Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation
Commission
HOME
EVENTS
DATA
Data List
Drilling
Production
Orders
Data Miner
Document Search
REPORTS
Reports and Charts
Pool Statistics
FORMS
LINKS
Links
Test Notification
Data Requests
Regulations
Industry Guidance Bulletins
How to Apply
ABOUT US
History
Staff
HELP
Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
218-104
1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: ESP Completion Hilcorp Alaska Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 11,315 feet 11,232 feet true vertical 7,468 feet N/A feet Effective Depth measured 11,232 feet N/A feet true vertical 7,390 feet N/A feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5# / L-80 / EUE 10,880' 7,059' Packers and SSSV (type, measured and true vertical depth)N/A NA NA NA 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Chad Helgeson Contact Name: Authorized Title:Operations Manager Contact Email: Contact Phone: WINJ WAG 0 Water-Bbl MD 80' 7,366' 11,291' TVD 80' 289 Oil-Bbl measured true vertical Packer 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 6000 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 218-104 50-029-23611-00-00 Plugs ADL025509, ADL355017 5. Permit to Drill Number: Milne Point Unit/ Kuparuk Oil pool 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-335 393 Authorized Signature with date: Authorized Name: Ian Toomey itoomey@hilcorp.com 140 MPU L-41 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 513 Gas-Mcf 650 Casing Pressure Tubing Pressure 42 N/A measured N/A Casing Conductor Size Junk measured Length 80' 7,366' 11,259' Surface Production N/A 5,750psi 7,240psi 20" 9-5/8" 7" 4,701' 7,445' 777-8434 2. Operator Name Senior Engineer: Senior Res. Engineer: Collapse N/A 3,090psi 5,410psi Burst Form 10-404 Revised 3/2020 Submit Within 30 days of Operations Chad A Helgeson 2020.09.28 13:48:17 -08'00' By Samantha Carlisle at 3:08 pm, Sep 28, 2020 DSR-9/28/2020MGR29SEP2020 RBDMS HEW 9/29/2020 Well Name Rig API Number Well Permit Number Start Date End Date MP L-41 ASR#1 50-029-23611-00-00 218-104 8/27/2020 8/31/2020 8/ 28/ 2020 - Friday Held PJSM and sundry review with crew. Continued MIRU ASR and and ancillary equipment. Final torque on Bop Stack. Spot rig pump and hook up circulating lines. Finished connecting Koomey control lines and fuctioned bop's. Hooked Kill/ Choke lines. Filled pits with 180 bbls of 8.3 Source water. Spotted the Catwalk and contianment. PU BOPE Testing equipment. MU 2-7/8" Test Joint. Filled stack and preformed shell test 250/ 3 000psi. Leak found on flange between annular and Dbl gate rams and on greyloc coming off the choke line. Repaired leaks. Continue to chase leaks found grease fitting leaking had to swap out, still leaking after trouble shooting narrowed down leak to annular element. after discussion with state rep. Rigged up heat trunks to the annular decided to roll on to the rest of the test shell test with out annular test good. Finish with BOPE test as Per sundry 250/ low 3,000/ high on all rams and valves, Annular 250/ low2,500/ high with 1 Fail/ Pass witness by state rep Bob Noble. Lay down BOPE test Equipment, Blow down Stack. Pull Test plug, Stab in BPV, had some pressure under but were able to bleed down and pull BPV. MU landing jnt. BOLDS Un-land TBG 85K of seat, 95k up wt. De-mob TBG hanger BO and LD. fill the IA 7.5Bbls. +- 250' fluid level. Pull #2 ESP cable and 3/8" Cap tube over and tie into spooler. the Lead came off of the Cap Line. had to splice back on. @ 270' out splice on cap line came apart had to splice back together. Cont. POOH/ w ESP on 2-7/8" 6.5# EUE 8rd tbg using continuous hole fill with 8.3# source water @ 9,550'md. 8/ 26/ 2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 8/ 27/ 2020 - Thursday Kill L-41 as per sundry, SITP/ IA/ OA 580/ 580/ 205. MIRU LRS. PT lines 3,000psi.-good test. Started pumping down IA with tbg SI at 5bpm/ 500psi. Pumped away 40bbls and catch pressure slowed rate down to 2bpm/ 1900psi. Continued pumping slowed rate down to 1.25bpm/ 2,000psi after 270bbls cont pumping away a total of 330bbls of 8.3ppg source water w/ 1 drum of BaraKlean dn IA. Swapped lines to the Tbg and PT to 3,000psi. With IA SI Started pumping dn tbg @ 1.25bpm/ 1,950psi. Pumped away Tbg vol of 63bbls of 8.3ppg source water. SD pump montinored well in 1 hr tbg/ IA fell from 1,500psi to 200psi and then started a slow build up. Call out well support to rig up flowback lines to tiger tank to bleed off or circulate well. RU Bleed off line with well support. 425PSI on the tbg, 250 PSI on the IA. Bleed off gas on both sides to monitor well while wait for the Well head suport to arrive with the BPV. While waiting tbg began to flow fluid to return tank. Shut in well while Well Head support gets Lubricator to location. pressure builds up to 87PSI tbg, 204PSI IA. Bleeed off the tbg flow pressure of 18psi. RU Lubricator, set BPV after RD lubricator checked fluid level in the stack well had went on a vac. ND Production tree, Set test plug in BPV and test to 5k test good. NU 11" Speed head, Flow cross, Double gate/ w 2-7/8"-5" VBR's, Annular. spot in the muddboat. Continue with Crane work, set the well hut, workfloor and heaters. lay out the BOPE lines. Spot in the Rig, Pits, and accumulator trailer. Run BOPE lines, RU ASR rig. Held PJSM discussed daily activities. Checked fliuds and servic es equipment. Cont POOH w/ 2-7/ 8' ESP Completions f/ 9,550'md t/ 6,000'md while pumping cont hole fill w/ 8.3ppg SW. Inspecting tbg and clamps while L/ D. Made Reel Swap on Jt 190 (6,000'). Cont POOH w/ 2-7/ 8' ESP Completions f/ 6,000'md to ESP Equipment. while pumping cont hole fill w/ 8.3ppg SW. Inspecting tbg and clamps while L/ D. Did not see any scale or sand on the outside of tbg or equipment. @ Discharge head. Did not have the proper size clamps in the baker box had to run to A-pad to get the right size. Lay Down ESP Equipment. When Breaking down found Heavy scale inside the Pump and little scale on the outside near connections and Flat guards. Pics in Well File. Prep. Load and tally New completion equipment. Swap ESP reels in the spooler, Test Capillary line. Start picking up ESP Equipment 8/ 29/ 2020 - Saturday Well Name Rig API Number Well Permit Number Start Date End Date MP L-41 ASR#1 50-029-23611-00-00 218-104 8/27/2020 8/31/2020 Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. Held PJSM and discussed daily activities. Checked fluids and serviced rig. Finished reel to reel splice and cable check. Splice 13' in on joint # 259. (8,142'). Continued RIH w/ ESP completion clamping every other jt and testing every 2,000'. PU Top GLM DPSOV 1" w/ BK2 Latch @ 205'md. Continued RIH to Hanger depth. MU 2-7/8" Landing Jt and Tbg Hanger. Cable check. Made penetrator splice and terminated cap-string. Made final cable checks and landed ESP completion w/ 35k down. RILDS. LD Landing Jt and Installed BPV. END OF WELL WORK. Start RDMO ARS and equipment. Stage equipment off location for north star rig move. Crane operations, Load out BOPE lines, Load work floor and the well hut. ND BOPE. NU production tree. Test void 500/ low 5,000/ high 5 min test good. Cetrilift did final checks on ESP cable all checks good. 9/ 1/ 2020 - Tuesday 8/ 30/ 2020 - Sunday Held PJSM, Checked fluids and serviced rig. MU and serviced New ESP assembly. While testing 3/8" capstring at 2,000psi found 2 leaks in spool. Called wells foreman and Decided to swap it out with a new spool. Swapped capstring and cont MU ESP assembly. Made final service checks. Swapped out 2 pups above and below the XN-Nipple and swapped out the first 3 2- 7/8" EUE jts in the hole with new Joints due to scale. RIH w/ NEW ESP and 3/8" capstring on 2-7/8" 6.5# L-80 EUE 8rd tbg. PU XN-Nipple on jt #1 and bottom GLM w/ Dummy on jt #3. Cont RIH f/ surface t/ 3,000' clamping cable the first 15 jts then every other jt after. Testing cable the first 1,000' the every 2,000' after. Cont RIH f/ 3,000' to 7,850' clamping cable every other jt. 550'/ hr Testing cable every 2,000'. Conduct a reel swap and cable splice. 8/ 31/ 2020 - Monday _____________________________________________________________________________________ Revised By: TDF 9/28/2020 SCHEMATIC Milne Point Unit Well: MP L-41 Last Completed: 8/31/2020 PTD: 218-104 TD =11,315’(MD) /TD =7,468’ (TVD) 20” Orig. KB Elev.: 33.7’ / GL Elev.: 16.5’ 7” 6 & 7 13 9-5/8” 1 3/8” Capstring MIN ID = 2.205” @ 10,738’ 2 3 13 PBTD =11,232’ (MD) / PBTD =7,390’(TVD) 4 & 5 8 11 ES Cementer @2,508’ ES Cementer @ 10,439’ 9 & 10 12 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 164 / A53B / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835 Surface 7,366’ 0.0758 7” Intermediate 26 / L-80 / TXP 6.276 Surface 11,291’ 0.0383 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE 8rd 2.441 Surface 10,896’ 0.0058 3/8” Capstring Stainless Steel N/A Surface 10,896’ N/A OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" Stg 1 1685 ft3/458 ft3, Stg 2 1937 ft3/314 ft3 9-7/8”x8-1/2” Stg 1 296ft3, Stg 2 191 ft3 WELL INCLINATION DETAIL KOP @ 600’ Max Hole Angle 61.8 deg @ 7299’ MD TREE & WELLHEAD DETAIL Tree 4-1/16” 5M Wellhead 11” 5M FMC Gen V GENERAL WELL INFO API: 50-029-23611-00-00 Drilled and Cased by Doyon 14 – 10/12/2018 ESP Completion by Doyon 14 – 11/14/2018 ESP Changeout and Perforate by ASR 1 – 10/5/2019 ESP Changeout ASR1 – 8-31-2020 JEWELRY DETAIL No. Top MD Item 1205’ST 2: 2-7/8” x 1”GLM BK@ w/DGLV 8-27-20 2 10,649’ST 1: 2-7/8” x 1”GLM BK2 w/Open pocket 8-27-20 3 10,738’ 2-7/8” XN-Nipple –Min ID= 2.205 4 10,790.7’ Discharge Head: 513 PMP B/O 5 10,791’ Zenith Ported Sub: B/O PSI PORT 513/ 538P PMP 6 10,792’ Pump 2: PMP 538PMSXD 161 P11 M FER 7 10,824’ Pump 1: PMP 538PMSXD 161 P11 M FER 8 10,846’ Gas Separator: 538GSTHVV 9 10,851’ Upper Tandem Seal: GSB3DB X UT FER HL SSCV 10 10,858’ Lower Tandem Seal: GSB3DB X LT FER HL SSCV 11 10,865’ Motor: 562XP – 200Hp/ 3,635V / 34A 12 10,876’ Motor Sensor: Zenith 13 10,878’ Centralizer:Bottom @ 10,880’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk B/C 11,000’ 11,005’ 7,172’ 7,176’ 5 3-1/8” 11/5/18 Open Kuparuk A3 11,108’ 11,116’ 7,273’ 7,281’ 8 3-1/8” 10/23/18 0pen Kuparuk A1 11,153’ 11,174’ 7,315’ 7,335’ 21 3-1/8” 10/3/19 0pen 11,166’ 11,187’ 7,328’ 7,347’ 21 3-1/8” 10/3/19 0pen GUN DETAIL:3-1/8” guns, 6 spf, 60 degree phasing with Millennium Charges.Ref Log: 10/16/2018 Pollard Radial / Sector CBL STATE OF ALASKA Reviewed By: J7f�-' OIL AND GAS CONSERVATION COMMISSION P.I. Supry `t l/;rl BOPE Test Report for: MILNE PT UNIT L-41 Comm Contractor/Rig No.: Hilcorp ASR I PTD#: 2181040 DATE: 8/28/2020 Inspector Bob Noble _ Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: Carl Linaman Rig Rep: Matt Beshea Inspector Type Operation: WRKOV Sundry No: Test Pressures: Inspection No: bopRCN200831092652 Type Test: INIT 320-335 Rams: Annular:---- Valves: MASP: - _ - _ - 250/3000 --250/2500 � 250/3000 ' 2363 - Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: Upper Kelly 0 P/F Lower Kelly Visual Alarm Time/Pressure P/F Location Gen.: - P Trip Tank NA - NA System Pressure 3100 P Housekeeping: P Pit Level Indicators P P Pressure After Closure 1900 P PTD On Location P Flow Indicator P P 200 PSI Attained _ _ I I P Standing Order Posted P Meth Gas Detector P P Full Pressure Attained 43 P " Well Sian P H2S Gas Detector P P Blind Switch Covers: all stations P Drl. Rig P- MS Mise NA NA Nitgn. Bottles (avg): 4 (a", 2350 P - Hazard Sec. NA P Inside Reel Valves 0 NA ACC Misc 0 _ NA Misc NA Check Valve 0 none NA FLOOR SAFTY VALVES: BOP STACK: Quantity P/F Upper Kelly 0 NA Lower Kelly 0 NA _ Ball Type I P Inside BOP _ 1 P FSV Misc 0 NA BOP STACK: CHOKE MANIFOLD: Quantity Size P/F Quantity P/F Stripper 0-- none NA No. Valves 16 - P - Annular Preventer l I1" FP Chokes IP_ #1 Rams - 1 2 7/8" x 5" - _ P Hydraulic Chokes 1 P #2 Rams 1 blinds P CH Misc 0 NA #3 Rams -0 none NA #4 Rams 0 none NA #5 Rams - 0 none - NA INSIDE REEL VALVES: #6 Rams 0 none NA (Valid for Coil Rigs Only) Choke Ln. Valves 1 - 2 1/16" P Quantity P/F HCR Valves 1 2 1/16" P Inside Reel Valves 0 NA Kill Line Valves 2 2 1/16", 3 1/8 P Check Valve 0 none NA BOP Misc 0 none NA Number of Failures: 1 - Test Results Test Time 5.8 Remarks: Annular F/P, functioned and heat put on it then passed. I told them to keep heat on it. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ESP Swap 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 11,315'N/A Casing Collapse Conductor N/A Surface 3,090psi Production 5,410psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15.W ell Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name:Ian Toomey Operations Manager Contact Email:itoomey@hilcorp.com Contact Phone: 777-8520 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 See Schematic Perforation Depth TVD (ft): COMMISSION USE ONLY Authorized Name: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025509 & ADL355017 218-104 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 Milne Point Unit/ Kuparuk Oil pool 50-029-23611-00-00 Hilcorp Alaska LLC Length Size 7,468' 11,232' 7,390' C.O. 432D PRESENT WELL CONDITION SUMMARY 2,363 11,232' MPU L-41 80'80' 6.5# / L-80 / EUE8rd TVD Burst 10,896' MD N/A Tubing Size:Tubing Grade: 5,750psi 7,240psi 4,701' 7,445' 7,366' 11,291' Tubing MD (ft): 80'20" 9-5/8" 7" 7,366' 11,259' 2-7/8" Perforation Depth MD (ft): N/A and NA N/A and NA Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: See Schematic Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. Sept 2, 2020 By Jody Colombie at 4:03 pm, Aug 13, 2020 320-335 Digitally signed by Chad A Helgeson DN: cn=Chad A Helgeson, c=US, o=Hilcorp Alaska, ou=ANS Operations Manager, email=chelgeson@hilcorp.com Date: 2020.08.13 15:24:21 -08'00' Chad A Helgeson ESP Swap SFD 8/14/2020 pre-rig work 8/27/20 10-404 * gls 8/27/20 3000 psi BOPE test (2500 psi annular) X DSR-8/13/2020 Guy Schwartz Comm. 8/28/2020 dts 8/27/2020 JLC 8/28/2020 RBDMS HEW 8/28/2020 ESP Swap Well: MPU L-41 Date: 08-7-20 Well Name: MPU L-41 API Number: 50-029-23611-00 Current Status: Shut-in ESP Producer Pad: L-Pad Estimated Start Date: September 2nd, 2020 Rig: ASR Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 218-104 First Call Engineer: Ian Toomey (907) 777-8343 (O) (907) 903-3987 (M) Second Call Engineer: David Haakinson (907) 777-8343 (O) (307) 660-4999 (M) AFE Number: Job Type: ESP Swap Current Bottom Hole Pressure: 2,773 psi @ 7,070’ TVD Downhole Gauge: 2-week PBU (8/7/20) | 7.54 PPG Maximum Expected BHP: 3,070 psi @ 7,070’ TVD 30-day PBU Extrapolation | 8.35 PPG MPSP: 2,363 psi Gas Column Gradient (0.1 psi/ft) Max Inclination 62° at 7,299’ MD Max Dogleg: 6°/100ft at 2,016’ MD BPV Profile: 2-1/2” CIW Type H Brief Well Summary: MPU producer L-41 was drilled and completed as a Kuparuk producer in November 2018. The well was completed with a perforation and fracture treatment of the Kuparuk A, and C sands. On 8/3/19, the pump shaft appeared to have twisted and resulted in a shutdown of the producer. A RWO was done in October 2019 and 42’ of perforation were added to the A1 sand. The pump shaft has appeared to have twisted again and resulted in a shutdown on 7/25/20. Notes Regarding Wellbore Condition x The 7” production casing passed an MIT to 2,500 psig on 10/14/18. x CTU FCO completed to 11,220’ CTMD post fracture treatment. Objective: x Pull 2-7/8” ESP completion. x Install new EPS components and re-run pulled 2-7/8” tubing. Pre-Rig Procedure: 1. RU Slickline unit 2. Pull OV from GLM at 198’ and install DV. 3. Pull DV from GLM @ 10,646’ MD. Leave pocket open. 4. RD Slickline Unit 5. RU LRS and PT lines. 6. Pump 1 IA volume (330 bbls) with 8.6 ppg NaCl down IA. 7. Bullhead 63 bbls of 8.6 ppg NaCl down tubing to the formation. 8. Clear and level pad area in front of well. Spot rig mats and containment. 9. RD well house and flowlines. Clear and level area around well. 10. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 MeOH. a. Freeze protect is up to the discretion of the Wellsite Supervisor depending on timing for arrival of the ASR. 11. RD LRS. ESP packer waived per CO 390A gls BHP < 8.55 ppg EMW Verbal approval given for pre-rig work 8/27/20 *(KWF approx 7.6 ppg ) ESP Swap Well: MPU L-41 Date: 08-7-20 12. RU crane. Set 2-1/2” HP BPV. ND Tree. Inspect the lift threads on the tubing hanger. Install the plug off tool into the BPV. 13. NU 11” 5M BOPE with two sets of 2-7/8” x 5” VBR’s. RD Crane. 14. RU BOPE house. Spot mud boat. RWO Procedure: 15. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines to returns tank. 16. Check for pressure and if 0 psi, pull BPV. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well with 8.6 ppg NaCl prior to pulling BPV. 17. Set TWC. 18. Test BOPE to 250/3,000 psi and annular to 250/2,500 psi. a. Notify AOGCC 24 hours in advance of BOP test. b. Perform Test per ASR #1 BOP Test Procedure dated 11/03/2015. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR’s and annular with 2-7/8” test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. Contingency: If BOPE test fails a. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) 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. 19. RU to pull 2-7/8” ESP completion. 20. Pull the plug off tool, check for pressure under the BPV, if needed kill the well with 8.6 ppg NaCl and pull the BPV. 21. MU landing joint or spear. BOLDS, unseat the tubing hanger and pull to the rig floor. a. SO = 32K and PU was not recorded when landed by ASR in 2019 in 8.3 ppg source water. 22. Lay down the landing joint and tubing hanger. RU to pull ESP cable and capillary line over sheaves to spooling units. a. Inspect the tubing hanger and note any corrosion or damage. 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 and sundry. 23. POOH laying down the 2-7/8” tubing spooling ESP cable and removing all jewelry as it presents itself. Lay down ESP components. BOPE test 3000 psi (Due to TWC failure ... hanger seal.) ESP Swap Well: MPU L-41 Date: 08-7-20 a. Note any corrosion, sand, or scale on the tubing with associated depths and ESP components on the morning report. b. If any joints 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 reuse Tubing & Pup joints Visually inspect on site and reuse Gaslift Mandrels/Nipple Visually inspect on site and reuse ESP equipment/Power Cable Centrilift to take possession for inspection and teardown Capillary Tubing Visually inspect on site and reuse Protectorlizer (4) Visually inspect on site and reuse Cannon clamps (352) Visually inspect on site and reuse Flat cable guard (2) Visually inspect on site and reuse Pump clamps (7) Visually inspect on site and reuse 24. PU new ESP and RIH on 2-7/8”, 6.5#, L-80, EUE 8rd tubing. Set base of ESP assembly at ±10,900’ MD. a. Motor centralizer b. Motor gauge unit c. ESP motor d. Lower tandem seal e. Upper tandem seal f. Gas separator g. Pump h. Ported discharge head i. Bolt on discharge head, 2-7/8”, 6.5#, L-80, EUE 8rd box up j. 1 joint, 2-7/8”, 6.5#, L-80, EUE 8rd tubing k. Nipple, HES 2.313” XN (2.205” no-go) with 10’ handling pups above and below l. 2 joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing m. GLM, 2-7/8” x 1”, DV installed with 10’ handling pups above and below n. XXX joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing o. GLM, 2-7/8” x 1”, 0.25” OV installed with 10’ handling pups above and below (setting depth = ±200’ MD) p. XXX joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing 25. PU and MU the new 2-7/8” tubing hanger. Make final splice of the ESP cable to the penetrator, MU the control line to the tubing hanger and dummy off any additional control line ports if present. 26. Land tubing hanger with extreme caution to avoid damaging the ESP cable, penetrator or control line. RILDS. Record PU and SO weights on tally and WellEZ. 27. Set 2-1/2” BPV. ESP Swap Well: MPU L-41 Date: 08-7-20 Post-Rig Procedure: 28. RD mud boat. RD BOPE house. Move to next well location. 29. RU crane. ND BOPE. Install plug off tool 30. NU the tubing head adapter and 2-9/16”, 5M tree. PT tubing hanger void to 500/5000 psi. PT the tree to 250/5000 psi. 31. Pull plug off tool and BPV. 32. RD crane. Move returns tank and rig mats to next well location. 33. Replace gauge(s) if removed. 34. Turn well over to production via handover form. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOP Schematic 4. Blank RWO MOC Form _____________________________________________________________________________________ Revised By: TDF 10/10/2019 SCHEMATIC Milne Point Unit Well: MP L-41 Last Completed: 10/5/2019 PTD: 218-104 TD =11,315’ (MD) /TD =7,468’ (TVD) 20” Orig. KB Elev.: 33.7’ / GL Elev.: 16.5’ 7” 5, 6, 7 & 8 15 9-5/8” 1 3/8” Capstring MIN ID = 2.205” @ 10,735’ 2 3 15 PBTD =11,232’ (MD) / PBTD =7,390’ (TVD) 4 9 & 10 13 ES Cementer @2,508’ ES Cementer @ 10,439’ 11 & 12 14 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 164 / A53B / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835 Surface 7,366’ 0.0758 7” Intermediate 26 / L-80 / TXP 6.276 Surface 11,291’ 0.0383 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE 8rd 2.441 Surface 10,896’ 0.0058 3/8” Capstring Stainless Steel N/A Surface 10,896’ N/A OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" Stg 1 1685 ft3/458 ft3, Stg 2 1937 ft3/314 ft3 9-7/8”x8-1/2” Stg 1 296ft3, Stg 2 191 ft3 WELL INCLINATION DETAIL KOP @ 600’ Max Hole Angle 61.8 deg @ 7299’ MD TREE & WELLHEAD DETAIL Tree 4-1/16” 5M Wellhead 11” 5M FMC Gen V GENERAL WELL INFO API: 50-029-23611-00-00 Drilled and Cased by Doyon 14 – 10/12/2018 ESP Completion by Doyon 14 – 11/14/2018 JEWELRY DETAIL No. Top MD Item 1198’ST 2: 2-7/8” x 1”GLM BK@ w/ 0.25” OV 2 10,646’ST 1: 2-7/8” x 1”GLM BK2 w/ Dummy GLV 3 10,735’ 2-7/8” XN-Nipple –Min ID= 2.205 4 10,786.6’ Discharge Head: 400 PMP Ported 5 10,787’ Pump 4: PMSXD/ 62 FLEX 17.5 6 10,799’ Pump 3: PMSXD/ 134 FLEX 17.5 7 10,822’ Pump 2: PMSXD/ 134 FLEX 17.5 8 10,846’ Pump 1: PMSXD/ 20GINPSHH 9 10,856’ Gas Separator: 538GSTHVV 10 10,861’ Gas Avoider: 538GSTHVV 11 10,864’ Upper Tandem Seal: GSB3DBUT SB/SB PFSA 12 10,871’ Lower Tandem Seal: GSB3DBLT SB/SB PFSA 13 10,878’ Motor: 562XP – 200Hp/ 3,635V / 34A 14 10,892’ Motor Sensor: Zenith 15 10,894’ Centralizer:Bottom @ 10,896’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk B/C 11,000’ 11,005’ 7,172’ 7,176’ 5 3-1/8” 11/5/18 Open Kuparuk A3 11,108’ 11,116’ 7,273’ 7,281’ 8 3-1/8” 10/23/18 0pen Kuparuk A1 11,153’ 11,174’ 7,315’ 7,335’ 21 3-1/8” 10/3/19 0pen 11,166’ 11,187’ 7,328’ 7,347’ 21 3-1/8” 10/3/19 0pen GUN DETAIL:3-1/8” guns, 6 spf, 60 degree phasing with Millennium Charges.Ref Log: 10/16/2018 Pollard Radial / Sector CBL _____________________________________________________________________________________ Revised By: IAT 8/7/2020 Proposed Milne Point Unit Well: MP L-41 Last Completed: 10/5/2019 PTD: 218-104 TD = 11,315’ (MD) / TD = 7,468’ (TVD) 20”00 Ori g. KB Elev.: 33.7’ / GL Elev.: 16.5’ 7” 5, 6, 7 & 8 15 9-5/8”88 1 3/8” Capstring MIN ID = 2.205” @ 10,735’ 2 3 PBTD = 11,232’ (MD) / PBTD = 7,390’ (TVD) 4 9 & 10 13 ES Cementer @2,508’ ES Cementer @ 10,439’ 11 & 12 14 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20"Conductor 164 / A53B / Weld N/A Surface 80’N/A 9-5/8"Surface 40 / L-80 /TXP 8.835 Surface 7,366’0.0758 7”Intermediate 26 / L-80 /TXP 6.276 Surface 11,291’0.0383 TUBING DETAIL 2-7/8"Tubing 6.5 / L-80 / EUE 8rd 2.441 Surface ±10,787’0.0058 3/8”Capstring Stainless Steel N/A Surface ±10,896’N/A OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4"Stg 1 1685 ft3/458 ft3, Stg 2 1937 ft3/314 ft3 9-7/8”x8-1/2”Stg 1 296ft3, Stg 2 191ft3 WELL INCLINATION DETAIL KOP @ 600’ Max Hole Angle 61.8 deg @ 7299’ MD TREE & WELLHEAD DETAIL Tree 4-1/16” 5M Wellhead 11”5M FMC Gen V GENERAL WELL INFO API: 50-029-23611-00-00 Drilled and Cased by Doyon 14 –10/12/2018 ESP Completion by Doyon 14 –11/14/2018 ESP Changeout and Perforate by ASR 1 –10/5/2020 JEWELRY DETAIL No.Top MD Item 1 ±198’ST 2:2-7/8” x 1”GLM BK@ w/ 0.25” OV 2 ±10,646’ST 1: 2-7/8” x 1”GLM BK2 w/ Dummy GLV 3 ±10,735’2-7/8” XN-Nipple –Min ID= 2.205 4 ±10,787’Discharge Head: 5 ±10,794’Upper Pump: 6 ±10,852’Lower Pump: 7 ±10,856’ Gas Separator: 8 ±10,864’ Upper Tandem Seal: 9 ±10,871’Lower Tandem Seal: 10 ±10,878’Motor: 11 ±10,894’Sensor: Bottom @ ±10,900’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk B/C 11,000’11,005’7,172’7,176’5 3-1/8”11/5/18 Open Kuparuk A3 11,108’11,116’7,273’7,281’8 3-1/8”10/23/18 0pen Kuparuk A1 11,153’11,174’7,315’7,335’21 3-1/8”10/3/19 0pen 11,166’11,187’ 7,328’ 7,347’21 3-1/8”10/3/19 0pen GUN DETAIL:3-1/8” guns, 6 spf, 60 degree phasing with Millennium Charges. Ref Log: 10/16/2018 Pollard Radial / Sector CBL 11” BOPE Sh affer 11'’-5000 7" Pipe CIW-U 430'Hydril GK4.30'4.30' 11" - 5000 2-7/8" x 5" VBR B lin d 11'’- 5000 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManual Stripping Head ManualManualManualManual Milne Point ASR 11” BOP w/ Jacks 05/17/2017 Milne Point ASR 11” BOP (Triple) Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Date: August 8, 2020 Subject: Changes to Approved Sundry Procedure for Well MPU L-41 Sundry #: TBD Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change. Step Page Date Procedure Change HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Asset Team Operations Manager Date Prepared: First Call Operations Engineer Date 1 Carlisle, Samantha J (CED) From:Schwartz, Guy L (CED) Sent:Thursday, August 27, 2020 12:05 PM To:Ian Toomey - (C) Cc:Melvin G Rixse (DOA) (melvin.rixse@alaska.gov) Subject:RE: L-41 sundry (PTD 218-104) Ian, YouhaveverbalapprovaltorigupBOPEsonLͲ41anddotheotherpreͲrigworkstepsasoutlinedinthesundry application. Note:Youmusthaveanapprovedsundrytopullthetubing/ESP. GuySchwartz Sr.PetroleumEngineer AOGCC 907Ͳ301Ͳ4533cell 907Ͳ793Ͳ1226office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). From:IanToomeyͲ(C)<itoomey@hilcorp.com> Sent:Thursday,August27,20209:09AM To:Schwartz,GuyL(CED)<guy.schwartz@alaska.gov> Subject:LͲ41sundry Guy, WewerescheduledbargeouttoNorthStarbutweatherisnotcooperatingandisnotlookinggoodforthenext4 days.ThereforewearelookingtogodotheESPswaponLͲ41whilewaitingfortheweathertoimprove.Iamjust wonderingthestatusonthesubmittedsundry. Regards, IanToomey|OperationsEngineer HilcorpAlaska,LLC|MilnePoint Office:907Ͳ777Ͳ8520 Cell:907Ͳ903Ͳ3987 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Ll Plug Perforations LJ Fracture Stimulate LJ Pull Tubing Operations shutdown Li Performed: Suspend ❑ Perforate ❑ Other Stimulate❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ Biforate New Pool ❑ Repair Well❑ Re-enter Susp Well ❑ Other: ESP Completion Q 2. Operator Hilcorp Alaska LLC 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development ❑r Exploratory ❑ 218-104 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, Stratigraphic❑ Service ❑ 6. API Number: AK 99503 50-029-23611-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADI -025509, ADL355017 MPU L-41 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Milne Point Unit/ Kuparuk Oil pool 11. Present Well Condition Summary: Total Depth measured 11,315 feet Plugs measured 11,232 feet true vertical 7,468 feet Junk measured N/A feet Effective Depth measured 11,232 feet Packer measured N/A feet true vertical 7,390 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 80' 80' N/A N/A Surface 7,366' 9-5/8" 7,366' 4,701' 5,750psi 3,090psi Production 11,259' 7" 11,291' 7,445' 7,240psi 5,410psi 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 / EUE8rd 10,896' 7,074' Packers and SSSV (type, measured and true vertical depth) N/A NA NA NA 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 p Subsequent to operation: 1230 25 179 300 389 14. Attachments (required per -20 AAC 25.070, 25.071, s 29.283) 15. Well Class after work: Daily Report of Well Operations 121 Exploratory❑ Development ❑ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status afterwork: Oil Gas ❑ WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exert 319-391 Authorized Name: Chad Helgeson Contact Name: David Haakinson Authorized Title: Operations Manager Contact Email: dhaakinsonahllcorD.corn Authorized Signature: �` /"7 Date 10/15/2019 Contact Phone: 777-8343 s�BDMS l�s.✓pCT 161019 Form 10-404 Revised 4/2017 Submit Original Only n llileora Alaska, LLC Orig. KB Elev.: 33.7 / GL Elev.: 16.5' TD= 11,315'(NM)/TD=7,468' (ND) PBTD=11,23Y (MD) /PBTD=7,390' (M) SCHEMATIC Milne Point Unit Well: MP L-41 Last Completed: 10/5/2019 PTD: 218-104 TREE & WELLHEAD DETAIL Tree 4-1/16" SM Wellhead 11" SM FMC Gen V OPEN HOLE/ CEMENT DETAIL tanductor Driven 12-1/4" Stg 11685 ft3/458 ft3, Stg 2 1937 ft3/314 ft3 9-7/8"x8-1/2" Stg 1296ft3, Stg 2191 ft3 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 164/A53B/Weld N/A Surface 80' N/A 9-5/8" Surface 40/L-80/TXP 8.835 Surface 7,366' 0.0758 7" Intermediate 26/L-80/TXP 6.276 Surface 11,291' 0.0383 TUBING DETAIL WELL INCLINATION DETAIL KOP @ 600' Max Hole Angle -61 8 deg @ 7299' MD JEWELRY DETAIL No. Top MD Item 1 198' S7 2: 2-7/8" x .......... w/ 0.25" OV 2 10,646' ST 1: 2-7/8" x 1"GLM BK2 w/ Dummy GLV 3 10,735' 2-7/8"XN-Nipple-Min ID= 2.205 4 10,786.6' Discharge Head: 400 PMP Ported 5 10,787' Pump PMSXD/62 FLEX 17.5 6 10,799' Pump 3: PMSXD/ 134 FLEX 17.5 7 10,822' Pump 2: PMSXD/134 FLE%17.5 8 10,846' Pump 1: PMSXD/20GINPSHH 9 10,856' Gas Separator: 53BGSTHW 10 10,861' Gas Avolder: 538GSTHW it 10,864' Upper Tandem Seal: GSB3DBUT SB/SB PFSA 12 10,871' Lower Tandem Sea): GSB3DBLT SB/SB PFSA 13 10,878' Motor: 562XP- 20OHp/ 3,635V/ 34A 14 10,892' Motor Sensor: Zenith 15 10,894' Centralizer: Bottom @ 10,896' PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT ISize I Date Status Kuparuk B/C 11,000' 11,005' 7,172' 7,176' S 3-1/8" 11/5/18 Open Kuparuk A3 11,108' 11,116' 7,273' 7,281' 8 3-1/8" 10/23/18 Open Kuparuk Al 111153' 11,174' 7,315' 7,335' 21 3-1/8" 10/3/19 Open 11,166' 11,187' 7,328' 7,347' 21 3-1/8" 10/3/19 Open GUN DETAIL: 3-1/8" guns, 6 spf, 60 degree phasing with Millennium Charges. Ref Log: 10/16/2018 Pollard Radial / SMor CBL GENERAL WELL INFO API: 50-029-23611-00-00 Drilled and Cased by Doyon 14-10/12/2018 ESP Completion by Doyon 14 -11/14/2018 Revised By: TDF 10/10/2019 Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP L-41 ASR 50-029-23611-00-00 218-104 9/30/2019 10/5/2019 9/25/2019 - Wednesday No operations to report. 9/26/2019 - Thursday No operations to report. 9/27/2019 - Friday No operations to report. 9/28/2019-Saturday No operations to report. 9/29/2019-Sunday No operations to report. 9/30/2019 - Monday MIRU LRS for well kill. Test lines to 2,300psi for good test. Bleed gas off of well, IA @ 888psi, tbg @ 745psi. No wind so had bleed slowly. End of bleed IA @ Opsi and tbg @ 15psi. Pump 100 bbls source water down tbg @ 5bpm @ Opsi. Swap to IA and pump 167 bkil ajar @ Shnm @ Opsi, well caught fluid and shut dawn pumping @ 550psi on tbg and casing. Pressure and fluid level in well fell off to negativepsi in 30 seconds. Start pumping again @ 3 bpm and caughtpsi @ 200 bbls away. Shut down pumping and well on strong vac. Install well scaffold and install BPV in well. SIMOPS RDMO LRS. MIRU ASR. Spot pits, mudboat, spot well house, floor to be lifted with crane. R&R HCR valves. Continue rigging up and spotting equipment, offloading from Worley trucks, start nipple down tree. Safty MTG, Crew Change. Cont. with crane operations. Pre-test BPV-PLG 2,500psi/15min. check TBG hanger threads are 2-7/8" EUE 8rnd. NU BOPE make up Mud cross valves, place well but and work floor. Load 13-5/8" BOPE and send back to A-Pad. Lay out BOPE lines Cont MIRU ASR Rig. Spot on Mud boat, Stand up rig, set rack pins and rig up work floor. Set stairs, finish torque BOPE up and connecting Bope lines. 10/1/2019-Tuesday Continue R/U ASR rig. Cleaned pits utilizing Super Sucker and Confined space permit, Welded ladder on pits and repaired door on triplex pump house that fell off in move, spotted choke and kill lines, all BOP lines, re-charged pre-charge on Accumulator bottles to 1,OOOpsi, continue prep for BOP test, state to witness. Test BOP's, test 2-3/8 x 3-1/2" VBR's, Annular and all NCR's and Manifold valves to 250psi Low and 2,500psi High as per Sundry. Performed draw down and recovery test on Accumulator for good test. Test Witnessed by Adam Earl for AOGCC. Had a failure on Annulartest after hunting down the leak. Finish the drawdown with state rep. 11 Sec 200PSI recovery 45 Sec Full Recovery. Leak was found on Annular Element. ND Hydril Annular and NU New Cameron Annular. Run Test 6 250Low/250OHigh Test Good. Blow Lines dry, swap out TBG Elevators, Spot in the HPH. Pull Test Pig and BPV TBG on a Vac. IA had 25PSI Bleed off to OPSI - Head Bleed right off. Hang ESP Sheave and Elephant Trunk. Make Up landing JNTwith TIW, BOLDS, Unland and pull free TBG Hanger @ 103K, 93 K 1u/wt. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP L-41 ASR 50-029-23611-00-00 218-104 9/30/2019 10/5/2019 10/2/2019 - Wednesday Crew swap and morning safety meeting, daily plan forward. Break-out and lay down hanger, make de -terminations and thread cap string and power cable through sheaves and elephant trunk and start spooling ropes. Pump 50 bbls source water down backside. well static. Start POOH w/ 2-7/8", 6.5#, EUE tubing. Spooling power cable and cap string. Unclamping clamps, making repairs to level wind on spooling unit. Able to keep running- pumping double displacement for tubing coming out of well. well static. Spooling unit level wind on power cable malfunctioning. Contact VMS and swap out lock ring with new larger lock ring for pin that rides the groove on level wind. Test for good and start POOH. 90 joints out of hole - 246 remaining. Continue POOH w/ 2-7/8 6.5# EUE tubing, pulling clamps and spooling power cable and cap string. 155 Jnts out of the hole. Pumping Double Displacement. Safety MTG, Service and inspect rig and equipment. Continue POOH w/ 2-7/8 6.5# EUE tubing, pulling clamps and spooling power cable and cap string 750ft/hr. Total of 336 Jnts out of the hole. Contact Well support to inspect and load Dummy and Orifice valve in GLM. Conduct Well control while POOH/ESP Shut in Time 1Min 30Sec. Lay down ESP Pump and motors. 10/3/2019 -Thursday Continue and complete last down last pump section. Morning safety meeting and daily plan forward. MIRU a -line. M/U shooting flange, M/U and P/U lubricator, pack -off and sheaves. P/U G/R and CCL Tool with 6' 1.75" weight bar and RIH an tag fill @ 11,187' (correlated depth) log up and pull strip to 10,650'. Send town for verification. Correlation approved. P/U and RIH with 22' 3-1/8" gun assembly, 6 shots per foot with 60 degree phasing. 25 gram JRC Millenium charges. RIH and tag up @ 11,188' (correlated depth). Log up to 10,650' and send log to town. Pump 5bpm with rig pump and break circulation fill hole w/ source water- Log approved and perforate well from 11,166' to 11,187'. Pump 10 bbls every 5 mins to keep hole fill and POOH. Guns on surface all shots fired. P/U second gun assembly identical to run #1. All tools and measurements same. All charges and phasing same. RIH and correlate w/ G/R CCL. RIH and tag up @ 11,160' adding 28' gun length gives depth of 11,188' to tag fill. same as first run. Pull log to 10,600' on depth and call town. RIH to 11,146.5' adding in 6.5' to top shot gives top shot @ 11,153' btm shot @ 11,174'. Pumping source water down well @ 5bpm to attempt circulation with no success. approval from town to shoot. Good indication guns fired. Continue pumping 5bpm for 15 mins and slow to 3bpm. POOH w/ wireline. Top shot @ 11,153' and btm shot @ 11,174' . Log up 400' after shooting and on depth. Continue pumping 3 bpm source while POOH wireline. No flow on well. Start RDMO E -Line. Safety MTG, Service rig and equipment. After getting the guns on the ground verified that all shots were fired. NO Firing Head and NU Spacer spool. Prep to Pick up New ESP Equipment. Do a reel swap With New Cable in spooler. Pick up and service ESP Pump and Motors( Zenith Motor Gauge S/N ZTB20924, Motor CL5562XP 200/3635/34_167/3030 S/N 14620914, Lower Tandem Seal S/N 14947994, Upper Tandem Seal S/N 14937316, Gas Avoider 513 HD HS 1"NO_PNT S/N14428132., Gas Separator 538GSTHVV MT H6 FER S/N14811004, ESP #1538PMSXD 020 GINPSHH H H6 S/N14842591, ESP #2PMSXD134 FLEX17.5 H6 FER STD_PNT S/N14607379,P#3S/N14611123,P#4 S/N14500292). Run Final tests on ESP All tests Good, Check All Fluid on Rig and Equipment. Start RIH with 2 7/8" 6.5# EUE 8 Rnd TBG. 10/4/2019 - Friday Morning Safety meeting and daily plan forward. Pumping double displacement every 15 joints or 3-4 bbls every 20 mins depending on pipe movement. RIH w/ ESP assembly, power cable, and 3/8" cap string on 2-7/8" 6.5#, L-80 EUE tubing. Clamping every collar with X -collar clamp. Swap spools and make power cable splice @ 91 joints in the hole . Cable splice 4' in on joint 91. Continue RIH pumping double displacement every 15 joints - Total of 157 JNTS in the hole. Safety Mtg, Crew change. Continue RIH pumping double displacement every 15 joints Testing cable and capillary every 1,000' CC -Clamp every Jnt - 326 jnts total in the hole 550'+ -/Hr. Hilcorp Alaska, LLC Weekly Operations Summary Well Name RigAPI Number Well Permit Number Start Date End Date MP L-41 ASR 50-029-23611-00-00 218-104 9/30/2019 10/5/2019 10/2/2019 - Wednesday 10/5/2019 -Saturday Morning Safety Meeting, Daily Plan Forward, Crew Swaps and Check Fluids. Continue RIH w/ ESP assembly on 2-7/8", 6.5#, L-80 EUE tubing, clamping every collar with X -collar clamp. Currently on joint 346. Prep to Terminate Hanger. Terminate Hanger power cable and cap string, test all connections for goad, land hanger with 37K down, RILDS, INSTALL BPV, Start RDMO ASR -John Deere generator in tool pusher shack lost alternator and water pump - VMS repairing. Prep To Mobilize to J-26. RD workfloor, RD rig, start crane operations, Fly off work floor, ND annular- total load to recover 850 bbls. ND BOPE, NU Wellhead 11" SM FMC Gen V and test Void to 500psi Low/ 5000Psi High, RD Well but stairs, Load HCR lines, Load Well but and floor onto trailer, do Final checks with Baker Rep. Checks all good. 10/6/2019 -Sunday No operations to report. 10/7/2019- Monday No operations to report. 10/8/2019 -Tuesday No operations to report. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk Oil Pool, MPU L-41 Permit to Drill Number: 218-104 Sundry Number: 319-391 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 �.00gcc.o loska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED thiszfday of August, 2019. RBDMS ± / AUG 3 0 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 'A I I APPLICATION FOR SUNDRY APPROVALS 9n AAC 2F 9Rn 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑✓ Other Stimulate ❑ Pull Tubing ❑✓ Change Approved Program ❑ Plug for Reddll ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ESP Complete ❑✓ 2. Operator Name: 4. Current Well Class: • 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development ✓❑ Stratigraphic ❑ Service ❑ e 218-104 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23611-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 432D , Will planned perforations require a spacing exception? Yes ❑ No ❑✓ ' MPU L-41 9. Property Designation (Lease Number): , 10. Field/Pool(s): ADL025509 & ADL355017 Milne Point Unit/ Kuparuk Gil pool it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 11,315' 7,468' 11,232' 7,390' 895 11,232' N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 80' 80' N/A N/A Surface 7,366' 9-5/8" 7,366' 4,701' 5,750psi 3,090psi Production 11,259' 7" 11,291' 7,445' 7,240psi 5,410psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 2-7/8" 6.5# / L-80 / EUESrd 10,553' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A and NA N/A and NA 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: 9/10/2019 v Commencing Operations: OIL ❑✓ ' WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson Contact Name: David Haakinson r Authorized Title: Operations Manager Contact Email: dhaaklnson hit b r .com Contact Phone: 777-8343 Authorized Signature: Date: 8!23/2019 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test Meeichanic�al Integrity Test El Location Clearance El Other: zgoo ?5l, /3 L) /PT3f— RBDMS-IA-/AU6 3 0 2019 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Subsequent Form Required: 16 K O �-I APPROVED BY Approved by:4i—de COMMISSIONER THE COMMISSION Date. I c-, l �j�I�zd S�.z,� ��► ORIGINAL Submit Form and F to -403 Revised 4/2017 Approved application is valid for 12 months from the date of approvaw I / Attachments in Duplicate �/Jr/a 0,A 8 8/2- f4 K Ifil.rp Alaska. LL, ESP Change -Out Well: MPU L-41 Date: 08-23-19 Well Name: MPU L-41 API Number: 50-029-23611-00 Current Status: Shut-in ESP Producer Pad: L -Pad Estimated Start Date: September 12t1, 2019 Rig: ASR Z Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 218-104 First Call Engineer: David Haakinson (907) 777-8343 (0) (307) 660-4999 (M) Second Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) AFE Number: Job Type: ESP Swap Current Bottom Hole Pressure: Maximum Expected BHP: MPSP: Max Inclination Max Dogleg: BPV Profile: 1,336 psi @ 6,749' TVD 1,570 psi @ 6,749' TVD 895 psi 62° @ 7,299' MD 67100ft @ 2,016' MD 2-1/2" CIW Type H Downhole Gauge: 2 -week PBU (8/22/13.8 PPG 30 -day PBU Extrapolation 14.5 PPG Gas Column Gradient (0.1 psi/ft) Pesti Brief Well Summary: /� 7 ct MPU producer L-41 was drilled and completed as a Kuparuk producer in November 2018. The well was completed with a perforation and fracture treatment of the Kuparuk A, and C sands. On 8/3/19, the pump shaft appeared to have twisted and resulted in a shutdown of the producer. A history of hard starts and overdesigned pump running in severeldown-thrust likely resulted in the short ESP run life. Recently, offset well L-05 was converted to water injection and should increase the reservoir pressure for L-41. The new pump design accounts for increased reservoir pressure. Notes Regarding Wellbore Condition • Slick -line tagged the ESP spline at 10,464' MD on 8/5/19. • The 7" production casing passed an MIT to 2,500 psig on 10/14/18. - CTU FCO completed to 11,220' CTMD post fracture treatment. Objective: • Pull 2-7/8" Tubing String, Flex 17.5 ESP, and 300 HP motor. • Perforate the Kuparuk Al Sands • Install new Baker Hughes 200 HP motor, Baker Hughes ESPs, new ESP cable, and re -run pulled 2-7/8" tubing. Pre -Rig Procedure: 1. MIRU Slickline unit a. Pull DV from GLM @ 10,292' MD. Leave pocket open. b. RD Slickline Unit 2. RU LRS and PT lines to 3000 psi. 3. Pump 1 IA volume (332 bbls) with 8.3 ppg source -water down IA. 4. Bullhead 62 bbls of 8.3 ppg source -water down tubing to the formation. 5. Clear and level pad area in front of well. Spot rig mats and containment. 6. RD well house and flowlines. Clear and level area around well. 7. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 McOH. ESP Change -Out Well: MPU L-41 Ilil..m Alaska, Lb Date: 08-23-19 a. Due to the low reservoir pressure, a tubing freeze protect should not be needed. Freeze protect is up to the discretion of the Wellsite Supervisor depending on timing for arrival of the ASR. 8. RD Little Red Services. 9. RU crane. Set BPV. ND Tree. NU BOPE. RD Crane. 10. NU BOPE house. Spot mud boat. Brief RWO Procedure: 11. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines to returns tank. 12. Check for pressure and if 0 psi, pull BPV. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/ 8.3 ppg source -water prior to pulling BPV. 13. Set TWC. 14. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5 -min). Record accumulator pre -charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Perform Test per ASR #1 BOP Test Procedure dated 11/03/2015. C. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 2-7/8" test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 5. Contingency: If BOPE test fails a. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 16. Bleed any pressure off casing to returns tank. Pull TWC. Kill well w/ 8.3 ppg source -water as needed. 17. Rig up spoolers for ESP #2 RD cable and 3/8" capillary string. a. Baker Hughes representative should be onsite for ESP pull. b. ESP cable will be spooled and allowed to decompress and tested for future well. c. 3/8" Capillary string will be re -run. 18. MU landing joint or spear and PU on the tubing hanger. a. The 2018 ASR #1 ESP completion SOF was documented at 29K. Anticipated PU weight is ±68K, assuming no buoyancy. ESP Change -out Well: MPU L-41 f[il..m Alaska, LU Date: 08-23-19 b. If needed, circulate (long or reverse) pill with lubricant, source -water, and/or baraclean pill prior to laying down the tubing hanger. 19. Recover the tubing hanger. Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re -land hanger (or test plug) in tubing head. Test BOPE per standard procedure. a. Evaluate pulled tubing hanger for possible thread damage. If any damage is found, dispose of tubing hanger and contact well head specialist for replacement. 20. POOH and lay down the 2-7/8" tubing. Lay down ESP and motor. a. Keep all tubing, XN Nipple, and GLMs on location to re -run in hole. b. Note any sand, scale, or corrosion on the tubulars and ESP on the morning report. i. Look for over -torqued connections from previous tubing runs. ii. If any joints appear suspect of damage to threads or tubing, send to G&I for disposal and replace with new. c. The old completion has the following amount of clamps/guards/cap-string: i. 338 Cross Collar Cannon Clamps ii. 8 Pump Body Clamps iii. 2 Flat Guards iv. 3 Protectolizers v. ±10,553' of 3/8" capillary tubing 1. Clamp added length to 3/8" capillary string and prepare to re -run. 2. Due to the deepening of the ESP, the 3/8" capillary string will need to be extended. 21. RU E -line to perforate the Al sands. a. PT PCE to 250 psig Low / 2500 psig High b. RIH with GR and CCL for driftand tag i. RIH to 11,220' MD. Pull up -hole to 10,850' MD for correlation run and tie into PEST (Pollard) CBL log dated 10-16-2018. c. RIH with GR, CCL, and 44' of guns. i. Guns are 3-1/8" hollow carrier 6 SPF, 60° phase. ii. Send gun/tool-string worksheet to engineering for review. d. RIH to ±11,220' MD and log up -hole to 10,850' MD for confirmation run. i. Contact Engineer David Haakinson (307-660-4999) and Geologists Radu Girbacea (907- 230-9490) or Kevin Eastham (907-777-8316) prior to perforating. e. RIH to ±11,200' MD and pull up -hole to perforating depth. f. Perforate interval as followed: Zone Sand Top (MD) Bottom (MD) Top (TVD) Bottom (TVD) Length PKuparuk I Al ±11,153 ±11,197' ±7,315' ±7,357' +44' g. POOH and LD perforating guns. i. Document condition of fired guns including any damage or un -fired charges. h. RD E -line n IliI.P Almkx. LU ESP Change -Out Well: MPU L-41 Date: 08-23-19 22. Call out for additional ±10 joints of new 2-7/8" tubing to be moved to location. The new ESP completion will be set deeper than pulled ESP. 23. PU new ESP and RIH on 2-7/8" 6.5# L-80 tubing. Set base of ESP assembly at±10,900' MD. a. Upper 2-7/8"x 1" Side -pocket GLM @ ±200' MD with 0.25" OV b. 2-7/8" tubing c. Lower 2-7/8"x 1" Side -pocket GLM with Dummy GLV d. 2 joints of 2-7/8" tubing e. 2-7/8" XN (2.205" No -Go) Nipple f. 1 joint of 2-7/8" tubing g. Downhole gauge for discharge temperature and pressure. i. Connected with a jumper from the lower sensor. Does not require a separate tech -wire. h. Baker Hughes 330 stage Flex17.5 ESP L Baker Hughes 20 Stage GINPSHH ESP j. Tandem Gas Separator k. 200 HP Baker Hughes 562XP Motor I. Motorgauge m. Base of ESP centralizer @ ±10,900' MD 24. Land tubing hanger. RILDS. Lay down landing joint. Note Pick-up and slack -off weights on tally. 25. Set BPV. Post -Rig Procedure: 26. RD mud boat. RD BOPE house. Move to next well location. 27. RU crane. NO BOPE. 28. NU existing 2-9/16" 5,000# tree. Test tubing hanger void to 500 psi low/5,000 psi high. 29. Pull BPV. 30. RD crane. Move returns tank and rig mats to next well location. 31. Replace gauge(s) if removed. 32. Turn well over to production. RU well house and flowlines. Attachments: 1. As -built Schematic 2. Proposed Schematic 3. BOP Schematic 4. Blank RWO MOC Form u ffilm,p Almka, LLC Orig. IB EILv.: 33.7 /GL Bev.: 16.5' To= 11,315' (NID) /TD= 7,468' (TVD) PBM=11,232'(NID)/ PBTD=7,39(Y MO) Milne Point Unit Well: MP L-41 SCHEMATIC Last Completed: 11/14/2018 PTD: 218-104 TREE & WELLHEAD DETAIL Tree I 4-1/16"5M Wellhead I11" SM FMC Sen V OPEN HOLE /CEMENT DETAIL Conductor Driven 12-1/4" St 11685 ft3/458 113, Stg 2 1937 ft3/314 113 9-7/8"x8-1/2" Stg 1296ft3, Stg 2191 ft3 CASING DETAIL Size Type Wt/Grade/Conn ID Top ST 2: 2-7/8" GLM DPSOV- 1" w/ BK2 Latch BPF 20" Conductor 164/A53B/Weld N/A Surface Fj N/A 9-5/8" Surface 40/L-80/7XP 8.835 Surface 0.0758 7" Intermediate 26/L-80/TXP 6.276 Surface I 11,290' 0.0383 TUBING DETAIL ji2-7/8" Tubing 6.5/L-80/EUE Brd 2.441 Surface 10,553' 3/8" Capstr4ng Stainless Steel N/A Surface 10,553' WELL INCLINATION DETAIL FKOP @ 600 Max Hole Angle 61.8 deg @ 7299' MD JEWELRY DETAIL No. Top MD Item 1 135' ST 2: 2-7/8" GLM DPSOV- 1" w/ BK2 Latch 2 10,292' ST 1: 2-7/8" GLM w/ Dummy 1" valve- BK2- Latch 3 10,412' 2-7/8"XN-Nipple—Min ID= 2.205 4 10,464' Discharge Head: FPDIS 400 5 10,465' Upper Pump: SXD FLEX 17.5 6 10,488' Lower Pump: SXD FLEX 17.5 7 10,512' Gas Separator: GRS FER N AR 8 10,515' Upper Tandem Seal: GSB3DBUT SB/SB PFSA 9 30,522' Lower Tandem Seal: GSB3DBUT SB/SB PFSA 10 10,529' Motor: XP—RERATED 202HP/ 1,893V/ 65A 11 10,549' 1 Sensor: PHEONIX XT -150 & Centralizer — Bottom @ 10,553' PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk B/C 11,000' 11,005' 7,172' 7,176' S 3-1/8" 11/5/18 Open Kuparuk A3 11,108' 11,116' 7,273' 7,281' 8 3-1/8" 10/23/18 0 en Ref Log: 10/16/2018 Pollard Radial /sector CBL GENERAL WELL INFO API: 50 -029 -23611 -00 -GO Drilled and Cased by Doyon 14 — 10/12/2018 ESP Completion by Doyon 14 —11/14/2018 Revised By: TDF 11/27/2018 3/8' n Ifileom Alaska. LLC Orig. KB Flee.: 33.7 / GL Elea.: 16.5' 7' ES Cementer @2,508 7&8 9820 ES Cerrenter @10,4391 TD=11,315' (MD)/TD=7,468' (TVD) PB1D=11,237 (MD) / P8TD=7,390' (IW) PROPOSED Milne Point Unit Well: MP L-41 Last Completed: 11/14/2018 PTD: 218-104 TREE & WELLHEAD DETAIL Tree 1 4-1/16" 5M Wellhead 1 11" 5M FMC Gen V OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" Stg 11685 ft3/458 ft3, Stg 2 1937 ft3/314 ft3 9-7/8"x8-1/2" I Stg 1296ft3, Stg 2191 ft3 CASING DETAIL Size Type Wt/Grade/Conn ID TopM11290' ST 2:2-7/8" x 1"GLM w/ 0.25" OV BPF 20" Conductor 164/A53B/Weld N/A SurfaN/A 4 ±10,791' 9-5/8" Surface 40 / L-80 / TXP 8.835 Surfa0.0758 ±10,852' Lower Pump: 7" Intermediate 26/L-80/TXP 6.276 Surfa0.0383 Upper Tandem Seal: 9 TUBING DETAIL 2-7/8" Tubing 6.5/L-80/ELIE 8rd 2.441 Surface ±10,900' 3/8" Capstr4ng 1 N/A Surface ji ±10,900' WELL INCLINATION DETAIL KOP @ 600' Max Hole Angle 61.8 deg @ 7299' MD JEWELRY DETAIL No. Top MD Item 1 ±200' ST 2:2-7/8" x 1"GLM w/ 0.25" OV 2 ±10,670' ST 1: 2-7/8" x 1"GLM w/ Dummy GLV 3 ±10,750' 2-7/8"XN-Nipple—Min ID= 2.205 4 ±10,791' Discharge Head: 5 ±10,794' Upper Pump: 6 ±10,852' Lower Pump: 7 ±10,861' Gas Separator: 8 ±10,870' Upper Tandem Seal: 9 ±10,877' Lower Tandem Seal: 10 ±10,884' Motor: 11 ±10,898' Sensor: Bottom @ ±30,900' PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk B/C 11,000' 11,005' 7,172' 7,176' S 3-1/8" li/5/38 Open Kuparuk A3 11,108' 11,116' 7,273' 7,281' 8 3-1/8" 10/23/18 Open Kuparuk Al ±11,153' ±11,197' ±7,315' 1 ±7,357 1 48 1 3-1/8" Future I Future GENERAL WELL INFO API: 50-029-23611-00-00 Drilled and Cad by Doyon 14-10/12/2018 ESP Completionseby Doyon 14 —11/14/2018 Revised By: DAH 08/23/2019 Milne Point ASR Rig 1 BOPE 2019 11" BOPE Updated 1/05/2018 t-7/8" x 5" VBR ind es UHilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Date: August 23rd, 2019 Subject: Changes to Approved Sundry Procedure for Well MPU L-41 Sundry M XXX -XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first call' engineer. AOGCC written approval of the change is required before implementing the change. HAK Step Page Date Procedure Change Prepared B Initials HAK Approved B Initials AOGCC Written Approval Received Person and Date Approval: Prepared: operations manager Date operations engineer Date DATA SUBMITTAL COMPLIANCE REPORT 2/28/2019 Permit to Drill 2181040 Well Name/No. MILNE PT UNIT L-41 O �2 �1 1 1/ L Operator HILCORP ALASKA LLC API No. 50-029-23611-00-00 MD 11315 TVD 7468 Completion Date 11/14/2018 Completion Status 1-0I1 Current Status 1 -OIL UIC No REQUIRED INFORMATION - — - _ Mud Log No ✓ Samples No ✓ Directional Survey Yes y DATA INFORMATION List of Logs Obtained: ROP ABG DGR EWR-Phase 4 MD/ABG DGR EWR-Phase 4 TVD/ CBL Well Log Information: (from Master Well Data/Logs) Log/ Electr Data Digital Dataset Log Log Run Interval / Type Med/Frtnt Number Name OH Scale Media No Start Sto ED C 29912 Digital Data P CH Received Comments 100 11316 10/29/2018 Electronic D t S ED C 29912 Digital Data a a et, Flename: MPU L-41 DGR -ABG -EWR_LWD Final.las ED C 29912 Digital Data 10/29/2018 Electronic File: MPU L-41 LWD Final MD.cgm ED C 29912 Digital Data 10/29/2018 Electronic File: MPU L-41 LWD Final TVD.ogm 10/29/2018 Electronic File: MPU L-41 - Definitive Survey ED C 29912 Digital Data Report.txt ED C 29912 Digital Data 10/29/2018 Electronic File: MPU L-41 - Definitive Survey.pdf ED C 29912 Digital Data 10/29/2018 Electronic File: MPU L-41 - GIS.txt ED C 29912 Digital Data 70/29/2018 Electronic File: MPU L-41 LWD Final MD.emf ED C 29912 Digital Data 10/29/2018 Electronic File: MPU L-41 LWD Final TVD.emf ED C 29912 Digital Data 10/29/2018 Electronic File: MPU L-41 LWD Final MD.pdf ED C 29912 Digital Data 10/29/2018 Electronic File: MPU L-41 LWD Final TVD.pdf ED C 29912 Digital Data 10/29/2018 Electronic File: MPU L-41 LWD Final MD.tif Log C 29912 Log Header Scans 10/29/2018 Electronic File: MPU L-41 LWD Final TVD.tif 0 0 1981400 PRUDHOE BAY UN PBU 1-2-08A LOG ED CHEADERS 29913 Digital Data 100 11330 10/29/2018 Electronic Data Set, Filename: MPU L-41PB1 ED C 29913 Digital Data DGR_ABG-EWR- ALD-CTN LWD Final.las 10/29/2018 Electronic File: MPU L-41PB1 LWD Final ED C 29913 Digital Data MD.cgm 10/29/2018 Electronic File: MPU L-41PB1 LWD Final ED C 29913 Digital Data TVD.cgm --- 10/29/2018 Electronic File: MPU L-41PB1 - Definitive Survey - -- - _ _- _ Report.tM AOGCC Page 1 of 3 Thursday, February 28, 2019 2 18 104 Bell, Abby E (DOA) 3 0 0 0 From: Guhl, Meredith D (DOA) Sent: Monday, February 25, 2019 3:38 PM To: Bell, Abby E (DOA) Subject: FW: [EXTERNAL] MPU L-41, PTD 218-104, Frac Focus digital needed Attachments: Hilcorp MPL-41 Kuparuk A Frac Treatment Report Oct -29-2018 rev3.pdf, Hilcorp MPL-41 Kuparuk C Frac Treatment 20181107_Rev1.pdf, 50-029-23611-00-00-11292018 20205 PM-4211-Hilcorp Alaska LLC.pdf Hi Abby, Could you please add these to RBDMS and Diglogs? Email will serve as transmittal. No need to print paper copies. I have the well history file in my office. Thanks, Meredith From: Cody Dinger <cdinger@hilcorp.com> Sent: Monday, February 25, 2019 3:33 PM To: Guhl, Meredith D (DOA) <meredith.guhl@alaska.gov> Cc: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Subject: RE: [EXTERNAL] MPU L-41, PTD 218-104, Frac Focus digital needed Hi Meredith, Attached are the MPL-41 frac documents you requested. Thanks, Cody Dinger Hilcorp Alaska, LLC Drilling Technician cdinger@hilcorp.com Direct: 907-777-8389 From: Guhl, Meredith D (DOA)[mailto:meredith.guhl@alaska.govj Sent: Monday, February 25, 2019 3:14 PM To: Cody Dinger <cdinger@hilcorp.com> Cc: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Subject: [EXTERNAL) MPU L-41, PTD 218-104, Frac Focus digital needed Hi Cody, RECEIVE FEB 2 5 2019 AOGG(-. I'm completing the compliance review of MPU L-41, PTD 218-104. A paper Frac Focus, along with two frac reports from Schlumberger were included in the 10-407 packet, but no digital data for either was received. Can you please email me, or if greater than 10MB, submit the frac info on CD for this well? Thank you, STATE OF ALASKA I ALA—.,, w OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS ECEDV v; DEC 0 6 2013 1. Operations Abandon U Plug Perforations Fracture StimulateLi Pull Tubing Li Operations shutdown LJ Performed: Suspend ❑ Perforate ❑r • Other Stimulate❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Wd❑ Re-enter Susp Well ❑ Other: ESP Completion 0 2. Operator 4. Well Class Before Work:5. Permit to Drill Number: Name: Hilcorp Alaska LLC Development Q Stratigraphic❑ Exploratory El218-104 . Service ❑. API Number: 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23611-00-00 ' 7. Property Designation (Lease Number): 8. Well Name and Number: ADL025509, ADL355017 MPU L-41 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): I N/A Milne Point Unit/ Kuparuk Oil pool 11. Present Well Condition Summary: Total Depth measured 11,315 ' feet Plugs measured 11,232 feet true vertical 7,468 ' feet Junk measured N/A feel Effective Depth measured 11,232 feet Packer measured N/A feet true vertical 7,390 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 80' 80' N/A N/A Surface 7,366' 9-5/8" 7,366' 4,701' 5,750psi 3,090psi Production 11,259' 7" 11,291' 7,445' 7,240psi 5,410psi Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 2-7/8" 26 / L-80 / EUE8rd 10,553' 6,751' Packers and SSSV (type, measured and true vertical depth) N/A NA NA NA 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 100 0 Subsequent to operation: 1 534 170 60 240 239 14. Attachments (required Per 20 AAC 25L70, 25.071, s 25.283) 15. Well Class after work: Daily Report of Well Operations ❑� Exploratory❑ Development❑✓ Service ❑ Strafigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Q • Gas ❑ WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SLISP❑ SPLUG 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. rap: Sundry Number or N/A if C.O. 6 t 318-480 c= Authorized Name: Bo York Contact Name: Taylor WellmanT / Authorized Title: Operations Manager Contact Email: twellman(WhllcorA.com Authorized Signature: / Date: 11/28/20108 Contact Phone: 777-8449 FM Form 10-404 Revised 4/2017 RBDMSL& ®EC 1 12018 fly (` � Submit Original Only r' n A:I..n Alaxka. LLC Orig. KB Elev.: 33.7 / GL Elev.: 16.5 SCHEMATIC Milne Point Unit Well: MPL-41 Last Completed: 11/14/2018 PTD: 218-104 TREE & WELLHEAD DETAIL Tree 41/16" SM Wellhead 11" SM FMC Gen V OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" Stg 11685 ft3/458 k3, Stg 21937 ft3/314 ft3 9-7/8"x8-1/2" Stg 1296k3, Stg 2191 k3 rnclnlr 119TAll Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 164/A53B/Weld N/A Surface 80' N/A 9-5/8" Surface 40/L-80/TXP 8.835 Surface 7,366' 0.0758 7" Intermediate 26/L-80/TXP 6.276 Surface 11,291' 0.0383 TUBING U[IAa WELL INCLINATION DETAIL KOP @ 600' Max Hole Angle 61.8 deg @ 7299' MD ICNIFI RY DFTAII No. Top MD Item 1 135' ST 2: 2-7/8" GLM DPSOV- 1" w/ BK2 Latch 2 10,292' ST 1: 2-7/8" GLM w/ Dummy 1" valve- BK2- Latch 3 10,412' 2-7/8"XN-Nipple—Min ID= 2.205 4 10,464' Discharge Head: FPDIS 400 5 10,465' Upper Pump: SXD FLEX 17.5 6 10,488' Lower Pump: SXD FLEX 17.5 7 10,512' Gas Separator: GRS FER N AR 8 10,515' Upper Tandem Seal: GS83DBUT SB/SB PFSA 9 10,522' Lower Tandem Sea': GSB3DBUT SB/..PFSA 30 31 1 10,529' 1 10,549' Motor- XP—P,ERA7ED 202HP/1,893V /65A Sensor: PHEONIX XT-150&Centralizer—Bottom@10,553' PFRFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk B/C 11,000' 11,005' 7,172' 7,176' S 3-1/8" 11/5/18 Open Kuparuk A3 11,108' 11,116' 7,273' 7,281' 8 3-1/8" 10/23/18 Open Ref Log: 10/16/2018 Pollard Radial /Sector CBL r ID12��(t Y TD=11,315 (MD) / TD = 7,4618' (TVD) PBTD =11,237 (MD) / PBFD= 7,390' (ND) GENERAL WELL INFO API: 50-029-23611-00-00 Drilled and Cased by Doyon 14-10/12/2018 ESP Completion by Doyon 14-11/14/2018 Revised By: TDF 11/27/2018 Hilcorp Alaska, LLC Weekly Ffileurp Alaska, LLC Operations Summary Well Name Rig API Number Well Permit Number I Start Date End Date MP L-41 E -line 50-029-23611-00-00 218-104 1 10/18/2018 11/14/2018 Daily Operations: 10/17/18- Wednesday No Operations to Report. 10/18/18 - Thursday '**WELL S/I ON ARRIVAL, NOTIFY PAD -OP, PT PCE 250L/2,500H**. PULL BALL & ROD FROM RHC PLUG BODY @ 10,757' SLM. PULL RHC PLUG BODY FROM X -NIPPLE @ 10,761' SLM / 10,765' MD, RECOVER ALL PACKING. DRIFT TBG FREELY W/ 12'x 3.40"" DUMMY GUN & S/D @ 11,228' SUM / 11,2321 MD P U CLEAN OFF BTM W 1,0004 P U. **JOB COMPLETE NOTIFY PAD -OP UPON DEPARTURE**" . 10/19/18 - Friday No Operations to Report. 10/20/18 -Saturday No Operations to Report. 10/21/18 -Sunday No Operations to Report. 10/22/18 - Monday No Operations to Report. 10/23/18 -Tuesday MIRU Alaska Eli ne Service Perforated Ku paruk A sands from 11,108-11,116'. Corrected to CBL. Guns are 3-1/8" 6 spf, 60 deg phasing, Geo Dynamic 22.7 g charges, Razor, EHD 0.42", Penetration 46.01". Log strip from TD. 11,227' through the tubing tail and packer. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date IMP L-41 Frac/Coil 50-029-23611-00-00 218-104 10/18/2018 11/14/2018 Daily Operations. 10/24/2018- Wednesday No activity to report. 10/25/2018 - Thursday No activity to report. 10/26/2018 - Friday No activity to report. 10/27/2018 -Saturday No activity to report. 10/28/2018 -Sunday RIG up frac Equipment. Safety meeting and operational meeting PT Treating Iron Low 300 psi and High 8,000 PSI Pump Data Frac using 30 # Linear Gel at 30 bpm. Analyize tata redesign sand ramp for Frac. Pump Propped Frac using 16/20 Resin Coated proppant. 35# crosslinked gel. at 25 bpm. Average pressure about 3,200 psi. Placed a roc 105,233# of proppant into formation. Slowed back diesel for Forced Closure procedure. RD frac Equipment and tree saver. Prep for FCO. 10/29/2018 - Monday No activity to report. 10/30/2018 -Tuesday MIRU CTU #6 with 13,780' of 2" coil. Perform BOP Test to 300 psi low and 3,500 psi high. Tested Stripper, 2 x Blind/Shear Rams, Slips, pipe rams, Choke valve, Kill valve, Check valve, 6 valves on choke manifold, and accumulator system. Assist in rigging up well test separator. RIH to 2,500' and circulate in freeze protect. Ice packing off in lubricator when attempting to POH. Unable to move coil. Circulate 85 degree 1% KCL from 2,200' until coil moves freely. Freeze protect from 2,500' to surface. SDFN. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP L-41 Frac/Coil 50-029-23611-00-00 218-104 10/18/2018 11/14/2018 Daily Operations. 10/31/2018- Wednesday CTU #6 w/ 2" coil. On location Stab onto well. P/T to 300psi/4,OOOpsi high. Bleed off to 2,OOOpsi and test check. All good tests. Open well. WHP = Opsi. RIH while circulating 1% KCL at 2 BPM at 1,300psi. At 2,500' reduce rate to 1 BPM. Weight check at 4,000' is 12,000 -lbs up and 5,000 -lbs down. Weight check at 9,000' is 28,000 -lbs up and 8,000 -lbs down. Dry tagged TOS at 10,767'. 36,000 -Ib pick up weight. 1:1 returns. Send gel sweep. Increase pump rate to 2.5 BPM. Gel at nozzle. Cleanout from 10,767' to 10,950'. P/U from 10,950' and perform wiper trip to inside tubing. RBIH to 10,950' and cleanout to 11,050'. P/U from 11,050' and perform wiper trip to inside tubing. Send gel sweep. RBIH to 11,050' and cleanout to PBTD at 11,245' ctmd. POH and perform wiper trip into tubing. Send final gel sweep. RBIH to PBTD to 11,245'. POH and chase final gel sweep to surface. See large amounts of proppant return in final gel sweep. Returns c. eared up 200' from surface. At surface, close gate valve above pump in sub and attempt to flow well through test separator. Well will not flow. Call for N2. Soonest arrival is tomorrow morning at 6am. RIH to freeze protect w/60/40 to 2,500'. POH to surface. At surface. FP surface lines and tree. Secure well. Stand back injector. SDFN and wait for N2. 11/1/2018 - Thursday On Location. Stab onto well. P/T to 300psi and 4,OOOpsi high. Bleed off to 2,OOOpsi and test check valve. Open well. WHP is Opsi. RIH to 500'. Cool down N2. P/T N2 lines to S,OOOpsi. Bring N2 online at 500 scf/min and continue to RIH. Stop at 2,900' and unload fluid column. Continue RIH while circulating N2 at 500 scf/min. Stop at 4,500' and unload fluid column. Continue RIH while circulating N2 at 500 scf/min. Stop at 6,500' and unload fluid column. Continue RIH while circulating N2 at 500 scf/min. Stop at 8,080' and unload fluid column. Continue RIH while circulating N2 at 500 scf/min. Continue RIH while circulating N2 at 500 scf/min. 225 bbls flowed back at 12:10 pm . Stop at 10,880' and unload fluid column. P/U weight is 33k - lbs. Divert flow to test separator. 355 bbls flowed back. Sample was 31% WC with trace solids. Flow well while lifting from tubing tail at 10,850'. WC is varying from 20% to 2%. Solids are 0.1% to 0. Rate is varying from 700 BPD to 400 BPD when well is being assisted with N2 at 750 scf/min. POH to surface while continuing to flow well with 750 scf/min of N2. 425 bbls flowed back at 20:00. At surface. Blow down lines and test separator with N2. Secure well Stand back injector. SDFN. 11/2/2018 - Friday On Location. Stab onto well. P/T to 300psi and 4,OOOpsi high. Bleed off to 2,OOOpsi and test check valve. Open well. WHP is 900psi. Bleed off N2 cap to flowback tank. RIH to tag PBTD. Tag at 11,014'. Repeat tag of 11,014'. Pressure up to 500psi on WHP with choke closed. WHP bled from 500 to 350psi over 5 minutes. Tag TOS at 11,005'. Tag TOS at 11,000'. Tag TOS 11,000'. POH to surface. At surface, close swab. Stand back injector. Break and L/D BHA. M/U Nipple Locator dressed to 2,300 lbs in 3.725". RIH w/ nipple locator. P/U with locator and locate XN at 10,772'. 12' correction needed. RIH and tag TOS at 10,988' (10,976'). At surface, close swab. Stand back injector. Break and L/D BHA. SDFN Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig AN Number Well Permit Number Start Date End Date MP L-41 Frac/Coil 50-029-23611-00-00 218-104 10/18/2018 11/14/2018 Daily Operations. 11/3/2018 -Saturday On location. Stab onto well. P/T to 300psi and 4,OOOpsi high. Bleed off to 2,OOOpsi and test check valve. Open well. WHP is 145psi. RIH to to 10,850'. Circulate 1% KCL while RIH. Stop at flag. Correct depth to 10,759'. P/U weight is 35k -lbs. Stop circulating. Tag TOS at 10,976'. P/U to 10,850'. Circulate and fluid pack wellbore with 125 bbls of 1% KCL. Well is static. RIH and tag top of sand at 10,976'. Circulate 8 bbls NVis gel, 30 bbls KCI, 8 bbls gel, 30 bbls KCL, and 12 bbls gel. Cleanout to 11,085'. Chase final gel sweep to surface while circulating 2.8 BPM. At surface. L/D SJN and M/U Pig Jet Nozzle. Stab onto well. P/T to 300psi and 4,OOOpsi high. RIH w/ pig jet nozzle. Tag TOS at 10,986'. Pressure up to 1,500psi. Bled off to 200psi in 3 minutes. Pressure up again to 1,500psi. Bled off to 200psi in 3 minutes. POH to surface. At surface. Secure well. Stand back injector. SDFN. 11/4/2018 -Sunday CTU #6: On location. M/U BHA: 3.07" CTC, 3.12" DBPV, 3.13" Jar, 3.11" Disconnect, 3.13" DCV (5/8" ball), 3.12" Xtreme Motor, 3.62" DB Underreamer, 3.7" Junk Mill. Stab onto well. P/T to 300psi and 4,OOOpsi high. Bleed off to 2,OOOpsi and test check valve. Open well. WHIP is Opsi. RIH and circulate out 60/40 McOH at 0.3 BPM while RIH. Stop at flag. Correct depth to 10,769'. P/U weight is 34k -lbs. Dry tag TOS at 10,976'. Pump 10 bbls of 50# gel. Begin underreaming from 10,976' to 11,030'. POH to 10,950'. Pump 10 bbls of 50# gel. RIH and begin underreaming from 11,030'11,085'. Pump 12 bbls of 50 # gel. Drop ball to open circ sub. POH to 10,950. RBIH to 11,085' with gel sweep at nozzle. Chase gel sweeps to surface. POH. Ball hit. Increase rate to 3.S BPM. POH to surface. L/D Underreamer and MU Pig Jet Nozzle. Stab onto well. P/T to 300psi and 4,OOOpsi high. RIH and tag TOS at 11,067'. R/U LRS for diesel. Begin Batch mixing cement. Pump 5 bbls fresh water. Pump cement through the micromotion and out to the flowback tank with contaminent until 15.8 ppg is seen at the micro motion. Load first pig. Pump 0.9 bbl of 15.8 ppg cement. Load pig with ball. Pump 5 bbls fresh water. Switch to LRS and pump 31.5 bbls of diesel Lay in 1 bbl of cement from 11067' Cement: 7 hours to get to 1000psi comp. strength. POH to 2,500'. Freeze protect well w/ diesel from 2,500'. At surface. Secure well. RDMO. 11/5/2018 - Monday Alaska E -Line arrive at Milne. Hold pre -job meeting. Clear frac equip from around well. Snow removal. MIRU E -Line. MU wt bar, 3.125" OD CCL, 2.5" OD junk basket with 3.60" gauge ring for drift run. Stab on well. PT with triplex to 300psi / 3,OOOpsi. T/I/O = 0/0/0. RIH. Tag PBTD. Log up, correlate to get on depth and find PBTD depth at 11,052' MD. No restrictions encountered. POOH. OOH. Close SV, BD, and pop off. L/D drift tools. MU and arm 3.125" OD x 5' pert gun loaded with 22.7 gm Frac IQ charges - 6 SPF - 60 degree phasing. CCL to top shot = 8.75';RIH with GR/CCL and S' pert gun. Tag PBTD. Make correlation pass. Tie into Halliburton MWD log dated 11 -Oct -2018. Tie in approved by Radu. Pull into shooting depth with CCL at 10,991.25' with top shot at 11,000'/ bottom shot at 11,005' MD. Fire gun, log off and POOH.;OOH. Close SV, BD and pop off well. L/D spent gun, ASF. RDMO. Job Complete. M Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig AN Number Well Permit Number Start Date End Date MP L-41 Frac / Coil 50-029-23611-00-00 218-104 10/18/2018 1 11/14/2018 Daily Operations. 11/6/2018-Tuesday PJSM with Oilstates tree saver hand, Wells Support, and crane operator. Discuss procedure for setting the tree saver and hazards. Set OilStates tree Saver. Stroke cup mandrel down into tubing - cup mandrel dressed with cups for 4-1/2" 26# tubing. No restrictions encountered while stroking the tool down. SLB frac crew on site at 0800. Wells Support spot frac support tanks near well and hookup tattle tail bleed line from companion valve. Frac crew spot missile trailer, RU pumps, hardline to tree saver, and all bleedoff lines. All frac tanks loaded with 110 degree Fresh Water. 2,175 bbls on site. SLB took water samples back to lab for final fluid testing. Spot POD blender and additional blender side equipment. LRS load diesel trailer used for flush with 85 bbls 90 degree diesel. RU complete - Ready for Frac tomorrow. Hilcorp Alaska, LLC Weekly Operations Summary Well Name TRig API Number Well Permit Number Start Date End Date MP L-41 Frac / Coil 50-029-23611-00-00 218-104 10/18/2018 11/14/2018 Daily Operations. 11/7/2018- Wednesday SLB Frac crew on site. PJSM. Fire up equip. Check comms with all equip. Spot support equip (vac trucks), perform final fluid testing, prime up pumps and PT hard line to 300psi / B4OOOpsi - good test. LRS : Assist Frac held backside preesure of 2,500psi, bled IA down to 0psi for Frac stimulation. Hold PJSM with all - 21 people head count. / Co Rep with rig attend/ held meeting with Pad Op earlier/ Discuss muster areas, emergency numbers, hazards and mitigation's, roles and responsibilities, job procedure. Put 2,500psi on backside with LRS pump and maintain 2500-,3000psi throughout pumping. 5.2 bbls diesel used. Annulus pop-offs set at 3,400psi and 3,200psi. Manual valve on Tree Saver froze- apply heat until fully functional. Open well to 20/2,589/15-T/I/0. Displace diesel from frac hardline with 20# gel. Shut down for 5 minutes. Perform Data Frac using 20# linear gel. Initial pump rate of 30 bpm at 4,145psi WHP. Increased rate to 35 bpm /4,500psi - observed good pressure fall off from increasing rate. Perform step down test - 35 bpm / 25 bpm/ 15 bpm/ 10 bpm and shut down. 202 bbls pumped. ISIP = 1751psi. Analyse data frac info to determine any changes needed for final frac pump schedule. Pump main frac as per design-180 bbl Pad / Staged prop in from 1-9 ppg. Ave pump rate = 30 bpm. Ave treating pressure'" 3,300psi (2426 HHP used). Max pressure= 3,910psi. Total proppant pumped= 116,971# / Proppant behind pipe = 115,690# / 1,281 lbs in well bore with est. TOS at 10,926'. Total slurry volume pumped =1,286 bbls including data frac / 1,156 bbls clean fluid total pumped. Well freeze protected with 40 bbls diesel. 5/10/15 min pressures after shut down. _ 2,052psi/1,980psi/ 1,903psi. Shut in well. Bleed IA to Opsi. Begin flushing lines and RD. Tree Saver pulled and Rig down complete at 18:00. CTU on site to spot up on well. 11/8/2018 - Thursday MIRU CTU #6 w/ 14,640' of 2" coil. Perform BOP Test to 300psi low and 3,500psi high. Tested Stripper, 2 x Blind/Shear Rams, Slips, pipe rams, Choke valve, Kill valve, Check valve, 6 valves on choke manifold, and accumulator system. Stab onto well. P/T to 300psi and 4,OOOpsi high. Bleed off to 2,OOOpsi and test check valve. Open well. WHP is Opsi. RIH to TOS at 10,908'. Circulate 1% KCL while RIH. Weight check at 10,900' is 38k-lbs up and 6k down. Cleanout to TOC at 11,065' while circulating at 2.8 BPM and 2,600psi. Circulate 10 bbl NVis gel, 30 bbls 1% KCL, 10 bbls NVis pill, 30 bbls 1% KCL, 20 bbls NVis pill. Final gel sweep exiting nozle. Chase sweep to surface while POH and circulating 1% KCL at 3 BPM. See large amount of proppant returns when coil is 1,000' from surface. Formation sand in returns as well. Freeze protect coil with 37.5 bbls of 60/40 McOH. FP well to 500'. Secure well. Stand back injector. SDFN. 11/9/2018 - Friday On Location. Stab onto well. P/T to 300psi and 4,OOOpsi high. Bleed off to 2,OOOpsi and test check valve. Open well. WHP is Opsi. RIH to 3,500' while circulating at N2 at 750 scf/min at 1,500psi. Rate at 1,000 BPD. RIH to 5,000' while circulating at N2 at 750 scf/min at 1,500psi. Rate at 750 BPD. RIH to 6,500' while circulating at N2 at 750 scf/min at 1,500psi. Rate at 2,400 BPD. RIH to 8,200' while circulating at N2 at 750 scf/min at 1,500psi. Rate at 1,000 BPD. RIH to 3,500' while circulating at N2 at 750 scf/min at 1,500psi. Rate at 1,000 BPD. Fluid returns decreasing. POH to 8,200'. Lost fluid returns. RBIH to 10,600'. Increase N2 rate to 1200 scf/min for 5 minutes. Chase N2 slug to surface at 750 scf/min while POH. Lost fluid returns at 5,000'. Continue POH. Cut N2 at 3,000'. At surface. Well is dead. Total fluid flowed back is 430 bbls. SDFN Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP L-41 Frac / Coil 50-029-23611-00-00 218-104 10/18/2018 11/14/2018 Daily Operations. 11/10/2018 -Saturday M/U BHA #1: 3.07" CTC, 3.13" DBPV, 3.13" G Force Jar, 3.13" Disconnect, 3.13' DCV (5/8" ball), 3.13" Xtreme Motor, 3,625" Underreamer, 3.71" Junk Mill. Stab onto well. P/T to 300psi and 4,OOOpsi high. Bleed off to 2,OOOpsi and test check valve. Open well. WHP is 700psi. Start circulating 1 % KCL at 0.3 BPM at 900psi. MM at 40 Bbls. RIH w/ BHA #1. Dry tag at 11,054. Underream from 11,054' to 11,090' while circulating at 2.7 BPM at 2,550psi. Seeing work as high as 3,OOOpsi. Send gel sweep. POH and make wiper trip to tubing tail at 10,900'. Send gel sweep. RBIH and underream from 11,100' to PBTD at 11,220' while circulating at 2.7 BPM at 2,550psi. Seeing work as high as 2,700psi. Send gel sweep. 1:1 returns. Drop 5/8" ball to open circ sub. Circu sub open. POH to surface. Gel at nozzle at tubing tail. Chase final sweep to surface. At surface. Well is dead. Saw proppant back at surface when coil was at 1,000'. RBIH and freeze protect the well with 60/40 McOH to 2,500' with 38 bbls. Close swab. Stand back injector. Secure well. RDMO. 0/420/20psi. Clear area around well for E -Line to MIRU. MIRU Alaska E -line. MU toolstring of cable head, Wt bar, tubular spangs, CCL, chem cut anchor, chemical tube asst', severing head, space out connections, and 3.75" OD tapered swage. No-go on swage to severing ports on chem cutter + 45 inches (3.75'). As per Halliburton spec sheet on packer the XN no go to center of cut area = 3.8' (45.6"). CCL to severing ports = 11.5'. CCL to 3.75" No-go =15.25'. PT PCE to 300psi / 2,500psi with field triplex. Open well to 0/50/Opsi - T/I/0. RIH with 3.5"" OD chem cutter and 3.75" OD no-go spaced out between each by 45". Land No-go in XN nipple at —10,766'T -r. Appear to be on depth according to CCL log. See bottom collar of 1st full joint above the packer. Fire cutter and see 150# increase in line tension. Wait 10 minutes for anchors to retract. Bottom No-go swage wedged into XN nipple. Work tubular spangs to pop free. POOH. anchor slips not fully retracted, seeing each collar as POOH. Eventually slips retract and POOH clean. OOH. Chem cutter fired. Use PPE and bleed any trapped pressure from tools and for disassembling. Severing head appeared to have full coverage of discharge. RDMO E -Line. Job Complete. MIRU ASR Rig. 11/11/2018 -Sunday Continue MIRU ASR Rig, all mats spotted, rig spotted, BOP nippled up and torqued, pits filled and finalizing rig up to begin test BOP'S. Continue to RU for Bope Test. RU tool carrier Bells and Elevators. start Shell test Bope 250PSI low 3000PSI high. Chase leaks and fix Leaks. also found Hydraulic choke and kill valves not functioning proper. Diagnose and fix problem. Cont. to Test BOPE with 2-7/8" & 4.5" test joint. rams 250 low/3,000 high. Annular 250 low/2,500high. Prep equipment to POOH when finished with BOPE test. 11/12/2018 - Monday Continue and complete BOP testing . Test VBR's with 2-7/8" and 4.5" test mandrels to 3,OOOpsi, Annular to 2,500psi, HCR's, TIW, IBOP, and choke and kill manifold and associated lines to 3,OOOpsi. All for Good Test. Pull 2 -way check, attempt to pump down backside, pump 0.2 bbl and caught 500psi pressure, verify casing valve open and no ice in lines from pump, re- attempt to pump down casing but only pump 0.2 bbl before 500psi, pump 12 bbls down tubing and catch pressure, S/D pump and wait 20 minutes and pump 8 bbls before loading hole. Fluid level at 800'. Verify tubing hanger unlocked and pull 100K before hanger unseat hanger pulled free very suddenly as if stuck, then pulled 146K before pipe weight broke over and indication of packer pulling free. Lay down hanger and start POOH with weight ranging from 119K to 133K, acting as if packer dragging. Pump 15 bbls down tubing before loading hole. Fluid level at 1,000' Continue POOH. Cont. POOH dragging PKR. Monitoring well. started swabbing CSG with PKR getting back diesel. RU to Flow back tank. 105 jnts out. Circulate Conventional 220 bbls to clean up the well. Cont. POOH with 4.5" #12.6 frac. string n �7' Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP L-41 Frac / Coil 50-029-23611-00-00 218-104 10/18/2018 11/14/2018 Daily Operations. 11/13/2018-Tuesday Continue POOH with 4.5" 12.6# frac string. OOH @ 07:30. Inspect packer with no noticeable damage or areas for concern from external visual inspection. Pulled 266 joints 4.5" 12.6# L-80 TXP connection tubing, sent 266 joints plus all jewelry to G- I to be cleaned. All jewelry was junked and all 266 joints 4.5" L-80 tubing is to be sent to Tuboscope for full inspection post cleaning at G-1 facility. MIRU Baker Centrilift, rig up sheaves, spoolers and associated running equipment. P/U motors and pump assembly and make up while RIH on 2-7/8" L-80 6.5# Tubing. P/U 2-7/8" 6.5# L-80 tubing and start RIH w/ tubing and ESP assembly. Test at surface and test every 1,000' to 8,450'. ESP Cable reel splice Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP L-41 Frac/Coil 50-029-23611-00-00 218-104 10/18/2018 11/14/2018 Daily Operations. 11/14/2018- Wednesday ESP assembly, clamping every collar. Swapped out ESP cable spool and Continue RIH w/ 2-7/8" L-80 production string and 3/8 capillary spool. Made splice and continue RIH w/ clamp on every collar and testing ESP and Capillary string every 1000'. Terminate hanger, test terminations for good test. Land Hanger at 1400 hrs. Total joint count run 336 its 2-7/8" 6.5H L-80 ELIE tubing, ESP Centralizer @ 10,552'- X -N nipple @ 10,412'(2.313 ID and 2.505 no-go)- Lower GLM w/ 1" dummy valve BK2 latch @ 10,299'- upper GLM @ 135'w/ 1" DPSOV BK2 Latch - Run 338 X -collar clamps, 8 pump clamps, 3 protectolizers, 2 fit guards. Weight Down = 29K. RDMO ASR Rig, N/D BOP's. Final checks on esp test good. Tree up well head and test. 500psi low/5,000psi high. Cont. to move off L-41 and stack out @ A -Pad. 11/15/2018 -Thursday No activity to report. 11/16/2018 - Friday No activity to report. 11/17/2018 -Saturday No activity to report. 11/18/2018 -Sunday No activity to report. 11/19/2018 - Monday No activity to report. 11/20/2018 -Tuesday No activity to report. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ®Fc 0 5 2013 WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1 a. Well Status: oil 21 • Gas❑ SPLUG❑ Other ❑ Abandoned ❑ Suspended L1 20AAC 25.105 20MC 25.110 GINJ ❑ WINJ ❑ WAG❑ WDSPL ❑ No. of Completions: _11 1b. Well Class: Development Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Abend.: 11/14/2018 14. Permit to Drill Number / Sundry: . 218-104/318-433/318-466 •i 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: August 30, 2018 15. API Number: 50-029-23611-00-00 ` 4a. Location of Well (Governmental Section): Surface: 3578' FSL, 5134' FEL, Sec 8, T13N, R10E, UM, AK Top of Productive Interval: 188' FSL, 2314' FWL, Sec 32, T14N, R10E, UM, AK Total Depth: 276' FSL, 2344' FWL, Sec 32, T14N, R10E, UM, AK 8. Date TO Reached: October 9, 2018 16. Well Name and Number: MPU L-41 9. Ref Elevations: KB: 50.2' • GL:16.5' BF:16.5' 17. Field / Pool(s): Milne Point Field Kuparuk River Oil Pool - 10. Plug Back Depth MD/TVD: • 11,232' MD 17,390' TVD • 18. Property Designation: ADL025504 / ADL355017 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 544744 • y- 6031767 • Zone- 4 TPI: x- 546843 y- 6038948 Zone- 4 Total Depth: x- 546872 y- 6039037 Zone- 4 11. Total Depth MD/TVD: - 11,3.}5 MD / 7,468' TVD . 19. DNR Approval Number: LONS 88-002 12. SSSV Depth MD1TVD: N/A 20. Thickness of Permafrost MDlrVD: I • 1,953' MD / 1,870' TVD ` 5. Directional or Inclination Survey: Yes � (attached) No Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL 21. Re-drill/Lateral Top Window MD/TVD: I N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary ROP ABG DGR EWR-Phase 4 MD /ABG DGR EWR-Phase 4 TVD / CBL 23. CASING, LINER AND CEMENTING RECORD CASING WT. PER FT GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE AMOUNT CEMENTING RECORD PULLED TOP BOTTOM TOP BOTTOM 20" 164# A53B Surface 80' Surface 80' Driven Driven 9-5/8" 40# L-80 Surface 7,366' Surface 4,700' 12-1/4" Sig 1 L - 720 sx / T - 400 sx 85 bible Sig 2 L - 300 sx / T - 270 sx 175 bbls 7" 26# L-80 Surface 11,290' Surface 7,444' 9-7/8x8-1/2" 255sx 24. Open to production or injection? Yes Q No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 11,000'- 11,005' MID / 7,172'- 7,176' TVD 11/5/18 11,108' - 11,116' MD / 7,273' - 7,281' TVD 10/23/18 LOI`dPLETJON 3-1/8", 6 SPF DATE 11 VERIFIED -- - 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 2-7/8" 10,553' N/A 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes No Per 20 AAC 25.283 (i)(2) attach electronic and printed information ❑ DEPTH INTERVAL (MD) JAMOUNT AND KIND OF MATERIAL USED See attached Frac Focus 27. PRODUCTION TEST Date First Production: 11/21/2018 Method of Operation (Flowing, gas lift, etc.): ESP Date of Test: 11/30/2018 Hours Tested: 24 Production for Test Period Oil -Bbl: 898 Gas -MCF: 287 Water -Bbl: 26 Choke Size: N/A Gas -Oil Ratio: 319.6 Flow Tubing Press. 242 Casing Press: 240 Calculated 24 -Hour Rate Oil -Bbl: 898 Gas -MCF: 287 Water -Bbl: 26 Oil Gravity - API (corr): 26 Form 10-407 Revised 5/2017 CONTINUED ON P GE 2 Submit ORIGINAL or(� �_��_; 9 ZA RBDMSnn(� c c % r: 2r.�a (' / ,/ ,� �`, 28. CORE DATA Conventional Core(s): Yes ❑ No ❑� . Sidewall Cores: Yes ❑ 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 ❑� , If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 1,953' 1,870' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 11,000' Kup C 7,172 information, including reports, per 20 AAC 25.071. Ugnu 2,976' 2,446' Schrader 6,211' 4,114' HRZ 10,563' 6,760' Kup C 10,996' 7,168' KupA 11,105' 7,270' Formation at total depth: Miluveach 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports, Frac Focus. 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. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: Cdir1 er h Icor .Com Authorized Contact Phone: 777-8389 Signature: — Date: Zv 1 �5 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 1b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY -123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rad 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, care chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only H FlilcorP Alaska, LLC Ong. KB Elm: 33.7' / GL Elev.: 16.5' 2a' ES Cementer @2,508' &5/8" 3/8' M10=2 @ 10,412' SCHEMATIC Milne Point Unit Well: MPL-41 Last Completed: 11/14/2018 PTD: 218-104 TREE & WELLHEAD DETAIL Tree 4-1/16" 5M Wellhead 11" 5M FMCGen V OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" Stg 11685 ft3/458 ft3, Stg 21937 ft3/314 ft3 9-7/8"x8-1/2" I Sig 1296113, Sig 2191 ft3 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm BPF 20" Conductor 164/A53B/Weld N/A Surface 80' N/A 9-5/8" Surface 40/L-80/TXP 8.835 Surface 7,366' 0.0758 7" Intermediate 26/L-80/TXP 6.276 Surface 11,290' 0.0383 TUBING DETAIL 2-7/8" Tubing 6.5/L-80/EUESrd 2.441 Surface 10,553' 3/8" Capstr4ng Stainless Steel N/A Surface 10,553' WELL INCLINATION DETAIL KOP E60 Max Hole Angle 61.8 deg @ 7299' MD JEWELRY DETAIL No. Top MD Item 1 135' ST 2: 2-7/8" GLM DPSOV-1" w/ BK2 Latch 2 10,292' ST 1: 2-7/8" GLM w/ Dummy 1" valve- BK2- Latch 3 10,412' 2-7/8" XN-Nipple — Min ID-- 2.205 4 10,464' Discharge Head: FPDIS 400 5 10,465' Upper Pump: SXD FLEX 17.5 6 10,488' Lower Pump: SXD FLEX 17.5 7 10,512' Gas Separator: GRS FER N AR 810,515' Upper Tandem Seal: GSB3DBUTSB/SB PFSA 9 10,522' Lower Tandem Seal: G563OBUTSB/SB PFSA 30 10,529' Motor: XP—RERATED202HP/1,893V/65A 11 10,549' Sensor: PHEONIX XT -150 & Centralizer— Bottom @ 10,553' PERFORATION DETAIL Sands Top (MD) I Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk B/C 11,000' 1 11,005' 7,172' 7,176' S 3-1/8" 11/5/18 Open Kuparuk A3 11,108' 1 11,116' 7,273' 7,281' 8 3-1/8" 10/23/18 Open Ref Log: 10/16/2018 Pollard Radial /Sector CBL 7&B 9&10 !'+ ES Cementer t-@ 10,435 Z- 71 7il3rs TD= 11,315 (MD) / TD = 7,468' (TVD) PBTD=11,237 (MD) / PBTD= 7,390' (TVD) GENERAL WELL INFO API: 50-029-23611-00-00 Drilled and Cased by Doyon 14-10/12/2018 ESP Completion by Doyon 14 — 11/14/2018 Revised By: TDF 11/27/2018 0 Well Name: MP L-41 Field: Milne Point Unit County/State: , Alaska i (LATILONG): evation (RKB): 33.7 API #: Spud Date: 8/30/2018 Job Name: 1813264D MPL-41 Drilling Contractor Doyon 14 ARE #: 1813264D APE $: $4,597,573 Hilcorp Energy Company Composite Report ARt" , Ops Summary... 8/2 812 01 8 See L-14 report.;RD and prep the rig floor to skid. Finish changing out the saver sub.;PJSM. Skid the rig floor into moving position.;PJSM. Jack up the rig and remove the shims. Pull the rig off well L-14 and position on move on the pad.;Move the rig around the on the pad to well L-41.;PU and set remaining mats for the 1 ri : S of the ricl over well L-41 8/29/2018 Continue to spot the rig over well L-41. Shim and level rig.;PJSM. Skid the rig Noor into drilling position. SimOps: Set rig mats in place for rock washer. Welders work on bracing for centrifuge 1 discharge line, work on stairs for rock washer and pits.;RU the rig floor. Install diverter line. Spot rock washer and shacks.;Work on rig acceptance checklist. Turn the power off on the entire rig. Change the highline breaker on the rig from 1600 amp to 2000 amp breaker. Could not get the breaker to latch open. Reinstall 1600 amp breaker. SimOps: Load, strap and tally 5" DS -50 DP. Rig accepted at 12:00 hours;NU the tee, bell nipple and riser. RU hydraulic lines to the diverter bag and knife valve. Grease the /BOP. RU to PU DP. SimOps: Load, strap and tally 5" DS -50 DP. Rig on highline power at 12:00 hours.;Function the diverter bag and knife valve.;PJSM. PU and MU stands of 5" DS -50 DP drifting to 2.3" OD from stand #82 to #28.;Perform the surface diverter test. The state's right to witness was waived by AOGCC inspector Adam Earl via email on 8/29/18 at 17:09 hours. Test: Knife valve = 9 seconds and Annular = 27 seconds.;Accumulator Test: System pressure = 3000 psi Pressure after closure = 1850 psi 200 psi attained in 36 seconds Full pressure attained in 147 seconds Nitrogen Bottles - 6 at 2100 psi;Conbnue to PU and MU stands of 5" DS -50 DP drifting to 2.3" OD from stand #27 to #1.;PU and MU 5 stands of 5" HW DP and 1 stand 5" HWDP with jars;Off load DP thread protectors. Mobilize BHA to the rig floor.;Pre Spud/PJSM with rig crew and all third party.;PU and MU conductor cleanout BHA.;Flood the lines and fill the stack with fresh water. Check for leaks, no leaks. Close the IBOP and test the mud lines to 3500 psi (good tesl).;Wash down from 36' at 385 GPM = 285 psi to tag at 109' and continue to wash down to the bottom of the conductor at 114'. Spud the well and drill 12-114" hole from 114' to 128' at 30 RPM = 0 ft -lbs torque. Displace the well to 8.8 ppg spud mud.;Hauled 350 bbls H2O from L -Pad Lake for total = 350 labile Hauled 0 blots H2O from G&I Heated for total = 0 bbis Hauled 0 bbis cuttings/liquids to G&I for total = 0 bbls Hauled 0 bbls cuttings/liquids to G&I DS4 = 0 bbis 8/30/2018 Drill 12-14' hole V 128' t/ 220' pumping 390 gpm, 400 psi, 30 rpm w/ no tq. 1-3k wob.;Ream f/ 220' to 125'350 gpm, 350 psi, Kill pump, RIH to 220'. Rack 2 stds back. BDTD. pull motor to surface, LID 12 114" cleanout bft.;MIU directoinal BHA, new 12 1/4" Kymera bit, 1.5 deg mtr, MWD/LWD tools and scribe same, offset @ 290.08 deg. Up Load MWD tools. MU UBHO, 3 NMDC's, BN XO, RU Gyro Tools and Sheave. Finish MU drilling assembly.;Crew change, Hold spud meeting w/ crew and third party personnel. Review well control and rig evac plan while on diverter.;WU std HWDP, shallow pulse test MWD, good.;Drill 12-1/4" directional hole F/ 220' T/ 400'. Pump 450 GPM, 1000 PSI, 50 RPM, 2-5 K WOB, 2-3K TO Submit diverter test form to AOGCC;600 psi pressure loss, troubleshoot pressure loss, pumps lost suction due to hi vis mud in suction line, clean suction screens, flush water thru suction lines with vac truck, circulate 2 BU at 450 GPM = 750 psi.;Mud 9 ppg, vis in/out 67/82, increase vis to 150 before drilling ahead. rotate and reciprocate while bring vis up; Drill 12-1/4" surface hole from 400' to 730' (730' TVD) at 444 GPM = 900 psi, 50 RPM =1 K ft -lbs torque, WOB = 5-10K, ECD = 9.6 ppg, PU = 82K, SO = 84K, ROT = 78K. AROP = 60 FPH. Started build section at 536' (3'/100);Drill 12-114" surface hole from 730' to 1297' (1280' TVD) at 480 GPM = 1280 psi, 50 RPM= 24K ft -lbs torque, WOB = 5-7K, ECD = 10.1 ppg. PU = 91 K, SO = 90K, ROT = 90K. AROP = 94.5 FPH. Put gyro on standby at 977'. Release gyro at 1071' and RD.;Hauled 410 bbis H2O from L -Pad Lake for total =760 bbis Hauled 0 bbls H2O from G&I Heated for total = 0 able Hauled 461 bbls cuttings/liquids to G&I for total = 461 bbis Hauled 0 bbls cuttings/liquids to G&I DS4 = 0 bbls;Last survey at 977.5' MD, 974.01' TVD, 13.47° Inc, 29.46° Az. Distance to Well Plan #10 = 12.53' (8.09' low and 9.57' right). 8/31/2018 Drill 12-114" surface hole from 1297' to 1949' (1874' TVD), AROP = 108.7 FPH. Build 5°1100'. Base of permafrost at 1925' MD. 465 GPM = 1330 psi, 60 RPM = 2-51K ft-lbs torque, WOB = 12-14K, MW = 9.4 ppg, Vis = 120, ECD = 10.12 ppg, Max gas = 45 units PU =102K, SO= 89K, ROT= 97K.;Ddll 12-1/4" surface hole from 1949to 2716' (2300' TVD), AROP = 127.8 FPH. Build 5'/100'to 2394'then maintain 59' inclination. 520 GPM = 1800 psi, 80 RPM = 4-6K ft-lbs torque, WOB = 5-1 OK,;MW = 9.3 ppg, Vis = 103, ECD = 10.5 ppg, Max gas = 308 units PU = 105K, SO = 87K, ROT = 95K. Pump 30 bbl hi vis sweep at 2420' (back 200 strokes late) with 75% increase in cuthngs;Drill 12-114" surface hole from 2716' to 3375' (2646' TVD), AROP = 109.8 FPH. Maintain 59' inclination. 575 GPM = 2000 psi, 80 RPM = 51K ft-lbs torque, WOB = 10K, MW = 9.3+ ppg, Vis = 161, ECD = 10.5 ppg, Max gas = 134 units PU = 103K, SO = 95K, ROT = 101 K.;Pump 30 bbl hi vis sweep at 3280' (back 200 strokes early) with 100% increase in cuftings;Drill 12-1/4" surface hole from 3375' to 4190'(3064! TVD), AROP = 135.8 FPH. Maintain 59° inclination. 577 GPM = 2300 psi, 80 RPM = -11 K ft-lbs torque, WOB = 1 OK, MW = 9.3+ ppg, Vis = 186, ECD = 10.5 ppg, Max gas = 67 units PU =137K, SO = 93K, ROT = 107K.;Pump 30 bbl hi vis sweep at 3752' (back 300 strokes early) with 50% increase in cuttings;Hauled 470 bbis H2O from L-Pad Lake for total = 1230 bbls Hauled 675 bbis H2O from B-Pad Creek for total = 675 bbis Hauled 0 bbis H2O from G&I Heated for total = 0 bbis Hauled 979 bbls cuttings/liquids to G&I for total= 1440 bbls;Last survey at 3807' MD, 2869' TVD, 58.95° Inc, 15.61° Az. Distance to Well Plan #10 = 14.69' 9/1/2018 Drill 12-1/4" surface hole from 4190'to 4825' (3398' TVD), AROP = 105.8 FPH. Maintain 59' inclination. 574 GPM = 2300 psi, 80 RPM =-10-14K ft-lbs torque, WOB = 10-15K, MW = 9.3 ppg, Vis = 157, ECD = 10.3 ppg, Max gas = 117 units PU = 155K, SO = 95K, ROT = 116K.;Pump 30 bbl hi vis sweep at 432U (back 300 strokes early) with 50% increase in cuttings;Drill 12-1/4" surface hole from 4826 to 5451' (3693' TVD), AROP = 104.3 FPH. Maintain 59' inclination. 600 GPM = 2250 psi, 80 RPM =-14-16K ft-lbs torque, WOB = 15-20K, MW = 9.3 ppg, Vis = 81, ECD = 10.2 ppg, Max gas = 110 units PU =175K, SO = 94K, ROT = 125K.;Pump 30 bbl hi vis sweep at 4889 (back 500 strokes early) with 25% increase in cuttings. Pump 30 bbl hi vis sweep at 5390' (back 500 strokes early) with 0% increase in cuttings;Drill 12-1/4" surface hole from 5451' to 6017' (4014' TVD), AROP = 94.3 FPH. Maintain 59' inclination. 598 GPM = 2250 psi, 80 RPM=-15-20K ft-lbs torque, WOB = 10-15K, MW = 9.3 ppg, Vis = 101, ECD = 10.1 ppg, Max gas = 143 units PU = 180K, SO = 90K, ROT = 127K.;Pump 30 bbl hi vis sweep at 5992' (back 300 strokes early) with 15% increase in cuttings;Drill 12-1/4" surface hole from 6017' to 6488' (4256' TVD), AROP = 78.5 FPH. Maintain 59' inclination. 590 GPM = 2350 psi, 80 RPM =-14-19K ft-lbs torque, WOB = 18-22K, MW = 9.2+ ppg, Vis = 135, ECD = 10.3 ppg, Max gas = 113 units PU = 200K, SO = 95K, ROT = 136K.;Hauled 1775 bbls H2O from L-Pad Lake for total = 3005 bbis Hauled 0 bbis H2O from B-Pad Creek for total = 675 bbis Hauled 0 bbis H2O from G&I Heated for total = 0 bbis Hauled 2020 bbis cuffings/liquids to G&I for total= 3460 bbls;Last survey at 6262' MD, 4140' TVD, 59.58' Inc, 18.92' Az. Distance to Well Plan #10 = 3.77' 9/212018 Drill 12-1/4" surface hole from 6488'to 674U (4384' TVD), AROP = 42 FPH. Maintain 59' inclination. 600 GPM = 2350 psi, 80 RPM =-16-20K ft-lbs torque, WOB = 18-22K, MW = 9.2 ppg, Vis = 147, ECD = 10.1 ppg, Max gas = 132 units PU = 205K, SO = 100K, ROT = 140K.;Pump 30 bbl hi vis sweep @ 6491', sweep back 300 stks early with 20% increase.;Drill 12-1/4" surface hole from 6740' to 7000' (4477' TVD), AROP = 43.3 FPH. Maintain 59' inclination. 600 GPM = 2550 psi, 80 RPM =-17-20K ft-lbs torque, WOB = 22K, MW = 9.3 ppg, Vis = 120, ECD = 10.1 ppg, Max gas = 62 units PU = 205K, SO= 100K, ROT= 140K.;Drill 12-114" surface hole from 7000'to 7223' (4631' TVD), AROP = 37.2 FPH. Maintain 59° inclination. 600 GPM = 2640 psi, 80 RPM= -15-21 K ft-lbs torque, WOB = 18-22K, MW = 9.3 ppg, Vis = 152, ECD = 10.1 ppg, Max gas = 81 units PU = 205K, SO = 103K, ROT = 135K.;Pump 30 bbl hi vis sweep @ 7057', with 0% increase.;Drill 12-1/4" surface hole from 7223' to 7374'(4703! TVD), AROP = 25.2 FPH. Maintain 59' inclination. Obtain survey at TD. 600 GPM = 2640 psi, 80 RPM = -15-21 K ft-lbs torque, WOB = 18-22K, MW = 9.2 ppg, Vis = 79, ECD = 9.9 ppg, Max gas = 32 units PU = 205K, SO = 103K, ROT = 135K.;Hauled 2085 bbls H2O from L-Pad Lake for total = 5090 bbis Hauled 0 bbls H2O from B-Pad Creek for total = 675 bbis Hauled 0 bbis H2O from G&I Heated for total = 0 bible Hauled 1906 bible cut ingslliquids to G&I for total= 5366 bbls;Last survey at 7205' MD, 4622.29 TVD, 60.15' Inc, 14.94' Az. Distance to Well Plan #10= 6.76' 9/3/2018 Rack 1 stand back. MU single and pup jt. Pump 40 bbl low visAow weight sweep followed by 40 bbl high vis/10.3 ppg weighted sweep with 15 ppg nut plug marker at 600 GPM = 2200 psi, 90 RPM, reciprocate pipe 90'. Sweep back 500 stks early with no increase in cuttings.;Circulate and condition the mud lowering the YP from 35 to 25 at 600 GPM = 2300 psi, 80 rpm, reciprocating pipe. MW = 9.3 ppg and vis = 53. Observe the well for flow and the well is static. LD single and pup jt.;SimOps: Change out the grabber dies on the top drive. Load, strap and tally 10 joints of 5" DS-50 DP.;BROOH from 7336' to 3177' at 5 min per stand, pumping 600 GPM =2100 psi, rotate 80 rpm, PU = 14OK and SO= 90K. Continue to treat mud and inspect tool joints for gripper die damage. Work tight spot two times at 4455'.;Continue to BROOH from 3177' to 735' at 5 min per stand, pumping 600 GPM = 2100 psi, rotate 80 rpm, PU = 140K and SO= 90K. Continue to treat mud and inspect tool joints for gripper die damage. Tight connection at 1301' and 1112'.;Hauled 1060 bbls H2O from L-Pad Lake for total = 6150 bbis Hauled 0 bbis H2O from B-Pad Creek for total = 675 bbls Hauled 0 bbls H2O from G&I Heated for total = 0 bbis Hauled 1154 bbis cuttings/liquids to G&I for total= 6520 bbls;Last survey at 7333' MD, 4975' TVD, 61.41' Inc, 15.06' Az. Distance to Well Plan #10= 11.1' 9/4/2018 POOH on elevators f/ 735' racking back HW DP and jars. LID BHA f/ 175' to 83'. Download MWD Data, LID remainder of BHA. Bit and stabilizer balled w/ clay. Bit grade= 5/2/CT/N/E/I/BU/'fD Correct displacement BROOH.;Monitor well, static, Clear tools and clean rig floor. flush flowline;R/U 9 5/8 casing handling equip, Install 8' dog bones, RN DDI CRT, elevators. Install bushings in rotary for 9 5/8" casing. PJSM for running casing, Monitor well, Static.;M/U 9-5/8" 40# L-80 TXP-BTC casing shoe track to 165'. Baker Loc & torque connections to 20,960 ft/lbs. Check floats, good. 2- Centralizers installed 10' f/ as end on shoe jt, 1 centralizer mid it on baker loc jt, FC it and BA jt. Note: install top hat in FC jt.;Run 9-518" 40# L-80 TXP casing f/ 165' T/ 2577', RIH 15-207min. and slow to 10'/min due to Iosses.Torque connections to 20,960 ft/ibs. Fill on the fly & top off every 10 then circulate 10 bbls. Install centralizers on every jt to jt 23, then every other to it 59. 44 bbls lost while running casing.;Circulate a bottoms up at 2577' after the end of build. Stage up to 5 BPM, 210 PSI ICP, 160 PSI FCP. Change bail extensions from V to 6', continue to circulate at 3 BPM. 13 bbls lost while circulafing.;Run 9-5/8" 40# L-80 TXP casing f/ 2577' T/ 4191', RIH 20 itlmin. Torque connections to 20,960 ft/lbs. Fill on the fly & top off every 10 then circulate 15 bbis. Install centralizers on every other from jt 61 to jt 99. Observe mud weight out increase to 9.7 PPG. 30 bbis lost for 87 bbis total.;Break circulation at 2 BPM, 120 PSI. Condition the mud to reduce the mud weight. Stage up the flow rate as allows. Add water and run centrifuge as needed ;Hauled 320 bbis H2O from L -Pad Lake for total = 6,470 bbis Hauled 0 bbis H2O from B -Pad Creek for total = 675 bbis Hauled 290 bbis H2O from G&I Heated for total = 290 bbls 9/5/2018 Circulate and condition the mud @ 4191', stage to 4 bpm, 170 psi, reciprocating pipe slow, running centrifuges and adding water 50 bph. lower out MW f/ 9.7 ppg to 9.5 ppg out, pumped 1 3/4 full circulations, flow check well, static. 19 BBL losses while circulating. PU 185, SO 110.;Continue RIH w/ 9 5/8" casing from 4191' to 4832' @ 10-15 fpm ( Place 1 -centralizer every other jt f/#25 to #105 ) @ jt 116, M/U ESIPC tool as per HES rep ( pinned to open @3000 psi and inflate @ 2080 psi ) RIH f/ 4872't/ 5033'.;( Place 1 centralizer on as jt to 5 its below tool and 10 its above the stage tool )Torque connections to 20,960 ft/lbs. Fill on the fly & op off every 10 then circulate 15 bbls.;Continue RIH w/ 9 5/8" casing 10-15 FPM f/ 5033' to 583T @ jt # 140 ( Place 1 -centralizer every other jt H #127 to #139 ) Correct displacement RIH f/ 4191'to 5837'.;Circulate and condition mud, CBU, staging pump to 4 bpm, 280 psi, reciprocate pipe slow, 14 bbl losses circulating.;Continue RIH w/9 5/8" casing 10-15 FPM f/ 5837' to 7367' Torque connections to 20,960 f (lbs. Fill on the fly & top off every 10 then circ. 15 bbls. it (Place 1 -centralizer every other it f/#141 to # 175). Washed down last three joints H 7246 V 736T with 3 BPM, 450 PSI.+10 bbis displacement.;178 joints of 9- 5/8" casing and 109 9-5/8"x12-1/4" Expand -O -Liter centralizers ran. 110 bbls total lost while running casing ;Condition mud prior to cement job. Stage up to 5 BPM, 380 PSI. 9.3 PPG, 47 vis in / 9.3 ppg 72 vis out. After bottoms up, increase flow to 5.7 BPM, 155 PSI while adding 50 BPH water. Increase to 7 BPM, 220 PSI. Slow to 5.7 BPM to prevent unnecessary washout.;Reduce volume in the mud pits prior to cement job. 13,870 stks total pumped - 3.5x bottoms up. 330K up weight / 125K down weight. 0 losses while circulating.;PJSM w/ Doyon rig crews, Halliburton cementers, mud man and truck drivers. R/U cement Iines.;Perfonn 1 st stage cement job. Pump 5 bbis H2O. Pressure test to 1000 14100 PSI. Mix & pump 60 bbis 10.0 ppg Clean Spacer @ 4.5 BPM, 230 PSI. 4# red dye & 5# Pol- E-Flake in 1 st 10 bbis. Drop by-pass plug. Mix & pump 302 bbis / 720 sks 12.0 ppg ExtendaCem lead cement @ 6 BPM, 460 PSI.;Mix & pump 82 bbis / 400 sks X 15.8 ppg Premium G tail cement @ 1.4 BPM, 260 PSI. Drop shut off plug. Pump 20 bbls 8.34 ppg H2O @ 3.5 BPM, 250 PSI. No losses while cementing.;Displace with rig pumps. Pump 9.3 ppg spud mud @ 7 BPM, 220 PSI. Slow to 5 BPM, 140 PSI. Observe 40-60% loss of returns, slow to 4 BPM, 170 PSI, losses slowed to 10%. Reciprocate and rotate pipe until became sticky 3725 stks into displacement, place at set depth.;Observe spacer back at 4165 stks and dump interface at 4730 stks. Slow to 2 BPM @ 5100 stks. Pump plug at 5228 stks, 1060 PSI final circulating pressure, increase to 1560 PSI & hold for 5 min. Bleed off & check floats - good. CIP @ 06:10.;Observed 675 PSI lift pressure from 12.0 ppg lead cement. Observed 155 PSI lift pressure from 15.8 ppg tail cement. 136 bbis lost while displacing.;Hauled 395 bbis H2O from L -Pad Lake for total = 6,865 bbis Hauled 0 bbis H2O from B -Pad Creek for total = 675 bbis Hauled 290 bbis H2O from G&I Heated for total = 290 bbis / s Hauled 431 bbis cuttings/liquids to G&I for total = 7322 bbis `a O 9/6/2018 Finish checking Floats, good. Inflate Halliburton ESIPC - pressure up to 2150, 2400 then 2700 PSI, hold for 5 min. Pressure up and Shear ESIPC open at 3730 PSI.;Circulate f/ 2508' @ tool pumping 7 bpm, 870 psi, dumped a total of 153 bbls, (seen cmt @ 67 bbis into displacement 85.6 bbls green cement returned to Q surface), dump all returns, continue circulating taking returns back to pits, Clabbered thick mud returns @ 200 bbis pumped.;R/U super sucker on 4" conductor valve, clear 30 bbis thick mud f/ annulus and flow line until good mud @ returns. Shut off pump, cycle -flush diverter stack and flowline w/ black water. Prep pits & n / rock washer f/2nd stage. Cont circulating 2 bpm, 90 psi. Submit 24 hr BOP test notification @ 08:39.;PJSM for pumping 2nd stage. Break out volant tool, inspect plunger, M/U same. Begin Dumping 2nd stage cement ah Pnmp 5 bbis water, pump 55 bbis 10 ppg Clean Spacer 3.5 bpm, 200 psi.;Mix & pump 230 bbis, 300 sxs 10.7 ppg Permafrost L cement, 6 BPM, 580 PSI. Mix & pump 56 bbls, 270 sxs 15.8 ppg Premium G cement, 4 BPM, 350 PSI. Drop closing plug. Pump 20 bbis water, 5 BPM, 250 PSI, Note: 212 bbis lead pumped see spacer returns.;With rig pump, displace w/ 9.3 ppg spud mud, 5 BPM, ICP 340 PSI, FCP 920 PSI, slow pump to 2 bpm @ 150 bbis, at 167.6 bbis pressure to 1450 psi shift cementer tool closed, hold for 5 min, bleed off pressure, bled back .5 bbl Note: 580 psi lift psi. CIP @ 16:46 hrs.;55 bbis spacer & 175 bbis good cmt returned to surface. No losses pumping 2nd stage.;Flush all surface equipment wl black water. Function test annular w/ black water 3 times. Blow down cement line. RID Volant & LID casing equipment. Start RID diverter llne.;R/D Volant casing running tool & L/D casing equipment. R/D diverter Iine.;Remove speed head LDS. Hoist diverter stack. Suck mud out of casing joint. Set casing slips w/ 100K weight on slips. Rig welder cut and dressed 9-5/8" casing as per Hilcorp wellhead representative. Cut joint length = 35.99'.;Pull riser and LID bell nipple. N/D diverter stack. Clean cement residue out of diverter stack. Clean surface equipment.;lnstall FMC well head as per Hilcorp well head representative. Test well head metal seals to 2500 PSI (80% of 9-5/8" 40# L-80 collapse) for 10 min. - good. Install casing hanger and tubing hanger mandrels.;N/U BOP stack.;Hauled 60 bbis H2O from L - Pad Lake for total = 6,925 bbls Hauled 0 bbis H2O from B -Pad Creek for total = 675 bbls Hauled 490 bbis H2O from G&I Heated for total = 780 bbls Hauled 1059 bbis cuttings/liquids to G&I for total = 8381 bbls 9/7/2018 N/U BOP stack, clean pds.;N/U managed pressure drilling equipment, Install MPD equipment w/ RCD body, actuator valves and high pressure flow line flanging up to annular, install trip nipple. R1U hardline, continue to clean pits, load 5" DS50 DP and BHA into shed.;Continue to N/U MPD equipment, torque connections to spec, clean pits. Simops: install new outer stairs to pits with crane. AOGCC Rep Guy Cook waived witness for upcoming BOP test @ 15:32 hrs.;R/U BOP test equipment. Install test plug and test joint. Fill BOP stack and lines with water prior to body test. Observed MPD riser flange Ieaking.;Remove clamp & observe water leaking from welded flange to riser connection. Area is welded internally. R/D test equip. / Pull test jt. Remove riser flange & send to shop. Welder found 3" of weldmenl not fused to flange. Grind out old weld & re -weld. Set lest jt. & R/U test equip.;KR valve on accumulator bypassing. Replace KR valve. Began testing choke valves while mechanic was replacing. Re -installed MPD riser flange, o -ring leaking -will change after BOP test.;Test BOP equipment as per PTD & AOGCC requirements. Upper 2-718"x5" VBR and annular tested on 5" drill pipe. Test 14 choke valves, upper & lower IBOP, dart valve, FOSV, manual & HCR choke & kill valves, manual & hydraulic chokes. Annular tested to 250 psi low / 2500 psi high.;All other tests to 250 psi low, 14000 psi high. All test held for 5 min. & charted. Test gas, PVT and flow alarms. Lower pipe rams failed to test, inspect and found damaged element. Remove to replace elements. 3 tests remaining in procedure.;Hauled 165 bbis H2O from L -Pad Lake for total = 7,090 bbis Hauled 0 bbls H2O from B -Pad Creek for total = 675 bbis Hauled 490 bbis H2O from G&I Heated for total = 780 bbis Hauled 510 bbis cuttings/liquids to G&1 for total = 8891 bbis 918/2018 Change out elements on 2 7/8" x 5" VBRs, reinstall VBRs on lower BOP, button up ram doors.;Fill stack with water, Test lower ram to 250 psi and 4000 psi 5 min ea, Perform accumulator drawdown test= initial 3000 psi, after closure 1750 psi, 200 psi attained in 37 sec, full psi in 167 sec, 6 N2 bttl avg 2050 psi.;Remove test jt, test blind rams to 250 psi and 4000 psi 5 min ea. chart record all tests. 2 F/P items, KR valve and lower pipe rams.;Modify MPD 22" x 16" boot adapter for removing and installing riser, inspect riser flange and replace o -ring, Install MPD test cap, Pressure test MPD equipment @ per procedure, pressure to 250 psi low and 1500 psi high 10 min as, Remove test cap and reinstall riser, check riser for leaks, good.;Circulate water thru MPD system checking return line for leaks. Pull test plug.;lnstall 9" ID wear bushing, install 22" x 16" boot adapter.;PJSM, NVU 8 112" mill tooth bit, 1.22 deg mtr, 2 fit subs w/ non ported fits, 6 HWDP, Jars, 11 HWDP= 589.96.;Drift, P/U and single in the hole w/ 5" DS50 DP V 589' to 2471'. Tagged cement stringers at 2471' ;Wash down (/ 2471' V 2491' w1300 GPM, I$ 450 PSI, 50 RPM, 2-5K TO. 105K PUW, 85K SOW, 95K ROT. Drill cement f/ 2491'V 2494'w/ 400 GPM, 730 PSI, 50 RPM, 5-10K TO. 5K WOB. Drilled closing plug at 2494' and drilled ESIPC profile at 2508'w/ 5-9K WOB. Ream 2x times & trip through w1 no difficulty.;Single in the hole w/ 5" drill pipe f/ 2508' V 3326', then TIH f/ 3326 V 6251'.;Perform kick while tripping drill. Well secure in 65 sec. all hands reported in in 107 sec. Perform AAR for kick drill. PJSM for MPD operations with Doyon crew, Beyond Energy MPD and DSM. Attempt to pull trip nipple, but needed split master bushing. Locate split bushing in Kuparuk.;Trip in X y hole f16251't/ 7006. Mobilize split master bushings from Doyon 1421 KIC pad in Kuparuk.;Wash f/ 7006 V 7195' at 400 GPM, 900 PSI, 50 RPM, 14K TQ. Circulates bottoms up at 600 GPM, 1000 PSI, 50 RPM, 15K TQ. Reciprocate f/ 7195' V 7101'. 240K PUW, 95K SOW, 135K ROT.;Blow down top drive & R/U PSI for 30 6.1 bbis bled back. R1D test ljN test equipment. Pressure test the 9-518" casing to 2500 min. - good test pumped and equipment.;Mobilize split master bushings to a ng oar. emove master us mgs, 1.en rotary table - remove 114" of scale/rust. Install split master bushings.;Slip and cut drilling line. Inspect draw works. Service top drive.;Hauled 205 bbis H2O from L -Pad Lake for total = 7,295 bels Hauled 0 bbis H2O from B -Pad Creek for total = 675 bbis Hauled 490 bbis H2O from G&I Heated for total = 780 bbls Hauled 171 bbis cuttings/liquids to G&I for total = 9062 bbis 9192018 Service lop drive, inspect saver sub.;Train rig crew for drilling using MPD before drilling out cmt and FE. Review procedure for making connections and holding back pressure on well, Review procedure for installing and removing RCD elemenFPOOH and Rack 3 stds back. Practice installing RCD element following Beyond procedure, remove MPD riser, stab and set bearing assembly, break circulation thru MPD equip. Practice connections w/ crew. Review RCD element C/O due to failure, remove bearing assy, install dser.;Wash and ream down 450 gpm, 1270 psi, 50 rpm, 16k tq f/ 7195', to 7218' Tagging cement, drill out cmtw/ 8k wob, Drill plugs and Baffle adaptor f/ 7235' PU 250K, SO 100K.;CBU while training rig crew for drilling using MPD before drilling out cmt and FE. review procedure for making connections and holding back pressure on well and for installing and removing RCD element, shut off pump.;Practice installing RCD element following Beyond procedure, remove MPD riser, stab and set bearing assembly, Practice connections w/ crew. Review RCD element C/O due to failure, / remove bearing assy, install riser.;Drill 9-5/8" shoe track f/ 7235' V 7367'. Clean out rathole to 7374'. 450 GPM, 1350 PSI, 50 RPM, 17K TO. Increase to 500 r(\ GPM, 1980 PSI. 230K PUW, 95K SOW, 140K ROT.;Drill 8-12" hole f/ 7374 V 7394'. 600 GPM, 2040 PSI, 50 RPM, 18K TO, 20K WOB.;Pump 30 blots hi -vis / Y spacer then displace wellbore to 9.5 ppg LSND mud. Max rate 8 BPM, 550 PSI. Good mud to surface at 486 bels, 470 calculated. Perform 5 min. flow check - static. Rack back stand & UD single to 7278'.;Perform FIT to 12.5 ppg EMW. 9.5 ppp LSND test fluid. Shoe depth 7367 MD 14703' TVD. Pressure up to 734 PSI f/ 7278'V 681 T. Pump 11.5 dry & blow down drive. Continue POOH fl .7 and chart test. 1.9 bels pumped and 3.0 bbis bled back.;PQOH V ppg job top to on elevators 6817't/ 33'. LID bit and motor. Clear & clean rig floor. Bk: 1-0-CD-1-E-I-NO-BHA;Hauled 205 bbis H2O from L -Pad Lake for total= 7,295 bbis Hauled 0 bels H2O from B -Pad Creek for total = 675 bbis Hauled 490 bbls H2O from G&I Healed for total = 780 bbls Hauled 918 bbis cuttings/liquids to G&I for total = 9980 bbis 9/10/2018 WU RSS/UR BHA #3 w/ 8.5" SK616M-J7 D PDC bit, Geo -Pilot W/ STB, DM, DGR, ILS, EWR-P4, PWD, HCIM, TM, FS NP plunger, PC, UR, FS NP flapper, PC, FS NP flapper, IBS, 6-HWDP, Jar, 5-HWDP. = 696.39. (Bit to UR = 110'). Download MWD.;Pressure test goo -span to 3000 psi, Shallow test MWD, good, Break in geo-pilot bearings pumping 450 gpm, 890 psi, 40 rpm.;TIH 5" DS50 stds V 696to 2590' passing thru ESIPC @ 2508' w/ no issues, Fill pipe, test tools. Continue RIH ft 2590'to 7302' just above csg shoe filling pipe every 2000'. Correct displacement TIH.;M/U TD, Break circulation, 450 gpm, 1350 psi, get parameters, pumps on -PU 225K, $O 105K, ROT 145K @ 45 RPM 15K TO, SPR 1 & 2 pumps. Wash down and tag bttm @ 7394';Drill 8-1/2" hole f/ 7394' to 7505' pumping 500 gpm, 1550 psi, 60 rpm, 13-15k tq, web 10k, avg rop 74 fph. MW and Vis inlout 9.5140, ECD 10.4.;Circulate open hole clean, P/U to 7486', break connection drop 1 318" steel ball, S/O to 7499, pump 350 gpm, 930 psi, rotate 60 rpm, 15-17k tq, at 840 stks, press drop to 880 psi, increase pump to 500 gpm, 1470 psi @ 130 psi drop, turbine rpm 3200, drop to 2846, ream to bttm, pull test 15k over;Drill 8-12" x 9-7/8" hole f/ 7385' V 8053' (83.5 AROP) wl 600 GPM, 2190 PSI, 80-140 RPM, 13-19K TO, 20-22K WOB. Mud in 9.5 ppg 46 vis, out 9.5 ppg, 46 vis. 11.02 ppg EMW ECD. PU 205K, SO 105K, Rot 148K. Observed high -full stall levels of stick slip. Varied surface parameters with no reduction After speaking w/ the drilling engineer, added 776 tube to the mud at 7780'. After adding 4 drums (0.6% system concentration) stick slip reduced to medium to none. ROP also increased from 807h r. to 1507hr. Max gas 68 units. Pumped tandem sweeps @ 7962'w/ 50% increase observed @ the shakers.;Drill 8-112" x 9-7/8" hole f/ 8053' V 8620' (94.5 AROP) w/ 600 GPM, 2390 PSI, 140 RPM, 16-17K TO, 16-22K WOB. Mud in 9.7 ppg 45 vis, out 9.7 ppg, 51 vis. 11.24 ppg EMW ECD. PU 215K, SO 107K, Rot 148K.;Last survey @ 8495.01' MD I 5286.46 TVD, 59.37° Inc., 16.22° azm. 6.28' from plan, 4.1' high & 4.75' Ieft.;Hauled 420 bola H2O from L -Pad Lake for total = 7,715 blols Hauled 0 bbis H2O from B -Pad Creek for total = 675 bole Hauled 490 bbis H2O from G&I Heated for total = 780 bbis Hauled 57 bbis cultings/liquids to G&I for total = 10,037 bbis 9/118018 Drill 8-1/2" x9-7/8!' hole f/ 8620' V 9088' (78 AROP) back ream lower 112 stds. 600 GPM, 2450 PSI, 140 RPM, 17-18K TO, 20K WOB. Mud in 9.7 ppg 46 vis, out 9.7 ppg, 51 vis. ECD 11.21. PU 230K, SO 105K, Rot 151K. Max gas= 115. Pumped sweeps at 8525'&9000', dumped to rock washer.;Drill 8-1 /2" x 9-718" hole f/ 9088' V 9471' (63.8 AROP) back ream lower 1/2 stds. 600 GPM, 2660 PSI, 140 RPM, 14K TQ, 14K WOB. Mud in 9.5 ppg 56 vis, out 9.6 ppg, 59 vis. ECD 11.32. PU 200K, SO 130K, Rot 161 K. Max gas = 62. Pumped sweep at 8525' & 9000', dumped to rock washer.;Drill 8-18" x 9-718" hole f/ 9471' V 9846' (62.5 AROP) back ream lower 1/2 stds two times. 600 GPM, 2860 PSI, 140 RPM, 16K TQ, 17-18K WOB. Mud in 9.5 ppg 57 vis, out 9.6 ppg, 63 vis. ECD 11.42. PU 210K, SO 132K, Rot 166K. Max gas = 48. Pumped sweeps at 9471', dumped to rock washer.;Drill 8-112" x 9-7/8" hole V 9846'V 10035' (47.5 AROP) back ream lower i8 stds two times. 600 GPM, 3050 PSI, 140 RPM, 19-20K TQ, 18-20K WOB. Mud in 9.55 ppg 61 vis, out 9.65 ppg, 37 vis. ECD 11.38. PU 235K, SO 133K, Rot 172K. Max gas = 51.;Last survey at 10004.14' MD / 6246.12' TVD, 30.32° inc., 16.00° azm. 8.62' from plan, 1.4' high and 8.5' Ieft.;Circulats prior to weighting up & installing MPD RCD. Pump tandem sweeps, dumped to rock washer. Circulate a total of 2.5x bottoms up. 600 GPM, 2905 PSI, 60 GPM, 8K TQ, 10.94 ECD.;Hauled 720 bbls H2O from L-Pad Lake for total = 8,435 bbls Hauled 0 bbls H2O from B-Pad Creek for total= 675 bbls Hauled 0 bbls H2O from G&I Heated for total= 780 bbls Hauled 610 bbls cutfings/liquids to G&I for total = 10,847 bbls 9/12/2018 Shut down pumps and monitor well. Static. R/U MPD head on stand and install.;Perform all checks on MPD system taking returns through MPD to flow line. Good. Work parameters up to 600 GPM. Getting 90 PSI line friction from MPD. MW 9.5+ECD&back pressure 11.2 clean hole.;Drill 8-18" x 9-7/8" hole F/10035' T/ 10275' (53 AROP) back ream lower 112 stds. 600 GPM, 2920 PSI, 140 RPM, 24K TQ, 20K-22WOB. Mud in 9.5 ppg 46 vis, out 9.6 ppg, 51 vis. ECD 11.38. PU 230K, SO 105K, Rot 151 K. Max gas 49. Hold back pressure during conections to maintain 11.38 ECD. 550-580 PSI;Start adding black product as we drill ahead.;Drill 8-18" x 9-718" hole'110275' T/ 10510'(39 AROP) back ream lower 18 stds. 600 GPM, 3020 PSI,140 RPM, 19-20K TQ, 19K-20WOB. Mud in 9.5 ppg 50 vis, out 9.6 ppg, 56 vis. ECD 11.54. PU 253K, SO 118K, Rot 135K. Max gas 42.;Hold back pressure during drilling & conections to maintain 11.5 ECD. 560-575 PSI. Began observing 10 BPH losses at 10439 MD. Losses increased to 30 BPH at 10505' MD. Reduce MPD to 11.3 ECD.;Drill 8-18" x 9-7/8" hole F/10510' T/ 10699 (32 AROP) back ream lower 112 stds. 600 GPM, 2940 PSI, 140 RPM, 20K TQ, 16K WOB. Mud in 9.5 ppg 56 vis, out 9.5 ppg, 63 vis. ECD 11.37. PU 255K, SO 141 K, Rot 182K. Max gas 68. Losses 10 BPH.;Hold back pressure during drilling & conections to maintain 11.3 ECD, 605-610 PSI. Began adding background LCM @ 10560'.5 ppb nut plug fine & 5 ppb SafeCarb fine. HRZ at 10548' MD / 6745' TVD, Kalubik @ 10615' MD 16808! TVD. Geologists called TD and drilled to ft casing to 10699 MD / 6887' TVD.;Last survey at 1066.05' MD / 6856.30' TVD, 20.17° inc, 15.93' azm. 2.43' from plan, 0.06' low, 2.43' IeR;Drop 1-7/8" steel ball to deactivate NOV Anderreamer. Chase with 100 GPM, 1000 PSI. Chase with tandem low vis / high vis, weighted sweeps. Ball seated at 566 stks and pressured up to 2580 PSI to shear pins & shift grapple to lock reamer closed.;Circulate out sweep & dump to rock washer. Continue to circulate 6x bottoms up, 37000 stks. 600 GPM, 3020' PSI, 120 RPM, 17k TQ. Quadrant ream lower 110' with Geo-Pilot deflected to enlarge 8-18" hole. No losses starting at 02:00, stop LCM. 10 BPM losses at 04:00, resume LCM.;As hole cleaned up, MPD backpressure had to increase from 80 to 160 PSI to maintain 11.3 ppg ECD. Obtain slow pump rates. PJSM w/ all parties for tripping with MPD.;Short trip from 10699'to 10575'. Hold 640' PSI static, 720' psi dynamic w/ MPD to maintain 11.3 EMW & counter swab. Initially began with 840 psi but was injecting. 9/M2018 POOH F/ 1063V T/ 10321' (Above HRZ) on elevators at 5 Min per stand. RIH to btm no issues. Holding back pressure with MPD to maintain 11.3. Had to back off back calculated pressure to control Iosses.;Break circ & stage up pumps to 600 gpm, 120 RPM, holding back pressure at 11.3. Monitor losses at 5-10 BPH. Conduct PJSM & begin to wt up the system in 3/10 increments per circulation. Bring up active system to 9.8 & circ around. Slowly drop GPM to match ECDs at 11.3 as wt increases.;Pump rate down to 2 BPM due to losses at+/- 50 BPH while pumping final spike fluid bringing wt from 10.1 to 10.8. MPD choke full open. No losses at 2 -2.5 BPM. Continue to circ once 10.8 in and out treating heavy and light spots. Total losses while bringing up wt = 71.5 bbls;Spot 32 bbi liner running pill from 10699'to 10361, across and above the HRZ. 2-2.5 BPM, 540 PSI, 120 RPM, 18K TO. MPD choke full open, calculated 11.3 ppg ECD;Shut down pumps, bleed off pressure and perform flow check with 10.8 ppg mud and no back pressure. 30 min. flow check had slight breathing. 1/4 bbl total returns over 30 min. and rate slowed to trickle. Blow down top drive and line back up on MPD.;POOH from 10695'to 7301' on elevators, pulling 5 min/stand as per MPD schedule, speed up to 4 min/stand. Maintain 200 PSI static, 275-330 PSI dynamic backpressure w/ MPD to maintain 11.3 ppg EMW. No overpull observed pulling BHA into the 9-5/8" casing shoe. 310k PUW. 130k SOW.;Bleed off MPD back pressure and open lines. Perform 10 min. flow check - static. Close MPD lines, start pump and hold 200 PSI static for 11.3 ppg EMW.;POOH from 7301'to 4856' on elevators, pulling 5 min/stand as per MPD schedule, speed up to 2 min/stand. Maintain 170-200 PSI static, 260-290 PSI dynamic backpressure w/ MPD to maintain 11.3 ppg EMW. 225k PUW, 110k SOW.;Hauled 190 bbls H2O from L-Pad Lake for total = 9,045 bbls Hauled 0 bbls H2O from B-Pad Creek for total= 675 bbls Hauled 0 bbls H2O from G&I Heated for total= 780 bbls Hauled 795 bbls cuttings/liquids to G&I for total = 12,512 bbls 148 bbls daily losses, 195 bbls total for interval. 9/14/2018 POOH F/ 4856'T/ 795 on elevators, pulling 2 min/stand as per MPD schedule. Maintain 170-200 PSI static, 260-290 PSI dynamic backpressure w/ MPD to maintain 11.3 ppg EMW.;Bleed off Dynamic Pressure & Monitor well at HWDP. Well breathing at 2.34BPH & slowed to .8 BPH in 30 Min. R/D MPD head & install riser. Fill stack and test for leaks. Good.;Stand back HWDP F/ 795' T/ Anderreamer. Clean and inspect. Looks good. Continue to UD BHA to MWD. All BHA looked good. No visable damage. Down load MWD & UD same. Break out bit from Geopilot & UD same. Bit grade- 1-1-WT-A-X-1-PN-TD;Clear and clean rig floor. Pull wear bushing, Monitor well. Breathing .89-1.37 BPH.;Change top rams to T' & install lower test plug to test rams. Test to 250 / 4000 psi. Monitor well & breathing @ 1.2 BPH slowing down to 0.5 BPH.;R/U Volant CRT, bail extensions, 7" elevators and spiders.;WU 7" casing shoe track: float shoe jt., BakerLoc spacer jt., float collar jt. & jt#1. Bakerl-oc first 3 connections. Torque to 14,750 ft/fibs. Pump through shoe track @ 5 BPM. P/U and check floats - holding. Two 7"x8-12' centralizers on shoe joint, one on spacer, float and jt #1 w/ 8 stop rings;Run 7" 26# L-80 TXP casing from 166'to 3701, joint#87'. Torque to 14,750 flU bs. 7x8-12" centralizers on joints #2-10 & #78-80.. Run at 40'-60'/min. with good displacement.;Hauled 195 bbl; H2O from L-Pad Lake for total = 9,045 bbis Hauled 0 bbis H2O from B-Pad Creek for total= 675 bbis Hauled 0 bbis H2O from G&I Heated for total = 780 bbis Hauled 0 bola cuttings/liquids to G&I for total = 12,512 bbis 9/15/2018 Run T'26# L-80 TXP casing F/3701 T/ 6369, joint #87'. Torque to 14,750 ft/lbs. Run at 40'-60'/min with good displacement until after 5000'. MPD running sheet showed ECDs over 11.3 after 5000' and thats when we started pushing fluid away.;Slowed down but still loosing. Continue running at 40-60'/min.;Break circ at 582U with full returns at 1 bpm.;Run 7" casing F/ 6369' T/ 7319. Fill pipe on the fly and top off every 10 joints. Torque to 14,750 ft/lbs. Run at 40'-60'/min.;Break circ at 0.5 BPM/ 320 PSI, inc to 1 BPM / 380 PSI, 3 BPM 1330 PSI then 3.5 BPM / 300 PSI. Reciprocate F17319 T/ 7360'. 185K PUW, 112K SOW. Lost 15 bbl while getting cifc.;Run T' casing F/ 7319'T/ 10450'. Fill pipe on the fly and top off every 10 joints. Torque to 14,750 ftAbs. Run at 40'-60'lmin ;After filling pipe, observed 19.2 bbis losses for the previous 10 joints. Attempt to establish circulation w/ 70 to 90% losses. Mix & pump 15 bbl LCM pill w/ 10 ppb nut plug fine & 10 ppb SafeCarb 20. Establish circulation w/ 1.5-2 BPM on the upstroke and 0-5 BPM on the down stroke.;Observed complete loss of returns. Attempt to circulate at 0.4 BPM while static, no returns. Continue to pump 1.5 BPM on the upstroke and no flow on the down stroke. Unable to est. circulation. Consult drilling manager, will run to bottom and cement. 275K PUW, 125K SOW. Lost 240 bbis while circ.;MPD hydraulics showing ECDS at 11.55 @ 30 GAL per Min. Well unable to hold over 11.3.;Run 7" casing F/ 10454 T/ 10655'. Fill pipe on the fly and top off every 10 joints. Torque to 14,750 ft/lbs. Run at 5'/min. to minimize surge through HRZ. No set downs.;Hauled 95 bbis H2O from L-Pad Lake for total = 9,335 bbis Hauled 0 bbis H2O from B-Pad Creek for total= 675 bbis Hauled 0 bbis H2O from G&I Heated for total = 780 bbis Hauled 160 bbls cuttings/liquids to G&I for total = 12,672 bbis 9/16/2018 MIU 7" casing hanger and landing joint. Land 7" casing string at 10689'w/ 80K on hanger. R/D Volant casing running tool and R/U Halliburton cement head & Lines.;PJSM on cmt job , while circ at.25 BPM at 200 psi with 100% Iosses.;Line up to Halliburton & Pump 5 BBL water, Test lines to 1000/ 4500 PSI. Good. Balch up 10.5 Clean Spacer & pump 25 bbl @ 2 BPM, 350 PSI.. Drop btm Plug,Pump 36 Will 80 SX 15.8 ppg, ExtendaCem Cmt @ 4 BPM, 285 PSI, Drop top plug. Halliburton pump 20 bbl H2O @ 1.3 BPM, 70 PSI to clean Iines.;Had to shut down while pumping cmt due to bulk cmt issues 100% losses during the job. No returns.;Line up to Rig and pump 3822 strks at 4 bpm with final lift at 2 bpm 580 psi. Bump on calculated stks. Displace with 10.8 PPG mud for 360 bbl then swap to 10.6 ppg. Pressure up- to 500 over final pressure. Hold 1200 psi for 5 min. Good. Bleed off 2 bbl and check floats. Good. CIP 11:05.;Drain stack, R/D cmt head, Back out landing joint and WU pack off. Run pack off & test to 250/5000 psi. 10 min.;Clean and clear the rig floor of cmt equipment and Doyon casing equipment. Prep floor to UD OP. UD 15 joints DP in mouse hole. Clean mud pits.;Change top rams from 7" back to 2 7/8 X 5". Change lower jaws on the ST-80.;Contiue to UD 5" Dip in the mouse hole. Inspect and mark joints with bad hardband. UD 61 stands. Unable to break one connection w/ steam and 52K torque, set aside. Sim ops: freeze protect OA w/ 65 bbis diesel. 1000 PSI @ 1 BPM. 600 PSI @ 05:00 9/17/18.;Continue to UD 5" Dp in the mouse hole. Inspect and mark joints with bad hardband. UD 46 stands.;Change top drive saver sub to 4" XT-39;Hauled 440 bbis H2O from L-Pad Lake for total = 9,775 bbis Hauled 0 bbis H2O from B-Pad Creek for total= 675 bbis Hauled 0 bbis H2O from G&I Heated for total = 780 bbls 9/17/2018 Continue to C/O saver sub on top drive to 4" XT-39. Mobilize 4" drill pipe handling equipment and safety valves.;R/U BOP test equipment. Install upper lest plug and 2-7/8" test joint. Fill stack and choke manifold with water and perform shell test.;Test BOP equipment as per PTD and AOGCC test requirements. Test annular on 2-7/8" test joint to 250/2500 PSI. All other tests to 250/4000 PSI. All tests with held for 5 min. each. Test 2-78"x5" VBR LPR on 2-7/8" & 4-1/2" test joints. Test 2-7/6'6" VBR UPR on 2-7/8", 4" & 4-112" test joints.;Test 14 choke valves, upper & lower IBOP, dart valve, FOSV, manual & HCR choke & kill valves, manual & hydraulic chokes. Test gas, PVT &flow alarms. Accumulator: 3000 PSI system, 1700 PSI after closure, 46 sec. 200 PSI recovery, 185 sec. full recovery, 6 bottles @ 2008 PSI.AOGCC inspector Bob Noble waived witness at 07:23 on 9/17/2018. On rig and camp generator power at 13:15, due to MPU L-pad power upgrades.;R/D test equipment. Pull test joint and test plug. Install 7" I.D. wear bushing. Blow down choke manifold, choke and kill Iines.;Break over torqued connections on stand of 5" drill pipe. Heat to 150° with steam, install new dies in ST-80 then broke free. Pressure test MPD line which was removed for the cement job to 250/1500 PSI.;P/U 30 joints of 4" XT-39 drill pipe from the pipe shed. Drift with 2.30" and torque to 22,000 ft/lbs. Rack back 10 stands in the derrick.;Slip and out drilling line. Service the rig-top drive and draw works.;M/U BHA #4 to 137'. 6-118" NOV/Hycalog SK613M-V3 bit, 5200 Geo-Pilot, MWD with directional, EWR-SP4, PWD, ALD and CTN and one drill collar Confidence test and initialize MWD tools. SPT MWD (too low of SPP for detection) then load logging sources. P/U drill collars and HWDP to 183';Hauled 240 bbls H2O from L-Pad Lake for total = 10,015 bbis Hauled 0 bbis H2O from B-Pad Creek for total= 675 bbls Hauled 0 bbis H2O from G&I Heated for total= 780 bbis Hauled 233 bbis cuttingslliquids to G&I for total = 13,128 bbis 9/18/2018 P/U 4 3/4 Flex Follars, 6 Joints 4"HWDP, Jars, 11 Joints 4"HWDP & Single in on 4" DP from pipe shed T11383'.;PJSM, Perform EMD training with crew. Install MPD rotory head, Break circ, Make two conections & RID same with new crew. Install Trip Nipple.;Continue to PIU 4" DP F/ 1291'T/ 2605". Filling DP every 2500'. Put rig back on High line at 1130.;Sewice the rig;Continue to PU 4" XT-39 DP from 2605'to 3019'. Filling the DP every 2500'.;Break in the Geo Pilot. Circulate at 52 GPM = 230 psi. Rotate at 20 RPM = 2K ft-lbs torque, 30 RPM = 2K ft-lbs torque and 40 RPM = 2K ft-lbs torque. Circulate at 230 GPM = 1060 psi. PU = 85K, SO = 75K and ROT = 75K.;Confinue to PU 4" XT-39 DP from 3019' to 8559. Filling the DP every 2500'.;TOOH standing back DP from 8559' to 7812'.;Confinue to PU 4" XT-39 DP from 7812' to 10354'. Filling the DP every 2500'.;Break circulation and slower bring the mud pumps up to 200 GPM =1640 psi. Continue to circulate and condition the mud until uniform weight in/out while reciprocating the DP from 10354! to 10322'. PU = 195K and SO = 98K.;Blow down the top drive. RU the head pin, cement hose and testing equipment.;PT the T' casing to 3700 psi for 30 minutes (good test).;RD testing equipment.;Wash down at 200 GPM = 1080 psi to tag on cement 10572'. Turn on the rotary at 40 RPM =10K ft-Ibs. Drill cement stringer to tag on the float collar at 10604' (PU = 210K and SO = 95K). Drill float collar to 10607' at 200 GPM = 1080 psi, 60 RPM= 11K, WOB =10K. 9/19/2018 Continue to drill cmt F/ 10607' T/ 10687'. 5-15 WOB, 60 RPM 190-230 GPM. Drill Shoe on depth at 10687-10689' ;Drill Rat hole at 5-15K WOB, 220 GPM, 1380 PSI, F/ 10689'T/ 10699'. Drill New hole F/ 10699' T/10719'.;Circ sweep around & condition mud for FIT. MW= 10.1 ppg.;RU tesfing equipment. Perform FIT to 13.5 ppg. Pressure up to 1220 psi in 22 strokes and hold for 12 minutes. Bleed to 0 psi and got 2 bbls back.;Blow down and RD testing equipment.;Pump 15 bbl hi vis sweep and displace the well to 11.5 ppg LNSD mud taking returns to the rock washer.;PJSM. Remove the air boot and trip nipple. Install bearing assembly. Inspect the line upon the MPD and install the flow line plug.;Break circulating and stage the pumps up to 250 GPM = 2010 psi, 60 RPM= 101(ft-Ibs torque. Drill from 10719 to 1074T (24', AROP = 6.8 FPH). 60 RPM= 10-12Kft-lbs torque, 250 GPM = 2220 psi, WOB = 5-15K. MW= 11.5 ppg, Vis = 41, ECD = 12.98 ppg, Max gas= 31 units.;Continue to drill from 10743' to 10784'(41', AROP = 11.7 FPH). 80 RPM= 11-12K ft-lbs torque, 250 GPM = 2220 psi, WOB = 5-1 SK. MW = 11.5 ppg, Vis = 40, ECD = 12.92 ppg, Max gas = 36 units. PU = 223K, SO = 90K, ROT = 145K. Pumped two 10 bbl and one 20 bbl sweep with nut plug/deep clean.;Continue to drill from 10784to 10821' (37', AROP = 14.8 FPH). 120 RPM = 11-12K ft-lbs torque, 250 GPM = 2120 psi, WOB = 5-15K. MW = 11.5, Vis = 37, ECD = 12.90 ppg, Max gas= 25 units.;Cominue to drill from 10821' to 10856', 7031' TVD (35', AROP = 10 FPH).140 RPM= 11-12Kft-lbs torque, 250 GPM = 220 psi, WOB = 10-12K. MW = 11.5, Vis = 36, ECD = 12.81 ppg, Max gas = 20 units.;W hila making the connection the DP float would not hold therefore unable to perform beyond draw down test.;Hauled 55 bbls H2O from L-Pad Lake for total = 10,190 bbis Hauled 0 bbls H2O from B-Pad Lake for total = 675 bbls Hauled 0 bbis H2O from G&I Heated for total= 780 bbls Hauled 347 bbis Cultings/Liquids to G&I for total= 13,590 bbls;Last survey at 10796 MD, 6978' TVD, 20.04° Inc, 18.34° Az. Distance to Well Plan #10 =1.72' (0.12' low and 1.72' left). 9/20/2018 Performed a pore pressure drawdown at 10856' as per Geologist with 11.5 Poo MUD in the hole. During a connection the rig pump was brought offline and 375 psi pressure was trapped on the MPD choke.;The pressure was staged down in 50 psi decrements to see if the well would begin to flow and build the backup. The choke pressure was reduced to 15 psi and no observation of underbalance was noted.;Drill ahead 61/8 Hole F/10856' T/ 10997'. Still slow drilling. AROP = 16.6 FPH. Trying different parameters but unable to get high ROPS. 80-140 RPM, 5-20 WOB, 190-250 GPM. ECDs while drilling with full open choke and MW at 11.5 is 12.8 -13 ppg.;Performed a pore pressure drawdown at 10997' as per Geologist. During a connection the rig pump was brought offline and 375 psi pressure was trapped on the MPD choke. In 5 min the pressure dropped to 350 psi. The pressure was staged down in 50 psi increments to see if the well would begin3o flow and build the pressure back up. The choke pressure was reduced to 15 psi and no observation of underbalance was noted. Talked to Drilling engineer and decided to drop MW to 11 ppg while drilling ahead and holding an 12-12.3 PPG ECD.;Drilling ahead while reducing MW to 11.0 ppg. Had to run minimum flow rates 190 GPM while drilling due to ECDS at 12.8 with full open choke. Drill ahead F/ 10997' TI 11007' with AROP = 10 FPH. Broke through into Kuparuk C & ROP picked up to 50-80 FPH.;Drill ahead F/11007'T/11 145', 7306' TVD (138', AROP = 27.6 FPH). 190 GPM, 1635 PSi, 10-15 WOB, 140 RPM= 8K TQ. Cutting MW back to l l ppg as we drill. Holding 12 PPG ECD on well during connections with MPD.: Perform pore pressure drawdown test at 11145' with MW at 11.0 ppg. Bring the pump offline with 300 psi trapped on the MPD choke. Staged the pressure down in 50 psi increments until the choke was fully open with no observations of underbalance. Reduce MW to 10.5 ppg.;Drill ahead while reducing the MW to 10.5 ppg. Continue to drill from 11146 to 11268'(123', AROP = 17.6 FPH). 140 RPM= 7-10K ft-Ibs torque, 220 GPM = 1650 psi, WOB = 7-20K. MW= 10.5 ppg, Vis = 37, ECD = 11.63 ppg, Max gas = 134 units. PU = 215K, SO= 98K, ROT= 144K.;Observed slight seepage with 11.7 ppg ECD.;Hauled 40 bbis H2O from L-Pad Lake for total= 10,190 bbis Hauled 30 bbis H2O from 6-Mile Lake for total= 30 bbls Hauled 0 bbis H2O from B-Pad Lake for total = 675 bbls Hauled 0 bbis H2O from G&I Heated for total= 780 bbls Hauled 338 bbis Cuttings/Liquids to G&I for total= 13,928 bbls;Last survey at 11 171'MD, 7331' TVD, 18.96° Inc, 11.29° Az. Distance to Well Plan #10 = 5.22' (0.31' high and 5.21' left). 9/21/2018 Continue to drill from 1126V to 11301', 7453' TVD (33', AROP = 5.5 FPH) 140 RPM=12-13K ft -lbs torque, 217 GPM = 17( ppg, Vis = 37, ECD = 11.5 ppg, Max gas = 3 units. PU = 220K, SO= 100K, ROT= 137K.;Continue to drill from 11301' to 1' FPH). 140 RPM =10K ft -lbs torque, 217 GPM = 1760 psi, WOB = 15-20K. MW = 10.0 ppg, Vis = 38, ECD = 10.85 ppg, Me 100K, ROT= 137K.;Hauled 185 bbls H2O from L -Pad Lake for total= 10,375 bbls Hauled 0 bbls H2O from 6 -Mile Lake for total= 30 bbls Hauled 0 bbls H2O from B -Pad Lake for total = 675 bbis Hauled 0 bbls H2O from G&I Heated for total= 780 bbls Hauled 328 bbls Cultings/Liquids to G&I for total= 14,256 bbls;TD survey at 11330' MD, 7480' TVD, 20.12° Inc, 16.25° Az. e11 .330 VOB = 15-20K MW = 10.1 480' TVD (29, AROP = 5.3 17 units. PU = 220K, SO = Distance to Well Plan #10 = 6.26' &Sii±zRate Ops Summary 9/21/2018 Details on drilling report., Pump 20 bbl hi vis sweep and circulate out of the well. Observed a 80% increase in cuttings. CBU to ensure the well was clean. 250 GPM = 1850 psi, rotating at 70 RPM and reciprocating 90'.,Observe the well for flow and the well is static. PJSM for TOOH using MPD.,Lay down two single joints of DP. TOOH with BHA #4 from 11330' to 7" casing shoe at 10689 while holding 150-250 psi back pressure with MPD. Did not observe any over pulls.,CBU at 250 GPM = 1830 psi, 80 RPM= 11 K ft -lbs torque and ROT= 139K. PU from 10689' to 10636. Observe the well for flow and the well is static., Blow down the top drive. Drop 2.34" OD drift on wire down the DP.,TOOH from 10635'to 6033' while holding 150-250 psi back pressure with MPD. Floats are not holding therefore having to MU the top drive with IBOP closed to TOOH with back pressure. At connection MPD pressure is bleed off to prevent back flow from the DP. 9/2212018 POOH F/ 6035 T/ 757', Holding pressure with MPD to compensate the swab. Pull at 3 Min per stand. Floats leaking so TD had to be kellyed up on each stand -Monitor well at HWDP. R/D & remove RCD bearing & install trip nipple.,UD HWDP jars & NMFC, F/ 757'T/ 168'.,PJSM, Remove Nuclear sources. Down load MWD. UD BHA & Bit. Bit Grade = 1 -1 -WT -A -X -1 -NO -TD. Lost 4 bible during the TOOH-Clean and clear the rig floor.,RU power tubing tong. Mobilize handling equipment to the dg floor and RU. MU crossovers to the TIW.,PJSM. PU and MU float shoe, float collar and landing collar. Fill the shoe track with mud and check the floats (good). RIH with 4-1/2", 12.6#, L-80, TXP liner torqued to 6170 ft -lbs installing centralizers on every joint to 794'.,Change elevator. PU and MU the liner hanger/liner top packer. Pour Zanplex and water into the tieback sleeve. MU DP crossover and 1 stand of 4" XT -39 DP. RIH to 838', break circulation at 2 BPM = 100 psi and circulate a liner volume.,TIH with 4-1/2' liner on 4" XT -39 DP from 838' to 10645'. Filling DP on the fly, topping off every 10 stands.,Circulate liner volume and DP volume at 4 BPM = 680 psi.,Rig Fuel (gallons): OH = 4410, Used = 475 &Rec = O Daily losses to the formation = 4 bbis Total losses to the formation = 4 bbls,Hauled 50 bbis H2O from L -Pad Lake for total = 10,425 bible Hauled 50 bbls H2O from 6 -Mile Lake for total= 80 bible Hauled 0 bbis H2O from B -Pad Lake for total = 675 bbis Hauled 0 bbls H2O from G&I Heated for total = 760 bible Hauled 198 bbis Cuttingsil- quids to G&I for total = 14,454 bbis 9/2312018 R/D RCD Lines and turn head on stack to fit mouse hole. Install mouse hole-,RIH F/ 10619' T/ 10 865'. Set down several times. Getting tight. Break circ & stage up pumps to 3 bpm, Fighting pack off & loosing hole. POOH while circ T/ 10766'. Find good free spot & shut down pumps. Work Pipe down past tight spots with no pumps and 10 RPM 5K tq. Pipe stalling if not moving. making hole each time F/ 10778' T/ 10875'. RIH F/ 10875 with no rot. Working through set downs on elevators T/ 11303'.,P/U cmt head on single & M/U circ hoses. Kelley up & break circ staging up pumps to 3 bpm. Washing down with set downs 7111303' T/ 11323'. Circ & condition while conducting PJSM., Lineup to Halliburton and fill Lines with H2O. Test to 4500 PSI. Lineup down hole, Mix & pump 30 bbl 13.5 ppg Mud push, 25 bbl lead 15.8 CMT. Line up to wash up line and wash up Halliburton lines. Blow down lines to Halliburton and R/D lines to cmt head. Line up on TD & displace with rig at 3 bpm. Caught pressure at 13 bbl away. Saw latch at 109.7 BBL , Bumped Plug @ 120.4 BBLs. Pressure up to 2600 psi. CIP @ 1608.,Set down to 50K. Set hanger. Good. Pressure up to 4000 psi with the mud pumps to release the running tool. Bleed down and check floats. Bled back 1 bbl. No losses during pumping cmt or displacing.,P/U to verified release. No release. Work several times setting down T/ 50K & working wt up to 210K. Unseat hanger attempting to release. Pressure up to 2600 & slack off. Set hanger. Good. Set down to 50 K & Pressure up to 4700 psi. Bleed down. P/U to see if mare released. No go. Work wt up to 215. Liner still moving.,Attempt to emergency left hand release. Work left had releasing procedure as per baker for 1 hr working from 3K to 5k. Attempt to pressure up to set hanger again and gained circ. Backed off something down hole. Turn to the right 10K & regain pressure to 2600 psi. Slack off and set hanger. Good. Work pipe with 2500 psi and attempt release with left hand tq. No go. Pressure up to 4200 psi.,Continue to work pipe while lining up the test pump to pressure up to 5K. PIU to 243K, lost 100K & gained circ.,Line the pump backup and circ at 10 BPM 3500 psi. Circ out spacer and cmt on calculated strokes while working pipe up. Still over pulling like we have the liner or the running tool is dragging. Shut down when we got Good mud back. Shut down and UD the double and the cmt head.,POGH pulling 215-250K. Work pipe down at 100 K with no drag like we are in cased hole. Kelley up & circ at 3 bpm, 600 psi. Continue to pull pipe not pulling over 250K and work pipe through drag spots F/ stand 111 to -15 upon stand 109.,Work the DP 20' while pumping 3 BPM = 600 psi, PU to 250K and SO to 60-100K. Getting shale across the shakers. PU to 275K and pulled free, PU = 190K. End of the DP at 10210'., Pump 20 bbl hi vis sweep at 10 BPM = 2600 psi and circulate out (90% increase in cuttings). Observe the well for flow and the well is static.,TOOH on elevators from stand 109 to surface. Recovered the entire liner running tool.,Inspect, break down and lay down the liner running tool. Observed some wash marks on the top of RS pack off, packing missing on the RS pack off and some damage on the slick stick -Clean and clear the rig floor.,Rig Fuel (gallons): OH = 6650, Used = 435 & Rao = 2676 Daily losses to the formation = 0 bible Total losses to the formation = 4 bbls,Hauled 135 bible H2O from L -Pad Lake for total = 10,560 bible Hauled 0 bbis H2O from 6 -Mile Lake for total= 80 bible Hauled 0 Icicle H2O from B -Pad Lake for total = 675 bible Hauled 0 bbis H2O from G&I Heated for total = 780 bible Hauled 315 bbis Cuttings/Liquids to G&I for total = 14,769 bbls 9/2412018 Mobilize bit, bit sub and scraper to the rig floor. PU cement head and break off the crossovers.,MU 6-1/8" Baker STX-1 tri -cone bit , bit sub, crossover, 7" casing scraper, bit sub with float, 3 joints 4" HWDP, combo jars, 9 joints 4"HWDP (409').,TIH with cleanout assembly from 409' to 10008', filling every 20 stands and checking each connection (PU = 180K and SO = 100K).,Wash down at 7 BPM = 1400 psi from 10008'to tag on top of the liner top packer at 10262' with 3K down. PU, rotate at 20 RPM = 8K ft -lbs torque, 8 BPM = 1600 psi and tag at 10262' with 9K down. Getting some shale across the shakem.,Pump 20 bbl hi vis sweep and circulate out at 9.5 BPM = 2100 psi, rotating 20 RPM = 8K ft -lbs torque and reciprocating 60' (10258' - 10196'). Observed 10% increase in returns. RIH with no pumps and tag the top of the liner top packer at 10262' with 15K down.,Obtained SPR at 10258' with 10.0 ppg mud: MP #1 - 30/40 SPM = 540/700 psi / MP #2 - 30140 SPM = 540/680 psi3Observe the well for flow and the well is static. Blow down the top drive.,TOOH with cleanout assembly from 10196' to 4091.,Lay down 4" HWDP, combo jar and cleanout assembly.,PU and MU tie back receptacle (TBR) polish mill, spacer sub, pack off, TBR top dress mill and crossover.,TIH with polish mill/pack off assembly from 20' to 7937'.,Rig Fuel (gallons): OH = 8355, Used = 369 & Rao = 2074 Daily losses to the formation = 0 bible Total losses to the formation = 4 bbis, Hauled 15 table H2O from L -Pad Lake for total = 10,575 bible Hauled 0 bbis H2O from 6 -Mile Lake for total= 80 bible Hauled 0 bbls H2O from B -Pad Lake for total = 675 bbis Hauled 0 table H2O from G&I Heated for total = 780 bbls Hauled 0 bbIs Cuttin s/Li u'ds to G&I for total = 14,769 bbl 9/25/2018 RIH W/5.25" polish mill / pack off assembly on 4" DP f/ 7937' to 10178'. PU 185K, SO 97K, Correct displacement on TIH.,Obtain parameters, circ 1 bpm 400 psi, tag at 10260', set down 51k then 10k, PIU just above TOL @ 10256'. rotate 10 rpm, 7k tq. w/ 130 rot wt. S/O setting down 51k working to 10k, P1U 4' to neutral wt, set 10k working to 15k polishing liner top as per BOT rep., Polish TOL making 4 passes 5' into TOL to 10265' circulating at 3 bpm, 490 psi. PIU 4' above TOL, stop rotating, slow pump to i bpm, 360 psi, S/O tagging liner top 10260' setting down 10k, P/U 4' above TOL, rotate 10 rpm, S/O entering liner top to 10262', stop rotating.,S/O to 10267' with no issues, set down 10k as seals entered TOL., work to 15k down, R/U to pump down string, attempt to test 4 1/2" liner to 3000 psi, pump 4.3 bbls to 3000 psi, shut in, psi bled to 0, S/O 1.5' attempt to retest liner, pressure to 1600 psi @ /bpm seeing returns. R/D test equipment. Notify Engineer of results. Note: Swivel packing leaking., Rotate 20 rpm, 7-9k tq polishing TOL at 10260' making 4 passes, PIU to 10256. Change out swivel packing on top drive.,CBU pumping 10 bpm, 1820 psi with no increases at shakers. Rack back 1 stand parking at 10174'. Flow check well, static., PJSM. Slip and cut 79' of drilling line. Inspect the draw works, service the top drive and inspect the saver sub.,TOOH from 10174' to surface. Lay down the polish mill and pack oft assembly. Pack off assembly severely damaged. Lost 4.5 bbis during the trip., RU pressure testing equipment. Attempt to PT to 3000 psi but unable to get above 2700 psi at 2 BPM in 70 strokes (calculated strokes was 45 to reach 3000 psi). Shut in and pressure dropped from 2700 psi to 2000 psi in 3.5 minutes. Pumped 7 bbis and bleed back 7 bbls. RD pressure testing equipment and blow down choke/kill Iine.,Sewice break the polish mill and pack off assembly. Clear rig floor of Baker equipment. Mobilize 2-7/8" handling equipment to the rig floor. RU power tongs and MU crossover to TIW. PJSM. Clean the rig floor.,PU and MU 16 joints of 2-7/8", 10.4#, 5-135, HT Pac working string to 504'. MU crossover 4" XT 39 box x 2-7/8" HT Pac pin.,TIH with 2-718" cement stinger from 506' to 10259.,MU 5' DP pup, head pin and cement hose. Circulate and condition the mud staging the pumps up to 7 BPM = 1600 psi. SimOps: RU HES cementers., Rig Fuel (gallons): OH = 7980, Used = 375 & Rec = 0 Daily losses to the formation = 8.5 bbis Total losses to the formation = 12.5 bbls, Hauled 180 bbis H2O from L-Pad Lake for total = 10,755 bbis Hauled 0 bbis H2O from 6-Mile Lake for total= 80 bbis Hauled 0 bbis H2O from B-Pad Lake for total = 675 bbis Hauled 0 bbis H2O from G&I Heated for total = 780 bbls Hauled 0 bbis Cuttings/Liquids to G&I for total = 14,769 bbis 9/26/2018 Circulate and condition mud pumping 7 BPM = 1600 PSI at 10260'.,PJSM, pump 5 We 10.5 ppg clean spacer. Test lines to 50012500 psi f/ 5 min ea, good. Pump 19 bbis 10.5 ppg clean spacer ( 1.27 YP, 6.87 gps, 38.5 gpb H2O ) 2.5 bpm, 400 psi, followed w/ 22.5 bbis 15.8 class G cement @ 3.5 bpm, 450 psi 1.154 YP, 110 sx, 4.98 gps ). Pump 10.7 bbis clean spacer.,Wfth rig pump displace cement w/ 86 bbis 10 ppg LSND mud 8 bpm, 1750 psi, slow to 3.5 bpm 850 psi for last 10 bbls. R/D circulating hose and headpin. CIP @ 10:52 hrs. Estimated TOC @ 9671'.,M/U single previously UD, POOH 30/40 fpm f/ 10260' to 9441' racking 9 stds 4" DP in derrick. Install foam DP wiper ball. M/U top drive, pull to 9350'. Note: pipe dry POOH.,Circulate BU at 9350' pumping 8 bpm, 1620 psi. Flow check well, static, BD top drive. 30 bbis contaminated spacer dumped.,PGOH f/ 9350' to 505', UD XO, R/U 2 7/8 handling equipment, POOH UD 16 its 2 7/8 stinger.,C/O handling equipment f/ 2 7/8" to 4". PU and MU 3-112" perforated stack washing tool and crossover. TIH on 4" DP to 9316' (PU = 175K and SO = 90K). Correct displacement while TIH.,Wait on cement to reach 2000 psi compressive strength. SimOps: Continue to strap and tally 5" DP. Clear the rig floor of unneeded equipment. Service the top drive and draw works. General housekeeping around the rig.,TIH and tag top of cement in the 7" casing at 9590' with 5K down (soft cement). Stand back one stand. RU the head pin and cement liner. PT cement plug and 7" casing to 2000 psi for 30 minutes (good test). Blow down and RD testing equipment.,TOOH from 9505'to 8848'.,Rig Fuel (gallons): OH = 7600, Used = 380 & Rec = 0 Daily losses to the formation = 0 bbls Total losses to the formation = 12.5 bbls,Hauled 0 bbls H2O from L-Pad Lake for total = 10,755 bbis Hauled 0 bible H2O from 6-Mile Lake for total= 80 bbis Hauled 0 bbis H2O from B-Pad Lake for total = 675 bbls Hauled 140 bbis H2O from G&I Heated for total = 920 bbls Hauled 227 bbis Cuttings/Liquids to G&I for total = 14,998 bbis 9/27/2018 Continue to TOOH with stack wash tool from 8848' to surface. Lay down crossover and stack wash tool.,M/U 7" Baker K-1 mechanical cement retainer, setting tool and XO= 12.19' TI w/ 4" DP, 120 fpm, easy in and out of slips, being careful not to turn to right to setting depth @ 7833' (PU 145K, SO 90K). Set retainer on depth as per BOT rep and release running tool. Submit 24 hr BOP test notification to AOGCC @ 10:15 hm.,Rack 1 std back, park @ 7815', R/U and test T' casing & retainer to 2000 psi f/ 15 min charted (2.4 bbis pumped, 2.4 bbis bled back), good test. R/D test equipment. Blow down lines, Re-tag retainer on depth at 7833'.,TOOH from 7833' to 3311' racking back 49 stands, leaving 86 stands 4" DP in derrick, POOH LD remaining 105 joints 4" DP and running tool.,POOH laying down 105 joints of 4" DP. Lay down cement retainer running tool., PU and MU Baker multi string cutter (MSC), stabilizer and crossover.,TIH with MSC assembly from 11'to 78091.,MU the top drive and RIH to tag on cement retainer at 7833'. PU to 7760', attempt to locate collar at 0.5 BPM = 280 psi but unable to due to TXP being a shouldered connection. Position the MSC at 7786'turn on the rotary at 80 RPM = 5.5K ft-lbs torque, 4 BPM 1020 psi, cut the casing and saw a 200 psi drop. Shut down the rotary and slow the pumps to 0.5 BPM = 280 psi. PU 15', SO and set 5K on the cut.,Observe the well for flow and had slight flow up the IA. OA pressure 500 psi. Bleed the OA to 320 psi and the well was static.,Break out the top drive and stand 1 stand back and the well was out of balance (slight flow on the DP). CBU at 4 BPM = 960 psi. Observe the well for flow and the well is static.,TOOH with MSC from 7712'to 2181'.,Rig Fuel (gallons): OH = 7276, Used = 324 & Rec = 0 Daily losses to the formation = 0 bbis Total losses to the formation = 12.5 bbls,Hauled 20 bbis H2O from L-Pad Lake for total = 10,775 bbis Hauled 0 bbls H2O from 6-Mile Lake for total= 80 bbis Hauled 0 bbls H2O from B-Pad Lake for total = 675 bbis Hauled 0 bbis H2O from G&I Heated for total = 920 bbis Hauled 57 bbis Cuttings/Liquids to G&I for total = 15,055 bbis 9/28/2018 Continue to TOOH with MSC from 2181' to surface and lay down MSC assembly. Inspect cutters.,PJSM, Slip and cut 86' drilling line, re-calibrate block height. Inspect draworks and saver sub. Service top drive., Drain stack, Flush top of wear ring, Remove 7" ID wear bushing, install test plug. PJSM for C/O rams-Remove lower 2 7/8 x 5 1/2" VBRs, cleanout debris found behind ram, small pieces of fiberglass, cleanout same. Install 4 1/2" x 7" VBRs, open blind ram and upper ram doors cleaning out same.,PJSM, Install 5" test jt, close UPR. Flood stack, lines and choke manifold with water, Perform shell test to 250/4000 psi, 5 min ea. good.,Conduct initial BOPE test to 250/4000 psi: Lower pipe rams (4-1/2" x 7" VBR's) with 4-1/2", 5" and 7" test joints, upper pipe rams (2-718" x 5" VBR's) with 2-7/8", 4", 4-1/2" and 5" test joints, annular with 2-7/8" and 7" test joints to 250/2500 psi, accumulator drawdown test and test gas alarms. The test was witnessed by AOGCC inspector Matthew Herrera.,Tests: 1.UPR with 5" test joint, 3" kill, upper IBOP, choke valves 12, 13 & 14 (passed) 2.HCR kill, lower IBOP, choke valves 9 & 11 (passed) 3.Manual kill, 4" TIW, choke valves 5, 8 & 10 (passed) 4.4" dart valve (failed) , choke valves 4, 6 & 7 (passed) 5.4" dart valve, choke valve 2 (passed) 6.5" TIW, choke valves i & 3 (passed) 71PR with 5" test joint, 5" dart valve (passed),8.LPR with 4-1/2" test joint (passed) 9.UPR with 4-1/2" test joint, HCR choke (passed) 101PR with 7" test joint (passed) 11.Annular to 2500 psi with 7" test joint (passed) 12.UPR with 4" test joint, manual choke (passed) 13.UPR with 2-7/8" test joint (passed) 14.Annular to 2500 psi with 2-7/8" test joint (passed) 15.Blind rams (passed) 16.Hydraulic super choke (passed) 17.Manual adjustable choke (passed).,Accumulator Test: System pressure = 3000 psi Pressure after closure = 1650 psi 200 psi attained in 39 seconds Full pressure attained in 186 seconds Nitrogen Bottles - 6 at 2033 psi.,Blow down and RD BOPE testing equipment. Drain the BOP stack.,MU crossover and pack off pulling tool to a joint of 4" DP. Engage the pulling tool, BOLDS and pull the 7" pack off. Lay down the 4" DP, crossover and pack off pulling t00l.,PU the 7" landing joint. MU drive sub, crossover and DP pup joint. MU landing joint to the mandrel hanger and BOLDS. Unseal the hanger and PU to 350K with no movement.,Circulate out the diesel and old mud from the OA at 5 BPM = 600 psi until good 10.0 ppg at surface.,Work the pipe, with and without pumps, pulling up to 400K (150K over estimated string weight with blocks) but unable to pull free. Notify town Engineer and discuss options.,Re-land the T' mandrel casing hanger and lay down the landing joint. Blow down the top drive. Install the wear ring.,Rig Fuel (gallons): OH = 6860, Used = 416 & Rec =0 Daily losses to the formation = 0 bbis Total losses to the formation = 12.5 bbls, Hauled 40 obis H2O from L-Pad Lake for total = 10,815 bbis Hauled 0 bbis H2O from 6-Mile Lake for total= 80 bbis Hauled 0 bbis H2O from B-Pad Lake for total = 675 bbls Hauled 0 bbls H2O from G&I Heated for total = 920 bbis Hauled 0 bbls Cuttings/Liquids to G&I for total = 15,055 bbis 9/29/2018 PU and MU 7" MSC, stabilizer and crossover- 11.17'. TIH with MSC on 4" DP to 7248' PU 135k, SO 85k Correct displacement while TIH.,P/U single, MU the top drive, Position the MSC at 7270' turn on the rotary at 60 RPM = 5K ft-lbs torque, 6 BPM 1300 psi, cut the casing w/5.5-7.5k torq, and saw a 250 psi drop. Shut down the rotary and slow the pumps to 1 BPM = 250 psi. PU 5', SO and set 5K on cut., UD single, BD TD, flowcheck well, static. TOOH f/ 7248' to surface, UD cutter assy. Inspect cutter, no indication of cut on knives. Tear down cutter, found washed O-rings, piston and indicator ring. Correct fill while TOOH.,Expedite new multi string cutter f/ Baker shop in Dead horse, While W/O cutter to arrive, pull wear bushing, MIU landing jt, w/ XOs, M/U TD, pull hanger free, work 7" casing pulling up to 375k w/ no movement, Re-land hanger, UD landing. Install wear bushing. Note: Nabors 7ES moving on Spine, Helicopter expedite cutter to MP.,P/U and MU new 7" MSC, stabilizer and crossover- 11.12'. TIH on 4" DP to 7244'. PU and MU a single joint of DP from the pipe shed. PU = 135K, SO = 85K and 80 RPM = 5K ft-lbs free torque. Correct displacement while TIH.,Cut the 7" casing at 7270' at 3.5 BPM = 830 psi, 80 RPM = 6K ft-lbs torque. Pressure dropped to 700 psi and torque leveled out at SK ft-lbs (free torque)., Lay down the single joint of DP. TIH from 7270' to 7786'.,Rotate at 80 RPM = 6K ft-lbs torque, 3.5 BPM = 650 psi confirm 7" is cut at 7786'., Blow down the top drive. TOOH with MSC from 7786' to surface. Lay down MSC. Correct fill while TOOK, Pull the wear ring and MU the landing joint. PU to 325K and the T' casing pulled free. Pull the hanger to the rig floor (PU = 180K).,Circulate bottoms up at 9 BPM = 480 psi. SimOps: RU 7" power casing tongs., Back out the landing joint. Breakout the DP pup and crossovers. Lay down the landing joint. Change elevator to 7". Breakout the 7" mandrel casing hanger and lay down. MU crossovers to the TIW.,PJSM. POOH laying down 7" casing inspecting the pin threads in the pipe shed from 7233' to 6318'.,Rig Fuel (gallons): OH = 6395, Used = 465 & Rec = 0 Daily losses to the formation = 0 bbls Total losses to the formation = 12.5 bbls,Hauled 40 bbis H2O from L-Pad Lake for total = 10,855 bbis Hauled 0 bible H2O from 6-Mile Lake for total= 80 bbls Hauled 0 bible H2O from B-Pad Lake for total = 675 bbis Hauled 0 bbls H2O from G&I Heated for total = 920 bbis Hauled 290 bbls Cuttings/Liquids to G&I for total = 15,345 bbis 9/30/2018 Continue to POOH laying down T' casing inspecting the pin threads in the pipe shed from 6318' to surface (175 jts + cut jt ). Lay down the cut joint, clean cut (L= 22.22'). 2.2 bbis over calculate on TOOH-RD handling equipment. Clean and clear the rig floor. Off load 7" casing from the pipe shed. Load fishing equipment into the pipe shed and mobilize tool to the rig floor. Install 9" ID wear ring.,MU 7" casing spear BHA: bull nose, pack off, 5-3/4" spear, spear extension, stop sub, bumper sub, oil jar, XO, (6 )6-1/4" DCs, crossover, intensifier, and crossover (BHA = 236.5l').,TIH with T' casing spear assembly from 236' to 7270' (PU = 145K and SO = 90K).,SO to 7279' and engage the spear into the 7" casing. Warm up the jars.,Commence jarring, working the jars up to 325K with straight pull to 375K while circulate at 2 BPM. Perform derrick inspection every hour. Unable to jar casing free (casing cut at 7833'). At one point the pump pressure increased from 220 psi to 600 psi but pressure slowly came back down to 220 psi.,Attempt to rotate the fish by putting right hand torque into the string and working it down. Made a total of 11 wraps with no downhole rotation. Discuss option with Engineer. Release the spear from the casing.,Rig Fuel (gallons): OH = 11060, Used = 435 & Rec = 5100 Daily losses to the formation = 0 bbis Total losses to the formation = 12.5 bbls,Hauled 70 bbls H2O from L-Pad Lake for total = 10,925 bbis Hauled 0 bbls H2O from 6-Mile Lake for total= 80 bible Hauled 0 bible H2O from B-Pad Lake for total = 675 bbis Hauled 0 bbis H2O from G&I Heated for total = 920 bbls Hauled 0 bible Culti s/Li uids to G&I for total = 15,345 bbl 10/1/2018 Release spear f/ 7" casing @ 7270', P/U to 7227', rack 1 stand back. Blow down top drive, perform full derrick and top drive inspection post jarring operations, well is static-TOOH with spear assembly f/ 7227' to 236', rack back DCs, UD jars and spear assembly, Note: grapple on spear had slight crack. Correct displacement on TOOH.,P/U and MU 7" MSC, stabilizer and crossover- 11.12'. TIH on 4" DP to 7621', M/U last std, M/U top drive. PU 140K, SO 85K., RI to cut depth @ 7667', rotate 80 rpm, 6k free tq. Pump 4 bpm, 880 psi, 6.5-7k tq and cut T' casing, seen 260 psi pressure drop, stop rotating, P/U 7', slow pump to 1.5 bpm, SID setting down 5k to confirm cut. shut off pump. P/U to 7619', BD TD, Well is static.,TOOH from 7619' to surface. Lay down the MSC.,Clean and clear the floor.,PU and MU 7" casing spear BHA: bull nose, pack off, 5-3/4" spear, spear extension, stop sub, bumper sub, oil jar, XO, (6 )6-1/4" DCs, crossover, intensifier, and crossover (BHA = 236.5l').,TIH with spear assembly from 236to 7191' (PU = 150K and SO = 87K).,Slip and cut 79' drilling line. Service the draw works and top drive.,TIH top offish at 7270' and engage the spear into the T' casing at 7279. PU to 200K (50K over) and bleed the jars. Straight pull to 350K (200K over) and fish pulled free (PU = 190K). Stand one stand back with 25K-75K drag to 7191'.,TOOH with spear assembly from 7191' to 236.,Rig Fuel (gallons): OH = 10570, Used = 490 & Rec = 0 Daily losses to the formation = 7 blots Total losses to the formation = 19.5 bbls, Hauled 40 bbls H2O from L-Pad Lake for total = 10,965 blols Hauled 0 bible H2O from 6-Mile Lake for total= 80 bbls Hauled 0 bbls H2O from B-Pad Lake for total = 675 bbls Hauled D bbls H2O from G&I Heated for total = 920 bbls Hauled 0 bbls Cuttings/Liquids to G&I for total = 15,345 bbls 10/2/2018 Monitor well, static. UD down intensifier, and XOs, rack back 2 stds DCs, UD jar and bumper sub. Pull out jt 7" casing, R/U pwer tongs. UD cut jt w/ spear, C/O handling equipment. Pull and UD 9 jts 7" casing and lower cut jt. ( upper out jt= 12.52', lower cut jt= 13.14') 397' total Note: clay packed on outer 7" casing.,R/D 7" handling equipment, clear rig floor, RIH w/ 2 stds of DCs and UD same. P/U and attempt to break out spear f/ casing cut it, UD same. R/U 2 7/8" handling equipment. Ready FOSV.,M/U bull nose and XO, TIH w/ 2 7/8" pac pipe U 570', M/U XO, C/O to 4" handling equipment. TIH w/ 4" DP to 7339' @ 9 5/8" shoe. Correct displacement TIH, R/U HES cementers.,M/U TD, wash down f/ 7339'to 7823' pumping 2 bpm, 300 psi. BD TD, R/U head pin and cement hose. CBU. Note: M/U 15' pup jt under last std. PU 140k, SO 85k.,PJSM, pump 2 bbls H2O. Test lines to 500/4000 psi f/ 5 min ea, good. Pump 30 blots 10.5 ppg clean spacer ( 1.30 YP, 7.00 gps) 2 bpm, 285 psi, followed w/ 54 bbls 15.8 class G cement @ 2 bpm, 100 psi (1.154 YP, 263 sx, 4.99 gips), Pump 5 bbls clean spacer.,With rig pump displace cement w/ 66.5 bbls 10 ppg LSND mud 8 bpm, 210 psi, 20 bbls away caught cmt, slow to 5 bpm, 890 psi, slow to 3 bpm 560 psi for last 10 bbls. R/D circulating hose and headpin. BD back to cmt unit. CIP @ 18:10 hrs. Estimated TOC @ 726T. No losses during cement job.,TOOH f/ 7823' @ 20'/ min for 10 stands, UD 15' pup after 1st std. Increase to 80'/min for last 5 stands @ 6400'.,Load 4" drill pipe wiper ball then circulate the drill pipe clean with surface to surface volume of 4700 stks, 470 bbls. @ 6 BPM, 800 PSI until wiper ball out then 8 BPM, 1340 PSI. No spacer or cement observed at bottoms up. No losses observed during circulating.,Perform 5 min. flow check - static. Pump dry job. POOH while laying down 4" drill pipe from 6400'to 5772'. Proper pipe displacement., Replace retainer bar on 4" drill pipe elevators hinge pin. SimOps - Service top drive.,Continue to POOH while laying down 4" drill pipe from 5772' to 572'. UD 2-7/8" PAC pipe from 572'. Proper pipe displacement.,RIH w/ remaining 24 stands of 4" drill pipe from the derrick and lay down 14 joints., Hauled 110 bible H2O from L-Pad Lake for total = 11,075 bbls Hauled 0 bbls H2O from 6-Mile Lake for total= 80 bbls Hauled 0 bbls H2O from B-Pad Lake for total = 675 bbls Hauled 140 bbls H2O from G&I Heated for total = 1060 bbls Hauled 193 blols Cuttings/Liquids to G&I for total = 15,538 bbls -a Well Name: MP L-41 Field: Milne Point Unit County/State: , Alaska i (LAT/LONG): evation (RKB): 33.7 API #: Spud Date: 8/30/2018 Job Name: 1813264D MPL-41 Drilling Contractor Doyon 14 AFE #: 1813264D AFE $ $4,597 573 Hilcorp Energy Company Composite Report Activity Pate Ops. Summary _ r 10/3/2018 TOOH UD 4" DP to pipe shed f/ 1825' to surface.,R/U MPD lines in cellar.;C/O the saver sub on tap drive V 4" XT39 to S' D550, change to 5" handling equipment, load 5" DP into pipe shed, strap and tally same.;Drift, P/U 180 jts 5" DS50 DP if pipe shed and TIH to 5649, TOOH racking back 60 stds in derrick.;Pull wear ring, install test plug, MPD test cap and pressure test MPD equipment. 250 PSI for 5 min. Attempt 1500 PSI and 6" air actuated drain valve leaking.;lnspect, flush, function, grease valve without success. The decision was made to change out the valve. PJSM to replace 6" valve. Remove short mousehole, drain stack, remove 4" MPD line, loosen MPD rotating flange bolts and rotate MPD head.;Remove 6" valve & found two pieces of composite material stuck in valve at 4" flange. Install new valve. Rotate MPD head, tighten flange bolts, install 4" Iine.;Fill lines and pressure test MPD equipment to 250/1500 PSI for 5 min. each test. Remove test cap then install trip nipple. Fill stack, but found leak on trip nipple flange. Adjust stack alignment with turn buckles, leak on flange stopped ;Hauled 125 bbis H2O from L -Pad Lake for total = 11,200 bbis Hauled 0 bbls H2O from 6 -Mile Lake for total= 80 bbls Hauled 0 bbis H2O from B -Pad Lake for total = 675 bbls Hauled 0 bbls H2O from G&I Heated for total = 1060 bbis 10/4/2018 Align MPD riser, test for leaks, good. BD choke line, Drain and rinse out stack, check for debris, pull test plug, Install 9" ID wear bushing.;PJSM, M/U 8.5" kickoff BHA. 8.5" VM -3 MT bit, 1.76 deg mu, fit sub, DM HOC, TM HOC, fit sub, Scribe w/offset @ 311.14 deg. MU 3-NMFCs, 6 HWDP, Jars, 11 HW DP= 697.46', Shallow Test MWD.;Dritt, P/U and TIH with 18 its 5" NC50 DP then Start singling in with 5" DS50 DP f/ 697'to 201 8'.:C/0 5" elevators, ship old elevators to WFD to be inspected.;Con[inue to single in w/150jts 5" DS50 DP f/ 2018'to 5905, fill the pipe at 250U & 5000',( shallow test MWD @ 2500', amplitude on pulser weak, should be 60 psi but down to 15 psi, survey pulsed up within 0.1", C/O transducer on stand pipe. test MWD @ 5000', good.;TIH on elevators f/ 5905' U 7048'& tagged up on cement stringer w/ BK.;Wash down f/ 7048't/ 7203'w/ 168 GPM, 430 PSI. Began to observe 8-10K drag. Ream down f/ 7203' V 7301' w/ 400 GPM, 1240 PSI, 45 RPM, 12.51K TO w/ 5-8K drag.;Drill cement f/ 7301'V 7367'w/ 300 GPM, 710 PSI, 45 RPM. 14-15K TQ, 1 O WOB. ROP slowed from 1707hr. to 777hr. as cement firmed up.;DrilI 8-1/2" hole from 7367' to 7412'.545 GPM, 1690 PSI, 45 RPM, 14-15K TO, 10-12 WOB. Began sliding at 150R TF at 7392' MD. 187hr AROP.;Rack back stand & LID single to 7369. Circulate the hole clean prior to FIT. 600 GPM, 1700 PSI, 45 RPM, 13-17K TO. Circulated 5185 strokes total - one complete circulation. Observed formation cuttings across the shakers. Blow down top drive.;Perform FIT to 12.5 ppg EMW at 9-5/8" shoe at 7367' MD / 4703' TVD with 10.2 ppg LSND mud to 563 PSI. 1.3 bbis pumped and 1.3 bbis bled back. RID equipment, blow down choke and kill Iines.;RIH it 7360' T/ 7412'. Drill 8-1/2" hole f/ 741 2' V 7556'. 487hr AROP, 550 GPM, 1420 PSI, 60 RPM, 15-17K TO, 10-15K WOB. Last survey @ 7450.61' MD/4742.62' TVD, 57.36° inc., 16.34° azm. 1.4T from wpl3a, 1.38' low & 0.62' right.;Hauled 80 bbis H2O from L -Pad Lake for total = 11,280 bbis Hauled 0 bbis H2O from 6 -Mile Lake for total= 80 bbls Hauled 0 bbis H2O from B -Pad Lake for total = 675 bbis Hauled 0 bbis H2O from G&I Heated for total = 1060 bbis Hauled 228 bbis Cultings/Liquids to G&I for total = 16,051 bbis 10/5/2018 Drill 8-1/2" hole ff 7556 V 7676'. 487hr AROP. 600 GPM, 2070 PSI, 60 RPM, 15-17K TO, 10-15K WOB. MW in/out 10.1/10.2 vis in/out 36/38, max gas 107u PU/SO/ROT 220K/l 03K/145K Distance from plan, 11.66', 11' low, 3.87' dght.;CBU at 7676' pumping 585 gpm, 1950 psi, rotate 60 rpm working full stand, get SPRs, take survey, 7641.70 MD / 4854.82 TVD / 52.31 inc / 22.32 az, Flow check the well, static. Note: 24' of separation f/ 7" casing stump @ 7667';BROOH pumping 580 gpm, 2050 psi, 60 rpm, 16-18k tq f/ 7676' to 7485'.;TOOH on elevators f/ 7485' into 9 5/8 casing @ 7297', BDTD, continue TOOH to 69T at HWDP. 2 bbis over calc displacement TOOH ;Flow check well, static. Rack 6 stds HWDP w/jars in derrick. UD 3 NMFCs, fit sub, MWD tools, mtr and bit. Grade= 1/1MlT/A/E/VNO/BHA.;Clear clean rig floor, load out tools, Load RSS tools to rig floor, PJSM for BHA.;M/U RSS/UR BHA #7 w/ 8.5" SK616M-J1 D PDC bit, Geo -Pilot W/ STB, DM, DGR, ILS, EWR-P4, PWD, HCIM, TM, FS NP plunger, IBS, PC, UR, FS NP flapper, PC, FS NP flapper, IBS, 6-14WDP, Jar, 11- HWDP. = 695.19'. (Bit to UR = 110.33'). Download MWD.;Pressure test Sperry Geo -Span to 250/1500 PSI. Break-in Geo -Pilot seals & bearings. Attempt to pulse test MWD, but low mud volume and aired up mud caused erratic pump pressure.;TIH from 695' to 2582'. Shallow pulse test MWD 450 GPM, 1200 PSI & down link to Geo -Pilot successfully. TIH from 2582'to 7299', filling pipe every 20 stands. 235K PLAN, 105K SOW.;Slip & cut 59' of drilling line. Service top drive and draw works.;TIH from 7299 to 7676'. PJSM with all parties involved for displacement to new 9.5 ppg LSND mud.;Pump 30 bbls 9.5 ppg high viscosity spacer 3 BPM, 300 PSI. Displace with 515 bbis 9.5 ppg LSND mud at 6 BPM, 810 PSI ICP, 630 PSI FCP, 60 RPM, 16K TO. Perform 5 minute flow check- static.;Obtain parameters, 500 GPM, 1660 PSI, 30 RPM, 17k TO. Drop 1-3/8" open ball. Pump down w/ 350 GPM, 910 PSI, 30 RPM, 6-10K TO. Observed pressure drop to 860 when reamer opened. Ream f/ 7614' V 7634' w/ 500 GPM, 1500 PSI, 60 RPM, 8-15K TO, 1-2K WOB. Overpull 20K to verify blades open.;Ream V 763N V 7676' w/ 500 GPM, 1500 PSI, 60 RPM, 8-15K TO, 3-6K WOB. Obtain slow pump rates.;Hauled 195 bbis H2O from L -Pad Lake for total= 11,475 bbls Hauled 0 bbis H2O from 6 -Mile Lake for total= 80 bbis Hauled 0 bbls H2O from B -Pad Lake for total = 675 bbis Hauled 0 bbis H2O from G&I Heated for total = 1060 bbls Hauled 301 bbis Cuttings/Liquids to G&I for total = 16,352 bbls 10/6/2018 Drill 8-12" x9-718" hole It 7676' V 8150' (79' AROP) 600 GPM, 2100 PSI, 120-140 RPM, 10-12K TO, 10-15K WOB. Mud in 9.4+ppg 40 vis, out 9.5 ppg, 39 vis. 10.32 ppg ECD. Max gas 89u PU 180K, SO 130K, Rot 155K.;Observed high levels stick slip. Varied surface parameters w/ no reduction. Add 4 drums 776 and Increase lubes f/ .5% to 1 % @ 7900' reducing slip stick to none, reducing torque If 14-17k to 10-12k.Pump tandem sweep @ 8146, Sweep back 20 bbls early w/ 75% increase. Dump sweep returns dump to rock.;DnII 8-1/2" x 9-7/8" hole f/ 8150' t/ 8589 (73.2' AROP) back ream 31' on ea. std. 600 GPM, 2180 PSI, 155 RPM, 11-13K TO, 16-18K WOB. Mud in 9.5 ppg 40 vis, out 9.5 ppg, 38 vis. 10.63 ppg ECD. Max gas 126u. PU 186K, $O 126K, Rot 155K.;Pump tandem sweeps @ 8522'. Sweep back 10 bbls early. Dump sweep returns dump to rock washer.;Drill 8-12" x 9-7/8" hole f/ 8589' t/9091' (84.7' AROP) back ream 31' on ea. std. 600 GPM, 2480 PSI, 140 RPM, 15-16K TO, 18-19K WOB. Mud in 9.5 ppg 39 vis, out 9.6 ppg, 43 vis. 10.90 ppg ECD. Max gas 149u. PU 190K, SO 128K, Rot 155K. Begin 3°/1 OO' drop at 8995'.;Pump tandem sweeps @ 8995' Sweep back 10x bbls early. Dump sweep returns dump to rock washer.;Drill 8-12" x 9-7/8" hole f/ 9091' V 9423' (55.3' AROP) back ream 31' on ea. std 600 GPM, 2675 PSI, 140 RPM, 10-14K TO, 18-20K WOB. Mud in 9.55 ppg 45 vis, out 9.55 ppg, 50 vis. 10.81 ppg ECD. Max gas 150xu PU 198K, SO 133K, Rot 163K.;Last survey @ 9339.27' MD / 5740.93' ND, 48.99° inc,14.70' azm. 3.17' from plan, 3' low and 1.03' right.;Hauled 375 bbis H2O from L -Pad Lake for total =11,850 bbls Hauled 0 bbis H2O from 6 -Mile Lake for total= 80 bbls Hauled 0 bbls H2O from B -Pad Lake for total = 675 bbls Hauled 0 bbis H2O from G&I Heated for total = 1060 bbis Hauled 1171 bbls Cuttings/Liquids to G&I for total = 17,523 bbls;7 bible daily losses, 20 bbis cumulative losses. 10/7/2018 Drill 8-1/2" x 9-7/8" hole f/ 9423' t/ 9802' (63.1' AROP) back ream 31' on ea. std, Perform 3°1100' drop. 600 GPM, 2500-1750 PSI, 140 RPM, 15K TO, 17-19K WOB. Mud in 9.5 ppg 47 vis in, out 9.+ ppg, 47 vis. 10.68 ppg ECD. Max gas 134u PU 208K, SO 142K, Rot 168K.;Dump and dilute w/ 290 bbls new 9.5 LSND mud @ 9520'to help lower ECDs f/ 10.8 ppg. Started seeing a gradual pressure drop after dumping and diluting ff 2500 psi to 1750 psi, reduction on impeller rpms on turbine f/2700 rpm to 2200 rpm.;Check surface equipment, geo span, mud pumps pop vales and mud lines, no leaks, shut down pumps, Notify town engineer of possible washout.;Rack i stand back to 9745', flow check well, static. TOOH on elevators f/ 9745'to 8710' looking for washout, BD TD. Continue TOOH on elevators f/ 8710'to 7366' pulling into 9 5/8 shoe, Found washout on std # 71 on top of double 4' below top tool jt.;Replace washed jt. TOOH racking std back, park at 7299', install FOSV, monitor hole with trip tank. Check valves and seats on mud pumps. C/O valves and seats on pump #2. Pressure up to 3500 PSI to seat valves. Replace gasket on #1 MP suction in pit #3.;TIH f/ 7299'tt 7676'. Circulate @ 500 GPM, 1840 PSI & 600 GPM, 2470 PSI, pressure holding steading. MWD pulser 2800 RPM. B/D top drive. TIH f/ 7676' t/ 9751' on elevators. Wash down to 9802' with 600 GPM, 2750 PSI, 60 RPM, 9K TO. Observe 9.75 MW, 92 vis. mud returns and 11.15 ppg ECD.;Circulate a bottoms up. 600 GPM, 2750 PSI, 60 RPM, 9K TO. ECD reduced from 11.15 to 10.64.;Drill 8-12" x 9- 7/8" hole f/ 9802' U 9969'(55.7' AROP) back ream 31' on ea. std, Perform 3°/ 100' drop. 600 GPM, 2750 PSI, 160 RPM, 15-16K TO, 20K WOB. Mud in 9.5 ppg 44 vis in, out 9.6 ppg, 53 vis. 11.1 ppg ECD. Max gas 84u. PU 212K, SO 143K, Rot 175K.;Drill 8-12" x 9-7/8" hole f/ 9802' t/ 10222'(105' AROP) back ream 31' on ea. std. Perform 3°/ 100' drop. 600 GPM, 2850 PSI, 160 RPM, 17-19K TO, 20K WOB. Mud in 9.55 ppg 48 vis in, out 9.55 ppg, 56 vis. 11.04 ppg ECD. Max gas 67u. PU 225K, SO 148K, Rot 180K.;Last survey @ 10190.62' MD 16413.99 TVD, 24.93' inc., 18.50° azm., 3.91' distance from plan, 2.29' low & 3.1 T right.;Circulate 2x bottoms up prior to installing MPD RCD. 600 GPM, 2800 PSI, 60 RPM, 10-12K TO. ECD dropped from 11.04 to 10.6 ppg EMW.;Remove trip nipple and install MPD RCD. New RCD element with 96 hours on the bearing.;Hauled 720 bbis H2O from L -Pad Lake for total = 12,570 bbis Hauled 0 bbls H2O from 6 -Mile Lake for total= 80 bbls Hauled 0 bbls H2O from B -Pad Lake for total = 675 bbis Hauled 0 bbis H2O from G&I Heated for total = 1060 bole Hauled 808 bbls Cutfings/Liquids to G&I for total = 18,331 bb1s;0 bola daily losses, 20 bbls cumulative losses. 10/8/2018 Take returns through MPD to flow line checking same. Ramp to 600 GPM, 80 psi line friction f/ MPD, 270 psi back pressure, 11.3 ppg ECD.;Drill 6-12" x 9-7/8" hole F/10222' T/ 10440'(36.3 AROP) back ream lower 31'. 600 GPM, 2920 PSI, 120 RPM, 18-20K TQ, 18-20K WOB. Mud in 9.5 ppg 36 vis, out 9.5+ ppg, 42 vis. ECD 11.3. PU 248K, SO 140K, Rot 181K. Max gas 70.;Hold back pressure to maintain 11.3 ECD. 260-310 psi drilling, 520-560 psi at connections. Start adding spike fluid w/black product as we drill ahead increasing system to 8 ppb. Continue w/ 3"/ 100' drop to 10330' then maintain 20 deg inc.;Drill 8-12" x 9-7/8" hole F/10440' T/ 10693'(42.2 AROP) back ream lower 31'. 600 GPM, 2980 PSI, 130 RPM, 18-19K TQ, 19-20K WOB. Mud in 9.5 ppg 36 vis, out 9.5 ppg, 37 vis. ECD 11.28. PU 260K, SO 145K, Rot 185K. Max gas 24.;Hold back pressure to maintain 11.3 ECD. 250-310 psi drilling, 520-560 psi on connections. Pump hi vis sweep @ 10500', sweep back 20 bbls early, dump returns to rock washer. HRZ @ 10563' MD/6760' TVD, Kalubik @ 10623' MD/6817' TVD. KLGM @ 10651' MD/6843' TVD.;Ddll 8-1/2" x 9-7/8" hole F/10693T/ 10813' (20 AROP) back ream lower 31'. 600 GPM, 3030 PSI, 120 RPM, 18-19K TO, 9-14K W OB. Mud in 9.5 ppg 34 vis, out 9.5 ppg, 36 vis. ECD 11.29. PU 265K. SO 143K, Rot 183K. Max gas 29. Kuparuk D @ 10812'MD/6995'TVD.;Hold back pressure to maintain 11.3 ECD. 250-310 psi drilling, 600-620 psi on connections.;Drill 8-1/2" x 9-7/8" hole F/10813' T/ 1098T (29 AROP) back ream lower 31'600 GPM, 3040 PSI, 120 RPM, 18-19K TO. 15K WOB. Mud in 9.5 ppg 33 vis, out 9.5 ppg, 38 vis. ECD 11.29 PU 280K, SO 130K, Rot 185K. Max gas 23.;Hold back pressure to maintain 11.3 ECD. 300-350 psi drilling, 520.620 psi on connections. Last survey @ 10946.73' MD / 7121.43' TVD, 20.22° inc., 20.66° azm. 1.81' from plan, 0.27' high and 1.79' right.;Hauled 520 bbis H2O from L -Pad Lake for total = 13,090 bbls Hauled 0 bbis H2O from 6 -Mile Lake for total= 80 bible Hauled 0 bola H2O from B -Pad Lake for total = 675 bbls Hauled 0 bbls H2O from G&I Heated for total= 1060 bbls Hauled 1269 bible Cuttings/Liquids to G&I for total= 19,600 bbls;22 bbls daily losses, 42 bible cumulative losses. 10/9/2018 Drill 8-1/2" x 9-7/8" hole F/10987 T/ 11175'(31 AROP) back ream lower 31'.600 GPM, 3070 PSI, 120 RPM, 17-19K TO, 15K WOB. Mud in 9.5 ppg 34 vis, out 9.5 ppg, 38 vis. ECD 11.29 PU 290K, SO 140K, Rot 195K. Max gas 29.;Hold back pressure to maintain 11.3 ECD. 300-350 psi drilling, 520-620 psi on connections. Kuparuk C @ 10996 MD/7167' TVD. Kuparuk B@ 11010'/7180' TVD. Kuparuk A2 @ 11125' MD/7289' TVD, Kuparuk Al @ 11153' MD/7315' TVD.;Drill 8-1/2" x 9-7/8" hole F/11175' T/ 11255' (40 AROP) back ream lower 31'. 600 GPM, 3070 PSI, 120 RPM, 17-19K TO. 15K WOB. Mud in 9.5 ppg 34 vis, out 9.5 ppg, 38 vis. ECD 11.29 PU 290K, SO 140K, Rot 200K. Max gas 36.;MPD Bearing starting to leak out of pop off. Attempt to drill at reduced RPM dropping RPM from 120-80. Still Leaking. Decided to change on Kelley down. Back ream stand. Close annular and hold 550 psi with MP while changing bearings out. Pulled old bearing and left on stand in derrick.;P/U two singles to TD on and WU new bearing. Test same and open annular.;Drill 8-12" x 9-7/8" hole F/11255' T/ 11315' (TD). 600 GPM, 3070 PSI, 120 RPM, 17-19K TQ, 15K WOB. Mud in 9.5 ppg 34 vis, out 9.5 ppg, 38 vis. ECD 11.29 PU 305K, SO 140K, Rot 200K. Max gas 45.;Obtain final survey @ 11286.08' MD 17440.3T TVD, 19.81" inc., 18.77° mm. 3.94' from plan, 0.05' high & 3.94' right. Close NOV reamer. Drop 1-7/8" ball & pump down w/ 350 GPM, 1080 PSI. Ball on seat @ 1400 stks & pressured up to 2440 PSI before shifting closed.;Circulate 5x bottoms up w/ 600 GPM, 3140 PSI ICP / 2450 PSI FCP, 120 RPM, 17-18K TO. Weight up from 9.5 ppg to 9.8 ppg then 10.0 ppg with spike fluid while maintaining 11.3 ECD. Perform Sperry quadrant ream at 45L, 45R, 135R & 135L tooHaces. 34800 total stks, 5.3 bottoms up, total circulations.;Drill string floats not holding. Attempt to close floats. Bleed off drillstring. Rotate while bleeding off. Surge drillstring. Pump 10 bbls low vis sweep followed by 10 bbl high vis sweep. Unsuccessful. Consult w/ drilling engineer. Decision made to weight up to 10.5 ppg then begin trip out of hole.;Weight up from 10.0 ppg to 10.3 ppg. 600 GPM, 2300 PSI ICP / 590 GPM 1950 PSI FCP, 60 RPM, 19K TO. Currently weighting up to 10.5 ppg with spike fluid while maintaining 11.3 ECD. 540 GPM, 1760 PSI, 60 RPM, 17K TO. 22300 stks, 2.6 total circulations.;Hauled 434 bbls H2O from L -Pad Lake for total = 13,524 bbis Hauled 0 bole H2O from 6 -Mile Lake for total= 80 bbls Hauled 0 bbis H2O from B -Pad Lake for total = 675 bbls Hauled 0 bbis H2O from G&I Heated for total = 1060 bible Hauled 560 bbls Cuttings/Liquids to G&I for total = 20,160 bb1s;0 bible daily losses, 42 bible cumulative losses. 10/10/2018 Finish bringing wt up 10.5 in and out. 590 GPM,1990 PSI, 120 RPM, 21 K TQ.;Monitor well. Slight breathing. Slowing down until stabc.;Spot liner running pill. Pump 80 bbl 6 PPB Resonex & 6 PPB Asphasol supreme, 2% Lube 776 Liner running pill. Spot out of the Drill pipe and putting the top above the HRZ. 500 GPM, 1540 PSI.;POOH at 5 min per stand following trip schedual holding 11.3 EMW on the annulus with MPD. Bleed down for connections. POOH clean F/ 11315' T/ 7714'. Pull 20K over but pull through. RIH past tight spot. POOH & pulled tight again.;Stage up pumps to 500 GPM monitoring ecds at 11.3. Rot at 60 RPMs. Back ream F/ 7760'T/ shoe at 7366'. Very fine cuttings at btms up. No losses holding 11.3 ECDs.;Circ btm up. 500 GPM, 1050 PSI, 50 RPM, 11-12K TO. Clean. Monitor well. static. Remove MPD bearing from stand # 112 in the derrick while monitoring well. Blowdown TD.;POOH F/ 7300' T/ 3808' holding 10.7- 10.8 ppg EMW while pulling pipe. Kelly up on each stand due to floats leaking. Utilize 23 min./stand pulling speed as per MPD schedule.;Found a washout in the 5" drill pipe on the top joint of stand #33. Washout was located 3.05' down from the box, just above where the slips set. 3805' above bit. Washout was 2"x114". Laid down joint. Apply MPD back pressure, floats holding.;POOH F/ 3777'T/ 757' while maintaining 10.8 ppg EMW. Needed 100 PSI static to seal floats. Utilize 1 2 mmJstand pulling speed as per MPD schedule.;Perform 30 min. flow check, well static. PJSM for removing MPD. L/D MPD RCD and install trip nipple.;_/D two drill pipe F/ 757'T/ 695'. Rack back HW DP to 139'. L/D BHA #7 F/ 139 T/ 77'. Both float valves @ 131'& 120' had broken springs & the valve faces were pitted, but the seals were still in good condition.;NOV reamer had two broken primary cutters on the leading edge of blade #1, graded: 1 -1 -BT-P-X-I-NO-TD. Read MWD tool - good data recovery. Lay down BHA F/ 77' T/ 67'.;Hauled 200 bbls H2O from L-Pad Lake for total = 13,724 bbls Hauled 0 bbis H2O from 6-Mile Lake for total= 80 bbls Hauled 0 bbls H2O from B-Pad Lake for total = 675 bbls Hauled 0 bbls H2O from G&I Heated for total = 1060 bbls Hauled 338 bbls Cuttings/Liquids to G&I for total = 20,498 bbls;l5 bbls daily losses, 57 bbls cumulative losses. 10/11/2018 Clear & clean floor of BHA. Pull Wear bushing, Flush stack with water. Set test plug.;R/U 4" test Joint & R/U to test. Perform Body test to 250/4000 psi.;Test BOPS to 25014000 psi as per AOGCC. Test with 4" & 7" test joints. Test annular to 250/2500 psi. Perform Accumulator draw down. Good. All test good against test plug. Witness waived at 08:39 by AOGCC inspector Jeff Jones.;R/D testing equipment & Blow down surface equipment. R/U to run 7" casing with Doyon Casing & Volant tool.;PJSM Run 7" Casing. P/U shoe track to 209'& Baker Loc first 4 connections. Check floats. Good. Installed bypass baffle on top of Float collar. P/U 7" 26# L-80 TXP casing. Torque to optimum at 14750 TO w/ Volant tool. Fill every joint and top off every 10.;Run 7" 26# L-80 TXP casing F/ 209' T/ 6331', joint #153. Replace joint #39 due to bad box. Torque to optimum at 14750 TQ.;7-118"x8-1/4" OMD centralizers on jt. 1 (2 ea.), jts. 3 & 4 (lea.) & each pump joint at ESIPC (1 ea.) T'x8-1/2" Centek centralizers on jt. 2, jts. 5-33 and jts. 95-97. 39 total centralizers and 10 stop rings.;Hauled 75 bbls H2O from L-Pad Lake for total = 13,799 bbls Hauled 0 bbls H2O from 6-Mile Lake for total= 80 bbls Hauled 0 bbls H2O from B-Pad Lake for total = 675 bbls Hauled 0 bbls H2O from G&I Heated for total = 1060 bbls 10/1212018 Continue to P/U 7" 26# Casing F/ 6331' T/ 7360'. Making up casing with Volant tool to 14700 TQ.;Circ and condition at shoe staging up pumps to 5 BPM 310 PSI. No losses while circulating. Work pipe 40'. UPIDN 175/114K.;Continue to P/U 7" 26# Casing F/ 7360'T/ 9998'. Making up casing with Volant tool to 14700 TQ.;Circ and condition staging up pumps to 2 bpm. Losing 50% returns at .25 BPM or 2 BPM. Attempt several methods working pipe and only pumping on the up stroke. $fill losing 50%. Pump 100 BBL total and lost 48 bbl.;Continue to P/U 7" 26# Casing F/ 9998' T/ 11273'. Making up casing with Volant tool to 14700 TQ.;R/D Volant tool & blow down top drive. M/U casing hanger & landing joint. RIH F/ 11273' T/ 11292'& could not work past. WU Volant tool & wash down F/ 11292' TI 11299'& could not work past. 48 GPM, 540 PSI. 315K PUW, 125K SOW. 87% losses, lost 76 bbls. Decision made to set casing higher.;UD landing joint w/ casing hanger & joint #273 to 11233'. Would not pull on elevators, needed to pump out. M/U 9.49' & 14.10' pup joints, casing hanger & landing joint. Land on hanger at 11290'. 130K SOW, 90K on hanger.;R/D Volant tool, blow down top drive & M/U cement head. PJSM wl all parties involved - Doyon, Peak, Halliburton, M-I & HAK.;Pump 1st stage cement job w/ Halliburton. Pump 5 bbls H2O then PT lines to 1200/4100 PSI. Pump 50 bbls 10.5 ppg Clean Spacer @3.2 BPM, 68 PSI. Drop by-pass plug. Pump 52.7 bbls (255 sks) 15.8 ppg Premium G cement 1.16113/sk yield @ 3.2 BPM, 780 PSI. Pump 30 bbls 8.34 ppg H2O @43 BPM, 500 PSI.;100% losses while pumping cement.;Displace w/ rig pumps wl 225 bbls 10.5 ppg LSND mud then 9.5 ppg _SND mud @ 5 BPM, 480 PSI ICP. 5 BPM, 460 PSI as cement exited shoe. 5 BPM, 820 PSI then slow to 3 BPM, 850 PSI with final 1050 PSI. 590 PSI lift pressure observed. 100% losses while displacing. Bumped plug @ 3937 stks. CIP @ 03:22.;Check float- holding. Inflate ESIPC. 1300, 1500, 1700, 1900 then 2100 PSI. Dropped to 2000 PSI. Pressure backup to 2100, 2400 then 2600 PSI. Cementer shifted open. Pump 10 bbls LSND at 4 BPM, 1200 PSI with no returns.;Pump 2nd stage cement job w/ Halliburton. Pump 50 bbls 10.5 ppg Clean spacer @ 2.3 BPM, 900 PSI. Drop bottom plug. Pump 34.1 bbls (165 sks) 15.8 Premium G cement 1.16 ft3/sk yield @ 1.8 BPM, 745 PSI. Drop top plug.;Displace w/ rig pumps w/ 8.34 ppg water @ 5 BPM, 1000 PSI ICP,1200 PSI FCP, 2200 stks. of 3765 calculated displacement. Final lift pressure at 1650 before bump.;Hauled 100 bbis H2O from L-Pad Lake for total= 13,899 bbls Hauled 0 bbls H2O from 6-Mile Lake for total= 80 bbls Hauled 0 bbls H2O from B-Pad Lake for total = 675 bbis Hauled 0 bbls H2O from G&I Heated for total = 1060 bbl$ Hauled 275 bbls Cutfings/Liquids to G&I for total = 20,773 bbls;126.5 bbls daily losses, 191.5 bbls cumulative losses. n Well Name: MP L41 Field: Milne Point Unit County/State: , Alaska (LAT/LONG): avation (RKB): API #: Hilcorp Energy Company Composite Report Spud Date: Job Name: 1813264C MPL-41 Completion Contractor AFE #: 1813264C AFE $: $2,245,953 Ops Summary 1 0/1 312 01 8 Displace w/ rig pumps w/ 8.34 ppg water @ 5 BPM, 1200 PSI ICP,1470 PSI FCP @3600 stks slow to 2.5 BPM, 1260 PSI ICP, 1620 PSI FCP. Bump plug at 3788 stks (3765 calculated). CIP @ 06:35. Increase pressure to shift cementer closed, did not see shift at calculated 2700 PSI.,Saw possible shift at 3100 PSI & continued to 3500 PSI with no further indication. Bleed off pressure, check flow- static indicating cementer closed. Pressure up to 2000 PSI & hold for 5 min. - good.,Rig down cement head, cement lines, 7" elevators and bail extensions. Rig up 5" elevators.,WU pack -off running tool on stand of 5" HWDP. Set 7" pack off as per wellhead representative. Test void to 250 PSI low 14000 PSI high for 10 min. each test.,lnstall mouse hole in the rotary table. UD 115 stands of 5" drill pipe from the derrick. SimOps: Freeze protect 7"x9-5/8" annulus w/ 70 bbls of diesel, 0.5 BPM, 1000 PSI 2.5 bbls bled off. Removed casing equipment from the rig floor. Attempt to break stand w/ bent joint, unsuccessful.,Change top drive saver sub from DS -50 to XT -39, change bell guide and grabber dies.,Slip and cut drilling Iine.,Mobilize BHA components to the rig floor. WU 6-1/8" bit, bit sub, drill collar, 5-7/8" stabilizer, 2 drill collars & XO sub to 103.71'. Single in the hole w/ 4" XT -39 drill pipe to 1921' and drift with 2.34".,Hauled 325 bbls H2O from L -Pad Lake for total = 14,224 bbls Hauled 0 bbls H2O from 6 -Mile Lake for total= 80 bbls Hauled 0 bbls H2O from B -Pad Lake for total = 675 bbls Hauled 0 bbls H2O from G&I Heated for total = 1060 bbls Hauled 173 bbis Cuttings/Liquids to G&I for total = 20,946 bbls,Daily losses 1251.1 bbls, cumulative losses 1442.6 bbls. 10/14/2018 Replace broken bolts on top drive bell guide.,Single in the hole w/ 4" XT -39 drill pipe from 1921' to 10384' and drift with 2.34".,Ream from 10384'to 1042T w/ 300 GPM, 1040 PSI, 60 RPM, 9K TQ. Drill cement from 10427to 10438'w/ 5K WOB & tag cement plugs on depth. Drill cement plugs and ES cementer from 10438' to 40442'w/ 200 GPM, 460 PSI, 80 RPM, 12K TO, 5-15K WOB. Ream from 10458'to 10435' twice then slack off clean. Pump 25 bbl high vis sweep. Circulate hole clean w/ 350 GPM, 1450 PSI, 60 RPM, 12K TQ.,Rig up test equipment. Pressure test 7" casing to 2500 PSI for 10 min. - good test. Record test on chart. Rig down test equipment -Single in the hole w/ 4" XT -39 drill pipe from 10458' to 11068' and drift with 2.34". Encountered cement stringer.,Ream f/ 11068' V 11153'then drill cement f/ 11 153' t/ 11232'w/ 300 GPM, 1120 PSI, 60 RPM, 13K TQ, 5-10K WOB. Observed plugs & baffle adapter on depth at 11183'. Observed float collar on depth at 11206'.,Pump 25 bbl high vis sweep at 11232', circulate out w/ 400 GPM, 1430 PSI, 100 RPM, 14K TO. PJSM for displacement. Displace wellbore from 8.5 ppg water to 8.45 ppg seawater, 6 BPM, 880 PSI, 80 RPM, 13K TO. Perform flow check - static. Pump dry job. Blow down top drive.,POOH from 11232' to 10343' on elevatom.,Hauled 40 bbls H2O from L -Pad Lake for total = 14,264 bbls Hauled 0 bbls H2O from 6 -Mile Lake for total= 80 bbls Hauled 0 bbls H2O from B -Pad Lake for total = 675 bbls Hauled 0 bbls H2O from G&I Heated for total = 1060 bbls Hauled 194 bbls Cuttings/Liquids to G&I for total = 21,140 bbls, Daily losses 0 bbls, cumulative losses 1442.6 bbls. 10/15/2018 POOH on 4" DP F/ 10343' T/ BHA. UD BH. Bit grade, 1,1,CT,A, E. I, BHA.,Test casing against blind rams to 3600 psi. Good. Bled down 20 psi in 30 min. Blow down surface lines and RID testing equipment.,WU Bit, scraper, boot baskets & XO & RIH to 11232'. Fill pipe every 3000'.,Perform displacement to 8.8 ppg 2% KCI brine. Pump high viscosity spacer. Displace at 8 BPM, 1580 PSI ICP, 1670 PSI FCP. Perform flow check - static. Pump dry job.,POOH from 11 232'to 3035while laying down 4" drill pipe.,Sewice rig and replace fitting on rig floor hydraulic pump.,POOH from 3035' to BHA while laying down 4" drill pipe. 10/16/2018 UD BHA, Check Boot baskets. Clean. Inspect scraper. Good. Change elevators to 5" & Break down bent stand of 5" DP in derrick. Had to cut one damaged joint. Clean and clear rig floor., R/U Pollard wire line. PJSM, RIH to 11232' & Log to 9500'. Run correlation pass. ON btm. Good. Top of cmt 9530'. POOH & RID Pollard. Send logs to town.,R/U Doyon 4.5 completion equipment. PJSM, PIU WLEG & packer assembly & RIH with 4.5" L-80 12.6 # TXP tubing to 6680'.,Service the draw works and top drive.,Continue to RIH with packer assembly on 4-1/2" TXP tubing from 6680' to 10039.,Changeout Doyon power tubing tongs due to O-ring failure.,Continue to RIH with packer assembly on 4-1/2" TXP tubing from 10039' to 10821'.,PU and MU the landing joint and tubing hanger (TWC installed). Land the tubing hanger and RILDS. 1 011 712 01 8 Remove mousehole, MPD clamp & Trip Riser. N/D stack & Tack back, Remove MPD drip pan.,N/U Tree & adaptor. Test hanger void to 500/5000 psi for 10 min as per wellhead rep. Fill tree with Diesel & Test to 5000. Good.,R/U Circ lines to freeze protect, set packer and utube.,Pull TWC, PJSM with LRS. Pump 85 bbl Diesel down annulus taking returns to the pits. Let utube for 1 hr to tubing. static. Drop ball and rod at 1658. Let drop for 20 min. Pressure up on tubing to 2500 psi. Set packer per Halliburon Rep. Hold Pressure on Tubing and pressure up annulus to 3500 psi. Hold for 30 min. Good. Test tubing to 5000 psi for 30 min. Good. Bleed down tubing to 3500 & bleed down both sides together.,Suck back lines with LRS. RID circ lines and secure the tree. Release the rig from L- 41. See L-55 report for details. 10/19/2018 "WELL S/I ON ARRIVAL, NOTIFY PAD -OP, PT PCE 250U2500H" PULL BALL & ROD FROM RHC PLUG BODY @ 10757 SLM PULL RHC PLUG BODY FROM X -NIPPLE @ 10761' SLIM 110765- MD, RECOVER ALL PACKING DRIFT TBG FREELY W/ 12'x 3.40" DUMMY GUN & SID @ 11228' SLM / 11232' MD, PIU CLEAN OFF BTM W/ 1000# PIU "JOB COMPLETE, NOTIFY PAD -OP UPON DEPARTURE" t P.ti,�'.q 5A I`J p 10/23/2018 MIRU Alaska Eline Service. Stab on well. PT PCE to 250 psi low/ 2000 psi high.,Perforated Kuparuk A saads from 1 11 08-1 1116'. Corrected to CBL. Guns are 3-1/8" 6 spf, 60 deg phasing, Geo Dynamic 22.7 gm charges, Razor , EHD 0.42", Penetration 46.01",Log strip from TO (11227') through the tubing tail and acker.,da Ii hts r A r S/ 10/28/2018 RIG up frac Equipment,Safety meeting and operational meeting, PT Treating Iron Low 300 psi and High 8000 PSI Pump Data Frac using 30 # Linear Gel at 30 ppm. Analyze data redesign sand ramp for Frac.,Pump Propped Frac using 16/20 Resin Coated proppa1freeze crosslinked gel at 25 bpm. Average pressure about3200 psi. Placed a rox 105233# of ro ant into formation. flowed back diesel for Forced Closure rocedure.,RD frac Equipment and tree saver. Pre for FCO 10/30/2018 MIRU CTU #6 with 13,780' of 2" coil -Perform BOP Test to 300 psi low and 3,500 psi high. Tested Stripper, 2 x Blind/Shear Rams, Slips, pipe rams valve, Kill valve, Check valve, 6 valves on choke manifold, and accumulator system.,Assist in rigging up well test separator.,RIH to 2,500' and circulaprotect. Ice packing off in lubricator when attempting to POH. Unable to move coil. Circulate 85 degree 1 % KCL from 2,200' until coil moves freely. Frotect from 2 500'to surface. SDFN. 10/31/2018 CTU #6 w/ 2" coil. On location Stab onto well. P/T to 300 psi/4000 psi high. Bleed off to 2,000 psi and test check. All good tests.,Open well. WHP = while circulating 1% KCL at 2 BPM at 1,300 psi. At 2,500' reduce rate to 1 BPM. Weight check at 4,000' is 12,000 -lbs up and 5,000 -lbs down. Weig at 9,000' is 28,000 -lbs up and 8,000 -lbs down.,Dry tagged TOS at 10,767'. 36,000 -Ib pick up weight. 1:1 returns. Send gel sweep. Increase pump rate to 2.5 BPM. Gel at nozzle. Cleanout from 10,767' to 10,950'.,P/U from 10,950' and perform wiper trip to inside tubing. RBIH to 10,950' and cleanout to 11,050'. P/U from 11,050' and perform wiper trip to inside tubing. Send gel sweep. RBIH to 11,050' and cleanout to PBTD at 11,245' ctmd. POH and perform wiper trip into tubing. Send final gel sweep. RBIH to PBTD to 11,245',POH and chase final gel sweep to surface. See large amounts of proppant return in final gel sweep. Returns cleaned up 200' from surface.,At surface, close gate valve above pump in sub and attempt to flow well through test separator. Well will not flow. Call for N2. Soonest arrival is tomorrow morning at 6am.,RIH to freeze protect w/60140 to 2,500'. POH to surface. At surface. FP surface lines and tree. Secure well. Stand back injector. SDFN and wait for N2. 11/1/2018 On Location. Stab onto well. P/T to 300 psi and 4000 psi high. Bleed off to 2,000 psi and test check valve. Open well. WHP is 0 psi.,RIH to 5001. Cool down N2. P/T N2 lines to 5,000 psi. Bring N2 online at 500 scf/min and continue to RIH.,Stop at 2,900' and unload fluid column. Continue RIH while circulating N2 at 500 scf/min.,Stop at 4,500' and unload fluid column. Continue RIH while circulating N2 at 500 scf/min.,Stop at 6,500' and unload fluid column. Continue RIH while circulating N2 at 500 scf/min.,Stop at 8,080' and unload fluid column. Continue RIH while circulating N2 at 500 scf/min.,Continue RIH while circulating N2 at 500 scf/min. 225 bbls flowed back at 12:10 pm . Stop at 10,880' and unload fluid column. P/U weight is 33k-Ibs.,Divert flow to test separator. 355 bbls flowed back. Sample was 31% WC with trace solids. Flow well while lifting from tubing tail at 10,859. WC is varying from 20% to 2%. Solids are 0.1 %to 0. Rate is varying from 700 BPD to 400 BPD when well is being assisted with N2 at 750 scf/min.,POH to surface while continuing to flow well with 750 sit/min of N2. 425 bbis Flowed back at 20:OO.,At surface. Blow down lines and test separator with N2. Secure well Stand back injector. SDFN. 11/2/2018 On Location. Stab onto well. PIT to 300 psi and 4000 psi high. Bleed off to 2,000 psi and test check valve.,Open well. WHP is 900 psi. Bleed off N2 cap to flowback tank. RIH to tag PBTD.,Tag at 11,014'. Repeat tag of 11,014'. Pressure up to 500 psi on WHP with choke closed. WHP bled from 500 to 350 psi over 5 minutes. Tag TOS at 11,005'. Tag TOS at 11,000'. Tag TOS 11,000'.,POH to surface.,At surface, close swab. Stand back injector. Break and UD BHA. M/U Nipple Locator dressed to 2,300 lbs in 3.725".,RIH w/ nipple locator. P/U with locator and locate XN at 10,772'. 12' correction needed. RIH and tag TOS at 10,988' 10,976' . At surface close swab. Stand back injector. Break and UD BHA.,SDFN. 11/3/2018 On location. Stab onto well. PIT to 300 psi and 4000 psi high. Bleed off to 2,000 psi and test check valve.,Open well. WHP is 145 psi. RIH to to 10,850'. Circulate 1% KCI while RIH.,Stop at flag. Correct depth to 10,759'. P/U weight is 35k -lbs. Stop circulating. Tag TOS at 10976'. P/U to 10,850'. Circulate and fluid pack wellbore with 125 bbls of 1 % KCL. Well is static.,RIH and tag top of sand at 10,976'. Circulate 8 bbls NVis gel, 30 bbls KCI, 8 bbls gel, 30 bbls KCL, and 12 bbls gel. Cleanout to 11,085'.,Chase final gel sweep to surface while circulating 2.8 BPM.,At surface. UD SJN and M/U Pig Jet Nozzle. Stab onto well. P/T to 300 psi and 4000 psi high.,RIH wl pig jet nozzle.,Tag TOS at 10,986'. Pressure up to 1,500 psi. Bled off to 200 psi in 3 minutes. Pressure up again to 1,500 psi. Bled off to 200 psi in 3 minutes.,POH to surface.,At surface. Secure well. Stand back injector.,SDFN. 11/4/2018 CTU #6: On location. M/U BHA: 3.07CTC, 3.12" DBPV, 3.13" Jar, 3.11" Disconnect, 3.13" DCV (5/8" ball), 3.12" Xtreme Motor, 3.62" DB Underreamer, 3.7" Junk Mill -Stab onto well. P/T to 300 psi and 4000 psi high. Bleed off to 2,000 psi and test check valve.,Open well. WHP is 0 psi. RIH and circulate out 60/40 McOH at 0.3 BPM while RIH.,Stop at flag. Correct depth to 10,769'. P/U weight is 34k -lbs. Dry tag TOS at 10976'.,Pump 10 bbls of 509 gel. Begin underreaming from 10,976' to 11,030'. POH to 10,950'. Pump 10 bbis of 50# gel. RIH and begin underreaming from 11,030'11,085'. Pump 12 bbls of 50 # gel. Drop ball to open circ sub. POH to 10,950.RBIH to 11,085' with gel sweep at nozzle.,Chase gel sweeps to surface. POH. Ball hit. Increase rate to 3.5 BPM. POH to surface -LID Underreamer and MU Pig Jet Nozzle.,Stab onto well. P/T to 300 psi and 4000 psi high.,RIH and tag TOS at 11,06T,R/U LRS for diesel. Begin Batch mixing cement. Pump 5 bbls fresh water. Pump cement through the micromotion and out to the flowback tank with contaminant until 15.8 ppg is seen at the micro motion. Load first pig. Pump 0.9 bbl of 15.8 ppg cement. Load pig with ball. Pump 5 bbls fresh water. Switch to LRS and pump 31.5 bbls of diesel. Lay in 1 bbl of cement from 11,06T. Cement: 7 hours to get to 1000 psi comp. strength.,POH to 2,500'. Freeze protect well w/ diesel from 2509,At surface. Secure well. RDMO. 11/5/2018 Alaska E -Line arrive at Milne. Hold pre -job meeting. Clear frac equip from around well. Snow removal,MI RU E -Line. MU wt bar, 3.125" OD CCL, 2.5" OD junk basket with 3.60" gauge ring for drift run. Stab on well. PT with triplex to 300 psi 13000 psi.,T/I/O = 0/0/0. RIH. Tag PBTD. Log up, correlate to get on depth fh and find PBTD depth at 11,052' MD. No restrictions encountered. POOH,OOH. Close SV, BD, and pop off. UD drift tools. MU and arm 3.125" OD x Sped gun }`J loaded with 22.7 gm FraclO 40 charges - 6 SPF - 60 degree phasing. CCL to top shot = 8.76,RIH with GR/CCL and 5' pert gun. Tag PBTD. Make correlation pass. Tie into Halliburton MWD log dated 11 -Oct -2018. Tie in approved by Radu. Pull into shooting depth with CCL at 10991.25' with top shot at 11,000' / V bottom shot at 11,005' MD. Fire gun, log off and POOH.,OOH. Close SV, BD and pop off well. UD spent gun, ASF. RDMO. Job Complete 11/6/2016 PJSM with Oilstates tree saver hand, Wells Support, and crane operator. Discuss procedure for setting the tree saver and hazards.,Set OilStates tree Saver. Stroke cup mandrel down into tubing - cup mandrel dressed with cups for 4-1/2" 26# tubing. No restrictions encountered while stroking the tool down. SLB frac crew on site at 0800. Wells Support spot frac support tanks near well and hookup tattle tail bleed line from companion valve.,Fmc crew spot missile trailer, RU pumps, hardline to tree saver, and all bleedoff lines. All frac tanks loaded with 110 degree Fresh Water. 2175 bbls on site. SLB took water samples back to lab for final fluid testing. Spot POD blender and additional blender side equipment. LRS load diesel trailer used for flush with 85 bbls 90 degree diesel. RU complete - Ready for Frac tomorrow fry" 5h� D 11/7/2018 SLB Frac crew on site. PJSM. Fire up equip. Check comms with all equip. Spot support equip (vac trucks), perform final fluid testing, prime up pumps and PT hard line to 300 psi / 8000 psi - good test. LRS : Assist Frac held backside preesure of 2500 PSI, bled IA down to 0 PSI for Frac stimulation.,Hold PJSM with all - 21 people head count. / Co Rep with rig attend/ held meeting with Pad Op earlier / Discuss muster areas, emergency numbers, hazards and mitigation's, roles and responsibilities, job procedure., Put 2500 psi on backside with LRS pump and maintain 2500 -3000 psi throughout pumping. 5.2 bbls diesel used. Annulus pop -offs set at 3400 psi and 3200 psi. Manual valve on Tree Saver froze- apply heat until fully functional. Open well to 20/2589/15 4/1/0. Displace diesel from frac hardline with 20# gel. Shut down for 5 minutes.,Perform Data Frac using 20# linear gel. Initial pump rate of 30 bpm at 4145 psi WHP. Increased rate to 35 bpm /4500 psi - observed good pressure fall off from increasing rate. Perform step down test - 35 bpm / 25 bpm/ 15 bpm/ 10 bpm and shut down. 202 bbls pumped. ISIP = 1751 psi.,Analyse data frac info to determine any changes needed for final frac pump schedule,Pump main frac as per design -180 bbl Pad / Staged prop in from 1-9 ppg Ave pump rate = 30 bpm Ave treating pressure - 3300 psi (2426 HHP used) Max pressure = 3910 psi Total proppant pumped = 116,971# / Proppant behind pipe = 115,6909 / 1281 Has in well bore with est. TOS at 10,926' Total slurry volume pumped = 1286 bbls including data frac 11156 bbls clean fluid total pumped. Well freeze protected with 40 bbls diesel.,5/10/15 min pressures after shut down = 2052 psU1980 psi/ 1903 psi. Shut in well. Bleed IA to 0 psi. Begin flushing lines and RD. Tree Saver pulled and Rig down complete at 18:00. CTU on site to spot up on well 11/8/2'018 MIRU CTU #6 w/ 14,640' of 2" coil. Perform BOP Test to 300 psi low and 3,500 psi high. Tested Stripper, 2x Blind/Shear Rams, Slips, pipe rams, Choke valve, Kill valve, Check valve, 6 valves on choke manifold, and accumulator system.,Stab onto well. PIT to 300 psi and 4000 psi high. Bleed off to 2,000 psi and !,(� i ,� V test check valve. Open well. WHP is 0 psi.,RIH to TOS at 10,908'. Circulate 1 % KCL while RIH. Weight check at 10900' is 38k -lbs up and 6k down.,Cleanout to TOC at 11,065' while circulating at 2.8 BPM and 2,600 psi. Circulate 10 bbl NVis gel, 30 bbls 1 % KCL, 10 bbls NVis pill, 30 bbls 1 % KCL, 20 bbis NVis pill., Final gel sweep exiting nozle. Chase sweep to surface while POH and circulating 1 % KCL at 3 BPM. See large amount of proppant returns when coil is 1,000' from surface. Formation sand in returns as well.,Freeze protect coil with 37.5 bbls of 60140 McOH. FP well to 500'. Secure well. Stand back in ector. SDFN. 11/92018 On Location. Stab onto well. PIT to 300 psi and 4000 psi high. Bleed off to 2,000 psi and test check valve.,Open well. WHP is 0 psi. RIH to 3,500' while circulating at N2 at 750 scf/min at 1,500 psi. Rate at 1000 BPD.,R IH to 5,000' while circulating at N2 at 750 scf/min at 1,500 psi. Rate at 750 BPD., RIH to 6,500' while circulating at N2 at 750 scl/min at 1,500 psi. Rate at 2400 BPD.,RIH to 8,200' while circulating at N2 at 750 scf/min at 1,500 psi. Rate at 1000 BPD.,RIH to 3,500' while circulating at N2 at 750 scf/min at 1,500 psi. Rate at 1000 BPD.,Fluid returns decreasing. POH to 8,200'.,Lost fluid returns. RBIH to 10,600'. Increase N2 rate to 1200 scf/min for 5 minutes. Chase N2 slug to surface at 750 scf/min while POH. Lost fluid returns at 5,000'. Continue POH. Cut N2 at 3 000'. At surface. Well is dead. Total fluid flowed back is 430 bbls. SDFN 11/10/2018 M/U BHA #1: 3.07" CTC, 3.13" DBPV, 3.13" G Force Jar, 3.13" Disconnect, 3.13" DCV (518" ball), 3.13" Xtreme Motor, 3,625" Underreamer, 3.71" Junk Mill. Stab onto well. P/T to 300 psi and 4000 psi high. Bleed off to 2,000 psi and test check valve.,Open well. WHP is 700 psi. Start circulating 1 % KCL at 0.3 BPM at 900 psi. MM at 40 Bbls. RIH w/ BHA #1.,Dry tag at 11,054. Underream from 11,054'to 11,090' while circulating at 2.7 at 2,550 psi. Seeing work as s 1_ high as 3,000 psi. Send gel sweep.,POH and make wiperT to tubing fail-ai 1U,90U . Send gelsweep. an underream from 11,100' to PBTD at 11,220' while circulating at 2.7 BPM at 2,550 psi. Seeing work as high as 2,700 psi. Send gel sweep. 1:1 returns.,Drop 5/8" ball to open circ sub,Circu sub open. POH to surface. Gel at nozzle at tubing tail. Chase final sweep to surface.,At surface. Well is dead. Saw proppant back at surface when coil was at 1000'. RBIH and freeze protect the well with 60/40 McOH to 2,500' with 38 bbls.,Close swab. Stand back injector. Secure well. RDMO. 0/420/20 psi,Clear area around well for E Line to MIRU,MIRU Alaska E -line. MU toolstring of cable head, Wt bar, tubular spangs, CCL, chem cut anchor, chemical tube assy, severing head, space out connections, and 3.75" OD tapered swage. No-go on swage to severing ports on chem cutter+ 45 inches (3.75'). As per Halliburton spec sheet on packer the XN no go to center of cut area = 3.8' (45.6"). CCL to severing ports = 11.5'. CCL to 3.75" No-go = 15.25,PT PCE to 300 psi 12500 psi with field triplex. Open well to 0/50/0 psi - T/I/O. RIH with 3.5"" OD chem cutter and 3.75" OD no-go spaced out between each by 45". Land No-go in XN nipple at -10,766' TT. Appear to be on depth according to CCL log. See bottom collar of 1st full joint above the packer. Fire cutter and see 150# increase in line tension. Wait 10 minutes for anchors to retract.,Bottom No-go swage wedged into XN nipple. Work tubular spangs to pop free. POOH. anchor slips not fully retracted, seeing each collar as POOH. Eventually slips retract and POOH clean.,OOH. Chem cutter fired. Use PPE and bleed any trapped pressure from tools and for disassembling. Severing head appeared to have full coverage of discharge. RDMO E -Line. Job Complete.,MIRU ASR Rig 11/11/2018 Continue MIRU ASR Rig,, all mats spotted, rig spotted, BOP rippled up and torqued, pits filled and finalizing rig up to begin test BOP's,Continue to RU for Bope Test. RU tool carrier Bells and Elevators. start Shell test Bops 250PSI low 3000PSI high,Chase leaks and fix Leaks. also found Hydraulic choke and kill valves not functioning proper. Diagnose and fix problem.,Cont. to Test BOPE with 2 7/8" 8 4.5" test joint. rams 250 low/3000 high. Annular 250 Iow12500high . Prep equipment to POOH when finished with BOPE test. 11/1 / 018 Continue and complete BOP testing . Test VBR's with 2-7/8 and 4.5" test mandrels to 3000 psi, Annular to 2500psi, HCR's, TIW, ISOP, and choke and kill manifold and associated lines to 3000psi. All for Good Test.,Pull 2 -way check, attempt to pump down backside, pump 0.2 bbl and caught 500psi pressure, verify casing valve open and no ice in lines from pump, re -attempt to pump down casing but only pump 0.2 bbl before 500 psi, pump 12 bbls down tubing and catch S/D pump and wait 20 minutes and pump 8 bbls before loading hole. Fluid level at 800'.,Veriy tubing hanger unlocked and pull LOOK before V pressure, (I/hanger unseat, hanger pulled free very suddenly as if stuck, then pulled 146K before pipe weight broke over and indication of packer pulling free.,Lay down "� hanger and start POOH with weight ranging from 119K to 133K, acting as if packer dragging. Pump 15 bbls down tubing before loading hole. Fluid level at 44 1000' Continue POOH,Cont. POOH dragging PKR. Monitoring well. started swabbing CSG with PKR getting back diesel. RU to Flow back tank. 105 jnts out,Circulate Conventional 220 bbls to clean up the well,Cont. POOH with 4.5" #12.6 frac. string 11/13/2018 Continue POOH with 4.5" 12.6# frac string ... OOH @07:30. Inspect packer with no noticeable damage or areas for concern from external visual inspection. Pulled 266 joints 4.5" 12.6# L-80 TXP connection tubing, sent 266 joints plus all jewelry to G-1 to be cleaned. All jewelry was junked and all 266 joints 4.5" L-80 tubing is to be sent to Tuboscope for full inspection post cleaning at G-1 facility.,MIRU Baker Cantrilift, rig up sheaves, spoolers and associated running equipment. P/U motors and pump assembly and make up while RIH on 2-7/8" L-80 6.5# Tubing,P/U 2-7/8" 6.5# L-80 tubing and start RIH w/ tubing and ESP assembly. Test at surface and test every 1000' to 8450',ESP Cable reels lice 1 111 4/2 01 8 Continue RIH w/ 2-718" L-80 production string and ESP assembly, clamping every collar. Swapped out ESP cable spool and 318 capillary spool. Made splice and continue RIH w/ clamp on every collar and testing ESP and Capillary string every 1000'.,Terminate hanger, test terminations for good test. Land Hanger at 1400 hrs. Total joint count run 336 jts 2-7/8" 6.5# L-80 EUE tubing, ESP Centralizer @ 10,552' - X -N nipple @ 10,412' (2.313 ID and 2.505 no-go)- Lower GLM w/ 1" dummy valve BK2 latch @ 10,299 - upper GLM @ 135'w/ V DPSOV BK2 Latch - Run 338 X -collar clamps, 8 pump clamps, 3 protectolizers, 2 fit guards. Weight Down = 29K,RDMO ASR Rig , N/D BOP's„Final checks on esp test good. Tree up well head and test. 500psi low/5000psi high.,Cont, to move off L-41 and stack out A -Pad. Hilcorp Alaska, LLC Milne Point M Pt L Pad MPU L-41 500292361100 Sperry Drilling Definitive Survey Report 11 October, 2018 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU L-41 Project: Milne Point TVD Reference: MPU L-41 Actual @ 50.20usft Site: M Pt L Pad MD Reference: MPU L-41 Actual @ 50.20usft Well: MPU L-41 North Reference: True Wellbore: MPU L-41 Survey Calculation Method: Minimum Curvature Design: MPU L-41 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 MPU L-41, Well Position +NIS +E/ -W Position Uncertainty 0.00 usft Northing: 0.00 usft Easting: 0.00 usft Wellhead Elevation: 6,031,767.05 usfl 544,744.45 usfl 16.50 usfl Latitude: Longitude: Ground Level: 70° 29'51.572 N 149° 38'2.738 W 16.50 usft Wellbore MPU L-41 Magnetics Model Name Sample Date Declination Dip Angle Field Strength Map Vertical MD Inc Azi (nT) TVDSS BGGM2018 9/26/2018 Northing 17.01 81.00 57,453 Design MPU L-41 (I (usft) (usft) (usft) (usft) Audit Notes: (ft) (°1100') (ft) Survey Tool Name 33.70 0.00 0.00 Version: 1.0 Phase: ACTUAL Tie On Depth: 7,363.62 Vertical Section: 0.00 UNDEFINED Depth From (TVD) +N/ -S +El -W Direction 49.80 -0.11 (usft) (usft) (usfl) 0.38 (I 200.00 0.69 33.70 0.00 0.00 -0.81 16.03 Survey Program Date 10/10/2018 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 100.00 817.00 MPU L-41 PB1 Gyro (MPU L-41 PB1) 2_Gyro-NS-GC_Drill coil: H029Ga: North seeking single shot in drill colla 08/24/2018 883.91 7,333.45 MPU L-41 PB1 MWD+IFR2+MS+sag (MF 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 08/31/2018 7,363.62 7,363.62 MPU L-41 PB1 MWD_Interp Azi+Sag(MF 2_ MWD_Interp Azi+Sag H003Mb: Interpolated azimuth+ sag correction 09/24/2018 7,392.00 7,392.00 MPU L-41 MWD_Interp Azi+Sag (MPU L 2_MWD _Interp Azi+Sag H003Mb: Interpolated azimuth +sag correction 09/28/2018 7,450.61 11,286.08 MPU L-41 MWD+IFR2+MS+Sag (MPU L2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 10/05/2018 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (I (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 33.70 0.00 0.00 33.70 -16.50 0.00 0.00 6,031,767.05 544,744.45 0.00 0.00 UNDEFINED 100.00 0.25 137.27 100.00 49.80 -0.11 0.10 6,031,766.95 544,744.55 0.38 -0.08 2_Gyro-NS-GC_Drill collar (I 200.00 0.69 154.88 200.00 149.80 -0.81 0.50 6,031,766.24 544,744.96 0.46 -0.64 2_Gyro-NS-GC Dnll collar (I 300.00 1.01 159.15 299.99 249.79 -2.18 1.07 6,031,764.88 544,745.53 0.33 -1.80 2_Gyro-NS-GC_Drill collar (1 350.00 1.27 163.61 349.98 299.78 -3.12 1.38 6,031,763.94 544,745.85 0.55 -2.62 2_Gym-NS-GC_DdIl collar (I 443.00 1.64 161.73 442.95 392.75 -5.38 2.09 6,031,761.69 544,746.57 0.40 -4.59 2_Gym-NS.GC_Drill collar (1 536.00 1.33 154.74 535.91 485.71 .7.62 2.97 6,031,759.45 544,747.47 0.39 -6.50 2_Gym-NS-GC_Drill collar (1 629.00 1.56 24.50 628.90 578.70 -7.44 3.96 6,031,759.64 544,748.45 2.82 -6.06 2_Gyro-NS-GC_Drill collar (1 723.00 4.45 24.19 722.76 672.56 -2.95 5.98 6,031,764.14 544,750.45 3.07 -1.18 2_Gyro-NS-GC_Ddil collar (1 817.00 7.41 31.39 816.25 766.05 5.55 10.63 6,031,772.67 544,755.05 3.24 8.27 2_Gyro.NS.GC_Drill collar (1 10/112018 7:08:37PM Page 2 COMPASS 5000.1 Build 81E Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: MPU L-41 Wellbore: MPU L-41 Design: MPU L-41 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: Well MPU L-41 TVD Reference: MPU L-41 Actual @ 50.20usft MD Reference: MPU L-41 Actual @ 50.20usft North Reference: True Survey Calculation Method: Minimum Curvature Database: Sperry EDM - NORTH US + CANADA 10/11/2018 7:08:37PM Page 3 COMPASS 5000.1 Build SIE Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 883.91 9.97 30.37 882.39 832.19 14.24 15.81 6,031,781.38 544,760.17 3.83 18.05 2_MWD+IFR2+MS+Sag(2) 977.50 13.47 29.46 974.01 923.81 30.72 25.27 6,031,797.92 544,769.53 3.74 36.51 2_MWD+IFR2+MS+Sag(2) 1,071.50 16.75 24.21 1,064.75 1,014.55 52.62 36.21 6,031,819.88 544,780.34 3.78 60.57 2_MWD+IFR2+MS+Sag(2) 1,165.98 17.67 21.84 1,155.00 1,104.80 78.34 47.13 6,031,845.67 544,791.10 1.22 88.31 2_MWD+IFR2+MS+Sag(2) 1,260.89 16.36 20.42 1,245.76 1,195.56 104.24 57.15 6,031,871.62 544,800.97 1.45 115.97 2_MWD+IFR2+MS+Sag (2) 1,354.13 16.57 13.64 1,335.18 1,284.98 129.47 64.87 6,031,896.90 544,808.53 2.07 142.35 2_MWD+IFR2+MS+Sag (2) 1,449.00 16.69 14.09 1,426.08 1,375.88 155.83 71.38 6,031,923.29 544,814.88 0.19 169.48 2_MWD+IFR2+MS+Sag (2) 1,543.56 18.97 12.20 1,516.10 1,465.90 184.03 77.93 6,031,951.53 544,821.27 2.49 198.39 2_MWD+IFR2+MS+Sag (2) 1,637.63 23.65 15.74 1,603.71 1,553.51 217.15 86.29 6,031,984.70 544,829.42 5.16 232.54 2_MWD+IFR2+MS+Sag (2) 1,732.53 28.54 14.08 1,688.91 1,638.71 257.49 96.97 6,032,025.09 544,839.86 5.21 274.25 2_MWD+IFR2+MS+Sag (2) 1,826.68 33.47 12.38 1,769.59 1,719.39 304.69 108.02 6,032,072.36 544,850.62 5.32 322.67 2_MWD+IFR2+MS+Sag(2) 1,921.31 38.50 14.32 1,846.14 1,795.94 358.75 120.90 6,032,126.49 544,863.18 5.45 378.19 2_MWD+IFR2+MS+Sag(2) 2,015.91 43.94 16.52 1,917.27 1,867.07 418.80 137.53 6,032,186.63 544,879.45 5.95 440.49 2_MWD+IFR2+MS+Sag(2) 2,109.76 48.18 17.53 1,982.38 1,932.18 483.39 157.34 6,032,251.33 544,898.86 4.58 508.04 2_MWD+IFR2+MS+Sag(2) 2,204.15 52.61 14.30 2,042.55 1,992.35 553.31 177.20 6,032,321.37 544,918.30 5.38 580.73 2_MWD+IFR2+MS+Sag(2) 2,297.87 56.46 15.20 2,096.92 2,046.72 627.11 196.65 6,032,395.27 544,937.30 4.18 657.03 2_MWD+IFR2+MS+Sag(2) 2,392.99 59.16 15.58 2,147.59 2,097.39 704.71 218.01 6,032,473.00 544,958.20 2.86 737.52 2_MWD+IFR2+MS+Sag(2) 2,486.95 60.17 15.54 2,195.04 2,144.84 782.84 239.77 6,032,551.24 544,979.48 1.08 818.61 2_MWD+IFR2+MS+Sag(2) 2,580.15 59.39 14.94 2,241.95 2,191.75 860.54 260.94 6,032,629.06 545,000.18 1.00 899.13 2_MWD+IFR2+MS+Sag(2) 2,674.35 59.24 15.32 2,290.02 2,239.82 938.74 282.08 6,032,707.38 545,020.85 0.38 980.13 2_MWD+IFR2+MS+Sag(2) 2,769.23 58.55 15.84 2,339.04 2,288.84 1,016.99 303.90 6,032,785.75 545,042.19 0.87 1,061.37 2_MWD+IFR2+MS+Sag(2) 2,863.44 57.68 15.90 2,388.80 2,338.60 1,093.94 325.77 6,032,862.82 545,063.60 0.93 1,141.36 2_MWD+IFR2+MS+Sag(2) 2,957.50 60.49 16.36 2,437.12 2,386.92 1,171.45 348.20 6,032,940.46 545,085.55 3.02 1,222.05 2_MWD+IFR2+MS+Sag(2) 3,051.56 60.39 16.39 2,483.52 2,433.32 1,249.95 371.26 6,033,019.09 545,108.14 0.11 1,303.87 2_MWD+IFR2+MS+Sag(2) 3,146.62 59.92 17.04 2,530.83 2,480.63 1,328.91 394.97 6,033,098.19 545,131.38 0.77 1,386.31 2_MWD+IFR2+MS+Sag(2) 3,241.17 59.59 17.16 2,578.46 2,528.26 1,406.98 418.99 6,033,176.39 545,154.92 0.37 1,467.98 2_MWD+IFR2+MS+Sag(2) 3,335.49 59.22 17.70 2,626.46 2,576.26 1,484.44 443.31 6,033,253.99 545,178.77 0.63 1,549.14 2 MWD+IFR2+MS+Sag(2) 3,430.35 59.29 17.49 2,674.96 2,624.76 1,562.16 467.95 6,033,331.84 545,202.95 0.20 1,630.64 2_MWD+IFR2+MS+Sag(2) 3,524.76 58.92 18.12 2,723.43 2,673.23 1,639.29 492.73 6,033,409.12 545,227.25 0.69 1,711.61 2_MWD+IFR2+MS+Sag(2) 3,618.61 59.01 16.13 2,771.82 2,721.62 1,716.14 516.40 6,033,486.10 545,250.46 1.82 1,792.01 2_MWD+IFR2+MS+Sag(2) 3,712.37 58.85 15.55 2,820.21 2,770.01 1,793.39 538.32 6,033,563.48 545,271.92 0.56 1,872.32 2 MWD+IFR2+MS+Sag(2) 3,807.22 58.95 15.61 2,869.20 2,819.00 1,871.63 560.14 6,033,641.83 545,293.26 0.12 1,953.53 2_MWD+11`112+MS+Sag(2) 3,901.84 59.17 15.68 2,917.85 2,867.65 1,949.78 582.02 6,033,720.10 545,314.67 0.24 2,034.68 2_MWD+IFR2+MS+Sag(2) 3,996.14 58.92 16.30 2,966.36 2,916.16 2,027.52 604.30 6,033,797.97 545,336.47 0.62 2,115.55 2_MWD+IFR2+MS+Sag(2) 4,090.32 59.59 15.03 3,014.50 2,964.30 2,105.45 626.15 6,033,876.03 545,357.85 1.36 2,196.49 2_MWD+IFR2+MS+Sag(2) 4,185.14 59.73 15.46 3,062.40 3,012.20 2,184.40 647.67 6,033,955.10 545,378.89 0.42 2,278.32 2_MWD+IFR2+MS+Sag(2) 4,279.49 58.36 13.13 3,110.93 3,060.73 2,262.80 667.66 6,034,033.61 545,398.41 2.57 2,359.18 2_MWD+IFR2+MS+Sag(2) 4,373.14 57.85 14.21 3,160.42 3,110.22 2,340.05 686.44 6,034,110.97 545,416.73 1.12 2,438.62 2_MWD+IFR2+MS+Sag(2) 4,467.16 57.71 14.74 3,210.54 3,160.34 2,417.07 706.33 6,034,188.09 545,436.14 0.50 2,518.13 2_MWD+IFR2+MS+Sag (2) 4,561.90 58.07 14.61 3,260.90 3,210.70 2,494.70 726.66 6,034,265.84 545,456.00 0.40 2,598.36 2_MWD+IFR2+MS+Sag(2) 10/11/2018 7:08:37PM Page 3 COMPASS 5000.1 Build SIE Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Coordinate Reference: Well MPU L-41 Project: Milne Point TVD Reference: MPU L41 Actual @ 50.20usft Site: M Pt L Pad MD Reference: MPU L41 Actual @ 50.20usft Well: MPU L-41 North Reference: True Wellbore: MPU L41 Survey Calculation Method: Minimum Curvature Design: MPU L-41 Database: Sperry EDM - NORTH US + CANADA Survey MapMap Vertical MD Inc Azi TVD TVDSS +N1 -S +EI -W Northing Easting DLS Section (usft) (I (I (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 4,656.28 58.48 15.12 3,310.53 3,260.33 2,572.29 747.25 6,034,343.54 545,476.13 0.63 2,678.62 2_MWD+IFR2+MS+Sag (2) 4,750.80 58.55 15.27 3,359.90 3,309.70 2,650.08 768.38 6,034,421.45 545,496.79 0.15 2,759.22 2_MWD+IFR2+MS+Sag (2) 4,845.32 58.91 15.80 3,408.96 3,358.76 2,727.91 790.02 6,034,499.40 545,517.95 0.61 4840.00 2_MWD+IFR2+MS+Sag (2) 4,939.80 59.38 15.56 3,457.42 3,407.22 2,806.00 811.94 6,034,577.62 545,539.40 0.54 2,921.11 2_MWD+IFR2+MS+Sag (2) 5,033.95 61.37 15.85 3,503.95 3,453.75 2,884.79 834.09 6,034,656.52 545,561.08 2.13 3,002.94 2_MWD+IFR2+MS+Sag (2) 5,128.64 61.05 15.43 3,549.56 3,499.36 2,964.70 856.46 6,034,736.56 545,582.97 0.52 3,085.93 2_MWD+IFR2+MS+Sag (2) 5,223.05 59.95 14.80 3,596.05 3,545.85 3,044.02 877.89 6,034,816.01 545,603.92 1.30 3,168.09 2_MWD+IFR2+MS+Sag (2) 5,317.38 59.08 14.81 3,643.90 3,593.70 3,122.61 898.66 6,034,894.71 545,624.21 0.92 3,249.36 2_MWD+IFR2+MS+Sag (2) 5,411.89 57.83 14.70 3,693.34 3,643.14 3,200.50 919.18 6,034,972.71 545,644.25 1.33 3,329.88 2_MWD+IFR2+MS+Sag (2) 5,507.00 58.72 14.49 3,743.36 3,693.16 3,278.79 939.56 6,035,051.12 545,664.17 0.95 3,410.75 2_MWD+IFR2+MS+Sag (2) 5,601.06 58.49 14.74 3,792.36 3,742.16 3,356.48 959.82 6,035,128.92 545,683.95 0.33 3,491.02 2_MWD+IFR2+MS+Sag(2) 5,694.88 58.26 15.40 3,841.55 3,791.35 3,433.62 980.59 6,035,206.18 545,704.26 0.65 3,570.89 2_MWD+IFR2+MS+Sag(2) 5,788.33 57.03 15.14 3,891.56 3,841.36 3,509.77 1,001.38 6,035,282.44 545,724.59 1.34 3,649.82 2_MWD+IFR2+MS+Sag(2) 5,883.69 57.48 18.00 3,943.15 3,892.95 3,586.63 1,024.26 6,035,359.43 545,747.00 2.57 3,730.01 2_MWD+IFR2+MS+Sag(2) 5,978.09 57.83 17.92 3,993.66 3,943.46 3,662.50 1,048.85 6,035,435.44 545,771.13 0.38 3,809.72 2_MWD+IFR2+MS+Sag(2) 6,072.17 58.50 17.58 4,043.28 3,993.08 3,738.62 1,073.21 6,035,511.70 545,795.03 0.78 3,889.61 2_MWD+IFR2+MS+Sag(2) 6,166.62 59.36 18.48 4,092.02 4,041.82 3,815.55 1,098.25 6,035,588.77 545,819.61 1.22 3,970.46 2_MWD+IFR2+MS+Sag(2) 6,261.56 59.58 18.92 4,140.25 4,090.05 3,893.01 1,124.47 6,035,666.38 545,845.36 0.46 4,052.15 2_MWD+IFR2+MS+Sag(2) 6,355.24 59.20 19.82 4,187.95 4,137.75 3,969.07 1,151.21 6,035,742.59 545,871.64 0.92 4,132.64 2_MWD+IFR2+MS+Sag(2) 6,449.84 59.64 16.78 4,236.09 4,185.89 4,046.38 1,176.78 6,035,820.05 545,896.73 2.81 4,214.00 2_MWD+IFR2+MS+Sag(2) 6,543.86 59.18 16.96 4,283.94 4,233.74 4,123.83 1,200.26 6,035,897.63 545,919.75 0.52 4,294.93 2_MWD+IFR2+MS+Sag(2) 6,638.41 59.24 15.73 4,332.34 4,282.14 4,201.77 1,223.12 6,035,975.70 545,942.14 1.12 4,376.15 2_MWD+IFR2+MS+Sag(2) 6,732.82 58.85 16.30 4,380.90 4,330.70 4,279.59 1,245.46 6,036,053.64 545,964.00 0.66 4,457.11 2_MWD+IFR2+MS+Sag(2) 6,827.18 58.69 14.00 4,429.83 4,379.63 4,357.47 1,266.54 6,036,131.64 545,984.62 2.09 4,537.78 2_MWD+IFR2+MS+Sag(2) 6,921.24 59.89 14.02 4,477.86 4,427.66 4,435.93 1,286.12 6,036,210.21 546,003.72 1.28 4,618.60 2_MWD+IFR2+MS+Sag(2) 7,015.91 58.81 13.77 4,526.12 4,475.92 4,514.99 1,305.68 6,036,289.37 546,022.80 1.16 4,699.98 2_MWD+IFR2+MS+Sag(2) 7,109.76 59.38 15.01 4,574.33 4,524.13 4,592.98 1,325.69 6,036,367.48 546,042.34 1.29 4,780.47 2_MWD+IFR2+MS+Sag(2) 7,205.01 60.15 14.94 4,622.29 4,572.09 4,672.48 1,346.96 6,036,447.10 546,063.13 0.81 4,862.75 2 MWD+IFR2+MS+Sag(2) 7,299.00 61.84 15.03 4,667.86 4,617.66 4,751.88 1,368.21 6,036,526.62 546,083.90 1.80 4,944.94 2_MWD+IFR2+MS+Sag(2) 7,333.45 61 Al 15.06 4,684.23 4,634.03 4,781.16 1,376.08 6,036,555.94 546,091.59 1.25 4,975.24 2_MWD+IFR2+MS+Sag(2) 7,363.62 61.16 15.03 4,698.73 4,648.53 4,806.71 1,382.95 6,036,581.53 546,098.30 0.83 5,001.70 2_MWD_Inlem Azi+Sag(3) 7,392.00 60.77 15.01 4,712.50 4,662.30 4,830.67 1,389.38 6,036,605.53 546,104.59 1.38 5,026.51 2_ MWD_Interp Azi+Sag(4) 7,450.61 57.36 16.34 4,742.63 4,692.43 4,879.07 1,402.95 6,036,654.00 546,117.87 6.13 5,076.77 2_MWD+IFR2+MS+Sag(5) 7,547.16 53.21 18.79 4,797.61 4,747.41 4,954.72 1,426.85 6,036,729.79 546,141.31 4.78 5,156.08 2_MWD+IFR2+MS+Sag(5) 7,641.70 52.31 22.32 4,854.83 4,804.63 5,025.18 1,453.26 6,036,800.39 546,167.29 3.12 5,231.09 2_MWD+IFR2+MS+Sag(5) 7,739.46 53.43 22.71 4,913.84 4,863.64 5,097.18 1,483.10 6,036,872.56 546,196.70 1.19 5,308.53 2_MWD+IFR2+MS+Sag(5) 7,833.70 54.99 22.58 4,968.95 4,918.75 5,167.73 1,512.53 6,036,943.28 546,225.70 1.66 5,384.46 2_MWD+IFR2+MS+Sag(5) 7,928.32 56.43 23.24 5,022.26 4,972.06 5,239.73 1,542.97 6,037,015.46 546,255.70 1.63 5,462.07 2 MWD+IFR2+MS+Sag(5) 8,022.77 59.17 20.87 5,072.59 5,022.39 5,313.80 1,572.95 6,037,089.70 546,285.23 3.59 5,541.54 2_MWD+IFR2+MS+Sag (5) 8,116.92 60.95 18.82 5,119.58 5,069.38 5,390.53 1,600.63 6,037,166.59 546,312.45 2.67 5,622.94 2_MWD+IFR2+MS+Sag(5) 10/112018 7:08:37PM Page 4 COMPASS 5000.1 Build 81E Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: MPU L-41 Wellbore: MPU L-41 Design: MPU L-41 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Map MD Inc Azi TVD TVDSS +NIS +El -W Northing (usft) (") (1) (usft) (usft) (usft) (usft) (ft) 8,211.47 61.01 16.51 5,165.45 5,115.25 5,469.31 1,625.72 6,037,245.51 8,305.54 61.23 16.28 5,210.88 5,160.68 5,548.33 1,648.97 6,037,324.66 8,399.64 61.08 15.56 5,256.28 5,206.08 5,627.59 1,671.58 6,037,404.05 8,493.88 61.15 15.04 5,301.81 5,251.61 5,707.18 1,693.35 6,037,483.76 8,588.92 61.04 15.37 5,347.74 5,297.54 5,787.47 1,715.17 6,037,564.17 8,680.30 61.03 17.22 5,392.00 5,341.80 5,864.20 1,737.60 6,037,641.03 8,777.00 61.02 17.10 5,438.85 5,388.65 5,945.03 1,762.56 6,037,722.00 8,871.09 61.20 17.59 5,484.30 5,434.10 6,023.67 1,787.12 6,037,800.78 8,966.20 61.16 16.44 5,530.15 5,479.95 6,103.35 1,811.50 6,037,880.59 9,060.91 58.63 17.60 5,577.66 5,527.46 6,181.69 1,835.47 6,037,959.07 9,154.18 55.84 16.88 5,628.13 5,577.93 6,256.58 1,858.72 6,038,034.10 9,249.02 52.32 16.79 5,683.76 5,633.56 6,330.08 1,880.97 6,038,107.72 9,339.27 48.99 14.70 5,740.97 5,690.77 '6,397.24 1,899.93 6,038,174.98 9,438.03 46.14 15.41 5,807.60 5,757.40 6,467.62 1,918.85 6,038,245.47 9,531.87 43.87 16.30 5,873.95 5,823.75 6,531.45 1,936.97 6,038,309.40 9,625.95 41.49 16.23 5,943.11 5,892.91 6,592.67 1,954.83 6,038,370.72 9,719.99 38.53 15.77 6,015.13 5,964.93 6,650.78 1,971.50 6,038,428.93 9,813.67 36.04 15.29 6,089.66 6,039.46 6,705.45 1,986.70 6,038,483.68 9,906.39 33.44 16.78 6,165.84 6,115.64 6,756.23 2,001.27 6,038,534.55 10,002.55 30.23 18.17 6,247.53 6,197.33 6,804.61 2,016.47 6,038,583.01 10,098.60 27.82 19.35 6,331.51 6,281.31 6,848.74 2,031.44 6,038,627.22 10,190.62 24.93 18.50 6,413.94 6,363.74 6,887.40 2,044.71 6,038,665.96 10,287.15 22.50 18.37 6,502.31 6,452.11 6,924.23 2,056.99 6,038,702.86 10,381.60 20.02 19.05 6,590.33 6,540.13 6,956.66 2,067.97 6,038,735.36 10,474.84 19.99 19.42 6,677.94 6,627.74 6,986.78 2,078.47 6,038,765.53 10,569.99 20.03 18.97 6,767.35 6,717.15 7,017.53 2,089.18 6,038,796.34 10,664.90 19.82 17.66 6,856.58 6,806.38 7,048.23 2,099.34 6,038,827.10 10,759.06 19.91 19.65 6,945.14 6,894.94 7,078.54 2,109.58 6,038,857.47 10,853.13 19.97 19.68 7,033.57 6,983.37 7,106.75 2,120.37 6,038,887.74 10,946.73 20.22 20.66 7,121.47 7,071.27 7,138.94 2,131.46 6,038,917.99 11,040.69 19.86 19.97 7,209.74 7,159.54 7,169.13 2,142.64 6,038,948.25 11,134.88 19.81 17.36 7,298.35 7,248.15 7,199.40 2,152.87 6,038,978.58 11,229.49 20.23 19.15 7,387.24 7,337.04 7,230.16 2,163.02 6,039,009.39 11,286.08 19.81 18.77 7,440.41 7,390.21 7,248.48 2,169.31 6,039,027.75 11,315.00 19.81 18.77 7,467.62 7,417.42 7,257.76 2,172.47 6,039,037.05 Well MPU L41 MPU L41 Actual @ 50.20usft MPU L41 Actual @ 50.20usft True Minimum Curvature Sperry EDM - NORTH US + CANADA Map Vertical Easting DLS Section (ft) (°1100') (ft) Survey Tool Name 546,337.06 2.14 5,705.57 2_MWD+IFR2+MS+Sag (5) 546,359.83 0.32 5,787.94 2_MWD+IFR2+MS+Sag (5) 546,381.96 0.69 5,870.37 2_MWD+IFR2+MS+Sag (5) 546,403.25 0.49 5,952.87 2_MWD+IFR2+MS+Sag (5) 546,424.58 0.33 6,036.07 2_MWD+IFR2+MS+Sag (5) 546,446.55 1.77 6,116.01 2_MWD+IFR2+MS+Sag (5) 546,471.02 0.11 6,200.59 2_MWD+IFR2+MS+Sag (5) 546,495.10 0.49 6,282.95 2_MWD+IFR2+MS+Sag (5) 546,519.01 1.06 6,366.26 2_MWD+IFR2+MS+Sag (5) 546,542.50 2.87 6,448.18 2_MWD+IFR2+MS+Sag (5) 546,565.30 3.06 6,526.58 2_MWD+IFR2+MS+Sag (5) 546,587.09 3.71 6,603.37 2_MWD+IFR2+MS+Sag(5) 546,605.65 4.10 6,673.14 2_MWD+IFR2+MS+Sag(5) 546,624.15 2.93 6,746.01 2_MWD+IFR2+MS+Sag(5) 546,641.88 2.51 6,812.37 2_MWD+IFR2+MS+Sag(5) 546,659.37 2.53 6,876.14 2_MWD+IFR2+MS+Sag(5) 546,675.69 3.16 6,936.59 2_MWD+IFR2+MS+Sag(5) 546,690.56 2.68 6,993.34 2_MWD+IFR2+MS+Sag(5) 546,704.82 2.95 7,046.16 2_MWD+IFR2+MS+Sag(5) 546,719.73 3.42 7,096.86 2_MWD+IFR2+MS+Sag(5) 546,734.43 2.58 7,143.41 2 MWD+IFR2+MS+Sag(5) 546,747.47 3.17 7,184.23 2_MWD+IFR2+MS+Sag(5) 546,759.52 2.52 7,223.01 2_MWD+IFR2+MS+Sag(6) 546,770.30 2.64 7,257.22 2_MWD+IFR2+MS+Sag(5) 546,780.63 0.14 7,289.07 2_MWD+IFR2+MS+Sag(5) 546,791.15 0.17 7,321.58 2_MWD+IFR2+MS+Sag(5) 546,801.12 0.52 7,353.89 2_MWD+IFR2+MS+Sag (5) 546,811.17 0.72 7,385.85 2_MWD+IFR2+MS+Sag(5) 546,821.79 0.06 7,417.87 2_MWD+IFR2+MS+Sag (5) 546,832.69 0.45 7,449.94 2_MWD+IFR2+MS+Sag (5) 646,843.69 0.46 7,482.05 2 MWD+IFR2+MS+Sag (5) 546,853.73 0.94 7,513.97 2_MWD+IFR2+MS+Sag (5) 546,863.70 0.79 7,546.33 2_MWD+IFR2+MS+Sag (5) 546,869.88 0.78 7,565.68 2_MWD+IFR2+MS+Sag (5) 546,872.98 0.00 7,575.47 PROJECTEDto TD Checked By: Chelsea Wright =' Approved By: Mitch Laird'tr Date: 10/11/2018 10/112018 7:08:37PM Page 5 COMPASS 5000.1 Build 81E Hilcorp Milne Point M Pt L Pad MPU L-41PB1 500292361170 Alaska, LLC Sperry Drilling Definitive Survey Report 11 October, 2018 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU L-41 Project: Milne Point TVD Reference: MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14 Site: M Pt L Pad MD Reference: MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14 Well: MPU L-41 North Reference: True Wellbore: MPU L-41 PB1 Survey Calculation Method: Minimum Curvature Design: MPU L-41 PB1 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 CON US) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPU L-41 Well Position +N/ -S 0.00 usft Northing: 6,031,767.05 usfl Latitude: 70° 29'51.572 N +EI -W 0.00 usft Easting: 544,744.45 usfl Longitude: 149° 38'2.738 W Position Uncertainty 0.00 usft Wellhead Elevation: 16.50 usft Ground Level: 16.50 usft Wellbore MPU L-41 PB1 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2018 9/1/2018 17.05 81.00 57,455 Design MPU L-41PB1 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 33.70 Vertical Section: Depth From (TVD) +NIS +E/ -W Direction (usft) (usft) (usft) (°) 33.70 0.00 0.00 26.48 Survey Program Date 10/4/2018 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Dale 100.00 817.00 MPU L-41PB1 Gyro (MPU L-41PB1) 2_Gyro-NS-GC_Drill colli H029Ga: North seeking single shot in drill colla 08/24/2018 883.91 7,333.45 MPU L-41 P81 MWD+IFR2+MS+sag (MF 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sa 08/31/2018 7,363.62 7,363.62 MPU L-41 P81 MWD_Inlerp Azi+Sag(MF 2_MWD _Interp Azi+Sag H003Mb: Interpolated azimuth+ sag correction 09/2412018 7,457.99 10,666.05 MPU L41 PB1 MWD+IFR2+MS+sag(2) 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec& multi -station analysis +sa 09/11/2018 10,703.74 11,306.91 MPU L41PB1 MWD+IFR2+MS+sag (3) 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + as 09/20/2018 Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +EI -W Northing Easting DLS Section (usft) M (I (usft) (usft) (usft) (usft) (ft) (ft) ('1100') (ft) Survey Tool Name 33.70 0.00 0.00 33.70 -16.50 0.00 0.00 6,031,767.05 544,744.45 0.00 0.00 UNDEFINED 100.00 0.25 137.27 100.00 49.80 -0.11 0.10 6,031,766.95 544,744.55 0.38 -0.05 2_Gyro-NS-GC_Drill collar It 200.00 0.69 154.88 200.00 149.80 -0.81 0.50 6,031,766.24 544,744.96 0.46 -0.50 2_Gyro-NS-GC_Dnll cellar It 300.00 1.01 159.15 299.99 249.79 -2.18 1.07 6,031,764.88 544,745.53 0.33 -1.47 2_Gyro-NS-GC_Dnll collar (I 350.00 1.27 163.61 349.98 299.78 -3.12 1.38 6,031,763.94 544,745.85 0.55 -2.18 2 Gyro-NS-GC_Dnll collar (I 443.00 1.64 161.73 442.95 392.75 -5.38 2.09 6,031,761.69 544,746.57 0.40 -3.88 2_Gyro-NS-GC_DnII cellar (11 536.00 1.33 154.74 535.91 485.71 -7.62 2.97 6,031,759.45 544,747.47 0.39 -5.49 2_Gyro-NS-GC_Drill cellar (11 629.00 1.56 24.50 628.90 578.70 -7.44 3.96 6,031,759.64 544,748.45 2.82 -4.90 2_Gyro-NS-GC_Drill collar (1 723.00 4.45 24.19 722.76 672.56 -2.95 5.98 6,031,764.14 544,750.45 3.07 0.03 2_Gyro-NS-GC Drill collar (1 817.00 7.41 31.39 816.25 766.05 5.55 10.63 6,031,772.67 544,755.05 3.24 9.71 2_Gyro-NS-GC_Drill cellar (1 10/112018 7:21:45PM Page 2 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU L-41 Project: Milne Point TVD Reference: MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14 Site: M Pt L Pad MD Reference: MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14 Well: MPU L-41 North Reference: True Wellbore: MPU L-41PB1 Survey Calculation Method: Minimum Curvature Design: MPU L-41PB1 Database: Sperry EDM - NORTH US+CANADA Survey - Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 883.91 9.97 30.37 882.39 832.19 14.24 15.81 6,031,781.38 544,760.17 3.83 19.79 2_MWD+IFR2+MS+Sag (2) 977.50 13.47 29.46 974.01 923.81 30.72 25.27 6,031,797.92 544,769.53 3.74 38.77 2_MWD+IFR2+MS+Sag (2) 1,071.50 16.75 24.21 1,064.75 1,014.55 52.62 36.21 6,031,819.88 544,780.34 3.78 63.24 2_MWD+IFR2+MS+Sag (2) 1,165.98 17.67 21.84 1,155.00 1,104.80 78.34 47.13 6,031,845.67 544,791.10 1.22 91.14 2_MWD+IFR2+MS+Sag (2) 1,260.89 16.36 20.42 1,245.76 1,195.56 104.24 57.15 6,031,871.62 544,800.97 1.45 118.79 2_MWD+IFR2+MS+Sag (2) 1,354.13 16.57 13.64 1,335.18 1,284.98 129.47 64.87 6,031,896.90 544,808.53 2.07 144.81 2_MWD+IFR2+MS+Sag (2) 1,449.00 16.69 14.09 1,426.08 1,375.88 155.83 71.38 6,031,923.29 544,814.88 0.19 171.31 2_MWD+IFR2+MS+Sag (2) 1,543.56 18.97 12.20 1,516.10 1,465.90 184.03 77.93 6,031,951.53 544,821.27 2.49 199.47 2 MWD+IFR2+MS+Sag (2) 1,637.63 23.65 15.74 1,603.71 1,553.51 217.15 86.29 6,031,984.70 544,829.42 5.16 232.84 2_MWD+IFR2+MS+Sag (2) 1,732.53 28.54 14.08 1,688.91 1,638.71 257.49 96.97 6,032,025.09 544,839.86 5.21 273.71 2_MWD+IFR2+MS+Sag (2) 1,826.68 33.47 12.38 1,769.59 1,719.39 304.69 108.02 6,032,072.36 544,850.62 5.32 320.89 2_MWD+IFR2+MS+Sag (2) 1,921.31 38.50 14.32 1,846.14 1,795.94 358.75 120.90 6,032,126.49 544,863.18 5.45 375.03 2_MWD+IFR2+MS+Sag (2) 2,015.91 43.94 16.52 1,917.27 1,867.07 418.80 137.53 6,032,186.63 544,879.45 5.95 436.19 2_MWD+IFR2+MS+Sag (2) 2,109.76 48.18 17.53 1,982.38 1,932.18 483.39 157.34 6,032,251.33 544,898.86 4.58 502.83 2_MWD+IFR2+MS+Sag (2) 2,204.15 52.61 14.30 2,042.55 1,992.35 553.31 177.20 6,032,321.37 544,918.30 5.38 574.28 2_MWD+IFR2+MS+Sag (2) 2,297.87 56.46 15.20 2,096.92 2,046.72 627.11 196.65 6,032,395.27 544,937.30 4.18 649.00 2_MWD+IFR2+MS+Sag (2) 2,392.99 59.16 15.58 2,147.59 2,097.39 704.71 218.01 6,032,473.00 544,958.20 2.86 727.99 2_MWD+IFR2+MS+Sag (2) 2,486.95 60.17 15.54 2,195.04 2,144.84 782.84 239.77 6,032,551.24 544,979.48 1.08 807.62 2_MWD+IFR2+MS+Sag (2) 2,580.15 59.39 14.94 2,241.95 2,191.75 860.54 260.94 6,032,629.06 545,000.18 1.00 886.61 2_MWD+IFR2+MS+Sag (2) 2,674.35 59.24 15.32 2,290.02 2,239.62 938.74 282.08 6,032,707.38 545,020.85 0.38 966.03 2_MWD+IFR2+MS+Sag (2) 2,769.23 58.55 15.84 2,339.04 2,288.84 1,016.99 303.90 6,032,785.75 545,042.19 0.87 1,045.80 2_MWD+IFR2+MS+Sag (2) 2,863.44 57.68 15.90 2,388.80 2,338.60 1,093.94 325.77 6,032,862.82 545,063.60 0.93 1,124.43 2_MWD+IFR2+MS+Sag (2) 2,957.50 60.49 16.36 2,437.12 2,386.92 1,171.45 348.20 6,032,940.46 545,085.55 3.02 1,203.81 2_MWD+IFR2+MS+Sag (2) 3,051.56 60.39 16.39 2,483.52 2,433.32 1,249.95 371.26 6,033,019.09 545,108.14 0.11 1,284.35 2_MWD+IFR2+MS+Sag (2) 3,146.62 59.92 17.04 2,530.83 2,480.63 1,328.91 394.97 6,033,098.19 545,131.38 0.77 1,365.61 2_MWD+IFR2+MS+Sag (2) 3,241.17 59.59 17.16 2,578.46 2,528.26 1,406.98 418.99 6,033,176.39 545,154.92 0.37 1,446.20 2_MWD+IFR2+MS+Sag (2) 3,335.49 59.22 17.70 2,626.46 2,576.26 1,484.44 443.31 6,033,253.99 545,178.77 0.63 1,526.38 2_MWD+IFR2+MS+Sag (2) 3,430.35 59.29 17.49 2,674.96 2,624.76 1,562.16 467.95 6,033,331.84 545,202.95 0.20 1,606.93 2_MWD+IFR2+MS+Sag (2) 3,524.76 58.92 18.12 2,723.43 2,673.23 1,639.29 492.73 6,033,409.12 545,227.25 0.69 1,687.01 2_MWD+IFR2+MS+Sag (2) 3,618.61 59.01 16.13 2,771.82 2,721.62 1,716.14 516.40 6,033,486.10 545,250.46 1.82 1,766.35 2_MWD+IFR2+MS+Sag (2) 3,712.37 58.85 15.55 2,820.21 2,770.01 1,793.39 538.32 6,033,563.48 545,271.92 0.56 1,845.28 2_MWD+IFR2+MS+Sag (2) 3,807.22 58.95 15.61 2,869.20 2,819.00 1,871.63 560.14 6,033,641.83 545,293.26 0.12 1,925.03 2_MWD+IFR2+MS+Sag (2) 3,901.84 59.17 15.68 2,917.85 2,867.65 1,949.78 582.02 6,033,720.10 545,314.67 0.24 2,004.74 2_MWD+IFR2+MS+Sag (2) 3,996.14 58.92 16.30 2,966.36 2,916.16 2,027.52 604.30 6,033,797.97 545,336.47 0.62 2,084.26 2_MWD+IFR2+MS+Sag (2) 4,090.32 59.59 15.03 3,014.50 2,964.30 2,105.45 626.15 6,033,876.03 545,357.85 1.36 2,163.76 2_MWD+IFR2+MS+Sag (2) 4,185.14 59.73 15.46 3,062.40 3,012.20 2,184.40 647.67 6,033,955.10 545,378.89 0.42 2,244.02 2_MWD+IFR2+MS+Sag(2) 4,279.49 58.36 13.13 3,110.93 3,060.73 2,26280 667.66 6,034,033.61 545,398.41 2.57 2,323.11 2_MWD+IFR2+MS+Sag(2) 4,373.14 57.85 14.21 3,160.42 3,110.22 2,340.05 686.44 6,034,110.97 545,416.73 1.12 2,400.63 2_MWD+IFR2+MS+Sag (2) 4,467.16 57.71 14.74 3,210.54 3,160.34 2,417.07 706.33 6,034,188.09 545,436.14 0.50 2,478.44 2_MWD+IFR2+MS+Sag (2) 4,561.90 58.07 14.61 3,260.90 3,210.70 2,494.70 726.66 6,034,265.84 545,456.00 0.40 2,556.99 2_MWD+IFR2+MS+Sag (2) 10/112018 7:21:45PM Page 3 COMPASS 5000.1 Build 81E Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: MPU L-41 Wellbore: MPU L-41PB1 Design: MPU L-41PB1 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: Well MPU L-41 TVD Reference: MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14 MD Reference: MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14 North Reference: True Survey Calculation Method: Minimum Curvature Database: Sperry EDM - NORTH US + CANADA Map MD Inc Azi TVD TVDSS +NIS +EI -W Northing (usft) (1) (1 (usft) (usft) (usft) (usft) (ft) 4,656.28 58.48 15.12 3,310.53 3,260.33 2,572.29 747.25 6,034,343.54 4,750.80 58.55 15.27 3,359.90 3,309.70 2,650.08 768.38 6,034,421.45 4,845.32 58.91 15.80 3,408.96 3,358.76 2,727.91 790.02 6,034,499.40 4,939.80 59.38 15.56 3,457.42 3,407.22 2,806.00 811.94 6,034,577.62 5,033.95 61.37 15.85 3,503.95 3,453.75 2,884.79 834.09 6,034,656.52 5,128.64 61.05 15.43 3,549.56 3,499.36 2,964.70 856.46 6,034,736.56 5,223.05 59.95 14.80 3,596.05 3,545.85 3,044.02 877.89 6,034,816.01 5,317.38 59.08 14.81 3,643.90 3,593.70 3,122.61 898.66 6,034,894.71 5,411.89 57.83 14.70 3,693.34 3,643.14 3,200.50 919.18 6,034,972.71 5,507.00 58.72 14.49 3,743.36 3,693.16 3,278.79 939.56 6,035,051.12 5,601.06 58.49 14.74 3,792.36 3,742.16 3,356.48 959.82 6,035,128.92 5,694.88 58.26 15.40 3,841.55 3,791.35 3,433.62 980.59 6,035,206.18 5,788.33 57.03 15.14 3,891.56 3,841.36 3,509.77 1,001.38 6,035,282.44 5,883.69 57.48 18.00 3,943.15 3,892.95 3,586.63 1,024.26 6,035,359.43 5,978.09 57.83 17.92 3,993.66 3,943.46 3,662.50 1,048.85 6,035,435.44 6,072.17 58.50 17.58 4,043.28 3,993.08 3,738.62 1,073.21 6,035,511.70 6,166.62 59.36 18.48 4,092.02 4,041.82 3,815.55 1,098.25 6,035,588.77 6,261.56 59.58 18.92 4,140.25 4,090.05 3,893.01 1,124.47 6,035,666.38 6,355.24 59.20 19.82 4,187.95 4,137.75 3,969.07 1,151.21 6,035,742.59 6,449.84 59.64 16.78 4,236.09 4,185.89 4,046.38 1,176.78 6,035,820.05 6,543.86 59.18 16.96 4,283.94 4,233.74 4,123.83 1,200.26 6,035,897.63 6,638.41 59.24 15.73 4,332.34 4,282.14 4,201.77 1,223.12 6,035,975.70 6,732.82 58.85 16.30 4,380.90 4,330.70 4,279.59 1,245.46 6,036,053.64 6,827.18 58.69 14.00 4,429.83 4,379.63 4,357.47 1,266.54 6,036,131.64 6,921.24 59.89 14.02 4,477.86 4,427.66 4,435.93 1,286.12 6,036,210.21 7,015.91 58.81 13.77 4,526.12 4,475.92 4,514.99 1,305.68 6,036,289.37 7,109.76 59.38 15.01 4,574.33 4,524.13 4,592.98 1,325.69 6,036,367.48 7,205.01 60.15 14.94 4,622.29 4,572.09 4,672.48 1,346.96 6,036,447.10 7,299.00 61.84 15.03 4,667.86 4,617.66 4,751.88 1,368.21 6,036,526.62 7,333.45 61.41 15.06 4,684.23 4,634.03 4,781.16 1,376.08 6,036,555.94 7,363.62 61.16 15.03 4,698.73 4,648.53 4,806.71 1,382.95 6,036,581.53 7,457.99 59.87 14.95 4,745.18 4,694.98 4,886.06 1,404.20 6,036,661.00 7,552.65 58.41 15.13 4,793.73 4,743.53 4,964.53 1,425.28 6,036,739.59 7,647.41 58.44 15.69 4,843.35 4,793.15 5,042.36 1,446.73 6,036,817.54 7,741.89 58.30 14.53 4,892.90 4,842.70 5,120.02 1,467.70 6,036,895.31 7,836.24 58.31 14.98 4,942.47 4,892.27 5,197.65 1,488.15 6,036,973.06 7,929.96 58.16 15.24 4,991.81 4,941.61 5,274.58 1,508.92 6,037,050.10 8,023.51 57.41 16.12 5,041.68 4,991.48 5,350.78 1,530.31 6,037,126.42 8,118.11 57.87 14.73 5,092.31 5,042.11 5,427.81 1,551.56 6,037,203.57 8,212.65 58.65 14.65 5,142.05 5,091.85 5,505.58 1,571.95 6,037,281.46 Map Vertical Easting DLS Section (ft) (^1100•) (ft) Survey Tool Name 545,476.13 0.63 2,635.62 2_MWD+IFR2+MS+Sag(2) 545,496.79 0.15 2,714.67 2_MWD+IFR2+MS+Sag(2) 545,517.95 0.61 2,793.99 2_MWD+IFR2+MS+Sag(2) 545,539.40 0.54 2,873.66 2_MWD+IFR2+MS+Sag (2) 545,561.08 2.13 2,954.05 2_MWD+IFR2+MS+Sag (2) 545,582.97 0.52 3,035.56 2_MWD+IFR2+MS+Sag (2) 545,603.92 1.30 3,116.11 2_MWD+IFR2+MS+Sag (2) 545,624.21 0.92 3,195.72 2_MWD+IFR2+MS+Sag(2) 545,644.25 1.33 3,274.58 2_MWD+IFR2+MS+Sag(2) 545,664.17 0.95 3,353.75 2_MWD+IFR2+MS+Sag(2) 545,683.95 0.33 3,432.32 2_MWD+IFR2+MS+Sag(2) 545,704.26 0.65 3,510.63 2_MWD+IFR2+MS+Sag(2) 545,724.59 1.34 3,588.06 2_MWD+IFR2+MS+Sag(2) 545,747.00 2.57 3,667.06 2_MWD+IFR2+MS+Sag(2) 545,771.13 0.38 3,745.93 2_MWD+IFR2+MS+Sag (2) 545,795.03 0.78 3,824.93 2_MWD+IFR2+MS+Sag (2) 545,819.61 1.22 3,904.95 2_MWD+IFR2+MS+Sag (2) 545,845.36 0.46 3,985.98 2_MWD+IFR2+MS+Sag (2) 545,871.64 0.92 4,065.98 2_MWD+IFR2+MS+Sag (2) 545,896.73 2.81 4,146.58 2_MWD+IFR2+MS+Sag (2) 545,919.75 0.52 4,226.38 2_MWD+IFR2+MS+Sag (2) 545,942.14 1.12 4,306.33 2_MWD+IFR2+MS+Sag(2) 545,964.00 0.66 4,385.95 2_MWD+IFR2+MS+Sag (2) 545,984.62 2.09 4,465.06 2_MWD+IFR2+MS+Sag(2) 546,003.72 1.28 4,544.02 2_MWD+IFR2+MS+Sag(2) 546,022.80 1.16 4,623.50 2_MWD+IFR2+MS+Sag(2) 546,042.34 1.29 4,702.24 2_MWD+IFR2+MS+Sag(2) 546,063.13 0.81 4,782.88 2_MWD+IFR2+MS+Sag(2) 546,083.90 1.80 4,863.43 2_MWD+IFR2+MS+Sag(2) 546,091.59 1.25 4,893.14 2_MWD+IFR2+MS+Sag (2) 546,098.30 0.83 4,919.07 2 MWD_Interp Azi+Sag(3) 546,119.07 1.37 4,999.57 2_MWD+IFR2+MS+Sag (4) 546,139.68 1.55 5,079.21 2_MWD+IFR2+MS+Sag (4) 546,160.66 0.50 5,158.44 2 MWD+IFR2+MS+Sag (4) 546,181.16 1.06 5,237.31 2_MWD+IFR2+MS+Sag (4) 546,201.14 0.41 5,315.91 2_MWD+IFR2+MS+Sag(4) 546,221.44 0.29 5,394.03 2 MWD+IFR2+MS+Sag(4) 546,242.37 1.13 5,471.77 2_MWD+IFR2+MS+Sag(4) 546,263.16 1.33 5,550.19 2_MWD+IFR2+MS+Sag (4) 546,283.07 0.83 5,628.90 2 MWD+IFR2+MS+Sag(4) 10/112018 7:21:45PM Page 4 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU L-41 Project: Milne Point TVD Reference: MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14 Site: M Pt L Pad MD Reference: MPL-41 wp06 prelim IRKS @ 50.20usft (Doyon 14 Well: MPU L-41 North Reference: True Wellbore: MPU L-41 PBI Survey Calculation Method: Minimum Curvature Design: MPU L-41 Pal Database: Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +El -W Northing Easting OLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,306.73 59.18 15.80 5,190.62 5,140.42 5,583.32 1,593.11 6,037,359.31 546,303.76 1.19 5,707.92 2_MWD+IFR2+MS+Sag(4) 8,401.45 59.54 16.69 5,238.90 5,188.70 5,661.56 1,615.90 6,037,437.68 546,326.09 0.89 5,788.12 2_MWD+IFR2+MS+Sag(4) 8,495.01 59.37 16.22 5,286.45 5,236.25 5,738.84 1,638.73 6,037,515.09 546,348.45 0.47 5,867.46 2_MWD+IFR2+MS+Sag(4) 8,589.95 59.08 16.61 5,335.02 5,284.82 5,817.08 1,661.78 6,037,593.46 546,371.02 0.47 5,947.78 2_MWD+IFR2+MS+Sag(4) 8,684.09 58.87 17.19 5,383.54 5,333.34 5,894.27 1,685.23 6,037,670.78 546,394.01 0.57 6,027.32 2_MWD+IFR2+MS+Sag(4) 8,778.06 58.51 16.66 5,432.38 5,382.18 5,971.08 1,708.60 6,037,747.72 546,416.91 0.62 6,106.49 2_MWD+IFR2+MS+Sag(4) 8,872.48 58.75 15.46 5,481.53 5,431.33 6,048.55 1,730.91 6,037,825.32 546,438.75 1.11 6,185.78 2_MWD+IFR2+MS+Sag(4) 8,965.07 58.61 15.50 5,529.66 5,479.46 6,124.78 1,752.02 6,037,901.66 546,459.40 0.16 6,263.42 2_MWD+IFR2+MS+Sag (4) 9,060.87 58.14 15.98 5,579.89 5,529.69 6,203.29 1,774.14 6,037,980.30 546,481.05 0.65 6,343.57 2_MWD+IFR2+MS+Sag(4) 9,155.72 55.71 15.16 5,631.65 5,581.45 6,279.85 1,795.48 6,038,056.98 546,501.92 2.66 6,421.61 2_MWD+IFR2+MS+Sag(4) 9,250.70 52.83 14.49 5,687.11 5,636.91 6,354.37 1,815.22 6,038,131.61 546,521.21 3.09 6,497.11 2_MWD+IFR2+MS+Sag(4) 9,345.17 50.27 14.91 5,745.85 5,695.65 6,425.93 1,833.98 6,038,203.27 546,539.54 2.73 6,569.53 2_MWD+IFR2+MS+Sag(4) 9,439.29 47.32 15.38 5,807.85 5,757.65 6,494.27 1,852.48 6,038,271.72 546,557.62 3.16 6,638.95 2_MWD+IFR2+MS+Sag(4) 9,532.45 44.74 15.26 5,872.52 5,822.32 6,558.93 1,870.19 6,038,336.48 546,574.94 2.77 6,704.73 2_MWD+IFR2+MS+Sag(4) 9,625.05 41.76 14.43 5,939.96 5,889.76 6,620.25 1,886.46 6,038,397.89 546,590.84 3.28 6,766.87 2_MWD+IFR2+MS+Sag(4) 9,722.21 38.73 14.80 6,014.12 5,963.92 6,680.99 1,902.29 6,038,458.71 546,606.30 3.13 6,828.29 2_MWD+IFR2+MS+Sag(4) 9,816.83 35.85 15.75 6,089.39 6,039.19 6,736.28 1,917.37 6,038,514.10 546,621.05 3.10 6,884.51 2_MWD+IFR2+MS+Sag(4) 9,910.84 33.25 16.14 6,166.81 6,116.61 6,787.55 1,932.01 6,038,565.44 546,635.38 2.78 6,936.92 2_MWD+IFR2+MS+Sag(4) 10,004.14 30.32 16.00 6,246.11 6,195.91 6,834.76 1,945.62 6,038,612.73 546,648.70 3.14 6,985.25 2_MWD+IFR2+MS+Sag (4) 10,098.84 27.01 16.53 6,329.19 6,278.99 6,878.37 1,958.33 6,038,656.41 546,661.15 3.51 7,029.95 2_MWD+IFR2+MS+Sag (4) 10,193.78 24.53 16.81 6,414.68 6,364.48 6,917.91 1,970.16 6,038,696.02 546,672.74 2.62 7,070.62 2_MWD+IFR2+MS+Sag(4) 10,288.27 21.54 17.05 6,501.63 6,451.43 6,953.28 1,980.92 6,038,731.45 546,683.29 3.17 7,107.07 2_MWD+IFR2+MS+Sag(4) 10,382.80 20.04 17.26 6,590.00 6,539.80 6,985.34 1,990.82 6,038,763.56 546,692.99 1.59 7,140.18 2_MWD+IFR2+MS+Sag(4) 10,476.69 20.08 17.86 6,678.19 6,627.99 7,016.04 2,000.53 6,038,794.32 546,702.52 0.22 7,172.00 2_MWD+IFR2+MS+Sag(4) 10,571.62 19.58 19.11 6,767.50 6,717.30 7,046.58 2,010.74 6,038,824.92 546,712.54 0.69 7,203.88 2_MWD+IFR2+MS+Sag(4) 10,666.05 20.17 15.93 6,856.30 6,806.10 7,077.19 2,020.39 6,038,855.58 546,722.00 1.30 7,235.58 2_MWD+IFR2+MS+Sag(4) 10,703.74 19.94 15.83 6,891.71 6,841.51 7,089.62 2,023.93 6,038,868.03 546,725.47 0.62 7,248.29 2_MWD+IFR2+MS+Sag(5) 10,796.16 20.05 18.34 6,978.56 6,928.36 7,119.82 2,033.21 6,038,898.28 546,734.57 0.94 7,279.46 2_MWD+IFR2+MS+Sag (5) 10,890.17 20.53 15.72 7,066.74 7,016.54 7,150.98 2,042.75 6,038,929.50 546,743.92 1.09 7,311.61 2_MWD+IFR2+MS+Sag (5) 10,984.44 20.15 13.05 7,155.13 7,104.93 7,182.71 2,050.89 6,038,961.28 546,751.87 1.06 7,343.64 2_MWD+IFR2+MS+Sag(5) 11,074.64 19.93 13.18 7,239.87 7,189.67 7,212.82 2,057.91 6,038,991.42 546,758.70 0.25 7,373.71 2_MWD+IFR2+MS+Sag(5) 11,171.84 18.93 11.66 7,331.53 7,281.33 7,244.39 2,064.87 6,039,023.03 546,765.47 1.15 7,405.08 2_MWD+IFR2+MS+Sag(5) 11,266.31 20.00 16.05 7,420.61 7,370.41 7,274.93 2,072.43 6,039,053.61 546,772.85 1.92 7,435.78 2_MWD+IFR2+MS+Sag(5) 11,306.91 20.12 16.25 7,458.74 7,408.54 7,288.30 2,076.31 6,039,067.01 546,776.65 0.34 7,449.48 2_MWD+IFR2+MS+Sag(5) 11,330.00 20.12 16.25 7,480.42 7,430.22 7,295.93 2,078.53 6,039,074.64 546,778.82 0.00 7,457.30 PROJECTED to TD Checked By: Chelsea Wright °tea Approved By: Mitch Laird Date: 10/11/1018 721:45PM Page 5 COMPASS 5000.1 Build 81E Lease & Well No. County TO Length Measurements WIO Threads RKB 33.70 Hiking Energy Company CASING & CEMENTING REPORT MP L41 Date Run 4Sep-18 State Alaska $up, D. Yessak/I. Toomey CASING RECORD Surface Shoe Depth. 7,367.00 PBTD: No. Jis. Delivered 200 No. Jts, Run 182 No. Jls, Returned Fig. Delivered Fig. Run Fig. Cut A 35.99 Fig. Balance RKB to BHF RKB to CHF Fig. Returned RKBto THF 22 Csg M. On Hook: 330,000 Type Float Collar: Halliburton No. His to Run: 31.5 Csg V& On Slips: 100,000 Type of Shoe: Antelope Casing Crew: Doyon Casing Rotate Csg X Yes No Redp Csg X Yes No 15 Ft. Min. g.3 PPG Fluid Description: Spw Liner hanger Info (Make/Madel): Liner hanger fest pressure: Centralizer Placement: CEMENTING REPORT Liner top Packet _Yes No Floats Held X Yes No Shoe @ 7367 FC @ 7,282.00 Casing (Or Liner) Detail Selling Depths its. Component Size wt. Grade THD Make Length Bottum Top 1 Shoe 103/4 Type: EdendaCem UP Antelope 1.60 7,366.49 7,364.89 2 Casing 95/8 40.0 L-80 UP 81.28 7,364.89 7,283.61 1 Float Collar 103/4 Density(ppg) 15B TXP Halliburton 1.31 7,283.61 7,282.30 1 Casing 95/8 40.0 L-80 TXP Rate (bpm): Volume: 40.41 7,282.30 7,241.89 1 Baffle Adapter 103/4 Type: Spud! Mud Density (ppg) TXP Halliburton 1.48 7,241.89 7,240.41 116 Casing 95/8 40.0 L-80 TXP 4,706.00 7240.41 2,534.41 1 Casing Pup Joint 95/8 40.0 L-80 UP 14.55 2,534.41 2,519.86 1 ESICP 103/4 Type ESIPC Closure OK Y TXP HES 11.85 2,519.86 2,508.01 1 CasingPu Joint 95/8 40.0 L-80 UP 13.60 2,508.01 2,494.41 61 Casin 95/8 40.0 LZ T%P 2,456.71 2,494.41 37.70 1 Cut Casin Joint 95/S 40.0 LSO TXP o 5.22 37.70 32.48 Csg M. On Hook: 330,000 Type Float Collar: Halliburton No. His to Run: 31.5 Csg V& On Slips: 100,000 Type of Shoe: Antelope Casing Crew: Doyon Casing Rotate Csg X Yes No Redp Csg X Yes No 15 Ft. Min. g.3 PPG Fluid Description: Spw Liner hanger Info (Make/Madel): Liner hanger fest pressure: Centralizer Placement: CEMENTING REPORT Liner top Packet _Yes No Floats Held X Yes No Past Job Calculations: Calculated! CnH Vol ® 0% excess: 4162 Total Volume amt Pumped: 670 Cm, returned to surface: 260.6 Calculated cement left in wellbore: 409.4 Shoe @ 7367 FC @ 7,282.00 Top of Liner Pregush(Spacer) Type: Clean Spacer Density (ppg) 10 Volume pumped (BBLs) 60 Lead Slurry Type: EdendaCem Sacks: 720 Yield: 2.36 Density (ppg) 12 Volume pumped (BBLs) 302 Mixing / Pumping Rate (bpm): 6 Tail Slurry w Type: Premium G Sacks: 400 Yield: 1.16 Density(ppg) 15B Volume pumped (BB") 82 Mixing/ Pumping Rate(bpm): t4 w, Post Flush (Spacer) c Type: Density (ppg) Rate (bpm): Volume: LL Displacement: Type: Spud! Mud Density (ppg) 9.3 Rate (bpm): 4 Vdume (actual I calculated): 548.03/549.1 FCP(psi): 1060 Pump used for dsp: Rig Bump Rug? X Yes No Bump press 1560 Casing Rotated? X Yes No Reciprocated? X Yes -No IS Returns during job 75 Cement returns to surface? X Yes No Spacer returns? X Yes _No Vol to Surf 85.6 Cement In Place At 610 Date: 8/62018 Estimated TOC: 2,508 Method Used To Detemune TOC: Retums to surface Stage Collar@ 2508 Type ESIPC Closure OK Y PreBush (Spacer) Type: Clean Spacer Density (ppg) 10 Volume pumped (BBLs) 55 Lead Slurry Type: PemtafrostL Sacks: 300 Yeld: 433 Density (ppg) 10.7 Volume pumped (BBLs) 230 Miring / Pumpitg Rate (bpm): 6 Tail Slurry o Type: Premium G Sacks: 270 Yield 1.17 n Density (ppg) 15A Volume pumped (BBLs) 56 Mixing I Pumping Rate (bpm): 4 Q, Post Flush (Spacer) Ou Type: Density (ppg) Rate (bpm): Volume: H Displacement: Type: Spud Mud Density (ppg) 9.3 Rate (bpm): 5 Volume (actual / calculated): 187.6/190.4 FCP(psi): Pump used for dsp: Rig Bump Plug? X Yes _No Bump press 920 Casing Rotated? _Yes X No Reciprocated? Yes X No % Returns during job 100 Cement returns to surface? X Yes No Spacerretums? X Yes No Vol to Surf: 175 Cement In Place At 16:46 Date: 952018 Estimated TOC: 0 Method Used To Determine TOC: Cetner4 to surface Past Job Calculations: Calculated! CnH Vol ® 0% excess: 4162 Total Volume amt Pumped: 670 Cm, returned to surface: 260.6 Calculated cement left in wellbore: 409.4 Hilcorp Energy Company CASING & CEMENTING REPORT Lease 8 Well No. MP L41 Date Run 12 -Oct -18 County Stale Alaska Supv. Sunderland /Demoaki CASING RECORD ___m ne P2 TD 11,31500 Shoe Depth. 11,290.00 PBTD: 11,245.00 No. Jts. Delivered 30D No, Jis. Run 272 No. Jts. Returned! 28 Fig. Delivered Fig. Run Fig. Retumed Length Measurements W/O Threads Ftg. Cut Ftg. Balance RKB 33.70 RKBto BHF RKBto CHF RKBto THF Gag VA. On Hook 130,000 Type Float Collar: Halfibudan No. Him to Rw: 28 Gag M. On Slips: 90,000 Type of Shoe: HalliGxlon Casing Crew: Doyon Rotate Csg Yes X No Recip Csg _ Yes X No 7 Ft Min. 10.5 PPG Fluid Description: LSND Liner hanger Info(Make/Model): WA Liner hanger test pressure: Centralizer placement: 7-1/8'X8-1/4" OMD centralizers on jt. 1 (2 ea.), P. 3 8 Tx8-V2" Cantek centralizers an IL 2, jts. 533 sand jet, 39 total centralizers and 10 stop rings. CEMENTING RE Shoe @ 11290 FC @ 11,206.90 Preflush(Spacer) Slurry Liner top Factual: _Yes X No Floats Held X Yes No pump junt at ESIPC (1 ea.) Density (ppg) 10.5 Volume pumped (BB") (ppg) Volume pumped (BBLs) Sacks: Yield: Mixing / Pumping Rate (bpm): Premium G Seeks: 255 Yield (Ppg) 15.8 Volume pumped (BBLs) 52.7 Mixing/ Pumping Rate (bpm): ash (Spacer) Density (ppg) Rate (bpm): Vdume: LSND Density(ppg) 10.5 Rate(bpm): 5 Volume (actual /calculated): Casing (Or Liner) Detail in)'. 1050 Pump used for disp Rig Setting Depths its. Component Size WL Grace THD Make Length Bottom Tap 1 Shoe 73/4 W Used To Oetennine TOC: Calculated BTC Halliburton 2.64 11,290.00 11,287.36 2 Casing 7 26.0 L-80 TXP Tenaris 80.61 11,287.36 11,206.75 1 Float Collar 7 3/4 BTC Halliburton 1.35 11,206.75 11,205.40 1 Casing 7 26.0 L-80 TXP Tenaris 41.34 11,205.40 11,164.06 1 Baffle Adapter 73/4 BTC Halliburton 1.05 11,164.06 11,163.01 17 Casing 7 26.0 L-80 TXP Tenaris 695.60 11,163.01 10,467.41 1 Casing Pup Joint 7 26.0 L-80 TXP Tenaris 12.03 10,467.41 10,455.38 1 ESICP Cementer 73/4 L-80 TXP Halliburton 17.42 10,455.38 10,437.96 1 Casing Pup Joint 7 26.0 L-80 TXP Tenaris 12.53 10,437.96 10,425.43 252 Casing 7 26.0 L-80 TXP Tenaris 10,368.89 10,425.43 56.54 1 Casing Pupjointi 7 1 26.0 L-80 TXP Tenaris 25.45 56.54 31.09 1 Casing Hanger FMC 0.55 31.09 30.54 Gag VA. On Hook 130,000 Type Float Collar: Halfibudan No. Him to Rw: 28 Gag M. On Slips: 90,000 Type of Shoe: HalliGxlon Casing Crew: Doyon Rotate Csg Yes X No Recip Csg _ Yes X No 7 Ft Min. 10.5 PPG Fluid Description: LSND Liner hanger Info(Make/Model): WA Liner hanger test pressure: Centralizer placement: 7-1/8'X8-1/4" OMD centralizers on jt. 1 (2 ea.), P. 3 8 Tx8-V2" Cantek centralizers an IL 2, jts. 533 sand jet, 39 total centralizers and 10 stop rings. CEMENTING RE Shoe @ 11290 FC @ 11,206.90 Preflush(Spacer) Slurry Liner top Factual: _Yes X No Floats Held X Yes No pump junt at ESIPC (1 ea.) Density (ppg) 10.5 Volume pumped (BB") (ppg) Volume pumped (BBLs) Sacks: Yield: Mixing / Pumping Rate (bpm): Premium G Seeks: 255 Yield (Ppg) 15.8 Volume pumped (BBLs) 52.7 Mixing/ Pumping Rate (bpm): ash (Spacer) Density (ppg) Rate (bpm): Vdume: LSND Density(ppg) 10.5 Rate(bpm): 5 Volume (actual /calculated): 427.1 in)'. 1050 Pump used for disp Rig Bump Plug? X Yes -No Bump press Rotated? _Yes X No Recipmcded? _Yes X No % Returns during jab X No % Returns during job returns to surface? Yes X No Spacerretums?_Yes X No VOI to Sud: 0 In Place At: 3:22 Date: 10/1312018 Estimated TOC: 10,503 Used To Determine TOC'. Calculated W Used To Oetennine TOC: Calculated Stage Collar@ 10438 Type ESIPC Closure OK Y reHush (Spacer) ype: Clean Spacer Density (ppg) 10.5 Volume pumped (BBLs) Sacks. Yield: Miring / Pumping Rate (bpm): Slurry 1: PremiumG Sacks: 165 Yield: sfty (ppg) 15.8 Volume purrped (BBLs) 34.1 Mixing / Pumping Rate (bpm): t Flush (Spacer) r DensBy(ppg) Rate (li m): Volume: Water Density (ppg) 834 Rale (bpm): 5 Volume (actual / calculated): 402.1 (psi): 1620 Pump used for disp: Rig Bump Plug? X Yes _No Bump press ig Rotated? _Yes X No Reciprocated? _Yes X No % Returns during job _ ant returns to surface? _Yes X No Spacer returns?_Yes X No Vol to Sud: 0 ant In Place At 8'.35 Dale: 10/132018 Estimated TOC: 9,938 W Used To Oetennine TOC: Calculated Calculated Cant Vol (a) M excess: 40.38 Total Volume urM1 Pumped: 527 Ont returned to surface: 0 Calculated cement left in wellbore: 52.7 OH volume Calculated: 35.52 OH volume actual: 46.18 Actual % Washout 40 50 Hydraulic Fracturing Fluid Product Component Information Disclosure Job Start Date: Job End Date: State: County: API Number: Operator Name: ame and Number: Latitude: Longitude: Datum: Federal Well: Indian Well: True Vertical Depth: Total Base Water Volume (gal): Total Base Non Water Volume: Hydraulic Fracturing Fluid Composition: 10/29/2018 11/7/2018 Alaska Beechey Point 50-029-23611-00-00 Hilcorp Alaska, LLC M P L-41 70.49765890 -149.63409390 NAD27 NO NO 7,169 112,635 0 Frac Focus Chemical Disclosure Registry >to'!C'�o% co.,%CI. �Oil&Gas Chemical Maximum Maximum Abstract Ingredient Ingredient Trade Name Supplier Purpose Ingredients Service Concentration Concentration Comments Number in Additive in HF Fluid (CAS #) (% by mass)** (% by mass)** Water Schlumberger Surfactant Breaker, Gelling Agent, Crosslinker, Clay Control Agent, LTCA, Additive, Bactericide, Propping Agent Water (Including Mix 7732-18-5 79.98238 Water Supplied by Client)` Items above are Trade Names with the exception of Base Water. Items below are the individual ingredients. _� Ceramic materials and 66402-68-4 96.02370 19.22166 wares, chemicals Guargum 9000-30-0 1.43527 0.28731 2-hydroxy-N,N,N- 67-48-1 0.62629 0.12537 trimethyl ethanam in i u m chloride Ulexite 1319-33-1 0.47666 0.09542 Methanol 67-56-1 0.37248 0.07456 Ethylene Glycol 107-21-1 0.27596 0.05524 Alcohols, c11-15- 68131-40-8 0.23590 0.04722 secondary, ethoxylated Diammonium 7727-54-0 0.17122 0.03427 peroxidisulphate 2-butoxyethanol 111-76-2 0.068471 0.01371 Propan-2-ol 67-63-0 0.06847 0.01371 Ethoxylated C11 Alcohol 34398-01-1 0.06289 0.01259 Sodium hydroxide 1310-73-2 0.05951 0.01191 Sodium Tetraborate 1303-96-4 0.05268 0.01055 Decahydrate Ethoxylated Alcohol 68131-39-5 0.03413 0.00683 Vinylidene 25038-72-6 0.03104 0.00621 chloride/methyl acryl ate copolymer but-2-enedioic acid 110-17-8 0.01254 0.00251 Poly(oxy-1,2- 25322-68-3 0.01242 0.00249 ethaned iyl), a-hydro-w- hydroxy- Ethane -1,2 -diol, ethoxylated Diatomaceous earth, 91053-39-3 0.00744 0.00149 calcined Undecanol 112-42-5 0.00548 0.00110 Non -crystalline silica 7631-86-9 0.00360 0.00072 (impurity) Magnesium nitrate 10377-60-3 0.00149 0.00030 Magnesium silicate 14807-96-6 0.00095 0.00019 hydrate (talc) ' Total Water Volume sources may include various types of water including fresh water, produced water, and recycled water " Information is based on the maximum potential for concentration and thus the total may be over 100% "' If you are calculating a percentage of total ingredients do not add the water volume below the green line to the water volume above the green line Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided. Ingredient information for chemicals subject to 29 CFR 1910.1200(i) and Appendix D are obtained from suppliers Material Safety Data Sheets (MSDS) 5 -chloro -2 -methyl -2h- isothiazolol-3-one 26172-55-4 0.00080 0.00016 Magnesium chloride 7786-30-3 0.00074 0.00015 Diutan gum 125005-87-0 0.00063 0.00013 Diutan 595585-15-2 0.00063 0.00013 poly(tetrafluoroethylene) 9002-84-0 0.00040 0.00008 2-methyl-2h-isothiazol-3- one 2682-20-4 0.00024 0.00005 Acetic acid, potassium salt 127-08-2 0.00021 0.00004 Cristobalite 14464-46-1 0.00015 0.00003 Quartz, Crystalline silica 14808-60-7 0.00015 0.00003 Acetic acid (impurity) 64-19-7 0.00003 0.00001 ' Total Water Volume sources may include various types of water including fresh water, produced water, and recycled water " Information is based on the maximum potential for concentration and thus the total may be over 100% "' If you are calculating a percentage of total ingredients do not add the water volume below the green line to the water volume above the green line Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided. Ingredient information for chemicals subject to 29 CFR 1910.1200(i) and Appendix D are obtained from suppliers Material Safety Data Sheets (MSDS) Schlumberger FracCAT Treatment Report: Well MPL-41 Field Kuparuk Formation A Sand Well Location 3,213 County :Prudhoe Bay State Alaska Country United States Prepared for Calibration BH ISIP (psi) Client Hilcorp Alaska U -C Client Rep Jim Abel Date Prepared October 29, 2018 Prepared by Name Alexander Martinez Division Schlumberger Phone :5613895006 Pressure (All Zones) Initial Wellhead Pressure (psi) 3,213 Surface Shut in Pressure(psi) 1,645 Calibration Surface ISIP (psi) 1,687 Final Surface ISIP (psi) 1,974 Calibration BH ISIP (psi) 4,823 Final BH ISIP (psi) 5,110 Maximum Treating Pressure (psi) Treatment Totals (All Zones As Per FracCAT) 4,974 Total Slurry Pumped (Water+Adds+Proppant) bbls 16".4 Total YF135ST Past Wellhead (bbls) 1023.4 Total WF120 Past Wellhead (bbls) 332.8 Total Freeze Protect Past Wellhead (bbls) 20 Total WF135 Past Wellhead (bbls) Total. J580 (lbs) 2096 136.6 2096 Total 16120 CarboBond Lbe Pumped (tbs.) Invoiced J604 (gal) 160 109,560 Past WIT 160 L071 (gal) 122 122 M002 (lbs) 84 84 F103 (gal) 62 62 J134 (Ibs) 10 0 J475 (Ibs) 220 220 M275 (Ibs) 30 20 J218 (Ibs) 33 33 LTCA (gal) 94 94 Disclaimer Notice This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. Schlumberger -Private Schlumberger Job Plots: Stage 1 Pressure Test — Tr. Press — Annulus Press — Slurry Rate Client: Hilcorp Alaska Well: MPL41 Formation: Kuparuk A District: Prudhoe Bay, AK Country: United States Hilcorp Alaska MPL-41 29 -Oct -2018 35 Time - hh:mm:ss Schlumberger -Private 10 Schlumberger, a m a d a Stage 1 DataFrac — Tr. Press — Annulus Press — Slurry Rate Client: Hilcorp Alaska Well: MPLAI Formation: Kuparuk A District: Prudhoe Bay, AK Country: United States Hilcorp Alaska MPL-41 29 -Oct -2018 Time - hh:mm:ss Schlumberger -Private LD C A m m rr o- 3 n 12 Schlumberger Stage 1 Kuparuk A Tr. Press Annulus Press Slurry Rate Prnn rnn Client: Hilcorp Alaska Well: MPL41 formation: Kuparuk A District: Prudhoe Bay, AK Country: United States Hilcorp Alaska MPL-41 29 -Oct -2018 Time - hh:mm:ss Schlumberger -Private N C 3 N N Q v 3 n 12 n. Schlumberger 40 30 E a a m 20 U) 10 0 12:42:49 Stage 1: Calibration Additives Client: Hilcorp Alaska Well: MPLA1 Formation: Kuparuk A District: Prudhoe Bay, AK Country: United States SLUR—RATE Hilcorp Alaska MPL-41 CFLD RATE Oct -29-2018 J604_CONC 8 12:53:14 13:03:39 13:14:04 Time - hh:mm:ss Schlumberger -Private 7 v 1 0 13:24:29 — F103 CONC -- L071 CONC — U028 CONC LTCA CONC — J475 CONC — J218_CONC 12:53:14 13:03:39 13:14:04 Time - hh:mm:ss Schlumberger -Private 7 v 1 0 13:24:29 Schlumberger Stage 1: Additives 30 25 +Zf E Client: Hilcorp Alaska Well: MPLA1 Formation: Kuparuk A District: Prudhoe Bay, AK Country United States SLUR RATE Hilcorp Alaska MPL-41 CFLD RATE Oct -29-2018 J604_CONC 12 0 15:04:38 15:25:28 15:46:1d-iovcvo Time - hh:mm:ss Schlumberger -Private 10 2 0 16:27:58 10 2 1 — F103 CONC — L071 CONC — U028 CONC — LTCA CONC — J218_CONC 0 15:04:38 15:25:28 15:46:1d-iovcvo Time - hh:mm:ss Schlumberger -Private 10 2 0 16:27:58 10 2 1 Schlumberger w Client: Hilcorp Alaska Well: MPL-41 Formation: Kuparuk A District: Prudhoe Bay, AK Country. United States Jecuon 1: As measurea rump bcneauie Step # Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Minimum Treating Pressure Pressure (psi) (psi) As Measured Pump 5.7 31.5 4098 4974 Step Step Slurry Slurry Pump 3767 Fluid 3690 Max Prop Prop Prop # Name Volume Rate Time Fluid Name Volume Proppant Name 3539 Cone Mass 1.5 PPA (bbl( (bbl/min) (min) 3778 (gal) PPA( IPPA) (lb) 1 Load 180 25.7 9.2 WF120 7539 364 0 293 .0 PPA hole 4.8 215 322 128 .0 PPA 43 4.8 022 2 Data 99.8 30.6 3.2 WF120 4193 020 0 0 .0 PPA 4.6 Frac 024 042 006 12 .0 PPA 4.7 034 48 3 Step 29. 22. 1. WF120 125 14 0 IA, 4.7 Down 190 077 15 G Flush 5.4 408 508 759 4 Warm 23.6 5.1 4. WF120 991 0 001 5 PAD 20 24.1 8. YF135FlexD 838 0 6 0.5 PPA 75. 2 YF135FIexD 311 CarboBond Lite 16/20 2. 213004 7 PAD2 7 2 YF135FIexD 315 CarboBond Lite 16/20 0.5 0 8 1.0 PPA 99. 24. YF135FIexD 4011 CarboBond Lite 16/20 1.1 0. 9 2.0 PPA 103. 24. 4. YF135FIexD 400 CarboBond Lite 16120 2.1 1. 10 3.0 PPA 10 24. 4. YF135FlexD 395 CarboBond Lite 16/20 3.1 3 11 4.0 PPA 206. 24. 8. YF135FIexD 731 CarboBond Lite 16/20 4.1 412 5.0 PPA 8 24. 3. YF135FIexD 294 CarboBond Lite 16/20 5.1 4.13 6.0 PPA 6 24. 2. YF135FIexD 1981 CarboBond Lite 16/20 6.1 5. 14 7.0 PPA 62. 24.5 2.5 YF135FlexD 1980 CarboBond Lite 16/20 7.1 6.9 1417 15 8.0 PPA 66.7 24.5 2.7 YF135FIexD 2141 CarboBond Lite 16/20 83 6.7 14741 16 LG 137 24.9 6.6 WF135 5736 2.2 0 Flush 17 Freeze 33.7 15.1 2.1 Freeze Protect 1426 0 0 Protect 1 Schlumberger -Private Stage Step # Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Minimum Treating Pressure Pressure (psi) (psi) 1 Load hole 5.7 31.5 4098 4974 40 ata Frac 0.8 30.9 3767 3824 3690 tep Down 2.7 30.8 3156 3821 110 PAD 4.1 25.4 3539 3779 110 1.5 PPA 5.0 5.1 3709 3778 3610 PAD2 5.0 5.0 597 607 588 1.0 PPA 4.8 5.2 364 498 293 .0 PPA 43 4.8 215 322 128 .0 PPA 43 4.8 022 138 947 10 .0 PPA 4.6 4.9 971 020 942 11 .0 PPA 4.6 4.8 024 042 006 12 .0 PPA 4.7 034 48 016 13 .0 PPA 4.7 056 80 14 .0 PPA IA, 4.7 124 190 077 15 G Flush 5.4 408 508 759 16 Freeze Protect 5.7 843 984 115 Schlumberger -Private Schlumberger Client: Hilcorp Alaska Well: MPL41 Formation: Kupamk A District: Prudhoe Bay, AK Country: United States Average Treating Pressure: 3368 psi Maximum Treating Pressure: 4974 psi Minimum Treating Pressure: 15 psi Average Injection Rate: 24.9 bbVmin Maximum Injection Rate: 31.5 bbl/min Average Horsepower: 2076.7 hhp Maximum Horsepower: 3792.6 hhp Maximum Prop Concentration: 8.3 PPA Schlumberger -Private Schlumberger Section 2: Job Messages Client: Hilcorp Alaska Well: MPLA1 Formation: KupamkA District: Prudhoe Bay, AK Country: United States / Time Message Message ,r Treating Pressure (Psi) Annulus Pressure (Psi) Total Slurry (bbl( Slurry hate (bbl/min) Prop. Conc. (PPA) 1 Reset Executed Steps 0. 0. 0. 2 Reset Executed Steps 0 0. 0A 0, 3 10:10:12 Priming up the POD with diesel 0. 0. 0. 4 11:28:58 Getting ready for pressure test 318 245 0. 01 0. 5 11:33:36 Coming up for low PT 4 2448 0. 0.0 0. 6 11:41:38Found small drip. Bleeding off pressure to fix 392 2441 0. 0. 0. 7 11:57:20 Drip is fixed setting up to prime the pump. 242 0. 0.0 0. 8 12:07:45 tarting PT again 213 242 O.N 0.0 0. 9 12:13:24 heck valve test is good 3650 2417 0.1 Oho 0. 10 12:13:42 Coming up for high PT 3631 2417 0. 0. 0. 11 12:23:19 tarting timer 8095 240 0.0 0.0 0. 12 12:27:27 Mixing 209 gel 7944 240 0.0 0. 0. 13 12:28:43 Matched well pressure 1089,240 0.0 0. 0. 14 12:37.30 Start Load hole Automatically 125N 239 0.0 0.0 0. 15 12:37:30 Start Propped Frac Automatically 1255 239 0. 0.0 0. 16 12:37:30 Start Kup A after Automatically 1255 239 0. 0.0 0. 17 12:37:41 Started Pumping 1253 239 0. 0.0 0. 18 12:46:28 Opening the well. 46 239 0. 0.0 0. 19 12:47:14 Well is open 43 239 0. 0.0 0. 20 12:49:46 Displacing diesel 3081 270 1. 5.0 0. 21 12:57:15 Startingfrac 453 242 10. 0.0 0. 22 1394:44 Start Data Frac Automatically 370q 289 180. 303 0. 23 13:04:48 Stage at Perfs: Load hole 378 289 182. 30. 0. 24 13:07:58 art Step Down Manually 381 298 279. 30. 0. 25 13:08:00 Activated Extend Stage 382 298 280. 30. 0. 26 13:14:14 Down for data decisions 11 282 309. 0. 0. 27 14:11:40 Movingfluid 141 269 309. 0. 0. 28 14:51:16 Mixing 35Mgel 201 261 309. 0. 0. 29 15:00:37 Started Pumping 1471 2604 309. 0.0 0. 30 15:09:31 Deactivated Extend Stage 110 2601 309. 0.0 0. 31 15:09:31 Start PAD Manually 110 2601 309. 0.0 0. 32 15:12:50 Stage at Perfs: Data Frac 3466 2991 362. 25.0 0. 33 15:16:48 Stage at Perfs: Step Down 3599 2960 462.1 25.1 0. 34 15:17:58 Stage at Perfs: PAD 3674 2998 491. 25.2 0. 35 15:18:41 Start 0.5 PPAAutamatically 3738 2996 509. 25.1 0. 36 15:18:41 Started Pumping Prop 3738 2996 509. 25.1 0. 37 15:20:44 Start PA02 Automatically 3605,29B6 560. 25.0 0. 38 15:20:46 Activated Extend Stage 358 2987 561, 25.0 0. 39 15:21:23 Deactivated Extend Stage 357q 29B4 576., 25.1 0. 40 15:21:23 IStart 0.5 PPA Manually 3575 29B4 576.1 25.1 0. 41 15:21:42 art PAD2 Manually353 2991 584. 24. 0. 42 15:24:42 tart 1.0 PPA Automatically 348 298 659. 251 -0.1 43 15:25:58 tage at Perfs: 0.5 PPA 338 298 691. 24.9.1. 44 15:28:02 tage at Perfs: PAD2 3321 298 742.7 24. 1. 45 15:28:41 tage at Perfs: 0.5 PPA 333 298 758. 24. 0. 46 15:28:42 Start2.0PPA Automatically 331 298 759. 24.7 0. 47 15:29:00 tage at Perfs: PAD2 332 2981 766. 24.8 1. Schlumberger -Private Schlumberger, Client: Hilcorp Alaska Well: MPL-41 Formation: Kuparuk A District: Prudhoe Bay, AK Country: United States I Time Message 9 Message Log Annulus Pressure (psi)(bbl) Total Slurry Slurry Hate IbbUmin) Prop. Cone. IPPA) 48 15:32:03 tage at Perfs:0.5 PPA 2981 841. 14. 2. 49 15:32:55 tart 3.0 PPA Automatically 12961 298 863. 24. 2.50 15:3695 tage at Perfs: PAD2 297 941. 24.7 3.51 15:37:15 tart 4.0 PPAAutomaticall 30 970. 24.7 3.52 15:40:18 to a at Perfs:1.0 PPA 299 1045. 24.6 4. 53 1 15:44:38 IStage at Parts: 2.0 PPA 01 299 1152.1 24.5 4. 54 15:4537 art 5.0 PPA Automatically 302 $ 299 1176 24.7 3. 55 15:4994 tart 6.0 PPA Automatically 303 2981 1261.1 20. 5. 56 15:51:31 tart 7.0 PPA Automatically 303 2,198 1321.3 24.5 6. 57 1 15:53:02 Otage at Perfs: 3.0 PPA 307 299 1358.6 24.6 7.1 58 15:54:03 Start 8.0 PPA Automatically 3054 298 1383A 24.5 6. 59 15:5497 Activated Extend Stage 30771 298q 1385.1 24.7 7. 60 15:56:29 Stage at Perfs: 4.0 PPA 3146 297A 1443.1 24. 2. 61 15:56:46 Deactivated Extend Stage 320 2977 1450.1 5.41 1. 62 1556:46 Start LG Flush Manually 320 297 1450.1 24. 1. 63 15:57:02 Stopped Pumping Prop 3281 299 14563 25.1 0.1 64 15:58:54 Stage at Perfs: 5.0 PPA 348 n1'0 25. 0. 65 16:01:22 tae at Ports: 6.0 PPA 341 300 1565. 25.1 0. 66 1692:20 tartFreeze Protect Automatically 2781 297 1587. 15.5 0. 67 16:09:00 ell is shut in 18, 265 1620. r 0. Schlumberger -Private Schlumberger, FracCAT Treatment Report: Well MPL-41 Field Kuparuk Formation C Sand Well Location 2,120 County Prudhoe Bay State Alaska Country United States Preparedfor 1,974 Client Hilcorp Alaska U -C Client Hep Jim Fagnant Date Prepared November 7, 2018 Prepared by 34.6 Name Alexander Martinez Division Schlumberger Phone :5613895006 Disclaimer Notice This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumbergers best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well of wells might be affected by the treatment proposed herein it is the Operators responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. Schlumberger -Private Pressure (All Zones) Initial Wellhead Pressure (psi) 22 Final Surface ISIP (psi) 2,120 Calibration Surface ISIP (psi) 1,751 EOJ 5 Minute Pressure (psi) 2,055 Maximum Treating Pressure (psi) 4,706 EOJ 10 Minute Pressure (psi) 1,974 Total 16P10 CarboBond Life Pumped (lbs.) 71711111 Totals (All Zones As Per FracCAT) Total Sluny Pumped (Water+Adds+Proppant) bbls 116,340 1286.2 EOJ 15 Minute Pressure Total YF130ST Past Wellhead (bbls) 1,906 819.1 Total WR 20 Past Wellhead (bbls) 202.3 Total Freeze Protect Past Wellhead (bbls) 34.6 WF130 (bbls) Total Chemical Additives Invoiced J580 (lbs) 1364 90.8 Past WH 1289 Total Freeze Protect Pumped (bbls) Invoiced J604 (gal) 100 44.6 Past WH 100 L071 (gal) 92 92 M002 (Ibs) 56 56 F103 (gal) 41 41 J134 (lbs) 10 0 J475 (lbs) 193 193 M275 (lbs) 30 20 J218 Obs) 33 33 LTCA (gal) 81 81 Disclaimer Notice This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumbergers best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well of wells might be affected by the treatment proposed herein it is the Operators responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. Schlumberger -Private Schlumberger Job Plots Pressure Test Client: Hilcorp Alaska Well: MPL-41 Formation: Kuparuk C District: Prudhoe Bay, AK Country United States Tr. Press -- Annulus Press Slurry Rate Hilcorp Alaska MPL-41 11/7/18 16 14 12 m Schlumberger 1994-2016 Time- hh:mm:ss Schlumberger -Private c ;11 N a c 3 '07 Schlumberger Schlumberger i Linear Gel DataFrac Client: Hilcorp Alaska Well. MPLAI Formation: Kuparuk C District Prudhoe Bay, AK Country. United States Hilcorp Alaska — Tr. Press MPL-41 — Annulus Press 11/7/18 — Slurry Rate 0 Schlumberger 19942016 Time - hh:mm:ss Schlumberger -Private Schlumberger Schlumberger i Kuparuk C Frac Client Hilcorp Alaska Well: MPLAI Formation: Kuparuk C District Prudhoe Bay, AK Country: United States Tr. Press Annulus Press Slurry Rate Hilcorp Alaska MPL-41 11/7/18 O Schrum be rger 19942016 Time - hh:mm:ss Schlumberger -Private 0 a 0 D Schlumberger Schlumberger 40 30 10 0 11:18:40 Kuparuk C Data Frac Additives Client: Hilcorp Alaska Well: MPLA1 Formation. Kuparuk C District: Prudhoe Bay, AK Country: United States SLUR RATE CFLD_RATE J604_CONC F103 CONC Hilcorp Alaska MPL-41 11/7/18 10 © Schlumberger 19942616 11:22:00 11:25:20 11:Za:4U Time - hh:mm:ss Schlumberger -Private 8 — L071_CONC 15 — U028_CONC — LTCA_CONC r - J475_CONC n' f, it — J218 CONC © Schlumberger 19942616 11:22:00 11:25:20 11:Za:4U Time - hh:mm:ss Schlumberger -Private 8 15 r ry n' c_ a 6 A a ^� Q � m 10 p z n u; 4 b1 Q ro 3 d m 5 2 0 0 Schlumberger Schlumberger Kuparuk C Additives Client: Hilcorp Alaska Well: MPLAI Formation: Kuparuk C District. Prudhoe Bay, AK Country: United States SLUR—RATE HilcorpAlaska CFLD_RATE MPL-41 J604_CONC 11/7/1$ © Schlum be Mer 1994-2016 Time - hh:mm:ss Schlu m berger-Private Schlumberger Schlumberger Section 1: As Measured Pump Schedule Client: Hilcorp Alaska Well: MPL-41 Formation: Kuparuk C District: Prudhoe Bay, AK Country: United States Step t Step Name Stage Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi( As d Pump Schedule Injection Test 7.9 05.6 706 4 Slurry Slurry Pump 938 Fluid Prop Prop Prop Stop p Volume Rate Time Fluid Name Volume Proppant Name Cone Cone Mass 0.1 Name (bbl( [bbl/min) (min) 9.9 (gal) 118 (PPA) (PPA) (Ib) 1 Injection 180. 27. 10. WF120 75 9.9 0. 0.0 a .0 PPA Tes2 292 340 265 10 .0 PPA 9.5 9.7 394 444 322 11 DataFRAC 22.3 25.2 1.2 WF120 944 .0 PPA 0.0 0. 594 3 PAD 180.0 28A. 6.8.YF130FIexD 749 7539 14 0.0 0.0 a 4 1.0 PPA 78.0 30.1 2.0 YF130FIexD 31811 CarbolSond Lite 16/20 1.0 0.0 204 5 2.0 PPA 82.0 30.1 2.A YF130FIexD 316A Carbol3ond Lite 16/20 2.0 1. 605 6 3.0 PPA 85.0 29.9 2.4 YF130FIexD 314N CarboBond Lite 16/20 3.1 2. 914 7 4.0 PPA 89.0 29.4 3.N YF130FIexD 316A CarboBond Lite 16/20 4.1 3.q 12391 8 5.0 PPA 74.0 29.6 2.1 YF130FlexD 25311 CarboBond Lite 16/20 5.2 4.1 1240 9 6.0 PPA 76.7 29.5 2.0 YF130FIexD 252 CarboBond Lite 16/20 6.1 5. 14918 10 7.0 PPA 79. 29. 2. YF130FlexD 251 CarboBond Lite 16/20 7.1 6. 1727 11 8.0 PPA 82.0 29.q ZO YF730FlexD 2519 CarboBond Lite 16120 8.2 7. 1989 12 9.0 PPA 92.8 29.5 3.1 YF130FlexD 2864 CarboBond Lite 16/20 9.2 7.1 2221 13 XL Flush 30.0 29. 1. YF130FIexD 125 CarboBond Lite 16/20 0. 0.0 C 14 LG Flush 90.8 28.7 3. WF130 38D3 0. 0. 15 Freeze44.1 197 2. Freeze Protect 1885 0. 0. Protect Step t Step Name Stage Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi( Maximum Treating Minimum Treating Pressure Pressure (psi) (psi) 1 Injection Test 7.9 05.6 706 4 ataFRAC 5.2 05.6 938 769 PAD 8.4 1310.3 244 475 1.0 PPA .1 0.1 301 349 263 .0 PPA .1 0.1 208 266 155 .0 PPA 9.9 0.1 118 161 0116 .0 PPA 9.4 9.7 142 195 094 .0 PPA 9.6 9.9 233 274 189 .0 PPA 9.5 9.7 292 340 265 10 .0 PPA 9.5 9.7 394 444 322 11 .0 PPA 9.4 9.7 502 552 7 12 .0 PPA 9.5 9.8 594 54 541 13 L Flush 9.8 0.0 749 874 620 14 LG Flush 8.7 0.2 638 888 707 15 reeze Protect 19.7 9.8 798 P021 Pump Time Proppant 1286.2 1 50.2 1 48570 1 116340 1 Average Treating Pressure: Maximum Treating Pressure: Minimum Treating Pressure: 3391 psi 4706 psi 5 psi Schlumberger -Private Schlumberger, Average Injection Rate: 28.7 bbVmin Maximum Injection Rate: 35.6 bbl/min Average Horsepower: 2423.1 hhp Maximum Horsepower: 4082.5 hhp Maximum Prop Concentration: 9.2 PPA Section 2: Job Messages Client: Hilcorp Alaska Well: MPLAI Formation: Kuparuk C District: Prudhoe Bay, AK Country: United States / Time Message Message Log Treating Pressure (psi) Annulus Total Slurry Slurry Rate Prop. one. Pressure (bbl) (bbVmin) (PPA) Ipsi) 1 Reset Executed Steps 01 0. 0. 2 Reset Executed Steps 1 0' 0' D. 3 8:39:05 Priming up pumps 6 -1 0. 4. 0. 0. 4 9:02:54 3etting up to PT 1 - CIA 0.1 0. 0. 5 9:05:42 Low pressure stall 231 - 0. 6 9:08:09 Coming u to 4K to do check valve test 217 -1 U. 7 9:12:30 heck valve test is good 37 0. 0. 0. 8 9:24:21 PT is good. Bleeding off pressure 794 - 0. 0. 0. 9 9:24:39 Getting gathered up for safety meeting. 747 0. 0. 0. 10 9:52:08 Mixing 20/ gel -1 0. 0. 0. 0. 11 10:17:37 PCM sample is good. -1 2601 0. 0. siting for Stinger valve to warm up only gets 8 _ 2601 g• 0, 0. 12 10:17:57 13 11:00:52 urns ettin uys into place tofrac -1 2587 0. 0. 0. 14 11:01:06 Priming up pod on gelled fluid 1 2587 0. 0. 0. 15 11:02:51 Matchin well head pressure 3 258 0. 0. 0. 16 11:05:21 Opening the well 21 258 17 11:06:02 ell is open 2 258 18 11:08:34 art lnjectionTestAutomatically 19 11:08:34 tart Pro ed Frac Automatically 20 11:08:34 tart Kup C Automatically 2 258 21 11:08:40 Started Pum in 2 258 0. 0. 0. 0. 22 11-19:28 Dis Iacingdieselfluid 3 262 0. 3.1 0. 23 11:15:12 Down for FP displacement 2008 269 23. 0. 0. 24 11:25:13 tag. at Perfs: Injection Test 375 279 179. 35.7 0. 25 11:25:14 start DataFRAC Automatically 3741 279 180. 35. 26 12:22:26 hemical lines have been run 117 258 202. 0. 0. 27 12:22:40 Mixing 301 gel 117 257 20,. 0. 0. 28 1231:17 tart PAD Manually 57 257 202. 0. U. 0. 29 12:46:25 tage at Perfs: DataFRAC - 32 278 360• 30. 0. 30 12:47:08 tea. at Perfs: PAD 326 281 382.1 30. 31 12:47:09 Start 1.0 PPA Automatically 326 281 382. 30.1 0. 32 12:47:09 tarted ll --inn Prop 326 281 382• 30'1 0. 33 12:49:45 art 2.0 PPA Automatically 325 290 460. 30.1 1. 34 12:52:26 tart3.0PPA AUtomatically 3137 294 542. 30.1 2. 35 12:53:08age at Perfs:2.0 PPA 312 295 562. 30.1 3• 36 12:55:19 tart 4.0 PPA Automatically 309 2927 627. 29.6 3. 37 12:55:45 tage at Perfs: 3.0 PPA 308 292 640. 29. 4.1 38 12:58:21 tart 5.0PPA Automaticall 320 2 716'7 29. 4.1 39 12:58:32 tage at Perfs: 4.0 PPA 319 294 722.1 29. 4. 40 13'.00:51t art 6.0PPA Automatically 326 295 790.7 29.2 5. Schlumberger -Private Client: Hilcorp Alaska Schlumberger Well: MPLd1 krmation: Kuparuk C District: Prudhoe Bay, AK Country: United States Schlumberger -Private MPt( L-4( Frh 2le,(04L) Reqq, James B (DOA) From: Regg, James B (DOA)[�'Ib�JQ Sent: Friday, November 16, 2018 9:33 AM '\ To: Phillip Shumake - (C) Cc: John Menke; Mark O'Malley; DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Subject: RE: [EXTERNAL] RE: BOPE Test Report Attachments: BOP Hilcorp ASR1 11-12-18 revised.xlsx Based on the explanations provided below, attached is a revised report for the 11/12/2018 BOPE test. Jim Regg Supervisor, Inspections AOGCC 333 W.7'h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 suaAKED 0EC 3 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.re¢e(aalaska.eov. From: Phillip Shumake - (C) <pshumake@hilcorp.com> Sent: Tuesday, November 13, 2018 2:26 PM To: Regg, James B (DOA) <jim.regg@alaska.gov> Cc: John Menke <jmenke@hilcorp.com>; Mark O'Malley <momalley@hilcorp.com>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (DOA) <phoebe.brooks@alaska.gov> Subject: RE: [EXTERNAL] RE: BOPE Test Report Here is the requested explanation. The failures after test one will be the attempts at getting a successful test on Test #2, test 2 had to be run on another chart due to lack of space to chart the test. Same thing occurred on test #7 (lack of space on chart ). The test sheet attached has the explanation of repairs as well as the tests for the components. ....sorry for the confusion. Phillip Shumake Company Rep, ASR #1 Hilcorp Alaska Office: 907-685-1266 Cell: 817-360-0930 From: Regg, lames B (DOA) [mailto:iim.reggc@alaska.gov] Sent: Tuesday, November 13, 2018 1:58 PM To: Phillip Shumake - (C) <pshumake hilcorp.com> Cc: John Menke <imenke@hilcorp.com>; Mark O'Malley <momalley hilcorp.com>; DOA AOGCC Prudhoe Bay <doa.aoecc.prudhoe. bay@alasko.gov>; Brooks, Phoebe L (DOA) <phoebe.b1„0ks@alaska.gov> Subject: [EXTERNAL] RE: BOPE Test Report Provide a list of the BOPE components tested that that matches the test charts sent to Mr. Herrera. Also explain what appears on those test charts to be - several failed test attempts after test #1; - a retest (high pressure) for test #3; and - an initial failure of test #7. Jim Regg Supervisor, Inspections AOGCC 333 W.71h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.reaa@alaska.eov. From: Phillip Shumake - (C) <pshumake@hilcorp.com> Sent: Monday, November 12, 2018 2:34 PM To: Regg, James B (DOA) <iim.rees@alaska.aov>; DOA AOGCC Prudhoe Bay <doa.aoecc.prudhoe.bav@alaska.eov>; Brooks, Phoebe L (DOA) <phoebe.brooks@alaska.eov> Cc: John Menke <jmenke@hilcorp.com>; Mark O'Malley <momallev@hilcorp.com> Subject: BOPE Test Report Phillip Shumake Company Rep, ASR #1 Hilcorp Alaska Office: 907-685-1266 Cell: 817-360-0930 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report `All BOPE reports are due to the agency within 5 days of testing' Submit to: iim.regg(cDalaska.gov; AOGCC.Inspectors(cDalaska.gov: Phoebe. brooks((Dalaska.gov Contractor: Hilcorp Rig No.: ASR 1 DATE: 11/12/18 - 0 Rig Rep.: Matt Beshea Rig Phone: 907-685-1266 I 11" FP Operator: Hilcorp Alaska Op. Phone: 907-685-1266 P - #2 Rams 1 Rep.: Carl Linaman/Phil Shumake E-Mailman313l@gmail.com / pshumakeq@hllc rC 0 Well Name: MPU L-41 - PTD # 2181040 Sundry # 318-480 - NA #5 Rams Operation: Drilling: Workover: x - Explor.: 0 Test. Initial: K, - Weekly: Bi -Weekly: P - HCR Valves Test Pressure (psi): Rams: 250 / 3000 - Annular: 250/2500 - Valves: 250 / 3000- MASP: 2331 " MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: NA Test Result Test Result mud cross Quantity Test Result Location Gen. P Well Sign P - Upper Kelly 0 NA Housekeeping P - Rig P - Lower Kelly 0 NA PTD On Location P Hazard Sec. P - Ball Type 1 P - inding Order Posted P - Misc. NA Inside BOP I P FSV Misc 0 NA BOP STACK: Quantity Size/Type Test Result Stripper 0 NA Annular Preventer I 11" FP #1 Rams 1 2-7/8" x 5.0" P - #2 Rams 1 Blinds P #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 2 1/16" P - HCR Valves 2 2 1/16" P Kill Line Valves 1 2 1/16" P Check Valve 0 NA BOP Misc I mud cross FP CHOKE MANIFOLD: Quantity Test Result No. Valves 16 P Manual Chokes 1 P Hydraulic Chokes I P CH Misc 0 NA MUD SYSTEM: Visual Trip Tank Pit Level Indicators Flow Indicator Meth Gas Detector H2S Gas Detector MS Misc Quantity Inside Reel valves 0 ACCUMULATOR SYSTEM: Time/Pressure System Pressure (psi)_ Pressure After Closure (psi) _ 200 psi Attained (sec) _ Full Pressure Attained (sec)_ Blind Switch Covers: Nitgn. Bottles # & psi (Avg.): 4 ACC Misc Test Results Number of Failures: 2 Test Time: 7.5 Hours Repair or replacement of equipment will be made within days. Notify the AOGCC of repairs with written confirmation to: AOGCC.Ins 2475 Alarm Test Result NA Test Result Remarks: Tested with 2 7/8" & 4.5" test joint. Tested all fire and gas alarms. Completed flow test with Flow indicator in Flowline. Test #2 - service mud cross for passing test (FP). Test #3 - tighten connection on pump -in 'T'. Test #7 - cycle annular for passing test (FP). AOGCC Inspection 24 hr Notice Yes Date/Time Waived By Matt Herrera Test Start Date/Time: 11/12/2018 0:00 (date) (time)Witness Finish Date/Time: 11/12/2018 7:30 `I (?v- C ke,*, e--Ork r,' \I�Iblf� Form 10-424 (Revised 04/2018) BOP Hilcorp ASR1 11-12-18 revised 4500-1 -� �IA( L-4( Pit 'Liic40 .4000 . \� 3500 -3000 - —2 0 `. -2000 1000 o / X i d 00 00 UO O CHART N0.I ! MO M,_,000- METER IHRw �P �: rl!`I �!'1' ' r f •� it � Ali 14 CHART PUT p � �1 pp(ry TAKEN OFF LOCATION lhRu / M - � REMARKS-----------� ' oo01��/ o° ocg .\ �\ 0g n 3' Q : 4500 _- ------ S n� �I(� 1L)4 -t7 -4000 � X3500 3000 2 500 ��j 20001j— 500 -�� �� n Sp I / So I Q 1 x 1 o JOD � J,o pO Gaphic CmWll O /(- lLp —I� C) CHART N0. MC MP -5000 -IHR i� CD, h: I II •i;'.'I j Vii METER � I I iI 1 CHART PUT ONTAKEN OFF YJ I,I I III N, II I I I II�cn I,I IrI _. LOCATION REMARKS ub I - 000£-� -.009£ Y 0004 02 cJ 4 A Hicorp ASR #1 BOP Test Procedure 3.0 ASR RIG 1 BOPS TEST 11" 5K STACK LOG WELL L-4_ 1 DATE 11/1 18 Test Pressure 250LoW/30001;igh Annular 250Low 2500High NL� hrS start time n0LOO Finish Q�3�__ Actual test time l h TEST # Pass Fail 1 Blinds, C12, C14, C16 !'^u'' �ftd65 2 Pipe Rams, I BOP, CI, K1 ',,P1 bE 3 Pipe Rams, TIW, HCR Choke, HCR Kill i 1(b�1iEf� Fri^ 1 — 4 Pipe Rams, "TIW, C5, C6, C9, K3 5 Pipe Rains, TIW, C4, C7, C11, K3 6 Pipe Rams, TIW,C8,CIO, C13,C14,C15,K3 7 Annular, TIW, C8, C91 C10, K3 36fZ 8 Choke Bleed Off uli�i( J iill(al� System Pressure a Draw Down Pressure Test witnessed by 200 PSI Ll SSC // Test witness waived byffA#h Full Recovery S� W - Ten Bottles 1a 2247 3 47 42Y� 5_6_ 7_ 8_ 9_ 10_ Tested Gas Alarms: Page 9 3 ON NEXT PAUL.. A i I /AV r 1"W IL avvL ILCOR® BOP TEST NOTES des �e5� VI � ( fl)�oel-5koL 0 Hil,nq Alwka, Lld: DATE 11/06/2018 21810'> Debra Oudean 2 9 9 3 0 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Ste 1400 1 Anchorage, Alaska 99503 Office: 907.777.8337 doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite100 Anchorage, AK 99501 DATA TRANSMITTAL CBL CD 1 M PL -41 - MP L-41 CBL 10-16-18.1as 10/17/201812:55 ... o MP L-41 CBL 10-16-18.pdf 10/17/201812:55 ... MP L-41 GR_Res.LAS 10/28/20181:42 PM LAS File PDFDocume LAS File Please acknowledgeAec4pt by signing and re*rning one copy of this transmittal or FAX to 907 777.8337 Date: THE STATE Alaska Oil and Gas 01ALASKA Conservation Commission GOVERNOR BILL WALKER Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk Oil Pool, MPU L-41 Permit to Drill Number: 218-104 Sundry Number: 318-480 Dear Mr. York: 333 West 7th Avenue Anchorage, Alaska 99501 Main: 907.297.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. 4( DATED this36 day of October, 2018. Sincerely, Hollis S. French Chair RBDMS1 NOVO 12010 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS S' 1. Type of Request: Abandon ❑ Plug Perforations ❑ ` Fracture Stimulate ❑ Repair Well Operations shutdown ❑ Suspend ❑ Perforate ❑r Other Stimulate ❑ Pull Tubing L Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Complete ❑✓ 2. Operator Name: 4. current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development Q Stratigmphic ❑ Service ❑ 218-104 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23611-00-00 ' 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 432D Will planned perforations require a spacing exception? Yes ❑ No 0 MPU L-41 9. Property Designation (Lease Number): 10. Field/Pool(s): I ADL025509, ADL355017 Milne Point Unit/ Kuparuk Oil pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 11,315' 7,468' 11,232' 7,390' 2,331 11,232' N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 80' 80' N/A N/A Surface 7,366' 9-5/8" 7,366' 4,701' 5,750psi 3,090psi Production 11,259' 7" 11,291' 7,445' 7,240psi 5,41 Opal Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 26# / L-80 / TXP 10,857' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 4-1/2" x 7" and NA 10,760r/ 6,946' and N/A 12. Attachments: Proposal Summary Q Wellbore schematic ❑j 13. Well Class after proposed work: Detailed Operations Progiam ❑ BOP Sketch ❑✓ Exploratory ❑ Stmtigraphic ❑ Development 10 Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 11/10/2018 OIL Q WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Bo York Contact Name: Paul Chan Authorized Title: Operations Manager Contact Email: DChan(ftilcorD.001T1 Contact Phone: 777-8333 Authorized Signature: Zd2Date: 10/24/2018 COMMISSION USE ONLY Conditions of approval: Notify Commission so flat a representative may witness Sundry Number: It - LA 8 V V Plug Integrity El BOP Test E(Q MechanicalIntegrityTest El Location Clearance El Other: 3 000 �p s � .6e P 1 �— / � Rc�&c� ��% S%0� f�+ 3. rSP w. /---,C.0 Post Initial Injection MIT Req'd? Yes ❑ No ❑ / Exception Required? Yes No d Subsequent Form Required: Q — L1044 Spacing ❑ / APPROVED BY OO� Approved by: COMMISSIONER THE COMMISSION Date: (d ( V /D -,?q- /d RBDM I' NOVO 12010 v� V ORIGINAL Submit Form and �}r1� rm 10-403 Revised 4/2017 Approved application is valid for 12 months from the date of approval. Attachments in Duplicate K Ilil..P Alaska, LL Well Prognosis Well: MP L-41 Date:30/23/2018 Well Name: MP L-41 API Number: 50-029-23611-00 Current Status: New Well Pad: L -Pad Estimated Start Date: November 101h, 2018 Rig: ASR #1 Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 218-104 First Call Engineer: Paul Chan (907) 777-8333 (0) (907) 444-2881 (M) Second Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) Current Bottom Hole Pressure: 3,031 psi @ 7,000' TVD (Estimated reservoir pressure / 8.34 ppg EMW) Maximum Expected BHP: 3,031 psi @ 7,000' TVD (Estimated reservoir pressure / 8.34 ppg EMW) MPSP: 2,331 psi (0.1 psi/ft gas gradient) Brief Weil Summary: The Milne Point L-41 well was drilled as a Kuparuk River development well in October 2018 and completed with a 4-1/2" fracture stimulation string. After the fracture stimulation, the 4-1/2" tubing string will be replaced by a 2-7/8" permanent ESP completion. The well is cased and cemented. Notes Regarding Wellbore Condition The 7" production casing was tested to 3500 psi for 30 minutes on October 15, 2018. CO 390A: Hilcorp Alaska respectfully requests that a packer not be required on this ESP completion ��— as the reservoir pressure is less than 8.55 ppg EMW. Objective: Replace the 4-1/2" tubing with a 2-7/8" ESP completion. ✓ Pre -Rig Procedure: 1. RU E -line. Test lubricator to 250 psi low/ 3,000 psi high. 2. Contingency adperfs: a. Kuparuk A2: ±11,126'– ±11,143' MD' b. Kuparuk B: ±11,058'– ±11,063' MD c. Kuparuk B: ±11,018' –±11,041' MD d. Kuparuk B/C: ±10,998'– ±11,018' MD 3. RIH w/ chemical cutter and cut the Halliburton AHC packer mandrel. 4. RD E -line. 5. Clear and level pad area in front of well. Spot rig mats and containment. 6. RD well house and flowlines. Clear and level area around well. 7. RU Little Red Services. RU reverse out skid and 500 bbl returns tank. 8. Pressure test lines to 4,000 psi. 9. Circulate at least one wellbore volume with ±8.5 ppg seawater down tubing, taking returns up casing to 500 bbl returns tank. Calculate kill weight fluid and circulate the well dead. 10. Confirm well is dead. Freeze protect tubing/casing if needed with 60/40 McOH or diesel. 11. RD Little Red Services and reverse out skid. H E#ilaarp Alaska, LLi 12. RU crane. Set BPV. ND Tree. NU 11" BOPE. RD Crane. 13. NU BOPE house. Spot mud boat. Brief RWO Procedure: Well Prognosis Well: MP L-41 Date: 10/23/2018 14. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines to 500 bbl returns tank. 15. Check for pressure and if 0 psi pull BPV. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well with kill weight fluid prior to pulling BPV. Set TWC. 16. Test BOPE to 250 psi Low/ 3,000 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5 -min). Record accumulator pre -charge pressures and chart tests. P a. Perform Test per ASR 1 BOP Test Procedure dated 11/03/2015. b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Test Annular, VBR and pipe rams on 2-7/8" and 4-1/2" test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 17. Contingency: (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.) a. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) 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. 18. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/ kill weight fluid as needed. 19. MU landing joint or spear to the tubing hanger. BOLDS. 20. Unseat hanger and release packer. Check for flow to ensure well is dead. Recover the tubing hanger. Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re -land hanger (or test plug) in tubing head. Test BOPE per standard procedure. 21. Contingency: If the packer will not release. a. RU E -line. Test lubricator to 250/3,000 psi. b. RIH w/ cutter. Correlate packer cut depth off of XN nipple below packer. c. Make cut across packer mandrel. d. POOH. RD E -line. 22. POOH and lay down the 4-1/2" tubing and completion jewelry P 15 tr,q Well Prognosis Well: MP L-41 Date: 10/23/2018 Hil.ry AI.Ikn, M Send 4-1/2" 12.6#/ft L-80 TXP-SR tubing in for cleaning and storage with thread protectors. • Junk 4-1/2" Packer. • Send 4-1/2" Jewelry to Halliburton Shop for re -dress. 23. RIH with 6" bit on workstring. Clean out well to 11,232' PBTD. POOH. 24. PU new ESP completion and RIH on 2-7/8" tubing. Set base of ESP at ± 10,570' MD. a. Tubing hanger b. 3 joints of tubing c. Upper GLM @ ± 140' MD w/SO d. 2-7/8" tubing e. Lower GLM w/ DGLV f. 3 joints of tubing g. 2-7/8" XN (2.205" No -Go) h. 1 joint of tubing L Base of ESP centralizer @ ± 10,570' MD 25. Land tubing hanger. RILDS. Lay down landingjoint. Note PU (Pick Up) and SO (Slack Off) weights on tally. 26. Set BPV. ND BOPE and NU 2-9/16" tree. Pull BPV and set TWC. Test tree flange to 500 psi low/5000 psi high. Freeze protect well (may be done post -rig) 27. Replace gauge(s) if removed. 28. Turn well over to production. RU well house and flowlines. 29. Set BPV. Rig down ASR. Post -Ria Procedure: 30. RD mud boat. RD BOPE house. Move to next well location. 31. RU crane. ND BOPE. 32. NU new 2-9/16" 5,000# tree/adapter flange. Test tubing hanger void to 500 psi low/500 psi high. Pull BPV. Set TWC. Pressure test tree. 33. RD crane. Move 500 bbl returns tank and rig mats to next well location. 34. Replace gauge(s) if removed. 35. Turn well over to production. RU well house and flowlines. Attachments: 1. As -built Schematic 2. Proposed Schematic 3. BOPE Schematic 4. Proposed Tree/Wellhead 5. Blank RWO MOC Form B Imrn Alaska, LLC Orifi. KB Elev.: 33.1 / GL Bev.: 16.5' TD =11,315' (MD) / TD= 7,468' (TVD) PBTD =11,232' (MD) / PBTD = 7,390' (TVD) Milne Point Unit Well: MPL-41 SCHEMATIC Last Completed: TBD PTD: 218-104 TREE & WELLHEAD DETAIL Tree 4-1/16" SM Wellhead 11" SM FMC Gen V Size OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" 1 Stg 11685113/458 ft3, Stg 21937 ft3/314 ft3 9-7/8"x8-1/2" 1 Stg 1296ft3, Stg 2191 ft3 CASING DETAIL Wt/ Grade/ Conn I ID Btm I BPF 9-5/8" Surface 40/L-80/TXP 6.6j, 6.276 Surface 11,291' 1 0.0383 7" Intermediate 26/L-80/TXP TUBING DETAIL 4-1/2" Frac String 12.6 / L-80 / TXP 3.958 Surface 10,857' 0.0152 WELL INCLINATION DETAIL KOP @ 600' Max Hole Angle 61 deg JEWELRY DETAIL M10,7bU Item ID 1/2"x 7"Paker 3.8801/2"XN Nipple 3.725ule Shoe 1 3.958" GENERAL WELL INFO API: 50-029-23611-00-00 Drilled and Cased by Doyon 14-10/12/2018 Revised By: TDF 10/23/2018 n HilcorP Alaska, LLC ong. KB Elev.: 33.7 / GL Elev.:16.5 ES Cementer @2,508' 2 3 4 7&8 ES Cementer @10,439 ro __......... TD =11,315' (MD) / TD = 7,468' (TVD) PBTD=11,237 (MD) / PBTD= 7,390' (TVD) Milne Point Unit ( Well: MPL-41 PROPOSED Last Completed: TBD PTD: 218-104 TREE & WELLHEAD DETAIL Tree 4-1/16" SM Wellhead 11" SM FMC Gen V OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" 5tg 11685 ft3/458 ft3, Stg 21937 ft3/314 ft3 9-7/8"x8-1/2" I Stg 1296f[3, Stg 2191 ft3 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm BPF TUBING DETAIL 5 5 / L 80 / EUE 8rd 2 441 Surface 1 ±30,57 WELL INCLINATION DETAIL !Max0' Hole Angle 61.8 deg @ 7299' MD ".c. ov nCTAII No. 1 Top MD ±140' Item ST 7.9-7/A" GLM 2 3 ± ± ST 1: 2-7/8" GLM 2-7/8"XN-Nipple-Min ID= 2.205 4 5 ± ± Discharge Head Pum 6 ± Gas Separator 7 ± Upper Tandem Seal 8 ± Lower Tandem Seal g ± Motor 10 ± 5ensor&Centralizer-Bottom@±10,570' PERFORATION DETAIL c SandsM ) Btm (MD) Top (TVD) etm (TVD) rl •- 8/C♦7210' ±11,018' ±7,1740' ±7,188' ±20 utureKuparuk uture B ±11,041' ±11,063' ±7,188'Kuparuk ±7,226' ±7,231' ±23 ±5 MFuture utureKu arukA3' ±11,117' ±7,272' ±7,282' ±8 uture Kuparuk A2' ±11,143'±7,290' ±7,306' ±17 /2018 Pollartl Ratlfal /Sector CBL GENERAL WLLL IINVU API: 50-029-23611-00-00 Drilled and Cased oy Doyon 14 - 10/12/2018 Revised By: TDF 10/24/2018 .RR Point ASR Rig 1 BOPE 2018 Ililro�p Ala.4s. l.id: I V BOPE Updated 5/14/2018 R or Pipe Rams nd es WELL—_MP."' DATE 10 24 1a Tree Cap. Otis style, 4 %" ACME 2 9/16" 5K, FE,DD L -U PN 2048774-01-01 SN 11 x 115K FMC Gen 5 tbg spool w/ Zea 2 1/16" 5K outs. 10.38" bore PN 13-300-718 Tbg Hgr, FMC Gen 5,11 x 2 7/8" EU E BOX top and bottom, 2 1/2" "H" BPV,ported for 2 ea 3/8" Control line, w/ ESP, dummy Heat Trace w/ 3' pup L-U,DD-NL, PN P134136-0002 SN 11 x 7, FMC Gen S,Mandrel casing hanger , 8" 4 ACME top x 7 5/8" 563 Hyd bottom with 3' pup UP pin down PN P1OOO124695 Csg Hgr, FMC C-21 18 3/4 x 9 5/8" Slip type hanger LU,DD-NL PN 12-093-174 SN . .S Hilcorp Alaska, LLC Swab valve Cameron FLS, 2 9/16" 5K, FE,EE,K-U PN 141522-31-07-02 SN Wing valve Cameron FLS, 2 9/16" 5K, FE,EE,K-U PN 141522-31-07-02 SN SSU valve Cameron FLS, Cameron Actuator 2 9/16" 5K, FE,EE,K-U PN2012043-03-01 SN Mastervalve Cameron FLS, 2 9/16" SK, FE,EE,K-U PN 141522-31-07-02 SN API 11" 5K API 13 5/6" SK Casing head section Assy.11" 5K x 9 5/8 sliplock RC -FMS - FMC w/ 2ea 2 1/16" 5K outs. 10.38" ID, PN P1000077731 GRADE / a P. 1k LW $I] t: \\} \ai \ « ;$ 2 ® �t7 £( (a /E »� a�) - _0- cy CaL.� /f Co k )Co a Q C \ \j a / \ k ) t G` £ O C CD / 0 \m � V - &/■ cr- w§ 2 2 C � \ \ a A J \ \/ & C 0 0 IL �@ - o\ E P. 1k LW DATE 10/26/2018 21 81 04 Debra Oudean Hilcorp Alaska, LLC 29 9 12 3800 Centerpoint Drive, Ste 1400 1 Anchorage, Alaska 99503 Office: 907.777.8337 doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite300 Anchors I a AK 99501 Me, E log data CD 1 MPL-41 Log Viewers 10/26/2018 9:03 A... File folder I CGM 10/26/2018 9:03 A... File folder A Definitive Survey 10/26/2018 9:03 A... File folder I. EMF 10/26/2018 9:01 A.. File folder I. LAS 10/26/2018 9:01 A... File folder I. PDF 10/26/2018 9:01 A... File folder I TIFF 10/26/2018 9:02 A... File folder RECEiV OCT z 9 ED 2018 AOGCC Please acknowledge/receipt by sigying and r Nming one copy of this transmittal or FAX to 907 777.8337 Received 8y: R W \) Date: 101 M W lok- DATE 10/26/2018 2 18 104 Debra Oudean 29 9 13 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Ste 1400 1 Anchorage, Alaska 99503 Office: 907.777.8337 doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite100 Anchors a AK 99501 E log data CD 1 MPL-41PB1 I _Log Viewers j CGM I Definitive Survey I. EMF I LAS I. PDF I TIFF Please acknowledge 10/26/201810:13 ... 10/26/201810:14 ... 10/26/201810:14 ... 10/26/201810:14 ... 10126/201810:14 ... 10/26/201810:15 ... 10/26/201810:16 ... R�ccF�V pj? y ?01 i® GCC File folder File folder File folder File folder File folder File folder File folder and r4rning one copy of this transmittal or FAX to 907 777.8337 Date: THE STATE °fALASKA GOVERNOR BILL WALKER Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk Oil Pool, MPU L-41 Permit to Drill Number: 218-104 Sundry Number: 318-466 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.aloska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. lk DATED this Z< day of October, 2018. Sincerely, Hollis S. French Chair RBDMS -)L OCT 2 5 2018 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25 280 RECEIVED OCT 15 2018 07-S 10 ( 25 / AGGGG 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑Q " Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate Q Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: CT FCO w/ N2 ❑Q 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development 10, Stratigraphic ❑ Service ❑ 218-104 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23611-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 432D Will planned perforations require a spacing exception? Yes ❑ No ❑Q I MPU L-41 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL025509, ADL355017 Milne Point Unit Kuparuk Oil pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth ND (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 11,315' 7,468' 11,232' 7,390' 2,331 11,232' N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 80' 80' N/A N/A Surface 7,366 9-5/8" 7,366' 4,701' 5,750psi 3,090psi Production 11,259' 7" 11,291' 7,445' 7,240psi 5,410psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schc I See Schematic 4-1/2" L-80 ±10,850' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 4-1/2"x 7" AHC / NA ±10,730' / NA and ±6,918' / NA 12. Attachments: Proposal Summary ❑✓ Wellbore schematic El 13. Well Class after proposed work: Detailed Operations program ❑ BOP Sketch Q Exploratory ❑ Stratigraphic ❑ Development ❑Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 10/26/2018 OIL ❑Q WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Bo York Contact Name: Paul Chan Authorized Title: Operatio age Contact Email: Chep hllcor .Colli Contact Phone: 777-8333 Authorized Signature: Date: ro 1 b r 8 "GCywR WE4.++N.�l fid COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: R �I 4I ^� V — I.V�I Plug Integrity ❑ BOP TestLD Mechanical Integrity Test ❑ Location Clearance ❑ Other: lF �rcv Yr r,r..� s u- 6.-e.: {-E..Q sfr `.c 10"5(— Post Initial Injection MIT Req'd? Yes ❑ No ❑ Subsequent Form Required: I Q 4 Q� t �fn� I Spacing Exception Required? Yes El No We f'�po�.'�J APPROVED BY �� IZ7 Il•p_ V Approved by: COMMISSIONER THE COMMISSION Date: C�Dw 10/.24j2018 Form 10-403 Revised 4/201Z�� U l'°rz '�,� R I G I N A L RMS -1 OCT 2 5 2d h Form and Approved app li ation is valid for 12 months from the date of approval. Attach entsin Duplicate ���� Mf Hilcorp Alaska, LLC October 16, 2018 Hollis S. French, Chair Alaska Oil and Gas Conservation Commission 333 West 7h Avenue, Suite 100 Anchorage, Alaska 99501 Post Office Boz 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Paul Chan Senior Operations Engineer (907)777-8333 RE: Hydraulic Fracturing Application, Milne Point Unit, MP L-41 Dear Commissioner French, Hilcorp Alaska, LLC ("Hilcorp"), as Operator of the Milne Point Unit, herein submits its application to fracture stimulate MP L-41. Please do not hesitate to contact Paul Chan at 907-777-8333 should you have any questions regarding this application. Sincerely, rhv'. ra Fae a.. �o¢� Bo York, Operations Manager HILCORP ALASKA, LLC Enclosures: Form 10-403 Sundry Attachments 20 AAC 25.283 (a)(1) Affidavit Affidavit stating that all owners, landowners, surface owners, and operators within a one-half mile radius of the current or proposed wellbore trajectory have been provided a notice of operations that is in compliance with 20 AAC 25.283 (a)(1) VERIFICATION OF NOTICE PER 20 AAC 25.283(a) MILNE POINT UNIT MP L-41 I, PAUL CHAN, Hilcorp Alaska, LLC, ("Hilcorp") do hereby verify the following: I am acquainted with Hilcorp Alaska, LLC's application for sundry approval to the Alaska Oil and Gas Conservation Commission to enhance production of the MP L-41 well via hydraulic fracturing. Pursuant to 20 AAC 25.283(a)(1), I assert that all owners, landowners, surface owners, and operators within a one-half mile radius of the current or proposed wellbore trajectory have been provided notice of Hilcorp Alaska, LLC's proposed operations. DATED at Anchorage, Alaska this �fdaVPaCh/a'n, aPc�201 Sr. Operations Engineer Hilcorp Alaska, LLC STATE OF ALAKSA THIRD JUDICIAL DISTRICT SUBSCRIBED TO AND SWORN before me this lSday of ©gofer' 2018 4"�a-cz�.✓ NOTARY PUBLIC IN AND FOR THE STATE OF ALSKA q My Commission expires: �e✓. /, a oy� STATE OP ALASKA _ NOTARY PUBLIC Sharon A. Chriss My Commission Expires: November 9, 2021 20 AAC 25.283 (a)(2) A Plat (A) Showing The Well Location; (B) Identifying each Water Well, if any, Located within a One -Half Mile Radius of the Well's Surface Location; and L 21 \ III I I I IF/1/ 1 l,. .L -14. .I I r/ �Sec. 36\/ PU014N010E // , '� L-29 L-isI 1I I qN)// / � ADL3550171 ADL3550A SeL,3111 t / ! Sec. 33 t(62j)l/rr /ct I Sec:32II lP153PB1/ 1 tC / / ! tI L-a1Pe1r L41,L=f1/ _• r / I 1 i/ Frac Zane � � A r L,''t/l \yr �1 I ' /l l t , /' ^ L 13 La3/I F''5a� r I I\1 (j / /\ t ♦� / '-a3Pe1 Sec..6J r x n \ Sec. 5' t / / Sec. 4 U013N009E� pa; (625)rr \I l r t /i �Secl: 1 Ott'' n V I MILNE 'MP.\o9 ' POINT UNIT F-azael /-. � F\ �/\f /}\\\.i It i F-21Fey \ \ l i I I -10 r / / f AD 11'0'251509 / / / ! ' ADL047434 / / \ L-03 \ \\ \ \ \ L-0 A' U013N010E i WELL SYMBOL L -02\\F21 `\\\II / rr/ / ♦ �- DRY HOLE \- \ ADL388235 \ j w MPUL-41_SHL /INJECTOR F-99. r \ L-02APB2l!)2APBf ,,.6 / \ F-99Pe1 �� MPU�L i a \ L=02A r 1,t1�1 01 c-36 G PLUG BACK / G2AL"2 L--02AL y — _ • OTHER \ Sec117 : ' % % CD�j' Sec i8' Sec. 12 \ ' (628)LG xi' /' / i \ \ i L -01A i OIL - ACTIVE _ C 05 \ !F-1071 !_ •— — Legend 112 Mile Radius -Well Bore Well Trajectory MPL-41 Well Trajectory MPL-01 00 and Gas Lease �. ADL315948 1/2 Mile Radius-Frac Zone — — Other Well Trajectories I _ ' ADL025509 L. � gOL355017 f`ADL$15848 • Top of Frac Zone C Pad Footprint - A01025514 , ADL355018 Sec. 16 Base of Frac Zone ADL025515 r ADL388235 0 Surface Hole Location (SHL) MPL-41 ADL047434 Milne Point Unit Petra Well Database - HAK MPL-41 Well MPL-41 Definitive Survey aamrr, Atoka, LV N Woo centemalnt on SUO 14M Plat depicting all Well types 0 1,000 2,000 Mn onge.AK,9003 within 1/2 mile of MPL-41 Feet Map Date: 10/152018 Sec 31 ADL355018 (622) Legend • Top of Frac Zone • Base of Frac Zone 0 Surface Hole Location (SHL) MPL-41 _ Well Trajectory MPL-41 ..ti ■ �� 1/2 Mile Radius from SHL Pad Footprint E1Fna■i■ Sec.6 (625) ■ MPUL-41_SHL i ■ U014N010E ADL355017 Sec 32 U013 L I Frac Zone OE ADL025509 .I MPU L-41 BHL i MILNE Sec.8 POINT #UNIT Petra Well Database - HAK Milne Point Unit MPL-41 Definitive Survey MPL-41 Well No Water Wells Within 112 Mile Rtl eq Awa. u.c 0 5001,000 1,5 N UN Cen�.I.M1 ay SUIte 14M Plat depicting no water wells Feet Antloage, AK, 9950 within 1/2 mile of the MPL-41 SHL Map Date: 10/15/2018 (C) Identifying for all Well Types each Well Penetration Well API PTD POOL Type Status MPL-01A 50029210680100 2030640 KR 1 -OIL Shut In MPL-02A 50029219980100 2091470 KR 1 -OIL Producing MPL-03 50029219990000 1900070 KR 1 -OIL Producing MPL-04 50029220290000 1900380 KR 1 -OIL Producing MPL-05 50029220300000 1900390 KR 1 -OIL Producing MPL-06 50029220030000 1900100 KR SUSP Sus ended MPL-07 50029220280000 1900370 KR 1 -OIL Producing MPL-08 50029220740000 1901000 KR WAG Shut In MPL-09A 50029220750100 2131870 KR WAG Shut In MPL-10 50029220760000 1901020 KR WAG Shut In MPL-11 50029223360000 1930130 KR 1 -OIL Producing MPL-12 50029223340000 1930110 KR 1 -OIL Producing MPL-13 50029223350000 1930120 KR 1 -OIL Shut In MPL-14 50029224790000 1940680 KR 1 -OIL Producing MPL-15 50029224730000 1940620 KR WAG Injecting MPL-16A 50029225660100 1990900 KR WAG Injecting MPL-17 50029225390000 1941690 KR 1 -OIL Shut In MPL-20 50029227900000 1971360 KR 1 -OIL Shut In MPL-21 50029226290000 1951910 KR WAG Shut In MPL-24 50029225600000 1950700 KR WAG Shut In MPL-25 50029226210000 1951800 KR 1 -OIL Producing MPL-28A 50029228590100 1982470 KR 1 -OIL Producing MPL-29 50029225430000 1950090 KR 1 -OIL Producing MPL-32 50029227580000 1970650 KR WAG Shut In MPL-33 50029227740000 1971050 KR WAG Injecting MPL-34 50029227660000 1970800 KR SUSP Suspended MPL-35A 50029227680100 2011090 KR SUSP Suspended MPL-36 50029227940000 1971480 KR 1 -OIL Producing MPL-37A 50029228640100 1980560 56 1 -OIL Shut In MPL-39 50029227860000 1971280 KR 1 -OIL Shut In MPL-40 50029228550000 1980100 KR 1 -OIL Producing MPL-42 50029228620000 1980180 KR WAG Shut In MPL-43 50029231900000 2032240 KR 1 -OIL Producing MPL-45 50029229130000 1981690 KR P&A P&A MPL-46 50029235510000 2151180 SB 1 -OIL Producing MPL-47 50029235500001 2151170 SB 1 -OIL Producing MPL-48 50029235520000 2151200 SB PWI Injecting MPL-49 50029235450000 2150990 SB PWI Shut In MPL-50 50029235550000 2151320 SB PWI Injecting Well API PTD POOL Type Status MPL-51 50029235870000 2171510 SB PWI Shut In MPL-52 50029235900000 2171740 56 PWI Shut In MPL-53 50029235860000 2171440 SB PWI Shut In MPL-54 50029236070000 2180660 SB 1 -OIL Producing MPL-56 50029236040000 2180500 SB 1 -OIL Producing MPL-57 50029236090000 2180720 SB 1 -OIL Producing 20 AAC 25.283 (a)(3) Identification of Freshwater Aquifers There are no underground sources of drinking water within a one-half mile radius of the current wellbore trajectory. Any and all freshwater aquifers lying below the Milne Point Unit are exempted aquifers under Aquifer Exemption Order 2 (AEO-2). See the Conclusion of AEO-2, which states that "The portions of freshwater aquifers lying directly below Milne Point Unit qualify as exempt freshwater aquifers under 20 AAC 25.440." 20 AAC 25.283 (a)(4) Baseline Water Well Sampling There are no water wells located within one-half mile radius of the current wellbore trajectory. A water sampling program is not required. 20 AAC 25.283 (a)(5) Detailed Casing and Cementing Information 9-5/8" 40#/ft L-80 TXP-SR surface casing set at 7,367' MD with stage tool at 2,520' MD. First stage cemented with 720 sxs / 302 bbls of 12 ppg cement followed by 400 sxs / 82 bbls of 15.8 ppg Class G cement. Second stage cemented with 300 sxs / 230 bbls of 10.7 ppg PermaFrost L followed by 270 sxs / 56 bbls of 15.8 ppg Class G cement. 7" 26#/ft L-80 TXP-SR production casing set at —11,290' MD. Two stage cement job: First stage cement job: 255 sxs / 52.7 bbls of 15.8 ppg Premium G cement. The second stage cement job: 165 sxs / 34.1 bbls of 15.8 ppg Premium G cement Detailed Casing Information Size Type Wt/ Grade/ Conn Pipe Body Yield (Ibs) Collapse Pressure (psi) Internal Yield Pressure (psi) Conductor N/A N/A N/A N/A 9-5/8" Surface 40# / L-80 / TXP-SR 916,000 3,090 5,750 7" Production 26# / L-80 / TXP-SR 604,000 5,410 7,240 Detailed Tubing Information 4'/2" Tubing 12.6 / L-80 / TXP-SR 288,000 7,500 8,430 20 AAC 25.283 (a)(6) Assessment of Each Casing and Cementing Operation Performed to Construct or Repair the Well The 9-5/8" surface casing was set below the base of the Schrader Bluff sands. The first stage cement job was started by pumping 60 bbls of 10 ppg Clean Spacer with red dye followed by 720 sxs / 302 bbls of 12 ppg ExtendaCem lead cement and 400 sxs / 82 bbis of 15.8 ppg Premium G tail cement at 4 BPM average rate with 75% returns during the first stage cement job. Lost 136 bbls while displacing cement. Casing was rotated and reciprocated during the first stage cement job. The ESIPC was inflated and the stage tool sheared open. 153 bbls of tuned spacer/mud and 85.6 bbls of green cement were circulated out. The second stage was cemented by first pumping 60 bbls of 10 ppg Clean Spacer followed by 300 sxs / 230 bbis of 10.7 ppg PermaFrost L lead cement and 270 sxs / 56 bbls of 15.8 ppg Premium G cement tail at 5 BPM average rate. Recovered 55 bbls of spacer and 155 bbls of cement at surface. Bumped plug and closed stage tool at 1450 psi. Floats held. No cement was lost during the second stage cement job. The job was pumped with cement to surface indicating a competent cement job. The 7" production casing was set across the Kuparuk sands and cemented in two stages. The first stage cement job was started by pumping 50 bbls of 10.5 ppg Clean Spacer followed by 255 sxs / 52.7 bbls of 15.8 ppg Premium G cement at 5 BPM average rate with 100% losses during the first stage cement job. 590 psi lift pressure observed during cement job. Floats held. The ESIPC was inflated and the stage tool sheared open. The second stage was cemented by pumping 50 bbls of 10.5 ppg Clean Spacer followed by 165 sxs / 34.1 bbls of 15.8 ppg Premium G cement at 5 BPM average rate with 100% losses. 300 psi lift pressure observed during cement job. Bumped plug and closed stage tool at 3100 psi. Bleed off pressure to confirm stage tool closed. The job was pumped with observed lift pressures during the first and second stage cement job, indicating a competent cement job. The 7" CBL/VDL log will be submitted after completing the logging run on the rig. Ac- LB C sh"., ` - C KII, 20 AAC 25.283 (a)(7) Plans to Pressure -Test the Casings and Tubing Installed in the Well The 9-5/8" casing was pressure tested to 2500 psi for 30 minutes on September 9, 2018. The 7" casing was pressure tested to 3500 psi for 30 charted minutes on October 15, 2018. The 4-%=" tubing will be pressure tested to 4950 psi for 30 minutes. The 4-1/2" x 7" annulus will be pressure tested to 3500 psi for 30 minutes. 20 AAC 25.283 (a)(8) Pressure Ratings and Schematics for the Wellbore, Wellhead, BOPE, and Treating Head Size Weight #/ft Grade API Collapse Pressure (psi) API Internal Yield Pressure (psi) 9-5/8" 40 L-80 3,090 5,750 7 26 L-80 5,410 7,240 Treating Head 15M Wellhead BOPE EN/A E] k7f� OIL STATES Energy Services (Canada) Inc. Maximum Allowable Pumping Rates PROPOSAL: Casing Isolation Tool -SIZE ID .. RATE in CSO 2.250 3.760 10 m'/min 3 1/2" Big Bore 2 718" & 31/2" 1.760 1.438 .2.750 2.360 6 m'lmin 4 m'/min- 2 3/8" 1.000 .1.900 2 m'/min 31116 & 4 1116 with tapered mandrel 2.750 4.000 15 m'lmin 41116 X Tool Mandrel 3.610 4.750 24 m'lmin 15M Treating Head OPEN POSmON yxwmnunun wvx�Oxi CLOSED POSMION I-- un q www. Sti n gerC a nada x om D Ori& KB Elev.: 33.7 / GL Elm:16.5' TD=11,315 (MD) / TD=7,468' (TVD) PBTD=11,164' (MD) / PBTD= 7,324' TVD) SCHEMATIC Milne Point Unit Well: MPL-41 Last Completed: TBD PTD: 218-104 TREE & WELLHEAD Tree I4-1/16" SM Wellhead I11"FMCGemv OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" 1 5tg 11685 ft3/458 ft3, Stg 21937 ft3/314 ft3 9-7/8"x8-1/2" I Stg 1296ft3, Stg 2191 ft3 rAcl Alr nLTAII Size Type Wt/Grade/Conn ID Top Btrn BPF 20" Conductor 164/A53B/Weld N/A Surface 1 3 N/A Mule Shoe Surface 40/L-80/TXP 8.835 Surface 7,36 ,36 6' 0.0758 7" Intermediate 26/L-80/TXP 6.276 Surface 11,291' 0.0383 I VUIIVU u[l AIL 4-1/2" Frac Strin 12.6 / L-80 / TXP 1 3.958 1 Surface 1 10,857' 1 0.0152 WELL INCLINATION DETAIL KOP Max Hole Angle 61 deg IFWFI Ry nFTAIL No. Top MD Item I ID 1 1 10,760' 1 4-1/2"x7" Packer 13.880" 2 1 10,765' 4-1/2" XN Nipple 3.725" 3 10,857' Mule Shoe 3.958" GENERAL WELL INFO AN: 50-029-23611-00-00 Drilled and Cased by Doyon 14-10/12/2018 Revised By: TDF 10/23/2018 u HBeneo Alaxka. LLC Orig. KB Elev.: 33.7 / GL Elev.: 16.5' PROPOSED FRAC STRING TD =11,315 (N1D) / TD= 7,468' (TVD) PBTD =±11,180' (KV) / PBTD=±7,341' (TVD) TREE & WELLHEAD Tree TBD Wellhead TBD Milne Point Unit Well: MPL-41 Last Completed: TBD PTD: 218-104 OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" Stg 11 1685 ft3/458 ft3, Stg 21937 ft3/314 ft3 9-7/8"x8-1/2" I Stg 1296ft3, Stg 2191 ft3 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm BPF 20" Conductor 164 / A53B / Weld N/A Surface 80' 3-5/8" Surface 40/L-80/TXP 8.835 Surface 1 7,366' 7" Intermediate 26/L-80/TXP 6.276 Surface ±11,291' TUBING DETAIL t-1/2" Frac String 12.6 / L-80 / TXP 1 3.958 1 Surface I ±10,850' WELL INCLINATION DETAIL 10)n7 KOP @ 600 Max Hole Angle 59 deg JEWELRY DETAIL No. Top MD Item ID 1 110,7 4-1/2" x 7" Packer 2 ±10,75eW 4-1/2" XN Nipple 3 ±10,85eYA Mule Shoe GENERAL WELL INFO API: 50-029-23611 Completion Date: TBD c dl,-- lvbL iollb1201 i' s� To C, ° S 3o ft C,),W to12q-J"19 7324' (TVD) c-DkJ l012412n 19 Edited By: PC 30-15-2018 20 AAC 25.283 (a)(9) Data for the Fracturing zone and Confining Zones (A) a lithologic description of each zone; (B) the geological name of each zone; (C) the measured depth and true vertical depth of each zone; (D) the measured thickness and true vertical thickness of each zone; and (E) the estimated fracture pressure for each zone; The Kuparuk formation is a Cretaceous -aged, fine-grained marine sandstone. The productive Kuparuk interval in the L-41 area consists of the Kuparuk C sands, Kuparuk B, and Kuparuk A sands. Formation tops and TVT numbers for the productive intervals are listed in the table below: Well Formation L-41 KUPARK C L-41 KUPARUK B L-41 KUPARUK A L-41 KUPARUK A BASE MD I TVD 7,116 14 7,130 90 7.220 17 The estimated fracture gradient for the Kuparuk interval is 0.65-0.68 psi/ft. The overlying confining zone consists of ^'2000' TVD of Kalubik, HRZ shale and Colville siltstones and shales. The top HRZ shale is in L-41 at -10,563' MD / 6,760' TVD. The top of the Colville is at 7,449' MD/4,741' TVD. The estimated fracture gradient for the Kalubik/HRZ is 0.75-0.82 psi/ft. The top of the Milluveach shales is in L - The underlying confining zone consists of the Milluveach shales. 41 at 11202' MD / 7,361 TVD. The estimated fracture gradient for the Milluveach shale is 0.8-0.82 psi/ft. 20 AAC 25.283 (a)(10) The Location, the Orientation, and a Report on the Mechanical Condition of Each Well that May Transect the Confining Zones MP L-05: 7" casing set across the Kuparuk sands and cemented with 435 sxs / 90 bbls of 15.8 ppg Class G cement. Bump plug and test casing to 3000 psi. Estimated TOC 8,900' MD. MP L-11: 7" casing set across the Kuparuk sands and cemented with 67 bbls / 302 sxs of 15.8 ppg Class G cement with partial returns during job. Bump pug and floats held. CBL log noted TOC low so thewell lcement. was perforated and squeeze cemented at 10,992' MD with 135 sxs / 28 bbls of 15.8 ppg MP L-14: 7' casing set across the Kuparuk sands and cemented with 44 bbls / 215 sxs of 15.8 ppg Class G cement with 30% returns during job. Bump plug with 3500 psi. MP L-41PB: Cemented 4-1/2" liner. Unable to release from 4-1/2" liner. Commence plug back operations. Spot balanced plug inside 7' production casing and tagged at 9,590' MD. Pressure tested 7" casing and cement plug to 2000 psi. Set retainer set at 7,833' MD and top ofed good to 2000 PMD to Cut pull 7and " casing down to 7,667 ' MD. Spot balanced cement plug p retainer at 7,267' MD. Note 9-5/8" casing shoe at 7,366' MD. Kick off well at 7,392' MD. Redacted For Public Disclosure 20 AAC 25.283 (a)(11) The Location of, Orientation of, and Geological Data for Each Known or Suspected Fault or Fracture that May Transect the Confining Zones 20 AAC 25.283 (a)(12) Proposed Hydraulic Fracturing Program ZA pRv 73ao P5 35oa15�, 1. RU SL. PT to 1500 psi. Note that the wellbore will be hydraulically isolated from the reservoir with pressure tested cemented 7" casing. 2. Pull ball/rod and RHC ball catcher. 3. Drift 4-1/2" tubing with 3-1/8" dummy pert gun to PBTD. 4. RDMO SL. 5. RU a -line and PCE. PT to 3000 psi (MPSP is 2331 psi / estimated Kuparuk River reservoir pressure). 6. Perforate the Kuparuk A3 sand formation f :[11,107 -±11,117' MD. Final depths to be 7. RDMO a -line. mfr S. MIRU frac fleet. MIRU frac and slop tanks. MIRU all ancillary support equipment. 9. Fill frac tanks with water. Heat water as needed. 10. Lay all hardlines and manifolds. Install pressure monitoring equipment on wellhead and tree. 11. RU 15K tree saver and hard line. 12. Pressure test all high pressure treating lines to 8000 psi. 13. Set the GORY (gas operated relief valve) at ±7300 psi. Set the staggered pump kickouts between 6800 psi and 6400 psi. 14. Pressurize annulus to 3000 psi. Set annular PRV at 3500 osi. 15. Prepare frac fleet to pump. 16. Pump Kuparuk A sand DFIT and analyze the results to obtain fluid loss coefficients. Adjust frac design. 17. Fracture stimulate Kuparuk A sand with 16/20 mesh resin coated proppant in cross-linked gel. See "Pump Schedule" for proposed design. 18. Displace with freeze protect fluid (optional). Do not over displace. 19. Shut well in. RD tree saver. 20. MIRU CTU, portable test separator and associated equipment. 21. RU CTU BOPE and PT to 3500 psi. RIH and cleanout frac sand/frac fluid to PBTD. Flowback well to portable test separator with filtered 2% KCI brine and N2 as needed to clean up frac. 22. Sand back 7" casing to 11,067' MD. 23. RU a -line and PCE. PT to 3000 psi (MPSP is 2331 psi / estimated Kuparuk River reservoir pressure). 24. Spot 10' cement cap on top of sand. 25. Perforate the Kuparuk C sand formation from ±10,998 -±11,018' MD. Final depths to be determined from OH logs. C 26. RDMO a -line. 27. RU 15K tree saver and hard line. 28. Pressure test all high pressure treating lines to 8000 psi. 29. Set the GORV (gas operated relief valve) at ±7300 psi. Set the staggered pump kickouts between 6800 psi and 6400 psi. 30. Pressurize annulus to 3000 psi. Set annular PRV at 3500 psi. 31. Prepare frac fleet to pump. 32. Pump Kuparuk C sand DFIT and analyze the results to obtain fluid loss coefficients. Adjust frac design. 33. Fracture stimulate Kuparuk C sand with 16/20 mesh resin coated proppant in cross-linked gel. See "Pump Schedule" for proposed design. 34. Displace with freeze protect fluid (optional). Do not over displace. 35. Contingency (Pending WO rig availability). MIRU CTU, portable test separator and associated to equipment. f,IQtw N ' �•'Sof' c } 36. Contingency (Pending WO rig availability). RU CTU BOPE and PT to 3500 psi. RIH and cleanout s CA"—, frac sand/frac fluid to PBTD. Flowback well to portable test separator with filtered 2% KCI brine and Ni as needed to clean up frac. 37. Turn well over to operations. 20 AAC 25.283 (a)(12) (A) Estimated Total Volumes Planned 20 AAC 25.283 (a)(12) (B) Trade Name, Generic Name, and Purpose of each Base Fluid and Additive to be Used; 20 AAC 25.283 (a)(12) (C) Chemical Ingredient Name of, and the Chemical Abstracts Service (CAS) Registry Number Assigned to, each Base Fluid and Additive to be used; 20 AAC 25.283 (a)(12) (D) Estimated Weight or Volume of each Inert Substance, including a Proppant or other Substance injected Schlumberger Client: Hilcorp Alaska, LLC Well: MPL-41 Basin/Field: Milne Point State: Alaska County/Parish: North Slope Borough Case: M002 Additive 1.1 Lb / 1000 Gal 149.0 Disclosure Type: Pre -Job Well Completed: 10/30/2018 Date Prepared: 10/11/2018 3:34 PM Report ID: RPT -57950 VF130F IexD:WF120: VFiexD: x 129,865 Gal D:WF330:WFI40 F103 1218 1475 1580 1604 •' Surfactant___ Breaker Breaker Gelling Agent Crosslinker _ e 1 1 5.9 33.8 1.8 Gal/1000 Gal Lb / 1000 Gal Lb / 1000 Gal Lb / 1000 Gal Gal/1000 Gal 129.0 132.0 770.0 4,391.0 233.0 Gal Lb Lb to Gal L071 Clay Control Agent 2 Gal / 1000 Gal 260.0 Gal LTCA LTCA 1.3 Gal/3000 Gal 163.0 Gal M002 Additive 1.1 Lb / 1000 Gal 149.0 Lb M275 Bactericide0.3 Lb / 1000 Gal 37.0 Lb 5526-1620 Propping Agent varied concentrations 289,900.0 Lb The total volume listed in the tables above represents the summation ofwaterandadditnuo. water is supplied oyniem. _ •Mix water is suppliedby the client. schlumherger has performed no analysis of the water anocannoe praameoereu.uvwn„r.,,,w2•••W•^-.------__-__.______ • The evaluation of attached document is performed based on the composition of the idennhed products to the extent that such Compositional information was known to GRC-Chemicals os of the date of the document wosproduced. Any new updates will not be reflected in this document Page 1 / 1 oma u..A F„ullmrn alnakn I lChaaermiS51a.. Water (Induding Mix Water Suppliedb Client)* "78% 66402-68-4 Ceramic materials and wares, chemicals -21 % 9000-30-0 Guargum <1 % 2-hydroxy-N,N,N-trimethylethanaminium chloride <1% 67-48-1 -Ulexite < 0.1 % 10.1 Methanol < % 67-56--11 67-56- 7727-54-0 Diammonium sulphate <0.1 % 107-21-1 Glycol Ethylene Glycal <0.1 % Alcohols, cit -15 -secondary, ethoxylated <0.1 68131-40-8 Propan-2-al <0.1 % 67-63-0 2-butoxyethanol <0.1 % 111-76-2 Ethoxylated C11 Alcohol <0.1 % 34398-01-1 Sodium hydroxide <0.1 % 1310-73-2 Vinylidene chloride/methylacrylate copolymer <0.01 % 25038-72-6 Sodium Tetraborate Decahydrate <0.01 % 1303-96-4 Ethoxylated Alcohol <0.01 % 68131-39-5 Poly(oxy-1,2-ethanediyl),a-h dro-w-hydrox -Ethane-1,2-diol, ethoxylated <0.01 % 25322-68-3 but-2-enedioic acid <0.01 % 110-17-8 Diatomaceous earth, calcined <0.01 % 91053-39-3 Undecanol <0.01 % 112-42-5 Non -crystalline silica (impurity) <0.001 % 7631-86-9 Magnesium silicate hydrate (talc) <0.001 % 14807-96-6 Magnesium nitrate <0.001 % 10377-60-3 5-chloro-2-methyl-2h-isothiazolol-3-one <0.001 % 26172-55-4 Magnesium chloride <0.001 % 7786-30-3 of (tetrafluoroethylene) <0.001 % 2-84-0 <0.001 05-87-0 Diutan gum <0.001 % Diutan Acetic acid, potassium salt <0.0001 % L595585-15-2 7-08-2 2 -meth I-2h-isothiazol-3-one <0.0001 % 2-20-4 Cristobalite <0.0001 % 64-46-1 Quartz, Crystalline silica < 0.0001 % 08-60-7 Acetic acid(impurity <0.0001 % -19-7 Total r •rAirA.n e, •Mix water is suppliedby the client. schlumherger has performed no analysis of the water anocannoe praameoereu.uvwn„r.,,,w2•••W•^-.------__-__.______ • The evaluation of attached document is performed based on the composition of the idennhed products to the extent that such Compositional information was known to GRC-Chemicals os of the date of the document wosproduced. Any new updates will not be reflected in this document Page 1 / 1 oma u..A F„ullmrn alnakn I lChaaermiS51a.. 20 AAC 25.283 (a)(12) (E) Maximum Anticipated Treating Pressure and Information Sufficient to Support a Determination that the Well is Appropriately Constructed for the Proposed Hydraulic Fracturing Program. The 4-% "production tubing will be tested to 4950 psi for 30 minutes and the 7" production casing will be tested to 3500 psi for 30 minutes prior to the fracture stimulation. The maximum surface differential pressure the tubing will be subjected to will be 4300 psi (7300 psi GORV maximum pressure setting - 3000 psi of pressure on the casing x tubing annulus). The calculated maximum treating pressure is 3,314 psi for the Kuparuk A sand and 5,279 psi for the Kuparuk C sand fracture stimulations. 20 AAC 25.283 (a)(12) (F) Designed Height And Length Of Each Proposed Fracture (i) the calculated measured depth and true vertical depth of the top of the fracture: Kuparuk A Sand: 11,005' MD / 7,176' TVD BKB Kuparuk C Sand: 11,005' MD / 7,176' TVD BKB a description of each method and assumption used to determine designed fracture height and length: The MP L-41 fracture stimulation was modeled using FracCADE program. Note — The TVD depths in FracCADE are BKB. scliumbepgep FraCCADE' STIMULATION PROPOSAL Operator Hilcorp Alaska Well MPL-41 Field Milne Point Formation Kuparuk A& C Well Location Milne Point County North Slope State Alaska Country United States Prepared for Almas Aitkulov Service Point Prudhoe Bay, AK Business Phone 1907 659 2434 Date Prepared 10-10-2018 FAX No. 1907 659 2538 Prepared by ScottLeahy Phone 907-330-4595 E -Mail Address SLeahy@slb.com Mark of Schlumberger Disclaimer Notice: This information is presented in goad faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based an calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown date and can be no more accurate than the model, the assumptions and such input data. The information presented Is Schlumberger's best estimate of the actual result that may be achieved and should he used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any condit ons whereby a neighboring well or walls might he affected by the treatment proposed herein it is the Operator's responsibilitvto nodfythe owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges mayvery depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is more be inferred. Schlumberger -Private Client Hilcorp Alaska Well MPL-41 Formation Kuparuk A & C District Prudhoe Bay, AK Country United States Section 1: Zone Data silomrger Formation Mechanical Properties Zone Name Top TO (ft) Zone Height (ft) Free Grad. (psi/ft) Insitu Stress (psi) Young's Modulus (psi) Poisson's Ratio Toughness (psl.inO.5) Shale 7064.2 112.1 0.824 5867 1.308E+6 0.35 2000 Kup C 7176.3 12.2 0.680 4884 1.847E+6 0.25 800 Kup B 7188.5 17.0 0.700 5038 1.733E+6 0.28 2000 Kup B 7205.5 18.0 0.717 5173 1.729E+6 0.32 2000 Kup B 7223.5 30.0 0.737 5335 1.729E+6 0.32 2000 Kup B 7253.5 23.4 0.754 5478 1.729E+6 0.32 2000 Kup A3 7276.9 17.9 0.650 4736 1.729E+6 0.25 2000 Kup A2 7294.8 28.4 0.670 4897 1.729E+6 0.28 2000 Kup Al 7323.2 25.0 0.710 5208 1.729E+6 0.32 2000 Miluveach 7348.2 100.0 0.820 6067 4.494E+6 0.35 1000 Formation Transmissibility Properties Zone Name Top TVD (ft) Net Height (ft) Perm (md) Porosity (%) Res. Pressure (psi) Shale 7064.2 1.0 0.001 1.0 2472 Kup C 7176.3 12.2 30.000 15.0 2507 Kup B 7188.5 12.0 1.000 10.0 2510 Kup B 7205.5 9.0 1.000 10.0 2525 Kup B 7223.5 15.0 1.000 10.0 2531 Kup B 7253.5 12.0 1.000 10.0 2534 Kup A3 7276.9 17.9 100.0 22.0 2539 Kup A2 7294.8 21.0 80.000 22.0 2546 Kup Al 7323.2 12.5 5.000 13.0 2555 Miluveach 7348.2 1.0 0.001 1 1.0 2575 Schlumberger -Private M Client Hilcorp Alaska Well MPL-41 Formation Kuparuk A & C District Prudhoe Bay, AK Country : United States SAIENPIOP Section 2: Propped Fracture Schedule- "A" Frac Pumping Schedule The following is the Pumping Schedule to achieve a propped fracture half-length (X,) of 309.6 ftwith an average conductivity (Krw) of 16136 md.ft. Please note thatthis pumping schedule is under -displaced by 7.0 bbl. Fluid Totals 36525 gal of YF140FIexD 7111 gal of WF130 Proppant Totals 152800 lb of CarboBond Lite 16/20 Pad Percentages %PAD Clean 24.6 Job Description 20.6 Step Pump Fluid Name Step Fluid Gel Prop. Prop. Name Rate Volume Conc. Type and Mesh Conc. (bbl/mini (gal) (lb/mgal) (PPA) PAD 25.0 YF140FIexD 4998 40.0 0.00 0.0 PPA 25.0 YF140FIexD 1050 40.0 0.00 PAD2 25.0 YF140FIexD 3990 40.0 0.00 1.0 PPA 25.0 VF740FI.xD 2087 40.0 CarboBond Lite 16/20 1.00 2.0 PPA 25.0 YF140FIexD 2076 40.0 CarboBond Lite 16/20 2.00 3.0 PPA 25.0 YF140FIexD 2914 40.0 CarboBond Lite 16/20 3.00 4.0 PPA 25.0 YF140FIexD 2906 40.0 CarboBond Lite 16/20 4.00 5.0 PPA 25.0 YF140FIexD 2388 40.0 CarboBond Lite 16/20 5.00 6.0 PPA 25.0 YF140FIexD 2433 40.0 CarboBond Lite 16/20 6.00 7.0 PPA 25.0 YF140FIexD 2824 40.0 CarboBond Lite 16/20 7.00 8.0 PPA 25.0 YF140FIexD 2790 40.0 CarboBond Lite 16/20 8.00 9.0 PPA 25.0 F!3 084 40.0 CarboBond Lite 16/20 9.00 10.0 PPA 25.0 YF140FIexD 2986 40.0 CarboBond Lite 16/20 10.00 Flush 25.0 1 WF130 7111 1 30.0 1 1 0.00 Please note thatthis pumping schedule is under -displaced by 7.0 bbl. Fluid Totals 36525 gal of YF140FIexD 7111 gal of WF130 Proppant Totals 152800 lb of CarboBond Lite 16/20 Pad Percentages %PAD Clean 24.6 %PAD Dirty 20.6 Schlumberger -Private Client Hilcorp Alaska Well MPL-41 Formation Kuparuk A & C District Prudhoe Bay, AK Country United States Schlumherger Schlumberger -Private Job Execution Step Name Step Fluid Volume (gal) Cum. Fluid Volume (gal) Step Slurry Volume (bbl) Cum. Slurry Volume (bbl) Step Prop (lb) Cum. Prop. (lb) Avg. Surface Pressure (psi) Step Time (min) Cum. Time (min) PAD 4998 4998 119.0 119.0 0 0 3192 4.8 4.8 0.0 PPA 1050 6048 25.0 144.0 0 0 3192 1.0 5.8 PAD2 3990 10038 95.0 239.0 0 0 3256 3.8 9.6 1.0 PPA 2087 12125 52.0 291.0 2087 2087 3308 2.1 11.6 2.0 PPA 2076 14201 54.0 345.0 4152 6239 3285 2.2 13.8 3.0 PPA 2914 17115 79.0 424.0 8741 14980 3189 3.2 17.0 4.0 PPA 2906 20021 82.0 506.0 11625 26605 3040 3.3 20.2 5.0 PPA 2388 22409 70.0 576.0 11938 38543 2947 2.8 23.0 6.0 PPA 2433 24842 74.0 650.0 14596 53139 2883 3.0 26.0 7.0 PPA 2824 27665 89.0 739.0 19765 72904 2794 3.6 29.6 8.0 PPA 2790 30455 91.0 830.0 22316 95221 27143.6 33.2 9.0 PPA 3084 33539 104.0 1 934.0 1 27755 122976 2688 4.2 37.4 10.0 PPA 2986 36525104.0 1038.0 29864 152839 2702 4.2 41.5 Flush 7111 43636 169.3 1207.3 0 152839 2855 6.8 48.3 Schlumberger -Private Client Hilcorp Alaska Well MPL-41 Formation Kuparuk A&C District Prudhoe Bay, AK Country United States Section 3: Propped Fracture Simulation Results- "A" Frac (1) ACL Fracture Profile and Proppant Concentration Plot FracCADE'MPL41 11111 Aa FxNrt PW.16 QM Pmewm Gncemrznun loIe z a f I FrzGurtR 11ni4s4an M0= A0. eift eI WGIM2-In 'Mark of Schlumberger (2) Treating Plot — settomMle Pressure o mmx oo-o A mnlz ad.oemnu ae nn mna 1] 1.I IbflQ 1 i f 110flR Et z51MIx x1W ]5391 � g-)IIOflp - � >3d IbIlR ILo— ..I IL,11 - X surface Pressure — Total lrj. Rab � EOJ SchIONPOer 0 10 20 30 40 50 00 70 fm 90 100 Trealmam T -a - min 5 Schlumberger -Private Client Hilcorp Alaska Well MPL-41 Formation Kuparuk A & C District Prudhoe Bay, AK Country United States Section 4: Propped Fracture Simulation- "A" Frac Schlumherger, The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fed are calculated based on perforated intervals with positive net heights. Initial Fracture Top TVD --- -------- .------------ 7276.9 ft Initial Fracture Bottom TVD ------------------- -7294.8 ft Propped Fracture Half -Length 309.6 ft EOJ Hyd Height at Well ----------- ------- ------ 183.1 ft Average Propped Width ---------- -_.-------_- 0.220 in Net Pressure--------------------------------------- 796 psi Efficiency ----------------------------------------- 0.517 Effective Conductivity --------------------------- , 25610 md.ft Effective Fed---------------------------- ----------.0.8 169.7 Max Surface Pressure --------------------------- 3314 psi Simulation Results by Fracture Segment From (ft) To (ft) Prop. Cone. at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Cone. (Ib/ft2) Frac. Gel Cone. (Ib/mgal) Fracture Conductivity (md.ft) 0.0 77.4 10.5 0.273 169.7 2.39 337.1 20705 77.4 154.8 7.1 0.256 148.5 2.29 381.7 18459 154.8 232.27.1 0.216 117.4 1.86 464.7 15740 232.2 309.6 5.3 0.144 86.2 1.24 754.8 1 9966 Proppant bridged at 305 ft after 83 bbl in step 10 Schlumberger -Private Client Hilcorp Alaska Well MPL-41 Formation Kuparuk A & C District Prudhoe Bay, AK Country United States salomrger Fracture Geometry Data Per Zone for Production Prediction Zone Name Top MD (ft) Top ND (ft) Gross Height Ift) Net Height Fracture Width (in) Fracture Length Ift) Fracture Conductivity (md.ft) Shale 10888.0 7064.2 112.1 1.0 0.012 68.6 859 Kup C 11007.3 7176.3 12.2 12.2 0.036 90.8 2714 Kup B 11020.3 7188.5 17.0 12.0 0.069 129.0 5101 Kup B 11038.4 7205.5 18.0 9.0 0.070 174.0 5227 Kup B 11057.6 7223.5 30.0 15.0 0.076 241.1 5664 Kup B 11089.5 7253.5 23.4 12.0 0.168 301.4 12256 Kup A3 11114. 4 7276.9 17.9 17.9 0.354 309.6 25610 Kup A2 11133.4 7294.8 28.4 21.0 0.341 309.6 24602 Kup Al 11163.7 7323.2 25.0 12.5 0.157 308.4 11350 Miluveach 11190.3 7348.2 100.0 1.0 0.034 154.1 2500 Schlumberger -Private Client Hilcorp Alaska Well MPL-41 Formation Kuparuk A & C District Prudhoe Bay, AK Country United States 3chlumhergcr Section 5: Propped Fracture Schedule- "C" Frac Pumping Schedule The following is the Pumping Schedule to achieve a propped fracture half-length (X,) of 334.7 ftwith an average conductivity (Krw) of 6598 md.ft. Please note thatthis pumping schedule is under -displaced by 7.0 bbl. Fluid Totals 40000 gal of YF130FIexD 6749 gal of WF120 Proppant Totals 136500 lb of CarboBond Lite 16/20 Pad Percentages % PAD Clean 30.0 %PAD Dirty 25.9 Job Execution Step Name Step Fluid Volume (gal) Job Description Step Slurry Volume (bbl) Cum. Slurry Volume (bbl) Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (gal) Gel Conc. (lb/mgal) Prop. Type and Mesh Prop. Conc. (PPA) PAD 30.0 YF130FIexD 12000 30.0 4970 0.00 0.5 PPA 30.0 YF130FIexD 1000 30.0 CarboBond Lite 16/20 0.50 1.0 PPA 30.0 YF130FIexD 2000 30.0 CarboBond Lite 16/20 1.00 2.0 PPA 30.0 YF130FIexD 4000 30.0 CarboBond Lite 16/20 2.00 3.0 PPA 30.0 YF130FIexD 3000 30.0 CarboBond Lite 16/20 3.00 4.0 PPA 30.0 YF130FIexD 4000 30.0 CarboBond Lite 16/20 4.00 5.0 PPA 30.0 YF130FIexD 3000 30.0 CarboBond Lite 16/20 5.00 6.0 PPA 30.0 YF130FIexD 3000 30.0 CarboBond Lite 16/20 6.00 7.0 PPA 30.0 YF130FIexD 2000 30.0 CarboBond Lite 16/20 7.00 8.0 PPA 30.0 YF130FIexD 2000 30.0 CarboBond Lite 16/20 8.00 9.0 PPA 30.0 YF130FIexD ?99932 CarboBond Lite 16/20 9.00 10.0 PPA 30.0 YF130FIexD 2000 30.0 CarboBond Lite 16/20 10.00 Flush 30.0 WF120 1 6749 20.0 0.00 Please note thatthis pumping schedule is under -displaced by 7.0 bbl. Fluid Totals 40000 gal of YF130FIexD 6749 gal of WF120 Proppant Totals 136500 lb of CarboBond Lite 16/20 Pad Percentages % PAD Clean 30.0 %PAD Dirty 25.9 Job Execution Step Name Step Fluid Volume (gal) Cum. Fluid Volume (gal) Step Slurry Volume (bbl) Cum. Slurry Volume (bbl) Step Prop (Ib) Cum. Prop. (lb) Avg. Surface Pressure (psi) Step Time (min) Cum. Time (min) PAD 12000 12000 285.7 285.7 0 0 4970 9.5 9.5 0.5 PPA 1000 13000 24.4 310.1 500 500 5002 0.8 10.3 1.0 PPA 2000 15000 49.8 359.9 2000 2500 5003 1.7 12.0 Schlumberger -Private Client Hilcorp Alaska Well MPL-41 Formation Kuparuk A & C District Prudhoe Bay, AK Country United States Schlumhopp Job Execution Step Name Step Fluid Volume (gal) Cum. Fluid Volume (gal) Step Slurry Volume (bbl) Cum. Slurry Volume (bbl) Step Prop (lb) Cum. Prop. (lb) Avg. Surface Pressure (psi) Step Time (min) Cum. Time (min) 2.0 PPA 4000 19000 104.1 463.9 8000 10500 4906 3.5 15.5 3.0 PPA 3000 22000 81.3 545.3 9000 19500 4780 2.7 18.2 4.0 PPA 4000 26000 112.9 658.2 16000 35500 4779 3.8 21.9 5.0 PPA 3000 29000 88.0 746.1 15000 50500 4800 2.9 24.9 6.0 PPA 3000 32000 91.3837.4 18000 68500 4844 3.0 27.9 7.0 PPA 2000 34000 63.0 900.4 14000 82500 4899 2.1 30.0 8.0 PPA 2000 36000 65.2 965.6 16000 98500 4969 2.2 32.2 9.0 PPA 2000 38000 67.4 1033.1 18000 116500 5066 2.2 34.4 10.0 PPA 2000 40000 69.7 1102.7 20000 136500 5201 2.3 36.8 Flush 6749 46749 160.7 1263.4 0 136500 4282 5.4 42.1 Schlumberger -Private Client Hilcorp Alaska Well MPL-41 Formation Kuparuk A & C District Prudhoe Bay, AK Country United States Section 6: Propped Fracture Simulation Results- "C" Frac (1) ACL Fracture Profile and Proppant Concentration Plot FracCADE' re�w A1w MO �3i 03018 PCL FMq— Pmlile and Pmppanl Conran ra1.1 1 FMaUM411nulandnuo $i.. 04 ACLLMdthatftllb M -In -Mark OSB hlumberger (2) Treating Plot — fiotomhoie Pressure — Sudaw Pressure Schlumhrger � oa-$alhmz o-0-a.$mm3 aa-oslbnu OS-txlbmx f 1.z ->s lbmx 151-0Ih,1Q � IB -2.I IMIx � x.1 -2a 1pmx � >x elbmz FnMre MYI1enpIF 4 Tula) le, RaM — PW Schlumberger 3000 90 00 5000 ]0 60 50 4000 40 30 3000 211 10 0 0 10 20 30 au �a w Trealmam Tme -min 10 Schlumberger -Private I i Client Hilcorp Alaska well MPL-41 Formation Kuparuk A & C District Prudhoe Bay, AK Country United States Section 7: Propped Fracture Simulation- "C" Frac Schlumherger The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-13 Vertical model. Effective Conductivity and Effective Fed are calculated based on perforated intervals with positive net heights. Initial Fracture Top TVD,--------- 7176.3 It Initial Fracture Bottom TO -------------------- 7188.5 ft Propped Fracture Half -Length -334.7 It EOJ Hyd Height at Well ---------------_- ------- 187.0 It Average Propped Width ----------- ------------ 0.130 in Net Pressure---------------------------------------- 531 psi Efficiency --------------------------------------------- 0.449 Effective Conductivity ---------------------------- 4649 md.ft Effective Fed---------------------------------------- 0.5 Max Surface Pressure ---------------------------5279 psi Simulation Results by Fracture Segment (ft) Fromk334)737 Prop. Cone. at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Cone. (lb/ft2) Frac. Gel Conc. (Ib/mgal) Fracture Conductivity (rnd.ft) 0.0 9.7 0.156 157.3 1.41 367.6 8105 83.7 9.8 0.148 173.5 1.35 370.3 7610 167.3 10.7 0.128 171.1 1.18 363.7 6489 251.0 9.7 1 0.092 168.9 0.90 410.9 4376 Execution completed Schlumberger -Private Client Hilcorp Alaska Well MPL-41 Formation Kuparuk A & C District Prudhoe Bay, AK Country United States Schlumhergcr, Fracture Geometry Data Per Zone for Production Prediction Zone Name Top Top Gross Net Fracture Fracture Fracture MD TO Height Height Width Length Conductivity Ift) Iftl Ift) (in) Iftl (md.ft) Shale 10888.0 7064.2 112.1 1.0 0.033 330.8 1673 Kup C 11007. 7176.3 12.2 12.2 0.093 334.7 4649 3 Kup B 11020.3 7188.5 17.0 12.0 0.129 334.7 6423 Kup B 11038.4 7205.5 18.0 9.0 0.099 334.7 4930 Kup B 11057.6 7223.5 30.0 15.0 0.054 334.7 2731 Kup B 11089.5 7253.5 23.4 12.0 0.088 334.7 4415 Kup A3 11114.4 7276.9 17.9 17.9 0.233 334.7 11729 Kup A2 11133.4 7294.8 28.4 21.0 0.236 334.6 11875 Kup Al 11163.7 7323.2 25.0 12.5 0.079 243.1 4009 Miluveach 11190.3 7348.2 1 100.0 1 1.0 0.006 111.0 318 12 Schlumberger -Private 20 AAC 25.283 (a)(13) Description of the Plan for Post -Fracture Wellbore Cleanup and Fluid Recovery through to Production Operations The well will be cleaned up through a portable separation system before turning the well over to Production. Initial returns will be taken to the permitted Milne Point G&I facility for disposal. HHilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Date: October 10, 2018 Subject: Changes to Approved Sundry Procedure for Well MP L-41 Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first calf' engineer. AOGCC written approval of the change is required before implementing the change. Step HAK Page Date Procedure Change Prepared B Initials HAK AOGCC Written Approved Approval Received B Initials Person and Date Approval: Prepared: Operations Manager Date Operations Engineer Date Coll Tubing Unit Diagram Fluid Flow Diagram FIII Clcnnout STANDARD WELL PROCEDURE IfilrorpAlaeka,LLC NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre -job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4 -gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 Coil Tubing Unit Fluid Flow Diagram Cleanout w/ Nitrogen Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Wednesday, October 24, 2018 10:41 AM To: 'Paul Chan' Cc: Bo York; Matthew Linder; Steven Wysocki - (C); Ed Hawker, Almas Aitkulov; Davies, Stephen F (DOA) (steve.davies@alaska.gov) Subject: RE: MP L-41 Perforating (PTD 218-104 / Sundry 318-466) Paul, You have verbal approval to perforate the Kuparuk A sand as proposed in the Frac sundry 318-466. ( Perf approx. 11,107-11,117') No other perforations are authorized until sundry approval. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete It, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226) or (Guv Schwartz@alaska.aovl. From: Paul Chan <pchan@hilcorp.com> Sent: Tuesday, October 23, 2018 4:02 PM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Cc: Bo York <byork@hilcorp.com>; Matthew Linder <mlinder@hilcorp.com>; Steven Wysocki - (C) <swysocki@hilcorp.com>; Ed Hawker <ehawker@ake-line.com>; Almas Aitkulov <aaitkulov@hilcorp.com> Subject: MP L-41 Perforating (PTD 218-104 / Sundry 318-466) Guy Permission requested to perforate ^'8' of the Kuparuk A sands in preparation for the fracture stimulation. Thanks Paul Chan Senior Operations Engineer Alaska North Slope Team Hilcorp Alaska LLC (907) 777 — 8333 (w) (907) 444 — 2881 (c) 20 AAC 25.283 Hydraulic Fracturing Application — Checklist MPU L-41 (PTD No. 218-104; Sundry No. 318-466) Paragraph 1 Sub -paragraph Section Complete? (a) Application for A(o)(1) Affidavit f.._..1_. ----.._, (a)(2) Plat (o)(2)(A) Well location (a)(2)(8) Each water well withii (a)(2)(C) Identify all well types i mile I (a)(3) Freshwater aquifers: gec name, measured and true verti AOGCC Page 1 October 24, 2018 Provided with application. SFD 10/22/2018 SFD Provided with application. 10/22/2018 Provided on map accompanying application. Well lies in Sections 8 and 5, T33N, R10E, UM and in Section 32, T14N, SFD R10E, UM. 10/22/2018 Provided with application: No wells are used for drinking water purposes are known to lie within %: mile of the surface location of MPU L-41. According to the Water Estate map available through DNR's Alaska Mapper Mile application (accessed online October 22, 2018), there are SFD subsurface water rights within about 0.9 miles of the 10/22/2018 surface location of, and fracturing interval within, MU L-41. These rights are associated with water wells drilled to 3300' to 5000' measured depth at Hilcorp's Milne Point F Pad. There are no other water rights within 2 miles of MPU L-41. There are currently 45 oil development -related wells that lie within %: mile of the MPU L-41 path. (See the list of wells vithin': accompanying the application.) There are three wells and SFD one plugged -back well bore within''/: mile of the planned 10/23/2018 fracturing interval. (MPU L-05, MPU L-11, MPU L-14, and MPU L-41PB1; see map, below. None. Permafrost here is over 1,600' thick. Beneath SFD logical permafrost lie sand and gravel aquifers assigned to the 10/22/2018 ;al depth Tertiary to Late Cretaceous -aged Sagavanirktok Formation. Portions of those aquifers in the MPU C -Pad area to the AOGCC Page 1 October 24, 2018 Paragraph 20 AAC 25.283 Hydraulic Fracturing Application — Checklist MPU L-41 (PTD No. 218-104; Sundry No. 318-466) Sub -Paragraph Section Complete? AOGCC Page 2 October 24, 2018 east of L -Pad contain native formation waters reported to have total dissolved solids content of less than 10,000 mg/I, but more than 3,000 mg/I. However, by letter dated SFD July 2, 1987, US EPA Region 10 advises that the aquifers 10/22/2018 occurring beneath the Milne Point Unit qualify for exemption for Class II activities, an exemption that is considered to be a minor exemption and a non -substantial program revision not requiring notice in the Federal Register. (See AEO 2, Findings 3 and 4.) (a)(4) Baseline water sampling plan None required. SFD 10/22/2018 (a)(SJ Casing and cementing information Provided with application. See the attached schematic for COW As -Built casing and cementing information. 10/24/2018 The 9 5/8" surface casing was cemented in 2 stages. First stage had some losses while pumping but casing was rotated and reciprocated. Only 75% returns for 1" stage. Opening the ES cementer at 2508 ft, green cement was circulated to surface of 85.6 bbl indicating cement from TO 7366 ft to 2508 ft. 2"d stage cementing recovered 155 bbl (a)(6) Casing and cementing operation to surface bumping plug and floats held., no losses. The 7" COW assessment production casing CBL (cement bond log) quality was 10/24/2018 indicative of TOC at 9530 ft. The 7" production casing cementing was aided by the 2 stage cementing with ES cementer at 10,439 ft. Even though 100% losses were observed while cementing, log shows competent cement throughout and lift pressures of 590 psi and 300 psi I indicate good cement placement. (0)(6)(A) Casing cemented below No freshwater aquifers present (see Section (a)(3), above). lowermost freshwater aquifer and Surface casing set at 7,366' MD (4,700' TVD, -4,650' TVDSS) SFD conforms to 20 AAC25,030 and cemented to surface. 10/23/2018 AOGCC Page 2 October 24, 2018 Paragraph 20 AAC 25.283 Hydraulic Fracturing Application — Checklist MPU L-41 (PTD No. 218-104; Sundry No. 318-466) Sub -Paragraph �— Section Complete? (a)(6)( B) Each hydrocarbon zone is isolated (a)(7) Pressure test: information and pressure -test plans for casing and tubing installed in well (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPS, treating head Yes. Surface casing is set below the hydrocarbon -bearing Ugnu and Schrader Bluff Sands (in descending stratigraphic order) and cemented to surface. SFD 10/23/2018 The production hole is cased with 7" pipe that was cemented in two stages. The estimated top of cement is at 9,530' MD (about -5,820' TVDSS), which lies near the center of the 2,000 -foot thick Colville mudstone and SFD siltstone interval, about 1,300 vertical feet above the top of 10/23/2018 the hydrocarbon -bearing Kuparuk C Sand. Provided with application. 9 5/8" to 2500 psi rig casing test, CDW 3500 psi 7" casing tested. Plan 4.5" tubing test of 4950 psi 10/24/2018 and 3500 psi MITIA. Provided with application. 15K psi wellhead/treating head, pump trips at 6400 and 6800 psi and GORV at 7300 psi CDW 10/24/2018 1 nlanc- Upper confining zones: approximately 410' of shale and (o)(9)(A) Fracturing and confining zones: siltstone assigned to the HRZ, Pebble, Kalubik, and Kuparuk lithologic description for each zone D intervals (in descending stratigraphic order). Fracture gradient expected to be about 0.75 to 0.82 psi/ft. (a)(9)(B) Geological name of each zone Fracturing Zone: Kuparuk C, B, and A intervals from 10,995' (o)(9)(C) and (o)(9)(D) Measured and true to 11,202' MD, a true vertical thickness of about 200'. SFD vertical depths Fracture gradient expected to be about 0.65 to 0.68 psi/ft. 10/23/2018 (a)(9)(E) Fracture pressure for each zone Lower confining zones: Miluveach Shale which is many hundreds of feet thick that overlies many additional hundreds of feet of Kingak Shale. Fracture gradient expected to be about 0.80 to 0.82 psi/ft. (a)(10) Location, orientation, reporton There are three wells and one plugged -back well bore r CDW mechanical condition of each well within %: mile of the planned fracturing interval. (MPU L-05, 10/24/2018 AOGCC Page 3 October 24, 2018 Paragraph 20 AAC 25.283 Hydraulic Fracturing Application — Checklist MPU L-41 (PTD No. 218-104; Sundry No. 318-466) Sub -Paragraph Section Complet01 AOGCC Page 4 October 24, 2018 MPU L-11, MPU L-14, and MPU L -41P81); see map, below. The 4 wells are identified and cementing and TOC estimates are provided. (a)(10 cont) Sufficient information to determine wells will not interfere with The 4 wells are identified and cementing and TOC CDW containment within.% mile estimates are provided. 10/24/2018 (a)(11) Faults and fractures, Location, Operator -provided structure map 'indicates two faults lie orientation near the fracturing interval: one fault that lies 440' to the east, and a second fault that lies about 700' to the north. (a)(Il) Faults and fractures, Sufficient The horizontal principal stress direction is SE trending, and SFD information to determine no interference the modeled half-length of the induced fracture is about 10/23/2018 with containment within M mile 335', so it is unlikely that the nearby faults will interfere _ with containment of the fracturing fluids. (a)(12) Proposed program for fracturing Provided with application. CDW operation 10/24/2018 Provided with application. 129,865 gal total dirty vol. CDW (a)(11)(A) Estimated volume excluding freeze protect, 290K pound proppant — 2 10/24/2018 (aJ(11j(8)Additives: names, purposes, separate stages using plug and pert coil tubing cleanouts. Provided with application. CDW concentrations 10/24/2018 C ( 12 )( )Chemical name and CAS number Provided with application. No proprietary products CDW of each each previously provided to AOGCC under confidentiality 10/24/2018 provisions. Provided with application. Inert substances, weight or CDW volume of each 10/24/2018 Maximum treating pressure with Max. 3314 psi estimated treating pressure Kuparuk A and CDW supporting supporting info to determine 5279 psi for shallower Kuparuk C. Max pressure is 7300 psi 10/24/2018 appropriateness for program to (Pump shutdown). With 3000 psi back pressure on IA, max tubing differential should be 4300 psi. AOGCC Page 4 October 24, 2018 20 AAC 25.283 Hydraulic Fracturing Application — Checklist MPU L-41 (PTD No. 218-104; Sundry No. 318-466) Paragraph Sub -Paragraph (b)Testing of casing or intermediate casing _ (c) Fracturing string (d) Pressure relief valve (e) Confinement (o)(12)(F) Fractures — height, length, MD and TVD to top, description of fracturing model (a)(13) Proposed program for post - fracturing well cleanup and fluid re Section Complete? Provided with revised supporting documentation received October 16, 2018. The anticipated half -lengths of the induced fractures range from 310' in the Kuparuk A Sands to 335' in the Kuparuk C Sand according to the Operator's computer simulation. Computer simulation indicates the SFD 10/23/2018 anticipated heights of the induced fractures are about 185' in each of the Kuparuk Sand intervals, so the induced fracture within the Kuparuk C Sand will likely penetrate nearly through the overlying 175 -foot thick Kuparuk D Shale, but not through the additional 230' of shale assigned to the Kalubik Shale, Pebble Shale, and HRZ Shale intervals (in ascending stratigraphic order). The Kuparuk A SFD 10/23/2018 Sands fracture may penetrate into, but certainly not through, the underlying Miluveach Shale, which is many hundreds of feet thick in this area. Provided with application. Hilcorp has Class I disposal at CDW Milne Point G&1. 10/24/2018 CDW Tested>110% of max anticipated pressure 3000 psi back pressure, plan to test to 3500 psi 10/24/2018 (c)(1) Packer >200' below roc of production or intermediate casin, (c)(2) Tested >210% of max anticipated pressure differential Line pressure <= test pressure, remotely controlled shut-in device Frac fluids confined to approved formations Est TOC 9530 ft, packer set 10760 ft (1230 ft). , ^ CDW 4.5" tubing to be pressure tested to 4950 psi. 3000 psi backpressure planned. Max differential (GORV trip) of 4300 psi. 15K psi frac treating head, pump knock out set 6800 and 6400 psi, GORV 7300 psi plans. IA PRV set as 3500 psi. line test pressure of 8000 psi. Provided with application. CDW 10/24/2018 CDW 10/24/2018 CDW AOGCC Page 5 October 24, 2018 20 AAC 25.283 Hydraulic Fracturing Application — Checklist MPU L-41 (PTD No. 218-104; Sundry No. 318-466) Paragraph Sub -Paragraph Section Complete? W Surface casing Monitored with gauge and pressure relief CDW pressures device IA PRV set at 3500 psi. Surface annulus open. 10/24/2018 (g) Annulus pressure monitoring & 500 psi criteria notification (9)(1) Notify AOGCC within 14 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting 0)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post -frac water _ sampling plan (k) Confidential Clearly marked and specific facts information supporting nondisclosure (1) Variances Modifications of deadlines, requests for requested variances or waivers I.0 Pidn Ior Pwt rracture water wen anaiysis. commission may require this depending on pertormance of the fracturing operation. AOGCC Page 6 October 24, 2018 Paragraph 20 AAC 25.283 Hydraulic Fracturing Application — Checklist MPU L-41 (PTD No. 218-104; Sundry No. 318-466) Sub -Paragraph Section Complete? Cementing Information for 7" Intermediate Liner and Swell Packer information for 4-1/2" Production Liner Intermediate Liner — 7" Production Liner — 4-1/2" (See attached schematic with swell packer locations below) AOGCC Page 7 October 24, 2018 20 AAC 25.283 Hydraulic Fracturing Application — Checklist MPU L-41 (PTD No. 218-104; Sundry No. 318-466) Paragraph Sub -Paragraph Section Complete? KEY Well Paths 00—'\ Cross -Section Path ' Frac Intervals - Proposed =-87A F-87 d F-33 F-73 F-69 L-24 H L-04 L-13 L-43 F-58 1 08 \ F-77 F-yyyyyy���ggqqqqA F -06 L-09 j F-02 _.l L-03 NIP -09A L-02 F-21 F-99 L-02AL L -M L-14 L-29 L-41 L-55 L-41 L -16A L-11 5 L-07 OL -06 C-17 L-10 a C-36 I n1A 0.5 I AOGCC Page 8 October 24, 2018 20 AAC 25.283 Hydraulic Fracturing Application — Checklist MPU L-41 (PTD No. 218-104; Sundry No. 318-466) Paragraph Sub -Paragraph Section Complete West 2032240 MPU KR L-43 0.6 miles 2181040 MPU L-41 0.9 miles 1900100 East MINE PT UNIT KR L-06 i Colville siltstone Iwo and mudstone - HRZ Shale Pebble Shale Kalubik Shale Upper .. Confining Layers Kuparuk D Shale °04 -- Fra ring Kuparuk C Sand Kuparuk B Inte al Kuparuk A Sands Lower Vertical scale for cross-section is in Confining Miluveach Shale units of True Vertical Feet Subsea Layers NUukA_ Page 9 October 24, 2018 MP L-41 Completion Program Run and cement 7" production casing. Set 7" packoff and test. Freeze protect 7" x 9-5/8" annulus LD 5" DP in mouse hole. MU 6-1/8" bit. PU and RIH on 4" DP. • Ensure Cement has reached 500 psi compressive strength prior to clean out run. Drill out 7" ES cementer to the baffle adapter (PBTD). Circulate wellbore with clean 8.45 ppg seawater at max rate, rotate and reciprocate pipe (the wellbore will be hydraulically isolated from the reservoir with cemented casing) POOH. Close blind rams and PT 7" casing to 3500 psi f/ 30 charted minutes. RIH with bit/scraper/junk baskets on 4" DP to PBTD. Circulate wellbore with clean 8.8 ppg KCI/NaCl at max rate with rotation and reciprocation • KWF Est —8.8 ppg (2% KCI/NaCl) RU E-line/line wiper & run CBL/VDL from PBTD to above estimated TOC. CBL/VDL will be across Kuparuk formation. RD E -line PU and RIH with 4-1/2" 12.6#/ft TXP-SR L-80 tubing / Frac String as follows: • 4-1/2" WLEG @"'10,850' MD • 2 joints of 4-1/2" 12.6#/ft TXP-SR L-80 • 4-1/2" XN nipple with RHC ball catcher • 7" x 4-1/2" HAL AHC Packer @"'10,750' MD. Final set depth to be confirmed after running CBL/VDL • 4-1/2" 12.6#/ft TXP-SR L-80 tubing • 4-1/2" Tubing Hanger Land tubing hanger. RILDS. Test tubing hanger, 500 psi low/ 5000 psi high Install BPV ND BOPE (the wellbore will be hydraulically isolated from the reservoir with cemented and pressure tested casing) NU Tree & pressure test Freeze protect IA and tubing Drop Ball and Rod and set packer with 2,500 psi. Test IA to 3500 psi for 30 charted minutes while monitoring tubing to identify any packer leaks Test tubing to 4,950 psi for 30 charted minutes Bleed off tubing pressure to 2,500 psi Bleed off IA to zero. Bleed off tubing pressure to zero. THE STATE °fALASKA GOVERNOR BILL WALKER Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk River Pool, MPU L-41 Permit to Drill Number: 218-104 Sundry Number: 318-433 Dear Mr. Myers: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. DATED this � day of October, 2018. Sincerely,, n '^ SIVA"' ' ONV v v �N�6 i Cathy P. Foerster Commissioner RBDMSJOC1 0 4.1018 STATE OF ALASKA SEP 2 7 2018 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOA C 20 AAc 91 1) ❑ Fracture Stimulate ❑ Repair Well 1-1 Operations shutdown El1. Type of Request: Abandon 10 lug Perforations Change Approved Program Q Suspend ❑ o Perforate El Other Stimulate ❑ Pull Tubing 9 ,Yv`I Plug for Redrill Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing Other: ❑ 4. Current Well Class: 5. Permit to Drill Number: Operator Name: Development Q • 218-104 - Exploratory ❑ Hilcorp Alaska, LLC H ❑ Service ❑ 6. API Number: 3. Address: Stratigraphic 50-029-23611-00-00 . 3800 Cenetrpoint Drive, Suite 1400 Anchorage, AK 99503 8. Well Name and Number: 7. If perforating: What Regulation or Conservation Order governs well spacing in this pool? CO 432D MPU L-41 ' Will planned perforations require a spacing exception? Yes ❑ No Q 9. Property Designation (Lease Number): 10. Field/Pool(s): Milne Point Field / Kuparuk Oil Pool ADL0255091ADL355017 ' 11 PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth ND (ft): Effective Depth MD: Effective Depth ND: MPSP (psi): Plugs (MD): Junk (MD): N/A 11,330' 7,480' 9,590' 5,914' 2704 9,590' Burst Collapse Casing Length Size MD ND Structural 80 Conductor 80' 20" 80' 3090 4,700' 5750 Surface 9-5/8" 7366' 6,878' 7240 5410 Intermediate 10,689' ?" 10,689' 6,475' 8430 7500 Production 831' 41/2" 10,260' Liner Perforation Depth MD (fl): Perforation Depth ND (ft Tubing Size: Tubing 9 Grade: Tubing MD (ft): N/A N/A N/A N/A N/A Packers and SSSV MD (ft) and ND (fl): N/A Packers and SSSV Type: N/A 12. Attachments: Proposal Summary 91 Wellbore schematic Q 13. Well Class after proposed work: ❑ Development ❑� Service ❑ Exploratory Detailed Operations Program ❑ BOP Sketch ElP ry ❑ Stratigraphic 15. Well Status after proposed work: 14. Estimated Date for 9/27/2018 OIL Q - WINJ [IWDSPL El Suspended ❑ Commencing Operations: 9/25/2018 GAS ❑ WAC' 1116. Verbal Approval: Yes - Email Date: Op Shutdown 11 Abandoned El El Commission Representative: Guy Schwartz GINJ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Monty Myers Contact Name: Joe Engel Authorized Name: Contact Email: 6D 61 hIICOr .COrn Authorized Title: Drilling Manager MOMY MYFR$ Contact Phone: 777-8395 / Date: ^Z7^1g Authorized Signature: COMMISSION USE ONLY Sundry Number: Conditions of approval: Notify Commission so that a representative may witness Sunj✓`t XU 111 Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance Cl Other: )t✓ 44 00 L) 0 5 Z �[7 / /�� �I lam/ rJ /'47 1 MIT Req'd? Yes ❑ No r_1- �f-7 / vw J Post Initial Injection Yes No Subsequent Form Required: Spacing Exception Required? ❑ APPROVED BY 1Q � Date: COMMISSIONER THE COMMISSION Approved by: p (� 1,,1 ,��[Jnt.�s'/ ,�rfr C' ed p AI I'v 44 ��llv OV�.�J'_� ubsii orm and/ S L'�i.1vkA14120 Approved a plical n i 2 the date of approval. Attachments in Duplicate Orig. KB Elev.: 33.7 / GL Elev.: 16.5' M 95/8' Pumped 22.5 bbls curt in 7'. Tag @9,59(y Y' ES Cementer @2,508' 4-1/2'a Shoe @ .,,�,f1 11,091'..... TD =11,330• (MD) / TD = 7,4W (TVD) PBTD =±11,005' (MD) / PB1D=±7,203' (TVD) Milne Point Unit Well: MPL-41 Current Schematic Last Completed: TBD PTD: 218-104 TREE & WELLHEAD Tree 1 TBD Wellhead I TBD OPEN HOLE / CEMENT DETAIL Conductor Driven Unable to Stg1L-720sx T-400sx/Stg2L-300sx T-270sx 9-7/8"x8-1/2" L-180sx -'meds passing L-130sx 164/A538/Weld PT on 4-1/2' Surface 80' :•�1 Liner. Liner Surface 40/L-80/TXP damaged. Surface 7,366' ,,.• Intermediate 26/L-80/TXP '•4 •e� Surface 10,689' 4-1/2" Liner 12.6 / L-80 / TXP 3.920 ±10,260' ±11,091' ..t - 4-1/2'a Shoe @ .,,�,f1 11,091'..... TD =11,330• (MD) / TD = 7,4W (TVD) PBTD =±11,005' (MD) / PB1D=±7,203' (TVD) Milne Point Unit Well: MPL-41 Current Schematic Last Completed: TBD PTD: 218-104 TREE & WELLHEAD Tree 1 TBD Wellhead I TBD OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" Stg1L-720sx T-400sx/Stg2L-300sx T-270sx 9-7/8"x8-1/2" L-180sx 6-1/8" L-130sx CASING DETAIL Size Type Wt/Grade/Conn ID Top Btnn BPF 20" Conductor 164/A538/Weld N/A Surface 80' 9-5/8" Surface 40/L-80/TXP 8.835 Surface 7,366' 7" Intermediate 26/L-80/TXP 6.276 Surface 10,689' 4-1/2" Liner 12.6 / L-80 / TXP 3.920 ±10,260' ±11,091' J TUBING DETAIL WELL INCLINATION DETAIL JEWELRY DETAIL No. Top MD Item ID 1 ±10,260' 4-1/2" x 7" Liner Top Packer (Potentially damaged) GENERAL WELL INFO API: 50-029-23611-00-00 Completion Date: TBD Edited By: CJD 8-9-2018 K Hilcorp Alaska, LLC Orig. KB Elev.: 33.7 / GL Elev.: 16.5' Cut & Pull 7" @7,767 NID Proposed PB Schematic FS Cementer @2,508' Our, a Shce@'',. �..1 ............... .. TD =11,330' (MD) / TD= 7,480' (TND) PBTD =±11,005 (MD) / PBTD=±7,203' (TVD) TREE & WELLHEAD Tree TBD Wellhead I TBD Milne Point Unit Well: MPL-41 Last Completed: TBD PTD: 218-104 OPEN HOLE / CEMENT DETAII Conductor Driven 12-1/4" 1 Stg1 L-720sx T-400sx/Stg2L-300sx T-270sx 9-7/8"x8-1/2" L-180 sx 6-1/8" I L-130 Sx CASING DETAIL LSize Type Wt/Grade/Conn ID Top Btm BPF 20" Conductor 164/A53B/Weld N/A Surface 80' 9-5/8" Surface 40/L-80/TXP I 8.835 I Surface 1 7,366' 7" Intermediate 26/L-80/TXP 1 6.276 7,767' 10,689' 4-1/2" Liner 12.6/L-80/TXP 1 3.920 1 ±10,260' ±11,091' TUBING DETAIL WELL INCLINATION DETAIL GENERAL WELL INFO mp-029-23611-0 Col Completion Date: TED Edited By: GD 8-9-2018 K Hit cura Alaska. LLC Orig. KB Elev.: 33.7 / GL Elev.: 16.5 20" 9 5/9' TOC@*10,503' ES Cementer @2,508' Milne Point Unit Well: MPL-41 Proposed Schematic Last Completed: TBD PTD: 218-104 TREE & WELLHEAD Tree TBD Wellhead TBD OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" Stg1L-720sx T-400sx/Stg2L-300sx T-270sx 9-7/8"x8-1/2" Proposed L-48.6 bbls 20" Contingency Stg 2 L-33 bbls CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm BPF 20" Conductor 164 / A53B / Weld N/A Surface 80' 9-5/8" Surface40/L-80/TXP 8.835 Surface 7,366' 7" Intermediate 26/L-80/TXP 6.276 Surface 11,242' ES Crntr @ ±10,450' MD Contingency 7' TD =11,247 (MD) / TD - 7,400' (TVD) PBM =±11,150' (MD) / PBTD-±7,320' (TVD) TUBING DETAIL WELL INCLINATION DETAIL JEWELRY DETAIL GENERAL WELL INFO API: 50-029-23611-00- ji Completion Date: TBD Edited By: CID 9-27-2018 U Ililm p Alp kp, LLC. HAK MPU L-41 Re -drill Outline -9.27.2018 Purpose: Due to failure of the running tool to release from the liner hanger, the liner top was pulled — 300' up from planned setting depth and the integrity of the 4.5" liner was compromised, L-41 will be re - drilled from the surface shoe depth of 7,367' MD. An 8.5" x 9.875" hole section will be drilled and 7" ran to TD, as no trapped injection pressure was found during the original drill. Plug Operations: • Pump 22.5 bbl 15.8 Class G Cement at liner top, 10,260' MD • Tag Cement Plug and PT t/ 2000psi ✓ • Set 7" CIBP at 7,833' MD o PT CIBP 2000psi • Cut 7" Casing at 7,767' MD o Baker Multi -string cutter • Pull & LD 7" Casing Pump 15.8 ppg Class G KOP �I• � .- W o 59.4 bbl slo�_ o Planned top of KOP: 7,267' MD Re -drill Operations: /_O,„ gay I • MU 8.5" Motor BHA • Kick off well • Perform FIT to 12.5 ppg EMW • MU 8-1/2" x 9-7/8" RSS BHA o Ensure —15' collar between UR & Integral Blade Stabilizer (Ex: L-41 BHA #3) o X2 Non Ported Plunger Floats before UR o X1 Non Ported Flapper Float After UR o Bit TFA: x6 13s • Drill 8-1/2" x 9-7/8" Hole To TO Below Kuparuk Al o 9.5ppg MW o Maintain 11.3 EMW CBHP (Colville broke down at 11.5 on original drill) • CBU x 5 • Perform Wiper Trip above HRZ o Offsetting swab with MPD • Increase MW t/ 10.5 ppg • POOH o Offsetting swab with MPD • CBU at 9-5/8" shoe • POOH • LD BHA • RU & Run 7" TXP 26# L-80 Casing • Cement 7" Casing o TOC: 500' MD above Kup C, ±10,503' MD o Stage tool will be ran to ensure sufficient cement coverage (@±10,450' MD) H Hil-m AI.Au, LLC o Base plan is to pump 48.6 bbls of 15.8 class G cement, if this is insufficient Hilcorp will proceed to pump an additional 33 bbls through the ES Cementer to ensure proper coverage of the Kuparuk C. • Run 4.5" tubing string as per approved plan Hilcorp Alaska, LLC Milne Point M Pt L Pad Rig: MPU L-41 MPU L-41 Plan: MPU L-41 wp12 Standard Proposal Report 27 September, 2018 HALLIBURTON Sperry Drilling Services 1-IALLIB e1P®rry Drilling Project: Milne Point Site: M Pt L Pad Weil: Rig: MPU L-41 Wellbore: MPU L-41 Design: MPU L-41 wp12 Hilcorp Alaska, LLC Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Closest Approach 3D Error Sutlers: Elliptical Conic Waming Method: Error Ratio REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well Rig: MPU L41, True North Vertical (TVD) Reference: MPU L41 Actual ® 50.20usR Measured Depth Reference: MPU L41 Actual Q 50.20us0 Calculation Method: Minimum Curvature CASING DETAILS WELL DETAILS: Rig: MPU L41 DDI = 6.283 ND NDSS MD Size Name Ground Level: 16.50 7400.20 7350.00 11241.84 7 7"x81/2" +N/ -S +EAW Narthing Fasting Letiffude Longitude 0.00 0.00 6031767.05 544744 45 70° 29' 51.572 N 149° 38' 2.738 W FORMATION TOP DETAILS SURVEY PROGRAM TVDPath TVDssPalh MDPath Formation 6745.26 SECTION DETAILS 10544.86 Sec MD Inc Azi TVD +N/ -S +E/ -W Dleg TFace VSect Target Annotation 1 7470.00 59.68 14.97 4751.22 4896.08 1406.87 0.00 0.00 5093.93 KOP: Start Dir3°/100': 7470'MD, 4751.22'TVD: 90°RTTF 2 7650.00 59.83 21.22 4841.94 5043.78 1455.15 3.00 90.00 5249.27 7323.18 3 7759.59 58.52 17.71 4898.11 5132.49 1486.52 3.00 -114.39 5343.24 End Dir : 7759.59' MD, 4898.11' TVD 4 9050.79 58.52 17.71 5572.33 6181.49 1821.51 0.00 0.00 6444.23 Start Dir 3°/100':9050.79' MD, 5572.33'ND 5 10334.88 20.00 18.00 6547.94 6940.77 2065.19 3.00 179.84 7241.49 End Dir : 10334.88' MD, 6547.94' TVD 611109.88 20.00 18.00 7276.20 7192.86 2147.10 0.00 0.00 7506.48 MPL41 Tgtl wP12 711241.84 20.00 18.00 7400.20 7235.78 2161.04 0.00 0.00 7551.60 Total Depth : 11241.84' MD, 7400.2' ND CASING DETAILS WELL DETAILS: Rig: MPU L41 DDI = 6.283 ND NDSS MD Size Name Ground Level: 16.50 7400.20 7350.00 11241.84 7 7"x81/2" +N/ -S +EAW Narthing Fasting Letiffude Longitude 0.00 0.00 6031767.05 544744 45 70° 29' 51.572 N 149° 38' 2.738 W 45501 4875 52011 c 5850 N (D -Z 6175 m m C 6500 H .°1. 7800 FORMATION TOP DETAILS SURVEY PROGRAM TVDPath TVDssPalh MDPath Formation 6745.26 6695.06 10544.86 HR2 6807.39 6757.19 10810.98 KLB 6839.90 6789.70 10845.58 KLGM 7002.82 6952.62 10818.95 KUP 7176.32 7126.12 11003.59 _0 KUP C 718853 7138.33 11016.58 KUP 67 7276.92 7226.72 11110.64 KUP A3 7294.84 7244.84 11129.71 KUP A2 7323.18 7272.98 11159.87 KUP Al 45501 4875 52011 c 5850 N (D -Z 6175 m m C 6500 H .°1. 7800 Oo ^o KOP :Start Dir 3°/100' : 7470' MD, 4751.22'ND : 90° RT TF 0 End Dir : 7759.59' MD, 4898.11' ND 0 9 518" 0 0 0 00o yoo Start Dir 3-1100': 9050.79'MD, 5572.33'ND 0 OhOO OZZ a 00 mo hoo 9 ho0 9 AOGOD End Dir : 10334.88' MD, 6547.94' ND Start ESP Tangent 105p0 -- End ESP Tangent e� Total Depth: 11241.84' MD, 7400.2' ND »3 MPU L-41 wp12 MPU L-41PB1 7" x 8 1/2" 8125 r 4225 4550 4875 5200 5525 5850 6175 6500 6825 7150 7475 7800 8125 8450 8775 9100 Vertical Section at 16.63° (650 usft/in) SURVEY PROGRAM Dale: 2018-09-26T000000 Validated: Yes Vensicn: Depth From Depth To Survey/Pian Tool 100.00 817.00 MPU L41 Gym (MPU 1-41PB1) 2_Gym-NS-GC_Drill caller 883.91 7333.45 MPU L4t MWD+IFR2+MS+sag( MPU L41PBlI 2MWD+IFR2+MS+Sag 7363.62 7363.62 MPU L41 MWD_Interp Azi+Sag(MPU L41 PT) 2MWD InteMAa+Sag 7457.99 7470.00 MPUL41 MWD+IFR2+MS+sag(2)(MPUL41PB1) 2_MWDaIFR2+MS+Sag 7470.00 11241.84 MPU L41 wp12 (MPU 141) 2_MWD+IFR2+MS+Sag Oo ^o KOP :Start Dir 3°/100' : 7470' MD, 4751.22'ND : 90° RT TF 0 End Dir : 7759.59' MD, 4898.11' ND 0 9 518" 0 0 0 00o yoo Start Dir 3-1100': 9050.79'MD, 5572.33'ND 0 OhOO OZZ a 00 mo hoo 9 ho0 9 AOGOD End Dir : 10334.88' MD, 6547.94' ND Start ESP Tangent 105p0 -- End ESP Tangent e� Total Depth: 11241.84' MD, 7400.2' ND »3 MPU L-41 wp12 MPU L-41PB1 7" x 8 1/2" 8125 r 4225 4550 4875 5200 5525 5850 6175 6500 6825 7150 7475 7800 8125 8450 8775 9100 Vertical Section at 16.63° (650 usft/in) HALLIBURTON Project: Milne Point 6Peeev Drilling Site: M Pt L Pad 1Ato11- Rin KAOI I I -Al WELL DETAILS: Rig: MPU I I Ground Level: +W -s +EI -W Nandan, Eying 0.00 0.00 6(131767.05 544744.45 16.50 latitude longitude 7129' 51.572 N 149` 38'2.738 W REFERENCE INFORMATION CoaNinate (NIE) Reference: Well Venlwl 7rVD) Refete.: MPU Measured Depth Reference: MPU Calculation MetM1o1 Minimum Rig: MPU 111. Tme LGM L<l Actuat ® 50.20uat L41 AAml @ 50 20use CurveWre -250 0 250 500. 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 west -)/Hast(+) (500 us8/in) HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: Rig: MPU L-41 Wellbore: MPU L-41 Design: MPU L-41 wp12 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Rig: MPU L-41 TVD Reference: MPU L-41 Actual @ 50.20usft MD Reference: MPU L-41 Actual @ 50.20usft North Reference: True Survey Calculation Method: Minimum Curvature 'roject Milne Point, ACT, MILNE POINT lap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level leo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point lap Zone: Alaska Zone 04 Using geodetic scale factor Site M Pt L Pad, TR -13-10 Site Position: Northing: From: Map Easting: Position Uncertainty: 0.00 usft Slot Radius: 6,029,799.28usft Latitude: 544,529.55usft Longitude: 0" Grid Convergence: 70° 29'32.230 N 149° 38'9.412 W 0.34 ° Well Rig: MPU L-41, Unused BP Conductor - Possible Kuparuk Slot Well Position +NIS 0.00 usft Northing: 6,031,767.05 usfl Latitude: 70' 29'51.572 N +E/ -W 0.00 usft Easting: 544,744.45 usfl Longitude: 149° 38'2.738 W Position Uncertainty 0.00 usft Wellhead Elevation: 16.50 usfl Ground Level: 16.50 usft Wellbore MPU L41 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (`) (nT) BGGM2018 9/26/2018 17.01 81.00 57,453 Design MPU L-41 wp12 Audit Notes: Version: Phase: PLAN Tie On Depth: 7,470.00 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (°) 33.70 0.00 0.00 16.63 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/ -S +EI -W Rate Rate Rate Tool Face (usft) (') (°) (usft) usft (usft) (usft) ('I100usft) ('/100usft) (`1100usft) (I 7,470.00 59.68 14.97 4,751.22 4,701.02 4,896.08 1,406.87 0.00 0.00 0.00 0.00 7,650.00 59.83 21.22 4,841.94 4,791.74 5,043.78 1,455.15 3.00 0.08 3.47 90.00 7,759.59 58.52 17.71 4,898.11 4,847.91 5,132.49 1,486.52 3.00 -1.20 -3.20 -114.39 9,050.79 58.52 17.71 5,572.33 5,522.13 6,181.49 1,821.51 0.00 0.00 0.00 0.00 10,334.88 20.00 18.00 6,547.94 6,497.74 6,940.77 2,065.19 3.00 -3.00 0.02 179.84 11,109.88 20.00 18.00 7,276.20 7,226.00 7,192.86 2,147.10 0.00 0.00 0.00 0.00 11,241.84 20.00 18.00 7,400.20 7,350.00 7,235.78 2,161.04 0.00 0.00 0.00 0.00 927/2018 5:57:19PM Page 2 COMPASS 5000.1 Build 81E Planned Survey Halliburton H A LL I B U R TO N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Rig: MPU L-41 Company: Hilcorp Alaska, LLC TVD Reference: MPU L-41 Actual @ 50.20usft Project: Milne Point MD Reference: MPU L-41 Actual @ 50.20usft Site: M Pt L Pad North Reference: True Well: Rig: MPU L-41 Survey Calculation Method: Minimum Curvature Wellbore: MPU L-41 Design: MPU L-41 wp12 Map 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) -16.50 33.70 0.00 0.00 33.70 -16.50 0.00 0.00 6,031,767.05 544,744.45 0.00 0.00 100.00 0.25 137.27 100.00 49.80 -0.11 0.10 6,031,766.95 544,744.55 0.38 -0.07 200.00 0.69 154.88 200.00 149.80 -0.81 0.50 6,031,766.24 544,744.96 0.46 -0.63 300.00 1.01 159.15 299.99 249.79 -2.18 1.07 6,031,764.88 544,745.53 0.33 -1.78 350.00 1.27 163.61 349.98 299.78 -3.12 1.38 6,031,763.94 544,745.85 0.55 -2.60 443.00 1.64 161.73 442.95 392.75 -5.38 2.09 6,031,761.69 544,746.57 0.40 -4.55 536.00 1.33 154.74 535.91 485.71 -7.62 2.97 6,031,759.45 544,747.47 0.39 -6.45 629.00 1.56 24.50 628.90 578.70 -7.44 3.96 6,031,759.64 544,748.45 2.82 -6.00 723.00 4.45 24.19 722.76 672.56 -2.95 5.98 6,031,764.14 544,750.45 3.07 -1.11 817.00 7.41 31.39 816.25 766.05 5.55 10.63 6,031,772.67 544,755.05 3.24 8.37 883.91 9.97 30.37 882.39 832.19 14.24 15.81 6,031,781.38 544,760.17 3.83 18.17 977.50 13.47 29.46 974.01 923.81 30.72 25.27 6,031,797.92 544,769.53 3.74 36.67 1,071.50 16.75 24.21 1,064.75 1,014.55 52.62 36.21 6,031,819.88 544,780.34 3.78 60.78 1,165.98 17.67 21.84 1,155.00 1,104.80 78.34 47.13 6,031,845.67 544,791.10 1.22 88.55 1,260.89 16.36 20.42 1,245.76 1,195.56 104.24 57.15 6,031,871.62 544,800.97 1.45 116.24 1,354.13 16.57 13.64 1,335.18 1,284.98 129.47 64.87 6,031,896.90 544,808.53 2.07 142.62 1,449.00 16.69 14.09 1,426.08 1,375.88 155.83 71.38 6,031,923.29 544,814.88 0.19 169.74 1,543.56 18.97 12.20 1,516.10 1,465.90 184.03 77.93 6,031,951.53 544,821.27 2.49 198.63 1,637.63 23.65 15.74 1,603.71 1,553.51 217.15 86.29 6,031,984.70 544,829.42 5.16 232.76 1,732.53 28.54 14.08 1,688.91 1,638.71 257.49 96.97 6,032,025.09 544,839.86 5.21 274.47 1,826.68 33.47 12.38 1,769.59 1,719.39 304.69 108.02 6,032,072.36 544,850.62 5.32 322.86 1,921.31 38.50 14.32 1,846.14 1,795.94 358.75 120.90 6,032,126.49 544,863.18 5.45 378.35 2,015.91 43.94 16.52 1,917.27 1,867.07 418.80 137.53 6,032,186.63 544,879.45 5.95 440.64 2,109.76 48.18 17.53 1,982.38 1,932.18 483.39 157.34 6,032,251.33 544,898.86 4.58 508.20 2,204.15 52.61 14.30 2,042.55 1,992.35 553.31 177.20 6,032,321.37 544,918.30 5.38 580.88 2,297.87 56.46 15.20 2,096.92 2,046.72 627.11 196.65 6,032,395.27 544,937.30 4.18 657.16 2,392.99 59.16 15.58 2,147.59 2,097.39 704.71 218.01 6,032,473.00 544,958.20 2.86 737.63 2,486.95 60.17 15.54 2,195.04 2,144.84 782.84 239.77 6,032,551.24 544,979.48 1.08 818.71 2,580.15 59.39 14.94 2,241.95 2,191.75 860.54 260.94 6,032,629.06 545,000.18 1.00 899.22 2,674.35 59.24 15.32 2,290.02 2,239.82 938.74 282.08 6,032,707.38 545,020.85 0.38 980.20 2,769.23 58.55 15.84 2,339.04 2,288.84 1,016.99 303.90 6,032,785.75 545,042.19 0.87 1,061.43 2,863.44 57.68 15.90 2,388.80 2,338.60 1,093.94 325.77 6,032,862.82 545,063.60 0.93 1,141.41 2,957.50 60.49 16.36 2,437.12 2,386.92 1,171.45 348.20 6,032,940.46 545,085.55 3.02 1,222.10 3,051.56 60.39 16.39 2,483.52 2,433.32 1,249.95 371.26 6,033,019.09 545,108.14 0.11 1,303.92 3,146.62 59.92 17.04 2,530.83 2,480.63 1,328.91 394.97 6,033,098.19 545,131.38 0.77 1,386.37 3,241.17 59.59 17.16 2,578.46 2,528.26 1,406.98 418.99 6,033,176.39 545,154.92 0.37 1,468.04 3,335.49 59.22 17.70 2,626.46 2,576.26 1,484.44 443.31 6,033,253.99 545,178.77 0.63 1,549.23 3,430.35 59.29 17.49 2,674.96 2,624.76 1,562.16 467.95 6,033,331.84 545,202.95 0.20 1,630.74 3,524.76 58.92 18.12 2,723.43 2,673.23 1,639.29 492.73 6,033,409.12 545,227.25 0.69 1,711.74 3,618.61 59.01 16.13 2,771.82 2,721.62 1,716.14 516.40 6,033,486.10 545,250.46 1.82 1,792.14 3,712.37 58.85 15.55 2,820.21 2,770.01 1,793.39 538.32 6,033,563.48 545,271.92 0.56 1,872.44 3,807.22 58.95 15.61 2,869.20 2,819.00 1,871.63 560.14 6,033,641.83 545,293.26 0.12 1,953.65 3,901.84 59.17 15.68 2,917.85 2,867.65 1,949.78 582.02 6,033,720.10 545,314.67 0.24 2,034.79 3,996.14 58.92 16.30 2,966.36 2,916.16 2,027.52 604.30 6,033,797.97 545,336.47 0.62 2,115.66 4,090.32 59.59 15.03 3,014.50 2,964.30 2,105.45 626.15 6,033,876.03 545,357.85 1.36 2,196.58 9272018 5:57:19PM Page 3 COMPASS 5000.1 Build 81E HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: Rig: MPU L-41 Wellbore: MPU L-41 Design: MPU L-41 wp12 Planned Survey Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Measured Map Map Vertical 1.37 +E/ -W Depth Inclination Azimuth Depth TVDss +N/ -S (usft) (1) (1) (usft) usft (usft) 4,185.14 59.73 15.46 3,062.40 3,012.20 2,184.40 4,279.49 58.36 13.13 3,110.93 3,060.73 2,262.80 4,373.14 57.85 14.21 3,160.42 3,110.22 2,340.05 4,467.16 57.71 14.74 3,210.54 3,160.34 2,417.07 4,561.90 58.07 14.61 3,260.90 3,210.70 2,494.70 4,656.28 58.48 15.12 3,310.53 3,260.33 2,572.29 4,750.80 58.55 15.27 3,359.90 3,309.70 2,650.08 4,845.32 58.91 15.80 3,408.96 3,358.76 2,727.91 4,939.80 59.38 15.56 3,457.42 3,407.22 2,806.00 5,033.95 61.37 15.85 3,503.95 3,453.75 2,884.79 5,128.64 61.05 15.43 3,549.56 3,499.36 2,964.70 5,223.05 59.95 14.80 3,596.05 3,545.85 3,044.02 5,317.38 59.08 14.81 3,643.90 3,593.70 3,122.61 5,411.89 57.83 14.70 3,693.34 3,643.14 3,200.50 5,507.00 58.72 14.49 3,743.36 3,693.16 3,278.79 5,601.06 58.49 14.74 3,792.36 3,742.16 3,356.48 5,694.88 58.26 15.40 3,841.55 3,791.35 3,433.62 5,788.33 57.03 15.14 3,891.56 3,841.36 3,509.77 5,883.69 57.48 18.00 3,943.15 3,892.95 3,586.63 5,978.09 57.83 17.92 3,993.66 3,943.46 3,662.50 6,072.17 58.50 17.58 4,043.28 3,993.08 3,738.62 6,166.62 59.36 18.48 4,092.02 4,041.82 3,815.55 6,261.56 59.58 18.92 4,140.25 4,090.05 3,893.01 6,355.24 59.20 19.82 4,187.95 4,137.75 3,969.07 6,449.84 59.64 16.78 4,236.09 4,185.89 4,046.38 6,543.86 59.18 16.96 4,283.94 4,233.74 4,123.83 6,638.41 59.24 15.73 4,332.34 4,282.14 4,201.77 6,732.82 58.85 16.30 4,380.90 4,330.70 4,279.59 6,827.18 58.69 14.00 4,429.83 4,379.63 4,357.47 6,921.24 59.89 14.02 4,477.86 4,427.66 4,435.93 7,015.91 58.81 13.77 4,526.12 4,475.92 4,514.99 7,109.76 59.38 15.01 4,574.33 4,524.13 4,592.98 7,205.01 60.15 14.94 4,622.29 4,572.09 4,672.48 7,299.00 61.84 15.03 4,667.86 4,617.66 4,751.88 7,333.45 61.41 15.06 4,684.23 4,634.03 4,781.16 7,363.62 61.16 15.03 4,698.73 4,648.53 4,806.71 7,367.00 61.11 15.03 4,700.36 4,650.16 4,809.57 95181, 7,457.99 59.87 14.95 4,745.18 4,694.98 4,886.06 7,470.00 59.68 14.97 4,751.22 4,701.02 4,896.08 KOP : Start Dir 3-1100': 7470' MD, 4751.22'TVD : 90° RT TF 7,500.00 59.69 16.02 4,766.36 4,716.16 4,921.04 7,600.00 59.76 19.49 4,816.79 4,766.59 5,003.27 7,650.00 59.83 21.22 4,841.94 4,791.74 5,043.78 7,700.00 59.22 19.63 4,867.30 4,817.10 5,084.17 Halliburton Standard Proposal Report Well Rig: MPU L-41 MPU L41 Actual @ 50.20usft MPU L-41 Actual @ 50.20usft True Minimum Curvature 1,404.20 Map Map 1.37 +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) 3,012.20 546,128.46 647.67 6,033,955.10 545,378.89 0.42 2,278.39 667.66 6,034,033.61 545,398.41 2.57 2,359.23 686.44 6,034,110.97 545,416.73 1.12 2,438.63 706.33 6,034,188.09 545,436.14 0.50 2,518.12 726.66 6,034,265.84 545,456.00 0.40 2,598.32 747.25 6,034,343.54 545,476.13 0.63 2,678.56 768.38 6,034,421.45 545,496.79 0.15 2,759.13 790.02 6,034,499.40 545,517.95 0.61 2,839.91 811.94 6,034,577.62 545,539.40 0.54 2,921.01 834.09 6,034,656.52 545,561.08 2.13 3,002.83 856.46 6,034,736.56 545,582.97 0.52 3,085.81 877.89 6,034,816.01 545,603.92 1.30 3,167.95 898.66 6,034,894.71 545,624.21 0.92 3,249.19 919.18 6,034,972.71 545,644.25 1.33 3,329.69 939.56 6,035,051.12 545,664.17 0.95 3,410.54 959.82 6,035,128.92 545,683.95 0.33 3,490.78 980.59 6,035,206.18 545,704.26 0.65 3,570.64 1,001.38 6,035,282.44 545,724.59 1.34 3,649.55 1,024.26 6,035,359.43 545,747.00 2.57 3,729.75 1,048.85 6,035,435.44 545,771.13 0.38 3,809.48 1,073.21 6,035,511.70 545,795.03 0.78 3,889.39 1,098.25 6,035,588.77 545,819.61 1.22 3,970.26 1,124.47 6,035,666.38 545,845.36 0.46 4,051.99 1,151.21 6,035,742.59 545,871.64 0.92 4,132.52 1,176.78 6,035,820.05 545,896.73 2.81 4,213.91 1,200.26 6,035,897.63 545,919.75 0.52 4,294.85 1,223.12 6,035,975.70 545,942.14 1.12 4,376.07 1,245.46 6,036,053.64 545,964.00 0.66 4,457.03 1,266.64 6,036,131.64 545,984.62 2.09 4,537.68 1,286.12 6,036,210.21 546,003.72 1.28 4,618.46 1,305.68 6,036,289.37 546,022.80 1.16 4,699.81 1,325.69 6,036,367.48 546,042.34 1.29 4,780.27 1,346.96 6,036,447.10 546,063.13 0.81 4,862.53 1,368.21 6,036,526.62 546,083.90 1.80 4,944.70 1,376.08 6,036,555.94 546,091.59 1.25 4,974.99 1,382.95 6,036,581.53 546,098.30 0.83 5,001.44 1,383.72 6,036,584.39 546,099.05 1.37 5,004.40 1,404.20 6,036,661.00 546,119.07 1.37 5,083.56 1,406.87 5,036,671.04 546,121.69 1.55 5,093.93 1,413.79 6,036,696.03 546,128.46 3.00 5,119.82 1,440.12 6,036,778.41 546,154.29 3.00 5,206.15 1,455.15 6,036,819.01 546,169.07 3.00 5,249.27 1,470.19 6,036,859.48 546,183.87 3.00 5,292.26 9/272018 5:57.19PM Page 4 COMPASS 5000.1 Build 81E HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: Rig: MPU L-41 Wellbore: MPU L-41 Design: MPU L-41 wp12 Planned Survey Measured Map Vertical Depth Inclination Azimuth Depth TVDss (usft) (1) (1) (usft) usft 7,759.59 58.52 17.71 4,898.11 4,847.91 End Dir : 7759.59' MD, 4898.11' TVD 3.00 7,800.00 58.52 17.71 4,919.21 4,869.01 7,900.00 58.52 17.71 4,971.42 4,921.22 8,000.00 58.52 17.71 5,023.64 4,973.44 8,100.00 58.52 17.71 5,075.86 5,025.66 8,200.00 58.52 17.71 5,128.07 5,077.87 8,300.00 58.52 17.71 5,180.29 5,130.09 8,400.00 58.52 17.71 5,232.51 5,182.31 8,500.00 58.52 17.71 5,284.72 5,234.52 8,600.00 58.52 17.71 5,336.94 5,286.74 8,700.00 58.52 17.71 5,389.16 5,338.96 8,800.00 58.52 17.71 5,441.37 5,391.17 8,900.00 58.52 17.71 5,493.59 5,443.39 9,000.00 58.52 17.71 5,545.81 5,495.61 9,050.79 58.52 17.71 5,572.33 5,522.13 Start Dir 3°1100' : 9050.79' MD, 5572.33'TVD 9,100.00 57.05 17.72 5,598.56 5,548.36 9,200.00 54.05 17.73 5,655.13 5,604.93 9,300.00 51.05 17.74 5,715.94 5,665.74 9,400.00 48.05 17.75 5,780.81 5,730.61 9,500.00 45.05 17.76 5,849.58 5,799.38 9,600.00 42.05 17.78 5,922.06 5,871.86 9,700.00 39.05 17.79 5,998.03 5,947.83 9,800.00 36.05 17.81 6,077.31 6,027.11 9,900.00 33.05 17.84 6,159.67 6,109.47 10,000.00 30.05 17.86 6,244.88 6,194.68 10,100.00 27.05 17.89 6,332.72 6,282.52 10,200.00 24.05 17.93 6,422.93 6,372.73 10,300.00 21.05 17.98 6,515.28 6,465.08 10,334.88 20.00 18.00 6,547.94 6,497.74 End Dir : 10334.88' MD, 6547.94' TVD 7,100.06 10,347.00 20.00 18.00 6,559.33 6,509.13 Start ESP Tangent 2,049.59 6,038,671.25 546,752.31 10,400.00 20.00 18.00 6,609.13 6,558.93 10,500.00 20.00 18.00 6,703.10 6,652.90 10,544.86 20.00 18.00 6,745.26 6,695.06 HRZ 6,038,723.39 546,768.87 0.00 7,245.63 10,547.00 20.00 18.00 6,747.27 6,697.07 End ESP Tangent 6,994.48 2,082.64 6,038,773.25 10,600.00 20.00 18.00 6,797.07 6,746.87 10,610.98 20.00 18.00 6,807.39 6,757.19 KLB 6,038,788.57 546,789.62 0.00 7,314.02 10,645.58 20.00 18.00 6,839.90 6,789.70 KLGM 7,030.58 2,094.37 6,038,809.42 546,796.25 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Rig: MPU L-41 MPU L-41 Actual @ 50.20usft MPU L-41 Actual @ 50.20usft True Minimum Curvature 9272018 5:57.,19PM Page 5 COMPASS 5000.1 Build 81E Map Map +NIS +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) 4,847.91 5,132.49 1,486.52 6,036,907.89 546,199.91 3.00 5,343.24 5,165.32 1,497.01 6,036,940.78 546,210.19 0.00 5,377.70 5,246.56 1,522.95 6,037,022.17 546,235.64 0.00 5,462.96 5,327.80 1,548.89 6,037,103.56 546,261.09 0.00 5,548.23 5,409.04 1,574.84 6,037,184.95 546,286.55 0.00 5,633.50 5,490.29 1,600.78 6,037,266.34 546,312.00 0.00 5,718.77 5,571.53 1,626.72 6,037,347.73 546,337.45 0.00 5,804.04 5,652.77 1,652.67 6,037,429.12 546,362.90 0.00 5,889.31 5,734.01 1,678.61 6,037,510.50 546,388.35 0.00 5,974.58 5,815.26 1,704.56 6,037,591.89 546,413.80 0.00 6,059.85 5,896.50 1,730.50 6,037,673.28 546,439.26 0.00 6,145.12 5,977.74 1,756.44 6,037,754.67 546,464.71 0.00 6,230.39 6,058.98 1,782.39 6,037,836.06 546,490.16 0.00 6,315.66 6,140.23 1,808.33 6,037,917.45 546,515.61 0.00 6,400.92 6,181.49 1,821.51 6,037,958.79 546,528.54 0.00 6,444.23 6,221.15 1,834.17 6,037,998.52 546,540.96 3.00 6,485.86 6,299.68 1,859.27 6,038,077.20 546,565.58 3.00 6,568.29 6,375.29 1,883.44 6,038,152.94 546,589.30 3.00 6,647.65 6,447.75 1,906.63 6,038,225.54 546,612.05 3.00 6,723.72 6,516.88 1,928.76 6,038,294.79 546,633.76 3.00 6,796.29 6,582.48 1,949.79 6,038,360.51 546,654.39 3.00 6,865.16 6,644.37 1,969.64 6,038,422.51 546,673.87 3.00 6,930.15 6,702.39 1,988.27 6,038,480.63 546,692.15 3.00 6,991.07 6,756.37 2,005.63 6,038,534.71 546,709.18 3.00 7,047.76 6,806.16 2,021.66 6,038,584.59 546,724.91 3.00 7,100.06 6,851.64 2,036.33 6,038,630.15 546,739.30 3.00 7,147.83 6,892.66 2,049.59 6,038,671.25 546,752.31 3.00 7,190.94 6,929.14 2,061.41 6,038,707.79 546,763.91 3.00 7,229.27 6,940.77 2,065.19 6,038,719.44 546,767.62 3.00 7,241.49 6,944.71 2,066.47 6,038,723.39 546,768.87 0.00 7,245.63 6,961.95 2,072.07 6,038,740.67 546,774.37 0.00 7,263.76 6,994.48 2,082.64 6,038,773.25 546,784.74 0.00 7,297.95 7,009.07 2,087.38 6,038,787.87 546,789.40 0.00 7,313.29 7,009.77 2,087.60 6,038,788.57 546,789.62 0.00 7,314.02 7,027.00 2,093.21 6,038,805.84 546,795.12 0.00 7,332.14 7,030.58 2,094.37 6,038,809.42 546,796.25 0.00 7,335.89 7,041.83 2,098.02 6,038,820.69 546,799.84 0.00 7,347.72 9272018 5:57.,19PM Page 5 COMPASS 5000.1 Build 81E HALLIBURTON Halliburton Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Rig: MPU L-41 Company: Hilcorp Alaska, LLC TVD Reference: MPU L-41 Actual @ 50.20usft Project: Milne Point MD Reference: MPU L-41 Actual @ 50.20usft Site: M Pt L Pad North Reference: True Well: Rig: MPU L-41 Survey Calculation Method: Minimum Curvature Wellbore: MPU L-41 Design: MPU L-41 wp12 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NIS +EI -W Northing Easting DLS Vert Section (usft) (1) V) (usft) usft (usft) (usft) (usft) (usft) 6,840.84 10,700.00 20.00 18.00 6,891.04 6,840.84 7,059.53 2,103.78 6,038,838.43 546,805.49 0.00 7,366.33 10,800.00 20.00 18.00 6,985.01 6,934.81 7,092.06 2,114.34 6,038,871.02 546,815.86 0.00 7,400.52 10,818.95 20.00 18.00 7,002.82 6,952.62 7,098.23 2,116.35 6,038,877.19 546,817.83 0.00 7,407.01 KUP _D 10,900.00 20.00 18.00 7,078.98 7,028.78 7,124.59 2,124.91 6,038,903.61 546,826.23 0.00 7,434.72 11,000.00 20.00 18.00 7,172.95 7,122.75 7,157.12 2,135.48 6,038,936.19 546,836.60 0.00 7,468.91 11,003.59 20.00 18.00 7,176.32 7,126.12 7,158.28 2,135.86 6,038,937.36 546,836.98 0.00 7,470.14 KUP _C 11,016.58 20.00 18.00 7,188.53 7,138.33 7,162.51 2,137.23 6,038,941.60 546,838.32 0.00 7,474.58 KUP S7 11,109.88 20.00 18.00 7,276.20 7,226.00 7,192.86 2,147.10 6,038,972.00 546,948.00 0.00 7,506.48 11,110.64 20.00 18.00 7,276.92 7,226.72 7,193.11 2,147.18 6,038,972.25 546,848.08 0.00 7,506.74 KUP A3 11,129.71 20.00 18.00 7,294.84 7,244.64 7,199.31 2,149.19 6,038,978.46 546,850.06 0.00 7,513.26 KUP A2 11,159.87 20.00 18.00 7,323.18 7,272.98 7,209.12 2,152.38 6,038,988.29 546,853.19 0.00 7,523.57 KUP Al 11,200.00 20.00 18.00 7,360.89 7,310.69 7,222.17 2,156.62 6,039,001.37 546,857.35 0.00 7,537.29 11,241.84 20.00 18.00 7,400.20 7,350.00 7,235.78 2,161.04 6,039,015.00 546,861.69 0.00 7,551.60 Total Depth : 11241.84' MD, 7400.2' TVD -7"x8 112" Targets Target Name - hitimiss target Dip Angle Dip Dir. TVD +NIS +EI -W Northing Easting -Shape (1) V) (usft) (usft) (usft) (usft) (usft) MPL-41 Tgtl wpl2 0.00 0.00 7,276.20 7,192.86 2,147.10 6,038,972.00 546,848.00 - plan hits target center - Circle (radius 200.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name () (11) 11,241.84 7,400.20 7' x 8 1/2" 7 8-1/2 9/272018 5:57:19PM Page 6 COMPASS 5000.1 Build 81E HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Local Coordinate Reference: Company: Hilcorp Alaska, LLC TVD Reference: Project: Milne Point MD Reference: Site: M Pt L Pad North Reference: Well: Rig: MPU L-41 survey Calculation Method: Wellbore: MPU L-41 KLB Design: MPU L-41 wp12 KUP_B7 Formations Measured Vertical Vertical 4,896.08 Depth Depth Depth SS 7,759.59 (usft) (usft) Name 11,003.59 7,176.32 KUP_C 10,544.86 6,745.26 HRZ 10,610.98 6,807.39 KLB 11,016.58 7,188.53 KUP_B7 11,159.87 7,323.18 KUP_A1 11,110.64 7,276.92 KUP_A3 10,818.95 7,002.82 KUP_D 10,645.58 6,839.90 KLGM 11,129.71 7,294.84 KUP_A2 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment Halliburton Standard Proposal Report Well Rig: MPU L-41 MPU L-41 Actual @ 50.20usft MPU L-41 Actual @ 50.20usft True Minimum Curvature Dip Dip Direction Lithology (1) (1 7,470.00 4,751.22 4,896.08 1,406.87 KOP : Start Dir 30/100': 7470' MD, 4751.22'TVD : 90° RT TF 7,759.59 4,898.11 5,132.49 1,486.52 End Dir : 7759.59' MD, 4898.11' TVD 9,050.79 5,572.33 6,181.49 1,821.51 Start Dir 301100': 9050.79' MD, 5572.33'TVD 10,334.88 6,547.94 6,940.77 2,065.19 End Dir : 10334.88' MD, 6547.94' TVD 10,347.00 6,559.33 6,944.71 2,066.47 Start ESP Tangent 10,547.00 6,747.27 7,009.77 2,087.60 End ESP Tangent 11,241.84 7,400.20 7,235.78 2,161.04 Total Depth : 11241.84' MD, 7400.2' TVD 9272018 5: 57:19PM Page 7 COMPASS 5000.1 Build 81E Hilcorp Alaska, LLC Milne Point M Pt L Pad Rig: MPU L-41 MPU L-41 MPU L-41 wp12 Sperry Drilling Services Clearance Summary Anticollision Report 27 September, 2018 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt L Pad - Rig: MPU L-41 - MPU L-41 - MPU L41 wp12 Well Coordinates: 6,031,767.05 N, 544,744.45 E (70° 29'51.57" N, 149° 38'02.74" W) Datum Height: MPU L41 Actual @ 50.20usft Scan Range: 7,470.00 to 11,241.84 usft. Measured Depth. Scan Radius Is 1,500.00 usft. Clearance Factor cutoff Is Unlimited. Max Ellipse Separation Is Unlimited Geode0c Scale Factor Applied Version: 5000.1 Build: 81E Scan Type: • • - Scan Type: 25.00 HALLIBLIRTON Sperry Drilling Services HALLIBURTON Anticollision Report for Rig: MPU L-41- MPU L-41 wp12 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt L Pad - Rig: MPU L-41 - MPU L-41 - MPU L-41 wp12 Scan Range: 7,470.00 to 11,241.84 usft. Measured Depth. Scan Radius is 1,500.00 usft. Clearance Factor cutoff Is Unlimited. Max Ellipse Separation is Unlimited Hilcorp Alaska, LLC Milne Point 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 L Pad MPL-05 - MPL-05 - MPL-05 7,470.00 1,491.74 7,470.00 1,223.61 7,600.00 5.563 Ellipse Separation Pass - MPL-05 - MPL-05 - MPL-05 7,495.00 1,497.96 7,495.00 1,228.68 7,628.87 5.563 Clearance Factor Pass - MPL-14 - MPL-14 - MPL-14 7,470.00 344.94 7,470.00 222.51 7,368.85 2.81 B Ellipse Separation Pass - MPL-I4-MPL-14-MPL-14 7,670.00 378.51 7,670.00 242.84 7,564.47 2.790 Clearance Factor Pass - MPL-21 - MPL-21 - MPL-21 7,748.49 703.99 7,748.49 575.83 8,031.44 5.493 Centre Distance Pass - MPL-2I-MPL-2I-MPL-21 7,770.00 704.17 7,770.00 575.70 8,047.76 5.481 Ellipse Separation Pass - MPL-21 - MPL-21 - MPL-21 8,220.00 724.71 17,220.00 588.79 8,462.57 5.332 Clearance Factor Pass - MPL-25 - MPL-25 - MPL-25 7,470.00 922.43 7,470.00 738.58 7,373.34 5.017 Clearance Factor Pass - MPL-29 - MPL-29 - MPL-29 7,470.00 1,146.65 7,470.00 943.06 7,325.52 5.632 Clearance Factor Pass - Plan: MPU L-55 - MPU L-55 - MPU L-55 wp17 7,470.00 1,152.53 7,470.00 1,041.17 7,091.49 10.349 Ellipse Separation Pass - Plan: MPU L-55 - MPU L-55 - MPU L-55 wp17 8,370.00 1,239.16 8,370.00 1,115.16 7,986.72 9.993 Clearance Factor Pass - Rig: MPU L-41 - MPU L-41PB1 - MPU L41PB1 7,770.00 16.17 7,770.00 13.28 7,769.34 5.586 Ellipse Separation Pass - Rig: MPU L-41 - MPU L-41PI31 - MPU L41PB1 10,870.00 66.15 10,870.00 56.06 10,870.83 2.863 Clearance Factor Pass - Survey tool 2roaram From To Survey/Plan Survey Tool (usft) (usft) 100.00 817.00 2_Gyro-NS-GC_Drill collar 883.91 7,333.45 2_MWD+IFR2+MS+Sag 7,363.62 7,363.62 2_MWD Interp Azi+Sag 7,457.99 7,470.00 2MWD+IFR2+MS+Sag 7,470.00 11,241.84 MPU L-41 wp12 27_MWD+IFR2+MS+Sag 27 September, 2018 - 17:56 Page 2 of 5 COMPASS HALLIBURTON Anticollision Report for Rig: MPU L-41- MPU L-41 wp12 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. Hilcorp Alaska, LLC Milne Point 27 September, 2018 - 17.56 Page 3 of 5 COMPASS HALLIBURTON Project: Milne Point REFERENCE INFORMATION WELLDETAIIS:Itiff MPUL-N NAD1927(NADCONCONUS) Alaskaane04 Site: M Pt L Pad Ceordlret0 (N/E) Reference: Well Rgo MPU _41, True NOM GromW Level: 16.50 pD)Reference: MPU L-01 Acme1®50.20usft 50.20.0 -NI-S 1E/_W Nanking gem, Lafitmdc Loagimde 9'e," Crllline Well: Rig: MPU L -41M asurVerthedl 0.00 0.00 fi031 ]fi]DS 544)44.45 )0°29'S45]2N 149°3R'2.flRW Wellbore: MPU L-41 calculation Method Mlnlmum Curvature Plan: MPU L-41 w 12 GLOBAL FILTER: Using user defined selection 8 filtering criteria SURVEY PROGRAM 7470.00 To 11241.84 Date: 2018-09-26T00:00:00 Validated: Yes Version: CASING DETAILS Depth From Depth To Tool MPU L 1 G 100.00 817.00 MPU L-01 Gyro(MPU L<iPBi) 2_MWD+IFR2+M+aag TVD TVD55 MD Size Name 893.91 7333.45 MPU L-41 MWD+IFR2+MS+sag(MPU L41PBI) 2_MWD+IFR2+MS+Sa9 7400.20 7350.00 II247.84 7 7"x81/2" 2_MWD _Interp AL+Seg Ladder/S.F. Plots 7383.62 7363.62 MPU L-41 MWD_Interp Aa+SagO(MPU L41P 7457.99 7470.00 MPU L41 MWD+IFR2+MS+seg (2) (MPU Ld1PBi) 2MWD+IFR2+MS+Sag 74]0.00 11241.84 MPU L41 w 12 MPU L-41 2MWD+IFR2+MS+Sa X750.00 I N I i O O (D C M PU L-01PB1 O 90.00 __. - _.... _.. Cl U) 1� 0 30.00---- 0.00IL I L 0 - I U 0.00 7600 7800 8000 B200 B400 8600 8800 9000 9200 9400 9600 9800 10000 10200 10400 10600 10800 11000 11200 Measured Depth (400 usfUin) 4.50 _. __._. O 03.00— 3.00 O .0 I i n Collision Risk Procedures Req. X1.50 -__ Collision Avoidance Req. No -Go Zone -Stop Drilling 1 I 0.00 1 7500 7750 8000 8250 8500 8750 9000 9250 9500 9750 10000 1025D 10500 10750 11000 11250 Measured Depth (400 usf /in) I Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, September 25, 2018 6:29 PM To: Joe Engel Cc: Paul Mazzolini; Monty Myers; Cody Dinger; Boyer, David R (LAW) Subject: Re: Hilcorp MPU L-41 (PTD# 218-104) Update Joe, You have approval to move forward with plugging well for sidetrack as proposed below. As stated submit sundry in morning with details including new directional plan. Regards, Guy Schwartz AOGCC Sent from my iPhone On Sep 25, 2018, at 5:42 PM, Joe Engel <leneel@hilcorp.com> wrote: Guy— I wanted to give you an update and a follow up email to our conversation earlier today. We were able to run our 4-1/2" liner to TD on L-41 and successfully pump our cement job, however we had trouble releasing the running tool after the liner hanger was set. While attempting to release from the liner hanger, it was determined that we pulled all or a portion of the liner top —300' MD up the hole to — 10,260' MD. We attempted to PT the liner and it failed two tests, the first at 3000psi and the second and 1500 psi. Due to this, Hilcorp Alaska would like to plug back this hole section and redrill the well to below the Kuparuk. A rough outline of our operations is below. • PT well t/ 3000psi • If PT fails, RIH and spot 500' of cement above TOL at 10,260' MD • RIH & set 7" cement retainer below 9-5/8" shoe • Cut and pull 7" below the 9-5/8" shoe, above retainer • Spot KOP • Kick off well with 8.5 motor BHA • Drill 8.5" x 9-7/8" hole section to TD below Kuparuk A2 • Run and cement 7" longstring We will submit a sundry ASAP. May we get verbal approval to begin plugging operations, prior to submitting the sundry? Please let me know if you have any questions. Thank you for your time. Joe Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK ( 99503 Office: 907.777.8395 1 Cell: 805.235.6265 Davies, Stephen F (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Friday, September 28, 2018 3:33 PM To: Davies, Stephen F (DOA); Joe Engel Cc: Schwartz, Guy L (DOA) Subject: RE: [EXTERNAL] MPU L-41 (PTD 218-104; Sundry 318-433) - Question Thank you for the reminder. We will make sure we conform Monty M Myers Drilling Manager 907.538.1168 (c) 907.777.8431 (o) From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Friday, September 28, 2018 3:08 PM To: Monty Myers <mmyers@hilcorp.com>; Joe Engel <jengel@hilcorp.com> Cc: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Subject: [EXTERNAL] MPU L-41 (PTD 218-104; Sundry 318-433) - Question Monty, Joe: Sorry to hear about problems with MPU L-41. While reviewing proposed directional survey data that accompanied this Sundry Application, I noticed that Hilcorp is targeting essentially the same BHL as originally permitted for this well. So, Hilcorp's Sundry Application No. 318-433 isn't for a plug for redrill; instead, it's to change the approved program to allow a sidetrack operation to correct mechanical difficulties in the original hole. (See 20 AAC 25.990(63).) If this is correct, please remember that all records, data and logs acquired in the lost section of L-41 must be labeled with the name MPU L-41PB1 and the API number of 50-029-23611-70-00 to prevent confusion. Regards, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) 907-793-1224 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 Steve Davies at 907-793-1224 or Steve daviestmalaska.zov. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: MILNE PT UNIT L-41 Contractor/Rig No.: Doyon 14 ' Operator: HILCORP ALASKA LLC Type Operation: DRILL Sundry No: TypeTest: BIWKLY MISC. INSPECTIONS: PTD#: 2181040 DATE: 9/28/2018 Operator Rep: Yessak/foomey Test Pressures: Rams: Annular: Valves: MASP: 250/4000 250/2500 250/4000 " 2704 ' TEST DATA MUD SYSTEM: Reviewed By: P.I. Supry TPya r'TV Comm Inspector Matt Herrera Insp Source Rig Rep: Hansen/Carlo Inspector Inspection No: bopMFI1180929114545 Related Insp No: ACCUMULATOR SYSTEM: P/F P/F Visual Alarm Location Gen.: P Trip Tank P P Housekeeping: P_ Pit Level Indicators P P . PTD On Location P - Flow Indicator P P Standing Order Posted . P Meth Gas Detector P P Well Sign _P H2S Gas Detector P P Dr]. Rig P - MS Misc NA NA Hazard Sec. P 2 3 1/8" P Misc NA 3 1/8" P Check Valve FLOOR SAFTY VALVES: BOP STACK: Reviewed By: P.I. Supry TPya r'TV Comm Inspector Matt Herrera Insp Source Rig Rep: Hansen/Carlo Inspector Inspection No: bopMFI1180929114545 Related Insp No: ACCUMULATOR SYSTEM: Quantity P/F Upper Kelly I _--P 3000 Lower Kelly 1 " _ P Ball Type __2 P Inside BOP _ _2 FP FSV Misc 0 NA Reviewed By: P.I. Supry TPya r'TV Comm Inspector Matt Herrera Insp Source Rig Rep: Hansen/Carlo Inspector Inspection No: bopMFI1180929114545 Related Insp No: ACCUMULATOR SYSTEM: 0 Time/Pressure P/F System Pressure 3000 P Pressure After Closure 1650 P 200 PSI Attained 39 P Full Pressure Attained 186 P " Blind Switch Covers: Yes P _ Quantity Size P/F Nitgn. Bottles (avg): 6@2033 - P ACC Misc 0 NA Stripper 0 NA '. Annular Preventer 1 13 5/8" P 41 Rams 1 2 7/8" x 5" P #2 Rams 1 - Blinds P #3 Rams 1 4 1/2" x 7" P #4 Rams 0 NA_ #S Rams 0 NA_ #6 Rams 0 NA Choke Ln. Valves 1 3 1/8" P HCR Valves 2 3 1/8" P Kill Line Valves 2 3 1/8" P Check Valve 0 NA BOP Misc 0 NA CHOKE MANIFOLD: Quantity WIT No. Valves 14 - P Manual Chokes 1 P Hydraulic Chokes 1 P - CH Misc 0 NA INSIDE REEL VALVES: (Valid for Coil Rigs Only) Quantity P/F Inside Reel Valves 0 NA Number of Failures: 1 ✓ Test Results Test Time 9.5 Remarks: 5 Different sizes Test Joints 2 7/8", 4", 4 1/2", 5" and T' 4" Dart Valve failed was replaced and retested good MP L-41 Completion Program Run and cement 7" production casing. Set 7" packoff and test. Freeze protect 7" x 9-5/8" annulus L - ° l ' 1 -/(0 LD 5" DP in mouse hole. n �� MU 6-1/8" bit. PU and RIH on 4" DP. 04,�•••� / 7„ 2— • Ensure Cement has reached 500 psi compressive strengt prior to clean out run. Drill out 7" ES cementer to the baffle adapter (PBTD). Circulate wellbore with clean 8.45 ppg seawater at max rate, rotate and reciprocate pipe (the wellbore will be hydraulically isolated from the reservoir with cemented casing) p �% POOH. Close blind rams and PT 7" casing to 3500 psi f/ 30 charted minutes. RIH with bit/scraper/junk baskets on 4" DP to PBTD. Circulate wellbore with clean 8.8 ppg KCI/NaCl at max rate with rotation and reciprocation • KWF Est —8.8 ppg (2% KCI/NaCl) RU E-line/line wiper & run CBL/VDL from PBTD to above estimated TOC. CBL/VDL will be across Kuparuk formation. RD E -line PU and RIH with 4-1/2" 12.6#/ft TXP-SR L-80 tubing / Frac String as follows: • 4-1/2" WLEG @ —10,850' MD • 2 joints of 4-1/2" 12.6#/ft TXP-SR L-80 i • 4-1/2" XN nipple with RHC ball catcher • 7" x 4-1/2" HAL AHC Packer @ —10,750' MD. Final set depth to be confirmed after running CBL/VDL • 4-1/2" 12.6#/ft TXP-SR L-80 tubing • 4-1/2" Tubing Hanger Land tubing hanger. RILDS. Test tubing hanger, 500 psi low / 5000 psi high Install BPV ND BOPE (the wellbore will be hydraulically isolated from the reservoir with cemented and pressure tested casing) NU Tree & pressure test Freeze protect IA and tubing Drop Ball and Rod and set packer with 2,500 psi. n Burp Alaska, LLC Orig. KB Elev.: 33.7 / GL Elev.:16.5' PROPOSED FRAC STRING TD=11,315' (ND) /TD= 7,468' (TVD) PBTD=±11,180' (ND) / PBTD=±7,341' (TVD) Milne Point Unit Well: MPL-41 Last Completed: TBD PTD: TBD TREE & WELLHEAD Tree TBD Wellhead TBD OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" Stg 11685 ft3/458 ft3, Stg 21937 ft3/314 ft3 9-7/8"x8-1/2" 1 202 ft3 6-1/8" 1 142 ft3 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 164/A53B/Weld N/A Surface 80' -5/8" Surface 40/L-80/TXP 8.835 Surface 7,366' 7" Intermediate 26/L-80/TXP 6.276 Surface ±11,307' TUBING DETAIL -1/2" Frac String 12.6 / L-80 / TXP 3.958 1 Surface 1 ±10,850' WELL INCLINATION DETAIL KOP @ 600' Max Hole Angle 59 deg JEWELRY DETAIL No. Top MD Item ID 1 110,730' 4-1/2" x 7" Packer 2 ±10,750' 4-1/2"XN Nipple 3 ±10,850' Muleshoe GENERAL WELL INFO API: TBD Completion Date: TBD Edited By: TDF 10-11-2018 THE STATE Alaska Oil and Gas 01A AS— h Conservation Commission GOVERNOR BILL WALKER Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.aloska.gov Re: Milne Point Field, Kuparuk River Oil Pool, MPU L-41 Hilcorp Alaska, LLC Permit to Drill Number: 218-104 Surface Location: 3578' FSL, 5134' FEL, SEC. 8, TI 3N, RI OE, UM, AK Bottomhole Location: 399' FSL, 2281' FWL, SEC. 32, T14N, R10E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, ms's!' Hollis S. French Chair w� J DATED this -3 day of August, 2018. STATE OF ALASKA AU, -KA OIL AND GAS CONSERVATION COMMIS., -)N PERMIT TO DRILL 20 AAC 25.005 ' C E i AUu 10 20119 Ia. Type of Work: 1b. Proposed Well Class: Exploratory -Gas Service - WAG Service - Disp ❑ 1c. Specify if well is proposed for: Drill Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑v • Service- Winj ❑ Single Zone ❑v ' Coalbed Gas ❑ Gas Hydrates ❑ Redrill❑ Reentry❑ Exploratory - Oil ❑ Development - Gas ❑ Service -Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket ❑✓ . Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 • MPU L-41 ' 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 11,587' TVD: 7,725' Milne Point Unit / Kupamk Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 3578' FSL, 5134' FEL, Sec 8, T1 3N, R10E, UM, AK ADL025509, ADL355017 Tap of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 235' FSL, 2234' FWL, Sec 32, T14N, R1 OE, UM, AK LONS 88-002 8/22/2018 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 399' FSL, 2281' FWL, Sec 32, T14N, RiOE, UM, AK 7013 14,130'to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 50.2 ' 15. Distance to Nearest Well Open Surface: x- 544744. y- 6031767 • Zone -4 GL / BF Elevation above MSL (ft): 16.5 to Same Pool: 1780' to MPL-05 16. Deviated wells: Kickoff depth: 550 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 59 degrees Downhole: 2476 'Sr(7- ,/b Surface: 2704 18. Casing Program: Specifications Top - Setting Dept - Bottom Cement Quantity, c.f. or sacks HoleCasing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Cend20" 164# A53B Weld 80' Surface Surface 80' 80' Driven Sig 1 L - 1685 ft3 /T -458 ft3 12-1/4" 9-5/8" 40# L-80 TXP 7,638' Surface Surface 7,638' • 4,850' Stg 2 L- 1937 ft3 / T - 314 ft3 9-7/8"x8-1/2" 7" 26# L-80 TXP 10,698' 1 Surface Surface 10,698' 6,889' 202 ft3 6-1/8" 4-1/2" 12.6# L-80 TXP 1,037' 10,550' 7,692' 11,587' 7,725 142 ft3 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD Hydraulic Fracture planned? Yes ❑t No ❑ 20. Attachments: Property Plat O BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysise Diverts, Sketch Seabed Report e Dulling Fluid Program r 20 AAC 25.050 requirements B 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: Left el hilCOr .COM Authorized Title: Drilling Manager Contact Phone: 777-8395 Authorized Signature: Date: 8, 1 O, lis Commission Use Only Permit Drill /v / API0 7-e _� Permit Approval See cover letter for other Number: !%�/f r: 50- - Z�(�/�� Date: requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane gas hydrates, or gas contained in shales: Samples req'd: Yes ❑ j✓o y Mud log req'd: Yes❑ JdoO Other: y L/OQv S « Bd �n S7^�' l HzS measures: Yes LR No E] /. Directional svy req'd: YesLrJ•� No Spacing exception req'd: Yes ❑ No Lj' Inclination -only svy mq'd: Yes❑ Noa ��� �'�-'J 4•a./',� l v4- Post initial injection MIT req'd: Yes❑ No[] APPROVED BY ./l. �Z3 lip Approved by: - COMMISSIONER THE COMMISSION Date: Cl 111 lJ 1 — 4y� 71, & _i - 15 Submit Fom and Form 10-401 Revised 5/2017 This permi valid for 24 months from the date of approval per 20 AAC 25.005(g) Attachments in Duplicate H Hilcorp eo� compwy 8.10.2018 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 711 Avenue Anchorage, Alaska 99501 Re: Application for Permit to Drill MPU L-41 Dear Commissioner, Joe Engel Hilcorp Alaska, LLC Drilling Engineer P•O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8395 Email: jengel@hilcorp.com Hilcorp Alaska, LLC hereby submits for review and approval for a Permit to Drill an onshore production well at Milne Point'L' Pad, well slot 41. Drilling operations are intended to commence approximately August 24th, 2018, pending rig schedule. MPU L-41 is a grassroots oil production well targeting the Kuparuk River Pool. located on Milne Point 'L -Pad'. The directional plan is a three string slant well, with the kick off point at ±600' MD/TVD. Maximum hole angle is 59 degrees at ±2,330 MD. Surface casing will be run to below the Schrader Bluff sands and cemented to surface via a two stage primary cement job. Intermediate casing will be run to landed in the Upper Kalubik and cemented via a single stage cement job bringing cement to 500' MD (minimum) above shoe depth. Although normal pressure in the Kupuark is expected, prior wells in this fault block have encountered high pressure. Top setting intermediate casing is being done as a precaution. -- Production liner will be 4.5" 12.6# L-80 cemented liner run to just below Kuparuk A. A 4-1/2" frac string with packer will be run. The Doyon 14 will be used to drill and complete the wellbore. After reviewing the LWD logs obtained while drilling the well, a determination will be made whether or not fracture stimulation will be performed at a later date. The base plan, however, is to fracture stimulate the Kuparuk reservoir. A separate sundry will be submitted for hydraulic fracture stimulation and completion operations. Please find attached the Form 10-401, Application For Permit to Drill per 20 AAC 25.005 (a) and the drilling program for MPU L-57, which includes information required by 20 AAC 25.005 (c). If you have any questions, or require further information, please do not hesitate to contact myself (Joe Engel) at 777-8395 or jengel@hilcorp.com or Monty Myers at 777-8431 or mmyers@hilcorp.com. Sincerely, Joe Engel Drilling Engineer Hilcorp Alaska, LLC Page i of 1 Hilcorp Alaska, LLC Milne Point Unit (MPU) L-41 Drilling Program Version 1 August 9, 2018 Table of Contents 1.0 Well Summary 2.0 Management of Change Information............................................................................................................3 3.0 Tubular Program: .......................................................................................................................................... 4 4.0 Drill Pipe Information: .................................................................................................................................. 4 5.0 Casing Inspection............................................................................................................................................4 6.0 Internal Reporting Requirements.................................................................................................................5 7.0 Planned Wellbore Schematic.........................................................................................................................6 8.0 Drilling/ Completion Summary....................................................................................................................7 9.0 Mandatory Regulatory Compliance / Notifications.....................................................................................8 10.0 R/U and Preparatory Work.........................................................................................................................10 11.0 N/U 21-1/4" 2M Diverter System.................................................................................................................11 12.0 Drill 12-1/4" Hole Section............................................................................................................................13 13.0 Run 9-5/8" Surface Casing...........................................................................................................................16 14.0 Cement 9-5/8" Surface Casing.....................................................................................................................21 15.0 BOPE N/U, Test, and Wellhead Installation..............................................................................................26 16.0 Drill 8.5" x 9.875" Intermediate Hole Section............................................................................................27 17.0 Run 7" Intermediate Casing........................................................................................................................31 18.0 Cement 7" Intermediate Casing..................................................................................................................33 19.0 Drill 6-1/8" Production Hole Section..........................................................................................................35 20.0 Run 4-1/2" Liner...........................................................................................................................................38 21.0 Cement 4-1/2" Production Liner.................................................................................................................41 22.0 Perform 4-1/2" Cleanout Run & Displacement.........................................................................................43 23.0 Run 4-1/2" Frac String.................................................................................................................................44 24.0 Doyon 14 Diverter Schematic......................................................................................................................45 25.0 Doyon 14 BOP Schematic............................................................................................................................46 26.0 Wellhead Schematic.....................................................................................................................................47 27.0 Days Vs Depth...............................................................................................................................................48 28.0 Formation Tops & Information..................................................................................................................49 29.0 Anticipated Drilling Hazards.......................................................................................................................51 30.0 Doyon 14 Layout...........................................................................................................................................54 31.0 FIT Procedure...............................................................................................................................................55 32.0 Doyon 14 Choke Manifold Schematic.........................................................................................................56 33.0 Casing Design Information..........................................................................................................................57 34.0 8-1/2" x 9.875" Hole Section MASP............................................................................................................58 35.0 6-1/8" Hole Section MASP...........................................................................................................................59 36.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................................60 37.0 Surface Plat (As Built) (NAD 27)................................................................................................................61 38.0 Drill Pipe Information..................................................................................................................................62 n Hilcorp 1.0 Well Summary Milne Point Unit L-41 Drilling Procedure Well MPU L-41 Pad Milne Point "L" Pad Planned Completion Type 4-1/2" Cemented Liner Target Reservoir(s) Ku aruk A Planned Well TD, MD / TVD 11,587' MD / 7,725' TVD PBTD, MD / TVD 111,500 MD / 7,643' TVD Surface Location Governmental 3578' FSL, 5134' FEL Sec 8, T13N, RIOE, UM, AK Surface Location (NAD 27 — Zone 4) X=544,744.45 Y=6,031,767.05 Top of Productive Horizon (Governmental) 235' FSL, 2234' FWL, Sec 32, T14N, RIOE, UM, AK TPH Location (NAD 27) X=546,763.10, Y=6,038,994.90 BRI, (Governmental) 399' FSL, 2281' FWL, Sec 32, T14N, RIOE, UM, AK BHL (NAD 27) X=546,808.72, Y=6,039,159.69 AFE Number 1813264 AFE Drilling Das 20 Days AFE Completion Das 6 Days AFE Drilling Amount $4,597,573 AFE Completion Amount $2,245,952 AFE Facility Amount $330,000 Maximum Anticipated Pressure (Surface) 2704 psi Maximum Anticipated Pressure (Downhole/Reservoir) 3476 psi Work String 5" 19.5# S-135 NC -50, DS -50 4" 14# S-135 XT -39 / HT38 KB Elevation above MSL: 33.7 ft + 16.5 ft = 50.2 ft GL Elevation above MSL: 16.5 ft - BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 Version I August 2018 H Hilcorp 2.0 Milne Point Unit L-41 Drilling Procedure Management of Change Information 14 Hilcorp Alaska, LLC 21�c. Changes to Approved Permit to Drill Date: 816/2018 Subject: Changes to Approved Permit to Drill for MPU L-41 File #: MPU L-41 Drilling and Completion Program Any modifications to MPU L-411 Drilling & Completion Program will be documented and approved below. Changes to an approved APD vall be communicated to and approved by the AOGCC. Approval: Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Version 1 August 2018 H Hilcorp 3.0 Tubular Program: X Milne Point Unit L-41 Drilling Procedure 4.0 Drill Pipe Information: Hole 'Section iD (in) Drift in77.656"26 TJ TD T.1OD Bu—W'Co14 (psi)si k -lbs Cond 20" 19" - Tension* (k -lbs) A -106B Weld 5" 4.276' 12-1/4" 9-5/8" 8.835" 8.75" S-135 L-80 Ci -51750 3,090 916 8-1/2" x 7" 9-7/8"6-1/8" 6.276" 6.151" 4.276" L-80 TXP 7,240 5,410 604 4-1/2" 3.968 3.833 26,800 L-80 TXP 8430 7500 288 4.0 Drill Pipe Information: Hole 'Section dD in ID(in) TJ TD T.1OD Wt Grade Conn MX Min M/U Max Tension* (k -lbs) Surface& 5" 4.276' 3.25" 6.625" 19.5 S-135 DS50 36,100 43,100 560 Intermediate 5" 4.276" 3.25" 6.625" 19.5 S-135 NC50 25,900 26,800 560 Production 4" 3.34" 2.5625" 4.875" 14 S-135 XT39 18,500 22,200 403 4" 3.34 2.5625 4.875 14 S-135 HT38 12,200 17,700 403 *Tension Rating Based on Premium Pipe 5.0 Casing Inspection All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 Version 1 August 2018 H Hilc� Milne Point Unit L-41 Drilling Procedure 6.0 Internal Reporting Requirements 6.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 6.2 Afternoon Updates • Submit a short operations update each work day to mmyers e hilcorp.com, pmazzolini@hilcorp.com , jengelghilcorp.com and cdin er .hilco[p.com 6.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 6.4 EHS Incident Reporting • Health and safety: Notify EHS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drlg Manager & Drlg Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 6.5 Casing Tally • Send final "As -Run" Casing tally to iengel@hilcoip.com and cdinger(a hilcorp.com 6.6 Casing and Cement report • Send casing and cement report for each string of casing to *engel@hilcom.com and cdinger@hilco!p.com 6.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 ienael@hilcorp.com Completion Engineer Paul Chan 907.777.8333 907.444.2881 pchan@hilcorp.com Geologist Radu Girbacea 907.777.8324 907.230.9490 rairbacea@hilcorp.com Reservoir Engineer Almas Aitkulov 907.777.8475 979.739.3133 aaitkulov@hilcorp.com Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350.9439 kflemine@hilcorp.com Safety Manager Chet Starke] 907.777.8344 406.544.7862 cstarkel@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 Version 1 August 2018 H Hilcorp 7.0 Planned Wellbore Schematic Milne Point Unit L-41 Drilling Procedure Milne Point Unit Well: MPL-41 Proposed Schematic Last Completed: TBD DILv.a :uukn. L_I PTD: TBD Org KBEIev_SIT /GL E)e :ME TD=:U, (MD)/TD-17,725'(W PBrD=31,500' (MD)/PBID=~7,643' OXq TREE & WELLHEAD Tree I TBD Wellhead I TBD OPEN HOLE /CEMENT DETAIL Can4uccor OAven 12-1/4' 1 Ste 11685 ft3/458 ft3, Stg 2 03 314 ft3 9-7/8^x&1(r" I 202ft3 ;1- 6-18" 1 142ft3 �f CASING DETAIL Size Type Wt/ Grade/ Conn I ID I Top Btm I BPF i-1/2^ I Liner I 126/L40/TKP 1 3920 1 I0,s50' I 21,MT -I I TUBING DETAIL WELL INCLINATION DETAIL KOP $�P,00' Maz Hale Mgle 99 Sa,^e JEWELRY DETAIL 1 Na. Top MD Hem ID 1 i10,0DD' 41(Y x r Packer 2 ±1005P I 412^KNNip 3 2m sw Mob Shx 4 10550' UnerT Packer GENERAL WELL INFO API: TBD Conn,,Ldw Dace -TBD Edn.d 6, U] 8-9-2018 Page 6 Version I August 2018 n Hilcorp Milne Point Unit L-41 Drilling Procedure 8.0 Drilling / Completion Summary MPU L-41 is a grassroots oil production well, targeting the Kuparuk River Pool, located on Milne Point `L - Pad'. The directional plan is a three string slant well, with the kick off point at ±600' MD/TVD. Maximum hole angle is 59 degrees at ±2,330 MD. Drilling operations are expected to commence approximately August 241h, 2018, pending rig schedule. Surface casing will be run to 3;,.136V MD / 4,850' TVD and cemented to surface via a two stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, a Temp log will be run between 6 —18 hrs after CEP to determine TOC. Necessary remedial action will then be discussed with AOGCC. Intermediate casing will be run to ±10,697' MD / 6,888' TVD, landed in the Upper Kalubik and cemented via a single stage cement job bringing cement to 500' MD (minimum) above shoe depth. Although normal pressure in the Kupuark is expected, prior wells in this fault block have encountered high pressure. Top setting intermediate casing is being done as a precaution. Production liner will be 4.5" 12.6# L-80 cemented liner run to 11,586' MD / 7,725' TVD, landed just below Kuparuk A. A 4-1/2" frac string with packer will be run. After reviewing the LWD logs obtained while drilling the well, a determination will be made whether or not fracture stimulation will be performed at a later date. Cr�j The base plan, however, is to fracture stimulate the Kuparuk reservoir. A separate sundry will be submitted for hydraulic fracture stimulation and completion operations. All waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility located on `B" pad. General sequence of operations: 1. MIRU Doyon 14 2. N/U 21-1/4"annular and 16" diverter line & Test 3. Drill 12-1/4" hole to TD of surface hole section 4. Run and Cement 9-5/8" surface casing 5. N/D diverter, N/U & test 13-5/8" x 5M BOPE 6. Drill 8-1/2" x 9-7/8" hole to TD 7. Run and cement 7" intermediate casing 8. Drill 6-1/8" hole to TD 9. Run 4-1/2" production liner & Cement 10. Run 4-1/2" Frac String 11. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface Hole: No mud logging. LWD: GR + Res ' 2. Intermediate Hole: No mud logging. LWD: GR + Res 3. Production Hole: No mud logging. LWD: GR + Res Page 7 Version 1 August 2018 H Hilcrp ..22 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Milne Point Unit L-41 Drilling Procedure 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-41. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/4000 psi & subsequent tests of the BOP equipment will be to 250/4000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, Notify AOGCC and test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". • Ensure AOGCC approved drilling permit is posted on the rig floor and in Cc Man office. AOGCC Regulation Variance Requests: • There are no variance requests at this time. Page 8 Version 1 August 2018 0 Hilc� Summary of BOP Equipment and Test Requirements Milne Point Unit L-41 Drilling Procedure Hole Section Equipment Test Pressure(psi) 12 1/4" • 21-1/4" 2M Diverter w/ 16" Diverter Line Function Test Only • 13-5/8" x 5M Hydril "GK" Annular BOP 4 0"> • 13-5/8" x 5M Hydril MPL Double Gate Initial Test: 250.(4986" o Blind ram in btm cavity • Mud cross w/ 3" x 5M side outlets 8-1/2" 13-5/8" x 5M Hydril MPL Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 25046ff qv • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: iim.reag@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 Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: httn://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Version 1 August 2018 H Hilcorp 1'1-p 10.0 RX and Preparatory Work Milne Point Unit L-41 Drilling Procedure 10.1 L-41 will utilizes a 20" conductor with newly set cellar on L Pad. Ensure to review attached surface plat and make sure site is ready to accept rig over conductor. 10.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 10.3 Ensure landing ring is installed on conductor. 10.4 Ensure (2) 4" threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. 10.5 Level pad and ensure enough room for layout of rig footprint and RAJ. 10.6 Ensure rig mats cover entire footprint of rig 10.7 MIRU Doyon 14, Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 10.8 Mud loggers will not be used on L-41 10.9 Mix spud mud for 12-1/4" surface hole section. Ensure mud temperatures are cool (<800F). 10.10 Set test plug prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 10.11 Ensure 6" liners in mud pumps. • Continental EMSCO FB -1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. FA Page 10 Version 1 August 2018 H Hilcorp 11.0 N/U 21-1/4" 2M Diverter System Milne Point Unit L-41 Drilling Procedure 11.1 N/U 21-1/4" Hydril MSP 2M diverter System (Diverter Schematic attached to program). • 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. 11.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 11.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking. A prohibition on ignition sources or running equipment. A prohibition on staged equipment or materials. Restriction of traffic to essential foot or vehicle traffic only. 11.4 Set wear bushing in wellhead. Page 11 Version 1 August 2018 H Hilcorp 11.5 Approximate Rig & Diverter Orientation (Drawing not to scale): Milne Point Unit L-41 Drilling Procedure 32 28 24 20 13 ■ ■ 8 i 39 ■ ❑ 42 41 5 34 ■ 4 3 ■ ■ S ■ = 4a 2 ■ ■ 7 12 ■ 40 ❑ "'" ' 3 �o 75' Radius Clear of Ignition Sources aiw� I_I ^ - - - - Diverter Line *Drawing Not To Scale MPU L -Pad Page 12 Version I August2018 32 ■ 33 ■ 28 ■ 29 ■ 24 ■ 25 ■ 20 ■ 21 ■ 414 +43 I Milne Point Unit L-41 Drilling Procedure 32 28 24 20 13 ■ ■ 8 i 39 ■ ❑ 42 41 5 34 ■ 4 3 ■ ■ S ■ = 4a 2 ■ ■ 7 12 ■ 40 ❑ "'" ' 3 �o 75' Radius Clear of Ignition Sources aiw� I_I ^ - - - - Diverter Line *Drawing Not To Scale MPU L -Pad Page 12 Version I August2018 R Hilcorp 12.0 Drill 12-1/4" Hole Section Milne Point Unit L-41 Drilling Procedure 12.1 P/U 12-1/4" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub so that wireline orientation is possible if necessary. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill pipe will be 5" 19.5# 5-135 NC50 & DS50 • Run a solid float in the surface hole section. 12.2 5" drill pipe, 5" HWDP, and Jars will come from Weatherford. 12.3 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. 12.4 Drill 12-1/4" hole section to section TD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. Target TD approximately 100' TVD through the base of the permafrost. Permafrost base is estimated at 1850' TVD • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation. • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 450-600 gpm. Monitor shakers closely to ensure shaker screen and return lines can handle the flow rate • Ensure not to out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Slow in/out of slips and while tripping to keep swab and surge pressures low • Make wiper trips if necessary. • Adjust MW and viscosity as necessary to maintain hole stability. Ensure MW at TD is 9.2 minimum. • Take MWD surveys every stand drilled. • No gas hydrates have been encountered on L Pad wells, however be prepared if hydrates are seen: Do not stop to circulate out gas hydrates — this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be V/ Page 13 Version 1 August 2018 H Hilcorp F� ��y Milne Point Unit L-41 Drilling Procedure reduced to prevent mud from belching over the bell nipple. Consider adding mud products such as Lecithin to allow the gas to break out. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling, packing off or running gravels • Do not stop to circulate on wiper trips with bit across a slide interval, especially not in an area where DLS is > 4. • Do not slide for 100' MD above the base of the permafrost or 100' below the base. We want to leave this transition as undisturbed as possible. • Ensure TD of the hole section is — 100' TVD below Schrader Bluff Sands, confirm with Geologist 12.5 12-1/4" hole mud program summary • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. • PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, and Toolpusher office • Rheology: Aquagel and viscosifier should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: POLYPAC SUPREME should be used for filtrate control. Background LCM (5 ppb total) SAFECARB can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of SCREENKLEEN are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high -clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 — 9.0 range with caustic soda. Daily additions of Busan 1060 MUST be made to control bacterial action. • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type: 8.8 — 9.5 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties: Section I Density Viscosity Plastic Viscosity Yield Point I AN FL Ternp I pH Surface 1 8.8-9.5' 75-175 1 20-40 25-45 1 <10 <70°F 1 8.5-9.0 Page 14 Version 1 August 2018 Milne Point Unit L-41 Drilling Procedure Hilcorp System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M -I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 Pol Pac Supreme UL 50 lb sx 0.08 Caustic Soda 50 Ib sx 0.1 SCREENCLEEN 55 gal dm 0.5 12.6 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 12.7 RIH t/ bottom, proceed to BROOH t/ HWDP • Pump at full drill rate (400-600 gpm), and maximize rotation. • Pull slowly, 5 — 10 ft / minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. WA30GoOl64 STIt 11 :1M 12.9 No open hole logging program planned. Page 15 Version 1 August 2018 H Hilcorp 13.0 Run 9-5/8" Surface Casing 13.1 R/U and pull wear bushing. Milne Point Unit L-41 Drilling Procedure 13.2 9-5/8" Surface casing will be set with slips to ensure complete circulation and returns during cement job. 13.3 R/U Weatherford 9-5/8" casing running equipment (CRT & Tongs) • Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 13.4 P/U shoe joint, visually verify no debris inside joint. 13.5 Continue M/U & thread locking 120' shoe track assembly consisting of: 9-5/8" Float Shoe I joint — 9-5/8" TXP, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" TXP, 1 Centralizer mid joint w/ stop ring 9-5/8" Float Collar w/ Stage Cementer Bypass Baffle 'Top Hat' 1 joint — 9-5/8" TXP, 1 Centralizer mid joint with stop ring 9-5/8" HES Baffle Adaptor • Ensure bypass baffle is correctly installed on top of float collar. This end up. Bypass Baffle • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 16 Version 1 August 2018 I/ H Hilcorp 13.6 Float equipment and Stage tool equipment drawings: "A 0,e,SN Lengm Type H ES Cementer Part No. SO No. Closing Sleeve No. Shear Pins Opening Sleeve No. Shear Fins ES Cementer Depth Battle Adapter (it used) ID Depth Bypass or Shutoff Baine ID Depth Float Collar Depth Float Shm Depth Hole TD "Feference Carno $alas Llanual $FCLCn � B Mm, ID Aller Dnllwt C Max_ TW OD D Openig Seat ID E Clot" Seat ID Plug Set Part No. SO No. Closing Plug W— OD Opening Plug 00- Do- Shut-off DODShut-off Plug oD Bypass Plug (if used) OD Milne Point Unit L-41 Drilling Procedure 13.7 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: • 1 centralizer every joint t/ — 1000' MD from shoe • 1 centralizer every 2 joints to 2,000' above shoe (Top of Ugnu) • Verify depth of lowest Ugnu water sand for isolation with Geologist Page 17 Version 1 August 2019 Retare ELII Banning Order ESB Um" Shm ON VAg Bartle AEaµer fl . t r ". By-0at Rug r r L� By pus Mete Fiwt colla. IiortSlue 13.7 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: • 1 centralizer every joint t/ — 1000' MD from shoe • 1 centralizer every 2 joints to 2,000' above shoe (Top of Ugnu) • Verify depth of lowest Ugnu water sand for isolation with Geologist Page 17 Version 1 August 2019 H Hilcorp Milne Point Unit L-41 Drilling Procedure • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. Establish circulation if needed. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 13.8 Install the Halliburton Type H ESIPC tool so that it is positioned at least 100' TVD below the permafrost (— 2,500' MD). • Install centralizers over couplings on 5 joints below and 10 joints above stage tool • Instal centralizers I/2 joints to base of conductor • Do not place tongs on ES cementer, this can cause damaged to the tool. • Ensure tool is pinned properly. ESIPC packer to inflate at — 2080 psi, and the tool to open at 3000 psi. Reference ESIPC Procedure. 9-5/8" 409 L-80 TXP Make Up Torques: Casing OD Min M/U Torque Max M/U Torque 9-5/8" 18,860 ft -lbs 23,060 ft -lbs Page 18 Version 1 August 2018 Milne Point Unit L-41 Drilling Procedure Hilcorp TXPO BTC .,--01122J2016 Outside Diameter 9,625 in Min. Wall 87.5% Thickness 41 Grade LBO l'P Tension EBY.kcty 100.0% Jo" Yield Strength 916001 111,'U Wemal Pressure Capacity t' 5750.000 psi Type 1 Wall Thickness 0 395 m Connection OD REGULAR 916.000x164 Max Akmable Bercing 38'1100€1 Option COUPLING PIPE BO6y Body: Red 1s[ nand: Red Grade LBO Type 1 • Drift API Standard 1st Bard: Brown 2nd band: 2nd Band - Brown Type Casing 3rd Band. - 3rd Band- - 4th Band: - PIPE 60Dy DATA GEOMETRY Nominal OD 9.625 in. Nominai Weight 40lbvri Lott 0 BM r Nominal ED 8.835 in. Nall Thickness 0.395 in Plan Erd VPeight 38 97 tzF. OD Tderance AN PERFORMANCE 6n1, Yield Strength 915 xI000lbs Internal Yield 5750 psi SMYS am psi Collapse 3090 psi CONNECTION DATA GEOMETRY__ Canes.-tian OD 10.625 in. Coping Length 16825b.. Cmnectm ID 8573 iL Wk -up Los UM in Tuards perp 5 CcnnazCan 00 Cpm REGULAR PERFORMANCE , Tension EBY.kcty 100.0% Jo" Yield Strength 916001 111,'U Wemal Pressure Capacity t' 5750.000 psi lbs Campresvan Eflivency 100% Cwnpresslon Strength 916.000x164 Max Akmable Bercing 38'1100€1 lbs External Pressure Capatitl 3090.000 psi MAKE-UP TORQUES Afinirnum 188601 -ba Cpemurn 20960 ft4bs Mairxin 23080 fa-tG OPERATION LIMIT TORQUES -ceratng Tcrque 3550084bs YeW Tor 434006Jbs Notes This connection is fully interchangeable with: TXPID BTC - 9.625 in. - 36 143.5 147 153-5 158.4 Ibslfl [1] Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10 3 API 5C31 ISO 10400 - 2007. Page 19 Version 1 August 2018 H Hilcorp Milne Point Unit L-41 Drilling Procedure 13.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 13.10 Slow in and out of slips. 13.11 Lower casing to setting depth. Confirm measurements. 13.12 Have slips staged in the cellar, along with necessary equipment for the operation. 13.13 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. 13.14 Reciprocate casing if possible while conditioning mud. Page 20 Version 1 August 2018 H Hilcorp 14.0 Cement 9-5/8" Surface Casing Milne Point Unit L-41 Drilling Procedure 14.1 Hold a pre job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cement unit at acceptable rates. ■ How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. ■ Which pump will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. ■ Positions and expectations of personnel involved with the cementing operation. • Extra hands in the pits to strap during the cement job to identify any losses ■ Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all iron lines and connections used to route slurry to rig floor. 14.2 Document efficiency of all possible displacement pumps prior to cement job. 14.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 14.4 R/U cementing line (if not already done so). Company rep to witness all plug loading to ensure they are done in the correct order. 14.5 Fill surface lines with water and pressure test. 14.6 Pump remaining 60 bbls 10.0 ppg tuned spacer. 14.7 Drop bottom plug (flexible bypass plug) — HEC rep to witness. Mix and pump cement per below calculations for the 151 stage, confirm actual cement volumes with cementer after TD is reached. 14.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail slurry, and TOC will be brought to the stage tool. Estimated 151 Stage Total Cement Volume: b6 L, 3 Page 21 Version I August 2018 ? '0 12-1/4" OH x 9-5/8" (6637- 2500') x .0558 bpf x 1.3 = 300 1684 J Casing Total Lead 300 1684 12-1/4" OH x 9-5/8" (7637'- 6637) x .0558 bpf x 1.3 = 72.5 407 Casing ~ 9-5/8" Shoe Track 120'x .0758 bpf = 9.1 51.09 Total Tail 81.6 458 Page 21 Version I August 2018 ? '0 n Hilcorp Milne Point Unit L-41 Drilling Procedure Cement Slurry Design (1St stage cement jobs): 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the casing collar depths in mind. If the hole gets "sticky", position casing string at desired depth and continue with cement job. 14.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting spacer across the stage tool. • Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 14.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the shutoff plug must be bumped. 14.12 Displacement calculation: oi"j (7,637' — 120') x .0758 bpf= 569.18 bbl total 40 bbl of weight space to be left behind stage tool. Confirm spacer is compatible with cement behind stage tool 14.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate the any cement seen at surface. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of the shoe track volume, —4.5 bbls before consulting with drilling engineer. 14.15 If the plug is not bumped, consult the drilling engineer. Ensure the free falls stage tool opening plug is available if needed. This is the backup option to open the stage tool if the plugs are not bumped. 14.16 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. Page 22 Version I August 2018 Lead Slurry Tail Slurry System ExtendaCEM TM System SwiftCEM TM System (Hal Cem) Density 11.7 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed Water 21.13 gal/sk 5.04 gal/sk 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the casing collar depths in mind. If the hole gets "sticky", position casing string at desired depth and continue with cement job. 14.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting spacer across the stage tool. • Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 14.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the shutoff plug must be bumped. 14.12 Displacement calculation: oi"j (7,637' — 120') x .0758 bpf= 569.18 bbl total 40 bbl of weight space to be left behind stage tool. Confirm spacer is compatible with cement behind stage tool 14.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate the any cement seen at surface. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of the shoe track volume, —4.5 bbls before consulting with drilling engineer. 14.15 If the plug is not bumped, consult the drilling engineer. Ensure the free falls stage tool opening plug is available if needed. This is the backup option to open the stage tool if the plugs are not bumped. 14.16 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. Page 22 Version I August 2018 H Hilcorp Milne Point Unit L-41 Drilling Procedure 14.17 Increase pressure to 2090 psi to shift ESIPC sleeve and to begin inflating the packer. Inflate packer as per HEC rep. Reference ESIPC procedure. 14.18 Once ESIPC packer is inflated, increase pressure to --3000 psi to open rupture disc /circulating ports in stage collar. Slightly higher pressure may—Fe if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 14.19 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 23 Version I August 2018 n Hilcorp Eov® Gnnpmy Milne Point Unit L-41 Drilling Procedure Second Stage Surface Cement Job: 14.20 Prepare for the 2"d stage as necessary. If ESIPC packer inflates, there is no need to wait on compressive strength of first stage, if there are any issues with the ESIPC, wait until first stage has reached sufficient compressive strength. Hold pre job safety meeting. 14.21 HEC representative to witness the loading of the ESIPC cementer closing plug in the cementing head. 14.22 Fill surface lines with water and pressure test. 14.23 Pump remaining 60 bbls 10.5 ppg tuned spacer. 14.24 Mix and pump cement per below recipe for the 2"d stage. 14.25 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Based upon first stage volume circulated back to surface and hole gauges sweeps, lead cement excess could be reduced to 150%. Estimate "d Stag otal Cement Volume: Cement Slurry Design (2nd stage cement Job): Section Calculation Vol (bbl) Vol (ft3) SwiftCEM 'M System (Hal Cem) 20" Conductorx 9-5/8" Casing (110') x.26 bpf x 1= 28.6 161 J 12-1 4" OH x 9-5/8" Casing (2000' - 110') x .0558 bpf x 3 = 316.4 1776.3 Total Lead 345 1937 12-1/4" OH x 9-5/8" Casing (2500'- 2000') x .0558 bpf x 2 = 55.8 314 ~ Total Tail 55.8 314 Cement Slurry Design (2nd stage cement Job): 14.28 Continue pumping lead cement until uncontaminated spacer is seen at surface, then switch to tail. 14.29 After pumping cement, drop ESIPC closing plug and displace cement with rig pumps, using spud mud in mud pits. 14.30 Displacement Calculation: 2500' x.0758 bpf = 190 bbls mud Page 24 Version 1 August 2018 Lead Slurry Tail Slurry System Permafrost L SwiftCEM 'M System (Hal Cem) Density 10.7 lb/gal 15.8 lb/gal Yield 4.3279 ft3/sk 1.16 ft3/sk Mixed Water 21.405 gal/sk 5.08 gal/sk 14.28 Continue pumping lead cement until uncontaminated spacer is seen at surface, then switch to tail. 14.29 After pumping cement, drop ESIPC closing plug and displace cement with rig pumps, using spud mud in mud pits. 14.30 Displacement Calculation: 2500' x.0758 bpf = 190 bbls mud Page 24 Version 1 August 2018 n Hilcorp Milne Point Unit L-41 Drilling Procedure 14.31 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 14.32 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 14.33 Land closing plug on stage collar and pressure up to 1000 — 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips as per wellhead rep. 14.34 Flush out wellhead with FW and BOP stack thoroughly to ensure cement, mud and cuttings are removed. 14.35 M/U pack -off running tool and pack -off to bottom of final joint. Set casing hanger packoff. Inject plastic packing element. Pressure test packof. . 14.36 Lay down cut joint and pack -off running tool. Ensure to report the following on WeIIEZ: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • If losses are seen during cement job, note at operation during the cement job they were observed and where the cement was • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the successor problems during the cement job Send final "As -Run" casing tally & casing and cement report to engej@hilcorp.com and cdin e�rghilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 25 Version 1 August 2018 H Hilcorp 15.0 BOPE N/U, Test, and Wellhead Installation Milne Point Unit L-41 Drilling Procedure 15.1 N/D the diverter T, 16" knife gate, 16" diverter line & N/U 11"x 13-5/8" 5M casing spool. 15.2 NIU 13-5/8" x 5M BOP as follows: • BOP configuration from top down: 13-5/8" x 5M annular / 13-5/8" x 5M double gate / 13- 5/8" x 5M mud cross / 13-5/8" x 5M single gate • Double gate ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in bottom cavity. • Single ram can be dressed with 2-7/8" x 5" VBRs • N/U bell nipple, install flowline. • Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 15.3 Run 5" BOP test assembly, land out test plug (if not installed previously). 15.4 Test BOP to 250/4000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Confirmtest pressures with PTD • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure /<G is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 15.5 R/D BOP test equipment 15.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 15.7 Mix 9.5 ppg LSND fluid for intermediate hole section. 15.8 Set wear bushing in wellhead. 15.9 If needed, rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 15.10 Ensure 6" liners in mud pumps. Page 26 Version 1 August 2018 n Hilcorp 16.0 Drill 8.5" x 9.875" Intermediate Hole Section Milne Point Unit L-41 Drilling Procedure 16.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.220 PDM) 16.2 TIH w/ 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 16.3 Managed Pressure Drilling will be used on the intermediate and production hole sections. Prior to drilling out the shoe track, install RCD bearing element and perform practice connections to familiarize crews with its operations. 16.4 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. C64"rtit&- 16.5 R/U and test casing to 2500 psi / 30 njLn. Ensure to record volume / pressure and plot on FIT graph. AOGCC reg is 3U77of burst but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 1 5 x . Ste' 0-879'p7.: 16.6 Drill out shoe track and 20' of new formation. Q qOO 16.7 Displace wellbore to 9.5 ppg LSND for FIT 16.8 OWFF and pull into casing shoe. 16.9 Conduct FIT to 12.5 ppg EMW. If 12.5 ppg EMW is not obtained call and discuss with Drilling Engineer. LGIR111316161awwre NARWr, Bill 111110 16.11 P/U 8.5" x 9.875" Rotary Steerable Directional Assembly w/ Under Reamer • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure MWD is R/U and operational. ' • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill pipe will be 5" 19.5# S-135, NC50 & DS50. • Run x2 Solid Plunger Floats for MPD Page 27 Version 1 August 2018 H Hilcorp 16.12 8.5" x 9.875" hole section mud program summary: Milne Point Unit L-41 Drilling Procedure • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Ensure 6 rpm is >9.875 (hole diameter) for sufficient hole cleaning, YP as low as possible • Inhibition: 3% KCl will be used for handling clay cuttings. Watch MBT levels, dilute as necessary to maintain. Increase KCl % if needed • Run the centrifuge continuously while drilling the production hole, this will help with solids removal and minimize sand content and LGS to maintain fluid properties and quality of the mud system. • PVT will be used throughout the drilling phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 9.5 - 10.8 ppg 3% KCI Inhibited LSND WBM Pro ernes: Section Density Plastic Yield Point LGS MBT HPHT PH Viscosity ntermediate 9.5-10J 15-25 15-20 <b% <20 <1 1.0 9- 16.13 RIH w/ 8.5" x 9.875" directional assembly on 5" DP from the derrick. • Shallow test MWD to confirm tool communication • Slow string speed when tripping through the stage collar 16.14 Drill — 100' of 8.5" Hole • Enough hole to bury RSS BHA and clear UR blades from casing shoe • RPM: 120+ • Flow Rate: 350-400 gpm • WOB as needed 16.15 Circulate hole clean, drop ball and open under reamer. • Indication of open under reamer will be pump pressure and turbine RPM • Perform pull test to confirm UR is open as well Page 28 Version 1 August 2018 N Hilcorp 16.16 Drill 8.5" x 9.875" Hole to — 500' MD above HRZ, 10,032' MD • RPM: 120+ Milne Point Unit L-41 Drilling Procedure • Flow Rate: 600 GPM (200 ft/min Annular Velocity) • Ensure shaker screens are set up to handle this flow rate, shakers running slightly wet to maximize solids removal efficiency. Check for holes on screens on every connection. • WOB as needed • Pump tandem high vise high weight / low vise low weight sweeps to aid in hole cleaning • Take MWD surveys every stand • Monitor hole cleaning indicators: PUW, pump pressure and ECD. Make wiper trips or backream connections if necessary 16.17 CBU x2, perform short trip to shoe if necessary • RPM: 120+ Flow Rate: 600 GPM (200 ft/min Annular Velocity) Alternate reciprocation depths to avoid troughing/ledging 16.18 Increase MW to 10.3 ppg • Increase MW with pre sheared spike fluid, in .3 ppg per circulation, this is to ensure no barite sag or uneven density • Add black products for shale stability as well 16.19 Install MPD Element V • Ensure rig crew is familiar with MPD connection operations • Ensure max pressure relief settings are set correction to ensure no wellbore damage is created 16.20 Drill 8.5" x 9.875" hole section to section TD per Geologist and Drilling Engineer in Upper Kalubik (To mitigate trapped injection pressure potential), 10,697' MD • RPM: 120+ • Flow Rate: 600 GPM (200 ft/min Annular Velocity) • WOB as needed • Target ECD: 11.5 ppg EMW ' • Utilize MPD to maintain CBHP (constant bottom hole pressure) on connections, following Annular pressure ramp schedule • This will reduce the pumps on/ pumps off pressure cycles on shales • Slow ramp pumps on/off on each connection • Smooth connections are more important that connection time • Pump tandem high vise high weight / low vise low weight sweeps to aid in hole cleaning, monitor ECD effect of sweeps • Take MWD surveys every stand • Monitor hole cleaning indicators: PUW, pump pressure and ECD. Make wiper trips or backream connections if necessary • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. Page 29 Version 1 August 2018 H Hilcorp Milne Point Unit L-41 Drilling Procedure 16.21 At TD; CBU at full rate and RPM least 4-5 times at maximum circulation and rotation. Alternate reciprocation depths while CBU to reduce risk of troughing and dropping inclination. Under reamer will be open during CBU, to maximize flow and hole cleaning. 16.22 Once hole is cleaned up, drop ball and close under reamer. Indications will be pump pressure and turbine rpm change. 16.23 Perform wiper trip t/ above the HRZ, offsetting swab with MPD 16.24 RIH to bottom Slow string speed to limit surge on shales 16.25 Weight up at TD for shale stability, ±10.8 ppg, maintaining CHBP of 11.5 ppg EMW - • Perform weight up with pre -sheared spike fluid, weighting up with .3 ppg increments 16.26 Observe well for flow 16.27 Spot Casing Running Pill 16.28 TOOH with the drilling assembly t/ 9-5/8" Shoe, Offsetting Swab with MPD • Follow tripping schedule, matching string speed and annular pressure • Rack back DP while TOOH, Do not lay down drill pipe. This is to minimize open hole time before casing is on bottom. 16.29 If backreaming is necessary: • Circulate at max rate while maintaining drilling ECD's (flow will be less due to 10.8 ppg MW) • Perform CBHP connections • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe and circ at least a b/u once at the shoe. 16.30 CBU x2 at 9-5/8" Shoe 16.31 Continue TOOH to HWDP/ BHA, offsetting swab with MPD 16.32 Pull RCD Bearing element 16.33 LD BHA 16.34 No open hole wire line logs are planned. Page 30 Version 1 August 2018 H Hilcorp 17.0 Run 7" Intermediate Casing Milne Point Unit L-41 Drilling Procedure 17.1 Change top rams to 7" solid body's for casing run. Test 250/4000psi. Chart test. 17.2 R/U 7" casing running equipment. • Ensure 7" TXP (BTC Compatible) x NC50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted prior to running. • Be sure to count the total # of joints before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. • R/U CRT w/ cement swivel. 17.3 M/U & threadlock shoe track assy consisting of: • (1) Float shoe joint w/ float shoe bucked on. Install (2) solid body centralizers over a stop ring at 10' from each end. • (1) Baker locked joint. Install (1) solid body centralizer mid joint over a stop ring • (1) Float collar joint w/ float collar bucked on pin end. Install (1) solid body centralizer mid tube over a stop ring. • Ensure proper operation of float shoe and float collar. 17.4 Run 7" 26# L-80 TXP casing. • Fill casing while running using CRT or fill up line. • Use "BOL 2000" thread compound. Dope pin end only w/ paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install centralizers on every joint to 500' above shoe depth. • Install 3 centralizers across 9-5/8" casing shoe. 17.5 RIH following casing running schedule, keeping surge below max drilling ECD EMW • Circulate BU — 500' above HRZ (10,032' MD) to ensure mud is conditioned prior to RIH • Monitor SOW while RIH, circulate BU if needed 17.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. Slow in and out of slips. 17.7 17.8 17.9 Lower string to depth. MU hanger and landing joint. Casing will be set on depth with hanger. Circulation and condition mud for cement job through CRT. Reduce YP to < 20 to help ensure success of cement job. After circulating, set string at setting depth. 7" Casing Torque Values Connection MUT (Min) MUT (Opt) MUT (Max) Max Operating ft -lb ft -lb ft -Ib Torque, ft -lb HTTC 13,280 14,750 16,230 20,000 Milne Point Unit L-41 Drilling Procedure Hilcorp � c—, TXP® BTC ---05709r2018 Outside Diameter 7.000 is Min. Wall 873% GEOMETRY GEOMETRY Thickness 10.200 in. (') Grade L80 low Namnal OD 7.000 in. NomtrW Atghl 26 IM Type 1 6.151 in. Wall Thickness 0.362 in Connection OD REGULAR Plain End Vk4ght 25.691 Itt. OD Tdererrs API Option COUPLING pimemy Max.AAxaable Bending 52'11000 Its Body: Red 1st Band: Red Grade I LBO Type P Drift API standard 1st Band: Brown 2nd Band' Body Yield Strength 604 x10001bs Internal Yield 7240 psi 2nd Band. - Brown Calapse 5410 psi Type Casing 3rd Band:- 3rd Band :- Notes This connection is fully interchangeable with: 4th Band: - PIPE E:GDti" '--,ATA GEOMETRY GEOMETRY Connection OD 7-556 in Coupling Le,a h 10.200 in. Ce .ectcn ID 6261 st Namnal OD 7.000 in. NomtrW Atghl 26 IM Drift 6.151 in. Nanlnal ID 6276 in. Wall Thickness 0.362 in. Plain End Vk4ght 25.691 Itt. OD Tdererrs API Cempiessim EffLiency 100% Compressun Suarcyth 604.000x1LC0 Max.AAxaable Bending 52'11000 Its PERFORMANCE MAKE-UP TORQUES Body Yield Strength 604 x10001bs Internal Yield 7240 psi SMys 80000 psi Calapse 5410 psi Operating Torque 200000.Ts Yeld Tangw 23400 ft -lbs CONNECTION DATA GEOMETRY Connection OD 7-556 in Coupling Le,a h 10.200 in. Ce .ectcn ID 6261 st Make-up Lose 1.578 in. Threads per m 5 Connection OD Opecn REGULAR PERFORMANCE _ _ — I Tension Effcismcy 100.0% Joie Yeld Strength 604.000 x7CCD irkmal Pressure Capadty I 7240.000 psi lbs Cempiessim EffLiency 100% Compressun Suarcyth 604.000x1LC0 Max.AAxaable Bending 52'11000 Its External Prtssure Capacity 5410.000 psi MAKE-UP TORQUES Mninlum 13280 ft -lbs Opurnun 14730 Mimi kdaxrmrn 16230 ft -t¢ OPERATION LIMIT TORQUES Operating Torque 200000.Ts Yeld Tangw 23400 ft -lbs Notes This connection is fully interchangeable with: TXPiD BTC - 7 in. - 23 / 29 / 321 35 / 38 Ibslft Page 32 Version 1 August 2018 H Hilcorp � ��y 18.0 Cement 7" Intermediate Casing Milne Point Unit L-41 Drilling Procedure 18.1 Hold a pre job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. • How to handle cement returns at surface, regardless of how unlikely it • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cement operation. • Extra hands in the pits to strap during the cement job to identify any losses • Document efficiency of all possible displacement pumps prior to cement job. 18.2 7" cement job will be a single stage, single slurry job. 18.3 RU Cement lines to cement swivel on CRT. Plugs will be dropped manually. 18.4 Pump 5 bbls fresh water. Pressure test surface cement lines to 4000 psi. 18.5 Pump remaining 40 bbls 10.5 ppg spacer. 18.6 Drop bottom plug, Mix and pump slurry per below calculations, 40% OH excess volume: Section: Calculation: VolVol (ft3) 9.875" OH x 7" Casing: (10,697'— 10,197') x 0.0471 bpf x 1.4 = 33 185.3 7" Shoe Track: 80' x .038 bpf= 3 16.8 Total Volume: 36 202 Slurry Information 18.7 After pumping cement, drop top plug and displace cement with drilling mud. Use rig pumps for displacement. Ensure to have a good baseline measurement for pump displacement ahead of time. Displacement calcs: 10,617' x .038 bpf = 403.4 bbls. Page 33 Version 1 August 2018 Cement Slurry System ExpandaCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mixed Water 4.972 gal/sk 18.7 After pumping cement, drop top plug and displace cement with drilling mud. Use rig pumps for displacement. Ensure to have a good baseline measurement for pump displacement ahead of time. Displacement calcs: 10,617' x .038 bpf = 403.4 bbls. Page 33 Version 1 August 2018 H Hilcorp Milne Point Unit L-41 Drilling Procedure 18.8 Reciprocate casing during cement job. If at any time pipe movement gets sticky, land casing hanger. 18.9 Monitor returns closely while displacing cement. Ensure pits are strapped every 10 bbls of displacement and communicated with Co Rep. If losses are seen, let DSM know and possibly reduce pump rate. 18.10 Do not over displace by more than 1/2 shoe track volume. Total volume in shoe track is 3.5 bbls 18.11 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. If this is the case, monitor the pressure on the casing and do not let it exceed 500 psi over the final pump pressure. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Sendfinal "As -Run" casing tally & casing and cement report to ien.eeL@hilcoW.com and cdin er .hilcorp. com. This will be included with rhe EOW documentation that Qoes to the AOGCC. 18.12 R/D cementing equipment. Flush out wellhead with FW. 18.13 Test void to 250/4000 psi for 10 min. 18.14 Freeze protect 9-5/8" x 7" Annulus 18.15 Lay down 5" DP. Page 34 Version 1 August 2018 n Hilcorp 19.0 Drill 6-1/8" Production Hole Section Milne Point Unit L-41 Drilling Procedure 19.1 Change upper pipe rams back to 2-7/8" x 5" VBR. Test to 250/4000. Chart Test 19.2 P/U 6-1/8" RSS Directional BHA • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. • Workstring will be 4" 14# S-135 HT -38 / XT 39 • Run x2 Solid Plunger Floats for MPD 19.3 6-1/8" hole mud program summary: 1� • Density: Although Kuparuk pressures are predicted to be normal, past wells in this fault block <: have seen higher pressure. 12.5 ppg will be used as a precaution. Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Ensure 6 rpm is >9.875 (hole diameter) for sufficient hole cleaning, YP as low as possible • Inhibition: 3% KCl will be used for inhibition. Watch MBT levels, dilute as necessary to maintain. Increase KCl % if needed • Run the centrifuge continuously while drilling the production hole, this will help with solids removal and minimize sand content and LGS to maintain fluid properties and quality of the mud system. • PVT will be used throughout the drilling phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 12.5ppg 3% KCl Inhibited LSND WBM Properties: Section Densit I Viscosity Plastic Viscosity Yield Point Total Solids MBT H 6-1/8" 12.5 75-175 15-25 15-25 <10% <7 Page 35 Version I August 2018 H Hilmrp Milne Point Unit L-41 Drilling Procedure 19.4 TIH w/ 6-1/8" directional assembly on 4" DP to above TOC. Shallow test MWD and LWD on trip in. 19.5 Note depth of TOC on morning report. Circulate bottoms up. SO a '7" Z& jr 19.6 R/U and test casing to 3_�n i / 4D min. Ensure to record volume / pressure and plot on FIT graph. AOGCC regulation is 50% of burst. 19.7 Ensure even 12.5ppg MW in and out before drilling shoe track 19.8 Drill out shoe track and 20' of new formation. 19.9 CBU and condition mud for FIT. 19.10 Conduct FIT to 14.0 ppg EMW. 19.11 Install MPD Element Ensure rig crew is familiar with MPD connection operations Ensure max pressure relief settings are set correction to ensure no wellbore damage is created 19.12 Drill 6-1/8" hole section to section TD per Geologist and Drilling Engineer. • Flow Rate: 150-250 gpm (Target 200 ft/min AV) • RPM: 120 — for hole cleaning • WOB as needed • Target ECD and CBHP: 14.0 ppg EMW • Utilize MPD to maintain CBHP (constant bottom hole pressure) on connections, following Annular pressure ramp schedule • This will reduce the pumps on/ pumps off pressure cycles on shales • Slow ramp pumps on/off on each connection • Smooth connections are more important that connection time • Take MWD surveys every stand drilled. • 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. 19.13 At TD; CBU at least 3 times at maximum circulation and rotation, and pull a wiper trip back to the window. If backreaming is necessary: • Circulate at full drill rate (150-250 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. Page 36 Version I August 2018 n Hilcorp Milne Point Unit L-41 Drilling Procedure 19.14 Observe well for flow, weight up if needed. MW at TD may be determined by connection monitoring while drilling this hole section. 19.15 TOOH with the drilling assembly t/ 7" Shoe, Offsetting Swab with MPD • Follow tripping schedule, matching string speed and annular pressure • Rack back DP while TOOH, Do not lay down drill pipe. This is to minimize open hole time before liner is on bottom. 19.16 If backreaming is necessary: • Circulate at max rate while maintaining drilling ECD's • Perform CBHP connections • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe and circ at least a b/u once at the shoe. 19.17 CBU at 7" Shoe 19.18 Continue TOOH to HWDP/ BHA, offsetting swab with MPD • Once inside casing, drop rabbit on remaining drillpipe on TOOH that will be used to run the 4.5" liner. Confirm diameter drift with Baker for setting liner hanger 19.19 Pull RCD Bearing element at HWDP 19.20 L/D 6-1/8" BHA 19.21 No additional logs are planned for the 6-1/8" hole section. Page 37 Version 1 August 2018 H Hilcorp 20.0 20.1 20.2 Run 4-1/2" Liner Ensure rams have been tested on 4-1/2" test joint prior to running liner. Ensure wear bushing is installed in wellhead. 20.3 R/U 4-1/2" casing running equipment. • Ensure 4-t/2" TXP crossover is on rig floor and M/U to FOSV. Milne Point Unit L-41 Drilling Procedure • Ensure all casing has been drifted prior to running. • Be sure to count the total # of joints before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 20.4 Run 4-1/2" liner per completion tally. • Dope pin end only w/ paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Run 1 centralizer per joint for the entire liner 4-1/2" Tenaris TXP Make Up Torques Casing OD Minimum Optimum Maximum 4.5" 5,550 ft -lbs 6,170 ft -lbs 6,790 ft -lbs 4-1/2" Tenaris TXP Operating Limit Torques Casing OD Operating Yield 4.5" 6,790 ft -lbs 8,890 ft -lbs Page 38 Version 1 August 2018 CONNECTION DATA GEOMETRY _ Connection OD 5.000 in. Cop:Aing Length 8.075 in. Ccnnection 10 3.996 e. WLa up Loss 4.016 in. rhwds Far:. 5 Connec0cn DD Optan REGULAR PERFORMANCE Milne Point Unit L-41 Ten ---ion Effie ncy 100.0% Jost Yeld SoengN 28&000 x1000 Drilling Procedure Hiloorp lbs Corpres-von Ef€¢iercy 100% Compression Strength a —PA' Mac.Pdvaable Bening at'no 11 Its TXP® BTC .—OW0311018 Outside Diameter 4.508 in Min. Wail 87,5% Thickness (')Grade L90 1101a Type 1 Wall Thickness 0.271 in. Connection DD REGULAR Option COUPLING PIPE BODY Body: Red 1st Band: Red Grade L80 Type 1' Drift API Standard 15t Ba -di: Brown 2nd Band: 2nd Band:- Brown Type Casing 3rd Band: - 3rd Band: - 4th Band: - PIPE BODY DATA GEOMETRY Nwdnal OD 4.500 in. Nominal NY•ght 121bsR Drift 3833 r, Norval 0 3150 in 'Wall Tndness 0171 in. Plan ERd Weight 1225 ts'il OD Tderance AR PERFORMANCE Booy Meld Strength 280 x!000lbs Inerna Yield 8630 psi SLAYS 80000 psi Collapse 7500 psi CONNECTION DATA GEOMETRY _ Connection OD 5.000 in. Cop:Aing Length 8.075 in. Ccnnection 10 3.996 e. WLa up Loss 4.016 in. rhwds Far:. 5 Connec0cn DD Optan REGULAR PERFORMANCE Ten ---ion Effie ncy 100.0% Jost Yeld SoengN 28&000 x1000 Interval Pressure CapeciN"1 8430.000 psi lbs Corpres-von Ef€¢iercy 100% Compression Strength 281L000x1000 Mac.Pdvaable Bening at'no 11 Its Enemal Pressure Capacity 7WD.DD0 psi MAKE-UP TORQUES _-- h8nimum 5550 e -'8s Cpt— 6170ft4bs maunrn 6M 11 -lbs OPERATION LIMIT TORQUES Op-vabng Tcrpue 6703 fits YeliTorqioe 880(ftAs Notes This connection is fully interchangeablie With: TXP& BTC - 4.5 in. - 10.5 111.6 113.51 15.1 Ibsift Page 39 Version 1 August 2018 H Hilcorp �y Milne Point Unit L-41 Drilling Procedure 20.5 Ensure to run enough liner to provide for approx 150' overlap inside 7" casing. Ensure hanger/pkr will not be set in a 7" connection and the packer should be above the 7" float collar. 20.6 Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 20.7 M/U 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 packof. . Wait 30 min for mixture to set up. 20.8 Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 20.9 RIH w/ liner on DP no faster than 1-2 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 20.10 Fill DP with Top drive every 10 stands or as appropriate. Slotted liner should fill while RIH. 20.11 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + S/O depth every 5 stands. Record torque value if it becomes necessary to rotate the string to bottom. 20.12 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 20.13 RIH to TD as per running schedule. Monitor run for losses. Page 40 Version 1 August 2018 U Hilcorp 21.0 Cement 4-1/2" Production Liner 21.1 Circulate and condition mud for cement job Milne Point Unit L-41 Drilling Procedure Break circulation slowly and stage up rate with reciprocation. Rotate DP slowly if hole condition allows, not exceed max torque or 20 rpms Circulate minimum 3 liner annular volumes to condition hole and mud for cementjob 21.2 Hold pre job safety meeting over upcoming liner cementing operations. Make room in pits for volume gained during cement job. Ensure adequate displacement volume is available. • Cement returns are not expected to surface, but may be seen after setting liner hanger and circulating, discuss how to hand returns if they are seen • Discuss pumps for displacement • Positions and expectations of all personnel involved in cement operations, have one hand in the pits specifically for strapping pits and recording volume returned. 21.3 4-1/2" Liner cement job will be a single stage. 21.4 RU cement head and cementing lines 21.5 Pump 5 bbls fresh water. Pressure test surface cement lines to 4000 psi. 21.6 Pump 60 bbls of 13.5 ppg spacer 21.7 Pump 15.8 ppg Class G Single Stage Slurry as per below calculations, 40% OH Excess: • The entire liner and liner lap is planned to be cemented Ensure cement slurry thickening time accounts for 30 min shutdown time for setting and releasing from liner hanger / packer. And compressive strength sufficient for perforation. Section: Calculation Vol (b Is) Vol (ft3) 6-1/8" OH x 4.5" Liner: 11.586'-10,697' x..0167 b f X 1.4= 20.8 116.7 7" x 4.5" Liner 150' x .0186 b f = 2.8 15.7 4.5" Shoe Track 40' x .0143 b f = 1.7 9. Total Volume 142 21.8 Drop liner wiper plug and displace with drilling mud. • Target max displacement rates to not exceed drilling ECDs • Slow pumps enough to check for liner wiper plug shear release L15+ t 21.9 Continue displacing cement until liner wiper plug bumps, or displacement volume has been pump. Pressure up over 1000psi to verify plug has bumped. Page 41 Version 1 August 2018 Cement Slurry System ExpandaCem Density 15.8 ppg Yield 1.16 ft3/sk Mixed Water 4.95 al/sk 21.8 Drop liner wiper plug and displace with drilling mud. • Target max displacement rates to not exceed drilling ECDs • Slow pumps enough to check for liner wiper plug shear release L15+ t 21.9 Continue displacing cement until liner wiper plug bumps, or displacement volume has been pump. Pressure up over 1000psi to verify plug has bumped. Page 41 Version 1 August 2018 i Hilcorp Milne Point Unit L-41 Drilling Procedure If plug does not bump, do not set the liner top packer, as string will be unsupported by an unset liner hanger. Discuss with Baker Rep. 21.10 Increase drill pipe pressure to set liner hanger, — 2700psi. Slack off to ensure liner hanger is set. 21.11 Increase pressure to release running tool from liner hanger. Pressure up in 500 psi increments holding for 5 min each up to 4000 psi until indication that running tool has released. 21.12 Pickup to expose rotating dog sub, set down on liner and set ZXP liner top packer. 21.13 With packoff on running tool still engaged, bleed DP pressure to zero, close BOP and test 7" x 4" annulus to 3000 psi for 30 min and chart record same. Rotate and set down, if necessary to ensure liner packer is set. Bleed off pressure and open BOPE. 21.14 Pressure up t/ 500 psi, pickup 2-3' to verify that the HRD setting tool has released. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 21.15 Pick up above liner top. 21.16 CBU x 2, to clean up wellbore and check for any cement returns to surface or above liner top 21.17 Displace entire wellbore to completion brine. Pump at max rates. c. 21.18 POOH, L/D 4" DP and inspect running tools. 3 21.19 L/D remaining 4" DP out of derrick. � Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the successor problems during the cement job Send final "As -Run" casing tally & casino and cement report to iewel@hilcorp.com, pchan(c�r�hilcorp. com, and cdinger@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 42 Version 1 August 2018 H Hilcorp 22.0 Perform 4-1/2" Cleanout Run & Displacement Milne Point Unit L-41 Drilling Procedure 22.1 If well conditions warrant, a clean out run will be performed prior to running completion tubing 22.2 M/TJ casing clean out assembly complete with casing scraper assemblies for each size casing in the hole. • 4" x 2-7/8" DP Tapered String • Casing scraper for 7" 26# casing • Casing Scraper & Bit for 4-1/2" Liner 22.3 TIH & clean out well to PBTD, confirm depth with completion engineer • Circulate as needed on trip in if string begins to take weight. Watch as cleanout string enters liner top Circulate hi -vis sweeps as necessary to carry debris out of wellbore. 22.4 Displace well to 9.2ppg 6% KCl completion brine • Confirm completion fluid with completion engineer 22.5 TOOH w/ clean out assembly. Lay down drill pipe on the trip out. Note any abnormal wear on the clean out assy. Page 43 Version 1 August 2018 H Hilcorp 23.0 23.1 23.2 23.3 23.4 23.5 Milne Point Unit L-41 Drilling Procedure Run 4-1/2" Frac String R/U and run 4-1/2" 12.6# L-0 TXP frac string assembly, including nipple profile, production packer and WLEG. Ensure appropriate well control crossovers on rig floor and ready. Makeup the tubing hanger and landing joint. Land hanger. RILDs and test hanger (500/5000 psi). Make note of actual weight on hanger on morning rpt. Freeze protect IA and Tubing. Drop ball and rod and set packer 23.6 Test the tubing to 3500 psi for 30 minutes. Monitor tubing to identify any packer leaks. Record and note all pressure tests on chart. Q W1 23.7 Bullhead diesel freeze protect down 9-5/8" x 7" annulus if not already done so. Do not allow flow back. 23.8 Install BPV 23.9 ND BOPE 23.10 NU Tree & Pressure test to 5000 psi. 23.11 RDMO Doyon 14 A separate sundry will be submitted for hydraulic fracture stimulation and completion operations. - 'i(- C(S c - Page 44 Version I August 2018 H Hilcorp 24.0 Doyon 14 Diverter Schematic Milne Point Unit L-41 Drilling Procedure Kdo Vji � -16'0,A1W LIm Page 45 Version 1 August 2018 H Hilcorp 25.0 Doyon 14 BOP Schematic Typical Ram Configuration Kd1 Lino--�! Milne Point Unit L-41 Drilling Procedure 2-7/8" x 5" VBR Blind Rams 40 twM Lna W Gato Valle 2-7/8" x 5" VBR Page 46 Version 1 August 2018 Milne Point Unit L-41 H Drilling Procedure Hilcorp 26.0 Wellhead Schematic FMC Gen 5 Typical — I!.vau' I--- ljr, I VE� M CZ Page 47 Version 1 August 2018 -cc Jt �EA J C, 25 7bahIdpFM I. I. ..... . NA Page 47 Version 1 August 2018 Milne Point Unit L-41 Drilling Procedure Hilcorp 27.0 Days Vs Depth 0 2000 -v00 sc c 6000 v 0 a v MPU L -41A Kuparuk A Producer Days vs Depth 12000 14000 0 5 10 15 20 25 30 Days Page 48 Version I August 2018 H Hilcorp t �;ee 28.0 Formation Tops & Information Milne Point Unit L-41 Drilling Procedure MPU L-41 Formations (Wp10) MD (ft) TVDss (ft) TVD (ft) Formation Pressure (psi) EMW (ppg) Ugnu 2970 2396 2446 1100.7 8.65 Schrader Bluff NB 6263 4092 4142 1863.9 8.65 Schrader Bluff OA 6523 4226 4276 1924.2 8.65 Colville 7500 4728 4778 2150.1 8.65 HRZ 10532 6684 6734 3030.3 8.65 Kalubik 10666 6810 6860 3087 8.65 Kup D 10883 7014 7064 3178.8 8.65 Kup C 10988 7113 7163 3223.35 8.65 Kup A 11086 7205 7255 3264.75 8.65 MPU L Pad Data Sheet GENERALIZED GEOLOGICAL FORECAST SS GEOLOGICAL TVD FM LITH DESCRIPTION COMMENTS NOTE: See individual Well Program for ielpmn Gob, specific casing design, depths, sizes, woo-. weights, grades and connections. {q p Unconswitsued coarse b mealum send and eoWl gannet E ^' •.+•.= ash .,no, sitn atoe. IF SIGNIFICANT AMOUNTS OF GRAVEL 1,000' ARE ENCOUNTERED WHEN DRILLING THE -a*— SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. 1350• Base permafrost � 2,000' I �cW watch pesslae slaetncking will WsenNgf!lYning. Lala L-15. No hydrates L sae.n Irktex -dol*= encountered on -Pad wells drilled to date. con I' mterbeas oe sena cuys.nd slnatones conn occase nal aho„s ofcoat Truces of pyrite at eb 3100 h 3,000- Internal at.c!- 3400 It can be sticky and tight (L-01). Clay Inui beds between MOO and 4500 fL C 3432. L A San• a.aa Y UGNU: Sense of obarsclimate!eninclimate!sands abler are IAlic,D{ made up of prom lop to boffoml coaase snw. fine sena. snty style. Better aeneellud mte.ung anima sa you UGNU progress Into Me Lens 11(deeper). us..." Schrader Bluff: Possible nyerxaroons nmued- Ls,,,e: to sw comer W Nltne denelopmem. Northern area Is i-xii deen.Uuclumand Wel. '3339 N.aeer (A&C) •4000• (NA) Schrader BIuH Sands: 4,000' eommued uyenng aousmmg apW.m saner as above + SchraderBluff: Possible lost circulationexcept rEll mar condebsmd aha Wnn occaslaad.MI. zone while drilling long strings and running claynchshah Interval 4300 he Also f -Ugnu and scnratler Bluff: Possible hyd,.rlam 11.11W casing. Recommend deep setting surface uAl tato SW comer oI Nlll denetopment. Lai and LJ5 are casing for Kuparuk long strings. Also, the compleNd In Ne Schrader Bluff sand. Northern area of Schrader Bluff sands area potential Schrader L -Pad Is aewnstrechn. end wet. differential stuck pipe interval if left un -cased Bluff C surbseecasingpamhlshaNbelOW for Kuparuk long strings. Sands: Son,". Bluff 08 ..it far tenger aeaeh wags. I L Page 49 Version 1 August 2018 0 Hilcorp � c ' '4290' O o1 Seabee (Colville) Interval: Seabee Y Predominantly interbedded slllsione and clay with beds of sand, shale and occasional seams of coal. The Seabee Is generally uneventful until reaching the HRZ Expect good penetration rates. Seabee: Continuous clay seclbn from 590D to 5,000. 6500 H (L-01). Periodic traces of calcite and 10 to 29 %L dolomite Q N- 6700 R (depths for SW 1997 L -Pad wells Is shallower). Seabee C 6,000, L UNCONFORMITY: uncontormityatthetopof A the HRZ. Erodes as deep as the Kuparuk a sand In some places at L -Pad. '6560' Top HRZ Y HRZ: Highly Radioactive Zone. Very dark. baste type HRZ shale, organic, good source rock. HRZ may be truncated out In central portion of L -Pad and not present In all wells. '6630' se H Kalublk Shale: Good log marker MK19 In the Kalublk (67051n L-01, 6900 in L-25 and 62701n L-361- Kalublk Unconformity, erodes KelYGlk and Kuparuk D Intervals in nrxthem L -Pad area. Tuff "V"(berrtoninc] zone possible at lop of HRZ. Sills within lower Kalublk and Kuparuk "D" 16660" can become overpressured due to high Infection pressures Into the Kuparuk sands. "D" Shale Kuparuk Interval: The "D" Shale Is me top Kuparuk sediment and '6960' C is known as He -Cap Rock-. KU PARUK OVER -PRESSURE MAY OCCUR IN THE D -SHALE. lova LC Kuparuk "C": Sandstone. anaba upward. Kuparuk Ing target. Very W n sand at L -Pad (4 m 14 h). LCU: Lower Cretaceous Uncontormdy '7080' B Kuparuk 13: Also known as the Laminated Zone. negins belaw LCU. Fine to medium grain sands becoming more ahatey with depth. Hydrocarbon bearing. A3 I TKA3: Fine grain sandstone, coarsening Upward, relatively low permeability. 15-18%L porosity- 10 to 100 and permeability. Hydrocarbon bearing. The Kuparuk At, A2 and A3 are the major production Intervals at L -Pad. -7100' A2 7132' Al Page 50 TKA1 & TKA2: SlmltartoTKA3. Version I Milne Point Unit L-41 Drilling Procedure LOST /I BONG MILE LNG DRILLING (MOSTLY 8-1/2" ING —IKALUBIK. L-43PB1: 12.0 PPG EM STUCK PIPE INTERVAL!! "D" CAP POSSIBLE OVER -PRESSURE IF DRILLING IN TRACT 22 NEAR THE KRU 30 -PAD OR NEAR INJECTION WELLS. L-20 and L-32 both required 13.3 ppg mud weight. L-34.-35 and -37 required 114,113 and 11.0 ppg mud weights respectively. L-39 (the furthest from KRU 30 Pad required a 10.8 ppg mud wt. LOST RETURNS AND BREATHING BACK WHILE RUNNING, CIRCULATING AND CEMENTING PRODUCTION CASING (MOSTLY 7" LONG STRINGS): L-13, L-11, L-12, L-14, L-15, L-17, L-29, L-25, L-21, L-34, L-33, L-39, AND L42. August 2018 n Hilcorp 29.0 Anticipated Drilling Hazards Surface Hole Section: Milne Point Unit L-41 Drilling Procedure Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates - Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section efficiently — control ROP and avoid loading the hole with gas. Minimize gas belching by reducing flow rate if necessary. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non -pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb DRILTREAT to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti -Collison: There are a number of adjacent wells in the vicinity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. 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: No H2S events have been documented on drill wells on this pad.Treat every hole section as though it has the potential for H2S. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. Page 51 Version 1 August 2018 H Hilo Milne Point Unit L-41 Drilling Procedure 2. The rig will have fully functioning automatic 142S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 52 Version 1 August 2018 n HHilcorp Intermediate & Production Hole Sections: Milne Point Unit L-41 Drilling Procedure Hole Cleaning: Maintain rheology of mud system. Sweep hole with low -vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate with AV of 200 ft/min. Lost Circulation: Lost circulation has been seen in the Colville formation at EMW exceeding — 12.0 ppg. Monitor ECDs during production section to ensure ECDs stay below 12.0. Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Abnormal Pressures and Temperatures: Although Kuparuk reservoir pressure is predicted to be normal (.45 psi/ft TVD), a past well in this fault ✓ block encountered trapped injection pressure in the Kuparuk D. This is the reason for the 7" top set depth and high 12.5 ppg production hole mud weight. Wellbore Stability: This well will drill through historically trouble shales, HRZ & Kalubik. Maintain sufficient MW for stability and utilize MPD to maintain constant bottom hole pressure to mitigate on/off pressure cycles. Use MPD to offset swab effect while TOOH. Follow tripping in hole schedule to manage surge pressures on shales. Anti -Collision: This well has a close approach with L-14 at — 4275' MD. Confirmation gyro surveys will be ran to confirm ellipse of uncertainty. Control drill across interval, monitoring MWD for magnetic interference. Faulting: There are no known faults in either hole section. I_',_P&I Treat every hole section as though it has the potential for 1-12S. No 1-12S events have been documented on drill wells on "L" pad. _--- - The AOGCC will be notified within 24 hours if 1-12S 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 1-12S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 53 Version 1 August 2018 H Hilcorp C, 30.0 Doyon 14 Layout Milne Point Unit L-41 Drilling Procedure Page 54 Version I August 2018 U Hilcorp 31.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: Milne Point Unit L-41 Drilling Procedure 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. PIU 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 55 Version 1 August 2018 H Hilcorp �y 32.0 Doyon 14 Choke Manifold Schematic Milne Point Unit L-41 Drilling Procedure Page 56 Version I August 2018 n Hilcorp 33.0 Casing Design Information Calculation & Casing Design Factors Milne Point Unit DATE: 8.9.2018 WELL: MPU L-41 DESIGN BY: Joe Engel n Criteria: Hole Size 12-1/4" Hole Size 8-1/2" x 9.875" Hole Size 6-1/8" Mud Density: 9.2 Mud Density: 10.8 Mud Density: 12.5 Drilling Mode MASP(8.5" x 9.875"): 2411 psi (see attached MASP determination & calculation) Production Mode MASP: 2704 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation " 1, 2, 3 Max MW gradient external stress and the casing evacuated for the internal stress Milne Point Unit L-41 Drilling Procedure Page 57 Version 1 August 2018 Casing Section Calculation/Specification 1 2 3 Casing OD 95/8" 7" 4-1/2" Top (MD) 0 0 10,547 Top (TVD) 0 0 6,730 Bottom (MD) 7,367 10,697 11,587 Bottom (TVD) 4,850 6,888 7,725 Length 7,367 10,697 1,040 Weight (ppf) 40 26 12.6 Grade L-80 L-80 L-80 Connection TXP TV TXP Weight w/o Bouyancy Factor(Ibs) 294,680 278,122 13,104 Tension at Top of Section (Ibs) 294,680 278,122 13,104 Min strength Tension (1000 lbs) 916 604 288 Worst Case Safety Factor (Tension) 3.11 ' 2.17 , 21.98 Collapse Pressure at bottom (Psi) 2,425 3,444 3,940 Collapse Resistance w/o tension (Psi) 3,090 5,410 7,500 Worst Case Safety Factor (Collapse) 1.27 - 1.57 1.90 MASP (psi) 1,989 2,411 2,704 Minimum Yield (psi) 5,750 7,240 8,430 Worst case safety factor (Burst) ji 2.89 -1 3.00 3.12 . Page 57 Version 1 August 2018 N Hilcorp 34.0 8-1/2" x 9.875" Hole Section MASP Milne Point Unit L-41 Drilling Procedure Maximum Anticipated Surface Pressure Calculation Hill 8-1/2" x 9.875" Intermediate Hole Section U=TMPU L-41 Milne Point MD TVD Planned Top: 7638 4850 Planned TD: 10697 6888 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Kalubik 6,860 3087 8.7 0.450 Offset Well Mud Densities (Same Fault Block) Well MW Range Top (TVD) Bottom (TVD) Date L-43 9.3-9.8 439 6,745 2004 Assumptions: 1. Fracture gradient at shoe is estimated at 0.7 psi / ft based on field test data. 2. Maximum planned mud density for the 8-1/2" x 9.875" hole section is 11.0 ppg. 3. Calculations assume Kuparuk reservior contains 100% gas (worst case). 4. Calculations assume worst case event is complete evacuation of wellbore to gas. Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 9-5/8" Shoe 7638' MD / 4850' TVD 4850 (ft) x 0.7(psi/ft)= 3395 psi 3395 (psi) - [0. 1(psi/ft) *4850(ft)]= F 2910 psi Drilling Mode MASP MASP from pore pressure (wellbore completely evacuated to gas) 6888(ft) x 0.45(psi/ft)= 3100 psi 3100 (psi) - [0.1(psi/ft)*6888(ft)]= 2411 psi Summary: 1. MASP while drilling Intermediate hole is governed by the wellbore completely evacuated togas from the Kuparuk Reservior Page 58 Version I August 2018 H Hilcorp Milne Point Unit L-41 Drilling Procedure 35.0 6-1/8" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 14 6.125" Production Hole Section HIcorp MPU L-41 Milne Point MD TVD Planned Top: 10697 6888 Planned TD: 11586 7725 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Kuparuk D 7,064 3179 8.7 0.45 KuparukC 7,163 3223 Oil 8.7 0.45 Kuparuk A 7,225 3264 Oil 8.7 0.45 Offset Well Mud Densities (Same Fault Block) Well MW Top (TVD) Bottom (TVD) Date L-43 12.5-12.6 6,745 7,483 2004 Assumptions: 1. Fracture gradient at shoe is estimated at 0.7 psi /ft based on field test data. 2. Maximum planned mud density for the 6-1/8" hole section is 12.5 ppg. 3. Calculations assume the Kuparuk reservior contains 100•% gas (worst case). 4. Calculations assume worst case event is complete evacuation of wellbore to gas. Fracture Pressure at 7" shoe considering a full column of gas from shoe to surface: 6888 (ft) x 0.7(psi/ft)= 4821 psi 4821 (psi) - [0.1(psi/ft)*6888(ft)]= 4133 psi Drilling Mode MASP-_�— MASP from pore pressure (wellbore comp] etely,evacuated to gas) (/ 7725(ft) x 0.45(psi/ft)= 3476 psi 3476 (psi) - [0.1(psi/ft)*7725(ft)]= 2704 psi Summary: 1. MASP while drilling 6-1/8" Intermediate hole is governed the Kuparuk. Page 59 Version I August 2018 from n Hilcorp Milne Point Unit L-41 Drilling Procedure 36.0 Spider Plot (NAD 27) (Governmental Sections) ,ot ' II', III 1 r/, I r r ,'i r i •' ,! I ,' ADL355017 .�! ADL355016, Sec 31 r I ,/� ' Sec. 32 U014N0f 10E ' ' S -c 3'-. d(622) �i it d�+� '' 'li ,t MPL L-31_BHL ,11 ,�,• MPU L-41TPIli I oil ;to h ,H I jr r It , Sec. 6 ' J �' 4 i , ° r Seo. 5 :}� r1ti f.' (625)♦ _ ..It , I $ It MILNE POINT UNIT f _ADL04743r 1 �AOL025500 � , � , \ • rii � v\ ^\ L.Oa a -� 0 \IPL 1-41 SHL z .,leu L -1628t>, Legend • MPU L41 SHL X MPU L41_TPH T MPU L41 FiHL — � Other surface Holes (SHL) As �' ' `�N ��" + i� `� • Other Bottom Holes fBHL) ,' - - _ Other Well Pala Coastline (USGS 1:63k) - vei Oi and Gas Unit Boundary c•'A4L025515 , , msec. 17 Pad FootPrinl n. 1E1E 30j8 , Milne Point Unit [1r� All.MPL-41 Well 0 1,000 2,000 TT wp10 ommmmoFeet Page 60 Version 1 August 2018 Milne Point Unit L-41 Drilling Procedure Hilcorp 37.0 Surface Plat (As Built) (NAD 27) O A A.S.P. r ` $ GEODETIC WOUND SECTION NO. I I� 0 ) � 32 ■ 33 ■ 28 ■ 29 ■ 1 0 i 24 ■ 25 ■ 20 ■ 21 / ' 16 ■ 17 ■ 41 + +43 LEGEND A5 -BUILT CONDUCTOR EI EXISTING CONDUCTOR DRILL POINT / EXISTING CONDUCTOR STMPS4N ucu i Fie nLn `' I 4 L P 1 iy� +s ` I 11Z I VICINITY MAP N.T.S. NOTES I. DATE OF SURVEY: DECEMBER 31, 1997. 2. REFERENCE FIELD BOON MP07-09 (PCS. 33-36) 3 ALASKA STATE PLANE CODROINATES ARE ZONE 4, HAD 27. 4 GEODETIC COORDINATES ARE NAD 1927, 5. PAD SCALE FACTOR 1S 0.9999023, 6, HORIZONTAL/VERTICAL CONTROL IS BASED ON MONUMENTS L-1 NORTH AND L-2 SOUTH, 7. ELEVATIONS ARE BPX MP DATUM (N.S-L). SURVEYOR'S CERTIFICATE I NCREBY CERTIFY THAT I AM PROPERLY REGISTERED AND LICENSED TO PRACTICE LAND SURVEYING IN TME STATE OF ALASXA AND THAT THIS PLA' REPRESENTS A SURVEY MADE Y ME OR UNDER My SUPERVISION AND THAT ALL DIRECT CREDETAILS CTI AS OF DECEMBER 31. 1997 .-.Tcn 1.111. ..n MAPTm cr N T 11 V R. 10 E.. UMIA1 MERIDIAN, AK. WELL A.S.P. PLANT GEODETIC GEODETIC WOUND SECTION NO. COORDINATES I� POSIT ON(DM5) POSITION(O.DD) ELEVATION OFFSETS /I N-1,110.32 70'29'48.249" 70.4967358156' 3,240' FSL 37 3 ■ E= t 382.77 149'37'53.923' ■ 9 . 4,835 FEL 3g N= 1,555.04 O42 70.4976589 6.5' 3.578 FSL 4, X- 544,744-45• ■ 9 49'38'02-7380 149.6340939 3{ ■ 5.134' FEL ■ 14 N= 1,554.98 I 3 ■ 16.3' 3.63E' FPI ■ 10 X= 544,837.72 E= 1,33505 15 1344 2 ■ ■ 7 12 / 40 O L a C3 III I 6 35 4 36 53710 38 co ! LL o L -PAD LEGEND A5 -BUILT CONDUCTOR EI EXISTING CONDUCTOR DRILL POINT / EXISTING CONDUCTOR STMPS4N ucu i Fie nLn `' I 4 L P 1 iy� +s ` I 11Z I VICINITY MAP N.T.S. NOTES I. DATE OF SURVEY: DECEMBER 31, 1997. 2. REFERENCE FIELD BOON MP07-09 (PCS. 33-36) 3 ALASKA STATE PLANE CODROINATES ARE ZONE 4, HAD 27. 4 GEODETIC COORDINATES ARE NAD 1927, 5. PAD SCALE FACTOR 1S 0.9999023, 6, HORIZONTAL/VERTICAL CONTROL IS BASED ON MONUMENTS L-1 NORTH AND L-2 SOUTH, 7. ELEVATIONS ARE BPX MP DATUM (N.S-L). SURVEYOR'S CERTIFICATE I NCREBY CERTIFY THAT I AM PROPERLY REGISTERED AND LICENSED TO PRACTICE LAND SURVEYING IN TME STATE OF ALASXA AND THAT THIS PLA' REPRESENTS A SURVEY MADE Y ME OR UNDER My SUPERVISION AND THAT ALL DIRECT CREDETAILS CTI AS OF DECEMBER 31. 1997 .-.Tcn 1.111. ..n MAPTm cr N T 11 V R. 10 E.. UMIA1 MERIDIAN, AK. WELL A.S.P. PLANT GEODETIC GEODETIC WOUND SECTION NO. COORDINATES COORDINATES POSIT ON(DM5) POSITION(O.DD) ELEVATION OFFSETS Y+6,031.431.09 N-1,110.32 70'29'48.249" 70.4967358156' 3,240' FSL 37 X= 545045.94 E= t 382.77 149'37'53.923' 149 .6316453 . 4,835 FEL Y=6,831,767.65, N= 1,555.04 70'29'51.5721- 70.4976589 6.5' 3.578 FSL 4, X- 544,744-45• E= 1.225.12 49'38'02-7380 149.6340939 5.134' FEL Y+6,031,825.26 N= 1,554.98 70'29'52.139" 70.4978164 16.3' 3.63E' FPI 43 X= 544,837.72 E= 1,33505 14977'59.982" 149.6333283 5040' EEL ® BP EXPLORATION u"�A0"A MPU L PAD AS -BUILT CONDUCTORS Ini WELLS L-37, L-41 & L-43 Page 61 Version 1 August 2018 0 Hilcorp �y 38.0 Drill Pipe Information 5" 19.59 S-135 NC -50 Milne Point Unit L-41 Drilling Procedure 500204050016200 Weatherford 5" 19.50 Ib/ft S-135 w/ NC 50 6-518" OD x 3-1/4" ID Tool Joint DRILL PIPE SPECIFICATIONS Outside Diameter Grade S-135 Connection NC 50 Interchangeable With 5' XH & 4-1f2' IF Upset Type IEU Nominal Weight per Foot 19.50 Ibs Adjusted Weight With Tool Joint per Foot 23.08 lbs TOOL JOINT DATA Outside Diameter 6-518'' Inside Diameter 3-114' API Drift 3-1/8' Rabbit OD, Suggested 3-1116" Minimum Make-up Torque 25,900 ftlbs Maximum Recommend Make-up Torque 26,800 ft -lbs Torsional Yield Strength 51,700 ft-Ibs Tensile Strength 1,269 000-1 _bs TUBE DATA New Premium Outside Diameter 5.000" 4.855' Inside Diameter 4 276" 4276' Wall Thickness 0.362" 0-290' Cross Sectional Area 5.275 sq in 4.154 sq in Maximum Hook Load/Tensile Strength 712,000 lbs 560,800 lbs Slip Crushing /Slip Type (SDXL) 572,100 lbs 453.500 lbs Burst Pressure 17,100 psi 16,100 psi Collapse Pressure 15,700 psi 10,000 psi Torsional Yield Strength 74,100 ft -lbs 58,100 ft -lbs Capacity Wi Tool Joint 0.726 US allft 0.726 US galift Displacement Wi Tool Joint 0.353 US gallft 0.322 US gait Excessive heat or pulling when tube is torqued can cause the maximum pull to decrease. Where possible all figures are obtained from OEM data source. NOTE: Weatherford in no way assumes responsibility or liability for any loss, damage or injury resulting from the use of the information listed above. All applications are for guidelines and the data described are at the user's own risk and are the user's responsibility. Page 62 Version I AUgust2018 U Hilcorp 5" 19.5# S-135 DS -50 Drill Pipe Configuration Pipe early 00 :.i5 000 Pipe Body Waa Thipatless aro 0.392 Pipe Baily Grade 5135 Dna Pipe -R T.1Join SMYS .^1120.000 Upset Type IEU Alan Upset OD TOTE) :.1 5.125 Tod Jelin00 6.925 Tod Joint ID :.13250 Pin Torg B Box Tony r., 12 Drill Pipe Performance Milne Point Unit L-41 Drilling Procedure Drill Pipe Performance Sheet ac % Inspep class Noi na wegle Desi9r.atian 19.50 -dll Pipe APpmxunace 14rg1h Pipe Te le SnelgM SeanJ4Edge Negld rvu 3:32 Raised T.1Join SMYS .^1120.000 Upset Type IEU Alan Upset OD TOTE) :.1 5.125 FncSon Factor II.0 Dag -Pipe Lenplh rtan0e2 follnance of Ont Pipe with Pim Body at Best Eshmalea Norrdnal 8040 Inspection Class nn..�.e: n.mc...,m a.wmml Cpraea� Maz T�.sm ONPWA*u Ale91t .w 24.11 2328 ' tern: Taye4 Fluid Dis laoemer�[-sa.n:037 039 100 Ta:sm Olyy 0 5@0.800 .. Fluid Dis Ua Mwt ass=m. _0095 u.a:a30.5W 410.503 Fhb Calp=N 'wrt:p]1 070 0.72 Ihid � 0 .0100 0.0107 0.0172 @]400 100 744 Dri0 eco .i 3.925 ommmwn,a 32.100 r.e.mn,.P...u-.,..v.n.. a -.:e-, a.+...rvare.emr=,:art,.�.c •zmn e:.r...N^.o...a.v:.a:... Connection Performance GP0.a50 t .w1.. u.t.-s Teena.c..e. 9041 Inspection CWs Maximum M1Y Tolpue Pipe Te le SnelgM 43100 Tetmis MOAN 1.fni mum Alaaerm To Pipe T.imi al Stre,M 30.100 1202.; 5e,ico vam<m..m:r.:aeaaaaavuanw Ta m.m To,:em,ao, .ace an rz.,.n xrtm,s...,x TYPoellocly Torsimal Wtio Tad i Tot.*Svtrength� eat 124 T=! Tod Jdra Tensile Strergm .en 1250.00p 1,2W. Elevator Shoulder Information l� 'llf7 SmoothEdge Height 332 Raised Buret Box OD^'0.012 Men 15.038 BJavaaor COWfa4 <.. 1.558.OW MM •^^C1 _. �,.,.._._. o_-_�,^_` Pipe OO Pipe Body Slip Crushing Capacity 17V 6.625 w OD X 3.250 - ID ) 120.000 _•^ T•^°"^•Ipum[dm Tool Joint Dimensions en, "tl0 Bdanmd On 1n18.435 i i.m.95o 12:J.000 •"'^1"^�• t-)5.930 cou:e e.T:�"•xoov [^15.93 API Premium Class ves: n nua....e. m wnen.z.nxm®cslpsm....t=ae -a...s nm.. Ppe Botlytg45praDpnf 54-1 OD 0.3621-) Wan S-135) PiDe Bodv Performance Poe BoN'CVAg,vatan( Sent OD 0.362-1 Wall S-135) ana emu .Ts�vew Page 63 Version 1 August 2018 Nominal 9041 Inspection CWs API Plemiwn class Pipe Te le SnelgM ms 71ZIW MOAN Sd1.80D Pipe T.imi al Stre,M mu.: 74.100 5e,ico 38.100 TYPoellocly Torsimal Wtio p.97 1.24 124 80% Ppa Torsional Slrelgm 50300 4!.500 45.500 Buret :"I 17.105 Men 15.038 col.Pse =I! 15.172 MM 10.028 Pipe OO 4.15.000 4.955 4855 'Nall TAipxness :a+0.352 0.28D a.28O NomirvN Pipe ID 4. 42Te 4.276 Cross Se- i Mea of Pipe Body _t .154 Cross SeLtiued Area c(OD @^:110.035 1@.514 les" Cross SBptgnal Mead ID:', 14.355 14380 N.390 ana emu .Ts�vew Page 63 Version 1 August 2018 H Hilcorp Eoep'Curo7�y 4" 14# S-135 XT -39 Drill Pipe Performance Sheet 3121/2017 Pipe Body Specification Connectwn XT -394875% 2563'(120 U S IFrceon Facets 10 Ape: 4 0' OD 0330' War TN,Jux,u S 135 l I.,. Gloss Pipe Body OD 11 4,0 Pipe Body Wall Thickness -Nominal l9e4ght 03301n-141Wh Pipe Body Grade 5-135 D ill Pipe Length 112 Max It 320 Min h 31.0 Type of Upset IU Maxupsetw In 9.188 -Assumed Transverse Lnad Fae xa 1x1 42 Pipe Body Performance Connectwn XT -394875% 2563'(120 U S IFrceon Facets 10 Ape: 4 0' OD 0330' War TN,Jux,u S 135 l I.,. Gloss At Mat MUyf22200k4bs) Connection Type and Size At Min MUT 08500 ft-Ibs) AN premium Sinai Inspection Class Bwrt Pressure pu17,800 0 903500 Collapse Pressure' pa 13,830 Slip Cnuhing Capacity' @s 306,400 - Assumed Slip Length In 16.5 -Assumed Transverse Lnad Fae xa 1x1 42 Adjurted Weight" WOn 16.73 Fluid Displacement- usgaen emva 0.26 00061 Fluid Capacity•' USgaNO ehlim 042 0.0101 emM,.wre>e,mwe.ks -bonenu..a,wo-4 122M 374500 Drill Pipe Performance Sheet 3mn017 Combined Loading for Drill Pipe Connectwn XT -394875% 2563'(120 U S IFrceon Facets 10 Ape: 4 0' OD 0330' War TN,Jux,u S 135 l I.,. Gloss At Mat MUyf22200k4bs) Connection Type and Size At Min MUT 08500 ft-Ibs) Operational Assembly Max TorquNft-lbs) Tensionlibs) Operational AssemblyMax TorquelN-lbs) Tensiori 0 9035M 0 903500 1000 x03300 8073 403490 X100 402800 1600 4030073 3100 401700 2400 40X00 41W 4W400 3M0 im600 SIX) 39B60O 4900 400590 61M 396500 4900 3990073 71M 393900 5700 391400 aim 391" 66W Wain 9200 U73W 7300 393400 1090 313500 aim 391000 11200 3792W Iglu 388300 122M 374500 SMO 385900 13200 369300 IOSW 382200 14200 363600 11300 37M 15300 356803 12100 375000 16300 350000 12900 3 17300 342600 138061 1E5000 18300 33400 14600 361700 19300 326000 15400 356100 Milne Point Unit L-41 Drilling Procedure Tool Joint Specification Max Make -Up Torque(Rewmmended) nlb, Connection Type and Size Min Make -Up Torque, XP99 Benchmark Min TJ OD (API Premium) GPmark^ Snu.WhEdge-Height per side In WA Tool Joint SMY P. 120,000 Connemon OD In 4875 Connedion ID 111 2563 Rn Tong Length In 120 Box Tong Length In We Thread<ompound Friction factor I66W to Tool oint Performance Max Make -Up Torque(Rewmmended) nlb, 22,200 Min Make -Up Torque, nabs 18,588 Min TJ OD (API Premium) 1n 4.653 Min Tl OD for Counterbore In 4.653 Drin9ze In 2438 nem+wo mw®wx+..>Mr4+rglw....r�x. �w,..ewmw...urnu. Caen xewrq.e aria 21000 Advisories and Warnings for Drill Pipe Aavbarks -Eema unvMYukntlwneoiemh (ensinlmeaegbNjvnMe�alm'gha+� Warninrs: Connection Wear Table Conrcctinrt l 94.8T'.2»?'.1 W t315A^.YS I FriCvn Face IL ToolJoint OD(in) Max MUT(ft4bs) Min MUTift-lbs) 4875 22200 185 4855 21900 182M 905 214M 17900 aria 21000 175M 4794 207M 17200 Ona 20300 16900 4234 15900 I66W 4334 19500 16300 4714 19900 16WO 4693 lame ism 4673 18400 IS400 4653 18100 I51W Elevator Capacity EFeeasx Base Dumetes:d2B17S Dexam5MY5:110,1 W ptl BmsTapn Mglc 18deg oMa[Von XP'39 40'0330' aw0 N ilii Tool JointOOtin.l EI*Mw Heist Capadty(Ibs) No Wear 1132• Wear Factor 4975 4697W 460500 4855 4529X) 4436X) 4X35 4362W 4269X) 4814 418600 4095X) 4794 402000 3927M 4124 385500 336X0 4714 360000 359X73 4739 352600 3433X) 4714 33 (X) 327000 4,03 319200 309900 4X73303000 293X0 4653 266800 I 27700(1 Page 64 Version I August 2018 n Hilcorp em i, 4" 14# S-135 HT -38 Milne Point Unit L-41 Drilling Procedure 400204138036211 W ■. ■.YaMfffffd 4" 14.00 Wit Internal Coating S-135 w/ HT 38 4-718" OD x 2-9116" ID w/ X 7000 Hard Banding Tool Joint DRILL PIPE SPECIFICATIONS Grade S-135 _ Connection HT 38 _ Interchangeable With 2-7/16' Upset Type IU Internal Coating TK 34 XT Nominal Weight per Fool 14,00 IbS Adjusted Weight With Tool Joint per Foot 15.65 lbs TOOL JOINT DATA Outside Diameter 4-718' Inside Diameter 2-9116' API Drift 2-7/16' Rabbit OD, Suggested 2-3/8' Hard Band X 7000 Minimum Mak"Torque 12,200 ft -lbs Maximum Recommend Make-up Torque 17,700 ft -lbs Torsional Yield Strength 29.500 ft -lbs Tensile Strength 649,200 Itis TUBE DATA New Premium _ Outside Diameter Inside Diameter Walt TNckness 4.000' 3.340' 0.330' 3.868' 3.340' 0.264' Cross Sectional Area 3.805 sq In 2.989 sq in Maximum Hook Loadfrensile Strength 513.600 lbs 403,500 lbs Slip Crushing SDXL 431,900 lbs 341.300 lbs Burst Pressure 19,500 psi 18,400 psi Collapse Pressure 20,700 sl 13,800 psi Torsional Yleitl Siren m 41,900 Mbs 32.800 ft -lbs Capacity W/ Tool Joint 1 ___ Dl�lacement W/ Toot Joint L 0.442 US gallift 0.2400.240 US daOR 1 0.442 US[M 0.223 US_ allft Excessive heat or pulling when tube Is torqued can cause the maximum pull to decrease. Where possible all figures are obtained from OEM data source. NOTE: Weatherford In no way assumes responsibility or liability for any loss, damage or Injury resulting from the use of the Information listed above. All applications are for guidelines and the data described are at the user's own risk and are the user's responsibility. Page 65 Version 1 August 2018 Hilcorp Alaska, LLC Milne Point M Pt L Pad Plan: MPU L-41 MPU L-41 Plan: MPU L-41 wp10 Standard Proposal Report 20 July, 2018 HALLIBURTON Sperry Drilling Services MALLIBURTON Project: Milne Point Site: M Pf L Pad spar,w orimng Coordinate (WE) Reference: Well Plan: MPU L-01, True North Well: Plan: MPU L-41 Vertical (ND) Reference: MPL41 wp06 prelim RKB @ 50.20usft (Doyon 14 Wellbore: MPU L-41 Measured Depth Reference: MPL41 wpW Prelim RKB @ 50.20usfl (Wynn 14 Design: MPUL41 wp10 Hilcerp Alaska, LLC REFERENCE INFORMATION Calculation Method: Minimum Curvatura Coordinate (WE) Reference: Well Plan: MPU L-01, True North Error System: ISC=A Vertical (ND) Reference: MPL41 wp06 prelim RKB @ 50.20usft (Doyon 14 Scan Method : Closest Approach 3D Error Surface: Elliptical Conic Measured Depth Reference: MPL41 wpW Prelim RKB @ 50.20usfl (Wynn 14 Warning Methotl: Error Ratio Calculation Method : Minimum Curvature SECTION DETAILS Sec MD Inc Azi TVD +N/ -S +E/ -W Dleg TFace VSecl Target Annotation 1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00 2 550.00 0.00 0.00 550.00 0.00 0.00 0.00 0.00 0.00 Stan Dir 3°/100' : 550' MD, 550'ND 3 816.67 8.00 28.00 815.80 16.41 8.73 3.00 28.00 18.18 4 1053.07 15.00 2200. 1047.32 59.36 27.93 3.00 -12.66 64.75 End Dir : 1053.07' MD, 1047.32' ND 5 1200.00 15.00 22.00 1189.25 94.62 42.18 0.00 0.00 102.56 Stan Dir 3°/100' : 1200' MD, 1189.25'ND 6 1250.02 15.00 16.20 1237.56 106.83 46.41 3.00 -92.80 115.47 End Dir : 1250.02' MD, 1237.56' ND 7 1450.02 15.00 16.20 1430.75 156.54 60.85 0.00 0.00 167.24 Start Dir 5°/100' : 1450.02' MD, 1430.75'TVD 8 2330.07 59.00 15.82 2116.44 653.47 202.50 5.00 -0.47 683.96 End Dir : 2330.07' MD, 2116.44' ND 9 9045.92 59.00 15.82 5575.11 6192.11 1772.11 0.00 0.00 6440.69 Stan Dir 3°/100' : 9045.92' MD, 5575.1l'TVD 10 10346.00 20.00 15.82 6559.01 6972.48 1993.25 3.00 -180.00 7251.79 End Dir : 10346' MD, 6559.01' ND - Start ESP Tangent 11 11086.87 20.00 15.82 7255.20 7216.27 2062.33 0.00 0.00 7505.18 MPU L41 Tgt1 wp09 KUP 12 11586.87 20.00 15.82 7725.05 7380.80 2108.95 0.00 0.00 7676.19 Total Depth : 11586.87' MD, 7725.05' TVD CASING DETAILS WELL DETAILS: Plant MPU L41 Ground Level: 16.50 TVD TVDSS MD Size +W -S +E/ -W Northing Easling Latmuce Longitude DDI = 6.201 4850.00 4799.80 7637.94 9 5/e" x 12 1/4" 0.00 0,0 603176705 54474445 70'29151,572 N 149° 36 2738 W 6889.00 6838.80 10697.17 7" x 8 1/2" 7725.05 7674.85 11586.87 41/2"x61/8" SURVEY PROGRAM Depth From Depth To Survey/Plan Tool 33.70 70000 MPU L41 v 10 2GyroSRGSS 700.00 76,10W MPU L41 wp10 2 MWD+IFR2+MS+Sag 7640.00 10700.00 MPU L41 ep10 2=MWD+IFR2+MS+Sag 0 Start Dir 3°/100' 550' MD, 550'ND 10700.00 11586.87 MPU L41w 10 2_MWD+IFR2+MS+Sag : FORMATION TOP DETAILS 500 End Dir : 1053.07' MD, 1047.32' ND TVDPath TVDssPatn MDPath Formation 750 1850.20 1800.00 1923.46 BPRF 1000. - " - Start Dir 3°/100' : 1200' MD, 1189.25'ND 2158.20 2108.00 2411.17 SVI - - - 2446.20 2396,0 2970.39 UG4 - - - - - - - End Dir : 1250.02' MD, 1237.56' ND 3568.20 3518.00 5149.02 LA3 4108.20 4058.00 6197.58 SB NA 1500- 15OZ - -Start Dir 50/100' :1450.02' MD, 1430.75T/D 4142.20 4092.00 6263.58 SB NB 4276.20 4226.00 6523.77 SB OA .BPR ....gyp°� p End Dir : 2330.07' MD, 2116.44' ND 4378.20 4328.00 6721.83 SB_OS - - 4728.20 4678.00 7401.44 SB BASE $V 1 _ 4 - - -0 - - - - 6734.20 6684,0 10532.43 HRZ 2250- op 6860.20 6810.00 10666.52 KLB UG4 r6 6918.20 6W&W 10728.24 KLGM - - - Op 7064.20 7014,W 10883.61 KUP_D ^y p 7163.20 7113.00 111988.96 KUP C pp 7172.20 7122.00 10998.54 KUPB7 b' O 7255.20 7205.00 11086.87 KUP7 A3 c 3000 pyp 7273.20 7223.00 11106.02 KUPA2 p0 7301.20 7251.00 11135.82 KUP__A1 = LA3 p f- 7355.20 7306.00 11194.35 KUP A BASE Id 3750-SB_NA SB NB _.. ..... .. yy yppp p �N'L159 5/8 95/8 x1 4500 SB OB SB OA n�po Start Dir 3°/100' : 9045.92' MD, 5575.1l'ND 4 - - -- - o0 SB BASE mo ypo 0 5250 opo F ? a p End Dir : 10346' MD, 6559.01' ND - Start ESP Tangent 1 60 9 p0"0 HRZ 1 - End ESP Tangent KLB .`KLGM - - - - -. _.- ___ }p6g0 7 x81/2" '--KUP_D- - " -------KUP13--KUP_B7 KUP_A2KUP_A3 - - - KUP_A1 KUP A BASE MPU L-41 Tgtl wp09 4 1/2" x 6 1/8" -Fault 112 _ MPU L-41 wp10 Total Depth : 11586.87' MD, 7725.05' ND 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 Vertical Section at 15.95° (1500 usfUin) HALLIBURTON Project: Site: Milne Point M Pt L Pad sPa�w o�wme ^_ 4200 Well: Wellbore: Plan: MPU L-41 MPU L-41 4'50 Plan: MPU L-41 wp10 CASING DETAILS TVD TVDSS MD Nara 9000 4850.00 4799.80 7637.94 9 5/8" x 12 1/4" 6889.00 6838.80 10697.17 7' x 8 1/2" 7725.05 7674.85 11586.87 41/2"x61/8" WELL DEIAI S: Plan: MPU L I Ground Level: 16.50 +N/ -S +Fl -W Nanking Easting [edttude Longitude 0.00 0.00 6031767.05 54474045 70°29'51572N 149°38'2338 W REFERENCE INFORMATION Co-onlinele (NE) Reference: Well Plan: MPU L41. True North Vertical (ND) Reference: MPL41 wOB prelim RNB Q W 20usfl (Doyon 14) Measured Depth Reference: MPL41 ap06 prelim RNB Q 50.20usB (Doyon 14) Calculation Method Minimum curvature 4 12" x 61/8" After, M'pj wul,41 TWI_P09 KUP 5 � !` Total Depth: 115868]'Nm, ]]2505'NU 7" x 8 1y2"- -� ] 0 ! ! 65 - - - ] J End ESP Tangent 00 / - - -- / /Pnd DIr:10346'bID, 6559,01'TVD-Son ESPTangent Start Dir 391 W : 9045.92' W, 5575.1= _ +u 5400— 5000 0 95Wx 121/4"- T 4800 4750 3500 320 /3000 50 2500 2250 2000 End Dir : 23300T MD, 2116.44' TVD Start Dir P100': 1450.02' Nm,1430.754 --5pQ - - End on : 1250.02' Nm, 1237.56 TVD -_Start Dir 3"/IW': 1200 MD, 1189.25'TVD End Dir: 1053.07hm,104752'TVD Sun on 3°ll W: 550 MD, 550TVD F.wt 111 -2400 -1800 -1200 -600 0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 West( -)/East( -F) (1200 usft/in) 4s00 ^_ 4200 L 4'50 0 to 3500 320 /3000 50 2500 2250 2000 End Dir : 23300T MD, 2116.44' TVD Start Dir P100': 1450.02' Nm,1430.754 --5pQ - - End on : 1250.02' Nm, 1237.56 TVD -_Start Dir 3"/IW': 1200 MD, 1189.25'TVD End Dir: 1053.07hm,104752'TVD Sun on 3°ll W: 550 MD, 550TVD F.wt 111 -2400 -1800 -1200 -600 0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 West( -)/East( -F) (1200 usft/in) HALLIBURTON Database: Sperry EDM - NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: Plan: MPU L-41 Wellborn: MPU L-41 Design: MPU L-41 wp10 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU L-01 TVD Reference: MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14) ' MD Reference: MPL-41 wp06 prelim IRKS @ 50.20usft (Doyon 14) North Reference: True Survey Calculation Method: Minimum Curvature Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) - Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site M Pt L Pad, TR -13-10 Site Position: Northing: 6,029,799.28usft Latitude: 70° 29'32.230 N From: Map Easting: 544,529.55usft Longitude: 149' 38'9,412 W Position Uncertainty: 0.00 usft Slot Radius: 0' Grid Convergence: 0.34 ° Well Plan: MPU L-41, Unused BP Conductor- Possible Kuparuk Slot Tie On Depth: 33.70 Well Position +N/S 0.00 usft Northing: 6,031,767.05 usft Latitude: (usft) +EI -W 0.00 usft Easting: 544,744.45 usft Longitude: Position Uncertainty 0.00 usft Wellhead Elevation: 16.50 usft Ground Level: Wellbore MPU L-41 Magnetics Model Name Sample Date Declination Dip Angle (•) M BGGM2018 9!112018 17.05 81.00 Design Audit Notes: Version: Vertical Section: MPU L-41 wp10 Phase: PLAN Tie On Depth: 33.70 Depth From (TVD) -NIS -E/-W Direction (usft) (usft) (usft) (') 33.70 0.00 0.00 15.95 70° 29'51.572 N 149' 38'2.738 W 16.50 usft Field Strength (nT) 57,455 Plan Sections Measured Vertical TVD Dogleg Build Tum Depth Inclination Azimuth Depth System +N/ -S +E/ -W Rate Rate Rate Teel Few (usft) (°) (') (usft) usft (usft) (usft) (7100usft) (°/t00usft) ('/100usft) (•) 33.70 0.00 0.00 33.70 -16.50 0.00 0.00 0.00 0.00 0.00 0.00 550.00 0.00 0.00 550.00 49980 0.00 0.00 0.00 0.00 0-00 0.00 816.67 8.00 28.00 815.80 765.60 16.41 8.73 3.00 3.00 0.00 28.00 1,053.07 15.00 22.00 1,047.32 99712 59.36 27.93 3.00 2.96 -2.54 -12.66 1,200.00 15.00 22.00 1,189.25 1,139.05 94.62 42.18 0.00 0.00 0.00 0.00 1,250.02 15.00 16.20 1,237.56 1,187.36 106.83 46.41 3.00 0.00 -11.60 -92.80 1,450.02 15.00 16.20 1,430.75 1,380.55 156.54 60.85 0.00 0.00 0.00 0.00 2,330.07 59.00 15.82 2,116.44 2,066.24 653.47 202.50 5.00 5.00 -0.04 -0.47 9,045.92 59.00 15.82 5,575.11 5,524.91 6,192.11 1,772.11 0.00 0.00 0.00 0.00 10,346.00 20.00 15.82 6,559.01 6,508.81 6,972.48 1,993.25 3.00 -3.00 0.00 -180.00 11,086.87 20.00 15.82 7,255.20 7,205.00 7,216.27 2,062.33 0.00 0.00 0.00 0.00 11,586.87 20.00 15.82 7,725.05 7.674.85 7,380.80 2,108.95 0.00 0.00 0.00 0.00 7/20/2018 6:49:53PM Page 2 COMPASS 5000.1 Build 81E HALLIBURTON Halliburton Standard Proposal Report Database: Company: Project: Site: Well: Wellbore: Design: Sperry EDM - NORTH US Hilwrp Alaska, LLC Milne Point M Pt L Pad Plan: MPU L41 MPU L-41 MPU L-41 wp10 + CANADA Local Co-ordinate Reference: Well Plan: MPU L41 TVD Reference: MPL-41 wp06 prelim MD Reference: MPL-41 wp06 prelim North Reference: True Survey Calculation Method: Minimum Curvature IRKS @ 50.20usft (Doyon 14) IRKS @ 50.20usft (Doyon 14) Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NIS +El -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -16.50 33.70 0.00 0.00 33.70 -16.50 0.00 0.00 6,031767.05 544,744.45 0.00 0.00 100.00 0.00 0.00 100.00 49.80 0.00 0.00 6,031,767.05 544,744.45 0.00 0.00 200.00 0.00 0.00 200.00 149.80 0.00 0.00 6,031,767.05 544,744.45 0.00 0.00 300.00 0.00 0.00 300.00 249.80 0.00 0.00 6,031,767.05 544,744.45 0.00 0.00 400.00 0.00 0.00 400.00 349.80 0.00 0.00 6,031,767.05 544,744.45 0.00 0.00 500.00 0.00 0.00 500.00 449.80 0.00 0.00 6,031,767.05 544,744.45 0.00 0.00 550.00 0.00 0.00 550.00 499.80 0.00 0.00 6,031,767.05 544,744.45 0.00 0.00 Start Dir 3°1100' : 550' MD, 550'TV0 600.00 1.50 28.00 599.99 549.79 0.58 0.31 6,031,767.63 544,744.75 3.00 0.64 700.00 4.50 28.00 699.85 649.65 5.20 2.76 6,031,772.27 544,747.18 3.00 5.76 800.00 7.50 28.00 799.29 749.09 14.43 7.67 6,031,781.52 544,752.03 3.00 15.98 816.67 8.00 28.00 815.80 765.60 16.41 8.73 6,031,783.51 544,753.08 3.00 18.18 900.00 10.45 24.98 898.05 847.85 28.39 14.64 6,031,795.52 544,758.92 300 31.32 1,000.00 13.42 22.81 995.88 945.68 47.31 22.97 6,031,814.49 544,767.14 3.00 51.80 1,053.07 15.00 22.00 1,047.32 997.12 59.36 27.93 6,031,826.57 544,772.02 3.00 64.75 End Dir : 1053.07' MD, 1047.32' TVD 1,100.00 15.00 22.00 1,092.65 1,042.45 70.62 32.48 6,031,837.86 544,776.50 0.00 76.82 1,200.00 15.00 22.00 1,189.25 1,139.05 94.62 42.18 6,031,861.91 544,786.05 0.00 102.56 Start Dir 3°1100': 1200' MD, 1189.25TVD 1,250.02 15.00 16.20 1,237.56 1,187.36 106.83 46.41 6,031,874.15 544,790.21 3.00 115.47 End Dir : 1250.02' MD, 1237.56' TVD 1,300.00 15.00 16.20 1,285.84 1,235.64 119.26 50.02 6,031,886.59 544,793.75 0.00 128.41 1,400.00 15.00 16.20 1,382.43 1,332.23 144.11 57.24 6,031,911.49 544,800.82 0.00 154.29 1,450.02 15.00 16.20 1,430.75 1,380.55 156.54 60.85 6,031,923.94 544,804.35 0.00 167.24 Start DWS -11100': 1450.02' MD, 1430.75'TVD 1,500.00 17.50 16.13 1,478.73 1,428.53 169.97 64.74 6,031,937.39 544,808.16 5.00 181.22 1,600.00 22.50 16.04 1,572.67 1,522.47 202.83 74.22 6,031,970.30 544,817.44 5.00 215.41 1,700.00 27.50 15.98 1,663.27 1,613.07 243.43 85.87 6,032,010.97 544,828.84 5.00 257.66 1,800.00 32.50 15.94 1,749.85 1,699.65 291.49 99.61 6,032,059.11 544,842.29 5.00 307.64 1,900.00 37.50 15.91 1,831.74 1,781.54 346.63 115.34 6,032,114.33 544,857.69 5.00 364.98 1,923.46 38.67 15.90 1,850.20 1,800.00 360.54 119.30 6,032,128.27 544,861.57 5.00 379.44 BPRF 2,000.00 42.50 15.88 1,908.32 1,858.12 408.43 132.94 6,032,176.23 544,874.91 5.00 429.23 2,100.00 47.50 15.86 1,979.01 1,928.81 476.42 152.27 6,032,244.33 544,893.83 5.00 499.92 2,200.00 52.50 15.84 2,043.27 1,993.07 550.09 173.18 6,032,318.12 544,914.30 5.00 576.50 2,300.00 57.50 15.83 2,100.61 2,050.41 628.87 195.53 6,032,397.02 544,936.17 5.00 658.39 2,330.07 59.00 15.82 2,116.43 2,066.23 653.47 202.50 6,032,421.66 544,942.99 5.00 683.96 End Dir : 2330.07' MD, 2116.44' TVD 2,400.00 59.00 15.82 2,152.45 2,102.25 711.14 218.84 6,032,479.43 544,958.99 0.00 743.90 2,411.17 59.00 15.82 2,158.20 2,108.00 720.35 221.45 6,032,488.65 544,961.54 0.00 753.47 SV1 2,500.00 59.00 15.82 2,203.95 2,153.75 793.61 242.21 6,032,562.03 544,981.86 0.00 829.62 2,600.00 59.00 15.82 2,255.45 2,20525 876.08 265.59 6,032,644.63 545,004.73 0.00 915.34 2,700.00 59.00 15.82 2,306.95 2,256.75 958.55 288.96 6,032,727.23 545,027.60 0.00 1,001.05 2,800.00 59.00 15.82 2,358.45 2,308.25 1,041.02 312.33 6,032,809.84 545,050.48 0.00 1,086.77 7/20/2018 6:49:53PM Page 3 COMPASS 5000.1 Build 81E Halliburton HALLI B U RTO N Standard Proposal Report Database: Sperry EDM - NORTH US +CANADA Local Coordinate Reference: Well Plan: MPU L41 Company: Hilcorp Alaska, LLC TVD Reference: MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14) Project: Milne Paint MD Reference: MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14) Site: M Pt L Pad North Reference: True Well: Plan: MPU L-41 Survey Calculation Method: Minimum Curvature Wellbore: MPU L-41 Depth Inclination Design: MPU L-41 wp10 TVDss -N/-S Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss -N/-S +El -W Northing Easting DLS Vert Section (usft) (^) (_) (usft) usft (usft) (usft) (usft) (usft) 2,359.75 2,900.00 59.00 15.82 2,409.95 2,359.75 1,123.50 335.70 6,032,892.44 545,073.35 0.00 1,172.49 2,970.39 59.00 15.82 2,446.20 2,396.00 1,181.55 352.15 6,032,950.58 545,089.45 0.00 1,232.83 UG4 3,000.00 59.00 15.82 2,461.45 2,411.25 1,205.97 359.07 6,032,975.04 545,096.22 0.00 1,258.21 3,100.00 59.00 15.82 2,512.95 2,462.75 1,288.44 382.44 6,033,057.64 545,119.09 0.00 1,343.93 3,200.00 59.00 15.82 2,564.45 2,514.25 1,370.91 405.82 6,033,140.24 545,141.97 0.00 1,429.65 3,300.00 59.00 15.82 2,615.95 2,565.75 1,453.38 429.19 6,033,222.85 545,164.84 0.00 1,515.37 3,400.00 59.00 15.82 2,667.45 2,617.25 1,535.85 452.56 6,033,305.45 545,187.71 0.00 1,601.09 3,500.00 59.00 15.82 2,718.95 2,668.75 1,618.32 475.93 6,033,388.05 545,210.58 0.00 1,686.80 3,600.00 59.00 15.82 2,770.45 2,720.25 1,700.79 499.30 6,033,470.65 545,233.46 0.00 1,772.52 3,700.00 59.00 15.82 2,821.95 2,771.75 1,783.27 522.67 6,033,553.26 545,256.33 0.00 1,858.24 3,800.00 59.00 15.82 2,873.45 2,823.25 1,865.74 546.05 6,033,635.86 545,279.20 0.00 1,943.96 3,900.00 59.00 15.82 2,924.95 2,874.75 1,948.21 569.42 6,033,718.46 545,302.07 0.00 2,029.68 4,000.00 59.00 15.82 2,976.45 2,926.25 2,030.68 592.79 6,033,801.06 545,324.95 0.00 2,115.40 4,100.00 59.00 15.82 3,027.95 2,977.75 2,113.15 616.16 6,033,883.66 545,347.82 0.00 2,201.12 4,200.00 59.00 15.82 3,079.45 3,029.25 2,195.62 639.53 6,033,966.27 545,370.69 0.00 2,286.84 4,300.00 59.00 15.82 3,130.95 3,080.75 2,278.09 662.90 6,034,048.87 545,393.56 0.00 2,372.55 4,400.00 59.00 15.82 3,182.45 3,132.25 2,360.56 686.28 6,034,131.47 545,416.44 0.00 2,458.27 4,500.00 59.00 15.82 3,233.95 3,183.75 2,443.03 709.65 6,034,214.07 545,439.31 0.00 2,543.99 4,600.00 59.00 15.82 3,285.45 3,235.25 2,525.51 733.02 6,034,296.68 545,462.18 0.00 2,629.71 4,700.00 59.00 15.82 3,336.95 3,286.75 2,607.98 756.39 6,034,379.28 545,485.06 0.00 2,715.43 4,800.00 59.00 15.82 3,388.45 3,338.25 2,690.45 779.76 6,034,461.88 545,507.93 0.00 2,801.15 4,900.00 59.00 15.82 3,439.95 3,389.75 2,772.92 803.13 6,034,544.48 545,530.80 0.00 2,886.87 5,000.00 59.00 15.82 3,491.45 3,441.25 2,855.39 826.51 6,034,627.09 545,553.67 0.00 2,972.58 5,100.00 59.00 15.82 3,542.95 3,492.75 2,937.86 849.88 6,034,709.69 545,576.55 0.00 3,058.30 5,149.02 59.00 15.82 3,568.20 3,518.00 2,978.29 861.34 6,034,750.18 545,587.76 0.00 3,100.32 LA3 5,200.00 59.00 15.82 3,594.45 3,544.25 3,020.33 873.25 6,034,792.29 545,599.42 0.00 3,144.02 5,300.00 59.00 15.82 3,645.95 3,595.75 3,102.80 896.62 6,034,874.89 545,622.29 0.00 3,229.74 5,400.00 59.00 15.82 3,697.45 3,647.25 3,185.27 919.99 6,034,957.49 545,645.16 0.00 3,315.46 5,500.00 59.00 15.82 3,748.95 3,696.75 3,267.75 943.36 6,035,040.10 545,668.04 0.00 3,401.18 5,600.00 59.00 15.82 3,800.45 3,750.25 3,350.22 966.74 6,035,122.70 545,690.91 0.00 3,486.90 5,700.00 59.00 15.82 3,851.95 3,801.75 3,432.69 990.11 6,035,205.30 545,713.78 0.00 3,572.62 5,800.00 59.00 15.82 3,903.45 3,853.25 3,515.16 1,013.48 6,035,287.90 545,736.65 0.00 3,658.33 5,900.00 59.00 15.82 3,954.96 3,904.76 3,597.63 1,036.85 6,035,370.51 545,759.53 0.00 3,744.05 6,000.00 59.00 15.82 4,006.46 3,956.26 3,680.10 1,060.22 6,035,453.11 545,782.40 0.00 3,829.77 6,100.00 59.00 15.82 4,057.96 4,007.76 3,762.57 1,083.59 6,035,535.71 545,805.27 0.00 3,915.49 6,197.56 59.00 15.82 4,108.20 4,058.00 3,843.03 1,106.40 6,035,616.30 545,827.59 0.00 3,999.12 SB -NA 6,200.00 59.00 15.82 4,109.46 4,059.26 3,845.04 1,106.97 6,035,618.31 545,828.14 0.00 4,001.21 6,263.58 59.00 15.82 4,142.20 4,092.00 3,897.48 1,121.83 6,035,670.83 545,842.69 0.00 4,055.71 SB -NB 6,300.00 59.00 15.82 4,160.96 4,110.76 3,927.52 1,130.34 6,035,700.91 545,851.02 0.00 4,086.93 6,400.00 59.00 15.82 4,212.46 4,162.26 4,009.99 1,153.71 6,035,783.52 545,873.89 0.00 4,172.65 6,500.00 59.00 15.82 4,263.96 4,213.76 4,092.46 1,177.08 6,035,866.12 545,896.76 0.00 4,258.37 7202018 6:49:53PM Page 4 COMPASS 5000.1 Build 81E HALLIBURTON Halliburton Standard Proposal Report Database: Company: Project: Site: Well: Wellbore: Design: Sperry EDM - NORTH US + CANADA Hilcorp Alaska, LLC Milne Point M Pt L Pad Plan: MPU L-41 MPU L-41 MPU L-41 wp10 Local Co-ordinate Reference: Well Plan: MPU L41 TVD Reference: MPL-41 wp06 prelim RKS @ 50.20usft (Doyon 14) MO Reference: MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14) North Reference: True Survey Calculation Method: Minimum Curvature Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (_) (^) (usft) usft (usft) (usft) (usft) (usft) 4,226.00 6,523.77 59.00 15.82 4,276.20 4,226.00 4,112.06 1,182.64 6,035,885.76 545,902.20 0.00 4,278.74 SE -OA 6,600.00 59.00 15.82 4,315.46 4,265.26 4,174.93 1,200.45 6,035,948.72 545,919.63 0.00 4,344.08 6,700.00 59.00 15.82 4,366.96 4,316.76 4,257.40 1,223.82 6,036,031.32 545,942.51 0.00 4,429.80 6,721.83 59.00 15.82 4,378.20 4,328.00 4,275.40 1,228.93 6,036,049.36 545,947.50 0.00 4,448.52 S8_oB 6,800.00 59.00 15.82 4,418.46 4,368.26 4,339.87 1,247.20 6,036,113.93 545,965.38 0.00 4,515.52 6,900.00 59.00 15.82 4,469.96 4,419.76 4,422.34 1,270.57 5,036,196.53 545,988.25 0.00 4,601.24 7,000.00 59.00 15.82 4,521.46 4,471.26 4,504.81 1,293.94 6,036,279.13 546,011.12 0.00 4,686.96 7,100.00 59.00 15.82 4,572.96 4,522.76 4,587.28 1,317.31 6,036,361.73 546,034.00 0.00 4,772.68 7,200.00 59.00 15.82 4,624.46 4,574.26 4,669.76 1,340.68 6,036,444.34 546,056.87 0.00 4,858.40 7,300.00 59.00 15.82 4,675.96 4,625.76 4,752.23 1,364.06 6,036,526.94 546,079.74 0.00 4,944.11 7,400.00 59.00 15.82 4,727.46 4,677.26 4,834.70 1,387.43 6,036,609.54 546,102.61 0.00 5,029.83 7,401.44 59.00 15.82 4,728.20 4,678.00 4,835.89 1,387.76 6,036,610.73 546,102.94 0.00 5,031.07 SB -BASE 7,500.00 59.00 15.82 4,778.96 4,728.76 4,917.17 1,410.80 6,036,692.14 546,125.49 0.00 5,115.55 7,600.00 59.00 15.82 4,830.46 4,780.26 4,999.64 1,434.17 6,036,774.74 546,148.36 0.00 5,201.27 7,637.94 • 59.00 15.82 4,850.00 • 4,799.80 5,030.93 1,443.04 6,036,806.09 546,157.04 0.00 5,233.80 9 5/8" x 121/4" 7,700.00 59.00 15.82 4,881.96 4,831.76 5,082.11 1,457.54 6,036,857.35 546,171.23 0.00 5,286.99 7,800.00 59.00 15.82 4,933.46 4,883.26 5,164.58 1,480.91 6,036,939.95 546,194.10 0.00 5,372.71 7,900.00 59.00 15.82 4,984.96 4,934.76 5,247.05 1,504.29 6,037,022.55 546,216.98 0.00 5,458.43 8,000.00 59.00 15.82 5,036.46 4,986.26 5,329.52 1,527.66 6,037,105.15 546,239.85 0.00 5,544.15 8,100.00 59.00 15.82 5,087.96 5,037.76 5,412.00 1,551.03 6,037,187.76 546,262.72 0.00 5,629.86 8,200.00 59.00 15.82 5,139.46 5,089.26 5,494.47 1,574.40 6,037,270.36 546,285.59 0.00 5,715.58 8,300.00 59.00 15.82 5,190.96 5,140.76 5,576.94 1,597.77 6,037,352.96 546,308.47 0.00 5,801.30 8,400.00 59.00 15.82 5,242.46 5,192.26 5,659.41 1,621.14 6,037,435.56 546,331.34 0.00 5,887.02 8,500.00 59.00 15.82 5,293.96 5,243.76 5,741.88 1,644.52 6,037,518.17 546,354.21 0.00 5,972.74 8,600.00 59.00 15.82 5,345.46 5,295.26 5,824.35 1,667.89 6,037,600.77 546,377.09 0.00 6,058.46 8,700.00 59.00 15.82 5,396.96 5,346.76 5,906.82 1,691.26 6,037,683.37 546,399.96 0.00 6,144.18 8,800.00 59.00 15.82 5,448.46 5,398.26 5,989.29 1,714.63 6,037,765.97 546,422.83 0.00 6,229.89 8,900.00 59.00 15.82 5,499.96 5,449.76 6,071.77 1,738.00 6,037,848.57 546,445.70 0.00 6,315.61 9,000.00 59.00 15.82 5,551.46 5,501.26 6,154.24 1,761.37 6,037,931.18 546,468.58 0.00 6,401.33 9,045.92 59.00 15.82 5,575.11 5,524.91 6,192.11 1,772.11 6,037,969.11 546,479.08 0.00 6,440.69 Start Dir 3"1100' : 9045.92' No, 5575.1VTVD 9,100.00 57.38 15.82 5,603.61 5,553.41 6,236.32 1,784.64 6,038,013.39 546,491.34 3.00 6,486.65 9,200.00 54.38 15.82 5,659.70 5,609.50 6,315.96 1,807.21 6,038,093.16 546,513.43 3.00 6,569.43 9,300.00 51.38 15.82 5,720.04 5,669.84 6,392.67 1,828.94 6,038,169.99 546,534.70 3.00 6,649.16 9,400.00 48.38 15.82 5,784.47 5,734.27 6,466.23 1,849.79 6,038,243.67 546,555.10 3.00 6,725.62 9,500.00 45.38 15.82 5,852.82 5,802.62 6,536.45 1,869.69 6,038,314.00 546,574.58 3.00 6,798.60 9,600.00 42.38 15.82 5,924.89 5,874.69 6,603.13 1,888.59 6,038,380.79 546,593.07 3.00 6,867.91 9,700.00 39.38 15.82 6,000.49 5,950.29 6,666.10 1,906.43 6,038,443.85 546,610.53 3.00 6,933.35 9,800.00 36.38 15.82 6,079.41 6,029.21 6,725.16 1,923.17 6,038,503.01 546,626.91 3.00 6,994.74 9,900.00 33.38 15.82 6,161.44 6,111.24 6,780.18 1,938.76 6,038,558.11 546,642.17 3.00 7,051.92 10,000.00 30.38 15.82 6,246.34 6,196.14 6,830.98 1,953.15 6,038,609.00 546,656.26 3.00 7,104.73 7/20/2018 6:49:53PM Page 5 COMPASS 5000.1 Build 81E Halliburton HAL L I B U R TO N Standard Proposal Report Database: Sperry EDM - NORTH US +CANADA Local Co-ordinate Reference: Well Plan: MPU L-41 Company: Hilcorp Alaska, LLC TVD Reference: MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14) Project: Milne Point MD Reference: MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14) Site: M Pt L Pad North Reference: True Well: Plan: MPU L41 Survey Calculation Method: Minimum Curvature Wellbore: MPU L41 Depth Inclination Design: MPU L41 wp10 TVDss -NIS Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss -NIS +EI -W Northing Easting DLS Vert Section (usft) (1 (') (usft) usft (usft) (usft) (usft) (usft) 6.283.70 10,100.00 27.38 15.82 6,333.90 6,283.70 6,877.45 1,966.32 5,038,655.54 546,669.14 3.00 7,153.02 10,200.00 24.38 15.82 6,423.86 6,373.66 6,919.44 1,978.22 6,038,697.59 546,680.79 3.00 7,196.66 10,300.00 21.38 15.82 6,515.98 6,465.78 6,956.84 1,988.82 6,038,735.06 546,691.16 3.00 7,235.54 10,346.00 20.00 15.82 6,559.01 6,508.81 6,972.48 1,993.25 6,038,750.72 546,695.50 3.00 7,251.79 End Dir : 10346' MD, 6559.01' TVD - Start ESP Tangent 10,400.00 20.00 15.82 6,609.75 6,559.55 6,990.25 1,998.28 6,038,768.52 546,700.42 0.00 7,270.26 10,500.00 20.00 15.82 6,703.72 6,653.52 7,023.15 2,007.61 6,038,801.47 546,709.55 0.00 7,304.46 10,532.43 20.00 15.82 6,734.20 6,684.00 7,033.83 2,010.63 6,038,812.16 546,712.51 0.00 7,315.55 HRZ 10,547.00 20.00 15.82 6,747.89 6,697.69 7,038.62 2,011.99 6,038,816.97 546,713.84 0.00 7,320.54 End ESP Tangent 10,600.00 20.00 15.82 6,797.69 6,747.49 7,056.06 2,016.93 6,038,834.43 546,718.67 0.00 7,338.66 10,666.52 20.00 15.82 6,860.20 6,810.00 7,077.95 2,023.13 6,038,856.36 546,724.74 0.00 7,361.41 KLB 10,697.17 20.00 15.82 6,889.00 6,838.80 7,088.03 2,025.99 6,038,866.46 546,727.54 0.00 7,371.90 7" x 8 112" 10,700.00 20.00 15.82 6,891.66 6,841.46 7,088.97 2,026.25 6,038,867.39 546,727.80 0.00 7,372.87 10,728.24 20.00 15.82 6,918.20 6,868.00 7,098.26 2,028.89 6,038,876.70 546,730.38 0.00 7,382.52 KLGM 10,800.00 20.00 15.82 6,985.63 6,935.43 7,121.87 2,035.58 6,038,900.35 546,736.92 0.00 7,407.07 10,883.61 20.00 15.82 7,064.20 7,014.00 7,149.39 2,043.37 6,038,927.91 546,744.55 0.00 7,435.66 KUP_D 10,900.00 20.00 15.82 7,079.60 7,029.40 7,154.78 2,044.90 6,038,933.31 546,746.05 0.00 7,441.27 10,988.96 20.00 15.82 7,163.20 7,113.00 7,184.05 2,053.20 6,038,962.63 546,754.17 0.00 7,471.70 KUP_C 10,996.54 20.00 15.82 7,172.20 7,122.00 7,187.21 2,054.09 6,038,965.79 546,755.04 0.00 7,474.97 KUP_B7 11,000.00 20.00 15.82 7,173.57 7,123.37 7,187.69 2,054.23 6,038,966.27 546,755.17 0.00 7,475.47 11,086.87 20.00 15.82 7,255.20 7,205.00 7,216.27 2,062.33 6,038,994.90 546,763.10 0.00 7,505.18 KUP_A3 11,100.00 20.00 15.82 7,267.54 7,217.34 7,220.59 2,063.55 6,038,999.23 546,764.30 0.00 7,509.67 11,106.02 20.00 15.82 7,273.20 7,223.00 7,222.57 2,064.11 6,039,001.21 546,764.85 0.00 7,511.73 KUP_A2 11,135.82 20.00 15.82 7,301.20 7,251.00 7,232.38 2,066.89 6,039,011.03 546,767.57 0.00 7,521.92 KUP_A1 11,194.35 20.00 15.82 7,356.20 7,306.00 7,251.64 2,072.35 6,039,030.32 546,772.91 0.00 7,541.94 KUP_A_BASE 11,200.00 20.00 15.82 7,361.51 7,311.31 7,253.50 2,072.87 6,039,032.19 546,773.42 0.00 7,543.88 11,300.00 20.00 15.82 7,455.48 7,405.28 7,286.41 2,082.20 6,039,065.15 546,782.55 0.00 7,578.08 11,400.00 20.00 15.82 7,549.45 7,499.25 7,319.31 2,091.52 6,039,098.10 546,791.67 0.00 7,612.28 11,500.00 20.00 15.82 7,643.42 7,593.22 7,352.22 2,100.85 6,039,131.06 546,800.80 0.00 7,646.48 11,586.87 20.00 15.82 7,725.05 7,674.85 7,380.80 2,108.95 6,039,159.69 546,808.72 0.00 7,676.19 Total Depth: 11586.87' MD, 7725.05' TVD 7120/2018 6:49:53PM Page 6 COMPASS 5000.1 Build 81E Halliburton H A LL I B U R TO N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Coordinate Reference: Well Plan: MPU L-41 Company: Hilcorp Alaska, LLC TVD Reference: MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14) Project: Milne Point MD Reference: MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14) Site: M Pt L Pad North Reference: True Well: Plan: MPU L-41 Survey Calculation Method: Minimum Curvature Wellbore: MPU L-41 (usft) (usft) Design: MPU L41 wp10 7,216.27 2,062.33 Targets Target Name -hitimiss target Dip Angle Dip Dir. NO +N/ -S +E/ -W Northing Easting -Shape (•) (•) (usft) (ustt) (usft) (usft) (usft) MPU L-41 Tgti wp09 KUP 0.00 0.00 7,255.20 7,216.27 2,062.33 6,038,994.90 546,763.10 - plan hits target center - Circle (radius 200.00) Fault 111 0.00 0.00 7,050.20 -809.18 -531.15 6,030,954.77 544,218.24 - plan misses target center by 5066.23usft at 3493.24usft MD (2715.47 TVD, 1612.75 N, 474.35 E) - Polygon Point 1 7,050.20 0.00 0.00 6,030,954.77 544,218.24 Point 7,050.20 862.68 305.05 6,031,819.19 544,518.06 Point 3 7,050.20 1,488.20 475.07 6,032,445.66 544,684.29 Point 7,050.20 2,202.58 852.98 6,033,162.23 545,057.86 Point 5 7,050.20 2,587.66 1,024.37 6,033,548.30 545,226.91 Point 7,050.20 3,293.68 1,196.49 6,034,255.27 545,394.76 Point 7,050.20 4,345.45 1,608.34 6,035,309.40 545,800.23 Point 7,050.20 4,588.77 1,834.27 6,035,554.05 546,024.67 Point 7,050.20 5,434.62 2,258.66 6,036,402.36 546,443.92 Point 10 7,050.20 5,905.93 2,460.64 6,036,874.83 546,643.04 Point 11 7,050.20 6,167.95 2,543.46 6,037,137.31 546,724.28 Point 12 7,050.20 6,608.04 2,666.80 6,037,578.10 546,844.95 Point 13 7,050.20 8,424.64 3,427.43 6,039,399.06 547,594.56 Point 14 7,050.20 8,580.66 3,377.00 6,039,554.76 547,543.20 Point 15 7,050.20 8,365.11 3,220.24 6,039,338.29 547,387.75 Point 16 7,050.20 7,932.02 3,318.12 6,038,905.84 547,488.23 Point 17 7,050.20 7,683.91 3,226.24 6,038,657.21 547,397.85 Point 18 7,050.20 6,383.07 2,742.29 6,037,353.61 546,921.79 Point 19 7,050.20 6,032.34 2,643.39 6,037,002.32 546,825.01 Paint 20 7,050.20 4,719.60 2,048.18 6,035,686.15 546,237.77 Point 21 7,050.20 4,416.63 1,826.61 6,035,381.88 546,018.05 Point 22 7,050.20 3,759.78 1,490.87 6,034,723.09 545,686.30 Point 23 7,050.20 3,581.44 1,425.28 6,034,544.37 545,621.79 Point 24 7,050.20 3,569.97 1,376.16 6,034,532.61 545,572.75 Point 25 7,050.20 3,119.06 1,247.10 6,034,080.97 545,446.42 Point 26 7,050.20 2,544.28 1,137.92 6,033,505.60 545,340.71 Point 27 7,050.20 2,030.38 939.91 6,032,990.57 545,145.82 Paint 28 7,050.20 1,441.96 596.05 6,032,400.15 544,805.54 Point 29 7,050.20 865.92 422.42 6,031,823.13 544,635.40 Point 30 7,050.20 0.00 0.00 6,030,954.77 544,218.24 Fault 112 0.00 0.00 7,263.20 8,235.92 -1,006.85 6,039,995.96 543,688.14 - plan misses target center by 3233.63usft at 11143.75usft MD (7308.65 TVD, 7234.99 N, 2067.63 E) - Polygon Point 1 7,263.20 0.00 0.00 6,039,995.96 543,688.14 Point 2 7,263.20 4.99 295.31 6,040,002.73 543,983.39 Point 3 7,263.20 -11.75 761.52 6,039,988.80 544,449.64 Point 7,263.20 -27.83 1,176.97 6,039,975.22 544,865.14 Points 7,263.20 -55.49 1,462.94 6,039,949.28 545,151.24 Point 6 7,263.20 -110.39 1,755.82 6,039,896.15 545,444.42 Point 7 7,263.20 -227.06 2,201.24 6,039,782.18 545,890.49 Point 7,263.20 -272.89 2,444.82 6,039,737.82 546,134.32 Point 9 7,263.20 -283.49 2,566.32 6,039,727.95 546,255.87 Point 10 7,263.20 -338.26 2,922.71 6,039,675.33 546,612.55 Point 11 7,263.20 -323.11 3,158.78 6,039,691.90 546,848.50 Point 12 7,263.20 -325.85 3,278.37 6,039,689.88 546,968.09 Point 13 7,263.20 -340.09 3,397.01 6,039,676.36 547,086.80 Point 14 7,263.20 -393.73 3,629.14 6,039,624.12 547,319.23 Point 15 7,263.20 -464.27 3,856.09 6,039,554.95 547,546.58 Point 16 7,263.20 -620.28 3,906.52 6,039,399.27 547,597.94 Point 17 7,263.20 -056.11 3,395.98 6,039,560.34 547,086.47 7/20/2018 6:49:53PM Page 7 COMPASS 5000.1 Build 81E HALLIBURTON Database: Sperry EDM - NORTH US+CANADA Company: Hiloorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: Plan: MPU L41 Wellbore: MPU L-41 Design: MPU L-41 wp10 1- 1114 1. Point 19 Point 20 Point 21 Point 22 Point 23 Point 24 Point 25 Point 26 Point 27 Point 28 Casing Points Local Corordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU LAI MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14) MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14) True Minimum Curvature Measured Vertical Casing Hole 7,263.20 -424.54 3,128.92 6,039,590.30 546,819.25 7,263.20 -431.71 2,863.34 6,039,581.54 546,553.75 7,263.20 -361.20 2,474.29 6,039,649.70 546,164.32 7,263.20 -341.26 2,347.82 6,039,668.87 546,037.74 7,263.20 -202.73 1,846.36 6,039,804.37 545,535.51 7,263.20 -133.42 1,586.55 6,039,872.11 545,275.31 7,263.20 -79.17 1,320.71 6,039,924.75 545,009.17 7,263.20 -46.34 1,049.68 6,039,955.94 544,737.98 7,263.20 -21.22 693.60 6,039,978.92 544,381.79 7,263.20 0.00 0.00 6,039,995.96 543,688.14 Measured Vertical Casing Hole Depth Depth Dip Diameter Diameter (usft) (usft) Name (usft) Name 7,637.94 4,850.00 95/8"x121/4" 9-5/8 12-114 10,697.17 6,889.00 7"x812' 7 8-1/2 11,586.87 7,725.05 4112"x61/8" 4-1/2 6-118 Formations i Measured Vertical Vertical Dip Depth Depth Depth 55 Dip Direction (usft) (usft) Name Lithology 7,401.44 4,728.20 SB BASE 10,666.52 6,860.20 KLB 2,970.39 2,446.20 UG4 2,411.17 2,158.20 SV7 10,883.61 7,064.20 KUP_D 10,998.54 7,172.20 KUP_B7 11,194.35 7,356.20 KUP_A_BASE 1,923.46 1,850.20 BPRF 11,135.82 7,301.20 KUP A7 11,106.02 7,273.20 KUP_A2 10,532.43 6,734.20 HRZ 10,988.96 7,163.20 KUP_C 6,197.56 4,108.20 SB NA 6,523.77 4,276.20 SS CA 10,728.24 6,918.20 KLGM 6,263.58 4,142.20 SB NB 6,721.83 4,378.20 SB 08 5,149.02 3,568.20 LA3 11,086.87 7,255.20 KUP_A3 7202018 6:49:53PM Page 8 COMPASS 5000.1 Build 81E HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hllcorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: Plan: MPU L-01 Wellbore: MPU L-41 Design: MPU L-41 wp10 Plan Annotations Measured Vertical Depth Depth (usft) (usft) 550.00 550.00 1,053.07 1,047.32 1,200.00 1,189.25 1,250.02 1,237.56 1,450.02 1,430.75 2,330.07 2,116.43 9,045.92 5,575.11 10,346.00 6,559.01 10,547.00 6,747.89 11,586.87 7,725.05 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU LAI TVD Reference: MPL-41 wp06 prelim RKB @ 50.20usft (Doyon 14) MD Reference: MPI -41 wp06 prelim IRKS @ 60.20usft (Doyon 14) North Reference: True Survey Calculation Method: Minimum Curvature Local Coordinates +N/ -S +E/ -W (usft) (usft) Comment 0.00 0.00 Start Dir 3°/100' : 550' MD, 550'TVD 59.36 27.93 End Dir : 1053.07' MD, 1047.32' TVD 94.62 42.18 Start Dir 3°/100' : 1200' MD, 1189.25'TVD 106.83 46.41 End Dir : 1250.02' MD, 1237.56' TVD 156.54 60.85 StartDir 5°1100' : 1450.02' MD, 1430.75'TVD 653.47 202.50 End Dir : 2330.07' MD, 2116.44' TVD 6,192.11 1,772.11 Start Dir 3°1100' : 9045.92' MD, 5575.1l'TVD 6,972.48 1,993.25 End Dir : 10346' MD, 6559.01' TVD - Start ESP Tangent 7,038.62 2,011.99 End ESP Tangent 7,380.80 2,108.95 Total Depth : 11586.87' MD, 7725.05' TVD 7202018 6:49:53PM Page 9 COMPASS 5000.1 Build 81E Hilcorp Alaska, LLC Milne Point M Pt L Pad Plan: MPU L-41 MPU L-41 MPU L-41 wp10 Sperry Drilling Services Clearance Summary Anticollision Report 20 July, 2018 Closest Approach 30 Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt L Pad -Plan: MPU L41 -MPU L41 -MPU L41 wp10 Well Coordinates: 6,031,767.05 N, 544,744.45 E (70° 29' 51.57" N, 149° 38' 02.74" W) Datum Haight: MPL41 wp06 prelim RKB @ 50.20usft (Doyon 14) Scan Range: 0,00 to 11,586.87 usft. Measured Depth. Scan Radius Is 1,588.06 usft. Clearance Factor cutoff Is Unlimited. Max Ellipse Separation Is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build: SIE Scan Type: Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU L-41 - MPU L-41 wp10 Hilcorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt L Pad - Plan: MPU L-01 - MPU L-41 - MPU L-41 wp10 Scan Range: 0.00 to 11,586.87 usft. Measured Depth. Scan Radius is 1,588.06 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measuretl Ellipse @Measuretl 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 L Pad MPL-04 - MPL-04 - MPL-04 1,665.18 245.59 1,665.18 229.56 1,843.91 15.317 Centre Distance Pass - MPL-04 - MPL-04 - MPL-04 1,675.00 245.66 1,675.00 229.54 1,853.14 15.235 Ellipse Separation Pass - MPL-04 - MPL-04 - MPL-04 1,775.00 254.08 1,775.00 236.99 1,946.92 14.864 Clearance Factor Pass - MPL-05 - MPL-05 - MPL-05 1,923.50 357.92 1,923.50 343.14 2,137.45 24.218 Ellipse Separation Pass - MPL-05 - MPL-05 - MPL-05 7,625.00 1,516.54 7,625.00 1,237.91 7,782.75 5.443 Clearance Factor Pass - MPL-08 - MPL-08 - MPL-08 1,775.54 209.91 1,775.54 196.26 1,817.61 15.378 Ellipse Separation Pass - MPL-08 - MPL-08 - MPL-08 2,175.00 319.43 2,175.00 289.61 2,180.58 10.711 Clearance Factor Pass - MPL-13 - MPL-13 - MPL-13 757.19 209.40 757.19 200.94 779.61 24.736 Centre Distance Pass - MPL-I3-MPL-I3-MPL-13 775.00 209.44 775.00 200.90 798.56 24.526 Ellipse Separation Pass - MPL-I3-MPL-13-MPL-13 1,625.00 310.41 1,625.00 291.05 1,645.93 16.037 Clearance Factor Pass- MPL-I4-MPL-I4-MPL-14 1,150.00 48.14 1,150.00 38.03 1,141.71 4.761 - Pass - MPL-I4-MPL-I4-MPL-14 33.70 59.66 33.70 58.75 20.70 65.375 - Pass - MPL-I5-MPL-I5-MPL-15 1,693.99 306.77 1,693.99 293.39 1,845.79 22.928 Centre Distance Pass - MPL-I5-MPL-I5-MPL-15 1,700.00 306.78 1,700.00 293.35 1,852.66 22.847 Ellipse Separation Pass - MPLA5-MPL-I5-MPL-15 3,750.00 763.35 3,750.00 677.61 3,965.89 8.903 Clearance Factor Pass - MPL-I5-MPL-15PB1-MPL-15PB1 1,693.99 306.77 1,693.99 293.39 1,845.79 22.928 Centre Distance Pass - MPL-I5-MPL-15PS1-MPL-15PB1 1,700.00 306.78 1,700.00 293.35 1,852.66 22.847 Ellipse Separation Pass - MPL-15 - MPL-15PB1 - MPL-15PB1 3,300.00 592.40 3,300.00 497.97 3,520.00 6.273 Clearance Factor Pass - MPL-I6-MPL-I6-MPL-16 33.70 30.00 33.70 29.09 35.22 32.895 Centre Distance Pass - MPL-I6-MPL-I6-MPL-16 325.00 31.69 325.00 27.18 326.10 7.023 Ellipse Separation Pass - MPL-I6-MPL-I6-MPL-16 700.00 44.02 700.00 34.71 697.71 4.727 Clearance Factor Pass- MPL-I6-MPL-I6A-MPL-16A 33.70 30.00 33.70 29.20 29.43 37.377 Centre Distance Pass - MPL-I6-MPL-I6A-MPL-16A 325.00 31.69 325.00 27.29 320.31 7.198 Ellipse Separation Pass - MPL-I6-MPL-I6A-MPL-16A 700.00 44.02 700.00 34.82 691.92 4.783 Clearance Factor Pass - MPL-17-MPL-17-MPL-17 1,142.73 48.10 1,142.73 38.02 1,134.72 4.774 Ellipse Separation Pass - MPL-17-MPL-17-MPL-17 1,150.00 48.14 1,150.00 38.03 1,141.71 4.761 Clearance Factor Pass - MPL-20 - MPL-20 - MPL-20 33.70 59.66 33.70 58.75 20.70 65.375 Centre Distance Pass - MPL-20 - MPL-20 - MPL-20 675.00 63.15 675.00 54.07 660.48 6.955 Ellipse Separation Pass - 20 Ju/y, 2018 - 18:43 Page 2 of 7 COMPASS HALLIBURTON Anticollision Report for Plan: MPU L-41 - MPU L-41 wp10 Hilcorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) MPL-39 - MPL-39 33.70 243.94 33.70 242.59 34.88 181.282 Reference Design: M Pt L Pad - Plan: MPU L41 - MPU L41 - MPU L41 wp10 Pass - MPL-39 - MPL-39 - MPL-39 325.00 246.45 325.00 241.82 Scan Range: 0.00 to 11,586.87 usft. Measured Depth. 53.176 Ellipse Separation Pass - MPL-39 - MPL-39 - MPL-39 725.00 266.50 725.00 Scan Radius is 1,588.06 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited 27.946 Clearance Factor Pass - MPL-43-MPL43-MPL43 33.70 109.95 Measured Minimum @Measured Ellipse @Measuretl Clearance Summary Based on MPL43- MPL-43 Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name -Wellbore Name - Design (usft) (usft) (usft) (usft) usft 4.732 Clearance Factor Pass - MPL-20 - MPL-20 - MPL-20 725.00 64.22 725.00 54.76 709.55 6.787 Clearance Factor Pass - MPL-2I-MPL-2I-MPL-21 1,162.20 85.65 1,162.20 73.72 1,136.01 7.177 Centre Distance Pass - MPL-2I-MPL-2I-MPL-21 1,175.00 85.72 1,175.00 73.70 1,148.28 7.133 Ellipse Separation Pass - MPL-2I-MPL-21-MPL-21 8,125.00 743.91 8,125.00 607.64 8,378.24 5.459 Clearance Factor Pass - MPL-24 - MPL-24 - MPL-24 919.12 86.27 919.12 75.64 910.06 8.118 Centre Distance Pass - MPL-24 - MPL-24 - MPL-24 975.00 86.43 975.00 75.47 964.64 7.887 Ellipse Separation Pass - MPL-24 - MPL-24 - MPL-24 1,125.00 89.71 1,125.00 77.80 1,110.99 7.536 Clearance Factor Pass - MPL-25-MPL-25-MPL-25 1,907.87 78.47 1,907.87 60.91 1,858.29 4.468 Centre Distance Pass - MPL-25-MPL-25-MPL-25 1,925.00 78.60 1,925.00 60.66 1,874.63 4.380 Ellipse Separation Pass - MPL-25 - MPL-25 - MPL-25 4,625.00 384.16 4,625.00 268.57 4,622.75 3.324 Clearance Factor Pass - MPL-28 - MPL-28 - MPL-28 33.70 120.12 33.70 119.21 33.40 131.585 Centre Distance Pass - MPL-28 - MPL-28 - MPL-28 950.00 126.50 950.00 115.60 938.41 11.603 Ellipse Separation Pass - MPL-28 - MPL-28 - MPL-28 1,075.00 130.84 1,075.00 119.17 1,056.83 11.216 Clearance Factor Pass - MPL-28 - MPL-28A - MPL-28A 33.70 120.12 33.70 119.32 33.40 149.496 Centre Distance Pass - MPL-28 - MPL-28A - MPL-28A 950.00 126.50 950.00 115.71 938.41 11.720 Ellipse Separation Pass - MPL-28 - MPL-28A- MPL-28A 1,075.00 130.84 1,075.00 119.28 1,056.83 11.322 Clearance Factor Pass - MPL-29 - MPL-29 - MPL-29 2,034.35 66.13 2,034.35 47.08 1,968.24 3.471 Centre Distance Pass - MPL-29 - MPL-29 - MPL-29 21050.00 66.35 2,050.00 46.68 1,982.68 3.373 Ellipse Separation Pass - MPL-29 - MPL-29 - MPL-29 2,075.00 67.69 2,075.00 47.11 2,005.69 3.289 Clearance Factor Pass - MPL-32 - MPL-32 - MPL-32 720.01 144.38 720.01 134.86 717.52 15.165 Centre Distance Pass - MPL-32 - MPL-32 - MPL-32 750.00 144.49 750.00 134.81 746.44 14.929 Ellipse Separation Pass - MPL-32 - MPL-32 - MPL-32 850.00 147.63 850.00 137.43 839.95 14.474 Clearance Factor Pass - MPL-33 - MPL-33 - MPL-33 1,115.35 162.44 1,115.35 150.73 1,082.02 13.881 Centre Distance Pass - MPL-33 - MPL-33 - MPL-33 11125.00 162.48 1,125.00 150.72 1,090.61 13.820 Ellipse Separation Pass - MPL-33 - MPL-33 - MPL-33 1,275.00 170.30 1,275.00 157.58 1,229.63 13.385 Clearance Factor Pass - MPL-39 - MPL-39 - MPL-39 33.70 243.94 33.70 242.59 34.88 181.282 Centre Distance Pass - MPL-39 - MPL-39 - MPL-39 325.00 246.45 325.00 241.82 322.70 53.176 Ellipse Separation Pass - MPL-39 - MPL-39 - MPL-39 725.00 266.50 725.00 256.96 710.29 27.946 Clearance Factor Pass - MPL-43-MPL43-MPL43 33.70 109.95 33.70 109.26 34.50 157.457 Centre Distance Pass - MPL43- MPL43- MPL-43 175.00 110.91 175.00 108.66 174.10 49.259 Ellipse Separation Pass - MPL43 - MPL43 - MPL43 2,875.00 218.11 2,875.00 172.02 2,671.77 4.732 Clearance Factor Pass - 20 July, 2018 - 18:43 Page 3 of 7 COMPASS HALLIBURTON Anticollision Report for Plan: MPU L-41 - MPU L-41 wp10 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt L Pad - Plan: MPU L-41 - MPU L-41 - MPU L-41 wpio Scan Range: 0.00 to 11,586.87 usft. Measured Depth. Scan Radius is 1,588.06 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Hilcorp Alaska, LLC Milne Point 20 July, 2018 - 18:43 Page 4 of COMPASS 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-43 - MPL-43PB1 - MPL-43PB1 33.70 109.95 33.70 109.04 34.50 120.583 Centre Distance Pass - MPL-43 - MPL-43PB1 - MPL-43PB1 175.00 110.91 175.00 108.45 174.10 44.992 Ellipse Separation Pass - - MPL-43 - MPL-43PB1 - MPL-43PB1 2,875.00 218.11 2,875.00 171.79 2,671.77 4.708 Clearance Factor Pass - MPL-45 - MPL-45 - MPL45 447.55 25.56 447.55 20.34 447.93 4.898 Centre Distance Pass - MPL-45 - MPLA5 - MPL45 525.00 25.10 525.00 19.94 525.05 4.238 Ellipse Separation Pass - MPL-45 - MPL-45 - MPL45 600.00 27.85. 600.00 20.79 599.69 3.942 Clearance Factor Pass - MPU L-51 - MPU L-51 - MPU L-51 307.01 164.22 307.01 160.12 299.02 40.064 Centre Distance Pass - MPU L-51 - MPU L-51 - MPU L-51 700.00 166.01 700.00 157.27 690.26 18.985 Ellipse Separation Pass - MPU L-51 - MPU L-51 - MPU L-51 775.00 167.91 775.00 158.91 763.58 18.663 Clearance Factor Pass - MPU L -52 -MPU L -52 -MPU L-52 658.83 171.89 658.83 163.54 646.88 20.590 Centre Distance Pass - MPU L -52 -MPU L -52 -MPU L-52 700.00 172.05 700.00 163.37 685.58 19.823 Ellipse Separation Pass - MPU L -52 -MPU L -52 -MPU L-52 800.00 173.93 800.00 164.99 779.73 19.453 Clearance Factor Pass - MPU L-53 - MPU L-53 - MPU L-53 495.15 194.57 495.15 188.13 487.38 29.740 Centre Distance Pass - MPU L -53 -MPU L -53 -MPU L-53 600.00 195.33 600.00 187.43 589.86 24.749 Ellipse Separation Pass - MPU L -53 -MPU L -53 -MPU L-53 775.00 200.79 775.00 191.73 754.09 22.182 Clearance Factor Pass - MPU L -54 -MPU L -54 -MPU L-54 1,126.63 46.58 1,126.63 35.79 1,126.41 4.315 Clearance Factor Pass - MPU L -56 -MPU L -56 -MPU L-56 818.89 209.61 818.89 197.43 808.25 17.197 Clearance Factor Pass - Plan: MPU L-55 - MPU L-41 objectives - MPU L-55 wp 279.10 113.17 279.10 108.55 279.30 24.507 Centre Distance Pass - Pian: MPU L-55 - MPU L-41 Objectives - MPU L-55 wp 350.00 113.69 350.00 107.85 347.84 19.486 Ellipse Separation Pass - Plan: MPU L-55 - MPU L41 Objectives - MPU L-55 wp 9,275.00 1,167.20 9,275.00 1,023.00 8,991.85 8.095 Clearance Factor Pass - Plan: MPU L-58 - MPU L-58 Sag Objectives - MPU L-5 530.45 58.49 530.45 49.42 531.81 6.450 Centre Distance Pass - Plan: MPU L-58 - MPU L-58 Sag Objectives - MPU L-5 575.00 58.82 575.00 48.97 575.93 5.972 Ellipse Separation Pass - PIen: MPU L -58 -MPU L-58 Sag Objectives - MPU L-5 700.00 64.21 Mom 52.61 698.91 5.536 Clearance Factor Pass- RIG: MPU L57 -MPU L -57 -MPU L-57 955.13 182.17 955.13 173.04 936.64 19.949 Ellipse Separation Pass - RIG: MPU L-57 - MPU L-57 - MPU L-57 975.00 182.32 975.00 173.16 954.42 19.899 Clearance Factor Pass - RIG: MPU L-57 - MPU L-57PB1 - MPU L-57PB1 955.13 182.17 955.13 173.04 936.64 19.949 Ellipse Separation Pass - RIG: MPU L-57 - MPU L-57PB1 - MPU L-57PB1 975.00 182.32 975.00 173.16 954.42 19.899 Clearance Factor Pass - RIG: MPU L-57. MPU L57PB1 - MPU L-57 WP09 974.86 174.13 974.86 160.40 957.57 12.680 Centre Distance Pass - RIG: MPU L-57 - MPU L-57PB1 - MPU L-57 WP09 975.00 174.13 975.00 160.40 957.69 12.680 Ellipse Separation Pass - RIG: MPU L-57 - MPU L-57PB1 - MPU L-57 WP09 1,000.00 174.50 1,000.00 160.69 978.42 12.633 Clearance Factor Pass - 20 July, 2018 - 18:43 Page 4 of COMPASS HALLIBURTON Anticollision Report for Plan: MPU L-41 - MPU L-41 wp10 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt L Pad - Plan: MPU L-41 - MPU L-41 - MPU L41 wp10 Scan Range: 0.00 to 11,586.87 usft. Measured Depth. Scan Radius is 1,588.06 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Site Name Comparison Well Name -Wellbore Name - Design Well #1_L-53 Row - Well #1 - Well #2 Targets wp01 Well #1_L-53 Row- Well #1 - Well #2 Targets wp01 Survey tool proamm Measured Minimum @Measured Depth Distance Depth (usft) (usft) (usft) 1.430.87 148.45 1,430.87 1,450.02 148.87 1,450.02 From To Clearance (usft) (usft) Depth 33.70 700.00 MPU L-41 wp10 700.00 7,640.00 MPU L-41 wp10 7,640.00 10.700.00 MPU L41 wp10 10,700.00 11,586.87 MPU L41 wp10 Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Survey/Plan Ellipse @Measuretl Clearance Summary Based on Separation Depth Factor Minimum (usft) usft 136.68 1,431.06 12.609 Ellipse Separation 136.99 1,446.64 12.534 Clearance Factor Survey Tool 2_Gyro-SR-GSS 2 MWD+IFR2+MS+Sag 2 MWD+IFR2+MS+Sag 2_MWD+IFR2+MS+Sag Hilcorp Alaska, LLC Milne Point Separation Warning Pass - Pass - 20 July, 2018 - 18:43 Page 5 of COMPASS HALLIBURTON Project: Milne Point REFERENCE INFORMATION WE DE AL:PIa:M1P 441 NAD1927MADCONCONUS) Alaska ZoneW Site: MFit L Pad Sperry OMlling Well: Plan: MPU L-41 Wellbore: MPU L-41 CaaNirele(N/E)Reference: Well Plan: MPU L41, True None `/edical(ND) RMerance: MP1_-41 wp(e prellm RGI@ 50.Musit (Doyon 14) Measured Depth Reference: MPL-41 wpW prelim R103 @ MMusR (Doyon 14) Calculation Meroad, Minimum cungture Ground Level' 16.50 +N/-S +E/-W Northing Eaaing lafidude LonyvWde 0,00 000 6031]6].05 544744A5 70° 29' 51.5]2 N 149° 38' 2.738 W Plan: MPU L-41 wp10 SURVEY PROGRAM GLOBAL FILTER: Using user defined selection 8 filtering criteria Depth From Depth To Survey/Plan Tool 1 33.70 To 11586 87 Ladder/S.F. Plots(1 of 2) Surface Hole Only 33.70 700.00 MPU L41 wp10 2_Gym-SR-GSS 700.00 7640.00 MPU L41 wp10 2 MWD+IFR2+MS+Sag 7640.00 10700.00 MPU L41 wp10 2 MWD+IFR2+MS+Sag 10700.00 11586.87 MPU L41wp10 2_MWD+IFR2+MS+Sag CASING DETAILS TVD TVDSS MD Size Name 4850.00 4799.80 7637.94 9-5/8 95/8" x 121/4" 6889.00 6838.80 10697.17 7 7" x 8 l/2" 7725.05 7674.85 11586.87 4-12 4 In" x 61/8" 5150.00 m AM X120.00 MP Mar 1 I - _0–. – II I Z Ter9 Is wP01 � __ MPL-25 MPL 4 M 14 �'� -----. T 29 c MP 1J 90.00 m L 24 I Ly MPU LS wP C L4 L-25 60.00 0) U o 11 MPL MPL0 -1 ..yMPL 17 " MPL-2 30.00 U MP -45 0.00 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600 Measured Depth (800 usftlin) 4.50 ___._ _.- ---- 0 o m 3.00— 00 O .0 6 W 1.50 Collision Risk Procedures Req. )„ Collision Avoidance Req. NO-Go Zone - Stop Drilling I 0.00 0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400 5850 6300 6750 7200 7650 Measured Depth (800 usfVin) HALLIBURTON Project: Milne Point REFERENCE INFORMATION WELL DETAIIS:%an: MPU LiI NAD1927(NADCONCONOB) Alaska Zone04 Coon inste (WE) Reference: Well Plan: NPU Lit. True Noah Ground Level: 16.50 Venicel(rVD) Referenw:MPL-41 wPW Pelpn RKB C Sa.2Wsa Payon 14) + Measured Deah Reference: MPL-41 wpe9Wolin RKB@Q 5o.2ousfi(ooyon 14) 0008 +000 60�3W176T05 544746165 7V 29'91,5UN 149ude 382,738W calculation Mutual : Minimum cawawre Site: M Pt L Pad Sperry OrlllinD Well: Plan: MPU L-41 Wellbore: MPU L-41 Plan: MPU L-41 wp10 SURVEY PROGRAM GLOBAL FILTER: Using user defined selection 8 filtering criteria EM 3370 To 11566.87 Depth From Depth To Survey/Plan Tool Ladder/S.F. Plots(2 of 2) INT & Prod Hole 33.70 700.00 MPU L41 wp10 2 Gyro-SR-GSS 700.00 7640.00 MPU L41 wp10 2_MWD+IFR2+MS+Sag 7640.00 10700.00 MPU L41 wp10 2 MWD+IFR2+MS+Sag 10700.00 11586.87 MPU L-41 wp10 2_MWD+IFR2+MS+Sag CASING DETAILS TVD TVDSS AAD Size Name 4850.00 4799.80 7637.94 9-5/8 95/8" x 12 1/4" 6889.00 6838.80 10697.17 7 7' x 8 12" 7725.05 7674.85 11586.87 4-1/2 412"x61/8" C150.00 on 3 I o j I � I 0 o 90+00- 0.00 m 60.00 60.00 0 U I- I O .0�-. 30.00 c 0 U I i o.DO 7200 7500 7800 8100 8400 8700 9000 9300 9600 9900 10200 10500 10800 11100 11400 11700 12000 12300 12600 Measured Depth (600 usft/in) o I I i 300 _ . - ___ ..........-. I o Collision Risk Procedures Req. n Collision Avoidance Req. I i No-Go Zone - Stop Drilling 0.00 7000 7350 7700 8050 8400 8750 9100 9450 9800 10150 10500 10850 11200 11550 11900 12250 12600 Measured Depth (600 usft/in) �1 Davies, Stephen F (DOA) From: Joe Engel <jengel@hilcorp.com> Sent: Monday, August 13, 2018 3:13 PM To: Davies, Stephen F (DOA) Subject: Hilcorp MPU L-41 (PTD#: Not Yet Assigned) Directional Plan Attachments: MPU L-41 wp10_GEO.TXT Hello Steve — Hilcorp submitted the application for permit to drill MPU L-41 on Friday, August 10th. Per your request, attached is a digital copy of the directional plan. Please let me know if you have any questions. Thank you for your time. -Joe Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 I Cell: 805.235.6265 Remark: AOGCC PTD No. 218-104 Coordinate Check 14 August 2018 INPUT Geographic, NAD27 OUTPUT State Plane, NAD27 5004 -Alaska 4, U.S. Feet MPU L-41 1/1 Latitude: 70 29 51.572 Northing/Y: 6031767.095 Longitude: 149 38 02.732 EaSting/X: 544744.670 Convergence: 0 20 41.69539 Scale Factor: 0.999902274 Corpscon v6.0.1, U.S. Army Corps of Engineers TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: Z ley el Development _ Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: �iyJ /' POOL: X�L a4_::�tz� le— 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' sam le 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, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, KUPARUK RIVER OIL - 525100 Well Name: MILNE PT UNIT L-41 Program DEV Well bore seg ❑ I PTD#:2181040 Company HILCORP ALASKA LLC Initial Class/Type DEV / PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Disposal ❑ Administration 17 Nonconven. gas conforms to AS31.05.030(i.1.A),(j.2.A-D) . . . . .... . ........... NA .... _ _ _ _ _ _ _ _ _ . Date: 1 Permit fee attached _ . _ _ _ ........ NA 81 � I } � j 2 Lease number appropriate... _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ Surface Location lies within ADL0026509; Top. Prod Int & TD lie within ADL0355017.... 3 Unique well, name and number _ _ _ _ _ _ _ _ Yes 4 Well located in. a. defined pool .. .... _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ Milne. Point, Kuparuk River Oil Pool,. governed. by Conservation Order No, 432D 5 Well located proper distance from drilling unit. boundary _ Yes Conservation Order No. 432D contains no spacing restrictions with respectto drilling unit boundaries. 6 Well located proper distance from other wells _ _ _ _ _ .. _ _ Yes _ Conservation Order No. 432D has. no interwell. spacing_ restrictions.... _ .. 7 Sufficient acreage available In. drilling unit. _ _ _ _ _ _ _ _ Yes _ Wellbore will be more than 50V from an external property line where ownership or landownership 8 1f. deviated, is wellbore plat. included .. _ _ _ _ _ Yes changes.. Well will conform to spacing requirements... 9 Operator only affected part... _ _ _ Yes 10 Operator has appropriate bond in force - _ _ Yes Appr Date 11 Permit. can be issued without conservation order.. .. Yes 12 Permit can be issued without administrative. approval Yes SFO 8/14/2018 13 Can permit be approved before 15 -day wait.. _ _ _ _ _ Yes 14 Well located within area and. strata authorized by Injection Order # (put 10# in comments) (For NA 15 All wells within 1/4 mile area of review identified (For service well only) _ _ _ _ _ _ _ _ _ NA 16 Pre -produced injector: duration of pre prodUctipn less than 3 months (For service well only) _ NA 18 Conductor string. provided ..................... . . . . . . . ..... Yes _ 20 inch.conductor set at 80ft Engineering 19 Surface casing. protects all known USDWs .... _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA no aquifers 20 CMT. vol adequate to circulate on conductor & surf mg _ _ _ _ _ NA 9 5/8" surface. casing will be fully. cemented... using 2 stage. ES 21 CMT. vot adequate to tie-in long string to surf csg. _ _ _ _ _ _ No... int casing will be cemented 500 8 MD at shoe 22 CMT. will cover all known productive horizons....... ....... Yes 4.5 inch liner will be fully cemented.. 23 Casing designs adequate for C, T, 6 & permafrost. _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ BTC calcs provided. 24 Adequate tankage or reserve pit _ _ _ _ .......... . .. Yes Rig has steel pits... All waste to approved disposal well. 25 If a. re -drill, has a 10-403 for abandonment been approved _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA _ _ grassroots well.... .. 26 Adequate wellbore separation proposed _ _ _ Yes Close crossing with L-14 at about 5000 ft. md.. Precautions needed. x.27 If diverter required, does it meet regulations - - _ _ _ _ _ _ _ _ _ _ Yes Appr Date 28 Drilling fluid program schematic & equip list adequate _ Yes Max form pressure =.3476 psi will drill with 12.5 ppg mud.. (with MPD) GLS 8/21/2018 29 BOPEs,.do they meet regulation _ _ _ _ .. _ _ _ _ Yes _ Doyon 14 ROPE 30 BOPE_press rating appropriate; test to (put prig in comments) _ Yes MASP= 2704 psi Will test BOPEto 4000 psi. 31 Choke. manifold complies w/API RP -53 (May 84)_ _ _ _ _ _ _ _ _ Yes 32 Work will occur without operation shutdown.. _ _ _ _ _ _ _ _ _ _ _ Yes _ Sundry required to perforate and frac stimulate the well 33 Is presence of H2S gas probable ... _ _ _ _ _ _ _ _ _ _ _ _ No... H2S on pad . Rig has sensors and alarms. 34 Mechanical condition of wells within AOR verified (For service well only) ......... _ NA 35 Permit can be issued w/o hydrogen sulfide measures _ _ _ _ _ _ _ _ _ _ _ _ _ No.. H2S measures required. Potential exists to encounter H2S in this mature reservoir. Geology 36 Data. presented on potential overpressure zones _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ Expected reservoir pressure is 8.7 ppg EMW; maximum potential is 12.5 ppg. Managed Pressure Drilling _ Appr Date 37 Seismic analysis of shallow gas zones _ _ _ _ _ _ _ _ NA Technique (MPDT) will be used to control potential geo-pressure and shale. Sufficient barite will be on SFD 8/14/2018 38 Seabed condition survey (if off -shore) _ _ _ _ ........ _ NA. location to increase mud weight to_1. ppg greater than operator's highest anticipated mud weight. 39 Contact name/phone for weekly progress reports [exploratory only] _ _ _ _ _ _ _ _ _ _ NA _ _ Potential exists to encounter gas, hydrates while.drilling. Mitigation measures discussed on p. 51._ Geologic Engineering Public Sundry required for fracture stimulation and perfing. GIs Commissioner: Date: Commissioner: Date Commissioner Dat DTS 81 � I } � j �7z3 11 ta)
