission 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 COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: September 9, 2021 3-1/2" 6,726' Perforation Depth MD (ft): See Attached Schematic 6,726' 3,495'5-1/2" 16" 9-5/8" 80' 2,269'5,750 psi1,401' 80' 2,291' 9.2# / L-80 TVD Burst 6,481' 10,640 psi MDLength Size CO 701C Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0384372 / FEE-PRIVATE 214-173 50-133-20647-00-00 Paxton 09 Ninilchik Field / BELUGA-TYONEK GAS Pool COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): See Attached Schematic ryan.rupert @hilcorp.com 3,503'6,458'3,273'~985 psi none N/A; SLB hydraulic landing nipple w/ WRDP WLSSSV installed N/A; 166' MD / 166' TVD Perforation Depth TVD (ft): Tubing Size: Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:46 am, Sep 01, 2021 321-439 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.08.31 09:56:15 -08'00' Taylor Wellman (2143) BJM 9/9/21 X CT SFD 9/1/2021 10-404 DSR-9/9/21 BOP test to 2500 psi dts 9/9/2021 JLC 9/10/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.09.10 15:05:15 -08'00' RBDMS HEW 9/13/2021 Well Prognosis Well: Paxton-09 Date: 8/30/2021 Well Name:Paxton-09 API Number:50-133-20647-00-00 Current Status:Gas Producer Leg:N/A Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:214-173 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (C) Second Call Engineer:Jake Flora (907) 777-8442 (O)(720) 988-5375 (C) Maximum Expected BHP:~ 1266 psi @ 2,813’ TVD (Based on a 0.45 psi/ft gradient from deepest open sand: BEL-83) Max. Potential Surface Pressure:~ 985 psi Using Max BHP minus 0.1 psi/ft. gas gradient to surface). Well Summary Paxton had a RWO for recomplete in March-2021. After several remedial interventions, the well had the last of it’s current perfs added in late-April 2021. The well came on at rates above 1.4MM, and has since slowly declined to its current rate of 925mcfd. There’s more perf opportunity uphole. The purpose of this work is to add perfs to increase production from Paxton-09 Notes Regarding Wellbore Condition x Inclination o Well goes >70 degrees inclination at ~1400’ MD o Sail angle of 75 degrees from 1400’ - 4000’ MD where it starts to turn vertical again, and ends up at <35 degrees at PBTD. x Mechanical history o 4/29/21: SL set WLSSSV in hydraulic nipple at 166’ MD o 4/24/21: e-coil shot final 3 zones with 2-3/8” guns down to 5400’ MD. No solids noted o 4/23/21: e-coil shot 2 zones while flowing with 2-3/8” guns. Made it down to 5770’ MD before shooting. BEL-60 gun came back oozing thick mud. o 4/12/21: SL successfully fished all EL tractor BHA o 4/10/21: EL tractor shot bottom 3 zones. Got stuck on way OOH at 2880’ MD, and left fish downhole o 3/31/21: Remedial IA squeeze performed via punches at 2401’ – 2405’ MD o February-2021: 3-1/2” tubing run and cemented in place Risks x Nitrogen o Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. o Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) o Ensure all crews are aware of stop work authority SFD 9/1/2021 Proposed perforations fall within the Beluga/Tyonek Gas Pool as defined in CO 701C. Well Prognosis Well: Paxton-09 Date: 8/30/2021 SL procedure 1. MIRU SL 2. Pull WRDP WL-SSSV from hydraulic profile at 166’ 3. Drift to deviation with a 2.70” gauge ring 4. RDMO SL Note: well can flow without an SSSV for no more than 14 days once removed e-Coil Procedure 1. MIRU Petrospec e-coil 2. Perform BOP test to 250psi low / 2500 high (notify AOGCC 24hrs in advance) 3. RU E-Line Data Acquisition Unit 4. MU GPT 5. RIH and log flowing GPT looking for FL. 6. Obtain a light tag of PBTD regardless of FL depth 7. Obtain an upward 30fpm flowing pass from 5925’ – 4675’ (across all perfs). POOH 8. RU perf guns. Likely 2” – 2-3/8” guns with 4-6 spf 9. RIH and perforate the below intervals per Geo/RE: Sand MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) BEL_41U ±3,639’±3,705’±1,790’±1,808’66’ BEL_41L ±3,713’±3,731’±1,811’±1,816’18’ BEL_43 ±3,765’±3,774’±1,825’±1,828’9’ BEL_44 ±3,831’±3,862’±1,845’±1,854’31’ BEL_45 ±3,871’±3,881’±1,856’±1,859’10’ BEL_45 ±3,924’±3,937’±1,872’±1,875’13’ BEL_45 ±3,945’±3,958’±1,878’±1,881’13’ BEL_46U ±3,975’±3,989’±1,886’±1,890’14’ BEL_46L ±4,005’±4,020’±1,895’±1,899’15’ BEL_47 ±4,065’±4,095’±1,912’±1,921’30’ BEL_48 ±4,172’±4,236’±1,944’±1,963’64’ BEL_49U ±4,358’±4,375’±2,003’±2,009’17’ BEL_49L ±4,426’±4,449’±2,029’±2,037’23’ BEL_50 ±4,517’±4,551’±2,065’±2,079’34’ BEL_51 ±4,574’±4,586’±2,089’±2,094’12’ BEL_52U ±4,640’±4,684’±2,116’±2,135’44’ BEL_58U ±5,151’±5,161’±2,351 ±2,356 10’ BEL_58L ±5,166’±5,177’±2,359 ±2,364’11’ Well Prognosis Well: Paxton-09 Date: 8/30/2021 Consult with OE for what WHP’s to use. May be shot while flowing Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a.Use Gamma/CCL to correlate. b. Record initial and 5/10/15 minute tubing pressures after firing c. Consult with RE/Geo between each perf interval: i. Matt Petrowsky (Geo): 814-421-6753 ii. Anthony McConkey (RE): 529-6199 10. Once sufficient production has been added per RE/Geo, RD E-Line Unit and Coiled Tubing Unit and turn well over to production. SL procedure 1. MIRU SL 2. Set WRDP WL-SSSV in hydraulic profile at 166’ 3. RDMO SL Note: The WLSSSV must be installed no more than 14 days after the well is brought back into service, and tested no later than 5 days after installation. Contingency e-Coil Plug or Patch 1. MIRU Petrospec e-coil 2. Perform BOP test to 250psi low / 3500 high (notify AOGCC 24hrs in advance) 3. RU E-Line Data Acquisition Unit 4. RIH W/ GPT tool and find fluid level 5. RU Nitrogen Truck a. Push water back into formation b. Use GPT tool to confirm water level is below interval to perf c. Consult OE for pressure to leave on well for perforating 6. Once fluid level is below interval to isolate, MU 3-1/2” patch or plug 7. RIH and set plug or patch per OE. 8. RD E-Line Unit and Coiled Tubing Unit and turn well over to production. Attachments: 1. Current schematic 2. Proposed Schematic 3. Standard Well procedure – N2 Operations Updated by CRR 4-29-2021 SCHEMATIC Ninilchik Unit Well: Paxton #9 PTD:214-173 API: 50-133-20647-00-00 PBTD = 6,458 MD /3,273’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ 9-5/8” cement Job: 12-1/4” hole. 137 bbls of 12.5 Type I lead and 65bbls 15.2# tail. 100% returns with cement to surface 5-1/2” cement job: 8-1/2” hole. 145 bbls of 13.5# class G lead, and 93 bbls of 15.7# class G tail. Full returns throughout job. Volumetric ToC at ~1450’ MD assuming 10% openhole washout. 40 bbls spacer pumped, and 40 bbls back to surface (no cement seen) 3-1/2” Cement Job: 42bbls of 12ppg lead and 18bbls 15.3 tail. No losses throughout job (had losses pre-job). Good lift pressure, but cement must have fallen back after job. (had losses pre-job). Good lift pressure, but cement must have fallen back after job. 2/18/21 Radial CBL:Solid cement up to ~4210’ MD (base BEL_47C squeeze perfs). Patchy cement up to 1850’ MD, free pipe at 890’ MD.Post-squeeze CBL run on 4/7/21 shows new ToC at ~820’MD 1 16” 9-5/8” 8-1/2” Hole 5.5” No.MD TVD ID Item 1 166’166’2.812”SSSV hydraulic nipple (SLB BP-6i)-SLB 3-1/2” WRDP WLSSSV installed 4/29/21 2 6570’Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) from 1/15/15. Tagged at 6586’ CTMD 7/25/20 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)Ft Date Status Punches 2401’2405’4 3/19/21 Squeezed (3/31/21) BEL_47A 4,070'4,082'1,914'1,917'12'7/28/20 Squeezed (2/15/21) BEL_47A 4,082'4,096'1,917'1,921'14'7/28/20 Squeezed (2/15/21) BEL_47C 4,179'4,194'1,946'1,950'15'7/27/20 Squeezed (2/15/21) BEL_47C 4,194'4,209'1,950'1,955'15'7/26/20 Squeezed (2/15/21) BEL_52L 4,707'4,725'2,145'2,153'18'4/24/21 Open Bel 53 4,790’4,802’2,181’2,186’12 1/13/15 Squeezed (2/15/21) Bel 53 4,802’4,822’2,186’2,195’20 4/20/15 Squeezed (2/15/21) Bel 53 4,819’4,839’2,194’2,202’20 1/11/20 Squeezed (2/15/21) Bel 53 4,839’4,859’2,202’2,211’20 1/10.20 Squeezed (2/15/21) Bel 53 4,863’4,883’2,213’2,222’20 1/10/20 Squeezed (2/15/21) Bel 53 4,883’4,903’2,222’2,231’20 1/9/20 Squeezed (2/15/21) BEL_56 5,083'5,096'2,316'2,322'13'4/24/31 Open BEL_58A 5,215 5,242’2,384'2,399'27'4/24/21 Open BEL_60 5,394'5,414'2,487'2,499'20’4/23/21 Open BEL_74U 5,673'5,678'2,665'2,668'5’4/23/21 Open BEL_74L 5,685'5,691'2,673'2,677'6’4/10/21 Open BEL_82L 5,840'5,846'2,783'2,787'6’4/10/21 Open BEL_83 5,870'5,882'2,805'2,813'12’4/10/21 Open CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16”Conductor 109 / X-56 / Weld Surf 80’ 9-5/8'Surface 40 /L-80 / BTC 8.835”Surf 2,291’ 5-1/2"Production 17 / P-110 / CDC 4.892”Surf 6,723' TUBING DETAIL 3-1/2”Tubing / Scab Liner 9.2# / L-80 / Supermax 2.992” Surf 6,481’ 2 1450’ ToC (volumetric) Updated by CRR 4-29-2021 SCHEMATIC Ninilchik Unit Well: Paxton #9 PTD:214-173 API: 50-133-20647-00-00 PBTD = 6,458 MD /3,273’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ 9-5/8” cement Job: 12-1/4” hole. 137 bbls of 12.5 Type I lead and 65bbls 15.2# tail. 100% returns with cement to surface 5-1/2” cement job: 8-1/2” hole. 145 bbls of 13.5# class G lead, and 93 bbls of 15.7# class G tail. Full returns throughout job. Volumetric ToC at ~1450’ MD assuming 10% openhole washout. 40 bbls spacer pumped, and 40 bbls back to surface (no cement seen) 3-1/2” Cement Job: 42bbls of 12ppg lead and 18bbls 15.3 tail. No losses throughout job (had losses pre-job). Good lift pressure, but cement must have fallen back after job. (had losses pre-job). Good lift pressure, but cement must have fallen back after job. 2/18/21 Radial CBL:Solid cement up to ~4210’ MD (base BEL_47C squeeze perfs). Patchy cement up to 1850’ MD, free pipe at 890’ MD.Post-squeeze CBL run on 4/7/21 shows new ToC at ~820’MD 1 16” 9-5/8” 8-1/2” Hole 5.5” No.MD TVD ID Item 1 166’166’2.812”SSSV hydraulic nipple (SLB BP-6i)-SLB 3-1/2” WRDP WLSSSV installed 4/29/21 2 6570’Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) from 1/15/15. Tagged at 6586’ CTMD 7/25/20 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)Ft Date Status Punches 2401’2405’4 3/19/21 Squeezed (3/31/21) BEL_47A 4,070'4,082'1,914'1,917'12'7/28/20 Squeezed (2/15/21) BEL_47A 4,082'4,096'1,917'1,921'14'7/28/20 Squeezed (2/15/21) BEL_47C 4,179'4,194'1,946'1,950'15'7/27/20 Squeezed (2/15/21) BEL_47C 4,194'4,209'1,950'1,955'15'7/26/20 Squeezed (2/15/21) Perfs per Sundry BEL_52L 4,707'4,725'2,145'2,153'18'4/24/21 Open Bel 53 4,790’4,802’2,181’2,186’12 1/13/15 Squeezed (2/15/21) Bel 53 4,802’4,822’2,186’2,195’20 4/20/15 Squeezed (2/15/21) Bel 53 4,819’4,839’2,194’2,202’20 1/11/20 Squeezed (2/15/21) Bel 53 4,839’4,859’2,202’2,211’20 1/10.20 Squeezed (2/15/21) Bel 53 4,863’4,883’2,213’2,222’20 1/10/20 Squeezed (2/15/21) Bel 53 4,883’4,903’2,222’2,231’20 1/9/20 Squeezed (2/15/21) BEL_56 5,083'5,096'2,316'2,322'13'4/24/31 Open BEL_58A 5,215 5,242’2,384'2,399'27'4/24/21 Open BEL_60 5,394'5,414'2,487'2,499'20’4/23/21 Open BEL_74U 5,673'5,678'2,665'2,668'5’4/23/21 Open BEL_74L 5,685'5,691'2,673'2,677'6’4/10/21 Open BEL_82L 5,840'5,846'2,783'2,787'6’4/10/21 Open BEL_83 5,870'5,882'2,805'2,813'12’4/10/21 Open CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16”Conductor 109 / X-56 / Weld Surf 80’ 9-5/8'Surface 40 /L-80 / BTC 8.835”Surf 2,291’ 5-1/2"Production 17 / P-110 / CDC 4.892”Surf 6,723' TUBING DETAIL 3-1/2”Tubing / Scab Liner 9.2# / L-80 / Supermax 2.992” Surf 6,481’ 2 1450’ ToC (volumetric) 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. 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: __Cap String__ 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/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 6,733'6570' Casing Collapse Structural Conductor Surface 3,090 psi Intermediate Production 7,480 psi Liner 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 Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 Date: Conditions of approval: Notify Commission 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 COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng ryan.rupert@hilcorp.com 3,503'6,458'3,273'~983 psi none N/A; SLB hydraulic landing nipple w/ WRDP WLSSSV installed N/A; 166' MD / 166' TVD Perforation Depth TVD (ft):Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0384372 / FEE-PRIVATE 214-173 50-133-20647-00-00 Paxton 09 Ninilchik Field / BELUGA-TYONEK GAS Pool Length Size CO 701C Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 9.2# / L-80 TVD Burst 6,481' 10,640 psi MD 5,750 psi1,401' 80' 2,291' 3,495'5-1/2" 16" 9-5/8" 80' 2,269' 6,726' Perforation Depth MD (ft): See Attached Schematic 6,726' Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: May 5, 2021 3-1/2" m n P t 66 Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 10:12 am, Jun 14, 2021 321-220 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.04.30 09:55:34 -08'00' Taylor Wellman (2143) DSR-6/14/21SFD 6/14/2021BJM 6/14/21 10-404 dts 6/15/2021 JLC 6/15/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.06.15 10:57:12 -08'00' RBDMS HEW 6/16/2021 Well Prognosis Well: Paxton-09 Date: 4/30/2021 Well Name:Paxton-09 API Number:50-133-20647-00 Current Status:Producing Gas Well Leg:N/A Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:214-713 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (M) Second Call Engineer:Ted Kramer (907) 777-8420 (O)(985) 867-0665 (M) Max. Expected BHP:~ 1,264 psi @ 2,809’ TVD 0.45 psi/ft. gradient from T-83 perfs Max. Potential Surface Pressure:~ 983 psi Based on max BHP less gas gradient @ 0.1psi/ft. Brief Well Summary Paxton-09 had a RWO completed in early 2021 to install a 3-1/2” scab liner and allow for recompletion of lower sands. Thewell came online in late April and IP’d at ~3MMscfd, but quickly began to decline and slug. It’s believed that water buildup may be the cause. The purpose of this work/sundry is to install a Capillary String in the well to allow for soap to be injected to help unload water. Base plan will be to run it to just above top perf, but deviation may force us to stop shallower. TBD. The WLSSSV will need to be pulled for this operation, and will remain out of hole per 20 AAC 25.265.d.4. Notes Regarding Wellbore Condition x E-coil perf’d upper zones with 2-3/8” guns on 4/21/21 x SL able to fall down to 2860’ MD and latch tractor assembly. x Inclination o Well goes > 70deg inclination at ~1350’ MD o Sail angle of ~75 from 1350’ – 4200’ MD, then rolls over to 35 degrees by PBTD Procedure: 1. RU SL and pull WLSSSV from166’ MD 2. RU Cap String Truck. 3. Stab 3/8” capillary line into wellhead pack-off assembly. Make up BHA components. Install pack-off and pressure test against swab valve 250 psi low/3,000 psi high. 4. RIH with 3/8” capillary string to ±4650’ MD, or as far as we can make it 5. Install slips and connect tubing to chemical injection pump. 6. Set spool of remaining line near well 7. RD cap string Unit, and turn well over to production. Attachments: 1. Proposed Schematic Updated by CRR 4-30-2021 SCHEMATIC Ninilchik Unit Well: Paxton #9 PTD:214-173 API: 50-133-20647-00-00 PBTD = 6,458 MD /3,273’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ 9-5/8” cement Job: 12-1/4” hole. 137 bbls of 12.5 Type I lead and 65bbls 15.2# tail. 100% returns with cement to surface 5-1/2” cement job: 8-1/2” hole. 145 bbls of 13.5# class G lead, and 93 bbls of 15.7# class G tail. Full returns throughout job. Volumetric ToC at ~1450’ MD assuming 10% openhole washout. 40 bbls spacer pumped, and 40 bbls back to surface (no cement seen) 3-1/2” Cement Job: 42bbls of 12ppg lead and 18bbls 15.3 tail. No losses throughout job (had losses pre-job). Good lift pressure, but cement must have fallen back after job. (had losses pre-job). Good lift pressure, but cement must have fallen back after job. 2/18/21 Radial CBL:Solid cement up to ~4210’ MD (base BEL_47C squeeze perfs). Patchy cement up to 1850’ MD, free pipe at 890’ MD.Post-squeeze CBL run on 4/7/21 shows new ToC at ~820’MD 1 16” 9-5/8” 8-1/2” Hole 5.5” No.MD TVD ID Item 1 166’166’2.812”SSSV hydraulic nipple (SLB BP-6i)- SLB 3-1/2” WRDP WLSSSV installed 4/29/21 (to be removed) 2 6570’Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) from 1/15/15. Tagged at 6586’ CTMD 7/25/20 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)Ft Date Status Punches 2401’2405’4 3/19/21 Squeezed (3/31/21) BEL_47A 4,070'4,082'1,914'1,917'12'7/28/20 Squeezed (2/15/21) BEL_47A 4,082'4,096'1,917'1,921'14'7/28/20 Squeezed (2/15/21) BEL_47C 4,179'4,194'1,946'1,950'15'7/27/20 Squeezed (2/15/21) BEL_47C 4,194'4,209'1,950'1,955'15'7/26/20 Squeezed (2/15/21) BEL_52L 4,707'4,725'2,145'2,153'18'4/21/21 Open Bel 53 4,790’4,802’2,181’2,186’12 1/13/15 Squeezed (2/15/21) Bel 53 4,802’4,822’2,186’2,195’20 4/20/15 Squeezed (2/15/21) Bel 53 4,819’4,839’2,194’2,202’20 1/11/20 Squeezed (2/15/21) Bel 53 4,839’4,859’2,202’2,211’20 1/10.20 Squeezed (2/15/21) Bel 53 4,863’4,883’2,213’2,222’20 1/10/20 Squeezed (2/15/21) Bel 53 4,883’4,903’2,222’2,231’20 1/9/20 Squeezed (2/15/21) BEL_56 5,083'5,096'2,316'2,322'13'4/24/31 Open BEL_58A 5,215 5,242’2,384'2,399'27'4/24/21 Open BEL_60 5,394'5,414'2,487'2,499'20’4/23/21 Open BEL_74U 5,673'5,678'2,665'2,668'5’4/23/21 Open BEL_74L 5,685'5,691'2,673'2,677'6’4/10/21 Open BEL_82L 5,840'5,846'2,783'2,787'6’4/10/21 Open BEL_83 5,870'5,882'2,805'2,813'12’4/10/21 Open CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16”Conductor 109 / X-56 / Weld Surf 80’ 9-5/8'Surface 40 /L-80 / BTC 8.835”Surf 2,291’ 5-1/2"Production 17 / P-110 / CDC 4.892”Surf 6,723' TUBING DETAIL 3-1/2”Tubing / Scab Liner 9.2# / L-80 / Supermax 2.992” Surf 6,481’ 2 1450’ ToC (volumetric) Capillary String (3/8”) to be installed Top Bottom MD 0’ 4,650’ TVD 0’ 2,120’ David Douglas Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: Hilcorp North Slope, LLC Date: 05/27/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Logging Company KALOTSA 1 50133206570000 216132 3/27/2021 SET PATCH/GAMMA RAY Yellowjacket KALOTSA 1 50133206570000 216132 4/23/2021 PERF GAMMA RAY / GPT Yellowjacket KALOTSA 2 50133206590000 216155 4/10/2021 PERF GAMMA RAY Yellowjacket PAXTON 2 50133205730000 207164 2/23/2021 PERF GAMMA RAY Yellowjacket PAXTON 9 50133206470000 214173 3/19/2021 PERF GAMMA RAY Yellowjacket PAXTON 9 50133206470000 214173 4/10/2021 PERF GAMMA RAY Yellowjacket PAXTON 9 50133206470000 216132 4/23/2021 PERF GAMMA RAY Yellowjacket PAXTON 10 50133206910000 220064 4/13/2021 SET WRP / CCL Yellowjacket PAXTON 10 50133206910000 220064 4/20/2021 SET WRP / CCL Yellowjacket SD-1A 50133100020100 185208 4/27/2021 PERF GAMMA RAY / GPT Yellowjacket Please include current contact information if different from above. PTD: 2141730 E-Set: 35207 06/02/2021 David Douglas Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: Hilcorp North Slope, LLC Date: 05/27/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Logging Company KALOTSA 1 50133206570000 216132 3/27/2021 SET PATCH/GAMMA RAY Yellowjacket KALOTSA 1 50133206570000 216132 4/23/2021 PERF GAMMA RAY / GPT Yellowjacket KALOTSA 2 50133206590000 216155 4/10/2021 PERF GAMMA RAY Yellowjacket PAXTON 2 50133205730000 207164 2/23/2021 PERF GAMMA RAY Yellowjacket PAXTON 9 50133206470000 214173 3/19/2021 PERF GAMMA RAY Yellowjacket PAXTON 9 50133206470000 214173 4/10/2021 PERF GAMMA RAY Yellowjacket PAXTON 9 50133206470000 216132 4/23/2021 PERF GAMMA RAY Yellowjacket PAXTON 10 50133206910000 220064 4/13/2021 SET WRP / CCL Yellowjacket PAXTON 10 50133206910000 220064 4/20/2021 SET WRP / CCL Yellowjacket SD-1A 50133100020100 185208 4/27/2021 PERF GAMMA RAY / GPT Yellowjacket Please include current contact information if different from above. PTD: 2141730 E-Set: 35206 06/02/2021 David Douglas Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: Hilcorp North Slope, LLC Date: 05/27/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Logging Company KALOTSA 1 50133206570000 216132 3/27/2021 SET PATCH/GAMMA RAY Yellowjacket KALOTSA 1 50133206570000 216132 4/23/2021 PERF GAMMA RAY / GPT Yellowjacket KALOTSA 2 50133206590000 216155 4/10/2021 PERF GAMMA RAY Yellowjacket PAXTON 2 50133205730000 207164 2/23/2021 PERF GAMMA RAY Yellowjacket PAXTON 9 50133206470000 214173 3/19/2021 PERF GAMMA RAY Yellowjacket PAXTON 9 50133206470000 214173 4/10/2021 PERF GAMMA RAY Yellowjacket PAXTON 9 50133206470000 216132 4/23/2021 PERF GAMMA RAY Yellowjacket PAXTON 10 50133206910000 220064 4/13/2021 SET WRP / CCL Yellowjacket PAXTON 10 50133206910000 220064 4/20/2021 SET WRP / CCL Yellowjacket SD-1A 50133100020100 185208 4/27/2021 PERF GAMMA RAY / GPT Yellowjacket Please include current contact information if different from above. PTD: 2141730 E-Set: 35205 06/02/2021 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: N2 / Cement Packer Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 6,733 feet N/A feet true vertical 3,503 feet 6,570 feet Effective Depth measured 6,458 feet N/A feet true vertical 3,273 feet N/A feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)3-1/2" 9.2# / L-80 6,481' MD 3,293' TVD N/A; SLB SCSSSV Packers and SSSV (type, measured and true vertical depth)Hydraulic Landing Nipple 166' MD 166' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 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: Taylor Wellman 777-8449 Contact Name:Ryan Rupert Authorized Title:Operations Manager Contact Email: Contact Phone:777-8443 WINJ WAG 51 Water-Bbl MD 80' 2,291' 0 Oil-Bbl measured true vertical Packer 5-1/2"6,726'3,495' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Ninilchik Field / Beluga-Tyonek Gas PoolN/A measured TVD Tubing Pressure 8332 NINILCHIK UNIT PAXTON 9 N/A ADL0384372 / FEE-PRIVATE Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 214-173 50-133-20647-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-035 & 321-127 81 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 0 Authorized Signature with date: Authorized Name: 590 Casing Pressure Liner 1,272 0 Representative Daily Average Production or Injection Data 80' 2,269' 6,726' Conductor Surface Intermediate Production 7,480psi Casing Structural 16" 9-5/8" Length 5,750psi Collapse 3,090psi ryan.rupert@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 10,640psi 80' 1,401' t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 7:47 am, May 24, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.05.21 16:30:40 -08'00' Taylor Wellman (2143) RBDMS HEW 6/10/2021 BJM 9/27/21 SFD 5/26/2021DSR-5/24/21 Rig Start Date End Date 1/31/21 4/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 02/01/2021 - Monday Safety meeting with crew, emphasis on cold weather, heating MGS, upcoming E-Line ops. Check equipment and fuel. SIMOPS: crew cleaning off herculite on Paxton 2, reset grating over well, clean berms and bumps. Line up for circulation. Open to tubing, initial pressure of 125 psi bled right off to 0 psi. Line up to IA, opened up and initial pressure of 300 psi dropped off to 0 psi. No gas from either. Fill tubing with 8.4 ppg source water. SIMOPS: E-Line crew getting rigged up for ops. PT lubricator to 2,500 psi. RIH with tbg punch and CCL BHA. Move to ~1,500 with no pumps. Have to pump down at 2 bpm to get to area of interest, initial 350 psi, fell off to 7 psi with BHA at bottom. Sent notice to AOGCC at 1000 hrs. Log lower jewelry, set punch on depth for shot interval at 3,375' - 3,378'. POH with BHA, sudden weight loss at 155', area of CI sub / SSSV. Notify town, mobilize fishing tool. Pull E-li ne to surface, parted at rope socket. Rig up new rope socket and most of fishing BHA - roller boagie, jars, roller boagie, CCL - and wait on fishing overshot. Pick up lubricator and hang BHA off while waiting on last component. Complete making up BHA, stab on with lubricator, RIH. Tag up at level of SSSV. Can't move down. Call Field Operator, possibly partially closed SSSV. Pump open, gas to surface, vent and close in. RU additional lubricator. RIH with fishing BHA. Run all the way on boagie rollers without pumping to 3,395', tag up on fish. Latch, POH to surface. Pump to confirm communication with annulus, circulate 33 bbls to catch returns. Pop off with lubricator,. MU BHA to run CIBP. Stab on with lubricator, RIH, set CIBP at 3,460'. POH, pop off and lay down BHA. MU RCT BHA. While crew is MU BHA, pressure test against CIBP to 1,500 psi, held tight. Stab on with lubricator. RIH to 1,300', can't make progress. Pump down at 1.5 bpm to 3,370' md, make cut. Attempt to POH, tool stuck at cut. Blow down circulation lines while crews works to get free, POH, pop off and LD BHA. Close in tree valves to secure well. Turn location over to Night Watch. Crew continue to RD E-line unit. 01/31/2021 - Sunday Safety Meeting with crew, emphasis on rigging down for move and on process for spooling line back on to drum. Check equipment, rearrange light plant. Place Koomie hoses in basket, secure hose bundle. Re-spool drilling line. Scope down derrick. Staging equipment over on Paxton 9. Lay out herculite, stage in equipment. Move in Carrier, begin rigging up. Raise derrick, install valves on tree, connect flow lines, set out heater trunks. 270 psi on tubing, 900 psi on IA. Turn over to Night Watch crew. Filled pits, cleaned off herculite on old location. set punch on depth for shot interval at 3,375' - 3,378' set CIBP at 3,460' o 3,370' md, make cut. Rig Start Date End Date 1/31/21 4/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 Safety meeting with crew, emphasis on cold weather, ND and NU operations, controlling pressure. Check equipment, prep for tree work. Open to well, no pressure. Install BPV. Remove rig floor. ND Tree. Terminate corrosion injection and SSSV control lines. NU 13-5/8" BOP stack: 13-5/8" Annular, 2-7/8" x 5-1/2" Variable Rams, Blind rams. Move in racking mat, install rig floor and skirting around BOP. Test all alarms. Function test Accumulator, attempt to shell test BOP. Pressure up but bled off twice, third test good. Attempt to begin test 1 of BOP test, line frozen somewhere. Troubleshoot, line from rig floor to test chart recorder frozen. Thaw, able to circulate. Delay BOP test due to timing and road conditions - test will take 3-4 hrs and road conditions have deteriorated drastically throughout day. Team has hour travel each way. Blow down circulation lines, ensure that cellar windwalls are secured tightly around cellar and test joint and place additional trunk in cellar. Pull 1/2" test hose and place into choke unit to keep thawed. Turn location over to Night Watch. They will monitor heaters and clear snow. 02/02/2021 - Tuesday 02/03/2021 - Wednesday PTSM, Blow through surface linesw, good, r/u test lines. Test BOP as per Hilcorp & AOGCC requirements, AOGCC witness waived by Jim Regg on 2-1-21 @ 10:49am, tested 2-7/8" & 3-1/2" Tj's, 250/2500psi. R/D test eq. blow down lines, pull blanking sub & BPV, m/u landing jt & r/u handling tools. BOLD pins. Pull hanger @ 16k, & cont pull to floor, l/d same, cont POOH l/d 4 jts, chem. inj. sub & SSSV, w/ ctl line's, c/o tongs. Cont. POOH l/d 2-7/8" to cut joint f/3,370', l/d 105 full joints, 1-cut joint 14.7', Chemical injection sub & SSSV w/pups. Blow down lines, secure well, turn over to Night watch. Night watch rig. 02/04/2021 - Thursday PJSM, blow through lines good, prep BHA, lay out & strap 2-7/8" PH6 wk string. P/U overshot BHA, - overshot w/top sub, xo, jars, bumper sub, xo =24.28'. RIh p/u 2-7/8" PH6 wk string, t/3,367', get free rot tq, 2k, rt wt, 13k, up wt, 16k, dn wt 12k. Engage fish @ 3,370', swallow down t/ 3,374' p/u set grapple, good, attempt to rotate out of anchor, no go, release tq, hit with 3 jar licks, rotate out @ 3k tq, 10 rounds tq fell off, p/u free, drop back down 2' below original engagement, p/u clean. L/D working jt, POOH standing back wk string. l/d BHA & fish, = 16.8' cut jt, 6.2' pup jt, latch & seal. Blow down lines, secure well, prep Milling BHA. Night watch rig. 02/05/2021 - Friday PTSM, M/u spools for circulating head, c/o handling eq for BHA. P/U milling BHA- 4-3/4" x 2-1/4" Packer mill, xo, 2-boot baskets, bit sub, bumper sub, Jars, xo, 6-3 1/8 DC, xo,xo=209.64'. RIH w/stands of 2-7/8" PH6 wk string, t/3,374', up wt 17.5k, dn wt 12.5k,. R/U power swivel, set cmt, counter weights, m/u tiw & saver sub t/power swivel, tq.same, install Kelly hose. attempt to back out of stump but unable to function swivel, troubleshoot finding Heim joint on linkage seized up locking up actuator, attempt to free but unsuccessful, blow down lines & secure well, sourced parts at farm yard will pickup for repair. Night watch rig. Test BOP as per Hilcorp & AOGCC requirements, AOGCC witness waived by Jim Regg on 2-1-21 @ 10:49am, tested 2-7/8" & 3-1/2"Tj's, 250/2500psi. Rig Start Date End Date 1/31/21 4/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 02/06/2021 - Saturday PTSM, blow through surface lines, check well static, p/u working single, tighten tq.lines, install circuating element,RIH tag packer @ 3,394', p/u start irculating, pump jacking off. troubleshoot & repair. break circulation good. start milling packer, up wt 18k, dn wt 12k, rot wt 13.5k , circ @4 bpm, 1,050psi, rot @ 60 rpm, tq off 1,000, tq on 1,500,. Had indication milled down t/ element, lost circulation , cont. pumping lost 24 bbls, before gaining returns, monitor losses @ 144bph cont. milling & @ same paramaters until packer started falling away. R/u circulated accross top of hole claculated losses @ 120BPH. R/D swivel, clear lines, RIH t/3,404' set down unable to push down, was able to push & rotate down t/3,412' without issues, still unable to push without rotating. clear pipe rack of counter weights, pull circulating head element. POOH standing back wk string. Rack back BHA, l/d boot baskets & mill, secure well. Night watch rig. 02/07/2021 - Sunday PTSM, check well, had 200 psi, bled off shut in, serviced rig, checked well 60 psi, fill hole 20 bbls, monitored static. M/U spear BHA, fill hole 5 bbls every 30 min,. TIH running stands from derrick t/ tag @ 3,412', up wt 17.5k, dn wt 12k. Packer moving down hole w/ 2kdown weight, push t/3,483', set down 5k, p/u with no overpull, work with no signs of engagment, r/u circulate set down 2k, put 2 turns to right tq.turns came back, circulate @ 1 bpm, 750 psi,wk string attempt to engage fish set down w/5k, p/u no overpull. Packer started moving again chase down t/ 3,504' take weight again, p/u no overpull, push down hole w/2k, put 2 wraps to left while pushing, set down @ 3,535'w/5k, p/u no overpull. Discuss options, Decision made to POOH inspect tools, POOH standing back wk string, t/BHA. stand back drill collars, l/d spear assy, had markings on top shoulder of spear. Night watch rig. 02/08/2021 - Monday PTSM, Check well, bleed off. Attempt to blow through pump lines, but unable, found ice plug, wrapped & heated, counted pipe on location, loaded pipe rack with pipe, prepped Spear BHA, Adjust tong hanging line, Blow through surface lines good. Fill hole with 8.4 PPG water, monitor well good, P/U Spear BHA- Spear w/2.44 grapple, xo, bumper sub, jars, xo, 6-3 1/8" DC, xo, xo=200.98',TIH from derrick t/tag @ 3572', moved down t/3581' set down 4k, p/u no op, went back down taking no weight chased down p/u 2 7/8" wk string t/4293, set down 2k, p/u t/4283 had 6k op, moved down with no issues & picked up clean. Cont. chase fish down hole p/u 2 7/8" wk string t/6476', (placing fish tail @ 6562' ) up wt 35k, dn wt 14k,POOH t/6415', blow down lines & secure well. Rig Start Date End Date 1/31/21 4/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 02/09/2021 - Tuesday PTSM, check well bleed off, blow through surface lines, good, start filling hole pump was jacking off, check valves good. Fill hole 65 bbls total, monitor hole good, blow down surface lines, Install circulating head element, tih to top of fish f/6415' t/6470', r/u circulating lines top off pits. Break circ. pump 1.6 BPM, 650 psi, up wt 36k, dn wt 14k, rih tag @ 6476' set down 4k, made 1.5', had increase of pump pressure p/u w/no op, rih set down, did have a 400psi increase of pressure but fell away cont. working made it down to 6486' (placing bottom of fish@6572') stopped making headway. no noticeable op or weight increase. r/d circulating line & blow down. POOH t/3977' stand back wk string, R/U pump & spot 30 bbl calcium carbonite pill, pump 1.5BPM 410psi, blow down lines. POOH l/d 2-7/8" wk string t/3153' up wt 20k, dn wt 12k, R/U pumped 3.5 bbls caught pressure cont. pumping 27 bbls, @ 1.5bpm, 700 psi. Blow down & secure well. 02/10/2021 - Wednesday PTSM, Check well, 20 psi, bleed off, blow through surface lines good, pump 30bbls hole fill, monitor hole good. R/U POOH l/d 2-7/8" wk string f/3,153'. L/D BHA- L/D drill collars, xo's, jars & bumper sub, spear came out missing grapple, no scarring on tool. M/U 2-7/8" & 3-1/2" test joints,. R/U pump 50 bbls @ 3bpm 135psi, no returns. N/D circulating head & x/o spool from stack. R/U test BOPE, Install 2-7/8" TJ, fill surface eq. shell test 250/2,500 repair needle valve on test manifold, service dampener. Test BOPE, as per Hilcorp & AOGCC requirements, AOGCC witness was waived by inspector Jim Regg, tested 2-7/8 & 3-1/2" TJ, 250 /2,500, had one FP w/ pipe rams on 2-7/8" tj, functioned rams re-tested good. R/D test eq. blow down lines, secure well. Daily fluid to well 105 bbls, Daily pill to well: 0 total: 995 bbls total: Cal Carbonite pill-30 bbls 9.5PPG. Night watch rig. 02/11/2021 - Thursday PTSM, check well, 320psi, bleed off, blow through surface lines good, fill 60 bbls, monitor good. TIH w/ 2-7/8" wk string from derrick, t/2,506', Mix 40 bbl Calcium carbonite Pill, 9.5 PPG. R/U pump 10 bbls water @ 3.8bpm, 380 psi, pump/spot 40 bbls 9.5ppg, calcium carbonite pill, blow down & r/d circ line. Pump 5 bbls drill water every 15 min down annulus. POOH t/1,497', l/d 2-7/8 wk string. Pump 10 bbls to clear string, blow down. Cont. POOH l/d wk string. Cont. pump 5 BPM drill water down annulus, total 90 bbls, after plumping pill. C/O handling eq. prep 3-1/2" liner. Pump, 80 bbls down hole @ 3.5bpm, 150 psi with no returns. blow down surface lines, monitor hole on vac. secure well, discuss options with ops engineer, cementer & mud engineer. Prep to p/u wk string in Am. Daily fluid to well 270 bbls, Daily pill to well: 40 total Fluid loss to well: 1,265 bbls total: Cal Carbonite pill-70 bbls 9.5PPG. Night watch rig. Rig Start Date End Date 1/31/21 4/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 02/12/2021- Friday PTSM, check well 390 psi, bleed off well, blow through surface lines, pump 99 bbls, monitor hole good. Prep to p/u wk string. P/U 2-7/8" wk string, rih t/ 3,875'. Finish mix 30 bbl Barofiber pill 9.3ppg, r/u circ lines. Pump & spot pill, @ 2.5bpm, 30 psi. R/U t/ fill annulus, pump 9bbls, shut in & squeeze 8x pressuring up t/250psi letting bleed down t/50, r/u lines & tank to capture excess pill. Circulate a hole volume, @ 3.5bpm, 540 psi, no losses, divert excess pill to slop tank as it surfaced. Blow down lines, rih p/u 2-7/8" wk string f/3,875' t/4,998' up wt 20k, dn wt 13k, blow down & secure well. Daily fluid to well 208 bbls, Daily pill to well: 30 total Fluid loss to well: 1473 bbls total: Cal Carbonite pill-70 bbls 9.5PPG, Barofibr pill: 30 bbls. Night watch rig. 02/13/2021 - Saturday PTSM, Check well- slight vac, blow through surface lines, r/u to capture excess pill material. Circulate 2 hole volumes, @ 3.5BPM, 640 psi, capture lcm pill when surfaced, circulate additional BU w/no fluid loss. Blow down, & r/u for cont. hole fill, POOH f/4,998', l/d 2-7/8" wk string. C/O handling eq. load pipe on skate pipe rack, r/u fill up line. P/U shoe track & 1st joint, check floats good. Cont. p/u 3-1/2" L-80 9.2# supermax tubing t/556', checking tq with make up markings, Average 2300, fill every 5 joints. Blow down & secure well. Night watch rig. 02/14/2021 - Sunday PTSM, check well slight vac, blow through surface lines good, fill hole 2 bbls,. RIh @ 100 fpm, p/u 3-1/2" 9.2, L-80 supermax liner, f/ 556' t/4,175', losses started to increase, checked static fluid loss @ 7BPH. Cont. RIH @ 60fpm p/u 3- 1/2" 9.2, L-80 supermax liner, f/4,175', t/6,331' p/u sssv landing nipple with valve installed. Install ctl line, function test valve good, opened @ 1,800 psi, hold 5k psi on line. Cont. rih to tag @ 6,488' up wt 30k, dn wt 15kp/u t/ 6,461'. R/U filled pipe, broke circulation 1.3bpm, 160psi. P/U space out pup, hanger & landing jt, m/u penetration for ctl line, pressure up line to 5k good, test internal hanger void t/5k good, land hanger & run in L/D pins, placing assembly tail @ 6,480'. R/U w/l, rih retrieve TRSV, r/d, test hanger void t/5k good, secure well for night. Night watch rig p/u 3-1/2" L-80 9.2# supermax tubing t P/U shoe track & 1st joint h p/u 2-7/8" wk string f/3,875' t/4,998' up wt 20k, dn wt 13k, blow down & secure well. Daily fluid to well 208 bbls, Rig Start Date End Date 1/31/21 4/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 02/15/2021 - Monday PTSM, check well on vac, blow through surface lines good,. R/U circulate @ 3.4 BPM, 650 psi, at 1/2 bottoms up had 2 bbl loss, started getting contaminated fluid back (pill ) diverted to slop tank continued CBU diverting till clean, @ 1.7 bottoms up we lost circulation. Attempt to fill annulus, pump 25 bbls with no luck , confer with ops engineer, decide to pump fiber pill down annulus. r/u mix Barofiber pill 23 bbls, 9.3ppg. line up & pump pill down annulus @ 1.4bpm, 170psi, pumped 22 bbls, chased with 25 bbls Drill water, pressured up t/370 psi, shut down & held pressure 15 min down t/319 psi. Bump pressure up t/ 375 f/ 15 min, bleed off pressure t/0, pressure back up t/ 375 hold f/ 12 min, down t/281, bleed off t/0 psi, let rest 5min, pressure back up t/375 bled down t/180, cont. w/2 more mini squeezes pumping up t/ 375 holding 10 min each, injected 5.3 bbls total while squeezing. R/U t/ CBU, pump @ 1.8 bpm 376psi, divert pill to slop tank when surfaced had 6.5 bbl loss, blow down lines, pump 1 bbl diesel freeze protect, r/u cementers. PJSM, for cmt job with personal involved. Pump CMT job as procedure filled lines 5 bbls, set KOs , P/T lines 1,200/3,800 good, pump 20 bbl water spacer, 42 bbls 12 PPG lead cmt @ 3bpm 300 psi, 18 bbls 15.3 tail cmt, @ 2bpm 70 psi, drop dart, chase with 56.2 bbls water @ 2bpm, bump plug @ calculated, FCP 1,200 psi, pressure up t/2,650 latch plug, bleed off return .75 bbl, float check good. R/d & blow down lines, wash up cementers, r/u wireline RIH w/ brush t/SSSV landing nipple, brush 30 min while pumping through control line, POOH brush clean. R/D wireline, pull landing joint, set BPV, well secured. Night watch rig. 02/16/2021 - Tuesday PTSM, R/D handling eq, clean off liner, r/d circulating lines, fluids from pits, r/d floor, start loading trailers. N/D BOPE, N/U tree, cont. breaking down aux eq. & prepping for loadout. Test void 5k good, pull BPV & install TWC, test tree 500/5,000 good, pull TWC. Freeze protect tree w/ Diesel, & secure well, install cellar grating. Prep, scope down mast & layover, r/d landings, wrap lines & prep for loadout, cont. load aux eq. on trailers & transport to KGF, remove eq. from liner, fold up liner. SDFN. 02/17/2021 - Wednesday Travel to location. Contact DSO, Inspect location, PTW, PJSM. Stand by while the rig finishes loading and moving rest of the rig off location. Assist operations in doing MIT-IA (Failed). MIRU Petrospec, Rig up hydraulic lines to bop's, make up hardline to the choke and return tank. Test BOPE as per Hilcorp & AOGCC requirements, witnessed waived by AOGCC Inspections Supervisor Jim Regg, 250/4,000. Emailed BOPE Test Report to AOGCC. Stack down, secure well and location for the night. Job in progress. 02/18/2021 - Thursday Travel to location. Arrive on location, contact DSO, inspect location, PTW, PJSM. Make up Drift run, ( CC 1.75" X 2') ( No- Go nozzle 1.8" X .25') TOL= 2.25', Stab on well, PT LOW/HIGH 250/4,000. Open well, Swab 25, T/I/OA= 0/0/0, RIH, Tag at 6,478' CTMD. POOH, Tagged up, swab closed, Bleed down, pop off well. Make up Read memory Cement bond log tools. Head to well, stabbed on well, Open up. RIH, @ 6,466' stop for 5 Min. Start logging up at 30FPM to surface. Tagged up, swab shut, bleed down, pop off well. Download logging tools. Make up 2.80" drift, stab on well, open well, tagging in tree with gauge ring. Finally made it through the tree. RIH With 2.80" gauge ring. Tag @ 6,480'. POOH, tagged up, swab shut, bleed down, pop off well. Rig down, secure well and location for the night. Job in progress. Pump CMT job as procedure f Assist operations in doing MIT-IA (Failed). p Read memory Cement bond log tools. 42 bbls 12 PPG lead cmt @ 3bpm 300 psi, 18 bbls 15.3 tail cmt, Rig Start Date End Date 1/31/21 4/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 02/19/2021 - Friday Travel to location, contact DSO, PTW, PJSM. Rig down coil, tank, and hot oil truck. Secure well, Clean up area. Leave location. Tested wellhead voids to ensure no communication. Tubing and inner casing voids each separately held 4,800+psi. (Vac/Vac/210 on annuli). 02/23/2021 - Tuesday Fire up hot oil truck at KGF. Doyles fuel on location loading middle tank with Methanol. Depart KGF for Paxton 9. Arrive on location. MIRU hot oil truck to IA valve. Initial pressures. Tubing 0 psi on vac, IA 0 psi slight vac, OA 200 psi, control line 180 psi. PT pump line to IA gate valve 250/4,500 psi. Pump 2 bbls of NEET methanol into IA. Did not catch pressure. Swap to fresh water. Online .3 bbls pumped and caught fluid. 2.3 bbl void in IA before being fluid packed. Pressure up IA to 2,000 psi and shut down. Pressure dropping steadily. Continue pressuring up to 2,000 psi. After 15 minutes pressure was at 100 psi. 10 minutes pressure averaged around 300 psi. 5 minutes pressure dropped from 2,000 to 450. Mix up 13 bbls of 50/50 methanol water in front tank. Roll tank. Pressure up to 4,000 psi. Drop pump gears into low low. .2 bbls/min not able to establish steady pump rate prior to 4,000 psi being reached. 4,000 psi down to 3,000 psi in 46 seconds. Keep working pressure up to 4,000 psi after it bleeds down to 3,000-3,500 psi. Attempting to keep high in hopes of breaking through cement to establish a larger rate . Not able to obtain enough rate to perform top down cement squeeze. Fairly accurate estimate of 12 bbls added to IA. 2.3 of those 12 were to fluid pack IA. Send pressure chart to town engineer. Decision was made to shut down. Rig down hot oil truck and depart for KGF. Location secure. Online .3 bbls pumped and caught fluid. 2.3 bbl void in IA before being fluid packed. Pressure up IA to 2,000 psi and shut down. Fairly accurate estimate of 12 bbls added to IA. 2.3 of those 12 were to fluid pack IA. Pressure dropping steadily. Rig Start Date End Date 1/31/21 4/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 03/10/2021 - Wednesday Leave Halliburton WP Shop and travel to Paxton 9 well in Ninilchik unit. Arrive on location. Wait on snow clearing equipment to finish clearing snow around Paxton 9. TBT regarding spotting equipment on PXTON 9 and rig up, safety and job procedures. Rig up 4- 10' joints of 4-1/2" Lubricator c/w triple wireline valves c/w tool trap and pump in tee c/w 2"- 1502 lo torque c/w 4-1/2" Otis wellhead crossover. Pressure test PCE rig up to 250 PSI low test and 1,500 Psi high test. No leaks. Pressure test all good. Open well 0 psi SITHP. RIH with 1-1/2" X 5 foot stem, c/w 10 foot roller stem (2.12" Wheels) c/w 1-1/2" mechanical Spangs c/w 2" Roller boogie (2.5" Wheels) 23" in length c/w 2" X 7' Dummy E-line gun to 1,819' SLM, no tag- 75 degrees deviation. POOH to 1,750' SLM and RIH again and pass through 1,819' SLM and proceed to 1,908' SLM, no tag- 75 Degrees deviation. POOH to 1,875' SLM and RIH to 2,602' SLM. Well very deviated had to work tools all the way to 2,602' SLM. Could not pass- attempted 2 x. POOH. At surface. Close swab valve and bleed off well. Change out BHA to 2.80" Gauge ring. RIH with 2.80" Gauge cutter to 1,819' SLM, no tag- 75 degrees deviation. Contact Hilcorp company representative and we request to add more weight bar. He agreed. POOH. At surface. Close swab valve and bleed off well. Breakout Gauge cutter BHA. Add 3 feet of 1-1/2" Stem to toolstring. RIH with 2.80" Gauge cutter to 1,849' SLM. No tag 75 degrees deviation. POOH. Contact Hilcorp company representative and decision to try 2.70" Gauge cutter. At surface. Close swab valve and bleed off well. Change out to 2.70" Gauge ring. RIH with 2.70" Gauge ring to 1,849' SLM, no tag- 75 degrees deviation. Work tools up and down but could not RIH any further due to high deviation. Contact Hilcorp company representative and inform him of stopped depth. Decision to POOH and rig down. At Surface, Close swab valve and bleed well to 0 psi. Break out toolstring. Rigdown 4-1/2" PCE rig up. Secure 4-1/2" OTIS Tree cap on well. Secure equipment on crane, PCE trailer and Slickline unit for transportation to WP workshop. Off location. Travel to Halliburton WP shop. Open Journey Management. Arrive at Halliburton WP workshop and close Journey Management. Rig Start Date End Date 1/31/21 4/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 03/19/2021- Friday PTW, JSA. MIRU Yellow Jacket E-line and Hilcorp hot oil truck. Hot oil truck has ice plug. Call out new HAK heaters from farm yard. and Thaw valve. Install heaters on hot oil truck. RIH with E-line 2 x 7" WB, 3 x 2.58" rollers, 1-11/16" GG, 2 x 1.97" rollers and 4' of 1-9/16" tubing punches loaded for 4 SPF 0deg phasing, and two magnets with OAL 38.41'. Initial pressure: tubing 0 psi. IA 5,000 psi, OA 300 psi. Bleed IA from 500 psi to zero (all gas). RIH to 2,600'. Log OOH and tie in. Pump down IA taking returns to formation. Took 3bbls to fill up. MIT-IA to 1,800psi failed. Lost 1,500psi in 15mins. Swap pump lines from IA to tubing. FIll void with 19 bbls pumped before catching fluid (CT had displaces drift volume on previous rigup). Apply 500 psi on tubing with hot oil truck and produced water. 12' CCL to top shot. Tubing punch 2,401- 2,405' (CBLM). CCL depth 2,389'. Fire guns and punch holes. After 5 minutes tubing pressure and IA pressure equalized at 200 psi. E line at surface. POP off and confirm all shots fired. Install night cap on pump in sub. Online with Hot oil truck down tubing taking returns up IA to surface. Average pump rate 0.6 bbls/min. Pressure up to 4,000 psi and hold rates. Pressure slowly dropped at beginning, but leveled off at ~3,650psi after 15bbls away. Attempted 0.7bpm, but exceeded 4,000psi maxP. Back to 0.6bpm Pump 51 bbls (surface to surface), keep injecting down tubing and close IA and inject 2 bbls through punches down IA into formation. Couldn't maintain injection rate. Pumped 3bbls over 20mins bumping 4,000psi. Swap pump lines from tubing to IA and inject two barrels (close to same injectivity as down tubing). Freeze protect tbg, IA. Attempt to RIH with E-line with composite BP. Tools stopped at 1,400'. Pick up and attempt to pump tools down hole at .6 bbls/min. Tools not falling. Make 3 more attempts up to 4,000 psi and .7 bbls/min. Tools are not falling. Not enough flow'restriction at CBP to create a differential pressure to assist tools to fall. POOH to surface. Freeze protect IA and tubing. RIg down Hot oil truck and YJES. Attempt to install wellhouse on another Paxton well. Not able to break free from the ice. Rig down crane. SDFN. location secure. 03/29/2021 - Monday De-mob SLB coiled tubing equipment from Kalotsa and move to Paxton 9. MIRU coil equipment on Paxton 9. Spot equipment and prepare for weekly BOPE Test. Perform weekly BOPE test. State witnessed BOPE test waived by Jim Regg. Continue to rig up equipment in parallel. Finish rigging up for the night. Continue in the morning. Tubing punch 2,401- 2,405' (CBLM). Back to 0.6bpm Pump 51 bbls (surface to surface), keep injecting down tubing and close IA and inject 2 bbls through punches down IA into formation. Couldn't maintain injection rate. Pumped 3bbls over 20mins bumping 4,000psi. S Bleed IA from 500 psi to zero (all gas). Rig Start Date End Date 1/31/21 4/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 03/30/2021 - Tuesday SLB coil and YellowJacket arrive on location. Conduct JSA and approve PTW. MU CTC and pull test to 25K. MU MHA and PT to 3,500 psi+A1. MU READ memory logging toolstring and MU lubricator to BOP's. PT out to choke 250/4,000 psi. Log from 2,700' to surface. Paint flag at 2,450'. Download data. Top 1,400' of data was corrupt. Bottom data was sufficient. Send data to town. Correct +1.5'. RIH with 3-1/2" composite bridge plug. Get to flag and correct depth to top of plug. Circulate 3/8" ball and set top of plug at 2,425'. Set down 3K# on top of plug to verify set. POOH. Circulate down coil, take returns up IA out to tank. Injectivity rate of 0.5 bpm, CTP = 1870 psi, WHP = 1,530 psi. Get 1:1 fluid returns at surface up the IA. Close IA. Circulate down coil into formation. No injectivity. Pressure up to 3,700 psi and pressure bleeds off to 2,200 psi in ~ 10 minutes.;POOH. Laydown BHA. Blow down coil with N2. finish for the night. Prepare to cement following morning. 03/31/2021 - Wednesday SLB coiled tubing arrive location. Conduct JSA and approve PTW. MU 1.75" slim BHA with big hole nozzle. Load coil with water and PT out to choke to 250/4,000 psi RIH and tag plug at 2,420' ctmd. PU to 2,410' ctmd. Verify circulation down coil, up IA. Halliburton start mixing cement and PT lines to 4,500 psi. Circulate 15 bbls of 13.0 ppg ultrafine cement down coil and let 1 bbl of cement come above nozzle. Close in Tubing x CT annulus. Open IA and pump 8 bbls of cement into IA taking returns to surface. Recover 5 bbls of fluid in 40 bbl tank. Close IA and attempt to pump down IA into formation. Pump 0.5 bbls and pressure up to 4,100 psi. Pressure not bleeding off. Circulate cement out of coil while PUH to 1,400' ctmd. Attempt to inject cement into formation through tubing punches. Pressure up tubing to 4,000 psi. Tubing pressure dropped from 4,008 psi to 3,880 psi in 1 hour. Bleed IA and Tubing down to 0 psi together. Pump 10 bbl gel pill down coil to contaminate cement. RIH washing to 2,300'. POOH. Wash across landing nipple at 166'. Coil at surface. Shut in Swab. Blowdown coil with N2. RD BOP's and hardline. Leave equipment staged on location. Plan to return and mill out cement after testing MITIA. 04/04/2021 - Sunday MIT-IA passed of 3-1/2" x 5-1/2" annulus with field triplex. Starting P = 1,555psi. 15mins P = 1,529psi. 30 min P = 1,513psi. P loss of 26, followed by 16psi for a total loss of 42psi over 30 mins. PASS. set top of plug at 2,425' Injectivity rate of 0.5 bpm, CTP = 1870 psi, WHP = 1,530 psi. MIT-IA passed of 3-1/2" x 5-1/2" annulus with field triplex. . Circulate down coil into formation. No injectivity. Pressure up to 3,700 psi and pressure bleeds off to 2,200 psi in ~ 10 minutes.; Circulate 15 bbls of 13.0 ppg ultrafine cement down coil and let 1 bbl of cement come above nozzle. Rig Start Date End Date 1/31/21 4/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 04/05/2021 - Monday SLB coiled tubing arrive location and conduct JSA and approve PTW. Spot equipment and RU hardline to choke skid. Test BOPE. State waived witness by Jim Regg. Test 250 psi low / 4,000 psi high. to choke skid.;Test BOPE. State waived witness by Jim Regg. Test 250 psi low / 4,000 psi high. MU CTC and pull test to 10K. MU MHA and PT to 3,500 psi. MU2.13" jars, disco, circ sub, 2.13" motor, and 2.75" junk mill. PT to 4,000 psi. Test downhole checks. RIH and tag TOC at 2,285'. Appears to be stringers, mill easily until 2,301'. Hard cement at 2,301'. Mill ~ 0.5'/minute. Stalls more frequent when getting deeper, make sweeps uphole. Mill cement until 2,421.7', then reach top of plug. Mill on plug starting at 2,421.7'. Mill through first set of slips, then middle element. Reach 2,422.5'. Keep stalling out and can't get through bottom set of slips. POOH with junk mill. Close Swab. Laydown milling BHA. Missing some teeth on bottom of junk mill and metal debris around mill. Blowdown reel. Stack down lubricator for the night. Install night cap on BOP's. Will resume in the morning. 04/06/2021 - Tuesday SLB Coil arrive on location and conduct JSA and approve PTW. MU lubricator joints and milling BHA. PT down to motor to 3,500 psi. PT out to choke skid. RIH with 1.75" CTC, 2.13" DFCV, 2.13" BiDi jar, 2.13" disco, 2.13" circ sub, 2.13" motor and 2.75" Tri Cone bit. Tag plug at 2,420'. Mill on plug, minimal stalls. Start pushing plug downhole. Push plug to PBTD and tag at 6,452' ctmd. POOH with milling BHA. Prep for MIT-T. MIT-T to 1,500 psi. Good test. 30 minute test. Initial P= 1,591 psi. 15 min P = 1,540psi. 30 min P = 1,523 psi. Pressure losses of 51psi followed by 17psi, for an overall loss of 68psi. IA remained constant at 760 psi. Laydown milling BHA. Stab back onto BOP's. Blow reel down with N2. Stack down lubricator. Set injector down on back deck. Install night cap on BOP's. Will resume memory logging next day. MIT-T to 1,500 psi. Good test.Push plug to PBTD and tag at 6,452' ctmd. Rig Start Date End Date 1/31/21 4/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 04/07/2021 - Wednesday SLB Coil arrive and conduct JSA and approve PTW. Have ice in tree valves. Get heater and triplex to thaw. PU lubricator and MU READ Memory CBL toolstring. Confirm CBL toolstring is activated. PT out to choke. RIH with READ memory CBL to 5100' ctmd. POOH logging at 30 ft/m from 5100' to surface. Confirm good data from memory CBL. TOC = 820'. MU 2"nozzle and cool down N2 unit for blowdown. RIH to 6,400', circulating N2 back to return tank. Recover 55 bbls of fluid at tank. POOH pumping N2 and trap 1,350 psi on wellhead. Close swab, bleed off pressure on surface lines. Stack down lubricator and set injector on back deck. Nipple down BOP's and install tree cap. Leave equipment on pad for the night, will mobilize equipment to next location in the morning. 04/08/2021 - Thursday SLB Coil and Weaver Bros trucks arrive on location to de-mob coil equipment. Pick coil reel and set on lowboy for transfer due to road restrictions. Load iron racks, baskets, on weaver trailers. Move water tanks. YellowJacket E-line and Welltec tractor MIRU. Collector on side of YellowJacket drum not working with Welltec tractor equipment. Have another collector sent to location and installed. MU Welltec tractor and Perf guns. Attempt to PU lubricator, wind gusting above crane limits. Set down lubricator. Break down tractor and guns. Will return tomorrow. Review this to compare to previous pre-squeeze CBL. RIH with READ memory CBL to 5100' ctmd. Rig Start Date End Date 1/31/21 4/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 04/10/2021 - Saturday YellowJacket E-line and Welltec tractor arrive on location. Conduct JSA and approve PTW. Welltec perform pre-perf checks on tractor. MU tractor and guns in lubricator. PT to 3,000 psi. RIH with E-line/tractor and perf guns. Perf guns are 2-3/8", 5 spf, 60 deg phasing, razor charges Stopped falling at 1,500'. Engaged tractor. Tagged at 2,300', 2,850', and 3,020'. Picked up and tractored past each time. Bleed WHP to 800 psi. Stop at 6,050' and log up for correlation pass. Send correlation data to Geo, add +1' Perf: (BEL_83) from 5,870’ – 5,882’ MD. Perf: (BEL_82L) from 5,840’ – 5,846’ MD. Perf: (BEL_74L) from 5,685’ – 5,69’ MD. Initial TP = 803 psi, 5 min = 820 psi, 10 min = 840 psi, 15 min = 860 psi E-line BHA stuck at 2,880' MD. Attempt to engage tractor to RIH, no success. Attempt to pull with E-line to get toolstring weight back and also engage tractor, no success. Attempt to surge well by closing in wing, letting WHP build, open wing, no success. Pull out of cable head at 3,000# while surging well. POOH. Clean pull out at surface. *** Fish in hole ***. YJ E-line tools = 38.75' (1-11/16" x 1.0' cable head, 1-11/16" x 6.85' gamma , 2-3/8" x 0.55' sub, 2-3/8" x 7,0' carrier, 2- 3/8" x 0.60' switch, 2-3/8" x 7.0' carrier, 2-3/8" x switch, 2-3/8" x 15.0' carrier, 2-3/8" x 0.15' plug) Welltec Tractor tools = 22.8' (2.18" x 18.55' tractor, 2.126" x 2.52" safe sub, 2.126" x 1.73' sub shock) OAL = 61.55'. Max OD ~ 2.5" (swell of 2-3/8" gun). RDMO. 04/11/2021 - Sunday SL standby: High winds. no work completed. Perf: (BEL_74L) from 5,685’ – 5,69’ MD. Perf: (BEL_82L) from 5,840’ – 5,846’ MD. Perf: (BEL_83) from 5,870’ – 5,882’ MD. Rig Start Date End Date 1/31/21 4/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 04/12/2021 - Monday ARRIVE ON LOCATION, PERMIT, JSA. RIG UP .160 S/L, P.T TO 2000 PSI - GOOD TEST. RIH W/ 2.50'' LIB, 1200' FALLS VERY SLOW, SIT DOWN T 2860'KB W/T POOH -CLEAN ROPE SOCKET. RIH W/ 1 3/8 JDC W/ 2'' BELL GUIDE TO 2863'KB W/T WONT LATCH POOH - TAKE R.B. UNDER LSSJ. RIH W/ SAME TO SAME W/T WONT LATCH POOH - NO MARKS ON PIN RIH W/ 3 1/2 GR W/ 2.76'' BAIT SUB W/ 2.32'' OVERSHOT TO 2883'KB W/T LATCH PULL UP TO 1200#. COMES FREE, NO CHANGE IN WEIGHT, BEAT DOWN FOR 30 MINS LATCH, COMES FREE AT 1200#. TALK W/ LEAD AND SUPERVISOR, BEAT DOWN FOR 1 HOUR, PUMP DIESEL DOWN WELL, BEAT FOR 10 MORE MIN, PULL UP COMES FREE POOH - W/ BAIT SUB AND OVERSHOT, NO MARKS. TALK W/ LEAD, STAND BY RIH W/ 1 3/8 JDC W/ 2.25'' BELL GUIDE TO 2863'KB, LATCH, DO 1 SPANG LICK COMES FREE. POOH. 500 EXTRA POUNDS, UNSTAB LUB, CONFIRM HAVE ALL ELINE TOOL STRING. YELLOW JACKET AND WELLTEK ARRIVE, TAKE APART ELINE TOOL STRING, LAY DOWN LUB. RIG DOWN. DEPART FIELD, END TICKET. 04/22/2021 - Thursday PJSM with Pollard Slickline crew on operation. RU lubricator, PT. RIH and pull SSSV with Slickline unit. RD Slickline unit. SIMOPS: Crane on location, install reel onto Petrospec Coil Unit 131. NU BOP. Test BOP to 250 psi low / 2,500 psi high. Good test. Continue with rigging up the coil unit. Stretch out hoses and hook up. MU connector to E-coil, head up for the E-coil for Yellow Jacket. Test connector. MU Yellow Jacket collector head to coil unit. Continue with making up hydraulic hoses. 04/23/2021- Friday Safety meeting with crew, emphasis on working under overhead lifts, pressure from well, handling guns. Confirm shot zones and gun OD. 65 psi on well, flowing at ~1,400 mcf. MU lubricator assembly and gun BHA #1 of CCL with two sections of 2-3/8" 5-spf, 60 deg phasing guns of 5' and 20' sections with multi-fire capability. Stab on, test lubricator. Attempt to RIH to ensure encoder is tracking for data collection. Not tracking, troubleshoot. Surface checks are good. Use manlift to reach encoder on injector, pull cable. Inspect, one of the pins on the 7-pin connector riding free so that when it is pushed it doesn't engage plug. Swap out, function check, good. RIH with gun BHA #1 on coil and log from 5,800' up to 5,200'. Send log, correlate with 0' correction. Set bottom shot zone on depth, perforate sand BEL 74U md of 5,673'-5,678'. 5/10/15 min avg 70 psi and increase rate from 337 to 510 MCFD. PU hole, re-log across second zone with +1' correction, place shot zone on depth in sand BEL 60 md of 5,394'-5,414'. 5/10/15 min psi and decrease in rate from 489 to 473 MCFD. POH with BHA #1, close in to well. Pop off, inspect guns, all shots fired but several shots from upper 20' gun oozing thick mud. LD lubricator assemblies, LD injector. Move and store spend gun. Ensure everything is prepped for run in morning. perforate sand BEL 74U md of 5,673'-5,678'. sand BEL 60 md of 5,394'-5,414' Rig Start Date End Date 1/31/21 4/29/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 04/29/2021 - Thursday SL set WLSSSV. 04/24/2021 - Saturday Safety meeting with crew, emphasis on overhead lifts, handling guns. Stage gun assembly to well head. Pick up injector, make up lubricator assembly. MU gun BHA #2 with CCL, stab on and test lubricator. RIH with gun BHA #2, 2-3/8" gun with 27' shot of 5 spf, 60 deg phasing. RIH, log across zone and correlate with +1' correction. Place on depth in BEL 58A sands, interval 5,215' to 5,242'. Initial pressure 69 psi, rate 430 mcfd. Fire, 5/10/15 min readings initially jumped to 484 mcfd but dropped back down to 409 mcfd at 15 min, pressure consistent at 69 psi. POH, pop off and inspect gun, all shots fired. Stand back gun, swap out single GR tool to dual fire GR tool and CCL. MU 41' gun assembly and stab on. RIH with gun BHA #3 of 2-3/8" 5 spf, 60 deg phasing gun on CCL and GR tool, log from 5,400' to 4,300', correlate with +2' correction. Place on depth in BEL 56 sands, interval 5,073-,5096'. Initial pressure 69 psi, rate 462 mcfd. Fire, flow reading initially dropped to 448 mcfd then 5/10/15 of 473/462/425 mcfd, pressure consistent at 69 psi. Log from 4,900' to 4,350', correlate with no correction. Place on depth in BEL 52L sands, interval 4,707'-4,725'. Initial pressure 69 psi, rate 439 mcfd. Fire, 5/10/15 min readings 1620/1907/2,078 mcfd, pressure at 86/92/97 psi. POH, close in valves, pop off, LD BHA and LD lubricator. Secure injector, RD E-line unit and RD coil unit in preparation to move to Paxton 10. ND BOP off Paxton 9, NU on Paxton 10. Move support equipment into place. Swap out hydraulic hose bundles. BEL 52L sands, interval 4,707'-4,725' BEL 58A sands, interval 5,215' to 5,242' 5096'. BEL 56 sands, interval 5,073-,5 Updated by CRR 4-29-2021 SCHEMATIC Ninilchik Unit Well: Paxton #9 PTD: 214-173 API: 50-133-20647-00-00 PBTD = 6,458 MD /3,273’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ 9-5/8” cement Job: 12-1/4” hole. 137 bbls of 12.5 Type I lead and 65bbls 15.2# tail. 100% returns with cement to surface 5-1/2” cement job: 8-1/2” hole. 145 bbls of 13.5# class G lead, and 93 bbls of 15.7# class G tail. Full returns throughout job. Volumetric ToC at ~1450’ MD assuming 10% openhole washout. 40 bbls spacer pumped, and 40 bbls back to surface (no cement seen) 3-1/2” Cement Job: 42bbls of 12ppg lead and 18bbls 15.3 tail. No losses throughout job (had losses pre-job). Good lift pressure, but cement must have fallen back after job. (had losses pre-job). Good lift pressure, but cement must have fallen back after job. 2/18/21 Radial CBL: Solid cement up to ~4210’ MD (base BEL_47C squeeze perfs). Patchy cement up to 1850’ MD, free pipe at 890’ MD. Post-squeeze CBL run on 4/7/21 shows new ToC at ~820’MD 1 16” 9-5/8” 8-1/2” Hole 5.5” No. MD TVD ID Item 1 166’ 166’ 2.812” SSSV hydraulic nipple (SLB BP-6i)- SLB 3-1/2” WRDP WLSSSV installed 4/29/21 2 6570’ Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) from 1/15/15. Tagged at 6586’ CTMD 7/25/20 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Ft Date Status Punches 2401’ 2405’ 4 3/19/21 Squeezed (3/31/21) BEL_47A 4,070' 4,082' 1,914' 1,917' 12' 7/28/20 Squeezed (2/15/21) BEL_47A 4,082' 4,096' 1,917' 1,921' 14' 7/28/20 Squeezed (2/15/21) BEL_47C 4,179' 4,194' 1,946' 1,950' 15' 7/27/20 Squeezed (2/15/21) BEL_47C 4,194' 4,209' 1,950' 1,955' 15' 7/26/20 Squeezed (2/15/21) BEL_52L 4,707' 4,725' 2,145' 2,153' 18' 4/21/21 Open Bel 53 4,790’ 4,802’ 2,181’ 2,186’ 12 1/13/15 Squeezed (2/15/21) Bel 53 4,802’ 4,822’ 2,186’ 2,195’ 20 4/20/15 Squeezed (2/15/21) Bel 53 4,819’ 4,839’ 2,194’ 2,202’ 20 1/11/20 Squeezed (2/15/21) Bel 53 4,839’ 4,859’ 2,202’ 2,211’ 20 1/10.20 Squeezed (2/15/21) Bel 53 4,863’ 4,883’ 2,213’ 2,222’ 20 1/10/20 Squeezed (2/15/21) Bel 53 4,883’ 4,903’ 2,222’ 2,231’ 20 1/9/20 Squeezed (2/15/21) BEL_56 5,083' 5,096' 2,316' 2,322' 13' 4/24/31 Open BEL_58A 5,215 5,242’ 2,384' 2,399' 27' 4/24/21 Open BEL_60 5,394' 5,414' 2,487' 2,499' 20’ 4/23/21 Open BEL_74U 5,673' 5,678' 2,665' 2,668' 5’ 4/23/21 Open BEL_74L 5,685' 5,691' 2,673' 2,677' 6’ 4/10/21 Open BEL_82L 5,840' 5,846' 2,783' 2,787' 6’ 4/10/21 Open BEL_83 5,870' 5,882' 2,805' 2,813' 12’ 4/10/21 Open CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16” Conductor 109 / X-56 / Weld Surf 80’ 9-5/8' Surface 40 /L-80 / BTC 8.835” Surf 2,291’ 5-1/2" Production 17 / P-110 / CDC 4.892” Surf 6,723' TUBING DETAIL 3-1/2” Tubing / Scab Liner 9.2# / L-80 / Supermax 2.992” Surf 6,481’ 2 1450’ ToC (volumetric) _q() BEL_52L 4,707' 4,725'2,145'2,153'18'4/21/21 Open _,,,,//q(//) ,,,,//q(//) BEL_56 5,083' 5,096'2,316'2,322'13'4/24/31 Open BEL_58A 5,215 5,242’2,384'2,399'27'4/24/21 Open BEL_60 5,394' 5,414'2,487'2,499'20’4/23/21 Open BEL_74U 5,673' 5,678'2,665'2,668'5’4/23/21 Open BEL_74L 5,685' 5,691'2,673'2,677'6’4/10/21 Open BEL_82L 5,840' 5,846'2,783'2,787'6’4/10/21 Open BEL_83 5,870' 5,882'2,805'2,813'12’4/10/21 Open Bel 53 4,883 4,903 2,222 2,231 20 1/9/20 Squeezed (2/15/21) Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 03/05/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL PAXTON 9 (PTD 214-173) Tubing Punch, CIBP, RCT 02/01/2021 Please include current contact information if different from above. PTD: 2141730 E-Set: 34992 Received by the AOGCC 03/08/2021 04/14/2021 Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 04/09/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL PAXTON 9 (PTD 214-173) Memory Radial Cement Bond Log 04/07/2021 Please include current contact information if different from above. PTD: 2141730 E-Set: 34961 Received by the AOGCC 04/09/2021 04/12/2021 Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 04/09/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL PAXTON 9 (PTD 214-173) Coil Flag 03/30/2021 Please include current contact information if different from above. PTD: 2141730 E-Set: 34960 Received by the AOGCC 04/09/2021 04/09/2021 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: __N2 / Cement Packer__ 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/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 6,733'6570' Casing Collapse Structural Conductor Surface 3,090 psi Intermediate Production 7,480 psi Liner 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 Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 Date: Conditions of approval: Notify Commission 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 COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng ryan.rupert@hilcorp.com 3,503'6,458'3,273'~1122 psi none N/A; SLB SSSV hydraulic landing nipple N/A; 166' MD / 166' TVD Perforation Depth TVD (ft):Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0384372 / FEE-PRIVATE 214-173 50-133-20647-00-00 Paxton 09 Ninilchik Field / BELUGA-TYONEK GAS Pool Length Size CO 701C Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 9.2# / L-80 TVD Burst 6,481' 10,640 psi MD 5,750 psi1,401' 80' 2,291' 3,495'5-1/2" 16" 9-5/8" 80' 2,269' 6,726' Perforation Depth MD (ft): See Attached Schematic 6,726' Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: March 17, 2021 3-1/2" m n P s t 66 Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:03 am, Mar 15, 2021 321-127 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.03.12 16:13:22 -09'00' Taylor Wellman (2143) Review final cementing plan with AOGCC after injectivity results are acquired. 10-404 DSR-3/15/21 Submit daily operations report to AOGCC. SFD 3/15/2021BJM 3/15/21 Comm 3/16/21 dts 3/15/2021 JLC 3/15/2021 RBDMS HEW 3/17/2021 Well Prognosis Well: Paxton-09 Date: 3/12/2020 Well Name:Paxton-09 API Number:50-133-20647-00-00 Current Status:Gas Producer Leg:N/A Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:214-173 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (C) Second Call Engineer:Todd Sidoti (907) 632-4113(C) Maximum Expected BHP:~ 1442 psi @ 3,204’ TVD (Based on a 0.45 psi/ft gradient) Max. Potential Surface Pressure:~ 1122 psi Using Max BHP minus 0.1 psi/ft. gas gradient to surface). Well Summary Paxton 9 wasworked over in Feb-2021 in an effort to isolate all the existing sands and the water production, and then selectively recomplete the well starting with deeper unperforated sands in the Beluga formation. The well was consistently on losses into the open perfs throughout the RWO. Several LCM pills were pumpedwith varying success. The 3-1/2” scab liner/tubing was cemented into place on 2/15/21. Although the losses were healed before the cement job, and the job itself was pumped with negligible losses, the well failed an MIT-IA afterwards. The objective ofthis program is to restore a monitorable annulus with a cement packer as close as possible to the top of the pool, and obtain a passing MIT-IA, so sands can be completed, and the well operated. Notes Regarding Wellbore Condition x Well goes >70 degrees inclination at ~1400’ MD, and sails at 75 degrees until 4000’ MD where it starts to turn vertical again, and ends up at <35 degrees at PBTD. x Drifts o 3/10/21 SL drifts Made it to 2621’ SLMD with a 2” 7’ dummy tubing punch assembly. Had to work down past 1819’ MD. No decentralizers included on this drift 2.80” and 2.70” gauge ring stopped at 1819’ MD o 2/18/21: CT drift with 2.80” x 4’ made it to 6480’ CTMD x MIT History: o 3/2/21: After 700psi gas pressure held on IA for 4.5 days, Fillup volume was 7.5bbls. Put 9bbls total into IA, but still failed MIT-IA to 1500psi. o 2/25/21: MIT-OA of 5-1/2” x 9-5/8” annulus failed to 1700psi Pumped 6.5bbls total o 2/24/21: MIT-OA of 5-1/2” x 9-5/8” annulus failed to 1500psi. Pumped 8bbls total o 2/23:21: MIT-IA of 3-1/2” x 5-1/2” to 4000psi failed. Couldn’t establish constant injectivity, just pressured up and bled off. 12bbls total pumped into IA o 2/19/21: PPPOT-T and PPPOT-IC each passed to 4800+psi (0/0/210) o 2/17/21: MIT-T of 3-1/2” passed to 1500psi passed (1660/0/0) MIT-IA of 3-1/2” x 5-1/2” to 1800psi failed. Couldn’t establish constant injectivity, just pressured up and bled off. 10bbls total pumped into IA o 1/12/21: 30 minute pressure test to 1500psi of the 5-1/2” x 2-7/8” annulus passed o 12/5/14: MIT-IA of 2-7/8” x 5-1/2” annulus to 2000psi passed o 12/3/14: MIT of 5-1/2" casing down to PBTD before tubing was run to 3500psi (pass) possible to theThe objective ofthis program is to restore a monitorable annulus with a cement packer as close as s p top of the pool, and obtain a passing MIT-IA, so sands can be completed, and the well operated. Well Prognosis Well: Paxton-09 Date: 3/12/2020 Remediation Objectives (in priority order) 1. Obtain a passing 1500psi MIT-IA of the 3-1/2” x 5-1/2” annulus 2. Install a cement packer as a bottom for a monitorable annulus between the 3-1/2” x 5-1/2” casings Want cement packer as close to top pool as possible (BEL_9B coal pick = 2480’ MD) Keep worst case ToC below ~1000’MD Keep planned IA ToC around ~1400’ MD (to match OA ToC, and original planned IA ToC from Sundry #321-035) 3. Remediate cement channel(s) from 2400-4000’ MD for future zonal isolation (all same pool) 4. Maintain 3-1/2” monobore Risk Mitigation / contingency Nitrogen o Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. o Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) o Ensure all crews are aware of stop work authority Punches have same low injectivity as prior surface rates. Attempt to breakdown with open IA (routed to a return tank). Switch cement product o FineCem for better squeeze properties.Consider laying in cement, and squeeze into IA (with IA open at surface).Forgo cement retainer IA locks up during squeeze Continue to pressure up, pump incremental volumes. Keep squeezing with an open IA initially, and then finish with a closed IA forcing at least 1 bbl downward.Be ready to unsting CT and circ remaining cement to surface. Punches connect to backside, but 'miss' channel Shoot in section with ringing pipe. Bring ToC up high to cover any other channels. Punch hits 5-1/2" casing Use tubing punchers, punch within 2' of collar Pre-sundry steps 1. Conduct PT of 5-1/2” x 3-1/2” annulus to 1500psi to confirm baseline integrity before punch a) Likely to fail b) Want to repeat falloff from previous attempts c) After fill-up, pressure up to 1800psi, and monitor falloff for 20mins Well Prognosis Well: Paxton-09 Date: 3/12/2020 EL Squeeze setup / Injectivity 2. MIRU pump truck and PT to 2500 psi. Have ~75bbls freshwater available 3. MIRU E-line and pressure control equipment. PT lubricator to 2,500 psi Hi 250 Low. 4. Rig up tubing puncher with GR/CCL (Likely 2” but may size down as needed) CONTINGENCY: May elect to move some/all of the below EL steps to CT or SL, if trouble falling down 5. RIH and punch ±2400 to ±2404’ MD. a) Ensure at least 100psi is held on tubing b) Target bottom punch 2’ uphole of collar at 2406’ MD c) Proximity to collar is more critical than actual MD depth d) Contact Geo/RE per below for tie-in before punching 6. Circulate down tubing through punches and up IA taking returns to surface a) Critical to track volumes in/out during this circulation b) Want to circulate at least 50 bbls (1 surface to surface volume) c) Discuss results with OE d) May elect to pump more volume if circulation is becoming easier e) Not OK to recycle same fluid. Top 1150’ of 3-1/2” tubing (10bbls) has freshwater with cement contaminate in it. Want that out of the well f)If low injectivity through punches SD after 6 bbls pumped, and contact OE. (don’t want to strand contaminate fluid in IA) g) Cap tubing with at least 1 bbl freeze protect 7. Close in IA and pump down tubing through punches taking returns to formation a) Inject at least 2 bbls b) Cap tubing with at least 1 bbl freeze protect 8. RU to IA and repeat injectivity test taking returns to formation with the tubing SI a) Want to compare against baseline from before and also ensure we didn’t penetrate the 5-1/2” casing. b) Cap IA with at least 1 bbl freeze protect 9. MU 3-1/2” composite bridge plug 10. RIH and set composite bridge plug at ±2410MD. a) Want to set just below tubing punches and avoid collars b) May have to pump the plug down through tubing punches taking returns to surface via IA c) If set on SL or CT, contact OE for new set depth, and depth control approach d) Pump down tubing after set to ensure punches are still open and communicating to IA CONTINGENCY: If injectivity through punches is low, may elect to forgo retainer set. Contact OE 11. MU 3-1/2” cement retainer 12. RIH and set at ±2390’ MD avoiding collars (may have to pump down as well) 13. If cement retainer allows, conduct 10 minute PT of 3-1/2” tubing against the cement retainer to 1500psi, bleed off to 0psi 14. RDMO EL and pump truck Contact AOGCC with injectivity results prior to pumping cement. BJM Consider max pressure of 4000 psi, same as initial tubing pressure test. BJM PT to 4000 psi to allow higher injectivity test and squeeze pressure. Consider max pressure of 4000 psi, same as initial tubing pressure test. BJM Well Prognosis Well: Paxton-09 Date: 3/12/2020 Coil squeeze 1. MIRU coil 2. Perform BOP test to 250psi low / 4000 high a. Notify AOGCC 24hrs in advance b. If SLB CT is used, BOP requirement may be met with scheduled weekly testing 3. MU cement retainer stinger BHA per vendor 4. RIH to above cement retainer and establish circulation using freshwater 5. Slowly sting into cement retainer and test CTxTubing annulus to 1500psi for 10 mins 6. Obtain baseline Injectivity rates down the CT a. CT x TBG backside shut in and the 3-1/2” x 5-1/2” annulus (IA) open to tanks b. Establish baseline injectivity pressures and rates down the CT. Target max rate. c. Document pressures and rates 7. Pump the squeeze schedule down CT and into IA, taking returns to surface out the 5-1/2” x 3-1/2” annulus a. Volumes and max pressures will be adjusted based on injectivity parameters b. Targeting 15bbls cement volume behind pipe c. This places worst case ToC with an empty annulus at ~1080’ MD d. With good injectivity down CT and taking returns up IA, traditional high compressive strength cement will be used (15.3 – 15.8ppg) e. If injectivity is low, may change cement blend to a 13ppg FineCem squeeze cement, TBD 8. Displace cement through CT to get cement to the punches. If injectivity is low, might need to displace cement through CT while un-stung, and then sting back into the retainer a few bbls away from cement hitting nozzle 9. Once cement is at the punches and before attempting to attain squeeze pressure on the well, attempt to circulate all cement behind pipe taking returns to surface with an open IA 10. Once all but 1 bbl cement is out of the nozzle, un-sting and lay in remaining cement volume on top of retainer 11. Open CT x TBG backside and circulate gel for contamination to the stinger. Contaminate cement to top of retainer and POOH. Take care to wash and contaminate across SSSV profile at 166’ MD 12. Bleed SITP down to 0psi 13. RU to 3-1/2” x 5-1/2” IA and squeeze cement down into channel a. Max P will be determined via pre-job injectivity parameters b. Plan to displace no more than 4bbls after any fillup volume c. This places final ToC at target depth of 1430’MD in 3-1/2” x 5-1/2” annulus 14. WoC per vendor 15. MIT-IA to 1500psi charted for 30 minutes 16. Once pass, MU CT motor/mill assembly 17. RIH and mill up cement retainer, cement, and CBP and push to PBTD = 6458’ MD. 18. MIT-T to 1500psi for 30 minutes (charted) 19. MU and RIH with memory CBL and log from ~5000’ to surface. 20. Confirm good data, and then RU nitrogen, and review N2 SOP before displacement 21. MU nozzle BHA, and RIH to PBTD displacing all fluid out of well to tanks with N2 (expected WBV ~57bbls) 22. POOH W/ coil. Leave 1200 psi trapped on tubing for upcoming perforating Circulate a few barrels cement into IA, then close IA valve and attempt to squeeze cement downard. Squeeze a few bbls away if possible before opening IA and circulating remaining cement upward. BJM State max pressure for squeeze. Well Prognosis Well: Paxton-09 Date: 3/12/2020 Below scope was previously approved on 1/28/21 (#321-035). Minor modifications and consolidation below Contingency: Below perforating work may be moved to EL/Tractor or kept on e-coil. TBD 23. RU E-Line Data Acquisition Unit 24. RU perf guns. Likely 2-3/8” guns with 4-6 spf 25. RIH and perforate the below intervals per Geo/RE: Sand MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) BEL 41 ± 3,640 ± 3,704 ±1,791'±1,808'64' BEL 44 ± 3,833 ± 3,865 ±1,845'±1,855'32' BEL 45 ± 3,872 ± 3,880 ±1,857'±1,859'8' BEL 45 ± 3,930 ± 3,939 ±1,873'±1,876'9' BEL 45 ± 3,946 ± 3,957 ±1,878'±1,881'11' BEL 45 ± 3,979 ± 3,984 ±1,887'±1,889'5' BEL_47 ±4,065'±4,099'±1,912'±1,922'34' BEL 49 ± 4,362 ± 4,372 ±2,005'±2,008'10' BEL 49 ± 4,427 ± 4,436 ±2,029'±2,032'9' BEL 52 ± 4,643 ± 4,649 ±2,118'±2,120'6' BEL 52 ± 4,659 ± 4,677 ±2,124'±2,132'18' BEL 52 ± 4,705 ± 4,725 ±2,144'±2,153'20' BEL_53 ±4,789'±4,905'±2,180'±2,232'116' BEL_56 ±5,083’±5,096’±2,316'±2,322'13’ BEL_58A ±5,216’±5,243’±2,385'±2,400'27’ BEL_60 ± 5,390 ± 5,427 ± 2,485 ± 2,507 37' BEL_73L ± 5,598 ± 5,613 ± 2,614 ± 2,624 15' BEL_74 ± 5,652 ± 5,699 ± 2,650 ± 2,682 47' BEL_82U ± 5,803 ± 5,816 ± 2,756 ± 2,765 13' BEL_82L ± 5,834 ± 5,849 ± 2,778 ± 2,789 15' BEL_83 ± 5,867 ± 5,885 ± 2,802 ± 2,816 18' BEL_97 ± 6,362 ± 6,374 ± 3,194 ± 3,204 12' Consult with OE for what WHP to use for each perf set. Some may be shot while the well is flowing, also. a. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. b.Use Gamma/CCL to correlate. c. Record initial and 5/10/15 minute tubing pressures after firing d. Consult with RE/Geo between each perf interval: i. Anthony McConkey: RE - 529-6199 ii. Matthew Petrowsky: Geo – 814-421-6753 26. Once sufficient production has been added per RE/Geo, RD E-Line Unit and Coiled Tubing Unit and turn well over to production. Well Prognosis Well: Paxton-09 Date: 3/12/2020 CT Plug or patch (CONTINGENT) 1. If these zones produce sand and/or water and need to be isolated: 2. Perform BOP test to 250psi low / 4000 high: Notify AOGCC 24hrs in advance 3. RIH and set 3-1/2” patch or set CIBP above the zone 4. RDMO CT May be set on Tractor if not e-coil. TBD SL install SSSV 27. RU SL and install WL-SSSV. The valve must be performance-tested within 5 days after stabilized production is achieved. 28. RDMO SL Attachments: 1. Current schematic 2. Proposed Schematic 3. Standard Well procedure – N2 Operations 5 days after return to production. Updated by CRR 3-5-2021 SCHEMATIC Ninilchik Unit Well: Paxton #9 PTD:214-173 API: 50-133-20647-00-00 PBTD = 6,458 MD /3,273’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ 9-5/8” cement Job: 12-1/4” hole. 137 bbls of 12.5 Type I lead and 65bbls 15.2# tail. 100% returns with cement to surface 5-1/2” cement job: 8-1/2” hole. 145 bbls of 13.5# class G lead, and 93 bbls of 15.7# class G tail. Full returns throughout job. Volumetric ToC at ~1450’ MD assuming 10% openhole washout. 40 bbls spacer pumped, and 40 bbls back to surface (no cement seen) 3-1/2” Cement Job: 42bbls of 12ppg lead and 18bbls 15.3 tail. No losses throughout job (had losses pre-job). Good lift pressure, but cement must have fallen back after job. (had losses pre-job). Good lift pressure, but cement must have fallen back after job. 2/18/21 Radial CBL:Solid cement up to ~4210’ MD (base BEL_47C squeeze perfs). Patchy cement up to 1850’ MD, free pipe at 890’ MD 1 16” 9-5/8” 8-1/2” Hole 5.5” No.MD TVD ID Item 1 166’166’2.812”SSSV hydraulic landing nipple (SLB BP-6i)-No valve/sleeve currently 2 6570’Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) from 1/15/15. Tagged at 6586’ CTMD 7/25/20 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16”Conductor 109 / X-56 / Weld Surf 80’ 9-5/8'Surface 40 /L-80 / BTC 8.835”Surf 2,291’ 5-1/2"Production 17 / P-110 / CDC 4.892”Surf 6,723' TUBING DETAIL 3-1/2”Tubing / Scab Liner 9.2# / L-80 / Supermax 2.995” Surf 6,481’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)Ft Date Status BEL_47A 4,070'4,082'1,914'1,917'12'7/28/20 Squeezed (2/15/21) BEL_47A 4,082'4,096'1,917'1,921'14'7/28/20 Squeezed (2/15/21) BEL_47C 4,179'4,194'1,946'1,950'15'7/27/20 Squeezed (2/15/21) BEL_47C 4,194'4,209'1,950'1,955'15'7/26/20 Squeezed (2/15/21) Bel 53/ Blg50channel 4,790’4,802’2,181’2,186’ 12 1/13/15 Squeezed (2/15/21) Bel 53/ Blg50channel 4,802’4,822’2,186’2,195’20 4/20/15 Squeezed (2/15/21) Bel 53 4,819’4,839’2,194’2,202’20 1/11/20 Squeezed (2/15/21) Bel 53 4,839’4,859’2,202’2,211’20 1/10.20 Squeezed (2/15/21) Bel 53 4,863’4,883’2,213’2,222’20 1/10/20 Squeezed (2/15/21) Bel 53 4,883’4,903’2,222’2,231’20 1/9/20 Squeezed (2/15/21) 2 1450’ ToC (volumetric) Updated by CRR 3-11-2021 PROPOSED SCHEMATIC Ninilchik Unit Well: Paxton #9 PTD:214-173 API: 50-133-20647-00-00 PBTD = 6,458 MD /3,273’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ 9-5/8” cement Job: 12-1/4” hole. 137 bbls of 12.5 Type I lead and 65bbls 15.2# tail. 100% returns with cement to surface 5-1/2” cement job: 8-1/2” hole. 145 bbls of 13.5# class G lead, and 93 bbls of 15.7# class G tail. Full returns throughout job. Volumetric ToC at ~1450’ MD assuming 10% openhole washout. 40 bbls spacer pumped, and 40 bbls back to surface (no cement seen) 3-1/2” Cement Job: 42bbls of 12ppg lead and 18bbls 15.3 tail. No losses throughout job (had losses pre-job). Good lift pressure, but cement must have fallen back after job. (had losses pre-job). Good lift pressure, but cement must have fallen back after job. 2/18/21 Radial CBL:Solid cement up to ~4210’ MD (base BEL_47C squeeze perfs). Patchy cement up to 1850’ MD, free pipe at 890’ MD 1 16” 9-5/8” 8-1/2” Hole 5.5” No.MD TVD ID Item 1 166’166’2.812”SSSV hydraulic landing nipple (SLB BP-6i)-No valve/sleeve currently 2 6570’Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) from 1/15/15. Tagged at 6586’ CTMD 7/25/20 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16”Conductor 109 / X-56 / Weld Surf 80’ 9-5/8'Surface 40 /L-80 / BTC 8.835”Surf 2,291’ 5-1/2"Production 17 / P-110 / CDC 4.892”Surf 6,723' TUBING DETAIL 3-1/2”Tubing / Scab Liner 9.2# / L-80 / Supermax 2.995” Surf 6,481’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)Ft Date Status Sqz punches 2,440'2,444'TBD BEL_47A 4,070'4,082'1,914'1,917'12'7/28/20 Squeezed (2/15/21) BEL_47A 4,082'4,096'1,917'1,921'14'7/28/20 Squeezed (2/15/21) BEL_47C 4,179'4,194'1,946'1,950'15'7/27/20 Squeezed (2/15/21) BEL_47C 4,194'4,209'1,950'1,955'15'7/26/20 Squeezed (2/15/21) Bel 53/ Blg50channel 4,790’4,802’2,181’2,186’ 12 1/13/15 Squeezed (2/15/21) Bel 53/ Blg50channel 4,802’4,822’2,186’2,195’20 4/20/15 Squeezed (2/15/21) Bel 53 4,819’4,839’2,194’2,202’20 1/11/20 Squeezed (2/15/21) Bel 53 4,839’4,859’2,202’2,211’20 1/10.20 Squeezed (2/15/21) Bel 53 4,863’4,883’2,213’2,222’20 1/10/20 Squeezed (2/15/21) Bel 53 4,883’4,903’2,222’2,231’20 1/9/20 Squeezed (2/15/21) Proposed perfs per sundry 2 1450’ ToC (volumetric) 1430’ ToC (Planned) 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. Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE : 02/24/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL PAXTON 9 (PTD 214-173) Memory Radial Cement Bond Log 02/18/2021 Please include c urrent contact information if different from above. PTD:2141730 E-Set: 34752 Received by the AOGCC 03/08/2021 03/09/2021 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: __N2 / Cement Packer__ 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/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 6,733'6570' Casing Collapse Structural Conductor Surface 3,090 psi Intermediate Production 7,480 psi Liner 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 Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 Date: Conditions of approval: Notify Commission 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 COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: January 28, 2020 2-7/8" 6,726' Perforation Depth MD (ft): See Attached Schematic 6,726'3,495'5-1/2" 16" 9-5/8" 80' 2,269'5,750 psi1,401' 80' 2,291' 6.4# / L-80 TVD Burst 3,482' 10,640 psi MDLengthSize CO 701C Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0384372 / FEE-PRIVATE 214-173 50-133-20647-00-00 Paxton 09 Ninilchik Field / BELUGA-TYONEK GAS Pool COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic ryan.rupert@hilcorp.com 3,503'6,643'3,428'~1164 psi none Prod Pkr; SLB TRMAXX 5E SCSSSV 3,394' MD / 1,722' TVD; 170' MD / 170' TVD Perforation Depth TVD (ft):Tubing Size: m n P s t 66 Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:55 am, Jan 19, 2021 321-035 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2021.01.15 16:02:19 -09'00' Taylor Wellman _N2 / Cement Packer_ 10-404 Petrospec CT DSR-1/19/21 *2500 psi BOPE test (Rig 401) *4000 psi BOPE test (CT Petrospec) Perforate rig 401 SFD 1/19/2021gls 1/28/21 X Comm 1/28/21 dts 1/28/2021 JLC 1/28/2021 RBDMS HEW 1/29/2021 Well Prognosis Well: Paxton-09 Date: 1/12/2020 Well Name:Paxton-09 API Number:50-133-20647-00-00 Current Status:Gas Producer Leg:N/A Estimated Start Date:1/28/21 Rig:401 Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:214-173 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (C) Second Call Engineer:Jake Flora (907) 777-8442 (O)(720) 988-5375 (C) Maximum Expected BHP:~ 1496 psi @ 3,324’ TVD (Based on a 0.45 psi/ft gradient) Max. Potential Surface Pressure:~ 1164 psi Using Max BHP minus 0.1 psi/ft. gas gradient to surface). Well Summary Paxton 9 was drilled and completed in December 2014 as a grassroots well to target gas sands in the Beluga formation. In January 2015 and April-2015 the Beluga 50 channel was perforated, and the well produced at 1.5MM with no water. It slowly declined from there, but sustained production for years. In January 2020 production had fallen to <400MCFD, but still no water to surface. The Beluga 53 sands were perforated deeper in the well below the existing perfs. The fluid level before perforating was found at 4820’ MD (below all open perfs) Production went on a steeper decline, but still no water to surface. E-Coil came back in July-2020 when the well was making 100-300 MCF and no water at 75 psi FTP. FL was found at 3728’ (~1000’ above all open perfs). Uphole adperfs were added in the BEL-47A and BEL-47C. No real pressure response was seen when shooting the 47C, but the 47A did quickly build up to 575psi. The well came on at >1MM, and 20-70bwpd. It subsequently declined to <100MCF and is struggling to stay online. The purpose of this work/sundry is to isolate all existing sands and the current water production, and then selectively recomplete the well starting with deeper unperforated sands in the Beluga formation, and work our way uphole. Notes Regarding Wellbore Condition x Well goes >70 degrees inclination at ~1400’ MD, and sails at 75 degrees until 4000’ MD where it starts to turn vertical again, and ends up at 65 degrees at the top of the Beluga-53 and gets back to 33 degrees at PBTD. x Drifts o 7/25/20: CT tagged top of fish at 6586’ CTMD o Jan-2020: CT made several runs as deep as 4903’ MD with 2” x 20’ guns x MIT History: o 12/3/2014: MIT of 5-1/2" casing down to PBTD before tubing was run to 3500psi (pass) o 12/5/2014: MIT-T of 2-7/8" tubing to 4500 psi passed o 12/5/2014: MIT-IA of 2-7/8” x 5-1/2” annulus to 2000psi passed o 1/12/21: 30 minute pressure test to 1500psi of the 9-5/8” x 5-1/2” annulus passed The purpose of this work/sundry is to isolate all existing sands and the current water production, and then selectively recomplete the well starting with deeper unperforated sands in the Beluga formation, and work our way uphole. Well Prognosis Well: Paxton-09 Date: 1/12/2020 Risks x Nitrogen o Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. o Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) o Ensure all crews are aware of stop work authority x Fish o An EL tractor fish was left in the hole 1/15/15 (73’ long). It was last tagged on 7/25/20 at 6586’ CTMD. o There is room to get beside the fish with through tubing tools o Use caution when approaching fish depth Objectives: x Shut off existing water production x Access deeper sands and selectively complete per below x Create a 3-1/2” monobore to allow for a perf/plug completion approach x Reestablish monitorable annulus Rig 401 Procedure 1. MIRU 401 workover rig. Provide 24hr notice to AOGCC of BOP Test. 2. Kill well down the tubing with 6% KCL (WBV to deepest perf ~52 bbls) 3. Set BPV, ND Tree, NU BOP. 4. Perform BOP Test to 250 psi low & 2,500 psi high, annular to 250 psi low & 2,500 psi high. Test BOP’s on 2-7/8” and 3-1/2” pipe. Record with chart & submit to AOGCC within 5 days of test. 5. Rigup and release 2-7/8” tubing from packer anchor at 3393’ MD a. 2-7/8” x 5-1/2” IA is loaded with 6% KCL and 3% corrosion inhibitor b. Tubing anchor should release with tension and rotation c. Consult Baker rep for exact pulling procedure d. CONTINGENT if tubing will not pull: i. RU EL ii. Perform BOP Test 250 psi low & 2,500 psi high iii. Perform tubing cut (may have to pump down) 6. Circ at least 1 bottoms up to ensure communication, and ensure same KWF is all the way around 7. POOH with 2-7/8” tubing 8. MU packer milling assembly per vendor rep 9. RIH on workstring and mill packer per vendor rep 10. Retrieve/fish packer and tailpipe assembly per vendor rep Contingency: Depending on complexity of fishing, may elect to push packer assembly to PBTD and leave in rathole will cut tubing (tubing punch above packer) and set plug in tubing tail NOTE: Need to pump down tools in this wellbore. gls Pull completion Well Prognosis Well: Paxton-09 Date: 1/12/2020 11. Pickup and RIH with 3-1/2” scab liner to bottom at ~6580’ MD with float shoe, float collar, and shoe track. An SSSV landing nipple is required, as well. New PBTD estimated at ~6560’ MD. 12. Cement 3-1/2” a. RU cement head b. Mix and pump ±83bbls cement down scab liner taking returns up 3-1/2” x 5-1/2” IA. c. Drop wiper plug and displace with ±56.8 bbls lease water to bump plug. d. Planned TOC is 1000’ which is ~400’ MD above top anticipated hydrocarbon bearing zone 13. ND BOP, NU Tree, RDMO. 14. WoC and then perform MIT’s a. MIT-T of 3-1/2” scab liner to 1500psi b. MIT-IA of 3-1/2” x 5-1/2” to 1500psi e-Coil Procedure 1. MIRU e-coil 2. Perform BOP test to 250psi low / 4000 high (notify AOGCC 24hrs in advance) 3. MU drift BHA for logging tools and 3-1/2” CIBP 4. Drift to PBTD Contingency: If drift has issues getting down to target perf depths, consult OE about a motor/mill run. 5. MU memory cement logging/GR/CCL BHA 6. RIH and acquire cement log data from PBTD to surface 7. Confirm good data, report CBL data to state, and RD memory loggers 8. RU nitrogen 9. MU nozzle BHA, and RIH to PBTD displacing all fluid out of well to tanks with N2 (expected WBV ~57bbls) 10. Consult OE for what nitrogen pressure to leave on well 11. RU E-Line Data Acquisition Unit 12. RU perf guns. Likely 2-3/8” guns with 4-6 spf 13. RIH and perforate the below intervals per Geo/RE: (submit CBL to AOGCC prior to perfing) 5560 ft x .0113= 63 bbls (notify AOGCC 24hrs in advance) Perforate well (notify inspector if PetroSpec CTU is used) 3.5" = .0087 bpf 3.5"x5.5"=.0113bpf(chart 30 min) Run scab liner TBD (Chart 30 min) TOC planned from 1400ft to 2500 ft md depending on losses. CBL Well Prognosis Well: Paxton-09 Date: 1/12/2020 Sand MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) BEL 41 ± 3,640 ± 3,704 ±1,791'±1,808'64' BEL 44 ± 3,833 ± 3,865 ±1,845'±1,855'32' BEL 45 ± 3,872 ± 3,880 ±1,857'±1,859'8' BEL 45 ± 3,930 ± 3,939 ±1,873'±1,876'9' BEL 45 ± 3,946 ± 3,957 ±1,878'±1,881'11' BEL 45 ± 3,979 ± 3,984 ±1,887'±1,889'5' BEL_47 ±4,065'±4,099'±1,912'±1,922'34' BEL 49 ± 4,362 ± 4,372 ±2,005'±2,008'10' BEL 49 ± 4,427 ± 4,436 ±2,029'±2,032'9' BEL 52 ± 4,643 ± 4,649 ±2,118'±2,120'6' BEL 52 ± 4,659 ± 4,677 ±2,124'±2,132'18' BEL 52 ± 4,705 ± 4,725 ±2,144'±2,153'20' BEL_53 ±4,789'±4,905'±2,180'±2,232'116' BEL_60 ± 5,390 ± 5,427 ± 2,485 ± 2,507 37' BEL_73L ± 5,598 ± 5,613 ± 2,614 ± 2,624 15' BEL_74 ± 5,652 ± 5,699 ± 2,650 ± 2,682 47' BEL_82U ± 5,803 ± 5,816 ± 2,756 ± 2,765 13' BEL_82L ± 5,834 ± 5,849 ± 2,778 ± 2,789 15' BEL_83 ± 5,867 ± 5,885 ± 2,802 ± 2,816 18' BEL_97 ± 6,362 ± 6,374 ± 3,194 ± 3,204 12' BEL_100 ± 6,474 ± 6,491 ± 3,287 ± 3,301 17' BEL_105 ± 6,507 ± 6,518 ± 3,314 ± 3,324 11' Consult with OE for what WHP to use for each perf set. Some may be shot while the well is flowing, also. a. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. b.Use Gamma/CCL to correlate. c. Record initial and 5/10/15 minute tubing pressures after firing d. Consult with RE/Geo between each perf interval: i. Anthony McConkey: RE - 529-6199 ii. Matthew Petrowsky: Geo – 814-421-6753 14. Once sufficient production has been added per RE/Geo, RD E-Line Unit and Coiled Tubing Unit and turn well over to production. 15. RU SL and install WL-SSSV. The valve must be performance-tested within 5 days after stabilized production is achieved. 16. RDMO SL Attachments: 1. Current schematic 2. Proposed Schematic 3. Rig 401 BOP schematic 4. RWO change form 5. Standard Well procedure – N2 Operations Updated by CRR 1-6-2021 SCHEMATIC Ninilchik Unit Well: Paxton #9 PTD:214-173 API: 50-133-20647-00-00 PBTD = 6,643 MD / 3,428’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ 9-5/8” cement Job: 12-1/4” hole. 137 bbls of 12.5 Type I lead and 65bbls 15.2# tail. 100% returns with cement to surface 5-1/2” cement job: 8-1/2” hole. 145 bbls of 13.5# class G lead, and 93 bbls of 15.7# class G tail. Full returns throughout job. Volumetric ToC at ~1450’ MD assuming 10% openhole washout. 40 bbls spacer pumped, and 40 bbls back to surface (no cement seen) 1 5 16” 9-5/8” 8-1/2” Hole 5.5” JEWELRY DETAIL No.MD TVD ID OD Item 1 154’154’CIM 2 170’170’2.312”4.609”SLB TRMAXX 5E SCSSSV 3 3,394’1,722’BOT 3-1/2” (crossed over) SABL-3 permanent production packer 4 3,443’1,737’3.25”X-Nipple 5 3,482’1,748’Wireline re-entry guide 2 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16”Conductor 109 / X-56 / Weld Surf 80’ 9-5/8'Surface 40 /L-80 / BTC 8.835”Surf 2,291’ 5-1/2"Production 17 / P-110 / CDC 4.892”Surf 6,723' TUBING DETAIL 2-7/8"Tubing 6.4 / L-80 / EUE-8rd 2.441”Surf 3,482’ 3 4 PERFORATION DETAIL Sands Top (MD)Btm (MD)Top (TVD)Btm (TVD)Ft Date Status BEL_47A 4,070'4,082'1,914'1,917'12'7/28/20 Open BEL_47A 4,082'4,096'1,917'1,921'14'7/28/20 Open BEL_47C 4,179'4,194'1,946'1,950'15'7/27/20 Open BEL_47C 4,194'4,209'1,950'1,955'15'7/26/20 Open Bel 53/ Blg50channel 4,790’4,802’ 2,181’ 2,186’ 12 1/13/15 Open Bel 53/ Blg50channel 4,802’4,822’ 2,186’ 2,195’ 20 4/20/15 Open Bel 53 4,819’4,839’2,194’2,202’20 1/11/20 Open Bel 53 4,839’4,859’2,202’2,211’20 1/10.20 Open Bel 53 4,863’4,883’2,213’2,222’20 1/10/20 Open Bel 53 4,883’4,903’2,222’2,231’20 1/9/20 Open FISH @ 6,570’ 01/15/15 Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length). Tagged at 6586’ CTMD 7/25/20 1450’ ToC (volumetric) Updated by CRR 1-12-2021 PROPOSED SCHEMATIC Ninilchik Unit Well: Paxton #9 PTD:214-173 API: 50-133-20647-00-00 PBTD = 6,643 MD / 3,428’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ 9-5/8” cement Job: 12-1/4” hole. 137 bbls of 12.5 Type I lead and 65bbls 15.2# tail. 100% returns with cement to surface 5-1/2” cement job: 8-1/2” hole. 145 bbls of 13.5# class G lead, and 93 bbls of 15.7# class G tail. Full returns throughout job. Volumetric ToC at ~1450’ MD assuming 10% openhole washout. 40 bbls spacer pumped, and 40 bbls back to surface (no cement seen) 1 16” 9-5/8” 8-1/2” Hole 5.5” JEWELRY DETAIL No.MD TVD ID OD Item 1 150 2.8 4.5 SSSV hydraulic landing nipple 2 6570’ Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length)from 1/15/15. Tagged at 6586’ CTMD 7/25/20 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16”Conductor 109 / X-56 / Weld Surf 80’ 9-5/8'Surface 40 /L-80 / BTC 8.835”Surf 2,291’ 5-1/2"Production 17 / P-110 / CDC 4.892”Surf 6,723' TUBING DETAIL 3-1/2”Tubing / Scab Scab Liner 9.2# / L-80 2.995” Surf 6,580’ PERFORATION DETAIL Sands Top (MD)Btm (MD)Top (TVD)Btm (TVD)Ft Date Status BEL_47A 4,070'4,082'1,914'1,917'12'7/28/20 To be Sqz BEL_47A 4,082'4,096'1,917'1,921'14'7/28/20 To be Sqz BEL_47C 4,179'4,194'1,946'1,950'15'7/27/20 To be Sqz BEL_47C 4,194'4,209'1,950'1,955'15'7/26/20 To be Sqz Bel 53/ Blg50channel 4,790’4,802’ 2,181’ 2,186’ 12 1/13/15 To be Sqz Bel 53/ Blg50channel 4,802’4,822’ 2,186’ 2,195’ 20 4/20/15 To be Sqz Bel 53 4,819’4,839’2,194’2,202’20 1/11/20 To be Sqz Bel 53 4,839’4,859’2,202’2,211’20 1/10.20 To be Sqz Bel 53 4,863’4,883’2,213’2,222’20 1/10/20 To be Sqz Bel 53 4,883’4,903’2,222’2,231’20 1/9/20 To be Sqz 2 1450’ ToC (volumetric) 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. The picture can't be displayed.The picture can't be displayed.The picture can't be displayed.The picture can't be displayed. 11" Spherical Annular Height: 42" 11" LWS Double BOP 2-7/8" to 5" Multirams top Blind rams bottom Height:33" 11" Mud Cross W/ 4-1/16" Outlets Dual 2-1/16" Manual Gate Valves W/ DSA to 4-1/16" Width to flange: 34" 2-1/16" Manual Gate Valve & 2-1/16" HCR W/ DSA to 4- 1/16" Full Mud Cross Assy. width w/ valves installed Width: 96" Kill side Choke side BOP Stack Width: 96" @ valves Height Addition for Ring Gaskets: .75" BOP Total Height: 101.75" 11" 5m BOP Package W/ 2-1/16" Valves Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well Paxton-09 (PTD 214-173)Sundry #:Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.SecPageDateProcedure ChangeNew 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date 1 Carlisle, Samantha J (CED) From:Schwartz, Guy L (CED) Sent:Thursday, January 28, 2021 11:54 AM To:Ryan Rupert Cc:Donna Ambruz Subject:RE: [EXTERNAL] Paxton 9 RWO (PTD 214-173) Thecontingencyisalreadyinplacetocuttubing.Iwillmakeanoteintheprogramstatingitwillbethepreferred. AlsotheTOCintheannuluscanbeadjustedonthefly.Itneedstobe250ftTVDaboveanyhydrocarbonstobein compliance.WewilllogitafterwardswithCBLtoverify. GuySchwartz Sr.PetroleumEngineer AOGCC 907Ͳ301Ͳ4533cell 907Ͳ793Ͳ1226office 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 Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). From:RyanRupert<Ryan.Rupert@hilcorp.com> Sent:Wednesday,January27,20219:18PM To:Schwartz,GuyL(CED)<guy.schwartz@alaska.gov> Cc:RyanRupert<Ryan.Rupert@hilcorp.com>;DonnaAmbruz<dambruz@hilcorp.com> Subject:RE:[EXTERNAL]Paxton9RWO(PTD214Ͳ173) You’recorrectGuy.ImisͲcalculated.Weareplanningfor~58bblsofcementcurrentlywhichwouldbringToCupto ~1400’MDtomatchthe9Ͳ5/8”x5Ͳ1/2”estimatedToC.Ioriginallywantedtogohigherformorebuffer,buttheopen perfshaveareservoirpressureof300Ͳ500psi,sotomitigatebreakingdownthosesands,I’mlookingataToCof1400’ rightnow.ThatToCmayneedtobeloweredasdeepas2500’MDtolowerpressuresinthe3Ͳ1/2”x5Ͳ1/2”annulus, TBD.IfwehavelossestothoseperfsduringtheRWO,wemayelecttopumpexcesscementtomatchthelosses,and targetthesameToC,ifthat’sokbyyou? Also,Iwillneedtodoatubingcutasmyprimarydecompletestep.Wedon’twanttorotatetheexistingstringto release,asithascontrollinesandacheminjline.Thesundryhaslanguagealreadyaboutatubingcut.Woulditbeok topunchthetubingfirst,soIstillhaveapumpdownoption(returnsuptheIA)forthetubingcutterafterIhopefullyset aTTP? Sorryfortheerrorinvolumes,andthanksforthetime,Guy.HopefullywecanstartpreͲrigworkthisweekend,and movetherigonearlynextweek.Thanks! 2 Ryan Rupert Kenai Ops Engineer (13146) 907-301-1736 (Cell) 907-777-8503 (Office) From:Schwartz,GuyL(CED)[mailto:guy.schwartz@alaska.gov] Sent:Wednesday,January27,20214:51PM To:RyanRupert<Ryan.Rupert@hilcorp.com> Subject:[EXTERNAL]Paxton9RWO(PTD214Ͳ173) Ryan, Step12intheproceduredoesn’taddup.Mycalcsshowyouwillgetcementtosurfaceinthe3.5x5.5”annulusbased onvolumepumped.Areyoutakingreturnstillyougetapprox.1000ftforTOCandthensqzawaycementintoperfs? GuySchwartz Sr.PetroleumEngineer AOGCC 907Ͳ301Ͳ4533cell 907Ͳ793Ͳ1226office 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 Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). 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.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: _Install capilary String_ 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/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 6,733'6570' Casing Collapse Structural Conductor Surface 3,090 psi Intermediate Production 7,480 psi Liner 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.W ell Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 Date: Conditions of approval: Notify Commission 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 COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: November 15, 2020 2-7/8" 6,726' Perforation Depth MD (ft): See Attached Schematic 6,726'3,495'5-1/2" 16" 9-5/8" 80' 2,269'5,750 psi1,401' 80' 2,291' 6.4# / L-80 TVD Burst 3,482' 10,640 psi MDLengthSize CO 701C Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0384372 / FEE-PRIVATE 214-173 50-133-20647-00-00 Paxton 09 Ninilchik Field / BELUGA-TYONEK GAS Pool COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic ryan.rupert@hilcorp.com 3,503'6,643'3,428'~780 psi none Prod Pkr; SLB TRMAXX 5E SCSSSV 3,394' MD / 1,722' TVD; 170' MD / 170' TVD Perforation Depth TVD (ft):Tubing Size: m n P s t _ 66 Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 10:51 am, Nov 16, 2020 320-487 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.11.16 08:29:29 -09'00' Taylor Wellman _Install capilary String_ gls 11/20/20 DSR-11/17/2020 10-404X DLB11/17/2020 q C 11/20/2020 dts 11/20/2020 JLC 11/20/2020 RBDMS HEW 11/25/2020 Well Prognosis Well: Paxton-09 Date: 11/10/2020 Well Name:Paxton-09 API Number:50-133-20647-00 Current Status:Producing Gas Well Leg:N/A Estimated Start Date:11/20/20 Rig:N/A Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:214-713 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (M) Second Call Engineer:Ted Kramer (907) 777-8420 (O)(985) 867-0665 (M) Max. Expected BHP:~ 1,003 psi @ 2,231’ TVD (Based on .45 Pressure Gradient.) Max. Potential Surface Pressure:~ 780 psi (Based on max BHP minus less gas gradient to surface (0.10psi/ft)) Brief Well Summary Paxton-09 came online in 2015 at rates > 1500mcf. The well had a very steady and slow decline from there until perfs were added in July-2020. These uphole perfs brought the gas rate up from ~100 mcf to ~1000mcf. The well slowly declined from there, making 15-40 bwpd, until mid-October when the water rate died, and the gas rate began to fall off. The well is now making ~200mcf. The purpose of this work/sundry is to install a Capillary String in the well to allow for soap to be injected to help unload water. Base plan will be to run it to the bottom of the tubing tail, and then if needed after some production data, we can run it deeper, if needed. Notes Regarding Wellbore Condition x CT tagged top of fish at 6586’ CTMD on 7/26/20 x CT made down to 4450 with 2” perf guns on 7/28/20 x FL found at 3628’ MD on 7/27/20 (before adperfs) x Inclination o Well goes > 70deg inclination at ~1350’ MD o Sail angle of ~75 from 1350’ – 4200’ MD, then rolls over to 35 degrees by PBTD x Historic tractor runs had to use tractor starting at ~1300’ MD (almost 70deg) all the way to PBTD Procedure: 1. RU Cap String Truck. 2. Stab 3/8” capillary line into wellhead pack-off assembly. Make up BHA components. Install pack-off and pressure test against swab valve 250 psi low/3,000 psi high. 3. RIH with 3/8” capillary string to ±3425’ MD. (keep cap string within tubing for initial deployment, may go deeper later) 4. Install slips and connect tubing to chemical injection pump. 5. Set spool of remaining line near well 6. RD cap string Unit, and turn well over to production. Attachments: 1. Proposed Schematic NOTE: ScSSV will not be operational with Cap string installed. SSV is in horizontal run. gls 11/20/20 Updated by CRR 11-10-2020 SCHEMATIC Ninilchik Unit Well: Paxton #9 PTD:214-173 API: 50-133-20647-00-00 PBTD = 6,643 MD / 3,428’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ 1 3 7 16” 9-5/8” 8-1/2” Hole 5.5” JEWELRY DETAIL No.MD TVD ID OD Item 1 154’154’CIM 2 170’170’2.312”4.609”SLB TRMAXX 5E SCSSSV 3 3,393’1,722’XO 4 3,394’1,722’Prod Pkr 5 3,399’1,724’XO 6 3,443’1,737’3.25”X-Nipple 7 3,482’1,748’Wireline re-entry guide 2 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16”Conductor 109 / X-56 / Weld Surf 80’ 9-5/8'Surface 40 /L-80 / BTC 8.835”Surf 2,291’ 5-1/2"Production 17 / P-110 / CDC 4.892”Surf 6,723' TUBING DETAIL 2-7/8"Tubing 6.4 / L-80 / EUE-8rd 2.441”Surf 3,482’ 456 PERFORATION DETAIL Sands Top (MD)Btm (MD)Top (TVD)Btm (TVD)Ft Date Status BEL_47A 4,070'4,082'1,914'1,917'12'7/28/20 Open BEL_47A 4,082'4,096'1,917'1,921'14'7/28/20 Open BEL_47C 4,179'4,194'1,946'1,950'15'7/27/20 Open BEL_47C 4,194'4,209'1,950'1,955'15'7/26/20 Open Bel 53/ Blg50channel 4,790’4,802’ 2,181’ 2,186’ 12 1/13/15 Open Bel 53/ Blg50channel 4,802’4,822’ 2,186’ 2,195’ 20 4/20/15 Open Bel 53 4,819’4,839’2,194’2,202’20 1/11/20 Open Bel 53 4,839’4,859’2,202’2,211’20 1/10.20 Open Bel 53 4,863’4,883’2,213’2,222’20 1/10/20 Open Bel 53 4,883’4,903’2,222’2,231’20 1/9/20 Open BEL_47A BEL_47C BEL_53 FISH @ 6,570’ 01/15/15 Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) Proposed Cap String 3/8” tubing from surface to ±3,425’ MD ScSSV 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: N2 Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 6,733 feet N/A feet true vertical 3,503 feet 6,570 feet Effective Depth measured 6,643 feet 3,394 feet true vertical 3,428 feet 1,722 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)2-7/8" 6.4# / L-80 3,482' MD 1,748' TVD SBL TRMAXX 5E SCSSSV 170' MD 170' TVD Packers and SSSV (type, measured and true vertical depth)Prod Pkr 3,394' MD 1,722' TVD 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 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: Taylor Wellman 777-8449 Contact Name:Todd Sidoti Authorized Title:Operations Manager Contact Email: Contact Phone:777-8443 WINJ WAG 97 Water-Bbl MD 80' 2,291' 6 Oil-Bbl measured true vertical Packer 5-1/2"6,726'3,495' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Ninilchik Field / Beluga-Tyonek Gas PoolN/A measured TVD Tubing Pressure 730 NINILCHIK UNIT PAXTON 9 N/A ADL0384372 / FEE-PRIVATE Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 214-173 50-133-20647-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-182 75 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 951 Authorized Signature with date: Authorized Name: 908 Casing Pressure Liner 878 0 Representative Daily Average Production or Injection Data 80' 2,269' 6,726' Conductor Surface Intermediate Production 7,480psi Casing Structural 16" 9-5/8" Length 5,750psi Collapse 3,090psi todd.sidoti@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 10,640psi 80' 1,401' t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 1:16 pm, Nov 04, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.11.04 12:55:44 -09'00' Taylor Wellman Perforate RBDMS HEW 11/5/2020 GLS 12/8/20 DSR-11/4/2020 SFD 11/5/2020 r: N2 E-COIL PERFS Rig Start Date End Date E-CTU 7/25/20 10/25/20 07/26/2020 - Sunday PTW, JSA. Fire equipment. Pick injector head and lubricator. Install E coil collector swivel and test with AK E-line unit. Stab on well. PT stack 250/3,500 psi. Open well 72 psi whp. RIH with GPT to find fluid level. Fluid level seen at 3,628'. POOH to surface. POOH to surface. Discuss with town which direction to proceed. N2 or shoot wet. Shooting wet. Continue to POOH to surface. Tagged up. Break down GPT tool. Make up 15' gun. Stab on well. RIH Log interval 4,400'- 3,850' Send log to town. Move log up 6'. Re log interval. Correlation Log #2 to town. Move log up 2' and on depth. Drop down and log into depth. Shooting 2" x 15' guns loaded 6 spf, 60° Phasing rzr charges in Beluga BEL_47C from 4,194'- 4,209'. CCL to top shot 12.4' Pull into position and stop ccl at 4,181.6' Fire guns 4,194'-4,209'. No increase in pressure or rate. POOH to surface. Tagged up. 72 psi WHP prior to shooting. Showing 75 psi WHP. Well may be flowing but at a low rate where the flow meter isn't accurate. Rig back for the night. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 10/28/2020 - Wednesday 07/27/2020 - Monday PTW JSA Fire equipment. Pick injector head and lubricator. Make up gun. Stab on well. PT stack 250/3,500 psi. Open well RIH. Log OOH from 4,450'-3,850'. Send Correlation pass into town. On depth. PU to 4,166.6' CCL depth (CCL top shot 12.4') 2" OD x 15' gun loaded 6 spf 60* phasing. Shoot BEL_47C sands from 4,179'-4,194'. Heard guns fire at wellhead. No increase in pressure. Well is shut in at wing. Not flowing. POOH to surface. Make up second gun and started running in hole. Called town and decision was made to shut down until n2 was available. POOH rig back CTU. Called out N2 job with SLB. Pump truck will be on location this evening with a full tank. We will start pumping in the AM to push fluid away. PTW, JSA Start BOPE test. 24 hr BOPE test witness notification sent 7/24/2020 @ 15:37 hrs. Witness waived by Jim Regg 7/24/2020 @ 16:44 hrs. Test all rams and valves 250/3,500. Pick injector head. Make up lubricator. Decision made to do dry tag / gun drift run due to the fish being close to our deepest per interval. Stab on well. PT stack 250/3,500 psi. Open well 72 psi whp. RIH tag top of fish 6,586' CTMD. Estimate 6,596' RKB. Pick up 30' and paint flag on coil. POOH to surface for GPT run to find fluid level. Tagged up. Pop off well make up AK E-line Gamma CCL. Stab on well. RIH at 70' turn on tool. Having communications issues between E coil and E line unit. Pooh to surface to diagnose. Troubleshoot connection issue. Found Petrospec collector swivel to be the issue. Coil crew and AK E-line crew head to shop to rebuild collector. Shoot BEL_47C sands from 4,179'-4,194'. Fire guns 4,194'-4,209'. No Rig Start Date End Date E-CTU 7/25/20 10/25/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Paxton 9 50-133-20647-00-00 214-173 10/25/2020 - Sunday Discussed drop in gas production with Reservoir Engineer. Drop in production is associated with new perforations in Paxton 3 on 10/23. We will not be moving forward with setting a plug for water shut. 07/28/2020 - Tuesday PTW, JSA. Fire equipment start rigging up CTU. Rig up SLB N2 pump. Pick injector head and lubricator. PT N2 lines 250/3,500 psi. Ready to make up gun and CTU packoff assembly leaking. Coil rear injector head chain not rolling. Stack down lubricator and inspect equipment. Open well. Initial WHP 250 psi. Online bull head N2 at 800 scf/min. Pressure break over at 870 psi. Drop rate to 500 scf/min 640 psi. Shut down N2. 23,600 scf pumped (253 gal). Petrospec initially indicated rear injector head motor may be blown. Found hydraulic line quick connect disconnected. Injector head back in service. Crew rebuild seals on Pack off assembly and tested good. Pick injector head and make up lubricator. Hot check and arm gun. Stabbed on well. PT stack 250/3,500 psi. Open well. RIH with 1.75" E-coil and 14' gun. Perform correlation pass for gun 3 and send to town for depth confirmation. 4,450'-3,950'. On depth . Pull shooting pass from 4,450'-3,950'. Parked at 4,074.4' with CCL. CCL to top shot 7.6'. 2" x 14' razor low swell gun loaded 6 spf 60* phasing. Initial pressure before shooting 300 psi. Shoot Beluga 47A sands from 4,082'-4,096'. After shooting WHP increased to 575 psi. POOH with coil . Tagged up. Confirm all shots fired. Gun dry. Rig up gun run 4 and hot check . Stab on well pt stack 250/3,500 psi. Open well. RIH. Perform correlation pass for gun run 4. and send to town for depth confirmation. On depth. Pull shooting pass. Park CCL at 4,060.6' (ccl top shot 9.4') 2"x 12' Razor low swell loaded 6 spf 60° phasing. Shoot BEL_47A sands from 4,070'-4,082'. Pressure prior to shooting 574 psi. After shooting 579 psi. POOH with coil. POOH. Tagged up. Close swab. Pop off well. Confirmed all shots fired. Guns dry. Break down tools. Rig back CTU unit. Leave BOPS , flow back iron, choke skid, and return tank rigged up to blow the N2 down. SDFN. Crews will demobe in the AM. Updated by DMA 10-28-2020 SCHEMATIC Ninilchik Unit Well: Paxton #9 PTD: 214-173 API: 50-133-20647-00-00 PBTD = 6,643 MD / 3,428’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ 1 3 7 16” 9-5/8” 8-1/2” Hole 5.5” JEWELRY DETAIL No. MD TVD ID OD Item 1 154’ 154’ CIM 2 170’ 170’ 2.312” 4.609” SLB TRMAXX 5E SCSSSV 3 3,393’ 1,722’ XO 4 3,394’ 1,722’ Prod Pkr 5 3,399’ 1,724’ XO 6 3,443’ 1,737’ 3.25” X-Nipple 7 3,482’ 1,748’ Wireline re-entry guide 2 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16” Conductor 109 / X-56 / Weld Surf 80’ 9-5/8' Surface 40 /L-80 / BTC 8.835” Surf 2,291’ 5-1/2" Production 17 / P-110 / CDC 4.892” Surf 6,723' TUBING DETAIL 2-7/8" Tubing 6.4 / L-80 / EUE-8rd 2.441” Surf 3,482’ 4 5 6 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Ft Date Status BEL_47A 4,070' 4,082' 1,914' 1,917' 12' 7/28/20 Open BEL_47A 4,082' 4,096' 1,917' 1,921' 14' 7/28/20 Open BEL_47C 4,179' 4,194' 1,946' 1,950' 15' 7/27/20 Open BEL_47C 4,194' 4,209' 1,950' 1,955' 15' 7/26/20 Open Bel 53/ Blg50channel 4,790’ 4,802’ 2,181’ 2,186’ 12 1/13/15 Open Bel 53/ Blg50channel 4,802’ 4,822’ 2,186’ 2,195’ 20 4/20/15 Open Bel 53 4,819’ 4,839’ 2,194’ 2,202’ 20 1/11/20 Open Bel 53 4,839’ 4,859’ 2,202’ 2,211’ 20 1/10.20 Open Bel 53 4,863’ 4,883’ 2,213’ 2,222’ 20 1/10/20 Open Bel 53 4,883’ 4,903’ 2,222’ 2,231’ 20 1/9/20 Open BEL_47A BEL_47C BEL_53 FISH @ 6,570’ 01/15/15 Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) CIM SSSV BEL_47A 4,070'4,082'1,914'1,917'12' 7/28/20 Open BEL_47A 4,082'4,096'1,917'1,921'14'7/28/20 Open BEL_47C 4,179'4,194'1,946'1,950'15'7/27/20 Open BEL_47C 4,194'4,209'1,950'1,955'15'7/26/20 Open 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: N2 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/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 6,733'6,570' Casing Collapse Structural Conductor Surface 3,090 psi Intermediate Production 7,480 psi Liner 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 Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Christina Twogood Operations Manager Contact Email: Contact Phone: 777-8443 Date: Conditions of approval: Notify Commission 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 COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: Friday, May 8, 2020 2-7/8" 6,726' Perforation Depth MD (ft): See Attached Schematic 6,726' 3,495'5-1/2" 16" 9-5/8" 80' 2,269'5,750 psi1,401' 80' 2,291' 6.4# / L-80 TVD Burst 3,482' 10,640 psi MDLength Size CO 701C Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 384372 214-173 50-133-20647-00-00 Paxton #9 Ninilchik Field / Beluga & Tyonek Gas Pool COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): See Attached Schematic ctwogood@hilcorp.com 3,503' 6,643' 3,428' ~ 1,163 psi N/A Prod Pkr; SLB TRMAXX 5E SCSSSV 3,394' MD / 1,722' TVD; 170' MD / 170' TVD Perforation Depth TVD (ft): Tubing Size: m n P 66 t Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.04.27 17:12:22 -08'00' Taylor Wellman N By Samantha Carlisle at 8:09 am, Apr 28, 2020 320-182 10-404 DSR-4/28/2020 r: N2 Perforate DLB 04/28/2020 X gls 4/28/20 Comm. 4/28/2020 dts 4/28/2020 JLC 4/28/2020 Well Prognosis Well: Paxton 9 Date 4/20/2020 Well Name: Paxton 9 API Number: 50-133-20647-00-00 Current Status: Leg: N/A Estimated Start Date: 5/8/2020 Rig: N/A Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 214-173 First Call Engineer: Christina Twogood (907) 777-8443 (O) (907) 378-7323 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (M) AFE Number: Max. Expected BHP: ~ 1,494 psi @ 3,324’ TVD (Based on normal gradient) Max. Possible Surface Pressure: ~ 1,163 psi (Based on expected BHP and gas gradient to surface (0.10psi/ft)) Brief Well Summary Paxton 9 was drilled and completed in December 2014 as a grassroots well to target gas sands in the Beluga formation. In January 2015 the Beluga 50 channel perforated with 300 psi on the tubing. In April 2015 the Beluga 50 channel was perforated in a lower interval on coil. In January 2020 the Beluga 53 sands were perforated/re- perforated. The purpose of this work/sundry is to perforate multiple sands in the Beluga formation. Notes Regarding Wellbore Condition x Tagged tractor fish at 6,623’ CTM on 4/19/2015, Drift ID is 2,441” Safety Concerns x Pre-job safety meetings and tailgate safety meetings will be conducted at each appropriate phase of the procedure. x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter x Consider tank placement based on wind direction and current weather forecast (venting nitrogen during this job) x Ensure all crews are aware of stop job authority E-Line Procedure 1. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 2,000 psi High. 2. RIH with GPT tool and find fluid level. If fluid level is over the depth of the new perfs, discuss using Nitrogen with the Operations Engineer. 3. If needed, RU Nitrogen Truck, pressure up on well and push water back into formation. Use GPT tool to confirm water level is below interval to perf. 4. RU perf guns. The purpose of this work/sundry is to perforate multiple sands in the Beluga formation. Well Prognosis Well: Paxton 9 Date 4/20/2020 5. RIH and perforate the following intervals: Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Beluga BEL_47A +4,068' +4,096' +1,913' +1,921' 28' Beluga BEL_47C +4,171' +4,211' +1,943' +1,955' 40' Beluga BEL_60 +5,390' +5,427' +2,485' +2,507' 37' Beluga BEL_73 (lower) +5,598' +5,613' +2,614' +2,624' 15' Beluga BEL_74 +5,652' +5,699' +2,650' +2,682' 47' Beluga BEL_82 (upper) +5,803' +5,816' +2,756' +2,765' 13' Beluga BEL_82 (lower) +5,834' +5,849' +2,778' +2,789' 15' Beluga BEL_83 +5,867' +5,885' +2,802' +2,816' 18' Beluga BEL_97 +6,362' +6,374' +3,194' +3,204' 12' Beluga BEL_100 +6,474' +6,491' +3,287' +3,301' 17' Beluga BEL_105 +6,507' +6,518' +3,314' +3,324' 11' a. Shoot well while flowing. b. Proposed perfs also shown on the proposed schematic in red font. c. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. d. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer and Geologist for confirmation. e. Use Gamma/CCL to correlate. f. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. g. All perforations in table above are located in the Beluga & Tyonek Gas Pool based on Conservation Order No. 701C. 6. POOH. 7. RD E-Line. 8. Turn well over to production. (Test SSV within 5 days of stable production on well – notify AOGCC 24 hours before testing). E-Line Procedure (Contingency) 1. If any zone produces sand and/or water or needs isolated: 2. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 2,000 psi High. 3. RIH and set 5-1/2” Expandable Plug with 25’ of cement on top. Coiled Tubing Procedure: 1. MIRU Coiled Tubing Unit and BOP equipment. 2. RU Coiled Tubing Stripper and Lubricator. 3. PT BOPE, Stripper and Lubricator to 250 psi Low / 3,500 psi High. (Notify AOGCC 24 hrs in advance on BOP test.) 4. RU E-Line Data Acquisition Unit. 5. RU perf guns. E-Coil E-line Perforations (alternative to tractor with Eline) Well Prognosis Well: Paxton 9 Date 4/20/2020 6. RIH and perforate the following intervals: Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Beluga BEL_47A +4,068' +4,096' +1,913' +1,921' 28' Beluga BEL_47C +4,171' +4,211' +1,943' +1,955' 40' Beluga BEL_60 +5,390' +5,427' +2,485' +2,507' 37' Beluga BEL_73 (lower) +5,598' +5,613' +2,614' +2,624' 15' Beluga BEL_74 +5,652' +5,699' +2,650' +2,682' 47' Beluga BEL_82 (upper) +5,803' +5,816' +2,756' +2,765' 13' Beluga BEL_82 (lower) +5,834' +5,849' +2,778' +2,789' 15' Beluga BEL_83 +5,867' +5,885' +2,802' +2,816' 18' Beluga BEL_97 +6,362' +6,374' +3,194' +3,204' 12' Beluga BEL_100 +6,474' +6,491' +3,287' +3,301' 17' Beluga BEL_105 +6,507' +6,518' +3,314' +3,324' 11' h. Prior to shooting build up the well to approx. 300 psi. i. Proposed perfs also shown on the proposed schematic in red font. j. Final perfs tie-in sheet will be provided in the field for exact per intervals. k. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. l. Use Gamma/CCL to correlate. m. Spacing allowance is based on CO 701C. Proposed intervals are in the Beluga & Tyonek Gas Pool. n. Record tubing pressure before and after each perforating run. o. Record 5, 10 and 15 minutes pressures after firing guns. 7. POOH. 8. RD E-Line Unit and Coiled Tubing Unit. 9. Turn well over to production. Coiled Tubing Procedure (Contingency): 1. MU standard coil reel and BHA. 2. RU N2 pumping unit. 3. Drop ball and come online with N2 and jet well dry. 4. RIH with coiled tubing and BHA and tag. 5. PU approx. 5 ft and displace well fluids with Nitrogen. 6. Once well is dry, verify desired surface pressure to leave on well with Operations Engineer (OE). 7. POOH w/ coil. LD BHA. 8. RD standard coil reel. 9. RU E-Coil reel. 10. Proceed with Coiled Tubing Procedure for perforating. Attachments: 1. Current Schematic 2. Proposed Schematic 3. Coiled Tubing BOPE Schematic 4. Standard Well Procedure – N2 Operations Updated by DMA 01-14-20 SCHEMATIC Ninilchik Unit Well: Paxton #9 PTD: 214-173 API: 50-133-20647-00 PBTD = 6,643 MD / 3,428’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ Blg50channel 1 3 7 16” 9-5/8” 8-1/2” Hole 5.5” JEWELRY DETAIL No. MD TVD ID OD Item 1 154’ 154’ CIM 2 170’ 170’ 2.312” 4.609” SLB TRMAXX 5E SCSSSV 3 3,393’ 1,722’ XO 4 3,394’ 1,722’ Prod Pkr 5 3,399’ 1,724’ XO 6 3,443’ 1,737’ 3.25” X-Nipple 7 3,482’ 1,748’ Wireline re-entry guide 8 6,570’ 3,367’ Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) 2 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16” Conductor 109 / X-56 / Weld Surf 80’ 9-5/8' Surface 40 /L-80 / BTC 8.835” Surf 2,291’ 5-1/2" Production 17 / P-110 / CDC 4.892” Surf 6,723' TUBING DETAIL 2-7/8" Tubing 6.4 / L-80 / EUE-8rd 2.441” Surf 3,482’ 4 5 6 8 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Ft Date Status Bel 53 4,819’ 4,839’ 2,194’ 2,202’ 20 1/11/20 Open Bel 53 4,839’ 4,859’ 2,202’ 2,211’ 20 1/10.20 Open Bel 53 4,863’ 4,883’ 2,213’ 2,222’ 20 1/10/20 Open Bel 53 4,883’ 4,903’ 2,222’ 2,231’ 20 1/9/20 Open Bel 53/ Blg50channel 4,790’ 4,802’ 2,181’ 2,186’ 12 1/13/15 Open 4,802’ 4,822’ 2,186’ 2,195’ 20 4/20/15 Open Bel 53 Updated by CMT 04-20-2020 PROPOSED SCHEMATIC Ninilchik Unit Well: Paxton #9 PTD: 214-173 API: 50-133-20647-00-00 PBTD = 6,643 MD / 3,428’ TVD TD = 6,733’ MD / 3,503’ TVD RKB = 18.7’ 1 3 7 16” 9-5/8” 8-1/2” Hole 5.5” JEWELRY DETAIL No. MD TVD ID OD Item 1 154’ 154’ CIM 2 170’ 170’ 2.312” 4.609” SLB TRMAXX 5E SCSSSV 3 3,393’ 1,722’ XO 4 3,394’ 1,722’ Prod Pkr 5 3,399’ 1,724’ XO 6 3,443’ 1,737’ 3.25” X-Nipple 7 3,482’ 1,748’ Wireline re-entry guide 8 6,570’ 3,367’ Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) 2 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16” Conductor 109 / X-56 / Weld Surf 80’ 9-5/8' Surface 40 /L-80 / BTC 8.835” Surf 2,291’ 5-1/2" Production 17 / P-110 / CDC 4.892” Surf 6,723' TUBING DETAIL 2-7/8" Tubing 6.4 / L-80 / EUE-8rd 2.441” Surf 3,482’ 4 5 6 8 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Ft Date Status BEL_47A +4,068' +4,096' +1,913' +1,921' 28' TBD Proposed BEL_47C +4,171' +4,211' +1,943' +1,955' 40' TBD Proposed BEL_60 +5,390' +5,427' +2,485' +2,507' 37' TBD Proposed BEL_73 (lower) +5,598' +5,613' +2,614' +2,624' 15' TBD Proposed BEL_74 +5,652' +5,699' +2,650' +2,682' 47' TBD Proposed BEL_82 (upper) +5,803' +5,816' +2,756' +2,765' 13' TBD Proposed BEL_82 (lower) +5,834' +5,849' +2,778' +2,789' 15' TBD Proposed BEL_83 +5,867' +5,885' +2,802' +2,816' 18' TBD Proposed BEL_97 +6,362' +6,374' +3,194' +3,204' 12' TBD Proposed BEL_100 +6,474' +6,491' +3,287' +3,301' 17' TBD Proposed BEL_105 +6,507' +6,518' +3,314' +3,324' 11' TBD Proposed Bel 53 4,819’ 4,839’ 2,194’ 2,202’ 20 1/11/20 Open Bel 53 4,839’ 4,859’ 2,202’ 2,211’ 20 1/10.20 Open Bel 53 4,863’ 4,883’ 2,213’ 2,222’ 20 1/10/20 Open Bel 53 4,883’ 4,903’ 2,222’ 2,231’ 20 1/9/20 Open Bel 53/ Blg50channel 4,790’ 4,802’ 2,181’ 2,186’ 12 1/13/15 Open 4,802’ 4,822’ 2,186’ 2,195’ 20 4/20/15 Open BEL_47A BEL_47C BEL_60 BEL_73 (lower) BEL_74 BEL_82 (upper) BEL_82 (lower) BEL_83 BEL_97 BEL_100 BEL_105 BEL_53 Coiled Tubing HydraCo 60K Injector Head & Gooseneck Weight = 3500 lbs 3" 500psi ArmorPak Stripper Bowen Type 5K 5.5" Lubricator 5K CJS ArmorPak Guide Bowen Type 5K x 5-1/8" 10K Flange 5-1/8" 10K Quad BOP 1.ArmorPak 1.5" x 1.5" Pipe Ram 2.ArmorPak 1.5" x 1.5" Pipe Ram 3.Shear Ram 4.Blind Ram 5-1/8 10K Spool with 2-1/16" 10K Outlets - Kill Port Manual Valve 1: 2-1/16" 10K Manual Valve 2: 2-1/16" 10K Manual Valve 3: 2" Weco 1502 Adapter Spool 5-1/8" 10K x 7-1/16" 5K Adapter Spool 7-1/16" 5K x 5-1/8" 5K 5-1/8" 5K ArmorPak 1.5" x 1.5" CT Head Wellhead 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. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS RECEIVED JAN 2 4 2020 An(_`r*%r% 1. Operations Abandon Ll Plug Pertorations Fracture Stimulate ET Pull Tubing Ll Operations shutdown Li Performed: Suspend p Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plugfor Redrill ❑ erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: i a 2. Operator Name: Hilcorp Alaska, LLC 4. Well Class Before Work: 5. Permit to Drill Number: Development ❑✓ Stratigraphic ❑ Exploratory ❑ Service ❑ 214-173 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-133-20647-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL384372 Paxton #9 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Ninilchik Fieldk / Beluga & Tyonek Gas Pool 11. Present Well Condition Summary: Total Depth measured 6,733 feet Plugs measured N/A feet true vertical 3,503 feet Junk measured 6,570 feet Effective Depth measured 6,643 feet Packer measured 3,394 feet true vertical 3,428 feet true vertical 1,722 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 2,269' 9-5/8" 2,291' 1,401' 5,750 psi 3,090 psi Intermediate Production 6,723' 5-1/2" 6,723' 3,495' 10,640 psi 7,480 psi Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 2-7/8" 6.4# / L-80 3,482' 1,748' TVD SLB TRAMAXX 5E SSSV 170' MD 170' TVD Packers and SSSV (type, measured and true vertical depth) Prod Pkr 3,394' MD 1,722' TVD 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: 0 318 0 950 92 Subsequent to operation: 0 561 0 950 179 14. Attachments (required per 20 AAC 25.070, 25.071, 825.283) 15. Well Class after work: Daily Report of Well Operations ❑Q Exploratory[] Development Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Gas WDSPL LJ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-466 Authorized Name: Bo York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramerfc�hilcom com Authorized Signature: Date: Z3 j G.% Ly 2a Contact Phone: 777-8420 Form 10-404 f*vised 4/2017 Q, /�jy��2(f � ( -,-R- y -'J Submit Original Only RBDMS- JAM 2 7 2020 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Paxton 9 E-CTU 50-133-20647-00-00 214-173 1/6/20 1/11/20 Daily Operations: 01/06/2020 - Monday Pre job safety meeting and convoy meeting with HAK rep and Petrosnec coil crews. Depart Pollard E-line shop. Half way mark to Paxton Pad CTU unit loosing air pressure. CTU pulled over on traffic bypass. Diagnosis of air supply, issue indicates frozen line at air line heater, mobilize dual frost fighter heater. After 30 minutes of heat, CTU unit building air pressure again. CTU en route to location. Arrive at Paxton. Spot CTU on Pax 9. Cruz crane will not shift into PTO mode. RU heater on PTO shaft. Crane PTO engaged. Spot on well. Pick and install combination BOPE stack on production tree. RU hydraulic lines. Spot Rain for rent return tank. Spot choke skid. RU 1502 iron from BOPE stack to choke skid and return tank. MIRU HAK hot oil pump truck . Function test BOPE stack. Fluid pack to top of BOPE stack and return tank with 60/40 methanol/water mix. Ambient temp on location is -4*F. Full Body PT to 250/3,500 psi. Blow stack dry. Disconnect hot oil truck from pump line. Disconnect crane and rig down. Move Hot oil truck and crane to production facilities to plug in equipment. Location walk around complete. SDFN. 01/07/2020-Tuesday Arrive at Susan Dionne. PTW/JSA. Discuss BOPE testing operations. Work on starting hot oil truck and crane. Heater and man lift will not start. Shut down CTU operations for the day due to cold temps. Let hot oil truck run for 1 hour to charge batteries. Fuel all equipment. State Rep Jeff Jones notified of job delay. Jeff Jones waived witness for following day. 01/08/2020- Wednesday Fire equipment. Paxton 9 flow line froze overnight. RU hot oil truck and pump 4 bbls of 60/40 down flow line to remove ice plug. 24 hr BOPE test witness notification sent 1/6/2020 @ 840 AM. Witness waived for BOPE test on 1/8/20 via phone call from Jeff Jones. Fluid pack lines with 60/40 methanol and water. Online for low PT of blind rams 265 psi. Blind ram bonnet seal leaking. Blow stack dry with air. Open BOPE ram to inspect failure. Wait on new bonnet seal orings. 5 hrs downtime. Continue BOPE test. Test all rams and valves 250/3,500 psi for 5 minutes. BOPE test complete Rig down hot oil truck and plug in block heater. Wellhead and location secure. SDFN. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Paxton 9 E -CTU 50-133-20647-00-00 1 214-173 1/6/20 1/11/20 Daily Operations: 01/09/2020 - Thursday PTW/JSA with petrospec CTU crew, Pollard E -line and Cruz crane operator. Spot in Pollard E -line and RU data cables to CTU unit. Perform integrity checks. Tail gate meeting with crews. Pick injector head and make up 40' of lubricator. Make up AK E -line GPT tools to Petrospec E -coil. Perform communications checks. Stab on well. Fluid pack with 60/40. PT stack 250/3,500 psi. Confirm no leaks. Bleed down stack. Open well. Initial rates 340K @ 77 psi. Tubing 77, IA 950, OA 195 psi. Well producing 3-5 bbls of fluid daily. RIH with GPT to check fluid level. Correlate depth to Halliburton open hole log. Halliburton Log MWD run number 200. 30 Nov 2014. Found fluid level at 4,820'. Fluid level is below current perfs. POOH to surface. Make up 21'x 2.0" guns. loaded 20' at 6 spf. 10.5 gram charges. Stab on well. PT stack. RIH with Gun run #1. Log pass from 5016' up to 4,000'. Not seeing good log signatures. Send log to town engineers. Drop back down to 5020' and re log to 4,000'. Send gun #1 correlation #2 to town. On depth. PU from 5,000' to 4876.3' CCL to top shot 6.7'. Pu and Park CCI at 4876.3'. Shoot from 4,883'-4,903'. POOH to surface. After CTU at surface monitor rate. Increase from 340K @ 77 psi flowing tubing pressure to 480K @ 77.6 psi flowing tubing pressure. IA/OA remain the same. Close swab valve. Bleed down stack. Pop off well. Lay down E -line gun and tools. Guns confirmed fired. Stack down lubricator and set injector head on back deck. SDFN. 01/10/2020 - Friday PTW/JSA with Pollard E -line, Petrospec E -coil and Cruz crane operator. Pick injector head. Stab 40' of lubricator. Make up Gamma/CCL and 2"x 20" guns. Stab on well. PT stack 250/3,500 psi. RIH. 5012'. Log OOH to 4,000'. Correlate log. send log to town. CCL to top shot 7.1'. Tubing 77 psi/ IA 950 psi/ OA 195 psi. Log on depth. PU to 4,855.9' CCL depth. Perforate 4,863'-4,883'. POOH to surface. Tagged up. Close swab and pop off well. All guns confirmed fired. Having issues dropping out of lubricator. Petrospec investigate at injector head. Coil connector stuck in pack offs. Petrospec cable head shear pins broke. Re pin cable head shear assembly. Re test E -coil and pollard CCL/Gamma tools. Good test. Make up 3rd gun run. PT stack 250/3,500 psi. Bleed down. RIH with 3rd gun run to 5,020' Log OOH for corelation. CCL to top shot 7.1'. Send log to town. On depth. PU to 4,831.9' CCL depth. Perforate 4,839'-4,859'. POOH to surface. flow rate 419K @ 79.5 psi. Tagged up. Close swab. Pop off well. Gun run #3 confirmed fired. Flow rate 548K @ 80 psi. Make up Gun run #4. Stab on well. PT stack 250/3,500 psi. Bleed down and RIH. injector head having issues. Sounds like chains slipping at 20'. POOH . Close swab. Call town to discuss. Will not run gun run # 4 until CTU injector is fixed. Found injector traction cylinder out of adjustment causing chains to bind. To late to continue operations. Break down Pollard Guns. Stack back lubricator and injector. Install night cap on BODE stack. Close all surface valves. SDFN. 01/11/2020 -Saturday PTW, JSA. Fire equipment. Pick injector head and make up lubricator. Make up 2.0" x 20" pert gun. Stab on well. PT stack 250/3500 psi. RIH to 5,010' MD. Log up to 4,000' and correlate. Send log to town. Confirmed on depth. Drop back down. CCL to top shot 7.1'. PU to CCL depth of 4811.9' Shoot guns from 4,819'-4,839'. POOH to surface. Close swab valve. Pop off well. All guns confirmed fired. Rig down Pollard and Petrospec. Move equipment to Paxton 3. Submit for BODE test witness notification. Equipment spotted up. Remove Pax 3 well house. Pax 9 flowing at 420K @ 80 psi. After moving to pax 3 with CTU. PAX 9 increased to 560K AT 79 psi. 16 9-5/E 8-1/2" 5.! RKB =18.7' PBTD = 6,643 MD / 3,428' TVD TD = 6,733' MD / 3,503' TVD SCHEMATIC CASING DETAIL Ninilchik Unit Well: Paxton #9 PTD: 214-173 API: 50-133-20647-00 Size Type Wt/Grade/Conn ID Top Btm 16" Conductor 109/X-56/WeldSurf 2 80' 9-5/8' Surface 40/L-80/BTC 8.835" Surf 2,291' 5-1/2" Production 17/P-110/CDC 4.892" Surf 6,723' TUBING DETAIL 2-7/8" 1Tubing 6.4/L-80/EUE-Srd 2.441" Surf 3,482' JEWELRY DETAII No. MD TVD ID OD Item 1 154' 154' CIM 2 17U 170' 2.312" 4.609" SLBTRMAXXSE SCSSSV 3 3,393' 1,722' XO 4 3,394' 1,722' Prod Pkr 5 3,399 1,724' XO 6 3,443' 1,737' 3.25" X -Nipple 7 3,482' 1,748' Wireline re-entry guide 8 6,570' 3,367' Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) PERFORATION DETAII Bel 53 SOchannel Updated by DMA 01-14-20 (MD) Btm (MD) Top (TVD) Btm (TVD) Ft Date Status ,819' 4,839' 2,194' 2,202' 20 1/11/20 Open ,839' 4,859' 2,202' 2,211' 20 1/10.20 Open Be[,863' !Blg50chanVne14,802' 4,883' 2,213' 2,222' 20 1/10/20 Open 883' 4,903' 2,222' 2,231' 20 1/9/20 Open ,790' 4,802' 2,181' 2,186' 12 1/13/15 Open 802' 4,822' 2,186' 2,195' 20 4/20/15 Open Bel 53 SOchannel Updated by DMA 01-14-20 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga and Tyonek Gas Pool, Paxton 9 Permit to Drill Number: 214-173 Sundry Number: 319-466 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 wv w.00gcc.oIaska.gov Enclosed is the approved application for the 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, Je ice Chair DATED this -Ll day of October, 2019. RBDMS1�✓ocT 2 2 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 2n AAC ?s ?an DT:S I©%zAlrC� 1. Type of Request: Abandon❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well❑ Operations shutdown❑ Suspend[] Perforate Perforate d�.(� Other Stimulate Pull Tubin g ❑ Change Approved Program ❑ // Plug for Redrill❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Oth 2. Operator Name: Hilcorp Alaska, LLC 4. Current Well Class: 5. Permit to Drill Number: Exploratory ❑ Development ❑✓ Stratigmphic ❑ Service ❑ 214-173 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, Alaska 99503 50-133-20647-00-00 7. IF perforating: 8. Well Name and Number: // q, What Regulation or Conservation Order governs well spacing in this pool? CO 7010 l .INA/ Will planned perforations require a spacing exception? Yes El No 210 Parton #9 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL384372 Ninilchik Field/ Beluga & Tyonek Gas Pool ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): MPSP (psi): Plugs (measured): Junk (measured): 6,733 3,503 6,643 3,428 753 psi N/A 6,570' Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 16" 80' Surface 2,269' 9-5/8" 2,291' 1,401' 5,750 psi 3,090 psi Intermediate Production 6,726' 5-1/2" 6,726' 3,495' 10,640 psi 7,480 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 4,790'-4,802' 2,181'-2,166' 2-7/8" 6.4#/ L-80 3,482 Packers and SSSV Type: Prod Pkr Packers and SSSV MD (ft) and TVD (ft): 3,394' MD / 1,722' TVD SLB TRMAXX 5E SCSSSV 170' MD / 170' TVD 12. Attachments: Proposal Summary ✓ Wellbore schematic ✓ 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stra[igraphic ❑ Development ❑✓ Service ❑ 14. Estimated Date for ✓ 15. Well Status after proposed work: OctoberF'i[fi 2019 Commencing Operations: � OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS Q' WAG ❑ GSTOR❑ ❑ SPLUG 16. Verbal Approval: Date: Commission Representative: GINJ O p Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Christina Twogood Authorized Name: Bo York 777-8345 Contact Email: CtyyOg00d(gDhIICOrp.Cor11 Authorized Title: Operations Manager Contact Phone: 777-8443 Signature Date 16 U COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 22 �j c'-in—r4/ "I Plug Integrity ❑ BOP Test Mechanical Mecha��nniQical Integrity Test ❑L Loc-ati�on Clearance ❑ "� Other: ' 3 5 - co p s., 66 / y -s � Cl b� / RBDMS 1�C1CT 2 2 2919 Post Initial Injection MIT Req'd? Yes ElNo ❑ Spacing Exception Required? Yes ElNo rL-Y-1✓ Subsequent Form Required: j V Ll (} I v V�) APPROVED BY,1(�Approved by: COMMISSIONER THE COMMISSION Date: 1 C/( 4 q vv �L'�24�1�I y17ORIGINAL Fo 10-403 (Revised 10/2012) Approved application is valid for 12 months from the date of approval. Submit Form and Attachments in Duplicate rLK .K Hilrorl, Alaska, LU Well Prognosis Well: Paxton 9 Date: 30/4/2019 Well Name: Paxton 9 API Number: 50-133-20647-00-00 Current Status: Leg: N/A Estimated Start Date: 10/20/2019 Rig: N/A Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 214-173 First Call Engineer: Christina Twogood (907) 777-8443 (0) (907) 378-7323 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) AFE Number: Max. Expected BHP: — 976 psi @ 2,234' TVD (Based on normal gradient) Max. Possible Surface Pressure: — 753 psi @ 2,234' TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft)) Brief Well Summary Paxton 9 was drilled and completed in December 2014 as a grassroots well to target gas sands in the Beluga formation. gagson e e . In January 2015 the Beluga 50 channel perforated with 300 psi on the tubing. In April 2015 the Beluga 50 channel was perforated in a lower interval on coil. The purpose of this work/sundry is to perforate/re-perforate the Bel 53 sands. Notes Regarding Wellbore Condition • Stuck tool string t 3,408' i Janes 2015, left fish in hole Safety Concerns • This coil is atypical for this area. Pre -job safety meetings and tailgate safety meetings will be conducted at each appropriate phase of the procedure. • Discuss nitrogylasphyxiation concerns and identify any areas where nitrogen could collect and people could enter _1 • Consider tank placement based on wind direction and current weather forecast (venting nitrogen during this job) • Ensure all crews are aware of stop job authority Petrospec Coiled Tubing Procedure: 1. MIRU Coiled Tubing Unit and BOP equipment. 2. RU Coiled Tubing Stripper and Lubricator. 3. PT BOPS, Stripper and Lubricator to 250 psi Low / 3,500 psi High. (Notify AOGCC 24 hrs in advance on BOP test.) 4. RU E -Line Data Acquisition Unit. 0 flilwrp Alaska, LL Well Prognosis Well: Paxton 9 Date: 10/4/2019 Well Name: Paxton 9 API Number: 50-133-20647-00-00 Current Status: Leg: N/A Estimated Start Date: 10/16/2019 Rig: N/A Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 214-173 First Call Engineer: Christina Twogood (907) 777-8443 (0) (907) 378-7323 (M) Second Call Engineer. Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) AFE Number: Max. Expected BHP: Max. Possible Surface Brief Well Summary — 976 psi @ 2,234' TVD — 753 psi @ 2,234' TVD Paxton 9 was drilled and completed in d formation. led, January 2015 the Beluga 50 channel perfc was perforated in a lower interval on coil. The purpose of this work/sundry is to Notes Regarding Wellbore Condition • Stuck tool string at 3,408' in January Safety Concerns (Based on normal gradient) (Based on expected BHP and gas gradient toArface (0.10psi/ft)) ler 2014 as a grassroots ell to target gas sands in the Beluga dsinthe—Tyenek fsrrrlaiion In with 300 psi on th,04ubing. In April 2015 the Beluga 50 channel 're -p forathe Bel 53 sands. fish in I%le • This coil is atypical for this are . Pre -job safety meetings and tailga\nigen gs will be conducted at each appropriate phase o he procedure. • Discuss nitrogen asphyxia . n concerns and identify any areas whld collect and people could enter • Consider tank placem t based on wind direction and current weaenting nitrogen during this job) • Ensure all crews a aware of stop job authority ec Coiled Tubi Procedure: 'V9VO lot- 1./Rerf ed Tubing Unit. PT BOPE to 250 psi Low /.2 (100 psi High. (Notify AOGCC 24 hrs in advance st.) 2.ns.Sro 3.Tubing Stripper, Lubricator and BOPS to 200 psi Low / 709psi High. 4.Data Acquisition Unit. K Ifilmru Alaska, M 5. RIH and perforate the following intervals: Well Prognosis Well: Paxton 9 Zate:10/4/2019 Zone Sand Top (MD) Btm (MD) Top (ND) 1 Bt MD) Coiled Tubing 4. Bel 53 +4,785' +4910' +2179' +2,234' 3FT,Beluga a. Prior to shooting, build up pressure to approx. 3 psi. b. Pr posed perfs also shown on the proposed s/.3 ematic in red font. c. Fin erfs tie-in sheet will be provided in t field for exact per intervals. d. Make rrelation pass and send log in to perations Engineer, Reservoir Engineer and the e. Use Garnntall f. Spacing alto a g. Record tubing h. Record 5, 10 a is based on CO sure before iii 5 minutes Ves 6. POOH. 7. RD E -Line Unit and Coiled Tubi Unit. S. Turn well over to production. E -line Procedure (Contingency): /Lo_i4.lq 01. Proposed intervals are in the Beluga Gas Pool. after each perforating run. Tres after firingguns. g 1. If these zones produce sa d and/or water an need to be isolated: 2. MIRU E -Line, PT lubricat r to 250 psi Low/ 2,00 si High. 3. RIH and set 5-1/2" Casi g Patch or set CIBP above a zone and dump 25' of cement on top of the plug. Attachments: 1. Current Scher 2. Proposed Sch 3. Coiled Tubing 4. Standard Wel Schematic Aure — N2 Operations 9-5/8" 8-1/2" Ninilchik Unit SCHEMATIC Well: Paxton #9 PTD: 214-173 l.0 API: 50-133-20647-00 liarorp Alukn, l: RKB = 18.7' CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 16" Conductor 109/X-56/Weld Surf 80' 9-5/8' Surface 40/L-80/BTC 8.835" Surf 2,291' 5-1/2' Production 17 / P-110 / CDC 4.892" Surf 6,723' TUBING DETAIL 2-7/8" Tubing 6.4/L-80/E1JE-8rd 1 2.441" Surf 3,482' JEWELRY DETAIL No. MD ND ID OD Item 1 154' 154' CIM 2 170' 170' 2.312" 4.609" SLBTRMAXX 5ESCSSSV 3 3,393' 1,722' XO 4 3,394 1,722' Prod Pkr 5 3,399' 1,724' XO 6 3,443' 1,737' 3.25" X -Nipple 7 1,482' 1,748' Wireline re-entry guide 8 6,570' 3,367' Schlumberger tension sub, telemetry, (2) tractors, GR, bumper sub, hollow carrier (73 ft. tool length) PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (ND) Btm (TVD) Ft Date Status BIg50channel 4.790' 4,802' 2,181' 2,186' 12 1/13/15 Open 4,802' 4,822' 2,186' 2,195' 20 4/20/15 Open BIg50channel BIg50channel PBTD = 6,643 MD / 3,428' TVD TO = 6,733' MD / 3,503' ND Updated by DMA 05-19-15 16' 9-5/S 8-1/2" Ninilchik Unit Wel; Paxton PROPOSED SCHEMATIC PTD: 214-1739 Hfimep AlosW.11.0 API: 50-133-20647-00 RKB = 18.7' PBTD = 6,643 MD / 3,428' TVD TD = 6,733' MD / 3,503' TVD CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109/X-56/Weld Surf 80' 170' Surface 40/L-80/BTC 8.835" Surf 2,291' 5-1/2" Production 17/P-110/CDC 4.892" Surf 6,723' TUBING DETAIL 2-7/8" Tubing 6.4/L-80/EUE-8rd 2.441" Surf 3,482' JEWELRY DETAII PERFORATION DETAIL , � { I Sands Top (MD) M70' D ND ID OD Item Date Status Be153 ±4,785• ±4910' ±2,179' 1 170' 2.312" 4.009" SLB TRMAXX SE SCSSSV F67 3,393' 1,722' XO 1/13/15 3,394' 1,722' Prod Pkr 2,186' 3,399' 1,724' XO 3,443' 1,737' 3.25" X -Nipple 3,482' 1,748' Wireline re-entry guide 8 6,570' 3,367' Schlumberger tension sub, telemetry, (2)tractors, GR,bumper sub, hollow carrier (73 ft, tool length) PERFORATION DETAIL , � { I Sands Top (MD) Btm (MD) Top (ND) Btm (TVD) Ft Date Status Be153 ±4,785• ±4910' ±2,179' ±2,234' Proposed TBD Blg50channel 4'790' 4,802' 2,181' 2,186' 12 1/13/15 Open 4,802' 4,822' 2,186' 2,195' 20 4/20/15 Open 50channelBe153 50channel Updated by DMA 10-02-19 STANDARD WELL PROCEDURE HilrurpAlaska, LLC NITROGEN OPERATIONS 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/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 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 11500 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. 12/08/2015 FINAL vl Page 1 of 1 TOOI CAL 6a.E9 I rG'brxnkx[ess MUOM@ 6>N CAL O'mal L. Type SK Lubricator ^35ft OC.s SID as vaar Gurvs. HYDRAULIC 11MSIU1 L 00 I. 43 75 Wp a eTi e140 LOS.. OR. HOOK IOPD 1. Combl etino/Shear R.K. ]a 2 1,25" CTCombl plpe/Slip Ram ~- -'---- ai NNew GL YOi]'a6i]raer.- Y \]v{{ri0wfni NIMchlkllnil NA,,KR 10/IO/xlIO r lLasl __ Coil ed Tubing HydraCO 45K Injector Head&Gooseneck moa Weight-4200Ibs �— 3" 500BpsiRBtriP r aso GL Type SK Lubricator ^35ft 15{0 as vaar Gurvs. HYDRAULIC 11MSIU1 L 00 I. 13/4 (glleLiuLing Whip Wp Dual-Combi BOP eTi e140 LOS.. OR. HOOK IOPD 1. Combl etino/Shear R.K. 2 1,25" CTCombl plpe/Slip Ram ~- -'---- Bowen 3" SK K 31/8" SK Btm 31%8 SK Spool with 2-1/i6" SK DOtie(s-KIII Port �"—"----- Manual Valvel: 2-1/16"SK Manual Valve 2: 2.-1/16"SK q'"de4p Weco 2" 1502 thread halt HU y le GL Schwartz, Guy L (CED) From: Christina Twogood - (C) <ctwogood@hilcorp.com> Sent: Thursday, October 17, 2019 5:35 PM To: Schwartz, Guy L (CED) Cc: Ted Kramer, Donna Ambruz Subject: RE: [EXTERNAL] Paxton #9 perf Sundry ( PTD 214-173) Attachments: Paxton 9 Procedure Add Perfs 10-17-2019.docx Please see responses in red below. Thank you, Christina Twogood Operations Engineer Kenai Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 99503 (w) 907-777-8443 (c) 907-378-7323 From: Schwartz, Guy L (CED) [maiIto:guy.schwartz@alaska.gov) Sent: Tuesday, October 15, 2019 8:48 AM To: Christina Twogood - (C) <ctwogood@hilcorp.com> Subject: [EXTERNAL] Paxton #9 perf Sundry ( PTD 214-173) Christina, Are you using the Canadian CT unit??? Yes, we will be using a Petrospec unit. They must test the BOPE on the wellhead as per a normal CT unit... not sure if that is what you had written up. They were allowed to do a stump test in Beluga but that was for the dual CTjob. Acknowledged. I have discussed with them and we will plan to rig up the BOPE, stripper and lubricator to the wellhead and pressure test as per a normal CT unit. Also, you have nitrogen on location but no mention in your procedure for using it. Please include these steps .. assume it is for fluid displacement prior to perfing. Yes, the Nitrogen on location will be used for a Nitrogen blowdown fluid displacement. Please see updated procedure. I also bumped up the BOPE test pressure to 3500 psi ... if they are using N2 with CT it needs to exceed pumping expected pumping pressure. Acknowledged. I have included this in the updated procedure as well. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at (907-793-1226 ) or (Guyschwartz@alaskagov). • STATE OF ALASKA A, CA OIL AND GAS CONSERVATION CC SSION GAS WELL OPEN FLOW POTENTIAL TEST REPORT 1a.Test: U Initial U Annual ❑Special lb.Type Test: U Stabilized LJ Non Stabilized ❑ Multipoint ❑ Constant Time ❑ Isochronal Q Other: PBU 2.Operator Name: 5.Date Completed: 11.Permit to Drill Number: Hilcorp Alaska,LLC 1/13/2015 214-173 3.Address: 6.Date TD Reached: 12.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 11/29/2014 50-133-20647-00 4a.Location of Well(Governmental Section): 7.KB Elevation above MSL(feet): 13.Well Name and Number: Surface: 3058'FEL,2219'FWL,Sec 13,T1S, R14W,SM,AK 166.6 Paxton#9 Top of Productive Horizon: 8.Plug Back Depth(MD+TVD): 14.Field/Pool(s): 888'FSL,2103'FWL,Sec 12,T1S, R14W,SM AK 6643'MD/3428'TVD Total Depth: 9.Total Depth(MD+ND): Ninilchik Field/Beluga&Tyonek Gas 936'FNL,2200'FWL,Sec 12,T1S,R124W,SM,AK 5733'MD/3503'ND 4b.Location of Well(State Base Plane Coordinates NAD 27): 10.Land Use Permit: 15. Property Designation: Surface: x- 206265.74 y-2230441.15 Zone- 4 N/A ADL384382 TPI: x- 206191.43 y-2232164.9 Zone- 4 16.Type of Completion(Describe): Total Depth: x- 206372.03 y-2235617.5 Zone- 4 5-1/2"Production String,Perforated 17.Casing Size Weight per foot,lb. I.D. in inches Set at ft. 19. Perforations: From To 5-1/2" 17# 4.892" 6,723' 4,790'-4,802' 18.Tubing Size Weight per foot, lb. I.D.in inches Set at ft. 4,802-4,822' 2-7/8" 6.4# 2.441" 3,482' 20.Packer set at ft: 21.GOR cf/bbl: 22.API Liquid Hydrocardbons: 23.Specific Gravity Flowing Fluid(G): 3,394' N/A N/A 0.56 24a.Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure(Pa): Q Tubing ❑ Casing 63 F° 573 psia @ Datum 2015 NDSS psia 25.Length of Flow Channel(L): Vertical Depth(H): Gg: %CO2: %N2: %H25: ' Prover: Meter Run: Taps: N/A N/A 0.56 0.158 0.266 0 26. FLOW DATA TUBING DATA CASING DATA Prover Choke Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow No. Line X Orifice psig Hw F° psig F° psig F° Size(in.) Size(in.) RECEIVED 1. X 2. X SCANNED .-.t-I'; 2 :'Lfl J U L 01 Z015 3. X 4. X AOGGG 5. X Basic Coefficient Flow Temp. Super Comp. No. (24-Hour) hw Pressure Gravity Factor Rate of Flow Pm Factor Fg (�l Mcfd Fb or Fp Ft g Fpv 1. 2. _ 3. 4. 5. Temperature for Separator for Flowing No. PrT Tr z Gas Fluid Gg G 1. 2. 3. Critical Pressure 4. Critical Temperature 5. RBDIHS f%� 'I� 9 Form 10-421 Rev. 7/2009 �� G 1 6 2OSITINUED ON REVERSE SIDE Submit in Duplicate Pc Pc2 'f Pf2 No. Pt Pt2 Pc2-Pt2 Pw Pw2 Pc2-Pw2 Ps Ps2 Pf2-Ps2 1. 2. 3. 4. 5. 25. AOF (Mcfd) 1762 n Remarks: This well is partially penetrated with just the top of the sand perforated so a PBU was run in May of 2015 to determine the perm and skin. These properties were used in the Prosper model for the AOF determination, both the PBU and the Prosper run are attached. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed jill .. Title Reservoir Engineer Date 6/30/2015 DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producin face were reduced to zero psia Fb Basic orifice factor Mcfd/ hwPm Fp Basic critical flow prover or positive choke factor Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= -r7112-dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensionless GOR Gas-oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet(TVD) L Length of flow channel, feet(MD) n Exponent(slope) of back-pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia Pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back-Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 7/2009 Side 2 O:\Alaska\Fields\Ninilchi. Kton\Wells\Paxton 9\Prosper\Paxt '9 - Beluga 50 Channel.Out Page 1 . SYSTEM SENSITIVITY ANALYSIS - Input Data . Top Node Pressure : 0 (psig) Water Gas Ratio : 0 (STB/MMscf) Condensate Gas Ratio : 0 (STB/MMscf) Surface Equipment Correlation : Beggs and Brill Vertical Lift Correlation : Petroleum Experts 2 Solution Node : Bottom Node Rate Method : Automatic - Linear Left-Hand Intersection : DisAllow O:\Alaska\Fields\Ninilch Ixton\Wells\Paxton 9\Prosper\Pax #9 - Beluga 50 Channel.Out Page 2 ########################################### # SYSTEM SENSITIVITY ANALYSIS - Results # ########################################### dP Gas Oil Water Liquid VLP IPR Total dP dP dP Completion Rate Rate Rate Rate Pressure Pressure Skin Perforation Damage Completion Skin (MMscf/day) (STB/day) (STB/day) (STB/day) (psig) (psig) (psi) (psi) (psi) (psi) 0.0018399 0 0 0 0.69041 572.72 0.19214 0 0 0 18.50 0.098504 0 0 0 2.75 557.58 10.47 0 0 0 18.50 0.19517 0 0 0 7.02 542.00 21.13 0 0 0 18.50 0.29183 0 0 0 12.31 525.96 32.22 0 0 0 18.50 0.3885 0 0 0 18.10 509.39 43.76 0 0 0 18.50 0.48516 0 0 0 24.14 492.26 55.83 0 0 0 18.50 0.58182 0 0 0 30.32 474.49 68.47 0 0 0 18.50 0.67849 0 0 0 36.61 456.01 81.76 0 0 0 18.50 0.77515 0 0 0 42.94 436.74 95.79 0 0 0 18.50 0.87182 0 0 0 49.31 416.55 110.66 0 0 0 18.50 0.96848 0 0 0 55.71 395.32 126.52 0 0 0 18.50 1.065 0 0 0 62.13 372.86 143.55 0 0 0 18.50 1.162 0 0 0 68.56 348.92 161.98 0 0 0 18.50 1.258 0 0 0 75.00 323.19 182.14 0 0 0 18.50 1.355 0 0 0 81.43 295.19 204.49 0 0 0 18.50 1.452 0 0 0 87.88 264.20 229.76 0 0 0 18.50 1.548 0 0 0 94.34 229.00 259.16 0 0 0 18.50 1.645 0 0 0 100.79 187.24 295.04 0 0 0 18.50 1.742 0 0 0 107.24 132.87 343.46 0 0 0 18.50 1.838 0 0 0 113.70 14.83 455.45 0 0 0 18.50 First Total Maximum Maximum Maximum Gas Total WeIlHead WeIlHead Node dP dP NoSlip Erosional C Grain Rate Skin Pressure Temperature Temperature Friction Gravity Velocity Velocity Factor Diameter (MMscf/day) (psig) (deg F) (deg F) (psi) (psi) (ft/sec) (ft/sec) (inches) 0.0018399 18.50 0 40.02 40.02 0.0027773 0.68763 0.63004 1887.314 0.13353 0.0001 0.098504 18.50 0 40.49 40.49 2.02 0.73335 33.603 1883.759 7.13534 0.049305 0.19517 18.50 0 40.96 40.96 6.17 0.8323 66.070 1876.554 14.0833 0.1249 0.29183 18.50 0 41.44 41.44 11.30 0.96122 97.588 1865.064 20.9297 0.18032 0.3885 18.50 0 41.91 41.91 16.90 1.11 127.761 1849.557 27.6306 0.21639 0.48516 18.50 0 42.37 42.37 22.71 1.27 156.240 1830.272 34.1458 0.24025 0.58182 18.50 0 42.83 42.83 28.64 1.43 182.728 1807.461 40.4386 0.25667 0.67849 18.50 0 43.26 43.26 34.64 1.60 208.495 1787.880 46.6462 0.26832 0.77515 18.50 0 43.68 43.68 40.66 1.78 232.069 1764.725 52.6017 0.27705 0.87182 18.50 0 44.08 44.08 46.71 1.95 253.105 1737.802 58.2587 0.28358 0.96848 18.50 0 44.47 44.47 52.77 2.13 272.829 1711.836 63.7513 0.28871 1.065 18.50 0 44.83 44.83 58.82 2.31 291.630 1687.616 69.1223 0.2928 1.162 18.50 0 45.18 45.18 64.87 2.49 308.654 1662.383 74.2679 0.29603 O:\Alaska\Fields\NinilchL xton\Wells\Paxton 9\Prosper\Paxi - Beluga 50 Channel.Out Page 3 1.258 18.50 0 45.52 45.52 70.91 2.68 324.448 1637.618 79.2487 0.29872 1.355 18.50 0 45.84 45.84 76.94 2.86 337.856 1610.411 83.9181 0.30097 1.452 18.50 0 46.15 46.15 82.96 3.05 350.780 1585.354 88.5052 0.30287 1.548 18.50 0 46.44 46.44 88.98 3.24 363.867 1563.447 93.0937 0.30433 1.645 18.50 0 46.72 46.72 94.99 3.42 374.504 1538.829 97.3478 0.30561 1.742 18.50 0 47.00 47.00 100.99 3.61 384.727 1515.793 101.525 0.30671 1.838 18.50 0 47.26 47.26 106.98 3.80 395.124 1495.210 105.704 0.30756 Erosional Maximum Liquid Gas Velocity Turner Loading Rate Flag Velocity Flag (MMscf/day) (ft/sec) 0.0018399 No No 0.098504 No No 0.19517 No No 0.29183 No No 0.3885 No No 0.48516 No No 0.58182 No No 0.67849 No No 0.77515 No No 0.87182 No No 0.96848 No No 1.065 No No 1.162 No No 1.258 No No 1.355 No No 1.452 No No 1.548 No No 1.645 No No 1.742 No No 1.838 No No Solution Point . GasRate 1.762 l_Mscf/day) Oil Rate : 0 (STB/day) Water Rate : 0 (STB/day) Liquid Rate : 0 (STB/day) Solution Node Pressure : 108.57 (psig) dP Friction : 102.22 (psi) dP Gravity : 3.65 (psi) dP Total Skin : 356.48 (psi) dP Perforation : 0 (psi) dP Damage : 0 (psi) dP Completion : 0 (psi) Completion Skin : 18.50 Total Skin : 18.50 Wellhead Liquid Density : 48.543 (Ib/ft3) O:\Alaska\Fields\Ninilch xton\Wells\Paxton 9\Prosper\Paxi f9 - Beluga 50 Channel.Out Page 4 Wellhead Gas Density : 0.044384 (Ib/ft3) Wellhead Liquid Viscosity : 1.4949 (centipoise) Wellhead Gas Viscosity : 0.010813 (centipoise) Wellhead Superficial Liquid Velocity : 0 (ft/sec) Wellhead Superficial Gas Velocity : 610.511 (ft/sec) Wellhead Z Factor : 0.99761 Wellhead Interfacial Tension : 15.1435 (dyne/cm) Wellhead Pressure : 0 (psig) Wellhead Temperature : 47.05 (deg F) First Node Liquid Density : 48.543 (Ib/ft3) First Node Gas Density : 0.044384 (Ib/ft3) First Node Liquid Viscosity : 1.4949 (centipoise) First Node Gas Viscosity : 0.010813 (centipoise) First Node Superficial Liquid Velocity : 0 (ft/sec) First Node Superficial Gas Velocity : 610.511 (ft/sec) First Node Z Factor : 0.99761 First Node Interfacial Tension : 15.1435 (dyne/cm) First Node Pressure : 0 (psig) First Node Temperature : 47.05 (deg F) +++++++++++++++++++ + End of Report + +++++++++++++++++++ Ay/q(PPD)((10spsi2/cP)/(MMsefd)/hr) o - a a m a ' 1 In 1 • o ►K 0 Lf) E 06 N + V) „„„...1 1 1 0 r N C3)1411,11%.40 ` a. e V / • 4/N s CO .''''I( . .... , I 01 r UNl 1. i O 1 X co ..,.,,, : . . . 0, ca. . .., „ . I: \ro o o .o tO •• • e.• • (PP SWW/(d3/z!SdeOA)•ngenus0.billy Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. Q1_ 1.+ - L73 Well History File Identifier Organizing (done) ❑ Two-sided ❑ Rescan Needed 7RE AN: OVERSIZED: NOTES: Col Items: ❑ Maps: Grayscale Items: ogs: ❑ Poor Quality Originals: ❑ Other: ❑ Other: BY: MSS Date: (0 la— IS- /s/ wP Project Proofing BY: Maria Date: 10/'I-- 15 /s/ LI , Scanning Preparation x 30 = J5O + c I = TOTAL PAGES / 71 (Count does not include cover sheet) BY: aZEPDate: 6/ 1411 15 /s/ Production Scanning 1 Stage 1 Page Count from Scanned File: 1 70-(count does include cover eet) Page Count Matches Number in Scanning Preparation: YES VVf NOOBY: deb Date: I15 /s/ I Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Stage 2 Additional Well Reports: el) NO TOTAL PAGES:(3` 3 Digital version appended by: Meredith 0 Michal Date: 1 n 1/r (/( /s/ Final Page Count: Stage 1 + Stage 2: TOTAL PAGES: a05/ g g --- Scanning is complete at this point unless rescanning is required. 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E O at 0 o a M 0 STATE OF ALASKA AL,..,r(A OIL AND GAS CONSERVATION COM, _SION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon U Plug Perforations U Fracture Stimulate ❑ Pull Tubing U Operations shutdown LI Performed: Suspend ❑ Perforate ❑✓ Other Stimulate ❑ Alter Casing ❑ Change Approves Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: 1(z w/e---/ ur 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development D Exploratory ❑ 214-173 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 50-133-20647-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL384372 Paxton#9 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Ninilchik Field/Beluga&Tyonek Gas Pool 11.Present Well Condition Summary: Total Depth measured 6,733 feet Plugs measured N/A R E C E I V E D true vertical 3,503 feet Junk measured 6,570 feet MAY 2 1 20 5 Effective Depth measured 6,643 feet Packer measured 3,394 feet �� true vertical 3,428 feet true vertical 1,722 feet . G CC Casing Length Size MD ND Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 2,269' 9-5/8" 2,291' 1,401' 5,750 psi 3,090 psi Intermediate Production 6,723' 5-1/2" 6,723' 3,495' 10,640 psi 7,480 psi Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 2-7/8" 6.4#/L-80 3,482' 1,748'ND SLB TRAMAXX 5E SSSV 170'MD 170'ND Packers and SSSV(type,measured and true vertical depth) Prod Pkr 3,394'MD 1,722'ND 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 1126 0 0 124 Subsequent to operation: 0 1691 0 0 128 14.Attachments: 15.Well Class after work: Daily Report of Well Operations Q Exploratory Development Q Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas Q WDSPL❑ 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: 315-210 Contact Taylor Nasse Email tnasse a.hilcorp.com Printed Name _j Taylor Nasse Title Operations Engineer / I Signature , Phone 907-777-8354 Date 5/., // iS 4, -i 4' ' RBDMS1 MAY 2 9 2015 Form 10-404 Revised 5/2015 � /�� Submit Original Only ,3� Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date Paxton 9 50-133-20647-00-00 214-173 4/18/15 4/21/15 Daily Operations: 04/18/2015 -Saturday Obtain PTW. Hold safety meeting and JSA. Pull pit liner, move in equipment. Unload 1.5" coil reel. Spot pump and nitrogen tank. Run return iron and choke to tank. Stab pipe. Start BOP test in accordance with sundry and AOGCC standards. Low pressure test 250 psi and high 4,500 psi. Witness waived by Jim Regg, AOGCC. BOP test complete. Well turned back over to production. Flow through the night. Wellsite secure and location secure. Crews off location. 04/19/2015 -Sunday Obtain PTW. Hold safety meeting and JSA. Pick injector head and 30 ft of lubricator. Make up 2-1/8" tool assembly as follows: 1.5in CT dimple connector. Check valves, NOV bidi jars, Hydraulic disconnect, circ sub, GS spear, GS box x JDC overshot gutted. Pull test coil connector 25k. Pressure test low 250 psi/ high 3,500 psi. Stab on well. Pressure test lubricator 250 low/4,500 psi high. Open well RIH. Initial WHP 318psi. Slow down for SSSV restriction. No weight stacked. RIH 85 ft/min. Perform weight checks every 1,500 ft. RIH Weight-750 lbs. 3,350 ft weight check 6,500 lbs. Perform 3 weight checks above fish. Consistent weight 6,500 lbs up and -750 down. Stack weight at 3,408' 2,100 lbs down on fish. No over pull seen. Second attempt stack 3,500 lbs down on fish at 35 ft/min. No overpull seen. 3rd attempt stack 4k down and 600 lbs on consistent over pull. Picked OOH to 3,250 ft. RIH 4th attempt. Stack weight at 3,408' CTMD. Jarred down. Broke fish loose. Picked up to see if we were latched. Same 600 lbs of over pull. POOH to 3,250 ft. RIH to bottom. RIH with fish latched at 60 ft/min. Stacked weight at 6,623ft CTMD. 1,800 lbs down. Picked up weight clean 11k. RIH stack same depth 6,623ft CTMD. Good indication we are on bottom with fish. With 1,500 lbs down came online with pump at 1 bbl/min 3,500 psi 2.5 bbls pumped. Pick up off fish. POOH to surface at 100 ft/min. At surface master swab closed. Bleed down stack, pop off well. Only GS spear. JDC and 2in GS box landed on fish and left at bottom. Break down tools. Memory tools programmed and powered up. Install on coil. Stab on well and pressure test lubricator. Open well. RIH WHP 650 psi. RIH with memory CCL PTL Stopped at 5,000 ft and painted flag. Log OOH at 45 ft/min. Stop at 4,850.5' and paint yellow flag for correlation depth to EOP. Continue to log OOH at 45 ft/min. Stop logging at 3,400 ft. Memory hand securing counter. Continue to POOH 100 ft/min. At surface. Close in well. Bleed down stack. Pop off well. Downloading memory log. Coil stack down lubricator. Secure wellhead. Location secure. Total fluid pumped 5 bbls of 6% KCL. Turn well over to production. 04/20/2015 - Monday Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date Paxton 9 50-133-20647-00-00 214-173 4/18/15 4/21/15 Daily Operations: Obtain PTW. Hold safety meeting and review JSA. Unload Weaver trailer with TCP Rack and guns. Fire equipment. Pick injector head and stab 30 ft off lubricator. Drift MHA with .5in ball for firing head. MHA consists of 2.125in tools. Dimple coil connector, double flapper check valves, mark IV hydraulic disconnect and 1.Sin MT x 1in MT x over. Online with pump. Fluid pack CT string. Pressure test MHA to 250 low/3,500 psi high. No leaks. Install TCP CBF firing head. Fluid pack and pressure test firing head down back side line. 300 low pt and 2,500 high pt. Good test. Slowly bleed down to tank. Pop of well and inspect firing head for pin shift. Firing head good to go . Pick up 20' 2.00" 6 SPF/60 degree PJ HMX 6.5gm 20' gun with 19' of penetration. Pull up and tag packoffs. Fluid pack stack and pressure test low 250 high/2,500psi. Good test. Shut in flow line and open well to RIH. WHP 343 psi. Run CT 50 ft past painted flag at 4,850.50 ft. Pick up OOH to Flag. OOH weight at flag 4,871 lbs. Confirmed with reservoir engineer depth shift of 4 ft. Uncorrected flag depth 4,850.50. Memory tool reference to EOP 13.06ft. 4,850.5-13.06+4ft=4,841.44. Corrected EOP at flag. EOP to top shot add 7.13ft. Top shot at flag 4,848.57 ft. Corrected depth on EIM CT counter. Production open wing and start flowing well. Load 1/2" steel ball in reel. High gears stall of 3,500' against reel valve. Ball launches and confirmed movement in coil. Pick up coil out of hole to 4,802 ft, top shot corrected depth. Online 1.4 bbls a minute. Confirmed ball went over goose neck. Drop rate to .6 bbls a minute 1,800 psi pump pressure. Ball on seat pressure up to fire guns. 3,750 psi guns fired. Pick up out of hole 200 ft. WHP before firing 123psi. No change in WHP after guns fired. Monitor well for 1 hr. No flow or increase in pressure. POOH to surface. Swab closed. Hold pre job safety meeting with TCP before popping off well. Confirmed all shots fired. 1/2in ball recovered. Stab on well. Cool down N2. Blow coil dry to open top tank. 1,200 scf for 20 minutes. Bleed down CT. Pop off well and stack down lubricator and injector head. While OOH well started coming online. 500k rate at 147 psi. 12.3 bbls returned . Night cap installed. Wellsite secure. Well increasing in rate to 900k and 153 psi whp. Crews off location. 04/21/2015-Tuesday Obtain PTW. Hold safety meeting and review JSA. Rig down SLB CTU 12. Swap Injector blocks goosneck rollers from 1.5in to 1.75in. Disptach trucks to move equipment. Load crane on low boy. Mobilize equipment to Susan Dionne 8 and stage. Ninilchik Unit 14 SCHEMATIC Well: Paxton #9 PTD: 214-173 API: 50-133-20647-00 Ililrorp Alaska,Lit RKB=18.7' ,� CASING DETAIL 16" Size Type Wt/Grade/Conn ID Top Btm ,. ,► 16" Conductor 109/X-56/Weld Surf 80' T'! 6461"• '• 9-5/8' Surface 40/L-80/BTC 8.835" Surf 2,291' rw 5-1/2" Production 17/P-110/CDC 4.892" Surf 6,723' i "'+ TUBING DETAIL 2-7/8" Tubing 6.4/L-80/EUE-8rd 2.441" Surf 3,482' 4' � '' . , JEWELRY DETAIL ) No. MD TVD ID OD Item 9-5/8" 4. Is' 1 154' 154' CIM 2 170' 170' 2.312" 4.609" SLB TRMAXX SE SCSSSV 3 3,393' 1 1,722' XO .. 4 3,394' 1,722' Prod Pkr 5 3,399' 1,724' XO Filt,c410..: 6 3,443' 1,737' 3.25" X-Nipple �' 7 3,482' 1,748' Wireline re-entry guide w, r 8 6,570 3,367' Schlumberger tension sub,telemetry, (2)tractors, GR,bumper �� sub,hollow carrier(73 ft tool length) PERFORATION DETAIL Sands Top(MD) Btm(MD) Top(ND) Btm(TVD) Ft Date Status 4i4"(. .4:4 BIg50channel 4,790' 4,802' 2,181' 2,186' 12 1/13/15 Open Iet 4,802' - 4,822' -- 2,186' 2,195' 20 4/20/15 Open 8-1/2"Hole ,'' • -. 3 c:/, • 6 744 A" t, rs' t7'ti Xy• BIg50chann . j • BIg50channel wA J ttt444,,, 4, t i (!y 8 `. PBTD=6,643 MD/3,428'TVD TD=6,733' MD/3,503'ND Updated by DMA 05-19-15 1111 4' 1i,i 3 THE STATE Alaska Oil and Gas ofALASKA Conservation Commission -� �- • iiti = 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907 279.1433 OA, AL Fax• 907.276.7542 www.aogoc.alaska.gov Taylor Nasse Operations Engineer Hilcorp Alaska, LLC cY)L1 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga& Tyonek Gas Pools, Paxton#9 Sundry Number: 315-210 Dear Mr.Nasse: 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, Daniel T. Seamount, Jr. Commissioner DATED this 1 5 day of April, 2015 Encl. RECEIVED ` STATE OF ALASKA APR 09 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program❑ Suspend❑ Plug Perforations❑ Perforate❑ . Pull Tubing ❑ Time Extension❑ Operations Shutdown❑ Re-enter Susp.Well ❑ Stimulate❑ Alter Casing ❑ Other. fIkr" 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5. Permit to Drill Number 1 Exploratory ❑ Development0 • 214-173 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic I:1 Service ❑ 6.API Number. Anchorage,Alaska 99503 50-133-20647-00 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O.701 Paxton#9 Will planned perforations require a spacing exception? Yes I=1 No E 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL384372 • Ninilchik Field/Beluga&Tyonek Gas Pool • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 6,733' 3,503 . 6,643 3,428 N/A 6,570' Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 16" 80' Surface 2,269' 9-5/8" 2,291' 1,401' 5,750 psi 3,090 psi Intermediate - Production 6,726' 5-1/2" 6,726' 3,495' 10,640 psi 7,480 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 4,790'-4,802' 2,181'-2,186' 2-7/8" 6.4#/L-80 3,482 Packers and SSSV Type: Prod Pkr Packers and SSSV MD(ft)and ND(ft): 3,394'MD/1,722'ND SLB TRMAXX 5E SCSSSV 170'MD/170'ND 12.Attachments: Description Summary of Proposal Q 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑� Exploratory ❑ Stratigraphic ❑ Development 10 Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 04/16/15 • Commencing Operations: Oil ❑ Gas ❑, • WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: VVI NJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative. GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Taylor Nasse Phone: 907-777-8354 Email tnasse aahilcorD.com Printed Name T Ir Nasse Title Operations Engineer 7 Signature �_ Phone 907-777-8354 Date Li// 0 p 1 15 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: (�1' 3I�- 21° Plug Integrity ❑ BOP Test [` Mechanical Integrity Test ❑ Location Clearance❑ I Other: P-1_Cir.') /,5,. Al f '�S/-- ( AkAJf A SIS p s ) Spacing Exception Required? Yes ❑ No Q Subsequent Form Required: i b-'1 Oy ,."-7/' � APPROVED BY 1 6 Approved by: l� ' > COMMISSIONER THE COMMISSION Date: "ig/ (-/3-/S ^ �J� j,/../1",15- Submit Form and Form 10-403 evised 10/zot2) �A Rt ej44 AaEfor 12 months from th ate of approval./,/ acen Duplicatev ' '' vv RBDMS� APR 1 8 2015' * a "' b `i-y /s Well Prognosis Well: Paxton#9 Flilcorp Alaska,LL Date:4/8/2015 Well Name: Paxton#9 API Number: 50-133-20647-00 Current Status: Producing Leg: Estimated Start Date: December 17, 2014 Rig: Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 214-173 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: Estimated Bottom Hole Pressure: —1,505 psi at 3,500' ND (Assumed 0.43 psi/ft gradient) Max. Anticipated Surface Pressure: —1,155 psi (0.10 psi/ft gas gradient) OK" Brief Well Summary Paxton#9 is currently completed and producing from the Beluga sands. The well consists of 9-5/8" surface casing and 5-1/2" production casing with 2-7/8"tubing/packer completion. Objective of Work Add perforations in the Beluga sands. . Notes Regarding Wellbore Condition • Prior to perforating,a 73 ft. e-line tool assembly consisting of a tension sub,telemetry, (2)tractors, GR, bumper sub, and a hollow carrier will need to be pushed to bottom. • A pressure/temperature survey will be run to assess fluid level. If significant fluid is found,the well will be jetted dry with nitrogen. Coiled Tubing Procedure 1. RU CTU and equipment. Notify AOGCC 24 hours prior to testing at http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html 2. Shcll tcst-BOPE/lubricator to 250 psi low/4500psi high (unless due for weekly BOPE test—then a full BOPE test will be done). jZ 5IP 'lest- re 3. Perforate the Beluga sands with 2" 6 SPF 60 deg phased perf guns.All intervals are planned for 12 SPF so each will be shot twice. Depths are from the Canrig LWD Combo log dated November 30`h, 2014. Send the correlation pass to Taylor Nasse and David Buthman for confirmation. • 1:1 Well Prognosis Well: Paxton#9 Hilcorp Alaska,LL Date:4/8/2015 Gross Proposed Perforated Intervals Sands Top(MD) Btm (MD) FT Beluga BIg50channel ±4,790' ±4,910' ±120 4. POOH. 5. Flow well through test separator and record water and gas rates. 6. RD CTU. 7. Turn well over to production. 8. If any of the Beluga sands are not commercial,then the zone will be plugged back with a bridge plug or casing/tubing patch as necessary. Attachment: Current and Proposed Wellbore Schematic Ninilchik Unit iti SCHEMATIC Well: Paxton #9 PTD: 214-173 API: 50-133-20647-00 Hileorp Alexke,LLC RKB=18.7' ..,, ).- W CASING DETAIL 16" .46 Size Type Wt/Grade/Conn ID Top Btm ,7r 16" Conductor 109/X-56/Weld Surf 80' 9-5/8' Surface 40/L-80/BTC 8.835" Surf 2,291' 1, J 5-1/2" Production 17/P-110/CDC 4.892" Surf 6,723' !' TUBING DETAIL -f` 'f'i 2-7/8" Tubing 6.4/L-80/EUE-8rd 2.441" Surf 3,482' Itkiy7 1'3 I r"' , rit ' t, 4'3 JEWELRY DETAIL A No. MD ND ID OD Item 9-5/8" F:-' 'r' L.'4" 1 154' 154' CIM JP Hut r,lit � ,i 2 170' 170' 2.312" 4.609" SLB TRMAXX 5E SCSSSV '" 3 3,393' 1,722' XO s 1 4 3,394' 1,722' Prod Pkr W5 3,399' 1,724' XO ��ss, 6 3,443' 1,737' 3.25" X-Nipple Or,ai +� �y�` jo s,`• 7 3,482' 1,748' Wireline re-entry guide r�Y"' s ; 8 3,412' 1,728' Schlumberger tension sub,telemetry, (2)tractors, GR,bumper * i sub,hollow carrier(73 ft tool length) i PERFORATION DETAIL r 'b Sands Top(MD) Btm(MD) Top(ND) Btm(ND) Ft Date Status • '+ BIg50channel ±4,790' ±4,802' ±2,181' ±2,186' ±12 1/13/15 Open +iet r4 8-1/2"Hole1 � 3 • *. s 4y 4 ,i c Th6 i (2A-1" 2 '— ' 8 + �1� 1 ' BIg5Ochannel it } . l ir+• ,, 410 4Trrr ' .d',.. ^+r 1 ♦, xkp .r,— 17 *4. 44#3 5" i, #.� 5. ?S Yf•�— +iS3� . , PBTD=6,643 MD/3,428'ND TD=6,733' MD/3,503'ND Updated by TWN 02-13-15 Ninilchik Unit II PROPOSED Well: Paxton #9 PTD: 214-173 API: 50-133-20647-00 Ilileorp Alaska,LLC RKB=18.7' .� CASING DETAIL 16" Size Type Wt/Grade/Conn ID Top Btm i }:Ti'4 16" Conductor 109/X-56/Weld Surf 80' 9-5/8' Surface 40/L-80/BTC _ 8.835" Surf 2,291' t • 5-1/2" Production 17/P-110/CDC 4.892" Surf 6,723' �`-,4 • TUBING DETAIL 2-7/8" Tubing 6.4/L-80/EUE-8rd 2.441" Surf 3,482' .ik ".#,$, , tirr JEWELRY DETAIL l• .. ° No. MD ND ID OD Item 9-5/8" , i -'I s 1 154' 154' CIM 2 170' 170' 2.312" 4.609" SLB TRMAXX 5E SCSSSV 3 3,393' _ 1,722' XO :,... 4 3,394' 1,722' Prod Pkr 5 3,399' 1,724' XO 6 3,443' 1,737' 3.25" X-Nipple I..,. 7 3,482' 1,748' Wireline re-entry guide 8 6,570' 3,367' Schlumberger tension sub,telemetry, (2)tractors, GR,bumper " �`' sub,hollow carrier(73 ft.tool length) *,? _, PERFORATION DETAIL >, Sands Top(MD) Btm(MD) Top(ND) Btm(ND) Ft Date Status Vit . BIg50channel ±4,790' ±4,802' ±2,181' ±2,186' ±12 1/13/15 Open • 8-1/2"Hole ,11,4' BIg50channel I ±4,790' ±4,910' ±2,181' ±2,234' ±120 Future Proposed • .f- es t. 0 •'' 6 +%a ` i 'L7 , . 1M ' lt,r_ BIg50channel 440_ _fes r •P'rr Ati ♦wJ e Pr,, 8 ,: „ 5.5" ,.F . p .' 4 sIt PBTD=6,643 MD/3,428'TVD TD=6,733' MD/3,503'ND Updated by TWN 04-08-15 Ninilchik Unit B Paxton#9 4/08/2015 Hilrorp Ua.L...1.1.1. Paxton#9 16X95/8X5'/:x2% Coil Tubing BOP Lubricator to injection head l la) 1.75"Tandem Stripper f 1 C � .,I --, 1/1610 -• I„ r I I Blind/Shear Blind/Shear I 11 Blind/Shear).i.ii mei Blind/Shear!,I,'.( F'• * -■ . si 11;11111=-11- I Nei 1.11 Mud Cross ni ui : + 4 1/16 10M X4 1/16 10M 0� 1 1 11lit 9 1...1118 ll II 1.1 1pl�i Outlet isoiill ; ; _ w/2-2 1/1610M full opening FMC valves Manual Manual Manual Manual 2 1/16 10M 2 1/16 10M '■' mi 2 1/16 10M 2 1/16 10M Crossover spool 4 1/1610M X3 1/8 5M i Swab Valve, til7: 110, , � WKM-M, r',<� Wing,WKM-M, 3 1/8 5M, DD trim ,eYc,, 3 1/8 5M, DD trim w/6 1/2"Otis top = Valve rated to 5,000psi Valves rated to 5,000psi \ /II 10 11KAII : ° NLS _ I411 IND�1 Upper Master, r■�` • SSV,3 1/8 5M WKM-M, � Valve rated to 5,000psi 3 1/8 5M, DD trim „,4-1,r,`�0' u Valves rated to 5,000psi !,, , itLower Master, WKM-M, ,.. 3 1/8 5M, DD trim .Y��' Valve ratpri to nnnosi 1,J , I, _I .11 Hilcorp Alaska, LLC Post Office Box 244027 Anchorage,AK 99524-4027 RECEIVED 3800 Centerpoint Drive Suite 1400 FEB 13 2015 Anchorage,AK 99503 Phone: 907/777.8300 February 13, 2015 AOGCG Fax: 907/777.8301 Alaska Oil and Gas Conservation Commission 333 W. 7t"Ave., Suite 100 Anchorage, Alaska 99501 Re: Paxton"9 Form 10-407 PTD: 214-173 API: 50-133-20647-00-00 Dear Commissioner: Please find the enclosed Well Completion Form 10-407 for Paxton 9. Please do not hesitate to contact me should you have any questions or need additional information. Sincerely, HILCORP ALASKA, L Cody Dinge Drilling Technician (907)777-8389 cdinger@hilcorp.com 1 of 1 STATE OF ALASKA • ALA OIL AND GAS CONSERVATION COM1 ,ON WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a.Well Status: Oil ❑ Gas Q . SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ 1b.Well Class: 20Mc25.105 2OMc25.11O Development ❑✓ • Exploratory ❑ GINJ ❑ WINJ ❑ WAG ❑ WDSPL❑ No.of Completions: _, Service ❑ Stratigraphic Test ❑ 2.Operator Name: 5.Da Comp.,Susp.,or/,/ 12.Permit to Drill Number: Hilcorp Alaska,LLC Aba .: X11 015 Ij ,/•2,2, /S 214-173 • 3.Address: 6.Date Spudded: 13.API Number: 3800 Centerpolnt Drive STE 1400 Anchorage,AK 99503 •11/18/2014 50-133-20647-00-00 • 4a.Location of Well(Govemmental Section): 7.Date TD Reared: 14.Well Name and Number: Surface: 3058'FEL,22 Sec 13,T1S,R4W,SM,AK " 114, 11/0/2014 Paxton#9 Top of Productive Horizon: '1i '1'"1-- 1/..21*i( 8.KB(ft above MSL): 166.6 15.Field/Pool(s): 888'FSL,2103'FWL,Sec 12,T1S,R14W,SM,AK GL(ft above MSL): 148,5'0 1; Ninilchik Field Total Depth: 9.Plug Back Depth(MD+TVD): 't' Beluga/Tyonek Gas Pool - 936'FNL,2200'FWL,Sec 12,T1S,R14W,SM,AK 6643'MD/3428'TVD 4b.Location of Well(State Base Plane Coordinates,NAD 27): 10.Total Depth(MD+TVD): 16.Property Designation: Surface: x- 206265.74 • y- 2230441.15 • Zone- 4 . 6733'MD/3503'TVD • ADL384372 TPI: x- 206191.43 y- 2232164.9 Zone- 4 11.SSSV Depth(MD+TVD): 17.Land Use Permit Total Depth: x- 206372.03 y- 2235617.5 Zone- 4 170'/170' Surface agreement w/parcel fee owner 18.Directional Survey: Yes Q No ❑ 19.Water Depth,if Offshore: 20.Thickness of Permafrost MD/TVD: (Submit electronic and printed information per 20 AAC 25.050) N/A (ft MSL) N/A 21.Logs Obtained(List all logs here and submit electronic and printed information per 20AAC25.071): 22.Re-drilVLateral Top Window MD/TVD: ROP-DGR-ADR 2"/5"MD,DGR-ADR 2"/5"TVD,Formation Log 2"/5"MD/TVD,LWD Combo Log 2"MD/TVD, N/A Gas Ratio 2"MDlTVD,Drilling Dynamics 2"MD/TVD 23. CASING,LINER AND CEMENTING RECORD WT.PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING . GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 16" 109 X-56 Surface 80' Surface 80' Driven N/A 9-5/8" 40 L-80 Surface 2291' Surface 1401' 12-1/4" 139 bbl 12.5#,65 bbl 15.2# 5-1/2" 17 P-110 Surface 6723' Surface 3494 8-1/2" 145 bbl 13.5#,90.3 bbl 15.7# r 24.Open to production or Injection? Yes Q No ❑ 25. TUBING RECORD If Yes,list each interval open(MD+TVD of Top and Bottom;Perforation SIZE DEPTH SET(MD) PACKER SET(MD/ND) Size and Number): 2-7/8" 3,482' 3,394'/1,722' Perforation Interval: 4,790'-4,802'MD(2,181'-2,186'ND)2"6 SPF 26. ACID,FRACTURE,CEMENT SQUEEZE,ETC. Was hydrauNc fracturing used during completion? Yes ❑ No ❑✓ - *.''_rokRECEIVED DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED � Jt . /* (/is FEB 13 2015 vt-IttnCC 27. AOG PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 1/16/2015 Flowina Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF. Water-Bbl: Choke Size: Gas-Oil Ratio: 1/19/2015 24 Test Period .-►0 652 0 N/A Flow Tubing Casing Press: Calculated Oil-Bbl Gas-MCF: Water-Bbl: Oil Gravity-API(torr): Press. 137 0 24-Hour Rate - 0 652 • 0 • 28. CORE DATA Conventional Core(s)Acquired? Yes p No D • Sidewall Cores Acquired? Yes p No❑� • If Yes to either question,list formations and intervals cored(MD+TVD of top and bottom of each),and summarize lithology and presence of oil,gas or water (submit separate sheets with this form,if needed).Submit detailed descriptions,core chips,photographs and laboratory analytical results per 20 AAC 25.071. Form 10-407 Revised 10/2012 i9NTINUED ON REVERSE Submit original only 'i' i Zip.i.S - Y/ '/I RBDMS . FEB 2 3 2015 /R,t.ai r',/,.,G 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? ❑ Yes 0 No . If yes,list intervals and formations tested, briefly summarizing test results.Attach separate sheets to this form,if needed, and submit detailed test information per 20 AAC 25.071 Beluga 2560 1480 Beluga 40 3606 1782 Beluga 50 4503 2059 Beluga 60 5304 2434 Beluga 70 5919 2841 Beluga 80 6142 3014 Beluga 130 6668 3449 Formation at total depth:Beluga 130 6668 3449 • 31. List of Attachments:Well Schematic, Days vs Depth Graph,MW vs Depth Graph,Definitive Directional Survey, Daily Drilling&Completion Composite Reports,Casing&Cementing Reports 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: L v-tL kEtt e. Email: Ikeller .hilcorp.com Printed Name: Luke Keller Title: Drilling Engineer 4// Signature: Phone: 907-777 8395 Date: 23 0/JINSTRUCTIONS 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 downhole well design is changed. Item 1 b: 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 production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI(Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. 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: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: 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 interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing,Gas Lift,Rod Pump,Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 10/2012 Ninilchik Unit a SCHEMATIC Well: Paxton #9 3 PTD: 214173 API: 50-13 -20647-00 Hileorp Alaska,Lt.0 RKB=18.7' " CASING DETAIL 16" , y + 1 Size Type Wt/Grade/Conn ID Top Btm f 16" Conductor 109/X-56/Weld Surf 80' e`: 9-5/8' Surface 40/L-80/BTC 8.835" Surf 2,291' .3 , (I " 5-1/2" Production 17/P-110/CDC 4.892" Surf 6,723' " TUBING DETAIL 2-7/8" Tubing 6.4/L-80/EUE-8rd 2.441" Surf 3,482' i'k I ' ,,,p�er� ii I �J 2 y . "; : ,. JEWELRY DETAIL , °' `" No. MD ND ID OD Item 9-5/8" w 1 154' 154' CIM 2 170' 170' 2.312" 4.609" SLB TRMAXX 5E SCSSSV 41 73 3 3,393' 1,722' XO J 4 3,394' 1,722' Prod Pkr cs., ' '" ". 5 3,399' 1,724' XO ,1�# " 6 3,443' 1,737' 3.25" X-Nipple IA-A: 7 3,482' 1,748' Wireline re-entry guide fi Schlumberger tension sub,telemetry, (2)tractors, GR,bumper 8 3,412' 1,728' 0 ` sub,hollow carrier(73 ft.tool length) ,r 5 '* - PERFORATION DETAIL Sands Top(MD) Btm(MD) Top(ND) Btm(ND) Ft Date Status 'lit..., *" ' BIg50channel ±4,790' ±4,802' ±2,181' ±2,186' ±12 1/13/15 Open 8-1/2"Hole ;� Li.',,, .-Ilt C.8/.._ No.-.•._ iLlifr-LA- ij ttrr" .73 1: 0 6 44, ir. ' R; ' BIg5Ochannel r 0,40 *r...„, "4(' :- . q 5.5" ,. PBTD=6,643 MD/3,428'TVD TD=6,733' MD/3,503'TVD Updated by TWN 02-13-15 Hilcorp Energy Company Composite Report Well Name: NINU Paxton 9 Field: Ninilchik County/State: ,AK Location(LAT/LONG): Elevation(RKB): 18.5 API#: 50-133-20647-00-00 Spud Date: 11/18/2014 Job Name: 1413466D Paxton 9 DRILLING Contractor AFE#: 1413466D AFE$: Rpt Date Activity Date Ops Summary 11/11/2014 11/10/2014 install cellar box 11/12/2014 11/11/2014 LEVEL PAD 11/13/2014 11/12/2014 11/14/2014 11/13/2014 11/15/2014 11/14/2014 Continue to R/D on FC#6,R/D pits,mud pumps,R/D boiler,blow down steam and water lines.Lay liner and matting on Paxton 9.Trucks on location @ 08:00 hrs.R/D gas buster and pit roofs.;R/D doghouse,draworks,motor skids and remaining rig floor equipment.Remove derrick.Mobilize rig to Paxton pad.Set 21 1/4"diverter tee and annular in place on Paxton 9.;Move carrier off well Falls Creek#6 and stage on location. Install ladder and grating for cellar box on Paxton#9. R/D well water hard lines. Prep misc equipment and secure on pallets for move.;Remove containment and felt from Falls Creek. Clean and clear location.Rig is 100%off Falls Creek#6.;Remove and store berm around shacks. Load misc equipment into"sea-can". Finish setting rig mats on Paxton#9. Set pony subs for carrier. Spot wellhead,test pump,power pack in cellar area. 11/16/2014 11/15/2014 Load out remaining equipment and continue to cleanup on Falls creek pad.Trucks arrived @ 08:00 hrs.Haul sub and derrick to paxton 9,set subase and draworks skid in place.;Set derrick,motor skids,boiler house,rig fuel tank,pits and catwalk in place,R/U pits,pump house and buildings.R/U hydraulics and electrical.;Finish positioning grass hopper,shut do gens and hook up all power cables. Dress out pump room,hp lines,shock hoses and restraints. Install walkways around rig.;Spool on drilling line and raise derrick. Scope derrick. Install handrails and grating around slop tank. Install centrifuge in pre-mix. 90% rigged up. 11/17/2014 11/16/2014 Pin and secure tq tube to mast. Install tq bushing. Run steam lines,rig down office trailers and move to Paxton,rig up same. Install top drive.Spot aux fuel tank;Set degasser skid. C/O camp gen. Attempted to install windwalls but had to suspend operations due to high winds.;Rig up floor,dress out top drive w/ handling equipment. Spot Sperry,Canrig and 3rd Gen. R/U flowlines in pits and centrifuge;R/U and function Pason. Begin Rig acceptance checklist. C/O saver sub. Raise gas buster. Tighten flanges on diverter"T". R/U water line from well. Rig is 100%set,85%rigged up. 11/18/2014 11/17/2014 Continute to R/U on Paxton 9.Set handy berm,pipe racks,geronimo line.Finish R/U steam lines and heaters.Set windwalls on rig floor,pits and sub.Finish water line from water well to rig.;Set cattle chute.Total safety R/U gas alarm system.Canrig and sperry on location rigging up equipment.Install diverter vent line.;P/U riser,Install bleeder line and hole fill line,4 point annular,hook up koomey lines. Funtion test same(good)w/34 sec close. C/O#2 winch line, troubleshoot and re-calibrate PVT system.;Fill pits w/water and function test mud pumps,centrifugal pumps,and low psi mud lines. Repair and dress out shakers w/4x70 and 4x80. Continue w/pre spud checklist. Build mud docks.;Set wear bushing. RKB to ctr LDS=22.52'. Rig accepted @ 06:00 hrs. 11/19/2014 11/18/2014 SLM 52 joints of 5"drill pipe and 19 Its of 5"HWDP.Reposition light plants,set diverter warning signs in place.Continue to build 8.7 ppg,90 vis spud mud.;Drift,P/U and stand back 26 stand of 5"DP, tag bottom @ 85';Perform diverter function test using 5"drill pipe.AOGCC rep Bob Noble on location to witness test.Annular dose time 35 sec.Knife valve open time 2 sec.Perform accumulator drawdown test.;Total safety on location to calibrate and demonstrate gas alarm operation.;Drift and P/U 10 stands of 5"HWDP including jars,rack in derrick.;Slip and cut 60'of drilling line.Re-set and test crown-o- matic;Test both mud pumps.Pump through to check for leaks,Presure test mud line to 2000 psi.;Load Dir.tools to cat walk and prepair rig floor picking up BHA;BHA#1.M/U 12.25 PDC bit,Sperry Motor,Sperry MWD,XO Jars and 5"HWDP;DrIg F/95'T/385'WOB 10k,RPM 60,GPM 450/500,SPP1000,P/U42K, S/038K,ROT,40K TQ on 6K,Off 4k Mtr RPM 117/130,ROP 300 Slide 164'@ 343 Mag.MW 8.6,Vis 98.No losses.;.57 slide hrs,.86 rotate hrs.Currently 22' above the line and 3'left of the line.;TOH F/385'T/81'L/D bottle neck XO (No Tight Spots);Continue p/u BHA 8"Flex DC,HWDP and Jars.;;90 bbls hauled to disposal,Paxton 9 total 90 bbls 11/20/2014 11/19/2014 Drilling 12 1/4"surface hole from 385'to 730'pumping 520 gpm,1390 psi.12-17k WOB,60 RPM.Torq on 5k.torq off 4.5k,P/U 60k,S/O 58K,ROT 60k.MW 8.8 ppg,vis 160.;Drilling from 730'to 1158'pumping 515 gpm,1300 psi.Diff 190 psi.10-18k WOB,60 RPM.Torq on 8500.torq off 5600,P/U 65k,S/O 57K, ROT 60k.MW 9 ppg,vis 180.No losses.;Run centrifuge to maintain 8.8 ppg MW.;Drilling from 1158'to 1474'pumping 515 gpm,1700 psi.Diff 190 psi.10-18k WOB,60 RPM.Torq on 8500.torq off 5600,P/U 65k,S/O 57K,ROT 60k.MW 9 ppg,vis 180.No Iosses.;EOB 1436.23' INC 74.09 AZM 0.80 TVD 1162.26' 4.7 low .71 to the right;CBU @ 1474'(EOB 1436.23'section,top of Tangent).Cuttings consistently covering 30%of Shaker Screens.Hi vis sweep was pumped and came back to surface at the calc.stks.no increace in cutting;POH from 1474'to 782'HWDP @ 782'.Flowcheck well,POH to NMDC @ 231'with no issues.The hole took 2.3bbls over calc.displacement on TOH;Service TD;TIH F/231'T/1414' (No Problems)Load sweep in the pipe while washing last std to bottom,circ.sweep above bit before drilling new hole.;No Fill On Btm After Short Trip;Drilling from 1474'to 1663'pumping 515 gpm,1700 psi.Diff 190 psi. 10-18k WOB,60 RPM.Torq on 8500.torq off 5600,P/U 65k,S/O 57K,ROT 60k.MW 9 ppg,vis 180.No losses.Av ROP 64 fph;4.14 hrs slide time,2.55 rotate hrs.Currently 4.7'below the line and.71'rigt of the Iine.;180 bbls hauled to disposal,Paxton 9 total 270 bbls 11/21/2014 11/20/2014 Drilling 12 1/4"surface hole from 1663'to 2014'pumping 526 gpm,1500 psi.Diff 200 psi.10k WOB,60 RPM.Torq on 9500.torq off 7500,P/U 63k,5/0 48K, ROT 57k.MW 9.3 ppg,vis 168.;Install 120 screens on shaker to help reduce solids,Continually run centrifuge.;Drilling from 2014'to 2300'@ TD pumping 580 gpm,1800 psi.Diff 200 psi.7-10k WOB,80 RPM.Torq on 10k.torq off 8k,P/U 68k,S/O 45K,ROT 56k.MW 9.5 ppg,vis 175.No Iosses.;At TD:ART 5.99 AST 1.52 TDT 7.51 Last Survey:MD 2259.87'INC 72.8 AZI 356.24 TVD 1391.99(4.2'High 1.88'Left);Cric.2 B/U,sweep back @ calculated strokes with 60% increase in cuttings.Flow check well,no flow.;POH from 2300'to 782'HWDP @ 781'.Flowcheck well,POH to NMDC @ 231'with no issues.The hole took 3.0bbls over calc.displacement on TOH;Service Rig;TIH From 231'to 2237' (No Problems)Load sweep in pipe while washing last std to bottom, (2300'),;Cric.1 B/U,sweep back 50 stks over calculated with 20%increase in cuttings.2nd B/U cutting diminished,Flow check well,no flow.;TOH from 2300' to DC,lay down BHA;L/D BHA:Drain motor,break the Bit&L/D Motor,MWD,2 NM flex DC. Bit grade=1/2/CT/T/X/I/NO/TD;Pull wear ring and R/U and make a dummy run with 9 5/8 hanger with Cameron field rep.;180 bbls hauled to disposal, Paxton 9 total 540 bbls 01122/2014 11/21/2014 Make hanger dummy run per on rep.RKB=22.51;Cleanup rig floor,R/U to run 9 5/8"casir Weatherford CRT and handling equipment. r Submit 24 hr notificaion to AOGCC for BOP test.;PJSM with Weatherford,rig crew and DSM.Baker loc and M/U shoe track with 2 centralizers over stop rings 10'from ends on shoe jt,1 mid tube on baker loc jt and float collar jt.;Check float operation.RIH with 9 5/8"BTC L-80 40#casing,M/U to diamond with an average M/U torq of 9845 ft lbs.Fill casing on the fly,use dog collar clamp on first 10 jts.;lnstall centralizer on every other jt ran to 317'(total 26 centralizers and 3 stop rings)RIH to 2266'.P/U 80K,S/O 45K.Correct displacement.;Stage pump up from 2 bpm to 4 bpm @ 425 psi.CBU,increase pump to 5 bpm @ 375 psi.slack off slowly just above landing hanger 20'in @ 2289',continue to circulate and reduce YP f/37-30.;Slow pump to 2 bpm,land hanger 22.5'RKB. Landed @ 2291.19'.Increase pump to 4 bpm @ 426 psi.continue to circulate and condition mud for cement job.DSM witness loading plugs.;Shut down pump, J" Unstab CRT.M/U cement head.;Shut down pump,PJSM,R/U cementing head and lines.Pressure test lines to 500/3500 psi 5 min ea.Batch 40 bbls of 10.0 6" ,i)• • ppg spacer.;Pumped 40 bbls of spacer @ 4 bpm.Pump 137 bbls Type 1 lead cement @4bpm.165 psi. Pump 65 bbls of 15.2 ppg tail cement starting @ 4 bpm,135 psi,;Drop upper plug,kick out plug pumping 10 bbs water, switch to rig pump,displace cement with 9.4 ppg mud,caught pressure at 20 bbls. Displace cement pumping 4 bpm,105 psi.;30 bbls away,spacer at returns to surface,at 60bbl.cement to surface,start dumping and adding retardant at flowline,pumping @4bpm 340psi(FCP 492);Slow pumps down to 2bpm to bump the plug(Plug did not bump.)CIP @ 22:40 HRS.Checked floats,bled back 1/2bbls(floats held);Total:10 bbls mud interface,40 bbls seal bond spacer,60 bbls lead cement,Casing was landed before cement job.100%returns entire job;Blow down&Rig down cementing equipment,hard lines,cement lines etc.;Back out landing jnt.flush out surface stack&well head:Make up pack off on running tool,land and test Per.Cameron Rep.;UD casing equipment:CRT,power tongs,spiders,service loop and power unit.;Check oil in motors,grease TD and blocks;R/D diverter line&diverter,and cleaning pits;900 bbls hauled to disposal,Paxton 9 total 1440 bbls 11/23/2014 11/22/2014 PJSM,N/D 21 1/4"diverter system.Cleanup up annular and knife valve.N/D diverter tee and ventline;lnstall multibowl wellhead,Install packoff,test void to 3000 psi for 15 min and test flange to 5000 psi for 15 min.per Cameron rep.continue remove diverter from celler.;N/U 11"5M BOPE.Continue to haul 9.4 ppg kla-shield mud from storage tanks.;Rigging up to test BOP's-set plug,fill stack, pressure up stack and check for leaks.;625 bbls hauled to disposal,Paxton 9 total 2165 bbls 11/24/2014 11/23/2014 PJSM,with 5"test jt,attempt to body test BOP,gland nut on wellhead leaking,Flange on kill line leaking,Tighten all flanges and gland packing nut.Perform Body test to 3500 psi;Test BOPE with 5",4 1/2"and 2 7/8"test jts.AOGCC Jim Regg waived witness on 11-21-14 @ 20:55 hrs.Test annular to 250/2500 psi 5 min ea.Test upper and lower IBOP,5"&4 1/2"floor valves,;choke maniflold valves,HCR,HCR kill valves,3"manual valve,upper and lower 2 7/8 x 5 VBR, blind ram to 250/3500 psi 5 min ea,Perfom electric and manual choke pressure bleed test.;Close annulas valve.Perform accumulator draw down test.Chart record all pressure tests.No failures.Total safety calibrate and test gas alarm system.;R/D test equipment,blow down lines.Install 9"ID wear bushing,Run in 4 LDS.;Service Top Drive,Pumps,Crown,Draw Works;PJSM on testing casing;Test casing to 2900 psi hold for 30 min,good test,blow down all lines and prepair to pick up BHA;P/U 8 1/2"BHA-Change stab.sleeve on motor,P/U BHA per DD.;Attempt to link up with MWD(NO GO),pump some warm mud through tool to help with down link,got some communication but not full;Continued picking up BHA,since the MWD will not be utilized on this run,we TIH and drilled out float equipment,and preform a fit test&TOH laying down 5"DP;Started washing down from 2105'pumping @ 350 gpm 35rpm 805psi 8tq.tagging the plug/cement @2161' (42'above the FC)continue drilling cement,float equipment and 20'of new hole;to 2320';90 bbls hauled to disposal,Paxton 9 total 2265 bbls 11/25/2014 11/24/2014 Cleanup rathole to 2300',drill 20'of new formation to 2320';Circulate and condition mud for F.I.T.;PJSM,P/U above shoe to 2285',close upper pipe ram. Perform F.I.T.to 12 ppg EMW with existing mud wt of 9.3 ppg.Apply 200 psi,10 sec press bled to 191 psi,5 min press bled to 158 psi.;.5 bbls pumped,.5 bbls bled back.Chart test.Good test.Bleed off pressure,open pipe ram.R/D test equipment.;Flowcheck well,Mix and pump dry job.;POH from 2285'UD 52 jts 5" DP to HWDP @ 760'.;Rack 5"HWDP,jars and flex collars in derrick.Correct displacement on trip out.:Trouble shoot MWD,coms with ADR,working with slower transfer protocol.;TIH with flex collars and 2 stds of HWDP.Test MWD tools,good test.;C/O to saver sub,install CDS40 saver sub.Change to 4 1/2" elevators.;P/U 4 1/2 DP(40 jnts)and single in the hole to 2000' +/-;TOH rack back(20 stnd)4 1/2 DP in hte derrick;P/U 4 1/2 DP single TIH to 2000'+/-and TOH racking 4 1/2 DP back in derrick,doing this procese until the remaining 4 1/2 DP is picked up to drill 8 1/2 hole section;Log down with LWD/MWD from 2300'to 2320';Drilling from 2320'to 2500'pumping 480 gpm,1600 psi.Diff 150 psi.10-12k WOB,60 RPM.Torq on 7.5K.torq off 5K,P/U 72,S/O 38K,ROT 50k.MW 9.3 ppg,vis 68.No losses.;4.2'above the line and 1.88'left of the line.;170 bbls hauled to disposal,Paxton 9 total 2435 bbls 11/26/2014 11/25/2014 Drilling 8-1/2"hole from 2,500'to 2,750' 450gpm 1,500 psi Rot.@ 70rpms TQ-8k ECD 10.45.;Pumped a hi-vis sweep @ 2,750'brought back 200%more cutting,no change in ECD(10.45)when sweep was completely out of hole.;Drilling 8-1/2"hole from 2,750'to 2,835'450gpm 1,500 psi.-rpm 70rpms TQ-8k ECD 10.45.;Decided to pump a 2nd sweep to ensure that we are staying a head of the game,sweep brought back 50%.;Drilling 8-1/2"hole from 2,835'to 3,310 TVD 1,683'450gpm 1,550 psi Rpm@ 75rpms TQ-9k ECD 10.61.;Pumped a hi-vis sweep @ 3,121'brought back 90%more cutting,no change in ECD (10.8)when sweep was completely out of hole.;Circ.and condition hole @ 450gpm 70rpms psi 1,350 beging ECD 10.47 ending 10.32.;TOH to 2,091' encountered some excessive drag(20k over)@ 2,698'to 2,549',dropped down 60'and CBU 75k p/u-40k s/o ECD 10.47.;Start pumping @ 150gpm increasing rate to 420gpm slowly.1300 psi ROT @ 35rpm.-begining ECD 10.47 ending 10.32.;Continue TOH from 2,549'to 2,300'(No Problems).;Service Top Drive.;TIH from 2,300'to 3,244'wash last 62'to bottom(3,306')No Problems.;Drilling from 3,306'to 3,620'TVD 1,784'pumping 420 gpm,1,500 psi.Diff 130 psi.10-12k WOB,75 RPM.Torq on 7.5K.torq off 4.5K,P/U 84,S/O 45K,ROT 54k.MW 9.4ppg,vis 62.No losses.ECD 10.54.;ART 10.85 AST 2.4 TDT 13.29 1.66 hiah 5.05 left.:180 bbls hauled to disoosal.Paxton 9 total 2615 bbls. 11/27/2014 11/26/2014 Drilling from 3,620'to 3,990' NO 1,892'pumping 430 gpm,1,450 psi.Diff 130 psi.10-12k WOB,75 RPM.Torq on 8K.torq off 90K,P/U 84,5/0 45K,ROT 54k.MW 9.4ppg,vis 58.No losses.ECD 10.47.;Drilling from 3,990'to 4,290' TVD 1,979'pumping 430 gpm,1,550 psi.Diff 150 psi.10-12k WOB,75 RPM. Torq on 10K.torq off 7K,P/U 90,S/O 45K,ROT 57k.MW 9.4ppg,vis.No losses.ECD 10.6.:Run centrifuge to drop MW from a 9.4 to 9.2 ppg water running 12 bph.;Drilling from 4,290'to 4,500' ND 2,061'pumping 430 gpm,1,550 psi.Diff 150 psi.10-12k WOB,75 RPM.Torq on 11K.torq off 7K,P/U 90,S/O 45K, ROT 57k.MW 9.4ppg,vis.No losses.ECD 10.6.;Last Survey MD 4,509'TVD 2,061'INC 65.75 AZI 3.81 2.14 low 2.78 left.;Circ.Tandem Sweeps around and brought back 80%on 1st and 50%on 2nd-pumping @ 450 gpms 1,700psi ECD's 10.6 start 10.43 end.;The remaining 4-1/2"drill pipe made it on location and off loaded @ 2130.;TOH from 4,500'to 3,300'(last short depth)monitor well for 10 min(no flow)continue TOH to the shoe(2,291')flow check(no flow).;PJSM, Slip&Cut off 41'of drilling line.;PJSM,P/U 76 jnts of 4-1/2"DP on top of the BHA.;440 bbls hauled to disposal,Paxton 9 total 2,615 bbls. 11/28/2014 11/27/2014 Continue to single in hole with 4 1.5"DP from 2,500'to 3,340'with no issues.;Fill pipe and CBU while lay out and tally 4-1/2"DP.400 GPM, 1,180 SPP, 70 RPM, Peak gas @ 1,140u.;Continue to single in hole from 3,340'to 3,897'with no issues.;Fill pipe,CBU, 400 GPM, 1,255 SPP, 70 RPM, Peak gas @ 47u.;Continue to TIH from 3,897'to 4,398'with no issues.;Fill Pipe,CBU,turn Elevators around.270 GPM,580 SPP, 70 RPM,ECD @ 11.0, Peak gas @ 47u.;Continue to TIH to 4,486'with no issues.Ream last stand to bottom @ 4,545'with 1'fill on bottom.;Drill f/4,545'to 4,682'(137)AROP=55 fph. 5-6K WOB,1560 SPP,80 TD RPM. 430 GPM,146 Mtr RPM,Diff 70 PSI,9.4 MW,ECD 10.56,PU 95K,SO 42K,Rot 55K,On Btm TQ 10-11K,Off Btm TO 10K.;CBU prior to drilling anticipated loss zone.430 GPM,1,509 SPP,80 RPM,Peak Gas @ 356u.;Drill f/4,682'to 4,827'(145)AROP=58 fph. 10K WOB,1,700 SPP,80 TD RPM. 430 GPM,146 Mtr RPM,Diff 117 PSI,9.4 MW,ECD 10.38,PU 100K,SO 45K,Rot 58K,On Btm TQ 11.8K,Off Btm TQ 10.2K.;Drill f/4,827'to 5,100'(273) AROP=58 fph. 10K WOB,1780 SPP,Dif 140,75 RPM. 450 GPM,9.3 MW,ECD 10.47,PU 102K,SO 45K,Rot 58K,On Btm TQ 12K,Off Btm TQ 10K.;Circ.tandom sweeps @ 5,100'sweep#1 brought back 100% more cuttings and#2 brought back 30%. Pumping @ 450gpm 80 rpm 10k TQ 1,600 psi.ECD 10.47 start 10.32 end with 9.3 MW.;TOH on elevators F/5,100' to 4,545'(No Problems).;Circ.bottoms up @ top of trip ECD 10.4/10.3.;Service Top Drive Grabber.;TIH F/4,545'wash last stand to bottom(no problems).;Drill f/5,100'to 5,323'(223)AROP=73 fph. 10K WOB,1780 SPP,Dif 140,80 RPM. 450 GPM,9.3 MW,ECD 10.42,PU 106K,SO 45K,Rot 60K,On Btm TQ 12K,Off Btm TQ 10K..18 low 2.54 Right.;;440 bbls hauled to disposal,Paxton 9 total 3,055 bbls. Energy Company Composite F._,_ort Well Name: NINU Paxton 9 Field: Ninilchik County/State: ,AK Location(LAT/LONG): Elevation(RKB): API#: 50-133-20647-00-00 Spud Date: Job Name: 1413466C Paxton 9 COMPLETION Contractor AFE#: 1413466C AFE$: Ops Summa," 12/4/2014 12/3/2014 Finish cleaning pits and tubing tally.,PJSM,make up scraper assy and TIH T/172'MD. Latch on elevators,failed and had to be replaced.,Wait on new elevators for 2-7/8"tubing to arrive. Continue cleaning non essential pits,flush mud lines and mixing KCL fluid.,Continue TIH w/scraper assy F/172'-T/6,733' MD. Tagged @ 6,633'MD,set dn 4k. 56k up,26k dn.,Circulate hole clean,pump 17 bbls vis sweep,displace w/6%KCL brine(8 NTU's). Pump @ 6 bpm, 1,300 psi,12%flow out.,TOH laying down tbg F/6,733'T/3,336'(107 jts total).,TOH standing back tubing F/3,336'-T/surface(53 stds total). Laydown scraper assy as per BOT rep.,Service rig.,Rig up Pollard test equipment. Test 5-1/2"casing T/3,500 psi w/30 min hold. Chart and record same. 12/5/2014 12/4/2014 Pulled wear bushing. Wear bushing,test joint,and retrieving tool shot out of hole due to trapped pressure of psi from 5.5"x 9.625"annulus. Incident investigation.,Safety stand down. Review incident and importance of understanding each task along with hazards.,Found that lockdown screws for 5.5"packoff had been backed out. Trapped psi from thermal expansion in 5.5"x 9.625"annulus forced packoff upward and caused the wear bushing retrieval assy to come out of hole. Redress packoff assy and re-install. Test packoff(test good).,R/U Weatherford casing and run 2.875"8rd EUE,6.4#tubing as per detail.,Make up control lines to SSSV and CIM. Make up hanger and terminate control lines. Land out hanger on depth w/27k dn,34k up. Pick up 3'and prep to circulate., Displace Packer fluid(6%KCL w/3%corrosion inhibitor). Pump @ 3 bpm,375 psi,5%flow.,Service rig.,Rig up Pollard and displace 2 bbls diesel down IA. Had trouble with feed pump for test pump. Service feed pump and put back online. Drop ball and rod,R/U Pollard on tbg and attempt to set packer. Unable to land ball and rod w/pump truck. Line up rig pumps and land ball and rod after pumping 9 bbls. R/U and pump another 2 bbls down IA. Rig up and attempt to set packer. 12/6/2014 12/5/2014 Rig up test manifold on landing joint with test pump and 2"Mud pump Tee.Pressure up tubing to 1,000 psi with mud pump.Isolate mud pump and take over with Pollard test pump.Increase Pressure to 4,500 psi to set PKR. Hold and chart 4,500 psi on tubing for 30 minutes. Rig down test equipment from landing joint and rig up on IA with test manifold.Test 5-1/5"x 2-7/8"annulus to top of PKR to 2,000 psi chart for 30 Min.,Bleed off SSSV.Pull landing joint.Set BPV.Flush all surface equipment with corrosion inhibited water.,Nipple down stack.Remove all rams and prep ram cavities for storage. Blow down service lines and prep for rig move. Clean pits and remove tools from floor.,Install adapter flange and master valve as per Cameron. Load master w/diesel. • 11/29/2014 11/28/2014 Drill f/5,323'to 5,723'(400)A' 40 fph. 7-8K WOB,1,820 SPP,Diff 1C. RPM. 450 GPM,9.3 MW,ECD 10.42,PU 120K,SO 50K,Rot 68K,On Btm TQ 13.4K,Off Btm TQ 12.8K.;Pump tandem High vis sweeps with 100%increase with 1st and 50%increase in cuttings with 2nd sweep. Continue to circulate hole clean for wiper trip.;Pump up survey,obtain SPR's,Flow check well.Well static No losses to well. Pull wiper trip to 5,050'with no issues.PU 118K,SO 50k.;Flow check.Service Rig.;TIH from 5,100'.Wash last stand to bottom @ 5,723'.;Drill f/5,723'to 5,785"6-8K WOB,1,720 SPP,Diff 150,80 RPM 450 GPM,9.25 MW,ECD 10.3.;Repair shaker motors.;Drill f/5,723'to 6,157' (434')AROP=51 fph. 6-8K WOB,1,820 SPP,Diff 130,80 RPM. 450 GPM,9.25 MW,ECD 10.32,PU 128K,SO 54K,Rot 72K,On Btm TQ 13.4K,Off Btm TQ 14K.;810 bbls hauled to disposal,Paxton 9 total 3,865bb1s. 6,000'TVD 2,902'INC 39.9 AZI 5.04 1.1 Below&6 Left. 11/30/2014 11/29/2014 Drill f/6,157'to 6,220'(63')AROP=63 fph. 6-8K WOB,1,820 SPP,Diff 130,80 RPM. 450 GPM,9.25 MW,ECD 10.32,PU 128K,SO 54K,Rot 72K,On Btm TQ 13.4K,Off Btm TQ 14K.;Circulate Tandem Hi Vis Sweeps to Surface.Circulate hole clean.;Pull short wiper trip from 6,220'to 5,695'with no issues.;CBU at top of trip.250 GPM with 750 SPP.;TIH from 5,695'.Wash last stand to bottom with no issue.Circulate 1/2 bottoms up.;Drill f/6,220'to 6,530'(310')AROP=44 fph. 8-9K WOB,1,950 SPP,Diff 107,80 RPM. 450 GPM,9.25 MW,ECD 10.42,PU 157K,SO 58K,Rot 84K,On Btm TQ 15.5K,Off Btm TQ 14.8K.;Drill f/6,530'to 6,733'(203')AROP=58 fph. 8-9K WOB,1,950 SPP,Diff 107,80 RPM. 450 GPM,9.25 MW,ECD 10.42,PU 157K,SO 58K,Rot 70K,On Btm TQ 15.5K,Off Btm TQ 13.5K;Art 8.19 Ast 1.08 Tdt 9.27. Last survey @ 6,733'TVD 3,503'Inc.33.20 Azi 359.26 18.61 low and 22.88 to the left.;CBU for the loggers,FINAL SAMPLE ANALYSIS FROM 6,733 FT. TUFFACEOUS CLAYSTONE 70%. TUFFACEOUS SILSTONE 20%. SAND 10%.;Circulate Tandem Hi Vis Sweeps to Surface.Circulate hole clean.ECD start 10.38 end 10.32 MW 9.3.;TOH from 6,733'to 2,291'(shoe)monitor well.;Continue TOH until reach BHA rack back HWDP and Jars UD MWD/PWD&motor.;;450 bbls hauled to disposal,Paxton 9 total 4,315 bbls. 12/1/2014 11/30/2014 Continue to lay dowm Directional Tools.Down load MWD Data.Clear and organize rig floor.;M/U Bit and bits on HWDP.TIH with HWDP,jars and 50 stands DP to 3,700'.;CBU from 3,700',Flow Check Well,Pump slug,Drop Drill pipe wiper.;POOH laying down 4-1/2"Drill Pipe from 3,700'.;Flow check well,UD 15 jnts of 5"HWDP and Jars,Rack back 1 stnd of HWDP and retrieve the mud pipe wiper.;Flow check-TIH hole with 1 stnd of HWDP and 20 stands of 4-1/2"DP from the derrick.;Flow check well-UD 40 jnts of 4-1/2"DP,clean every thread.;TIH with remaining 32 stands from the derrick.;Flow check well-L/D 65 jnts of 4-1/2"DP,HWDP and bit sud,clean every thread.;Service Rig-Top Drive,Draw work,Check the oil in motors.;;0 bbls hauled to disposal,Paxton 9 total 4,315 bbls. 12/2/2014 12/1/2014 PJSM.Change the upper pipe rams from 2-7/8"X 5"variables to 5-1/2"fix-bore pipe rams.;Set test plug.R/U test equipment,flood BOPE.Test upper 5-1/2" rams per AOGCC 250/3,500psi 5 min R/D test equipment.Pull test plug.;Blow down standpipe kill line and mud pumps.;UD all Weatherford 5"handling equipment.slips,elevators,full opening TIW,Dart vavle.;Change over cds-40 saver sub to 41F due to Weatherford equipment configured the wrong way.;Rig up Weatherford CRT,service loop,elevators,air slips and set top drive TQ.;Make a dummy run with Cameron Rep. Mark landing Jnt.&Mesure RKB.;Make up shoe track&backer lock connection,check floats(Good)continue TIH w/5-1/2"casing every joint to 2,290'.;At the shoe circ.one casing vol.374 psi. MW 9.4.:Continue runnig 5-1/2"casing From 2,290'to 6,645'filling every jnt.break circ.every 500'.;Encounter tight hole @ 6,570' to 6,645'attempt to work through (no go)brought pumps up slowly to 2bpm @ 430psi and attempt through(no go)while washing we brought rot.on @ 5rpm and worked.;Tight spots.;Wash from 6,645'to 6,723'(no problems)@ 2bpm 450 psi.pick up jnt.171 washed to bottom @ 6,733'CBU pumping @ 2 bpm incresing rate slowly unil reaching 6bpm.;;450 bbls hauled to disposal,Paxton 9 total 4,765 bbls. 12/3/2014 12/2/2014 Continue to circulate and condition for cement job lowering MW to 9.3 and YP to 17.Lay down tag joint.MU and land casing hanger with 46K Dn Wt.Continue to circulate and condition.;Ran 5 1/2"17#P110 DWDC csg as follows: Float Shoe,2 Shoe Jts,Float Collar,6 Joints,Marker Joint,51 Joints,Marker Joint,112 Joints,Casng Hgr.;Centralizer place 10'above FS,10'above FC and one per jt to 4,700'&every other jt f/4,718'to 2,000'. 84 Total.;Tag bottom at 6,735'.Casing shoe landed at 6,726'.Top of FC at 6,643'.;Details:Washed csg ,`'y f/6,570'to 6,735'.Broke circulation every 500'of open hole.Losses 0 bph.;PJSM with BJ Hughes and R/U cementing equipment.;Perform cmt job as follows: (? ef. Drop btm plug,pump 5 bbls FW,load top plug. Pressure test lines to 3500 psi.Pump 40 bbls of spacer at 10 ppg.;Mix and pump 443 sxs(145 bbls)of class G r" Lead cement at 13.5 ppg. Mix and pump 451 sxs(93 bbls)of class G Tail cement at 15.7 ppg.;Drop top plug and displace cmt w/156 bbls of 8.6 ppg 6% KCL.Catch cement 30 bbls into displacement.;Bump plug with 500 psi over final circulating pressure. Bleed off pressure with 2 bbls back. Floats held.;Full returns through out job.Pump Cement @ 4 BPM Average.Pump Displacement @ 4.5 BPM Average.Calculated Displacement 154.5,Actual Displacement 156.;Final circulation pressure prior to bumping plug 1175 psi at 2 bpm.Cmt in place at 15:55 hrs.;Wash up and R/D BJ cement equipment.Flush stack and surface equipment.;Land and test Pack off. Test packoff T/5k(test good).;Rig down cementers and equipment. Laydown same from rig floor.;R/D Weatherford CRT,UD 5"tools and dress top drive.Changeout Weatherford power unit.Offload and stage 2 7/8"tbg(216 jts).;Changeout upper pipe rams T/2 7/8"x 5"VBR's. Test 250 low/3500 high. 5 min hold on both,chart and record same. R/D test equipment.;lnstall wear bushing.Clean pits,prepping for scraper run. Strap and tally 2 7/8"tubing(216 jts). Drift tubing w/2.347"drift. 12/4/2014 12/3/2014 See completions reports 12/5/2014 12/4/2014 12/6/2014 12/5/2014 12/7/2014 12/6/2014 Clean rig floor,UD and sort misc subs and equipment. R/D top drive,prep mast for scoping,winterize and R/D misc water and mud lines. Psi wash mast, Demob equipment on location,R/D total safety.;Continue Cleaning derrick,windwalls and rig floor. R/D and winterize pits and pump house. Blow down steam lines to pits and pump house. Winterize choke and prep for demob. R/D pason.;Continue sort and demob equipment on location. Rig released @ 06:00 12/6/2014. Hauled 90 bbls to G&I. Total for well-6655 bbls. 12/8/2014 12/7/2014 Derrick inspection,lower mast. Remove and secure lines on derrick. Remove windwalls,roofs and remove choke manifold. Re-install choke house and catwalk roof for shipping. Continue steam cleaning;Wait on Daylight. 12/9/2014 12/8/2014 Continue cleaning pits,pumps and prep for move. Crane ops-Remove pulsation dampeners,vibrator hose,flowline,sub doors,iron roughneck, stage BOP's,and cable tray.;Layover derrick,clean up location,clean radiators on mp motors and gens. Demob svc lines. Seperate pits,gas buster,cattle chute and stage @ SLB yard. Rig is 60%demob.;WOD. 12/10/2014 12/9/2014 Unspool drilling line,prep derrick and remove. Stage and clean same. Prep and move MP#1&#2 off Paxton T/stack location. Removed annular,clean and inspect same,prep for storage.;Rig down and clean#3 gen,stage on trailer to be moved. Rig down boiler and prep for move. Remove drawworks and prep for move. 12/11/2014 12/10/2014 Clean all and demob boiler#2,diesel tank,drawworks,clean gen houses,doghouse and mats. Load out mats and misc Saxon support equipment. Psi wash sub structure.;lnventory subs,mats,other Hilcorp equipment;Steam on Wheels psi wash sub and associated equipment. Prep for demob at first light. 90%demob.;Sym ops-E-line Paxton 8 12/12/2014 12/11/2014 Demob sub and pony sub from Paxton 8. Rig components are 100%demob. Clean and sort rig mats,send out remaing Saxon mats to stackout yard. Clean up location and ship misc loads.;Lay containment and mats @ stackout yard(SLB yard). Clean wellhead and prep for handover to production. E-line operations on Paxton 8.;Wait on daylight;Rig released @ 00:00 12/11/14 12/13/2014 12/12/2014 Rigged down and winterized Saxon living quarters,Peak break shack and MI office trailer. Demob same along with black water tanks and plumbing. Load out remaining hilcorp mats and send to CIFO.;Hilcorp mats demob(17)8'x40', (2)5'x40',(2)10'x20',(2)10'x10'.;Load misc subs into Connex#UOCD 4109 and secure. Load hot shack with Hilcorp low psi hoses and pallet lift. Demob to CIFO. Install and weld out working platform in cellar of Paxton#9.;Install production tree on Paxton#9. Sym Ops-SLB perforating on Paxton#8;Wait on daylight Hilcorp Energy Company Composite Report Well Name: NINU Paxton 9 Field: Ninilchik County/State: ,AK Location(LAT/LONG): Elevation(RKB): API#: 50-133-20647-00-00 Spud Date: Job Name: 1413466C Paxton 9 COMPLETION Contractor AFE#: 1413466C AFE$: Rpt Date Activity Date Ops Summary k' 12/4/2014 12/3/2014 Finish cleaning pits and tubing tally.,PJSM,make up scraper assy and TIH T/172'MD. Latch on elevators,failed and had to be replaced.,Wait on new elevators for 2-7/8"tubing to arrive. Continue cleaning non essential pits,flush mud lines and mixing KCL fluid.,Continue TIH w/scraper assy F/172'-T/ 6,733'MD. Tagged @ 6,633'MD,set dn 4k. 56k up,26k dn.,Circulate hole clean,pump 17 bbls vis sweep,displace w/6%KCL brine(8 NTU's). Pump @ 6 bpm,1,300 psi,12%flow out.,TON laying down tbg F/6,733'T/3,336'(107 jts total).,TON standing back tubing F/3,336'-T/surface(53 stds total). Laydown scraper assy as per BOT rep.,Service rig.,Rig up Pollard test equipment. Test 5-1/2"casing T/3,500 psi w/30 min hold. Chart and record same. 12/5/2014 12/4/2.014 Pulled wear bushing. Wear bushing,test joint,and retrieving tool shot out of hole due to trapped pressure of psi from 5.5"x 9.625"annulus. Incident investigation.,Safety stand down. Review incident and importance of understanding each task along with hazards.,Found that lockdown screws for 5.5" packoff had been backed out. Trapped psi from thermal expansion in 5.5"x 9.625"annulus forced packoff upward and caused the wear bushing retrieval assy to come out of hole. Redress packoff assy and re-install. Test packoff(test good).,R/U Weatherford casing and run 2.875"8rd EUE,6.4#tubing as per detail.,Make up control lines to SSSV and CIM. Make up hanger and terminate control lines. Land out hanger on depth w/27k dn,34k up. Pick up 3'and prep to circulate.,Displace Packer fluid(6%KCL w/3%corrosion inhibitor). Pump @ 3 bpm,375 psi,5%flow.,Service rig.,Rig up Pollard and displace 2 bbls diesel down IA. Had trouble with feed pump for test pump. Service feed pump and put back online. Drop ball and rod,R/U Pollard on tbg and attempt to set packer. Unable to land ball and rod w/pump truck. Line up rig pumps and land ball and rod after pumping 9 bbls. R/U and pump another 2 bbls down IA. Rig up and attempt to set packer. 12/6/2014 12/5/2014 Rig up test manifold on landing joint with test pump and 2"Mud pump Tee.Pressure up tubing to 1,000 psi with mud pump.Isolate mud pump and take over M• � with Pollard test pump.Increase Pressure to 4,500 psi to set PKR, Hold and chart 4,500 psi on tubing for 30 minutes. Rig down test equipment from landing joint and rig up on IA with test manifold.Test 5-1/5"x 2-7/8"annulus to top of PKR to 2,000 psi chart for 30 Min.,Bleed off SSSV.Pull landing joint.Set BPV. Flush all surface equipment with corrosion inhibited water.,Nipple down stack.Remove all rams and prep ram cavities for storage. Blow down service lines and prep for rig move. Clean pits and remove tools from floor.,Install adapter flange and master valve as per Cameron. Load master w/diesel. 12/14/2014 12/13/2014 PTW JSA. Mobe to location. Spot equip and rig up lubricator. PT 250 low and 3,500 psi high. Help with field to pump open SSSV.,RIH W/2"RB pulling tool &3 Roller boogies(2.25")10'of 1.5"stem to 1,440'WLM.Stop going down. Tried three times-POOH and change up tool string.,RIH W/2"RB pulling tool& 4 Roller boogies 10'of 1.75"stem to 1,440'WLM. Stop going down. Trived three times-POOH and change up tool string.,RIH W/5 roller boogies w/10'OF 1.75"stem w/RB to 1,860'WLM. Stopped falling. Tried several times but could not go deeper.,RIH W/5 roller boogies wl 15'OF 1.75 stem w/RB TO 1,860' WLM. Stopped falling Tried several times but could not go deeper.,RIH w/2"DD bailer and roller boogies to 1507'.Would not fall.POOH.,Rig down lubricator. 12/17/2014 12/16/2014 Obtain PTW. Hold safety meeting.,RIG up SLB 1.5in CTU. BOP and x overs on well. Flow back rigged up tanks spotted.,BOP test all valves and rams 250 psi low/4,500 psi high. Notification to state sent 12-15-14 @ 1140PM. Witness waived by Jim Regg on 12-16-14 @ 0904 AM.,Secure location. Crews off location 1700. 12/18/2014 12/17/2014 Obtain PTW. Hold safety meeting with crews.,Pick injector head,10ft lub x 2.5 ft lub,3 ft lubricator. Install IBL coil connector,pull test 20k. Make up MHA 1- 11/16"CC,DF check valve, Hyd disconnect,Circ sub,and 2.5in GS spear baited with 1.81"GS fishing box with Gutted JDC Slick line tool below it. Head to well. Pressure test lubricator 250 low 4,500 high.,Open well,WHP 0 psi. RIH Tag top of ball and rod at 3,419'CTMD. Set down 1500 lbs. POOH. At surface,fish recovered.,Pop off well, Run down on coil. Break down ball rod. Zero at lubricator. Headed back to well. Screw on lubricator. Pressure test lubricator. Open well RIH for 2nd fish run of the RHCP.,RIH,stop at 3,400 ft perform weight check. Up wt 3,800 lbs. RIH wt-2,300 lbs. RIH tag top of RHCP with 2.5in GS spear at 3,427'CTMD. Stack 3k on fish. POOH no increase in weight seen. Run back in on top of fish. Stack 5k on fish. Pick up hole. No weight seen.,POOH to check for RHCP. At surface,fish recovedred. Release fish from tool string. Break down 2.5in GS spear. Install x over and nozzle. Tag at stripper. RIH 33.36 ft(CBL and memory tool string length). Measure length of tools and coil sticking out lubricator. 8.3 ft. Stab back on well. PT lubricator.,RIH for CBUMemory drift run to PBTD. Tag Bottom at 6,587ft CTMD, RKB correction puts cement at 6,600 ft coil depth. Pick up 5 ft. Run back in to verify tag. Same spot 6,587 ft CTMD.Pick up 2 ft off bottom. Flag coil. Current flag is simulated correct depth for CBUmemory log run. Mechanical counter on reel reads 6,606 ft.at PBTD tag. Flag painted on pipe at 6,585 ft CTMD.,POOH,at surface 1900 hrs. Swab master closed, Stacking down lubricator,Secure BOPS with night cap. All ground valves closed, Shutting down equipment. Notified production operator to assist in sucking down fluid in open top tank from pipe displacement. Crew on standby in morning to await word on when tools from slope will arrive. Estimated to land at 1030 am. Crews will head to location when confirmed arrival of tools to pick up injector head and lubricator. 12/20/2014 12/19/2014 Obtain PTW. Hold safety meeting with crews. Discuss Procedure for rigging up Memory logging tools.,Pick injector head,28ft of lubricator. RIH and make up l� Memory logging tools. Tools consist of PBMS,SCMS,SECH with associated centralizers.Audible confirmation that tool was working. Stab on well. Pressure test lubricator 250 low 4500 high pt. Open master and swab valve.,RIH with logging tools. Rig up N2 unit and return tank which was previously used the previous day on pax 8. ON bottom waiting for tool temperatures to stabalize prior to logging.,Start logging up hole at 30 ft a minute. CTMD 6589.8 at flag from previous drift run. Stopped logging inside tubing tail at 3105. Wait 5 minutes.,RIH 80 ft/min to 4000 ft.,Logging up from 4000 ft CTMD to 3105 at 30 ft/min.,Tagged up at surface. Master swab closed.,Stacking down injector head. Memory hand downloading log. Confirmation good data on log. Location secure. Crews leave location. 12/21/2014 12/20/2014 SLB wire line arrive location. Obtain PTW. Hold safety meeting.,Equipment spotted. Rigging up wire line. Making up SLB MaxTrac RST tools. Tool Length A-01 is 66.41 ft. OD is 2.125.,RIH, Turn tractor on at 1300 ft. Tools would not fall down hole. Had to run tractor from 1300 ft to PB I D. Found plug back TD at 6614 uncorrected wire line depth.,At depth on Bottom. Log 300 ft up hole. Run back to Bottom. Adjusting tools. Small issue with tractor arms not closing. Reboot computers a few times and reset and recalibrate tools. Everything looked good at 1900 hrs.,Logging out of hole at 30 ft/min from 6614 to 3100 ft at the tubing tail. Pooh to surface. Logging complete good data.,Rigging Donw SLB. Leaving location 22:30. Well secure. SLB will upload corrected log to server. 12/22/2014 12/21/2014 Obtain PTW. Hold safety meeting.,Fire equipment, Plck injector head,stab 10 ft lubricator. Make up 1.75 in DF check vavles,2 1.75 in straight bars and Ball drop nozzle. Stab on well. Pressure test lubricator to 250 psi low and 4500 psi high for 5 minutes each.,Open well. RIH @ 90 ft//min. Periodic weight checks. Cooling down n2 at 2500 ft. Tag Bottom at 6589 CTMD.,Online with n2 at 500 scf/min. Increase n2 rate to 1500 scf/min. Returns to surface at 13:30. Continue to blow well dry. Expected volume from n2 lift is 77 bbls. Previous run returned 15 bbls from coil displacement alone. for a total expected volume of 92 bbls. Nitrogen to surface. Only n2 at surface. Star POOH.,In tubing tail. No signs of fluid down on n2.continue to POOH to surface. 1300 psi on wellhead. At surface.,Bleeding down coil and wellhead to 450 psi. well shut in with 450 psi. Bleeding down coil to open top tank.,Rigging down CTU 12. Wellhead secured. Crews off location. SLB crew will arrive following day to Demobilize equipment to SLB yard. Total n2 pumped for job 195,552 scf. or 2100 gallons. Total BBLS recoverd from n2 lift 75 bbls+previous run of 15=90 bbls. 1/14/2015 1/13/2015 PTW and JSA.Spot equipment and rig up lubricator.PT to 250 psi low and 3,500 psi high.Arm gun.,RIH w/2"x 12'HC Nova,6 spf,60 deg phase on tractors and tie into Halliburton CBL dated 19-Dec-14. tun correlation log and send to town.Get ok to perforate.Spot shot from 4,790'to 4,802'per Nasse/Allen.TP- 300 psi.,Fired gun and tubing pressure went to 386 psi in 20 min.Still building.Begin to POOH and tool string stuck at 3,408'.Tractor back down and make another attempt to POOH.Tool still catching at same location.Make a couple more attempts before decision is made to SDFN. 1, 'I 1 /2015 1/14/2015 Continue working stuck tools pert gun and tractor assembly. No progress past X-nipple[rd '. Able to tractor down with no issues,no progress moving past X-nipple. Decisi, dump methanol w/hot oil truck to remove possible pert debris., .on hot oil truck w/tension on stuck tools.,RU Pollard Hot Oil truck. PT lines to 1,500 psi and pump 5.3 bbls methanol down well @ 4 BPM. RD Pollard.,RIH w/tractor to 3,650'and POOH @ 12,000 FPH,stuck at �, same spot in X-nipple(-3,450'). RIH w/tractor to 3,650'and POOH @ varying speeds up to 12,000 FPH,stuck same. Decision to bring well on and clean up tools in pert interval.,RIH w/tractor to pert interval(4,790'-4,802'),begin venting N2.,Monitor well and continue flowing well to system,300 psi @ 300 MCFD with tools in pert interal. Pull above perfs,secure well,and flow overnight.,Shut down for night. 1/16/2015' 1/15/2015 Shut down for night.,Held PJSM and obtained permit.,POOH w/tractor and spent guns from pert interval @ 12,000 FPH. Tag obstruction @ 3,450'WLM. L WT and no progress. Tractor in hole to 3,650'and POOH at varying speeds,tag same. Tractor in hole to 3,650'.,WO decision to leave tools in hole.,POOH ( S and tag obstruction @ 3,450'WLM. Pull 2,300#and pulled out of rope socket. POOH w/wireline. Left in hole'rooe socket(1.19"x 1.02"fish neck),CCL, 27.5'x 2.125"tractor,GR,shock sub,and 25.5'of 2"spent HC pelf guns+firing head. Total length:73'. Estimated TOF:3,408'WLM.,LD lubricator and secure well. Well continues to flow @ 325 psi and 300 MCFD. RD Schlumberger. lit 00 Hilcorp Energy Company Ninilchik Unit Paxton Paxton #9 50-133-20647-00-00 50-133-20647-00-00 Sperry Drilling Definitive Survey Report 15 December, 2014 0014 HALL.IBURTON Sperry Drilling fir Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well Paxton#9 Project: Ninilchik Unit TVD Reference: Paxton#9(148.5+18.5)@ 167.00usft Site: Paxton MD Reference: Paxton#9(148.5+18.5)@ 167.00usft Well: Paxton#9 North Reference: True Wellbore: Paxton#9 Survey Calculation Method: Minimum Curvature• Design: Paxton#9 Database: Sperry EDM-NORTH US+CANADA Project Ninilchik Unit Map System: US State Plane 1927(Exact solution)• System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 • Using geodetic scale factor Well7 " 1�(i ! Paxton#9 Well Position +N/-S 0.00 usft Northing: 2,230,441.15 usft . Latitude: 60.09559681°N +E/-W 0.00 usft Easting: 206,265.74 usft , Longitude: -151.60933637 Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: _ 148.50 usft Wellbore Paxton#9 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2013 11/15/2014 16.51 73.11 55,196 Design Paxton#9 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 18.50 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 18.50 0.00 0.00 0.00 Survey Program Date 12/15/2014 From To (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 162.58 2,259.87 Paxton 9 MWD+SC+Sag(Paxton#9) MWD+SC+sag Fixed:v2:standard dec&axial correction+sag 11/17/2014 2,317.34 6,700.24 Paxton 9 MWD+SC+Sag(Paxton#9) MWD+SC+sag Fixed:v2:standard dec&axial correction+sag 11/17/2014 Survey - -- -- - - Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) 0100') (ft) Survey Tool Name 18.50 0.00 0.00 18.50 -148.50 0.00 0.00 2,230,441.15 206,265.74 0.00 0.00 UNDEFINED 162.58 3.74 309.93 162.48 -4.52 3.02 -3.60 2,230,444.25 206,262.21 2.60 3.02 MWD+SC+sag(1) 225.52 5.79 316.11 225.20 58.20 6.62 -7.38 2,230,447.95 206,258.52 3.35 6.62 MWD+SC+sag(1) 284.97 8.53 318.75 284.18 117.18 12.10 -12.37 2,230,453.55 206,253.67 4.64 12.10 MWD+SC+sag(1) 347.58 9.29 318.63 346.03 179.03 19.38 -18.77 2,230,460.99 206,247.45 1.21 19.38 MWD+SC+sag(1) 376.51 9.33 317.84 374.58 207.58 22.87 -21.89 2,230,464.55 206,244.42 0.46 22.87 MWD+SC+sag(1) 433.98 9.53 324.52 431.28 264.28 30.20 -27.77 2,230,472.02 206,238.71 1.93 30.20 MWD+SC+sag(1) 493.38 11.20 333.77 489.71 322.71 39.38 -33.18 2,230,481.33 206,233.53 3.96 39.38 MWD+SC+sag(1) 546.28 11.93 335.62 541.53 374.53 48.97 -37.71 2,230,491.02 206,229.24 1.55 48.97 MWD+SC+sag(1) 617.45 15.48 339.82 610.67 443.67 64.59 -44.02 2,230,506.79 206,223.30 5.18 64.59 MWD+SC+sag(1) 648.12 17.23 340.70 640.10 473.10 72.72 -46.94 2,230,514.99 206,220.59 5.76 72.72 MWD+SC+sag(1) 678.80 19.62 341.68 669.20 502.20 81.90 -50.06 2,230,524.24 206,217.69 7.85 81.90 MWD+SC+sag(1) 711.63 22.67 343.08 699.82 532.82 93.19 -53.63 2,230,535.62 206,214.39 9.42 93.19 MWD+SC+sag(1) 12/15/2014 6:16:54PM Page 2 COMPASS 5000.1 Build 70 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well Paxton#9 Project: Ninilchik Unit TVD Reference: Paxton#9(148.5+18.5)@ 167.00usft Site: Paxton MD Reference: Paxton#9(148.5+18.5)@ 167.00usft Well: Paxton#9 North Reference: True Wellbore: Paxton#9 Survey Calculation Method: Minimum Curvature Design: Paxton#9 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 741.57 24.80 344.48 727.22 560.22 104.76 -56.99 2,230,547.27 206,211.32 7.36 104.76 MWD+SC+sag(1) 772.47 26.37 345.55 755.09 588.09 117.65 -60.44 2,230,560.24 206,208.18 5.30 117.65 MWD+SC+sag(1) 805.23 28.64 347.06 784.15 617.15 132.35 -64.01 2,230,575.02 206,204.97 7.25 132.35 MWD+SC+sag(1) 837.31 30.89 348.55 812.00 645.00 147.92 -67.37 2,230,590.66 206,201.99 7.38 147.92 MWD+SC+sag(1) 868.43 33.39 350.24 838.35 671.35 164.19 -70.41 2,230,607.00 206,199.35 8.54 164.19 MWD+SC+sag(1) 899.30 36.15 351.46 863.70 696.70 181.57 -73.20 2,230,624.44 206,196.98 9.22 181.57 MWD+SC+sag(1) 931.40 38.10 353.03 889.29 722.29 200.76 -75.81 2,230,643.70 206,194.84 6.75 200.76 MWD+SC+sag(1) 962.17 40.35 354.06 913.13 746.13 220.09 -77.99 2,230,663.08 206,193.13 7.61 220.09 MWD+SC+sag(1) 994.76 43.23 355.51 937.43 770.43 241.72 -79.96 2,230,684.75 206,191.69 9.32 241.72 MWD+SC+sag(1) 1,024.36 45.59 356.18 958.57 791.57 262.38 -81.45 2,230,705.43 206,190.70 8.13 262.38 MWD+SC+sag(1) 1,056.85 47.87 356.90 980.84 813.84 285.99 -82.88 2,230,729.07 206,189.85 7.20 285.99 MWD+SC+sag(1) 1,088.16 49.55 358.36 1,001.50 834.50 309.49 -83.85 2,230,752.59 206,189.45 6.41 309.49 MWD+SC+sag(1) 1,119.47 51.48 359.55 1,021.41 854.41 333.65 -84.29 2,230,776.76 206,189.60 6.83 333.65 MWD+SC+sag(1) 1,153.39 53.83 0.64 1,041.98 874.98 360.62 -84.24 2,230,803.71 206,190.31 7.38 360.62 MWD+SC+sag(1) 1,182.64 56.11 0.96 1,058.77 891.77 384.56 -83.90 2,230,827.64 206,191.23 7.85 384.56 MWD+SC+sag(1) 1,214.76 58.85 0.77 1,076.04 909.04 411.64 -83.49 2,230,854.70 206,192.29 8.55 411.64 MWD+SC+sag(1) 1,246.13 61.10 0.97 1,091.73 924.73 438.80 -83.08 2,230,881.84 206,193.37 7.19 438.80 MWD+SC+sag(1) 1,280.33 63.88 1.12 1,107.53 940.53 469.12 -82.53 2,230,912.14 206,194.66 8.14 469.12 MWD+SC+sag(1) 1,309.26 66.50 0.72 1,119.67 952.67 495.38 -82.11 2,230,938.38 206,195.72 9.14 495.38 MWD+SC+sag(1) 1,341.59 69.25 0.92 1,131.84 964.84 525.32 -81.68 2,230,968.30 206,196.88 8.53 525.32 MWD+SC+sag(1) 1,372.03 70.33 1.37 1,142.36 975.36 553.88 -81.11 2,230,996.84 206,198.14 3.81 553.88 MWD+SC+sag(1) 1,405.02 71.71 1.48 1,153.09 986.09 585.07 -80.33 2,231,028.00 206,199.68 4.19 585.07 MWD+SC+sag(1) 1,436.23 74.09 0.80 1,162.26 995.26 614.89 -79.74 2,231,057.80 206,201.00 7.90 614.89 MWD+SC+sag(1) 1,469.63 74.46 0.38 1,171.32 1,004.32 647.04 -79.41 2,231,089.93 206,202.11 1.64 647.04 MWD+SC+sag(1) 1,499.02 74.86 0.50 1,179.09 1,012.09 675.38 -79.19 2,231,118.25 206,203.02 1.42 675.38 MWD+SC+sag(1) 1,563.64 72.35 0.01 1,197.33 1,030.33 737.36 -78.91 2,231,180.22 206,204.81 3.95 737.36 MWD+SC+sag(1) 1,629.57 72.62 359.50 1,217.17 1,050.17 800.24 -79.18 2,231,243.08 206,206.07 0.84 800.24 MWD+SC+sag(1) 1,689.94 73.09 0.11 1,234.97 1,067.97 857.92 -79.38 2,231,300.75 206,207.28 1.24 857.92 MWD+SC+sag(1) 1,752.41 73.58 0.22 1,252.88 1,085.88 917.77 -79.20 2,231,360.57 206,208.91 0.80 917.77 MWD+SC+sag(1) 1,815.86 75.46 359.65 1,269.82 1,102.82 978.91 -79.27 2,231,421.70 206,210.32 3.09 978.91 MWD+SC+sag(1) 1,877.42 75.76 358.25 1,285.12 1,118.12 1,038.53 -80.37 2,231,481.33 206,210.68 2.26 1,038.53 MWD+SC+sag(1) 1,943.06 75.16 357.73 1,301.60 1,134.60 1,102.03 -82.60 2,231,544.86 206,210.00 1.19 1,102.03 MWD+SC+sag(1) 2,005.23 73.62 356.84 1,318.33 1,151.33 1,161.84 -85.43 2,231,604.72 206,208.62 2.83 1,161.84 MWD+SC+sag(1) 2,068.57 72.75 356.70 1,336.65 1,169.65 1,222.37 -88.85 2,231,665.32 206,206.68 1.39 1,222.37 MWD+SC+sag(1) 2,132.19 73.73 356.09 1,354.99 1,187.99 1,283.17 -92.68 2,231,726.19 206,204.33 1.79 1,283.17 MWD+SC+sag(1) 2,195.82 73.05 356.17 1,373.18 1,206.18 1,344.00 -96.79 2,231,787.11 206,201.70 1.08 1,344.00 MWD+SC+sag(1) 2,259.87 72.80 356.24 1,391.99 1,224.99 1,405.10 -100.85 2,231,848.28 206,199.14 0.40 1,405.10 MWD+SC+sag(1) 2,317.34 72.31 356.88 1,409.22 1,242.22 1,459.82 -104.14 2,231,903.07 206,197.18 1.36 1,459.82 MWD+SC+sag(2) 2,344.31 72.36 356.87 1,417.40 1,250.40 1,485.48 -105.54 2,231,928.76 206,196.40 0.19 1,485.48 MWD+SC+sag(2) 2,405.29 72.89 356.17 1,435.61 1,268.61 1,543.57 -109.07 2,231,986.92 206,194.29 1.40 1,543.57 MWD+SC+sag(2) 12/15/2014 6:16:54PM Page 3 COMPASS 5000.1 Build 70 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well Paxton#9 Project: Ninilchik Unit TVD Reference: Paxton#9(148.5+18.5)@ 167.00usft Site: Paxton MD Reference: Paxton#9(148.5+18.5)@ 167.00usft Well: Paxton#9 North Reference: True 1 Wellbore: Paxton#9 Survey Calculation Method: Minimum Curvature Design: Paxton#9 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (0) (0) (usft) (usft) (usft) (usft) (ft) (ft) (0/100') (ft) Survey Tool Name 2,466.94 72.74 357.35 1,453.83 1,286.83 1,602.37 -112.40 2,232,045.78 206,192.39 1.84 1,602.37 MWD+SC+sag(2) 2,528.59 74.09 358.54 1,471.43 1,304.43 1,661.42 -114.52 2232,104.86 206,191.71 2.87 1,661.42 MWD+SC+sag(2) 2,590.99 74.32 358.13 1,488.41 1,321.41 1,721.44 -116.26 2,232,164.90 206,191.43 0.73 1,721.44 MWD+SC+sag(2) 2,650.91 73.72 359.43 1,504.91 1,337.91 1,779.03 -117.49 2,232,222.51 206,191.60 2.31 1,779.03 MWD+SC+sag(2) 2,716.47 73.78 359.17 1,523.25 1,356.25 1,841.96 -118.26 2,232,285.44 206,192.37 0.39 1,841.96 MWD+SC+sag(2) 2,777.58 74.23 358.74 1,540.09 1,373.09 1,900.70 -119.33 2,232,344.19 206,192.73 1.00 1,900.70 MWD+SC+sag(2) 2,839.27 73.13 358.51 1,557.43 1,390.43 1,959.88 -120.75 2,232,403.39 206,192.75 1.82 1,959.88 MWD+SC+sag(2) 2,900.86 73.50 358.37 1,575.11 1,408.11 2,018.86 -122.35 2,232,462.39 206,192.58 0.64 2,018.86 MWD+SC+sag(2) 2,963.62 73.91 358.04 1,592.72 1,425.72 2,079.07 -124.24 2,232,522.62 206,192.16 0.83 2,079.07 MWD+SC+sag(2) 3,025.74 72.92 358.63 1,610.45 1,443.45 2,138.58 -125.97 2,232,582.16 206,191.88 1.84 2,138.58 MWD+SC+sag(2) 3,087.56 72.99 358.28 1,628.57 1,461.57 2,197.66 -127.57 2,232,641.26 206,191.72 0.55 2,197.66 MWD+SC+sag(2) 3,150.45 72.69 359.12 1,647.13 1,480.13 2,257.73 -128.93 2,232,701.35 206,191.82 1.36 2,257.73 MWD+SC+sag(2) 3,212.07 72.07 358.66 1,665.78 1,498.78 2,316.45 -130.07 2,232,760.08 206,192.11 1.23 2,316.45 MWD+SC+sag(2) 3,274.25 71.38 359.41 1,685.28 1,518.28 2,375.49 -131.06 2,232,819.12 206,192.56 1.59 2,375.49 MWD+SC+sag(2) 3,335.36 71.74 359.64 1,704.61 1,537.61 2,433.46 -131.54 2,232,877.08 206,193.49 0.69 2,433.46 MWD+SC+sag(2) 3,397.18 72.76 0.56 1,723.45 1,556.45 2,492.33 -131.44 2,232,935.94 206,195.03 2.18 2,492.33 MWD+SC+sag(2) 3,459.18 73.33 0.38 1,741.53 1,574.53 2,551.64 -130.95 2,232,995.21 206,196.96 0.96 2,551.64 MWD+SC+sag(2) 3,521.46 74.36 359.97 1,758.86 1,591.86 2,611.45 -130.77 2,233,055.01 206,198.59 1.77 2,611.45 MWD+SC+sag(2) 3,583.24 74.48 0.01 1,775.46 1,608.46 2,670.96 -130.78 2,233,114.50 206,200.03 0.20 2,670.96 MWD+SC+sag(2) 3,638.55 74.49 0.09 1,790.25 1,623.25 2,724.26 -130.73 2,233,167.78 206,201.38 0.14 2,724.26 MWD+SC+sag(2) I 3,707.59 73.86 359.52 1,809.08 1,642.08 2,790.68 -130.96 2,233,234.19 206,202.77 1.21 2,790.68 MWD+SC+sag(2) 3,769.94 73.09 359.53 1,826.81 1,659.81 2,850.45 -131.45 2,233,293.95 206,203.73 1.24 2,850.45 MWD+SC+sag(2) 3,831.49 73.00 359.04 1,844.76 1,677.76 2,909.32 -132.19 2,233,352.82 206,204.43 0.78 2,909.32 MWD+SC+sag(2) 3,893.80 73.15 358.46 1,862.90 1,695.90 2,968.92 -133.49 2,233,412.43 206,204.58 0.92 2,968.92 MWD+SC+sag(2) 3,955.49 73.33 358.01 1,880.69 1,713.69 3,027.96 -135.31 2,233,471.50 206,204.20 0.76 3,027.96 MWD+SC+sag(2) 4,017.60 73.01 358.10 1,898.67 1,731.67 3,087.38 -137.33 2,233,530.95 206,203.63 0.53 3,087.38 MWD+SC+sag(2) 4,079.67 73.40 357.72 1,916.61 1,749.61 3,146.76 -139.49 2,233,590.37 206,202.91 0.86 3,146.76 MWD+SC+sag(2) 4,142.28 72.70 357.57 1,934.86 1,767.86 3,206.60 -141.95 2,233,650.25 206,201.90 1.14 3,206.60 MWD+SC+sag(2) 4,203.81 73.02 357.38 1,953.00 1,786.00 3,265.34 -144.55 2,233,709.03 206,200.74 0.60 3,265.34 MWD+SC+sag(2) 4,265.81 71.97 358.29 1,971.64 1,804.64 3,324.42 -146.78 2,233,768.16 206,199.95 2.20 3,324.42 MWD+SC+sag(2) 4,327.14 69.43 0.11 1,991.91 1,824.91 3,382.29 -147.60 2,233,826.03 206,200.54 5.00 3,382.29 MWD+SC+sag(2) 4,389.45 67.84 1.48 2,014.61 1,847.61 3,440.31 -146.79 2,233,884.01 206,202.76 3.27 3,440.31 MWD+SC+sag(2) 4,451.90 66.98 1.94 2,038.60 1,871.60 3,497.94 -145.07 2,233,941.58 206,205.88 1.54 3,497.94 MWD+SC+sag(2) 4,509.16 65.75 3.81 2,061.56 1,894.56 3,550.33 -142.45 2,233,993.89 206,209.78 3.68 3,550.33 MWD+SC+sag(2) 4,573.06 65.15 5.02 2,088.11 1,921.11 3,608.28 -137.97 2,234,051.71 206,215.66 1.96 3,608.28 MWD+SC+sag(2) 4,635.02 64.80 5.05 2,114.32 1,947.32 3,664.21 -133.05 2,234,107.50 206,221.95 0.57 3,664.21 MWD+SC+sag(2) 4,697.72 65.02 4.63 2,140.91 1,973.91 3,720.79 -128.26 2,234,163.95 206,228.12 0.70 3,720.79 MWD+SC+sag(2) 4,759.59 63.98 4.88 2,167.54 2,000.54 3,776.44 -123.63 2,234,219.47 206,234.10 1.72 3,776.44 MWD+SC+sag(2) 4,821.45 64.11 4.76 2,194.62 2,027.62 3,831.86 -118.95 2,234,274.77 206,240.12 0.27 3,831.86 MWD+SC+sag(2) 4,883.38 63.61 4.90 2,221.90 2,054.90 3,887.26 -114.27 2,234,330.03 206,246.15 0.83 3,887.26 MWD+SC+sag(2) 12/15/2014 6:16:54PM Page 4 COMPASS 5000.1 Build 70 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well Paxton#9 Project: Ninilchik Unit TVD Reference: Paxton#9(148.5+18.5)@ 167.00usft Site: Paxton MD Reference: Paxton#9(148.5+18.5)@ 167.00usft Well: Paxton#9 North Reference: True Wellbore: Paxton#9 Survey Calculation Method: Minimum Curvature Design: Paxton#9 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +E/-W Northing Easting DLS Section ' (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 4,945.30 62.66 5.57 2,249.88 2,082.88 3,942.27 -109.24 2,234,384.90 206,252.53 1.81 3,942.27 MWD+SC+sag(2) 5,007.69 61.41 6.12 2,279.14 2,112.14 3,997.08 -103.63 2,234,439.56 206,259.47 2.15 3,997.08 MWD+SC+sag(2) 5,069.50 60.41 5.25 2,309.19 2,142.19 4,050.83 -98.27 2,234,493.16 206,266.13 2.03 4,050.83 MWD+SC+sag(2) 5,131.56 59.00 3.90 2,340.50 2,173.50 4,104.24 -93.99 2,234,546.46 206,271.71 2.95 4,104.24 MWD+SC+sag(2) 5,193.72 57.49 4.54 2,373.21 2,206.21 4,156.95 -90.11 2,234,599.05 206,276.87 2.58 4,156.95 MWD+SC+sag(2) 5,256.06 56.59 4.87 2,407.13 2,240.13 4,209.08 -85.82 2,234,651.06 206,282.43 1.51 4,209.08 MWD+SC+sag(2) 5,317.66 54.75 4.60 2,441.87 2,274.87 4,259.77 -81.62 2,234,701.64 206,287.87 3.01 4,259.77 MWD+SC+sag(2) 5,380.42 53.36 4.94 2,478.70 2,311.70 4,310.41 -77.39 2,234,752.15 206,293.32 2.26 4,310.41 MWD+SC+sag(2) 5,442.60 52.58 4.95 2,516.15 2,349.15 4,359.86 -73.12 2,234,801.49 206,298.80 1.25 4,359.86 MWD+SC+sag(2) 5,504.08 51.45 5.44 2,553.99 2,386.99 4,408.12 -68.73 2,234,849.63 206,304.36 1.94 4,408.12 MWD+SC+sag(2) 5,565.74 49.64 5.80 2,593.17 2,426.17 4,455.50 -64.07 2,234,896.88 206,310.17 2.97 4,455.50 MWD+SC+sag(2) 5,627.70 48.07 4.65 2,633.94 2,466.94 4,501.96 -59.81 2,234,943.22 206,315.56 2.89 4,501.96 MWD+SC+sag(2) 5,685.98 46.61 3.53 2,673.43 2,506.43 4,544.70 -56.75 2,234,985.88 206,319.66 2.88 4,544.70 MWD+SC+sag(2) 5,751.74 44.97 3.60 2,719.28 2,552.28 4,591.75 -53.82 2,235,032.84 206,323.74 2.50 4,591.75 MWD+SC+sag(2) 5,813.95 43.70 3.79 2,763.78 2,596.78 4,635.13 -51.02 2,235,076.14 206,327.59 2.05 4,635.13 MWD+SC+sag(2) 5,875.73 42.68 4.91 2,808.82 2,641.82 4,677.29 -47.82 2,235,118.21 206,331.82 2.07 4,677.29 MWD+SC+sag(2) 5,937.76 41.40 5.70 2,854.89 2,687.89 4,718.65 -43.98 2,235,159.46 206,336.66 2.23 4,718.65 MWD+SC+sag(2) 6,000.31 39.90 5.04 2,902.35 2,735.35 4,759.22 -40.16 2,235,199.93 206,341.47 2.49 4,759.22 MWD+SC+sag(2) 6,061.95 38.34 4.45 2,950.17 2,783.17 4,797.97 -36.94 2,235,238.59 206,345.63 2.60 4,797.97 MWD+SC+sag(2) 6,125.70 36.75 4.82 3,000.71 2,833.71 4,836.69 -33.81 2,235,277.22 206,349.71 2.52 4,836.69 MWD+SC+sag(2) 6,184.70 35.87 5.08 3,048.25 2,881.25 4,871.50 -30.79 2,235,311.95 206,353.57 1.51 4,871.50 MWD+SC+sag(2) 6,247.32 34.64 4.95 3,099.39 2,932.39 4,907.51 -27.63 2,235,347.86 206,357.60 1.97 4,907.51 MWD+SC+sag(2) 6,309.38 34.47 3.87 3,150.50 2,983.50 4,942.60 -24.93 2,235,382.88 206,361.17 1.02 4,942.60 MWD+SC+sag(2) 6,371.16 34.19 3.15 3,201.52 3,034.52 4,977.38 -22.79 2,235,417.60 206,364.15 0.80 4,977.38 MWD+SC+sag(2) 6,434.51 33.82 1.99 3,25403 3,087.03 5,012.77 -21.20 2,235,452.94 206,366.60 1.18 5,012.77 MWD+SC+sag(2) 6,497.21 33.53 1.36 3,306.21 3,139.21 5,047.52 -20.19 2,235,487.65 206,368.46 0.72 5,047.52 MWD+SC+sag(2) 6,559.02 33.59 0.82 3,357.72 3,190.72 5,081.68 -19.54 2,235,521.79 206,369.94 0.49 5,081.68 MWD+SC+sag(2) 6,619.59 33.48 0.06 3,408.21 3,241.21 5,115.14 -19.28 2,235,555.24 206,371.01 0.72 5,115.14 MWD+SC+sag(2) 6,681.70 33.28 359.43 3,460.07 3,293.07 5,149.31 -19.43 2,235,589.40 206,371.69 0.64 5,149.31 MWD+SC+sag(2) 6,700.24 33.20 359.26 3,475.58 3,308.58 5,159.47 -19.55 2,235,599.56 206,371.82 0.66 5,159.47 MWD+SC+sag(2) 6,733.00 33.20 359.26 3,502.99 , 3,335.99 5,177.41 -19.78 2,235,617.50 206,372.03 0.00 5,177.41 PROJECTED to TD Checked By: Patrick Walker��, �°mApproved By: Car Taylor .4..'":7»-`o..,.` =` Date: 12/15/2014 6.16:54PM Page 5 COMPASS 5000.1 Build 70 ,/e -r V Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. Ninilchik,Paxton#9 Date 21-Nov-14 County South Kenai State Alaska Supv. D.Yessak/L.Toussant CASING RECORD i TD 2300.00 Shoe Depth: 2291.19 PBTD: 2203.75 �4&G Casing(Or Liner)Detail Setting Depths No.of Jts. Size Wt. Grade THD Make Length Bottom Top (..�"Sr shoe 9 5/8 BTC Weatherford 1.88 2,291.19 2,289.31 v 2 jts 9 5/8 40 1-80 BTC 84.06 2,289.31 2,205.25 Float collar 9 5/8 BTC Weatherford 1.50 2,205.25 2,203.75 52 jts 9 5/8 40 1-80 BTC 2,178.79 2,203.75 24.96 1 pup jt 9 5/8 40 L-80 BTC 2.00 24.96 22.96 Hanger 16 3/4 x 11 1-80 BTC Sea board 0.45 22.96 22.51 RKB 22.51 22.51 0.00 0.00 0.00 0.00 0.00 0.00 Totals Csg Wt.On Hook: 80,000 Type Float Collar: Weatherford#303 No.Hrs to Run: 6 hrs Csg Wt.On Slips: 60,000 Type of Shoe: Weatherford#402 Casing Crew: Weatherford Fluid Description: 9.6 ppg Spud mud Liner hanger Info(Make/Model): Liner top Packer?: _Yes_No Liner hanger test pressure: Centralizer Placement: 80'spacing,26 ran,top centralizer on jt#47 at 317 ft. CEMENTING REPORT Preflush(Spacer) Type: Seal bond Density(ppg) 10 Volume pumped(BBLs) 40 Lead Slurry 1,, Type: Type 1 Density(ppg) 12.5 Volume pumped(BBLs) 139 Mixing/Pumping Rate(bpm): 4 Tail Slurry Type: Type 1 Density(ppg) 15.2 Volume pumped(BBLs) 65 Mixing/Pumping Rate(bpm): 4 N Post Flush(Spacer) N Type: Density(ppg) Rate(bpm): Volume: LL Displacement: Type: Drilling mud Density(ppg) 9.4 Rate(bpm): 4 Volume(actual/calculated): 167/172.5 FCP(psi): 492 Pump used for disp: Rig pump X Plug Bumped? _Yes x No Bump press Casing Rotated? Yes X No Reciprocated? _Yes X No 100%Retums during job yes Cement retums to surface? X Yes_No Spacer returns? X Yes_No Vol to Surf: 40 bbls spacer,60 bbls lead cmt Cement In Place At: 22:40 Date: 11/21/2014 Estimated TOC: Surface Method Used To Determine TOC: Visual Preflush(Spacer) I Type: Density(ppg) Volume pumped(BBLs) Lead Slurry Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tail Slurry wType: F Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): yr Post Flush(Spacer) 0 o Type: Density(ppg) Rate(bpm): Volume: yDisplacement: Type: Density(ppg) Rate(bpm): Volume(actual/calculated): FCP(psi): Pump used for disp: Plug Bumped? _Yes No Bump press Casing Rotated? Yes _No Reciprocated? _Yes_No %Returns during job Cement returns to surface? Yes_No Spacer returns? Yes_No Vol to Surf: Cement In Place At: Date: Estimated TOC: - Method Used To Determine TOC: WELLHEAD Make Sea board Type Multi bowl Serial No. 11360943 Size 16 3/4 x 11 W.P. 3M X 5M Test Head To 3000 PSIG 30 MIN test OK Remarks: Pumped 4.5 bbls over calculated attempting to bump plug.Float held. or V Nr- Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. Paxton#9 Date 3-Dec-14 County KPB State Alaska Supv. James Lott/Shane Barber CASING RECORD TD 6733.00 Shoe Depth: 6726.00 PBTD: 6643.00 Casing(Or Liner)Detail Setting Depths No.of Jts. Size Wt. Grade THD Make Length Bottom Top _ SHOE 51/2" 17 P-110 DWC Weatherford 3.08 6,726.00 6,722.92 2 51/2" 17 P-110 DWC US STEEL 78.66 6,722.92 6,644.26 Float collar 51/2" 17 P-110 DWC Weatherford 1.24 6,644.26 6,643.02 6 51/2" 17 P-110 DWC US STEEL 235.75 6,643.02 6,407.27 RA tag 51/2" 17 P-110 DWC US STEEL 5.00 6,407.27 6,402.27 51 5 1/2" 17 P-110 DWC US STEEL 1,996.95 6,402.27 4,405.32 pp RA tag 51/2" 17 P-110 DWC US STEEL 5.00 4,405.32 4,400.32 J 112 5 1/2" 17 P-110 DWC US STEEL 4,375.97 4,400.32 24.35 �(� 511. Hanger 5 1/2" 17 P-110 DWC US STEEL 4.00 24.35 20.35 6 a RKB 20.35 20.35 0.00 Csg Wt.On Hook: 66 Type Float Collar: Weatherford No.Hrs to Run: 12 Csg Wt.On Slips: 46 Type of Shoe: Weatherford Casing Crew: Weatherford Fluid Description: 9.3 Kla Shield Liner hanger Info(Make/Model): Liner top Packer?: Yes X No Liner hanger test pressure: Centralizer Placement: 51 @ 40'(shoe-4719'),33 @ 80'(4719'-2130') CEMENTING REPORT Preflush(Spacer) Type: SEAL BOND Density(ppg) 10 Volume pumped(BBLs) 40 Lead Slurry Type: TYPE 1 Density(ppg) 13.5 Volume pumped(BBLs) 145 Mixing/Pumping Rate(bpm): 3.7 Tall Slurry Type: TYPE 1 Density(ppg) 15.7 Volume pumped(BBLs) 90.3 Mixing/Pumping Rate(bpm): 3.6 y Post Flush(Spacer) N Type: Density(ppg) Rate(bpm): Volume: rc E Displacement: Type: 6%KCL Density(ppg) 8.6 Rate(bpm): 4.5 Volume(actual/calculated): 156/154.5 FCP(psi): 1175 Pump used for disp: Cementers Plug Bumped? X Yes No Bump press 1800 Casing Rotated? Yes X No Reciprocated? _Yes x No %Returns during job 100 Cement returns to surface? Yes x No Spacer returns? X Yes_No Vol to Surf: 40 SPACER Cement In Place At: 15:55 Date: 12/2/2014 Estimated TOC: cii ee' 7 ,t/v._ Method Used To Determine TOC: '7 VISUAL/Wt.Volume calculation based on 100%returns. /' 1 1— J� Preflush(Spacer) (,/ Type: Density(ppg) Volume pumped(BBLs) Lead Slurry Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tail Slurry wType: a Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): y Post Flush(Spacer) 0 o Type: Density(ppg) Rate(bpm): Volume: yDisplacement: Type: _Density(ppg) Rate(bpm): Volume(actual/calculated): FCP(psi): Pump used for disp: Plug Bumped? Yes No Bump press Casing Rotated? Yes _No Reciprocated? Yes_No %Returns during job Cement returns to surface? _Yes_No Spacer returns?_Yes_ No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0%excess: 0 Total Volume cmt Pumped: 145(lead)+90.3(tail)=235.3 bbls Cmt returned to surface: 0 Calculated cement left in wellbore: 235.3 OH volume Calculated: 181 OH volume actual: 0 Actual%Washout: 0 Paxton 9 Days Vs Depth o 1000 Paxton 9 Actual Paxton 9 Plan 2000 3000 v - �- 4000 I o ar co a, 5000 6000 7000 8000 0 5 10 15 20 25 30 Days Paxton 9 MW Vs Depth 0 -Paxton 9 Plan 500 -Paxton 9 Actual 1000 1500 2000 2500 3000 t fl. 3500 a v d L 4000 4500 5000 5500 6000 6500 7000 7500 8.0 9.0 10.0 11.0 12.0 13.0 14.0 Mud Density(ppg) z\A2— \-13 II Seth Nolan Hilcorp Alaska, LLC l `�22•, GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8308 DATA LOGGED tsiviiri, thiol a.1.i.c Fax: 907 777-8510 / -1201 E-mail: snolan@hilcorp.com M.K.BENDER DATE 01/23/14 To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL Paxton 9 Digital Survey Data CD: fj Paxton#9-Definitive Survey 12/18(20149:10 AM PDF Document 1;144 KB Paxton#9 Definitive Survey 12118.,2014 9:10 AM Text Document 9 KB Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By:11) j /17) Date: REE I V E D "✓ � JAN 262015 AOGCC 11 Seth Nolan Hilcorp Alaska, LLC 2 1 4 1 7 3 GeoTech 3800 Centerpoint Drive Anchorage, AK 99503 Tele: 907 777-8308 Iiiharp Alaska.IJ I Fax: 907 777-8510 2 5 2 9 4 E-mail: snolan@hilcorp.com 25295 DATE 01/14/15 To: Alaska Oil & Gas Conservation Commission RECEIVEC1 Makana Bender JAN 2 2 20 5 DATA` LOGGED Natural Resource Technician II m,K.BENDER 333 W 7th Ave Ste 100 A o�^^ Anchorage, AK A`1 CC 99501 DATA TRANSMITTAL Paxton 9 Elog and Mudlog prints and digital data Prints: 5" Formation Log MD 2" Gas Ratio Log MD 5" Formation Log TVD 2" Gas Ratio Log TVD 2" Formation Log MD 2" Drilling Dynamics MD 2" Formation Log TVD 2" Drilling Dynamics TVD 2" LWD Combo Log MD 2"/5" ROP-DGR-ADR MD 2" LWD Combo Log TVD 2"/5" DGR-ADR TVD CD1: digital Elog Data CGM 12/16/2014 2:01 PM File folder DLIS+LAS 12/16/2014 2:01 PM File folder EMF 12116./2014 2:02 PM File folder PDF 12/16/2014 2:02 PM File folder TIFF 12116/2014 2:02 PM File folder CD2: digital Mudlog Data Daily Reports 1/2/20153:44 PM File folder DML Data 112.,2015 3:44 PM File folder Final ';'fell Report 1/2/2015 3:44 PM File folder LAS Data 1/2/2015 3:44 PM File folder Lcg PDFs 1,2120153:44 PM File folder Lcg TIFFS 1/2/20153:44 PM File folder Sho Reports 1/2/2015 3:44 PM File folder Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received BM „Lo."0„44„;./) 6V��e1/Dh Date: \14-x-13 , � I�j,�s THE STATE Alaska Oil and Gas � 0,0 � ofALASI�:A- 3 Conservation Commission fix_ k_ 333 West Seventh Avenue • / GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OF ALAS' Fax: 907.276.7542 www.aogcc.alaska.gov Taylor Nasse Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga&Tyonek Gas Pool, Paxton#9 Sundry Number: 314-669 Dear Mr. Nasse: 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, • • David J. Mayberr Commissioner DATED this I&'?lay of December, 2014. Encl. } RECEIVED • STATE OF ALASKA DEC 11 2014 ALASKA OIL AND GAS CONSERVATION COMMISSION )4/6 ( _ APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redrill ❑ Perforate New Pool❑ Repair Well ❑ Change Approved Program 0 Suspend❑ Plug Perforations 0 Perforate E • PuN Tubing ❑ Time Extension❑ Operations Shutdown❑ Re-enter Susp.Well ❑ Stimulate❑ Alter Casing ❑ Other. 0 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to DriN Number Exploratory ❑ Development 214-173 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number. Anchorage,Alaska 99503 50-133-20647-00 • 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? C.O.701 Paxton#9 Will planned perforations require a spacing exception? Yes ❑ No ❑r 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL384372 • Ninilchik Field/Beulga&Tyonek Gas Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 6,733 3,503 6,643 3,428 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 16" 80' Surface 2,269' 9-5/8" 2,291' 1,401' 5,750 psi 3,090 psi Intermediate Production 6,726' 5-1/2" 6,726' 3,495' 10,640 psi 7,480 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): N/A N/A 2-7/8" 6.4#/L-80 3,482 Packers and SSSV Type: Prod Pkr Packers and SSSV MD(ft)and ND(ft): 3,394'MD/1,722'ND SLB TRMAXX 5E SCSSSV 170'MD/170'ND 12.Attachments: Description Summary of Proposal Q 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development❑✓ Service 0 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 12/17/14 Oil ❑ Gas Q WDSPL ❑ Suspended 0 16.Verbal Approval: Date: WINJ ❑ GINJ 0 WAG 0 Abandoned 0 Commission Representative: GSTOR 0 SPLUG 0 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Taylor Nasse Phone: 907-777-8354 Email tnasse@hilcorp.com Printed Nameaylor Nasse Title Operations Engineer For 1-044.- /11 -54 C Signature Phone 907-777-8354 Date /9. --I t --.1-e/LI COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3\1-k- 4ck. Plug Integrity ❑ BOP Test 0 Mechanical Integrity Test ❑ Location Clearance❑ Other: Spacing Exception Required? Yes 0 No [ Subsequent Form Required: / — ye 7 Y""„i L}e -` A ) APPROVED BY Approved by: / , COMMISSIONER THE COMMISSION Date: 11/16//g4 Submit Form and Form 10-403(Revised 10/2012) fry IEMaILfor 12 months from the date of a proval � l 4.7h/ents in uplricazte /2., /yYL-/ -,z /1OR1 I V RBEMS DEC 16 20 II Well Prognosis Well: Paxton#9 Hilcorp Alaska,LL, Date: 12/8/2014 Well Name: Paxton#9 API Number: 50-133-20647-00 Current Status: Completed, not Leg: perforated Estimated Start Date: December 17, 2014 Rig: Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 214-173 First Call Engineer: Taylor Nasse (907)777-8354 (0) (907)903-0341 (C) Second Call Engineer: Paul Chan (907)777-8333 (0) (907)444-2881 (C) AFE Number: 1412365C Estimated Bottom Hole Pressure: —1,505 psi at 3,500' TVD (Assumed 0.43 psi/ft gradient) Max. Anticipated Surface Pressure: —1,155 psi (0.10 psi/ft gas gradient) Brief Well Summary Paxton#9 is a grass roots well that is currently completed but not perforated. The well consists of 9-5/8" surface casing and 5-1/2" production casing with 2-7/8"tubing/packer completion. Objective of Work Add perforations in the Beluga sands. ' E-Line Procedure 1. MIRU a-line and pressure control equipment. PT lubricator to 250 psi low/32500 si high. Note that the well is pressurized with nitrogen. 2. If necessary, bleed nitrogen pressure down as requested by the RE to establish a drawdown on the formation. 3. Perforate the Beluga sands with 2" 6 SPF 60 deg phased perf guns.All intervals are planned for 12 SPF so each will be shot twice. Depths are from the Canrig LWD Combo log dated November 30th, 2014. Send the correlation pass to Taylor Nasse and David Buthman for confirmation. Gross Proposed Perforated Intervals Sands Top (MD) Btm (MD) FT Beluga BIg40 ±3,640' ±3,708' ±68 , Beluga BIg43a ±3,836' ±3,865' ±29 Beluga BIg43b ±3,953' ±3,968' ±15 Beluga BIg45 ±4,060' ±4,097' ±37 Beluga BIg45b ±4,180' ±4,230' ±50 Beluga BIg50a ±4,640' ±4,683' ±43 • II Well Prognosis Well: Paxton#9 Hilcorp Alaska,LL; Date:12/8/2014 Beluga BIg50b ±4,705' ±4,726' ±21 Beluga BIg50channel ±4,790' ±4,910' ±120 Beluga BIg55 ±5,215' ±5,250' ±35 Beluga BIg60 ±5,390' ±5,427' ±37 Beluga BIg100 ±6,482' ±6,492' ±10 Beluga BIg120 ±6,569' ±6,587' ±18 4. POOH. 5. Flow well through test separator and record water and gas rates. 6. If any of the Beluga sands are not commercial,then the zone will be plugged back with a bridge plug. 7. RD a-line. 8. Turn well over to production. Attachment: Current and Proposed Wellbore Schematic Ninilchik Unit • SCHEMATIC Well: Paxton #9 • PTD: 214-173 API: 50-133-20647-00 Hileorp Alaska.I.I.I RKB=18.7' N. ' L CASING DETAIL 16" ?In) Size Type Wt/Grade/Conn ID Top Btm 16" Conductor 109/X-56/Weld Surf 80' t. 9-5/8' Surface 40/L-80/BTC _ 8.835" Surf 2,291' 5-1/2" Production 17/P-110/CDC 4.892" Surf 6,723' 1-21 TUBING DETAIL 2-7/8" Tubing 6.4/L-80/EUE-8rd 2.441" Surf 3,482' • ' JEWELRY DETAIL No. MD TVD ID OD Item 9-5/8" s 1 154' 154' CIM ' 2 170' 170' 2.312" 4.609" SLB TRMAXX 5E SCSSSV 3 3,393' 1,722' XO • 4 3,394' 1,722' Prod Pkr 5 3,399' 1,724' XO 6 3,443' 1,737' 3.25" X-Nipple 7 3,482' 1,748' Wireline re-entry guide rA 444444333333rrrrrr',S, • 8-1/2"Hole l' . 1. • 3 • I,. 4 . t ` 5 6 7 - .4 . • 1„ r ' r ,r , 5.5" Q. PBTD =6,643 MD/3,428'TVD TD=6,733' MD/3,503'TVD Updated by DMA 12-11-14 Ninilchik Unit Well: Paxton #9 • II PROPOSED PTD: 214-173 API: 50-133-20647-00 Hikorp Alaska,LLC RKB=18.7' CASING DETAIL 16" Ia � Size Type Wt/Grade/Conn ID Top Btm 1 16" - Conductor 109/X-56/Weld Surf _80' _ 9-5/8' _ Surface 40/L-80/BTC 8.835" Surf 2,291' _' .. 5-1/2" Production 17/P-110/CDC 4.892" Surf 6,723' tili 5'- - TUBING DETAIL 2-7/8" Tubing 6.4/L-80/EUE-8rd 2.441" Surf 3,482' f' • ii JEWELRY DETAIL No. MD TVD ID OD Item 9-5/8" de • " aye' 1 154' 154' CIM •`r 2 170' 170' 2.312" 4.609" SLB TRMAXX SE SCSSSV y J3 3,393' 1,722' XO 4 5 3,394' 1,722' Prod Pkr 3,399' 1,724' XO 6 3,443' 1,737' 3.25" X-Nipple 7 3,482' 1,748' Wireline re-entry guide ' PERFORATION DETAIL it.' " • Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) Ft Date Status BIg40 ±3,640' =3,708' ±1,791' ±1,809' ±68 Future Proposed BIg43a ±3,836' ±3,865' ±1,846' ±1,855' ±29 Future Proposed ' BIg43b ±3,953' ±3,968' ±1,880' ±1,884' ±15 Future Proposed BIg45 ±4,060' ±4,097' ±1,911' ±1,922' ±37 Future Proposed BIg45b BIg50a ±4,180' ±4,230' ±1,946' ±1,961' ±50 Future Proposed 8-1/2"Hole ±4,640' ±4,683' ±2,116' ±2,135' ±43 Future Proposed * BI 50b ±4 705' ±4 726' ±2 144' ±2 153' ±21 Future Proposed g BIg50channel ±4,790' ±4,910' ±2,181' ±2,234' ±120 Future Proposed ' 3 BIg55 ±5,215' ±5,250' ±2,385' ±2,404' ±35 Future Proposed • G.7zil 5 BIg60 ±5,390' ±5,427' ±2,484' ±2,507' ±37 Future Proposed � 6 BIg100 ±6,482' ±6,492' ±3,294' ±3,385' ±10 Future _ Proposed 7 , BIg120 ±6,569' ±6,587' ±3,366 ±3,381' ±18 Future Proposed BIg40 � BIg43a � _ 7r 1 '~ B1g43b .'- BIg45 "'' BIg45b BIg50a 4BIg50b ., • BIg5Ochannel aBIg55 BIg60 , , BIg100 I '•` BIg120 5-1/2" ".A, ., - . ',,_ PBTD=6,643 MD/3,428'TVD TD=6,733' MD/3,503'TVD Updated by DMA 12-11-14 2,.4-v13 w\�qii/Z4'*7 THE STATE Alaska Oil and Gas ��` �'"' °fALASKA Conservation Commission i7-- GOVERNOR BILL WALKER 333 West Seventh Avenue ;° Anchorage,Alaska 99501-3572 Op,ALASY' Main:907.279.1433 Fax:907.276.7542 Paul Chan Senior Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage,AK 99503 Re: Ninilchik Field, Beluga and Tyonek Gas Pools, Paxton#9 Sundry Number: 314-641 Dear Mr. Chan: 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, 1-et44 i©,54 ,0cL Cathy P.foerster Chair DATED this 4-da of December, 2014. Y Encl. STATE OF ALASKA fi CEIVED ALASKA OIL AND GAS CONSERVATION COMMISSION NOV 2 6 204 6i1�� APPLICATION FOR SUNDRY APPROVALS /�� 12.( Z11 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well 0 Char ylQ iibN Q am ❑ Suspend❑ Plug Perforations❑ Perforate❑ PuH Tubing 0 Time Extension❑ Operations Shutdown❑ Re-enter Susp.Well ❑ Stimulate❑ Alter Casing 0 Other. Complete 0• 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to DOH Number: Exploratory ❑ Development0 • 214-173' 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 50-133-20647-00• 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? C.O.701 Paxton#9 • • Will planned perforations require a spacing exception? Yes 0 No El - 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL384372 ' • Ninilchik Field/Beulga&Tyonek Gas Pool • . 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): Drilling 8-1/2"Hole Casing Length Size MD ND Burst Collapse Structural Conductor 80' 16" 80' Surface 2,269' 9-5/8" 2,291' 5,750 psi 3,090 psi - Intermediate Production Drilling 8-1/2"Hole Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): N/A N/A N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): N/A N/A 12.Attachments: Description Summary of Proposal 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development Q Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 12/03/14 / Oil ❑ Gas 0 WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: 'WINJ 0 GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG El 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Paul Chan Phone: 907-777-8333 Email pchan@hilcorp.com Printed Na aul C -n Title Senior Operations Engineer / Signature .A \. Phone 907-777-8333 Date i( (z ' / c COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ;y \Lk- lQ `t Plug Integrity ❑ BOP Test Mechanical Integrity Test 0 Location Clearance 0 Other. .� �C1(.' r ,� 6 C' 1 L ('f- !* -S l-) - i i, C �/�Sc } Spacing Exception Required? YesNo (Je ( !g "lM p g p q 0 [7, Subsequent Form Required: �Ci —� L 7 � . APPROVED BY \\\\ Approved byP )1.4.4.4#4,t........„- agiCOMMISSIONER THE COMMISSION Date: /Z — -/ ' /L- 3 /� Submit Form and 1" Br,or 1 D31 s O 1g�ot AeRaIetIINviAl ter 12 months 414 the date of approval. L'YfS L 1 1 ' v n ` Attachments in Duplicate ,� /4. /51A• /•/Z•iv Well Prognosis Well: Paxton#9 Hilcorp Alaska,LL Date: 11/25/2014 Well Name: Paxton#9 API Number: 50-133-20647-00 Current Status: Drilling 8-1/2" hole Leg: section Estimated Start Date: December 4, 2014 Rig: Saxon 147 Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 214-173 First Call Engineer: Paul Chan (907) 777-8333 (0) (907) 345-3161 (H) (907)444-2881 (C) Second Call Engineer: Stan Porhola (907)777-8412 (0) (907) 331-8228(C) AFE Number: 1412365C Estimated Bottom Hole Pressure: —1,505 psi at 3,500' TVD (Assumed 0.43 psi/ft gradient) Max. Anticipated Surface Pressure: —1,155 psi (0.10 psi/ft gas gradient) Brief Well Summary Paxton#9 is a grass roots well currently being drilled by the Saxon 147 rig. 9-5/8" surface casing has been set and the rig is drilling the 8-1/2" hole section. After the production casing is run and cemented, Saxon 147 will run the 2-7/8"completion. Objective of Work Complete the well with 2-%"tubing and jewelry with the Saxon 147 rig. RDMO the rig. Completion Procedure: 1. Change over to 2-7/8"x 5-1/2"VBR. Test all breaks and VBR with a 2%."test joint to 250 psi low/ 3'C111r590-psi high. LD test joint. 2. PU bit and scraper for 5-1/2" 17#casing on 2-7/8"tubing string. Rabbit the tubing before RIH 3. RIH and reciprocate scraper across packer set depth by making a 4 stand short trip. Depths for short trip will be forwarded after evaluating the open hole logs. Continue RIH to PBTD and circulate the hole clean at maximum rate. 4. POOH and stand back tubing. 5. Prepare to PU tubing. Run 2-W' 6.4#L-80 tubing w/packer and 2-%s"tailpipe as detailed below. Rabbit the tubing with"2.4"drift. Drift jewelry before RIH. RU control line spoolers as needed. • 2-Vs"WLEG @ "'1800' MD • 1 joint 2%." 6.4#L-80 tubing • 2-7/8" X nipple with RHC-P ball catcher • 1 joint 2-V." 6.4#L-80 tubing • 5-34"x 2-V." Hydraulic set packer w/handling pups. Packer set depth± 1,750' MD • 2-V." 6.4#L-80 tubing Well Prognosis Well: Paxton#9 Hilcorp Alaska,LL Date: 11/25/2014 • 2-%" 6.4#L-80 handling pup • 2-Vs"SCSSSV w/2.312" packing bore @—170' MD • 2-/," 6.4# L-80 handling pup • 2-%" 6.4#L-80 handling pup • 2-%"Chemical injection sub @-157' MD • 2-%," 6.4# L-80 handling pup • 4 joints 2-%" 6.4# L-80 tubing • Tubing hanger with handling pup 6. RIH with completion. Record PU and SO weights. 7. MU tubing hanger, control lines, and landing joint. Test control line for SSSV to 6000 psi. 8. Land tubing hanger and RILDS. LD landing joint. Test tubing hanger packoff. 9. Reverse circulate in 8.6 ppg KCI brine with 0.5 gal/bbl of corrosion inhibitor. 10. Drop ball/rod. Pressure up on the tubing and set the packer. 11. Test tubing to 3,500 psi for 30 min. Bleed off pressure to 1500 psi. 12. Test the IA to 241:1Qpsi for 30 min. Bleed off IA. 13. Set TWC. ND BOPE. NU adapter flange and tree. PT tree. RU lubricator and pull TWC. Slickline Procedure 14. MIRU slickline. PT lubricator to 250 psi low/1500 psi high. E' t- 15. Pull ball/rod. POOH. 16. Retrieve RHC-P. POOH. 17. Drift well to maximum depth/deviation. POOH. 18. RDMO. E-Line Procedure 19. MIRU e-line. PT to 250 psi low/ 1500 psi high. cs 20. Run GR/CCL/CBL/Neutron logs with rollers as needed: a. Run Neutron log from PBTD to "1600' MD. b. Run GR/CCL from PBTD to surface. All 5-1/2"casing/tubing details should be notated on the log(RA tags and marker joints if any. See casing/cementing report for details). c. Run CBL cement bond log with GR/CCL from PBTD to^'1800' MD. Depending upon results from the initial CBL run, a pressure pass may also be required. 21. RDMO e-line Coiled Tubing Procedure 22. RU CTU, nitrogen,and flow back tanks. Notify AOGCC 24 hours prior to testing at http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html 23. Shell test BOPE/lubricator to 250psi low/4,500psi high(unless due for weekly BOPE test—then a full BOPE test will be done). -- C II Well Prognosis Well: Paxton#9 Hilcorp Alaska,LL Date:11/25/2014 24. RIH with CT and blow the well dry with nitrogen. Strap tank before and after blowing the well down. 25. Leave well with 1000 psi N2 cap. POOH. 26. RDMO CTU. E-Line Procedure- Perforating 27. A separate Form 10-403 will be submitted for the initial perforations on this well. ' Attachment: Current(drilling)and Proposed Wellbore Schematic Ninilchik Unit , currently Drilling Well: Paxton #9 PTD: 214-173 API: 50-133-20647-00 Ilthorp Alaska,I.I.(: CASING DETAIL 1e 47A,It s! r Size Type Wt/Grade/Conn ID Top Btm 4 -' 16" Conductor 109/X-56/Weld Surf 80' 7,filt ; 9-5/8' Surface 40/L-80/BTC 8.835" Surf 2,291' , . 5-1/2" Production 17/P-110/CDC 4.892" Surf 6,733' * Estimated depth from Drilling Plan , 4 1 ;A ibt_I SM 9-5/8" ' b. shoe s" 8-1/2" Hole ..1 PBTD=6,607 MD/3,382'TVD TD=6,733'MD/3,500'TVD Updated by PC 11/25/2014 Ninilchik Unit Proposed Cornpletion Well: Paxton #9 PTD: 214-173 API: 50-133-20647-00 Hilcorp Alaska,LLC i CASING DETAIL 16" 1 Size Type Wt/Grade/Conn ID Top Btm • 16" Conductor 109/X-56/Weld Surf 80' 9-5/8' Surface 40/L-80/BTC 8.835" _ Surf 2,291' r'y 5-1/2" Production 17/P-110/CDC 4.892" Surf ±6,733' * `r {Myr TUBING DETAIL 11 /4"'"1: 7 :1 2-7/8" Tubing 6.4/L-80/EUE-8rd 2.441" Surf ±...11806r** I... "i 3,-I 5° 1 * Estimated depth from Drilling Plan ►' i ** Estimated depth from Geologic Prognosis , . t,; 9-5/8" �. shoe .. � JEWELRY DETAIL T r 4 Q' S No. MD TVD ID OD Item K3."; '1 .` 1 ±150' ±150' CIM k„� r" 2 - ±170' ±170' 2.312" 4.609" SLB TRMAXX 5E SCSSSV , } t. 3 }''�'-1(+,Z50'' t-1-245� Prod Pkr t-re. .0 ` *t"l} 4BAOr5' Wireline re-entry guide t . - q- 1,...4 ,;4„,,,, 8-1/2" . � * j ' o% Hole , :3 r44.,....4 4404. iiikq A. 3 i Z S- ' R ' Nita I/ shoeriki: ' , .#. PBTD=±6,607 MD/±3,382'TVD TD=±6,733'MD/±3,500'TVD Updated by PC 11/25/2014 Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Wednesday, December 03, 2014 11:35 AM To: 'Paul Chan'; Davies, Stephen F (DOA) Cc: Chad Helgeson;Taylor Nasse;James Lott- (C); Lenward Toussant- (C) Subject: RE: Paxton#9 Packer Set Depth Change (PTD 214-173) Paul, Packer depth change is approved. I will pencil in new depth on the sundry. Also I kept the BOP test pressure for Saxon 147 same at 3500 psi ( in step#1) to reduce confusion when the test charts come though. Everything else is good on sundry. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at(907-793-1226) or (Guy.schwartz@alaska.gov). From: Paul Chan [mailto:pchan@hilcorp.com] Sent:Tuesday, December 02, 2014 1:06 PM To: Schwartz, Guy L(DOA); Davies, Stephen F(DOA) Cc: Chad Helgeson;Taylor Nasse; James Lott- (C); Lenward Toussant- (C) Subject: Paxton #9 Packer Set Depth Change (PTD 214-173) Guy/Steve After further review of the open hole logs for the Paxton#9 well, Hilcorp Alaska respectfully requests to change the packer set depth from 1750' MD to 3400' MD as noted in the completion running order. • 2-Y8"WLEG @=1800'-3450' MD • 1 joint 2%," 6.4#L-80 tubing • 2-7/8" X nipple with RHC-P ball catcher • 1 joint 2%' 6.4#L-80 tubing • 5-%2" x 2%" Hydraulic set packer w/handling pups. Packer set depth±1,750'3,400' MD • 2-%a"6.4#L-80 tubing • 2-%" 6.4#L-80 handling pup • 2-Y," SCSSSV w/2.312" packing bore @ ^'170' MD • 2-%," 6.4# L-80 handling pup • 2%," 6.4#L-80 handling pup • 2-'/," Chemical injection sub @ "'157' MD • 2%,"6.4# L-80 handling pup 1 • 4 joints 2;%"6.4#L-80 tubing • Tubing hanger with handling pup I have also attached the 10-403 submittal to run the completion for your reference. Thanks Paul Chan Senior Operations Engineer Kenai Asset Hilcorp Alaska LLC (907) 777—8333 (w) (907)444—2881 (c) (907)345—3161 (h) 2 Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Thursday, December 04, 2014 10:29 AM To: 'Paul Chan'; Davies, Stephen F(DOA) Cc: Chad Helgeson;Taylor Nasse;James Lott- (C);Shane Barber- (C) Subject: RE: Paxton#9 Packer Set Depth Change(PTD 214-173) Paul, Verbal approval granted... sundry should be out later today. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). From: Paul Chan [mailto:pchan@hilcorp.com] Sent: Thursday, December 04, 2014 10:17 AM To: Schwartz, Guy L(DOA); Davies, Stephen F(DOA) Cc: Chad Helgeson;Taylor Nasse; James Lott- (C); Shane Barber- (C) Subject: RE: Paxton #9 Packer Set Depth Change(PTD 214-173) Guy Hilcorp Alaska respectfully requests verbal approval to complete the well with 2-7/8" tubing and a packer set depth of 3400' MD as per this e-mail and the submitted 10-403. Sincerely Paul Chan Senior Operations Engineer Kenai Asset Hilcorp Alaska LLC (907) 777—8333 (w) (907)444—2881 (c) (907) 345—3161 (h) From: Schwartz, Guy L(DOA) [mailto:guy.schwartz(aalaska.gov] Sent: Wednesday, December 03, 2014 11:36 AM To: Paul Chan; Davies, Stephen F(DOA) Cc: Chad Helgeson; Taylor Nasse; James Lott- (C); Lenward Toussant- (C) Subject: RE: Paxton #9 Packer Set Depth Change (PTD 214-173) Paul, Packer depth change is approved. I will pencil in new depth on the sundry. Also I kept the BOP test pressure for Saxon 147 same at 3500 psi ( in step#1) to reduce confusion when the test charts come though. Everything else is good on sundry. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at (907-793-1226) or(Guy.schwartz@alaska.gov). From: Paul Chan [mailto:pchan@hilcorp.com] Sent: Tuesday, December 02, 2014 1:06 PM To: Schwartz, Guy L(DOA); Davies, Stephen F(DOA) Cc: Chad Helgeson; Taylor Nasse; James Lott- (C); Lenward Toussant- (C) Subject: Paxton #9 Packer Set Depth Change (PTD 214-173) Guy/Steve After further review of the open hole logs for the Paxton#9 well, Hilcorp Alaska respectfully requests to change the packer set depth from 1750' MD to 3400' MD as noted in the completion running order. • 2-'/"WLEG @ r-X800•'•3450' MD • 1 joint 2-Y."6.4#L-80 tubing • 2-7/8"X nipple with RHC-P ball catcher • 1 joint 2%:"6.4#L-80 tubing • 5-36"x 2%." Hydraulic set packer w/handling pups. Packer set depth±1,750'3,400' MD • 2-7/e"6.4#L-80 tubing • 2%."6.4#L-80 handling pup • 2%."SCSSSV w/2.312" packing bore @^'170' MD • 2%" 6.4# L-80 handling pup • 2-74"6.4#L-80 handling pup • 2-'/e"Chemical injection sub @—157' MD • 2%" 6.4# L-80 handling pup 2 I • 4 joints 2-741"6.4#L-80 tubing • Tubing hanger with handling pup I have also attached the 10-403 submittal to run the completion for your reference. Thanks Paul Chan Senior Operations Engineer Kenai Asset Hilcorp Alaska LLC (907)777—8333 (w) (907)444—2881 (c) (907)345—3161 (h) 3 „O'\1 , s THE STATE Ada.c°1.-2 Oil and Cas 44vi t ®f _\ i pl\ � � Cid` e Ta aci f6 Cc rii l.y i e'`c 333 West Seventh Avenue GOVERNOR SEAN PARNELL Anchorage, Alaska 99501-3572 Moin: 907.279 1433 Fax: 907.276 7542 Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga/Tyonek Gas Pool, Paxton#9 Hilcorp Alaska, LLC Permit No: 214-173 revised Surface Location: 3058' FEL, 923' FNL, SEC. 13, T1S, R14W, SM, AK Bottomhole Location: 337' FNL, 2068' FWL, SEC. 12, T1S, R14W, SM,AK Dear Mr. Keller: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy P Foerster Chair DATED this fay of November, 2014. RECEIVED STATE OF ALASKA P :A OIL AND GAS CONSERVATION COME DN NOV 1 3 2014 • PERMIT TO DRILL! �, r 20 AAC 25.005AOG,per1a.Type of Work: 1 b. Proposed Well Class: Development-Oil [1] Service- Winj ❑C..K .- Single Zone 0 . 1 c.Specify if well is proposed for: Drill - 0 Lateral ❑ Stratigraphic Test ❑ Development-Gas 0- Service-Supply ❑ Multiple Zone ❑ Coalbed Gas ❑ Gas Hydrates ❑ Redril❑ Reentry ❑ Exploratory ❑ Service- WAG ❑ Service-Disp ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket 0 Single Well ❑ 11.Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 - Paxton#9 ' 3.Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive Ste 1400,Anchorage AK 99503 MD: 6,733. - TVD: 3,500' - Ninilchik Field 4a. Location of Well(Governmental Section): 7. Property Designation(Lease Number): Beluga/Tyonek Gas Pool Surface: 3058'FEL,923'FNL,Sec 13,T1S,R14W,SM,AK ADL384372' Top of Productive Horizon: 8. Land Use Permit: 13.Approximate Spud Date: 1713'FSL,2144'FWL,Sec 12,T1S,R14W,SM,AK Surface agreement w/parcel fee owner 11/14/2014 Total Depth: 9.Acres in Property: 14. Distance to Nearest Property: 337'FNL,2068'FWL,Sec 12,T1S,R14W,SM,AK 3507.84(ADL 384372) 5470'to nearest unleased tract 4b. Location of Well(State Base Plane Coordinates-NAD 27): 10. KB Elevation above MSL: - 166.6 feet 15.Distance to Nearest Well Open Surface: x-206265.74 ' y-2230441.15 . Zone-4 GL Elevation above MSL: • 148 feet to Same Pool: 2658'to Paxton 4 16. Deviated wells: Kickoff depth: 251 feet 17. Maximum Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 73 degrees Downhole: 1505 psi Surface: 1155 psi 18.Casing Program. Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Gond 16" 109 X-56 Weld 80' Surf Surf 80' 80' Driven 12-1/4" 9-5/8" 40 L-80 BTC 2,300' Surf Surf 2,300' 1,403' 157 bbl 12.5#lead,50.7 bbl 15.2#tail 8-1/2" 5-1/2" 17 P-110 CDC 7,376". Surf Surf _...;,..376' 3,500' 145 bbl 13.5#lead, 126 bbl 15.2#tail 17;717 6,773 L /,/../41 -a:. ///af /4` 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): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): 20. Attachments: Property Plat 0 BOP Sketch 0 Drilling Program 0 Time v. Depth Plot 0 Shallow Hazard Analysis❑ Diverter Sketch 0 Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. Contact Luke Keller Email Ikeller(c�hilcorp.com Printed Name Luke Keller Title Drilling Engineer Signature ,Z--- Phone 907-777-8395 Date 11/13/2014 Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other Number: 2._\LA-V"j 50- \3-5-10(e'-i-'1- O O-po Date: \`I'-r/\y requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained in shales: Lf Other: ��• � '0.hs /� Samples req'd: Yes ii No 0 Mud log req'd:Yes II] No Eir S 'f2-(1'f2-(15 p l • HZS measures: Yes❑ No❑ , Directional svy req'd:Yes❑• No❑ Spacing exception req'd: Yes❑ No❑ Inclination-only svy req'd.Yes❑ No EI APPROVED BY Approved by: 4 ��' COMMISSIONER THE COMMISSION Date: l� /�� l //' iL DD nn Submit Form and Form 10-401(Revi d 10/2012) �T is �pit�sGi f �DnLs from the date of approval(20 AAC 25. 5(g) Attachments in uplicate Luke Keller Hilcorp Alaska, .'-C Drilling Engineer P.O. Box 244027 Anchorage,AK 99524-4027 Tel 907 777 8395 Email Ikeller@hilcorp.com Hileorp Alaska,I.LC November 13th, 2014 RECEIVED NOV 13 2014 Commissioner Alaska Oil &Gas Conservation Commission AOGCC 333 W. 7th Avenue Anchorage, Alaska 99501 Re: Paxton#9 Dear Commissioner, Enclosed for review and approval is a revision to the Permit to Drill for Paxton#9. The"as-built"surface location plat is attached and differs from the"as-staked"surface plat by 10 ft. A revised directional plan is included that reflects this slight change of surface location. The directional plan was also slightly modified to reduce anti-collision concerns of previous plan. The most recent version (WP 6.0) is attached. There is no change to TPH or BHL. The surface casing was also modified to stop just short of the beluga 50. Planned casing point for the surface is now 2300' MD/1403'TVD. If you have any questions, please don't hesitate to contact myself at 777-8395 or Paul Mazzolini at 777-8369. Sincerely, /2(J(--- Luke Keller Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 SECTION UNE NTS N 2231286.547 12 7 4...._ _ E 209345.736 1318 PAXTON J SPENCER ESTATE - GOVT.LOT 1 SEC.13 / 5 T 01 S,'R 4 W S.M.AK HOMER RECORDING °� N OR TH DISTRICT QOFO 64634 RED BLUFF DRIVE 0 . F .,1111111111111117— _.....(4.rnuIIlP, SCALE 0 100 200 PLEV'ER ALDERS& I I I i I BRUSH FEET .� / Ep s \\\"\% ,j,ti I 'N' '•-.7 .-.7 / Owen BLDG Tµc ? -' 1 �. . / y �, 41 ' / w ttl j''c'•;M, SCOTT McLANEr' i ` / ,,,te NAIR` �` I II/II/�14 f �y �� 4928 S / l'. ,N / LIMITS OF SEAS V .'14 % / =j�i W LU DMI AGE CH NEL /-. / � �`�" 4DQ" / / I— / PAXTON p1 WE SUPIPORT ~� i / :C o. DSIZ AXTON PADENDS IS ® o / u•• ` PAXTON N J WELLN ® /// troPON#2WELL / ' / / / / '/,:l --- ii J / PO / // /Jf �/� PAXTON#1 WE � jS � r, 04'4, / :Y / / ®m w z O ry I w /� PG .'// / ® PAXTON p5 WELL �+ � j i / / / / III / ® PAXTON p B WELL / '":(7 PAXTONp]WELL " _ ff l` �/ ! ® WATER // 1 •t/' ` t1 ' ^:HOUSE /S / Ilk.. f j / PAXTON#9 WELL �` ^ f I AS-BUILT /NAD27ASPZONE4 / „!' ' t ,` 1` 31 / r I 1 I N: 2230441.15' j`i \V A\ i. '( I 1 E: 206265.74' /0'01.BASIS OF ELEVATIONS IS NGS MONUMENT S 82 PID TT0583 AT MILE POST \ \ I? J 124.2 OF THE STERLING HIGHWAY. THE ELEVATION OF S82 IS 237.12 FEET \ LAT:60°O5'44.148"N // i \ ��_ " LON:151°36'33.611"W j// (NGVD 29). BASIS OF HORIZONTAL COORDINATES ARE ALASKA STATE PLANE NAD 83 ZONE 4 EPOCH 2003 DETERMINED BY AN NGS OPUS SOLUTION FROM \\ It ELEV=148.5'NGVD29 ///,'; /f/ � CORS BASE STATIONS.2701_03 TLPID AH2494","ZAN1 PID DE9153"AND"GNAA PID ./ SECTION 13 T1S,R14W,AK r r AH2492" OBSERVED JUNE 5,2007 ON MCI S82 ECC 2"ALUM.CAP SET MAIN 3058'FEL,923'FNL ''I, / ADJACENT TO BM S82 N:2252517.780 E:1368533.525 ELEV:240.08 FEET. GATE \ 2)NORTHEAST CORNER SEC.13 COORDINATES DETERMINED FROM DIRECT 4:,' SURVEY TIE TO THE TO EXISTING BLM SECTION CORNER RECOVERED. • PROTRACTED SECTION CORNER VALUES NOT USED. A V‘ 3)CORPSCON VERSION 6.0.1 USED TO CONVERT NAD83 TO NAD27. PAXTON #9 WELL AS-BUILT SURFACE LOCATION NOTES (NAD27) H LOCATION: SECTION 13, TOWNSHIP 1 SOUTH, /, ENGINEERING-TESTING RANGE 14 WEST, SEWARD MERIDIAN ALASKA LC SURVEYING MAPPING P.O.BOX 468 Hilcorp Alaska,L McLAN L. SOLDOTNA,AK.99669 JOB NO. 143144 REV.0 VOICE: (907)283-4218 FAX:(907)283-3265 DWG. Consulting Inc WWW.MCLANECG.COM 143144 Date: Nov. 11, 2014 FIGURE: 1 Hilcorp Energy Company Ninilchik Unit Paxton Plan: Paxton #9 Paxton #9 Plan: Paxton #9 wp6 II Standard Proposal Report 13 November, 2014 I II�I!I hG' i HALLIBURTON •h■ Sperry Drilling Services ISI` riscorp tnergy Lompany Project: Ninilchik Unit HALL!B U RTD N Calculation Method: m Curvature Site: Paxton Error System: A Scan Method: . stApproach 3D Well: Plan: Paxton, Sperry Drilling Error Surface: Elliptical Conic Wellbore: Paxton#9 Warning Method: Error Ratio Design: Paxton#9 wp6 Hula corp REFERENCE INFORMATION Co-ordinate(N/E)Reference: Well Plan:Paxton#9,True North CASING DETAILS Vertical(TVD)Reference: Paxton#9(148.5+18.5)@ 167.O0usft Measured Depth Reference: Paxton#9(148.5+18.5)@ 167.00usft TVD TVDSS MD Size Name Calculation Method: Minimum Curvature 80.00 -87.00 80.00 16 16" 1403.71 1236.71 2300.00 9-5/8 9 5/8" 3500.15 3333.15 6733.31, 5-1/2 5 1/2" WELL DETAILS: Plan:Paxton#9 Ground Level: 148.50 +N/-S +E/-W Northing Easting Latittude Longitude Slot 0.00 0.00 2230441.15 206265.74 60.09559681 -151.60933637 -900- SURVEY PROGRAM Date:2014-11-11T00:00:00 Validated:Yes Version: -600- _ Depth From Depth To Survey/Plan Tool 18.50 2300.00 Paxton#9 wp6(Paxton#9) MWD+SC+sag 2300.00 6733.31. Paxton#9 wp6(Paxton#9) MWD+SC+sag -300- -_ • FORMATION TOP DETAILS 0_' I ITVDPath TVDssPath MDPath Formation G 1434.00 1267.00 2404.66 Top Beluga - 16" 2137.00 1970.00 4705.54 Beluga 50 2473.00 2306.00 5380.76 Belgua 60 300- - 500 600- -_ 00 900- `0 0 0 1200- N o � -Top Beluga - - - - - - - - - � - - - - o - - - - - - - - - - - - - - - - - - - - - - - - - 1500- M o 9 5/8" h M 0_ 1800- _ O tJ R 2100- -Beluga 50• - - - - - - - - - - - - - - - - - - - - - - - - - - - - o0 a) h0 Pax#9 wp3_BIg50 tgt 2400- -4.. Belpue BO - - - - - - - - 2700- - 00 - 60 3000- 6500 3300- - 6133 3600- 5 1/2' ' / Paxton#9 wp6 3900- 4200- iiii iiia iiiIIIIIIIIIIi iiiI IIII IIIIIIIII � iIii � IIIIIIiii III � IIII � IIiI � IIIIIiiIIliiii � 0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 540. Vertical Section at 0.00° (750 usft/in) HALUBUI'-�i . ON ti a CASING DETAILS Cori) TVDSS MD Size Name 6 -87.00 80.00 16 16" Sperry Drilling 1403.1 i 1236.71 2300.00 9-5/8 9 5/8" 3500.15 3333.15 6733.31 5-1/2 5 1/2" 5525- - Project:Ninilchik Unit COMPANY DETAILS: Hilcorp Energy Company Paxton#9 wp6 Site:Paxton Calculation Method: Minimum Curvature Well:Plan:Paxton#9 Error System:ISCWSA 5200- Wellbore:Paxton#9 Scan Method: Closest Approach 3D 5 1/2"----' '3500 Design:Paxton#9 wp6 Error Surface: Elliptical Conic Warning Method: Error Ratio 4875- - 3000 REFERENCE INFORMATION Co-ordinate(N/E)Reference: Well Plan:Paxton#9,True North Vertical(TVD)Reference: Paxton#9(148.5+18.5)@ 167.00usft 4550- Measured Depth Reference: Paxton#911 48.5+18.5)@ 167.00usft Calculation Method: Minimum Curvature 2500 4225- WELL DETAILS: Plan:Paxton#9 Ground Level: 148.50 +N/-S +E/-W Northing Ea sting Latittude Longitude Slot 90%conf. 0.00 0.00 2230441.15 206265.74 60.09559681 -151.60933637 3900- t1 Pax#9 wp3_BIg50 tgt SURVEY PROGRAM 3575- Date:2014-11-11T00:00:00 Validated:Yes Version: Depth From Depth To Survey/Plan Tool 2000 18.50 2300.00 Paxton#9 wp6(Paxton#9) MWD+SC+sag 2300.00 6733.31 Paxton#9 wp6(Paxton#9) MWD+SC+sag 3250- - SECTION DETAILS c - 2925- Sec MD Inc Ad TVD TVDSS 41/-S .E/-W Northing Fasting DLeg TFace VSec Target 1 18.50 0.00 0.00 18.50 -148.50 0.00 0.00 2230441.15 206265.74 0.00 0.00 0.00 2 125.00 0.00 0.00 125.00 -42.00 0.00 0.00 2230441.15 206265.74 0.00 0.00 0.00 3 300.00 1.75 340.00 299.97 132.97 2.51 -0.91 2230443.68 206264.89 1.00 340.00 2.51 4 400.00 5.75 340.00 399.74 232.74 8.66 -3.15 2230449.88 206262.80 4.00 0.00 8.66 + 2600- 5 700.00 20.75 340.00 690.92 523.92 73.08 -26.60 2230514.86 206240.93 5.00 0.00 73.08 6 1371.31 73.18 358.66 1134.94 967.94 540.79 -78.67 2230983.70 206200.26 8.00 22.33 540.79 7 4302.59 73.18 358.66 1983.28 1816.28 3345.86 -144.37 2233789.53 206202.88 0.00 0.00 3345.86 0 8 4554.92 65.00 5.00 2073.35 1906.35 3581.11 -137.21 2234024.53 206215.76 4.00 145.16 3581.11 9 4804.92 65.00 5.00 2179.00 2012.00 3806.83 -117.46 2234249.70 206241.00 0.00 0.00 3806.83 Pani/9wp3_131g50tgt 10 6733.31 26.43 5.00 3500.15 3333.15 5156.27 0.60 2235595.86 206391.88 2.00 180.00 5156.27 .� 2275- . - 0 rn 1950- 1500 1625- r 1300- 9 5/8" 975- _ 650- - 325- 1000 0- Q - 16" -325- -650 -325 0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 West(-)/East(+)(650 usft/in) HALLIBUPTON Sperry Drilling w.r.dw. Project: Ninilchik Unit Site: Paxton Well: Plan: Paxton#9 Wellbore: Paxton #9 Plan: Paxton#9 wp6 -_ Paxton#3-___ Paxton#9 wp6-- 4011 \ - Paxton-k 4178 / - 2 74 t ✓ Paxton#1 5400— Paxton#9 wp6 \ - Paxton#2 - 5 1/2 '500 400— Paxton#7 2000 �. Paxton#3 I o - 4800— 3000 3000 - 1000 l `Op 7000 - -- ,-C 200— rt Start Dir 2.3°/100':5119.51'MD,2178.85TVD _ pr'r - - - Paxton#8 4200— - e - - o - Start Dir 1°/100':4717.71'MD,2108.76'TVD 8038 0— -- �� 7000 .) ,Paxton#7 - - Paxton#1 3600— c600p _ Paxton#6 Wpl.a 0 'o, P _ I I I I I I I I I I I I I I I I i i r -tr.' r000 -200 0 200 5000 West(-)/East(+)(300 usft/in) 3000— 2000 - Bottom of Fish - ALL)aource ❑ 0 w - 300 Top of Fish 400 2400— 0 o - 0 o, - ,� _ Paxton#2 1800- 30'9996 ,q - 9 5/8" 7 - o - - 1200— 10o0 End Dir :1930.34'MD,1622.67'TVD---- 2000 21r0 Paxton#5 600— Ili _ Start Dir 8°/100':1120'MD,1107.96'TVD_ -- 4.. ^00 Start Dir 2°/100':420'MD,419.87TVDI � 0— ." - 1000 -600— 2000 - 3000 T -1200— M Azimuths to True North - Magnetic North:16.52° - Magnetic Field 4000 Strength:55195.8snT Dip Angle:73.11° -1800— Paxton#6 Wpl.a Date: 11/15/2014 Model:BGGM2013 I 1 I I I I i I I I I 1 I I I I I 1 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I r I i I I I -1800 -1200 -600 0 600 1200 1800 2400 3000 3600 4200 West(-)/East(+)(900 usft/in) Halliburton FIALLIBURTCA Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:Paxton#9 Company: Hilcorp Energy Company TVD Reference: Paxton#9(148.5+18.5)@ 167.00usft Project: Ninilchik Unit MD Reference: Paxton#9(148.5+18.5)@ 167.00usft - Site: Paxton North Reference: True ' Well: Plan:Paxton#9 Survey Calculation Method: Minimum Curvature • Wellbore: Paxton#9 Design: Paxton#9 wp6 Project Ninilchik Unit Map System: US State Plane 1927(Exact solution) • System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Paxton ympli mica ,,,,,,,,,,p,,,,, g1,,,oiiioiiooiiou000iiioiioii IN111IIIIIIIIIIIIIIIIII111MINIIpN111.^.•fes Site Position: Northing: 2,230,587.12 usft Latitude: 60.09599940 From: Map Easting: 206,316.53 usft Longitude: -151.60907766 Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -1.39 ° Well Plan:Paxton#9 mm1mmmmm1mmr, imm9®°wmmmmmnmmmma111mmmmmmna11tm Well Position +N/-S 0.00 usft Northing: 2,230,441.15 usft • Latitude: 60.09559681 +EI-W 0.00 usft Easting: 206,265.74 usft • Longitude: -151.60933637 Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: . 148.50 usft Wellbore Paxton#9 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2013 11/15/2014 16.51 73.11 55,196 Design Paxton#9 wp6 Audit Notes: Version: Phase: PLAN Tie On Depth: 18.50 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 18.50 0.00 0.00 0.00 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/-S +E/-W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (°/100usft) (°/100usft) (°I100usft) (°) 18.50 0.00 0.00 18.50 -148.50 0.00 0.00 0.00 0.00 0.00 0.00 125.00 0.00 0.00 125.00 -42.00 0.00 0.00 0.00 0.00 0.00 0.00 300.00 1.75 340.00 299.97 132.97 2.51 -0.91 1.00 1.00 0.00 340.00 400.00 5.75 340.00 399.74 232.74 8.66 -3.15 4.00 4.00 0.00 0.00 700.00 20.75 340.00 690.92 523.92 73.08 -26.60 5.00 5.00 0.00 0.00 1,371.31 73.18 358.66 1,134.94 967.94 540.79 -78.67 8.00 7.81 2.78 22.33 4,302.59 73.18 358.66 1,983.28 1,816.28 3,345.86 -144.37 0.00 0.00 0.00 0.00 4,554.92 65.00 5.00 2,073.35 1,906.35 3,581.11 -137.21 4.00 -3.24 2.51 145.16 4,804.92 65.00 5.00 2,179.00 2,012.00 3,806.83 -117.46 0.00 0.00 0.00 0.00 6,733.31 26.43 5.00 3,500.15 3,333.15 5,156.27 0.60 2.00 -2.00 0.00 180.00 11/13/2014 11:59:21AM Page 2 COMPASS 5000.1 Build 70 Halliburton HALLIBURTA Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:Paxton#9 Company: Hilcorp Energy Company TVD Reference: Paxton#9(148.5+18.5)@ 167.00usft Project: Ninilchik Unit MD Reference: Paxton#9(148.5+18.5)@ 167.00usft Site: Paxton North Reference: True Well: Plan:Paxton#9 Survey Calculation Method: Minimum Curvature Wellbore: Paxton#9 Design: Paxton#9 wp6 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NI-S +El-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -148.50 18.50 0.00 0.00 18.50 -148.50 0.00 0.00 2,230,441.15 206,265.74 0.00 0.00 80.00 0.00 0.00 80.00 -87.00 0,00 0.00 2,230,441.15 206,265.74 0.00 0.00 16" 100.00 0.00 0.00 100.00 -67.00 0.00 0.00 2,230,441.15 206,265.74 0.00 0.00 125.00 0.00 0.00 125.00 -42.00 0.00 0.00 2,230,441.15 206,265.74 0.00 0.00 125.15 0.00 340.00 125.15 -41.85 0.00 0.00 2,230,441.15 206,265.74 0.00 0.00 Start Dir 1°1100':125'MD,125'TVD 200.00 0.75 340.00 200.00 33.00 0.46 -0.17 2,230,441.62 206,265.58 1.00 0.46 300.00 1.75 340.00 299.97 132.97 2.51 -0.91 2,230,443.68 206,264.89 1.00 2.51 400.00 5.75 340.00 399.74 232.74 8.66 -3.15 2,230,449.88 206,262.80 4.00 8.66 420.15 6.76 340.00 419.77 252.77 10.72 -3.90 2,230,451.96 206,262.10 5.00 10.72 Start Dir 2°/100':420'MD,419.87'TVD 500.00 10.75 340.00 498.67 331.67 22.14 -8.06 2,230,463.47 206,258.22 5.00 22.14 600.00 15.75 340.00 595.98 428.98 43.67 -15.89 2,230,485.19 206,250.91 5.00 43.67 700.00 20.75 340.00 690.92 523.92 73.08 -26.60 2,230,514.86 206,240.93 5.00 73.08 750.00 24.50 343.67 737.07 570.07 91.36 -32.55 2,230,533.28 206,235.43 8.00 91.36 800.00 28.31 346.40 781.84 614.84 112.84 -38.25 2,230,554.89 206,230.25 8.00 112.84 850.00 32.16 348.53 825.04 658.04 137.41 -43.69 2,230,579.59 206,225.41 8.00 137.41 900.00 36.04 350.25 866.43 699.43 164.96 -48.82 2,230,607.25 206,220.95 8.00 164.96 950.00 39.95 351.68 905.83 738.83 195.36 -53.64 2,230,637.75 206,216.87 8.00 195.36 1,000.00 43.86 352.89 943.04 776.04 228.44 -58.11 2,230,670.94 206,213.21 8.00 228.44 1,050.00 47.79 353.93 977.87 810.87 264.06 -62.21 2,230,706.65 206,209.97 8.00 264.06 1,100.00 51.73 354.86 1,010.16 843.16 302.04 -65.93 2,230,744.71 206,207.18 8.00 302.04 1,120.15 53.32 355.20 1,022.42 855.42 317.97 -67.32 2,230,760.67 206,206.19 8.00 317.97 Start Dir 8°l100':1120'MD,1107.961VD 1,150.00 55.67 355.69 1,039.76 872.76 342.19 -69.24 2,230,784.93 206,204.85 8.00 342.19 1,200.00 59.62 356.44 1,066.51 899.51 384.32 -72.13 2,230,827.12 206,202.99 8.00 384.32 1,250.00 63.58 357.14 1,090.29 923.29 428.23 -74.59 2,230,871.07 206,201.60 8.00 428.23 1,300.00 67.53 357.79 1,110.97 943.97 473.69 -76.60 2,230,916.56 206,200.70 8.00 473.69 1,350.00 71.49 358.41 1,128.47 961.47 520.49 -78.15 2,230,963.39 206,200.29 8.00 520.49 1,371.31 73.18 358.66 1,134.94 967.94 540.79 -78.67 2,230,983.70 206,200.26 8.00 540.79 1,400.00 73.18 358.66 1,143.24 976.24 568.24 -79.31 2,231,011.16 206,200.29 0.00 568.24 1,500.00 73.18 358.66 1,172.18 1,005.18 663.94 -81.55 2,231,106.88 206,200.38 0.00 663.94 1,600.00 73.18 358.66 1,201.12 1,034.12 759.63 -83.79 2,231,202.60 206,200.47 0.00 759.63 1,700.00 73.18 358.66 1,230.07 1,063.07 855.33 -86.03 2,231,298.32 206,200.56 0.00 855.33 1,800.00 73.18 358.66 1,259.01 1,092.01 951.02 -88.28 2,231,394.04 206,200.65 0.00 951.02 1,900.00 73.18 358.66 1,287.95 1,120.95 1,046.72 -90.52 2,231,489.76 206,200.74 0.00 1,046.72 1,930.49 73.18 358.66 1,296.77 1,129.77 1,075.89 -91.20 2,231,518.94 206,200.76 0.00 1,075.89 End Dir :1930.34'MD,1622.6T TVD 2,000.00 73.18 358.66 1,316.89 1,149.89 1,142.41 -92.76 2,231,585.48 206,200.83 0.00 1,142.41 2,100.00 73.18 358.66 1,345.83 1,178.83 1,238.10 -95.00 2,231,681.20 206,200.91 0.00 1,238.10 2,200.00 73.18 358.66 1,374.77 1,207.77 1,333.80 -97.24 2,231,776.92 206,201.00 0.00 1,333.80 2,300.00 73.18 358.66 1,403.71 1,236.71 1,429.49 -99.48 2,231,872.64 206,201.09 0.00 1,429.49 9 5/8" 2,400.00 73.18 358.66 1,432.65 1,265.65 1,525.19 -101.72 2,231,968.36 206,201.18 0.00 1,525.19 11/13/2014 11:59:21AM Page 3 COMPASS 5000.1 Build 70 Halliburton HALLIBURTA Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:Paxton#9 Company: Hilcorp Energy Company -;TVD Reference: Paxton#9(148.5+18.5)@ 167.00usft Project: Ninilchik Unit MD Reference: Paxton#9(148.5+18.5)@ 167.00usft Site: Paxton North Reference: True Well: Plan:Paxton#9 Survey Calculation Method: Minimum Curvature Wellbore: Paxton#9 Design: Paxton#9 wp6 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/S +E/-W Northing Easting DLS Vert Section (usft) (0) (0) (usft) usft (usft) (usft) (usft) (usft) 1,267.00 2,404.66 73.18 358.66 1,434.00 1,267.00 1,529.65 -101.83 2,231,972.82 206,201.19 0.00 1,529.65 Top Beluga 2,500.00 73.18 358.66 1,461.59 1,294.59 1,620.88 -103.97 2,232,064.08 206,201.27 0.00 1,620.88 2,600.00 73.18 358.66 1,490.53 1,323.53 1,716.58 -106.21 2,232,159.80 206,201.36 0.00 1,716.58 2,700.00 73.18 358.66 1,519.47 1,352.47 1,812.27 -108.45 2,232,255.52 206,201.45 0.00 1,812.27 2,800.00 73.18 358.66 1,548.42 1,381.42 1,907.97 -110.69 2,232,351.24 206,201.54 0.00 1,907.97 2,900.00 73.18 358.66 1,577.36 1,410.36 2,003.66 -112.93 2,232,446.96 206,201.63 0.00 2,003.66 3,000.00 73.18 358.66 1,606.30 1,439.30 2,099.35 -115.17 2,232,542.68 206,201.72 0.00 2,099.35 3,100.00 73.18 358.66 1,635.24 1,468.24 2,195.05 -117.41 2,232,638.40 206,201.81 0.00 2,195.05 3,200.00 73.18 358.66 1,664.18 1,497.18 2,290.74 -119.66 2,232,734.12 206,201.90 0.00 2,290.74 3,300.00 73.18 358.66 1,693.12 1,526.12 2,386.44 -121.90 2,232,829.84 206,201.99 0.00 2,386.44 3,400.00 73.18 358.66 1,722.06 1,555.06 2,482.13 -124.14 2,232,925.56 206,202.07 0.00 2,482.13 3,500.00 73.18 358.66 1,751.00 1,584.00 2,577.83 -126.38 2,233,021.28 206,202.16 0.00 2,577.83 3,600.00 73.18 358.66 1,779.94 1,612.94 2,673.52 -128.62 2,233,117.00 206,202.25 0.00 2,673.52 3,700.00 73.18 358.66 1,808.88 1,641.88 2,769.21 -130.86 2,233,212.72 206,202.34 0.00 2,769.21 3,800.00 73.18 358.66 1,837.82 1,670.82 2,864.91 -133.10 2,233,308.44 206,202.43 0.00 2,864.91 3,900.00 73.18 358.66 1,866.77 1,699.77 2,960.60 -135.35 2,233,404.16 206,202.52 0.00 2,960.60 4,000.00 73.18 358.66 1,895.71 1,728.71 3,056.30 -137.59 2,233,499.89 206,202.61 0.00 3,056.30 4,100.00 73.18 358.66 1,924.65 1,757.65 3,151.99 -139.83 2,233,595.61 206,202.70 0.00 3,151.99 4,200.00 73.18 358.66 1,953.59 1,786.59 3,247.69 -142.07 2,233,691.33 206,202.79 0.00 3,247.69 4,302.59 73.18 358.66 1,983.28 1,816.28 3,345.86 -144.37 2,233,789.53 206,202.88 0.00 3,345.86 4,400.00 69.99 1.03 2,014.05 1,847.05 3,438.26 -144.64 2,233,881.91 206,204.86 4.00 3,438.26 4,500.00 66.76 3.56 2,050.90 1,883.90 3,531.13 -140.95 2,233,974.66 206,210.81 4.00 3,531.13 4,554.92 65.00 5.00 2,073.35 1,906.35 3,581.11 -137.21 2,234,024.53 206,215.76 4.00 3,581.11 4,600.00 65.00 5.00 2,092.40 1,925.40 3,621.81 -133.65 2,234,065.13 206,220.31 0.00 3,621.81 4,700.00 65.00 5.00 2,134.66 1,967.66 3,712.10 -125.75 2,234,155.20 206,230.41 0.00 3,712.10 4,705.54 65.00 5.00 2,137.00 1,970.00 3,717.10 -125.32 2,234,160.19 206,230.97 0.00 3,717.10 Beluga 50 4,717.86 65.00 5.00 2,142.21 1,975.21 3,728.22 -124.34 2,234,171.29 206,232.21 0.00 3,728.22 Start Dir 1°/100':4717.71'MD,2108.76'TVD 4,804.92 65.00 5.00 2,179.00 2,012.00 3,806.83 -117.46 2,234,249.70 206,241.00 0.00 3,806.83 4,900.00 63.10 5.00 2,220.60 2,053.60 3,891.99 -110.01 2,234,334.66 206,250.52 2.00 3,891.99 5,000.00 61.10 5.00 2,267.40 2,100.40 3,980.02 -102.31 2,234,422.48 206,260.37 2.00 3,980.02 5,100.00 59.10 5.00 2,317.25 2,150.25 4,066.38 -94.76 2,234,508.62 206,270.02 2.00 4,066.38 5,119.66 58.71 5.00 2,327.40 2,160.40 4,083.15 -93.29 2,234,525.35 206,271.90 2.00 4,083.15 Start Dir 2.3°/100':5119.51'MD,2178.85'TVD 5,200.00 57.10 5.00 2,370.09 2,203.09 4,150.94 -87.36 2,234,592.98 206,279.48 2.00 4,150.94 5,300.00 55.10 5.00 2,425.86 2,258.86 4,233.62 -80.12 2,234,675.46 206,288.72 2.00 4,233.62 5,380.76 53.48 5.00 2,473.00 2,306.00 4,298.95 -74.41 2,234,740.63 206,296.02 2.00 4,298.95 Belgua 60 5,400.00 53.10 5.00 2,484.50 2,317.50 4,314.31 -73.07 2,234,755.96 206,297.74 2.00 4,314.31 5,500.00 51.10 5.00 2,545.93 2,378.93 4,392.92 -66.19 2,234,834.37 206,306.53 2.00 4,392.92 5,600.00 49.10 5.00 2,610.07 2,443.07 4,469.34 -59.50 2,234,910.60 206,315.08 2.00 4,469.34 5,700.00 47.10 5.00 2,676.85 2,509.85 4,543.48 -53.02 2,234,984.56 206,323.37 2.00 4,543.48 5,800.00 45.10 5.00 2,746.19 2,579.19 4,615.25 -46.74 2,235,056.16 206,331.39 2.00 4,615.25 11/13/2014 11:59:21AM Page 4 COMPASS 5000.1 Build 70 Halliburton HALLIBURTIA Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:Paxton#9 Company: Hilcorp Energy Company TVD Reference: Paxton#9(148.5+18.5)@ 167.00usft Project: Ninilchik Unit MD Reference: Paxton#9(148.5+18.5)@ 167.00usft Site: Paxton North Reference: True Well: Plan:Paxton#9 Survey Calculation Method: Minimum Curvature Wellbore: Paxton#9 Design: Paxton#9 wp6 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 2,651.00 5,900.00 43.10 5.00 2,818.00 2,651.00 4,684.57 -40.67 2,235,125.32 206,339.14 2.00 4,684.57 6,000.00 41.10 5.00 2,892.20 2,725.20 4,751.36 -34.83 2,235,191.94 206,346.61 2.00 4,751.36 6,100.00 39.10 5.00 2,968.69 2,801.69 4,815.52 -29.22 2,235,255.94 206,353.78 2.00 4,815.52 6,200.00 37.10 5.00 3,047.38 2,880.38 4,876.98 -23.84 2,235,317.26 206,360.66 2.00 4,876.98 6,300.00 35.10 5.00 3,128.18 2,961.18 4,935.67 -18.70 2,235,375.81 206,367.22 2.00 4,935.67 6,400.00 33.10 5.00 3,210.98 3,043.98 4,991.52 -13.82 2,235,431.52 206,373.46 2.00 4,991.52 6,500.00 31.10 5.00 3,295.69 3,128.69 5,044.45 -9.19 2,235,484.32 206,379.38 2.00 5,044.45 6,600.00 29.10 5.00 3,382.20 3,215.20 5,094.41 -4.82 2,235,534.15 206,384.97 2.00 5,094.41 6,700.00 27.10 5.00 3,470.41 3,303.41 5,141.32 -0.71 2,235,580.96 206,390.21 2.00 5,141.32 6,733.31 26.43 5.00 3,500.15 . 3,333.15 5,156.27 0.60 2,235,595.86 206,391.88 2.00 5,156.27 1 Targets Target Name I -hit/miss target Dip Angle Dip Dir. TVD +NI-S +E!-W Northing Easting -Shape (°) (°) (usft) (usft) (usft) (usft) (usft) Pax#9 wp3_BIg50 ti, 0.00 0.00 2,179.00 3,806.83 -117.46 2,234,249.70 206,241.00 -plan hits target center -Circle(radius 100.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 80.00 80.00 16" 16 16 2,300.00 1,403.71 9 5/8" 9-5/8 12-1/4 6,733.31 3,500.15 5 1/2" 5-1/2 8-1/2 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology (1 (°) 2,404.66 1,434.00 Top Beluga 0.00 4,705.54 2,137.00 Beluga 50 0.00 5,380.76 2,473.00 Belgua 60 0.00 11/13/2014 11:59:21AM Page 5 COMPASS 5000.1 Build 70 Halliburton HALLIBURT011 Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:Paxton#9 Company: Hilcorp Energy Company TVD Reference: Paxton#9(148.5+18.5)@ 167.00usft Project: Ninilchik Unit MD Reference: Paxton#9(148.5+18.5)@ 167.00usft Site: Paxton North Reference: True Well: Plan:Paxton#9 Survey Calculation Method: Minimum Curvature Wellbore: Paxton#9 Design: Paxton#9 wp6 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 125.15 125.15 0.00 0.00 Start Dir 1°/100':125'MD,125'TVD 420.15 419.77 10.72 -3.90 Start Dir 2°/100':420'MD,419.87'TVD 1,120.15 1,022.42 317.97 -67.32 Start Dir 8°/100':1120'MD,1107.96'TVD 1,930.49 1,296.77 1,075.89 -91.20 End Dir :1930.34'MD,1622.67'TVD 4,717.86 2,142.21 3,728.22 -124.34 Start Dir 1°/100':4717.71'MD,2108.76'TVD 5,119.66 2,327.40 4,083.15 -93.29 Start Dir 2.3°/100':5119.51'MD,2178.85'TVD 7,421.27 Total Depth:7421.13'MD,3500'TVD 11/13/2014 11:59:21AM Page 6 COMPASS 5000.1 Build 70 N I t L at Of c ML J J >' 4 L L ai I a W 0 m 0 .0 a NM N C U E C f. 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N C� N Z a 0 P.. - 1:543 19 o - o L Is N - - L y ,, i -@o n - o p CO C I- 0 0 .O Q.11 0 0 J N m v _ E _0 iii y o a Ikkkk � kkkklkkkklkikilkikklkikk kV� i o Q v o 0 0 0 0 0 0 0 0 0 0 o Z V C o 0 0 0 0 0 0 0 0 0 0 0 L o 6i W f� o cn M N O C .3 Q U (w/ 05'Z) _locoed uoi;eiedes TRANSMITTAL LETTER CHECKLIST 7-7 WELL NAME: PTD: ZR /Development Service Exploratory Stratigraphic Test Non-Conventional FIELD: �!'4 f /i`1 L POOL: 40. t 6 t:;7 maw Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL The permit is for a new wellbore segment of existing well Permit (If last two digits No. , API No. 50- - - - in API number are Production should continue to be reported as a function of the original between 60-69) API number stated above. In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name Pilot Hole ( PH) and API number (50- - - - ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce / inject is contingent upon issuance of a Spacing Exception conservation order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for Non-Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are Well Lo ,n also required for this well: gg g Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. vy Revised 4/2014 /(7 i ;� El El r 1F5 a co , , 4 0 L , , , , . , , , , , , , , , , , a If) c a) o) c ; . ; . y .o' as E os rna M. r. E CO o. n .0 Q 0 O , U .N uj. � 0 , , CO. C c . , , 0 •pY , o , � , p, O E , a 'o O 5' va 0 , c' , c a z O a - o. 2i 4 a o o "' v �; 0 X Oo j a. OO N, fp 2 , o, • a. , ICY , p, C vA 0) j N, N. a •C 0 , i' 0 , a, , O -.. co d O Cl 0 >' O C 1. Is. DI ( p, ; O' uuyy ,,, i . . , , , a m; ; 0,0, o' ; v, a .N ; m; a0 , ; o 'c' 2, a N, a 03 E a' °3 a' Y co a ca � m E; o o 0 m, 0) COi o a $ 70 Z CO L o ° ; , ; ; 0; y 4 Q. gay v y' `r; 3. o. 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Ty a, a, >, .� a L a . u) a. L. p aY C, E. �1 0 a E a,, ' N, :?' 0, -a 0 L, E' c, . m, 3, c. aa) m m, 0 o' m' T 0) 01 0 .� a �; c. 2' E, ° a 0 3, 0, 0 0 �, �, R, R E, ... 1:2 > 0 0 _, v, a; - a� v m m' c c�� m cg U '. c 0 0 0 0 0 0 0' 0 v, o n E' a c 0' p2' 0 (n J ' a O' O' O d N ._+ «' a o . 0 U a, O, O, lG , l0, C. va 3, O, C? CD, 0. , CA 'j is Cy. a , 0. Q U -00 N > > �' C a 7 a, C w. w. Y y .0 [1 E, �, c„a 2 a J i E; ' o- a. d m' ` , a a`, a. E; E; c, �, 3, a, c c 't 1; 1- H. 'w, a (, V > _ a a o o, a 0, E g a,, m c, 0 a, c 0 a a a a a 0, o, o, 0, 2, 2 2 0, v 0 v, ''0 •c; O' O' L, a o 5 0_, - D 5 5' 5; Cl),,w 0 o; n.; a; 0, 5, a 0- Z, 0, co, 0,, 0,, 0, 0, < w, <, '�, 0, m, m, 0, 5' y, a, 0, Cl), v), 0,, o W a --- = E N co -ct 0 O N- co coO `- N M -� W� N N N M 74 1N CON Nn CNO N O M M`c,%4 M �M CM COM fM CMb MC) VO - ...---- ---V I V a c� i Ey N C p C �' 0 � w N tea-' O U CO Wco O f6 V R co V' a) U) r_ ..C. 0 c- C G a- 0 a- 0 0 H J N '- a CA (7 E J #t c 0 0 w aIE a C qo 0 n U 0_ Q Q w Q 1 Q • \ //7: THE STATE liEE el C> ilid GSE -• � � TA f 7 777-_ A :2;;; ; “n] .l'�'�I -I J F F 1- .i 1 i i ___ — -- 333 West Seventh Avenue (;05'1'RNOR SENIP \RN111, Anchorage Alaska 99501-3572 Main 907 279 1433 r 0, chi/ ;/6 7522 Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga/Tyonek Pool, Paxton#9 Hilcorp Alaska, LLC Permit No: 214-173 Surface Location: 3051' FEL, 917' FNL, SEC. 13, T1S, R14W, SM, AK Bottomhole Location: 337' FNL, 2068' FWL, SEC. 12, T1S, R14W, SM, AK Dear Mr. Keller: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, 0 / Daniel T. Seamount, Jr. Commissioner DATED this / day of November, 2014. HECEIVEU STATE OF ALASKA OCT 2 1 2014 A it OIL AND GAS CONSERVATION COMA N PERMIT TO DRILL �1��C 20 AAC 25.005 1 a.Type of Work. 1 b.Proposed Well Class. Development-Oil ❑ Service- Winj ❑ Single Zone 0 . 1 c.Specify if well is proposed for: Drill 0• Lateral 0 Stratigraphic Test 0 Development-Gas 0 • Service-Supply 0 Multiple Zone ❑ Coalbed Gas 0 Gas Hydrates 0 Redril 0 Reentry 0 Exploratory 0 Service- WAG 0 Service-Disp 0 Geothermal 0 Shale Gas 0 2.Operator Name: 5. Bond. Blanket 0 Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC Bond No. 022035244 . Paxton#9 • 3.Address: 6.Proposed Depth: 12.Field/Pool(s). 3800 Centerpoint Drive Ste 1400,Anchorage AK 99503 MD: 7,376' TVD: 3,500' . Ninilchik Field 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Beluga/Tyonek Gas Pool . Surface: 3051'FEL,917'FNL,Sec 13,T1 S,R14W,SM,AK ' ADL384372 . Top of Productive Horizon. 8.Land Use Permit: 13.Approximate Spud Date: 1 713'F..(.d 2.i sk I l)L. 12-O/ " /4/0 Surface agreement w/parcel fee owner 11/14/2014 Total Depth: / 9.Acres in Property: 14.Distance to Nearest Property: 337 FA 74, _ iJ FL: c., 1 z-c4." I'.42, 3507.84(ADL 384372) 5470'to nearest unleased tract 4b.Location of Well(State Base Plane Coordinates-NAD 27):Mj.ai i10.KB Elevation above MSL: . 166.6 feet 15.Distance to Nearest Well Open Surface: x-206273.5 . y-2230447 Zone-4 GL Elevation above MSL: 148 feet to Same Pool: 2658'to Paxton 4 16.Deviated wells: Kickoff depth: 251 feet 17 Maximum Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 73 degrees Downhole 1505 psi Surface:1155 psi 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Cond 16" 109 X-56 Weld 80' Surf Surf 80' 80' Driven 12-1/4" 9-5/8" 40 L-80 BTC 2,700' Surf Surf 2,700'. 1,869' 174 bbl 12.5#lead,67 bbl 15.2#tail 8-1/2" 5-1/2" 17 P-110 CDC 7,376' Surf Surf 7,376' 3,500' 145 bbl 13.5#lead, 126 bbl 15.2#tail 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth ND(ft): Plugs(measured): Effect.Depth MD(ft). Effect.Depth TVD(ft): Junk(measured): Casing Length Size Cement Volume MD ND Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth ND(ft): 20. Attachments: Property Plat 0 BOP Sketch 0 Drilling Program 0 Time v.Depth Plot 0 Shallow Hazard Analysis Diverter Sketch 0 Seabed Report 0 Drilling Fluid Program 0 20 AAC 25.050 requirements0 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. Contact Luke Keller Email Ikeller ac hilcorp.com Printed Name Luke Keller Title Drilling Engineer Signature /:L/ Phone 907-777-8395 Date 10/20/2014 Commission Use Only Permit to Drill _, API Number: `/ Z Permit Approval See cover letter for other Number: /e l7 50153--.2 C:Y 7" J40 Date: 1101 /1 requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained in shales: 12( Other: 5CC--1 lob, 6 C In 1-' Samples req'd: Yes❑ Nod Mud log req'd:Yes 0 No Er H2S measures: Yes 0 No[sE Directional svy req'd:Yes Q No❑ / Spacing exception req'd: Yes❑ No 1 Inclination-only svy req'd.Yes 0 No RI' .F- S i 0 LA l' rC_ u-L;ick c 1 l d A f APPROVED BY � � y Approved b . ' COMMISSIONER THE COMMISSION Date: l L ` '" ' �eR rt i *Anf SubmitnForm and Form 10-4 Revised 10/2012) T s t fs from the date of approval(20 AAC 25.005( Attachments Duplicate • Luke Keller Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Anchorage,AK 99524-4027 Tel 907 777 8395 Email Ikeller©hilcorp.com Hilrorp Alaska,LLC August20, 2014 RECEIVED OCT 212014 Commissioner �� Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 Re: Paxton#9 Dear Commissioner, Enclosed for review and approval is the application for the Permit to Drill the Paxton#9 Development gas well. Paxton#9 is a twin to the Paxton 3 Beluga 50 gas sandstone and a follow up to the Paxton#7 which did not reach the intended targets due to a stuck BHA. The base plan is an S-turn wellbore with a shallow kickoff at 150' MD, building up to a maximum inclination of 80 deg, then dropping back to 33 degrees by TD. Drilling operations are expected to commence approximately November 14th, 2014. The Saxon Rig# 147 will be used to drill and complete the wellbore. A separate 10-403 sundry will be submitted prior to completion operations. The 10-401 PTD covers all operations up to running and cementing the 5-1/2" long string. If you have any questions, please don't hesitate to contact myself at 777-8395 or Paul Mazzolini at 777-8369. Sincerely, r c_ Luke Keller Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 HilcorpAlaska , LLC Paxton #9 Drilling & Completion Program Ninilchik Field Version 1 October 16th, 2014 Paxton #9 Drilling Procedure Bilrorp Alaska,LLC Contents 1.0 Well Summary 2 2.0 Management of Change Information 3 3.0 Tubular Program: 4 4.0 Drill Pipe Information: 4 5.0 Internal Reporting Requirements 5 6.0 Planned Wellbore Schematic 6 7.0 Drilling/Completion Summary 7 8.0 Mandatory Regulatory Compliance/Notifications 8 9.0 R/U and Preparatory Work 10 10.0 N/U 21-1/4"2M Diverter 11 11.0 Drill 12-1/4"Hole Section 14 12.0 Run 9-5/8" Surface Casing 18 13.0 Cement 9-5/8" Surface Casing 21 14.0 BOP N/U and Test 24 15.0 Drill 8-1/2"Hole Section 25 16.0 Run 5-1/2"Production Casing 30 17.0 Cement 5-1/2"Production Casing 33 18.0 Completion Operations 36 19.0 BOP Schematic 37 20.0 Wellhead Schematic 38 21.0 Days Vs Depth 39 22.0 Formation Tops 40 23.0 Anticipated Drilling Hazards 41 24.0 Saxon Rig 147 Layout 43 25.0 FIT Procedure 44 26.0 Choke Manifold Schematic 45 27.0 Casing Design Information 46 28.0 8-1/2"Hole Section MASP 47 29.0 Spider Plot(NAD 27) (Governmental Sections) 48 30.0 Surface Plat(As Staked) (NAD 27) 49 31.0 Offset MW vs TVD Chart 50 32.0 Drill Pipe Specification Sheet 51 Paxton #9 Drilling & Completion Procedure Ililrorp Ala'.ka.1.I,f 1.0 Well Summary Well Paxton#9. Pad&Old Well Designation Paxton#9 is a grass roots well on the Paxton Pad. 2-7/8"Production tubing, SCSSV at 150', CIM above Planned Completion Type packer. Target Reservoir(s) Beluga/Tyonek. Planned Well TD,MD/TVD 7,376' MD/3,500' TVD. PBTD, MD/TVD 7,250' MD/3,397' TVD. Surface Location(Governmental) 3051'FEL, 917'FNL, Sec 13, T1S,R14W, SM,AK Surface Location(NAD 27) X=206273.5,Y=2230447 Surface Location(NAD 83) Top of Productive Horizon (Governmental) 1713'FSL,2144'FWL, Sec 12, T1S,R14W, SM,AK TPH Location(NAD 27) X=206252.1,Y=2232988.88 TPH Location(NAD 83) BHL(Governmental) 337'FNL,2068'FWL, Sec 12,T1S,R14W, SM,AK BHL(NAD 27) X=206253.95,Y=2236220.06 BHL(NAD 83) AFE Number AFE Drilling Days 4 MOB,20 Drlg AFE Completion Days AFE Drilling Amount AFE Completion Amount Maximum Anticipated Pressure (Surface) 1505 psi(Drilling) Maximum Anticipated Pressure (Downhole/Reservoir) 1155 psi Work String 4-1/2" 16.6# S-135 CDS-40(Saxon Owned String) KB elevation above MSL 18.6' + 148' = 166.6' GL elevation above MSL 148' BOP Equipment 11" 5M T3-Energy Annular BOP 11" 5M T3-Energy Double Ram 11" 5M T3-Energy Single Ram Page 2 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Hilcorp Alnaka,LLC 2.0 Management of Change Information Hilcorp Alaska, LLC Hilcorp Changes to Approved Permit to Drill Date: Subject Changes to Approved Permit to Drill for Paxton #9 File#: Paxton#9 Drilling and Completion Program Any modifications to Drilling&Completion Program will be documented and approved below. Changes to an approved APD will be C e AOGCC. p Y o c,t_.�C. ."4" ea,.2..=f/54 Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Hiirorp Alaska, 3.0 Tubular Program: j Hole OD (in) ID (in) Drift Conn Wt Grade Conn Burst Collapse Tension Section ; (in) OD (in) (#/ftp (psi) (psi) (k-lbs) Cond 16" 15" - - 109 X-56 Weld 12-1/4" 9-5/8" 8.835" 8.75" 10.625" 40 L-80 BTC 5750 3090 916 8-1/2" 5-1/2" 4.892" 4.767" 6.05" 17 P-110 CDC 10640 7480 546 4.0 Drill Pipe Information: Hole OD (in) ID (in) TJ ID TJ OD Wt Grade Conn Burst Collapse Tension Section (in) _ (in) (#/ft) (psi) (psi) (k-lbs) All 4.5" 3.826 2.6875" 5.25" 16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100%mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Version 1 July,2014 Paxton #9 Drilling & Completion Procedure llilrorp Ala'.ka.LLC. 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area—this will not save the data entered,and will navigate to another data entry tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, Ikeller@hilcorp.com andjbarrett@hilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a username to login with. 5.4 EHS Incident Reporting • Notify EHS field coordinator. 1. This could be one of(3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don't wait until an emergency to have to call around and figure it out!!!! a. John Coston: 0: (907) 777-6726 C: (907)227-3189 b. Mark Tornai: 0: (907)283-1372 C: (907)748-3299 c. Thad Eby: 0: (907)777-8317 C: (907)602-5178 2. Spills: Kate Kaufman: 0:907-777-8329 C:907-244-8292 • Notify Drlg Manager 1. Paul Mazzolini: 0: 907-777-8369 C: 907-317-1275 • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final"As-Run"Casing tally to Ikeller@hilcorp.com and jbarrett@hilcorp.com 5.6 Casing and Cmt report • Send casing and cement report for each string of casing to lkeller@hilcorp.com and jbarrett@hilcorp.com Page 5 Version 1 July,2014 II Paxton #9 Drilling & Completion Procedure Iiiirorp Ala,ka,1,1,1' 6.0 Planned Wellbore Schematic CASING DETAIL if- • ti; ;I,r b,- - r 1 Size —.ice Wt Grade Conn. ID To; B.:— Conductor— 16" Driven to Set 109 X-56 Weld 16" Surf 80.' Al°. Depth „C:' '' 9-5/8" Surf.Csg 40 L-8.0 BTC 8.835" Surf 2700' 5-1/2" Prod Casing 17 P-110HC DQX 4.892" Surf 7,376 1', 1 itt "I' '4. .' TUBING 2-7/8" Production 6.4 L-80 IBT 2.441" Surf 4000' 9-5 S" shoe * '"., ,4 - Drilling into I ' I-ole Section Casing NeW 'Norkstring zzoo 12-1/4" 9-5/8" 8.8 ppg 4-1/2" 8-1/2" 5-1/2" 9.5 ppg 4-1/2" 0 41bt.41Al JEWELRY DETAIL No. Depth ID CD Item fi- 1,- "lot,;(* slk, 1 150' SCSSV 2 2000' CIM 7 * 3 _ 2200' Prod Pkr 8-112" 4:4 '''" Hole - 4 2220' Wireline re-entry guide $141ii 1 kr*? 4 A3 1 m, i , -A, k .,,.. ' 4 I Planned Reservoir Objectives Zone Top(NT) Top i7VD) Est Pressure EMW Gradient Ft ;el, Beluga 50 4,524 2140 920.2 8.3 0.43 Beluga 60 4,987 2476 1064.68 8.3 0.43 L 1,,t-vi prittfid ' *•t. ;be":', ' 5.5" 1.44et i shoe 7"..., r'il.E474 , .....w.,e. ' ,..-7, . k., . - PBTD=7,250 All)13,397'TVD ID=7,376'NM 13,500'TVD Page 6 Version 1 July, 2014 14Paxton #9 Drilling & Completion Procedure 11 ilrnrp Alaska,LLC 7.0 Drilling / Completion Summary Paxton#9 is a twin to the Paxton 3 Beluga 50 gas sandstone and a follow up to the Paxton#7 which did not reach the intended targets due to a stuck BHA. The base plan is an S-turn wellbore with a shallow kickoff at 150' MD,building up to a maximum inclination of 80 deg,then dropping back to 33 degrees by TD. Drilling operations are expected to commence approximately Nov 14th, 2014. ' The Saxon Rig# 147 will be used to drill and case the wellbore with the 5-1/2"long string. All known potential fresh water zones exist above 200'. This information is based off salinity calculations of neighboring water wells. Chlorides are 1100 ppm at the 171 — 194' sand, 1800 ppm at the 505 — 535' sand, and 6000 ppm at the 1040' sand. Furthermore, the TGAS (total gas) curve from offset mud logs begins registering shallow gas at depths just below the sandstone bed at 200'. Surface casing will be run to 2,700' MD/ 1,869' TVD and cemented to surface to ensure protection of these resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6 — 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal/beneficial reuse depending on test results. General sequence of operations: 1. MOB Saxon Rig# 147 to well site. 2. N/U 21-1/4"x 2M diverter. 3. Drill 12-1/4"hole to 2700' MD. Run and cmt 9-5/8" surface casing. 4. N/D diverter,N/U &test 11"x 5M T3-Energy BOP. 5. Drill 8-1/2"hole section to TD. Run and cmt 5-1/2"production long string. 6. Complete well per separate sundry.. <.._j -r°c- 7. N/D BOP,N/U tree, RDMO. Reservoir Evaluation Plan: 1. Surface hole: Mud logging, GR+Res LWD 2. Production Hole: Mud Logging,GR+Res LWD. Page 7 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Rilcorp Alaska,LLC 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of Paxton #9. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 5/5 min(annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements" • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • No variance requests at this time. Page 8 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Hilrorp tla.ka.1.I,C Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 12-1/4" • 21-1/4"x 2M Hydril MSP diverter Function Test Only • 11"x 5M T3-Energy(Model 7082)Annular BOP • 11"x 5M T3-Energy Double Ram Initial Test:250/3500 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross 8 1/2" • 11"x 5M T-3 Energy Single Ram • 3-1/8"5M Choke Line Subsequent Tests: • 2-1/16"x 5M Kill line 250/3500 • 3-1/8"x 2-1/16"5M Choke manifold (Annular 2500 psi) • Standpipe,floor valves,etc • Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon(12 x 11 gal bottles). • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: • Well control event(BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email: iim.regg(a,alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-301-4533 /Email: guy.schwartz@alaska.gov Victoria Ferguson/Petroleum Engineer/(0): 907-793-1247/Email: Victoria.ferguson@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors(cr�,alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone: 907-793-1236(During normal Business Hours) Notification/Emergency Phone: 907-659-2714(Outside normal Business Hours) Page 9 Version 1 July, 2014 Paxton#9 Drilling & Completion Procedure Ri!carp Alaska.LLC 9.0 R/U and Preparatory Work 9.1 Set 16" conductor at 60' below ground level. ' 9.2 Dig out and set impermeable cellar. 9.3 Install Seaboard slip-on 16-3/4" 3M "A" section. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Saxon Rig# 147, spot service company shacks, spot & R/U company man&toolpusher offices. 9.7 Mud loggers ARE required on the surface hole section. 9.8 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.9 Mix mud for 12-1/4"hole section. 9.10 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.11 Install 5-1/2" liners in mud pumps. • TSM 1000 mud pumps are rated at 3633 psi (85%)/ 333 gpm (100%) with 5-1/2" liners. ✓' Page 10 Version 1 July,2014 Paxton #9 Drilling & Completion Procedure Hilcorp Alaska,LLC 10.0 N/U 21-1/4" 2M Diverter 10.1 N/U 21-1/4" Hydril MSP 2M diverter System. • N/U 16-3/4" 3M x 21-1/4" 2M DSA (Hilcorp) on 16-3/4" 3M wellhead. • N/U 21-1/4" diverter"T". • Knife gate, 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C)which states: (1)the diverter system must consist of a remotely operated annular pack-off device, a full-opening vent line valve, and a diverter vent line with a diameter (A)of at least 16 inches, unless a smaller diameter is approved by the commission to account for smaller hole size, geological conditions,rig layout, or surface facility constraints; and (B)at least as large as the diameter of the hole to be drilled,unless a pilot hole with a diameter no larger than that of the vent line is drilled first; the commission will waive the requirement of this paragraph if the operator demonstrates, based on drilling experience in the near vicinity, that drilling a pilot hole would not be necessary for safety; (2)the diverter system must be assembled as follows: (A)the diverter vent line outlet must be located below the annular pack-off, either as an integral part of the annular pack-off device or as a vent-line outlet spool immediately below it; (B)the actuating mechanism for the vent line valve must be integrated with the actuating mechanism for the annular pack-off device in a fail-safe manner so that the vent line valve automatically opens before full closure of the annular pack-off; (C)the vent line must extend to a point at least 75 feet (i)away from a potential source of ignition;and (ii)beyond the drill rig substructure, or to a point within the reserve pit and at least 50 feet beyond the drill rig substructure; (D)the vent line must be as straight as possible,secured to prevent movement,and designed to avoid freeze-up; (E) the vent line may be secured to the rig and with portable cradle supports, but may not be attached to flowlines, cable trays,or other processing equipment; (F)all turns with a bend radius less than 20 times the inside diameter of the vent line must be targeted; (G)all valves must be full-opening; (3) a clearly marked "warning zone" must be established on each side and ahead of the vent line tip, and the following restrictions must be in effect within the warning zone, beginning with the function test of the diverter system immediately before drilling operations begin and ending with diverter system rig-down: (A)a prohibition on vehicle parking; (B)a prohibition on ignition sources or running equipment; (C)a prohibition on staged equipment or materials; (D)the restriction of traffic to essential foot or vehicle traffic only; (4) the commission will, in its discretion, inspect the diverter system for compliance with the requirements of this subsection and require the operator to test the system to ensure proper operation. Page 11 Version 1 July, 2014 11 Paxton #9 Drilling & Completion Procedure 1l ilrorp:41a.ka,LLC 10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked"warning zone" is established on each side and ahead of the vent line tip. "Warning Zone"must include: • A prohibition on vehicle parking • A prohibition on ignition sources or running equipment • A prohibition on staged equipment or materials • Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set 15.375" ID wearbushing in wellhead. 10.5 Ri• & diverter line orientation on Paxton •ad: IPM' rt 2--,,,:-+..,Nf 5ih�'iL f 1 rlfl "Prt't:MN3'ttll.tR j/I` ,r-7-7:-,' 1 I j c iy 1 1 i .•0r'' ` ',\M1 W '1 _ .1 t 1 } t ti ,, c t• , x. 1c 1 41 1; + - s' 4'147-JII a' l'.0,?C iiii, \ \ — -------,_ Wo Ail 1 --- ---,A\ \w Az- t j Pii ?{r�,. • Ir. 1. 43 ,. T 'tom __=--;------1 �.f,` / �Q /11J mat / li Page 12 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Hilcorp Alaska,LLC 10.6 Diverter Schematic r ill iii ill III iii cit iii iii Annular Preventer ,G, . 21-`6"2M 11111 , _I til f _ ,iii_i_1 ( K-1`n. Caair. e. 11ill lin Ili Iii 1h" Diverlrr linr. Diverter Tee,21-W x 21-f"x [tj 2M wl 16"ANSI 150 outlet t!1 lit 10 III I i 1 16-34"3Mx21-'/"2MOSA T ammo _a MI Lai ! V,: t i ?1111 Seaboard 16-'/4"3M Casing head Assy R 6" Page 13 Version 1 July, 2014 11 Paxton #9 Drilling & Completion Procedure Hilcorp Alaska,LLC 11.0 Drill 12-1/4" Hole Section 11.1 P/U 12-1/4" directional drilling assy: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 4.5" 16.6# S-135 CDS40. • Ensure motor setting can achieve 6 deg/100' DLS in surface hole. Minimum of 1.5 deg AKO is required. 'J 11.2 12-1/4" BHA (GR and Res LWD are included in below BHA): COMPONENT DATA L-.-/,atta 4 CD ( - -*eight '''''f""- .. ' '"� umulattveItem Description Serial Plum # (in) (in) (in) (lbpf) Connection (g) Length (ft) MN HOBS-OHC1GRC Milfooth 12.200 3.000 12.250 374.30 P 6-58"REG 1.20 1 20 © 8'SperryDrill Lobe 415-5.3 stg 8.000 5.000 121.08 B 6-58"REG 28.99 30.19 _ Stabilizer -__ 11.500 _--_ © Integral Blade Stabilizer 8.000 2.813 12.125 150.12 B&518'REG 6.00 38.19 Ell 8"DM Collar(Directional) 7 8.000 3.500 147.40 B 6-58"REG 9.20 45.39 Ell 8"DGR Collar (Gamma) / 8.000 1.920 142.70 B 6-58"REG 4.55 49.94 8'EWR-P4 Collar(Resistively) 1 8.000 2.000 151.00 B 6-58-REG 12.19 62.13 Ell 8"HCIM Collar(Processor) 8.000 1.920 149.90 B 6-58"REG 4.97 67.10 Q 8"TM-HOC(Pulser) 8.150 4.000 145.20 B 6-58-REG 15.77 82.87 Q Orienting Sub UBHO 8.000 3.000 147.22 B 6-58"REG 3.50 86.37 10 Non Mag Flex Drill Collar - 8.000 3.000 147.22 B 6-58'REG 30.00 116.37 El Non Mag Flex Drill Collar 8.000 3.000 147.22 B 6-5/r REG 30.00 146.37 ® X-O 8.518 Reg Pin X 4-12"IF Box 8.000 2.813 150.12 B 4-112"IF 3.5D 149.87 ® 8 Joints 5"HWDP 5.000 3.000 49.30 240.00 389.87 III Weatherford 6-1/4"Hyd Jar 6.250 2.250 91 01 B 4-12"IF 30.00 419.87 ® 19 Joints 5"HWDP 5.000 3.000 49.30 570.00 989.87 Total: 989.87 BIT DATA Bit Number Nozzles : 1x12,3x18 Bit Size (in) : 12.250 TFA (in2) :0.8560 Manufacturer : HDBS Dull Grade In Model Dull Grade Out . Serial Number .• MOTOR DATA Motor Number : 2 Bend (deg) : 1.15 OD (in) : 8.000 Nozzles (32nd) : 0.0 Manufacturer : Sperry Drilling Avg Diff Press . Model : 5perryOri® Cumul Cir Nm .• Serial Number . Page 14 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Ililrorp Alaska.LLC 11.3 Primary Bit: 12-114" (311 MM) QHC 1 GRC PRODUCT SPECIFICATIONS IARC Code 117W Total Tooth Count 67 Gage Rose Tooth Count 39 Journal Angle 33' Offset(1'16") 6 Jet Nozzle Types m Standard 83''44 Extended 302447 Center Jet (If Center Jetted)501813 T.J.Connection 6-5/'8"(API Reg.) Recommended Make-Up Torque* 28000.32000 Ft'lbs. Bit Weight(Boxed) 250 Lbs.(113 Kg.) Bit Breaker (Matti/Legacy-1i) S 15353/506463 PRODUCT FEATURES • New patented Diamond Claw R.tooth bit design. . Tungsten carbide'surf inserts in gage teeth for added gage protection. . Newly formulated,proprietary hardfacing on cutting structure and w „ gage maximizes carbide and diamond volume for ultimate wear resistance. w . High-speed bearing designed for high rpm and high-energy applications. . Innovative mechanical pressure compensating system provides reliable pressure equalization and relief for maximum bearing and seal life. . Raised tungsten carbide inserts and proprietary hardfacing provides maximum arm protection in abrasive and directional applications while minimizing drill string torque. • QuadPack8.Plus Series incorporates its successful"longevity" features and patented engineered hydraulics system for optimal cleaning efficiency. . Center jet feature to prevent bit balling problems Material#622394 'Calculations based on rccommcndations from API and tool-joint manufacturers. C 2012 Halliburton.All rights reserved.Sales of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the sale. v Page 15 Version 1 July, 2014 Paxton#9 Drilling & Completion Procedure Hilcorp Alaska,LLC 11.4 4-1/2" Workstring & HWDP will come from Saxon. Jars will come from Weatherford. 11.5 Begin drilling out from 16" conductor at reduced flow rates to avoid broaching the conductor. 11.6 Drill 12-1/4"hole section to 2,700' MD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. This setting depth will protect the build section of the well with the surface casing. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. • TD the hole section in a good shale btwn 2600' MD and 2800' MD. • Take MWD surveys every stand drilled (60' intervals). 11.7 12-1/4"hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on / location to weight up the active system(1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 8.8—9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths /Density iscosity Plastic Viscosity Yield Point API FL LGS 80-2700' ( 8.8—9.5 85-150 20-40 25-45 <10 <15% System Formulation: M-1 Gel + FW spud mud Product Concentration Fresh Water 0.905 bbl M-I Gel Export 20 ppb M-I Wate As needed Soda Ash 0.5 ppb Caustic Soda 0.1 ppb Busan 1060 0.04ppb Page 16 Version 1 July, 2014 14Paxton#9 Drilling & Completion Procedure Hilrorp Alaska,Ilk 11.8 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16" conductor shoe. 11.9 TOH with the drilling assy, handle BHA as appropriate. 11.10 No open hole logging program planned for Paxton#9. Page 17 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Hilrni p 11a'ka.I.LC 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull 15.375" wearbushing. 12.2 R/U Weatherford 9-5/8" casing running equipment. • Ensure 9-5/8" BTC x CDS 40 XO on rig floor and M/U to FOSV. • R/U fill-up line to fill casing while running. • Ensure all casing has been drifted on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U &thread locking shoe track assy consisting of: • (1) Shoe joint w/float shoe bucked on(thread locked). • (1)Joint with coupling thread locked. • (1)Joint with float collar bucked on pin end&thread locked. • Install (2) centralizers on shoe joint over a stop collar. 10' from each end. • Install (1) centralizer,mid tube on thread locked joint and on FC joint. • Ensure proper operation of float equipment. 12.5 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use"API Modified"thread compound. Dope pin end only w/paint brush. • M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values required to achieve this position. • After making up several connections,use the torque required to M/U to base of triangle as the M/U torque and continue running string. • Install (1) centralizer every other joint to 300'. Do not run any centralizers above 300' in the event a top out job is needed. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 9-5/8" BTC Estimated M/U Torque Casing OD Est Torque to Reach Triangle Base 9-5/8" 9,630 ft-lbs Page 18 Version 1 July, 2014 I Paxton #9 Drilling & Completion Procedure Hileorp Alaska,LLC Tenaris Casing and Tubing Performance Data Choose pipe size,wall thickness and steel grade to view API connection options and performance data. Size Wall 0 Grade 0 Connection -CI Unit Pipe Body Data GEOMETRY y Nominal OD 9.625 in Wall Thickness 0.395 in API Drift Diameter 8.679 in Nominal Weight 40.00 bslft Nominal ID 8.835 in Alternate Drift Diameter 8.75 in Plain End Weight 38.97 bslft Nominal Cross Section 11.454 sq in PERFORMANCE Steel Grade L80 Minimum Yield 80,000 psi Minimum Ultimate 95,000 psi Body Yield Strength 916,000 lbs Internal Yield Pressure 5,750 psi Collapse Pressure 3,080 psi Connection Data GEOMETRY Regular OD 10.625 in Threads Per Inch 5 Make-Up Thread Turns 1 PERFORMANCE Steel Grade L80 Minimum Yield 80,000 psi Minimum Ultimate 95,000 psi Joint Strength 947,E lbs Internal Pressure 5,750 psi Resistance Print Contact Us Ver 8.6 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Page 19 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Hilcorp Alaska,LLC 12.10 RAJ circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. Page 20 Version 1 July, 2014 11 Paxton#9 Drilling & Completion Procedure Hilrorp Alaska,LIC 13.0 Cement 9-5/8" Surface Casing 13.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud& water can be delivered to the cmt unit at acceptable rates. • How to handle cmt returns at surface. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls 10 ppg spacer. Test surface cmt lines. 13.5 Pump remaining 35 bbls 10 ppg spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume+ 50% open hole excess. Job will consist of lead& tail, TOC brought to surface. Estimated Total Cement Volume: Section: Calculation: Vol(BBLS) Vol(ft3) LEAD: 130' x .129 bpf= 16.8 94.3 16" Conductor x 9-5/8" casing annulus: LEAD: (2000' — 130') x .0558 bpf x 1.5 157 882 12-1/4" OH x 9-5/8" _ Casing annulus: _ Total LEAD: 174 bbl 977 ft3 '- `` TAIL: (2700'-2000') x .0558 bpf x 1.5 = 59 331 12-1/4" OH x 9-5/8" Casing annulus: TAIL: 90 x .096 bpf = 8.7 48.8 9-5/8" Shoe track: Total TAIL: 67.7 bbl 380 014. 5'. Page 21 Version 1 July, 2014 Paxton#9 Drilling & Completion Procedure Hilrorp AlaAka,LLC Cement Slurry Design: Lead Slurry(2000' MD to surface) Tail Slurry(2700'to 2000' MD) System Extended Conventional Density 12.5 lb/gal 15.2 lb/gal Yield 2.13 ft3/sk i/ 1.25 ft3/sk Mixed 12.02 gal/sk 5.7 gal/sk Water Mixed Fluid 12.03 gal/sk 5.71 gal/sk Code Description Concentration Code Description Concentration Type1 Cement 94 lb/sk WBWOB Type1 Cement 94 lb/sk WBWOB Static Free De-Foamer 0.005 lbs/sk Static Free De-Foamer 0.005 lbs/sk CaCI Accelerator 2% bwoc CaCI Accelerator .25% bwoc Additives CD-32 Dispersant 0.4%bwoc CD-32 Dispersant 0.5% bwoc FL-52 Fluid Loss Add 0.3%bwoc FL-52 Fluid Loss Add 0.2% bwoc FP-6L De-Foamer 1 gal/100 sk FP-6L De-Foamer 1 gal/100 sk Na Extender 2% bwoc Metasillicate 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with 9.5 ppg Kla-shield. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Displacement calculation: 2600' x .0758 bpf= 197 bbls 13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.13 Do not overdisplace by more than ''V2 shoe track volume. Total volume in shoe track is 8.7 bbls. 13.14 Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log btwn 6— 18 hours after CIP. 13.15 Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require us to run steel pipe through the hanger flutes. The ID of the flutes is 1.5". Page 22 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Hilcorp Alooka,LLC 13.16 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold,pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.17 R/D cement equipment. Flush out wellhead with FW. 13.18 Back out and L/D landing joint. Flush out wellhead with FW. 13.19 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.20 Lay down landing joint and pack-off running tool. Ensure to report the following on wellez: • Pre flush type,volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing,bpm,note any shutdown during mixing operations with a duration a. Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume,whether plug bumped&bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job.Final circulating pressure e. Note if pre flush or cement returns at surface &volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As-Run" casing tally & casing and cement report to lkeller@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 23 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Hilcorp Alaska, 14.0 BOP N/U and Test 14.1 N/D the diverter. 14.2 N/U Seaboard multi-bowl wellhead assy. Install packoff 9-5/8" P-seals. Test to 3000 psi. 14.3 N/U 11" x 5M T3-Energy BOP as follows: • BOP configuration from Top down: 11" x 5M T3-Energy annular BOP/11"x 5M T3-Energy Model 6011i double ram/11" x 5M mud cross/11"x 5M T3-Energy Model 6011i single ram • Double ram should be dressed with 2-7/8 x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should be dressed with 2-7/8 x 5" VBRs • 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. 14.4 Run 4-1/2" BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/3500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 R/D BOP test assy. 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 9.5 ppg Kla-Shield mud system. 14.8 R/U mud loggers for production hole section. 14.9 Set 10" ID wearbushing in wellhead. 14.10 Rack back as much 4-1/2" DP in derrick as possible to be used while drilling the hole section. 14.11 Keep 5-1/2" liners in mud pumps. Page 24 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Hilrorp Alaska,LLC 15.0 Drill 8-1/2" Hole Section 15.1 P/U 8-1/2" directional BHA. 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TF offset is measured accurately and entered correctly into the MWD software. 15.5 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. 15.6 Workstring will be 4.5" 16.6# S-135 CDS40. Page 25 Version 1 July, 2014 II Paxton #9 Drilling & Completion Procedure IIilcorp Alaska.LL(: 15.7 8-1/2" BHA (Includes GR+Res LWD components): COMPONENT.DATA;, ,.., DD 115 Gauge Weight TopLength Cumulative ' n rt i'` i�inber (in) (in) (an) (ibpil Connection ;.tt) HDBS-FX65D PDC 8.400 2.500 8.500 472.13 P 4-112"REG 1.00 1.00 © 7"SperryDritl Lobe 718-6.0 stg - 7.000 4.952 _ 93.13 B 4-112'IF MEMMIMEZMI - Stabilizer -__ 7.760 _-- ® Non Mag Float Sub 5.7 50 2.75" 101.71 B 4-112"IF 3.00 31.38 fl Integral Blade Stabilizer(NM) 6.750 18111111E131 100.77 B 4-112'IF 5.00 36.38 Ell 6 3?4"DM(Directional) 6.750 3.125 103.40 B 4-112'IF 9.20 45.58 EIIIIIIIIIIIMIZZSIEIEEIIIIIIIIIIIIIIIIIIII 6.750 1.905 _ 97.70 B 4-112'IF 20.30 65.89 6 34"DGR(Gamma) 6.750 1 420 97.80 B 4-112'IF 4.55 70.44 pi 6 3/4'EWR-P4 (Resistively) MIIMMIll 6.750 2.000 EMI 104.30 - 12.10 ECM 9 6 314"HCIM (Processor; 6.750 1 920 101.70 B 4-172'IF 4.97 87.51 10 6 314'ALD (Density) S 6.750 1920 8.250 104.30 MMEMil 14.54 EMI 111 Stabilizer -__ 8.250 _-- m 6 374"CTN(Neutron) 6.750 1905 102.30 B 4-112'iF 11.84 113.89 ® 6 314"TV-HOC(Pulsar) 6.900 • 103.60 ® Nan Mag Flex Drill Collar 6.750 2.813 100.77 B 4-112"IF 30.00 15948 ® Non Mag Flex Drill Collar 6.750 2.813 130.77 B 4-112"IF 30.00 ® &Joints 5"HWDP 5.000 3.000 49.3C 240.00 429.48 ® Weatherford 6-114'Jam 6.250 2.250 91.01 B 4-112"IF 30.00 IIEME Ell 19 Joints 5'HWDP 5900 3.000 =9.30 570.00 1029.48 Teta:: 1029.48 BIT DATA Bit Number Nozzles :5x13 Bit Size (in) : 8.500 TEA (int) : 0.6421 ManufacturerDull Grade In Model Dull Grade Out • Serial Number . MOTOR DATA Motor Number - 1 Bend (deg) : 0.00 OD (in) : 7.000 Nozzles (32nd) : 3 0 Manufacturer : Sperry Drilling Avg Diff Press . Model : SperryDrill Cumul Cir Hrs .• Serial Number . Page 26 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Hilrorp Alaska.,LLC 15.8 Primary Bit: 8-1/2" (216mm) MM65M PRODUCT SPECIFICATIONS Cutter Type SelectCutter IADC Code M324 11 Body Type MATRIX 00 v. Total Cutter Count 41 Cutter Distribution 13mm Dmm Face 1 29 Gauge 5 0 Up Drill 6 0 r . Number of Large Nozzles 0 Number of Medium Nozzles 0 Number of Small Nozzles 6 Number of Micro Nozzles 0 "r Number of Ports(Size) 0 , Number of Replaceable Ports(Size) 0 _ Junk Slot Area(sq in) 14.81 ' Normalized Face Volume 42.139 API Connection 4-1'2 REG.PIN Recommended Make-Up Torque* 12,46!—17.766 Ft`lbs. Nominal Dimensions** ;** ee ser Make-Up Face to Nose 10.'3 in-273 mm Gauge Length 2.5 in-64 mm Sleeve Length 0 in-0 mm Shank Diameter 6 in-152 mm Break Out Plate(Mat.#..'Legacyti) 181954'44040 Approximate Shipping Weight 160Lbs.-73Kg. SPECIAL FEATURES I132"Relieved Gage.Combination Backream;Clp-Drill Cutters. Secondary Cutting Element-"R"Feature.TSP Gage Material#803275 'Bit specific recommended make-up torque is a function of the hit I.D.and actual bit sub O.D.utilized as specified in API RP7G Section A.S.2. **Design dimensions arc nominal and may vary slightly on manufactured product.Halliburton Drill Bits and Services models are continuously reviewed and refined. Product specifications may change without notice. C 2013 Halliburton.All rights reserved.Sales of Halliburton products and services will he in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the sale. Page 27 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Hilrorp Alaska,LLC 15.9 8-1/2"hole section mud program summary: Weighting material to be used for the hole section will be salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.5 ppg Kla-Shield fresh water based drilling fluid with 6% KCl. Properties; _ Depths Density Plastic Viscosity Yield Point Chlorides API FL pH 2700'-7376' • 9.5 10-20 15-25 60,000—70,000 <8 9.0- 10 System Formulation: M-I Swaco Kla-Shield with 6% KCI Product Concentration/Function Water Base Fluid Busan 1060 0.4 ppb Biocide Soda Ash 0.25 ppb PH/Hardness Control Flowzan 1.0 ppb Viscosifier/Rheology KCL 21.8 ppb weight/inhibition NaCI Salt 20.0ppb weight/inhibition Poly Pac Sup UL 0.75 ppb API Fluid Loss EMI-2009 2-3%v/v Clay/Shale inhibitor Safe-Carb 40 If needed for weight increase over Conqor 404 9.0ppg Asphasol Supreme Corrosion Mitigation Sack Black 4ppb Shale/Coal Stabilizer 3ppb-Gilsonite Shale/Coal Stabilizer 15.10 TIH w/ 8-1/2" directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 15.11 R/U and test casing to 2900 psi/30 min. Ensure to record volume/pressure and plot on FIT graph. AOGCC reg is 50% of burst= 5750 /2 =2875-2900 psi. 15.12 Drill out shoe track and 20' of new formation. 15.13 CBU and condition mud for FIT. Page 28 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Hikorp Alaska,LLC 15.14 Conduct FIT to 12 ppg EMW. Note: Offset field test data predicts frac gradient at the 9-5/8"shoe to be btwn 16- 17 ppg EMW. A 12 ppg FIT results in a 2.5 ppg kick margin while drilling with the planned MW of 9.5 ppg• 15.15 Drill 8-1/2"hole section to 7,376' MD / 3,500' TVD. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 400 - 450 gpm. Ensure shaker screens are set up to handle this flowrate. • Utilize inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team,try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. • Take MWD surveys every stand drld. Surveys can be taken more frequently if deemed necessary. • Mudlog from Top Beluga to Total Depth, 20' samples in zones of interest,two sets of cuttings, chromatograph,pixler plots. 15.16 At TD; pump sweeps, CBU, and pull a wiper trip back to the 9-5/8" shoe. 15.17 TOH with the drilling assy, lay down drill pipe on the way out. L/D stands out of the derrick prior to running 5-1/2" long string. 15.18 No open hole logs planned for Paxton#9 production hole. 15.19 Monitor the well at all times while Laying down drill pipe. Page 29 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Ililrnrp Alaska,1.LC 16.0 Run 5-1/2" Production Casing 16.1. R/U 5-1/2" casing running equipment. • Ensure 5-1/2"CDC x CDS 40 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure to R/U Tesco or Weatherford CRT so that string can be rotated if necessary while running. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U &thread locking shoe track assy consisting of: • (1) Shoe joint w/shoe bucked on&threadlocked(coupling also thread locked). Install (2) solid body centralizers on shoe joint prior to bucking on float shoe. The centralizers should be held in place 10' from each end via stop rings on either side. • (1) Thread locked joint(coupling thread locked). • (1)Joint with float collar bucked on pin end &threadlocked (coupling also thread locked). Install (1) solid body centralizer on float collar joint prior to bucking on float collar. • Install a solid body centralizer on landing collar joint. Leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe and float collar prior to running in the hole. 16.4. Continue running 5-1/2"prod casing. • Fill casing while running using fill up line on rig floor. • Use "Best 0 Life 2000"thread compound. Dope pin end only w/paint brush. • Install solid body centralizers on every joint to 2,000 MD. None above 2000'. Leave the centralizers free floating. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 5-1/2" CDC M/U torques Casing OD Minimum Maximum Yield Torque 5.5" 12,000 ft-lbs 13,800 ft-lbs 15,500 ft-lbs Page 30 Version 1 July, 2014 11 Paxton#9 Drilling & Completion Procedure Hilcorp Alaska,LLC 5.5 1710.304 P110 HC USS-COCTm vinem t 03 522 PM ,,, L,,,,,,, ,F ,..,,,,,--,---f u',+a. -- MECHANICAL PROPERTIES Pips USS-CDC" I Minimum Yield Strength 110.000 -- psi Maximum Yield Strength 140,000 — psi Minimum Tensile Strength 125.000 -- pat DIMENSIONS Pipe USS-COC'"' Outside Diameter 5.500 6.050 in. Wall Thickness 0.304 -. in. Inside Diameter 4.892 4.892 in. Standard Drift 4.767 4.767 in, Alternate Drift -- -- in, Coupling Length — 9.250 rn, Nominal Linear Weight,TEC 17.00 — Ibsdft Plain End Weight 16.89 -- Ibs/ft SECTION AREA Pipe US$CDC' Critical Area — 4.962 sq.in. Joint Efficiency -- 100.0 % Minimum Collapse Pressure 8.730 8,730 psi External Pressure -- 6,984 psi Minimum Internal Yield Pressure 10,640 10,600 pee Minimum Pipe Body Yield Strength 545 — 1000 lbs Joint Strength -- 568,000 1000 lbs Compression Rating -- 340,800 lbs Reference Length -- 22,275 ft Maximum Uniaxial Bend Rating -- 572 deg/100 ft Make-Up Loss -- 4.63 in. Minimum Make-Up Torque -- 8,500 ft-lbs Maximum Make-Up Torque -- 10,500 ft-lbs Connection Yield Torque -- 13,000 ft-Itis Verification of connection shoulder required.Twotcat shoulder range 16.5. M/U casing hanger joint to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe approx 10—20' above TD. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. Page 31 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Hilcarp Alaska,LLC 16.6. Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 16.7. R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat(slightly)to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 16.8. After circulating, lower string and land hanger in wellhead again. Page 32 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Hikorp Alaska.LLC 17.0 Cement 5-1/2" Production Casing 17.1. Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 17.2. Attempt to reciprocate the casing during cmt operations. 17.3. Pump 5 bbls 10 ppg SealBond spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining 15 bbls 12 ppg SealBond spacer. 17.6. Mix and pump lead and tail cmt per below recipe. Ensure cmt is pumped at designed weight. Job is designed to pump 30% OH excess. Section: Calculation: BLS) Vol (ft3) (B9-5/8" x 5-1/2" Overlap(Lead): 500' x 0.046 = 23 129 8-1/2" OH x 5-1/2" Liner(Lead): (5,000—2,700') x 0.0408 x 1.3 = 122 685 8-1/2" OH x 5-1/2" Liner(Tail): (7,376' —5,000') x 0.0408 x1.3 = 126 707 Shoe Track(Tail): 90' x 0.023 = 2 11.2 Total Volume (Lead): 145 814 ti,-(75;\ Total Volume (Tail): 126 707 Page 33 Version 1 July,2014 Paxton #9 Drilling & Completion Procedure Ilii orp 11a-ha.I.I Lead Slurry (5,000' to 2,200') Tail Slurry (7,376' to 5,000' MD) System I Extended Conventional Density 13.5 lb/gal 15.2 lb/gal Yield 1.82 ft3/sk ,% 1.25 ft3/sk 1---/ Mixed Water 9.21 gal/sk 5.7 gal/sk Mixed Fluid 9.22 gal/sk 5.71 gal/sk Code Description Concentration Code Description Concentration Class G Cement 94 Ib/sk Type1 Cement 94 Ib/sk WBWOB WBWOB BA-90 Low den. additive 10% bwoc Static Free De-Foamer 0.005 lbs/sk BA-56 Gas Migration 2.5% bwoc R-3 Retarder 0.9% bwoc CD-32 Dispersant 0.4% bwoc CD-32 Dispersant 0.6%bwoc Additives Free water ASA-301 control 0.1%bwoc FP-6L De-Foamer 1 gal/100 sk Bonding o FP-6L De-Foamer 1 gal/100 sk BA-10A agent 1% bwoc Metalsillicate Extender 0.5%bwoc Metasillicate Extender 0.5% bwoc Static Free De-Foamer 0.005 lbs/sk 17.7. Drop DP dart and displace with 6% KC1. 7350' x .023 = 169 bbls 17.8. Do not overdisplace by more than V2 shoe track. Shoe track volume is 1.7 bbls. 17.9. Bleed pressure to zero to check float equipment. 17.10. Pressure up again to 3500 psi and hold for 30 min to test production bore. Page 34 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Hilrorp Alaska,LLC Ensure to report the following on wellez: • Pre flush type,volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing,bpm, note any shutdown during mixing operations with a duration i. Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid j. Note if casing is reciprocated or rotated during the job k. Calculated volume of displacement, actual displacement volume,whether plug bumped&bump pressure, do floats hold 1. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure m. Note if pre flush or cement returns at surface&volume n. Note time cement in place o. Note calculated top of cement p. Add any comments which would describe the success or problems during the cement job Send final "As-Run" casing tally & casing and cement report to lkeller@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 35 Version 1 July, 2014 Paxton#9 Drilling & Completion Procedure Hilcorp Alatka,LLC 18.0 Completion Operations 18.1 A separate 10-403 sundry will be submitted to cover the completion operations involving running the production tubing and perforating. Page 36 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure IIilrarp Ala4a,1.I.0 19.0 BOP Schematic Ill 111 Witt Ilk A T3-Energy Saxon Rig 147 11"5M T-3EnergyBOP lit lir I#r riraiI IT3-Ennrgy Model 60111 Illt _ . i _ Manual Manual =�"- AtrrLrI 11.05' Valve Valve - 'i o . s a,;e 1-r:1 1 III III I l 1,!ly 1l I » kir ...,-- i kill ' ry - Choke Line � 1 • y L re 'Iii fill Ili watt . --� T -Ener t,, del 601 Cliirill i, .. ' ,.. I . . L1 LU 1. Grade Lo'��e' 1 «pane-.ponl 1.95' 11SMX1151 EaItrfirfl 'f1 1. l IIII lQ 111 • 3eat.o,-x -NAGS sys'.er•r '' 0 / ]i +1I' -1• 1 6'.--<, N1 X 11 .541 La x • ! Mi I Pi - : , 7, ! t IJ It 9-518kk 16, Page 37 Version 1 July. 2014 II Paxton #9 Drilling & Completion Procedure Hileorp Alaska,LLC 20.0 Wellhead Schematic Ninilchik Unit New drill system-Seaboard Saxon Rig 147 16x95/8x5112 ill M 1 Ai smov 'lel ti= Tubing head,Seaboard-S8, 115M X 71/16 5M, , w/2-21/16 5M SSC), 7"P seal bottom 11] Ill III ,{~ ° 1 . 1 • /111Tril - = -= a.a �•-- ilia II i 1I ' Casing spool,Seaboard-58, �,+ 1.11 „ 163/43MX115Mr - so !--Tisiti IIi w/221/16sM$50, �' MINIM! ” • 95/8 P seal bottom lam ''MPS 1111P1111" .®Y ,, . ,. Iii. Starting head,Se hoard, 16 3'16 34 3MX16"SOW BMA, II ? w/2 21/16 SM SSO �j I�1 Alio: g ' ii a }•1� ' 1•.. i i i I ,_ i II 16" j i 9 5/8" _ i is Page 38 Vet iou 1 Jul',. 2014 Paxton #9 Drilling & Completion Procedure Hileorp Alaska,LI C 21.0 Days Vs Depth Days Vs Depth 0 -Paxton#9 Falls Creek#5 2000 4900 8 6000 3 N W CN WOO 10000 12000 0 5 10 15 20 25 30 35 40 Days Page 39 Version 1 July, 2014 II Paxton #9 Drilling & Completion Procedure ltileorp Alaska,LLC 22.0 Formation Tops ANTICIF4TOO FOR"T00001 TOPS&GEOHAZARDS EXPECTED Intersection Points TOP TOP NAME FLUID MD(Fl) TVD(FT) j TVDSS(FT) J.. Est.Pressure X Y +1. Surface Loc 0 ' 206222' 2230463 Top Beluga Fm GAS 3037 1,437 -1,267 ' 618 Beluga50 GAS 4524 2,140 -1,970 ' 920 206181.0 2234515.0 10 Beluga 60 GAS 4987 2.476 -2.306 r 106E Total Depth 5500 2.872 2,702 206225 2235084 =Primary Objective =Secondary Objective TARGET RADIUS 100 FT Page 40 Version 1 July, 2014 II Paxton #9 Drilling & Completion Procedure Hilrorp Alaska,LLC 23.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation: Ensure adequate amounts of LCM are available. Safe-carb 10, 20, 40, 250, & 750. Ensure G-seal, Pecan nut plug, and Mix II are also available for more severe lost returns incidents. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of Safe-carb 10 & 20 to the active system at 1 —2 ppb. Hole Cleaning: Maintain rheology w/gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP btwn 25 —45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of—50 - —60 lbs/100ft2 to combat this issue. Maintain low flow rates for the intial 200' of drilling to reduce the likelihood of washing out the conductor shoe. To help insure good cement to surface after running the casing, condition the mud to a YP of 25 —30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: / H2S is not present in this hole section. / No abnormal pressures or temperatures are present in this hole section. Page 41 Version 1 July, 2014 14Paxton #9 Drilling & Completion Procedure Hilcorp Alaska,LLC 8-1/2" Hole Section: Lost Circulation: i Ensure adequate amounts of LCM are available. Safe-carb 10, 20, 40, 250, & 750. Ensure G-seal, Pecan nut plug, and Mix II are also available for more severe lost returns incidents. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of Safe-carb 10 & 20 to the active system at 1 —2 ppb. Hole Cleaning: Maintain rheology w/flowzan. Sweep hole w/20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP btwn 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain 1ppb total of PolyPac Supreme UL to maintain a thin/strong wall cake and keep HTHP filtrate below 9 ml/30 min. Maintain MW as necessary using additions of Barite. Maintain 6 ppb EMI-2009 for shale/clay inhibition. Maintain 4 ppb Asphasol Supreme & 3 ppb Sack Black for Shale/Coal stabilizer. Maintain 6%KC1 in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt-type additives to further stabilize coal seams (Asphasol Supreme, Sack Black). • Increase fluid density as required to control a"running coal". • Emphasize good hole cleaning through hydraulics, ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb Asphasol Supreme pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 42 Version 1 July,2014 II Paxton #9 Drilling & Completion Procedure 1 I ilcorp Alaska,r.LC 24.0 Saxon Rig 147 Layout 123'-7" 36'--C" 55'--6" 313'-.0" �2_T- b PRE-V1X TANK !TOTAL VOL 396 B8LS' w . -,:�. �� ' • II ��• �� Ylk!II"I"II 111118 ��.._. l 'I { ,: 1�% �61 IpIIIIIGII II MUD PUMP/2 f I I I. 1 arca Tu« 4I['IIMIM�I�MMIII • p L. • . ,r_--' —al Awn own ii [TOT�1iLL yg9i_1 __M=M=■.. If _ 1� ��: NH MIN' 111E (� (I•'• _ 1 NIT (Mu0 PUMVI!U* : II 1 da,'.� � IMPli ___T. 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I ii A `' nrWCRATOR RI II fA'N i 2221 9 /WAT R TMdK/T ROO 53'_0" I. 45'_0" I,� tis'-0" I 85'-5" ',70'-4" i Page 43 Version 1 July, 2014 14Paxton #9 Drilling & Completion Procedure Ililrnrp Alaska,LLC 25.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer(ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 44 Version 1 July, 2014 II Paxton #9 Drilling & Completion Procedure II'Icor')Alaska.1,1,1. 26.0 Choke Manifold Schematic 1 a .'n L., JI cF. ,,,.... , . I 1.4 III ' I 0 11111i lliAAllii Iiiiiiiiii e ka P 0 le.I .,,: 2222 � I , ; ::7.1•11:476.1 /7° ' 7: '-' 11 .1i. P „111.4 v!: i i°I, "111.1.11' r.117.‘i ii: i Ili i Lif Alk-etio i 1 t s�ll�rt � ,,'moi _`� +.� � ��/r� � i� N , � � a �. ■ -,,,,,, .,� o.. � ,--t p ��l1 a P IK 0 ,a a r'yfot w S) ♦fir ri L 4'7S •" To 1 1 � i� s,.? 2 e: Ail ,40: , a li 1 .�w1Aw s h.:'Ain M1r1,;1.` L: �t. i �i I Allill -,,tr;:;iii to i� p CO ioi�� a re1, gii, __ ,41�r .I. ` R 1 � __, 1 .<lupui iiiG E1 , i?e [ki1 IA, P c - , 1i1 ° 7 €r lj __ y -lre ! 1I' — ill!!I 1l Page 45 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure Ililcorp Alaska,LLC 27.0 Casing Design Information DATE: /0/2012014 WELL: Paxton#9 DESIGN BY:Luke Keller Design Criteria: Hole Size 12-114" Mud Density: 8.8 ppg Hole Size 8-112" Mud Density: 9.5 ppg Hole Size Mud Density: Drilling Mode MASP: 1155 psi(see attached MASP determination&calculation) MASP: Production Mode MASP: 1155 psi(see attached MASP determination&calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress(0.494 psitft)and the casing evacuated for the internal stress Casing Section Calculation/Specification 1 2 Casing OD 9-518" 5-1/2" Top(MD) 0 0 Top(TVD) 0 0 Bottom(MD) 2,700 7,376 Bottom(TVD) 1,869 3.500 Length 2,700 7.376 Weight(ppf) 40 17 Grade L-80 P-110 Connection BTC CDC Weight w.o Bouyancy Factor(lbs) 108,000 "25.392 Tension at Top of Section(lbs) 108,000 '25.392 Min strength Tension(1000 lbs) 916 546 Worst Case Safety Factor(Tension) 8.48 4.35 Collapse Pressure at bottom(Psi) 923 1.729 Collapse Resistance wio tension(Psi) 3.090 7.480 Worst Case Safety Factor(Collapse) 3.35 4.33 MASP(psi) 1.155 1,155 Minimum Yletd(psi) 5,750 10,640 Worst case safety factor(Burst) 4.98 9/1 Page 46 Version 1 October, 2014 Paxton #9 Drilling & Completion Procedure Hilrorp Ala4ka.1.1.0 28.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 8-1J2"Hole Section Hiic°rp Paxtor#9 Ninilchik Unit MD TVD Planned Top: 2700 1869 Planned TD: 7376 35C3 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Top Beluga Fm 1,437 618 GAS 8.3 0.430 Beluga 50 2,140 920 GAS 8.3 0.430 Beluga 60 2,476 1065 GAS 8.3 0.430 TD 3,500 1511 Gas 8.3 0.430 Offset Well Mud Densities Well MW range Top(TVD) Bottom(TVD) Date Falls Creek#1 11.6-13.1 3,500 10.000 1960 Falls Creek#2 10.5-11 3,500 6.300 1966 Falls Creek#3 9.4-9.5 3,500 8.400 2003 Falls Creek#4 9-9.5 3,500 6.000 2004 Falls Creek#5 9.5-9.7 3,520 9,715 2014 Corea Creek#1 9.5-10.9 3,530 9.000 1996 Frances#1 9-5-9.8 3,500 10.000 _ 2013 Paxton#1 9.2-9.4 3.600 8,000 2004 Paxton#2 9.2-9.4 3,600 9,500 2008 Assumptions: 1. Fracture gradient at shoe is estimated at 0.936 psi/ft based on field test data. 2. Maximum planned mud density for the 8-1/2"hole section is 9.5 ppg. 3. Calculations assume"Unknown"reservoir contains 10096 gas(worst case). 4. Calculations assume worst case event is complete evacuation of wellbore to gas Fracture Pressure at 9-5/8"shoe considering a full column of gas from shoe to surface: 1869(ft)x 0.936(psi/ft)= 1750 psi 1750(psi)-[0.1(psi/ft)•1869(ft))= 1564 psi MASP from pore pressure(unknown gas sand at TD,at 8.3 ppg,encountered while drilling) 3,500(ft)x 0.43(psi/ft)= 1505 psi 1505(psi)-[0.1(psi/ft)•3500(ft))= 1155 psi Summary: 1. MASP while drilling 8-1/2"production hole is governed by pore pressure and complete evacuation of wellbore to gas at TD. Page 47 Version 1 July, 2014 Paxton #9 Drilling & Completion Procedure IliIcorp 41:1.1.n.1,1,4" 29.0 Spider Plot (NAD 27) (Governmental Sections) e l 1 Legend 0 • Parlan 9 SHL + I )Paxton 43 BHL ..,.. X Paxton 9 TPI -- – i DD#g1E4OHL.-- ----------------- -- - Parton 9 BHL T AX"de 3 XL a • Otter Surace Hole Laa'wn 1 0 1 0 • Omer Ben=Hale Lacaaen I o 1 0i,GL3 -924 ---Weil Paths 1 e L-KPB PscNs l o 1 4 On.3'n<Ga:Urn Ba rmary 1 1 0Q� AX—I.,-EH_ i a 1 1 44 I !8 =At:I 4 9.-IL 1 Io f 1 18 / 1 to I 10 ,, I to f 1 to AD. 4372 //r g+ PAXTON 1 BHL 1 1'0 r tag �` 110 .0 0 '' II• / f Y 11 JF Y tip 11 SOO1S014W NINILCHII4t1NIT /' s +4 wp C061505 r,° i�.4-.'"Paxton +TPP r +4 �_.._._. / SOOISU13W 4, lb /i t lb ;�. / / Ib 4 Ib / /' 4 tf F i 44 p1 FAtICN„eh / t+t s.t fes;;` / //. ,;Y,.-. M k i Y 144 1 +++ 10i 1 //� n;. 3B .. - 4 14r I / ...-�' NINILCHII'C2 + ts-4r r Ni 4. 1 I � /Ti .+�' _ s N. I PrX/7.Ii 3 BHL • /'' '• est r I I_ 1 PAXX..a BJtt'ADL3&4372 .; Paxton 9 SHL / / C160385 i 1 03 ' // ,, ../ .,.f.,, ,,e'---„, , ADL390105 ill c 1.000 z:aoa Paxton 9 Feet Il a:ai.,61.1.i I.I.l1. 4 Alaska Stale Plane Zane 4,NAD2T Map Dale:1012012014 /`R Page 48 Version 1 July, 2014 II Paxton #9 Drilling & Completion Procedure flilrnrp Alaska,LLC 30.0 Surface Plat (As Staked) (NAD 27) F TtN J SPENCER ESTATE .., is 1O . OOVT.LOT It 1 SEO.19 roskr AK \"-1,,,,,,,/...... } HOME61REC 14 IJIG } 1dBTA1CT SCALE RTH 9; .' 64641 RED BLLIFFSW& Frr, ( 1J r / `__ / 1 / ;#,..7:'..• 'Q. / / i'''>ki ' 1 ,18,4,3.....8 *.:45,4,. i ,,,. , , ,,..- A/.I/ I „Mit, ,,,,,,,•,",, ,, / ) I ( , . 10 ''f,t 4, / .„,, / , ...,..: --.,,,,,,,.)) ,,, ,,. 0,Vim.scam Isamu, '.:," -— / ,i-,-,,-/- i Ilfip/I1 S f � �,/ r 1/ I 177* /r , 1111' ` `+47.' ` i `^.7� /, f l J i� ~i\ i / ;J :et /iir{ ,awtM / eil :/ L.WE ' ill J a " I" '1°4, • {tff,i . :f i tAP- li'i'I/ • •. ��.. 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ADJACENT-MOM 982 M 2252S47.710 E*5661.152S ELEV NOSS FEET. 2)NORTHEAST CCRhER tEC 19 CCORD7IMES DETERMAED FROM ORECT / • v -, SIITY TIF'TO 116 1')11%117111M.BI M.4rCTXIN[.aR}SRK. R n.4RrD ''. ' , - R1FRLT'PJAcire,,SECTrN CiJANS.1 tiFv.LESI•OT itS1.20 ...,...4.— •\ ?} - -osPm1YEA 50_4480 t ISED TO COvvEFT•,1 4:181 To to.or PAXTON #9 WELL AS-STAKED SURFACE LOCATION NOTES (NAD27) LOCATION:SECTION 13, TOWNSHIP 1 SOUTH, ENGINEERING-TESTING;4 RANGE 14 WEST,SEWARD MERIDIAN ALASKA SURVEYING-MAPPING i iilcf►r f Alaska.l.L1: P.O.BOX 468 SOLbC?TNA,AX.99860 JOB NO, 143144 REV.Q VOICE=007I 283-4.214 _. FAX:tem)283.3 65 DWG. C/lvellkwtNa W1AWNJACLANECG.COM 143144 'Date-October 17,2014 FIGURE: 1 Page 49 Version 1 July, 2014 HPaxton #9 Drilling & Completion Procedure Hilcorp Alaska,LLC 31.0 Offset MW vs TVD Chart Paxton#9 Offset Wells 1000 'II., Paxton#1 —Paxton#2 2000 — Falls Creek#3 Falls Creek#4 rit 3000 N Frances#1 . Susan Dunne 4000 Falls Creek#5 Iiii . SODO pl - 2.----. iEE€ € 4 O 7000 1 { 8000 7 E y�y 9000 10000 11000 12000 S. 13000 14000 8 9 10 11 12 13 14 15 Mud Weight(PPG) Page 50 Version 1 July, 2014 11 Paxton #9 Drilling & Completion Procedure Ililcorp Ala.ka,1.1A: 32.0 Drill Pipe Specification Sheet SIZE: 4 1/2" WRIGHT: 16.6 LIg/F'r E COMMAND GRADE: 5.135 ENMMY SERVICES RANGE: II(31.5') RILL,PIPE SPECS CONNECTION: CDS4O TUBE ___ I NEW PREMIUM IN MM IN MM OD 4.503 114.3 4.365 110.9 WALLT:-IICKNE5S 0.337 8.61 0.270 6.8 ID 3.826 97.2 3.826 97_2 FT-LBS N-M FT-LBS N-M TGR SdONAL 5TRENGTHI 55.453 75.200 43.451 58.903 BO"'=•TORSIONAL STRENGTH 44.362 60.200 34.761 47.100 LBS DAN LES DAN TENSILE STRENGTH 595.004 265.300 468.297 208.800 PSI EPA PSI EPA 3NTERNAL PRESSURE CAPACITY 17.6c1 - 121.985 16.176 `. 11.530 COLLAPSE CAPACITY 16.769 115.615 10.959 75.561 I INz MMz INz MMz CR055 SEMI ONAL AREA BODY 4.407 2844 3.469 2238 ` CROSS SECTIONAL AREA OD '5.904 102611 14 966 96=5 CROSS SECTIONAL AREA ID :1.497 7417 11.497 7417 IN3 MM3 IN3 MM3 SECTION MODULUS 4.271 69995 3.347 54845 POLAR SE TION MODUL1-15,_. _:9:.543. _...____' P969i ___ ___w563A__._... ,_._e_,1 u3690, TOOL JOINT I NEW �� PREMIUM PSI EPA ( PSI EPA YIELD S7RENG n-I 130.07.1r. 896.318 130.000 896.318 iIN MM IN MM OD 5.2500 133.4 5.1198 130.0 i ID 2.6875 68.3 2.6875 68.3 I RN L1✓VG'T-I 1 1.0 279.4 11.0 279.4 BOX LENGTH 14.0 355.6 14.0 355.6 FT-LBS N-M FT-LBS N44 TORSIONAL STRENG-TH 35.400 48.000 34.700 47.100 MAX MAKE-UP TORQUE 22.500 30.503 21.400 29.00C RECOMMENDED MAKE-UP TORQUE 21.200 26.800 20,800 28.200 MIN MAKE-UP TOQUE 19.600 26.600 19.300 26.200 LBS DAN LBS DAN TENSILE 5 t•rENGTH 824.400 367.600 834.900 358.900 TOOL JOINT/DRILL PIPE TORSIONAL RATIO 0.64 0.80 i DRILL PIPE ASSEMBLY WITH CONNECTION I t5✓Fr KG/M AlJUSI tU"WEIGHT 17.57 26.64 FT M APPROXIMATE LENGTH 31.50 9.60 GAL/FT MVM1 I FLUID DISPLACEMENT 0.2:73 0.003394 I FLUID CAPAC 7Y, 0.=.77 0.007169 IN MM I' DRIrT SIZE 2.5625 G Page 51 Version 1 July. 2014 Paxton #9 Drilling & Completion Procedure Hilcorp Alaska,LLC COMBINED LOAD CURVE FOR 4 1/2"5.135 16.6 LBS/FT DRILL PIPE WITH CDS4O CONNECTIONS 5 0C:..40 Ins •!B am env mat .' $ i 4111. 41110 to,totti d 0 d •M d 'V' a 2 404 000M 4 • 300,000 , •+ 4,!.• .Ia • • i. •• Illkt 200,000 • • •0 ift 300.000 1tIIPIIPMI*: H` i st 0 I4,000 20.407 30,000 40.000 70,000 60,000 Applied Torauelft-lbsl 0.0 00 NEW TUBE COMS:NELs LOAD ••••PREMiUM TL BE COMBINED LOAD MAKE-UP TORQUE •-•-SHOULDER SEPERATON --Pliti Y1=L'` --••90X YIELD Page 52 Version 1 July, 2014 Hilcorp Energy Company Ninilchik Unit , Paxton Paxton #9 Paxton #9 Plan: Paxton #9 WP1.0 1, . i Standard Proposal Report tl p p 16 October, 2014 0 50 I a4 sx• v 1 ,mil or HALLUBURTON 1 Sperry Drilling Services 1. HALLS BURTON Ialmil= Project: Ninilchik Unit Sit Paxton Paxton Sperry Drilling Paxton#9 Wellbore: #9 SECTION DETAILS I Paxton#9 WP1.O iec MD Inc Azi TVD +N/-S +E/-W DIeg TFace VSect Target 1 18.50 0.00 0.00 18.50 0.00 0.00 0.00 0.00 0.00 CASING DETAILS 2 150.00 0.00 0.00 150.00 0.00 0.00 0.00 0.00 0.00 3 600.00 13.05 357.64 596.12 50.98 -2.10 2.90 357.64 51.02 TVD MD Name Size 4 800.00 25.05 357.15 784.82 116.07 -5.15 6.00 359.00 116.17 80.00 80.00 16" 16 5 2633.39 80.05 358.20 1857.42 1515.30 -56.88 3.00 1.26 1516.31 6 5142.82 80.05 358.20 2291.20 3985.73 -134.60 0.00 0.00 3987.95 1647.43 2000.00 9 5/8" 9-5/8 7 5221.46 77.00 359.00 2306.85 4062.76 -136.48 4.00 165.61 4065.01 Pax17_BIg50 T2 Adjusted 3500.00 7375.98 5 1/2" 5-1/2 8 7375.98 33.91 359.00 3500.00 5795.61 -166.73 2.00 180.00 5798.01 -1200- WELL DETAILS: Paxton#9 Ground Level: 148.35 - +N/-S +E/-W Northing Easting Latittude Longitude Slot -800- 0.00 0.00 2230422.13 206279.53 60.09554570 -151.60925833 REFERENCE INFORMATION -400- Co-ordinate(N/E)Reference: Well Paxton#9,True North Vertical(TVD)Reference: Planned @ 166.85usft - A Measured Depth Reference: Planned @ 166.85usft • Calculation Method: Minimum Curvature 0- __16" - ------------ Start Dir 2.9°/100': 150'MD, 150'TVD Hilcorp Energy Company 400- Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Closest Approach 3D Start Dir 6°/100':600'MD,596.12'TVD Error Surface: Elliptical Conic Warning Method: Error Ratio 800- --- - Start Dir 3°/100':800'MD,784.82'TVD SURVEY PROGRAM 1200- Date:2014-10-16T00:00:00 Validated:Yes Version: (0 - = Depth From Depth To Survey/Plan Tool 00 9 5/8" 18.50 2000.00 Paxton#9 WP1.0(Paxton#9) MWD+SC+sag 0 2000.00 7375.92 Paxton#9 WP1.0(Paxton#9) MWD+SC+sag 1600- a) Top Beluga --End Dir :2633.39'MD, 1857.42'TVD 0 2000- Start Dir 4°/100':5142.82'MD,2291.2'TVD - - - Start Dir 2°/100':5221.46'MD,2306.85'T\ - Beluga 50 ---- 1- 2400 - Pax#7_BIg50 T2 Adjusted 2800- Belgua 60 3200- - 5 1/2" 3600- Paxton#9 WP1.0- Total Depth:7375.98'MD,3500'TVD 4000- 4400- FORMATION TOP DETAILS - TVDPath MDPath Formation 4800- 1437.00 1628.20 Top Beluga 2140.00 4268.11 Beluga 50 2476.00 5758.86 Belgua 60 5200- ii I I I I I I I l I I I I I I l I I I I l I I I I I l I i i 1 i I l i i i I i i i l I i I I l I i i i i I i i i i I i i i i j i i 1 I I I I l I 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 Vertical Section at 358.35° (800 usft/in) Z ,y'e cr4 0 ,.t o W.c...' 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X _ n NNW • U �L O00 N 000 , O 000 O� 0 J 0 ,1 M M N N N (ui/gsn 001)(+)twoN/(-)mnosnal ?, L 1111 L tan >, a - - o N —`,,, 00 ° 00 0O 0.O N b Y o lt // _ 0. Y. pOI X o X Oh I a _ / Co oo — a ° co K M NC0 / O O - o a O N .d- C:' C,',.CZ O M 00 1� O N ___ __+ /- oo O 0 O�Cl I _ ,, r O M / - o O —M 00 jI _ �..' � 1 y W A r, O c: _0,p W ,' 0 R. OcfN oN It M —O 0 Q. b a 00015 —M -- O O —h OZ-8 _ 00090; ��q� - O o '100 -0 1< - a 0. -- o 00 —M - N I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I l l t r l I I I I I 1 ( 11 1 I I I I I I I I 1 I I I I l I I I I 1 I I I I l I 1 I I I I I- O O O O O O O O O O O O O O O O O O O O N 00 V sD N W 7 O o N 00 S O M N 00 Q t- 7 h O 1- 7 O 1- M O r O ,0 M \O h v� vi 7 7 7 M M M N N N .-. -. 0 (u!/►3sn 058)(+A poN/(-)ulnos Halliburton HALLIBURTC . J Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Paxton#9 Company: Hilcorp Energy Company TVD Reference: Planned @ 166.85usft • Project: Ninilchik Unit MD Reference: Planned @ 166.85usft Site: Paxton North Reference: True Well: Paxton#9 Survey Calculation Method: Minimum Curvature Wellbore: Paxton#9 Design: Paxton#9 WP1.0 Project Ninilchik Unit Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Paxton Site Position: Northing: 2,230,587.12 usft Latitude: 60.09599940 From: Map Easting: 206,316.53usft Longitude: -151.60907766 Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -1.39 ° J Well Paxton#9 Well Position +NI-S 0.00 usft Northing: 2,230,422.13 usfi Latitude: 60.09554570 +EI-W 0.00 usft Easting: 206,279.53 usfi Longitude: -151.60925833 Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usf Ground Level: . 148.35 usft Wellbore Paxton#9 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (0) (0) (nT) BGGM2013 10/15/2014 16.54 73.11 55,198 Design Paxton#9 WP1.0 Audit Notes: Version: Phase: PLAN Tie On Depth: 18.50 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 18.50 0.00 0.00 358.35 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +NI-S +E/-W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (°/100usft) (°/100usft) (°/100usft) (0) 18.50 0.00 0.00 18.50 -148.35 0.00 0.00 0.00 0.00 0.00 0.00 150.00 0.00 0.00 150.00 -16.85 0.00 0.00 0.00 0.00 0.00 0.00 600.00 13.05 357.64 596.12 429.27 50.98 -2.10 2.90 2.90 0.00 357.64 800.00 25.05 357.15 784.82 617.97 116.07 -5.15 6.00 6.00 -0.25 359.00 2,633.39 80.05 358.20 1,857.42 1,690.57 1,515.30 -56.88 3.00 3.00 0.06 1.26 5,142.82 80.05 358.20 2,291.20 2,124.35 3,985.73 -134.60 0.00 0.00 0.00 0.00 5,221.46 77.00 359.00 2,306.85 2,140.00 4,062.76 -136.48 4.00 -3.87 1.02 165.61 L 7,375.98 33.91 359.00 3,500.00 3,333.15 5,795.61 -166.73 2.00 -2.00 0.00 180.00 10/16/2014 2:44:07PM Page 2 COMPASS 5000.1 Build 70 Halliburton HALLIBURT Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Paxton#9 Company: Hilcorp Energy Company TVD Reference: Planned @ 166.85usft Project: Ninilchik Unit MD Reference: Planned @ 166.85usft Site: Paxton North Reference: True Well: Paxton#9 Survey Calculation Method: Minimum Curvature Wellbore: Paxton#9 Design: Paxton#9 WP1.0 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section I (usft) (0) (°) (usft) usft (usft) (usft) (usft) (usft) -148.35 18.50 0.00 0.00 18.50 -148.35 0.00 0.00 2,230,422.13 206,279.53 0.00 0.00 80.00 0.00 0.00 80.00 -86.85 0.00 0.00 2,230,422.13 206,279.53 0.00 0.00 16" 100.00 0.00 0.00 100.00 -66.85 0.00 0.00 2,230,422.13 206,279.53 0.00 0.00 150.00 0.00 0.00 150.00 -16.85 0.00 0.00 2,230,422.13 206,279.53 0.00 0.00 Start Dir 2.9°/100':150'MD,150'TVD 200.00 1.45 357.64 199.99 33.14 0.63 -0.03 2,230,422.76 206,279.52 2.90 0.63 300.00 4.35 357.64 299.86 133.01 5.69 -0.23 2,230,427.82 206,279.43 2.90 5.69 400.00 7.25 357.64 399.33 232.48 15.78 -0.65 2,230,437.92 206,279.26 2.90 15.79 500.00 10.15 357.64 498.17 331.32 30.89 -1.27 2,230,453.04 206,279.01 2.90 30.92 600.00 13.05 357.64 596.12 429.27 50.98 -2.10 2,230,473.14 206,278.67 2.90 51.02 Start Dir 6°/100':600'MD,596.12'TVD 700.00 19.05 357.32 692.18 525.33 78.59 -3.33 2,230,500.77 206,278.11 6.00 78.65 800.00 25.05 357.15 784.82 617.97 116.07 -5.15 2,230,538.29 206,277.21 6.00 116.17 Start Dir 3°/100':800'MD,784.82'TVD 900.00 28.05 357.29 874.27 707.42 160.71 -7.31 2,230,582.96 206,276.13 3.00 160.85 1,000.00 31.05 357.40 961.25 794.40 209.96 -9.59 2,230,632.26 206,275.05 3.00 210.15 i 1,100.00 34.05 357.50 1,045.54 878.69 263.70 -11.98 2,230,686.04 206,273.97 3.00 263.94 ii 1,200.00 37.05 357.58 1,126.89 960.04 321.78 -14.47 2,230,744.16 206,272.89 3.00 322.07 1,300.00 40.05 357.66 1,205.09 1,038.24 384.04 -17.06 2,230,806.46 206,271.82 3.00 384.37 1,400.00 43.05 357.72 1,279.92 1,113.07 450.30 -19.73 2,230,872.77 206,270.76 3.00 450.68 1,500.00 46.05 357.78 1,351.18 1,184.33 520.38 -22.49 2,230,942.90 206,269.72 3.00 520.82 1,600.00 49.05 357.83 1,418.68 1,251.83 594.10 -25.32 2,231,016.67 206,268.68 3.00 594.59 1,628.20 49.89 357.84 1,437.00 1,270.15 615.52 -26.12 2,231,038.10 206,268.40 3.00 616.02 Top Beluga 1,700.00 52.05 357.88 1,482.22 1,315.37 671.25 -28.21 2,231,093.87 206,267.67 3.00 671.79 1,800.00 55.05 357.92 1,541.63 1,374.78 751.62 -31.16 2,231,174.28 206,266.68 3.00 752.21 1,900.00 58.05 357.96 1,596.75 1,429.90 834.99 -34.16 2,231,257.70 206,265.71 3.00 835.63 2,000.00 61.05 358.00 1,647.43 1,480.58 921.13 -37.20 2,231,343.89 206,264.76 3.00 921.82 9 5/8" 2,100.00 64.04 358.03 1,693.53 1,526.68 1,009.81 -40.28 2,231,432.61 206,263.85 3.00 1,010.55 2,200.00 67.04 358.07 1,734.92 1,568.07 1,100.77 -43.37 2,231,523.62 206,262.97 3.00 1,101.56 2,300.00 70.04 358.10 1,771.50 1,604.65 1,193.78 -46.49 2,231,616.68 206,262.12 3.00 1,194.62 2,400.00 73.04 358.13 1,803.15 1,636.30 1,288.57 -49.61 2,231,711.52 206,261.30 3.00 1,289.47 2,500.00 76.04 358.16 1,829.79 1,662.94 1,384.90 -52.73 2,231,807.89 206,260.53 3.00 1,385.84 2,600.00 79.04 358.19 1,851.36 1,684.51 1,482.48 -55.84 2,231,905.52 206,259.79 3.00 1,483.47 2,633.39 80.05 358.20 1,857.42 1,690.57 1,515.30 -56.88 2,231,938.36 206,259.56 3.00 1,516.31 End Dir :2633.39'MD,1857.42'TVD 2,700.00 80.05 358.20 1,868.93 1,702.08 1,580.87 -58.94 2,232,003.96 206,259.09 0.00 1,581.92 2,800.00 80.05 358.20 1,886.22 1,719.37 1,679.32 -62.04 2,232,102.46 206,258.39 0.00 1,680.41 2,900.00 80.05 358.20 1,903.51 1,736.66 1,777.77 -65.14 2,232,200.95 206,257.69 0.00 1,778.90 • 3,000.00 80.05 358.20 1,920.79 1,753.94 1,876.21 -68.23 2,232,299.44 206,256.99 0.00 1,877.40 3,100.00 80.05 358.20 1,938.08 1,771.23 1,974.66 -71.33 2,232,397.93 206,256.30 0.00 1,975.89 3,200.00 80.05 358.20 1,955.37 1,788.52 2,073.10 -74.43 2,232,496.42 206,255.60 0.00 2,074.39 3,300.00 80.05 358.20 1,972.65 1,805.80 2,171.55 -77.52 2,232,594.92 206,254.90 0.00 2,172.88 10/16/2014 2:44:07PM Page 3 COMPASS 5000.1 Build 70 Halliburton HALLIBURTA Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Paxton#9 Company: Hilcorp Energy Company TVD Reference: Planned @ 166.85usft Project: Ninilchik Unit MD Reference: Planned© 166.85usft Site: Paxton North Reference: True Well: Paxton#9 Survey Calculation Method: Minimum Curvature Wellbore: Paxton#9 Design: Paxton#9 WP1.0 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 1,823.09 3,400.00 80.05 358.20 1,989.94 1,823.09 2,270.00 -80.62 2,232,693.41 206,254.20 0.00 2,271.38 3,500.00 80.05 358.20 2,007.22 1,840.37 2,368.44 -83.72 2,232,791.90 206,253.50 0.00 2,369.87 3,600.00 80.05 358.20 2,024.51 1,857.66 2,466.89 -86.82 2,232,890.39 206,252.80 0.00 2,468.36 3,700.00 80.05 358.20 2,041.80 1,874.95 2,565.33 -89.91 2,232,988.88 206,252.10 0.00 2,566.86 3,800.00 80.05 358.20 2,059.08 1,892.23 2,663.78 -93.01 2,233,087.38 206,251.40 0.00 2,665.35 3,900.00 80.05 358.20 2,076.37 1,909.52 2,762.23 -96.11 2,233,185.87 206,250.70 0.00 2,763.85 4,000.00 80.05 358.20 2,093.65 1,926.80 2,860.67 -99.20 2,233,284.36 206,250.00 0.00 2,862.34 r 4,100.00 80.05 358.20 2,110.94 1,944.09 2,959.12 -102.30 2,233,382.85 206,249.30 0.00 2,960.84 4,200.00 80.05 358.20 2,128.23 1,961.38 3,057.56 -105.40 2,233,481.34 206,248.60 0.00 3,059.33 4,268.11 80.05 358.20 2,140.00 1,973.15 3,124.61 -107.51 2,233,548.42 206,248.13 0.00 3,126.41 Beluga 50 4,300.00 80.05 358.20 2,145.51 1,978.66 3,156.01 -108.49 2,233,579.84 206,247.90 0.00 3,157.82 4,400.00 80.05 358.20 2,162.80 1,995.95 3,254.45 -111.59 2,233,678.33 206,247.20 0.00 3,256.32 4,500.00 80.05 358.20 2,180.09 2,013.24 3,352.90 -114.69 2,233,776.82 206,246.51 0.00 3,354.81 4,600.00 80.05 358.20 2,197.37 2,030.52 3,451.35 -117.79 2,233,875.31 206,245.81 0.00 3,453.31 4,700.00 80.05 358.20 2,214.66 2,047.81 3,549.79 -120.88 2,233,973.80 206,245.11 0.00 3,551.80 4,800.00 80.05 358.20 2,231.94 2,065.09 3,648.24 -123.98 2,234,072.30 206,244.41 0.00 3,650.30 4,900.00 80.05 358.20 2,249.23 2,082.38 3,746.68 -127.08 2,234,170.79 206,243.71 0.00 3,748.79 5,000.00 80.05 358.20 2,266.52 2,099.67 3,845.13 -130.17 2,234,269.28 206,243.01 0.00 3,847.28 5,100.00 80.05 358.20 2,283.80 2,116.95 3,943.58 -133.27 2,234,367.77 206,242.31 0.00 3,945.78 5,142.82 80.05 358.20 2,291.20 2,124.35 3,985.73 -134.60 2,234,409.95 206,242.01 0.00 3,987.95 Start Dir 4°/100':5142.82'MD,2291.2'TVD 5,200.00 77.83 358.78 2,302.17 2,135.32 4,041.83 -136.08 2,234,466.06 206,241.90 4.00 4,044.07 5,221.46 77.00 359.00 2,306.85 2,140.00 4,062.77 -136.48 2,234,487.00 206,242.00 4.00 4,065.01 Start Dir 2°/100':5221.46'MD,2306.85'TVD 5,300.00 75.43 359.00 2,325.57 2,158.72 4,139.03 -137.82 2,234,563.28 206,242.53 2.00 4,141.28 5,400.00 73.43 359.00 2,352.41 2,185.56 4,235.34 -139.50 2,234,659.60 206,243.19 2.00 4,237.60 5,500.00 71.43 359.00 2,382.59 2,215.74 4,330.65 -141.16 2,234,754.93 206,243.85 2.00 4,332.92 5,600.00 69.43 359.00 2,416.09 2,249.24 4,424.86 -142.80 2,234,849.14 206,244.50 2.00 4,427.13 5,700.00 67.43 359.00 2,452.85 2,286.00 4,517.84 -144.43 2,234,942.13 206,245.14 2.00 4,520.12 5,758.86 66.25 359.00 2,476.00 2,309.15 4,571.94 -145.37 2,234,996.24 206,245.51 2.00 4,574.23 Belgua 60 5,800.00 65.43 359.00 2,492.84 2,325.99 4,609.47 -146.03 2,235,033.78 206,245.77 2.00 4,611.77 5,900.00 63.43 359.00 2,536.00 2,369.15 4,699.66 -147.60 2,235,123.98 206,246.39 2.00 4,701.96 6,000.00 61.43 359.00 2,582.28 2,415.43 4,788.29 -149.15 2,235,212.62 206,247.00 2.00 4,790.60 ' 6,100.00 59.43 359.00 2,631.63 2,464.78 4,875.24 -150.67 2,235,299.58 206,247.60 2.00 4,877.56 6,200.00 57.43 359.00 2,683.98 2,517.13 4,960.43 -152.15 2,235,384.78 206,248.19 2.00 4,962.75 6,300.00 55.43 359.00 2,739.28 2,572.43 5,043.73 -153.61 2,235,468.09 206,248.77 2.00 5,046.06 6,400.00 53.43 359.00 2,797.44 2,630.59 5,125.05 -155.03 2,235,549.42 206,249.33 2.00 5,127.39 6,500.00 51.43 359.00 2,858.41 2,691.56 5,204.30 -156.41 2,235,628.68 206,249.87 2.00 5,206.64 6,600.00 49.43 359.00 2,922.11 2,755.26 5,281.36 -157.75 2,235,705.76 206,250.41 2.00 5,283.72 6,700.00 47.43 359.00 2,988.47 2,821.62 5,356.16 -159.06 2,235,780.56 206,250.92 2.00 5,358.52 6,800.00 45.43 359.00 3,057.39 2,890.54 5,428.60 -160.32 2,235,853.01 206,251.42 2.00 5,430.97 6,900.00 43.43 359.00 3,128.80 2,961.95 5,498.59 -161.55 2,235,923.01 206,251.90 2.00 5,500.96 7,000.00 41.43 359.00 3,202.60 3,035.75 5,566.04 -162.72 2,235,990.47 206,252.37 2.00 5,568.42 10/16/2014 2:44:07PM Page 4 COMPASS 5000.1 Build 70 Halliburton IIALLIBURTCANI Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Paxton#9 Company: Hilcorp Energy Company TVD Reference: Planned @ 166.85usft Project: Ninilchik Unit MD Reference: Planned @ 166.85usft Site: Paxton North Reference: True Well: Paxton#9 Survey Calculation Method: Minimum Curvature Wellbore: Paxton#9 Design: Paxton#9 WP1.0 Planned Survey ! Measured Vertical Map Map ! Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (usft) usft (usft) (usft) (usft)(°) (°) (usft) 3,111.87 7,100.00 39.43 359.00 3,278.72 3,111.87 5,630.88 -163.86 2,236,055.32 206,252.82 2.00 5,633.26 7,200.00 37.43 359.00 3,357.05 3,190.20 5,693.02 -164.94 2,236,117.47 206,253.24 2.00 5,695.41 7,300.00 35.43 359.00 3,437.51 3,270.66 5,752.39 -165.98 2,236,176.84 206,253.65 2.00 5,754.79 7,375.98 33.91 359.00 3,500.00 . 3,333.15 5,795.61 -166.73 2,236,220.06 206,253.95 2.00 5,798.00 Total Depth:7375.98'MD,3500'TVD-5 1/2" Targets Target Name -hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Easting -Shape (°) (°) (usft) (usft) (usft) (usft) (usft) Pax#7 BIg50 T2 Adjusted 0.00 0.00 2,306.85 4,062.76 -136.48 2,234,487.00 206,242.00 -plan hits target center -Circle(radius 100.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 80.00 80.00 16" 16 16 2,000.00 1,647.43 9 5/8" 9-5/8 12-1/4 7,375.98 3,500.00 5 1/2" 5-1/2 8-1/2 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology (°) (°) 5,758.86 2,476.00 Belgua 60 0.00 4,268.11 2,140.00 Beluga 50 0.00 1,628.20 1,437.00 Top Beluga 0.00 I Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 150.00 150.00 0.00 0.00 Start Dir 2.9°/100': 150'MD, 150'TVD 600.00 596.12 50.98 -2.10 Start Dir 6°/100':600'MD, 596.12'TVD 800.00 784.82 116.07 -5.15 Start Dir 3°/100':800'MD,784.82'TVD 2,633.39 1,857.42 1,515.30 -56.88 End Dir :2633.39'MD, 1857.42'TVD 5,142.82 2,291.20 3,985.73 -134.60 Start Dir 4°/100':5142.82'MD,2291.2'TVD , 5,221.46 2,306.85 4,062.77 -136.48 Start Dir 2°/100':5221.46'MD,2306.85'TVD 7,375.98 3,500.00 5,795.61 -166.73 Total Depth :7375.98'MD,3500'TVD 10/16/2014 2:44:07PM Page 5 COMPASS 5000.1 Build 70 ZW m 0 eL m ac a) M3 iii T- .3 J ai 4 Ifi L = a d .E ilfit C N_ C O �j, R U II ME V- N d C9 co a) ifh d N L d• M fl. 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Z co X OI I G NP < I I �1 �� O O - 'lir Q O O O O I 45 r O c (6 U ii LI �` '. -CE m m to o i1 ' O (� -Ni / i 0 pcN NO al .N NM (0 ' O O O 0 °' J = U m z (0 O O O o "a V) a 6) CO CO J o Q - mc o f (uiiT sn 00£) uoi�eaedeS aqua° of ai ue ° O Ws O _ c `) t 8 C - 5 0) cl Ei 0) x o U " > > > 'S t z al > 0) 0) > 5 > > c 9919999 C z a CO a a CO CL a x J co a a a a co a 5 (NC (O (0 W + 4 * + 4 + 04 I - o o • - O —Lc) N - CO - O to _ r-- - - LC) - O o {- — —L L i _ co 0 0 - CD VRI a. - o LI- ---- ------ -----* --------- -...---i- —o _ co 0. V C N OU c i _ _C O m- CO a - m m i a T4 z _ co i C CU CL o _ a I- a a _ —N 0RS = � 0 to Q. e -0 o o OC cp 3 C CL Q 0 o IN _ OCU U NV J d t i � � � � i � � � � i 1 { I I I I { I I I I I I I l I I I I l I i ri I I I I o 0 J 0 V 0' O 0 O to 0 O O fI`, up N O r to N O V+ O 11 N h (O to co N O -,O �J m (u!/og.Z) aojoe- uo!TeJedag < 0 Davies, Stephen F (DOA) From: Luke Keller <Ikeller@hilcorp.com> Sent: Tuesday, October 28, 2014 2:08 PM To: Davies, Stephen F (DOA) Subject: RE: Paxton 9 (PTD#214-173) Attachments: Revised 10-401.pdf Steve, I apologize for the typos on the 10-401. I must have dragged them in from the wrong file..The correct#s are on the drilling program on page#2. Also attached is a scanned copy of the fixed 10-401. Sorry about that! Let me know if there is anything else you need. Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 From: Davies, Stephen F(DOA) [mailto:steve.davies@alaska.gov] Sent: Friday, October 24, 2014 4:24 PM To: Luke Keller Subject: Paxton 9 (PTD #214-173) Luke, Could Hilcorp please provide corrected metes and bounds coordinates(footages from section lines)for the Top of Productive Horizon and Total Depth for Paxton 9? The surface location on the Permit to Drill form (Box 4a) is given as 3051' FEL, 907' FNL,Section 13,T1S, R14W, SM, but the coordinates for the Top of Productive Horizon and Total Depth are listed as being in Section 8 of T5N, R11W, SM. The correct section should be Section 12 of 15, 14W, but I'm not sure if the footage numbers provided are correct. Thanks, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue,Suite 100 Anchorage,AK 99501 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 1 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 Steve Davies at 907-793-1224 or steve.davies@alaska.gov. 2 OVERSIZED DOCUMENT INSERT This file contains one or more oversized documents. These materials may be found in the original hard file or check the parent folder to view it in digital format. TRANSMITTAL LETTER CHECKLIST WELL NAME: Fay h PTD: Q I� 113 Development Service Exploratory Stratigraphic Test Non Conventional FIELD: I. ( \ POOL: 11 I(1 eyi (1t/ M/t 45 Check Box for Appropriate Letter/ Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL The permit is for a new wellbore segment of existing well Permit (If last two digits No. , API No. 50- - - - . in API number are Production should continue to be reported as a function of the original between 60-69) API number stated above. In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name Pilot Hole ( PH) and API number (50- - - - ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce / inject is contingent upon issuance of a Spacing Exception conservation order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for Non-Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application,the following well logs are Well Lo ,n also required for this well: gg g Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 4/2014 To u) 0) 0 a) a u) N N O `o `m _ a m c a 0 H c c O as o o ui _ V E o a) M a a W U) - c E N. U co a a. a E O s a "' a) 0 0 E of w (o O L ca co a r 0 C) 2 a a O N 3 Q o o w m a) - 0 3 0 s- LO `o M N. O C L V) N N V O O O 0 a) o Lr) U a) a) CS) W a --> o_ T O C U u) > o O O 'p c T co Y '0 c O c ami =o 0 w o C C _ a) c Z E o U .N 2 co E o O - N 3 0 Z O u) O co co O OU W a a) T6 2O O 0) "O =O o 0. N Q 0 CO -o c H O c a) O N C u) a o O C u) a) X O 0 E o O T. 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To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. Paxton #9 Ninilchik Unit Kenai Peninsula Borough, Alaska November 19, 2014 – December 02, 2014 Provided by: Approved by: Dave Buthman Compiled by: Josh Dubowski, Eric Andrews Harry E. Bleys Distribution Date: December 30, 2014 Paxton #9 1 TABLE OF CONTENTS 1 MUDLOGGING EQUIPMENT & CREW ................................................................................................2 1.1 Equipment Summary ......................................................................................................................2 1.2 Crew................................................................................................................................................2 2 GENERAL WELL DETAILS...................................................................................................................3 2.1 Well Objectives...............................................................................................................................3 2.2 Hole Data........................................................................................................................................3 2.3 Daily Activity Summary...................................................................................................................4 3 GEOLOGICAL DATA.............................................................................................................................5 3.1 Lithostratigraphy .............................................................................................................................5 3.2 Lithology Details..............................................................................................................................5 3.3 Sampling Program........................................................................................................................13 4 DRILLING DATA..................................................................................................................................14 4.1 Surveys.........................................................................................................................................14 4.2 Bit Record.....................................................................................................................................18 4.3 Mud Record ..................................................................................................................................18 5 SHOW REPORTS ...............................................................................................................................19 6 DAILY REPORTS ................................................................................................................................20 Enclosures 5” / 100’ Formation Log (MD/TVD) 2” / 100’ Formation Log (MD/TVD) 2” / 100’ LWD Combo Log (MD/TVD) 2” / 100’ Drilling Dynamics Log (MD/TVD) 2” / 100’ Gas Ratio Log (MD/TVD) Final Data CD Paxton #9 2 1 MUDLOGGING EQUIPMENT & CREW 1.1 Equipment Summary Parameter Equipment Type /Position Total Downtime Comments Computers – Surface Logging (5) Rigwatch Server, Rigwatch Remote DML, LWD WITS, Rigwatch Remote 0 Ditch gas QGM gas trap; Flame ionization total gas & chromatography. 0 Hook Load / Weight on bit WITS from Pason 0 Mud Flow In Derived from Strokes/Minute and Pump Output 0 Mud Flow Out WITS from Pason 0 Pit Volumes, Pit Gain/Loss WITS from Pason 0 Pump Pressure WITS from Pason 0 Pump Stroke Counters (2) WITS from Pason 0 Rate of Penetration Calculated from Pason 0 RPM WITS from Pason 0 Torque WITS from Pason 0 WITS To/ From Pason Rigwatch Remote (HP Compaq) 0 1.2 Crew Mud Logging Unit Type: Arctic Mud Logging Unit Number: ML030 Logging Geologists Years1 Days2 Sample Catchers Years Days2 Joshua Dubowski 8 11/18 Lindsay Cameron 0.5 14 Eric Andrews 3 14 Harry E. Bleys 14 11/22 *1 Years experience as Mudlogger *2 Days at wellsite between rig up and rig down of logging unit. Paxton #9 3 2 GENERAL WELL DETAILS 2.1 Well Objectives Paxton #9 is a twin to the Paxton #3 Beluga 50 gas sandstone and a follow up to the Paxton #7 which did not reach the intended target due to a stuck BHA. Operator: HILCORP ALASKA, LLC Well Name: Paxton #9 Field: Ninilchik Unit County: Kenai Peninsula Borough State: Alaska Company Representatives: Doug Yessak, Shane Barber Location: Surface Coordinates 3051’ FEL, 917’ FNL, Sec 13, T1S, R14W, SM, AK Ground ( Pad ) Elevation 148’ NGVD88 Rotary Table Elevation 166.6’ AMSL Classification: Development - Gas API #: 50-133-20647-00-00 Permit #: 2141730 Rig Name/Type: Saxon 147 / Land / Double Spud Date November 18, 2014 Total Depth Date: November 28, 2014 Total Depth 6733’ MD / 3503’ TVD Primary Targets Beluga 50 ,Beluga 60 Primary Target Depths Beluga 50: 4503’MD / 2059‘TVD, Beluga 60: 5304’MD / 2434’TVD Total Depth Formation: 6733’ MD / 3503’ TVD Completion Status: LWD-MWD Services. Halliburton/ Sperry Drilling Services Directional Drilling Halliburton/ Sperry Drilling Services Wireline Logging Services None Drilling Fluids Service M.I. Swaco MD/TVD 2.2 Hole Data Max Depth Shoe Depth Hole Section MD (ft) TVD (ft) TD Formation MW ppg Dev oinc Csg Dia MD (ft) TVD (ft) FIT ppg 12 ¼” 2300’ 1421’ Beluga 9.4 73.2 9 5/8” 2291’ 1400’ 12.0 8 ½” 6733’ 3502’ Beluga 9.3 33.20 5 1/2” 6733’ 3503’ - Paxton #9 4 2.3 Daily Activity Summary 11/18/2014: Picked up drill pipe and BHA, ran in hole, and began drilling from 80' to a midnight depth of 136'. 11/19/2014: Drilled ahead from 136' to 1473', pumped sweep and circulated hole clean. Pulling out of hole with elevators at time of midnight report. 11/20/2014: Drilled ahead from 1474' to 2300'. Pumped sweep and circulated out of hole to conductor. 11/21/2014: Ran back into the hole after pulling to conductor, circulated mud and pulled out of hole. Laid down BHA #1 and rigged up to run casing. Ran 9.625" surface casing to 2290', landed hanger, circulated and conditioned mud. Pumped cement job, dropped plug, and displaced mud. 11/22/2014: Rigged down stack and prepared to remove shipping beams and install lower pipe rams. Performed a job safety analysis. Set the double ram and annular torque stack bolts. Continue to install HCR kill and choke valves. Install choke and kill lines, pollution pan, flow nipple and flow line. Close sub doors, and rig up catwalk hydraulic reset V-door. Secure cross chain stack to sub. 11/23/2014: Pre job safety meeting to test casing. Tested casing to 2950 psi for thirty minutes. Replaced plug in kill block. Blew down choke manifold, topdrive and kill line. Held pre job safety meeting to change stab sleeve on motor, and began picking up BHA per Directional driller’s directions. 11/24/2014: Picked up new BHA and tripped in hole and drilled out cement. Drilled 20 Ft of new hole and performed a FIT test to 12.0 pounds. Pulled out of hole and laid down 5 inch drill pipe and picked up 4 inch pipe. Tripped in hole making up stands. Pulled out of hole near surface and tripped back in hole. At present at 1672 Ft. Max gas was 109 u of gas at 2299 Ft. 11/25/2014: Drilled ahead until 3306 Ft and circulated and pumped a sweep prior to tripping out of hole on a short trip to the shoe at 3228 Ft. Circulated and tripped back in hole to bottom where we received trip gas of 223 u. Commenced drilling ahead and presently at 3476 Ft . Max gas was 762 u @ 2740 Ft. 11/26/2014: Drilled ahead all day until 4545 ft. circulated bottoms up and pumped a sweep receiving 321u. Of gas, prior to commencing a short trip to shoe. At present still tripping to shoe. Max gas 504u @ 3860 ft. 11/27/2014: Drilled all day until 5102 FT. circulated bottoms up and received 207 u of gas. Pumped a sweep and commenced a short trip. Tripped back in hole and drilled ahead. Max gas 354u at 4678 FT. Trip gas of 1099 u. at 3335 FT. 11/28/2014: Drilled all day until 5720 Ft. Circulated and pumped a sweep than commenced a short trip to 5067 Ft. Stopped and tripped back in hole to bottom and received 40 units of trip gas. Max gas was 235 u @ 5244 Ft. 11/29/2014: Drilled until 6733 ft., and circulated bottoms up and called TD at 21:18 hrs. Pumped a sweep and did a short trip than began tripping out of hole. 11/30/2014: Pumped a slug and blowed down topdrive and Kelly. Pulled out of hole to 2290'. Checked the flow at the shoe, than continued to pull out of the hole laying down the BHA as per DD instructions. Pulled corrosion ring located at the top of the flex collars. Made up bit and dumb iron and ran in hole with drill pipe to 3721'. Pumped a dry job, and loaded mud dog and pull out of hole laying down drill pipe. At present at 211 ft. Trip gas was 75 u. Paxton #9 5 3 GEOLOGICAL DATA 3.1 Lithostratigraphy Tops provided by Hilcorp Geologist. PROGNOSED ACTUAL FORMATION MD (ft) TVD (ft) SSTVD (ft) MD (ft) TVD (ft) SSTVD (ft) Beluga 50 Top 4524’ 2340’ -1970’ 4503’ 2059’ -1889’ Beluga 50 Channel 4777’ 2175’ -2005’ Beluga 50 Bottom 4909’ 2233’ -2063’ Beluga 60 4987’ 2476’ -2306’ 5304’ 2434’ -2264’ Beluga 65 5768’ 2731’ -2561’ Beluga 70 5919’ 2841’ -2671’ Beluga 80 6142’ 3014’ -2844’ Beluga 90 6298’ 3141’ -2971’ Beluga 100 6456’ 3272’ -3102’ Beluga 110 6504’ 3312’ -3142’ Beluga 130 6668’ 3449’ -3279’ TD WELL 6733’ 3503’ -3334’ 3.2 Lithology Details Full service mudlogging began at 2300’ MD/ 1421’ TVD. All the sample lithology descriptions provided by Canrig began after the surface casing point. The well includes Sterling, Beluga and Tyonek formations. The basic building blocks in this depositional area have a unique lithology of thick structured formations of tuffaceous sediments. These fluvial deposits are of tuffaceous claystone, tuffaceous siltstone, tuffaceous sandstones, and lose disaggregated, unconsolidated sands. The ash and tuff are revealed along with devitrified volcanic glasses as loosely (friable) to heavily indurated clasts of volcanic origin. CEMENT, SAND, TUFFACEOUS CLAYSTONE, AND TUFFACEOUS SILTSTONE ( 2300' - 2375' ) = Tannish gray finely grained cement from drilling casing to loose poorly sorted unconsolidated sands of upper fine to lower coarse grain size; dominantly quartz of a hazy translucent to grayish white color; tuffaceous claystone is soft and malleable with rounded slumped cuttings and smooth texture; tuffaceous siltstone is crumbly with irregular fracture; wedge like cuttings; gritty texture; overall dull earthy to slight shiny luster due to hydrated cuttings submerged in drilling fluids. SAND ( 2375' - 2450' ) = Translucent to grayish white opaque with an overall medium dark gray color; very fine upper to upper medium grains; poorly to fair sorted; subangular to subround with low to fair sphericity; young immature textural maturity; loose unconsolidated sands are entrained within tuffaceous claystones, tuffaceous siltstones, an small coal stringer with visible degassing from loosely indurated coal clasts with interior connectivity allowing quantities of escaping gases to become visible. Paxton #9 6 TUFFACEOUS CLAYSTONE/SAND ( 2450' - 2560') = Dark medium grey to medium grey with brown and black hues; poor induration; clumpy; pulverulent to crumbly to malleable; irregular to earthy fracture; amorphous cuttings habit; dull to earthy luster; silty to clayey texture; sands are typically light medium grey overall; dominated by clear to translucent grey and white quartz; upper fine to lower medium; good to moderate sorting; sub rounded to rounded; good sphericity; tuffaceous and carbonaceous sediment common throughout the interval; coals are sub bituminous; semi tough to brittle and crumbly; blocky to planar fracture; platy to flaky cuttings habit; resinous to earthy luster; no hydrocarbon indicators. TUFFACEOUS SILTSTONE/CLAYSTONE ( 2560' - 2600' )= Dark medium grey to medium grey with black to dark brown hues; poor to occasionally moderate induration; clumpy to lumpy; pulverulent to crumbly; earthy to irregular; amorphous cuttings habit; dull to earthy luster. SAND (2600' - 2660') = Medium grey to dark medium grey; unconsolidated; upper fine to lower medium with upper medium and lower fine common; moderate to well sorted; angular to sub angular with trace moderately rounded grains; sub spherical to sub discoidal; sample 50% translucent white to clear quartz; 40% dark grey to medium light grey lithics; minor amount of biotite; pyrite and tuffaceous claystone/siltstone. SAND/TUFFACEOUS CLAYSTONE (2660' - 2740') = Medium grey with black to brown hues to dark medium grey; upper to lower fine to lower medium; moderate to poor sorting; sub angular to angular to occasionally sub rounded; sub spherical to sub discoidal; predominantly clear to translucent white quartz; dark to light grey lithics very common; moderate amount of tuffaceous claystone; poorly consolidated; clumpy to lumpy; crumbly to pulverulent; earthy to irregular fracture; amorphous cuttings habit; dull to earthy luster; trace biotite and pyrite. SAND/TUFFACEOUS CLAYSTONE (2740' - 2810') = Dark medium grey to medium grey with black to brown hues; upper fine to lower medium; moderate to poor sorting; sub angular to angular to occasionally sub rounded; sub spherical to sub discoidal; predominantly clear to translucent white quartz; dark to light grey lithics very common; moderate amount of tuffaceous claystone; poorly consolidated; lumpy to clumpy; crumbly to pulverulent; irregular to earthy fracture; amorphous cuttings habit; dull to earthy luster. TUFFACEOUS CLAYSTONE/SAND (2810' - 2890') = Dark medium grey to medium grey with dark brown to black hues; clumpy to lumpy; crumbly to pulverulent; earthy fracture; dull to earthy luster; amorphous cuttings habit; sands are unconsolidated; lower medium to upper fine to upper very fine; sub angular to sub rounded; sub spherical to sub discoidal; moderate to poor sorting; clear to translucent white quartz and dark to medium grey lithics are common; trace pyrite, biotite and carbonaceous sediment. SAND (2890' - 2940') = Grayish black to dark gray; upper fine to very fine; spherical to subprismoidal; subrounded to round; moderately to well sorted; moderately to well sorted; texturally immature; quartz predominantly clear to opaque; 10% tuffaceous claystone; biotite and carbonaceous material common; trace volcanic lithics. TUFFACEOUS CLAYSTONE (2940' - (2940' - 3040') = Dark gray to medium dark gray; easily friable; poor to very poor induration; pulverulent to crumbly tenacity; irregular to blocky tenacity; metallic to dull luster; smooth to clayey texture; predominantly massive structure; curdy and mushy consistency; quartz sand present; clear to white opaque; upper very fine to upper fine; spherical to sub--discoidal; sub- rounded; poorly sorted; unconsolidated; trace volcanics and lignitic to sub-bituminous coal. TUFFACEOUS SILSTONE/CLAYSTONE (3040' -- 3090') = Medium dark gray to dark gray; moderately to easily friable; moderate to poor induration; brittle to sectile tenacity; tabular to elongate cutting habit; sucrosic to matte texture; earthy luster; cohesive clay properties; clumpy to stiff consistency; rare lenticular bedding; sub-bituminous coal in sample 3080'; occasional lithic volcanics; trace biotite. Paxton #9 7 TUFFACEOUS CLAYSTONE (3090' - 3145') = Medium gray to dark gray; friable to easily friable; very poor to poorly indurated; malleable tenacity; dull to earthy luster; expansive to adhesive play properties; pasty to clumpy consistency; trace amounts of carbonaceous material; occasional trace amounts of biotite. TUFFACEOUS SILTSTONE/SAND (3150' - 3255') = Grayish black to dark gray; soft to easily friable; very poor to poor induration; dense to pulverulent tenacity; massive cutting habit; tabular to slumped cuttings; earthy to metallic luster; punky clay consistency; occasional lenticular and thick laminae structure; gritty texture grading to smooth with increased tuffaceous claystone interbedded; loose unconsolidated quartz sand; poorly sorted from upper coarse to upper very fine grain size; subangular to rounded with low to fair sphericity; larger clasts have visible surface etching and conchoidal caving; a thinly structured stringer of coal in this lower sequence with visible evidence of degassing indicating a light indurate coal; overall sand grain size decreasing to very fine to lower fine in lower sequence with back ground gases remaining static. SAND ( 3255' - 3306' ) = Translucent to grayish white opaque color; well sorted subrounded; fair sphericity; dominantly quartz grading medium low to very fine low; occasional trace lower coarse grain with interbedded tuffaceous siltstone claystone, feldspar, carbonaceous shale. SAND/ TUFFACEOUS SANDSTONE ( 3306' - - 3400' ) = Light medium gray overall; loose unconsolidated sands interbedded with grain supported to matrix supported sandstones composed of volcanic ash and tuff; non reactive to HCl; obvious good visual porosity; grain supported sandstones are moderately indurated and resist being sheared; lower sequence increased tuffaceous claystone and siltstone interbedded with sands and tuffaceous sandstones; very fine lower to very fine upper found in tuffaceous sandstones. TUFFACEOUS SILTSTONE ( 3400' - 3440' ) = Overall medium dark gray color; soft to crumbly tenacity; irregular fracture; rounded blocky cuttings; gritty texture; overall thick basal structure; dull to shiny luster due to volcanic ash, tuff and devitrified volcanic glass. TUFFACEOUS CLAYSTONE/ TUFFACEOUS SILT- -STONE ( 3440' - 3530' ) = Dark gray overall color; thick structured tuffaceous claystone and siltstone formations interbedded with loose disaggregated poor to fair sorted angular to subrounded quartz grains; very fine to upper medium grain size; tuffaceous claystone has soft malleable consistency; irregular fracture and rounded slumped cuttings; smooth texture with a thick basal structure; tuffaceous siltstone is firmer and has malleable to pulverulent to crumbly tenacity; irregular fracture; wedge like cuttings; gritty texture; thick basal structure. TUFFACEOUS CLAYSTONE ( 3530' - 3585' ) = Medium dark gray to dark gray color; soft malleable consistency; irregular fracture; slumped rounded cuttings; smooth texture with shiny waxy luster; thick basal structure; carbonaceous shale, carbonaceous materials, and sandstones entrained within the hydrated claystones, along with loose disaggregated sands of varied grain sizes. TUFFACEOUS CLAYSTONE (3585' - 3655') = Dark medium grey to medium grey with dark brown and black hues; clumpy to mushy; pulverulent to malleable; earthy to irregular fracture; amorphous cuttings habit; dull to earthy luster; clayey to silty texture; good cohesion; poor adhesion; moderate amount of coal in samples; matte black; bituminous to sub bituminous; semi tough to brittle and crumbly; planar to hackly fracture; platy to flaky cuttings habit; resinous to greasy luster; visible off gassing. SAND (3655' - 3715') = Dark medium grey to medium grey with black to dark brown hues; unconsolidated; lower medium to upper and lower fine grained; moderate to well sorted; sub angular to sub rounded to angular; sub spherical to spherical to sub discoidal; comprised of clear to translucent white quartz and dark to medium grey lithics; minor amounts of tuffaceous claystone and siltstone. TUFFACEOUS CLAYSTONE (3715' - 3795') = Dark medium grey to medium grey with dark brown and black hues; mushy to pasty; pulverulent to malleable; earthy to irregular fracture; dull to earthy luster; amorphous cuttings habit; clayey clayey to silty texture; good cohesion; moderate adhesion; sands are dominated by clear to translucent white quartz and dark medium to medium grey lithics; upper fine to Paxton #9 8 lower medium to upper very fine; moderate to poor sorting; sub angular to sub rounded to angular; sub spherical to sub discoidal; minor amount of carbonaceous sediment. SAND/TUFFACEOUS CLAYSTONE (3795' - 3910') = Medium grey with dark brown to black hues to dark medium grey; upper fine to lower medium to upper very fine; unconsolidated to rare soft and easily friable tuffaceous clasts; moderate to poor sorting; sub angular to angular to sub rounded; sub spherical to sub discoidal; dominated by clear to translucent white quartz and dark medium to medium grey lithics; tuffaceous claystone is poorly indurated; clumpy to pasty pulverulent to malleable; irregular to earthy fracture; amorphous cuttings habit; clayey to silty texture; dull to earthy luster; moderate amount of coal; matte black; bituminous to sub bituminous; semi tough to brittle and crumbly; planar to hackly; platy to flaky cuttings habit; resinous to slightly greasy luster; trace off gassing. SAND/TUFFACEOUS CLAYSTONE (3910' - 3990') = Dark medium grey to medium grey with blackish hues; upper fine to lower medium; moderate to poor sorting; sub angular to sub rounded; unconsolidated to soft and easily friable clasts; sub spherical to sub discoidal; primarily made up of clear to translucent white quartz and dark grey lithics; tuffaceous clasts are matrix supported; claystones are poorly indurated; malleable to pulverulent; earthy to irregular fracture; amorphous cuttings habit; minor amount of coal and tuffaceous siltstone. TUFFACEOUS SILTSTONE/TUFFACEOUS CLAYSTONE (3990' - 4055') = Dark gray to medium dark gray; friable to easily friable; predominantly poorly indurated; crumbly to malleable; wedgelike to massive cutting habit; metallic to sparkling; lumpy to mushy with occasional punky material; some lenticular bedding; quartz present, upper very fine grained, well to very well sorted, translucent to dull; carbonaceous material present. SAND (4055' - 4115') = Dark gray to medium dark gray; predominately upper fine to upper medium with some very fines; spherical to sub-prismoidal; sub-rounded to rounded; poorly to moderately well sorted; unconsolidated; textural immature; trace carbonaceous material; occasional volcanic lithics; trace amounts of biotite; tuffaceous siltstone, moderately friable, dull to earthy luster. TUFFACEOUS CLAYSTONE (4115' - 4175') = Medium dark gray to dark gray with occasional light white hues; friable to firm friable; moderately indurated; dense to tough tenacity; blocky to mottled fractures; smooth to clayey texture; dull to occasional metallic luster; cohesive clay properties; clumpy and pasty consistency; some claystone imbedded in siltstone; trace carbonaceous material. SAND (4175' - 4230') = Dark gray to grayish black; upper very fine to upper fines with some upper mediums; spherical to sub-prismoidal; angular to sub-rounded; poor to very poorly sorted; unconsolidated; texturally immature; predominately quartz; carbonaceous material common; trace amounts of volcanic lithics; some tuffaceous claystones. TUFFACEOUS CLAYSTONE ( 4230' - 4305 ) = Dark gray with slight black hues; soft malleable consistency due to hydrated by drill fluid; irregular fracture; slumped rounded cuttings; entrained by loose disaggregated sands, tuffaceous sand- -stone, black carbonaceous material, feldspars, calcite, and trace shales grading towards carbonaceous shale; smooth texture; thick moderately cohesive to adhesive properties; thick basal structure; dull to shiny with volcanic ash, tuff and devitrified glass in the tuffaceous matrix cement. SAND ( 4305' - 4395' ) = Bluish gray opaque color to dirty grayish white to trace translucent quartz grains; poorly sorted of upper fine to lower coarse grain size; angular to subrounded; low to fair sphericity; young textural maturity; surface etching; dominantly quartz with sand clasts of tuffaceous siltstone, coal, feldspars, trace biotite and calcite; matrix cement is volcanic ash , tuff and devitrified glass; interbedded with the sands are trace tuffaceous sandstones, thick structured tuffaceous claystone and tuffaceous siltstones; tuffaceous sandstone does no react to HCl, but does appear to have fair visual porosity while hydrated. Paxton #9 9 TUFFACEOUS SILTSTONE ( 4395' - 4440' ) = Medium dark gray to dark gray with black hues; crumbly to firmer crunchy tenacity; softer and malleable in part due to immersion and hydrated by drilling fluids; irregular fracture; smooth to gritty texture; dull waxy to shiny luster due to volcanic devitrified glass embedded with ash tuff composition; over all structure has a thick basal structure; tuffaceous claystone, carbonaceous shales, feldspars, calcites, and loose disaggregated unconsolidated sands with trace tuffaceous sandstones. SAND/TUFFACEOUS CLAYSTONE ( 4440' - 4625' ) = Primarily dark gray with hues of medium gray and grayish black; upper very fine ranging to lower medium grains with occasional lower coarse; sub- prismoidal to prismoidal to spherical; angular to sub-rounded; very poorly to poorly sorted; unconsolidated; grain supported; texturally immature; good estimated visual porosity; dominantly quartz, opaque to clear; feldspars; trace biotite; tuffaceous claystone easily friable, crumbly to pulverulent tenacity, clayey to mottled texture, mostly thick structure but occasional lenticular structure. TUFFACEOUS CLAYSTONE/SAND ( 4625' - 4710' ) = Medium dark gray to dark gray; soft to easily friable to some friable; mostly poorly indurated to occasional moderately indurated; elastic to gently stiff tenacity; curved to massive cuttings habit; metallic to waxy dull luster; mushy and clumpy to punky consistency; massive bedding when present; quartz sand present, lower fine to upper fine, spherical to sub- prismoidal, sub-angular to sub-rounded, moderately sorted, unconsolidated, texturally young; occasional siltstone with lenticular carbonaceous material; trace feldspars and biotite. SAND ( 4710' - 4760' ) = Dark gray to grayish black with medium gray hues; predominantly fine grains with total range of upper very fine to lower medium grains; sub-prismoidal to sub-discoidal; sub-angular with some sub-rounded; unconsolidated; texturally immature; bituminous coal present; trace feldspars. TUFFACEOUS CLAYSTONE/TUFFACEOUS SILT- -STONE/SAND ( 4755' - 4885' ) = Medium to dark gray with black hues to dark gray with greenish hues; soft malleable to firmer crumbly tenacity; irregular fracture; slumped to wedge like cuttings with smooth texture; dull to shiny luster due to devitrified glass in matrix cement; loose disaggregated sands are increasing in bottom of sequence; trace black carbonaceous material interbedded; tuffaceous siltstone is in trace amounts with obvious crumbly tenacity; irregular fracture; blocky cuttings; gritty texture with slight shiny luster and thin structure; loose disaggregated sands increased exponentially to 80 - 90% ; very fine upper to lower medium grain size; dominantly dirty grayish white to darker blue color with upper very fine to upper medium grain size; fair sorting; subround to round with trace subangular; fair to middle aged textural maturity; sands reducing to 70-80 quartz with 20% to 30% sand sized tuffaceous claystone and tuffaceous siltstone clasts. SAND ( 4885' - 4965' ) = Dark gray over all with quartz, tuffaceous claystone, tuffaceous siltstone, black carbonaceous material and trace accessory minerals fairly well sorted from upper very fine to upper medium to trace lower coarse grain size; poorly sorted; subangular to subround; low to fair sphericity; young to moderate textural maturity; increased quantities of tuffaceous claystone and siltstone sand clast; increase of tuffaceous claystone with moderate to strong cohesive and adhesive properties; trace black carbonaceous materials entrained. TUFFACEOUS CLAYSTONE ( 4965' - 5030 ) = Dark gray with black and greenish hues; soft malleable when hydrated; due to bit and drilling fluid; black carbonaceous material, loose disaggregated sands, tuffaceous siltstone, and trace accessory minerals interbedded; smooth texture; shiny luster; thick structure. SAND ( 5030' - 5080' ) = Translucent to dirty grayish white to blue color with an overall dark gray; disaggregated poorly sorted grains, fine lower to upper medium with trace lower coarse grains; angular to subrounded; low to fair sphericity; low to moderate textural maturity; entrained in soft tuffaceous claystone. SAND ( 5080' - 5170 ) = Translucent clear to dirty grayish white and blue; upper fine to lower medium grain size; poor to fair sorted; fair to moderate sphericity; subrounded to round; middle age textural Paxton #9 10 maturity; entrained with tuffaceous siltstone and tuffaceous claystone; both having matrix composed of volcanic ash, tuff and devitrified glass; trace lower coarse grains in loose disaggregated sands; trace black carbonaceous material and carbonaceous shales. TUFFACESOUS CLAYSTONE ( 5170' - 5220' ) = Medium gray to dark gray with black and greenish hues; soft consistency due to bit action and hydrated by drilling fluid; black carbonaceous material interbedded; irregular fracture; slumped cuttings; smooth texture with waxy to shiny texture; thick basal structure. SAND/TUFFACEOUS CLAYSTONE (5220' - 5300') = Dark medium grey to medium grey with very dark blue to black hues; lower fine to upper medium to lower medium; moderate to good sorting; sub angular to sub rounded; unconsolidated to soft and easily friable clasts; sub spherical to sub prismoidal; primarily made up of clear to translucent white quartz and dark grey lithics; tuffaceous clasts are matrix supported; claystones are poorly indurated; malleable to pulverulent; earthy to irregular fracture; amorphous cuttings habit; minor amount of coal and tuffaceous siltstone. SAND/TUFFACEOUS CLAYSTONE (5300' - 5390') = Dark medium grey to medium grey with very dark blue to black hues; lower fine to upper medium to lower medium; moderate to good sorting; sub angular to angular to sub rounded; unconsolidated to trace soft to easily friable clasts; sub spherical to sub prismoidal; predominantly made up of clear to translucent white quartz and medium to dark grey lithics; tuffaceous clasts are matrix supported; claystones are poorly indurated; malleable to pulverulent; irregular to earthy fracture; amorphous cuttings habit; minor amount of coal and tuffaceous siltstone. SAND (5390' - 5450') = Dark gray to grayish black speckled with medium gray; upper fine to lower fine to upper medium grains; moderate to high sphericity with some sub-prismoidal; sub-rounded to rounded to sub-angular; moderately to poorly sorted; unconsolidated; predominately quartz grains, white opaque to translucent to slightly yellow; occasional feldspars; minor amounts of carbonaceous material. TUFFACEOUS CLAYSTONE/SAND (5450' - 5550') = Medium dark gray to dark gray with hues of olive and medium light gray; soft to easily friable; poor to very poor induration; crumbly to dense tenacity; weakly adhesive; wedge-like to nodular cuttings habit; mushy to punky consistency; dull luster with subtle metallic sparkle; quartz sand, white to yellowy to transparent, mostly lower fine grains but range from upper very fine to lower medium, low sphericity, sub-rounded to sub-angular, some tuffaceous clay cement, minor amounts of feldspars; dark carbonaceous microlamina intergrading in siltstone; trace biotite. TUFFACEOUS CLAYSTONE/SAND (5550' - 5610') = Medium dark gray to dark gray with speckles of yellowish gray; friable to easily friable; poor to moderate induration; elongate to wedgelike to massive cuttings habit; smooth to gritty texture; dull luster; mildly hydro fissile; occasional tiny stringers and thinly bedded carbonaceous material; minor amounts of tuffaceous sandstones composed of coarse quartz. TUFFACEOUS CLAYSTONE/SAND (5510' - 5695') = Dark black to medium dark gray with light gray hues; friable to easily friable; moderate to poorly indurated; crumbly to dense tenacity; blocky to bladed to play cuttings habit; dull luster; cohesive to hydro fissile and slightly expansive; stiff to crumbly to pasty consistency; smooth to gritty texture; mass bedding; quartz sands, upper fines to lower fines to lower medium, moderately spherical, sub-rounded to sub-angular, unconsolidated, immature, some volcanic lithics; occasional siltstone with stringers of carbonaceous material. SAND ( 5695' - 5770' ) = Translucent clear to medium dark blue hues to dirty grayish white to blue opaque color with overall dark gray color; loose disaggregated unconsolidated sands composed of quartz, black carbon clasts, tuffaceous claystone and siltstone sand sized particles; upper fine to upper medium grain size; fair sorting; fair to moderate sphericity; subround to round; trace larger coarser grains with surface etching; trace black carbon materials; trace carbonaceous shales of dark red brown hues. Paxton #9 11 SAND/TUFFACEOUS CLAYSTONE/TUFFACEOUS SILTSTONE ( 5770' - 5830' ) = Overall dark gray with black and greenish hues; poorly sorted from lower fine to upper coarse grains; subround to round; poorly sorted; fair to high sphericity; fair to moderate textural maturity; entrained tuffaceous siltstone and claystone; tuffaceous claystone has soft malleable consistency due to bit action and hydrated by drilling fluid. TUFFACEOUS SILTSTONE AND TUFFACEOUS CLAYSTONE ( 5830' - 5940' ) = Medium dark gray to dark gray with black and greenish hues; tuffaceous claystone is soft malleable due to bit action and hydrated by drilling fluids; irregular fracture and slumped rounded cuttings; smooth texture; slight shiny luster due to devitrified glass; thick structure; tuffaceous siltstone is firmer with crumbly tenacity and irregular fracture with rounded blocky cuttings; gritty texture also with shiny luster due to volcanic ash tuff and devitrified glass in the matrix cement; coals traces and carbonaceous shale clasts are thinly bedded stringers. SAND ( 5940' - 6010' ) = Translucent clear to dirty grayish white to blue gray color; poorly sorted from fine lower to coarse upper; angular to subrounded; poor to low sphericity; textural maturity is low; large clasts of two mm in length are in evidence as possible conglomerate sand particles; sands entrained in larger bodies of tuffaceous claystone and siltstone with trace black carbonaceous shales and thinly bedded stringers of coal; trace tuffaceous sandstone scattered through out. COAL ( 6015' - 6060' ) = Dark brown to matte black to vitreous black color; firm hard brittle tenacity; splintery to blocky cuttings; smooth to rough texture due to protruding fractured laminae and conchoidal cratering; visible degassing; evidence of cleat jointing; brown lignite to blacker subbituminous, possibly bituminous in sample; shiny vitreous luster; overall thin to slightly thicker structure; dark brown to black carbonaceous shale scattered through out sample. TUFFACEOUS CLAYSTONE (6060' - 6140') = Dark gray to grayish black; easily friable to soft; poor to very poorly indurated; platy cuttings habit; dull to earthy to metallic luster; smooth to gritty texture; clumpy to tacky consistency; minor bedding of clays and carbonaceous material; trace amounts of dark yellowish orange sandstone, very fine grained. TUFFACEOUS CLAYSTONE/SAND (6140' - 6230') = Medium dark gray to dark gray with medium gray hues; firm friable to friable; moderately to poorly indurated; brittle to stiff to crunchy tenacity; massive to wedgelike cuttings habit; dull to earthy to greasy luster; smooth to mottled to silty texture; pliable clay properties with trend of increasing hydro fissile; lumpy to pasty consistency; mass bedding to occasion carbonaceous stringers; sand, quartz, upper fines to upper very fines, spherical to sub- discoidal, angular to rounded, moderately to poorly sorted, textually immature; minor carbonaceous material; trace volcanic lithics. TUFFACEOUS CLAYSTONE (6230' - 6310') = Medium dark gray to dark gray with grayish black hues; easily friable to friable; moderately to poorly indurated; crumbly to malleable tenacity; vitreous to earthy luster; tabular to platy cuttings habit; pasty to stiff consistency; hydro fissile to plastic clay properties; mass to lenticular bedding; common carbonaceous material; trace pale yellowish orange lithic volcanics. COAL (6310' - 6330') = Black to grayish black; hard to moderately hard; moderate to well indurated; brittle; bladed to wedgelike to tabular cuttings habit; smooth to matte luster. TUFFACEOUS CLAY (6330' - 6420') = Dark gray to medium dark gray with grayish black hues; easily friable to friable; poorly to moderately indurated; crumbly to brittle tenacity; nodular to elongate to bladed cuttings habit; earthy to vitreous luster; smooth to mottled texture; adhesive to hydro fissile clay properties; punky to pasty to lumpy consistency; rare carbonaceous stringers; quartz sands, lower fine ranging to lower medium grained, moderate to high sphericity, sub-angular to rounded, moderate to poor sorting, unconsolidated, immature. Paxton #9 12 TUFFACEOUS CLAY (6420' - 6480') = Dark gray to dark gray with black hues; soft consistency; irregular fracture; slumped cuttings; smooth texture; thick basal structure; shiny luster due to volcanic ash, tuff and devitrified glass; entrained loose disaggregated sands composed of tuffaceous siltstone, tuffaceous claystone, black carbon material, coal shards, carbonaceous shale shards and trace tuffaceous sandstone. SAND ( 6480' - 6565' ) = Quartz sand is loose unconsolidated disaggregated sand composed of quartz, tuffaceous claystone, tuffaceous siltstone, black carbon material, coal clasts, trace calcites, and carbonaceous shale shards; sands are composed of 50% quartz and the other 50% is drawn from the minerals mentioned above; poorly sorted; upper fine to lower medium grain size; low to fair sphericity; young textural maturity with sands interbedded with tuffaceous claystones and siltstones; sands appear as thinly bedded stringer between the tuffaceous claystones and the tuffaceous siltstones. TUFFACEOUS CLAYSTONE ( 6565' - 6635' ) = Medium dark gray to dark gray with black and greenish hues; soft malleable consistency; irregular fracture; slumped cuttings; smooth texture; shiny luster; thick basal structure; entrained with loose unconsolidated sands of upper fine to lower medium grains; fair sorted and fair sphericity; middle aged textural maturity; traces of coal shards carbonaceous shale shards, and tuffaceous sandstones. COAL ( 6630' - 6660' ) = Matte black to shiny vitreous black; brittle tenacity; parallel to splintery fracture; blocky cuttings; smooth texture; shiny vitreous luster; thinly bedded; evidence of cleat with sub-bituminous and possibly bituminous coals present. TUFFACEOUS CLAYSTONE ( 6660' - 6733' ) = Dark gray color; soft consistency; irregular fracture; slumped wedge like cuttings; smooth texture; slight shiny luster; thick basal structure. Paxton #9 13 3.3 Sampling Program The sampling program, specified by the Hilcorp Geologist called for the collection of two sets of Washed and Dried Reference Samples beginning at 2300’ MD. The resulting set, interval, and distribution are shown below. Set A Type and Purpose Interval Frequency Distribution BOX 1 Washed and Dried Reference Samples 2300’ – 4010’ 30’ David Buthman Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 BOX 2 Washed and Dried Reference Samples 4010’-4550’ 4550’-5250’ 5250-5520’ 30’ 20’ 30’ David Buthman Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 BOX 3 Washed and Dried Reference Samples 5520’-6733’ 30’ David Buthman Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 Set B Type and Purpose Interval Frequency Distribution BOX 1 Washed and Dried Reference Samples 2300’ – 4010’ 30’ David Buthman Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 BOX 2 Washed and Dried Reference Samples 4010’-4550’ 4550’-5250’ 5250-5520’ 30’ 20’ 30’ David Buthman Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 BOX 3 Washed and Dried Reference Samples 5520’-6733’ 30’ David Buthman Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 Paxton #9 14 4 DRILLING DATA 4.1 Surveys Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 18.50 0.00 0.00 18.50 0.00 0.00 0.00 0.00 162.58 3.74 309.93 162.48 3.02 -3.60 3.02 2.59 225.52 5.79 316.11 225.20 6.62 -7.38 6.62 3.36 284.97 8.53 318.75 284.18 12.10 -12.37 12.10 4.64 347.58 9.29 318.63 346.03 19.39 -18.77 19.39 1.22 376.51 9.33 317.84 374.58 22.88 -21.89 22.88 0.46 433.98 9.53 324.52 431.28 30.21 -27.78 30.21 1.93 493.38 11.20 333.77 489.71 39.38 -33.18 39.38 3.97 546.28 11.93 335.62 541.53 48.98 -37.71 48.98 1.55 617.45 15.48 339.82 610.67 64.60 -44.03 64.60 5.17 648.12 17.23 340.70 640.10 72.72 -46.94 72.72 5.79 678.80 19.62 341.68 669.20 81.91 -50.06 81.91 7.85 711.63 22.67 343.08 699.82 93.19 -53.64 93.19 9.40 741.57 24.80 344.48 727.22 104.77 -57.00 104.77 7.36 772.47 26.37 345.55 755.09 117.66 -60.44 117.66 5.29 805.23 28.64 347.06 784.15 132.35 -64.02 132.35 7.24 837.31 30.89 348.55 812.00 147.92 -67.37 147.92 7.39 837.31 30.89 348.55 812.00 147.92 -67.37 147.92 7.39 868.43 33.39 350.24 838.35 164.19 -70.41 164.19 8.55 899.30 36.15 351.46 863.70 181.57 -73.21 181.57 9.21 931.40 38.10 353.03 889.29 200.76 -75.81 200.76 6.76 962.17 40.35 354.06 913.13 220.10 -78.00 220.10 7.63 994.76 43.23 355.51 937.43 241.72 -79.96 241.72 9.30 1024.36 45.59 356.18 958.57 262.38 -81.46 262.38 8.13 1056.85 47.87 356.90 980.84 285.99 -82.89 285.99 7.20 1088.16 49.55 358.36 1001.50 309.49 -83.85 309.49 6.42 1119.47 51.48 359.55 1021.41 333.65 -84.29 333.65 6.82 1153.39 53.83 0.64 1041.99 360.61 -84.24 360.61 7.39 1182.64 56.11 0.96 1058.78 384.56 -83.90 384.56 7.85 1214.76 58.85 0.77 1076.04 411.64 -83.50 411.64 8.55 1246.13 61.10 0.97 1091.74 438.80 -83.08 438.80 7.20 1280.33 63.88 1.12 1107.53 469.12 -82.53 469.12 8.12 1309.26 66.50 0.72 1119.67 495.38 -82.11 495.38 9.15 1341.59 69.25 0.92 1131.85 525.32 -81.68 525.32 8.54 1372.03 70.33 1.37 1142.36 553.88 -81.11 553.88 3.80 Paxton #9 15 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 1405.02 71.71 1.48 1153.09 585.06 -80.34 585.06 4.21 1436.23 74.09 0.80 1162.27 614.89 -79.74 614.89 7.90 1469.63 74.46 0.38 1171.32 647.04 -79.41 647.04 1.64 1499.02 74.86 0.50 1179.09 675.38 -79.20 675.38 1.38 1563.64 72.35 0.01 1197.33 737.36 -78.92 737.36 3.95 1629.57 72.62 359.50 1217.18 800.24 -79.19 800.24 0.84 1689.94 73.09 0.11 1234.97 857.92 -79.38 857.92 1.24 1752.41 73.58 0.22 1252.89 917.77 -79.20 917.77 0.80 1815.86 75.46 359.65 1269.83 978.91 -79.27 978.91 3.09 1877.42 75.76 358.25 1285.13 1038.53 -80.36 1038.53 2.26 1943.06 75.16 357.73 1301.61 1102.03 -82.59 1102.03 1.18 2005.23 73.62 356.84 1318.33 1161.83 -85.42 1161.83 2.84 2068.57 72.75 356.70 1336.65 1222.37 -88.84 1222.37 1.39 2132.19 73.73 356.09 1355.00 1283.17 -92.67 1283.17 1.79 2195.82 73.05 356.17 1373.18 1344.00 -96.79 1344.00 1.08 2259.87 72.80 356.24 1391.99 1405.09 -100.84 1405.09 0.41 1436.23 74.09 0.80 1162.27 614.89 -79.74 614.89 7.90 1469.63 74.46 0.38 1171.32 647.04 -79.41 647.04 1.64 1499.02 74.86 0.50 1179.09 675.38 -79.20 675.38 1.38 1563.64 72.35 0.01 1197.33 737.36 -78.92 737.36 3.95 1629.57 72.62 359.50 1217.18 800.24 -79.19 800.24 0.84 1689.94 73.09 0.11 1234.97 857.92 -79.38 857.92 1.24 1752.41 73.58 0.22 1252.89 917.77 -79.20 917.77 0.80 1815.86 75.46 359.65 1269.83 978.91 -79.27 978.91 3.09 1877.42 75.76 358.25 1285.13 1038.53 -80.36 1038.53 2.26 1943.06 75.16 357.73 1301.61 1102.03 -82.59 1102.03 1.18 2005.23 73.62 356.84 1318.33 1161.83 -85.42 1161.83 2.84 2068.57 72.75 356.70 1336.65 1222.37 -88.84 1222.37 1.39 2132.19 73.73 356.09 1355.00 1283.17 -92.67 1283.17 1.79 2195.82 73.05 356.17 1373.18 1344.00 -96.79 1344.00 1.08 2259.87 72.80 356.24 1391.99 1405.09 -100.84 1405.09 0.41 1436.23 74.09 0.80 1162.27 614.89 -79.74 614.89 7.90 1469.63 74.46 0.38 1171.32 647.04 -79.41 647.04 1.64 1499.02 74.86 0.50 1179.09 675.38 -79.20 675.38 1.38 1563.64 72.35 0.01 1197.33 737.36 -78.92 737.36 3.95 1629.57 72.62 359.50 1217.18 800.24 -79.19 800.24 0.84 1689.94 73.09 0.11 1234.97 857.92 -79.38 857.92 1.24 1436.23 74.09 0.80 1162.27 614.89 -79.74 614.89 7.90 1469.63 74.46 0.38 1171.32 647.04 -79.41 647.04 1.64 1499.02 74.86 0.50 1179.09 675.38 -79.20 675.38 1.38 1563.64 72.35 0.01 1197.33 737.36 -78.92 737.36 3.95 Paxton #9 16 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 2005.23 73.62 356.84 1318.33 1161.83 -85.42 1161.83 2.84 2068.57 72.75 356.70 1336.65 1222.37 -88.84 1222.37 1.39 2132.19 73.73 356.09 1355.00 1283.17 -92.67 1283.17 1.79 2195.82 73.05 356.17 1373.18 1344.00 -96.79 1344.00 1.08 2259.87 72.80 356.24 1391.99 1405.09 -100.84 1405.09 0.41 2317.34 72.31 356.88 1409.22 1459.82 -104.13 1459.82 1.36 2344.31 72.36 356.87 1417.41 1485.48 -105.53 1485.48 0.19 2405.29 72.89 356.17 1435.62 1543.57 -109.06 1543.57 1.40 2466.94 72.74 357.35 1453.83 1602.37 -112.39 1602.37 1.84 2528.59 74.09 358.54 1471.43 1661.42 -114.51 1661.42 2.87 2590.99 74.32 358.13 1488.42 1721.44 -116.25 1721.44 0.73 2650.91 73.72 359.43 1504.92 1779.02 -117.48 1779.02 2.30 2716.47 73.78 359.17 1523.26 1841.96 -118.26 1841.96 0.39 2777.58 74.23 358.74 1540.10 1900.69 -119.33 1900.69 1.00 2839.27 73.13 358.51 1557.43 1959.88 -120.74 1959.88 1.82 2900.86 73.50 358.37 1575.12 2018.86 -122.35 2018.86 0.64 2963.62 73.91 358.04 1592.72 2079.07 -124.24 2079.07 0.83 3025.74 72.92 358.63 1610.46 2138.58 -125.98 2138.58 1.85 3087.56 72.99 358.28 1628.58 2197.66 -127.57 2197.66 0.55 3150.45 72.69 359.12 1647.14 2257.73 -128.93 2257.73 1.36 3212.07 72.07 358.66 1665.79 2316.45 -130.07 2316.45 1.24 3274.25 71.38 359.41 1685.28 2375.48 -131.07 2375.48 1.61 3335.36 71.74 359.64 1704.62 2433.45 -131.54 2433.45 0.69 3397.18 72.76 0.56 1723.46 2492.33 -131.44 2492.33 2.19 3459.18 73.33 0.38 1741.55 2551.63 -130.95 2551.63 0.95 3521.46 74.36 359.97 1758.88 2611.45 -130.77 2611.45 1.77 3583.24 74.48 0.01 1775.47 2670.96 -130.79 2670.96 0.20 3638.55 74.49 0.09 1790.26 2724.25 -130.74 2724.25 0.14 3707.59 73.86 359.52 1809.10 2790.68 -130.97 2790.68 1.21 3769.94 73.09 359.53 1826.84 2850.45 -131.47 2850.45 1.23 3831.49 73.00 359.04 1844.79 2909.32 -132.20 2909.32 0.77 3893.80 73.15 358.46 1862.93 2968.91 -133.50 2968.91 0.93 3955.49 73.33 358.01 1880.71 3027.95 -135.32 3027.95 0.75 4017.60 73.01 358.10 1898.70 3087.37 -137.33 3087.37 0.53 4079.67 73.40 357.72 1916.63 3146.75 -139.50 3146.75 0.85 4142.28 72.70 357.57 1934.89 3206.59 -141.96 3206.59 1.14 2005.23 73.62 356.84 1318.33 1161.83 -85.42 1161.83 2.84 2068.57 72.75 356.70 1336.65 1222.37 -88.84 1222.37 1.39 2132.19 73.73 356.09 1355.00 1283.17 -92.67 1283.17 1.79 2195.82 73.05 356.17 1373.18 1344.00 -96.79 1344.00 1.08 4451.90 66.98 1.94 2038.63 3497.94 -145.09 3497.94 1.55 Paxton #9 17 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 4509.16 65.75 3.81 2061.59 3550.32 -142.46 3550.32 3.68 4573.06 65.15 5.02 2088.14 3608.27 -137.99 3608.27 1.96 4635.02 64.80 5.05 2114.35 3664.20 -133.06 3664.20 0.56 4697.72 65.02 4.63 2140.94 3720.78 -128.27 3720.78 0.70 4759.59 63.98 4.88 2167.58 3776.43 -123.64 3776.43 1.72 4821.45 64.11 4.76 2194.65 3831.85 -118.96 3831.85 0.27 4883.38 63.61 4.90 2221.93 3887.25 -114.28 3887.25 0.83 4945.30 62.66 5.57 2249.91 3942.26 -109.25 3942.26 1.81 5007.69 61.41 6.12 2279.17 3997.07 -103.64 3997.07 2.16 5069.50 60.41 5.25 2309.23 4050.82 -98.29 4050.82 2.03 5131.56 59.00 3.90 2340.53 4104.23 -94.01 4104.23 2.94 5193.72 57.49 4.54 2373.25 4156.94 -90.12 4156.94 2.58 5256.06 56.59 4.87 2407.16 4209.07 -85.83 4209.07 1.51 5317.66 54.75 4.60 2441.90 4259.76 -81.63 4259.76 3.01 5380.42 53.36 4.94 2478.74 4310.40 -77.41 4310.40 2.26 5442.60 52.58 4.95 2516.19 4359.85 -73.13 4359.85 1.26 5504.08 51.45 5.44 2554.03 4408.10 -68.75 4408.10 1.94 5565.74 49.64 5.80 2593.21 4455.48 -64.09 4455.48 2.96 5627.70 48.07 4.65 2633.98 4501.94 -59.84 4501.94 2.90 5685.98 46.61 3.53 2673.47 4544.69 -56.78 4544.69 2.87 5751.74 44.97 3.60 2719.32 4591.73 -53.85 4591.73 2.50 5813.95 43.70 3.79 2763.82 4635.12 -51.05 4635.12 2.04 5875.73 42.68 4.91 2808.86 4677.28 -47.85 4677.28 2.07 5937.76 41.40 5.70 2854.92 4718.64 -44.01 4718.64 2.24 6000.31 39.90 5.04 2902.38 4759.21 -40.20 4759.21 2.50 6061.95 38.34 4.45 2950.20 4797.96 -36.97 4797.96 2.60 6125.70 36.75 4.82 3000.75 4836.68 -33.83 4836.68 2.52 6184.70 35.87 5.08 3048.30 4871.48 -30.82 4871.48 1.52 6247.32 34.64 4.95 3099.43 4907.48 -27.66 4907.48 1.97 6309.38 34.47 3.87 3150.54 4942.58 -24.95 4942.58 1.03 6371.16 34.19 3.15 3201.56 4977.35 -22.82 4977.35 0.80 6434.51 33.82 1.99 3254.08 5012.75 -21.23 5012.75 1.18 6497.21 33.53 1.36 3306.25 5047.50 -20.21 5047.50 0.73 6559.02 33.59 0.82 3357.76 5081.66 -19.56 5081.66 0.49 6619.59 33.48 0.06 3408.25 5115.13 -19.30 5115.13 0.71 6681.70 33.28 359.43 3460.11 5149.30 -19.46 5149.30 0.66 6700.24 33.20 359.26 3475.62 5159.46 -19.57 5159.46 0.66 Pa x t o n # 9 18 4. 2 B i t R e c o r d BI T NO . SI Z E TY P E S/ N JE T S / TF A IN OU T FT HR S AV E RO P Ft / H R CONDITION 1 1 2 . 2 5 ” HD B S F X 6 6 M PD C 12 0 4 9 5 4 0 9 x 1 2 0. 9 9 4 0 95 ’ 2 3 0 0 ’ 2 2 0 5 ’ 1 5 . 6 2 9 4 1 - 2 - C T - T - X - I - N O - T D 2 8 . 5 ” HD B S M M 6 5 M PD C 12 5 1 2 3 6 7 6 x 1 2 0. 6 6 2 7 23 0 0 ’ 6 7 3 3 ’ 4 4 3 3 ’ 5 8 . 3 6 9 7 1 - 1 - N O - A - X - 1 - P N - T D 4. 3 M u d R e c o r d Co n t r a c t o r : M . I . S w a c o Da t e De p t h MD (f t ) TV D (f t ) MW (p p g ) VI S (s / q t ) PV YP Ge l s FL (c c ) FC So l s (% ) O/ W Ra t i o Sd (% ) MB T pH Cl (ml/l) Ca (ml/l) Sp u d M u d 11 / 1 8 / 2 0 1 4 0 0 8 . 6 1 0 0 1 2 44 2 3 / 2 8 / 3 2 1 3 . 8 2 / - 2 0/ 9 8 - 2 5 9 . 8 5 0 0 4 0 11 / 1 9 / 2 0 1 4 1 4 1 0 1 1 5 3 8 . 9 1 3 0 2 3 27 1 5 / 1 9 / 2 3 7 . 8 2 / - 2 0/ 9 8 - 2 5 9 . 2 1 1 0 0 6 0 11 / 2 0 / 2 0 1 4 2 3 0 0 1 4 0 4 9 . 4 1 6 2 2 5 42 2 0 / 2 8 / 3 4 7 6 2 / - 4 0/ 9 6 - 2 3 9 . 5 1 2 0 0 4 0 11 / 2 1 / 2 0 1 4 2 3 0 0 1 4 0 4 9 . 4 5 6 1 9 26 4 / 8 / 1 2 8 . 8 2 / - 5 0/ 9 5 - 1 6 9 . 0 9 0 0 4 0 Kl a - S h i e l d 11 / 2 2 / 2 0 1 4 2 3 0 0 1 4 0 4 9 . 4 6 8 1 6 2 3 6/ 7 / 9 4 . 8 1 / - 6 . 5 2 / 92 0 . 1 5 . 5 9 . 4 3 4 0 0 0 2 0 0 11 / 2 3 / 2 0 1 4 2 3 0 0 1 4 0 4 9 . 4 1 0 8 3 4 3 9 10 / 1 2 / 1 5 4 . 8 1 / - 6 . 5 2 / 92 0 . 1 5 . 5 9 . 5 3 9 0 0 0 2 0 0 11 / 2 4 / 2 0 1 4 2 3 2 0 1 4 1 0 9 . 3 6 8 1 7 3 1 6/ 1 1 / 1 5 5 . 2 1 / - 6 2 / 92 0 . 1 5 . 0 1 0 . 5 4 0 0 0 0 2 0 0 11 / 2 5 / 2 0 1 4 3 3 0 6 1 6 9 5 9 . 4 5 5 1 8 2 0 7/ 9 / 1 2 4 . 8 1 / - 6 1 / 93 0 . 1 5 . 0 1 0 . 1 4 6 0 0 0 2 0 0 11 / 2 6 / 2 0 1 4 4 4 2 2 2 0 2 8 9 . 4 5 5 1 7 2 0 5/ 1 0 / 1 3 4 . 8 1 / - 6 1 / 93 0 . 1 5 . 4 1 0 . 1 4 8 0 0 0 2 0 0 11 / 2 7 / 2 0 1 4 4 9 4 7 2 2 5 0 9 . 3 5 5 1 7 2 0 6/ 1 0 / 1 4 4 . 6 1 / 1 5 1 / 94 0 . 1 5 . 0 1 0 . 0 4 8 0 0 0 2 0 0 11 / 2 8 / 2 0 1 4 5 7 2 3 2 6 9 9 9 . 3 5 8 1 7 2 0 7/ 1 0 / 1 4 4 . 4 1 / 1 5 2 / 94 0 . 1 5 . 0 1 0 . 2 3 7 0 0 0 2 0 0 11 / 2 9 / 2 0 1 4 6 7 3 3 3 5 0 3 9 . 3 5 5 1 4 2 4 5/ 8 / 1 2 4 . 2 1 / 1 4 2 / 95 0 . 1 5 . 0 1 0 . 1 3 9 0 0 0 2 0 0 11 / 3 0 / 2 0 1 4 6 7 3 3 3 5 0 3 9 . 5 5 1 1 4 2 2 5/ 7 / 1 0 4 . 4 1 / 1 4 1 / 95 0 . 1 5 . 0 1 0 . 1 3 8 0 0 0 2 0 0 Ab b r e v i a t i o n s : MW = M u d W e i g h t V I S = F u n n e l V i s c o s i t y PV = P l a s t i c V i s c o s i t y Y P = Y i e l d P o i n t G e l s = G e l S t r e n g t h F L = W a t e r o r F i l t r a t e Lo s s F C = F i l t e r C a k e O / W = O i l t o W a t e r r a t i o S o l s = S o l i d s S d = S a n d c o n t e n t M B T = M e t h y l e n e B l u e A l k , P m = A l k a l i n i t y , M u d pH = A c i d i t y C l = C h l o r i d e s C a = H a r d n e s s C a l c i u m n r = N o t R e c o r d e d Paxton #9 19 5 SHOW REPORTS Hydrocarbon Show Report # 1 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 2598 MD 2678 MD Country: TVD TVD Averages Before During After Maximum ROP (fph) 154 164 144 372 WOB 7.2 7.2 5.5 11.0 RPM 56 46 67 57 Mud Weight 9.50 9.50 9.50 9.50 Chloride Total Gas 99 441 121 729 C1 (ppm) 17,450 79,990 23,462 140,710 C2 (ppm) - - - C3 (ppm) - - - C4 (ppm) - - - - C5 (ppm) - - - - Lithology Cuttings Analysis Odor Fluorescence Cut Fluorescence Residual Cut Stain Amount Type Amount Amount Distribution Intensity Color Color Intensity Color Residual Fluorescence Cut Color Intesity Color Color Show Rating Free Oil in Mud Comments Report by: Josh Dubowski Gas show, no oil indicators present. 7:30 Medium grey to dark medium grey; unconsolidated; upper fine to lower medium with upper medium and lower fine common; moderate to well sorted; angular to sub angular with trace moderately rounded grains; sub spherical to sub discoidal; sample 50% translucent white to clear quartz; 40% dark grey to medium light grey lithics; minor amount of biotite; pyrite and tuffaceous claystone/siltstone. Kenai Peninsula Borough Alaska United States of America Saxon 147 11/25/2014 Hilcorp Alaska, LLC. 50-133-20638-00-00 Paxton #9 Ninilchik Unit Pixler Plot 1 10 100 1000 10000 1 2 3 4 pp m DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 2 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 2722 MD 2795 MD Country: TVD TVD Averages Before During After Maximum ROP (fph) 152 146 161 200 WOB 5.6 5.4 6.6 8.0 RPM 70 69 52 70 Mud Weight 9.50 9.50 9.50 9.50 Chloride Total Gas 153 536 95 762 C1 (ppm) 29,548 104,062 18,378 147,774 C2 (ppm) - - - - C3 (ppm) - - - - C4 (ppm) - - - - C5 (ppm) - - - - Lithology Cuttings Analysis Odor Fluorescence Cut Fluorescence Residual Cut Stain Amount Type Amount Amount Distribution Intensity Color Color Intensity Color Residual Fluorescence Cut Color Intesity Color Color Show Rating Free Oil in Mud Comments Report by: Josh Dubowski Gas show, no oil indicators present. 9:15 Medium grey with black to brown hues to dark medium grey; upper to lower fine to lower medium; moderate to poor sorting; sub angular to angular to occasionally sub rounded; sub spherical to sub discoidal; predominantly clear to trasclucent white quartz; dark to light grey lithics very common. Kenai Peninsula Borough Alaska United States of America Saxon 147 11/25/2014 Hilcorp Alaska, LLC. 50-133-20638-00-00 Paxton #9 Ninilchik Unit Pixler Plot 1 10 100 1000 10000 1 2 3 4 pp m DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Paxton #9 20 6 DAILY REPORTS Hilcorp Alask LLC Ninilchik Unit DAILY WELLSITE REPORT PAXTON 9 REPORT FOR J. Lott / L. Toussant DATE Nov 30, 2014 DEPTH 6733' PRESENT OPERATION Pulling out of hole. TIME 23:59:59 YESTERDAY 6733' 24 HOUR FOOTAGE 4433 CASING INFORMATION 16"@80' 9.625" @2291' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 6733'/3503' MW 9.5 VIS 51 PV 14 YP 22 FL 4.4 Gels 5/7/10 CL- 38000 FC 1/1 SOL 4 SD 0.1 OIL 1/95 MBT 5 pH 10.1 Ca+ 200 Alk MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 75 CUTTING GAS @ @ WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) @ @ CONNECTION GAS HIGH 0 ETHANE (C-2) @ @ AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 1/99 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY BELUGA PRESENT LITHOLOGY TUFFACEOUS CLAYSTONE 70%, TUFFACEOUS SILSTONE 20%, AND SAND 10% DAILY ACTIVITY SUMMARY Pumped a slug and blowed down topdrive and kelly . Pulled out of hole to 2290'. Checked the flow at the shoe, than continued to pull out of the hole laying down the BHA as per DD instructions. Pulled corrosion ring located at the top of the flex collars. Made up bit and dumb iron and ran in hole with drill pipe to 3721'. Pumped a dry job, and loaded mud dog and pull out of hole laying down drill pipe. At present at 211 ft. Trip gas was 75 u. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3077.00 REPORT BY HARRY E. BLEYS Hilcorp Alask LLC Ninichik Unit DAILY WELLSITE REPORT PAXTON 9 REPORT FOR J. Lott / L Toussant DATE Nov 29, 2014 DEPTH 6733.00000' PRESENT OPERATION TRIPPING OUT OF HOLE TIME 23:59:59 YESTERDAY 5850.00000' 24 HOUR FOOTAGE 883' CASING INFORMATION 16"@80' 9.625"@2291' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 6700.24 33.20 359.26 3475.62 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 8.5" HDBS MM65M 12512367 6X12 2300 6733' 4433' 58.37 TD WELL DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 1054.1 @ 6173.00000 1.3 @ 6234.00000 88.1 103.93360 FT/HR SURFACE TORQUE 16451 @ 6723.00000 794 @ 6047.00000 12729.8 16061.86035 AMPS WEIGHT ON BIT 41 @ 6174.00000 0 @ 6112.00000 8.6 10.96000 KLBS ROTARY RPM 68 @ 5895.00000 3 @ 6047.00000 44.8 47.28000 RPM PUMP PRESSURE 2357 @ 6310.00000 1692 @ 5858.00000 1956.5 1957.34998 PSI DRILLING MUD REPORT DEPTH 6733' MW 9.3 VIS 55 PV 14 YP 24 FL 4.2 Gels 5/8/12 CL- 39000 FC 1/1 SOL 4 SD 0.1 OIL 2/95 MBT 5 pH 10.1 Ca+ 200 Alk MWD SUMMARY INTERVAL 5850' TO 6733' TOOLS MUD MOTOR, AND DIRECTIONAL MODULE GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 433 @ 6513.00000 1 @ 6248.00000 96.5 TRIP GAS 0 CUTTING GAS 0 @ 6733.00000 0 @ 6733.00000 0.0 WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 76274 @ 6513.00000 29 @ 6220.00000 15941.8 CONNECTION GAS HIGH 0 ETHANE (C-2) 158 @ 6513.00000 0 @ 6180.00000 28.0 AVG 0 PROPANE (C-3) 19 @ 6693.00000 0 @ 6714.00000 0.7 CURRENT 0 BUTANE (C-4) 0 @ 6733.00000 0 @ 6733.00000 0.0 CURRENT BACKGROUND/AVG 5/97 PENTANE (C-5) 0 @ 6733.00000 0 @ 6733.00000 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY BELUGA PRESENT LITHOLOGY TUFFACEOUS CLAYSTONE 70%, TUFFACEOUS SILTSTONE 20%, AND SAND 10%. DAILY ACTIVITY SUMMARY DRILLED UNTIL 6733 FT. AND CIRCULATED BOTTOMS UP AND CALLED TD AT 21:18 HRS. PUMPED A SWEEP AND DID A SHORT TRIP THAN BEGAN TRIPPING OUT OF HOLE. CANRIG PERSONNEL ON BOARD 4 DAILY COST 3077.00 REPORT BY HARRY E. BLEYS Hilcorp Alask LLC Ninilchik Unit DAILY WELLSITE REPORT PAXTON 9 REPORT FOR J. Lott / L Toussant DATE Nov 28, 2014 DEPTH 5850.00000 PRESENT OPERATION Drilling ahead. TIME 23:59:59 YESTERDAY 5102.00000 24 HOUR FOOTAGE 748' CASING INFORMATION 16"@80' 9.625"@ 2291" SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 5875.73 42.68 4.91 2808.79 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 8.5" HDBS MM65M 12512367 6X12 2300' 3550' 45.23 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 600.0 @ 5599.00000 3.3 @ 5661.00000 87.9 96.55263 FT/HR SURFACE TORQUE 14951 @ 5629.00000 1333 @ 5418.00000 8997.4 13314.82031 AMPS WEIGHT ON BIT 29 @ 5734.00000 0 @ 5130.00000 7.5 5.68000 KLBS ROTARY RPM 72 @ 5635.00000 0 @ 5418.00000 39.0 60.23000 RPM PUMP PRESSURE 1954 @ 5755.00000 760 @ 5785.00000 1767.3 1793.22998 PSI DRILLING MUD REPORT DEPTH 5784' MW 9.3 VIS 58 PV 17 YP 20 FL 4.4 Gels 7/10/14 CL- 37000 FC 1/1 SOL 5 SD 0.1 OIL 2/94 MBT 5 pH 10.2 Ca+ 200 Alk MWD SUMMARY INTERVAL 5102' TO 5850' TOOLS MUD MOTOR AND DIRECTIONAL MODULE GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 235 @ 5244.00000 2 @ 5510.00000 58.6 TRIP GAS 40 CUTTING GAS 0 @ 5850.00000 0 @ 5850.00000 0.0 WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 41215 @ 5244.00000 15 @ 5510.00000 9526.8 CONNECTION GAS HIGH 0 ETHANE (C-2) 90 @ 5676.00000 0 @ 5486.00000 5.5 AVG 0 PROPANE (C-3) 10 @ 5525.00000 0 @ 5493.00000 0.1 CURRENT 0 BUTANE (C-4) 0 @ 5850.00000 0 @ 5850.00000 0.0 CURRENT BACKGROUND/AVG 24/58 PENTANE (C-5) 9 @ 5102.00000 0 @ 5247.00000 0.3 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY BELUGA PRESENT LITHOLOGY SAND 60%, TUFFACEOUS CLAYSTONE 30%, AND TUFFACEOUS SILTSTONE 10 %. DAILY ACTIVITY SUMMARY Drilled all day until 5720 Ft. Circulated and pumped a sweep than commenced a short trip to 5067 Ft. Stopped and tripped back in hole to bottom and received 40 units of trip gas. Max gas was 235 u @ 5244 Ft. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3077.00 REPORT BY HARRY E. BLEYS Hilcorp Alask LLC Ninilchik Unit DAILY WELLSITE REPORT PAXTON 9 REPORT FOR J. Lott/L. Toussant DATE Nov 27, 2014 DEPTH 5102.00000 PRESENT OPERATION Drilling ahead. TIME 23:59:59 YESTERDAY 4545.00000 24 HOUR FOOTAGE 557 CASING INFORMATION 16" @80' 9.625"@ 2291' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 5069.50 60.41 5.25 2309.16 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 8.5 HDBS MM65M 12512367 6X12 2300 2802 33.983 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 200.2 @ 4546.00000 2.0 @ 4855.00000 88.6 103.78158 FT/HR SURFACE TORQUE 13232 @ 5071.00000 3680 @ 4560.00000 8831.2 11797.04980 AMPS WEIGHT ON BIT 18 @ 4741.00000 0 @ 4569.00000 6.1 5.37000 KLBS ROTARY RPM 71 @ 4799.00000 12 @ 4560.00000 43.4 57.07000 RPM PUMP PRESSURE 1888 @ 5016.00000 1441 @ 4732.00000 1608.3 1702.05005 PSI DRILLING MUD REPORT DEPTH 4947' MW 9.3 VIS 55 PV 17 YP 20 FL 4.6 Gels 6/10/14 CL- 48000 FC 1/1 SOL 5 SD 0.1 OIL 1/93 MBT 5 pH 10.0 Ca+ 200 Alk MWD SUMMARY INTERVAL 4545' TO 5102' TOOLS MUD MOTOR AND DIRECTIONAL MODULE GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 354 @ 4678.00000 17 @ 5051.00000 87.8 TRIP GAS 1099 CUTTING GAS 0 @ 5102.00000 0 @ 5102.00000 0.0 WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 62477 @ 4678.00000 195 @ 4548.00000 15538.8 CONNECTION GAS HIGH 0 ETHANE (C-2) 52 @ 4838.00000 0 @ 4974.00000 7.1 AVG 0 PROPANE (C-3) 0 @ 5102.00000 0 @ 5102.00000 0.0 CURRENT 0 BUTANE (C-4) 0 @ 5102.00000 0 @ 5102.00000 0.0 CURRENT BACKGROUND/AVG 9/88 PENTANE (C-5) 9 @ 5100.00000 1 @ 5094.00000 0.1 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY BELUGA PRESENT LITHOLOGY TUFFACEOUS CLAYSTONE 50%, SAND 40%, AN D TUFFACEOUS SILTSTONE 10% DAILY ACTIVITY SUMMARY Drilled all day until 5102 FT. Circulated bottoms up and received 207 u of gas. Pumped a sweep and cemmenced a short trip. Tripped back in hole and drilled ahead. Max gas 354u at 4678 FT. Trip gas of 1099 u. at 3335 FT. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3077.00 REPORT BY HARRY E. BLEYS Hilcorp Alask LLC Ninilchik Unit DAILY WELLSITE REPORT PAXTON 9 REPORT FOR L. Toussant/S. Barber DATE Nov 26, 2014 DEPTH 4545.00000 PRESENT OPERATION SHORT TRIP TO SHOE. TIME 23:59:59 YESTERDAY 3422.00000 24 HOUR FOOTAGE 1123 CASING INFORMATION 16" @ 80' 9.625" 2291' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 4509.16 65.75 3.81 2061.53 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 8.5" HDBS MM65M 12512367 6X12 2300' 2245' 26.583 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 568.4 @ 4118.00000 6.2 @ 3778.00000 87.9 91.41595 FT/HR SURFACE TORQUE 11741 @ 4232.00000 1367 @ 4385.00000 7274.8 9813.86035 AMPS WEIGHT ON BIT 27 @ 3990.00000 0 @ 3688.00000 7.6 6.68000 KLBS ROTARY RPM 94 @ 3701.00000 1 @ 4241.00000 48.5 56.00000 RPM PUMP PRESSURE 1626 @ 4374.00000 1270 @ 3422.00000 1495.4 1570.05005 PSI DRILLING MUD REPORT DEPTH 4422' MW 9.4 VIS 55 PV 17 YP 20 FL 4.8 Gels 5/10/12 CL- 48000 FC 1/- SOL 6 SD 0.1 OIL 1/93 MBT 5.4 pH 10.1 Ca+ 200 Alk MWD SUMMARY INTERVAL 3422' TO 4545' TOOLS MUD MOTOR AND DIRECTIONAL MODULE GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 504 @ 3860.00000 2 @ 4044.00000 99.2 TRIP GAS 0 CUTTING GAS 0 @ 4545.00000 0 @ 4545.00000 0.0 WIPER GAS 321 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 90546 @ 3860.00000 47 @ 3989.00000 16201.3 CONNECTION GAS HIGH 0 ETHANE (C-2) 59 @ 3650.00000 0 @ 3423.00000 4.5 AVG 0 PROPANE (C-3) 0 @ 4545.00000 0 @ 4545.00000 0.0 CURRENT 0 BUTANE (C-4) 0 @ 4545.00000 0 @ 4545.00000 0.0 CURRENT BACKGROUND/AVG 11/99 PENTANE (C-5) 0 @ 4545.00000 0 @ 4545.00000 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY BELUGA PRESENT LITHOLOGY SAND 60%, TUFFACEOUS CLAYSTONE 30%, AND TUFFACEOUS SILTSTONE 10% DAILY ACTIVITY SUMMARY DRILLED AHEAD ALL DAY UNTIL 4545 FT. CIRCULATED BOTTOMS UP AND PUMPED A SWEEP RECEIVING 321 u. OF GAS, PROIR TO COMMENCING A SHORT TRIP TO SHOE. AT PRESENT STILL TRIPPING TO SHOE. MAX GAS 504 u @ 3860 FT. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3077.00 REPORT BY HARRY E. BLEYS Company Ninilchik Unit DAILY WELLSITE REPORT Paxton 9 REPORT FOR D. Yessack / S. Barber DATE Nov 25, 2014 DEPTH 3422' PRESENT OPERATION Drilling ahead. TIME 23:59:59 YESTERDAY 2319' 24 HOUR FOOTAGE 1103' CASING INFORMATION 16"@ 80' 9.625"@ 2291' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 3397.18 72.76 0.56 1723.42 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 8.5 HDBS MM65M 12512367 6X12 2300' 1122 12.38 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 1495.4 @ 2518.00000 1.0 @ 3183.00000 123.8 62.45521 FT/HR SURFACE TORQUE 9667 @ 2526.00000 6797 @ 3065.00000 7036.9 8390.33008 AMPS WEIGHT ON BIT 16 @ 3248.00000 0 @ 2519.00000 6.6 4.71000 KLBS ROTARY RPM 81 @ 3177.00000 7 @ 2388.00000 50.0 34.73000 RPM PUMP PRESSURE 1760 @ 2526.00000 698 @ 2312.00000 1527.9 1270.58997 PSI DRILLING MUD REPORT DEPTH 3306' MW 9.4 VIS 55 PV 18 YP 20 FL 4.8 Gels 7/9/12 CL- 46000 FC 1/- SOL 6 SD 0.1 OIL 1/93 MBT 5 pH 10.1 Ca+ 200 Alk MWD SUMMARY INTERVAL 2300' TO 3422' TOOLS MUD MOTOR AND DIRECTIONAL MODULE GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 762 @ 2740.00000 4 @ 3032.00000 136.1 TRIP GAS 223 CUTTING GAS 0 @ 3422.00000 0 @ 3422.00000 0.0 WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 147774 @ 2740.00000 746 @ 3032.00000 25279.4 CONNECTION GAS HIGH 52 ETHANE (C-2) 74 @ 3242.00000 0 @ 3176.00000 3.7 AVG 34 PROPANE (C-3) 0 @ 3422.00000 0 @ 3422.00000 0.0 CURRENT 0 BUTANE (C-4) 0 @ 3422.00000 0 @ 3422.00000 0.0 CURRENT BACKGROUND/AVG 77/136 PENTANE (C-5) 0 @ 3422.00000 0 @ 3422.00000 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY BELUGA FORMATION PRESENT LITHOLOGY TUFFACEOUS CLAYSTONE 40%, SAND 30%, TUFFACEOUS SILTSTONE 20%, AND TUFFACEOUS SANDSTONE 10%. DAILY ACTIVITY SUMMARY Drilled ahead until 3306 Ft and circulated and pumped a sweep prior to tripping out of hole on a short trip to the shoe at 3228 Ft. Circulated and tripped back in hole to bottom where we received trip gas of 223 u. Commenced drilling ahead and presently at 3476 Ft . Max gas was 762 u @ 2740 Ft. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3077.00 REPORT BY HARRY E. BLEYS Hilcorp Alaska, LLC Ninilchik Unit DAILY WELLSITE REPORT Paxon #9 REPORT FOR D. Yessak/S. Barber DATE Nov 24, 2014 DEPTH 2319.00000 PRESENT OPERATION Tripping in Hole. TIME 06:59:59 YESTERDAY 2299.00000 24 HOUR FOOTAGE 20 CASING INFORMATION 16"@80' 9.625"@2291' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 8.5" HDBS PDC MM65M 12512367 6X12 2300 20' .400 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 186.5 @ 2301.00000 13.7 @ 2306.00000 70.0 41.02252 FT/HR SURFACE TORQUE 10247 @ 2299.00000 7520 @ 2302.00000 8689.0 8305.17969 AMPS WEIGHT ON BIT 7 @ 2299.00000 0 @ 2301.00000 4.5 4.70000 KLBS ROTARY RPM 76 @ 2299.00000 11 @ 2310.00000 18.7 14.07000 RPM PUMP PRESSURE 1775 @ 2299.00000 698 @ 2312.00000 820.9 715.38000 PSI DRILLING MUD REPORT DEPTH 2320 MW 9.3 VIS 68 PV 17 YP 31 FL 5.2 Gels 6/11/15 CL- 40000 FC 1/- SOL 6 SD 0.1 OIL 2/92 MBT 5 pH 10.5 Ca+ 200 Alk MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 109 @ 2299.00000 44 @ 2300.00000 90.3 TRIP GAS 0 CUTTING GAS 0 @ 2319.00000 0 @ 2319.00000 0.0 WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 14298 @ 2299.00000 14298 @ 2299.00000 714.9 CONNECTION GAS HIGH 0 ETHANE (C-2) 0 @ 2319.00000 0 @ 2319.00000 0.0 AVG 0 PROPANE (C-3) 0 @ 2319.00000 0 @ 2319.00000 0.0 CURRENT 0 BUTANE (C-4) 0 @ 2319.00000 0 @ 2319.00000 0.0 CURRENT BACKGROUND/AVG 90 PENTANE (C-5) 0 @ 2319.00000 0 @ 2319.00000 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Picked up new BHA and tripped in hole and drilled out cement. Drilled 20 Ft of new hole and performed a FIT test to 12.0 pounds. Pulled out of hole and laid down 5 inch drill pipe and picked up 4 inch pipe. Tripped in hole making up stands. Pulled out of hole near surface and tripped back in hole. At present at 1672 Ft. Max gas was 109 u of gas at 2299 Ft. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3077.00 REPORT BY HARRY E. BLEYS Hilcorp Alaska, LLC Ninilchik Unit DAILY WELLSITE REPORT Paxon #9 REPORT FOR Doug Yessak, Shane Barber DATE Nov 23, 2014 DEPTH 2299' PRESENT OPERATION Picking up BHA. TIME 23:59 YESTERDAY 2299' 24 HOUR FOOTAGE 0' CASING INFORMATION 16" @ 80' 9.625"@2291' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH no mud Report MW VIS PV YP FL Gels CL- FC SOL SD OIL MBT pH Ca+ Alk MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Pre job safety meeting to test casing. Tested casing to 2950 psi for thirty minutes. Replaced plug in kill block. Blew down choke manifold, topdrive and kill line. Held pre job safety meeting to change stab sleeve on motor, and began picking up BHA per Directional drilliers directions. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3077.00 REPORT BY HARRY E. BLEYS Hilcorp Alaska, LLC Ninilchik Unit DAILY WELLSITE REPORT Paxon #9 REPORT FOR Doug Yessak, Shane Barber DATE Nov 22, 2014 DEPTH 2299' PRESENT OPERATION Cement Job Completion TIME 23:59 YESTERDAY 2299' 24 HOUR FOOTAGE 0' CASING INFORMATION 16" @ 80' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBT pH Ca+ Alk MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Rigged down stack and prepared to remove shipping beams and install lower pipe rams. Performed a job safety analysis and set the double ram and annular torque stack bolts. Continue to install HCR kill and choke valves. Install choke and kill lines, pollution pan, flow nipple and flow line. Close sub doors, and rig up catwalk hydraulic reset V- door. Secure cross chain stack to sub. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2,148.50 REPORT BY Eric Andrews Hilcorp Alaska, LLC Ninilchik Unit DAILY WELLSITE REPORT Paxon #9 REPORT FOR Doug Yessak, Shane Barber DATE Nov 21, 2014 DEPTH 2299' PRESENT OPERATION Cement Job Completion TIME 23:59 YESTERDAY 2299' 24 HOUR FOOTAGE 0' CASING INFORMATION 16" @ 80' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 2300' MW 9.6 VIS 120 PV 26 YP 38 FL 7.6 Gels 19/24/37 CL- 1200 FC 2 SOL 6 SD 0.5 OIL 0/94 MBT 23 pH 9.5 Ca+ 40 Alk MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Ran back into the hole after pulling to conductor, circulated mud and pulled out of hole. Layed down BHA #1 and rigged up to run casing. Ran 9.625" surface casing to 2290', landed hanger, circulated and conditioned mud. Pumped cement job, dropped plug, and displaced mud. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2,148.50 REPORT BY Eric Andrews Hilcorp Alaska, LLC Ninilchik Unit DAILY WELLSITE REPORT Paxon #9 REPORT FOR Doug Yessak, Shane Barber DATE Nov 20, 2014 DEPTH 2299' PRESENT OPERATION Cleaning hole TIME 23:59 YESTERDAY 1474' 24 HOUR FOOTAGE 825' CASING INFORMATION 16" @ 80' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1 12.25" HDBS FX 66M PDC 12049540 9x12 80' 2299' 2219' TD DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 4261.5 @ 2131' 2.3 @ 2199' 141.9 92.05816 FT/HR SURFACE TORQUE 11131 @ 1843' 1404 @ 2178' 7241.1 10247.86035 AMPS WEIGHT ON BIT 23 @ 1868' 0 @ 1575' 9.1 7.92000 KLBS ROTARY RPM 106 @ 2075' 3 @ 1666' 54.0 76.48000 RPM PUMP PRESSURE 2041 @ 1837' 1292 @ 1474' 1743.9 1775.93994 PSI DRILLING MUD REPORT DEPTH 2300' MW 9.2 VIS 128 PV 22 YP 26 FL 7.6 Gels 14/17/21 CL- 1100 FC 2 SOL 2 SD 0.75 OIL 0/98 MBT 25 pH 9.2 Ca+ 60 Alk MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 279 @ 2290' 1 @ 1868' 49.5 TRIP GAS CUTTING GAS 0 @ 2299' 0 @ 2299' 0.0 WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 52967 @ 2290' 381 @ 1868' 9651.6 CONNECTION GAS HIGH ETHANE (C-2) 346 @ 2060' 1 @ 1996' 11.5 AVG PROPANE (C-3) 0 @ 2299' 0 @ 2299' 0.0 CURRENT BUTANE (C-4) 0 @ 2299' 0 @ 2299' 0.0 CURRENT BACKGROUND/AVG PENTANE (C-5) 0 @ 2299' 0 @ 2299' 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Drilled ahead from 1474' to 2300'. Pumped and sweep and circulated out of hole to conductor. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2,148.50 REPORT BY Eric Andrews Hilcorp Alaska, LLC Ninilchik Unit DAILY WELLSITE REPORT Paxon #9 REPORT FOR Doug Yessak, Shane Barber DATE Nov 19, 2014 DEPTH 1474' PRESENT OPERATION Pulling out of hole TIME 23:59 YESTERDAY 136' 24 HOUR FOOTAGE 1338' CASING INFORMATION 16" @ 80' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 1469.93 74.46 0.38 1171.32 1499.02 74.86 0.50 1179.09 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1 12.25" HDBS FX66M PDC 12049540 9x12 80' 1474' 1394' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 43128.7 @ 227' 1.3 @ 525' 389.2 15.22971 FT/HR SURFACE TORQUE 10695 @ 1399' 1368 @ 804' 2238.6 6822.12012 AMPS WEIGHT ON BIT 25 @ 1474' 0 @ 560' 8.6 6.31000 KLBS ROTARY RPM 66 @ 1473' 0 @ 927' 7.9 63.45000 RPM PUMP PRESSURE 1646 @ 1094' 711 @ 145' 1264.6 1292.37000 PSI DRILLING MUD REPORT DEPTH 1410' MW 8.8 VIS 240 PV 46 YP 40 FL 10 Gels 34/39/46 CL- 1100 FC 2/- SOL 2 SD 0.5 OIL 0/98 MBT 25 pH 9.5 Ca+ 60 Alk MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 94 @ 1238' 1 @ 455' 24.4 TRIP GAS CUTTING GAS 0 @ 1474' 0 @ 1474' 0.0 WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 17761 @ 1240' 75 @ 192' 4414.8 CONNECTION GAS HIGH ETHANE (C-2) 0 @ 1474' 0 @ 1474' 0.0 AVG PROPANE (C-3) 0 @ 1474' 0 @ 1474' 0.0 CURRENT BUTANE (C-4) 0 @ 1474' 0 @ 1474' 0.0 CURRENT BACKGROUND/AVG PENTANE (C-5) 0 @ 1474' 0 @ 1474' 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Drilled ahead from 136' to 1473', pumped sweep and circulated hole clean. Pulling out of hole with elevators at time of midnight report. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2,148.50 REPORT BY Eric Andrews Hilcorp Alaska, LLC Ninilchik Unit DAILY WELLSITE REPORT Paxon #9 REPORT FOR DATE Nov 18, 2014 DEPTH 136' PRESENT OPERATION Drilling Ahead TIME 23:59 YESTERDAY 80' 24 HOUR FOOTAGE 56' CASING INFORMATION 16" @ 80' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1 12.25" HDBS FX66M PDC 12049540 9x12 80' 56' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 1331.9 @ 91' 5.3 @ 85' 329.9 444.94382 FT/HR SURFACE TORQUE 9175 @ 106' 1458 @ 119' 3741.3 1748.82996 AMPS WEIGHT ON BIT 85 @ 81' 0 @ 85' 5.8 8.91000 KLBS ROTARY RPM 45 @ 115' 4 @ 88' 13.9 0.00000 RPM PUMP PRESSURE 1106 @ 110' 683 @ 93' 828.4 842.96997 PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBT pH Ca+ Alk MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 1 @ 84' 1 @ 129' 1.2 TRIP GAS CUTTING GAS 0 @ 136' 0 @ 136' 0.0 WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 0 @ 136' 0 @ 136' 0.0 CONNECTION GAS HIGH ETHANE (C-2) 0 @ 136' 0 @ 136' 0.0 AVG PROPANE (C-3) 0 @ 136' 0 @ 136' 0.0 CURRENT BUTANE (C-4) 0 @ 136' 0 @ 136' 0.0 CURRENT BACKGROUND/AVG PENTANE (C-5) 0 @ 136' 0 @ 136' 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Picked up drill pipe and BHA, ran in hole, and began drilling from 80' to a midnight depth of 136'. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2,148.50 REPORT BY Eric Andrews