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218-014
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: ESP Swap 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 12,380 feet N/A feet true vertical 4,048 feet N/A feet Effective Depth measured 12,375 feet 6,282'feet true vertical 4,048 feet 4,054'feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5 / L-80 / EUE 8rd 5,285' 3,770' Packers and SSSV (type, measured and true vertical depth)BOT SLZXP LTP N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A 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: Wells Manager Contact Phone: Burst N/A Collapse N/A 3,090psi 8,540psi 5,750psi 6,890psi 9,020psi 6,289' 4,054' 4,790psi Conductor 4,048'12,380' 6,264' 6,451'Surface Tieback Liner 20' 9-5/8' 7-5/8' 107' 6,426' MILNE POINT / SCHRADER BLUFF OIL MILNE PT UNIT F-109 Plugs Junk measured measured TVD 4-1/2' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 218-014 50-029-23596-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0025509, ADL0025515 & ADL0388235 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing PressureGas-Mcf MD 107' Size 107' 4,068' Length 6,098' Casing N/A Ryan Lewis ryan.lewis@hilcorp.com 303-906-5178 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 409 160 149 46020 0 3560 401 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 324-615 & 324-666 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG PL G 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, Jan 21, 2025 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2025.01.17 16:24:57 - 09'00' Taylor Wellman (2143) DSR-1/22/25 RBDMS JSB 012825 SFD 2/13/20252/7/25 _____________________________________________________________________________________ Revised By: TDF 1/17/2025 SCHEMATIC Milne Point Unit Well: MPU F-109 Last Completed: 12/21/24 PTD: 218-014 TD =12,380’ (MD) / TD =4,048’ (TVD) 4 & 5 20” Orig. KB Elev.: 26.5’ / GL Elev.: 10.9’ 7-5/8”9&10 13 4 19 9-5/8” 1 2 3 20 See Screen/ Solid Liner Detail PBTD =12,375’ (MD) / PBTD =4,048’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,509’ MD 6,7 & 8 4-1/2” Shoe @ 12,380’ 14 16 1517 18 2-7/8” 11 & 12 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor N/A / X-52 / Weld N/A Surface 107’ N/A 9-5/8" Surface 40 / L-80 / DWC/C 8.835 Surface 6,451’ 0.0758 7-5/8” Tieback 29.7 / L-80 / Vam STL SMLS 6.875 Surface 6,289’ 0.0459 4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hydril 625 3.920 6,282’ 12,380’ .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE R2 2.441 Surface 5,314’ 0.0058 OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4" Stg 1 – Lead - 495 sx Extenda Cem / Tail – 398 sx Swift Cem Stg 2 – Lead – 324 sx Perm Cem / Tail – 268 sx Class G (180 bbls to surface) 8-1/2” Cementless Screens Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 50’ Max Hole Angle = 93° @ 10,671’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M Wellhead FMC Gen V GENERAL WELL INFO API: 50-029-23596-00-00 Completion Date: 3/15/18 ESP Swap by ASR – 12/21/2024 4-1/2” SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 6,351’ 4,059’ 6,474’ 4,070’ 5 7,218’ 4,089’ 7,425’ 4,089’ 4 8,251’ 4,075’ 8,416’ 4,073’ 5 9,035’ 4,077’ 9,201’ 4,082’ 5 10,728’ 4,064’ 10,934’ 4,052’ 1 12,298’ 4,046’ 12,339’ 4,047’ JEWELRY DETAIL No. Top MD Item ID 1 219’ GLM #2: 2-7/8” x 1” BK 1/4'' Orifice Valve 2.347” 2 5,092’ GLM #1: 2-7/8” x 1” W/ Dummy 2.347” 3 5,180’ XN Nipple, 2.205” no go 2.205” 4 5,213’ Discharge Head: B/O PMP 400 5 5,231.6’ Ported Sub Head: S/A B/O 400 PX PRESS PORT 6 5,232’ Pump #3: 400PMSSD 134 FLEXER HF H6 FE 7 5.256’ Pump #2: 400PMSXD 069 MVPER H6 FER 8 5,269’ Pump #1: 400PMSXD 024 GINPSHL HS 416SS 9 5,278.7’ Adaptor: FPX/GINT MNL FSTNR 400 PMP 10 5,279’ Intake: GPXARCINT FER H6 11 5,285’ Upper Tandem Seal: GS3 B/B/L SB H6 PFSA HL FER 12CRC 12 5,292’ Lower Tandem Seal: GS3 B/B/L SB H6 PFSA HL FER 12CRC 13 5,299’ Motor: 562XP 150/1505/61/6R 12CRC 14 5,310’ Sensor: E7 MW 456 400 BAR 150C AFL 15 5,313’ Centralizer:Bottom @ 5,314’ 16 6,282’ BOT SLZXP LT Packer / Liner Hanger 7” x 9-5/8” 6.190” 17 6,289’ 7-5/8” Tieback Assy. 6.151” 18 6,304’ 7” H563 x 4.5” HTTC L-80 XO 3.830” 19 12,344’ 4-1/2” Drillable Packoff Sub 2.390” 20 12,375’ WIV Valve LTC BxB (1” Ball on Seat/Closed) - 4-1/2” Screens LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 18 6,474’ 4,070’ 7,218’ 4,089’ 20 7,425’ 4,089’ 8,251’ 4,075’ 15 8,416’ 4,073’ 9,035’ 4,077’ 37 9,201’ 4,082’ 10,728’ 4,064’ 33 10,934’ 4,052’ 12,298’ 4,046’ Well Name Rig API Number Well Permit Number Start Date End Date MP F-109 ASR 50-029-23596-00-00 218-014 12/14/2024 Future 12/13/2024 - Friday No operations to report. 12/11/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 12/12/2024 - Thursday No operations to report. Cont. Short trip out. F/ 6,344 Laying dw 3-1/2" NC31 10.37# G-105. T/ 5,922'. Change handling equip. to 2-3/8" RIH w/ vac tools clean out BHA on 2-3/8" P110 5.95# PH-6 F/ 5,922'. T/ 6,230'. P/U BS, Jars, & 4 x 4.25" collars. to 6,377'. Change handling equip. for 3-1/2" 10.37# G-105 NC-31 work string. A21Wash down with vacs tool at 2.5 BPM w/ 2,480 psi F/ 6,377'. T/ 10,180'. All parameters remained consistent. P/U wt = 54K - S/O wt = 21K. Small amount of returns coming back, intermittently. Accept rig at 06:00 on 12-14-2024. Pump 30 bbl of 8.4 ppg source water dw IA. Ia on a vacuum. P/U 2-3/8" test mandrel. Circulate fresh water through surface lines. Fluid pack BOP stack. Test BOPE as per approved sundry. AOGCC waived witness to testing. Test to 250 psi low & 1,500 psi high f/ 5/5 charted mins. Completed BOPE testing with 1 fail/pass test. Preform successful accumulator drawdown test. B/D testing lines. Line up BOPE for wellbore operations. Fill gas buster. P/U tee bar pull CTS & BPV. M/U landing joint BOLDS. Pull hanger off seat at 37K continue pulling to free P/U wt = 48K. Slight drag of 1-2K. Hanger at rig floor. Cut ESP, cap lines & secure. 12/14/2024 - Saturday RIH w/ vac tools clean out BHA on 2-3/8" P110 5.95# PH-6 F/ 1,033' T/ 5,922'. P/U wt = 32K S/O wt = 13K. Pump double displacement for pipe trip in. No returns. Line up to wash down to clean out above TOL. Change handling equip. to 3-1/2" XO to ASR work string NC31 10.37# G-105. Kelly up. Wash down at 2.5 BPM w/ 2,300 psi F/ 5,944' to 6,464'. No returns while pumping. Short trip out. F/ 6,464 Laying dw 3-1/2" NC31 10.37# G-105. T/ 6,344' P/U wt = 33K - S/O wt = 16K. Pump double displacement. No returns. 12/17/2024 - Tuesday 12/15/2024 - Sunday Run ESP cable & cap lines over sheave. Fill IA with 20 bbls of 8.4 ppg source wtr. No returns. POOH w/ 2-7/8" 6.5# L-80 EUE ESP completion. F/ 5,284' - T/ 94'. Pumping 2x displacement every 15 joints. No returns. Joints sanded off above ESP. L/D at ESP assy. Top pump full of sand a seized. All clamps accounted for on tally. All ESP equip. intact. Load in pipe shed & tally 2-3/8" P110 5.95# PH-6 work string. Change handling equip. P/U & M/U vac tool clean out BHA. P/U carbine mule shoe & double flapper. 12/16/2024 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP F-109 ASR 50-029-23596-00-00 218-014 12/14/2024 12/22/2024 No operations to report. Continue RIH w/ ESP completion F/ 4,669'. PU/MU TBG Hanger. FINAL PUW = 41K, SOW = 22K. Test ESP systems - good. Measure and cut cable. MU connector. Pump away remaining source water to well. RD pipe racks and pipe sheds. Land hanger while monitoring ESP, placing centralizer at 5,313'. RILDS. Final clamp count: Motor 4, Flat Guards 2, Protectolizers 6, Pump Body 19, CC 169. Release rig 12:00 12-21-2024 12:00 12/21/2024 - Saturday No operations to report. 12/24/2024 - Tuesday 12/22/2024 - Sunday WELLHEAD: M/U hanger to with BPV installed to string, centrilift to splice cable to penetrator, landed hanger to RKB, RILDS. S/B for BOP N/D. N/U tree/adapter test hanger void 500 low 5000 high 5/10 min Good Test. pulled BPV with Tbar no pressure on well. secure well. 12/23/2024 - Monday 12/20/2024 - Friday PU/MU and service ESP motors and pumps. RIH w/ 2-7/8",6.5#,L,EUE completion as per approved tally. Install 38 used joint prior to new joints. Install CC Clamps on every connection. Test ESP systems at 4,692' SOW - 20K - good test. 12/18/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Continue washing down with vacs tool at 2.5 BPM w/ 2,480 psi F/ 10,180' - T/ 12,302' BTM of Screens. All parameters remained consistent. P/U wt = 63K - S/O wt = 23K. No returns while pumping. Blow down surface equipment. POOH w/ BHA F/ 12,302' - T/ 9,419' maintaining 1x displacement. 12/19/2024 - Thursday Continue POOH w/ VACS BHA F/ 9,419' pumping 1x displacement. POOH w/ VACS BHA T/ 6,374'. BO/LD drill collars, Jars, and bumper sub. Swap handling equipment to 2-3/8". POOH T/ 1,024' B/O VACS "engine". Top section surrounding screen recovered ~4 cups of sand/gravel. Continue POOH. BO/LD Dual Flapper and attempt to vac out last joint (full of solids). Aquire samples. Total of 9gal solids. Clean and clear rig floor. Pull wear bushing. 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: ESP Swap 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 12,380'N/A Casing Collapse Conductor N/A Surface 3,090psi Tieback 4,790psi Liner 8,540psi 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: Wells Manager 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 MILNE PT UNIT F-109 MILNE POINT SCHRADER BLUFF OIL N/A 4,048' 12,375' 4,048' 887 N/A Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 11/22/2024 BOT SLZXP LTP and N/A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509, ADL0025515 & ADL0388235 218-014 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23596-00-00 Hilcorp Alaska LLC C.O. 477.07 Length Size Proposed Pools: 107' 107' 6.5 / L-80 / EUE 8rd TVD Burst 5,285' MD 9,020psi 5,750psi 6,890psi 4,068' 4,054' 4,048' 6,282 MD/ 4,054 TVD and N/A 6,451' 6,289' 107' 20' 9-5/8' 7-5/8' 6,426' 6,264' N/A Ryan Lewis ryan.lewis@hilcorp.com 303-906-5178 4-1/2'6,098' Perforation Depth MD (ft): 12,380' See Schematic See Schematic 2-7/8" No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 2:31 pm, Dec 05, 2024 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.12.05 13:18:50 - 09'00' Taylor Wellman (2143) 324-666 x JJL 12/9/24 10-404 A.Dewhurst 06DEC24 8:12 am, Dec 06, 2024 Witnessed BOP and Annular Test to 1500 psi. GKC for GCW Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.11 10:00:55 -09'00'12/11/24 RBDMS JSB 121324 Well: MPF-109 PTD: 218-014 API: 50-029-23596-00-00 Well Name:MPF-109 API Number:50-029-23596-00-00 Current Status:Shut-in ESP Rig:ASR #1 Estimated Start Date:11/22/2024 Estimated Duration:4 days Regulatory Contact:Tom Fouts Permit to Drill Number:218-014 First Call Engineer:Ryan Lewis (303) 906-5178 (M) Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) Current Bottom Hole Pressure: 1264 psi @ 3,767’ TVD 10/24/2023 | 6.5 EMW, 6.9 KWF Max Potential Surface Pressure: 887 psi Gas Column Gradient (0.1 psi/ft) Max Angle: 61° Max Angle at 5,007’ MD Brief Well Summary: MPU F-109 was drilled and completed in March 2018 as a Schrader Bluff OA producer with an ESP completion. The first/current ESP completion was installed in 2018. The ESP has failed due to warn out pumps after a 6 year run life. Scale was collected and is 80% Fe. We plan to upsize the motor and pumps to help with the high viscosity oil to get a repeat 6+ year run on this install. Objectives: Pull failed ESP completion, run new ESP completion. Notes Regarding Wellbore Condition: - 7” casing test to 1,800 psi on 3/12/2018 at 6,282’ MD. Pre-Rig Procedure (Non Sundried Work) Slickline 1. RU slickline, pressure test PCE to 250psi low / 1,500psi high. 2. Drift and tag with sample bailer. 3. Caliper from as deep as possible to surface. 4. Attempt to pull dummy valve from GLM at 5,047’ MD and leave open. 5. Pull GLV and set dummy valve in upper GLM at 131’ MD. 6. RDMO. Eline (Contingency) 1. RU Eline, pressure test to 250psi low / 1,500psi high. 2. RIH as deep as possible and punch 5’ tubing holes staying 2’ off a collar. 3. RDMO. Pumping & Well Support 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU Little Red Services. RU reverse out skid and 500 barrel returns tank. 4. Pressure test lines to 3,000 psi. 5. Circulate at least one wellbore volume with source water down tubing, taking returns up casing to 500 barrel returns tank. Bullhead down tbg and IA taking returns to formation as needed to establish and maintain a full column of source water. Well: MPF-109 PTD: 218-014 API: 50-029-23596-00-00 6. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR arrival. 7. RD Little Red Services and reverse out skid. 8. Set BPV. ND tree. NU BOPE. Brief RWO Procedure (Begin Sundried Work) 1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 barrel returns tank. 2. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing and casing. a. If needed, kill well with source water prior to setting CTS. 3. Test BOPE to 250 psi low/ 1,500 psi high. Test annular to 250 psi low/ 1,500 psi high (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform test per ASR 1 BOP Test Procedure b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry conditions of approval. d. Test VBR rams on the 2-7/8” and 3-1/2”test joint. e. Test single ram on the 2-3/8” test joint. f. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Bleed any pressure on casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the returns tank. Kill well with source water as needed. Pull BPV. a. If indications show pressure underneath BPV, lubricate out BPV. 5. Call out Centrilift for ESP pull. 6. RU spoolers to handle ESP cable and dual 3/8” capillary string. a. Use extreme care in spooling the capillary string to promote reuse of the string. 7. MU landing joint or spear, BOLDS, PU on the tubing hanger. a. Tubing hanger is an FMC 11” x 2-7/8” EUE thread top and btm. b. 2018 tubing PU weight on Innovation recorded as 80 kip. Slack off weight recorded as 60 kip. Block weight of 35K. c. 2-7/8” L-80 EUE yield is 144 kip. 8. Confirm hanger free, lay down tubing hanger. 9. POOH and lay down the 2-7/8” tubing. a. Keep/re-use joints 1-42. Wash and toss the rest. b. Keep ported discharge head and centralizer for future use. c. Note any sand or scale inside or on the outside of the ESP on the morning report. d. Recorded Clamp Totals: i. Canon Clamps: 174 ii. Motor Clamps: 4 iii. Seal clamps: 4 iv. Pump Clamps: 19 10. Lay Down ESP. Well: MPF-109 PTD: 218-014 API: 50-029-23596-00-00 11. Pressure test pulled 3/8” capillary tubing to 3500 psi. If PT passes, plan to save for future work. 12. PU Cleanout BHA: a. 1500’ of 2-3/8” PH-6 b. dual flapper c. 1500’ of 2-3/8” PH-6 d. dual flapper e. VACS tool 2.992” OD f. 3,500’ 2-3/8” PH-6 g. 2-3/8” PH-6 x 3-1/2” IF crossover h. 6,100’ of 3-1/2” 13. TIH to the liner top at 5,600’(70 degrees), break circulation and washdown to PBTD 12,375’. 14. TOOH 15. RIH with 2-7/8” 6.5# L-80 ESP completion to +/- 5,325’ and obtain string weights. a. Check electrical continuity every 1000’. b. Note PU and SO weights on tally. c. Install ESP clamps per Baker, and cross coupling clamps every other joint Nom. Size Length Item Lb/ft Material Notes 5.85 2 Centralizer 4 ~5,325 4.5 2 Intake Sensor 30 5.62 34 Motor - 250HP 80 5.2 7 Lower Tandem Seal 38 5.2 7 Upper Tandem Seal 38 5.2 8 Gas Separator 52 5.38 57 Pumps – TBD 45 5.38 57 Pumps – TBD 45 1 Ported Discharge Head 13 L-80 2-7/8" 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 30 2-7/8" EUE 8rd L-80 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"2 XN-nipple 2.313" / 2.205" No-Go 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 60 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"8 2-7/8" x 1" GLM, DV installed 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 4,775 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"8 2-7/8" x 1" GLM, 1/4" OV 6.5 L-80 ~200 MD 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 Well: MPF-109 PTD: 218-014 API: 50-029-23596-00-00 2-7/8" 150 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8" 10 Space out pup 6.5 L-80 2-7/8" 30 Tubing Hanger with full joint 6.5 L-80 16. Land tubing hanger. Use extra caution to not damage cable. 17. Lay down landing joint. 18. Set BPV. 19. RDMO ASR. Post-Rig Procedure: Well Support 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. ND BOPE, set CTS plug, and NU tree. 3. Test tubing hanger void to 500 psi low/5,000 psi high. Pull CTS and BPV. 4. RD crane. Move 500 bbl returns tank and rig mats to next well location. 5. RU well house and flowlines. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Triple BOPE Schematic _____________________________________________________________________________________ Revised By: JH 10/31/2024 SCHEMATIC Milne Point Unit Well: MPU F-109 Last Completed: 3/15/18 PTD: 218-014 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20"Conductor N/A / X-52 / Weld N/A Surface 107’N/A 9-5/8"Surface 40 / L-80 / DWC/C 8.835 Surface 6,451’0.0758 7-5/8”Tieback 29.7 / L-80 / Vam STL SMLS 6.875 Surface 6,289’0.0459 4-1/2”Liner 100ђ Screens 13.5 / L-80 / Hydril 625 3.920 6,282’12,380’.0149 TUBING DETAIL 2-7/8"Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,285’0.0058 3/8”Dual Cap String 3/8”N/A Surface 5,285’N/A OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4" Stg 1 – Lead - 495 sx Extenda Cem / Tail – 398 sx Swift Cem Stg 2 – Lead – 324 sx Perm Cem / Tail – 268 sx Class G (180 bbls to surface) 8-1/2”Cementless Screens Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 50’ Max Hole Angle = 93° @ 10,671’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M Wellhead FMC Gen V GENERAL WELL INFO API: 50-029-23596-00-00 Completion Date: 3/15/18 4-1/2” SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 6,351’4,059’6,474’4,070’ 5 7,218’4,089’7,425’4,089’ 4 8,251’4,075’8,416’4,073’ 5 9,035’4,077’9,201’4,082’ 5 10,728’4,064’10,934’4,052’ 1 12,298’4,046’12,339’4,047’ JEWELRY DETAIL No.Top MD Item ID 1 131’GLM: 2-7/8” x 1” Side Pocket KPMM w/DGLV 2.347” 2 5,047’GLM w/Dummy: 2-7/8” x 1”2.347” 3 5,157’XN Nipple, 2.205” no go 2.205” 4 5,200’Discharge Head: FPDIS 5 5,201’Upper Tandem Pump: 134 STG FLEX 17.5 6 5,224’Lower Tandem Pump: 134 STG FLEX 17.5 7 5,248’Gas Separator: GRS FER N AR 8 5,251’Upper Tandem Seal: GSB3DBUT SB/SB PFSA 9 5,258’Lower Tandem Seal: GSB3DBUT SB/SB PFSA 10 5,265’Motor: CL5 XP – 225hp / 2715V / 51A 11 5,280’Sensor, Zenith 12 5,283’Centralizer: Bottom @ 5,285’ 13 6,282’BOT SLZXP LT Packer / Liner Hanger 7” x 9-5/8”6.190” 14 6,289’7-5/8” Tieback Assy.6.151” 15 6,304’7” H563 x 4.5” HTTC L-80 XO 3.830” 16 12,344’4-1/2” Drillable Packoff Sub 2.390” 17 12,375’WIV Valve LTC BxB (1” Ball on Seat/Closed)- 4-1/2” Screens LINER DETAIL Jts Top (MD)Top (TVD)Btm (MD)Btm (TVD) 18 6,474’4,070’7,218’4,089’ 20 7,425’4,089’8,251’4,075’ 15 8,416’4,073’9,035’4,077’ 37 9,201’4,082’10,728’4,064’ 33 10,934’4,052’12,298’4,046’ _____________________________________________________________________________________ Revised By: TDF 10/23/2024 PROPOSED Milne Point Unit Well: MPU F-109 Last Completed: 3/15/18 PTD: 218-014 TD =12,380’(MD) /TD =4,048’ (TVD) 4 20” Orig. KB Elev.: 26.5’ / GL Elev.: 10.9’ 7-5/8” 7 8&9 10 4 16 9-5/8” 1 2 3 17 See Screen/ Solid Liner Detail PBTD =12,375’ (MD) / PBTD = 4,048’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,509’ MD 5&6 4-1/2” Shoe @ 12,380’ 11 13 1214 15 2-7/8” CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor N/A / X-52 / Weld N/A Surface 107’ N/A 9-5/8" Surface 40 / L-80 / DWC/C 8.835 Surface 6,451’ 0.0758 7-5/8” Tieback 29.7 / L-80 / Vam STL SMLS 6.875 Surface 6,289’ 0.0459 4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hydril 625 3.920 6,282’ 12,380’ .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,285’ 0.0058 OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4" Stg 1 – Lead - 495 sx Extenda Cem / Tail – 398 sx Swift Cem Stg 2 – Lead – 324 sx Perm Cem / Tail – 268 sx Class G (180 bbls to surface) 8-1/2” Cementless Screens Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 50’ Max Hole Angle = 93° @ 10,671’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M Wellhead FMC Gen V GENERAL WELL INFO API: 50-029-23596-00-00 Completion Date: 3/15/18 4-1/2”SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 6,351’ 4,059’ 6,474’ 4,070’ 5 7,218’ 4,089’ 7,425’ 4,089’ 4 8,251’ 4,075’ 8,416’ 4,073’ 5 9,035’ 4,077’ 9,201’ 4,082’ 5 10,728’ 4,064’ 10,934’ 4,052’ 1 12,298’ 4,046’ 12,339’ 4,047’ JEWELRY DETAIL No. Top MD Item ID 1 ±XXX’ GLM: 2-7/8” x 1” 2.347” 2 ±X,XXX’ GLM: 2-7/8” x 1” 2.347” 3 ±X,XXX’ XN Nipple, 2.205” no go 2.205” 4 ±X,XXX’ Discharge Head: FPDIS 5 ±X,XXX’ Pump #2: TBD 6 ±X,XXX’ Pump #1: TBD 7 ±X,XXX’ Gas Separator: 8 ±X,XXX’ Upper Tandem Seal: 9 ±X,XXX’ Lower Tandem Seal: 10 ±X,XXX’ Motor: 11 ±X,XXX’ Sensor: 12 ±X,XXX’ Centralizer: Bottom @ ±X,XXX’ 13 6,282’ BOT SLZXP LT Packer / Liner Hanger 7” x 9-5/8” 6.190” 14 6,289’ 7-5/8” Tieback Assy. 6.151” 15 6,304’ 7” H563 x 4.5” HTTC L-80 XO 3.830” 16 12,344’ 4-1/2” Drillable Packoff Sub 2.390” 17 12,375’ WIV Valve LTC BxB (1” Ball on Seat/Closed) - 4-1/2” Screens LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 18 6,474’ 4,070’ 7,218’ 4,089’ 20 7,425’ 4,089’ 8,251’ 4,075’ 15 8,416’ 4,073’ 9,035’ 4,077’ 37 9,201’ 4,082’ 10,728’ 4,064’ 33 10,934’ 4,052’ 12,298’ 4,046’ Updated 10/9/2024 11” BOPE INTEGRATED 11'’-5000 INTEGRATED 4.30'INTEGRATED 11" - 5000 2-7/8" x 5" VBR Blind 11'’- 5000 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManual Stripping Head ManualManual 2-3/8" Pipe Ram Milne Point ASR 11” BOP w/ Jacks 05/17/2017 Milne Point ASR 11” BOP (Triple) 10/9/2024 Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 12/05/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241205 Well API #PTD #Log Date Log Company Log Type AOGCC ESet AN 15(GRANITE PT ST 18742 15) 50733200700000 167082 11/18/2024 AK E-LINE Perf BRU 221-26 50283202010000 224098 10/24/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 10/21/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 10/30/2024 AK E-LINE Perf BRU 241-23 50283201910000 223061 11/8/2024 AK E-LINE Perf BRU 241-26 50283201970000 224068 11/12/2024 AK E-LINE Plug/Perf END 2-72 50029237810000 224016 10/16/2024 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 10/18/2024 HALLIBURTON COILFLAG MGS-ST 17595-05 50733100710000 165038 10/6/2024 AK E-LINE CBL MPU F-109 50029235960000 218014 10/28/2024 READ CaliperSurvey MPU J-02 50029220710000 190096 11/16/2024 READ CaliperSurvey MPU J-47 50029238010000 224120 11/9/2024 READ LeakPointSurvey MPU D-01 50029206640000 181144 10/23/2024 AK E-LINE TubingPunch MPU F-02 50029226730000 196070 11/18/2024 READ CaliperSurvey MPU I-08 50029228210000 197192 10/22/2024 AK E-LINE TubingPunch MPU I-08 50029228210000 197192 10/26/2024 HALLIBURTON JETCUT MPU L-60 50029236780000 220048 10/26/2024 HALLIBURTON MFC24 MRU M-25 50733203910000 187086 11/15/2024 AK E-LINE Plug NCIU A-21 50883201990000 224086 11/9/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/19/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Perf NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Plug/Perf PBU 06-07A 50029202990100 224043 9/30/2024 HALLIBURTON RBT PBU 14-41A 50029222900100 224076 11/8/2024 HALLIBURTON RBT PBU H-36A 50029226050100 200025 10/26/2024 HALLIBURTON RBT PCU 02A 50283200220100 224110 11/24/2024 AK E-LINE Perf Please include current contact information if different from above. T39808 T39809 T39810 T39810 T39811 T39812 T39813 T39813 T39814 T39815 T39816 T39817 T39818 T39819 T39820 T39820 T39821 T39822 T39823 T39823 T39823 T39823 T39824 T39825 T39826 T39827 MPU F-109 50029235960000 218014 10/28/2024 READ CaliperSurvey Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.05 14:52:46 -09'00' 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: ESP Swap 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 12,380'N/A Casing Collapse Conductor N/A Surface 3,090psi Tieback 4,790psi Liner 8,540psi 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: Wells Manager 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 6,282 MD/ 4,054 TVD and N/A Ryan Lewis ryan.lewis@hilcorp.com 303-906-5178 4-1/2'6,098' 6,264' Perforation Depth MD (ft): 12,380' See Schematic See Schematic 2-7/8" 6,451' 6,289' 107' 20' 9-5/8' 7-5/8' 6,426' N/A 9,020psi 5,750psi 6,890psi 4,068' 4,054' 4,048' Length Size Proposed Pools: 107' 107' 6.5 / L-80 / EUE 8rd TVD Burst 5,285' MD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509, ADL0025515 & ADL0388235 218-014 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23596-00-00 Hilcorp Alaska LLC C.O. 477.07 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 11/7/2024 BOT SLZXP LTP and N/A Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY MILNE PT UNIT F-109 MILNE POINT SCHRADER BLUFF OIL N/A 4,048' 12,375' 4,048' 887 N/A No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 10:46 am, Oct 25, 2024 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.10.25 09:58:41 - 08'00' Taylor Wellman (2143) SFD 10/26/2024MGR28OCT24 * BOPE test to 1500 psi. DSR-10/29/24 10-404 JLC 10/29/2024 Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.10.30 05:22:08 -08'00'10/30/24 RBDMS JSB 103024 Well: MPF-109 PTD: 218-014 API: 50-029-23596-00-00 Well Name:MPF-109 API Number:50-029-23596-00-00 Current Status:Shut-in ESP Rig:ASR #1 Estimated Start Date:11/7/2024 Estimated Duration:4 days Regulatory Contact:Tom Fouts Permit to Drill Number:218-014 First Call Engineer:Ryan Lewis (303) 906-5178 (M) Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) Current Bottom Hole Pressure: 1264 psi @ 3,767’ TVD 10/24/2023 | 6.5 EMW, 6.9 KWF Max Potential Surface Pressure: 887 psi Gas Column Gradient (0.1 psi/ft) Max Angle: 61° Max Angle at 5,007’ MD Brief Well Summary: MPU F-109 was drilled and completed in March 2018 as a Schrader Bluff OA producer with an ESP completion. The first/current ESP completion was installed in 2018. The ESP has failed due to warn out pumps after a 6 year run life. Scale was collected and is 80% Fe. We plan to upsize the motor and pumps to help with the high viscosity oil to get a repeat 6+ year run on this install. Objectives: Pull failed ESP completion, run new ESP completion. Notes Regarding Wellbore Condition: - 7” casing test to 1,800 psi on 3/12/2018 at 6,282’ MD. Pre-Rig Procedure (Non Sundried Work) Slickline 1. RU slickline, pressure test PCE to 250psi low / 1,500psi high. 2. Drift and tag with sample bailer. 3. Caliper from as deep as possible to surface. 4. Attempt to pull dummy valve from GLM at 5,047’ MD and leave open. 5. Pull GLV and set dummy valve in upper GLM at 131’ MD. 6. RDMO. Eline (Contingency) 1. RU Eline, pressure test to 250psi low / 1,500psi high. 2. RIH as deep as possible and punch 5’ tubing holes staying 2’ off a collar. 3. RDMO. Pumping & Well Support 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU Little Red Services. RU reverse out skid and 500 barrel returns tank. 4. Pressure test lines to 3,000 psi. 5. Circulate at least one wellbore volume with source water down tubing, taking returns up casing to 500 barrel returns tank. Bullhead down tbg and IA taking returns to formation as needed to establish and maintain a full column of source water. EMW, 6.9 KWF Well: MPF-109 PTD: 218-014 API: 50-029-23596-00-00 6. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR arrival. 7. RD Little Red Services and reverse out skid. 8. Set BPV. ND tree. NU BOPE. Brief RWO Procedure (Begin Sundried Work) 1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 barrel returns tank. 2. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing and casing. a. If needed, kill well with source water prior to setting CTS. 3. Test BOPE to 250 psi low/ 1,500 psi high. Test annular to 250 psi low/ 1,500 psi high (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform test per ASR 1 BOP Test Procedure b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry conditions of approval. d. Test VBR rams on the 2-7/8” test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Bleed any pressure on casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the returns tank. Kill well with source water as needed. Pull BPV. a. If indications show pressure underneath BPV, lubricate out BPV. 5. Call out Centrilift for ESP pull. 6. RU spoolers to handle ESP cable and dual 3/8” capillary string. a. Use extreme care in spooling the capillary string to promote reuse of the string. 7. MU landing joint or spear, BOLDS, PU on the tubing hanger. a. Tubing hanger is an FMC 11” x 2-7/8” EUE thread top and btm. b. 2018 tubing PU weight on Innovation recorded as 80 kip. Slack off weight recorded as 60 kip. Block weight of 35K. c. 2-7/8” L-80 EUE yield is 144 kip. 8. Confirm hanger free, lay down tubing hanger. 9. POOH and lay down the 2-7/8” tubing. a. Caliper will determine how mucc tubing we reuse. b. Keep ported discharge head and centralizer for future use. c. Note any sand or scale inside or on the outside of the ESP on the morning report. d. Recorded Clamp Totals: i. Canon Clamps: 174 ii. Motor Clamps: 4 iii. Seal clamps: 4 iv. Pump Clamps: 19 10. Lay Down ESP. 11. Pressure test pulled 3/8” capillary tubing to 3500 psi. If PT passes, plan to save for future work. Well: MPF-109 PTD: 218-014 API: 50-029-23596-00-00 12. RIH with 2-7/8” 6.5# L-80 ESP completion to +/- 5,325’ and obtain string weights. a. Check electrical continuity every 1000’. b. Note PU and SO weights on tally. c. Install ESP clamps per Baker, and cross coupling clamps every other joint Nom. Size Length Item Lb/ft Material Notes 5.85 2 Centralizer 4 ~5,325 4.5 2 Intake Sensor 30 5.62 34 Motor - 250HP 80 5.2 7 Lower Tandem Seal 38 5.2 7 Upper Tandem Seal 38 5.2 8 Gas Separator 52 5.38 57 Pumps – TBD 45 5.38 57 Pumps – TBD 45 1 Ported Discharge Head 13 L-80 2-7/8" 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 30 2-7/8" EUE 8rd L-80 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"2 XN-nipple 2.313" / 2.205" No-Go 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 60 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"8 2-7/8" x 1" GLM, DV installed 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 4,775 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"8 2-7/8" x 1" GLM, 1/4" OV 6.5 L-80 ~200 MD 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 150 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8" 10 Space out pup 6.5 L-80 2-7/8" 30 Tubing Hanger with full joint 6.5 L-80 13. Land tubing hanger. Use extra caution to not damage cable. 14. Lay down landing joint. 15. Set BPV. 16. RDMO ASR. Post-Rig Procedure: Well Support 1. RD mud boat. RD BOPE house. Move to next well location. Well: MPF-109 PTD: 218-014 API: 50-029-23596-00-00 2. RU crane. ND BOPE, set CTS plug, and NU tree. 3. Test tubing hanger void to 500 psi low/5,000 psi high. Pull CTS and BPV. 4. RD crane. Move 500 bbl returns tank and rig mats to next well location. 5. RU well house and flowlines. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Double BOPE Schematic _____________________________________________________________________________________ Revised By: TDF 10/23/2024 SCHEMATIC Milne Point Unit Well: MPU F-109 Last Completed: 3/15/18 PTD: 218-014 TD =12,380’ (MD) / TD =4,048’ (TVD) 4 20” Orig. KB Elev.: 26.5’ / GL Elev.: 10.9’ 7-5/8”7 8 & 9 10 4 16 9-5/8” 1 2 3 17 See Screen/ Solid Liner Detail PBTD =12,375’ (MD) / PBTD =4,048’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,509’ MD 5 & 6 4-1/2” Shoe @ 12,380’ 11 13 1214 15 2-7/8” CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor N/A / X-52 / Weld N/A Surface 107’ N/A 9-5/8" Surface 40 / L-80 / DWC/C 8.835 Surface 6,451’ 0.0758 7-5/8” Tieback 29.7 / L-80 / Vam STL SMLS 6.875 Surface 6,289’ 0.0459 4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hydril 625 3.920 6,282’ 12,380’ .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,285’ 0.0058 3/8” Dual Cap String 3/8” N/A Surface 5,285’ N/A OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4" Stg 1 – Lead - 495 sx Extenda Cem / Tail – 398 sx Swift Cem Stg 2 – Lead – 324 sx Perm Cem / Tail – 268 sx Class G (180 bbls to surface) 8-1/2” Cementless Screens Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 50’ Max Hole Angle = 93° @ 10,671’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M Wellhead FMC Gen V GENERAL WELL INFO API: 50-029-23596-00-00 Completion Date: 3/15/18 4-1/2”SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 6,351’ 4,059’ 6,474’ 4,070’ 5 7,218’ 4,089’ 7,425’ 4,089’ 4 8,251’ 4,075’ 8,416’ 4,073’ 5 9,035’ 4,077’ 9,201’ 4,082’ 5 10,728’ 4,064’ 10,934’ 4,052’ 1 12,298’ 4,046’ 12,339’ 4,047’ JEWELRY DETAIL No. Top MD Item ID 1 131’ GLM: 2-7/8” x 1” Side Pocket KPMM w/DPSOV 2.347” 2 5,047’ GLM w/Dummy: 2-7/8” x 1” 2.347” 3 5,157’ XN Nipple, 2.205” no go 2.205” 4 5,200’ Discharge Head: FPDIS 5 5,201’ Upper Tandem Pump: 134 STG FLEX 17.5 6 5,224’ Lower Tandem Pump: 134 STG FLEX 17.5 7 5,248’ Gas Separator: GRS FER N AR 8 5,251’ Upper Tandem Seal: GSB3DBUT SB/SB PFSA 9 5,258’ Lower Tandem Seal: GSB3DBUT SB/SB PFSA 10 5,265’ Motor: CL5 XP – 225hp / 2715V / 51A 11 5,280’ Sensor, Zenith 12 5,283’ Centralizer:Bottom @ 5,285’ 13 6,282’ BOT SLZXP LT Packer / Liner Hanger 7” x 9-5/8” 6.190” 14 6,289’ 7-5/8” Tieback Assy. 6.151” 15 6,304’ 7” H563 x 4.5” HTTC L-80 XO 3.830” 16 12,344’ 4-1/2” Drillable Packoff Sub 2.390” 17 12,375’ WIV Valve LTC BxB (1” Ball on Seat/Closed) - 4-1/2” Screens LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 18 6,474’ 4,070’ 7,218’ 4,089’ 20 7,425’ 4,089’ 8,251’ 4,075’ 15 8,416’ 4,073’ 9,035’ 4,077’ 37 9,201’ 4,082’ 10,728’ 4,064’ 33 10,934’ 4,052’ 12,298’ 4,046’ _____________________________________________________________________________________ Revised By: TDF 10/23/2024 PROPOSED Milne Point Unit Well: MPU F-109 Last Completed: 3/15/18 PTD: 218-014 TD =12,380’(MD) /TD =4,048’ (TVD) 4 20” Orig. KB Elev.: 26.5’ / GL Elev.: 10.9’ 7-5/8” 7 8&9 10 4 16 9-5/8” 1 2 3 17 See Screen/ Solid Liner Detail PBTD =12,375’ (MD) / PBTD = 4,048’ (TVD) 9-5/8” ‘ES’ Cementer @ 2,509’ MD 5&6 4-1/2” Shoe @ 12,380’ 11 13 1214 15 2-7/8” CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor N/A / X-52 / Weld N/A Surface 107’ N/A 9-5/8" Surface 40 / L-80 / DWC/C 8.835 Surface 6,451’ 0.0758 7-5/8” Tieback 29.7 / L-80 / Vam STL SMLS 6.875 Surface 6,289’ 0.0459 4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hydril 625 3.920 6,282’ 12,380’ .0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,285’ 0.0058 OPEN HOLE / CEMENT DETAIL Conductor ±270 ft3 12-1/4" Stg 1 – Lead - 495 sx Extenda Cem / Tail – 398 sx Swift Cem Stg 2 – Lead – 324 sx Perm Cem / Tail – 268 sx Class G (180 bbls to surface) 8-1/2” Cementless Screens Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 50’ Max Hole Angle = 93° @ 10,671’ MD TREE & WELLHEAD Tree Cameron 2-9/16" 5M Wellhead FMC Gen V GENERAL WELL INFO API: 50-029-23596-00-00 Completion Date: 3/15/18 4-1/2”SOLID LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4 6,351’ 4,059’ 6,474’ 4,070’ 5 7,218’ 4,089’ 7,425’ 4,089’ 4 8,251’ 4,075’ 8,416’ 4,073’ 5 9,035’ 4,077’ 9,201’ 4,082’ 5 10,728’ 4,064’ 10,934’ 4,052’ 1 12,298’ 4,046’ 12,339’ 4,047’ JEWELRY DETAIL No. Top MD Item ID 1 ±XXX’ GLM: 2-7/8” x 1” 2.347” 2 ±X,XXX’ GLM: 2-7/8” x 1” 2.347” 3 ±X,XXX’ XN Nipple, 2.205” no go 2.205” 4 ±X,XXX’ Discharge Head: FPDIS 5 ±X,XXX’ Pump #2: TBD 6 ±X,XXX’ Pump #1: TBD 7 ±X,XXX’ Gas Separator: 8 ±X,XXX’ Upper Tandem Seal: 9 ±X,XXX’ Lower Tandem Seal: 10 ±X,XXX’ Motor: 11 ±X,XXX’ Sensor: 12 ±X,XXX’ Centralizer: Bottom @ ±X,XXX’ 13 6,282’ BOT SLZXP LT Packer / Liner Hanger 7” x 9-5/8” 6.190” 14 6,289’ 7-5/8” Tieback Assy. 6.151” 15 6,304’ 7” H563 x 4.5” HTTC L-80 XO 3.830” 16 12,344’ 4-1/2” Drillable Packoff Sub 2.390” 17 12,375’ WIV Valve LTC BxB (1” Ball on Seat/Closed) - 4-1/2” Screens LINER DETAIL Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD) 18 6,474’ 4,070’ 7,218’ 4,089’ 20 7,425’ 4,089’ 8,251’ 4,075’ 15 8,416’ 4,073’ 9,035’ 4,077’ 37 9,201’ 4,082’ 10,728’ 4,064’ 33 10,934’ 4,052’ 12,298’ 4,046’ Updated 10/24/2024 Milne Point ASR Rig 1 BOPE 2024 11” BOPE 4.48' 4.54' 2.00' CIW-U 4.30'Hydril GK 11" - 5000 VBR or Pipe Rams Blind11'’- 5000 DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualHCR Stripping Head 2-7/8” x 5” VBR THE STATE ALASKA GOVERNOR MIKE DUNLEAVY March 21, 2019 Mr. Bo York Operations Manager Hilcorp Alaska LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: OTH 18-048 Well Testing Methods MPU F-107 (PTD 2180010 and MPU F-109 (PTD 2180140) Milne Point Unit 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 www.00gcc.olaska.gov By letter dated September 12, 2018, Hilcorp Alaska, LLC (Hilcorp) requested approval of a well testing method for Milne Point Unit (MPU) wells F-107 (PTD 218-001) and F-109 (PTD 218-014). The MPU F-107 and F-109 wells were drilled and completed in the Schrader Bluff Oil Pool in the first quarter of 2018. Both wells encountered more viscous oil than anticipated, which makes obtaining acceptable well testing results on the wells difficult. Hilcorp proposes an alternative well testing methodology for these wells in order to obtain more accurate test results. In its letter Hilcorp provides detailed testing procedures. A summary of Hilcorp's proposal is to conduct a flow test on the MPU F -87A (PTD 203-213) well, which produces from the much warmer Kuparuk River formation, then, one at a time, commingle production from the MPU F-107 and MPU F-109 wells with the MPU F -87A well and conduct a well test on the combined flow streams. Commingling production from the warm MPU F -87A well and MPU F-107 or F-109 wells will have the effect of reducing the viscosity of the produced oil as it flows through the test separator. Hilcorp's request to use an alternative well testing methodology to test the MPU F-107 and MPU F- 109 wells is APPROVED on the condition that the testing is conducted in accordance with the detailed procedure contained in the September 12, 2018, letter. Any questions regarding t4is approval should be directed to Dave Roby at 907-793-1232. Sincerely, C/ Daniel T. Seamount, Jr Commissioner Jessie e owski Commissioner to York 3800 Centerpoint Dr Operations Manager Suite 1400 bvork(dHilcoro corn Anchorage, AK 99503 Alaska, LLC Phone: 907/777-8345 Fax: 907/777-8560 12 September 2018 Mr. David Roby Alaska Oil & Gas Conservation Commission SEP 12 7013 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 A0 G C- C Re: Milne Point Unit Schrader Bluff Pool Oil F-107 (PTD 218-001) and F-109 (PTD 218-014), Request for Approval of Well Test Procedure Dear Mr. Roby: Milne Point's new Schrader Bluff NB wells, F-107 (on ESP production 22 Feb 2018) and F-109 (on ESP production 17 Mar 2018), have proven difficult to obtain a well test after coming online with higher than expected fluid viscosities. At 60 degrees F, F-107 exhibits an API gravity of 16.1 and 3,102 cP and F-109 exhibits an API gravity of 16.5 and 1,864 cP. This higher viscosity makes achieving an accurate test difficult. As required by 20 AAC 25.230, Hilcorp has developed a well test procedure that will accurately and reliably measure the produced fluids from F-107 and F-109. Hilcorp requests AOGCC review and approve the proposed well test procedure detailed below. This procedure is very similar to the previous approved method for testing L-51 and L- 53, both wells that share similar characteristics to F-107 and F-109. Proposed Well Test Procedure for F-107 and F-109 Alter the control logic to allow two wells into the test separator at the same time and determine the rates per the detailed procedure note below. The higher temperature well MP F -87A flows at 157 °F to improve the well test accuracy of the MP F-107 and F-109 wells. The Milne automations technicians will revise the control logic as follows: 1. A standard/normal six hour test is performed on F -87A. F -87A is a Kuparuk producer with 157 °F produced fluid (1,200 bwpd, —170 bopd and —100 mscfd)). The F -87A choke is manipulated as necessary to mimic the higher back pressure observed when F-107 or F-109 are placed in the test header. This test will not be considered a valid test for F -87A since the back pressure will be artificially higher than normal. 2. Immediately following the F -87A test, the operator selects the Schrader well (i.e., F-107 or F-109) for test. 3. The revised test logic automatically rolls F -87A into the test header prior to F- 107 or F-109. F -87A purges the test header for 15 minutes with warm produced fluids. 4. After the 15 minute F -87A only purge, the selected F-107 or F-109 well will automatically roll into the test header along with F -87A for a second 15 minute purge cycle. Once the entire 30 minute purge cycle is completed the test begins. 5. The produced gas and the warm fluid from F-8 7A mixes with F-107 or F-109 and the extra gas and the extra heat allows for the separator to function as designed. The level control stays at setpoint, the pressure controller maintains the desired differential, and there is no liquid carryover into the gas leg. 6. During the test phase, three individual 100 mL grab samples are taken from the separator. These samples are allowed to separate over 24 hours in order to determine an average shrinkage factor. 7. At the end of the test both wells are diverted from the test header, per normal procedure, and the next well selected will start its test cycle per normal operations. 8. Following the test, the amount of produced fluid from F -87A as determined by the F-8 7A test immediately prior to the F-107 or F-109 test cycle, is backed out of the F-107 or F-109 well test. The average shrinkage factor determined from the three grab samples is then applied to the F-107 or F-109 test results in order to determine the final approved test result. Based on the above attempts to achieve an accurate well test on F-107 and F-109, Hilcorp requests AOGCC approve the test procedure as detailed in steps 1-8 above. This test procedure would not change or modify any other test procedure for any other well on F - pad and would also not adjust or modify production reporting or allocation procedures. Hilcorp believes the proposed procedures will result in an accurate and reliable test per 20 AAC 25.230. If you have questions regarding this communicated intent please feel free to contact me. Sincerely, Hilcorp Alaska, LLC B ork Operations Manager • • o N o 0) OCO n, a ain O ❑ Q rn m M Z _ W O O Q Q 7 = Q Q a > Q Q Q R N � I co co I I N N I NI > as N D } O ❑ ❑ w w w LU E w W w a J LL LL 'E 'c — — o con @ rn 2 2 1I CI .( .� CCI CCI CCI I ► CD CD ❑ ❑ C7 CD ❑ ❑ 0 C7 C! 2 Z E LL E 0 0 . 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N 0 G U o - a E 2 o E d E E d a 2 w 3 i U a 0 8i U c 0 0 0 IRS • STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION C 3 2018 WELL COMPLETION OR RECOMPLETION REPORT AND LOG la.Well Status: Oil Q I Gas❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ lb.Well CIAO CC 20AAC 25.105 20AAC 25.110 Development ' Exploratory ❑ GINJ ❑ WINJ ❑ WAGE WDSPL❑ No.of Completions: _1om Service ❑ Stratigraphic Test ❑ 2.Operator Name: 6. ate CSusp.,or 14. Permit to Drill Number/ Sundry: Hilcorp Alaska, LLC Aband.: 3/9/2018. 218-014 ' 3.Address: 7.Date Spudded: 15.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 February 17,2018' 50-029-23596-00-00 4a. Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: Surface: 1415'FSL,3299'FEL,Sec 6,T13N, R10E, UM,AK March 2,2018• MPU F-109 ' Top of Productive Interval: 9. Ref Elevations: KB: 37.4' 17. Field/Pool(s):Milne Point Field 2128'FNL, 185'FWL,Sec 7,T13N, R10E, UM,AK GL: 10.9' BF: 10.9' Schrader Bluff Oil Pool • Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 1853'FNL, 1790'FEL,Sec 18,T13N, R10E, UM,AK 12,375'MD/4,048'TVD ADL025509,ADL388235,ADL025515 • 4b.Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- 541270 y- 6034863 Zone- 4 •12,380'MD/4,048'TVD LONS 94-109 TPI: x- 539610 y- 6031311 Zone- 4 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 542859 y- 6026324 Zone- 4 N/A 2,209'MD/1,861'TVD 5. Directional or Inclination Survey: Yes U (attached) No ❑ 13.Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) N/A 22. Logs Obtained: List all logs run and,pursuant to AS 31.05.030 and 20 AAC 25.071,submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first.Types of logs to be listed include, but are not limited to: mud log,spontaneous potential, gamma ray,caliper, resistivity,porosity,magnetic resonance,dipmeter,formation tester,temperature,cement evaluation,casing collar locator,jewelry,and perforation record. Acronyms may be used.Attach a separate page if necessary ROP-DGR-ABG-EWR-ADR 2"/5"MD DGR-EWR-ADR 2"/5"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 FT PULLED 20" - X-52 Surface 107' Surface 107' 42" 270 ft3 Stg 1 L-495 sx/T-398 sx 57 bbIs 9-5/8" 40# L-80 Surface 6,451' Surface 4,068' 12-1/4" Stg 2 L-324 sx/T-268 sx 180bbls - 1 7-5/8" 29.7# L-80 Surface 6,289' Surface 4,054' Tieback Tieback Assy. 4-1/2" 13.5# L-80 6,282' 12,380' 4,054' 4,048' 8-1/2" Cementless Screens Liner 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/TVD) Size and Number; Date Perfd): bra lie my 2-7/8" 5,285' N/A **See attached schematic for Screen/Solid Liner Detail** 26.ACID, FRACTURE,CEMENT SQUEEZE,ETC. Was hydraulic fracturing used during completion? Yes❑ No ❑✓ �e(' �J Per 20 AAC 25.283(i)(2)attach electronic and printed information Ye(' o DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 3/22/2018 ESP Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 3/30/2018 24 Test Period ,—+288 107 1653 N/A 371 Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 250 350 24-Hour Rate — 288 107 1653 Form 10-407 Revised 5/2017 p CONTINUED ON PAGE 2 p r Submit ORIGINIAL onl�r, (l4?, •111_/1? G.(P 41t Y//271,/ Rip �s ' ` 3 2t 18 • 28.CORE DATA Conventional Core(s): Yes ❑ No Q Sidewall Cores: es ❑ No 0 If Yes, list formations and intervals cored(MD/TVD, From/To),and summarize lithology and presence of oil,gas or water(submit separate pages with this form, if needed).Submit detailed descriptions,core chips, photographs,and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑✓ Permafrost-Top If yes, list intervals and formations tested, briefly summarizing test results. Permafrost-Base 2,209' 1,861' Attach separate pages to this form, if needed,and submit detailed test Top of Productive Interval SB OA 6,474' 4,064' information, including reports,per 20 AAC 25.071. SV5 1,497' 1,389' SV1 2,508' 2,057' Ugnu LA3 4,579' 3,388' Schrader NA 5,557' 3,896' Schrader OA 6,401' 4,064' Formation at total depth: Schrader Bluff OA 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys,Casing and Cement Report. Information to be attached includes, but is not limited to:summary of daily operations,wellbore schematic,directional or inclination survey,core analysis, paleontological report, production or well test results,per 20 AAC 25.070. 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: ail flger hIICOrp.00171 Authorized Contact Phone: 777-8389 Signature: — 3. Zo i 9 Date: � S INSTRUCTIONS General: This form and the required attachmentsprovide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram q P 9 with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed.All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC,no matter when the analyses are conducted. Item 1 a: 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 1 b: Well Class-Service wells:Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation,or Other. Item 4b: TPI(Top of Producing Interval). Item 9: The Kelly Bushing,Ground Level,and Base Flange 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 15: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 19: Report the Division of Oil&Gas/Division of Mining Land and Water: Plan of Operations(LO/Region YY-123), Land Use Permit(LAS 12345), and/or Easement(ADL 123456)number. Item 20: Report measured depth and true vertical thickness of permafrost.Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and,pursuant to AS 31.05.030,submit all electronic data and printed logs within 90 days of completion,suspension, or abandonment,whichever occurs first. Item 23: Attached supplemental records 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.Pursuant to 20 AAC 25.071,submit detailed descriptions,core chips,photographs,and all subsequent laboratory analytical results, including,but not limited to:porosity, permeability,fluid saturation,fluid composition,fluid fluorescence,vitrinite reflectance,geochemical,or paleontology. 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. Item 31: Pursuant to 20 AAC 25.070,attach to this form:well schematic diagram,summary of daily well operations,directional or inclination survey,and other tests as required including,but not limited to:core analysis,paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only Milne Point Unit Well: MPU F-109 II • SCHEMATIC Last Completed: 3/15/18 llilcoru-llnaka,LLC PTD: 218-014 Orig.KBEIev.:26.5'/GLEIev.:10.9' TREE &WELLHEAD Tree Cameron 2-9/16" 5M ` Wellhead FMC Gen V 20" ' . i i 1 OPEN HOLE/CEMENT DETAIL Conductor ±270 ft3 Stg 1-Lead-495 sx Extenda Cern/Tail-398 sx Swift Cern 2-7/8" i 12-1/4" Stg 2-Lead-324 sx Perm Cern/Tail-268 sx Class G (180 bbls to surface) 8-1/2" Cementless Screens Liner in 8-1/2"hole `. 3. , r CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm BPF 9&8'ES . Demister 4!) 20" Conductor N/A/X-52/Weld N/A Surface 106.5' N/A 2509'MD 9-5/8" Surface 40/L-80/DWC/C 8.835 Surface 6,451' 0.0758 7-5/8" Tieback 29.7/L-80/Vam STL SMLS 6.875 • Surface . 6,289' 0.0459 4-1/2" Liner 1O0µScreens 13.5/L 80/Hydril 625 3.920 6,282' 12,380' .0149 TUBING DETAIL 1' 2-7/8" Tubing 6.5/L-80/EUE-8rd 2.441 Surface 5,285' 0.0058 3/8" Dual Cap String 3/8" N/A Surface 5,285' N/A 2 WELL INCLINATION DETAIL KOP@50' 3 Max Hole Angle=93°@ 10,671'MD 1 4 JEWELRY DETAIL No. Top MD Item ID 316 1 131' GLM: 2-7/8"x 1"Side Pocket KPMM w/DPSOV 2.347" 2 5,047' GLM w/Dummy: 2-7/8"x 1" 2.347" 3 5,157' XN Nipple,2.205"no go 2.205" Tspr W9 4 5,200' Discharge Head:FPDIS 5 5,201' Upper Tandem Pump:134 STG FLEX 17.5 6 5,224' Lower Tandem Pump:134 STG FLEX 17.5 70 7 5,248' Gas Separator:GRS FER N AR 8 5,281' Upper Tandem Seal:GSB3DBUT SB/SB PFSA " �� 9 5,258' Lower Tandem Seal:GSB3DBUT SB/SB PFSA 10 5,265' Motor:CL5 XP-225hp/2715V/51A 14 12 11 5,280' Sensor,Zenith 12 _ 5,283' _ Centralizer: Bottom @ 5,28' `` 15 13 _ 6,282' _ BOT SLZXP LT Packer/Liner Hanger 7"x 9-5/8" 6.190" 9-5/8- 1 14 6,289' _ 7-5/8"Tieback Assy. 6.151" 15 6,304' 7"H563 x 4.5"HTTC L-80 XO 3.830" 16 12,344' 4-1/2"Drillable Packoff Sub 2.390" 17 12,375' WIV Valve LTC BxB(1"Ball on Seat/Closed) - See Seized 4-1/2"SOLID LINER DETAIL salla 4-1/2"Screens LINER DETAIL Liner Jts Top Top Btm Btm Demi (MD) (TVD) (MD) (TVD) Jts Top(MD) Top(TVD) Btm(MD) Btm(TVD) 4 6,351' 4,059' 6,474' 4,070' 5 7,218' 4,089' 7,425' 4,089' 18 6,474' 4,070' 7,218' 4,089' 4 8,251' 4,075' 8,416' 4,073' 20 7,425' 4,089' 8,251' 4,075' 41/2' 116 5 9,035' 4,077' 9,201' 4,082' 15 8,416' 4,073' 9,035' 4,077' Shoe @ 5 10,728' 4,064' 10,934' 4,052' 37 9,201' 4,082' 10,728' 4,064' 12,380' 17 1 12,298' 4,046' 12,339' 4,047' 33 10,934' 4,052' 12,298' 4,046' TD=12,380'(MD)/ID=4,048'(1VD) GENERAL WELL INFO PBTD=12,375'(MD)/PBTD=4,048'(TVD) API:50-029-23596-00-00 Completion Date:3/15/18 Edited By:CJD 4-3-2018 Milne Point Unit II • i Well: MPU F-109 SCHEMATIC Last Completed: 3/15/18 Hilcarp Alaska,LLC PTD: 218-014 Orig.KB Elev.:26.5'/GL Elev.:10.9 TREE&WELLHEAD Tree Cameron 2-9/16" 5M ' Wellhead FMC Gen V 20 J a 1 P OPEN HOLE/CEMENT DETAIL Conductor ±270 ft3 Stg 1-Lead-495 sx Extenda Cern/Tail-398 sx Swift Cern 2-7/8" - - 12-1/4" Stg 2-Lead-324 sx Perm Cern/Tail-268 sx Class G (180 bbls to surface) 8-1/2" Cementless Screens Liner in 8-1/2"hole CASING DETAIL ^� i4 Size Type Wt/Grade/Conn ID Top Btm BPF gCementer @ 20" Conductor N/A/X-52/Weld N/A Surface 106.5' N/A 2,50g ND9-5/8" Surface 40/L-80/DWC/C 8.835 Surface 6,451' 0.0758 7-5/8" Tieback 29.7/L-80/Vam STL SMLS 6.875 Surface 6,289' 0.0459 12 380' .0149 4-1/2" Liner 100 Screens 13.5 L-80 Hydril 625 3.920 6,282' , / µ / / Y t ^ TUBING DETAIL 01 2-7/8" Tubing _ 6.5/L-80/EUE-8rd 2.441 Surface 5,285' 0.0058 er gi il 3/8" Dual Cap String 3/8" N/A Surface 5,285' N/A 2 WELL INCLINATION DETAIL it yer KOP @ 50' 1 3 4, 9 -4- Max Hole Angle=93°@ 10,671'MD %F,. JEWELRY DETAIL )18 J11cr-^'TMD op Item ID 5/6 t1 1 131' GLM. 2-7/8"x 1"Side Pocket KPMM w/DPSOV 2.347" a 2 5,047' GLM w/Dummy: 2-7/8"x 1" 2.347" 7 5/8"-� III:I 7 3 5,157' XN Nipple,2.205"no go 2.205" ; 8/9 r 4 5,200' Discharge Head:FPDIS 5 5,201' Upper Tandem Pump:134 STG FLEX 17.5 6 5,224' Lower Tandem Pump:134 STG FLEX 17.5 I 10 7 5,248' Gas Separator:GRS FER N AR 8 5,281' Upper Tandem Seal:GSB3DBUT SB/SB PFSA ' 7-- 11 9 5,258' Lower Tandem Seal:GSB3DBUTSB/SB PFSA i11i 10 5,265' Motor:CL5 XP-225hp/2715V/51A 14 124 11 5,280' Sensor,Zenith 13 12 5,283' Centralizer:Bottom @ 5,285' 15 13 6,282' BOT SLZXP LT Packer/Liner Hanger 7"x 9-5/8" 6.190" 15/8 ;4114 6,289' 7-5/8"Tieback Assy. 6.151" I 15 6,304' 7"H563 x 4.5"HTTC L-80 XO 3.830" 16 12,344' 4-1/2"Drillable Packoff Sub 2.390" 17 12,375' WIV Valve LTC BxB(1"Ball on Seat/Closed) - SeeI 4-1/2"SOLID LINER DETAIL Solid 4-1/2"Screens LINER DETAIL Liner Jts Top(MD) Btm(MD) S Derail Jts Top(MD) Btm(MD) .....,....0".."---' 6,351' 6,474' _ 5 7,218' 7,425' 18 6,474' 7,218 4 8,251' 8,416' 20 7,425' 8,251' SSASCN 5 9,035' 9,201' 15 8,416' 9,035' 4-1/2" l -.it. 16 37 9,201' 10,728' Shoe @ 5 10,728' 10,934' 33 10,934' 12,298' 12,380' 17 1 12,298' 12,339' GENERAL WELL INFO TD=12,380'(MD)/TD=4,048'(ND) API:50-029-23596-00-00 PBTD=12,375'(MD)/PBTD=4,048'(TVD) Completion Date:3/15/18 Created By:CJD 3-15-2018 • II , nHilcorp Energy Company Composite Report Well Name: MP F-109 Field: Milne Point County/State: Milne Point,Alaska (LAT/LONG): avation(RKB): 26.5 API#: 50-029-23596-00-00 Spud Date: 2/18/2018 Job Name: 1714020D MPF-109 Drilling Contractor AFE#: AFE$: ............... >,.p:<:::::::. ...::.r:.r.:.:.r ..... .:... ;:: 5 S`um mar 2/16/2018 Continue to Separate and stage Mods on Pad.Clear Snow/Ice from around F-109.Set Rig Mats around F-109.Walk Sub Off F-107 and Spot/Level Sa e.Spot Catwalk,Pipe Shed,Pit Mod and Power Mod.;Submit 24 notification to AOGCC for diverter test©17:55 hrs on 2-16-2018.;Continue to spot motor mod le. Connect power cables and interconnects.Swap from cold start to gen power.Release Peak @ 19:30;R/U lower stairways,utility interconnects,mud an•flow lines,Spot envirovac and break room.Spot and berm cuttings tank.R/U sub outriggers.Get steam,air and water circulating.;Put mud pumps back toge her. Organize pad.Install grating in cellar.Hook up Wt Bucket and Geronimo lines.PJSM to scope Derrick.Scope and pin same.Bridle down and secure lines.;Perform derrick inspection. Circulate warm water thru pits and lines.Work on rig acceptance checklist.;N/U Diverter System,set speed head w/ ell head rep. PJSM,Set diverter tee,M/U knife valve, position and flange up diverter sections.;Set BOP stack,TQ flanges.M/U conductor valves.R/U koo ey lines to Knife valve and annular.Energize accumulator. 2/17/2018 Finish Rig Acceptance Check List.Accept Rig @ 06:00.Continue to N/U Diverter System.;Weld on bolts for Weather Cushions on Mezz/Pits Interconn.ct.C/O Break out side Tong Chain.RU 3'Rig Tongs. Inspect DP handling Equip.;Test Diverter System on 5"DP Start:3000,After close 2050 psi,200 psi buil. 17 sec,Full Recovery 53 sec.Ann.Close time 10 sec,Knife Valve Open 5 sec.6 Bottles©2333 psi average.;Test Gas alarms and PVT System.All Pass Test Witness Waived by Matt Herrera via phone call©09:45.;R/U Hawk Jaw and service same.Work in Pits on obtain Measurements.Strap and tally 5"H DP. Install Mouse Hole in Rotary Table.C/O Check Valves on Koomey, Pumps and#1 Dampener.;PU and rack back 210 jts DS-50 Dp and 17 jts HWDP w/ ars. Total DS-50 in derrick=210 jts+17jts HWDP=-6552'.;R/D and demob Hawk Jaw. Clean and clear rig floor. Prep for making up BHA and verify corr'ct lineup in cellar and pits for spud.;Pre-Spud meeting.Discussed upcoming task and hazards associated with.;M/U 12.25"Kymera,1.5°bend motor,BN 0 and HWDP. Tag ice @ 90'MD, Flood surface lines and conductor with H2O. Test surface lines to 3k and check for leaks(test good).;Clear ice to 106'then .rill . new formation to 120'MD. P/U and displace to 8.7#spud mud. Continue drill ahead to 218'MD. 400 gpm,450 psi,40 rpm,2k tq,1-2k wob.;B/D TD. "ack back HWDP.M/U remaining MWD/LWD tools and scribe same.;Hauled 25 bbls cuttings to G&I for total=25 bbls Hauled 520 bbls from 6 mi lake for total=520 bbls 0 bbl daily losses to formation for total=0 bbls II 2/18/2018 Continue Up Load MWD tools.MU 2 NMDC's.Shallow pulse test.RU Gyro Tools and Sheave.Service Rig.;Drill 12 1/4"Hole F/219'-T/456'.237'total(59' AROP) 400 gpm/900 psi.40 rpm/3.2k tq,8-12k wob 61k up,65k dn,64k rot. ECD 9.44,Max Gas Ou.;Drill 12 1/4"Hole F/456'-T/969'.423'total(71.5' AROP) 486 gpm/1230 psi.40 rpm/4k tq,8-12k wob 78k up,76k dn,80k rot. ECD 9.9,Max Gas 5u.;Release Gyro©459'.;Drill 12 1/4"Hole F/969'-T/ 1517'.548'total(91.3'AROP) 552 gpm/1600 psi.60 rpm/4k tq,5-12k wob 85k up,78k dn,79k rot. ECD 9.7,Max Gas 7u.MW/vis 9.1/185.;Drill 12 1/4" Hole F/1517'-T/2210'.693'total(115.5'AROP) 550 gpm/1700 psi.80 rpm/6k tq,6-13k wob 93k up,78k dn,82k rot. ECD 9.9,Max Gas 342u.M /vis 9.1/166.;Pump 40 bbl hi vis sweep @ 1644',back on time w/100%increase @ shakers,mostly clay and sand. Pump 30 bbl hi vis sweep @ 2115',bac on time w/25%increase,clay and fine sand.;Currently 4.63'above the line and 5.87'right 5.62 slide hrs,5.61 rotate hrs.;Hauled 798 bbls cuttings to G&I for total=823 bbls Hauled 910 bbls from 6 mi lake for total=1430 bbls 0 bbl daily losses to formation for total=0 bbls 2/19/2018 Drill 12 1/4"Hole F/2180'-T/2715.535'total(89'AROP) 475 gpm/1380 psi.80 rpm/6.7k tq,5k wob,105k up,81k dn,93k rot. ECD 9.8,Max Gas 342u. MW/vis 9.2/160.;Pump Hi Vis Sweep @ 2652'with 50%increase of cuttings back.;DriII 12 1/4"Hole F/2715-T/3220'.505'total(84.2'AROP) 500 gpm /1618 psi.80 rpm/8k tq,8k wob, 175k up, 111k dn,83k rot. ECD 9.8,Max Gas 342u.MW/vis 9.2/160.;Send Sweep @ 3158',back 16 bbls late,50% increase,sand,silt,clay,some small pea sized coal.;Drill 12 1/4"Hole F/3220'-T/3910'.690'total(115'AROP)550 gpm/1830 psi.80 rpm/8-10k tq,4-10k wob,132k up,90k dn, 103k rot. ECD 9.87,Max Gas 210u.MW/vis 9.2/120.;Drill 12 1/4"Hole F/3910'-T/4227'.317'total(105.6'AROP)600 gpm/2125 psi.80 rpm/9k tq,5k wob,133k up,90k dn, 104k rot. ECD 10.14,Max Gas 183u.MW/vis 9.2/120.;Pump cleanup cycle,pump 30 bbl hi vis sweep,600 gpm,2100 psi,80 rpm,8.5k tq, reciprocate pipe,2 BU, 100%increase©1st BU,sweep back 1000 stks early.ECD reduced f/10.1 -9.9,max gas 142u.;Drill 12 1/4"Hole F/4227'-T/4415.188'total(125.3'AROP)at 4275'start build and turn 5 deg/100'600 gpm/2125 psi.80 rpm/9k tq,5-10k wob,133k up,90k dn,104k rot. MW/vis 9.2/120.;Currently 11.29'above the line,2.02'right 1.96 slide hrs,8.99 rotate hrs.;Hauled 1254 bbls cuttings to G&I for total=2077 bbls Hauled 1310 bbls from 6 mi lake for total=2740 bbls 0 bbl daily losses to formation for total=0 bbls • S 2/20/2018 Drill 12 1/4"Hole F/4415'-T/4795'.(380')(63.3 AROP) 600 gpm/2150 psi.80 rpm/10.3k tq,6k wob,145k up,91k dn,114k rot. ECD 9.8,Max Gas 109u. MW/vis 9.2/110.;Pumped High Vis/High Wt sweep @ 4795'.Circulate Sweep OOH.Observed 40%increase of cutting @ shaker.;Drill 12 1/4"Hole F/4795'- T/5297'.(502')(100'AROP)500 gpm/1830 psi.80 rpm/13.4k tq,8-15k wob, 158k up,91k dn,120k rot. ECD 9.8,Max Gas 109u.MW/vis 9.2/110.;.tarted drilling ESP Pump Tangent @ 4975'.;Drill 12 1/4"Hole F/5297'-T/5549'.(252')(72'AROP)600 gpm/2180 psi.80 rpm/15k tq,5-10k wob,165k up, •1k dn, 117k rot.ECD 9.8,Max Gas 83u.MW/vis 9.2/90.;Drilled in rotation for pump tangent to 5359'(pump tangent=4975'to 5359')then resumed the 5°per 100' build and turn.Obtained 189'pump tangent<1.5 deg from 5006'-5195'.;At 5549'connection,survey showed 8.53°dogleg.Racked stand back,pumped tandem sweep around while rotating/reciprocating and reaming dogleg.Had 25%increase in cuttings to surface consisting of;clay balls and some coal. •.urvey after reaming and sweeping showed 7.62°dogleg.;Drill 12 1/4"Hole F/5549'-T/5672'.(123')(123'AROP) 600 gpm/2440 psi.80 rpm/14k tq, 10-15k ob, 158k up,91k dn,120k rot.ECD 9.9,Max Gas 83u.MW/vis 9.2/89.;Drill 12 1/4"Hole F/5672'-T/6051'.(379')(84'AROP) 604 gpm/2370 psi.80 rpm 13.4k tq,10-15k wob, 163k up,87k dn,113k rot.ECD 10,Max Gas 220u.MW/vis 9.2/89.;At 5736'Geo informed us that formations were coming in 10'high ertical depth.Landing target was revised to 6447'md,4067'tvd.Survey at 6051'shows dogleg of 8.49°.;Racked stand back,pumped tandem sweep and rotated/reciprocated reaming dogleg.604 gpm-2030 psi,80 rpm-14,000 ft/lbs off bott torque.Dogleg reduced to 6.34°.;Drill 12 1/4"Hole F/6051'-T/614.'.(94') 604 gpm/2475 psi.80 rpm/14k tq,5-15k wob,163k up,87k dn, 113k rot. ECD 10,Max Gas 135u.MW/vis 9.2/89.;Last survey at 6010'has us 8.69' igh and 28.10'right of the line.;Hauled 1055 bbls cuttings and fluid to G&I for total=3132 bbls Hauled 1020 bbls from 6 mi lake for total=3760 bbls 0 bbl daily losses to formation for total=0 bbls 2/21/2018 Drill 12 1/4"Hole F/6154'-T/6460'.(Section TD)600 gpm/2440 psi.80 rpm/15.4k tq, 16k wob, 163k up,85k dn,116k rot.ECD 10.0,Max Gas 366u. MW/vis 9.3+/80.TD'd at 84.74°Inc, 143.97°Az.;Set back 2 stands,pump tandem sweep and circulate condition mud 600 gpm,2200 psi,62%flow,81 rpm, 13.8k tq. Sweep brought back 30%increase in cuttings. Run back to bottom and Re survey.;Service wash pipe,blocks and crown.;BROOH from 6460'to 4544'Pulling 30-40 fpm,600 gpm/1964,80 rpm/12k Tq.;Utilizing surveys from each dataset after backreaming through the pump tangent,we are recor.ing 314'(from 5069'to 5383')of 1*or less dogleg.;BROOH from 4544'to 4034'pulling 30-40 ft/min,600 gpm-2000 psi,80 rpm-11,000 ft/lbs torque,up wt 14K. Washpipe appears to be leaking.;At 4034'CBU one time.600 gpm-1860 psi,80 rpm-11,400 ft/lbs torque,rotated and reciprocated.;C/O washpipe asse bly. Broke circ and ensured no leaks.;BROOH from 4034'to 2529'pulling 40-50 ft/min,600 gpm-1870 psi,80 rpm-10,400 ft/lbs torque,up wt 103K.;At 252• stopped as planned and CBU one time,prior to pulling through base of permafrost at 2238'.600 gpm-1628 psi,80 rpm-7000 ft/lbs torque.BGG 167 unit.. Good amount of clay at shakers.;BROOH from 2529'to 933'pulling 40-50 ft/min,then slowed to 30 ft/min due to increase in cuttings at shakers,to 707'.600 gpm-1500 psi,80 rpm-8,400 ft/lbs torque,up wt 90K,BGG 18 units.;Blew down topdrive and cont to POOH racking back HWDP and jars,from 707'to 150'.;LD NMDC's and UBHO sub. Plugged in to HCIM collar and downloaded MWD data.LD TM-HOC, HCIM,PWD, EWR-P4, DGR and DM collars.F ushed and LD motor.Bit graded at 1-3-CT-T-E-1-WT-TD. K Revs=371.5.;Removed elevators,hung bail extensions,staged Weatherford tongs on rig floor and RU same,Installed Valant tool on topdrive.Verified bypass baffle is in place.;At 6421'md/4968'tvd(TD)we are 9.66'high and 23.52'right of the line.;Haule.969 bbls cuttings and fluid to G&I for total=4101 bbls Hauled 1170 bbls from 6 mi lake for total=4930 bbls 0 bbl daily losses to formation for total=0 bbls 2/22/2018 Held PJSM with Weatherford casing crew and rig team on.PU RIH with 9.625"casing.;PJSM,Run DWC/C 9-5/8:,40#, L-80 casing as per detail. M/U -hoe track w/Bakerlok. Check floats(good). Circulate thru shoe track(good).;Run casing from 120'to 2500'filling pipe every 5 jts and breaking circulation b.ck to pits every 15 jts. No Issues running to 2500'.;CBU @ 2500'.(-300'below base of Permafrost)Staging pump up to 7 bpm.;Run casing from 2500'to 5310' filling pipe every 5 jts and breaking circulation back to pits every 15 jts.No Issues running to 5310'(end of pump tangent section)up wt 252K,dwn wt 105K.;Saw some occasional losses while RIH,but nothing while circulating back to pits.;CBU staging pump rate from 3 bpm to 7 bpm-175 psi and reciprocating pipe.While circulating,up wt 230K,dwn wt 110K.BGG 34 unit at bottoms up,little to no cuttings on shakers,no losses while circ.;Run c- ing from 5310'to 6413',filling pipe every 5 jts and breaking circulation back to pits every 15 jts at+/-40 ft/min. Halliburton cementers on location at midnig t and spotting equipment/RU.;MU last jnt(#157)and washed down with no problem to 6450'.Staged pump rate up to 7 bpm-230 psi. Down wt 110K.;Cont to irc at 7 bpm-230 psi,reciprocated pipe 257K up,110K down,and have full returns.Initial MW 9.5/vis 64,BGG 4 units.RD Weatherford casing tongs,bail ext•nsions and elevators.;Prepped to RU cement hose on rig floor.Shut down at bottoms up,MU cement hose.Cont circ 7 bpm-429 psi for a total of surface to su :ce. YP at 17,MW at 9.4 ppg.;Held PJSM with rig team and Halliburton cementers.Transferred water to cement unit,flooded lines to rig floor and pressure t•sted at 1000 and 4000 psi,good tests. Lined up on Halliburton;and pumped 60 bbls Tuned Spacer III with 4#red dye in first 10 bbls pumped,at 4 bpm-334 psi.;Hauled 467.8 bbls cuttings and fluid to G&I for total=4568.8 bbls Hauled 530 bbls from 6 mi lake for total=5460 bbls 0 bbl daily losses to formation for total=0 bbls 2/23/2018 Continue t/pump 1st stage Cmt Job: Pump 60 bbls 10.5#Tuned Spacer III w/4#red dye first 10 bbls. Drop bypass plug.;Mix and pump 485 sxs(219 bbls) Extends Cern Lead Cement at 11.7 ppg. Mix and pump 398 sxs(82 bbls)Hal CemTail Cement at 15.8 ppg.Drop Shut off Plug.;Displace cmt w/20 bbls RN f/Cmt Unit. Rig Pump 229 bbls,9.3 ppg mud. Cmt Unit 80 bbls RN @ 4 bpm,465 FCP. Rig 150.7 bbls 9.3 ppg mud,6 bpm/1010 psi,FCP 785 psi @ 3 lrn bpm last 20 bbls.;Using rig pump,stage pressure up 2900tpsi to open ES Cementer. CBU x 2 through Stage tool staging up to 6 bpm,bringing all spacer and 57 bbls green CMT to surface.;1 st Stage Details: Total Displacement 479.7 bbls CIP @ 09:00 hrs. Full Returns through out job Pump Cement @ 5.5 BPM avg. FCP 1010 psi @ 3 BPM.Bump plug 500 psi over FCP to 1300 psi,Floats Held.;Bring all of spacer and 57 bbls green CMT to surface. Phase 1 Conditions.;WOC Prep for 2nd stage.Shut down pumping. Disconnect knife valve. Flush stack and work annular with"Black Water". Circulate"Black Water" through flow line jets and all surface Iines.;Continue to circulate through stage tool @ 3 bpm/100 psi while prepping for 2nd stage Cement.CIP was @ 09:00.;PJSM, Pump 2nd stage cmt job.,Lineup to cmtrs,wet lines w/5 bbls FW.60 bbls 10.5#Tuned Spacer III w/4#red dye first 10 bbls,4 BPM,250 ,-„/1 psi.;Mix and pump 324 sxs(250 bbls)(4.33 yld)Perm"L" Lead Cement at 11.1 ppg. Mix and pump 268 sxs(82 bbls)(1.169 yld)Premium"G"Tail Cement at 15.8 ppg.Drop closing plug.;Displace cmt w/20 bbls RN f/Cmt Unit. Rig 169.3 bbls(170.5 calculated)9.3 ppg mud,6 bpm/790 psi,FCP 620 psi @ 3 bpm last 20 bbls.Bumped and psi up to 1800 psi(ES shift @ 1490 psi)Held 5 min.;Bled back 1 bbls,flow stopped. Full Returns through out job Pump Cement @ 6 BPM avg. See Trace/Contaminated Cmt @ surface 10 bbls into Tail.See Green Cmt 10 bbls into Displacement.;Bring 180 bbls green cmt to surface.CIP @ 18:40.Phase 2 Conditions.;Flush cement lines and stack with black water. Blowdown cement service line to unit.R/D Weatherford casing CRT. RD cement lines and clear same.LD CRT to cradle.RU sidedoor elevators.;Blow down TDS.LD remaining Weatherford equipment and release casing crew.Fill and drain stack with black water while functioned annular.;RD outer sub diverter sections. RD diverter tube from knife valve.4 bolt bottom of diverter"T".Clean out cellar box.Vac out casing joint(landing joint).RU stack trolly's.;Wellhead Reps BO 6 set screws from starting head.Raised BOP stack off conductor, PU to 106K on jnt.Wellhead Reps installed slips,centered joint in wellhead,SO setting casing with 70K on slips.;Made rough cut on casing and LD same.Cut off jnt= 30.57'.;Re-set stack on conductor,MU stack wash tool on TDS.Flush stack and wellhead with blackwater.RD wash tool and blow down TDS.Remove stack from"T".Pick"T"and remove from cellar.;Pick DSA/starting head and remove from cellar.;Welder made final cut on 9 5/8"stump and dressed same.Installed and NU 11"x 13 5/8"5M multibowl casing spools.;Hauled 1621 bbls cuttings and fluid to G&I for total=6189.8 bbls Hauled 530 bbls from 6 mi lake for total=5990 bbls 0 bbl daily losses to formation for total=0 bbls • • 2/24/2018 Finish installing Slip Loc Wellhead. Run in and Tq Set Pins.Energize seals.Test to 80%Collapse @ 2470 psi.Test Good.;N/U BOP stack and flange up to DSA,install kill and choke lines,turn buckles,riser,drip pan and hole fill line.Set Mouse Hole.;R/U test equipment with 5"test jt.;Test BOP on 5"Test Joint to 250/3000 psi.Test Gas and PVT system.Test Accumulator:Start 3000 psi,after close 1550 psi,Build 200 psi 25 sec,Full recovery 88 sec.6 N2 bottles @ 2310 psi ave.;Break Down Test Jt.Blown down Test equipment.SET 10"ID WEAR BUSHING.;Milne point in PHASE III conditions.Suspend all operations Field Wide and WOW.Send all non essential personnel to Main Camp via Convoy.;Milne point in PHASE III conditions field wide.Cont wait on weather;Milne point in PHASE III conditions field wide.Cont wait on weather.;Hauled 0 bbls cuttings and fluid to G&I for total=6189.8 bbls Hauled 0 bbls from 6 mi lake for total=5990 bbls 0 bbl daily losses to formation for total=0 bbls 2/25/2018 Milne point still in PHASE III conditions.All operations field wide have been suspended while WOW.;Milne point still in PHASE Ill conditions.All operations field wide have been suspended while WOW and road clearing.;Hauled 0 bbls cuttings and fluid to G&I for total=6189.8 bbls Hauled 0 bbls from 6 mi lake for total=5990 bbls 0 bbl daily losses to formation for total=0 bbls 2/26/2018 Milne Point off weather hold @ 0:600.Crews dug out vehicles from camp Bull Rail and arrived rig @ 07:00 hrs.Dug out and cleared walkways ect around rig area.;Serviced Rig.RU Hawk Jaw. Prep to PU C/O BHA.;MU Used 8.5 Baker VM-3 Mill tooth Bit and 1.5 bend Mtr.TIH picking up NC-50 drill pipe to 267' Make up Top Drive.;Wash down,take Wt @ 2499'.Drill Cmt,plug and Escmtr 2499'to 2526'400/gpm/610 psi,30 rpm/6K Tq,UpWt 100K,Dn Wt 72K Rot 83K,WOB 3-4K. Pass through w/no rotary/pump w/no issues.;Continue to RIH PU Drill Pipe from 2526'to 6236'.(Total of 182 jts).;Circulate surface to-urface w 9.0 in/out.600 gpm/1530 psi,15 rpm/16-18 Tq, Up Wt 192,Dn Wt 77K, Rt 115K.UD Hawk Jaw,Clear floor,blow down Top Drive.;RU and Test ca-ing to 2500 psi.Chart for 30 minute.Test good.R/D Test equipment.(7 bbls to reach Start pressure 2650 psi)(Bled Back 4.1 bbls)(Final Pressure charted for'0 min 2570).;Cleared exterior radiator/heat exchangers and poorboy vent pipe of snow.Blew down test equipment and RD same.;SO and tagged solid cement°t 6308'w/5K.Proceeded to drill hard cement from 6308'to 6320',then drilled up shut off plug,bypass plug and baffle adaptor.Cont drilling remaining sho-track and;float equipment to 6450'. Drilled 10'of cement in rathole to 6460'.Wob 4-5K,450 gpm-1000 psi,20 rpm-17,700 ft/lbs torque,using 9.0 ppg spud mud.;Cont drilling 20'new formation from 6460'to 6480',wob 6-8K,594 gpm-1151 psi,40 rpm-17,500 ft/lbs on bott torque, 16 ft/hr ROP,MW 9.0 ppg/ is 52, BGG 4 units.;At 6480'displaced well to new BaraDrill-N mud,8.9 ppg/vis 52,rotated and reciprocated,595 gpm-1000 psi,40 rpm-16,350 ft/lbs off bott orque, 6 up wt 136K,dwn wt 107K,rot wt 116K.;Shut down with good mud to surface.Racked back 1 stand. RU head pin and circ hose. Flushed choke and kill ines. Pumped down DP and kill line to clear air.Closed upper pipe rams.Using rig pump,;slowly pumped and pressured up on formation at 670 psi to achiev-a 12.0 EMWPu w/8.9 ppg mud).psi 656ped 2.3 bbls as per strokes.Pressure dropped from 670 to 580 over 5 minutes.Bled back.5 bbls;Bled off,blew do n and ( Pumped RD test equipment. MU to drive and obtained SPR's with new mud in hole.Flow check=static.;POOH from 6402'to 460'with cleanout BHA.;Hauled 2'8.7 R p bbls cuttings and fluid to G&I for total=6418.5 bbls Hauled 800 bbls from 6 mi lake for total=6790 bbls 0 bbl daily losses to formation for total=0 bbls 2/27/2018 Cont to POOH with BHA#2,from 460' to HWDP,Stand back two stands with jars. UD remaining joints&BHA. Bit Grade.;Clean and clear rig floor.;M/U BHA#3,8.5 Geo Pilot,Assembly T/86'. Up Load MWD, Attemp shallow test @ 315'.Failed. RIH to 1200'.Trouble shoot shallow test.Good. 450 GPM Break in seals.;RIH F/1200'T/6427'.Fill pipe every 2000'.;Circ btm up. Slip&Cut drilling line.;Service rig.Change proximity switch on handler.;Drill ahead stage up pumps&wash to btm F/6427 T/6480'. Drill ahead T/6545'. 450 GPM,1070 PSI, 60 RPM @ 14k TQ 3-7 WOB, 150-175 ROP. UP/DN/ROT 175K/79K/112K.;Drill 8.5"production hole Fl 6545'-T/7117'MD.572'@ 95 fph AROP 380 GPM,910 PSI, 120 RPM @ 15.8k TQ 7 WOB,9.9 ECD,51% flow,400 BGG.;Drill 8.5"production hole F/7117'-T/7566'MD.449'@ 75 fph AROP 400 GPM,1160 PSI, 120 RPM @ 16.8k TQ 7 WOB,10.1 ECD,51% flow,300 BGG 192k up,67k dn,108k rot.;Last svy @ 7463'MD,88.7°Inc, 148°Az=12.6 low,2.3'right of plan.14 concretions for 110'length(10%of lateral) have been drilled.;Hauled 1028 bbls cuttings and fluid to G&I for total=7446 bbls Hauled 130 bbls from 6 mi lake for total=6920 bbls 0 bbl daily losses to formation for total=0 bbls 2/28/2018 Drill 8.5"production hole F/7566' T/8006'M .440'@ 73 fph AROP 400 GPM, 1150 PSI, 120 RPM @ 18k TQ 8-18WOB,10.1 ECD,51%flow,300 BGG 192k up,62k dn, 108k rot.;Drilling 15%total concretions. Sweeps coming back on time. Drilled out of OA3 @ 7865'&in to OA1 @ 7976'.;Drill 8.5"production hole F/8006'T!8238'MD.232'@ 38'fph AROP 400-450 GPM,1450 PSI, 120 RPM @ 18k TQ 8-18WOB,10.1 ECD,51%flow,300 BGG 196k up,48k dn, 104k rot.;Pumped walnut low vis sweep 8125'.Came back on time.No increase in ROP or cuttings. Slow drilling lots of concretions. 16.5%Con creations for a total of 38 and 302'.;Drill 8.5"production hole F/8238'T/8560'MD.322'@ 54 fph AROP 450 GPM, 1530 PSI, 120 RPM @ 19.2k TQ 8-18 WOB 10.1 ECD,51%flow,300 BGG 206k up,48k dn, 106k rot.;Drill 8.5"production hole F/8560'T/9060'MD.500'@ 84 fph AROP 450 GPM,1360 PSI, 120 RPM @ 19.7k TQ 8-18 WOB 10.1 ECD,54%flow,500 BGG 213k up,35k dn,107k rot.;Pumped tandem sweep @ 8501'MD. On time w/no inc in cuttings.;Last svy @ 8847'MD,89.8°Inc, 152.8°Az=8.5 low,3'left of plan.55 concretions for 452'length(18.2%of lateral)have been drilled.;"Hauled 749 bbls cuttings and fluid to G&I for total=8195 bbls Hauled 940 bbls from 6 mi lake for total=7860 bbls 0 bbl daily losses to formation for total=0 bbls 5lbs metal/51bs total 3/1/2018 Drill ahead 8.5 Hole F/9060'T/9570'. 510'@ 85 FPH average. 450 GPM, 1150 PSi 120 RPM,22k TQ. Pumped sweep @ 9000'with 80%increase.On time.;Drilled out of the OA 1 and in to the OA 3 @ 9220'. Targeting up dip of 90.5 deg.;Drill ahead 8.5 Hole F/9570'T/ 10206'. 636'@ 106 FPH average. 450 GPM, 1150 Psi 120 RPM,22k TQ.;Drill ahead 8.5 Hole F/10206'T/ 10555'. 349 @ 58 FPH average. 450 GPM, 1370 PSi,54%flow 120 RPM,23.5k TQ,10.1 ECD's,350 avg BGG.;Drill ahead 8.5 Hole F/10555'T/ 11019'. 464 @ 77 FPH average. 450 GPM,1350 PSi,54%flow 120 RPM,23.5k TO,10.6 ECD's,350 avg BGG.;Pumped tandem sweep @ 10080'MD, 50 bbl late w/no 50%inc in cuttings.The highest gas in the past 24hrs was 2,680 units from OA-3 Sand.;Last svy @ 10734'MD,93.2°Inc,149°Az=18 high,5.4'left of plan. 73 concretions for 583'length(13%of lateral)have been drilled.;Hauled 977 bbls cuttings and fluid to G&I for total=9172 bbls Hauled 940 bbls from 6 mi lake for total=8800 bbls 0 bbl daily losses to formation for total=0 bbls l lbs metal I 6Ibs total 3/2/2018 Drill ahead 8.5 Hole T/ 11019'T!11530',511'@ 85 FPH average. 450 GPM,1450 PSi,54%flow 120 RPM,23.5k TQ,10.6 ECD's,350 avg BGG UP/ROT 237K/106K MW 9.1 ECDs 10.7.;Pumped tandem sweep @ 11334',Back on time with 100%increase.;Drill ahead 8.5 Hole To TD @ T/11530' 12380' ,850'@ 113 FPH average. 450 GPM, 1450 PSi,54%flow 120 RPM,23.5k TQ,11 ECD's,450 avg BGG UP/ROT 242K/101 K MW 9.1.;Circ 3x BU • @ TD 12380'MD,4048'TVD. Rot and Recip pipe. 453 gpm, 1300 psi,52%flow,100 rpm,23.6k tq,11 ECD's w/9.1 MW.242k up,101k rot prior to cleanup cycle. 10.6 ECD post cleanup cycle.;Monitor well 30 min(static). Backream out of hole F/12,380'-T/12150'MD. 400 gpm,1250 psi,51%flow,100 rpm, 24.8k tq. Screen up as shakers allow.;Continue backream out of hole F/12,150'-T/9950'MD. 400 gpm,1130 psi,51%flow, 100 rpm,21.6k tq.;Pumped tandem sweep @ 12380'MD, On time with minimal inc in cuttings.The highest gas in the past 24hrs was 2,287 units.;Last svy @ 12347'MD,89°Inc,149.4° Az=18 high,3.6'left of plan.80 concretions were drilled in lateral for a total length of 611'-10%of the lateral.;Hauled 571 bbls cuttings and fluid to G&I for total =9743 bbls Hauled 660 bbls H2O from 6 mi lake for total=9460 bbls Hauled 0 bbls H2O from L pad lake for total=130 bbls • i Hilcorp Energy Company Composite Report Well Name: MP F-109 Field: Milne Point County/State: Milne Point,Alaska (LAT/LONG): 9vation(RKB): 26.5 API#: 50-029-23596-00-00 Spud Date: 2/18/2018 Job Name: 1714020C MPF-109 Completion Contractor AFE#: AFE$: ,414 r Date OpS 5lttli rY t...,....,✓ 3/3/2018 Back ream out F/9950'T/6450'. 400 GPM, 100 RPM. Monitor well, Slight breathing. Static after 10 min.,Pump tandem sweep around with no increase in cuttings. Monitor well,Slight breathing. Static in 5 min.,Pull stands with no losses.Pull 5 more and loose one bbl.Monitor well,Static.Pump 25 bbl Dry job.,B/1 TDS. Line up on TT. POOH F/5672'to BHA. Hole took proper displacement for trip.,Monitor well(static). PJSM,B/O and L/D flex DC's. Download MWD, D remaining BHA components. B/O and L/D bit sleeve and bit. Bit grade-1,2,CT,T,X,I,JD,TD(see pics in"O"drive).,PJSM,M/U 8.5"VM-3,Near bit st-b(non ported float),lx HWDP,stab,3x HWDP,Jars,2x HWDP(total length=227.38'),TIH F/227'-TI 3805'MD. Isolate and screen up(200's)shaker#2. C rc surface volume across shaker throughout evening to reduce solids in mud. Maintain 9.1 MW w/salt and 10 ppb baracarb 5,Hauled 346 bbls cuttings an.fluid to G&I for total=10088 bbls Hauled 520 bbls H2O from 6 mi lake for total=9980 bbls Hauled 0 bbls H2O from L pad lake for total=130 bbls 3/4/2018 RIH F/3805'T/4996'.,Adjust Catheads and service rig.Adjust board saver.,RIH F/4996'T/6450'.Shoe.Monitor well.Good. RIH on elevators F/6450'TI 8460'.Set down.Out of wt.,Wash and ream F/8460' T/11760'@ 20 RPM,200 GPM, with TQ continuing to climb to 20K.Set down and stall out. B p up TQ to 25K 30 RPMs.Continue to wash and ream T/12200'.Set down and stall out. Increase to 400 GPM 40 RPM.23K TQ.Wash down to TD with n• problem. 12380'. Hole took proper displacement for the trip in. Wash and ream to btm with both centrifuges on and 170s on one shaker and 200s on another.,Circulate and condition mud while rot/recip pipe. 40 rpm,22.1k tq,400 gpm,980 psi,51%flow. Screen up to 4x 200's on#2 and 2x 200's,2x 270's on#1 shaker. Circulate 2.5 total volumes.Perform PST(failed)on active. Plugged off @ 4 secs into 1st test.,Screen up as shaker allow on shaker#1 f•m 200's to 270's. Continue to condition mud,400 gpm,970 psi,51%flow,40 rpm,22.6k tq,95 bgg.Perform PST @ 3 total active volumes(Failed @ 8. secs). Continue conditioning mud.,Hauled 343 bbls cuttings and fluid to G&I for total=10432 bbls Hauled 390 bbls H2O from 6 mi lake for total=10370 bbls Hauled 0 bbls H2O from L pad lake for total=130 bbls 3/5/2018 After PST failed. Consult town and decide to perform pilot test before proceeding.Circ and Condition while diluting mud system with water and Maintaining MW with salt @ 200 GPM 20 RPM. Get passing pilot test on Baradril N with 10 PPB Baracarb 5 and 4%lubes.Start cleaning pits. Send hot water to ud plant to build mud as per plan.,Continue circulate and condition mud @ TD(12,380'MD). 200 gpm,375 psi,20 rpm,20-23k tq,375 BGG. Offload exc ss mud from pits.Clean pits in preparation for upcoming displacement. C/O all swabs and liners in#2 MP. Clean and perform maintenance on rig.,Haul 806 bbls cuttings and fluid to G&l for total=11238 bbls Hauled 520 bbls H2O from 6 mi lake for total=10890 bbls Hauled 0 bbls H2O from L pad lake for total=130 bbls Total metal collected for well=12 lbs 0 losses to formation 3/6/2018 Circ&condition @ 200 gpm,20 RPM, 23-25K TQ while waiting on New Baradril N Type 3 mud to be built and on location.Continue to circulate.4th load of mud leaving the baroid plant at 12:30.up/dn/rot 274/120/109.Back ground gas @ 320.,PJSM,Start displacement with 50 bbl high vis sweep&9.2 PPG Baradril N Type 3, 10 PPB barabarb 5&4%Lubes.(1%EZ glide&3%barolube Gold seal)@ 200 GPM off loading from trucks strait to mud pumps. New mud back and over displace by over 100 bbl.,Mud coming back and after shakers still failing PST test. Continue to circ staging up pumps to 300 gpm taking PST test every btm up.Test after first btm up from displacement was 400mils past through in 4.87 sec then plugged.Almost doubled from the first test. Clean used screens for testing. Consult Completion engineer and decide to continue circ as per plan.,Continue to circulate 300 gpm 440 psi,reciprocate pipe,rotate 20 rpm,14.9-15.1k TQ. Perform PST test every bottoms up from mud returning after shakers,test after 2nd BU from displacement was 250 mils past thru in 4.84 sec then plugged.Test after 3rd BU was 100 mils past thru in 2.35 sec then plugged.Lower pump rate to 200 gpm,370 psi,add water @ 30 bph,start both centrifuges. PU/SO/ROT 170/74/108.,Continue circulating 200 gpm 340 psi,reciprocate and rotate taking PST tests every BU,test after 4th BU was 100 mils past thru in 2.74 sec then plugged.Test after 5th BU was 100 mils past thru in 2.25 sec then plugged.(Sample from centrifuge discharge 1000 mils past thru in 9.18 sec)Test after 6th BU was 100 mils past thru in 1.94 sec then plugged.Maintain 9.2 ppg MW w/oilfield salt,vis 42.,Hauled 1447 bbls cuttings and fluid to G&I for total=12685 bbls Hauled 130 bbls H2O from 6 mi lake for total=11020 bbls Hauled 130 bbls H2O from L pad lake for total=260 bbls Total metal collected for well=12 lbs 0 losses to formation S • 3/7/2018 Continue to circ &condition @ 200 GPM 20 RPM PST test still not getting better from flow line and under shakers.Getting silt like solids over the shakers. Take PST from discharge from centrifuge and test passed. Increase to 25 PSI for the PST from under the shakers and we were able to pass one leter through @ 10 SEC. Second one failed in less that one sec.,Consult Hilcorp Production and drilling team and decide to treat mud system back to 4%Lubes and take samples from flow line,Under shakers,Centrifuge discharge and return,and solids over shakers.Prep Samples to get sent to town for further evaluation, Before adding final lubes,20 RPM,15.6K TO. After Adding lubes 20 RPM,13.9 TQ. UP/DN/ROT 168/72/113.,Monitor well,Slight breathing.Flow stopped in 10 min. POOH on elevators F/12380'T/8554'. Over Pull 30 K over 8554'T/8545'. Wiped back through clean. POOH on elevators F.8545 TI 7272 Over pull 20K 7272'-7267'.POOH F/7267'To shoe @ 6450'.Clean. Proper Hole fill for the trip.,M/U top drive,circulate bottoms up pumping 525 gpm,640 psi, rotate 60 rpm,6.2k TQ,reciprocate 60',CBU until clean @ shakers,BU gas 355u,PU/SO/ROT 138/99/109.,Displace f/6450'@ shoe w/9.2 ppg 3%KCL brine f/vac truck pumping 250 gpm,300 psi,reciprocate and rotate 20 rpm 5.4k TQ.Pump 50 bbl spacer followed w/620 bbls brine until clean @ returns, 176 bbls over calculated displacement.Flush choke and kill line,blow down same. BD TD,flowcheck well,static.,R/U hawk jaw. Drop 2.375"drift on wi•e, POOH on elevators ft 6450'to 5945'racking 8 stds 5"DP in derrick.,Rig service,grease top drive and blocks.,POOH L/D 48 jts 5"DS50 DP f/5945'to 4435', POOH LID 134 jts 5"NC50 DP.L/D cleanout BHA.Recover drift on wire. Correct displacement on trip out.,Hauled 585 bbls cuttings and fluid to G&I for total= 13271 bbls Hauled 520 bbls H2O from 6 mi lake for total=11540 bbls Hauled 0 bbls H2O from L pad lake for total=260 bbls Total metal collected for well=12 lbs 0 losses to formation 3/8/2018 Pull wear bushing,R/U BOP test equipment. Perform Body test.Good.,Test bops to 250/3000 psi as per AOGCC.Perform Bleed off test on super choke and Manual choke to 1500 psi.Good.Test rams and annular on 5"Test joint and test plug. Perform accumulator test. 3000 PSI Starting pressure 1500 PS after shut in 200 PSi increase-16 Sec Full Pressure 92 Sec Test PVT&Gas system.Good.,R/D testing equipment&clear floor. Set wear bushing. Blow down choke and kill Iines.,R/U to run 4.5"13.5#Hydril 625 Halliburton Petro Guard 100 Micron Screens. M/U 5"safety Joint for screens. Stage 150 7'OD Centralizers on the rig floor. R/U&test Weatherford Power tongs.,P/U Shoe track and check same.Good.P/U screens and TQ to 9600#Opt. Screens are being ran in brine and are self fill. RIH to 825'.,Continue P/U and RIH with 4 1/2"lower screen completion as per tally f/825 to 6069'w/123 screens and 23 solid jts.Install 1-7"OD centralizer butted to stop ring on pin end of every screen ran,123 total.Install 1-7"OD centralizer with stop ring on top free floating on ea solid jt ran,23 total Correct displacement on TIH.PU/SO 106/82.,Make up safety joint for inner string and screens. Rig up false rotary table,C/O power tong dies,C/O Elevators. Count remaining screen and solid body joints. Set max top drive torque to 9600 ft-Ibs.,PJSM,M/U slick stinger. P/U and RIH with 2-3/8" PH6 inner string to 3815'(136 jts ran).Correct displacement on TIH.,Hauled 114 bbls cuttings and fluid to G&I for total=13384 bbls Hauled 0 bbls H2O from 6 mi lake for total=11540 bbls Hauled 260 bbls H2O from L pad lake for total=520 bbls Total metal collected for well=12 lbs 0 losses to formation 3/9/2018 P/U and RIH with 2-3/8"PH6 inner string f/3815'to 6040'and tag out on packoff no-go on depth setting 5K down. Lay down 1 joint. 193 Joints,M/U 10' Space out pup. C/O pipe handling equipment. M/U swivel on running tool w/7"x 9 5/8"SL ZXP LTP/Flex lock liner hanger,44,100 lbs shear force,2 00 psi set. (slick stinger is 4.78 off of no go).,M/U XO to stump M/U Hydril 625 connection,verify 8 shear screws installed in hyd setting tool set @ 2650 psi.Mix and fill liner tie back sleeve w/XAN PLEX. UP/DN after P/U out of slips.130K/100K.,RIH on 5"DP from derrick. F/6109'T/6420'.Shoe. M/U top drive, Displace brine out of well with 9.2 ppg Mud, 1500 psi max to ensure clear flow path,w/top drive TQ set @ 9.8k,rotate 7 rpm record TQ,blow down top drive. Take parameters at 10 RPM,TQ 6.7. UP/DN/ROT 130/100/113K. Set max TO to 9.8K.,RIH Fl 6420'T/8688'. P/U 27 6 1/4 DC,T/9520'. UP/DN 188/113.,RIH on 5"DP from derrick drifting out of derrick F/9520'T/9705'. Hole taking correct displacement to this point. Fill pipe on the fly from fill up line. Top off every 5.,Continue to RIH w/lower completion conveyed on 5"DP f/9705'to 10841', P/U and RIH with 48 jts 5"HWDP to 12328'with no issues,fill on the fly and top off every 5 stds.M/U std of DP and Top drive,est.returns,wash down 1 bpm,320 psi,tag bttm on depth @ 12380'.Correct displacement on TIH.PU/SO 248/91.,Set pump trips to 1700 psi,stage pump to 4.5 bpm, 1700 psi,reciprocate pipe 15,at 5000 stks into CBU start loosing down wt,w/TQ set @ 9.8k able to rotate down 1-2 rpm moving string down,shut down pump, LID 2 singles,drift and P/U 5'-15'pup jts and 1 single to position tool jt just above rig floor when on bttm.Drift and P/U 10'pup jt.M/U TD.Well support R/U hardline f/annulus to tanks.,Continue to CBU pumping 4.5 bpm,1700 psi, reciprocate pipe 10',max gas @ BU 3910u with no flow increase,lost all down wt,work pipe 5'.,PJSM,Displace well 800 bbls 9.2 ppg brine pumping 3 bpm, 1700 psi,continue to reciprocate pipe 5',no down wt.Dump and monitor mud returns.BGG 870u.Pull mouse hole, Halliburton on location @ 05:30,spot equipment and start R/U same.,Hauled 568 bbls cuttings and fluid to G&I for total=13952 bbls Hauled 0 bbls H2O from 6 mi lake for total=11540 bbls Hauled 40 bbls H2O from L pad lake for total=560 bbls Total metal collected for well=12 lbs 0 losses to formation 3/10/2018 Continue to displace well 800 bbls 9.2 ppg brine pumping 3 bpm,1700 psi,continue to reciprocate pipe 5',no down wt.Dump and monitor mud returns Brine back&Return to pits.,Monitor well.Slight breathing.Slowed&stopped in 30 min. Flush surface lines with water. Circ on closed loop to pits @ 3 bpm while waiting on Halliburton to get rigged up. R/U Halliburton. Flood lines from annulus to tiger tanks and test with test pump to 3000 psi good.,PJSM with Hi corp safety and all personnel involved. Shut down pumps,R/U circ lines&side entry sub to string with TIW above and below. Fill and test lines to 500/5000 good. Stage emergency eye wash station by Acid unit&test same.,Circ with rig pump taking returns back to the pits while Halliburton fixes Low pressure line Ieak.,Line up to Halliburton acid unit, pump 250 bbl 12%HCL Acid,250 BBL 15%Mud acid,Chase to rig floor with 12 bbl of 9.2 brine. Line up to rig pump and displace with 9.2 3%KCL 180 bbl taking PH samples at wellhead. Swap returns from pits to Tiger tanks.Shut top rams&open annulus. Continue displacing with 280 bbl total when we got PH drop from 8.5 to 1.Swap tanks and start on tank 2. Continue displacing.,Continue to Displace acid w/9.2 brine pumping 3 bpm,1700 psi diverting all acid returns to tiger tanks.Monitor PH on returns from annulus sample port in cellar,strap and monitor volume on returns @ tiger tanks, 1383 bbls into displacement,513 bbls over calculated displacement w/1.65 ph @ returns.,Mix 30 bbl pills w/800 lbs soda ash and load 30 bbl pills onto vac trucks to neutralize acid offloaded f/tiger tanks to vac truck.,Continue to displace out acid w/9.2 brine pumping 3 bpm, 1700 psi.Continue to monitor PH @ returns.pump a total of 1842 bbls @ 2 full circulations w/final PH @ 1.4, Discuss options with town engineer,decision made to set LTP release and test packer,unsting and finish circulating until PH level is acceptable.Note:daylight savings.,PJSM for setting LTP,shut down pump,R/U and pump 10 bbls w/soda ash thru kill line and returns going to tiger tank to neutralize fluid below rams and line to tiger tank.Blow down line to tiger tank,open bag and close annulus valve. L/D pump in sub and TIW valves,blow down hardline.Drop 1 1/4"ball.M/U top drive.Open annulus valve.,Put string in tension, Close bag. Pump down ball as per baker at 3 bpm 1700 psi ft 60 bbls,slow to 1.5 bpm 450 psi,Ball on seat at 86.3 bbls.Pressure up to 2800 psi&set LT hanger,seen pusher tool start to shift.Continue to pressure up to 4300&neutralize pusher tool.Bleed off pressure,set down 50k,P/U to breakover @ 204k, note:30k wt loss. LIP set @ 6282'.,Hauled 1688 bbls cuttings and fluid to G&I for total=15640 bbls Hauled 0 bbls H2O from 6 mi lake for total=11540 bbls Hauled 0 bbls H2O from L pad lake for total=560 bbls Hauled to B-50 684 bbls for total=684 bbls 0 losses to formation • • 3/11/2018 Blow down lines to tiger tanks, UD 10'Pup,Blow down TD,R/U for LT test. Test annulus to 1500 psi for 30 min.R/D Same.,P/U on string 208K& out of pack off with 2 3/8 Slick stick T/I2292'.,Break circ @ 4.25 bpm 3500 psi&circ 450 bbl taking samples on annulus. PH stayed 1.5-2.5 until 450 bbl.Circ 610 bbl total with final PH at 4.5.Shut down&monitor well. Slight breathing for 1 hr.Slowing down to 0.,Blow down all surface equipment and lines to return tanks. R/D same. Prep for slip&cut.,Monitor well,Slip&cut drilling line.,Service rig,Perform PMs on the Crown,Blocks and Draw works.,POOH f/12279'to 10872' UD 48 jts HWDP,POOH racking 21 stds 5"DS50 DP in derrick to 9520'.,M/U safety jt,POOH f/9520'to 8688'UD 27 6 1/8"DCs, POOH f/8688'to 6109' racking 41 stds 5"DS50 DP in derrick.Loss rate 3.5 bph.,Monitor well,static loss rate @ 3.7 bph,R/U Weatherford power tongs.PJSM, Inspect and UD running tool as per BOT rep. R/U 2 3/8"handling equipment.Ready safety jt. UD 2 3/8"pup jt.M/U crossover on polish mill in mousehole and load out same for ASR rig.,POOH UD 193 jts 2 3/8"inner string f/6040'to surface,Rinse with water,dope pin and box. UD slick stick.Loss rate @ 3-3.5 bph TOOH 39 bbls over calculated displacement.,Hauled 1659 bbls cuttings and fluid to G&I for total=17299 bbls Hauled 0 bbls H2O from 6 mi lake for total=11540 bbls Hauled 560 bbls H2O from L pad lake for total=1120 bbls Hauled 580 bbls to B-50 for total=1264 bbls 22 bbl losses to formation for total=22 bbls 3/12/2018 CIO handling equipment for 5",R/U hawk jaw,M/U 3 1/2"EUE wash tool and XO on stand of 5"DP.,RIH on 5"DP T/6236'. Wash down T/6294'.12'in the top of the liner.Circ sweep out of the hole @ 10 RPM&450 GPM. Very fine silt back. Displace well to clean 3%KCL 9.2 PPG Brine. Monitor well for 20 min until breathing stopped.Good.,Circ sweep out of the hole @ 10 RPM&450 GPM. Very fine silt back. Displace well to clean 3%KCL 9.2 PPG Brine. Lost 5bb while circulating.Monitor well for 20 min until breathing stopped.Good.1260u max gas while circulating.,POOH UD 5"DP F/6294'T/surface,UD XO and wash tool.UD remaining 4 stds in derrick.20.2 bbls over calculated displacement on TOOH.,Pull wear bushing.Drain stack,close bind ram,remove VBR f/upper BOP,install 7 5/8"ram,open blind ram,R/U test equipment w/7 5/8"test jt,Test upper ram to 250/3000 psi 5 min ea.charted.R/D test equip.close I/A Monitor well,static loss rate 5 bph.,R/U to run 7 5/8"casing,Setup torque turn equipment.M/U crossover to FOSV.R/U and make hanger dummy run per well head rep, hanger landed out @ 25'RKB.,PJSM with all parties involved,review plan for well control.P/U and run 7 5/8"tie back per tally,P/U tie back seal assy,8.25"nogo locator,XO and pup, P/U and RIH w/7 5/8"Vam,STL,29.7#L-80 casing f/17'to 4476'.Torque turn connections to optimum @ 5349 ft/lbs.Utilize dog collar clamp on every jt.use BOL 2000 pipe dope.Monitor well w/trip tank,Loss rate @ 3.5 bph.,Hauled 699 bbls cuttings and fluid to G&I for total=17998 bbls Hauled 0 bbls H2O from 6 mi lake for total=11540 bbls Hauled 0 bbls H2O from L pad lake for total=1120 bbls Hauled 0 bbls to B-50 for total=1264 bbls 44 bbls losses to formation for total=66 bbls 3/13/2018 P/U and RIH w;7 5/8"Vam,STL,29.7#L-80 casing fI 4476'to 6289' Land on no go on joint#155.3.5'in. Torque turn connections to optimum @ 5349 ft/lbs.Utilize dog collar clamp on every jt.use BOL 2000 pipe dope.Monitor well w/trip tank,Loss rate @ 3.5 bph.,UD 3 Jts casing to 6202'.MU 16.68'space out pups.(4.88',11.80').PU Jt 153.MU Csg Hgr with pup and Landing Joint.Land out, XO landing jt to DP,MU Top Drive,Close bag and PT Annulus to 500 psi to ensure proper space out and seal engagement.Bleed pressure to 250 psi,strip up hole until pressure dumped,exposing seal ports to annulus.,Using the /c\ L `J Kill Line,Establish reverse circulation through ported seals with fluid from rig pits.Line up on and pump 93 bbls Corrosion inhibited 9.2 ppg KCL,chase surface J lines with 10 bbls Brine.Turn over to LRS and Reverse in 50 bbls DSL. Strip in hole and land out Tie back seals Assy 1.'off no go w/Mule Shoe @ 6285.87'. 'xi' (TOL @ 6282')PU/S0 164/112.,Open bag,drain stack,R/D Reversing equipment, Pull landing joint,Monitor well.MU,Land and test pack off to 500/3000 psi. 10 min ea.,LRS PT 9 5/8"x 7 5/8"Annulus to 1800 psi on chart for 30 min..R/D LRS.Monitor well for 30 minutes before changing UPR's. Well @ 3.5 bph loss rate,Close blind ram.Change UPR back to 2 7/8"x 5 1/2"VBR's.Open blind ram.,RU test equipment wl 2 7/8"test jt,test annular to 250 psi low aid 3000 psi hi 5 min ea,charted, attempt to test upper 2 7/8"x 5"VBR,failed,cycle ram and attempt to re-test.Pull and inspect test jt,good. Re-install test jt. Monitor well @ I/A with hole fill,3.5 bph static loss rate.,Test lower 2 7/8"x 5 1/2"VBR to 250 low and 3000 psi hi 5 min ea,charted.Open UPR doors and inspect seals on VBRs,damaged.Install new VBR rams with new seals.Test upper VBR to 250 low and 3000 psi hi 5 min ea,charted,good test.R/D test equipment,Close I/A.,Rig up to run ESP completion.R/U WOT equip.Hang Sheave for ESP cable.Thread ESP cable and 2-3/8"capillary lines thru sheave to rig floor.Load ESP tools and equipment to rig floor.M/U FOSV to XO.Static loss rate 3.5 bph.,PJSM with all parties involved,discuss well control plan with motor and pump across BOP,ESP cable contingency plan for shutting in well.M/U ESP pump assy as per centrilift.M/U seals and service same.P/U GS and Pumps.M/U MLE and cap string lines and test same. Pump through cap string good. Check valves set at 1700 psi.,M/U discharge head to 10'pup with Weatherford,P/U and RIH with 2 7/8 tbg installing clamps on each collar of every jt ran,Run 1 jt,M/U XN nipple w/2.205"nogo, RIH to 220'install 1 mid collar clamp on 1st 4 jts ran,M/U GLM w/DV,RIH T/1076'.Test cable @ 1000'and cap lines @ 2000'. TQ 2 7/8 EUE to 2240 ft/lbs.Static loss rate continues @ 3 bph.,Hauled 57 bbls cuttings and fluid to G&I for total=18055 bbls Hauled 0 bbls H2O from 6 mi lake for total=11540 bbls Hauled 0 bbls H2O from L pad lake for total=1120 bbls Hauled 0 bbls to B-50 for total=1264 bbls 75 bbls losses to formation for total=141 bbls 3/14/2018 RIH W/2 7/8 ESP completion as per tally f/1076'to 5258'(163 Jts)Test cable every 1000'and cap lines every 2000'.Start testing every 500'f/4000'to 5200'. TQ 2 7/8 EUE to 2240 ft/lbs.Static loss rate continues @ 3 bph.Note:take rig off high line and put on Gen power @ 08:00.,MU Tubing Hgr and landing joint. Centrilift splice ESP.Terminate control lines.Make test on cables.Test good.Drain stack.Land Hanger,RILDS,UD Landing Joint, install BPV.Bottom of pump @ 5284'.Up Wt 80K w/Blocks,Dn Wt 60K w/Blocks. Start Rigging Down and removing running equipment from Rig. 163 jts 2 7/8" 6.5#L-80 EUE tubing ran.,Clamp detais:4 motor clamps,4 seal clamps,19 pump clamps,174 cross collar clamps on every jt.Count includes 1 cross collar clamp installed mid jt on 1st 4 jts ran.,PJSM,N/D BOPE:Pull Bell Nipple,R/D Choke and Kill Hoses and flange together.R/U Bridge Cranes. Bleed Koomey, R/D Koomey Hoses.Pump hot flush thru kelly hose and blow down same.Hoist stack up and set back same.Flush and R/D choke/kill lines. t .. Welder install landing ring on F-110 conductor.,Centrilift make final test on ESP.Test good. Remove DSA.Orient and install tree.Torque flange bolts. \ Terminate capillary lines.Test hanger void as per wellhead rep to 500 psi low for 5 min,5000 psi high for 15 min,good.,Drain liner wash on both mud pumps, disassemble mud pump fluid ends to ensure dry for rig move and reassemble same.Vac out cellar box,vac out sumps,cleanup cellar area. Inspect saver sub and gripper dies. R/D tongs.Bridal up.Finish cleaning pits.Disconnect pit interconnects.Load DP in shed and Prep pipe shed for move.Blow down water lines.Scope derrick down.,Hauled 501 bbls cuttings and fluid to G&I for total=18535 bbls Hauled 0 bbls H2O from 6 mi lake for total=11540 bbls Hauled 0 bbls H2O from L pad lake for total=1120 bbls Hauled 0 bbls to B-50 for total=1264 bbls 54 bbls losses to formation for total=195 bbls • • Hilcorp Alaska, LLC Milne Point M Pt F Pad MPU F-109(OA Producer) 50-029-23596-00-00 Sperry Drilling 9 Definitive Survey Report 05 March, 2018 HALLIBURTON Sperry Drilling 11 • a Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU F-109 Project: Milne Point TVD Reference: MPU F-109 Actual RKB @ 37.65usft Site: M Pt F Pad MD Reference: MPU F-109 Actual RKB @ 37.65usft Well: MPU F-109 North Reference: True Wellbore: MPU F-109(OA Producer) Survey Calculation Method: Minimum Curvature Design: MPU F-109 Database: Sperry EDM-NORTH US+CANADA Project Milne Point,ACT,MILNE POINT Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 NADCONWell Reference Point ( CONUS) Using Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPU F-109 Well Position +N/-S 0.00 usft Northing: 6,034,863.78 usft Latitude: 70°30'22.227 N +El-W 0.00 usft Easting: 541,270.05 usft Longitude: 149°39'44.515 W Position Uncertainty 0.00 usft Wellhead Elevation: 10.70 usft Ground Level: 10.70 usft Wellbore` MPU F-109(OA Producer) Magnetics Model Name st,F Sample Date Declination Dip Angle Field Strength BGGM2017 2/15/2018 17.29 81.03 57,486 Design MPU F-109 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 26.95 Vertical Section: Depth From(TVD) +N/-S +EI-W Direction (usft) (usft) (usft) (°) 26.95 0.00 0.00 170.28 Survey Program Date 3/5/2018 From To (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 50.00 231.00 SRG-SS(MPU F-109(OA Producer)) 2_Gyro-SR-GSS H047Ga:Surface readout gyro single shot 02/14/2018 295.09 6,421.31 MWD+IFR2+MS+sag(1)(MPU F-109(OA 2_MWD+IFR2+MS+Sag A013Mb:IIFR dec&multi-station analysis+sag 02/14/2018 6,518.29 12,347.54 MWD+IFR2+MS+sag(2)(MPU F-109(OA 2_MWD+IFR2+MS+Sag A013Mb:IIFR dec&multi-station analysis+sag 02/28/2018 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +El-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 26.95 0.00 0.00 26.95 -10.70 0.00 0.00 6,034,863.78 541,270.05 0.00 0.00 UNDEFINED 50.00 0.07 310.01 50.00 12.35 0.01 -0.01 6,034,863.79 541,270.04 0.30 -0.01 2_Gyro-SR-GSS(1) 1'I 100.00 0.22 18.98 100.00 62.35 0.12 0.00 6,034,863.90 541,270.05 0.41 -0.12 2Gyro-SR-GSS(1) 168.00 0.40 3.40 168.00 130.35 0.48 0.05 6,034,864.26 541,270.10 0.29 -0.46 2_Gyro-SR-GSS(1) 231.00 0.58 332.89 231.00 193.35 0.98 -0.08 6,034,864.76 541,269.97 0.49 -0.98 2Gyro-SR-GSS(1) 295.09 1.84 312.82 295.07 257.42 1.97 -0.98 6,034,865.75 541,269.06 2.04 -2.11 2_MWD+IFR2+MS+Sag(2) 358.39 3.61 300.33 358.30 320.65 3.67 -3.45 6,034,867.43 541,266.58 2.93 -4.20 2_MWD+IFR2+MS+Sag(2) 420.10 5.63 293.61 419.80 382.15 5.86 -7.90 6,034,869.60 541,262.12 3.38 -7.11 2_MWD+IFR2+MS+Sag(2) 480.71 7.53 284.66 480.01 442.36 8.06 -14.46 6,034,871.76 541,255.54 3.55 -10.38 2_MWD+IFR2+MS+Sag(2) 543.34 8.79 272.35 542.01 504.36 9.29 -23.22 6,034,872.94 541,246.78 3.43 -13.08 2_MWD+IFR2+MS+Sag(2) 605.26 9.64 256.04 603.14 565.49 8.24 -32.98 6,034,871.83 541,237.03 4.42 -13.69 2_MWD+IFR2+MS+Sag(2) 664.62 10.79 238.78 661.58 623.93 4.16 -42.56 6,034,867.70 541,227.48 5.48 -11.28 2_MWD+IFR2+MS+Sag(2) 3/5/2018 5:45:25PM Page 2 COMPASS 5000.1 Build 81E II s Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU F-109 Project: Milne Point TVD Reference: MPU F-109 Actual RKB @ 37.65usft Site: M Pt F Pad MD Reference: MPU F-109 Actual RKB @ 37.65usft Well: MPU F-109 North Reference: True Wellbore: MPU F-109(OA Producer) Survey Calculation Method: Minimum Curvature Design: MPU F-109 Database: Sperry EDM-NORTH US+CANADA NI I Survey Map Map Vertical MD Inc Azi TVD TVDSS +1,11-5 +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°l100') (ft) Survey Tool Name 728.59 10.74 228.99 724.43 686.78 -2.86 -52.17 6,034,860.63 541,217.90 2.86 -5.99 2_MWD+IFR2+MS+Sag(2) 791.64 11.72 222.80 786.27 748.62 -11.41 -60.96 6,034,852.03 541,209.16 2.46 0.96 2_MWD+IFR2+MS+Sag(2) 854.96 15.05 222.55 847.86 810.21 -22.19 -70.89 6,034,841.20 541,199.29 5.26 9.90 2_MWD+IFR2+MS+Sag(2) 917.41 19.06 224.01 907.55 869.90 -35.50 -83.46 6,034,827.82 541,186.79 6.46 20.90 2_MWD+IFR2+MS+Sag(2) 979.40 22.02 224.63 965.60 927.95 -51.06 -98.66 6,034,812.18 541,171.68 4.79 33.67 2_MWD+IFR2+MS+Sag(2) 1,042.28 24.70 224.55 1,023.32 985.67 -68.81 -116.16 6,034,794.33 541,154.28 4.26 48.21 2_MWD+IFR2+MS+Sag(2) 1,105.18 27.88 224.71 1,079.70 1,042.05 -88.63 -135.74 6,034,774.40 541,134.82 5.06 64.44 2_MWD+IFR2+MS+Sag(2) 1,168.11 31.08 225.14 1,134.48 1,096.83 -110.55 -157.61 6,034,752.36 541,113.08 5.10 82.36 2_MWD+IFR2+MS+Sag(2) 1,230.98 34.53 225.83 1,187.31 1,149.66 -134.42 -181.90 6,034,728.36 541,088.92 5.52 101.78 2_MWD+IFR2+MS+Sag(2) 1,294.23 37.57 225.27 1,238.45 1,200.80 -160.49 -208.46 6,034,702.15 541,062.50 4.83 122.99 2_MWD+IFR2+MS+Sag(2) 1,357.07 40.73 224.81 1,287.17 1,249.52 -188.53 -236.53 6,034,673.96 541,034.60 5.05 145.89 2_MWD+IFR2+MS+Sag(2) 1,419.93 43.43 223.86 1,333.82 1,296.17 -218.66 -265.96 6,034,643.67 541,005.34 4.41 170.62 2_MWD+IFR2+MS+Sag(2) 1,483.12 45.19 224.38 1,379.04 1,341.39 -250.34 -296.69 6,034,611.82 540,974.79 2.84 196.66 2_MWD+IFR2+MS+Sag(2) 1,545.89 47.03 225.10 1,422.55 1,384.90 -282.47 -328.53 6,034,579.52 540,943.13 3.05 222.95 2_MWD+IFR2+MS+Sag(2) 1,608.99 47.77 225.50 1,465.26 1,427.61 -315.14 -361.55 6,034,546.67 540,910.30 1.26 249.58 2_MWD+IFR2+MS+Sag(2) 1,671.74 49.93 223.70 1,506.56 1,468.91 -348.79 -394.71 6,034,512.84 540,877.32 4.06 277.14 2_MWD+IFR2+MS+Sag(2) 1,734.60 49.00 224.07 1,547.41 1,509.76 -383.22 -427.83 6,034,478.23 540,844.40 1.55 305.49 2_MWD+IFR2+MS+Sag(2) 1,797.10 48.99 224.32 1,588.42 1,550.77 -417.04 -460.70 6,034,444.23 540,811.71 0.30 333.27 2_MWD+IFR2+MS+Sag(2) 1,860.07 48.17 225.33 1,630.08 1,592.43 -450.53 -493.99 6,034,410.56 540,778.62 1.77 360.66 2_MWD+IFR2+MS+Sag(2) 1,923.82 48.66 223.15 1,672.39 1,634.74 -484.69 -527.25 6,034,376.22 540,745.55 2.67 388.71 2_MWD+IFR2+MS+Sag(2) 1,986.66 48.41 222.31 1,714.00 1,676.35 -519.28 -559.20 6,034,341.45 540,713.80 1.08 417.41 2_MWD+IFR2+MS+Sag(2) 2,049.62 47.44 222.87 1,756.19 1,718.54 -553.69 -590.83 6,034,306.88 540,682.37 1.68 445.99 2_MWD+IFR2+MS+Sag(2) 2,111.54 49.77 222.92 1,797.13 1,759.48 -587.71 -622.44 6,034,272.68 540,650.94 3.76 474.19 2_MWD+IFR2+MS+Sag(2) 2,174.51 48.10 222.94 1,838.50 1,800.85 -622.47 -654.78 6,034,237.74 540,618.80 2.65 502.99 2_MWD+IFR2+MS+Sag(2) 2,238.08 50.08 222.65 1,880.13 1,842.48 -657.73 -687.41 6,034,202.31 540,586.37 3.13 532.23 2_MWD+IFR2+MS+Sag(2) 2,301.02 49.40 222.17 1,920.80 1,883.15 -693.19 -719.81 6,034,166.67 540,554.18 1.23 561.71 2_MWD+IFR2+MS+Sag(2) 2,364.08 47.64 222.48 1,962.57 1,924.92 -728.12 -751.62 6,034,131.57 540,522.56 2.82 590.77 2_MWD+IFR2+MS+Sag(2) 2,426.93 49.26 223.59 2,004.25 1,966.60 -762.49 -783.72 6,034,097.02 540,490.66 2.90 619.23 2_MWD+IFR2+MS+Sag(2) 2,489.72 50.03 223.56 2,044.91 2,007.26 -797.16 -816.70 6,034,062.18 540,457.87 1.23 647.83 2_MWD+IFR2+MS+Sag(2) 2,552.67 48.28 222.93 2,086.08 2,048.43 -831.84 -849.33 6,034,027.32 540425.44 2.88 676.50 2_MWD+IFR2+MS+Sag(2) 2,615.32 49.43 224.95 2,127.30 2,089.65 -865.80 -882.06 6,033,993.18 540,392.90 3.04 704.45 2_MWD+IFR2+MS+Sag(2) 2,677.66 51.32 226.73 2,167.06 2,129.41 -899.24 -916.51 6,033,959.55 540,358.64 3.75 731.60 2_MWD+IFR2+MS+Sag(2) 2,740.93 50.75 226.62 2,206.85 2,169.20 -933.00 -952.30 6,033,925.60 540,323.04 0.91 758.82 2_MWD+IFR2+MS+Sag(2) 2,803.96 49.79 226.40 2,247.14 2,209.49 -966.36 -987.47 6,033,892.05 540,288.06 1.55 785.77 2_MWD+IFR2+MS+Sag(2) 2,866.81 51.30 227.14 2,287.07 2,249.42 -999.59 -1,022.83 6,033,858.62 540,252.89 2.57 812.55 2_MWD+IFR2+MS+Sag(2) 2,929.77 51.00 227.24 2,326.57 2,288.92 -1,032.91 -1,058.80 6,033,825.10 540,217.11 0.49 839.32 2_MWD+IFR2+MS+Sag(2) 2,992.45 50.00 227.35 2,366.44 2,328.79 -1,065.71 -1,094.34 6,033,792.11 540,181.75 1.60 865.65 2_MWD+IFR2+MS+Sag(2) 3,055.56 49.15 227.96 2,407.36 2,369.71 -1,098.08 -1,129.85 6,033,759.55 540,146.43 1.53 891.56 2_MWD+IFR2+MS+Sag(2) 3,118.60 50.91 225.77 2,447.86 2,410.21 -1,131.11 -1,165.09 6,033,726.32 540,111.38 3.86 918.17 2_MWD+IFR2+MS+Sag(2) 3,181.52 50.46 225.71 2,487.72 2,450.07 -1,165.09 -1,199.95 6,033,692.16 540,076.71 0.72 945.77 2_MWD+IFR2+MS+Sag(2) 3/5/2018 5:45:25PM Page 3 COMPASS 5000.1 Build 81E • S Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU F-109 ' Project: Milne Point TVD Reference: MPU F-109 Actual RKB @ 37.65usft , Site: M Pt F Pad MD Reference: MPU F-109 Actual RKB @ 37.65usft Well: MPU F-109 North Reference: True Wellbore: MPU F-109(OA Producer) Survey Calculation Method: Minimum Curvature Design: MPU F-109 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Verti•cal t 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, 3,244.64 50.12 224.08 2,528.05 2,490.40 -1,199.48 -1,234.22 6,033,657.58 540,042.63 2.06 973.88 2_MWD+1FR2+MS+Sag(2) 3,307.66 49.62 225.24 2,568.67 2,531.02 -1,233.75 -1,268.09 6,033,623.12 540,008.96 1.62 1,001.95 2_MWD+IFR2+MS+Sag(2) 3,370.61 48.26 226.01 2,610.02 2,572.37 -1,266.95 -1,302.01 6,033,589.74 539,975.22 2.35 1,028.94 2_MWD+IFR2+MS+Sag(2) 3,433.67 49.80 223.19 2,651.37 2,613.72 -1,300.85 -1,335.43 6,033,555.66 539,942.00 4.17 1,056.72 2_MWD+IFR2+MS+Sag(2) 3,496.09 49.06 223.49 2,691.96 2,654.31 -1,335.34 -1,367.97 6,033,520.99 539,909.65 1.24 1,085.21 2_MWD+IFR2+MS+Sag(2) 3,558.39 48.66 223.69 2,732.95 2,695.30 -1,369.32 -1,400.32 6,033,486.83 539,877.50 0.69 1,113.24 2_MWD+IFR2+MS+Sag(2) 3,622.03 49.80 223.83 2,774.51 2,736.86 -1,404.13 -1,433.65 6,033,451.84 539,844.36 1.80 1,141.93 2_MWD+IFR2+MS+Sag(2) 3,684.73 48.40 225.39 2,815.56 2,777.91 -1,437.87 -1,466.93 6,033,417.92 539,811.27 2.92 1,169.56 2_MWD+IFR2+MS+Sag(2) 3,746.17 50.74 223.78 2,855.41 2,817.76 -1,471.18 -1,499.75 6,033,384.43 539,778.65 4.30 1,196.86 2_MWD+IFR2+MS+Sag(2) 3,810.66 50.94 223.21 2,896.13 2,858.48 -1,507.46 -1,534.16 6,033,347.97 539,744.43 0.75 1,226.80 2_MWD+IFR2+MS+Sag(2) 3,873.70 50.82 222.08 2,935.91 2,898.26 -1,543.43 -1,567.30 6,033,311.82 539,711.51 1.40 1,256.66 2_MWD+1FR2+MS+Sag(2) 3,935.67 50.24 222.85 2,975.30 2,937.65 -1,578.72 -1,599.59 6,033,276.35 539,679.41 1.34 1,286.00 2_MWD+IFR2+MS+Sag(2) 3,999.34 49.41 222.63 3,016.37 2,978.72 -1,614.45 -1,632.61 6,033,240.44 539,646.59 1.33 1,315.64 2_MWD+IFR2+MS+Sag(2) 4,062.47 48.96 223.91 3,057.64 3,019.99 -1,649.24 -1,665.35 6,033,205.48 539,614.05 1.69 1,344.40 2_MWD+IFR2+MS+Sag(2) 4,125.28 48.79 224.07 3,098.95 3,061.30 -1,683.28 -1,698.22 6,033,171.26 539,581.38 0.33 1,372.40 2_MWD+IFR2+MS+Sag(2) 4,187.92 48.42 225.11 3,140.37 3,102.72 -1,716.74 -1,731.20 6,033,137.61 539,548.58 1.38 1,399.82 2_MWD+IFR2+MS+Sag(2) 4,250.88 48.69 223.89 3,182.04 3,144.39 -1,750.41 -1,764.28 6,033,103.77 539,515.69 1.51 1,427.41 2_MWD+IFR2+MS+Sag(2) 4,313.80 50.16 221.47 3,222.97 3,185.32 -1,785.54 -1,796.66 6,033,068.46 539,483.51 3.74 1,456.57 2_MWD+IFR2+MS+Sag(2) 4,376.67 50.72 221.98 3,263.01 3,225.36 -1,821.72 -1,828.92 6,033,032.11 539,451.45 1.09 1,486.78 2_MWD+IFR2+MS+Sag(2) 4,439.69 51.94 217.57 3,302.40 3,264.75 -1,859.52 -1,860.38 6,032,994.13 539,420.21 5.80 1,518.74 2_MWD+IFR2+MS+Sag(2) 4,502.48 52.07 212.91 3,341.07 3,303.42 -1,899.92 -1,888.91 6,032,953.58 539,391.91 5.85 1,553.74 2_MWD+IFR2+MS+Sag(2) 4,565.13 51.65 207.30 3,379.78 3,342.13 -1,942.51 -1,913.62 6,032,910.86 539,367.44 7.07 1,591.55 2_MWD+IFR2+MS+Sag(2) 4,628.54 52.39 202.98 3,418.81 3,381.16 -1,987.75 -1,934.83 6,032,865.51 539,346.48 5.49 1,632.55 2_MWD+IFR2+MS+Sag(2) 4,691.41 54.14 198.34 3,456.43 3,418.78 -2,034.88 -1,952.58 6,032,818.29 539,329.00 6.54 1,676.00 2_MWD+IFR2+MS+Sag(2) 4,754.34 55.32 193.34 3,492.78 3,455.13 -2,084.28 -1,966.58 6,032,768.81 539,315.27 6.75 1,722.34 2_MWD+IFR2+MS+Sag(2) 4,817.20 55.33 189.60 3,528.55 3,490.90 -2,134.93 -1,976.86 6,032,718.11 539,305.28 4.89 1,770.52 2_MWD+IFR2+MS+Sag(2) 4,880.16 55.85 185.30 3,564.14 3,526.49 -2,186.41 -1,983.58 6,032,666.60 539,298.84 5.69 1,820.13 2_MWD+IFR2+MS+Sag(2) 4,942.84 59.28 181.97 3,597.76 3,560.11 -2,239.19 -1,986.91 6,032,613.81 539,295.81 7.07 1,871.59 2_MWD+IFR2+MS+Sag(2) 5,006.52 60.68 180.97 3,629.62 3,591.97 -2,294.31 -1,988.32 6,032,558.69 539,294.70 2.58 1,925.68 2_MWD+IFR2+MS+Sag(2) 5,069.12 60.13 181.72 3,660.53 3,622.88 -2,348.73 -1,989.59 6,032,504.27 539,293.73 1.36 1,979.10 2_MWD+IFR2+MS+Sag(2) 5,131.86 60.05 181.29 3,691.82 3,654.17 -2,403.09 -1,991.02 6,032,449.90 539,292.60 0.61 2,032.44 2_MWD+IFR2+MS+Sag(2) 5,193.99 59.43 181.32 3,723.13 3,685.48 -2,456.74 -1,992.24 6,032,396.25 539,291.68 1.00 2,085.12 2_MWD+IFR2+MS+Sag(2) 5,257.30 59.23 181.63 3,755.42 3,717.77 -2,511.18 -1,993.65 6,032,341.81 539,290.58 0.53 2,138.53 2_MWD+IFR2+MS+Sag(2) 5,317.95 58.71 181.85 3,786.69 3,749.04 -2,563.12 -1,995.22 6,032,289.86 539,289.29 0.91 2,189.47 2_MWD+IFR2+MS+Sag(2) 5,383.49 59.63 181.61 3,820.27 3,782.62 -2,619.38 -1,996.92 6,032,233.61 539,287.90 1.44 2,244.63 2_MWD+IFR2+MS+Sag(2) 5,446.24 62.45 178.71 3,850.66 3,813.01 -2,674.27 -1,997.06 6,032,178.73 539,288.08 6.04 2,298.71 2_MWD+IFR2+MS+Sag(2) 5,508.51 66.63 176.22 3,877.43 3,839.78 -2,730.41 -1,994.55 6,032,122.60 539,290.89 7.62 2,354.47 2_MWD+1F142+MS+Sag(2) 5,571.93 67.70 174.47 3,902.04 3,864.39 -2,788.67 -1,989.80 6,032,064.38 539,295.96 3.05 2,412.69 2_MWD+IFR2+MS+Sag(2) 5,635.27 70.21 173.48 3,924.78 3,887.13 -2,847.45 -1,983.59 6,032,005.64 539,302.50 4.22 2,471.68 2_MWD+IFR2+MS+Sag(2) 5,697.83 71.89 170.43 3,945.10 3,907.45 -2,906.02 -1,975.31 6,031,947.11 539,311.11 5.34 2,530.81 2_MWD+IFR2+MS+Sag(2) 3/5/2018 5:45:25PM Page 4 COMPASS 5000.1 Build 81E 0 • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU F-109 Project: Milne Point TVD Reference: MPU F-109 Actual RKB @ 37.65usft Site: M Pt F Pad MD Reference: MPU F-109 Actual RKB @ 37.65usft Well: MPU F-109 North Reference: True Wellbore: MPU F-109(0A Producer) Survey Calculation Method: Minimum Curvature Design: MPU F-109 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 5,760.48 73.98 168.25 3,963.49 3,925.84 -2,964.87 -1,964.22 6,031,888.33 539,322.52 4.71 2,590.69 2_MWD+IFR2+MS+Sag(2) 5,823.60 74.94 166.71 3,980.40 3,942.75 -3,024.24 -1,951.04 6,031,829.05 539,336.03 2.80 2,651.42 2_MWD+IFR2+MS+Sag(2) 5,886.30 76.10 163.15 3,996.08 3,958.43 -3,082.84 -1,935.25 6,031,770.54 539,352.14 5.80 2,711.85 2_MWD+IFR2+MS+Sag(2) 5,949.43 77.55 159.13 4,010.48 3,972.83 -3,141.00 -1,915.38 6,031,712.50 539,372.33 6.61 2,772.53 2_MWD+IFR2+MS+Sag(2) 6,010.59 80.08 156.14 4,022.34 3,984.69 -3,196.47 -1,892.55 6,031,657.16 539,395.47 6.33 2,831.05 2_MWD+IFR2+MS+Sag(2) 6,074.97 81.70 152.92 4,032.54 3,994.89 -3,253.85 -1,865.21 6,031,599.94 539,423.12 5.54 2,892.22 2_MWD+IFR2+MS+Sag(2) 6,138.05 83.19 150.83 4,040.83 4,003.18 -3,308.99 -1,835.74 6,031,544.97 539,452.90 4.05 2,951.55 2_MWD+IFR2+MS+Sag(2) 6,201.12 84.62 146.95 4,047.53 4,009.88 -3,362.67 -1,803.34 6,031,491.48 539,485.59 6.52 3,009.93 2_MWD+IFR2+MS+Sag(2) 6,263.49 86.11 146.73 4,052.57 4,014.92 -3,414.71 -1,769.34 6,031,439.63 539,519.88 2.41 3,066.97 2_MWD+IFR2+MS+Sag(2) 6,326.46 85.49 145.19 4,057.18 4,019.53 -3,466.75 -1,734.18 6,031,387.79 539,555.32 2.63 3,124.19 2_MWD+IFR2+MS+Sag(2) 6,389.83 84.90 144,39 4,062.49 4,024.84 -3,518.34 -1,697.78 6,031,336.41 539,592.01 1.57 3,181.19 2_MWD+IFR2+MS+Sag(2) 6,421.31 84.74 143.97 4,065.33 4,027.68 -3,543.76 -1,679.43 6,031,311.09 539,610.50 1.42 3,209.35 2_MWD+IFR2+MS+Sag(2) 6,518.29 85.54 145.42 4,073.55 4,035.90 -3,622.62 -1,623.58 6,031,232.55 539,666.77 1.70 3,296.50 2_MWD+IFR2+MS+Sag(3) 6,581.73 86.09 146.57 4,078.18 4,040.53 -3,675.07 -1,588.20 6,031,180.31 539,702.44 2.01 3,354.17 2_MWD+IFR2+MS+Sag(3) 6,644.93 86.71 146.07 4,082.15 4,044.50 -3,727.56 -1,553.22 6,031,128.02 539,737.71 1.26 3,411.81 2_MWD+IFR2+MS+Sag(3) 6,707.89 87.33 146.36 4,085.42 4,047.77 -3,779.81 -1,518.26 6,031,075.96 539,772.96 1.09 3,469.22 2_MWD+IFR2+MS+Sag(3) 6,770.66 87.39 145.47 4,088.31 4,050.66 -3,831.75 -1,483.12 6,031,024.23 539,808.38 1.42 3,526.34 2_MWD+IFR2+MS+Sag(3) 6,833.71 89.57 145.51 4,089.98 4,052.33 -3,883.68 -1,447.41 6,030,972.50 539,844.37 3.46 3,583.56 2_MWD+IFR2+MS+Sag(3) 6,896.81 90.67 145.71 4,089.85 4,052.20 -3,935.75 -1,411.77 6,030,920.64 539,880.30 1.77 3,640.89 2_MWD+IFR2+MS+Sag(3) 6,959.55 90.54 145.24 4,089.19 4,051.54 -3,987.44 -1,376.22 6,030,869.15 539,916.14 0.78 3,697.84 2_MWD+IFR2+MS+Sag(3) 7,022.73 89.80 145.06 4,089.00 4,051.35 -4,039.28 -1,340.11 6,030,817.51 539,952.53 1.21 3,755.04 2_MWD+IFR2+MS+Sag(3) 7,085.78 89.06 143.51 4,089.63 4,051.98 -4,090.47 -1,303.31 6,030,766.53 539,989.61 2.72 3,811.71 2_MWD+IFR2+MS+Sag(3) 7,148.84 90.36 145,40 4,089.95 4,052.30 -4,141.78 -1,266.65 6,030,715.44 540,026.55 3.64 3,868.47 2_MWD+IFR2+MS+Sag(3) 7,211.63 91.72 148.25 4,088.81 4,051.16 -4,194.32 -1,232.31 6,030,663.09 540,061.18 5.03 3,926.05 2_MWD+IFR2+MS+Sag(3) 7,274.45 90.23 148.24 4,087.74 4,050.09 -4,247.72 -1,199.25 6,030,609.88 540,094.53 2.37 3,984.27 2_MWD+IFR2+MS+Sag(3) 7,337.35 89.49 149.18 4,087.89 4,050.24 -4,301.47 -1,166.58 6,030,556.31 540,127.49 1.90 4,042.77 2_MWD+IFR2+MS+Sag(3) 7,399.95 88.68 149.99 4,088.89 4,051.24 -4,355.45 -1,134.89 6,030,502.52 540,159.48 1.83 4,101.32 2_MWD+IFR2+MS+Sag(3) 7,463.37 88.75 148.04 4,090.32 4,052.67 -4,409.80 -1,102.25 6,030,448.35 540,192.41 3.08 4,160.40 2_MWD+IFR2+MS+Sag(3) 7,526.00 89.31 146.63 4,091.38 4,053.73 -4,462.52 -1,068.46 6,030,395.83 540,226.50 2.42 4,218.07 2_MWD+IFR2+MS+Sag(3) 7,589.55 88.44 147.01 4,092.62 4,054.97 -4,515.70 -1,033.69 6,030,342.85 540,261.56 1.49 4,276.35 2_MWD+IFR2+MS+Sag(3) 7,651.40 88.19 146.80 4,094.44 4,056.79 -4,567.49 -999.93 6,030,291.25 540,295.61 0.53 4,333.10 2_MWD+IFR2+MS+Sag(3) 7,715.29 90.18 146.98 4,095.35 4,057.70 -4,621.00 -965.03 6,030,237.95 540,330.79 3.13 4,391.73 2_MWD+IFR2+MS+Sag(3) 7,776.47 91.97 147.77 4,094.20 4,056.55 -4,672.51 -932.06 6,030,186.62 540,364.05 3.20 4,448.08 2_MWD+IFR2+MS+Sag(3) 7,840.76 92.70 148.53 4,091.58 4,053.93 -4,727.08 -898.16 6,030,132.25 540,398.25 1.64 4,507.58 2_MWD+IFR2+MS+Sag(3) 7,904.00 92.26 147.55 4,088.85 4,051.20 -4,780.68 -864.72 6,030,078.84 540,431.99 1.70 4,566.06 2_MWD+IFR2+MS+Sag(3) 7,966.53 92.39 147.63 4,086.31 4,048.66 -4,833.43 -831.23 6,030,026.28 540,465.76 0.24 4,623.70 2_MWD+IFR2+MS+Sag(3) 8,028.79 92.39 147.56 4,083.71 4,046.06 -4,885.95 -797.89 6,029,973.96 540,499.39 0.11 4,681.10 2_MWD+IFR2+MS+Sag(3) 8,091.61 92.14 146.48 4,081.23 4,043.58 -4,938.60 -763.73 6,029,921.50 540,533.84 1.76 4,738.76 2_MWD+IFR2+MS+Sag(3) 8,147.08 92.08 146.15 4,079.19 4,041.54 -4,984.73 -732.98 6,029,875.55 540,564.84 0.60 4,789.42 2_MWD+IFR2+MS+Sag(3) 8,217.96 92.95 145.25 4,076.08 4,038.43 -5,043.22 -693.08 6,029,817.28 540,605.06 1.77 4,853.81 2_MWD+IFR2+MS+Sag(3) 3/5/2018 5:45:25PM Page 5 COMPASS 5000.1 Build 81E 0 Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU F-109 Project: Milne Point TVD Reference: MPU F-109 Actual RKB @ 37.65usft Site: M Pt F Pad MD Reference: MPU F-109 Actual RKB @ 37.65usft Well: MPU F-109 North Reference: True ' Wellbore: MPU F-109(OA Producer) Survey Calculation Method: Minimum Curvature Design: MPU F-109 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,279.97 92.02 143.88 4,073.39 4,035.74 -5,093.70 -657.16 6,029,767.01 540,641.26 2.67 4,909.63 2_MWD+IFR2+MS+Sag(3) 8,343.52 90.47 144.46 4,072.01 4,034.36 -5,145.21 -619.97 6,029,715.71 540,678.73 2.60 4,966.67 2_MWD+IFR2+MS+Sag(3) 8,406.62 88.74 144.19 4,072.44 4,034.79 -5,196.46 -583.17 6,029,664.67 540,715.81 2.77 5,023.41 2_MWD+IFR2+MS+Sag(3) 8,469.34 89.62 145.63 4,073.34 4,035.69 -5,247.78 -547.12 6,029,613.56 540,752.14 2.69 5,080.07 2_MWD+IFR2+MS+Sag(3) 8,532.20 88.44 145.16 4,074.41 4,036.76 -5,299.51 -511.43 6,029,562.03 540,788.12 2.02 5,137.08 2_MWD+IFR2+MS+Sag(3) 8,594.97 90.18 148.12 4,075.16 4,037.51 -5,351.92 -476.92 6,029,509.81 540,822.91 5.47 5,194.57 2_MWD+IFR2+MS+Sag(3) 8,658.62 91.10 150.17 4,074.45 4,036.80 -5,406.56 -444.28 6,029,455.37 540,855.85 3.53 5,253.94 2_MWD+IFR2+MS+Sag(3) 8,721.15 91.22 151.07 4,073.19 4,035.54 -5,461.03 -413.61 6,029,401.07 540,886.82 1.45 5,312.81 2_MWD+IFR2+MS+Sag(3) 8,784.02 90.23 152.32 4,072.39 4,034.74 -5,516.38 -383.80 6,029,345.89 540,916.93 2.54 5,372.39 2_MWD+IFR2+MS+Sag(3) 8,846.91 89.80 152.77 4,072.37 4,034.72 -5,572.19 -354.81 6,029,290.25 540,946.23 0.99 5,432.29 2_MWD+IFR2+MS+Sag(3) 8,909.91 89.49 152.61 4,072.76 4,035.11 -5,628.16 -325.90 6,029,234.44 540,975.45 0.55 5,492.35 2_MWD+IFR2+MS+Sag(3) 8,968.35 87.45 151.71 4,074.32 4,036.67 -5,679.82 -298.62 6,029,182.95 541,003.01 3.82 5,547.86 2_MWD+IFR2+MS+Sag(3) 9,036.06 88.32 151.12 4,076.82 4,039.17 -5,739.23 -266.25 6,029,123.72 541,035.71 1.55 5,611.89 2_MWD+IFR2+MS+Sag(3) 9,099.15 88.07 148.70 4,078.81 4,041.16 -5,793.79 -234.64 6,029,069.34 541,067.62 3.85 5,671.00 2_MWD+IFR2+MS+Sag(3) 9,161.82 88.44 147.18 4,080.72 4,043.07 -5,846.88 -201.39 6,029,016.45 541,101.16 2.50 5,728.94 2_MWD+IFR2+MS+Sag(3) 9,225.11 88.56 147.77 4,082.38 4,044.73 -5,900.22 -167.37 6,028,963.30 541,135.47 0.95 5,787.26 2_MWD+IFR2+MS+Sag(3) 9,288.34 87.39 146.84 4,084.61 4,046.96 -5,953.40 -133.24 6,028,910.32 541,169.90 2.36 5,845.44 2_MWD+IFR2+MS+Sag(3) 9,350.53 87.57 146.75 4,087.34 4,049.69 -6,005.38 -99.21 6,028,858.53 541,204.21 0.32 5,902.42 2_MWD+IFR2+MS+Sag(3) 9,413.06 89.75 146.93 4,088.81 4,051.16 -6,057.71 -65.02 6,028,806.39 541,238.68 3.50 5,959.77 2_MWD+IFR2+MS+Sag(3) 9,476.18 90.17 146.48 4,088.85 4,051.20 -6,110.47 -30.37 6,028,753.83 541,273.62 0.98 6,017.63 2_MWD+IFR2+MS+Sag(3) 9,539.37 90.54 146.63 4,088.46 4,050.81 -6,163.20 4.45 6,028,701.31 541,308.74 0.63 6,075.47 2_MWD+IFR2+MS+Sag(3) 9,602.12 90.66 145.64 4,087.80 4,050.15 -6,215.30 39.42 6,028,649.41 541,343.99 1.59 6,132.73 2_MWD+IFR2+MS+Sag(3) 9,665.34 90.47 145.32 4,087.18 4,049.53 -6,267.38 75.24 6,028,597.52 541,380.10 0.59 6,190.12 2_MWD+IFR2+MS+Sag(3) 9,727.78 90.41 145.28 4,086.70 4,049.05 -6,318.72 110.79 6,028,546.39 541,415.92 0.12 6,246.71 2_MWD+IFR2+MS+Sag(3) 9,790.54 90.91 146.65 4,085.98 4,048.33 -6,370.72 145.91 6,028,494.59 541,451.33 2.32 6,303.90 2_MWD+1F82+MS+Sag(3) 9,851.31 90.78 145.46 4,085.08 4,047.43 -6,421.13 179.84 6,028,444.38 541,485.54 1.97 6,359.31 2_MWD+IFR2+MS+Sag(3) 9,916.67 90.29 144.19 4,084.47 4,046.82 -6,474.55 217.49 6,028,391.17 541,523.48 2.08 6,418.32 2_MWD+IFR2+MS+Sag(3) 9,979.96 91.16 143.78 4,083.67 4,046.02 -6,525.74 254.70 6,028,340.20 541,560.97 1.52 6,475.06 2_MWD+IFR2+MS+Sag(3) 10,042.63 91.21 143.72 4,082.37 4,044.72 -6,576.27 291.75 6,028,289.88 541,598.30 0.12 6,531.12 2_MWD+IFR2+MS+Sag(3) 10,105.42 89.69 145.40 4,081.88 4,044.23 -6,627.42 328.16 6,028,238.94 541,634.98 3.61 6,587.68 2_MWD+IFR2+MS+Sag(3) 10,166.04 90.54 146.56 4,081.76 4,044.11 -6,677.66 362.07 6,028,188.89 541,669.17 2.37 6,642.93 2_MWD+IFR2+MS+Sag(3) 10,231.19 90.47 145.66 4,081.18 4,043.53 -6,731.74 398.40 6,028,135.02 541,705.79 1.39 6,702.37 2_MWD+IFR2+MS+Sag(3) 10,294.66 91.53 147.68 4,080.08 4,042.43 -6,784.76 433.26 6,028,082.20 541,740.95 3.59 6,760.51 2_MWD+IFR2+MS+Sag(3) 10,357.28 91.65 148.11 4,078.34 4,040.69 -6,837.78 466.53 6,028,029.36 541,774.51 0.71 6,818.39 2_MWD+IFR2+MS+Sag(3) 10,420.49 91.52 148.23 4,076.59 4,038.94 -6,891.47 499.86 6,027,975.87 541,808.13 0.28 6,876.93 2_MWD+IFR2+MS+Sag(3) 10,482.80 92.71 149.15 4,074.29 4,036.64 -6,944.66 532.21 6,027,922.86 541,840.78 2.41 6,934.83 2_MWD+IFR2+MS+Sag(3) 10,545.33 90.35 148.13 4,072.62 4,034.97 -6,998.04 564.74 6,027,869.68 541,873.60 4.11 6,992.92 2_MWD+IFR2+MS+Sag(3) 10,608.51 93.03 150.24 4,070.76 4,033.11 -7,052.26 597.09 6,027,815.63 541,906.24 5.40 7,051.83 2_MWD+IFR2+MS+Sag(3) 10,671.47 93.76 149.65 4,067.03 4,029.38 -7,106.66 628.56 6,027,761.41 541,938.02 1.49 7,110.77 2_MWD+IFR2+MS+Sag(3) 10,734.28 93.19 148.96 4,063.22 4,025.57 -7,160.57 660.57 6,027,707.69 541,970.32 1.42 7,169.31 2_MWD+IFR2+MS+Sag(3) 3/5/2018 5:45:25PM Page 6 COMPASS 5000.1 Build 81E • S Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU F-109 Project: Milne Point TVD Reference: MPU F-109 Actual RKB @ 37.65usft Site: M Pt F Pad MD Reference: MPU F-109 Actual RKB @ 37.65usft Well: MPU F-109 North Reference: True Wellbore: MPU F-109(OA Producer) Survey Calculation Method: Minimum Curvature Design: MPU F-109 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name i 10,797.15 93.44 149.40 4,059.59 4,021.94 -7,214.47 692.72 6,027,653.97 542,002.77 0.80 7,227.86 2_MWD+IFR2+MS+Sag(3) 10,860.18 93.13 148.84 4,055.98 4,018.33 -7,268.48 725.02 6,027,600.15 542,035.36 1.01 7,286.55 2_MWD+IFR2+MS+Sag(3) 10,923.02 92.51 149.18 4,052.88 4,015.23 -7,322.28 757.34 6,027,546.53 542,067.97 1.12 7,345.03 2_MWD+IFR2+MS+Sag(3) 10,985.95 91.77 147.96 4,050.53 4,012.88 -7,375.94 790.13 6,027,493.06 542,101.06 2.27 7,403.46 2_MWD+IFR2+MS+Sag(3) 11,048.38 91.96 148.46 4,048.50 4,010.85 -7,428.98 823.00 6,027,440.22 542,134.22 0.86 7,461.28 2_MWD+IFR2+MS+Sag(3) 11,111.59 91.52 147.58 4,046.58 4,008.93 -7,482.57 856.46 6,027,386.82 542,167.98 1.56 7,519.75 2_MWD+IFR2+MS+Sag(3) 11,174.94 91.34 146.94 4,045.00 4,007.35 -7,535.84 890.71 6,027,333.74 542,202.52 1.05 7,578.04 2_MWD+IFR2+MS+Sag(3) 11,237.23 91.46 147.87 4,043.48 4,005.83 -7,588.30 924.26 6,027,281.47 542,236.35 1.50 7,635.41 2_MWD+IFR2+MS+Sag(3) 11,300.45 89.86 147.38 4,042.75 4,005.10 -7,641.69 958.11 6,027,228.28 542,270.49 2.65 7,693.75 2_MWD+IFR2+MS+Sag(3) 11,363.24 89.73 147.92 4,042.98 4,005.33 -7,694.73 991.70 6,027,175.43 542,304.38 0.88 7,751.71 2_MWD+IFR2+MS+Sag(3) 11,426.17 89.80 147.33 4,043.23 4,005.58 -7,747.88 1,025.40 6,027,122.47 542,338.37 0.94 7,809.78 2_MWD+IFR2+MS+Sag(3) 11,489.15 89.92 145.40 4,043.39 4,005.74 -7,800.32 1,060.28 6,027,070.24 542,373.54 3.07 7,867.35 2_MWD+IFR2+MS+Sag(3) 11,551.98 90.29 144.73 4,043.27 4,005.62 -7,851.82 1,096.26 6,027,018.94 542,409.80 1.22 7,924.19 2_MWD+IFR2+MS+Sag(3) 11,615.14 91.28 145.84 4,042.41 4,004.76 -7,903.73 1,132.23 6,026,967.23 542,446.05 2.35 7,981.43 2_MWD+IFR2+MS+Sag(3) 11,677.53 91.03 145.96 4,041.15 4,003.50 -7,955.39 1,167.20 6,026,915.78 542,481.30 0.44 8,038.24 2_MWD+IFR2+MS+Sag(3) 11,740.79 89.11 144.99 4,041.07 4,003.42 -8,007.50 1,203.05 6,026,863.87 542,517.44 3.40 8,095.67 2_MWD+IFR2+MS+Sag(3) 11,801.48 88.99 145.17 4,042.08 4,004.43 -8,057.26 1,237.78 6,026,814.31 542,552.45 0.36 8,150.57 2_MWD+IFR2+MS+Sag(3) 11,866.83 89.37 146.01 4,043.01 4,005.36 -8,111.17 1,274.71 6,026,760.62 542,589.67 1.41 8,209.94 2_MWD+IFR2+MS+Sag(3) 11,929.01 87.76 146.19 4,044.57 4,006.92 -8,162.76 1,309.38 6,026,709.22 542,624.62 2.61 8,266.65 2_MWD+IFR2+MS+Sag(3) 11,992.07 88.44 147.92 4,046.66 4,009.01 -8,215.65 1,343.65 6,026,656.53 542,659.18 2.95 8,324.56 2_MWD+IFR2+MS+Sag(3) 12,055.22 89.50 149.45 4,047.80 4,010.15 -8,269.59 1,376.47 6,026,602.78 542,692.30 2.95 8,383.27 2_MWD+IFR2+MS+Sag(3) 12,118.23 91.04 149.29 4,047.50 4,009.85 -8,323.80 1,408.57 6,026,548.75 542,724.69 2.46 8,442.12 2_MWD+IFR2+MS+Sag(3) 12,181.01 91.22 149.26 4,046.26 4,008.61 -8,377.76 1,440.64 6,026,494.97 542,757.06 0.29 8,500.72 2_MWD+IFR2+MS+Sag(3) 12,245.05 89.49 148.94 4,045.87 4,008.22 -8,432.71 1,473.52 6,026,440.22 542,790.25 2.75 8,560.43 2_MWD+IFR2+MS+Sag(3) 12,307.74 89.12 149.61 4,046.63 4,008.98 -8,486.59 1,505.55 6,026,386.51 542,822.57 1.22 8,618.95 2_MWD+IFR2+MS+Sag(3) 12,347.54 89.06 149.39 4,047.26 4,009.61 -8,520.88 1,525.75 6,026,352.34 542,842.96 0.57 8,656.16 2_MWD+IFR2+MS+Sag(3) 12,380.00 89.06 149.39 4,047.79 4,010.14 -8,548.81 1,542.27 6,026,324.50 542,859.63 0.00 8,686.48 PROJECTED to TD mitchell.laird@hallitwrton.com ....,.`a.....` Checked By: 2018.03.0514:51:47-09Ya' Approved By: Michael Calkins tea - Date: 3/5/2018 3/5/2018 5:45:25PM Page 7 COMPASS 5000.1 Build 81E Hi/carpEnergyCompany i P Y CASING&CEMENTING REPORT Lease&Well No. MP F-109 Date Run 23-Feb-18 County Milne Point State Alaska Supv. J.Lott/R.Pederson CASING RECORD Surface TD 6,460.00 Shoe Depth: 6,451.00 PBTD: No.Jts.Delivered 169 No.Jts.Run 157 No.Jts.Returned 12 Ftg.Delivered 6,900.00 Ftg.Run 6,379.52 Ftg.Returned 520.48 Length Measurements W/O Threads Ftg.Cut Jt. 30.57 Ftg.Balance 489.91 RKB 26.50 RKB to BHF RKB to CHF RKB to THF Casing(Or Liner)Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top 1 Float Shoe 10 3/4 40.0 L-80 DWC/C Antelope 1.60 6,450.55 6,448.95 2 CSG JT 9 5/8 40.0 L-80 DWC/C TENARIS 82.01 6,448.95 _ 6,366.94 1 FC 10 3/4 40.0 L-80 DWC/C ANTELOPE 1.32 6,366.94 6,365.62 1 CSG JT 9 5/8 40.0 L-80 DWC/C TENARIS 39.90 6,365.62 6,325.72 1 BFLADAPT 10 3/4 40.0 L-80 _ DWC/C HES 1.60 6,325.72 6,324.12 93 _ CSG JT 9 5/8 40.0 L-80 DWC/C TENARIS 3,811.57 6,324.12 _ 2,512.55 1 STAGE TOOL _ 10 3/4 40.0 L-80 DWC/C HES 3.10 2,512.55 _ 2,509.45 62 CSG JT 9 5/8 40.0 L-80 DWC/C TENARIS 2,483.05 2,509.45 26.40 Csg Wt.On Hook: 110 Type Float Collar: Antelope No.Hrs to Run: 19.5 Csg Wt.On Slips: 70,000 Type of Shoe: Bullnose Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg X Yes No 40 Ft.Min. 9.3 PPG Fluid Description: Spud Mud Liner hanger Info(Make/Model): Liner top Packer?: _Yes X No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: CEMENTING REPORT Shoe @ 6450 FC @ 6,365.00 Top of Liner Preflush(Spacer) Type: Tuned Spacer Ill Density(ppg) 10.5 Volume pumped(BBLs) 60 Lead Slurry Type: Extenda Lead Sacks: 495 Yield: 2.47 Density(ppg) 11.7 Volume pumped(BBLs) 219 Mixing/Pumping Rate(bpm): 5 Tail Slurry m Type: Cern Tail Sacks: 398 Yield: 1.16 Q Density(ppg) 15.8 Volume pumped(BBLs) 82 Mixing/Pumping Rate(bpm): 4 F Post Flush(Spacer) re Type: Density(ppg) Rate(bpm): Volume: LL Displacement: Type: Spud Mud Density(ppg) 9.3 Rate(bpm): 6 Volume(actual/calculated): 479.7/0 FCP(psi): 785 Pump used for disp: Rig Bump Plug? X Yes No Bump press 785 Casing Rotated? Yes X No Reciprocated? Yes X No %Returns during job 100 Cement returns to surface? X Yes No Spacer returns? X Yes No Vol to Surf: 57 Cement In Place At: 9:00 Date: 2/23/2018 Estimated TOC: 2,513 Method Used To Determine TOC: ESCementer Stage Collar @ 2513 Type ESCementer Closure OK Preflush(Spacer) Type: Tuned Spacer Ill Density(ppg) 10.5 Volume pumped(BBLs) 60 Lead Slurry Type: Perm"L" Sacks: 324 Yield: 4.33 Density(ppg) 11.1 Volume pumped(BBLs) 250 Mixing/Pumping Rate(bpm): 4 Tail Slurry Lu Type: Premium"G" Sacks: 268 Yield: 1.17 y Density(ppg) 15.8 Volume pumped(BBLs) 82 Mixing/Pumping Rate(bpm): 4 z Post Flush(Spacer) o Type: Density(ppg) Rate(bpm): Volume: Lu ur Displacement: Type: Spud Mud Density(ppg) 9.3 Rate(bpm): 6 Volume(actual/calculated): 169.3/170.5 FCP(psi): 620 Pump used for disp: Rig Bump Plug? X Yes No Bump press 620 Casing Rotated? Yes X No Reciprocated'? _Yes X No %Returns during job 100 Cement returns to surface? X Yes No Spacer returns'? X Yes No Vol to Surf: 180 !, Cement In Place At: 18:40 Date: 2/23/2018 Estimated TOC: 0 Method Used To Determine TOC: Returns at Surface www.wellez.net WellEz Information Management LLC ver_102716bf • • 11 Seth Nolan Hilcorp Alaska, LLC 2 1 8 0 1 4 GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 2 9 1 4 4 Tele: 907 777-8308 Hillnnrp Alaska,HA: Fax: 907 777-8510 E-mail: snolan@hilcorp.com DATE 03/12/2018 To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU F-109 Prints: ROP-DGR-ABG-EWR-ADR 2"/5" MD DGR-EWR-ADR 2"/5"TVD CD: _Log Viewers 3/9/2018 9:46 AM File folder CGMt 3/9/2018 9:47 AM File folder Definitive Survey 3/9/2018 9:52 AM File folder EMF 3/9/2018 9:47 AM File folder LAS 3/9/2018 9:48 AM File folder PDF 3/9/2018 9:49 AM File folder TIFF 3/9/20189:50 AM File folder RECEIVED MAR 202018 AOGCC Please include current contact information if different from above. Please acknowledge receipt • signing and returning one copy of this transmittal or FAX to 907 777.8337 Received ' , Date: S /z91 ■o OF T • • \ / w THE STATE ����\I/���s,, Alaska Oil and Gas w � `�---��' ® Conservation Commission . = = 333 West Seventh Av nue e GOVERNOR BILL WALKER Anchorage, Alaska 99501 3572 III Main: 907.279.1433 ALA`,Y' Fax: 907.276.7542 www.aogcc.alasko.gov Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU F-109 HilcorpAlaska, LLC Permit to Drill Number: 218-014 Surface Location: 1415' FSL, 3299' FEL, SEC. 6, T13N, R10E, UM Bottomhole Location: 1692' FNL, 1895' FEL, SEC. 18, T13N, R10E, UM Dear Mr. Myers: Enclosed is the approved application for permit to drill the above referenced development well. 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. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition,the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20,Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05,Title 20,Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Hollis S. French Chair DATED this day of February, 2018. STATE OF ALL OIL AND GAS CONSERVATION COMMI IN RECEEVEiD PERMIT TO DRILL 20 AAC 25.005 JAN a 5 2018 la.Type of Work: lb.Proposed Well Class: Exploratory-Gas ❑ Service- WAG ❑ Service-Disp ❑ lc.Specify if well is proposed for: Drill ❑., Lateral ❑ Stratigraphic Test El Development-Oil ❑., Service- Winj ❑ Single Zone ❑., Coalbed GH Eacnes 0 Redrill El Reentry❑ Exploratory-Oil 0 Development-Gas 0 Service-Supply ❑ Multiple Zone 0 Geotherm CI 2.Operator Name: 5. Bond: Blanket Q. Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC Bond No. 022035244, MPU F-109 3.Address: 6.Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Drive,Suite 1400, Anchorage,AK 99503 MD: 12,204' • TVD: 4,030' k Milne Point Field 4a. Location of Well(Governmental Section): 7.Property Designation: Schrader Bluff Oil Pooli, Surface: 1415'FSL,3299'FEL,Sec 6,T13N,R10E,UM,AK ' ADL025509,ADL388235,ADL025515 t Top of Productive Horizon: 8.DNR Approval Number: 13.Approximate Spud Date: 2167'FNL,237'FWL,Sec 7,T13N,R10E,UM,AK LONS 94-109 2/16/2018 Total Depth: 9.Acres in Property: 14.Distance to Nearest Prope I : 1692'FNL,1895'FEL,Sec 18,T13N,R10E,UM,AK 6997 . 5538'to nearest unit bounsary 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL(ft): 37.4 , 15.Distance to Nearest Well 0'en Surface: x-541270 y- 6034863 Zone-4 ' GL I BF Elevation above MSL(ft): 10.9 - to Same Pool: 285'MPL-37A 16.Deviated wells: Kickoff depth: 325 feet . 17.Maximum Potential Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 90.56 degrees' Downhole: 1800 Surface: 1387 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sa ks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 42" 20" _ - X-52 Weld 80' Surface Surface 106.5' 106.5' 12.6 bbls/6 sx Stg 1 -L-1224 ft3/T-458 ft3 12-1/4" 9-5/8" 40# L-80 DWC 6,507' Surface Surface 6,505' 4,080' Stg 2-L-1943 ft3/T-314 ft3 8-1/2" 4-1/2" 29.7# L-80 Hyd 625 5,849' 6,355' 4,065' 12,204' 4,030' Cementless Screen Liner Tieback 7-5/8" 13.5# L-80 Vam STL 6,355' Surface Surface 6,355' 4,065' Tieback Assembly 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): 1 Hydraulic Fracture planned? Yes 0 No ❑✓ 20. Attachments: Property Plat ❑ BOP Sketch 7 Drilling Program 7 Time v.Depth Plot — Shallow Hazard Analysis 7 Diverter Sketch .i Seabed Report Drilling Fluid Program 7 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: 1enaeIt hilcorp.com Authorized Title: Drilling Manager Contact Phone: 777-8395 Fox r^aNl'C 'A.‘Y6A,S Authorized Signature: ,.,,./t ( ` / Date: D t-25-?.at 8 Commission Use Only Permit to Drill API Number: Q Permit Appro/qJ/y See cover letter for other Number: Ig-011-1 50-0 a.9-» �,35 I G —00—G1) Date: 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: ( ❑ Other: a Samples req'd: Yes No1 Z [V] Mud log req' d:Yes No g 30 p©'Sl 136P EST H2S measures: Yes No❑ Directional svy req'd:Yes['No❑ al �-� r� �,� d Ps 0- S/!t C A�,zr`�r Spacing exception req'd: Yes E1 No LI Inclination-only svy req'd:Yes❑ No 2. ` g /7 Post initial injection MIT req'd:Yes❑ No❑ Cjt"-----.*----\'--' APPROVED BYIA roved bIA()1(aCOMMISSIONER THE COMMISSION Date: I (( 4.)Pp Y "1"C� ` A 1A\ Submit Form and Form 10-4 1 evi ed 5/2017 T is permit"s v lid for m t t rteNaAo al per 20 AAC 25. 5(g) Attachments in Duplicate • Joe Engel Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Hilc orp Anchorage,AK 99524-4027 Tel 907 777 8395 Energy Company Email:jengel@hilcorp.com 01.25.2018 Commissioner Alaska Oil &Gas Conservation Commission 333 W. 7th Avenue RECEIVED Anchorage, Alaska 99501 JAN 7 5 ?_ #a Re: Application for Permit to Drill MPU F-109 Dear Commissioner, Hilcorp Alaska, LLC hereby submits for review and approval for a Permit to Drill an onshore production'f well at Milne Point'F' Pad, well slot 109. Drilling operations are intended to commence approximately Feb 16, 2018, pending rig schedule. MPU F-109 is a grassroots ESP producer planned to be drilled in the Schrader Bluff OA sand. F-109 is part of a five well program targeting the OA sand. The directional plan is a catenary wellpath build, 12.25" hole with 9-5/8" surface casing set into the top of the Schrader Bluff OA sand. An 8.5" lateral section will then be drilled. A 4.5" screen liner will be run in the open hole section and the well produced with an ESP assembly. r The Innovation Rig will be used to drill and complete the wellbore. Hilcorp Alaska respectfully asks for a variance to 20 AAC 25.200 (d) as per CO 390A Rule 4. The estimated reservoir pressure is 8.49 ppg EMW(1800 psi)at 4075'TVDss. Please find attached the Form 10-401, Application For Permit to Drill per 20 AAC 25.005 (a) and the drilling program for MPU F-109, which includes information required by 20 AAC 25.005(c). If you have any questions, or require further information, please do not hesitate to contact myself(Joe Engel)at 777-8395 or jengel@hilcorp.com or Monty Myers 777-8431 or mmyers@hilcorp.com. Sincerely, oe Eigel Dr irl'g Engineer Hilcorp Alaska, LLC Page 1 of 1 • Hilcorp Alaska, LLC Milne Point Unit (MPU) F-109 Drilling Program Version 1 1/25/2018 • • Milne Point F-109 SB OA Producer Hilcorp Drilling Procedure Energy Company 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 RAT and Preparatory Work 10 10.0 N/U 13-5/8"5M Diverter Configuration 11 11.0 Drill 12-1/4"Hole Section 13 12.0 Run 9-5/8" Surface Casing 16 13.0 Cement 9-5/8" Surface Casing 21 14.0 BOP N/U and Test 26 15.0 Drill 8-1/2"Hole Section 27 16.0 Run 4-1/2"Production Screen Liner(Lower Completion) 31 17.0 Run 7-5/8"Tieback 36 18.0 Run ESP Assembly-Upper Completion 39 19.0 RDMO 40 20.0 Innovation Rig Diverter Schematic 41 21.0 Innovation Rig BOP Schematic 42 22.0 Wellhead Schematic 43 23.0 Days Vs Depth 44 24.0 Formation Tops & Information 45 25.0 Anticipated Drilling Hazards 46 26.0 Innovation Rig Layout 48 27.0 FIT Procedure 49 28.0 Innovation Rig Choke Manifold Schematic 50 29.0 Casing Design 51 30.0 8-1/2"Hole Section MASP 52 31.0 Spider Plot(NAD 27) (Governmental Sections) 53 32.0 Surface Plat(As Built) (NAD 27) 54 33.0 Schrader Bluff OA Sand Offset MW vs TVD Chart 55 34.0 Drill Pipe Information 5" 19.5# S-135 DS-50 &NC50 56 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 1.0 Well Summary Well MPU F-109 Pad Milne Point"F"Pad Planned Completion Type ESP on 2-7/8"Production Tubing Target Reservoir(s) Schrader Bluff OA Sand Wellplan Iteration WP09 Planned Well TD, MD/TVD 12,204' MD/4,030' TVD PBTD, MD/TVD 12,193' MD/4,030' TVD Surface Location(Governmental) 1415'FSL, 3299'FEL, Sec 6, T13N,R10E,UM,AK Surface Location(NAD 27) X=541,270.05,Y=6,034,863.78 Surface Location(NAD 83) X= 1,681,301.09 ,Y=6,034,616.38 Top of Productive Horizon (Governmental) 2167'FNL, 237'FWL, Sec 7, T13N,R10E,UM,AK TPH Location(NAD 27) X=539,663.40 Y=6,031,272.4 TPH Location(NAD 83) X= 1,679,694.47 Y=6,031,024.92 BHL(Governmental) 1692'FNL, 1895'FEL, Sec 18,T13N, R10E,UM,AK BHL(NAD 27) X=542,752.99,Y=6,026,485 BBL(NAD 83) X= 1,682,784.13,Y=6,026,237.50 AFE Number 1714020 AFE Drilling Days 18 days AFE Completion Days 6 days AFE Drilling Amount $3,905,236 AFE Completion Amount $2,139,009 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1387 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1800 psig Work String 5" 19.5# S-135 DS-50 &NC 50 (Weatherford Rental) KB Elevation above MSL: 26.5 ft+ 10.9 ft=37.4 ft GL Elevation above MSL: 10.9 ft BOP Equipment 13-5/8"x 5M Annular,(3)ea 13-5/8"x 5M Rams Page 2 Version 1 January 2018 • • Milne Point Unit nit 111 F-109 Producer Drilling Procedure Hilcorp Energy Company 2.0 Management of Change Information Hilcorp Alaska, LLC Hilcorp Emmy Compaq. Changes to Approved Permit to Drill Date: 112312018 Subject: Changes to Approved Permit to Drill for MPU F-109 File#: MPU F-109 Drilling and Completion Program Any modifications to MPU F-109 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be communicated to the ELM and AOGCC. Sec Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Version 1 January 2018 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Eomgy Company 3.0 Tubular Program: Hole OD (in) ID (in) Drift Conn Wt Grade Conn Burst Collapse Tension (psi) (psi) Cond 20" 19.25" - - - X-52 Weld 12-1/4" 9-5/8" 8.835" 8.75" 10.235" 40 L-80 DWC 5,750 3,090 916 Tieback 7-5/8" 6.875" 6.75" 7.625 29.7 L-80 vAMs ss i 6,890 4,790 683 4-1/2" 8-1/2" Screens 3.920 3.795 4.714 13.5 L-80 H62dsn1 9020 8540 279 4.0 Drill Pipe Information: Hi '# ID (in) TJ ID TJ OD Wt Grade ti `s M/U t ien n (in) (in ( ' !) (Max) Surface& 5" 4.276" 3.25" 6.625" 19.5 S-135 GPI)S50 36,100 43,100 560klb Production 5" 4.276" 3.25" 6.625" 19.5 S-135 NC50 31,032 34,136 560k1b All casing will be new,PSL 1 (100%mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Version 1 January 2018 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 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 le of the data entry area—this will not save the data entered, and will navigate to another data en • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Detailed Daily Plan Forwards • Distributed to jengel(a�hilcop.com and pmazzolini@hilcop.com 5.3 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, jengel@hilcorp.com and cdinger@hilcorp.com 5.4 Intranet Home Page Morning Update • Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.5 EHS Incident Reporting • Health and safety:Notify EHS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drilling Manager&Drilling Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 5.6 Casing Tally • Send final"As-Run"Casing tally to pmazzolini@hilcorp.com, jengel@hilcorp.com and cdinger@hilcorp.com 5.7 Casing and Cmt report • Send casing and cement report for each string of casing to pmazzolini@hilcorp.com, jengel@hilcorp.com and cdinger@hilcorp.com 5.8 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Paul Mazzolini 907.777.8369 907.317.1275 pmazzolini@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com Completion Engineer Paul Chan 907.777.8333 907.444.2881 pchan@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 Version 1 January 2018 • s Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 6.0 Planned Wellbore Schematic fit Milne Point Unit Well:MPU F-109 PROPOSED SCHEMATIC LastCompleted:TBD Ila..ap 4..ee.1.1.1 PTD:TBD Org.KBEiev_265'/GL Elev:10.9' TREE&WELLHEAD Tree FMC 2-9/16"SM 1•I LI Wellhead FMC Gen V si OPEN HOLE/CEMENT DETAIL ,t Conductor ±270 ft3 12-1/4" Planned Pump Vol:700.4 bbl 2a/S'#nP 5-1/2' rameatIgAti Screens Liner in 8-1/2-hale 7 CASING DETAIL .,„:4 Size Type Wt/Grade/Conn ID c,p Btm BPF I" 3 il 20" Conductor N/A/X-52/Weld N/A Surface 2365' N/A 9-5/8" Surface 40/L-80/DWC/C 5-835 Surface 6.535' 0.0758 7-5/8" Tieback 29.7/L-S0/VamSTLSMLS 6.875 Surface 5,555' 0.0459 988 4-1/2" Liner Screens 13.5/L-SO/Hydril 625 3-920 6,355' 12,204' .0149 a..re^e'L, •j • is TUBING DETAIL �+ 27/3" Tubing 6.5/L-80f EUE-8rd 2.441 Surface _5,203' 0.0053 , 0/6" Capillary Strirg 318" N/A Surface :5,000' N/A liIl'• i 5' 4 '.(e) C 1-, WELL INCLINATION DETAIL D KOP'3 275' "./ Max Hole Angle=90 deg.@ 6,700'MD to TD JEWELRY DETAIL ' i No. 1 Tcp MD I Item I ID ''' t ? Upper Completion _ Tubing Hanger 2.441' 1 2 ±140 GLM:2-7/8"x 1' 2.347' 4' ,�. 3 GLM:2-7/8`x 1" 2.347" ' 4 XN Nipple .0 5 1-5,200 Base ESP Assembly Lower Completion 10 :6255BOT SLZXP LT Packer/Liner Hanger 7"x 9-5/8" 6.200" 11 :5,255' 7-5/8"Teback.Assy. 6.151`• " ' 12 :6 90' 7"H5E x4.5"HTTC L-SC XO tt `tJ 14 ±-12 123' 4-1 Drillable Packof Sub 2.400` mis d L' 00' L ..:e RC SxB(1.5"Bal on SeatfClosedl _ 4 � t3 • fir ....„?...._.,... . 4_yr SOLID LINER DETAIL 4-1/2"Screens LINER DETAIL 1u Top(MD) Btm(MD) Sawa 1t5 Top(MD) Btm(MD) I; Sdid Leer TBD TBD Delail 4-1'_' 4 GENERAL WELL INFO ' 32,204 1.. API: CompleTBD t:cn Dare:TBD - TD=12,204'(Iv1D)/TD=4,034(r PM=12,2DY(NDo/PBTD=4,(50(1VC Created By.CJD 1-23-2018 Page 6 Version 1 January 2018 i • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 7.0 Drilling / Completion Summary MPU F-109 is a grassroots ESP producer planned to be drilled in the Schrader Bluff OA sand. F-109 is p. of a five well program targeting the OA sand. The directional plan is a catenary well path build, 12.25"hole with 9-5/8" surface casing set into the top o I the Schrader Bluff OA sand. An 8.5"lateral section will then be drilled. A 4.5"screen liner will be run in the open hole section and the well produced with an ESP assembly. Drilling operations are expected to commence approximately Feb 16, 2018. The Innovation Rig will be used to drill and complete the wellbore. Surface casing will be run to 6,505' MD/4,030' TVD and cemented to surface via a 2 stage primary cern nt job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observe , 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. 4 pet" 41j. goof All cuttings&mud generated during drilling operations will be hauled to the Milne Point"B"pad G&I facility. General sequence of operations: 1. MIRU Innovation to well site 2. N/U& Test 13-5/8"Diverter and 16" diverter line 3. Drill 12-1/4"hole to TD of surface hole section. Run and cement 9-5/8" surface casing. 4. N/D diverter,N/U &test 13-5/8"x 5M BOP. 5. Drill 8-1/2" lateral to well TD. Run 4-1/2"production screen liner 6. Run 7-5/8"tieback. 7. Run production tubing. 8. N/D BOP,N/U Tree, RDMO. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR+Res 2. Production Hole: No mud logging. On site geologist. LWD: GR+ADR(For geo-steering) ✓ Page 7 Version 1 January 2018 • • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply w th 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 MPU F-109. Ens e to provide AOGCC 24 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipme t will be to 250/3000 psi for 5/5 min(annular to 50%rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation or control fluid flow from th well bore,AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BO ' test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid progr. and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". o Ensure the diverter vent line is at least 75' away from potential ignition sources • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Variance/Waiver Request(s): Hilcorp Alaska respectfully asks for a variance to 20 AAC 25.200 (d) as per CO 390A Rule 4. The estimated reservoir pressure is 8.49 ppg EMW (1800 psi) at 4075' TVDss. k- Page 8 Version 1 January 2018 • • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 12 1/4" • 13-5/8"5M CTI Annular BOP w/16"diverter line Function Test Only • 13-5/8"x 5M Control Technology Inc Annular BOP • 13-5/8"x 5M Control Technology Inc Double Gate Initial Test:250/3000 o Blind ram in btm cavity • Mud cross w/3"x 5M side outlets 8-1/2" • 13-5/8"x 5M Control Technology Single ram • 3-1/8"x 5M Choke Line Subsequent Tests: • 3-1/8"x 5M Kill line 250/3000 • 3-1/8"x 5M Choke manifold • Standpipe,floor valves,etc Primary closing unit: Control Technology Inc. (CTI), 6 station, 3000 psi,220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event(BOPs utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email:jim.regg@alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-301-4533 /Email: guy.schwartz@alaska.gov Victoria Loepp/Petroleum Engineer/(0): 907-793-1247/Email: Victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone: 907-793-1236(During normal Business Hours) Notification/Emergency Phone: 907-659-2714(Outside normal Business Hours) Page 9 Version 1 January 2018 • • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 9.0 R/U and Preparatory Work 9.1 F-109 will utilize a newly set 20" conductor on F Pad Expansion. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Dig out and set impermeable cellar inside of existing cellar. 9.3 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.4 Install FMC landing ring. sJ'r� 9.5 Iii (2) 4"threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. These will be used to take cement returns to the cellar during the surface cmt job, and also to wash out the diverter and hanger in preparation for running the pack-off . 9.6 Level pad and ensure enough room for layout of rig footprint and R/U. 9.7 Ensure rig mats cover the entire footprint of rig. 9.8 Confirm that the rig is over the appropriate well slot. 9.9 MIRU Innovation Rig 9.10 Mud loggers WILL NOT be used on either hole section. 9.11 Mix spud mud for 12-1/4" surface hole section. Keep mud cool. 9.12 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it i accidentally dropped. 9.13 Ensure 5" liners in mud pumps. • White Star Quattro 1300 Hp mud pumps are rated at 4097 psi, 381 gpm @ 140 spm @ 96.5%volumetric efficiency. Page 10 Version 1 January 2018 Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 10.0 N/U 13-5/8" 5M Diverter Configuration 10.1 N/U 13-5/8" CTI BOP stack in diverter configuration (Diverter Schematic in Sec 21 of program). • N/U 20"x 13-5/8"DSA • N/U 13 5/8", 5M diver�f"T". • NU Knife gate & 16"diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 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 wear bushing in wellhead. Page 11 Version 1 January 2018 • • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 10.5 Rig & Diverter Orientation: I I F-1061 i rr -` .f F-107 • / I X F-105 t !171 I r �F-109 I x r 4 F-11C F-10! f • i F-1101 +- r I 75'Radius Clear of Ignition Sources t — Dive rter Line ‘.\•,_ h 1 *Drawing Not To Scale MPU F Pad Expansion Page 12 Version 1 January 2018 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 11.0 Drill 12-1/4" Hole Section 11.1 P/U 12-1/4" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside component. that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure Gyro MWD is R/U and operational. Be sure to run a UBHO sub so that wireline orientation is possible if necessary. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulic calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# S-135. • Run a solid float in the surface hole section. 11.2 5"Drill string, HWDP, and Jars will come from Weatherford. 11.3 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 12-1/4"hole section to TD as per geologist and drilling engineer. • Monitor the area around the conductor for any signs of broaching. If broaching is observe., Stop drilling (or circulating) immediately notify Drilling Engineer. • Efforts should be made to minimize dog legs in the surface hole. ESP equipment can be damaged if run through high dog legs. Keep DLS <6 deg/ 100. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 400-600 gpm. Ensure shaker screens are set up to handle this flowrate. • Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs seen. • Keep swab and surge pressures low when tripping. • Ensure to leave a"Pump Tangent" section that is approx. 300' long in the directional plan. The ESP will need a straight section to sit. Target location of ESP pump tangent is 1000' MD and 200' TVD above target reservoir. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. , • Adjust MW as necessary to maintain hole stability, ensure MW is at a 9.2 at TD. • TD the hole section just into the Schrader Bluff sand. Geologists and Drilling Engineers will help adjust well path to ensure well is landed correctly. Page 13 Version 1 January 2018 • • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company • Take MWD surveys every stand drilled(60' intervals). • Watch returns closely for signs of gas when near the base of the permafrost and circulate o t all gas cut mud before continuing to drill. There have been no indications of hydrates on . y of the "F"pad wells to date. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. 11.5 12-1/4" hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1)ppg above highest anticipa ed MW. We will start with a simple gel+FW spud mud at 8.8 ppg and TD with 9.2+ppg. • PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM(10 ppb total)BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5-9.0 range with caustic soda. Daily additions of ALDACIDE G/X- CIDE 207 MUST be made to control bacterial action. • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP<20 (check with the cementers to see what YP value they have targeted). System Type: 8.8-9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8-9.2 / 75-175 20-40 25-45 <10 8.5-9.0 <_70 F Page 14 Version 1 January 2018 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company System Formulation: Gel + FW spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 -20 ppb caustic soda 0.1 ppb(8.5—9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8—9.2 ppg PAC-L/DEXTRID LT if required for<10 FL ALDACIDE G 0.1 ppb 11.6 At TD; pump sweeps, CBU, and POOH to the 20" conductor shoe. 1 Should backreamingbe necessaryto get out of the hole: 1 .7 • Prior to initiating backreaming, ensure at least 3 —4 B/U have been circulated to get hole as clean as possible. • Pump at full drill rate (400-600 gpm), and maximize rotation. • Pull slowly, 5— 10 ft/minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.8 TOOH and LD BHA 11.9 No open hole logging program planned. Page 15 Version 1 January 2018 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull wearbushing. 12.2 Make a dummy run with the 9-5/8" casing hanger. 12.3 R/U Weatherford 9-5/8" casing running equipment(CRT &Tongs) • Ensure 9-5/8"DWC x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/paint brush. • R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" 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. 12.4 P/U shoe joint, visually verify no debris inside joint. 12.5 Continue M/U&thread locking shoe track assy consisting of: • (1) Shoe joint w/float shoe bucked on(thread locked). Install (2) centralizers on shoe joint over stop collars 10' from each end. • (1) Joint with float collar bucked on pin end&thread locked. Install (1) centralizer mid tube over a stop collar. • Ensure bypass baffle is correctly installed on top of float collar. Bypass Baffle This end up. 01111") !t • (1) Joint with Halliburton bypass baffle adapter bucked on pin&threadlocked. Install (1) centralizer mid tube over a stop collar. • Ensure proper operation of float equipment while picking up. Page 16 Version 1 January 2018 • • 11 Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company • Ensure to record S/N's of all float equipment and stage tool components. 12.6 Float equipment and Stage tool equipment drawings: "A Overall Length 1111 Type HES Cementer Part No. Mir..ID After Dnllout im , SO No. C Id ax.Tcbl OD RIM D Hgtoap ES ll Running Order Opening Seat ID AIiiiClosing Sleeve No.Shear Pins E Closing Seat ID a Opening Sleeve c-' I. 1 No.Shear Pins � Plug Set ES.Yi�w�Ws ES Cementer Part No. _ Depth SO No. 6 el•"'- \ / Closi^g Plug It N 1 r W Baffle Adapter(if used) OD Shut Off Plug ID Opening Plug W Depth OD BalleAr.pur i OD a 7 Bypass or Shut-off Baffle ' I ID n By-Pass Plug II( 1 Depth Shut-off Plug 4 • Float Collar (`�, Depth By Pass Bare 11111.1 OD Float Collar Float Shoe n Depth Bypass Plug (if used) 1111111 Hole TD Float Shoe "Reference Casing OD Sales Manual Section 5 Page 17 Version 1 January 2018 • a Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 12.7 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/paint brush. • Install (1) centralizer every joint— 1000' MD from shoe, 1 centralizer every 2 joints to 2000' above shoe (Top of Ugnu) • Verify depth of lowest Ugnu water sand for isolation with Geologist • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferabl- to POH with casing and condition hole than to risk not getting cement returns to surface. 12.8 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100' TVD belo the permafrost(—2,500' MD). • Install centralizers over couplings on 5 joints below and above stage tool. • Do not place tongs on ES cementer, this can cause damaged to the tool. • Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 p.i. 9-5/8" 40# L-80 DWC Make Up Torques: Casing OD Min M/U Torque Max M/U Torque 9-5/8" 29,800 ft-lbs 34,800 ft-lbs Page 18 Version 1 January 2018 • • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company Technical Specifications Connection Type: Size(O.D.): Weight(Wall): Grade: DWC/C Casing 9-5/8 in 40.00 Ibift (0.395 in) L-80 standard Material L-80 Grade 80,000 Minimum Yield Strength (psi) ill. USA 95,000 Minimum Ultimate Strength (psi) VAM USA 4424 W.Sam Houston Pkwy.Suite 150 Pipe Dimensions Houston,TX T7041 Phone:713-479-3200 9.625 Nominal Pipe Body O.D. (in) Fax:713-479-3234 8.835 Nominal Pipe Body I.D.(in) E-mail:VAMUSAsalesavam-usa.com 0.395 Nominal Wall Thicknessin { ) 40.00 Nominal Weight (lbs/ft) 38.97 Plain End Weight(lbs/ft) 11.454 Nominal Pipe Body Area (sq in) . Pipe Body Performance Properties 916,000 Minimum Pipe Body Yield Strength Ohs) 3.090 Minimum Collapse Pressure (psi) 5,750 Minimum Internal Yield Pressure (psi) 5,300 Hydrostatic Test Pressure (psi) Connection Dimensions 10.625 Connection O.D. (in) 8.835 Connection I.D. (in) 8.750 Connection Drift Diameter(in) 4.81 Make-up Loss (in) 11.454 Critical Area (sq in) 100.0 Joint Efficiency (%) Connection Performance Properties 916,000 Joint Strength (lbs) 16,360 Reference String Length (ft) 1.4 Design Factor 947,000 API Joint Strength (lbs) „> 916.000 Structural Compression Rating (lbs) 3,090 API Collapse Pressure Rating (psi) 5,750 API Internal Pressure Resistance (psi) 19.0 Maximum Uniaxial Bend Rating [degrees/100 ft] i Appoximated Field End Torque Values 29,800 Minimum Final Torque (ft-lbs) 34,800 Maximum Final Torque (ft-lbs) 39,800 Connection Yield Torque (ft-lbs) Page 19 Version 1 January 2018 • Milne Point Unit 1 F-109 Producer Drilling Procedure Hilcorp Energy Company 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 P/U landing joint and M/U to casing string. Position the casing shoe+1- 10' from TD. Strap the landing joint prior to the casing job and mark the joint at(1) ft intervals to use as a reference when getting the casing on depth. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to <20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 20 Version 1 January 2018 • • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 13.0 Cement 9-5/8" Surface Casing 13.1 Hold a pre job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud& water can be delivered to the cementing unit at acceptable rates. • How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all iron lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug)—HEC rep to witness. Mix and pump cement per bel t w calculations for the 1St stage, confirm actual cement volumes with cementer after TD is reaches. 13.8 Cement volume based on annular volume+30% open hole excess. Job will consist of lead& tail, TOC brought to stage tool. Estimated Total Cement Volume: , Section: Calculation: Vol (BBLS) Vol (ft3) 12-l/4" OH x 9-5/8" Casing (5,505'- 2500')x .0558 bpf x 1.3 = 217 bbls 1224 ft3 SJ( annulus: Total LEAD: 217 bbls `'r 1224 ft3 2V1 12-1/4" OH x 9-5/8" Casing (6505'- 5505') x .0558 bpf x 1.3 = 72.5 bbls ✓ 407.3 ft3 annulus: 9-5/8" Shoe track: 120 x .0758 bpf = 9.096 51.07 Total 15.8 ppg TAIL: 81.6 bbl 458 ft3 I I Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company Cement Slurry Design: Lead Slurry Tail Slurry System ExtendaCEM TM System SwiftCEM TM System Density 12.0 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed 21.13 gal/sk 5.04 gal/sk Water 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. a. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. x/43 •` �,5k - A 13.11 cement calculation: C / � (�(, - _ ? 6100' x .0758 bpf=483.9 bbls ViliP 80 bbls of water must be left across stage tool to ensure proper operation once opened. • 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume,±4.5 bbls before consulting with Drilling Engineer. Page 22 Version 1 January 2018 • • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold,pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held,this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP <20 again in preparation for the 2nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 23 Version 1 January 2018 I • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Eng Company Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until 1 stage reaches sufficient compressive strength. Hold pre job safety meeting. 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2nd stage. .3X .2 k 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated Total Cement Volume: 2- 51-4- Section: - s1-Section: Calculation: Vol (BBLS) Vol (ft3) 20" Conductor x 9-5/8" (110') x .27 bpf x 1 = 29.7 bbls 166.7 ft3 casing annulus: 12-1/4" OH x 9-5/8" Casing (2000'- 110')x .0558 bpf x 3 = 316.4 bbls 1778 ft3 annulus: Total LEAD: 346 bbls 1943 ft3 its-1 12-1/4" OH x 9-5/8" Casing (2500'- 2000') x .0558 bpf x 2 = 55.8 314 ft3 annulus: Total TAIL: 55.8 bbls 314 ft3 Cement Slurry Design (2nd stage cement job): Lead Slurry Tail Slurry System Permafrost L Type I/II Density 11.1 lb/gal 14.5 lb/gal Yield 4.3279 ft3/sk 1.39 ft3/sk Mixed Water 21.405 gal/sk 6.8 gal/sk Page 24 Version 1 January 2018 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 13.24 Continue pumping lead until uncontaminated spacer is seen at surface,then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: h/ 2500' x .0758 bpf= 190 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1000— 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8" final joint. L/D cut joint. Make final cut on 9-5/8". Dress off stump. Install 9-5/8"wellhead. If transition nipple is welded on, allow to cool as per schedule. 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 jengel@hilcorp.com and cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 25 Version 1 January 2018 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 14.0 BOP N/U and Test 14.1 N/D the diverter T, 16"knife gate, 16" diverter line&N/U 11"x 13-5/8" 5M casing spool. 14.2 N/U 13-5/8"x 5M CTI BOP as follows: • BOP configuration from top down: 13-5/8"x 5M annular/ 13-5/8" x 5M double gate / 13- 5/8"x 5M mud cross/ 13-5/8"x 5M single gate • Double gate ram should be dressed with 2-7/8" x 5.5" VBRs in top cavity, blind ram in bottom cavity. • Single ram should be dressed with 2-7/8" x 5.5" VBRs • N/U bell nipple, install flowline. • Install (1)manual valve &HCR valve on kill side of mud cross. (Manual valve closest to mud cross). ✓ • Install (1)manual valve & HCR valve on choke side of mud cross. (manual valve closest to mud cross) ✓ 14.3 Run 5" BOP test assemblynd out test plug (if not installed previously). • Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Confirm test pressures with PTD • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does no build up beneath the test plug. 14.4 R/D BOP test equipment 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 8.9 ppg Baradrill-N fluid for production hole. 14.7 Set 10" ID wearbushing in wellhead. 14.8 Rack back as much 5"DP in derrick as possible to be used while drilling the hole section. 14.9 Install 5" liners in mud pumps. Page 26 Version 1 January 2018 • • Milne Point Unit F-109 Producer Drilling Procedure Hileorp Energy Company 15.0 Drill 8-1/2" Hole Section 15.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.22° PDM) 15.2 TIH w/ 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 2-VU ) 15.4 R/U and test casing to si/30 min. Ensure to record volume/pressure and plot on FIT graph. AOGCC reg is 50% of burst= 6870/2 =—3500 psi, but max test pressure on the well i. 3,000 psi. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001 . 15.5 Drill out shoe track and 20' of new formation. (3) V 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12.aug EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH& LD Cleanout BHA 15.9 P/U 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components th.t cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# S-135 DS50 &NC50. • Run a ported float in the surface hole section. 15.10 8-1/2"hole section mud program summary: • Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1)pp t. above highest anticipated MW. Only Baracarb 5 is to be used on this well. Page 27 Version 1 January 2018 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensu le we are running the finest screens possible. • Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump hi:h vis sweeps, instead use tandem sweeps. Ensure 6 rpm is> 8.5 (hole diameter) for sufficient hole cleaning • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 8.9—9.5 ppg Baradrill-N drilling fluid Properties: Section Density Plastic Viscosity Yield Point Total Solids MBT HPHT OA Lateral 8.9-9.5 15-25 20-25 <10% <7 <11.0 System Formulation: Baradrill-N Product Concentration/Function Water 0.955 bbl KCL 11 ppb KOH 0.1 ppb N-VIS 1.0— 1.5 ppb N-DRIL HT PLUS 5 ppb BARACARB 5 16 ppb BARASCAV D 0.5 ppb X-CIDE 207 0.15 b 15.11 TIH with 8-1/2" directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid Page 28 Version 1 January 2018 • • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 15.13 Begin drilling 8.5"hole section, on-bottom staging technique: • Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8 i. • Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations pulsed up real time. • If BHA begins to show excessive vibrations/whirl/stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. 15.14 Drill 8-1/2"hole section to section TD per Geologist and Drilling Engineer. • Flow Rate: 350-550 gpm,target min. AV's 200 ft/min, 385 gpm • RPM: 120+ • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightli wet to maximize solids removal efficiency. Check for holes in screens on every connectio i. • Keep swab and surge pressures low when tripping. • Take MWD surveys every stand. • Monitor Torque and Drag with pumps on every 5 stands • Monitor ECD & Hookload trends for hole cleaning indication • Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. • Use ADR to stay in section. Reservoir plan is to undulate between Schrader OA1 & 0A3 lobes in 1000-1500' MD increments, and keeping DLS <3° when moving between lobes • Limit maximum instantaneous ROP to <250 fph. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. • Target ROP is as fast as we can clean the hole without having to backream connections • Schrader Bluff OA Concretions: 5-10% of lateral • L-47: 6%, L-50 9.5% 15.15 Reference: Open hole sidetracking practice: • If a known fault is coming up,put a slight"kick-off ramp" in wellbore ahead of the fault s• we have a nice place to low side. • Attempt to lowside in a fast drilling interval where the wellbore is headed up. • Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working stri g back and forth. Trough for approx. 30 min. • Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.16 At TD, CBU at least 4 times at maximum circulation(500 gpm) and rotation(120 rpm). Pump tandem sweeps if needed. Increase lube %to 4% max. • Once well has TD'd the production lateral, swap to the completion AFE Page 29 Version 1 January 2018 • • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 15.17 Monitor the returned fluids carefully while conditioning the mud. After 4 (or more) BU, Perform production screen test(PST). The mud has been properly conditioned when the mud will pass the production screen test(3 one liter samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure • Circulate and condition mud as much as needed to pass the production screen test • If unable to pass test, the hole may have to be swapped over to a new solids free mud system prior to POOH 15.18 BROOH with the drilling assembly to the 9-5/8" casing shoe. • Circulate at full drill rate (350-550 gpm). • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std(slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe and circ at least 2 b/u once at the shoe. 15.19 Ensure all mud pumped downhole passes production screen test prior to running screens. 15.20 Swap over to clean filtered brine in preparation for running screens, (brine weight equal to mule weight at TD) Rotate and reciprocate as needed to ensure the mud is removed from the 9-5/8" casing. 15.21 Continue to POH and stand back BHA if possible. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section(GR+Res). There will not be any additional logging runs conducted. Page 30 Version 1 January 2018 • • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 16.0 Run 4-1/2" Production Screen Liner (Lower Completion) 16.1. Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2" screen liner, the following well control response procedure will be followed: • P/U&M/U the 5" safety joint (with 4-1/2" crossover installed on bottom, TIW valve in open position on top, 4-1/2"handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2" screen. • Slack off and position the 5"DP across the BOP, shut in ram or annular on 5" DP. Close TIW valve. • Proceed with well kill operations. 16.2. In the event of an influx of formation fluids while running the 2-3/8" inner string inside the 4- 1/2" screen liner: • P/U &M/U the 5" safety joint (with 4-1/2"x 2-3/8"triple connect crossover installed on bottom, TIW valve in open position on top, 2-3/8"handling joint above TIW). M/U 2-3/8" and then 4-1/2"to triple connect. • This joint shall be fully M/U with crossovers prior to running the first joint of wash pipe. • Slack off and position the 5"DP across the BOP, shut in ram or annular on 5"DP. Close TIW valve. Proceed with well kill operations. 16.3. R/U 4-1/2" liner running equipment. • Ensure 4-1/2" 13.5 Hydril 625 x DS-50 crossover is on rig floor and M/U to FOSV. • 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. 16.4. Run 4-1/2"production screen liner • Use API Modified or"Best 0 Life 2000 AG"thread compound. Dope pin end only w/paint brush. Wipe off excess. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Run packoff and float shoe on bottom. • 4-1/2"pre-drilled liner will auto—fill • Swell packers will not be installed on this completion unless a major out of zone even occurs 4-1/2" 13.5 #Hydril 625 Torque OD Minimum Maximum Yield Torque 4.5" 8,000 ft-lbs 12,800 ft-lbs 15,000 ft-lbs Page 31 Version 1 January 2018 • • IIMilne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company Wedge 625® PrInkd an:1013112017 Outside Diameter 4.500 min.Wall 87.5%in. Thickness (')Grade L80 Type 1 Wall Thickness 0.290 in. Connection OD REGULAR COUPLING PIPE BODY 111 Option Body:Red let Band:Red 41r* Grade L80 Type 10 Drift API Standard let Band:Brovm 2nd Band: Type Casing 2nd Band:- 3rd Band:- Brown 3rd f3and:- 4th Band:- PILE BODY DATA i GEOMETRY 1 Nominal 00 4.530 in. Nominal Weight 13.50 lbsift Drift 3.795 In Nominal ID 3.920 in. Wall Thickness 0.290;n. Plain Eno Weight 13_05 Ls.ft OD Toleranoe API PERFORMANCE Body Yield Strength 307 x1000 tbs Internal Yield 9020 psi SMYS 80000 psi Collapse 8540 psi CONNECTION DATA GEOMETRY Connection OD 4.714 in. Connection ID 3.849 in. Make-up Loss 4.830 in Threads per in 3.59 Connec5on OD Option REGULAR PERFORMANCE Tension Efficiency 91.0 S6 Joint Yield Strength 279.370 x1000 Internal Pressure Capacity 9020.000 psi lbs Compression Efficiency 94.5 Si, Compression Strength 290.115 x1000 Max.Allowable Bending 73.7°'10C ft Ls External Pressure Capacity 8540.000 psi MAKE-UP TORQUES Minimum 8000 ft-lbs Orimum 9600 ft-lbs Maximum 12800 ft-lbs OPERATION LIMIT TORQUES Operating Torque 12800 ft-lbs Yield Torque 15000 ft-lbs Page 32 Version 1 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company Halliburton PetroGuard Screen ��1�1�I •UI I • 1.14, IVO 4-1/z" Lower Completion Running Order • 4-1/2" Float Shoe, BTC box (Bakerlok all 4-1/2" shoe track connections below the last Hydril 625 connection) • 4-%2" WIV (wellbore isolation valve), BTC box x pin • 4-'/2" spacer joint,—30 - 40', IBT box x BTC pin • 4-1/2"Drillable Pac Off Sub, IBT box x pin • 5' 4.5" 13.5# Hydril 625 Box X 4.5" 12.6# IBT Pin crossover • 1 joint 4-1/2" 13.5#/ft L-80 Hydril 625 Liner(optional) • 4-1/2" 13.5#/ft L-80 Hydril 625 Halliburton 100 micron PetroGuard screen from 6,220' to 12,6 8' MD • Joints of 4-1/2" 13.5#/ft Hydril 625 L-80 Liner(liner lap) as needed • 4'4.5" 13.5#Hydril 625 Box X Pin pup joint(safety joint) • 7" 26#HYD 563 Box x 4.5" 13.5# Hydril 625 Pin crossover • Baker SLZXP Liner Hanger/Liner Top Packer w/ 7" 26# Hydril 563 pin 16.5. Ensure to run enough liner to provide for approx 150' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8"connection. 16.6. R/U false rotary and run 2-3/8" 4.6 # Inner String 16.7. Displace 9-5/8" surface casing back to mud, ensure lube concentration is 4%max 16.8. Before picking up Baker SLZXP liner hanger/packer assy, count the#of joints on the pipe deck to make sure it coincides with the pipe tally. Page 33 Version 1 January 2018 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 16.9. M/U Baker SLZXP liner top packer to inner string and 4-1/2" liner. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 16.10. Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.11. RIH w/liner on DP no faster than 30 ft/min—this is to prevent buckling the liner and drill string. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 16.12. The inner string will prevent the DP from auto filling. Fill DP with PST passed mud every 5 stands, more frequently if SOW trend indicates. 16.13. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth+ S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.14. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 0, & 20 rpm 16.15. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensur- shoe enters correct hole. 16.16. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.17. Rig up to pump down the work string with the rig pumps. NOTE: The wellbore will be swapped over to brine after the liner has reached TD to remove mud cake from the well bore. Mud cake will cause facility upsets. 16.18. Break circulation and circulate out the mud. Begin circulating at—1 BPM and monitor pump pressures. Slowly bring rate up while circulating the lateral clean. Displace well to—9.2 ppg KC1/NaC1 brine and over displace well by at least 100 bbl. Do not exceed 1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed befo e exceeding 1,600 psi. 16.19. Monitor pump pressures closely and adjust pump rate if the well appears to be packing off at t e swell packers (if run). Do not exceed 1,600 psi while circulating as noted above. Note all loss-s. Confirm all pressures with Baker. 16.20. Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAPP pill train with 50 bbl in between. Displace out SAPP pills. Keep circulation rate low to Page 34 Version 1 January 2018 S Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company keep from packing off around the ICDs (if run). Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. 16.21. Displace 1.5 OH+Liner volume. 16.22. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.23. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. 16.24. Continue pressuring up to 2700 psi to set the ZXPN liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the liner hanger to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4500 psi to activate the hydraulic pusher tool to set the SLZXP packer. This will also release the HRDE running tool. 16.25. Bleed DP pressure to zero. Pick up to expose Rotating Dog Sub and set down 50k#without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 rpm and set down 50k# again, 16.26. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.27. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.28. P/U pulling 2-3/8" out of the pack off& displace out liner with two liner volumes at max rate. 16.29. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. L/D 2-3/8" inner string. Leave enough 5"DP racked back to trip back to 9- 5/8" shoe. 16.30. M/U 3.5"wash tool &RIH w/remaining DP out of derrick to liner top. 16.31. Wash through liner top at max rate &circulate hole clean. Pump sweeps around. Displace well to clean filtered brine after no solids are returned. 16.32. POOH & L/D remaining 5" DP. Page 35 Version 1 January 2018 Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 17.0 Run 7-5/8" Tieback 17.1 R/U and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoul s er to be used for tie-back space out calculation. Install and test 7-5/8" (250/3000 psi) solid body casing rams. 17.2 R/U 7-5/8" casing handling equipment. • Ensure XO to DP made up to FOSV and ready on rig floor. • Rig up computer torque monitoring service. • String should stay full while running, r/u fill up line and check as appropriate. 17.3 P/U tieback seal assembly and set in rotary table. Ensure 7-5/8" seal assembly has x4 1"holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8"x 7-5/8" '— annulus. 17.4 M/U first joint of 7-5/8"to seal assy. 17.5 Run 7-5/8"29.7#VAM STL SMLS tieback to position seal assy two joints above tieback slee e. Record up & down weights. • Following running procedure outlined above. Page 36 Version 1 January 2018 S Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company Technical Specifications Connection Type: Size(O.D.): Weight(Wall): Grade: ST-L Casing 7-5i8 in 29.70 Ibift(0.375 in) -80 STANDARD Material L-80 Grade 80,000 Minimum Yield Strength (psi.) 11,1111g 95,000 Minimum Ultimate Strength (psi.) CUBA Pipe Dimensions VAM USA 7.625 Nominal Pipe Body O.Q. (in.) 4424 W.Sam Houston Pkwy.Suite ISO 6.875 Nominal Pipe Body La (in.) Houston. Phone:713 479-3240 0.375 Nominal Wall Thickness(in) Fax:713-479-3234 E-mail:VAMUSAsalesslvam-usa-tom 29.70 Nominal Weight(Ibs.ift.) 29.06 Plain End Weight(Ibs_ift.) 8.541 Nominal Pipe Body Area (sq. in.) Pipe Body Performance Properties 1.6 683,000 Minimum Pipe Body Yield Strength(lbs.) hit 4,790 Minimum Collapse Pressure(psi.) 6,890 Minimum Internal Yield Pressure(psi.) 6,300 Hydrostatic Test Pressure(psi.) Connection Dimensions 7.625 Connection O.D. (in.) 6.782 Connection I.D. (in.) 6.750 Connection Drift Diameter(in.) 4.39 Make-up Loss(in.) 5.550 Critical Area(sq. in.) 65.0 Joint Efficiency(%) Connection Performance Properties 444,000(1)Joint Strength (lbs.) 527,000(2) Reference Minimum Parting Load(lbs.) 10.910 Reference String Length(ft) 1.4 Design Factor 266,000 Compression Rating(lbs_) 4,790 Collapse Pressure Rating(psi.) 6,890 Internal Pressure Rating (psi.) 18.8 Maximum Uniaxial Bend Rating [degreesi100 ft] Recommended Torque Values 4.600(3) Minimum Final Torque (ft-lbs.) 6,000 (3) Maximum Final Torque (ft.-lbs.) Page 37 Version 1 January 2018 I S Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 17.6 M/U 7-5/8"to DP crossover. 17.7 M/U stand of DP to string, and M/U top drive. 17.8 Break circulation at 1 bpm and begin lowering string. 17.9 Note seal assembly entering tieback sleeve with a pressure increase, Stop pumping and bleed orf pressure, leave standpipe bleed off valve open. 17.10 Continue lowering string and land out on no-go. Set down 5 — 10k lbs. Mark the pipe at this depth as "NO-GO DEPTH". 17.11 P/U string&remove unnecessary 7-5/8"joints. 17.12 P/U hanger assembly and space out. M/U (or L/D) necessary joints and pup joints to position seal assembly 1 ft above "NO-GO DEPTH"whcn,tie-back hanger lands out in wellhead. 17.13 Ensure circulation is possible through 7-5/8" string. 17.14 RU and circulation corrosion inhibited brine in the 9-5/8"x 7-5/8" annulus. 17.15 With seals stabbed into SBE, Spot diesel freeze protection from 2500' to surface in 7-5/8"x 9- 5/8" annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent casing collapse of 7-5/8". Verify collapse pressure of 7-5/8"tie back. 17.16 Slack off and land hanger. 17.17 Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning rpt. 17.18 Back out landing joint. M/U packoff running tool and install packoff on bottom of landing joint. Set pack off and RILDS. Test void to 3000 psi/ 10 min. 17.19 R/D casing running tools. /t 17.20 Test 7-5/8"x 9-5/8"production annulus to 0 psi/30 min. 17.2 Set test plug and change top rams from 7-5/8"to 2-7/8"x 5-1/2"VBR. Test annular and lower rams to 2-7/8"test joint, 250 low/3000 psi high. Page 38 Version 1 January 2018 ! S Milne Point Unit F-109 Producer Drilling Procedure Hilcorp &ABBY Company 18.0 Run ESP Assembly — Upper Completion 18.1 RU spooler with ESP power cable and 3/8" capillary string. The capillary string should be fill,d with hydraulic fluid. 18.2 Verify the ESP components as per Centrilift. Verify that the length of the motor lead flat cab': will place the splice between the discharge head and the 10' handling pup collar. A Centrilift -p shall be on the rig floor at all times during the running of the ESP. 18.3 Makeup new ESP assembly with new motor lead extension, seal section and motor. 18.4 Run the 2-7/8" ESP Completion as noted below. The completion includes 3/8" capillary tube from surface to the pump intake. The capillary tune will be secured to the tubing with Cannon clamps. Function test the capillary tube every 2,000' by pumping—2 gallons of hydraulic oil through d e check valves. Record the pressure at each testing point 18.5 M/U ESP assy and RIH to setting depth. i. Ensure appropriate well control crossovers on rig floor and ready. ii. Monitor displacement from wellbore while RIH. • Centrilift ESP Assembly with bottom of assembly @-5,200' MD (Final pump set dept will be determined after receiving the definitive survey) • 10' 2-7/8" 6.5#, L-80 Pup Joint • 3 joints 2-7/8" 6.5#, L-80 EUE 8rd tubing • 2-7/8" "XN"nipple (2.313"packing bore/2.205"No-Go ID) • 3 joints 2-7/8" 6.5#, L-80 EUE 8rd tubing • 10' 2-7/8" 6.5#, L-80 Pup Joint • GLM 2-7/8"x 1" GLM w/dummy installed • 10' 2-7/8" 6.5#, L-80 Pup Joint • 2-7/8" 6.5#, L-80 EUE 8rd tubing • 10' 2-7/8" 6.5#, L-80 Pup Joint • GLM 2-7/8"x 1"w/ SO @—140' MD • 10' 2-7/8" 6.5#, L-80 Pup Joint • 3 joints 2-7/8" 6.5#, L-80 EUE 8rd tubing • Tubing Hanger Page 39 Version 1 January 2018 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company o Check the conductivity of electric cable every 2,000' and every new splice while running in hole. o Function test the capillary tube every 2,000' when checking the conductivity of the electric cable. o Use Cannon clamps on every joint to secure the capillary tube. o The make up torque values for 2-7/8" L-80 6.5# EUE 8rd tubing are: Minimum: 1,730 ft-lb, Optimum: 2,300 ft-lb, and maximum: 2,800 ft-lb. o The 2-7/8" L-80 6.5#EUE 8rd tubing performance properties are: Body Yield: 145,000#, Burst: 10,570 psi, Collapse: 11,160 psi. 18.6 Fill tubing while splicing cable, mid-cable splices and tubing hanger splices. After tubing is 11, break circulation by pumping 10 bbls down the tubing to clear any debris. 18.7 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along w' h band/clamp summary. 18.8 Install a brass-shipping cap on the ESP penetrator. Land tubing with extreme care to minimize damaging the ESP penetrator,pigtail and alignment pin. 18.9 RILDS and test hanger. 18.10 Install BPV and N/D BOP. 18.11 N/U tree/adapter and test tree. Terminate the capillary tubes. Pull BPV. 18.12 Circulate diesel freeze protection down 2-7/8"x 7-5/8" annulus (Volume should equal capacit of tubing to 2500' +tubing annulus to 2500'). Connect IA to tree and allow diesel freeze prot:ct to "U-tube" into position. 18.13 Set BPV. Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. RDMO 19.0 RDMO 19.1 RDMO Innovation Rig Page 40 Version 1 January 2018 • II Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 20.0 Innovation Rig Diverter Schematic - 111111 II not U 111111 1 „--..-- -----------13-518'5M Control Technology Annular BOP I___ J ID Pp Fa4 11) Fri or ® ----13.518'5M control i o Technology Double Rarn N0 OM 3118 KM line p•—M• %"r , _ 111 1 + ,`v'r �- Io, aril 1' - -3-118'Choke line 0 i. aerA-J =arm go 2 v--=, — ix ,i; ...---2 13-518'5M Control—/1 1- Technology Smgle Ram 13-518'x 5M —ILA 16 Diverter line \-2-1116 x 5M 61 k.20-Casing Page 41 Version 1 January 2018 J • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 21.0 Innovation Rig BOP Schematic (O O r� MMMir m -----'------13-5/8"5M Control Technology Annular BOP 1 r Imo_ =�� 'a' ` o j �I = ii il I. ME "' ----------13-5/8"5M Control = o Technology Double Ram D.-., r_-7 t.T.i 3-1/8"Kill Line .� n .4\111A—.....a–A, .. y! — %,�j% -----'`""_3 i/8"Choke Line F 7 o 1. r''`"---13-518"5M Control I Technology Single Ram 13-5/8"x 5M 11"x5M l [or qv aj Ilk %Ilk 9-5/8"DBL D Seal-' _ .10' "�►'11 111t1 � 2-1/16"x5M Casing Hanger _'1� �_D ¢��' �l 13-5/8"x 5M S-22 �w �w' 13-5/8"NOM 9-5/8"BTC Btm x 2-1/16"x 5M / 10.5"-4 SA Pin Top WI Primary Seal7 20"Casing 9-5/8"Casing Page 42 Version 1 January 2018 • i IllMilne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 22.0 Wellhead Schematic ADAPTER.4-4-M, f } TU81 NC HANGER,1C-4.OAS_ / + :I-5X 2100 BTM x4 1212-51,STDG ALF F 17-420 0QN4., OMR}4'7-,15 74)EEE 4 1:'2 6T8F.6400 DTV v 'a PE14oSC-0002 4 2 918$TOP It,0 T,1,5 ET,47 9 �.--TUBING NEAR SEETIEH 1551'. 8 2 P:000002897 - .=i ' 1 .80 TNRU•4011E. I 2 .--c' X 14-STE4f t.BTM �' F H 94 54 TOP t ,47 I - �,� PI?0190-od08 ,3.00 �■ ®, f III2 I Ilb-51,MI20 Po§r:GV c+ 11111 2602 r' t •- 1 ! r 57.T8 PAC OFF,A-15 NM Imo,:. I7.74)@3YL 0 T - 561446 EELTISN 5554, '..-a,®... 2 155.015 v .. . *. w ', 40.300 8041.. 1 •:wx« �... i • Y42 INCH NW TAPER Y-iQ-M SEA.914 .� 4 11-se TLG 4E0 ,I F- " 91000+5 rebs ,355 1111 ,``s; _l 11111 "� !.,5-5/ 41212 PISS CI 722146 IANC)R,C-71—^ ..– _ ,,.'l^ �_ 1030 X 7 1 ♦ f `I 12-04!-112 ■ 2.T5 1 ..1.i.:ii i Asirf ) i ill _64� ,O—CASN1,45110;44.MAMOFi5L,FLUTED —_-•m Fi 10,380 80Wt, BELT NIPftE. 1 ISA 553 26-o LA'CT IFIN1Y 9 5;8 509 W; TP . 4 8.000,4 116-2C-lm 00:100 taw 1925X 4,10-M SEAL TOP - P1000:24545 048334-5705 �$ OAEING X4E4EH 1404071EL.L 4E40114C PINS, 47.22 155400,F! 15.27 8045.. 0,45 4.62S 1514 555 140 LB/F Ti lit X 020044 HANGER,0.21 -.,- 1.1! '9'i . 40.220-i 56412-2C-LX FFA. ' 155.25 BOWL Y' 5 Sze ( 'v. .... Si}IA*004114-10-10 SEAL,PREP iCW , M+€TER-000N OE. PIOCAI 124695 12-090-ice �V E [ LAIDING RING I 11. Eq I6 504 BtY PREP A 3 1500 51174 45444 TOP. +413.p440-F10FG+ t5.2112010 It ...,ii ( I 1N= 9 519.OD 7044417 I 4 1;t'00 184 GEN 5 SL Pi HOLE .—___------ 2.3 9 5/E X . 5,,.E X 4 1,`2 a0TE LA101JT PET;012100153343 PRIVATE A.HL'1 (LIIJI1 DEN F I As_ 0E5751414125 3..00 Pelt.,'2+:4n.'IJ4..T ern r\M .ewnt. cIt wren 111.n r ov.m,+nu ua c•cL .w SURFACE WELLHEAD LAYOUT CP,\FTrv4)04:0221 )41ir r .__...T. ..._ 4 gbp{�eII M i, D+n4.. 44 a*It 0*exm.una [ ❑❑ y� dd t-• Z.MARQUEE IO-25-17 000.60.6.46 WE 46650 4P w1VA Pkat ID 4XHe51 4:1102 I4 x Th� x 7 x 9 } i! w,045 41 41 B. 4441 lt_17 La 0.04t.s A713*5 m CAST}�G PROGRAM. aE51G4 4En[AI '"' `xTE:.. �xLE1 SKE 4Et`P1Et�1 FEPswv1 Io 4w[E E 1011+4 I.tr•o«u C,Mct�fLI i€a-25-!7 NA ...,—111 70 Ant'. 4714410 4 4114 _ .. 15K x 4 1.16 5R. 4.6602A 000\{E4C5 MAI AFl1Ctf5 M«It 1.ttM.ORK[F*+.DOM YAINRACTUPAaG\iFFt7kM: 9A TE, Gei ILP@Ep pE4. 91414*4r S.C.I.BE Efrt�OFEP 1Wm4i 4:4 E4.S1M AHl cut 40.010.46514*w*414 .44464 42444 40 40 24444.6,640 IQ-L5- r" A A1io.¶14 1rs[14 i.t4 IN wWIF4LTU*44 40 w.onyx 114040 µ''94h lI 0444, IR4AwE 4@441EP 44)40 pti11'Iry 2466#tn4es,.om,.4I v44,m m T.rhNell24. { J.[ARwA r(I-75-37 OM100217004 I EI I.I.2222 2222. 1 .,-2«2,22,... 2222.. CCP010,0 1460240g Page 43 Version 1 January 2018 I Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 23.0 Days Vs Depth MPU F-109 SB OA Producer Days vs Depth —MPU F-109 SB OA Producer 2000 4000 — 6000 ru 8000 — 1 2 I 10000 I ; j 12000 14000 0 5 10 15 20 25 30 Days Page 44 Version 1 January 2018 410 Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 24.0 Formation Tops & Information UPDATED FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 1643.20 1606.00 1779.89 SV4 1868.20 1831.00 2119.79 Base Permafrost 205520 2028.0 2436.94 SV1 2734.20 2697.00 3513.98 UG3 3398.20 3361.00 4585.69 Ugnu LA3 3914.20 3877.00 5578.65 Schrader NA 4075.20 4038.00 6449.30 Schrader OA GENERALIZED GEOLOGICAL FORECAST TVD FM UTM GEOLOGICALCOMMENTS DESCRIPTIONN moue. f1 NOTE:See Individual Well Program for twi..ra Cwbik specific casing design,depths,sizes. *1-lor. ggg weights.grades and connections. • g • Unconsolidated coarse to medium sand and small grew! with minor siltstone. 1,000' S IF SIGNIFICANT AMOUNTS OF GRAVEL ARE ENCOUNTERED WHEN DRILLING THE ° SURFACE HOLE,THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE • • EFFECTIVE HOLE CLEANING. 1750'---- Base permafrost Interbeds of sand,clays and silnstones with occasional 2,000' show of coal. Saga's rktok No hydrates encountered on F-Pad wells drilled to date. Continued Interbeds of sand,clays and sinstones with occasional shows of coal. Interval at*1-3400 ft can be 3,000' sticky and tight Clay interned between 3000 and 4500 ft. • C Traces of pyrite at+4-3100 f1(Lt, 3472, L 3esr A weaves v UGNU:Sodas of coarsening upward sands which are IdB,CDI made up oh (from top to bottom)coarse sand,line sand, silty shale.Better dswloped intervening shales as you UGNU progress Meath*L and u(deeper). Ugnu and Schrader Bluff:Possible hydrocarbons limited Leaves to SW corner of Milne development. Northern area is IAs; downstructureand wet(F50 had oil!). 3739' Wsams t-A,B.G: 4,000' Schrader Bluff Sands: Schrader Bluff: Possible lost circulation 3800' tea. cp Continued layering coarsening upward sands as above zone while drilling long strings and running 4160' E.FI except more condensed and with occasional coal. (NA) Clay rich shale interval 4300 to 4000 rt. casing. Recommend deep setting surface Schrader Ugnu and Schrader Bluff:Possible hydrocarbons limited casing for Kuparuk long strings. Also,the to SW corner of Milne development.Northern area Is Schrader Bluff sands are a potential Bluff downstructure andwet(F•50 had oil!). 40e0 differential stuck pipe interval if left.un-eased 4320'Sands: t. for Kuparuk long strings. If drilling over- (OA) o.Sand pressure Kalubik wells,plan on covering all o.E,F; Surface caning point In shah below lower Ugnu sands with deep set surface 427°. TO Of -- Schrader Bluff OB sand for longer reach wells. casing. Over-pressured Kalubik intervals are 44°0• P found on C,L and F pads. Seabee Page 45 Version 1 January 2018 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 25.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lo.t circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Historically, no gas hydrates have been seen on 'F' Pad. Remember that hydrate gas behave differentl• from a gas sand. Additional fluid density will not prevent influx of gas hydrates. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Add 1.0—2.0 ppb DRILTREAT to the system to help thin the mud and releas- the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor EC D s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods o f time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 46 Version 1 January 2018 411 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requireme its of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. 8-1/2" Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore,pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotati on after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of> 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lo.t circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least(1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a"ramp" in the wellbore to aid in kicking off(low siding) later. Once a fault is crossed, we'll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm durint drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requireme is of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: There are no abnormal pressures or temperatures observed on this pad. Page 47 Version 1 January 2018 4 Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 26.0 Innovation Rig Layout 170'-3 " if (, • ! I I Ifi.T I 1 Ici ; „ - — I u E _1 I III 1{q :V 1 -'���" ' 4 Ilei ; ' fii ii 11 « , it E` I - �- 7 Ir . , • ,, xI 1. � ..„_ �— VIIIA HAK 2 FOOTMr.11 V PRINT I . .,, l05/21/16 --- --- - "--ld �� a.. . . !di- ,A.,„ 1L I ,�, IR1NJ 113'-111 . ... 36'-1 " Page 48 Version 1 January 2018 Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 27.0 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) s. 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 stabiliz-s. 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 EM at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of k ck 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 flu d; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and press e monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document increme al volume pumped and returned during test. Page 49 Version 1 January 2018 • M F-109ilne Point ProducerUnit Drilling Procedure Hilcorp Energy Company 28.0 Innovation Rig Choke Manifold Schematic 4IPLI J n El 10---n �1)---ate-p al #—� p d 1)--0G--q c c litilb 4,...,z las . , . , nI - - 11 iliiin I,I, El • AV�I —p tl p 11110.6/6, illi- 11 I1' \ . . 2-4%le-SMB82D4 - - 2-kk78 5A76B709 --�►r... k. ^� Poor Bae Varves - - Pcor EaS Valves Sl n—. .\ IIt ,,.a � ii.,-_D0 r iJ [ t3* I 14 s l ][ , j Page 50 Version 1 January 2018 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 29.0 Casing Design Calculation 8, Casing Design Factors DATE: 0112412018 WELL: MPU F-109 DESIGN BY: Joe Engel Design Criteria: Hole Size 1244" Mud Density: 9.2 ppg Hole Size 842" Mud Density: 9.2 ppg Hole Size Mud Density: Drilling Mode MASP: 1387 psi (see attached MASP determination&calculation) MASP: Production Mode MASP: 1387 psi(see attached MASP determination&calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress(0.494 psi/ft) and the casing evacuated for the internal stress Casing Section Calculation/Specification 1 2 3 4 Casing OD 9-518" 442" • Top(MD) 0 6,355 Top(TVD) 0 4,068 Bottom(MD) 6,505 12,203 Bottom(TVD) 4,080 4,030 • Length 6,505 5,848 (PP) Weight f 40 13.5 9 • Grade L-80 L-80 Connection DWC H625 Weight Ino Bouyancy Factor(lbs) 260,200 ; 78,948 Tension at Top of Section(lbs) 260,200 78,948 Min strength Tension(1000 lbs) 916 i 279 . Worst Case Safety Factor(Tension) 152 3.53 Collapse Pressure at bottom(Psi) 2,016 * 1,991 Collapse Resistance odo tension(Psi) 3,090 8,540 Worst Case Safety Factor(Collapse) 1.53 4.29 MASP(psi) 1,387 1,387 Minimum Yield(psi) * 5,750 * 9,020 * Worst case safety factor(Burst) 4.15 6.50• , Page 51 Version 1 January 2018 • 41 Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 30.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 812"Hole Section Hilcorp MPU F-109 Milne Point Unit MD TVD Planned Top: 6505 4080 Planned TO: 12203 4030 Anticipated Formations and Pressures: Formation TVD TVDss Est Pressure ❑ilIGaslWet PPG Grad Schrader Bluff OA Sand 4,080 4,038 1777 Oil 8.46 0.440 Offset Well Mud Densities Well MW range Top(TVD) Bottom[TVD] Date L-50 8.8-9.1 Surface 4125 2015 L-49 9.0-9.2 Surface 4196 2015 L-48 8.9-9.2 Surface 4147 2015 L-47 8.8-9.0 Surface 4158 2015 L-46 9.0-9.3 Surface 4177 2015 L-37(1998) 8.9-9.3 Surface 7,050 1998 L-35(1997) 8.4-9.2 Surface 5,687 1997 L-34i (1997) 8.4-9.4 Surface 5,842 1997 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density for the 812"hole section is 9.5 ppg. 3. Calculations assume Full evacuation of wellbore to gas Fracture Pressure at 9-5+8' shoe considering a full column of gas from shoe to surface: 4080(ft) x 0.78(psilft)= 3182.4 3182.4(psi) -[0.1(psi?ft)''4080[ft]]= 2774 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff OA sand) 4080[ft] x 0.44(psilft)= 1795.2 psi 1795.2(psi) -0.1(psirft]"4080(ft) 1387 psi Summary: 1. MASP while drilling 812"production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psilift. Page 52 Version 1 January 2018 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 31.0 Spider Plot (NAD 27) (Governmental Sections) 11 `.___ `` ----,===_,-,--,_ .+� ♦ -41,,,,,,,.„\., 1 sill t{' tv I r a/ t r J L.:±=E ly `..a ,`i,,a` 1lti i1,1 r ,4a ! { A tr/ .. - , `y` _ '. „ alaa ct ., f k 1'y, �I d/ t t ,, ., r f , I, 1 ` _ • •A` 4al,,, �: aa.,t tlpl,I+ r '/,�, fr )r s 1. �♦ �l.`.,`syr 4.11 N .,10 1 1 41 r { l_ ij 41 et11 ,_ e SEC 1 ' -"'-''rt Sec.6 l'''...1: `c t l - �a z y 1--C3-c3 ate " '" .,� ';,.412 ,,'r ! PUF-10�APro&)_SHL �', `{ / are `• '+ `O▪tt}' � r/ t i y, ,t • 1 o `/ X41` 1 !'ti i,'v• a` 4t t4 .477 54=ADL388235 . '\'`--4ADL025509-. 4ti '• ', ' 1y4 4,j' VI r r aa 1 4 fl1 APE' ' `'• + , 0 `K , , ! , f r , 1 MILNEPOINFUNIT 2..1PiF-109(OAProdwa) TPH '''',0',.:::::.,• e'g. sec 7 U013N1010E' •� f _c 0' Sec v / eV Sec.12 *4'•. {62B) r - o - f•' ' f O • r' • '/ ,f r/' /� 1 a - • /r f' r, 1 1 -/ C • ' ' r�' rr/r / //r 1' ' { a !,! r, r r/ , i, r 1r 0t,i f i' r 0 ,t t e 1 , t /f n r� I II O% •' X{ fr r' �d// !^ III` Legend ,, `la o tt , „:J/ 4♦ 1'I • MPU F-109 SHL • Other Surface Holes(SH-, f 11_, f'v,r' •` 'I X MPU F-109 TPH + Other Bottom Hoses{BHLi '�� baa ' r�'*"-r'' I ___. i G.......................... /i 3 L'1eFr t C. —Other Weil Paths , ;tom { ' - MPU F-1DS_BHL O Oil and Gas Unit Eco a-y ,' rry a e `{';I r' `s I o r '' \� , Fad Footprint 1 f 1 'r r ° ! �4 f�, • r r ,-a ,t ro r!f' It r , a.11 as { ' ' ' =i.ti•`.,tt�ES,c..t� / at ' i `I is`,. 'r r' t r 10 ADL025514 Se_ 13f '.ADL0255151' ,' _i.` 1,°o r sec.t? ._ . r r r ffUF-109(OAProdacer)_BM.., ;▪, E: { •„ + • Ell Milne Point Unit T MPF-109 well 0 1,000 2,000 „ar Cate,ie_3,iw,P_09 Feet Page 53Version 1 January 2018 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 32.0 Surface Plat (As Built) (NAD 27) T14N 1 _ __.. . __.-1 13 N I i 1 - NF_ lAC 1 3'.IR 71 .. \ SON OON tf v w OR 7.,' 0 6 5 4 R = °`1 il -~ I .£ L.. PA01CT F-1061 €-107 ._� -F-11161 + ^ LPAD F-109F-110'1 ♦ VICINITY MAP I N.T.S. / / // �`%%�t11<111 m*...,, 9111 N '. . a'`- 1$, 'I = r, i • , 0Q I.-La .. othy F. !.. , . ...il .. �'\I � !i kl i k c. 10200 `-�_ NOTES + 1 j{ Cal sSIOW, %I.` 1 sTAT P.AAF C0ORONATES ARE NAD27,ALASKA,ZONE 4. LEGEND ".!„ 1, \1A‘‘' 2. 6AS5 or LDCA-ION S MILN E PONT F PAD OPERATCR #A5-BUILT CONDUCTOR MORLMENrs SURI Y ;'S .CERTIFICATE 3 OASIS O=ELEYA1ON IS MLHE PIY4T F PAD OPERATOR a EX51114G CONCXJCTD9 I HEREBY CERTIFY THAT I AM MO,AMENTS PROPERLY REGISTERED AND LICENSED TO PRACTICE LAND SJRY611ND IN 4. E.EYATHIN5 ARE O=xR MEAN 5£A LOU.DATUM. THE STATE OF ALASKA AND THAT 5 CECOETIC ODCICINATES ARE NAD27, THIS AS-BUILT REPRESENTS A SURVEY MADE BY ME OR'JNCER MY DIRECT G PAD MEAN SCALE FACTOR IS D99990195 GRAPHIC SCALE 5IFERN519N AND 1HAT ALL 7DIMEN. CRAWL EXPANSEN AREA NOT SURVEYED,0ESCN 0 30 100 207 CORRECT IONS AND (*COOV-ILIM DETAILS ARE CINENSICNS USED FGR VISUAL KAMM& C IECT AS OF CECEMITER 20, 2077 9. REFERENCE FIELD DOCK: NC17-03,PGS,60-67. I N FEET) 9. CATE CF SURVEY:DECEMBER 20 2017, 1 WO A.106 11. LOCATED WITHIN PROTRACTED SEC. 06, T. 13 k., R. 10 E.. UMIAT MERIDIAN. ALASKA WELL A.S.P. PLANT GEODETIC GEODETIC SECTION PAD CELLAR NO. COORDINATES COORDINATES POSITIONWMS) POSITION(O_DD) OFFSETS ELEVATION BOX EL. Y= 6,034,949.46 N= 9,575,31 70'30'23.067" 70.5064075' 1,500' FSL F-1061 , 10.9' 10.8' X= 541,330.84 E. 4,879.35 149'39'42.710" 149.6618639' 3,237' FEL Y. 6.034937.43 N=9,560.45 70'30'22.949" 70.5063747" 1,488' FSL' F-107 X= 541 322.13 E= 4,879.20 149'39'42.969" 149.6619355' 3,246' FEL 10.9' 10.8' F-1DSi Y= 6,034,900.70 N= 9,515.39~ 70'30'22.589" 70.5062747' 1,457 FSL 10.8' 10.6' X= 541,296.04 E. 4,879.15 149'39'43.743" 149.6621508' 3.272' FEL -F-109 Y= 6,034,863.78 N=9,470.24 70'30'22.227" 70.5061742` 1,415' FSL 10.9' 10.7' X. 541,270.05 E= 4,879.29 149'39'44.515" 149.6623653' 3,299' FEL F-110> Y= 6,034,851.59 N=9,455.43 70'30'22.108" 70.5061411' 1,403' ESL 10.8' 0.T X- 541,261.54 E= 4,879.47 149'39'44.765" 149.6624347' 3,307' EEL xLEb1 b111 '. Nd LAWAY 11Hilcorp Alaska __._._. p..12/23/17 �ItniAAN 711or m MPU F-PAD •" AS-BUILT CONDUCTORS a {W .,�,,xl" a t a 1 "' +.c.„,,.w.w.mA 4Aa , 1.IDV Page 54 Version 1 January 2018 • • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 33.0 Schrader Bluff OA Sand Offset MW vs TVD Chart Schrader Bluff OA Sand Offset MW vs TVD MW,ppg 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5 0 500 1000 1500 - MPU L-46(2015) MPU L-47(2015) 2000 MPU L-48(2015) MPU L-49(2015) 2500 MPU L-50(2015) 3000 3500 4000 4500 Page 55 Version 1 January 2018 • M F-109 ill no ProducerPoint Unit Drilling Procedure Hilcorp Energy Company 34.0 Drill Pipe Information 5" 19.5# S-135 DS-50 & NC50 Drill Pipe Configuration Pipe Body OD n n:5.000 80`,4,Inspection Class Pipe Body Wall Thickness tri)0.362 Nominal Weight Designation 19.50 Pipe Body Grade 5-135 Drill Pipe Approximate Length 31.5 Drill Pipe Length Range2 SmoothEdge Height an,(3132 Raised Connection GPDS50 Tool Joint SMYS x 120 000 Tod Joint OD 6.625 Upset Type EU dJoint ID n'3.250 Max Upset OD (DTE) r:5.125 Pin Tong 9 Friction Factor 11 A Box Torg l n. 12 Mae.Tara scare may Include bme'aclr1. Drill Pipe Performance Drill-Pipe Length Range2 Irformance of Drill Pipe with Pipe Body at Best Estimates ( Nominal 60%Inspection Class tatK'd Cr0tna1 (ws,cwdrrg) (least accurate l Myra,,,, Drill Pipe Adjusted Weight Obvert,24.11 23.29 Operational Max Tension , t-.abs; Torque in_Ibs? Imn) Fluid Displacement tca.nn 0.37 0.36 Tension Only 0 560,800 Fluid Displacement ':Bb=aril 0 DOES 0.0085 aonna'r +u'43,100 c m� ioaa �39,600 410,500Capacity 1 Fluid tgatq 0.71 0.70 0.72 Fluid Capacity mown,0.0169 0.0167 0.0172 36,100 Tension Only 0 564.800 Minimum MUT Size um 3.125 cpmaneb t.oaaria 32100 467,400 Note 01.field barrel equals 42 US satire's. hole:Dell ripe assembly values are best eobrnates one may vary due to ripe lastly mill loerarce,Internal plasm coaling and other localts. Connection Performance GPDS54 ( 6.625(n} OD X 3.250 tri) ID ) 120,000 Imo ArpledMaeauup Ters.omateawtde- TenslcoaTcrrneaor ToolOD Joint Dimensions To-que Separmnr Veld in-os? Host obs, Balanced dr.:6,435 Maximum Make-up Torque 43,100 Tensile Limited 1,046,900 Mlnrnun Tod Jamb 00 kif API 5,930 M,,rimum Make-up Torque 36,100 1.202,500 1.250.000 Prc k n°la"' `,, ------ tic,The ira.er:ium makeua ions .e shct,ld be applied oilerrossbe Mtramlfi,Tod JdM 00 s. 5.93 hex T:reaxl-,Se esene[tm opeta:anal lensle,a 1.4:571141.37,5CC Mitts;should be applied .:.ounterbaro OM Tool Joint Torsional Strength tn-tel 71,800 If Tool Joint Tensile Strength me 1,250.000 Elevator Shoulder Information Elevator OD 3f32 Raised 6.812 In) 7 SmoothEdge Height Nominal Tool Joint Worn to Bevel Worn to Min TJ OD for 3132 Raised OD Diameter API Premium Class Box OD 6.812 6.8.25 6.063 5.930 Elevator Capacity anon 1,658,000 1.440,204 823.600 685,600 No, Elevator capacty rases on assumed Ereva cf Bore,ne wear roam.and Contact stress of 11O,tOCpsi (Assumed Elevator Bore Diameter rn 5.219 rime A raised eevalol lac II-creases ele.m_r cocas*,.-non aner:,,o make-up torque Pipe Body Slip Crushing Capacity Pipe Body Configuration( 5 OD 0.362 t,) Wall S-135) Nominal 80%Inspection Ciass API Premium Glass Q/ [Slip Crushing Capacity ted;498.300 396.500 396.500 t / tomSMp.:sans-sSsm_bles load,canialcsettt Tx Ftrr-Peetsad0230r l'>: eVhy Sees D'1'Pre f Assumed Slip Length (n316.5 Faun',SIP ken'Wont CC ISIS Se dee s(leedS as bairmae see SAS harlot ave al:11 to refe'e'ae Transverse Load Factor IX) 42 ar,.atr._nirng seedersn seta-t rSr dsamandcrrenar,raexmdnm lineskoarsea-ebb, -e e ass rim OD and viol lah000,and cels'adds Cwu2t Mn the s Id nu'mx:.rer for adrnx-at rro-ratire. Pipe Body Performance Pipe Bary Configuration( 5(ri) OD 0.362 In) Wall S-135) Nominal 80%Inspection Class API Premium Class Pipe Tensile Strength •ars?712,100 560,800 560,800 , Pipe Torsional Strength :r-m-,,74.100 58.100 58.100 TJiPipeBody Torsional Ratio 0.97 1.24 1.24 80%Pipe Torsional Sreny t' ':n-ma,59.3.00 46.500 46.500 Burst roil 17,105 15.638 15,638 Note:Nominal Buri: Collapse ,P,-, 15.672 10.029 10.029 cacutated at a?sib Rew per API Pipe OD orf 5.000 4.855 4.855 Wall Thickness ,n,0.362 0.290 0.290 Nominal Pipe ID tin)4.276 4.276 4.276 Cross Sectional Area of Pipe Body .i-i": 5.275 4.154 4.154 Cross Sectional Area of OD ti"21 19.635 18.514 18.514 Cross Sectional Area of ID un=i 14.360 14.360 14.360 Section Modulus (043)5.708 4.476 4.476 y i Polar Section Modulus (N.'Si 11.415 8.953 8.953 Page 56 Version 1 January 2018 • Milne Point Unit F-109 Producer Drilling Procedure Hilcorp Energy Company 500204050016200 Weatherford 5" 19.50 lb/ft S-135 w/ NC 50 6-5/8" OD x 3-1/4" ID Tool Joint DRILL PIPE SPECIFICATIONS Grade S-135 Connection NC 50 Interchangeable With 5'XH &4-1/2" IF Upset Type IEU Nominal Weight per Foot 19.50 lbs Adjusted Weight With Tool Joint per Foot 23.08 lbs TOOL JOINT DATA Outside Diameter 6-5/8' Inside Diameter 3-1/4' API Drift 3-1/8" Rabbit OD, Suggested 3-1/16" Minimum Make-up Torque 25.900 ft-lbs Maximum Recommend Make-up Torcue 26.800 ft-lbs Torsional Yield Strength 51.700 ft-lbs Tensile Strength 1.269.000 lbs TUBE DATA New Premium Outside Diameter 5.000" 4.855' Inside Diameter 4.276" 4.276' Wall Thickness 0.362" 0.290' Cross Sectional Area 5.275 sq in 4.154 sq in Maximum Hook Load/Tensile Strength 712.000 lbs 560.800 lbs Slip Crushing 1 Slip Type (SDXL) 572.100 lbs 453.500 lbs Burst Pressure 17,100 psi 16,100 psi Collapse Pressure 15.700 psi 10,000 psi Torsional Yield Strength 74.100 ft-lbs 58.100 ft-lbs Capacity W/Tool Joint 0.726 US gal/ft 0.726 US gal/ft Displacement WI Tool Joint _ 0.353 US gat/ft 0.322 US gal ft Excessive heat or pulling when tube is torqued can cause the maximum pull to decrease. Where possible all figures are obtained from OEM data source. NOTE: Weatherford in no way assumes responsibility or liability for any loss. damage or injury resulting from the use of the information listed above. All applications are for guidelines and the data described are at the user's own risk and are the user's responsibility. Page 57 Version 1 January 2018 • Hilcorp Alaska, LLC Milne Point M Pt F Pad Plan: MPU F-109 MPU F-109(OA Producer) Plan: MPU F-109 WP09 Standard Proposal Report 15 January, 2018 HALLIBURTON Sperry Drilling Services ! i HALLIBURTO REFERENCE INFORMATION WELL DETAILS:Plan:MPU F-109 iii:I I i I co r!) Co-ordinate(N/E)Reference:Well Plan:MPU F-109,True North Ground Level: 10.70 ' Sperry Drilling Vertical(TVD)Reference:As-Built @ 37.20usft(Innovation) ON/-S +E/-W Northing Easting Latittude Longitude Measured Depth Reference:As-Built @ 37.20usft(Innovation) 0.00 0.00 6034863.78 541270.05 70°30'22.227 N 149°39'44.515 W Calculation Method:Minimum Curvature Project: Milne Point Site: M Pt F Pad Well: Plan:MPU F-109 SECTION DETAILS Wellbore: MPU F-109(OA Producer) Design: MPUF-109WP09 Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Hilcorp Alaska,LLC 1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.00 • 2 325.00 0.00 0.00 325.00 0.00 0.00 0.00 0.00 0.00 Calculation Method:Minimum Curvature 3 2045.00 51.60 225.50 1821.74 -507.15 -516.08 3.00 225.50 412.75 tem:ISCWSA Sc Method:Closest Approach 3D 4 4280.00 51.60 225.50 3210.01 -1734.83 -1765.37 0.00 0.00 1411.92 EnSurface:Elliptical Conic Warningng Method:Error Ratio 5 5000.00 59.30 182.38 3631.38 -2259.22 -1986.81 5.00 -91.00 1891.41 6 5350.00 59.30 182.38 3810.07 -2559.90 -1999.32 0.00 0.00 2185.66 �- • - � 7 6049.04 83.09 155.15 4037.67 -3194.74 -1861.72 4.99 -52.62 2834.62 o- 8 6206.67 85.00 147.48 4054.05 -3332.16 -1786.51 4.99 -76.33 2982.76 Start Dir 3°/l00':325 MD,325'ND 9 6506.67 85.00 147.48 4080.20 -3584.16 -1625.84 0.00 0.00 3258.27 MPF-109 wp08 Heel - --- 10 6617.81 90.56 147.48 4084.51 -3677.76 -1566.16 5.00 0.02 3360.60 450- 11 12203.75 90.56 147.48 4030.20 -8387.71 1436.52 0.00 0.00 8509.84 MPF-109 wp08 Toe _ 500 900- j000 UPDATED FORMATION TOP DETAILS SURVEY PROGRAM _ NDPath NDssPath MDPath Formation Date:2018.04-2172018.04-21700:00:00zlo:oo:ao velia.00.r°° version: _ 1643.20 1606.00 1779.89 SV4 Depth From Depth To luny/Plan Tool 1868.20 1831.00 2119.79 Base Permafrost 28.50 5510.00 MPV F-108 WP08 2_MWD0IFR2O Soueg to 1350- 150p End Dir:2045'MD,1821.74'ND 2065.20 2028.00 243694 SV1 8510.00 /2203.75 MPU F-108 WPoB 2 MWDoIFR21.SoS.g 2734.20 2697.00 3513.98 UG3 p - 3398.20 3361.00 4585.69 Ugnu LA3 SV4-- 391420 3877.00 5578.65 Schrader NA CASING DETAILS 4075.20 4038.00 6449.30 Schrader OA a1800-_ Base PermafrostND MD Name Size Q 4080. 05 6505.00 95/8"x 12 1/4" 9-5/8 -rpt 4030.20 12203.75 4 1/2'x 8 12" 4-12 TS' - SV1 '17 ,�y ecENdd odd 2250- ^ 5tLOQt�- �t�.tet`0 $1 O • eta 2 eti5 ' s'o- s°+° ~ 2700- UG3- 'OP o\t�lhcp' 3, .1J0 p1e(4°' gll ►� Ot.. `'0, r04‘5'hy�eo1�0 s'OC) 3150 FS5 1¢t O, O, Ugnu 1H3--- F ' ,k'COA t.61�6T o,h . 11' Total ao�' �gp �t�v tt5 t� O\t:05 Total Depth:12203.75' D,4030.7 NE 3600- "" s,.d� g MPtA-109 WP09 - 1 / $, ' 12204 4050- Schrader NA _ - Q Schrader OA 4 $ o o 8 o $ c 5 0 1 4 2'x812" - 95/8"0121/41 MPF-109 .08 Toe 4500- MPF-109 vp08 Heel I iliililillirriiiiiiiiiriiiiiirririllfrirrliliirriliriirJ1111111111111liiipTr iiiliill11111111H r , SII 0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400 5850 6300 6750 7200 7650 8100 ;550 Vertical Section at 170.28°(900 usft/in) S! • HALLIBURTON Project: Milne Point WELL DETAILS: Plan:MPU F-109 Site: M Pt F Pad Ground Level: 10.70 Sperry OriilIng Well: Plan: MPU F-109 +N/-S +E/-W Northing Fasting Latittude Longitude r Wellbore: MPU F-109(OA Producer) 0.00 0.00 6034863.78 541270.05 70°30'22.227 N 149°39'44.515 W 1�1����1I,Y�11 Plan: MPU F-109 WPO9 REFERENCE INFORMATION I Co-ordinate(WE)Reference:Well Plan:MPU F-109,True North Vertical(TVD)Reference:As-Built 37.20usft(Innovation) Measured Depth Reference:As-Built CO 37.20usft(Innovation) Calculation Method:Minimum Curvature CASING DETAILS 0— Ao TVD TVDSS MD Size Name ils 4080.05 4042.85 6505.00 9-5/8 9 5/8"x 12 1/4" <sa,o 4030.20 3993.00 12203.75 4-1/2 4 1/2"x 8 1/2" -600— Ie sP 2000 Start Dir 3°/100':325'MD,325'TVD 22'r0 End Dir:2045'MD,1821.74'TVD -1200— 2�oa 2� �Qy -1800-- 'kms,_--UU---Start Dir 5°/100':4280'MD,3210.011VD 3500 End Dir:5000'MD,3631.38'TVD-Start 350'Pump Tangent Hold -2400— Start Dir 4.99°/100':5350'MD,3810.07TVD-End 350'Pump Tangent Hold 3750_____-- . End Dir:6206.67'MD,4054.05'TVD -3000— 401 Start Dir 5°/100':6506.67'MD,4080.2TVD -- End Dir:6617.81'MD,4084.51'TVD -3600— 9 5/8"x 12 1/4"- ---- - - MPF-109 wp08 Heel y - o -4200— + -4800— o - • -5400— o rn -6000-- -6600— _ -7200- -7800— x9� 9 XQv -8400— MPF-109 wp08 Toe- Total Depth:12203.75'MD,4030.2'TVD - 4 1/2"x 8 1/2" -9000- -9600- -10200— I I f 1 1 I l I I l l l l l l l l l l l l l l l l l l l l l l l l l l l l l l l l l l l l l l l r l r -3000 -2400 -1800 -1200 -600 0 600 1200 1800 2400 3000 3600 4200 4800 West(-)/East(+)(1200 usft/in) el Halliburton -IALLIBURTDN Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU F-109 Company: Hilcorp Alaska,LLC TVD Reference: As-Built @ 37.20usft(Innovation) Project: Milne Point MD Reference: As-Built @ 37.20usft(Innovation) Site: 'x M Pt F Pad North Reference: True Well: 'Plan:MPU F-109 Survey Calculation Method: Minimum Curvature Wellbore: MPU F-109(0A Producer) Design: MPU F-109 WP09 _> 1 Project Milne Point,ACT,MILNE POINT V 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 M Pt F Pad,TR-13-10 rY•" , •- «,..,., _•. .» Site Position: Northing: 6,029,958.49 usft Latitude: 70°29'34.438 N From: Map Easting: 531,814.44 usft Longitude: 149°44'23.616 W Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.25° �;.. ._.._.: a -�.,w_.: _.,,_.:�. Asa . ,, :...: ..•F...:,� 'Well Plan:MPU F-109 Well Position +N/-S 0.00 usft Northing: 6,034,863.78 usft Latitude: 70°30'22.227 N +EI-W 0.00 usft Fasting: 541,270.05 usft Longitude: 149°39'44.515 W Position Uncertainty 0.00 usft Wellhead Elevation: 10.70 usft r Ground Level: 10.70 usft MPU F 109(OA Producer Model Name • Sample Date Declination ) Field Strength (°) t :t-.,::-..1 (nT) BGGM2017 1/15/2018 17.34 81.03 57,489 ® ign ' "-� MPU F-109 WP09 ,sa:..:.......... .a :...- :,a _Y;- s:e..4..::. - :..: .<-:me...x ,.r,.., ,..,ux t>._=.:....d' Audit Notes: Version: Phase: PLAN Tie On Depth: 26.50 4 �Depth From(TVD) t ' ��k ; Vertical Section: '�� ` � 1-1 ,_ k ,- A4,,vl V ,i x ;Via, _ ._ ,;: (usft) ifyi , 1 t v. - 1. i - t lo 26.50 0.00 0.00 170.28 Plan Sections Measured Vertical TVDDogleg t Build '', Turn Depth Inclination Azimuth Depth System ,-:••,•„ +N/-S +E/-W Rate Rate • Rate Tool Face (usft) () • i O . (usft) D usft u ;•',:` (usft) (°/100usft) (°/100usft) (°/100usft) aO 26.50 0.00 0.00 26.50 -10.70 0.00 0.00 0.00 0.00 0.00 0.00 325.00 0.00 0.00 325.00 287.80 0.00 0.00 0.00 0.00 0.00 0.00 2,045.00 51.60 225.50 1,821.74 1,784.54 -507.15 -516.08 3.00 3.00 0.00 225.50 4,280.00 51.60 225.50 3,210.01 3,172.81 -1,734.83 -1,765.37 0.00 0.00 0.00 0.00 5,000.00 59.30 182.38 3,631.38 3,594.18 -2,259.22 -1,986.81 5.00 1.07 -5.99 -91.00 5,350.00 59.30 182.38 3,810.07 3,772.87 -2,559.90 -1,999.32 0.00 0.00 0.00 0.00 6,049.04 83.09 155.15 4,037.67 4,000.47 -3,194.74 -1,861.72 4.99 3.40 -3.90 -52.62 6,206.67 85.00 147.48 4,054.05 4,016.85 -3,332.16 -1,786.51 4.99 1.21 -4.87 -76.33 6,506.67 85.00 147.48 4,080.20 4,043.00 -3,584.16 -1,625.84 0.00 0.00 0.00 0.00 6,617.81 90.56 147.48 4,084.51 4,047.31 -3,677.76 -1,566.16 5.00 5.00 0.00 0.02 12,203.75 90.56 147.48 4,030.20 3,993.00 -8,387.71 1,436.52 0.00 0.00 0.00 0.00 1/15/2018 1:48:43PM Page 2 COMPASS 5000.1 Build 81D • 411 Halliburton HALLI B U RTO N Standard Proposal Report Database: ;Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU F-109 Company: Hilcorp Alaska,LLC TVD Reference: As-Built @ 37.20usft(Innovation) Project: Milne Point MD Reference: As-Built @ 37.20usft(Innovation) Site M Pt F Pad North Reference: True Well: , ,. Plan:MPU F-109 Survey Calculation Method: Minimum Curvature Wellbore MPU F-109(OA Producer) ' MPUF-109WP09 Design: W '5;32 s D,: AZ" Planned Survey , � Q4', - : v , , - u , Measured . Vertical tr x . Map Map '+ h Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing - Easting DIS'`''r .1-c e i. (usft) (°) (°) (usft) usft (usft) (usft) (usft) ,:sli ' (usft) -10.70 ,,,f 26.50 0.00 0.00 26.50 -10.70 0.00 0.00 6,034,863.78 541,270.05 0.00 0.00 100.00 0.00 0.00 100.00 62.80 0.00 0.00 6,034,863.78 541,270.05 0.00 0.00 200.00 0.00 0.00 200.00 162.80 0.00 0.00 6,034,863.78 541,270.05 0.00 0.00 300.00 0.00 0.00 300.00 262.80 0.00 0.00 6,034,863.78 541,270.05 0.00 0.00 325.00 0.00 0.00 325.00 287.80 0.00 0.00 6,034,863.78 541,270.05 0.00 0.00 Start Dir 3°/100':325'MD,325'TVD - 400.00 2.25 225.50 399.98 362.78 -1.03 -1.05 6,034,862.74 541,269.01 3.00 0.84 500.00 5.25 225.50 499.76 462.56 -5.62 -5.71 6,034,858.13 541,264.37 3.00 4.57 600.00 8.25 225.50 599.05 561.85 -13.85 -14.10 6,034,849.85 541,256.03 3.00 11.27 700.00 11.25 225.50 697.60 660.40 -25.72 -26.17 6,034,837.92 541,244.02 3.00 20.93 800.00 14.25 225.50 795.12 757.92 -41.19 -41.91 6,034,822.36 541,228.37 3.00 33.52 900.00 17.25 225.50 891.35 854.15 -60.21 -61.27 6,034,803.23 541,209.12 3.00 49.00 1,000.00 20.25 225.50 986.03 948.83 -82.74 -84.20 6,034,780.58 541,186.32 3.00 67.34 1,100.00 23.25 225.50 1,078.91 1,041.71 -108.71 -110.62 6,034,754.47 541,160.04 3.00 88.48 1,200.00 26.25 225.50 1,169.71 1,132.51 -138.05 -140.48 6,034,724.97 541,130.35 3.00 112.35 1,300.00 29.25 225.50 1,258.20 1,221.00 -170.68 -173.69 6,034,692.15 541,097.33 3.00 138.91 1,400.00 32.25 225.50 1,344.13 1,306.93 -206.51 -210.15 6,034,656.12 541,061.07 3.00 168.08 1,500.00 35.25 225.50 1,427.27 1,390.07 -245.45 -249.77 6,034,616.97 541,021.67 3.00 199.76 1,600.00 38.25 225.50 1,507.38 1,470.18 -287.38 -292.44 6,034,574.81 540,979.24 3.00 233.89 1,700.00 41.25 225.50 1,584.26 1,547.06 -332.20 -338.05 6,034,529.74 540,933.89 3.00 270.36 1,779.89 43.65 225.50 1,643.20 1,606.00 -369.98 -376.50 6,034,491.75 540,895.65 3.00 301.12 SV4 1,800.00 44.25 225.50 1,657.68 1,620.48 -379.77 -386.46 6,034,481.91 540,885.75 3.00 309.08 1,900.00 47.25 225.50 1,727.45 1,690.25 -429.97 -437.54 6,034,431.43 540,834.95 3.00 349.94 2,000.00 50.25 225.50 1,793.38 1,756.18 -482.66 -491.16 6,034,378.45 540,781.63 3.00 392.82 2,045.00 51.60 225.50 1,821.74 1,784.54 -507.15 -516.08 6,034,353.82 540,756.85 3.00 412.75 End Dir :2045'MD,1821.74'TVD 2,100.00 51.60 225.50 1,855.91 1,818.71 -537.36 -546.82 6,034,323.45 540,726.28 0.00 437.34 2,119.79 51.60 225.50 1,868.20 1,831.00 -548.23 -557.88 6,034,312.52 540,715.28 0.00 446.19 Base Permafrost - 2,200.00 51.60 225.50 1,918.02 1,880.82 -592.29 -602.72 6,034,268.21 540,670.69 0.00 482.04 2,300.00 51.60 225.50 1,980.14 1,942.94 -647.22 -658.61 6,034,212.98 540,615.11 0.00 526.75 2,400.00 51.60 225.50 2,042.25 2,005.05 -702.15 -714.51 6,034,157.74 540,559.52 0.00 571.46 2,436.94 51.60 225.50 2,065.20 2,028.00 -722.44 -735.16 6.034,137.34 540,538.99 0.00 587.97 SV1 2,500.00 51.60 225.50 2,104.37 2,067.17 -757.08 -770.41 6,034,102.51 540,503.94 0.00 616.16 2,600.00 51.60 225.50 2,166.48 2,129.28 -812.01 -826.30 6,034,047.28 540,448.35 0.00 660.87 2,700.00 51.60 225.50 2,228.60 2,191.40 -866.94 -882.20 6,033,992.04 540,392.76 0.00 705.57 2,800.00 51.60 225.50 2,290.71 2,253.51 -921.87 -938.10 6,033,936.81 540,337.18 0.00 750.28 2,900.00 51.60 225.50 2,352.83 2,315.63 -976.80 -993.99 6,033,881.57 540,281.59 0.00 794.98 3,000.00 51.60 225.50 2,414.94 2,377.74 -1,031.73 -1,049.89 6,033,826.34 540,226.01 0.00 839.69 3,100.00 51.60 225.50 2,477.06 2,439.86 -1,086.66 -1,105.79 6,033,771.11 540,170.42 0.00 884.40 3,200.00 51.60 225.50 2,539.17 2,501.97 -1,141.59 -1,161.69 6,033,715.87 540,114.84 0.00 929.10 3,300.00 51.60 225.50 2,601.28 2,564.08 -1,196.52 -1,217.58 6,033,660.64 540,059.25 0.00 973.81 3,400.00 51.60 225.50 2,663.40 2,626.20 -1,251.44 -1,273.48 6,033,605.40 540,003.67 0.00 1,018.51 1/15/2018 1:48:43PM Page 3 COMPASS 5000.1 Build 81D • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference.: Well Plan:MPU F-109 Company: `Hilcorp Alaska,LLC TVD Reference: As-Built @ 37.20usft(Innovation) Project: Milne Point MD Reference: s � g As-Built @ 37.20usft(Innovation) Site: M Pt F Pad North Reference: True Well: Plan:MPU F-109 Survey Calculation Method: (: Minimum Curvature Wellbore: MPU F-109(OA Producer) Design: MPU F-109 WP09 Planned Survey Measured .....,:, k..., Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S '5555' +E/-W ''' Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) ;W, (usft) 2,688.31 3,500.00 51.60 225.50 2,725.51 2,688.31 -1,306.37 -1,329.38 6,033,550.17 539,948.08 0.00 1,063.22 3,513.98 51.60 225.50 2,734.20 2,697.00 -1,314.06 -1,337.19 6,033,542.45 539,940.31 0.00 1,069.47 UG3 3,600.00 51.60 225.50 2,787.63 2,750.43 -1,361.30 -1,385.27 6,033,494.94 539,892.50 0.00 1,107.92 3,700.00 51.60 225.50 2,849.74 2,812.54 -1,416.23 -1,441.17 6,033,439.70 539,836.91 0.00 1,152.63 3,800.00 51.60 225.50 2,911.86 2,874.66 -1,471.16 -1,497.07 6,033,384.47 539,781.32 0.00 1,197.34 3,900.00 51.60 225.50 2,973.97 2,936.77 -1,526.09 -1,552.96 6,033,329.23 539,725.74 0.00 1,242.04 4,000.00 51.60 225.50 3,036.09 2,998.89 -1,581.02 -1,608.86 6,033,274.00 539,670.15 0.00 1,286.75 4,100.00 51.60 225.50 3,098.20 3,061.00 -1,635.95 -1,664.76 6,033,218.77 539,614.57 0.00 1,331.45 4,200.00 51.60 225.50 3,160.32 3,123.12 -1,690.88 -1,720.66 6,033,163.53 539,558.98 0.00 1,376.16 4,280.00 51.60 225.50 3,210.01 3,172.81 -1,734.83 -1,765.37 6,033,119.34 539,514.51 0.00 1,411.92 Start Dir 5°/100':4280'MD,3210.01'TVD 4,300.00 51.59 224.22 3,222.43 3,185.23 -1,745.94 -1,776.43 6,033,108.18 539,503.52 5.00 1,421.01 4,400.00 51.74 217.85 3,284.50 3,247.30 -1,805.05 -1,827.88 6,033,048.78 539,452.40 5.00 1,470.59 4,500.00 52.24 211.54 3,346.11 3,308.91 -1,869.79 -1,872.67 6,032,983.80 539,407.97 5.00 1,526.83 4,585.69 52.93 206.21 3,398.20 3,361.00 -1,929.36 -1,905.51 6,032,924.06 539,375.48 5.00 1,580.00 Ugnu LA3 4,600.00 53.07 205.33 3,406.81 3,369.61 -1,939.65 -1,910.47 6,032,913.74 539,370.57 5.00 1,589.31 4,700.00 54.21 199.29 3,466.13 3,428.93 -2,014.10 -1,940.99 6,032,839.13 539,340.47 5.00 1,657.54 4,800.00 55.65 193.43 3,523.62 3,486.42 -2,092.58 -1,963.99 6,032,760.52 539,317.90 5.00 1,731.02 4,900.00 57.35 187.80 3,578.84 3,541.64 -2,174.50 -1,979.30 6,032,678.54 539,303.05 5.00 1,809.17 5,000.00 59.30 182.38 3,631.38 3,594.18 -2,259.22 -1,986.81 6,032,593.78 539,296.02 5.00 1,891.41 End Dir :5000'MD,3631.38'TVD-Start 350'Pump Tangent Hold 5,100.00 59.30 182.38 3,682.43 3,645.23 -2,345.13 -1,990.38 6,032,507.86 539,292.92 0.00 1,975.48 5,200.00 59.30 182.38 3,733.49 3,696.29 -2,431.04 -1,993.96 6,032,421.94 539,289.82 0.00 2,059.55 5,300.00 59.30 182.38 3,784.55 3,747.35 -2,516.95 -1,997.53 6,032,336.02 539,286.73 0.00 2,143.63 5,350.00 59.30 182.38 3,810.07 3,772.87 -2,559.90 -1,999.32 6,032,293.06 539,285.18 0.00 2,185.66 Start Dir 4.99°1100':5350'MD,3810.077VD-End 350'Pump Tangent Hold 5,400.00 60.83 180.11 3,835.03 3,797.83 -2,603.22 -2,000.25 6,032,249.75 539,284.48 4.99 2,228.20 5,500.00 64.01 175.77 3,881.33 3,844.13 -2,691.75 -1,997.03 6,032,161.24 539,288.20 4.99 2,316.01 5,578.65 66.60 172.52 3,914.20 3,877.00 -2,762.81 -1,989.72 6,032,090.23 539,295.90 4.99 2,387.29 Schrader NA 5,600.00 67.31 171.66 3,922.56 3,885.36 -2,782.27 -1,987.02 6,032,070.79 539,298.71 4.99 2,406.92 5,700.00 70.71 167.75 3,958.39 3,921.19 -2,874.09 -1,970.31 6,031,979.07 539,315.93 4.99 2,500.24 5,800.00 74.19 164.00 3,988.55 3,951.35 -2,966.51 -1,947.02 6,031,886.79 539,339.73 4.99 2,595.27 5,900.00 77.73 160.38 4,012.82 3,975.62 -3,058.84 -1,917.34 6,031,794.64 539,369.92 4.99 2,691.28 6,000.00 81.31 156.85 4,031.01 3,993.81 -3,150.36 -1,881.48 6,031,703.33 539,406.28 4.99 2,787.54 6,049.04 83.09 155.15 4,037.67 4,000.47 -3,194.74 -1,861.72 6,031,659.06 539,426.29 4.99 2,834.62 6,100.00 83.69 152.66 4,043.54 4,006.34 -3,240.20 -1,839.45 6,031,613.73 539,448.80 4.99 2,883.19 6,206.67 85.00 147.48 4,054.05 4,016.85 -3,332.16 -1,786.51 6,031,522.08 539,502.25 4.99 2,982.76 End Dir :6206.67'MD,4054.05'TVD 6,300.00 85.00 147.48 4,062.19 4,024.99 -3,410.56 -1,736.52 6,031,443.97 539,552.67 0.00 3,068.47 6,400.00 85.00 147.48 4,070.90 4,033.70 -3,494.55 -1,682.97 6,031,360.27 539,606.68 0.00 3,160.31 6,449.30 85.00 147.48 4,075.20 4,038.00 -3,535.97 -1,656.57 6,031,319.01 539,633.31 0.00 3,205.58 Schrader OA 1/15/2018 1:48:43PM Page 4 COMPASS 5000.1 Build 810 0 S Halliburton HALLI U RTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: ". Well Plan:MPU F-109 Company: Hilcorp Alaska,LLC TVD Reference: As-Built @ 37.20usft(Innovation) Project: Milne Point MD Reference: g5,01:•,4,-. , As-Built @ 37.20usft(Innovation) Site: M Pt F PadNorth Reference: `€ True Well: Plan:MPU F-109 Survey Calculation Method: Minimum Curvature Wellbore: MPU F-109(OA Producer) MPU F-109 WP09 a Design: Planned Survey 1 : k X14 Measu red ',614‘01-.4,1:-"'1,-Z. ` Vertical `y,-'1 Map 4 Map Depth Inclination Azimuth Depth TVDss +N/-5 - Northing Easting s Vert Section (usft) (°) r) (usft) usft (usft) ) (usft) - (usft) 6,505.00 85.00 147.48 4,080.05 4,042.85 -3,582.75 -1,626.74 6,031,272.40 539,663.40 0.00 3,256.73 9 518"x 12 1/4" 6.506.67 85.00 147.48 4,080.20 4,043.00 -3,584.16 -1,625.84 6,031,271.00 539,664.30 0.00 3,258.27 Start Dir 5°/100':6506.67 MD,4080.2'TVD 6,600.00 89.67 147.48 4,084.54 4,047.34 -3,662.75 -1,575.74 6,031,192.70 539,714.84 5.00 3,344.19 6,617.81 90.56 147.48 4,084.51 4,047,31 -3,677.76 -1,566.16 6,031,177.73 539,724.49 5.00 3,360.61 End Dir :6617.81'MD,4084.51'TVD 6,700.00 90.56 147.48 4,083.71 4,046.51 -3,747.07 -1,521.98 6,031,108.69 539,769.05 0.00 3,436.37 6,800.00 90.56 147.48 4,082.74 4,045.54 -3,831.38 -1,468.23 6,031,024.68 539,823.27 0.00 3,528.55 6,900.00 90.56 147.48 4,081.76 4,044.56 -3,915.70 -1,414.47 6,030,940.67 539,877.49 0.00 3,620.73 7,000.00 90.56 147.48 4,080.79 4,043.59 -4,000.02 -1,360.72 6,030,856.66 539,931.70 0.00 3,712.92 7,100.00 90.56 147.48 4,079.82 4,042.62 -4,084.34 -1,306.97 6,030,772.65 539,985.92 0.00 3,805.10 7,200.00 90.56 147.48 4,078.85 4,041.65 -4,168.66 -1,253.21 6,030,688.64 540,040.14 0.00 3,897.28 7,300.00 90.56 147.48 4,077.87 4,040.67 -4,252.97 -1,199.46 6,030,604.63 540,094.35 0.00 3,989.46 7,400.00 90.56 147.48 4,076.90 4,039.70 -4,337.29 -1,145.70 6,030,520.62 540,148.57 0.00 4,081.64 7,500.00 90.56 147.48 4,075.93 4,038.73 -4,421.61 -1,091.95 6,030,436.61 540,202.79 0.00 4,173.83 7,600.00 90.56 147.48 4,074.96 4,037.76 -4,505.93 -1,038.19 6,030,352.60 540,257.00 0.00 4,266.01 7,700.00 90.56 147.48 4,073.99 4,036.79 -4,590.25 -984.44 6,030,268.59 540,311.22 0.00 4,358.19 7,800.00 90.56 147.48 4,073.01 4,035.81 -4,674.56 -930.68 6,030,184.58 540,365.44 0.00 4,450.37 7,900.00 90.56 147.48 4,072.04 4,034.84 -4,758.88 -876.93 6,030,100.57 540,419.65 0.00 4,542.55 8,000.00 90.56 147.48 4,071.07 4,033.87 -4,843.20 -823.18 6,030,016.56 540,473.87 0.00 4,634.74 8,100.00 90.56 147.48 4,070.10 4,032.90 -4,927.52 -769.42 6,029,932.55 540,528.09 0.00 4,726.92 8,200.00 90.56 147.48 4,069.12 4,031.92 -5,011.84 -715.67 6,029,848.54 540,582.30 0.00 4,819.10 8,300.00 90.56 147.48 4,068.15 4,030.95 -5,096.15 -661.91 6,029,764.53 540,636.52 0.00 4,911.28 8,400.00 90.56 147.48 4,067.18 4,029.98 -5,180.47 -608.16 6,029,680.52 540,690.74 0.00 5,003.46 8,500.00 90.56 147.48 4,066.21 4,029.01 -5,264.79 -554.40 6,029,596.51 540,744.95 0.00 5,095.65 8,600.00 90.56 147.48 4,065.24 4,028.04 -5,349.11 -500.65 6,029,512.50 540,799.17 0.00 5,187.83 8,700.00 90.56 147.48 4,064.26 4,027.06 -5,433.42 -446.89 6,029,428.49 540,853.39 0.00 5,280.01 8,800.00 90.56 147.48 4,063.29 4,026.09 -5,517.74 -393.14 6,029,344.48 540,907.60 0.00 5,372.19 8,900.00 90.56 147.48 4,062.32 4,025.12 -5,602.06 -339.39 6,029,260.47 540,961.82 0.00 5,464.38 9,000.00 90.56 147.48 4,061.35 4,024.15 -5,686.38 -285.63 6,029,176.46 541,016.04 0.00 5,556.56 9,100.00 90.56 147.48 4,060.37 4,023.17 -5,770.70 -231.88 6,029,092.45 541,070.25 0.00 5,648.74 9,200.00 90.56 147.48 4,059.40 4,022.20 -5,855.01 -178.12 6,029,008.44 541,124.47 0.00 5,740.92 9,300.00 90.56 147.48 4,058.43 4,021.23 -5,939.33 -124.37 6,028,924.43 541,178.69 0.00 5,833.10 9,400.00 90.56 147.48 4,057.46 4,020.26 -6,023.65 -70.61 6,028,840.42 541,232.90 0.00 5,925.29 9,500.00 90.56 147.48 4,056.49 4,019.29 -6,107.97 -16.86 6,028,756.41 541,287.12 0.00 6,017.47 9,600.00 90.56 147.48 4,055.51 4,018.31 -6,192.29 36.90 6,028,672.40 541,341.34 0.00 6,109.65 9,700.00 90.56 147.48 4,054.54 4,017.34 -6,276.60 90.65 6,028,588.39 541,395.55 0.00 6,201.83 9,800.00 90.56 147.48 4,053.57 4,016.37 -6,360.92 144.40 6,028,504.38 541,449.77 0.00 6,294.01 9,900.00 90.56 147.48 4,052.60 4,015.40 -6,445.24 198.16 6,028,420.37 541,503.99 0.00 6,386.20 10,000.00 90.56 147.48 4,051.62 4,014.42 -6,529.56 251.91 6,028,336.36 541,558.20 0.00 6,478.38 10,100.00 90.56 147.48 4,050.65 4,013.45 -6,613.88 305.67 6,028,252.35 541,612.42 0.00 6,570.56 10,200.00 90.56 147.48 4,049.68 4,012.48 -6,698.19 359.42 6,028,168.34 541,666.64 0.00 6,662.74 10,300.00 90.56 147.48 4,048.71 4,011.51 -6,782.51 413.18 6,028,084.33 541,720.85 0.00 6,754.92 10,400.00 90.56 147.48 4,047.74 4,010.54 -6,866.83 466.93 6,028,000.32 541,775.07 0.00 6,847.11 1/15/2018 1:48:43PM Page 5 COMPASS 5000.1 Build 81D • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA _ ,Local Co-ordinate Reference: Well Plan:MPU F-109 Company: Hilcorp Alaska,LLC TVD Reference: As-Built @ 37.20usft(Innovation) Project: Milne Point MD Reference: A :*; , As-Built @ 37.20usft(Innovation) 3 Site: M Pt F Pad North Reference: True Well: Plan:MPU F-109 Survey Calculation Method: Minimum Curvature Wellbore: MPU F-109(OA Producer) - 1 Design: MPU F-109 WP090 Planned Survey Measured i Vertical rs '' ' ¢. Map Map x Depth Inclination Azimuth Depth TVDss +N/-$ +E/-W Northing Easting ® ;Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) it . 10,500.00 90.56 147.48 4,046.76 4,009.56 -6,951.15 520.68 6,027,916.31 541,829.29 0.00 6,939.29 10,600.00 90.56 147.48 4,045.79 4,008.59 -7,035.47 574.44 6,027,832.30 541,883.50 0.00 7,031.47 10,700.00 90.56 147.48 4,044.82 4,007.62 -7,119.78 628.19 6,027,748.29 541,937.72 0.00 7,123.65 10,800.00 90.56 147.48 4,043.85 4,006.65 -7,204.10 681.95 6,027,664.28 541,991.94 0.00 7,215.83 10,900.00 90.56 147.48 4,042.87 4,005.67 -7,288.42 735.70 6,027,580.27 542,046.15 0.00 7,308.02 11,000.00 90.56 147.48 4,041.90 4,004.70 -7,372.74 789.46 6,027,496.26 542,100.37 0.00 7,400.20 11,100.00 90.56 147.48 4,040.93 4,003.73 -7,457.06 843.21 6,027,412.25 542,154.59 0.00 7,492.38 11,200.00 90.56 147.48 4,039.96 4,002.76 -7,541.37 896.97 6,027,328.24 542,208.80 0.00 7,584.56 11,300.00 90.56 147.48 4,038.99 4,001.79 -7,625.69 950.72 6,027,244.23 542,263.02 0.00 7,676.74 11,400.00 90.56 147.48 4,038.01 4,000.81 -7,710.01 1,004.47 6,027,160.22 542,317.24 0.00 7,768.93 11,500.00 90.56 147.48 4,037.04 3,999.84 -7,794.33 1,058.23 6,027,076.21 542,371.45 0.00 7,861.11 11,600.00 90.56 147.48 4,036.07 3,998.87 -7,878.65 1,111.98 6,026,992.21 542,425.67 0.00 7,953.29 11,700.00 90.56 147.48 4,035.10 3,997.90 -7,962.96 1,165.74 6,026,908.20 542,479.89 0.00 8,045.47 11,800.00 90.56 147.48 4,034.13 3,996.93 -8,047.28 1,219.49 6,026,824.19 542,534.10 0.00 8,137.65 11,900.00 90.56 147.48 4,033.15 3,995.95 -8,131.60 1,273.25 6,026,740.18 542,588.32 0.00 8,229.84 12,000.00 90.56 147.48 4,032.18 3,994.98 -8,215.92 1,327.00 6,026,656.17 542,642.54 0.00 8,322.02 12,100.00 90.56 147.48 4,031.21 3,994.01 -8,300.24 1,380.76 6,026,572.16 542,696.75 0.00 8,414.20 12,203.75 90.56 147.48 4,030.20 3,993.00 -8,387.71 1,436.52 6,026,485.00 542,753.00 0.00 8,509.84 Total Depth:12203.75'MD,4030.2'TVD Targets , '4‘1%,,.,,-,- ' , r'^ ,a^ate- 4-ems r�; g-,1- ., -, ' r Target Name .z.,,,:,11" -hit/miss target Dip Angle Dip Dir TVD +N/-S +E/-W .r„ Northing '' Easting (°) (°) (usft) (usft) (usft) (usft) (usft) Shape .: MPF-109 wp08 Toe 0.00 0.00 4,030.20 -8,387.71 1,436.52 6,026,485.00 542,753.00 'I -plan hits target center -Circle(radius 50.00) MPF-109 wp08 Heel 0.00 0.00 4,080.20 -3,584.16 -1,625.84 6,031,271.00 539,664.30 -plan hits target center -Circle(radius 50.00) Casing Points . Measured Vertical ` Casing Hole a Depth Depth . ,. +_ , ; Diameter Diameter usftusfta-,i :`i '" (.1 (1i a�` a. 6,505.00 4,080.05 9 5/8"x 12 1/4" 9-5/8 12-1/4 12,203.75 4,030.20 4 1/2"x 8 1/2" 4-1/2 8-1/2 1/15/2018 1:48:43PM Page 6 COMPASS 5000.1 Build 81D • III Halliburton HALLIBURTON Standard Proposal Report Database: 4t Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: 14 Well Plan:MPU F-109 Company: Hilcorp Alaska,LLC TVD Reference: .fv.i� As-Built @ 37.20usft(Innovation) Project: Milne Point MD Reference: a ':.1,44*441.:14 As-Built @ 37.20usft(Innovation) Site: M Pt F Pad North Reference: True Well: Plan:MPU F-109 Survey Calculation Method: Minimum Curvature Wellbore:, MPU F-109 OA Producer) * Design 11S.'1141.1? MPU F-109 WP09 y 4444 444 Formations Measured Vertical Vertical ' r4 ' Depth : Depth Depth SS4 ® a usft usft 9Y -''' i 3,513.98 2,734.20 UG3 6,449.30 4,075.20 Schrader OA 1,779.89 1,643.20 SV4 4,585.69 3,398.20 Ugnu LA3 5,578.65 3,914.20 Schrader NA 2,436.94 2,065.20 SV1 2,119.79 1,868.20 Base Permafrost Plan Annotations ,. 4'-'1.4'- :.x . ,'1,. , i`'7->, ;. "` Measured Vertical Local Coordinates 1 t..`4.!!'.,„::. Depth Depth +N/-S +E/-W ` ""` (usft) (usft) (usft) 4 (usft) Comment 325.00 325.00 0.00 0.00 Start Dir 3°/100':325'MD,325'TVD 2,045.00 1,821.74 -507.15 -516.08 End Dir :2045'MD,1821.74'TVD 4,280.00 3,210.01 -1,734.83 -1,765.37 Start Dir 5°/100':4280'MD,3210.01'TVD 5,000.00 3,631.38 -2,259.22 -1,986.81 End Dir :5000'MD,3631.38'TVD-Start 350'Pump Tangent Hold 5,350.00 3,810.07 -2,559.90 -1,999.32 Start Dir 4.99°/100':5350'MD,3810.07'TVD-End 350'Pump Tangent Hold 6,206.67 4,054.05 -3,332.16 -1,786.51 End Dir :6206.67 MD,4054.05'TVD 6,506.67 4,080.20 -3,584.16 -1,625.84 Start Dir 5°/100':6506.67'MD,4080.2'TVD 6,617.81 4,084.51 -3,677.76 -1,566.16 End Dir :6617.81'MD,4084.51'TVD 12,203.75 4,030.20 -8,387.71 1,436.52 Total Depth:12203.75'MD,4030.2'TVD 1/15/2018 1:48:43PM Page 7 COMPASS 5000.1 Build 810 i I _1 i 0 Hilcorp Alaska, LLC Milne Point M Pt F Pad Plan: MPU F-109 MPU F-109(0A Producer) MPU F-109 WP09 Sperry Drilling Services Clearance Summary Anticollision Report 15 January,2018 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: M Pt F Pad-Plan:MPU F-109-MPU F-109(0A Producer)-MPU F-109 WP09 Well Coordinates: 6,034,863.78 N,541,270.05 E(70°30'22.23"N,147'39'44.51"W) Datum Height:As-Built @ 37.20usft(Innovation) Scan Range:0.00 to 12,203.75 usft.Measured Depth. Scan Radius is 1,500.00 usft.Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied S Version: 5000.1 Build:810 Scan Type: ui7 Scan Type: 25.00 a HALLIBURTON Sperry Drilling Services I • Hilcorp Alaska,LLC HALLIBURTON Milne Polint Anticollision Report for Plan: MPU F-109-MPU F-109 WP09 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: M Pt F Pad-Plan:MPU F-109-MPU F-109(OA Producer)-MPU F-109 WPO9 Scan Range:0.00 to 12,203.75 usft.Measured Depth. Scan Radius is 1,500.00 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft M Pt F Pad MPF-81-MPF-S1-MPF-81 4,900.00 157.59 4,900.00 82.93 5,610.28 2.111 Clearance Factor Pass- MPF-81-MPF-81-MFF-81 4,950.00 149.75 4,950.00 81.14 5,651.94 2.183 Ellipse Separation Pass- MPF-81-MPF-81-MPF-81 5,021.46 144.75 5,021.46 87.48 5,710.35 2.527 Centre Distance Pass- Plan:MPU F-106i-MPU F-106i-MPU F-106i WPO4 251.36 105.06 251.36 101.84 251.46 32.546 Centre Distance Pass- Plan:MPU F-106i-MPU F-106i-MPU F-106i WPo4 325.00 105.32 325.00 101.19 324.25 25.514 Ellipse Separation Pass- Plan:MPU F-106i-MPU F-106i-MPU F-106i WPO4 625.00 139.27 625.00 131.49 615.21 17.911 Clearance Factor Pass- Plan:MPU F-107-MPU F-107(OA Producer)-MPU F 326.97 90.18 326.97 87.26 327.17 30.829 Centre Distance Pass- Plan:MPU F-107-MPU F-107(OA Producer)-MPU F 350.00 90.32 350.00 87.24 350.22 29.343 Ellipse Separation Pass- Plan:MPU F-107-MPU F-107(OA Producer)-MPU F 5,150.00 1,343.54 5,150.00 1,261.10 7,456.29 16.298 Clearance Factor Pass- Plan:MPU F-108i-MPU F-108i-MPU F-108i WPO7 325.00 45.15 325.00 41.02 324.90 10.925 Centre Distance Pass- Plan:MPU F-108i-MPU F-1081-MPU F-1081 WPO7 350.00 45.32 350.00 40.88 349.90 10.212 Ellipse Separation Pass- Plan:MPU F-108i-MPU F-108i-MPU F-108i WPO7 11,748.52 766.37 11,748.52 513.66 12,176.64 3.033 Clearance Factor Pass- Plan:MPU F-1101-MPU F-1101-MPU F-1101 WPO6 507.68 11.98 507.68 5.65 506.64 1.891 Centre Distance Pass- Plan:MPU F-1101-MPU F-1101-MPU F-110i WPO6 575.00 12.38 575.00 5.22 573.52 1.730 Ellipse Separation Pass- Plan:MPU F-1101-MPU F-1101-MPU F-1101 WPO6 600.00 12.76 600.00 5.30 598.36 1.711 Clearance Factor Pass- M Pt L Pad MPL-20-MPL-20-MPL-20 9,170.07 898.64 9,170.07 837.36 6,470.81 14.665 Centre Distance Pass- MPL-20-MPL-20-MPL-20 9,200.00 899.13 9,200.00 837.21 6,473.46 14.521 Ellipse Separation Pass- MPL-20-MPL-20-MPL-20 9,700.00 1,042.10 9,700.00 960.39 6,519.49 12.754 Clearance Factor Pass- MPL-32-MPL-32-MPL-32 8,594.41 519.17 8,594.41 460.84 6,647.23 8.901 Centre Distance Pass- MPL32-MPL-32-MPL-32 8,600.00 519.20 8,600.00 460.77 6,647.00 8.886 Ellipse Separation Pass- MPL-32-MPL-32-MPL-32 8,900.00 602.30 8,900.00 527.05 6,634.32 8.004 Clearance Factor Pass- MPL-34-MPL-34-MPL-34 9,990.95 159.56 9,990.95 113.43 7,056.08 3.459 Centre Distance Pass- MPL-34-MPL-34-MPL-34 10,025.00 163.09 10,025.00 110.42 7,060.61 3.096 Ellipse Separation Pass- MPL-34-MPL-34-MPL-34 10,100.00 192.72 10,100.00 121.02 7,070.58 2.688 Clearance Factor Pass- MPL-35-MPL-35-MPL-35 11,109.69 529.16 11,109.69 456.90 6,958.64 7.323 Centre Distance Pass- MPL-35-MPL-35-MPL-35 11,150.00 530.55 11,150.00 455.39 6,970.45 7.059 Ellipse Separation Pass- 15 January,2018-14:18 Page 2 a/7 COMPASS • • Hilcorp Alaska,L C HALLIBURTON MilneP 'nt Anticollision Report for Plan: MPU F-109-MPU F-109 WP09 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: M Pt F Pad-Plan:MPU F-109-MPU F-109(0A Producer)-MPU F-109 WP09 Scan Range: 0.00 to 12,203.75 usft.Measured Depth. Scan Radius is 1,500.00 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft MPL-35-MPL-35-MPL-35 11,475.00 632.90 11,475.00 528.08 7,073.12 6.038 Clearance Factor Pass- MPL-35-MPL-35A-MPL-35A 11,109.69 529.16 11,109.69 456.90 6,959.44 7.323 Centre Distance Pass- MPL-35-MPL-35A-MPL-35A 11,150.00 530.55 11,150.00 455.39 6,971.25 7.059 Ellipse Separation Pass- MPL-35-MPL-35A-MPL-35A 11,475.00 632.90 11,475.00 528.08 7,073.92 6.038 Clearance Factor Pass- MPL-35-MPL-35APB1-MPL-35APB1 11,109.69 529.16 11,109.69 456.90 6,959.44 7.323 Centre Distance Pass- MPL-35-MPL-35APB1-MPL-35APB1 11,150.00 530.55 11,150.00 455.39 6,971.25 7.059 Ellipse Separation Pass- MPL-35-MPL-35APB1-MPL-35APB1 11,475.00 632.90 11,475.00 528.08 7,073.92 6.038 Clearance Factor Pass- MPL-35-MPL-35APB2-MPL-35APB2 11,109.69 529.16 11,109.69 456.90 6,959.44 7.323 Centre Distance Pass- MPL-35-MPL-35APB2-MPL-35APB2 11,150.00 530.55 11,150.00 455.39 6,971.25 7.059 Ellipse Separation Pass- MPL-35-MPL-35APB2-MPL-35APB2 11,475.00 632.90 11,475.00 528.08 7,073.92 6.038 Clearance Factor Pass- I MPL-35-MPL-35APB3-MPL-35APB3 11,109.69 529.16 11,109.69 456.90 6,959.44 7.323 Centre Distance Pass- MPL-35-MPL-35APB3-MPL-35APB3 11,150.00 530.55 11,150.00 455.39 6,971.25 7.059 Ellipse Separation Pass- MPL-35-MPL-35APB3-MPL-35APB3 11,475.00 632.90 11,475.00 528.08 7,073.92 6.038 Clearance Factor Pass- MPL-36-MPL-36-MPL-36 9,861.47 665.03 9,861.47 604.14 6,778.55 10.921 Centre Distance Pass- MPL-36-MPL-36-MPL-36 9,875.00 665.17 9,875.00 603.89 6,780.38 10.854 Ellipse Separation Pass- MPL-36-MPL-36-MPL-36 10,275.00 781.20 10,275.00 698.01 6,832.65 9.390 Clearance Factor Pass- MPL-36-MPL-36L1-MPL-36L1 9,861.47 665.03 9,861.47 604.42 6,778.55 10.972 Centre Distance Pass- MPL-36-MPL-36L1-MPL-36L1 9,875.00 665.17 9,875.00 604.17 6,780.38 10.905 Ellipse Separation Pass- MPL-36-MPL-36L1-MPL-36L1 10,275.00 781.20 10,275.00 698.29 6,832.65 9.422 Clearance Factor Pass- MPL-36-MPL-36L1 PB1-MPL-36L1 PB1 9,861.47 665.03 9,861.47 604.35 6,778.55 10.960 Centre Distance Pass- MPL-36-MPL-36L1 PBI-MPL-36L1 PB1 9,875.00 665.17 9,875.00 604.10 6,780.38 10.892 Ellipse Separation Pass- MPL-36-MPL-36L1 PBI-MPL-36L1 PB1 10,275.00 781.20 10,275.00 698.23 6,832.65 9.415 Clearance Factor Pass- MPL-36-MPL-36PB1-MPL-36PB1 9,861.47 665.03 9,861.47 604.14 6,778.55 10.921 Centre Distance Pass- 1 MPL-36-MPL-36PB1-MPL-36PB1 9,875.00 665.17 9,875.00 603.89 6,780.38 10.854 Ellipse Separation Pass- MPL-36-MPL-36PB1-MPL-36PB1 10,275.00 781.20 10,275.00 698.01 6,832.65 9.390 Clearance Factor Pass- MPL37-MPL-37-MPL-37 - • 67.74 - a -9.72 „„ 7,294.11 - NM tentre Distance ,..2,FAIL- MPL-37-MPL-37-MPL-37 77.99 - • -26.aq MN 7,3a. L 0.744 Clearance Factor AIL' MPL-37-MPL-37A-MPL-37A - WI 67.7 II -91 =NM ® 0j Centre MPL37-MPL-37A-MPL-37A - W 77.99 - I. -26.84 - IN ill. PealillIWN MPL-39-MPL-39-MPL-39 9,176.59 542.25 9,176.59 483.30 6,559.71 9.198 Centre Distance Pass- MPL-39-MPL-39-MPL-39 9,200.00 542.75 9,200.00 483.15 6,560.79 9.106 Ellipse Separation Pass- 15 January,2018-14:18 Page 3 a/7 COMPASS • • Hilcorp Alaska,LLC HALLI B U RTO N Milne Point Anticollision Report for Plan: MPU F-109-MPU F-109 WP09 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: M Pt F Pad-Plan:MPU F-109-MPU F-109(0A Producer)-MPU F-109 WP09 Scan Range:0.00 to 12,203.75 usft.Measured Depth. Scan Radius is 1,500.00 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft MPL-39-MPL-39-MPL-39 9,500.00 631.21 9,500.00 554.03 6,574.59 8.179 Clearance Factor Pass- MPL-40-MPL-40-MPL-40 7,842.87 215.51 7,842.87 143.93 6,917.91 3.011 Centre Distance Pass- MPL-40-MPL-40-MPL-40 7,975.00 249.20 7,975.00 99.52 6,875.67 1.665 Ellipse Separation Pass- MPL-40-MPL-40-MPL-40 8,025.00 276.04 8,025.00 104.75 6,859.77 1.612 Clearance Factor Pass- MPL-47-MPL-47-MPL-47 11,825.00 675.29 11,825.00 512.94 7,012.81 4.160 Clearance Factor Pass- MPL-47-MPL-47-MPL-47 11,847.49 674.91 11,847.49 514.06 7,012.81 4.196 Centre Distance Pass- MPL-47-MPL-47 PB1-MPL-47 PB1 11,825.00 675.29 11,825.00 512.77 7,012.81 4.155 Clearance Factor Pass- MPL-47-MPL-47 PB1-MPL-47 PB1 11,847.49 674.91 11,847.49 513.89 7,012.81 4.191 Centre Distance Pass- MPL-50-MPL-50-MPL-50 11,804.56 353.70 11,804.56 238.06 7,170.15 3.059 Centre Distance Pass- MPL-50-MPL-50-MPL-50 12,050.00 370.15 12,050.00 210.80 7,417.16 2.323 Ellipse Separation Pass- MPL-50-MPL-50-MPL-50 12,203.75 377.39 12,203.75 211.02 7,632.89 2.268 Clearance Factor Pass- MPU L-51-MPU L-51-MPU L-51 11,425.00 164.54 11,425.00 49.09 7,159.00 1.425 Clearance Factor Pass- MPU L-51-MPU L-51-MPU L-51 11,450.00 153.00 11,450.00 47.12 7,174.99 1.445 Ellipse Separation Pass- MPU L-51-MPU L-51-MPU L-51 11,566.19 125.90 11,566.19 74.85 7,250.08 2.466 Centre Distance Pass- MPU L-52-MPU L-52-MPU L-52 9,868.23 115.60 9,868.23 68.76 6,865.41 2.468 Centre Distance Pass- MPU L-52-MPU L-52-MPU L-52 9,975.00 134.50 9,975.00 43.63 6,947.46 1.480 Ellipse Separation Pass- MPU L-52-MPU L-52-MPU L-52 10,025.00 153.42 10,025.00 46.46 6,985.22 1.434 Clearance Factor Pass- MPU L-53-MPU L-53-MPU L-53 7,829.35 402.09 7,829.35 332.12 6,406.20 5.747 Centre Distance Pass- MPU L-53-MPU L-53-MPU L-53 7,850.00 402.57 7,850.00 331.30 6,411.93 5.648 Ellipse Separation Pass- MPU L-53-MPU L-53-MPU L-53 8,025.00 442.77 8,025.00 357.46 6,472.32 5.190 Clearance Factor Pass- Plan:MPU L-54-MPU L-54-MPU L-54 WPO6 12203.75 420.46 12,203.75 245.84 7,826.87 2.408 Clearance Factor Pass- 15 January,2018-14:18 Page 4 of 7 COMPA• • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU F-109-MPU F-109 WP09 Survey tool program From To Survey/Plan Survey Tool (usS) (usft) 26.50 6,510.00 MPU F-109 WP09 2_MWD+IFR2+MS+Sag 6,510.00 12,203.75 MPU F-109 WP09 2_MWD+IFR2+MS+Sag Ellipse error terms are correlated across survey tool tie-on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor=Distance Between Profiles/(Distance Between Profiles-Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 15 January,2018-14:18 Page 5 of 7 COMPASS • HALLIBURTON Project: Milne Point REFERENCE INFORMATION WELL DEFAIS:Mem MPU F-109 NAD 1927(NADCONCONUS) Alaska Zone 04 Site: M Pt F Pad Co-ordinate(NNE)Reference:Well Plan:MPU F..108,True North Ground Level: 10.70 Sperry Drilling Well: Plan:MPU F-109yarticel(TVD)Reference:As-Buda eta7.20uea(Innovedon) +N/-0 +EI-W xottliieg Fasting Latimule LongiNde Measured Depth Reference:As-Built et a7.200.0(Innov.000 0.00 0.00 6034863.78 541270.05 70°30'22.227 N 149°39'44.515 Wellbore: MPU F-109(OA Producer) Cekulehon Method:Minimum Curvature Plan: MPU F-109 WP09 SURVEY PROGRAM GLOBAL FILTER:Using user defined selection&leering trite':. 1 Iile )rO _ 26.50 To 12203.75 Date 2016-0421T00:00:00 Validated Yes Version: Ladder/S.F. Plots Depth From Depth To Survey/Plan Tool CASING DETAILS - 26.50 6510.00 MPU F-109 WP09 2_MWD*IFR2*MS*Sag 6510.00 12203.75 MPU F-109 WP09 2_MWD*IFR2+MS+Sag TVD TVDSS MD Size Name 4080.05 4042.85 6505.00 9-58 9 58"x 12 1/4" 4030.20 3993.00 12203.75 4-1/2 4 12"z 8 12" III - if MPU F-1t,. 150.00— l"bA I I F-1081 WP07 illi 1111 ii 1 I —11 ._ I1 o A,Illt0a _ 10111 . , 0120.00 I 'I 11111 1 111 — iv .n _ III Il111 11, 10,.WPD6_i. 11111��Ill I IF ( 1. Ip —.mei 0 111 90.00 , 1111 III — �I �� I 1 a _ M L-3y 6 OOUF-1081 F elf i� IIIb .._....._I III II I ,I Ili _...... m P III U ......milllllllall 1111 1 l 30.00 IIII _ _..... c ®.11 I'illll ® J U —"Mill I'" MPU F 110i WP(. 0.00 l 0 700 1400 2100 2800 3500 4200 4900 5600 6300 7000 7700 8400 9100 9800 10500 11200 11900 12600 13300 Measured Depth(1400 usft/in) 4.50 - _ ._...- ......... + ........_ _ — '_— _ ak itt o _ m 3.00 _ Ii LL Collision Risk Procedures Req. m I n N 1.50 - - Collision Avoidance Req - No Go Zone-Stop Drilling 0.00 ; 1 11 � 11 1111.. 1 1111111 l l 1111 1111 111 , 1111 1111 1 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 Measured Depth(1400 usft/in) TRANSMITTAL LETTER CHECKLIST WELL NAME: - PTD: °/4/ Development Service _Exploratory Stratigraphic Test _Non-Conventional FIELD: Mil At POOL: � 1fl /1 1 T0� 4)/-- SJ'\Jd&TZitkk 1 Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - . (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) 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 Pilot Hole name ( 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 conservation Spacing Exception 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 also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2XB) 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 2/2015 0 • El El y a) O , a = , N C CO Qc.) , , a O o. 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