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Home My WebLink About219-1331. 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 13,785 feet N/A feet true vertical 7,656 feet N/A feet Effective Depth measured 13,777 feet 12,900 feet true vertical 7,648 feet 6,824 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 12,841' 6,768' Packers and SSSV (type, measured and true vertical depth)Liner Top Packer 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: 7,500psi 5,750psi 7,240psi 8,430psi 13,054' 6,968' Burst N/A Collapse N/A 3,090psi 5,410psi 877' Casing Conductor 7,648'13,777' 13,029' 9,055'Surface Production Liner 20" 9-5/8" 7" 80' 9,029' measured TVD 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-133 50-029-23650-00-00 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: ADL025509 / ADL355017 MILNE POINT / KUPARUK RIVER OIL MILNE PT UNIT F-116 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 238 Gas-Mcf MD 107' 360 Size 107' 4,724' 960 40013 341 359961 346 323-542 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 17 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Ryan Lewis ryan.lewis@hilcorp.com 303-906-5178 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 3:37 pm, Jan 02, 2024 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.01.02 14:47:29 - 09'00' Taylor Wellman (2143) RBDMS JSB 010324 WCB 7-2-2024 DSR-1/26/24 _____________________________________________________________________________________ Revised By: TDF 12/22/2023 SCHEMATIC Milne Point Unit Well: MP F-116 Last Completed: 10/18/2023 PTD: 219-133 TD =13,785’(MD) / TD =7,656’(TVD) 20” Jet Pump Fish Left in Hole Orig. KB Elev.: 37.6’ / GL Elev.: 11.5’ 7” 16 9-5/8” 2 17 PBTD =13,691’(MD) / PBTD = 7,567’(TVD) 4-1/2” Shoe @ 13,777’ 10 &11 4&5 ES Cementer @2,769’ 3 6& 7 12 & 13 8 & 9 14 15 1 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 215 / X-52 / Weld N/A Surface 107’ N/A 9-5/8" Surface 40 / L-80 / TXP BTC 8.835 Surface 9,055’ 0.0758 7” Intermediate 26 / L-80 / TXP-BTC 6.276 Surface 13,054’ 0.0383 4-1/2” Liner 12.6 / L-80 / TXP-BTC 3.958 12,900’ 13,777’ 0.0152 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE 8rd 2.441 Surface 12,841’ 0.0058 OPEN HOLE / CEMENT DETAIL Conductor ± 270 ft3 12-1/4" Stg 1 L – 900 sx / T - 400 sx / Stg 2 L – 447 sx / T – 270 sx (304 bbls to surface) 9-7/8”x 8-1/2” 180 sx 6-1/8” 102 sx WELL INCLINATION DETAIL KOP @ 400’ Max Hole Angle 65 deg TREE & WELLHEAD Tree 5M CIW 3-1/8” Tree Wellhead 5M FMC Gen IV GENERAL WELL INFO API: 50-029-23650-00-00 Cased by Innovation: 11/29/2019 Completed by ASR#1 – 3/18/2020 ESP Swap by ASR#1 – 12/20/2020 ESP Swap by ASR#1 – 10/18/2023 JEWELRY DETAIL No. Top MD Item ID 1 206’ ST 2: 2-7/8”x 1” Side-pocket Camco GLM with 0.25” OV 2 12,625’ ST 1: 2-7/8” x 1" Side-pocket Camco GLM w/ DV 3 12,712’ 2-7/8” XN Nipple w/ 2.205" Min ID 2.205 4 12,763’ Discharge Head: B/O PMP 400 5 12,764’ Zenith Ported Sub: S/A B/O PRESS PORT 400P 6 12,764’ Pump 2: 400PMSXD 134 FLEXER H6 FER 7 12,782’ Pump 1: 400PMSXD 024 GINPSHL H6 FER STD PNT 8 12,799 Gas Separator: 538 GSTHVEX 9 12,805 Intake: GPXARCINT FER H6 10 12,806 Upper Tandem Seal: GSBDB H6 SB/AB PFSA 11 12,812 Lower Tandem Seal: GSB#DB H6 SB/AB PFSA 12 12,819 Motor: 562 XP 250 Hp /2,505 V/61A - 208/2090 10R 13 12,836 Zenith Motor Gauge 14 12,839 Centralizer: Bottom @ 12,841’ 15 12,900’ Liner Top Packer 4.340 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk C 13,354’ 13,358’ 7,251’ 7,255’ 4 2-1/8” 12/25/19 Open Kuparuk B7 13,362’ 13,400’ 7,258’ 7,294’ 38 2-1/2” 12/25/19 Open Kuparuk A3 13,438’ 13,448’ 7,330’ 7,339’ 10 2-1/2” 1/25/2020 Open Kuparuk A2 13,456’ 13,460’ 13,460’ 13,474’ 7,347’ 7,350’ 7,350’ 7,364’ 4 14 2-1/8” 2-1/2” 12/13/19 1/25/2020 Open Open Kuparuk A1 13,485’ 13,540’ 7,374’ 7,426’ 55 2-1/2” 12/25/19 Open Ref Log: 11/24/2019 Halliburton MWD Well Name Rig API Number Well Permit Number Start Date End Date MP F-116 ASR 50-029-023650-00-00 219-133 10/12/2023 10/20/2023 10/13/2023 - Friday Test BOPE as per approved sundry. Testing t/ 250 psi low & 2500 psi high for 5/5 charted mins. Preformed accumulator drawdown test. AOGCC witnessed testing. IA monitored through open valve during all testing. Well on a vacuum. L/D test tools & B/D all lines. Line choke & kill manifolds up for well operations. Fill gas buster w/ 9.2 ppg brine. Change out handling equip. Hang ESP cable sheave. W/ tee bar pull CTS & BPV. Tubing & IA static. M/U landing joint & BOLDS. P/U unseat hanger at 103k. P/U wt reaching 142K. Clean P/U wt =135K. Slight drag f/ 140K t/ 135K. L/D hanger. Tie on to ESP cable & run over sheave, L/D landing JT. Fill hole w/ 11 bbls. Fluid level ~ 417'. POOH w/ 3-1/2" 9.3# Hyd 563 ESP completion. F/ 12,787' T/ 12,348' Pump double displacement for pipe tripped out. Perform kick while tripping drill & AAR. Preform derrick inspection. Cont. POOH w/ 3-1/2" 9.3# Hyd 563 ESP completion. F/ 12,348' T/ 9,124' Pump double displacement for pipe tripped out. Rig service, check equip. fluid levels. Cont. POOH w/ 3-1/2" 9.3# Hyd 563 ESP completion. F/ 9,124' T/ 5,929' Pump double displacement for pipe tripped out. 10/11/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 10/12/2023 - Thursday MIRU to F-116. Function test BOPE. Finish rig acceptance checklist. Accept rig. Prep to test BOPE. P/U test tools. 2-7/8" test joint fill stack w/ freshwater. Preform shell test. Test BOPE as per approved sundry t/ 250 psi low & 2500 psi high for 5/5 charted mins. Completed 3 tests. Cont. POOH w/ 3-1/2" 9.3# Hyd 563 ESP completion. F/ 5,929' T/ 2921' Pump double displacement for pipe tripped out. Perform reel swap. Service Rig, check equip. fluid levels. Cont. POOH w/ 3-1/2" 9.3# Hyd 563 ESP completion. F/ 2,921' T/ 122' Pump double displacement for pipe tripped out. L/D ESP clamps from rig floor, clear unneeded equip. P/U ESP L/D tools. Change elevator inserts to 2-7/8" for ESP lift sub. L/D ESP Assy. DS head, 4 x pumps, Gas Sep., upper seal, lower seal, motor, zenith gauge, centralizer. Clamps recovered 262 cc clamps, 11 pump clamps, 2 protectolizers, 1 flat guard. Packed off with frac sand 6' above discharge head. Pump shaft seized. Tandem seal & motor shafts free. Remove all ESP equip. from rig floor. L/D ESP slop hose. Unhang sheave. Extend clean & clear rig floor due to packed off frac sand. Clean up all frac sand. Service Rig, check equip. fluid levels. Change out handling equip. Prep vacs clean out BHA. P/U 4x finger basket mule shoe assy. on PH6 jt. Cont. P/U vacs BHA for 70 jts of 2-7/8" 7.9# P110 PH6. T/ 2,181' Pump double displacement for pipe trip in. P/U VACS tool & jars, XO back to PH6. 10/14/2023 - Saturday 10/15/2023 - Sunday P/U VACS tool & jars, XO back to PH6. Cont. RIH w/ VACS clean out BHA on 2-7/8" 7.9# P110 PH6. F/ 2,212' T/ 5,099'. Pump double displacement for pipe trip in. P/U wt = 32K S/O wt =13 K. Rig service, check equip. fluid levels. Cont. RIH w/ VACS clean out BHA on 2-7/8" 7.9# P110 PH6. F/ 5,099' T/ 6,003'. Pump double displacement for pipe trip in. Switch handling equipment F/ 2-7/8" T/ 3-1/2". XO string to 3.5" workstring. Cont. RIH w/ VACS clean out BHA on 3-1/2" 10.37# workstring . F/ 6,003' T/ 12,988'. Pump double displacement for pipe trip in. Entering liner top observed no set down weight. P/U wt = 128K S/O wt = 24 K. Kelly up & wash down w/ VACS tool. F/ 12,988' T/ 13,408' No indication of fill, no tag up. Attempt to dry tag after connections, no tag. Cont. to wash dw at 2.3 BPM w/ 2100 PSI. P/U wt = 138K S/O wt = 23 K. Loss rate 16 BPH dynamic. P/U wt increasing to 145K Circ & condition. Pump NXS lube around at 2.3 BPM w/ 2200 PSI. Drag reduced by 15K to 130K P/U WT. Loss rate 13.4 BPH dynamic. Cont wash down w/ VACS tool. F/ 13,409' T/ 13,548' Tagged fill / sand at 13,548' Picking up at mid joint to ensure manageable P/U weights. Cont. to wash dw at 2.3 BPM w/ 2100 PSI. P/U wt = 135K S/O wt = 24 K. Loss rate 13.4 BPH dynamic. Cont. RIH w/ VACS clean out BHA on 2-7/8" 7.9# P110 PH6. F/ 5,099' T/ 6,003'. Pump double displacement for pipe trip in. Switch handling equipment F/ 2-7/8" T/ 3-1/2". XO string to 3.5" workstring. Cont. RIH w/ VACS clean out BHA on 3-1/2" 10.37# workstring . F/ 6,003' T/ 12,988'. Pump double displacement for pipe trip in. Entering liner top observed no set down weight. P/U wt = 128K S/O wt = 24 K. Kelly up & wash down w/ VACS tool. F/ 12,988' T/ 13,408' No indication of fill, no tag up. Attempt to dry tag after connections, no tag. Cont. to wash dw at 2.3 BPM w/ 2100 PSI. P/U wt = 138K S/O wt = 23 K. Loss rate 16 BPH dynamic. P/U wt increasing to 145K Circ & condition. Pump NXS lube around at 2.3 BPM w/ 2200 PSI. Drag reduced by 15K to 130K P/U WT. Loss rate 13.4 BPH dynamic. Cont wash down w/ VACS tool. F/ 13,409' T/ 13,548' Tagged fill / sand at 13,548' Picking up at mid joint to ensure manageable P/U weights. Cont. to wash dw at 2.3 BPM w/ 2100 PSI. M/U landing joint & BOLDS. P/U unseat hanger at 103k. P/U wt reaching 142K. Clean P/U wt =135K. Slight drag f/ 140K t/ 135K. L/D hanger POOH w/ 3-1/2" 9.3# Hyd 563 ESP completion. F/ 12,348' T/ 9,124' Pump double displacement for pipe tripped out. Rig service, check equip. fluid levels. Cont. POOH w/ 3-1/2" 9.3# Hyd 563 ESP completion. F/ 9,124' T/ 5,929 Cont. POOH w/ 3-1/2" 9.3# Hyd 563 ESP completion. F/ 2,921' T/ 122' Change elevator inserts to 2-7/8" for ESP lift sub. L/D ESP Assy. Well Name Rig API Number Well Permit Number Start Date End Date MP F-116 ASR 50-029-023650-00-00 219-133 10/12/2023 10/20/2023 Hilcorp Alaska, LLC Weekly Operations Summary Complete Johny wacking stack. B/D kelly hose. Rack & tally 2-7/8" Tubing. Change out handling equip. Load ESP assy & GLMs . Hang ESP sheave & run esp cable through. P/U Motor, & tandem seals, Servcie. P/U GS, 2 x pumps, Zenith ported sub, DS head & 10' 2-7/8" 6.5# L-80 EUE pup. Cont. T/ RIH w/ ESP Assy. on 2-7/8" 6.5# L-80 EUE TBG F/ 118' T/ 4,067' Testing ESP cable every 1000'. Pump double displacement for pipe tripped in, RIH at 60 FPM. S/O wt = 12K. Service rig, Checkequip. fluid levels. Cont. T/ RIH w/ ESP Assy. on 2-7/8" 6.5# L-80 EUE TBG F/ 4,067' T/ 6,400' Testing ESP cable every 1000'. Pump double displacement for pipe tripped in, RIH at 60 FPM. S/O wt = 16K Cont wash down w/ VACS tool. to 13,548' Tagged fill / sand at 13,548' Pump NXS-lube New p/u WT = 89k s/o WT = 39K. Unable to wash past 13,548'. Decision made with OE, depth of clean out = 13,570' (ORKB adjusted) Bottom perf depth = 13,540' Loss rate 13.4 BPH dynamic. Shut down pumps & monitor well F/ 30 mins. Prep to POOH. (well Static). POOH w/ VACS clean out BHA & tapered string , L/D to pipeshed w/ 3-1/2" 10.37# workstring . F/ 13,548' T/ 10,021 '. Pump double displacement for pipe tripped out. P/U wt = 55 K S/O wt = 20 K. Service rig, check equip. fluid levels. POOH w/ VACS clean out BHA & tapered string, L/D to pipeshed w/ 3-1/2" 10.37# workstring . F/ 10,021' T/ 6,212 '. Pump double displacement for pipe tripped out. P/U wt = 28 K. Switch handling equipment F/ 3-1/2" T/ 2-7/8". Remove XO from TIW & install 2-7/8" PH6 XO. POOH w/ VACS clean out BHA L/D to pipeshed w/ 2-7/8" 7.9# PH6 . F/ 6,212 ' - T/ 2,212'. Pump double displacement for pipe tripped out. P/U wt = 14 K. L/D, jars & upper VACS tool, Service break BHA components. Cont. L/D VACS BHA for 70 jts of 2- 7/8" 7.9# P110 PH6. F/ 2,181' T/ 192' Pump double displacement for pipe trip in. Packed sand in last 6 joint of 2-7/8" 7.9# P110 PH6. For a total volume of sand = 5.5 cu / ft. L/D VACS BHA fingers basket subs x 2 & inspect. All components intact. Clean & clear rig floor of BHA & frac sand. Extended clean up time due to frac sand. Johny wack stack. 10/17/2023 - Tuesday 10/16/2023 - Monday Cont. L/D VACS BHA for 70 jts of 2- 7/8" 7.9# P110 PH6. F/ 2,181' T/ 192' Pump double displacement for pipe trip in. Packed sand in last 6 joint of 2-7/8" 7.9# P110 PH6. For a total volume of sand = 5.5 cu / ft. Load ESP assy & GLMs . Hang ESP sheave & run esp cable through. P/U Motor, & tandem seals, Servcie. P/U GS, 2 x pumps, Zenith ported sub, DS head & 10' 2-7/8" 6.5# L-80 EUE pup. Cont. T/ RIH w/ ESP Assy. on 2-7/8" 6.5# L-80 EUE TBG F/ 118' T/ 4,067' Testing ESP cable every 1000'. Pump double displacement for pipe tripped in, RIH at 60 FPM. S/O wt = 12K. Service rig, Checkequip. fluid levels. Cont. T/ RIH w/ ESP Assy. on 2-7/8" 6.5# L-80 EUE TBG F/ 4,067' T/ 6,400' Testing ESP cable every 1000'. Pump double displacement for pipe tripped in, RIH at 60 FPM. S/O wt = 16 Cont wash down w/ VACS tool. to 13,548' Tagged fill / sand at 13,548' Pump NXS-lube New p/u WT = 89k s/o WT = 39K. Unable to wash past 13,548'. Decision made with OE, depth of clean out = 13,570' Well Name Rig API Number Well Permit Number Start Date End Date MP F-116 ASR 50-029-023650-00-00 219-133 10/12/2023 10/20/2023 No operations to report. No operations to report. 10/21/2023 - Saturday No operations to report. 10/24/2023 - Tuesday 10/22/2023 - Sunday No operations to report. 10/23/2023 - Monday 10/20/2023 - Friday WELLHEAD. M/U hanger to LJ then P/U and M/U to string, Baker rep preformed penatrator splice. landed hanger to RKB then RILDS set BPV S/B for RDMO. Cleaned up hanger and void area N/U tree/adapter test void 500 low 5000 high 5/10 min test good. Pulled BPV and secured well. 10/18/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Cont. T/ RIH w/ ESP Assy. on 2-7/8" 6.5# L-80 EUE TBG F/ 6,400' T/ 7,911' Testing ESP cable every 1000'. Pump single displacement for pipe tripped in, RIH at 60 FPM. S/O wt = 20K. Perform ESP reel to reel splice. Simops. paint & stencil landing joints. Clean rig. Cont. T/ RIH w/ ESP Assy. on 2-7/8" 6.5# L-80 EUE TBG F/ 7,911' T/ 8,130' Testing ESP cable every 1000'. Pump single displacement for pipe tripped in, RIH at 60 FPM. S/O wt = 21K. Service rig, check equip. fluid levels. Cont. T/ RIH w/ ESP Assy. on 2-7/8" 6.5# L-80 EUE TBG F/ 8,130' T/ 12,794' Testing ESP cable every 1000'. Pump single displacement for pipe tripped in, RIH at 60 FPM. S/O wt = 31K P/U wt = 78K. P/U & M/U hanger w/ XO to 3-1/2" Torque to spec. Test ESP cable (good) Perform hanger splice. Land hanger on depth at 12,839' . S/O wt = 32K, P/U wt = 78K RILDS. Remove well equip. from rig floor. L/D all ESP tools. Rig released at 06:00 10/19/2023 Tubing hanger void test will be reported here when completed. 10/19/2023 - Thursday No operations to report. Perform hanger splice. Land hanger on depth at 12,839' . S/O wt = 32K, P/U wt = 78K RILDS. Cont. T/ RIH w/ ESP Assy. on 2-7/8" 6.5# L-80 EUE TBG F/ 6,400' T/ 7,911' Testing ESP cable every 1000'. Pump single displacement for pipe tripped in, RIH at 60 FPM. S/O wt = 20K. Perform ESP reel to reel splice. Simops. paint & stencil landing joints. Clean rig. Cont. T/ RIH w/ ESP Assy. on 2-7/8" 6.5# L-80 EUE TBG F/ 7,911' T/ 8,130' Testing ESP cable every 1000'. Pump single displacement for pipe tripped in, RIH at 60 FPM. S/O wt = 21K. Service rig, check equip. fluid levels. Cont. T/ RIH w/ ESP Assy. on 2-7/8" 6.5# L-80 EUE TBG F/ 8,130' T/ 12,794' Testing ESP cable every 1000'. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________MILNE PT UNIT F-116 JBR 11/24/2023 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:1 2 7/8" and 3 1/2" test joints used for testing. During test #2 valve K2 failed to hold dp. The valve was cycled and retested for a pass. Test Results TEST DATA Rig Rep:C. Grubb/M. BoordOperator:Hilcorp Alaska, LLC Operator Rep:S. Heim/R. Gallen Rig Owner/Rig No.:Hilcorp ASR 1 PTD#:2191330 DATE:10/13/2023 Type Operation:WRKOV Annular: 250/2500Type Test:INIT Valves: 250/2500 Rams: 250/2500 Test Pressures:Inspection No:bopGDC231013155937 Inspector Guy Cook Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 9 MASP: 2259 Sundry No: 323-542 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 0 NA Ball Type 2 P Inside BOP 1 P FSV Misc 0 NA 16 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 11" 5000 P #1 Rams 1 2 7/8"X5" VB P #2 Rams 1 Blinds P #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 2 /16" 5000 P HCR Valves 1 2 /16" 5000 P Kill Line Valves 3 1.5" 2 /16" 50 FP Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1825 200 PSI Attained P17 Full Pressure Attained P53 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P4@2337 ACC Misc NA0 NA NATrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P12 #1 Rams P6 #2 Rams P6 #3 Rams NA0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill NA0 9 9 9 9 9 9999 9 9 FP K2 failed to hold dp. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Fill Cleanout 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): 13,785'N/A Casing Collapse Conductor N/A Surface 3,090psi Production 5,410psi Liner 7,500psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: 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 12,900' MD / 6,824' TVD and N/A Ryan Lewis ryan.lewis@hilcorp.com 303-906-5178 4-1/2"877' 13,029' Perforation Depth MD (ft): 13,777' See Schematic See Schematic 3-1/2" 9,055' 13,054' 80' 20" 9-5/8" 7" 9,029' N/A 8,430psi 5,750psi 7,240psi 4,724' 6,968' 7,648' Length Size Proposed Pools: 80' 80' 9.2 / L-80 / Hyd 563 TVD Burst 12,832' MD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025509 / ADL355017 219-133 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23650-00-00 Hilcorp Alaska LLC C.O. 432E AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 10/10/2023 Liner Top Packer 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-116 MILNE POINT KUPARUK RIVER OIL n/a 7,656' 13,777' 7,648' 2,259 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 12:55 pm, Oct 04, 2023 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.10.04 07:49:44 - 08'00' Taylor Wellman (2143) 2,259 SFD 10/5/2023 107' *107' * DSR-10/5/23 *from Initial Well Completion Report received 4/8/2020 SFD MGR09OCT23 10/10/2023 10-404 * BOPE test to 2500 psi. *&:JLC 10/9/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.10.10 09:07:11 -08'00'10/10/23 RBDMS JSB 101023 ESP Swap & FCO Well: MPU F-116 Date: 09-28-2023 Well Name:MPU F-116 API Number:50-029-23650-00 Current Status:ESP Producer/Failed ESP Pad:F-Pad Estimated Start Date:10/10/23 Rig:ASR Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:219-133 First Call Engineer:Ryan Lewis (303) 906-5178 (M) Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) AFE Number:Job Type:ESP Swap & FCO Current Bottom Hole Pressure:2,504 psi @ 6,752’ TVD BHP taken on 09/28/2023 (DH Gauge) |7.13 PPG Maximum Expected BHP:2,934 psi @ 6,752’ TVD BHP from prior RWO & VRR ~1.0 |8.36 PPG MPSP:2,259 psi Gas Column Gradient (0.1 psi/ft) Max Inclination 68° @ 2,703’ MD Max Dogleg:7.5°/100ft @ 2,067’ MD Brief Well Summary: MPU well F-116 is a Kuparuk A & C sand production well drilled in November 2019. The well was hydraulically fracture stimulated in both the Kuparuk A & C sands (2 stage job) in late December 2019. The temporary 3-1/2” jet pump completion in the well was installed for the frac and for initial flowback. March of 2020 the Jet Pump assembly was removed and the ESP was installed. On 11/5/2020 the ESP pulled in a slug of frac sand and became plugged. The well operated until another large influx of sand has plugged the ESP on 09/21/2023. Attempts to clean and restart have resulted in a grounded ESP motor. Notes Regarding Wellbore Condition x 9-5/8” casing pressure tested to 2,500 psi for 30 minutes on 11/9/19 x 7” casing pressure tested to 4,000 psi for 10 minutes on 11/27/19 Objective: x Pull 3-1/2” ESP completion / Clean out liner past perfs / Install new ESP Pre-Rig Procedure (Non Sundried Work): 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 produced water down tubing, taking returns up casing to 500 barrel returns tank. a. Add metal to metal friction reducer to the KWF to aid in pulling weights. 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. Brief RWO Procedure (Begin Sundried Work): 9. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 bbl returns tank. 7” casing pressure tested to 4,000 psi for 10 minutes on 11/27/19 ESP Swap & FCO Well: MPU F-116 Date: 09-28-2023 10. 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 produced water prior to setting CTS. 11. NU BOPE. 12. Test BOPE to 250 psi low/ 2,500 psi high. Test annular to 250 psi low/ 2,500 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 2-7/8” and 3-1/2” test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 13. Bleed any pressure on casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the returns tank. Kill well with produced water as needed. Pull BPV. a. If indications show pressure underneath BPV, lubricate out BPV. 14. Call out Centrilift for ESP pull. 15. MU landing joint or spear and PU on the tubing hanger. a. During the December 2020 ASR ESP Install: PUW = 135k lbs and SOF = 42k lbs. 16. Recover the tubing hanger. a. Evaluate pulled tubing hanger for possible thread damage. If any damage is found, dispose of tubing hanger and contact well head specialist for replacement. 17. POOH and lay down the 3-1/2” tubing (Note: Hydril 563 Connections). a. Note any sand or erosive damage on the tubulars and ESP on the morning report. i. Look for over-torqued connections from original completion. ii. If any joints appear suspect of damage to threads or tubing, send to G&I for disposal. iii. Send the good 3-1/2” tubing for inspection. 18. RU Baker VACS clean-out assembly. 19. RIH on 3-1/2” workstring and dry tag fill. a. Expected fill at bottom of ESP at ± 12,840’ MD. 20. Pick up to closest connection and come online down tubing with pump at 5bpm. Establish pumping parameters. Monitor for possible returns from well with pumps online. 21. Continue pumping once joint is fully tripped to ensure save travels to the uphole end of the washpipe. 22. Continue to clean out to target depth of ± 13,600’ MD. 23. TOOH LD cleanout assembly. 24. RU spooler for ESP cable. 25. PU new ESP and RIH on 2-7/8” 6.5# L-80 tubing. Set base of ESP assembly at ± 12,840’ MD. a. 2-7/8” EUE 8rd Tubing b. 2-7/8”x 1” Side-pocket GLM with 0.25” OV at ± 140’ MD. c. 2-7/8” EUE 8rd Tubing d. 2-7/8”x 1” Side-pocket GLM with DV e. 2 full joints of 2-7/8” Tubing If indications show pressure underneath BPV, lubricate out BPV. ESP Swap & FCO Well: MPU F-116 Date: 09-28-2023 f. 2-7/8” ‘XN’ (2.205” ID) Nipple g. 1 joint of 2-7/8” tubing h. ESP Pump assembly i. Base of ESP centralizer @ ±12,840’ MD 26. Land tubing hanger. RILDS. Lay down landing joint. Note Pick-up and slack-off weights on tally. 27. Set BPV. Post-Rig Procedure: 28. RD mud boat. RD BOPE house. Move to next well location. 29. RU crane. ND BOPE. 30. NU existing 3-1/8” 5,000# tree. Test tubing hanger void to 500 psi low/5,000 psi high. 31. Pull BPV. 32. RD crane. Move returns tank and rig mats to next well location. 33. Replace gauge(s) if removed. 34. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOP Schematic _____________________________________________________________________________________ Revised By: TDF 1/21/2021 SCHEMATIC Milne Point Unit Well: MP F-116 Last Completed: 12/20/2020 PTD: 219-133 TD =13,785’ (MD) / TD =7,656’ (TVD) 20” Jet Pump Fish Left in Hole Orig. KB Elev.: 37.6’ / GL Elev.: 11.5’ 7” 16 9-5/8” 1 17 PBTD =13,691’ (MD) / PBTD = 7,567’ (TVD) 4-1/2” Shoe @ 13,777’ 10 &11 3& 4 ES Cementer @2,769’ 2 5, 6, 7 & 8 &11 12 9 13 14 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 215 / X-52 / Weld N/A Surface 107’ N/A 9-5/8" Surface 40 / L-80 / TXP BTC 8.835 Surface 9,055’ 0.0758 7” Intermediate 26 / L-80 / TXP-BTC 6.276 Surface 13,054’ 0.0383 4-1/2” Liner 12.6 / L-80 / TXP-BTC 3.958 12,900’ 13,777’ 0.0152 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / Hyd 563 2.992 Surface 12,832’ 0.0087 OPEN HOLE / CEMENT DETAIL Conductor ± 270 ft3 12-1/4" Stg 1 L – 900 sx / T - 400 sx / Stg 2 L – 447 sx / T – 270 sx (304 bbls to surface) 9-7/8”x 8-1/2” 180 sx 6-1/8” 102 sx WELL INCLINATION DETAIL KOP @ 400’ Max Hole Angle 65 deg TREE & WELLHEAD Tree 5M CIW 3-1/8” Tree Wellhead 5M FMC Gen IV GENERAL WELL INFO API: 50-029-23650-00-00 Cased by Innovation: 11/29/2019 Completed by ASR#1 – 3/18/2020 ESP Swap by ASR#1 – 12/20/2020 JEWELRY DETAIL No. Top MD Item ID 1 12,578’ST 1: Camco " x 1" w/Dummy Valve BK Latch 2 12,668’ 3-1/2” X Nipple w/ 2.813" Min ID 2.813 3 12,709.8’ Discharge Head: B/O PMP 400 3.5"x2-7/8" EUE 1040 4 12,710’ Ported Sub: Zenith B/O S/A B/O PRESS PORT 400P PMP 5 12,711’ Pump 4: 400PMSXD 134 FLEXER H6 FER 6 12,735’ Pump 3: 400PMSXD 134 FLEXER H6 FER 7 12,758’ Pump 2: 400PMSXD 134 FLEXER H6 FER 8 12,782’ Pump 1: 400PMSXD 024 GINPSHL H6 FER 9 12,792’ Gas Separator: GASSEP 538 GSTHVEX 10 12,798’ Upper Tandem Seal: GSBDB H6 SB/AB PFSA 11 12,805’ Lower Tandem Seal: GSB#DB H6 SB/AB PFSA 12 12,811’ Motor: 562 XP 250/2505/61_208/2090 10R 13 12,828’ Gauge & Centralizer: Zenith –Bottom @ 12,832’ 14 12,900’ Liner Top Packer 4.340 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk C 13,354’ 13,358’ 7,251’ 7,255’ 4 2-1/8” 12/25/19 Open Kuparuk B7 13,362’ 13,400’ 7,258’ 7,294’ 38 2-1/2” 12/25/19 Open Kuparuk A3 13,438’ 13,448’ 7,330’ 7,339’ 10 2-1/2” 1/25/2020 Open Kuparuk A2 13,456’ 13,460’ 13,460’ 13,474’ 7,347’ 7,350’ 7,350’ 7,364’ 4 14 2-1/8” 2-1/2” 12/13/19 1/25/2020 Open Open Kuparuk A1 13,485’ 13,540’ 7,374’ 7,426’ 55 2-1/2” 12/25/19 Open Ref Log: 11/24/2019 Halliburton MWD _____________________________________________________________________________________ Revised By: TDF 10/3/2023 PROPOSED Milne Point Unit Well: MP F-116 Last Completed: 12/20/2020 PTD: 219-133 TD =13,785’(MD) / TD =7,656’(TVD) 20” Jet Pump Fish Left in Hole Orig. KB Elev.: 37.6’ / GL Elev.: 11.5’ 7” 16 9-5/8” 2 17 PBTD =13,691’(MD) / PBTD = 7,567’(TVD) 4-1/2” Shoe @ 13,777’ 10 &11 4&5 ES Cementer @2,769’ 3 6& 7 12 & 13 8 & 9 14 15 1 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 215 / X-52 / Weld N/A Surface 107’ N/A 9-5/8" Surface 40 / L-80 / TXP BTC 8.835 Surface 9,055’ 0.0758 7” Intermediate 26 / L-80 / TXP-BTC 6.276 Surface 13,054’ 0.0383 4-1/2” Liner 12.6 / L-80 / TXP-BTC 3.958 12,900’ 13,777’ 0.0152 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE 8rd 2.441 Surface ±12,840’ 0.0058 OPEN HOLE / CEMENT DETAIL Conductor ± 270 ft3 12-1/4" Stg 1 L – 900 sx / T - 400 sx / Stg 2 L – 447 sx / T – 270 sx (304 bbls to surface) 9-7/8”x 8-1/2” 180 sx 6-1/8” 102 sx WELL INCLINATION DETAIL KOP @ 400’ Max Hole Angle 65 deg TREE & WELLHEAD Tree 5M CIW 3-1/8” Tree Wellhead 5M FMC Gen IV GENERAL WELL INFO API: 50-029-23650-00-00 Cased by Innovation: 11/29/2019 Completed by ASR#1 – 3/18/2020 ESP Swap by ASR#1 – 12/20/2020 JEWELRY DETAIL No. Top MD Item ID 1 ±140’ 2-7/8”x 1” Side-pocket GLM with 0.25” OV 2 ±XX,XXX’ST 1: 2-7/8” x 1" Side-pocket GLM w/ DV 3 ±XX,XXX’ 2-7/8” X Nipple w/ 2.205" Min ID 2.813 4 ±XX,XXX’ Discharge Head: 5 ±XX,XXX’ Ported Sub: 6 ±XX,XXX’ Pump 2: 7 ±XX,XXX’ Pump 1: 8 ±XX,XXX’ Gas Separator: 9 ±XX,XXX’ Intake: 10 ±XX,XXX’ Upper Tandem Seal: 11 ±XX,XXX’ Lower Tandem Seal: 12 ±XX,XXX’ Motor: 13 ±XX,XXX’ Motor: 14 ±XX,XXX’ Sensor & Centralizer: Bottom @ ±12,840’ 15 12,900’ Liner Top Packer 4.340 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk C 13,354’ 13,358’ 7,251’ 7,255’ 4 2-1/8” 12/25/19 Open Kuparuk B7 13,362’ 13,400’ 7,258’ 7,294’ 38 2-1/2” 12/25/19 Open Kuparuk A3 13,438’ 13,448’ 7,330’ 7,339’ 10 2-1/2” 1/25/2020 Open Kuparuk A2 13,456’ 13,460’ 13,460’ 13,474’ 7,347’ 7,350’ 7,350’ 7,364’ 4 14 2-1/8” 2-1/2” 12/13/19 1/25/2020 Open Open Kuparuk A1 13,485’ 13,540’ 7,374’ 7,426’ 55 2-1/2” 12/25/19 Open Ref Log: 11/24/2019 Halliburton MWD Milne Point ASR Rig 1 BOPE 2023 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 David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-5245 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt and return one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 07/22/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Log Date Log Type MPU C-04 500292080100 182-126 2/27/2021 Wipestock MPU I-07A 500292260201 221-010 5/8/2021 Perf Record MPU L-06 500292200300 190-010 5/18/2021 Wipestock MPU S-21 500292306500 202-009 6/3/2021 Perf Record MPU F-116 500292365000 219-133 1/25/2020 Perf Record MPU I-19 500292321800 204-135 4/10/2020 CCL Please include current contact information if different from above. eceived By: 07/22/2021 37' (6HW By Abby Bell at 3:14 pm, Jul 22, 2021 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: ESP Swap Hilcorp Alaska 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 13,785 feet N/A feet true vertical 7,656 feet N/A feet Effective Depth measured 13,777 feet 12,900 feet true vertical 7,648 feet 6,824 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3 / L-80 / Hyd 563 12,832' 6,760' Packers and SSSV (type, measured and true vertical depth)Liner Top Packer 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 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Chad Helgeson Contact Name: Authorized Title:Operations Manager Contact Email: Contact Phone: WINJ WAG 0 Water-Bbl MD 80' 9,055' 13,054' TVD 80' 559 Oil-Bbl measured true vertical Packer 13,777' Junk measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 00 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-133 50-029-23650-00-00 Plugs ADL025509 / ADL355017 5. Permit to Drill Number: Milne Point Field / Kuparuk Oil Pool 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-481 349 Authorized Signature with date: Authorized Name: David Gorm dgorm@hilcorp.com Size 360 Milne Point Unit F-116 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 589 Gas-Mcf 340 Casing Pressure Tubing Pressure 291 N/A measured 877' N/A Liner Casing Conductor Length 80' 9,029' 13,029' Surface Production 20" 9-5/8" 7" 4-1/2" 4,724' 6,968' 7,648' 5,410psi 7,500psi Burst N/A 5,750psi 7,240psi 8,430psi 777-8333 2. Operator Name Senior Engineer: Senior Res. Engineer: Collapse N/A 3,090psi PL G Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 10:15 am, Jan 22, 2021 Chad Helgeson (1517) 2021.01.21 14:17:14 - 09'00' SFD 1/26/2021DSR-1/22/21MGR18FEB2021 RBDMS HEW 1/27/2021 _____________________________________________________________________________________ Revised By: TDF 1/21/2021 SCHEMATIC Milne Point Unit Well: MP F-116 Last Completed: 12/20/2020 PTD: 219-133 TD =13,785’ (MD) / TD =7,656’ (TVD) 20” Jet Pump Fish Left in Hole Orig. KB Elev.: 37.6’ / GL Elev.: 11.5’ 7” 16 9-5/8” 1 17 PBTD =13,691’(MD) / PBTD =7,567’(TVD) 4-1/2” Shoe @ 13,777’ 10 &11 3& 4 ES Cementer @2,769’ 2 5, 6, 7 & 8 &11 12 9 13 14 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 215 / X-52 / Weld N/A Surface 107’ N/A 9-5/8" Surface 40 / L-80 / TXP BTC 8.835 Surface 9,055’ 0.0758 7” Intermediate 26 / L-80 / TXP-BTC 6.276 Surface 13,054’ 0.0383 4-1/2” Liner 12.6 / L-80 / TXP-BTC 3.958 12,900’ 13,777’ 0.0152 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / Hyd 563 2.992 Surface 12,832’ 0.0087 OPEN HOLE / CEMENT DETAIL Conductor ± 270 ft3 12-1/4" Stg 1 L – 900 sx / T - 400 sx / Stg 2 L – 447 sx / T – 270 sx (304 bbls to surface) 9-7/8”x 8-1/2” 180 sx 6-1/8” 102 sx WELL INCLINATION DETAIL KOP @ 400’ Max Hole Angle 65 deg TREE & WELLHEAD Tree 5M CIW 3-1/8” Tree Wellhead 5M FMC Gen IV GENERAL WELL INFO API: 50-029-23650-00-00 Cased by Innovation: 11/29/2019 Completed by ASR#1 – 3/18/2020 ESP Swap by ASR#1 – 12/20/2020 JEWELRY DETAIL No. Top MD Item ID 1 12,578’ST 1: Camco " x 1" w/Dummy Valve BK Latch 2 12,668’ 3-1/2” X Nipple w/ 2.813" Min ID 2.813 3 12,709.8’ Discharge Head: B/O PMP 400 3.5"x2-7/8" EUE 1040 4 12,710’ Ported Sub: Zenith B/O S/A B/O PRESS PORT 400P PMP 5 12,711’ Pump 4: 400PMSXD 134 FLEXER H6 FER 6 12,735’ Pump 3: 400PMSXD 134 FLEXER H6 FER 7 12,758’ Pump 2: 400PMSXD 134 FLEXER H6 FER 8 12,782’ Pump 1: 400PMSXD 024 GINPSHL H6 FER 9 12,792’ Gas Separator: GASSEP 538 GSTHVEX 10 12,798’ Upper Tandem Seal: GSBDB H6 SB/AB PFSA 11 12,805’ Lower Tandem Seal: GSB#DB H6 SB/AB PFSA 12 12,811’ Motor: 562 XP 250/2505/61_208/2090 10R 13 12,828’ Gauge & Centralizer: Zenith –Bottom @ 12,832’ 14 12,900’ Liner Top Packer 4.340 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk C 13,354’ 13,358’ 7,251’ 7,255’ 4 2-1/8” 12/25/19 Open Kuparuk B7 13,362’ 13,400’ 7,258’ 7,294’ 38 2-1/2” 12/25/19 Open Kuparuk A3 13,438’ 13,448’ 7,330’ 7,339’ 10 2-1/2” 1/25/2020 Open Kuparuk A2 13,456’ 13,460’ 13,460’ 13,474’ 7,347’ 7,350’ 7,350’ 7,364’ 4 14 2-1/8” 2-1/2” 12/13/19 1/25/2020 Open Open Kuparuk A1 13,485’ 13,540’ 7,374’ 7,426’ 55 2-1/2” 12/25/19 Open Ref Log: 11/24/2019 Halliburton MWD Well Name Rig API Number Well Permit Number Start Date End Date MP F-116 LRS 50-029-23650-00-00 219-133 12/14/2020 12/20/2020 Begin to prep for ASR rig move. No operations to report. 12/12/2020 - Saturday LRS load diesel and mobilize to MP F-116. MIRU LRS. P/T lines to 250 psi low and 2,500 psi high. T/I/O = 52/538/45 psi. Attempt to bleed off gas from Tubing but see fluid returns (more than line volume) so shut in at Tank. T/I/O = 42/538/45 psi. Wait on 8.6 ppg brine to arrive. Open IA to tank and bleed gas while heating diesel. Circulate 10 bbls of 100 degree diesel down tubing while taking returns out the IA and to the return tank. Choke at 50%. T/I/O = 463/102/46 psi. Circulate 120 degree 8.6 ppg brine at 4.8 BPM. See fluid at tank at 16 bbls of 8.6 ppg brine away but returns are very gassy ( energized fluid). T/I/O = 600/90/100 psi. Tubing fluid packed at 120 bbls away. T/I/O = 590/330/350 psi. M/U hose to bleed OA if necessary. Choke full open. Circulate a total of 550 bbls of 8.6 ppg brine while taking returns to the tiger tank. Seeing 1:1 returns until 337 bbls away. Returns drop to 80%. T/I/O = 600/538/52 psi. Reduce rate to 4 BPM. T/I/O = 450/260/450 psi. At 360 bbls away, returns drop to 60%. Choke is full open. Reduce rate again to 3 BPM. T/I/O = 87/110/414 psi. Returns still at 50%. From 409 bbls away to 530 bbls away, returns contnue to decrease from 60% to 25% . Still no 8.6 ppg brine to surface. Tubing pressure continues to increase from 87 psi to 250 psi while IA pressure is falling rapidly as 8.6 ppg fills IA. See 8.6 returns at tank at 520 bbls away. Contnued to circulate until returns seemed clean. Shut down at 550 bbls of 8.6 ppg brine circulated. (pumped 30 bbls after 8.6 ppg brine seen at tank and only got 9 bbls returned) Got a total of 455 bbls of returns. Lost a total of 95 bbls . Monitor well. T/I/O = vac/vac/200 psi. FP surface lines with 60/40. Set BPV. Pump 1 bbl of 60/40 down IA and Tubing. T/I/O = vac/vac/200 psi. RDMO LRS to Milne camp. 12/15/2020 - Tuesday 12/13/2020 - Sunday No operations to report. 12/14/2020 - Monday 12/11/2020 - Friday No operations to report. 12/9/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 12/10/2020 - Thursday No operations to report. Well Name Rig API Number Well Permit Number Start Date End Date MP F-116 LRS 50-029-23650-00-00 219-133 12/14/2020 12/20/2020 12/16/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Waiting on weather: Monitoring weather for a window to start up ops. Winds down to 25-30mph. Crane crew arrived 14:00hrs. MIRU 150 ton Crane. ND Production tree. Inspected hanger and lifting threads. Fly on NU the 11" BOP Stack. Fly on Rig floor. RDMO Crane. Stand up the ASR. Hook up HCR lines and winterize. Finish torque up BOPE. Continue to Prep for BOPE test make up 3.5" test mandril. NU Spacer spools and Flow Spool. RU 6" Flow line Cont. to RU pump lines and Glycol unit. Hook up BOPE lines and function test. Install derrick rack pins. RU work floor. Pick up test mandril and RU kelly. set in stack and fill stack . work air out of the system. BOPE Test as per sundry 250/low 2,500/high annular, 250/low 3,000/high all rams and valves hold 5min no failures. wittness waived bt Adam Earl. 12/17/2020 - Thursday Continued BOPE Test number 8 and 9 (250psi Low/3,000psi High). Preformed Koomey Draw down test. Pre-charge 1,000psi, Sys Pressure 2,925psi, Draw Down 1,650psi, 200psi Attainted 15sec, Full Pressure Attained 65sec, Nitgn Bottles 4 avg pressure of 2,312psi. No failures recorded. AOGCC witness waived by Adam Earl on 12-15-20 @ 10:06am. Blow lines dry and L/D BOPE Testing equipment. NU 2' 11" 5M Spacer spool on top of stack. Hung cable sheave and the elephant trunk. PU 3- 1/2 Handling tools. PU Tee Bar, Pulled plug off tool. Monitored well Tbg on vac. Pulled BPV PU/MU 3-1/2" Landing Jt into hanger. BOLDS verified IA pressure is 0psi. Pulled Tbg Hanger off-seat 95k PU to 150k check stack to make sure hanger was not hanging up in a BOP Cavity. Continued work pipe to 150k. Discussed with town and decide to pull Rig Max 163k. Continued working string up to 163k with no success. Calculated string weight 135k. Measured pipe stretch of 31" at 165k. Discussed with town and decided to mix and spot a lube pill due to reduce friction. Landed Hanger and RILDS. BO/LD Landing joint. Mixed 40 bbls NXS lube pill. Lined up to pump dn tbg returns up IA. Began Pumping, Pumped 40 bbls lube pill @ 3bpm/50psi swapped to 8.6 brine and caught fluid @ 42bbls/350psi, started getting minimal returns at 45bbls away continued circulating 3bpm/330psi SD pump at 150bbls spotting lube pill @ ~11,000'. Returns during circulation of 18bbls of 8.6 Brine. 90% losses. PU/MU Landing Jt and BOLDS. Pulled tbg hanger off seat 95k and pulled to 165k same parameters with no help from lube pill. Order 320bbls of lubed brine from Bariod. Continue working string while waiting on fluid to arrive from town. Work Tbg string from 100k to 165K while waiting on Lubed Fluid from Barriod. Fluid arrive. Lay down landing jnt. RU to Pump Lube down the CSG up the TBG. Start pumping @ 4 BPM about 100 psi. caught pressure 110 BBls away pressure at 250psi. fluid level +- 4170'. 135 Bbls away caught returns. tbg pressure at 400psi Csg pressure at about 50 psi. getting about a 45% returns. total fluid loss 216 Bbls. 350 total bbls pumped. shut pumps off and bleed off both sides went on a vac. Blow down lines Make up landing jnt and BOLDS. Pick up on tbg string 95 K off seat, 135K up wt. Tbg moving free. Pull tbg hanger to surface. De-mobe Tbg hanger with Wellhead support and Baker centrilift. LD landing jnt and tbg hanger. pull ESP cable through sheave and tie into the spooler. POOH/w ESP completion on 3-1/2" 9.3# L-80 536 wedge TBG. 60 jnts out @ +-10,800'MD Up Wt. 84K clamps and tbg look good and reusable. fluid loss 4BPH. POOH/w ESP completion on 3-1/2" 9.3# L-80 536 wedge TBG 10,800'MD- 9,500'MD Up Wt. 73K, clamps and tbg look good and reusable. fluid loss 4BPH Well Name Rig API Number Well Permit Number Start Date End Date MP F-116 LRS 50-029-23650-00-00 219-133 12/14/2020 12/20/2020 Hilcorp Alaska, LLC Weekly Operations Summary 12/18/2020 - Friday Held PJSM, Checked fluid and serviced rig. POOH/w ESP completion on 3-1/2" 9.3# L-80 536 wedge TBG f/9,500' t/7,704' PUW 65k, inspecting tbg and clamps for rerun. Pumping displacement @ ~2bph, L/D total of 159jts. Cont POH/w ESP completion on 3-1/2" 9.3# L-80 536 wedge TBG f/7,704' t/6,022' PUW 47k, inspecting Tbg and clamps for rerun. Pumping displacement @ ~2bph, L/D total of 213jts. Cont POH/w ESP completion on 3-1/2" 9.3# L-80 536 wedge TBG f/6,022' t/4,832' PUW 41k, inspecting Tbg and clamps for rerun. Pumping displacement @ ~2bph, L/D total of 252jts. Made reel swap. Cont POH/w ESP completion on 3-1/2" 9.3# L-80 536 wedge TBG f/4,832' t/2,923' PUW 27k, inspecting Tbg and clamps for rerun. Pumping displacement @ ~2bph, L/D total of 312jts. Cont POH/w ESP completion on 3-1/2" 9.3# L-80 536 wedge TBG f/2,923' t/921' PUW 15k, inspecting Tbg and clamps for rerun. Pumping displacement @ ~2bph, L/D total of 376jts. Crew change, Service and inspect rig. and equipment. Cont POH/w ESP completion on 3-1/2" 9.3# L-80 536 wedge TBG from 921' to surface with pump, inspecting Tbg and clamps for rerun. Pumping displacement @ ~2bph. Did not see any sand in GLM, XN, 3 jnts below GLM. Sand in discharge head and handling sub pump sanded off. lower pump spinning free. rest of equipment clean. All clamps accounted for, cable tested good. Make up slickLine tools 3" drive down Sand bailer, 3.5" Cenrilizer, RU slickline. RIH to 5,200' tag fluid, RIH @ 20FPM down to 13,498' verifiy depth. POOH/w Slick line and RD. Bailer came out with frac sand in it. Set Dummy Valve in open GLM with slick line at surface. Swap reels in spooler, Prep to PU/MU and service New ESP completion. PJSM, checked fluids and serviced rig as needed. PU/MU and service New ESP Assembly. Pulled cable thru sheave and prepared to RIH. TIH w/New ESP on 3-1/2" 9.3# L-80 563 Hydril Tbg. PU 1 Joint, X-Nipple (2.813" ID), 2 Joints, GLM w/Dummy Value continued TIH. Utilizing X-collar Clamps every Joint. Stopped on joint 60 (2,016') to test cable-good test. Current SOW 15k. Continued TIH w/ ESP on 3-1/2" 9.3# L-80 563 Hydril Tbg. f/2016'md t/4,016'md. Stopped on Joint 123 to test cable-good test. Utilizing X-collar Clamps every Joint then every other after Joint 110. Current SOW 20k. Continued TIH w/ ESP on 3-1/2" 9.3# L-80 563 Hydril Tbg. f/4,016'md t/6,021'md. Stopped on Joint 187 to test cable-good test. Utilizing X- collar Clamps every other Joint. Current SOW 23k. Continued TIH w/ ESP on 3-1/2" 9.3# L-80 563 Hydril Tbg. f/6,021'md t/6,337'md. Stopped on Joint 197 to make reel splice. Made reel to reel splice. Continued TIH w/ ESP on 3-1/2" 9.3# L-80 563 Hydril Tbg. f/6,337' t./8,343' added a 10' pup jnt between jnts 202-203 to space out splice off the collar. test cable good.Utilizing X-collar Clamps every other Joint. Current SOW 27k. Continued TIH w/ ESP on 3-1/2" 9.3# L-80 563 Hydril Tbg. f./8,343' t/10,311 . test cable good.Utilizing X-collar Clamps every other Joint. Current SOW 32k. Continued TIH w/ ESP on 3- 1/2" 9.3# L-80 563 Hydril Tbg. f/10,311 t/12,787' . test cable good.Utilizing X-collar Clamps every other Joint. Current SOW 41k. PU/MU TBG hanger with 3.5" NCST lifting threads. BPV installed. Make Final penetrator splice on hanger. 12/19/2020 - Saturday No operations to report. 12/20/2020 - Sunday PJSM, Centrifilt make cable splice to penetrator. Preformed final cable test good. Land Completion, PU wt. 135k, SO wt. 42K. RILDS, Total Jnts 403, Hanger+ KB, EOT @ 12,831.83'MD. BO/LD Landing joint. BPV is set. No issues while Landing Completion. END OF WELL. Begin RDMO to F-58. Cleaned and cleaned rig floor. Broke down winterizations and circulating lines. Soft broke BOP Stack and removed Hyd control lines. RDMO pipe shed, Pump and Catwalk. Hauled 118 bbls of 8.5 Brine out of pits and RDMO. LD Mast and RDMO ASR 1 and Mud Boat. Began Crane ops. Fly off Stairs and Rig Floor. ND BOP Stack. Loaded NU Production Tree. Fly off Well Hut. Test Tree 250/low 5,000/high hold 5min and 15 min test good. 12/21/2020 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP F-116 LRS 50-029-23650-00-00 219-133 12/14/2020 12/20/2020 Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 12/22/2020 - Tuesday 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? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 13,785'N/A Casing Collapse Conductor N/A Surface 3,090psi Production 5,410psi Liner 7,500psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name: David Gorm Operations Manager Contact Email: Contact Phone: 777-8333 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng 12/2/2020 3-1/2" Perforation Depth MD (ft): See Schematic Milne Point Field / Kuparuk Oil Pool Milne Point Unit F-116 Liner Top Packer and N/A 12,900' MD / 6,824' TVD and N/A 13,777' See Schematic 80'20" 9-5/8" 7" 9,029' 4-1/2"877' N/A 8,430psi 13,029' 5,750psi 7,240psi 4,724' 6,968' 7,648' 9,055' 13,054' 7,648'2,448 N/A 80'80' 9.2 / L-80 / Hyd 563 TVD Burst 12,815' MD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025509 / ADL355017 219-133 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23650-00-00 Hilcorp Alaska LLC C.O. 432D Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY Length Size 7,656'13,777' dgorm@hilcorp.com COMMISSION USE ONLY Authorized Name: Authorized Signature: Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. Chad A Helgeson 2020.11.11 14:18:21 -09'00' By Samantha Carlisle at 9:28 am, Nov 12, 2020 320-481 BOPE Test tp 3000 psi. Annular to 2500 psi. DLB11/12/2020 X MGR13NOV20 10-404 DSR-11/13/2020Comm pq Yes 11/17/2020 dts 11/16/2020 JLC 11/16/2020 RBDMS HEW 11/17/2020 Convert to ESP Well: MPU F-116 Date: 11-10-2020 Well Name:MPU F-116 API Number:50-029-23650-00 Current Status:ESP Producer/Failed ESP Pad:F-Pad Estimated Start Date:December 2nd, 2020 Rig:ASR Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:219-133 First Call Engineer:David Gorm (907) 777-8333 (O)(505) 215-2819 (M) Second Call Engineer:David Haakinson (907) 777-8343 (O)(307) 660-4999 (M) AFE Number:Job Type:ESP Repair Current Bottom Hole Pressure:3,183 psi @ 7,350’ TVD BHP taken on 3/3/2020 (SBHP) |8.3 PPG Maximum Expected BHP:3,183 psi @ 7,350’ TVD BHP taken on 3/3/2020 (SBHP) |8.3 PPG MPSP:2,448 psi Gas Column Gradient (0.1 psi/ft) Max Inclination 68° @ 2,703’ MD Max Dogleg:7.5°/100ft @ 2,067’ MD Brief Well Summary: MPU well F-116 is a Kuparuk A & C sand production well drilled in November 2019. The well was hydraulically fracture stimulated in both the Kuparuk A & C sands (2 stage job) in late December 2019. The temporary 3-1/2” jet pump completion in the well was installed for the frac and for initial flowback. March of 2020 the Jet Pump assembly was removed and the ESP was installed. On 11/5/2020 the ESP pulled in a slug of frac sand. Notes Regarding Wellbore Condition x 9-5/8” casing pressure tested to 2,500 psi for 30 minutes on 11/9/19 x 7” casing pressure tested to 4,000 psi for 10 minutes on 11/27/19 Objective: x Pull existing 3-1/2” ESP completion x Install new ESP Pre-Rig Procedure: 1. RU Pump Unit and PT lines to 3000 psi. 2. Kill the well with 8.3 PPG Source water. Contact Engineer to review kill procedure. 3. Clear and level pad area in front of well. Spot rig mats and containment. 4. RD well house and flowlines. Clear and level area around well. 5. Confirm well is dead. 6. RU crane. Set BPV. ND Tree. NU BOPE. RD Crane. 7. NU BOPE house. Spot mud boat. Brief RWO Procedure: 8. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines to returns tank. 9. Check for pressure and if 0 psi, pull BPV. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/8.33 ppg Source Water prior to pulling BPV. 10. Set PBV Plug (converting BPV to TWC). Convert to ESP Well: MPU F-116 Date: 11-10-2020 11. Test BOPE to 250 psi Low/ 3,000 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Confirm test pressures per the Sundry Conditions of approval. c. Test VBR ram on 3-1/2” test joint. d. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 12. Bleed any pressure off casing to returns tank. Pull BPV plug and BPV. Kill well w/8.3 ppg Source water as needed. 13. MU landing joint or spear and PU on the tubing hanger. a. During the 2020 ASR ESP Install. PUW = 98k lbs (Note: ESP Stuck Cable in the WH on initial landing had to pull 144 Klbs to free then landed again). b. If needed, circulate (long or reverse) pill with lubricant, source-water prior to laying down the tubing hanger. 14. Recover the tubing hanger. a. Evaluate pulled tubing hanger for possible thread damage. If any damage is found, dispose of tubing hanger and contact well head specialist for replacement. 15. POOH and lay down the 3-1/2” tubing (Note: Hydril 563 Connections). a. Note any sand or erosive damage on the tubulars and ESP on the morning report. i. Look for over-torqued connections from original completion. ii. If any joints appear suspect of damage to threads or tubing, send to G&I for disposal. iii. Plan to re-run 3-1/2” tubing. 16. PU 850’ of 2-3/8” Clean Out BHA, RIH on 3-1/2” workstring. Contact Engineer to Review clean out plan, max clean out depth of 13,650’ MD. POOH 17. RU spooler for ESP cable. 18. PU new ESP and RIH on 3-1/2” 9.2# L-80 tubing. Set base of ESP assembly at ± 12,850’ MD. a. 3-1/2” H563 Tubing b. 3-1/2”x 1” Side-pocket GLM with 0.25” OV. c. 3-1/2” H563 Tubing d. 3-1/2”x 1” Side-pocket GLM with DV e. 2 full joints of 3-1/2” Tubing f. 3-1/2” ‘X’ (2.813” ID) Nipple g. 1 joint of 3-1/2” tubing h. ESP Pump assembly i. Base of ESP centralizer @ ±12,850’ MD 19. Land tubing hanger. RILDS. Lay down landing joint. Note Pick-up and slack-off weights on tally. 20. Set BPV. Post-Rig Procedure: 21. RD mud boat. RD BOPE house. Move to next well location. 22. RU crane. ND BOPE. 23. NU existing 3-1/8” 5,000# tree. Test tubing hanger void to 500 psi low/5,000 psi high. Convert to ESP Well: MPU F-116 Date: 11-10-2020 24. Pull BPV. 25. RD crane. Move returns tank and rig mats to next well location. 26. Replace gauge(s) if removed. 27. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOP Schematic _____________________________________________________________________________________ Revised By: TDF 11/11/2020 SCHEMATIC Milne Point Unit Well: MP F-116 Last Completed: 3/18/2020 PTD: 219-133 TD =13,785’ (MD) / TD =7,656’ (TVD) 20” Jet Pump Fish Left in Hole Orig. KB Elev.: 37.6’ / GL Elev.: 11.5’ 7” 5, 6 & 7 16 9-5/8 ” 1 17 PBTD =13,691’(MD) / PBTD =7,567’(TVD) 3 & 4 4-1/2” Shoe @ 13,777’ 8 & 9 12 ES Cementer @2,769’ 2 10 & 11 13 14 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 215 / X-52 / Weld N/A Surface 107’ N/A 9-5/8" Surface 40 / L-80 / TXP BTC 8.835 Surface 9,055’ 0.0758 7” Intermediate 26 / L-80 / TXP-BTC 6.276 Surface 13,054’ 0.0383 4-1/2” Liner 12.6 / L-80 / TXP-BTC 3.958 12,900’ 13,777’ 0.0152 TUBING DETAIL 3-1/2" Tubing 9.2 / L-80 / Hyd 563 2.992 Surface 12,815’ 0.0087 OPEN HOLE / CEMENT DETAIL Conductor ± 270 ft3 12-1/4" Stg 1 L – 900 sx / T - 400 sx / Stg 2 L – 447 sx / T – 270 sx (304 bbls to surface) 9-7/8”x 8-1/2” 180 sx 6-1/8” 102 sx WELL INCLINATION DETAIL KOP @ 400’ Max Hole Angle 65 deg TREE & WELLHEAD Tree 5M CIW 3-1/8” Tree Wellhead 5M FMC Gen IV GENERAL WELL INFO API: 50-029-23650-00-00 Cased by Innovation: 11/29/2019 Completed by ASR#1 – 3/18/2020 JEWELRY DETAIL No. Top MD Item ID 1 12,587’ST 1: Camco 3-1/2” X 1'' GLM Dummy w/ BK Latch 2 12,647’ 3-1/2” X Nipple 2.813 3 12,728’ Discharge Head: 4 12,728.7’ Ported Discharge PSI Head 5 12,729’ Pump 3: 538PMSXD 119 P23 M FER 6 12,747’ Pump 2: 538PMSXD 066 FLEX47 H6 7 12,763’ Pump 1: 538PMSXD 020 GINPSHH H6 8 12,773’ Gas Separator: 538 GSTHVEX MT FER 9 12,778’ Bolt on Intake: GPXARCINT FER H6 10 12,779’ Upper Seal: GSB3DB H6 SB/AB PFSA 11 12,786’ Lower Seal: GSB3DB H6 SB/AB PFSA 12 12,793’ Motor: 562 XP 250 Hp/2,505 V/ 61A 13 12,810’ Zenith Motor Gauge & Centralizer: Bottom @ 12,815 14 12,900’ Liner Top Packer 4.340 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk C 13,354’ 13,358’ 7,251’ 7,255’ 4 2-1/8” 12/25/19 Open Kuparuk B7 13,362’ 13,400’ 7,258’ 7,294’ 38 2-1/2” 12/25/19 Open Kuparuk A3 13,438’ 13,448’ 7,330’ 7,339’ 10 2-1/2” 1/25/2020 Open Kuparuk A2 13,456’ 13,460’ 13,460’ 13,474’ 7,347’ 7,350’ 7,350’ 7,364’ 4 14 2-1/8” 2-1/2” 12/13/19 1/25/2020 Open Open Kuparuk A1 13,485’ 13,540’ 7,374’ 7,426’ 55 2-1/2” 12/25/19 Open Ref Log: 11/24/2019 Halliburton MWD _____________________________________________________________________________________ Revised By: TDF 11/11/2020 PROPOSED Milne Point Unit Well: MP F-116 Last Completed: 3/18/2020 PTD: 219-133 TD =13,785’ (MD) / TD =7,656’ (TVD) 20” Jet Pump Fish Left in Hole Orig. KB Elev.: 37.6’ / GL Elev.: 11.5’ 7” 16 9-5/8” 1 17 PBTD =13,691’ (MD) / PBTD = 7,567’ (TVD) 4-1/2” Shoe @ 13,777’ 3 ES Cementer @2,769’ 2 4 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 215 / X-52 / Weld N/A Surface 107’ N/A 9-5/8" Surface 40 / L-80 / TXP BTC 8.835 Surface 9,055’ 0.0758 7” Intermediate 26 / L-80 / TXP-BTC 6.276 Surface 13,054’ 0.0383 4-1/2” Liner 12.6 / L-80 / TXP-BTC 3.958 12,900’ 13,777’ 0.0152 TUBING DETAIL 3-1/2" Tubing 9.2 / L-80 / Hyd 563 2.992 Surface ±12,850’ 0.0087 OPEN HOLE / CEMENT DETAIL Conductor ± 270 ft3 12-1/4" Stg 1 L – 900 sx / T - 400 sx / Stg 2 L – 447 sx / T – 270 sx (304 bbls to surface) 9-7/8”x 8-1/2” 180 sx 6-1/8” 102 sx WELL INCLINATION DETAIL KOP @ 400’ Max Hole Angle 65 deg TREE & WELLHEAD Tree 5M CIW 3-1/8” Tree Wellhead 5M FMC Gen IV GENERAL WELL INFO API: 50-029-23650-00-00 Cased by Innovation: 11/29/2019 Completed by ASR#1 – 3/18/2020 JEWELRY DETAIL No. Top MD Item ID 1 ±12,682’ST 1: 3-1/2” X 1'' GLM 2 ±12,762’ 3-1/2” X Nipple 3 ±12,763’ ESP Assembly: Bottom @ ±12,850 5 12,900’ Liner Top Packer 4.340 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk C 13,354’ 13,358’ 7,251’ 7,255’ 4 2-1/8” 12/25/19 Open Kuparuk B7 13,362’ 13,400’ 7,258’ 7,294’ 38 2-1/2” 12/25/19 Open Kuparuk A3 13,438’ 13,448’ 7,330’ 7,339’ 10 2-1/2” 1/25/2020 Open Kuparuk A2 13,456’ 13,460’ 13,460’ 13,474’ 7,347’ 7,350’ 7,350’ 7,364’ 4 14 2-1/8” 2-1/2” 12/13/19 1/25/2020 Open Open Kuparuk A1 13,485’ 13,540’ 7,374’ 7,426’ 55 2-1/2” 12/25/19 Open Ref Log: 11/24/2019 Halliburton MWD Milne Point ASR Rig 1 BOPE BOPE ~4.48' ~4.54' 2.00' 5000# 2-7/8" x 5" VBR 5000#Blind DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualManual Stripping Head Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 8/20/2020 To: AOGCC Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL MPU F-116 (PTD 219-133) Please include current contact information if different from above. Received by the AOGCC 08/24/2020 PTD: 2191330 E-Set: 33678 Abby Bell 08/24/2020 STATE OF ALASKA Reviewed By: 32<� OIL AND GAS CONSERVATION COMMISSION P.J. Supry BOPE Test Report for: MILNE PT UNIT F -I 16 , Comm Contractor/Rig No.: Hilcorp ASR 1 Operator: Hilcorp Alaska LLC Type Operation: WRKOV Sundry No: Type Test: INIT 319-587 PTD#: 2191330 DATE: 3/9/2020 - Operator Rep: Phillip Shumake/Rob Oneal Test Pressures: Rams: Annular: Valves: MASP: 250/5000 ' 250/2500 - 250/4000 ' 3144 FLOOR SAFTY VALVES: System Pressure _ TEST DATA P/F MISC. INSPECTIONS: MUD SYSTEM: NA Lower Kelly P/F NA Visual Alarm ._ 1 - Location Gen.: P Trip Tank NA NA Housekeeping: P Pit Level Indicators P P - PTD On Location P Flow Indicator NA - NA. Standing Order Posted P Meth Gas Detector P P - Well Sign P H2S Gas Detector P -_ P" Drl. Rig P MS Mise NA NA Hazard Sec. P -- "Mise Check Valve 0 Mise NA 1 FP FLOOR SAFTY VALVES: System Pressure _ Quantity P/F Upper Kelly 0 NA Lower Kelly 0 NA Ball Type ._ 1 - FP✓ Inside BOP 1 P- FSV Misc 0 NA BOPSTACK: Quantity Size Inspector Lou Laubenstein Insp Source Rig Rep: Matt Beshea Inspector Inspection No: bopLOL200311121938 Related Insp No: ACCUMULATOR SYSTEM: Time/Pressure P/F System Pressure _ 2900 P Pressure After Closure 1550 P 200 PSI Attained 17 P Full Pressure Attained 65 P " Blind Switch Covers: yes P " Nitgn. Bottles (avg): 4 (&_ 2500_P 1 ACC Misc 0 NA P/F Stripper 0 NA_ Annular Preventer 1 . 11" FP ✓' #1 Rams 1 2 7/8" x 5" P #2 Rams 1 - 2 7/8" x 5" P #3 Rams 1 - Blinds P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA_ Choke Ln. Valves 1 . 2 1/16" P -_ HCR Valves 1 ' 2 1/16" P Kill Line Valves 2 " 2 1/16" P Check Valve 0 NA BOP Misc 1 FP CHOKE MANIFOLD: INSIDE REEL VALVES: (Valid for Coil Rigs Only) Quantity P/F Inside Reel Valves 0 _ NA Number of Failures: 3 Test Results Test Time 8 Remarks: 5K test pressure on a new stack, 4k on the rest of the equipment. TIW valve failed to hold and was greased and retested. Annular failed and was cycled then passed. BOP Misc failure was a leaking flange on the kill manifold. Quantity P/F No. Valves 16 P Manual Chokes I P ' Hydraulic Chokes I P ' CH Misc 0 NA INSIDE REEL VALVES: (Valid for Coil Rigs Only) Quantity P/F Inside Reel Valves 0 _ NA Number of Failures: 3 Test Results Test Time 8 Remarks: 5K test pressure on a new stack, 4k on the rest of the equipment. TIW valve failed to hold and was greased and retested. Annular failed and was cycled then passed. BOP Misc failure was a leaking flange on the kill manifold. DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23650-00-00Well Name/No. MILNE PT UNIT F-116Completion Status1-OILCompletion Date12/13/2019Permit to Drill2191330Operator Hilcorp Alaska, LLCMD13785TVD7656Current Status1-OIL4/14/2020UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, DGR, EWR-PH 4, CTN, ALD MD, DGR, EWR-PH 4, CTN, ALD TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleC12/17/2019100 13785 Electronic Data Set, Filename: MPU F-116 LWD Final.las31678EDDigital DataC12/17/20199045 13733 Electronic Data Set, Filename: MPU F-116 ADR Quadrants All Curves.las31678EDDigital DataC12/17/2019 Electronic File: MPU F-116 LWD Final MD.cgm31678EDDigital DataC12/17/2019 Electronic File: MPU F-116 LWD Final TVD.cgm31678EDDigital DataC12/17/2019 Electronic File: MPU F-116_DSR Surveys.xlsx31678EDDigital DataC12/17/2019 Electronic File: MPU F-116_DSR.pdf31678EDDigital DataC12/17/2019 Electronic File: MPU F-116_DSR.txt31678EDDigital DataC12/17/2019 Electronic File: MPU F-116_GIS.txt31678EDDigital DataC12/17/2019 Electronic File: MPU F-116_Plan.pdf31678EDDigital DataC12/17/2019 Electronic File: MPU F-116_VSec.pdf31678EDDigital DataC12/17/2019 Electronic File: MPU F-116 LWD Final MD.emf31678EDDigital DataC12/17/2019 Electronic File: MPU F-116 LWD Final TVD.emf31678EDDigital DataC12/17/2019 Electronic File: MPU_F-116_Geosteering.dlis31678EDDigital DataC12/17/2019 Electronic File: MPU_F-116_Geosteering.ver31678EDDigital DataC12/17/2019 Electronic File: MPU F-116 LWD Final MD.pdf31678EDDigital DataC12/17/2019 Electronic File: MPU F-116 LWD Final TVD.pdf31678EDDigital DataC12/17/2019 Electronic File: MPU F-116 LWD Final MD.tif31678EDDigital DataC12/17/2019 Electronic File: MPU F-116 LWD Final TVD.tif31678EDDigital Data0 0 2191330 MILNE PT UNIT F-116 LOG HEADERS31678LogLog Header ScansTuesday, April 14, 2020AOGCCPage 1 of 2MPU F-116 LWDFinal.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23650-00-00Well Name/No. MILNE PT UNIT F-116Completion Status1-OILCompletion Date12/13/2019Permit to Drill2191330Operator Hilcorp Alaska, LLCMD13785TVD7656Current Status1-OIL4/14/2020UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsSentSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:12/13/2019Release Date:10/8/2019Tuesday, April 14, 2020AOGCCPage 2 of 2M. Guhl4/14/2020 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: __________________ Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3.Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8.Date TD Reached: 16.Well Name and Number: Surface: Top of Productive Interval: 9.Ref Elevations: KB: 17. Field / Pool(s): GL: BF: Total Depth: 10.Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- TPI: x- y- Zone- 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore:21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22.Logs Obtained: 23. BOTTOM 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: Oil-Bbl: 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 Date of Test: Flow Tubing Gas-Oil Ratio:Choke Size:Water-Bbl: PRODUCTION TEST Per 20 AAC 25.283 (i)(2) attach electronic information CASING WT. PER FT.GRADE TOP SETTING DEPTH MD TOP CEMENTING RECORDSETTING DEPTH TVD HOLE SIZE AMOUNT PULLED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG WAG Gas BOTTOM SIZE DEPTH SET (MD) PACKER SET (MD/TVD) TUBING RECORD If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, to production or injection? YesNo 25. 26. Ye No SIZE DEPTH SET (MD) TUBING RECORD t each interval open (MD/TVD of Top and Bottom; Perforation Number; Date Perfd): ACID, FRACTURE, CEMENT SQUEEZE, ETC. PACKER SET (MD/TVD) BOTTOM WT. PER FT.GRADE TOP SETTING DEPTH MD TOP CEMENTING RECORDSETTING DEPTH TVD HOLE SIZE AMOUNT PULLEDBOTTOM CASING, LINER AND CEMENTING RECORD Obtained: on, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, esistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation Acronyms may be used. Attach a separate page if necessary List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, onal or Inclination Survey: Yes (attached) No 13.Water Depth, if Offshore:21.Re-drill/Lateral Top Window MD/TVD: it electronic information per 20 AAC 25.050 (ft MSL) ion of Well (State Base Plane Coordinates, NAD 27):11.Total Depth MD/TVD: 19.DNR Approval Number: x-y-Zone- x- y-Zone-12.SSSV D 20.epth MD/TVD:Thickness of Permafrost MD/TVD: pth: x- y-Zone- ion of Well (Governmental Section):8.Date TD Reached:16.Well Name and Number: oductive Interval:9.Ref Elevations: KB: 17.f Field / Pool(s): GL: BF: pth:10.Plug Back Depth MD/TVD: 18.Property Designation: ss:7.Date Spudded:15.API Number: or Name:6.., Susp., or 14. Permit to Drill Number / Sundry: Aband.: Status:OilSPLUG OtherAbandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory WINJ WDSPLNo. of Completions: ____________________ Service Stratigraphic Test WAG G Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment 1 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 2227' FSL, 2429' FEL, Sec 6, T13N, R10E, UM, AK 1570' FNL, 203' FWL, Sec 33, T14N, R10E, UM, AK 1468' FNL, 307' FWL, Sec 33, T14N, R10E, UM, AK 542131 549978 550081 6035680 6042490 6042593 4 4 4 11/28/2019 10/31/2019 11/22/2019 37.6' 11.5'11.5' 13,691' MD / 7,567' TVD 13,785' MD / 7,656' TVD N/A N/A 219-133 / 319-545 / 319-587 50-029-23650-00-00 MPU F-116 Milne Point Unit / Kuparuk River Oil Pool ADL025509 / ADL355017 LONS 94-109 2,512' MD / 1,937' TVD N/A ROP DGR EWR-Phase 4, CTN, ALD MD, DGR, EWR-Phase 4, CTN, ALD TVD 20" 215# X-52 Surface 107' Surface 107' 42" ±270 ft3 9-5/8"40# L-80 Surface 9,055' Surface 4,724' 12-1/4" Stg 1 L - 900 sx / T - 400 sx Stg 2 L - 447 sx / T - 270 sx 304 bbls 7" 26# L-80 Surface 13,054' Surface 6,969' 9-7/8" x 8-1/2" 180 sx 4-1/2" 12.6# L-80 12,890' 13,777' 6,815' 7,647' 6-1/8" 102 sx ***Please see attached schematic for perforation detail*** 3-1/2" 12,815' 12,890' MD / 6,815' TVD Liner Top Packer **See Frac Report** 02/21/2020 ESP 03/28/2020 24 1188 244 378 N/A 205 625 580 1188 244 378 22.0 ✔ ✔ ✔ ✔ ✔ By Samantha Carlisle at 8:40 am, Apr 08, 2020 12/13/2019 YesCompletion date 12/13/19 A sand perforated (gls) gls 4/9/20 G Was hydraulic fracturing used during completion? Date Comp. DSR-4/8/2020 CDW 04/14/2020 Completion Date 12/13/2019 HEW SFD 4/10/2020 RBDMS HEW 4/9/2020 ✔ DLB 4/8/2020 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Top of Productive Interval 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Contact Email: Contact Phone: General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: 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. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). 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. 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. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. 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). 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. 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. This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. 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. 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. TPI (Top of Producing Interval). INSTRUCTIONS Authorized Name: Authorized Title: Authorized SignatureZ'DWH: 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Formation at 7': 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. Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base No Sidewall Cores: 30. TVD countered):FORMATION TESTS d summarize lithology and presence of oil, gas or water (subm and all subsequent laboratory analytical results per 20 AAC 2 Yes No Well tested? Yes No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment 2512 1937 Kup C 13354 7251 SV6 3180 2204 UG4 3844 2484 LA3 6284 3542 SB NA 7696 4139 Colville 9185 4777 HRZ 12992 6910 Kalubik 13011 6928 Kup D 13207 7112 Kup C 13350 7247 Kup B 13362 7258 Kup A 13437 7328 Kup A Drilling Manager Monty Myers Cody Dinger cdinger@hilcorp.com 777-8389 Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports, Frac Reports. ✔✔ ✔ Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.04.08 07:55:11 -08'00' Monty M Myers _____________________________________________________________________________________ Revised By: CJD 4/6/2020 SCHEMATIC Milne Point Unit Well: MP F-116 Last Completed: 11/29/19 PTD: 219-133 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 215 / X-52 / Weld N/A Surface 107’ N/A 9-5/8" Surface 40 / L-80 / TXP BTC 8.835 Surface 9,055’ 0.0758 7” Intermediate 26 / L-80 / TXP-BTC 6.276 Surface 13,054’ 0.0383 4-1/2” Liner 12.6 / L-80 / TXP-BTC 3.958 12,900’ 13,777’ 0.0152 TUBING DETAIL 3-1/2" Tubing 9.2 / L-80 / Hyd 563 2.992 Surface 12,815’ 0.0087 OPEN HOLE / CEMENT DETAIL Conductor ± 270 ft3 12-1/4" Stg 1 L – 900 sx / T - 400 sx / Stg 2 L – 447 sx / T – 270 sx (304 bbls to surface) 9-7/8”x 8-1/2” 180 sx 6-1/8” 102 sx WELL INCLINATION DETAIL KOP @ 400’ Max Hole Angle 65 deg TREE & WELLHEAD Tree 5M CIW 3-1/8” Tree Wellhead 5M FMC Gen IV GENERAL WELL INFO API: 50-029-23650-00-00 Cased by Innovation: 11/29/2019 Completed by ASR#1 – 3/18/2020 JEWELRY DETAIL No. Top MD Item ID 1 12,587’ ST 1: Camco 3-1/2” X 1'' GLM Dummy w/ BK Latch 2 12,647’ 3-1/2” X Nipple 2.813 3 12,728’ Discharge Head: 4 12,728.7’Ported Discharge PSI Head 5 12,729’ Pump 3: 538PMSXD 119 P23 M FER 6 12,747’ Pump 2: 538PMSXD 066 FLEX47 H6 7 12,763’ Pump 1: 538PMSXD 020 GINPSHH H6 8 12,773’ Gas Separator: 538 GSTHVEX MT FER 9 12,778’ Bolt on Intake: GPXARCINT FER H6 10 12,779’ Upper Seal: GSB3DB H6 SB/AB PFSA 11 12,786’ Lower Seal: GSB3DB H6 SB/AB PFSA 12 12,793’ Motor: 562 XP 250 Hp/2,505 V/ 61A 13 12,810’ Zenith Motor Gauge & Centralizer: Bottom @ 12,815 14 12,900’ Liner Top Packer 4.340 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk C 13,354’ 13,358’ 7,251’ 7,255’ 4 2-1/8” 12/25/19 Open Kuparuk B7 13,362’ 13,400’ 7,258’ 7,294’ 38 2-1/2” 12/25/19 Open Kuparuk A3 13,438’ 13,448’ 7,330’ 7,339’ 10 2-1/2” 1/25/2020 Open Kuparuk A2 13,456’ 13,460’ 13,460’ 13,474’ 7,347’ 7,350’ 7,350’ 7,364’ 4 14 2-1/8” 2-1/2” 12/13/19 1/25/2020 Open Open Kuparuk A1 13,485’ 13,540’ 7,374’ 7,426’ 55 2-1/2” 12/25/19 Open Ref Log: 11/24/2019 Halliburton MWD Activity Date Ops Summary 10/28/2019 Finish installing Tree. Test void and Tree 500 PSI 5 min, 5,000 PSI 10 min. R/U and rig pumped 88 bbls Diesel Freeze Protect. Secure well. SIMOPS Cont. cleaning pits, Finish laying Herculite and matt boards at F-116. Clear rig floor of tools and Equip. Prep pad for rig move. Remove Beyond Equip.;Clear F Pad for rig moving in. Cont moving mud product and Misc truck loads to F-116.;PJSM R/D tongs. Removed board saver F/ Derrick for electrician. Bridle up and scope Derrick down. Blow down H2O & steam lines.. Swapped to Gen power at 16:30. R/D inner connects. Swapped to cold start power at 17:00. Secure Iron Roughneck.;PJSM Move mud products and misc loads to F Pad. Disconnect Enviro Vac and Break Shack. Jack up Pipe Shed and Gen Mod. Install Jeep. Peak trucks on location at 20:00. Stage Pipe Shed, Gen Mod, Catwalk and Mud Mod. Jack up Sub and remove shims. Prep for walking off well.;PJSM Walk off Sub F/ K-44 and install jeep. Pull Sub off matt boards. Prep all mods for convoy to F Pad. Cont. loading matt boards and clean pad. Start convoy to F Pad at 03:00. SIMOPS Install blank flanges on Tree annulus. 10/29/2019 Continue convoying modules from K-Pad to F-Pad. Stage mods. SimOps: install diverter 'T', stage wellhead equipment behind well.;Spot rig mats. Pull sub on mats and remove rear tires. Rotate and walk sub over F-116. Spot and level sub. Install 4" conductor valves on conductor.;Spot catwalk mod and shim pipeshed side. Spot MPD choke house. Spot pipeshed, mud mod. Hook up interconnect.;Spot and set Gen Mod Rig up air, water and steam. Spot auxiliary equipment; cuttings box, break shack, envirovac. Swap to gen power at 03:00. Remove diverter T and speed head. Weld on 7" extension on conductor. Mobilize pusher camp and shop from K-Pad. Begin rig acceptance checklist. 10/30/2019 Begin rig acceptance checklist. Safe out walkways and roof tops. Scope up derrick and bridle down. Rig up tongs. Perform derrick inspection. Sim Ops: begin processing 5" drill pipe in shed.;N/U Diverter. Install diverter 'T', set stack on diverter and hook up chain binders. Install knife valve. Begin installing diverter sections. SimOps: C/O wash pipe, racking board saver sensor, saversub, grabber dyes and bell guide. Cont. with rig acceptance checklist.;Cont. N/U diverter system. prep mat boards, dunnage and diverter stand for crane pick. SimOps: C/O saver sub. Cont working on rig acceptance checklist. Test gas alarms.;Change out shot pin housing on top drive and function test - good. Change out lube oil and hydraulic filter. SimOps: Unload aux trailers. Cont. to process 5" drill pipe. Spot diverter mat, stand and last section with crane. Take on mud, and function test equipment.;Install bell nipple and riser. Obtain RKB's. Install master bushings. Cont. to process drill pipe;Perform diverter test. State's right to witness waived by Guy Cook. Knife valve open = 4 second, annular close = 7 seconds. (6) N2 bottles at 2350 psi average. Drawdown starting pressure 2900 psi, final 1950 psi, first 200 psi recharge =20 seconds, full recharge 58 seconds.;Install mousehole. Pick up, drift and rack back 80 stands of 5" DP. 10/31/2019 Continue to drift, pick up and rack back total of 145 stands of 5" drill pipe, jars and 9 stands HWDP. L/D mousehole. Clean and clear rig floor and prep to pick up BHA.;Service rig: inspect and grease crown, iron roughneck, top drive and drawworks. Check oil level in TD. C/O 4 Hyd hoses on HPE unit.;M/U 12-1/4" Kymera bit to mud motor. Fill conductor Flood lines and PT to 3,000 psi - good.;Pre-Spud meeting. RIH and tag at 106'. Drill to 113', observe sand at shakers. Pick up and Displace to Spud Mud. Cont. drilling from 113' to 221' at 400 gpm/280 psi of bottom 400 psi on bottom. 40 rpms/1200 ft-lbs. WOB 1-3K. PUW 52K, SOW 48K.;CBU x 2 while racking one stand back. POOH with no issues. B/D TD. Pick up and inspect bit - good. Install short mouse hole.;Cont. to M/U 12-1/4" drilling BHA: M/U Gyro while drilling collar, measure RFO to motor =350.1°, M/U DM collar, measure RFO to motor =129.85°, M/U DGR, EWR-P4, PWD, HCIM, TM collars. Plug in and download. M/U (2) NM flex collars, XO, and 1 stand HWDP.;Shallow pulse test and check Gyro correlation. Wash down at 400 gpm/450 psi, 40 rpms/1000 ft-lbs to 221'.;Drill 12-1/4" surface hole from 221' to 238' at 400 gpm/550 psi, 40rpms/1200ft-lbs, WOB 2-5K. Collecting Gyro surveys every stand. PUW 55K, SOW 55K, ROTW 55K.;Cont. drilling 12-1/4" hole from 238' to 630' total 392' (AROP = 65 fph) at 450 gpm/950 psi, 40 rpms/2500 ft-lbs, WOB 8-15K, ECD's 9.6 ppg with 9.0 ppg drilling fluid. PUW 67K, SOW 67K, ROTW 67. Sliding as necessary to maintain 3-4°/100' from KOP at 396'. Obtaining gyro surveys every stand.;Daily hauled 114 bbls to G&I total = 114 bbls Hauled 1040bbls from 6 mile lake, Total 1040 bbls Lost 0 bbls to formation Total fluid lost section = 0 bbls 11/1/2019 Continue Drilling 12.25" surface hole F/ 630' - T/ 1245' MD (615' total / 103' AROP) . 450 gpm, 1220 psi, 60 rpm, 4.5k tq on, 8-12k WOB, 9.9 ECD's. 82k up, 78k dn, 79k rot. 250 avg diff psi.;Saw clean surveys @ 696' but kept Gyro surveys until 818' MD (last gyro svy). Shutdown gyro downhole tool. Drilling mostly clay.;Continue Drilling 12.25" surface hole F/ 1245' - T/ 1881' MD (636' total / 106' AROP) . 500 gpm, 1595 psi, 80 rpm, 5.5k tq on, 8-12k WOB, 10.15 ECD's. 90k up, 73k dn, 80k rot. 250 avg diff psi. Increase RPM's to 80 and flow to 500 gpm @ ~1465' MD. Max gas 235U.;Drilling predominantly clay to 1700' then transitioned to fine sand/silt.;Continue Drilling 12.25" surface hole F/ 1881' - T/ 2483' MD (602' total / 100' AROP). 525 gpm, 1630 psi, 80 rpm, 5k tq on, 2-4k WOB, 10.35 ECD's with 9.1 ppg mud. 95k up, 72k dn, 78k rot. Max gas 152U.;Continue Drilling 12.25" surface hole F/ 2483' - T/ 3023' MD (540' total / 90' AROP). Maintenance slide as needed to maintain WP08 550 gpm, 1700 psi, 80 rpm, 5K tq on, 2-5k WOB, 10.07 ECD's with 9.1 ppg mud. 106k up, 70k dn, 86k rot. Max gas 210U. Pump high vis sweep at 2960' 10% increase.;Distance to WP08: 19.46', 9.7' low, 16.88' right. Daily hauled 969 bbls to G&I total = 1083 bbls Hauled 910bbls from 6 mile lake, Total 1950 bbls Lost 0 bbls to formation Total fluid lost section = 0 bbls 26.5 n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: MP F-116 Milne Point Hilcorp Energy Company Composite Report North Slope Bourough, AK Contractor AFE #: AFE $: Innovation Job Name:1914665D MPU F-116 Drilling Spud Date: hydraulic filter. SimOps: Unload aux trailers. Cont. to process 5" drill pipe. Spot diverter mat, stand and last section with crane. T Continue Drilling 12.25" surface hole F/ 630' - T/ 1245' MD Knife valve open = 4 second, annular close = 7State's right to witness waived by Guy Cook. 11/2/2019 Continue Drilling 12.25" surface hole F/ 3023' - T/ 3660' MD (637' total / 106' AROP). Maintenance slide as needed to maintain WP08 525 gpm, 1640 psi, 80 rpm, 8K tq on, 2-5k WOB, 10.07 ECD's with 9.1 ppg mud. 112k up, 76k dn, 90k rot. Max gas 230u / 140u BGG.;Note: Base of Permafrost logged at 2512' MD/1937' TVD.;Continue Drilling 12.25" surface hole F/ 3660' - T/ 4296' MD (636' total / 106' AROP). Maintenance slide as needed to maintain WP08 600 gpm, 2280 psi, 80 rpm, 9.5K tq on, 8-11k WOB, 10.15 ECD's with 9.1 ppg mud. 121k up, 78k dn, 89k rot. Max gas 325u / 140u BGG.;Pump 40 bbls high vis sweep at 3914', 25% increase in cuttings, on time.;Continue Drilling 12.25" surface hole F/ 4296' - T/ 4931' MD (635' total / 106' AROP). Maintenance slide as needed to maintain WP08 600 gpm, 2225 psi, 80 rpm, 10.5K tq on, 2-7k WOB, 10.15 ECD's with 9.1 ppg mud. 137k up, 77k dn, 97k rot. Max gas 340u / 150u BGG.;Continue Drilling 12.25" surface hole F/ 4931' - T/ 5596' MD (665' total / 95' AROP). Maintenance slide as needed to maintain WP08 600 gpm, 2500 psi on btm with 150 psi diff, 80 rpm, 12-15K tq on, 5-12k WOB, 10.43 ECD's with 9.1 ppg mud. 152k up, 77k dn, 97k rot. Max gas 271u / 110u BGG.;Pump 35 bbls high vis sweep at 5313' with 30% increase in cuttings.;Distance to WP08: 7.55', 6.6' High, 3.65' Left. Daily hauled 1254 bbls to G&I total = 2337 bbls Hauled 1300 bbls from 6 mile lake, Total 3900 bbls Lost 0 bbls to formation Total fluid lost section = 0 bbls 11/3/2019 Continue Drilling 12.25" surface hole F/ 5596' - T/ 6236' MD (640' total / 107' AROP). Maintenance slide as needed to maintain WP08 600 gpm, 2680 psi on btm with 250 psi diff, 80 rpm, 16.5K tq on, 5-12k WOB, 10.2 ECD's with 9.1 ppg mud. 171k up, 79k dn, 108k rot. Max gas 230u / 40u BGG.;Continue Drilling 12.25" surface hole F/ 6236' - T/ 6397' MD (161' total / 107' AROP). Maintenance slide as needed to maintain WP08 600 gpm, 2660 psi on btm with 250 psi diff, 80 rpm, 16.5K tq on, 5-12k WOB, 10.2 ECD's with 9.1 ppg mud. 172k up, 78k dn, 108k rot. Max gas 195u / 40u BGG.;Circulate and condition @ 6397' MD. Rot / Recip. Pump 35 bbl hi vis sweep around. 10% inc, on time. 80 rpm, 15k tq, 600 gpm, 2435 psi.;Continue Drilling 12.25" surface hole F/ 6397' - T/ 6713' MD (316' total / 105' AROP). Maintenance slide as needed to maintain WP08 600 gpm, 2520 psi on btm with 150 psi diff, 80 rpm, 17.5K tq on, 4-8k WOB, 10.25 ECD's with 9.2 ppg mud. 182k up, 76k dn, 112k rot. Max gas 180u / 40u BGG.;Continue Drilling 12.25" surface hole F/ 6713' - T/ 7350' MD (637' total / 106' AROP). Maintenance slide as needed to maintain WP08 600 gpm, 2650 psi on btm with 250 psi diff, 80 rpm, 18.5K tq on, 7-12k WOB, 10.26 ECD's with 9.2 ppg mud. 195k up, 77k dn, 116k rot. Max gas 450u / 210u BGG.;Continue Drilling 12.25" surface hole F/ 7350' - T/ 7922' MD (572' total / 95' AROP). Maintenance slide as needed to maintain WP08 600 gpm, 2610 psi on btm with 210 psi diff, 80 rpm, 21-24K tq on, 5-15k WOB, 10.02 ECD's with 9.2 ppg mud. 1214 up, 81k dn, 122k rot. Max gas 430u / 200u BGG.;Distance to WP08: 13.18', 8.79' High, 9.82' Left. Daily hauled 1083 bbls to G&I total = 3420 bbls Hauled 1430 bbls from 6 mile lake, Total 5330 bbls Lost 0 bbls to formation Total fluid lost section = 0 bbls 11/4/2019 Continue Drilling 12.25" surface hole F/ 7922' - T/ 8527' MD (605' total / 101' AROP). Maintenance slide as needed to maintain WP08 600 gpm, 2850 psi on btm with 250 psi diff, 80 rpm, 23.5K tq on, 21k tq off,12k WOB, 10.3 ECD's w/ 9.2 ppg mud. 216k up, 81k dn, 126k rot. Max gas 550u / 200u BGG.;Saw ~100u BGG increase after drilling top of Schrader. Schrader formation top called @ 7696' MD / 4139' TVD. Pump high viscosity sweep at 8500' with 10% increase in cuttings.;Continue Drilling 12.25" surface hole F/ 8527' - T/ 9065' MD (538' total / 77' AROP). Maintenance slide as needed to maintain WP08 600 gpm, 3080 psi on btm with 250 psi diff, 80 rpm, 23K tq on, 21k tq off,16-20k WOB, 10.35 ECD's w/ 9.5 ppg mud. 222k up, 81k dn, 124k rot. Max gas 385u / 50u BGG.;Circulate hole clean: Pump 55 bbls high viscosity sweep (25% increase), reciporcate and rotate: 575 gpm/2460 psi, 80 rpms, 22K ft-lbs. Rack back 1 stand and circulate additional bottoms up. Max gas while circulating 185U. Monitor well, static. Wash and ream to bottom.;Downlink and cycle pumps to turn on Gyro on outrun battery mode.;BROOH from 9065' to 6644' at 600 gpm, 2350 psi, 60 rpms, 20Kft-lbs. Initial pulling speed 15 fph increasing to 30 fpm with no issues. ECD 9.9 ppg EMW, mud 9.45 ppg. 202k up, 81k dn, 112k rot. Max Gas 265U.;Distance to WP08: 14.34', 13.54' High, 4.73' Left. Daily hauled 912 bbls to G&I total = 4332 bbls Hauled 1330 bbls from 6 mile lake, Total 6660 bbls Lost 0 bbls to formation Total fluid lost section = 0 bbls 11/5/2019 Continue to BROOH from 6644' to 3723' at 600 gpm, 2050 psi, 60 rpms, 10k tq at 30-50fpm as hole dictates. 130k up, 71k dn, 91k rot.;Continue to BROOH from 3723' to 2100' (HWDP) 50 fpm, 600 gpm, 1522 psi, 60 rpms, 8-18k tq. Slow pulling speed to 5-15 fpm as hole dictates from 2100' to 737', 550 gpm, 1350 psi, 40 rpms, 4-10k tq, 77k up, 59k dn, 74k rot.;Monitor well, static. POOH from 737' (HWDP) on elevators; initial 5-10K drag through slides. Rack back HWDP, L/D (2) DC. Download MWD while cleanin and clearing rig floor.;L/D BHA: Remove probe from TM collar. L/D HCIM, PWD, DGR, DM collars. Remove probe from GWD collar. Drain motor and break bit. Bit Grade 1-3-BT-S-F-1-BU-TD. 2/3 cones had failed bearings. L/D GWD collar and motor.;Clean and clear rig floor.;Cut and slip drill line. Hang blocks, cut 75' drill line and slip on. TQ dead man, calibrate blocks. Service rig: grease blocks, crown and top drive. Check gear oil and hyd oil levels. Perform derrick inspection.;Rig up to RIH with 9-5/8" casing. Pick up volant CRT tool, install bail extensions. C/O handling equipment.;Daily hauled 342 bbls to G&I total = 4674 bbls Hauled 650 bbls from 6 mile lake, Total 7310 bbls Lost 0 bbls to formation Total fluid lost section = 0 bbls 11/6/2019 Finish rigging up Weatherford casing equipment. Power tongs and adjust operating pressures. 2 bph static loss rate.;PJSM, Run 9-5/8", 40#, L-80, TXP BTC casing to 1928' MD. M/U Shoe track (bakerlock connections). Circulate thru and check floats (good). Installed bypass above float collar. Fill every 5 jts. 20,800 ft/lbs tq connections. 40-60 fpm running speed. No issues running thru build section.;Continue run 9-5/8", 40#, L-80, TXP BTC casing F/ 1928' - T/ 3107' MD. 126k up, 75k dn.;Rot/Recip pipe @ 3107' MD. Stage up to 7 bpm, 150 psi, 48% flow, 7-10 rpm w/ 15k max tq. 142k up, 80k dn. Circulated STS. Saw slight to moderate sand/clay returns during cleanup cycle.;Continue run 9-5/8", 40#, L-80, TXP BTC casing F/ 3107' - T/ 6273' MD. Reduced running speed to 50 fpm max. M/U ES cementer - Bakerlok. Cont. RIH to 6390'. PUW 290K, SOW 84K. M/U TQ 21K.;Circulate hole clean, casing volume staging pumps up to 7 bpm, 200 psi, 0-2 rpms, 15K tq.;Continue run 9-5/8", 40#, L-80, TXP BTC casing F/ 6273' - T/ 9055' MD (casing point). Reduced running speed to 40 fpm max, then down to 30fpm at 7846'. SOW 85K. Cal displacement for run 137.1 bbls, actual 74.6 bbls.;Circulate hole, staging pumps up to 7 bpm, 240 psi. Attempt to reciprocate pipe, pulling up to 400K without breaking over.;Daily hauled 57 bbls to G&I total = 4731 bbls Hauled 390 bbls from 6 mile lake, Total 7310 bbls Lost 46 bbls to formation Total fluid lost section = 46 bbls Run 9-5/8", 40#, L-80, TXP BTC casing to 1928' MD. M/U Continue Drilling 12.25" surface hole F/ 7922' - T/ 8527' MD (6 TD surf ;Rig up to RIH with 9-5/8" casing. 11/7/2019 Continue circulating and conditioning mud 9.5 MW, 16 YP. Staged up to 7 bpm, 530 psi. Circulated a total of 2.5x btms up with no notable losses while circulating. Sym Ops - HES cementers rigged up H2O feed lines and 1502 high psi cmt line to rig.;R/U cmt line to cmt swivel head. Break circulation and stage up to 7 bpm, 570 psi, 47% flow. Attempt to recip pipe (no go w/ 450k max up, 15k tq). Wet lines and attempt to P/T. Had good low @ 1000 psi but failed 4k high psi test. Troubleshoot surface equipment. Found (2)ea leaking plug valves.;Replaced both valves and retested (test good). P/T 1000 low, 4000 high. Set eKO's @ 2000 psi (HES). 1st Stage 60 bbls 10 ppg tuned spacer (4# dye, 5# polyflake in 1st 10 bbls), 3.5 bpm, 215 psi Drop bypass plug 377 bbls Lead 12# ExtendaCem, 5 bpm, 500 psi,900 sxs, 2.349 yld;82 bbls Tail 15.8# SwiftCem, 3.6 bpm, 639 psi, 400 sxs, 1.158 yld Drop shut off plug Displacement - HES pumped 20 bbls H2O, 4 bpm, 215 psi Rig MP#1 pumped 141 bbls 9.5 mud, 7 bpm, 620 psi HES pumped 80 bbls 9.4 spacer, 4 bpm, 411 psi;Rig MP#1 pumped 441 bbls 9.5 mud, 5 bpm, 730 psi. Slowed rate to 3 bpm last 10 bbls. 3 bpm, 910 FCP. Bumped @ 9387 stks (9351 calc stks). CIP @ 15:24. Psi up 1200 and hold 5 min. Bled off 2.8 bbls, floats held. Saw spacer back @ 525 bbls into displacement.;Pressure up @ 3 bpm, shift ES cementer @ 2922 psi. Establish returns and stage up from 3 bpm to 5 bpm, 435 psi with partial returns initially and full returns within 10 mins. Stage pumps up to 6.5 bpm/400 psi circulating 2 x BU; 100bbls of green cement returned to surface. Shut down. disconnect;knife valve, drain stack and fill with black water. Function annular 3x. Perform flush two times. Flush out surface lines. Continue circulating at 6.5bpm/375 psi while prepping for second stage cement job. Flush lines, reduce surface volume.;PJSM pump second stage cement job: 5 bbls water at 2 bpm, 40 psi 60 bbls 10 ppg tuned spacer (4# dye, 5# polyflake in 1st 10 bbls), 4 bpm, 265 psi 351 bbls 'Perm L' Lead 10.7# , 5 bpm, 560 psi, 447 sxs, 4.407yld 56.2 bbls Class G Tail 15.8#, 3 bpm, 560 psi, 270sxs, 1.169 yld;Drop shut off plug Displacement - HES pumped 20 bbls H2O, 4.3 bpm, 365 psi Rig MP#1 pumped 190.4 bbls 9.4 mud, 5 bpm, 900 psi. Bump plug with calculated strokes. Pressure up to 2050 psi, observe ES cementer shift close at 1850 psi. Hold pressure for 5 minutes, bleed back 1 bbl and confirm tool;closed. CIP at 04:31, no losses during cement job. 304 bbls of green cement observed at surface.;Disconnect knife, drain stack and fill with black water, function annular 3x. Perform flush twice. Rig down and blow down cement lines. Flush out surface lines. Disconnect Volant tool. Suck out joint of casing.;Daily hauled 1628 bbls to G&I total = 6359 bbls Hauled 840 bbls from 6 mile lake, Total 8540 bbls 11/8/2019 PJSM, N/D diverter line. N/D riser, N/D DSA @ speed head. L/D mousehole and hoist stack. Secure same.;Clean slip profile and center casing. Set "E" slips w/ 110k string wt. mark cut jt 22" above slips. Cut 9-5/8" landing jt while hold 3k in elevators. L/D cut off joint. Cut jt = 30.16 - 4.35' stickup = 25.81' RKB to cut.;M/U Johnny whacker on single jt 5" DP. Flush stack @ 14 bpm. B/O and L/D jt. Drain stack, clean out cellar box. N/D knife valve and rack back BOP's on stump.;N/D diverter "T" and demob from cellar. Remove starter head and DSA. Dress casing stump. Remove 4" valves from conductor and install 4" caps. C/O solid master to split bushings. Sym Ops - Clean pits.;Install wellhead. Test seals to 500/2470 psi for 15 min -good.;Remove bell nipple on stack, clean out bolt holes for MPD. Lift MPD spool to flow box with tuggers. Set stack on well head and N/U BOPE. Install aluminum drip pan, and MPD spool. Sim Ops: clean pits, C/O ball valve on centrifuge suction line.;Install and torque choke and kill lines. Install MPD hard line. Pull MPD cap and install flow riser. Pressure up accumulator line.;M/U 5" test joint, TIW, dart valve. Fill stack, purge air. MPD clamp leaking. Adjust stack and tighten clamp. Shell test BOPE - Mezzanine kill line leaking. Close HCR and obtain good shell test.;Rebuild mezzanine kill valve, grease and function. Fill stack with air and purge.;Daily hauled 1069 bbls to G&I total = 7428 bbls Hauled 520 bbls from 6 mile lake, Total 9060 bbls Lost bbls to formation Total fluid lost section = 46 bbls 11/9/2019 Fill all lines and stack. Purge air from system. Shell test (pass). Test BOP's w/ 3.5" and 5" test jts. 250/4000 psi 5/5 min hold on each. Chart and record same. Drawdown test - 3000 psi initial, 1500 psi drawdown, 27 sec for 200 psi increase, 96 sec full charge.;Test witnessed by AOGCC rep Austin McLeod. Mezzanine kill was the only F/P for test. Tested 1x 5" Dart, 2x 5" TIW, 1x 4" Dart, 1x 4" TIW. Total test time post shell test 4.5 hrs. Next BOP test due - 11/23/2019;Install MPD test cap in RCD. Test MPD surface equipment to 1200 psi w/ 5 min hold (test good). R/D test equipment. Remove test cap and install MPD trip nipple. Pull BOP test plug.;Install wear bushing (38" H x 9" ID). RILDS (4x). Stage tool on floor for BHA.;M/U BHA #2 - 8.5" Smith XR+PS milltooth (re-run, 3x20's = .9204 TFA), 1.5° mtr strataforce 6/7 lobe: 6.0 stg w/ non ported float, 6x HWDP (5"), SLB jars, 11x HWDP (5"). Total BHA length = 592.96';Trip in hole F/ 592' - T/ 2,730' MD out of derrick.;Wash down to 2747' at 300 gpm, 500 psi. Tag on cement stringer at 2755'. Drill cement, ES cementer (tagging on depth) 400 gpm, 700 psi, 40 rpms 6k tq. Wash down to 2809', ream back through and run through without pumps/rotary. Clean.;Continue to RIH on elevators from 2809' to 8861' filling pipe every 3000'. PUW 240K, SOW 60K;Wash down from 8861' to 8921' with no issues. Circulate hole clean at 500 gpm, 1200 psi dumping contaminated mud. Rotate on downstroke at 20 rpms Tq limiter set at 24.5K; unable to get free torque. PUW 265K, SOW 75K.;Rig up head pin. Flush lines and purge air. Close UPR's. PT casing to 2500 psi for 30 minutes - good; 6.1 bbls pumped, 6.1 bbls returned. Rig down testing equipment, blow down lines.;Wash down and drill shoe track from 8924' to 9055' (5' above shoe) 500 gpm, 1750 psi, 30-40 rpms torque limiter set at 24.5k no free rotary, WOB 0-5K. Pump lube pill and add ~0.5% v/v. Tag up on Baffle adapter at 8941' (2'low) continue drilling with 0-1K WOB, tag FC on depth at 8978', on depth;Observe cement firm up a little at 9030' with WOB 2-4K.;At 9055' observe highly contaminated mud back at the shakers, packing off flow line multiple times. Jet flow line and pump through bleeder to clear. Continue circulating 2-10 bpm; lowering rate to prevent over running drag chain. Dump 187 bbls of mud, replacing with water.;Displace to 9.5 ppg LSND due to inability to maintain mud properties circulating on short system; 10 bpm/980 psi 40 rpms, 23K-ftlbs.;Daily hauled 295 bbls to G&I total = 7723 bbls Hauled 260 bbls from 6 mile lake, Total 9320 bbls Lost 0 bbls to formation Total fluid lost section = 46 bbls no losses during cement job. Drill cement, ES cementer (tagging 100bbls of green cement returned to surface. 1st stage N/U BOPE. 56.2 bbls Class G Tail PT casing to 2500 psi for 30 minutes - good; 351 bbls 'Perm L' Lead erfo 2nd stage ;82 bbls Tail MIT csg 377 bbls Lead 12# shift ES cementer @ 2922 psi. Establish 1st Stage 11/10/2019 Drill shoe track and rathole F/ 9050' - T/ 9065' MD. Drill new formation F/ 9065' - T/ 9085' MD. 450 gpm, 22k tq, 40, 3-5k wob drilling shoe track and new formation. Worked thru several times then tripped thru clean with no pump rotary (clean). Pull into casing @ 9050' MD.;Circulate and condition 9.5 LSND In/Out while Rot/Recip @ 9050' MD. 550 gpm, 1475 psi, 40 rpm, 21k tq.;B/D TDS. R/U head pin with test equipment. Perform FIT 12.5 EMW, 9085' MD / 4723' TVD w/ 9.5 ppg MW = 740 psi. Pumped @ 1/2 bpm to 740 psi. Chart and record same. 1.4 bbls pumped, 1.4 bbls bled back. R/D and blow down test equipment.;Monitor well (static). Equipment failure - Iron Roughneck hydraulically engaged and ran into stump on its own. Shut down operations and discussed plan forward to mitigate potential injury. Pump dry job, B/D TDS. POOH on elevators F/ 9050' - T/ 5614' MD (154k up, 77k dn).;Continue POOH on elevators F/ 5614' - T/ surface MD. B/O and L/D mtr and bit. Bit grade - 1,1,WT,A,E,I,BT,BHA. Calculated displacement for trip.;Clean and clear rig floor. Mob BHA tools to rig floor. Prep pipeshed for trip in.;PJSM, M/U 8.5" RSS w/ 9.875" under reamer (NOV); M/U 8-1/2 NOV bit to Geo-Pilot, M/U DM, ADR/HCIM, stabilizer, DGR, PWD, TM. Plug in and upload MWD. M/U float sub, stab, NM pony collar, NOV 9-7/8" under reamer, float sub, NM pony collar, float sub, stab and 1 stand HWDP.;Shallow pulse test at 450 gpm - good. RIH with 4 more joints HWDP, Jars, and 11 jnts HWDP from derrick.;Pick up, drift and single in the hole with additional 100 joints of drill pipe to 3887'. Fill pipe every 2500', break in Geo-Pilot seals at 3251'.;Cont. to RIH with RSS drilling assembly from 3887' to 9036' out of derrick, fill pipe every 3000'. PUW 242K, SOW 86K. Obtain SPR's 32/48 stokes MP1 245/320, MP2 245/315;Service rig: grease crown, blocks and top drive. Check hyd and oil levels.;Wash down from 9036' at 500 gpm/1850 psi to 9085', 5' fill. Drill 8.5" intermediate hole from 9085' to 9176'MD (91' total / AROP 45fpm) at 550 gpm, 2150 psi, 80 rpm, 23k tq on, 5-10k WOB, 10.4 ECD's with 9.5 ppg mud. 220k up, 79k dn, 129k rot. Max gas 67u.;Daily hauled 1021 bbls to G&I total = 8744 bbls Hauled 390 bbls from 6 mile lake, Total 9710 bbls Lost 0 bbls to formation Total fluid lost section = 0 bbls Fluid lost on surface hole = 46 bbls 11/11/2019 Drill 8.5" x 9.875" (under reamer) intermediate hole F/ 9176' - T/ 9577' MD / 4957' TVD. 600 gpm, 2350 psi on, 2300 psi off. 80-140 rpm, 21-24k tq on, 22-24k tq off. 246k up, 74k dn, 130k rot. 10.8 ECD's (clean hole ECD's 10.5 @ shoe w/ 9.5mw). Pump dn 1-3/8" activation ball to open UR (NOV).;At 9184' MD (bit depth), Pumped dn ball @ 350 gpm, landed on seat @ 1593 stks (2475 calc stks). Saw 80 decrease in pump psi. Drilled down F/ 9184' - T/ 9196' w/ 9-7/8" under reamer. Shut dn rot and straight pull up to 9184' w/ 15k over pull to confirm under reamer blades engaged.;9-7/8" hole starts @ 9068' MD (116' back from bit). Erratic tq seen prior and post of under reamer activation. Vary parameters to help minimize stick/slip. Increase lubes from 3% to 4% by volume. Originally seeing 8k swings in tq for first 200' of hole section then calmed dn 1-3k tq swings.;Cont. drilling 9-7/8" from 9577' to 10,077' (total=500', AROP=83fph) 550 gpm, 2285 psi on, WOB 15K, 130 rpm, 25k tq on, 24k tq off. 275k up, 75k dn, 136k rot. 10.8 ECD's with 9.5 ppg mud. Max gas 212U. Backream 30' every stand at 60 rpms (recommended limit for under reamer).;Losses encountered at 9860' initial rate 40 bph, increase background LCM to 20 ppb and 10 ppb black product. Well observed breathing at first connection after losses encountered;Cont. drilling 9-7/8" from 10,077' to 10,500' (total=432', AROP=70fph) 500 gpm, 2080 psi on, WOB 15K, 140 rpm, 26k tq on, 24.5k tq off. 295k up, 73k dn, 138k rot. 10.84 ECD's with 9.6 ppg mud. Max gas 394U. Backream 30' every stand at 60 rpms (recommended limit for under reamer).;Pumped lube pill at 10,330' with no decrease in torque; lube concentration at 4%. Losses slowed to 15-20 bph while drilling, breathing on connections for overall 10 bph loss rate.;Cont. drilling 9-7/8" from 10,500' to 10,882' (total=382', AROP=64fph) 550 gpm, 2475 psi on, WOB 15K, 110 rpm, 26k tq on, 25k tq off. 285k up, 78k dn, 139k rot. 10.85 ECD's with 9.6 ppg mud. Max gas 522U. Backream 30' every stand at 60 rpms (recommended limit for under reamer).;Continue to see breathing on connection - with total lost 10 bbls since 00:00. Pump lube sweep at 10,622' with minimal decrease in torque.;Daily hauled 285 bbls to G&I total = 9029 bbls Hauled 530 bbls from 6 mile lake, Total 10,240 bbls Lost 132 bbls to formation Total fluid lost section = 132 bbls Fluid lost on surface hole = 46 bbls 11/12/2019 Continue drill 8.5" x 9.875" intermediate hole section F/ 10,882' - T/ 11,328' MD / 5723' TVD. 550 gpm, 2670 psi on, 2600 psi off, 120 rpm, 27k tq on, 26k tq off, 310k up, 80k dn, 141k rot, 10.9 ECD's w/ 9.6 MW. Breathing @ connections. Dynamic loss rate = 1 BPH.;Continue drill 8.5" x 9.875" intermediate hole section F/ 11,328' - T/ 11773' MD / 5928' TVD. 598 gpm, 2860 psi on, 2800 psi off, 120-130 rpm, 29k tq on, 27k tq off, 285k up, 85k dn, 147k rot, 10.83 ECD's w/ 9.6 MW. Breathing @ connections. Dynamic loss rate = 1 BPH.;At 11,455' MD added 8 drums ( 4 NXS-Lube, 4 Gold Seal) lowered P/U 50K, Inc down 20K. Initially lowered drill TRQ 4K for 2 stands. Back ream 20' each stand W/ 60 RPM. Started 4°/100 drop at 11,600' MD.;PJSM Drill 8.5" X 9.875" Intermediate Hole F/ 11,773' to 12,155' MD ( 6,174' TVD) total 382' (AROP 63.6') 600 GPM, 2,820 PSI, 125 RPM, TRQ ON 30K, TRQ off 28.5K, WOB 6K. F/O 59.1% ECD 10.85 ppg, P/U 275K, SLK 98K, ROT 154K. Max Gas 236U. Back ream 20' each stand W/ 60 RPM. Dynamic loss 1 BPH.;Breathing slowing down on each connection. SPR 12,025' (6,082' TVD) MW 9.6 ppg MP #1 32-381, 48-456 MP #2 32-382, 48-455;Drill 8.5" X 9.875" Intermediate Hole F/ 12,155' to 12,501' MD ( 6,455' TVD) total 346' (AROP 57.6') 600 GPM, 2,810 PSI, 110-120 RPM, TRQ ON 29-30K, TRQ off 24K, WOB 10-15K. F/O 59.2% ECD 10.91 ppg, P/U 243K, SLK 113K, ROT 161K. Max Gas 175U. Back ream 20' each stand W/ 60 RPM.;Dynamic loss 1 BPH. MW 9.7 ppg Cont 4°/100 drop as per plan. Slight breathing on connections. Added 4 drums NSX to control TRQ. Adjusting parameters to mitigate TRQ. Distance to WP #8: 2.59', 2.39' Low, 1.0' Left;Daily hauled 342 bbls to G&I total = 9,371 bbls Hauled 510 bbls from 6 mile lake, Total 10,750 bbls Lost 20 bbls to formation Total fluid lost section = 152 bbls Fluid lost on surface hole = 46 bbls Continue drill 8.5" x 9.875" intermediate Drill 8.5" x 9.875" (under reamer) intermediate hole F/ 9176' - T/ 9577' MD FIT 12.5 ppg Perform FIT 12.5 EMW, 11/13/2019 Drill 8.5" X 9.875" Intermediate Hole F/ 12,501' to 12,535' MD ( 6,485' TVD) total 34' 600 GPM, 2,810 PSI, 120 RPM, TRQ ON 29-30K, TRQ off 24K, WOB 15K. F/O 59.2% ECD 10.91 ppg, P/U 243K, SLK 113K, ROT 161K. Max Gas 171U.;SPR at 12,535' MD (6,485' TVD) MW 9.7 MP #1 32-387, 48-460 MP #2 32-362, 48-438;CBU 2X 600 GPM, 2,600 PSI 80 RPM on the up stroke, 120 rpm on the down TRQ 26K. Recip 60'. NOV Rep onsite.;PJSM Monitor well for 30 min initial 17 bph, final 2 bph. POOH on elevators F/ 12,535' to 8,970' MD Pulled 7 stands observed no swabbing. Pulled 5 W/ hole fill proper Disp. Cont. pulling W/ no losses. P/U 200K, SLK 105K. 10K bobble pulling BHA through shoe. Reamer no issue. Lost 10K P/U in Csg.;PJSM Monitor well static. Pull riser and install MPD bearing. Circ. thru lines and check for leaks, good.;PJSM Slip and cut 63' (10 wraps) Accum TM 17,492. 2,186' on spool. Check brake air gaps. Grease Crown, Blocks, Top Drive and check oil.;PJSM RIH F/ 8,970' to 10,600' MD. P/U 237K, SLK 96K. No losses. Reamer at 9,224' MD. Pump through MPD Equip and attempt to hold 450 PSI W/ MPD. Was only able to achieve 430 PSI 10.98 EWM before falling and resting at 180 PSI 10.22 EMW.;PJSM Cont. RIH F/ 10,600' to 12,474' MD. P/U 237K, SLK 96K. No losses.;PJSM Circ Surf to Surf to get air out of system for MPD. Recip F/ 12,536' to 12,474' MD. 40 RPM, TRQ 22K, 494 GPM, 1,870 PSI. Saw Gas at 7,000 strokes Max Gas 617U. Beyond MPD density and GPM very inconsistent during Gas and air going through Coriolis. Initially appeared to have dynamic loss around;25 bbls over 45 min but tapered off to no dynamic loss. MPD showing 100 GPM (400 GPM) difference then rig pump rate 494 GPM. Saw no indication of losses at surface. Kelly up on stand F/ Derrick.;PJSM Drill F/ 12,536' to 12,551' MD 600 GPM, 2,430 PSI, 120 RPM, TRQ ON 29-30K, WOB 15K. MPD F/O 500 GPM. Pump Press was 400 PSI less then yesterday and MPD F/O still showing 100 GPM less then pump rate. Decision was made to rack back stand and trouble shoot. Distance to WP#8 3.64', 3.06' L, 1.97' L;Service Rig - Grease traveling equipment, drawworks, IR and tongs.;Circ and Recip F/ 12,536' to 12,474' MD Ran MP #1 at 300 GPM MPD showed 300 GPM F/O. Ran MP #2 at 300 GPM, MPD showed 220 GPM F/O. Circ. W/ MP #1 at 300 GPM, 1,080 PSI, 40 RPM, TRQ 22.9K, MPD F/O 300 GPM. Max Gas 174U. Inspected MP #2 found nicked rubber on discharge valve Pod 1.;Primed and pumped with MP #2 with slight increase in rate. Shut down MP #2 and pulled valve seat on discharge Pod 1 and found pod washed out. Decision was made to pull to shoe to replace pod on MP #2.;Obtain SPR at 12,535' MD 6,448 TVD MW 9.7 32-350, 48-434. Monitor well for 15 min initial flow 32 bph slowing to 10 bph. Blow down top drive. Monitoring flow down to almost static, 17 bbls back.;PJSM POOH on elevators F/ 12,537' to 8,970' MD. P/U 197K, SLK 100K. Pulled 5 stands off bottom with no swabbing. Observed 10K bobble as Under Reamer entered Shoe at 9,055'MD. NOV Rep onsite. Monitor well on trip tank, static. Calc Disp 28 bbl, actual 26 bbl, lost 2 bbl. SIMOPS work on removing Pod;PJSM Work on replacing MP#2 Pod 1. Check wobble on crown sheaves. Service rig.;Daily hauled 350 bbls to G&I total = 9,721 bbls Hauled 390 bbls from 6 mile lake, Total 11,140 bbls Lost 0 bbls to formation Total fluid lost section = 152 bbls Fluid lost on surface hole = 46 bbls 11/14/2019 Repair / Replace #1 pod (washed out) on Mud Pump #2. Install new valve, seats and seals. Tq all fasteners to spec as per White Star. Function test pump thru bleeder. Test to 3500 psi (test good) w/ no leaks. Continually monitor well - Static.;PJSM, TIH F/ 8970' - T/ 12551' MD on elevators. Trip was clean. Washed down last stand. Proper displacement for trip. 265k up, 115k dn. No fill.;Service Rig - Grease Traveling equipment. Inspect TDS (saver sub). Prep floor for drilling operations.;Drill 8.5" X 9.875" Intermediate Hole F/ 12,535' - T/ 12744' MD (6677' TVD) total 193' (32 AROP). 505 gpm, 2,520 psi, 120 rpm, 27K tq on,26K tq off, 15-20k WOB, 11 ECD's w/ 9.8 MW, 375u Max gas, 50u BGG. 95% returns initially but climbed to 100% returns after first 2 hours of drilling interval.;At 12,665' MD started holding back Press W/ MPD during connections, only able to hold 330 PSI, 10.77 EMW. Not holding MPD Press during drilling. Torque limiter set to 35.5K due to full stalls. Checked Top Drive TRQ W/ rig tong and found ~5K difference Top Drive 35,5K, Rig Tong 30.7K.;Drill 8.5" X 9.875" Intermediate Hole F/ 12,744' to 13,000' MD ( 6,917' TVD) total 256' ( 42.6 AROP) 500 GPM, 2,400 PSI, 120 RPM, TRQ ON 27K, TRQ off 26K, WOB 20K. MPD F/O 493 GPM, ECD 11.03 PPG, P/U 255K, SLK 123K, ROT 172K. Max Gas 80U, BGG 45U. Back ream 20' at 60 RPM.;MPD holding 320 PSI at connections, resting at 300 PSI. Encountering dynamic losses about 10 bph when exceeding 10.9 ECD's. Lost 120 bbls during drilling for 12 Hrs.;End 4°/100' Drop at 12745' MD Begin 20° hold for pump tangent at 12745' MD to TD At 12,897' saw a drill break and TRQ fell off 4K F/ 29.5K to 25.5K. TRQ cam back at 12,942' MD.;Drill 8.5" X 9.875" Intermediate Hole F/ 13,000' to 13,063' MD ( 6,976' TVD) total 63' 500 GPM, 2,460 PSI, 120 RPM, TRQ ON 27-29K, TRQ off 26K, WOB 20K. MPD F/O 493 GPM, ECD 10.96 PPG, P/U 259K, SLK 129K, ROT 172K. Max Gas 68U, BGG 55U. Back ream 20' at 60 RPM.;Distance to WP08: 2.21', 1.42' Low, 1.96' Left TD was called by Geo in town. Rack back stand and P/U working single. MPD trying to hold 320 PSI, 292 PSI resting Press.;SPR at 13,063' MD (6,976' TVD) MW 9.8 ppg MP #1 32-245, 48-346 MP #2 32-245, 48-335;PJSM CBU 4X Rot and Rec F/ 13,063' to 13,013' MD. 530 GPM, 2,560 PSI, 60 RPM on the up stroke TRQ 22-24k, 120 RPM on the down TRQ 27-29K. Max Gas 52U, BGG 8U. MPD full open 68 PSI, MPD F/O 512 gpm. ECD 10.89 EMW. At 550 GPM ECD was 10.92 and showed 10 BPH dynamic loss.;Shakers showing small amount of fines. Perform press rate for 1,230 PSI, 317 GPM, MPD 163 PSI for closing Under Reamer. Need to land ball at 265 GPM as per NOV Rep onsite.;PJSM POOH on elevators F/ 13,063' to 12,880' MD. P/U 285K, SLK 125K MPD holding 310 PSI 10.65 EMW during connections, MPD holding 369 PSI 10.9 EMW while pulling 15 ft/min W/ 9.8 ppg MW. No issues. Pumping 170 GPM through kill line.;Daily hauled 228 bbls to G&I total = 9,949 bbls Hauled 390 bbls from 6 mile lake, Total 11,530 bbls Lost 120 bbls to formation Total fluid lost section = 272 bbls Fluid lost on surface hole = 46 bbls Drill 8.5" X 9.875" Intermediate Hole 11/15/2019 TIH F/ 12880' - T/ 13063' MD holding 10.9 EMW w/ MPD (~230 psi). Dropped 1-7/8" steel ball for locking under reamer in closed position. Tripped clean.;Pumped down @ 260 gpm, 1060 psi. Did not see ball land on calc stks. Stage pumps up attempting to seat ball. Max rate 500 gpm, 2350 psi, 110 rpm, 28k tq. Never saw ball land on seat. Cont circ at max rate keeping ECD's @ 10.9 max to prevent pushing away fluid while waiting up to 10.2 MW;Decreased rate to manage ECD's with a final rate of 375 gpm, 1495 psi, 110 rpm, 29k tq (97% returns). Spot 30 bbl 10.15 MW liner running pill on btm.;Monitor well - Initial flow 100 bph, decreased over 30 min to 12.8 and continually trending down. Shut in w/ 78 psi over 10 min. L/D working single. B/D TDS and ready floor for tripping out. 270k up, 130k dn, 170k rot.;POOH F/ 13063' - T/ 9224' MD @ 15 fpm (1st 1500') before increasing to 40 fpm (1500' - 3000' off btm).Increase to 60 fpm from 10000' MD on. Tripped clean. Held 10.9 EMW (~230 static / ~275 dynamic) w/ MPD. 32 bbl loss for trip.;Pump out of hole F/ 9224' - T/ 9158' to ensure under reamer blades were in locked position. 400 gpm, 1455 psi while pulling up into 8.5" hole. No overpull observed (blades confirmed in locked position). Continue pull into 9-5/8" shoe w/ minimal flow @ 125 gpm, 485 psi, 20 rpm, 13k tq;PJSM Rot & Rec F/ 9,036' to 8,964' MD. CBU 2X 350 GPM, 1,120 PSI, 40 RPM, TRQ 11K. ECD 11.1, MPD full open. Lost 2 bbls. No increase of cutting, no gas.;PJSM POOH F/ 9,036' to 7,443' MD. Pump through top of MPD holding 295 PSI (10.9 EMW) tripping, 275 PSI (10.85 EMW) during connections. Calc Disp 14 bbls, actual 18, lost 4 bbls. At 21:10 tripping out Iron Roughneck moved toward drill string with no one at the controls.;All personnel were clear of the area. Held a safety meeting to discuss the incident, person whipping pipe to be on opposite side of roughneck, Hydraulics shut down when not used. Cont. tripping until Electrician was able to trouble shoot Iron Roughneck.;Electrician was called out to trouble shoot Iron Roughneck. Mechanic worked on replacing rollers on spinners. Electrician checked plug at control box and control box for moisture or loose connection. Found a couple flattened spots in control wire going to control panel on Iron Roughneck.;Changed out control wire F/ controls to Iron Roughneck. Functioned tested Iron Roughneck. Function tested spinners.;Shut down and monitor well. Staged down MPD Press, initial rate 100 GPM slowing to 8.8 GPM over 1 hour W/ 36 bbls gained. Shut in MPD W/ 19 PSI built to 87 PSI in 25 min. Opened MPD for 10 min gained 1.56 bbls gain. Shut in MPD W/ 27 PSI built to 78 PSI at 40 Min.;Monitor well for 25 min gained 1 bbbl. Shut in well for 30 min Press built to 64 PSI. Total bled back 41 bbls.;PJSM POOH F/ 7,443' to 4,396' MD at 60 ft/min Was unable to achieve 290 PSI due to formation ballooning. MPD holding 220 PSI (10.7 EMW) tripping, 210 PSI (10.68 EMW) during connections. Still over displacing during tripping. Calc Disp 25.2 bbls, actual 38.4, lost 13 bbls. P/U 128K;Daily hauled 57 bbls to G&I total = 9,949 bbls Hauled 260 bbls from 6 mile lake, Total 11,790 bbls Lost 68 bbls to formation Total fluid lost section = 340 bbls Fluid lost on surface hole = 46 bbls 11/16/2019 Monitor well - Bleed down MPD to 0 psi. Initial flow 80 gpm decreasing to static over 45 mins. Pull RCD and install trip nipple. B/D MPD lines.;POOH on elevators F/ 4396' - T/ 2805' MD laying down 5" NC50 drill pipe to shed. Trip speed in excess of 60 fpm would show slight swabbing.;Continue POOH laying down 5" NC50 F/ 2805' to 706' (BHA). Monitor well for 15 min (static).;POOH F/ 706' - T/ surface. L/D 5" HWDP (17x ), Jars, B/O and laydown NOV 9-7/8" under reamer (reamer grade 1,1, WT), NM Floats and stabs. Download MWD. B/O and L/D MWD smart tools. B/O and L/D bit, Geo Pilot. Bit Grade - 1-1-WT-A-X-I- NO-TD Monitor well, static.;PJSM Drain Stack and shut Blind Rams. Bleed down Koomey and lock out. C/O Upper Rams (2 7/8" X 5.5") to 7" Rams. Monitor well at OA.;PJSM Remove Wear Bushing and install test plug W/ 7" Test Jnt. R/U and test 7" Rams. 250 PSI low and 4,000 high for 5 min on chart. R/D test Equip. Blow down Equip.;PJSM C/O Hydraulic elevators. R/U Weatherford tools, CRT and power tongs. M/U CRT to Top Drive. M/U 7" Safety valve. SIMOPS Load Pipe Shed W/ 7" D.P.;PJSM P/U and dummy run 7" Hanger and Landing Joint W/ NOS onsite.;P/U M/U 7" Csg Shoe Track 125' W/ Centralizers and Baker Loc.. Check Floats, good. Cont. RIH 7" 26# L-80 TXP F/ 125' to 840' MD. P/U 55K, SLK 54K. Running speed 25 ft/min ~10,78 EMW as per Beyond surge modeling. TRQ 14,750 ft/lb Filling every 5 Jnts and topping off every 10 Jnts.;Calc Disp 7.6 bbls, actual 7.4, lost 0.2 bbls.;Daily hauled 57 bbls to G&I total = 10,006 bbls Hauled 130 bbls from 6 mile lake, Total 11,920 bbls Lost 13 bbls to formation Total fluid lost section = 353 bbls Fluid lost on surface hole = 46 bbls 11/17/2019 Cont RIH 7" 26#, L-80, TXP F/ 840' - T/ 4003' MD. 111k Up, 79k Dn. Running speed 40-70 ft/min ~10.9 EMW as per Beyond surge modeling. TRQ 14,750 ft/lb Filling every 5 Jnts and topping off every 10 Jnts.;Cont RIH 7" 26#, L-80, TXP F/ 4003' - T/ 5234' MD. Running speed 40-70 ft/min ~10.9 EMW as per Beyond surge modeling. TRQ 14,750 ft/lb Filling every 5 Jnts and topping off every 10 Jnts.;Circ and condition @ 5234' MD. Stage pumps up to 2 bpm, 240 psi, 20 rpm, 7k tq with 90% returns and continually increasing. Circulated 45 bbls. Shut down early to prevent charging formation until required for cement job.;Cont RIH 7" 26#, L-80, TXP F/ 5234' - T/ 7297' MD. Running speed 40-70 ft/min ~10.9 EMW as per Beyond surge modeling. TRQ 14,750 ft/lb Filling every 5 Jnts and topping off every 10 Jnts.;Cont. RIH 7" 26# L-80 TXP F/ 7,297' to 8,098' MD. P/U 160K, SLK 90K. Running speed 70 ft/min ~10,9 EMW as per Beyond surge modeling. TRQ 14,750 ft/lb Filling every 5 Jnts and topping off every 10 Jnts.;Monitor well Via Trip Tank. 3 bbl gain in 15 min. Replaced ORing seals on Weatherford hydraulic controls due to leaking. Controls still leaking. had to swap out Power Tongs to backups. Broke Circ. at 8,098' instead of at 8,850' prior to going in open hole.;Staged up F/ 0.5 bpm 240 PSI W/ 50% returns, staged up to 1.25 bpm, 275 PSI, F/O 3.3% 80% returns. Pumped a total of 75 bbls, lost 18 bbls. Avg return rate 75%. Seeing ballooning with pumps off.;Cont. RIH 7" 26# L-80 TXP F/ 8,098' to 9,615' MD. P/U 170K, SLK 94K. Running speed 55 ft/min ~10,9 EMW as per Beyond surge modeling. TRQ 14,750 ft/lb Filling every 5 Jnts and topping off every 10 Jnts. Calc Disp 19 bbls, actual 10 bbls, lost 9 bbls.;At 9,000' MD before going into open hole set TRQ limiter to 11,7K. Could rotate at 10 RPM 11.7K TRQ on the down stroke. No issue exiting Shoe at 9,055' MD.;Cont. RIH 7" 26# L-80 TXP F/ 9,615' to 12,587' MD. SLK 98K. Reduced run speed to 45 ft/min (~10.9 EMW) at 10,060' MD due to Displacement. At 10,330' MD reduced F/45 to 35 ft/min (~10.9 EMW) due displacement. At 11,400' MD Running speed 30 ft/min (~10.825 EMW);Pushing Disp. away.;TRQ 14,750 ft/lb Filling every 5 Jnts and topping off every 10 Jnts. Calc Disp 30.6 bbls, actual 0 bbls, lost 30.6 bbls.;Daily hauled 57 bbls to G&I total = 10,063 bbls Hauled 0 bbls from 6 mile lake, Total 11,920 bbls Lost 46 bbls to formation Total fluid lost section = 399 bbls Fluid lost on surface hole = 46 bbls R/U and test 7" Rams. run 7" int csg Min.;Monitor well for 25 min gained 1 bbbl. Shut in well for 30 min Press built to 64 PSI. Cont RIH 7" 26#, L-80, TXP F/ 840' - T/ 4003' MD. M/U 7" Csg Shoe Track 125' W/ Centralizers 11/18/2019 Continue RIH w/ 7" TXP, 26#, L-80 casing F/ 12,587' - T/ 13026' MD. Fill every 5, track disp every 10 jts. RIH @ 30 FPM to minimize surge pushing fluid away. 110k dn, 260k up. Wash dn last 3 jts @ 2bpm, 325 psi. Pumped away 52 bbls before returns stabilized w/ zero losses.;M/U 7" hanger w/ landing jt. Put casing on depth @ 13,053' MD. No issues running casing in OH. Stg pumps up while recip pipe. Stg up F/ 2 BPM to 3 BPM with ever increasing returns. 30% returns initially / final returns @ 3 bpm, 70%. Sym Ops - R/D bail extensions, elevators. Circ 2x csg vol.;Continue circulate while reciprocating pipe @ 13053' MD. 260k up, 107k dn (72k string wt on hanger). 3 bpm, 600 psi, 16 bph loss rate.;PJSM, Wet lines, P/T to 4640 psi (test good). HES pump 40 bbls 11 ppg tuned spacer, 3.5 bpm, 600 psi Drop btm plug HES pump 38.3 bbls 15.8 ExtendaCem cmt, 2.3 bpm, 667 psi, 1.206 yld, 180 sxs;Drop top plug HES pump 20 bbls H2O, 4 bpm, 450 psi Rig disp MP#2 480 bbls 10.2 ppg LSND, 5 BPM, 700 psi (pumped 50% shoe track) Did not bump plug Hold 5 min, bled back 1.25 bbls, floats held. CIP @ 16:19 hrs. Lost 146 bbls during job. Monitor well - Balloon back 126 bbls and trending down.;PJSM R/D and clean Volant. Clean and clear rig floor of Csg Equip and cement job. Monitor flow back to pits, initial rate 16 bph slowed to 5 bph. Open IA in cellar and monitor flow from ballooning.;PJSM P/U 5" D.P. and install Pack Off running tool W/ Pack Off. Install Pack Off in well head. Verified seated by pulling lock down pin. RILDS. Test Pack Off 500 PSI low and 5,000 PSI high as per NOS onsite.;PJSM Install 5" Hydraulic elevators, L/D lower test plug and bring up upper test plug to rig floor. Prep for laying down 5" D.P. with Mouse Hole.;PJSM L/D to Pipe Shed 53 stands (106 Jnst) 5" D.P. F/ Derrick using the Mouse Hole. Cont monitoring IA in cellar, flow declining to 3 bph. Installed cap and gauge on IA. 23:30 70 PSI on gauge. SIMOPS Clean Pits;PJSM Cont. L/D 5" D.P. F/ Derrick W/ Mouse Hole. (61 stands) Using rig tongs to break connections. Monitor IA 70 PSI. SIMOPS Clean and prep Pits for new 10.5 ppg LSND.;Daily hauled 380 bbls to G&I total = 10,443 bbls Hauled 130 bbls from 6 mile lake, Total 12,050 bbls Lost 283 bbls to formation Total fluid lost section = 682 bbls Fluid lost on surface hole = 46 bbls 11/19/2019 PJSM Cont. L/D 5" D.P. to Pipe Shed W/ Mouse Hole (137 Stands) Using rig tongs W/ multiplier due to high TRQ. SIMOPS Finish cleaning Pits. Bring on new 290 bbls 10.5 ppg LSND.;PJSM C/O Upper 7" Rams to 2 7/8" X 5.5" VRBS. C/O Upper door seals. SIMOPS Load and process 4" D.P. in Pipe Shed. C/O elevator inserts to 4".;PJSM L/D 5" Handling Equip. P/U 4" handling Equip. C/O NC 50 Saver Sub to 4" XT 39. TRQ split ring. C/O 5" Die Blocks to 4" W/ new dies. Install 4" Bell Guide. SIMOPS Cont loading and process 4" D.P. in Pipe Shed. Grease Crown.;PJSM M/U 4" HT 38 TIW and Dart to NC 50 X/O to side entry sub. M/U X/O to Top Drive. SIMOPS LRS Freeze Protect 9 5/8" X 7" IA 2 bpm 598 PSI, FCP 860 PSI. Shut in 650 PSI. Weld on skate.;PJSM P/U 3.5" Test jnt and test plug. Flood Stack and lines W/ H2O. Work air out of system. Perform 4,000 PSI shell test, good.;PJSM Perform BOPE test W/ 3.5" & 4.5" to 250 PSI low and 4,000 PSI high for 5 Min. Tested Choke Manifold 1-15, 5" Dart, 5" TIW, Upper and lower IBOP, Mez Kill, HCR and manual Choke and Kill, manual and Super Choke to 2,000 PSI,;Upper and lower VRB Rams (2,875" X 5.5") Blind Rams, Annular W/ 3.5" test Jnt. Koomey draw drown Initial System 3,000 PSI, Manifold 1,400 PSI, Annular 1,400 PSI, after System 1,500 PSI, Man 1,500 PSI, Annular 1,450 PSI. 200 PSI increase 25 Sec, full charge 95 sec.;Nitrogen 6 bottle average 2,333 PSI. Test H2S 10-20 ppm, LEL 20-40%, PVT high/ low level alarms. Witnessed waived by AOGCC Rep Guy Cook.;PJSM L/D test jnt and R/D test Equip. Blow down Choke Manifold and lines.;PJSM Install Wear Ring Lng 12", OD 10.75", ID 6.875". RILDS 4 ea.;PJSM Service Rig. Grease Blocks, Wash Pipe, Top Drive, IBOP and Iron Roughneck. Check oil in Top Drive.;PJSM P/U and stage BHA components in Pipe Shed and rig floor.;PJSM P/U M/U 60 Jnts (30 Stands) 4" XT39 14# S-135 D.P. and rack back in Derrick. TRQ 22K. Drift off Skate (2.35" OD);PJSM P/U M/U 6.125" BHA. 6.125" MM54R Bit, 6" GeoPilot 5200, 4 3/4" DM Collar, 6" ILS, 4 3/4" GM Collar, 4 3/4" ADR Collar, 6" ILS, 4 3/4" ALD Collar (RFO 155.3°), 4 3/4" CTN Collar, 6" ILS, 4 3/4" PWD, 4 3/4" TM Collar 119.19' MD. Down load MWD.;Daily hauled 369 bbls to G&I total = 10,812 bbls Hauled 260 bbls from 6 mile lake, Total 12,310 bbls Lost 0 bbls to formation Total fluid lost section = 682 bbls Fluid lost on surface hole = 46 bbls 11/20/2019 PJSM Cont. to P/U 6.125" Production BHA #4 as per DD & MWD onsite. C/O Bit F/ 6.125" HDBS MM54R to 6.125" Reed TK56. Cont. P/U BHA F/ TM Collar. 6" Integral Blade, 4 3/4" BAT Collar, 6" Integral Blade, 4 3/4" Float Sub (Solid Plunger), 2 ea 4 3/4" NM FC, 4 3/4" Float Sub (Solid Plunger);X/O 3.5" IF P X HT38 B, 4" HWDP, 4 3/4" SLB Drilling Jars and 4" HWDP to 320.97' MD. Installed Nuclear Source and downloaded at BAT Collar.;PJSM Single in hole BHA #4 W/ 4" D.P. 14# S-135 HT38 F/ 320' to 3,450' MD. Break in GeoPilot 220 PSI 1,250 PSI, 60 RPM TRQ 3K. P/U 80K, SLK 58K and shallow hole test MWD. Fill D.P. W/ 10.5 ppg MW. Drift (2.375") off skate.;Cont. Single in hole BHA #4 W/ 4" D.P. 14# S-135 HT38 F/ 3,450' to 9,410' MD. Put in X/O 1.47' 2.562" ID. Cont Single in hole W/ 4" 14# S-135 XT39 F/ 9,410' to 9,728' MD. P/U 141K, SLK 71K. Fill D.P. W/ 10.5 ppg MW. Drift (2.375") off skate.;PJSM Cont RIH W/ 4" 14# S-135 XT39 F/ 9,728' to 12,870' MD. P/U 206K, SLK 85K. Fill D.P. W/ 10.5 ppg MW. Drift (2.375") off skate. Wash down and tag at 12,934' MD W/ 5K. Rack back 1 stand.;PJSM Slip and Cut Drilling line.;Daily hauled 57 bbls to G&I total = 10,869 bbls Hauled 0 bbls from 6 mile lake, Total 12,310 bbls Lost 0 bbls to formation Total fluid lost section = 682 bbls Fluid lost on surface hole = 46 bbls Perform BOPE test W/ 3.5" & 4.5" to 250 PSI low and cement 7" casing HES pump 38.3 bbls 15.8 ExtendaCem cmt, 2.3 bpm, 667 psi, 1.206 yld, 180 sxs;Drop top plug HES pump 20 bbls H2O, 4 bpm, 450 psi Rig disp MP#2 480 bbls 10.2 ppg LSND, 5 BPM, 700 psi (pumped 50% shoe track) Did not bump plug Hold 5 min, bled back 1.25 bbls, floats held. CIP @ 16:19 hrs. Lost 146 bbls during job. Monitor well 11/21/2019 PJSM Cont Cut and slip drilling line. (81') 2,105' on spool. Accum TM 18,546. Re calibrate block position. SIMOPS Cont Circ and Cond mud to 10.5 ppg.;PJSM Service rig. Grease Crown, Blocks, Wash Pipe, IBOP, Top Drive and check oil. SIMOPS Condition mud weight to 10.5 ppg.;PJSM Circ and cond mud to 10.5 ppg 250 GPM, 2,450 PSI. SIMOPS Perform weekly on Iron Roughneck. Grease spline on Drawworks. C/O Tong dies.;PJSM Blow down Top Drive. Install Head Pin and TIW. Flood lines and Choke Manifold. Test 7" Csg to 3,650 PSI for 30 min on chart. Pumped 6 bbls, bled back 5.8 bbls. Blow down and R/D.;PJSM P/U stand and RIH. Tag TOC at 12,934' MD. P/U 197K, SLK 111K SPR at 12,394 MD (6,363' TVD) MW 10.5 ppg MP #1 32-700, 48-1,005 MP #2 32-665, 48-940;PJSM Drill F/ 12,934' to 13,063' MD. 180 GPM, 1,600 PSI, 60 RPM, TRQ 15K, P/U 197K, SLK 88K, ROT 114K. WOB 8K. At 12,934' at BU saw Black Plug rubber. Saw Orange Plug rubber at 12,969' as per tally. Shoe in depth at 13,053' MD. Saw Press spikes as ILS went thru FC and Shoe.;Worked string to clear rubber around BHA.;Drill F/ 13,063' to 13,083' MD 250 GPM, 2,450 PSI, 90 RPM, TRQ 15K. F/O 45%. Saw Press spikes working ILS thru FC & Shoe up to 2,800 PSI. Rotate back into 7" Csg without issue.;PJSM Circ. and Rec F/ 13,000' to 12,940' MD. 250 GPM, 2,420 PSI, 40 RPM, TRQ 15K, P/U 197, SLK 88K, ROT 117K. Max Gas 31U. MW in and out 10.5 ppg. Shut down and blow down.;PJSM R/U Head Pin and Circ. hose. Blow air thru Choke to ensure no rubber was in the line. Purge air from Choke Manifold and lines. Shut in upper rams. Press up to 909 PSI EMW 13.0 ppg, Pumped 1.4 bbls, bled back 1.4 bbls. Blow down Choke Manifold and lines. R/D test Equip.;PJSM Drain Stack. Pull Riser and install Air Boot protector. Install RCD Bearing as per Beyond Rep onsite. Flood and check MPD lines.;PJSM Drill 6.125" Production hole F 13,083' to 13,095' MD 250 GPM, MPD 269 GPM, 2,670 PSI, 90 RPM,TRQ 16K, WOB 15K, P/U 215K, SLK 60K, ROT 108K. MPD 780 PSI during connections, 180 PSI while drilling. EMW 12.5 ppg.;SPR at 13,066 MD (6,980' TVD) MW 10.5 ppg MP #1 32-930, 48-1,090 MPD 300/ 175 MP #2 32-926, 48-1,085 MPD 300/ 175;PJSM Drill Production 6.125" Production Hole F/ 13,095' to 13,253' MD ( 7,156' TVD) total 158' (AROP 26.3') 250 GPM, 2,810 PSI, 120 RPM, TRQ 16K, WOB 8-15K. P/U 215K, SLK 66K, ROT 109K. Max Gas 31U. MPD 100 PSI pumps on, pumps off 780 PSI 12.5 ppg EMW W/ 10.5.ppg MW.;MPD resting at ~740 PSI. Picking up frequently as Press increases are observed. Ream 10-15' off bottom for Press to fall and normal Press back on bottom. F/ 13,129' MD ILS are coming out of 7" Csg, press increases are less frequent. Increased RPM F/ 90 to 120 RPM.;Maintain 20° Inc 47.3° to TD. Distance to WP8 2.58', 2.39' Low, 0.97' Right;Daily hauled 0 bbls to G&I total = 10,869 bbls Hauled 130 bbls from 6 mile lake, Total 12,440 bbls Lost 0 bbls to formation Total fluid lost section = 682 bbls Fluid lost on surface hole = 46 bbls 11/22/2019 PJSM Control drill Production 6.125" Production Hole F/ 13,253' to 13,386' MD ( 7,281' TVD) total 133' (AROP 22.2') 250 GPM, 2,750 PSI, 120-130 RPM, TRQ 17.5K, WOB 8-10K. P/U 225K, SLK 73K, ROT 114K. Max Gas 51U. Control drill at 35-75 ft/min. At 13,354' saw a 200 PSI decrease;and TRQ increased 1.5K, drilling TRQ smoothed out indicating something may have been balled up around a ILS. Back ream 60' at connections. MPD 650 PSI pumps on, pumps off 780 PSI 12.5 ppg EMW W/ 10.5.ppg MW.;PJSM Control drill Production 6.125" Production Hole F/ 13,386' to 13,575' MD ( 7,458' TVD) total 189' (AROP 31.5') 250 GPM, 2,955 PSI, 130 RPM, TRQ 17K, WOB 10-14K. ECD 12.55 ppg. P/U 240K, SLK 70K, ROT 117K. Max Gas 238U. Control drill at 35-75 ft/min.;MPD 35-80 PSI pumps on, pumps off 780 PSI 12.5 ppg EMW W/ 10.5.ppg MW. Back ream 60' at connections.;PJSM Control drill Production 6.125" Production Hole F/ 13,575' to 13,734' MD ( 7,608' TVD) total 159' (AROP 26.5') 230 GPM, 2,700 PSI, 130 RPM, TRQ 17K, WOB 11-15K. ECD 12.51 ppg. P/U 245K, SLK 72K, ROT 118K. Max Gas 106U. Control drill at 35-75 ft/min.;MW. At 13,638' MD back down flow rate F/ 250 GPM 2,980 PSI to 230 GPM 2,650 PSI to control ECD F/ 12.61 to 12.5 EMW. Back ream 60' at connections.;PJSM Control drill Production 6.125" Production Hole F/ 13,734' to 13,785' MD ( 7,655' TVD) total 51' (AROP 20.4') 230 GPM, 2,705 PSI, 130 RPM, TRQ 17K, WOB 8-13K. ECD 12.52 ppg. P/U 233K, SLK 76K, ROT 118K. Max Gas 30U. Control drill at 40-50 ft/min.;At 13,762' start increasing MW F/ 10.5 to 10.6 ppg. MPD 35-50 PSI pumps on, pumps off 740 PSI 12.5 ppg EMW W/ 10.5.ppg. Back ream 60' at connections. No losses observed while drilling.;Perform weight up F/ 10.6 to 10.8 ppg and clean up cycles. Rot & Rec F/ 13,875' to 13,718' MD. 230 GPM, 2,560 PSI, 120 RPM, TRQ 18-19K, ECD 12.5 ppg, Max Gas 14U. P/U 233K, SLK 76K, ROT 118K. MPD holding 35-40 PSI for 12.5 ppg EMW. No losses.;Maintain 20° Inc 47.3° to TD. Distance to WP8 2.84', 2.65' Low, 1.02' Right;Daily hauled 134 bbls to G&I total = 11,003 bbls Hauled 260 bbls from 6 mile lake, Total 12,700 bbls Lost 0 bbls to formation Total fluid lost section = 682 bbls Fluid lost on surface hole = 46 bbls Metal 10# 11/23/2019 Perform weight up F/ 10.7 to 10.8 ppg. Rot & Rec F/ 13,875' to 13,718' MD. 230 GPM, 2,560 PSI, 120 RPM, TRQ 18-19K, ECD 12.5 ppg, Max Gas 14U. P/U 248K, SLK 76K, ROT 118K. MPD holding 35-40 PSI for 12.5 ppg EMW. No losses.;SPR at 13,785' MD ( 7,655' TVD) MW 10.8 ppg MP #1 32-1,080, 48-1,430 MP #2 32-1,100, 48-1,415 MPD 300 PSI 32 Stks, MPD 275 PSI 48 Stks;PJSM POOH on elevators as per Beyond trip schedule F/ 13,785' to 13,038' MD 20-30 FPM. Encountered 20-30K over pull periodically. MPD holding 880 PSI Dynamic, 820 PSI Static. Pulled through Shoe at 13,053' MD without issue.;PJSM CBU Rot & Rec F/ 13,038; to 12,975' MD. 260 GPM, 2,960 PSI, 80 RPM, TRQ 16.5K, P/U 202K, SLK 70K, ROT 113K. MPD open choke 26 PSI line friction. No real increase at Shakers.;PJSM Grease Crown, Blocks, Top Drive, Wash Pipe ad IBOP. Check oil in Top Drive.;PJSM RIH on elevators as per Beyond trip schedule F/ 13,038' to 13,765' MD 20-30 FPM, encountered 15-20K drag periodically. MPD 880 PSI Dynamic, 820 PSI Static. Lost down weight at 13,375' washed down 10' to 13,785'.;Perform weight up F/ 10.8 to 11.5 ppg. Rot & Rec F/ 13,875' to 13,718' MD. 260 GPM, 3,250 PSI, 160 RPM, TRQ 18.5K, ECD 13.6 ppg, Max Gas 0U. P/U 252K, SLK 76K, ROT 118K. MPD full open 26 psi line friction. No losses.;PJSM POOH on elevators as per Beyond trip schedule F/ 13,785' to 12,943' MD 20- 30 FPM. P/U 230K, SLK 72K. MPD holding 640 PSI Dynamic, 430 PSI Static. Pulled through Shoe at 13,053' MD without issue. Calc Disp 7.7 bbls, actual 8.2 bbls. Lost 2.5 bbls.;Monitor well for ten minutes through MPD holding 430 PSI with no increase. Pumped 15 bbl 13.5 ppg dry job. Blow down Top Drive. Drop 1.93" OD drift.;POOH on elevators as per Beyond trip schedule F/ 12,943' to 11,338' MD 30 FPM. P/U 230K, SLK 72K. MPD holding 610 PSI Dynamic, 410 PSI Static.;PJSM Swap Hydraulic Elevators to manual due to hard band hanging up in inserts.;POOH on elevators as per Beyond trip schedule F/ 11,338' to 5,705' MD 55 FPM. P/U 125K, SLK 70K. MPD holding 600 PSI Dynamic, 400 PSI Static. Calc Disp 41.8 bbls, actual 46.6 bbls. Lost 4.8 bbls.;PJSM POOH on elevators as per Beyond trip schedule F/ 5,705' to 320' MD 55-60 FPM. P/U 48K, SLK 47K. MPD step down F/ 600 to 170 PSI Dynamic, 400 to 170 PSI Static. Open MPD Choke and monitor well for 15 min, static. Calc Disp 32.3 bbls, actual 34.8 bbls. Lost 2.5 bbls. Clean rig floor.;Daily hauled 57 bbls to G&I total = 11,060 bbls Hauled 130 bbls from 6 mile lake, Total 12,830 bbls Lost Production section 8 bbls to formation Total fluid lost Intermediate section = 682 bbls Fluid lost on surface hole = 46 bbls Metal 10# Press up to 909 PSI EMW 13.0 ppg, press test 7" casing Tag TOC at 12,934' MD. P/U 197K, SLK 111K FIT Test 7" Csg to 3,650 PSI for 30 min on chart. 11/24/2019 PJSM Pull and strip off RCD Bearing as per Beyond rep onsite. Install trip nipple. Well static. Blow down MPD choke and steam lines.;PJSM L/D BHA #4 as per Halliburton DD & MWD onsite. L/D 4" HWDP, 4" SLB Jars and NM FC. Plug in and upload BAT Collar. Remove Nuclear Source. Upload DM Collar. Blow down Geo Span while uploading. L/D the rest of the BHA. Bit had 2 chipped cutters and upper seal protector on Geo Pilot loose.;Bit Grade 1-3-CT-T-X-I-WT-TD;PJSM Clean and clear rig floor of BHA components.;PJSM Weatherford 4.5" liner tools and Equip. R/U Power Tongs and 4.5" Elevators. Bring up 20 Centralizers.;PJSM P/U M/U 4.5" Shoe, FC and Landing Collar and Baker Loc 86.43'. Fill and check floats, good. Cont. RIH W/ 4.5" 12.6# L-80 TXP BTC F/ 86.43' to 849' MD. (Centralizer every Joint) TRQ to 6,170 ft/lbs. P/U M/U Halliburton Versastim liner hanger as Halliburton Rep onsite.;Made multiple adjustments to the adjusting nut for the emergency release. Clac Disp 2.9 bbls, actual 2.2, lost 0.7 bbls. Max Circ. Press 3,000 PSI and do not exceed 30K down over string weight.;PJSM Load and process 15 jnts 4" HWDP in Pipe Shed. RIH 4.5" Liner conveyed on 14 jnts 4" HWDP from the Skate. P/U 52K, SLK 50K. Observed issue W/ 4.5" Liner count for liner run, discrepancy in Tally. Decision was made to POOH and add 2 jnts to liner run.;PJSM POOH and rack back 7 stands of 4" HWDP. Was able to rack back Versastim liner hanger Assy in Derrick as per Halliburton Rep onsite.. Had to remove casing plug from bottom of liner hanger.;PJSM R/U Weatherford Power Tongs and C/O Elevators for 4.5" Liner.;PJSM P/U M/U 2 jnts 4.5" 12.6# L-80 TXP BTC to 849' MD. C/O 4.5" Liner Elevators to 4" Hydraulic. P/U Halliburton Versastim liner hanger F/ Derrick installed casing plug as per Rep onsite and M/U to string. R/D Weatherford Power Tongs. C/O 4" Hydraulic Elevators to manuals.;PJSM RIH 4.5" Liner W/ Versastim liner hanger W/ 15 stands HWDP F/ 918' to 1,372' MD. Cont RIH W/ 4" D.P. F/ Derrick F/ 1,372' to 4,510' MD. P/U 85K SLK 59K. Running speed 90 ft/min as per Halliburton. Beyond running schedule 120 FPM.;Filling D.P. every 15 stand (945') due to differential Press on the Shear Pins. Disp 17 bbls, actual 16 bbls, lost 1 bbl.;Daily hauled 0 bbls to G&I total = 11,060 bbls Hauled 0 bbls from 6 mile lake, Total 12,830 bbls Lost Production section 7 bbls to formation. Total 15 bbls Total fluid lost Intermediate section = 682 bbls Fluid lost on surface hole = 46 bbls Metal 10# 11/25/2019 PJSM Cont RIH 4.5" and Versastim liner hanger conveyed W/ 4" D.P. F/ 4,510' to 11,095' MD. 50-90 ft/min as per Beyond trip schedule. P/U 159K, SLK 74K. Filling D.P. every 1,000'. Calc Disp 34 bbl, actual 27.7 bbl, Lost 6.3 bbls. Max Press for Versastrim 3,000 PSI, Max set down 30K.;PJSM Cont RIH 4.5" and Versastim liner hanger conveyed W/ 4" D.P. F/ 11,095' to 13,045' MD. 30 ft/min as per Beyond trip schedule. P/U 190K, SLK 80K. Filling D.P. every 1,000'.;PJSM CBU at 13,054' MD Stage pumps up to 4 bpm 1,320 PSI. No losses observed. Max Gas 80U. P/U 220K, SLK 80K.;PJSM Cont RIH 4.5" and Versastim liner hanger conveyed W/ 4" D.P. F/ 13,045' to 13,743' MD. 20 ft/min as per Beyond trip schedule. P/U 220K, SLK 85K. Filling D.P. every 1,000'. Calc Disp 80.7 bbl, actual 79.6 bbl, Lost 1.1 bbls.;PJSM Wash down F/ 13,743' to 13,777' MD. 2.5 bpm, 1,073' PSI, F/O 32%. P/U 220K, SLK 80K. No losses. No fill.;Rec F/ 13,777’ to 13,715’ MD. Stage up pumps to 4 BPM, 1,495 PSI, F/O 39.1%, P/U 203K, SLK 80K. Slight Press spike at 13,740’ MD. Reduced pump rate to 2 BPM, 880 PSI. Saw slight packing off with no issue moving pipe.;Wash out of hole F/ 13,777’ to 13,610’ MD Adjusting pump rate 2-4 BPM 880-1700 PSI, P/U 197-230K, pull speed 4-8 ft/min. Set TRQ limiter to 6.4K 3-5 RPM. Encountered slight Press spike adjusting parameters as needed. Max Gas 145U. No losses during washing.;Wash down F/ 13,610’ to 13,777’ MD at 3-3.5 BPM, 1,180-1,380 PSI, TRQ limit 6.4K 3-5 RPM, SLK 79-85K, No notable Press spikes. No losses. Max Gas 52U.;Rec 13,777’ to 13,738’ MD Stage up pumps F/ 3.5 to 4 BPM, 1,260 PSI to 1,340 PSI, 41.4%, Max Gas 88U, P/U 202K, SLK 81K. Set pump limiter to 1,575 PSI. Appears keeping Press below 1,500 PSI no issues Circ. 3.5 BPM FCP 1,180 PSI, FCP 4 BPM 1,300 PSI.;Sat at 13,777’ MD Circ at 3.5 bpm 1,180 PSI for 15 min with no losses or issues. Max Gas 64U. SIMOPS PJSM Bring Commander Head to rig floor and set in mouse hole. R/U Halliburton hard lines to Commander Head.;PJSM for cement job. and setting liner hanger. Shut down and M/U Commander Head to drill string. Have tuggers assisting hard lines to cement unit and Commander. Halliburton fill lines W/ 5 bbl H2O. Low Press test to 1,545 PSI kick out, high Press test to 9,135 PSI.;PJSM Halliburton start pumping 60 bbl 12.0 ppg Tuned Spacer at 3 bpm, 1,067 PSI. SLK to 13,781' 86K, P/U to 13,777' MD Broke over at 212K, set in tension W/ 207K. Pump 21 bbls 15.8 ppg Standard Primary Cement 1.16 ft/sx 4.975 gal/sk 102 sx 3.3 bpm, 1,080 PSI.;Shut down and wash up through bleeder line. Launch D.P. Dart as per Halliburton. Halliburton displaced W/ 11.45 ppg LSND at 3.5 bpm, 1,230 PSI, At 105 bbls away dropped 1.75" steel ball through TIW on top of Commander. Dart landed at 137.5 bbls away as calculated CIP 01:30. FCP 1,378 PSI.;Press up to 2,085 PSI for 5 Min. Bleed down Press and checked floats, good. Bled back 1 bbl. Halliburton Press up to 4,425 PSI to expand liner hanger. Cont. pumping at 1 bpm, 1,000 PSI P/U to 266K, SLK to 35K, P/U 194K and released F/ liner hanger.;P/U to 13,760' P/U 194K Halliburton pumped at 5.5 bpm, 2,400 PSI saw 60 bbl spacer at surface and light cement. Dumped 100 bbls overboard. Total pumped 440 bbls. TOL at 12,899'.;PJSM Blow down cement lines. Break down all 1502 Halliburton lines. L/D Halliburton lines. P/U to 12,864' break working single F/ string. Set Commander and single Jnt in mouse hole. Break single and L/D. L/D Commander. L/D 5' pup F/ string to 12,859' MD.;PJSM R/U Head Pin, TIW and test Equip. Test 7" Csg, Versastim Liner Hanger and 4.5" Liner to 3,000 PSI for 30 Min on chart. Pumped 4.6 bbls, bled back 4.5 bbls.;Daily hauled 33 bbls to G&I total = 11,093 bbls Hauled 130 bbls from 6 mile lake, Total 12,960 bbls Lost Production section 8 bbls to formation. Total 23 bbls Total fluid lost Intermediate section = 682 bbls Fluid lost on surface hole = 46 bbls Metal 10# cmt 4.5 liner RIH W/ 4.5" 12.6# L-80 TXP BTC F/ 86.43' to 849' MD. Halliburton start pumping 60 bbl 12.0 ppg Tuned Spacer at 3 bpm, 1,067 PSI. SLK to 13,781' 86K, P/U to 13,777' MD Broke over at 212K, set in tension W/ 207K. Pump 21 bbls 15.8 ppg Standard Primary Cement 1.16 ft/sx 4.975 gal/sk 102 sx 3.3 bpm, 1,080 PSI.;Shut down and wash up through bleeder line. Launch D.P. Dart as per Halliburton. Halliburton displaced W / 11.45 ppg LSND at 3.5 bpm, 1,230 PSI, At 105 bbls away dropped 1.75" steel ball through TIW on top of Commander. Dart Activity Date Ops Summary 11/26/2019 Cont. to PT casing/liner to 3000 psi for 30 minutes - good. 4.6 bbls pumped, 4.5 bbls returned. Blow down lines, R/D head pin, XO and TIW.,Service rig: Grease crown, blocks, wash pipe, TD, IBOP and roughneck. Check oil in TD.,Attempt to POOH on elevators; 20K overpull. Break circulation at 2 bpm/830 psi, 5 rpms/9000ft-lbs. Stage pumps up to 8 bpm/3170 psi and circulate 1.5x bottoms up. PUW 231K, SOW 78K.,POOH on elevators from 12,753' to 8,607'; pump dry job at 12,500 with calculated hole fill. PUW 172K, SOW 767K,Cont. to POOH on elevators from 8607' to 554', calculated hle fill. PUW 76K, SOW 50K.,POOH from 554' to surface, laying down 15 joints of HWDP and liner hanger running tool.,R/U to RIH with cleanout assembly. Bring scraper BHA to rig floor, check OD's, ID's and lengths. Rig up Weatherford power tongs,M/U tricone bit, bit sub, 4-1/2" casing scraper, Bit sub, XO. Pick up drift and single in the hole with 26 joints of 2-3/8" PH6, P/U XO, double pin sub, 7" casing scraper, bit sub and XO to 827'.,RIH with cleanout assembly on drill pipe from derrick to 3023', calculated hole fill observed. PUW 54K, SOW 46K.,RIH with cleanout assembly on drill pipe from derrick from 3023' to 13695', tag landing collar x 2 with 4K. No issues going through liner top. calculated hole fill observed. PUW 211K, SOW 80K.,Establish circulation. Stage pumps up to 5.5 bpm/2640 psi; circulate surface to surface.,Daily hauled 572 bbls to G&I total = 11,665 bbls Hauled 520 bbls from 6 mile lake, Total 13,480 bbls Lost Production section 0 bbls to formation. Total 23 bbls Total fluid lost Intermediate section = 682 bbls Fluid lost on surface hole = 46 bbls Metal 14# 11/27/2019 Continue circulating surface to surface at 5.5 bpm/2765 psi. Displace drilling fluid to 8.8 ppg brine; pump high viscosity spacer followed by 442 bbls brine at 6 bpm/2890 psi. Shut down, drill string underbalanced. Pump additional bottoms up at 9 bpm/2870 psi.,PT Liner and casing: L/D single to 13667'. Blow down top drive. Install head pin and TIW. Flood lines and Purge air. PT liner and casing to 4000 psi for 30 minutes - good. 6.2 bbls pumped, 5.8 bbls returned. Rig down testing equipment and blow down choke manifold and kill line.,POOH laying down drill pipe from 13,671' to 2569', RIH with stands from derrick and L/D same. Calculated hole fill observed.,Cont. to POOH laying down drill pipe from 2569' to 820'. Calculated hole fill observed.,Rig up Weatherford power tongs. C/O handling equipment. L/D 26 joints 2-3/8" PH6, and casing scraper BHA.,Drain stack. BOLDS. Pull wear bushing.,C/O elevators. Rig up 3-1/2" handling equipment. Verify lengths, OD, ID on equipment. Verify pipe count. RIH with 3-1/2", 9.3#, L-80, H563W frac string as per tally: Seal assembly, (2) jnts tubing, X-Nipple, (1) jnt tubing, Sliding sleeve and tubing to 312'. PUW 37K, SOW 37K. Calculated displacement.,Daily hauled 922 bbls to G&I total = 12,587 bbls Hauled 0 bbls from 6 mile lake, Total 13,480 bbls Lost Production section 0 bbls to formation. Total 23 bbls Total fluid lost Intermediate section = 682 bbls Fluid lost on surface hole = 46 bbls Total Metal 14# 11/28/2019 Cont. to RIH with 3-1/2", 9.3#, L-80, 563W tubing from 316' to 6897'. Calculated displacement observed. PUW 98K, SOW 54K.,Cont. to RIH with 3-1/2", 9.3#, L- 80, 563W tubing from 6897' to 12,038'. Calculated displacement observed. PUW 110K, SOW 60K.,Cont. to RIH with 3-1/2", 9.3#, L-80, 563W tubing from 12,038' to 12,882'. PUW 120K, SOW 65K.,Rig up XO, head pin, and hose on jnt 411. Establish circulation at 2bpm/140psi. Slack off and attempt to engage seals. Tag up with mule shoe on liner top, no pressure increase. Attempt to get mule shoe through liner top, setting up to 15K down and pumping 4bpm/490 psi. Rig down circulating equipment. L/D jnt 411. Change out elevators. Pick up XO's to 4" XT39 DP. Establish circulate at 2 bpm/87 psi,,rotary at 4 rpms/1700 ft- lbs, slack off and observe seals engage with pump pressure increase. Shut down pumps and rotary. Continue to slack off, NO-Go at 12,920'. Set 15K down to 12,922'. Space out, L/D XO's, landing joint and joint #410. Pick up 9.79' and 3.8' pup joints, followed by joint #410.,M/U tubing hanger and landing joint. Slack off and attempt to engage seals, stack out. Establish pumps 2bpm/81 psi, rotary 4 rpms/2000 ft- lbs. Engage seals. Shut down pumps/rotary. Drain stack. Slack off and land tubing with 15K down on No-go. Verify hanger landed. Pressure up on tubing to 500 psi and pick up out of seals until pressure drops.,Rig up to freeze protect well. Reverse 79 bbls of diesel followed by 60 bbls brine. Line up and circulated down tubing 26 bbls of diesel followed by 10 bbls of brine to clear lines; 4 bpm/620 psi.,Slack off and land tubing on depth with 15K on No-Go, 15K on hanger. SOW 65K, verify hanger landed. RILDS. Rig up testing equipment. PT tubing to 4000 psi for 30 minutes - good.,Daily hauled 228 bbls to G&I total = 12,815 bbls Hauled 0 bbls from 6 mile lake, Total 13,480 bbls Lost Production section 0 bbls to formation. Total 23 bbls Total fluid lost Intermediate section = 682 bbls Fluid lost on surface hole = 46 bbls Total Metal 14# n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: MP F-116 Milne Point Hilcorp Energy Company Composite Report North Slope Bourough, AK Contractor AFE #: AFE $: Job Name:1914665C MPU F-116 Completion Spud Date: Cont. to PT casing/liner to 3000 psi for 30 minutes --Jet pump completion for frac. Cont. to RIH with 3-1/2", 9.3#, L-80, 563W tubing from 316' to 6897'. 11/29/2019 Attempt to PT IA to 3500 psi with 1000 psi on tubing. Unable to get good test due to surface leaks. L/D landin gjoint and XO's. B/D top drive. Close blind rams and purge choke and kill. Pressure up tubing up to 1000 psi. PT IA to 3500 psi for 30 minutes - good. Rig down testing equipment.,Pick up T bar. Set BPV as per wellhead rep.,R/D testing equipment. Flush mud pumps, top drive, choke manifold and blow down. Pull mouse hole. Clean drip pan. Remove choke and kill lines. Pin weight buckets and remove tongs.,De-energize accumulator. Break down MPD hard lines. Pull riser, install airboot protector. Install RCD test cap. R/U long slings from bails to RCD. 4- bolt stack. Pull RCD. Set stack back on stump. SimOps: Perform Bi-annual mud pump inspection on MP 2.,N/U dry hole tree. Test tubing hanger void to 500/5000 psi - good.,Blow down water and steam. Freeze protect test pump, pressure washer. Skid MPD choke skid. Lay herculite and rig mats for MP F-45. Bridle up and scope derrick down. prep rig floor for rig move. Rid down interconnects. Rig released at 00:00.,Daily hauled 415 bbls to G&I total = 13,230 bbls Hauled 100 bbls from 6 mile lake, Total 13,580 bbls Lost Production section 0 bbls to formation. Total 23 bbls Total fluid lost Intermediate section = 682 bbls Fluid lost on surface hole = 46 bbls Total Metal 14# 12/13/2019 MIRU AK eline. CCL to TS = 10.375'. PT to 3500 psi. RIH with 2.5" -2511 ReFrac IQ, 6 SPF, 60 deg phasing - 5' perf gun. Correlation pass from 13,608' to 13,220'. Tie into MWD log (24-Nov-2019). Final depth shift = +17.2'. Log into position with CCL at 13,445.6'. Shoot 13,456' - 13,460'. Log off. Jewelry log from 13,600' to 12,700'. POOH. RDMO. Initial T/I/O = 0/0/0 psi Final = 650 psi/0/0 psi PU WT off bottom = 3k 12/19/2019 Complete Frac RU. MIRU LRS on backside. PT IA surface lines to 4500 psi. Set IA pop-offs to 4k. Problem with SLB blender. Will need to swap out blenders. Unable to frac today. 12/20/2019 PT all lines to 1,000/8,000psi. Pump min-frac, freeze protect and shut down to analyze. Perform Frac on A2 Sand. Pumped 2,229 bbls total and 201,880 lbs of 16/20 CarboBond lite. 7,020 psi max pressure seen. Average rate of ~19 bpm. Underflush by 3 bbls. Pull tree saver and MIRU CTU on well. 12/21/2019 MIRU SLB CTU with new string of 1.75" CT. Drift string with 1.188" OD steel ball. Perform full BOP test and record on 10-424. MIRU on F-116 MU CTC, MHA, PDS memory GR/CCL logging tools enclosed in 2.375" OD pump thru logging carrier, and 2.5" OD JSN. PT on well to 280/4000 psi. RIH and found final TOS depth at 13,485' ctmd. Clean out above tag by pumping 1.5x BU at 1.9 bpm. RE-Tag same and log up 50' (stop to flag pipe),then to 12,700' ctmd. POOH. Download logging tools, tie into HAL MWD dated 24_NOV-2019, depth shift by +49.5' putting TOS at 13,428.54', leaving 27.5' of proppant above KUP A perfs. RBIH and freeze protect well to 2500' with 60/40 meth. POOH. At surface apply 3500 psi WHP to test permeability of sand plug using 1.1 bbls. Initial test pressure was 3510 psi and after 7 minutes,,30 psi was lost with final pressure of 3,480 psi. RDMO SLB CTU. 12/22/2019 "***Well S/I ON ARRIVAL***(perf) PT PCE 250L / 3000H***" PT PCE 250 LP-3000HP MADE 1 ATTEMPT TO 2.50" X 4' PERF GUN, UNABLE TO PASS 3129' ELMD. RAN 1-7/8" SS SPANGS, 2.25" X 5' DRIVE DOWN BAILER, MULE SHOE FLAPPER BTM, UNABLE TO PASS 3158' ELMD. FLAPPER FOULED WITH FRAC SAND, NO SIGNIFIGANT RETURNS. RAN 1-7/8" SS SPANGS, 2.25" X 5' DRIVE DOWN BAILER, MULE SHOE BALL BTM,UNABLE TO PASS 3142' ELMD. RECOVERED FULL BAILER OF FRAC SAND(5 CUPS) R/D AND MOVE OVER FOR SLICKLINE TO BAIL. WELL LEFT S/I. 12/23/2019 MIRU SLICKLINE **WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/1500H** MAKE 8 BAILER RUNS WITH MULTIBLE BAILERS FROM 3142' SLM TO 3344' SLM (recovered ~16gal frac sand total) **RDMO, CLOSE PERMIT W/PAD-OP** 12/24/2019 MIRU SLB CTU #8 with 1.75" CT. PT to 300/3500 psi. RIH with 2.5" OD JSN to 2500' ctmd. Begin pumping and clean out tubing and liner down to 13,384' ctmd pumping slick 1% and gel sweeps. Circulate sweeps out of hole. SD and dry tag at 13,418' ctmd (13,409' corrected to coil flag from logging run). POOH pumping 2 bpm swap to 60/40 at 6900' ctmd and freeze protect from 3900' while POOH. Stop pumping with nozzle at surface.,PT sand plug to 3000 psi twice. Both times lost ~2000 psi in 5 minutes. RD coil off well and leave unit in place for KUP C sand post frac cleanout.,Perf Kup C sand - 13,354'-13,358' with GEO REFrac IQ charges - 2.5" OD gun - 6 SPF - 60 deg phasing. Performed by AK-Eline 12/25/2019 Use LRS hot oil unit to heat the water back up to +100 degrees in the 4 Frac tanks needed for KUP C frac 12/26/2019 Finish heating water in frac tanks. Heated to 120 degrees. Stab Tree Saver and RU Frac. PT all lines to 1,000/8,000psi. Pump min-frac and shut down for 15 min to analyze. Perform Frac on C Sand. Pumped 1500 bbls total and 137,500 lbs of 16/20 CarboBond lite. 7400 psi max pressure seen. Average rate of ~17 bpm. Underflush by 3 bbls. Pull tree saver and MIRU CTU on well. 12/27/2019 MIRU SLB CTU #8 with 1.75" CT. PT to 360/4000 psi. RIH with 2.25" OD DJN. At 2800' start pumping 105 degree SLK 1% down coil at 1 bpm. After 9 bbls, water froze in coil. Try to chase with 60/40 and no luck. POOH, apply heat to reel to thaw coil. Coil thawed. Start BOP test that is due. 12/28/2019 Complete CT BOP test and record on 10-424. Get on well PT to 300/4000 psi. RIH with 2.25" OD DJN. Tag at ~13,000' ctmd. Clean out to 13,673' ctmd, hard tag. POOH. Freeze protect well. MIRU Slickline and drift to 13,684' slmd. POOH 12/29/2019 CONTINUED FROM PREVIOUS DAY. RAN 3'x1-7/8"" R-STEM (2.6""wls), 3-1/2"" 42BO (keys down) TO 12,780' SLM (12,770' MD) & SHIFTED XD SLIDING SLEEVE OPEN. SET 3"" JET PUMP W/ SCREEN (ratio: 11C, ser# HC-0002) @ 12,780' SLM (12,770' MD), ALL PINS ON X-LINE RECOVERED. 1/22/2020 1-23-2020 "PRESSURE TEST LOW 250 PSI, HIGH 3500 PSI CORRELATE TO HALLIBURTON MD LOG LRS PUMP 2 BPM TO GET TOOLSTRING DOWN 20' 2.5"" GEODYNAMICS GUN SHOOT FROM 13,520-13,540' NIGHT CAP WELL ***JOB IN PROGRESS*** " PT IA to 3500 psi for 30 minutes - good perf A sand Frac C sand TOS depth at 13,485' ctmd. Clean out above tag by pump Perform Frac on C Sand. Pumped 1500 bbls total and 137,500 lbs of 16/20 CarboBond lite. 7400 psi max pressure seen. Average rate of ~17 bpm. Underflush Perform Frac on A2 Sand. Pumped 2,229 bbls total and 201,880 lbs of 16/20 CarboBond lite. 7,020 psi max pressure seen. Average rate of ~19 bpm. Underflush Shoot 13,456' - 13,460'. Perf C sand ,Perf Kup C sand - 13,354'-13,358' Frac A sand Attempt to PT IA to 3500 psi with 1000 psi on tubing. U SET 3"" JET PUMP W/ SCREEN 1/24/2020 SLB E-LINE: T/I/O = 600/660/50. Pressure test PCE to 250 psi low and 3,500 psi high. RIH and perforate the Kuparuk A1 sands from 13,500' to 13,520' with a 20' 2-3/8" Geodynamics Razor Gun (6spf). Tubing pressure increased from 600 psi to 640 psi after firing guns. POH. L/D spent guns.,T/I/O = 640/660/50. P/U 14' gun and RIH. Perforate the Kuparuk A1 sands from 13,485' to 13,499' w/ 2-3/8" Geodynamics Razor Gun (6spf). No Tubing pressure increase noted. POH. L/D spent guns.,T/I/O = 620/660/50. P/U 20' gun and RIH. Perforate the Kuparuk B6 sands from 13,380' to 13,400' with a 20' 2-3/8" Geodynamics Razor Gun (6spf). Tubing pressure increase from 620 psi to 625 psi. POH. L/D spent guns. T/I/O = 625/660/50.,RD and SDFN 1/25/2020 SLB E-LINE: T/I/O = 650/700/50. Pressure test PCE to 250 psi low and 3,500 psi high.,RIH and perforate the Kuparuk B6 sands from 13,362' to 13,380' with a 18' 2-3/8" Geodynamics Razor Gun (6spf). No tubing pressure response after firing guns. POH. L/D spent guns.,T/I/O = 655/700/50. P/U 14' gun and RIH. Perforate the Kuparuk A2 sands from 13,460' to 13,474' with a 14' 2-3/8" Geodynamics Razor Gun (6spf). No Tubing pressure increase noted. POH. L/D spent guns.,T/I/O = 655/700/50. P/U 10' gun and RIH. Perforate the Kuparuk A3 sands from 13,438' to 13,448' with a 10' 2-3/8" Geodynamics Razor Gun (6spf). No Tubing pressure increase noted. POH. L/D spent guns.,T/I/O = 655/700/50. Secure well. RDMO. 2/4/2020 MIRU CTU #6 w/ 15,538' of 2" coil. BOP Test to 250 psi low and 4,000 psi high. Tested : Stripper, 2 x Blind shear rams, slips, and pipe rams. Tested 2 choke line valves, 2 kill line valves, check valve, and 7 choke valves within manifold. System pressure for the accumulator was 3,000 psi, pressure after closure was 1,750 psi. 200 psi attained in 20 seconds. Full pressure attained in 124 seconds. Total test time was 5 hour 2/5/2020 Wait on Weather 2/6/2020 Wait on Weather 2/7/2020 Wait on Weather 2/8/2020 Wait on Weather 2/9/2020 MIRU CTU #6: 15,335' of 2" coil. CV = 42.8 bbls.,M/U BHA: 2.0 " CTC, 2.13" DBPV, 2.25" Jar, 2.13" Disconnect, 2.13" Circ Sub, 3" GS. OAL = 11.38'.,Stab onto the well. P/T lubricator and surface lines to 250 psi low and 3,500 psi high. No returns seen at flowback tanks. Attempt to find ice plug downstream. Thaw lines. Lines free. P/T lines to 250 psi low and 3,500 psi high.,Open swab. WHP = 630 psi. RIH w/ BHA #1 while taking displacement to the open top tank. Holding 200 psi back pressure on the choke. Returns to tank are 0.75BPM to 1 BPM. Pump 60/40 MeOH to BOPs with triplex every 10-15 minutes.,Sit down 4k-lbs while RIH at 5,500'. Attempt to circulate 60/40 MeOH at 1 BPM. No returns seen but injecting into formation. Circulation pressure quickly increases to 3,000 psi and quickly decreases to 1,500 psi with no sign of WHP response. Circulation pressure increases quickly to 4,100 psi and then quickly falls to 1,500 psi. Cannot get returns. Attempt to POH. P/U to 46k-lbs. No movement.,Wait on LRS.,R/U LRS. P/T line to 250 psi and 3,500 psi. Come online and pump 120 degree diesel down coil tubing at 1 BPM and 1,800 psi. Ice thaws with 90 bbls of 140 degree diesel away.,Contnue to RIH w/ BHA #1. RIH and tag at 13,609' ctmd. Set down 5k lbs. POH to 13,550'. P/U weight is 32-k lbs. RBIH to 13,609'. Set down 5k-lbs. P/U weight is 32-k lbs.,POH to surface. Hang up at 12,922' and experience 10k-lb overpull. RBIH to 13,050'. POH and hang up again at 12,922'. Pull 13k-lbs overpull. RBIH to 13,050'. Decision made to RIH and drop Jet Pump below perforations.,Bullhead 30 bbls of 60/40 MeOH at 2 BPM at 1250 psi. Close SV and UMV. Bleed lubricator. Blow down lines. Stand back injector. 2/10/2020 CTU 6: Drive to location.,Attempt to RIH. Packoffs leaking. Change packoffs and cut 200' of coil.,SDFN 2/11/2020 MIRU CTU #6: 15,335' of 2" coil. T/I/O = 820/750/100 psi. M/U BHA #2; 2" CTC, 2 x NPT, DFCV, 2" DJN. OAL = 9.4'. Pressure test PCE to 250 psi low and 3,500 psi high. RIH w/ BHA #2 to 13,300'. Pumped 290 bbls of 1% KCL and two 20 bbl gel sweeps. Pumped 44 bbl of Diesel down IA to maintain positive pressure and flow through sliding sleeve. Cleaned out to 13,600' ctmd. Freeze protected coil with 42 bbls of 60/40 MeOH.,Freeze protect tubing with 34.5 bbls of 60/40 MeOH.,RDMO 3/5/2020 Perform well kill. Initial TB psi 550, CSg psi-260. KW fluid = 9.0ppg Nacl brine. Start pumping and ramp up to 4.25 bpm in and 3.8-4.0 bpm out to returns tank. Pump total of 590 bbls in well with total of 510 bbls returned fluid. s/d pumping and tubing and casing on vac. Install BPV. RDMO Little Red Services. 3/6/2020 Well work on I-19,Start RDMO of ASR off of I-19 to F-116. Start move heaters, Pipe skate, remove horse shoe scaffolding from F-116, begin packing conex's, R/D and move 300 KW "rental" generator, move pipe sheds, and R/D winterization. Pull pipe rams from current stack to load in second BOP stack.,Lay over derrick on rig, begin crane operations, pull floor , pull annular, pull double gate BOP, Fly in tree and start to nipple up tree.,Pick up and load out accumulator hoses, and pull well house.,Begin to swap out rams in BOP for upcoming string dimensions. Continue to stage equipment to F-pad.,Complete swapping out to 2- 7/8" x 5" rams, function test - all good. Moving and staging equipment to F-pad.,Torque bolts on ram bodies. Move pits module to F-pad. Begin to MIRU on F- 116. 3/7/2020 Continue MIRU equipment, complete spotting pits, Bleed off PSI on backside, start to pull tree and found pressure on tree. Called out Wellhead Team and found BPV leaking. Made several attempts to manipulate BPV.,Continue to work on BPV and finally got it to hold, monitored and pulled tree. SIMOPS: Start to assemble BOP. Drilling needed Crane for Conductor pipe work, R/D crane and begin moving heaters and small loads from I-19. Crane returned @ 1300 hours. Begin BOP assembly and complete pull tree. Road rig to location. VMS reset settings on transmission. tran shifting smooth and speedo working properly.,Start to N/U BOP components on well, SIMOPS lay out BOP hoses w/ Crane, Spot floor next to well hut w/ crane, Start spotting conex's, Necessary to swap connections on HCR valve to match BOP lines, Spot Camps, VMS repaired 300KW in the pit trailer - generator engine running good- generator not generating electricity. Spot rig and raise derrick.,Complete NU of BOP. Continue with moving in stairs, prep for connecting Accumulator lines,RU and connect Accumulator lines. Supply hydraulic fluid, leak at door hinge point (this model of Single Gate supplies hydraulics through that point). Attempt to function rams twice, still leaking.,Call BOP representative to troubleshoot. Discuss options.,Crew eat lunch and conduct Sundry brief for well F-116 at same time.,Remove bolts for ram door and attempt to cycle door open and closed several times per recommendation from BOP rep. Install and torque bolts, supply fluid and door still leaking. (Loss of one hour due to time change at 0200 hrs). Take on fresh water into pits for BOP test.,Send recommendation to ODE for moving forward. Open up to IA with gauge to check for pressure, no pressure. RU test pump to test between Check Valve in hanger and Blind Rams. 3/8/2020 Morning Safety Meeting, Daily plan forward to attempt to repair leaking BOP Hinge Seal.,Start breaking out bolts to attempt to rotate single gate BOP in order to fully open the ram door and re-seat hinge seal. SIMOPS keep winterizing lines in order to PT blind rams to 3500psi for preliminary test. Test blinds to 3500psi. for good pre-test. Continue to lay down derrick and prep to pull floor.,Pull rig floor and rotate single gate rams, open and close ram door 8 times and close and tighten. Function rams open and closed 15 times and hold pressure on seal with no leak. Torque ram onto double stack , re-install annular, pick up and land rig floor, stand up derrick, . Elecs working on gen, found several bad connections, r&r connections. Gen continue to make bad sound mechanics ordered more parts,Electricians re-connect fire and gas detection and test, fill BOP with water. P/U test mandrel, pressure up for function test of lines for shell test, find leak. Troubleshoot and address leak.,Pressure up again to inspect lines, leak at TIW. Address leak, frozen TIW. Thaw, pressure up and good. Begin shell test to 3500 psi, good test. Conduct 5000 psi test against blinds to confirm test pump capability and no leaks, all good. Notify State AOGCC Rep.,Continue to inspect lines, address cold areas while waiting on AOGCC Rep. Rep on location, discuss expectations for high pressure testing requirements.,Conduct required high pressure testing of new BOP components to 250 psi low / 5000 psi high. State AOGCC Rep witnessed tests, confirmed good tests.,Continue with normal BOP test. Test BOP equipment and 2-7/8" by 5" VBRs to 250 psi low / 4000 psi high against 3-1/2" test joint. Annular tested to 2500 psi per Sundry permit. = 600/660/50. Pressure test PCE to 250 psi low and 3,500 psi high. RIH and perforate the Kuparuk A1 sands from 13,500' to 13,520' with a 20' 2-3/8" Geodynamics Razor Gun (6spf). Tubing pressure increased from 600 psi to 640 psi after firing guns. POH. L/D spent guns.,T/I/O = 640/660/50. P/U 14' gun and RIH. Perforate the Kuparuk A1 sands from 13,485' to 13,499' w/ 2-3/8" Geodynamics Razor Gun (6spf). No Tubing pressure increase noted. POH. L/D spent guns.,T/I/O = 620/660/50. P/U 20' gun and RIH. Perforate the Kuparuk B6 sands from 13,380' to 13,400' with a 20' 2-3/8" Geodynamics Called out Wellhead Team and found BPV leaking. 3/9/2020 Crew swaps and morning safety meeting. SIMOPS continue test BOP.,Continue testing BOP. Lou Loubenstein witnessing for AOGCC. Tested BOP double gate (pipe and blind rams) S/N A68-17 to 5000 psi for good test. Single Gate BOP S/N A91-23 pipe rams to 5000psi for good test, Test 2-1/16" choke and kill manual valves S/N A226-43, 47, and 52 to 5000 psi for good test. Tested 2-1/16" HCR valve to 5000spi for good test.,Complete BOP testing. Tested all other BOPE and tested all fire and gas, pit levels. Completed BOP testing.,Blow down all lines and prep to start circulating out tubing. Pull CTS dart, found pressure under BPV, backside dead, take on 280 bbls 9.0 heavy NaCl brine.,Hydraulic hose blew out on elevators while 20 feet in air, S/D hydraulics, bring manlift and utilize man lift to repair hose, lower and swap elevators,,Prep to circulate tubing , line up tiger tank for returns, tighten lines to tiger tank and check flow with air.,Start pumping down tubing @ 2bpm (max allowed by bpv) 2 400psi. Backside no flow, pump 20 bbls to get returns. Fluid level @ ~720'. Pumped 50 bbls with 16 bbls returns. Returns weigh 9.0 swapped to circulate to pits, circulate 80 bbls monitoring returns losing 1 bbl for 4 pumped shut down and check tubing psi. Tubing psi @ 187. BPV not holding. Casing on vac.,Let tubing settle and bleed tubing to tiger tank. Tubing bleed to zero. Install t-bar and screw poppet off set and let tubing vent. Pull BPV and shut blinds to monitor tubing.,Crew Pre-Tour meeting and swap out. Check fluids on equipment, line up to confirm pressures on tubing and IA. Initial pressure on tubing at 185 psi.,Decide to reverse circulate to ensure a full backside of 9.0 fluid and sweep the tubing. Target 4 bpm while holding ~100 psi back-pressure. Tubing pressure now 260 psi. Circulated, monitored returns, initial large crude return from tubing, lost 87 bbls to formation. Shut in, IA and Tubing both at 28 psi. IA dropped to 0, tubing to 6 psi. After 45 minutes, IA at 8 psi and tubing at 19 psi (eventually rose to 35 psi).,Discuss with ODE while monitoring. IA remained at 0 psi and remained static (not on a loss but not giving any pressure either), tubing remained at 35 psi. Convinced it was mixed fluids causing erratic pressures. Plan forward is to bullhead into perfs and then take returns from tubing to assess weights.,Circ across top, took 6 bbls to clean up. IA fluid weight 9.0 ppg heavy. Bullhead 30 bbls down backside with high circ pressure of 425 psi and breakover to final pressure of 390 psi at 3.5 bpm. Down on pumps, tubing pressure against closed choke 178 psi. Monitor 30 minutes, pressure dropped to 43 psi and held steady. Bled, taking returns from tubing through MGS, initial returns were a little oily, weight at 9.0 ppg.,Tubing bled to ZERO, monitor well, tubing and casing dead. Conduct walk through of Well Control Drill. Pull hanger, release at 37k PUW. Breakover at 108k while pulling hanger to rig floor. Break off hanger, lower to ground.,POH and lay down 3-1/2" 9.3# tubing string. Initial PUW coming out of hole at 98k. 55 joints out hole @ 0530. 3/10/2020 Morning Safety meeting, fluid checks on all equipment.,Monitor well- tubing and casing dead, continue to POOH w/ 9.3# 3.5" tubing laying down, pumping double displacement w/ 9.0 ppg brine every 15 joints and blowing down lines after pumping. 170 joints out of hole @ 11:30 hrs. Rig pulling in low gear due to weight.,Continue to POOH w/ 9.3# 3.5" tubing laying down, pumping double displacement w/ 9.0 ppg brine every 15 joints and blowing down lines after pumping. 295 joints out of hole @ 15:30 hrs.,Continue to POOH w/ 9.3# 3.5" tubing laying down, pumping double displacement w/ 9.0 ppg brine every 15 joints and blowing down lines after pumping. 387 joints out of hole @ 1800 hrs.,Complete pulling out of hole with 3-1/2" tubing, total of 410 joints pulled (will be run back in).,Prep for running ESP assembly. Pick up and make up motor and pump assemblies per Baker Centrilift personnel.,Continue to pick up and make up motor and pump assemblies per Baker Centrilift personnel. Test electrical cable.,Begin RIH on 3-12" 9.3# L-80 Hyd 563 tubing. X-Nipple and GLM placed into string per running tally. Test electrical cable every 1000' run. Joint 45 in well as of 0445 hrs. Crew conducting fluid checks and strapping pipe while troubleshooting 300k backup generator. 3/11/2020 Crew swaps, fluid checks and morning Safety Meeting.,Continue to RIH w/ 3-1/2" 9.3# Hydril 563 tubing, clamping every joint for first 100 collars then every tother collar. Pumping double displacement of 9.0ppg brine every 15 joints. Testing cable every 1000',Continue to RIH w/ 3-1/2" 9.3# Hydril 563 tubing, clamping every other collar, Pumping double displacement of 9.0ppg brine every 15 joints. 135 joints in the hole @ 13:30 hours. Testing cable every 1000',Lost John Deere Generator on accumulator unit. Notify VMS, VMs arrived and founf faulty fuel guage. Gauge showing full, but fuel empty. Refuel, re-start and go back RIH.,Continue to RIH w/ 3-1/2" 9.3# Hydril 563 tubing, clamping every other collar, Pumping double displacement of 9.0ppg brine every 15 joints. Testing cable every 1000',Continue to RIH with ESP completion on 3-1/2" 9.3# Hydril 563 tubing; clamp on every other collar. Pump single displacement of 9.0ppg brine every 15 joints. Test cable every 1000'.,RIH with ESP completion on 3-1/2" 9.3# Hydril 563 tubing; clamp on every other collar. Pump single displacement of 9.0ppg brine every 15 joints. Test cable every 1000'.,Conduct splice of ESP cable,Fill well, took 3.7 bbls. RIH with ESP completion on 3-1/2" 9.3# Hydril 563 tubing; clamp on every other collar. Splice is located on joint 256. Continue to RIH, fill well with displacement every 15 joints. Test cable every 1000'.,RIH with ESP completion on 3-1/2" 9.3# Hydril 563 tubing; clamp on every other collar. Fill well with displacement every 15 joints and test cable every 1000'. 3/12/2020 Crew swaps, Morning Safety Meeting, and Fluid Checks in all equipment.,RIH with ESP completion on 3-1/2" 9.3# Hydril 563 tubing; clamp on every other collar. Fill well with displacement every 15 joints and test cable every 1000'. 1 GLM assembly and 3 joints tubing left to pick up and land hanger.,At RIH w/ GLM crew noticed pipe jump and slack in ESP cable. Attempt to P/U and pipe not moving @ 136K up. Attempt to lower in hole and lower 3' feet @ 21K down, attempt to pull up and pipe stops moving @ 136 -140K up with 3' loss in pipe. Notify Engineer. Make several attempts to free pie. Pull to 146K and loud "clink" sound at well head and pipe free at 146K up.,Pull GLM and 3 joints tubing @ 142-44K up. Found cable pulled in two at length matching where GLM would pass through wellhead. Cut and test cable for good test. Prep to splice cable. Splice located between joint # 396 and 397. Plan is to re-run tubing and ESP assembly without installing GLM.,Add heater trunks to rig floor and build visquine hooch for cable splice. Centrilift splice cable.,RIH with ESP completion on last 6 joints of 3-1/2" tubing. Make Penetrator Splice and terminate cap tube. Do final checks.,MU pup and hanger. Conduct crew changeout, check fluids and heaters. Weather is kicking up and causing berms.,Land completing into hanger, SOW 20k. Run in Lock Down Screws and set BPV. Total joints run 406, hanger plus ORKB places EOT at 12,814' md.,Close in Blinds, monitor to choke for any pressure buildup. Well Secure 2000 hrs, begin RDMO for move to L-25. Prep to lay down Derrick; Phase 2 called due to drifting snow and high winds - 35 -40 mph sustained, up to 60 mph gusting. Derrick limit is 35 mph, cannot lay down derrick.,Cleaning up location, moving and staging equipment and support materials in preparation for moving to L-25. Visibility and blowing snow is limiting further work. Discussion with crew on operations in Phase 2 /3 weather, emphasis on radios, 2-man minimal on jobs, equipment inspection every 2 hours.,Phase 3 weather called. Keep all personnel indoors whule monitoring well. 3/13/2020 S/D down due to phase 3 weather. Keep minimal crew at wellsite monitoring well. BPV installed with BOP blinds locked shut . 0 psi build up between blinds and hanger. 3/14/2020 Start RDMO all equipment to L-25. 3/15/2020 Morning Safety Meeting, RDMO equipment to L-25..,N/U tree, test ESP cable terminaton / penetration at hanger and ESP cable shows to be grounded. Clean penetrator and re-test for ground fault. ESP cable determined bad. Call town and decision made to re-pull well troubleshoot and repair. SIMOPS service ASR rig at tent, look for hydraulic leak.,Start re-mobilizing equipment back to F-116. Re-set well hut, re-install BOPS, notify state for new BOP test. Drive ASR to well and spot on mud boat,,Continue to MIRU ASR, re-spot heaters, Electricians connect and test LEL and gas detectors, continue to N/U BOP's. Raise and secure Derrick.,Night Tour Safety Meeting, crew swap. Conduct walkaround and equipment check.,Prep rig for operations. Bring in Fresh Water for BOP test. Complete NU of BOP stack with 2-7/8" x 5" VBRs.,Complete RU on F-116. Fluid pack lines, check for leaks. Prepare for BOP test.,Shell test BOP, chase minor leaks, good test. Begin BOP test with 2-7/8" and 3-1/2" test joints on 2-7/8" x 5" variable rams to 250 psi low / 4000 psi high on rams and 250 psi low / 2500 psi high on Annular per Sundry. Run ESP ,Prep for running ESP assembly. Rig back pull frac string (jet pump) SIMOPS continue test BOP.,Continue testing BOP. Lou Loubenstein witnessing for AOGCC. Pull hanger, release at 37k PUW. Breakover at 108k while pulling hanger to rig floor. ESP Fault ground Pick up and make up motor and pump assemblies per Baker Centrilift personnel. ,Monitor well- tubing and casing dead, continue to POOH w/ 9.3# 3.5" tubing laying down, 3/16/2020 Morning Safety Meeting, Continue BOP test with 2-7/8" and 3-1/2" test joints on 2-7/8" x 5" variable rams to 250 psi low / 4000 psi high on rams and 250 psi low / 2500 psi high on Annular per Sundry. BOP testing complete.,Connect hoses to backside and flowback tank. Blow down BOP stack and associated lines. Backside psi = 277psi. Bleed off gas and start getting live crude oil. Bled 2 bbls crude oil and shut in backside. PSI @ 277. Pull CTS plug from BPV and pump into tubing @ 850 -900psi. Call town and decision made to order 9.5ppg NaCl brine to re-kill well. Order Brine.,Clean location and stage pipe racks, prep for circulation,First truck on location, waiting on next two trucks. Service equipment, inventory tool storage.,Safety meeting with evening crew, explain days events.,Back in trucking. Spot in Little Red Pumping unit. Third truck on location, piggyback trucks, rig up to Little Red. Conduct pre-job on Bullhead operation.,Begin Bullhead Operation. Cannot attain rate, alter schedule and volumes. Total bbls pumped into formation 680 bbls. Monitor well, RD pumping unit.,Open up to well, bleed off residual pressure. Back out BPV. Break circulation, well on ~1/2 bpm losses while pumping.,Slight pressure on IA and Tubing, suspect entrained gas. Control bleed off of IA, then Tubing in 10 psi increments through MGS. Mixed fluid and gas returns, pressure dropping slowly and evenly. 3/17/2020 Morning Safety Meeting, plan forward and monitor well. Casing psi = 80 psi and tbg psi = 80 psi.,Bleed casing slowly to bleed off gas. Bleed to 33psi and fluid hit -Shut in casing. Bleed tubing to 20psi and fluid hit. Let well settle and equalize. 1 hour stabilization casing @ 52 psi and tubing @ 58 psi.,Discuss plan forward w/ engineer - decision made to pull G/L valve and circulate 9.8ppg NaCl brine. Notify Slickline and call Baroid to order brine. S/L arrive do a seafty R/U walk thru and discussion on rig floor. Install shooting flange on top of BOP. Start spotting S/L equipment.,R/U Slickline, S/L had to totally rebuild lubricator and PC equipment to accommodate ASR. P/U kick-over tool and stab lubricator, Pressure test lubricator to 500 psi, bleed off to 100 psi and open blinds and Slick-line RIH w/ kick-over tool.,RIH w/ kick-over tool on slickline @ 60- 75 fpm. S/L operator saying tools falling slow. Tools reach GLM @ 12591' WLM. W ork down locate and pull 1100# up and fire oil jars. Weight fall to 700# . RIH and check for set down, operator feels good to POOH. POOH w S/L @ xxx fpm.,POOH w/ S/L @ 150 fpm. On surface @1815 hrs with downhole dummy valve. RD Slickline Lubricator and sheave system. Line up trucks, strap tank for circ-out.,Begin circulation to swap well over from 9.1 ppg NaCl brine to 9.8 ppg NaCl brine. Circulate at 3.5-3.7 bpm, 410-625 psi. Circulate total of 682 bbls with ~25% loss rate to formation while pumping. With surface-to-surface volume around, fluid weight in 9.8 ppg, fluid weight out 9.7+ ppg. Monitor well for 15 minutes, flow across top - loss rate of ~42 bph.,Monitor IA, well on a vac. Back out LockDown screws and pull hanger to floor. PUW 166k, ESP cable badly damaged. Cut below damage, conduct meg test. Good test.,Prepare cable for splice. Splice cable, make up to Penetrator and test. 3/18/2020 Morning Safety Meeting, Daily plan forward, complete new hanger splice.,Cut 2 bent old 3.5" X-collar clamps into 4 half clamps. Utilize 4 half clamps to position ESP cable 90 to the left of hanger penetrator. Lower into hole, noting a definite pull force to the back of well (away from operator console). Landed hanger with test umbilical installed and tested hanger set for good test on ESP cable. Verified hanger in place.,RILDS, Install BPV - Final Test on hanger good @ 5000psi. END OF WELL. Begin RDMO to E-42.,Lower derrick move rig to tent, pull rig floor, N/D BOP"s , N/U tree , test void to 5000psi for good test. Continue to RDMO to E-42 pull hanger fix splice Back out LockDown screws and pull hanger to floor. PUW 166k, ESP cable badly damaged. er with test umbilical installed and tested hanger set for good test on ESP cable. Verified hanger in place.,RILDS, Install BPV - Final 02 December, 2019 Milne Point M Pt F Pad MPU F-116 500292365000 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt F Pad Halliburton Definitive Survey Report Well: Wellbore: MPU F-116 MPU F-116 Survey Calculation Method:Minimum Curvature MPU F-116 Actual RKB @ 37.57usft Design:MPU F-116 Database:NORTH US + CANADA MD Reference:MPU F-116 Actual RKB @ 37.57usft North Reference: Well MPU F-116 True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: MPU F-116 usft usft 0.00 0.00 6,035,680.49 542,131.74 11.49Wellhead Elevation:usft0.00 70° 30' 30.213 N 149° 39' 19.001 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU F-116 Model NameMagnetics BGGM2018 10/4/2019 16.45 80.97 57,415.10052009 Phase:Version: Audit Notes: Design MPU F-116 1.0 ACTUAL Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:26.08 49.260.000.0026.08 From (usft) Survey Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 12/2/2019 Survey Date 3_Gyro-MWD70+Sag H056Ga: Gyro-MWD70 + sag correction131.11 818.76 MPU F-116 GWD Survey (MPU F-116)10/28/2019 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa859.10 9,000.50 MPU F-116 MWD+IFR2+MS+Sag (1) (M 11/01/2019 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa9,068.26 13,014.68 MPU F-116 MWD+IFR2+MS+Sag (2) (M 11/06/2019 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa13,108.14 13,761.90 MPU F-116 MWD+IFR2+MS+Sag (3) (M 11/22/2019 MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 26.08 0.00 0.00 26.08 0.00 0.00-11.49 6,035,680.49 542,131.74 0.00 0.00 UNDEFINED 131.11 0.26 161.81 131.11 -0.23 0.0793.54 6,035,680.26 542,131.82 0.25 -0.09 3_Gyro-MWD70+Sag (1) 198.02 0.18 187.37 198.02 -0.47 0.11160.45 6,035,680.02 542,131.85 0.19 -0.23 3_Gyro-MWD70+Sag (1) 260.54 0.18 80.76 260.54 -0.56 0.19222.97 6,035,679.93 542,131.94 0.46 -0.22 3_Gyro-MWD70+Sag (1) 323.50 0.44 143.31 323.50 -0.73 0.43285.93 6,035,679.76 542,132.18 0.62 -0.15 3_Gyro-MWD70+Sag (1) 386.22 0.53 86.40 386.22 -0.91 0.87348.65 6,035,679.59 542,132.61 0.75 0.06 3_Gyro-MWD70+Sag (1) 447.50 2.73 47.81 447.47 0.09 2.23409.90 6,035,680.59 542,133.97 3.82 1.75 3_Gyro-MWD70+Sag (1) 509.38 4.14 49.57 509.24 2.53 5.02471.67 6,035,683.05 542,136.75 2.28 5.46 3_Gyro-MWD70+Sag (1) 571.20 5.20 46.75 570.85 5.89 8.76533.28 6,035,686.43 542,140.47 1.75 10.49 3_Gyro-MWD70+Sag (1) 633.65 6.87 46.04 632.95 10.43 13.51595.38 6,035,690.99 542,145.19 2.68 17.04 3_Gyro-MWD70+Sag (1) 696.75 10.04 49.39 695.36 16.63 20.41657.79 6,035,697.23 542,152.05 5.08 26.31 3_Gyro-MWD70+Sag (1) 12/2/2019 3:47:16PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt F Pad Halliburton Definitive Survey Report Well: Wellbore: MPU F-116 MPU F-116 Survey Calculation Method:Minimum Curvature MPU F-116 Actual RKB @ 37.57usft Design:MPU F-116 Database:NORTH US + CANADA MD Reference:MPU F-116 Actual RKB @ 37.57usft North Reference: Well MPU F-116 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 760.52 13.39 49.22 757.79 25.07 30.22720.22 6,035,705.73 542,161.82 5.25 39.26 3_Gyro-MWD70+Sag (1) 818.76 16.83 49.57 814.01 34.95 41.75776.44 6,035,715.67 542,173.29 5.91 54.44 3_Gyro-MWD70+Sag (1) 859.10 17.44 49.43 852.56 42.67 50.79814.99 6,035,723.44 542,182.28 1.52 66.32 3_MWD+IFR2+MS+Sag (2) 924.83 19.45 47.52 914.91 56.46 66.34877.34 6,035,737.32 542,197.75 3.19 87.12 3_MWD+IFR2+MS+Sag (2) 985.12 22.89 44.30 971.12 71.64 81.94933.55 6,035,752.59 542,213.26 6.02 108.84 3_MWD+IFR2+MS+Sag (2) 1,051.68 26.07 44.91 1,031.69 91.27 101.31994.12 6,035,772.32 542,232.52 4.79 136.32 3_MWD+IFR2+MS+Sag (2) 1,115.15 29.17 46.72 1,087.92 111.75 122.421,050.35 6,035,792.92 542,253.52 5.06 165.69 3_MWD+IFR2+MS+Sag (2) 1,178.80 31.96 46.62 1,142.72 133.96 145.961,105.15 6,035,815.26 542,276.93 4.38 198.02 3_MWD+IFR2+MS+Sag (2) 1,242.36 33.85 47.47 1,196.09 157.48 171.241,158.52 6,035,838.93 542,302.07 3.06 232.52 3_MWD+IFR2+MS+Sag (2) 1,305.27 35.73 47.22 1,247.75 181.81 197.631,210.18 6,035,863.40 542,328.32 3.00 268.39 3_MWD+IFR2+MS+Sag (2) 1,367.03 38.72 47.35 1,296.92 207.15 225.081,259.35 6,035,888.89 542,355.62 4.84 305.73 3_MWD+IFR2+MS+Sag (2) 1,432.84 41.33 48.38 1,347.31 235.53 256.471,309.74 6,035,917.45 542,386.85 4.09 348.04 3_MWD+IFR2+MS+Sag (2) 1,496.51 43.45 48.60 1,394.33 263.98 288.611,356.76 6,035,946.07 542,418.82 3.34 390.95 3_MWD+IFR2+MS+Sag (2) 1,560.11 46.36 48.86 1,439.37 293.58 322.361,401.80 6,035,975.87 542,452.40 4.58 435.85 3_MWD+IFR2+MS+Sag (2) 1,623.56 49.25 48.80 1,481.99 324.53 357.741,444.42 6,036,007.01 542,487.60 4.56 482.85 3_MWD+IFR2+MS+Sag (2) 1,687.03 50.38 49.11 1,522.94 356.37 394.311,485.37 6,036,039.05 542,523.98 1.82 531.33 3_MWD+IFR2+MS+Sag (2) 1,750.56 49.43 47.98 1,563.86 388.54 430.731,526.29 6,036,071.42 542,560.22 2.02 579.93 3_MWD+IFR2+MS+Sag (2) 1,814.32 51.50 47.81 1,604.44 421.51 467.211,566.87 6,036,104.60 542,596.51 3.25 629.08 3_MWD+IFR2+MS+Sag (2) 1,876.73 55.74 48.58 1,641.45 454.98 504.671,603.88 6,036,138.28 542,633.77 6.87 679.31 3_MWD+IFR2+MS+Sag (2) 1,940.82 56.97 48.78 1,676.96 490.21 544.741,639.39 6,036,173.73 542,673.63 1.94 732.66 3_MWD+IFR2+MS+Sag (2) 2,003.68 57.77 49.73 1,710.86 524.76 584.841,673.29 6,036,208.51 542,713.54 1.80 785.60 3_MWD+IFR2+MS+Sag (2) 2,067.51 62.33 51.34 1,742.72 559.89 627.541,705.15 6,036,243.88 542,756.03 7.47 840.87 3_MWD+IFR2+MS+Sag (2) 2,130.97 65.71 52.55 1,770.51 595.04 672.461,732.94 6,036,279.28 542,800.75 5.60 897.85 3_MWD+IFR2+MS+Sag (2) 2,193.98 64.54 51.31 1,797.02 630.29 717.461,759.45 6,036,314.77 542,845.54 2.58 954.95 3_MWD+IFR2+MS+Sag (2) 2,257.77 62.88 51.40 1,825.27 666.00 762.131,787.70 6,036,350.74 542,890.00 2.61 1,012.10 3_MWD+IFR2+MS+Sag (2) 2,321.39 62.62 51.71 1,854.40 701.17 806.421,816.83 6,036,386.15 542,934.10 0.60 1,068.61 3_MWD+IFR2+MS+Sag (2) 2,385.05 64.20 51.64 1,882.89 736.47 851.081,845.32 6,036,421.70 542,978.55 2.48 1,125.49 3_MWD+IFR2+MS+Sag (2) 2,449.06 64.74 51.24 1,910.48 772.47 896.251,872.91 6,036,457.96 543,023.50 1.01 1,183.20 3_MWD+IFR2+MS+Sag (2) 2,512.63 65.07 50.86 1,937.44 808.66 941.021,899.87 6,036,494.40 543,068.06 0.75 1,240.75 3_MWD+IFR2+MS+Sag (2) 2,576.31 64.07 51.36 1,964.79 844.77 985.781,927.22 6,036,530.75 543,112.62 1.72 1,298.23 3_MWD+IFR2+MS+Sag (2) 2,639.83 66.04 51.84 1,991.57 880.54 1,030.921,954.00 6,036,566.78 543,157.54 3.18 1,355.77 3_MWD+IFR2+MS+Sag (2) 2,703.43 68.05 51.07 2,016.38 917.03 1,076.711,978.81 6,036,603.53 543,203.13 3.35 1,414.29 3_MWD+IFR2+MS+Sag (2) 2,767.17 66.51 51.30 2,040.99 953.89 1,122.522,003.42 6,036,640.63 543,248.73 2.44 1,473.04 3_MWD+IFR2+MS+Sag (2) 2,830.47 65.89 50.99 2,066.54 990.22 1,167.632,028.97 6,036,677.22 543,293.62 1.08 1,530.93 3_MWD+IFR2+MS+Sag (2) 2,893.45 66.57 50.32 2,091.92 1,026.76 1,212.202,054.35 6,036,714.01 543,337.98 1.45 1,588.55 3_MWD+IFR2+MS+Sag (2) 2,957.36 66.04 50.16 2,117.61 1,064.19 1,257.192,080.04 6,036,751.69 543,382.75 0.86 1,647.06 3_MWD+IFR2+MS+Sag (2) 3,020.97 66.10 49.66 2,143.41 1,101.63 1,301.672,105.84 6,036,789.38 543,427.01 0.72 1,705.20 3_MWD+IFR2+MS+Sag (2) 3,084.01 67.99 48.55 2,167.99 1,139.64 1,345.542,130.42 6,036,827.63 543,470.66 3.41 1,763.24 3_MWD+IFR2+MS+Sag (2) 3,148.04 68.31 48.35 2,191.83 1,179.05 1,390.022,154.26 6,036,867.29 543,514.91 0.58 1,822.67 3_MWD+IFR2+MS+Sag (2) 3,211.96 66.79 48.42 2,216.23 1,218.29 1,434.182,178.66 6,036,906.77 543,558.85 2.38 1,881.74 3_MWD+IFR2+MS+Sag (2) 12/2/2019 3:47:16PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt F Pad Halliburton Definitive Survey Report Well: Wellbore: MPU F-116 MPU F-116 Survey Calculation Method:Minimum Curvature MPU F-116 Actual RKB @ 37.57usft Design:MPU F-116 Database:NORTH US + CANADA MD Reference:MPU F-116 Actual RKB @ 37.57usft North Reference: Well MPU F-116 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 3,275.33 64.53 48.36 2,242.35 1,256.63 1,477.352,204.78 6,036,945.35 543,601.79 3.57 1,939.46 3_MWD+IFR2+MS+Sag (2) 3,338.29 62.89 47.93 2,270.24 1,294.29 1,519.392,232.67 6,036,983.25 543,643.62 2.68 1,995.90 3_MWD+IFR2+MS+Sag (2) 3,402.47 65.50 47.74 2,298.17 1,333.07 1,562.212,260.60 6,037,022.27 543,686.22 4.08 2,053.66 3_MWD+IFR2+MS+Sag (2) 3,466.45 65.69 48.26 2,324.61 1,372.06 1,605.512,287.04 6,037,061.50 543,729.29 0.80 2,111.90 3_MWD+IFR2+MS+Sag (2) 3,529.99 65.08 48.67 2,351.07 1,410.36 1,648.752,313.50 6,037,100.04 543,772.31 1.13 2,169.66 3_MWD+IFR2+MS+Sag (2) 3,593.41 64.48 48.47 2,378.10 1,448.32 1,691.772,340.53 6,037,138.24 543,815.10 0.99 2,227.03 3_MWD+IFR2+MS+Sag (2) 3,656.83 64.94 49.43 2,405.19 1,485.98 1,735.012,367.62 6,037,176.14 543,858.13 1.55 2,284.37 3_MWD+IFR2+MS+Sag (2) 3,720.43 65.61 50.15 2,431.79 1,523.27 1,779.132,394.22 6,037,213.68 543,902.03 1.47 2,342.14 3_MWD+IFR2+MS+Sag (2) 3,783.75 65.01 50.41 2,458.24 1,560.04 1,823.382,420.67 6,037,250.69 543,946.07 1.02 2,399.66 3_MWD+IFR2+MS+Sag (2) 3,846.58 64.55 50.55 2,485.01 1,596.21 1,867.232,447.44 6,037,287.11 543,989.70 0.76 2,456.49 3_MWD+IFR2+MS+Sag (2) 3,910.41 64.21 50.68 2,512.61 1,632.73 1,911.712,475.04 6,037,323.88 544,033.97 0.56 2,514.03 3_MWD+IFR2+MS+Sag (2) 3,974.36 63.50 50.93 2,540.79 1,669.01 1,956.202,503.22 6,037,360.40 544,078.25 1.16 2,571.41 3_MWD+IFR2+MS+Sag (2) 4,037.87 63.93 51.15 2,568.91 1,704.81 2,000.482,531.34 6,037,396.45 544,122.32 0.74 2,628.33 3_MWD+IFR2+MS+Sag (2) 4,101.66 64.46 51.05 2,596.68 1,740.88 2,045.172,559.11 6,037,432.77 544,166.81 0.84 2,685.73 3_MWD+IFR2+MS+Sag (2) 4,165.24 64.33 51.44 2,624.16 1,776.77 2,089.892,586.59 6,037,468.91 544,211.31 0.59 2,743.03 3_MWD+IFR2+MS+Sag (2) 4,227.86 64.60 51.72 2,651.15 1,811.88 2,134.152,613.58 6,037,504.27 544,255.38 0.59 2,799.49 3_MWD+IFR2+MS+Sag (2) 4,291.68 63.92 52.33 2,678.87 1,847.25 2,179.472,641.30 6,037,539.89 544,300.48 1.37 2,856.91 3_MWD+IFR2+MS+Sag (2) 4,355.57 63.90 52.20 2,706.97 1,882.37 2,224.852,669.40 6,037,575.26 544,345.66 0.19 2,914.21 3_MWD+IFR2+MS+Sag (2) 4,419.47 64.43 51.61 2,734.81 1,917.85 2,270.112,697.24 6,037,611.00 544,390.71 1.17 2,971.66 3_MWD+IFR2+MS+Sag (2) 4,482.98 64.92 50.04 2,761.98 1,954.12 2,314.612,724.41 6,037,647.51 544,435.00 2.36 3,029.04 3_MWD+IFR2+MS+Sag (2) 4,546.84 64.95 50.37 2,789.04 1,991.14 2,359.052,751.47 6,037,684.78 544,479.23 0.47 3,086.88 3_MWD+IFR2+MS+Sag (2) 4,610.24 64.21 50.50 2,816.25 2,027.61 2,403.202,778.68 6,037,721.50 544,523.16 1.18 3,144.13 3_MWD+IFR2+MS+Sag (2) 4,673.33 64.43 50.07 2,843.59 2,063.95 2,446.932,806.02 6,037,758.08 544,566.69 0.71 3,200.98 3_MWD+IFR2+MS+Sag (2) 4,736.85 63.31 49.98 2,871.56 2,100.58 2,490.642,833.99 6,037,794.96 544,610.18 1.77 3,258.00 3_MWD+IFR2+MS+Sag (2) 4,800.38 62.04 50.82 2,900.73 2,136.56 2,534.122,863.16 6,037,831.18 544,653.46 2.32 3,314.43 3_MWD+IFR2+MS+Sag (2) 4,864.09 63.50 50.18 2,929.88 2,172.59 2,577.832,892.31 6,037,867.46 544,696.96 2.46 3,371.06 3_MWD+IFR2+MS+Sag (2) 4,928.51 64.54 50.51 2,958.10 2,209.55 2,622.422,920.53 6,037,904.66 544,741.33 1.68 3,428.96 3_MWD+IFR2+MS+Sag (2) 4,991.84 63.91 50.84 2,985.64 2,245.69 2,666.532,948.07 6,037,941.05 544,785.23 1.10 3,485.97 3_MWD+IFR2+MS+Sag (2) 5,055.27 64.61 50.21 3,013.18 2,282.01 2,710.632,975.61 6,037,977.62 544,829.12 1.42 3,543.09 3_MWD+IFR2+MS+Sag (2) 5,119.20 66.42 49.25 3,039.68 2,319.62 2,755.023,002.11 6,038,015.47 544,873.29 3.14 3,601.27 3_MWD+IFR2+MS+Sag (2) 5,182.67 66.77 49.13 3,064.89 2,357.69 2,799.113,027.32 6,038,053.78 544,917.16 0.58 3,659.52 3_MWD+IFR2+MS+Sag (2) 5,246.52 66.09 48.85 3,090.42 2,396.09 2,843.273,052.85 6,038,092.43 544,961.10 1.14 3,718.04 3_MWD+IFR2+MS+Sag (2) 5,309.95 64.62 48.58 3,116.87 2,434.13 2,886.593,079.30 6,038,130.71 545,004.20 2.35 3,775.69 3_MWD+IFR2+MS+Sag (2) 5,373.43 63.72 48.88 3,144.53 2,471.82 2,929.533,106.96 6,038,168.64 545,046.92 1.48 3,832.82 3_MWD+IFR2+MS+Sag (2) 5,437.27 64.01 48.95 3,172.65 2,509.48 2,972.733,135.08 6,038,206.54 545,089.90 0.46 3,890.13 3_MWD+IFR2+MS+Sag (2) 5,500.59 64.25 48.89 3,200.28 2,546.92 3,015.683,162.71 6,038,244.22 545,132.63 0.39 3,947.11 3_MWD+IFR2+MS+Sag (2) 5,564.86 64.48 49.06 3,228.08 2,584.95 3,059.393,190.51 6,038,282.50 545,176.13 0.43 4,005.05 3_MWD+IFR2+MS+Sag (2) 5,628.34 65.34 49.34 3,255.00 2,622.52 3,102.913,217.43 6,038,320.31 545,219.43 1.41 4,062.54 3_MWD+IFR2+MS+Sag (2) 5,692.31 64.82 49.41 3,281.95 2,660.29 3,146.953,244.38 6,038,358.33 545,263.24 0.82 4,120.55 3_MWD+IFR2+MS+Sag (2) 5,755.86 63.65 50.02 3,309.58 2,697.30 3,190.603,272.01 6,038,395.57 545,306.68 2.03 4,177.78 3_MWD+IFR2+MS+Sag (2) 12/2/2019 3:47:16PM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt F Pad Halliburton Definitive Survey Report Well: Wellbore: MPU F-116 MPU F-116 Survey Calculation Method:Minimum Curvature MPU F-116 Actual RKB @ 37.57usft Design:MPU F-116 Database:NORTH US + CANADA MD Reference:MPU F-116 Actual RKB @ 37.57usft North Reference: Well MPU F-116 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 5,819.31 64.35 49.83 3,337.39 2,734.01 3,234.243,299.82 6,038,432.53 545,350.11 1.14 4,234.81 3_MWD+IFR2+MS+Sag (2) 5,883.27 63.72 49.90 3,365.40 2,771.08 3,278.203,327.83 6,038,469.84 545,393.85 0.99 4,292.31 3_MWD+IFR2+MS+Sag (2) 5,946.93 63.66 50.21 3,393.61 2,807.72 3,321.953,356.04 6,038,506.73 545,437.39 0.45 4,349.37 3_MWD+IFR2+MS+Sag (2) 6,010.70 63.36 50.08 3,422.06 2,844.29 3,365.773,384.49 6,038,543.55 545,480.99 0.50 4,406.44 3_MWD+IFR2+MS+Sag (2) 6,074.16 63.71 50.17 3,450.34 2,880.71 3,409.373,412.77 6,038,580.21 545,524.38 0.57 4,463.24 3_MWD+IFR2+MS+Sag (2) 6,137.95 64.73 50.18 3,478.08 2,917.50 3,453.483,440.51 6,038,617.24 545,568.28 1.60 4,520.67 3_MWD+IFR2+MS+Sag (2) 6,201.28 64.53 50.18 3,505.21 2,954.15 3,497.433,467.64 6,038,654.13 545,612.02 0.32 4,577.89 3_MWD+IFR2+MS+Sag (2) 6,264.55 63.37 51.19 3,533.00 2,990.16 3,541.413,495.43 6,038,690.39 545,655.78 2.33 4,634.71 3_MWD+IFR2+MS+Sag (2) 6,328.53 63.85 51.43 3,561.44 3,025.99 3,586.143,523.87 6,038,726.47 545,700.31 0.82 4,691.99 3_MWD+IFR2+MS+Sag (2) 6,391.92 65.30 51.30 3,588.65 3,061.73 3,630.863,551.08 6,038,762.46 545,744.82 2.29 4,749.20 3_MWD+IFR2+MS+Sag (2) 6,456.22 65.40 51.08 3,615.47 3,098.36 3,676.403,577.90 6,038,799.34 545,790.15 0.35 4,807.60 3_MWD+IFR2+MS+Sag (2) 6,519.68 64.20 49.70 3,642.49 3,134.96 3,720.633,604.92 6,038,836.20 545,834.17 2.73 4,865.01 3_MWD+IFR2+MS+Sag (2) 6,582.56 64.61 49.32 3,669.66 3,171.79 3,763.763,632.09 6,038,873.26 545,877.09 0.85 4,921.72 3_MWD+IFR2+MS+Sag (2) 6,646.08 64.88 49.20 3,696.76 3,209.28 3,807.293,659.19 6,038,910.99 545,920.40 0.46 4,979.17 3_MWD+IFR2+MS+Sag (2) 6,709.54 64.75 48.85 3,723.76 3,246.93 3,850.653,686.19 6,038,948.89 545,963.53 0.54 5,036.59 3_MWD+IFR2+MS+Sag (2) 6,773.44 65.15 49.98 3,750.82 3,284.59 3,894.613,713.25 6,038,986.80 546,007.28 1.72 5,094.48 3_MWD+IFR2+MS+Sag (2) 6,837.36 65.36 51.74 3,777.57 3,321.23 3,939.633,740.00 6,039,023.69 546,052.09 2.52 5,152.51 3_MWD+IFR2+MS+Sag (2) 6,900.91 65.48 51.95 3,804.01 3,356.94 3,985.083,766.44 6,039,059.64 546,097.32 0.35 5,210.24 3_MWD+IFR2+MS+Sag (2) 6,964.52 65.37 52.13 3,830.46 3,392.52 4,030.693,792.89 6,039,095.48 546,142.73 0.31 5,268.02 3_MWD+IFR2+MS+Sag (2) 7,028.14 65.28 51.80 3,857.02 3,428.14 4,076.223,819.45 6,039,131.36 546,188.05 0.49 5,325.76 3_MWD+IFR2+MS+Sag (2) 7,092.05 66.04 51.38 3,883.36 3,464.32 4,121.853,845.79 6,039,167.79 546,233.47 1.33 5,383.95 3_MWD+IFR2+MS+Sag (2) 7,155.64 65.84 51.58 3,909.29 3,500.48 4,167.283,871.72 6,039,204.20 546,278.69 0.43 5,441.97 3_MWD+IFR2+MS+Sag (2) 7,219.58 64.60 52.58 3,936.09 3,536.16 4,213.073,898.52 6,039,240.14 546,324.27 2.40 5,499.95 3_MWD+IFR2+MS+Sag (2) 7,283.38 63.17 53.06 3,964.17 3,570.78 4,258.713,926.60 6,039,275.01 546,369.71 2.34 5,557.12 3_MWD+IFR2+MS+Sag (2) 7,346.45 61.98 53.54 3,993.22 3,604.23 4,303.593,955.65 6,039,308.72 546,414.40 2.00 5,612.96 3_MWD+IFR2+MS+Sag (2) 7,410.32 63.84 53.80 4,022.30 3,637.92 4,349.403,984.73 6,039,342.66 546,460.01 2.93 5,669.66 3_MWD+IFR2+MS+Sag (2) 7,473.89 65.96 52.79 4,049.27 3,672.33 4,395.554,011.70 6,039,377.33 546,505.96 3.63 5,727.08 3_MWD+IFR2+MS+Sag (2) 7,537.31 66.69 52.37 4,074.74 3,707.62 4,441.684,037.17 6,039,412.88 546,551.88 1.30 5,785.06 3_MWD+IFR2+MS+Sag (2) 7,600.81 66.29 51.62 4,100.07 3,743.47 4,487.564,062.50 6,039,448.99 546,597.56 1.25 5,843.22 3_MWD+IFR2+MS+Sag (2) 7,664.85 65.49 49.92 4,126.23 3,780.44 4,532.844,088.66 6,039,486.20 546,642.62 2.73 5,901.65 3_MWD+IFR2+MS+Sag (2) 7,728.62 64.82 50.02 4,153.02 3,817.66 4,577.154,115.45 6,039,523.67 546,686.71 1.06 5,959.52 3_MWD+IFR2+MS+Sag (2) 7,791.91 64.59 49.61 4,180.06 3,854.58 4,620.864,142.49 6,039,560.84 546,730.21 0.69 6,016.73 3_MWD+IFR2+MS+Sag (2) 7,855.89 64.68 49.15 4,207.47 3,892.22 4,664.744,169.90 6,039,598.72 546,773.88 0.66 6,074.55 3_MWD+IFR2+MS+Sag (2) 7,919.08 64.27 47.17 4,234.70 3,930.25 4,707.224,197.13 6,039,636.99 546,816.14 2.90 6,131.55 3_MWD+IFR2+MS+Sag (2) 7,983.16 63.84 47.60 4,262.74 3,969.26 4,749.634,225.17 6,039,676.24 546,858.32 0.90 6,189.14 3_MWD+IFR2+MS+Sag (2) 8,046.96 64.32 47.91 4,290.63 4,007.84 4,792.114,253.06 6,039,715.05 546,900.57 0.87 6,246.51 3_MWD+IFR2+MS+Sag (2) 8,110.63 65.36 48.86 4,317.70 4,046.11 4,835.194,280.13 6,039,753.56 546,943.43 2.12 6,304.13 3_MWD+IFR2+MS+Sag (2) 8,174.24 65.70 48.54 4,344.04 4,084.32 4,878.694,306.47 6,039,792.02 546,986.71 0.70 6,362.02 3_MWD+IFR2+MS+Sag (2) 8,237.75 65.90 47.91 4,370.08 4,122.92 4,921.894,332.51 6,039,830.85 547,029.68 0.96 6,419.94 3_MWD+IFR2+MS+Sag (2) 8,301.92 64.06 47.75 4,397.22 4,161.95 4,964.984,359.65 6,039,870.12 547,072.55 2.88 6,478.07 3_MWD+IFR2+MS+Sag (2) 12/2/2019 3:47:16PM COMPASS 5000.15 Build 91E Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt F Pad Halliburton Definitive Survey Report Well: Wellbore: MPU F-116 MPU F-116 Survey Calculation Method:Minimum Curvature MPU F-116 Actual RKB @ 37.57usft Design:MPU F-116 Database:NORTH US + CANADA MD Reference:MPU F-116 Actual RKB @ 37.57usft North Reference: Well MPU F-116 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 8,365.43 63.50 47.80 4,425.28 4,200.24 5,007.174,387.71 6,039,908.65 547,114.52 0.88 6,535.02 3_MWD+IFR2+MS+Sag (2) 8,429.03 62.76 48.19 4,454.02 4,238.21 5,049.334,416.45 6,039,946.85 547,156.46 1.29 6,591.74 3_MWD+IFR2+MS+Sag (2) 8,492.44 63.57 47.80 4,482.65 4,276.07 5,091.374,445.08 6,039,984.95 547,198.28 1.39 6,648.31 3_MWD+IFR2+MS+Sag (2) 8,556.27 65.02 47.90 4,510.33 4,314.67 5,134.014,472.76 6,040,023.78 547,240.70 2.28 6,705.80 3_MWD+IFR2+MS+Sag (2) 8,617.47 64.53 47.93 4,536.41 4,351.77 5,175.104,498.84 6,040,061.11 547,281.57 0.80 6,761.15 3_MWD+IFR2+MS+Sag (2) 8,683.04 63.90 47.35 4,564.94 4,391.55 5,218.734,527.37 6,040,101.14 547,324.97 1.25 6,820.17 3_MWD+IFR2+MS+Sag (2) 8,746.46 63.38 47.32 4,593.09 4,430.06 5,260.514,555.52 6,040,139.88 547,366.53 0.82 6,876.96 3_MWD+IFR2+MS+Sag (2) 8,810.91 63.02 47.27 4,622.15 4,469.08 5,302.794,584.58 6,040,179.13 547,408.58 0.56 6,934.46 3_MWD+IFR2+MS+Sag (2) 8,874.55 64.34 47.07 4,650.37 4,507.86 5,344.624,612.80 6,040,218.14 547,450.19 2.09 6,991.46 3_MWD+IFR2+MS+Sag (2) 8,937.89 66.11 47.20 4,676.91 4,546.98 5,386.774,639.34 6,040,257.50 547,492.11 2.80 7,048.93 3_MWD+IFR2+MS+Sag (2) 9,000.50 66.37 47.57 4,702.14 4,585.78 5,428.944,664.57 6,040,296.53 547,534.06 0.68 7,106.20 3_MWD+IFR2+MS+Sag (2) 9,068.26 66.57 47.52 4,729.19 4,627.71 5,474.784,691.62 6,040,338.72 547,579.65 0.30 7,168.30 3_MWD+IFR2+MS+Sag (3) 9,132.06 65.76 47.34 4,754.97 4,667.19 5,517.764,717.40 6,040,378.44 547,622.40 1.30 7,226.63 3_MWD+IFR2+MS+Sag (3) 9,195.80 64.65 47.65 4,781.70 4,706.29 5,560.424,744.13 6,040,417.77 547,664.83 1.80 7,284.46 3_MWD+IFR2+MS+Sag (3) 9,259.66 63.69 48.06 4,809.53 4,744.86 5,603.034,771.96 6,040,456.58 547,707.22 1.61 7,341.92 3_MWD+IFR2+MS+Sag (3) 9,323.18 62.81 48.70 4,838.12 4,782.53 5,645.434,800.55 6,040,494.49 547,749.41 1.65 7,398.64 3_MWD+IFR2+MS+Sag (3) 9,387.01 62.27 49.36 4,867.55 4,819.67 5,688.204,829.98 6,040,531.87 547,791.96 1.25 7,455.27 3_MWD+IFR2+MS+Sag (3) 9,450.49 62.89 49.93 4,896.78 4,856.15 5,731.144,859.21 6,040,568.59 547,834.68 1.26 7,511.62 3_MWD+IFR2+MS+Sag (3) 9,514.35 63.03 50.69 4,925.82 4,892.48 5,774.914,888.25 6,040,605.16 547,878.24 1.08 7,568.49 3_MWD+IFR2+MS+Sag (3) 9,577.33 62.97 50.39 4,954.41 4,928.14 5,818.234,916.84 6,040,641.07 547,921.36 0.43 7,624.59 3_MWD+IFR2+MS+Sag (3) 9,641.84 62.87 50.64 4,983.77 4,964.66 5,862.564,946.20 6,040,677.84 547,965.48 0.38 7,682.02 3_MWD+IFR2+MS+Sag (3) 9,705.77 62.72 49.87 5,013.00 5,001.02 5,906.284,975.43 6,040,714.43 548,008.98 1.10 7,738.86 3_MWD+IFR2+MS+Sag (3) 9,769.42 63.03 48.86 5,042.02 5,037.91 5,949.275,004.45 6,040,751.56 548,051.76 1.49 7,795.51 3_MWD+IFR2+MS+Sag (3) 9,833.22 63.03 48.56 5,070.96 5,075.43 5,991.995,033.39 6,040,789.32 548,094.27 0.42 7,852.37 3_MWD+IFR2+MS+Sag (3) 9,895.56 62.93 48.99 5,099.28 5,112.03 6,033.765,061.71 6,040,826.15 548,135.82 0.64 7,907.90 3_MWD+IFR2+MS+Sag (3) 9,959.21 62.83 49.50 5,128.29 5,149.01 6,076.685,090.72 6,040,863.38 548,178.52 0.73 7,964.56 3_MWD+IFR2+MS+Sag (3) 10,023.08 63.71 50.13 5,157.02 5,185.82 6,120.265,119.45 6,040,900.43 548,221.89 1.64 8,021.60 3_MWD+IFR2+MS+Sag (3) 10,086.37 63.92 50.23 5,184.95 5,222.19 6,163.885,147.38 6,040,937.04 548,265.30 0.36 8,078.39 3_MWD+IFR2+MS+Sag (3) 10,150.00 64.20 49.54 5,212.78 5,259.06 6,207.645,175.21 6,040,974.15 548,308.84 1.07 8,135.60 3_MWD+IFR2+MS+Sag (3) 10,214.06 63.89 49.41 5,240.82 5,296.48 6,251.425,203.25 6,041,011.82 548,352.41 0.52 8,193.20 3_MWD+IFR2+MS+Sag (3) 10,278.24 64.26 49.74 5,268.88 5,333.91 6,295.365,231.31 6,041,049.50 548,396.13 0.74 8,250.92 3_MWD+IFR2+MS+Sag (3) 10,340.97 63.98 49.24 5,296.26 5,370.57 6,338.275,258.69 6,041,086.40 548,438.83 0.84 8,307.36 3_MWD+IFR2+MS+Sag (3) 10,404.88 64.26 48.82 5,324.16 5,408.27 6,381.685,286.59 6,041,124.34 548,482.03 0.74 8,364.86 3_MWD+IFR2+MS+Sag (3) 10,468.50 63.99 48.53 5,351.92 5,446.07 6,424.675,314.35 6,041,162.38 548,524.79 0.59 8,422.10 3_MWD+IFR2+MS+Sag (3) 10,531.83 64.19 48.05 5,379.59 5,483.97 6,467.205,342.02 6,041,200.52 548,567.10 0.75 8,479.05 3_MWD+IFR2+MS+Sag (3) 10,595.53 64.05 47.82 5,407.40 5,522.37 6,509.745,369.83 6,041,239.15 548,609.42 0.39 8,536.35 3_MWD+IFR2+MS+Sag (3) 10,658.89 64.14 47.94 5,435.08 5,560.60 6,552.025,397.51 6,041,277.61 548,651.48 0.22 8,593.32 3_MWD+IFR2+MS+Sag (3) 10,722.73 64.21 48.13 5,462.89 5,599.02 6,594.755,425.32 6,041,316.27 548,693.98 0.29 8,650.78 3_MWD+IFR2+MS+Sag (3) 10,786.08 63.91 48.24 5,490.60 5,637.00 6,637.205,453.03 6,041,354.49 548,736.22 0.50 8,707.73 3_MWD+IFR2+MS+Sag (3) 10,849.96 64.12 48.53 5,518.59 5,675.14 6,680.135,481.02 6,041,392.87 548,778.93 0.52 8,765.15 3_MWD+IFR2+MS+Sag (3) 12/2/2019 3:47:16PM COMPASS 5000.15 Build 91E Page 6 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt F Pad Halliburton Definitive Survey Report Well: Wellbore: MPU F-116 MPU F-116 Survey Calculation Method:Minimum Curvature MPU F-116 Actual RKB @ 37.57usft Design:MPU F-116 Database:NORTH US + CANADA MD Reference:MPU F-116 Actual RKB @ 37.57usft North Reference: Well MPU F-116 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 10,913.74 63.92 48.81 5,546.53 5,713.00 6,723.195,508.96 6,041,430.97 548,821.76 0.50 8,822.48 3_MWD+IFR2+MS+Sag (3) 10,976.86 64.11 48.45 5,574.18 5,750.50 6,765.775,536.61 6,041,468.71 548,864.12 0.59 8,879.22 3_MWD+IFR2+MS+Sag (3) 11,041.14 64.06 47.89 5,602.28 5,789.06 6,808.855,564.71 6,041,507.51 548,906.98 0.79 8,937.02 3_MWD+IFR2+MS+Sag (3) 11,104.92 64.11 47.79 5,630.15 5,827.57 6,851.375,592.58 6,041,546.25 548,949.28 0.16 8,994.37 3_MWD+IFR2+MS+Sag (3) 11,168.83 64.28 48.67 5,657.97 5,865.89 6,894.285,620.40 6,041,584.81 548,991.97 1.27 9,051.90 3_MWD+IFR2+MS+Sag (3) 11,231.87 64.32 48.96 5,685.31 5,903.30 6,937.035,647.74 6,041,622.46 549,034.50 0.42 9,108.70 3_MWD+IFR2+MS+Sag (3) 11,295.80 64.32 48.85 5,713.01 5,941.17 6,980.455,675.44 6,041,660.57 549,077.70 0.16 9,166.31 3_MWD+IFR2+MS+Sag (3) 11,360.41 64.32 48.35 5,741.01 5,979.68 7,024.135,703.44 6,041,699.32 549,121.16 0.70 9,224.54 3_MWD+IFR2+MS+Sag (3) 11,423.32 64.46 48.32 5,768.20 6,017.39 7,066.515,730.63 6,041,737.27 549,163.32 0.23 9,281.26 3_MWD+IFR2+MS+Sag (3) 11,487.54 64.46 49.16 5,795.89 6,055.60 7,110.075,758.32 6,041,775.72 549,206.66 1.18 9,339.20 3_MWD+IFR2+MS+Sag (3) 11,550.69 64.60 48.85 5,823.05 6,093.00 7,153.105,785.48 6,041,813.36 549,249.47 0.50 9,396.21 3_MWD+IFR2+MS+Sag (3) 11,614.85 63.51 48.23 5,851.12 6,131.20 7,196.345,813.55 6,041,851.80 549,292.49 1.91 9,453.90 3_MWD+IFR2+MS+Sag (3) 11,678.22 61.63 47.82 5,880.31 6,168.81 7,238.155,842.74 6,041,889.65 549,334.08 3.02 9,510.13 3_MWD+IFR2+MS+Sag (3) 11,742.37 58.63 48.17 5,912.26 6,206.04 7,279.485,874.69 6,041,927.10 549,375.20 4.70 9,565.74 3_MWD+IFR2+MS+Sag (3) 11,805.11 55.93 48.27 5,946.17 6,241.20 7,318.845,908.60 6,041,962.49 549,414.35 4.31 9,618.51 3_MWD+IFR2+MS+Sag (3) 11,868.24 53.33 48.07 5,982.71 6,275.53 7,357.195,945.14 6,041,997.03 549,452.51 4.13 9,669.97 3_MWD+IFR2+MS+Sag (3) 11,932.79 51.02 48.01 6,022.29 6,309.62 7,395.115,984.72 6,042,031.33 549,490.22 3.58 9,720.95 3_MWD+IFR2+MS+Sag (3) 11,996.63 48.42 47.91 6,063.56 6,342.23 7,431.286,025.99 6,042,064.14 549,526.20 4.07 9,769.63 3_MWD+IFR2+MS+Sag (3) 12,060.15 46.31 48.13 6,106.58 6,373.48 7,466.016,069.01 6,042,095.59 549,560.75 3.33 9,816.35 3_MWD+IFR2+MS+Sag (3) 12,124.25 44.14 48.20 6,151.73 6,403.83 7,499.916,114.16 6,042,126.13 549,594.48 3.39 9,861.84 3_MWD+IFR2+MS+Sag (3) 12,187.97 41.24 48.44 6,198.56 6,432.56 7,532.176,160.99 6,042,155.03 549,626.57 4.56 9,905.04 3_MWD+IFR2+MS+Sag (3) 12,251.44 38.37 49.07 6,247.31 6,459.35 7,562.726,209.74 6,042,181.99 549,656.96 4.57 9,945.66 3_MWD+IFR2+MS+Sag (3) 12,315.41 36.12 48.94 6,298.23 6,484.75 7,591.946,260.66 6,042,207.55 549,686.04 3.52 9,984.37 3_MWD+IFR2+MS+Sag (3) 12,378.43 33.61 47.79 6,349.94 6,508.67 7,618.876,312.37 6,042,231.63 549,712.83 4.12 10,020.39 3_MWD+IFR2+MS+Sag (3) 12,442.38 30.30 45.89 6,404.19 6,531.80 7,643.576,366.62 6,042,254.89 549,737.39 5.41 10,054.20 3_MWD+IFR2+MS+Sag (3) 12,506.25 28.05 45.00 6,459.95 6,553.63 7,665.766,422.38 6,042,276.85 549,759.46 3.59 10,085.26 3_MWD+IFR2+MS+Sag (3) 12,569.21 25.56 45.75 6,516.14 6,573.58 7,685.966,478.57 6,042,296.91 549,779.54 3.99 10,113.59 3_MWD+IFR2+MS+Sag (3) 12,632.82 23.24 46.67 6,574.07 6,591.77 7,704.926,536.50 6,042,315.20 549,798.40 3.70 10,139.82 3_MWD+IFR2+MS+Sag (3) 12,696.64 21.33 47.17 6,633.12 6,608.30 7,722.596,595.55 6,042,331.84 549,815.97 3.01 10,164.00 3_MWD+IFR2+MS+Sag (3) 12,760.02 20.25 46.19 6,692.37 6,623.73 7,738.966,654.80 6,042,347.36 549,832.25 1.79 10,186.48 3_MWD+IFR2+MS+Sag (3) 12,823.72 20.30 44.25 6,752.13 6,639.28 7,754.636,714.56 6,042,362.99 549,847.83 1.06 10,208.49 3_MWD+IFR2+MS+Sag (3) 12,887.69 20.06 42.95 6,812.17 6,655.26 7,769.846,774.60 6,042,379.05 549,862.95 0.80 10,230.45 3_MWD+IFR2+MS+Sag (3) 12,951.31 20.36 45.58 6,871.87 6,670.99 7,785.186,834.30 6,042,394.87 549,878.20 1.50 10,252.34 3_MWD+IFR2+MS+Sag (3) 13,014.68 20.21 47.92 6,931.31 6,686.04 7,801.186,893.74 6,042,410.01 549,894.11 1.30 10,274.29 3_MWD+IFR2+MS+Sag (3) 13,108.14 19.72 49.28 7,019.16 6,707.15 7,825.116,981.59 6,042,431.25 549,917.92 0.72 10,306.19 3_MWD+IFR2+MS+Sag (4) 13,172.29 18.72 47.44 7,079.73 6,721.17 7,840.907,042.16 6,042,445.36 549,933.63 1.82 10,327.31 3_MWD+IFR2+MS+Sag (4) 13,235.41 19.66 42.85 7,139.35 6,735.81 7,855.587,101.78 6,042,460.08 549,948.23 2.82 10,347.98 3_MWD+IFR2+MS+Sag (4) 13,298.34 19.98 44.65 7,198.55 6,751.22 7,870.347,160.98 6,042,475.57 549,962.89 1.10 10,369.22 3_MWD+IFR2+MS+Sag (4) 13,361.18 20.12 46.83 7,257.58 6,766.25 7,885.777,220.01 6,042,490.69 549,978.23 1.21 10,390.72 3_MWD+IFR2+MS+Sag (4) 13,424.23 20.20 47.23 7,316.77 6,781.06 7,901.677,279.20 6,042,505.59 549,994.05 0.25 10,412.43 3_MWD+IFR2+MS+Sag (4) 12/2/2019 3:47:16PM COMPASS 5000.15 Build 91E Page 7 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt F Pad Halliburton Definitive Survey Report Well: Wellbore: MPU F-116 MPU F-116 Survey Calculation Method:Minimum Curvature MPU F-116 Actual RKB @ 37.57usft Design:MPU F-116 Database:NORTH US + CANADA MD Reference:MPU F-116 Actual RKB @ 37.57usft North Reference: Well MPU F-116 True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 13,487.74 20.07 46.75 7,376.40 6,795.97 7,917.657,338.83 6,042,520.59 550,009.95 0.33 10,434.28 3_MWD+IFR2+MS+Sag (4) 13,550.31 19.93 45.02 7,435.19 6,810.87 7,933.027,397.62 6,042,535.57 550,025.23 0.97 10,455.64 3_MWD+IFR2+MS+Sag (4) 13,614.04 20.34 44.57 7,495.03 6,826.44 7,948.477,457.46 6,042,551.23 550,040.59 0.69 10,477.51 3_MWD+IFR2+MS+Sag (4) 13,677.07 20.14 44.55 7,554.17 6,841.97 7,963.777,516.60 6,042,566.85 550,055.80 0.32 10,499.24 3_MWD+IFR2+MS+Sag (4) 13,739.69 20.11 44.46 7,612.96 6,857.34 7,978.887,575.39 6,042,582.30 550,070.82 0.07 10,520.71 3_MWD+IFR2+MS+Sag (4) 13,761.90 19.93 45.29 7,633.83 6,862.73 7,984.247,596.26 6,042,587.72 550,076.15 1.51 10,528.29 3_MWD+IFR2+MS+Sag (4) 13,785.00 19.93 45.29 7,655.55 6,868.27 7,989.847,617.98 6,042,593.29 550,081.71 0.00 10,536.15 PROJECTED to TD Approved By:Checked By:Date: 12/2/2019 3:47:16PM COMPASS 5000.15 Build 91E Page 8 Chelsea Wright Digitally signed by Chelsea Wright Date: 2019.12.02 14:20:34 -09'00' Benjamin Hand Digitally signed by Benjamin Hand Date: 2019.12.02 14:19:32 -09'00' TD Shoe Depth: PBTD: Jts. 2 1 158 69 Yes X No Yes X No 40 Fluid Description: Liner hanger Info (Make/Model):Liner top Packer?: Yes No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type:Density (ppg)Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type:Density (ppg)Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Casing (Or Liner) Detail Shoe Cut Joint 9 5/8 40.0 L-80 SECOND STAGERig 4:31 Returns 470 425 536 866 304 462 Spud Mud Shoe @ 9055 FC @ Top of Liner CASING RECORD County North Slope Bourough State AK Supv.S Barber/ C Montague Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.MP F-116 Date Run 6-Nov-19 Setting Depths Component Size Wt.Grade THD Make Length Bottom Top BTC Downhole Solutions 1.60 9,055.00 9,053.40 9.14 35.46 26.32 22.5 9 5/8 40.0 L-80 TXP BTC Bump Plug? Csg Wt. On Hook:Type Float Collar:Conventional No. Hrs to Run: 8,978.00 Floats Held Rotate Csg Recip Csg 15.8 750 9.5 5 2050 10 10.7 351 5 100 0 RigFIRST STAGE10Tuned Spacer 60 910 #N/A 2,770 2769 15.8 82 Bump press Returns after opening ES Cementer Bump Plug? Yes 682/679.9 1200 304 9,055.009,065.00 CEMENTING REPORT Csg Wt. On Slips:100 Spud Mud 15:24 11/8/2019 4.41 Stage Collar @ 60 Bump press 100 3 9.4 5 190.4/190.4 4.3208.4 56.2 Perm L Type Class G 270 Tuned spacer 447 Type of Shoe:Bullnose Casing Crew:Weatherford 12 377 Ft. Min.PPG9.5 www.wellez.net WellEz Information Management LLC ver_04818br 4 208.4Water 3.6 Water ES Cementer Closure OK 2 on jnt 1. 1 every joint 9055' - 8056' (jnt 26) . 1 every other 8056' - 7043' (jnt 52.). 5 before and 10 after ES cementer; 2978' - 2346' (jnts 157-171). 1 every other jnt 2346' - 314'. Casing 9 5/8 40.0 L-80 TXP BTC 72.78 9,053.40 8,979.62 Float Collar 9 5/8 40.0 L-80 BTC Downhole Solutions 1.29 8,979.62 8,978.33 Casing 9 5/8 40.0 L-80 TXP BTC 38.82 8,978.33 8,939.51 Baffle Adapter 9 5/8 40.0 L-80 TXP BTC HES 1.47 8,939.51 8,937.04 Casing 9 5/8 40.0 L-80 TXP BTC 6,156.68 8,937.04 2,781.36 2.87 Pup Joint 9 5/8 40.0 L-80 TXP BTC 2,769.41 9.08 2,781.36 2,772.28 ES Cementer 9 5/8 40.0 L-80 TXP BTC HES 35.46 2,772.28 2,769.41 Pup Joint 9 5/8 40.0 L-80 TXP BTC 26.75 5 2,742.66 Casing 9 5/8 40.0 L-80 TXP BTC 2,707.20 2,742.66 1.17 11/9/2019 27 Spud Mud Type I/II 900 2.35 Class G 400 1.16 304 TD Shoe Depth: PBTD: Jts. 2 323 X Yes No X Yes No 30 Fluid Description: Liner hanger Info (Make/Model): Liner top Packer?: Yes No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg)Rate (bpm):Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: Yes X No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface? Yes X No Spacer returns?Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Expanda Chem 180 1.2 25.28 Hanger 11 3/4 1.20 25.28 24.08 12,969.63 27.73 Pup Jnt 7 26.0 L-80 TXP Tenaris 2.45 27.73 1.35 12,970.98 12,969.63 7" 26# L-80 TXP 7 26.0 L-80 TXP Tenaris 12,941.90 FC 7 2 Ea 10' above and below Shoe Jnt. 2 EA 10' above and below blank jnt. 2 EA 10' above and below FC jnt. 1 EA 10 Jnts above FC Jnt. 3 EA Jnts 99, 100, 101 for 9 5/8" Shoe. 7" 26# L-80 TXP 7 26.0 L-80 TXP Tenaris 80.67 13,051.65 12,970.98 www.wellez.net WellEz Information Management LLC ver_04818br 4 208.34H20 2.3 Type of Shoe:Bullet Casing Crew:Weatherford 13,053.0013,063.00 CEMENTING REPORT Csg Wt. On Slips:110,000 LSND 16:19 11/19/2019 12,250 15.8 38.5 Bump press Calc Bump Plug? 480/478.5 0 RigFIRST STAGE11Tuned Spacer 40 10.2 5 80 640 Csg Wt. On Hook:265,000 Type Float Collar:Standard No. Hrs to Run:29 TXP 2.00 13,053.65 13,051.65 Setting Depths Component Size Wt.Grade THD Make Length Bottom Top Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.MP F-116 Date Run 18-Nov-19 CASING RECORD County North Slope Bourough State AK Supv.S Barber/ O Amend 12,970.00 Floats Held 23.55 38.3 0 35.3 5000 LSND Rotate Csg Recip Csg Ft. Min.PPG10.2 Shoe @ 13056 FC @ Top of Liner 23.55 35.25 Casing (Or Liner) Detail Shoe 7 TD Shoe Depth: PBTD: Jts. 1 2 19 Yes X No X Yes No 33 Fluid Description: Liner hanger Info (Make/Model):Liner top Packer?:X Yes No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs)Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs)Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg)Rate (bpm):Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Standard Primary Cement 102 1.16 27.58 12,927.46 12,899.88Versastim Liner Hanger 5 3/4 TXP BTC Halliburton 13,690.57 Liner 4 1/2 12.6 L-80 TPX BTC Tenaris 763.11 13,690.57 12,927.46 13,733.56 13,692.56 Landing Collar 4 1/2 TPX BTC Halliburton 1.99 13,692.56 1.29 13,734.85 13,733.56 Liner 4 1/2 12.6 L-80 TPX BTC Tenaris 41.00 FC 4 1/2 TPX BTC Davis Lynch L-80 TPX BTC Tenaris 40.45 13,775.30 13,734.85 www.wellez.net WellEz Information Management LLC ver_04818br 3.3 Type of Shoe:Davis Casing Crew:Weatherford Halliburton Versastim 1 Centralizer on every Joint, total 21. 13,777.0013,785.00 CEMENTING REPORT Csg Wt. On Slips:205,000 LSND Liner 4 1/2 12.6 15.8 21 Bump press Surface Bump Plug? 1:30 11/26/2019 12,899 33 11.45 3.5 100 1378FIRST STAGE12Tuned Spacer 60 TPX BTC Davis Lynch 1.70 13,777.00 13,775.30 Csg Wt. On Hook:205,000 Type Float Collar:Davis No. Hrs to Run: Setting Depths Component Size Wt.Grade THD Make Length Bottom Top Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.MP F-116 Date Run 24-Nov-19 CASING RECORD County North Slope Bourough State AK Supv.J Lott/ O Amend 40 21 5 16 3000 LSND 137.5/137.5 2085 5 Halliburton Ft. Min.PPG11.45 Shoe @ 13777 FC @ Top of Liner 12899 Floats Held Casing (Or Liner) Detail Shoe 4 1/2 12.1 Rotate Csg Recip Csg Hydraulic Fracturing Fluid CompositionTrade NameSupplierPurposeIngredientsChemical Abstract Service Number (CAS #)Maximum Ingredient Concentration in Additive (% by mass)**Maximum Ingredient Concentration in HF Fluid (% by mass)**CommentsYF128 FLEXD:WF128OneStimSurfactant , Breaker J218, Breaker, Gelling Agent, Crosslinker J604, Clay Control Agent, LTCA, Additive, Bactericide, B511 Disclosure, Propping AgentWater (Including Mix Water Supplied by Client)*CAS Not Assigned76.78132%Ceramic materials and wares, chemicals66402-68-496.51493%22.40950%Guar gum9000-30-01.11125%0.25802%2-Butenedioic acid, (Z)-, polymer with sodium 2-propene-1-sulfonate 68715-83-31.02884%0.23888%Phenolic resin9003-35-40.73489%0.17063%2-hydroxy-N,N,N-trimethylethanaminium chloride67-48-10.53623%0.12451%Ulexite1319-33-10.35208%0.08175%Methanol67-56-10.33510%0.07781%Alcohols, c11-15-secondary, ethoxylated68131-40-80.21223%0.04928%Ethylene Glycol107-21-10.20384%0.04733%Hydraulic Fracturing Fluid Product Component Information DisclosureFracture Date:12/26/2019State:AlaskaCounty/ParishAPI Number:50029236500000 Operator Name:Hilcorp AlaskaWell Name and Number:MPU F-116Longitude:-149.655283806399Latitude:70.5083884105453Long/Lat Projection:Production Type:True Vertical Depth (TVD):7774Total Water Volume (gal)*:136879 Trade NameSupplierPurposeIngredientsChemical Abstract Service Number (CAS #)Maximum Ingredient Concentration in Additive (% by mass)**Maximum Ingredient Concentration in HF Fluid (% by mass)**CommentsPotassium hydroxide1310-58-30.14696%0.03412%Diammonium peroxidisulphate7727-54-00.10667%0.02477%Propan-2-ol67-63-00.06541%0.01519%2-butoxyethanol111-76-20.06541%0.01519%Ethoxylated C11 Alcohol34398-01-10.06008%0.01395%Sodium hydroxide1310-73-20.04558%0.01058%Sodium Tetraborate Decahydrate1303-96-40.03891%0.00904%Ethoxylated Alcohol68131-39-50.03261%0.00757%Vinylidene chloride/methylacrylate copolymer25038-72-60.01969%0.00457%Poly(oxy-1,2-ethanediyl),a-hydro-w-hydroxy- Ethane-1,2-diol, ethoxylated 25322-68-30.01117%0.00259%but-2-enedioic acid110-17-80.00927%0.00215%Diatomaceous earth, calcined91053-39-30.00808%0.00188%Undecanol112-42-50.00523%0.00122%Non-crystalline silica (impurity)7631-86-90.00279%0.00065%Magnesium nitrate10377-60-30.00162%0.00038%5-chloro-2-methyl-2h-isothiazolol-3-one26172-55-40.00087%0.00020%Magnesium chloride7786-30-30.00081%0.00019%Magnesium silicate hydrate (talc)14807-96-60.00060%0.00014%Diutan gum125005-87-00.00046%0.00011%Diutan595585-15-20.00046%0.00011%2-methyl-2h-isothiazol-3-one2682-20-40.00026%0.00006%poly(tetrafluoroethylene)9002-84-00.00026%0.00006%Acetic acid, potassium salt127-08-20.00020%0.00005%Cristobalite14464-46-10.00016%0.00004%Quartz, Crystalline silica14808-60-70.00016%0.00004%Acetic acid (impurity)64-19-70.00003%0.00001% † Proprietary Technology* Total Water Volume sources may include fresh water, produced water, and/or recycled water** Information is based on the maximum potential for concentration and thus the total may be over 100% Report ID: RPT-64848 (Generated on 1/8/2020 1:25 PM)All component information listed was obtained from the supplier’s Safety Data Sheets (SDS). As such, the Operator is not responsible for inaccurate and/or incomplete information. Any questions regarding the content of the SDS should be directed to the supplier who provided it. The Occupational Safety and Health Administration’s (OSHA) regulations govern the criteria for the disclosure of this information. Please note that Federal Law protects "proprietary", "trade secret", and "confidential business information" and the criteria for how this information is reported on an SDS is subject to 29 CFR 1910.1200(i) and Appendix D. The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC-Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. Schlumberger-Private FracCAT Treatment Report Well : MPF-116 Field : Kuparuk Formation : A Sand Well Location : County : Prudhoe Bay State : Alaska Country : United States Prepared for Client : Hilcorp Alaska LLC Client Rep : Jim Abel Date Prepared : December 20, 2019 Prepared by Name : Alexander Martinez Division : Schlumberger Phone : 5613895006 Pressure (All Zones) Initial Wellhead Pressure (psi) 715 Surface Shut in Pressure(psi) 2,345 DataFrac Surface ISIP (psi) 2,283 Final Surface ISIP (psi) 2,690 Maximum Treating Pressure (psi) 7,020 Total Proppant Pumped (lbs) 201,880 Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbls) 2228.9 Total YF128FlexD Past Wellhead (bbls) 1,498.9 Total WF128 Past Wellhead (bbls) 439.4 Total Freeze Protect Past Wellhead (bbls) 66.3 Total 16/20 CarboBond Lite Pumped (lbs.) 171,598 Total ScaleGuard Pumped (lbs.) 30,282 Total Chemical Additives Invoiced Past WH Invoiced Past WH J580 (lbs) 2325 2,230 J604 (gal) 158 158 L071 (gal) 160 160 M002 (lbs) 94 94 F103 (gal) 76 76 J134 (lbs) 10 0 J475 (lbs) 248 248 M275 (lbs) 36 36 J218 (lbs) 22 22 LTCA (gal) 138 138 Disclaimer Notice This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. Client : Hilcorp Alaska Well : MPF-116 Formation : Kuparuk C District : Prudhoe Bay Country : United States Schlumberger-Private Job Plots: 10:32:40 10:49:20 11:06:00 11:22:40 11:39:20 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 Tr. Press - psi0 5 10 15 20 25 30 Slurry Rate - bbl/min-2 0 2 4 6 8 10 12 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con Kuparuk A Pressure Test © Schlumberger 1994-2016 Hilcorp Alaska MPF-116 20-Dec-2019 Client : Hilcorp Alaska Well : MPF-116 Formation : Kuparuk C District : Prudhoe Bay Country : United States Schlumberger-Private 11:52:37 12:42:37 13:32:37 14:22:37 15:12:37 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 Tr. Press - psi0 10 20 30 40 Slurry Rate - bbl/min-1 0 1 2 3 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con Kuparuk A DataFrac © Schlumberger 1994-2016 Hilcorp Alaska MPF-116 20-Dec-2019 Client : Hilcorp Alaska Well : MPF-116 Formation : Kuparuk C District : Prudhoe Bay Country : United States Schlumberger-Private 14:45:15 15:18:35 15:51:55 16:25:15 16:58:35 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 8000 Tr. Press - psi0 5 10 15 20 25 30 35 40 Slurry Rate - bbl/min0 2 4 6 8 10 12 14 16 18 20 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con Kuparuk A Main Frac © Schlumberger 1994-2016 Hilcorp Alaska MPF-116 20-Dec-2019 Client : Hilcorp Alaska Well : MPF-116 Formation : Kuparuk C District : Prudhoe Bay Country : United States Schlumberger-Private Section 1: As Measured Pump Schedule As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 Load hole 27.8 4.6 6.2 WF128 1166 0 0 0 2 Shutdow n 1 2.3 0.4 WF128 39 0 0 0 3 Load hole 140.8 22 7 WF128 5895 0 0 0 4 DataFR AC 150 30.2 5 WF128 6298 0 0 0 5 Displace ment 31.1 25.8 1.3 WF128 1312 0 0 0 6 Diesel 19.5 10.3 2.1 Freeze Prot 829 0 0 0 7 Shutdow n 10.4 6.3 2.1 Freeze Prot 437 0 0 0 8 PAD 298.3 23.6 13.1 YF128FlexD 12513 0 0 0 9 1.0 PPA 260.2 22 11.8 YF128FlexD 10564 CarboBond Lite 16/20 1 0.7 7450 10 2.0 PPA 136.5 22 6.2 YF128FlexD 5273 CarboBond Lite 16/20 2 1.9 9448 11 3.0 PPA 142.3 21.9 6.5 YF128FlexD 5295 CarboBond Lite 16/20 2.9 2.8 13964 12 4.0 PPA 177.7 21.6 8.3 YF128FlexD 6344 CarboBond Lite 16/20 4.1 3.8 22947 13 5.0 PPA 153.8 20.1 7.6 YF128FlexD 5264 CarboBond Lite 16/20 5.2 4.9 24536 14 6.0 PPA 191.5 18.7 10.2 YF128FlexD 6330 CarboBond Lite 16/20 6.3 5.9 35168 15 7.0 PPA 99.2 18 5.5 YF128FlexD 3174 CarboBond Lite 16/20 7.1 6.8 20352 16 8.0 PPA 102.7 17.9 5.7 YF128FlexD 3177 CarboBond Lite 16/20 8 7.8 23292 17 9.0 PPA 50.9 15.4 3.3 YF128FlexD 1527 CarboBond Lite 16/20 9.6 8.7 12608 18 10.0 PPA 120.3 14.6 8.2 YF128FlexD 3493 CarboBond Lite 16/20 11 9.7 32115 19 Flush 32 15 2.1 WF128 1344 0 0 0 20 Flush 46.8 15.2 3.1 WF128 1965 0 0 0 21 Flush 36.2 15.3 2.4 Freeze Prot 1517 0 0 0 Stage Pressures & Rates Step # Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 Load hole 4.6 4.7 2681 3264 761 2 Shutdown 2.3 3.7 1995 2617 1168 3 Load hole 22.0 30.0 6225 6935 2658 4 DataFRAC 30.2 31.7 6449 6801 5991 5 Displacement 25.8 31.6 5287 6641 3596 6 Diesel 10.3 13.8 3220 3655 1236 7 Shutdown 6.3 7.1 186 1235 42 8 PAD 23.6 25.9 6245 7020 1325 9 1.0 PPA 22.0 22.3 5813 6016 5687 10 2.0 PPA 22.0 22.5 5729 5820 5657 11 3.0 PPA 21.9 22.0 5863 5972 5780 12 4.0 PPA 21.6 22.2 6002 6182 5744 13 5.0 PPA 20.1 20.3 5846 5961 5749 14 6.0 PPA 18.7 20.3 5761 6094 5611 15 7.0 PPA 18.0 18.3 5600 5664 5570 Client : Hilcorp Alaska Well : MPF-116 Formation : Kuparuk C District : Prudhoe Bay Country : United States Schlumberger-Private Stage Pressures & Rates Step # Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 16 8.0 PPA 17.9 18.2 5763 5893 5664 17 9.0 PPA 15.4 17.9 5119 5892 4941 18 10.0 PPA 14.6 15.0 5159 5260 5007 19 Flush 15.0 15.1 5092 5146 5021 20 Flush 15.2 15.3 4765 5023 4554 21 Flush 15.3 15.3 4442 4591 71 As Measured Totals Slurry (bbl) Pump Time (min) Clean Fluid (gal) Proppant (lb) 2228.9 118.3 83756 201880 Average Treating Pressure: 5733 psi Maximum Treating Pressure: 7020 psi Minimum Treating Pressure: 42 psi Average Injection Rate: 20.7 bbl/min Maximum Injection Rate: 31.7 bbl/min Average Horsepower: 2978.5 hhp Maximum Horsepower: 5161.1 hhp Maximum Prop Concentration: 11.0 PPA Client : Hilcorp Alaska Well : MPF-116 Formation : Kuparuk C District : Prudhoe Bay Country : United States Schlumberger-Private Section 2: Job Messages Message Log # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 Reset Executed Steps 0 0 0.0 0.0 0.0 2 Reset Executed Steps 0 0 0.0 0.0 0.0 3 8:58:58 Arrived on location at 07:00 0 0 0.0 0.0 0.0 4 8:59:13 All equipment running 08:30 0 0 0.0 0.0 0.0 5 8:59:35 Waiting on Pod to regen Start at 08:30 0 0 0.0 0.0 0.0 6 9:06:48 Regen is done. Doing additional checks 0 0 0.0 0.0 0.0 7 9:29:16 Priming up the POD -1 0 0.0 0.0 0.0 8 9:43:28 Flooding the lines 21 -0 0.0 0.0 0.0 9 9:48:22 Priming up pumps 31 -0 0.0 0.0 0.0 10 10:09:32 Pumps are primed 108 -0 0.0 0.0 0.0 11 10:09:56 Woring on oiler issue on pump 3 109 -0 0.0 0.0 0.0 12 10:21:31 Warming up lines 35 -1 0.0 0.0 0.0 13 10:40:17 Getting ready to do low PT 37 -1 0.0 0.0 0.0 14 10:44:16 Coming up to 4000 for checkvalve test 1997 -1 0.0 0.0 0.0 15 10:49:36 Check valve test is good 3727 -1 0.0 1.7 0.0 16 10:49:44 Coming up for high PT 3714 -1 0.0 0.0 0.0 17 10:58:44 Bumping up pressure 8358 -1 0.0 0.0 0.0 18 11:04:02 Pressure test is good 8218 -1 0.0 0.0 0.0 19 11:04:28 Bleeding off pressure 8189 -1 0.0 0.0 0.0 20 11:06:26 Gathering up for safety meeting 83 -1 0.0 0.0 0.0 21 11:27:22 PJSM is done 104 -1 0.0 0.0 0.0 22 11:31:11 Making 28 lb gel 76 -1 0.0 0.0 0.0 23 11:52:19 Getting POD primed up with gelled fluid 28 -0 0.0 0.0 0.0 24 11:58:37 Matching WH Pressure 62 -1 0.0 0.0 0.0 25 11:59:50 Opening the well to displace freeze protect 1196 -1 0.0 0.0 0.0 26 12:00:53 Start Load hole Automatically 760 159 0.0 0.0 0.0 27 12:00:53 Start Propped Frac Automatically 760 159 0.0 0.0 0.0 28 12:00:53 Start KupA New Automatically 760 159 0.0 0.0 0.0 29 12:00:58 Started Pumping 760 487 0.0 0.0 0.0 30 12:01:06 Activated Extend Stage 767 574 0.0 0.0 0.0 31 12:15:48 Deactivated Extend Stage 1470 2463 27.8 0.0 0.0 32 12:15:49 Start Shutdown Automatically 1468 2463 27.8 0.0 0.0 33 12:26:03 Start Load hole Automatically 2681 2504 28.8 4.7 0.0 34 12:27:07 Activated Extend Stage 5420 2573 39.3 13.6 0.0 35 12:31:52 Stage at Perfs: Load hole 6063 3132 134.0 28.4 0.0 36 12:32:49 Stage at Perfs: Shutdown 6295 3195 162.1 29.7 0.0 37 12:32:51 Stage at Perfs: Load hole 6390 3203 163.0 29.3 0.0 38 12:33:03 Deactivated Extend Stage 6373 3210 169.0 30.0 0.0 39 12:33:04 Start DataFRAC Automatically 6494 3214 169.5 30.0 0.0 40 12:37:32 Stage at Perfs: DataFRAC 6649 3432 303.6 31.8 0.0 41 12:38:03 Start Displacement Automatically 6632 3449 319.9 31.6 0.0 42 12:38:07 Activated Extend Stage 6573 3449 322.0 31.6 0.0 43 12:39:21 Deactivated Extend Stage 3632 3417 350.7 13.8 0.0 44 12:39:21 Start Diesel Manually 3632 3417 350.7 13.8 0.0 45 12:39:23 Activated Extend Stage 3621 3421 351.1 13.8 0.0 46 12:42:27 Down for datafrac 2226 3397 370.2 0.0 0.0 47 14:31:56 Deactivated Extend Stage 1235 2979 370.2 0.0 0.0 Client : Hilcorp Alaska Well : MPF-116 Formation : Kuparuk C District : Prudhoe Bay Country : United States Schlumberger-Private Message Log # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 48 14:31:56 Start Shutdown Manually 1235 2979 370.2 0.0 0.0 49 14:32:00 Activated Extend Stage 1235 2978 370.2 0.0 0.0 50 14:45:02 Closed well to warm up lines 1188 2962 370.2 0.0 0.0 51 14:45:08 Bleeding pressure 1187 2962 370.2 0.0 0.0 52 14:48:45 Warming up the lines 62 2958 370.2 0.0 0.0 53 14:51:39 Lining up to match pressure 83 2954 380.5 0.0 0.0 54 14:53:50 Well is opened back up 1051 2952 380.6 0.0 0.0 55 14:59:27 Deactivated Extend Stage 1431 2951 380.6 1.0 0.0 56 14:59:28 Start PAD Automatically 1546 2952 380.6 1.5 0.0 57 14:59:32 Activated Extend Stage 1896 2966 380.7 2.2 0.0 58 15:03:12 Stage at Perfs: Displacement 7034 3087 453.8 25.7 0.0 59 15:04:30 Stage at Perfs: Diesel 6853 3151 484.4 24.5 0.0 60 15:05:17 Stage at Perfs: Shutdown 6601 3189 503.9 24.8 0.0 61 15:05:43 Stage at Perfs: PAD 6257 3193 514.7 25.0 0.0 62 15:12:29 Deactivated Extend Stage 5851 3429 677.8 22.1 0.0 63 15:12:32 Start 1.0 PPA Manually 5868 3430 678.9 22.1 0.0 64 15:12:32 Started Pumping Prop 5868 3430 678.9 22.1 0.0 65 15:18:38 Stage at Perfs: 1.0 PPA 5976 3512 812.7 21.9 1.0 66 15:19:36 Activated Extend Stage 5906 3522 833.9 22.0 1.0 67 15:24:21 Deactivated Extend Stage 5750 3522 938.7 22.1 1.0 68 15:24:22 Start 2.0 PPA Automatically 5725 3521 939.1 22.1 1.2 69 15:30:27 Stage at Perfs: 2.0 PPA 5799 3520 1072.8 22.0 1.9 70 15:30:35 Start 3.0 PPA Automatically 5834 3522 1075.8 21.9 1.9 71 15:36:41 Stage at Perfs: 3.0 PPA 5969 3518 1209.3 21.8 2.8 72 15:37:05 Start 4.0 PPA Automatically 5935 3522 1218.0 21.7 3.4 73 15:43:13 Stage at Perfs: 4.0 PPA 6195 3511 1351.7 21.8 3.9 74 15:45:20 Start 5.0 PPA Automatically 5769 3500 1395.6 20.2 4.3 75 15:51:58 Stage at Perfs: 5.0 PPA 5929 3477 1529.1 20.2 5.1 76 15:52:59 Start 6.0 PPA Automatically 5933 3476 1549.6 19.9 5.6 77 16:00:01 Stage at Perfs: 6.0 PPA 5653 3501 1683.1 17.9 5.7 78 16:03:14 Start 7.0 PPA Automatically 5642 3473 1741.1 17.9 6.0 79 16:08:45 Start 8.0 PPA Automatically 5667 3511 1840.3 17.8 7.1 80 16:10:39 Stage at Perfs: 7.0 PPA 5721 3498 1874.5 17.9 7.8 81 16:14:28 Start 9.0 PPA Automatically 5892 3479 1942.7 17.8 7.7 82 16:16:28 Stage at Perfs: 8.0 PPA 4997 3497 1973.7 14.8 8.8 83 16:17:49 Start 10.0 PPA Automatically 5059 3486 1993.7 14.9 9.5 84 16:17:52 Activated Extend Stage 5051 3485 1994.4 14.7 9.7 85 16:23:29 Stage at Perfs: 9.0 PPA 5193 3487 2076.1 14.7 10.4 86 16:26:03 Deactivated Extend Stage 5036 3464 2113.9 14.9 0.0 87 16:26:03 Start Flush Manually 5036 3464 2113.9 14.9 0.0 88 16:26:23 Stopped Pumping Prop 5092 3465 2118.9 15.0 0.0 89 16:26:56 Stage at Perfs: 10.0 PPA 5142 3464 2127.2 15.0 0.0 90 16:28:11 Start Flush Automatically 5012 3476 2146.0 15.1 0.0 91 16:31:15 Start Flush Manually 4557 3522 2192.7 15.1 0.0 92 16:31:18 Activated Extend Stage 4544 3520 2193.4 15.2 0.0 93 16:34:53 Watching pressures 2673 3472 2228.9 0.0 0.0 94 16:52:01 Closing in the well 2392 3311 2228.9 0.0 0.0 95 16:56:18 Bleeding off pressure 72 3083 2228.9 0.0 0.0 96 16:56:24 End of job 71 3057 2228.9 0.0 0.0 Client : Hilcorp Alaska Well : MPF-116 Formation : Kuparuk C District : Prudhoe Bay Country : United States Schlumberger-Private Message Log # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 97 16:56:43 Deactivated Extend Stage 71 2978 2228.9 0.0 0.0 14:50:42 15:19:52 15:49:02 16:18:12 16:47:22 Time - hh:mm:ss 0 5 10 15 20 25 30 Slurry Rate - bbl/min0 1 2 3 4 5 6 7 8 9 10 Liquid Additives - gal/mgal0 2 4 6 8 10 12 14 J218, J475 CONC - lb/mgalSLUR_RATE CFLD_RATE J604_CONC F103_CONC L071_CONC U028_CONC LTCA_CONC J475_CONC Kuparuk A: Additives © Schlumberger 1994-2016 Hilcorp Alaska MPF-116 20-Dec-2019 Schlumberger-Private FracCAT Treatment Report Well : MPF-116 Field : Kuparuk Formation : C Sand Well Location : County : Prudhoe Bay State : Alaska Country : United States Prepared for Client : Hilcorp Alaska LLC Client Rep : Jim Abel Date Prepared : December 26, 2019 Prepared by Name : Alexander Martinez Division : Schlumberger Phone : 5613895006 Pressure (All Zones) Initial Wellhead Pressure (psi) 1,020 Surface Shut in Pressure(psi) 4,487 Pump Check Surface ISIP (psi) 2,555 Final Surface ISIP (psi) 5,780 Maximum Treating Pressure (psi) 7,283 Total Proppant Pumped (lbs)* 137,800 Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbls) 1500.9 Total YF128FlexD Past Wellhead (bbls) 1170.8 Total WF128 Past Wellhead (bbls) 177.8 Total Freeze Protect Past Wellhead (bbls) 25.9 Total 16/20 CarboBond Lite Pumped (lbs.)* 117,130 Total ScaleGuard Pumped (lbs.)* 20,670 Total Chemical Additives Invoiced Past WH Invoiced Past WH J580 (lbs) 1,642 1,542 J604 (gal) 125 125 L071 (gal) 110 110 M002 (lbs) 64 64 F103 (gal) 69 69 J134 (lbs) 20 0 J475 (lbs) 193 193 M275 (lbs) 24 20 J218 (lbs) 33 33 LTCA (gal) 94 94 *All proppant pumped was 85% CarboBond Lite and 15% ScaleGuard blend Disclaimer Notice This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. Client : Hilcorp Alaska Well : MPF-116 Formation : Kuparuk C District : Prudhoe Bay Country : United States Schlumberger-Private Job Plots: 20:06:49 20:19:19 20:31:49 20:44:19 20:56:49 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 Tr. Press - psi0 5 10 15 20 25 Slurry Rate - bbl/min0 2 4 6 8 10 12 14 16 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con Pressure Test © Schlumberger 1994-2016 Hilcorp MPF-116 26-Dec-2019 Client : Hilcorp Alaska Well : MPF-116 Formation : Kuparuk C District : Prudhoe Bay Country : United States Schlumberger-Private 20:54:40 21:07:10 21:19:40 21:32:10 21:44:40 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 8000 Tr. Press - psi0 5 10 15 20 25 Slurry Rate - bbl/min0 2 4 6 8 10 12 14 16 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con Open Well Displace Freeze Protect Pump Check Pump Check © Schlumberger 1994-2016 Hilcorp MPF-116 26-Dec-2019 Client : Hilcorp Alaska Well : MPF-116 Formation : Kuparuk C District : Prudhoe Bay Country : United States Schlumberger-Private 21:34:49 22:03:59 22:33:09 23:02:19 23:31:29 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 8000 Tr. Press - psi0 5 10 15 20 25 30 Slurry Rate - bbl/min0 2 4 6 8 10 12 14 16 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con Kuparuk C © Schlumberger 1994-2016 Hilcorp MPF-116 26-Dec-2019 Client : Hilcorp Alaska Well : MPF-116 Formation : Kuparuk C District : Prudhoe Bay Country : United States Schlumberger-Private Section 2: As Measured Pump Schedule As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 Load Hole 50.6 6.1 10.4 WF128 2114 0 0 0 2 Pump Check 51.4 19.4 2.7 YF128FlexD 2155 0 0 0 3 Step Down 51.3 20.7 2.7 WF128 2164 0 0 0 4 Shutdow n 2 4.6 0.5 WF128 81 0 0 0 5 PAD 300 24.5 12.5 YF128FlexD 12585 0 0 0 6 1.0 PPA 150.2 23.2 6.5 YF128FlexD 6037 CarboBond Lite 16/20 1.1 1 6283 7 2.0 PPA 138.5 22.4 6.2 YF128FlexD 5333 CarboBond Lite 16/20 2.1 2 11115 8 3.0 PPA 139.7 21.6 6.5 YF128FlexD 5160 CarboBond Lite 16/20 3.2 3 16255 9 4.0 PPA 117.7 20 5.9 YF128FlexD 4181 CarboBond Lite 16/20 4.1 4 17559 10 5.0 PPA 84.7 17.8 4.8 YF128FlexD 2894 CarboBond Lite 16/20 5.3 5 15257 11 6.0 PPA 84.8 16.8 5.1 YF128FlexD 2791 CarboBond Lite 16/20 6.5 6 17713 12 7.0 PPA 84.8 15 5.6 YF128FlexD 2696 CarboBond Lite 16/20 7.2 7 19892 13 8.0 PPA 45.4 13.8 3.3 YF128FlexD 1396 CarboBond Lite 16/20 9 8 11837 14 9.0 PPA 45.6 12.5 3.7 YF128FlexD 1356 CarboBond Lite 16/20 9.1 8.9 12831 15 10.0 PPA 38.9 12.3 3.2 YF128FlexD 1244 CarboBond Lite 16/20 10.2 9.9 9059 16 Flush 32 12.4 2.6 WF128 1344 0 0 0 17 LG Flush 42.3 12.2 3.5 WF128 1768 0 0 0 18 Flush 41.1 11.6 3.6 Freeze Prot 1735 0 0 0 Client : Hilcorp Alaska Well : MPF-116 Formation : Kuparuk C District : Prudhoe Bay Country : United States Schlumberger-Private Stage Pressures & Rates Step # Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 Load Hole 6.1 15.9 4031 6941 1714 2 Pump Check 19.4 21.0 6826 7283 6355 3 Step Down 20.7 24.4 5635 6440 2321 4 Shutdown 4.6 4.8 3858 4408 2081 5 PAD 24.5 26.7 6727 7159 4247 6 1.0 PPA 23.2 25.1 6608 7159 6103 7 2.0 PPA 22.4 22.6 6528 6702 6439 8 3.0 PPA 21.6 22.6 6694 6975 6172 9 4.0 PPA 20.0 20.2 6693 6988 6458 10 5.0 PPA 17.8 20.1 6542 7006 6365 11 6.0 PPA 16.8 17.6 6720 6975 6363 12 7.0 PPA 15.0 15.3 6686 6871 6473 13 8.0 PPA 13.8 15.3 6611 6957 6243 14 9.0 PPA 12.5 12.7 6590 6715 6467 15 10.0 PPA 12.3 12.7 6810 6912 6706 16 Flush 12.4 12.6 7014 7071 6912 17 LG Flush 12.2 12.4 7027 7059 6945 18 Flush 11.6 12.5 7069 7178 4519 As Measured Totals Slurry (bbl) Pump Time (min) Clean Fluid (gal) Proppant (lb) 1500.9 89.2 57034 137800 Average Treating Pressure: 6568 psi Maximum Treating Pressure: 7283 psi Minimum Treating Pressure: 1714 psi Average Injection Rate: 19.3 bbl/min Maximum Injection Rate: 26.7 bbl/min Average Horsepower: 3139.6 hhp Maximum Horsepower: 4516.4 hhp Maximum Prop Concentration: 10.2 PPA Client : Hilcorp Alaska Well : MPF-116 Formation : Kuparuk C District : Prudhoe Bay Country : United States Schlumberger-Private Section 4: Job Messages Message Log # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 Reset Executed Steps 0 0 0.0 0.0 0.0 2 Reset Executed Steps 0 0 0.0 0.0 0.0 3 16:33:16 All equipment is running 8 2 0.0 0.0 0.0 4 16:33:25 Getting ready to prime up pumps 7 1 0.0 0.0 0.0 5 16:37:00 Priming up the POD 0 -1 0.0 0.0 0.0 6 16:45:44 Flooding the lines with freeze protect 7 2 0.0 0.0 0.0 7 17:08:58 Priming pumps 28 0 0.0 0.0 0.0 8 17:29:30 Pumps are primed 41 -1 0.0 0.0 0.0 9 17:30:34 Warming lines back up 36 -0 0.0 0.0 0.0 10 17:48:30 Coming up for low pt 1912 4 0.0 1.3 0.0 11 17:54:01 Coming up to 4K for check valve test 1118 5 0.0 0.0 0.0 12 17:59:27 Coming up for high PT 3436 3 0.0 0.0 0.0 13 18:01:24 Leak on main line check valve 1797 3 0.0 0.0 0.0 14 19:24:41 PJSM is done 92 7 0.0 0.0 0.0 15 19:24:51 Waiting for diesel to be filled 92 7 0.0 0.0 0.0 16 19:46:26 Spotting diesel back in 92 5 0.0 0.0 0.0 17 20:01:31 POD primed up on diesel 124 5 0.0 0.0 0.0 18 20:02:16 Warming up the lines 115 5 0.0 0.0 0.0 19 20:11:32 Getting lined up to PT 134 7 0.0 0.0 0.0 20 20:17:10 Low pressure stall 122 5 0.0 0.0 0.0 21 20:19:06 Coming up for high PT 1539 6 0.0 0.0 0.0 22 20:30:33 Bleed down pressure to match wellhead 1132 6 0.0 0.0 0.0 23 20:32:18 Mixing up 28 lb gel 1170 8 0.0 0.0 0.0 24 20:51:44 Chief gates are checked out 688 6 0.0 0.0 0.0 25 20:56:16 Priming up POD with 28 lb gel 577 6 0.0 0.0 0.0 26 20:57:02 Bringing IA to 1000 psi 559 6 0.0 0.0 0.0 27 20:58:19 Opening the well 531 233 0.0 0.0 0.0 28 21:04:05 Start Load Hole Automatically 1404 2034 0.0 1.5 0.0 29 21:04:05 Start Propped Frac Automatically 1404 2034 0.0 1.5 0.0 30 21:04:05 Start KupC JA New Automatically 1404 2034 0.0 1.5 0.0 31 21:04:09 Started Pumping 1692 2041 0.0 1.5 0.0 32 21:04:18 Activated Extend Stage 2272 2054 0.3 2.6 0.0 33 21:13:41 Displaced freeze protect 2275 2045 35.2 0.0 0.0 34 21:20:58 Deactivated Extend Stage 7302 3143 50.3 17.5 0.0 35 21:20:59 Start Pump Check Automatically 7301 3146 50.6 17.9 0.0 36 21:21:02 Activated Extend Stage 7093 3141 51.5 18.5 0.0 37 21:23:37 Deactivated Extend Stage 6418 3405 101.6 21.2 0.0 38 21:23:38 Start Step Down Automatically 6430 3409 102.0 21.3 0.0 39 21:23:39 Activated Extend Stage 6398 3410 102.3 21.3 0.0 40 21:24:59 Stage at Perfs: Load Hole 5331 3438 133.0 21.9 0.0 41 21:27:46 Deactivated Extend Stage 2423 3510 153.3 0.0 0.0 42 21:27:47 Start Shutdown Automatically 2422 3510 153.3 0.0 0.0 43 21:27:48 Activated Extend Stage 2421 3510 153.3 0.0 0.0 44 21:36:19 PCM having stg 2 issues 2192 3505 153.3 0.0 0.0 45 21:43:32 Deactivated Extend Stage 2084 3491 153.3 0.0 0.0 46 21:44:13 Start PAD Automatically 4642 3554 155.3 4.3 0.0 47 21:45:56 Stage at Perfs: Pump Check 6230 3422 183.5 24.1 0.0 Client : Hilcorp Alaska Well : MPF-116 Formation : Kuparuk C District : Prudhoe Bay Country : United States Schlumberger-Private Message Log # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 48 21:48:03 Stage at Perfs: Step Down 6257 3506 234.9 24.2 0.0 49 21:50:02 Stage at Perfs: Shutdown 7051 3464 286.3 25.8 0.0 50 21:50:07 Stage at Perfs: PAD 7080 3472 288.4 25.7 0.0 51 21:56:45 Start 1.0 PPA Automatically 6854 3517 455.7 24.9 0.0 52 21:56:45 Started Pumping Prop 6854 3517 455.7 24.9 0.0 53 22:02:28 Stage at Perfs: 1.0 PPA 6456 3511 588.3 22.4 1.0 54 22:03:14 Start 2.0 PPA Automatically 6444 3509 605.6 22.5 0.9 55 22:09:10 Stage at Perfs: 2.0 PPA 6696 3507 738.3 22.2 2.0 56 22:09:26 Start 3.0 PPA Automatically 6717 3504 744.2 22.3 1.9 57 22:15:34 Stage at Perfs: 3.0 PPA 6446 3514 876.9 19.9 3.0 58 22:15:55 Start 4.0 PPA Automatically 6486 3513 883.9 20.0 3.0 59 22:21:48 Start 5.0 PPA Automatically 6993 3511 1001.4 20.1 4.0 60 22:22:35 Stage at Perfs: 4.0 PPA 6387 3496 1016.4 18.0 5.0 61 22:26:35 Start 6.0 PPA Automatically 6670 3514 1086.2 17.4 4.9 62 22:29:20 Stage at Perfs: 5.0 PPA 6937 3513 1133.9 17.4 6.2 63 22:31:39 Start 7.0 PPA Automatically 6486 3489 1170.8 15.2 6.0 64 22:34:50 Stage at Perfs: 6.0 PPA 6744 3484 1218.8 15.1 7.0 65 22:37:18 Start 8.0 PPA Automatically 6849 3490 1255.8 15.1 7.0 66 22:40:38 Start 9.0 PPA Automatically 6465 3495 1301.2 12.6 8.0 67 22:40:48 Stage at Perfs: 7.0 PPA 6496 3491 1303.3 12.5 8.2 68 22:44:17 Start 10.0 PPA Automatically 6680 3504 1346.6 12.4 9.0 69 22:44:19 Activated Extend Stage 6706 3509 1347.0 12.4 9.1 70 22:47:26 Deactivated Extend Stage 6951 3495 1385.5 12.4 -0.1 71 22:47:26 Start Flush Manually 6951 3495 1385.5 12.4 -0.1 72 22:47:31 Stopped Pumping Prop 6956 3498 1386.6 12.5 -0.1 73 22:47:39 Stage at Perfs: 8.0 PPA 6995 3492 1388.2 12.5 0.0 74 22:50:02 Start LG Flush Automatically 7016 3526 1417.6 12.2 0.0 75 22:51:21 Stage at Perfs: 9.0 PPA 7001 3526 1433.7 12.2 0.0 76 22:53:29 Start Flush Manually 7073 3516 1459.8 12.5 0.0 77 22:53:30 Activated Extend Stage 7022 3518 1460.0 12.4 0.0 78 22:55:03 Stage at Perfs: 10.0 PPA 7145 3504 1479.3 12.4 0.0 79 23:00:41 Down on the pumps 5529 3477 1500.9 0.0 0.0 80 23:00:48 Watching pressures 5530 3498 1500.9 0.0 0.0 81 23:03:32 Waiting for pressure to drop below 5K 5431 3456 1500.9 0.0 0.0 82 23:17:39 Shutting in the well 4615 346 1500.9 0.0 0.0 83 23:20:31 Deactivated Extend Stage 4505 98 1500.9 0.0 0.0 84 23:20:45 Well is closed 4467 83 1500.9 0.0 0.0 85 23:23:20 Bleeding off the pressure 4121 7 1500.9 0.0 0.0 86 23:24:11 End of job 116 -6 1500.9 0.0 0.0 Schlumberger-Private 21:31:44 22:00:54 22:30:04 22:59:14 23:28:24 Time - hh:mm:ss 0 5 10 15 20 25 30 Slurry Rate - bbl/min0 1 2 3 4 5 6 7 8 Liquid Additives - gal/mgal0 2 4 6 8 10 12 14 J218, J475 CONC - lb/mgalSLUR_RATE CFLD_RATE J604_CONC F103_CONC L071_CONC U028_CONC LTCA_CONC J475_CONC Main Treatment Additives © Schlumberger 1994-2016 Hilcorp Alaska MPF-116 26-Dec-2019 THE STATE Chad Helgeson GOVERNOR MIKE DUNLEAVY Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk Oil Pool, KRU F-116 Permit to Drill Number: 219-133 Sundry Number: 319-587 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, J r . Price air DATED this J day of January, 2020. 3BDMS '4rA/,lAN 0 6 2020 REICH STATE OF ALASKA DEC 3 0 /019 ALASKA OIL AND GAS CONSERVATION COMMISSION QTS % 31/x,0 APPLICATION FOR SUNDRY APPROVALSACICCC 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate Q Other Stimulate ❑ Pull Tubing ❑✓ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ESP Change -out Q 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development ❑✓ Stratigraphic ❑ Service ❑ 219-133 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: , Anchorage Alaska 99503 50-029-23650-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 432D Will planned perforations require a spacing exception? Yes ❑ No Q i Milne Point Unit F-116 9. Property Designation (Lease Number): . 10. Field/Pool(s): ADL025509 / ADL355017 Milne Point Field / Kuparuk Oil Pool If 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 13,785' 7,656' 13,777' 7,648' 3,144 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 80' 80' Surface 9,029' 9-5/8" 9,055' 4,724' 5,750psi 3,090psi Production 13,029' 7" 13,054' 6,968' 7,240psi 5,410psi Liner 877' 4-1/2" 13,777' 7,648' 8,430psi 7,500psi Perforation Depth D (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See S ematic See Schematic 3-1/2" 9.3# / L-80 / Hydril 563 12,935' Packers an SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Liner Top Packer and N/A 12,900' MD / 6,824' TVD and N/A 12.Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: etailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 1/18/2020 OIL ❑WINJ ❑WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson Contact Name: Taylor Wellman Authorized Title: Operations Manager Contact Email: tWellman hllCor .Com Contact Phone: 777-8449 Authorized Signaturw CDate: 12/30/2019 COMMISSION USE ONLY Conditions of approv . Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test v/ Mechanical Integrity Test ❑ Location Clearance ❑ Other: 41 t16C0�` P �� 1 '3BDMS1<�jAN 0 6 2020 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes No N/ Subsequent Form Required: APPROVED BY + LiV Approved by: I COMMISSIONER THE COMMISSION Date: Ua-IGINAL X 1-2-2-6 Form 10-403 Revised 4/2017 Approved application is valid for 12 months from the date of approval. Submit Form and Attachments in Duplicate ; K IIilcorp Alaska, LLI Convert to ESP Well: MPU F-116 Date: 12-29-2019 Well Name: MPU F-116 API Number: 50-029-23650-00 Current Status: Jet Pump Producer Pad: F -Pad Estimated Start Date: January 18th, 2020 Rig: ASR Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 219-133 First Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) Second Call Engineer: David Haakinson (907) 777-8343 (0) (307) 660-4999 (M) AFE Number: 1914665C Job Type: Convert to ESP Current Bottom Hole Pressure: 3,878 psi @ 7,340' TVD Maximum Expected BHP: 3,878 psi @ 7,340' TVD MPSP: 3,144 psi Max Inclination 68° @ 2,703' MD Max Dogleg: 7.5°/100ft @ 2,067' MD BPV Profile: 3" CIW Type H BHP taken on 12/15/19 (Pre -Frac Treatment) 10.2 PPG BHP taken on 12/15/19 (Pre -Frac Treatment) 10.2 PPG Gas Column Gradient (0.1 psi/ft) Brief Well Summary: MPU well F-116 is a Kuparuk A & C sand production well drilled in November 2019. The well was hydraulically fracture stimulated in both the Kuparuk A & C sands (2 stage job) in late December 2019. The temporary 3-1/2" jet pump completion in the well was installed for the frac and for initial flowback. The objective of this RWO is to install an ESP for full-time production. Notes Regarding Wellbore Condition • 9-5/8" casing pressure tested to 2,500 psi for 30 minutes on 11/9/19 • 7" casing pressure tested to 4,000 psi for 10 minutes on 11/27/19 • 4-%" liner pressure tested to 4,000 psi for 10 minutes on 11/27/19 • 3-%" tubing was pressure tested to 4,000 psi for 30 minutes on 11/28/19 • 3-1/2" x 7" annulus pressure tested to 3,500 psi for 30 minutes on 11/29/19 Objective: • Pull existing 3-1/2" jet pump completion • Install new Baker Hughes 150 HP motor, Baker Hughes ESPs, new ESP cable, and new 2-7/8" tubing Pre -Rig Procedure: 1. MIRU Slickline unit and pressure test to 250psi low/3,500psi high. a. Pull jet pump from sliding sleeve @ 12,770' md. b. Drift and tag top of fill. c. Run B P urvey to confirm BHP for RWO. i. Potential for not running vented ESP packer based on BHP to be in compliance with CO 390A. d. RD Slickline Unit. I I r�1 C�.,�Q�o�►-, 2. Contingency — Based on well performance & analog wells if the Kuparuk Al and B7 sands are contributing. a. RU EL unit and pressure test to 250psi low/3,500psi high. b. MU 2-1/2" Geodynamics Razor guns and perforate the following: Convert to ESP Well: MPU F-116 Ililcorp Alaska, LL Date: 12-29-2019 c. ±13,485' - ±13,510' md: Kuparuk Al (2 runs) d. ±13,437'- ±13,450' md: Kuparuk B7 (1 run) i. Correlation Log: Halliburton F-116 MWD e. RD EL unit. 3. RU LRS and PT lines to 3000 psi. 4. Circulate 1.25 BU volume to the sliding sleeve (560 bbls) with 10.2 ppg brine while taking returns to tank. Shut in and bullhead an additional 15 bbls to formation. 5. Clear and level pad area in front of well. Spot rig mats and containment. 6. RD well house and flowlines. Clear and level area around well. 7. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 McOH. a. Freeze protect is up to the discretion of the Wellsite Supervisor depending on timing for arrival of the ASR. 8. RD Little Red Services. 9. RU crane. Set BPV. ND Tree. NU BOPE. RD Crane. 10. NU BOPE house. Spot mud boat. Brief RWO Procedure: 11. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines to returns tank. 12. Check for pressure and if 0 psi, pull BPV. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/ 10.2 ppg brine prior to pulling BPV. 13. Set PBV Plug (converting BPV to TWC). 14. Test BOPE to 250 psi Low/ 4 000 psi High annular to 250 psi Low/ 2,500 psi Hi>;h (hold each ram/valve and test for 5 -min). Record accumulator pre -charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Perform Test per ASR #1 BOP Test Procedure dated 11/03/2015. C. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 2-7/8" and 3-1/2" test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 15. Contingency: If BOPE test fails a. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) I U Ililcorn Alaska, LLi Convert to ESP Well: MPU F-116 Date: 12-29-2019 f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 16. Bleed any pressure off casing to returns tank. Pull BPV plug and BPV. Kill well w/ 10.2 ppg brine as needed. 17. MU landing joint or spear and PU on the tubing hanger. a. During the 2019 Innovation Rig jet pump completion the tubing was set in compression (-15k lbs). PUW = 120k lbs and the SOF = 65k lbs, Wt of blocks = 35k lbs. b. If needed, circulate (long or reverse) pill with lubricant, source -water, and/or baraclean pill prior to laying down the tubing hanger. 18. Recover the tubing hanger. Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re -land hanger (or test plug) in tubing head. Test BOPE per standard procedure. a. Evaluate pulled tubing hanger for possible thread damage. If any damage is found, dispose of tubing hanger and contact well head specialist for replacement. b. There is no anchor latch in the sealbore. 19. POOH and lay down the 3-1/2" tubing. a. Note any sand or erosive damage on the tubulars and ESP on the morning report. i. Look for over -torqued connections from original completion. ii. If any joints appear suspect of damage to threads or tubing, send to G&I for disposal. iii. Send 5-10% random selection of joints to Tuboscope for full inspection for re -use. Send rest to G&I for cleaning and label as Frac String. 20. RU dual spoolers for ESP cable and for 3/8" control line. 21. PU new ESP and RIH on 2-7/8" 6.5# L-80 tubing. Set base of ESP assembly at ±12,800' MD. a. 2-7/8" tubing b. Sta #3: 2-7/8"x 1" Side -pocket GLM with Dummy GLV c. 2-7/8" tubing d. Sta #2: 2-7/8"x 1" Side -pocket GLM with Dummy GLV e. 1 joint of 2-7/8" tubing �1 �F f. 7" x 2-7/8" Viking vented, ESP Packer @ ±5,000' MD g. Sta #1: 2-7/8"x 1" Side -pocket GLM with Dummy GLV h. 2 full joints of 2-7/8" tubing i. 2-7/8" XN (2.205" No -Go) Nipple j. 1 joint of 2-7/8" tubing k. Downhole gauge for discharge temperature and pressure i. Connected with a jumper from the lower sensor. Does not require a separate tech -wire. I. Baker Hughes 268 stage Flex17 Pump m. 20 GIN Pump n. Tandem Gas Separator o. 150 HP Baker Hughes 562XP Motor p. Motorgauge Convert to ESP Well: MPU F-116 Itilcorp Alaska, LL Date: 12-29-2019 q. Base of ESP centralizer @ ±12,800' MD 22. Land tubing hanger. RILDS. Lay down landing joint. Note Pick-up and slack -off weights on tally. 23. Set BPV. p Post -Rig Procedure: 24. RD mud boat. RD BOPE house. Move to next well location. 25. RU crane. ND BOPE. 26. NU new 2-9/16" 5,000# tree. Test tubing hanger void to 500 psi low/5,000 psi high. 27. Pull BPV. 28. RD crane. Move returns tank and rig mats to next well location. 29. Replace gauge(s) if removed. 30. Turn well over to production. RU well house and flowlines. Attachments: 1. As -built Schematic 2. Proposed Schematic 3. BOP Schematic 4. Blank RWO MOC Form fiileoru Alaska, LLC Orig. KB Elev.: 38'/ GL Elev.: 11.5' TD= 13,785' (MD)/TD=±7,774' (TVD) PBTD =13,692' (MD) / PBTD = ±7,659' (TVD) Milne Point Unit Well: MPF -116 SCHEMATIC Last Completed: 11/29/19 LL&V,/� —� PTD: 219-133 TREE & WELLHEAD Tree 5M 4-1/16" Wellhead I 5M FMC Gen IV OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" Stg 1 L - 2240 ft3 / T - 458 ft3 / Stg 2 L - 1776.3 ft3 / T - 314 ft3 9-7/8"x 8-1/2" 215 ft3 6-1/8" 178 ft3 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 215 / X-52 / Weld N/A Surface 107' N/A 9-5/8" Surface 40 / L-80 / TXP-BTC 8.835 Surface 9,055' 0.0758 7" Intermediate 26/L-80/TXP-BTC 6.276 Surface 13,054' 0.0383 4-1/2" Liner 12.6 / L-80 / TXP-BTC 3.958 12,900' 13,777' 0.0152 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / Hyd563 1 2.992 1 Surface 1 12,922' 1 0.0087 WELL INCLINATION DETAIL KOP @ 400' Max Hole Angle 65 deg JEWELRY DETAIL No. Top MD Item ID ±13,694' ±13,702' 8 2-1/8" xx/xx/xx Future Kuparuk A3 ±13,770' ±13,778' 8 2-1/8" 2 12,770' 3-1/2" Sliding Sleeve 2.992 3 12,826' 3-1/2" XN Nipple - No-go = 2.725" 2.725 4 12,905' Sealbore — Bottom at 12,922' and 2.992 5 12,900' HES VersaFlex Liner Top Packer 4.340 GENERAL WELL INFO API : 50-029-xxxxx-00-00 Cased by Doyon 14:xx/xx/xxxx PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk C ±13,694' ±13,702' 8 2-1/8" xx/xx/xx Future Kuparuk A3 ±13,770' ±13,778' 8 2-1/8" xx/xx/xx Future Ref Log: xx/xx/xxxx Halliburton MWD Revised By: TTW 12/4/2019 Itileorp Alaska. LLC Orig. KB Elev.: 38'/ GL Elev.: 11.5' TD =14,178' (MD) /TD = 8,023' (TVD) PBTD = 14,158' (MD) / PBTD = 8,000' (TVD) Milne Point Unit Well: MP F-116 Last Completed: 11/29/19 PTD: 219-133 TREE & WELLHEAD Tree 5M 2 -1/8 - Wellhead I SM FMC Gen IV OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" Stg 1 L - 2240 ft3 / T - 458 ft3 / Stg 2 L - 1776.3 ft3 / T - 314 ft3 9-7/8"x 8-1/2" 215 ft3 6-1/8" 178 ft3 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 215 / X-52 / Weld N/A Surface 107' N/A 9-5/8" Surface 40 / L-80 / TX BTC 8.835 Surface 9,055' 0.0758 7" Intermediate 26 / L-80 / TXP-BTC 6.276 Surface 13,054' 0.0383 4-1/2" Liner 12.6 / L-80 / TXP-BTC 3.958 12,900' 13,777' 0.0152 �y TUBING DETAIL 4i 2-7/8" Tubing 6.5 / L-80 / EUE 1 2.441 1 Surface 1 ±12,800' 1 0.0087 !!" WELL INCLINATION DETAIL KOP @ 400' Max Hole Angle 65 deg JEWELRY DETAIL No. Top MD Item ID FT ±140' ST 3: Camco 2-7/8" X 1" GLM, DUMMY Status ±4,970' ST 2: Camco 2-7/8" X 1" GLM, DUMMY 1 ±5,000' Viking ESP Packer w/ dual Vent valves split w/ single control line (2,500psi opening) 2 ±12,590' ST 1: Camco 2-7/8" X 1" GLM, DUMMY 3 ±12,650' 2-7/8" XN Nipple - No-go = 2.25" 2.25 4 ± Discharge Head: 5 ± Pump 1: 6 ± Pump 2: 7 ± Gas Separator: 8 ± Upper Tandem Seal: 9 ± Lower Tandem Seal: 10 ± Motor: 11 ±12,795 Sensor & Centralizer: Bottom @ ±12,800' 12 ±12,945' Liner Top Packer 4.340 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk C 13,354' 13,358' 7,251' 7,255' 4 2-1/8" 12/25/19 Open Kuparuk B7 ±13,437' ±13,450' 13 2-1/8" 12/25/19 Future Kuparuk A2 13,456' 13,460' 7,347' 7,350' 4 2-1/8" 12/13/19 Open Kuparuk Al ±13,485' ±13,510' 25 2-1/8" 12/25/19 Future Ref Log: xx/xx/xxxx Halliburton MWD GENERAL WELL INFO API: 50-029-23650-00-00 Cased by Innovation: 11/29/2019 Revised By: TTW 12/30/2019 Ane Point ASR 11" BOP (Triple) 12/30/2019 Hilrorp 11" BOPE Updated 12/30/19 F v CD 0 CD v CD 0 v wx go -, cn v C7 °�rrO v ic 0 cn m 0 s m C 0 j N 0 nLn a o 0 D CD r 11 � o m a Qn C) c m cn w � 3 Cl) W v r a v Cr 0 Q- �. 0 0 C: m 3 cD m CL v D a v 70 0 co 0_ 0 0 m M cr m 0 C 0 0 a� c� D W O a D 0 wx go -, cn v C7 °�rrO v ic 0 CD s m C 0 j N 0 nLn a o 0 D CD r 11 � o m a Qn C) c O cn w � 3 Cl) W v r a Cr 0 Q- �. 0 0 C: 3 cD m CL v D a v 70 0 co 0_ cr m 0 wx go THE STATE 'ALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk Oil Pool, MPU F-116 Permit to Drill Number: 219-133 Sundry Number: 319-545 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, V�Q _rey.Price Cair DATED this \1 day of December, 2019. RIBDMS p DEC 19 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RE7'e DEC 2 - 2019 Vr5 (ZI /7161 AOGGL; 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑� Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate Q Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ESP Change -out ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development ❑✓ Stratigraphic ❑ Service ❑ 219-133 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23650-00-020 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 432D > Will planned perforations require a spacing exception? Yes ❑ No Q Milne Point unit F-116 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL025509 / ADL355017 Milne Point Field / Kuparuk Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 13,785' 7,656' 13,777' 7,648' 3,113 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 80' 80' Surface 9,029' 9-5/8" 9,055' 4,724' 5,750psi 3,090psi Production 13,029' 7" 13,054' 6,968' 7,240psi 5,410psi Liner 877' 4-1/2" 13,777' 7,648' 8,430psi 7,500psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 3-1/2" 9.3# / L-80 / Hydril 563 12,935' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Liner Top Packer and N/A 12,900' MD / 6,824' TVD and N/A 12. Attachments: Proposal Summary Wellbore schematic 1,/1 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: 12/12/2019 OIL ❑✓ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson Contact Name: Taylor Wellman Authorized Title: Operations Manager Contact Email: twellman hllcor .colli ` Contact Phone: 777-8449 Authorized Signature: Date: 11 Z` i COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: -5�f5 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: BDMS DEC 19 2019 Post Initial Injection MIT Req'd? Yes [:]No ❑ �^� Y LJ If(s/� C� Spacing Exception Required? Yes F1 No Subsequent Form Required: V � J►(APPROVED BY 1 y Approved by: V� I COMMISSIONER THE COMMISSION Date: `_j�j i(3 it`d Form 10-403 Revised 4/2017 A.,�� 0 m G I N A L �� z� �9,,�; 6 -11 A., Approved application is valid for 12 months from the date of approval. Attachments in Duplicate Schematic Hileorp Alaska. I,LC Orig. KB Elev.: 38' / GL Elev.:11.5' TD =13,785' (MD) / TD =±7,774' (TVD) PBTD =13,692' (MD) / PBTD =±7,659' (TVD) Milne Point Unit Well: MPF -116 Last Completed: 11/29/19 PTD: 219-133 TREE & WELLHEAD Tree SM 4-1/16" Wellhead I 5M FMC Gen IV OPEN HOLE/ CEMENT DETAIL Conductor Driven 12-1/4" Stg 1 L - 2240 ft3 / T - 458 ft3 / Stg 2 L - 1776.3 ft3 / T - 314 ft3 9-7/8"x 8-1/2" 215 ft3 6-1/8" 178 ft3 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 215 / X-52 / Weld N/A Surface 107' N/A 9-5/8" Surface 40 / L-80 / TXP-BTC 8.835 Surface 9,055' 0.0758 7" Intermediate 26 / L-80 / TXP-BTC 6.276 Surface 13,054' 0.0383 4-1/2" Liner 12.6 / L-80 / TXP-BTC 3.958 12,900' 13,777' 0.0152 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / Hyd563 I 3.958 I Surface 1 12,922' 1 0.0087 WELL INCLINATION DETAIL KOP @ 400' Max Hole Angle 65 deg JEWELRY DETAIL No. Top MD Item ID 2 12,770' 3-1/2" Sliding Sleeve 2.992 3 12,826' 3-1/2" XN Nipple - (`d e: 2.725 4 12,905' Sealbore — Bottom at 12,922' and 2.992 5 12,900 HES VersaFlex Liner Top Packer 4.340 GENERAL WELL INFO API: 50-029-xxxxx-00-00 Cased by Doyon 14: xx/xx/xxxx PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk C ±13,694' ±13,702' S 2-1/8" xx/xx/xx Future Kuparuk A3 ±13,770' ±13,778' S 2-1/8" xx/xx/xx Future Ref Log: xx/xx/xxxx Halliburton MWD Revised By: TTW 12/4/2019 ITI Hilcorp Alaska, LLC November 29, 2019 Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: Hydraulic Fracturing Application, Milne Point Unit, MP F-116 Dear Commissioner Price, Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Taylor Wellman Operations Engineer (907)777-8449 Hilcorp Alaska, LLC ("Hilcorp"), as Operator of the Milne Point Unit, herein submits its application to fracture stimulate MP F-116. Please do not hesitate to contact Taylor Wellman at 907-777-8449 should you have any questions regarding this application. Sincerely, ( e/I - Chad Helgeson, Operations Manager HILCORP ALASKA, LLC Enclosures: Form 10-403 Sundry Attachments 20 AAC 25.283 (a)(1) Affidavit Affidavit stating that all owners, landowners, surface owners, and operators within a one-half mile radius of the current or proposed wellbore trajectory have been provided a notice of operations that is in compliance with 20 AAC 25.283 (a)(1) HHilcorp Alaska, LLC November 27, 2019 Toni Stokes, Acting Director Division -of Oil and Gas Alaska Department of Natural Resources 550 W. 7' Avenue, Ste, 1100 Al tch-orage AK 99501-351.0 Re: Notice of Hydraulic Fracturing Operation — Milne Point MP P-116 Dear Mr. Stokes, Past (Iffxx- Box 244027 Anrha",ge, AK "S24-402'7 MOO Crntupalft Drlvc 5 5U10? 1.400 Ar)MOrage, AK 99503 Pha,i,e' 9071777-6412 Hilcorp Alaska, LLC ("Hilcorp Alaska7),as Operator of the Milne Point Unit, reevnitly submitted an application to the Alaska Oil and Gas ComseiAation Commission ("AOGCC") to allow for the hydraulic fracturing of Milne Point Unit WeH MP F-1161. The surface of the well is located on ADL 025509 and the bottom hole location falls on ADL 355017. 'Yee attached map (ExhibitA). I lilcorp and our joint working interest owner,, BP Exploration (AlasLa) Inc. ("BPXA"), own all applicable !cases within the MPU. The. State of Alaska, Department of Natural Resources is the sole landowner and surface owner. There are no other aff"ted landowners, owners or operators within, a one-half mile radius of the well- Moreover, there are no water wells within this affected area and therefore no water well sampling is required. A complete copy of our ApplicWhin for Sundry Approval can be obtained from the undersigned at the address above, or by requesting a copy from the public records at the folloN%ring address: Alaska Oil and Gas Conservation Commission 33;3 West 71t' Avenue -Suite 100 Anchorage, Alaska 99501 Phone: (907) 279-1433 Sincerely, Taylor Well ir Operations Engineer Taylor HILCORP'A.4c SIVA, LLC CC: Yuliva McDaniel, 111'XA (via email Yuliya.McF)aniel( qbpcorn) I-andowrier Notifitation Letter Mr 12-116 Page 2 of 3 ser" 19 'n,617r Sec. 30 (6201 V P] W il-M Sec. 31 (0;12J Legend F-Ilk-pall"Is V'xhihitA: MPF-116PIat see. Sec_ 29 -" WOMM 40#0 op"T Sec, 37 Svc. MILNV POINT UN Top of Frac Zone 5 13,35X mo f s1wr, 5 1 Soc. 4 Sec. 4! Milrio PoInt, Unit IAPF-116 Well EXhl it A U813NDIDE I AULG41414 sn-r__ 9 NwCr P41M VW* "n W.'W*f Wes% WoMn 312 man 0 1,250 2-sw mm" Feet Lmdowavj Notification 14tter W F-116 Pagc 3 00 VERIVICA110N OF NOTICE PER 20 AAC 25.283(a) MII,N.f--", POINT UNIT MP F-116 1, TAYLOR WELLMAN, Operations Engineer, do hereby verify the following: 1. ani acquainted with Hilearp Alaska, LLC's application for sundry approval to the Alaska Oil and Gas Conservation Commission to enhance production of the MP F -I 16 well, via hydraulic fiacturing- Pursuant to 20 AAC 25.283(a)(1), I assert that all owners, landowners, surface owners, and operators within a one4ialf mile radius of the current or proposed wellbore trajectory have been provided notice of Hilcorp Alaska, LLC"s proposed operations. ItI7 DATED at Anchorage, Alaska this Hday of Novernher, 2019. Taylor Iman, Operations Engmecr Hilcorp Alaska, LLC. STAT E OF ALASKA THIRD JUDICIAL DISTRICT SUBSCR I B F DTO AND SWORN before me this.)4 day of November, 2019. �vt 1u 5407�A'- BLIC IN 'IND FOR 0 . 41'S THE SI�A-: F , �A STATE OF ALASKA My Commission expires,. NOTARY PUBLIC M. Sbine 9 �jorj okvm Fob 2& 2M 20 AAC 25.283 (a)(2) A Plat F, (A) Showing The Well Location; (B) Identifying each Water Well, if any, Located within a One -Half Mile Radius of the Well's Surface Location; and Wells within % mile Well Name PTD Annulus Integrity MPU F-116 219-133 9-5/8 casing tested on 2,500 psi on 11/7/19 before drillout of shoe. 4-1/2" production liner: Pumped 21bbls / 7" casing x 4-1/2" production liner MIT'd on 11/27/19 passed to 4,000psi MIT -T on 11/28/19 passed to 4,000 psi ESP Producer — returns during job. Plug bumped, floats MIT -IA on 11/29/19 passed to 3,500 psi MPU F-49 197-003 MIT -IA on 10/21/18 passed to 2,000psi MPU F-57 197-040 MIT (7" casing) on 11/12/03 passed to 3,000psi MPU F -57A 203-167 MIT -IA on 5/6/13 passed to 3,500psi MPU L-21 195-191 MIT -IA on 1/21/19 passed to 2,900psi MPU L-29 195-009 MIT -IA (7" casing to 13,000' md) on 1/18/12 passed to 3,000psi Completion Detail API Well No Permit Well Current Status Zonal isolation (method) 4-1/2" production liner: Pumped 21bbls / 102 sxs of 15.8ppg Class G cement. Full ESP Producer — returns during job. Plug bumped, floats 50-029-23650-00-00 219-133 F-116 Kuparuk Oil Pool held and MIT casing to 3,000psi good. CBL planned to be run and results will be provided prior to proceeding. Pumped 56bbls / 275 sxs of 15.8ppg Class G cement. No returns during job. Plug bumped, floats held and MIT casing to 50-029-22732-00-00 197-003 F-49 WAG Injector — 4,000psi good.Kuparuk Ultrasonic Imager CBL run on 02/17/97 indicates good cement to 14,230' and and a TOC of 13,930' md. 7" casing was isolated with 2 plugs: EZSV @ 16,003' and w/ TOC @ 15,451' md; ESP Producer — EZSV @ 9364' md. Both plugs MIT'd to 50-029-22747-00-00 197-040 F-57 Kuparuk Oil Pool 3,000psi on 11/12/03. 7" casing was run to 16,732' md, cemented with 51bbls of 15.8ppg Class G, bumped plug and floats held. MIT casing to 3,500psi good. Pumped 37bbls / 180 sxs of 15.8ppg Class G cement. No returns during job. Plug bumped, floats held and MIT casing to ESP Producer— 4,500psi good on 11/29/03. 50-029-22747-01-00 203-167 F -57A Kuparuk Oil Pool CBL indicates TOC above 15,900' and (above tubing tail of the frac string and logging capability at time of logging) on 12/27/03. 7" casing set across Kupuaruk sands. 50-029-22629-00-00 195-191 L-21 LTSI — Water Cemented with 51 bbls / 250sxs of 15.8ppg Injector cement, plug bumped, floats held and full returns during entire job. Shut In ESP Pumped 61 bbls / 300 sxs of 15.8ppg Class 50-029-22543-00-00 195-009 L-29 Producer — G cement. Plug bumped, floats held and Kuparuk Oil Pool full returns during job. Ser:. 19 Sec. 30 (620) Mile radius nd MPF -116 ADL35501B Sec. 31 (622) Sec. 2D Sec.. 21 7J,%4�— 11 PF -5r7 U014N1a10E51117 __j I MPF -'I 6 MPL-21 � s$c_ 3z Sec_Amma- 3 d,,. ! MPL-29 Top of Fras Zare 13,352 MD Sec. 4 U013NO 10E ADLO47434 Legend - F -916 -Points a Virll itssc r ��` � 0 NIPF•11�6_SIC �� Sec" 8 Sec_ J D PA'F-11$ TPH MPF -116 -SM Milne Paint Unit DCes: N1«Well Qambase.1 MPF -116 Well Mo wry Wats within 1J2 mile k—,"`•. ` Exhibit A 0 1.250 2 500 Feel Sec. 19 Sec, 20 .161 F I Arwym,ills, "-- sec- 30 5,ft 29 (620)' 1 112 Mille- ra-d,ium 1000 UMN410e � mAmPlsfr ApLiMM arc. 3tSee. MOM 19 PONT JJW .0of 112,3w ml :501 5 1 Sac. 4 U013NOICE I AOLS41424 sec. 9 See. a X 0 tFJ-1 td IFIL NWra rvi.ine Point unit r)qt2t=sc � I tax MPF -116 Well W W4W VVvtaqthn III nan EXIIII31t A 0 i2m 2'sm it" DAN ltqSllb =feel (C) Identifying for all Well Types each Well Penetration Well API PTD Pool Type Status MPF -01 50029225520000 1950450 KR 1 -OIL Producing MPF -02 50029226730000 1960700 TER WSW Producing MPF -05 50029227620000 1970740 KR 1 -OIL Shut In MPF -06 50029226390000 1960020 KR 1 -OIL Producing MPF -09 50029227730000 1971040 KR 1 -OIL Producing MPF -10 50029226790000 1960940 KR WAG Injecting MPF -13 50029225490000 1950270 KR PWI Injecting MPF -14 50029226360000 1952120 KR 1 -OIL Producing MPF -17 50029228230000 1971960 KR WAG Shut In MPF -18 50029226810000 1961000 KR 1 -OIL Producing MPF -21 50029226940000 1961350 TER WSW Producing MPF -22 50029226320000 1952010 KR 1 -OIL Producing MPF -25 50029225460000 1950160 KR 1 -OIL Producing MPF -26 50029227670000 1970840 KR WAG Injecting MPF -29 50029226880000 1961170 KR 1 -OIL Shut In MPF -30A 50029226230100 2131880 KR WAG Injecting MPF -33A 50029226890100 2010620 SR Suspended Suspended MPF -34 50029228240000 1971970 KR 1 -OIL Producing MPF -37 50029225480000 1950250 KR 1 -OIL Shut In MPF -38 50029226140000 1951680 KR 1 -OIL Producing MPF -41 50029227700000 1970950 KR Suspended Suspended MPF -42 50029227410000 1970200 KR WAG Injecting MPF -45 50029225560000 1950580 KR 1 -OIL Producing MPF -46 50029224500000 1940270 KR WAG Injecting MPF -49 50029227320000 1970030 KR WAG Shut In MPF -50 50029227560000 1970580 KR 1 -OIL Producing MPF -53A 50029225780100 2131360 KR 1 -OIL Producing MPF -54 50029227260000 1961920 KR 1 -OIL Producing MPF -57A 50029227470100 2031670 KR 1 -OIL Shut In MPF -58 50029227060000 1961560 TER WSW Producing MPF -61 50029225820000 1951170 KR 1 -OIL Producing MPF -62 50029226090000 1951610 KR WAG Shut In MPF -65 50029227520000 1970490 KR 1 -OIL Producing MPF -66A 50029226970100 1961620 KR 1 -OIL Producing MPF -69 50029225860000 1951250 KR 1 -OIL Shut In MPF -70A 50029226030100 2131690 KR WAG Injecting MPF -73A 50029227440100 2001980 KR 1 -OIL Producing MPF -74A 50029226820100 2131890 KR WAG Injecting MPF -77 50029225940000 1951360 TER WSW Producing MPF -78A 50029225990100 2131760 KR 1 -OIL Producing MPF -79 50029228130000 1971800 KR 1 -OIL Producing MPF -80 50029229280000 1982170 KR Suspended Suspended MPF -81 50029229590000 2000660 KR 1 -OIL Shut In MPF -82A 50029229710100 2091350 KR WAG Injecting MPF -83 50029229630000 2000930 KR WAG Shut In MPF -84B 50029229310200 2001760 KR WAG Injecting MPF -85 50029229360000 1982500 KR WAG Injecting MPF -86 50029230180000 2010870 KR 1 -OIL Producing MPF -87A 50029231840100 2032130 KR 1 -OIL Producing MPF -88 50029231850000 2031930 KR WAG Injecting MPF -89 50029232680000 2050900 KR WAG Shut In MPF -90 50029230510000 2012110 KR WAG Shut In PF -91 50029232710000 2051100 KR WAG Injecting M -92 50029229240000 1981930 KR WAG Shutln MPF -93 50029232660000 2050870 KR 1 -OIL Producing MPF -94 50029230400000 2011700 KR 1 -OIL Producing MPF -95 50029229180000 1981790 KR WAG Injecting MPF -96 50029234060000 2081860 KR 1 -OIL Producing MPF -99 50029233320000 2061560 KR WAG Injecting MPF -106 50029236000000 2180280 SB PWI Injecting MPF -107 50029235920000 2180010 SB 1 -OIL Producing MPF -108 50029235980000 2180210 SB PWI Injecting MPF -109 50029235960000 2180140 SB 1 -OIL Producing MPF -110 50029235990000 2180220 SB PWI Injecting 20 AAC 25.283 (a)(3) Identification of Freshwater Aquifers There are no underground sources of drinking water within a one-half mile radius of the current wellbore trajectory. Any and all freshwater aquifers lying below the Milne Point Unit are exempted aquifers under Aquifer Exemption Order 2 (AEO-2). See the Conclusion of AEO-2, which states that "The portions of freshwater aquifers lying directly below Milne Point Unit qualify as exempt freshwater aquifers under 20 AAC 25.440." 20 AAC 25.283 (a)(4) Baseline Water Well Sampling There are no water wells located within one-half mile radius of the current wellbore trajectory. A water sampling program is not required. 20 AAC 25.283 (a)(5) Detailed Casing and Cementing Information 9-5/8" 40#/ft L-80 TXP-BTC surface casing set at 9,055' MD with ES Cementer at 2,772' MD. First stage cemented with 900 sxs / 377 bbls of ExtendaCem 12 ppg cement followed by 400 sxs / 82 bbls of 15.8 ppg Class G cement. Rotated and reciprocated during V stage. Bumped plug, full returns during pumping with cement returns once ES Cementer was opened. Second stage cemented with 447 sxs / 351 bbls of Perm L 10.7ppg cement followed by 270 sxs / 56.2 bbls of 15.8 ppg Class G cement. Bumped plug, full returns during pumping and cement returns to surface. 7" 26#/ft L-80 TXP-BTC production casing shoe set at 13,053' MD and cemented. Pumped 40 bbls 11.0 ppg Tuned Spacer followed by 180 sxs / 38.3 bbls of 15.8 ppg ExtendaCem cement with 70% returns during the job. Plug did not bump and floats held. 4-1/2" 12.6#/ft L-80 TXP-BTC production liner shoe set at 13,777' MD and cemented. Pumped 60 bbls 12 ppg Tuned Spacer followed by 102 sxs / 21 bbls of 15.8 ppg Premium G cement. Full returns during cementing. Bumped plug and floats held. Detailed Casing Information Size Type Wt/ Grade/ Conn Pipe Body Yield (Ibs) Collapse Pressure (psi) Internal Yield Pressure (psi) Conductor N/A N/A N/A N/A 9-5/8" Surface 40# / L-80 / TXP-BTC 916,000 3,090 5,750 7" Production 26# / L-80 / TXP-BTC 604,000 5,410 7,240 4-1/2" Liner 12.6# / L-80 / TXP-BTC 288,000 7,500 8,430 Detailed Tubing Information 3-'/2" Tubing 9.2 / L-80 / Hydril 563 207,200 10,540 10,160 20 AAC 25.283 (a)(6) Assessment of Each Casing and Cementing Operation Performed to Construct or Repair the Well The 9-5/8" 40#/ft L-80 TXP-BTC surface casing set below the Schrader Bluff sands at 9,055' MD. An ES Cementer was set at 2,772' MD for a 2 stage cement job. First stage cemented with 900 sxs / 377 bbls of ExtendaCem 12 ppg cement followed by 400 sxs / 82 bbls of 15.8 ppg Class G cement at 3.6 bpm. Displaced cement by pumping 4 bpm until bumped the plug. Full returns were observed during pumping with cement returns once ES Cementer was opened. The casing was rotated and reciprocated during VY stage. The second stage was cemented with 447 sxs / 351 bbls of Perm L 10.7ppg cement followed by 270 sxs / 56.2 bbls of 15.8 ppg Class G cement. Bumped plug, full returns during pumping and cement returns to surface. The 9-5/8" casing is adequately cemented The 7" 26#/ft L-80 TXP-BTC production casing shoe set in the Kuparuk D formation at 13,053' MD and cemented. Pumped 40 bbls 11.0 ppg Tuned Spacer at 3.5 bpm followed by 180 sxs / 38.3 bbls of 15.8 ppg ExtendaCem cement at 2.3 bpm. Displaced with 10.2 ppg mud at 5 bpm. The 7" casing was reciprocated during the cement job. There were 70% returns during the job. Plug did not bump and floats held. The 7" casing is adequately cemented. The 4-1/2" production liner shoe was set across the Kuparuk River formation and cemented with a single stage cement job. A 60 bbls 12 ppg Tuned Spacer was followed by 102 sxs / 21.0 bbls of 15.8 ppg Premium G cement at 3.5 BPM average rate. The liner was not rotated/reciprocated. Bumped plug and floats held. Pressured up to 4,425psi, expanded liner hanger/packer and released from same. Pressure tested liner and liner lap to 3,000psi for 30 min (charted). The 4-1/2" CBL/VDL log will be submitted after completing the logging run post -rig. 20 AAC 25.283 (a)(7) Plans to Pressure -Test the Casings and Tubing Installed in the Well The 9-5/8" casing pressure tested to 2,500 psi for 30 minutes on November 9, 2019. The 7" casing pressure tested to 4,000 psi for 10 minutes on November 27, 2019. The 4-%" liner pressure tested to 4,000 psi for 10 minutes on November 27, 2019. The 3-%" tubing was pressure tested to 4,000 psi for 30 minutes on November 28, 2019. The 3-1/2" x 7" annulus pressure tested to 3,500 psi for 30 minutes on November 29, 2019. 20 AAC 25.283 (a)(8) Pressure Ratings and Schematics for the Wellbore, Wellhead, BOPE, and Treating Head Size Weight #/ft Grade API Collapse Pressure (psi) API Internal Yield Pressure (psi) 9-5/8" 40 L-80 3,090 5,750 7" 26 L-80 5,410 7,240 4-1/2" 12.6 L-80 7,500 8,430 Treating Head 15M Wellhead 5M BOPE N/A OIL STATES J Energy Services (Canada) Inc. Maximum Allowable Pumping Rates PROPOSAL: Casing Isolation Tool SIZE CSG ID 2.250 .. 3.750 RATE m3lmin 10 m'lmin 3 112" Big Bore 1.750 .2.750 6 ml/min 2 718" & 3 112" 1.438 2.360 4 m'/min 2 3/8" 1.000 . 1.900 2 m'/min 3 1116 & 4 1116 with tapered mandrel 2.750 4.000 15 m'/min 4 1/16 X Tool Mandrel 3.610 4.750 24 m'/min 1YTlUli vu� tt01 15M Treating Head OPEN POSITION OR TO '.W+'fN!C:L %,v# i ru) CLOSED POSITION J.\WJ wt 01suffol OWD fA(iMT A4SLMLLY IN IIAf! IK 1LEII.T. www.StingerCanada.com 20 AAC 25.283 (a)(9) Data for the Fracturing Zone and Confining Zones (A) a lithologic description of each zone; (B) the geological name of each zone; (C) the measured depth and true vertical depth of each zone; (D) the measured thickness and true vertical thickness of each zone; and (E) the estimated fracture pressure for each zone; The Kuparuk formation is a Cretaceous -aged, fine-grained marine sandstone. The productive Kuparuk interval in the F-116 area consists of the Kuparuk C, Kuparuk B, and Kuparuk A sands. Formation tops and TVT numbers for the productive intervals are listed in the table below: Well Formation MD TVD TVT F-116 KUPARK C 13,350 7,247 8 F-116 KUPARUK B 13,385 7,280 50 F-116 KUPARUK A 13,438 7,330 97 F-116 KUPARUK A BASE 13,542 7,427 50 The estimated fracture gradient for the Kuparuk interval is 0.65-0.68 psi/ft. The overlying confining zone consists of 2000' TVD of Kalubik, HRZ shale and Colville siltstones and shales. The top HRZ shale in well F-116 is at—12,879MD / 6,841' TVD. The top of the Colville is at 8,728' MD/6,861' TVD. The estimated fracture gradient for the Kalubik/Hrz is 0.75-0.82 psi/ft. The underlying confining zone consists of the Milluveach shales. The top of the Milluveach shales in well F-116 is at 13,510' MD / 7,434 TVD. The estimated fracture gradient for the Milluveach shale is 0.8-0.82 psi/ft. 20 AAC 25.283 (a)(10) The Location, the Orientation, and a Report on the Mechanical Condition of Each Well that May Transect the Confining Zones MPF -49: 7" casing set across the Kuparuk sands and cemented with 56bbls / 275 sxs of 15.8ppg Class G cement. No returns during job. Plug bumped, floats held and MIT casing to 4,000psi good. Ultrasonic Imager CBL run on 02/17/97 indicates good cement to 14,230' and and a TOC of 13,930' md. MPF -57: 7" casing set across the Kuparuk sands and cemented with 51bbls of 15.8ppg Class G. Bumped plug and floats held. MIT casing to 3,500psi good. This wellbore has been P&A'd and the 7" casing was isolated with 2 plugs: EZSV @ 16,003' and w/ TOC @ 15,451' md; EZSV @ 9364' md. Both plugs MIT'd to 3,000psi on 11/12/03. MPF -57A: 7" casing set across the Kuparuk sands and cemented with 37bbls / 180 sxs of 15.8ppg Class G cement. No returns during job. Plug bumped, floats held and MIT casing to 4,500psi good on 11/29/03. CBL indicates TOC above 15,900' and (above tubing tail of the frac string and logging capability at time of logging) on 12/27/03. MP L-21: 7" casing set across the Kuparuk sands and cemented with 51 bbls / 250 sxs of 15.8 ppg Class G cement with 30% returns during job. Bump plug with 3500 psi. Estimated TOC from CBL is 12,000' MD. MPL-29: 7" casing set across the Kuparuk sands and cemented with 61bbls / 300 sxs of 15.8ppg Class G cement. Plug bumped, floats held and full returns during job. CONFIDENTIAL 20 AAC 25.283 (a)(11) The Location of, Orientation of, and Geological Data for Each Known or Suspected Fault or Fracture that May Transect the Confining Zones The map above shows the structure at the top of the Kuparuk C Sand interval. All faults shown are inferred from high-quality seismic data. Well F-116 is located at a distance of between 290'-1480' from the nearby faults, as shown in the map above. Horizontal principal stress from well data indicate that the fracture should propagate approximately NW -SE (SHmax is NW -SE, SHmin is NE -SW). Based on current mapping and fracture modeling results, the fracture wings should not extend into the nearby faults. fVI_ rt1< 20 AAC 25.283 (a)(12) Proposed Hydraulic Fracturing Program Proposed Hydraulic Fracturing Program 1. RU SL and PCE. PT to 2,000 psi (Cemented, pressure tested, and unperforated/fully isolated wellbore). 2. RIH and drift liner to PBTD at 13,785' MD. 3. RD SL. 4. RU E -Line and PCE. PT to 2000 psi (Cemented, pressure tested, and unperforated/fully isolated wellbore). 5. Run CBL from PBTD (13,785' MD) to top of 4-1/2" liner at ±12,893' MD. Run repeat section as needed. �—� A 0Gic a. Send data to Operations Engineer: Taylor Wellman, twellma6@hilcorp.com. 6. RDMO E -Line. 7. RU E -Line and PCE. PT to 3,500 psi (MPSP is 3,113 psi / estimated Kuparuk River reservoir pressure). 8. Perforate the Kuparuk A sand formation from ±13,455 - ±13,469' MD. Confirm final depths with Telj Perf Sheet. a. Note that when perforating, wellbore will be —800 psi underbalanced to aide in perf tunnel clearing. b. Perf Charges: Geodynamics 2-1/2" 2511 ReFrac IQ, 60 deg phasing, 6 spf. c. Correlation Log: MPU F-116 Open Hole Logs dated: 24 -Nov -2019 d. Log Jewelry Log of GR/CCL from ±13,600'– 12,850' MD (above the 7"x4-1/2" liner hanger). 9. RDMO E -Line. 10. MIRU frac fleet. MIRU frac and slop tanks. MIRU all ancillary support equipment. 11. Fill frac tanks with water. Heat water as needed. 12. Lay all hardline and manifolds. Install pressure monitoring equipment on wellhead and tree. Monitor 7" x 4-1/2" annulus pressure during DFIT and fracture stimulation. RU flowmeter if performing forced closure on tank return line. 13. RU hardline from 9-5/8" x 7" annulus to tank and shall be left open to atmosphere during the stimulation job. 14. RU 15K tree saver and hard line. 15. Pressure test all high pressure treating lines to 8,000 psi. 16. Set the GORV (gas operated relief valve) at ±7,000 psi. Set the staggered pump kickouts between 6,800 psi and 6,400 psi. 17. Pressurize annulus to 3,500 psi. Set annular PRV at 3750 psi. .3 PS; 18. Prepare frac fleet to pump. 19. Pump Kuparuk A sand DFIT and analyze the results to obtain fluid loss coefficients. Adjust frac design. 20. Fracture stimulate Kuparuk A sand with 16/20 mesh resin coated proppant in cross-linked gel. See "Pump Schedule" for proposed design. 21. Displace with freeze protect fluid. Underdisplace by ±3 bbls. Do not over displace. 22. Shut well in. Perform forced closure (optional) 23. RD tree saver. 24. RU Slickline and pressure test PCE to 500 psi over observed WHP. 25. Drift and tag top of fill w/ memory GR/CCL. POOH and RD Slickline. 26. MIRU CTU and associated equipment. 27. RU CTU BOPE and PT to 4,000 psi. a. Contingency (if top of fill/sand is above 13,340' md): RIH and cleanout frac sand/frac fluid 0 to ±13,390' md. 1 t` b. Contingency (if top of sand is below 13,410'): Place sand cap of 20/40 and 16/20 back to ±13,390' MD. 28. Tag top of sand and log GR/CCL pass up. a. Flag coil at ±13,275' and on way out of hole in case a new sandback is needed. 29. Pressure test sand plug to 3,OOOpsi to check for leakoff rate. 30. RU E-Line and PCE. PT to 4,000 psi. 31. Perforate the Kuparuk C sand formation from ±13,352' - ±13,369' MD. Confirm final depths with the Perf Sheet. a. Perf Charges: Geodynamics 2-1/2" 2511 ReFrac IQ, 60 deg phasing, 6 spf. 1111 �� b. Correlation Log: MPU F-116 Open Hole Logs dated: 24-Nov-2019 V 32. RDMO E-Line. V33. RU 15K tree saver and hard line. 34. Pressure test all high pressure treating lines to 8000 psi. 35. Set the GORV (gas operated relief valve) at±7,000 psi. Set the staggered pump kickouts between 6,800 psi and 6,400 psi. 36. Pressurize annulus to 3,500 psi. Set annular PRV at 3750 psi. 37. Prepare frac fleet to pump. 38. Pump Kuparuk C sand DFIT and analyze the results to obtain fluid loss coefficients. Adjust frac design. 39. Fracture stimulate Kuparuk C sand with 16/20 mesh resin coated proppant in cross-linked gel. See "Pump Schedule" for proposed design. 40. Displace with freeze protect fluid. Underdisplace by ±3 bbls. Do not over displace. 41. Shut well in. Perform forced closure (optional) 42. RD tree saver. 43. RU CTU BOPE and PT to 4,000 psi. 44. RIH and cleanout frac sand/frac fluid to PBTD. 45. RD CTU unit. 46. RU Slickline and pressure test PCE to 500psi above shut in WHP. 47. Shift SSD open at ±13,310' md. 48. Set jet pump in SSD at ±13,310' md. 49. RD Slickline unit. 50. Bring well online with jet pump and 'reverse flow jet pump' to flowback well to portable test separator as needed to clean up frac. 51. Turn well over to operations. 20 AAC 25.283 (a)(12) (A) Estimated Total Volumes Planned 20 AAC 25.283 (a)(12) (B) Trade Name, Generic Name, and Purpose of each Base Fluid and Additive to be Used; 20 AAC 25.283 (a)(12) (C) Chemical Ingredient Name of, and the Chemical Abstracts Service (CAS) Registry Number Assigned to, each Base Fluid and Additive to be used; 20 AAC 25.283 (a)(12) (D) Estimated Weight or Volume of each Inert Substance, including a Proppant or other Substance injected BS 31 Client: Alaska Onestift well: MPU F-110 rudho 1.E Ga 1COO GcI Basin/Field: PPrudhoe Say Breaker 121E State: Alaska -� A7^ County}Fartsh: North slope Borough 017.D ib Case: 2,943.0 Lb 1330 YF12a flexD'W FE28 1 W,884 Gel _ X,24 Disclosure Type. Pre -lob 2024 Gal Welt Cornpleted: 12/20,12019 L071 Clay Control Agent Date Prepared: 12/2/2019 2.11 PM 1 tb / lOt^A Gel Report ID: RPT -64401 BS 31 solid scale Inhibitor 8311 vanec concentration: 50,035.7 ib F 10 _� surlaLiarxt 1.E Ga 1COO GcI E06A Gal 1218 Breaker 121E D.S ib /iD:O Gal 30.0 16 -� A7^ Breaker 6.1 lb f io..0 WI 017.D ib 29 2 ib r 3070 Gal 2,943.0 Lb 1330 YF12a flexD'W FE28 1 W,884 Gel _ X,24 GelliatBAyent _ CrossOnkrr 1004 _.. _.._ ,. 2.6 Gal/1COOGal 2024 Gal 2.1 Gal / 1400 Gal 210.D Gal L071 Clay Control Agent "OZ2 Additsre 1 tb / lOt^A Gel 104.0 Lb • k127.5 .1_ Bactericide _ o.5 lb ; loDa Gal 48.0 ib 5920-16,0 Propping Agent varied concentrations 283,549.3 1b 71r fcrnl .uls'nr.SMbal of dM mils nin : tg•.-,.n.a rhe au.+man.m+f ,.vlwu^f u:ttCin, tYWxr,u vycr.5st is/ coni. 2,0.01 -0.01 % - Water (lrxiudlnS Mix Water supplied by Client)` ^' 71 % E 473.08-4 Ceramic materials and wares, chemicals "28 % _...._._..... Potassium salt of maleic acid c0-polvin" < i % 9COO.aD.O c7-48.1 1315-.33-1 .. 7727.54.0 -_.. ....... 307-21-: Guar gum Phen_ck resin _ 2hyd coy"N.N,N-trlmethylethanaminl�m ch-aje t;'.exi:e .... MalnmonlLm p_•roxidi: Jlphatc ftF)'lent Glycol - -1 � 1 % 3 % 40:1 % 4 0.1 Propane -2.01 i 0.1 % 111.7a-2 2-hutoayet?hanal - 0.1 % _ 3n33^o-71.1 Ethoxylated C11 Alcohol - 0.1 % 25038-72-a vwtdene chloride(methylacrylate copolymer -0.01 % 1310.73-2 Sodium hydroxide 1303.96-4 sodium Tetraborate Decahydrate -0.01 % _ 68131-39-3 _ Ethoxylated Alcohol -0.01 %_ 93036-39-3 11.2-42.9 7CK-80.9 10377-00-3 14807.90-0 _ 20172-05-4 Diatomaceous earth, calcined but-2-ene&olc acd - tJndecancl lion- :,01a line silica (impurity) Magnesium nitrate Magnesium WKate hydrate (talc) S-chloro-2-methy4-2h-Lsothlaz0{al-3-one -.0.02 % 2,0.01 -0.01 % - MOM % _ � O.D01 % <0.001 % 7786-3D-3 Mal4teslum chloride K D.00S % 9002-84-0 poty^Itetra;luoroethvlene) - D.D31 % _ 393383-13-2 Olutan s 0.01x13 % _ 1230D3-87-0 Dlutan Sum -^ <. O.ODO2 % 2M2 -2D-4 2-methyl-1h-Isothlazol-3-ane -0.0001 % 127-08-2 _ Acetic acid, potassium salt s O.OW1 % 14we-60-7 Duartz, Crystalline silica < O.ODOl % _..__..___.._ 14404-90-1 .�. Cristoballte -0.0001 64.19-7 Act= acid (impurity) - 0.0001 % '7lr nv6:v.itncy�u :i r. J:ar..awaruy Jcr.av`i4onre.. rurn s^pcsc arcf lhr t.a:•.ar.-slj*-4.xr:G>it�e,Gr.>•rau!.uth �..nwi*=+a+n rRk..m s..uc rraa .,,a«„rn•..I L!c nsu�a. grae.•.:bw''t&d-.nnr �, wntar.,i. +nr nnr.udu!n rt4 nor IK rsJle, t.,t w ih's wz unmt. 20 AAC 25.283 (a)(12) (E) Maximum Anticipated Treating Pressure and Information Sufficient to Support a Determination that the Well is Appropriately Constructed for the Proposed Hydraulic Fracturing Program. The 4-% "production tubing tested to 4,000 psi for 30 minutes, 4-% "production liner tested to 4,000 psi for 30 minutes, and the 7" production casing tested to 4,000 psi for 30 minutes prior to the fracture stimulation. The maximum surface differential pressure the tubing will be subjected to will be 4,000 psi (7,000 psi GORV maximum pressure setting - 3000 psi of pressure on the casing x tubing annulus). The calculated maximum treating pressure is 5,666 psi for the Kuparuk A sand and 5,990 psi for the Kuparuk C sand fracture stimulations. 20 AAC 25.283 (a)(12) (F) Designed Height And Length Of Each Proposed Fracture (i) the calculated measured depth and true vertical depth of the top of the fracture: Kuparuk A Sand: 13,492' MD / 7,380' TVD BKB Kuparuk C Sand: 13,387' MD / 7,282' TVD BKB (ii) a description of each method and assumption used to determine designed fracture height and length: The MP F-116 fracture stimulation was modeled using the FracCADE program. Kuparuk A Sand propped half length0498.7'Kuparuk C Sand propped half length Note — The TVD depths in FracCADE are BKB. Schlumberger FracCADC STIMULATION PROPOSAL Operator HilcorpAteska Well MPF -116 Field Milne Point Formation Kuparuk A cotinty+ North Slope State Alaska Country United Skates PrePared for Taylor Wallman Semse Point Prudhoe Bay Date Prepared 11-29-2019 Prepared by Michael Hyatt Phone 9072734758 E -Mail Address : mhyati>msl6.co , ' FALA 04riti+x! w, liifi�l4tnfiYtr kV�ii[yj "re xiuri"Yy'i+, iAl Ai �� a.cy+fi�fry•gYl3ilisiYd+?�`��Ak4�.+,RV,atr Yr )�ri� lrrayYt�taYyYil'b+e!!i imaf*ril r?deY%U kf ilii"trot Irrn. #s} A5f 311r1 i+Sl YCk+RrYi:C rIf rntYS IRTe erfC9l/MUi SB s!"! Ce L2$'I$1if5 rrLirClGl try'd 2M(f]" rriiCl F;ii(tr! rS+SVS M4Jsissypf')lf y�T#.rC".iriir:axi rrEtitT;af RR�ke+#g �yljzltfn'.4r�rtca+lgalil�ltliiliassll3sallilAr�lisi4li!i5'ArKwa+ldkt�fixlia)m}gicit`iintAm!'yfgdyLtw:zs,ntAAAlralttl:l +riot III" itw rrlmficr= remei ,s ScH'"gerete-0 ".*tot fe sm,31'"1115 hr ng tr. aa,. t-1 eri stv..AQ to Amo i3, cTaµa+vn iigcses:Aixx- m, tt+sitir ,r11- riigmyvrpi 0"NAxl Afrctr?. JN 1f ke nr+c+Vl ult rte Lie U ctnA.YgsArlr+crMxt°.MacyYrlkrit�rs Aszs,r stiC^Sx! +!rrCrM1F'.SIrl+Rrircrt!!i!tItie Aea.ttl`'rp!;ftlTr,yae%TY9,!(I:hxxSSAYS ASr{lr lAtn111ti (!�!�Syv'; AtaXriCa 'cCr+}aais•MHftiAMtjlr7*ry e4!16•MAs a gtl tf 41itw IrEU A11wY'= {?'h iTi[,{�l3'dit;*ti# niiliYyIfi(fw#I f.,.ny7t0, 1fw �t1d{F tY�iY"�rl#( Prfi#puri ;+ifriT/{$iakart}iIll({ Y(r Cs�f ht�Ili1 iNi:3ri klti!_,pia*±AIf? If{ietty 0I51,A,, f#tk.kok irmiouil U14")e @dyt li pNf(—Itty "r.1e5 3cWumberger-Private clic -'rt �-.Iccrp Alaska Well MF:: -116 Fe,rra bn KuFarukA D:gtrr Prodhas Baa' CCAITV trotted States Sectiont: Zone Data Schlumberger-Prhrate Formation Tranmmsrni Sibility Properties Formation Mechanical Properties Zone Name Top TVD iftl Net Height lttl Zone Name Top TVD 1h) Zone Height ittl Frac Grad. loslIf1} Insitu Stress 1p�1 Young's Modulus Ipsl Poisson's Ratio Toughness 1psi.io.5� Kalubik 6621.0 331.0 0.764 5477 1.308E+6 0.35 2000 Kup D 71520 134-0 0.784 5658 1.847E+6 0.35 2000 Kup C 7282.0 12.0 0.664 4810 1.847E+6 0.25 BIYI Kup B 7294.0 73.0 0.7DD 5131 1.729E+6 0.32 2000 Kup A3 7387.0 13.0 0.610 4498 1.729E+6 0.25 2000 KoR m Ku Al 7=0 74090 2.9_0 54.0 0.510 Q.6 4511 �6@5 173 _+6_ 1729E+6 0.2_8 0.32 2000 2000 Miluvear.h 7463.4 100.0 1 0.780 5650 4.494E+6 0.35 1000 Schlumberger-Prhrate Formation Tranmmsrni Sibility Properties Zone Name Top TVD iftl Net Height lttl Perm 11,0 Porosity i%l Res. Pressure ; si1 Sat. i%l Gas Oil Sat.!20.0 11 ter t. Kalubik 6821.0 1-0 0.001 1.0 3595 0.0 80.0 Kup D 71520 1-0 0.001 1-0 3681 0-0 80.D 20.0 Kup C 72824 6.0 5.004 15.0 3744 0-0 80.4 20.0 Kup D 7294.0 6-4 1.000 10.0 3760 0-0 80.4 20.0 Kt A3 _ Kvp A2 7367.!1 7380.0 10.1) _ a,0 40. DDO 40.00 0 22.0 22.0 3790 3800 0-0 80.0 4.0 60A 20.0 20.0 Kup At 7409-0 5-7 20.DDO 13.0 3814 0-4 80.0 20.0 IJliluveach 1 7463-4 1-0 0.001 1-4 3843 0-0 80.D 20.4 Schlumberger-Prhrate Client Alcarp Alaska well MRF'116 fcm-albn XupartikA Os6ct Prudhoe Bay Cwnuv Unhed Siates fthpgep Section Z Propped Fracture Schedule Pumping Schedule The following is the Pumping Schedule to achieve a propped fracture half4ength DGI of 498.7 ftwith an averaga conductivity (Krvvl 08933 md-ft. Please note that this pumping schedule is under-displa c ed bV3,15 bbl Fluid Totals IM bbl oi YFI25FIexD 116 W Qi WFI25 Proppent Totals 193100 lt) of CarboBmd Lite I VN Pad Percentages PAD Clean 24.2 96 PAD t7irty 20.1 7 - Schlumberger -private Job Oestri ption Step Name Pump Rate Jbullhlol fluid Nam Step) luld Volume ibbli Gel Conc, ilblmoall Prop, Type and Mesh Prop cont. WPAI PtrD I a PPA __!O'O 1 50— YFI25floxD --TF-125FIq,,D 300 119 25o ar Lite I OAU 20 PPA I 20.0 YFI25F[exD 114 MO Carb MUMV20 200 30 PPA MO YFI25flexD 110 25,0 1 CatboBoad Lite TUN 3100 40 PPA ZU YFI25FI@xD 127 210 Carbolilond Litt 161211 4,00 5,0 PPA 20.0 YFI25FIoxD 102 25.0 CarbuRond Lite 150 5.00 60 PPA 2010 YFI25FIexD 78 25.0 CarboBemij Lit,& WO 6100 74 PPA 20.0 YFI25FIexD 76 25.0 COrI508010 bk, I WD TOO 8Q PPA I Mo YFI25FIexD 73 25,0 CarboBond Lite 15120 8100 90 PPA O.Q PPA MO 20.Q W125hexD YFI25FIexQ WF125 7125,0 68. 116 25,0 25o COrbOBOOd Lite TWO CarbaBood Litt W20 9,00 1000 O.W Please note that this pumping schedule is under-displa c ed bV3,15 bbl Fluid Totals IM bbl oi YFI25FIexD 116 W Qi WFI25 Proppent Totals 193100 lt) of CarboBmd Lite I VN Pad Percentages PAD Clean 24.2 96 PAD t7irty 20.1 7 - Schlumberger -private chat Mcarp Alaska Well MPF -716 Fcamea iDn : 4uparukA OriVv Prudhoe Bay Cwntry united States schloMpgop Step Name Step fluid Volume Ibbll Cute, fluid Vetumo ibbil Step Slurry Volume ibbll Jab Execution Cunl_ Step Slurry Prep Volume jlbh b01 Cum, Prop, jib) Avg, g Surface Pressure si Stop Time iminI Cum. Time Iminj PAD 390 380 300 300.0 0 0 8770 15.0 15.0 IA PPA 119 819 125 425.0 5019 5019 4800 63 21,3 2.0 PPA 114 534 125 550,0 9814 14633 4797 6.3 27.5 3.0 PPA s 110 644 125 675A 13837 28969 4815 6.3 33,8 40 PPA 127 770 150 825.0 21278 49747 4862 7.5 413 5.0 PPA 102 872 125 950.0 21334 7141 4926 € 63 47.5 big PPA TO PPA 78_9558_. 75 � _ 1025 100 100 1050.0 11500 � 1974; 22229 901' 113051 5;157 5116 -T--57u— 5.0 52.5 57,5 89 PPA 79 1499 100 12W 24509 137504 5265 51U 62,5 9.0 PPA 71 1178 108 13509 26716 164317 5"9 5.0 67.5 10kPPA 69 1238 100 14509 28758 1.13067 5555 i 5.0 72,5 flt�shJ 116 1355 110 15%.8 0 143067 4880 1 5.8 70.3 Schlumberge-r-Private client 144corp Alaska well MPF -116 Fcm,a t b : lfuparukA 0tivict Prudhoe Bay Gentry Unhed nates Section3 Propped Fracture Simulation The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3D Vertical model. Effective Conductivity and Effective Fod are calculated based on perforated intervals with positive net heights. Initial Fracture Top ND...._ ............ .. 7380.0 it Initial Fracture Bottom TVD 7409.0 it Propped Fracture Hall -Length .......... ..... 498.7 It EOJ Hyd Height at Well 11361 1t Average Propped Width.,,-,........_....._. 0.184 in Average Bel Concentration... . _ ...4013.1 Ihlmgal Average Bel Fluid Retained Factor..,,_,_. 0,79 Net Pressure...... ...............................,. 684 psi Max Surface Pressure 5784 psi Simulation Results by Fracture Segment f rank to Prop, Cant, Propped Propped frac. fra , fractute Ifll lit) at End of Width Height Prop, Get Coat. Conductivrfy Pumping 111311 Citi Corte. lux;M0811 lmd,ftl iPPAI lltVh2l 0.0 1243 9.7 1,234 9710 204 3 216.4 11753 1247 248.3 7.0 0-222 115.7 1.93 239<l 11314 249.9 3i4,n 6,0 . 1lil 117.9 1.65 2991 8715 374.0 499,7 3.fi tl,llil 85.3 Q.96 359 3705 Sr Oumberget-Private Schlumbergep FrocCADE' STIMULATION PROPOSAL Operator Hilcorp Alaska Well MPF -116 Field Milne Point Formation Kuperuk C County North Slope State Alaska Country : United States Prepared for Taylor Wellman Service Point : Prudhoe Bay [late are�areri t 1-29 x019 Prepared by Michael Hyatt Phone : 9072734788 E•Maii Address mhyattl2shco 'MY%$Sri k -w w no; 1144 01 to 6.IYm:W rt![Vi, *b-t#Ili*XY0,I "ra 4Y.YA$0krow 0? C"fo'kity kv 01'4S4 AtAY} V*Aoodtte�-1#0E 4Ut,-ffilIt rW,.k*#i t# CtiiW Grp#. tP?if wK4re ?#E R4##511[tR!':Vr#}T.5 t3FEd 4f P,EI, �1Qi#5FR1tSC �TfS+.GFsE#A1+rrX.�rr,Y}j[iv!�!l72SS.!#!#F#9C li#,^'FY1.R3tivFr:saJ rto.a r# ?t# r{ryt34itn':1 ��n ril,# r} p t,(etiFt }t tro} �r.rl?}� 3n14i'Yr;i}4 a# ri. r#u':a[s A�X� #!f S#r sd rr1 nyb #{r.r #man Evia €e:.yi, ti++ 4�.repF4#f ird 4r;M ;F!smIry Frtbt+teller'apaVe;$Xwtttivlt))*RsllshF.ri#tta7lt+Jart stdbA to#sfii Av FFi'iTLYs9?#tFljtY_5 tF t!!!ek4so, aUI.C.. Neltx lf}? rttl".all ttstemstts..optt rrFm fI#rFt1!t#t tae d(Mlnx<"slot Vve t#rY .141, Stlkrtlirge-CdN I54s?:<l teo*nF7 fiv.' �irA'JptvTsstttnCr'?4+tiHle p ftt. pr€.,ItC R'7M61r, jN1�.1 frNCY 1D#F#S lffFrr§7lstrrtl r#E UY'sXr � ta'{Md asr [+OMs7ls NtrR+,� a €4v1t3a'r; r.?(r 4CFs rfttr teba#t1A betb++}aR1Y ^ayl N'#rtsiia909r01)r 4rFit5F9trn'rRrc11Yti# Csat tr[w'fi'bfl**10,-4, Aalf* N,* cp-wt "#lr:1ill#1 Cfkerd}+1 ON.,Y Ike Am0it3!#ksl#I:Y}`l}t167?r11#i#1#rgtT)?r+8,tit4Y1#ri Ott n}ar#g stn#!}} f8Qw#j rE r0rP# I/f" se -Ates Schfumherger-Private client t, Icerp Alaska Viell W F-116 Fe7rati�n XUI:tr_t C 4F5t�cF Prudhae Bay icvntry lr ned &atas cac.,asa LlpE SAWkepoep 5ectionl: Zone Data Schlumberger -private Formation AAerhanieal Pro riieg Zone Name Top TVD 110 Zone Height 1141 Frac Grad_ lrisi;h) Insitu Stress WS4 Young's Modulus 10s1 Poisson's Retro Toughness ipsi.iv,3.5} Kaluhik 6821.0 331.0 0.784 5477 1.308E+6 0.35 2000 Ku D 7157.0 130-0 0.784 5658 1.847E+6 0.35 2000 Kup 86 7282,0 7244.0 iZ.O 20.0 0.660 0.623 4810 4553 1.847E+6 _ 1.7331+6 M25 0.28 � 800 2000 Kup 8 7314.0 53.0 O.7DD 5138 1.729E+6 0.32 2000 Ku A3 7367.0 13.0 0.610 4498 1.729E+6 0.25 2000 Ku A2 7380.0 29.0 0.610 4511 1.729E+6 0.28 2000 Ku Al 7409.0 54.D 0.630 4685 1.729E+6 0.32 2000 Miluveach 7463.0 1DO-0 0.780 5850 4.494E+6 0.35 1000 Schlumberger -private Formation Transmissibifi Properties Zone Name Top_ TVD 1111 Net Height ru Perm {iro p Porosity MI Res. Pressure d sib Gas Sat MI Oil Sat. 1 d Water Sat 9i,f Kaluhik Ktt 0_ Kup C 6821.0 7152.0 7282.0 1.0 1-0 60 0.001 f 0.001 5.000 1.0 1.0 15.0 3596 3681 3744 0110 0-0 0.0 80.D 80.D 80A 20.D 20.0 20,.0 Kttp 66 7294.0 6.0 30.000 10.D 3749 0.0 80.0 20.0 Kup 6 7310 6.0 1.ODD 10.0 3760 0-0 80.0 20.0 Ku A3 7367.0 10.0 40.ODO 22.D 3790 0-0 80.0 2D.D Kup A2 7380.0 5-0 40.000 22.0 3800 O.0 80.0 20.D Kup Al 7409.0 5.7 20,000 13.0 3814 0.0 80.D 20.D Miltiveach 7463.0 1.0 0.001 1.0 3843 0.0 80.D 20.0 Schlumberger -private Clic -rd Rrlearp Alaska Well MK -116 Fmr4ibri 9upar-A C District Prudhoe Bay Cwtilry i? ned Slates kcadsasa 6upC Ob -0111M erger Section 2 Propped Fracture Schedule Pumping Schedule The folloMaq is tate Pumping Schedule to achieve a propped fracture half length Mel at 299,7 ftwith an average conductivity IK,wI of 7148 rnd.ft Please note that this pumping schedule is under -displaced by5.0 bbl Fluid Totals Ffaabbl at YFI25 WKU 111 bbl of WF125 Proppant Totals 13700014 of CarbaBond Lite IWO Pad Percentages % PAD Clean 28.9 PAG QiPly___.._...�. 24.4 Schiumberges-Private Jab Doseri ption Stop Name Pump Rate ibbtlminl Fluid Name Stapfluid Volume {boll Gel Cone. lllvin all Prop. Type and Mesh Prop, Cone, iPPAI PAD 20.0 YFI25FlexD 200 25.0 0.00 10 PPA 20,0 YFI25FloKD 48 25.0 CarboBond Lite 15120 1.00 20 PPA 2010 YFI25FIexD 32 251 CarbaBond Lits 1880 2,00 30 PPA 204 YFI25fl"D 31 25.0 CarbaBond Lite IfH2O 3100 4,0 PPA 50 PPA 20.0 210 YFI25FIexD YF125FI"D 30 ._ 28 25,0 250 CerbaBoAd Lite Ird20 CarboBond Lite TWO 4,00_ 5100 60 PPA 2010 YFI25FIexD 27 25A CarbcBond L l9 i6 ZO b,CO 74 PPA 20.0 4FI25FIax0 26 25.0 CarboBood Lite IU20 TIM 80 PPA 2010 YFI25FIoxD 26 250 CartlaBond Lits TOO &W 8.0 PPA 20.0 YFI25FI"D 37 25.0 CarboBoad Lite 111120 8.07 90 PPA 20.0 YFI2 104 35 254 CarbaBond Lite IW20 5100 100 FPA 204 YFI25FIexD 51 25.0 Carbo=Bond Lite lUZ0 1000 110 PPA 29.0 YF125FI"D 50 25,0 CarbaB+Snd lite T 20 1160 120 PPA 200 YF125Flir.KD 48 250 CarbaBond lite 15120 12W Flush 200 WF125 111 250 0109 Please note that this pumping schedule is under -displaced by5.0 bbl Fluid Totals Ffaabbl at YFI25 WKU 111 bbl of WF125 Proppant Totals 13700014 of CarbaBond Lite IWO Pad Percentages % PAD Clean 28.9 PAG QiPly___.._...�. 24.4 Schiumberges-Private Clicit Hcerp Alaska Mil VPFF-I 16 Fvra1,bn : Kupa" C i$i 6CC Prudhoe Bay Cwntry vfiled States t.eaoeas..: XUg:t SOIlmhopgop Schlumberger -Private Job ExecOon Stop 1 Name Sfep Fluid Volume {bbl} Cum, Fluid Volume lbbil Step Slum Volume Ibbll Cure, Slurry Volume 01 Step Prep {Ib) Curn, Prop, 0b) Avg, z Surface Pressure W-1 _ 1 Step Time ;min) Cutin, Time imin) PAD 1.1 PPA 2.0 PPA 200 48 32 100 248 280 200 50 35 200 2500 MO 0 2007 2692 0 M 4699 5171 5090 4934 )0.0 2.5 1.8 100, 12.5 14,3 3,11 PPA 31 311 35 3100 3874 8574 OR 118 16.0 4,9 PPA 30 340 35 355.0 4965 13538 4870 1.8 17.8 54 PPA 28 369 35 393.0 5973 19512 4883 1.8 19.5 6,0 PPA 27 398 35 425.0 6909 26421 4920 1.8 21.3 0A 26 422 35 460.0 7780 34201 4982 1,8 210 8.0 PPA 26 448 35 4950 8592 42794 5073 1.8 24.8 8.0 PPA 4 37 405 1 50 545.0 12274 55C158 5211 2.5 21.3 9.0 PPA 1 PPA 35 Sl 520 571 50 75 591,5 669.0 13230 21420 68298 89718 5356 5524 25 3J 29.7 335 11.0PPA 50 m _ 621 75 7444 23100 112818 5748 3.8 ... 31.2 12.0 PPA 1 40 669 75 8189 24192 137010 5990 3,1 40.9 Flusl: 111 78C III SMO 0 137010 5164 5.6 46.5 Schlumberger -Private Cie='rt *,Icarp A,leata WL -11 VF1;-116 Fc ra;ba G4!}`*4c 1rwl t Prudhoe Bay icanh} 1:"med States _cocas= 4ufiC S'margor Section 3. Propped Fracture Simulation The following o re the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fed are calculated based on perforated intervals with pmitive net heights. Initial Fracture Top TVD 7282.0 ft Initial Fracture Bottom TVD .. ....... ...... 7794.0 ft Propped Fracture Hall -Length. ..... ....M-7 It ECJ Hyd Height at Well_ _..... . .... . 189.6 ft P Average Propped Width 0.142 in Average Gel Concentration ....... .........358..4 IblmgeI Average Gel Fluid Retained Factor...., 0.81 Net Pressures _ _ _ _ _ _ 734 psi Max Surface Pressure .. .............. 6194 psi Simulation Results by Fracture Segment From f itl To lit) Prop. Cunc. at End of Pumping dt'PAI Propped Width liol Propped Height iftl Frac. frac, Prop, i Gel Colic, Conc. ob,o-ol Itlil;21 fracture Conductivity 1-d-ftl 0.0 74.9 13.9 0.176 1114$ 1.55 2078It7 743 149.9 1314 0.190 1537 170 1899 99115 1490 224.8 12.2 0,161 1549 151 I 215.0 8108 2248 2997 3.5 0.447 t 931 080 8217 1585 Schdumberger-Private 20 AAC 25.283 (a)(13) Description of the Plan for Post -Fracture Wellbore Cleanup and Fluid Recovery through to Production Operations The well will be cleaned up through a portable separation system before turning the well over to Production. Initial returns will be taken to the permitted Milne Point G&I facility for disposal. ai rn rn am rn rn rn CL O O O O O O _y CL Cn N m N J� --_jJ". m N Co N m N J Co N J E _j 0 0 0 0 0 1.0 0 0 kD LL m r.o a o o U N N N N N N ,ten r•i rq -1 r- rq r -I c C� O o U U .Q .Q Q 0. 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V-4 U. eq 0 75 z L GJ CL E u U 0 0 Schwartz, Guy L (CED) From: Taylor Wellman <twellman@hilcorp.com> Sent: Tuesday, December 17, 2019 3:27 PM To: Schwartz, Guy L (CED) Subject: RE: [EXTERNAL] F-116 frac half length (PTD 219-133) Mr. Schwartz, The submitted fracture design was completed with the information we had at the time. During the drilling of this well we elected to run a dipole sonic log to update our Geomechanical Earth Model. With the update of the model and the very analogous/petro-physically similarity to well MPU L-55 (fracture stimulated in 2018) we have tweaked the design slightly. Enclosed are the updated modeled fracture half -lengths (Kup A — 270', Kup C — 244'). Sorry that it took me so long to get this into a presentable format. Kuparuk A Initial Fracture Top TVD _ 7341.4 ft Initial Fracture Bottom TVD 7354.3 ft Propped Fracture Half -Length 269.5 ft EOJ Hyd Height at Well _ _ 196.1 It Average Propped Width 0.224 in Net Pressure _ _ _ _ _ _ 779 psi Efficiency 0.546 Effective Conductivity 11202 md.ft Effective Fcd 0.5 Max Surface Pressure_ _ _ 7679 psi Kuparuk C Initial Fracture Top TVD_ _ _ _ _ 7244.9 It Initial Fracture Bottom TVD 7260.9 It Propped Fracture Half -Length 243.8 ft EOJ Hyd Height at Well _ _ . _ _ ... 203.9 ft Average Propped Width 0.164 in Net Pressure_ _._ _ 633 psi Efficiency 0.460 Effective Conductivity _ 4955 md.ft Effective Fcd 0.3 Max Surface Pressure.__ _.........._._._ 7463 psi Please let me know if you need or would like additional information. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC — Ops Engineer: Alaska North Slope Team Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com 1 From: Schwartz, Guy L (CED) [mailto.suy.schwartz@alaska.gov] Sent: Tuesday, December 17, 2019 11:49 AM To: Taylor Wellman <twellman@hilcorp.com> Subject: [EXTERNAL] F-116 frac half length (PTD 219-133) Taylor, Based on the projected frac half length and assumed frac propagation direction the wing may extend into the adjacent fault just east (290ft) of the F-116 wellbore. Please provide some background on how this could affect frac containment and if there should be any concerns. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226) or (Guy.schwartz@alaska.gov). The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 21 91 33 De_ a Oudean Hilcorp Alaska, LLC 3 1 6 7 8 GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Hiletirp Ahwka, M.t: Fax: 907 777-8510 E-mail: doudean@hilcorp.com DATE: 12/12/2019 To: AOGCC Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 RECEIVED DEC 13 2019 AOGC Log Viewers CGM Definitive Survey EMF LAS PDF TIFF Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 THE STATE °'ALASKA GoVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk Oil Pool, MPU F-116 Hilcorp Alaska, LLC Permit to Drill Number: 219-133 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.alaska.gov Surface Location: 2227' FSL, 2429' FEL, SEC. 6, T13N, R1OE, UM, AK Bottomhole Location: 1372' FNL, 404' FWL, SEC. 33, T14N, R10E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the 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, 1 rerice Chair DATED this day of October, 2019. STATE OF ALASKA AL ,.,KA OIL AND GAS CONSERVATION COMMlb-,ON PERMIT TO DRILL 20 AAC 25.005 1 a. Type of Work: 1b. Proposed Well Class: Exploratory -Gas ❑ Service - WAG ❑ Service - Disp ❑ 1c. Specify if well is proposed for: Drill a Q Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑✓ -Service - Winj ❑ Single Zone Q CoalbedGas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket ❑✓ Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 MPU F-116 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 14,178' TVD: 8,023' Milne Point Field Kuparuk Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation: S Surface: 2227' FSL, 2429' FEL, Sec 6, TI 3N, R10E, UM, AK ADL025509 / ADL355017 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 1582' FNL, 189' FWL, Sec 33, T14N, R10E, UM, AK LONS 94-109 10/9/2019 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 1372' FNL, 404' FWL, Sec 33, T14N, R10E, UM, AK 7013 4752' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 38.0' 15. Distance to Nearest Well Open Surface: x- 542131 y- 6035680 Zone -4 GL / BF Elevation above MSL (ft): 11.5' to Same Pool: 1773' to MPL-21 16. Deviated wells: Kickoff depth: 400 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 65 degrees Downhole: 4332 ' Surface: 3530 • 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length IVf15 TVD MD TVD (including stage data) Conductor 20" 215# X-52 Weld 80' Surface Surface 107' 107' Driven 12-1/4" 9-5/8" 40# L-80 TXP 9,000' Surface Surface 9,000' 4,714' / Stg 1 L - 2240 ft3 T - 458 ft3 Stg 2 L - 1776.3 ft3 / T - 314 ft3 9-7/8" x 8-1/2" 7" 26# L-80 TXP 13,095' Surface Surface 13,095' 7,005' 215 ft3 6-1/8" 4-1/2" 12.6# L-80 TXP 1,233' 12,945' 1 6,866' 14,178' 8,023' 178 ft3 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): Hydraulic Fracture planned? Yes Q No ❑ L.1 �tPp 20. Attachments: Property Plat P1 BOP Sketch Diverter Sketch e Drilling Program B ,_Tigre -V" bepth Plot e ✓ Seabed Report Drilling Fluid Program ✓ Shallow Hazard Analysis 20 AAC 25.050 requirements e 21. Verbal Approval: Commission Representative: Date 22. 1 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: '@rl 21 hIICOr .COm Authorized Title: Drilling Manager Contact Phone: 777-8395 Authorized Signature: �`� Date: Commission Use Only Permit to Drill API tuber: Permit Approval See cover letter for other Number: 150- 07— -X361 150 -p D —00 Date: �O I 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: -y G P e -S -r' Samples req'd: Yes ❑ NoEj�' Mud log req'd: Yes❑ NoE�r r L; �CSpacing H2S measures: Yes ❑ Nov Directional No svy req'd: Yes�❑ GBI�— ✓�� / �� / exception req'd: Yes ❑ No lr-a/ Inclination -only svy req'd: Yes❑ No51� C\ `� /� �'/�• y� [!,.� Post initial injection MIT req'd: Yes❑ No[] APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date:o •� 1 �l � ' � I U- Submit Form and Form 10-401 Revised 5/2017 his permit is valid for 24 months from the date of approval per 20 AAC 25.005(8) Attachments in Duplicate '-.b 6 1olzlfq Hilcorp Alaska, LLC Milne Point Unit (MPU) F-116 Drilling Program Version 1 9/23/2019 Table of Contents 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Casing Inspection............................................................................................................................4 6.0 Internal Reporting Requirements..................................................................................................5 7.0 Planned Wellbore Schematic..........................................................................................................6 8.0 Drilling / Completion Summary.....................................................................................................7 9.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 10.0 R/U and Preparatory Work..........................................................................................................10 11.0 NIU 13-5/8" 5M Diverter System.................................................................................................11 12.0 Drill 12-1/4" Hole Section.............................................................................................................13 13.0 Run 9-5/8" Surface Casing...........................................................................................................16 14.0 Cement 9-5/8" Surface Casing.....................................................................................................21 15.0 BOPE N/U, Test, and Wellhead Installation...............................................................................26 16.0 Drill 8.5" x 9.875" Intermediate Hole Section.............................................................................27 17.0 Run 7" Intermediate Casing.........................................................................................................31 18.0 Cement 7" Intermediate Casing...................................................................................................34 19.0 Drill 6-1/8" Production Hole Section...........................................................................................36 20.0 Run 4-1/2" Liner............................................................................................................................39 21.0 Cement 4-1/2" Production Liner..................................................................................................42 22.0 Perform 4-1/2" Cleanout Run & Displacement..........................................................................45 23.0 Run 4-1/2" Frac String.../.........................................................................................................46 24.0 Innovation Rig Diverter Schematic.............................................................................................47 25.0 Innovation Rig BOP Schematic....................................................................................................48 26.0 Wellhead Schematic......................................................................................................................49 27.0 Days Vs Depth................................................................................................................................50 28.0 Formation Tops & Information...................................................................................................51 29.0 Anticipated Drilling Hazards.......................................................................................................54 30.0 Innovation Rig Layout..................................................................................................................57 31.0 FIT Procedure................................................................................................................................58 32.0 Doyon 14 Choke Manifold Schematic..........................................................................................59 33.0 Casing Design Information...........................................................................................................60 34.0 8-1/2" x 9.875" Hole Section MASP.............................................................................................61 35.0 6-1/8" Hole Section MASP............................................................................................................62 36.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................63 37.0 Surface Plat (As Built) (NAD 27).................................................................................................64 38.0 Drill Pipe Information...................................................................................................................65 1.0 Well Summary Milne Point Unit F-116 Kuparuk Producer Drilling Procedure Well MPU F-116 Pad Milne Point "F" Pad Planned Completion Type 4-1/2" Cemented Liner Target Reservoir(s) Ku aruk C & A Well Plan 08 Planned Well TD, MD / TVD 14,178' MD / 8,022' TVD PBTD, MD / TVD ±14,158 MD / 8,000' TVD Surface Location (Governmental) 2227' FSL, 2429' FEL, Sec 6, T13N, R10E, UM, AK Surface Location (NAD 27 — Zone 4) X=542,131.74 Y=6,035,680.49 Top of Productive Horizon (Governmental) 1582' FNL, 189' FWL, Sec 33, T14N, R10E, UM, AK TPH Location (NAD 27) X=549,965.05, Y=6,042,478.06 BHL (Governmental) 1372' FNL, 404' FWL, Sec 33, T14N, R10E, UM, AK BHL (NAD 27) X=550,177.41, Y=6,042,690.44 AFE Number 1914665 AFE Drilling Das 21 Days AFE Completion Days 4 Days AFE Drilling Amount $4,365,221 AFE Completion Amount $2,076,482 AFE Facility Amount $330,000 Maximum Anticipated Pressure (Surface) 3530 psi Maximum Anticipated Pressure (Downhole/Reservoir) 4332 psi Work String 5" 19.5# 5-135 NC -50, DS -50 4" 14# 5-135 XT -39 / HT38 KB Elevation above MSL: 26.5 ft + 11.5 ft = 38.0 ft GL Elevation above MSL: 11.5 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 2.0 Management of Change Information Milne Point Unit F-116 Kuparuk Producer Drilling Procedure Hilcorp Alaska, LLC Hililcorp Changes to Approved Permit to Drill Date: 9/25/2019 Subject: Changes to Approved Permit to Drill for MPU F-116 File #: MPU F-116 Drilling and Completion Program Any modifications to MPU F-116 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be approved in advance by the AOGCC. Approval: Drilling Manager Prepared: Drilling Engineer Page 3 Change Date Date 3.0 Tubular Program: Milne Point Unit F-116 Kuparuk Producer Drilling Procedure Hole ection OD in ID (in) Drift in Conn T OD in Wt ##/ft(psi)(psi)(k-lbs) Grade Conn Burst Collapse Tension Cond 20" 19" - - 164 A -106B Weld 36,100 43,100 560 12-1/4" 9-5/8" 8.835" 8.75" 10.235" 40 L-80 TXP 5,750 3,090 916 8-1/2" x 9-7/8" 7" 6.276" 6.151" 7.656" 26 L-80 TXP 7,240 5,410 604 6-1/8" 4-1/2" 3.968 3.833 45.00 1 12.6 L-80 TXP 8430 7500 288 4.0 Drill Pipe Information: HOOF Soon in (in) TJ ID its, TJ OD in Wt ##lft Grade 'n Min Max Tensionx Surface & 5" 4.276" 3.25" 6.625" 19.5 5-135 DS50 36,100 43,100 560 Intermediate 5" 4.276" 3.25" 6.625" 19.5 5-135 NC50 25,900 26,800 560 Production 4" 3.34" 2.5625" 4.875" 14 5-135 XT39 18,500 22,200 403 4" 3.34 2.5625 4.875 14 5-135 HT38 12,200 17,700 403 *Tension Rating Based on Premium Pipe 5.0 Casing Inspection All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 Hilcorp Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 6.0 Internal Reporting Requirements 6.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 6.2 Afternoon Updates • Submit a short operations update each work day to mmyers2hilcorp.com, pmazzolini@hilcor2.com , jengel@hilcorp.com and cdin er e,hilcorp.com 6.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 6.4 EHS Incident Reporting • Health and safety: Notify EHS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drlg Manager & Drlg Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 6.5 Casing Tally • Send final "As -Run" Casing tally to jen eg_lghilcorp.com and cdin eg_r(2hilcorp.com 6.6 Casing and Cement report • Send casing and cement report for each string of casing to jen_el(cr�,hilcorp.com and cdinger@hilco!p.com 6.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers f 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Joe Engel '� 907.777.8395 805.235.6265 jengel@hilcorp.com Completion Engineer Taylor Wellman 907.777.8449 907.947.9533 twellman@hilcorp.com Geologist Radu Girbacea 907.777.8324 907.230.9490 rgirbacea@hilcorp.com Reservoir Engineer Almas Aitkulov 907.777.8475 979.739.3133 aaitkulov@hilcorp.com Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com Safety Manager Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 c�@hilcorp.com Page 5 7.0 Planned Wellbore Schematic Crt IB Eec. IGS. Ee::1.15' Milne Pent Unit Well: MPF -116 Proposed Schematic Last Compteted_xx/xx/19 PTD: xxx-xxx -- ------------------- ; TREE -& WELLHEAD - - Trek I SM 4-1}16" Wellhead I SM FMC Gen IV ----------------------- - - --- - ---- - ------------------ OPEN HOLE J CEMENT DETAIL Cmduttur Driw•n 12-1/4" 5 1L-2240ft3/T-45883/ 2L-1776.3ft3/T-314ft3 9-7/8`a 8-V2" 21S U Milne Point Unit IM3 WTI Grade/ Cann ID Top F-116 Kuparuk Producer BPF Hilcorp e -V C—p-gY Drilling Procedure 7.0 Planned Wellbore Schematic Crt IB Eec. IGS. Ee::1.15' Milne Pent Unit Well: MPF -116 Proposed Schematic Last Compteted_xx/xx/19 PTD: xxx-xxx -- ------------------- ; TREE -& WELLHEAD - - Trek I SM 4-1}16" Wellhead I SM FMC Gen IV ----------------------- - - --- - ---- - ------------------ OPEN HOLE J CEMENT DETAIL Cmduttur Driw•n 12-1/4" 5 1L-2240ft3/T-45883/ 2L-1776.3ft3/T-314ft3 9-7/8`a 8-V2" 21S U 6-1/9, IM3 ,i wy WELL INCLINATION DETAIL XOP @ 400' Max #late Angle 65 &% -------------------------------------------------------------------- CASING DETAIL No. Top, WO Sine Type WTI Grade/ Cann ID Top IBM BPF 20" Cmdudar 21S/x-S2/We1d WA Surfaee 107 N/A 9--w. Surface 40/L-W/TXP 8.835 Surface 9.0w 0-0758 7" Internwlixte 26/L-8t1/THP 6.276 Surface 13,095' 0.0383 44/2" L-ner 12.6/L-80ITXP 3.958 12,99S' 14,176' 0.0152 Tu811. DETAIL 3- Tubinit 93 L -8D S63 I 3.958 I Surfaa- I x1 35" 00067 ,i wy WELL INCLINATION DETAIL XOP @ 400' Max #late Angle 65 &% -------------------------------------------------------------------- JEWELRY DETAIL No. Top, WO Item ID I 212,790' 4-1/2" x 7" AI IC Packer ;Cut to Relewe 3.880 2 312,900' 4.1W HN Nipple - No- o = 3.725' 3.725 3 312,935' Muleshoe- 3.958 4 ±12,945' liner Top Packer 4.340 GENERAL WELL INFO API: W-029-wrxwc-0DUO Cased try Dwan 14: Wxxjy;" -------------------------------------------------------------------------------------------------------- PERFORATION DETAIL Sands Top (1v10) 51m 11,10) Top (TVD) Btm (Tm) FT Size I Date Status C TBD TBD 8 2.1/8' 1 xyfxxixt I future KurewkA3 TBD I TBD I I I 8 1 2-"' 1 xxlWxx I Future TD= L1,LV fNCj LTD=4023' IT' kq P5TD=1:3153' [Nq / FSTD=5,000' 1TO) Page 6 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 8.0 Drilling / Completion Summary MPU F-116 is a grassroots oil production well, targeting the Kuparuk River Pool, located on Milne Point `F - Pad'. The directional plan is a three string slant well, with the kick off point at ±500' MD/TVD. Maximum hole angle is 64.6 degrees at ±2,025 MD. Drilling operations are expected to commence approximately October 9, 2019, pending rig schedule. � Gu:r'� Surface casing will be run to 9,000' MD / 4,714 TVD and cemented to surface via a two stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, a Temp log will be run between 6 —18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC. Intermediate casing will be run to ±13,095' MD / 7,005' TVD, landed in the Upper Kalubik and cemented via a single stage cement job bringing cement to 500' MD (minimum) above shoe depth. Top setting intermediate casing is being done as a precaution due to potential high Kuparuk pressure to ensure Colville and HRZ are r behind casing before drilling into the Kuparuk. Production liner will be 4.5" 12.6# L-80 cemented liner run to 14,178' MD / 8,022' TVD, landed just below Kuparuk A. A 4-1/2" frac string with packer will be run. After reviewing the LWD logs obtained while drilling the well, a determination will be made whether or not fracture stimulation will be performed at a later date. v The base plan, however, is to fracture stimulate the Kuparuk reservoir. r A separate sundry will be submitted for hydraulic fracture stimulation and completion operations. All waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility located on `B" pad. General sequence of operations: 0 1. MIRU Innovation Rig 2. N/U & Test 13-5/8" Diverter and 16" diverter line 3. Drill 12-1/4" hole to TD of surface hole section 4. Run and Cement 9-5/8" surface casing 5. N/D diverter, N/U & test 13-5/8" x 5M BOPE 6. Drill 8-1/2" x 9-7/8" hole to TD 7. Run and cement 7" intermediate casing 8. Drill 6-1/8" hole to TD 9. Run 4-1/2" production liner & Cement 10. Run 4-1/2" Frac String 11. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface Hole: No mud logging. LWD: GR + Res 2. Intermediate Hole: No mud logging. LWD: GR/Res, PWD 3. Production Hole: No mud logging. LWD: GR/Res, Neutron/Density, Sonic Page 7 Hilcorp 0 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU F-116. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/4000 psi & subsequent tests of the BOP equipment will be to 250/4000 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, Notify AOGCC and test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • There are no variance requests at this time. Page 8 Hilcorp Summary of BOP Equipment and Test Requirements Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 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: 250/4000 o Blind ram in bottom cavity 8-1/2" x 9-7/8" . Mud cross w/ 3" x 5M side outlets & 0 13-5/8" x 5M Control Technology Single ram 6-1/8" • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/4000 • 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). 0 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: j im.regagalaska. gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy. schwartzna,alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectorsgalaska.gov Test/Inspection notification standardization format: hqp://doa.alaska.gov/ogc/forms/TestWitnessNotifhtml Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 10.0 RX and Preparatory Work Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 10.1 F-116 will utilize a 20" conductor with newly set cellar on F Pad. Ensure to review attached surface plat and make sure site is ready to accept rig over conductor. 10.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 10.3 Ensure landing ring is installed on conductor. 10.4 Ensure (2) 4" threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. d 10.5 MIRU Innovation Rig • Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 10.6 Mud loggers will not be used on F-116 10.7 Mix spud mud for 12-1/4" surface hole section. Ensure mud temperatures are cool (<80°F). 10.8 Set test plug prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 10.9 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 Hilcorp E -WC -Puy 11.0 NX 13-5/8" 5M Diverter System Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 11.1 N/U 13-5/8" CTI BOP stack in diverter configuration (Diverter Schematic attached to program). • N/U 20" x 13-5/8" DSA • N/U 13 5/8", 5M diverter "T". • NU Knife gate & 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. • Utilized extensions if needed. 11.2 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. 11.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking. • A prohibition on ignition sources or running equipment. • A prohibition on staged equipment or materials. • Restriction of traffic to essential foot or vehicle traffic only. Page 11 11.4 Approximate Rig & Diverter Orientation (Drawing not to scale): F-82 ■ F-81 ■ 78 ■ 74 ■ 70 ■ 66 ■ Page 12 F-116 F-991 ■ F-77 ■ F-73 ■ 69 ■ 65 ■ 75' Radius Clear of Ignition Sources — Diverter Line MPU F -Pad Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 1 *Drawing Not To Scale Hilcorp E -W C72 12.0 Drill 12-1/4" Hole Section Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 12.1 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 components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • 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. Hydraulics calculations and recommended TFA is attached below. • Drill pipe will be 5" 19.5# 5-135 NC50 • Run a solid float in the surface hole section. 12.2 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. 12.3 Drill 12-1/4" hole section to section TD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. Target TD =proximately 100'T—VD through the base of the permafrost. Permafrost base is estimated at 1850' TVD • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation. • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 450-600 gpm. Monitor shakers closely to ensure shaker screen and return lines can handle the flow rate • Ensure not to out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen • Tangent Angle: 64.5°, watch hole cleaning/ECDs • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Slow in/out of slips and while tripping to keep swab and surge pressures low • Make wiper trips if necessary. • Adjust MW and viscosity as necessary to maintain hole stability. Ensure MW at TD is 9.2 minimum. • Take MWD surveys every stand drilled. • Watch returns closely for signs of gas when near the base of the permafrost and circulate out all gas cut mud before continuing to drill. There have been no indications of hydrates on any of the "F" pad wells to date. • Do not stop to circulate out gas hydrates — this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be Page 13 Hilcorp Milne Point Unit F-116 Kuparuk Producer Drilling Procedure reduced to prevent mud from belching over the bell nipple. Consider adding mud products such as Lecithin to allow the gas to break out. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling, packing off or running gravels • Do not stop to circulate on wiper trips with bit across a slide interval, especially not in an area where DLS is > 4. • Do not slide for 100' MD above the base of the permafrost or 100' below the base. We want to leave this transition as undisturbed as possible. • There are no major AC risks with separation factors < 1.0 • Ensure TD of the hole section is — 100' TVD below Schrader Bluff Sands, confirm with Geologist 12.4 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 anticipated 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, and Toolpusher office • Rheology: Aquagel and viscosifier should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: POLYPAC SUPREME should be used for filtrate control. Background LCM (5 ppb total) SAFECARB can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of SCREENKLEEN are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high -clay content sections of the Sagavanirktok 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 Busan 1060 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 — 9.5 ppg Pre -Hydrated Aquagel/freshwater spud mud erties: Section I Density I Viscositv I Plastic Viscositv I Yield Point I API Fl. I Tem Page 14 0 Hilcorp ffi-OC.-POY Milne Point Unit F-116 Kuparuk Producer Drilling Procedure Surface 8.8-9.5 1 75-17 1 20-40 25-45 <10 I < 70° F 1 8.5 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 12.5 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 12.6 RIH t/ bottom, proceed to BROOH t/ HWDP • 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. 12.7 TOOH and LD BHA 12.8 No open hole logging program planned. Page 15 Hilcorp E-WC-V-E� 13.0 13.1 13.2 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure Run 9-5/8" Surface Casing R/U and pull wear bushing. 9-5/8" Surface casing will be set with slips to ensure complete circulation and returns during cement job. 13.3 R/U Weatherford 9-5/8" casing running equipment (CRT & Tongs) • Ensure 9-5/8" TXP 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. 13.4 P/U shoe joint, visually verify no debris inside joint. 13.5 Continue M/U & thread locking 120' shoe track assembly consisting of - 9 -5/8" Float Shoe 1 joint — 9-5/8" TXP, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" TXP, 1 Centralizer mid joint w/ stop ring 9-5/8" Float Collar w/ Stage Cementer Bypass Baffle `Top Hat' 1 joint — 9-5/8" TXP, 1 Centralizer mid joint with stop ring 9-5/8" HES Baffle Adaptor • Ensure bypass baffle is correctly installed on top of float collar. Bypass Baffle This end up. • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 16 v 13.6 Float equipment and Stage tool equipment drawings: "A Overed Length Type H ES Cementer Part No. SO No. Closing Sleeve No. Shear Pins Opening Sleeve No. Shear Pins ES Cementer Depth Baffle Adapter (it used) ID Depth Bypass or Shut -orf Baffle ID Depth Float Collar Depth Float Shoe Depth Hole TD "Reference Casmg Salos btanual Section S B Hkory E$tI Rennin Order I.I n. ID Met DmIlout C Max Tool OD D Baffle Adapter Openog Seat IO E By-pass plug Cicvng Seat 90 Plug Set Part No_ SO No. Closing PtW OD Opening Plug OD OD Shut-off Plug OD Bypass Plug (if used) OD Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 13.7 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. • Centralization: • 1 centralizer every joint t/ - 1000' MD from shoe • 1 centralizer every 2 joints to 2,000' above shoe (Top of Ugnu� • Verify epth of lowest Ugnu water sand for isolation with Geolojzist Page 17 Hkory E$tI Rennin Order ESDI Cementer 9W Off ft4 Baffle Adapter By-pass plug By pass Battle Float Collar i Float Shce 13.7 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. • Centralization: • 1 centralizer every joint t/ - 1000' MD from shoe • 1 centralizer every 2 joints to 2,000' above shoe (Top of Ugnu� • Verify epth of lowest Ugnu water sand for isolation with Geolojzist Page 17 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 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. Establish circulation if needed. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 13.8 Install the Halliburton Type H ES -II Stage tool so that it is positioned at least 100' TVD below the permafrost (— 2.500' MD). , • Install centralizers over couplings on 5 joints below and 10 joints 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 psi. 9-5/8" 404 L-80 TXP Make Up Torques: Casing OD Min M/U Torque Max M/U Torque 9-5/8" 18,860 ft -lbs 23,060 ft -lbs Page 18 rCONNECTION DATA GEOMETRY Connection OD 10.625 in. -' CoirpAng Length 10.825 irA. Connection ED 8.823 IrL Make-up Loss 4.991 in. Threads Fer La 5 C-crmeclian 00 Optcn REGULAR PERFORMANCE I Milne Point Unit — Tension EFze7cq 100.0% JDtrl Y*ld Strength 916LDN v,1 XG F-116 Kuparuk Producer 5750.000 psi Hilcorp lbs Drilling Procedure 100% E -v C -P-7 91&DOID x1,Xf, MD- Alowable BerxJing 38 ';100 ft lbs Ext -ma) Pressure Capa:itj 3090.000 psi TXPO BTC MAKE-UP TORQUES .�„r.-0112212018 Outside Diameter 9-625 in. Min- Wall B7.5% 18860 Nbcs Cpt— 20960 ft -lbs KA&xmjm Thickness OPERATION LIMIT TORQUES I') Grade LBO Sorg Operating Tcrque 35600 ft -lbs Type 1 43460 h,11oz WaEl Thickness 0.395 in- Connection OD REGULAR Option COUPLING PIPE BODY Body Red I st Band. Red Grade LBO Type 1 Drift APE Standard tat Ba rj: Brown 2nd Band 2nd Band: - Brown Type Casing ".rd Band:- 3rd Band:- and:-4th 4thBand: - P! PF B 0C Y DA:Ti', GEOMETRY I Narrinal OD 9.625 in. Nominal iWght 40 losit Clift 8.679 r. Nominal ID 8-835 in. A'all TticVw5E 0.395 in. Plain Erd&,ight 38.97 lbst OD Tder-arce APE PERFORMANCE B.-dyIrield Snnglh 916 xM0 lbs Internal Yied 5750;si Skfys BOODO psi Collmse 3093 psi rCONNECTION DATA GEOMETRY Connection OD 10.625 in. -' CoirpAng Length 10.825 irA. Connection ED 8.823 IrL Make-up Loss 4.991 in. Threads Fer La 5 C-crmeclian 00 Optcn REGULAR PERFORMANCE I — Tension EFze7cq 100.0% JDtrl Y*ld Strength 916LDN v,1 XG W. --.nal Pre5vire Capacity M 5750.000 psi lbs Ccrnprsssion Effivnercy 100% Compression Strength 91&DOID x1,Xf, MD- Alowable BerxJing 38 ';100 ft lbs Ext -ma) Pressure Capa:itj 3090.000 psi MAKE-UP TORQUES Minimum 18860 Nbcs Cpt— 20960 ft -lbs KA&xmjm 23060 ftbs OPERATION LIMIT TORQUES Operating Tcrque 35600 ft -lbs Y16d Tomrae 43460 h,11oz Notes This connection is fully interchangeable with: TXn'BTC - 9.625 in. - 36143.5147; 53.5 J 58-4 lbs.,ft 11] Intemal Pressure. Capacity related to structural resistance only. Internal pressure leak resistance as per section 10-3 API 5C3 I ISO 10400 - 2007. Page 19 0 Hilcorp E -W C--P-F" Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 13.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 13.10 Slow in and out of slips. 13.11 Lower casing to setting depth. Confirm measurements. 13.12 Have slips staged in the cellar, along with necessary equipment for the operation. 13.13 RAJ circulating equipment and circulate B/U. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. 13.14 Reciprocate casing if possible while conditioning mud. Page 20 14.0 Cement 9-5/8" Surface Casing Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 14.1 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 cement 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. • 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. 14.2 Document efficiency of all possible displacement pumps prior to cement job. 14.3 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. 14.4 R/U cementing line (if not already done so). Company rep to witness all plug loading to ensure they are done in the correct order. 14.5 Fill surface lines with water and pressure test. 14.6 Pump 60 bbls 10.0 ppg tuned spacer. 14.7 Drop bottom plug (flexible bypass plug) — HEC rep to witness. Mix and pump cement per below calculations for the I" stage, confirm actual cement volumes with cementer after TD is reached. 14.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail slurry, and TOC will be brought to the stage tool. Estimated lst Stage Total Cement Volume: Page 21 12-1/4" OH x 9-5/8" (8000'- 2500') x .0558 bpf x 1.3 = 399 2240 vCasing Total Lead 399 2240 12-1/4" OH x 9-5/8" (9000'- 1000') x .0558 bpf x 1.3 = 72.5 407 — Casing ~ 9-5/8" Shoe Track 120'x .0758 bpf = 9.1 51.09 Total Tail 81.6 458 Page 21 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure Cement Slurry Design (1St stage cement jobs): 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the casing collar depths in mind. If the hole gets "sticky", position casing string at desired depth and continue with cement job. 14.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting spacer across the stage tool. • Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 14.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the shutoff plug must be bumped. 14.12 Displacement calculation: (9,000' —120') x .0758 bpf = 673.1 bbl total 80 bbl of tuned spacer to be left behind stage tool. Confirm spacer is compatible with cement behind stage tool 14.13 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 the any cement seen at surface. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of the shoe track volume, —4.5 bbls before consulting with drilling engineer. 14.15 If the plug is not bumped, consult the drilling engineer. Ensure the free falls stage tool opening plug is available if needed. This is the backup option to open the stage tool if the plugs are not bumped. 14.16 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. Page 22 Lead Slurry Tail Slurry System ExtendaCEM'm System SwiftCEM rM System (Hal Cem) Density 11.7 Ib/gal 15.8 Ib/gal Yield 4.298 ft3/sk 1.16 ft3/sk ✓ Mixed Water 21.13 gal/sk 5.04 gal/sk 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the casing collar depths in mind. If the hole gets "sticky", position casing string at desired depth and continue with cement job. 14.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting spacer across the stage tool. • Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 14.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the shutoff plug must be bumped. 14.12 Displacement calculation: (9,000' —120') x .0758 bpf = 673.1 bbl total 80 bbl of tuned spacer to be left behind stage tool. Confirm spacer is compatible with cement behind stage tool 14.13 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 the any cement seen at surface. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of the shoe track volume, —4.5 bbls before consulting with drilling engineer. 14.15 If the plug is not bumped, consult the drilling engineer. Ensure the free falls stage tool opening plug is available if needed. This is the backup option to open the stage tool if the plugs are not bumped. 14.16 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. Page 22 Hilcorp �� 14.17 Increase Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 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. 14.18 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 ✓ Hilcorp E—VC—Pay Milne Point Unit F-116 Kuparuk Producer Drilling Procedure Second Stage Surface Cement Job: 14.19 Prepare for the 2nd stage as necessary. Circulate until first stage has reached sufficient compressive strength. Hold pre job safety meeting. 14.20 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 14.21 Fill surface lines with water and pressure test. 14.22 Pump 60 bbls 10.5 ppg tuned spacer. 14.23 Mix and pump cement per below recipe for the 2nd stage. 14.24 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. Based upon first stage volume circulated back to surface and hole gauges sweeps, lead cement excess could be reduced to 150%. Estimated 211 Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): Section Calculation Vol (bbl) Vol (ft3) SwiftCEM TM System (Hal Cem) 20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1= 28.6 161 J 12-1/4" OH x 9-5/8" Casing (2000'- 110') x .0558 bpf x 3 = 316.4 1776.3 Total Lead 345 1937 12-1/4" OH x 9-5/8" Casing (2500'- 2000') x .0558 bpf x 2 = 55.8 314 ~ Total Tail 55.8 314 Cement Slurry Design (2nd stage cement job): A 7� 14.27 Continue pumping lead cement until uncontaminated spacer is seen at surface, then switch to tail. 14.28 After pumping cement, drop ES cementer closing plug and displace cement with rig pumps, using spud mud in mud pits. 14.29 Displacement Calculation: 2500' x .0758 bDf = 190 bbls mud Page 24 Lead Slurry Tail Slurry System Permafrost L SwiftCEM TM System (Hal Cem) Density 10.7 Ib/gal 15.8 Ib/gal Yield 4.3279 ft3/sk 1.16 ft3/sk Mixed Water 21.405 gal/sk 5.08 gal/sk A 7� 14.27 Continue pumping lead cement until uncontaminated spacer is seen at surface, then switch to tail. 14.28 After pumping cement, drop ES cementer closing plug and displace cement with rig pumps, using spud mud in mud pits. 14.29 Displacement Calculation: 2500' x .0758 bDf = 190 bbls mud Page 24 Hilcorp Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 14.30 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. 14.31 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. 14.32 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 as per wellhead rep. 14.33 Flush out wellhead with FW and BOP stack thoroughly to ensure cement, mud and cuttings are removed. 14.34 M/U pack -off running tool and pack -off to bottom of final joint. Set casing hanger packoff. Inject plastic packing element. Pressure test packoff. 14.35 Lay down cut joint and pack -off running tool. Ensure to report the following on WellEz: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • If losses are seen during cement job, note at operation during the cement job they were observed and where the cement was • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Send final "As -Run " casing tally & casing and cement report to jengelghilcorp. com and c&7gerghilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 25 Hilcorp 15.0 BOPE N/U, Test, and Wellhead Installation Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 15.1 N/D the diverter T, 16" knife gate, 16" diverter line & N/U 11" x 13-5/8" 5M casing spool. 15.2 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 or 5" Solid Body Rams — • N/LT 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) 15.3 Run 5" BOP test assembly, land out test plug. 15.4 Test BOP to 250/4000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Test 5" test joints • Confirm test pressures with PTD s� • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 15.5 RAD BOP test equipment 15.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 15.7 Mix 9.5 ppg LSND fluid for intermediate hole section. 15.8 Set wear bushing in wellhead. 15.9 If needed, rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 15.10 Ensure 5" liners in mud pumps. Page 26 Hilcorp F—vC—p.Fw Milne Point Unit F-116 Kuparuk Producer Drilling Procedure Drill 8.5" x 9.875" Intermediate Hole Section M/U 8.5" Cleanout BHA (Milltooth Bit & 1.22° PDM) TIH w/ 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 11 to drilling out the shoe track, verify all rig crew member are familiar with operation. If needed, install RCD bearing element and perform practice connections to familiarize crews with its operations. 16.4 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 16.5 R/U and test casing to 2500 psi / 30 min._ Ensure to record volume / pressure and plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = 2875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 16.6 Drill out shoe track and 20' of new formation. 16.7 Displace wellbore to 9.5 ppg LSND for FIT 16.8 OWFF and pull into casing shoe. 16.9 Conduct FIT to 12.5 ppg EMW. If 12.5 ppb EMS is not obtained call and discuss with Drilling Engineer. 16.10 POOH and LD cleanout BHA 16.11 P/U 8.5" x 9.875" Rotary Steerable Directional Assembly w/ Under Reamer • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure 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 pipe will be 5" 19.54 S-135, NC50 & DS50. • Run x2 Solid Plunger Floats for MPD ,/ Page 27 ff Hilcorp E -w C-pwy 16.12 8.5" x 9.875" hole section mud program summary: Milne Point Unit F-116 Kuparuk Producer Drilling Procedure • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Ensure 6 rpm is >9.875 (hole diameter) for sufficient hole cleaning, YP as low as possible • Inhibition: 3% KCl will be used for handling clay cuttings. Watch MBT levels, dilute as necessary to maintain. Increase KCl % if needed • Run the centrifuge continuously while drilling the production hole, this will help with solids removal and minimize sand content and LGS to maintain fluid properties and quality of the mud system. • PVT will be used throughout the drilling phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 9.5 - 10.8 ppg 3% KCl Inhibited LSND WBM Properties: J Section Density Plastic Yield Point LGS MBT HPHT pH Viscosity Intermediate 9.5- 10.8 15-25 15-20 <6% <20 <1 1.0 9-10 16.13 RIH w/ 8.5" x 9.875" directional assembly on 5" DP from the derrick. • Shallow test MWD to confirm tool communication Slow string speed when tripping through the stage collar 16.14 Drill — 100' of 8.5" Hole • Enough hole to bury RSS BHA and clear UR blades from casing shoe • RPM: 120+ • Flow Rate: 350-400 gpm (confirm with closed UR) • WOB as needed 16.15 Circulate hole clean, drop ball and open under reamer. • Indication of open under reamer will be pump pressure and turbine RPM • Perform pull test to confirm UR is open as well Page 28 Hilcorp E-A, C..pi�l 16.16 Drill 8.5" x 9.875" Hole to — 500' MD above HRZ, 12,417' MD • RPM: 120+ Milne Point Unit F-116 Kuparuk Producer Drilling Procedure • Flow Rate: 600 GPM (200 ft/min Annular Velocity) • Ensure shaker screens are set up to handle this flow rate, shakers running slightly wet to maximize solids removal efficiency. Check for holes on screens on every connection. • WOB as needed • Pump tandem high vise high weight / low vise low weight sweeps to aid in hole cleaning • Take MWD surveys every stand • Monitor hole cleaning indicators: PUW, pump pressure and ECD. Make wiper trips or backream connections if necessary 16.17 CBU x2, perform short trip to shoe if necessary • RPM: 120+ Flow Rate: 600 GPM (200 ft/min Annular Velocity) Alternate reciprocation depths to avoid troughing/ledging 16.18 Increase black productions for Shale stability. MW will remain at 9.5 ppg • If needed, increase MW with pre sheared spike fluid, in .3 ppg per circulation, this is to ensure no barite sag or uneven density 16.19 Install MPD Element • Ensure rig crew is familiar with MPD connection operations • Ensure max pressure relief settings are set correction to ensure no wellbore damage is created 16.20 Drill 8.5" x 9.875" hole section to section TD per Geologist and Drilling Engineer in Upper Kalubik (To mitigate trapped injection pressure potential), 13,095' MD • RPM: 120+ • Flow Rate: 600 GPM (200 ft/min Annular Velocity) • WOB as needed r�Gfl • Target ECD: 11.3 ppg EMW, for all operations (Range: ±5%) • Utilize MPD to maintain CBHP (constant bottom hole pressure) at the bottom of the HRZ on connections, following Annular pressure ramp schedule • This will reduce the pumps on/ pumps off pressure cycles on shales • Slow ramp pumps on/off on each connection • Smooth connections are more important that connection time • Monitor losses on connetions, reduce annular pressure if needed. • Pump tandem high vise high weight / low vise low weight sweeps to aid in hole cleaning, monitor ECD effect of sweeps • Take MWD surveys every stand • Monitor hole cleaning indicators: PUW, pump pressure and ECD. Backream connections if 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 anv extended period of time. Page 29 Hilcorp Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 16.21 At TD; CBU at full rate and RPM least 4-5 times at maximum circulation and rotation. Alternate reciprocation depths while CBU to reduce risk of troughing and dropping inclination. Under reamer will be open during CBU, to maximize flow and hole cleaning. 16.22 Once hole is cleaned up, drop ball and close under reamer. Indications will be pump pressure and turbine rpm change. 16.23 Perform wiper trip t/ above the HRZ, offsetting swab with MPD maintaining 11.3 CBHP. 16.24 RIH to bottom • Slow string speed to limit surge on shales, ensuring not to exceed 11.3 EMW 16.25 Weight up at TD for shale stability, ±10.5 ppg, maintaining CHBP of 11.3 ppg EMW • Perform weight up with pre -sheared spike fluid, weighting up with .3 ppg increments 16.26 Observe well for flow 16.27 Spot Casing Running Pill • 12ppg black product, graphite, 4% lube 16.28 TOOH with the drilling assembly t/ 9-5/8" Shoe, Offsetting Swab with MPD • Target offset swab is 11.3 ppg EMW • Follow tripping schedule, matching string speed and annular pressure • Rack back DP while TOOH, Do not lay down drill pipe. This is to minimize open hole time before casing is on bottom. 16.29 If backreaming is necessary: • Circulate at max rate while maintaining drilling ECD's (flow will be less due to 10.5 ppg MW) • Perform CBHP connections • 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 a b/u once at the shoe. 16.30 CBU x2 at 9-5/8" Shoe 16.31 Continue TOOH to HWDP/ BHA, offsetting swab with MPD 16.32 Pull RCD Bearing element ---------- 16.33 LD BHA Page 30 Hilcorp 17.0 Run 7" Intermediate Casing Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 17.1 Change pipe rams to 7". Test same. 250/4000 psi. Confirm test due dates. 17.2 R/U 7" casing running equipment. • Ensure 7" TXP (BTC Compatible) x NC50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted prior to running. • Be sure to count the total # of joints 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. • R/U CRT w/ cement swivel. 17.3 M/U & threadlock shoe track assembly consisting of. • (1) Float shoe joint w/ float shoe bucked on. Install (2) solid body centralizers over a stop ring at 10' from each end. • (1) Baker locked joint. Install (1) solid body centralizer mid joint over a stop ring • (1) Float collar joint w/ float collar bucked on pin end. Install (1) solid body centralizer mid tube over a stop ring. • Ensure proper operation of float shoe and float collar. 17.4 Run 7" 26# L-80 TXP casing. • Fill casing while running using CRT or fill up line. • Use "BOL 2000" thread compound. Dope pin end only w/ paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install centralizers on every ioint to 500' above shoe depth. • Install 3 centralizers across 9-5/8" casing shoe. 17.5 RIH following casing running schedule, keeping surge below max drilling ECD EMW • Monitor T&D while RIH • CBU at the 9-5/8" shoe and — 500' above HRZ (12,417' MD) to ensure mud is conditioned prior to RIH • Model circulation rates, do not exceed 11.3 PP2 EMW ECD, for both losses at the colville and shale stability • Monitor SOW while RIH, if SOW trend starts decreasing, circulate extra BU if needed (or at other depths) • Do not circulate in the middle of the HRZ, can increase possibility of packoffs and prevent casing from reaching bottom • Past 7" casing runs through HRZ have had success with very slow running speeds, do not stack weight or push casing down. Let the hole dictate running speeds. 17.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. Slow in and out of slips. 17.7 Lower string to depth. MU hanger and landing joint. Casing will be set on depth with hanger. Page 31 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 17.8 Circulation and condition mud for cement job through CRT. Reduce YP to < 20 to help ensure success of cement job. Slowly stage up pump rates, if possible, in 15 min increments .25-.5 bpm at a time. 17.9 After circulating, set string at setting depth. 7" Casing Torque Values Connection MUT (Min) MUT (Opt) MUT (Max) Max Operating ft -lb Xf- ft -lb Torque, ft -lb TXP 13,280 i 14,750' 16,230 20,000 Page 32 Outside Diameter 7.000 in- Min. Wall 87.5% Milne Point Unit LKIn F-116 Kuparuk Producer Hilo Drilling Procedure TXPO BTC ft --.05f0912018 Outside Diameter 7.000 in- Min. Wall 87.5% Lo ID5.:3i LKIn W131 V - Thickness 6.276 in. {'j Grade L80 0.362 in. Plain E=u114Eighl 25.69 OD Tolerance Type 1 Wall Thickness 0.362 in- Connection OD REGULAR PERFORMANCE Option COUPLI14G PIPE BODY Body Red is[Eand:Red Grade L80 Type 1 Drift API Standard 1st Sar>d: Brown 2nd Band: 80000 psi Calla*ase 5410 psi 2nd Band - Brown Type Casing 3rd Band: - 3rd Band - _ { C0,14NECTION DATA 4th Rand: - •-`irk._ :3ti� G LG GEOMETRY rtamrnal Lu d_uuw In. nmmira vve:gnl Lo ID5.:3i LKIn W131 V - Nominal lD 6.276 in. Thrall Ttickness 0.362 in. Plain E=u114Eighl 25.69 OD Tolerance API PERFORMANCE Badp'rield Strength 604 x1001, Ibs romal Yield 7240 s5i sklyS 80000 psi Calla*ase 5410 psi _ { C0,14NECTION DATA G LG Connection CSD 7.656 in. C:Dipling Length 10.200 in. J cnw-flan 1D 6-964 n Vakr-up Loss 4.579 in. Thuds per in 5 Gannecticn CSD OptIon REGULAR PERFORMANCE – ' Tensian EfFckm+ 100.0 % Joim Yeld Strength 604.000 x 1{CO iraema! Pressure Capacity 17 72+0.000 psi lbs Compression Efr=r y 100% C:ampression S'irerrith 604.000 x t CO Max. Ah-- able Beading 52 "i 100 f1 lbs External Press=ure Capacity 5410.00D psi � MAKE-UP TORQUES htinirnum 13280 ft4bs eptrr— 14750It4bs Ie HATI–ran 16230 k;ft OPERATION LIMIT TORQUES — Operafing Torque 20000 It -lbs 'afield Torque 23400 ft -lbs Notes This cnranec iean is fully interchangeable with: TXR& BTC - 7 in. - 23,129 132,35 1 38 Ibv ft Page 33 18.0 Cement 7" Intermediate Casing Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 18.1 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. • How to handle cement returns at surface, regardless of how unlikely it • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cement operation. • Extra hands in the pits to strap during the cement job to identify any losses • Document efficiency of all possible displacement pumps prior to cement job. 18.2 7" cement job will be a single stage, single slurry job. 18.3 RU Cement lines to cement swivel on CRT. Plugs will be dropped manually. 18.4 Pump 5 bbls fresh water. Pressure test surface cement lines to 4000 psi. 18.5 Pump remaining 40 bbls 10.5 ppg tuned spacer. 18.6 Drop bottom plug, Mix and pump slurry per below calculations, 50% OH excess volume: Section: Calculation: of Vol (ft3) 9.875" OH x 7" Casing: (13,095' — 12,595') x 0.0471 bpf x 1.5 = 35.25 198.3 7" Shoe Track: 80' x.038 bpf = 3 16.8 Total Volume: 38.25 215.1 Slurry Information Page 34 tK's- Cement Slurry System ExpandaCem Density 15.8 Ib/gal Yield 1.16 ft3/sk Mixed Water 4.972 gal/sk Additives Super CBL, Microbond Page 34 tK's- Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 18.7 After pumping cement, drop top plug and displace cement with drilling mud. Use rig pumps for displacement. Ensure to have a good baseline measurement for pump displacement ahead of time. Displacement calcs: • 13,015' x .038 bpf = 494.6 bbls 18.8 Reciprocate casing during cement job. If at any time pipe movement gets sticky, land casing hanger. 18.9 Monitor returns closely while displacing cement. Ensure pits are strapped every 10 bbls of displacement and communicated with Co Rep. If losses are seen, let DSM know and possibly reduce pump rate. 18.10 Do not over displace by more than 1/2 shoe track volume. Total volume in shoe track is 3.5 bbls 18.11 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. If this is the case, monitor the pressure on the casing and do not let it exceed 500 psi over the final pump pressure. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Send final "As -Run " casing tally & casing and cement report to iengelghilcorp com and cdin eerrghilcoo. com. This will be included with the EOW documentation that goes to the AOGCC. 18.12 R/D cementing equipment. Flush out wellhead with FW. 18.13 Test void to 250/4000 psi for 10 min. 18.14 Freeze protect 9-5/8" x 7" Annulus 18.15 Lay down 5" DP. Page 3 5 Hilcorp E -w C-*.ffy 19.0 Drill 6-1/8" Production Hole Section Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 19.1 Change lower pipe rams to 2-7/8" x 5.5" VBR. Test to 250/4000. Chart Test. 19.2 P/U 6-1/8" RSS Directional BHA • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. • Workstring will be 4" 14# S-135 HT -38 / XT 39 • Run x2 Solid Plunger Floats for MPD • Density/Neutron & Dipole Sonic will be ran on this hole section 19.3 6-1/8" hole mud program summary: •� Density: Kuparuk pressures are predicted to be 10.4. 10.5 ppg with MPD will be used as a precaution. Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Ensure 6 rpm is >6.125 (hole diameter) for sufficient hole cleaning, YP as low as possible • Inhibition: 3% KCl will be used for inhibition. Watch MBT levels, dilute as necessary to maintain. Increase KCl % if needed • Run the centrifuge continuously while drilling the production hole, this will help with solids removal and minimize sand content and LGS to maintain fluid properties and quality of the mud system. • PVT will be used throughout the drilling phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 10.5 — 12.5ppg 3% KCl Inhibited LSND WBM Properties: Section Density Viscosity Plastic Viscosity Yield Point Total Solids MBT H 6-1/8" 10.5 -12.5 1 75-175 15-25 15-25 <10% < 7 1 8.5 Page 36 Hilcorp E -WC --PCV Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 19.4 TIH w/ 6-1/8" directional assembly on 4" DP to above TOC. Shallow test MWD and LWD on trip in. 19.5 Note depth of TOC on morning report. Circulate bottoms up. �N 19.6 R/U and test casing to 3650 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC regulation is 50% of burst. 19.7 Ensure even 10.5ppg MW in and out before drilling shoe track 19.8 Drill out shoe track and 20' of new formation. • Take time drilling out shoe track. Do not risk damaging bit or D&M tools. 19.9 CBU and condition mud for FIT. r 19.10 Conduct FIT to 14.0 ppg EMW. 19.11 Install MPD Element Ensure rig crew is familiar with MPD connection operations Ensure max pressure relief settings are set correction to ensure no wellbore damage is created 19.12 Drill 6-1/8" hole section to section TD per Geologist and Drilling Engineer. • Flow Rate: 150-250 gpm (Target 200 ft/min AV) • RPM: 120 — for hole cleaning • WOB as needed • Target ECD and CBHP: 12.0 ppg EMW (This will be adjusted if any pressure increase is seen during connections or fluid pushed away) • Utilize MPD to maintain CBHP (constant bottom hole pressure) on connections, following Annular pressure ramp schedule • This will reduce the pumps on/ pumps off pressure cycles on shales • Slow ramp pumps on/off on each connection • Smooth connections are more important that connection time • Monitor connections for losses, adjust as necessary • Take MWD surveys every stand drilled. • Kuparuk PP estimate is 10.4 ppg. 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. • Watch for fluid losses while drilling through Kuparuk. 19.13 At TD; CBU at least 3 times at maximum circulation and rotation Circulate at full drill rate (150-250 gpm). Rotate at maximum rpm that can be sustained, target 120 Perform short trip to 7" shoe if needed after CBU cycles are complete Page 37 Hilcorp F --W C—p-my Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 19.14 Observe well for flow, weight up to 11.5 ppg (this will be determined by connection monitoring while drilling this hole section) 19.15 TOOH with the drilling assembly t/ 7" Shoe, Offsetting Swab with MPD • Follow tripping schedule, matching string speed and annular pressure • Rack back DP while TOOH, Do not lay down drill pipe. This is to minimize open hole time before liner is on bottom. 19.16 If backreaming is necessary: • Circulate at max rate while maintaining drilling ECD's • Perform CBHP connections • 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 a b/u once at the shoe. 19.17 CBU at 7" Shoe 19.18 Continue TOOH to HWDP/ BHA, offsetting swab with MPD • Once inside casing, drop rabbit on remaining drillpipe on TOOH that will be used to run the 4.5" liner. Confirm diameter drift with Baker for setting liner hanger 19.19 Pull RCD Bearing element at HWDP 19.20 L/D 6-1/8" BHA 19.21 No additional logs are planned for the 6-1/8" hole section. Page 38 Hilcorp e-® C -PRY 20.0 Run 4-1/2" Liner Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 20.1 Ensure rams have been tested on 4-1/2" test joint prior to running liner. 20.2 Ensure wear bushing is installed in wellhead. 20.3 R/U 4-1/2" casing running equipment. • Ensure 4-1/2" TXP crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted prior to running. • Be sure to count the total # of joints 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. 20.4 Run 4-1/2" liner per completion tally. • Dope pin end only w/ paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Run 1 centralizer per joint for the entire liner 4-1/2" Tenaris TXP Make Up Torques Casing OD Minimum O timum Maximum 4.5" 5,550 ft -lbs 6,170 ft -lbs 6,790 ft -lbs 4-1/2" Tenaris TXP Operating Limit Torques Casing OD Operating Yield 4.5" 6,790 ft -lbs 1 8,890 ft -lbs Page 39 6 CONNECTION DATA t GEOMETRY Milne Point Unit Connection OD 5.000 in- Cmplinq Lary& 9.075 in. Connection ID F-116 Kuparuk Producer Hilcorp 4016 in- ThreadsTer in 5 Connection CSD Op6m Drilling Procedure TXP& BTC Tension Eikisaacy Outside Diameter 4.500 in. Min_ Wail Thickness OT5% Grade L80 Type 1 Wall Thickness 0.275 in_ Connection OD Option REGULAR COUPLING PIPE BOBY Congression Eri a cy Grade LBO Type 1' Drift API Standard Body: Red 1 st Band: Red 1st Barad: Brown 2nd Band: lbs 2nd Band: - Brawn Type Casing 3rd Band:- 3rd Band. - 4th Hand: - GEOMETRY- Nominal CID 4500 in. Nominal 111eight 12.6 Ib€. ft Loft 3-033,47, Nantnal ID 3.8958 in. Abil Thicikness 0.271 in. Plain Enid Y',Vght 1225':tmh OD Tdera ce API PERFORMANCE Body Held Strength 288 xT000 lbs Internal Yeld 8430 psi Sl lYs 80006 psi Collapse 7500 psi 6 CONNECTION DATA t GEOMETRY _ Connection OD 5.000 in- Cmplinq Lary& 9.075 in. Connection ID 3.948 iii,. klake-up Loss 4016 in- ThreadsTer in 5 Connection CSD Op6m REGULAR PERFORMANCE Tension Eikisaacy 100.0'v Juim N'lield Sbangth 2B'&OOO x1i:CQ lintemal Pressure CApecity n 8430.000 psi lbs Congression Eri a cy 100% Compres im strergh 288.000 x100 Max.,' byNable Beading at �r'100 ft lbs External Pressure Capacity 7500.000 psi MAKE-UP TORQUES k6nimum 5650 P :Lhs Cpfn cn 6170 ft -lbs t& rrran 6790 ft -lbs OPERATION LIMIT TORQUES Operating Tr_rque 6790 fl.-I`r Yield Toaaye BBDO ft -lbs Notes This connection is fully interchangeable Wth: TKP.R BTG - 4.5 in. -10.5.r 11.8 f 13.5 1 15.1 ibsrft Page 40 Hilcorp Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 20.5 Ensure to run enough liner to provide for approx 150' overlap inside 7" casing. Ensure hanger/pkr will not be set in a 7" connection and the packer should be above the 7" float collar. 20.6 Before picking up Halliburton VersaFlex liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 20.7 M/U HAL VersaFlex liner top hanger/packer to liner. Ensure proper XO before making connection. • Lower Versaflex through rig floor & BOPE carefully to not damage elastomer sections 20.8 Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 20.9 RIH w/ liner on DP no faster than 1-2 min / stand. Watch displacement carefully and avoid surging the hole. Follow running schedule. 20.10 Fill DP with Top drive every 10 stands oras, appropriate. 20.11 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + S/O depth every 5 stands. Record torque value if it becomes necessary to rotate the string to bottom. 20.12 CBU at 7" shoe. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 20.13 RIH to TD as per running schedule. Monitor run for losses. Space out on surface according to Versaflex setting procedure. If any circulations are performed, ensure ECDS are modeled and that differential pressure at Versaflex does not exceed 80% of expansion pressure Page 41 21.0 21.1 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure Cement 4-1/2" Production Liner Circulate and condition mud for cement job, 1-2 BU Break circulation slowly and stage up rate with reciprocation. Rotate DP slowly if hole condition allows, not exceed max torque or 20 rpms Circulate minimum 3 liner annular volumes to condition hole and mud for cement job 21.2 Hold pre job safety meeting over upcoming liner cementing operations. Make room in pits for volume gained during cement job. Ensure adequate displacement volume is available. • Cement returns are not expected to surface, but may be seen after setting liner hanger and circulating, discuss how to hand returns if they are seen • Discuss pumps for displacement • Positions and expectations of all personnel involved in cement operations, have one hand in the pits specifically for strapping pits and recording volume returned. • Versaflex Specific Topics: • Toe Sleeve opening pressure for cement job • Pumping rates and pressures • Kickout set points • Max/Min rates for pumping drill pipe wiper dar and casing wiper plug • Contingencies for not landing plug • Displacement / Over Displacement volumes 21.3 RU cement head and cementing lines • Cementing darts will be loaded in Deadhorse. Ensure proper darts have been loaded. 21.4 Pump 5 bbls fresh water. Pressure test surface cement lines to 4000 psi. 21.5 Pump 60 bbls of 13.5 ppg spacer 21.6 Pump 15.8 ppg Class G Single Stage Slurry as per below calculations, 40% OH Excess: • The entire liner and liner lap is planned to be cemented Ensure cement slurry thickening time accounts for 30 min shutdown time for setting and releasing from Versaflex, confirm liner set time with HAL. And compressive strength sufficient for perforation. Section: Calculation Vol (bbls) Vol (ft3) 6-1/8" OH x 4.5" Liner: (14,178'— 13,095') x.0167 b f X 1.4 = 25.5 143.17 7" x 4.5" Liner 150' x.0186 b f = 2.8 15.7 4.5" Shoe Track 80' x .0143 b f = 3.4 19 Total Volume 31.7 177.9 Page 42 Cement Slurry System ExpandaCem Density 15.8 ppg Yield 1.16 ft3/sk Mixed Water 4.95 gal/sk Additives Super CBL, Microbond Page 42 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 21.7 Drop drill pipe dart and displace with drilling mud. • Target max displacement rates to not exceed drilling ECDs • Slow pumps enough to check for plug release, watch tattletale on cement head • Once cement exits liner shoe, slow displacement rates to 2-3 bpm. • Rotate and reciprocate during displacement if possible, check liner max TO 21.8 Continue displacing cement until drill pipe dart latches, or displacement volume has been pumped. Pressure up to shear wiper plug and pump the plug to the landing collar • If drill pipe dart does not latch, discuss with HAL rep. • Pump max 1/2 shoe track volume, if still not latch, drop primary setting ball and allow to fall to seat and set hanger off ball • Note contingency chart in HAL Versaflex wellsite instructions 21.9 Bump the plug to 500 psi and hold for 10 min. Bleed back pressure to check floats 21.10 Confirm liner hanger setting tool is intension prior to commencing Versaflex setting procedure. 21.11 Drop the Versaflex setting ball and allow to fall to seat 21.12 Pump at 1 bpm and observe constant pressure increase to predicted hanger expansion pressure. Maintain constant rate during expansion (until hanger sets). Pressure will drop after expansion. After pressure dumps, pump an addition 5-10 bbls at .5 bbl/min to clean running tool. Bleed off pressure at pump truck. 21.13 Pick up on setting tool, 50klb over neutral, to confirm hanger is set. 21.14 Bleed off pressure then set down 5klb compression and pick back up to neutral weight. 21.15 Before releasing running tool. Close BOPE and test 7" x 4-1/2" annulus to 3000 psi for 30 min, chart same. Bleed off pressure and open BOPE 21.16 Apply RH torque to 7500 ft -lb, work string l0k above below neutral to confirm all connections are torqued. Count turns. Release torque. 21.17 Set down to planned weight to release running tool. 21.18 Apply LH rotation until required torque to release is reached. Work torque down. Set down at planned release weight. 21.19 Pickup drill pipe to neutral weight and rotate to confirm collets are released and string is intact. 21.20 Once running tool is release. Pump .25-.5 bbl/min while pulling setting tool out. 21.21 Once above liner top, CBU x 2, to clean up wellbore and check for any cement returns to surface or above liner top Page 43 ff Hilcorp ft�w C—"4 21.22 POOH, L/D 4" DP and inspect running tools. 21.23 L/D remaining 4" DP out of derrick. Milne Point Unit F-116 Kuparuk Producer Drilling Procedure Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Send final "As -Run " casing tally & casing and cement report to ien el@hilcorp. com, pchan@hilcorp. com, and cdinger ,hilcorp. com. This will be included with the EOW documentation that goes to the AOGCC. Page 44 Hilcorp E—vC—paw 22.0 Perform 4-1/2" Cleanout Run & Displacement Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 22.1 If well conditions warrant, a clean out run will be performed prior to running completion tubing. Confirm with completion engineer prior. 22.2 M/U casing clean out assembly complete with casing scraper assemblies for each size casing in the hole. • 4" x 2-7/8" DP Tapered String • Casing scraper for 7" 26# casing • Casing Scraper & Bit for 4-1/2" Liner 22.3 TIH & clean out well to PBTD, confirm depth with completion engineer • Circulate as needed on trip in if string begins to take weight. • Watch as cleanout string enters liner top • Circulate hi -vis sweeps as necessary to carry debris out of wellbore. 22.4 PT 4-1/2" Liner to 4000 psi f/ 30 min. Confirm Test Pressure with OE. • 4-1/2" 12.64 L-80 Yield Internal Pressure: 8430 psi, 4290psi = 48% of Yield • 7" 26# L-80 Yield Internal Pressure: 7240 psi, 4000psi = 55% of Yield • Chart test. 22.5 Displace well to 8.8ppg 2% KCl NaCl completion brine • Confirm completion fluid with completion engineer and reservoir pressure 22.6 TOOH w/ clean out assembly. Lay down drill pipe on the trip out. Note any abnormal wear on the clean out assy. Page 45 Hilcorp 0 23.0 Run 4-1/2" Frac String Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 23.1 R/U and run 4-1/2" 12.6# L-80 TXP frac string assembly, including nipple profile, production packer and WLEG. • Ensure appropriate well control crossovers on rig floor and ready. 23.2 Makeup the tubing hanger and landing joint. 23.3 Land hanger. RILDs and test hanger (500/5000 psi). Make note of actual weight on hanger on morning rpt. 23.4 Freeze protect IA and Tubing. 23.5 Drop ball and rod and set packer 23.6 Test the tubing to 3500 psi for 30 minutes. Monitor tubing to identify any packer leaks. Record and note all pressure tests on chart. TA 23.7 Bullhead diesel freeze protect down 9-5/8" x 7" annulus if not already done so. Do not allow flow back. 23.8 Install BPV 23.9 ND BOPE 23.10 NU Tree & Pressure test to 5000 psi. 23.11 RDMO Innovation A separate sundry will be submitted for hydraulic fracture stimulation and completion operations. Page 46 24.0 Innovation Rig Diverter Schematic 3.118' KiB line 13-518' SM Technology Sine 13-S'8' Page 47 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure :ontrol Technology 3-S'8' 5M Contra 'echnology Double Ram -1V Choke line 16' Diveder Line 0 Hilcorp 25.0 Innovation Rig BOP Schematic Typical Ram Configuration 13-518" 5M Coi Annular BOP 13-518" 5M Cor Technology Dc 3-118" Kill Li 13 -SW SM Coi Technology Sii Page 48 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 2-7/8" x 5-1/2" VBR Blind Rams "~--3-118" Choke Line 2-7/8" x 5-1/2" VBR rx5M x 5M Hilcorp 26.0 Wellhead Schematic FMC Gen 5 Typical Page 49 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure r IC AkAt, Ph, ; A C elm 5,ET. r. 10, E 1 ., _ M 2, w ehrl. 1 NCH LC Ar'E.. 1 '•r %LL 'Cs r —T11 t -J a I! Lsl ' � I TIFF _ 4s11Ay 4AtG'Ew UVVTT L. LAhM FU -err., wIi', rF 15.17,dM_. 9 3 11. c.Fan - I Sev: iL Y 5 PEC h1 -.V M t()lf) M -AI 5[AL FF[^ ';1 1 l i. afar w. --Lmf @J' PIIIv 1.—__.._.. C 6M hrY K[. r E V L CR IEC E,:e_ r i aLKtri LL+,Y l DAl10�,9336 DAI 0,72-,1V9 Fc vA E ^tlCl ([111 I[7 PTIA �Ct ,a1E ICn i`6a• n � � _-- r F:tA?h I --- �ItchnWW � � 2 f A C!� tJC, PT�.'CR_.�1, 15-5,, c.rd-.hrl�_ -- 4; v< �_ rol[ e ti o.. rz5-Ii A r:y . (Fts 4•rl�. u H wr.aa.,,,rl: �.—_— 45! [FS:n. CFeWrsfY: M1:its tF Or.ec OEo-�iw +lr'FKIL�LU.P�• �.. - :RLe1NY Ht14g[F — __ 25 7 27.0 Days Vs Depth n ale, .me a v 0 a 8000 v Ln Ln m v Page 50 12000 14000 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure MPU F-116 Kuparuk Producer Days vs Depth 16000 0 5 10 15 20 25 30 Days 28.0 Formation Tops & Information Milne Point Unit F-116 Kuparuk Producer Drilling Procedure Page 51 Normal Normal Normal Normal Normal Normal Normal Normal Normal J Normal -ligh -ligh high sigh digh sigh J sigh • T 10 138 CC). r,�z MPU F-116 Formations (wp08) MD I (ft) TVDss (ft) ND (ft) Formation Pressure (psi) EMW (ppg) Gradient (psi/ft TV D) BPRF Base Permafrost 2318 1800 1838 827.1 8.7 0.45 UG4 Top Upper Ugnu 3702 2395 2433 1094.9 8.7 0.45 LA3 Top Lower Ugnu 6445 3572 3610 1624.5 8.7 0.45 SB NA Top Schrader Bluff 7559 4050 4088 1839.6 8.7 0.45 SB NB Schrader NB 7656 4092 4130 1858.5 8.7 0.45 SB OA Schrader OA 7987 4236 4274 1923.3 8.7 0.45 SB BASE Top Colville 8781 4581 4619 2078.6 8.7 0.45 HRZ Top HRZ 12917 6801 6839 3077.6 8.7 0.45 KLB Top Kalubik 12939 6820 6858 3086.1 8.7 0.45 KLGM Kalubik Gamma Marker 12973 6852 6890 3100.5 8.7 0.45 KUP_D Top Kuparuk D Shale ` �� M36 7006 7044 3803.8 10.4 0.54 KUP_C Top Kuparuk C Sand 13367 7223 7261 3920.9 10.4 0.54 KUP B7 Top Kuparuk B Silts 13373 7228 7266 3923.6 10.4 0.54 KUP A3 Top Kuparuk A Sand 13443 7294 73321 3959.3 10.4 0.54 KUP A2 13460 7310 7348 3967.9 10.4 0.54 KUP Al 13488 7336 7374 3982.0 10.4 0.54 KUP_A_BASE Top Miluveach 13548 7393 7431 4012.71 10.41 0.54 Page 51 Normal Normal Normal Normal Normal Normal Normal Normal Normal J Normal -ligh -ligh high sigh digh sigh J sigh • T 10 138 CC). r,�z Hilcorp F—v , MPU F Pad Data Sheet GENERALIZED GEOLOGICAL S.S. TVD FM a.r�r.. Gub ns• 37:� t ,aog' 975€+ 2.000' 3W 1 C Sagava riirkw 3,000' GEOLOGICAL LITH DESCRIPTION r Unconsobdated coarse to ansdlu sand and srnaam gmt.] ry wdh minae siltsiawa. a Base permafrost Inkibsds c4 sanrt clays and siltssonas with oceaskmal shers of cwt eorrtinued intarbods of sand, cloys and slftmerrres *Wl. occasional shoos of coat Yderval at •i'- 24W 91 can be sticky and ilrAt Clay inlatbods Herten 3640 and 4-140 7L C Traces or pyrite at a`- 3166 it (L.11. 34T2'. IF L Schrader Bluff Sands: 365T' er X4.3 cn A Continued layering cearstninq upward sands as abom At fire' nn•„m Y UIGNt1: rnmies of coarsening upward sands ohieh are INA;: 1_-h.C.111 made up o9: (from top to bonaml coarse sand, fine. Amid, Schrader ,sem silty shaft- @#tier de4alopad lnlar> nlnq shales as you B UGNU progress into the L and M (deepen, i466' `$ands: UgAu and 6chradar Blurt: P"%Zla hydrocarbons limited 4326• Laa*+sa tr to 6W termor of Milne darelapn nt. Nonhtm arta Is IGAI ilr'-'dl downs9ructurt and wet(F-W had oa!l. a� - L I a,cp surface casing pcint In shale bellow 4,000'M.s. Schrader Bluff Sands: My' er X4.3 cn Continued layering cearstninq upward sands as abom At fire' t r I oretpt moot ewdemed and wish occasbonal eotl- INA;: Clay r ch shale interval 43rd) to "40 It Schrader ,sem and 5chradtr Bluff. Fossala hydrocubort36rmlted B tt u l to 5w causer at Mllnt dert3apr t_ Nonm arta is dowristructurt and. wet (F-56 had sill. i466' `$ands: r` 4326• I tr IGAI cl&. a� - L n.trl surface casing pcint In shale bellow �rd''. Top Ot 5chrader Bluff 0S sand for longer reach weft. Babe Y Page 52 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure I c COMMENTS s D MOTE See individual Well program for speciifar casting desa'gn1 depths.. sizes, weights.. grades anti connections - IF SIGNIFICANT AMOUNTS OF GRAVEL ARE ENCOUNTERED WHEN DRILLING THE "111I SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISEO TO 150 SEC to ENSURE EFFECTIVE HOLE CLEANING. 4q*m No hydrates encountered on F -Pad wells drilled to date. --I*m Schrader Bluff! Possible lost circulation zone while drilling long strings and running casing_ Recommend deep setting surface casing for Kuparuk tong strings. Also, the Schrader Bluff sands are a potential differential stuck pipe Interval it left un -cased for Kuparuk long strings. It drilling over- pressure Kslublk wells, plan on covering all lower Ugnu sands with deep set surface casing. Over -pressured Kalubik intervals are found an C, L and F pads. Hilcorp E. -W , Seabee (Colville) Interval: Predominantly Interbedded si[tstone and clay with beds of sand, shale and occasional seams 5,000 of coal_ The Seabee Is generally uneventful until reaching the H.RZ. Expect good penetration rates. Seabee: Continuous clay section from 590 to 6500 ft IL -04)_ Periodic traces of calcite and 10 to 20 % dolomite a •t- 6700 ft. Page 53 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure SEVERE PACKING OFF(TIGHT HOLEISTICKING PIPE: F -57A (LACK OF HOLE CLEANING), F-87 (FAULT RELATED COMPLICATED BY OVER -PRESSURE). 11 SEYE T HOLE, STUCK PIPE INTERVAL INTERFACE KALUBIK AND KUPARUK D SHALE LOST RETURNS AND BREATHING BACK WHILE DRILLING (MOSTLY 8-112" LONG STRINGS): F•80, F -63i, F-8413, F -73A, F -33A, F -57A, F-87 & F-88. POTENTIAL OVER -PRESSURE IF DRILLING IN TRACT 22 NEAR THE KRU 3R -PAD OR NEAR INJECTION WELLS. F-80 (LATE i998) RECORDED 4200 PSI (3500 PSI HAD BEEN PREDICTED), REQUIRED 11.6 PPG MW. F-90 (2001) REQUIRED 11.1 PPG MUD WT. PENETRATE KUPARUK WITH CAUTIONI SEE INDIVIDUAL WELL PROGRAM FOR DETAILS AND BHP RESERVOIR PRESSURE TABLE (TO THE RIGHT AND MID LOWER RIGHT). ENCOUNTERED OVER -PRESSURE IN 2,103 WELLS: F-87 (11.3 PPG MW) S F -87A (10.7 PPG MW). LOST RETURNS AND BREATHING BACK WHILE RUNNING, CIRCULATING AND CEMENTING PRODUCTION CASING (MOSTLY 7" LONG STRINGS): F-84, F-34, F-17, F-95, F-92, F-80, F -8413i, F -73A, F -57A & F -87A_ C 6,000' L A H RZ: Highly Radioactive tone. Very dark, Iisslie type y shale, organic, good source rock_ HRZ may be truncated out an central portion of F -Pad and not present In ail wells. Kalubik Shale: Good log masker MK19 at 6724 to 6564'- Top HRR 6961. Unconformity erodes Kalubik and Kuparuk D 6866' intervals in northern F -Pad area. Tuff "V-(bentonifie) zone 6654'- V y possible at top of HR2_ Silts within lower Kalubik and 6818' ase H Kuparuk "0„cin become over -pressured due to high Kalubik Injection pressures Into the Kuparuk sands. F, L 6 C pe s ausa•- Kuparuk Interval: 7091' The ^D- Shale is the trap Kuparuk sediment and is known ”"D" Shale as the "Cap Rock". KUPARUK OVER -PRESSURE , C 7 MAY OCCUR IN THE. D -SHALE. "C" ,d© ,00 1 LDU Kuparuk 5to 10 ft thick In eastern F -Pad area. 7241' B LCU: LarrerCretaceous Unconfarmkty Kuparuk Kuparuk B begins below LCU. Fine to medium grain sands becoming more shaley with dep4h. Hydrocarbon 70001- bearing. 15 to 70' thick at F -Pad but pinches 7260' out to the north. A3 TKUA3: Fine grain sandstone, coarsening upward, relatively low permeability- 7014'- 15-18`W porosity, 10 to 100 and permeabildty. 7275, A2 Hydrocarbon bearing. TKA1 & TKA2: Similar to TKA3. At west edge T029'- Al only Al present due to LCU truncation. 72$5' Miluveaach shales: Predominantly 7086._ 7353' silty shake. Extend 3041400 ft below Kuparuk A1. (Cas-ing Seat 300 It below last Miluveach oil bearing sand)_ USE RECOMMENDED MUD WT TO Shale STABILIZE MILUVEACH AND KINGAK SHALES IF WELL HAS SAG ROVER TARGET. SEE WELL PROGRAM. 7260' TJGTJf 7270' Kingak: Kann* shale with thin linterbeds of 7470• TIE siftstone. The Kingak Is known to become (Ingak Shale unstable the longer it i5 left opera to drilling 7B60 fluids_ In hole angles above 45 degrees, I additional mud weight is required for hole T,ap 8260' T.o-C stabilization. In addition, hole stabilization Page 53 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure SEVERE PACKING OFF(TIGHT HOLEISTICKING PIPE: F -57A (LACK OF HOLE CLEANING), F-87 (FAULT RELATED COMPLICATED BY OVER -PRESSURE). 11 SEYE T HOLE, STUCK PIPE INTERVAL INTERFACE KALUBIK AND KUPARUK D SHALE LOST RETURNS AND BREATHING BACK WHILE DRILLING (MOSTLY 8-112" LONG STRINGS): F•80, F -63i, F-8413, F -73A, F -33A, F -57A, F-87 & F-88. POTENTIAL OVER -PRESSURE IF DRILLING IN TRACT 22 NEAR THE KRU 3R -PAD OR NEAR INJECTION WELLS. F-80 (LATE i998) RECORDED 4200 PSI (3500 PSI HAD BEEN PREDICTED), REQUIRED 11.6 PPG MW. F-90 (2001) REQUIRED 11.1 PPG MUD WT. PENETRATE KUPARUK WITH CAUTIONI SEE INDIVIDUAL WELL PROGRAM FOR DETAILS AND BHP RESERVOIR PRESSURE TABLE (TO THE RIGHT AND MID LOWER RIGHT). ENCOUNTERED OVER -PRESSURE IN 2,103 WELLS: F-87 (11.3 PPG MW) S F -87A (10.7 PPG MW). LOST RETURNS AND BREATHING BACK WHILE RUNNING, CIRCULATING AND CEMENTING PRODUCTION CASING (MOSTLY 7" LONG STRINGS): F-84, F-34, F-17, F-95, F-92, F-80, F -8413i, F -73A, F -57A & F -87A_ Hilcorp Emu comp4a, 29.0 Anticipated Drilling Hazards Surface Hole Section: Milne Point Unit F-116 Kuparuk Producer Drilling Procedure Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Remember that hydrate gas behave differently 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 efficiently — control ROP and avoid loading the hole with gas. Minimize gas belching by reducing flow rate if necessary. 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 release 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 ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti -Collison: There are a number of adjacent wells in the vicinity. 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. There are no nearby wells with a separation factor < 1.0. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations btwn 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: V/ No H2S events have been documented on drill wells on this pad. Treat every hole section as though it has the potential for H2S. 50KVT'f_ &* S w The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. Page 54 Hilcorp Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC I 25.066. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 55 Hilcorp E -w C-9.qF Intermediate & Production Hole Sections: Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 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 rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate with AV of 200 ft/min. Lost Circulation: Lost circulation has been seen in the Colville formation at EMW exceeding — 12.0 ppg. Monitor ECDs during production section to ensure ECDs stay below 12.0. Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Abnormal Pressures and Temperatures: Although Kuparuk reservoir pressure is predicted to be normal (45 psi/ft TVD), a past well in this fault block encountered trapped injection pressure in the Kuparuk D. This is the reason for the 7" top set depth and high 12.5 ppg production hole mud weight. Wellbore Stability: This well will drill through historically trouble shales, HRZ & Kalubik. Maintain sufficient MW for stability and utilize MPD to maintain constant bottom hole pressure to mitigate on/off pressure cycles. Use MPD to offset swab effect while TOOH. Follow tripping in hole schedule to manage surge pressures on shales. Anti -Collision: This well has no close approaches on the planned wellpath with a clearance factor <1.0. Monitor MWD survey for magnetic interference while drilling ahead. Faulting: There are no known faults in either hole section. H2S: Treat every hole section as though it has the potential for 1-12S. No H2S events have been documented on drill wells on "L" pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 56 Hilcorp 30.0 Innovation Rig Layout Milne Point Unit F-116 Kuparuk Producer Drilling Procedure Page 57 Hilcorp E-u Cp.Ar 31.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 58 Hilcorp 32.0 Doyon 14 Choke Manifold Schematic Milne Point Unit F-116 Kuparuk Producer Drilling Procedure Page 59 Hilco2 0 33.0 Casing Design Information 14 Calculation & Casing Design Factors Hilcorp Milne Point Unit DATE: 9.30.2019 WELL: MPU F-116 DESIGN BY: Joe Engel Design Criteria: Hole Size 12-1/4" Hole Size 8-1/2" x 9.875" Hole Size 6-1/8" Mud Density: 9.2 Mud Density: 10.8 Mud Density: 10.5 Drilling Mode MASP(8.5" x 9.875"): 2452 psi (see attached MASP determination & calculation) Production Mode MASP: 3530 psi (see attached MASP determination & calculation Milne Point Unit F-116 Kuparuk Producer Drilling Procedure Collapse Calculation: Section Calculation 1, 2, 3 Max MW gradient external stress and the casing evacuated for the internal stress Page 60 Casing Section Calculation/Specification 1 2 3 Casing OD 9-5/8" 7" 4-1/2" Top (M D) 0 0 13,095 Top (TVD) 0 0 7,005 Bottom (MD) 9,000 13,095 14,178 Bottom (TVD) 4,714 1 7,005 8,022 Length 9,000 13,095 1,083 Weight (ppf) 40 26 12.6 Grade L-80 L-80 L-80 Connection TXP TXP TXP Weight w/o Bouyancy Factor (lbs) 360,000 ' 340,470 13,646 Tension at Top of Section (lbs) 360,000 340,470 13,646 Min strength Tension (1000 lbs) 604 288 k Worst Case Safety Factor (Tension) 1.77 21.11 Collapse Pressure at bottom (Psi) E09 3,503 4,091 Collapse Resistance w/o tension (Psi) 5,410 7,500 Worst Case Safety Factor (Collapse) 1.54 ✓ 1.83 ✓ MASP (psi) 1,650 2,452 3,530 Minimum Yield (psi) 5,750 7,240 8,430 Worst case safety factor (Burst) 3.48 2.95 ✓ 2.39 f Page 60 34.0 8-1/2" x 9.875" Hole Section MASP Milne Point Unit F-116 Kuparuk Producer Drilling Procedure Maximum Anticipated Surface Pressure Calculation 118-1/2" x 9.875" Intermediate Hole Section MPU F-116 Milne Point MD TVD Planned Top: 9000 4714 Planned TD: 13095 7005 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Kalubik 7,005 F 3152 1 - 1 8.7 0.450 Offset Well Mud Densities Well MW Range Top (TVD) Bottom (TVD) Date L-55 9.5-10.5 4,640 6,736 2018 Assumptions: 1. Fracture gradient at shoe is estimated at 0.7 psi / ft based on field test data. 2. Maximum planned mud density for the 8-1/2" x 9.875" hole section is 11.0 ppg. 3. Calculations assume Kuparuk reservior contains 100% gas (worst case). 4. Calculations assume worst case event is complete evacuation of wellbore to gas. Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 9-5/8" Shoe 9000' MD / 4471' TVD 4714 (ft) x 0.7(psi/ft)= 3300 3300 (psi) - [0.1(psi/ft)*4471(ft)]= I 2853 psi Drilling Mode MASP MASP from pore pressure (wellbore completely evacuated to gas) 7005(ft) x 0.45(psi/ft)= 3152 psi 3152 (psi) - [0.1(psi/ft)*7005(ft)]= 2452 psi Summary: 1. MASP while drilling Intermediate hole is governed by the wellbore completely evacuated to gas from the Kuparuk Reservior Page 61 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 35.0 6-1/8" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 11 6.125" Production Hole Section HiImT E� �� , MPU F-116 Milne Point MD TVD Planned Top: 13095 7005 Planned TD: 14178 8023 Anticinated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Kuparuk D 7,044 3804 - 10.4 0.540 Kuparuk C 7,261 3921 Oil 10.4 0.540 Kuparuk A 7,332 3959 Oil 10.4 0.540 Kup A Base 7,431 4013 Oil 10.4 0.540 Offset Well Mud Densities Well MW Top (TVD) Bottom (TVD) Date L-43 12.5-12.6 6,745 7,483 2004 Assumptions: 1. Fracture gradient at shoe is estimated at 0.7 psi /ft based on field test data. 2. Maximum planned mud density for the 6-1/8" hole section is 12.5 ppg. 3. Calculations assume the Kuparuk reservior contains 100% gas (worst case). 4. Calculations assume worst case event is complete evacuation of wellbore to gas. Fracture Pressure at 7" shoe considering a full column of gas from shoe to surface: 7005 (ft) x 0.7(psi/ft)= 4904 psi 4904 (psi) - [0.1(psi/ft)*7005(ft)]= 4203 psi Drilling Mode MASP MASP from pore pressure (wellbore completely evacuated to gas) 8023(ft) x 0.54(psi/ft)= 4332 psi 4332 (psi) - [0.1(psi/ft)*8023(ft)]= 3530ps7i Summary: 1. MASP while drilling 6-1/8" Intermediate hole is governed by wellbore com- pTeTely evacu�ed.tagas-jfrom the Kuparuk. Page 62 36.0 Spider Plot (NAD 27) (Governmental Sections) '1 1 1 r ! f JJ t F.iR4 JJ i i 1 �.I I �.... f f f • I r q r J J rl � fTl f f ! , ♦+ J Ir ' '--i,l Sec. 29 ♦ Sec. 22 It,gs. M h 1 r) l J r �f FAB It ! I J+ r 1 + it r r• ! r ... Milne Point Unit —r F-116 Kuparuk Producer Hilcoorrp E—V Drilling Procedure 36.0 Spider Plot (NAD 27) (Governmental Sections) '1 1 1 r ! f JJ t F.iR4 JJ i i 1 �.I I �.... f f f • I r q r J J rl � fTl f f ! , ♦+ J Ir ' '--i,l Sec. 29 ♦ Sec. 22 It,gs. M h 1 r) l J r �f FAB It ! I J+ r 1 + it r r• ! r ... J'lrlf+-�- 1 i r t I s q l i 1 +� ! p 1 rr r♦ ♦r ♦r �r 1 !r If - r, 9I F i=nv, i1t/r ri; IF tMILNE,P INT UNIT r rias •\ ! 1 L-14 L'4t r+ 1 i r l - r l 1♦ I f }! I r 1 r !,� 1 1+ r r � \ r ` ff J r • L , r r r r 1 1 f J ,r + r, 1{ 1 r to `r'. 11} tr rr 1 + r + J , J I �` - w. f► 1i f `tt r�r r rr f f +r I4 { t ` ' 1 fJf*'1 ! tr r 1 1 f � 10 S 5 Vr e!r fR:; 6 d r- Jf i;6251r ��,r1 , ! Y\ ADL025508 ,�� ' ; r, U013N010E ta.r 11 1, r N 4.,, i Legend to !, ♦jjjr • • MPU F-116_SHL Other Surface Hales (SHL) r i 1 `: .. rr Other Batmm Ho4Fs BHL' A r i l r � x MPU F-116 1 l \ . R \` i '- k —i . • - - - Other Wen Panus h1PU F-116_BHL O Oil and Gas 1,nh Bowrrdary 11 \ ' • Cac. 7 �\,' `R R+ ' o P1 11 ,l r r� rJ r' Pad Footpttnt 625 %` - Coarsfte (USGS 1.63k) R IIR.xr 1 Milne Point Unit � 1,25G 2,500 MPF -116 Well tupo.w 923'2019 WPOS Feet Page 63 —r li + 1 + f f f.'�A:f f ! f ♦ ,F.STAI'ei ,`1 �r 1 r r I ri f, ,r a JJ ♦J MPUF-Illi BiiL 11 1 r ADL355018' r, J 1 I UD14N010E r ♦ r J r 1 9 Ii r 4 , �J , i1 r ♦ + J r r + r JADL355017 r w 9 • 1� 1 i 1 ' � 1 t rte: 1_•. i fl,� 1 JI / + r ♦ r r♦ r r f 1 r r 1.94 ♦ I' r r r - f , I t rf r J♦ ♦ r t .Sec. 32 1 rl f IOLc• +11!!t J'lrlf+-�- 1 i r t I s q l i 1 +� ! p 1 rr r♦ ♦r ♦r �r 1 !r If - r, 9I F i=nv, i1t/r ri; IF tMILNE,P INT UNIT r rias •\ ! 1 L-14 L'4t r+ 1 i r l - r l 1♦ I f }! I r 1 r !,� 1 1+ r r � \ r ` ff J r • L , r r r r 1 1 f J ,r + r, 1{ 1 r to `r'. 11} tr rr 1 + r + J , J I �` - w. f► 1i f `tt r�r r rr f f +r I4 { t ` ' 1 fJf*'1 ! tr r 1 1 f � 10 S 5 Vr e!r fR:; 6 d r- Jf i;6251r ��,r1 , ! Y\ ADL025508 ,�� ' ; r, U013N010E ta.r 11 1, r N 4.,, i Legend to !, ♦jjjr • • MPU F-116_SHL Other Surface Hales (SHL) r i 1 `: .. rr Other Batmm Ho4Fs BHL' A r i l r � x MPU F-116 1 l \ . R \` i '- k —i . • - - - Other Wen Panus h1PU F-116_BHL O Oil and Gas 1,nh Bowrrdary 11 \ ' • Cac. 7 �\,' `R R+ ' o P1 11 ,l r r� rJ r' Pad Footpttnt 625 %` - Coarsfte (USGS 1.63k) R IIR.xr 1 Milne Point Unit � 1,25G 2,500 MPF -116 Well tupo.w 923'2019 WPOS Feet Page 63 37.0 Surface Plat (As Built) (NAD 27) 3519"21• T 14N J { _T13N Milne Point Unit F-116 Kuparuk Producer Hilcorp Drilling Procedure 37.0 Surface Plat (As Built) (NAD 27) 3519"21• T 14N J { _T13N a g1 _N SIMPSON LAOOON GRID — — + F-916 iil"IS F-�� PROJECT ■ 99 F -BI ■ F-991 a 7E ■ F-77 ■ 1 a L ■ 97 74 ■ F-73 ■ I I `t'�,�,Ya _-... ■ 96 70 ■ 69 ■ i L -PAD ■ 95 M 04 66 ■ :5 ■ I + I y11 I Y� 62 ■ 61 ` ` 7� `� 6 ■ W i ■ 92 m 57 54 ■ 53 ■ VIC9NITY MAP 508 49 W r 90 46 ■ 45 ■ • ■ 42 41as LEGEND ■ e7 38 ■ J7 ■ 1 + AS -BUILT CONDUCTOR ■ B6 34 ■ ■ ■ EASTING CONDUCTOR 30 ■ 20 y r es 26 is 25 ■ ■ ■ Z2 ■ 21 ■ OF q�� 0 62 I ■ Y to ■ 17 ■ ■ 61 N ■ 13 ■ to ■ 9 ■ � 1!T: ■ 60 6 ® 5 ■ ■ 79 2 ■ 1 ■ � • rnDihy F omhart 10200 •� -i tss OWL GRAPHIC SCALE NOTES 0 75 150 300 1, STATE PLANE CODRONATES ARE NA027, ALASKA, ZONE 4 SURVEYOR'S CERTIFICATE { IN FEET) I kith 750 tt 2 BASIS OF LOCATION IS MILNE FONT F PAD OPERATOR PROPEB Y�CISTERTIFY HAT I AM MONUMENT F- AND NSEL TO PRACTICE LAND STRt "NG IN 3. BASS OF ELEVATION IS MLNE PONT F PAD OPERATOR THE STATE OF ALASKA AND THAT MONUMENT F-3. 14S AS -BOLT REPRESENTS A SURVEY 4. CATIONS ARE NLAE PONT DATUM, MEAN SEA LEVEL MADE BY WE OR UNDER WY DIRECT SUPERM90N AND THAT ALL 5, GEODETIC COMI)INATES ARE NAD27. DIMENSIONS AND OTHER GETA14 ARE CORRECT AS OF JULY 24, 2019, Q PAD " SCALE FACTOR IS 0.99980190. 7. REFERENCE naD BOOK: HC19-04 P0. 01, a GATE OF SURVEY: JULY 24, 2019, LOCATED WITHIN PROTRACTED SEC, 08, T_ 13 N., R. 10 E., U[UTAT MERIDIAN, ALASKA WELL A.S_P. PLANT GEODETIC GEODETIC GRAVEL CELLAR SECTION N0, CQORDINATES COORDINATES POSITION(DMS) PQSi11CN{D.DD} PAD ELEV. BOX ELEV. OFFSETS F-116 Y=6,035,680.49' N=10,634.93' 7030'30.293' 74.5063924' 11.5' 11.5" 2,22TFSL X= 542,131.74' E=$,11Q.1T 14939'19.001" 149.65S278Q' 2429�FEL �' e HMcorp Alaska JAGaBS 79 �� 9 MFr Nn MPU F -PAD AS -BUILT CONDUCTOR WELL F-116 1 0 1 I.R "°°' Os,a rEDcse2 1". ts0 o c4 c aamo w ca Page 64 38.0 Drill Pipe Information 5" 19.5# S-135 NC -50 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 500204050016200 Weatherford 5" 19.50 Ib/ft S-135 W/ NC 50 6-518" OD x 3-1/4" ID Tool Joint DRILL PIPE SPECIFICATIONS Outside Diameter 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 1 23.08 lbs TOOL JOINT DATA Outside Diameter 6-5/8' Inside Diameter 3-1/4' API Drift 3-1/8' Rabbit OD, Suggested 3-1116" Minimum Make-up Torque 25,900 ft -lbs Maximum Recommend Make-up To ue 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 4276" 4276' Wall Thickness 0.362" 0.290' Cross Sectional Area 5275 sq in 4.154 sq in Maximum Hook LoadiTensile Strength 712,000 lbs 560,800 lbs Slip Crushing / 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 W1 Tool Joint 0.726 US gallft 0.726 US gallft Displacement W1 Tool Joint tO.353 US gallft 0.322 US gallft 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 65 5" 19.54 S-135 DS -50 IWr.AK3L.[C(rt�SrbnlPY.aecc='�Gne: �1 I'_°118 m--CC� Drill Pipe Configuration Pipe Body 60 ion 5. COC Pipe Body Wait Thickness n7; 0.392 Pipe Body Grade S-135 Drill Pipe Length Rance2 Connecton GPOS50 Toed Joint OD $.525 Tod Joint lD i m 3.250 Pin Torg 8 Box Tong ion;' 12 U Drill Pipe Performance Milne Point Unit F-116 Kuparuk Producer Drilling Procedure Drill Pipe Performance Sheet 80 % Insoeclion Gass Nominal Weight Designation 19.50 Drill Pipe Approximate Lerxath ri 31.5 SmoothEdge Heigh W 3FJ2 Raised Tool Joint SMYS Iry "0- coo Upset Type 0 &fax Upset OD IDT_i nv .125 Friction Factor 11.0 VE1r: Tenq a;a -ar ncL]e ta^Yaceq. Drill -Pipe Lenqth Ranae2 Perfomlance of Dril Pine with Pipe Body at Best Estimates Nominal 1 80 % Inspection Glass wloacaro rrtncaacnol neat ac 111 1 aDU.eeW►m Oparidonal Max Tr�sicn oripgelldused Weight resat 24.11 2326 rra. Z. Tories rswq ana:� Fluid Displacement Igami 0.37 0.39 Tension Orly @ 560,800 Fluid Dis lacemert r��i 3.0085 uarnm Iaur ¢3,1 QQ � u wi; Fhtid Capacity 1"010.71 0.70 0.72 39.900 10,500 FkAdCy tearal0,0106 0.31.87 0.0172 tamwx 11 36,100 Tensmn Ali' D 580,800 Drift Size cEmtx^� laamna 32.100 457,400 Hae- co ne,a earlei at as a: u: grans. 1.1: Dr`1 Do10aa1.2%'rtlue3 a rt Dt:reat; les ani may �.1.F.. Raey nllIDkxrtce, InEemal9�aSE E9aanp, anG omeraa .. Connection Performance GPDS50 { 6.625 only OD X 3.250 mu ID ) 120.000 ,rur hp91t0 R1aRt-0 TErare Pl. sKl` at aneu.atr YeYw at G>mietlbn 3epYaD9n 1' API Premum Class ca-ezy Urs? Otz7 Alaximum Make-up Torque 43,100 Tensile U6ted 1.040,600 arms; 4,100 MinlmurrMake-up Tomue 30.100 11,202,100 11,250.000 vxr -a%e ms'mlr. mnaru9 apse wua x aD9ea rlrt 9e:atla - r r45,5CC, Tool Joint Dimensions Salarced CID wlfl.435 M:nlmmn TCC! iDM DO MAPI 5.830 Premlrm Gasz tom+ Mmimwr tea rant eft Ib 5.83 Cdr!Ilerpan: Sr; l9X ,cmvma anrtGon setae Cert of fFa�... 1Nas, Too€:!Tm Torsio�l Strength 2, 71,800 Inspection Gass API Premum Class Toot JdrsTensile S:rengrh ans> 1,250. 0 les: 712,100 Elevator Shoulder Information Elevator OD 3x32 Raised 6.812 w arms; 4,100 SmoothEdge Height Nominal Tool Joint Wom to Bevel Worn to Min TJ 00 for 58,1CO 3,'32 Raised OD Diameter A.PI Premium Class r45,5CC, 1.24 BOx OQ^-' 0.812 5.925 0.093 '.930 ,500 Burs Elevator Capackv +,msl 1,558,000 1,440,200 823,600 085,000 15,038 Collapse Ass41n1ed Elevator Bore Diameter 1-115-219 —.d Ea =1 Meana Dn aS:Ymea EtvatG 6Tl. flD r[a•hEhr, anD Zlr ilta4 Et 119,1CVpE1. rrue: n raise Gevah� M mutat: ezvsa ta9aElty rlm9Yt atnaq raiewi L+qua. Pipe Body Slip Crushing Capacity a'4* Body Conli9—( 5 - OD 0.362am1 W211 S-135) 4.855 4.855 Nominal 180 % 1-pecoon Class I API Premium Chas ,W 0.382 slip CrusNnq Capacit anal 496,300 369,500 1396.500 \'!f �J fb. naaum�astint,�D�rl.surm,mn.:Vr�+rnaD.nY.+=rn�roaq et.. as Ra A ed 8 Len Tran verse Load Factor r,Kl dm715.5 r.l inM 9ph� Nb�0i, 4rN8bsr. JnrnA+rtiafu.rnr �ltln Jc.n.wrkr dr.re n.'ranwlil+gka•anrwem Dti rb rro,..ns.mam nann.^Ermen, .rb+a=w+aiur, m...n 4.2 ab.,rxa Pipe Bodv Performance Prc Body Confit { 5 ism OD 0.362 srr W20 S-135) r rant Pr,deco Page 66 1_: Na, ft 111 cacwa9edffi TS! RBW �nm. a,e�trw 1�a•I'"OaM ¢ar.Wl maxdpe t'at tiAt QfefSi tln arE DCr Q1 a, bd 1arc ID hitt: b Cu5LCf118r Clealee 99-14-^_013 Nominal Inspection Gass API Premum Class Pipe Tensile Strength les: 712,100 5w. Sao Pipe TarsionalStrength arms; 4,100 58,1CO TJJPipeBody Torsional Raiio 0.97 r45,5CC, 1.24 8.0% Pipe Torsional Syengri rttib, 58,300 ,500 Burs lou', 17,105 15,038 Collapse loan 15,972 10,024 Pipe OD 1m} 5.000 4.855 4.855 4Nall Thickness ,W 0.382 0.29C '029D Nominal Pipe ID imm 4.270 4.279 4278 Cross Sectional Area & F'ipe Body iir :z' 5.275 4.154 4.154 Cress Sectoral Area & OD w2) 10.035 18.514 18.514 Crass Sectoral Area & ID na•_s. 14.350 14.390 14.3eO Section Modulus Im-7F 5.708 4.476 4.475 Polar Section Modulus n-3:111.415 8.953 8.963 1_: Na, ft 111 cacwa9edffi TS! RBW �nm. a,e�trw 1�a•I'"OaM ¢ar.Wl maxdpe t'at tiAt QfefSi tln arE DCr Q1 a, bd 1arc ID hitt: b Cu5LCf118r Clealee 99-14-^_013 Hilcorp 4" 14# S-135 HT -38 Milne Point Unit F-116 Kuparuk Producer Drilling Procedure 400204138036211 1W Weatherford 4" 14.00 Ib/ft Intemal Coating S-135 w/ HT 38 4-7/8" OD x 2-9/16" ID w/ X 7000 Hard Banding Tool Joint DRILL PIPE SPECIFICATIONS Grade S-135 Connection HT 38 Interchangeable With 2-7116" UpsetType IU Internal Coating TK 34 XT Nominal Weight per Foot 14.00 lbs Adjusted Weight With Tool Joint per Foot 15.65 lbs TOOL JOINT DATA Outside Diameter 4-718' Inside Diameter 2-9116" API Drift 2-7116" Rabbit OD. Suggested 2-318' Hard Band X 7000 Minimum Make-up Torque 12,200 ft -lbs Maximum Recommend Make-up TorqueTorq!!ej 17,700 ft4bs Torsional Yieki Strength 29,500 ft -lbs Tensile Strength 649.200 lbs TUBE DATA New Premium Outside Diameter 4.000' 3.868' Inside Diameter 3.340' 3.340' Wall Thickness 0.330' 0.264' Cross Sectional Area 3.805 sg in , 513,600 lbs 2.989 sq in 403,500 lbs Maximum Hook Load/Tensile Strength Crushing (SDXL) 431,900 lbs 341,300 lbs Burst Pressure �19,500psi __ 18,400 psi Collapse Pressure _ _20.100 psi _ 13,800 psi Torsional Yield Strength 41.900 ft -lbs 32,800 ft -lbs Capacity Wt Tool Joint 1 0.442 US oaVft 1T0.442 US qaVft Displacement Wt Tool Joint 0.240 US gaVft 1 0.223 US qaVIt 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 67 Hilcorp Alaska, LLC Milne Point M Pt F Pad Plan: MPU F-116 MPU F-116 Plan: MPU F-116 WP08 Standard Proposal Report 17 September, 2019 HALLIBURTON Sperry Drilling Services HALLIBURTON Sperry Grilling Project: Milne Point Site: M Pt F Pad Well: Plan: MPU F-11 Wellbore: MPU F-116 Design: MPU F-116 WP08 0 750 1500 c_ �0. 3000 N 0 3750 U 4500 r i d I` 5250 Sec MDInc SURVEY PROGRAM Azi TVD +N/ -S +E/ -W Dleg TFace VSect Target Annotation 1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.00 Tool 2 MWD+IFR2+MS+Sag 2 400.00 0.00 0.00 400.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3°/100' : 400' MD, 400'ND 3500.00 6967.06 3.00 47.85 499.95 1.76 1.94 3.00 47.85 2.62 Start Dir 4°/100' : 500' MD, 499.95'ND 4 1500.00 43.00 47.85 1401.88 258.67 285.78 4.00 0.00 385.35 KUPD 5 2025.00 64.00 47.85 1712.42 540.30 596.91 4.00 0.00 804.88 13443.35 6 2085.71 64.58 50.47 1738.76 576.07 638.29 4.00 76.80 859.58 End Dir : 2085.71' MD, 1738.76' TVD 7 7041.10 64.58 50.47 3866.00 3424.81 4090.15 0.00 0.00 5334.15 MPF -116 wpO4a CP1 Northing 8 7541.10 64.58 50.47 4080.64 3712.25 4438.44 0.00 0.00 5785.63 Start Dir 2°/100' : 7541.1' MD, 4080.64'TVD 97620.11 ry $ 10 64.24 48.76 4114.77 3758.43 4492.72 2.00 -102.56 5856.90 End Dir : 7620.11' MD, 4114.77' TVD 10 11609.03 64.24 48.76 5848.09 6126.98 7194.03 0.00 0.00 9449.40 Start Dir 4°/100' : 11609.03' MD, 5848.099ND 11 12716.28 20.00 45.32 6649.18 6613.32 7730.57 4,00 -178,32 10173,32 Endow : 12716.28' MD, 6649.18' ND 12 13316.2820.00 45.32 7213.00 6757.61 7876.48 0.00 0.00 10378.05 MPF -116 wp06 tgtl 13 13928.18 20.00 45.32 7788.00 6904.77 8025.29 0.00 0.00 10586.84 MPF -116 Wp06 tgt2 14 14178.18 20.00 45.32 8022.92 6964.89 8086.09 0.00 0.00 10672.14 Total Depth : 14178.18' MD, 8022.92' TVD e REFERENCE INFORMATION UG4 0o Co-ordinate (N/E) Reference: Well Plan: MPU F-116, True North J o Vertical (TVD) Reference: MPU F-116 Planned RKB ® 38.00usft (Original Well Elev) yho o Measured Depth Reference: MPU F-116 Planned RKB ® 38.00usft (Original Well Elev) Calculation Method: Minimum Curvature 'o 0 LA3_ _ oyo o MPF -116 wp04a CPI Start Dir 2'/100': 7541.1' MD, 40B0.64'lVD SE NA_ r`y - - a End Dir : 7620.11' MD, 4114.77' TVD as Na- SB_OA 38_06 - my� $ 9518-.121/4- SB-BASEOpp 0 00 Dy O A. 0 DPath TVDssPath MID ath SURVEY PROGRAM 838.60 1800.60 2318.29 BPRF CASING DETAILS 16'x171/2' d 3429.78 0-:201-17r00:00:00 Validatea:Ves Version: 432.67 2394.67 ND NDSS MD Size Name 6445.07 _Start Dir 3-1100': 400' MD, 400'ND 88.29 Depth Fram Depth To SurveylPan 21.50 9000.00 MPU F-116 WPOs (MPU F-116) Tool 2 MWD+IFR2+MS+Sag S9 NA 113.00 714.38 75.00 4676.38 113.00 9000.00 16 16' x 17 12° 9-5/8 9 5/B' x 12 1/4' 274.35 rygg 7987.36 9000.00 13095.00 MPU F-116 WPOa (MPU F-111) 2 MD FIR +MS+Sa9 4340.31 005.06 6967.06 13095.00 7 7' x 8 12' 8781.24 Stan Dir 4°/1 O0': 500' MD, 499.957VD 838.62 1309500 14178.18 MPU F-116 WPOS (MPU F-116) 2_MWD+IFR2+MS+Sa9 HRZ 022.92 7984.92 14178.18 4-1/2 412'61/8' I0p0 6852.30 - KLGM 13136.34 KUPD End Dir : 2085.71' MD, 1738.76' ND 13366.87 KUP C Hilcerp Alaska, LLC 28.21 13372.91 KUPB7 ".915.91 ,O 13443.35 KUPA3 09.63 WELL DETAILS: Plan: MPU F-116 35.9513487.56 KUPAl Calculation Method: Minimum Curvature 13548.67 KUP A BASE 11 50 BPRF_ _ h Error System: ISCWSA Scan Method: Closest Approach 3D +N/ -S +E/ -W Northing Easling Latittude Longitude _ - --- - --- - --- '- ---`V Qom Error Surface: Pedal Curve Warming Method: Enor Ratio 0.00 0.00 6035680.49 542131'74 70' 30'30.213 N 149° 39' 19.001 ry $ 10 e REFERENCE INFORMATION UG4 0o Co-ordinate (N/E) Reference: Well Plan: MPU F-116, True North J o Vertical (TVD) Reference: MPU F-116 Planned RKB ® 38.00usft (Original Well Elev) yho o Measured Depth Reference: MPU F-116 Planned RKB ® 38.00usft (Original Well Elev) Calculation Method: Minimum Curvature 'o 0 LA3_ _ oyo o MPF -116 wp04a CPI Start Dir 2'/100': 7541.1' MD, 40B0.64'lVD SE NA_ r`y - - a End Dir : 7620.11' MD, 4114.77' TVD as Na- SB_OA 38_06 - my� $ 9518-.121/4- SB-BASEOpp 0 00 Dy O A. 0 DPath TVDssPath MID ath Formation 838.60 1800.60 2318.29 BPRF 315.74 2277.74 3429.78 SV 7 432.67 2394.67 3702.17 UG4 610.14 3572.14 6445.07 LA3 88.29 4050.29 7558.89 S9 NA 130.37 4092.37 7656.01 SB NB 274.35 4236.35 7987.36 SB OA 378.31 4340.31 8226.60 SB OB 619.32 4581.32 8781.24 SB BASE 838.62 6800.62 12917.87 HRZ 858.46 6820.46 12938.99 KLB 890.30 6852.30 12972.87 KLGM 13136.34 KUPD 22.54 13366.87 KUP C 28.21 13372.91 KUPB7 ".915.91 94.41 13443.35 KUPA3 09.63 13459.55 KUPA2 35.9513487.56 KUPAl 93.37 13548.67 KUP A BASE Start Dir 4°/100' :11609.03' MD, 5848.09'TVD 6000 --- oat---- A2500 End Dir : 12716.28' MD, 6649.18' ND HRZ 6750- - _ -- _ _. -_ . ,-___ K- L ,- --Start ESP t t - _KLGM__ KUPR %`PgG _ _ _ End ESP tangent . KUPC -- ' ' - - - -' 7' x 81/2' - .. -- - - --. - _ __ - _ _ - - ._ _ - _ _ _ _ _ _ - MPF 116 Ig KUP B7�P_ AS ^3500 - Wp06 t1 _ ..... .. .. .. - ._KUP A2 7500 _ _ - - _ - - - _ _ - _ - _ _ - _ - - - KUP_A1 - MPF -116 wp06 tgt2 NUP_A BASE 'A0� 412'x61/8" AT$' - - - - - - - Total Depth : 14178.18' MD, 8022.92' ND 8250 MPU F-116 WPO8 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 Vertical Section at 49.26' (1500 usft/in) I 4667 9 5/8" x 12 1/4" mm End D, : 2085.71' Mm, 1738.76' TVD Start Dv 4°/100': 5W'MD, 499.95TVD . v-- ----Start Dir 3"/IW': 40W MD, 4001VD -667 0 667 1333 2000 2667 NfPF-116wp04a CPI Q End Dir : 7620.11' MD, 4114.77' N S—Dir 24100' : 7541.1' MD, 4080.64 rVD VeF-I Iti xpW tgt2 MPU F-1161VP08 MPF -116 %p06 tg[I 7"x 812'---- ?r$ 41/2'. 61/8" 0 s � g TotW Depth: 14178.18' MD, 8022.92' TVD End ESP -g— Start ESP Iangenl E,ul Dv : 12716.28' MD, 6649.18' TVD Start Dir4"/100': 11609.03' MD, 5848.09'TVD 3333 4000 4667 5333 6000 6667 7333 8000 8667 West( -)/East(+) (1000 usft/in) WELL DETAILS: Plan: MPU F-116 Project: Milne Point 11.50 Site: M Pt F Pad +N/ -S +E/ -w Northing Ea4ing L.UI. c L—giNdc Well: Plan: MPU F-116 6667 0.00 0.00 6035630.49 542131.74 70° 30' 30.213 N 149° 39' 19.001 W Wellbore: MPU F-116 Plan: MPU F-116 WP08 CASING DETAILS TVD TVDSSMD Size Name 113.00 4714.38 75.00 113.00 16 16• x 1712' 4676.38 9000.00 9-5/8 9 5/8' x 12 1/4" HALLIBURTON 6000 7005.06 6967.06 13095.00 7 7• x 8 12' 8022.92 7964.92 14178.18 4-12 41/2•x61/8' Bp ... y U�illing REFERENCE INFORMATION C ,dinaie (NEI Reference: Well Plan: MPU F-116, Tena NOM 5333 V,rB I (vD) Reference: ASU F-116 Planned Rn @ 38.NO .ft (Original Well Elev) Measured DepON Rea MPU F-116 PlRn ® 36.WO ,ft (Odginal Well Elev) efenrs: Manned Calculation m,tI—I: Minimum Curvature 4667 9 5/8" x 12 1/4" mm End D, : 2085.71' Mm, 1738.76' TVD Start Dv 4°/100': 5W'MD, 499.95TVD . v-- ----Start Dir 3"/IW': 40W MD, 4001VD -667 0 667 1333 2000 2667 NfPF-116wp04a CPI Q End Dir : 7620.11' MD, 4114.77' N S—Dir 24100' : 7541.1' MD, 4080.64 rVD VeF-I Iti xpW tgt2 MPU F-1161VP08 MPF -116 %p06 tg[I 7"x 812'---- ?r$ 41/2'. 61/8" 0 s � g TotW Depth: 14178.18' MD, 8022.92' TVD End ESP -g— Start ESP Iangenl E,ul Dv : 12716.28' MD, 6649.18' TVD Start Dir4"/100': 11609.03' MD, 5848.09'TVD 3333 4000 4667 5333 6000 6667 7333 8000 8667 West( -)/East(+) (1000 usft/in) FA 3 iq on =inat • \I Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt F Pad Well: Plan: MPU F-116 Wellbore: MPU F-116 Design: MPU F-116 WP08 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU F-116 TVD Reference: MPU F-116 Planned RKB @ 38.00usft (Original' MD Reference: MPU F-116 Planned RKB @ 38.00usft (Original' North Reference: True Survey Calculation Method: Minimum Curvature Project Milne Point, ACT, MILNE POINT 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 6,029,958.49usft Latitude: 531,814.44usft Longitude: 0" Grid Convergence: 6,035,680.49 usfl Latitude: 542,131.74 usfl Longitude: usfl Ground Level: Wellbore MPU F-116 Magnetics Model Name Sample Date Declination Dip Angle (°) (°) BGGM2018 10/4/2019 16.45 Design MPU F-116 WP08 Audit Notes: Version: Phase: PLAN Tie On Depth: Vertical Section: Depth From (TVD) +N/ -S +E/ -W (usft) (usft) (usft) 26.50 0.00 0.00 Plan Sections +E/ -W -_ _ -- --- ----._.._----------- Site M Pt F Pad, TR -13-10 (usft) Site Position: Northing: From: Map Easting: Position Uncertainty: 0.00 usft Slot Radius: Well Plan: MPU F-116 Inclination Azimuth Well Position +N/ -S 0.00 usft Northing: +E/ -W 0.00 usft Easting: Position Uncertainty 0.00 usft Wellhead Elevation: 6,029,958.49usft Latitude: 531,814.44usft Longitude: 0" Grid Convergence: 6,035,680.49 usfl Latitude: 542,131.74 usfl Longitude: usfl Ground Level: Wellbore MPU F-116 Magnetics Model Name Sample Date Declination Dip Angle (°) (°) BGGM2018 10/4/2019 16.45 Design MPU F-116 WP08 Audit Notes: Version: Phase: PLAN Tie On Depth: Vertical Section: Depth From (TVD) +N/ -S +E/ -W (usft) (usft) (usft) 26.50 0.00 0.00 Plan Sections +E/ -W (usft) (usft) 0.00 Measured 0.00 0.00 Vertical TVD Depth Inclination Azimuth Depth System (usft) (°) (°) (usft) usft 26.50 0.00 0.00 26.50 -11.50 400.00 0.00 0.00 400.00 362.00 500.00 3.00 47.85 499.95 461.95 1,500.00 43.00 47.85 1,401.88 1,363.88 2,025.00 64.00 47.85 1,712.42 1,674.42 2,085.71 64.58 50.47 1,738.76 1,700.76 7,041.10 64.58 50.47 3,866.00 3,828.00 7,541.10 64.58 50.47 4,080.64 4,042.64 7,620.11 64.24 48.76 4,114.77 4,076.77 11,609.03 64.24 48.76 5,848.09 5,810.09 12,716.28 20.00 45.32 6,649.18 6,611.18 13,316.28 20.00 45.32 7,213.00 7,175.00 13,928.18 20.00 45.32 7,788.00 7,750.00 14,178.18 20.00 45.32 8,022.92 7,984.92 +N/ -S +E/ -W (usft) (usft) 0.00 0.00 0.00 0.00 1.76 1.94 258.67 285.78 540.30 596.91 576.07 638.29 3,424.81 4,090.15 3,712.25 4,438.44 3,758.43 4,492.72 6,126.98 7,194.03 6,613.32 7,730.57 6,757.61 7,876.48 6,904.77 8,025.29 6,964.89 8,086.09 80.97 26.50 Direction (I 49.26 70° 29'34.438 N 149° 44'23.616 W 0.25 ° 70° 30'30.213 N 149° 39' 19.001 W 11.50 usft Field Strength (nT) 57,415.09702087 Dogleg Build Turn Rate Rate Rate (°/100usft) (°/100usft) (°/100usft) 0.00 0.00 0.00 0.00 0.00 0.00 3.00 3.00 0.00 4.00 4.00 0.00 4.00 4.00 0.00 4.00 0.95 4.31 0.00 0.00 0.00 0.00 0.00 0.00 2.00 -0.42 -2.17 0.00 0.00 0.00 4.00 -4.00 -0.31 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Tool Face 0.00 0.00 47.85 0.00 0.00 76.80 0.00 0.00 -102.56 0.00 -178.32 0.00 0.00 0.00 9/17/2019 5:17:34PM Page 2 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt F Pad Well: Plan: MPU F-116 Wellbore: MPU F-116 Design: MPU F-116 WP08 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU F-116 TVD Reference: MPU F-116 Planned RKB @ 38.00usft (Original' MD Reference: MPU F-116 Planned RKB @ 38.00usft (Original' North Reference: True Survey Calculation Method: Minimum Curvature Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (1) (1) (usft) usft (usft) (usft) (usft) (usft) -11.50 26.50 0.00 0.00 26.50 -11.50 0.00 0.00 6,035,680.49 542,131.74 0.00 0.00 100.00 0.00 0.00 100.00 62.00 0.00 0.00 6,035,680.49 542,131.74 0.00 0.00 113.00 0.00 0.00 113.00 75.00 0.00 0.00 6,035,680.49 542,131.74 0.00 0.00 16" x 17 1/2" 200.00 0.00 0.00 200.00 162.00 0.00 0.00 6,035,680.49 542,131.74 0.00 0.00 300.00 0.00 0.00 300.00 262.00 0.00 0.00 6,035,680.49 542,131.74 0.00 0.00 400.00 0.00 0.00 400.00 362.00 0.00 0.00 6,035,680.49 542,131.74 0.00 0.00 Start Dir 3°/100' : 400' MD, 4007VD 500.00 3.00 47.85 499.95 461.95 1.76 1.94 6,035,682.26 542,133.67 3.00 2.62 Start Dir 41/100' : 500' MD, 499.95'TVD 600.00 7.00 47.85 599.55 561.55 7.60 8.40 6,035,688.14 542,140.10 4.00 11.33 700.00 11.00 47.85 698.30 660.30 18.10 20.00 6,035,698.70 542,151.63 4.00 26.96 800.00 15.00 47.85 795.72 757.72 33.19 36.67 6,035,713.89 542,168.22 4.00 49.45 900.00 19.00 47.85 891.33 853.33 52.81 58.34 6,035,733.62 542,189.78 4.00 78.67 1,000.00 23.00 47.85 984.67 946.67 76.85 84.91 6,035,757.82 542,216.20 4.00 114.49 1,100.00 27.00 47.85 1,075.28 1,037.28 105.21 116.23 6,035,786.35 542,247.36 4.00 156.73 1,200.00 31.00 47.85 1,162.73 1,124.73 137.74 152.17 6,035,819.07 542,283.11 4.00 205.18 1,300.00 35.00 47.85 1,246.58 1,208.58 174.28 192.54 6,035,855.84 542,323.27 4.00 259.62 1,400.00 39.00 47.85 1,326.42 1,288.42 214.66 237.15 6,035,896.47 542,367.64 4.00 319.77 1,500.00 43.00 47.85 1,401.88 1,363.88 258.67 285.78 6,035,940.75 542,416.02 4.00 385.35 1,600.00 47.00 47.85 1,472.58 1,434.58 306.12 338.19 6,035,988.49 542,468.16 4.00 456.02 1,700.00 51.00 47.85 1,538.17 1,500.17 356.75 394.13 6,036,039.44 542,523.81 4.00 531.45 1,800.00 55.00 47.85 1,598.34 1,560.34 410.34 453.33 6,036,093.35 542,582.69 4.00 611.28 1,900.00 59.00 47.85 1,652.79 1,614.79 466.61 515.50 6,036,149.97 542,644.53 4.00 695.10 2,000.00 63.00 47.85 1,701.26 1,663.26 525.29 580.33 6,036,209.01 542,709.02 4.00 782.52 2,025.00 64.00 47.85 1,712.42 1,674.42 540.30 596.91 6,036,224.11 542,725.52 4.00 804.88 2,085.71 64.58 50.47 1,738.76 1,700.76 576.07 638.29 6,036,260.11 542,766.69 4.00 859.58 End Dir : 2085.71' MD, 1738.76' TVD 2,100.00 64.58 50.47 1,744.89 1,706.89 584.28 648.25 6,036,268.38 542,776.60 0.00 872.48 2,200.00 64.58 50.47 1,787.82 1,749.82 641.77 717.91 6,036,326.26 542,845.92 0.00 962.78 2,300.00 64.58 50.47 1,830.75 1,792.75 699.26 787.56 6,036,384.13 542,915.25 0.00 1,053.07 2,318.29 64.58 50.47 1,838.60 1,800.60 709.77 800.31 6,036,394.72 542,927.93 0.00 1,069.59 BPRF 2,400.00 64.58 50.47 1,873.68 1,835.68 756.74 857.22 6,036,442.01 542,984.57 0.00 1,143.37 2,500.00 64.58 50.47 1,916.60 1,878.60 814.23 926.88 6,036,499.89 543,053.90 0.00 1,233.67 2,600.00 64.58 50.47 1,959.53 1,921.53 871.72 996.54 6,036,557.76 543,123.22 0.00 1,323.97 2,700.00 64.58 50.47 2,002.46 1,964.46 929.21 1,066.20 6,036,615.64 543,192.55 0.00 1,414.26 2,800.00 64.58 50.47 2,045.39 2,007.39 986.70 1,135.86 6,036,673.52 543,261.87 0.00 1,504.56 2,900.00 64.58 50.47 2,088.32 2,050.32 1,044.18 1,205.52 6,036,731.39 543,331.20 0.00 1,594.86 3,000.00 64.58 50.47 2,131.24 2,093.24 1,101.67 1,275.18 6,036,789.27 543,400.52 0.00 1,685.15 3,100.00 64.58 50.47 2,174.17 2,136.17 1,159.16 1,344.83 6,036,847.14 543,469.85 0.00 1,775.45 3,200.00 64.58 50.47 2,217.10 2,179.10 1,216.65 1,414.49 6,036,905.02 543,539.17 0.00 1,865.75 3,300.00 64.58 50.47 2,260.03 2,222.03 1,274.14 1,484.15 6,036,962.90 543,608.50 0.00 1,956.05 3,400.00 64.58 50.47 2,302.95 2,264.95 1,331.62 1,553.81 6,037,020.77 543,677.82 0.00 2,046.34 9/1712019 5:17:34PM Page 3 COMPASS 5000.15 Build 91 Halliburton HALLIBURT®N Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU F-116 Company: Hilcorp Alaska, LLC TVD Reference: MPU F-116 Planned RKB @ 38.00usft (Original Project: Milne Point MD Reference: MPU F-116 Planned RKB @ 38.00usft (Original''' Site: M Pt F Pad North Reference: True Well: Plan: MPU F-116 Survey Calculation Method: Minimum Curvature Wellbore: MPU F-116 (1) (1) Design: MPU F-116 WP08 (usft) (usft) Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (1) (1) (usft) usft (usft) (usft) (usft) (usft) 2,277,74 3,429.78 64.58 50.47 2,315.74 2,277.74 1,348.75 1,574.56 6,037,038.01 543,698.47 0.00 2,073.24 SV1 3,500.00 64.58 50.47 2,345.88 2,307.88 1,389.11 1,623.47 6,037,078.65 543,747.15 0.00 2,136.64 3,600.00 64.58 50.47 2,388.81 2,350.81 1,446.60 1,693.13 6,037,136.53 543,816.47 0.00 2,226.94 3,700.00 64.58 50.47 2,431.74 2,393.74 1,504.09 1,762.79 6,037,194.40 543,885.80 0.00 2,317.23 3,702.17 64.58 50.47 2,432.67 2,394.67 1,505.34 1,764.30 6,037,195.66 543,887.30 0.00 2,319.19 LIG4 3,800.00 64.58 50.47 2,474.67 2,436.67 1,561.58 1,832.44 6,037,252.28 543,955.12 0.00 2,407.53 3,900.00 64.58 50.47 2,517.59 2,479.59 1,619.06 1,902.10 6,037,310.16 544,024.44 0.00 2,497.83 4,000.00 64.58 50.47 2,560.52 2,522.52 1,676.55 1,971.76 6,037,368.03 544,093.77 0.00 2,588.13 4,100.00 64.58 50.47 2,603.45 2,565.45 1,734.04 2,041.42 6,037,425.91 544,163.09 0.00 2,678.42 4,200.00 64.58 50.47 2,646.38 2,608.38 1,791.53 2,111.08 6,037,483.79 544,232.42 0.00 2,768.72 4,300.00 64.58 50.47 2,689.31 2,651.31 1,849.02 2,180.74 6,037,541.66 544,301.74 0.00 2,859.02 4,400.00 64.58 50.47 2,732.23 2,694.23 1,906.50 2,250.40 6,037,599.54 544,371.07 0.00 2,949.31 4,500.00 64.58 50.47 2,775.16 2,737.16 1,963.99 2,320.06 6,037,657.41 544,440.39 0.00 3,039.61 4,600.00 64.58 50.47 2,818.09 2,780.09 2,021.48 2,389.71 6,037,715.29 544,509.72 0.00 3,129.91 4,700.00 64.58 50.47 2,861.02 2,823.02 2,078.97 2,459.37 6,037,773.17 544,579.04 0.00 3,220.21 4,800.00 64.58 50.47 2,903.95 2,865.95 2,136.45 2,529.03 6,037,831.04 544,648.37 0.00 3,310.50 4,900.00 64.58 50.47 2,946.87 2,908.87 2,193.94 2,598.69 6,037,888.92 544,717.69 0.00 3,400.80 5,000.00 64.58 50.47 2,989.80 2,951.80 2,251.43 2,668.35 6,037,946.80 544,787.02 0.00 3,491.10 5,100.00 64.58 50.47 3,032.73 2,994.73 2,308.92 2,738.01 6,038,004.67 544,856.34 0.00 3,581.39 5,200.00 64.58 50.47 3,075.66 3,037.66 2,366.41 2,807.67 6,038,062.55 544,925.67 0.00 3,671.69 5,300.00 64.58 50.47 3,118.58 3,080.58 2,423.89 2,877.33 6,038,120.43 544,994.99 0.00 3,761.99 5,400.00 64.58 50.47 3,161.51 3,123.51 2,481.38 2,946.98 6,038,178.30 545,064.32 0.00 3,852.29 5,500.00 64.58 50.47 3,204.44 3,166.44 2,538.87 3,016.64 6,038,236.18 545,133.64 0.00 3,942.58 5,600.00 64.58 50.47 3,247.37 3,209.37 2,596.36 3,086.30 6,038,294.06 545,202.96 0.00 4,032.88 5,700.00 64.58 50.47 3,290.30 3,252.30 2,653.85 3,155.96 6,038,351.93 545,272.29 0.00 4,123.18 5,800.00 64.58 50.47 3,333.22 3,295.22 2,711.33 3,225.62 6,038,409.81 545,341.61 0.00 4,213.47 5,900.00 64.58 50.47 3,376.15 3,338.15 2,768.82 3,295.28 6,038,467.68 545,410.94 0.00 4,303.77 6,000.00 64.58 50.47 3,419.08 3,381.08 2,826.31 3,364.94 6,038,525.56 545,480.26 0.00 4,394.07 6,100.00 64.58 50.47 3,462.01 3,424.01 2,883.80 3,434.59 6,038,583.44 545,549.59 0.00 4,484.37 6,200.00 64.58 50.47 3,504.94 3,466.94 2,941.29 3,504.25 6,038,641.31 545,618.91 0.00 4,574.66 6,300.00 64.58 50.47 3,547.86 3,509.86 2,998.77 3,573.91 6,038,699.19 545,688.24 0.00 4,664.96 6,400.00 64.58 50.47 3,590.79 3,552.79 3,056.26 3,643.57 6,038,757.07 545,757.56 0.00 4,755.26 6,445.07 64.58 50.47 3,610.14 3,572.14 3,082.17 3,674.97 6,038,783.15 545,788.81 0.00 4,795.96 LA3 6,500.00 64.58 50.47 3,633.72 3,595.72 3,113.75 3,713.23 6,038,814.94 545,826.89 0.00 4,845.55 6,600.00 64.58 50.47 3,676.65 3,638.65 3,171.24 3,782.89 6,038,872.82 545,896.21 0.00 4,935.85 6,700.00 64.58 50.47 3,719.57 3,681.57 3,228.73 3,852.55 6,038,930.70 545,965.54 0.00 5,026.15 6,800.00 64.58 50.47 3,762.50 3,724.50 3,286.21 3,922.21 6,038,988.57 546,034.86 0.00 5,116.45 6,900.00 64.58 50.47 3,805.43 3,767.43 3,343.70 3,991.86 6,039,046.45 546,104.19 0.00 5,206.74 7,000.00 64.58 50.47 3,848.36 3,810.36 3,401.19 4,061.52 6,039,104.33 546,173.51 0.00 5,297.04 7,041.10 64.58 50.47 3,866.00 3,828.00 3,424.81 4,090.15 6,039,128.11 546,202.00 0.00 5,334.15 7,100.00 64.58 50.47 3,891.29 3,853.29 3,458.68 4,131.18 6,039,162.20 546,242.84 0.00 5,387.34 7,200.00 64.58 50.47 3,934.21 3,896.21 3,516.17 4,200.84 6,039,220.08 546,312.16 0.00 5,477.63 9/17/2019 5:17:34PM Page 4 COMPASS 5000.15 Build 91 Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU F-116 Company: Hilcorp Alaska, LLC TVD Reference: MPU F-116 Planned RKB @ 38.00usft (Original ' ! Project: Milne Point MD Reference: MPU F-116 Planned RKB @ 38.00usft (Original', Site: M Pt F Pad North Reference: True Well: Plan: MPU F-116 Survey Calculation Method: Minimum Curvature Wellbore: MPU F-116 (1) (1) Design: MPU F-116 WP08 (usft) (usft) Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (1) (1) (usft) usft (usft) (usft) (usft) (usft) 3,939.14 7,300.00 64.58 50.47 3,977.14 3,939.14 3,573.65 4,270.50 6,039,277.95 546,381.48 0.00 5,567.93 7,400.00 64.58 50.47 4,020.07 3,982.07 3,631.14 4,340.16 6,039,335.83 546,450.81 0.00 5,658.23 7,500.00 64.58 50.47 4,063.00 4,025.00 3,688.63 4,409.82 6,039,393.71 546,520.13 0.00 5,748.53 7,541.10 64.58 50.47 4,080.64 4,042.64 3,712.26 4,438.45 6,039,417.49 546,548.63 0.00 5,785.64 Start Dir 2°/100' : 7541.1' MD, 4080.64'TVD 7,558.89 64.50 50.08 4,088.29 4,050.29 3,722.52 4,450.80 6,039,427.83 546,560.92 2.00 5,801.70 SB NA 7,600.00 64.33 49.19 4,106.04 4,068.04 3,746.53 4,479.05 6,039,452.00 546,589.03 2.00 5,838.78 7,620.11 64.24 48.76 4,114.77 4,076.77 3,758.43 4,492.72 6,039,463.97 546,602.63 2.00 5,856.89 End Dir : 7620.11' MD, 4114.77' TVD 7,656.01 64.24 48.76 4,130.37 4,092.37 3,779.75 4,517.04 6,039,485.42 546,626.82 0.00 5,889.23 SB NB 7,700.00 64.24 48.76 4,149.48 4,111.48 3,805.86 4,546.82 6,039,511.71 546,656.46 0.00 5,928.84 7,800.00 64.24 48.76 4,192.94 4,154.94 3,865.24 4,614.54 6,039,571.46 546,723.84 0.00 6,018.91 7,900.00 64.24 48.76 4,236.39 4,198.39 3,924.62 4,682.26 6,039,631.22 546,791.21 0.00 6,108.97 7,987.36 64.24 48.76 4,274.35 4,236.35 3,976.49 4,741.42 6,039,683.42 546,850.07 0.00 6,187.65 SB OA 8,000.00 64.24 48.76 4,279.84 4,241.84 3,984.00 4,749.98 6,039,690.97 546,858.59 0.00 6,199.03 8,100.00 64.24 48.76 4,323.30 4,285.30 4,043.38 4,817.70 6,039,750.73 546,925.96 0.00 6,289.09 8,200.00 64.24 48.76 4,366.75 4,328.75 4,102.76 4,885.42 6,039,810.48 546,993.34 0.00 6,379.15 8,226.60 64.24 48.76 4,378.31 4,340.31 4,118.55 4,903.44 6,039,826.38 547,011.26 0.00 6,403.11 SB OB 8,300.00 64.24 48.76 4,410.20 4,372.20 4,162.13 4,953.14 6,039,870.24 547,060.71 0.00 6,469.22 8,400.00 64.24 48.76 4,453.66 4,415.66 4,221.51 5,020.86 6,039,930.00 547,128.09 0.00 6,559.28 8,500.00 64.24 48.76 4,497.11 4,459.11 4,280.89 5,088.58 6,039,989.75 547,195.47 0.00 6,649.34 8,600.00 64.24 48.76 4,540.56 4,502.56 4,340.27 5,156.30 6,040,049.51 547,262.84 0.00 6,739.40 8,700.00 64.24 48.76 4,584.02 4,546.02 4,399.65 5,224.02 6,040,109.26 547,330.22 0.00 6,829.47 8,781.24 64.24 48.76 4,619.32 4,581.32 4,447.89 5,279.04 6,040,157.81 547,384.96 0.00 6,902.64 SB BASE 8,800.00 64.24 48.76 4,627.47 4,589.47 4,459.03 5,291.75 6,040,169.02 547,397.59 0.00 6,919.53 8,900.00 64.24 48.76 4,670.92 4,632.92 4,518.40 5,359.47 6,040,228.77 547,464.97 0.00 7,009.59 9,000.00 64.24 48.76 4,714.38 4,676.38 4,577.78 5,427.19 6,040,288.53 547,532.34 0.00 7,099.65 9 5/8" x 121/4" 9,100.00 64.24 48.76 4,757.83 4,719.83 4,637.16 5,494.91 6,040,348.29 547,599.72 0.00 7,189.71 9,200.00 64.24 48.76 4,801.28 4,763.28 4,696.54 5,562.63 6,040,408.04 547,667.10 0.00 7,279.78 9,300.00 64.24 48.76 4,844.74 4,806.74 4,755.92 5,630.35 6,040,467.80 547,734.47 0.00 7,369.84 9,400.00 64.24 48.76 4,888.19 4,850.19 4,815.30 5,698.07 6,040,527.55 547,801.85 0.00 7,459.90 9,500.00 64.24 48.76 4,931.64 4,893.64 4,874.67 5,765.79 6,040,587.31 547,869.22 0.00 7,549.96 9,600.00 64.24 48.76 4,975.10 4,937.10 4,934.05 5,833.51 6,040,647.06 547,936.60 0.00 7,640.02 9,700.00 64.24 48.76 5,018.55 4,980.55 4,993.43 5,901.23 6,040,706.82 548,003.98 0.00 7,730.09 9,800.00 64.24 48.76 5,062.00 5,024.00 5,052.81 5,968.95 6,040,766.57 548,071.35 0.00 7,820.15 9,900.00 64.24 48.76 5,105.46 5,067.46 5,112.19 6,036.67 6,040,826.33 548,138.73 0.00 7,910.21 10,000.00 64.24 48.76 5,148.91 5,110.91 5,171.57 6,104.39 6,040,886.09 548,206.10 0.00 8,000.27 10,100.00 64.24 48.76 5,192.36 5,154.36 5,230.94 6,172.11 6,040,945.84 548,273.48 0.00 8,090.33 10,200.00 64.24 48.76 5,235.82 5,197.82 5,290.32 6,239.83 6,041,005.60 548,340.85 0.00 8,180.40 9/17/2019 5:17:34PM Page 5 COMPASS 5000.15 Build 91 :iLwA041 Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt F Pad Well: Plan: MPU F-116 Wellbore: MPU F-116 Design: MPU F-116 WPOS Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU F-116 TVD Reference: MPU F-116 Planned RKB @ 38.00usft (Original' MD Reference: MPU F-116 Planned RKB @ 38.00usft (Original' North Reference: True Survey Calculation Method: Minimum Curvature Measured Map Map Vertical +E/ -W Depth Inclination Azimuth Depth TVDss +N/ -S (usft) (1) (1) (usft) usft (usft) 10,300.00 64.24 48.76 5,279.27 5,241.27 5,349.70 10,400.00 64.24 48.76 5,322.72 5,284.72 5,409.08 10,500.00 64.24 48.76 5,366.18 5,328.18 5,468.46 10,600.00 64.24 48.76 5,409.63 5,371.63 5,527.84 10,700.00 64.24 48.76 5,453.08 5,415.08 5,587.21 10,800.00 64.24 48.76 5,496.54 5,458.54 5,646.59 10,900.00 64.24 48.76 5,539.99 5,501.99 5,705.97 11,000.00 64.24 48.76 5,583.44 5,545.44 5,765.35 11,100.00 64.24 48.76 5,626.90 5,588.90 5,824.73 11,200.00 64.24 48.76 5,670.35 5,632.35 5,884.11 11,300.00 64.24 48.76 5,713.80 5,675.80 5,943.48 11,400.00 64.24 48.76 5,757.26 5,719.26 6,002.86 11,500.00 64.24 48.76 5,800.71 5,762.71 6,062.24 11,609.03 64.24 48.76 5,848.09 5,810.09 6,126.98 Start Dir 41/100' : 11609.03' MD, 5848.09'TVD 549,532.10 11,700.00 60.61 48.63 5,890.19 5,852.19 6,180.20 11,800.00 56.61 48.49 5,942.27 5,904.27 6,236.68 11,900.00 52.61 48.33 6,000.17 5,962.17 6,290.78 12,000.00 48.61 48.15 6,063.61 6,025.61 6,342.25 12,100.00 44.62 47.95 6,132.29 6,094.29 6,390.81 12,200.00 40.62 47.72 6,205.86 6,167.86 6,436.25 12,300.00 36.62 47.45 6,283.97 6,245.97 6,478.34 12,400.00 32.63 47.12 6,366.25 6,328.25 6,516.87 12,500.00 28.63 46.71 6,452.28 6,414.28 6,551.66 12,600.00 24.64 46.18 6,541.64 6,503.64 6,582.54 12,700.00 20.65 45.46 6,633.92 6,595.92 6,609.35 12,716.28 20.00 45.32 6,649.18 6,611.18 6,613.32 End Dir : 12716.28' MD, 6649.18' TVD 6,042,398.95 549,885.96 12,750.00 20.00 45.32 6,680.87 6,642.87 6,621.43 Start ESP tangent 7,822.67 6,042,428.49 549,915.49 0.00 12,800.00 20.00 45.32 6,727.85 6,689.85 6,633.45 12,900.00 20.00 45.32 6,821.82 6,783.82 6,657.50 12,917.87 20.00 45.32 6,838.62 6,800.62 6,661.80 HRZ 12,938.99 20.00 45.32 6,858.46 6,820.46 6,666.88 KLB 12,950.00 20.00 45.32 6,868.81 6,830.81 6,669.52 End ESP tangent 12,972.87 20.00 45.32 6,890.30 6,852.30 6,675.02 KLGM 13,000.00 20.00 45.32 6,915.79 6,877.79 6,681.55 13,095.00 20.00 45.32 7,005.06 6,967.06 6,704.40 7" x 8 1/2" 13,100.00 20.00 45.32 7,009.76 6,971.76 6,705.60 9/172019 5:17:34PM Page 6 COMPASS 5000.15 Build 91 Map Map +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) 5,241.27 6,307.55 6,041,065.35 548,408.23 0.00 8,270.46 6,375.27 6,041,125.11 548,475.61 0.00 8,360.52 6,442.99 6,041,184.86 548,542.98 0.00 8,450.58 6,510.71 6,041,244.62 548,610.36 0.00 8,540.64 6,578.43 6,041,304.37 548,677.73 0.00 8,630.71 6,646.15 6,041,364.13 548,745.11 0.00 8,720.77 6,713.87 6,041,423.89 548,812.48 0.00 8,810.83 6,781.59 6,041,483.64 548,879.86 0.00 8,900.89 6,849.31 6,041,543.40 548,947.24 0.00 8,990.96 6,917.03 6,041,603.15 549,014.61 0.00 9,081.02 6,984.75 6,041,662.91 549,081.99 0.00 9,171.08 7,052.47 6,041,722.66 549,149.36 0.00 9,261.14 7,120.19 6,041,782.42 549,216.74 0.00 9,351.20 7,194.03 6,041,847.57 549,290.20 0.00 9,449.40 7,254.59 6,041,901.12 549,350.45 4.00 9,530.02 7,318.57 6,041,957.96 549,414.11 4.00 9,615.36 7,379.53 6,042,012.41 549,474.75 4.00 9,696.85 7,437.17 6,042,064.19 549,532.10 4.00 9,774.11 7,491.22 6,042,113.06 549,585.86 4.00 9,846.76 7,541.40 6,042,158.78 549,635.78 4.00 9,914.43 7,587.47 6,042,201.12 549,681.61 4.00 9,976.81 7,629.22 6,042,239.89 549,723.13 4.00 10,033.59 7,666.43 6,042,274.88 549,760.14 4.00 10,084.48 7,698.92 6,042,305.94 549,792.45 4.00 10,129.25 7,726.54 6,042,332.90 549,819.92 4.00 10,167.68 7,730.57 6,042,336.89 549,823.92 4.00 10,173.32 7,738.77 6,042,345.05 549,832.07 0.00 10,184.83 7,750.93 6,042,357.14 549,844.16 0.00 10,201.89 7,775.25 6,042,381.33 549,868.34 0.00 10,236.01 7,779.59 6,042,385.65 549,872.67 0.00 10,242.11 7,784.73 6,042,390.75 549,877.77 0.00 10,249.31 7,787.41 6,042,393.42 549,880.43 0.00 10,253.07 7,792.97 6,042,398.95 549,885.96 0.00 10,260.87 7,799.57 6,042,405.51 549,892.52 0.00 10,270.13 7,822.67 6,042,428.49 549,915.49 0.00 10,302.54 7,823.88 6,042,429.69 549,916.70 0.00 10,304.25 9/172019 5:17:34PM Page 6 COMPASS 5000.15 Build 91 Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU F-116 Company: Hilcorp Alaska, LLC TVD Reference: MPU F-116 Planned RKB @ 38.00usft (Original' Project: Milne Point MD Reference: MPU F-116 Planned RKB @ 38.00usft (Original' Site: M Pt F Pad North Reference: True Well: Plan: MPU F-116 Survey Calculation Method: Minimum Curvature Wellbore: MPU F-116 Design: MPU F-116 WPO8 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 7,005.91 13,136.34 20.00 45.32 7,043.91 7,005.91 6,714.34 7,832.72 6,042,438.48 549,925.49 0.00 10,316.65 KUP_D 13,200.00 20.00 45.32 7,103.73 7,065.73 6,729.65 7,848.20 6,042,453.88 549,940.88 0.00 10,338.37 13,300.00 20.00 45.32 7,197.70 7,159.70 6,753.70 7,872.52 6,042,478.06 549,965.06 0.00 10,372.49 13,316.28 20.00 45.32 7,213.00 7,175.00 6,757.61 7,876.48 6,042,482.00 549,969.00 0.00 10,378.05 13,366.87 20.00 45.32 7,260.54 7,222.54 6,769.78 7,888.79 6,042,494.24 549,981.23 0.00 10,395.31 KUP_C 13,372.91 20.00 45.32 7,266.21 7,228.21 6,771.23 7,890.25 6,042,495.69 549,982.69 0.00 10,397.37 KUP_B7 13,400.00 20.00 45.32 7,291.67 7,253.67 6,777.74 7,896.84 6,042,502.25 549,989.24 0.00 10,406.61 13,443.35 20.00 45.32 7,332.41 7,294.41 6,788.17 7,907.39 6,042,512.73 549,999.73 0.00 10,421.41 KUP_A3 13,459.55 20.00 45.32 7,347.63 7,309.63 6,792.07 7,911.32 6,042,516.65 550,003.64 0.00 10,426.93 KUP_A2 13,487.56 20.00 45.32 7,373.95 7,335.95 6,798.80 7,918.14 6,042,523.42 550,010.42 0.00 10,436.49 KUP_All 13,500.00 20.00 45.32 7,385.64 7,347.64 6,801.79 7,921.16 6,042,526.43 550,013.42 0.00 10,440.74 13,548.67 20.00 45.32 7,431.37 7,393.37 6,813.50 7,933.00 6,042,538.20 550,025.19 0.00 10,457.34 KUP_A_BASE 13,600.00 20.00 45.32 7,479.61 7,441.61 6,825.84 7,945.48 6,042,550.62 550,037.60 0.00 10,474.86 13,700.00 20.00 45.32 7,573.58 7,535.58 6,849.89 7,969.80 6,042,574.80 550,061.78 0.00 10,508.98 13,800.00 20.00 45.32 7,667.55 7,629.55 6,873.94 7,994.12 6,042,598.98 550,085.96 0.00 10,543.10 13,900.00 20.00 45.32 7,761.52 7,723.52 6,897.99 8,018.44 6,042,623.17 550,110.14 0.00 10,577.22 13,928.18 20.00 45.32 7,788.00 7,750.00 6,904.77 8,025.29 6,042,629.98 550,116.96 0.00 10,586.84 14,000.00 20.00 45.32 7,855.49 7,817.49 6,922.04 8,042.76 6,042,647.35 550,134.32 0.00 10,611.34 14,100.00 20.00 45.32 7,949.46 7,911.46 6,946.09 8,067.08 6,042,671.54 550,158.50 0.00 10,645.46 14,178.18 20.00 45.32 8,022.92 7,984.92 6,964.89 8,086.09 6,042,690.44 550,177.41 0.00 10,672.14 Total Depth : 14178.18' MD, 8022.92' TVD - 4 1/2"x 6 1/8" Targets Target Name hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting Shape (°) (°) (usft) (usft) (usft) (usft) (usft) MPF -116 wp04a CPI 0.00 0.00 3,866.00 3,424.81 4,090.15 6,039,128.11 546,202.00 - plan hits target center - Point MPF -116 wp06 tqtl 0.00 0.00 7,213.00 6,757.61 7,876.48 6,042,482.00 549,969.00 plan hits target center Point MPF -116 wp06 tgt2 0.00 0.00 7,788.00 6,904.76 8,025.29 6,042,629.98 550,116.96 - plan hits target center - Point 9/17/2019 5:17:34PM Page 7 COMPASS 5000.15 Build 91 Casing Points Vertical Halliburton HALLIBURTON Measured Vertical Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU F-116 Company: Hilcorp Alaska, LLC TVD Reference: MPU F-116 Planned RKB @ 38.00usft (Original' Project: Milne Point MD Reference: MPU F-116 Planned RKB @ 38.00usft (Original' Site: M Pt F Pad North Reference: True Well: Plan: MPU F-116 Survey Calculation Method: Minimum Curvature Wellbore: MPU F-116 9-5/8 12-1/4 Design: MPU F-116 WP08 7" x 8 1/2" 7 Casing Points Vertical Depth Depth Measured Vertical (usft) Casing Hole Depth Depth 499.95 Diameter Diameter (usft) (usft) Name (") (") 113.00 113.00 16" x 17 1/2" 16 17-1/2 9,000.00 4,714.38 9 5/8" x 12 1/4" 9-5/8 12-1/4 13,095.00 7,005.06 7" x 8 1/2" 7 8-1/2 14,178.18 8,022.92 4 1/2"x 6 1/8" 4-1/2 6-1/8 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology 7,558.89 4,088.29 SB_NA 12,917.87 6,838.62 HRZ 13,487.56 7,373.95 KUP_A1 13,443.35 7,332.41 KUP_A3 13,459.55 7,347.63 KUP_A2 3,702.17 2,432.67 UG4 7,987.36 4,274.35 SB_OA 8,781.24 4,619.32 SB_BASE 13,372.91 7,266.21 KUP_B7 8,226.60 4,378.31 SB_OB 3,429.78 2,315.74 SV1 7,656.01 4,130.37 SB—NB 2,318.29 1,838.60 BPRF 12,972.87 6,890.30 KLGM 6,445.07 3,610.14 LA3 13,136.34 7,043.91 KUP_D 13,548.67 7,431.37 KUP_A_BASE 13,366.87 7,260.54 KUP_C 12,938.99 6,858.46 KLB Plan Annotations Measured Vertical Depth Depth (usft) (usft) 400.00 400.00 500.00 499.95 2,085.71 1,738.76 7,541.10 4,080.64 7,620.11 4,114.77 11,609.03 5,848.09 12,716.28 6,649.18 12,750.00 6,680.87 12,950.00 6,868.81 14,178.18 8,022.92 Local Coordinates +N/ -S +E/ -W (usft) (usft) 0.00 0.00 1.76 1.94 576.07 638.29 3,712.26 4,438.45 3,758.43 4,492.72 6,126.98 7,194.03 6,613.32 7,730.57 6,621.43 7,738.77 6,669.52 7,787.41 6,964.89 8,086.09 Comment Start Dir 3°/100' : 400' MD, 400'TVD Start Dir 4°/100' : 500' MD, 499.95'TVD End Dir :2085.71' MD, 1738.76' TVD Start Dir 2°/100' : 7541.1' MD, 4080.64'TVD End Dir : 7620.11' MD, 4114.77' TVD Start Dir 41/100' : 11609.03' MD, 5848.09'TVD End Dir : 12716.28' MD, 6649.18' TVD Start ESP tangent End ESP tangent Total Depth : 14178.18' MD, 8022.92' TVD 9/17/2019 5:17:34PM Page 8 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt F Pad Plan: MPU F-116 MPU F-116 MPU F-116 WP08 Sperry Drilling Services Clearance Summary Anticollision Report 17 September, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt F Pad - Plan: MPU F-116 - MPU F-116 - MPU F-116 WP08 Well Coordinates: 6,035,680.49 N, 542,131.74 E (70° 30'30.21" N, 149° 39' 19.00" W) Datum Height: MPU F-116 Planned RKB @ 38.00usft (Original Well Elev) Scan Range: 0.00 to 14,178.18 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU F -116 -MPU F-116 WP08 Hilcorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt F Pad -Plan: MPU F-116 -MPU F -116 -MPU F-116 WPOB Scan Range: 0.00 to 14,178.18 usft. Measured Depth. Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance SummaryBased 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 -53 - MPF -53 - MPF -53 MPF -53 - MPF -53 - MPF -53 MPF -53 - MPF -53 - MPF -53 MPF -53 - MPF -53A- MPF -53A MPF -53 - MPF -53A- MPF -53A MPF -53 - MPF -53A- MPF -53A MPF -53 - MPF-53AL1 - MPF-53AL1 MPF -53 - MPF-53AL1 - MPF-53AL1 MPF -53 - MPF-53AL1 - MPF-53AL1 MPF -53 - MPF-53AL2 - MPF-53AL2 MPF -53 - MPF-53AL2 - MPF-53AL2 MPF -53 - MPF-53AL2 - MPF-53AL2 MPF -53 - MPF-53PB1 - MPF-53PB1 MPF -53 - MPF-53PB1 - MPF-53PB1 MPF -53 - MPF-53PB1 - MPF-53PB1 MPF -57 - MPF -57 - MPF -57 MPF -57 - MPF -57 - MPF -57 MPF -57 - MPF -57 - MPF -57 MPF -57 - MPF -57A- MPF -57A MPF -57 - MPF -57A- MPF -57A MPF -57 - MPF -57A- MPF -57A MPF -57 - MPF-57APB1 - MPF-57APB1 MPF -57 - MPF-57APB1 - MPF-57APB1 MPF -57 - MPF-57APB1 - MPF-57APB1 MPF -58 - MPF -58 - MPF -58 MPF -58 - MPF -58 - MPF -58 MPF -58 - MPF -58 - MPF -58 MPF -61 - MPF -61 - MPF -61 403.29 244.51 403.29 241.01 411.71 69.997 Centre Distance Pass - 425.00 244.63 425.00 240.98 433.43 67.068 Ellipse Separation Pass - 2,800.00 1,487.84 2,800.00 1,436.59 2,577.03 29.028 Clearance Factor Pass - 403.29 244.51 403.29 241.01 414.11 69.997 Centre Distance Pass - 425.00 244.63 425.00 240.98 435.83 67.068 Ellipse Separation Pass - 2,800.00 1,487.84 2,800.00 1,436.59 2,579.43 29.028 Clearance Factor Pass - 403.29 244.51 403.29 241.01 414.11 69.997 Centre Distance Pass - 425.00 244.63 425.00 240.98 435.83 67.068 Ellipse Separation Pass - 2,800.00 1,487.84 2,800.00 1,436.59 2,579.43 29.028 Clearance Factor Pass - 403.29 244.51 403.29 241.01 414.11 69.997 Centre Distance Pass - 425.00 244.63 425.00 240.98 435.83 67.068 Ellipse Separation Pass - 2,800.00 1,487.84 2,800.00 1,436.59 2,579.43 29.028 Clearance Factor Pass - 403.29 244.51 403.29 240.58 411.71 62.288 Centre Distance Pass - 425.00 244.63 425.00 240.55 433.43 59.962 Ellipse Separation Pass - 1,950.00 835.51 1,950.00 811.68 1,908.38 35.052 Clearance Factor Pass - 448.82 214.11 448.82 209.60 456.99 47.397 Centre Distance Pass - 8,050.00 326.99 8,050.00 156.89 8,660.25 1.922 Ellipse Separation Pass - 8,350.00 348.05 8,350.00 163.05 8,954.84 1.881 Clearance Factor Pass - 448.82 214.11 448.82 209.60 456.99 47.397 Centre Distance Pass - 8,050.00 326.99 8,050.00 156.89 8,660.25 1.922 Ellipse Separation Pass - 8,350.00 348.05 8,350.00 163.05 8,954.84 1.881 Clearance Factor Pass - 448.82 214.11 448.82 209.60 462.04 47.397 Centre Distance Pass - 8,050.00 326.99 8,050.00 156.89 8,665.30 1.922 Ellipse Separation Pass - 8,350.00 348.05 8,350.00 163.05 8,959.89 1.881 Clearance Factor Pass - 411.14 240.51 411.14 236.83 415.68 65.360 Centre Distance Pass - 425.00 240.56 425.00 236.78 429.49 63.646 Ellipse Separation Pass - 1,050.00 381.24 1,050.00 371.80 1,008.56 40.378 Clearance Factor Pass - 434.93 179.29 434.93 175.57 449.39 48.165 Centre Distance Pass - 17 September, 2019 - 17:20 Page 2 of 8 COMPASS Hilcorp Alaska, LLC HALLI B U RTO N Milne Point Anticollision Report for Plan: MPU F-116 - MPU F-116 WPO8 416.86 123.08 416.86 118.88 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 29.294 Centre Distance Pass - MPF -69 - MPF -69 - MPF -69 425.00 123.09 Reference Design: M Pt F Pad - Plan: MPU F-116 - MPU F-116 - MPU F-116 WP08 28.806 Ellipse Separation Pass - MPF -69 - MPF -69 - MPF -69 725.00 150.78 Scan Range: 0.00 to 14,178.18 usft. Measured Depth. 735.35 21.702 Clearance Factor Pass - MPF -70 - MPF -70 - MPF -70 26.50 166.26 Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft 146.921 Centre Distance Pass - MPF -70 - MPF -70 - MPF -70 400.00 168.05 Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on 850.00 Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft Pass - MPF -70 - MPF -70A- MPF -70A MPF -61 - MPF -61 - MPF -61 450.00 179.34 450.00 175.51 464.69 46.808 Ellipse Separation Pass - MPF -61 - MPF -61 - MPF -61 825.00 224.06 825.00 217.50 838.80 34.189 Clearance Factor Pass - MPF -62 - MPF -62 - MPF -62 402.73 215.37 402.73 211.93 410.78 62.573 Centre Distance Pass - MPF -62 - MPF -62 - MPF -62 425.00 215.49 425.00 211.89 433.10 59.866 Ellipse Separation Pass - MPF -62 - MPF -62 - MPF -62 875.00 279.91 875.00 273.11 878.84 41.197 Clearance Factor Pass - MPF -65 - MPF -65 - MPF -65 468.82 149.65 468.82 146.39 478.46 45.892 Centre Distance Pass - MPF -65 - MPF -65 - MPF -65 475.00 149.66 475.00 146.36 484.72 45.396 Ellipse Separation Pass - MPF -65 - MPF -65 - MPF -65 4,650.00 1,497.11 4,650.00 1,438.23 5,310.15 25.426 Clearance Factor Pass - MPF -66 - MPF -66 - MPF -66 490.65 184.61 490.65 180.41 502.34 43.920 Centre Distance Pass - MPF -66 - MPF -66 - MPF -66 500.00 184.63 500.00 180.36 511.88 43.238 Ellipse Separation Pass - MPF -66 - MPF -66 - MPF -66 4,275.00 1,495.93 4,275.00 1,235.71 4,475.86 5.749 Clearance Factor Pass - MPF -66 - MPF -66A - MPF -66A 490.65 184.61 490.65 180.41 502.34 43.920 Centre Distance Pass - MPF -66 - MPF -66A - MPF -66A 500.00 184.63 500.00 180.36 511.88 43.238 Ellipse Separation Pass - MPF -66 - MPF -66A - MPF -66A 4,275.00 1,495.93 4,275.00 1,235.71 4,475.86 5.749 Clearance Factor Pass - MPF -66 - MPF-66PB1 - MPF-66PB1 490.65 184.61 490.65 180.41 502.34 43.920 Centre Distance Pass - MPF -66 - MPF-66PB1 - MPF-66PB1 500.00 184.63 500.00 180.36 511.88 43.238 Ellipse Separation Pass - MPF -66 - MPF-66PB1 - MPF-66PB1 4,275.00 1,495.93 4,275.00 1,235.71 4,475.86 5.749 Clearance Factor Pass - MPF -69 - MPF -69 - MPF -69 416.86 123.08 416.86 118.88 427.68 29.294 Centre Distance Pass - MPF -69 - MPF -69 - MPF -69 425.00 123.09 425.00 118.82 435.83 28.806 Ellipse Separation Pass - MPF -69 - MPF -69 - MPF -69 725.00 150.78 725.00 143.83 735.35 21.702 Clearance Factor Pass - MPF -70 - MPF -70 - MPF -70 26.50 166.26 26.50 165.13 36.65 146.921 Centre Distance Pass - MPF -70 - MPF -70 - MPF -70 400.00 168.05 400.00 164.53 409.25 47.847 Ellipse Separation Pass - MPF -70 - MPF -70 - MPF -70 850.00 224.90 850.00 217.98 854.23 32.504 Clearance Factor Pass - MPF -70 - MPF -70A- MPF -70A 26.50 166.26 26.50 165.13 36.65 146.921 Centre Distance Pass - MPF -70 - MPF -70A- MPF -70A 400.00 168.05 400.00 164.53 409.25 47.847 Ellipse Separation Pass - MPF -70 - MPF -70A- MPF -70A 850.00 224.90 850.00 217.98 854.23 32.504 Clearance Factor Pass - MPF -70 - MPF-70AL1 - MPF-70AL1 26.50 166.26 26.50 165.13 36.65 146.921 Centre Distance Pass - MPF -70 - MPF-70AL1 - MPF-70AL1 400.00 168.05 400.00 164.53 409.25 47.847 Ellipse Separation Pass - MPF -70 - MPF-70AL1 - MPF-70AL1 850.00 224.90 850.00 217.98 854.23 32.504 Clearance Factor Pass - MPF -73 - MPF -73 - MPF -73 457.03 92.45 457.03 88.66 463.18 24.396 Centre Distance Pass - 17 September, 2019 - 17:20 Page 3 of 8 COMPASS Hileorp Alaska, LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU F-116 - MPU F-116 WP08 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt F Pad - Plan: MPU F-116 - MPU F-116 - MPU F-116 WP08 Scan Range: 0.00 to 14,178.18 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft 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 MPF -73 - MPF -73 - MPF -73 475.00 92.52 475.00 88.58 481.29 23.491 Ellipse Separation Pass - MPF -73 - MPF -73 - MPF -73 700.00 108.67 700.00 102.81 706.62 18.535 Clearance Factor Pass - MPF -73 - MPF -73A- MPF -73A 457.03 92.45 457.03 88.66 463.88 24.396 Centre Distance Pass - MPF -73 - MPF -73A- MPF -73A 475.00 92.52 475.00 88.58 481.99 23.491 Ellipse Separation Pass - MPF -73 - MPF -73A - MPF -73A 700.00 108.67 700.00 102.81 707.32 18.535 Clearance Factor Pass - MPF -73 - MPF-73APB1 - MPF-73APB1 457.03 92.45 457.03 88.66 463.88 24.396 Centre Distance Pass - MPF -73 - MPF-73APB1 - MPF-73APB1 475.00 92.52 475.00 88.58 481.99 23.491 Ellipse Separation Pass - MPF -73 - MPF-73APB1 - MPF-73APB1 700.00 108.67 700.00 102.81 707.32 18.535 Clearance Factor Pass - MPF -73 - MPF-73APB2 - MPF-73APB2 457.03 92.45 457.03 88.66 463.88 24.396 Centre Distance Pass - MPF -73 - MPF-73APB2 - MPF-73AP82 475.00 92.52 475.00 88.58 481.99 23.491 Ellipse Separation Pass - MPF -73 - MPF-73APB2 - MPF-73APB2 700.00 108.67 700.00 102.81 707.32 18.535 Clearance Factor Pass - MPF -74 - MPF -74 - MPF -74 536.48 138.34 536.48 133.90 547.50 31.216 Centre Distance Pass - MPF -74 - MPF -74 - MPF -74 550.00 138.38 550.00 133.85 561.25 30.570 Ellipse Separation Pass - MPF -74 - MPF -74 - MPF -74 3,925.00 1,479.01 3,925.00 1,314.90 3,798.95 9.012 Clearance Factor Pass - MPF -74 - MPF -74A - MPF -74A 536.48 138.34 536.48 133.90 547.50 31.216 Centre Distance Pass - MPF -74 - MPF -74A- MPF -74A 550.00 138.38 550.00 133.85 561.25 30.570 Ellipse Separation Pass - MPF -74 - MPF -74A- MPF -74A 3,925.00 1,479.01 3,925.00 1,314.90 3,798.95 9.012 Clearance Factor Pass - MPF -74 - MPF-74APB1 - MPF-74APB1 536.48 138.34 536.48 133.90 547.50 31.216 Centre Distance Pass - MPF -74 - MPF-74APB1 - MPF-74APB1 550.00 138.38 550.00 133.85 561.25 30.570 Ellipse Separation Pass - MPF -74 - MPF-74APB1 - MPF-74APB1 3,925.00 1,479.01 3,925.00 1,314.90 3,798.95 9.012 Clearance Factor Pass - MPF -77 - MPF -77 - MPF -77 638.25 38.97 638.25 33.47 656.43 7.091 Centre Distance Pass - MPF -77 - MPF -77 - MPF -77 650.00 39.02 650.00 33.39 668.15 6.931 Ellipse Separation Pass - MPF -77 - MPF -77 - MPF -77 750.00 43.66 750.00 36.78 767.33 6.348 Clearance Factor Pass - MPF -78 - MPF -78 - MPF -78 26.50 126.94 26.50 124.96 36.04 64.078 Centre Distance Pass - MPF -78 - MPF -78 - MPF -78 75.00 127.00 75.00 124.74 84.23 56.296 Ellipse Separation Pass - MPF -78 - MPF -78 - MPF -78 3,100.00 1,489.72 3,100.00 1,418.40 2,897.50 20.887 Clearance Factor Pass - MPF -78 - MPF -78A- MPF -78A 26.50 126.94 26.50 124.96 36.04 64.078 Centre Distance Pass - MPF -78 - MPF -78A- MPF -78A 75.00 127.00 75.00 124.74 84.23 56.296 Ellipse Separation Pass - MPF -78 -MPF -78A -MPF -78A 3,100.00 1,489.72 3,100.00 1,418.40 2,897.50 20.887 Clearance Factor Pass - MPF -78 - MPF-78AL1 - MPF-78AL1 26.50 126.94 26.50 124.96 36.04 64.078 Centre Distance Pass - 17 September, 2019 - 17:20 Page 4 of 8 COMPASS Hilcorp Alaska, LLC HALLI B U RTO N Milne Point Anticollision Report for Plan: MPU F-116 - MPU F-116 WP08 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt F Pad - Plan: MPU F-116 - MPU F-116 - MPU F-116 WPO8 Scan Range: 0.00 to 14,178.18 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft 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 MPF -78 - MPF-78ALl - MPF-78AL1 75.00 127.00 75.00 124.74 84.23 56.296 Ellipse Separation Pass - MPF -78 - MPF-78ALl - MPF-78ALl 3,100.00 1,489.72 3,100.00 1,418.40 2,897.50 20.887 Clearance Factor Pass - MPF -78 - MPF-78AL2 - MPF-78AL2 26.50 126.94 26.50 124.96 36.04 64.078 Centre Distance Pass - MPF -78 - MPF-78AL2 - MPF-78AL2 75.00 127.00 75.00 124.74 84.23 56.296 Ellipse Separation Pass - MPF -78 - MPF-78AL2 - MPF-78AL2 3,100.00 1,489.72 3,100.00 1,418.40 2,897.50 20.887 Clearance Factor Pass - MPF -78 - MPF-78APB1 - MPF-78APB1 26.50 126.94 26.50 124.96 36.04 64.078 Centre Distance Pass - MPF -78 - MPF-78APB1 - MPF-78APB1 75.00 127.00 75.00 124.74 84.23 56.296 Ellipse Separation Pass - MPF -78 - MPF-78APB1 - MPF-78APB1 3,100.00 1,489.72 3,100.00 1,418.40 2,897.50 20.887 Clearance Factor Pass - MPF -99 - MPF -99 - MPF -99 26.50 34.92 26.50 33.63 34.30 27.134 Centre Distance Pass - MPF -99 - MPF -99 - MPF -99 425.00 36.02 425.00 30.32 433.00 6.326 Ellipse Separation Pass - MPF -99 - MPF -99 - MPF -99 525.00 40.40 525.00 33.47 532.39 5.828 Clearance Factor Pass - MPF -99 - MPF-99PB1 - MPF-99PB1 26.50 34.92 26.50 33.63 34.30 27.134 Centre Distance Pass - MPF -99 - MPF-99PB1 - MPF-99PB1 425.00 36.02 425.00 30.32 433.00 6.326 Ellipse Separation Pass - MPF -99 - MPF-99PB1 - MPF-99PB1 525.00 40.40 525.00 33.47 532.39 5.828 Clearance Factor Pass - MPFB-01 - MPFB-01 - MPFB-01 101.46 116.00 101.46 67.75 108.46 2.404 Centre Distance Pass - MPFB-01 - MPFB-01 - MPFB-01 125.00 116.62 125.00 60.65 120.00 2.083 Clearance Factor Pass - MPFB-02 - MPFB-02 - MPFB-02 101.46 112.09 101.46 72.59 108.46 2.838 Centre Distance Pass - MPFB-02 - MPFB-02 - MPFB-02 125.00 112.73 125.00 65.47 120.00 2.385 Clearance Factor Pass - Plan : MPU F-97 - MPU F-97 - MPU F-97 wp03 1,588.15 315.53 1,588.15 302.77 1,753.20 24.738 Centre Distance Pass - Plan : MPU F-97 - MPU F-97 - MPU F-97 wp03 1,600.00 315.59 1,600.00 302.77 1,764.45 24.621 Ellipse Separation Pass - Plan : MPU F-97 - MPU F-97 - MPU F-97 wp03 1,700.00 321.24 1,700.00 307.93 1,858.57 24.141 Clearance Factor Pass - M Pt L Pad MPL-21 - MPL-21 - MPL-21 9,575.00 1,314.45 9,575.00 1,185.95 11,866.20 10.229 Clearance Factor Pass - MPL-2I-MPL-2I-MPL-21 10,200.00 1,224.33 10,200.00 1,115.12 12,249.55 11.211 Ellipse Separation Pass - MPL-21 - MPL-21 - MPL-21 10,317.70 1,222.16 10,317.70 1,116.50 12,336.09 11.567 Centre Distance Pass - 17 September, 2019 - 17.20 Page 5 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPU F-116 - MPU F-116 WP08 Survey tool proctram From To Survey/Plan (usft) (usft) 26.50 9,000.00 MPU F-116 WP08 9,000.00 13,095.00 MPU F-116 WP08 13,095.00 14,178.18 MPU F-116 WP08 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. Survey Tool 2 MWD+IFR2+MS+Sag 2_MWD+IFR2+MS+Sag 2_MWD+IFR2+MS+Sag Hilcorp Alaska, LLC Milne Point 17 September, 2019 - 17.20 Page 6 of 8 COMPASS HALLIBURTON Project: Milne Point REFERENCE INFORMATION WEILDETAQS:PIan:MPUF-116 NAD1927(NADCONCONUS) AlashZoae04 Sp " OHM— Site: M Pt F Pad Co-ordinate (Nf) Reference: Well Plan: MPU F-116, True North Well: Plan: MPU F-116 V.N.I (-VD) Ref..- MPU F-116 Planned RKB (d} 38.W.sft (Original Well Elev) 11.50 Wellbore: MPU F-116 Measured D, Reference: MPU F-116 Planned RKB @ 38.00usft (Original Well Ele) +N/ -S +F/ -W Northing listing L tinode Longitude Cslrul.b- Method: Minimum Curvature 0.00 0.00 6035680.49 542131.74 70° 30' 30.213 N 149° 39' 19.01 W Plan: MPU F-116 WPOB GLOBAL FILTER APPLIED: All wellpaths Within 200'+ 100/1000 of reference SURVEY PROGRAM 26.50 To 14178.18 Date: 2019-04-17T00:00:00 Validated: Yes Version: CASING DETAILS Depth From Depth To Survey/Plan Tool TVD TVDSS MD St. Name Ladder S.F. Plots 26.50 9000.0 MPU F-116 WP08 MPU F-116 2 MWD+IFR2+MS+Sas 3.00 5.00 3.00 6 I6"x171/2" 9000.00 13095.00 MPU F-116 WP08(MPU F-116) 2_MWD+IFR2+MS+Sag 4714.38 4676.38 9000.00 9-5/8 95/8" x 121/4" 13095.00 14178.18 MPU F-116 WP08 (MPU F-116) 2_MWD+IFR2+MS+Sag 7005.06 6967.06 13095.00 7 7" x 8 I/2" 8022.92 7984.92 14178.18 4-1/2 41/2"x 6 1/8" 180.00 ! .... r __ V,T- _-_..r_._ _�� , -T7I MPF-70�� E MPF -6 i N150.00 - 7 MPF -74 o MPF -7 l o MPF -6 S120.00- cMPFB- i �. �EMPFB-02 a 90.0x7 MPF -73 at MPF -7 ;! J to 60.00 p ! I I y MPF -99 i c 30.00 -Tf-- U I I 0.00 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 Measured Depth (1500 usft/in) 4.00 I I t0 LL -4 3.00 - C is i I m I � 2.00 Collision Risk Procedures Req. Collision Avoidance Req. No -Go Zone - Stop Drillin NOERRORS 0.00 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 Measured Depth (1500 usft/in) From: Joseph Enael To: Boyer David L (CED) Cc: Cody Dinner; Taylor Wellman; Mack Myers Subject: RE: [EXTERNAL] H2S Data on Milne F -Pad Date: Wednesday, October 2, 2019 8:43:04 AM David — Thanks for the question and concern. While F -pad is a mature pad, it is a source -water flood (as opposed to a seawater flood which carries the microbes that cause H2S) and there have been no correlations to rising H2S values with source water injection. F -Pad injection started in mid-90s, and we do not expect increasing H2S concentrations beyond what was seen in 2004. While we do not have any recent H2S data from F pad specifically (that is scheduled to be done in the near future), we do have monthly fuel gas samples that test for 1-12S. Our fuel gas is combined gas from all pads at MPU, and the combined gas H2S levels are less that 20ppm. It can then be inferred that each pad has less than 20ppm H2S. Please let me know if you have any other questions. Thank you for your time. -Joe Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 From: Boyer, David L (CED)[mailto:david.boyer2@alaska.gov] Sent: Tuesday, October 1, 2019 3:11 PM To: Cody Dinger <cdinger@hilcorp.com> Cc: Joseph Engel <jengel@hilcorp.com> Subject: [EXTERNAL] H2S Data on Milne F -Pad Cody, It has been a while since a grassroots Kuparuk well has been drilled on F -Pad. Because it is a mature pad, one would expect H2S values higher than 20 ppm. Does Hilcorp have any recent H2S data from that pad? In our database, values from 2004 and earlier were less than 10 ppm. We want to error on the side of safety for those in the field. Thanks, Dave Boyer AOGCC The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e- mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Transform Points Source coordinate system State Plane 1927 - Aaska Zone 4 Datum: NAD 1927 - North America Datum of 1927 (Mean) ES W Target coordinate system Albers Equal Area t.-150) Datum: NAD 1927 - North America Datum of 1327 (Mean) . . ... . .... . "Type values into the spreadsheet or copy and paste columns of data from a spreadsheet using the keyboard shortcuts Ctd+C to copy and Ctd+V to paste. Then click on the appropriate arrow button to transform the points to the desired coordinate system. 0 < Back Finish CancelI Help .1111- J TRANSMITTAL LETTER CHECKLIST WELL NAME: M r cam. F' PTD: ::?, 19 - (33 VDevelopment _ Service Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: I I ht- PD ! h + POOL: K Ld a r D i � u� 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 IJ 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)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, KUPARUK RIVER OIL - 525100 - Well Name: M_ ILNE PT UNIT _F-116 Program DEV Well bore seg ❑ PTD#: 2191330 Company Hilcorp Alaska LLC —_ — _ _ —__ — - Initial Class/Type DEV/PEND GeoArea 890 _ Unit _11328_ On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached NA Geologic Engineering 2 Lease number appropriate Yes Commissioner: Date: Commissioner: Date 3 Unique well name and number Yes 4 Well located in a defined pool Yes 5 Well located proper distance_ from drilling unit boundary_ Yes I6 Well located proper distance from other wells Yes 7 Sufficient acreage available in drilling unit Yes 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes 10 Operator has appropriate_ bond in force Yes _ 11 Permit can be issued without conservation order Yes Appr Date i 12 Permit can be issued without administrative approval Yes 13 Can permit be approved before 15 -day wait Yes DLB 10/1/2019 14 Well located within area and -strata authorized by Injection Order # (put 10# in comments) (For NA 15 All wells within 1/4 mile area of review identified (For service well only) NA_ - - ----------------------------------------------- 16 Pre -produced injector:. duration of pre -production less than 3 months (For service well only) NA 17 Nonconven. gas conforms to AS31.05.030Q.1.A),(j.2.A-D) NA 18 Conductor string provided Yes 20" inch conductor set at 107 ft Engineering 119 Surface casing_ protects all known USDWs NA Permafrost area. 20 CMT vol adequate to circulate on conductor & surf -csg Yes 9 5/8" surface casing set below SB sand... -using 2 stage tool, 21 CMT vol adequate to tie-in long string to surf csg No 22 CMT will cover all known productive horizons Yes 23 Casing designs adequate for C, T, B &_permafr_ost_ Yes BTC ca_lcsprovided. 24 Adequate tankage or reserve pit Yes Innovation rig has steel pits. 25 If a re -drill, has_a 10-403 for abandonment been approved NA grassroots well. 26 Adequate wellbore separation proposed Yes No issues 27 If_diverter required, does it_meet _regulations _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes -------------------- Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max for_matiion press _= 4332 Psi (_ 1.0.4 ppg EMW) Will drill with MPD. -------------- GLS 10/7/2019 29 BOPEs, do they meet_ regulation - Yes 30 BOPE_press rating appropriate; test to -(put psig in comments)_ Yes MASP = 3530 psi Will test BOPE to 4000 psi-(annul_ar to 2500 psi )_ 31 Choke manifold complies w/API RP -53 (May 84)_ Yes 32 Work will occur without operation shutdown Yes Separate sundry for frac stimulation required. 33 Is presence of H2S gas probable Yes 34 Mechanical condition of wells within AOR verified (For_ service well only) NA 35 Permit can be issued w/o hydrogen_ sulfide measures Yes Due to source -water flood (not seawater), H2S values are <20ppm. Geology I36 Data presented on potential overpressure zones Yes Appr Date 137 Seismic analysis of shallow gas zones NA_ DLB 10/2/2019 38 Seabed condition survey (if off -shore) NA_ 39 Contact name/phone for weekly_ progress reports_ [exploratory only] NA_ Geologic Engineering Public Frac stimulation for Kuparuk sands in planned. GIs Commissioner: Date: Commissioner: Date Commissioner �j Date