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Home My WebLink About215-1171. 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 Install Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 12,995 feet N/A feet true vertical 4,158 feet N/A feet Effective Depth measured 12,993 feet feet true vertical 4,158 feet 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 / EUE 8rd 5,594' 3,421' SLZXP LTP, Packers and SSSV (type, measured and true vertical depth)Swell Packers (2) 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: 7,399, 11,068 & 11,328 4,062, 4,120 & 4,142 7,480psi 5,750psi 7,240psi 10,640psi 7,400' 4,062' Burst N/A Collapse N/A 3,090psi 5,410psi 5,607' Casing Conductor 4,158'12,995' 7,370' 7,664'Surface Production Liner 13-3/8" 9-5/8" 7" 80' 7,629' measured TVD 5-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-117 50-029-23550-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0025509 / ADL0025515 MILNE POINT / SCHRADER BLUFF OIL MILNE PT UNIT L-47 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) 67 Gas-Mcf MD 80' 2,557 Size 80' 4,094' 741 350509 153 345277 344 323-582 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 530 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 Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 8:37 am, Jan 17, 2024 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.01.15 10:40:02 - 09'00' Taylor Wellman (2143) DSR-1/26/24WCB 2024-07-02 _____________________________________________________________________________________ Revised By: TDF 1/12/2024 SCHEMATIC Milne Point Unit Well: MPU L-47 Last Completed: 12/13/2023 PTD: 215-117 TD =12,995’ (MD) / TD =4,158’(TVD) 13-3/8” Orig. KB Elev.: 50’/ GL Elev.: 17’ 7” 3 9&10 14 & 15 11 12 13 9-5/8” 1 2 16 17 18 Min ID 2.666” @ 5,455’ PBTD =12,993’ (MD) / PBTD =4,158’(TVD) 8 9-5/8” ‘ES’ Cementer @ 2,535’ 19 4 & 5 5-1/2” 6 & 7 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 13-3/8" Conductor 68 / A-53 / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TC II 8.835 Surface 7,664’ 0.0759 7” Production 26 / TXP / BTC 6.276 Surface 7,409’ 0.0383 5-1/2” Liner 17 / P-110 / DWC/C HT 4.892 7,399’ 12,995 0.0233 TUBING DETAIL 3-1/2” Liner 9.3# / L-80 / EUE 8rd 2.992 Surface 5,594' 0.0087 JEWELRY DETAIL No Depth Item 1 197’STA #2:GLM 3-1/2” x 1” BK Latch w/ DPSOV 2 5,364’STA #1: GLM 3-1/2” x 1” BK Latch w/ DV 3 5,455’ XN Nipple, 2.813” Profile,Min ID=2.666” 4 5,508’ Discharge Adapter: Vigilant, 3 1/2" SS (same as 25022) 5 5,508.7’ Discharge, Bolt On: 3 1/2" 8RD, 400X, 416 SS 6 5,509’ Pump 2: 400,SFGH2500,75S,INC,15,2:1,D7,TS3 7 5,531’ Pump 1: 400,SF1750,124S,INC,15SS,1:1,D7,TS3 8 5,553’ Gas Separator: 400,TDM,H2X,SS,INC,D15 9 5,558’ Upper Tandem Seal: 400 Series, BPBSL, Inconel Shaft, SLUB, HD 10 5,566’ Lower Tandem Seal: 400 Series, BPBSL, Inconel Shaft, UT, SLUB, HD 11 5,574’ Motor: 456 series, FMS2, 120HP/1970/43, 8 Rotor 12 5,589’ Intake Sensor: Vigilant, Extreme Temp, 177C, w/discharge,6000PSI, SS 13 5,591’ Centralizer: Anode, Triplate –Bottom @ 5,594’ 14 7,399’ SLZXP Liner Top Packer w/ BD Slips 15 7,402’ Seal Assembly 10’ Inside LTP 16 7,421’ 5-1/2” H563 X 7'' DWC XO 17 11,068’ Swell Packer: Bottom @ 11,078’ 18 11,328’ Swell Packer: Bottom @ 11,338’ 19 12,993’ WIV (Ball in Seat/ Closed) – Bottom@ 12,995’ OPEN HOLE / CEMENT DETAIL 13-3/8" 350 sx of Arcticset I (Approx) 9-5/8" 541 bbls in 12-1/4” Hole Cement to Surface 5-1/2” Cementless Slotted Liner w/ Swell Packers 8-1/2” hole WELL INCLINATION DETAIL KOP @ 882’ Max Hole Angle = 92.1 deg. @ 12,925’ MD TREE & WELLHEAD Tree 5M Seaboard 2-9/16” Wellhead Seaboard MB-22 5M GENERAL WELL INFO API: 50-029-23550-00-00 Drilled and Cased by Doyon 14 - 2/15/2016 ESP Swap & Patch by ASR #1 – 10/11/2021 Tieback and Convert to JP by ASR#1 – 10/7/2022 ESP Install by ASR#1 – 12/13/2023 5-1/2” SLOTTED LINER DETAIL Top (MD) Btm (MD) 7,474’ 11,063’ 11,341’ 12,948’ Liner Slot Dimensions= 2.250” L x .125” W 6.72” Sq/In of Inlet Area per FT of Casing 24 Slots Per Foot of Casing Well Name Rig API Number Well Permit Number Start Date End Date MP L-47 Slickline 50-029-23550-00-00 215-117 9/16/2023 12/13/2023 No operations to report. WELL SHUT-IN ON ARRIVAL. RIG-UP .125 CARBON WIRE. TS = 1.75" RS, 8' x 1-7/8" ROLLER STEM (2.60" whls), KJT 5' x 1-7/8" ROLLER STEM (2.60" whls), OJ, KJT LSS. STACK PCE AND TAKE CONTROL OF WIRE. PULL TREE CAP AND STAB ONTO WELLHEAD. PT LUB 350L/3500H (Good). LRS FLUSHED TUBING W/ 50bbls CRIESEL (Hot). BRUSH PATCH AREA FROM 6,514' SLM TO 6,680' SLM (no issues) W/ 3-1/2" BRUSH, 2.50" GAUGE RING. WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED. 9/16/2023 - Saturday No operations to report. 9/19/2023 - Tuesday 9/17/2023 - Sunday No operations to report. 9/18/2023 - Monday 9/15/2023 - Friday No operations to report. 9/13/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 9/14/2023 - Thursday No operations to report. Well Name Rig API Number Well Permit Number Start Date End Date MP L-47 ASR #1 50-029-23550-00-00 215-117 12/7/2023 12/13/2023 12/8/2023 - Friday Complete BOPE test as Per AOGCC testing variance. Attempt to retrieve TWC. Moblize new lubricator. Retrieve TWC.TBG pressure= 550 psi. Cont. to perform well kill w/ 8.45 SW. Pumping a total of 400 bbls pump. TBG on a vacuum & IA static. M/U landing jt to hanger BOLDS. P/U to 48k hanger off seat. Observed PKR release at 68K for 20 k over P/U wt. Free P/U wt = 48K S/O wt = 26K Pump for mitigation of PKR gas. Allow elements to relax. IA static. Pump dw TBG w/ 8.5 ppg SW at 7 bpm w/ 500 psi. After 52 bbls away pressure increased rapidly. Shut down. Attempt to pump w/ one pump dw TBG. pressure up. Pump across kill to choke. Path clear. Set hanger back in profile. Remove landing joint. TBG on a vac. TBG clear. Obstruction in goose neck of TD. Cont. to pump PKR gas out of well. 12/6/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 12/7/2023 - Thursday Take on fresh fluid for testing. Stab landing joint isolating BPV profile. Begin testing BOPs, Test BOPE as per AOGCC approve variance, Cont to test BOPE as per AOGCC approved variance. T/ 250 PS low & 2,500 PSI high f/ 5/5 charted mins. Change out valve on testing equipment. Terminate ESP cable at hanger as per ESP rep. Hanger slice short. Remove hanger, pull one joint, replace with shorter joint. M/U Hanger. P/U wt = 53K S/O wt = 28K. Connect penetrator to hanger & test ESP cable. Land Hanger w/ bpv preset in hanger. Blow down all fluid lines. Rig down spools and flow spool. Rig down tongs. Pull rack pins. move pipe shed out of way. Rig released from L-47 at 12:00 on 12-12-2023 Void test to be completed & BPV pulled, see Wellhead report. Pump 400 bbls of 8.45 SW dw TBG, no returns ICP = 575 psi, FCP = 203 psi. TBG on a vacuum & IA static, M/U landing Joint & pull hanger to floor. L/D hanger. M/U new hanger and land. RILDS Rig down landing joint. Fill stack.Test blinds against new hanger. Retest test#2. Found leaking lockdown screw. Tighten, good test Rig down test equipment. blow down fluid lines pull CTS and BPV. TBG on a vacuum. IA had 10 psi. Close blinds, Pump 100 BBLs down tubing taking returns up IA to flow back tank. No returns seen. TBG on vacuum IA static. P/U M/U landing joint. BOLDS. pull hanger to floor. Pull free 48 K POOH w/ 3- 1/2" 9.3 # L-80 EUE Jet pump completion F/ 7,423' Pump double displacement for pipe tripped out POOH w/ 3-1/2" 9.3 # L-80 EUE Jet pump completion T/ 3,288' Pump double displacement for pipe tripped out. 12/9/2023 - Saturday Begin picking up ESP equip. Service motor. Finish P/U M/U ESP equipment as per ESP hand. Test cable, good test. Begin RIH W/ 3-1/2" EUE 9.3# L-80 and ESP testing cable every 1,000'. pumping a double pipe displacement every 15 joints. RIH W/ 3- 1/2" EUE 9.3# L-80 ESP completion T/ 5.564 '. S/O wt = 26K P/U wt = 53K. P/U Hanger & M/U. Orient hanger in correct position for tree. Prep to terminate ESP cable at hanger. 12/12/2023 - Tuesday 12/10/2023 - Sunday HOLD PJSM W/ RIG CREW, RU .125" WIRE, 5' x 2-1/8" ROLLER (2.70"wheels), KJ, 5' x 2-1/8" ROLLER (2.70"wheels), KJ, SSS, STRIPPER CAP, RAISE TOP SHEAVE INTO PLACE. STAB ON & PRESSURE TEST TO 2,500 PSI (pass). PERFORM 40 ARM CALIPER SURVEY OF 7" CASING FROM 7120' SLM TO SURFACE. PREP TO RUN ESP COMPLETION. 12/11/2023 - Monday M/U landing Joint & pull hanger to floor. L/D hanger. M/U new hanger and land. RILDS Rig down landing joint Terminate ESP cable at hanger as per ESP rep. Hanger slice short. Remove hanger, pull one joint, replace with shorter joint. M/U Hanger. P/U wt = 53K S/O wt = 28K. Connect penetrator to hanger & test ESP cable. Land Hanger w/ bpv preset in hanger. The 40-arm caliper on the 7" casing was required by Sundry 323-582 and was emailed to the AOGCC, as required, on 12-13-2023. -WCB Complete BOPE test as Per AOGCC testing variance. Attempt to retrieve TWC. Moblize new lubricator. Retrieve TWC.TBG pressure= 550 psi. Cont. to perform well kill w/ 8.45 SW. Pumping a total of 400 bbls pump. TBG on a vacuum & IA static. M/U landing jt to hanger BOLDS. P/U to 48k hanger off seat. Observed PKR release at 68K for 20 k over P/U wt. PERFORM 40 ARM CALIPER SURVEY OF 7" CASING FROM 7120' SLM TO SURFACE. Begin RIH W/ 3-1/2" EUE 9.3# L-80 and ESP testing cable every 1,000'. pumping a double pipe displacement every 15 joints. RIH W/ 3- 1/2" EUE 9.3# L-80 ESP completion T/ 5.564 '. S/O wt = 26K P/U wt = 53K. P/U Hanger & M/U. Orient hanger in correct position for tree. Prep to terminate ESP cable at hanger Well Name Rig API Number Well Permit Number Start Date End Date MP L-47 ASR #1 50-029-23550-00-00 215-117 12/7/2023 12/13/2023 12/15/2023 - Friday No operations to report. 12/13/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Post rig move tested wellhead adapter void to 500 / 5000 psi for 10 mins good tests, Pull BPV with S-10 lubricator approx 300 psi on well. Well Support Techs set foundation, installed prodcution and test piping and pressure test lines to 1150 psi, and set well house. No issues . 12/14/2023 - Thursday No operations to report. No operations to report. No operations to report. 12/16/2023 - Saturday No operations to report. 12/19/2023 - Tuesday 12/17/2023 - Sunday No operations to report. 12/18/2023 - Monday Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 12/28/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20231221 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 221-35 50283201930000 223077 11/4/2023 AK E-LINE CBL MPU L-47 50029235500000 215117 12/10/2023 READ Caliper Survey Please include current contact information if different from above. T38247 T38248 12/29/2023 MPU L-47 50029235500000 215117 12/10/2023 READ Caliper Survey Kayla Junke Digitally signed by Kayla Junke Date: 2023.12.29 12:42:52 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/30/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20231130 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 11/13/2023 YELLOW JACKET GPT BCU 13 50133205250000 203138 10/5/2023 YELLOW JACKET PERF KBU 13-08 50133203040000 177029 10/16/2023 YELLOW JACKET CALIPER KU 12-17 50133205770000 208089 10/4/2023 YELLOW JACKET CALIPER/TEMP KU 24-7RD 50133203520100 205099 10/4/2023 YELLOW JACKET CALIPER MPU B-32 50029235700000 216151 9/20/2023 YELLOW JACKET RCT MPU L-47 50029235500000 215117 10/25/2023 YELLOW JACKET CUT NS-05 50029232440000 205009 9/9/2023 YELLOW JACKET PERF NS-16A 50029230960100 206141 9/12/2023 YELLOW JACKET PERF NS-20 50029231180000 202188 9/11/2023 YELLOW JACKET PERF NS-24 50029231110000 202164 9/10/2023 YELLOW JACKET PATCH PTM P1-13 50029223720000 193074 10/24/2023 YELLOW JACKET PL Please include current contact information if different from above. T38164 T38164 T38165 T38166 T38167 T38168 T38169 T38170 T38171 T38172 T38173 T38174 12/1/2023 YELLOW MPU L-47 50029235500000 215117 10/25/2023 JACKET CUT Kayla Junke Digitally signed by Kayla Junke Date: 2023.12.01 10:42:44 -09'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ESP Install 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 12,995'N/A Casing Collapse Conductor N/A Surface 3,090psi Production 5,410psi Liner 7,480psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Wells Manager Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng MILNE POINT SCHRADER BLUFF OIL N/A 4,158' 12,993' 4,158' 789 N/A 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 L-47 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 11/4/2023 Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 / ADL0025515 215-117 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23550-00-00 Hilcorp Alaska LLC C.O. 477.05 Length Size Proposed Pools: 80' 80' 9.3# / L-80 / EUE TVD Burst 7,423' MD N/A 10,640psi 5,750psi 7,240psi 4,094' 4,062' 4,158' 3-1/2" Ryan Lewis 7,664' 7,400' 80' 13-3/8" 9-5/8" 7" 7,629' 7,370' ryan.lewis@hilcorp.com 303-906-5178 7" x 4-1/2" Baker Premier, SLZXP LTP, Swell Packer (2) and N/A 6,621 MD/ 3,860 TVD, 7,399 MD/ 4,062 TVD, 11,068 MD/ 4,120 TVD & 11,328 MD/ 4,142 TVD and N/A 5-1/2"5,607' Perforation Depth MD (ft): 12,995' See Schematic See Schematic No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 10:56 am, Oct 30, 2023 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.10.24 14:32:38 - 08'00' Taylor Wellman (2143) 323-582 DSR-11/1/23 * BOPE pressure test to 2500 psi. * Assure KWF in both tubing and IA are balanced before pulling tubing hanger. * 40 arm caliper log to AOGCC 10-404 MGR01NOV23 SFD 10/30/2023*&: Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2023.11.01 13:27:51 -08'00'11/01/23 RBDMS JSB 110223 Well: MPL-47 PTD: 215-117 API: 50-029-23550-00-00 Well Name:MPL-47 API Number:50-029-23609-00-00 Current Status:Shut-in Producer Rig:ASR #1 Estimated Start Date:11/4/2023 Estimated Duration:3 days Regulatory Contact:Tom Fouts Permit to Drill Number:215-117 First Call Engineer:Ryan Lewis (303) 906-5178 (M) Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) Current Bottom Hole Pressure:1,203 psi @ 4,136’ TVD (7/23/22 / 5.60 ppg EMW) Max Potential Surface Pressure: 789 psi Gas Column Gradient (0.1 psi/ft) Max Angle:81° @ 7,389’ MD Brief Well Summary: MPU L-47 was drilled and completed in February 2016 as a horizontal Schrader Bluff OA producer. The ESP failed in February 2021 due to electrical grounding. Prior to the ESP failure, an IAxOA leak developed in September 2019. A RWO in 2021 installed a 3-1/2” patch in the 7-5/8” to restore casing integrity. An ESP was run above the casing patch. In late 2021 an MBE developed from L-48i to L-47 and L-48 was shut in waiting on a conformance treatment. September 2022 it was converted to jet pump. A recent caliper revealed a hole at 6,580’ MD below the bottom hole pressure gauge. Objectives: Pull 4-1/2” jet pump completion, log 7” for PF wear, run new ESP completion on 3-1/2” tubing. Notes Regarding Wellbore Condition: Baker Premier Packer – mechanical cut mandrel to release packer @ 6,621’ MD. Pre-Rig Procedure E-Line (Non-sundried Work) 1. MIRU E-Line. Pressure test PCE to 250 psi low, 2,500 psi high. 2. RIH w Mechanical cutter, tie in for depth control and cut mandrel to release packer. See info in well folder. 3. POOH. RDMO. Pumping & Well Support 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU Little Red Services. RU reverse out skid and 500 barrel returns tank. 4. Pressure test lines to 3,000 psi. 5. Circulate at least one wellbore volume with source water down tubing, taking returns up casing to 500 barrel returns tank. 6. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR arrival. 7. RD Little Red Services and reverse out skid. 8. Set BPV. ND tree. NU BOPE. Well: MPL-47 PTD: 215-117 API: 50-029-23550-00-00 Brief RWO Procedure 1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 bbl returns tank. 2. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing and casing. a. If needed, kill well with produced water prior to setting CTS. 3. 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 3-1/2” test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Bleed any pressure on casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the returns tank. Kill well with produced water as needed. Pull BPV. a. If indications show pressure underneath BPV, lubricate out BPV. 5. RU spooler to handle gauge TEC line. 6. MU landing joint or spear, BOLDS, PU on the tubing hanger. a. Wellhead is a Seaboard SB-22 b. PU weight ASR1: 48kip. c. SO weight ASR1: 25kip. 7. Confirm hanger free, lay down tubing hanger. 8. POOH and lay down the 3-1/2” tubing. Number all joints. a. Keep the first 157 jts of 3-1/2” tubing joints. We will re-run these with the ESP. Trash the other 48 plus any visibly bad joints. b. Keep gauge carrier, sliding sleeve c. Note any sand or scale inside or on the outside of the tubing. d. Look for over-torqued connections from previous tubing runs, trash these joints. e. Clamp Totals i. Cross Collar clamps: 112 9. RU slickline with a 40-arm caliper. RIH as deep as you can, est 6,700’ @ 70 deg. 10. Log OOH to surface. RD slickline. 11. RIH with 3-1/2” 9.2# L-80 and ESP completion to +/- 5,600’ (where DLS < 1.0), and obtain string weights. a. Check electrical continuity every 1000’. b. Note PU and SO weights on tally. c. Install ESP clamps per ESP toolhand, and cross coupling clamps every other joint d. No 3/8” cap string planned as of pre job. Caliper log to AOGCC. -mgr Assure balanced KWF both tubing and IA before pulling tubing hanger. - mgr Well: MPL-47 PTD: 215-117 API: 50-029-23550-00-00 Nom. (OD)Length Item Lb/ft Material Notes 5.85 2 Centralizer 4 ~5,600’ 4.5 2 Intake Sensor 30 5.62 34 Motor 80 5.2 7 Lower Tandem Seal 38 5.2 7 Upper Tandem Seal 38 5.2 8 Gas Separator 52 5.38 57 Pump 45 1 Ported Discharge Head 13 L-80 3-1/2" 10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2" 30 3-1/2" EUE 8rd L-80 9.2 L-80 3-1/2”10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2”2 3-1/2” XN-nipple 9.2 L-80 3-1/2”10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2” 60 3-1/2" EUE 8rd Jt 9.2 L-80 3-1/2”10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2”"8 3-1/2" x 1" GLM, DV installed 9.2 L-80 3-1/2"10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2” 5,115 3-1/2" EUE 8rd Jt 9.2 L-80 3-1/2”10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2”8 3-1/2" x 1" GLM, 1/4" OV 9.2 L-80 ~200 MD 3-1/2”10 3-1/2" EUE 8rd Pup Jt 9.2 L-80 3-1/2” 150 3-1/2" EUE 8rd Jt 9.2 L-80 3-1/2” 10 Space out pup 9.2 L-80 3-1/2” 30 Tubing Hanger with full joint 9.2 L-80 12. Land tubing hanger. Use extra caution to not damage cable. 13. Lay down landing joint. 14. Set BPV. 15. RDMO ASR. Post-Rig Procedure: Well Support 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. ND BOPE, set CTS plug, and NU tree. 3. Test tubing hanger void to 500 psi low/5,000 psi high. Pull CTS and BPV. 4. RD crane. Move 500 bbl returns tank and rig mats to next well location. 5. RU well house and flowlines. Attachments: Well: MPL-47 PTD: 215-117 API: 50-029-23550-00-00 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. BOPE Double Ram Schematic _____________________________________________________________________________________ Revised By: TDF 10/9/2023 SCHEMATIC Milne Point Unit Well: MPU L-47 Last Completed: 10/11/2021 PTD: 215-117 TD =12,995’ (MD) / TD =4,158’(TVD) 13-3/8” Orig. KB Elev.: 50’/ GL Elev.: 17’ 1 2 11 19 9-5/8” 8 9 Min ID 2.81” @ ±6,700’ PBTD =12,993’ (MD) / PBTD =4,158’(TVD) 9-5/8” ‘ES’ Cementer @ 2,535’ 10 5-1/2” 3 4 7” 5, 6 & 7 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 13-3/8" Conductor 68 / A-53 / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TC II 8.835 Surface 7,664’ 0.0759 7" Production 26 / L-80 / TXB BTC 6.276 Surface 7,400’ 0.0383 5-1/2” Liner 17 / P-110 / DWC/C HT 4.892 7,399’ 12,995 0.0233 TUBING DETAIL 3-1/2” Tubing 9.3# / L-80 / EUE 2.992 Surface 7,423' 0.0087 JEWELRY DETAIL No Depth Item 1 6,510’ HES Sliding Sleeve 2 6,562’ BHP Gauge 3 6,621’ 7”x4-1/2” Baker Premier Packer 4 6,689’ X Nipple (Min ID = 2.813”) 5 7,399’ SLZXP Liner Top Packer w/ BD Slips 6 7,392’ WLEG –Btm @ 7,423’ 7 7,421’ 5-1/2” H563 X 7'' DWC XO 8 11,068’ Swell Packer: Bottom @ 11,078’ 9 11,328’ Swell Packer: Bottom @ 11,338’ 10 12,993’ WIV (Ball in Seat/ Closed) – Bottom@ 12,995’ OPEN HOLE / CEMENT DETAIL 13-3/8" 350 sx of Arcticset I (Approx) 9-5/8" 541 bbls in 12-1/4” Hole Cement to Surface 5-1/2” Cementless Slotted Liner w/ Swell Packers 8-1/2” hole WELL INCLINATION DETAIL KOP @ 882’ Max Hole Angle = 92.1 deg. @ 12,925’ MD TREE & WELLHEAD Tree 5M Seaboard 2-9/16” Wellhead Seaboard MB-22 5M GENERAL WELL INFO API: 50-029-23550-00-00 Drilled and Cased by Doyon 14 - 2/15/2016 ESP Swap & Patch by ASR #1 – 10/11/2021 Tieback and Convert to JP by ASR#1 - 5-1/2” SLOTTED LINER DETAIL Top (MD) Btm (MD) 7,474’ 11,063’ 11,341’ 12,948’ Liner Slot Dimensions= 2.250” L x .125” W 6.72” Sq/In of Inlet Area per FT of Casing 24 Slots Per Foot of Casing _____________________________________________________________________________________ Revised By: TDF 10/24/2023 PROPOSED Milne Point Unit Well: MPU L-47 Last Completed: 10/11/2021 PTD: 215-117 TD =12,995’ (MD) / TD =4,158’(TVD) 13-3/8” Orig. KB Elev.: 50’/ GL Elev.: 17’ 7-5/8” 3 7 & 8 8 12 & 13 9 10 11 9-5/8” 1 2 14 15 16 Min ID 2.635” @ ±5,430’ PBTD =12,993’ (MD) / PBTD =4,158’(TVD) 6 9-5/8” ‘ES’ Cementer @ 2,535’ 17 5 4 5-1/2” CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 13-3/8" Conductor 68 / A-53 / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TC II 8.835 Surface 7,664’ 0.0759 7-5/8" Production 29.7 / L-80 / Vam SLIJ-II 6.875 Surface 7,402’ 0.0459 5-1/2” Liner 17 / P-110 / DWC/C HT 4.892 7,399’ 12,995 0.0233 TUBING DETAIL 3-1/2” Liner 9.3# / L-80 / EUE 8rd 2.992 Surface ±5,600' 0.0087 JEWELRY DETAIL No Depth Item 1 ±200’STA #2: 3-1/2”GLM w/ ¼” OV 2 ±5,342’STA #1:3-1/2” GLM w/ ¼” OV 3 ±5,430’ XN Nipple, 2.750” Profile, Min ID=2.635” 4 ±5,482’ Discharge Head: 5 ±5,483’ Pump: 6 ±5,540’ Gas Separator: 7 ±5,548’ Upper Tandem Seal: 8 ±5,555’ Lower Tandem Seal: 9 ±5,562’ Motor: 10 ±5,596’ Intake Sensor: 11 ±5,598’ Centralizer: Bottom@ ±5,600’ 12 7,399’ SLZXP Liner Top Packer w/ BD Slips 13 7,402’ Seal Assembly 10’ Inside LTP 14 7,421’ 5-1/2” H563 X 7'' DWC XO 15 11,068’ Swell Packer: Bottom @ 11,078’ 16 11,328’ Swell Packer: Bottom @ 11,338’ 17 12,993’ WIV (Ball in Seat/ Closed) – Bottom@ 12,995’ OPEN HOLE / CEMENT DETAIL 13-3/8" 350 sx of Arcticset I (Approx) 9-5/8" 541 bbls in 12-1/4” Hole Cement to Surface 5-1/2” Cementless Slotted Liner w/ Swell Packers 8-1/2” hole WELL INCLINATION DETAIL KOP @ 882’ Max Hole Angle = 92.1 deg. @ 12,925’ MD TREE & WELLHEAD Tree 5M Seaboard 2-9/16” Wellhead Seaboard MB-22 5M GENERAL WELL INFO API: 50-029-23550-00-00 Drilled and Cased by Doyon 14 - 2/15/2016 ESP Swap & Patch by ASR #1 – 10/11/2021 Tieback and Convert to JP by ASR#1 - 5-1/2” SLOTTED LINER DETAIL Top (MD) Btm (MD) 7,474’ 11,063’ 11,341’ 12,948’ Liner Slot Dimensions= 2.250” L x .125” W 6.72” Sq/In of Inlet Area per FT of Casing 24 Slots Per Foot of Casing 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 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:AOGCC Permitting (CED sponsored) To:Brooks, James S (OGC) Subject:FW: MP L-47 10-403 Withdrawal Request for Sundry # 323-560, PTD: 215-117 Date:Tuesday, October 24, 2023 10:38:05 AM Hi James, I have noted this in the processing 10-403 log. Grace Thank you, Grace Christianson Executive Assistant AOGCC (907) 793-1230 From: Tom Fouts <tfouts@hilcorp.com> Sent: Tuesday, October 24, 2023 10:08 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Ryan Lewis <Ryan.Lewis@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com> Subject: MP L-47 10-403 Withdrawal Request for Sundry # 323-560, PTD: 215-117 Hello, Hilcorp Alaska LLC requests the withdrawal of the 10-403 submittal for MP L-47, Sundry # 23-560. We will be submitting another 10-403 for this well to perform an ESP conversion. Regards, Tom Fouts | Senior Ops/ Reg Tech Hilcorp Alaska, LLC tfouts@hilcorp.com Direct: (907) 777-8398 Mobile: (907) 351-5749 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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. RBDMS JSB 102623 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: Replace Jet Pump 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 12,995'N/A Casing Collapse Conductor N/A Surface 3,090psi Production 5,410psi Liner 7,480psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Wells Manager Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng MILNE POINT SCHRADER BLUFF OIL N/A 4,158' 12,993' 4,158' 789 N/A 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 L-47 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 11/6/2023 Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 / ADL0025515 215-117 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23550-00-00 Hilcorp Alaska LLC C.O. 477.05 Length Size Proposed Pools: 80' 80' 9.3# / L-80 / EUE TVD Burst 7,423' MD N/A 10,640psi 5,750psi 7,240psi 4,094' 4,062' 4,158' 7,664' 7,400' 80' 13-3/8" 9-5/8" 7" 7,629' 7,370' Perforation Depth MD (ft): 12,995' See Schematic See Schematic 3-1/2" Ryan Lewis ryan.lewis@hilcorp.com 303-906-5178 7" x 4-1/2" Baker Premier, SLZXP LTP, Swell Packer (2) and N/A 6,621 MD/ 3,860 TVD, 7,399 MD/ 4,062 TVD, 11,068 MD/ 4,120 TVD & 11,328 MD/ 4,142 TVD and N/A 5-1/2"5,607' 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 9:37 am, Oct 11, 2023 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.10.10 15:55:15 - 08'00' Taylor Wellman (2143) BOPE pressure test to 2500 psi. MGR11OCT23 DSR-10/13/23 10-404 SFD 10/16/2023*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.10.16 21:28:57 -06'00'10/16/23 RBDMS JSB 101723 Well: MPU L-47 Scope: Tubing replacement Date: 09/25/2023 Well Name:MPU L-47 API Number:50-029-23550-00-00 Current Status:Jet Pump Pad:L-Pad Estimated Start Date:Nov 06 , 2023 Rig:ASR 1 Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:215-117 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:RWO Current Bottom Hole Pressure: 1,203 psi @ 4,136’ TVD (7/23/22 / 5.60 ppg EMW) Maximum Expected BHP:1,203 psi @ 4,136’ TVD (7/23/22 / 5.60 ppg EMW) MPSP:789 psi (0.1 psi/ft gradient to surface) Brief Well Summary: MPU L-47 was drilled and completed in February 2016 as a horizontal Schrader Bluff OA producer. The ESP failed in February 2021 due to electrical grounding. Prior to the ESP failure, an IAxOA leak developed in September 2019. A RWO in 2021 installed a 3-1/2” patch in the 7-5/8” to restore casing integrity. An ESP was run above the casing patch. In late 2021 an MBE developed from L-48i to L-47 and L-48 was shut in waiting on a conformance treatment. September 2022 it was converted to jet pump. A recent caliper revealed a hole at 6,580’ MD below the bottom hole pressure gauge. Objective: Pull 3-1/2” tubing / replace 48 jts of tubing, and parts below the sliding sleeve with chrome / Run 3-1/2” Jet Pump Completion Notes Regarding Wellbore Condition: Baker Premier Packer – mechanical cut mandrel to release packer. Electric Line 1. MIRU E-Line. Pressure test PCE to 250 psi low, 2,500 psi high. 2. RIH w Mechanical cutter, tie in for depth control and cut mandrel to release packer. See info in well folder. 3. POOH, RDMO E-Line. Pre-Rig Procedure Pumping & Well Support 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU Little Red Services. RU reverse out skid and 500 barrel returns tank. 4. Pressure test lines to 2,500 psi. Well: MPU L-47 Scope: Tubing replacement Date: 09/25/2023 5. Circulate at least one wellbore volume with produced water down tubing, taking returns up casing to 500 barrel returns tank. 6. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR arrival. 7. RD Little Red Services and reverse out skid. 8. Set BPV. ND tree. NU BOPE. Brief RWO Procedure 1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 bbl returns tank. 2. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing and casing. a. If needed, kill well with produced water prior to setting CTS. 3. 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 3-1/2” test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Bleed any pressure on casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the returns tank. Kill well with produced water as needed. Pull BPV. a. If indications show pressure underneath BPV, lubricate out BPV. 5. MU landing joint or spear, BOLDS, PU on the tubing hanger. a. The current completion was landed with 25K slack off wt and a PUW of 48K. 6. Confirm hanger free, work to confirm the packer is released, lay down tubing hanger. 7. Reverse circulate a bottoms up to flush out all the packer gas. Confirm the tubing and IA are dead. 8. RU the spooler for the I-line. 9. POOH and lay down the 3-1/2” tubing. Number all joints. a. Keep first 157 full jts. Wash and toss everything below that. b. Note any sand or scale inside or on the outside of the tubing on the morning report. c. Look for over-torqued connections from previous tubing runs, trash these joints. 112 Cross collar clamps 10. Lay Down Sliding sleeve, BHP Carrier, Baker Premier Packer, and the x-nipple. Visually inspect the everything for re-use on a different well. Discard the packer. 11. RU slickline to run a 40-arm caliper on the 7” from 7,399’ to surface. Verify the 7” casing is good. 12. RIH with new 3-1/2”, 9.2# 13Cr below the sliding sleeve and L-80 (157 re-use + 48 new/Yellow = 205 jts) above completion to +/- 7,423’ and obtain string weights. Well: MPU L-47 Scope: Tubing replacement Date: 09/25/2023 Colors indicate assemblies to be bucked up prior to RWO. Nom. Size ~Length Item Lb/ft Material Notes 3.5'' 30’WLEG 9.2 9Cr Land Bottom @ 7,423’ 3.5''690'22 Joints 9.2 13Cr BEAR thread 3.5''10'Pup Joint 9.2 9Cr 3.5''XN Nipple w/ RHC Profile 9.2 9Cr Halliburton Set below 70 o ~6,690' MD 3.5''10'Pup Joint 9.2 9Cr 3.5'' 1 joint 9.2 13Cr BEAR thread 3.5''10'XO 4.5'' to 3.5'' Joint 9.2 9Cr 4.5'' 7” x 4-1/2” Packer Ni TriPoint Permanent Packer 3.5''10' XO 3.5'' to 4.5'' Joint 9.2 9Cr 3.5'' 1 joint 9.2 13Cr BEAR thread 3.5''10'Pup Joint 9.2 9Cr 3.5''BHP Guage 9.2 Ni Baker 3.5''10'Pup Joint 9.2 9Cr 3.5'' 1 joint 9.2 13Cr BEAR thread 3.5''10'Pup Joint 9.2 9Cr 3.5''HAL Sliding Sleeve 9.3 L-80 3.5''10'Pup Joint 9.3 L-80 3.5''6430 ~205 Joints 9.3 L-80 3.5''Space out PUPS 9.3 L-80 3.5'' 1 joint 9.3 L-80 3.5''PUP 9.3 L-80 3.5''Tubing Hanger 9.3 L-80 13. Spot corrosion inhibited packer fluid in the IA between the sliding sleeve and the packer. IA volumes based on proposed depths: a. Surface to sliding sleeve: 0.0264bpf x 6,510’ = 172 bbls b. Sliding sleeve to packer: 0.0264bpf x 111’ = 3.0 bbls c. IA Surface to 2,000’ (freeze protect): 0.0264bpf x 2,000’ = 53 bbls d. Tbg Surface to 2,000’ (freeze protect): 0.0087bpf x 2,000’ = 18 bbls 14. Drop ball and rod and complete loading tubing with FP and hydraulically set the packer as per manufacturers setting procedure. 15. Pressure up and test the tubing to 3,000 psi for MIT-T with positive pressure on the IA. Bleed off the tubing to 1000psi. Test the IA to 3,500 psi for MIT-IA. Record and notate all pressure tests (30 minutes) on chart. Well: MPU L-47 Scope: Tubing replacement Date: 09/25/2023 16. Set BPV. 17. RDMO ASR. Post-Rig Procedure: Well Support 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. ND BOPE, set CTS plug, and NU tree. 3. Test tubing hanger void to 500 psi low/5,000 psi high. Pull CTS and BPV. 4. RD crane. Move 500 bbl returns tank and rig mats to next well location. 5. RU well house and flowlines. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Double Ram BOPE Schematic _____________________________________________________________________________________ Revised By: TDF 10/9/2023 SCHEMATIC Milne Point Unit Well: MPU L-47 Last Completed: 10/11/2021 PTD: 215-117 TD =12,995’ (MD) / TD =4,158’(TVD) 13-3/8” Orig. KB Elev.: 50’/ GL Elev.: 17’ 1 2 11 19 9-5/8” 8 9 Min ID 2.81” @ ±6,700’ PBTD =12,993’ (MD) / PBTD =4,158’(TVD) 9-5/8” ‘ES’ Cementer @ 2,535’ 10 5-1/2” 3 4 7” 5, 6 & 7 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 13-3/8" Conductor 68 / A-53 / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TC II 8.835 Surface 7,664’ 0.0759 7" Production 26 / L-80 / TXB BTC 6.276 Surface 7,400’ 0.0383 5-1/2” Liner 17 / P-110 / DWC/C HT 4.892 7,399’ 12,995 0.0233 TUBING DETAIL 3-1/2” Tubing 9.3# / L-80 / EUE 2.992 Surface 7,423' 0.0087 JEWELRY DETAIL No Depth Item 1 6,510’ HES Sliding Sleeve 2 6,562’ BHP Gauge 3 6,621’ 7”x4-1/2” Baker Premier Packer 4 6,689’ X Nipple (Min ID = 2.813”) 5 7,399’ SLZXP Liner Top Packer w/ BD Slips 6 7,392’ WLEG –Btm @ 7,423’ 7 7,421’ 5-1/2” H563 X 7'' DWC XO 8 11,068’ Swell Packer: Bottom @ 11,078’ 9 11,328’ Swell Packer: Bottom @ 11,338’ 10 12,993’ WIV (Ball in Seat/ Closed) – Bottom@ 12,995’ OPEN HOLE / CEMENT DETAIL 13-3/8" 350 sx of Arcticset I (Approx) 9-5/8" 541 bbls in 12-1/4” Hole Cement to Surface 5-1/2” Cementless Slotted Liner w/ Swell Packers 8-1/2” hole WELL INCLINATION DETAIL KOP @ 882’ Max Hole Angle = 92.1 deg. @ 12,925’ MD TREE & WELLHEAD Tree 5M Seaboard 2-9/16” Wellhead Seaboard MB-22 5M GENERAL WELL INFO API: 50-029-23550-00-00 Drilled and Cased by Doyon 14 - 2/15/2016 ESP Swap & Patch by ASR #1 – 10/11/2021 Tieback and Convert to JP by ASR#1 - 5-1/2” SLOTTED LINER DETAIL Top (MD) Btm (MD) 7,474’ 11,063’ 11,341’ 12,948’ Liner Slot Dimensions= 2.250” L x .125” W 6.72” Sq/In of Inlet Area per FT of Casing 24 Slots Per Foot of Casing _____________________________________________________________________________________ Revised By: TDF 10/9/2023 PROPOSED Milne Point Unit Well: MPU L-47 Last Completed: 10/11/2021 PTD: 215-117 TD =12,995’ (MD) / TD =4,158’(TVD) 13-3/8” Orig. KB Elev.: 50’/ GL Elev.: 17’ 5, 6 & 7 1 2 11 19 9-5/8” 8 9 Min ID 2.81” @ ±6,700’ PBTD =12,993’ (MD) / PBTD =4,158’(TVD) 9-5/8” ‘ES’ Cementer @ 2,535’ 10 5-1/2” 3 4 7” CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 13-3/8" Conductor 68 / A-53 / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TC II 8.835 Surface 7,664’ 0.0759 7" Production 26 / L-80 / TXB BTC 6.276 Surface 7,400’ 0.0383 5-1/2” Liner 17 / P-110 / DWC/C HT 4.892 7,399’ 12,995 0.0233 TUBING DETAIL 3-1/2” Tubing 9.3# / L-80 / EUE 2.992 Surface ±6,444' 0.0087 3-1/2” Tubing 9.2# / 13CR / Bear 2.992 ±6,444' ±7,423’ 0.0087 JEWELRY DETAIL No Depth Item 1 ±6,440’ HES Sliding Sleeve 2 ±X,XXX’ BHP Gauge 3 ±X,XXX’ 7”x 4-1/2” Permanent Packer 4 ±6,690’ X Nipple (Min ID = 2.813”) 5 7,399’ SLZXP Liner Top Packer w/ BD Slips 6 ±X,XXX’ WLEG – Btm @ ±7,423’ 7 7,421’ 5-1/2” H563 X 7'' DWC XO 8 11,068’ Swell Packer: Bottom @ 11,078’ 9 11,328’ Swell Packer: Bottom @ 11,338’ 10 12,993’ WIV (Ball in Seat/ Closed) – Bottom@ 12,995’ OPEN HOLE / CEMENT DETAIL 13-3/8" 350 sx of Arcticset I (Approx) 9-5/8" 541 bbls in 12-1/4” Hole Cement to Surface 5-1/2” Cementless Slotted Liner w/ Swell Packers 8-1/2” hole WELL INCLINATION DETAIL KOP @ 882’ Max Hole Angle = 92.1 deg. @ 12,925’ MD TREE & WELLHEAD Tree 5M Seaboard 2-9/16” Wellhead Seaboard MB-22 5M GENERAL WELL INFO API: 50-029-23550-00-00 Drilled and Cased by Doyon 14 - 2/15/2016 ESP Swap & Patch by ASR #1 – 10/11/2021 Tieback and Convert to JP by ASR#1 - 5-1/2” SLOTTED LINER DETAIL Top (MD) Btm (MD) 7,474’ 11,063’ 11,341’ 12,948’ Liner Slot Dimensions= 2.250” L x .125” W 6.72” Sq/In of Inlet Area per FT of Casing 24 Slots Per Foot of Casing 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 Nolan Vlahovich Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 08/2/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL Well: MPU L-47 PTD: 215-117 API: 50-029-23550-00-00 Caliper Survey, 7/24/23 SFTP Transfer - Data Folders: Please include current contact information if different from above. 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ϭϬͬϭϬͬϮϬϮϮͲDŽŶĚĂǇ ϭϬͬϳͬϮϬϮϮͲ&ƌŝĚĂǇ t>>&>Kt/E'KEZZ/s>͘^d<W^t/E'KsZd<KEdZK>͕^dKEdKt>>,͕WdWϮϱϬ>ͬϮϱϬϬ,;ŐŽŽĚͿ͘ Wh>>ϯͲϭͬϮΗyͲ>K<tͬϯΗ:dWhDW/E^>//E'^>sdϲ͕ϱϴϬΖD͘^dϯͲϭͬϮΗyͲ>K<tͬϯΗ:dWhDWtͬ^ZE ;ϭϯ^ͬEͲWͲϭϬϵϵͿ/Ey^>//E'^>sdϲ͕ϱϴϬΖD͘t>>^ͬ/KEZdhZ͕EKd/&/WKW͕t>>/^ZzdKWKW͘ ϭϬͬϱͬϮϬϮϮͲtĞĚŶĞƐĚĂǇ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůǇKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ ϭϬͬϲͬϮϬϮϮͲdŚƵƌƐĚĂǇ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/3/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20220930 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPU I-17 500292321200 204098 3-Aug-22 READ CaliperSurvey MPU B-24 500292264200 196009 7/19/2022 READ CaliperSurvey MPU F-38 500292261400 195168 9/19/2022 READ CaliperSurvey MPU F-73A 500292274401 200198 7/31/2022 READ CaliperSurvey MPU I-01 500292206500 190090 8/31/2022 READ CaliperSurvey MPU I-30 500292371000 222023 7/12/2022 READ Inj_Profile MPU J-27 500292355700 215153 8/11/2022 READ CaliperSurvey MPU L-47 500292355000 215117 7/23/2022 READ CaliperSurvey Please include current contact information if different from above. T37121 T37122 T37123 T37124 T37125 T37126 T37127 T37128MPU L-47 500292355000 215117 7/23/2022 READ CaliperSurvey Kayla Junke Digitally signed by Kayla Junke Date: 2022.10.05 13:20:28 -08'00' From:Regg, James B (OGC) To:AOGCC Records (CED sponsored) Subject:FW: MPU L-47 (PTD 215-117) Sundry #322-405 BOP Test Date:Friday, September 9, 2022 9:10:51 AM Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Regg, James B (OGC) Sent: Friday, September 9, 2022 9:09 AM To: Taylor Wellman <twellman@hilcorp.com> Subject: RE: MPU L-47 (PTD 215-117) Sundry #322-405 BOP Test Thanks for your call and clarifying the dates. You may forgo the BOPE test due today based on the expectation the jet pump completion should be landed or at least being run in the well. If the completion has to be pulled back to surface a BOPE Test will be required before rerunning. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Regg, James B (OGC) Sent: Friday, September 9, 2022 8:28 AM To: Taylor Wellman <twellman@hilcorp.com> Subject: RE: MPU L-47 (PTD 215-117) Sundry #322-405 BOP Test Dates are confusing. Is test due today 9/9 or tomorrow 9/10? ASR1? Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From: Taylor Wellman <twellman@hilcorp.com> Sent: Friday, September 9, 2022 7:20 AM To: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: MPU L-47 (PTD 215-117) Sundry #322-405 BOP Test Mr. Regg, The workover operations for Milne Point well MPU L-47 (PTD 215-117) under Sundry #322-405 have a due date for the next BOP test by midnight tomorrow evening (09/09/22). We have submitted a test notification earlier today for a 10:00 test tomorrow morning. There is a chance we will be running the completion starting tomorrow morning and should complete the scope of work by midnight barring any unforeseen hiccups. If things go smoothly through the night and we are running the completion by late morning, the proposed plans would be to continue on and not perform the weekly BOP test. I will provide an update in the morning to you and to your inspectors on the progress of the job. If you see any issue with this course of action or if you would like any further details I can provide with the morning update. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC – Ops Engineer: Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. 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ĐŽŶĨŽƌŵĂŶĐĞƚƌĞĂƚŵĞŶƚ͘/Ŷ:ƵŶĞϮϬϮϮƚŚĞ^WƐƚĂƌƚĞĚƚŽĞǆƉĞƌŝĞŶĐĞ ůŽǁŝŶĨůŽǁĂŶĚ ĨĂŝůĞĚŵĞĐŚĂŶŝĐĂůůǇ ĚŽǁŶŚŽůĞ͘ ůƐŽĂƚƚŚŝƐƚŝŵĞ͕ƚŚĞϳͲϱͬϴ͟ǆϵͲϱͬϴ͟ŽƵƚĞƌĂŶŶƵůƵƐƉƌĞƐƐƵƌĞĚƌŽƉƉĞĚĂŶĚǁĞŶƚŽŶĂǀĂĐŝŶĚŝĐĂƚŝŶŐ ƉŽƐƐŝďůĞůŽƐƐŽĨĐŽŵƉĞƚĞŶĐǇŽĨƚŚĞϳͲϱͬϴ͟ĐĂƐŝŶŐ͘ EŽƚĞƐZĞŐĂƌĚŝŶŐtĞůůďŽƌĞŽŶĚŝƚŝŽŶ x <ŶŽǁŶŚŽůĞƐŝŶƚŚĞϳͲϱͬϴ͟ĐĂƐŝŶŐ͘ ƵƌŝŶŐƚŚĞKĐƚŽďĞƌϮϬϮϭǁŽƌŬŽǀĞƌƚŚĞϳͲϱͬϴ͟ĐĂƐŝŶŐǁĂƐƚĞƐƚĞĚ ǁŝƚŚĂƚĞƐƚƉĂĐŬĞƌĂŶĚŚĂĚŚŽůĞ;ƐͿďĞƚǁĞĞŶϱ͕ϱϰϬ͛ ʹ ϳ͕ϰϯϲ͛ŵĚ͘/ŶƚĞŐƌŝƚǇǁĂƐƌĞƐƚŽƌĞĚǁŝƚŚĂϯͲϭͬϮ͟ ĐĂƐŝŶŐƉĂƚĐŚ͘/Ŷ:ƵŶĞϮϬϮϮ ƚŚĞϳͲϱͬϴ͟ǆϵͲϱͬϴ͟ŽƵƚĞƌĂŶŶƵůƵƐƉƌĞƐƐƵƌĞĚƌŽƉƉĞĚĂŶĚǁĞŶƚŽŶĂǀĂĐ ŝŶĚŝĐĂƚŝŶŐƉŽƐƐŝďůĞůŽƐƐŽĨĐŽŵƉĞƚĞŶĐǇŽĨƚŚĞϳͲϱͬϴ͟ĐĂƐŝŶŐŽƌϯͲϭͬϮ͟ƉĂƚĐŚ͘ x ϵͲϱͬϴ͟ĐĂƐŝŶŐƉĂƐƐĞĚĂƉƌĞƐƐƵƌĞƚĞƐƚƚŽϭ͕ϬϬϬƉƐŝŽŶϭϬͬϬϴͬϮϬϮϭ͘ KďũĞĐƚŝǀĞ͗ WƵůů ĨĂŝůĞĚ ^W ƌƵŶĂŶĞǁ ũĞƚƉƵŵƉĐŽŵƉůĞƚŝŽŶ͘ ^ůŝĐŬůŝŶĞ;EŽŶͲƐƵŶĚƌŝĞĚƐƚĞƉƐͿ ϭ͘ Zh^ůŝĐŬůŝŶĞƵŶŝƚĂŶĚƉƌĞƐƐƵƌĞƚĞƐƚWƚŽϮϱϬƉƐŝͬϭ͕ϱϬϬƉƐŝŚŝŐŚ͘ Ϯ͘ ƌŝĨƚĂŶĚƚĂŐǁŝƚŚƐĂŵƉůĞƌďĂŝůĞƌ͘ ϯ͘ ĂůŝƉĞƌƚƵďŝŶŐ͘ ϰ͘ WƵůůůŽǁĞƌ'>sĨƌŽŵ ϱ͕ϮϮϰ͛ŵĚ͘ ϱ͘ WƵůů>'>sĂŶĚƐĞƚ'>sŝŶƵƉƉĞƌ'>DĂƚϭϮϯ͛ŵĚ͘ ϲ͘ Z^>ƵŶŝƚ͘ WƌĞͲZŝŐWƌŽĐĞĚƵƌĞ͗ ϭ͘ ůĞĂƌĂŶĚůĞǀĞůƉĂĚĂƌĞĂ ŝŶĨƌŽŶƚŽĨǁĞůů͘^ƉŽƚƌŝŐŵĂƚƐĂŶĚĐŽŶƚĂŝŶŵĞŶƚ͘ Ϯ͘ ZǁĞůůŚŽƵƐĞĂŶĚĨůŽǁůŝŶĞƐ͘ůĞĂƌĂŶĚůĞǀĞůĂƌĞĂĂƌŽƵŶĚǁĞů ů͘ WƵůů ĨĂŝůĞĚ ^W ƌƵŶĂŶĞǁ ũĞƚƉƵŵƉĐŽŵƉůĞƚŝŽŶ͘ ƐŐZĞƉĂŝƌΘ ŽŶǀĞƌƚƚŽ:W tĞůů͗ DWh >Ͳϰϳ ĂƚĞ͗ ϬϳͬϬϲͬϮϬϮϮ ϯ͘ Zh>ŝƚƚůĞZĞĚ^ĞƌǀŝĐĞƐ͘ZhƌĞǀĞƌƐĞŽƵƚƐŬŝĚĂŶĚϱϬϬďďůƌĞƚƵƌŶƐƚĂŶŬ͘ ϰ͘ WƌĞƐƐƵƌĞƚĞƐƚůŝŶĞƐƚŽϯ͕ϬϬϬƉƐŝ͘ ϱ͘ ŝƌĐƵůĂƚĞĂƚůĞĂƐƚŽŶĞǁĞůůďŽƌĞǀŽůƵŵĞǁŝƚŚ ƉƌŽĚƵĐĞĚ ǁĂƚĞƌͬƐŽƵƌĐĞǁĂƚĞƌ ĚŽǁŶƚƵďŝŶŐ͕ƚĂŬŝŶŐ ƌĞƚƵƌŶƐƵƉ / ƚŽϱϬϬďďůƌĞƚƵƌŶƐƚĂŶŬ͘ ϲ͘ ^ǁĂƉƚŽƚŚĞ/ĂŶĚĐŝƌĐƵůĂƚĞŽŶĞ/ͬKǀŽůƵŵĞǁŝƚŚƉƌŽĚƵĐĞĚǁĂƚĞƌͬƐŽƵƌĐĞǁĂƚĞƌĚŽǁŶ/͕ƚĂŬŝŶŐ ƌĞƚƵƌŶƐƵƉKƚŽϱϬϬďďůƌĞƚƵƌŶƐƚĂŶŬ͘ ƵůůŚĞĂĚĚŽǁŶƚŚĞ/ ĂŶĚͬŽƌƚŚĞK ƚŽĞŶƐƵƌĞ ƉƌŽĚƵĐĞĚ ǁĂƚĞƌͬƐŽƵƌĐĞǁĂƚĞƌ ŝƐĐŽŵƉůĞƚĞůǇĐŝƌĐƵůĂƚĞĚ͘ ϳ͘ ŽŶĨŝƌŵǁĞůůŝƐĚĞĂĚ͘ ŽŶƚĂĐƚƚŚĞŽƉĞƌĂƚŝŽŶƐĞŶŐŝŶĞĞƌŝĨĨƌĞĞǌĞƉƌŽƚĞĐƚŝŽŶŝƐŶĞĞĚĞĚĚĞƉĞŶĚŝŶŐŽŶ ^ZĂƌƌŝǀĂů͘ ϴ͘ Z>ŝƚƚůĞZĞĚ^ĞƌǀŝĐĞƐĂŶĚƌĞǀĞƌƐĞŽƵƚƐŬŝĚ͘ ϵ͘ ^ĞƚWs͘ EƚƌĞĞ͘ ƌŝĞĨ ZtK WƌŽĐĞĚƵƌĞ͗ ϭϬ͘ D/Zh ^Z͕ĂŶĐŝůůĂƌǇĞƋƵŝƉŵĞŶƚĂŶĚůŝŶĞƐ͘ ϭϭ͘ ŚĞĐŬĨŽƌƉƌĞƐƐƵƌĞĂŶĚŝĨϬƉƐŝ͘/Ĩ ŶĞĞĚĞĚ͕ďůĞĞĚŽĨĨĂŶǇƌĞƐŝĚƵĂůƉƌĞƐƐƵƌĞŽĨĨƚƵďŝŶŐĂŶĚĐĂƐŝŶŐ͘/Ĩ ŶĞĞĚĞĚ͕ŬŝůůǁĞůůǁͬ ƉƌŽĚƵĐĞĚǁĂƚĞƌŽƌƐŽƵƌĐĞǁĂƚĞƌ͘ ^Ğƚd^WůƵŐ͘ ϭϮ͘ EhKW͘ ϭϯ͘ dĞƐƚKWƚŽϮϱϬͬϮ͕ϱϬϬƉƐŝĨŽƌϱͬϱŵŝŶ͘dĞƐƚĂŶŶƵůĂƌƚŽϮϱϬͬϮ͕ϱϬϬƉƐŝĨŽƌϱͬϱŵŝŶ͘ Ă͘ EŽƚŝĨǇƚŚĞK'Ϯϰ ŚŽƵƌƐŝŶĂĚǀĂŶĐĞŽĨKWƚĞƐƚ͘ ď͘ dĞƐƚƵƉƉĞƌ ϮͲϳͬϴ͟ǆ ϱ͟ƌĂŵƐǁŝƚŚƚŚĞ ϮͲϳͬϴ͟ ƚĞƐƚũŽŝŶƚ ĂŶĚϯЪ͛͛ƚĞƐƚũŽŝŶƚ͘ Đ͘ ŽŶĨŝƌŵƚĞƐƚƉƌĞƐƐƵƌĞƐǁŝƚŚƉƉƌŽǀĞĚ^ƵŶĚƌǇ͘ Ě͘ ŶƐƵƌĞƚŽŵŽŶŝƚŽƌƐŝĚĞŽƵƚůĞƚǀĂůǀĞƐĂŶĚĂŶŶƵůƵƐǀĂůǀĞƉƌĞƐƐƵ ƌĞŐĂƵŐĞƐƚŽĞŶƐƵƌĞ ŶŽƉƌĞƐƐƵƌĞŝƐƚƌĂƉƉĞĚ ƵŶĚĞƌŶĞĂƚŚƚĞƐƚƉůƵŐ͘ Ğ͘ KŶĐĞKWƚĞƐƚŝƐĐŽŵƉůĞƚĞ͕ƐĞŶĚĂĐŽƉǇŽĨƚŚĞƚĞƐƚƌĞƉŽƌƚ;ϭϬͲϰϮϰĨŽƌŵͿƚŽK' ĂŶĚƚŽǁŶĞŶŐŝŶĞĞƌ͘ ϭϰ͘ ůĞĞĚĂŶǇƉƌĞƐƐƵƌĞŽĨĨĐĂƐŝŶŐƚŽ ƚŚĞ ƌĞƚƵƌŶƐƚĂŶŬ͘WƵůů d^ƉůƵŐĂŶĚWs͘<ŝůůǁĞůů ǁŝƚŚ ƉƌŽĚƵĐĞĚǁĂƚĞƌ ŽƌƐŽƵƌĐĞǁĂƚĞƌ ĂƐŶĞĞĚĞĚ͘ ϭϱ͘ DhůĂŶĚŝŶŐũŽŝŶƚŽƌƐƉĞĂƌĂŶĚWhŽŶƚŚĞƚƵďŝŶŐŚĂŶŐĞƌ͘ Ă͘ dŚĞWhǁĞŝŐŚƚĚƵƌŝŶŐƚŚĞϮϬϮϭ ^WƐǁĂƉǁĂƐ ϰϯ<ůďƐ ƚŽĨƌĞĞƉŝƉĞ͘dŚĞĐƵƌƌĞŶƚ ĐŽŵƉůĞƚŝŽŶǁĂƐůĂŶĚĞĚǁŝƚŚĂ ƐůĂĐŬŽĨĨ ǁƚŽĨ ϭϳ͘ϱŬ͘ WhtǁĂƐŶŽƚƌ ĞĐŽƌĚĞĚ ϭϲ͘ ZĞĐŽǀĞƌƚŚĞƚƵďŝŶŐŚĂŶŐĞƌ͘ ϭϳ͘ WKK,ĂŶĚůĂǇĚŽǁŶƚŚĞ ϮͲϳͬϴ͟ƚƵďŝŶŐ͘ EƵŵďĞƌĂůůũŽŝŶƚƐ͘ dďŐǁŝů ůďĞ ŝŶƐƉĞĐƚĞĚĂŶĚ ďƌŽƵŐŚƚƚŽŝŶǀĞŶƚŽƌǇ ƵŶůĞƐƐĚĂŵĂŐĞŽƌŽƚŚĞƌŽďƐĞƌǀĂƚŝŽŶƐĂƌĞƐĞĞŶǁŚŝůĞƉƵůůŝŶŐ͘ >ĂǇ ĚŽǁŶĨĂŝůĞĚ^W͘ Ă͘ WƵůůŽƵƚĂůůǀŝƐƵĂůůǇďĂĚũŽŝŶƚƐ ĂŶĚŵĂƌŬ ĨŽƌĚŝƐƉŽƐĂů͘ ď͘ >ŽŽŬĨŽƌŽǀĞƌͲƚŽƌƋƵĞĚĐŽŶŶĞĐƚŝŽŶƐĨƌŽŵƉƌĞǀŝŽƵƐƚƵďŝŶŐƌƵŶƐ ĂŶĚũƵŶŬƚŚĞŵ͘ Đ͘ ůůĐůĂŵƉƐĂŶĚũĞǁĞůƌǇǁŝůůďĞĐůĞĂŶĞĚĂŶĚƉƵƚŝŶƚŽŝŶǀĞŶƚŽƌǇ ĨŽƌƌĞͲƵƐĞ͘ &URVVFROODUFODPSV 3URWHFWROL]HU&ODPSV )ODW*XDUG&ODPSV 3XPS&ODPSV ƐŐZĞƉĂŝƌΘ ŽŶǀĞƌƚƚŽ:W tĞůů͗ DWh >Ͳϰϳ ĂƚĞ͗ ϬϳͬϬϲͬϮϬϮϮ ϭϴ͘ Dh ƌĂƚĐŚůĂƚĐŚ ůŽĐĂƚŝŶŐƐĞĂůĂƐƐĞŵďůǇ ,ŽŶϯͲϭͬϮ͟ǁŽƌŬƐƚƌŝŶŐ͘ ϭϵ͘ d/,ƚŽцϱ͕ϰϲϬ͛ĂŶĚŽďƚĂŝŶWht͘d/,ĂŶĚůĂƚĐŚŝŶƚŽƌĂƚĐŚůĂƚĐŚ͘WhƚŽƌĞůĞĂƐĞW,>ƉĂĐŬĞƌĂŶĚdKK,͘ Ă͘ dŚĞW,>ƉĂĐŬĞƌŝƐƉŝŶŶĞĚĨŽƌ ϯϲ͘ϰŬ ŽǀĞƌƉƵůůƚŽƌĞůĞĂƐĞ͘ ď͘ >ŽǁĞƌƉŽƌƚŝŽŶŽĨƚŚĞƉĂƚĐŚ ĂƌĞďƵůůĞƚƐĞĂůƐƐƚƵŶŐŝŶƚŽĂϰͲϭͬϮ͟ǆϳ͟ĂŬĞƌWƌĞŵŝĞƌWĂĐŬĞƌ͘ dŚĞďƵůůĞƚƐĞĂůƐǁŝůůďĞƌĞĐŽǀĞƌĞĚŽŶƚŚŝƐƌƵŶ͘ Đ͘ ^ĞŶĚW,>ƉĂĐŬĞƌƚŽ,ĂůůŝďƵƌƚŽŶĨŽƌƌĞͲĚƌĞƐƐ͘ ϮϬ͘ ŚĂŶŐĞŽƵƚŚĂŶĚůŝŶŐĞƋƵŝƉŵĞŶƚ͕ŝŶƐƚĂůůĐĂƐŝŶŐĐƌĞǁƚŽŶŐƐ͕ĂŶĚƵƉƉĞƌƌĂŵƐĨŽƌŚĂŶĚůŝŶŐϳͲϱͬϴ͟ ĐĂƐŝŶŐ͘ Ϯϭ͘ WĞƌĨŽƌŵKWƚĞƐƚŽŶƚŚĞϳͲϱͬϴ͟ƉŝƉĞƌĂŵƐŽŶϳͲϱͬϴ͟ƚĞƐƚũŽŝŶƚƚŽϱϬϬͬϮ͕ϱϬϬƉƐŝ͘ ϮϮ͘ /ŶƐƚĂůůĐĂƐŝŶŐũĂĐŬƐŽŶƚŽƉŽĨKWƐƚĂĐŬĂŶĚĨƵŶĐƚŝŽŶƚĞƐƚ͘ Ϯϯ͘ hƚŝůŝǌĞĐĂƐŝŶŐũĂĐŬƐƚŽƵŶƐĞĂƚĂŶĚƉƵůůϳͲϱͬϴ͟ĐĂƐŝŶŐ͘ Ă͘ WhǁĞŝŐŚƚĚƵƌŝŶŐƚŚĞϮϬϭϲ ŝŶƐƚĂůůĂƚŝŽŶŽĨƚŚĞϳͲϱͬϴ͟ĐĂƐŝŶŐǁĂƐ ϭϲϱŬůďƐ͘EŽƚĞƚŚĂƚƚŚŝƐ ǁĞŝŐŚƚǁĂƐǁŝƚŚĂĨƵůůĐŽůƵŵŶŽĨ ϴ͘ϵƉƉŐďƌŝŶĞ͘ ď͘ hƐĞĐĂƐŝŶŐũĂĐŬƐƵŶƚŝůĐŽŵĨŽƌƚĂďůǇƵŶĚĞƌƚŚĞƉƵůůŝŶŐůŝŵŝƚĂƚŝ ŽŶƐŽĨƚŚĞ ^ZĂŶĚƐǁĂƉŽǀĞƌƚŽ ƵƐŝŶŐƚŚĞ^ZĞůĞǀĂƚŽƌƐ͘ Đ͘EŽƚĞƚŚĂƚƚŚĞƌĞŝƐĂϳ͟ǆϰͲϭͬϮ͟ĂŬĞƌWƌĞŵŝĞƌWĂĐŬĞƌƐĞƚŝŶƐŝĚĞƚŚĞůĂƐƚũŽŝŶƚŽĨƚŚĞϳͲϱͬϴ͟ ĐĂƐŝŶŐ͘ Ϯϰ͘ ^ǁĂƉƉŝƉĞƌĂŵƐƚŽϮͲϳͬϴ͟ǆϱ͟ƌĂŵƐĂŶĚƚĞƐƚϯЪ͛͛ƚĞƐƚũŽŝŶƚƚŽϱϬϬͬϮ͕ϱϬϬƉƐŝ͘ Ϯϱ͘ DhůĞĂŶŽƵƚĂƐƐĞŵďůǇǁŝƚŚ ĐĂƐŝŶŐƐĐƌĂƉĞƌĂďŽǀĞ͘ Ă͘ Z/,ƚŽ цϳ͕ϰϬϮ͛DƚŽĞŶƐƵƌĞŶĞǁ:WĐŽŵƉůĞƚŝŽŶǁŝůůĚƌŝĨƚƚŽĚĞƐŝƌĞĚĚĞƉƚŚ͘ ď͘ ƚƚĞŵƉƚƚŽĐůĞĂŶŽƵƚǀŝĂ ĨŽƌǁĂƌĚŽƌ ƌĞǀĞƌƐĞĐŝƌĐƵůĂƚŝŶŐƚŽ цϳ͕ϰϭϬ͛D͘ >ŽǁƐŝĚĞĨŝůůŵĂǇ ƌĞƋƵŝƌĞǁĂƐŚŝŶŐƚŚĞ&KĂƐƐĞŵďůǇĚŽǁŶ͘/ĨƌĞƚƵƌŶƐĂƌĞŶŽƚŽďƚĂ ŝŶĂďůĞ͕ĐŽŶƚĂĐƚKĂďŽƵƚ ƌŽƚĂƚŝŶŐĂŶĚƌĞĐŝƉƌŽĐĂƚŝŶŐǁŚŝůĞƉƵŵƉŝŶŐĂŶĚƉƵƐŚŝŶŐƐŽůŝĚƐŝŶƚ ŽƚŚĞůŝŶĞƌǁŚŝůĞĂƚĨŝŶĂů ĚĞƉƚŚ͘ Ϯϲ͘ Wh ϳ͟ƵůůĞƚƐĞĂůĂƐƐĞŵďůǇǁŝƚŚ ϵͲϱͬϴ͟ƚĞƐƚƉĂĐŬĞƌ ĂďŽǀĞ ĂŶĚd/,ƚŽ цϳ͕ϰϬϮ͛D͘ ^ƚŝŶŐďƵůůĞƚƐĞĂůƐ ŝŶƚŽ^>yW͕ůŽĂĚǁĞůůĂŶĚWdϵͲϱͬϴ͟ĐĂƐŝŶŐƚŽϭ͕ϱϬϬƉƐŝ͘ Ă͘ Wh,ĂƐŶĞĞĚĞĚƚŽĚĞƚĞƌŵŝŶĞ ĐŽŵƉĞƚĞŶƚϵͲϱͬϴ͟ĐĂƐŝŶŐĚĞƉƚŚ͘ŽŶƚĂĐƚKƚŽĚŝƐĐƵƐƐĚĞƉƚŚ ŽĨƉĂƐƐŝŶŐƚĞƐƚ͘ Ϯϳ͘ ^ǁĂƉƉŝƉĞƌĂŵƐƚŽϳ͟ƌĂŵƐĂŶĚƚĞƐƚϳ͛͛ƚĞƐƚũŽŝŶƚƚŽϱϬϬͬϮ͕ϱϬϬƉƐŝ͘ Ϯϴ͘ ZƵŶϳ͟ĐĂƐŝŶŐǁͬďƵůůĞƚƐĞĂůĂƐƐĞŵďůǇ͘^ƉĂĐĞŽƵƚĂŶĚ WhƚŽĐŝƌĐƵůĂƚĞŝŶϭй<ůǁͬĐŽƌƌŽƐŝŽŶ ŝŶŚŝďŝƚŽƌǁŝƚŚĂĚŝĞƐĞůĨƌĞĞǌĞƉƌŽƚĞĐƚŝŶƚŽƚŚĞϳ͟ǆϵͲϱͬϴ͟ĂŶŶƵůƵƐ͘>ĂŶĚϳ͟ĐĂƐŝŶŐ ĂŶĚƉƌĞƐƐƵƌĞƚĞƐƚ ƚŽϭ͕ϬϬϬƉƐŝ͘ Ă͘ Ϯ͕ϮϬϬ͛ŽĨĚŝĞƐĞůĨƌĞĞǌĞƉƌŽƚĞĐƚŝŽŶ͗ϲϮďďůƐ ď͘ ϳ͟ǆϵͲϱͬϴ͟ĂŶŶƵůƵƐƚŽϳ͕ϰϬϮ͛ŵĚ;ƐƵďƚƌĂĐƚĨƌĞĞǌĞƉƌŽƚĞĐƚͿ͗ϭϱϯďďůƐ Ϯϵ͘ ^ǁĂƉƉŝƉĞƌĂŵƐƚŽϮͲϳͬϴ͟ǆϱ͟ƌĂŵƐĂŶĚƚĞƐƚϯЪ͛͛ƚĞƐƚũŽŝŶƚƚŽϱϬϬͬϮ͕ϱϬϬƉƐŝ͘ ϯϬ͘ ZƵŶŶĞǁϯͲϭͬϮ͟ĐŽŵƉůĞƚŝŽŶ͘ ŽůŽƌƐŝŶĚŝĐĂƚĞĂƐƐĞŵďůŝĞƐƚŽďĞďƵĐŬĞĚƵƉƉƌŝŽƌƚŽZtK͘ 1RP 6L]H a/HQJWK ,WHP /EIW 0DWHULDO 1RWHV :/(*/3ODFHDW ¶PG ƐŐZĞƉĂŝƌΘ ŽŶǀĞƌƚƚŽ:W tĞůů͗ DWh >Ͳϰϳ ĂƚĞ͗ ϬϳͬϬϲͬϮϬϮϮ -RLQWV / 3XS-RLQW / ;1LSZLWK5+&SURILOH /6HWEHORZGHJUHHV ¶PG 3XS-RLQW / MRLQW / ;2 WR -RLQW / ´ [ ´3DFNHU /6HWDW¶PG ;2 WR -RLQW / MRLQW / 3XS-RLQW / %+3*XDJH / 3XS-RLQW / MRLQW / 3XS-RLQW / +$/6OLGLQJ6OHHYH / 3XS-RLQW / -RLQWV / 6SDFHRXW3836 / MRLQW / 383 / 7XELQJ+DQJHU / ϯϭ͘ ^ƉĂĐĞŽƵƚĂŶĚůĂŶĚƚŚĞϯͲϭͬϮ͟ĐŽŵƉůĞƚŝŽŶ͘Z/>^͘ ϯϮ͘ ƌŽƉďĂůůĂŶĚƌŽĚĂŶĚĐŽŵƉůĞƚĞůŽĂĚŝŶŐƚƵďŝŶŐǁŝƚŚ&WĂŶĚŚǇ ĚƌĂƵůŝĐĂůůǇƐĞƚƚŚĞƉĂĐŬĞƌĂƐƉĞƌ ŵĂŶƵĨĂĐƚƵƌĞƌƐƐĞƚƚŝŶŐƉƌŽĐĞĚƵƌĞ͘ ϯϯ͘ WƌĞƐƐƵƌĞƵƉĂŶĚƚĞƐƚƚŚĞƚƵďŝŶŐƚŽϯϬϬϬƉƐŝĨŽƌD/dͲdǁŝƚŚƉ ŽƐŝƚŝǀĞƉƌĞƐƐƵƌĞŽŶƚŚĞ/͘ůĞĞĚŽĨĨ ƚŚĞƚƵďŝŶŐƚŽϭϬϬϬƉƐŝ͘dĞƐƚ ƚŚĞ/ƚŽϯϳϬϬƉƐŝĨŽƌD/dͲ/͘ZĞĐŽƌĚĂŶĚŶŽƚĂƚĞĂůůƉƌĞƐƐƵƌĞƚĞƐƚƐ;ϯϬ ŵŝŶƵƚĞƐͿŽŶĐŚĂƌƚ͘ ϯϰ͘ ^ĞƚWs͘ ϯϱ͘ ZDK^Z͘ WŽƐƚͲZŝŐWƌŽĐĞĚƵƌĞ͗ tĞůů^ƵƉƉŽƌƚ ϭ͘ ZŵƵĚďŽĂƚ͘DŽǀĞƚŽŶĞǆƚǁĞůůůŽĐĂƚŝŽŶ͘ Ϯ͘ ZhĐƌĂŶĞ͘EKW͘ ^Ğƚd^ƉůƵŐ͘ ϯ͘ EhƚƌĞĞĂŶĚƚƵďŝŶŐŚĞĂĚĂĚĂƉƚĞƌ͘ ϰ͘ dĞƐƚďŽƚŚƚƌĞĞĂŶĚƚƵďŝŶŐŚĂŶŐĞƌǀŽŝĚƚŽϱϬϬƉƐŝůŽǁͬϱ͕ϬϬϬƉƐŝŚŝŐŚ͘ ƐŐZĞƉĂŝƌΘ ŽŶǀĞƌƚƚŽ:W tĞůů͗ DWh >Ͳϰϳ ĂƚĞ͗ ϬϳͬϬϲͬϮϬϮϮ ϱ͘ WƵůůd^ ƉůƵŐ ΘWs͘ ϲ͘ ZĐƌĂŶĞ͘DŽǀĞϱϬϬďďůƌĞƚƵƌŶƐƚĂŶŬĂŶĚƌŝŐŵĂƚƐƚŽŶĞǆƚǁĞůůůŽĐĂƚŝŽŶ͘ ϳ͘ ZĞƉůĂĐĞŐĂƵŐĞ;ƐͿŝĨƌĞŵŽǀĞĚ͘ ϴ͘ dƵƌŶǁĞůůŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶ͘ZhǁĞůůŚŽƵƐĞĂŶĚĨůŽǁůŝŶĞƐĨŽ ƌĂ:ĞƚWƵŵƉĐŽŵƉůĞƚŝŽŶ͘ WŽƐƚZŝŐtŽƌŬ ^ůŝĐŬůŝŶĞ ϭ͘ ^ƉŽƚ^ůŝĐŬůŝŶĞƵŶŝƚĂŶĚZh͘ Ϯ͘ WƌĞƐƐƵƌĞƚĞƐƚůƵďƌŝĐĂƚŽƌƚŽϯϬϬƉƐŝůŽǁĂŶĚϮ͕ϴϬϬƉƐŝŚŝŐŚ͘ ϯ͘ WƵůůĂůůĂŶĚƌŽĚ͘ ϰ͘ WƵůůZ,ƉƌŽĨŝůĞ͘ ϱ͘ ^ŚŝĨƚ^^ŽƉĞŶ͘ ϲ͘ ^Ğƚ ϭϮ :W͘ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ ƐͲďƵŝůƚ^ĐŚĞŵĂƚŝĐ Ϯ͘ WƌŽƉŽƐĞĚ^ĐŚĞŵĂƚŝĐ ϯ͘ KW^ĐŚĞŵĂƚŝĐ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB ZĞǀŝƐĞĚǇ͗,ϭϬͬϮϴͬϮϬϮϭ ^,Dd/ DŝůŶĞWŽŝŶƚhŶŝƚ tĞůů͗DWh>Ͳϰϳ >ĂƐƚŽŵƉůĞƚĞĚ͗ϭϬͬϭϭͬϮϬϮϭ Wd͗ϮϭϱͲϭϭϳ dсϭϮ͕ϵϵϱ͛;DͿͬdсϰ͕ϭϱϴ͛;dsͿ ϭϯͲϯͬϴ͟ KƌŝŐ͘<ůĞǀ͗͘ϱϬ͛ͬ'>ůĞǀ͗͘ϭϳ͛ ϳͲϱͬϴ͟ ϵͲϱͬϴ͟ DŝŶ/ Ϯ͘ϮϬϱ͟Λ ϱ͕ϯϭϯ͛ WdсϭϮ͕ϵϵϯ͛;DͿͬWdсϰ͕ϭϱϴ͛;dsͿ ´ µ(6¶ &HPHQWHU# ¶ ϱͲϭͬϮ͟ /ǆK>ĞĂŬ ^/E'd/> 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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: Install Patch & ESP Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 12,995 feet N/A feet true vertical 4,158 feet N/A feet Effective Depth measured 12,993 feet feet true vertical 4,158 feet 4,062' & 4,120' & 4,142' 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 5,450' 3,357' SLZXP LTP,See Packers and SSSV (type, measured and true vertical depth)Swell Packers (2) N/A 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: Contact Name: Contact Email: Authorized Title:Operations Manager Contact Phone: 10,640psi Burst Collapse N/A 3,090psi measuredPlugs Junk measured N/A Length 80' 7,629' Size Conductor Surface Production 13-3/8" 9-5/8" 7-5/8" Liner 7,370' 5,607' Casing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-117 50-029-23550-00-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0025509 / ADL0025515 MILNE POINT / SCHRADER BLUFF OIL Hilcorp Alaska LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: MILNE PT UNIT L-47 MD 80' 7,664' 650 TVD 80' 4,094' 4,063' 4,158' 7,402' 12,995'5-1/2" 4,790psi 7,480psi N/A 5,750psi 6,890psi Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 1,413 60023 0 N/A 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 278 Gas-Mcf 7,399' & 11,068' & 11,328' 321-400 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 0 349 Taylor Wellman twellman@hilcorp.com 907-777-8449 measured true vertical Packer Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Samantha Carlisle at 4:03 pm, Nov 01, 2021 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2021.11.01 14:51:59 -08'00' David Haakinson (3533) DSR-11/1/21 RBDMS HEW 11/3/2021 SFD 11/2/2021MGR17FEB2022 Well Name Rig API Number Well Permit Number Start Date End Date MP L-47 ASR 50-029-23550-00-00 215-117 8/25/2021 10/11/2021 Hilcorp Alaska, LLC Weekly Operations Summary Spot Mud Boat, Mod Rig to ASR Tent for maintenance, Well kill operation on hold, waiting on night crew to complete COVID testing prior to completing RU and well kill operations. 8/26/2021 - Thursday Well kill operation on hold, waiting on night crew to complete COVID testing prior to completing RU and well kill operations. Waiting on test results. SimOps: RU LRS and PT lines to 250/2,500 psi (good test). Initial well pressures: tubing = 684 psi, IA = 640 psi & OA = 909 psi. Call out for 9.1 ppg KWF. Bleed gas off the tubing and IA. The tubing had very little gas. Bleed gas off the OA while waiting for KWF to arrive. Spot and RU vac truck with 9.1 ppg NaCl/NaBr brine. Well pressures: tubing = 14 psi, IA = 39 psi & OA = 136 psi. Begin well kill by pumping 20 bbls of 100°F diesel followed by 9.1 ppg NaCl/NaBr (fluid at surface 5 bbls into pumping diesel) down the tubing taking returns up the IA to the kill tank 3 BPM = 100 psi. After 290 bbls pumped we had 220 bbls returned (circulating volume 234 bbls). SI pressures: tubing = 64 psi, IA = 31 psi & OA = 220 psi. Second vac truck yet to arrive. Wait for second vac truck to arrive. Open the tubing & IA and both had a slight blow of gas immediately. Bleed gas off the OA. RU the vac truck. Resume pumping 9.1 ppg brine down the tubing up the IA to the kill tank at 3 BPM. Got fluid back to the kill tank after 5 bbls pumped. Pumped an additional 50 bbls with 36 bbls returned for a total of 340 bbls pumped and 256 bbls returned. Had good clean 9.1 ppg brine to surface. SI in the IA and bullhead 96 bbls down the tubing to the formation at 3 BPM = 300 psi. SD and SI to monitor pressures. Initial pressures: tubing = 297 psi, IA = 255 psi & OA = 361 psi. Bleed off pump pressure and attempt to bleed down tubing and IA but both slight blow of gas. Pressures: tubing =54 psi, IA = 47 psi & OA = 347 psi. OA slowing bleeding down with tubing and IA. Bleed gas off the OA. Pressures: tubing = 63 psi, IA = 65 psi & OA = 44 psi. SI the OA and pressure starts to increase immediately. Bleed the gas off the tubing and IA. Pressures: tubing = 10 psi, IA = 8 psi & OA = 147 psi. Discuss with town engineer. Continue to bleed gas off the tubing, IA & OA. SimOps: PT the tubing hanger void and 7-5/8" pack-off (both good tests). NU 1502 flange to the OA and RU 2" hose to the manifold. Pressures: tubing = 4 psi, IA = 6 psi & OA = 0 psi (still getting gas from all). Begin pumping 9.1 ppg brine down the IA (tubing SI) taking returns out the OA to the kill tank at 3 BPM. After 40 bbls pumped started getting gas cut fluid at the tank. After 60 bbls pumped getting mostly fluid to the tank. Pumped at total of 80 bbls. SD and SI. Pressures: tubing = 201 psi, IA = 198 psi & OA = 82 psi. Monitor the pressure and the tubing & IA went on a vac, the OA pressure increased to 94 psi. Bleed the OA down to 56 psi, SI and the pressure increased to 87 bbls. Tubing and IA still on a vac. Install the 2-1/2" BPV. SimOps: LRS freeze protected lines and RD. Blow and RD circulating line. Empty the kill tank and move. Spot the mud boat, pusher's shack, company man's shack, change room and pits, ND the tree. Install the plug off tool into the BPV. Check the tubing hanger lift thread - good. PT the BPV and plug off tool (good test). Check all the gland nuts and LDS - all good. Spot the crane. Set the BOP stack onto the wellhead and secure. Fly the well house into position over well L-47. Fly the rig floor on top of the well house and secure. Layout the koomey lines and RU. NU the BOP stack. Mobilize the rig from A-pad tent. Spot and level the rig. 8/25/2021 - Wednesday Well Name Rig API Number Well Permit Number Start Date End Date MP L-47 ASR 50-029-23550-00-00 215-117 8/25/2021 10/11/2021 Hilcorp Alaska, LLC Weekly Operations Summary Continue to POOH with ESP completion laying down 2-7/8", 6.4#, L-80 EUE 8rd tubing spooling ESP cable from 3,595' to 65'. Note: The GLM set at 5,354' still had a DV installed. Multiple ESP cable blowouts from joint #162 (tally joint 10, set depth 5,155') to the pump. Started to see light scale on the tubing and corrosion on the cross coupling clamps at joint #115 out of the hole (tally joint #56, set depth at 3,689'). Scale on the tubing and corrosion on the cross coupling clamp increased at joint #157 out of the hole (tally joint #14, set depth 5,027'). The cross coupling clamp just above the XN corroded off and was recovered on top of the pump. No corrosion on the ESP equipment. Lay down the ESP components. Spool the ESP cable over the sheave to the spooling unit. Clear the rig floor of pulled cross coupling clamps. RRD the elephant trunk. RD ESP pulling equipment. Clear the pipe rack of pulled tubing and ESP components. Load 3-1/2" work string (2-7/8" IF connections) onto the pipe rack. Strap and tally. Strap, OD and IA scraper BHA components. PU and MU BHA#1 - dual scraper: 6-1/8" tricone bit, 7" scraper, 7-5/8" scraper, jar and bumper sub (BHA length = 48.77'). RIH with BHA# 1 from 48' to 6,925' on 3-1/2" work string. Started taking weight @ 6,925', Work scrapers from 6,925' to 7,015' then wash & work scrapers from 7,015' to 7,370' to hard tag with 10K down pumping at 2 bpm @ 125 psi to catch fluid, slow pump to 1 bpm while working down, with minimal returns. Returns oil. Not enough fluid in the pits to continue. Call for 290 bbls of brine. 8/28/2021 - Saturday 8/27/2021 - Friday Raise the derrick and pin. RU the ESP cable sheave in the derrick. Continue to NU the BOP stack. Install stairs, landings and hand rails around the rig. Spot the mud pump. RU the pits and service lines. Take on 40 bbls fresh water to pit 4. Set catwalk and pipe racks. RU BOPE testing equipment. Flood the coke manifold & BOP stack with fresh water and purge the air. PU and MU the 2-7/8" test joint. Shell test the BOPE to 250/2,500 psi (good test). Conduct initial BOPE test to 250/2,500 psi: Pipe rams (2-7/8” x 5” VBR’s) with 2-7/8” and 3-1/2”” test joints, annular with 2-7/8” test joint to 250/2,500 psi, accumulator drawdown test and test gas alarms. The states right to witness was waived by AOGCC inspector Guy Cook via email on 8/27/21 at 07:05 hours. Tests: 1. Annular with 2-7/8” test joint, IBOP, C8, C9 & C10 (passed), 2. Pipe rams with 2-7/8” test joint, C1 & K1 (passed), 3. Pipe rams with 3-1/2” test joint, 2-7/8” TIW, HCR choke, K2 (passed), 4. C5, C6 & K3 (passed), 5. C4, C7 & C11 (passed), 6. C13, C14 & C15 (passed), 7. Blind rams, C12 & C16 (passed), 8. Hydraulic super choke (passed), 9. Manual adjustable choke (passed),Accumulator Test: System pressure = 2950 psi, Pressure after closure = 1650 psi, 200 psi attained in 12 seconds, Full pressure attained in 61 seconds. Nitrogen Bottles - 4 at 2100 psi, Pull plug from BPV, stab into BPV open, no pressure observed, pull BPV. Rig up and pump down tubing and take returns from OA, pump 75 bbl at 3 bpm, ICP = 100 psi FCP = 250 psi, no returns to surface, shut down and check pressures, 25 psi on OA, 5 psi on IA. Rig up and pump down tubing returning from IA, pump 3 bpm at 100 psi, returns observed at 20 bbl pumped, returns #9 +, pump 42 bbl, shut down and check pressures. IA and tubing on vac, 30 psi on OA. Losses = 72 bph while pumping. BOLDS, install landing joint, pull hanger to floor, 43K up weight, rig up ESP tools to POOH with 2 7/8" ESP completion. POOH laying down 2 7/8" tubing ESP. Tubing began pulling wet, rig up and pump down tubing, pumped 42 bbl down tubing, no returns to surface, FCP = 725 psi at 1.3 bpm. shut down tubing on vac. 100 psi on OA. Resume POOH with 2 7/8" ESP completion at 3,595'. Note: The upper GLM that was set at 138' had an empty pocket. Well Name Rig API Number Well Permit Number Start Date End Date MP L-47 ASR 50-029-23550-00-00 215-117 8/25/2021 10/11/2021 Hilcorp Alaska, LLC Weekly Operations Summary Continue to RIH with the test packer from 2,820' to 3,086' (PU = 28K & SO = 14.5K) where the packer set down and took weight (packer possibly set). PU 20' with no overpull, SO and set down at the same spot. Manipulate the packer into the release position, PU freely, SO and set down at the same spot. Lay down 1 joint. PU and SO 40' without issue. PU and manipulate the packer into the set position. SO 10K down, PU 10K over and the packer is set. Manipulate late the packer into the release position and move the packer up/down 40' without issue. PU 1 joint of work string, RIH and tag at 3,086' multiple times. Lay down the joint and RU to pump. Attempt to bullhead down the IA but it pressured up to 1,000 psi after 4 bbls; packer must have not been fully engaged in the run position and the element compressed while pumping. Bleed pressure to 0 psi. RD pumping equipment. PU/SO 20' without issue. MU 1 joint of works string, RIH and tag again at 3,086'. SO 15K and the string moved down ~0.5'. Work the string up and down setting 15K down each time and slowly made about 3'. Discuss with town engineer. POOH with test packer from 3,060' to 18'. Break down and lay down the 7 5/8" test packer assembly. Wait for additional tools to arrive from Deadhorse. PU and MU BHA #3 - 7-5/8" scraper, smooth OD string mill, bumper sub and oil jar. RIH with BHA #3, 7 5/8" scraper and mil assembly on 3 1/2" work string t/3,070'. Taking weight at 3,070', work pipe to 3,080', wash from 3,080' to 3,130', unable to go down with out pump, once circ down pipe free can work up and down with out pump. RIH with out pumping from 3,130' to 3,684', wash from 3,684' to 3,750', unable to go down with out pump, once circ down pipe free can work up and down with out pump. Reverse circ 3 tubing volumes @ 3,750', no solids observed at shakers. Pump @ 2 bpm @ 140 psi,) losses during circulation, 17K dn, 29K up. Unable to go down with out pumps, wash from 3,750 to 3,980. 2 bpm @ 140 psi. 8/29/2021 - Sunday Called for 290 bbls of 9.1 ppg brine. While waiting for additional fluid in order to wash down POOH from 7,730' to 5,445'. Work scraper from 5,445' to 5,574' 5 times. RIH with BHA #1 from 5,574' to 6,975'. Load the pits with 9.1 ppg brine. RIH with BHA #1 from 6,975' to 7,227' where it tagged up with 5K down. Wash down at 2 BPM to catch fluid then slow the pump to 1 BPM from 7,220' to hard tag at 7,370' (top of the tie back seal assembly. PU and slowly rotate while pumping and work BHA into the tie back seal assembly. Continue to wash and rotate down to tag at 7,378'. No pump pressure increase just took weight and torque increased, appear to be the 7-5/8" no-go out. Work up and down multiple time with the same result. PU to 7,350' (above the tie back seal assembly). RU & line up to reverse circulate. Reverse circulate 70 bbls at 3 BPM = 700 psi (BU = 64 bbls) and did not see any solids in the returns. POOH with BHA #1 laying down 3-1/2" work string from 7,350' to 48'. Break and lay down 7' and 7 5/8" dual scraper assembly. Set 10" ID wear ring, Pick up and make up 7 5/8' ASI-X test packer. RIH with packer on 3 1/2" work string to 3,581'. 8/30/2021 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP L-47 ASR 50-029-23550-00-00 215-117 8/25/2021 10/11/2021 Hilcorp Alaska, LLC Weekly Operations Summary Continue washing cleaning out 7 5/8" liner from 3,980' to 4,171' with BHA #3, 7 5/8" mill and scraper on 3 1/2" work string. RIH with out pump from 4,171' to 4,703'. Unable to go down without pump, wash from 4,703' to 4,730'. RIH w/o pump from 4,730' to 5,013', wash to 5,050' RIH to 5,470'. wash to 5,490'. Rig up LRS hot oil and pump 20 bbl 180 deg diesel, displace with 45 bbl 9.1 brine. No fluid losses during circulation. RIH from 5,490' to to 7,177'. Took weight @ 7,177', 10K overpull. Circ and work pipe while circulate out 20 bbl diesel pill. No fluid losses during circulation. No solid returns observed during circulation. 2 bpm = 350 psi. 3 bpm = 550 psi. Wash down from 7,177' to tag @ 7,351' with 3k more to slack off 16k continue washing tagging up solid at 7,359' dpm, 7,391' rkb. Continue working pipe and circulating at 2 bpm at 400 psi increase rate to 3 bpm at 750 psi. Pump 20 bbls diesel and displace same with 50 bbls shut pump. Close Annular and pressured up to 600 psi monitoring pressure for 5 minutes Bleeding down to 200 psi each time, pressure up to 750 psi twice monitor pressure for 15 minutes pressure bleeding down 400 psi in 15 minutes. Pressure up to 950 psi monitor pressure for 15 minutes. Pressure bleed down 431 psi in 15 minutes. OA pressured up to 900 psi while attempting to bull head diesel into liner, Bleeding down at same rate as tbg. Circulate well with 9.1 fluid, observe well for 30 min, well static. POH with BHA #3 and 3 1/2" work string to 48'. Laying down BHA #3, 7 5/8" scraper and mill assembly. 8/31/2021 - Tuesday 9/1/2021 - Wednesday Finish laying down BHA #3, 7 5/8" mill and scraper. Pull wear ring, rack and strap 3 1/2" 9.3 L80 EUE kill string. Pick up and RIH with 3 1/2" kill string. Tag up, pick up, space out and land hanger with mule shoe @ 7,409' RILDS. Freeze protect 9 5/8" by 7 5/8" annulus. Rig up LRS & pump 49 bbl diesel into OA returning from IA, pumped 8 bbl to returns, returned 40 bbl to rig tank. ICP .6 bpm @ 900 psi @ , FCP 1.4 bpm @ 865 psi. OA shut in pressure = 305 psi. Rigging down ASR #1, clear rig floor, prep mast and lay over, move off carrier, rig down koomey house, pull fluids from rig tanks, remove cellar sub, general rig down, Nipple down and set out BOPE, Setting in dry hole tree, prep for move to I-38. Testing dry hole tree to 500 / 5,000 psi. remove cellar sub, g Well Name Rig API Number Well Permit Number Start Date End Date MP L-47 ASR 50-029-23550-00-00 215-117 8/25/2021 10/11/2021 Hilcorp Alaska, LLC Weekly Operations Summary 10/4/2021 - Monday Mobilize Rig Crews to North Slope. Call out 580 bbls, 9.0 ppg NaCl Brine, Spot and RU LRS. PT lines to 250/2500 psi (good test). Initial well pressures: tubing = 90 psi, IA = 106 psi & OA = 92 psi,Bleed gas off the tubing and IA while waiting for KWF to arrive. No gas observed. Shut in and standby while waiting for KWF to arrive. Spot and RU Vac truck with 9.0 ppg NaCl brine. Well pressures: tubing = 89 psi, IA = 101 psi & OA = 70 psi. Open tbg to kill tank for 10 min bleeding down to 2 psi. 6 bbls fluid return to tank. Begin well kill by pumping 9.0 ppg NaCl down the IA taking returns up the tbg to the kill tank @ 4.5 BPM. ICP = 291 psi, Tbg = 4 psi, OA = 78 psi 25% returns to tank throughout with intermittent gas @ 66 bbls pumped. Total of 260 bbls pumped with 100 bbls returned. FCP = 169 psi, Tbg = 239 psi & OA = 452 psi. SI in the IA and bullhead 120 bbls down the tubing to the formation at 3 BPM, ICP 241 psi peaking at 417 psi with 50 bbls pumped. FCP = 248 psi, IA = 178 psi & OA = 446 psi. SD and SI to monitor the pressure and the tubing & IA went on a vac, the OA pressure @ 253 psi. Install the 2-1/2" BPV. LRS freeze protected lines and RD. Blow and RD circulating lines. Empty the kill tank and send remaining NaCl on truck to yard for standby. Mobilize stack, cellar hut, rig floor and pushers shack from A pad. N/D the dry holetree. Install the plug off tool into the BPV. Check the tubing hanger lift thread - good. Spot the crane. Set the BOP stack onto the wellhead and secure. Fly the well house into position over well. Fly the rig floor on top of the well house and secure. Layout the koomey lines and RU. NU the BOP stack. Mobilize the rig from A-pad tent. Spot and level the rig. 10/5/2021 - Tuesday Continue RU all hydraulic lines and pump lines. Spot pump and connect pit system. Torque BOP stack. Pin derrick. Set up rig floor. Spot catwalk and containment. Insulate and winterize rig footprint, Fill pits with 60 bbls fresh water for BOP test. Fill pits with 180 bbls 9.0 ppg NaCl Brine KWF. Position heaters and insulate cellar. Begin warming BOP stack and all lines. Spot pipe racks, Continue warming BOP stack, lines and cellar. Hunt for cold spots and mitigated. R/U BOPE testing equipment. PU and MU the 2-7/8" test joint. Flood the choke manifold & BOP stack with fresh water and purge the air. Shell test the BOPE to 250/2,500 psi (good test). Test BOP equipment as per Sundry and AOGCC requirement. Pipe rams (2-7/8” x 5” VBR’s) with 2- 7/8” and 3-1/2”” test joints, annular with 2-7/8” test joint. All tests performed with fresh water against test plug to 250 psi low and 2500 psi high, held for 5 min and charted. AOGCC rep Brian Bixby waived witness on 10/04/21 at 15:43 hours. Tests: 1. Annular with 2-7/8” test joint, IBOP, C8, C9 & C10 (passed), 2. 2-7/8”x5” VBR with 2-7/8” test joint, C1 & K1 (passed), 3. 2- 7/8”x5” VBR with 3-1/2” test joint, 2-7/8” FOSV, HCR Choke, K2 (passed), 4. C5, C6 & K3 (passed), 5. C4, C7 & C11 (passed), 6. C13, C14 & C15 (passed), 7. Blind Rams, C12 & C16 (passed), 8a. Manual adjustable choke (passed), 8b. Hydraulic super choke (passed),Accumulator Test: System pressure = 3150 psi, Pressure after closure = 1750 psi, 200 psi attained in 15 seconds, Full pressure attained in 63 seconds, Nitrogen Bottles - 4 at 2212 psi. Gas Alarms Tested. Rig down and blow down test equipment & lines. SimOps: Well Support take fluid shot on IA = 2000', Rig up T-bar and pull test dart from BPV. Close Blind rams and bullhead 15 bbls, 9.0 ppg Nacl brine down tubing, 2 BPM, 20 psi. Blow down lines. Check pressures. IA on slight Vac, Tbg give a little air then go on Vac. OA = 10 psi. Pull BPV. SimOps: Dress elevators and tongs for 2-7/8",Make up landing joint with FOSV and XO. Engage hanger, 9-1/2 turns. BOLDS and unseat hanger. Unseat with 55k, Free travel @ 52k,Lay down landing joint and hanger. Make up XO to FOSV. Dress Elevators and Tongs for 3-1/2". Well Name Rig API Number Well Permit Number Start Date End Date MP L-47 ASR 50-029-23550-00-00 215-117 8/25/2021 10/11/2021 Hilcorp Alaska, LLC Weekly Operations Summary Finish dressing 3-1/2" handling equipment. Clean and clear rig floor. Begin L/D 3 1/2" 9.3# Kill String. L/D 90 jts and conduct well control drill. Stab TIW and simulate shutting annular. Good response from crew. Fill backside with 6 bbl 9 ppg brine per hour while tripping. Resume operations after well control drill and find rig only performing @ 50% speed. Investigate and troubleshoot rig, power pack and hydraulics. Shut down and re-set hydraulics. Resume normal operations with full pulling speeds. Cont L/D 3-1/2" 9.3# kill string from jt 95. Fill backside with 6 bbl 9 ppg brine per hour. Cont L/D 3-1/2" 9.3# kill string from jt 190. Fill backside with 6 bbl 9 ppg brine per hour. OOH with last jt 236. Bbls pumped on trip OOH = 51. Clean and clear rig floor. Offload remaining kill string. Load and tally 3-1/2" IF work string. P/U 7-5/8" x 3-1/2" Yellow Jacket ASI-X Production packer. Inspect and function test on floor. Single in hole with test packer on 3-1/2", 9.5# IF work string to 5467'. Drift pipe while picking up w/ 1.75". Install Kelly hose and Kelly up to string. Line up and fill IA with 60 bbls, 9.0 ppg brine, until seeing slight fluid returns from pipe (some diesel in initial returns). Initial OA at 10 psi, record 120 psi after fill IA. Set YellowJacket 7- 5/8" Packer, with element at 5460'. Fill IA to top of annular with 10 bbls. Shut annular and pressure up IA to 1000 psi. OA holding 120 psi. Increase pressure to 2000 psi, OA at 122 psi. Bleed down and perform 2x more tests t/ 1000 psi, at 5500' & 5540' with same results. Test again at 5580' where communication with OA is observed, pressure increase to 1000 psi, equalized with IA. Bleed down pressures, blow down lines. Remove Kelly hose and clear & clean rig floor. POOH from 5587' to 4004', laying down work string to catwalk. 10/7/2021 - Thursday POOH from 4004' to surface laying down work string to catwalk. Fill backside with 6 bbls/hr with 9 ppg NaCl brine. L/D 7-5/8" test packer. Clean and clear rig floor. Load Baker Premier Packer assembly and verify lengths and OD's on catwalk. M/U Baker Premier Packer assembly with 3-1/2" 9.3# L-80 mule shoe tail pipe. M/U and RIH through BOP stack and well head without issue. RIH f/surface to 7435.51' where assembly no-go out. Set down 10k wt. Observe 4k wt "bobble" at 7415'. 66k PU / 22k SO. Install Kelly hose and Kelly up to string. P/U 35', put 1/4 turn in string and slack off setting 10k dn at same depth. Repeat 3x for 1 full turn in string, each time tagging up at same depth. Verify depths and tally. Install 3' XO's for working room at floor. Slack off to No-Go w/ 10k down at 7435.51'. P/U to neutral wt, line up and circulate 25 bbls to ensure clear flow path. 2 BPM, 120 psi. Drop 29/32" phenolic ball and pump down 45 bbls at 2 BPM, 120 psi. Slow rate to 1 BPM and ball on seat at 48 bbls pumped. Pressure up to 2200 psi setting packer. Hold 3 min. Pull 10k over and S/O set 10k down. Pull up 5k over, line up and test 7-5/8" x 9-5/8" envelope & Packer Top to 1000 psi for 30 min. Good test. Bleed off and line up on work string. Top LSS = 7370.70', No-Go Locator = 7387.02', Packer element = 7391.02', Mule Shoe = 7435.51'. Pressure up to 3150 psi to release from packer. Pull 5k over and see string travel. Pressure up to 3800 psi to shear ball seat - did not shear. Rig up FOSV and hard line, pressure to 2000 psi and observe leaking connection. Kelly back up and pressure to 4000 psi then swap to test pump and continue to 4850 psi, rupturing burst disk. Lay down 2 jts and wait on CDR to complete cement job on MPU L-50. Call Wells Support out for fluid shots to monitor Well. Starting fluid shot level @ 290'. Subsequent shots = holding at 350'. Perform monthly safety inspection on equipment. Clean Rig and Doghouse. Remove 3-1/2" work string catwalk and start rack & tally 3- 1/2" EUE for upcoming Patch Assembly. Top off pits with 9.0 ppg brine. 10/6/2021 - Wednesday Well Name Rig API Number Well Permit Number Start Date End Date MP L-47 ASR 50-029-23550-00-00 215-117 8/25/2021 10/11/2021 Hilcorp Alaska, LLC Weekly Operations Summary 10/9/2021 - Saturday Continue RIH picking up 3-1/2" EUE 9.3# L-80 tubing as patch assembly t/ 1775'. Drift t/ 2.85". Make up XN nipple w/ RHC-M installed, 3x jts 3-1/2" tubing and HES Packer and Ratch-Latch Seal assembly for upper patch t/ 1915'. 12k PU / 12k SO. RIH with patch assembly, picking up 3-1/2" EUE 9.3# L-80 tubing t/ 7346'. Drift t/ 2.85". 51k PU / 22k SO. Space out and RIH t/7378' where No-Go out with 4k dn. Observed wt indication of all three bullet seals entering the LSS prior to No-Go. P/U to neutral weight, continue picking up until weight back (51k). Picked up approximately 1’. Rig up and line up to pressure test IA with rig pump to 1000 psi. Test IA, Lower Packer and Tie-Back Seal Assembly to 1000 psi for 30 charted min. Good test. Drop 1- 3/8" ball & rod. Install XO's and FOSV on string. Rig up on tubing and set HES PHL packer with 3600 psi, holding for 5 min. Packer set @ 5477.26'. Bleed pressure down and rig up LRS on the OA. PT lines, and bleed OA pressure down to O psi. Pressure test 9-5/8"x7-5/8" OA & Patch 7-5/8"x3.5" IA with diesel to 1000 psi for 30 charted min. Good test. 1.7 bbls pumped, 1.7 bbls bled off. Rig down, blow down. Line up rig pump to IA and test Upper Packer to 2000 psi for 30 charted min. OA start with 0 psi and climb to 280 psi where it stabilized and held throughout test. Good test. 3 bbls pumped, 3 bbls bled back. Rig down and blow down lines. Rig up HES slickline and pull ball & rod. Attempt to run in and pull RHC plug, taking wt at 1900'. Pull out of hole and install 5' wt bar. Run in and take wt at same depth and again at 3850', able to work past and continue in hole retrieving RHC. Observe 2.5" piece of banding material wedged in RHC retrieving tool and 1"x3/4"x1/2" piece of rubber in plug. Rig down HES slickline equipment. Kelly up to string, rotate off Ratch Latch with 15 RH turns, L/D FOSV and pup jt. Top of RCH LCH receptacle @ 5471.53'. POOH laying down 3-1/2" tubing to catwalk f/ 5471' t/ 1440’. Fill backside every 15 jts with calculated displacement. 10/8/2021 - Friday Standby for coiled tubing cement job pumping on supporting injector L-50. Continue rig maintenance and housekeeping. Rack & tally 3-1/2" EUE for upcoming patch assembly. Continue to take fluid shots of well. Consistent fluid level ~ 600' while coiled tubing pumping on L-50. Spot and line up to pump 200bbls of 9 ppg brine w/Concor 303 corrosion inhibitor. Begin pumping down OA and taking returns up IA. Initial returns to flow back tank until cleaned up. 2 bpm and 500 psi ICP. Pump total of 110 bbls with 37 total bbls returned. 500 psi FCP. OAP = 0. Line up to pump 9 ppg brine down IA. Bullhead 95 bbls 9 ppg brine @ 3bpm and 400 psi. Shut down and line up to pump inhibited brine down OA and take returns from IA. Rig up on OA and pump 90 bbls 9.0 ppg CI Brine taking returns to pits. 2 BPM, 600 psi. Rig up LRS to OA. PT lines to 1500 psi. Pre-Heat diesel FP to 40°. Pump 70 bbls diesel FP 2 BPM, down OA taking returns up IA to pits. ICP = 390 psi, FCP = 605 psi. Shut in OA pressure = 140 psi. Rig down & blow down all lines. Clean and clear floor in prep for POOH. POOH laying down 3-1/2" work string f/ 7398' to surface. Fill hole with calculate pipe displacement every 15 jts. L/D Baker liner running tool. P/U Baker Bullet Seal Assembly with No-Go locator, XO and 3-1/2" pup jt t/ 21'. RIH picking up 3-1/2" EUE 9.3# L-80 tubing as Patch assembly t/ 1275'. Drift t/ 2.85". Well Name Rig API Number Well Permit Number Start Date End Date MP L-47 ASR 50-029-23550-00-00 215-117 8/25/2021 10/11/2021 Hilcorp Alaska, LLC Weekly Operations Summary Terminate ESP cable to Hanger. Take final readings, M/U ESP umbilical cord. Land 2-7/8" tubing on Hanger at 5450'. RILDS& L/D landing joint. Total of 177 joints tubing, 101 cannon clamps, 3 protectolizer clamps, 2 flat clamps and 6 pump clamps ran. 17.5k SOW on hanger. Set BPV. Continue with ASR rig down. Offload pits and send ~ 170 bbls 9# NaCl brine to MI for storage. R/D pipe skate and containment. R/D Rig floor and pump. Lay derrick over and move rig off location. N/D BOPE. R/D and store all hoses and fluids connection. ,N/U 2-9/16" ESP Tree. Pressure test tubing hanger void to 500/5000 psi. Good test. Pressure test new production tree to 500/5000 psi. Good test. Pull BPV. Release rig and continue RDMO. 10/10/2021 - Sunday POOH laying down 3-1/2" tubing f/ 1440’ t/surface. Fill backside every 15 jts with calculated displacement. Clean and clear rig floor. Load jewelry and tubing. Spot spooler. R/U and hang sheave. Spot and load Baker Centrilift handling equipment. M/U Baker Hughes. Centrilift 150 HP 268 Stage Flex ER ESP Motor. Load and tally new 2-7/8" 6.5#, L-80 tubing. Continue M/U Baker Hughes Centrilift 150 HP 268 Stage Flex ER ESP Motor. Load and tally new 2-7/8" 6.5#, L-80 tubing,Test ESP cable. OHM and MEG tests good. Test 1/4" cap string to 5000 psi. Good. M/U Discharge head and handling pup joint. RIH with 2-7/8" 6.5# L-80 ESP completion per program and Baker Centrilift f/ 94' t/ 897'. Torque connections to 2100 ft/lbs. Install Cannon clamps on 1st 10 joints then every other joint. Test ESP cable at 897' – Discharge pressure reading 0 psi. Suspect air in jumper line. All other readings good. Continue run 2-7/8" 6.5# L-80 ESP completion tubing as per tally f/ 897' t/ 5429’. Tq to 2100 ft/lbs. Test ESP cable every 1000', - good. See good reading on discharge pressure starting with second test @ 2000’. Maintain 4600 psi on cap line while RIH. Install CC Cannon clamps on every other joint. Additional Cannon clamp both sides of each GLM & at Top of jt #91 (ESP cable splice) & mid jt #97 (below cap string splice). M/U 2 7/8"x 11" tubing hanger and landing joint. SimOps: Test ESP cable. OHM and MEG tests good. Terminate ESP cable to Hanger. Take final readings, M/U ESP umbilical cord. Land 2-7/8" tubing on Hanger at 5450'. RILDS& L/D landing joint. Total of 177 joints tubing, 100 cannon clamps, 3 protectolizer clamps, 2 flat clamps and 6 pump clamps ran. 17.5 k SOW on hanger. 10/11/2021 - Monday _____________________________________________________________________________________ Revised By: DH 10/28/2021 SCHEMATIC Milne Point Unit Well: MPU L-47 Last Completed: 10/11/2021 PTD: 215-117 TD =12,995’ (MD) / TD =4,158’(TVD) 13-3/8” Orig. KB Elev.: 50’/ GL Elev.: 17’ 7-5/8” 3 7 8 18 9 10 11 19 9-5/8” 1 2 20 21 22 Min ID 2.205” @ 5,313’ PBTD =12,993’ (MD) / PBTD =4,158’(TVD) 6 9-5/8” ‘ES’ Cementer @ 2,535’ 23 5 4 5-1/2” IAxOA Leak 12 13 14 15 16 17 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 13-3/8" Conductor 68 / A-53 / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TC II 8.835 Surface 7,664’ 0.0759 7-5/8" Production 29.7 / L-80 / Vam SLIJ-II 6.875 Surface 7,402’ 0.0459 5-1/2” Liner 17 / P-110 / DWC/C HT 4.892 7,399’ 12,995 0.0233 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE 8rd 2.441 Surf 5,450’ 0.0058 3-1/2” Liner 9.3# / L-80 / EUE 2.992 5,472 7,380' 0.0087 JEWELRY DETAIL No Depth Item 1123’STA #2:2-7/8” GLM w/0.4375” OV 25,224’STA #1: 2-7/8”GLM w/1” Dummy Valve 3 5,313’ XN Nipple, 2.313” Profile,ID=2.205” 4 5,365’ Discharge Head, B/O PMP 400 5,367’ Pump #2, 400PMSXD 134 FLEXER H6 FER 5 5,390’ Pump #1, 400PMSXD 134 FLEXER H6 FER 6 5,414’ Gas Separator, 538GSTHVV MT H6 FER STD PNT 7 5,420’ Upper Tandem Seal, GSB3DB H6 SB/AB PFSA 8 5,427’ Lower Tandem Seal, GSB3DB H6 SB/AB PFSA 9 5,434 Motor, 562XP 150/2420/38_1125/2020 06R 10 5,445’ Zenith Motor Gauge 11 5,448’ Centralizer: Bottom@ 5,450’ 12 5,472’ Ratch Latch Receptacle 13 5,477’ 7-5/8” x 3-1/2” PHL Packer 14 5,593’ XN Nipple, 2.813” Packing Bore, ID= 2.75” 15 7,369’ 5” x 3-1/2” Cross-over 16 7,371’ 5.25” Bullet Seal Assembly, Mule Shoe 17 7,436’ 7” Baker Premier Packer 18 7,399’ SLZXP Liner Top Packer w/ BD Slips 19 7,402’ Seal Assembly 10’ Inside LTP 20 7,421’ 5-1/2” H563 X 7'' DWC XO 21 11,068’ Swell Packer: Bottom @ 11,078’ 22 11,328’ Swell Packer: Bottom @ 11,338’ 23 12,993’ WIV (Ball in Seat/ Closed) – Bottom@ 12,995’ OPEN HOLE / CEMENT DETAIL 13-3/8" 350 sx of Arcticset I (Approx) 9-5/8" 541 bbls in 12-1/4” Hole Cement to Surface 5-1/2” Cementless Slotted Liner w/ Swell Packers 8-1/2” hole WELL INCLINATION DETAIL KOP @ 882’ Max Hole Angle = 92.1 deg. @ 12,925’ MD TREE & WELLHEAD Tree 5M Seaboard 2-9/16” Wellhead Seaboard MB-22 5M GENERAL WELL INFO API: 50-029-23550-00-00 Drilled and Cased by Doyon 14 - 2/15/2016 ESP Swap & Patch by ASR #1 – 10/11/2021 5-1/2” SLOTTED LINER DETAIL Top (MD) Btm (MD) 7,474’ 11,063’ 11,341’ 12,948’ Liner Slot Dimensions= 2.250” L x .125” W 6.72” Sq/In of Inlet Area per FT of Casing 24 Slots Per Foot of Casing Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/18/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-47 (PTD 215-117) Temperature Survey 09/07/2021 Please include current contact information if different from above. 37' (6HW Received By: 10/19/2021 By Abby Bell at 11:04 am, Oct 19, 2021 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Install Patch & ESP 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): 12,995'N/A Casing Collapse Conductor N/A Surface 3,090psi Production 4,790psi Liner 7,100psi 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: Operations Manager Contact Email:dhaakinson@hilcorp.com Contact Phone: 777-8343 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 David Haakinson C.O. 477.05 SLZXP LTP, Swell Packer (2) and N/A 7,399 MD/ 4,062 TVD, 11,068 MD/ 4,120 TVD & 11,328 MD/ 4,142 TVD and N/A 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. 12,995'5-1/2" 2-7/8" Perforation Depth MD (ft): See Schematic 4,063' 4,158' 6.5# / L-80 / EUE 8rd 5,607' 7,370' 4,094' Tubing Grade: 7,664' 7,402' See Schematic 80' 13-3/8" 9-5/8" 7-5/8" 7,629' 80' 80' TVD Burst 5,564' MD N/A 7,740psi 5,750psi 6,890psi 215-117 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23550-00-00 Hilcorp Alaska LLC MILNE PT UNIT L-47 4,158'1,136 N/A MILNE POINT / SCHRADER BLUFF OIL PRESENT WELL CONDITION SUMMARY Length Size 4,158'12,993' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 / ADL0025515 COMMISSION USE ONLY Authorized Name: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: Authorized Signature: 8/23/2021 ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:38 am, Aug 16, 2021 321-400 Chad Helgeson (1517) 2021.08.13 15:56:23 - 08'00' BOPE test to 2500 psi. X DLB 08/17/2021 DSR-8/16/21MGR17AUG21 10-404 dts 8/23/2021 JLC 8/23/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.08.23 11:38:04 -08'00' RBDMS HEW 8/24/2021 ESP Changeout| Casing Patc h Well: MPU L-47 Date: 8-13-2021 Well Name:MPU L-47 API Number:50-029-23550-00-00 Current Status:Shut-in [Failed ESP]Pad:L-Pad Estimated Start Date:August 23rd, 2021 Rig:ASR #1 Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:215-117 First Call Engineer:David Haakinson (307) 777-8343 (O) (307) 660-4999 (M) Second Call Engineer:David Gorm (907) 777-8333 (O) (505) 215-2819 (M) AFE Number:Job Type:ESP Changeout Current Bottom Hole Pressure:1,463 psi @ 3,275’ TVD SBHP 5/28/21 |8.59 ppg Maximum Expected BHP:1,463 psi @ 3,275’ TVD 6-month Shut-In |8.59 ppg MPSP:1,136 psi Gas Column Gradient (0.1 psi/ft) Max Inclination 66.3° @ 3,145’ MD Max Dogleg:7.3°/100ft @ 1,827’ MD BPV Profile:2-1/2” CIW Type H Brief Well Summary: MPU L-47 was drilled and completed in February 2016 as a horizontal Schrader Bluff OA producer. The ESP failed in February 2021 due to electrical grounding. Prior to the ESP failure, an IAxOA leak developed in September 2019. Subsequent leak detect temperature surveys indicate the leak is below the ESP. Notes Regarding Wellbore Condition x The 7-5/8” x 9-5/8” casing annulus production has a known leak. AOGCC approval dated 9/25/19 allowed production of well until the next ESP failure. Due to ESP failure, it now requires repair of IAxOA leak. x Analog producer L-46 has a known corrosion problem, assumption is under-deposit corrosion on lower side of completion x Offset injectors with status as of 8/6/2021.Wells will be shut in prior to RWO. o L-48: Shut in; previously injecting 1,600 bwpd. o L-50: Shut in; previously injecting 400 bwpd. Objective: x Pull 2-7/8” tubing string and Baker Hughes ESP x Install 3-1/2” x 7-5/8” Casing Patch x Install new Baker Hughes ESP with new 2-7/8” Tubing Pre-Rig Procedure: 1. RU LRS. 2. Kill the well with heated 9.0 ppg KCL Brine. a. Bleed off the tubing and IA gas. Bleed to 0 psi if possible. 3. Pump 260 bbls of 9.0ppg KCL Brine down the tubing while leaving IA open to tank. a. Allow circulation out IA if any at all. Continue to circulate and increase volume if gas continues to circulate out. b. If pumping is not achieving 1:1 returns and there is not gas in returns, swap to bull-heading after at a least a minimum 60 bbls is pumped. ESP Changeout| Casing Patc h Well: MPU L-47 Date: 8-13-2021 c. DNE 1,000 psi. Achieve max rate. 4. Pump up to 328 bbls of 9.0 ppg KCL Brine down IA to formation. If 1:1 returns were achieved throughout the tubing circulation, reduce IA kill volume to 95 bbls. a. Ensure Tubing is closed. b. DNE 800 psi on IA. Limit rate to <2 BPM. 5. Confirm well is dead. 6. RD LRS. 7. Clear and level pad area in front of well. Spot rig mats and containment. 8. RD well house and flowlines. Clear and level area around well. 9. RU crane. Set 2-1/2” ‘H’ BPV. ND Tree. Inspect the lift threads on the tubing hanger. 10. NU BOPE. RD Crane. RWO Procedure: 11. MIRU Hilcorp ASR #1 Rig and ancillary equipment. 12. Check for pressure and if 0 psi, pull BPV. 13. Set TWC. 14. Test BOPE to 250/2,500 psi, annular to 250/2,500 psi. 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 2-7/8” and 3-1/2” test joints. d. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. Contingency: If BOPE test fails a. Notify Operations Engineer (Hilcorp), Mr. Mel Rixse (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.) 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. 15. RU to pull 2-7/8” ESP completion. Rig up spooler for ESP #2 RD cable. a. Baker Hughes representative should be onsite for the ESP pull. 16. Pull the TWC. Kill the well with 9.0 ppg KCL Brine as needed. ESP Changeout| Casing Patc h Well: MPU L-47 Date: 8-13-2021 17. MU landing joint. BOLDS, unseat the tubing hanger and pull to the rig floor. a. SO = 70K and PU = 89K when landed in 9.1 ppg brine by Doyon 14 (block weight = 40K) in 2016. 18. Lay down the landing joint and tubing hanger. RU to pull ESP cable over the sheaves to the spooling unit. a. Inspect the tubing hanger and note any damage. If any damage is found, contact well head specialist for redress or replacement. 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. 19. POOH and lay down the 2-7/8” tubing. Lay down ESP and motor. a. Tubing to be junked due to results from caliper survey indicating tubing wall loss. b. Note any corrosion, sand or scale on the tubing with associated depths and ESP components on the morning report. c. Look for over-torqued connections from previous tubing runs. d. If any joint(s) appear suspect of damage to threads or tubing, send to G&I for disposal and replace with new. Equipment Disposition Tubing hanger Visually inspect on site and hold in inventory Tubing & Pup joints Send to G&I for disposal Tubing Jewelry Send to G&I for disposal ESP equipment/Power Cable Baker Hughes to take possession Flat Cannon Pump Clamps (4)Visually inspect on site and reuse if in good condition Flat guards (2)Visually inspect on site and reuse if in good condition Protectolizers (3)Visually inspect on site and reuse if in good condition Cannon clamps (92)Visually inspect on site and reuse if in good condition 20. MU 7” and 7-5/8” casing scraper BHA and TIH w/ 3-1/2” workstring to ±7,402’ MD. a. Make sure base of 7” scraper is 12’ below base of 7-5/8” casing scraper. b. Very slowly ease down to no- go 7-5/8” scraper on 7-5/8” x 7” crossover. Do not rotate on crossover. Pick-up 2’ after tag and rotate to clean out 7” SBA. c. Slowly rotate and reciprocate in and out of the tie-back assembly. d. Circulate Wellbore clean e. The 7-5/8” scraper should no-go on top of the tie-back assembly (10.12’ in Length). 21. POOH and reciprocate the 7-5/8” scraper across the following intervals. a. 6,550’ MD to 6,450’ MD b. 5,550’ MD to 5,500’ MD 22. POOH and LD scraper BHA. 23. PU 7-5/8” test packer and RIH on work string to ±7,392’ MD. ESP Changeout| Casing Patc h Well: MPU L-47 Date: 8-13-2021 a. Test Packer should no-go on the top of the tie-back assembly. 24. PU 2’ from no-go and set the test packer. Pressure Test the combo 7-5/8”x 9-5/8” casing envelope (OA casing test) to 1,000 psig for 30 minutes. a. Chart results. b. Contingency: If pressure test fails, contact engineering to discuss and diagnose possible seal bore assembly leak. 25. Pull up-hole as necessary to locate 7-5/8” casing leak to ±5,550’ MD. 26. Once a passing pressure test to 1,000 psig is achieved, test casing to 2,000 psig for 30 minutes. a.Contact engineering with the depth of a passing 2,000 psi test. This depth may change the location of the upper patch packer and final ESP set depth. 27. Complete a final 7-5/8” casing test to 2,000 psi for 30 minutes at ±5,550’ MD. 28. POOH and lay down the test packer BHA. 29. Call out Baker Hughes to set the lower patch packer. 30. PU 7” Baker Premier Packer assembly with tieback assembly and Baker Hughes setting tools. 31. RIH and no-go the assembly on the 7” liner tie-back assembly at ±7,392’ MD. 32. Set Bottom Patch Packer per Baker Hughes packer setting instructions. 33. Pressure test the 7-5/8” x 9-5/8” casing envelop to 1,000 psig for 30 minutes prior to shearing off packer. a. This test is necessary to confirm proper setting of lower 7” Packer. 34. POOH and lay-down packer setting tool and 3-1/2” workstring. 35. Pick up 3-1/2” EUE Tubing for work-string. 36. Call out Halliburton for upper patch packer setting. 37. PU patch assembly with the following equipment: a. Baker Hughes Tie-back bullet seals (10’) b. 5” TXP to 3.5” EUE crossover c. 3.5” EUE tubing d. 2.813” X-Lock Profile at ±5,600’ MD i. Load with RHC plug if shear out device is unavailable. e. 3.5” EUE Tubing f. Halliburton 7-5/8” x 3-1/2” EUE PHL Packer g. Halliburton Ratch-Latch Seal Assembly h. 3.5” EUE tubing to surface (for full-bore workstring). 38. Note PU weight of the patch assembly on the Patch Tally. Please take photos and document all parts of the patch assembly,place photos in well file. 39. RIH and tag the Baker tie-back bullet seals just above the lower 7” packer seal bore receptacle. 40. Call out Well Support Techs to shoot fluid level in 9-5/8” OA. Fill OA with diesel prior to circulating patch corrosion inhibited fluid and setting patch. 41. Circulate in 120 bbls of 9.0 ppg KCL brine with 1% CRW corrosion inhibited fluid down the work-string taking returns up the 7-5/8” casing to spot corrosion inhibited fluid in the IA between patch elements. 42. Land Bullet seals in the lower 7” Baker Packer Seal Bore Receptacle. ESP Changeout| Casing Patc h Well: MPU L-47 Date: 8-13-2021 43. Pressure test the IAxOA (backside of 3.5” tubing workstring) to 1,000 psig for 30 minutes to ensure integrity of lower packer and tie-back assembly. 44. After passing pressure test is achieved, perform hydraulic setting of the upper 7-5/8” Halliburton PHL packer per the on-site Halliburton tool representative. 45.If a ball and rod is dropped to set the packer, call out Halliburton slickline to pull the ball and rod and RHC Plug prior to un-latching from the upper packer. 46. The 7-5/8” Halliburton PHL packer should be set at ±5,525’ MD. 47. After the upper packer is set, pressure test the 9-5/8” casing (OA) to 1,000 psig for 30 minutes. a. Chart Test 48. Pressure Test IA (backside of 3-1/2” tubing work string) to 2,000 psig for 30 minutes. a. Chart Test 49. Rotate off ratch-latch upper 7-5/8” Halliburton PHL Packer. 50. POOH and lay down 3-1/2” EUE tubing work string. a. Send 3-1/2” tubing to S-pad to be used in S-48’s injection completion. 51. PU new Baker Hughes ESP and and RIH on new 2-7/8” 6.5# L-80 tubing. Set the base of the ESP assembly at ±35’ above the 7-5/8” PHL packer. a. Note: If severe corrosion is seen on the pulled ESP completion, prepare to run a 3/8” capillary tubing string for corrosion inhibition. b. Base of ESP centralizer at ±5,490’ MD. c. Motor Gauge d. 150 HP motor e. 268 Stage Flex ER ESP f. Downhole Gauge for discharge temperature and pressure i. Connected with a jumper from the lower sensor. Does not require a separate tech- wire. g. 1 joint of 2-7/8” tubing h. 2-7/8” XN (2.205” No-go) Nipple i. 2 joints of 2-7/8” tubing j. Lower 2-7/8” x 1” Side pocket GLM with dummy GLV k. 2-7/8” tubing l. Upper 2-7/8” x 1” Side pocket GLM loaded with 7/16” OV. 52. Land tubing hanger. RILDS. a. Note Slack-off weight on Tally. b. Avoid PU (if possible) to prevent stretch on ESP cable/clamps. 53. Lay Down Landing Joint. 54. Set BPV. 55. ND BOPE. 56. NU 2-9/16” ESP Tree. 57. Pull BPV. Set TWC. The OA will be closed with a pressure gauge in line to monitor. Pressure bled down on OA. The MIT-IA will then be completed to 2,000 psig with the OA blocked in with an initial pressure of 0 psig being recorded for pressure build. ESP Changeout| Casing Patc h Well: MPU L-47 Date: 8-13-2021 58. Pressure test the tubing hanger void to 500 psig low and 5,000 psi high. 59. Pressure test the tree to 500 psig Low and 5,000 psig High. 60. Pull TWC. 61. RD ASR #1 and all ancillary equipment. 62. Turn well over to production with the handover form. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOPE Diagram _____________________________________________________________________________________ Revised By: NLW 07-29-21 SCHEMATIC Milne Point Unit Well: MPU L-47 Last Completed: 2/13/2016 PTD: 215-117 TD =12,995’ (MD) / TD =4,158’(TVD) 13-3/8” Orig. KB Elev.: 50’/ GL Elev.: 17’ 7-5/8” 3 7 8 9 10 11 13 9-5/8” 1 2 14 15 16 Min ID 2.205” @ 5,498’ PBTD =12,993’ (MD) / PBTD =4,158’(TVD) 6 9-5/8” ‘ES’ Cementer @ 2,535’ 5 4 5-1/2” 12 IAxOA Leak. Estimated below ESP. AOGCC approval to produce to Oct. 2023 or ESP failure CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 13-3/8" Conductor 68 / A-53 / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TC II 8.835 Surface 7,664’ 0.0759 7-5/8" Production 29.7 / L-80 / Vam SLIJ-II 6.875 Surface 7,402’ 0.0459 5-1/2” Liner 17 / P-110 / DWC/C HT 4.892 7,399’ 12,995 0.0233 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE 8rd 2.347 Surf 5,564’ 0.00579 JEWELRY DETAIL No Depth Item 1139’STA #2:GLM w/ Dummy 7-29-21 –ID=2.25” 25,354’STA #1:GLM w/ Empty pocket 7-29-21 –ID=2.25” 3 5,498’ XN Nipple –ID=2.205” 4 5,509’ Discharge Head: FPHVDIS 5 5,510’ Pump: SXD - 134FLEX17.5 6 5,533’ Gas Separator: GRSFTXAR H6 7 5,538’ Upper Tandem Seal: GSB3DB SB/SB PFSA 8 5,545’ Lower Tandem Seal: GSB3DB SB/SB PFSA 9 5,552’ Motor: CL5 - MSP3-250ȗ 84Hp/ 2,210V/ 23A 10 5,560’ Sensor: WellLift E 11 5,562’ Centralizer:Bottom@ 5,564’ 12 7,399’ SLZXP Liner Top Packer w/ BD Slips 13 7,402’ Seal Assembly 10’ Inside LTP 14 7,421’ 5.5” H563X 7'' DWC XO 15 11,068’ Swell Packer: Bottom @ 11,078’ 16 11,328’ Swell Packer: Bottom @ 11,338’ 17 12,993’ WIV (Ball in Seat/ Closed) –Bottom@ 12,995’ OPEN HOLE / CEMENT DETAIL 13-3/8" 350 sx of Arcticset I (Approx) 9-5/8" 541 bbls in 12-1/4” Hole Cement to Surface 5-1/2” Cementless Slotted Liner w/ Swell Packers 8-1/2” hole WELL INCLINATION DETAIL KOP @ 882’ Max Hole Angle = 92.1 deg. @ 12,925’ MD TREE & WELLHEAD Tree 5M Seaboard 2-9/16” Wellhead Seaboard MB-22 5M GENERAL WELL INFO API: 50-029-23550-00-00 Drilled and Cased by Doyon 14 - 2/15/2016 AOGCC approval to produce 4-year limit to Oct 2023 or ESP failure (9/25/19) 5-1/2” SLOTTED LINER DETAIL Top (MD) Btm (MD) 7,474’ 11,063’ 11,341’ 12,948’ Liner Slot Dimensions= 2.250” L x .125” W 6.72” Sq/In of Inlet Area per FT of Casing 24 Slots Per Foot of Casing _____________________________________________________________________________________ Revised By: TDF 8/13/2021 PROPOSED Milne Point Unit Well: MPU L-47 Last Completed: 2/13/2016 PTD: 215-117 TD =12,995’ (MD) / TD =4,158’(TVD) 13-3/8” Orig. KB Elev.: 50’/ GL Elev.: 17’ 7-5/8” 3 7 8 9 10 11 18 & 19 9-5/8 ” 1 2 20 21 22 Min ID 2.205” @ 5,500’ PBTD =12,993’ (MD) / PBTD =4,158’(TVD) 6 9-5/8” ‘ES’ Cementer @ 2,535’ 5 4 5-1/2” AxOA Leak. 12 13 14 15 16 17 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 13-3/8" Conductor 68 / A-53 / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TC II 8.835 Surface 7,664’ 0.0759 7-5/8" Production 29.7 / L-80 / Vam SLIJ-II 6.875 Surface 7,402’ 0.0459 5-1/2” Liner 17 / P-110 / DWC/C HT 4.892 7,399’ 12,995 0.0233 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE 8rd 2.347 Surf 5,564’ 0.00579 3-1/2” Liner 12.6# / L-80 / H521 3.958 ~5,600 ~7,400' JEWELRY DETAIL No Depth Item 1 ±110’STA #2:GLM 2 ±5,490’STA #1:GLM 3 ±5,500’ XN Nipple – ID=2.205” 4 ±5,508’ Discharge Head: 5 ±5,510’ Pump: 6 ±5,526’ Gas Separator: 7 ±5,530’ Upper Tandem Seal: 8 ±5,550’ Lower Tandem Seal: 9 ±5,570’ Motor: 10 ±5,393’ Sensor: 11 ±5,398’ Centralizer: Bottom@ ±5,490’ 12 ±5,525’ Ratch Latch Receptacle 13 ±5,530’ 7-5/8” x 3-1/2” PHL 14 ±5,600 X Nipple – ID= 2.813” 15 ±7,382’ 5” x 3-1/2” Cross-over 16 ±7,384’ Seal Assembly 17 ±7,392’ 7” Baker Premier – Btm @ ±7,400’ 18 7,399’ SLZXP Liner Top Packer w/ BD Slips 19 7,402’ Seal Assembly 10’ Inside LTP 20 7,421’ 5.5” H563X 7'' DWC XO 21 11,068’ Swell Packer: Bottom @ 11,078’ 22 11,328’ Swell Packer: Bottom @ 11,338’ 23 12,993’ WIV (Ball in Seat/ Closed) –Bottom@ 12,995’ OPEN HOLE / CEMENT DETAIL 13-3/8" 350 sx of Arcticset I (Approx) 9-5/8" 541 bbls in 12-1/4” Hole Cement to Surface 5-1/2” Cementless Slotted Liner w/ Swell Packers 8-1/2” hole WELL INCLINATION DETAIL KOP @ 882’ Max Hole Angle = 92.1 deg. @ 12,925’ MD TREE & WELLHEAD Tree 5M Seaboard 2-9/16” Wellhead Seaboard MB-22 5M GENERAL WELL INFO API: 50-029-23550-00-00 Drilled and Cased by Doyon 14 - 2/15/2016 5-1/2” SLOTTED LINER DETAIL Top (MD) Btm (MD) 7,474’ 11,063’ 11,341’ 12,948’ Liner Slot Dimensions= 2.250” L x .125” W 6.72” Sq/In of Inlet Area per FT of Casing 24 Slots Per Foot of Casing 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 1 Winston, Hugh E (CED) From:Carlisle, Samantha J (CED) Sent:Friday, August 13, 2021 11:21 AM To:Winston, Hugh E (CED) Subject:FW: MP L-47, PTD: 215-117 & Sundry # 321-389 Withdrawal Request From: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Sent: Friday, August 13, 2021 11:19 AM To: Tom Fouts <tfouts@hilcorp.com> Cc: Carlisle, Samantha J (CED) <samantha.carlisle@alaska.gov>; Guhl, Meredith D (CED) <meredith.guhl@alaska.gov> Subject: RE: MP L‐47, PTD: 215‐117 & Sundry # 321‐389 Withdrawal Request Tom, Got your notice. I will look for your replacement sundry. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907‐793‐1231 Office 907‐223‐3605 Cell CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907‐793‐1231 ) or (Melvin.Rixse@alaska.gov). cc. Samantha Carlisle, Meredith Guhl From: Tom Fouts <tfouts@hilcorp.com> Sent: Friday, August 13, 2021 11:10 AM To: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Cc: David Haakinson <dhaakinson@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com> Subject: MP L‐47, PTD: 215‐117 & Sundry # 321‐389 Withdrawal Request Mel, I would like to request the withdraw of the 10‐403 submittal for MP L‐47 at this time. We will be submitting another 10‐403 for MP L‐47 that includes additional changes not included in the original submittal. . Please feel free to contact me if you have any questions. Regards, Tom Fouts | Senior Ops/ Reg Tech Hilcorp Alaska, LLC tfouts@hilcorp.com Direct: (907) 777‐8398 Mobile: (907) 351‐5749 RBDMS HEW 8/13/2021 David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt and return one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 08/09/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL MPU L-47 (PTD 215-117) FTP Folder Contents: Log Print Files and LAS Data Files: Please include current contact information if different from above. 37' (6HW Received By: 08/10/2021 By Abby Bell at 3:21 pm, Aug 09, 2021 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Install Kill String 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 12,995'N/A Casing Collapse Conductor N/A Surface 3,090psi Production 4,790psi Liner 7,100psi 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: Operations Manager Contact Email:dhaakinson@hilcorp.com Contact Phone: 777-8343 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 C.O. 477.05 SLZXP LTP, Swell Packer (2) and N/A 7,399 MD/ 4,062 TVD, 11,068 MD/ 4,120 TVD & 11,328 MD/ 4,142 TVD and N/A 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. 12,995'5-1/2"5,607' 7,370' Authorized Signature: 8/20/2021 2-7/8" Perforation Depth MD (ft): See Schematic 4,063' 4,158' 7,664' 7,402' See Schematic 80' 13-3/8" 9-5/8" 7-5/8" 7,629' 6.5# / L-80 / EUE 8rd TVD Burst 5,564' MD N/A 7,740psi 5,750psi 6,890psi 4,094' 4,158' 1,136 N/A MILNE POINT / SCHRADER BLUFF OIL 80' 80' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 / ADL0025515 215-117 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23550-00-00 Hilcorp Alaska LLC MILNE PT UNIT L-47 Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY Length Size 4,158'12,993' David Haakinson COMMISSION USE ONLY Authorized Name: ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 2:02 pm, Aug 06, 2021 321-389 Chad Helgeson (1517) 2021.08.06 13:55:37 - 08'00' DLB 08/06/2021 10-404 BOPE test to 2500 psi. Annular to 2500 psi. X MGR09AUG21 DSR-8/10/21 dts 8/10/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.08.10 16:51:27 -08'00' RBDMS HEW 8/13/2021 ESP Changeout Well: MPU L-47 Date: 8-6-2021 Well Name:MPU L-47 API Number:50-029-23550-00-00 Current Status:Shut-in [Failed ESP]Pad:L-Pad Estimated Start Date:August 20th, 2021 Rig:ASR #1 Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:215-117 First Call Engineer:David Haakinson (307) 777-8343 (O) (307) 660-4999 (M) Second Call Engineer:David Gorm (907) 777-8333 (O) (505) 215-2819 (M) AFE Number:Job Type:ESP Changeout Current Bottom Hole Pressure:1,463 psi @ 3,275’ TVD SBHP 5/28/21 |8.59 ppg Maximum Expected BHP:1,463 psi @ 3,275’ TVD 6-month Shut-In |8.59 ppg MPSP:1,136 psi Gas Column Gradient (0.1 psi/ft) Max Inclination 66.3° @ 3,145’ MD Max Dogleg:7.3°/100ft @ 1,827’ MD BPV Profile:2-1/2” CIW Type H Brief Well Summary: MPU L-47 was drilled and completed in February 2016 as a horizontal Schrader Bluff OA producer. The ESP failed in February 2021 due to electrical grounding. Prior to the ESP failure, an IAxOA leak developed in September 2019. Subsequent leak detect temperature surveys indicate the leak is below the ESP. MPU L-47 well will remain shut in post RWO. The well will require a subsequent RWO and sundry request after diagnostic work is complete. Notes Regarding Wellbore Condition x The 7-5/8” x 9-5/8” casing annulus production has a known leak. AOGCC approval dated 9/25/19 allowed production of well until the next ESP failure. Due to ESP failure, it now requires repair of IAxOA leak. x Analog producer L-46 has a known corrosion problem. Diagnostics are needed on MPU L-47 to determine the location and cause of the IAxOA leak. x Offset injectors with status as of 8/6/2021.Wells will be shut in prior to RWO. o L-48: Online, injecting 1,600 bwpd. o L-50: Online, injecting 400 bwpd. Objective: x Pull 2-7/8” tubing string and Baker Hughes ESP x Install 4-1/2” kill string to set up well for post rig E-line diagnostics Pre-Rig Procedure: 1. RU LRS. 2. Kill the well with heated 9.0 ppg KCL Brine. a. Bleed off the tubing and IA gas. Bleed to 0 psi if possible. 3. Pump 260 bbls of 9.0 KCL Brine down the tubing while leaving IA open to tank. a. Allow circulation out IA if any at all. Continue to circulate and increase volume if gas continues to circulate out. ESP Changeout Well: MPU L-47 Date: 8-6-2021 b. If pumping is not achieving 1:1 returns and there is not gas in returns, swap to bull-heading after at a least a minimum 60 bbls is pumped. c. DNE 1,000 psi. Achieve max rate. 4. Pump up to 328 bbls of 9.0 KCL Brine down IA to formation. If 1:1 returns were achieved throughout the tubing circulation, reduce IA kill volume to 95 bbls. a. Ensure Tubing is closed. b. DNE 800 psi. Limit rate to <2 BPM. 5. Confirm well is dead. 6. RD LRS. 7. Clear and level pad area in front of well. Spot rig mats and containment. 8. RD well house and flowlines. Clear and level area around well. 9. RU crane. Set 2-1/2” ‘H’ BPV. ND Tree. Inspect the lift threads on the tubing hanger. 10. NU BOPE. RD Crane. RWO Procedure: 11. MIRU Hilcorp ASR #1 Rig and ancillary equipment. 12. Check for pressure and if 0 psi, pull BPV. 13. Set TWC. 14. Test BOPE to 250/2,500 psi, annular to 250/2,500 psi. 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 2-7/8” and 4-1/2” test joints. d. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. Contingency: If BOPE test fails a. Notify Operations Engineer (Hilcorp), Mr. Mel Rixse (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.) 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. 15. RU to pull 2-7/8” ESP completion. Rig up spooler for ESP #2 RD cable. a. Baker Hughes representative should be onsite for the ESP pull. ESP Changeout Well: MPU L-47 Date: 8-6-2021 16. Pull the TWC. Kill the well with 9.0 ppg KCL Brine as needed. 17. MU landing joint. BOLDS, unseat the tubing hanger and pull to the rig floor. a. SO = 70K and PU = 89K when landed in 9.1 ppg brine by Doyon 14 (block weight = 40K) in 2016 18. Lay down the landing joint and tubing hanger. RU to pull ESP cable over the sheaves to the spooling unit. a. Inspect the tubing hanger and note any damage. If any damage is found, contact well head specialist for redress or replacement. 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. 19. POOH and lay down the 2-7/8” tubing. Lay down ESP and motor. a. Tubing to be junked due to results from caliper survey indicating tubing wall loss. b. Note any corrosion, sand or scale on the tubing with associated depths and ESP components on the morning report. c. Look for over-torqued connections from previous tubing runs. Equipment Disposition Tubing hanger Visually inspect on site and hold in inventory Tubing & Pup joints Send to G&I for disposal Tubing Jewelry Send to G&I for disposal ESP equipment/Power Cable Baker Hughes to take possession Flat Cannon Pump Clamps (4)Visually inspect on site and reuse if in good condition Flat guards (2)Visually inspect on site and reuse if in good condition Protectolizers (3)Visually inspect on site and reuse if in good condition Cannon clamps (92)Visually inspect on site and reuse if in good condition 20. PU, MU and RIH w/ 4.5” Hydril 521 kill string tubing. Set base of Tubing a. 4-1/2” Tubing Specs: i. 192K Tensile Strength ii. MU Torque (FT-LBS): 3,900 Min / 4,700 Optimum / 6,800 Max 21. Install Completion as outlined below. Set the WLEG at ±2,600’ MD. Send tally to engineer prior to Install. a. 4.5” WLEG b. 4-1/2” 12.6# L-80 Tubing c. 4-1/2” Tubing Hanger 22. PU and MU the 4-/1/2” tubing hanger. 23. Land tubing hanger. RILDS. Lay down landing joint. Record PU and SO weights on the tally and WellEZ. ESP Changeout Well: MPU L-47 Date: 8-6-2021 24. Set 4” BPV. 25. ND BOPE. NU 4-1/16” 5K tree and adaptor flange. a. Contact drill-site operator to inspect directionality of tree and casing valves. 26. Pull BPV. Set TWC. 27. Pressure test the tubing hanger void to 500 psig low and 5,000 psi high. 28. Pressure test the tree to 500 psig Low and 5,000 psig High. 29. Pull TWC. 30. RD ASR #1 and all ancillary equipment. 31. Turn well over to production with the handover form. 32. Follow-up E-line leak detect to occur after rig has moved off the well. Attachments: 1. As-built Schematic 2. Proposed Schematic Freeze protect kill string. 3. BOPE Schematic (IA x Tubing) _____________________________________________________________________________________ Revised By: NLW 07-29-21 SCHEMATIC Milne Point Unit Well: MPU L-47 Last Completed: 2/13/2016 PTD: 215-117 TD =12,995’ (MD) / TD =4,158’(TVD) 13-3/8” Orig. KB Elev.: 50’/ GL Elev.: 17’ 7-5/8” 3 7 8 9 10 11 13 9-5/8” 1 2 14 15 16 Min ID 2.205” @ 5,498’ PBTD =12,993’ (MD) / PBTD =4,158’(TVD) 6 9-5/8” ‘ES’ Cementer @ 2,535’ 5 4 5-1/2” 12 IAxOA Leak. Estimated below ESP. AOGCC approval to produce to Oct. 2023 or ESP failure CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 13-3/8" Conductor 68 / A-53 / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TC II 8.835 Surface 7,664’ 0.0759 7-5/8" Production 29.7 / L-80 / Vam SLIJ-II 6.875 Surface 7,402’ 0.0459 5-1/2” Liner 17 / P-110 / DWC/C HT 4.892 7,399’ 12,995 0.0233 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE 8rd 2.347 Surf 5,564’ 0.00579 JEWELRY DETAIL No Depth Item 1139’STA #2:GLM w/ Dummy 7-29-21 –ID=2.25” 25,354’STA #1:GLM w/ Empty pocket 7-29-21 –ID=2.25” 3 5,498’ XN Nipple –ID=2.205” 4 5,509’ Discharge Head: FPHVDIS 5 5,510’ Pump: SXD - 134FLEX17.5 6 5,533’ Gas Separator: GRSFTXAR H6 7 5,538’ Upper Tandem Seal: GSB3DB SB/SB PFSA 8 5,545’ Lower Tandem Seal: GSB3DB SB/SB PFSA 9 5,552’ Motor: CL5 - MSP3-250ȗ 84Hp/ 2,210V/ 23A 10 5,560’ Sensor: WellLift E 11 5,562’ Centralizer:Bottom@ 5,564’ 12 7,399’ SLZXP Liner Top Packer w/ BD Slips 13 7,402’ Seal Assembly 10’ Inside LTP 14 7,421’ 5.5” H563X 7'' DWC XO 15 11,068’ Swell Packer: Bottom @ 11,078’ 16 11,328’ Swell Packer: Bottom @ 11,338’ 17 12,993’ WIV (Ball in Seat/ Closed) –Bottom@ 12,995’ OPEN HOLE / CEMENT DETAIL 13-3/8" 350 sx of Arcticset I (Approx) 9-5/8" 541 bbls in 12-1/4” Hole Cement to Surface 5-1/2” Cementless Slotted Liner w/ Swell Packers 8-1/2” hole WELL INCLINATION DETAIL KOP @ 882’ Max Hole Angle = 92.1 deg. @ 12,925’ MD TREE & WELLHEAD Tree 5M Seaboard 2-9/16” Wellhead Seaboard MB-22 5M GENERAL WELL INFO API: 50-029-23550-00-00 Drilled and Cased by Doyon 14 - 2/15/2016 AOGCC approval to produce 4-year limit to Oct 2023 or ESP failure (9/25/19) 5-1/2” SLOTTED LINER DETAIL Top (MD) Btm (MD) 7,474’ 11,063’ 11,341’ 12,948’ Liner Slot Dimensions= 2.250” L x .125” W 6.72” Sq/In of Inlet Area per FT of Casing 24 Slots Per Foot of Casing _____________________________________________________________________________________ Revised By: TDF 8/5/2021 PROPOSED Milne Point Unit Well: MPU L-47 Last Completed: 2/13/2016 PTD: 215-117 TD =12,995’ (MD) / TD =4,158’(TVD) 13-3/8” Orig. KB Elev.: 50’/ GL Elev.: 17’ 7-5/8” 7 3 9-5/8” 1 4 5 6 PBTD =12,993’ (MD) / PBTD =4,158’(TVD) 9-5/8” ‘ES’ Cementer @ 2,535’ 5-1/2” 2 IAxOA Leak. Estimated below ESP. AOGCC approval to produce to Oct. 2023 or ESP failure CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 13-3/8" Conductor 68 / A-53 / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TC II 8.835 Surface 7,664’ 0.0759 7-5/8" Production 29.7 / L-80 / Vam SLIJ-II 6.875 Surface 7,402’ 0.0459 5-1/2” Liner 17 / P-110 / DWC/C HT 4.892 7,399’ 12,995 0.0233 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / Hydril 521 3.958 Surface ±2,600’ 0.0152 JEWELRY DETAIL No Depth Item 1 ±2,599’ WLEG – Bottom @ ±2,600’ 2 7,399’ SLZXP Liner Top Packer w/ BD Slips 3 7,402’ Seal Assembly 10’ Inside LTP 4 7,421’ 5.5” H563X 7'' DWC XO 5 11,068’ Swell Packer: Bottom @ 11,078’ 6 11,328’ Swell Packer: Bottom @ 11,338’ 7 12,993’ WIV (Ball in Seat/ Closed) –Bottom@ 12,995’ OPEN HOLE / CEMENT DETAIL 13-3/8" 350 sx of Arcticset I (Approx) 9-5/8" 541 bbls in 12-1/4” Hole Cement to Surface 5-1/2” Cementless Slotted Liner w/ Swell Packers 8-1/2” hole WELL INCLINATION DETAIL KOP @ 882’ Max Hole Angle = 92.1 deg. @ 12,925’ MD TREE & WELLHEAD Tree 5M Seaboard 2-9/16” Wellhead Seaboard MB-22 5M GENERAL WELL INFO API: 50-029-23550-00-00 Drilled and Cased by Doyon 14 - 2/15/2016 AOGCC approval to produce 4-year limit to Oct 2023 or ESP failure (9/25/19) 5-1/2” SLOTTED LINER DETAIL Top (MD) Btm (MD) 7,474’ 11,063’ 11,341’ 12,948’ Liner Slot Dimensions= 2.250” L x .125” W 6.72” Sq/In of Inlet Area per FT of Casing 24 Slots Per Foot of Casing 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 907 777.8337 Received By: Date: DATE 7/22/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-47(215-117) Leak Detection Log Received by the AOGCC 07/27/2020 PTD: 2151170 E-Set: 33628 Abby Bell 07/27/2020 H corp Alaska, LLC Orig. KB Elev.: 50'/ GL Elan.: 17' TO =12,995' (MD) /TD = 4,15KCM) PBTD =12,993' (MD) / PHTD = 4,158'(TVD) SCHEMATIC Milne Point Unit Well: MPU L-47 Last Completed: 2/13/2016 PTD: 215-117 TREE & WELLHEAD Tree SM Seaboard 2-9/16" Wellhead Seaboard MB -225M OPEN HOLE / CEMENT DETAIL 13-3/8" 350 sx of Arcticset I (Approx) 9-5/8" 541 bbls in 12-1/4" Hole Cement to Surface 5-1/2" Cementless Slotted Liner w/ Swell Packers 8-1/2" hole CASING DETAIL Size Type Wt/Grade/Conn Drift ID Top Btm4BP13-3/8" 2 5,354' Conductor 68/A-53/Weld N/A Surface 80' 5,509' 9-5/8" Surface 40/L-80/TCn 8.835 Sufiace 7,664' Gas Separator: GRSFTXAR H6 7-5/8" Production 29.7 / L-80 / Vam SLIT -11 6.875 Surface 7,40Y 9 5-1/2" Liner 17/P-110/DWC/CHT 4.892 7,399' 12,995 TUBING DETAIL 2-7/8" Tubing 6.5/L-80/EUE 8rd 1 2.347 1 Surf 5,564' 0.00579 5-1/2" SLOTTED LINER DETAIL Top (MD) Btm 63(MD) 7,474' 11,0' 11,341' 12,948' Liner Slot Dimensions= 2.250" L x .125" W 6.72" Sq/In of Inlet Area per FT of Casing 24 Slots Per Foot of Casing WELL INCLINATION DETAIL KOP @ 882' Max Hole Angle = 92.1 deg. @ 12,925' MD JEWELRY DETAIL No Depth Item 1 139' STA f12: GLM w/ Orifice- ID=2.25" 2 5,354' STA 81: GLM w/ Dummy - ID -2.25" 3 5,498' XN Nipple- ID=2.205" 4 5,509' Discharge Head: FPHVDIS 5 5,510' Pump: SXD-134FLEX37.5 6 5,533' Gas Separator: GRSFTXAR H6 7 5,538' Upper Tandem Seal: GSB3DB SB/SB PFSA 8 1 5,545' 1 Lower Tandem Seal: GSB3DB SB/SB PFSA 9 5,552' Motor: CL5 - MSP3-250' 84Hp/ 2,21OV/ 23A 30 5,560' Sensor: WeI1Lift E 11 5,562' Centralizer: Bottom@ 5,564' 12 7,399' SLZXP Liner Top Packer w/ BD Slips 13 7,402' Seal Assembly 10' Inside LTP 14 7,421' 5.5" H563X 7" DWC XO 15 11,068' Swell Packer: Bottom @ 11,078' 16 11328' Swell Packer: Bottom @ 11,338' 17 12,993' WIV (Bail in Seat/ Closed)- Bottom@ 12,995' GENERAL WELL INFO API: 50 -029 -23550 -MOD Drilled and Cased by Doyon 14 - 2/15/2016 AOGCC approval to produce 4 -year limit to Oct 2023 or ESP failure (9/25/19) N Revised By: DAH 9/20/2019 Z/5. //7 .. F Ir Alaska Oil and Gas HE STATE °fALASKA GOVERNOR MIKE DUNLEAVY September 25, 2019 David Haakinson Operations engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Dear Mr. Haakinson: Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v .00gcc.olaska.gov Your request to allow continued production on L-47 with a known IA x OA leak is APPROVED. Since this is an ESP completion without a production packer, the well now has one barrier to flow (9 5/8" surface casing). Several mitigating factors are noted such as the well is new (drilled in 2015) with recently tested casing and a no -flow test indicating fluid rates are relatively low. To eliminate or greatly reduce the likelihood of external surface casing corrosion, Hilcorp has filled the 9 5/8" by conductor space with dielectric grease. The AOGCC will allow production to continue on L-47 conditionally as follows: 1) L-47 wellhead pressures (T/IA/OA) must be monitored daily. 2) The IA X OA leak must be repaired at the earliest RWO opportunity (ESP failure) or within 4 years of this approval. (At this point a RWO will be required to repair the IA X OA leak whether or not the ESP is still functioning.) 3) The well schematic will require the IA X OA leak noted as well as the 4 -year limit (October 2023) on continued production before requiring a RWO. Sincerely, k Je sie 1. Chm ski Commissioner Schwartz, Guy L (CED) From: David Haakinson <dhaakinson@hilcorp.com> Sent: Tuesday, September 24, 2019 10:28 AM To: Schwartz, Guy L (CED) Cc: Wyatt Rivard; Chad Helgeson; Tom Fouts Subject: RE: MPU L-47 (PTD 215-117) IAxOA Production Variance Request Good morning Guy, Results are as followed; as I received this morning: • L-47 o The producer remains shut in. o The no -flow test was completed on L-47 yesterday evening. • As suspected with the 9.8 ppge reservoir gradient, the well flowed during the test. o On the initial bleed, we were unable to bleed the tubing pressure to zero psig to perform a true no -flow test. o We did however flow to a tank to monitor unassisted flow with the results below: Time (PM) Pressure (psig) Total Volume (bbl) BBL/hr T 260 4 IA 240 0 OA 380 T NA 4:30 1 IA 260 1 33.48 66.96 OA 380 T NA 5:00 IA 270 53.48 40 OA 380 T NA 5:30 IA 280 70.48 34 OA 380 T 220 6:00 IA 280 79.48 18 OA 380 y3Z IFc5v C Solo • L-46 o MIT -OA was completed on Saturday, and failed. o Operations is working locating our calibrated no -flow test meter. o Better results are expected with L-46 due to the lower 8.9 ppge reservoir pressure gradient. o L-46 remains online. Please let us know how to proceed. Apologies for the delay. 1 David Haakinson Operations Engineer I North Slope Asset Team Hilcorp Alaska, LLC Office: (907) 777-8343 1 Cell: (307) 660-4999 dhaakinson@hi lcorp.com From: Schwartz, Guy L (CED) [mailto:guy.schwartz@alaska.gov] Sent: Tuesday, September 24, 2019 9:50 AM To: David Haakinson <dhaakinson@hilcorp.com> Cc: Wyatt Rivard <wrivard@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com>; Tom Fouts <tfouts@hilcorp.com> Subject: [EXTERNAL] RE: MPU L-47 (PTD 215-117) IAxOA Production Variance Request David, Working on a response.. how did the No -Flow tests end up on L -47 and L-46? 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, It you are an unintended recipient of this e-mail, please delete if, 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 (Guv.schwartz@alaska aov(. From: David Haakinson <dhaakinson@hilcorp.com> Sent: Friday, September 20, 2019 1:31 PM To: Schwartz, Guy L (CED) <Ruy.schwartz@alaska.gov> Cc: Wyatt Rivard <wrivard@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com>; Tom Fouts <tfouts@hilcorp.com> Subject: MPU L-47 (PTD 215-117) IAxOA Production Variance Request Guy, Attached is Hilcorp Alaska's approval request to produce MPU L-47 (PTD 215-117) with an IAxOA leak. A formal document will be mailed to you this afternoon. No -flow tests on both MPU L-46 and L-47 are tentatively planned for this weekend 9/21-9/22. A formal approval request for MPU L-46 will be sent after a MIT -OA is completed. Please contact me if you have any questions or comments. Thank you, David Haakinson Operations Engineer I North Slope Asset Team Hilcorp Alaska, LLC Office: (907) 777-8343 1 Cell: (307) 660-4999 dhaakinson cr hilcorp.com H Ilikurp Alit4a, LLC September 20, 2019 Jessie L. Chmielowski Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (/ 3800 Centerpolnt Drive Suite 1400 Anchorage, AK 99503 Phone: 907/777-8300 Fax: 907/777-8301 Re: Milne Point Production Well MPU L-47 (PTD # 2151170) Request To Produce MPU L-47 with IAxOA Communication Dear Commissioner Chmielowski, Hilcorp Alaska, LLC (HAK) requests approval to produce packer -less ESP well L-47 with an Inner Annulus by Outer Annulus leak. Schrader Bluff producer MPU L-47 exhibits inner -annulus by outer -annulus communication that is manageable by bleeds. The primary leak path appears to be below the ESP completion with an established leak rate of 0.07 BPM at 1500 psig on the outer annulus. When the producer is online, OA pressurization is greatly reduced. With the production casing leak, the packer -less well equates to a mono -bore style ESP completion with a single surface casing barrier. While mono -bore ESPs are being phased out at Milne Point, existing wells continue to be operated safely with regular pressure testing as per CO 390A. MPU L -47's 9-5/8" surface casing passed an integrity test to 3000 psi on 1/31/16 during the initial completion, and is documented to have cement to surface. In order to establish integrity of the 7-5/8" production casing, a rig workover would be necessary to pull the functional ESP completion, determine leak location and then repair the production casing. Instead, HAK requests to produce the well until the next RWO for ESP failure. HAK projects an average ESP run -life of three years for Milne Point Schrader Bluff producers. As with all Milne Point wells, MPU L -47's tubing, inner annulus, and outer annulus pressures are documented daily for trending of pressure data and detection of mechanical integrity issues. HAK believes MPU L-47 is safe to operate as stated above and requests approval to produce the well until the ESP is no longer operable, at which time the IA x OA leak will be repaired with a rig workover. Page 12 If you have any additional questions concerning this request, please contact me at 777- 8343 or by email at dhaakinson@hilcorp.com. Sincerely, David Haakinson Operations Engineer Hilcorp Alaska, LLC Attachments: Technical Justification TIO Plot Wellbore Schematic 9-5/8" Surface Casing Test on 1/31/16 CC Guy Schwartz James Regg 1'nge 13 Milne Point L-47 Technical Justification for Production Approval Request September 19, 2019 Well History and Status MPU L-47 was drilled and completed in the Schrader Bluff OA sand in February 2016. The well was a stable producer with no previous flow difficulties or well -work activities until September 2019. Prior to shut in, the well last tested at 519 BOPD, 40%, and a GOR of 74 scf/bbl. On September 2, 2019 the drill -site operator noticed that the OA pressure was at zero versus 460 psig the day prior. Well Integrity was notified and attempts to measure a fluid level or build pressure on the OA resulted in failure. After the inability to build OA pressure, the well was shut-in on 9/4/19. After the well was shut-in, OA pressure built to 10 psig and a fluid level was observed at -300-400' MD, two days after fluid packing the OA annulus. During the MIT -OA, a leak rate of approximately 0.07 BPM was established. A diagnostic temperature survey was completed down to the XN-Nipple at 5,498' MD. Baseline and pumping overlays indicate an IA x OA leak that is likely below the ESP completion (or lowest logged interval). There is a possibility of an IA x OA leak that was within the logged interval but masked by OA fluids entering the IA and moving downhole to formation. Regardless, due to the change in OA pressure variance dependent upon when the ESP is running, and results of the temperature survey, HAK is confident of the IA x OA leak and not an OA by formation leak. Repair Considerations A repair of the well's 7-5/8" casing would entail the shut-in and removal of an operable ESP. Due to the set depth and restriction of the ESP, further diagnostics of the leak location are not possible. After removal of the ESP completion, a leak detect survey and/or caliper survey of the 7-5/8" production casing would be performed. Dependent upon the results of the leak and extent of damage, the repair proceedings could go down multiple paths. Likely repair mechanisms include, but are not limited to a casing patch, seal -bore replacement, or replacement of the 7-5/8" casing. Barrier Evaluation The primary barrier envelope is the 9-5/8" surface casing that passed a pressure test to 3150 psig on 1/31/16. The surface casing was cemented to surface. The 40 Ib/ft L-80 casing was installed new in 2016, and with a burst rating of 5,750 psig can safely operate within our operational parameters of a MAOSP of 1000 psig with assumptions of either a liquid or gas packed annulus. Due to the two stage cement job to surface and age of the completion, HAK views the risk of failure to be extremely low. A tubing integrity test was completed after the initial IA by OA diagnosis. The pressure test to 1200 psig passed on 9/13/19. In addition, HAK completed a tubing caliper in an P�i�,,c 14 attempt to learn about the condition of the downhole piping. The tubing is in good condition most joints exhibiting less than 20% wall loss, and five joints with less than 30% wall loss. Proposed Operating and Monitoring Plan 1) A no -flow test will be completed on MPU L-47 to test the producer's ability to flow to surface. 2) Record wellhead pressures daily. 3) The well's OA MOASP is limited to 1000 psi. The well will be shut in if unable to maintain pressure below MOASP. 4) The well will be shut-in and the AOGCC notified if there is a change in the well's mechanical condition. AOGCC approval shall be required to restart production following any such shut-in. MPU L-47 180 -Day TIO Plot MPU L-47 TIO Plot —Tubing(psi)—IA(psi)—OA(psi) 1 •m �, . _ A .li�JiL^1%�I ICi1.�C�1— —�.. _ �2 4 ,ao 2W W r Lfi 3 0 \o• vq\q p�q ,DAN ��9 ryp•0 ,��A V1q �tp %,,, 40 ,\p,q "q �p"N 4, NT ,p,q 'lA \VAN ,0�9 ,��A 1��A \e \§' app ZDp �n� 0p T\�'\ P\"p\ 'CC 41 �,\"'\\ �9 t d, P )' s\�n �\ AV \\,�''\ ,\'°\ a.$� 1P c\s0\ \q\ q�P q\p\ 4% Explanation of Events: Note that the well was shut-in early August for the Milne Point facility shut -down. 1. 9/2/19: OA Anomaly Identified. 2. 9/4/19: MPU L-47 Shut In. MIT -OA failed 3. 9/5/19 to 9/16/19: OA pressure Build while SI 4. 9/17/19: Temperature Survey Wellwork Org. KB Elw..: 50'/ (IEle2.: 17 TD- 12,995' (M))/TD= 4,159CTVDI PBTD=12,993' (ND)/PBTD-4,159FM SCHEMATIC Page 16 Milne Point Unit Well: MPU L-47 Last Completed: 2/13/2016 PTD: 215-117 TREE & WELLHEAD Tree I SM Seaboard 2-9j16" Wellhead I Seaboard MS -225M OPEN HOLE/ CEMENT DETAIL 13.3/8" 350 sx of Arcticsat I (Approx) 9-58' S4Lbbisin 12-1/4" Hole Cement to Surface i Slotted Uner tv Swell Packers 8-1/2" hole CASING DETAIL Size Type Wt/Grade/Conn Drift ID Top Btm BPF 13.3/8" Conductor 68/A-53/Weld N/A Surface 80' N/A 9.58" Surface 40/L-80/TCII 8.835 Surface 7,664' 0.0759 7-58" Production I 29.7 L-80 Vam SUI -II 6.875 Swface 7402' 0.0459 5• 2" Liner 17/P-110 DWC/CHT 4.892 7,399' 12,995 0.0233 TUBING DETAIL 2-7/11" 1 Tubing 6.5 L-80 EUE Brd 1 2.347 1 Surf I 5 564' I 0.00579 5-1/2' SLOTTED LINER DETAIL Top (MD) Btm (MD) 7,474' 11,063' 11,341' T 12,948' Liner Slot Dimensions= 2.250' L x.125" W 6.72" Win of Inlet Area per FT of Casing 24 Slots Per Foot of Casing WELL INCLINATION DETAIL KOP @ 882' Max Hole Angle. 92.1 deg. @ 12,925' MO JEWELRY DETAIL No Depth Item 1 139' STA112r GIMw Orifice-ID.125' 2 5,354' STA 81i GLM vi/Dummy -ID=2.25' 3 5,498' XN Nipple ID=2.205" 4 5,509' Discharge ad: FPHVDIS 5 5,510' Pump: SX0-134FLEX17.5 6 5,533' Gas Separator: GRSFTXAR H6 7 5538' Upper Tandem Seal: GSB3DB SB/S8 PFSA 8 5,545' Lovvt Tandem Seal: G383DB SB/S8 PFSA 9 5,552' Mator: CLS -MSP3.250'84H 2,210V/ 23A 10 5,560' Sensor: Wg I' E 11 5,562' Centralizer: Bottom@ 5,564' 12 7,399' SLZXP Liner Top Packer vi/BD Slips 13 7,402' Seal Assembly 10' Inside LTP 14 7,421' S.5" H563X T' DWC XO 15 11068' Swell Packer: Bottom @ 11,078' 16 11,328' Swell Packer: Bottom @ 11,338' 17 12993' WIV(Hall in Seat/ Closed) -Bottom@12,995' GENERAL WELL INFO API: 50-029-23550.00.00 Drilled and Cased by Doyon 14 -2/15/2016 Page 17 Jessie L. Chmielowski - Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 . Re: Milne Point Production Well MPU L-47 (PTD # 2151170) Request To Produce MPU L-47 with IAxOA Communication Dear Commissioner Chmielowski, Hilcorp Alaska, LLC (HAK) requests approval to produce packer -less ESP well L-47 with an Inner Annulus by Outer Annulus leak. Schrader Bluff producer MPU L-47 exhibits inner -annulus by outer -annulus communication that is manageable by bleeds. The primary leak path appears to be below the ESP completion with an established leak rate of 0.07 BPM at 1500 psig on the outer annulus. When the producer is online, OA pressurization is greatly reduced. With the production casing leak, the packer -less well equates to a mono -bore style ESP completion with a single surface casing barrier. While mono -bore ESPs are being phased out at Milne Point, existing wells continue to be operated safely with regular pressure testing as per CO 390A. MPU L -47's 9-5/8" surface casing passed an integrity test to 3000 psi on 1/31/16 during the initial completion, and is documented to have cement to surface. In order to establish integrity of the 7-5/8" production casing, a rig workover would be necessary to pull the functional ESP completion, determine leak location and then repair the production casing. Instead, HAK requests to produce the well until the next RWO for ESP failure. HAK projects an average ESP run -life of three years for Milne Point Schrader Bluff producers. As with all Milne Point wells, MPU L -47's tubing, inner annulus, and outer annulus pressures are documented daily for trending of pressure data and detection of mechanical integrity issues. HAK believes MPU L-47 is safe to operate as stated above and requests approval to produce the well until the ESP is no longer operable, at which time the IA x OA leak will be repaired with a rig workover. DUPLICATE 3800 Centerpoint Drive Suite 1400 liileorp Alaska, LLC Anchorage, AK 99503 Phone: 907/777-8300 Fax: 907/777-8301 September 20, 2019 Jessie L. Chmielowski - Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 . Re: Milne Point Production Well MPU L-47 (PTD # 2151170) Request To Produce MPU L-47 with IAxOA Communication Dear Commissioner Chmielowski, Hilcorp Alaska, LLC (HAK) requests approval to produce packer -less ESP well L-47 with an Inner Annulus by Outer Annulus leak. Schrader Bluff producer MPU L-47 exhibits inner -annulus by outer -annulus communication that is manageable by bleeds. The primary leak path appears to be below the ESP completion with an established leak rate of 0.07 BPM at 1500 psig on the outer annulus. When the producer is online, OA pressurization is greatly reduced. With the production casing leak, the packer -less well equates to a mono -bore style ESP completion with a single surface casing barrier. While mono -bore ESPs are being phased out at Milne Point, existing wells continue to be operated safely with regular pressure testing as per CO 390A. MPU L -47's 9-5/8" surface casing passed an integrity test to 3000 psi on 1/31/16 during the initial completion, and is documented to have cement to surface. In order to establish integrity of the 7-5/8" production casing, a rig workover would be necessary to pull the functional ESP completion, determine leak location and then repair the production casing. Instead, HAK requests to produce the well until the next RWO for ESP failure. HAK projects an average ESP run -life of three years for Milne Point Schrader Bluff producers. As with all Milne Point wells, MPU L -47's tubing, inner annulus, and outer annulus pressures are documented daily for trending of pressure data and detection of mechanical integrity issues. HAK believes MPU L-47 is safe to operate as stated above and requests approval to produce the well until the ESP is no longer operable, at which time the IA x OA leak will be repaired with a rig workover. DUPLICATE �2 If you have any additional questions concerning this request, please contact me at 777- 8343 or by email at dhaakinson@hilcorp.com. Sincerely, David Haakinson Operations Engineer Hilcorp Alaska, LLC Attachments: Technical Justification TIO Plot Wellbore Schematic 9-5/8" Surface Casing Test on 1/31/16 CC Guy Schwartz James Regg Pa,,e 13 Milne Point L-47 Technical Justification for Production Approval Request September 19, 2019 Well History and Status MPU L-47 was drilled and completed in the Schrader Bluff OA sand in February 2016. The well was a stable producer with no previous flow difficulties or well -work activities until September 2019. Prior to shut in, the well last tested at 519 BOPD, 40%, and a GOR of 74 scf/bbl. On September 2, 2019 the drill -site operator noticed that the OA pressure was at zero versus 460 psig the day prior. Well Integrity was notified and attempts to measure a fluid level or build pressure on the OA resulted in failure. After the inability to build OA pressure, the well was shut-in on 9/4/19. After the well was shut-in, OA pressure built to 10 psig and a fluid level was observed at —300-400' MD, two days after fluid packing the OA annulus. During the MIT -OA, a leak rate of approximately 0.07 BPM was established. A diagnostic temperature survey was completed down to the XN-Nipple at 5,498' MD. Baseline and pumping overlays indicate an IA x OA leak that is likely below the ESP completion (or lowest logged interval). There is a possibility of an IA x OA leak that was within the logged interval but masked by OA fluids entering the IA and moving downhole to formation. Regardless, due to the change in OA pressure variance dependent upon when the ESP is running, and results of the temperature survey, HAK is confident of the IA x OA leak and not an OA by formation leak. Repair Considerations A repair of the well's 7-5/8" casing would entail the shut-in and removal of an operable ESP. Due to the set depth and restriction of the ESP, further diagnostics of the leak location are not possible. After removal of the ESP completion, a leak detect survey and/or caliper survey of the 7-5/8" production casing would be performed. Dependent upon the results of the leak and extent of damage, the repair proceedings could go down multiple paths. Likely repair mechanisms include, but are not limited to a casing patch, seal -bore replacement, or replacement of the 7-5/8" casing. Barrier Evaluation The primary barrier envelope is the 9-5/8" surface casing that passed a pressure test to 3150 psig on 1/31/16. The surface casing was cemented to surface. The 40 Ib/ft L-80 casing was installed new in 2016, and with a burst rating of 5,750 psig can safely operate within our operational parameters of a MAOSP of 1000 psig with assumptions of either a liquid or gas packed annulus. Due to the two stage cement job to surface and age of the completion, HAK views the risk of failure to be extremely low. A tubing integrity test was completed after the initial IA by OA diagnosis. The pressure test to 1200 psig passed on 9/13/19. In addition, HAK completed a tubing caliper in an Page 14 attempt to learn about the condition of the downhole piping. The tubing is in good condition most joints exhibiting less than 20% wall loss, and five joints with less than 30% wall loss. Proposed Operating and Monitoring Plan 1) A no -flow test will be completed on MPU L-47 to test the producer's ability to flow to surface. 2) Record wellhead pressures daily. 3) The well's OA MOASP is limited to 1000 psi. The well will be shut in if unable to maintain pressure below MOASP. 4) The well will be shut-in and the AOGCC notified if there is a change in the well's mechanical condition. AOGCC approval shall be required to restart production following any such shut-in. MPU L -47180 -Day TIO Plot MPU L-47 TIO Plot I" M eoo 7m u o cm sao � E — am .. A AA. mo xaa 1W r _ 5 —Tubing(psi)—IA(psi)—OA(psi) 1 El W0 3 A�1\�91\1O5D bY5 \5\100�~,15PP'�y5,a"p\�~"Crbe� ��S��b\'��b�e'� fib•^yti �b14� �b�N�~O9�\ b•'S�\ Oy9 1015 ,ybla•�vO10\ ypy5 ryOyA(L yO•`D'Y �1>•\ plD•y �',b} \0 Explanation of Events: Note that the well was shut-in early August for the Milne Point facility shut -down. 1. 9/2/19: OA Anomaly Identified. 2. 9/4/19: MPU L-47 Shut In. MIT -OA failed 3. 9/5/19 to 9/16/19: OA pressure Build while SI 4. 9/17/19: Temperature Survey Wellwork if Ug. KB Elev.: 50'1 Q Eley 17 TD= 12,9%' (MD) /TD= 4,158' (TVD) PBTD=12,9%'(ND)/PBID=4,159 ffM SCHEMATIC Page 16 Milne Point Unit Well: MPU L-47 Last Completed: 2/13/2016 PTD: 215-117 TREE & WELLHEAD Tree I SM Seaboard 2-9/16" Wellhead I Seaboard MB -225M OPEN HOLE / CEMENT DETAIL 13-318" 1 350 sx of Arc luc I (Approx) 9-518" 541 bbis in 12-1/4" Hole Cement m Surface 5-1/2' Slotted Unerw Swell Packers8- 2" hole CASING DETAIL Size Type Wt/Grade/Conn Drift ID Top Btm BPF 13-3,'8" Conductor 68 J A-53 /Weld NJA Surtace 80' N/A 9-518" Surface 40 JL-SO/TCII 8.835 Surface 7,664° 0.0759 7-5/8" Production 297/L-80 Vam SW -11 6.875 Surface 1 7,402' 0.0459 S-1/2" Liner 17 J P-110 J DWC/C NT 4.892 7,399' 12,995 0.0233 TUBING DETAIL 2-7/8" Tubing I 6.5 L-80 EUE Srtl 1 2.347 1 Surf S 564' 0.00579 5-1/2" SLOTTED LINER DETAIL Top (MD) Btm (MD) 7,474' i1,C63` 13,341' 12,945' Liner Slat Dimensions= 2.250" Lx .125" W 6.72" Wn of Inlet Area per FT of Casing 24 Slots Per Foot of Casing WELL INCLINATION DETAIL KOP @ 882' Max Hole Angle= 92.1 deg. @ 12,925' MO JEWELRY DETAIL No Depth Item 1 139' STA#2: GLMw/Orifice—ID=225" 2 5,354' STA#1: GLM w/Dumm—10=2__ti' 3 5,498' XN Nipple10=2205" 4 5,509' Discharge :FP tS 5 5,510' Pump: SXD-134FLEXSZS 6 5,533' Gas Separ r- GRSFTXA.4 H6 7 5,538' Upper Tandem Seal: GSB3DB SB/SS PFSA 8 5,545' Lower Tandem Seal: GS63DE S6/SB PFSA 9 5,552' MMor.CL5-MSP3-250'84Hp/2,21C4/234 10 S,Sw Sensor: E 11 5,562' Centralizer: 8ottom� 5,564' 12 7,399' SLZXP Uner Tap Packer w/ BD Slips 13 7,402' Seal Assembly 10` Inside LTP 14 7,421' S.5'H563X 7'DWC XO 15 11,068' Swell Packer: Bottom @ 11,078' 16 11,328' Swell Packer: Bottom @ 11,338' 17 12,993` Mjilall in Seat/ Closed)—Bottom@12,995' GENERAL WELL INFO liAPI: 50-029-23550-00-00 Grilled and Cased by Doyon 14 - 2/15/2016 • • o o • o N O 6 �9 ,, > © a) U) ro Z cE 5- N COCO ca E ' J a -) N • E E • O 0 = w n e z ao0 col 2 - + m 0 • ❑ • ❑ J 0 co c4 _ J ❑ > N > > > J LL O � @ ' F- N o > c c I- F Hd d o N m > 0 LC LY .- rcC cC2CCccCLL I 2 2 >. — ❑ ❑ 'E ❑ ❑ U) a) ❑ ❑ ❑ ❑ ❑ ❑ J -J 0 o i) (.- Q Q in�Q Q m Q Q Q Q Q Q N m CO N Z Z I I a) • + + 0 0 1 1 I I I I E cn cn E 7 j Ico co ❑ co cn a) N N Co cn cn CO Co as @ E. co 5 LL LL LL LL 0 0 LL LL LL LL LL LL cF- I Q To 1 n N- n N- N- N- N- N- N- N- n r` r- N- r— — Z Z — c , @ v Ti- v a a a v V v v v a V v IL ❑ 2 ll 0 I 2 J J J J J J J J J J J J J J 0- LL d CL d d -LL 0. 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J W p 2 N H M z LO 0 WM e-- c--:, ai p p- Cn z o 0 Q J O LI Q ° 11,Q Z E 121 d 0 0 z • Lo 3 • 1 O r, > 1 m ✓ u> I3 N „ N .' 0) F. toet c7, o N V C i+ G C U r Q co 40 U E V Q C7 41 41 o d G C 0¢ • STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG la.Well Status: Oil Q Gas❑ SPLUG El Other 0 Abandoned ❑ Suspended E] lb.Well Class: 20AAC 25.105 20AAC 25.110 Development Q Exploratory ❑ GINJ fl WINJ 0 WAGE] WDSPL❑ No.of Completions: _1 Service 0 Stratigraphic Test 0 2.Operator Name: 6. Date Comp.,Susp.,or 14. Permit to Drill Number/ Sundry: Hilcorp Alaska, LLC Aband.: 2/15/2016 215-117 • 3.Address: 7. Date Spudded: 15.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 January 20,2016 50-029-23550-00-00 ' 4a. Location of Well(Governmental Section): 8.Date TD Reached: 16.Well Name and Number: Surface: 3450'FSL,4722'FEL,Sec 8,T13N,R10E, UM,AK February 7,2016 MPU L-47 " Top of Productive Interval: 9.Ref Elevations: KB: 50',04 17. Field/Pool(s):Milne Point Unit 1440'FNL, 1038'FEL,Sec 18,T13N, R10E,UM,AK GL: 17' BF:17' Schrader Bluff Oil Pool - Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 744'FSL, 1999'FEL,Sec 17,T13N, R10E,UM,AK 12,993'MD/4,158'TVD . (SHL)ADL025509(BHL/TPH)ADL025515 ' 4b. Location of Well(State Base Plane Coordinates,NAD 27): 11.Total Depth MD/TVD: 19. Land Use Permit: Surface: x- 545157 y- 6031642 Zone- 4 12,995'MD/4,158'TVD • N/A TPI: x- 543607 y- 6026742 Zone- 4 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 547955 y- 6023674 Zone- 4 N/A 2,137'MD/1,860'TVD 5. Directional or Inclination Survey: Yes Q(attached) No 0 13.Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071,submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first.Types of logs to be listed include, but are not limited to:mud log,spontaneous potential, gamma ray,caliper, resistivity,porosity,magnetic resonance,dipmeter,formation tester,temperature,cement evaluation,casing collar locator,jewelry,and perforation record. Acronyms may be used.Attach a separate page if necessary L-47:ROP-DGR-ADR-EWR-HORIZONTAL PRES 21N MD, DGR-ADR-EWR-REVERTED INTERVAL 21N ND L-47PB1: ROP-DGR-ADR-EWR-HORIZONTAL PRES 21N MD, DGR-ADR-EWR-INVERTED INTERVAL 2IN ND RECEIVED MAR 1�±4 "2016 23. CASING, LINER AND CEMENTING RECORD OGCC WT. PER SETTING DEPTH MD SETTING DEPTH ND AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD FT. PULLED 13-3/8" 68# A-53 Surface 80' Surface 80' Conductor Yes/–350 sx Stg 1 L-335 bbls/T-75 bbls 9-5/8" 40# L-80 Surface 7,664' Surface 4,095' 12-1/4" Stg 2 L-310 bbls/T-56 bbls 235 bbls 7-5/8" 29.7# L-80 Surface 7,402' Surface 4,063' Tieback Assy Tieback Assy. Inside Casing 5-1/2" 17# P-110 7,399' 12,995' 4,062' 4,158' 8-1/2" Slotted Liner w/Swell Pkrs. 24.Open to production or injection? Yes Q No ❑ 25.TUBING RECORD If Yes, list each interval open(MD/TVD of Top and Bottom;Perforation SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Size and Number): 2-7/8" 5,564' N/A 5-1/2"Slotted Liner Detail 7,474'-11,063'MD/4,072'-4,119'ND 26.ACID, FRACTURE,CEMENT SQUEEZE, ETC. 11,341'-12,948'MD/4,144'-4,160'ND .:0111i'LL 1'iOiv r1A'1 r'.= Was hydraulic fracturing used during completion? Yes❑ No Q✓ "'L/l5. (IP Per 20 AAC 25.283(i)(2)attach electronic and printed information DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED VERIPIEDV-- - 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 2/21/2016 ESP Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 2/27/2016 24 Test Period 606 61 0 N/A 1/10 Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 259 0 24-Hour Rate — 606 61 0 18 Form 10-407 Revised 11/2015 / ) CO,TINUED ON PAlE 2 bmit ORIGINIAL onl 5 it rb �' ��( /46" �r� sr3�I� RBDMS ��- Ma,R 1 5 20 �' 28.CORE DATA Conventional CO): Yes ❑ No ❑✓ Sidewall Coresilles ❑ No ❑✓ If Yes, list formations and intervals cored(MD/TVD, From/To), and summarize lithology and presence of oil,gas or water(submit separate pages with this form, if needed).Submit detailed descriptions,core chips,photographs,and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No .❑ Permafrost-Top 0 0 If yes, list intervals and formations tested,briefly summarizing test results. Permafrost-Base 2,137' 1,860' Attach separate pages to this form, if needed,and submit detailed test Top of Productive Interval 7,480' 4,072' information,including reports,per 20 AAC 25.071. SV1 2,720' 2,139' Ugnu MA 6,190' 3,682' Schrader Bluff NA 6,810' 3,924' Schrader Bluff OA 7,637' 4,092' Formation at total depth: Schrader Bluff 31. List of Attachments: Wellbore Schematic, Drilling and Completion Composite Reports, Definitive Directional Surveys, Days vs. Depth,MW vs. Depth,Casing and Cement Report. Information to be attached includes,but is not limited to:summary of daily operations,wellbore schematic,directional or inclination survey,core analysis, paleontological report,production or well test results,per 20 AAC 25.070. 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Luke Keller Email: Ikelleri�hilcorp.com Printed Name: Luke Keller I / Title: Drilling Engineer Signature: Phone: 907-777-8395 Date: 37 0/6 INSTRUCTIONS General: 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. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1 b: Well Class-Service wells:Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation,or Other. Item 4b: TPI(Top of Producing Interval). Item 9: The Kelly Bushing,Ground Level,and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 20: Report measured depth and true vertical thickness of permafrost.Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and,pursuant to AS 31.05.030,submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26.(Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing,Gas Lift, Rod Pump, Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box.Pursuant to 20 AAC 25.071,submit detailed descriptions,core chips,photographs,and all subsequent laboratory analytical results, including,but not limited to:porosity, permeability,fluid saturation,fluid composition,fluid fluorescence,vitrinite reflectance,geochemical,or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070,attach to this form:well schematic diagram,summary of daily well operations,directional or inclination survey,and other tests as required including,but not limited to:core analysis,paleontological report,production or well test results. Form 10-407 Revised 11/2015 Submit ORIGINAL Only II • • Milne Point Unit Well: MPU L-47 SCHEMATIC Last Completed: 2/13/2016 HiIcory Alaska,LLC PTD: 215-117 Orig.KBEIev.:50'!GLElev.:17' TREE&WELLHEAD Tree 5M Seaboard 3-1/8" Wellhead Seaboard MB-22 5M 13-3/8" OPEN HOLE/CEMENT DETAIL 13-3/8" 350 sx of Arcticset I(Approx) " . 9-5/8" 541 bbls in 12-1/4"Hole Cement to Surface 5-1/2" Cementless Slotted Liner w/Swell Packers 8-1/2"hole ;; CASING DETAIL • Size Type Wt/Grade/Conn Drift ID Top Btm BPF 13-3/8" Conductor 68/A-53/Weld N/A Surface 80' N/A 9-5/8" Surface 40/L-80/TC II 8.835 Surface 7,664' 0.0759 7-5/8" Production 29.7/L-80/Vam SLIJ-II 6.875 Surface 7,402' 0.0459 5-1/2" Liner 17/P-110/DWC/C HT 4.892 7,399' 12,995 0.0233 TUBING DETAIL 9-5/8' ES 2-7/8" Tubing 6.5/L-80/EUE 8rd 2.347 Surf 5,564' 0.00579 Cementer @ 2,5355-1/2"SLOTTED LINER DETAIL Top(MD) Btm(MD) l'' 7,474' 11,063' 11,341' 12,948' 2 r &' WELL INCLINATION DETAIL . 3 ' KOP@882' it) 4 z. Max Hole Angle=92.1 deg.@ 12,925'MD . 5 'F. JEWELRY DETAIL ja 6 7 '1 No Depth Item 8o 1 139' STA#2:GLM w/Orifice-ID=2.25" ::1 2 5,354' STA#1:GLM w/Dummy-ID=2.25" 9 r` 3 5,498' XN Nipple-ID=2.25" 4 5,509' Discharge Head:FPHVDIS 10 f4 5 5,510' Pump:SXD-134FLEX17.5 1([s 11 6 5,533' Gas Separator:GRSFTXAR H6 ri 7 5,538' Upper Tandem Seal:GSB3DB SB/SB PFSA t 8 5,545' Lower Tandem Seal:GSB3DB SB/SB PISA 7-5/8" . 9 5,552' Motor:CL5-MSP3-250' 10 5,560' Sensor:WellLift E 11 5,562' Centralizer: Bottom@ 5,564' ',1 12 V _ t 12 7,402' Seal Assembly 10'Inside LTP �4 ® ':13 13 7,399' Liner Top Packer }5/g-e 14 11,068' Swell Packer:Bottom @ 11,078' 1 15 11,328' Swell Packer:Bottom @ 11,338' 16 12,993' WIV(Ball in Seat/Closed) iiii GENERAL WELL INFO IIII' API:50-029-23550-00-00 fillDrilled and Cased by Doyon 14 -2/15/2016 14 5-1/2" 15 1111 16 TD=12,995'(MD)/TD=4,158'(TVD) PBTD=12,993'(MD)/PBTD=4,158'(TVD) Revised By:CJD 3/10/2016 • Hilcorp Energy Company Composite Report Well Name: MP L-47 Field: North Slope County/State: ,Alaska t(LAT/LONG): evation(RKB): API#: Spud Date: 1/20/2016 Job Name: 1511125D MP L-47 Drilling Contractor AFE#: 1511125D AFE$: $4,137,342 *040 Ops Summary �.. 1/16/2016 Move Doyon 14 from Prudhoe bay to Kuparak river bridge. 1/17/2016 Move Doyon 14 from Kuparuk river bridge to MPL-pad,rig camp to follow. Note:Hot bolt diverter tee and 20"annular on L-47 Spot rig malts for camp&rig on L-47. Finish hauling Mis Doyon Equipment;Doyon 14 currently 4 miles from L-pad. Note:finish moving Nordic 3 Rig and camp to Texaco pad for cold stack. 1/18/2016 Move rig from from L-pad turnoff to MPL-pad.Notify MP security and DSO for arrival on L-pad. Note:49.2 mile,48.5 hr rig move.;Spot rig in middle of L-pad,PJSM,Remove front and rear boosters,Secure BOP on rig pedestal in cellar.;Move new CSG/TBG spools,adapter flange and tree from cellar area.;PJSM,MIRU on L-47.Notify L-pad DSO before spotting over well.Align and back rig over well,stage choke line in pits.;PJSM,Shim and level rig,start spotting rig equipment&service buildings. Note:accept rig @ 21:30 hrs.;Skid rig floor into drilling position,R/U lines,position beaver slide,turn on steam to rig floor.Skid conveyor#2 into position,work on rotating annular and diverter tee into position.;N/U diverter system,stage MWD and mud shacks,finish getting conveyor#2 into drilling position.Spot cuttings box and rock washer. (work on rig acceptance checklist);Notified AOGCC of diverter test for 0800 1-20-2016;-Hauled 0 bbls to G&I,Total Hauled 0 bbls -Hauled 0 bbls to B-50,Total Hauled 0 bbls -Hauled 0 bbls to ORT,Total Hauled 0 bbls -Hauled 0 bbls from Lake 2,Total Hauled 0 bbls 1/19/2016 Finish installing rock washer,stage warmup shack,prep pipe shed,load DS50 5"drill pipe in pipeshed.;Attend pre spud meeting for L-47 AT MP base camp.;Continue loading 5"DP in shed(190 jts total)strap and tally same.Spot sperry shack into position and power up same.Continue to R/U conveyor#2. Load sperry tools in pipe shed.;Power up accumulator,P/U 1 jt 5"DP.Function test diverter system,22 sec for knife valve to open,26 sec for annular to close.;PJSM,drift,P/U 5"DP and rack in derrick.;Continue P/U 5"DP singles and racking in derrick.Install 4"ball valves on conductor.Add another 40'jt to diverter line.Flush lines in pits to ensure no leaks and functioning correctly.;PJSM,Pressure test circulating lines to 4000 psi,leak tight test.Blow down Iines.;Continue to P/U 5"DP and rack in derrick,start Loading 8.8 ppg spud mud in pits.;-Hauled 0 bbls to G&I,Total Hauled 0 bbls -Hauled 0 bbls to B-50,Total Hauled 0 bbls -Hauled 0 bbls to ORT,Total Hauled 0 bbls -Hauled 0 bbls from Lake 2,Total Hauled 0 bbls 1/20/2016 Continue to P/U 5"DP and rack in derrick,start Loading 8.8 ppg spud mud in pits.Finish installing last section of Diverter Line.Install ball valves on Conductor.;Finish Mobilizing secondary equipment.NOV/TOTCO installing work stations in support shacks.MPU Electricians working on high line for camp and rig.;RIH with 1 stand 5"DP and perform Diverter test.Test witnessed by Johnnie Hill of AOGCC. 25 sec for knife valve to open,35 sec for annular to close.;Perform Accumulator Test:System Pressure 3000 psi,Pressure After Closure 1800 psi,200 psi Build 35 sec,Full Recovery 158 sec,N2 Bottles 6 @ 1930 psi.All Pass.Test Gas detectors.All Pass.;PJSM.Install Wear Bushing.ID 15 1/4",OD 16 5/8"Length 1.00'RILDS x 4.;PU and rack back 17-5"HWDP and Jars.;Stage 12 1/4"Used Bit and 8"Sperry Mud Motor on rig floor for conductor clean out.Hang Mud Bucket.Remove DP Thread Protectors from rig floor.;PJSM MU Conductor Clean out Assy:12 1/4"HDBS Mill Tooth Bit,8"Sperry 1.5 deg Mud Motor,Xo to DP.Total length=36.77'MU 1 Stand HWDP.Tag hard @ 37';Bring on pumps and check flow paths for leaks.Clean out conductor with FW from 37'switching to Spud Mud©120'.GPM 450/500 psi,Rot 40 RPM's,WOB 5-10K,drill to 222'.;POH from 222'to mud motor,L/D Mill tooth bit,M/U Varel DT1GJMRS 12 1/4"bit,P/U MWD tools,perform rig floor offset,set @ 254.74 deg. Scribe and orient UBHO,test and load MWD tool.;R/U Gyro data,hang sheave,R/U tools.M/U 3-8"NMFC,Bottleneck X0=175.72',M/U 1 std HWDP and top drive.Shallow test MWD,magnetic interference.;Drilling 12 1/4"surface hole from 222'to 266'pumping 450 gpm,950 psi,WOB 5K,40 RPM,4K torq.PU 75K, S/O 70K,ROT 75K.Ciculate hole clean.;Park bit @ 263',Break out and Blow down top drive,RIH with Gyro,orient from 347 deg to 225 deg tool face.POH with gyro.M/U top drive.;Slide from 266'to 329'pumping 453 gpm,950 psi.WOB 18K.100 psi diff,200 fph.;Work pipe,pump @ reduced rate,unclog solids conveyor.;Drilling from 329'to 361'pumping 457 gpm 1050 psi,WOB 8K,60 rpm,torq 3200#, unable to take survey due to interference.Circulate hole clean.;Park bit @ 358',Break out and Blow down top drive,RIH with Gyro,222 deg tool face,POH with gyro.M/U top drive.;Slide f/361'to 420',rotate to 456' pumping 453 gpm 1030 psi,WOB 8K,60 rpm,torq 3500#, able to take survey with MWD.;MW in/out 9 ppg,vis 142.ECD 9.28 ppg.No losses. Currently.27'above the line,.83'right of the Iine.;Rack 1 stand back,M/U std HWDP with jars.Slide from 456';-Hauled 0 bbls to G&I,Total Hauled 0 bbls -Hauled 275 bbls to B-50,Total Hauled 275 bbls -Hauled 0 bbls to ORT,Total Hauled 0 bbls -Hauled 165 bbls from 6m Lake 2,Total Hauled 165 bbls 1/21/2016 Drill 12 1/4"Surface hole from 4560'MD(925 TVD)(469')AROP 78.1 FPH. 500 GPM,1520 PSI ON,1380 PSI ON, 80 RPM,3-4K TQ ON,1-2KTQ OFF,PU 100K,SO 100K,ROT 100K;MW IN 9.2,MW OUT 9.2,ECD 9.55 PPG MWD SURVEY EVERY 95'.LAST GYRO SURVEY @ 546'.MWD SURVEY @ 790'WAS DIRTY,BACK REAM 30'PRIOR TO CONNECTIONS AS PER SPERRY DD,LAST SURVEY 12.91'H/1.4'L;WATER ON @ 25 BPH,BOTH CENTRIFUGES AND MUD CLEANER RUNNING.;Drill 12 1/4"Surface hole from 930'to 1489'MD(1437'TVD)(559')AROP 93.2 FPH. 504 GPM, 1520 PSI ON, 1330 PSI OFF,80 RPM,2-3K TQ ON,2-3K TQ OFF,PU 106K,SO 106K,ROT 108K,WOB 20-25K;MW IN 9.1,MW OUT 9.2,ECD 9.94 PPG,VIS IN/OUT 175/200 MWD SURVEY EVERY 95'.LAST GYRO SURVEY @ 546'. BACK REAM 30'PRIOR TO CONNECTIONS AS PER SPERRY DD;LAST SURVEY @ 1450'MD,1406'TVD,INC 35.47, AZM 218.61,DISTANCE TO PLAN 10' HIGH,6'LEFT. WATER ON @ 25 BPH BOTH CENTRIFUGES AND MUD CLEANER RUNNING. NO RIG ISSUES.;Drill 12 1/4"Surface hole from 1489'to 1772'MD(1653'TVD)(283')AROP 56.6 FPH. 500 GPM, 1400 PSI ON, 1300 PSI OFF,80 RPM,4-5K TQ ON,2-3K TQ OFF,PU 116K,SO 105K,ROT 110K,WOB 20-25K;MW IN 9.1+,MW OUT 9.2,ECD 9.8 PPG,VIS IN/OUT 156/187 MWD SURVEY EVERY 95'.FINAL GYRO SURVEY(MULTI SHOT)@ 1677'. R/D AND RELEASE GYRO. BACK REAM 30'PRIOR TO CONNECTIONS AS PER SPERRY DD;LAST SURVEY @ 1733'MD,1625'TVD,INC 46.01 AZM 212.87,DISTANCE TO PLAN 1' HIGH,16.5'RIGHT. WATER ON @ 25 BPH BOTH CENTRIFUGES AND MUD CLEANER RUNNING.;CIRCULATE W/#1 MP,WORK PIPE.C/O LEAKING SWAB#2 MP,DS.;Drill 12 1/4"Surface hole from 1772'to 2287 MD(1944'TVD)(515')AROP 86 FPH. 508 GPM, 1530 PSI ON, 1400 PSI OFF,80 RPM,4-8K TQ ON,2-4K TQ OFF,PU 116K,SO 105K,ROT 110K,WOB 20-25K;NOTE:ROTATE TANGENT SECTION THRU BASE PERMAFROST F/1960'TO 2240'. MW IN 9.2,MW OUT 9.2+,ECD 10 PPG,VIS IN/OUT 165/176,MWD SURVEY EVERY 95'. BACK REAM 30'PRIOR TO CONNECTIONS AS PER SPERRY DD.;LAST SURVEY @ 2205.37'MD,1898'TVD,INC 56.06 AZM 211.02,DISTANCE TO PLAN 2.49'LOW,12.66'RIGHT. WATER ON @ 25 BPH BOTH CETRIFUGES AND MUD CLEANER RUNNING. NO LOSSES;-Hauled 1130 bbls to G&I,Total Hauled 1130 bbls -Hauled 0 bbls to B-50,Total Hauled 275 bbls -Hauled 0 bbls to ORT,Total Hauled 0 bbls -Hauled 819 bbls from 6m Lake 2,Total Hauled 987 bbls 1/22/2016 DRILL 12 1/4"HOLE SECTION F/2287'to 2527' (240')AROP 120 FPH. 550 GPM, 1290 PSI ON, 1270 PSI OFF,80 RPM,4-5K TQ ON,3-4K TQ OFF,PU 118K,SO 100K,ROT 110K,WOB 5-10K;MW IN 9.1,MW OUT 9.2,ECD 9.94 PPG,VIS IN/OUT 175/200 WATER ON @ 25 BPH,BOTH CETRIFUGES AND MUD CLEANER RUNNING. LAST SURVEY @ 2489.01'MD,2036.17'TVD,INC 63.88 AZM 211.54,DISTANCE F/PLAN-14.37,10.27'LOW,10.04'RIGHT;CBU F/2527'@ 550 GPM, 1170 PSI,50 RPM,4-STQ,ROT/RECIPROCATE 95'. NO SUBSTANTIAL INCREASE IN CUTTINGS AT BOTTOMS UP.;POOH ON ELEVATORS F/2527'TO 83'.WIPE THROUGH TIGHT SPOTS WITH 25K MAX OVER PULLS @ 2260',1680',1350'.BREAK OUT&UD UBHO SUB,RIH W/1 STND HWDP.HOLE FILL 8 BBLS OVER CALCULATED.;NOTE: AT 1100'THE 3/4"THREADED NIPPLE ON THE TOTCO BLOCK HEIGHT/DEPTH ENCODER ON DRAW WORKS BACKED DAMAGING THE NIPPLE.REMOVE ROTORY SWIVEL AND AIR LINE FROM;ENCODER ASSEMBLY REINSTALL ON DRAW WORKS AND CONTINUE TO POOH WHILE REPAIRING ENCODER.;CLEAN RIG FLOOR AFTER WET TRIP.SERVICE TOP DRIVE/BLOCKS&IBOP.REINSTALL DEPTH/BLOCK HEIGHT ENCODER.;TIH ON ELEVATORS F/173'.MU TOP DRIVE @ 1200',FILL PIPE&BREAK CIRCULATION,BREAK OFF&BLOW DOWN TD.CONTINUE TO TIH F/1200'-2113'.;ATTEMPT TO WORK PAST 2113'ON ELEVATORS WITH NO SUCCESS.WASH AND REAM 3 STDS F/2113.-2338'.WASH&REAM 2 STDS F/2338'-2527'WITH NO ISSUES.400 GPM 1100 PSI,40 RPM,5-10 TQ;DRILL 12 1/4"HOLE SECTION F/2527'to 2733' (206')AROP 67 FPH. 550 GPM, 1480 PSI ON, 1420 PSI OFF,80 RPM,5-6K TQ ON,4-5K TQ OFF,PU 125K,SO 110K,ROT 110K,WOB 5-15K.;MUD WT CLIMBING F/9.2 TO 9.5 PPG AFTER WIPER TRIP DUE TO HOPPER BEING INOPERABLE, UNABLE TO RUN DILUTION. STOP DRILLING,RACK 1 STD BACK.ORIENT HI SIDE,PUMP 200 GPM,WORK PIPE SLOW.;ALSO CENTRIFUGE#1 PACKING OFF/DISCHARGE DRY, FEED PUMP NOT WORKING. #2 CENTRIFUGE NOT KICKING OUT SOLIDS/ SHUT DOWN AND CLEANOUT BOTH. GET BOTH BACK ON LINE. M/U STD AND TOP DRIVE.;CONTINUE TO DRILL 12 1/4"HOLE SECTION F/2733'to 3054' (321')AROP 128 FPH 550 GPM, 1970 PSI ON, 1830 PSI OFF,80 RPM,6-7K TQ ON,4-5K TQ OFF,PU 125K,SO 102K,ROT 111K,WOB 5-15K.;MW IN/OUT 9.4/9.4+,VIS IN/OUT 86/105.ECD 9.91 PPG NO LOSSES;CONTINUE TO DRILL 12 1/4"HOLE SECTION F/3054'to 3562' (508')AROP 85 FPH. 629 GPM, 2130 PSI ON, 2030 PSI OFF,80 RPM,6-7K TQ ON,4-5K TQ OFF,PU 125K,SO 104K,ROT 111K,WOB 5-15K.;PUMP 35 BBL HI VIS SWEEP @ 3278',SWEEP BACK 300 STKS LATE W/25%INCREASE CONSISTING OF MOSTLY SAND W/SOME CLAY.;MW IN 9.3,MW OUT 9.3+,ECD 9.81 PPG,VIS IN/OUT 83/87, WATER ON @ 40 BPH,BOTH CETRIFUGES AND MUD CLEANER RUNNING, NO LOSSES;LAST SURVEY @ 3334.62'MD,2397.41'TVD,INC 63.26, AZM 210.18,DISTANCE F/PLAN-10.49'ABOVE, 5.79'RIGHT OF THE LINE. 5.23 ROTATE HRS,1.40 SLIDE HRS;-Hauled 654 bbls to G&I,Total Hauled 1784 bbls -Hauled 0 bbls to B-50,Total Hauled 275 bbls -Hauled 0 bbls to ORT,Total Hauled 0 bbls -Hauled 451 bbls from 6m Lake,Total Hauled 1438 bbls;-Hauled 214 bbls from L-Pad Lake,Total Hauled 214 bbls 1/23/2016 CONTINUE TO DRILL 12 1/4"HOLE SECTION F/3562'to 4222' (660')AROP 110 FPH. 600 GPM, 2300 PSI ON, 1970 PSI OFF,80 RPM,6-7K TQ ON,8-10K TQ OFF 5-7K,PU 150K,SO 106K,ROT 122K,WOB 20-30K.;MW IN 9.3,MW OUT 9.4, ECD 9.87 PPG,VIS IN/OUT 97/123.WATER ON @ 25 BPH,BOTH CENTRIFUGES AND MUD CLEANER RUNNING.;LAST SURVEY @ 4277.75'MD 63.35, AZ 209.55,TVD 2825.29,DISTANCE TO PLAN 5.65 HIGH,4.00 RIGHT. NOTE:2 SWABS LEAKING ON#2 MP.;DRILLED KELLY DOWN TO 4222'.COME DOWN TO 1 PUMP.CIRCULATE WITH 1 MP @ 315 GPM/800 PSI WHILE CHANGING OUT 2 SWABS ON#2 PUMP.;CONTINUE TO DRILL 12 1/4"HOLE SECTION F/4222'to 4694' (472')AROP 105 FPH. 624 GPM, 2200 PSI ON, 2170 PSI OFF,90 RPM,10-12K TQ ON,8-10K TQ OFF,PU 155K,SO 105K,ROT 125K,WOB 17-22K.;MW IN 9.3,MW OUT 9.4, ECD 9.94 PPG,VIS IN/OUT 93/107.WATER ON @ 10 BPH,BOTH CENTRIFUGES AND MUD CLEANER RUNNING.;CONTINUE TO DRILL 12 1/4"HOLE SECTION F/4694'to 5071' (377)AROP 84 FPH. 628 GPM, 2320 PSI ON, 2200 PSI OFF,90 RPM,11-12K TQ ON,8-10K TQ OFF,PU 158K,SO 105K,ROT 125K,WOB 5-15K.;MW IN 9.2+MW OUT 9.2+, ECD 9.94 PPG,VIS IN/OUT 127/143.WATER ON @ 20 BPH,BOTH CENTRIFUGES AND MUD CLEANER RUNNING. LOAD 35 BBL HI VIS SWEEP IN PIPE.;ROTATE AND RECIPROCATE,PUMP 35 BBL W/7.5 PPB WALNUT HI VIS SWEEP W/CONDET AROUND,SWEEP BACK @ CALC STKS,50%INCREASE MOSTLY SAND,SOME CLAY AND COAL.CLEANUP WELL BORE.;LAST SURVEY @ 5032.56'MD, 3161.90'TVD, INC 62.06 AZM 212.47,DISTANCE F/PLAN-8.5'ABOVE, 3.86'LEFT OF THE LINE. 8.20 ROTATE HRS,2.17 SLIDE HRS,;POH TO 4975'.RACK 1 STD BACK,BLOW DOWN TD,FLOWCHECK,WELL STATIC.POH ON ELEVATORS F/4975', TIGHT @ 4491'AND 4395'W/20K OVERPULLS,WORK THRU ON ELEVATORS.;SWABBING,PUMP OUT F/4350',TIGHT @ 4330',ATTEMPT TO WORK THRU SEVERAL TIMES,BACKREAM F/4330'TO 4301',CONTINUE TO PUMP OUT F/4301',TIGHT @ 4100',ATTEMPT TO WORK THRU.;BACKREAM F/ 4100'TO 4038',CONTINUE TO PUMP OUT F/4038'TO 2400', ATTEMPT TO PULL ON ELEVATORS EVERY 5 STDS 20/30K DRAG,CONTINUES TO SWAB, NOTE:STRIP CLAY OFF TOOL JTS ON TRIP OUT.;-Hauled 1325 bbls to G&I,Total Hauled 3136 bbls -Hauled 0 bbls to B-50,Total Hauled 275 bbls -Hauled 0 bbls to ORT,Total Hauled 0 bbls -Hauled xxx bbls from 6m Lake,Total Hauled 1438 bbls;-Hauled 838 bbls from L-Pad Lake,Total Hauled 1052 bbls 1/24/2016 CONTINUE TO PUMP OUT F/24 2100',POOH ON ELEVATORS FROM 2100'-731'(BHA) WI ISSUES.125k PU,105 SO @ 2100';POOH STANDING BACK HWDP/JARS AND FLEX COLLARS.BREAK OFF BIT. BIT GRADED:2-3-WT-A-E-2-BU-BHA;MU NEW BIT:HUGHES VMD-3 TRIGONE.ADD 10 1/2"INTEGRAL BLADE STABILIZER BETWEEN MUD MTR&DM COLLAR.TIH WITH FLEX COLLARS AND 1 STAND HWDP TO 272'.;CLEAN RIG FLOOR AFTER WET TRIP.SERVICE TOP DRIVE/BLOCKS&IBOP. INSPECT IRON ROUGHNECK&DRAW WORKS.;CONTINUE TIH WITH BHA TO 458',PULSE TEST MWD.BLOW DOWN TOP DRIVE.;TIH PICKING UP ADDITIONAL 42 JTS NC50 DRILL PIPE FROM 458'TO 1777'.;TIH WITH 5"DRILL PIPE FROM DERRICK F/1777'.ENCOUNTER TIGHT SPOT @ 1780'. PU 115,SO 70K;MU TOP DRIVE,FILL PIPE.WORK THROUGH TIGHT SPOTS UTILIZING TOP DRIVE FOR SO WEIGHT W/NO ROTATION/CIRCULATION WIPE TIGHT SPOTS CLEAN AND MINIMIZE HAVING TO WASH/REAM.;WORKED THROUGH TIGHT SPOTS F/1780'-1808', 1966-2060',&2164'.TIH ON ELEVATORS F/2164'-3250'. ATTEMPT TO WORK PAST 3250'.;WASH/REAM F/3250'-3266'@ 300 GPM,50 RPM.;TIH ON ELEVATORS F/3266'-4420'. ATTEMPT TO WORK PAST 4420'(UG COAL 2)ENCOUNTER 30-35K OVER PULL,COULD NOT SLACK OFF.;MU TD WASH OOH F/4420'TO HIGH KELLY W/NO ISSUES.BRING ON ROTARY,WASH/REAM F/4420'-4515'@ 300 GPM,50 RPM,5-8K TQ.WASH OUT TO HIGH KELLY,KILL ROTARY&PUMP,RIH PAST 4420'W/NO ISSUES.;TIH ON ELEVATORS F/4515'-4796', WASH&REAM LAST 3 STDS TO BTM F/4796'-5071'@ 600 GPM,2370 PSI,8-10 TQ,150K PU,100K SO,120K ROT.;DRILL 12 1/4"HOLE SECTION F/5071' to 5172' (101')AROP 34 FPH. 626 GPM, 2500 PSI ON, 2310 PSI OFF,80 RPM,11-12K TQ ON,8-10K TQ OFF,PU 167K,SO 106K,ROT 128K,WOB 15-20K.;MW IN 9.3 MW OUT 9.35, ECD 10.15 PPG,VIS IN/OUT 167/194.WATER ON @ 20 BPH,BOTH CETRIFUGES AND MUD CLEANER RUNNING. PUMP 35 BBL HI VIS SWEEP W/7.5 PPB WALNUT AND CONDET @ 5110'.;ROTATE AND RECIPROCATE.SWEEP BACK 300 STKS EARLY,HOLE UNLOADED,300%INCREASE OF 80%SAND,10%CLAY AND 10%FLAT PIECES OF COAL 1/2"IN SIZE.CIRCULATE HOLE CLEAN;DRILL 12 1/4"HOLE SECTION F/5072'to 5644' (572')AROP 191 FPH. 627 GPM, 2430 PSI ON, 2360 PSI OFF,80 RPM,11-12K TQ ON,8-10K TQ OFF,PU 172K,SO 105K,ROT 130K,WOB 15K.;MW IN 9.3 MW OUT 9.4,ECD 10.09 PPG,VIS IN/OUT 118/180.WATER ON @ 30 BPH,BOTH CETRIFUGES AND MUD CLEANER RUNNING. .26 SLIDE HRS,3.44 ROTATE HRS;LAST SURVEY @ 5599.98'MD,3424'ND,INC 63.34,AZ 210.23,DISTANCE TO PLAN 0.19'HIGH,1.03' RIGHT.;ROTATE,RECIPROCATE.CBU,CLEANUP WELLBORE.BLOW DOWN TD.FLOWCHECK WELL,STATIC;PUMPS OFF P/U 177K,S/O 105K,PULL WIPER TRIP FROM 5644'TO 4600',TIGHT @ 5365',ATTEMPT TO WORK THRU SEVERAL TIMES,PUMP OUT FROM 5365'TO 5356',PASS BACK THRU, CLEAN.;CONTINUE TO PUMP OUT F/5345'TO 4875'DUE TO 20-30K DRAG POH.PULL ON ELEVATORS F/4875'TO 4600'WITH NO OTHER ISSUES.;BLOW DOWN TD,TIH ON ELEVATORS F/4600'TO 5552'WITH NO ISSUES.M/U TD,FILL PIPE,LOAD 35 BBL HI VIS SWEEP IN PIPE, WASH/REAM LAST STD TO BTTM @ 5644'.NO FILL, CORRECT DISPLACEMENT ON TRIP IN.;;-Hauled 517 bbls to G&I,Total Hauled 3653 bbls -Hauled 310 bbls to B-50,Total Hauled 585 bbls -Hauled 0 bbls to ORT,Total Hauled 0 bbls -Hauled 0 bbls from 6m Lake,Total Hauled 1438 bbls;-Hauled 481 bbls from L-Pad Lake,Total Hauled 1533 bbls 1/25/2016 CONT.TIH REAMING LAST STD TO BTM WITH NO FILL @ 5646'. CIRC HI VIS SWEEP TO SURFACE WITH NO SUBSTANTIAL CHANGE OF CUTTING INCREASE.500 GPM/1560 PSI,80 RPM/11-13K TQ,PU 177K,105 SO, 131 ROT.;DRILL 12 1/4"HOLE SECTION F/5646'to 5930' (284')AROP 63 FPH. 629 GPM, 2160 PSI ON, 2080 PSI OFF,80 RPM,13-14K TQ ON,12-13K TO OFF,PU 188K,SO 100K,ROT 136K,WOB 5-10K.;MW IN 9.3 MW OUT 9.4, ECD 9.92 PPG,VIS IN/OUT 103/116.WATER ON @ 20 BPH,BOTH CENTRIFUGES AND MUD CLEANER RUNNING.;DRILL 12 1/4"HOLE SECTION F/5930' to 6351' (421')AROP 70.6 FPH. 623 GPM, 2170 PSI ON, 2160 PSI OFF,80 RPM,13-14K TQ ON, 12-13K TQ OFF,PU 190K,SO 101K,ROT 137K,WOB 10-20K.;MW IN 9.3 MW OUT 9.4, ECD 9.92 PPG,VIS IN/OUT 103/116.WATER ON @ 20 BPH,BOTH CENTRIFUGES AND MUD CLEANER RUNNING.;DRILL 12 1/4"HOLE SECTION F/6351' to 6587' (236')AROP 59 FPH. 638 GPM, 2270 PSI ON, 2160 PSI OFF,80 RPM,13-14K TQ ON, 12-13K TQ OFF,PU 190K,SO 101K,ROT 137K,WOB 10-20K.;MW IN 9.3 MW OUT 9.5, ECD 10.02 PPG,VIS IN/OUT 141/195.WATER ON @ 30 BPH,BOTH CENTRIFUGES AND MUD CLEANER RUNNING.;PUMP SURVEY,PUMP OUT OF THE HOLE 600 GPM,2100 PSI F/6587'TO 5600'WITH NO ISSUES.LOAD SWEEP IN PIPE.;PUMP 35 BBL HI VIS SWEEP W/7.5 PPB WALNUT AND CONDET @ 500 GPM, ROTATE 80 RPM WORKING PIPE.SWEEP BACK 300 STKS EARLY,75%INCREASE SAND,SOME CLAY. BLOW DOWN TD.;TIH ON ELEVATORS F/5600'TO 6306',M/U 3 STDS HWDP F/PUSH PIPE.WASH AND REAM LAST STD TO BTTM AT 6587',NO FILL. CORRECT DISPLACEMENT ON TRIP IN.;DRILL 12 1/4"HOLE SECTION F/6587'to 6750' (163')AROP 47 FPH. 550 GPM, 1980 PSI ON, 1850 PSI OFF,80 RPM,13-14.5K TQ ON, 12-13K TO OFF,PU 200K,SO 100K,ROT 14K,WOB 10-20K.;MW IN 9.3 MW OUT 9.4, ECD 9.91 PPG,VIS IN/OUT 101/158.WATER ON @ 30 BPH,BOTH CENTRIFUGES AND MUD CLEANER RUNNING. NO LOSSES.;LAST SURVEY @ 6635'MD,3864'ND,INC 67.46,AZ 169.22,DISTANCE TO PLAN 2.15'LOW,19.71'RIGHT. 7.75 SLIDE HRS,2.27 ROTATE HRS.;-Hauled 696 bbls to G&I,Total Hauled 4349 bbls -Hauled 0 bbls to B-50,Total Hauled 585 bbls -Hauled 0 bbls f/6m Lake,Total Hauled 1438 bbls -Hauled 802 bbls f/L-Pad Lake,Total Hauled 2335 bbls. 1/26/2016 DRILL 12 1/4"HOLE SECTION F/6750'to 7023' (273')AROP 45 FPH. 620 GPM, 2250 PSI ON, 2150 PSI OFF,80 RPM,17-19K TQ ON, 15-18K TQ OFF,PU 209K,SO 106K,ROT 145K,WOB 20-27K.;MW IN 9.3 MW OUT 9.3, ECD 9.91 PPG,VIS IN/OUT 101/158.WATER ON @ 20 BPH,BOTH CENTRIFUGES AND MUD CLEANER RUNNING. NO LOSSES.;DRILL 12 1/4"HOLE SECTION F/7059'to 7330' (271')AROP 46 FPH. 600 GPM, 2140 PSI ON, 2080 PSI OFF,80 RPM,15-19K TQ ON, 17-18K TQ OFF,PU 210K,SO 105K,ROT 149K,WOB 20-27K.;MW IN 9.3 MW OUT 9.3, ECD 9.91 PPG,VIS IN/OUT 101/158.WATER ON @ 20 BPH,BOTH CENTRIFUGES AND MUD CLEANER RUNNING. NO LOSSES.;DRILL 12 1/4"HOLE SECTION F/7330'to 7529'(199')AROP 33 FPH. 620 GPM, 2450 PSI ON, 2340 PSI OFF,80 RPM,15-19K TQ ON, 14K TQ OFF,PU 205K,SO 103K,ROT 148K,WOB 25K.;DRILL 12 1/4"HOLE SECTION F/ 7529'to TD @ 7672'(143')AROP 72 FPH. 630 GPM, 2540 PSI ON, 2400 PSI OFF,80 RPM,15-19K TQ ON, 14K TO OFF,PU 207K,SO 105K,ROT 148K,WOB 25K.;MW IN 9.4 MW OUT 9.6,ECD 10.13 PPG,VIS IN/OUT 92/142.WATER ON @ 20 BPH,BOTH CENTRIFUGES AND MUD CLEANER RUNNING. NO LOSSES.;Circulate and condition hole @ TD(7672'MD/4096'TVD). Formation tops came in+/-20'low from expected. Pump @ 612 gpm,2340 psi,46% flow,80 rpm,14k tq. Pump 35 bbl hi vis sweep w/50%inc.;ECD's decreased to 10.00 EMW post cleanup cycle. Saw sweep back 1000 stks early and was strung out to on time stks.;Monitor well(static). Pump out of hole Fl 7672'-T/6388. 207k up,105k dn,600 gpm,2230 psi,44%flow w/no rotary. Pulled clean with no issues.;LAST SURVEY @ 7626'MD,4090'ND,INC 82.83°,AZ 124.11°,DISTANCE TO PLAN 25'LOW,1'left. Projected 85.5°Inc @ bit. 1/27/2016 Continue to Pump out of hole F/6388'-T/5350'.Pumping 600 GPM w/1780psi FCP @ 5350'.;Circ and condition pumping hi vis sweep to surface,rotate, reciprocating pipe from 5360'to 5300'w/25%increase in cuttings.;POOH on elevators from 5300'to 4460'with no issues. Encounter 25K drag at 4040'(TVD 2901'UG 2 Coal).Work through on elevators and wipe clean.;Continue TOH to 3290'.Encounter 25K drag.Work through and wipe clean on elevators. Continue to TOH on elevators to 2290'.Encounter tight spot.;Wipe tight spots clean on elevators from 2290'-2225'and 2100'-2033'(Base of Perm Frost). TOH to 272'with no issues. Hole fill took 30 bbls over calculated.;Slip and cut 68'drill line.Inspect Saver Sub.;Continue L/D BHA#2. L/D NM DC's,Download MWD,B/O bit, drain mtr(flush),LID MWD and Mtr. BHA had moderate balling with no damage to tools noted. Bit graded a 1,2,WT,G,E,1,NO,TD;Bit pics are located in"0" drive.;Clean and clear tools from rig floor. Prep for R/U. Bring centralizers to floor.;Drain stack,pump out cellar. Flush stack,M/U wear bushing retrieving tool. Made several attempts before success retrieving wear bushing(flush cuttings from wear bushing).Clean and lay down same.;R/U 250T 9 5/8"side doors. M/U hanger to landing jt. RIH and landout on depth as per Cameron Rep(Greg Ruge). L/D hgr and landing jt.;Continue rigging up casing equipment. M/U Volant CRT. Rig up bail extensions to drilling bails,250T side doors,false bowl w/hand slips. Size up rig tongs and safety clamp. Prep Centralizers;PJSM,Run 9 5/8", L-80,TC II,40#as per detail. M/U shoe track and bakerlok connections. Flashlight shoe track and check floats(good). Verify bfl bypass plate installed(Glen Fisher).;Continue run casing as per detail to 160'MD.;Hauled 844 bbls(114 bbls cuttings,730 bbls mud) to G&I for total=6111 bbls Hauled 0 bbls to B-50 for total=900 bbls Hauled 0 bbls F/6 mi lake for total=1718 bbls;Hauled 454 bbls F/L-Pad lake for total=3061 bbls Daily losses downhole=0 bbls for cumulative losses 0 bbls. A1/28/2016 Continue to run 9 5/8',40#,L-80, asing f/160'to 2577'.MU Csg to 12,600 fUlbs TQ.RIH @ 45 fp 6-1729',reduce running speed to 30 fpm f/1729'- 2536'.Losses @ 21 bbls.MW out @ 9.8.;Circulate bottoms up plus casing volume f12536',staging pump rate to 6 bpm with 180 psi,150K PU,95K SO.MW 9.3 in,9.8 out @ start of circulation.Circulate until 9.4 MW out.;Continue to run 9 5/8',40#,L-80,TC II Casing f/2577'to 5124'with no issues.PU Halliburton ES CMTR w/HES Rep,verify 6 pins set @ 3300 psi shear.Thread lock connection.;Continue to run casing to 5412'with no issues.;Circulate lx csg vol @ 5412'MD. Reciprocate pipe staging up to 6 BPM,300 FCP,27%flow 235k up,85k dn. Saw slight losses while staging up. No losses at end of clean up cycle.;Continue running 9-5/8",40#,L-80,TC II casing F/5412'to 7623'MD. Had to work casing down,floating in last 1000'. 81 bbl loss for total trip in(includes losses for circulating).;P/U and M/U hanger w/landing jt. Landout on depth 7661'MD. Stage pumps up-3 bpm,690psi,13%flow. 4 bpm,420 FCP,31%. 270k up,97k dn. Recip pipe.;Rig down CRT and L/D same. Blow down topdrive. Install bypass plug in drop plug head(witnessed by Shane Barber/Glen Fisher). R/U cmt head. blowdown cmt line to cmt truck from floor.;Mud came back with a 9.7 and 800+vis @ 52°temp. Conditioned mud to 19 YP,9.3 MW,62 vis. Staging up to 6 BPM,430 psi,25%flow. Parked string,landed out on depth w/42k string wt in wellhead.;No losses noted for FCP @ 6 BPM. Transfer excess mud from pits to tank farm,Rig up Halliburton cementers,PJSM.;Hauled 496 bbls to G&I for total=6602 bbls Hauled 530 bbls to B-50 for total=1430 bbls Hauled 0 bbls from 6 mi lake for total=1718 bbls Hauled 1050 bbls from L-Pad for total=4111 bbls;21 bbl daily downhole losses for total=21 bbls. 1/29/2016 Continue to circulate @ 6 bpm,310 psi while transfer excess mud from pits to tank farm,Rig up Halliburton cementers.;Hold PJSM with all personnel involved in cementing operation.;Attempt to PT cement lines.Could not get more than 50-80 gpm of water from up right tank to cement unit.Disconnect CMT Unit from tank, tie in to Vac Truck with same results.;Investigate unit and found valve stem on actuated butter fly valve to transfer pump had sheared,partially opening butter fly valve.Replace valve.Prime up and transfer water with no further issues.;Perform cmt job as follows: Pump 10 bbls FW,Pressure test lines to 3500 psi,Pump 60 bbls of spacer at 10.5 ppg @ 4 BPM. Drop by pass plug w/last 2 bbls spacer.;Shut down and load shut off plug. Mix and pump 145 sxs(331 bbls)(1858 ft)of class G Lead cement at 12 ppq. Mix and pump 390 sxs(79 bbls)(449 ft)of class G Tail cement at 15.8 ppg.;Drop Shut off Plug with last 2 bbls cement.;Displace cmt w/20 bbls FW f/Cmt Unit, turn over to rig,pump 322 bbls,9.4 ppg Mud,pump 80 bbls FW f/cmt unit,turn over to rig,pump 152 bbls Mud. Bump plug with 500 psi over final circulating.;Spacer back to surface @ 422 bbls into the 574 bbl displacement.Circulated 60 bbl spacer and 102 bbls Cement to surface prior to bumping the plug.;Bump and hold 1600 psi for 5 min. Bleed off 3.3 bbl.Using rig pump,stage pressure up 2770 psi and shear open ES Cementer.;lst Stage Details: Full returns through out job. Pump Cement @ 5 BPM Average. Pump Displacement @ 5.5 BPM Average.Calculated Displacement 574 bbl,Actual Displacement 574 bbl.;Check floats.Held with 3.2 bbls back to pits.Total cement circulated to surface 242 bbl+60 bbl spacer.Final lift pressure 1070 psi @ 3 bpm.No Losses during job. Cement In Place @ 15:23 hrs;Circulate bottoms up from ES Cementer @ 2535'bringing 142 bbls of cement to surface.Continue to circulate through Stage Tool @ 6 bpm,590 psi while prepping for 2nd stage Cement job.;Had to clean residual cmt from pit 1. Offload thick mud to tank farm. Prep pits for cmt job. Wait for supersucker to return from G&I.;Perform cmt job as follows: Pump 10 bbls FW,Pressure test lines to 3500 psi,Pump 60 bbls of spacer at 10.5 ppg @ 4 BPM.;Mix and pump 402 sxs(310 bbls)(1740 ft)of Perm L Lead cement at 10.7 pps pumped @ 4 BPM Mix and pump 265sxs(55.3 bbls)(310 ft)of class G Tail cement at 15.8 ppg pumped @ 4.3 BPM;Drop plug last 2 bbls cmt.Displace with 20 bbls water.Turn over to rig.Displace 172 bbls(calculated same)(4 BPM)with rig.No bump.Shut dn.Ramp up pump twice and bump 2nd attempt.450 FCP;Psi up 800 then 1350 saw tool shift.Continue psi up to 2000 psi w./5 min hold. Bleed off psi(2 bbls back)with no flow. R/D cmtrs. Saw spacer @ 196 bbls cmt pumped w/all to surface.;Saw cmt returns to surface @ 236 bbls cmt pumped(lead). Pumped 310 bbls lead then pumped tail w/a Intal of 275 hhie rmt rphimPd to eurfare, CIP @ 03:30.;L/D cmt head. Rack out cmtrs. Drain stack. Having trouble breaking out landing jt. Cameron Rep onsite(Greg Ruge). Continue working on breaking out landing jt.;Hauled 965 bbls to G&I for total=7572 bbls Hauled 0 bbls to B-50 for total=1430 bbls Hauled 0 bbls 6 mile for total=1718 bbls Hauled 392 bbls from L pad Ik=4503 bbls 1/30/2016 Continue working on breaking out landing jt.MU CRT and attempt to back out land jt @ 28,000 fUlbs TQ.Use rig tongs to back out land joint.Land jt broke loose @ 40'000 fUlbs.L/D land jt.;Clear rig floor of csg run tools.Clean surface equipment in pits.Remove riser,N/D Pitcher nipple.Clean CMT from Diverter Bag flutes.Remove diverter lines.L/D 20"riser nipple from cellar.;Continue functioning Annular cleaning cmt debris from flute.N/D Knife Valve,N/D Diverter Adapt flange.SIM-OPS:Clean mud pits,load DS-50&NC-50 DP in pipe shed.;PJSM w/Cameron Rep.Install pack off,N/U Tubing Spool and multibowl 11"5M wellhead. Test packoff 600 low w/5 min hold(good)and 3000 high w/15 min hold(good).;Nipple up BOP equipment. Install riser,flowline,and 4 pt stack. Hook up koomey lines,charge koomey. Inspect lines.RKB-LLDS=32.93',RKB-ULDS=30.44';C/O saver sub.;Test BOP equipment. Upr rams dressed w/2- 7/8"x 5",Middle rams dressed w/blinds, Lwr rams dressed w/5"fixed bodies. AOGCC rep Matt Herrera witness test.;Shell test BOP. Address several leaks and re-shell test(good).Test BOP components 250/3000 w/5 min hold. Chart and record same.Test annular 250/2500 w/5 min hold.;Hauled 1021 bbls to G&I for total=8593 bbls Hauled 0 bbls to B-50 for total=1430 bbls Hauled 0 bbls F/6 mi lake for total=1718 bbls Hauled 226 bbls F/L pad lake for total=4503 bbls 1/31/2016 Continue to test BOPE to 250/3000 psi.Test gas alarms.Test Witnessed by Matt Herrera with the AOGCC.All test pass.No issues.R/D test equipment.Blow down choke/kill line,choke manifold.;lnstall wear bushing.RILDS x 4.Stage BHA components and geo pilot HP iron on rig floor.;PU Clean Out BHA:8.5",HDBS, Tircone Bit,6 3/4"Straight motor,3-NM Flex Collars,1-jt HWDP,Jars,1-jt HWDP. TIH w/HWPD f/Derrick.TOH L/D 15 jts excess HWDP. Total C/O BHA=215.21';TIH with C/O assy on 5"DP f/derrick to 2477'.;Condition and shear out mud prior to drilling ES CMTER,staging pumps to 550 gpm w/1180 psi.;Tag soft cement @ 2514'.Obtain parameters,PUW 110K,SOW 85K,Rot 100K,RPM 40,Free TO 4K, WOB 5-15 w/5-7 TQ. Drill cement&closing plug @ 2537'.Drill EZ Cmtr @ 2540.Fell through @ 2543'.;Wash/ream down to 2572'.;Close Annular and PT across ES Cementer to 1600 psi for 5 minutes with no bleed off.CBU from 2572'1400 stks,500 gpm,900 psi.Blow down Top Drive.;Continue trip in hole out of derrick F/2572'-T/7542'MD. Fill pipe and break circulation to help clean up cold spud mud from wellbore.;Circulate and condition mud @ 7542'MD. Stage pumps up to 11 BPM,1280 psi,42%flow,20 rpm,16k tq. 9.5 MW.;R/U casing test equipment. Test 9-5/8",L-80,40#casing. Pump a total of 6.6 bbls @ 3/4 min to a final psi of 3150 psi. Shut in and hold 30 min w/ final psi @ 3050 psi(Pass).;Wash/Ream down F/7542'-T/7577'MD(tagged BFL on depth). Drill shoe track w/good cmt F/7577'-T/7672'MD. Tagged top of BFL(7576'),FC(7616')and FS(7658')on depth.;Drilled shoe track w/5-15k wob,8-11 BPM,950 psi,40 rpm,18k tq,46%flow. Moderate stalling and psi spikes while drilling shoe. Work clean.;Unable to displace on the fly due to slow mud transfer rate to tank farm. Pickup into shoe for displacement.;Displace 8.9 ppg spud mud to 8.75 ppg Baradrill"N". 406 gpm,1080 psi,50 rpm,17.5k tq.;Hauled 285 bbls to G&I for total=8878 bbls Hauled 0 bbls to B-50 for total=1430 bbls Hauled 0 bbls F/6 mi lake for total=1718 bbls Hauled 238 bbls F/L-Pad for total=4741 bbls 2/1/2016 Continue Displace 8.9 ppg spud mud to 8.75 ppg Baradrill"N". 406 gpm,1080 psi,50 rpm,17.5k tq.Clean Dirty pits after displacement.;Drill 20'new formation from 7662 to 7692'.542 gpm,1410 psi,15-20 WOB,15 TQ,60 PM.;Pull up into casing.Had to wash/ream through FC several times,with 30K over pull before pulling clean.;Perform FIT to 12.0 ppg.Target Pressure of 685 psi. Shoe @ 7663'MD,4095'TVD,Test MW 8.8.;TOH on elevators from 7650'.225K PUW,95K SOW.;Work BHA standing back NM Dc,s and HWDP w/jars.Break off bit&UD straight motor.;PJSM,M/U 8.5"Rotary steerable assembly(BHA#4)as per HES directional. M/U smart tools w/8.5"PDC,RIH w/flex DC's,HWDP w/jars(BHA length=268.6').;Shallow Pulse test MWD and test downlink to Geo-Pilot. MWD (test good)but Geo-Pilot test inconclusive due to shallow test depth. Decision made to trip in and re-test @ 2,500'MD.;Shallow test @ 400 gpm/500 psi/32% flow, 450 gpm/620 psi/34%flow, 500 gpm/770 psi/36%flow. Blowdown TDS post test.;Trip in hole F/268'-T/1210'MD w/singles from pipeshed. 5"NC-50. 98k P/U,93k S/O;Trip in hole F/1210'-T/2529'MD out of derrick with remaining 14 stds of NC-50 drill pipe. 115k P/U,98k S/O.;Fill pipe and re-test Geo-Pilot downlink(test good)@ 2529'MD. Test w/550 gpm/1090 psi/36%flow, 600 gpm/1220 psi/38%flow. 107k Rot @ 30 rpm w/3k tq.;Single in F/2529'-T/4039' MD. 150k P/U,9k S/O.;Continue single in F/4039'-T/7058'then RIH out of derrick T/7525'MD. Hole showed 4 bbl loss for total trip.;Cut and slip 49'of drilling line. Service rig.;Hauled 1217 bbls to G&l for total=10095 bbls Hauled 0 bbls to B-50 for total=1430 bbls Hauled 0 bbls from 6 mi lake for total=1718 bbls Hauled 166 bbls from L-pad lake for total=4907 bbls 2/2/2016 Service TD&Blocks. RIH F/752 655'.Establish parameters and take SPRs. #1-30/40 260/31080/320;Drilling Ahead F/7692'T/8179' 487' @ 57 fph ay.100-200 fph when not on concretions. 5-10 WOB,18K TO,80-100 RPM 507 GPM,@ 1425 PSI UP/DN 230/190K;Attempt to bring RPM up to 150.Getting lots of down hole vibration and pipe beating the well head. Try different parameters.Same result.The more RPM the harder the pipe hits.;Take SPRs @ 8090'. 30/40 stks#1 260/320#2 40/320;Service top drive and drawworks.;Drilling ahead F/8179'-T/8471' MD/4128'TVD 294'@ 84 fph ay. 525 gpm,1520 psi on,1420 psi off,39%flow,100 rpm,20k tq on,19k tq off,10.03 ECD,242k P/U,135k rot,80k S/0;8'right of plan and in zone(7'below top of 0A3)matching dip @ 89.3 ABI. Quadco repaired TOTCO gas sensor. Found a leak in vac line to sensor.;Lost detection with MWD. Troubleshoot,discuss with Sperry in town w/no success. Mode switch,C/O transducers,surge pumps to clear any debris-No success.;Saw no change in parameters when detection was lost.;TOH F/8471'-T/7529'MD. Saw slight overpull when entering shoe. 225k up,77k dn.;Attempt another mode switch as recommended by Sperry Town while inside shoe-no success.;Pump Dry job,Slowdown TDS and continue TOH F/7529'-T/BHA.;Monitor well(static),Std back HWDP w/jars,Flex DC's and UD MWD. Hole took calculated displacement for trip out.;B/O and visually inspect MWD tools/Laydown same. No visual damage noted. Bit grade=1,1,CT,G,X,I,NO,DTF. Download showed intermittent bus fault but no insight to pulser failure. Replace all MWD.;P/U backup MWD tools and make up same for BHA#5. Re-run bit and geo-pilot as per Sperry recommendations.;Daily losses to formation=0 bbls Cumulative losses to formation=21 bbls;Hauled 597 bbls to G&I for total=10692 bbls Hauled 190 bbls to B-50 for total=1620 bbls Hauled 0 bbls from 6 mi lake for total=1718 bbls Hauled 273 bbls from L-lake for total=5180 bbls 2/3/2016 Finish M/U BHA#5. Run Same bit&Geo pilot.Replace all MWD. Shallow pulse test. GOOD.;RIH T/5925'.P/U 15 joints of HWDP. Had to clean out dried mud from HWDP.Drift getting stuck.RIH F/6393'T/7662'. Test Tools.Good. RIH T/8374'.Establish parameters. Wash down @ 500 gpm.;Mad pass as per GEO @ 200 FPH,525 gpm,100 rpm,F/8450'T/8471'.;Drill ahead F/8471'T/8715'. 244'@ 120 fph average 3-8 WOB, 18K TQ 80-120 RPM. 500 GPM@ 1450 PSI MW 8.8 in and out vis 40.;Adjusting parameters to eliminate pipe vibration and wobble.Slow RPM to 40 and bring up slowly to keep drilling smooth.;Drlg ahead F/8715'-T/8940'MD,4135'TVD.38 ft/hr avg rop,525 gpm,1620 psi on,1600 psi off,40%flow,100 rpm,21k on,20k off,9.71 ECD's,240k P/U,90k S/O,140k ROT.;Drlg ahead F/8940'-T/ 9465'MD,4137'TVD. 88 ft/hr rop avg,562 gpm,1770 psi on,1740 psi off,40%flow,100 rpm,21k on,20k off,9.98 ECD's,240k P/U,90k S/O,140k ROT.;0 losses to formation for total=21 bbls;Hauled 240 bbls to G&I for total=10932 bbls Hauled 0 bbls to B-50 for total 1620 bbls Hauled 0 bbls from 6 mi lake for total=1718 bbls Hauled 321 bbls from L-Pad for total=5501 bbls 2/4/2016 Drill ahead F/9465'T/9736. 271'@ 45 fph average 3-14 WOB, 22K TQ 80-110 RPM. 600 GPM@ 2100 PSI MW 8.8 in and out vis 40.ECD 10;Using best drilling practices on concretions. Drill staging up wt.After reaching 14K WOB it drills about 20-30 FPH.;Drill ahead Fl 9736 T/10117'. 381'@ 63 fph average 3-14 WOB, 18K TQ 100 RPM 600 GPM@ 2200 PSI MW 8.8 in and out vis 40.ECD 10;Finish strapping and tallying the Slotted liner.Bring in 9 joints of HWDP to pick up on a short trip.;Drill 8.5"production hole F/ 10,117'-T/10,764'MD(108'rop avg). 550 gpm,1920 psi on,1900 psi off,40%flow,92 rpm,21k tq on,19k tq off,10.5 ECD's.270k P/U,62k S/0,140k Rot.;Drill 8.5"production hole F/10,764'-T/11,013'MD(42'rop avg).520 gpm,1720 psi on,1700 psi off,40%flow,92 rpm,22k tq on,20k tq off,10.40 ECD's;Unable to obtain S/O wts with no rotary std#108. Run out of string wt slacking off. Continue drilling ahead without obtaining S/O wts @ connections.;Pump low vis/hi wt(25 bbl ea)tandem sweep while drilling on concretion @ 10957'to reduce ECD's. 504 gpm/10.44 ECD's before sweep,520 gpm/10.4 ECD after;Sweep brought back moderate increase in very fine cuttings(beds).;Currently located 10'TVD from top of 0A3 sands(100%in zone for lateral thus far)and 30'right of plan.;Daily losses to formation 0 bbls for total=21 bbls;Hauled 674 bbls to G&I for total=11606 bbls Hauled 0 bbls to B-50 for total=1620 bbls Hauled 0 bbls from 6 mi lake for total=1718 bbls Hauled 476 bbls from L-Pad lake for total=5977 bbls 2/5/2016 Circ hole clean @ 600 gpm 2.5 btm up. Monitor well.Static.ECDs 10.5;POOH F/11013'T/7665'.Pulling 30-50 K over.Hole not taking correct hole fill. Pump out of the hole @ 500 gpm. Decide to Pull one and pump one out.Pulling 30-50 K over;Pull in to the shoe hard 60 K over. Kelly up and back ream through the shoe.GOOD.;CBU @ 500 gpm,80 rpm. Getting lots of cuttings for the first btm up. Clean after. Monitor well.Static.;POOH T/HWDP/6000'.Stand back 5 stands of HWDP.RIH with 5"DP to shoe @ 7662'.;Service rig,Slip&cut Drilling line.;RIH from 7662'T/11013'MD. TIH on elevator to 9062'before losing all string wt. Kelly up F/9062'T/10826'. Rotate slowly @ 5 rpm as needed tripping in.;Wash down last 2 stds F/10826'-T/11013'MD. 40 rpm,22k tq,450 gpm, 1740 psi,37%flow.;Drill ahead Geosteering F/11013'-T/11,390'MD. 584 gpm,2225 psi on,2170 psi off,37%flow,98 rpm,21.4k tq on,19k tq off,10.6 ECD's.;B/U max gas 4414 units.We are currently assessing geoligical structure. Possible fault crossed @ 11,160'(Discuss with town).3.4'right of plan. Waiting on new correlation.;Daily losses to formation 0 bbls for total=21 bbls;Hauled 58 bbls to G&I for total=11664 bbls Hauled 0 bbls to B-50 for total=1620 bbls Hauled 0 bbls from 6 mi lake for total=1718 bbls Hauled 226 bbls from L-Pad lake for total=6203 bbls 2/6/2016 Drill ahead Geosteering F/11,390' T/11556'MD. 584 gpm,2225 psi on,2170 psi off,37%flow,98 rpm,21.4k tq on,19k tq off,10.6 ECD's.;Decide the fault was overthrow of 60'. Plan side track @ 11069'.;POOH F/11556'T/11069'.30-40k over pull. Pull 2 stand and pump out due to improper hole fill.LD top single to make working room to trough.;Drill ahead @ 30FPH,-149 L F/11069'T/11099'. Drill ahead @-149 L F/11099'T/11112'@ 10fph. 600 gpm,100 rpm.,2450 psi, Dropping angle To 83 deg to hold.;Drill ahead F/11099'T/11365'. Found top of OA @ 11365'. Begin building angle to 85 deg. Drill ahead F/11365'T/11575 @ 500 gpm, 1922 psi,110 rpm,22 tq, Hitting concretions.;Drill 8.5"production hole geo-steering F/11,575'-T/ 11872'MD. 550 gpm,2260 psi on,2240 psi off, 37%flow,110 rpm,25k tq on,22k tq off,255k P/U,145k rot,10.53 ECD's.;Drill 8.5"production hole geo-steering F/11,872'-T/12144'MD. 502 gpm,1870 psi on,1860 psi off,36%flow,110 rpm,25k tq on,22k tq off,255k P/U,145k rot,10.30 ECD's.;lncrease MW F/8.9 ppg to 9.0 ppg. Plan to increase to 9.1 ppg @ TD prior to tripping out of hole. Last correlation showed us 10'below top of 0A3 and 40'left.;Daily losses to formation 0 bbls for total=21 bbls;Hauled 754 bbls to G&I for total=12418 bbls Hauled 0 bbls to B-50 for total=1620 bbls Hauled 0 bbls from 6 mi lake for total=6713 bbls Hauled 510 bbls from L-Pad for total=6713 bbls 2/7/2016 Drill ahead Geosteering 8.5"produholeF/12144'-T/12428'MD. 500 gpm,1960 psi on,1940 psi %flow,110 rpm,26k tq on 24k tq off,10.47 ECDs.;Drill ahead Geosteering 8.5"production hole Fl 12428'-T/12995'MD/4158'TVD(TD). 550 gpm,2340 psi on,2300 psi off,37%flow,110 rpm,26k tq on 24k tq off,10.56 ECDs.;TD'd at base of 0A3. 320k P/U,140k Rot,55k S/0. Obtain final svy before starting cleanup cycle.;Circulate and condition hole @ TD 12,955'MD. Rot and recip pipe,590 gpm,2440 psi,38%flow,110 rpm,25k tq,310k P/U,135k Rot,55k S/O,10.54 ECD's w/9#MW.;Shut down and work pipe prior to cleanup cycle for 10 mins. Saw no correlation between connections and previous gas spikes. (gas spikes/cuttings gas);Pumped tandem hi wt/lo vis sweep with slight increase in cuttings. 200 stks late. Circulated 3x btms up.;Monitor well(static). Backream out of hole F/12,995'-T/11580'MD. 500 gpm, 1990 psi,36%flow,80 rpm,23k tq. No issues.;Continue backreaming F/11,580'-T/11,014'MD. Same parameters as above. Saw slight increase in drag and packing off when pulling BHA past sidetrack point.;TIH F/11014'to 11,080 with no pumps and 10-15 rpm slowly past sidetrack point. Tripped clean. Shut off rotary and continued tripping in slowly as hole allowed T/11290'MD.;275k P/U,75k S/O. Check shot svy @ 11221',83.32°Inc and 118°Az). Confirmed no issues entering sidetrack while tripping.;TOH on elevators F/11,290'-T/11,014'MD,Continue backreaming out of hole F/11,014'-T/8850'MD.520 gpm,1600 psi,36%flow,80 rpm,19k tq. No issues.;TD @ base of 0A3(4148'TVD)and 3'left of plan. Daily losses to formation 15 bbls for total=36 bbls;Hauled 454 bbls to G&I for total=12872 bbls Hauled 0 bbls to B-50 for total=1620 bbls Hauled 0 bbls from 6 mi lake for total=1718 bbls Hauled 512 bbls from L-pad for total=7225 bbls 2/8/2016 Continue backreaming out of hole F/8850'-T/7624'MD.500 gpm,1400 psi,35%flow,80 rpm,14k tq. No issues.;Circulate and condition hole @ 7624'MD. 600 gpm,1900 psi,120 rpm,15k tq. Shut down monitor well(static). Blow down TDS and geo skid.;Re-arrange HWDP in derrick for upcoming liner run.;TOH on elevators F/7624'-T/927'MD.;POOH laying down F/927'-T/BHA. L/D jars,DC's,Download MWD then B/O laydown same. B/O bit(graded= 3,2,CT,S,X,I,NO,TD). L/D geo-pilot.;Change over to completion AFE @ 18:00 hrs. Daily losses to formation 21 bbls for total=57 bbls. 870 bbls 2%KCL brine on location for upcoming displacement;Hauled 302 bbls to G&I for total=13174 bbls Hauled 0 bbls to B-50 for total=1620 bbls Hauled 0 bbls from 6 mi lake for total=1718 bbls Hauled 190 bbls from L-Pad for total=7415 bbls Hilci Energy Company CompositSeport Well Name: MP L-47 Field: North Slope County/State: ,Alaska i(LAT/LONG): evation(RKB): 33.86 API#: Spud Date: 1/21/2016 Job Name: 1511125C MP L-47 Completion Contractor AFE#: 1511125C AFE$: $1,155,100 Activity Date Ops Summary 2/8/2016 Bring tools to rig floor. M/U pkr assy w/swivel on top and pup on btm(stand back same). M/U 5"safety jt as follows from pin up(XO,single jt 5"DP,TIW,XO and 5'handling pup). TIW—Open,Rig up Weatherford casing w/double stack tongs. Work on double stack power tongs(1 hr). Unable to get directional cam lever to move(inoperable). Lay down and pickup single stack power tongs.,PJSM, Perform shut in drill with 5"safety joint as per AOGCC. L/D safety joint. Run 5.5",P-110,17#,DWC/C slotted liner as per detail. M/U shoe and check float(good). RIH F/surface to 4247'MD. Slight seepage of.5 bph while running. 2/9/2016 P/U 5 1/2 slotted completion F/4274'T/5553'. P/U extra joint&set liner in an up wt.UD Extra joint. UP/DN 120/80,R/U 2 7/8 Equipment.P/U Slick stick and 2 7/8 fox tubing T/5524'. Land out on No go.On depth. L/D two joints.P/U pups and space out. Change elevators to 5". M/U SLZXP 9 5/8 LT hanger packer assembly from derrick. M/U 2 7/8 swivel. P/U string.UP/DN 150/110K R/D false bowl&2 7/8 equipment.,Mix and fill liner tie back sleeve with pal mix,wait 30 min.Finish R/D 2 7/8"handling equipment,UD swivel and safety jt.run 1 std from 5607'to 5701',M/U top drive,break circulation pumping 3 bpm @ 560 psi.Blow down top drive.,TIH with 5 1/2"liner conveyed on 5"DP 1.5 min per std from 5701'to 7586'just above 9 5/8"csg shoe,fill pipe every 10 stds.,M/U top drive,P/U 190K,S/O 115K.Adjust TD torq to 10k,10 rpm 10k torq,20 rpm 9k torq, 30 rpm 9k torq while pumping 2 bpm and S/O slowly.,RIH from 7586'to 10982' 1.5 min std with a set down @ 9385'working past easily,run 8 stds HWDP from 10982'to 11361', Fill pipe every 10 stds with top drive.,RIH with remaining HWDP to 11731', continue RIH with 5"DP to 12704'w/58K 8/0,pump 3 bpm 600 psi,wash last 2 stds, single and 6'tagging bottom on depth @ 12995',S/O 55K,P/U 290K. Note: 37.7 bbls under calculated hole fill on trip in including inner string.(confirm 78x stds total DP ran),Pull string in tension @ 250K,CBU pumping 4 bpm 970 psi. Did not get a cuttings increase on btm up.,Displace to 8.9 ppg brine @ 4 bpm.939 psi.,Daily losses to formation 38 bbls, total losses 95 bbls. Rig fuel used 2400 gal.Rig fuel on hand 7050 gal.Fuel received 0 gal.,Hauled 0 bbls to G&I for total=13174 bbls Hauled 0 bbls to B-50 for total=1620 bbls Hauled 0 bbls from 6 mi lake for total=1718 bbls Hauled 40 bbls from L-Pad for total=7455 bbls 2/10/2016 Continue to displace to 8.9 ppg 2%KCL brine. Pump 100 bbl over displacement. Shut down and monitor well.Static.Wait on pits to clean pits and transfer fluid.,Drop setting 1.25 ball.Pump down @ 4 bpm.Slow rate to 3 bpm last 30 bbl. over displace 20 bbl.Still no bump. Stage up rate to 5 bpm. Ball on seat 40 bbl over displacement.Pressure up to 1800 psi.Close WIV.Bring pressure to 3000 psi.hold for 15 min.Packer set @ 2500. Stage pressure up to 4000 psi. Good. Hold for 15 min.Good. Bleed down and test the 9 5/8 X 7 5/8 annulus to 1500 psi. 15 min.Good.,Release running tool. Set down to 50 K two times to verify setting.Good. 5.5 LT set @ 7398'. Blow down surface equipment. Stand back 22 stands 5"dp T/11294'. UD DP T/9418'.,Service rig. Inspect TD.Service skate.,Continue POH and L/D 5"DP from 9418'to 5527'@ LRT.(UD total 137 jts 5"DP and 24 jts HWDP),R/U weatherford power tongs,L/D xo,LRT,swap elevators,UD 4-2 7/8"pup jts,inspect LRT per baker rep. Note:13 bbls over calculated displacement on trip out.,M/U 2 jts 2 7/8"fox tbg and 2 XOs.BHA-slick stick,xo,181 jts 2 7/8"fox tbg,2 XOs=5561.82',swap elevators. M/U 1 std 5"DP and FOSV,M/U top drive.,PJSM,monitor well.Hang blocks,slip and cut 55'drlg line. L/D FOSV,reset and test crown saver.,Service rig,grease top drive,blocks,swivel packing and rollers.Inspect saver sub. Note:well took 1.5 bbls while monitoring.,TIH with stds 78 stds 5"DP from 5624'to 12922',Note:correct displacement on trip in the hole.,M/U top drive.PJSM, R/U to reverse circulate.,Daily losses to formation 37 bbls, total losses 132 bbls. Rig fuel used 2410 gal.Rig fuel on hand 7800 gal.Fuel received 3160 gal.,Hauled 918 bbls to G&I for total=14092 bbls Hauled 0 bbls to B-50 for total=1620 bbls Hauled 0 bbls from 6 mi lake for total=1718 bbls Hauled 93 bbls from L-Pad for total=7548 bbls 2/11/2016 Parked @ 12922',reverse circulate 2nd displacement,pump 8.9 ppg 2%KCL staging pumps from 1 bpm,70 psi to 4 bpm,570 psi.loss rate©25%,slow pump to 2 bpm,240 psi loss rate @ 5%.Pump until clean returns,check for pressure,open annular,blow down TD. Pumped total 920 bbls KCL,lost 84 bbls to formation while displacing.,Note:Send in notification 24 hr notification to AOGCC on 2/11/16 for BOP test witness, AOGCC rep J.Hill waived witness @ 9:45 am,2/11/16.,Flowcheck and monitor well for 30 min,slight flowback from charged formation,pull 5 stands from 12922' to 12450'with hole taking proper displacement.,Continue POH UD 5"drill pipe from 12450'to 6061',RIH with 8 stds 5"DP from derrick,POH L/D remaining DP to 5561'.,R/U 2 7/8"handling equipment.UD 2 XOs,Continue POH UD 2 7/8"workstring from 5561'to surface,UD slick stick.Test choke manifold valves to 250/3000 psi 5 min ea.charted while POH. Note:30.5 bbls over calculated displacement on trip out of the hole.,C/O elevators.R/D tbg power tongs.BOLDS,pull wear bushing.R/U and install test plug. RILDS,C/O 5"lower pipe rams to 7 5/8"casing rams.,Daily losses to formation 133 bbls, total losses 265 bbls. Rig fuel used 1416 gal.Rig fuel on hand 9750 gal.Fuel received 3366 gal.,Hauled 830 bbls to G&I for total=14992 bbls Hauled 750 bbls to B-50 for total=2370 bbls Hauled 0 bbls from 6 mi lake for total=1718 bbls Hauled 30 bbls from L-Pad for total=7579 bbls 2/12/2016 Change btm rams from 5"to 7 5/8 solid LD,Check Gland nuts,R/U testing equipment. Test top s&Annular to 2 7/8.Test btm rams to 7 5/8. Test blinds and all components to 250/3000 psi. accumulator Draw down.Good. While performing body test we had a le n the flange in the multi bowl. tighten flange and all test .,ed.,After consulting our wellhead specialist and Seaboard about the leak on the multi bowl it was decided the flange could have the wrong API ring installed. Decide to set a storm packer,N/D BOPs,inspect and replace api ring before running 7 5/8.,Pull test plug,blow down choke and kill line.Make hanger dummy run landing out @ 32.80'per well head rep,load 20 jts of 5"HWDP into pipe shed. Note:well taking approx.2 bph.,P/U 20 jts 5"HWDP and TIH.M/U HES storm packer and running tool,P/U 80K,S/O 85k,set storm packer per HES rep @ 35'. POH with running tool.Close blind rams,test storm packer to 1000 psi for 10 min,charted.,PJSM,with 2 barriers in place,drain stack.Break and remove bolts on API flange @ multi bowl,P/U stack.Inspect ring groove and C/O API ring gasket from R-54 to RX-54 per wellhead rep.Lower stack and tighten flange bolts.,Fill stack,close blind ram,body test API flange to 250 psi low for 5 min,3000 psi high for 10 min,good,chart record test.Bleed off pressure,blow down choke and kill lines.open blind rams. Note:spot ESP spooling unit,rig electrician wire in same.,RIH with storm packer running tool,1 jt DP w/FOSV,close annular,open storm packer and release elements per HES rep with 0 psi below packer.Open annular,LID storm packer assembly.,POH L/D 20 jts 5"HWDP and XOs.,R/U to run 7 5/8"tie back string, mobilize tools and pup jts to rig floor,R/U 7 5/8"handling equipment.Load HWDP from pipe shed.M/U 7 5/8"x/o to FOSV. Note:Monitor well,static loss rate @ 3 bph.,PJSM,Inspect and M/U 7.37"seal assembly with pup jt,XO and no go per Baker rep.P/U and RIH with 7 5/8"SLIJ-II, 29.7#,L-80 Liner,use dog collar clamp on every jt.,use optimum M/U torq @ 11400 ft/lbs.RIH to 3100' Note:well continues taking 3 bph while RIH,Daily losses to formation 63 bbls, total losses 328 bbls. Rig fuel used 2250 gal.Rig fuel on hand 7500 gal.Fuel received 0 gal.,Hauled 57 bbls to G&I for total=14979 bbls Hauled 0 bbls to B-50 for total=2370 bbls Hauled 0 bbls from 6 mi lake for total=1718 bbls Hauled 111 bbls from L-Pad for total=7690 bbls 2/13/2016 P/U 7 5/8 SLIJ-Il F/3150 T/7363'. Ready to space out and circ freeze protect.Well loosing 1.5 BPH while running. Shut down due to Phase 3 weather. Roads blown shut.,Well operations shut down. Rig crew Working on changing out blower motor on top drive.,Weather reduced to Phase 2 @ 18:00, Finish up top drive blower motor and function test same,call out fuel truck,well head hand etc.,PJSM,M/U 1 jt 7 5/8 for spaceout.P/U 215K,S/O 120K.RIH from 7361'to 7394',see seals entering tie back extension,tag NOGO 10.12'in @ 7404'setting down 15k.p/u 1',close annular,test seals to 500 psi.good. Bleed off pressure.Open annular.Unstab seals,L/D jt 10'PUP and 2 jts 7 5/8.,M/U 2 pup joints 19.86'and 19.87'to position seal assy @ 7402.26'=1.74'above "NO-GO DEPTH"when tie-back hanger lands out in wellhead,run pup jts and space out,M/U pup,hanger and landing jt.position seas)assembly 9'above tie back per Baker rep.,Drain fluid from stack,M/U top drive,circulate lines full,close annular.Reverse circulate pumping 91 bbls 11.3 ppg brine followed with 59 bbls diesel freeze protecting 9 5/8 x 7 5/8 annulus to 2700',open annular,land hanger with 73k per wellhead rep. Note:nogo depth @ 7402.26'(1.74'above tie back). Pump Diesel freeze protect with the rig.Roads and pads shipped strait to the mud pumps.They brought there own XO,Drain stack,land packoff,RILDS,pull landing jt.Test hanger void to 500 psi low for 5 min,3000 psi high for 10 min per wellhead rep,break out sub LID landing jt.,R/U test pump to 9 5/8 X 7 5/8 production annulus,pump diesel and test O/A to 1000 psi for 30 min,charted,good.Bleed off pressure.Close 0/A. R/D test equipment.,PJSM,Utilize tools and equipment to pipeshed and rig floor.Hang ESP sheave in derrick,string ESP cable. Not:well continues @ 4 bph static loss rate.,PJSM,M/U ESP pump assembly per Centrilift.,Daily losses to formation 100 bbls, total losses 428 bbls. Rig fuel used 2350 gal.Rig fuel on hand 5510 gal.Fuel received 0 gal.,Hauled 0 bbls to G&I for total=14979 bbls Hauled 0 bbls to B-50 for total=2370 bbls Hauled 0 bbls from 6 mi lake for total=1718 bbls Hauled 15 bbls from L-Pad for total=7705 bbls 2/14/2016 M/U ESP pump assembly and service same, M/U ESP cable to motor,install guards,meg test same.M/U XN nipple w/2.250"no go.run 4 jts 2 7/8 EUE 8rd 6.5#L-80 tbg,M/U GLM with dummy valve, RIH with ESP completion per tally,meg test cable every 2000',use optimum M/U torque @ 2250 ft/lbs,RIH to 4932' Note:well continues taking 4 bph while TIH.,Make ESP cable splice per Centrilift.Meg test cable. Monitor well,3 bph static loss rate.,Continue RIH with ESP completion from 4932'to 5408',M/U pup jts,GLM w/orifice.RIH from 5435'to 5529',P/U 89,S/O 70k.(verify tbg count 170 jts 2 7/8"tubing ran,15 jts left out)M/U pup jt,tbg hanger w/BPV installed and landing jt. Note:well continues to take 4 bph TIH.,Install penetrator,Meg test and cut ESP cable.terminate cable to penetrator,meg test same.Land hanger 30.44'RKB,w/ upper GLM w/oriface @ 138.75',lower GLM w/dummy valve @ 5354.26', XN nipple @ 5498',EOP @ 5564.25',wt on hanger=20k,RILDS per wellhead rep. Note:(92 cannon clamps placed every other jt)(3 protectolizers)(2 flat guards)(4 pump clamps),L/D landing jt,pull riser,L/D mousehole.,PJSM,C/O lower 7 5/8 rams to 5"solid pipe rams. Simops-R/D ESP cable and sheave,R/D,clean and load out 2 7/8"handling equipment.Cleaning pits.,N/D BOPE,N/U 11"x 2 9/16" adapter flange w/2 9/16"tree.,Daily losses to formation 69 bbls, total losses 497 bbls. Rig fuel used 2350 gal.Rig fuel on hand 2800 gal.Fuel received 0 gal.,Hauled 90 bbls to G&I for total=15069 bbls Hauled 0 bbls to B-50 for total=2370 bbls Hauled 0 bbls from 6 mi lake for total=1718 bbls Hauled 17 bbls from L-Pad for total=7722 bbls 2/15/2016 N/U tree&adaptor,Test void to 500/3000 psi. Test tree 250/5000 psi.Good. Pull BPV,R/U LRS.Test lines to 3500 psi. Pump down annulus taking returns out tubing.Got diesel back in 14 bbl.Came through the gaslift orifice @ 138'.Shut tubing&bullhead 110 bbl down the annulus @ 2 bpm 800 psi. Let well U tube for 1 hr. R/D circ lines. While U tubing freeze protect. Black out rig&change highline breaker.,Swap camp to Gen power. Test rig on highline.Good. Hilcorp electricians spool up highline power trailer. Secure well.Install gauges&clean cellar area. Prep&skid rig floor.Clear pipe shed. Move snow&equipment. Warm move system,roll tires Note:release rig from well @ 1800.,Notify pad operator,PJSM for pulling rig off well,with well secure,jack up rig,move off well,stage rig on far side of pad. Clear mats and cleanup around L-47,Pad inspection with DSO,Notify well support that L-47 is clear of rig and equipment.,lnstall rear boosters,continue to mobilize equipment to B-PAD and cleanup around L-pad.,PJSM with oncoming crew for rig move,make final checks,move rig to pad entrance.,Notify security, pad operator,well support and roads and pads. Mobilize rig to MPB-pad,currently between MPC and A-pad.,Rig fuel used 941 gal.Rig fuel on hand 5550 gal. Fuel received 3741 gal. • • MPL-47 FINAL Days vs Depth 0 500 -MPL-47 Actual 1000 MPL-47 Plan 1500 MPL-47 Stretch Goal 2000 2500 3000 3500 4000 4500 5000 - �'t 5500 . 6000 a 6500 7000 7500 co 8000 8500 9000 9500 10000 10500 11000 11500tot 12000 12500 13000 :.�.��, 13500 14000 0 5 10 15 20 25 30 Days • • MPL-47 MW vs Depth 0 MPL 1000 MPL 47-47 Actual 2000 3000 4000 5000 6000 a E.' L a 7000 ca a, 8000 9000 10000 11000 12000 13000 8.0 9.0 10.0 11.0 12.0 13.0 14.0 Mud Density(ppg) I • Hilcorp Energy Company Milne Point M Pt L Pad MPL-47 50-029-23550-00-00 50-029-23550-00-00 Sperry Drilling Definitive Survey Report 11 February, 2016 III 111111 1111111 HALLIBURTON Sperry Drs'6imp • Halliburton • Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well MPL-47 Project Mine Point TVD Reference: MPL-47 @ 50.70usft(Doyon 14) Site:% M Pt L Pad MD Reference: MPL-47 @ 50.70usft(Doyon 14) Well: MPL-47 North Reference: True Wellbore: MPL-47 Survey Calculation Method: Minimum Curvature Design: MPL-47 Database: Sperry EDM-NORTH US+CANADA Project Milne Point,ACT,MILNE POINT Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPL-47 Well Position +N/-S 0.00 usft Northing: 6,031,641,90 usft Latitude: 70°29'50.316 N +El-W 0.00 usft Easting: 545,157.43 usft Longitude: 149°37'50.603 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 16.90 usft Wellbore MPL-47 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (0) (0) (nT) BGGM2015 2/6/2016 18.68 81.08 57,501 Design MPL-47 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 11,037.45 Vertical Section: Depth From(TVD) +N/-S +El-W Direction (usft) (usft) (usft) (o) 33.80 0.00 0.00 160.99 Survey Program Date 2/11/2016 From To (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 82.00 1,582.00 SRG-MS(MPL-47 PB1) SRG-MS Surface readout gyro multishot 01/22/2016 1,639.10 7,739.95 MWD+IFR2+MS+sag(1)(MPL-47 PB1) MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 01/22/2016 7,740.95 11,037.45 MWD+IFR2+MS+sag(1)(MPL-47 PB1) MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 01/22/2016 11,101.17 12,924.82 MPL-47(MPL-47) MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 02/06/2016 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +EI-W Northing Easting DLS Section (usft) (0) (0) (usft) (usft) (usft) (usft) (ft) (ft) (°H00) (ft) Survey Tool Name 33.80 0.00 0.00 33.80 -16.90 0.00 0.00 6,031,641.90 545,157.43 0.00 0.00 UNDEFINED 82.00 0.53 260.00 82.00 31.30 -0.04 -0.22 6,031,641.86 545,157.21 1.10 -0.03 SRG-MS(1) 182.00 0.41 269.37 182.00 131.30 -0.12 -1.03 6,031,641.77 545,156.40 0.14 -0.22 SRG-MS(1) 282.00 0.63 231.16 281.99 231.29 -0.47 -1.82 6,031,641.42 545,155.61 0.40 -0.15 SRG-MS(1) 382.00 3.54 212.51 381.92 331.22 -3.42 -3.91 6,031,638.46 545,153.54 2.95 1.96 SRG-MS(1) 482.00 4.60 210.17 481.66 430.96 -9.49 -7.58 6,031,632.36 545,149.91 1.07 6.50 SRG-MS(1) 582.00 4.77 212.97 581.33 530.63 -16.45 -11.86 6,031,625.38 545,145.67 0.28 11.69 SRG-MS(1) 682.00 6.16 221.48 680.87 630.17 -23.95 -17.68 6,031,617.84 545,139.90 1.61 16.89 SRG-MS(1) 782.00 7.42 221.07 780.17 729.47 -32.84 -25.47 6,031,608.91 545,132.16 1.26 22.75 SRG-MS(1) 882.00 10.36 226.50 878.96 828.26 -43.90 -36.24 6,031,597.78 545,121.46 3.05 29.70 SRG-MS(1) 982.00 11.92 228.42 977.07 926.37 -56.95 -50.49 6,031,584.65 545,107.29 1.60 37.40 SRG-MS(1) 2/11/2016 2:11:14PM Page 2 COMPASS 5000.1 Build 73 0 Halliburton • Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well MPL-47 Project: Milne Point TVD Reference: MPL-47 @ 50.70usft(Doyon 14) Site: M Pt L Pad MD Reference: MPL-47 @ 50.70usft(Doyon 14) Well: MPL-47 North Reference: True Wellbore: MPL-47 Survey Calculation Method: Minimum Curvature Design: MPL-47 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 1,082.00 16.15 231.27 1,074.07 1,023.37 -72.51 -69.07 6,031,568.98 545,088.81 4.28 46.06 SRG-MS(1) 1,182.00 20.66 232.99 1,168.93 1,118.23 -91.84 -94.02 6,031,549.50 545,063.98 4.54 56.21 SRG-MS(1) 1,282.00 25.03 226.99 1,261.07 1,210.37 -116.90 -123.59 6,031,524.26 545,034.56 4.95 70.27 SRG-MS(1) 1,382.00 30.47 223.48 1,349.54 1,298.84 -149.76 -156.54 6,031,491.21 545,001.82 5.68 90.60 SRG-MS(1) 1,482.00 36.56 220.22 1,432.89 1,382.19 -190.94 -193.25 6,031,449.81 544,965.36 6.35 117.58 SRG-MS(1) 1,582.00 38.39 217.11 1,512.25 1,461.55 -238.45 -231.23 6,031,402.07 544,927.68 2.63 150.13 SRG-MS(1) 1,639.10 40.73 214.92 1,556.27 1,505.57 -267.87 -252.59 6,031,372.53 544,906.50 4.77 170.99 MWD+IFR2+MS+sag(2) 1,733.37 46.01 212.87 1,624.78 1,574.08 -321.61 -288.63 6,031,318.57 544,870.79 5.80 210.06 MWD+IFR2+M8+sag(2) 1,827.11 52.88 213.03 1,685.69 1,634.99 -381.34 -327.35 6,031,258.62 544,832.44 7.33 253.91 MWD+IFR2+MS+sag(2) 1,923.32 55.85 210.05 1,741.75 1,691.05 -447.98 -368.21 6,031,191.73 544,791.99 3.98 303.61 MWD+IFR2+MS+sag(2) 2,016.85 57.22 209.69 1,793.32 1,742.62 -515.64 -407.06 6,031,123.85 544,753.55 1.50 354.93 MWD+IFR2+MS+sag(2) 2,111.09 55.54 211.07 1,845.50 1,794.80 -583.34 -446.74 6,031,055.91 544,714.29 2.16 406.01 MWD+IFR2+MS+sag(2) 2,205.37 56.06 211.02 1,898.49 1,847.79 -650.15 -486.95 6,030,988.87 544,674.48 0.55 456.08 MWD+IFR2+MS+sag(2) 2,300.53 61.42 210.97 1,947.86 1,897.16 -719.85 -528.83 6,030,918.92 544,633.04 5.63 508.34 MWD+IFR2+MS+sag(2) 2,395.06 61.47 211.95 1,993.04 1,942.34 -790.68 -572.16 6,030,847.84 544,590.14 0.91 561.19 MWD+IFR2+MS+sag(2) 2,489.01 63.88 211.54 2,036.17 1,985.47 -861.66 -616.07 6,030,776.60 544,546.67 2.59 613.99 MWD+IFR2+MS+sag(2) 2,578.97 64.20 210.34 2,075.55 2,024.85 -931.03 -657.65 6,030,706.98 544,505.51 1.25 666.03 MWD+IFR2+MS+sag(2) 2,672.29 62.79 211.45 2,117.19 2,066.49 -1,002.69 -700.53 6,030,635.07 544,463.08 1.85 719.82 MWD+IFR2+MS+sag(2) 2,765.56 64.43 210.67 2,158.65 2,107.95 -1,074.26 -743.63 6,030,563.25 544,420.42 1.91 773.45 MWD+IFR2+MS+sag(2) 2,862.59 64.94 210.44 2,200.14 2,149.44 -1,149.79 -788.22 6,030,487.45 544,376.29 0.57 830.34 MWD+IFR2+MS+sag(2) 2,944.75 64.95 211.36 2,234.93 2,184.23 -1,213.66 -826.44 6,030,423.36 544,338.46 1.01 878.27 MWD+IFR2+MS+sag(2) 3,049.16 65.47 211.18 2,278.71 2,228.01 -1,294.67 -875.64 6,030,342.06 544,289.76 0.52 938.84 MWD+IFR2+MS+sag(2) 3,145.34 66.28 209.86 2,318.02 2,267.32 -1,370.29 -920.21 6,030,266.18 544,245.65 1.51 995.81 MWD+IFR2+MS+sag(2) 3,239.80 65.65 209.99 2,356.50 2,305.80 -1,445.06 -963.25 6,030,191.16 544,203.07 0.68 1,052.49 MWD+IFR2+MS+sag(2) 3,334.62 63.26 210.18 2,397.38 2,346.68 -1,519.08 -1,006.13 6,030,116.88 544,160.64 2.53 1,108.50 MWD+IFR2+MS+sag(2) 3,428.67 62.71 210.25 2,440.10 2,389.40 -1,591.49 -1,048.30 6,030,044.23 544,118.92 0.59 1,163.22 MWD+IFR2+MS+sag(2) 3,521.69 63.07 210.36 2,482.49 2,431.79 -1,662.97 -1,090.08 6,029,972.50 544,077.58 0.40 1,217.20 MVVD+IFR2+MS+sag(2) 3,616.83 62.09 210.75 2,526.30 2,475.60 -1,735.69 -1,133.01 6,029,899.52 544,035.10 1.09 1,271.97 MWD+IFR2+MS+sag(2) 3,711.97 62.62 210.34 2,570.45 2,519.75 -1,808.28 -1,175.84 6,029,826.69 543,992.71 0.68 1,326.65 MWD+IFR2+MS+sag(2) 3,806.90 62.58 211.61 2,614.13 2,563.43 -1,880.54 -1,219.21 6,029,754.17 543,949.78 1.19 1,380.84 MWD+IFR2+MS+sag(2) 3,900.85 62.34 211.56 2,657.57 2,606.87 -1,951.50 -1,262.85 6,029,682.95 543,906.59 0.26 1,433.72 MWD+IFR2+MS+sag(2) 3,994.83 61.60 212.45 2,701.74 2,651.04 -2,021.85 -1,306.81 6,029,612.35 543,863.06 1.15 1,485.91 MWD+IFR2+MS+sag(2) 4,090.02 64.46 210.53 2,744.91 2,694.21 -2,094.19 -1,351.10 6,029,539.75 543,819.21 3.50 1,539.88 MWD+IFR2+MS+sag(2) 4,182.96 64.82 211.10 2,784.72 2,734.02 -2,166.32 -1,394.12 6,029,467.37 543,776.63 0.68 1,594.06 MWD+IFR2+MS+sag(2) 4,277.75 65.35 209.55 2,824.65 2,773.95 -2,240.52 -1,437.52 6,029,392.91 543,733.68 1.58 1,650.08 MWD+IFR2+MS+sag(2) 4,372.46 64.74 209.47 2,864.61 2,813.91 -2,315.25 -1,479.82 6,029,317.93 543,691.85 0.65 1,706.95 MWD+IFR2+MS+sag(2) 4,466.15 64.78 209.25 2,904.56 2,853.86 -2,389.11 -1,521.37 6,029,243.83 543,650.75 0.22 1,763.25 MWD+IFR2+MS+sag(2) 4,560.73 63.45 209.66 2,945.85 2,895.15 -2,463.20 -1,563.21 6,029,169.49 543,609.36 1.46 1,819.67 MWD+IFR2+MS+sag(2) 4,654.96 62.94 209.75 2,988.34 2,937.64 -2,536.25 -1,604.89 6,029,096.19 543,568.14 0.55 1,875.16 MWD+IFR2+MS+sag(2) 4,749.41 63.22 210.70 3,031.10 2,980.40 -2,609.02 -1,647.28 6,029,023.18 543,526.19 0.94 1,930.15 MWD+IFR2+MS+sag(2) 2/11/2016 2:11:14PM Page 3 COMPASS 5000.1 Build 73 • Halliburton 1 Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well MPL-47 Project: Milne Point TVD Reference: MPL-47 @ 50.70usft(Doyon 14) Site: M Pt L Pad MD Reference: MPL-47 @ 50.70usft(Doyon 14) Well: MPL-47 North Reference: True Wellbore: MPL-47 Survey Calculation Method: Minimum Curvature Design: MPL-47 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 4,843.51 63.04 210.72 3,073.63 3,022.93 -2,681.18 -1,690.15 6,028,950.76 543,483.76 0.19 1,984.42 MWD+IFR2+MS+sag(2) 4,937.45 61.81 212.16 3,117.12 3,066.42 -2,752.23 -1,733.58 6,028,879.46 543,440.78 1.89 2,037.44 MWD+IFR2+MS+sag(2) 5,032.56 62.06 212.47 3,161.87 3,111.17 -2,823.16 -1,778.44 6,028,808.27 543,396.35 0.39 2,089.89 MWD+IFR2+MS+sag(2) 5,126.40 61.81 212.37 3,206.02 3,155.32 -2,893.05 -1,822.83 6,028,738.11 543,352.38 0.28 2,141.51 MWD+IFR2+MS+sag(2) 5,222.38 61.00 212.43 3,251.95 3,201.25 -2,964.21 -1,867.99 6,028,666.69 543,307.66 0.85 2,194.08 MWD+IFR2+MS+sag(2) 5,317.44 62.43 211.59 3,297.00 3,246.30 -3,035.19 -1,912.36 6,028,595.45 543,263.73 1.69 2,246.74 MWD+IFR2+MS+sag(2) 5,411.97 63.27 210.98 3,340.13 3,289.43 -3,107.07 -1,956.03 6,028,523.31 543,220.50 1.06 2,300.47 MWD+IFR2+MS+sag(2) 5,505.49 63.60 210.64 3,381.96 3,331.26 -3,178.91 -1,998.88 6,028,451.21 543,178.10 0.48 2,354.44 MWD+IFR2+MS+sag(2) 5,599.98 63.34 210.23 3,424.16 3,373.46 -3,251.81 -2,041.70 6,028,378.07 543,135.72 0.48 2,409.41 MWD+IFR2+MS+sag(2) 5,692.58 64.63 208.10 3,464.78 3,414.08 -3,324.47 -2,082.24 6,028,305.17 543,095.62 2.49 2,464.90 MWD+IFR2+MS+sag(2) 5,787.11 62.37 205.43 3,506.96 3,456.26 -3,399.98 -2,120.35 6,028,229.43 543,057.98 3.48 2,523.88 MWD+IFR2+MS+sag(2) 5,881.89 63.35 200.87 3,550.22 3,499.52 -3,477.51 -2,153.48 6,028,151.71 543,025.32 4.40 2,586.39 MWD+IFR2+MS+sag(2) 5,976.43 64.27 196.37 3,591.96 3,541.26 -3,557.88 -2,180.55 6,028,071.19 542,998.75 4.38 2,653.56 MWD+IFR2+MS+sag(2) 6,071.06 65.24 190.83 3,632.34 3,581.64 -3,641.03 -2,200.65 6,027,987.93 542,979.16 5.39 2,725.63 MWD+IFR2+MS+sag(2) 6,164.46 65.40 185.28 3,671.37 3,620.67 -3,725.02 -2,212.53 6,027,903.88 542,967.78 5.40 2,801.16 MWD+IFR2+MS+sag(2) 6,260.27 64.91 181.80 3,711.63 3,660.93 -3,811.77 -2,217.90 6,027,817.10 542,962.94 3.34 2,881.44 MWD+IFR2+MS+sag(2) 6,354.59 65.11 180.72 3,751.48 3,700.78 -3,897.24 -2,219.78 6,027,731.63 542,961.58 1.06 2,961.64 MWD+IFR2+MS+sag(2) 6,446.28 65.93 178.74 3,789.48 3,738.78 -3,980.68 -2,219.39 6,027,648.20 542,962.48 2.16 3,040.65 MWD+IFR2+MS+sag(2) 6,542.92 66.11 173.59 3,828.78 3,778.08 -4,068.74 -2,213.48 6,027,560.18 542,968.92 4.87 3,125.84 MWD+IFR2+MS+sag(2) 6,633.55 67.46 169.22 3,864.51 3,813.81 -4,151.07 -2,201.02 6,027,477.94 542,981.88 4.67 3,207.73 MWD+IFR2+MS+sag(2) 6,729.51 71.20 162.50 3,898.41 3,847.71 -4,238.04 -2,179.04 6,027,391.12 543,004.39 7.62 3,297.12 MWD+IFR2+MS+sag(2) 6,823.81 72.53 156.41 3,927.79 3,877.09 -4,321.90 -2,147.59 6,027,307.46 543,036.34 6.30 3,386.65 MWD+IFR2+MS+sag(2) 6,918.41 73.91 151.41 3,955.12 3,904.42 -4,403.20 -2,107.77 6,027,226.40 543,076.66 5.27 3,476.49 MWD+IFR2+MS+sag(2) 7,012.81 73.75 146.56 3,981.42 3,930.72 -4,480.88 -2,061.07 6,027,149.02 543,123.82 4.94 3,565.14 MWD+IFR2+MS+sag(2) 7,107.25 76.02 140.33 4,006.07 3,955.37 -4,554.06 -2,006.78 6,027,076.18 543,178.55 6.81 3,652.01 MWD+IFR2+MS+sag(2) 7,201.11 78.18 135.15 4,027.03 3,976.33 -4,621.73 -1,945.26 6,027,008.89 543,240.47 5.85 3,736.03 MWD+IFR2+MS+sag(2) 7,295.42 79.44 129.33 4,045.35 3,994.65 -4,683.88 -1,876.80 6,026,947.16 543,309.31 6.20 3,817.10 MWD+IFR2+MS+sag(2) 7,389.93 81.55 124.62 4,060.97 4,010.27 -4,739.92 -1,802.35 6,026,891.58 543,384.09 5.40 3,894.33 MWD+IFR2+MS+sag(2) 7,484.13 83.76 124.45 4,073.01 4,022.31 -4,792.88 -1,725.39 6,026,839.10 543,461.36 2.35 3,969.47 MWD+IFR2+MS+sag(2) 7,579.77 82.38 123.47 4,084.55 4,033.85 -4,845.91 -1,646.65 6,026,786.55 543,540.41 1.77 4,045.26 MWD+IFR2+MS+sag(2) 7,626.07 82.83 124.11 4,090.51 4,039.81 -4,871.45 -1,608.49 6,026,761.24 543,578.72 1.68 4,081.83 MWD+IFR2+MS+sag(2) 7,740.95 85.55 122.82 4,102.14 4,051.44 -4,934.46 -1,513.15 6,026,698.82 543,674.43 2.62 4,172.46 MWD+IFR2+MS+sag(3) 7,829.33 86.54 124.71 4,108.23 4,057.53 -4,983.46 -1,439.86 6,026,650.27 543,748.01 2.41 4,242.66 MWD+IFR2+MS+sag(3) 7,928.18 88.27 126.52 4,112.71 4,062.01 -5,040.96 -1,359.59 6,026,593.26 543,828.62 2.53 4,323.18 MWD+IFR2+MS+sag(3) 8,024.50 88.27 127.58 4,115.62 4,064.92 -5,098.97 -1,282.75 6,026,535.73 543,905.80 1.10 4,403.05 MWD+IFR2+MS+sag(3) 8,116.41 88.52 127.56 4,118.19 4,067.49 -5,154.99 -1,209.93 6,026,480.16 543,978.95 0.27 4,479.73 MWD+IFR2+MS+sag(3) 8,211.37 87.78 128.14 4,121.26 4,070.56 -5,213.23 -1,134.99 6,026,422.38 544,054.24 0.99 4,559.20 MWD+IFR2+MS+sag(3) 8,306.52 88.21 129.52 4,124.58 4,073.88 -5,272.85 -1,060.91 6,026,363.22 544,128.67 1.52 4,639.70 MWD+IFR2+MS+sag(3) 8,396.58 88.08 128.49 4,127.50 4,076.80 -5,329.50 -990.97 6,026,307.00 544,198.95 1.15 4,716.05 MWD+IFR2+MS+sag(3) 8,489.68 88.77 128.58 4,130.06 4,079.36 -5,387.48 -918.17 6,026,249.47 544,272.10 0.75 4,794.58 MWD+IFR2+MS+sag(3) 2/11/2016 2:11:14PM Page 4 COMPASS 5000.1 Build 73 • Halliburton • Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well MPL-47 Project: Milne Point TVD Reference: MPL-47 @ 50.70usft(Doyon 14) Site: M Pt L Pad MD Reference; MPL-47 @ 50.70usft(Doyon 14) Well: MPL-47 North Reference: True Wellbore: MPL-47 Survey Calculation Method: Minimum Curvature Design: MPL-47 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°I100') (ft) Survey Tool Name 8,586.04 89.63 128.81 4,131.40 4,080.70 -5,447.71 -842.97 6,026,189.70 544,347.65 0.92 4,876.02 MWD+IFR2+MS+sag(3) 8,679.89 90.00 129.23 4,131.71 4,081.01 -5,506.80 -770.06 6,026,131.06 544,420.92 0.60 4,955.64 MWD+IFR2+MS+sag(3) 8,775.08 89.32 129.40 4,132.27 4,081.57 -5,567.11 -696.41 6,026,071.21 544,494.92 0.74 5,036.65 MWD+IFR2+MS+sag(3) 8,870.07 89.14 129.58 4,133.55 4,082.85 -5,627.51 -623.11 6,026,011.26 544,568.58 0.27 5,117.63 MWD+IFR2+MS+sag(3) 8,962.52 87.78 130.00 4,136.03 4,085.33 -5,686.66 -552.10 6,025,952.55 544,639.94 1.54 5,196.68 MWD+IFR2+MS+sag(3) 9,060.49 90.31 127.39 4,137.67 4,086.97 -5,747.88 -475.66 6,025,891.79 544,716.74 3.71 5,279.47 MWD+IFR2+MS+sag(3) 9,151.77 90.31 126.46 4,137.17 4,086.47 -5,802.72 -402.69 6,025,837.41 544,790.04 1.02 5,355.08 MWD+IFR2+MS+sag(3) 9,247.15 91.48 125.86 4,135.68 4,084.98 -5,858.99 -325.69 6,025,781.61 544,867.37 1.38 5,433.36 MWD+IFR2+MS+sag(3) 9,340.92 89.94 125.87 4,134.52 4,083.82 -5,913.92 -249.71 6,025,727.15 544,943.67 1.64 5,510.05 MWD+IFR2+MS+sag(3) 9,435.70 89.20 124.71 4,135.23 4,084.53 -5,968.68 -172.35 6,025,672.87 545,021.36 1.45 5,587.01 MWD+IFR2+MS+sag(3) 9,528.69 88.95 124.34 4,136.73 4,086.03 -6,021.37 -95.75 6,025,620.64 545,098.27 0.48 5,661.79 MWD+IFR2+MS+sag(3) 9,622.72 90.19 124.99 4,137.44 4,086.74 -6,074.85 -18.41 6,025,567.64 545,175.92 1.49 5,737.54 MWD+IFR2+MS+sag(3) 9,717.58 92.35 127.02 4,135.34 4,084.64 -6,130.60 58.30 6,025,512.37 545,252.96 3.12 5,815.23 MWD+IFR2+MS+sag(3) 9,810.23 91.11 127.91 4,132.54 4,081.84 -6,186.93 131.80 6,025,456.49 545,326.80 1.65 5,892.43 MWD+IFR2+MS+sag(3) 9,904.75 90.49 127.45 4,131.22 4,080.52 -6,244.69 206.60 6,025,399.19 545,401.94 0.82 5,971.42 MWD+IFR2+MS+sag(3) 9,995.95 90.68 126.47 4,130.29 4,079.59 -6,299.53 279.47 6,025,344.80 545,475.13 1.09 6,046.99 MWD+IFR2+MS+sag(3) 10,090.90 90.99 126.02 4,128.90 4,078.20 -6,355.66 356.04 6,025,289.14 545,552.03 0.58 6,125.00 MWD+IFR2+MS+sag(3) 10,185.38 90.43 124.87 4,127.73 4,077.03 -6,410.44 433.00 6,025,234.83 545,629.32 1.35 6,201.87 MWD+IFR2+MS+sag(3) 10,281.24 90.56 123.61 4,126.91 4,076.21 -6,464.38 512.24 6,025,181.39 545,708.88 1.32 6,278.67 MWD+IFR2+MS+sag(3) 10,375.94 90.43 123.00 4,126.09 4,075.39 -6,516.37 591.38 6,025,129.88 545,788.33 0.66 6,353.62 MWD+IFR2+MS+sag(3) 10,472.68 90.56 122.71 4,125.25 4,074.55 -6,568.85 672.65 6,025,077.89 545,869.90 0.33 6,429.70 MWD+IFR2+MS+sag(3) 10,566.72 90.31 121.40 4,124.54 4,073.84 -6,618.76 752.34 6,025,028.48 545,949.90 1.42 6,502.85 MWD+IFR2+MS+sag(3) 10,661.66 91.11 121.16 4,123.36 4,072.66 -6,668.05 833.48 6,024,979.68 546,031.32 0.88 6,575.88 MWD+IFR2+MS+sag(3) 10,755.38 90.37 121.94 4,122.15 4,071.45 -6,717.09 913.34 6,024,931.14 546,111.47 1.15 6,648.25 MWD+IFR2+MS+sag(3) 10,850.51 90.68 123.61 4,121.28 4,070.58 -6,768.58 993.32 6,024,880.14 546,191.75 1.79 6,722.99 MWD+IFR2+MS+sag(3) 10,944.89 90.62 120.12 4,120.21 4,069.51 -6,818.39 1,073.45 6,024,830.82 546,272.18 3.70 6,796.19 MWD+IFR2+MS+sa9(3) 11,037.45 90.31 118.74 4,119.46 4,068.76 -6,863.87 1,154.07 6,024,785.84 546,353.06 1.53 6,865.45 MWD+IFR2+MS+sag(3) 11,101.17 88.39 118.68 4,120.18 4,069.48 -6,894.48 1,209.95 6,024,755.57 546,409.12 3.01 6,912.58 MWD+IFR2+MS+sag(4) 11,129.04 87.03 118.52 4,121.29 4,070.59 -6,907.81 1,234.39 6,024,742.39 546,433.65 4.91 6,933.15 MWD+IFR2+MS+sag(4) 11,223.83 83.18 117.72 4,129.38 4,078.68 -6,952.31 1,317.67 6,024,698.40 546,517.18 4.15 7,002.36 MWD+IFR2+MS+sag(4) 11,320.52 82.76 118.33 4,141.21 4,090.51 -6,997.40 1,402.38 6,024,653.83 546,602.16 0.76 7,072.58 MWD+IFR2+MS+sag(4) 11,414.27 83.87 119.66 4,152.13 4,101.43 -7,042.54 1,483.82 6,024,609.19 546,683.86 1.84 7,141.78 MWD+IFR2+MS+sag(4) 11,509.02 85.05 121.06 4,161.28 4,110.58 -7,090.20 1,565.19 6,024,562.03 546,765.51 1.93 7,213.35 MWD+IFR2+MS+sag(4) 11,603.35 88.03 123.88 4,166.97 4,116.27 -7,140.74 1,644.61 6,024,511.98 546,845.23 4.35 7,287.01 MWD+IFR2+MS+sag(4) 11,699.11 90.68 126.52 4,168.05 4,117.35 -7,195.93 1,722.84 6,024,457.27 546,923.79 3.91 7,364.66 MWD+IFR2+MS+sag(4) 11,791.99 89.69 126.68 4,167.75 4,117.05 -7,251.31 1,797.41 6,024,402.35 546,998.68 1.08 7,441.31 MWD+IFR2+MS+sag(4) 11,886.08 89.88 127.80 4,168.10 4,117.40 -7,308.24 1,872.31 6,024,345.88 547,073.92 1.21 7,519.54 MWD+IFR2+MS+sag(4) 11,980.56 89.20 127.21 4,168.86 4,118.16 -7,365.76 1,947.26 6,024,288.82 547,149.21 0.95 7,598.34 MWD+IFR2+MS+sag(4) 12,075.57 89.69 127.30 4,169.78 4,119.08 -7,423.28 2,022.88 6,024,231.77 547,225.17 0.52 7,677.34 MWD+IFR2+MS+sag(4) 12,169.59 90.99 126.70 4,169.22 4,118.52 -7,479.86 2,097.96 6,024,175.66 547,300.59 1.52 7,755.30 MWD+IFR2+MS+sag(4) 2/11/2016 2:11:14PM Page 5 COMPASS 5000.1 Build 73 • Halliburton • Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well MPL-47 Project: Milne Point TVD Reference: MPL-47 @ 50.70usft(Doyon 14) Site: M Pt L Pad MD Reference: MPL-47 @ 50.70usft(Doyon 14) Well: MPL-47 North Reference: True Wellbore: MPL-47 Survey Calculation Method: Minimum Curvature Design: MPL-47 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°I100') (ft) Survey Tool Name 12,264.93 91.48 126.66 4,167.17 4,116.47 -7,536.79 2,174.41 6,024,119.19 547,377.37 0.52 7,834.03 MWD+IFR2+MS+sag(4) 12,357.60 90.31 127.45 4,165.72 4,115.02 -7,592.63 2,248.35 6,024,063.81 547,451.64 1.52 7,910.90 MWD+IFR2+MS+sag(4) 12,452.62 89.57 127.25 4,165.82 4,115.12 -7,650.27 2,323.89 6,024,006.63 547,527.52 0.81 7,990.01 MWD+IFR2+MS+sag(4) 12,546.03 91.85 128.52 4,164.66 4,113.96 -7,707.63 2,397.60 6,023,949.73 547,601.57 2.79 8,068.24 MWD+IFR2+MS+sag(4) 12,641.06 89.81 128.65 4,163.28 4,112.58 -7,766.88 2,471.87 6,023,890.93 547,676.19 2.15 8,148.46 MWD+IFR2+MS+sag(4) 12,735.95 89.88 128.08 4,163.54 4,112.84 -7,825.78 2,546.27 6,023,832.50 547,750.94 0.61 8,228.38 MWD+IFR2+MS+sag(4) 12,830.83 90.62 128.67 4,163.13 4,112.43 -7,884.68 2,620.65 6,023,774.06 547,825.67 1.00 8,308.30 MWD+IFR2+MS+sag(4) 12,924.82 92.10 127.54 4,160.90 4,110.20 -7,942.66 2,694.59 6,023,716.53 547,899.95 1.98 8,387.20 MWD+IFR2+MS+sag(4) 12,995.00 92.10 127.54 4,158.32 4,107.62 -7,985.40 2,750.20 6,023,674.14 547,955.82 0.00 8,445.72 PROJECTED to TD brian.wheeler@halfiburtoow�.+.+... cary.taylor@halliburton.co r �a+r m�r+nohas�nw�.a. Checked By: nom � ., � Approved By: m cn .---, :x211-..,—,,a1 � Date: 2/11/2016 2:11:14PM Page 6 COMPASS 5000.1 Build 73 • • • Hilcorp Energy Company Milne Point M Pt L Pad MPL-47 PB1 50-029-23550-70-00 50-029-23550-70-00 Sperry Drilling Definitive Survey Report 11 February, 2016 11 III I A 1111 HAL.LWBURTON 1111 II I Sperry Drilling µG • Halliburton • Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well MPL-47 Project: Milne Point ND Reference: MPL-47 @ 50.70usft(Doyon 14) Site: M Pt L Pad MD Reference: MPL-47 @ 50.70usft(Doyon 14) Well: MPL-47 North Reference: True Wellbore: MPL-47 PB1 Survey Calculation Method: Minimum Curvature Design: MPL-47 PBI Database: Sperry EDM-NORTH US+CANADA Project Milne Point,ACT,MILNE POINT Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPL-47 Well Position +NI-S 0.00 usft Northing: 6,031,641.90 usft Latitude: 70°29'50.316 N +E/-W 0.00 usft Easting: 545,157.43 usft Longitude: 149°37'50.603 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 16.90 usft Wellbore MPL-47 PB1 Magnetics Model Name Sample Date- Declination Dip Angle Field Strength (°) (0) (nT) BGGM2015 2/6/2016 18.68 81.08 57,501 Design MPL-47 PB1 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 33.80 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (0) 33.80 0.00 0.00 160.99 Survey Program Date 2/11/2016 From To (usft) (usft)> Survey(Wellbore) Tool Name Description Survey Date 82.00 1,582.00 SRG-MS(MPL-47 PB1) SRG-MS Surface readout gyro multishot 01/22/2016 1,639.10 7,739.95 MWD+IFR2+MS+sag(1)(MPL-47 PB1) MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 01/22/2016 7,740.95 11,413.83 MWD+IFR2+MS+sag(1)(MPL-47 PB1) MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 01/22/2016 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (0) (°) (usft) (usft) (usft) (usft) (ft) (ft) (011001 (ft) Survey Tool Name 33.80 0.00 0.00 33.80 -16.90 0.00 0.00 6,031,641.90 545,157.43 0.00 0.00 UNDEFINED 82.00 0.53 260.00 82.00 31.30 -0.04 -0.22 6,031,641.86 545,157.21 1.10 -0.03 SRG-MS(1) 182.00 0.41 269.37 182.00 131.30 -0.12 -1.03 6,031,641.77 545,156.40 0.14 -0.22 SRG-MS(1) 282.00 0.63 231.16 281.99 231.29 -0.47 -1.82 6,031,641.42 545,155.61 0.40 -0.15 SRG-MS(1) 382.00 3.54 212.51 381.92 331.22 -3.42 -3.91 6,031,638.46 545,153.54 2.95 1.96 SRG-MS(1) 482.00 4.60 210.17 481.66 430.96 -9.49 -7.58 6,031,632.36 545,149.91 1.07 6.50 SRG-MS(1) 582.00 4.77 212.97 581.33 530.63 -16.45 -11.86 6,031,625.38 545,145.67 0.28 11.69 SRG-MS(1) 682.00 6.16 221.48 680.87 630.17 -23.95 -17.68 6,031,617.84 545,139.90 1.61 16.89 SRG-MS(1) 782.00 7.42 221.07 780.17 729.47 -32.84 -25.47 6,031,608.91 545,132.16 1.26 22.75 SRG-MS(1) 882.00 10.36 226.50 878.96 828.26 -43.90 -36.24 6,031,597.78 545,121.46 3.05 29.70 SRG-MS(1) 982.00 11.92 228.42 977.07 926.37 -56.95 -50.49 6,031,584.65 545,107.29 1.60 37.40 SRG-MS(1) 1,082.00 16.15 231.27 1,074.07 1,023.37 -72.51 -69.07 6,031,568.98 545,088.81 4.28 46.06 SRG-MS(1) 2/11/2016 2:01:51PM Page 2 COMPASS 5000.1 Build 73 • Halliburton • Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well MPL-47 Project: Milne Point TVD Reference: MPL-47 @ 50.70usft(Doyon 14) Site: M Pt L Pad MD Reference: MPL-47 @ 50.70usft(Doyon 14) Well: MPL-47 North Reference: True Wellbore: MPL-47 PB1 Survey Calculation Method: Minimum Curvature Design: MPL-47 PB1 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi, TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°)' (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 1,182.00 20.66 232.99 1,168.93 1,118.23 -91.84 -94.02 6,031,549.50 545,063.98 4.54 56.21 SRG-MS(1) 1,282.00 25.03 226.99 1,261.07 1,210.37 -116.90 -123.59 6,031,524.26 545,034.56 4.95 70.27 SRG-MS(1) 1,382.00 30.47 223.48 1,349.54 1,298.84 -149.76 -156.54 6,031,491.21 545,001.82 5.68 90.60 SRG-MS(1) 1,482.00 36.56 220.22 1,432.89 1,382.19 -190.94 -193.25 6,031,449.81 544,965.36 6.35 117.58 SRG-MS(1) 1,582.00 38.39 217.11 1,512.25 1,461.55 -238.45 -231.23 6,031,402.07 544,927.68 2.63 150.13 SRG-MS(1) 1,639.10 40.73 214.92 1,556.27 1,505.57 -267.87 -252.59 6,031,372.53 544,906.50 4.77 170.99 MWD+IFR2+MS+sag(2) 1,733.37 46.01 212.87 1,624.78 1,574.08 -321.61 -288.63 6,031,318.57 544,870.79 5.80 210.06 MWD+IFR2+MS+sag(2) 1,827.11 52.88 213.03 1,685.69 1,634.99 -381.34 -327.35 6,031,258.62 544,832.44 7.33 253.91 MWD+IFR2+MS+sag(2) 1,923.32 55.85 210.05 1,741.75 1,691.05 -447.98 -368.21 6,031,191.73 544,791.99 3.98 303.61 MWD+IFR2+MS+sag(2) 2,016.85 57.22 209.69 1,793.32 1,742.62 -515.64 -407.06 6,031,123.85 544,753.55 1.50 354.93 MWD+IFR2+MS+sag(2) 2,111.09 55.54 211.07 1,845.50 1,794.80 -583.34 -446.74 6,031,055.91 544,714.29 2.16 406.01 MWD+IFR2+MS+sag(2) 2,205.37 56.06 211.02 1,898.49 1,847.79 -650.15 -486.95 6,030,988.87 544,674.48 0.55 456.08 MWD+IFR2+MS+sag(2) 2,300.53 61.42 210.97 1,947.86 1,897.16 -719.85 -528.83 6,030,918.92 544,633.04 5.63 508.34 MWD+IFR2+MS+sag(2) 2,395.06 61.47 211.95 1,993.04 1,942.34 -790.68 -572.16 6,030,847.84 544,590.14 0.91 561.19 MWD+IFR2+MS+sag(2) 2,489.01 63.88 211.54 2,036.17 1,985.47 -861.66 -616.07 6,030,776.60 544,546.67 2.59 613.99 MWD+IFR2+MS+sag(2) 2,578.97 64.20 210.34 2,075.55 2,024.85 -931.03 -657.65 6,030,706.98 544,505.51 1.25 666.03 MWD+IFR2+MS+sag(2) 2,672.29 62.79 211.45 2,117.19 2,066.49 -1,002.69 -700.53 6,030,635.07 544,463.08 1.85 719.82 MWD+IFR2+MS+sag(2) 2,765.56 64.43 210.67 2,158.65 2,107.95 -1,074.26 -743.63 6,030,563.25 544,420.42 1.91 773.45 MWD+IFR2+MS+sag(2) 2,862.59 64.94 210.44 2,200.14 2,149.44 -1,149.79 -788.22 6,030,487.45 544,376.29 0.57 830.34 MWD+IFR2+MS+sag(2) 2,94.4.75 64.95 211.36 2,234.93 2,184.23 -1,213.66 -826.44 6,030,423.36 544,338.46 1.01 878.27 MWD+IFR2+MS+sag(2) 3,049.16 65.47 211.18 2,278.71 2,228.01 -1,294.67 -875.64 6,030,342.06 544,289.76 0.52 938.84 MWD+IFR2+MS+sag(2) 3,145.34 66.28 209.86 2,318.02 2,267.32 -1,370.29 -920.21 6,030,266.18 544,245.65 1.51 995.81 MWD+IFR2+MS+sag(2) 3,239.80 65.65 209.99 2,356.50 2,305.80 -1,445.06 -963.25 6,030,191.16 544,203.07 0.68 1,052.49 MWD+IFR2+MS+sag(2) 3,334.62 63.26 210.18 2,397.38 2,346.68 -1,519.08 -1,006.13 6,030,116.88 544,160.64 2.53 1,108.50 MWD+IFR2+MS+sag(2) 3,428.67 62.71 210.25 2,440.10 2,389.40 -1,591.49 -1,048.30 6,030,044.23 544,118.92 0.59 1,163.22 MWD+IFR2+MS+sag(2) 3,521.69 63.07 210.36 2,482.49 2,431.79 -1,662.97 -1,090.08 6,029,972.50 544,077.58 0.40 1,217.20 MWD+IFR2+MS+sag(2) 3,616.83 62.09 210.75 2,526.30 2,475.60 -1,735.69 -1,133.01 6,029,899.52 544,035.10 1.09 1,271.97 MWD+IFR2+MS+sag(2) 3,711.97 62.62 210.34 2,570.45 2,519.75 -1,808.28 -1,175.84 6,029,826.69 543,992.71 0.68 1,326.65 MWD+IFR2+MS+sag(2) 3,806.90 62.58 211.61 2,614.13 2,563.43 -1,880.54 -1,219.21 6,029,754.17 543,949.78 1.19 1,380.84 MWD+IFR2+MS+sag(2) 3,900.85 62.34 211.56 2,657.57 2,606.87 -1,951.50 -1,262.85 6,029,682.95 543,906.59 0.26 1,433.72 MWD+IFR2+MS+sag(2) 3,994.83 61.60 212.45 2,701.74 2,651.04 -2,021.85 -1,306.81 6,029,612.35 543,863.06 1.15 1,485.91 MWD+IFR2+MS+sag(2) 4,090.02 64.46 210.53 2,744.91 2,694.21 -2,094.19 -1,351.10 6,029,539.75 543,819.21 3.50 1,539.88 MWD+IFR2+MS+sag(2) 4,182.96 64.82 211.10 2,784.72 2,734.02 -2,166.32 -1,394.12 6,029,467.37 543,776.63 0.68 1,594.06 MWD+IFR2+MS+sag(2) 4,277.75 65.35 209.55 2,824.65 2,773.95 -2,240.52 -1,437.52 6,029,392.91 543,733.68 1.58 1,650.08 MWD+IFR2+MS+sag(2) 4,372.46 64.74 209.47 2,864.61 2,813.91 -2,315.25 -1,479.82 6,029,317.93 543,691.85 0.65 1,706.95 MWD+IFR2+MS+sag(2) 4,466.15 64.78 209.25 2,904.56 2,853.86 -2,389.11 -1,521.37 6,029,243.83 543,650.75 0.22 1,763.25 MWD+IFR2+MS+sag(2) 4,560.73 63.45 209.66 2,945.85 2,895.15 -2,463.20 -1,563.21 6,029,169.49 543,609.36 1.46 1,819.67 MWD+IFR2+MS+sag(2) 4,654.96 62.94 209.75 2,988.34 2,937.64 -2,536.25 -1,604.89 6,029,096.19 543,568.14 0.55 1,875.16 MWD+IFR2+MS+sag(2) 4,749.41 63.22 210.70 3,031.10 2,980.40 -2,609.02 -1,647.28 6,029,023.18 543,526.19 0.94 1,930.15 MWD+IFR2+MS+sag(2) 4,843.51 63.04 210.72 3,073.63 3,022.93 -2,681.18 -1,690.15 6,028,950.76 543,483.76 0.19 1,984.42 MWD+IFR2+MS+sag(2) 2/11/2016 2:01:51PM Page 3 COMPASS 5000.1 Build 73 • Halliburton • Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well MPL-47 Project: Milne Point TVD Reference: MPL-47 @ 50.70usft(Doyon 14) Site: M Pt L Pad MD Reference: MPL-47 @ 50.70usft(Doyon 14) Well: MPL-47 North Reference: True Wellbore: MPL-47 PB1 Survey Calculation Method: Minimum Curvature Design: MPL-47 PB1 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +Nl-S +EI-W Northing Easting DLS Section (usft) (0) (0) (usft) (usft) (usft) (usft) (ft) (ft) (0/100') (ft) Survey Tool Name 4,937.45 61.81 212.16 3,117.12 3,066.42 -2,752.23 -1,733.58 6,028,879.46 543,440.78 1.892,037.44 MWD+IFR2+MS+sag(2) 5,032.56 62.06 212.47 3,161.87 3,111.17 -2,823.16 -1,778.44 6,028,808.27 543,396.35 0.39 2,089.89 MWD+IFR2+MS+sag(2) 5,126.40 61.81 212.37 3,206.02 3,155.32 -2,893.05 -1,822.83 6,028,738.11 543,352.38 0.28 2,141.51 MWD+IFR2+MS+sag(2) 5,222.38 61.00 212.43 3,251.95 3,201.25 -2,964.21 -1,867.99 6,028,666.69 543,307.66 0.85 2,194.08 MWD+IFR2+MS+sag(2) 5,317.44 62.43 211.59 3,297.00 3,246.30 -3,035.19 -1,912.36 6,028,595.45 543,263.73 1.69 2,246.74 MWD+IFR2+MS+sag(2) 5,411.97 63.27 210.98 3,340.13 3,289.43 -3,107.07 -1,956.03 6,028,523.31 543,220.50 1.06 2,300.47 MWD+IFR2+MS+sag(2) 5,505.49 63.60 210.64 3,381.96 3,331.26 -3,178.91 -1,998.88 6,028,451.21 543,178.10 0.48 2,354.4.4 MWD+IFR2+MS+sag(2) 5,599.98 63.34 210.23 3,424.16 3,373.46 -3,251.81 -2,041.70 6,028,378.07 543,135.72 0.48 2,409.41 MWD+IFR2+MS+sag(2) 5,692.58 64.63 208.10 3,464.78 3,414.08 -3,324.47 -2,082.24 6,028,305.17 543,095.62 2.49 2,464.90 MVD+IFR2+MS+sag(2) 5,787.11 62.37 205.43 3,506.96 3,456.26 -3,399.98 -2,120.35 6,028,229.43 543,057.98 3.48 2,523.88 MVVD+IFR2+MS+sag(2) 5,881.89 63.35 200.87 3,550.22 3,499.52 -3,477.51 -2,153.48 6,028,151.71 543,025.32 4.40 2,586.39 MWD+IFR2+MS+sag(2) 5,976.43 64.27 196.37 3,591.96 3,541.26 -3,557.88 -2,180.55 6,028,071.19 542,998.75 4.38 2,653.56 MWD+IFR2+MS+sag(2) 6,071.06 65.24 190.83 3,632.34 3,581.64 -3,641.03 -2,200.65 6,027,987.93 542,979.16 5.39 2,725.63 MWD+IFR2+MS+sag(2) 6,164.46 65.40 185.28 3,671.37 3,620.67 -3,725.02 -2,212.53 6,027,903.88 542,967.78 5.40 2,801.16 MWD+IFR2+MS+sag(2) 6,260.27 64.91 181.80 3,711.63 3,660.93 -3,811.77 -2,217.90 6,027,817.10 542,962.94 3.34 2,881.44 MWD+IFR2+MS+sag(2) 6,354.59 65.11 180.72 3,751.48 3,700.78 -3,897.24 -2,219.78 6,027,731.63 542,961.58 1.06 2,961.64 MWD+IFR2+MS+sag(2) 6,446.28 65.93 178.74 3,789.48 3,738.78 -3,980.68 -2,219.39 6,027,648.20 542,962.48 2.16 3,040.65 MWD+IFR2+MS+sag(2) 6,542.92 66.11 173.59 3,828.78 3,778.08 -4,068.74 -2,213.48 6,027,560.18 542,968.92 4.87 3,125.84 MWD+IFR2+MS+sag(2) 6,633.55 67.46 169.22 3,864.51 3,813.81 -4,151.07 -2,201.02 6,027,477.94 542,981.88 4.67 3,207.73 MW3+IFR2+MS+sag(2) 6,729.51 71.20 162.50 3,898.41 3,847.71 -4,238.04 -2,179.04 6,027,391.12 543,004.39 7.62 3,297.12 MWD+IFR2+MS+sag(2) 6,823.81 72.53 156.41 3,927.79 3,877.09 -4,321.90 -2,147.59 6,027,307.46 543,036.34 6.30 3,386.65 MWD+IFR2+MS+sag(2) 6,918.41 73.91 151.41 3,955.12 3,904.42 -4,403.20 -2,107.77 6,027,226.40 543,076.66 5.27 3,476.49 MWD+IFR2+MS+sag(2) 7,012.81 73.75 146.56 3,981.42 3,930.72 -4,480.88 -2,061.07 6,027,149.02 543,123.82 4.94 3,565.14 MWD+IFR2+MS+sag(2) 7,107.25 76.02 140.33 4,006.07 3,955.37 -4,554.06 -2,006.78 6,027,076.18 543,178.55 6.81 3,652.01 MWD+IFR2+MS+sag(2) 7,201.11 78.18 135.15 4,027.03 3,976.33 -4,621.73 -1,945.26 6,027,008.89 543,240.47 5.85 3,736.03 MWD+IFR2+MS+sag(2) 7,295.42 79.44 129.33 4,045.35 3,994.65 -4,683.88 -1,876.80 6,026,947.16 543,309.31 6.20 3,817.10 MWD+IFR2+MS+sag(2) 7,389.93 81.55 124.62 4,060.97 4,010.27 -4,739.92 -1,802.35 6,026,891.58 543,384.09 5.40 3,894.33 MWD+IFR2+MS+sag(2) 7,484.13 83.76 124.45 4,073.01 4,022.31 -4,792.88 -1,725.39 6,026,839.10 543,461.36 2.35 3,969.47 MWD+IFR2+MS+sag(2) 7,579.77 82.38 123.47 4,084.55 4,033.85 -4,845.91 -1,646.65 6,026,786.55 543,540.41 1.77 4,045.26 MWD+IFR2+MS+sag(2) 7,626.07 82.83 124.11 4,090.51 4,039.81 -4,871.45 -1,608.49 6,026,761.24 543,578.72 1.68 4,081.83 MWD+IFR2+MS+sag(2) 7,740.95 85.55 122.82 4,102.14 4,051.44 -4,934.46 -1,513.15 6,026,698.82 543,674.43 2.62 4,172.46 MWD+IFR2+MS+sag(3) 7,829.33 86.54 124.71 4,108.23 4,057.53 -4,983.46 -1,439.86 6,026,650.27 543,748.01 2.41 4,242.66 MWD+IFR2+MS+sag(3) 7,928.18 88.27 126.52 4,112.71 4,062.01 -5,040.96 -1,359.59 6,026,593.26 543,828.62 2.53 4,323.18 MWD+IFR2+MS+sag(3) 8,024.50 88.27 127.58 4,115.62 4,064.92 -5,098.97 -1,282.75 6,026,535.73 543,905.80 1.10 4,403.05 MWD+IFR2+MS+sag(3) 8,116.41 88.52 127.56 4,118.19 4,067.49 -5,154.99 -1,209.93 6,026,480.16 543,978.95 0.27 4,479.73 MWD+IFR2+MS+sag(3) 8,211.37 87.78 128.14 4,121.26 4,070.56 -5,213.23 -1,134.99 6,026,422.38 544,054.24 0.99 4,559.20 MWD+IFR2+MS+sag(3) 8,306.52 88.21 129.52 4,124.58 4,073.88 -5,272.85 -1,060.91 6,026,363.22 544,128.67 1.52 4,639.70 MWD+IFR2+MS+sag(3) 8,396.58 88.08 128.49 4,127.50 4,076.80 -5,329.50 -990.97 6,026,307.00 544,198.95 1.15 4,716.05 MWD+IFR2+MS+sag(3) 8,489.68 88.77 128.58 4,130.06 4,079.36 -5,387.48 -918.17 6,026,249.47 544,272.10 0.75 4,794.58 MWD+IFR2+MS+sag(3) 8,586.04 89.63 128.81 4,131.40 4,080.70 -5,447.71 -842.97 6,026,189.70 544,347.65 0.92 4,876.02 MWD+IFR2+MS+sag(3) 2/11/2016 2:01:51PM Page 4 COMPASS 5000.1 Build 73 • Halliburton • Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well MPL-47 Project: Milne Point TVD Reference: MPL-47 @ 50.70usft(Doyon 14) Site: M Pt L Pad MD Reference: MPL-47 @ 50.70usft(Doyon 14) Well: MPL-47 North Reference: True Wellbore: MPL-47 PB1 Survey Calculation Method: Minimum Curvature Design: MPL-47 PB1 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,679.89 90.00 129.23 4,131.71 4,081.01 -5,506.80 -770.06 6,026,131 06 544,420.92 0.60 4,955.64 MWD+IFR2+MS+sag(3) 8,775.08 89.32 129.40 4,132.27 4,081.57 -5,567.11 -696.41 6,026,071.21 544,494.92 0.74 5,036.65 MWD+IFR2+MS+sag(3) 8,870.07 89.14 129.58 4,133.55 4,082.85 -5,627.51 -623.11 6,026,011.26 544,568.58 0.27 5,117.63 MWD+IFR2+MS+sag(3) 8,962.52 87.78 130.00 4,136.03 4,085.33 -5,686.66 -552.10 6,025,952.55 544,639.94 1.54 5,196.68 MWD+IFR2+MS+sag(3) 9,060.49 90.31 127.39 4,137.67 4,086.97 -5,747.88 -475.66 6,025,891.79 544,716.74 3.71 5,279.47 MWD+IFR2+MS+sag(3) 9,151.77 90.31 126.46 4,137.17 4,086.47 -5,802.72 -402.69 6,025,837.41 544,790.04 1.02 5,355.08 MWD+IFR2+MS+sag(3) 9,247.15 91.48 125.86 4,135.68 4,084.98 -5,858.99 -325.69 6,025,781.61 544,867.37 1.38 5,433.36 MWD+IFR2+MS+sag(3) 9,340.92 89.94 125.87 4,134.52 4,083.82 -5,913.92 -249.71 6,025,727.15 544,943.67 1.64 5,510.05 MWD+IFR2+MS+sag(3) 9,435.70 89.20 124.71 4,135.23 4,084.53 -5,968.68 -172.35 6,025,672.87 545,021.36 1.45 5,587.01 MWD+IFR2+MS+sag(3) 9,528.69 88.95 124.34 4,136.73 4,086.03 -6,021.37 -95.75 6,025,620.64 545,098.27 0.48 5,661.79 MWD+IFR2+MS+sag(3) 9,622.72 90.19 124.99 4,137.44 4,086.74 -6,074.85 -18.41 6,025,567.64 545,175.92 1.49 5,737.54 MWD+IFR2+MS+sag(3) 9,717.58 92.35 127.02 4,135.34 4,084.64 -6,130.60 58.30 6,025,512.37 545,252.96 3.12 5,815.23 MWD+IFR2+MS+sag(3) 9,810.23 91.11 127.91 4,132.54 4,081.84 -6,186.93 131.80 6,025,456.49 545,326.80 1.65 5,892.43 MWD+IFR2+MS+sag(3) 9,904.75 90.49 127.45 4,131.22 4,080.52 -6,244.69 206.60 6,025,399.19 545,401.94 0.82 5,971.42 MWD+IFR2+MS+sag(3) 9,995.95 90.68 126.47 4,130.29 4,079.59 -6,299.53 279.47 6,025,344.80 545,475.13 1.09 6,046.99 MWD+IFR2+MS+sag(3) 10,090.90 90.99 126.02 4,128.90 4,078.20 -6,355.66 356.04 6,025,289.14 545,552.03 0.58 6,125.00 MWD+IFR2+MS+sag(3) 10,185.38 90.43 124.87 4,127.73 4,077.03 -6,410.44 433.00 6,025,234.83 545,629.32 1.35 6,201.87 MWD+IFR2+MS+sag(3) 10,281.24 90.56 123.61 4,126.91 4,076.21 -6,464.38 512.24 6,025,181.39 545,708.88 1.32 6,278.67 MWD+IFR2+MS+sag(3) 10,375.94 90.43 123.00 4,126.09 4,075.39 -6,516.37 591.38 6,025,129.88 545,788.33 0.66 6,353.62 MWD+IFR2+MS+sag(3) 10,472.68 90.56 122.71 4,125.25 4,074.55 -6,568.85 672.65 6,025,077.89 545,869.90 0.33 6,429.70 MWD+IFR2+MS+sag(3) 10,566.72 90.31 121.40 4,124.54 4,073.84 -6,618.76 752.34 6,025,028.48 545,949.90 1.42 6,502.85 MWD+IFR2+MS+sag(3) 10,661.66 91.11 121.16 4,123.36 4,072.66 -6,668.05 833.48 6,024,979.68 546,031.32 0.88 6,575.88 MWD+IFR2+MS+sag(3) 10,755.38 90.37 121.94 4,122.15 4,071.45 -6,717.09 913.34 6,024,931.14 546,111.47 1.15 6,648.25 MWD+IFR2+MS+sag(3) 10,850.51 90.68 123.61 4,121.28 4,070.58 -6,768.58 993.32 6,024,880.14 546,191.75 1.79 6,722.99 MWD+IFR2+MS+sag(3) 10,944.89 90.62 120.12 4,120.21 4,069.51 -6,818.39 1,073.45 6,024,830.82 546,272.18 3.70 6,796.19 MWD+IFR2+MS+sag(3) 11,037.45 90.31 118.74 4,119.46 4,068.76 -6,863.87 1,154.07 6,024,785.84 546,353.06 1.53 6,865.45 MWD+IFR2+MS+sag(3) 11,131.28 91.30 119.75 4,118.14 4,067.44 -6,909.71 1,235.93 6,024,740.50 546,435.19 1.51 6,935.45 MWD+IFR2+MS+sag(3) 11,226.33 91.67 121.75 4,115.67 4,064.97 -6,958.29 1,317.58 6,024,692.43 546,517.13 2.14 7,007.97 MWD+IFR2+MS+sag(3) 11,318.04 92.16 124.55 4,112.61 4,061.91 -7,008.40 1,394.31 6,024,642.78 546,594.16 3.10 7,080.35 MWD+IFR2+MS+sag(3) 11,413.83 92.16 124.63 4,109.00 4,058.30 -7,062.74 1,473.12 6,024,588.93 546,673.28 0.08 7,157.40 MWD+IFR2+MS+sag(3) 11,556.00 92.16 124.63 4,103.64 4,052.94 -7,143.48 1,590.01 6,024,508.91 546,790.66 0.00 7,271.81 PROJECTED to TD brian.wheeler@hailiburton ...v-, .-- uwwr......n �. � Checked By: .com -.b,�,.,,•,,w Approved By: cary.tayiorahailiburton.com Date: 2/112016 2:01:51PM Page 5 COMPASS 5000.1 Build 73 ! • Hi/corp Energy Company CASING&CEMENTING REPORT Lease&Well No. MP L-47 Date Run 30-Jan-16 County State Alaska Supv. J.Lott/S.Barber CASING RECORD Surface V TO 7,672.00 Shoe Depth: PBTD: 7,579.14 No.Jts.Delivered 200 No.Jts.Run 189 No.Jts.Returned _ Length Measurements W/O Threads Ftg.Delivered Ftg.Run 7,614.89 Ftg.Returned _ Casing(Or Liner)Detail Setting Depths _ Its. Component Size Wt. Grade THD Make Length Bottom Top Shoe 9 5/8 TC-II 2.96 7,663.53 7,660.57 1 Casing 9 5/8 40.0 L-80 TC-II 39.97 7,660.57 7,620.60 Float Collar 9 5/8 TC-II 1.95 7,620.60 7,618.65 1 Casing 9 5/8 40.0 L-80 TC-II 37.72 7,618.65 7,580.93 Baffle Adapter 9 5/8 TC-II 1.79 7,580.93 7,579.14 125 Casing 9 5/8 40.0 L-80 TC-Il 5,040.24 7,579.14 2,538.90 ES Cementer 9 5/8 TC-II 4.02 2,538.90 2,534.88 62 Casing 9 5/8 40.0 L-80 TC-II 2,496.96 2,534.88 37.92 Hanger w/Pup Joint 9 5/8 TC-II Seaboard 3.55 37.92 34.37 RKB 34.37 Csg Wt.On Hook: 97 Type Float Collar: No.Hrs to Run: Csg Wt.On Slips: 42 Type of Shoe: Casing Crew: Weatherford Rotate Csg _ Yes X No Recip Csg _Yes X No 40 Ft.Min. 94 PPG Fluid Description: SPUD Liner hanger Info(Make/Model): Liner top Packer?: _Yes_No Liner hanger test pressure: Floats Held X Yes_ No Centralizer Placement: 10'from top and btm on shoe and float collar jts.1 every other joint to 6938'.1 on 3 jts above/below stage tool. CEMENTING REPORT Shoe @ 7661.3 FC @ 7,618.37 Top of Liner Preflush(Spacer) Type: Spacer Clean Density(ppg) 10.5 Volume pumped(BBLs) �... Lead Slurry Type: ArcticCem 745 sx/yield=2.49 ft3/sx Density(ppg) 12 Volume pumped(BBLs) 331 Mixing/Pumping Rate(bpm): 5.2 Tail Slurry w Type: SwiftCem 390 sx/yield=1.15 ft3/sx r Density(ppg) 15.8 Volume pumped(BBLs) 79 Mixing/Pumping Rate(bpm): ',2PostFlush(Spacer) rc Type: Density(ppg) Rate(bpm): Volume: LL Displacement: Type: Spud Mud Density(ppg) 9.4 Rate(bpm): 5.3 Volume(actual/calculated): 422/422 FCP(psi): 1070 Pump used for disp: Rig MP#2 Bump Plug? X Yes No Bump press 3300 Casing Rotated? Yes X No Reciprocated? _Yes X No %Returns during job 100 Cement returns to surface? X Yes-No Spacer returns? Yes X No Vol to Surf: 0 Cement In Place At: 15:23 Date: 1/29/2016 Estimated TOC: 2,536 Method Used To Determine TOC: Visually confirmed Stage Collar @ 2536_.67 Type Hal ES II Closure OK Preflush(Spacer) Type: Clean Spacer Density(ppg) 10.5 Volume pumped(BBLs) Lead Slurry Type: Perm L 402 sx/yield=4.32 ft3/sx Density(ppg) 10.7 Volume pumped(BBLs) 310 Mixing/Pumping Rate(bpm): Tail Slurry • t4 Type: Premium"G"265 sx/yield=1.13 ft3/sx H Density(ppg) 15.8 Volume pumped(BBLs) 55.3 Mixing/Pumping Rate(bpm): 4.3 i Post Flush(Spacer) 8 Type: Density(ppg) Rate(bpm): Volume: Di Displacement: Type: Spud Mud Density(ppg) 9.4 Rate(bpm): 4 Volume(actual/calculated): 172/172 FCP(psi): 450 Pump used for disp: Rig MP#2 Bump Plug? X Yes No Bump press 2000 Casing Rotated? Yes X No Reciprocated? Yes X No %Returns during job 94 Cement returns to surface? X Yes_No Spacer returns? X Yes_No Vol to Surf: 235 Cement In Place At: 3:30 Date: 1/30/2016 Estimated TOC: 0 Method Used To Determine TOC: Visual/Mud scale/PH tool/samples Post Job Calculations: Calculated Cmt Vol @ 0%excess: 581 Total Volume cmt Pumped: Cmt returned to surface: 477 Calculated cement left in wellbore: 299 OH volume Calculated: 580 OH volume actual: 580 Actual%Washout: www.wellez.net WellEz Information Management LLC ver_041416bf *Milne Point Unit L-47 H • Drilling Procedure ` Hilcorp Energy Company 10.6 Rig&Diverter Orientation on"L"pad: F (` ! to-,,`. 1 ) ? ''(....%M I !� �C..-- ]„y i�yt� I lil 11: / i 1 g I ' � ''I G ii 1111-1314.71 1 ,�l i _- ' i3 N --I ' I ,7 ,_ 0!!0.. 1 .: , 16.4 I mu 3 171 411,141421,1 j11".••••;;Z".- , 1 . :1 I -.1 � _ I� rill r 1411H11 MI :,,,0 , , �.. ,.....,,:vinit I i 1' ,, , , ,,,,..,,,e) 1 .,..„,,,,, _...„,.. , , , ,,,,, ,„..,e,.,,,, ,,,,,_;",., .:...„4... ., ,....„, 1 i I 14 ;,z( c—_ // 7 Page 12 Revision 1 Dee,2015 • 110 215117 Maile Sweigart Alaska North Slope Team Hilcorp Alaska, LLC 3800 Centerpoint Drive, Ste 1400 Anchorage, Alaska 99503 Fiilrnrp Alauka.LLt Office: 907.777.8473 msweigart@hilcorp.com DATA LOGGED Z /1.1/2014 M K. BENDER Date: 2/16/16 RECEIVED To: Alaska Oil & Gas Conservation Commission FEB 16 ZUl6 Makana Bender Natural Resource Technician AOGCC 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MP L-47, L-48PB1 L-47 Prints: ROP-DGR-ADR-EWR-HORIZONTAL PRES 2IN MD, DGR-ADR-EWR-REVERTED INTERVAL 2IN TVD L-47PB 1 Prints: ROP-DGR-ADR-EWR-HORIZONTAL PRES 21N MD,DGR-ADR-EWR-INVERTED INTERVAL 2IN TVD E log data CD 1 : Final Well Data Date modified T,,l,e MPL-41 21'15/20151:04 PM He folder 2 6 8 2 1 MPL-47 PB1 2/15/2016105 PM File felclei 2 6 8 2 2 Each folder contains subfolders: Date modified Type CGM 2/15/2016 1:03 PM File folder Definitive Survey 2/15/2016 1:04 PM File folder DLIS+LAS 2/15/2016 1:04 PM File folder EMF 2/15/20161:04 PM File folder PDF 2/15/2016 1:04 PM File folder TIFF 2/15/2016 1:04 PM File folder Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: STATE OF ALASKA LASKA OIL AND GAS CONSERVATION COMMIS. REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed Abandon 0 Plug Perforations ❑ Fracture Stimulate 0 Pull Tubing ❑ Operations shutdown 0 Suspend 0 Perforate 0 Other Stimulate 0 Alter Casing0 Change Approved Program 0 Plug for Redrill ❑ Perforate New Pool ❑ Repair Well 0 Re-enter Susp Well 0 Other:Pull/ReSet LTP 0 2. Operator Name: BP Exploration(Alaska),Inc 4. Well Class Before Work 5. Permit to Drill Number: 214-117 3. Address: P.O.Box 196612 Anchorage, Development 0 Exploratory 0 AK 99519-6612 Stratigraphic 0 Service ❑ 6. API Number: 50-029-22209-03-00 7. Property Designation(Lease Number): ADL 0028308 8. Well Name and Number: PBU 02-32C 9. Logs(List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pools: PRUDHOE BAY,PRUDHOE OIL 11.Present Well Condition Summary: �� Total Depth: measured 11875 feet Plugs measured feet true vertical 8969 feet Junk measured 8946/9271 feet JAN $ 2 2016 Effective Depth: measured 11840 feet Packer measured 8270 feet true vertical 8967 feet Packer true vertical 8126.04 feet AOGCA[`/- Casing: Length: Size: MD: TVD: Burst: Collapse: Structural Conductor 77 20"91.5#H-40 27-104 27-104 1490 470 Surface 3430 13-3/8"68#L-80 26-3456 26-3456 5020 2260 Intermediate 6596 9-5/8"47#L-80 23-6620 23-6619 6870 4760 Production Liner See Attachment See Attachment See Attachment See Attachment See Attachment See Attachment Perforation Depth: Measured depth: 10530-10700 feet 10760-10880 feet 10935-11480 feet 11505-11630 feet 11700-11740 feet True vertical depth: 8934-8940 feet 8943-8948 feet 8949-8959 feet 8959-8959 feet 8961-8963 feet Tubing(size,grade,measured and true vertical depth) 4-1/2"12.6#L-80 20-8327 20-8177 Packers and SSSV(type,measured and See Attachment See Attachment See Attachment true vertical depth) 12.Stimulation or cement squeeze summary: Intervals treated(measured): Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 416 33677 4 550 331 Subsequent to operation: 455 35710 5 80 234 14.Attachments:(required per 20 AAC 25.070.25.071,a 25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory 0 Development 0 Service 0 Stratigraphic 0 Copies of Logs and Surveys Run 0 16.Well Status after work: Oil 0 Gas 0 WDSPL ❑ Printed and Electronic Fracture Stimulation Data 0 GSTOR ❑ WINJ 0 WAG 0 GINJ ❑ SUSP 0 SPLUG 0 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: N/A Contact Catron,Garry R(Wipro) Email Garry.Catron@bp.com Printed Name Catron,Garry R(Wipro) Title PDC Principal Engineer Signature ida 77 / "ip_- _ Phone +1 907 564 4424 Date 1/12/16 Form 10-404 Revised 5/2015 f T/ 1/ z-//JPO RBDMS-\tiAN 141016 Submit Original Only or-re 11110 • Q O O O O O O 0 O CO CO r-- ON O Nr- V LU 0 CO IC) O N V Ln N- r N. U io0) NN- C) CD NC00 • O CO N CO LC) .4- 00 Ln CO N- 00 c) co O) O O (fl () 0 0- 6) O) r- 00 (fl 00 00 CO 00 00 CO 0 1 1 1 1 1 1 1 1 1 H O) L1) CO — N- • O 00 Ln 0- O N70 07 O N N N Nt 0- 0- CD N CO OO CO 00 00 C as NT CO O Ln M Ln N- CD 1.0 N O C) C N OD N Cfl Ln O O 00 co (0 Co O) 6) O CO v o 03 0 C I I I I 4'j CNA Q MCD 10 CO 01 I's N- (O 00 LU1 N 00 0 0 N N N d- CO a) 0 0 N N CDC owrnr- O a O gO s3 0 0 0 2 • 00 O J 00 00 00 J C) J 00 JJJ cl) A 4t J � N CSO 4k CO U) N � v. 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O -- 0_ N0 * .0N -0 -0 LU LU O LU r r .-- o o O O O N N N N O 0 0 N N N N N N N v- • • tfi -J m $ 2 0 z ¢ 0 >< E 22 2CL E I / § \ ® H 22 - - � � _k f / 2 / II aLi.) co _ r2 „ O \ % 2 / \ : c © ,N7) w ¢ E o a-� = 1:= ,LO ECI G Ce / � kno � � / O m (i) -J 2L 22 # Q = > Q2O g@wgI0 Do „ f // E / / � z 0_J I- ƒ qOg0 / $ L/ CCcc 11 C \ I \ / / - / / Tu / f ! u D 2 Q ± 2 O - Q 5 m a_ a. m m a_ 2 t 3 2 6 Lo (NI LoG To- Lc) mq / _ # TREE= 4-1/16""McEVOY ACTUATOR=IMELLHEA R •Oi' 0 -3 **'jYIAX NOTES: 33.7°W@ ANGLE54'0 10490' OKB.REV= 69' f BF.ELEV= NA /J KOP= 665(7 20"CONDUCTOR, --j 116' Max Angle= 92"@9250 91.5#,H-40, 2204' 4-1/2"HES X NP,D=3.813" Dation MD= 10369' 1 1 �� Datum TVD= 8800,SS D=19.124" GAS LFT MANDRELS 13-3/8'CSG,68#,1-80,D=12.415" - 1 3458" ST MD TVD DEV TYPE VLV LATCH PORT DATE 3 3772 3772 0 MAG DMV RK 0 12/21/15 Mitlimun ID - 2.313"@ 8969' L 2 6021 6021 1 MMS CMY RK 0 12/21/15 2-718" BKR CMD SLD SLV4. 1 7877 7774 26 KBG-2 DM' BK 0 03/06/02 4 8461' H 9-518"X 7"BKR TIEBACK SLEEVE,D=7.75" 9-5/8"WfPSTOCK(XX/)0/XX) H ~6621 6467' J-19-5/8"X 7"BKR ZXP PKR,D=6.312" 9-518"CSG,47#,1-80 BTRS 0=8.681" H -6621 6474' --19-5/8"X 7"BKR MC HGR,D=6.290" 9-5/8"CSG ML.LOUT WINDOW (02-32B) 6621'-6638' I I 1 I 8268' 1-14-112"HES X NP,D=3.813" 8271' H 7"X 4-1/2"BKR S-3 PKR,D=3.875" S , 8296' --I4-1f2"HES X NP,D=3.813" ' 8316' H4-1/2"HES XN NF',MLLE)TO 3.80"(09/07/14) ? -I BKR TIEBA CK SLV,D=5.250" 8327' --I 7"X 4-1/2"BKR ZXP PKR,D=4.430" 4-1/2"TBG,12.6#,1-80 BT-M,.0152 bpf,D=3.958" -{ 8328' il 8328° H4-1/2"WLEG,D=4.000" 8338' -I 7°X 4-1/2"BKR FAMC HGR,D=4.430" 7"LNR,26#,1-80 BT-M,.0383 bpf,ID=6.276" H 8506' 1--4111 8962' - 45 KB LIP ASSY,ID=2.313"(12/20/15) 8969' --{2-718 BKR CMD SLD SLV,D 2.313"(12/20/15) 1 TOP OF 3-1/2"X 3-1i4"X 2-7/8"LNR/C8 .ff l--{ 8988• III • 8992' I--2-7/8"X NI?D=2.313"(12120/15) I • 9009' H3-112"I-ES X NP,D=2.813" 1 4-1/2"WtPSTOC,)C(10/25/14) -{ 904V , ko ??? I--FISH.4 SLPS FROM TBG STOP(12/15/15) 4-1/2"LNR,12.6#,L-80 ST,.0152 bpf,D=3.958" -9041 + ??? --I FISH 2 GRA(�LES FROM WFD Rte EAS SPEAR(08117/15) i 3-1/2"LW,9.2#,1-80 SR.,.0087 bpf,D=2.992" - 9042' Nam fit.:. MLLOUT W OW(02-320) 9041'-9050' PERFORATION SLWARY > '\ »� *IC,...it,,,,, 9042' H3-1t2"X 3-3/16"XO,C)=2.786' REF LOG: BKR RPR/GR/OCL on 11/05/14 " ' ♦4,#� .`, 10606' N3-3/16"X 2-7/8"XO,D=2.377" I ANGLE AT TOP PERF: 810 7 1053(7 •� 0• . Note:Refer to FYoduction DB for historical perf data ,x'►`� a'%. ti 10607' -2-7/8"MARKER PUP SIZE SPF INTERVAL OpnfSgz SHOT SQZ �' `fir •. JT W/2 RA TAGS 2" 6 10530-10700 O 11/06/14 4t#14, .� 2" 6 10760-10880 O 11!06/14 3-1/4"UR,6.6#, 10606' 2" 6 10935 11480 0 11/06/14 L-80 TC11,.0079 bpf, r��• .1� �'7‘.#,.. 1+� 2" 8 11505-11630 0 11/06/14 D=2.850" Pt3TD 11840' �'•�� 2" 6 11700 11740 0 11KI6J14 •1��. 2-7/8"LNR,6.4#,L-80 STL,.0058 bpf,D=2.441" J- 11875' CATE REV BY COM NTS DATE RFS/BY COMMENTS P -OE BAY ( MT 10104/91 AUDI INITIAL COMPLETION 02/05/15 TJHIPJC PURESET LTP 1 WWELL.: 02-32C 12/21/99 CTD SIDETRACK (02-32A) 01/01/16 CJNrTLH FULL LIP/LEFT FISH(08/16/15) PERMT b:"2141170 03/06102 0.16 RIG SIDETRACK(02-328) 01/01/16rSWCJTLI-SETLTPASSY/RSH(12/20/15) APINo: 50-029-22209-03 11/07/14 NORCIC GTD(02-32C) SEC 25,T11 t+(R14E 23'ESL&740'FWL 11/10/14 NS/JMD FINAL ODEAPPRpVAL 12/02/14 PJC CtMDUCTOR CORRECTION BP Exploration(Alaska) OF 71.1 -0".A I%j s THE STATE Alaska Oil and Gas ;. - Conservati®n Commission T A S KA 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OF LASFax: 907.276.7542 www.aogcc.alaska.gov Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive,Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU L-47 Hilcorp Alaska, LLC Permit No: 215-117 Surface Location: 3450' FSL, 4722' FEL, SEC. 8, T13N, R10E, UM, AK Bottomhole Location: 730' FSL, 1994' FEL, SEC. 17, T13N, R10E, UM, AK Dear Mr. Keller: Enclosed is the approved application for permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, i%/y -4 Cathy P Foerster Chair DATED thisl IP day of July, 2015. 41110A OIL AND GASSTATE CONSERVOFALASKA ATION CCOON PERMIT TO DRILL 20 AAC 25.005 la.Type of Work: lb.Proposed Well Class: Development-Oil Q 'Service- Winj ❑ Single Zone Q . lc.Specify if well is,proposed for: Drill O. Lateral ❑ Stratigraphic Test ❑ Development-Ga: ❑ Service-Supply ❑ Multiple Zone ❑ Coalbed Gas ❑ Gas Hydrates ❑ Redrie❑ Reentry ❑ Exploratory ❑ Service- WAG ❑ Service-Disp ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket Q, Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC • Bond No. 022035244, MPU L-47 s- 3. 3.Address: 6.Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Drive,Suite 1400,Anchorage AK 99503 MD: 13,002'. TVD: 4,067' • Milne Point Unit 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): .04 Schrader Bluff Oil Pool- Surface: 3450'FSL,4722'FEL,Sec 8,T13N,R10E,UM,AK • ADL 025515 a SSOi Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 1603'FNL,818'FEL,Sec 18,T13N,R10E,UM,AK N/A L, 8/20/2015 Total Depth: 9.Acres in Property: Tj x+14.Distance to Nearest Property: 730 FSL, 1994'FEL,Sec 17,T13N,R10E,UM,AK 545 S07:- 15935'from Unit Boundry 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL: • 47 feet 15.Distance to Nearest Well Open Surface: x-545157.43 y- 6031641.9 Zone-4 , GL Elevation above MSL: •17 feet to Same Pool: -2,000'L-46(future) 16.Deviated wells: Kickoff depth: 300 feet < 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 94 degrees• Downhole: 1828 psi ' Surface: 1420 psi 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Stg 1 -Lead-1808 ft3/Tail-445 ft3 12-1/4" 9-5/8" 40 L-80 TC-II 7,941' 0 0 7,941' 4,088' Stg 2-Lead-1813 ft3/Tail-314 ft3 7-5/8" 29.7 L-80 VAM SLIJ-II 7,741' 0 0 7,741' 4,070' Vire_-6,44_ G,hen- 2c�. 8-1/2" 5-1/2" 17 L-80 DWC/C HT 13,002' 7,741' 4,070' 13,002' 4,067' Cmntess Prod(Slotted w/Swell Pkr) 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 Conductor/Structural RE ElqED Surface Intermediate ,IU _ 0 1 /0 15 Production Liner GCC Perforation Depth MD(ft): Perforation Depth ND(ft): 20. Attachments: Property Plat Q BOP Sketch El Drilling Program ❑✓ Time v.Depth Plot ❑✓ Shallow Hazard Analyss❑ Diverter Sketch Q Seabed Report ❑ Drilling Fluid Program ❑✓ 20 AAC 25.050 requiremensO 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. Contact Luke Keller Email Ikeller(c�hiicorp.com Printed Name uk Keller Title Drilling Engineer aL_ Signature Phone 907-777-8395 Date 7/(/-20/-s" Commission Use Only Permit to Drill API Number: _ Permit Approval 7I /� ( � See cover letter for other Number: J[5--'I 7- 50-O Q!-(236-so-00 -(fid Date: I W requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed met ne,gas hydrates,or gas contained in sh: Other: pss 130 P -7::::-E Samples req'd: Yes Ns) Mud log req'd:Ye No[( � C)L� H2S measures: Yes Nib❑ Directional svy req'd:Ys q No pSpacing exception req'd: Ys❑ Nhy Inclination-only svy req'd:Yes❑ No 912-€- (11, __ APPROVED BY /Approved by: COMMISSIONER THE COMMISSIONN/ , Date: 7(to -IS- 7Ro IG I VA ae /I5.O ��S Submn Form ane .31t Form 10-401(Re ised 10/2012) This permit is valid for 24 h al(20 AAC 25.005(8)) Attach ents in Duplicate • Luke Keller Hilcorp Alaska, LLC Drilling Engineer • P.O. Box 244027 Anchorage,AK 99524-4027 Tel 907 777 8395 Email Ikeller@hilcorp.com nileorp Ala,6a,LIE ^ July 1st, 2015 RECEIVED ED JUL 01 2015 Commissioner AOGGC Alaska Oil &Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 Re: MPL-47 Dear Commissioner, Enclosed for review and approval is the Permit to Drill for MPL-47 oil well. MPU L-47 is a grassroots ESP producer planned to be drilled in the Schrader Bluff OA sand. L-47 is part of a(5)well pilot program targeting the OA sand. Each producing lateral will have water injection support on either side. The directional plan is a catenary wellpath build with 9-5/8" surface casing set into the top of the Schrader Bluff OA sand. A lateral section will then be drilled in the OA sand. A slotted liner will be run in the open hole section and the well produced with an ESP assembly. Drilling operations are expected to commence approximately August 20th, 2015. Nordic Calista Rig#3 will be used to drill and complete the wellbore. If you have any questions, please don't hesitate to contact myself at 777-8395 or Paul Mazzolini at 777-8369. Sincerely, Luke Keller Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 i �► Hilcorp Alaska, LLC Milne Point Unit (MPU) L-47 Drilling Program Version 1 April 29th, 2015 Milne Point Drilling Procedure Hilcorp Energy Company Contents 1.0 Well Summary 2 2.0 Management of Change Information 3 3.0 Tubular Program: 4 4.0 Drill Pipe Information: 4 5.0 Internal Reporting Requirements 5 6.0 Planned Wellbore Schematic 6 7.0 Drilling/Completion Summary 7 8.0 Mandatory Regulatory Compliance/Notifications 8 9.0 R/U and Preparatory Work 10 10.0 N/U 21-1/4"2M Diverter System 10 11.0 Drill 12-1/4"Hole Section 14 12.0 Run 9-5/8" Surface Casing 18 13.0 Cement 9-5/8" Surface Casing 24 14.0 BOP N/U and Test 29 15.0 Drill 8-1/2" Hole Section 30 16.0 Run 5-1/2"Production Liner 34 17.0 Run ESP assy. 38 18.0 RDMO 39 19.0 Diverter Schematic 40 20.0 BOP Schematic 41 21.0 Wellhead Schematic 42 22.0 Days Vs Depth 43 23.0 Formation Tops 44 24.0 Anticipated Drilling Hazards 45 25.0 Nordic#3 Rig Layout(Drillers Side) 47 26.0 Nordic#3 Rig Layout(Well End&Top View) 48 27.0 FIT Procedure 49 28.0 Choke Manifold Schematic 50 29.0 Casing Design Information 51 30.0 8-1/2"Hole Section MASP 52 31.0 Spider Plot(NAD 27)(Governmental Sections) 53 32.0 Surface Plat(As Built)(NAD 27) 54 33.0 Offset MW vs TVD Chart 55 34.0 Drill Pipe Information 5" 19.5#S-135 DS-50 56 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 1.0 Well Summary Well MPU L-47 Pad Milne Point"L"Pad Planned Completion Type ESP on 2-7/8"Production Tubing Target Reservoir(s) Schrader Bluff OA Sand Planned Well TD,MD/TVD 13,002' MD/4,067' TVD PBTD, MD/TVD 12,990' MD/4,067' TVD Surface Location(Governmental) 3,450' FSL, 4,722' FEL, Sec 8,T13N, R10E,UM, AK Surface Location(NAD 27) X=545,157.43' Y=6,031,641.9' Surface Location(NAD 83) Top of Productive Horizon (Governmental) 1603' FNL, 818'FEL, Sec 18, T13N, R10E,UM,AK TPH Location(NAD 27) X=543829.93, Y=6026580.49 TPH Location(NAD 83) BHL(Governmental) 730' FSL, 1994' FEL, Sec 17, T13N,R10E, UM,AK BHL(NAD 27) X=547961.16, Y=6023660.5 BHL(NAD 83) AFE Number 1511125 AFE Drilling Days 15 days AFE Completion Days 4 days AFE Drilling Amount $4,137,342.00 AFE Completion Amount $1,155,100.00 AFE Facility Amount $431,000.00 Maximum Anticipated Pressure (Surface) 1420 psig V Maximum Anticipated Pressure (Downhole/Reservoir) 1828 psig Work String 5" 19.5# S-135 DS-50(Weatherford Rental) KB Elevation above MSL: 30 ft+ 17 ft=47 ft GL Elevation above MSL: 17 ft BOP Equipment 11"x 5M Annular,(3)ea 11"x 5M Rams Page 2 Version 1 June, 2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 2.0 Management of Change Information Hilcorp Alaska, LLC Hilcorp ,Company Changes to Approved Permit to Drill Date: 6-26-2015 Subject: Changes to Approved Permit to Drill for MPU L-47 File#: MPU L47 Drilling and Completion Program Any modifications to MPU L-47 Drilling& Completion Program will be documented and approved below. Changes to an approved APD will be approved by the AOGCC. Sec Page Date Procedure Change Approved Approved By BY Approval: Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Version 1 June,2015 • j Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 3.0 Tubular Program: Hole OD (in) ID (in) Drift Conn Wt Grade Conn Burst Collapse Tension Section (in) OD(in) (#/ft) (psi) (psi) (k-lbs) _ Cond 13-3/8" 12.25" - - 68 A-53 Weld 12-1/4" 9-5/8" 8.835" 8.75" 10.235" 40 L-80 TC-II 5,750 ' 3,090 916 7-5/8" 6.82" 6.75" 7.711" 29.7 L-80 VAM 6,890 • 4,760 473 SLIJ-II 8-1/2" 5-1/2" 4.892" 4.767" 6.05" 17 L-80 DWC/C 7,740 7,100 397 HT 4.0 Drill Pipe Information: Hole OD (in) ID (in) TJ ID TJ OD Wt Grade Conn M/U M/U Tension Section (in) (in) (#/ft) (Min) (Max) (k-lbs) All 5" 4.276" 3.25" 6.625" 19.5 S-135 GPDS50 36,100 43,100 560k All casing will be new, PSL 1 (100%mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Version 1 June, 2015 • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 5.0 Internal Reporting Requirements 18.1 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. 18.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, Ikeller@hilcorp.com and cdinger@hilcorp.com 18.3 Intranet Home Page Morning Update • Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 18.4 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 18.5 Casing Tally • Send final"As-Run"Casing tally to lkeller@hilcorp.com and cdinger(ahilcorp.com 18.6 Casing and Cmt report • Send casing and cement report for each string of casing to Ikeller@hilcorp.com and cdinger@hilcorp.com 18.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Paul Mazzolini 907.777.8369 907.317.1275 pmazzolini@hilcorp.com Drilling Engineer Luke Keller 907.777.8395 832.247.3785 Ikeller@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Keith Elliot 907.777.8355 832.233.5855 kelliott@hilcorp.com Drlg Environmental Coord Julieanna Orczewska 907.777.8444 907.715.7060 jorczewska@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com EHS Field Coordinator Jimmy Watson 907.777.8450 907.744.7376 iiwatson@hilcorp.com Drilling Tech Cody Dinger /� 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 Version 1 June, 2015 ./ • II 141 Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 6.0 Planned Wellbore Schematic AFE No. Well Name: KB: 30 ft AGL 1511125 Milne Point Unit(MPU)L47 GL+RKB 17 ft+3011=47 ft API ti TED AFE WELLBORE DESIGN Proposed TD: 13.002 Permit No. TED Proposed TVD: 4,067' Geologic Information 'A.e<Pore i-sc-maticn Casing Info f Mud Info/Hole Size I Cement Specs MLATTMKW SS TVD FM Lithology Conductor aKs-n6reaaracc, 13-3/8"conductor(Pre-set)to 80'BGL(110'RKB) Interval: c 1 Tim id Surface Casing : E 9 9-5r8 408 L-80 TC-ll set at 7.941'MD MudT}ySW^reface hale 4.088'TVD Fresh WatertNative o '' i 1 ,. l N Weight Range: EOe ! Surface Casing Cement 8-8-9.2 1st Stage: is E 14. EO bbk 10.5 ppg Tuned spacer III u Lead:(3096 OH Excess)ARCTICCEM @ 10.7 ppg a d3 1 Tail:(30%OH Excess)SW IFTCEM 15.8 ppg -a es o m 2nd stage: aa 60 bbls 10.5 ppg Tuned spacer III v a Lead:(Until returns at surface)ARCTICCEM 10.7 ppg 175C' r - Tail:SWIFTCEM 15.8 ppg • _ L N bt I ri Production Liner e ,._°r+ c 5-1,2-178 L-80 DWC1C HT Slotted liner(g 13.002'MDI 4,067'TVD 'a.ir `o .M Tieback Ps 4 -"N 7-5i8"29.7#L-80 SLID-II 11 7741'MD 1 4.088'TVD c a" c I- U x jK t^ y Production Tubing ✓ c m.0tt r>-, N $ ! 2-748"6.4#L-80 8RD EUE. ti0 O a O n 1 D ,L . e o 14-A 1 Liner Tcp°a:ker:T , 47 7741 MD3500' uIm -, �, K-sands Coarse sand,silty �. shale,better \� ESP Interval.. UGNU developed Bullet Seal Assy Production Hole 1-Sands intervening shales - _ Slotted liner Mud Type: -4000' M-sands in the L and M ` 13 N N-sands Continued layering as 1 x,. Weight- Range: Schrader in Ugnu,more - _P/y ---, 1I — — 8.9-9 2 0-sands condensed with occ. -:- C�jh I� 643D0, coal l-- -- Page 6 Version 1 June, 2015 . 410 li Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 7.0 Drilling / Completion Summary MPU L-47 is a grassroots ESP producer planned to be drilled in the Schrader Bluff OA sand. L-47 is part of a(5)well pilot program targeting the OA sand. Each producing lateral will have water injection support on either side. The directional plan is a catenary wellpath build with 9-5/8" surface casing set into the top of the Schrader Bluff OA sand. A lateral section will then be drilled in the OA sand. A slotted liner will be run in the open hole section and the well produced with an ESP assembly. Drilling operations are expected to commence approximately August 20`h, 2015. Nordic Calista Rig# 3 will be used to drill and complete the wellbore. Surface casing will be run to 7,941' MD/4,088' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6 — 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste&mud generated during drilling operations will be hauled to the Milne Point G&I facility. General sequence of operations: 1. MOB Nordic Rig #3 to well site. 2. N/U 21-1/4" conductor and 16" diverter line. 3. Drill 12-1/4" hole to TD of surface hole section. Run and cmt 9-5/8" surface casing. 4. N/D diverter,N/U &test 11"x 5M BOP. 5. Drill 8-1/2" lateral to well TD. Run 5-1/2" slotted liner. 6. Run 7-5/8" Tieback. 7. Run ESP assy. 8. N/D BOP,N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR+Res 2. Production Hole: No mud logging. On site geologist. LWD: GR+ADR(For geo-steering) Page 7 Version 1 June, 2015 • Milne Point Unit L-47 re- Drilling Procedure Hilcorp Energy Company 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at(2) week intervals during the drilling and completion of MPU L-47 Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulationsulations 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 Version 1 June, 2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Compeny Summary of BOP Equipment and Test Requirements (A)e' 01 Hole Section Equipment Test Pressure(psi) 12-1/4" • 21-1/4"2M diverter w/ 16"diverter line Function Test Only • 11"x 5M Hydril Annular BOP • 11"x 5M Shaffer Double Ram Initial Test:250/3000 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross w/3"x 5M side outlets 8-1/2" • 11"x 5M Hydril Single Ram • 3"x 5M Choke Line Subsequent Tests: • 3"x 5M Kill line 250/3000 • 3"x 5M Choke manifold(10M Hydraulic remote Choke (Annular 2500 psi) • Standpipe,floor valves,etc • Primary closing unit: Hydril, 165 gal, 6 station accumulator w/dual electric and air pumps,w/ 1 (ea) electric over hydraulic remote control panel at the driller station. • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Tertiary pressure is provided by air pumps. Required AOGCC Notifications: • Well control event(BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email:jim.regg(a,alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-301-4533 /Email: guy.schwartz@alaska.gov Victoria Loepp/Petroleum Engineer/(0): 907-793-1247/Email: Victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone: 907-793-1236(During normal Business Hours) Notification/Emergency Phone: 907-659-2714(Outside normal Business Hours) v/ Page 9 Version 1 June, 2015 • • 1 ti Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 9.0 R/U and Preparatory Work 9.1 13-3/8" conductor is already driven to 80' BGL. 9.2 Dig out and set impermeable cellar. 9.3 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.4 Install Seaboard slip-on 16-3/4" 3M "A" section. Ensure to orient wellhead so that tree will line up with flowline later. Weld on 16"x 13-3/8" swedge. 9.5 Insure (2) 3"threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. These will be used to take cement returns to the cellar during the surface cmt job, and also to wash out the diverter and hanger in preparation for running the pack-off 9.6 Level pad and ensure enough room for layout of rig footprint and R/U. 9.7 Rig mat over footprint of rig. 9.8 Confirm that the rig is over the appropriate well slot. 9.9 MIRU Nordic #3. 9.10 Mud loggers WILL NOT be used on either hole section. 9.11 Mix spud mud for 12-1/4" surface hole section. Keep mud cool. 9.12 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.13 Install 5-1/2" liners in mud pumps. • Continental EMSCO F-1000 mud pumps are rated at 3500 psi (100%)/354 gpm(120 spm @ 95%eff)with 5-1/2" liners. 10.0 N/U 21-1/4" 2M Diverter System 10.1 N/U 21-1/4" Hydril MSP 2M diverter System (Diverter Schematic at Sec 18 at back of program). Page 10 Version 1 June, 2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Ewa Company • N/U 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead. • N/U 21-1/4"diverter"T". • Knife gate, 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. 10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. All a 10.3 Ensure to set up a clearly marked"warning zone" is established n each side and ahead of the vent line tip. "Warning Zone"must include: • A prohibition on vehicle parking • A prohibition on ignition sources or running equipment • A prohibition on staged equipment or materials • Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set 15.375" ID wearbushing in wellhead. Page 11 Version 1 June,2015 • • --- MDrilliilne ng Point UnitProcedurL-47e 11 Hilcorp Energy Company 10.5 Pad Drawing ■ ■ IN ■ II . I-(t _ 1 11 a t I a a ■ in a ■ a ■ - ,.121E=301= -Timm a--m`i 1 0 f ■ enara ■ a ■ ? 0 1 II Page 12 Version 1 June, 2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 10.6 Rig& Diverter Orientation on"L"pad: 111 i '16 in Diverter Line \\V \\! 1 1 1� r., — - 4JIJfl -mss= , L- il� r _l� Page 13 Version 1 June, 2015 • • II Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 11.0 Drill 12-1/4" Hole Section 11.1 P/U 12-1/4" directional drilling assy: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure Gyro MWD is R/U and operational. Be sure to run a UBHO sub so that wireline orientation is possible if necessary. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 5" 19.5# S-135. • Run a solid float in the surface hole section. 11.2 12-1/4" BHA (GR+ Res LWD and PWD planned in surface hole): / HAL.UBUPTON i 1,1P..ry.o".u'^. WELL INFORMATION11111 Created On:May 01 2011 BHA TallyCustomer : Hilcorp Engergy Well Name : MPL-1 Job Number : -XX- Drillstring Rig Name : Nordic 3 IADC Rig MN/ Field Name : Mine Pont Run# 100 Country : USA COMPONENT DATA Item Description Iral Nber t7r 1'0 # (in) " (In).". `' (in) (lbp}}' annectt (ft) umLength (ft) 1111 PDC 8.000 3.000 12.250 147-22 P 6-5/8'REG 1-10 1.10 En 8"SperryDrill Lobe 415-5.3 stg 8.000 5.000 103.09 B 6-5/8"REG 31.47 32.57 11111 Stabilizer -__ 12.125 --- ® Float Sub 8.000 2.880 149.10 B 6-5/8"REG 2-40 34.97 ® Stabilizer 8.000 3.000 10.250 147.22 B 6-518"REG 6 00 40-97 0 8'DM Collar 8.000 3.500 147.40 B 6-518"REG 9.20 50.17 ME 8"DGR Collar 8.000 1.920 142.70 8 6-518"REG 4.55 54.72 ® 8"EWR-P4 Collar 8.000 1.985 151.00 8 6-518"REG 12.19 66.91 O 8"HCIM Collar 8.000 1.920 149.90 8 6-518"REG 4-97 71.88 9 8"POS PULSER 8.000 4.000 145.20 B 6-518"REG 15.44 87.32 10 Orienting Sub UBHO 8.000 2.875 149.18 B 6-518"REG 2.50 89.82 ® NM Flex Collar 8.000 2.813 150.13 8 6-518"REG 31.00 120.82 ® NM Flex Collar 8.000 2.813 150.13 B 6-518"REG 31-00 151.82 ® NM Flex Collar 8.000 2.813 150.12 B 6-5±8"REG 31.00 182.82 In ()Its x 5"X 3'HWDP#149.3-NC50(IF)- 5.000 3.000 49-30 240.00 422.82 1112 Jar 7.500 2.813 129.38 8 4-112"IF 35.00 457.82 ® 12jts x 5'X 3"HWDP#49.3-NC50 5.000 3.000 49.30 360.00 817.82 IF Total: 817.82 Page 14 Version 1 June, 2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 11.3 Primary Bit: 12-1/4" (311rnm) QHCI+GRC PRODUCT SPECIFICATIONS 1ADC Code 117W r 0► Total Tooth Count 67 Gage Row Tooth Count 39 • ; Journal Angle 33° Offset(1/16") 60+, Jet Nozzle Types Standard 83244 Extended 302447 $ Center Jet (If Center Jetted)501813 T.J.Connection 6-5/8"(API Reg.) • "ra Recommended Make-Up Torque' 28000(32000 Felbs. Bit Weight(Boxed) 250 Lbs.(113 Kg.) Bit Breaker (Mat.#!Legacy#) 515353/506463 •. PRODUCT FEATURES • New patented Diamondr"r C1awR tooth bit design • Tungsten carbide'surf inserts in gage teeth for added gage protection. :4 ▪ Newly formulated,proprietary hardfacing on cutting structure and gage maximizes carbide and diamond volume for ultimate wear x "` * o` resistance. r : 4 . Raised tungsten carbide inserts and proprietary hardfacing yh sr provides maximum arm protection in abrasive and directional applications while minimizing drill string torque. . QuadPackt Plus Series incorporates its successful"longevity" features and patented engineered hydraulics system for optimal cleaning efficiency. • Center jet feature to prevent bit balling problems . Dual seal/dual compensation bearing system containing dual seals. dual independent pressure compensators,and a dual grease formulation. • The latest OCP seal technology designed with the highest contact pressures on the outside edges of the seal where it is needed most, Material#740990 helps keep contaminants out extending bearing life. `Calculations hosed on recommendations from API and tool joint manufacturers. C 2014 Halliburton.All rights reserved.Sales of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the sale. www.halliburton.com 11.4 5" Workstring, HWDP, and Jars will come from Weatherford. 11.5 Begin drilling out from 13-3/8" conductor at reduced flow rates to avoid broaching the conductor. 11.6 Drill 12-1/4"hole section to 7,941' MD/4,088' TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. Page 15 Version 1 June, 2015 O! • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating)immediately notify Drilling Engineer. • Efforts should be made to minimize dog legs in the surface hole. ESP equipment can be damaged if run through high dog legs. Keep DLS < 6 deg/ 100. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 600 - 650 gpm. Ensure shaker screens are set up to handle this flowrate. • Keep swab and surge pressures low when tripping. • Ensure to leave a"Pump Tangent" section that is approx. 300' long in the directional plan. The ESP will need a straight section to sit. This will occur very near TD of the hole section. • Make wiper trips every 2000' unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. • TD the hole section just into the Schrader Bluff OA sand. Geologists and Drilling Engineers will help adjust well path to ensure well is landed correctly. • Take MWD surveys every stand drilled (60' intervals). • 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 "L"pad wells to date. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. Page 16 Version 1 June,2015 • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 11.7 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. • PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM(10 ppb total)BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5—9.0 range with caustic soda. Daily additions of ALDACIDE G/X- CIDE 207 MUST be made to control bacterial action. • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP<20 (check with the cementers to see what YP value they have targeted). System Type: 8.8—9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths ( Density J, Viscosity Plastic Viscosity Yield Point API FL pH 80-7941' 8.8—9.2,: 85-250 20-40 25-75 <10 8.5—9.0 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 Page 17 Version 1 June, 2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 11.8 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16" conductor shoe. 11.9 Should backreaming be necessary to get out of the hole: • Prior to initiating backreaming, ensure at least 3 —4 B/U have been circulated to get hole as clean as possible. • Pump at full drill rate (600—700 gpm), and maximize rotation. • Pull slowly, 5— 10 ft/minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.10 TOH with the drilling assy, handle BHA as appropriate. 11.11 No open hole logging program planned. 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull 15.375" wearbushing. 12.2 Make a dummy run with the 9-5/8" casing hanger. 12.3 R/U Weatherford 9-5/8" casing running equipment. • Ensure 9-5/8"TC-II x DS50 XO on rig floor and M/U to FOSV. • Consider R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor& model info. 12.4 P/U shoe joint, visually verify no debris inside joint. 12.5 Continue M/U& thread locking shoe track assy consisting of: • (1) Shoe joint w/float shoe bucked on (thread locked). Install (2) centralizers on shoe joint over stop collars 10' from each end. • (1) Joint with float collar bucked on pin end & thread locked. Install (1) centralizer mid tube over a stop collar. • Ensure bypass baffle is correctly installed on top of float collar. Page 18 Version 1 June, 2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company Bypass Baffle This end up. $11004. • (1) Joint with Halliburton bypass baffle adapter bucked on pin&threadlocked. Install (1) centralizer mid tube over a stop collar. • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 19 Version 1 June,2015 • 0 t Milne Point Unit L-47 , 110 Drilling Procedure Hilcorp Energy Company 12.6 Float equipment and Stage tool equipment drawings: "A ___ -- Ove-all Length j Type H ES Cementer B Iiiii Par`N�. Mir.ID Ager Dr'=lou; C SO No. Max.TC:,CD j Ai r D Openir_.'3' a' C Hllcorp ES-II Running Order II� Closing Sleeve No.Shear Pins 1 E I Closing Seat ID II --D l Opening Sleeve C _ I No.Shear Pins Plug Set Ii f. FSYCeerieeoer --- ES Cementer Part No. Depth T B SO No. ..------ ME Closing Plug Baffle Adapter(if used) li 9r*O Ph ID OD OD Opening Plug OD Depth &Me Adapter ® Bypass or°hut-off Baffle By-Pass Plug Depth Shut-off Plug 11 t--P Float Collar D 1111111141 Depth By Pass Baffle �1 OD 1711 Float Collar Float Shoe Depth Bypass Plug (if used) Hole TD Float Shoe OD "'Reference Casing Sales Manual Section 5 Page 20 Version 1 June, 2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 12.7 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use Jet Lube Seal or BOL 72733 thread compound. Dope pin end only w/paint brush. • Install (1) centralizer every other joint for the first 15 joints. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cmt returns to surface. 12.8 Install the Halliburton Type H FS-TI Stage tool so that it is positioned at 2300' MD/2194' TVD. This should be approx. 450' TVD below the base of the permafrost. • Install centralizers over couplings on 5 joints below and above stage tool. • Do not place tongs on ES cementer, this can cause damaged to the tool. • Ensure tool is pinned with 6 opening shear pins. There are 6 holes, the tool is normally sent with only 4 pins installed. This will allow the tool too en at 3300 psi. 9-5/8" 40#L-80 TC-II Make Up Torques: Casing OD Min M/U Torque Max M/U Torque 9-5/8" 11,600 ft-lbs 13,600 ft-lbs Page 21 Version 1 June,2015 • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company Technical Specifications Connection Type: Slze(O.D.): Weight(Wall): Grade: TC-II Casing 9-5/8 in 40.00 lb/ft(0.395 in) L-80 standard Material L-80 Grade 11APS 80.000 Minimum Yield Strength (psi) 1111111111111111111111111111MW U SA 95.000 Minimum Ultimate Strength (psi) VAM USA Pipe Dimensions 4424 W.Sam Houston Pkwy.Suite 150 Houston,Tx 77041 9.625 Nominal Pipe Body O.D. (in) Phare:713-479-3200 8.835 Nominal Pipe Body I.D.(in) Fax:713-479-3234 0.395 Nominal Wall Thickness (in) E-mail:VAMUSAsalesuam use.com 40.00 Nominal Weight (lbs/ft) 38.97 Plain End Weight (lbs/ft) 11.454 Nominal Pipe Body Area (sq in) Pipe Body Performance Properties 916.000 Minimum Pipe Body Yield Strength (lbs) 3.090 Minimum Collapse Pressure (psi) 5.750 Minimum Internal Yield Pressure (psi) 5.300 Hydrostatic Test Pressure (psi) Connection Dimensions 10.235 Connection O.D. (in) 8.835 Connection I.D. (in) 8.750 Connection Drift Diameter (in) 5.23 Make-up Loss (in) Connection Performance Properties 916,000 (1) Joint Strength (lbs) 16.360 Reference String Length (ft) 1.4 Design Factor 916.000 Compression Rating (lbs) 3.090 Collapse Pressure Rating (psi) 5.750 Internal Pressure Rating (psi) 38.1 Maximum uniaxial bend rating [degrees/100 ft] Recommended Torque Values 11.600 (2) Minimum Final Torque (ft-lbs) 13.600 (2) Maximum Final Torque (ft-lbs) Page 22 Version 1 June, 2015 • • 111 Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at(1) ft intervals to use as a reference when landing the hanger. 12.12 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.13 Have emergency slips ready to go in the event we can not land the hanger. 12.14 R/U 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. Elevate hanger slightly above hang off point while circulating to avoid plugging the flutes. 12.15 After circulating, lower string and land hanger in wellhead again. Page 23 Version 1 June, 2015 i Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 13.0 Cement 9-5/8" Surface Casing 13.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud& water can be delivered to the cmt unit at acceptable rates. • How to handle cmt returns at surface. 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 cmt operation. • Review test reports and ensure pump times are acceptable. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cmt pump or treating iron will not be pumped downhole. 13.4 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.5 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 13.6 Pump remaining 55 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug). Mix and pump cmt per below recipe for the 1st stage. 13.8 Cement volume based on annular volume+ 30%open hole excess. Job will consist of lead& tail, TOC brought to stage tool. Estimated Total Cement Volume: Section: Calculation: Vol(BBLS) Vol(ft3) 12-1/4" OH x 9-5/8" Casing (6941'- 2500') x .0558 bpf x 1.3 = 322 1808 annulus: Total LEAD: 322 bbl 1808 ft3 N 2-1 12-1/4" OH x 9-5/8" Casing (7941'- 6941') x .0558 bpf x 1.3 = 72.5 407 annulus: 9-5/8" Shoe track: 90 x .0758 bpf = 6.8 38.3 Total TAIL: 79.3 bbl 445 ft3 3 Y3 5)(- Page KPage 24 Version 1 June, 2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company Cement Slurry Design: Lead Slurry Tail Slurry System ArcticCEM TM System SwiftCEM TM System Density 10.7 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed 21.13 gal/sk 5.04 gal/sk Water 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. To operate the stage tool hydraulically,the plug must be bumped. 13.11 Displacement calculation: 7841' x .0758 bpf= 364 bbls mud, 80 bbls water, 149 bbls mud The 80 bbls of water must be left across stage tool to ensure proper operation once opened. 13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.13 Do not overdisplace by more than 1/2 shoe track volume. Total volume in shoe track is 8.7 bbls. Page 25 Version 1 June, 2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 13.14 If plug is not bumped consult with drilling engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.16 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface. Circulate until YP <20 again in preparation for the 2nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cmt returns in the cellar or open the shaker bypass line to the cuttings tank. Have sacks of sugar available and vac trucks ready to assist. Ensure to flush out any rig components used to route cmt. Page 26 Version 1 June,2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company Second Stage: 13.18 Prepare for the 2nd stage as necessary. Hold another pre job meeting if crew change has occurred. 13.19 Load ES cementer closing plug in cmt head. 13.20 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 13.21 Pump remaining 55 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2nd stage. 13.23 Cement volume based on annular volume+200% open hole excess. Job will consist of lead& tail, TOC brought to surface. However cmt will continue to be pumped until clean spacer is observed at surface. Estimated Total Cement Volume: 514( Section: Calculation: Vol(BBLS) Vol(ft3) 13-3/8" Conductor x 9-5/8" (110') x .062 bpf x 1 = 6.82 bbl 38.3 ft3 casing annulus: 12-1/4" OH x 9-5/8" Casing (2000'- 110')x .0558 bpf x 3 = 316 bbl 1774 ft3 annulus: Total LEAD: 323 bbl 1813 ft3 Z( 5 12-1/4" OH x 9-5/8" Casing (2500'- 2000')x .0558 bpf x 2 = 56 314 ft3 annulus: Total TAIL: 56 bbls 314 ft3 -276;9'. 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement cal . ation: - 2500' x .0758 ..f= 190 bbls mud Page 27 Version 1 June, 2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.28 Decide ahead of time what will be done with cmt returns once they are at surface. We should get back approx. 150 bbls of cmt slurry. 13.29 Back out and L/D landing joint. Flush out wellhead with FW. 13.30 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.31 Lay down landing joint and pack-off running tool. Ensure to report the following on wellez: • Pre flush type,volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume &weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing,note whether displacement by pump truck or mud pumps, weight&type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped&bump pressure,do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface&volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As-Run" casing tally & casing and cement report to lkeller@hilcorp.com and cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 28 Version 1 June, 2015 • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 14.0 BOP N/U and Test 14.1 N/D the diverter. 14.2 N/U Seaboard multi-bowl tubing spool. Install pack-off 9-5/8" P-seals. Test to 3000 psi. 14.3 N/U 11"x 5M BOP as follows: • BOP configuration from Top down: 11"x 5M Hydril annular BOP/11" x 5M Shaffer double ram/11"x 5M mud cross/11"x 5M Hydril single ram • Double ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should be dressed with 2-7/8" x 5" VBRs. • N/U bell nipple, install flowline. • Install (1) manual valve & (1) HCR valve on kill side of mud cross. (manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Run 5" BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 R/D BOP test assy. 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 8.9 ppg Baradrill-N fluid for production hole. 14.8 Set 10" ID wearbushing in wellhead. 14.9 Rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.10 Install 5" liners in mud pumps. Page 29 Version 1 June, 2015 • • II Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 15.0 Drill 8-1/2" Hole Section 15.1 P/U 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 5" 19.5# S-135. • Run a ported float in the surface hole section. 15.2 8-1/2" BHA (Includes GR+Res+ADR LWD components & PWD): COMPONENT DATAlir MOT Item Description Serial Number OD ID Gauge Weight Top Length Cumulative # (in) (in) (in) (lbpf) Connection ('ft) Length (ft) EE HOBS-FX85D 8.400 2.500 8.500 172.13 P 4-112'REG 1.00 1.00 © 7"SperryDrill Lobe 718-6.0 stg 7.000 4.952 MI 93.13 B 4-112'IF 27.38 28.38 - Stabilizer -__ 7.750 _--- © Non Mag Float Sub 6.750 2.750 101.71 B 4-1/2'IF 3.00 31.38 © Integral Blade Stabilizer(NM) 6.750 2.813 8.375 100.77 B 4-112"IF 5.00 36 38 © 6 314"OM(Oirec6onal) 6.750 3.125 103 40 B 4-117 IF 9.20 45.58 El 6 314"DGR(Gamma) 8.750 1.920 97.80 4.55 50.14 © 6 314'EWR-P4 (Resistivity) 6.750 2.000 104.30 B 4-112"IF 12.10 62.24 ER 6 314'HCIM (Processor) 6.750 1.920 101.70 OEM 4.97 67.21 © 6 314"ALD Collar 175C 36KSI 6.750 1.920 8.250 104.30 P NC 50 14.54 81 75 _ Stabilizer -__ 8.250 ---- 10 6 3/4'CTM Collar 175C 30KSI 6.750 1.905 102.30 B NC 50 11.84 93.59 ® 6 314"TM-HOC(Pulser) 6.900 3.250 103.60 B 4-1/2'IF 15.59 109.18 6-3/4'Non Mag Flex Drill Collar 6.750 2.813 100.77 11=e1 30.00 139.18 ® 6-314'Non Mag Flex DnII Collar 6.750 2.813 100.77 B 4-112'IF 30.00 169.18 ® X-0 4-/./2"CDS 40 Box X 4-112"IF Pin 6.500 2.750 92.85 B 4.5"CDS 40 2.75 171.93 ® 6 Joints 4-112-CDS 40 HWDP 4.500 2.500 37.47 180.00 351.93 m X-0 4-1/2"IF Box X 4-117 CDS 40 Pin 6.500 2.750 92.85 B 4-112"IF 2.75 354.68 Mill Weatherford 6-114"Jars 6.250 2.250 91.01 B 4-112'IF 30.00 384.68 gm X-0 4-112"IF Pin X 4-112"CDS 40 Box 8.500 2.750 92.85 B 4.5'CDS 40 2.75 387.43 NM 19 Joints 4-112'CDS 40 HWDP 4.500 2.500 37.47 570.00 957.43 Y,04)*,;-zL°d6 957.43 Bit Number Nozzles : 5x13 Bit Size (in) 8 5C0 TFA (in2) :0.6481 Manufacturer Dull Grade In . Model Dull Grade Out • Serial Number . Page 30 Version 1 June, 2015 0 • 11 Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 15.3 Primary Bit: 8-1/2" (216mm) SFE56 PRODUCT SPECIFICATIONS Cutter Type X2-Tough Drilling IADC Code S424 Body Type STEEL i Jr, Total Cutter Count 29 11l�a► Cutter Distribution gg 19mm !tr Face 0 19 1 4 Gauge 10 0 Number of Large Nozzles 5 °' Number of Medium Nozzles 0 Number of Small Nozzles 0 Number of Micro Nozzles 0 41 Number of Ports(Size) 0 2. Number of Replaceable Ports(Size) 0 3 i r Junk Slot Area(sq in) 20.81 1 1 'r if r fig Normalized Face Volume 73.86% API Connection 4-1/2 I.F.PIN INIP »1 Recommended Make-Up Torque* 23,743 Felbs. 1 ■ Nominal Dimensions** Make-Up Face to Nose 8.31 in-211 mm w OP Gauge Length 3 in-76 mm oI Sleeve Length 0 in-0 mm Shank Diameter 6.688 in-170 nun Break Out Plate(MaL#/Legacy#) 181960/44073 Approximate Shipping Weight 120Lbs.-54Kg. SPECIAL FEATURES Anti-Balling Coating.Short Shank,EDL Tool Specific Gage,.084"Dia Step..l26"Dia Step Material#761417 / Page 31 Version 1 June, 2015 • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 15.4 8-1/2"hole section mud program summary: • Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system(1)ppg above highest anticipated MW. • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use water or low vis sweeps. • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 8.9—9.2 ppg Baradrill-N drilling fluid Properties: Depths Density Plastic Viscosity Yield Point MBT HTHP pH 7941-to 8.9—9.2 15-25 15-25 < 7 < 11.0 8.5—9.5 13,002' System Formulation: Baradrill-N Product Concentration/Function Water Base Fluid Busan 1060 0.4 ppb Biocide Soda Ash 0.25 ppb PH/Hardness Control Flowzan 1.0 ppb Viscosifier/Rheology KCL 21.8 ppb weight/inhibition NaCI Salt 20.0ppb weight/inhibition Poly Pac Sup UL 0.75 ppb API Fluid Loss EMI-2009 2-3%v/v Clay/Shale inhibitor Safe-Carb 40 If needed for weight increase over Conqor 404 9.0ppg Asphasol Supreme Corrosion Mitigation Sack Black 4ppb Shale/Coal Stabilizer 3ppb-Gilsonite Shale/Coal Stabilizer Page 32 Version 1 June,2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 15.5 TIH w/ 8-1/2" directional assy to stage tool. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. Drill out stage tool as follows: • Do not exceed 75 rev/min rotation speed. A good range is 40 to 75 rpm. • Because of aggressive nature of PDC bits, drilling with minimal WOB is recommended. Approx 2-5 k is enough. • Apply weight and allow it to drill off before applying more. • After drilling out, chase any remaining debris to bottom with the drill bit. 15.6 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.7 R/U and test casing to psi/30 min. Ensure to record volume/pressure and plot on FIT graph. AOGCC reg is 50% of burst= 6870/2 si 15.8 Drill out shoe track and 20' of new formation. 15.9 CBU and condition mud for FIT. 15.10 Conduct FIT to 12 ppg E . 15.11 Drill 8-1/2"hole section to section TD per Geologist and Drilling Engineer. • Pump at 500 - 550 gpm. • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Pump water or other low vis sweeps to aid in hole cleaning. • Keep swab and surge pressures low when tripping. • Make wiper trips every 1500—2000 ft if necessary. • Take MWD surveys every other stand drld. Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. • Use ADR to stay in section. Ideally, we would like to stay in section 100%of the time and DO NOT want to serpentine between the upper and lower lobes. 15.12 Open hole sidetracking practice: • If a known fault is coming up, put a slight"kick-off ramp" in wellbore ahead of the fault so we have a nice place to low side. • Attempt to lowside in a fast drilling interval where the wellbore is headed up. • Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for approx. 30 min. • Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. Page 33 Version 1 June, 2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 15.13 At TD; pump low vis sweeps, CBU at least 3 times at maximum circulation and rotation, and pull a wiper trip back to the 9-5/8" shoe. If backreaming is necessary: • Circulate at full drill rate (500—550 gpm). • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe and circ at least a b/u once at the shoe. 15.14 TOH with the drilling assy, stand back BHA if possible. Rabbit DP on TOH. 15.15 No open hole logs are planned for the production hole section. 16.0 Run 5-1/2" Production Liner 16.1. Install and test 5-1/2" casing ram in top ram cavity. Pull wear ring, install test plug, Test to 250/3000 psi. 16.2. Test VBRs on 2-7/8"test joint to 250/3000 psi. 16.3. Re-install wear bushing in wellhead after test. 16.4. R/U 5-1/2" casing running equipment. • Ensure 5-1/2"DWC/C x DS-50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor& model info. 16.5. Run 5-1/2" slotted production liner. • Use "Best 0 Life 2000"thread compound. Dope pin end only w/paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install swell packers as per guidance from Operations Engineer. • Ensure all plastic packing is removed from element. • Do not place tongs or slips on element. • Run packoff and float shoe on bottom. 5-1/2" DWC/C HT M/U torques Casing OD Minimum Maximum Yield Torque 5.5" 9,800 ft-lbs 11,000 ft-lbs 14,800 ft-lbs Page 34 Version 1 June, 2015 • Milne Point Unit L-47 111 Drilling Procedure Hilcorp Energy Company Technical Specifications Connection Type: Siae(O.D.): Weight(Wall): Grade: DWC/C-HT Casing 5-1/2 in 17.00 lb/ft(0.304 in) L-80 standard Material L-80 Grade 80.000 Minimum Yield Strength (psi) ININIMINNIMMIWUSA 95.000 Minimum Ultimate Strength(psi) VAM USA 4424 W.Sam Houston Pkwy.Suite 150 Pipe Dimensions Houston,TX 77041 Phone: 3200 5.500 Nominal Pipe BodyO.D. (in) Fax:73-479-3234 4.892 Nominal Pipe Body l.D.(in) E-mail:VAMUSAsalesAvam-usa.com 0.304 Nominal Wall Thickness (in) 17.00 Nominal Weight(lbs/ft) 16.89 Plain End Weight(lbs/ft) ;--•a 4.962 Nominal Pipe Body Area (sq in) Pipe Body Performance Properties 397,000 Minimum Pipe Body Yield Strength(lbs) 6,290 Minimum Collapse Pressure(psi) 7.740 Minimum Internal Yield Pressure(psi) 7.100 Hydrostatic Test Pressure(psi) Connection Dimensions 6.050 Connection O.D. (in) 4.892 Connection I.D.(in) 4.767 Connection Drift Diameter(in) 4.13 Make-up Loss(in) 4.962 Critical Area(sq in) 100.0 Joint Efficiency(°/a) Connection Performance Properties 397.000 Joint Strength (lbs) 16,680 Reference String Length (ft) 1.4 Design Factor 428,000 API Joint Strength(lbs) 397,000 Compression Rating(lbs) 6,290 API Collapse Pressure Rating (psi) 7,740 API Internal Pressure Resistance (psi) 66.7 Maximum Uniaxial Bend Rating[degrees/100 ft] Appoximated Field End Torque Values 9.800 Minimum Final Torque(ft-lbs) 11.000 Maximum Final Torque(ft-lbs) 14,800 Connection Yield Torque(ft-lbs) Page 35 Version 1 June, 2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 16.6. Ensure to run enough liner to provide for approx 200' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. 16.7. Before picking up Baker ZXP liner hanger/packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.8. If inner string is to be run, R/U false rotary and run inner string at this time. 16.9. M/U Baker ZXP liner top packer. Fill liner tieback sleeve with"Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 16.10. Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.11. RIH w/liner on DP no faster than 1-1/2 min/ stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.12. DP should autofill. 16.13. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth+ S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.14. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 16.15. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.16. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.18. Rig up to pump down the work string with the rig pumps. 16.19. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 16.20. Pressure up to 3000 psi and hold for 5-15 minutes to set SLZXP hanger packer. Continue pressuring up in 500 psi increments holding for 5 min each up to 4000 psi. Page 36 Version 1 June, 2015 • • Milne Point Unit L-47 14 Drilling Procedure Hilcorp Energy Company 16.21. Bleed DP pressure to zero, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.22. Bleed off pressure and pickup to verify that the HRD setting tool has released. If packer did not test, rotating dob sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.23. P/U above liner top packer and displace well to 8.9 ppg completion fluid. 16.24. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. 16.25. RIH w/remaining DP out of derrick and L/D same. 17.0 Run 7-5/8" Tieback 17.1 R/U and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie-back space out calculation. Install and test 7-5/8" (250/3000 psi) casing rams in top ram. 17.2 R/U 7-5/8" casing handling equipment. • Ensure XO to DP made up to FOSV and ready on rig floor. • Rig up computer torque monitoring service. • String should stay full while running, r/u fill up line and check as appropriate. 17.3 P/U tieback seal assy and set in rotary. 17.4 M/U first joint of 7-5/8"to seal assy. 17.5 Run 7-5/8"tieback to position seal assy two joints above tieback sleeve. Record up & down weights. • Following running procedure outlined above. • Install ported collar so it is positioned at 2500' MD when landed out. 17.6 M/U 7-5/8" SLIJ-II to DP crossover. 17.7 M/U stand of DP to string, and M/U top drive. 17.8 Break circulation at 1 bpm and begin lowering string. 17.9 Note seal assy entering tieback sleeve with a pressure increase, Stop pumping and bleed off pressure, leave standpipe bleed off valve open. Page 37 Version 1 June, 2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 17.10 Continue lowering string and land out on no-go. Set down 5 — 10k lbs. Mark the pipe at this depth as "NO-GO DEPTH". 17.11 P/U string & stand back DP stand, L/D XO. 17.12 M/U (or L/D) necessary joints and pup joints to position seal assy 1 ft above "NO-GO DEPTH" when tie-back hanger lands out in wellhead. 17.13 P/U hanger assy. Top of hanger landing joint is 7-5/8" SLIJ-II. Ensure crossover is available to allow circulation down the string. 17.14 R/U to circulate down tieback. Displace 7-5/8"x 9-5/8" annulus to inhibited packer fluid. 17.15 Confirm hanger has seated properly in wellhead. Should be approx. 13k lb on hanger when landed. Make note of actual weight on hanger on morningrpt. g 17.16 Run in hanger lock downs. 17.17 Back out landing joint. M/U packoff running tool and install packoff on bottom of landing joint. Set tubing hanger pack off. Test void to 3000 psi/ 10 min. 17.18 R/D casing running tools. 17.19 Run in hole with 2-7/8"tubing and ported collar opening tool. Shift open ported collar at 2500'. Circ diesel freeze protection from 2500' to surface in 7-5/8"x 9-5/8" ann'uius.� 17.20 Close ported collar. 17.21 Test 7-5/8" x 9-5/8"production annulus to 1000 psi/30 min. 17.2 POH and stand back 2-7/8"tubing for ESP run. 18.0 Run ESP assy. 18.1 M/U ESP assy and RIH to setting depth. • Ensure appropriate well control crossovers on rig floor and ready. • Monitor displacement from wellbore while RIH. 18.2 Land hanger, RILDs and test hanger. 18.3 Install BPV and N/D BOP. Page 38 Version 1 June,2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Enema Company 18.4 N/U tree adapter and test tree. Pull BPV. 18.5 Circulate diesel freeze protection down 2-7/8" x 7-5/8" annulus (Volume should equal capacity of tubing to 2500' +tubing annulus to 2500'). Connect IA to tree and allow diesel freeze protect to "U-tube" into position. 18.6 Shut in well and prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 19.0 RDMO 19.1 RDMO Nordic #3. Page 39 Version 1 June, 2015 i S Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 20.0 Diverter Schematic 16" Full Opening Knife Valve trn trn ma En Schaffer 21-114"2M — Annular 111 au uu 1U1 21-1/4" 2M Diverter "T" 2.9981 ET� uu ILL au au 21-114" 2M 16" Diverter Line—//i Spacer Spool 4.0380 Ground Level rn OM 16-3/4" 3M x 21-114" 2M DSA Seaboard Casinghead, S-22-AP-8— 16" SOW x 16-3/4" 3M; (2) ea 2-1/16" 5M studded outlets 20" Casing Page 40 Version 1 June, 2015 i 9 II Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 21.0 BOP Schematic / 1 1 l 6 U Hydril Annular BOP 11"x 5M .L. nsd) r LijI 1 v6.g. c _ ii, 2 7l K 1_.; _r** 0 El :o 0 0 a o o. o a B`- 1 I .1111/M11111 .1.1.1414 ^ .7 "3"x 5M HCR III I�■�IC J�I I[iii►ill I.i I '..-----Choke Line Kill Line • 4101 0„a, al MI �3"x 5M Manual Gate Valve ^a Hydril 11"x 5Mr I v /\ ( rs") °! ilmi Y Y Y ~`"--11"x 5M �_ _[/1► llifli 9-5/8"DBL D Seal 2-1/16'x 5M Casing Hanger "till *►�• 16-314"x 3M SMB-22 -pi k[,y„}[,i,.} 16-314"NOM di9-5/8"BTC Btm x �2-1116"x 5M 14.5"-4 SA Pin Top W/Primary Seal 20"Casing 9-5/8"Casing Page 41 Version 1 June, 2015 0 • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 22.0 Wellhead Schematic HILCORP ALASKA i SCHRADER BLUFF WELLS HO—35449H it: ...... . i 2-9/16 5M HOLD-009N FLANGE ADAPTER. ESP-2 L rA, TOADSTOOL �f 11 X 2-9/15 5M '_ 1n1 -■ i gyp- • i it 111E1AC HAACER }Tn 5 HE Lor' LTJ ■1 fix 2-1/8 _ 8R0 TOP X : I E-:i+ i'„/TTra` API HOC BTM •1 EST i/TAURUS PENETRArCR ; —��t •la •I: ; 43-217-00 X101�9' i .j: :� iii. alp jh 71 1 11 gin+ % CAG HANGER. SM19-22 111 p 1.1 `2-I/Ifi 71.1 11 X 7-5/8 W/PRIMARY SEAL ; _:.. .- ) ; 0 E ■�2ds� � � (31114 1 i.. 9-5/8OeLDom._a*f i ilei 11' `2-1/,6 5M 4 n4 j tit i. MI CASING HANGER •, II 111111 15 X 9-5/8 : W/PRIMARY SEAL , • 28.A 713 `• 7. �� .I II EST _ .1 y:' _ ... 1 , - ljr I +I I 13-3/8 CASING 9-5/8 CASMO WEIll 7-5/8 CASING- ,.____.• OIL,x CiAJ 5.000 PS ESP IKLLNEAO ASSEMBLY NCS 2-7/8 CASING ...0 11E SACK STKE ENS1 D410NS SIMnM/C 4'HS CRA9ING ARE 13-3/8 X 9-5/8 X 7-5/8 X 2-7/8 ESTI,ATES(NY ANTI CAN+MT 9GMIF.CNILY RESTRICTED CCNMTDENTIAL DCCLIAINT WENDING CN CN RAW NATTRIA. IF1r1MS. ...d,,.,.,,r.. wrwrw L"�` RPL ar 1:9 i�19JUNts me. NO GUARANTEE CF STAMP*EiOoT IS MFLED, 01111.111.7.1.,.._151_11.1, .iiKaN we.•r arm' MI Iw DYCNSIGIS SNCARI SWUM FE CONSIOFRFO w. •�r ' ''CR RCFCRFNCE PUIPCSFS CMIY. a ti, .a iris, QD-000619 Page 42 Version 1 June, 2015 0 • II Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 23.0 Days Vs Depth Days Vs Depth 0 -1— avanwtS.hr3der Bluff Well -MPI-1312004) W1 PI-1812011) -MPI-17 12004) 2000 ( --MPI-1512002) _ 1\1'411 1. 4(100 1, z 6-X0 t 8 v v II\ 8000 i li � 10000 y 12000 14000 _. 0 5 10 15 20 25 30 Days Page 43 Version 1 June, 2015 • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 24.0 Formation Tops Formation ND(Top) ND(Bottom) Anticipated Pressure(Psi) SV1 2150 3520 961 UgnuLA1 3521 3748 1575 Ugnu MB 3749 3998 1677 SB NB Sand Top 3999 4135 1788 SB©A Sand Top 4136 4156 1850 Page 44 Version 1 June, 2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 25.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of 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 as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Add 1.0—2.0 ppb DRILTREAT to the system to help thin the mud and 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 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. 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: Treat every hole section as though it has the potential for H2S. 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. Page 45 Version 1 June, 2015 • r Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 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. 8-1/2" Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of> 500 gpm. Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least(1)fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a"ramp" in the wellbore to aid in kicking off(low siding)later. Once a fault is crossed, we'll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on `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. Abnormal Pressures and Temperatures: There are no abnormal pressures or temperatures observed on"L" pad. Page 46 Version 1 June, 2015 • 0 Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 26.0 Nordic #3 Rig Layout (Drillers Side) •1 mir tJOld,1 ) -€aIista 0 Services (,),Ri .ippr RIG NO. 3 VA Thr Draipr,including ape,repoa nn.Jrawiimgr end them connote IThr Jr.gnl Fr reel MIN,property of Vcrdrr- Calms ed a groomed Ire 1.S and trerrruewelelr evriOn lar,.r-.r I".`.eciyn ra fernahra on s rontblerc.ial bcuxxh the eeprrat agreement she n..ill rem be.dd.r_anr&cnod.aprpl.rs crurd.pdaa,agre?brd.or rrprrdcurd in am manner ,rpurw.,cr.in whale In pare.not any nein heron be guile.main(rwarrJ...r aesrn,bkd with Ow aid of c_Y de non wakens the wiinm egreennre of Nordnt:apeau no I:k.etn may rn o h Arckncj to arra Lehr,pine eurpr(or the apaair pimped.for=Irian ii tree been pro.idrd. rii. IF IIdA vir ice... 6„, Me a(e' 044P Pike c,04,..... I-11 vt+.—.1Tv�......► if i- VC .6Mrifrip 1111 :I! On n\ Warm I 01;\:;\%:14,:sst -- _ Fa_ are re .—re are ! _-? rp,r r-r ere Drillers Side Page 47 Version 1 June,2015 • • II Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 27.0 Nordic #3 Rig Layout (Well End & Top View) dill 1111111 liii } = �� 4 7 ii, ,, , • sop _ Mie - c►Kxoaac --- ,- b :-. TAMC = L�A • MOMMOM Dari m AooEPT ROW UM w'-n. Well End ,,.4' 1 -0. Y-t 114.-1 —+S-'d M-Y 33-_T- 9 I I nma mma n I I j WAWA...NI ` ii1 lig NRAiV ...R OOn1 T �,.. x � ma • JTy Y j {, } i 'e v' i 41 .MED PPE*ED aaOF C i { k1T a ' it r f A a Q e a —3-f--- !— — A I ..I •a '_ 36a eat ',. %writi owKE»wi[ b Pic DOPA 3 Huila u Pi<ncw,oN (11T1111U11111U11If1 ..----13'.40.--•-,.... . IM.l'' _.._ -_._._-__ ..-........_._.___�_.. ,by-o TOP VIEW Page 48 Version 1 June, 2015 Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 28.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer(ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 49 Version 1 June, 2015 0 • II Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 29.0 Choke Manifold Schematic 'S> J4i>d d>t4>• J<4 3 „`:>2 < Tt'• }t < J Rh S<t : :::::::::::::::::?:::E::::::: . ><frt>`Sn<>t< I`'< < << <}(>i'S > 'ticeS<#>t>t S><S)'<i{>[<3<t> >Mtr 1 !x a'<>`S r< S4 >` :><3`)'>i{lS 2K'< >Sl' . xS <l`l4 .'• <'<' t 'S' ' ME i ' ' ' ' ) s > Sts > s � ��w> r � SS4 < Si # C41' it < it < t < < ' t ` `.Y` ' t >}<4f<t c J!ti "` S3' ``Y`)`a`Y ° " ` '( '4 <'i'' Ss ' >' ' ' ' ' ' ' ' 'x' ' ' ' ) > > a J > s > > > sa :,S > > < > c > ,,,,,.,,,,x,:,,,,,,,,,,,,,:„. 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Y`!} >`Y`>`T`!.>')`a`>` ow twitAk' ` 4 ( 111111 ` ib 'bf 'i 4'4'4'4'4'4'. ' ` 4'44 ` t` * } ) 4. 4 14`4 ! 1 > i >`>`>`>`>'> >°> a Y <l<><f< YTf>< > } >`} ><><>4 4T6)tS;i a >>`>'}`11 fi`> > >` ` l ! r110111111:::::::::::!::::::::›24:4:4:::::::::::::::::::::: e xli><> !l<l<lt ` 23t11> ) !'tltS1)<l@ ! ' 1S4S '!3f4x't'{`<4tsjt a•fS ! s )' ' ' ' ' > f3 > ) > ' ' ' s } ' fa11 ! 1 a > '> ' M' ket < e't' 'e'e'r'e't'e ♦ :fteeteeeteer eree < tee " eeeteeeeeeee eeereeeeeereeeatee Page 50 Version 1 June, 2015 I • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 30.0 Casing Design Information Calculation & Casing Design Factors DATE: 6/29/2015 WELL: MPU L-47 DESIGN BY:Luke Keller Design Criteria: Hole Size 12-14" Mud Density: 9.5 ppg Hole Size 8-1/2" Mud Density: 9.5 ppg Hole Size Mud Density: Drilling Mode MASP: 1420 psi (see attached MASP determination&calculation) MASP: Production Mode MASP: 1420 psi (see attached MASP determination&calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress(0.494 psi/ft)and the casing evacuated for the internal stress Casing Section Calculation/Specification 1 2 3 4 Casing OD 9-518" 5-1/2" Top(MD) 0 7,741 Top (TVD) 0 4,088 Bottom (MD) 7,941 13,002 Bottom (TVD) 4,088 4,067 Length 7.941 8,914 Weight(ppf) 40 17 Grade L-80 L-80 Connection TC-II DWC/C HT Weight wio Bouyancy Factor(lbs) 317,640 151.538 Tension at Top of Section (lbs) 317,640 151.538 Min strength Tension(1000 lbs) 916 347 Worst Case Safety Factor(Tension) 2.88 2.29 Collapse Pressure at bottom (Psi) 2,019 2,009 Collapse Resistance w/o tension (Psi) 3,090 7,100 Worst Case Safety Factor(Collapse) 1.53 3.53 MASP(psi) 1,420 1,420 Minimum Yield(psi) 5,750 7,740 Worst case safety factor(Burst) 4.05 5.45 Page 51 Version 1 June, 2015 • • Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 31.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 8-1/2" Hole Section Hilcar� MPU L-47 Milne Point Unit MD TVD Planned Top: 7941 4088 Planned TD: 13002 4067 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OA Sand I 4,088 1828 Oil/Wet (.13,6..„„,_ 0.447 Offset Well Mud Densities Well MW range Top(ND) Bottom(ND) Date L-37(1998) 8.9-9.3 Surface 7,050 1998 L-35(1997) 8.4-9.2 Surface 5,687 1997 L-34i(1997) 8.4-9.4 Surface 5,842 1997 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density for the 8-1/2"hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 4088(ft)x 0.78(psi/ft)= 3189 3189(psi)-[0.1(psi/ft)*4088(ft))= 2781 psi MASP from pore pressure(complete evacuation of wellbore to gas from Schrader Bluff OA sand) 4088(ft)x 0.447(psi/ft)= 1828 psi 1828(psi)-0.1(psi/ft)*4088(ft) 1420 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Page 52 Version 1 June, 2015 0 S 11 Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 32.0 Spider Plot (NAD 27) (Governmental Sections) ii II ' I i • ; / / „•/ 4*,•• ,•%• ..-•-•O \\ , I 1 s -':.."" ...- „ .„ :: : vs,o , ' I, .vi 'c-" .. ,I, ,vi / ,-..._:0•.-•";"". Sec-6 ,. .6'Z•k I' • it' Sec 5, ../ Sec. Sec 1 .0.'`.. • '' % ' 1 °/ 0' I ii ' ,..,-;' • '1, - 1 1%, 11 4 • r ,' / „/ •c, .,„.". -, ,' '„ )0'1, ir . i-' , / ,,, ,, ;?':;—).:', , r ,1 ,• r, A ' ',., - %., ) ',\.,. 1 'il ' tt‘ 1, . " + ".‘ ' ,p % , ...' 0 ' , , 1• , I 41. 1 L.,,""4,...... 'k ` .. , .. .1%1 i I ". ,e, - '''''' , '''‘', s 0,Vi, 7. i,', ' ' , 4 ..„..,, ....„......14 A - ‘ivkl,I4% ,I•„ ,,, ..., • ADL388235” , \ A00255091: _...,o.i, ,asi•1, ,a,:',„.„, _ ADL047434 MPL-47 SHL , . F A-Fa .LG . . .„,%.‘„••••"" • Se&7 .."- ..- - .. E .8 -- „-.,..- r. .- , . ” '- -- ./.. i# .... ;';',./ i I ,....._.-•••''' .,' ..,, .;,.. ot • • , , ' 1, '" -' II A ... .....• ....,, „,• .1.• r % s. , b ,1' i •il:,. 1 b N ..'•k ,, 0• -' ., • .. •----' a. 0' , i.:: 'I_ %. ,, ,' .0 , - i' 0. , ' , # . I .0 , , t % : 1 • /or„• /2/ .. r 4 ,A NT.11(.;-• 5( .- ''' UD13N010E . ' ' • 1 U013N009E, ,`.pE',...,_. , .(1, MPL-47 TPH ... • !.. ../ ,I /1/ ... ... ... . . .• , I * .0. oo' . ' ./,, I -.. . . ., o ''• .sp, -- , Sec.. ,..2.... 1 . ... /Xe I ., . 0, 4 / • ... .•......... ., y .... MPL-47 BHL .. ADL025514 ADL025515 ADL315848 •11.4:” . .Q, bb Z , boiC , Legend • MPL-47 SHL &..J.,.) s . MPL-47 TPH 4 S.c 20 -411- MPL-47 BI-4L ,. x .,:,, Other Surface Holes(SHL) • i * , I .• - A ' % 4 Ar NI NE SITE E • Other Bottom Holes(BH4 kL) • • k I L 1 I 'Other Well Paths 1 if -- DL25 rIAC OC'2 , 11 kil • i1 dAik• .5.•"'" :2':'1 - -...... - I " 17**-1' CIMEI, III Milne Point Unit 0 1.000 2.000 3.000 MPL-47 Well Feet •••,.c..v.•...... _ • Page 53 Version 1 June, 2015 • • Milne Point Unit L-47 IMS Drilling Procedure Hilcorp Energy Company 33.0 Surface Plat (As Built) (NAD 27) rater --- ---".""_- , 34 31 32 33 \\\\ \ I I \1\ /�l :7;)� T 14 N 4 4'l�,E' ,-- -hi- s la la 13 N I I ' r 32 ■ 33 • I m r ♦ I S 4 \ // 28 ■ 29 ■ . p 1 F-P I I t24 ■ 25 ■ �"-- _-1 -I-_- 20 ■ 21 ■ ,%�-rAo / 41 • 43 • / / 46 ■ \..-..-_- MS PR01iCf _ _ I .. I -. 1 L'k 13 ■ II8 I -i__ 1 ■ [~ /// 34 • • 14 24 � s 19 I 20 I 21 3 • • 10 VICINITY MAP 15 • +L-47 N.T.S. 2 ■ ■ 7 LEGEND 49 12 ■ • AS-BUILT YELL CONCUCTCR RENAMED I 40 ■ • ■ •■ ■■ ■+■■ ■ I E3ISTANG CONDUCTOR 6 35 436 5 37 11 048 46 ;1 k) -J a NOTES: i' -"- , 1. ALASKA STATE PLANE COORDINATES ARE IOW 4, NA027, 2. BASIS OF LOCATION IS 1.-PAD MONUMENTS L-1 NORTH 8. I AND L-2 SOUTH. N. 3. BASIS CF ELEVATION IS 1451.. D I L-PAD 4. OECOETIC POSITIONS ARE 10D27. 20 I 5. PAD MEAN SCALE FACTOR IS: 0.9999023 6. DATE OF SURVEY: JANUARY 11 &JULY 10,1991. I I 7. REFERENCE FIELD BOOKS: MP91-01 PCS. 7-8& I MP98-07 POS. 19-24. GRAPHIC SCALE 8, REFERENCE DRAWINGS MPLPADAB WELL L-38&MPLPAOAS 'HELL L-44.. 0 100 200 400 - ,,0Ni.% titbit, (IN FEET) ii'6,:* .q..... ii , I -200 ft. 6,:' .- **.•!!.4- •,r' RENAMED CONDUCTOR REVISION NOTE ... Iki / •.,{r�j SURVEYOR'S CERTIFICATE WELLS: 47 AND 50 :: 7g 4 I I HEREBY CERTIFY THAT I AM TItiS A5-BL1q,T DRAWMIG K A REISSUE CF A PREVIOUS i t'""' f; I PROPERLY REGISTERED AND LICENSED AS-BUILT DRAWING FCR CONDUCTORS 38 AND 44. I. '"� fl t..s,. �' TO PRACTICE LAS SURVEYING IN sy �► RENAMED CCNOUCTCRS ARE AS FOLLOWS: s' -7-1: + THE STATE CF AU$IA AND NAT �� •* R'•,ar AN TI = MAILE he OR UNDERMY DIRECT QLD COND. NAME NEW COND. NAME. •""+ MASUPERVISION AND THAT ALL L-38 L-5D ' 108'D8 • : s CIMENS10N5 AND OTHER DETAILS ARE L-44 L-47 .�py 1�. CORRECT AS CF JANUARY 11, 1998 EF rir "rafSsiC71N FCR HELL 1-50 AND AS OF JULY 10, �, ,.{{t""```�� 1996 FOR HELL L-47. LOCATED WITHIN PROTRACTED SEC. 8, T. 13 N.. R. 10 E., UMIAT MERIDIAN, AK. WELL A.S.P. PLANT GEODETIC GEODETIC GROUND ' SECTION NO. COORDINATES COORDINATES POSITION(DMS) POSIT1ON(D.OD) ELEV. OFFSETS Y-6,031,641,90 \N- 1230.03 70'29'50.318" 70.4973100' 3,450'FSL 1-47 X= 545,157.43 E= 1509.06 149'37'50.603" 149.6307231' 18.9' 4,722'FEL Y-6,031,462.90 N. 1109.80 70'29'48.559" 70.4968219' 3,272'FSL L-50 17.8'545,097.84 E= 1363.65 149'37'52.389" 149.6312192' 17'8" 4,783'FEL nr.* �""' M0.iAWAY ji_,HiIcOrpA)aska w._.._n _ m e MPL as MPf! L-PAO '�� e RENAMED CONDUCTORS INA024161R.1181E� . '14R@9141991 _.,d[.+41 I 1••2001 WELLS L-47 & L-50 1 a 1 I .Loo, Orrrw, Page 54 Version 1 June,2015 • II Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 34.0 Offset MW vs TVD Chart MW vs TVD Offsets 0 ___,_. -L-37 —L-35 I 1000 -L-34i 2000 III a 3000 ii . 4000 5000 `�� .1 4 5000 111 1111111111h 7000 i — IIII 8000 8.0 9.0 10.0 11.0 12.0 13.0 14.0 15.0 Mud Weight(PPG) Page 55 Version 1 June, 2015 I 0 II Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company 35.0 Drill Pipe Information 5" 19.5# S-135 DS-50 Drill Pipe Configuration e ow 5 Pipe Body OD in,5.000 80%Inspection Class t Pipe Body Wall Thickness in!0.362 Nominal Weight Designation 19.50 V I, Pipe Body Grade S-135 Drill Pipe Approximate Length n.31.5 Drill Pipe Length Rangel SmoothEdge Height n)i3132 Raised Connection GPDS50 Tool Joint SMYS a 120.000 I Tool Joint 00 6.625 Upset Type EUTool Joint ID n.3.250 Max Upset OD (DTE) nri 5.125 '11 1 Pin Tong 9 Friction Factor 11.0 j_/ Box Tong I n:.12 Nm:Tong space may Include harceacmo.... Drill Pipe Performance Drill-Pipe Length Range2 Performance of Drell Pipe with Pipe Body at Best Estimates Nominal 9 '-ot',—tCdatp21 tena'l coaarq) (Wail accurate) i 80 4 Inspection Class wed f' `"'ip Operational Max Tension Drill Pipe Adjusted Weight Ibvni 24.11 23.29 Torque ftJbs) Torque tn.insi ,ba, Fluid Displacement ro.tl,0.37 0.36 Tension Only 0 560,800 Fluid Displacement soar n,00088 0.0085 t.6anPnum MUT 43,140 cemanea Leaetng 39,600 410,500 Fluid Capacity igakni 0.71 .0.70 0.72 Fluid Capacity tebls rtt 0.0169 0.0167 0.0172 Tension Only 0 560,800 tAwblrhi MUT 36,100 32,100 467,400 Dnft Size tint 3.125 .. l:cmdrhed Loading NOAe.Ot nihil barrel equals 02 US gallons. Mole:Dell ppe assembly vaiaes are beak eabmates and may vary di..e In pipe body mill loierance,Internal paskx coating,and other factors. Connection Performance GPDS50 ( 6.625 rni OD X 3.250 tet ID ) 120,000 (Psi) ,ill Angled rtake.up Terson al anmakiet le icI,al GameceP Tool Joint Dimensions lint 6.435 TongueSeparar.or Yrld m-bar) nos; lbs) Balanced 00 Maximum Make-up Torque 43,100 Tensile Limited 1,046,900 ranmp.n Toa,gel oe tor Aeu 5.934 Minimum Make-up Torque 36,100 1.202.500 1.250.000 Premium ciasa un) Note The rraximzm naked d.o.e Motile re argued alien possein -rowminimum Joint DO tor Note To maslmte connect.,operaaanai IensYe.a IAA'174,-3T,31,00(a.itsy should be applied. Tool Joint Torsional Strength tpws) 71,800 Tool Joint Tensile Strength ba 1,250,000 Cahanterbore Orn Elevator Shoulder Information Elevator OD 3/32 Raised 6.812 ah) 7 SmoothE(ge Height Nominal Tool Joint Worn to Bevel Worn to Min TJ OD for 3132 Raised OD Diameter API Premium Class Box OD 6.812 6.625 6.063 5.930 Elevator Capacity bol 1,658,000l 1.440,200 823,604 685,600 i,n 5219'.. .._1 vc,r- Ein'n rC.:41.7,,,- r ,n. e- a sent t ami 1 :Ire: f t t) a'o,.. Assumed Elevator Bore Diameter j �«e A rail d ee,aior Co I a. _r ca....,t n n,n age::IM n aKc.4,ION, Pipe Body Slip Crushing Capacity Pipe Body Configuration( 5 OD 0.362 i^) Wall S-135) Nominal 80%Inspection Class API Premium Class yT 7 Slip Crushing Capacity (gm,498.300 396,500 ,396,500 `•\ fff Note:Sag 0,0.1na Slip g lead is caudated Mb fie spr.xerilrdd mance horn'Any toes D's..P.rr Assumed Slip Length tel)16.5 Fal in to Ste Area Wald at 1939 nor the sap lengh and raps erre load ndbr sheen ane h to ret renes Transverse Load Factor fl<1 4.2 arty. �"stal'padetergent P.O the sepdesign a dcona rr,coealeientct ton loading cl` r sips all Pipe 00 and eat farUtice and other tazffica.Canh,il MAlh the stp marufactter for aalMeoi rdal.,lun. Pipe Body Performance Pipe Body Configuration( 5 aro OD 0.362 on) Wall S-135) Nominal 80%Inspection Class API Premium Class Pipe Tensile Strength ion 712,100 560,800 560,800 Pipe Torsional Strength '11-Ifni 74,100 58.100 58,100 TJ/PipeBody Torsional Ratio 0.97 1.24 1.24 80%Pipe Torsional Strength mit,59.300 46.500 46,500 1 Burst par 17,105 15.638 15,638 Nate:NOT4rvl Burst Collapse I i 15.672 10.029 10,029 calculated at e>s,RBW Pipe OD n,5.000 4.855 4.855 peAPI Thickness 0.362 0.290 0.290 Nominal Pipe ID clni 4.276 4.276 4.276 Cross Sectional Area of Pipe Body ,in'2i 5.275 4.154 4.154 Cross Sectional Area of OD (m.21 19.635 18-514 18.514 Cross Sectional Area of ID ,n'2, 14.360 14.360 14.360 Section Modulus (.1"•3)'5.708 4.476 4.476 K.Y Polar Section Modulus lir3i 11.415 8.953 8.953 Grant Page 56 Version 1 June, 2015 0 • II Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company Operational Limits of Drill Pi e Connection `GPDS50 Tool Joint 00 15,116.625 Tool Joint ID ,,n,3.250 Tool Joint Specified Minimum 124,004 11 Yield Strength tai Pipe Body I 80%Inspection Class Pipe Body OD 0,015 Wall Thickness ,,n 0.362 Pipe Body Grade 1S-135 Combined Loading for Drill Pipe at Combined Loading for Drill Pipe at Maximum Make-up Torque= 43,100 1n-F6:, Minimum Make-up Torque= 36.100 Inlbsy Operational Assembly Pipe Body Connect/on Mn. Operation Assembly Pipe Body Cunedion MaxTorque Tension Max Tension Tension I Torque Max Tension Mex T,,,,,,„„ n Max Tension t'It-Ins, Bbs7 0651 Wbs1 IA-lbs) 110.5) {lbs] 11501 0 560,800 560.800 1.046.900 0 560.800 560,800 1.202.500 I 2,100 560,400 560,400 1.046.900 1.700 560.500 560.500 1,202.500 4.200 559.300 559,300 1.046.900 3 400 559,800 559.800 1,202,500 6,300 557.500 557,500 1,046.900 5.100 558.600 558,600 1.202.500 8,300 555,000 555,000 1.046.900 6.800 556.900 556.900 1.202,500 10,400 551,700 551.700 1.046.900 8.400 554.900 554.900 1.202,500 12,500 547,600 547.600 1.046.900 10.100 552.200 552.200 1.202.500 14,600 542,800 542.800 1.046.900 11,800 549,100 549,100 1,202,500 16.700 537.100 537,100 1.046.900 13.500 545.400 545.400 1.202.500 18,800 530,600 530,600 1.046.900 15.200 541.200 541.200 1,202.500 20,800 523,600 523,600 1.046.900 16.900 536.500 536.500 1.202,500 22,900 515,400 515,400 1,046.900 18,600 531,300 531,300 1,202.500 25.000 506.200 506.200 1.046.900 20.300 525.400 525.400 1,202,500 27.100 496.100 496,100 1.046.900 22,000 519.000 519.000 1.202,500 29,200 484,800 484,800 1.046.900 23 700 512.000 512.000 1.202.500 31,300 472,500 472,500 1.046.900 25,300 504.800 504,800 1.202,500 33.300 459,600 459,600 1.046.900 27.000 496.600 496.600 1,202,500 35,400 444,700 444,700 1,046.900 28.700 487.600 487.600 1.202,500 37.500 428.400 428,400 1.046.900 30.400 477.900 477.900 1.202.500 39,600 410,500 410,500 '1.046.900 32.100 467.400 467.4001,202.500 Operational drilling torque is limited by the Make-up Torque. Operational drilling torque is limited by the Make-up Torque. Connection Make-up Torque Range Make-up Torque Connection Max ,,- ,,Tension ,Y:: Min MUT 36,100 1,202,500 36,900 1,229,200 37,700 1,243,600 " 38,400 1,218,100 39,200 1,169,000 tilli 40,000 1,159,800 40,800 1,130,700 41,500 1,105,200 42,300 1,076,100 Max MUT 43,100 1,048,900 Page 57 Version 1 June,2015 • • II Milne Point Unit L-47 Drilling Procedure Hilcorp Energy Company Connection Wear Table ea ab e Connection GPDS50 Tool Joint CID ,..016.625 Tool Joint ID ;,,,;13250 Tool Joint Specified Minimum 120,000 Yield Strength many Connection Wear Tool Connection Max Connection Max Min MUT Connection Max New OD, Joint OD Torsional MUT Tension Tension Strength ,,,_,_,, 6.625 71,800 43,100 1,046,900 35,908 1.195.900 6.562 71,800 43,100 1,034,900 35,900 1.208.700 T 6.499 71,800 43,100 1,022,600 35,900 1,222,400 6.435 71,800 43,100 1,009,800 35.900 1.237.500 6.372 71,200 42,700 1,008,100 35.600 1.245,200 I! 6.309 68.000 40,800 1,057,300 34.000 1.207.700 6.246 64,800 38,900 1,104,800 32.400 1,169,800 6.183 61,700 37,000 1,150,400 30,800 1.131.300 6.12 58,600 35,200 1,190,900 29,300 1,096.100 6.056 55,500 33,300 1,232,300 27.800 1.060.800 Worn OD 5.993 52,600 31,500 1,227,200 26,300 1,024,600 5.93 49,600 29,800 1,187,100 24.E 987.900 Pipe Body Combined Loading Table(Torque-Tension) PIC*Body 80%Inspection Class Pipe Body OD .t, 5 Wall Thickness uny10_362 Pipe Body Grade S-135 Pipe Body Torque 9 5.300 10.600 15,800 21.100 26.400 31.700 37.000 42.300 47,500 52.800 58.100 tooys-lbsy Pipe Body Max Tension 540,800 558.400 551,400 539.800 522,500 499,800 470,000 432.400 384.500 323,100 234,300 12.200 Page 58 Version 1 June,2015 • 0 Hilcorp Energy Company Milne Point M Pt L Pad Plan MPL-47 MPL-47 (Well #4) Plan: MPL-47 wp3 Standard Proposal Report 26 June, 2015 T, . �u ,, ! i I ti. i► ..I z HALLIBURTON Sperry Drilling Services • • HALLIBURTON Project: Milne Point WELL DETAILS:Plan MPL-47 NAD 1927(NADCON CONUS) Alaska Zone 04 Site: M Pt L Pad Ground Level 16.90 s"" Or110 a Well: Plan MPL-47 +Los +&-W Nortling Ana 18m6.1e Longitude Slot Wellbore: MPL-47(Well#4) 0.00 0.00 6031641.90 545157.43 70°29'50.516N 149°3750.603W Design: MPL-47 wp3 FORMATION TOP DETAILS -2000- No formation data is available -1500- -1000- -500-_ - 4 0- __Start Build 1.00 CASING DETAILS 500- 500 TVD TVDSS MD Size Name Start Build 3.00 4088.60 4041.70 7941.81 9-5/8 9 58" 4066.90 4020.00 13002.29 5-1/2 5 1/2" Start DLS 5.00 TFO-18.41 1000- 1 o00 ----- � Start 3712.35 hold at 2058.77 MD "' 10 us 1500_ Op 4N kp' h cPa 2000- ti _ �� „p Start 500.00 hold at 7441.81 MD Start DLS 5.00 TFO-92.39 2500_ �O� ,,p 1 Start DLS 5.00 TFO-5.19 H 51 I Start 302.83 hold at 8120.81 MD m 1 3000- , i " Start DLS 5.00 TFO 188.32 TD at 13002.29 h'r/ I itStart 4498.73 hold at 8503.58 MD 3500= 4� i -'' •d R i Q • 1. n 75 4000- -• i '- - o m O '' O ro ` I O :• OnO O O S O O O * o 4500- I I, ... 9 5/8" 5 1/2" 5000- 5500- 6000- I V III 11/111111 I ii I ii 111111111 1111111111111111 1111111111111111111111111111111111111 1111111111111111111111111 1111111 i1 -1500 -1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 8000 8500 7000 7500 8000 8500 9000 9500 10000 Vertical Section at 160.99°(1250 usft/in) t] I lilt r,rll • • HALLIBURTON Project: Milne Point WELL DETAILS:Plan MPL-47 Site: M Pt L Pad GmladLevel 16.90 auur :- ,",n^„ +N/-S+E/-W Northing FastingLatino& Longitude Slot tooa- Wellbore: MPL-4477(Well 7Y4) Well: Plan 0.00 0.00 6031641.90 545157.43 70°2950.316N 149.37 50.603 W Plan: MPL-47 wp3 REFERENCE INFORMATION 5007. Co-ordinate(N/E)Reference:Wel Pon MPL-47.True North • Vertical(TVD)Reference:Plan MPL-47 06 90usft Nordic 3 16.9 CBE 0 30 - te4 Measured Depth Ra a encu:Plan MPL-47 @ 46 90us0(Nordic 3(16.9 CBE 0 30'KB)) 07 'Start Build IMO Calculation Method:Minimum Curvature 734 ' StmtBuild3.09 CASING DETAILS '5007IJ,p ND TVDSS MO Size Name Start DLS 5.00 TPO-18.41 4088.60 4041.70 7941.81 9-5/8 95/6' 1000- .7 4086.90 4020.00 13002.29 5-1/2 512' Start 3712.35 hold at 2056.77 MD -1500- �� -2000- _ .2Jj6 2500 ii G, -3000- 100 so a - .Start ILS 5.00 TFO-92.39 g -3500- 36-00 3750 Stan S10.00 Mid at 7441.81 MD v-4000 /StartDLS 5.00 TFO-5.19 -45007 f Start 3)2.83 hold at 8120.81 MD - °► StartDLS 5.00170 168.32 a -5000- IO _ ___ ___Start 4478.73 hold at 8503.56 MD -5500- 95/Se/ 6000- -6500- ' - TD at 13002.29 -7000- • -7500- / _8000- T M Azimuths to True North ' - MagnetcNorth:18.90° 11•L-47lntereTcewp2/__ 0lr,' --_. }-P Magnetic Field 5 12" -8500- Strength:57504.4snT Dip Angle:81.08° / - Date:923/2015 'Weil 4 Tool = Model:BGGM2015 TITilllllll rlllllllllllErrE TIIIIIIIIrIII,flllllllllll 13111 ji/ir i irr Il Illllrllllljllllll111IIIi Tillllllllllillllllllllllllllllllllll IL -6500 -6000 -5500 -5000 -4500 -4000 -3500 -3000 -2500 -2000 -1500 -1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 West(-)/East(+)(1500 usft/in) r • . Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan MPL-47 Company: Hilcorp Energy Company TVD Reference: Plan MPL-47 @ 46.90usft(Nordic 3(16.9 CBE+30'K Project: Milne Point MD Reference: Plan MPL-47 @ 46.90usft(Nordic 3(16.9 CBE+30'K Site: M Pt L Pad North Reference: True Well: Plan MPL-47 Survey Calculation Method: Minimum Curvature Wellbore: MPL-47(Well#4) Design: MPL-47 wp3 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 Site M Pt L Pad,TR-13-10 Site Position: Northing: 6,029,799.28 usft Latitude: 70°29'32.230 N From: Map Easting: 544,529.55 usft Longitude: 149°38'9.412 W Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.34 ° Well Plan MPL-47,BP Slot L-44 Well Position +NI-S 0.00 usft Northing: 6,031,641.90 usft Latitude: 70°29'50.316 N +E/-W 0.00 usft Easting: 545,157.43 usft Longitude: 149°37'50.603 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 16.90 usft Wellbore MPL-47(Well#4) Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°l (°l (nT) BGGM2015 9/23/2015 18.90 81.08 57,504 Design MPL-47 wp3 Audit Notes: Version: Phase: PLAN Tie On Depth: 30.00 Vertical Section: Depth From(ND) +NI-S +E/-W Direction (usft) (usft) (usft) (°) 30.00 0.00 0.00 160.99 Plan Sections Measured Vertical ND Dogleg Build Turn Depth Inclination Azimuth Depth System +NI-S +E/-W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) 0100usft) (°/100usft) (°/100usft) (°) 30.00 0.00 0.00 30.00 -16.90 0.00 0.00 0.00 0.00 0.00 0.00 300.00 0.00 0.00 300.00 253.10 0.00 0.00 0.00 0.00 0.00 0.00 600.00 3.00 225.00 599.86 552.96 -5.55 -5.55 1.00 1.00 0.00 225.00 1,200.00 21.00 225.00 1,184.34 1,137.44 -93.40 -93.40 3.00 3.00 0.00 0.00 2,056.77 63.04 211.06 1,807.81 1,760.91 -550.53 -414.03 5.00 4.91 -1.63 -18.41 5,769.12 63.04 211.06 3,490.88 3,443.98 -3,385.02 -2,121.24 0.00 0.00 0.00 0.00 7,441.81 85.00 125.67 4,045.02 3,998.12 -4,763.30 -1,763.01 5.00 1.31 -5.10 -92.39 7,941.81 85.00 125.67 4,088.60 4,041.70 -5,053.75 -1,358.36 0.00 0.00 0.00 0.00 8,120.81 93.91 124.86 4,090.30 4,043.40 -5,156.99 -1,212.37 5.00 4.98 -0.45 -5.19 8,423.64 93.91 124.86 4,069.63 4,022.73 -5,329.68 -964.46 0.00 0.00 0.00 0.00 8,503.56 90.00 125.67 4,066.90 4,020.00 -5,375.79 -899.27 5.00 -4.90 1.01 168.32 13,002.29 90.00 125.67 4,066.90 4,020.00 -7,999.07 2,755.46 0.00 0.00 0.00 0.00 6/26/2015 7:00:19PM Page 2 COMPASS 5000.1 Build 73 • • Halliburton H A LL I B U R'I'O N Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan MPL-47 Company: Hilcorp Energy Company TVD Reference: Plan MPL-47 @ 46.90usft(Nordic 3(16.9 CBE+30'K Project: Milne Point MD Reference: Plan MPL-47 @ 46.90usft(Nordic 3(16.9 CBE+30'K Site: M Pt L Pad North Reference: True Well: Plan MPL-47 Survey Calculation Method: Minimum Curvature Wellbore: MPL-47(Well#4) Design: MPL-47 wp3 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-5 +E/-W Northing Easting DLS Vert Section (usft) (^) (^) (usft) usft (usft) (usft) (usft) (usft) -16.90 30.00 0.00 0.00 30.00 -16.90 0.00 0.00 6,031,641.90 545,157.43 0.00 0.00 100.00 0.00 0.00 100.00 53.10 0.00 0.00 6,031,641.90 545,157.43 0.00 0.00 200.00 0.00 0.00 200.00 153.10 0.00 0.00 6,031,641.90 545,157.43 0.00 0.00 300.00 0.00 0.00 300.00 253.10 0.00 0.00 6,031,641.90 545,157.43 0.00 0.00 400.00 1.00 225.00 399.99 353.09 -0.62 -0.62 6,031,641.28 545,156.82 1.00 0.38 500.00 2.00 225.00 499.96 453.06 -2.47 -2.47 6,031,639.42 545,154.98 1.00 1.53 600.00 3.00 225.00 599.86 552.96 -5.55 -5.55 6,031,636.31 545,151.91 1.00 3.44 700.00 6.00 225.00 699.54 652.64 -11.10 -11.10 6,031,630.73 545,146.40 3.00 6.88 800.00 9.00 225.00 798.68 751.78 -20.33 -20.33 6,031,621.45 545,137.23 3.00 12.60 900.00 12.00 225.00 896.99 850.09 -33.21 -33.21 6,031,608.49 545,124.42 3.00 20.58 1,000.00 15.00 225.00 994.22 947.32 -49.72 -49.72 6,031,591.89 545,108.02 3.00 30.81 1,100.00 18.00 225.00 1,090.09 1,043.19 -69.80 -69.80 6,031,571.69 545,088.06 3.00 43.26 1,200.00 21.00 225.00 1,184.34 1,137.44 -93.40 -93.40 6,031,547.94 545,064.61 3.00 57.89 1,300.00 25.79 221.37 1,276.10 1,229.20 -122.41 -120.47 6,031,518.77 545,037.72 5.00 76.50 1,400.00 30.64 218.82 1,364.19 1,317.29 -158.62 -150.84 6,031,482.39 545,007.57 5.00 100.84 1,500.00 35.53 216.92 1,447.95 1,401.05 -201.73 -184.29 6,031,439.07 544,974.38 5.00 130.71 1,600.00 40.45 215.42 1,526.74 1,479.84 -251.43 -220.57 6,031,389.16 544,938.41 5.00 165.89 1,700.00 45.38 214.19 1,599.95 1,553.05 -307.34 -259.39 6,031,333.02 544,899.93 5.00 206.10 1,800.00 50.32 213.16 1,667.04 1,620.14 -369.03 -300.47 6,031,271.09 544,859.24 5.00 251.05 1,900.00 55.27 212.27 1,727.49 1,680.59 -436.04 -343.48 6,031,203.83 544,816.63 5.00 300.39 2,000.00 60.22 211.48 1,780.84 1,733.94 -507.84 -388.11 6,031,131.76 544,772.45 5.00 353.75 2,056.77 63.04 211.06 1,807.81 1,760.91 -550.53 -414.03 6,031,088.91 544,746.79 5.00 385.67 2,100.00 63.04 211.06 1,827.41 1,780.51 -583.54 -433.91 6,031,055.79 544,727.11 0.00 410.40 2,200.00 63.04 211.06 1,872.74 1,825.84 -659.89 -479.90 6,030,979.17 544,681.59 0.00 467.62 2,300.00 63.04 211.06 1,918.08 1,871.18 -736.25 -525.89 6,030,902.54 544,636.08 0.00 524.83 2,400.00 63.04 211.06 1,963.42 1,916.52 -812.60 -571.87 6,030,825.92 544,590.56 0.00 582.04 2,500.00 63.04 211.06 2,008.76 1,961.86 -888.95 -617.86 6,030,749.30 544,545.04 0.00 639.25 2,600.00 63.04 211.06 2,054.09 2,007.19 -965.30 -663.85 6,030,672.67 544,499.52 0.00 696.46 2,700.00 63.04 211.06 2,099.43 2,052.53 -1,041.66 -709.84 6,030,596.05 544,454.00 0.00 753.68 1 2,800.00 63.04 211.06 2,144.77 2,097.87 -1,118.01 -755.82 6,030,519.43 544,408.49 0.00 8 0 89 2,900.00 63,04 211.06 2,190.10 2,143.20 -1,194.36 -801.81 6,030,442.80 544,362.97 0.00 868.10 3,000.00 63.04 211.06 2,235.44 2,188.54 -1,270.72 -847.80 6,030,366.18 544,317.45 0.00 925.31 3,100.00 63.04 211.06 2,280.78 2,233.88 -1,347.07 -893.78 6,030,289.56 544,271.93 0.00 982.52 3,200.00 63.04 211.06 2,326.12. 2,279.22 -1,423.42 -939.77 6,030,212.94 544,226.41 0.00 1,039.74 3,300.00 63.04 211.06 2,371.45 2,324.55 -1,499.77 -985.76 6,030,136.31 544,180.90 0.00 1,096.95 3,400.00 63.04 211.06 2,416.79 2,369.89 -1,576.13 -1,031.75 6,030,059.69 544,135.38 0.00 1,154.16 3,500.00 63.04 211.06 2,462.13 2,415.23 -1,652.48 -1,077.73 6,029,983.07 544,089.86 0.00 1,211.37 3,600.00 63.04 211.06 2,507.46 2,460.56 -1,728.83 -1,123.72 6,029,906.44 544,044.34 0.00 1,268.59 3,700.00 63.04 211.06 2,552.80 2,505.90 -1,805.18 -1,169.71 6,029,829.82 543,998.83 0.00 1,325.80 3,800.00 63.04 211.06 2,598.14 2,551.24 -1,881.54 -1,215.69 6,029,753.20 543,953.31 0.00 1,383.01 3,900.00 63.04 211.06 2,643.48 2,596.58 -1,957.89 -1,261.68 6,029,676.57 543,907.79 0.00 1,440.22 4,000.00 63.04 211.06 2,688.81 2,641.91 -2,034.24 -1,307.67 6,029,599.95 543,862.27 0.00 1,497.43 4,100.00 63.04 211.06 2,734.15 2,687.25 -2,110.60 -1,353.66 6,029,523.33 543,816.75 0.00 1,554.65 4,200.00 63.04 211.06 2,779.49 2,732.59 -2,186.95 -1,399.64 6,029,446.70 543,771.24 0.00 1,611.86 4,300.00 63.04 211.06 2,824.82 2,777.92 -2,263.30 -1,445.63 6,029,370.08 543,725.72 0.00 1,669.07 6/26/2015 7:00:19PM Page 3 COMPASS 5000.1 Build 73 • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan MPL-47 Company: Hilcorp Energy Company TVD Reference: Plan MPL-47 @ 46.90usft(Nordic 3(16.9 CBE+30'K Project: Milne Point MD Reference: Plan MPL-47 @ 46.90usft(Nordic 3(16.9 CBE+30'K Site: M Pt L Pad North Reference: True Well: Plan MPL-47 Survey Calculation Method: Minimum Curvature Wellbore: MPL-47(Well#4) Design: MPL-47 wp3 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NI-S +E/-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 2,823.26 4,400.00 63.04 211.06 2,870.16 2,823.26 -2,339.65 -1,491.62 6,029,293.46 543,680.20 0.00 1,726.28 4,500.00 63.04 211.06 2,915.50 2,868.60 -2,416.01 -1,537.60 6,029,216.83 543,634.68 0.00 1,783.50 4,600.00 63.04 211.06 2,960.84 2,913.94 -2,492.36 -1,583.59 6,029,140.21 543,589.16 0.00 1,840.71 4,700.00 63.04 211.06 3,006.17 2,959.27 -2,568.71 -1,629.58 6,029,063.59 543,543.65 0.00 1,897.92 4,800.00 63.04 211.06 3,051.51 3,004.61 -2,645.06 -1,675.56 6,028,986.96 543,498.13 0.00 1,955.13 4,900.00 63.04 211.06 3,096.85 3,049.95 -2,721.42 -1,721.55 6,028,910.34 543,452.61 0.00 2,012.34 5,000.00 63.04 211.06 3,142.18 3,095.28 -2,797.77 -1,767.54 6,028,833.72 543,407.09 0.00 2,069.56 5,100.00 63.04 211.06 3,187.52 3,140.62 -2,874.12 -1,813.53 6,028,757.09 543,361.57 0.00 2,126.77 5,200.00 63.04 211.06 3,232.86 3,185.96 -2,950.48 -1,859.51 6,028,680.47 543,316.06 0.00 2,183.98 5,300.00 63.04 211.06 3,278.19 3,231.29 -3,026.83 -1,905.50 6,028,603.85 543,270.54 0.00 2,241.19 5,400.00 63.04 211.06 3,323.53 3,276.63 -3,103.18 -1,951.49 6,028,527.22 543,225.02 0.00 2,298.40 5,500.00 63.04 211.06 3,368.87 3,321.97 -3,179.53 -1,997.47 6,028,450.60 543,179.50 0.00 2,355.62 5,600.00 63.04 211.06 3,414.21 3,367.31 -3,255.89 -2,043.46 6,028,373.98 543,133.99 0.00 2,412.83 5,700.00 63.04 211.06 3,459.54 3,412.64 -3,332.24 -2,089.45 6,028,297.35 543,088.47 0.00 2,470.04 5,769.12 63.04 211.06 3,490.88 3,443.98 -3,385.02 -2,121.24 6,028,244.39 543,057.00 0.00 2,509.59 5,800.00 62.99 209.33 3,504.89 3,457.99 -3,408.80 -2,135.07 6,028,220.53 543,043.31 5.00 2,527.56 5,900.00 62.96 203.72 3,550.37 3,503.47 -3,488.46 -2,174.83 6,028,140.64 543,004.05 5.00 2,589.93 6,000.00 63.15 198.11 3,595.71 3,548.81 -3,571.68 -2,206.63 6,028,057.23 542,972.76 5.00 2,658.26 6,100.00 63.57 192.54 3,640.58 3,593.68 -3,657.84 -2,230.23 6,027,970.94 542,949.68 5.00 2,732.04 6,200.00 64.19 187.01 3,684.63 3,637.73 -3,746.28 -2,245.45 6,027,882.42 542,935.00 5.00 2,810.70 6,300.00 65.03 181.55 3,727.53 3,680.63 -3,836.32 -2,252.17 6,027,792.34 542,928.82 5.00 2,893.64 6,400.00 66.06 176.18 3,768.96 3,722.06 -3,927.29 -2,250.36 6,027,701.40 542,931.19 5.00 2,980.24 6,500.00 67.27 170.89 3,808.59 3,761.69 -4,018.48 -2,240.00 6,027,610.28 542,942.10 5.00 3,069.83 6,600.00 68.66 165.71 3,846.13 3,799.23 -4,109.20 -2,221.20 6,027,519.68 542,961.45 5.00 3,161.73 6,700.00 70.20 160.63 3,881.28 3,834.38 -4,198.77 -2,194.09 6,027,430.29 542,989.11 5.00 3,255.25 6,800.00 71.88 155.65 3,913.80 3,866.90 -4,286.50 -2,158.87 6,027,342.78 543,024.85 5.00 3,349.66 6,900.00 73.69 150.77 3,943.41 3,896.51 -4,371.72 -2,115.81 6,027,257.83 543,068.42 5.00 3,444.26 7,000.00 75.60 145.98 3,969.91 3,923.01 -4,453.79 -2,065.25 6,027,176.08 543,119.47 5.00 3,538.32 7,100.00 77.61 141.27 3,993.08 3,946.18 -4,532.08 -2,007.57 6,027,098.15 543,177.63 5.00 3,631.13 7,200.00 79.70 136.64 4,012.75 3,965.85 -4,605.99 -1,943.20 6,027,024.64 543,242.44 5.00 3,721.98 7,300.00 81.86 132.07 4,028.78 3,981.88 -4,674.97 -1,872.64 6,026,956.10 543,313.41 5.00 3,810.17 7,400.00 84.07 127.55 4,041.04 3,994.14 -4,738.48 -1,796.42 6,026,893.06 543,390.01 5.00 3,895.05 7,441.81 85.00 125.67 4,045.02 3,998.12 -4,763.30 -1,763.01 6,026,868.44 543,423.56 5.00 3,929.40 7,500.00 85.00 125.67 4,050.09 4,003.19 -4,797.10 -1,715.92 6,026,834.93 543,470.85 0.00 3,976.69 7,600.00 85.00 125.67 4,058.81 4,011.91 -4,855.19 -1,634.99 6,026,777.34 543,552.13 0.00 4,057.97 7,700.00 85.00 125.67 4,067.52 4,020.62 -4,913.28 -1,554.06 6,026,719.75 543,633.40 0.00 4,139.25 7,751.04 85.00 125.67 4,071.97 4,025.07 -4,942.93 -1,512.75 6,026,690.35 543,674.88 0.00 4,180.74 Well 4 Heel 7,800.00 85.00 125.67 4,076.24 4,029.34 -4,971.37 -1,473.13 6,026,662.16 543,714.67 0.00 4,220.53 7,900.00 85.00 125.67 4,084.96 4,038.06 -5,029.46 -1,392.20 6,026,604.57 543,795.95 0.00 4,301.81 7,941.81 85.00 125.67 4,088.60 4,041.70 -5,053.75 -1,358.36 6,026,580.49 543,829.93 0.00 4,335.80 9 518" 8,000.00 87.90 125.41 4,092.20 4,045.30 -5,087.50 -1,311.11 6,026,547.02 543,877.38 5.00 4,383.10 8,100.00 92.88 124.96 4,091.53 4,044.63 -5,145.10 -1,229.40 6,026,489.93 543,959.43 5.00 4,464.17 8,120.81 93.91 124.86 4,090.30 4,043.40 -5,156.99 -1,212.37 6,026,478.15 543,976.53 5.00 4,480.95 6/26/2015 7:00:19PM Page 4 COMPASS 5000.1 Build 73 0 . Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan MPL-47 Company: Hilcorp Energy Company TVD Reference: Plan MPL-47 @ 46.90usft(Nordic 3(16.9 CBE+30'K Project: Milne Point MD Reference: Plan MPL-47 @ 46.90usft(Nordic 3(16.9 CBE+30'K Site: M Pt L Pad North Reference: True Well: Plan MPL-47 Survey Calculation Method: Minimum Curvature Wellbore: MPL-47(Well#4) Design: MPL-47 wp3 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NI-S +EI-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 4,037.99 8,200.00 93.91 124.86 4,084.89 4,037.99 -5,202.15 -1,147.54 6,026,433.39 544,041.63 0.00 4,544.77 8,300.00 93.91 124.86 4,078.07 4,031.17 -5,259.17 -1,065.68 6,026,376.86 544,123.82 0.00 4,625.35 8,400.00 93.91 124.86 4,071.24 4,024.34 -5,316.20 -983.82 6,026,320.34 544,206.02 0.00 4,705.92 8,423.64 93.91 124.86 4,069.63 4,022.73 -5,329.68 -964.46 6,026,306.98 544,225.46 0.00 4,724.97 8,503.56 90.00 125.67 4,066.90 4,020.00 -5,375.79 -899.27 6,026,261.27 544,290.93 5.00 4,789.80 8,600.00 90.00 125.67 4,066.90 4,020.00 -5,432.03 -820.92 6,026,205.52 544,369.61 0.00 4,868.49 8,700.00 90.00 125.67 4,066.90 4,020.00 -5,490.34 -739.68 6,026,147.71 544,451.19 0.00 4,950.08 8,800.00 90.00 125.67 4,066.90 4,020.00 -5,548.65 -658.44 6,026,089.90 544,532.78 0.00 5,031.67 8,900.00 90.00 125.67 4,066.90 4,020.00 -5,606.96 -577.20 6,026,032.08 . 544,614.36 0.00 5,113.26 9,000.00 90.00 125.67 4,066.90 4,020.00 -5,665.27 -495.96 6,025,974.27 544,695.94 0.00 5,194.85 9,100.00 90.00 125.67 4,066.90 4,020.00 -5,723.58 -414.72 6,025,916.46 544,777.53 0.00 5,276.44 9,200.00 90.00 125.67 4,066.90 4,020.00 -5,781.90 -333.48 6,025,858.65 544,859.11 0.00 5,358.03 9,300.00 90.00 125.67 4,066.90 4,020.00 -5,840.21 -252.24 6,025,800.84 544,940.69 0.00 5,439.63 9,400.00 90.00 125.67 4,066.90 4,020.00 -5,898.52 -171.00 6,025,743.03 545,022.28 0.00 5,521.22 9,500.00 90.00 125.67 4,066.90 4,020.00 -5,956.83 -89.77 6,025,685.22 545,103.86 0.00 5,602.81 9,600.00 90.00 125.67 4,066.90 4,020.00 -6,015.14 -8.53 6,025,627.40 545,185.45 0.00 5,684.40 9,700.00 90.00 125.67 4,066.90 4,020.00 -6,073.45 72.71 6,025,569.59 545,267.03 0.00 5,765.99 9,800.00 90.00 125.67 4,066.90 4,020.00 -6,131.77 153.95 6,025,511.78 545,348.61 0.00 5,847.58 9,900.00 90.00 125.67 4,066.90 4,020.00 -6,190.08 235.19 6,025,453.97 545,430.20 0.00 5,929.17 10,000.00 90.00 125.67 4,066.90 4,020.00 -6,248.39 316.43 6,025,396.16 545,511.78 0.00 6,010.76 10,100.00 90.00 125.67 4,066.90 4,020.00 -6,306.70 397.67 6,025,338.35 545,593.36 0.00 6,092.35 10,200.00 90.00 125.67 4,066.90 4,020.00 -6,365.01 478.91 6,025,280.54 545,674.95 0.00 6,173.94 10,300.00 90.00 125.67 4,066.90 4,020.00 -6,423.32 560.15 6,025,222.73 545,756.53 0.00 6,255.54 10,400.00 90.00 125.67 4,066.90 4,020.00 -6,481.63 641.38 6,025,164.91 545,838.12 0.00 6,337.13 10,500.00 90.00 125.67 4,066.90 4,020.00 -6,539.95 722.62 6,025,107.10 545,919.70 0.00 6,418.72 10,600.00 90.00 125.67 4,066.90 4,020.00 -6,598.26 803.86 6,025,049.29 546,001.28 0.00 6,500.31 10,700.00 90.00 125.67 4,066.90 4,020.00 -6,656.57 885.10 6,024,991.48 546,082.87 0.00 6,581.90 10,800.00 90.00 125.67 4,066.90 4,020.00 -6,714.88 966.34 6,024,933.67 546,164.45 0.00 6,663.49 10,900.00 90.00 125.67 4,066.90 4,020.00 -6,773.19 1,047.58 6,024,875.86 546,246.03 0.00 6,745.08 11,000.00 90.00 125.67 4,066.90 4,020.00 -6,831.50 1,128.82 6,024,818.05 546,327.62 0.00 6,826.67 11,100.00 90.00 125.67 4,066.90 4,020.00 -6,889.82 1,210.06 6,024,760.24 546,409.20 0.00 6,908.26 11,200.00 90.00 125.67 4,066.90 4,020.00 -6,948.13 1,291.30 6,024,702.42 546,490.78 0.00 6,989.85 11,300.00 90.00 125.67 4,066.90 4,020.00 -7,006.44 1,372.54 6,024,644.61 546,572.37 0.00 7,071.45 11,400.00 90.00 125.67 4,066.90 4,020.00 -7,064.75 1,453.77 6,024,586.80 546,653.95 0.00 7,153.04 11,500.00 90.00 125.67 4,066.90 4,020.00 -7,123.06 1,535.01 6,024,528.99 546,735.54 0.00 7,234.63 11,600.00 90.00 125.67 4,066.90 4,020.00 -7,181.37 1,616.25 6,024,471.18 546,817.12 0.00 7,316.22 11,700.00 90.00 125.67 4,066.90 4,020.00 -7,239.69 1,697.49 6,024,413.37 546,898.70 0.00 7,397.81 11,800.00 90.00 125.67 4,066.90 4,020.00 -7,298.00 1,778.73 6,024,355.56 546,980.29 0.00 7,479.40 11,900.00 90.00 125.67 4,066.90 4,020.00 -7,356.31 1,859.97 6,024,297.74 547,061.87 0.00 7,560.99 12,000.00 90.00 125.67 4,066.90 4,020.00 -7,414.62 1,941.21 6,024,239.93 547,143.45 0.00 7,642.58 12,100.00 90.00 125.67 4,066.90 4,020.00 -7,472.93 2,022.45 6,024,182.12 547,225.04 0.00 7,724.17 12,200.00 90.00 125.67 4,066.90 4,020.00 -7,531.24 2,103.69 6,024,124.31 547,306.62 0.00 7,805.76 12,300.00 90.00 125.67 4,066.90 4,020.00 -7,589.56 2,184.92 6,024,066.50 547,388.21 0.00 7,887.35 12,400.00 90.00 125.67 4,066.90 4,020.00 -7,647.87 2,266.16 6,024,008.69 547,469.79 0.00 7,968.95 12,500.00 90.00 125.67 4,066.90 4,020.00 -7,706.18 2,347.40 6,023,950.88 547,551.37 0.00 8,050.54 6/26/2015 7:00:19PM Page 5 COMPASS 5000.1 Build 73 S i Halliburton HALLIBLiRTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan MPL-47 Company: Hilcorp Energy Company TVD Reference: Plan MPL-47 @ 46.90usft(Nordic 3(16.9 CBE+30'K Project: Milne Point MD Reference: Plan MPL-47 @ 46.90usft(Nordic 3(16.9 CBE+30'K Site: M Pt L Pad North Reference: True Well: Plan MPL-47 Survey Calculation Method: Minimum Curvature Wellbore: MPL-47(Well#4) Design: MPL-47 wp3 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +EI-W Northing Easting DLS Vert Section (usft) (^) (^) (usft) usft (usft) (usft) (usft) (usft) 4,020.00 12,600.00 90.00 125.67 4,066.90 4,020.00 -7,764.49 2,428.64 6,023,893.07 547,632.96 0.00 8,132.13 12,700.00 90.00 125.67 4,066.90 4,020.00 -7,822.80 2,509.88 6,023,835.25 547,714.54 0.00 8,213.72 12,800.00 90.00 125.67 4,066.90 4,020.00 -7,881.11 2,591.12 6,023,777.44 547,796.12 0.00 8,295.31 12,900.00 90.00 125.67 4,066.90 4,020.00 -7,939.42 2,672.36 6,023,719.63 547,877.71 0.00 8,376.90 13,002.29 90.00 125.67 4,066.90 4,020.00 -7,999.07 2,755.46 6,023,660.50 547,961.16 0.00 8,460.36 MPL-47 Interp Toe wp2-Well 4 Toe Targets Target Name -hit/mIss target Dip Angle Dip Dir. TVD +NI-S +E/-W Northing Easting -Shape (°) (°) (usft) (usft) (usft) (usft) (usft) MPL-47 Interp Toe wp2 0.00 0.00 4,066.90 -7,999.07 2,755.46 6,023,660.50 547,961.16 -plan hits target center -Point I Well4 Toe 0.00 0.35 4,066.90 -8,118.39 2,921.69 6,023,542.20 548,128.10 -plan misses target center by 204.63usft at 13002.29usft MD(4066.90 TVD,-7999.07 N,2755.46 E) -Circle(radius 100.00) Well 4 Heel 0.00 0.35 4,066.90 -4,937.91 -1,508.60 6,026,695.40 543,679.00 -plan misses target center by 8.26usft at 7751.04usft MD(4071.97 TVD,-4942.93 N,-1512.75 E) -Circle(radius 100.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 7,941.81 4,088.60 9 5/8" 9-5/8 12-1/4 13,002.29 4,066.90 5 1/2" 5-1/2 8-1/2 6/26/2015 7:00:19PM Page 6 COMPASS 5000.1 Build 73 fa s Hilcorp Energy Company Milne Point 3 M Pt L Pad • Plan MPL-47 MPL-47(Well#4) MPL-47 wp3 ` . .. Sperry Drilling Services Clearance Summary Anticollision Report 26 June,2015 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design:M Pt L Pad-Plan MPL-47-MPL-47(Well#4)-MPL-47 wp3 Well Coordinates:6,031,641.90 N,545,157.43 E(70'29'50.32"N,149'37'50.60"W) Datum Height:Plan MPL-47(9 46.90usft(Nordic 3(16.9 CBE+30'KB)) y.`u Scan Range: 0.00 to 13,002.29 usft.Measured Depth. Scan Radius is 1,497.23 usft.Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build:73 Scan Type: GLOBAL FILTER APPLIED All wellpaths within 200'+100/1000 of reference Scan Type: 25.00 .. ., H.ALLIBUPTON ,Sit Sperry Drilling Services i • • SURVEY PROGRAM Hilcorp Energy Company ANTI-COLLISION SETTINGS Date:2015-04-13T00:00:00 Validated:Y. Version: Calculation Method:Minim=Curvature Interpolation Method:MD,interval:25.00 Error System:ISCWSA Depth Range From:30.00 To 13002.29 Depth From Depth lb Survey/Plan Tool Scan Method:Closest Approach 3D Centre Distance:1497.23 30.00 1500.00 MPL47wp3(MPL-47(Well fillG-SS Error Surface:Elliptical Conic Reference:Plan:MPLd7 wp3(Plan MPL-47/MPL 47(Well#4)) 1500.00 7941.81 MPL47 wp3(MPL-47(Well A4))/D+IFR2+MS+sag Warning Method:Error Ratio 7941.81 13002.28 MPL-47 wp3(MPL-47}L- (Wen 011))D+IFRI+MS+sag IMPL t -1a a,,�.t.. I ""'1 IMPL-81 `t MP101 j MPL.o2Al IMPL-05I I MPLS/I IMPL-4d I MPL-1 a I MPL-05I ', 9 I IMPL-*, O IMPL-10I !i=! \:cam/ I MPI-44 330 r .it•1�Ltty• 16 - IMPLd2l 330 t��-�NNerIare•irc;,a►v 30 IMPL.AAs� -',/ .. � I _ __ ?1,016 �i=� ►r • a 41. 1MPlA1l '44‘.4.0.1.42? 1 .40.F D.'\ -MPL-0{ l - ,.. .q....1:"...,"---.t.7.s -IMLL-01 wp4 300 ' a 1 4.1_ 300 e:.` '-\� •.rite �� 6-__ �•�1l "' � t 4.0 a,i�a �, •:.f ! 4e,. w IM�-1� ,, I��4�rvra ....._..•‘,0'*,t�� 5��'�°r f �$ 2 r uo rr - % ,40 o ti T'�i ' ! '- Ai,` lr�4, „Atli! !!tv ti , • _ ! 41 1 / • ,�' 0 # �` pie t5. tis Lsr 'S I�►IIJ�t•/��,I , I W.t�,► "� a � • 9 +� MPLd6wp From Colour To MD Nplitiilii. � � �'�A��i1��1(• .. r-y j'.r ,.►Ve �\ ,. 270 7\30.,.N a.+d.40.. eY,90 till I�sv� j¢ si.N rr® • • ti'• ♦ ♦ � �Ali � ,,• q/� ��'�, ��41! n0 re r1� alRiErw' o#ilAral : &0 so30 250 4�1 ��'��t�� f✓�j� i4 �. � ®� ...,14..,.v.',...':,:.....• /1t7s J+�Off/ • n7wrw a i� ` 6i. Q1 , flu+ ,�rre�i�'rldiScep °;►w�he r/r�M'* 250 500 v41a ��/`�'� /t, L4ya.. Mi4 ea7` �: •.► IN ,IMPL.48wp4 *;ti. i / ALT4041►Olka �=4• t L4: ,� h� �s r., ` ♦.• i 500 750 �Ak I �V 19�;A7 ► 1sy �.at. 3�t R� • - �,.. 750 1000 240 �, . �' 4i »/�120 4�d ,�vo !' tee. .:.r.� , #7, 1000.. .-_. 1250 ��a,`*•N. \I05.�4 , MP449 wp� p� 4 ' .,!•. r->�! '' 1250 1500 �� //r�tOP ��Ii j�e IMPLS0 vtp 240 % • ,4 210 _..„,0,,00.1 „,..10.-- ,:: • 1'-/_ j..- 150 / �,w..,..'. , • , 120 1500 2000 '��,,00.1 „,. :4 �� 2000 2500 180 II.i141/ 2500 3000 1b'., Q ' 3000 4000 Azimuth from North[°]vs Centre to Cesare Sepantioe[50 odt/m[ na��1&\`d1't6 o.:' 4000 6000 210 ..,,,,q•.: / 150 ��.,, 6000 6000 180 8000 10000 10000 13002 Azimuth from North flys Centre to Centre Separation[200 usft/in] Details:Plan MPL-47 NAD 1927(NADCON CONUS) Alaska Zone 0/ SECTION DETAILS Sec MD Inc 0zi TVD +N/-9 •FJ-W DIe9 TFace VSed Target Ground Level: 16.90 1 3000 Dam 000 3000 0.00 000 090 0.00 0.00 +N/S +E/-W NOANng Easting Latitude Longitude Slot 2 30000 0.o3 090 300.00 0.00 0.00 0.03 0.00 0.00 0.00 0.00 6031641.90 545157.43 70°29.50.316 N 149°3r 50.6003 W 3 60000 3.03 225.00 599.86 -5.55 5.55 1.00 225.00 3.44 4120000 21.30 225.00 1184.34 -93.40 -93.40 300 0.00 57.89 52056.77 63.04 211.08 1807.81 -550.53 -414.03 500 -18.41 385.87 REFERENCE INFORMATION 65769.12 63.04 211.06 3490.68 3385.02 -2121.24 0.03 0.00 2509.59 77441 81 85.00 125.67 4045.02 -4763.30 -1763.01 500 -92.39 3929.40 W Reference:Well Plan MPL-47,True North 67941.61 65.00 125.67 4068.60 -5053.75 -1358.36 000 0.00 433580 Coordinate ( 08120.81 93.91 124.86 4090.30 -5156.99 -1212.37 500 -5.19 448095 Vertical(ND)Reference:Plan MPL47 a 48.90ustt(Nordic 3(16.9 CBE+30.KB)) 106423.64 93.91 124.86 4069.63 3329.68 364.46 000 0.00 472497 Section(VS)Reference:Slot- ,0.00E) 11 6503.56 90.00 125.67 4066.90 3375.79 -899.27 5.00 168.32 4789.80 Measured Depth Reference:Plan MPWL-4 U7 ra 48.90usft(Nordic 3(16.9 CBE+30'NB)) 133002.29 9090 125.67 4066.90 -7999.07 2755.46 0.00 0.00 8460.36 MPL-47 In.,T.vp2 Calculation Method:Minimum Curvature ! • Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan MPL-47-MPL-47 wp3 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design:M Pt L Pad-Plan MPL-47-MPL-47(Well#4)-MPL-47 wp3 Scan Range: 0.00 to 13,002.29 usft.Measured Depth. Scan Radius is 1,497.23 usft.Clearance Factor cutoff Is Unlimited.Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft M Pt I Pad MPL-01-MPL-01-MPL-01 1,600.00 209.94 1,600.00 175.45 1,535.64 8.088 Clearance Factor Pass- MPL-01-MPL-01-MPL-01 1,615.57 209.68 1,615.57 175.45 1,547.51 6.127 Ellipse Separation Pass- MPL-01-MPL-01A-Plan#3 1,600.00 209.94 1,600.00 175.45 1,535.64 6.088 Clearance Factor Pass- MPL-01-MPL-01A-Plan#3 1,615.57 209.68 1,615.57 175.45 1,547.51 6.127 Ellipse Separation Pass- MPL-01-MPL-01A-MPL-01A 1,600.00 209.94 1,600.00 175.45 1,535.64 6.088 Clearance Factor Pass- MPL-01-MPL-01A-MPL-01A 1,615.57 209.68 1,615.57 175.45 1,547.51 6.127 Ellipse Separation Pass- MPL-02-MPL-02-MPL-02 1,682.45 96.36 1,682.45 73.67 1,596.85 4.248 Clearance Factor Pass- MPL-02-MPL-02A-MPL-02A 1,682.45 96.36 1,682.45 73.95 1,596.85 4.301 Clearance Factor Pass- MPL-02-MPL-02AL1-MPL-02AL1 1,682.45 96.36 1,682.45 73.97 1,596.85 4.305 Clearance Factor Pass- MPL-02-MPL-02AL2-MPL-02AL2 1,682.45 96.36 1,682.45 73.67 1,596.85 4.248 Clearance Factor Pass- MPL-02-MPL-02APB1-MPL-02APB1 1,682.45 96.36 1,682.45 73.67 1,596.85 4.248 Clearance Factor Pass- MPL-02-MPL-02APB2-MPL-02APB2 1,682.45 96.36 1,682.45 73.67 1,596.85 4.248 Clearance Factor Pass- MPL-03-MPL-03-MPL-03 1,436.88 342.40 1,436.88 326.29 1,281.00 21.255 Centre Distance Pass- MPL-03-MPL-03-MPL-03 1,475.00 342.92 1,475.00 325.77 1,307.20 19.993 Ellipse Separation Pass- MPL-03-MPL-03-MPL-03 1,625.00 359.33 1,625.00 339.15 1,404.18 17.807 Clearance Factor Pass- MPL-04-MPL-04-MPL-04 1,313.84 159.75 1,313.84 144.98 1,262.67 10.818 Centre Distance Pass- MPL-04-MPL-04-MPL-04 1,325.00 159.92 1,325.00 144.83 1,270.59 10.597 Ellipse Separation Pass- MPL-04-MPL-04-MPL-04 1,425.00 177.61 1,425.00 159.57 1,334.28 9.846 Clearance Factor Pass- MPL-05-MPL-05-MPL-05 1,329.92 39.87 1,329.92 24.00 1,315.83 2.512 Ellipse Separation Pass- MPL-05-MPL-05-MPL-05 1,350.00 41.86 1,350.00 25.14 1,331.24 2.504 Clearance Factor Pass- MPL-06-MPL-06-MPL-06 1,438.38 35.58 1,438.38 16.63 1,419.78 1.878 Clearance Factor Pass- MPL-07-MPL-07-MPL-07 538.09 28.41 538.09 22.96 547.43 5.218 Centre Distance Pass- MPL-07-MPL-07•MPL-07 550.00 28.43 550.00 22.88 559.28 5.118 Ellipse Separation Pass- MPL-07-MPL-07-MPL-07 625.00 30.46 625.00 24.20 633.48 4.865 Clearance Factor Pass- MPL-08-MPL-08-MPL-08 30.00 149.85 30.00 148.93 32.00 164.331 Centre Distance Pass- MPL-08-MPL-08-MPL-08 300.00 151.94 300.00 148.70 300.69 46.871 Ellipse Separation Pass- MPL-08-MPL-08-MPL-08 1,025.00 197.08 1,025.00 186.64 1,011.97 18.884 Clearance Factor Pass- MPL-09-MPL-09-MPL-09 367.64 89.74 367.64 85.85 376.99 23.109 Centre Distance Pass- 26 June,2015-19:08 Page 2 of 7 COMPASS • • Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan MPL-47-MPL-47 wp3 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design:M Pt L Pad-Plan MPL-47-MPL-47(Well#4)-MPL-47 wp3 Scan Range:0.00 to 13,002.29 usft.Measured Depth. Scan Radius Is 1,497.23 usft.Clearance Factor cutoff Is Unlimited.Max Ellipse Separation Is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft MPL-09-MPL-09-MPL-09 550.00 90.57 550.00 85.01 559.34 16.303 Ellipse Separation Pass- MPL-09-MPL-09-MPL-09 875.00 106.75 875.00 97.98 881.70 12.180 Clearance Factor Pass- MPL-09-MPL-09A-MPL-09A 367.64 89.74 367.64 86.16 376.99 25.059 Centre Distance Pass- MPL-09-MPL-09A-MPL-09A 550.00 90.57 550.00 85.31 559.34 17240 Ellipse Separation Pass- MPL-09-MPL-09A-MPL-09A 900.00 109.86 900.00 101.15 906.16 12.613 Clearance Factor Pass- MPL-09-MPL-09APB1-MPL-09APB1 367.64 89.74 367.64 85.85 376.99 23.109 Centre Distance Pass- MPL-09-MPL-09APB1-MPL-09APB1 550.00 90.57 550.00 85.01 559.34 16.303 Ellipse Separation Pass- MPL-09-MPL-09APB1-MPL-09APB1 875.00 106.75 875.00 97.98 881.70 12.180 Clearance Factor Pass- MPL-10-MPL-10-MPL-10 114.92 30.68 114.92 29.25 124.02 21.473 Centre Distance Pass- MPL-10-MPL-10-MPL-10 475.00 31.54 475.00 26.68 484.06 6.492 Ellipse Separation Pass- MPL-10-MPL-10-MPL-10 675.00 36.34 675.00 29.60 683.72 5.390 Clearance Factor Pass- MPL-11-MPL-11-MPL-11 1,102.95 49.89 1,102.95 31.70 1,110.85 2.743 Clearance Factor Pass- MPL-12-MPL-12-MPL-12 1,677.92 94.59 1,677.92 70.96 1,575.69 4.002 Ellipse Separation Pass- MPL-12-MPL-12-MPL-12 1,700.00 95.81 1,700.00 71.62 1,590.57 3.960 Clearance Factor Pass- MPL-15-MPL-15-MPL-15 1,430.83 218.97 1,430.83 203.43 1,370.76 14.089 Centre Distance Pass- MPL-15-MPL-15-MPL-15 1,450.00 219.44 1,450.00 203.30 1,383.05 13.598 Ellipse Separation Pass- MPL-15-MPL-15-MPL-15 1,525.00 230.59 1,525.00 212.47 1,428.71 12.728 Clearance Factor Pass- MPL-34-MPL-34-MPL-34 1,703.03 195.24 1,703.03 172.53 1,589.75 8.596 Ellipse Separation Pass- MPL-34-MPL-34-MPL-34 1,725.00 195.71 1,725.00 172.82 1,607.28 8.551 Clearance Factor Pass- MPL-35-MPL-35-MPL-35 2,070.64 7829 2,070.64 53.02 1,874.06 3.099 Ellipse Separation Pass- MPL-35-MPL-35-MPL-35 4,825.00 152.92 4,825.00 77.05 4,750.33 2.016 Clearance Factor Pass- MPL-35-MPL-35A-MPL-35A 2,070.64 78.29 2,070.64 53.02 1,874.86 3.099 Ellipse Separation Pass- MPL-35-MPL-35A-MPL-35A 4,825.00 152.92 4,825.00 77.05 4,751.13 2.016 Clearance Factor Pass- MPL-35-MPL-35APB1-MPL-35APB1 2,070.64 7829 2,070.64 53.02 1,874.86 3.099 Ellipse Separation Pass- MPL-35-MPL-35APB1-MPL-35APB1 4,825.00 152.92 4,825.00 77.05 4,751.13 2.016 Clearance Factor Pass- MPL-35-MPL-35APB2-MPL-35APB2 2,070.64 7829 2,070.64 53.02 1,874.86 3.099 Ellipse Separation Pass- MPL-35-MPL-35APB2-MPL-35APB2 4,825.00 152.92 4,825.00 77.05 4,751.13 2.016 Clearance Factor Pass- MPL-35-MPL-35APB3-MPL-35APB3 2,070.64 78.29 2,070.64 53.02 1,874.86 3.099 Ellipse Separation Pass- MPL-35-MPL-35APB3-MPL-35APB3 4,825.00 152.92 4,825.00 77.05 4,751.13 2.016 Clearance Factor Pass- MPL-35-Plan MPL-35B-MPL-35B wp1 2,070.64 78.29 2,070.64 53.20 1,874.06 3.120 Ellipse Separation Pass- 26 June,2015-19:08 Page 3 of 7 COMPASS . • Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan MPL-47-MPL-47 wp3 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design:M Pt L Pad-Plan MPL-47-MPL-47(Well#4)-MPL-47 wp3 Scan Range: 0.00 to 13,002.29 usft Measured Depth. Scan Radius is 1,497.23 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation Is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft MPL-35-Plan MPL-35B-MPL-35B wp1 4,825.00 152.92 4,825.00 77.22 4,750.33 2.020 Clearance Factor Pass- MPL-37-MPL-37-MPL-37 1,708.02 145.66 1,708.02 125.07 1,590.66 7.073 Centre Distance Pass- MPL-37-MPL-37-MPL-37 5,925.00 225.17 5,925.00 83.10 6,097.92 1.585 Ellipse Separation Pass- MPL-37-MPL-37-MPL-37 5,950.00 227.98 5,950.00 84.14 6,120.45 1.585 Clearance Factor Pass- MPL-37-MPL-37A-MPL-37A 1,708.02 145.66 1,708.02 125.06 1,599.86 7.072 Centre Distance Pass- MPL-37-MPL-37A-MPL-37A 5,925.00 225.17 5,925.00 82.82 6,107.12 1.582 Ellipse Separation Pass- MPL-37-MPL-37A-MPL-37A 5,950.00 227.98 5,950.00 83.86 6,129.65 1.582 Clearance Factor Pass- MPL-37-Plan MPL-37B-MPL-37B WP2 1,708.02 145.66 1,708.02 125.28 1,590.66 7.147 Centre Distance Pass- MPL-37-Plan MPL-37B-MPL-37B WP2 5,925.00 225.17 5,925.00 83.17 6,097.92 1.586 Ellipse Separation Pass- MPL-37-Plan MPL-37B-MPL-37B WP2 5,950.00 227.98 5,950.00 84.20 6,120.45 1.586 Clearance Factor Pass- MPL-39-MPL-39-MPL-39 1,855.18 352.62 1,855.18 331.04 1,673.39 16.335 Centre Distance Pass- MPL-39-MPL-39-MPL-39 1,875.00 352.80 1,875.00 330.85 1,688.85 16.071 Ellipse Separation Pass- MPL-39-MPL-39-MPL-39 5,000.00 1,461.17 5,000.00 1,345.54 4,613.78 12.636 Clearance Factor Pass- MPL-40-MPL-40-MPL-40 1,902.35 201.84 1,902.35 182.42 1,688.83 10.394 Centre Distance Pass- MPL-40-MPL-40-MPL-40 1,925.00 202.37 1,925.00 182.30 1,705.28 10.082 Ellipse Separation Pass- MPL-40-MPL-40-MPL-40 2,000.00 212.19 2,000.00 190.30 1,757.70 9.693 Clearance Factor Pass- MPL-42-MPL-42-MPL-42 970.45 104.11 970.45 96.82 980.10 14.271 Centre Distance Pass- MPL-42-MPL-42-MPL-42 1,025.00 104.41 1,025.00 96.64 1,035.60 13.434 Ellipse Separation Pass- MPL-42-MPL-42-MPL-42 1,175.00 110.44 1,175.00 101.53 1,186.78 12.393 Clearance Factor Pass- MPL-45-MPL-45-MPL-45 - - MPL-45-MPL-45-MPL-45 - - Plan MPL-46-MPL-46(Well#2)-MPL-46 wp3 701.34 143.84 701.34 138.68 693.89 27.877 Centre Distance Pass- Plan MPL-46-MPL-46(Well#2)-MPL-46 wp3 725.00 143.92 725.00 138.61 716.18 27.104 Ellipse Separation Pass- Plan MPL-46-MPL-46(Well#2)-MPL-46 wp3 1,500.00 309.80 1,500.00 295.35 1,462.35 21.428 Clearance Factor Pass- Plan MPL-48-MPL-48(Well#3)-MPL-48 wp3 1,064.67 129.77 1,064.67 119.89 1,036.93 13.132 Centre Distance Pass- Plan MPL-48-MPL-48(Well#3)-MPL-48 wp3 1,075.00 129.81 1,075.00 119.81 1,046.16 12.979 Ellipse Separation Pass- Plan MPL-48-MPL-48(Well#3)-MPL-48 wp3 13,002.29 1,030.04 13,002.29 773.18 12,044.66 4.010 Clearance Factor Pass- Plan MPL-49-MPL-49(Well#1)-MPL-49 wp3 676.62 58.53 676.62 52.32 676.38 9.426 Centre Distance Pass- Plan MPL-49-MPL-49(Well#1)-MPL-49 wp3 700.00 58.58 700.00 52.20 699.64 9.194 Ellipse Separation Pass- Plan MPL-49-MPL-49(Well#1)-MPL-49 wp3 825.00 61.75 825.00 54.71 823.00 8.763 Clearance Factor Pass- 26 June,2015-19:08 Page 4 of 7 COMPASS • • Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan MPL-47-MPL-47 wp3 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design:M Pt L Pad-Plan MPL-47-MPL-47(Well#4)-MPL-47 wp3 Scan Range: 0.00 to 13,002.29 usft.Measured Depth. Scan Radius is 1,497.23 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning • Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft Plan MPL-50-MPL-50(well#5)-MPL-50 wp3 374.53 187.80 374.53 184.10 373.23 50.778 Centre Distance Pass- Plan MPL-50-MPL-50(well#5)-MPL-50 wp3 2,425.00 199.11 2,425.00 174.18 2,221.60 7.987 Ellipse Separation Pass- Plan MPL-50-MPL-50(well#5)-MPL-50 wp3 13,002.29 926.58 13,002.29 672.23 13,656.75 3.643 Clearance Factor Pass- Survey tool grogram From To Survey/Plan Survey Tool (usft) (usft) 30.00 1,500.00 MPL-47 wp3 SRG-SS 1,500.00 7,941.81 MPL-47 wp3 MWD+IFR2+MS+sag 7,941.81 13,002.28 MPL-47 wp3 MWD+IFR1+MS+sag Ellipse error terms are correlated across survey tool tie-on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor=Distance Between Profiles/(Distance Between Profiles-Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 26 June,2015- 19:08 Page 5 of 7 COMPASS • • Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan MPL-47-MPL-47 wp3 Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to Plan MPL-47 @ 46.90usft(Nordic 3(16.9 CBE a 30'KB)).Northing and Fasting are relative to Plan MPL-47. Coordinate System is US State Plane 1927(Exact solution),Alaska Zone 04. Central Meridian is-150,00°,Grid Convergence at Surface is:0.35°. c1-MPL-02 MPL-02ALI.NPL-02AL1 VO L-002 V Ladder Plot $ NPL-02,NPL-02APB1 NP2AAPB1VO :- NPL-02,NPL-02APB2,NPL-02APB2VO r r r - -e- MPL-03,MPL-03,MPL-03 V1 1 ,�i I i {r i . (j $ MPL-04,MPL-04,MPL-04V1 4 1 I 111•( I I_"' II 11 t 1 -s- MPL-05,MPL-05,NPL-05 V1 Vj till. �/� -� MPL-06,MPL-06,NPL-06V1 `/ iS, I� I� �� t ,e,_ MPL-07,MPL-07,MPL-07 V1 in ___ ill y g 'if/ -1,- MPL-08,MPL-08,MPL-08 V1 o if;t I4 Al i±'� f - , $ MPL-09,MPL-09,MPL-09 V1 p./d d �, /7•.;:L `i7 It "' l010 ♦E- NPL-09,NPL-09A,MPL-09AV0 `` �/Vri,I��IfirAr4 - I ► /fiI $ NPL-09,NPL-09AP61,NPL-09APB1V0 0) l•Q /., I. . iA /Ir „I $ MPL-10,MPL-10,MPL-10V1 s,fri � l,'.f•. -I I $ MPL-11 MPL-11MPL-11 V1 s�tt, 11^A III / �,�t/ �, /� I„ $ MPL-12,NPL-12,NPL-12V1 ��'at I7 I� I� -�E- MPL-15,MPL-15,MPL-15 V1 U I L, Ib' i_ 0 :7r $ MPL-34,MPL-34,MPL-34V10 IA O 4 E --tt. ,r. .0° 1P71' !'� s;: $ MPL-35,MPL-35,MPL35 V6 �I % i „.:,,,,...0.-pe $ MPL-35 MPL-35A,NPL-35AV12 � y�^� y47 NOW, - -3E- NFL35,NPL-35APB1,NPL-35APB1V5 0) x I .' I ` r!r I -te- NPL-35,NI L-35APB2,NPL35APB2V3 �% w i U 0, ` ,,,,,,' 1 1 NPL35,NPL-35APB3,NPL-35APB3V5 I 0 , r -°.- MPL-35,Plan NPL-35B,NPL-35Bwp1 V0 0 2500 5000 7500 10000 12500 MPL-37,MPL-37,MPL-37 V3 MPL-37,MPL-37A,MPL-37A V1 Measured Depth(2500 usff/in) '-3*- MPL37,Plan MPL37B,NFL37BWP2V19 IVI9...-au,IVMLSAJ,IVYL-, mVJ 26 June,2015- 19:08 Page 6 of 7 COMPASS • • Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan MPL-47-MPL-47 wp3 Clearance Factor Plot: Measured Depth versus Separation(Clearance)Factor -11r-M"L-DZ,IVIPL-72AL1,N1P11-O2{L1 VO 44.•MPL-02,MPL-02AL2,NPL-02AL2 VO e,♦, O„ $MPL-02,NPL-02APBI,NPL-02APB1 VO 10.00- 111111,11111191 , - $MPL-02,MPL-02APB2,MPL-02APB2V0 p1., !a 4f•,� -13-MPL-03,MPL-03,MPL-03 V1 - 111I11 � !� .101 MPL-04,MPL-04,MPL-04 V1 8.75 111•' i % = I ia1 $ MPL-05,MPL-05,MPL-05 V1 `` r kV O -$- MPL-06,MPL-06,MPL-06 V1 750- I c 0 ,4.0 ____ _ __ -hi- MPL-07,MPL-07,MPL-07V1 $ MPL-08,MPL-08,MPL-08V1 N _ V 0 0 -e- MPL-09,MPL-09,MPL-09V1 r✓ 6.25-,' Ili - ------------ 00 -k-- MPL-09,MPL-09A,MPL-09AV0 �,! .4_44- MPL-09,MPL-09APBI,MPL-09APB1V0 LL - %a _ ��`,,` -h-MPL-10, -10,MPL-10V1 0 5.W 411!11 �♦� $MPL-11,MPL-11,MPL-11 V1 • V/ ♦�O, $MPL-12,MPL-12,MPL-12 V1 yam- - ' tl 0♦S �(-MPL-15,MPL-15,MPL-15V1 N 3.75 __ ___. .. - $MPL-34,MPL-34,MPL-34V10 ' -_-MPL35,MPL35,MPL-35V6 250- __ �•.4 _.____ -♦-MPL-35 -35A,MPL-35AV12 - Collision Avoidance Req �F MPL35,NPL-35APB1,MPL35APB1V5 -�� MPL35,NPL35APB2,NPL35APB2V3 1.25 $- MPL35,NPL35APB3,MPL35APB3V5 -+ t ` Y S ? -$ MPL-35,Plan MPL35B,MPL-35B, VO _ -8- MPL-37,MPL37,MPL-37 V3 0.00 Ilii 1 1 1 1 1 1 1 1 1111 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1111 1 $ MPL-37,MPL37A,MPL37AV1 0 1250 2500 3750 5000 6250 7500 8750 10000 11250 12500 13750 15000 -f MPL37,Plan MPL37B,MPL37BWP2 V19 MeaSised Depth(2ra00usft/ln) $ MPL-39,MPL39,MPL-39 V3 26 June,2015-19:08 Page 7 o/7 COMPASS 1 • Schwartz, Guy L (DOA) From: Luke Keller <Ikeller@hilcorp.com> Sent: Tuesday,July 14, 2015 2:04 PM To: Schwartz, Guy L (DOA) Cc: Kevin Eastham Subject: MPU L-47 Anti-collision concerns with L-45 Guy, Let me know if the below spider map and write up makes the geologic certainty anti-collision case for the wells in question. We will monitor the L-45 well and all drilling parameters during this close approach while drilling MPU L-47. Tops were picked using Gamma Ray from drilling the L-45 well. 1 0 • -1,-- a 1 T • y. •i ,, •l,.• �i � ADL35523 1 ADL025504 1,•t o ADL047434 . �L! \IPL-47 SHL ,,,s44;.:4 e. � - n� 5, Sec 9 At the apparent �, 1 _ intersection,L-45 is ,4' / justenteringthe upper lobe of the OA H' • sand,L-49 will be r _.r• geo-steering in the bottom lobe at this U013N009E•''' • U013 010E 'M, -47 r, same apparent - — intersection. Wells f j' Q should be approx25' •3 ;' Call/ apartTVD. / f o 7 (/j WPL-47 BHL A01025514 ADL025515 ADL3155411 ,i Legend • AWL 47 SHL ' MPL-47 TPH _.• MPL-47 BHL -- ... Other Surrace HoleS(Stilt "•' • Other Bottom Holes(BHL) - 5', , i- ADL025517 -` • • Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Thursday,July 09, 2015 4:49 PM To: Luke Keller Cc: Bettis, Patricia K(DOA) Subject: L-47 close crossing (PTD 215-116) Luke, Are you doing anything to mitigate the close crossing with L-45 ?(at about 8500'md) Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226)or(Guy.schwartz@alaskagov). 1 • • OVERSIZED DOCUMENT INSERT This file contains one or more oversized documents. These materials may be found in the original hard file or check the parent folder to view it in digital format. • TRANSMITTAL LETTER CHECKLIST WELL NAME: T?L• L L1 PTD: 215-- 1)7- ✓evelopment Service Exploratory _Stratigraphic Test Non-Conventional FIELD: MI IAL -2114— POOL: , . a�T S-11 Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10'sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non-Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a)authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application,the following well logs are also required for this well: Well Logging Requirements /Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, /Per 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 • • ❑ N O a cn - c as, Q , a v t , c, c , o; , 3, ; ; ; ; , , I c o, „ „ fes' C' > ma 0 G C 2 p O = (6 sc O c 3 E c . 3, a: ' a o c co N a c a 0 ` co 04 , , , c o o a , ; a y. •3 c' c c •- C O co' � O O '3 , , .N -0 E. o w ; ; m �,' un N a) a. o, c, a. E 17:' E, o. m o. (U W. a J a '. ` as m w �, >), a, a u oo' m rn aai 2 co H� � LL N C O, c O� .c� a , c0• O N' co 'D ti I-- b'' 0' ; E m ° Z a m' n .N co a o; co, .0'' a��i I-. Lo co p W' 00: QY c � c a, T O 0 c' N � J' - co, .y co', � as �� N a o. ¢ a f4 w a 1:1 3 s (D, �; o ur, v y 3 a o _ CO �_ 0001 ¢, 2. y o' y, •s . ° ¢ r>, y, o. c. 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