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Home My WebLink About216-1531. 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: Complete 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 9,620'feet 9,387 feet true vertical 9,093'feet N/A feet Effective Depth measured 9,387'feet 7,030 feet true vertical 8,865'feet 6,668 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 7,150' 6,779' 7,030' MD Packers and SSSV (type, measured and true vertical depth)Baker Premier N/A 6,668' TVD N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Contact Email: Authorized Title:Operations Manager Contact Phone: 322-182 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 1,294 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 24 0 Brian Glasheen brian.glasheen@hilcorp.com 907-564-5277 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 19 2,6684,798 263 181 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 427 Gas-Mcf MD 106' 5,215' 1,085 TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 216-153 50-029-23571-00-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0047437, ADL0047438 MILNE POINT / KUPARUK RIVER OIL, SAG RIVER OIL Hilcorp Alaska LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: MILNE PT UNIT B-30 measuredPlugs Junk measured N/A Length 106' 5,215' Size Conductor Surface Production 20" 9-5/8" 7"9,605' Casing 106' 4,933' 9,078'9,605' 5,410psi N/A 5,750psi 7,240psi Burst Collapse N/A 3,090psi Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Meredith Guhl at 9:47 am, Jul 19, 2022 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2022.07.19 08:53:37 -08'00' David Haakinson (3533) _____________________________________________________________________________________ Revised by: DH 7/13/2022 SCHEMATIC Milne Point Unit Well: MPU B-30 Last Completed: 5/12/22 PTD: 216-153 TD =9,620 (MD) / TD =9,093(TVD) 20 KB Elev.:49.6/ GL Elev.:23.1 RKB THF: 22.92 (Innovation) 9-5/8 36Cement Plug Top @ 9,378 ELM 5/18/2022 PBTD =9,515 (MD) /PBTD = 8,990(TVD) 7 ES Cementer @ 1,819 SAG TOC 8,600 MD CAST M 5/13/17 TOC 6,050 MD CAST M 5/13/17 ES Cementer @ 7,600 4 5 6 1 3 2 Last Tag: @ 9,515 SLM 8/04/19 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 78.6 / A-53 / Weld 19.124 Surface 106 9-5/8" Surface 40 / L-80 / DWC/C 8.835 Surface 5,215 7" Production 26 / L-80 / Hydril 563 6.276 Surface 9,605 TUBING DETAIL 4-1/2 Tubing 12.6 /L-80/ TXP 3.920 Surface 7,150 WELL INCLINATION DETAIL KOP @ 600 MD Max Hole Angle = 25.08 deg at 8,467 MD Hole angle through perforated interval: 12° TREE & WELLHEAD Tree Wellhead Seaboard Weir, 3 spools, w/11 x 5M top flange. 2-7/8 TC-II Tubing Hanger PERFORATION DETAIL Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kup C 7,246 7,259 6,869 6,881 15 5/18/2022 Open Kup B 7,269 7,288 6,891 6,908 19 5/18/2022 Open Kup B SLT 7,316 7,347 6,934 6,963 31 5/18/2022 Open Kup B SLT 7,362 7,392 6,977 7,005 30 5/18/2022 Open Sag River 9,450 9,490 8,926 8,965 40 5/20/17 Closed Perf Guns: 2.875, 60 Phase HSC w/MaxForce charges / Ref Log: HES CAST 5/13/17 OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 50 bbls of Arcticset in 42 Hole 9-5/8" (2nd Stage) Cmt w/ 350 sks 10.7 ppg Perm L, 275 sx 15.8 ppg SwiftCEM in 12-1/4 Hole 9-5/8 (1st Stage) Cmt w/ 505 sks 11.7 ppg ExtendaCEM, 215 sx 15.8 ppg SwiftCEM in 12-1/4 Hole 7 (2nd Stage) Cmt w/ 119 sks 14.7 ppg Class G in 8-1/2 Hole 7 (1st Stage) Cmt w/ 165 sks 15.3 ppg Class G in 8-1/2 Hole GENERAL WELL INFO API: 50-029-23571-00-00 Drilled, Cased & Completed by Innovation #1 5/16/2017 Frac Job 5/29/2017 Recompletion by ASR #1 6/17/2017 Recompletion and Perf by ASR #1 5/12/2022 JEWELRY DETAIL No Depth Item ID 1 6,926 4-1/2 HES Sliding Sleeve 3.813 2 6,963 4-1/2 Zenith C-6 Gauge Carrier 3.930 3 7,030 7 x 4-1/2 Baker Premier Packer 3.870 4 7,100 4-1/2 XN Nipple w/RHC-M 3.725 5 7,111 4-1/2 TXP WLEG, bottom @ 7,150 N/A 6 9,414 7 CIBP N/A SAFETY NOTE Seaboard conductor supported wellhead. Retrofit reverse acting slip style hanger installed Sept 2019 Well Name Rig API Number Well Permit Number Start Date End Date MP B-30 Eline/ ASR #1 50-029-23571-00-00 216-153 4/23/2022 5/19/2022 WELL S/I ON ARRIVAL, DSO NOTIFIED, PT PCE 250L/2500H. (troubleshoot leak). RAN 2" CENT, 3'x1-1/2" STEM, 2.1" STEM, 1.75" LIB & TAGGED PRONG @ 9,430' SLM, CLEAR IMPRESSION OF PRONG ON LIB. RAN 2.1" CENT, 3'x1-1/2" STEM, 2-7/8" 42BO (keys up) DOWN TO XD SS @ 9,223' SLM (9,201' MD) & SHIFTED SLEEVE CLOSED, 42BO PIN NOT SHEARED. LRS ATTEMPTED TO PRESSURE UP TUBING TO 1700psi 3 TIMES, LOST 1000psi IN 5min EACH TIME. WELL S/I ON DEPARTURE, DSO NOTIFIED. 4/28/2022 - Thursday (Pressure Test equipment to 250/2500 psi) Pumped 15 bbls diesel down IA and never caught pressure. Pumped 22 bbls diesel down TBG to freeze protect. Never caught pressure. 4/30/2022 - Saturday Load Well/CMIT-TxIA to 3000 psi. (Pressure Test equipment to 250/2500 psi) Pumped 327 bbls of 120* Produced water down TBG up IA taking returns to tank. Pumped a total of 10 bbls of 100* diesel down TBG/IA. TBG/IA pressures fell off rapidly. Let well settle over night for possible thermal. WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2500H. SET PXN-PLUG (4x3/16" ports, OAL=23') IN XN-NIP AT 9432' SLM/9413' MD. SET P-PRONG (1-3/8" FN, max OD 1.5", OAL=40") AT 9430' SLM IN PXN-PLUG. PULL BK-OGLV (orifice, recovered all packing). FROM STA#1 AT 8576' SLM/8555' MD. PULL BK-LGLV (dome, recovered all packing) FROM STA#2 AT 8020' SLM/8001' MD. L/D FOR THE NIGHT, NOTIFY PAD-OP. CONTINUE TICKET 04-23-22. 4/23/2022 - Saturday CONTINUE TICKET FROM 04-24-22. WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2500H. RUN 1.25" LIB TO STA#10 AT 2335' SLM/2340' MD (impression of BK latch, backside of impression looks like something could be there). ATTEMPT TO PULL BK-LGLV FROM STA#10 AT 2335' SLM/2340' MD (metal mark on backside edge of daniels skirt, per WSL leave in pocket). SHIFT OPEN XD-SS AT 9223' SLM/9201' MD WITH 2-7/8 42BO (keys down). RDMO, CLOSE PERMIT W/PAD- OP. 4/27/2022 - Wednesday 4/24/2022 - Sunday CONTINUE TICKET FROM 04-23-22.WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2500H. STA#4 AT 6718' SLM/6706' MD - PULL BK-LGLV (dome, recovered all packing), SET BK-DGLV. STA#6 AT 5449' SLM/5440' MD - PULL BK-LGLV (dome, recovered all packing), SET BK-DGLV. STA#8 AT 4145' SLM/4143' MD - PULL BK-LGLV (dome, recovered all packing), SET BK-DGLV. STA#9 AT 3524' SLM/3526' MD - PULL BK-DGLV (recovered all packing), SET BK-DGLV. STA#2 AT 8020' SLM/8001' MD - SET BK-DGLV / STA#1 AT 8576' SLM/8555' MD - SET BK-DGLV. L/D FOR THE NIGHT, NOTIFY PAD-OP. CONTINUE TICKET 04-25-22. (MIT-OA) ( Pre RWO) (Pressure Test equipment to 250/2500 psi) MIT-OA to 1200 psi Inconclusive. Pressured up OA with 1.8 bbls diesel. 3rd test= 15 min OA lost 43 psi. 30 min OA lost 31 psi. Bled back 1.5 bbls. Tags hung. 4/25/2022 - Monday Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP B-30 Eline/ ASR #1 50-029-23571-00-00 216-153 4/23/2022 5/19/2022 Hilcorp Alaska, LLC Weekly Operations Summary 5/6/2022 - Friday ND tree, changed API ring, NU tree on J-06 and test Void to 5000psi good test. Cont'd RD for move to B-30. MIRU ASR on B-30, spot rig on mud boat and spot pits into position. Set rig floor on the well house with the crane. Offload 190 BBLS of 8.3 PPG source water fluid in the pits. Cont'd hooking up lines and laying out koomy hoses. Stand rig to full mast. Spot pipe handler skid in place and cont'd rigging up ASR. Installed flow riser and bird bath on the stack. Prepped for BOPE Test. PU and MU 2 7/8'' test Jt. Start filling up lines and shell test. Test BOPE's and CMV to low/high 250psi/2500psi 5 min tests witness waived by AOGCC Adam Earl. 5/7/2022 - Saturday Finished rigging up for BOPE test, cleared air out of system and shell tested BOPE's. Test BOPE witness waived by AOGCC Adam Earl low/high 250psi/2500psi 5min each test. Preformed accumulator drawdown test, RU LJ and screwed into hanger. BOLDS and prepared to pull hanger. Starting working pipe to pull hanger and to get the packer to release @ PUW= 97K increased to 105K and increased to 115k. Worked pipe 6-7 times until pulled free. Free PUW= 72k LD hanger. While pulling hanger pumped 125bbls down the IA w/no returns. RU to pump down the tubing and pumped 55bbls no returns or pump psi. No packer gas was observed at surface. Changed pipe handling equip on the floor, Functioned ESD's, service the rig, POOH LD 2 7/8'' Jber CR13 tubing and tec cable F/ 9410' T/ 5347' . While POOH could see the packer hanging up on casing collars ever so often causing 10-15k overpull then dropping right off. 5/1/2022 - Sunday WELL S/I ON ARRIVAL, DSO NOTIFIED, PT PCE 250L/2500H. (troubleshoot leak). RAN 2-7/8" D&D HOLE FINDER DOWN TO 9,410' SLM, 20' ABOVE PLUG & TESTED TUBING TO 600psi. PULLED P-PRONG FROM 9,430' SLM, ALL PACKING RECOVERED. PULLED 2-7/8" P-PLUG FROM XN @ 9,432' SLM (9,413' MD), ALL PACKING & PINS RECOVERED. SET 2-7/8" CAT STANDING VALVE IN XN NIP @ 9,432' SLM (9,413' MD), LRS PRESSURED UP TUBING TO 1500psi, LOST 300psi IN 5min. LRS PRESSURED UP IA TO 1000psi, LOST 700psi IN 1min. WELL S/I ON DEPARTURE, DSO NOTIFIED. 5/2/2022 - Monday WELL S/I ON ARRIVAL, DSO NOTIFIED, PT PCE 250L/2500H. (troubleshoot leak). SET 2-7/8" PXX PLUG BODY (oal: 23") IN X-NIP @ 9,372' SLM (9,355' MD), GOOD PULL TEST, SHEARED OFF CLEAN, ALL PINS ON X-LINE RECOVERED. SET P-PRONG (oal: 40") IN PXX PLUG BODY @ 9,372' SLM (9,355' MD). LRS PRESSURED UP TUBING & IA TO 3300pai FOR COMBO MIT (pass). RAN 2.1" CENT, 3'x1-1/2" STEM, 2-7/8" 42BO (keys down) & SHIFTED XD SS @ 9,223' SLM (9,201' MD) OPEN, MADE 10 PASSES THROUGH CLEAN, HAD 300psi PRESSURE GAIN ON TUBING, 42BO PIN NOT SHEARED. PULLED P-PRONG FROM PXX PLUG @ 9,370' SLM, ALL PACKING RECOVERED. PULLED 2-7/8" PXX PLUG BODY FROM X-NIP @ 9,372' SLM (9,255' MD), ALL PACKING & PINS RECOVERED. PULLED 2-7/8" CAT STANDING VAVLE FROM XN @ 9,432' SLM (9,413' MD), ALL PACKING RECOVERED. WELL S/I ON DEPARTURE, DSO NOTIFIED. Well Name Rig API Number Well Permit Number Start Date End Date MP B-30 Eline/ ASR #1 50-029-23571-00-00 216-153 4/23/2022 5/19/2022 Hilcorp Alaska, LLC Weekly Operations Summary Service rig check fluids and ESD's. POOH 2 7/8'' F/5347' T/2135' observing packer hanging up with 10-15k over pull intermittingly on casing collars. Service rig hydraulics C/O high psi oil filters due to possible containments in oil. POOH 2 7/8'' F/ 2135' T/885' observing packer hanging up with 10-15k over pull at every casing collar. Service rig. Had incident where the carriage came into contact with a mid racking link pin causing the top of the pin to fall out ~15 to the floor. This was due to the keeper pin backing out and letting the pin move causing the incident. Replaced pin and conducted mast inspection. POOH 2 7/8'' F/885' T/791' pulled 16k over and could not go up or down. MU XO's to power swivel head to attempt rotating. Rig lost hydraulic psi on AUX pump #2 and could not run slips and pipe handler. Called out rig mech to troubleshoot and fix. Cleared return valve of debris and hydraulics started working. Set 7k down and rotated 1 full turn in pipe and then pulled free with 15k over pull. RD XO's from power swivel. POOH 2 7/8'' F/791' T/Surface pulling pipe slow and observing hang ups every jt max over pull 10K. Once packer made it to the floor you could see that the packer rubbers were catching and causing the hang ups while POOH. Total clamps : 299 Cannon clamps and 24 mid clamps. Clear rig floor of cannon clamps. Cleared pipe rack and catwalk of all 2 7/8'' tubing and jewelry. Moved spooling unit prepping for WL. RU AK EL. 5/9/2022 - Monday RU AK EL & RIH w/ 5.75'' gauge ring/ junk basket to 9425' POOH LD tools. MU 7'' CIBP RIH w/ AK EL and set on correlated depth @ 9414'. Saw 400lbs drop, pulled up 10' and tagged CIBP for verification of set. POOH closed blind rams, LD tools and RD AK EL. RU to test 7'' casing and CIBP. While pressuring up hydraulic pump failed stopping at 2600psi. Released AK EL. LO/TO all necessary equip to trouble shoot and work on rig hydraulics. Started to strap and tally 4.5'' completion tubing and jewelry. Called out Little Red to perform 7'' casing and CIBP MIT. Good 30min 3000psi test. LO/TO all necessary equip to trouble shoot and work on rig hydraulics. Cont'd cleaning up and organizing around rig. 5/10/2022 - Tuesday Service rig. Installed rebuilt rig hydraulic pump. Cont'd cleaning rig and prepping 4.5'' completion tubing. While testing rebuilt hydraulic pump found a bad rubber seal on high psi oil filter and replaced. Installed new keeper bolts on all racking pins to prevent them from backing out again. Troubleshot and identified link tilt function failure before PU 4.5'' completion tubing and jewelry. Spot tech wire spooling unit. Ran tech wire through ESP sheave and installed in mast. PU & MU 4.5'' jet pump completion assy as per Company and BOT Rep. Attached tech wire. Service rig. RIH w/ 4.5'' jet pump assy and completion tubing T/4456' testing tech wire every 1000' SOW=38K PUW=53K. 5/8/2022 - Sunday Well Name Rig API Number Well Permit Number Start Date End Date MP B-30 Eline/ ASR #1 50-029-23571-00-00 216-153 4/23/2022 5/19/2022 Hilcorp Alaska, LLC Weekly Operations Summary WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2500H. PULL BALL & ROD AT 7100' SLM WITH 3.60" & 2.60" BELL GUIDES, 2" JUS. PULL 4-1/2 RHC FROM XN-NIP AT 7106' SLM/7100' MD. DRIFT & TAG CIBP AT 9433' SLM/9414' MD WITH 3.5" CENT, 2'x1-7/8" STM, 3.5" G-RING (no restrictions). RDMO, CLOSE PERMIT W/PAD-OP. 5/14/2022 - Saturday WELL S/I ON AARIVAL***(dump bail cement). TAG PLUG AT 9419', NO POSITIVE INDICATION OF DUMPED CEMENT. BAILERS FULL ON SURFACE. LAY DOWN AND CLEAN BAILERS. WELL S/I, WSR CONT ON 15-MAY-2022. 5/15/2022 - Sunday JOB CONT. FROM 14-MAY-2022 (dump bail cement). DUMP APPROX 7' (11.5 gal) OF CEMENT ON PLUG. ON THIRD RUN, BAILER CAME BACK FULL. WELL S/I, WSR CONT ON 16-MAY-2022. 5/11/2022 - Wednesday Rig service. RIH w/ 4.5'' jet pump assy and completion tubing F/4456' T/5562' testing tech wire every 1000'. Took 12K down weight @ 5562' got with well engineer to make a plan moving forward. SOW=49K PUW=7OK. Worked pipe up and down setting 15K down and getting 8K overpull. Kept working this made about 1' of progress. Decide to hook up and reverse circ to possibly get by tight spot. PU & MU XO's to circ w/power swivel hooking up Kelly hose to power swivel. Pumping made it worse got minimal circ and shut down. Started setting 20k down weight and slowly making head way into hole F/5662' T/5710' broke free and started moving better but not free taking 10-18k down weight to 5791' started moving free without taking weight. Service rig. RIH w/ 4.5'' jet pump assy and completion tubing F/5791' T/7122' no tight spots testing tech wire every 1000' final test at 7122' Good test. MU 2 7/8'' LJ to 4.5'' TCII Hanger. C/O pipe handling equip to 2 7/8''. Terminate Tech wire to hanger as per wellhead tech. Landed hanger on depth @ 7150' PUW=90K SOW=63K. RILDS. Total cannon clamps= 94,LD 2 7/8'' LJ w/ 4.5'' TCII XO ready to install for dropping the ball and rod. RU hoses for pumping corrosion inhibited brine off the vac-truck w/ rig pump. Also RU hoses and valves for using Little Red to pump FP, setting packer, and MIT's on well. Spot vac-truck in place and pumped 100 BBLS of 1% KCL brine with corrosion inhibitor down the IA at 3 bpm, 390 psi. 5/12/2022 - Thursday Rig up LRS and pump 70 bbl of diesel freeze protect down IA taking returns up the tubing 2 bpm, 150 psi. Line up to allow diesel freeze protect to U-tube to the tubing. Drop ball and rod. Allow ball and rod to fall to ball seat at 7101' MD. Increase pressure on tubing to 3200 psi. Observe indication of packer shear pins shearing at 1700 psi. Hold pressure for 30 min to test tubing (good test). Reduce tubing pressure to 1000 psi. Line up to pump down the IA. Pressure test IA to 3700 psi for 30 min (good test). Both tests charted. RD ASR #1 off of B-30 move carrier into the ASR rig shop to C/O hydraulic filters and oil. ***Rig released from B-30 at 18:00, see E-20 report for 5/13/2022*** 5/13/2022 - Friday Well Name Rig API Number Well Permit Number Start Date End Date MP B-30 Eline/ ASR #1 50-029-23571-00-00 216-153 4/23/2022 5/19/2022 Hilcorp Alaska, LLC Weekly Operations Summary Plug Verification and PERF. Tag TOC @ 9,378' (36' above CIBP) i. 7362-7392 MD (Shot 3 pressure increased 0 to 200 PSI) ii. 7316-7347 MD Shot 3 pressure increased 0 to 200 PSI) iii. 7269-7288 MD No Pressure Change iv. 7246-7259 MD No Pressure Change 2.875" Guns, 6 SPF, 60 Degree Phasing, Maxfire Charges AOGCC MIT-T to 2500 psi (PASSED) (Witnessed by Matt Herrea) (Pressure test equipment to 250/3500 psi) Pump 3.5 bbls Dsl to reach Test pressure. 1st 15 Min Tbg lost 39 psi. 2nd 15 Min Tbg lost 13 psi. Bleed Tbg down w/ 3 bbls Dsl returned. 5/19/2022 - Thursday WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2500H. SHIFT XD-SS OPEN WITH 4-1/2 42BO AT 6932' SLM/6925' MD (took 3 runs, sheaered pin twice). SET 3" JET PUMP (serial# BP-1111, ratio: 12A, sec lock, screen, OAL=70"") IN XD-SS AT 6929' SLM/6925' MD. RDMO, CLOSE PERMIT W/PAD-OP, TAG WELL. 5/16/2022 - Monday JOB CONT. FROM 15-MAY-2022. (dump bail cement). DUMP APPROXIMATELY 26 GAL OF 17 PPG CEMENT. JOB CONT ON 17- MAY-2022. STILL IN PROGRESS, WOC. 5/17/2022 - Tuesday JOB CONT. FROM 16-MAY-2022. (dump bail cement). DUMP 6.5 GALLONS OF 17 PPG CEMENT. ESTIMATED TOTAL VOLUME DUMPED: 44 GALLONS. STILL IN PROGRESS, WOC. 5/18/2022 - Wednesday Kaitlyn Barcelona Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: Date: 07/11/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL Well API # PTD # Log Date Log Company Log Type Notes BCU 18RD 50133205840100 222033 6/11/2022 Yellowjacket GPT-PERF + Report BCU 18RD 50133205840100 222033 6/18/2022 Yellowjacket GPT-PERF + Report BCU 18RD 50133205840100 222033 6/7/2022 Yellowjacket GPT-PLUG + Report BCU 24 50133206390000 214112 6/16/2022 Halliburton PPROF BCU 24 50133206390000 214112 5/23/2022 Yellowjacket GPT-PERF + Report BCU 24 50133206390000 214112 5/26/2022 Yellowjacket GPT-PERF + Report BCU 7A 50133202840100 214060 6/21/2022 Yellowjacket CBL BCU 7A 50133202840100 214060 6/15/2022 Yellowjacket GAMMA RAY + Report BRU 232-26 50283200770000 184138 5/25/2022 Yellowjacket CBL CLU 01RD 50133203230100 203129 5/19/2022 Yellowjacket PERF + Report CLU 01RD 50133203230100 203129 5/24/2022 Yellowjacket PERF + Report CLU 09 50133205440000 204161 5/27/2022 Yellowjacket PERF + Report CLU-1RD 50133203230100 203129 5/28/2022 Halliburton PPROF + Report END 1-17A 50029221000100 196199 5/26/2022 Halliburton LDL END 1-45 50029219910000 189124 5/23/2022 Halliburton LDL + Report END 3-17F 50029219460600 203216 6/15/2022 AK E-Line PLUG CUT FALLS CREEK 3 50133205240000 203102 6/4/2022 Yellowjacket PERF + Report HVB B-16 50231200400000 212133 6/14/2022 AK E-Line CIBP KALOTSA 1 50133206570000 216132 7/7/2022 Yellowjacket PERF + Report KBU 11-07 50133205560000 205165 6/16/2022 Yellowjacket GPT-PERF + Report KBU 11-07 50133205560000 205165 6/20/2022 Yellowjacket GPT-PERF + Report KBU 33-06X 50133205290000 203183 6/22/2022 Yellowjacket CBL MPU B-28 50029235660000 216027 5/27/2022 Halliburton LDL MPU B-28 50029235660000 216027 5/27/2022 Halliburton MFC + Report MPU B-30 50029235710000 216153 5/18/2022 Halliburton PERF MPU E-06 50029221540000 191048 5/28/2022 Halliburton MFC + Report Kaitlyn Barcelona Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: MPU E-35 50029236150000 218152 6/15/2022 Halliburton MFC + Report MPU L-50 50029235550000 215132 6/24/2022 Read COIL FLAG PAXTON 10 50133206910000 220064 5/27/2022 Halliburton PPROF + Report PBU C-24B 50029208160200 212063 5/28/2022 Halliburton PPROF + Report PBU C-24B 50029208160200 212063 5/28/2022 Halliburton RBT PBU GNI-03 50029228200000 197189 6/25/2022 Read CALIPER PBU GNI-03 50029228200000 197189 6/25/2022 Read TEMP-PRESS PBU K-01 50029209980000 183121 6/21/2022 Halliburton PPROF + Report PBU M-13A 50029205220100 201165 5/27/2022 Halliburton TMD3D-WFL + Report PBU NGI-05 50029201960000 176014 6/7/2022 Halliburton CAST PBU W-01A 50029218660100 203176 6/8/2022 Halliburton RBT SRU 241-33 50133206630000 217047 6/13/2022 Yellowjacket PERF SRU 241-33B 50133206960000 221053 5/25/2022 Halliburton TEMP-PRESS SRU 32A-33 50133101640100 191014 6/11/2022 AK E-Line PPROF Please include current contact information if different from above. BCU 18RD PTD:222-033 T36747 BCU 24 PTD:214-112 T36748 BCU 7A PTD:214-060 T36749 BRU 232-26 PTD:184-138 T36750 CLU 01RD PTD:203-129 T36751 CLU 09 PTD: 204-161 T36752 CLU1RD PTD:203-129 T36751 END 1-17A PTD:196-199 T36753 END 1-45 PTD:189-124 T36754 END 3-17F PTD:203-216 T36755 Falls Creek 3 PTD:203-102 T36756 HVB B-16 PTD:212-133 T36757 Kalosta 1 PTD:216-132 T36758 KBU 11-7 PTD:205-165 T36759 KBU 33-06X PTD:203-183 T36760 MPU B-28 PTD:216-027 T36761 MPU B-30 PTD:216-153 T36762 MPU E-06 PTD: 191-048 T36763 MPU E-35 PTD:218-152 T36764 MPU L-50 PTD:215-132 T36765 Paxton 10 PTD:220-064 T36766 PBU C-24B PTD:212-063 T36767 PBU GNI-03 PTD:197-189 T36768 PBU K-01 PTD:183-121 T36769 PBU M-13A PTD:201-165 T36770 PBU NGI-05 PTD:176-014 T36771 PBU W-01A PTD:203-176 T36772 SRU 241-33 PTD:217-047 T36773 SRU 241-33B PTD:221-053 T36774 SRU 32A-33 PTD: 191-014 T36775 Kayla Junke Digitally signed by Kayla Junke Date: 2022.07.12 12:56:51 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 18 Township: 13N Range: 11E Meridian: Umiat Drilling Rig: HES Rig Elevation: 22.9 Total Depth: 9620 ft MD Lease No.: ADL 047438 Operator Rep: Suspend: P&A: X Conductor: 20 O.D. Shoe@ 106 Feet Csg Cut@ Feet Surface: 9 5/8" O.D. Shoe@ 5215 Feet Csg Cut@ Feet Intermediate: O.D. Shoe@ Feet Csg Cut@ Feet Production: 7" O.D. Shoe@ 9605 Feet Csg Cut@ Feet Liner: O.D. Shoe@ Feet Csg Cut@ Feet Tubing: 2 7/8" O.D. Tail@ 9452 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Fullbore Bridge plug 9414 ft 9378 ft 17 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 2774 2735 2722 IA 148 148 147 OA 0 0 0 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Josh McNeal Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): MPU B-30 was originally drilled as a SAG producer and completed as a Gaslift producer. Due to poor performance well is to be converted to a Kuparuk producer with a Jet Pump completion per Sundry 322-182 May 18, 2022 Matt Herrera Well Bore Plug & Abandonment MPU B-30 Hilcorp Alaska LLC PTD 2161530; Sundry 322-182 none Test Data: P Casing Removal: rev. 11-28-18 2022-0518_Plug_Verification_MPU_B-30_mh 9 99 9 99 9 9 9 9 9 9 9 9 9 9 9 5HJJ-DPHV%2*& )URP5HJJ-DPHV%2*& 6HQW7XHVGD\0D\30 7R6FRWW+HLP& &F%URRNV3KRHEH/2*& 6XEMHFW5(038%%237HVW ŚĂŶŐĞĚŽƵƌĐŽƉǇƚŽƐŚŽǁDŝƐĐƋƵĂŶƚŝƚǇсϬ :ŝŵZĞŐŐ ^ƵƉĞƌǀŝƐŽƌ͕/ŶƐƉĞĐƚŝŽŶƐ K' ϯϯϯt͘ϳƚŚǀĞ͕^ƵŝƚĞϭϬϬ ŶĐŚŽƌĂŐĞ͕<ϵϵϱϬϭ ϵϬϳͲϳϵϯͲϭϮϯϲ &ƌŽŵ͗^ĐŽƚƚ,ĞŝŵͲ;Ϳф^ĐŽƚƚ͘,ĞŝŵΛŚŝůĐŽƌƉ͘ĐŽŵх ^ĞŶƚ͗^ƵŶĚĂǇ͕DĂǇϴ͕ϮϬϮϮϭϭ͗ϱϰD dŽ͗ůĂƐŬĂE^Ͳ^ZͲtĞůů^ŝƚĞDĂŶĂŐĞƌƐфůĂƐŬĂE^Ͳ^ZtĞůů^ŝƚĞDĂŶĂŐĞƌƐΛŚŝůĐŽƌƉ͘ĐŽŵх͖ZĞŐŐ͕:ĂŵĞƐ;K'Ϳ фũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх͖KK'WƌƵĚŚŽĞĂǇфĚŽĂ͘ĂŽŐĐĐ͘ƉƌƵĚŚŽĞ͘ďĂǇΛĂůĂƐŬĂ͘ŐŽǀх͖ƌŽŽŬƐ͕WŚŽĞďĞ>;K'Ϳ фƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗DWhͲϯϬKWdĞƐƚ͘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ll BOPE reports are due to the agency within 5 days of testing* SSu b m i tt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:ASR 1 DATE: 5/7/22 Rig Rep.: Rig Phone: 685-1266 Operator: Op. Phone:685-1266 Rep.: E-Mail Well Name: PTD #22161530 Sundry #322-182 Operation: Drilling: Workover: x Explor.: Test: Initial: x Weekly: Bi-Weekly: Other: Rams:250/2500 Annular:250/2500 Valves:250/2500 MASP:746 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig P Lower Kelly 0NA PTD On Location P Hazard Sec.P Ball Type 1P Standing Order Posted P Misc.NA Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank NA NA Annular Preventer 1 11"P Pit Level Indicators PP #1 Rams 1 2 7/8" x 5"P Flow Indicator PP #2 Rams 1 Blinds P Meth Gas Detector PP #3 Rams 0NAH2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NA Quantity Test Result Choke Ln. Valves 1 2 1/16"P Inside Reel valves 0NA HCR Valves 1 2 1/16"P Kill Line Valves 2 2 1/16"P Check Valve 0NAACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure (psi)3125 P CHOKE MANIFOLD:Pressure After Closure (psi)1900 P Quantity Test Result 200 psi Attained (sec)16 P No. Valves 16 P Full Pressure Attained (sec)58 P Manual Chokes 1P Blind Switch Covers: All stations Yes Hydraulic Chokes 1P Nitgn. Bottles # & psi (Avg.): 4x2250 P CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:4.0 Hours Repair or replacement of equipment will be made within days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 05/05/22 1800 HRS Waived By Test Start Date/Time:5/7/2022 0830 HRS (date) (time)Witness Test Finish Date/Time:5/7/2022 1230 HRS BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Adam Earl Hilcorp Annular closure time = 27 sec. Colt Pace, J. Haberthur Hilcorp Alaska S. Hiem / L. Moore MPU B-30 Test Pressure (psi): skaNS-ASR-Well Site Managers@hilcorp.c Form 10-424 (Revised 02/2022) 2022-0507_BOP_Hilcorp_ASR1_MPU_B-30 9 9 9 9 9999 9 9 9 9 9 9 9 7HVWFKDUWDQGVHTXHQFHDWWDFKHGMEU7HVWFKDUWDQG VHTXHQFHDWWDFKHGMEUG Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 5/16/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU B-30 (PTD 216-153) CIBP 5/09/2022 Please include current contact information if different from above. PTD:216-153 T36615 Kayla Junke Digitally signed by Kayla Junke Date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'>D͗ϮͲϳͬϴ͟ϭϯƌϴϬ^WDKͲϭ͘ϬD<>ĂƚĐŚ EŽ ĞƉƚŚ / /ƚĞŵ ϭ Ϯ͕ϯϰϬ͛ Ϯ͘ϰϰϭ͟^dϭϬ͗Ϯ͕Ϯϰϴ͛ds;ϭϮͬϲϰ͟ϭ͕ϮϯϮηͿƐĞƚϭϬͬϭϭͬϭϳ Ϯ ϯ͕ϱϮϲ͛ Ϯ͘ϰϰϭ͟^dϵ͗ϯ͕ϯϰϵ͛ds;ƵŵŵǇsĂůǀĞƐĞƚϭϬͬϭϭͬϭϳͿ ϯ ϰ͕ϭϰϯ͛ Ϯ͘ϰϰϭ͟^dϴ͗ϯ͕ϵϮϱ͛ds;ϭϮͬϲϰ͟ϭ͕ϭϴϴηƐĞƚϬϵͬϮϱͬϮϬͿ ϰ ϰ͕ϳϵϭ͛ Ϯ͘ϰϰϭ͟^dϳ͗ϰ͕ϱϯϬ͛ds;ƵŵŵǇsĂůǀĞƐĞƚϲͬϭϳͬϭϳͿ ϱ ϱ͕ϰϰϬ͛ Ϯ͘ϰϰϭ͟^dϲ͗ϱ͕ϭϰϵ͛ds;ϭϮͬϲϰ͟ϭ͕ϭϱϱηͿƐĞƚϭϬͬϭϭͬϭϳ ϲ ϲ͕Ϭϱϳ͛ Ϯ͘ϰϰϭ͟^dϱ͗ϱ͕ϳϰϭ͛ds;ƵŵŵǇsĂůǀĞƐĞƚϬϵͬϮϱͬϮϬͿ ϳ ϲ͕ϳϬϲ͛ Ϯ͘ϰϰϭ͟^dϰ͗ϲ͕ϯϲϯ͛ds;ϭϮͬϲϰ͟ϭ͕ϭϮϲηͿƐĞƚϬϵͬϮϱͬϮϬͿ ϴ ϳ͕ϯϱϰ͛ Ϯ͘ϰϰϭ͟^dϯ͗ϲ͕ϵϳϬ͛ds ;ƵŵŵǇsĂůǀĞƐĞƚϭϮͬϭϱͬϮϬϭϵͿ ϵ ϴ͕ϬϬϭ͛ Ϯ͘ϰϰϭ͟^dϮ͗ϳ͕ϱϳϮ͛ds ;ϭϮͬϲϰ͟ϭϭϬϬ ƐĞƚ ϬϵͬϮϱͬϮϬͿ ϭϬ ϴ͕ϱϱϱ͛ Ϯ͘ϰϰϭ͟^dϭ͗ϴ͕Ϭϴϭ͛ds ;ϭϮͬϲϰ͟KƌŝĨŝĐĞ ƐĞƚ ϬϵͬϮϱͬϮϬͿ ϭϭ ϵ͕ϮϬϭ͛ Ϯ͘ϯϭϯ͟ ϮͲϳͬϴ͟ϵƌy^ůŝĚŝŶŐ^ůĞĞǀĞ DŝŶ/сϮ͘ϯϭϯ͟;ůŽƐĞĚͿ ϭϮ ϵ͕Ϯϰϳ͛ Ϯ͘ϰϭϰ͟ ϮͲϳͬϴ͟ϭϯƌ,^ZKͲϭϱϬWƌĞƐƐƵƌĞ/ŶƚĂŬĞ'ĂƵŐĞ ϭϯ ϵ͕ϯϱϱ͛ Ϯ͘ϯϭϯ͟ ϮͲϳͬϴ͟ϵƌyWƌŽĨŝůĞ DŝŶ/сϮ͘ϯϭϯ͟ ϭϰ ϵ͕ϯϲϲ͛ Ϯ͘ϯϲϬ͟ ϳ͟ǆϮͲϳͬϴ͟ϭϯƌW,>,ǇĚƌĂƵůŝĐZĞƚƌŝĞǀĂďůĞWĂĐŬĞƌ ϭϱ ϵ͕ϰϭϯ͛ Ϯ͘ϮϬϱ͟ ϮͲϳͬϴ͟ϵƌyEWƌŽĨŝůĞ DŝŶ/сϮ͘ϮϬϱ͟ ϭϲ ϵ͕ϰϱϭ͛ Ϯ͘ϯϱϬ͟ ϮͲϳͬϴ͟ϭϯƌt>'Ͳ ŽƚƚŽŵΛϵ͕ϰϱϮ͛ ^&dzEKd ^ĞĂďŽĂƌĚĐŽŶĚƵĐƚŽƌƐƵƉƉŽƌƚĞĚ ǁĞůůŚĞĂĚ͘ZĞƚƌŽĨŝƚƌĞǀĞƌƐĞĂĐƚŝŶŐ ƐůŝƉƐƚǇůĞŚĂŶŐĞƌŝŶƐƚĂůůĞĚ^ĞƉƚϮϬϭϵ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB ZĞǀŝƐĞĚďǇ͗d&ϯͬϯϭͬϮϬϮϮ WZKWK^ DŝůŶĞWŽŝŶƚhŶŝƚ tĞůů͗DWhͲϯϬ >ĂƐƚŽŵƉůĞƚĞĚ͗ϯͬϮϰͬϮϮ Wd͗ϮϭϲͲϭϱϯ dсϵ͕ϲϮϬ ;DͿͬdсϵ͕Ϭϵϯ͛;dsͿ ´ <ůĞǀ͗͘ϰϵ͘ϲ͛ͬ'>ůĞǀ͗͘Ϯϯ͘ϭ͛ Z<ʹd,&͗ϮϮ͘ϵϮ͛;/ŶŶŽǀĂƚŝŽŶͿ ϵͲϱͬϴ͟ Ϯϱ͛ĞŵĞŶƚ WůƵŐdŽƉΛ цϵ͕ϯϴϵ͛ Wdс ϵ͕ϱϭϱ͛;DͿͬWdсϴ͕ϵϵϬ͛;dsͿ ϳ͟ ^ĞŵĞŶƚĞƌ Λϭ͕ϴϭϵ͛ ^' 72& ¶0' &$670 72& ¶0' &$670 ^ĞŵĞŶƚĞƌ Λϳ͕ϲϬϬ͛ >ĂƐƚdĂŐ͗ Λϵ͕ϱϭϱ͛^>D ϴͬϬϰͬϭϵ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚͬ'ƌĂĚĞͬŽŶŶ / dŽƉ ƚŵ ϮϬΗ ŽŶĚƵĐƚŽƌ ϳϴ͘ϲͬͲϱϯͬtĞůĚ ϭϵ͘ϭϮϰ͟ ^ƵƌĨĂĐĞ ϭϬϲ͛ ϵͲϱͬϴΗ ^ƵƌĨĂĐĞ ϰϬͬ>ͲϴϬͬtͬ ϴ͘ϴϯϱ͟ ^ƵƌĨĂĐĞ ϱ͕Ϯϭϱ͛ ϳΗ WƌŽĚƵĐƚŝŽŶ Ϯϲͬ>ͲϴϬͬ,ǇĚƌŝůϱϲϯ ϲ͘Ϯϳϲ͟ ^ƵƌĨĂĐĞ ϵ͕ϲϬϱ͛ dh/E'd/> ϰ͘ϱ͟ dƵďŝŶŐ ϭϮ͘ϲͬ>ͲϴϬͬdyW ϯ͘ϴϭϯ ^ƵƌĨĂĐĞ цϳ͕ϭϰϬ͛ t>>/E>/Ed/KEd/> <KWΛϲϬϬ͛D DĂǆ,ŽůĞŶŐůĞсϮϱ͘ϬϴĚĞŐĂƚϴ͕ϰϲϳ͛D ,ŽůĞĂŶŐůĞƚŚƌŽƵŐŚƉĞƌĨŽƌĂƚĞĚŝŶƚĞƌǀĂů͗ϭϮΣ dZΘt>>, dƌĞĞ tĞůůŚĞĂĚ ^ĞĂďŽĂƌĚtĞŝƌ͕ϯƐƉŽŽůƐ͕ǁͬϭϭ͟ǆϱDƚŽƉ ĨůĂŶŐĞ͘ϮͲϳͬϴ͟dͲ//dƵďŝŶŐ,ĂŶŐĞƌ WZ&KZd/KEd/> ^ĂŶĚ dŽƉ;DͿ ƚŵ;DͿ dŽƉ;dsͿ ƚŵ;dsͿ &d ĂƚĞ ^ƚĂƚƵƐ <ƵƉ цϳ͕ϮϱϬ͛ цϳ͕Ϯϲϱ͛ цϲ͕ϴϳϯ͛ цϲ͕ϴϴϳ͛ цϭϱ &ƵƚƵƌĞ &ƵƚƵƌĞ <ƵƉ цϳ͕Ϯϲϱ͛ цϳ͕ϮϵϮ͛ цϲ͕ϴϴϳ͛ цϲ͕ϵϭϮ͛ цϮϳ &ƵƚƵƌĞ &ƵƚƵƌĞ <ƵƉ^>d цϳ͕ϯϭϱ͛ цϳ͕ϯϰϲ͛ цϲ͕ϵϯϰ͛ цϲ͕ϵϲϯ͛ цϯϭ &ƵƚƵƌĞ &ƵƚƵƌĞ <ƵƉ^>d цϳ͕ϯϲϴ͛ цϳ͕ϯϵϴ͛ цϲ͕͕ϵϴϯ͛ цϳ͕Ϭϭϭ͛ цϯϬ &ƵƚƵƌĞ &ƵƚƵƌĞ ^ĂŐZŝǀĞƌ ϵ͕ϰϱϬ͛ ϵ͕ϰϵϬ͛ ϴ͕ϵϮϲ͛ ϴ͕ϵϲϱ͛ ϰϬ͛ ϱͬϮϬͬϭϳ ďĂŶĚŽŶ WĞƌĨ'ƵŶƐ͗ϯͲϭͬϴ͟'ĞŽǇŶĂŵŝĐƐϯϯϮϯŽŶŶĞyͬZĞĨ>ŽŐ͗WŽůůĂƌĚ>ϱͬϭϮͬϭϳ KWE,K>ͬDEdd/> ϮϬΗ ŵƚǁͬϱϬďďůƐŽĨƌĐƚŝĐƐĞƚŝŶϰϮ͟,ŽůĞ ϵͲϱͬϴΗ;ϮŶĚ^ƚĂŐĞͿ ŵƚǁͬϯϱϬƐŬƐϭϬ͘ϳƉƉŐWĞƌŵ>͕ϮϳϱƐǆϭϱ͘ϴƉƉŐ^ǁŝĨƚDŝŶϭϮͲϭͬϰ͟,ŽůĞ ϵͲϱͬϴ͟;ϭƐƚ^ƚĂŐĞͿ ŵƚǁͬϱϬϱƐŬƐϭϭ͘ϳƉƉŐǆƚĞŶĚĂD͕ϮϭϱƐǆϭϱ͘ϴƉƉŐ^ǁŝĨƚDŝŶϭϮͲϭͬϰ͟,ŽůĞ ϳ͟;ϮŶĚ^ƚĂŐĞͿ ŵƚǁͬϭϭϵƐŬƐϭϰ͘ϳƉƉŐůĂƐƐ͞'͟ŝŶϴͲϭͬϮ͟,ŽůĞ ϳ͟;ϭƐƚ^ƚĂŐĞͿ ŵƚǁͬϭϲϱƐŬƐϭϱ͘ϯƉƉŐůĂƐƐ͞'͟ŝŶϴͲϭͬϮ͟,ŽůĞ 'EZ>t>>/E&K W/͗ϱϬͲϬϮϵͲϮϯϱϳϭͲϬϬͲϬϬ ƌŝůůĞĚ͕ ĂƐĞĚ ΘŽŵƉůĞƚĞĚ ďǇ /ŶŶŽǀĂƚŝŽŶηϭ ϱͬϭϲͬϮϬϭϳ &ƌĂĐ:Žď ʹ ϱͬϮϵͬϮϬϭϳ ϮŶĚŽŵƉůĞƚŝŽŶďǇ^ZηϭʹϲͬϭϳͬϮϬϭϳ :t>Zzd/> EŽ ĞƉƚŚ / /ƚĞŵ ϭ цϮ͕ϮϬϬ͛ ϯ͘ϴϭϯ ϰ͘ϱ͟>ͲϴϬyWƌŽĨŝůĞ Ϯ цϳ͕ϬϭϬ͛ Eͬ ^ůŝĚŝŶŐ^ůĞĞǀĞ>ͲϴϬ ϯ цϳϬϰϬ͛ Eͬ ŽƚƚŽŵ,ŽůĞWƌĞƐƐƵƌĞ'ĂƵŐĞ ϰ цϳ͕ϬϳϬ͛ ϯ͘ϴϭϯ ϰ͘ϱ͟ >ͲϴϬy WƌŽĨŝůĞ ϱ цϳ͕ϭϬϬ͛ Eͬ ϳyϰ͘ϱ͟ WĂĐŬĞƌ ϲ цϳ͕ϭϯϬ͛ ϯ͘ϳϮϱ ϰ͘ϱ͟>ͲϴϬyEWƌŽĨŝůĞ ϳ цϳ͕ϭϰϬ͛ Eͬ ϰ͘ϱ͟>ͲϴϬt>' ϴ цϵ͕ϰϭϰ͛ Eͬ /W ^&dzEKd ^ĞĂďŽĂƌĚĐŽŶĚƵĐƚŽƌƐƵƉƉŽƌƚĞĚ ǁĞůůŚĞĂĚ͘ZĞƚƌŽĨŝƚƌĞǀĞƌƐĞĂĐƚŝŶŐ ƐůŝƉƐƚǇůĞŚĂŶŐĞƌŝŶƐƚĂůůĞĚ^ĞƉƚϮϬϭϵ 8S+ROH5HFRPSOHWH :HOO03% 37' $3, 7LHLQORJ 8S+ROH5HFRPSOHWH :HOO03% 37' $3, $65%23( STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon LJ Plug Perforations Fracture StimulateLl Pull Tubing Li Operations shutdown Ll Performed: Suspend ❑ Perforate ❑ Other Stimulate[] Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well❑ Re-enter Susp Well ❑ Other: Install Reverse Slip Lac ❑✓ 2. Operator Hilcorp Alaska LLC 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development ❑✓ Stratigraphic❑ Exploratory ❑ Service ❑ 216-153 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-029-23571-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL047438 / ADL047437 Milne Pt Unit B-30 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Milne Point / Sag River Oil 11. Present Well Condition Summary: Total Depth measured 9,620 feet Plugs measured N/A feet true vertical 9,093 feet Junk measured N/A feet Effective Depth measured 9,515 feet Packer measured 9,366 feet true vertical 8,990 feet true vertical 8,844 feet Casing Length Size MD TVD Burst Collapse Conductor 106' 20" 106' 106' N/A N/A Surface 5,215' 9-5/8" 5,215' 4,933' 5,750psi 3,090psi Production 9,605' 7" 9,605' 9,078' 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" 6.4#/ 13Cr-85 / JFE Bear 9,452' 8,928' Packers and SSSV (type, measured and true vertical depth) 7" x 2-7/8" 13Cr PHIL N/A See bove N/A 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 1,200 1 0 Subsequent to operation: 1181 300 18 624 156 14. Attachments (required per 20 AAC 25.070, 25.071, &25.283) 15. Well Class after work: Daily Report of Well Operations El Exploratory❑ Development 0 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil ✓ Gas WDSPL LJ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct t0 the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-393 Authorized Name: Chad HelgesonW Contact Name: Wyatt Rivard Authorized Title: Operations Manager Contact Email: wriyardtEDhilcorp.conn Authorized Signature:11. 1 Date 9/24/2019 Contact Phone: 777-8547 Form 10-404 Revised 4/2017 RBDMS�E OCT 0 2 2019 Submit Original Only Hilcorp Alaska, LLC Weekly Operations Summary Name 1:1i PImWell Well Permit Number Start Date End Date MP B-30 N/A 50-029-23571-00-00216-153 9/10/2019 1 9/15/2019 9/4/2019 - Wednesday No operations to report. 9/5/2019 -Thursday No operations to report. 9/6/2019 - Friday No operations to report. 9/7/2019 - Saturday No operations to report. 9/8/2019 -Sunday I&E disconnect B-30 and pull wellhouse. Disconnect flowline in preparation for the well support structure. 9/9/2019 - Monday Dirt work to level pad behind and in front of well for WSS placement at B-30. 9/10/2019 -Tuesday With XXN plug set at 9413' and and tested. Bleed tubing and annulus to 0 psi. Set BPV. Disconnect ROC DH gauge Wellhead terminal. Flush with water the top SC x Conductor annulus. ND THA bolts at 11" flange and pull tree. MIRU Well Support Structure (WSS) Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP B-30 N/A 50-029-23571-00-00 216-153 9/10/2019 9/15/2019 9/11/2019 -Wednesday PJSM / Sign off permits / PU on well with WSS to 60k / With air arc, cut out bell nipple from casing head and conductor / Install Reverse Slip -Lock assembly as per procedure / Slack off tension with WSS and no observed slippage / Installation complete / MIT -OA to 1,OOOpsi Passed. Pumped 1.5 bbls of diesel / MIT -OA lost 90 psi in 1st 15 minutes and 10 psi in 2nd 15 minutes for a total of 100 psi during 30 minute test. Bled OA to 0 psi. Start RDMO. 9/12/2019 -Thursday Disconnect cables from WSS to control shack. Load out WSS. 9/13/2019 - Friday No operations to report. 9/14/2019 -Saturday Scope: ND 2 9/16" 5K tree, Re -install fiber optic and NU 2-9/16" 5K tree. BPV still in well. IA=75 psi Tbg has pressure but not gauged. Remove trewe to expose the broken 1/4" fiber optic line. Attempt to repair it. Lifted about 3" and HAL examined and determined it was possible to fix. Consult with wells foreman and all in agreement. Lift tree all the way off and feed fiber optic tail through adapter. Was not sure if a Swagelok was run under hanger. Checked IA and found 75psi. A little bit of gas escaped when we backed off upper Swagelok cap. Bled down IA to Opsi. Upon removing upper Swagelok, the fiber optic line broke and was now non -repairable. Cut line close to hanger and install a 1/2" NPT plug. NU Tree prep to test tree to S,OOOpsi. WELL S/I ON ARRIVAL, NOTIFY PAD -OP, PT PCE 250L/2500H. ASSIST WELL HEAD TECHNICIANS WITH PULLING BACK PRESSURE VALVE. PULL BK-OGLV 16/64"" PORTS, FROM STA#1 @ 8,565' SUM/ 8,555' MD. PULL BK-LGLV 12/64" PORTS, FROM STA#2 @ 8,009' SLM/ 8,001' MD. PULL BK-DGLV FROM STA#3 @ 7,360' SLM/ 7,354' MD. WELL S/I 9/15/2019 -Sunday CONTINUE TICKET FROM 9/14/19, WELL S/I ON ARRIVAL, NOTIFY PAD -OP, PT PCE 250L/2,500H. SET BK-DGLV (20/64"" ports) IN STA#3 @ 7,360' SLM/ 7,354' MD. SET BK-DGLV IN STA#2 @ 8,009' SLM/ 8,001' MD. SET BK-DGLV IN STA#1 @ 8,565' SLM/ 8,555' MD. HAVE LRS PUMP 20bbls OF DIESEL PUTTING US SLIGHTLY OVERBALLANCED FOR PULLING PLUG. EQUALIZE THEN PULL X-XN PLUG FROM XN-NIP @ 9,413' MD. 9/16/2019- Monday No operations to report. 9/17/2019 -Tuesday No operations to report. MPB-30 Seaboard Retrofit 8/29/19 SET XXN-PLUG IN XN-NIPAT 9423' SLM/9413' MD 9/1/2019 Downhole plug test - tested downhole plug by bleeding off tubing to plant. Starting pressures 1650/1650/0, Ending pressures 850/1050/0. Held for 45 minutes Good test 9/7/2019 I&E disconnect in preparation to pull wellhouse 9/8/2019 Demobe injection line and pull wellhouse 9/9/2019 Pre -job meeting - conference call with town engineering and slope operations Dirt work to level pad behind and in front of well for WSS placement Offload Manitowoc Crane at B -Pad 9/10/2019 Bleed T/1/0 to 0 psi Flush conductor and inspect cellar for hydrocarbons / Disconnect ROC DH gauge terminal / ND tree at the 11' THA flange and pull tree/ MIRU WSS / Unbolt all traveling bolts / Fly cross and well attachment beam and land center of WSS. NU flanges to THA flange. Bolt up top plate over cross. Hook up power to WSS shack and function test WSS. 9/11/19 P1SM /Sniff cellar for LEL, 02, and CC— good / Sign off on Hot work and regulated CSE permits PU on well with the WSS to 60k / Make top, bottom and 2 vertical cuts on bell nipple and remove in two pieces / As cutting proceeded, the tension weight increased gradually with final tension of 158,000 lbs with the bell nipple cut free / Cut an additional 5-1/2" inches off top of 20" conductor pipe to allow working window for installing the Slip -Lock assy. / Dress off top of conductor and the bottom of casing head to provide smooth entry into the casing head / Note: the neck of the bell nipple remained in the bottom of the casing head as designed / Install Reverse Slip -Lock Assembly as per WEHR procedure and tighten to 125 ft/lbs. / With Reverse Slip -Lock assembly installed, mark 9-5/8" casing 1" below Slip -Lock assy / Slowly release tension with the WSS while observing for any slippage of the Slip -Lock assy / With tension fully released no movement was observed and mark still in place 1" below the Slip -Lock assy / MIT -OA passed to 1000 psi / Pressured OA to 1000 psi with 1.5 bbls of diesel. MIT -OA lost 90 psi in 1ST 15 minutes and 10 psi in 2nd 15 minutes for a total of 100 psi during 30 minute test. Bled OA to 0 psi / ND WSS cross and beam from well / Lift cross out and lay down / PU and install tree and NU at THA flange NOTE: Metal tubing that houses the DH BHP gauge was damaged while setting the tree 9/12/2019 Complete RD of WSS / Pick WSS with Manitowoc and haul to C -Pad 9/14/2019 Reconnect flowlines and PT / Install Wellhouse and reconnect I&E / ND tree / Trouble shoot DH gauge wire — The wire was still intact but when trying to repair the damaged tubing that houses the wire, the tubing broke off completely and beyond repair which unfortunately caused loss of use of DH gauge / Capped off Swagelok tubing / NU tree / Pull BPV and install TWC / Perform void test to 500/5000 psi / PT tree to 5000 psi / Pull TWC / Slickline pull GLV's from stations 1,2, and 3 9/15/2019 Slickline install GLV's as per WWR in stations 3,2, and 1 / Equalize and pull X-XN plug from XN nipple at 9413'/ Well ready to POP THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, Inc. 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Sag River Oil Pool, MPU B-30 Permit to Drill Number: 216-153 Sundry Number: 319-393 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www. aogcc.a laska.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 this I day of September, 2019. RBDMStL SEP 0 5 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25 280 1. Type of Request: Abandon ❑ PlugPerforations d"�. >s h ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown El Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Install Reverse Slip Loc ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development Stratigraphic ❑ Service ❑ 216-153 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23571-00-00 - 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 423 Will planned perforations require a spacing exception? Yes ❑ No ❑� Milne Pt Unit B-30 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL047438 / ADL047437 I Milne Point/ Sag River Oil ' 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): 9,620' 9,093' ' 9,515' 8,990' 1,150 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 106' 20" 106' 106' N/A N/A Surface 5,215' 9-5/8" 5,215' 4,933' 5,750psi 3,090psi Production 9,605' 7" 9,605' 9,078' 7,240psi 5,41 Ops! Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 2-7/8" 6.4#/ 13Cr-85 / JFE Bear 9,452 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 2.360" 7"x 2-7/8" 13Cr PHIL Hydraulic Retrievable Packer and N/A 9,366(MD)/ 8,844(TVD) and N/A 12. Attachments: Proposal Summary r Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch ❑ Exploratory p ry ❑ Stratigraphic ❑ Development Service ❑ 14. Estimated Dale for 15. Well Status after proposed work: Commencing Operations: 9/10/2019 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: Chad Helgeson Contact Name: Wyatt Rivard Authorized Title: Operations Manager Contact Email: wrlvard hilcor .Corn Contact Phone: 777-8547 Authorized Signature: Date: 8/28/2019 Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31q- 3q3 Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location ❑ /Clearance Q QA❑ Other: �E �!20� t{O�w»�✓� /� ✓% Wt�c'C "�.r--�r () Post Initial Injection MIT Req'd? RBDMS-t* 14,ZEP 0 51019 Yes No Spacing Exception Required? Yes ❑ No Subsequent Form Required: / C) —410,-1 APPROVED BY Approved by: COMMISSIONER THE L` . COMMISSION Date: 'dry;-C//�6- �" ` '?/I ORIGINAL Submit Form and 7 Form 10-403 Revised 412017 Approved application is valid for 12 months from the date of approval. �y Attachments Duplicate q U Ilikarp Alaska, LL Well Prognosis Well: MPU B-30 Date: 7/11/2019 Well Name: MPU B-30 API Number: 50-029-23571-00 Current Status: SI Producer Pad: B -Pad Estimated Start Date: 9/10/19 Rig: WSS Reg. Approval Req'd? Date Reg. Approval Rec'vd: Regulatory Contact: om TFouts Permit to Drill Number: 216-153 First Call Engineer: Wyatt Rivard (907) 777-8547 (0) (509) 670-8001 (M) Second Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) AFE Number: Job Type: Wellhead Repair Current Bottom Hole Pressure: 2025 psi @ 8,750' TVD (Current SI BHP Gauge Reading) Maximum Expected BHP: 2025 psi @ 8,750' TVD (Current SI BHP Gauge Reading) MPSP: 1150 psi (0.1 psi/ft gas gradient)\ Min ID: 2.205" ID 2-7/8 XN Nip at 9,413' MD Brief Well Summary: The Milne Point B-30 well is a recently drilled Sag River development well. The well's surface casing was fully cemented and hung off a slip style casing hanger as part of a conductor supported wellhead system. The system has since been identified has having the potential to cause wellhead movement in the event of conductor subsidence. In order to fully tie well load back to the surface casing, conductor will be cut and a reverse acting slip style hanger assembly will be installed. Notes Regarding Wellbore Condition • Casing last tested to 3,750 psi for 30 min down to 9,296' on 5/15/2017. Objective: ( VIAlt.„A Cut conductor bell nipple below starting head and install Reverse Slip Loc assembly to ensure fully supported by surface casing. Procedure: Pre -Sundry Work Slickline 1. MIRU SL unit. 2. Pressure test to 300psi low and at least 1500 psi high. 3. MU plug setting toolstring and set 2-7/8" XN at 9413' MD. a. Bleed down the tubing pressure to confirm set. 4. RDMO Prep Work 5. Disconnect flowline and instrumentation. 6. Verify tubing, IA and OA pressures have been bled to Opsi. 7. Sniff cellar and adjacent area with multi -gas meter for LEL, CO, H2S and 02• Ensure confined space, egress and ventilation is adequate for operations 8. Vac out gravel from well cellar down to cellar liner to remove residual hydrocarbons. 9. Install fire blankets around the conductor landing ring to protect surface casing holes from hot machining debris. H rlil.w Alaska, Lb Well Prognosis Well: MPU B-30 Date:7/11/2019 Sundry Work (Approval required to proceed) Surface Casing Support Retrofit 10. Sniff cellar and adjacent area with mutli-gas meter for LEL, CO, H2S and 02. Ensure confined space, egress and ventilation is adequate for operations 11. Flush conductor with water from the conductor starting head valve and while taking fluid returns from the cement return line bull plug. Flush until clean returns are observed. 12. Move in and rig up Well Support Structure. Place rig mats as needed to level out support structure legs. 13. Install BPV and nipple down tree at master valve or tubing head adapter as needed to makeup Wellhead Support Structure adapter flange. 14. Prepare to transfer load to the Well Support Structure. Pretension load cells according to operating manual. 15. Pull 8000 lbs (Wellhead Weight) gradually building up load in 1000 Ib increments. a. Monitor the wellhead for any signs of movement and discontinue increasing tension if movement observed. 16. Increase weight up to 60,000 lbs (50 K preloading) 17. Once pre loaded, begin cutting conductor horizontally at bottom of conductor bell nipple using air arc cutter. a. Monitor load on Well Support Structure in addition to wellhead vertical displacement during cutting operations. a. Maximum dry production casing, tubing and wellhead load = 29#*6050'+6.4#*9366'+8K = 225K b. Maintain constant vertical displacement while well support structure is loaded by well. 18. Proceed to cut conductor bell nipple below the starting head then remove conductor bell nipple section. a. Ensure minimum of 12" of clearance between bottom of starting head and top of conductor. b. Record Well Support Structure Load in WSR once conductor fully loaded. 19. Leave remaining bell nipple section engaged in starting head. Bevel as needed to ensure smooth entry of slip assembly. 20. Place each half of Reverse Slip Loc assembly around surface casing, bolt halves together. 21. Install energizing plate halves at 90 degree offset from slip assembly such that joint between halves are perpendicular to slips. 22. Lift Reverse Slip Loc up inside conductor starting head. 23. In a criss cross pattern, begin to tighten bolts on energizing plates initially to 50 ft -lbs on first pass then to a final torque of 100-125 ft -lbs on second pass. 24. Mark casing at the bottom of the Reverse Slip Loc 25. Release tension, observe for any slippage. If slipping occurs, retension and tighten bolts to 150 ft -lbs. 26. Once load is released to Reverse Slip Loc, conduct MIT -OA to 1000 psi to confirm SC integrity. 27. Unbolt and remove the adapter flange 28. Reinstall 5K production tree. 29. Remove BPV and install TWC. Pressure test tree to 5000psi. 30. Re -install flowline and instrumentation 31. Weld centralizer/landing ring onto top of conductor. 32. Reinstall well house and backfill gravel over cellar liner. 33. Install Corrosion Inhibitor in SC by Conductor Annulus up to the conductor top. Slickline H IIikvq� A].sku, LLi 34. MIRU SL unit. 35. Pressure test to 300psi low and at least 1500 psi high. 36. RIH and pull 2-7/8" XN at 9413' MD. 37. RDMO 38. Turn well back over to production Attachments: -Wellbore Schematic Well Prognosis Well: MPU B-30 Date: 7/11/2019 L Milne Point Unit 8 SCHEMATIC Well: MPU 6-30 }� T Last Completed: 6/17/2017 Flilroru Aloska. 1.ti('. PTD: 216-153 KB Elev.: 49.6/GL Elev.: 23.1' Wellhead RKB—THF: 22V(Innovation) TREE & WELLHEAD SAFETY NOTE L Cmt w/ 50 bbls of Arcticset in 42" Hole 8 Cmt w/ 350 sks 10.7 ppg Perm L, 275 sx 15.8 ppg SwiftCEM in 12-1/4" Hole }� T Tree CIW 2-9/16" 5M Cmt w/ 119 sks 14.7 ppg Class "G" in 8-1/2" Hole Seaboard conductor supported wellhead. 50-80 Wellhead Seaboard Weir, 3 spools, w/11" x SM top 9 roc Surface 10 86WRAD Surface flange. 2-7/8" TC -II Tubing Hanger CAST M Klbs max compressive load. @ IAUY Watch fa MDRAN STA#10 @ 7.340' 9-5/8 TOC 6,aW fVn CAST M 5'13'17 1 'Watdlfc PARAFR @1575- 2 t n 3 4 5 6 7 OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 50 bbls of Arcticset in 42" Hole 8 Cmt w/ 350 sks 10.7 ppg Perm L, 275 sx 15.8 ppg SwiftCEM in 12-1/4" Hole 9-5/8" (1,t Stage) ii ES Cementer Cmt w/ 119 sks 14.7 ppg Class "G" in 8-1/2" Hole 7" (Vt Stage) @7,6W Surface 9 roc Surface 10 86WRAD Surface 1 5,215' CAST M Production 1 26 / L-80 / Hydril 563 5"13'17 Surface 1 9,605' 6 n 2.441" STA 5: 2-7/8" 13Cr80 SPMO-1.0M (Dummy Valve set 6/17/17) 2 6,706' 7, 13 i i 2.441" STA 3: 2-7/8" 13Cr80 SPMO-1.0M (Dummy Valve set 6/17/17) 9 8,001' 2.441" STA 2: 2-7/8" 13Cr80 SPMO-1.OM (12/64" 1,100#) BK Latch set 10/11/17 10 14 2.441" 15 11 9,201' 16 2-7/8" 9Cr, XD Sliding Sleeve Min ID = 2.313" (Closed) SAG 9,247' 2.414" OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 50 bbls of Arcticset in 42" Hole 9-5/8" (2nd Stage) Cmt w/ 350 sks 10.7 ppg Perm L, 275 sx 15.8 ppg SwiftCEM in 12-1/4" Hole 9-5/8" (1,t Stage) Cmt w/ 505 sks 11.7 ppg ExtendaCEM, 215 sx 15.8 ppg SwiftCEM in 12-1/4"Hole 7" (2nd Stage) Cmt w/ 119 sks 14.7 ppg Class "G" in 8-1/2" Hole 7" (Vt Stage) Cmt w/ 165 sks 15.3 ppg Class "G" in 8-1/2" Hole CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 78.6/A-53/Weld 19.124" Surface 106' 9-5/8" Surface 40/L-80/DWC/C 8.835" Surface 1 5,215' 7" Production 1 26 / L-80 / Hydril 563 1 6.276" 1 Surface 1 9,605' TUBING DETAIL 2-7/8" 1 Tubing 6.4/13Cr-SS/1FE Bear 2.441" Surface 9,451' WELL INCLINATION DETAIL KOP @ 600' MD Max Hole Angle= 25.08 deg at 8,467' MD Hole angle through perforated interval: 12' JEWELRY DETAIL No Depth ID Item 1 2,340' 2.441" STA 10: 2-7/8" 13Cr80 SPMO-1.0M (12/64" 1,232#) BK Latch set 10/11/17 2 3,526' 2.441" STA 9: 2-7/8" 13Cr80 SPMO-1.OM (Dummy Valve set 10/11/17) 3 4,143' 2.441" STA 8: 2-7/8" 13Cr80 SPMO-1.OM (12/64" 1,188#) BK Latch set 10/11/17 4 4,791' 2.441" STA 7: 2-7/8" 13Cr80 SPMO-1.0M (Dummy Valve set 6/17/17) 5 5,440' 2.441" STA 6: 2-7/8" 13Cr80 SPMO-1.OM (12/64" 1,155#) BK Latch set 10/11/17 6 6,057' 2.441" STA 5: 2-7/8" 13Cr80 SPMO-1.0M (Dummy Valve set 6/17/17) 7 6,706' 2.441" STA 4: 2-7/8" 13Cr80 SPMO-1.OM (12/64" 1,123#) BK Latch set 10/11/17 8 7,354' 2.441" STA 3: 2-7/8" 13Cr80 SPMO-1.0M (Dummy Valve set 6/17/17) 9 8,001' 2.441" STA 2: 2-7/8" 13Cr80 SPMO-1.OM (12/64" 1,100#) BK Latch set 10/11/17 10 8,555' 2.441" STA 1: 2-7/8" 13Cr80 SPMO-1.OM (16/64" OGLV) BK Latch set 10/11/17 11 9,201' 2.313" 2-7/8" 9Cr, XD Sliding Sleeve Min ID = 2.313" (Closed) 12 9,247' 2.414" 2-7/8" 13Cr HES ROC -150 Pressure Intake Gauge 13 9,355' 2.313" 2-7/8" 9Cr X Profile Min ID = 2.313" 14 9,366' 2.360" 7" x 2-7/8" 13Cr PHIL Hydraulic Retrievable Packer 15 9,413' 2.205" 2-7/8" 9Cr XN Profile Min ID = 2.205" 16 9,451' 1 2.350" 2-7/8" 13Cr WLEG - Bottom @ 9,452' 7' 'f; -.L TD = 9,620 (MD) / TD = 9,093'(TVD) PBTD=9,515' (ND) / PBID=8,99(Y(TVD) PERFORATION DETAIL Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) FF Date Status Sag River 9,450' 9,490' 1 8,926' 1 8,965' 40' 5/20/17 Open PerfGuns: 3-1/8"Geo Dynamics 3323 ConneX / Ref Log: Pollard CBL 5/12/17 GENERAL WELL INFO API: 50-029-23571-00-00 Drilled, Cased & Completed by Innovation #15/16/2017 Frac Job — 5/29/2017 2nd Completion by ASR#1— 6/17/2017 Revised by: DH 5/24/2018 Confidential Business Information As Per 18 AAC 83.165 WEIR PRESSURE CONTROL 9-5/8 Reverse Slip -Lock Assembly (Split) Installation Operation CONTROLLED DOCUMENT Any proton! Copies Are Considered Uncontrolled. All information in this manual is proprietary and Confidential and the extlusiv property of a 2013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or instructions, either expressed or implied, Is forbidden without the expressed written permission of Weir Oil & Gas or Its authorized agent(s). 9-5/8" Reverse Slip -Lock (Split) P-21476 Installation Operation Rev: 0Page: I of 12 Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: WEIR PRESSURE CONTROL 9-5/8 Reverse Slip -Lock Assembly (Split) Installation Operation CONTROLLED DOCUMENT Any proton! Copies Are Considered Uncontrolled. All information in this manual is proprietary and Confidential and the extlusiv property of a 2013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or instructions, either expressed or implied, Is forbidden without the expressed written permission of Weir Oil & Gas or Its authorized agent(s). Confidential Business Information As Per 18 AAC 83.185 9-5/8" Reverse Slip -Lock (Split) P-21476 Installation Operation Rev: 0 Page: 2 of 12 Reviewed By: Thinh Nguyen I Approved By: Josh Douglas I Date Approved: Reviewed by Thinh Nguyen Engineer Approved by Josh Douglas Engineering Manager CONTROLLED DOCUMENT Any Printed Copies Are Considered Unconbolled. All information h this manual is Proprietary and Confidential and the exclusive property of ® 2013 Seaboard Holdings Inc. Any reproduction or use of the calcolations, drawings, photographs, procedures, or instructions, either expressed or implied, Is forbidden without the expressed written permission of Weir Oil 8 Gas or its authodmil agenf(s). Confidential Business Information As Per 18 AAC 83.165 REVISION AND HISTORY PAGE Rev 9-5/8" Reverse Slip -Lock (Split) P-21476 0 Initial Release 10/05/2018 Installation Operation Rev: 0 Page: 3 of 12 Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: REVISION AND HISTORY PAGE Rev Description Release Date 0 Initial Release 10/05/2018 CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and Conftlenfial and the exclusive propenyof ® 2013 Seaboard Holdings Inc. Any reproduction or use of Me calculations, drawings, photographs, procedures, or instructions, either expressed or implied Is forbidden without the expressed written permission of Weir Oil & Gas or Its authorized agent(s). Confidential Business Information As Per 18 AAC 83.165 9-5/8" Reverse Slip -Lock (Split) Installation Operation Reviewed By: Thinh Nguyen Approved By: Josh Douglas TABLE OF CONTENTS 1.0 EQUIPMENT OVERVIEW ................................................. 2.0 CASING CUT-OFF.............................................................. 3.0 INSTALLATION OF REVERSE SLIP LOCK ................... TABLE OF FIGURES Figure 1: Original Configuration................................................... Figure2: Cut Made........................................................................ Figure 3: Install Split Halves......................................................... Figure 4: Install Lower Halves and Install ..................................... Figure 5: Final Installation............................................................. P-21476 Rev: 0 I Page: 4 of 12 Date Approved: 5 5 8 .......................................... 6 .......................................... 7 .......................................... 9 ........................................ 10 ........................................ 12 CONTROLLED DOCUMENT Any printed Copies Are Considered Uncontrolled. All information in We manual is Propdelary and Confidential and the exclusive property of®2013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, pmcedures, or instructions, either expressed or implied. Is forbidden without the expressed %riren permission of Weir Oil & Gas or its authorized agends). Confidential Business Information As Per 18 AAC 83.165 9-5/8" Reverse Slip -Lock (Split) Installation Operation Reviewed By: Thinh Nguyen I Approved By: Josh Douglas 1.0 EQUIPMENT OVERVIEW P-21476 Rev: 0 Fge: 5 of 12 Date Approved: The Reverse Slip -Lock (W20932-001) is designed as a retrofit component to an existing well. It will divert the load of the wellhead from the surface casing/conductor and reload it to the intermediate string. 2.0 CASING CUT-OFF 2.1 The original tree configuration should be as shown in Figure 1, For installation of the Reverse Slip -Loc the bell nipple will be removed and the 9-5/8 casing exposed. 2.2 Pull tree in tension then do casing cut-off with minimum 12.0" clearance between the bottom of the casing head and 20" conductor. See figure 2. 2.3 The slip loc design requires that the remaining bell nipple remain in the bottom of the SOW prep. If the bell nipple is not welded at the top retain this piece for further use. 2.4 Bevel prep as required to ensure a smooth entry. CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. AllInfoonadon in this manual is Proprietary and Confidential and me exdlusive property of 0 2013 Seaboard Holdings Inc. Any reproduction of use of the calculations, dravnngs, photographs, Procedures, or instructions, either expressed or implied, is forbidden without the expressed written permission of Weir Oil & Gas or its authorized agent(s). Confidential Business Information As Per 18 AAC 83.185 CASING HAP c 13-5/8 X 9- 13-3/8 50 20 CASING M Figure 1: Original Configuration CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. 3-5/8 5M All information in this manual is Proprietary and Confidential and the exGusive properlyof®2013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or instructions, either expressed or implied, Is forbidden Wthout the expressed written permissicn of Weir Oil 8 Gas or its allthodzed agent(s). 9-5/8" Reverse Slip -Lock (Split)Installation P-21476 =Thinh OperationRev: 0 Page: 6 of 12 Approved By: Josh Douglas Date Approved: CASING HAP c 13-5/8 X 9- 13-3/8 50 20 CASING M Figure 1: Original Configuration CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. 3-5/8 5M All information in this manual is Proprietary and Confidential and the exGusive properlyof®2013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or instructions, either expressed or implied, Is forbidden Wthout the expressed written permissicn of Weir Oil 8 Gas or its allthodzed agent(s). Confidential Business Information As Per 18 AAC 83.165 CASING HAr c 13-5/8 X 9 - CAST 20 CASING 9-5/8 CA FIGURE 1 Figure 2: Cut Made CONTROLLED DOCUMENT Any printed! Copies Are Considered Uncontrolled. 3-5/8 5M All information In this manual is proprietary and Confidential and the exGusive property of a 2013 SeaboeM Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or instructions, eiMer expressed or implied, Is forbidden without the expressed Written permission of Weir Oil 8 Gas or its authorized agent(s). 9-5/8" Reverse Slip -Lock (Split) P-27476 Installation Operation Rev: 0 Page: 7 of 12 Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: CASING HAr c 13-5/8 X 9 - CAST 20 CASING 9-5/8 CA FIGURE 1 Figure 2: Cut Made CONTROLLED DOCUMENT Any printed! Copies Are Considered Uncontrolled. 3-5/8 5M All information In this manual is proprietary and Confidential and the exGusive property of a 2013 SeaboeM Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or instructions, eiMer expressed or implied, Is forbidden without the expressed Written permission of Weir Oil 8 Gas or its authorized agent(s). Confidential Business Information As Per 18 AAC: 19'1 1 FS 9-5/8" Reverse Slip -Lock (Split) P-21476 Installation Operation Rev: 0 Page: 8 of 12 Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: 3.0 INSTALLATION OF REVERSE SLIP LOCK 3.1 Visually inspect the Slip Set thread for any damage. 3.2 Place a board or plate over the 20" casing to provide a work area. WARNING —SAFETY ALERT ! Each half of the Reverse slip-loc is approximately 50lbs, utilize proper lifting methods using provided .500-13UNC lift holes. 3.3 Using proper lifting equipment place each half around the 9-5/8 casing. 3.4 Bolt the two halves together. CONTROLLED DOCUMENT Any Printed Caples Are Considered Uncontrolled. All information In this manual is Proprietary and Confidential and the exclusive property cf®2013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or instructions, either expressed or Implied is forbidden without the expressed wren permission of Weir Oil 8 Gas or its authorized agent(,). Confidential Business Information As Per 18 AAC 83.165 � 9-5/8" Reverse Slip -Lock (Split) P-21476 E Installation OperationRev: 0 Page: 9 of 12 Nguyen Approved By: Josh Douglas Date Approved: Figure 3: Install Split Halves CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. All information in this manual is proprietary and Confidential and the exclusive property of ® 2013 Seaboard Holdings Inc. Any reproduction cruse of the calculations, drawings, photographs, procedures, or Instructions, either expressed or implied. is forbidden Without the expressed enthan permission of Weir Oil B Gas or its authonud agent(s). Confidential Business Information As Per 18 AAC 83.165 MEMOMEN 9-5/8" Reverse Slip -Lock (Split) P-21476 Installation Operation Rev: 0 Page: 10 of 12 Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: Figure 4: Install Lower Halves and Install 71 CONTROLLED DOCUMENT Any printed Copies Are Considered Uncontrolled. All information in this manual is proprietary and Confidential and the exclusive property of © 2013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or instructions, either expressed or Implied, is forbidden without the expressed written peimisslon of Weir Oil & Gas or its authorized agent(s). Confidential Business Information As Per 18 AAC 83.165 9-518" Reverse Slip -Lock (Split) P-21476 Installation Operation Rev: 0 Page: I 1 of 12 Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: 3.5 Install bottom plate (2X) 90 degrees from each other such that the splits do not align. 3.6 Install nuts hand tight. 3.7 Using appropriate lifting equipment insert the Reverse slip-loc into the bottom of the casing head. See Figure 3. WARNING — SAFETY ALERT To properly function the Reverse slip loc must fit inside the casing head. If the bell nipple from Section 2.0 was removed utilize it when installing the Reverse slip loc to ensure a tight fit. The bolts are not designed to hold the two halves together under loadina. 3.8 Loosen the bolt and nut keeping the two halves together, but do not remove. 3.9 Remove cap screws retaining the slip segments. 3.10 Pull final tension required. 3.11 In an alternating criss-cross pattern tighten the bolt pattern to 50 ft -lbs in the first pass, and to the final torque of 100-125 ft -lbs in the final pass. 3.12 Make a mark on the casing at the bottom of the reverse slip lock. 3.13 Release tension and observe for any slippage. If slippage has occurred re-pull tension and apply up to 150 ft -lbs of torque on the bolting. If slippage still occurs, contact engineering. CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and Contitlentialand the exclusive propeny of a 2013 seaboaml Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, Procedures, or Instructions. either expressed or Implied, is Is without the expressed written peression of Weir Oil & Gas or its authonzed agent(s). Confidential Business Information As Per 18 AAC 81 1 R5 CASING HAI 13-5/8 X 9- 20 CASING 9-5/8 CA Figure 5: FinalInstallation CONTROLLED DOCUMENT /8 5M Any Printed Copies Are Considered Uncontrolled. All information in this manual is proprietary Intl Confidential and the exdusive property cf®2013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, Procedures, or instructions, either expressed or implied, is forbidden without the expressed written permission of Weir Oil & Gas or Its authorized agent(s). 9-5/8" Reverse Slip -Lock (Split) P-21476 EReviewedink Installation Operation Rev: 0 Page: 12 of 12 Nguyen Approved By: Josh Douglas Date Approved: CASING HAI 13-5/8 X 9- 20 CASING 9-5/8 CA Figure 5: FinalInstallation CONTROLLED DOCUMENT /8 5M Any Printed Copies Are Considered Uncontrolled. All information in this manual is proprietary Intl Confidential and the exdusive property cf®2013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, Procedures, or instructions, either expressed or implied, is forbidden without the expressed written permission of Weir Oil & Gas or Its authorized agent(s). • 111 oqlCv- ls3 Hilcorp Alaska,LLC Post Office Box 244027 Anchorage,AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage,AK 99503 Phone: 907/777-8547 scow JUN 61 'mi June 5, 2018 RECEIVED Mr. Guy Schwartz Alaska Oil and Gas Conservation Commission JUN 0 6 2018 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 AOGCC Re: Conductor Annulus Corrosion Inhibitor Treatments 4/20/18-5/12/18 Dear Mr. Schwartz, Enclosed please find multiple copies of a spreadsheet with a list of wells that were treated with corrosion inhibiting casing filler in the surface casing by conductor annulus. The heavier than water "grease-like" filler displaces water to prevent external casing corrosion that could result in a surface casing leak. The attached spreadsheets include the well names, field, PTD and API numbers, treatment volumes and treatment dates. This treatment campaign represents primarily new Milne Point HAK drill wells along with two Northstar wells which previously had excavations and external surface casing leak repairs. If you have any additional questions,please contact me at 777-8547 or wrivard@hilcorp.com. Sincerely, Wyatt Rivard Well Integrity Engineer Hilcorp Alaska, LLC • • Cl) a) a) (1) a) a) a) a) a) 0) a) Cl) a) a) m a) _ c c CCCCCCCCCCC J J J J J J J J J J J J J O O O O C ccCCcccCCcCc22 DOODn7O = D D a) a) a) Cl) Cl) a) a) a) a) Cl) a) Cl) a) Q- 0- 5 1 CLCti CtrYW CLCtrECYc C c c c c c c c c c c cc L L a) a) a) a) a) a) a) a) a) a) a) a) U) O O E E E E E E E E E E E E E U U a) a) a) a) a) a) a) a) a) a) a) a) a) D D U U C.) 00000000007373 Q < Q Q Q Q Q Q Q Q Q Q Q U U O Q Q L6 •Q L4 co U {� a) O O O O aa Lo. 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N d p.N N N V .2 co y co U C E E E 0.a 2 ci 0 Ask • 21 61 53 Seth Nolan Hilcorp Alaska, LLC v GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-83 Hilenrg,tlaska,i.IA: RECEIVED Fax: 907 777-850810 E-mail: snolan@hilcorp.com JUL 072017 DATA LOGGED DATE 07/07/2017 AOGCC M, t ENDE ,K.BENDE/2017 R To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU B-30 Prints: CAST-M Cement Inspection Log CD 1: r MPU B-30_CAST_1.3MAY17.pdf 5/13/2017 10:34PM PDF Document 2,415 KB MPU B-30_CAST_13MAY17 img.tiff 5/13/2017 10:35 PM TIFF He 7,047 KB MPU B-30 CAST_13MAY17 Main.las 6/23/2017 1:32 PM LAS File 9,291K3 Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: 1,1 Date: /'•22Aasz.J;; 5 • • 216153 Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 TeNile+rp 8 Ua.ke.Lt,r: RECEIVED Fax: 907 0 907 777 -8510 E-mail: snolan@hilcorp.com JUN 2 9 2017 DATA LOGGED 1(5/2017 Zvi.K.BENDER DATE 06/28/17 AOGCC To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU B-30 AND MPU B-30PB1 Production profile and digital data Prints: ROP-DGR-EWR-ADR-ALD-CTN 2"/5" MD DGR-EWR-ADR-ALD-CTN 2"/5"TVD PERFORATION RECORD AND PRESS/TEMP SURVEY ROP-DGR-EWR-ADR-ALD-CTN 2"/5" MD PB1 DGR-EWR-ADR-ALD-CTN 2"/5"TVD PB1 GR_CLB_04222017 PB1 GR_CBL_05122017 CD1: 28 3 3 3 , Hilcorp MPB-30_Perf Temp_20May17 FINAL 5/24/2017 11:28 AM Ale folder CD2: 28334 28335 . Log Viewers 5/16/2017 12:11 PM File folder MPU B-30 a � 2 3 3 7 5/16/2017 12:11 PM Ale folder �, ��PB1 � 5/16/201712:11 PM File folder CD;3: 3 3 MPU B-30 CBL-0 PSI Pass.las 5/19/2017 11:17 PM LAS File 1,208 KB MPU B-30 CBL 0 psi 5-12-17.pdf 5/12/2017 9:32 PM PDF Document 3,089 KB MPU B-30 CBL 1000 PSI Pass.las 5/19/2017 2:01 PM LAS File 1,042 KB *,o MPU B-30 CBL 1000psi 5-13-17.pdf 5/13/2017 3:36 PM PDF Document 1,543 KB MPU 5-30 PB1 CBL 4-22-17.pdf 5/2/2017 10:22 AM PDF Document 2,730 KB MPU-B-30_Field CASTM_13-May-17.pdf 5/13/2017 10:27 PM PDF Document 2,415 KB Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: RECEIVED 111 STATE OF ALASKA U 2 01 ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT 4 1 a.Well Status: Oil Q Gas❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ '1 b.Well Class: 20AAC 25.105 20AAC 25.110 Development Q Exploratory ❑ GINJ ❑ WINJ ❑ WAGE' WDSPL❑ No.of Completions: _1 Service ❑ Stratigraphic Test ❑ 2.Operator Name: !6. Date Comp.,Susp.,or 14. Permit to Drill Number/ Sundry: Hilcorp Alaska, LLC Aband.: 6/17/2017 . + 216-153/317-151 /317-206/317-157 3.Address: 7. Date Spudded: 15.API Number: 17-((7 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 April 6,2017 50-029-23571-00-00 . 4a. Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: Surface: 86'FSL,4328'FEL,Sec 18,T13N, R11 E, UM,AK May 4,2017 MPU B-30 Top of Productive Interval: 9. Ref Elevations: KB: 49.6' 17.Field/Pool(s): Milne Point Field 1851'FNL, 1103'FEL,Sec 24,T13N, R10E, UM,AK GL:23.1' BF:23.1' Sag River Oil Pool Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 1858'FNL, 1130'FEL,Sec 24,T13N, R10E, UM,AK 9,515'MD/8,990'TVD , ADL047438(SHL)ADL047437(TPH/BHL) 4b. Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- 571962 y- 6023208 Zone- 4 9,620'MD/9,093'TVD .. LONS 81-054 TPI: x- 569994 y- 6021253 Zone- 4 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 569966 y- 6021246 Zone- 4 N/A 3,190'MD/3,050'TVD 5. Directional or Inclination Survey: Yes E (attached) No ❑ 13.Water Depth, if Offshore: '21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071,submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first.Types of logs to be listed include, but are not limited to: mud log,spontaneous potential, gamma ray,caliper,resistivity,porosity,magnetic resonance,dipmeter,formation tester,temperature,cement evaluation,casing collar locator,jewelry,and perforation record. Acronyms may be used.Attach a separate page if necessary ROP-DGR-EWR-ADR-ALD-CTN 2"/5"MD(B-30),DGR-EWR-ADR-ALD-CTN 2"/5"TVD(B-30),ROP-DGR-EWR-ADR-ALD-CTN 2"15"MD(B-30PB1),DGR- EWR-ADR-ALD-CTN 2"/5"ND(B-30PB1),GAMMA RAY SECTOR BOND LOG(B-30PB1),GR_CBL_05122017(B-30)7". - 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH ND AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD FT. PULLED 20" 78.6# A-53 Surface 106' Surface 106' 42" 50 bbls dumped in annulus 9-5/8" 40# L-80 Surface 5,215' Surface 4,933' 12-1/4" Stg 1 -720 sx/Stg 2-525 sx 243 bbls 7" 26# L-80 Surface 9,605' Surface 9,078' 8-1/2" Stg 1 -165 sx/Stg 2-119 sx 24.Open to production or injection? Yes ❑✓ No ❑ 25.TUBING RECORD If Yes, list each interval open(MD/TVD of Top and Bottom; Perforation SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Size and Number; Date Perfd): 2-7/8" 9,451' 9,366'MD/8,844'ND 9,450'-9,490'MD/8,926'-8,965'TVD 6 SPF,3-1/8"Guns,5/20/17 It.`—ti.,r 0I" 26.ACID, FRACTURE,CEMENT SQUEEZE, ETC. )Ai' 01i-I fo P. Was hydraulic fracturing used during completion? Yes Q No ❑ /t?c<!FfEr_' Per 20 AAC 25.283(i)(2)attach electronic and printed information L,— DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED Frac Focus Attached 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 5/30/2017 Gas Lift Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 6/5/2017 24 Test Period —+487 463 45.2 N/A 950 Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API (corr): Press. 200 50 24-Hour Rate — 487 463 45.2 38 Form 10-407 Revised 5/2017_ lo •2,, 7 CONTINUED,0 PAGE 2 RBDMSubmit ORIGINIAL ons^ )011 Pr- / 17/7 JULaur - s20» ( 1 • 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 ❑✓ Permafrost-Top If yes, list intervals and formations tested, briefly summarizing test results. Permafrost-Base 1,615 1,569 Attach separate pages to this form, if needed,and submit detailed test Top of Productive Interval Sag River(9,450') 8,926' information,including reports,per 20 AAC 25.071. SV1 2,718' 2,599' Ugnu LA3 4,122' 3,905' Top Schrader Bluff 4,626' 4,373' Top HRZ 6,818' 6,468' Kuparuk C Sand 7,260' 6,882' Top Miluveach 7,568' 7,169' Top Sag River 9,432' 8,908' Top Shublik 9,509' 8,984' Formation at total depth: Shublik 31. List of Attachments: Wellbore Schematic,All reports for Drilling,Completion, Frac Work,Completion String Run, Definitive Surveys,Csg and Cmt Reports, Frac Focus, Days vs Depth. Information to be attached includes, but is not limited to:summary of daily operations,wellbore schematic,directional or inclination survey,core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name:Paul Mazzolini Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: cdinger p(7hiIcorp.Com Authorized �,� ' � Contact Phone: 777-8389 Signature: d' /Date: GoU J 7 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, Rod Pump, Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Pursuant to 20 AAC 25.071,submit detailed descriptions,core chips,photographs,and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability,fluid saturation,fluid composition,fluid fluorescence,vitrinite reflectance,geochemical,or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070,attach to this form:well schematic diagram,summary of daily well operations,directional or inclination survey,and other tests as required including, but not limited to:core analysis, paleontological report,production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only Milne Point Unit H . SCHEMATIC • Well: MPU B-30 Last Completed: 6/17/2017 Hilcorp Alaska,LLC PTD: 216-153 KBEIev.:49.6'/GLElev.:23.1' TREE&WELLHEAD RKB—THF:22.92'JInnovation) Tree CIW 2-9/16"5M 4 E.4t.,,, } Wellhead Seaboard Weir,3 spools,w/11"x 5M top 20° flange.2-7/8"TC-II Tubing Hanger 1 P OPEN HOLE/CEMENT DETAIL n 20" Cmt w/50 bbls of Arcticset in 42"Hole 'i' ►, 9-5/8"(2"d Stage) Cmt w/350 sks 10.7 ppg Perm L,275 sx 15.8 ppg SwiftCEM in 12-1/4"Hole 2 Q 9-5/8"(1st Stage) Cmt w/505 sks 11.7 ppg ExtendaCEM,215 sx 15.8 ppg SwiftCEM in 12-1/4"Hole ES cementer 7"(2nd Stage) Cmt w/119 sks 14.7 ppg Class"G"in 8-1/2"Hole @1,819 7"(1st Stage) Cmt w/165 sks 15.3 ppg Class"G"in 8-1/2"Hole 3 0, CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm w 4 i 20" Conductor 78.6/A-53/Weld 19.124" Surface 106' 95/80 9-5/8" Surface 40/L-80/DWC/C 8.835" Surface 5,215' 7 7" Production 26/L-80/Hydril 563 6.276" Surface 9,605' 5 TUBING DETAIL 111 f°>r "' 2-7/8" Tubing 6.4/13Cr-85/JFE Bear 2.441" Surface 9,451' a-Tac WELL INCLINATION DETAIL 6,050'MD V 2 4.t KO P @ 600' MD 5/13/171 ,C) at l is Max Hole Angle=25.08 deg at 8,467' MD 'i'" 5,A N b Hole angle through perforated interval: 12° JEWELRY DETAIL , ,: 8 No Depth ID Item 5 1 2,340' 2.441" STA 10:2-7/8" 1.0M GLM (12/64 Dome)TRO 1043 Latch BK ES Cementer 2 3,526' 2.441" STA 9:2-7/8" 1.0M GLM (12/64 Dome)TRO 1036 Latch BK @7,600 s 3 4,143' 2.441" STA 8: 2-7/8" 1.0M GLM (SO 16/64) Latch BK 4 4,791' 2.441" STA 7: 2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) roc 10 5 5,440' 2.441" STA 6: 2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) MD i 6 6,057' 2.441" STA 5: 2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) 5/13/17 6$ 11 11 7 6,706' 2.441" STA 4: 2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) 8 7,354' 2.441" STA 3:2-7/8" 13Cr80 SPMO 1.OM GLM (Dummy Valve) 12 9 8,001' 2.441" STA 2:2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) 10 8,555' 2.441" STA 1:2-7/8" 13Cr80 SPMO-1.0M GLM (Dummy Valve) sot 1�1 13 11 9,201' 2.313" 2-7/8"9Cr XD Sliding Sleeve _ ,,. , 4.14 12 9,247' 2.414" 2-7/8" 13Cr Pressure Intake Gauge 13 9,355' 2.313" 2-7/8"9Cr X Profile il l a 14 9,366' 2.360" 7"x 2-7/8" 13Cr PHL Hydraulic Retrievable Packer 15 15 9,413' 2.205" 2-7/8"9Cr XN Profile lu tt 16 9,451' 2.350" 2-7/8" 13Cr WLEG-Bottom @ 9,452' 16 0 PERFORATION DETAIL k .ii, Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status SAG { Sag River 9,450' 9,490' 8,926' 8,965' 40' 5/20/17 Open 3-1/8"GeoDynamics 3323 ConneX l ") GENERAL WELL INFO „. API:50-029-23571-00-00 7" l a _ " Drilled,Cased&Completed by Innovation#1 5/16/2017 TD=9,620(MD)/TD=9,093'(TVD) Frac Job 5/29/2017 PBTD=9,515'(MD)/PBTD=8,990'(TVD) 2"d Completion by ASR#1—6/17/2017 Revised by:TDF 6/29/2017 ! • Hilcorp Alaska, LLC Hilcorp Alaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future Daily Operations: 3/29/17-Wednesday No operations to report. 3/30/17-Thursday No operations to report. 3/31/17-Friday No operations to report. 4/1/17-Saturday No operations to report. 4/2/17-Sunday Continue R/D svc lines. Blowdown steam system. Prep location and continue demobing periphial equipment from perimeter of rig. Ready landings and secure stairs.Peak on location @ 23:00 hrs.PJSM,Demob utility complex,Pit complex,Pipeshed,. Scope cattle chute and demob catwalk. Stage at ends of location. Demob sub and stage same. Trucks released @ 04:00 hrs.Prep 10"flowline for removal and replacement. Give 1 hr notification to Wells Support for work to begin on B-33. Clean,Remove and stage mats from B-33. Remove liner and clean around cellar area.Spot heaters @ pump room and sub. Begin working to replace 3x liners on mud pump#2 and ready both pumps for B-30. Continue cleaning up mats and containment from around well B-33. Set up crane and remove/replace 10"flowline with 12"flowline. Continue working on MP#2.Continue working on misc projects throughout rig while waiting on wells group to complete work on B-33. C/O geo-span. Prep pad,lay liner and set mats for rig on B-30.Set diverter Tee&adapter.Well support finished with B-33 Tie in&clear equipment from B-33.Peak trucks on location @ 1530.Spot sub over well B-30. Set Catwalk,pipeshed,pits and utility complex.Begin rigging up svc lines and equipment. Scope cattle chute and winterize connections between modules.Steam on @ 0300. Released Peak Rig Movers @ 00:30 Set stairs and walkways.Begin setting 3rd party shacks. Set cuttings box. Begin Rig Acceptance checklist. 4/4/17-Tuesday Continue to work on rig acceptance check list.Scope up derrick.Bridle down. N/U BOPs on Diverter Tee,N/U 16"Knife valve and Diverter.Dress shakers with screens.Receive first loads of spud mud.Leave on trucks to keep cool. Swap rig to gen power from cold starts. Swap to high line @ 1100. Note:rig accepted @ 12:00 hrs Finishing torquing all connections on the diverter and finishing up in the cellar. Continue to work on flow line upgrade. Prepping to pick up drill pipe.Perform derrick inspection.Work on rig acceptance checklist.Thaw cellar box,install 4"valves on conductor.Steam off top drive,check and tighten all fittings.Welder finish 12"flow line install.Remove flow line jet plumbing not being used,re-route and install new flow line jets, install flow sensor paddle.Install mud line and shock hose in mezzanine.Stock hopper room w/mud products.Strap surface BHA.Set diverter warning sign and diverter containment in place.Attempt to install 11'bails,eye to small on bail,remove same.Reinstall 10'bails.Install 12.375"ID wear bushing, function test diverter,annular closed in 36 sec,knife valve opened in 6 sec.Drift and P/U 200 jts 5"DS50 drill pipe racking stands in derrick,currently 65 stds in drk.Finish plumbing flow line jets,fill pill pit 1 w/water.Circulate and test low pressure mud lines and equipment. • • Hilcorp Alaska, LLC HiIcorpAlaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future �r 5 t 3K'K ,�;ST)t�f '•.A� S U.y`SWa M h C l"'i*c 34e.. �t i # t � 4/5/1744rednesday P i P/U 5"DS-50 DP and stand back 100 stands total.Stand back 18 stands HWDP.Perform Diverter drill and accumulator Draw Down.Chuck Scheve Waived witness of Diverter test @ 0715 4-5-2017 Knife valve open in 4 sec,Annular Closed in 9 sec.200 PSi INC 7 Sec,Full Pressure Obtained 37 sec. N2-6 BTL @ 2300 psi. All passing.Slip&Cut Drilling line,Service rig and TD.Pre Spud Meeting from 15:30 to 16:30,wait on weather,planes grounded due to high wind and blowing snow,phase 2 weather conditions,clean on rig,house keeping.Pre spud meeting with oncoming crew and rig support,continue to wait on weather,planes grounded due to high wind and blowing snow,phase 2 weather conditions,clean on rig,general house keeping.Clean in pump room,rig floor and pipe shed.Work on hard copy for SDS.Conduct table top rig evacuation drill,rolls and responsibilities,primary and secondary muster areas.Continue to wait on weather,planes grounded due to high wind and blowing snow,phase 1 weather conditions,clean on rig,general house keeping.Continue to work on hard copy for SDS. 4 s 177 Thursda Continue waiting on weather due to phase 2 weather conditions.Pressure wash under pipe skate,clean and organize throughout rig.PJSM,Test standpipe manifold and lines with water to 3000 psi,good.Blow down lines.M/U cleanout BHA,12 1/4"Tricone bit,mud motor,XO and 1 std HWDP to 97'.Make connection,wash down f/97'tagging cmt @ 100',cleanout cmt to bttm of conductor @ 106'pumping 350 gpm,250 psi,20 rpm.Spud well,drill 12 1/4" surface hole f/106'to 139'pumping 350-400 gpm,340-450 psi,4-6k wob,25 rpm,1.5k tq.P/U into conductor 2 times to check flow line.Pump 550 gpm, 740 psi attempting to clear flow line.Observed flow line packing off on second time.Attempt to pump thru bleeder to clear line,shut down,rack 1 std back,BD TD.Cleanout flow line w/super sucker.Remove 12"dresser sleeve,weld in solid piece of 12"to eliminate gravel buildup in dresser sleeve.Install 2 flow line jets.Test flow line up to 740 GPM with all jets on attempting to clear gravel.Working jets. Make connection and drill down 5-10 at a time.to 154'.Plumb in air to new flow line jets. Work all Jets while clearing flow line.Pick up in to conductor and clear flow line using bleeder and high flow rates working jets. Continue drilling ahead F/154'T/ 220'. While making connection circ through bleeder at 320 GPM.Circulate hole clean,POOH f/220'to mud motor racking 3 stds HW in derrick,L/D XO,pull mud motor,L/D tricone bit.PJSM,M/U 12 1/4"PDC bit,1.5 deg mud motor w/stb,integral blade, DMC,offset set @ 127.14 deg.M/U DGR,EWR-P4,PWD,HCIM,TM,UBHO,download MWD,M/U 2 flex collars,BN xo=154.94' R/U Gyro.Wash and ream down 2 stds HWDP f/155'to 220'@ bttm staging pump up to 440 gpm,640 psi,20 rpm,2200 tq.No fill Drilling 12 1/4"hole f/ 220'pumping 442 gpm,800 psi,60 rpm,2.1k tq.2.5-3.5k wob,drill 3 stds HWDP down to 398',rack 1 std back,M/U single HW w/jars.Continue,drlg f/ 398'to 440'(220')avg rop 62.8 fph PU/SO/ROT 60k/58k/60k MW in/out 9.1,vis 217 running water 40 bph,both centrifuges running. Drill Ahead 12.25 Directional hole section F/431'1/585'@ 480 GPM,70 RPM,5K WOB. Back reaming one single.Start build section.Drill Ahead 12.25 Directional hole section sliding 75-100%on each stand F/585'T/752' 450 GPM,Taking gyro surveys every 60'. Last Gyro survey at 726'.Keep Gyro on stand by until MWD clears 3 good MWD surveys. Release Gyro @ 1017'.R/D same.Drill Ahead 12.25 Directional hole section F/752'T/1240'. 488'av ROP @ 69(150 FPH on btm)Stage up pumps to 550 GPM 1460 psi,MW 9.1 240 Vis,9.7 ECD 6K WOB 5K TQ Drill 12.25"Directional hole F/1240'T/ 1965'.725',AV ROP 120.8 (221 FPH on btm)Finish Build section @ 1330' 22 deg GPM 552,PSI 1550 WOB 5k,TQ 5 MW 9.2/200 Vis,10 ECD PU/SO/ROT 99/89/95 Drill 12.25"Directional hole F/1965'T/2594'. 629',AV ROP 104.8 (166.8 FPH on btm) GPM 575,PSI 1700 WOB 2-6k 80 RPM TQ 6.6k MW 9.3/150 Vis,10.05 ECD PU/SO/ROT 110/94/102 Continue with 17'maintenance slides 10%of the time.Note:at 2230'pump 40 bbl hi vis,4 ppb walnut w/condet sweep around,sweep back 200 stks late w/100%inc @ shakers,mostly clay w/fine silt. Max gas 2300u @ 2279'9.87 rotate hrs,5.15 slide hrs. Currently 0.7'left of the line. . • Hilcorp Alaska, LLC 'blearpAlaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future 4/8/17-SaturdaY;. Drill 12.25"Directional hole F/2594'T/3131.537',AV ROP 89 (150FPH on btm) GPM 475,1500PSI WOB 10k 80 RPM TQ 6.6k MW 9.3/160 Vis,10.2 ECD PU/SO/ROT 129/107/117.Back ream 60'Control drill F-2594 T-3250 due to shakers packing off.Build Volume&Limit ROP to 150 FPH. Pump 20 bbl sweeps every 500'. Sweeps @ 2654'0%3158'300%.Drill 12.25"Directional hole F/3131'T/3729'.598',AV ROP 100 (200 FPH on btm) GPM 475,1500PSI WOB 10k 80 RPM TQ 6.6k MW 9.3/160 Vis,9.9 ECD PU/SO/ROT 129/107/117 3754 100%inc.Drill 12.25"Directional hole F/3729'T/4293'.564',AV ROP 94 (176.2 FPH on btm) GPM 550,1800 PSI WOB 10k 80 RPM TQ 10k MW 9.3+/150 Vis,10.2 ECD PU/SO/ROT 150/117/134.3754'Pump 50 bbl hi vis sweep w/4ppb walnut/condet,Hole unloaded at B/U,sweep back 600 stks late w/100%increase @ shakers.Drill 12.25"Directional hole F/4293'T/4720'.427',AV ROP 71 (142 FPH on btm) GPM 580,1950 PSI WOB 8-10k 80 RPM TO 10k MW 9.3+/150 Vis,9.8 ECD PU/SO/ROT 167/123/142.4374'Pump 30 bbl hi vis sweep w/4ppb walnut/condet,Hole unloaded at B/U,sweep back 400 stks late w/500%increase @ shakers.mostly clay/silt and some sand. Maintenance slides @ 10%.Currently 8.6'above the line,2.9'left of the line. 4/9/17'-Sunday Drill 12.25"Directional hole F/4720'T/5220.500',AV ROP 62 (30-150 FPH on btm) GPM 580,2000 PSI WOB 10-15 80 RPM TQ 10k MW 9.3+/100 Vis,9.8 ECD PU/SO/ROT 167/123/142.Back reaming full stands. Drop angle 18.5 deg. hard drilling at the base of the Shrader bluff.Broke through in to shale @ 150 FPH.Circ sweep around @ 600 GPM treating mud for cmt job.Dropped vis from 150-76. Gravel started running after sweep returned. Reduce GPM to 500&Hold off on dropping vis.Circ two btm up.Shakers cleaned up ok but still getting gravel intermittently. MW 9.4,Vis 76.YP 25. Sweep came back.Monitor well.Static.POOH on elevators F/5220'T/3658'.Pulling 10-40 Over puts.Work back down with no problem.Not sticky. Work through on elevators.After pulling through its clean.Pulling tight @ 3658'w/40k overpull,m/u top drive,pump out f/3658'to 1585'400 gpm,1000 psi. Attempt to pull on elevators several times w3Ok overpull and swabbing issues.Continue to pump out of hole f/1585'to HWDP @ 709',Pump out f/709' to 580'racking 2 stds HWDP,Blow down top drive. Note:correct displacement on trip out.POOH on elevators f/580'racking 6 stds HWDP w/jars in derrick.L/D BHA-BN XO,2 NMFCs,upload MWD data. L/D UBHO,TM,HCIM,PWD,EWR-P4,DGR and DMCs,stab,mud mtr,BO bit.12 1/4"PDC bit grade=1/4/BT/A/X/I/WT/TD. • • Hilcorp Alaska, LLC HikorpAlaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future 4/10/17-Monday Pul Wear bushing.Flush flow line out.R/U Weatherford 9 5/8 casing equipment.Change bails to long 14'casing bails. Install 9 5/8 side door Elevators. Install 9 5/8 Insert bushings PJSM,P/U Shoe,FC,&Baffle adapter.Install centralizers as per tally.Check floats.Good. RIH F/129'T/1065'.Tag up. Fill on the fly topping off every 5 joints with fill up line.Use BOL 2000 pipe dope,optimum torq @ 31000 ft/lbs,utalize dog collar clamp on 1st 10 jts ran.Tag up. Stage up pumps to 3 bpm,Attempt to wash through with no success.Rot down @ 10 RPM 6K tq. Wash through and ream through without issue. Wash and ream as needed F/1065'T/1287'.RIH on elevators F/1287'T/2215'. Filling on the fly and topping off with CRT every 15 joints.Use RIH on elevators F/2215'T/2648'. Filling on the fly and topping off with CRT every 15 joints.Circ and condition mud lowering YP f/32 to 17/23 in/out,staging pump up f/3 bpm,100 psi,4 bpm,130 psi-to 5 bpm 150 psi,reciprocate casing,pump 1 circulation.Losses @ 1 bph. PU/SO 136/96 RIH on elevators F/2648'T/3395',Baker loc and MU ESC between jts 79-80,ensuere 6 pins 3300 psi shear(placing top ESC @ 1819') Continue RIH on elevators f/3395'to 4350'(jt 102)w/50k set downs,unable to work past,PU 200K,50 115K Note:Install 3 centralizers on 3 jts above and below ESC Wash down f/4350'to 5218'pumping 3 bpm 380 psi, (122 jts total)PU 225K,SO 138K.Verify pipe count,6 jts left out. Note:slight packing off to start and then full returns on jt 102 Circulate and condition mud for cement job,stage pump to 5 bpm 240 psi,reciprocate pipe 15',lower YP 20+-. 4/11/17-Tuesday Circulate and condition mud for cement job @ 5215',stage pump to 5 bpm 240 psi,reciprocate pipe 15',lower YP 20+- k� ',PJSM for 1st stage cement iob.R/U cementers.M/U cement head,witness loading bypass plug,11 1/2 turns on plug release plunger,Blow down top drive. (P R/U circ lines.Pump 1st stage CMT:With cementers,pump 5 bbls water,pressure test lines to 800 psi low,4000 psi. 77 Pump 60 bbls 10.5 ppg tunned spacer with red dye.Drop bypass plug,load closing plug Mjx and pump 505 sxs(221 bbls)Extenda Cem Lead Cement at 11.7 ppg. Mix and pump 215 sxs(44.3 bbls)Swift CemTail Cement at 15.8 Dog.Drop Shut off plug.displace cmt w/20 bbls FW f/Cmt Unit Rig Pump 190.8 bbls,9.6 ppg mud Cmt Unit 80 bbls FW Rig Pump 97.9 bbls 9.6 ppg mud. Total Displacement @ 388.7 bbls CIP @ 12:30 hrs 1st Stage Details:Lost 25 bbls during displacement. Pump Cement @ 4 BPM Average. Pump Disp @ 5 BPM Average.Calculated Disp 388.7 bbl,Actual Disp 388.7 bbl.FCP 800 psi @ 2 BPM Using rig pump,stage pressure up 3150 psi to open ES Cementer.CBU through Stage tool staging up to 5 bpm,bringing 116 bbls contaminate. _Mud and 66 bbls green CMT to surface.Overboarded Total of 405 bbls.Lost 25 bbls to o e.S ut sown pumping. I isconnec m e va ve. ush stack and work annular with"Black Water". Circulate"Black Water"through flowline jets and all surface lines.Continue to circulate through ESCMTR @ 4 bpm, while prepping for 2nd stage cement.Send Notification to AOGCC on up coming BOP Test.Test witness waived by Brian Bixby via email.PJSM with all parties on pumping 2nd stage cement. - Pump 2nd stage Cement As Fnllnws: Mix&pump 60 bbl 10.5 ppg spacer Mix and pump 350 sxs(270 bbls)Perm L Lead Cement at 10.7 ppg. ss)'d Mix and pump 275 sxs(56.6 bbls)Swift CemTail Cement at 15.8 ppg.Drop closing Plug.Displace cmt w/20 bbls FW f/Cmt Unit Rig Pump 117.2 bbls,9.4 ,f% ppg mud Total Displacement 137.2 bbls Bump Plug @ 2 bpm,430 psi FCP Pressure up to 1730 psi&close ESCMTR.Hold for 5 min.2nd Stage Details:Full returns through out job. Pump Cement @ 4.8 BPM Average. Pump Disp @ 4 BPM Average.Calculated Disp 138.7 bbl,Actual Disp 137 bbl. FCP 430 psi @ 2 BPM Pumped 50 bbls Excess Lead,bringing contaminated cmt to surface before going into Tail cement.Bring total of 177 bbls Groan CMT tr,mac. Overboard returns when spacer at surface. CIP @ 23:20 hrs.Blow down cement line,Flush stack and all surface equipment with black water,function annular and flush,R/D cementers.Fill stack w/ blackwater and soak. Center up csg in wellhead.ND diverter system,P/U stack,install 9 5/8"emergency slips per wellhead rep w/100k set on slips, R/D cement head,welder cut off 9 5/8"casing,remove cut jt.Set stack down and 4 point same.Flush stack with black water,function rams,open up ram doors and inspect ram cavities,N/D diverter line.Continue to clean pits.Load 5"DP into pipe shed. • i Hilcorp Alaska, LLC 11ileorpLLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future Daily Operations: 4/12/17-Wednesday Inspect ram cavities,C/O top seal on upper VBR ram.Remove diverter valve.P/U stack and remove Diverter Tee,Set BOP stack on stump.Service drag chain and skate.dress 9 5/8"casing stub.(32.83'cut jt)Install multi bowl wellhead,pressure test void,500 psi low f/5 min,2450 psi high 15 min.Finish inspecting ram cavities.Clean in pits.Install 4 flow line jets.Remove long bails f/top drive.Stage pitcher nipple on rig floor.N/U BOPE,Install and flange 11"x 13 5/8"5M DSA,Install and flange BOP stack,M/U kill and choke hoses.Install riser and drain pan,drain hoses and flow line.Load pits w/580 bbls 9.5 ppg Baradril N drilling mud.Welder finish installing flow line jets,plumb in same.Prep test jt and test plug.R/U test equipment,fill stack and lines with P FW.Shell test BOPE to 4000 psi,good.AOGCC rep Brian Bixby waived test witness on 4-11-17 @ 17:03 hrs.Test w/5"test joint. 6 a Open and Monitor annulus.Test upper and lower 2 7/8"x 5 1/2"VBR,choke manifold,blind ram,upper and lower IBOP,FOSV,dart valve,mud cross 1� r/ valves and annular to 250 psi 5 min ea.4000 psi 5 min ea,chart all tests.Perform hyd and manual choke bleed test.Test PVT operation. Perform accumulator drawdown test,check N2 bttls.Calibrate and test gas alarms.Close annulus valve,R/D test equipment.No failures.Blow down choke manifold and lines,Install 10"ID wear bushing,RI4LDS.PJSM,load tools to rig floor,M/U BHA 2, PDC bit,mud mtr w/1.5 deg bend,Scribe&set offset @ 355.89 deg,M/U DMC,DGRC,PWD,ADRC, ALDC w/stab,CTNC,TMC,NMFS,download MWD data.M/U NMFC,perform MWD shallow pulse test pumping 400 gpm,800 psi,good.Blow down top drive.PJSM,load sources per MWD.RIH with 3 stds HWDP,jars with single jt HWDP and 5 stds HWDP= 734.02'. 4/13/17-Thursday Service Rig @ 734'.Continue to TIH Picking up 5"DS-50 DP from 734'to 1782'.Tag Cement w/5K Dn 81 Dn Wt,96K Pu Wt.Drill cement f/1782'to 1813'. Drill ES CMTR f/1813 to 1817'@ 3K WOB,350 GPM,850 PSI,25 RPM, 4-7K Tq.Ream through X2,pass through no rotary,no issues.Continue to single in the hole with DS-50 drill pipe to 3816'.TIH from Derrick from 3816'to 5070'.MU TD and wash down(/5070,tag CMT @ 5092'.Work Pipe and circulate hole clean for casing test @ 400 GPM,1300 psi,25 RPM,11K Tq.Stand back 1 stand,Blow down TD,MU 2"Circulating equipment.RU to Test casing.Test Casing to 2900 psi on chart for 30 minutes.Good Test.R/D&Blow Down Test Equipment.Drill soft cement f/5092'to firm cement @ 5108'pumping 400 gpm,1230 psi,30 rpm,11.2k tq. drill baffle adaptor and plugs f/5119'to 5123',drill cmt to 5162' drill FC F/5162'to 5164'.Drill cement to 5207',drill out shoe f/5207'exiting.shoe @ 5209',cleanout rat hole to 5220'. Note:tag BA,FC and shoe 6'high compared to casing tally.Drill 20'new formation f/5220'to 5240'pumping 400 gpm,1200 psi,30 rpm,12k tq.wob 10k. Start displacement,pump 30 bbl hi vis spacer,followed w/new 9.5 ppg LSND drlg mud.Continue to Displace w/new mud until a good 9.5+in/out, reciprocate and work string. Obtain SPR#1 and#2 mud pumps. PU/50/ROT 180/125/150.Pull into casing,park @ 5197',BD top drive,M/U FOSV,Head pin and circ hose,circulate through choke and DP,close annular, perform F.I.T to 12.5 ppg EMW using existing 9.5+ppg MW.Pump 1.1 bbls down kill line and drill pipe applying 757 psi,monitor casing pressure,10 sec 751 psi,5 min 735 psi,bleed off pressure,1.1 bbls bled back,open annular.BD choke and lines.M/U stand,wash and ream f/5215 to bttm @ 5240'.Drill 8 1/2"Directional hole F/5240'T/5820'.580',AV ROP 82.9 (116 FPH on btm) GPM 500,1700 PSI WOB 8-15k 80 RPM TQ 11.5k MW 9.5/44 Vis,10.3 ECD PU/SO/ROT 188/131/154.0.58 slide hrs,2.93 rotate hrs. Currently 1.1'below the line,6.4'left. i • Hilcorp Alaska, LLC Hi!carp Alaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future 4/14/17-Friday Drill 8 1/2"Directional hole F/5820'T/6330'(510')AROP 85 (150 FPH on btm) GPM 500,1928 PSI WOB 13k 50 RPM TQ 12-13k MW 9.5/44 Vis,10.4 ECD PU/SO/ROT 205/136/167.Madd pass Every Slide Section as per DD @ 180 to 200 fph.Drill 8 1/2"Directional hole F/6330'TI 6770'(440')AROP 88 (150- 180 FPH onbtm) GPM 500,2100 PSI WOB 12-16k,80 RPM TQ 14k MW 9.5/44 Vis,10.4 ECD PU/SO/ROT 205/136/167.Madd Pass Slide Interval @ 6738'to 6703'.Pump 40 bbls hi visc sweep&clean up hole W/500 gpm/1750 psi,80 rpm,/11K Tq. Hole unloaded with 50%increase in cutting at shaker.Mostly clays.Down on Pump,Monitor Well.TOH on elevators from 6770'to 6250'with no issues. Started seeing swabbing and over pull @ 6250'.UWT 220K,DWT 153K.Pump out of hole from 6250'into 9 5/8"casing just above shoe @ 5191',BD top drive.Service rig,Electrician replace PLC card for drillers console.Weight up mud system f/9.6 ppg to 10.3 ppg before tripping back to bttm and drilling into HRZ.RIH on elevators f/5191'to 6710',wash last stand tagging bttm @ 6770',no fill.Pump hi vis sweep,displace well to 10.3 ppg mud until 10.3 in/out pumping 400 gpm,1170 psi.reciprocate pipe,sweep back on time w/50%increase.Obtain SPR#1&#2 MP.Drill 8 1/2"Directional hole F/6770' T/6860'(90')AROP (140 FPH on btm) GPM 500,2000 PSI WOB 12-14k,80 RPM TQ 12k MW 10.3/45 Vis,11 ECD PU/SO/ROT 202/151/176.0.99 slide hrs.7.28 rotate hrs. Currently 4.31'left of the line. 4/15/17-Saturday Drill 8 1/2" hole F/6860'T/7202'(342')AROP 57 FPH(30-50 FPH on btm) GPM 500,2070 PSI WOB 12-14k,80 RPM TQ 12k MW 10.3/45 Vis,11.1 ECD PU/SO/ROT 208/148/176.@^'7100' noticed some slight seepage(3bph),shut off water and monitored while we continued drilling ahead seepage healed (7200')after increasing background LCM to 8 ppb.Drill 8 1/2" hole F/7202'T/7338'(136')AROP 39 FPH(90 FPH on btm) GPM 500,2070 PSI WOB 12-14k,80 RPM TQ 12k MW 10.3/45 Vis,11.1 ECD PU/SO/ROT 215/150/176.Max gas @ 1400 units.Pumped 20 bbls hi vis sweep @ 7200'.Circulate Sweep out of hole with 50%increase in cutting at shakers.Drill 8 1/2" hole F/7338'T/7438'(100')AROP 50 FPH(66 FPH on btm) GPM 500,2070 PSI WOB 12-14k,80 RPM TQ 12k MW 10.3/45 Vis,11.1 ECD PU/SO/ROT 222/151/174.Drill 8 1/2" hole F/7438'T/7776'(338')AROP 56 FPH(95 FPH on btm) GPM 500,2300 PSI WOB 8-12k,80 RPM TQ 15k MW 10.3/45 Vis,11 ECD PU/SO/ROT 230/152/190.Note:Add dril-n-slide to mud system to.80%torq dropped from 16.5k to 14.5k. Pump 20 bbl hi vis sweep @7715',no increase @ sweep returns.Drill 8 1/2" hole F/7776'T/8092'(316')AROP 52.6 FPH(90 FPH on btm) GPM 500,2350 PSI WOB 8-12k,80 RPM TQ 15k MW 10.3/45 Vis,11.1 ECD PU/SO/ROT 234/157/192.Currently 3.52'below the line,1.82'right. • • Hilcorp Alaska, LLC Hilcorp Alaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future 4/16/17-Sunday Drill 8 1/2" hole F/8202'T/8470'(268')AROP 44.6 FPH(90 FPH on btm) GPM 500,2235 PSI WOB 8-12k,80 RPM TQ 14k MW 10.3/45 Vis,11.1 ECD PU/50/ROT 247/155/195.Increase lube to 2%with Drill N Slide.Drill 8 1/2"hole F/8470'T/8753'(283')AROP 47.1 FPH(72.7 FPH on btm) GPM 500,2550 PSI WOB 8-12k,80 RPM TQ 15.5k MW 10.3/45 Vis,11.1 ECD PU/SO/ROT 247/155/195.At 8593'pump hi vis sweep,200%increase @ shakers,dump sweep returns,Attempt to slide @ 8665',see 40 K Over pull, Attempt to Rotate see 20K Stalls.Work free with no further issues.Drill 8 1/2"hole F/8753'T/9036'(301')AROP 50.1 FPH(70.6 FPH on btm) GPM 500,2550 PSI WOB 10-15k,80 RPM TO 16k MW 10.3/44 Vis,11.1 ECD PU/SO/ROT 259/175/208.Drill 8 1/2"hole F/9036'11 9275'(239')AROP 39.8 FPH(55 FPH on btm) GPM 500,2600 PSI WOB 10-15k,80 RPM TQ 16k MW 10.3/48 Vis,11.2 ECD PU/5O/ROT 262/173/211.At 9100'Pump 20 bbl hiv sweep,100%increase @ shakers,dump sweep returns. Currently 15.61'below the line,3.68'right 3.76 slide hrs,12.34 rotate hrs. 4/17/17-Monday Drill 8 1/2"hole F/9275'T/9650'Section TD as per Geologist GPM 500,2665 PSI WOB 10-15k,80 RPM TQ 16k MW 10.3/48 Vis,11.1 ECD PU/SO/ROT 267/182/219.Observed 7 bph loss rate @ 9510'.Treat and heal losses with Baracarb.Had over pull and stall at 9600'.Maintain 2%lube.Pump tandem 35 bbl Low Vis/HiVis sweeps.Sweeps back on time.Minimal change w/Low Vis/50%with Hi Vis at shakers.Stand back 1 stand.continue to circulate and increase MW from 10.3 to 10.8 ppg.Pump 400 GPM 1180 psi working pipe slowly.Get SPR#1&#2 MP PU/SO/ROT 280/190/228.Flow check well,static.Pump out of hole 500 fph pumping 200 gpm,535 psi f/9590'to 8345'.Continue to pump out of hole 500 fph pumping 200 gpm 550 psi 1/8345'to 7276'with packing off and 15-20k overpulls,work pipe,unable to get returns.Increase pump to 400 gpm, working and rotating pipe down 20k torq w/several stalls,get full returns and rotation back,backream f/7276'to 7230',note-pumped away 80 bbls. Continue pumping out pulling 500 fph pumping 200 gpm,550 psi f/7230'6710'w/no further issues.Pump 40 bbl hi vis sweep pumping 400 gpm,1500 psi,rotate 50 rpm,working pipe up slow cleaning up wellbore. 4/18/17-Tuesday Drill 8 1/2"hole F/9275'T/9650'Section TD as per Geologist GPM 500,2665 PSI WOB 10-15k,80 RPM TQ 16k (' MW 10.3/48 Vis,11.1 ECD PU/SO/ROT 267/182/219.Observed 7 bph loss rate @ 9510'.Treat and heal losses with Baracarb.Had over pull and stall at 9600'.Maintain 2%lube.Pump tandem 35 bbl Low Vis/HiVis sweeps.Sweeps back on time.Minimal change w/Low Vis/50%with Hi Vis at shakers.Stand back 1 stand.continue to circulate and increase MW from 10.3 to 10.8 ppg.Pump 400 GPM 1180 psi working pipe slowly.Get SPR#1&#2 MP PU/SO/ROT 280/190/228.Flow check well,static.Pump out of hole 500 fph pumping 200 gpm,535 psi f/9590'to 8345'.Continue to pump out of hole 500 fph pumping 200 gpm 550 psi f/8345'to 7276'with packing off and 15-20k overpulls,work pipe,unable to get returns.Increase pump to 400 gpm, working and rotating pipe down 20k torq w/several stalls,get full returns and rotation back,backream f/7276'to 7230',note-pumped away 80 bbls. Continue pumping out pulling 500 fph pumping 200 gpm,550 psi f/7230'6710'w/no further issues.Pump 40 bbl hi vis sweep pumping 400 gpm,1500 psi,rotate 50 rpm,working pipe up slow cleaning up wellbore. • • Hilcorp Alaska, LLC Hileorp Alaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future Daily Operations: 4/19/17-Wednesday Continue run 7"DWC/C,26#,L-80 casing as per detail f/209'to Cse Shoe=@ 52Q0..$reak Circulation and establish parameters @ 2 bpm/200 psi,163 PU/106 SO,Rt 10 rpm 11.5 TQ,4 BPM/240 PSI,160 PU/108 SO,Rt 10 rpm 12.5 TQ.Continue run 7"DWC/C,26#,L-80 casing as per detail f/5200'-T/ 6700'.(100'above HRZ).CBU @ 6700'.Staging pump to 6 BPM/480 PSI,198K PU/115K Dn,115K.5 RPM/16K TQ.10 RPM 16-17K Tq.Continue run 7" DWC/C,26#,L-80 casing as per detail f/6700'-T/8350'.Losing SO Wt w/30-50K Bobbles and return flow falling off.Engage Volant tool,fill pipe and break circulation @ 2 BPM.Establish returns with 450 psi.Stage pump to 3 BPM/530 PSI with full returns.Continue run 7"DWC/C,26#,L-80 casing as per detail F/8350'-T/9330'MD.Encountered tight spot @ 9330'MD. Able to 5/0 but unable to break over picking up(350k max up).Attempt to break circulation (no returns @ 1/2 to 2 BPM).Continue work pipe with rot and pumps. Establish circulation @ 1.5 BPM/575 psi w/diminished returns(50%). Increase rate to 2 BPM and slowly wash down F/9330'-T/9575'MD Cleaning up hole.Encountered tight spot @ 9575'MD. Temporarily detained w/no circulation. Establish circulation and stage up F/1.5 BPM to 4.5 BPM w/820 psi(75-90%returns).Work pipe using rot&pumps w/consistent hard tags @ 9575'MD. 18k max tq. Pick up @ 330-350k w/break backs to 250k when pulling extremely slow. 4210 units gas @ 9575'btms up.Saw fine shale back at shakers while working pipe. Max gas observed @ 14,400 units while working pipe. MW 10.2 no psi/10.3 psi scale. Run degasser and continue to build active volume.Continue working pipe F/9575'-T/9594'MD. (Making progress). Increase MW T/10.9 for wellbore stability and increase in gas units. 4/20/17-Thursday Continue to work 7"casing Tag Jt from 9600'to 9646',establish rotation @ 10 RPM/10-12K Tq,full circulation @ 5 BPM/600 PSI,320K Up,156K Dn.Work down and C/O 12'below Shoe setting depth.PUH to 9600'and lay down Tag it.PU and MU 7'Fluted Mandrel Casing Hanger and Landing Joint.Wash down and land hanger on depth,placing the shoe @ 9634',FC @ 9547'.CBU from 9634'.Pump half Btm Up @ 6 BPM&remainder of circulation @ 5 BPM. Loss rate @ 6 BPM-35 BPH,5 BPM-Static.Clean and clear rig floor of casing running equipment.Shut down.RD Volant Tool.DSM witness loading of top and btm plugs.MU CMT head and lines.Circulate through CMT Hose @ 5 BPM/575 PSI.PJSM with HES and Drill Crew.HES start batch up spacer.Pump CMT:With cementers,pump 5 bbls water,pressure test lines to 800 psi low,4000 psi. Pump 30 bbls 12 ppg tunned spacer Drop Bottom plug,Mix and pump 315 sxs(86 bbls)Premium Cement at 15.8 ppg. ` (� Drop Top Plug Plug. ,� �5 j Displace cmt w/20 bbls FW f/Cmt Unit �' Rig Pump 345 bbls,10.9 ppg mud Total Displacement @ 365 bbls CIP @ 15:45 Details: Lost 41 bbls through out job. , Pump Cement @ 2.5 BPM Average. Pump Disp @ 5 BPM Average.Calculated Disp 366 bbl,Actual Disp 365 bbl. FCP 883 psi @ 2 BPM.Bump Plug 500 psi over FCP(1615 psi). Floats held.Bleed back 2.4 BBLS.Prepare cellar and wellhead. R/D cmt head. Blow down lines. B/O landing jt. M/U packoff and set same. Test packoff 500/5000 psi w/10 min hold(ok). R/D casing equipment.Change out upper pipe rams to 2-7/8"x 5-1/2"VBR's.Cut and slip drilling line(126'). Sym Ops- Continue cleaning pits and prep to take on 9.5 ppg Brine.Laydown 5"drill pipe out of derrick using rotating mousehole. L/D 40 stds.Service rig. Grease and inspect crown,top drive,spinners,drawworks.Continue laying down all remaining 5"DS-50 drill pipe out of derrick using rotating mousehole. 108 stds(148 total stds laid down). 4/21/17-Friday Assist welder with Misc welding projects.C/O saver sub.Load shed with 4:DP.Continue cleaning pits.PU Misc Subs/handling equipment.Stage C/O BHA on rig floor.C/O#1 MP Lube Oil Electric Motor.Prep handling equipment.RU and BOP.Test to 4'and 4 1/2"pipe size to 250 4000 psi.Tested Annular, TPR,LPR,Dart TIW.R/D test equipment.Set wear bushing.MU 7"Scraper assembly with 6 1/8"Tricone Bit.TIH Picking up 4"DP to 9511'MD.Soft tag W/ 10k dn @ 9511'MD(jt#293). Drill cmt F/9511'-T/9536'MD(jt#294). 5-10 rpm,9.6k tq,180k up,120k dn,136k rot. Stage pumps up to 7.5 bpm,2000 psi.Circulate out cmt @ 9536'MD. 7.5 BPM,2000 psi. Observed good cmt back at shakers. Cleaned up prior to shutting down for casing test.B/D TDS. R/U test equipment. Test 7",26#,L-80 casing to 3700 psi.4.5 bbls pumped,4.5 bbls bled back. Pump @.6 BPM. Final psi @ 3750 w/30 min hold(test good). Chart and record same. R/D test equipment.Drill cmt F/9536'-T/9540'MD. 7.5 BPM,1750 psi,46%flow,10 rpm,9.6k tq. Hilcorp Alaska, LLC HilcorpAlaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future 4/22/17-Saturday Displace 7"casing to 9.5 ppg brine @ 9 BPM/3100 psi. Continue loading 41/2"tubing in pipe shed. Pumped total of 444 bbls brine.POOH laying down 4"DP from 9640'to 311'(BHA).Lay down Scraper BHA.Pull wear bushing.Spot and RU Pollard E-Line. L Run CBL from bottom logged interval 9529'to top logged interval 6500'MD. Logs correlated to Halliburton Dual Gamma Ray Compensated Thermal Neutron. Logs showed top of cement @ 7600'MD.Rig Service,,,Review logs.Discuss options with drilling team. Inadequate cmt above top hydrocarbon , " bearing zone as per AOGCC requirements(Kuparuk C sands). Decision made to proceed with remedial work(cut,pull and re-drill 8.5"hole section).Load and Tally 232 jts 4"drill pipe. Make arrangements for CIBP(HES). Start batching up 10.3 ppg mud and plant. Sym Ops-Install center beam in shed for 164 trolley. Continue clean pits and prep to onboard LSND mud. Install wear bushing(10"ID).Stage CIBP on rig floor. PJSM with rig crews and HES tool hand (Calvin Timothy). M/U HES 7'EZ Drill SVB. RIH singling in out of pipeshed to 2826'MD. 4/23/17-Sunday Continue RIH w/CIBP on 4"drill pipe from 2826'to 7698'MD.Up Wt 147k,Dn Wt 115K.Set CIBP 7698'as oer HES Setting nmredure,Make 15K Tag on plug.Test top of plug to 3500 psi and chart for 10 minutes.Displace casing to 10.3 ppg Mud System.Prep to TOH.TOH from 7698'to 311'.Set back HWDP. Lay down running tool.Clean and clear rig floor.Work on Kick Over Roller.Load mud into pits while W/O HES Perf Crew.Stage TCP's in shed and bring running tools to rig floor. PJSM.M/U TCP's Dressed as follows-5 SPF,60°phasing,10'guns,4-5/8"tools w/.4"holes and 39 gram charges.Firing head setup with 2000 psi annular fire and+/-6 min timed delay. disk sub(circ sub),xo,10 jts 4"HWDP. Total BHA length=303.66'MD.RIH F/303'-T/7230' MD w/4-5/8"TCP's on 4"drill pipe. Open 7"x 9-5/8"annulus and equalize psi to static. Close annulus.Put guns on depth with string in tension. 108k dn, 140k up. Break circ @ 2 BPM/250 psi. Close annular. PSI dn string @ 1 BPM to max psi of 2600 psi. Hold 30 sec and bleed off to 250 psi.Observe guns fire @ 7 min w/noted psi drop on spp from 250 to 135 psi. Stabilize spp @ 135 psi. Open annulus w/no psi. Pump @.5 BPM/260 psi. Observed slight air movement @ annulus valve.Established circulation @ 9 bbls pumped. Obtain return percentage @ annulus(75%returns). Pumped a total of 20 bbls. Bleed down psi and open annular. Slight flow.CBU @ 7230'MD. 6 BPM/695 psi w/46%flow. Monitor well(flow). Continue circulating while building wt'd pill.Pumped 53 bbls 13.3 ppg weighted pill @ 7230'MD. B/D TDS.POOH F/7230'-T/770'MD. Verify hole static @ 10 stds and 20 stds(static). 3r 4/24/17-Monday Continue to POOH f/770'to surface.PJSM.L/D fire head and gun assembly.All shots fired.Clean and clear rig floor.Lay down gun handling tools.Pull wear bushing.PU landing Jt with Pack off Run tool.BOLDS,Pull and L/D Pack off and landing jt.(7"x 9 5/8"on vac.)Stage CMT Retainer/Stinger assy on rig floor.MU HES EZ Drill CMT Retainer.Run HWDP.TIH from 310"to 5290'with cement retainer.Easy in and out of slips.CBU from 5290'@ 4 bpm/450 psi and displace heavy pill from casing.Continue to TIH to Retainer setting depth of 7190'.Circulate Bottoms up @ 4 bpm/750 psi.Set CMT Retainer @ 7190' as per HES Rep.Up Wt 130K/Dn Wt 109K.PU and shear off @ 50 K over.Un sting from retainer,work back down and set 30K down on Retainer.RU Cement line.Estab circ below retainer through perfs @ 1 bpm/540 psi with returns. Stage to 2 bpm,lost returns w/1700 psi.BK rate to 1 bpm w/1250 psi injection.1.5 bpm w/1440 psi injection.2 bpm/1440 psi.Discuss options w/drilling team.Decision made to attempt squeeze.Just before batching up cmt, pressure increase to 1850 psi @ 1/2 BPM.Discuss options.Gradually increase rate to 2 BPM w/1960 max psi and stabilize.Pump 20 bbls water to perfs and attempt to establish lower squeeze psi. Saw a 100 psi drop while injecting 20 bbl water pill into perfs.Psi increased back to 1960 psi after 18 bbls of mud pumped into perfs behind 20 bbls water. Stabilize @ 1960 psi/2 BPM.Reduce rate T/1 BPM/1700 psi while discussing options with drilling team. Pumped away a total of 208 bbls trying to establish circulation. Shut down pumping and B/D TDS.Rig Service while WOO. Batch up a 150 bbls new LSND 10.3 ppg mud(offline).Monitor well(flow @ stump/out of balance). Build 15 bbl 1.5 ppg over pill and load in drill pipe. B/D TDS.POOH w/cmt retainer running tool F/7198'-T/surface. Hole took proper displacement. B/O and laydown retainer running tool. Tool showed indications of good set on retainer.Drain stack.Set dummy 7"packoff w/no seals. Set Test plug. Fill stack with water. M/U Floor valves and R/U test equipment. / /°. 'Z ./7 • i Hilcorp Alaska, LLC Hileorp Alaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future 4/25/17-Tuesday • Test bops as per AOGCC with 4"&5"test joints. Test to 250/4000 psi.All test passed.AOGCC waived witness by Chuck Scheve.Performed accumulator draw down test.Good. Starting pressure 3000 psi After shut in 1650 200 psi Increase 18 sec Full pressure 64 sec.6 bottle avg nitrogen=2300 psi.RID testing equipment. Blow down surface equipment.Service rig and handling equipment. Clean rig&equipment.Prep 20 Joints 2 7/8 tubing.Strap&tally same. M/U landing joint.Remove 7"dummy pack off&install new pack off with seals. Test 500/5000 psi.10 min.Good. R/U 2 7/8 equipment.P/U 2 7/8 mule shoe&20 joints 2 7/8 T/633'. M/U XO&RIH on 4"Dp from derrick F/633'T/4720'.Continue TIH w/cmt stinger on 4"DP F/4720'-T/7190'MD. Hole took proper displacement for trip.Soft tag(2x's)on depth @ 7190'MD w/2k dn. P/U 2"and park with pipe in tension @ 7188'MD. 132k up,104k dn. R/U and break circulation @ 4 bpm/570 psi.PJSM w/HES and rig crew.Pump 5 bbls H20,PT lines T/3K(ok),5 bbls H20,4.5 bbls 15.8(class"G") cmt,5 bbls H2O @ 3-4 BPM.Turnover to rig. Disp w/10.3 LSND @ 3 BPM,410 ICP,342 FCP-64 bbls.CIP @ 22:00 hrs. Calc string vol=70.7 bbls.Pull out of cmt plug F/7188'-T/6985'MD. Pull @ 40 ft/min.Slight U-Tube out of stump. Drop wiper ball and circulate string clean @ 8 BPM,1000 psi,50%flow. Circulated 1.25 X's surf to surf. Saw PH inc @ btms up.No wt inc observed in returns. Dump 24 bbls mud due to PH in(12.3 max Ph). Flush stack with Blackwater.R/U to PT casing/cmt retainer. Flood lines. Psi up @ 1/4 BPM to 2075 psi w/15 min hold(ok). Chart and record same. 1.8 bbls pumped,1.8 bbls bled back. R/D equipment and blowdown same.Monitor well(static). Pump dry job. POOH F/6985'-T/633'MD. Hole took proper displacement. Monitor well on last std 4"dp(static).C/O handling equipment for 2-7/8"tbg. POOH F/633'-T/surface w/2-7/8"tbg Racking back. L/D cmt stinger assy. C/O handling equipment to 4".M/U HES 7"EZ drill CIBP as per Halliburton Tool Rep(Calvin Timothy). • • Hilcorp Alaska, LLC Hileorp Alaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future Daily Operations: 4/26/17-Wednesday RIH with Halliburton CIBP.Set on depth @ 5825'as per drilling engineer due to connection @ 5814'. up/dn 120/97K. Set in up wt.36 turns to the right. Over pull 15K&hold for 2 min.Pull to 162k&shear off running tool.P/U 5'.Rot 25 more turns to verify release. Set back down to 5825&Set down 15k over. Good.On depth.POOH&L/D Running tool.Good. Clean and clear floor.M/U Baker hydraulic casing cutter. RIH T/5713'.Slip&Cut drilling line. PJSM, Pump 1.5 BPM @ 275 psi.RIH F/5713-5717'Verifying no connection hang up.P/U to 5715&Stage up pumps to 3.1 BPM @ 600psi,80rpm.Cut casing @ 5715'. Saw pressure drop&700#TO Drop.Shut down Pump&ROT.Check annulus and 7".Static.Close annular pump down DP with annulus open.Pressure up to 470 psi.no movement in annulus.Shut down Pump pressure held @ 450 psi.Open up and bleed down. Pump @ 350 psi and set down on cutters 2K.On depth. Start rot @ 80 RPM&Stage up pumps To 800 psi @ 4 BPM. Got 400 psi pressure drop in a few min and tq dropped also. Shut down and close annular.Pressure started building to 110 psi in 7". Est 200 psi under balanced from old mud on back side. Start pump with annulus valve open and got movement in annulus @ 320 psi @.3 BPM.got returns at 2 bbl away and staged up pumps to 1 bpm @ 420 psi.100%returns.Disp 7"x 9-5/8"annulus with 10.3 LSND staging pumps up to 3 bpm w/FCP 290 psi. 10.3 MW In/Out @ btms up.Bleed down dp and csg to 0 psi. Open annular and monitor well(static). Disengage cutters from casing wall by slowly picking up w/no pump T/5713'. No overpull observed. Pulled clean @ 112k up. Continue monitor well(static). Pump dry job and blowdown TDS.POOH racking back F/5713'-T/surface. Clean and inspect cutter tool(no damage noted).Cutter showed signs of good cut. L/D same. Hole took proper displacement.Clean and clear rig floor. L/D BHI tools and put on standby until verification of good cut has been made.Drain stack. Close blind rams. PJSM,Isolate and bleed down koomey. C/O upper pipe rams to 7"fixed body. Put koomey back online and charge same. Open blind rams.R/U BOP test equipment. Test upper 7"pipe rams. 250/4000 psi w/5/5 min hold on each. Chart and record same.C/O elevators T/7"250T side doors. R/U casing equipment. Verify 0 psi on 7"x 9-5/8"annulus.BOLDS,P/U landing jt and M/U packer running/pulling tool. RIH and engage packer. Pull same.Work hanger off seat starting @ 200k. Continue working string attempting to break over (no go). Work free point(19.5"stretch w/100k pull force)Estimated 3680'MD. Max pull @ 320k(no go).Obtain new free point measurements as per BOT fishing rep. Free point measurements vary from 2075'to 3680'MD. Discuss options with drilling team. 4/27/17-Thursday Attempt to pull casing with landing joint staging wt up to 400k. Hanger starting to move @ 200K. Calculate 16"stretch from 350K to 400K free point @ 5667'.Circ while pulling with full returns @ 4 bpm 180 psi.Consult with drilling engineer and decide to change top rams back to VBR&RIH to previous cut &Re Cut @ 5715&5600.Change top Rams from 7"to VBRs.Test with 4"Test joint.250/4000 psi.Good.Set pack off for ram test.L/D landing joint and 7" casing equipment.M/U New cutter blades and RIH with baker 7"casing cutter T/5715.Locate old cut.Stage up pumps and locate old cut.Work @ 80 RPM 4 bpm with 400 psi drop from initial pressure before dropping cutters in to old cut.All signs indicate casing is cut with 6-8"of casing separation.Set up to 5K down while rotating @ 80 RPM.Work pipe up and down to verify cut.Shut down pump and rot and pull cutters up to 5600'.Make second cut @ 80 RPM staging pumps up to 4 bpm @ 800 psi&4200#TQ.Saw good 400 psi pressure drop and indication of full cut @ 25 min. Continue working wt setting down 5K while rotating.Continue cutting for another 20 min with 400 psi pressure drop and 80 RPM.All indications of full cut. Pump slug.POOH F/ 5600'T/Surface and inspect cutters.Good indication of full extended cutters.Service rig.Change top rams from VBRs to 7".Set pack off and test plug.Test rams to 250/4000 psi.Good. Chart and record same.R/D test equipment. Pull test plug. Pull 7"packoff.M/U 7"landing jt. Slowly stage pick up wt to 320k lx(no go). Slack of slowly,saw bobble on wt indicator @ 180k do stroke. Pick back up with casing free @ 162K with no overpull or break backs. Bring hanger to floor. Finish rigging up Weatherford Casing. PJSM,B/O landing jt w/xo's and L/D same. Ready xo w/TIW and stage. L/D BOT cutters and other tools. Monitor well(static).Pump 12 bbl 12.3 ppg wt'd pill.Cap wt'd pill with fresh water to flush casing for laying down operations. B/D TDS. Stage protectors on floor and ready pipeshed.Pull and L/D 7",26#,L-80,DWC/C casing from assumed cut point 5600'-T/4800'MD. Clean inspect collars for possible damage or indication of hang up(none noted).Continue pull and L/D 7",26#,L-80,DWC/C casing F/4800'-T/Surface. Clean inspect collars for possible damage or indication of hang up(none noted).Mouse hole last 14 jts and flush w/H20.137 jts w/9.2'cutoff jt=5597.17'cut depth as per tally. S • Hilcorp Alaska, LLC Hikorp Alaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future 4/28/17-Friday Clean and clear floor,RID Weatherford, Install 4"Hyd Elevators,Drain BOP Stack.Change top rams from 7"to VBRs. Test VBRs to 250/4000 psi. Install long Wear bushing.RIH with 4"HWDP, T/558'.Service rig. Grease crown.L/D HWDP.P/U 2 7/8 Cmt stinger with 23'of holes 4 per foot&Bull nose on btm.P/U 20 joints total 633'. Change handling equipment&RIH with 4"Dp F/633'T/5825'. Tag CIBP on depth.P/U T/5818'MD&R/U Circ equipment through cmt line.Circ&condition mud @ 200 GPM 430 psi while conducting cmt pre-job meeting.Pump 5 BBL H2O&Test lines to 3000 psi.Change out two failed plug valves on rig floor. Retest same. Batch mix spacer @ 12 PPG.Pump 25 bbls TSIII spacer-3.25 BPM Pump 24.5 bbls 15.8 Class"G"cmt-3.3 BPM,300 psi(batch @ 18:20 hrs) Pump 3 bbls TSII spacer-3.25 BPM Turnover to rigDispw/10.3 LSND mud. Pump4.5 BPM,105 psi(caught cmt 38 bbls into disp). Reduce rate to 4 BPM,FCP @ 350 psi for a total @ ( g @ P) displacement of 48 bbls. CIP @ 19:19. B/O and.L/D working single.POOH F/5818'-T/4970'MD. Pull @ 25 ft/min. Pulled dry first 3 stds then slightly wet for remaining 10 stds.Drop wiper ball. Circulate pipe and casing clean @ 7.5 BPM,570 psi,48%flow. Circulated a total of 1.4x surface to surface volume. Noted slight increase in PH @ btms up. B/D TDS.L/D excess 4"drill pipe out of derrick using mousehole while waiting on cement. L/D total 40 stds. Monitor well via TT(hole static).C/O handling equipment. P/U 5 stds 5"HWDP w/jars,1 std 6"NM flex DC and stand back same.C/0 handling equipment. RIH F/4965'-T/5410'MD. Wash down F/5410'-T/5440'MD @ 1 BPM,130 psi w/no tag or psi increase. Wet sample still soft.P/U T/ 5410'MD and CBU @ 10.8 BPM,1255 psi,53%flow. Saw residual cmt @ btms up w/12.8 ph,10.9 MW.Wash down F/5410'-T/5450'MD. Saw 10 psi increase washing down F/5440-T/5450'MD. Saw 3k tag w/40 psi increase @ 5450'MD. P/U TI 5410'and CBU 9 BPM,800 psi.HES,batch spacer,clear cmt line,and load water for cmt unit. 4/29/17-Saturday Circ&Condition mud while conducting cmt meeting and batching spacer. Circ @ 375 GPM 770 psi.Line up to Halliburton and pump 5 bbl fresh water. Test lines to 3000 psi. Finish batching up spacer and 34 bbl 15.8 ppg cmt. Pump 25 bbl 12 ppg Tune III spacer,34.3 bbl 15.8 PPG CMT(168 SX).Pump 3.5 12 PPG Tune III Spacer. Pump 1 bbl water from cmt unit to clear lines. f* Line up to rig and chase with 45 bbl mud. CIP @ 0843. Estimated TOC @ 5035'MD.POOH slow starting @ 10'FPM&work our speed up to 30 FPM within 100'from pulling. POOH F/5440'T/4500'.Kelly up and circ @ 375 GPM.Pump wiper ball down to clear tubing.Service rig&start changing topdrive lube pump motor. Change out TD lube pump motor. Continue circ 1 bpm not to freeze up.Pump slug&Blow down TD. POOH L/D 4"DP T/2250'MD.Rig service.Continue lk, POOH laying down 4"DP F/2250'-T/633'MD. C/O handling equipment and L/D 2-7/8"cmt stinger F/633'-T/surface. Hole proper displacement.R/U BOP test equipment. Drain stack.Pull wear bushing and set test plug w/5"test jt. Fill stack,purge air from all equip.Test all components T/250/4000 w/ 5 min hold on each.Chart and record.No failures. Start test time @ 23:00 hrs,Finish test time @ 02:30 hrs(3.5 hrs total). AOGCC waived witness by Matt Herrera.Drawdown Test Start psi-3025 Drawdown psi-1550 200 psi inc-23 secs Full charge-80 secs 6 bottle avg N2-2366 PSI.Pull test plug.Set wear bushing and RILDS. L/D test jt. R/D test equipment and B/D lines. Wear bushing ID=9-15/16".C/O saver sub on TDS to 5"DS-50. Replace 3/4"hydraulic hose on service loop. Temporarily anchor to outside of service loop.R/U 5"elevators. M/U 5"Johnny Whacker and TIH picking up 5"DS-50 T/775'MD. Tq connections 40k,Drift 2.85". 4/30/17-Sunday Continue TIH w/DS-50 5"drill pipe on Johnny Whacker F/775'-T/4715'MD. Re-position HWDP and DC's in derrick. Pull out of hole to surface racking back same.Clean and clear rig floor. Stage BHA components on floor.M/U 8.5"prod BHA#12(SSDS-Run 300). Inspect bit and stabilizers. Download MWD. M/U DC's,ported float w/HWDP. Total BHA length=461.25'. Shallow pulse test @ 212'(good)400 gpm,640 psi.TIH picking up NC-50,5"DP singles F/461'-T/4736'MD. Drift=2.8".Saw slight wt change on wt indicator. Wash down F/4736'-T/tag depth @ 5024'MD. Green cmt across shaker w/minor stringers in last 100'before tag. Tag w/3-5k WOB. 300 gpm,585 psi.Soft cmt.Control drill cmt F/5024'-T/5150'@ 60 ft/hr rop w/1-2k wob, 360 gpm,850 psi,30 rpm,8.1k tq. Inc ROP to 200 ft/hr F/5150'-T/5260'MD.Orient 160L and slide.Time drill soft cmt F/5260'-T/5270'MD.364 gpm, 870 psi,49%flow. 1k wob. 5 ft/hr. ------------\ /1- j_ S--2,0 b -3t7-C6/ • • Hilcorp Alaska, LLC Hileorp Alaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future 5/1/17-Monday Oji Continue Time drilling sliding 160L @ 7FPH F/5270'T/5280'.Increase ROP due to increased WOB&Cuttings at shakers @ 10-20 FPH F-5280'T/5298'. Drill Ahead F/5298'T/5332'40 RPM,10k TQ 2-8k WOB, 360 GPM,1020 PSI Staging ROP up to 100 FPh. Take survey showing Kick off @ 5260'.POOH ti P« on elevators F/5332'T/5174'. 20 over pull pulling off btm. Pulled clean after first 20'.Displace From 10.3 To 9.5 ppg.@ 6bpm. Monitor well.Static. Perform FIT to 12.5 ppg EMW. 768 psi. Good test. Pumped 1.5 bbl&Bled back 1 bbl. Monitor well.Static.Service rig.RIH on elevators F/5174'T/5332' MD. Drill Ahead F/5332'T/5675'=343'/77 ft/hr avg 40 RPM,10k TQ 2-8k WOB,360 GPM,1020 PSI.Drill Ahead F/5675'-T/6242'MD=567'/95 ft/hr avg ROP.80 RPM,10k TO,off,10k WOB,500 GPM,1450 PSI,200 diff.ECD's 10.8,BGG 12 units.Drill Ahead F/6242'-T/6424'MD=182'/91 ft/hr avg ROP.80 RPM,10k TQ off,10k WOB,555 GPM,1880 PSI,300 diff.ECD's 10.8,BGG 15 units.Drill Ahead F/6424'-T/6554'MD with diminished ROP due to failed liner seal-pod#3 on#1 MP. Continue drill ahead w/#2 MP @ max ROP 90 ft/hr.130'/44 ft/hr avg ROP.80 RPM,10k TQ off,10k WOB,360 GPM,1080 PSI,120 diff,ECD's 10.2,BGG 30 units.Drill Ahead F/6554'-T/6604'MD=50'/50 ft/hr avg ROP 80 RPM,10k TO off,10k WOB, 555 GPM, 1910 PSI,300 diff ECD's 10.5,BGG 30 units. 5/2/17-Tuesday Drilling ahead F/6604'T/6620'550 GPM.2100 PSI\80 RPM 10K TQ 20K WOB 10.5 ECD Pump 40 bbl HV walnut sweep @ Diminished capacity due to Liner gaskets leaking again on MP @1 Pod#3.Circ with pump#1 @ 360 GPM 80 RPM, 950 PSI.Circ clean @ 1.7 STS. Sweep Brought back 100%.Monitor Well.Static POOH F/6620'T/5174'on Elevators. Had Over pulls on swelling clays @ 6255',6100',5655', Pulled 15-25 Over.Work back down with no drag&Pulled through slow with out issue.Circ&Condition to clear BHA of clays. Hole unloaded clay balls 800 stk before btm up&Through out.Circ 2 BU.Slip&Cut Drilling line,Service rig while bringing MW in the pits up from 9.5 to 10.3.Continue bringing MW in the pits from 9.5 to 10.3.RIH on elevators clean F/5174'T/6620'.Wash down last stand.Correct displacement for the trip. No fill.Displace to 10.3 @ 500 GPM,50 RPM.Take SPR.Monitor well.Static.Drilling ahead F/6620'T/6682'Slide drilling Building from 16 Deg to 21 Deg. 500 GPM,1955 PSI 80 RPM 11.5K TQ 20K WOB 10.6 ECD.Drill 8 1/2"hole F/6682'T/7122'(440')AROP 73.3 FPH(119 FPH on btm) GPM 500,1900 PSI WOB 10-20k,80 RPM TQ 12k MW 10.3/45 Vis,11.1 ECD PU/SO/ROT 226/147/172.Pump 30 bbl hi vis sweep @ 6882'sweep back on time w/200% increase,mostly sand w/balls of clay and shale.Note:maintain 21 deg inc with minimal slides thru HRZ.Drill 8 1/2"hole F/7122'T/7468'(346')AROP 57.6 FPH(82.6 FPH on btm) GPM 500,1950 PSI WOB 10-20k,80 RPM TQ 12k MW 10.3/45 Vis,11.1 ECD PU/SO/ROT 239/150/179.Pump 30 bbl hi vis sweep @ 7253'sweep 90 stks late w/200%increase,mostly sand w/2-3"balls of clay and some shale reducing ECD f/11.3 to 11.Note:start turn @ 7312' f/222 deg to 262 deg w/40'slides per std for 350'Currently 1.98'below the line,9.97'right,2.25 slide hrs,8.43 rotate hrs. • • Hilcorp Alaska, LLC HilcorpAlaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future Daily Operations: 5/3/17-Wednesday Drill 8 1/2"hole 1/7468'T/7878'(410')AROP 68 FPH(125 FPH on btm) GPM 500,1950 PSI WOB 10-15k,80 RPM TQ 15k MW 10.3/45 Vis,11 ECD PU/SO/ROT 245/150/179;Started getting a few 1 1/2 shale splinters on the shakers.Start to bring MW to 10.4 Pumped sweep @ 7830'.Came back with 100%Increase in cuttings. Pumping lube sweeps before slides to aid in slip;Drill 8 1/2"hole F/7878'T/8257'(379')AROP 63 FPH(125FPH on btm) GPM 500,1950 PSI WOB 10-15k,80 RPM TQ 15k MW 10.3/45 Vis,11.1 ECD PU/SO/ROT 250/152/182;Begin bringing Lubes up to 2%by volume&Black product to 8 ppb for Kingak.;Drill 8 1/2"hole F/8257'T/8633'(376')AROP 63 FPH(91 FPH on btm) GPM 500,2300 PSI WOB 10-15k,80 RPM TQ 15k MW 10.4/45 Vis,11.4 ECD PU/SO/ROT 280/158/195;Pump 30 bbl hi vis sweep @ 8385',sweep back 180 stks early,200%inc mostly sand,some small clay balls w/min shale, Slide per direction prior to kingak shale,maintain hole inc due to rotary drop.;Drill 8 1/2"hole F/8633'T/8947'(314')AROP 52 FPH(78 FPH on btm) GPM 500,2500 PSI WOB 10-15k,80 RPM TQ 16k MW 10.4/46 Vis,11.4 ECD PU/SO/ROT 291/161/197;Pump 30 bbl hi vis sweep @ 8640',sweep back 180 stks early,100%increase mostly clay and sand.Note:10k overpull @ 8811',backream and cleanup same.;Currently 11.02'above the line,3.94'right.4.52 slide hrs,12.69 rotate hrs. 5/4/17 Thursday Drill 8 1/2"hole F/ 8947' T/9450(503')AROP 83 FPH(115 FPH on btm) GPM 450,2350 PSI WOB 17k,80 RPM TQ 18k MW 10.4/46 Vis,11.3 ECD PU/SO/ROT 288/163/204;Drill 8 1/2"hole F/ 9450'T/9620 @ TD (170')AROP 56 FPH(90 FPH on btm) GPM 450,2300 PSI WOB 18k,80 RPM TQ 18k MW 10.4/46 Vis,11.2 ECD PU/SO/ROT 288/163/204;81.02'above the line and 22.78'right;Circ&Condition btm up @ 450 GPM with sweep.Came clean at btm up.Sweep brought back minimal cuttings. Bring pumps up to 500 gpm,ECDs @ 11 PPG.Dropping YP from 28 to below 20.;Lower pump rate to 250 gpm,750 psi,weight up pits F/10.3+to 10.8 ppg, rotate 60 rpm,work pipe up slowly.Continue to lower YP f/24 to 20. Displace wellbore and treat until a good 9.8 ppg in/out;Note:L/D 5 singles while working pipe up slowly;Pull 2 stds on elevators f/9490'to 9380',pulling clean,RIH with single and 4 stands f/derrick washing last std to bttm @ 9620' PU/SO 300/165,obtain SPR#1&2 MP;Mix 80 bbl 10.8 ppg liner running pill w/4%lube,12 ppb black product and 20 ppb graphite,pump and spot pill f/ 9620'to 7910'(8539'without drill pipe in hole)placing @ top of kingak.;Monitor and Flowcheck well 5 min,static,POOH on elevators 500 fph f/9620' rack back 3 stds,blow down top drive,continue POOH on elevators 500 fph f/9447'to 8383';20-25k overpulls @ 9081',8758',8634'. - 5/5/17-Friday POOH on elevators 500 fph 1/8383'T/7780'. Lost high line power. Put rig on Gen Power. Power on in 5 min and pulling pipe in 9 min. Great job by rig crews.;POOH F/7780'T/7540'.Over pulls through all slides 20-40k Work back down and pull through good.Not sticky. Pull Tight @ 7796',7718',7703',7529',7525',;Pulling tight @ 7525'Unable to work past. Stage up pumps to 250 GPM&Orientate to 90 Right for slide.still unable to pull through.Not packing off or pressuring up. Back ream F/7540'T/7240'.;@ 300 GPM,1000 PSI, 60 RPM TQ 13K-15K. Attempt to pull several times with out reaming or pumping.Unable to pull without reaming. Only getting sand over the shakers.;Pull on elevators F/7240'T/5628'on elevators clean. Hole taking the correct fill.;Pull on elevators F/5628'T/5615'with 25k overpull,M/U top drive,pump out 126 gpm,400 psi F/5615'to 5605', continue Pulling on elevators to 5271'w/5 k over pull;upper stab hanging up on 9 5/8"shoe,M/U top drive,rotate 5-10 rpm working past easily,pull above shoe @ 5200';M/U top drive,establish circulation,pump 40 bbl hi vis sweep 250 gpm,800 psi,rotate 30 rpm.50%increase @ sweep returns,flow check well 15 min,static,pump dry job,BD top drive.;Note:use lower circulating rate to maintain ECD @ 11.4;P1SM,POOH L/D 5"DP F/5200'to 461'@ HWDP(82 jts DS50 DP and 70 jts NC50 DP) Note:correct fluid displacement on trip out;L/D BHA 12,9 jts HWDP and jars,2 NMDCS,float sub,download MWD data,L/D remaining MWD tools,stab, drain mud motor, L/D motor and bit.Grade=0/1/CT/S/X/1/NO/TD Stabilizer in gauge. • Hilcorp Alaska, LLC 11ilcorpAlaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future 5/6/17-Saturday Finish L/D BHA,clear and clean rig floor,load outtools f/pipe shed.,R/U and pull 9 15/16"ID wear bushing.Close blind ram,remove upper 2 7/8"x 5 1/2" VBR,install 7"casing rams,open blind ram.,R/U test equipment w/7"test jt,fill stack and lines w/water.test 7"casing rams to 250 psi low,4000 psi hi 5 min ea.chat test.,R/U to run 7"casing,R/U Doyon casing equipment.Ready pipe shed for running casing.,PJSM with all personnel for running casing. Discuss primary and secondary muster locations,stop job authority,well control procedures and assignments. Doyon casing crew new to this rig,conduct rig orientaioneP/U and run 7"26#TSH 536,L-80 casing per tally,backerloc and M/U shoe track assembly w/ 11 centralizer 10'f/ea.end on shoe jt,1 mid tube on 2 FC jts 1 mid tube on BA jt, ensure float operation.Tq connections to 9000 ft/lbs, Use jet lube seal gaurd pipe dope,utilize dog collar clamp on 1st 10 jts ran,use stabbing guide,fill casing on the fly,install 1 cenralizer on every jt on 72 jts. Lg� RIH to 1991'(48 jts),M/U Cement tool with pup jt above and below per hailiburton rep,continue RIH to 3750'(90 jts ran),Continue RIH w/7"casing f/ GG 3750 to 4995'(120 jts ran) conduct valve drill,well secure in 54 sec. Correct displacement,R/U head pin and hose,break circulation,stage pump slowly to 3 bpm,250 psi.PJSM for R/U Volant CRT,remove elevators and short bails,load volant tool to rig floor in cradle,M/U top drive to volant,tq to 35k.remove cradle.R/U cables to CRT. install 14'bails and extensions,R/U elevators. Note:pump 1 full circulation while R/U,Continue RIH w/7"casing f/4995'to 5203'just above 9 5/8"shoe(jt 125).Get parameters before exiting shoe. 10/20/30=rpm 6.7k/8k/8.5k TQ.Pumping 1/2/3/4/BPM=250/290/325/350/390 psi PU/s0/ROT 150/113/130,Continue RIH w/7"casing f/5203'to 6605'@ 200'+- above HRZ(jt 159) Note:fill on the fly,Stage pump up slowly in.5 bpm increments f/1 bpm,430 psi,2 bpm,460 psi,3 bpm,500 psi to 4 bpm,540 psi,reciprocate pipe slow, continue @ 3 bpm 340 psi.@ BU,80u gas PU/SO 179/121,Continue RIH w/7"casing f/6605'to 7475'(jt 180)continue to fill on the fly. 2.4 bbl under calculated displacement.,CBU,Stage pump up slowly in.5 bpm increments f/1 bpm 570 psi,2 bpm,650 psi,3 bpm,600 psi,152u gas @ BU PU/SO 200/134. 5/7/17-Sunday Continue RIH w/7"casing f/7475'to 8050'.Continue to fill on the fly. Started taking wt down.,Attempt to break circ staging pumps up to 650 psi. Work pipe getting slight movement on annulus. No circulation. Getting displacement working pipe down and when try to circ we loose displacement. Decide to run a few more joints to break pack off free.up/dn 300/125,Continue RIH w/7"casing f/8050'to 8378'.Continue to fill on the fly. Going in the hole good with correct displacement.,Attempt to break circ staging pumps up to 850 psi. Work pipe 60' getting slight movement on annulus. No circulation. Work pipe up and Down with 40-60 RPM stalling out @ 18000 if you stop moving pipe. Work pipe at several pressures attempting to get circ. Continue to work pipe getting slight movements on while pulling pipe.18K TQ Limit. Decide to run a few more joints to break pack off free.,Continue RIH w/7"casing f/8378'to 9580'.Continue to fill on the fly. 15-20 K bobbles&with correct displacement.,Attempt to break circ staging pumps up to 350-1000 psi Working pipe 60'. Start pushing fluid away @ 1000 ps No circulation. Work pipe up and Down with 40 RPM stalling out if you stop moving pipe. Work pipe at several pressures 350-1000 psi attempting to get circ. Pushing fluid away.,Get a little flow on the up stroke and loose it after stopping or going down.Note:@ 16:00 hrs power tongs failed while breaking out high torque connections,cam followers on rotating assembly broke,R/U backup tongs.,Pump out of hole f/9580'to 9345' pumping 1-2 bpm due to swabbing, rotating 10-20 rpm,18.5k tq.to keep pipe free,pulling up to 350k,unable to pull unless rotating pipe,(taking up to 28k-30k tq to break out with power tongs)Continue to pump out without rotating string f/9345'to 7479',attempt to circulate several times w/little returns,able to circ @ 7479'rotating 10 rpm.,Note:1st 8 jts pulled-power tongs damaged pin end,crushing pipe.use volant tool to break jts,30k TQ and hitting on collar w/2 sledge hammers to warmup before jts will backout.release volant tool and backout remaining threads w/power tongs on each jt.,Set pump pressure limit @ 1300 psi, Circulate 1/2 bpm,1050 psi @ 75%returns rotating 10 rpm working pipe slowly,16.4k TO,stage pump to 3 bpm,1200 psi, 100 bbls pumped see 100% increase in sand at shakers w/10.8 ppg in/11.4 ppg out.140 bbl pumped pressure decreased to 1050 psi.300%increase in sand @ shakers w/11.9 ppg out,260 bbls pumped 600 psi,11.5 ppg out.(max gas 235u @ BU)PU/SO/ROT 230/130/147,Continue to circulate increasing rate to 4 bpm,330 psi conditioning mud until 10.8 ppg in/out adding water 30 bph. Note:15 bbl losses to formation while circulating hole clean. • S Hilcorp Alaska, LLC HileorpAlaska,ilJ.0 Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future 5/8/17-Monday Circ and condition mud staging pumps up to 5 bpm @ 430 psi. Circ 3 Btm up total.,Wash and ream 7"casing F/ 7410'T/8360'. 5 BPM @ 450 psi, 10 RPM&16K TQ. Circulating monitoring losses and pump pressure. Not loosing fluid. Set down @ 8370'.,Wash and ream 7"casing F/ 8360'T/9105'w/pressure increase to 645 psi @ jt 220 5 BPM @ 540 psi, 5 RPM&17.5K TO. Circulating monitoring losses and pump pressure.,Wash and ream working pipe f/9105'to 9120'taking small bites until circulating pressure @ 500 psi,CBU working and rotaing pipe.,Wash and ream 7"casing F/ 9120'T/9284'w/450 psi pressure increase,(jt 224)5 BPM @ 500 psi, 5 RPM&18K TO. Circulating monitoring losses and pump pressure.,Wash and ream working casing f/9284'to 9260' until circulating pressure @ 500 psi. Note:75%increse in cuttings @ shaker,mostly 1/2"pieces of shale.,Wash and ream 7"casing F/ 9284'TI 9320'w/500 psi pressure increase, 5 BPM @ 500 psi, 5 RPM&18K TO. Circulating monitoring losses and pump pressure.,Wash and ream working casing f/9320'to 9300' until circulating pressure @ 500 psi,Wash and ream 7"casing F/ 9320'T/9376'w/20k set down 5 BPM @ 500 psi, 5 RPM&18K TQ. Circulating monitoring losses and pump pressure.,Wash and ream casing working tight hole f/9376'to 9400'Note: 60 bbl losses while washing/reaming and circulating F/7400'T/9400'. 5/9/17-Tuesday Continue to wash and ream 7'casing from 9400'to 9620v(TD1.10 RPM/22K Tq/PU 255K/SO 194K.Observe 735 u Max Gas.,CBU from 9620'@ 5 BPM/450 PSI,Rotate/Reciprocate 50',Lay down Tag Jt to 9590'.Blow down TD,RIH with 9.62'&14.33'Csg Pup Jts to 9607'.MU CMT Line.,Continue circulate @ 5 BPM/550 PSI,while holding PJSM for Cement Job.,PT Cement Lines to 4000 psi.Continue to circulate and work pipe while batch mixing cement.,Pump Cement as Folows:Pump 30 bbls 12 ppg tunned spacer Load&Drop By Pass plug.Mix and pump 165 sxs(49.3 bbls)Premium Class G Cement at 15.3 ppg. Load&Drop Shut Off Plug.,Displace cmt w/20 bbls FW f/Cmt Unit Rig Pump 41.7 bbls Mud Rig Follow with 20 bbls FW Rig Follow with 281.6 bbls Mud s.t1 Total Displacement @ 363.3 bbls,Details:Lost 10 bbls while pumping displacement.Pump Cement @ 4.5 BPM Average. Pump Disp @ 4.5 BPM Average. . Calculated Disp 363.3 bbl,Actual Disp 364 bbl. FCP 640 psi @ 2 BPM,Bump Plug 500 psi over FCP(1150 psi)Floats held. CIP @ 19:10 Using rig pump, stage pressure up 3400 psi and shear open ES Cementer,Circulate bottoms up from ES Cementer @ 7600"bringing 34 bbls 11 ppg contaminated spacer to surface.6 bpm/650 psi.No losses on circulation.,Pump 20 bbl hi vis sweep around 6 bpm,650 psi,sweep back(600 stks early 37.2 bbls)Pump 2nd sweep around,sweep strung out,back 650-800 stks early,continue to Circulae thru ESC @ 7600'while W/O 1st stage(8 hrs)to reach compressive strength.,PJSM f/pumping 2nd stage cement job.,Pump 2nd stage Cement As Follows: Mix&pump 30 bbl 12.0 ppg Spacer Mix and pump 119 sxs(28.9 bbls)Premium Class G Cement at 14.7 ppg. Load&Drop Closing Plug.,Displace cmt w/20 bbls FW f/Cmt Unit Rig Pump 271.6,10.7 ppg mud Total Displacement @ 291.6 bbls Bump Plug @ 3 bpm,700 psi FCP Pressure up to 1700 psi&close ESCMTR.Hold 2078 psi,Bleed back 1.5 bbls.,Pumped k� 50% Excess CMT,No Cement or Spacer to surface. Calculated Displacement=291.6 bbls,Actual=291.6 bbls Lost 2.5 bbls before displacement.No losses during displacement. CIP @ 06:00 hrs. • • Hilcorp Alaska, LLC HilcorpAlaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future Daily Operations: 5/10/17-Wednesday 2nd Stage CIP @ 06:00.Monitor annulus to trip tank for 1 hour with no flow.Drain Stack and continue to monitor annulus @ cellar while rigging down CRT ,CMT Line,pull mouse hole,R/D catch can,turn buckles and flow riser.N/D choke and Kill Lines.Lift Stack&Tubing head,set casing slips with 140K on slips.Rough cut casing,Set back BOP Stack.Make and dress final cut on stub.Land Pack off.C/0 bails on TD.Load 4"HWDP into shed.Offload and begin cleaning pits.Land and NU BOP/Tubing Head.Test Pack Off to 500 low/4300 psi High. Change out 7"casing rams and install 2-7/8"x 5"VBRs.Change IBOP actuator on TD.C/O Saver sub from 5"to 4".Finish N/U BOPE and installing saver sub with 4"bell guide,clean in pit 4.PJSM,R/U and L/D 5" stands of drill pipe from derrick using rotating mouse hole,140 jts total,pull shaker screens,cleanup possum belly,continue cleaning in pit 4,open and cleanout both centrifuges.Clear and clean rig floor,C/O elevator inserts to 4",PJSM,slip and cut drilling line. 5/11/17-Thursday PJSM.Slip and cut 100'drill line.Inspect wire line Anchor,Dead man clamp and brass.Unhang and calibrate blocks.Pull Wear bushing,RU Test Equipment. Flood Stack and Choke manifold.Test BOPE to 4"&4.5"Pipe size to 250/4000 psi.Test gas alarms.Test witnessed by Adam Earl of AOGCC.No issues on test.Rig down test equipment.Blow down surface equipment.Install 10"ID Wear Bushing,PJSM on PU BHA.Drift and P/U clean out assembly BHA with 10 jts HWDP and 6.125"Tri Cone Bit to 308.62,Drift and Single in with 4"HT38 Drill pipe from pipe shed to 6606' Fill pipe every 2500',Continue to single in with 4"Drill pipe from 6606'to 7454',fill pipe,Pump 2 bpm 480 psi,wash from 7454'to 7590'tagging cement stringers.(232 jts) PU/SO/ROT 147/106/122,Drill cement f/7590'to top of ESC @ 7600'on depth,pumping 3 bpm,500 psi,30-60 rpm,2-10k wob,6.5k tq,drill ESC.Ream and cleanup same,pass thru easily with pump and rotary off. Note:see cement and plug rubber @ BU,Blow down top drive,continue to single in from 7610'to 8900'. 5/12/17-Friday Cotinue to TIH picking up 4"DP from 8120'to 9400'.PU 188K/SO 115K/Rot 145K,Wash down from 9400'@ 2 bpm 340 psi.Tag cement @ 9427',Drill hard e ent from 9427'to baffle adaptor @ 9472'.Drill baffle adaptor and hard cement from 9472'to 9515',w/5-12 WOB,5-7 bpm/520/1350 psi,30-40 f.\rpm/8-9K Tq.Pass through Baffle Adapter no pump/rotation with no issues.Displace well from 10.8 ppg mud to 9.5 ppg brine @ 10 bpm/3230 psi.Blow down Top Drive.Rig up on stump to test 7"Casing.Test 7"casing on chart for 30 minutes to 3700 psi with good test.Rig down casing test equipment. Blow down choke and kill lines.Prep to POOH racking back 4"DP.TOH from 9515'to 300'racking back 4"DP.Lay down 10 jts HWDP,Bit Sub and bit.Spot and RU Pollard E-Line. Run CBL from bottom logged interval 9515'to top logged interval 5900'MD. Logs correlated to Halliburton Dual Gamma Ray Compensated Thermal Neutron. Logs showed top of 1st stage cement @ 8720'MD. V 1'04 16(y, . onsult with town,decision made to determine Top of cement for 2nd stage after running pressure passes. S'/ �� Note:TIH w/DP to 2000'in preparation while W/O log interpretation,POOH with 4"drill pipe from 2000'racking stands in derrick.PJSM,R/U LRS,test lines to 2000 psi,Freeze protect 7"X 9 5/8"annulus with 60 bbls diesel to 2100',ICP 1 bpm,140 psi,FCP 1 bpm,1040 psi.R/D LRS.Service rig,crown, draworks,spinners and top drive.R/U for shooting flange,pull drip pan,L/D mouse hole. LID down riser and pitcher nipple,round up bolts for shooting flange. Flush lines in pits with fresh water.Locate shooting flange,W/O shooting flange XO to arrive. 5/13/17-Saturday W/O XO for shooting flange.Rig service,inspect top drive.Continue to W/O XO to arrive.Replace elevator hydraulic hoses.Modify guard on top drive and re-install same.Continue to clean around rig.N/U shooting flange.R/U E-line w/CBL tools.RIH w/E-line to 7600',apply 500 psi to 7"casing, make pressure pass f/7600'to 6500',RIH to 7600',apply 800 psi to casing,log up to 6500',RIH to 9500',apply 1000 psi on casing,log up to 5900',POOH with logging tools. < �1 C , Read logs,decision made to run Ultrasonic log tools. 2. S 11) Note:monitor 9 5/8"x 7"annulus,740 psi,L/D CBL tools, While W/0 ultrasonic log tools to arrive,R/D shooting flange, P/U HES CAST-M ultrasonic log tools.RIH with logging tools to 9500',log from 9500'to 4900',TOC on first stage @ 8600',2nd stage,TOC @ 6050',POOH,L/D logging tools.R/D E-line. R/U pitcher nipple,riser and flowline,W/6.125"C/O bit and bit sub M/U,RIH w/146 stds of 4"drill pipe to 9158' Correct displacement on trip in the hole,POOH L/D 4"HT38 drill pipe to pipe shed from 9158'to 4787'. S Hilcorp Alaska, LLC HilcorpAlaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPB-30 Innovation 50-029-23571-00-00 216-153 4/2/2017 Future 5/14/17-Sunday Continue to L/D 4"Drill pipe from 4756'to surface. L/D Bit and Bit sub.Pull Wear Bushing,Clean and clear rig floor. Prep to run completion.Lay down Misc handling tools.Stage and prep completion equipment on floor.RU Tec Iwire spooler.Hang Sheave.RU WOT Power tongs.MU Safety Valve.Count and stage cannon clamps on floor.Confirm pipe count to tally.PJSM on running completion.MU completion jewelry:41/2"WLEG,Tbg 1T,4-1/2"XN(3.725" No-Go)(w/RHC Plug Body),Tbg JT, 7"x 4.5"Baker Premier Packer,Tubing Pup Jt w/RA MARKER,Tbg it, Down hole Pressure Gauge w/'4"TEC wire,Tbg JT, Sliding Sleeve,Continue Run 4-1/2"12.6#L-80 1Cr Vam Top(Range 3)Tubing from 225'to 4282'(102 jts),Continue Run 4-1/2"12.6#L-80 1Cr Vam Top(Range 3)Tubing from 4282'to 9322',M/U 10'pup,M/U last jt#225 to 9373.74',M/U pup jt and tbg hanger. 11"x 4 1/2"Hanger-Top thread 41/2"TCII,Bottom thread 4 1/2"TCII PU/SO 157/107,Haliburton terminate TEC wire to hanger,meg test same,Drain stack,M/U XO and landing jt.Land hanger 22.92'in,w/tbg tail @ 9399.93', RILDS per wellhead rep.R/U circulating lines to pump diesel down annulus and take returns out tbg and set packer.PJSM with LRS,Baker rep,rig crews. LRS test lines 5000 psi,pump 75 bbls 80 deg diesel down annulus 2 bpm,500 psi,take returns out tbg back to pits.open and let tbg x annulus communicate.Let diesel U-tube up tubing for 1 hr. 5/15/17-Monday Continue to U-Tube DSL IA to Tubing.Drop ball and rod and wait 30 minutes for seat. LRS PT lines to 5000 psi.Using LRS,set packer as per BOT Rep procedure.Final hold pressure on PKR @ 4800 psi."Walk pressure to 5000 psi.Attempt to achieve tubing test with slow bleed off. Attempt 2nd time and observed OA Pack off Gland Nut leaking. Bleed tubing and OA(390 psi)to zero and leave IA and OA open to atmosphere.C/O Lock pin/Gland nut assembly. Attempt tubing test with same results. Line up LRS on IA PT IA to 3750 psi,monitoring tubing.Obtain good 30 min.test of IA on Chart.LRS line up on tubing and attempt tubing test again with slight leak off,but slower than previous attempts. Isolate and remove LRS from tubing. RU test pump directly on landing joint.PT tubing to 5100 psi for 30 minutes.Lost 50 psi before flat line at 5100 psi.R/D all test equipment.Blow down all surface lines.Using vac truck suck DSL from stack and lines.Back out and L/D Landing it.Clear rig floor of Misc XO's and subs.Set BPV,Bleed Dn Koomey.Pull Bell Nipple.R/D Choke and Kill lines.N/D stack,set back and secure.C/O elevator inserts.Start Saver Sub C/O to 4 1/2"DS-50.Assist w/termination of I wire.MT Mud Pits, flush lines w/FW.Assist welder with cutting flow line @ interconnect.Prep Tree for Install.N/U adaptor flange and dry hole tree,make final TEC wire checks.Test hanger void per wellhead rep to 500 psi low for 5 min,5000 psi hi for 10 min.Lay herculite and mats on C-46„Pull BPV,install TWC,fill tree with diesel,R/U and test tree to 500 psi low for 5 min,5000 psi hi for 10 min.Pull TWC,install BPV,Secure cellar,C/O saver sub,prep to scope down derrick,Hang blocks,slip and cut 50'drilling line.Bridal up,pressure wash derrick.Disassemble mud pumps,continue to flush and clean pits.Scope down derrick,blow down steam and water throughout rig,disconnect steam,air and water lines.Trucks to arrive @ 08:00. Rig released @ 06:00. 5/16/17-Tuesday No Operations to Report.Rig Move to MPC-46. i Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP B-30 Coil 50-029-23571-00-00 216-153 5/26/17 5/29/17 Daily Operations: 5/24/2017-Wednesday No activity to report. 5/25/2017-Thursday No activity to report. 5/26/2017- Friday PT hardline and test PRVs to 3,000psi Start ticket Ml/PJSM/RU/PT PRV#1 sett to 3,000psi PRV#2 Set to 3,000psi 5/27/2017-Saturday LRS Hold IA pressure at 2,000psi during Frac Pumped 2 bbls diesel to pressure up and an add'l 1 bbl to maintain pressure during frac. SLB pumping ( Frac crew)B-30 aver test pressure 3,315psi Max Treat pressure 6,662psi Min Treat Pressure 1,012psi,Average Inj rate 29.1bbls/min, Max inj rate 30.4 bbl/min, MPU Well support R/D all tanks hardline equipment. 5/28/2017-Sunday SLB CTU #8- Pull on B-Pad. Raise mast and test BOPE on CT back deck as per state requirement. Start BOPE test - perform draw down test,test all rams to 250/3500psi. MIRU LRS test seperator#2 with Sand Hog for solids control. End BOP Test on CTU. Continue flowback RU. Stage up CTU on B-30. Raise mast. PU injector, lubricator, BOPE. MU clean out BHA. Keep injector stood back on deck. CT SDFN.Complete flowback rig up. 5/29/2017- Monday CTU crew and LRS Well testers on site. PJSM. Walk lines and inspect RU. Flowback line rigged up from wing valve to well test unit with a "sand catcher" in line before the unit. Return lines to tanks.Also,tied into B-23 to produce well after cleanup. Oil State Tree Saver guy left location job completed. Stab on well with injector and BOPE. Open SSV and Install fusible cap. Fluid pack out to Choke on Well test unit. PT low-300psi/ High 3,750psi. BD to 2,000psi and Open Well.T/I/O = 843psi/ 1,584psi/Opsi. RIH not pumping with BHA#1- 1.75" OD CTC, 2" OD DBPV, 2 x Wt Bars, 2" OD JSN. OAL=9.7'. Take returns to tanks maintaining—750psi WHP. Initial tag at 2,660' ctmd. PU clean and RBIH and pass tag depth. 2nd tag at 2,800'. Start cleanout from 2800' - 1.4 bpm/3780psi CTP/770psi WHP using Slick water with Safelube. Bleed annulus down to 150psi and bleed throughout job as needed. Clean out 4-1/2" tubing taking 500' bites followed by short trip. Pump 5 bbl gel pill after every 30 bbls water pumped. RIH speed at 60 fpm, Maintain 700-750psi WHP. Dump sand hog of proppant every 300- 500' of tubing cleaned out. Maintaining 1:1 returns. Clean out 7' casing from TT to PBTD in 40' bites. Tagged hard at top of perfs at 9,449' ctmd. Had to PU and RBIH, increase pump rate to work through perfs. Tough jetting down to 9479' ctmd. Broke thru and cleaned out to 9517'. Short trip to TT. RBIH and able to jet down to PBTD found at 9,532' ctmd. Hard bottom. Pump 44 bbl gel sweep with short trip and back to bottom. Park on bottom for all gel out nozzle. POOH chasing returns. Reduced WHP to—350psi.Tag up at surface. SD pumping. Close swab 23-1/2 turns. Continue flowing well via seperator to tanks, monitoring returns. WHP at 10-20psi. Flow rate at 300-500 bpd all frac fluid. Large amount of proppant in tank from cleanout. Divert flow through vessel in well test unit monitoring rates. Still flowing at 300- 500 bpd.All frac fluid Continue to flowback frac. Current well rates at 19:00= 1800-1900 bpd /78%WC/222,000 scf gas/ 117psi WHP 5/30/2017-Tuesday No activity to report. • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP B-30 ASR 50-029-23571-00-00 216-153 6/13/17 6/18/17 Daily Operations: ' 6/7/2017-Wednesday No activity to report. 6/8/2017 -Thursday No activity to report. 6/9/2017 - Friday No activity to report. 6/10/2017-Saturday No activity to report. 6/11/2017 -Sunday No activity to report. 6/12/2017- Monday No activity to report. 6/13/2017-Tuesday Continue to move rig from L-36 to B-30. Mobilize pit system to Bravo pad. Roads and pads on B-pad to set rig floor into position on well house. Pits arrive on B-pad and backed into place. Set Catwalk into position followed by Tool pushes trailer. Begin hooking up choke/kill lines, hydraulic lines for BOPE's. Roads and pads deliver 150bbls of fresh water to location. Crews mix system to 2% KCI in pit trailer. Continue to R/U on well B-30. Hook up hydraulic lines, Electrician Sean Logan on location to R/U and test fire and gas alarms. Raise mast on carrier into position. Greg Ruge and John Morrow on location to pull BPV and set TWC. Verify IA is dead, prior to pulling BPV. R/U to test BOPE w/2-7/8" and 4-1/2" test joints as per ASR BOPE test procedure.Test BOPE to 250psi low,4000psi high f/5 charted minutes each.Test annular to 250psi low, 2,500psi high w/2-7/8" test joint f/5 charted mins each. AOGCC test witness was waved by Brian Bixby on 6/12/17 @ 4:15am.Thermal indications LLC. on Location Fabricating and Patching Wind wall back of Derrick,. Well head Rep John Morrow Tee Bar TWC Valve, While Pulling TWC with Tee Bar Pressure was encountered under Valve Spraying 8.4 ppg Sea Water out on the Containment on about a 60x40 sq./ft. and about 8x8 sq./ft. on the gravel pad Estimated about .5 Gallon Sprayed on the Gravel, Containment was wiped down, Gravel dirt was put in metal bin and Hauled to G-I Plant, Milne point Security and Rod Murray was called. Changed out Elevators to 4.5 Picked up made up 4.5 Landing Joint Make up in Hanger open I-A Valve psi-0 Pulled Hanger unset Hanger at 120k Max Pull 160k Worked Hanger 6-8 Times unable to make Ground, Landed hanger, back out Landing Joint and Lay down, Nipple down Spacer Spools, Rig up casing Jacks on top Annular. Function Test Casing Jacks Check for Clearance of Tong Rack. Pulled 160k with the Rig, Changed over to Casing Jacks Max pull 185k Packer Element Broke Free, Free Pull at 130k. Landed Hanger Break out and Lay down Landing Joint, Rig down Casing Jacks ASRC Crane operator Hoisted CSG Jacks off Rig Floor, Hoisted Spacer Spools to the Rig Floor, Nipple up Spools, Pick up landing Joint make up in Hanger,. Pick up landing Joint make up in Hanger, Pull Tubing Hanger Rig Floor at 130k Break and lay down Hanger and Landing Joint, Peak Truck has been Dispatched to Bring 290 bbl. 2% Brine to Location. R/U Circulating Hose,Total pit Volume 147bb1. Circulate Down Tubing at 3 bpm at Psi=200 Got Returns to the Pits with 57 bbl. Pumped,Total Pit Volume 90 bbl. Pumping at 3 bpm at 300 psi, Pumping 2bpm at 200psi Holding bbl. • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP B-30 ASR 50-029-23571-00-00 216-153 6/13/17 6/17/17 Daily Operations< 0.414 =4x+ 6/14/2017 -Wednesday Continue to circulate out gas cut brine. Circulate a total of 544bb1s varying flow rate between 2-3BPM. Loss rate between 3- 5bbl/hr circulating @ 3BPM = 175psi. Shut down and allow any residual flow to bleed off. Monitor well to ensure no gas is breaking out. PEAK trucking on location. Offload 250bbls of 8.4ppg 2% KCI into pits and remaining 40bbls into 400bbl upright. Position man li' into place to remove rear paneling on derrick to access the rear of the carriage. Assess the hydraulic fittings on the rear of the carriage in order to ensure they are all clear of the hydraulic service loop movement. Remove bent 90deg fitting and rotate any fittings that could cause a snag. PEAK vac truck discharged 5 gallons of brine onto gravel during fluid transfer. Rob Murray on location to assess. POOH w/4.5" 12.644 Vam Top TBG 1/"9,400'md to "8,800'md. Remove cross collar cable clamps and spool TEC line. Line up to reverse circulate and assess loss rate. Reverse circulate @ 3BPM =400psi on the IA, 151psi on the TBG w/ no recorded losses.Verify no flow, open annular and blow down fluid system. Continue to POOH w/4.5" TBG f/—8,800'md to ^'4,400'md. Remove cross collar cable clamps and spool TEC line. Service Rig Check Fluids and Grease. Continue to POOH w/4.5"TBG f/4,400'. to Surface. Remove cross collar cable clamps and spool TEC line.Total Joints Recovered 225 & 195 Collar Clamps. Change over Handling Equipment From 4.5 to 3.5, Clear and Clean Rig Floor, Load and Talley 320 joints of 3.5 RTS-8 Work String on Racks.TIH w/mule Shoe on 3.5 RTS-8 Work String to 2700'md. 6/15/2017-Thursday Rig down due to failed coolant pump and fan belt. Bearing in coolant pump found to be seized resulting in fan belt damage. VMS on location @ 7:00am to assess. Drain engine coolant, remove pump, replace pump, replace fan belt, fill coolant and start engine. (No codes being thrown, all gauges reading proper.) Rig crews clean rig floor, bring spare 11" BOPE to A pad for move to Endicott, Unload TBG @ G&I to free up pipe tubs. RIH w/mule shoe clean out BHA on 3.5" work string 1/ "2,700'md to 9,400'md. SIMOPS: swap out flow back tanks in prep for move to Endicott. Field support on location to deliver hard line for Endicott well. Service Rig Check Fluids Grease. Rig up to Circulate at 9,342'. P/U=94K D/N=52K Get Circulating Parameters at 3 bpm at Tbg=168psi IA=510psi Continued RIH Tag top of Fill at 9,445'. Reverse Circulate Down Through Btm Set of Perfs 41'. (9,450-9,490)to 9,515'.Tagged Hard with 8k ( PDMD 9,515'.) Continued Reversing 2-25 bbl. High Vis Sweeps to Surface at 3.9 bpm at Tbg-180 IA=520 Total Loss to Formation 100 bbl.Total bbl. Pumped 610.Trip out of the hole w/3.5 RTS-8 Work String f/9,515'.to 1,000'. 6/16/2017- Friday Service Rig Check Fluids and Grease.Trip out of the hole w/3.5 RTS-8 Work String f/1,000'. to Surface, Break Lay down Mule Shoe. Rig down Power Tongs/Tong Rack off Rig Floor, Load and Tally 110 jts of 2-7/8" 13Cr Bear Tubing on Racks, R/U Weatherford Torque Turn Handing Equipment/ Rig up Halliburton Tec Wire Spooler, Pull Tec Wire over Sheave in Derrick. Pick and Make up Halliburton Jewelry Completion BHA and PHL Packer Assembly, R/U Roc Gauge Mandrel Connection and Test Tec Wire.TIH w/ PHL Packer Completion Assembly on 2-7/8" Cr13 Bear tubing f/287md to 985md. Service Rig Check Fluids and Grease. Continued TIH w/ PHL Packer Completion Assembly on 2-7/8" Cr13 Bear tubing f/985'. to 8,500'. Load and tally Completion Tubing on the Go, we are not getting no displacement to the pits while Running Completion, Fill Hole w/5bbl every Hour • • 1:1Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP B-30 ASR 50-029-23571-00-00 216-153 6/13/17 6/17/17 Daily Operations: 6/17/2017 -Saturday Continue to POOH w/ mule shoe clean out BHA f/Service Rig Check Fluids and Grease. Continued TIH w/ PHL Packer Completion Assembly on 2-7/8" Cr13 Bear tubing f/8,500'. to 9,428'. P/U/W=65k D/N/W=41k. Make up landing joint into hanger String Tec Wire, Land Hanger RILDS, Rig down Weatherford Torque Turn Equipment, Rig up ASR Power tongs and base Plate. Drop ball and Rod, R/U LRS, P/T Lines to 4,400psi, Fill Tubing Close Blind Rams, Pressure up on Tubing set Packer 2,500-4,000psi 30 charted Min ( Good Test) Bleed Tubing Down to 1,250psi R/U on IA Pressure Test Back side 3,700psi 30 Charted Min ( Good Test)Bleed off both sides to the pits. Well Head Rep John Morrow Tee bar install BPV, Blow down and disconnect all Service Lines. Electrician Sean Logan Disconnected Fire and Gas Alarms, Roads and Pads Hauled off 120 bbl. 8.4 ppg Brine to B-50, Removed Pipe Racks, Peak super Sucker Cleaning Pits pit 3 has about 1'. Frac Sand on Bottom. Break and Lay over Derrick, Nipple down bope stack to four Bolts, Rig down and remove Hydraulic hoses from bop and cat walk. ASRC Crane Remove Rig Floor and well House load on Trailer, Nipple down bope stack, Nipple up Production Tree.Test Hanger Void to 5,000psi,Tee Bar and Remove BPV, Install TWC Valve, Well Support Fill Tree with Diesel Test Tree Flanges to 5,000psi (Good Test). Clear and Clean Location, Rig Move Haul ASR Rig and Equipment to Endicott 6/18/2017 -Sunday No activity to report. 6/19/2017- Monday No activity to report. 6/20/2017-Tuesday No activity to report. Hilcorp Alaska, LLC Milne Point M Pt B Pad MPU B-30 50-029-23571-00-00 Sperry Drilling Definitive Survey Report 10 May, 2017 s� x HALLIBURTON Sperry Drilling • Halliburton • Definitive Survey Report Company: HilcorpAlaska,LLC Local Co-ordinate Reference: Well MPU B-30 Project: Milne Point TVD Reference: MPB 30 As-Built @ 49.60usft(Innovation) Site: M Pt B Pad MD Reference: MPB 30 As-Built @ 49.60usft(Innovation) Well: MPU B-30 North Reference: True Wellbore: MPU B-30 Survey Calculation Method: Minimum Curvature Design: MPU B-30 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 B-30 Well Position +N/-S 0.00 usft Northing: 6,023,208.86 usft Latitude: 70°28'25.298 N +El-W 0.00 usft Easting: 571,962.88 usft Longitude: 149°24'43.916 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 23.10 usft -I Wellbore MPU B-30 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2016 4/10/2017 17.82 81.06 57,558 Design MPU B-30 i Audit Notes: Survey at 5260'is an interpolated kick off point. Version: 1.0 Phase: ACTUAL Tie On Depth: 5,222.25 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (0) 26.50 0.00 0.00 228.00 Survey Program Date 5/10/2017 From To (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 50.00 477.00 SRG-MS(MPU B-30 PB1) SRG-MS Surface readout gyro multishot 04/03/2017 539.00 726.00 SRG-SS(MPU B-30 PB1) SRG-SS Surface readout gyro single shot 04/10/2017 787.53 5,173.66 MWD+IFR2+MS+sag(1)(MPU B-30 PB1 MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 04/10/2017 5,222.25 5,222.25 MWD+IFR2+MS+sag(2)(MPU B-30 PB1 MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 04/14/2017 5,260.00 5,509.78 MWD+IFR2+MS+sag(MPU B-30) MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 04/26/2017 5,572.82 5,572.82 MWD_Interp Azi+sag(MPU 13-30) MWD_Interp Azi+sag Fixed:v2:std dec with interpolated azimuth+sag 05/02/2017 5,635.63 9,578.38 MWD+IFR2+MS+sag(2)(MPU B-30) MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 05/02/2017 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 26.50 0.00 0.00 26.50 -23.10 0.00 0.00 6,023,208.86 571,962.88 0.00 0.00 UNDEFINED 50.00 0.31 178.67 50.00 0.40 -0.06 0.00 6,023,208.80 571,962.88 1.32 0.04 SRG-MS(1) 150.00 0.26 203.46 150.00 100.40 -0.54 -0.08 6,023,208.32 571,962.80 0.13 0.43 SRG-MS(1) 250.00 0.33 205.31 250.00 200.40 -1.01 -0.30 6,023,207.85 571,962.59 0.07 0.90 SRG-MS(1) 350.00 0.33 197.44 350.00 300.40 -1.55 -0.51 6,023,207.31 571,962.39 0.05 1.41 SRG-MS(1) 450.00 0.55 205.67 449.99 400.39 -2.25 -0.80 6,023,206.60 571,962.10 0.23 2.10 SRG-MS(1) 477.00 0.88 201.01 476.99 427.39 -2.56 -0.93 6,023,206.29 571,961.97 1.24 2.41 ERG-MS(1) 539.00 1.07 207.13 538.98 489.38 -3.52 -1.37 6,023,205,33 571,961.55 0.35 3.37 SRG-SS(2) 600.00 1.50 199.85 599.97 550.37 -4.78 -1.90 6,023,204.06 571,961.03 0.75 4.61 SRG-SS(2) 5/10/2017 4:47:12PM Page 2 COMPASS 5000.1 Build 81 Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-30 Project: Milne Point TVD Reference: MPB 30 As-Built @ 49.60usft(Innovation) Site: M Pt B Pad MD Reference: MPB 30 As-Built @ 49.60usft(Innovation) Well: MPU B-30 North Reference: True Wellbore: MPU B-30 Survey Calculation Method: Minimum Curvature Design: MPU B-30 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 663.00 4.63 177.01 662.87 613.27 -8.10 -2.05 6,023,200.75 571,960.91 5.24 6.94 SRG-SS(2) 726.00 7.03 188.62 725.54 675.94 -14.45 -2.49 6,023,194.39 571,960.53 4.23 11.52 SRG-SS(2) 787.53 7.58 203.70 786.58 736.98 -21.89 -4.69 6,023,186.93 571,958.41 3.23 18.13 MWD+IFR2+MS+sag(3) 850.47 10.39 212.86 848.74 799.14 -30.46 -9.44 6,023,178.32 571,953.74 5.00 27.39 MWD+IFR2+MS+sag(3) 913.07 13.22 219.40 910.01 860.41 -40.73 -17.04 6,023,167.97 571,946.23 4.99 39.92 MWD+IFR2+MS+sag(3) 976.02 13.78 222.59 971.23 921.63 -51.82 -26.69 6,023,156.79 571,936.70 1.48 54.50 MWD+IFR2+MS+sa9(3) 1,039.15 16.23 227.01 1,032.20 982.60 -63.37 -38.23 6,023,145.13 571,925.27 4.28 70.81 MWD+IFR2+MS+sag(3) 1,102.25 19.84 230.15 1,092.19 1,042.59 -76.25 -52.91 6,023,132.11 571,910.72 5.92 90.34 MWD+IFR2+MS+sag(3) 1,164.77 21.51 230.48 1,150.68 1,101.08 -90.34 -69.90 6,023,117.86 571,893.87 2.68 112.39 MWD+IFR2+MS+sag(3) 1,227.67 21.99 227.65 1,209.11 1,159.51 -105.61 -87.49 6,023,102.42 571,876.42 1.83 135.69 MWD+IFR2+MS+sag(3) 1,291.47 21.37 222.34 1,268.40 1,218.80 -122.25 -104.15 6,023,085.62 571,859.92 3.22 159.20 MWD+IFR2+MS+sag(3) 1,353.66 21.36 221.08 1,326.32 1,276.72 -139.17 -119.23 6,023,068.56 571,845.02 0.74 181.72 MWD+IFR2+MS+sag(3) 1,416.66 21.20 217.52 1,385.02 1,335.42 -156.85 -133.70 6,023,050.74 571,830.71 2.07 204.31 MWD+IFR2+MS+sag(3) 1,479.65 21.40 214.97 1,443.71 1,394.11 -175.30 -147.23 6,023,032.16 571,817.37 1.50 226.71 MWD+IFR2+MS+sag(3) 1,542.58 21.59 215.87 1,502.26 1,452.66 -194.09 -160.59 6,023,013.24 571,804.19 0.60 249.21 MWD+IFR2+MS+sag(3) 1,605.91 21.44 216.30 1,561.18 1,511.58 -212.86 -174.27 6,022,994.35 571,790.69 0.34 271.94 MWD+IFR2+MS+sag(3) 1,668.48 21.14 216.28 1,619.48 1,569.88 -231.17 -187.72 6,022,975.91 571,777.42 0.48 294.19 MWD+IFR2+MS+sag(3) 1,731.42 20.92 216.03 1,678.23 1,628.63 -249.41 -201.04 6,022,957.54 571,764.28 0.38 316.29 MWD+IFR2+MS+sag(3) 1,794.70 20.36 217.54 1,737.45 1,687.85 -267.27 -214.40 6,022,939.55 571,751.10 1.22 338.17 MWD+IFR2+MS+sag(3) 1,857.15 20.12 216.07 1,796.04 1,746.44 -284.57 -227.34 6,022,922.13 571,738.32 0.90 359.36 MWD+IFR2+MS+sag(3) 1,920.00 20.89 214.42 1,854.91 1,805.31 -302.55 -240.04 6,022,904.03 571,725.80 1.53 380.83 MWD+IFR2+MS+sag(3) 1,983.17 21.25 213.17 1,913.86 1,864.26 -321.42 -252.67 6,022,885.04 571,713.36 0.91 402.84 MWD+IFR2+MS+sag(3) 2,046.04 20.39 213.63 1,972.62 1,923.02 -340.08 -284.97 6,022,866.27 571,701.24 1.39 424.47 MWD+IFR2+MS+sag(3) 2,108.75 20.72 212.42 2,031.34 1,981.74 -358.54 -276.97 6,022,847.69 571,689.42 0,86 445.74 MWD+IFR2+MS+sag(3) 2,171.98 20.75 214.58 2,090.47 2,040.87 -377.21 -289.32 6,022,828.91 571,677.25 1.21 467.41 MWD+IFR2+MS+sag(3) 2,234.75 20.41 213.07 2,149.24 2,099.64 -395.53 -301.60 6,022,810.47 571,665.14 1.00 488.80 MWD+IFR2+MS+sag(3) 2,297.53 20.38 214.24 2,208.08 2,158.48 -413.74 -313.73 6,022,792.14 571,653.20 0.65 509.99 MWD+IFR2+MS+sag(3) 2,360.16 21.21 215.15 2,266.63 2,217.03 -432.02 -326.39 6,022,773.74 571,640.72 1.42 531.63 MWD+IFR2+MS+sag(3) 2,423.51 20.77 213.84 2,325.78 2,276.18 -450.72 -339.24 6,022,754.92 571,628.05 1.02 553.69 MWD+IFR2+MS+sag(3) 2,486.00 20.68 214.43 2,384.23 2,334.63 -469.03 -351.65 6,022,736.50 571,615.82 0.36 575.16 MWD+IFR2+MS+sag(3) 2,549.37 22.06 215.18 2,443.24 2,393.64 -487.98 -364.83 6,022,717.42 571,602.82 2.22 597.65 MWD+IFR2+MS+sag(3) 2,611.73 22.56 214.67 2,500.93 2,451.33 -507.39 -378,38 6,022,697.88 571,589.46 0.86 620.70 MWD+IFR2+MS+sag(3) 2,674.72 23.01 214.15 2,559.00 2,509.40 -527.52 -392.17 6,022,677.62 571,575.87 0.78 644.42 MWD+IFR2+MS+sag(3) 2,737.75 22.89 214.24 2,617.05 2,567.45 -547.85 -405.98 6,022,657.16 571,562.25 0.20 668.28 MWD+IFR2+MS+sag(3) 2,800.58 23.15 214.35 2,674.87 2,625.27 -566.15 -419.82 6,022,636.74 571,548.61 0.42 692.15 MWD+IFR2+MS+sag(3) 2,863.42 22.44 214.63 2,732.80 2,683.20 -588.21 -433.61 6,022,616.54 571,535.02 1.14 715.83 MWD+IFR2+MS+sag(3) 2,926.53 21.39 212.68 2,791.35 2,741.75 -607.81 -446.67 6,022,596.82 571,522.15 2.02 738.64 MWD+IFR2+MS+sag(3) 2,989.94 21.60 212.67 2,850.35 2,800.75 -627.37 -459.21 6,022,577.14 571,509.80 0.33 761.05 MWD+IFR2+MS+sag(3) 3,052.70 21.52 213.20 2,908.72 2,859.12 -646.73 -471.75 6,022,557.66 571,497.45 0.34 783.32 MWD+IFR2+MS+sag(3) 3,115.77 21.63 214.19 2,967.37 2,917.77 -666.02 -484.62 6,022,538.25 571,484.77 0.60 805.80 MWD+IFR2+MS+sag(3) 5/10/2017 4:47:12PM Page 3 COMPASS 5000.1 Build 81 4110 • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-30 Project: Milne Point TVD Reference: MPB 30 As-Built @ 49.60usft(Innovation) Site: M Pt B Pad MD Reference: MPB 30 As-Built @ 49.60usft(Innovation) Well: MPU B-30 North Reference: True Wellbore: MPU B-30 Survey Calculation Method: Minimum Curvature Design: MPU B-30 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (0) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 3,178.45 21.56 213.77 3,025.65 2,976.05 -685.15 -497.51 6,022,519.00 571,472.06 0.27 828.18 MWD+IFR2+MS+sag(3) 3,241.56 21.31 214.73 3,084.40 3,034.80 -704.21 -510.49 6,022,499.81 571,459.27 0.68 850.58 MWD+IFR2+MS+sag(3) 3,304.73 21.26 214.94 3,143.28 3,093.66 -723.04 -523.59 6,022,480.86 571,446.36 0.14 872.91 MWD+IFR2+MS+sag(3) 3,367.75 21.56 215.69 3,201.93 3,152.33 -741.81 -536.89 6,022,461.97 571,433.24 0.64 895.35 MWD+IFR2+MS+sag(3) 3,430.70 21.25 215.16 3,260.54 3,210.94 -760.53 -550.20 6,022,443.12 571,420,11 0.58 917.77 MWD+IFR2+MS+sag(3) 3,493.58 21.28 215.60 3,319.14 3,269.54 -779.12 -563.41 6,022,424.40 571,407.08 0.26 940.03 MWD+IFR2+MS+sag(3) 3,556.40 21.08 216.49 3,377.71 3,328.11 -797.47 -576.76 6,022,405.92 571,393.91 0.60 962.23 MWD+IFR2+MS+sag(3) 3,619.10 20.75 217.80 3,436.28 3,386.68 -815.31 -590.28 6,022,387.95 571,380.57 0.91 984.21 MWD+IFR2+MS+sag(3) 3,681.42 20.96 217.09 3,494.52 3,444.92 -832.93 -603.76 6,022,370.21 571,367.25 0.53 1,006.02 MWD+IFR2+MS+sag(3) 3,744.98 20.85 217.91 3,553.90 3,504.30 -850.92 -617.57 6,022,352.09 571,353.62 0.49 1,028.32 MWD+IFR2+MS+sag(3) 3,807.89 20.65 214.91 3,612.73 3,563.13 -868.85 -630.80 6,022,334.03 571,340.57 1.72 1,050.15 MWD+IFR2+MS+sag(3) 3,870.65 20.96 213.76 3,671.40 3,621.80 -887.26 -643.37 6,022,315.51 571,328.18 0.82 1,071.81 MWD+IFR2+MS+sag(3) 3,933.36 21.04 213.57 3,729.94 3,680.34 -905.96 -655.83 6,022,296.68 571,315.91 0.17 1,093.58 MWD+IFR2+MS+sag(3) 3,996.38 21.29 215.11 3,788.71 3,739.11 -924.75 -668.66 6,022,277.78 571,303.25 0.97 1,115.69 MWD+IFR2+MS+sag(3) 4,059.87 21.29 215.49 3,847.87 3,798.27 -943.56 -681.98 6,022,258.84 571,290.12 0.22 1,138.18 MWD+IFR2+MS+sag(3) 4,122.11 21.45 215.11 3,905.83 3,856.23 -962.07 -695.09 6,022,240.20 571,277.19 0.34 1,160.30 MWD+IFR2+MS+sag(3) 4,184.90 22.18 214.56 3,964.12 3,914.52 -981.22 -708.41 6,022,220.92 571,264.05 1.21 1,183.02 MWD+IFR2+MS+sag(3) 4,248.49 23.17 214.42 4,022.79 3,973.19 -1,001.43 -722.30 6,022,200.59 571,250.37 1.56 1,206.86 MWD+IFR2+MS+sag(3) 4,310.76 22.08 212.50 4,080.27 4,030.67 -1,021.41 -735.51 6,022,180.49 571,237.35 2.11 1,230.04 MWD+IFR2+MS+sag(3) 4,373.78 22.19 212.06 4,138.65 4,089.05 -1,041.48 -748.19 6,022,160.29 571,224.86 0.32 1,252.90 MWD+IFR2+MS+sag(3) 4,436.43 22.91 211.85 4,196.51 4,146.91 -1,061.87 -760.91 6,022,139.79 571,212.35 1.16 1,275.99 MWD+IFR2+MS+sag(3) 4,499.55 21.70 213.36 4,254.90 4,205.30 -1,082.05 -773.81 6,022,119.48 571,199.64 2.12 1,299.08 MWD+IFR2+MS+sag(3) 4,562.00 20.16 214.63 4,313.23 4,263.63 -1,100.55 -786.27 6,022,100.86 571,187.36 2.57 1,320.72 MWD+IFR2+MS+sag(3) 4,625.11 18.59 216.26 4,372.77 4,323.17 -1,117.61 -798.40 6,022,083.69 571,175.40 2.63 1,341.16 MWD+IFR2+MS+sag(3) 4,687.94 18.55 215.30 4,432.33 4,382.73 -1,133.84 -810.10 6,022,067.34 571,163.86 0.49 1,360.71 MWD+IFR2+MS+sag(3) 4,750.88 19.42 215.64 4,491.84 4,442.24 -1,150.52 -821.98 6,022,050.56 571,152.14 1.39 1,380.70 MWD+IFR2+MS+sag(3) 4,813.91 18.06 214.71 4,551.53 4,501.93 -1,167.07 -833.65 6,022,033.90 571,140.63 2.21 1,400.44 MWD+IFR2+MS+sag(3) 4,876.51 17.97 213.17 4,611.06 4,561.46 -1,183.13 -844.46 6,022,017.74 571,129.98 0.77 1,419.22 MWD+IFR2+MS+sag(3) 4,939.96 18.57 214.31 4,671.31 4,621.71 -1,199.66 -855.51 6,022,001.09 571,119.09 1.10 1,438.50 MWD+IFR2+MS+sag(3) 5,002.40 19.14 213.48 4,730.40 4,680.80 -1,216.41 -866.76 6,021,984.24 571,108.00 1.01 1,458.07 MWD+IFR2+MS+sag(3) 5,065.63 17.83 215.01 4,790.37 4,740.77 -1,232.99 -878.03 6,021,967.55 571,096.89 2.21 1,477.54 MWD+IFR2+MS+sag(3) 5,128.27 17.44 215.84 4,850.06 4,800.46 -1,248.45 -889.03 6,021,951.99 571,086.04 0.74 1,496.06 MWD+IFR2+MS+sag(3) 5,173.66 17.56 216.00 4,893.35 4,843.75 -1,259.51 -897.04 6,021,940.86 571,078.14 0.28 1,509.41 MWD+IFR2+MS+sag(3) 5,222.25 17.50 215.90 4,939.69 4,890.09 -1,271.36 -905.63 6,021,928.93 571,069.67 0.14 1,523.72 MWD+IFR2+MS+sag(4) 5,260.00 17.32 215.59 4,975.71 4,926.11 -1,280.52 -912.23 6,021,919.70 571,063.16 0.54 1,534.76 MWD+IFR2+MS+sag(5) 5,289.82 15.79 208.74 5,004.29 4,954.69 -1,287.69 -916.77 6,021,912.49 571,058.69 8.31 1,542.92 MWD+IFR2+MS+sag(5) 5,320.99 15.61 206.34 5,034.30 4,984.70 -1,295.17 -920.67 6,021,904.97 571,054.87 2.16 1,550.82 MWD+IFR2+MS+sag(5) 5,384.07 15.26 206.84 5,095.10 5,045.50 -1,310.18 -928.18 6,021,889.89 571,047.50 0.59 1,566.45 MWD+IFR2+MS+sag(5) 5,446.64 14.78 206.29 5,155.54 5,105.94 -1,324.68 -935.43 6,021,875.32 571,040.39 0.80 1,581.55 MWD+IFR2+MS+sag(5) 5,509.78 14.32 206.12 5,216.65 5,167.05 -1,338.92 -942.44 6,021,861.02 571,033.52 0.73 1,596.28 MWD+IFR2+MS+sag(5) 510/2017 4:47:12PM Page 4 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-30 Project: Milne Point TVD Reference: MPB 30 As-Built @ 49.60usft(Innovation) Site: M Pt B Pad MD Reference: MPB 30 As-Built @ 49.60usft(Innovation) Well: MPU B-30 North Reference: True Wellbore: MPU B-30 Survey Calculation Method: Minimum Curvature Design: MPU B-30 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 5,572.82 16.70 206.45 5,277.39 5,227.79 -1,354.03 -949.90 6,021,845.84 571,026.20 3.78 1,611.94 MWD_InterpAzi+sag(6) 5,635.63 17.25 206.72 5,337.47 5,287.87 -1,370.43 -958.11 6,021,829.36 571,018.15 0.88 1,629.01 MWD+IFR2+MS+sag(7) 5,699.00 17.04 204.76 5,398.02 5,348.42 -1,387.25 -966.23 6,021,812.46 571,010.20 0.97 1,646.30 MWD+IFR2+MS+sag(7) 5,759.62 16.97 207.45 5,455.99 5,406.39 -1,403.17 -974.02 6,021,796.47 571,002.56 1.30 1,662.74 MWD+IFR2+MS+sag(7) 5,824.77 16.68 206.86 5,518.35 5,468.75 -1,419.94 -982.63 6,021,779.62 570,994.12 0.52 1,680.37 MWD+IFR2+MS+sag(7) 5,887.72 16.48 206.31 5,578.68 5,529.08 -1,436.01 -990.67 6,021,763.48 570,986.23 0.40 1,697.09 MWD+IFR2+MS+sag(7) 5,950.58 16.01 205.70 5,639.03 5,589.43 -1,451.81 -998.38 6,021,747.60 570,978.68 0.80 1,713.39 MWD+IFR2+MS+sag(7) 6,013.58 15.69 205.90 5,699.64 5,650.04 -1,467.30 -1,005.87 6,021,732.04 570,971.34 0.52 1,729.32 MWD+IFR2+MS+sag(7) 6,076.86 15.24 205.58 5,760.63 5,711.03 -1,482.50 -1,013.20 6,021,716.77 570,964.16 0.72 1,744.94 MWD+IFR2+MS+sag(7) 6,139.75 17.06 207.71 5,821.03 5,771.43 -1,498.13 -1,021.06 6,021,701.07 570,956.45 3.04 1,761.24 MWD+IFR2+MS+sag(7) 6,202.57 17.32 208.35 5,881.05 5,831.45 -1,514.51 -1,029.78 6,021,684.60 570,947.88 0.51 1,778.69 MWD+IFR2+MS+sag(7) 6,265.49 16.97 207.81 5,941.17 5,891.57 -1,530.88 -1,038.51 6,021,668.16 570,939.31 0.61 1,796.12 MWD+IFR2+MS+sag(7) 6,328.63 16,60 207.34 6,001.62 5,952.02 -1,547.04 -1,046.96 6,021,651.92 570,931.03 0.62 1,813.21 MWD+IFR2+MS+sag(7) 6,391.73 16.46 208.05 6,062.11 6,012.51 -1,562.94 -1,055.30 6,021,635.94 570,922.84 0.39 1,830.05 MWD+IFR2+MS+sag(7) 6,454.57 16.33 207.19 6,122.40 6,072.80 -1,578.65 -1,063.52 6,021,620.15 570,914.77 0.44 1,846.67 MWD+IFR2+MS+sag(7) 6,517.39 16.06 206.64 6,182.73 6,133.13 -1,594.27 -1,071.45 6,021,604.45 570,906.99 0.49 1,863.02 MWD+IFR2+MS+sag(7) 6,579.56 16.08 207.72 6,242.47 6,192.87 -1,609.58 -1,079.31 6,021,589.07 570,899.28 0.48 1,879.11 MWD+IFR2+MS+sag(7) 6,642.40 17.30 213.49 6,302.66 6,253.06 -1,625.08 -1,088.52 6,021,573.49 570,890.23 3.27 1,896.32 MWD+IFR2+MS+sag(7) 6,705.97 18.41 216.58 6,363.17 6,313.57 -1,641.02 -1,099.72 6,021,557.43 570,879.18 2.30 1,915.31 MWD+IFR2+MS+sag(7) 6,768.00 19.88 221.09 6,421.77 6,372.17 -1,656.84 -1,112,49 6,021,541.50 570,866.57 3.36 1,935.38 MWD+IFR2+MS+sag(7) 6,830.81 20.79 222.82 6,480.67 6,431.07 -1,673.07 -1,127.08 6,021,525.13 570,852.13 1.74 1,957.09 MWD+IFR2+MS+sag(7) 6,894.24 19.93 222.63 6,540.13 6,490.53 -1,689.28 -1,142.06 6,021,508.78 570,837.32 1.36 1,979.06 MWD+IFR2+MS+sag(7) 6,957.59 19.44 222.62 6,599.78 6,550.18 -1,704.98 -1,156.51 6,021,492.94 570,823.02 0.77 2,000.31 MWD+IFR2+MS+sag(7) 7,020.55 21.21 222.67 6,658.82 6,609.22 -1,721.06 -1,171.32 6,021,476.71 570,808.36 2.81 2,022.08 MWD+IFR2+MS+sag(7) 7,083.35 21.28 222.35 6,717.35 6,667.75 -1,737.84 -1,186.70 6,021,459.79 570,793.15 0.22 2,044.73 MWD+IFR2+MS+sag(7) 7,146.40 21.21 223.48 6,776.12 6,726.52 -1,754.57 -1,202.26 6,021,442.91 570,777.76 0.66 2,067.49 MWD+IFR2+MS+sag(7) 7,209.10 20.94 223.72 6,834.62 6,785.02 -1,770.90 -1,217.80 6,021,426.44 570,762.37 0.45 2,089.97 MWD+IFR2+MS+sag(7) 7,271.90 20.92 222.70 6,893.28 6,843.68 -1,787.25 -1,233.16 6,021,409.94 570,747.17 0.58 2,112.32 MWD+IFR2+MS+sag(7) 7,332.92 20.83 228.87 6,950.30 6,900.70 -1,802.39 -1,248.72 6,021,394.65 570,731.76 3.60 2,134.02 MWD+IFR2+MS+sag(7) 7,397.62 21.39 237.61 7,010.67 6,961.07 -1,816.28 -1,267.36 6,021,380.58 570,713.26 4.94 2,157.16 MWD+IFR2+MS+sag(7) 7,460.61 21.17 246.93 7,069.39 7,019.79 -1,826.90 -1,287.53 6,021,369.77 570,693.20 5.38 2,179.25 MWD+IFR2+MS+sag(7) 7,523.25 21.30 255.05 7,127.79 7,078.19 -1,834.26 -1,308.93 6,021,362.20 570,671.87 4.70 2,200.09 MWD+IFR2+MS+sag(7) 7,586.56 22.01 260.48 7,186.63 7,137.03 -1,839.19 -1,331.74 6,021,357.05 570,649.11 3.36 2,220.34 MWD+IFR2+MS+sag(7) 7,648.99 21.60 260.34 7,244.60 7,195.00 -1,843.06 -1,354.61 6,021,352.97 570,626.28 0.66 2,239.91 MWD+IFR2+MS+sag(7) 7,712.06 21.09 260.16 7,303.34 7,253.74 -1,846.94 -1,377.23 6,021,348.86 570,603.70 0.82 2,259.33 MWD+IFR2+MS+sag(7) 7,775.00 22.20 261.12 7,361.84 7,312.24 -1,850.72 -1,400.14 6,021,344.87 570,580.83 1.85 2,278.88 MWD+IFR2+MS+sag(7) 7,837.87 21.80 261.71 7,420.13 7,370.53 -1,854.23 -1,423.43 6,021,341.13 570,557.58 0.73 2,298.53 MWD+IFR2+MS+sag(7) 7,900.48 21.21 260.86 7,478.38 7,428.78 -1,857.71 -1,446.11 6,021,337.43 570,534.93 1.07 2,317.72 MWD+IFR2+MS+sag(7) 7,963.04 20.37 261.08 7,536.87 7,487.27 -1,861.19 -1,468.04 6,021,333.74 570,513.04 1,35 2,336.35 MWD+IFR2+MS+sag(7) 8,026.47 21.58 263.53 7,596.10 7,546.50 -1,864.22 -1,490.54 6,021,330.49 570,490.57 2.36 2,355.09 MWD+IFR2+MS+sag(7) 5/10/2017 4:47:12PM Page 5 COMPASS 5000.1 Build 81 Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-30 Project: Milne Point TVD Reference: MPB 30 As-Built @ 49.60usft(Innovation) Site: M Pt B Pad MD Reference: MPB 30 As-Built @ 49,60usft(Innovation) Well: MPU B-30 North Reference: True Wellbore: MPU B-30 Survey Calculation Method: Minimum Curvature Design: MPU B-30 Database: Sperry EDM-NORTH US+CANADA Survey I Map Map Vertical MD Inc Azi ND TVDSS +NI-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 8,089.37 22.60 265.77 7,654.38 7,604.78 -1,866.41 -1,514.09 6,021,328.07 570,467.05 2.10 2,374.06 MWD+IFR2+MS+sag(7) 8,152.44 23.38 263.66 7,712.44 7,662.84 -1,868.69 -1,538.61 6,021,325.56 570,442.55 1.80 2,393.81 MWD+IFR2+MS+sag(7) 8,214.86 23.12 263.59 7,769.79 7,720.19 -1,871.43 -1,563.10 6,021,322.59 570,418.10 0.42 2,413.84 MWD+IFR2+MS+sag(7) 8,278.40 22.63 263.24 7,828.33 7,778.73 -1,874.26 -1,587.63 6,021,319.52 570,393.59 0.80 2,433.97 MWD+IFR2+MS+sag(7) 8,341.36 24.01 263.65 7,886.15 7,836.55 -1,877.10 -1,612.39 6,021,316.44 570,368.86 2.21 2,454.27 MWD+IFR2+MS+sag(7) 8,404.16 23.86 263.81 7,943.55 7,893.95 -1,879.88 -1,637.72 6,021,313.41 570,343.57 0.26 2,474.95 MWD+IFR2+MS+sag(7) 8,467.15 25.08 263.95 8,000.88 7,951.28 -1,882.66 -1,663.66 6,021,310.38 570,317.65 1.94 2,496.09 MWD+IFR2+MS+sag(7) 8,529.95 24.85 263.44 8,057.81 8,008.21 -1,885.57 -1,690.01 6,021,307.21 570,291.34 0.50 2,517.62 MWD+IFR2+MS+sag(7) 8,593.14 24.07 263.30 8,115.33 8,065.73 -1,888.59 -1,716.00 6,021,303.94 570,265.38 1.24 2,538.95 MWD+IFR2+MS+sag(7) 8,656.36 23.33 262.99 8,173.22 8,123.62 -1,891.63 -1,741.23 6,021,300.67 570,240.19 1.19 2,559.73 MWD+IFR2+MS+sag(7) 8,719.14 22.63 262.56 8,231.02 8,181.42 -1,894.71 -1,765.54 6,021,297.35 570,215.91 1.15 2,579.86 MWD+IFR2+MS+sag(7) 8,782.16 22.07 261.67 8,289,30 8,239.70 -1,897.99 -1,789.28 6,021,293.84 570,192.20 1.04 2,599.70 MWD+IFR2+MS+sag(7) 8,845.23 21.46 262.04 8,347,88 8,298.28 -1,901.31 -1,812.43 6,021,290.30 570,169.09 0.99 2,619.12 MWD+IFR2+MS+sag(7) 8,908.19 20.76 260.96 8,406.61 8,357.01 -1,904.66 -1,834.86 6,021,286.73 570,146.70 1.27 2,638.03 MWD+IFR2+MS+sag(7) 8,970.71 19.84 260.38 8,465.25 8,415.85 -1,908.17 -1,856.26 6,021,283.01 570,125.33 1.51 2,656.28 MWD+IFR2+MS+sag(7) 9,033.63 19.04 259.79 8,524.58 8,474.98 -1,911.77 -1,876.89 6,021,279.21 570,104.74 1.31 2,674.02 MWD+IFR2+MS+sa9(7) 9,096.69 17.79 258.78 8,584.41 8,534.81 -1,915.47 -1,896.46 6,021,275.32 570,085.21 2.05 2,691.04 MWD+IFR2+MS+sag(7) 9,159.28 17.02 257.67 8,644.13 8,594.53 -1,919.29 -1,914.79 6,021,271.33 570,066.92 1.34 2,707.22 MWD+IFR2+MS+sag(7) 9,222.91 15.30 257.19 8,705.25 8,655.65 -1,923.14 -1,932.07 6,021,267.31 570,049.67 2.71 2,722.64 MWD+IFR2+MS+sag(7) 9,285.35 14.16 257.18 8,765.63 8,716.03 -1,926.66 -1,947.55 6,021,263.64 570,034.23 1.83 2,736.50 MWD+IFR2+MS+sag(7) 9,348.03 13.10 256.62 8,826.55 8,776.95 -1,930.00 -1,961.94 6,021,260.16 570,019.88 1.70 2,749.43 MWD+IFR2+MS+sag(7) 9,411.35 11.97 255.86 8,888.36 8,838.76 -1,933.27 -1,975.29 6,021,256.77 570,006.56 1.80 2,761.53 MWD+IFR2+MS+sag(7) 9,474.00 11.68 256.09 8,949.68 8,900.08 -1,936.38 -1,987.74 6,021,253.53 569,994.14 0.47 2,772.87 MWD+IFR2+MS+sag(7) 9,537.15 11.33 256.08 9,011.56 8,961.96 -1,939.41 -1,999.97 6,021,250.39 569,981.94 0.55 2,783.99 MWD+IFR2+MS+sag(7) 9,578.38 10.78 255.38 9,052.02 9,002.42 -1,941.36 -2,007.63 6,021,248.37 569,974.30 1.37 2,790.98 MWD+IFR2+MS+sag(7) 9,620.00 10.78 255.38 9,092.91 9,043.31 -1,943.32 -2,015.16 6,021,246.33 569,966.79 0.00 2,797.90 PROJECTED to TD benjamin.hand4halliburton.com Checked By: Mitchell Laird Approved By: 2017.05.1016:11:49-08'00' Date: 5/10/7017 5/10/2017 4:47:12PM Page 6 COMPASS 5000.1 Build 81 • • Hilcorp Alaska, LLC Milne Point M Pt B Pad MPU B-30 PB1 50-029-23571-70-00 Sperry Drilling Definitive Survey Report 10 May, 2017 HALLIBURTON Sperry Drilling • Halliburton • Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU 8-30 Project: Milne Point TVD Reference: MPB 30 As-Built @ 49.60usft(Innovation) Site: M Pt B Pad MD Reference: MPB 30 As-Built @ 49.60usft(Innovation) Well: MPU B-30 North Reference: True Wellbore: MPU B-30 PB1 Survey Calculation Method: Minimum Curvature Design: MPU B-30 PBI Database: Sperry EDM-NORTH US+CANADA Project Milne Point,ACT,MILNE POINT Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPU B-30 Well Position +N/-S 0.00 usft Northing: 6,023,208.86 usft Latitude: 70°28'25.298 N +E/-W 0.00 usft Easting: 571,962.88 usft Longitude: 149°24'43.916 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 23.10 usft Wellbore MPU B-30 PB1 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2016 4/10/2017 17.82 81.06 57,558 Design MPU B-30 PB1 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 26.50 Vertical Section: Depth From(TVD) +N1-S +E/-W Direction (usft) (usft) (usft) (°) 26.50 0.00 0.00 228.00 Survey Program Date 5/10/2017 From To (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 50.00 477.00 SRG-MS(MPU B-30 PB1) SRG-MS Surface readout gyro multishot 04/03/2017 539.00 726.00 SRG-SS(MPU B-30 PB1) SRG-SS Surface readout gyro single shot 04/10/2017 787.53 5,173.66 MWD+IFR2+MS+sag(1)(MPU B-30 PB1 MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 04/10/2017 5,222.25 9,607.32 MWD+IFR2+MS+sag(2)(MPU B-30 PB1 MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 04/14/2017 Survey =r,.... ... , Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 26.50 0.00 0.00 26.50 -23.10 0.00 0.00 6,023,208.86 571,962.88 0.00 0.00 UNDEFINED 50.00 0.31 178.87 50.00 0.40 -0.06 0.00 6,023,208.80 571,962.88 1.32 0.04 SRG-MS(1) 150.00 0.26 203.46 150.00 100.40 -0.54 -0.08 6,023,208.32 571,962.80 0.13 0.43 SRG-MS(1) 250.00 0.33 205.31 250.00 200.40 -1.01 -0.30 6,023,207.85 571,962.59 0.07 0.90 SRG-MS(1) 350.00 0.33 197.44 350.00 300.40 -1.55 -0.51 6,023,207.31 571,962.39 0.05 1.41 SRG-MS(1) 450.00 0.55 205.87 449.99 400.39 -2.25 -0.80 6,023,206.60 571,962.10 0.23 2.10 SRG-MS(1) 477.00 0.88 201.01 476.99 427.39 -2.56 -0.93 6,023,206.29 571,961.97 1.24 2.41 SRG-MS(1) 539.00 1.07 207.13 538.98 489.38 -3.52 -1.37 6,023,205.33 571,961.55 0.35 3.37 SRG-SS(2) 600.00 1.50 199.85 599.97 550.37 -4.78 -1.90 6,023,204.06 571,961.03 0.75 4.61 SRG-SS(2) 663.00 4.63 177.01 662.87 613.27 -8.10 -2.05 6,023,200.75 571,960.91 5.24 6.94 SRG-SS(2) 726.00 7.03 188.62 725.54 675.94 -14.45 -2.49 6,023,194.39 571,960.53 4.23 11.52 SRG-SS(2) 5/10/2017 5.08.55PM Page 2 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-30 Project: Milne Point TVD Reference: MPB 30 As-Built©49.60usft(Innovation) Site: M Pt B Pad MD Reference: MPB 30 As-Built @ 49.60usft(Innovation) Well: MPU B-30 North Reference: True Wellbore: MPU B-30 PB1 Survey Calculation Method: Minimum Curvature Design: MPU B-30 PB1 Database: Sperry EDM-NORTH US+CANADA j Survey Map Map Vertical MD Inc Azi TVD TVDSS +N1-S +E/-W Northing Easting DLS Section (usft) (°) (0) (usft) (usft) (usft) (usft) (ft) (ft) (0/100') (ft) Survey Tool Name 787.53 7.58 203.70 786.58 736.98 -21.89 -4.69 6,023,186.93 571,958.41 3.23 18.13 MWD+IFR2+MS+sag(3) 850.47 10.39 212.86 848.74 799.14 -30.46 -9.44 6,023,178.32 571,953.74 5.00 27.39 MWD+IFR2+MS+sag(3) 913.07 13.22 219.40 910.01 860.41 -40.73 -17.04 6,023,167.97 571,946.23 4.99 39.92 MWD+IFR2+MS+sag(3) 976.02 13.78 222.59 971.23 921.63 -51.82 -26.69 6,023,156.79 571,936.70 1.48 54.50 MWD+IFR2+MS+sag(3) 1,039.15 16.23 227.01 1,032.20 982.60 -63.37 -38.23 6,023,145.13 571,925.27 4.28 70.81 MWD+IFR2+MS+sag(3) 1,102.25 19.84 230.15 1,092.19 1,042.59 -76.25 -52.91 6,023,132.11 571,910.72 5.92 90.34 MWD+IFR2+MS+sag(3) 1,164.77 21.51 230.48 1,150.68 1,101.08 -90.34 -69.90 6,023,117.86 571,893.87 2.68 112.39 MWD+IFR2+MS+sag(3) 1,227.67 21.99 227.65 1,209.11 1,159.51 -105.61 -87.49 6,023,102.42 571,876.42 1.83 135.69 MWD+IFR2+MS+sag(3) 1,291.47 21.37 222.34 1,268.40 1,218.80 -122.25 -104.15 6,023,085.62 571,859.92 3.22 159.20 MWD+IFR2+MS+sag(3) 1,353.66 21.36 221.08 1,326.32 1,276.72 -139.17 -119.23 6,023,068.56 571,845.02 0.74 181.72 MWD+IFR2+MS+sag(3) 1,416.66 21.20 217.52 1,385.02 1,335.42 -156.85 -133.70 6,023,050.74 571,830.71 2.07 204.31 MWD+IFR2+MS+sag(3) 1,479.65 21.40 214.97 1,443.71 1,394.11 -175.30 -147.23 6,023,032.16 571,817.37 1.50 226.71 MWD+IFR2+MS+sag(3) 1,542.58 21.59 215.87 1,502.26 1,452.66 -194.09 -160.59 6,023,013.24 571,804.19 0.60 249.21 MWD+IFR2+MS+sag(3) 1,605.91 21.44 216.30 1,561.18 1,511.58 -212.86 -174.27 6,022,994.35 571,790.69 0.34 271.94 MWD+IFR2+MS+sag(3) 1,668.48 21.14 216.28 1,619.48 1,569.88 -231.17 -187.72 6,022,975.91 571,777.42 0.48 294.19 MWD+IFR2+MS+sag(3) 1,731.42 20.92 216.03 1,678.23 1,628.63 -249.41 -201.04 6,022,957.54 571,764.28 0.38 316.29 MWD+IFR2+MS+sag(3) 1,794.70 20.36 217.54 1,737.45 1,687.85 -267.27 -214.40 6,022,939.55 571,751.10 1.22 338.17 MWD+IFR2+MS+sag(3) 1,857.15 20.12 216.07 1,796.04 1,746.44 -284.57 -227.34 6,022,922.13 571,738.32 0.90 359.36 MWD+IFR2+MS+sag(3) 1,920.00 20.89 214.42 1,854.91 1,805.31 -302.55 -240.04 6,022,904.03 571,725.80 1.53 380.83 MWD+IFR2+MS+sag(3) 1,983.17 21.25 213.17 1,913.86 1,864.26 -321.42 -252.67 6,022,885.04 571,713.36 0.91 402.84 MWD+IFR2+MS+sag(3) 2,046.04 20.39 213.63 1,972.62 1,923.02 -340.08 -264.97 6,022,866.27 571,701.24 1.39 424.47 MWD+IFR2+MS+sag(3) 2,108.75 20.72 212.42 2,031.34 1,981.74 -358.54 -276.97 6,022,847.69 571,689.42 0.86 445.74 MWD+IFR2+MS+sag(3) 2,171.98 20.75 214.58 2,090.47 2,040.87 -377.21 -289.32 6,022,828.91 571,677.25 1.21 467.41 MWD+IFR2+MS+sag(3) 2,234.75 20.41 213.07 2,149.24 2,099.64 -395.53 -301.60 6,022,810.47 571,665.14 1.00 488.80 MWD+IFR2+MS+sag(3) 2,297.53 20.38 214.24 2,208.08 2,158.48 -413.74 -313.73 6,022,792.14 571,653.20 0.65 509.99 MWD+IFR2+MS+sag(3) 2,360.16 21.21 215.15 2,266.63 2,217.03 -432.02 -326.39 6,022,773.74 571,640.72 1.42 531.63 MWD+IFR2+MS+sag(3) 2,423.51 20.77 213.84 2,325.78 2,276.18 -450.72 -339.24 6,022,754.92 571,628.05 1.02 553.69 MWD+IFR2+MS+sag(3) 2,486.00 20.68 214.43 2,384.23 2,334.63 -469.03 -351.65 6,022,736.50 571,615.82 0.36 575.16 MWD+IFR2+MS+sag(3) 2,549.37 22.06 215.18 2,443.24 2,393.64 -487.98 -364.83 6,022,717.42 571,602.82 2.22 597.65 MWD+IFR2+MS+sag(3) 2,611.73 22.56 214.67 2,500.93 2,451.33 -507.39 -378.38 6,022,697.88 571,589.46 0.86 620.70 MWD+IFR2+MS+sag(3) 2,674.72 23.01 214.15 2,559.00 2,509.40 -527.52 -392.17 6,022,677.62 571,575.87 0.78 644.42 MWD+IFR2+MS+sag(3) 2,737.75 22.89 214.24 2,617.05 2,567.45 -547.85 -405.98 6,022,657.16 571,562.25 0.20 668.28 MWD+IFR2+MS+sag(3) 2,800.58 23.15 214.35 2,674.87 2,625.27 -568.15 -419.82 6,022,636.74 571,548.61 0.42 692.15 MWD+IFR2+MS+sag(3) 2,663.42 22.44 214.63 2,732.80 2,683.20 -588.21 -433.61 6,022,616.54 571,535.02 1.14 715.83 MWD+IFR2+MS+sag(3) 2,926.53 21.39 212.68 2,791.35 2,741.75 -607.81 -446.67 6,022,596.82 571,522.15 2.02 738.64 MWD+IFR2+MS+sag(3) 2,989.94 21.60 212.67 2,850.35 2,800.75 -627.37 -459.21 6,022,577.14 571,509.80 0.33 761.05 MWD+IFR2+MS+sag(3) 3,052.70 21.52 213.20 2,908.72 2,859.12 -646.73 -471.75 6,022,557.66 571,497.45 0.34 783.32 MWD+IFR2+MS+sag(3) 3,115.77 21.63 214.19 2,967.37 2,917.77 -666.02 -484.62 6,022,538.25 571,484.77 0.60 805.80 MWD+IFR2+MS+sag(3) 3,178.45 21.56 213.77 3,025.65 2,976.05 -685.15 -497.51 6,022,519.00 571,472.06 0.27 828.18 MWD+IFR2+MS+sag(3) 3,241.56 21.31 214.73 3,084.40 3,034.80 -704.21 -510.49 6,022,499.81 571,459.27 0.68 850.58 MWD+IFR2+MS+sag(3) 5/10/2017 5.08:55PM Page 3 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-30 Project: Milne Point TVD Reference: MPB 30 As-Built @ 49.60usft(Innovation) Site: M Pt B Pad MD Reference: MPB 30 As-Built©49.60usft(Innovation) Well: MPU B-30 North Reference: True Wellbore: MPU B-30 PB1 Survey Calculation Method: Minimum Curvature Design: MPU B-30 PB1 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 3,304.73 21.26 214.94 3.143.26 3,093.66 -723.04 -523.59 6,022,480.86 571,446.36 0.14 872.91 MWD+IFR2+MS+sag(3) 3,367.75 21.56 215.69 3,201.93 3,152.33 -741.81 -536.89 6,022,461.97 571,433.24 0.64 895.35 MWD+IFR2+MS+sag(3) 3,430.70 21.25 215.16 3,260.54 3,210.94 -760.53 -550.20 6,022,443.12 571,420.11 0.58 917.77 MWD+IFR2+MS+sag(3) 3,493.58 21.28 215.60 3,319.14 3,269.54 -779.12 -563.41 6,022,424.40 571,407.08 0.26 940.03 MWD+IFR2+MS+sag(3) 3,556.40 21.08 216.49 3,377.71 3,328.11 -797.47 -576.76 6,022,405.92 571,393.91 0.60 962.23 MWD+IFR2+MS+sag(3) 3,619.10 20.75 217.80 3,436.28 3,386.68 -815.31 -590.28 6,022,387.95 571,380.57 0.91 984.21 MWD+IFR2+MS+sag(3) 3,681.42 20.96 217.09 3,494.52 3,444.92 -832.93 -603.76 6,022,370.21 571,367.25 0.53 1,006.02 MWD+IFR2+MS+sag(3) 3,744.98 20.85 217.91 3,553.90 3,504.30 -850.92 -617.57 6,022,352.09 571,353.62 0.49 1,028.32 MWD+IFR2+MS+sag(3) 3,807.89 20.65 214.91 3,612.73 3,563.13 -868.85 -630.80 6,022,334.03 571,340.57 1.72 1,050.15 MWD+IFR2+MS+sag(3) 3,870.65 20.96 213.76 3,671.40 3,621.80 -887.26 -643.37 6,022,315.51 571,328.18 0.82 1,071.81 MWD+IFR2+MS+sag(3) 3,933.36 21.04 213.57 3,729.94 3,680.34 -905.96 -655.83 6,022,296.68 571,315.91 0.17 1,093.58 MWD+IFR2+MS+sag(3) 3,996.38 21.29 215.11 3,788.71 3,739.11 -924.75 -668.66 6,022,277.78 571,303.25 0.97 1,115.69 MWD+IFR2+MS+sag(3) 4,059.87 21.29 215.49 3,847,87 3,798.27 -943.56 -681.98 6,022,258.84 571,290.12 0.22 1,138.18 MWD+IFR2+MS+sag(3) 4,122,11 21.45 215.11 3,905.83 3,856.23 -962.07 -695.09 6,022,240.20 571,277.19 0.34 1,160.30 MWD+IFR2+MS+sag(3) 4,184.90 22.18 214.56 3,964.12 3,914.52 -981.22 -708.41 6,022,220.92 571,264.05 1.21 1,183.02 MWD+IFR2+MS+sag(3) 4,248.49 23.17 214.42 4,022.79 3,973.19 -1,001.43 -722.30 6,022,200.59 571,250.37 1.56 1,206.86 MWD+IFR2+MS+sag(3) 4,310.76 22.08 212.50 4,080.27 4,030.67 -1,021.41 -735.51 6,022,180.49 571,237.35 2.11 1,230.04 MWD+IFR2+MS+sag(3) 4,373.78 22.19 212.06 4,138.65 4,089.05 -1,041.48 -748.19 6,022,160.29 571,224.86 0.32 1,252.90 MWD+IFR2+MS+sag(3) 4,436.43 22.91 211.85 4,196.51 4,146.91 -1,061.87 -760.91 6,022,139.79 571,212.35 1.16 1,275.99 MWD+IFR2+MS+sag(3) 4,499.55 21.70 213.36 4,254.90 4,205.30 -1,082.05 -773.81 6,022,119.48 571,199.64 2.12 1,299.08 MWD+IFR2+MS+sag(3) 4,562.00 20.16 214.63 4,313.23 4,263.63 -1,100.55 -786.27 8,022,100.86 571,187.36 2.57 1,320.72 MWD+IFR2+MS+sag(3) 4,625.11 18.59 216.26 4,372.77 4,323.17 -1,117.61 -798.40 6,022,083.69 571,175.40 2.63 1,341.16 MWD+IFR2+MS+sag(3) 4,687.94 18.55 215.30 4,432.33 4,382.73 -1,133.84 -810.10 6,022,067.34 571,163.86 0.49 1,360.71 MWD+IFR2+MS+sag(3) 4,750.88 19.42 215.64 4,491.84 4,442.24 -1,150.52 -821.98 6,022,050.56 571,152.14 1.39 1,380.70 MWD+IFR2+MS+sag(3) 4,813.91 18.06 214.71 4,551.53 4,501.93 -1,167.07 -833.65 6,022,033.90 571,140.63 2.21 1,400.44 MWD+IFR2+MS+sag(3) 4,876.51 17.97 213.17 4,611.06 4,561.46 -1,183.13 -844.46 6,022,017.74 571,129.98 0.77 1,419.22 MWD+IFR2+MS+sag(3) 4,939.96 18.57 214.31 4,671.31 4,621.71 -1,199.66 -855.51 6,022,001.09 571,119.09 1.10 1,438.50 MWD+IFR2+MS+sag(3) 5,002.40 19.14 213.48 4,730.40 4,680.80 -1,216.41 -666.76 6,021,984.24 571,108.00 1.01 1,458.07 MWD+IFR2+MS+sag(3) 5,065.63 17.83 215.01 4,790.37 4,740.77 -1,232.99 -878.03 6,021,967.55 571,096.89 2.21 1,477.54 MWD+IFR2+MS+sag(3) 5,128.27 17.44 215.84 4,850.06 4,800.46 -1,248.45 -889.03 6,021,951.99 571,086.04 0.74 1,496.06 MWD+IFR2+MS+sag(3) 5,173.66 17.56 216.00 4,893.35 4,843.75 -1,259.51 -897.04 6,021,940.86 571,078.14 0.28 1,509.41 MWD+IFR2+MS+sag(3) 5,222.25 17.50 215.90 4,939.69 4,890.09 -1,271.36 -905.63 6,021,928.93 571,069.67 0.14 1,523.72 MWD+IFR2+MS+sag(4) 5,284.46 17.20 215.39 4,999.07 4,949.47 -1,286.43 -916.44 6,021,913.75 571,059.00 0.54 1,541.84 MWD+IFR2+MS+sag(4) 5,347.45 17.20 215.26 5,059.24 5,009.64 -1,301.63 -927.21 6,021,898.45 571,048.38 0.06 1,560.01 MWD+IFR2+MS+sag(4) 5,410.52 16.82 214.93 5,119.55 5,069.95 -1,316.72 -937.82 6,021,883.25 571,037.92 0.62 1,578.00 MWD+IFR2+MS+sag(4) 5,473.14 18.59 217.12 5,179.20 5,129.60 -1,332.11 -949.03 6,021,867.76 571,026.86 3.02 1,596.63 MWD+IFR2+MS+sag(4) 5,536.00 18.68 216.82 5,238.77 5,189.17 -1,348.16 -961.11 6,021,851.60 571,014.94 0.21 1,616.34 MWD+IFR2+MS+sag(4) 5,599.00 18.37 215.85 5,298.50 5,248.90 -1,364.28 -972.97 6,021,835.36 571,003.23 0.69 1,635.94 MWD+IFR2+MS+sag(4) 5,661.64 18.18 215.91 5,357.98 5,308.38 -1,380.20 -984.49 6,021,819.34 570,991.88 0.30 1,655.15 MWD+IFR2+MS+sag(4) 5,725.00 18.01 215.98 5,418.21 5,368.61 -1,396.13 -996.04 6,021,803.30 570,980.48 0.27 1,674.39 MWD+IFR2+MS+sag(4) 5/102017 5:08:55PM Page 4 COMPASS 5000.1 Build 81 Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU 13-30 Project: Milne Point TVD Reference: MPB 30 As-Built @ 49.60usft(Innovation) Site: M Pt B Pad MD Reference: MPB 30 As-Built @ 49.60usft(Innovation) Well: MPU B-30 North Reference: True Wellbore: MPU B-30 PB1 Survey Calculation Method: Minimum Curvature Design: MPU B-30 P81 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi ND TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 5,787.77 17.70 216.01 5,477.96 5,428.36 -1,411.70 -1,007.35 6,021,787.62 570,969.32 0.49 1,693.22 MWD+IFR2+MS+sag(4) 5,850.20 18.99 215.35 5,537.21 5,487.61 -1,427.66 -1,018.81 6,021,771.55 570,958.02 2.09 1,712.41 MWD+IFR2+MS+sag(4) 5,913.45 18.82 215.33 5,597.05 5,547.45 -1,444.38 -1,030.66 6,021,754.72 570,946.33 0.27 1,732.41 MWD+IFR2+MS+sag(4) 5,976.28 18.43 214.23 5,656.59 5,606.99 -1,460.86 -1,042.11 6,021,738.13 570,935.04 0.84 1,751.94 MWD+IFR2+MS+sag(4) 6,039.26 17.97 213.63 5,716.42 5,666.82 -1,477.18 -1,053.09 6,021,721.71 570,924.22 0.79 1,771.02 MWD+IFR2+MS+sag(4) 6,102.27 19.96 216.28 5,776.01 5,726.41 -1,493.95 -1,064,84 6,021,704.83 570,912.64 3.44 1,790.97 MWD+IFR2+MS+sag(4) 6,164.96 20.04 217.81 5,834.92 5,785.32 -1,511.06 -1,077.75 6,021,687.60 570,899.89 0.84 1,812.02 MWD+IFR2+MS+sag(4) 6,227.77 19.74 217.19 5,893.98 5,844.38 -1,528.01 -1,090.76 6,021,670.52 570,887.04 0.58 1,833.03 MWD+IFR2+MS+sag(4) 6,290.76 19.31 215.77 5,953.35 5,903.75 -1,544.93 -1,103.28 6,021,653.48 570,874.69 1.02 1,853.66 MWD+IFR2+MS+sag(4) 6,353.77 19.07 216.14 6,012.86 5,963.26 -1,561.70 -1,115.44 6,021,636.60 570,862.70 0.43 1,873.92 MWD+IFR2+MS+sag(4) 6,416.48 18.81 214.89 6,072.17 6,022.57 -1,578.27 -1,127.27 6,021,619.92 570,851.03 0,77 1,893.79 MWD+IFR2+MS+sag(4) 6,479.27 18.42 214.74 6,131.68 6,082.08 -1,594.72 -1,138.71 6,021,603.35 570,839.75 0.63 1,913.30 MWD+IFR2+MS+sag(4) 6,542.15 18.13 214.91 6,191.38 6,141.78 -1,610.91 -1,149.97 6,021,587.06 570,828.65 0.47 1,932.50 MWD+IFR2+MS+sag(4) 6,604.85 17.62 217.92 6,251.06 6,201.46 -1,626.39 -1,161.38 6,021,571.47 570,817.38 1.68 1,951.35 MWD+IFR2+MS+sag(4) 6,667.94 17.30 217.41 6,311.24 8,261.64 -1,641.38 -1,172.95 6,021,556.37 570,805.96 0.56 1,969.97 MWD+IFR2+MS+sag(4) 6,731.77 18.23 • 220.68 6,372.03 6,322.43 -1,656.49 -1,185.23 6,021,541.15 570,793.84 2.14 1,989.20 MWD+IFR2+MS+sag(4) 6,794.23 18.19 221.80 6,431.36 6,381.76 -1,671.17 -1,198.09 6,021,526.35 570,781.11 0.56 2,008.58 MWD+IFR2+MS+sag(4) 6,856.90 18.17 216.87 6,490.91 6,441.31 -1,686.28 -1,210.48 6,021,511.12 570,768.88 2.45 2,027.90 MWD+IFR2+MS+sag(4) 6,919.62 17.84 217.30 6,550.55 6,500.95 -1,701.74 -1,222.16 6,021,495.54 570,757.34 0.57 2,046.93 MWD+IFR2+MS+sag(4) 6,982.08 17,55 218.13 6,610.06 6,560.46 -1,716.76 -1,233.78 6,021,480.41 570,745.87 0.62 2,065.61 MWD+IFR2+MS+sag(4) 7,045.19 18.91 216.33 6,670.00 6,620.40 -1,732.48 -1,245.71 6,021,464.58 570,734.09 2.33 2,085.00 MWD+IFR2+MS+sag(4) 7,107.88 18.88 217.75 6,729.31 6,679.71 -1,748.69 -1,257.94 6,021,448.26 570,722.02 0.74 2,104.93 MWD+IFR2+MS+sag(4) 7,169.50 19.48 220.69 6,787.51 6,737.91 -1,764.36 -1,270.74 6,021,432.46 570,709.38 1.85 2,124.93 MWD+IFR2+MS+sag(4) 7,232.66 20.26 231.11 6,846.93 6,797.33 -1,779.22 -1,286.12 6,021,417.46 570,694.14 5.73 2,146.31 MWD+IFR2+MS+sag(4) 7,296.81 21.06 242.27 6,906.98 6,857.38 -1,791.56 -1,304.98 6,021,404.94 570,675.40 6.25 2,168.58 MWD+IFR2+MS+sag(4) 7,359.48 20.59 249.21 6,965.56 6,915.96 -1,800.71 -1,325.25 6,021,395.59 570,655.22 4.01 2,189.77 MWD+IFR2+MS+sag(4) 7,422.88 20.60 255.92 7,024.92 6,975.32 -1,807.38 -1,346.50 6,021,388.71 570,634.05 3,72 2,210.02 MWD+IFR2+MS+sag(4) 7,485.72 20.82 258.28 7,083.70 7,034.10 -1,812.34 -1,368.15 6,021,383.55 570,612.44 1.37 2,229.43 MWD+IFR2+MS+sag(4) 7,548.72 21.49 259.45 7,142.46 7,092.86 -1,816.73 -1,390.46 6,021,378.95 570,590.18 1.26 2,248.94 MWD+IFR2+MS+sag(4) 7,611.48 22.96 259.06 7,200.55 7,150.95 -1,821.16 -1,413.78 6,021,374.29 570,566.90 2.35 2,269.24 MWD+IFR2+MS+sag(4) 7,674.52 23.02 259.07 7,258.58 7,208.98 -1,825.83 -1,437.96 6,021,369.39 570,542.78 0.10 2,290.33 MWD+IFR2+MS+sag(4) 7,737.79 22.39 259.03 7,316.95 7,267.35 -1,830.46 -1,461.93 6,021,364.52 570,518.85 1.00 2,311.25 MWD+IFR2+MS+sag(4) 7,799.23 21.91 258.96 7,373.86 7,324.26 -1,834.89 -1,484.67 6,021,359.88 570,496.16 0.78 2,331.11 MWD+IFR2+MS+sag(4) 7,862.81 22.73 262.07 7,432.67 7,383.07 -1,838.85 -1,508.48 6,021,355.68 570,472.39 2.26 2,351.45 MWD+IFR2+MS+sag(4) 7,925.46 22,39 262.73 7,490.53 7,440.93 -1,842.03 -1,532.31 6,021,352.27 570,448.60 0.68 2,371.29 MWD+IFR2+MS+sag(4) 7,988.77 21.88 262.12 7,549.17 7,499.57 -1,845.18 -1,555.95 6,021,348.90 570,424.99 0.88 2,390.96 MWD+IFR2+MS+sag(4) 8,051.66 21.36 261.73 7,607.64 7,558.04 -1,848.43 -1,578.90 6,021,345.43 570,402.08 0.86 2,410.19 MWD+IFR2+MS+sag(4) 8,114.11 22.56 261.83 7,665.56 7,615.96 -1,851.77 -1,602.01 6,021,341.86 570,379.00 1.92 2,429.60 MWD+IFR2+MS+sag(4) 8,177.21 23.04 262.83 7,723.73 7,674.13 -1,855.03 -1,626.24 6,021,338.37 570,354.80 0.98 2,449.79 MWD+IFR2+MS+sag(4) 8,240.50 22.78 263.47 7,782.02 7,732.42 -1,857.97 -1,650.70 6,021,335.19 570,330.37 0.57 2,469.94 MWD+IFR2+MS+sag(4) 5/102017 5:08:55PM Page 5 COMPASS 5000.1 Build 81 41110 r Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-30 Project: Milne Point TVD Reference: MPB 30 As-Built @ 49.60usft(Innovation) Site: M Pt B Pad MD Reference: MPB 30 As-Built @ 49.60usft(Innovation) Well: MPU B-30 North Reference: True Wellbore: MPU B-30 PB1 Survey Calculation Method: Minimum Curvature Design: MPU B-30 PB1 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,303.10 22.47 262.21 7,839.81 7,790.21 -1,860.97 -1,674.60 6,021,331.96 570,306.51 0.92 2,489.70 MWD+IFR2+MS+sag(4) 8,366.05 23.79 265.18 7,897.70 7,848.10 -1,863.67 -1,699.17 6,021,329.03 570,281.97 2.80 2,509.76 MWD+IFR2+MS+sag(4) 8,429.20 23.76 264.66 7,955.49 7,905.89 -1,865.92 -1,724.53 6,021,326.53 570,256.64 0.34 2,530.12 MWD+IFR2+MS+sag(4) 8,491.98 23.09 265.14 8,013.09 7,963.49 -1,868.14 -1,749.39 6,021,324.07 570,231.80 1.11 2,550.08 MWD+IFR2+MS+sag(4) 8,554.66 22.40 264.64 8,070.90 8,021.30 -1,870.30 -1,773.52 6,021,321.68 570,207.69 1.14 2,569.46 MWD+IFR2+MS+sag(4) 8,617.64 21.75 264.65 8,129.26 8,079.66 -1,872.51 -1,797.09 6,021,319.24 570,184.15 1.03 2,588.45 MWD+IFR2+MS+sag(4) 8,680.64 21.21 263.71 8,187.89 8,138.29 -1,874.84 -1,820.04 6,021,316.68 570,161.22 1.02 2,607.07 MW0+IFR2+MS+sag(4) 8,744.06 21.99 260.07 8,246.86 8,197.26 -1,878.15 -1,843.14 6,021,313.16 570,138.16 2.44 2,626.45 MWD+IFR2+MS+sag(4) 8,806.78 21,73 260.56 8,305.07 8,255.47 -1,882.08 -1,866.16 6,021,309.01 570,115.18 0.51 2,646.18 MWD+IFR2+MS+sag(4) 8,869.71 21.16 260.36 8,363.64 8,314.04 -1,885.89 -1,888.85 6,021,304.97 570,092.53 0.91 2,665.59 MWD+IFR2+MS+sag(4) 8,932.87 21.54 259.48 8,422.46 8,372.86 -1,889.92 -1,911.49 6,021,300.73 570,069.93 0.79 2,685.11 MWD+IFR2+MS+sag(4) 8,995.46 21.31 258.92 8,480.73 8,431.13 -1,894.20 -1,933.94 6,021,296.23, 570,047.52 0.49 2,704.67 MWD+IFR2+MS+sag(4) 9,058.73 20,52 259.46 8,539.83 8,490.23 -1,898.44 -1,956.13 6,021,291.78 570,025.38 1.29 2,723.99 MWD+IFR2+MS+sag(4) 9,121.29 19.72 258.31 8,598.57 8,548.97 -1,902.58 -1,977.25 6,021,287.43 570,004.31 1.43 2,742.46 MWD+IFR2+MS+sag(4) 9,184.07 18.82 260.33 8,657.83 8,608.23 -1,906.43 -1,997.60 6,021,283.39 569,983.99 1.78 2,760.16 MWD+IFR2+MS+sag(4) 9,246.51 20.31 260.31 8,716.67 8,667.07 -1,909.94 -2,018.21 6,021,279.67 569,963.42 2.39 2,777.83 MWD+IFR2+MS+sag(4) 9,309.50 19.65 260.51 8,775.87 8,726.27 -1,913.53 -2,039.43 6,021,275.88 569,942.23 1.05 2,796.00 MWD+IFR2+MS+sag(4) 9,372.55 18.89 262.08 8,835.38 8,785.78 -1,916.69 -2,060.00 6,021,272.53 569,921.70 1.46 2,813.39 MWD+IFR2+MS+sag(4) 9,435.30 18.13 261.13 8,894.89 8,845.29 -1,919.59 -2,079.71 6,021,269.43 569,902.03 1.30 2,829.98 MWD+IFR2+MS+sa9(4) 9,498.51 17.86 261.20 , 8,955.01 8,905.41 -1,922.59 -2,099.00 6,021,266.25 569,882.76 0.43 2,846.33 MWD+IFR2+MS+sag(4) 9,561.28 17.33 261.66 9,014.84 8,965.24 -1,925.42 -2,117.77 6,021,263.24 569,864.03 0.87 2,862.16 MWD+IFR2+MS+sag(4) 9,607.32 16.87 262.06 9,058.84 9,009.24 -1,927.34 -2,131.17 6,021,261.19 569,850.65 1.03 2,873.40 MWD+IFR2+MS+sag(4) 9,650.00 16.87 262.06 9,099.69 9,050.09 -1,929.05 -2,143.43 6,021,259.36 569,838.40 0.00 2,883.67 PROJECTED to TD benjamin.hand@halliburton.com Checked By: Mitchell L aird Approved By: 2017.05.1016:12:21-08'00' Date: 5/10/2017 5/10/2017 5:08:55PM Page 6 COMPASS 5000.1 Build 81 • Hilcorp Energy Company • CASING&CEMENTING REPORT Lease&Well No. MP B-30 Date Run 10-Apr-17 County State Alaska Supv. S.Sunderland/D.Yessak CASING RECORD Surface t TD 5220.W Shoe Depth: 5215.00 PBTD: 5,127.32 No.Jts.Delivered 132 No.Jts.Run 126 No.Jts.Returned 6 Ftg.Delivered 5,460.42 Ftg.Run 5,212.71 Ftg.Returned 247.71 Length Measurements W/O Threads Ftg.Cut Jt. 32.83 Ftg.Balance RKB 26.00 RKB to BHF 22.53 RKB to CHF 26.36 RKB to THF Casing(Or Liner)Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top Shoe 97/8 40.0 1-80 DWC/C 2.31 5,215.00 5,212.69 1 Shoe 1T 9 5/8 40.0 1-80 DWC/C- 42.46 5,212.69 5,170.23 Float Collar 97/8 40.0 L-80 DWC/C 1.74 5,170.23 5,168.49 2 Float JT 95/8 _ 40.0 L-80 DWC/C 39.56 5,168.49 5,128.93 BFL Adapter 97/8 _ 40.0 L-80 DWC/C 1.61 5,128.93 5,127.32 3 BFL Adapter.11. 95/8 40.0 L-80 DWC/C 41.45 5,127.32 5,085.87 82 Casing 95/8 40.0 L-80 DWC/C 3,263.41 5,085.87 1,822.46 Stage Tool 9 7/8 40.0 L-80 DWC/C 3.11 1,822.46 1,819.35 125 Casing 95/8 40.0 L-80 DWC/C 1,786.03 1,819.35 33.32 Cut it 9 5/8 40.0 L-80 DWC/C 6.97 33.32 26.35 RKB 26.35 26.35 0 Csg Wt.On Hook: 200 Type Float Collar: PES No.Hrs to Run: Csg Wt.On Slips: 100 Type of Shoe: PES Casing Crew: WOT Rotate Csg Yes X No Recip Csg X Yes No 15 Ft.Min. 9.6 PPG Fluid Description: Spud Mud Liner hanger Info(Make/Model): Liner top Packer?: _Yes X No Liner hanger test pressure: _ Floats Held X Yes_ No Centralizer Placement: CEMENTING REPORT Shoe @ 5215 FC @ 5,168.49 Top of Liner Preflush(Spacer) Type: Spacer Density(ppg) 10.5 Volume pumped(BBLs) 60 Lead Slurry f Type: Exlenda Cern Sacks: 505 Yield: 2.47 Density(ppg) 11.7 Volume pumped(BBLs) 221 Miorng/Pumping Rate(bpm): 5 L Tail Slurry S S a Type: Swig Cem Sacks: 215 ' Yield: 1.16 IF Density(ppg) 15.8 Volume pumped(BBLs) 44.3 Mi:dng/Pumping Rate(bpm): 3 N Post Flush(Spacer) STpt Pe Type: LL Densly(ppg) Rate(bpm): Volume: Displacement: Type: Mud Density(ppg) 9.6 Rate(bpm): 5 Volume(actual/calculated): 388.6/388.6 FCP(psi): 800 Pump used for disp: Rig Bump Plug? X Yes No Bump press 1300 Casing Rotated? Yes X No Reciprocated? X Yes_No %Returns during job 100 Cement returns to surface? X Yes_No Spacer returns? X Yes No Vol to Surf: 66 Cement In Place At: 12:30 Date: 4/11/2017 Estimated TOC: 1,820 Method Used To Determine TOC: Cmt to surface from stag tool @ 1820' ......-- Stage ,/Stage Collar@ 1819.35 Type HES Closure OK Y Preflush(Spacer) Type: Spacer Density(ppg) 10.5 Volume pumped(BBLs) 60 Lead Slurry Type: Penn L Sacks: 350 Yield: 4.33 Density(ppg) 10.7 Volume pumped(BBLs) 270 Mbdng/Pumping Rate(bpm): 4.8 a C. Tail Slurry Y L Type: Swift Cem Sacks: 275 Yield: 1.16 w Density(ppg) 15.8 Volume pumped(BBLs) 56.6 Mbdng/Pumping Rate(bpm): 3 pa z Post Flush(Spacer) 8 Type: Density(ppg) Rate(bpm): Volume: 51 tu at Displacement: Type: Mud Density(ppg) 9.6 Rate(bpm): 4 Volume(actual/calculated): 137.2/138.3 FCP(psi): 430 Pump used for disp: Rig Bump Plug? X Yes No Bump press 1730 Casing Rotated? Yes X No Reciprocated? Yes X No %Returns during job 100 Cement returns to surface? X Yes_No Spacer returns? X Yes No Vol to Surf: 177 Cement In Place At: 23:30 Date: 4/11/2017 Estimated TOC: 0 Method Used To Determine TOC: Cement to surface Post Job Calculations: Calculated Cmt Vol(fp 0%excess: 313.7 Total Volume cmt Pumped: 591 Cmt returned to surface: 243 Calculated cement left in wellbore: 348 OH volume Calculated: 285 OH volume actual: 314 Actual%Washout: WELLHEAD Make Sea Board Type Multi bowl Serial No. Size 11 W.P. 5000 Test head to 2450 PSIG 15 MIN x OK Remarks: www.wellez.net WellEZ Information Management LLC ver_102716bf • Hllcorp Energy Company • CASING&CEMENTING REPORT Lease&Well No. MP B-30 Date Run 10-May-17 County State Alaska Supv. J.Lott/D.Yessak CASING RECORD Production 41 TD 9,620.00 Shoe Depth: 9,605.00 PBTD: 9,515.00 No.Jts.Delivered 244 No.Jts.Run 231 No.Jts.Returned 12 Ftg.Delivered 10,058.07 Ftg.Run 9,549.84 Ftg.Returned 508.23 Length Measurements W/O Threads Ftg.Cut Jt. 12.10 Ftg.Balance 496.13 RKB 28.00 RKB to BHF 22.53 RKB to CHF RKB to THF Casing(Or Liner)Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top Reamer Shoe 7 3/4 26.0 L-80 Hyd 563 BOT 3.60 9,605.00 9,601.40 1 Shoe JT 7 26.0 L-80 Hyd 563 TSA 41.50 9,601.40 9,559.90 Float Collar 7 5/8 26.0 L-80 Hyd 563 DHP 2.65 9,559.90 9,557.25 2 Float its 7 26.0 L-80 Hyd 563 TSA 83.03 9,557.25 9,474.22 Baffle Adapt 75/8 26.0 L-80 Hyd 563 HES 2.15 9,474.22 9,472.07 Li- 48 48 Casing jt 7 26.0 L-80 Hyd 563 TSA 1,858.80 9,472.07 7,613.27 / r� Csg Pup 7 26.0 L-80 Hyd 563 TSA 9.10 7,613.27 7,604.17 J!'�4 /'.j f I Stage Tool 7 3/4 26.0 L-80 Hyd 563 HES 3.88 7,604.17 7,600.29 "'---- 1` c4t Csg Pup 7 26.0 L-80 Hyd 563 TSA 9.95 7,600.29 7,590.34 W 230 Csg jt 7 26.0 L-80 Hyd 563 TSA 7,536.92 7,590.34 53.42 Cut it 7 26.0 L-80 Hyd 563 TSA 29.59 53.42 23.83 RKB 23.83 0 Csg Wt.On Hook: 220 Type Float Collar: DHP No.Hrs to Run: 48 Csg Wt.On Slips: 140 Type of Shoe: BOT Reamer Casing Crew: Doyon Rotate Csg X Yes No Recip Csg X Yes_ No 10 Ft Min. 10.7 PPG Fluid Description: MUD Liner hanger Info(Make/Model): Liner top Packer?: _Yes _No Liner hanger test pressure: Floats Held X Yes_ No Centralizer Placement: 1©10'up each end of Shoe Jt, 1 mid joint on both float joints. 1 every joint to 6596'. 4 from 5312'to 5146' Total of 77 Bow spring ran. CEMENTING REPORT Shoe @ 9605 FC @ 9,557.00 Top of Liner Preflush(Spacer) Type: Tuned Spacer III Density(ppg) 12 Volume pumped(BBLs) 27.6 Lead Slurry Type: Class G Sacks: 165 Yield: 1.63 Density(ppg) 15.3 Volume pumped(BBLs) 49.3 Mixing/Pumping Rate(bpm): 4 Tail Slurry w Type: Sacks: Yield: li Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): 2 Post Flush(Spacer) rc Type: Density(ppg) Rate(bpm): Volume: LL Displacement: Type: Mud Density(ppg) 10.7 Rate(bpm): 5 Volume(actual/calculated): 363.3/363.3 FCP(psi): 640 Pump used for disp: Rig Bump Plug? X Yes No Bump press 1100 Casing Rotated? X Yes No Reciprocated? X Yes No %Returns during job 95 R`y 'r6 ' Cement returns to surface? Yes X No Spacer returns? X Yes No Vol to Surf: 0 F;',.-FJ 'r &CD Cement In Place At: 19:00 Date: 5/9/2017 Estimated TOC: 8,130 . s . O0 Method Used To Determine TOC: Calculation Stage Collar @ 7600 Type HES Closure OK y Preflush(Spacer) , Type: Tunned Spacer III Density(ppg) 12 Volume pumped(BBLs) 30 Lead Slurry ,n,,CA Type: ClassG Sacks: 119 Yield: 1.36 .5,L [j; t Density(ppg) 14.7 Volume pumped(BBLs) 28.9 Mixing/Pumping Rate(bpm): 4.5 �-{/ 1"a Tail Slurry -q Type: Sacks: Yield: 14.4 OC, N Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): H z Post Flush(Spacer) 8 Type: Density(ppg) Rate(bpm): Volume: w m Displacement: Type: Mud Density(ppg) 10.7 Rate(bpm): 4 Volume(actual/calculated): 28.9/19.3 FCP(psi): 700 Pump used for disp: Rig Bump Plug? X Yes No Bump press 2078 Casing Rotated? Yes X No Reciprocated? Yes X No %Returns during job 100 Cement returns to surface? Yes X No Spacer returns? Yes X No Vol to Surf: 0 .N.:. Cement In Place At: 6:00 Date: 5/10/2017 Estimated TOC: 6,304 �,- G 4,1,r-- Method Used To Determine TOC: Calculation ✓e.., 4R1 Post Job Calculations: W Calculated Cmt Vol @ 0%excess: 38.2 Total Volume cmt Pumped: 78.2 L s ErA-4 6 Cmt returned to surface: 0 Calculated cement left in wellbore: 78.2 OH volume Calculated: 52.67 OH volume actual: 52.67 Actual%Washout: www.wellez.net WellEz Information Management LLC ver_102716bf y4," lc's"i7 • • MPB-30 Days vs Depth 0 l l -MPB-30 Plan 500 -MPB-30 Actual 1000 1500 2000 2500 3000 3500 i 4000 j $ 4500 s aai 5000 v 15500 - h m v ii 6000 6500 ' 7000 . A 7500 8000 8500 9000 9500 10000 10500 1 0 5 10 15 20 25 30 35 40 45 Days 6/29/2017 • • 1 U) . ,, c a) E 0 CX.i t ....... ...Agort"-- ** co o U XN U(O 0) S NNrNcc IT o 8U• �. C N • > 2 ci t �\ 10) Cl.* Of: 1 "''' U C o V @ U N *k O o Tu vs... Q c6. upm o -05I 6 « U a N Zi X N- r CO O 0 O O O N- Q O 0) O "'E' T Q r — O J CO co O N V 00 C 0)S O O U O Z Z a) C D O J V 6) Q o0 O ) . 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O \C) j\ fEb ® ti co\C' \\ \- � \\ 38 \ ELo - %2/ § \ 2g ,} TD ± / s \ 1\ E ¢ 2 ; }\\ 00 . . ; z. • Scn a Berger Client:Hilcorp Alaska Well:MPB-30 Formation:Sag River District:Prudhoe Bay Country:United States Section 3: Propped Frac: As Measured Pump Schedule As Measured Pump Schedule Slurry Slurry Fluid Max Prop Prop Prop ' Step Pump Time Step Name Volume Rate Fluid Name Volume Proppant Name Cone Conc Mass # (bbl) (bbl/min) (min) (gal) (PPA) (PPA) (lb) 1 PAD 499.8 29.7 17 YF130FIexD 20970 0 0 0 2 1.0 PPA 60 29.6 2 YF130FIexD 2435 16/20 CarboBond Lite 1 0.1 1829 3 2.0 PPA 61.3 29.5 2.1 YF130FIexD 2326 16/20 CarboBond Lite 2.8 1 5297 4 3.0 PPA 61.2 29.6 2.1 YF130FIexD 2222 16/20 CarboBond Lite 3.9 0.8 7543 5 4.0 PPA 61.2 29.5 2.1 YF130FIexD 2133 16/20 CarboBond Lite 4.9 3.4 9388 6 5.0 PPA 61.1 29.3 2.1 YF130FIexD 2054 16/20 CarboBond Lite 5.9 2.3 11067 7 6.0 PPA 61.1 29.5 2.1 YF130FIexD 1977 16/20 CarboBond Lite 6.9 0.2 12682 8 7.0 PPA 61 29.5 2.1 YF130FIexD 1910 16/20 CarboBond Lite 7.8 5.3 14109 9 8.0 PPA 61 29.4 2.1 YF130FIexD 1844 16/20 CarboBond Lite 8.9 0.6 15476 10 9.0 PPA 60 29.5 2 YF130FIexD 1778 16/20 CarboBond Lite 9.1 1 16008 11 10.0 PPA 60 27.6 2.2 YF130FIexD 1794 16/20 CarboBond Lite 12 5.8 15929 12 11.0 PPA 21.7 20.3 0.8 YF130FIexD 912 16/20 CarboBond Lite 11 0 33 13 Flush 11.6 14.3 2.4 WF130 488 0.1 0 0 Stage Pressures & Rates Average Slurry Maximum Slurry Average Treating Maximum Treating Minimum Treating Step# Step Name Rate Rate Pressure Pressure Pressure (bbl/min) (bbl/min) (psi) (psi) (psi) 1 PAD 29.7 30.4 3315 3547 1012 2 1.0 PPA 29.6 30.0 3524 3552 3483 3 2.0 PPA 29.5 29.7 3416 3487 3310 4 3.0 PPA 29.6 29.8 3200 3312 3123 5 4.0 PPA 29.5 29.7 3077 3119 3049 6 5.0 PPA 29.3 29.6 3059 3066 3047 7 6.0 PPA 29.5 29.7 3073 3086 3061 8 7.0 PPA 29.5 29.7 3108 3134 3081 9 8.0 PPA 29.4 29.7 3169 3211 3134 10 9.0 PPA 29.5 29.7 3248 3306 3206 11 10.0 PPA 27.6 29.6 3729 5194 3306 12 11.0 PPA 20.3 20.4 3530 3537 3527 13 Flush 14.3 21.1 4863 6662 3345 As Measured Totals Slurry Pump Time Clean Fluid Proppant )bbl) (min) (gal) (Ib) 1141.0 40.9 42852 109362 Average Treating Pressure: 3315 psi Maximum Treating Pressure: 6662 psi Minimum Treating Pressure: 1012 psi Average Injection Rate: 29.1 bbl/min Maximum Injection Rate: 30.4 bbl/min Average Horsepower: 2351.5 hhp Maximum Horsepower: 3577.3 hhp Maximum Prop Concentration: 12.0 PPA y OF 7•4 "s., THE STATE Alaska Oil and Gas Of�T AConservation Commission SKA 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OF L Fax: 907.276.7542 www.aogcc.alaska.gov Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage,AK 99503 Re: Milne Point Field, Sag River Oil Pool, MPU B-30 Permit to Drill Number: 216-153 Sundry Number: 317-206 Dear Mr. York: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, P Cathy . Foerster Chair DATED this Z5 day of May, 2017. RBDMS UV P ", 3 0 2017 • • RECEIVED MAY 22 '2017 STATE OF ALASKA iirS Si 2-51 t ALASKA OIL AND GAS CONSERVATION COMMISSION OG APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend 1:1Perforate ❑ Other Stimulate ❑ C�A Si+��Bull Tubing Q Change Approved Program 0 G:ks Li-r Plug for Redrill El Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Complete ❑✓ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: q; r- i4tc. \ Hilcorp Alaska LLC Exploratory 0 Development Q• 216-153 • C r J 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage Alaska 99503 50-029-23571-00-00 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 423 Will planned perforations require a spacing exception? Yes ❑ No 0 / Milne Pt Unit B-30 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL047438/ADL047437.. Milne Point/Sag River Oil. 11. PRESENT WELL CONDITION SUMMARY Total DepthMD(ft): Total Depth TTVD(ft): EffectivElEslept iMD: Effective De th rVD: MPSP(psi): Plugs(MD): Junk(MD): 18,962 +a�1n A 3,478 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 106' 20" 106' 106' N/A N/A Surface 5,220' 9-5/8" 5,220' 4,983' 5,750psi 3,090psi Production 9,605• 7" 9,605' 9,057' 7,240psi 5,410psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 4-1/2" 12.6#/L-80 1Cr/Vam Top 9,400 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Baker 7"x 4-1/2"Premier and N/A , 9,296'MD/8,763 and N/A 12.Attachments: Proposal Summary ❑✓ Wellbore schematic 0 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: Commencing6/2/2017 D Operations: OIL Di WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown 0 Abandoned 0 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. <¢ yn� Authorized Name: Bo York Contact Name: Stan Porhola .-..._)—r. Authorized Title: Operations Manager Contact Email: sporholaCa�hilcorp.com _ Contact Phone: 777-8412 Authorized Signature: � rrZ Date: 5/19/2017 Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31-7- 2_0 4. Plug Integrity ❑ BOP Test 21 Mechanical Integrity Test 0 Location Clearance ❑ uSF- S 12_3 (3 Other: v '/vas) ®5. cif e,.r•f`" Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ Nod Subsequent Form Required: � <_, 3/_...90,c4.1lam`_ 1© RBDMS LL- Approved � 0 2017 APPROVED BY Approved by: (Lie-- COMMISSIONER THE COMMISSION Date: S -ZS.- (7 jdadi /0 J/74///7 ORIGINAL Submit Form and Form 10-403 R vised 4/2017 Approved application is valid for 12 months from the date of approval. Attachments in Duplicate 41111 Well Prognosis Well: MPU B-30 Hilcora Alaska,LU Date:5/17/2017 Well Name: MPU B-30 API Number: 50-029-23571-00 Current Status: Oil Well (New Well) Pad: B-Pad Estimated Start Date: June 2"d, 2017 Rig: ASR#1 Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 216-153 (revised) First Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Second Call Engineer: Paul Chan (907) 777-8333 (0) (907)444-2881 (M) AFE Number "; 41 16125570 , , Job,Type; Recompletion Current Bottom Hole Pressure: 0 psi @ 8,926' TVD (Not Perforated) Maximum Expected BHP: 4,409 psi @ 8,926' TVD (Estimated BHP/9.50 ppg EMW) MPSP: 3,516 psi (0.1 psi/ft gas gradient) Brief Well Summary: The Milne Point B-30 well was drilled as a Sag River development well.The initial 4-1/2" completion was ran by the Innovation#1 rig.The well is currently waiting to be perforated thru tubing,then fracture stimulated. Notes Regarding Wellbore Condition N.1 r� • Casing last tested to 3,750 psi for 30 min down to 9,296' on 5/15/2017. • Max angle is 25.1° @ 8,467' MD. • Deviation at the perfs is 12.0°. • 7"x 4-1/2" Premier Packer to have mandrel cut pre-rig to allow for packer removal with the rig. (,4s'je lj Objective: The purpose of this vrork is to install a 2-7/8" gaslift completion string after the initial flowback following the fracture stimulation. The well is estimated to be fracture stimulated in late May 2017 and flowed back for approximately 2 weeks. The smaller tubing and gaslift string will allow for the use of artificial lift on the well to provide stable production. Pre-Rig Procedure: 1. RU E-line.Test lubricator to 250/4,000 psi. 2. RIH w/mechanical cutter.Correlate across packer w/GR/CCL. c44 3. Make cut across packer to allow Baker Premier Packer mandrel to release (will allow packer to be Pic retrieved with straight-pull). 4'• 4. POOH. 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 9.5-9.8 ppg brine down tubing, taking returns up casing to 500 bbl returns tank. 10. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 McOH or diesel. 11. RD Little Red Services and reverse out skid. • Well Prognosis Well: MPU B-30 Hikorp Alaska,LL' Date:5/17/2017 12. RU crane. Set BPV. ND Tree. NU 11" BOPE. RD Crane. 13. NU BOPE house. Spot mud boat. Brief RWO Procedure: 14. MIRU Hilcorp ASR#1 WO Rig, ancillary equipment and lines to 500 bbl returns tank. 15. PU Casing Jacks via the beaver slide and Tugger winches to rig floor. 16. Set Casing Jacks on top of the BOP Annular with Tugger winches. Connect hydraulics and function test same. 17. 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/9.5-9.8 ppg brine prior to pulling BPV. Set TWC. ,,� 18. Test BOPE to 250 psi Low/4,000_psi Highannular to 250 psi Low/2,500 psi High (hold each i2. ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. /6"4( 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 4-1/2"test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 19. 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.) cl 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. kd 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. 20. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/9.5-9.8 ppg brine as needed. 21. Casing Jack RU Procedure. a. RU Casing Jack hydraulics to the ASR#1 Control Panel. ��S I do b. Yield strength of 4-1/2" 12.6# L-80 1Cr Vam Top=288,000 lbs. c. PU weight of string= 122,000lbs (Innovation#1 in May 2017). d. Cycle jacks up and down to ensure proper function (dry run without being connected to the tubing hanger). 22. MU landing joint or spear to the tubing hanger. BOLDS. 23. Set Casing Jack pressure to 1,080 psi (122,000 lbs). Slowly pressure up on jacks. Hold for 5 min. A • II Well Prognosis Well: MPU B-30 Flileorp Alaska,LL) Date:5/17/2017 24. If tubing hanger does not unseat or packer does not release, increase in 100 psi increments holding for 5 min between pressure increases. DO NOT EXCEED 2,038 psi (230,000 lbs). If unable to release tubing hanger, contact Ops Engineer for further discussion. 25. Once hanger and packer comes free, 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. 26. Once the tubing hanger is laid down and the packer is unset and moving uphole, set tubing in the lower slips, retract Casing Jacks into lowered position and swap to `Carriage mode'. 27. Contingency: If the packer will not release. a. RU E-line.Test lubricator to 250/4,000 psi. b. RIH w/chemical cutter. Correlate across packer w/GR/CCL. ,� Jf c. Make cut across packer to release Baker Premier Packer. /2. �'- '"` � � d. POOH. RD E-line. N�_el , 28. POOH and lay down the 4-1/2"tubing and completion jewelry. Rig down Casing Jacks. a. Send 4-1/2"Vam Top tubing in for cleaning and store with thread protectors. b. Send 4-1/2" Packer and pup w/RA tag to Baker Shop. c. Send 4-1/2"Jewelry to Halliburton Shop for re-dress. 29. Change out lower pipe rams from 4-1/2"to 2-7/8" pipe rams. 30. Test changed rams to 250 psi Low/4,000 psi High, annular to 250 psi Low/2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. 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"test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 31. PU new gaslift completion and RIH on 2-7/8" tubing. Set tubing tail at±9,400' MD. a. GLMs and jewelry spaced out per proposed schematic. 32. Land tubing hanger. RILDS. Note PU (Pick Up) and SO (Slack Off) weights on tally. l< , 3. Drop ball and rod. Pressure up and set Halliburton PHL packer(start 2,500 psi/final 4,000 psi). iN - rp34. Pressure up and test tubing to 4,000 psi for 30 min and chart. Bleed tubing to 0 psi. `P 35. Test inner annulus to 3 700 psi for 30 in and chart. Monitor tubingforpacker leaks. Bleed casing .� .�._.��.,...._..,._.r...� .� ®...._...r..-_azo to 0 psi. 36. Lay down landing joint. 37. Set BPV. Rig down ASR. Post-Rig Procedure: 38. RD mud boat. RD BOPE house. Move to next well location. 39. RU crane. ND BOPE. 40. NU new 2-9/16" 5,000#tree/adapter flange. Test tubing hanger void to 500 psi low/5,000 psi high. Pull BPV. 41. RD crane. Move 500 bbl returns tank and rig mats to next well location. i • Well Prognosis Well: MPU B-30 Hilcorp Alaska,LL+ Date:5/17/2017 42. Replace gauge(s) if removed. 43. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOPE Schematic w/Casing Jacks 4. Proposed Tree/Wellhead 5. Blank RWO MOC Form . H 0 • Milne Point Unit SCHEMATIC Well: MPU B-30 • Last Completed: 5/16/2017/ Hilcorp Alaska,LLC PTD: 216-153 KBEIev.:49.6'/GLEIev.:23.1' TREE&WELLHEAD RKB—THF:22.92'(Innovation) iiii,, Tree CIW 4-1/16"5M 14 '';,:l a i.4,-, Seaboard Weir,3 spools,w/11"x 5M top flange Wellhead 20" 4-1/2"TC-II Tubing Hanger OPEN HOLE/CEMENT DETAIL a,, 20" Cmt w/50 bbls of Arcticset in 42"Hole a* $Y` 9-5/8"(2nd Stage) Cmt w/350 sks 10.7 ppg Perm L,275 sx 15.8 ppg SwiftCEM in 12-1/4"Hole 6 9-5/8"(15t Stage) Cmt w/505 sks 11.7 ppg ExtendaCEM,215 sx 15.8 ppg SwiftCEM in 12-1/4"Hole ES Cementer 17"(2nd Stage) Cmt w/123 sks 14.7 ppg Class"G"in 8-1/2"Hole @1,819' S 7"(1st Stage) Cmt w/170 sks 15.3 ppg Class"G"in 8-1/2"Hole L CASING DETAIL 41 II Size Type Wt/Grade/Conn Drift ID Top Btm 1 20" Conductor 78.6/A-53/Weld 19.100" Surface 106' 9-5/8" 4 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 5,220' 7" Production 26/L-80/Hydril 563 6.151" Surface 9,605' �('4 TUBING DETAIL 4-1/2" Tubing 12.6/L-80 1Cr/Vam Top 3.833" Surface 9,400' TOC /r s,os0'MD WELL INCLINATION DETAIL a IIIJJJ CAST r KOP @ 600' MD 5/13/17 9 I,s.4,b�:;) Max Hole Angle=25.08 deg at 8,467' MD `' Hole angle through perforated interval: 12° JEWELRY DETAIL No Depth Drift ID Item FS Cementer• 5 1 23' 3.833" 11"x 4-1/2"Tubing Hanger(4-1/2"TC-II Top& Btm) @7,600' 2 9,180' 3.813" 4-1/2"XD Sliding Sleeve Min ID=3.813" (3 ports plugged) 3 9,236' 3.842" 4-1/2" ROC Pressure Intake Gauge Min ID=3.842" 4 9,296' 3.870" Baker 7"x 4-1/2" Premier Packer(598-387) Min ID=3.870" TOC 8,613a nm I s 5 9,355' 3.725" 4-1/2"XN Profile Min ID=3.725" 5/13/17CAS6 9,399' 3.833" 4-1/2"WLEG Btm @ 9,400' 111 2 , k:, PERFORATION DETAIL L 3 Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status RA Tag . ya 44 9,286' _ I I I �. 4 _ GENERAL WELL INFO trek API:50-029-23571-00-00 r"*, 5 Drilled and Cased by Innovation#1 5/16/2017 ,'i k,, 1 14 6 1 4: >Y: t C' +� tam.• i', 7" 4.,03 TD=9,620(MD)/TD=9,093'(TVD) PBTD=9,515'(MD)/PBTD=8,990'(TVD) Revised by:STP 5/16/17 • • • Milne Point Unit in • PROPOSED Well: MPU B-30 Last Completed: Proposed 'Ekon,Alaska,LLC PTD: 216 153 KBEIev.:49.6'/GLEIev.:23.1' TREE&WELLHEAD RKB—THF:22.92'(Innovation) Tree CIW 2-9/16"5M j ;,..?,.. ki 1 .4 ki Wellhead Seaboard Weir,3 spools,w/11"x 5M top flange 20" "' 2-7/8"TC-II Tubing Hanger II OPEN HOLE/CEMENT DETAIL 2 of 20" Cmt w/50 bbls of Arcticset in 42"Hole '' 9-5/8"(2"d Stage) Cmt w/350 sks 10.7 Perm L,275 sx 15.8n g ) ppgppg SwiftCEM in 12-1/4"Hole 0 3 'J 9-5/8"(1st Stage) Cmt w/505 sks 11.7 ppg ExtendaCEM,215 sx 15.8 ppg SwiftCEM in 12-1/4"Hole ES Cementer >a @1,819 7"(2nd Stage) Cmt w/123 sks 14.7 ppg Class"G"in 8-1/2"Hole 11 Z. 7"(1st Stage) Cmt w/170 sks 15.3 ppg Class"G"in 8-1/2"Hole 4 ,ti CASING DETAIL Size Type Wt/Grade/Conn Drift ID Top Btm 5 ,c„ 20" Conductor 78.6/A-53/Weld 19.100" Surface 106' 9-5/8" 1* II N' 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 5,220' 7" Production 26/L-80/Hydril 563 6.151" Surface 9,605' 6 TUBING DETAIL III 2-7/8" Tubing 6.4/13Cr-85/JFE Bear 2.441" Surface 9,400' TOC 6,050 MD 7 WELL INCLINATION DETAIL 5/13/1M7 KOP @ 600' MD PA 8 Max Hole Angle=25.08 deg at 8,467' MD Hole angle through perforated interval: 12° 9 JEWELRY DETAIL No Depth Drift ID Item ES Cementer 1 ±23' 3.833" 11"x 2-7/8"Tubing Hanger(2-7/8"TC-II Top&Btm) @7600 10 2 ±2,300' 2.347" 2-7/8" 13Cr GLM#10 li 3 ±3,475' 2.347" 2-7/8" 13Cr GLM#9 TOC 11 4 ±4,100' 2.347" 2-7/8" 13Cr GLM#8 5 ±4,750' 2.347" 2-7/8" 13Cr GLM#7 5/13/17 1 6 ±5,400' 2.347" 2-7/8" 13Cr GLM#6 11112 t, 7 ±6,000' 2.347" 2-7/8" 13Cr GLM#5 1.4 8 ±6,650' 2.347" 2-7/8" 13Cr GLM#4 13 • 9 ±7,300' 2.347" 2-7/8" 13Cr GLM#3 14 >! x,. v > 10 ±7,950' 2.347" 2-7/8" 13Cr GLM#2 ». I i 'i X 15 11 ±8,500' 2.347" 2-7/8" 13Cr GLM#1 I 12 ±9,180' 2.313" 2-7/8" 13Cr Sliding Sleeve ? 13 ±9,220' 2.347" 2-7/8" 13Cr Pressure Intake Gauge 16 14 ±9,280' 2.313" 2-7/8" 13Cr X Profile 15 ±9,3402.347" 7"x 2-7/8" 13Cr Hydraulic Retrievable Packer —' 17 16 ±9,370' 2.250" 2-7/8" 13Cr XN Profile 17 ±9,399' 2.347" 2-7/8" 13Cr WLEG Btm±9,400' SAG { -� PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status Sag River ±9,450' ±9,490' ±8,926' ±8,965' 40' Prop Prop t3-1/8"Perf Guns 7 GENERAL WELL INFO TD=9,620(MD)/TD=9,093'(TVD) API:50-029-23571-00-00 PBTD=9,515'(MD)/PBTD=8,990'(TVD) Drilled and Cased by Innovation#1 5/16/2017 Revised by:STP 5/17/17 . 11 • • Milne Point ASR 11" BOP w/ Jacks Ilac orn Alaska,LLC c 05/17/2017 11" BOPE t A slips , , -le LI , aik.,. alit ask _JOS-14 200 TON JACKING SYSTEM Slips 1 f fiJi ,mmm 6 • Shaffer • 11" - 5000 li€ 111 111111111 111 III Ill 111 111 27/8"-5"VBR 11 1111 ‘af 11v — 000 ��—�� ' fir- ' 2 Kill Lit?e 2"Choke Line III/ 1 I 1 1 1 1 1 1 1 III - ----. y r s ,tL ,1I1 111 Ili 111 III'11 Manual Manual Manual HCR - ,,n�, Pipe 11"7:000 h: 'or- -.. . „ - 41/2" Pipe iti'111 I!! ill ill POMP iii at tit iii I#1 Updated 5/17117 . 11 . • MPU B-30 • PROPOSED TREE/WELLHEAD Wellhead/Tree Hilcorp Alaska,LLC Milne Point Unit r WELL MPB-30 DATE 5/17/17 II PROPOSED Hilcorp Alaska, LLC ......10'Mgm, Swab valve Seaboard Tree Cap. Otis style " ;� 2 9/16" 5K 4'/�"ACME 2 9/16" 5K H 11*% 1 Wing valve Seaboard . '4. [ ,;k 2 9/16"5K imi i 10 0®0 0 0 �/ •_iP0 0 n 0000. SSV valve Seaboard MS t= 29/16" 5K C1 t Ili °g1 {;►. ' Master valve Seaboard I' 2 9/16"5K 4. Tbg Hgr,Seaboard SM- E-CL11x 4W'EUEBOX ., It' '?' API 11"5K top and bottom,4" "H" ) I BPV,ported for 2 ea 3/ B [-T.:,8 Control line, , 0 -41 ,w/3 pup L-U,DD-NL, PN W10220 _ l ' . API 13 5/6"5K SN . 11 x 7",SMB 22,8.54 stub l . • acme top x DWC box Csg Hgr,Seaboard [ l a oa j S-22 13 5/8 x 9 5/8" bottom,w/DWC-C pup, Slip type hanger ) � 6.844 bore PN A34330 LU,DD-NL PN A16232-001 SN i+s . • • c2CD _c I � k k � 2 / / 0 > as _ � > o / 0 R0. g 2 / « tea E• c o Q % CD it - a co / b < 2 E / E� a. $ § « m � 2 $ � 13 s- sn § k 22 o_ CU fl„) 0- ,=, CO _< � 11 a)\ C k sok Q @ // $ f £ 4 15 VD CD k o O C k 0 �k a) ( 2 — 7U / \ / 0 \ 9 � L. 2E § 2 a) 0 = a 2 0 20 / i a , - - CU -a / / Ui »k § % § / / .5) co G0 C 2 2 / - / \ o_ ( a 2 � � k 0 a k in 00 E cs 2 _� © 2 w ® CO 2 03 / f & 0 0 6 / a < 0 ' \ U T k Z U 0 0 > - .z acu 2 >.o a. co . . a 0 o Cl) Cl) \ 9 a. a. 110 4111 yOF ? 1)"1'�I vj,'� THE STATE Alaska Oil and Gas ti�;,-i��, fALASI�:A o Conservation Commission r _ _ 333 West Seventh Avenue 1 GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OF ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage,AK 99503 Re: Milne Point Field, Sag River Oil Pool, MPU B-30 Permit to Drill Number: 216-153 Sundry Number: 317-157 Dear Mr. York: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, P-);t4'&- Cathy P. Foerster Chair DATED this 1'day of May,2017. RBDMS L" MAY 2 4 2017 IP • RECEIVED APR 1 9 ? 17 STATE OF ALASKA �� S. �� ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOG 20 MC 25.280 1.Type of Request Abandon ❑ Plug Perforations❑ Fracture Stimulate 0 ` 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. 0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development Q -216-153 . 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage Alaska 99503 50-029-23571-00-00 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? C.O.423 ' Will planned perforations require a spacing exception? Yes ❑ No Q J Milne Pt Unit B-30 . 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL047438/ADL 047437• Milne Point/Sag River Oil ' 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): ±9,512 ±8,952 ±9,430 ±8,875 3,478 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor *80' 20' ±80' ±80' N/A N/A Surface ±5,200' 9-5/8' ±5,200' ±4,918' 5,750psi 3,090psi Production ±9,512' 7' ±9,512' *8,952' 7,240psi 5,410psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 4-1/2' 12.6#/L-80 1Cr/Vam Top ±9,320 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Baker 7"x 4-1/2"Prenier and N/A *9,215'MD/*8,675 and N/A 12.Attachments: Proposal Summary ❑d Wellbore schematic Q 13.Well Class after proposed work Detailed Operations Program ❑ BOP Sketch ❑✓ Exploratory ❑ Stratigraphic 0 Development❑✓ Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 5/4/2017 OIL Q WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG 0 Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Bo York Contact Name: Stan Porhola Authorized Title: Operations Manager Contact Email: sporholaahiloorp.Com Contact Phone: 777-8412 Authorized Signature: �_�� Date: 4/18/2017 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number r k1 - 1 , l Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ IA ,-.6_..-..t.-0 � ,Other. �4 C,: - ' �ls � j iL.C i-e_1 - ✓Yz Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No { Subsequent Form Required: 1 0--14 C)II APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 5-aq - (7 INAL Abs6-4/417- 74, 5--- ict—i-7— ORI Submit Form and Form 10-403 Revised 4/2017 Approved application is valid for 12 months from the date of approval. Attachments in Duplicate cW 4-(2(12.0(7 RBDMS W MAY 2 4 2017 RECEIVED APR 1 v9 2017 Post Officbk24U Anchorage,AK 99524-4027 Hilcorp Alaska, LLC 3800 Centerpoint Drive Suite 1400 Anchorage,AK 99503 Stan Porhola Operations Engineer (907)777-8412 April 18, 2017 Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 1400 Anchorage, Alaska 99501 RE: Hydraulic Fracturing Application,Milne Point Unit,MP B-30 (PTD 216-153) Dear Commissioner Foerster, Hilcorp Alaska, LLC ("Hilcorp"), as Operator of the Milne Point Unit, herein submits its application to fracture stimulate MP B-30. Please do not hesitate to contact Stan Porhola at 907-777-8412 should you have any questions regarding this application. Sincerely, York, Operations Manager HILCORP ALASKA, LLC Enclosures: Form 10-403 Sundry Procedure and Attachments (Section 1 — 13) Coil BOPE Nitrogen Procedure • Hilcorp Alaska,LLC Post Office Box 244027 Anchorage,AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage,AK 99503 April 11,2017 Phone:907/777-8412 sporhola@hlicor p.com Chantal Walsh,Director Division of Oil and Gas Alaska Department of Natural Resources 550 W. 7th Avenue/Ste. 1100 Anchorage AK 99501-3510 Re: Notice of Hydraulic Fracturing Operation—Milne Point MPB-30 Dear Mrs. Walsh, Hilcorp Alaska, LLC ("Hilcorp Alaska"),as Operator of the Milne Point Unit,has recently submitted an application to the Alaska Oil and Gas Conservation Commission ("AOGCC") to allow for the hydraulic fracturing of Milne Point Unit Well MPB-30. The surface of the well is located on ADL 047438 and the bottom hole location falls on ADL 047437. See attached map(Exhibit A). Hilcorp and our joint working interest owner, BP Alaska Exploration, Inc. ("BPXA"), own all applicable leases within the MPU. The State of Alaska, Department of Natural Resources is the sole landowner and surface owner. There are no other affected landowners, owners or operators within a Y2 mile radius of the well. Moreover, there are no water wells within this affected area and therefore no water well sampling is required. A complete copy of our Application for Sundry Approval can be obtained from the undersigned or by requesting a copy from the public records at the following address: Alaska Oil and Gas Conservation Commission 333 West 7th Avenue- Suite 100 Anchorage,Alaska 99501 Phone: (907)279-1433 Sincerely, Stan Porhola, Operations Engineer, HILCORP ALASKA, LLC CC: John Dittrich,BPXA (via email John.dittrich@bp.com) • 0 1 Landowner Notification Letter MPB-30 Page 2 of 3 Exhibit A: MPB-30 Plat Legend .r a, fr a`3D r -MPB-32 f' MPB-30 r -Sr:c.12 ,1 ADL392703 Sec 7 fr Sec:Esr• • !WUI:WU B-30 SHL 1 ts2o) , na. >! fiPil B-30 TPH o AiPU B-30 DHL fc,D', ; t t 112 nxie v.leitoxe 4 '`1. t r r buffer ` it M 1I2m4eFrac �;�' •� i,. .."w�terve4 butler r i1Ri?,Y'` vl L LcU r r r • R:r \v I• r -11.-.`, v Vv t.SE.C.1B w5ec'17 ' SEC.r-0 "`v. vs " t 1 fit.: ,F3D) *N. Sec.13. 1 1 `tt.fC 1 t ,i," rrr alt {i d` '‘-_ • s Lr rir ~``- z t^`t{' ` ___-AD1047438 j C 'T:.- r.u, ` fes- 1s •• ADL047437` tib-`-- - t. .y," t ". wMILNE POiNT UNIT -U013N010E_ -- "Ys a y � • •• •� r* • c, c-1 7 ----- --"AA-- ' A fv'E \II 3 ti 110131.4011E s '' * - r I E I:f S S _c \, . - cat]+.01: a33,-' I I r-': tt l f _.in `'.. <• I - ti ! • 'd r)r I • 1p f •I. S N. "• N f I C / •. / ipt r ' .,ac 19 ` /f Set 23 I '�f •ar+ ` Set 24 : rr [1u cr: /i?T"` t 33) f Sec 29 �, e t AC f�t:fi F f t ' I {.1. ES[rF2't •yI Ir• r 1• s. ‘,�\�E YL `� G t. rr /1 ) 1„f` (1 f ,778%.13-'27 E 1[. r t 4 1 ftrifl ff �) f 1 Z • v 8.133 v v v t � •tr f ,i o ` + v ` ` 'p { 11 /1 f .r [t' _... +y L.,4,14111 ' V t a1AD�1 --- --„ •„t- S I V 1 1121 Y '� -v 1(l S1E EFfl yty ” ~ � ! J1 F -f h •t�Y rt 4. A- li ADL025518 c i 4'` sec 26 SFx.35 t :` sADL02&231 sec 30' ' a r Glu i r 1 di/ �t t 4FZ5i411 tt r 4 E Jf { ` 1 \ 505 ElMilne Point Unit MPB-30 Well 0 1,200 2,400Feet ”.„,. ^_?377,17 1 Section 1—Affidavit 10 AAC 25.283 (a)(1) Landowner Notification Letter MPB-30 Page 3 of 3 VERIFIATION OF NOTICE PER 20 AAC 25.283(a) MILNE POINT UNIT MPB-30 I,STAN PORHOLA,Operations Engineer 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 MPB-30 well via hydraulic fracturing. Pursuant to pending regulation 20 AAC 25.283, 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 jjay of April,2017. /4"0"11- Stan Porhola,Operations Engineer Hilcorp Alaska,LLC STATE OF ALAKSA ) )ss THIRD JUDICIAL DISTRICT ) SUBSCRIBED TO AND SWORN before me this t("8ay of April,2017 ITATB OP ALASKA l NOTARY I• ALIO N ARY PUBLIC A OR David W. Duffy THE STATE OF ALSKA COMMeSeiOn ENDgep t,2017 My Commission expires: ? O 0 Section 2-Plat 20 AAC 25.283(a)(2) Legend .J E-50 G -•--- MPB-32 MPB-30 ,t Sec 12 ADL392703 Sec 7 Sec e. MPU B-30 SHL4628) MPU B-30 TPH -e- MPU B-30 BHL 1/2 mile wellbore `• ,' buffer 1/2 mile Frac -1 interval buffer ,, , - -�'� � ,'Sec'16 a"Se.c`17 Sec 14 �" t, _1 (630; ,�, Sec.13 t ..\E. 6 - •- •N -- imJ v V ' a , ,. .....C's.:"'"- - -- Y sem.` k-.'* ,:, -��•' ADL047438 M _ J I c-f f _ ' ADL047437 ::',..,.'...1-_, MILNE POINT UNIT i U013N010E__ - ,• f ''°* .;\, 6-0, a $7,,,'",15_, U013N011 E /1. I�. �� 2 ' , / ✓ Av V /7 Sec.23 6:9 - Sec.24 , r X ,. Sec.19 `, A\ Sec 26 / ' , /' E'e cFP-2 .(033) ti \ ��q ' �' . -I. Q4"1 Qc A ,E ` ', • // lEi A 0 r C / ._ ADL025518 t =' r < �, E,5,_ I See.30 c'sEi Sec.26 Sea 25 I a ADL028231 (es) Sec 29 .racei ``\ -- /• / \ tt 4E-25P6! I,A \ �� I, \ e..- — II Milne Point Unit ! MPB-30 Well 0 1,200 2,400 A,aPoae 3'23'20,] Feet Plat depicting all well types within a%z mile radius of MP B-30 111 Legend MPB-01 (Sag River) Frac Interval MPB-30 MPU B-30 SHL MPU B-30 TPH MPU B-30 BHLSec 18 c.13 {830) 1/2 mile wellbore buffer ADL047438 ADL047437 MILNE Pf311 1 +tail U013N010E U013N011E 0 Sec 19 Sec.24 (n t3) ADL025518 Sec 25 ADL028231 Sec 30 0030) Milne Point Unit 0 680 1.360 MPB-30 Well amin =iFeet Atop Dote 321-317 Plat depicting one (1) other Sag well penetration within a 1/2 mile Radius of MP B-30 • 111 Section 3—Freshwater Aquifers 20 AAC 25.283(a)(3) There are no freshwater aquifers of underground sources of drinking water within one-half mile radius of the current well bore 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." Legend MPB-30 • MPU B-30 SHL r e'r'r X MPU B-30 TPH -4- MPU B-30 BHL 13Sec 18 i 1632; k, ..•,--112 mile SHL #_ A.4 i,.=buffera i 'at, S a I i i a i i f 1 a a a a a a a a aADL047438 a ADL047437- a t r a a MILNE POINT UNIT U013N010E \ i ji � ".....% U013N011E gs '' , a .'. •,'''. a.a air. $CC.iJ Sec.24 133331 ........_.... ADL025518 Sec.25 ADL028231 sec 32 .6361 11 Milne Point Unit MPB-30 Well 0 680 1.360 mmiwit===Feet Plat depicting the MP B-30 well location with no water wells within1/2 mile radius of the MP B-30 surface location • Section 4—Plan for Baseline Water Sampling for Water Wells 20 AAC 25.283(a)(4) There are no water wel Gated within one-half mile radius of the cur t wellbore trajectory and fracturing inte I. A water sampling plan is not applicable. ✓ m?(,l„ —01 /5 Awl - Da/ aa. Go c r. _scr).0/ 144._// £r J'Aci slry 0 • Section 5-Detailed Cementing and Casing Information 20 AAC 25.283(a)(5) 9-5/8"40#/ft L-80 DWC/C surface casing will be set at 5,200' MD and cemented with Stage#1 consisting of 265 sxs of ArcticCEM followed by 212 sxs of Class G (cement top to 1,900' MD). Stage#2 consisting of 222 sxs of ArcticCEM followed by 270 sxs of Class G (cement to surface). 7"26#/ft L-80 DWC/C production casing will be set at 9,512 MD and cemented with 289 sxs of Class G (cement top to 7,000' MD). --- 2 31/.4.2k., `"...-tom e) J.:_„.„.11.-- c::<;' V -� -- c::c 0,. 74.0 /1D Detailed Casing Information Size Type Wt/Grade/Conn Pipe Body Yield Collapse Pressure Internal Yield Pressure (lbs) (psi) (psi) 20" Conductor 78.6#/A-53 N/A N/A N/A 9-5/8" Surface 40#/L-80/DWC/C 916,000 3,090 5,750 7" Production 26#/L-80/DWC/C 604,000 5,410 7,240 Detailed Tubing Information 4-%" Tubing 12.6/L-80 1 Cr/Vam Top 288,000 7,500 8,430 . c z- 7- e....,,--k...,j- r, .1-- st--,r_ ,) 1 Section 6—Assessment of Each Casing and Cementing Operation to be Performed to Construct or Repair the Well 20 AAC 25.283(a)(6) The B-30 well will be constructed in accordance with 20 AAC 25.030. 9-5/8"Surface Casing- The Surface casing will be set at+/-5,200' MD. The casing string will be cemented with 265 sxs of ArcticCEM Cement followed by 212 sxs Class`G' 15.8 ppg cement as a first stage, bringing cement up to+/- 1,900' MD. A second stage will be pumped thru a stage collar with 222 sxs of ArcticCEM followed by 270 sxs Class`G' 15.8 ppg cement to surface. Pressure test of the casing to 2,900 psi on chart for 30 min. The cement will be drilled out and a FIT test conducted to 12.5 ppg. 7"26#Production Casing- The Production casing will be set at+/-9,512' MD. The casing string will be cemented with 289 sxs of Class'G' 14.5 ppg cement, bringing cement up to+/-7,000' MD. Pressure test of j �✓-" ` -" the casing to 3,700 psi on chart for 30 min. Run Cement Bond I Z 5fi" Log on 7" casing. --_ /1-sT�G�Ey Attachment#1 Cement Bond Log pending. Section 7—Pressure Test Information and Plans to Pressure Test Casings and Tubings Installed in the Well 20 AAC 25.283 (a)(7) The 9-5/8"Surface casing will be pressure tested to 2,900 psi. The 7" Production casing will be pressure tested to 3,700 psi/ 614- The 4-1/2" Production tubing will be pressure tested to 5,000 psi. , A 0 • Section 8—Pressure Ratings and Schematics for the Wellbore 20AAC 25.283(a)(8) Detailed Casing Information Size Type WV Grade/Conn Pipe Body Yield Collapse Pressure Internal Yield Pressure (lbs) (psi) (psi) 20" Conductor 78.6#/A-53 N/A N/A N/A 9-5/8" Surface 40#/L-80/DWC/C 916,000 3,090 5,750 7" Production 26#/L-80/DWC/C 604,000 5,410 7,240 Detailed Tubing Information 4-Y2" Tubing 12.6/L-80 1 Cr/Vam Top 288,000 7,500 8,430 Tree Saver 15,000 psi Wellhead 5,000 psi BOPE N/A Schematic—See Next Page 0 I II Milne Point Unit PROPOSED Well: MPU B-30 Last Completed: Proposed ufi,.,rn i., : a::,.i.Lr PTD: 216-153 KB Elev.:49.6'/GL Elev.:23.1' TREE&WELLHEAD RKB-THF:23' Innovation - "—..- Tree _ CIW 41/16"SM jLWellhead Seaboard Weir,3 spools,will x 5M top flange 20" 4-1/2"TC-II Tubing Hanger OPEN HOLE/CEMENT DETAIL 20" Cmt w/±50 bbls of Arcticset in 42"Hole 9-5/8"(20d Stage) Cmt w/±222 sks 10.7 ppg ArticCEM,±270 sx 15.8 ppg SwiftCEM in 12-1/4"Hole 0 0 9-5/8"(1"Stage) Cmt w/±265 sks 10.7 ppg ArticCEM,±212 sx 15.8 ppg SwiftCEM in 12-1/4"Hole Es cementer ? 7" Cmt w/±288 sks 14.5 ppg Class"G"in 8-1/2"Hole G 1.900' , 1. a CASING DETAIL Size Type Wt/Grade/Conn Drift ID Top Btm a 20" Conductor 78.6/A-53/Weld 19.100" Surface ±80' x4, 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface ±5,200' 9-5J8- • 47" Production 26/L-80/DWC/C 6.151" Surface ±9,512' TUBING DETAIL 4-1/2" 1 Tubing ( 12.6/1-80 1Cr/yam Top 3.833" Surface ±9,320' WELL INCLINATION DETAIL 1„ ..' KOP @±600'MD �Y '.7(�l Q Max Hole Angle=±22.63 deg at±7,520'MD �" Hole angle through perforated interval:±22° •E 1-,X,' 1,4), Ujot'r."c 21,Jr-2- -> JEWELRY DETAIL 00 4 No Depth Drift ID Item Li 1 ±23' 3.833" 11"x 4-1/2"Tubing Hanger(4-1/2"TC-II Top&Btm) 2 ±9,105' 3.813" 4-1/2"XD Sliding Sleeve Min ID=3.813" 3 ±9,160' 3.842" 4-1/2"ROC Pressure Intake Gauge Min ID=3.842" 4 ±9,215' 3.870" Baker 7"x 4-1/2"Premier Packer(598-387)Min ID=3.870" 5 ±9,273' 3.725" 4-1/2"XN Profile _. �a 6 ±9,319' 3.833" 4-1/2"WLEG Btm e±9,320' PERFORATION DETAIL k- * ti Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status 1 f '1Sag River ±9,375' ±9,415' ±8,825' I ±8,862' 40' Prop Prop 3 t 3-1/8"Perf Guns RA Tag? c` 14 GENERAL WELL INFO 11 a API:50-029-23571-00-00 a; Drilled and Cased by Innovation#1 TBD 6 SAG 4 4 _gi r ' TD=±9,512(MD)/TO=±8,952'(TVD) PBTD=±9,430'(MD)/PBTD=±8,875'(IVD) Revosed by:STP 4/03/17 0 WELL MPB-30 DATE 2/27/17 til PROPOSEDiMem ) Alaska. I,1,(: Cz' Swab valve Seaboard Tree Cap.Otis style,6 3/8" Model 510,4 1/16"5K, ACME 4 1/16" 5K,FE,DD L-U FE,DD L-U PN 348218-000 PN 564680-WD1 pm SNS SN i 1 Ii 1p Wing valve Seaboard Model 510,4 1/16"5K,FE,DD L-U PN 564680-WD1 o aaa. .0 0 SN ` a o 0,- 7 _- mc SSV valve Seaboard Model 0€0 510,4 1/16"5K,FE,DD L-U ®' PN 348434 1; ® 4 SN ,' Master valve Seaboard Model - t '^ 1 - - 510,4 1/16"5K,FE,DD L-U 1 ) PN 564680-WD1 ti Tb Hgr,Seaboard SM- 1 t ' SN g g 4 1. ��1 ' E-CL 11 x 4'A"EUE BOX _^ API 11"5K •top and bottom,4""H" ' ` lam. BPV,ported for 2 ea 3/ 8"Control line, 41 11 ti.L:�, L' ,w/3'pup L-U,DD-NL, PN W10220 _1 `-- SN L API 13 5/6"5K 7 11 x 7",SMB 22,8.5 4 stub 3 • 44.,.; acme top x DWC box Csg Hgr,Seaboard 1 �• .,.# S-22 13 5/8 x 9 5/8" bottom,w/DWC-C pup, Slip type hanger j ° . i 6.844 bore PN A34330 LU,DD-NL PN A16232-001 SN y 0 0 el PROPOSAL:OIL sTATEs Casing Isolation Tool Energy Services(Cana : he Maximum Allowable Pumping Rates SIZE 10 00 RATE ri',nal CSG 1 2 250 3 7E0 10 treitntin 3 1 ir 81 Bea 1.760 2.760 4 remia 2-11r 41:3fie— 14311 2.340 4 rehnin 23$8. 1.000 , 1.900 2 reirttln 2 VIA It I.V •••••22 toporoil mandrel 2.120 4. 00 is m.knin-- 41116 X Tool Mandrel 3.610 f 4.750 - 44 m1W&n o. POUTI31 Clown i1/400**t twern4 rit=,..._.... ----- r 1 — yr Eir........r, 1 . '. .. :0: .. I ,..• , — ANEW I I ...... r. i Romig 1 i d , 11.... • •••.•4 •*.! ' I•':' ,t ' 7 f . ...g " . , a_a, V......o*. "r .i . • ..74,...., ., 7 - -"%k ...1 10 1 Or' olort., - ..1.110. ,. 11047 .011 www.StmgenCanada.c cdn 15M Treating Head le 0 Section 9—Data for Fracturing Zones and Confining Zones 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 Sag River formation is a Triassic-aged,fine-grained marine sandstone. The productive Sag River interval is+/-40'TVD thick. The top of the Sag River is at 9,380' MD/8,825'TVD. The estimated fracture gradient for the Sag River interval is 0.575 psi/ft. The overlying confining zone consists of+/- 1,100' TVD of Kingak shales. The top Kingak shale is at 8,184' MD/7,725'TVD. The estimated fracture gradient for the Kingak is 0.689 psi/ft. The underlying confining zone consists of+/- 175'TVD of Shublik mixed carbonates,siltstones and shales.The top of the Shublik is at 9,430' MD/8,875' TVD. The estimated fracture gradient for the Shublik is 0.601 psi/ft. M • Section 10—Location,Orientation and a Report on Mechanical Condition of Each Well that may Transect Confining Zone 20 AAC 25.283(a) (10) One (1) other well transects the confining layer(Kingak shale) in the%2 mile radius surrounding B-30. The B-01 well (PTD 180-075)was constructed in accordance with 20 AAC 25.030 and penetrates the confining layer(Kingak shale)within a 1/2 mile radius of B-30. 9-5/8" Production Casing - The Production casing was set at 7,617' MD. The casing string was cemented around the shoe with 580 sxs of Cement as a first stage, bringing cement up to approx. 6,520' MD. The stage collar at 5,033' MD was opened and a second stage was pumped thru the stage collar with 417 sxs of cement to approx. 4,185' MD. Pressure test of the casing to 4,000 psi was performed. After setting the 7" liner, and perforating and flow testing the Sag River and Kuparuk formations in the 7" liner, the well was plugged back inside the 9-5/8". A bridge plug set at 4,596', 5 sx of sand dumped on top of the plug, squeeze holes shot and squeezed at 4,530' (200 sx), 4,395' (200 sx), 3,965' (200 sx). A RTTS packer and 4 joints of drillpipe were left in the hole with the bottom of the fish at 3,885' and the top of the fish at 3,755'. The 9-5/8"was section milled from 3,487'to 3,529' and a cement plug (150 sx)was layed in and used as a kick-off plug for a 8-1/2"sidetrack. 7"26# Production Liner- The Production liner was set from 7,470' to 9,630' MD. The casing string was cemented with 230 sxs of Cement, however the liner lap failed at 1,700 psi. A 1st cement squeeze of 100 sx of Cement was pumped but also failed at 1,700 psi. A 2nd cement squeeze of 100 sx was pumped but also failed at 2,900 psi. A 3rd cement squeeze of 300 sx was pumped and successfully test to 3,500 psi. Ran Cement Bond Log on 7" production liner. The interval from 9,270'-9,300' (Sag River) was perforated and flow tested. Following the flow test, a cement retainer was set at 9,240' MD. There was 100 sx of cement squeezed below the retainer, and 50 sx left on top of the retainer and tested to 1,500 psi for 30 min. A bridge plug was set at 7,479' (inside the 7" liner) with 50 sx of cement left on top of the bridge plug and cleaned out to 7,364' (inside the 9-5/8"casing). • Section 11-Location of,Orientation of and Geological Data for Faults and Fra\ct..,u...res That May Transect the Confining Zones 20 AAC 25.283 (a) (11) / SYMBOL HIGHLIGHTS oa • SGR INJECTOR-AL, SI '� ciimr2 /AG PRODUCED P8A9Ay AG PRODUCING 51AG SHOW ):Pr AZT a b� 90 �ip R ,,,14,‘,v, 1 n J '. b , es„, i C p0�p m c J -°Lrs ''$ /„..N. -B, 1- ' i9g ay %' irk' Sp J�. J X75 B97s, �� \ $ y my b ears ,.Jl, ,,, \\. J „aso , , , ,,,,_ -,,,,,, \ r vCg cg 9b :P .90. , 'ite,:: 6 B2J �7$K-,.. 9so4414”4 %101044,4,6........4644, 4k, J BB50 %%IN( "'N -8"3„, ' ...... 0 ----,74-.1.„, � s The map above shows the structure at the top of the Sag River interval (TVDSS).All faults shown are inferred from seismic data. There are several faults based off of seismic data that are within the 1/2 mile radius of the MPB-30 wellbore. However, MPK-33, MPC-23, and MPS-90 (all vertical, hydraulically fractured Sag River producers, similar to what is proposed here) are similar distances to mapped faults and did not suffer containment issues. Horizontal principal stress from surrounding well data indicate that the fracture should propagate approximately NW SE (SHmax is NW-SE,SHmin is NE-SW). Based on current mapping,the fracture wings should not extend into suspected faults. .„7,1s1 ' Stiu Section 12—Proposed Hydraulic Fracturing Program 20 AAC 25.283(a)(12) w P Proposed Hydraulic Fracturing Program ( 3 1.) MIRU frac fleet. MIRU frac and slop tanks. MIRU CTU and associated equipment. Stump test BOPE, if possible. MIRU all ancillary support equipment. 2.) Fill frac tanks with fresh water. Heat water as needed. 3.) Lay all hardlines and manifolds. Install pressure monitoring equipment on wellhead and tree. 4.) RU 15K tree Saver and hard line. 5.) Pressure test all high pressure treating lines to 8,000 psi. 6.) Set the GORV (gas operated relief valve)at±7,000 psi. Set the staggered pump kickouts between 7,000 psi and 6,500 psi. 7.) Pressurize annulus to 2,000 psi. Set annular PRV at 3,000 psi. 8.) Prepare frac fleet to pump. 9.) Pump Sag DFIT and analyze the results to obtain fluid loss coefficients. Adjust frac design. 10.) Fracture stimulate Sag interval with 16/20 mesh resin coated proppant in cross-linked gel. See "Pump Schedule"for proposed design. 11.) Displace w/20 bbl of diesel for freeze protect. 12.) Shut well in. RDMO. 13.) RU CTU BOPE and PT to 3,500 psi. 14.) RIH and cleanout frac sand/frac fluid to a portable test separator with filtered 2%KCI brine and N2 as needed to 9,430' MD. 15.) POOH jetting casing and tubing clean. RD CTU. 16.) RU SL. Pull protector sleeve from XD sliding sleeve (if installed). Drift and tag tubing to maximum TD with GR/JB. 17.) Brush sliding sleeve. RDMO. 18.) Turn well over to operations. • Frac Fleet Layout D r! CUMFracCAT I Ntl-j — !11 I Popoff/Check Valve Skid Schlumberger To Well Milne Point MPB-30 Hilcorp Energy .; 11110 • 20 AAC 25.283(a)(12) (A) Estimated Total Volumes Planned Frac Pump Schedule PU4950410113E 1505051 assns 046 We99.773 .7-4.2 01, 43 %3 640737703.20 °5 6.93mm 8766 $6640 -0001[01. IUY 6335644 0004200Eu111 E.s04 - 8080836 • • TYPE SATE SA, STAGE GUIS STAGE CUM STAGE GM 3419 06049 CUM n.na $3044 STAGE 004 19946 MCI 103,1 3041) 1044 0201 7.001 043 150E1 03586 104000 445404301 O...l 7 66.49064.3 WF130 30 iM 144 8028 6025 144 144 3.0 00:0447 0094,47 00.0090 00:04:42 31430FM20 33 254 6300 12328 150 294 34 00.0500 00:0947 0 0.04..47114 ,'. 150 3 03 7777.... 61.4774. YF130Fka0 30 77 77 50 344 2100 11428 1028 1,026 .5:405:7777... 10 ....341 3.0 7777... 000140 001127.. 1 ....004.48664.1 11130F107113 0 30 100 444 426E 1472E 100 441 31 00 0320 001132 Owq.ewrM WF139 30 140 009 6112 24239 146 586 3.0 00 04 00:19'36 7777__„77_77._ RO...__.IIM_-__Cr'-...__--_7777 011119040101 77....___.........8 304A4I.__ 0.1.03I1614 Ix. Faa 604 13C STEP CCM[ WEN. 000005 TYPE RAW Pr, 111013 013 117H3 *011 07514 CM CM 31046 C63 56..64 Cas. *WILE 0114 • 1.4 18.1 1 - 10011 MCI 104081 10461 5.551 11837 091.1 3014 406.6 153946 30)500 W+s..34 YF13094,0 30 450 1039 _ 18900 43639 0 7026 450 1036 3.9 004200 0031:36 811305400 30 60 1099 2520 46159 2304 3435 52 1095 3,0 0002% 0036:38 0913694.0 30 1 49 1159 2520 48629 4,611 8050 932 20, 55 1150 34 00 02 00 00'38.30 1913891540 30 60 1216 2520 51199 6,641 14691 74.147 53 1203 3.9 000200 00.40:38 4 834114 7913051440 30 - 60 1229 2520 53719 6.510 23.201 14724 Ca 51 1254 3.0 00.0200 00.42:38 11 1 RASP 091305440 30 00 1339 3520 56239 10,239 33,440 9 47 cat 49 1302 3.0 0002.00 00:44:38 12 9 RASP 091309400 30 60 1390 2520 55259 11.043 15283 47 1349 1 0002:00 00:46.38 13 591339440 30 40 1455* 2520 61220 13.335 58,618 61 45 1395 0 00:02.00 0018:38 14 0 RAMP 0913119440 30 34 1319 2520 63799 14.222 73,345 44 1439 61 00:02:00 00'.50-.33 911.4.1 0113091440 30 60 1519 2520 66319 16,035 09373 42 1181 41 00'02:00 00'.52:38 1 10 FLAT 55130710 30 60 1839 2520 66839 12246 108,614 41 1522 9A 009290 00:54:30 iF1301123230 30 60 1399 2520 71359 18.391 125,010 9.105 19 1502 IA 00:02.00 00:56:38 1. FLAT 1513091440 30 325 2024 13650 115009 105146 230,456 209 1771 SA 00:10:50 010728 126311 049130 10 102 2131 4475 89484 230.456 107 1826 104 000133 01:1101 18 91806 53054e460911 15 33 2154 1405 90889 230.458 33 1911 00:02:13 0113:11 101013 2181 234456 1911 0113:14 80544441.MS 3..a17f4. 04109004 19.6141SI03%C04 • }336L NW 99DIENT)TWA..00LY13CE 111606101906a9..33 110.091110116101.11911MAN 43240 90904 10L4T>ISM•� 0 071200 1806 Wrt.X66= R/ 7777 04140000 13500014 1.64 1140 73 11.3% y( 0 6016 0002 00 TOTM04 J = 1339 604 61811034CI81p 1110 • 30.06300 1320 Oats 60196505P64Y ____,_, 0070 TE9i ii NGO•%4005 4030065{4X9= 0C78508OIWO 0711 SLEEVE= CST.44541077605100 041444/80a5aP i PIPE 7750950 42 42660 T0= 99 55. .=400 10014705363010,0008012*1661.944 MUM,013 Su041 319 64086 59041 518407 902.044.60513.665965 5.61 54054 UPPER 71110 566- 4.500 0032<AAA %map 043.1 504.6 PION 3330 OW 41055 pSw�6 w___.__ 0.384830.38483887760.. . r P.m.) 140044. VD .bssnss 17421X40046 TAG) Panne.. 42.5. 4E X16. .68782= 1..aw64 136 014 6315 143.3 WA 645015420. 7POW 57,... Doi. IDS 1164 Pump me 113.14 64aa.M 45 • 8183 M M r SO 4 w % 1111 • 20 AAC 25.283(a)(12) (B)and (C) Frac Chemical Listing Q Client: Hilcorp Alaska.LLC Schlumberger MPB P Basin/Field: Milne Point State: Alaska County/Parish: North Slope Borough Case: 6999969 Disclosure Type: Pre-Job Welt Completed: 5/10/2017 Date Prepared: 4/17/2017 2:10 PM Report ID: RPT-48561 Fluid Name&Volume 7:iri.' Additive Description Concentration Volume F103 Surfactant 1 Gal/1000Gal 80.0 Gal 2218 Breaker 0.6 lb 11000 Gal 45.0 Lb 1450 Stabilizing Agent 0.5 Gal/1000 Gal 40.0 Gal. 1569 Breaker 4.6 Lb/1000 Gal 360.0 Lb YF130FIexD:Wf130 78,876 Ga! 1604 Crosslinker 2.4 Gal/1000 Gal 190.0 Gal 1891 Guar Slurry 7.1 Gal/1000 Gal 560.0 Gal 1071 - Clay Control Agent 2 Gal/1000 Gal 160.0 Gal M002 Additive 1.9 Lb/1000 Gal 150.0 Lb M275 Bactericide 0.4 Lb/1000 Gal 30.0 Lb 5526-1620 Propping Agent varied concentrations 230,000.0 Lb The tnal'votvne Avecr+the tabh abase rave sews ttsvamovwn of water and addn:rcs.Water is suppi'eci by alert CAS Number Chemrca t urns Water(including Mix Water Supplied by Client)" 73% 66402-68-4 Ceramic materials and wares,chemicals "26% 64742-47-8 -.., Distillates petroleum,hydrotreated light <1% 9000-30-0 Guar gum <1% 67-48-1 2 hydroxN N.N-trimethylethanamtnium chloride _.,_. y ... a 1 % 1319-33-1 Boronatrocalcite a 0.1 96 107.21 1 Ethylene Glycol <0.1% 102-71-6 2.2,2"-nitrilctnethanol <0.1 96 7727-54-0Diammoniurn perm,drsu phate <0.1 % 1310-73-2 Sodium hydroxide <0,1% 67-63-0Propar-2-ol <0.1 9u 111-76-22-butoxyethanot <0.1 96 „ _ 34398-01-1 Ethoxylated C11 Alcohol c 0.1 96 25038-72-6 Vinylidene chloride/methylacrytate copolymer,,,.... a 0.1% 1303-96-4 Sodium Tetraborate Decahydrate <0.1 96 68131-39.5 Ethoxytated Alcohol a 0.01% 68153-30-0 Amine treated smectite clay a 0.01 96 110-17-8 Fumaric acid a 0.01.96 91053-39-3 Diatomaceous earth,calcined c 0.01 96 112-42-5 Undecanol <0.01% _ 7631-86-9 Silicon Dioxide a 0.001 96 10377-60-3 Magnesium nitrate a 0.001 96 9002-84-0 poly(tetrafluoroethylene) a 0.001 96 26172-55-4 5-chloro-2-methyl-2h-isothiazdol-3-one a 0.001% 7786.30-3 Magnesium chloride a 0.001 96 14807-96-6 Magnesium silicate hydrate(talc) a 0.001% 595585-15-2 Diutan a 0.001% 125005-87-0 �.. Diutangum <0.001% 2682-20-4 2-methyl-2h-isothiarat-3-one a 0.0001% 127-08-2 Acetic acid,potassium salt------------- ----- a 0.0001% 14464-46-1 Cristobalite a0.0001% 14808-60-7 Quartz,,Cstalknesitica__,_-___,..._,_.-.._...__..--.-_- ry <Q_0001% -` - 64-19-7 € Acetic acid int.:ri <0.0001 96 Total 1Ct). •Ma rbton As tupsptrd by the dent.se U/thew-has perfaenmd no analysts o/the water avd canna provide a breakdown atcamaanents that may have beer added to the water by th$td-tames. the eratuanan of artached ia-ument is pe fasrnedlnsed an Ito cae,ansanvn a ter fdennfied pe d4:t to the retort that sat,eamposemod m/a^unm was Wwrr to OAC-Chemtab as of the dote of the datun+er+t Was produced.Any row updates.inti nal be rel cotrd us this datumcnt. • • 20 AAC 25.283(a)(12) (D) Frac Design-See Page#6 (Note:Volumes and Weights may change slightly after Data Frac) Schioffiberger FracCADE' STIMULATION PROPOSAL Operator : Hilcorp Alaska Well : MPB-30 Field : Milne Point Formation : Sag River c) Well Location : North Slope c County State : Alaska Country : United States to Prepared for : Stan Porhola Service Point : Prudhoe Bay m Proposal No. Business Phone : 907 659 2434 Date Prepared : 11 Apr 2017 FAX No. : 907 659 2538 Prepared by : Gunther Rutzinger Phone : 9012731788 E-Mail Address : grutzinger©slb.corn Mark of Sch umberge' Disclaimer Notice. This information is presented in good faith,but no warranty b 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 bye compoter model including various assumptions on Ore welt reservoir and treatment.The results depend on input data provided by One Operator end estimates as to unknown data and can be no more accurate than the modet,the assumptions and such Input data.The information presented is Schlumberger a 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,end 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 O the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it u the Operetots 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 S Client : Hilcorp Alaska Schlumberger Wefi : MPB-30 Formation : Sag River District : Prudhoe Bay country United States Loadease : 200kIbs frac design Contents Section 1: Wellbore Configuration 3 Section 2: Zone Data 4 Section 3: Propped Fracture Schedule 6 Section 4: Propped Fracture Simulation 8 Section 5: Propped Fracture Simulation Results 11 Section 7: Treatment Fluid Data 13 Section 8: Proppant Data 15 Section 9: Hole Survey 16 ZT ca da 2 Client : Hilcorp Alaska Schl{IIlI erger well : MPB-30 trl'tl'll Formation : Sag River District : Prudhoe Bay Country : United States toadcase : 2OOklbs frac design Section 1: Wellbore Configuration Bottom Hole Temperature 235 degF Deviated Hole YES Treat Down TUBING Well Type Vertical Well Location OnShore Tubing Data OD Weight ID Depth (in) (lb/ft) (in) (ft) 4.500 12.6 3.960 9335.0 Casing Data OD Weight ID Depth (in) (Ib/ft) (in) (ft) 7.000 26.0 6.276 9512.0 Perforation Data Top Top Bottom Bottom Shot Number Diameter MD TVD MD TVD Density (ft) (ft) (ft) (ft) (shot/ft) (in) 9375.0 8825.0 9415.0 8861.9 6.00 240 0.32 3 0 • Client : Hilcorp Alaska SChinIYe1-ger Well : MPB-30 I�it Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 200klbs frac design Section 2: Zone Data Formation Mechanical Properties Zone Name Top TVG Zone Frac Insitu Young's Poisson's Toughness (tt) Height Grad. Stress Modulus Ratio (psi.in0.5) (ft) (psi/ft) (psi) (psi) Kingak 8619.6 79.6 0.753 6524 2.960E+6 0.36 1000 Kingak 8699.2 69.5 0.764 6672 2.670E+6 0.36 1000 Kingak 8768.7 29.7 0.774 6801 2.370E+6 0.37 1000 Sag D 8798.4 5.9 0.647 5694 3.910E+6 0.26 1000 Sag D 8804.3 8.9 0.680 5989 3.120E+6 0.29 1000 Sag C _ 8813.2 4.9 0.699 6161 2.690E+6 0.31 1000 Sag C 8818.1 3.9 0.658 5804 3.850E+6 0.27 1000 Sag C 8822.0 3.0 0.632 5578 4.160E+6 0.25 1000 Sag B 8825.0 2.4 0.617 5448 4.300E+6 0.23 700 Sag B 8827.4 12.5 0.612 5410 4.110E+6 0.23 1200 Sag B 8839.9 3.9 0.629 5558 4.230E+6 0.24 1200 Sag B 8843.8 2.3 0.643 5685 4.450E+6 0.26 700 Sag A 8846.1 10.6 0.643 5690 4.310E+6 0.26 1200 Sag A 8856.7 3.3 0.645 5714 , 4.630E+6 0.26 1200 Sag A 8860.0 1.4 0.679 6017 5.290E+6 0.29 1000 Sag A 8861.4 .6 0.665 5895 4.890E+6 0.28 700 Shublik-A 8862.0 16.1 0.770 6826 6.740E+6 0.31 1000 Shublik-A 8878.1 2.0 0.799 7094 8.430E+6 0.34 1000 Shublik-A 8880.1 2.5 0.783 6954 8.300E+6 0.32 1000 Shublik-A 8882.6 3.4 0.763 6780 8.380E+6 0.31 1000 Shublik-A 8886.0 6.7 0.663 5898 7.930E+6 0.28 700 Shublik-A 8892.7 5.2 0.620 5513 7.260E+6 0.23 1200 Shublik-A 8897.9 4.7 0.628 5587 6.600E+6 0.24 700 Shublik-A 8902.6 3.2 0.691 6149 4.360E+6 0.29 1000 Shublik-A 8905.8 25.8 0.654 5831 5.040E+6 0.27 700 Shublik-A 8931.6 8.8 0.709 6333 3.970E+6 0.32 1000 Shublik-A 8940.4 20.4 0.701 6273 4.470E+6 0.31 1000 Shublik-A 8960.8 7.6 0.652 5846 5.870E+6 0.27 1000 Shublik-A 8968.4 16.4 0.680 6105 5.150E+6 0.29 1000 Shublik-C 8984.8 7.3 0.772 6938 8.790E+6 0.36 1000 Shublik-C 8992.1 16.4 0.710 6392 8.500E+6 0.32 1000 Shublik-C 9008.5 12.9 0.669 6035 6.120E+6 0.28 1000 Shublik-C 9021.4 5.6 0.694 6267 7.280E+6 0.30 1000 Shublik-C 9027.0 5.7 0.630 5686 6.080E+6 0.24 1000 Eileen 9032.7 13.7 0.678 6125 6.580E+6 0.29 1000 Eileen 9046.4 14.5 0.631 5712 5.400E+6 0.25 700 Eileen 9060.9 55.0 0.600 5455 5.030E+6 0.21 700 4 • • Client : Hilcorp Alaska Sphlrt bprger Well : MPB-30 4 I{ �i Formation : Sag River District : Prudhoe Bay country : United States Loadcase : 200klbs frac design Formation Transmissibility Properties Zone Name Top TVD Net Perm Porosity Res. Gas Oil Sat. Water (ft) Height (Ind) 1%) Pressure Sat. (%) Sat. (ft) (psi) (%) (%) Kingak 8619.6 8.0 0.001 1.0 4053 65.0 10.0 25.0 Kingak 8699.2 7.0 0.001 1.0 4087 65.0 10.0 25.0 Kingak 8768.7 3.0 0.001 1.0 4111 65.0 10.0 25.0 Sag D 8798.4 2.4 0.100 10.0 4119 65.0 10.0 25.0 Sag D 8804.3 3.6 0.100 10.0 4122 65.0 10.0 _ 25.0 Sag C 8813.2 2.0 0.100 10.0 4126 65.0 10.0 25.0 Sag C 8818.1 1.6 0.100 10.0 4128 65.0 10.0 25.0 Sag C 8822.0 0.3 0.001 1.0 4129 65.0 10.0 25.0 Sag B 8825.0 1.9 1.000 10.0 4131 65.0 10.0 25.0 Sag B 8827.4 12.5 8.000 14.0 4134 65.0 10.0 25.0 Sag B 8839.9 3.9 8.000 14.0 4138 65.0 10.0 25.0 Sag B 8843.8 1.8 2.000 12.0 4139 65.0 10.0 25.0 Sag A 8846.1 10.6 8.000 14.0 4142 65.0 10.0 25.0 Sag A 8856.7 3.3 8.000 14.0 4146 65.0 10.0 25.0 Sag A 8860.0 0.6 0.100 10.0 4147 65.0 10.0 25.0 Sag A 8861A 0.5 2.000 12.0 4147 65.0 10.0 25.0 Shublik-A 8862.0 1.6 0.001 1.0 4151 65.0 10.0 25.0 Shublik-A8878.1 0.2 0.001 1.0 4155 65.0 10.0 25.0 Shublik-A _ 8880.1 1.0 0.100 10.0 4156 65.0 10.0 25.0 Shublik-A _ 8882.6 1.4 0.100 10.0 4158 65.0 10.0 25.0 Shublik-A 8886.0 5.4 1.000 12.0 4160 65.0 10.0 25.0 Shublik-A 8892.7 5.2 5.000 14.0 4163 65.0 10.0 25.0 Shublik-A 8897.9 3.8 1.000 12.0 4165 65.0 10.0 25.0 Shublik-A 8902.6 1.3 0.100 10.0 4167 65.0 10.0 25.0 Shublik-A 8905.8 20.6 1.000 12.0 4174 65.0 10.0 25.0 Shublik-A 8931.6 3.5 0.100 10.0 4182 65.0 10.0 25.0 Shublik-A 8940.4 8.2 0.100 10.0 4189 65.0 10.0 25.0 Shublik-A 8960.8 3.0 0.100 10.0 4195 65.0 10.0 25.0 Shublik-A 8968.4 6.6 0.100 10.0 4201 65.0 10.0 25.0 Shublik-C 8984.8 0.7 0.001 1.0 4207 65.0 10.0 25.0 _ Shublik-C 8992.1 6.6 0.100 10.0 4212 65.0 10.0 25.0 Shublik-C 9008.5 5.2 0.100 10.0 4219 65.0 10.0 25.0 Shublik-C 9021.4 2.2 0.100 10.0 4223 65.0 10.0 25.0 Shublik-C 9027.0 0.6 0.001 1.0 4226 65.0 10.0 25.0 Eileen 9032.7 5.5 0.100 10.0 4230 65.0 10.0 25.0 Eileen 9046.4 11.6 1.000 10.0 4237 65.0 10.0 25.0 Eileen 9060.9 44.0 1.000 10.0 4253 65.0 10.0 25.0 5 • • Client : Hilcorp Alaska Schlumberger Well : MPB-30 4 1�� 6 1 Formation : Sag River District : Prudhoe Bay country : United States Loadcase : 200klbs frac design Section 3: Propped Fracture Schedule Pumping Schedule The following is the Pumping Schedule to achieve a propped fracture half-length(X1)of 417.5 ft with an average conductivity(K,w)of 5109 md.ft. Job Description Step Pump Fluid Name Step Fluid Gel Prop. Prop. Name Rate Volume Conc. Type and Mesh Conc. (bbl/min) (bbl) (lb/mgal) IPPA! PAD 30.0 YF130FIexD 450.0 30.0 0.00 1.0 PPA 30.0 YF130FIexD 57.3 30.0 16/20 CarboBond Lite 1.00 2.0 PPA 30.0 YF130FIexD 54.9 30.0 16/20 CarboBond Lite 2.00 3.0 PPA 30.0 YF130FIexD 52.7 30.0 16/20 CarboBond Lite 3.00 4.0 PPA 30.0 YF130FIexD 50.6 30.0 16/20 CarboBond Lite 4,00 5.0 PPA 30.0 YF130FIexD 48.7 30.0 16/20 CarboBond Lite 5.00 6.0 PPA 30.0 YF130FIexD 46.9 30.0 16/20 CarboBond Lite 6.00 7.0 PPA 30.0 YF130FIexD 45.3 30.0 16/20 CarboBond Lite 7.00 8.0 PPA 30.0 YF130FlexD 43.8 30.0 16/20 CarboBond Lite 8.00 9.0 PPA 30.0 YF130FIexD 42.3 30.0 16/20 CarboBond Lite 9.00 10.0 PPA 30.0 YF130FIexD 41.0 30.0 16/20 CarboBond Lite 10.00 11.0 PPA 30.0 YF130FlexD 39.7 30.0 16/20 CarboBond Lite 11.00 12.0 PPA 30.0 YF130FIexD 208.9 30.0 16/20 CarboBond Lite 12.00 Flush 30.0 WF130 107.0 30.0 0.00 Freeze prot 30.0 Freeze prote 33.0 0.0 0.00 Please note that this pumping schedule is under-displaced by 3.0 bbl. Fluid Totals 1182 bbl of YF130FIexD 107 bbl of WF130 33 bbl of Freeze protect Proppant Totals 229100 lb of 16/20 Carbo Bond Lite Pad Percentages %PAD Clean 38.1 %PAD Dirty 31.4 6 • S Client : Hilcorp Alaska Schlumberger Well : MPB-30 1! Il G Formation : Sag River District Prudhoe Bay Country : United States Loadcase : 200klbs frac design Job Execution Step Step Cum.Fluid Step Cum. Step Cum. Avg. -, Step Cum. Name Fluid Volume Slurry Slurry Prop Prop. Surface Time Time Volume (bbl) Volume Volume (lb) (lb) . Pressure ,/(min) (min) (bbl) (bbl) (bbl) fPsi}---- PAD 450.0 450.0 450.0 450.0 0 0 3923 15.0 15.0 1.0 PPA 57.3 507.3 60.0 510.0 2408 2408 3916 2.0 17.0 2.0 PPA 54.9 562.3 60.0 570.0 4613 7021 3771 2.0 19.0 3.0 PPA 52.7 614.9 60.0 630.0 6637 13658 3649 2.0 21.0 4.0 PPA 50.6 665.5 60.0 690.0 8504 22162 3490 2.0 23.0 5.0 PPA 48.7 714.3 60.0 750.0 10230 32392 3499 2.0 25.0 6.0 PPA 46.9 761.2 60.0 810.0 11831 44223 3545 2.0 27.0 7.0 PPA 45.3 806.5 60.0 870.0 13320 57542 3583 2.0 29.0 8.0 PPA 43.8 850.3 60.0 930.0 14708 72250 3571 2.0 31.0 9.0 PPA 42.3 892.6 60.0 990.0 16005 88256 3549 2.0 33.0 10.0 PPA 41.0 933.6 60.0 1050.0 17221 105476 3543 2.0 35.0 11.0 PPA 39.7 973.4 60.0 1110.0 18361 123837 3551 2.0 37.0 12.0 PPA 208.9 1182.2 325.0 1435.0 105267 229105 3651 10.8 47.8 Flush 107.0 1289.2 107.0 1542.0 0 229105 4490 3.6 51.4 ti) to Freeze 33.0 1322.2 33.0 1575.0 0 229105 4942 1.1 52.5 z- prot cr ro Pumping Schedule Totals iti Summary for This Stage: Average Pump Rate 30.0 bbl/min su Volume Weighted Average Rate 30.0 bbl/min Total Fluid Volume 55534 gal Total Proppant Mass 229100 lb Total Slurry Volume 1575.0 bbl Total Pump Time 52.5 min Fluid Based Totals for This Stage Average Volume Total Total Total Total Fluid Pump Weighted Fluid Proppant Slurry Pump Rate Average Rate Volume Mass Volume Time IbblImin) Ibblimin) (gal) (Ib) (bbl) (min) YF130FIexD 30.0 30.0 49654 229105 1435.0 47.8 WF130 30.0 30.0 4494 0 107.0 3.6 Freeze protect 30.0 30.0 1386 0 33.0 1.1 Proppant Based Totals for This Stage Average Volume Total Total Total Total Proppant Pump Weighted Fluid Proppant Slurry Pump Rate Average Rate Volume Mass Volume Time (bbl(min) Obi/min) (gal) (Io) (bbl) (min) 16/20 CarboBond Lite 30.0 30.0 30754 229105 985.0 32.8 7 S • Client : Hilcorp Alaska SChlIImaerger weu : MPB-30 i,�6 Formation : Sag River District : Prudhoe Bay Country : United States toadcase : 200klbs frac design Section 4: Propped Fracture Simulation The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model.Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Initial Fracture Top TVD 8827.4 ft Initial Fracture Bottom TVD 8839.9 ft Propped Fracture Half-Length 417.5 ft EOJ Hyd Height at Well 2161 ft Average Propped Width 0.212 in Average Gel Concentration 1097.0 Ib/mgal Average Gel Fluid Retained Factor 0.55 Net Pressure 1283 psi Efficiency 0.442 Effective Conductivity 7017 md.ft Effective Fcd 8.4 Max Surface Pressure 0026 psi Simulation Results by Fracture Segment From To Prop.Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Width Height Prop. Gel Conc. Conductivity Pumping (in) (ft) Conc. (Ib/mgal) )md.ft) (PPA) (Ib/ft2) 0.0 104.4 11.7 0.258 205.6 2.28 1360.3 5316 104.4 208.7 14.6 0.299 156.5 2.62 165.4 7739 208.7 313.1 13.3 0.209 102.8 1.83 330.7 5599 313.1 417.5 37.4 0.081 67.8 0.71 2531.3 1917 Proppant bridged at 403 ft after 0 bbl in step 10 8 • 0 Client : Hilcorp Alaska Schlumberger Well : MPB-30 Schlumberger G Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 200klbs frac design Fracture Geometry Data Per Zone for Production Prediction Zone Name Top Top Gross Net Fracture Fracture Fracture MD TVD Height Height Width Length Conductivity (ft) (ft) (ft) (in) (ft) (moth) Kingak 9152.5 8619.6 79.6 8.0 0.000 .0 0 Kingak 9238.7 8699.2 69.5 7.0 0.000 .0 0 Kingak 9314.0 8768.7 29.7 3.0 0.070 278.8 1672 Sag D 9346.2 8798.4 5.9 2.4 0.153 416.1 3664 Sag D 9352.6 8804.3 8.9 3.6 0.207 417.5 4979 Sag C 9362.2 8813.2 4.9 2.0 0.243 417.5 5842 Sag C 9367.5 8818.1 3.9 1.6 0.269 417.5 6451 Sag C 9371.7 8822.0 3.0 .3 0.289 417.5 6932 Sag B 9375.0 8825.0 2.4 1.9 0.308 417.5 7387 Sag B 9377.6 8827.4 12.5 12.5 0.321 417.5 7680 Sag B 9391.1 8839.9 3.9 3.9 0.316 417.5 7557 Sag B 9395.4 8843.8 2.3 1.8 0.306 417.5 7332 Sag A 9397.8 8846.1 10.6 10.6 0.277 417.5 6638 v Sag A 9409.3 8856.7 3.3 3.3 0.240 417.5 5749 D- Sag A 9412.9 8860.0 1.4 .6 0.222 416.3 5323 Sag A 9414.4 8861.4 .6 .5 0.194 410.1 4661 cr Shublik-A 9415.1 8862.0 16.1 1.6 0.155 343.6 3710 o Shublik-A 9432.5 8878.1 2.0 .2 0.126 295.0 2995 Shublik-A 9434.7 8880.1 2.5 1.0 0.129 289.9 3055 Shublik-A 9437.4 8882.6 3.4 1.4 0.134 283.9 3187 Shublik-A 9441.1 8886.0 6.7 5.4 0.149 273.4 3530 Shublik-A 9448.3 8892.7 5.2 5.2 0.163 259.9 3861 Shublik-A 9454.0 8897.9 4.7 3.8 0.166 248.1 3948 Shublik-A 9459.1 8902.6 3.2 1.3 0.165 238.9 3922 Shublik-A 9462.5 8905.8 25.8 20.6 0.147 214.7 3478 Shublik-A 9490.5 8931.6 8.8 3.5 0.097 169.1 2267 Shublik-A 9500.0 8940.4 20.4 8.2 0.066 141.1 1506 Shublik-A 9521.4 8960.8 7.6 3.0 0.041 105.4 894 Shublik-A 9529.0 8968.4 16.4 6.6 0.020 83.1 407 Shublik-C 9545.4 8984.8 7.3 .7 0.006 54.4 123 Shublik-C 9552.7 8992.1 16.4 6.6 0.000 .0 0 Shublik-C 9569.1 9008.5 12.9 5.2 0.000 .0 0 Shublik-C 9582.0 9021.4 5.6 2.2 0.000 .0 0 Shublik-C 9587.6 9027.0 5.7 .6 0.000 .0 0 Eileen 9593.3 9032.7 13.7 _ 5.5 0.000 .0 0 Eileen 9607.0 9046.4 14.5 11.6 0.000 .0 0 Eileen 9621.5 9060.9 55.0 44.0 0.000 .0 0 9 • • client chlu berge1� Well : MPB-30 it !" �i Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 200klbs frac design Exposure Time Prediction by Step Step Name Fluid Name Pump Fluid Perforation Exposure at Exposure Rate Volume Injection BUST of aboveWatch (bbl/min) Ibbl) Temp. 235 degF Temp.of (degF) iminl 230 degF (min) PAD YF130FIexD 30.0 450.0 135 22.6 22.6 1.0 PPA YF130FIexD 30.0 57.3 101 21.3 21.3 2.0 PPA YF130FIexD 30.0 54.9 100 16.3 16.3 3.0 PPA YF130FIexD 30.0 52.7 99 9.4 9.4 4.0 PPA YF130FIexD 30.0 50.6 98 0.0 0.0 5.0 PPA YF130FIexD 30.0 48.7 97 0.0 0.0 6.0 PPA YF130FIexD 30.0 46.9 96 0.0 0.0 7.0 PPA YF130FIexD 30.0 45.3 96 0.0 0.0 8.0 PPA YF130FIexD 30.0 43.8 96 0.0 0.0 9.0 PPA YF130FIexD 30.0 42.3 95 0.0 0.0 10.0 PPA YF130FIexD 30.0 41.0 95 0.0 0.0 11.0 PPA YF130FIexD 30.0 39.7 94 0.0 0.0 12.0 PPA YF130FIexD 30.0 208.9 94 0.0 0.0 Flush WF130 30.0 107.0 Freeze prat Freeze prote 30.0 33.0 93 0.0 0.0 10 • i Client : Hilcorp Alaska Schlumberger Wet MPB-30 t► 1 1"ufi 4J I Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 200klbs frac design Section 5: Propped Fracture Simulation Results (1) ACL Fracture Profile and Proppant Concentration Plot FracCADE` use-30A"" 20Guaaerr,333.3. ID Apr AV7 ,.:i Fix xe iro4re ena Dropper 2C3ree31333x 6700 .. a.oa- ..._ -3,.. MI on w• • - t) to tY. 1, 1•30 g ]0]A: fl .g 6900• - . r lii 232A•,. . d Mk 2A•32 n.2 B9aa• t ,.3.330 I Pr mMOa9lax t, 2190 5a:_ 869P .e 3a l d C i 0.2 Q 3 0 a 600 $2 Sves-Ps ACL MYCY.at~gum•. _ Cr' '"S LO a (2) Treating Plot 13 Botbact.Pawn]• Surface Pawn. — 70004 R. — bot :: 50 513 ro 7i.iC i 40 Y 6000 . 5000 t. 1a 1 10 3000 2000 • '0 0 10 20 30 40 so 60 70 60 00 /0 TaamraT.ro-min 11 • • Client : Hilcorp Alaska Schlumberger Well : MPB-30 Schlumberger Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 200klbs frac design Section 6: Fluid Descriptions 2%KCI brine • M117,Potassium Chloride 166.00 lb/mgal YF130FIexD • J580,Gelling Agent 30.00 lb/mgal • L071,Temporary Clay Stabilizer 2.00 gal/mgal • J450,Stabilizer 0.50 gal/mgal • U028,Activator 2.00 gal/mgal • J604,Crosslinker 2.50 gal/mgal • F103,EZEFLO Surfactant 1.00 gal/mgal • M275,Microbiocide 0.30 lb/mgal • J569,EB-CLEAN Med Temp Breaker 1.00 lb/mgal WF130 • M275,Microbiocide 0.50 lb/mgal • L071,Temporary Clay Stabilizer 2.00 gal/mgal • J580,Gelling Agent 30.00 lb/mgal g • F103,EZEFLO Surfactant 1.00 gal/mgal • J569,EB-CLEAN Med Temp Breaker 1.00 lb/mgal Freeze protect • M117,Potassium Chloride 83.00 lb/mgal 12 • Client : Hilcorp Alaska Schlumberger Well : MPB-30 Schlumberger Formation : Sag River District : Prudhoe Bay Country : United States Loadcase 200klbs frac design Section 7: Treatment Fluid Data Fluid data is given at 7.094 md. Fluid Name 2%KCI brine YF130FIex0 Friction Rate Low(bbl/min) 5.0 1.0 Pressure Low(psi/1000ft) 10.0 20.0 Rate Pivot(bbl/min) 25.0 10.0 Pressure Pivot(psi/1000ft) 400.0 40.0 Rate High(bbl/min) 60.0 100.0 Pressure High(psi/1000ft( 1000.0 500.0 Fluid Loss C„, (ft/min0.5) 1.0E+0 5.5E-3 Spurt(gal/100ft2) 0.0 0.0 C,(ft/min0.5) 1.9E-2 3.5E-3 Rheology Temperature(degF) 235 235 Time(hr) 0.0 0.0 Behavior Index(N') 1.00 0.67 Consist.Index(KS)(Ibf.s^n/ft2) 5.21E-6 4.99E-2 Viscosity©Shear Rate(cP) 0.250 307.109 Shear Rate(1/s) 170 170 13 • s Client : Hilcorp Alaska YUh1Itfi he1-gfir Well : MPB-30 It Formation : Sag River District I Prudhoe Bay Country : United States toadcase : 200klbs frac design Fluid Name WF130 Freeze prote Friction Rate Low(bbl/min) 1.0 0.0 Pressure Low(psi/1000ft( 1.2 0.0 Rate Pivot(bbl/min) 30.0 30.0 Pressure Pivot(psi/1000ft) 200.0 300.0 Rate High(bbl/min) 100.0 63.7 Pressure High(psi/1000ft) 300.0 1000.0 Fluid Loss Cs.„ (ft/min0.5) 5.5E-3 1.0E+0 Spurt(gal/100ft2) 1.6 0.0 C,(ft/min0.51 4.7E-3 1.9E-2 Rheology Temperature(degF) 235 235 Time(hr) 0.0 0.0 Behavior index(N') 1.00 1.00 Consist.Index(K')(Ibf.s^n/ft2) 2.09E-5 5.21E-6 Viscosity t Shear Rate(cP) 1.000 0.250 Shear Rate(1/s) 170 170 14 • • Client Hilcorp Alaska Sbill 11blliNlilberger Well MPB-30 13 6 Formation : Sag River District Prudhoe Bay Country : United States Loadcase : 200klbs frac design Section 8: Proppant Data Proppant Permeability is calculated based on the following parameters: BH Static Temperature: 235 degF Stress on Proppant: 3410 psi Propped Fracture Conc.: 1.00 lb/ft2 Average Young's Modulus: 4.317E+06 psi Proppant Data Proppant Name Specific Mean Pack Permeability Gravity Diameter Porosity (md) (in) (%) Jordan Unimin 20/40 2.65 0.022 35.0 161252 CarboLite 16/20 2.74 0.043 35.0 894806 16/20 CarboBond Lite 2.59 0.041 39.3 554190 crt Proppant Permeability Plot Proppant P.meabtli y .f2Y. .231 10:0300 111, 906000.._ 4 800.700 g 1 707000' 600000 r---- 3-u,iauYiJ�Vo 5C00007 ca.tam/640:_. -- -- 16,20Carullnid �— ------ .. a00000 . 1CS000 o loon 8000 y0p] s WA 7000 8600 3000 10000 11000 12000 13200 14000 15 • I Client : Hilcorp Alaska Se lumbe-ger well : MPB-30 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 200klbs frac design Section 9: Hole Survey Hole Survey MD ND Deviation Deviation Azimuth Azimuth Dogleg (ft) (ft) Angle Build Rate Angle Build Rate Severity (deg) (deg/100ft) (deg) (deg/100ft) (deg/100ft) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 100.0 100.0 0.0 0.0 0.0 0.0 0.0 200.0 200.0 0.0 0.0 0.0 0.0 0.0 300.0 300.0 0.0 0.0 0.0 0.0 0.0 400.0 400.0 0.0 0.0 0.0 0.0 0.0 500.0 500.0 0.0 0.0 0.0 0.0 0.0 600.0 600.0 0.0 0.0 0.0 0.0 0.0 700.0 699.9 4.0 4.0 230.0 -130.0 4.0 800.0 799.4 8.0 4.0 230.0 0.0 4.0 900.0 897.8 12.0 4.0 230.0 0.0 4.0 1000.0 994.8 16.0 4.0 230.0 0.0 4.0 1100.0 1090.2 18.8 2.8 222.4 -7.6 3.6 1200.0 1184.1 21.4 2.6 214.7 -7.7 3.7 1300.0 1277.3 21.4 0.0 214.7 0.0 0.0 1400.0 1370.4 21.4 0.0 214.7 0.0 0.0 1500.0 1463.5 21.4 0.0 214.7 0.0 0.0 1600.0 1556.6 21.4 0.0 214.7 0.0 0.0 1700.0 1649.7 21.4 0.0 214.7 0.0 0.0 1800.0 1742.8 21.4 0.0 214.7 0.0 0.0 1900.0 1835.9 21.4 0.0 214.7 0.0 0.0 2000.0 1929.0 21.4 0.0 214.7 0.0 0.0 2100.0 2022.1 21.4 0.0 214.7 0.0 0.0 2200.0 2115.2 21.4 0.0 214.7 0.0 0.0 2300.0 2208.3 21.4 0.0 214.7 0.0 0.0 2400.0 2301.4 21.4 0.0 214.7 0.0 0.0 2500.0 2394.5 21.4 0.0 214.7 0.0 0.0 2600.0 2487.6 21.4 0.0 214.7 0.0 0.0 2700.0 2580.7 21.4 0.0 214.7 0.0 0.0 2800.0 2673.8 21.4 0.0 214.7 0.0 0.0 2900.0 2766.9 21.4 0.0 214.7 0.0 0.0 3000.0 2860.0 21.4 0.0 214.7 0.0 0.0 3100.0 2953.1 21.4 0.0 214.7 0.0 0.0 3200.0 3046.3 21.4 0.0 214.7 0.0 0.0 3300.0 3139.4 21.4 0.0 214.7 0.0 0.0 3400.0 3232.5 21.4 0.0 214.7 0.0 0.0 3500.0 3325.6 21.4 0.0 214.7 0.0 0.0 3600.0 3418.7 21.4 0.0 214.7 0.0 0.0 3700.0 3511.8 21.4 0.0 214.7 0.0 _ 0.0 3800.0 3604.9 21.4 0.0 214.7 0.0 0.0 16 • • Client : Hilcorp Alaska �j ,ii SehlUmbernnr Well : MPB-30 Il I� Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 200klbs frac design Hole Survey MD TVD Deviation Deviation Azimuth Azimuth Dogleg (ft) (ft) Angle Build Rate Angle Build Rate Severity (deg) (deg/100ft) (deg) (deg/100ft) (deg/100ft) 3900.0 3698.0 21.4 0.0 214.7 0.0 0.0 4000.0 3791.1 21.4 0.0 214.7 0.0 0.0 4100.0 3884.2 21.4 0.0 214.7 0.0 0.0 4200.0 3977.3 21.4 0.0 214.7 0.0 0.0 4300.0 4070.4 21.4 0.0 214.7 0.0 0.0 4400.0 4163.5 21.4 0.0 214.7 0.0 0.0 4500.0 4256.6 21.4 0.0 214.7 0.0 0.0 4600.0 4350.1 20.1 -1.3 215.1 0.4 1.3 4700.0 4444.5 18.5 -1.6 215.8 0.6 1.6 4800.0 4539.3 18.5 0.0 215.8 0.0 0.0 4900.0 4634.1 18.5 0.0 215.8 0.0 0.0 5000.0 4729.0 18.5 0.0 215.8 0.0 0.0 5100.0 4823.8 18.5 0.0 215.8 0.0 0.0 5200.0 4918.6 18.5 0.0 215.8 0.0 0.0 5300.0 5013.4 18.5 0.0 215.8 0.0 0.0 5400.0 5108.2 18.5 0.0 215.8 0.0 0.0 5500.0 5203.0 18.5 0.0 215.8 0.0 0.0 5600.0 5297.9 18.5 0.0 215.8 0.0 0.0 toco 5700.0 5392.7 18.5 0.0 215.8 0.0 0.0 13 5800.0 5487.5 18.5 0.0 215.8 0.0 0.0 ,e` 5900.0 5582.3 18.5 0.0 215.8 0.0 0.0 ..," 6000.0 5677.1 18.5 0.0 215.8 0.0 0.0 6100.0 5771.9 18.5 0.0 215.8 0.0 0.0 6200.0 5866.7 18.5 0.0 215.8 0.0 0.0 6300.0 5961.6 18.5 0.0 215.8 0.0 0.0 6400.0 6056.4 18.5 0.0 215.8 0.0 0.0 6500.0 6151,2 18.5 0.0 215.8 0.0 0.0 6600.0 6246.0 18.5 0.0 215.8 0.0 0.0 6700.0 6340.8 18.5 0.0 215.8 0.0 0.0 6800.0 6435.6 18.5 0.0 215.8 0.0 0.0 6900.0 6530.5 18.5 0.0 215.8 0.0 0.0 7000.0 6625.3 18.5 0.0 215.8 0.0 0.0 7100.0 6720.1 18.5 0.0 215.8 0.0 0.0 7200.0 6814.5 19.8 1.3 223.6 7.8 2.9 7300.0 6908.3 21.0 1.3 236.4 12.8 4.6 7400.0 7001.5 21.4 0.3 250.2 13.8 5.0 7500.0 7094.3 22.6 1.3 261.9 11.7 4.6 7600.0 7186.7 22.6 0.0 261.9 0.0 0.0 7700.0 7279.0 22.6 0.0 261.9 0.0 0.0 7800.0 7371.3 22.6 0.0 261.9 0.0 0.0 7900.0 7463.6 22.6 0.0 261.9 0.0 0.0 17 • • Client : Hilcorp Alaska SCII�JIIIMIs(�ergen Well : MPB-30 ! Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 200ktbs frac design Hole Survey MD ND Deviation Deviation Azimuth Azimuth Dogleg (ft) (ft) Angle Build Rate Angle Build Rate Severity (deg) (deg/100ft) (deg) (deg/100ft) (deg/100ft) 8000.0 7555.9 22.6 0.0 261.9 0.0 0.0 8100.0 7648.2 22.6 0.0 261.9 0.0 0.0 8200.0 7740.5 22.6 0.0 261.9 0.0 0.0 8300.0 7832.8 22.6 0.0 261.9 0.0 0.0 8400.0 7925.1 22.6 0.0 261.9 0.0 0.0 8500.0 8017.4 22.6 0.0 261.9 0.0 0.0 8600.0 8109.7 22.6 0.0 261.9 0.0 0.0 8700.0 8202.0 22.6 0.0 261.9 0.0 0.0 __ 8800.0 _w 8294.3 22.6 0.0 261.9 0.0 0.0 8900.0 8386.6 22.6 0.0 261.9 0.0 0.0 9000.0 8478.9 22.6 0.0 261.9 0.0 0.0 9100.0 8571.2 22.6 0.0 261.9 0.0 0.0 9200.0 8663.5 22.6 0.0 261.9 0.0 0.0 9300.0 8755.8 22.6 0.0 261.9 0.0 0.0 9400.0 8848.1 22.6 0.0 261.9 0.0 0.0 9500.0 8940.4 22.6 0.0 261.9 0.0 0.0 9513.0 8952.4 22.6 0.0 261.9 0.0 0.0 1.4 to 18 • 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 Fracturing Program. From the Frac design modeling the highest anticipated well head pressure for the Frac job is predicted to be 5,026 psi. The 7"casing above and below the packer set depth will be pressure tested to 3,700 psi. The 4-1/2" production tubing will be pressure tested to 5,000 psi. During the Frac.Job, 2,000 psi will be maintained on the back side of the 4-1/2"frac string/production tubing. Therefore the maximum differential pressure that the tubing will be subjected to should be 5,000 psi. (7,000 psi GORV Max Pressure Setting—2,000 psi on the casing by tubing annulus.) The calculated maximum treating pressure is 5,026 psi. • 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; 9,314' MD/8,769TVD (Note: This depth is the predicted initialization depth of the fracture. The fracture is expected to grow both up and downward and may actually penetrate into the Kingak on the top and the Shublik shale below the Sag River formation but will not break through either shale.) (ii) a description of each method and assumption used to determine designed fracture height and length: The MP B-30 fracture stimulation was modeled using Schlumberger FracCADE program. The input parameters are attached. • Section 13-20 AAC 25.283(a)(13) Post Fracture Wellbore Cleanup and Fluid Recovery Plan Post Frac well flow back will be to a tank either directly or through a portable test separator to bleed down pressure and clean up the well. Once well fluids have cleaned up,the well will be turned over to production and placed into the system. (Initial flowback fluids will be taken from the tank to the G&I disposal facility and injected.) Contingency: If the well does not flow back on its own,then a Coil Tubing Unit will be placed on the well and the well cleaned out using nitrified fluids. Coiled Tubing Procedure: 1. MIRU CTU. 2. Pick up lubricator. Stab on to well. 3. Pressure Test BOPE to 250psi low/3,500psi high. 4. Open tree and count turns on valves. Record in ops cab. 5. Make up coil connector pull test 25k. Make up Cleanout BHA with nozzle.Start RIH, perform weight checks as needed. RIH W/Coil at running speeds not to exceed 120 ft/min. Note: Min ID is 3.725"through XN profile. 6. Attempt to dry tag fill. Start cleaning out to PBTD. Come online with 2%safe lube (friction reducer) if needed. This should aid with metal to metal friction. 7. Come online with N2 at 800-1500 scf/min and fluid rate of 1.5 bbls/min if needed to get good returns . Cleanout to PBTD at+/-9,750MD.Circulate hole clean. 8. POOH w/coil. 9. RDMO Coil Unit. 10. Turn well over to production. 6 • n Coil Tubing Unit Fluid Flow Diagram Cleanout w/Nitrogen SEAWATER • W/ FOAMER 400 BBL UPRIGHT (: -' M...7y. SEAWATER F• 1: 400 BBL UPRIGHT FOAMER r E .F; � Mill ` ffi �i . ?W - .. at. Ilt 0 .e, ., r A _11_"J1,,j®. s A NITROGEN PUMP OPn .1 ..., To Flowline Ela',,j Q '''.ra favki Choke Manifold NITROGEN TANK • aaaaa� Y LEGEND. 500 BBL KILL TANK 1 < Fluids Pumped A Fluids Returned Q 50 BBL FREEZE Valve Open M Valve Closed I♦ PROTECT TANK Gate Valve D4 Ball Valve CO3 Butterfly Valve N Lo Torq Valve DW Check Valve N Manual Choke I Updated 11/22/15 Pressure Gauge 0 STANDARD WELL PROCEDURE HHileorp 11a ka.,,1,u: 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 ! • �`�, 3\ f1 Well Field API PTD POOL Type MPB-01 MPU 50029204900000 1800750 TER WSW MPB-02 MPU 50029206620000 1811420 SB PWI __ MPB-03 MPU 50029207320000 1820560 KR 1-OIL MPB-04A MPU 50029207480100 1821000 KR 1-OIL MPB-05A MPU 50029207720100 1851480 KR PWI MPB-06 MPU 50029212760000 1850130 KR 1-OIL MPB-07 MPU 50029213240000 1850620 KR 1-OIL MPB-08 MPU 50029213250000 1850630 KR PWI MPB-09 MPU 50029212970000 1850340 KR 1-OIL MPB-10 MPU 50029212800000 1850170 KR 1-OIL MPB-11 MPU 50029213050000 1850430 KR PWI MPB-12 MPU 50029213380000 1850800 KR PWI MPB-13 MPU 50029213480000 1850930 KR PWI MPB-14 MPU 50029213660000 1851120 KR PWI MPB-15 MPU 50029213740000 1851210 KR 1-OIL MPB-16 MPU 50029213840000 1851490 KR 1-OIL MPB-17 MPU 50029214340000 1852090 KR PWI MPB-18 MPU 50029214500000 1852290 KR PWI MPB-19 MPU 50029214510000 1852300 KR 1-OIL MPB-20 MPU 50029215240000 1860050 KR PWI MPB-21 MPU 50029215350000 1860230 KR 1-OIL MPB-22A MPU 50029215090200 2081680 KR 1-OIL MPB-23 MPU 50029219150000 1890160 KR 1-OIL MPB-24 MPU 50029226420000 1960090 UGNU DW MPB-25 MPU 50029228410000 1972330 KR WAG MPB-27 MPU 50029232330000 2042210 SB PWI MPB-28 MPU 50029235660000 2160270 SB 1-OIL MPB-29 MPU 50029235640000 2160150 SB PWI MPB-30 MPU 50029235710000 2161530 SR 1-OIL MPB-32 MPU 50029235700000 2161510 SB 1-OIL MPB-33 MPU 50029235730000 2161640 SB PWI MPB-34 MPU 50029235690000 2161390 UGNU DW MPB-50 MPU 50029232400000 2042520 UGNU DW Status Producing Injecting Shut in Shut in LTSI Shut in LTSI LTSI Producing Producing LTSI LTSI Shut in LTS I Producing Producing LTSI Injecting Shut in Injecting Producing Producing Shut in Injecting Injecting Injecting Producing Injecting New well - not producing yet Producing Injecting Shut in Injecting • 410 Bettis, Patricia K (DOA) From: Paul Chan <pchan@hilcorp.com> Sent: Friday,April 21, 2017 2:27 PM To: Bettis, Patricia K(DOA) Cc: Stan Porhola;Wyatt Rivard;Taylor Wellman Subject: RE: MPU B-30(PTD 216-153): Sundry Application Attachments: MPU B-PAD WELLS 4-21-17.xlsx Patricia Attached is the list of wells on B-pad with the data requested. Please let me know if you need any further information Thanks Paul than Senior Operations Engineer Alaska North Slope Team Hilcorp Alaska LLC • (907)777—8333 (w) (907)444—2881 (c) From: Bettis, Patricia K(DOA) [mailto:patricia.bettis@alaska.gov) Sent:Thursday,April 20, 2017 3:10 PM To: Paul Chan<pchan@hilcorp.com> Subject: FW: MPU B-30(PTD 216-153): Sundry Application Good afternoon Paul, Please see the email below. Patricia From: Bettis, Patricia K(DOA) Sent:Thursday, April 20,2017 2:30 PM To:Stan Porhola <sporhola@hilcorp.com> Subject: MPU B-30(PTD 216-153): Sundry Application Good afternoon Stan, Please provide a table listing all wells within one-half mile radius of MPU B-30. Include the type of well (producer, injector, water supply well,etc), status current status(producing, P&A, shut-in, etc), and what formation or reservoir the well is completed in. Thank you, 1 • Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Ste 100 Anchorage,AK 99501 Tel: (907)793-1238 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 Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. 2 41) • HALLI B U RTO N 'Cern Service HILCORP ALASKA LLC - EBUS For:James Lott Date:Tuesday,May 09,2017 HILCORP B-30 PRODUCTION LINER 1ST STAGE B-30 7"Production Liner First Stage Job Date:Tuesday,May 09,2017 Sincerely, Jeff Helms • Leal Notice Warning Disclaimer Although the information contained in this report is based on sound engineering practices,the copyright owner(s)does(do)not accept any responsibility whatsoever,in negligence or otherwise,for any loss or damage arising from the possession or use of the report whether in terms of correctness or otherwise.The application,therefore,by the user of this report or any part thereof,is solely at the user's own risk. Limitations of Liability Except as expressly set forth herein,there are no representations or warranties by Halliburton,express or implied,including implied warranties of merchantability and/or fitness for a particular purpose.In no event will Halliburton or its suppliers be liable for consequential, incidental,special,punitive or exemplary damages(including,without limitation,loss of data,profits,use of hardware,or software). Customer accepts full responsibility for any investment made based on results from the Software.Any interpretations,analyses or modeling of any data,including,but not limited to Customer data,and any recommendation or decisions based upon such interpretations, analyses or modeling are opinions based upon inferences from measurements and empirical relationships and assumptions,which inferences and assumptions are not infallible,and with respect to which professional may differ.Accordingly,Halliburton cannot and does not warrant the accuracy,correctness or completeness of any such interpretation,recommendation,modeling or other products of the Software Product.As such,any interpretation,recommendation or modeling resulting from the Software for the purpose of any drilling, well treatment,production or financial decision will be at the sole risk of Customer.Under no circumstances will Halliburton or its suppliers be liable for any damages. ©2015 Halliburton.All Rights Reserved • HALLIBURTON Customer: HILCORP ALASKA LLC-EBUS Job:HILCORP B-30 PRODUCTION LINER 1ST STAGE Case:B-30 7"Production Liner First Stage I SO#:904018240 Table of Contents 1.0 Real-Time Job Summary 4 1.1 Job Event Log 4 2.0 Attachments 5 2.1 Job Graph.png 5 2.2 Pump Fluids.png 6 _ iCern- Service (v.4.2.393) Page 3 Created:Tuesday,May 09,2017 • 0 O , _ , as 1./) Cl N U E o d \ a u_ C a W Ol e-I W vt a u ^ 0 a Y c O .0 E O• E V" MAi " 1 H V Z- N CCl„' ei O a F- 00 V a' / Ol el ei C E cc do t0 r0 N A V N 0 C `O J W 2k N -0 N V 6 .O O O ° Q Z O ~ d aa.. 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L 1.0 3 N LnCD as °° a cc� a ca ° o m o a� (,) N O 0. aD 0 TU C •L •a) a+(13 Ln c LA o 1° -° (1) o to ks) ccv, a) O V) U OC O L O v a) x afa ill N i- -o a _ °' — Nj •0 CJ L ri Z L a)VI VI �° 'a Sim CI E a h 1— v H o in -C iii , Cra v 0.3 er v.13 a= n; M O al ° CI cNh i v id COu. • °i I � v .� c�, 3 ° i' 01•� o a �, O. v 0 $ O V tai 0 N, i V N d ocO. rn v s O C o in ! W 'a c o o Q G v v v cc v '�` o ` o 0 0 Q ,n "a v, i +-+ L c V V` O taiin ° o o 0 3 a !O c •- z a v 1 N U E o . v a, t I v a c=, h n., 3 c S. v E e H 06 o °i U 4 c°, = oma, tt L. c U y Z C o �` c O Of ° _ z r`r. Ln c ° v c v o O c o il •o c o O y a a.�' , c° `n cu 1 in opo1-3 . cu a° CL a o > a 1 U - • Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Saturday, May 06, 2017 10:52 PM To: Joe Engel Cc: Paul Mazzolini C Subject: Re: MPB-30 Update and Question z lS/ 3 Joe, You have approval to use slips to land the 7"casing in order to allow rotation during the 1st stage of cementing. As we discussed wait 2-3 hours after 2nd stage to verify well is stable and allow cement to cure before pulling BOP stack. Update MOC with change. Regards, Guy Schwartz AOGCC Sent from my iPhone On May 6,2017,at 9:17 AM,Joe Engel<jengel@hilcorp.com>wrote: Guy— I wanted to keep you updated on MPB-30 progress and a potential change to our plan forward. We TD'd on Thursday at 9620' MD,cleaned the hole up,weighted up to 10.8 for shale stability and POOH with minimal issues.Currently we are changing our rams t/7"solid bodies and testing. Our plan forward is to RU and run 7"casing t/—9605' MD and perform our 7"two stage cement job. Our original plan was to land the 7"on the casing hanger, however in order to facilitate the best cement job possible we would like to rotate and reciprocate during our cement job,which is not possible with the LH threaded landing joint. Our new path forward is to plan to set casing slips, instead of using the hanger.This will require us to ND the stack with the open annulus to set the slips and pack off,and then NU the stack to continue well work. Our barriers in place at the time that we ND will be 10.8 ppg KW mud inside the casing and the annulus and cement isolating all hydrocarbon zones(confirmed with good returns during the cement job).We will monitor the 9-5/8"x 7"annulus for 1 hr before ND to ensure the well is under control. Please let me know if you are ok with this change and if you would like us to submit a sundry. We have a 7" hanger on location, ready to run and if we do not hear back from you we will use that as per the original plan. If you have any questions,do not hesitate to let me know.Thank you for your time. 1 OF T� • • \ THE STATE Alaska Oil and Gas o fA /� c /� Conservation servation Commission L1Z�7 !1Z }�---~ 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OF ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Paul Mazzolini Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk and Sag River Oil Pools, MPU B-30 Permit to Drill Number: 216-153 Sundry Number: 317-169 Dear Mr. Mazzolini: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cath P. Foerster Chair DATED this 4-- day of May, 2017. RBDMS ()-' t1AY - 3 2017 RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APR 2 6 2017 APPLICATION FOR SUNDRY APPROVALS AO //G�.J� 20 AAC 25.280 t„/ 1.Type of Request: Abandon ❑ Plug Perforations 0 Fracture Stimulate 0 Repair Well 0 Operations shutdown 0 Suspend DIA, Perforate 0 Other Stimulate 0 Pull Tubing 0 Change Approved Program Q Plug for Redrill j Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: 0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory 0 Development 0 216-153 3.Address: Stratigraphic 0 Service ❑ 6.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 50-029-23571-00-00 - 7.If perforating: 8.Well Name and Number: ct��What Regulation or Conservation Order governs well spacing in this pool? C.O 423 7.;� / MPU B-30 ^. Will planned perforations require a spacing exception? Yes ❑ No Q 9.Property Designation(Lease Number): 10.Field/Pool(s): Pil) (SHL)ADL047438/(TPH/BHL)ADL047437 ' Milne Point Field/Sag River Oil Pool ( / A/ 0 J,,,k ?t\ .r z)r) 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): 9,650' 9,100' 7,190 , , 6,805' 3368 7,190',7,689' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 20" 80' 80' Surface 5,215' 9-5/8" 5,215' 4,932' 5750 3090 Intermediate Production 9,634' 7" 9,634' 9,082' 7240 5410 Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 7,220'-7,230' 6,835'-6,845' N/A N/A N/A Packers and SSSV Type: N/A Packers and SSSV MD(ft)and TVD(ft): N/A 12.Attachments: Proposal Summary ❑✓ Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Stratigraphic ❑ Development D , Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 4/25/2017 Commencing Operations: OIL Q, WINJ ❑ WDSPL 0 Suspended ❑ 16.Verbal Approval: Date: 4/25/2017 GAS ❑ WAG ❑ GSTOR 0 SPLUG ❑ Commission Representative: Guy Schwartz GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Paul Mazzolini Contact Name: Joe Engel Authorized Title: Drilling Manager Contact Email: jengel((X7.hiIcorp.com � Contact Phone: 777-8395 Authorized Signature: ili Date:°Q� ION /7 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 317- ICP Plug Integrity 0 BOP Test li Mechanical Integrity Test 0 Location Clearance ❑ C s FL-1r+ Other: *t 404942 061i-/ta ' Spat Initial Injection MIT Req'd? Yes ❑ No ❑, , � /f Spacing Exception Required? Yes No 2( Subsequent Form Required: / 0 —Ile 7 l// i,�`'",�',(,+� APPROVED BY RBDMS I/`' MAY - 3 2017 Approved by: COMMISSIONER THE COMMISSION Date: 5 - 2•— 1 7 1/479/77 L q-2 7`l7 Submit Form and Form 10-403 Revised 4/2017 I Ap ved application is valid for 12 m nb the from the date of approval. Attachments in Duplicate • • Well Prognosis Well: MPU B-30 Ili!carp Alaska,LLC Date:4/25/2017 Well Name: MPB-30 API Number: 50-029-23571-00-00 Current Status: Cased and cemented Leg: N/A Estimated Start Date: Ongoing Rig: Innovation Reg.Approval Form 10-403 Date Reg.Approval Rec'vd: 4/25/17 (Verbal) Regulatory Contact: Cody Dinger 777-8389 Permit to Drill Number: 216-153 First Call Engineer: Joe Engel (907) 777-8395 (0) Second Call Engineer: Paul Mazzolini (907) 777-8369 (0) AFE Number: 1612657 MPB-30 Job Summary Surface Hole—Successfully drilled 12 1/4" hole, ran 9-5/8" casing and cemented. Shoe @ 5,215' MD, Cement to surface. Production Hole (MPB-30PB1)—Successfully drilled 8-1/2" hole, and ran 7" casing to 9,643' MD. Performed 7" cement job,with partial returns and 41 bbls of losses during the job. CBL showed TOC^'7,600' MD, —84Q' below required TOC of 6,760' MD (500' MD above Kuparuk C, 7260' MD). Decision was made to abandon wellbore and r�-4 A CIBP was set at 7,689' MD and the well was perforated F/7,220'—7,230' MD for Kuparuk C isolation cement. A cement retainer was set at 7,190' MD, circulation was established through the 7"x 8-1/2" annulus at 1 bpm with 540 psi. In an attempt to establish a cementing rate, circulation rates were staged up to 2 BPM where the annulus packed off and pressure increased to 1700 psi. Multiple attempts were made to regain circulation with no success. Injection pressures increased to 1960 psi at 2 bpm,which did not give confidence that any quantity of cement could be squeezed into the annulus. Current well schematic is attached. Below is a plan forward to P&A this 7"x 8-1/2" hole (MPB-30PB1) and redrill the well. P&A Procedure for MPB-30PB1, Proposed Schematic Attached: 1. RIH w/2-7/8" stinger and lay in 100' cement plug on top of retainer @ 7190' MD(10.3 ppg mud in well) 2. POOH to above cement plug, circulate clean, pump wiper ballA.a i 3. RU test equipment, PT casing t. 2000 psi f/15 min. Chart test. N` � 4. POOH 5. PU and RIH with CIBP 6. Set CIBP at 5815' MD, POOH 7. PU Baker knives and cut 7" casing at 5715' MD, Establish circulation through cut to confirm cut is good, POOH, LD knives and inspect for goo. c 8. BOLDS, Rig up casing handling equipment, Engage hanger with landing joint 9. POOH and L/D 7" casing, RD casing running equipment 10. RIH w/ DP and stinger to lay in P&A 15.8ppg cement plug from—5815' MD (top of CIBP)to 5450' MD, POOH t. above plug 11. C&C Mud and batch mix cement for kick off plug section 12. RIH,tag first cement plug to confirm depth and lay in 15.8ppg cement kick off plug from ^'5450' MD to 5000' MD (adjust cement volumes if plug is tagged lower than expected) • • Well Prognosis Well: MPU B-30 Ililcorp Alaska,LLC Date:4/25/2017 Drilling Procedure for MPB-30, Proposed Schematic Attached: 1. WOC to reach sufficient compressive strength,simops: LD 4" DP and PU 5" DP, PU directional drilling BHA, BOPE Test(5" test joint) 2. RIH and tag cement plug with 8-1/2" Directional BHA • BHA: PDM • Logging: Resistivity and Gamma Ray 3. Drill t/9-5/8" Surface shoe at 5215' MD, and Kick off 4. Once Kick off confirmed, displace well t/9.5 ppg Baradrill N • Mud Properties: Depths Density(sag) Plastic Viscosity Yield Point LGS MBT HPHT pH 5215'-TD 9.5—11.5 15-25 15-20 <6% <20 <11.0 9-10 5. Drill 8-1/2" Hole section to TD, per Geologist and Drilling Engineer 6. At TD, CBU x3, weight up for hole stability, POOH, LD BHA 7. Change out upper pipe tames to 7" solid body rams and test same (250/4000psi), chart test 8. Run 7" casing and cement, 500' above hydrocarbon bearing zones • Cement job will be two stage, with a stage collar at the Kuparuk C • 1st Stage will bring cement 1000' MD above top of Sag, minimum • 2nd Stage will bring cement 500' MD above top of Kup, minimum 9. MU & RIH with cleanout BHA, drill out stage collar,tag top of plugs 10. PT Casing 11. POOH, LD Cleanout BHA 12. RU and E-line CBL 13. Run 4.5" Tubing as per original MPB-30 Completion Sundry 14. ND, NU 15. RDMO ' n • Milne Point Unit Current SCHEMATI Well: MPU B-30PB1 PTD: 216-153 Hilcorp Alaska,LLC KB Elev.:49.6'/GL Elev.:23.1' ...a k y 20' VOPEN HOLE/CEMENT DETAIL V4 20" Cmt w/50 bbls of Arcticset in 42"Hole 9-5/8"(2nd Stage) Cmt w/350 sks 10.7 ppg PermL,275 sx 15.8 ppg SwiftCEM in 12-1/4"Hole ES Cementer 9-5/8"(1st Stage) Cmt w/505 sks 11.7 ppg ExtendaCEM,215 sx 15.8 ppg SwiftCEM in 12-1/4"Hole 1 @1,819' ' 54 7" Cmt w/315 sks 15.8 ppg Class"G"in 8-1/2"Hole ►t r: CASING DETAIL P' 5 Size Type Wt/Grade/Conn Drift ID Top Btm 20" Conductor 78.6/A-53/Weld 19.100" Surface 80' 9-5/8" s^ k 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 5,215' 7" Production 26/L-80/DWC/C 6.151" Surface 9,634' WELL INCLINATION DETAIL 1 KOP @ 600' MD Max Hole Angle=23.79 deg at 8,366' MD JEWELRY DETAIL Est TOC r.,, 2 No Depth Drift ID Item +L7,600' "+i'�`-- 1 7,190' Cement Retainer v 2 7,689' CIBP kq pi 1Y PERFORATION DETAIL Top(MD) Btm(MD) FT Date Status 7,220' 7,230' 10' 4/24/17 Open 1 lb t wt 1,44 wl GENERAL WELL INFO g il API:50-029-23571-70-00 it Drilled and Cased by Innovation#1 .4 71 V TD=9,650(MD)/TD=9,100'(TVD) PBTD=9,547'(MD)/PBTD=8,952'(TVD) Revised by:CJD 4/25/17 Milne Point Unit li PropostA Abandonment SCHEMAIllt WeII: MPU B-30PB1 PTD: 216-153 Ililcorp Alaska,LLC KB Elev.:49.6'/GL Elev.:23.1' 4 41 20" A. OPEN HOLE/CEMENT DETAIL a. a. 20" Cmt w/50 bbls of Arcticset in 42"Hole 9-5/8"(2nd Stage) Cmt w/350 sks 10.7 ppg PermL,275 sx 15.8 ppg SwiftCEM in 12-1/4"Hole ES Cementer 9-5/8"(15t Stage) Cmt w/505 sks 11.7 ppg ExtendaCEM,215 sx 15.8 ppg SwiftCEM in 12-1/4"Hole @ 1,819' • 7" Cmt w/315 sks 15.8 ppg Class"G"in 8-1/2"Hole Cmt Kckoff ., CASING DETAIL Plug F/ '' 5,450'T/ ,. i SCOCY • `` Size Type Wt/Grade/Conn Drift ID Top Btm � ..g.47.2., e, <.z.. aA 20" Conductor 78.6/A-53/Weld 19.100" Surface 80' 9-5/8" Sig Fs0. PanCm� 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 5,215' 4 Xt ;^+. Plug F/ r` t 5,815'Ti 7" Production 26/L-80/DWC/C 6.151" Surface 9,634' 4 ..' 3t- -40. 5,450 :� ``- Cut Casing ,� _ C,5,715' r�1/•�"iYJ�" L a �� is-.3 ) .3 4. WELL INCLINATION DETAIL 2 TR�etaur KOP@600 MD Max Hole Angle=23.79 deg at 8,366' MD git C JEWELRY DETAIL Est roc 1 _ 3 No Depth Drift ID Item *4 7,600 1 5,815' CIBP 2 7,190' Cement Retainer '" 3 7,689' CIBP 1 PERFORATION DETAIL I., I' ai_- Sand Top(MD) Btm(MD) FT Date Status Y;' k Sag River 7,220' 7,230' 10' 4/24/17 Open rt 4 46t i A 1/41 GENERAL WELL INFO API:50-029-23571-70-00 Drilled and Cased by Innovation#1 Id TD=9,650(MD)/TD=9,100'(TVD) PBTD=9,547'(MD)/PBTD=8,952'(TVD) Revised by:CJD 4/25/17 Milne Point Unit • "ROPOSED SCHEMA Well: MPU B-30 Last Completed: Proposed Hilcorp Alaska,LLC PTD: 216-153 KBElev.:49.6'/GLEIev.:23.1' TREE&WELLHEAD RKB—THF:23' Innovation)4 Tree CIW 4-1/16"5M ,,,_ 6? k Wellhead Seaboard Weir,3 spools,w/11"x 5M top flange 20" it 4-1/2"TC-II Tubing Hanger 9 OPEN HOLE/CEMENT DETAIL y, 20" Cmt w/50 bbls of Arcticset in 42"Hole 99-_55//88',', 2"d ) w/350 sks 10.7 ppg PermL,275 sx 15.8 ppg M in 12 1/4"Hole ES Cementer• ((1St StageStage) CmtCmt w/505 sks 11.7 ppg ExtendaCEM,215 sx 15.8 ppgSwiftCESwiftCEM in 12 1/4"Hole @1,904 7" 2 Stage Cement to Cover Sag and Kuparuk(SKS TBD) ►s CASING DETAIL , Size Type Wt/Grade/Conn Drift ID Top Btm 4 20" Conductor 78.6/A-53/Weld 19.100" Surface 80' 9.5/8" 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 5,215' 7" Production 26/L-80/DWC/C 6.151" Surface ±9,655' TUBING DETAIL 4-1/2" Tubing 12.6/L-80 1Cr/Vam Top 3.833" Surface ±9,320' r ► WELL INCLINATION DETAIL KOP @ 5,473' MD Max Hole Angle=22.40 deg F/7,575'to TD Hole angle through perforated interval:22° JEWELRY DETAIL Est TOC +/-6,80j ; No Depth Drift ID Item 4* 4 1 23' 3.833" 11"x 4-1/2"Tubing Hanger(4-1/2"TC-II Top& Btm) 2 ±9,190' 3.813" 4-1/2"XD Sliding Sleeve Min ID=3.813" ES Cementer 3 ±9,250' 3.842" 4-1/2" ROC Pressure Intake Gauge Min ID=3.842" @+7,6m' 4 ±9,300' 3.870" Baker 7"x 4-1/2" Premier Packer(598-387) Min ID=3.870" III 2 5 ±9,360' 3.725" 4-1/2"XN Profile Min ID=3.725" 6 ±9,400' 3.833" 4-1/2"WLEG Btm @ 9,400' 3 RA Tag ±9,205 I I' I& I 4 Est TOC +1-8,4W ,. III i S } c i 5 wu "' 6 GENERAL WELL INFO `SR A A API:50-029-23571-00-00 i ys Drilled and Cased by Innovation#1 TBD 1,9 A i it? eta ii to TD=9,655(MD)/TD=9,100'(TVD) PBTD=9,555'(MD)/PBTD=9,003'(TVD) Revised by:GD 4/25/17 • • Schwartz, Guy L (DOA) From: Paul Mazzolini <pmazzolini@hilcorp.com> Sent: Wednesday,April 26, 2017 3:29 PM To: Schwartz, Guy L(DOA) Cc: Joe Engel; Cody Dinger; Quick, Michael.) (DOA) Subject: RE: Forward Ops Plan for MPU B 30 (PTD 216-153) Attachments: MPU B-30 WP11 - DRAFT Report.pdf Guy, The directional plan needed a couple corrections so was not ready when Cody dropped the B 30 sundry off earlier this afternoon. Let us know if you have any questions. Thank you again for your timely response to our requests. Regards Paul From: Schwartz, Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent: Tuesday, April 25, 2017 11:41 AM To: Paul Mazzolini Cc: Joe Engel; Cody Dinger; Quick, Michael J (DOA); Regg, James B (DOA) Subject: RE: Forward Ops Plan for MPU B 30 (PTD 216-153) Paul, The procedure as outlined below is approved as written with one addition. After dumping cement on top of retainer in step#1 test the casing to 2000 psi for 15 min and chart it. A sundry would be beneficial so we can document the cement placement for the abandoned hole section ( please provide a well sketch showing the retainers and cement placement including the Kick off plug.) The abandoned hole section will have a API suffix of-70 and should be labeled B-30 PB1 for the acquired directional and OH data. Submit a sundry as soon as you can ...you have verbal approval to proceed. 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.gov). From: Paul Mazzolini [mailto:pmazzolini@hilcorp.com] Sent:Tuesday,April 25, 2017 11:02 AM To:Schwartz,Guy L(DOA)<guy.schwartz@alaska.gov> Cc:Joe Engel<jengel@hilcorp.com>;Cody Dinger<cdinger@hilcorp.com> Subject: Forward Ops Plan for MPU B 30 Guy, As discussed B 30 was perforated from 7230'—7220' MD. Stabbed into retainer set at 7190' MD and were able to establish circulation pumping at 1 BPM with 540 psi. In an attempt to establish a cementing rate the rate was staged up 1 to 2 BPM where the annulus packedoff and pressure jumped to 1700 psi. Multi le attempts were made to regain circulation with no success. Injection pressures kept increasing from 1440 psi to 1960 psi at 2 BPM which do not give us confidence that any quantity of cement could be squeezed into the annulus. It is felt that the HRZ located at 6800' MD which is an unstable shale formation has packed off above the Kuparuk C Sand at 7260' MD. Hilcorp proposes the following program going forward to isolate B 30 original wellbore from B 30A: 1. Lay in 100'cement plug on top of retainer @ 7190' MD(10.3 ppg mud in well) 2. Set CIBP at 5815' MD 3. Cut 7" casing at 5715' MD. POH and LID casing 4. RIH w/DP and stinger to lay in P&A cement plug from 5815' MD to 5450' MD 5. C&C Mud and batch mix cement for kick off plug section 6. RIH and lay in cement kick off plug from 5450' MD to 5000' MD 7. WOC and PU directional drilling BHA 8. Polish cement plug, kick off and drill to TD as per approved sidetrack directional plan (twin original wellbore,+/- 60'of separation) Hilcorp will supply a follow up email with the following: 1. MOC Page 2. Directional plan 3. Revised wellbore schematic 4. High level Drilling Program for production hole Would you like the above to be accompanied by a sundry? Call either Joe or I if you would like to discuss. Regards Paul 2 • yOF Tji g&I\ �yyy�8A THE STATE Alaska Oil and Gas �.,;"t� OAT 1 Conservation Commission 'Witt_()),-,____ __=__:..:-41* ..,,-______,..:__, _= _ 333 West Seventh Avenue k, -- -.1---- t GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 no- Main: 907.279.1433 Off+ ALAS P Fax: 907.276.7542 www.aogcc.alaska.gov Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage,AK 99503 Re: Milne Point Field, Sag River Oil Pool, MPU B-30 Permit to Drill Number: 216-153 Sundry Number: 317-151 Dear Mr. York: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, aj' P ./ - -�1T�-- Cathy . Foerster Chair DATED this I y ' day of April, 2017. RBDMS U-- D? 1 7 2017 • • RECEIVED STATE OF ALASKA APR 1 .2017 ALASKA OIL AND GAS CONSERVATION COMMISSION 14./`, APPLICATION FOR SUNDRY APPROVALS ACGCC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate 0 - Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Complete Q 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development Q • 216-153 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage Alaska 99503 50-029-23571-00-00 ' 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 423 ' Will planned perforations require a spacing exception? Yes ❑ No 0 ✓ Milne Pt Unit B-30` 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL047438/ADL 047437 ' Milne Point/Sag River Oil ` 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): ±9,512 ±8,952 ±9,430 ±8,875 3,478 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor ±80' 20" ±80' ±80' N/A N/A Surface ±5,200' 9-5/8" ±5,200' ±4,918' 5,750psi 3,090psi Production ±9,512' 7" ±9,512' ±8,952' 7,240psi 5,410psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 4-1/2" 12.6#/L-80 1 Cr/Vam Top ±9,320 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Baker 7"x 4-1/2"Prenier and N/A ±9,215'MD/±8,675 and N/A 12.Attachments: Proposal Summary Q Wellbore schematic Q 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: 4/22/2017 Commencing Operations: OIL ❑✓ • WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. ..SW Authorized Name: Bo York Contact Name: Stan Porhola Authorized Title: Operations Manager Contact Email: sporholatU7hilcorp.com ' /' Contact Phone: 777-8412 Authorized Signature:... I_ 4-14•••-- -C. EU Yu/14, Date: 4/11/2017 C / COMMISSION USE ONLY Conditions of approv�i Notify Commission so that a representative may witness Sundry Number: 31'1_ 1Gl Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: i(4 o / '->.: 66/ 112 S 11 RBDMS 1-i— Ann 1 7 2017 Post Initial Injection MIT Req'd? Yes ❑ No ❑ ,f I ` i( feepc 4) Spacing Exception Required? Yes ❑ No d Subsequent Form Required: r D-- it/ 1.. V APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date.../4 —1 7 +PKC 12)0-- y'z/r7 i3_!7 IGINAL Submit Form and Form 10-403 Revised 4/2017 Approved application is valid for 12 months from the date of approval. Attachments in Duplicate • • Well Prognosis Well: MPU B-30 I$kcora Alaska,I.I. Date:4/11/2017 Well Name: MPU B-30 API Number: 50-029-23571-00 Current Status: Currently Drilling Pad: B-Pad Estimated Start Date: April 22"d, 2017 Rig: Innovation#1 Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 216-153 (revised) First Call Engineer: Stan Porhola (907)777-8412 (0) (907) 331-8228 (M) Second Call Engineer: Paul Chan (907)777-8333 (0) (907)444-2881 (M) __ '117 e.c= _. ".i?r7tur. Askt rivarz, Current Bottom Hole Pressure: 0 psi @ 8,820'TVD (Not Drilled) Maximum Expected BHP: 4,360 psi @ 8,820' TVD (Estimated BHP/9.50 ppg EMW) MPSP: 3,478 psi (0.1 psi/ft gas gradient) Brief Well Summary: • MPU B-30 is planned as a producing oil well with a completion in the Sag River Oil Pool. PTD 216-153 (revised)approved on 3/06/2017 Objective: The purpose of this work is to install the initial 4-1/2" completion after the successful setting and cementing of the 7" production casing. Brief RWO Procedure: Continued from the approved PTD 216-153(revised)after successful setting and cementing of the 7"production casing(Step#18.15). 1. Change out 7" casing rams and install 2-7/8"x 5"VBRs. 2. Test VBR ram to 250 psi Low/4,000 psi High (hold ram and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform Test per Innovation BOP Test Procedure. b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 4"and 4-1/2"test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 3. PU 6-1/8" bit and 7" 26#Casing Scraper. 4. RIH w/4" or 4.5" workstring to PBTD(+/-9,430' MD). 5. Circ well clean w/current weight drilling mud. t\i\X 6. Test casing to 3,700 psi for 30 min and chart. Bleed casing to 0 psi. 7. Displace drilling mud to 9.5 ppg brine. 8. POOH and LID 4" or 4-1/2"workstring, bit and casing scraper. 9. RU E-line.Test lubricator to 250/4,000 psi. cest, 10. RIH w/cement bond logging tool to PBTD (+/-9,430' MD). 11. Log cement from PBTD to+/-7,000' MD(above Kuparuk River formation top). 12. POOH. RD E-line. • Well Prognosis • • • Well: MPU B-30 Meer,Allaska,I1) Date:4/11/2017 13. PU completion and RIH on 4-1/2"tubing. a. Tubing is 4-1/2" 12.6#L-80 1Cr Vam Top (Range 3) b. Sliding Sleeve @ ±9,105' MD w/3 or 4 ports plugged c. Downhole Pressure Gauge @ ±9,160' MD w/X"TEC wire to surface d. Premier Packer @ ±9,215' MD [RA tag placed just above packer] e. 4-1/2" XN (3.725" No-Go) @ ±9,273' MD [Pre-load RHC plug body] f. 4-1/2" WLEG @ ±9,320' MD 14. RIH to 2,000' MD. Circulate freeze protect to surface. 15. Continue to RIH to+/-9,320' MD. Land hanger. 16. Drop ball and rod. Pressure up and set Baker Premier Packer(start 2,500 psi/final 4,000 psi). 17. Pressure up and test tubing to 5,000 psi for 30 min and chart. Bleed tubing to 0 psi. 18. RU Slickline.Test lubricator to 250/4,000 psi. 19. RIH and pull ball and rod from XN profile at+/-9,273' MD. 20. POOH. RD Slickline. 21. Test casing to 3.700 psi for 30 min and chart. Monitor tubing for packer leaks. Bleed casing to 0 psi. 22. Bullhead diesel down the 9-5/8"x 7"for freeze protect. Install wellhead gauges. 23. Install BPV and ND BOPE. 24. NU Tree and Adapter.Test to 250/5,000 psi. 25. RDMO Innovation Rig#1. Wireline Procedure: 26. RU well house and tie-in flowlines. 27. Hook up BHP gauge to surface unit(utilize same panel as MPU B-32). 28. RU Slickline.Test lubricator to 250/4,000 psi. 29. RIH and pull RHC plug body from XN profile at+/-9,273' MD. POOH. 30. RIH and drift tubing and tag PBTD. POOH. 31. RD Slickline. 32. RU E-line.Test lubricator to 250/4,000 psi. 33. RIH w/GR/CCL to PBTD (+/-9,430' MD). Log back to surface. POOH. 34. MU 20'of 3-1/8" perf guns. 35. RIH and perforate the Sag River from +/-9,395'-9,415' MD. POOH. 36. MU 20'of 3-1/8" perf guns. 37. RIH and perforate the Sag River from +/-9,375'-9,395' MD. POOH. 38. POOH. RD E-line. 39. Turn well over to production. RU well house and flowlines.• Attachments: J' J ` 1. Proposed Schematic 5Li ' .-L Lf y 3b 2. BOPE Schematic C� 3. Proposed Tree/Wellhead . Milne Point Unit . „ . , 11 • PROPOSED Well: MPU B-30 Last Completed: Proposed tlilcorp Alaska,LLC PTD: 216-153 KBEIev.:49.6'/GLEIev.:23.1' TREE&WELLHEAD RKB—THF:23' Innovation �� Tree CIW 4-1/16"5M., 2 i.41 i4 Seaboard Weir,3 spools,w/11"x 5M top flange 20„ 1 Wellhead 4-1/2"TC-II Tubing Hanger e 4 11 14 1 OPEN HOLE/CEMENT DETAIL 4. az 20" Cmt w/±50 bbls of Arcticset in 42"Hole c, 1, 9-5/8"(2nd Stage) Cmt w/±222 sks 10.7 ppg ArticCEM,±270 sx 15.8 ppg SwiftCEM in 12-1/4"Hole I 9-5/8"(1st Stage) Cmt w/±265 sks 10.7 ppg ArticCEM,±212 sx 15.8 ppg SwiftCEM in 12-1/4"Hole ES Cementer 41 7" Cmt w/±288 sks 14.5 ppg Class"G"in 8-1/2"Hole @ 1,900' 1 CASING DETAIL ". Size Type Wt/Grade/Conn Drift ID Top Btm to i 20" Conductor 78.6/A-53/Weld 19.100" Surface ±80' 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface ±5,200' 7" Production 26/L-80/DWC/C 6.151" Surface ±9,512' 9-5/8" TUBING DETAIL 4-1/2" Tubing 12.6/L-80 1Cr/Vam Top 3.833" Surface ±9,320' WELL INCLINATION DETAIL KOP @±600' MD Max Hole Angle=±22.63 deg at±7,520' MD Hole angle through perforated interval:±22° Est TOC JEWELRY DETAIL 700 0 'ti Ct No Depth Drift ID Item 1 ±23' 3.833" 11"x 4-1/2"Tubing Hanger(4-1/2"TC-II Top& Btm) i 2 ±9,105' 3.813" 4-1/2"XD Sliding Sleeve Min ID=3.813" 3 ±9,160' 3.842" 4-1/2" ROC Pressure Intake Gauge Min ID=3.842" vt t,, 4 ±9,215' 3.870" Baker 7"x 4-1/2" Premier Packer(598-387) Min ID=3.870" wt 5 ±9,273' 3.725" 4-1/2"XN Profile Min ID=3.725" 6 ±9,319' 3.833" 4-1/2"WLEG Btm @±9,320' '0 I I II PERFORATION DETAIL 2 ii! Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status Sag River ±9,375' ±9,415' ±8,825' ±8,862' 40' Prop Prop �# 3 s RA Tag �,� �? 3-1/8"Perf Guns 9,209; i,A GENERAL WELL INFO vt IJ i �'tta ti_ , API:50-029-23571-00-00 , Drilled and Cased by Innovation#1 TBD n ' a 5 4; SAG { PA nrl rl A w TD=±9,512(MD)/TD=±8,952'(TVD) PBTD=±9,430'(MD)/PBTD=±8,875'(TVD) Revised by:STP 4/03/17 S Milne Point Innovation Rig 1 BOPE ifeku,rf. ‘14.1.aw. 13-5/8" BOPE0 m [min in 5M Control Technology Annular BOP [ l � 5M Control i 4 Technology Double Ram � 'c � P-ao; 61 .7.; 1°4_1 r [in 3-1/8"Kill Line � II 1 Choke Line E _E _ o 5M Control Technology Single Ram 13-5/8"x 5M 11"x5M �- ,1[ ,1 /f1► -11-- [:i ; u,li� . 9-5/8" DBL D Seal—NN, `'ri► ,'`► 2-1/16"x 5M Casing Hanger 1 Ix 5M S-22 "I 1 4 [ i35t8" 13-5/8"NOM l 9-5/8"BTC Btm x 2-1/16"x 5M 10.5"-4 SA Pin Top W/Primary Seal 20"Casing 9-5/8"Casing Updated 4/03/2017 • • PROPOSED TREE/WMPU B-30 ELLHEAD Wellhead/Tree uiEe,�rp Alasku,Lac Milne Point Unit WELL MPB-30 DATE 2/27/17 II PROPOSED Iiilcorp Alaska, LLC MIII iii, 111 I_u 11.1111111111111111111 .41111111111.11,11111... Swab valve Seaboard Model 510,4 1/16"5K, Tree Cap.Otis style,6 3/8" ACME 4 1/16" 5K,FE,DD L-U T mwn FE,DD L-U PN 348218-000 os ( , PN 564680-WD1 bed MI w1 SN SN I. 0�0• • �� Wing valve Seaboard Model 510,4 1/16"5K,FE,DD L-U "i mi PN 564680-WD1 o o\ SN :i0 to 0 a Opo jrtt 'r'Tt J SSV valve Seaboard Model je)402 510,4 1/16" 5K,FE,DD L-U PN 348434 �N, SN 1 — Master valve Seaboard Model f.I 510,4 1/16" 5K,FE,DD L-U '.,...,AI PN 564680-WD1 L.t . �� SN Tbg Hgr,Seaboard SM- 411 '`� 1) E-CL 11 x 4%z"EUE BOX ' 1 �� API 11"5K top and bottom,4" "H" -,, r BPV,ported for 2 ea 3/ • ( 8"Control line, 11, ,w/3'pup L-U,DD-NL, n PN W10220 i SN1�t ,li 0 API 13 5/6"5K I; 11 x 7",SMB 22,8.5 4 stub Csg Hgr,Seaboard i ` •5 „ - acme top x DWC box 5-22 13 5/8 x 9 5/8" I � bottom,w/DWC-C pup, mi Slip type hanger I�. `� ; 6.844 bore PN A34330 LU,DD-NL (J" \ PN A16232-001 i SN . 1 F T • THE STATE //7,.n• yam �9 Alaska Oil and Gas OfAT AS} A Conservation Commission === 333 West Seventh Avenue T., GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OF LA AS*� Fax: 907.276.7542 www.aogcc.alaska.gov Paul Maz7olini Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage,AK 99503-5832 Re: Milne Point Field, Sag River and Kuparuk River Oil Pools,MPU B-30 Hilcorp Alaska, LLC Permit to Drill Number: 216-153 revised Surface Location: 86' FSL, 4328' FEL, Sec. 18, T13N,R11E, UM, AK Bottomhole Location: 1845' FNL, 1254' FEL, Sec. 24, T13N, R10E, UM, AK Dear Mr. Mazzolini: Enclosed is the approved application for permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B)and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations o erations 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, aZ Cathy . Foerster Chair DATED this day of March,2017. RECEIVED STATE OF ALASKA 411,A OIL AND GAS CONSERVATION COMAN FEB 2 3 2017 PERMIT TO DRILL _ 20 AAC 25.005 r. l a.Type of Work: 1 b. Proposed Well Class: Exploratory-Gas ❑ Service- WAG ❑ Service-Disp n 1 c.Specify if well is proposed for: Drill ❑' Lateral ❑ Stratigraphic Test ❑ Development-Oil • Service- Winj ❑ Single Zone 1 1 Coalbed Gas ❑ Gas Hydrates ❑ Redrill❑ Reentry ❑ Exploratory-Oil ❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone U✓tib Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket 0, Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC Bond No. 022035244 , MPU B-30• 3.Address: 6. Proposed Depth: ''9, 12. Field/Pool(s): 043 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 MD: 9,512' • TVD: 8,902' h) Milne Point Unit 4a. Location of Well(Governmental Section): 7. Property Designation(Lease Number): Sag River Oil Pool Surface: 86'FSL,4328'FEL,Sec 18,T13N,R11 E,UM,AK (SHL)ADL047438/(TPH/BHL)ADL 047437 • I{, RwViAr b i Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 1833'FNL, 1173'FEL,Sec 24,T13N,R10E,UM,AK N/A 3/31/2017 Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 1845'FNL, 1254'FEL,Sec 24,T13N,R10E, UM,AK .J/:J-1 4344 Acres :,-i:): 6,644'to nearest unit boundary 4b. Location of Well(State Base Plane Coordinates-NAD 27): 10. KB Elevation above MSL(ft): 49.6 , 15.Distance to Nearest Well Open Surface: x-571962 y- 6023208 Zone-4 ' GL Elevation above MSL(ft): 23.1 to Same Pool: -11,800' 16.Deviated wells: Kickoff depth: 600 feet v 17.Maximum Potential Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 22 degrees , Downhole: 4360 Surface: 3478 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 42" 20" 78.6# A-53 Weld 80' Surface Surface 80' 80' 50 bbls from Cement Truck Stg 1 L-1140ft3/T-246ft3 12-1/4" 9-5/8" 40# L-80 DWC/C 5,200' Surface Surface 5,200' 4,918' Stg 2 L-956 ft3/T-314 ft3 8-1/2" 7" 26# L-80 DWC/C 9,512' Surface Surface 9,512' 8,952' 402 ft3 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth TVD(ft): Plugs(measured): Effect. Depth MD(ft): Effect.Depth TVD(ft): Junk(measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): 20. Attachments: Property Plat Q BOP Sketch ❑✓ Drilling Program E Time v.Depth Plot 0 Shallow Hazard Analysis Diverter Sketch ❑✓ Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050 requirements E 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Paul Mazzolini Email pmazzolini@hilcorp.com Printed Name Paul Mazzolini Title Drilling Manager b�/2 3/ Signature ��/'/GL it- ' k Phone 777-8369 Date !ZO l7 6/ Commission Use Only Permit to Drill 2 ‘53 API Number: Permit Approval See cover letter for other Number: rev SEId 50_011- 23,-71-00-00 Date: 1 Z- (/- 2d i Ce requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methan ,gas hydrates,or gas contained in shales: dOther: 1 LI0as/ Sd �vi st Samples req'd: Yes No No[l Mud log req'd:Yes � No rgr H2S measures: Yes No❑ Directional svy req'd:Yes No❑ /- S (J��y .-iv e..� 1 Spacing exception req'd: Yes ElNoZ Inclination-only svy req'd:Yes❑ No ✓[1 �J• � Post initial injection MIT req'd:Yes Ill No Cbi"--P l4v-' errs dr ;c /i-e•e"...c.fwt.,_ r,Lw,. Ill APPROVED BY / Approved by:e/ a° "s9911:1,------- A COMMISSIONER THE COMMISSION Date:3 -77 f l' O R I C IA ' "3- 1.7- Submit Form and Form 10-401 revised 11/2015) h e t 24 months from t)tgi date of approval(20 AAC 25.005(g)) Attachments in Duplicate // 2(%7; • Paul Mazzolini Hilcorp Alaska, LLC Drilling Manager P.O. Box 244027 Anchorage,AK 99524-4027 Tel 907 777 8369 Email pmazzolini@hilcorp.com Hilcorp Alaska,LEI: 2/23/2017 RECEIVED Commissioner FEB 2 3 2017 Alaska Oil &Gas Conservation Commission � � ��,, 333 W. 7th Avenue Anchorage, Alaska 99501 ✓r✓' tik Re: MPB-30 g/1-' 21Z, 3-341 Dear Commissioner, Enclosed for review and approval is the Revised Permit to Drill for MPB-30 well. MPB-30 was initially permitted as a Kuparuk producer, but Hilcorp has identified a Sag River target that can be effectively drilled from n the MPB-30 well slot. / „,re-, �(,4aw ( L S „,...-lfwe>fJ el scc.rFz.e.. C c.,i'az O;. 'v�.�, /`3(�L �—`�s /l�v.�t�w."fr.• MPU B-30 is a grassroots producer with the Sag River asThe primary and the Kuparuk C sand as a secondary . target. MPU B 30 is planned as a slightly deviated well with the kick off point at 600' MD/TVD. The hole angle deviates slightly from 17-21 degrees in the surface hole and then is built to a maximum hole angle of 22 degrees and held to TD at 9512' MD/8952' TVD (based upon depths formations are encountered)through the Sag River and just into the top of the Shublik Formation./ Drilling operations are expected to commence approximately March 31st, 2017. The Innovation Rig will be used to drill and complete the well. After reviewing the LWD logs obtained while drilling the well, a determination will be made whether or not fracture stimulation be required at a later date. The base plan, however, is to fracture stimulate the well if a Sag River producer and will be reviewed if a Kuparuk producer. A CBL will be run on the 7" production casing in the event fracture stimulation is required at a later date. If you have any questions, please don't hesitate to contact myself at 777-8395 or Paul Mazzolini at 777-8369. Sincerely, ?al-a niOAffe-22-- Paul Mazzolini Drilling Manager Hilcorp Alaska, LLC Page 1 of 1 • • Hilcorp Alaska, LLC Milne Point Unit (MPU) B-30 Drilling Program Version 1 February 10, 2017 • • Milne Point B-30 Drilling Procedure Hilcorp Energy Company Contents 1.0 Well Summary 2 2.0 Management of Change Information 3 3.0 Tubular Program: 4 4.0 Drill Pipe Information: 4 5.0 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 9 5/8"5M Diverter System 10 12.0 Drill 12-1/4"Hole Section 12 13.0 Run 9-5/8"Surface Casing 17 14.0 Cement 9-5/8"Surface Casing 21 15.0 BOP N/U and Test 25 16.0 Drill 8-1/2"Hole Section 26 17.0 Run 7"Production Casing 30 18.0 Cement 7"Production Casing 32 19.0 Perforate&Run Production Tubing. 35 20.0 Contingency String• 36 21.0 Wellbore with contingency 4-1/2"liner installed 37 22.0 Diverter Schematic 38 23.0 BOP Schematic 39 24.0 Wellhead Schematic 40 25.0 Days Vs Depth 41 26.0 Formation Description 42 27.0 Anticipated Drilling Hazards 43 28.0 Innovation Rig Layout 46 29.0 FIT Procedure 47 30.0 Choke Manifold Schematic 48 31.0 Casing Design Information 49 32.0 8-1/2"Hole Section MASP 50 33.0 Spider Plot(NAD 27)(Governmental Sections) 51 34.0 Surface Plat(As Built)(NAD 27) 52 35.0 Offset MW vs TVD Chart 53 36.0 Drill Pipe Information 5" 19.5#S-135 DS-50 54 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 1.0 Well Summary Well MPU B-30 Pad Milne Point"B"Pad Planned Completion Type Gas Lift or Jet Pump completion on 2 7/8"tubing Target Reservoir(s) Sag River Planned Well TD,MD/TVD 9512' MD/8902' TVD PBTD,MD/TVD 9430' MD/8875' TVD Surface Location(Governmental) 86' FSL,4,328' FEL, Sec 18, T13N,R11E,UM,AK Surface Location(NAD 27—Zone 4) X=571,962.88,Y=6,022,208.86 Surface Location(NAD 83) Top of Productive Horizon (Governmental) 1833'FNL, 1173'FEL, Sec 24,T13N,R10E,UM,AK TPH Location(NAD 27) X=569,923.92 Y=6,021,270.60 TPH Location(NAD 83) BHL(Governmental) 1845'FNL, 1254'FEL, Sec 24,T13N,R10E,UM,AK BHL(NAD 27) X=569,842.90,Y=6,021,258.30 BHL(NAD 83) AFE Number 1612657D AFE Drilling Days 25 Days AFE Completion Days AFE Drilling Amount $5,165,327 AFE Completion Amount AFE Facility Amount Maximum Anticipated Pressure (Surface) 3478 psig Maximum Anticipated Pressure (Downhole/Reservoir) 4360 psig 5" 19.5# S-135 DS-50(Weatherford Rental) Work String 4" 14# S-135 HT-38 (Weatherford Rental—Contingency) KB Elevation above MSL: 26.5 ft+23.1 ft=49.6 ft GL Elevation above MSL: 23.1 ft BOP Equipment 13-5/8"x 5M Annular, (3)ea 13-5/8"x 5M Rams Page 2 Version 1 Feb 2017 • • Milne Point Unit B-30 Drilling Procedure Hileorp Energy Company 2.0 Management of Change Information Hilcorp Alaska, LLC Hilcorp Famypany Changes to Approved Permit to Drill Date: Subject: Changes to Approved Permit to Drill for MPU B-030 File#: B-030 Drilling and Completion Program Any modifications to B-030 Drilling&Completion Program will be documented and approved below. Changes to an approved APD will be communicated to the AOGCC. Sec Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Version 1 Feb 2017 • • Milne Point Unit B-30 Drilling Procedure Hilcorp EnecgY cry 3.0 Tubular Program: Hole OD (in) ID (in) Drift Conn Wt Grade Conn Burst Collapse Tension Section (in) OD (in) (#/ft) (psi) (psi) (k-lbs) Gond 20"" 19.25" - - 78.6 A-53 Weld 12-1/4" 9-5/8" 8.835" 8.679" 10.625" 40 L-80 DWC/C 5750 3090 916 8-1/2" 7" 6.276" 6.151" 7.656" 26 L-80 DWC/C 7240 5410 604 *6-1/8" 4.5" 3.920" 3.795" 4.93" 13.5# L-80 VAM 9,020 8,540 307 HTTC *Note: Contingency string highlighted in yellow. 4.0 Drill Pipe Information: Hole OD ID (in) TJ ID TJ OD Wt Grade Conn M/U M/U Tension Section (in) (in) (in) (#/ft) (Min) (Max) (k-lbs) Surface& 5" 4.276" 3.25" 6.625" 19.5 S-135 GPDS50 36,100 43,100 560k Intermediate *6-1/8" 4" 3.34" 2.5625" 4.875" 14 S-135 HT-38 12,200 17,700 649,200 *Note: Contingency drill pipe highlighted in yellow 5.0 Casing Inspection All casing will be new, PSL 1 (100% mill inspected, 10%inspection upon delivery to TSA in Fairbanks). Page 4 Version 1 Feb 2017 Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 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 pmazzolini@hilcorp.com and cdinger@hilcorp.com 6.3 Intranet Home Page Morning Update • Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays,ensure to have this update in before 5am. 6.4 EHS Incident Reporting • Health and safety: Notify EHS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drilling Manager&Drilling Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 6.5 Casing Tally • Send final"As-Run"Casing tally to pmazzolini@hilcorp.com and cdinger@hilcorp.com 6.6 Casing and Cmt report • Send casing and cement report for each string of casing to pmazzolini@hilcorp.com and cdinger@hilcorp.com 6.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Paul Mazzolini 907.777.8369 907.317.1275 pmazzoliniphilcorp.com Drilling Engineer Paul Mazzolini 907.777.8369 907.317.1275 pmazzolini@hilcorp.com Geologist Matt Brown 907.777.8448 713-458-8667 mbrown@hilcorp.com Reservoir Engineer Anthony McKonkey 907.777.8460 amckonkev@hilcorp.com Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350-9439 jorczewska@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com EHS Field Coordinator Jimmy Watson 907.777.8450 907.744.7376 jiwatson@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 Version 1 Feb 2017 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 7.0 Planned Wellbore Schematic II M11ne Point Unit PROPOSED SCHEMATIC weal_MPU B-3u Last Completed:Proposed PTD: TBD I2.Eek:.G.5'/GL Eev.:23.3' rTREE&WELLHEAD I ...5.-TrSF[23.lar:Net=r Tree CIW 7-3116`Shill 1 I wellhead Seaboard Weir,3 spools,w/33"x 5M fl=_^te "'NI°tubing hanger*" ��...///^ ye I CASING DETAIL 0 0 10v v ti Size Type Vet/Grade/Conn - Drift iD Top 6trr - � 101'1"' ' 2C" Conductor 73.6 f 4-53 f Weld 19 ICC' Suria:e !Y e.yx 9-5/3' Surface 4.,:),11-3.0/PSYC/C 8.679`• Sura:e 5,200 - Froduc60n 26/1-36/D1VC/C 6.151`• Sung:_ 9512' TUBING DETAIL f' I I I I I I WELL INCLINATION DETAIL KO :E-3C!VD .". Max.Hore Angle=22.63 deg at 7,52a MD I gle angle through perforated irten'aI:22° JEWELRY DETAIL • No Depth Item { MR Will run Cor-pletion on separate ti nor,. a PERFORATION DETAIL S3^•d- Top(MD) strn{MD) Top(TM) Don(TVD) FT Date Status _�. to tc ., Aci Fes,, TD=9,512{n0/m=S, 2 T'.V( FSTD=9,:33'{r,, :/9I9aD.&5"5•(r.D Page 6 Version 1 Feb 2017 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 8.0 Drilling / Completion Summary MPU B-30 is a grassroots producer with the Sag River as the primary target and the Kuparuk C sand as a secondary target. MPU B 30 is planned as a slightly deviated well with the kick off point at 600' MD/TVD. The hole angle deviates slightly from 17—21 degrees in the surface hole and then is built to a maximum hole angle of 22 degrees and held to TD at 9512' MD/8952' TVD (based upon depths formations are encountered)through the Sag River and just into the top of the Shublik Formation. Drilling operations are expected to commence approximately March 31st, 2017. The Innovation Rig will be used to drill and complete the well. After reviewing the LWD logs obtained while drilling the well, a determination will be made whether or not fracture stimulation will be required at a later date. The base plan,however, is to fracture stimulate the well if a Sag River producer and will be reviewed if a Kuparuk producer. A CBL will be run on the 7" production casing in the event fracture stimulation is required at a later date. Surface casing will be run to 5200' MD /4918' TVD and cemented to surface via a 2 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 12—24 hours after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC personnel. All waste &mud generated during drilling operations will be hauled to the Milne Point G&I facility located on"B"Pad. I General sequence of operations: 1. MIRU Innovation Rig to well site 2. N/U 9-5/8", 5K BOP stack in diverter configuration with a 13-5/8" diverter T& 16"knife gate valve on the conductor and 16"diverter line. Function test diverter. 3. Drill 12-1/4"hole to TD of surface hole section. Run& cement 9-5/8" surface casing. 4. N/D diverter line, diverter T& knife gate valve.N/U casing head,N/U&test 9-5/8"BOPE. 5. Drill 8-1/2"hole to TD. 6. Obtain rotary sidewall cores (optional). 7. Run and cement 7"production casing. 8. Perforate well & frac. 9. Run 2-7/8"jet pump or gas lift completion. 10.N/D BOP,N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR+Res 2. Production Hole: No mud logging. On site geologist. LWD: GR+ Res + CTN / 3. Obtain rotary sidewall cores (optional, depending upon hole conditions) 4. Cased Hole Logs: CBL over 7"production casing. ' Page 7 Version 1 Feb 2017 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU B-30. 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, we must test all BOP components utilized forwell control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and • completion: blowout prevention equipment and diverter requirements". • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • There are no variance requests at this time. / Page 8 Version 1 Feb 2017 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 12 1/4" • 13-5/8"5M diverter w/16"diverter line Function Test Only • 13-5/8"x 5M Control Technology Inc Annular BOP • 13-5/8"x 5M Control Technology Inc Double Gate Initial Test:250/4000 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross w/3"x 5M side outlets 8-1/2" • 13-5/8"x 5M Control Technology Single ram • 3-1/8"x 5M Choke Line Subsequent Tests: • 3-1/8"x 5M Kill line 250/4000 • 3-1/8"x 5M Choke manifold (Annular 2500 psi) • Standpipe,floor valves,etc Primary closing unit: Control Technology Inc. (CTI), 6 station, 3000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event(BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email: iim.regg@alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-301-4533 /Email:guv.schwartz@alaska.gov Victoria Loepp/Petroleum Engineer/(0): 907-793-1247/Email:Victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone: 907-793-1236(During normal Business Hours) Notification/Emergency Phone: 907-659-2714(Outside normal Business Hours) Page 9 Version 1 Feb 2017 s • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 10.0 R/U and Preparatory Work 10.1 B-30 will utilize a newly set 20" conductor on B Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 10.2 Dig out and set impermeable cellar inside existing culvert. 10.3 Ensure PTD and Drilling Program is posted in the rig office and on the rig floor. 10.4 Install Seaboard slip-on 13-5/8" 3M "A" section. Ensure to orient wellhead so that tree will line up with flowline later. 10.5 Insure (2) 3"threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. These will be used to take cement returns to the cellar during the surface cement job and also to wash out the diverter and hanger in preparation for running the pack-off. 10.6 Level pad and ensure enough room for layout of rig footprint and R/U. 10.7 MIRU Innovation Rig. 10.8 Mud loggers WILL NOT be used on either hole section. ✓ 10.9 Mix spud mud for 12-1/4" surface hole section. Keep mud cool. 10.10 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 10.11 Install 5" liners in mud pumps. • White Star Quattro 1300 Hp mud pumps are rated at 4097 psi, 368 gpm @ 140 spm @ 96.5%volumetric efficiency. 11.0 N/U 13-5/8" 5M Diverter Configuration 11.1 N/U 13-5/8" CTI BOP stack in diverter configuration(Diverter Schematic in Sec 21 of program). • N/U 20" SOW • N/U 13 5/8", 5M diverter"T". • NU Knife gate & 16"diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. Page 10 Version 1 Feb 2017 ,;� II IIII II Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 11.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 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 15.375" ID wear bushing in wellhead. 11.5 Pad Drawing I 1 1',IP ?7Q4'i i 1iuu,uu , 1 1 I , ��% � E-=iI, Sag Fr --, / 1 /9 �� ,�E _1 ��h F'r�dt_1 �r 1e�i" niotrt,r I ins ria r r; i Jf,, r"moi I ;,„. rr rill 7 1 r--.-ujLl r ''01113 L-t''n H,PHI{'. }C LE m 0 30 CO 1 1 % I l� X JFEET j 4 r RJ 1 irlr_h =r3 7J ft. 1 1 . �` r 1 Page 11 Version 1 Feb 2017 • • 11 Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 12.0 Drill 12-1/4" Hole Section 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# S-135. • Run a solid float in the surface hole section. 12.2 12-1/4"BHA(GR+Res LWD and PWD planned in surface hole): COMPONENT DATA Item OD ID Gauge Weight Toffy Length Cumulative # Description Serial Number (in) (i'n) (in) (Ibpt) Connection if# ) Length On 1 Varel PDC 7.500 2.875 12.250 128.44 1.05 1.05 2 8"SperryDrill Lobe 4/5-5.3 stg 8.000 5.000 IM 121.08 B 6-548"REG 32.07 33.12 IIIIII StabilizerMIIIIIIIIIIIIIIIIIIII_ 12.125 ElIII 8"Integral Blade Stab 11111111111111111111 8.000 3.250 11.500 143.03 B 6-58"REG MEN 40.97 EMI 8"DM Collar 8.000 3.500 147.40 B 6-5,8"REG 9.16 50.13 5 8"DGR Collar MIIIIIIIIIII 8.000 1.920 ® 142.70 B 6-5 8"REG 6.41 6 8"EWR-P4 Collar 8.000 2.000 151.00 B 6-5=8"REG 12.16 68.70 Ea 8"PWD MIIIIIIIIII 8.000 1.920 143.40 B 6-518"REG 4.36 73.06 8 8"HCIM Collar 8.000 1.920 149.90 B 6-5/8"REG ® 80.83 9 8"HOC 111111111111111 8.150 3.250 IIIIIIIIII 151.20 B 6-518"REG 9.85 90.68 10 8"Non-Mag UBHO 8.000 M_ 149.18 B 6-5.8"REG 3.50 94.18 11 8"Non-Mag Flex IIIIIMIIIIIIIII 7.400 2.875 124.45 B 6-5:'8"REG 30.16 MEM 12 8"Non-Mag Flex 7.610 3.250 EMI B 6-5 8"REG 29.51 ® 8"Non-Mag Flex 1111111111111 7.750 111221.1111111 138.64 B 6-5 8"REG 30.06 183.91 Ili X-Over Sub 7.938 2.875 146.51 ErE131 2.65 186.56 15 6 Jts x 5"X 3"HWDP#49.5 NC50 MillIll 5.000 3.040 I. 111111111111MEZE IF 16 Jar 6.250 2.250 91.01 B 4-112"IF 29.76 401.17 Ell 13 Jts x 5'X 3"HIF WDP#49.3-NC50MEI 5.000 3.000 ® 49.30 111.111 402.30 803.47 803.47 12.3 Primary Bit: 12-1/4"PDC Page 12 Version 1 Feb 2017 • • ti Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company " (311. , m) Tool#: 1r;. 6i�+ V Assembly: A09591 RS616HX IADC Code: S323 ' 0 PRODUCT SPECIFICATIONS 1 9 r7 Cutter Size: 16 mm o p to 4,x Cutter Back Up: Carbide Shock Studs Total Cutter Count: 53 " Face Cutter Count: 47 litiaiirttConnection: 6 518"API Regular Nozzle 1 Qty/Type: 9-Series 65 Nozzle 2 Qtrype: - Junk Slot Area: 29.1i if(187.7cm2) Gage Pad Length: 6"(152mm) Make Up Length: 12.5"(316.2mm) + � . Shank Diameter: 7.6"(193mm) OPERATING PARAMETERS* Rotary Speed: For all rotary and motor applications Flowrate Min-Max: 300-900GPM(1.14-3.41m'Imin) Max Weight On Bit: 36,000Ibs(16014daN) Makeup Torque: 28,000-32,000Ft-Lbs.(37963-43386Nm) ro a..,.n4 pa 0, ti.__F!.a ,:ii, .t.:_: t7r teecf:ed For recommendations on your specific application,contact your Varel international representative. Bit Features H -Increased number of nozzles for improved bit cleaning. X -Shock studs limit drill bit vibration and increase stability allowing smooth cutting action increasing cutter life and overall bit performance. 12.4 5" drill pipe, 5" HWDP, and Jars will come from Weatherford. Page 13 Version 1 Feb 2017 • 10 Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 12.5 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. 12.6 Drill 12-1/4"hole section to 5200' MD/4868' TVD. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. • 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 screens and returns line are set up to handle this flowrate. • Keep swab and surge pressures low when tripping. • Make wiper trips if necessary. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW and viscosity as necessary to maintain hole stability. • Ensure TD of the hole section will cover up the Schrader Bluff sands + 50' MD. • Take MWD surveys every 90'. Gas has been encountered between 2300' —2350' MD on other B Pad wells. • Have the water and air flowline jets hooked up and be ready to jet the flowline at the first sign of flowline backup. The combination of air and water is useful to minimize volume of fluid added to the system. • 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. Page 14 Version 1 Feb 2017 Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 12.7 12-1/4"hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1)ppg above highest anticipated MW. We will start with a simple gel+ FW spud mud at 8.8 ppg. • PVT System: An electronic PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the Driller's console, Drilling Foreman office and Toolpusher office. • Hydrates: Hydrates and or shallow gas have been encountered on B Pad wells drilled to date. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 45 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 —9.0 range with caustic soda. Daily additions of ALDACIDE G/X-CIDE 207 MUST be made to control bacterial action. • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP<20 (check with the cementers to see what YP value they have targeted). System Type: 8.8 —9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL Temp pH 110.-5200' 8.8—9.5 75-175 20 40 25 45 <10 <70° F 8.5—9.0 Page 15 Version 1 Feb 2017 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company System Formulation: Gel + FW spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 -20 ppb caustic soda 0.1 ppb(8.5 —9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8—9.5 ppg PAC-L/DEXTRID LT if required for<10 FL ALDACIDE G 0.1 ppb 12.8 At TD; pump sweeps, CBU, and pull a wiper trip back to the 20" conductor shoe. 12.9 Should backreaming be necessary to get out of the hole: • Prior to initiating backreaming, ensure at least 3 —4 B/U have been circulated to get hole as clean as possible. • Pump at full drill rate (500-600 gpm) and maximize rotation. • Pull slowly, 5 — 10 ft/minute, monitor torque closely. • Monitor well for any signs of packing off or losses. • Have the air and water flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 12.10 TOH with the drilling assembly and handle BHA components as required. 12.11 No open hole logging program planned. Page 16 Version 1 Feb 2017 • Milne Point Unit B-30 11 Drilling Procedure Hilcorp Emmy Company 13.0 Run 9-5/8" Surface Casing 13.1 R/U and pull 15.375"wear bushing. 13.2 The plan is to set slips for 9-5/8" casing. 13.3 R/U Weatherford 9-5/8" casing running equipment. • Ensure 9-5/8" DWC/C x DS50 XO on rig floor and M/U to FOSV. • Use "Besto Life 2000"thread compound. Dope pin end only w/paint brush. • Consider R/U of CRT if hole conditions require. • R/U a fill up line to fill casing while running if the CRT is not used. • Ensure all casing has been strapped& drifted to 8.679"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 shoe track assembly consisting of: • (1) Shoe joint w/float shoe bucked on(thread locked). Install (2) centralizers on shoe joint over stop collars 10' from each end. • (1) Joint with float collar bucked on pin end&thread locked. Install (1)centralizer mid tube over a stop collar. • Ensure bypass baffle is correctly installed on top of float collar. Bypass Baffle This end up. 0111, • (1)Joint with Halliburton bypass baffle adapter bucked on pin&threadlocked. Install (1) centralizer mid tube over a stop collar. • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 17 Version 1 Feb 2017 40 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 13.6 Float equipment and Stage tool equipment drawings: ••A Overall Length Type H ES Cementer B Part No. Min.ID After Drillout fl V� i SONO. C i'' Max.Tool OD o c P * D Hilcorp ES-11 Running Order "'a E'"` Opening Seat ID A Closing Sleeve No.Shear Pins E Closing Seat ID r D' Opening Sleeve c tI No.Shear Pins Plug Set : gP ES-Il Cementer ES Cementer Part No. B_.._ Depth SO No. Closing Plug tommori slimi Baffle Adapter(if used) OD Shut Oft Plug ...LmL.. ID A Opening Plug Depth OD Baffle Adapter 00 a ,or N E[ Bypass or Shut-off Baffle ID ,_. - By-Pass Plug Depth Shut-off Plug 1 �, Float Collar1 n... , .` Depth 1 1! By Pass Baffle € OD Float Collar I Float Shoe Depthlir Bypass Plug ( (if used) ! .,1. IIII Hole TDlir Float Shoe "Reference Casing W OD Sales Manual Section 5 Page 18 Version 1 Feb 2017 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 13.7 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor or CRT. Circ through shoe track. • Install (1) centralizer every other joint for the first 15 joints. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • M/U DWC/C connections as per recommended torque ratings below. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 13.8 Install the Halliburton Type H ES-II Stage tool so that it is positioned at 1900' MD/ 1835' TVD. This will position the stage collar comfortably below the permafrost. • Install centralizers over couplings on 3 joints below and above stage tool. • Do not place tongs on ES cementer,this can cause damage to the tool. • Ensure tool is pinned with 6 opening shear pins. There are 6 holes, the tool is normally sent with only 4 pins installed. This will allow the tool to open at 3300 psi. 9-5/8" 40# L-80 DWC/C Make Up Torques: Min MU Torque Max MU Torque 28,900 ft-lbs 34,800 ft-lbs 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 P/U landing joint and M/U to casing string. Position the casing shoe+/- 10' from TD. Strap the landing joint prior to the casing job and mark the joint at(1) ft intervals to use as a reference when getting the casing on depth. 13.12 Lower casing and land out in wellhead. Confirm measurements and set slips in the wellhead profile. 13.13 Stage casing slips in the cellar. Page 19 Version 1 Feb 2017 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company Technical Specifications Connection Type: Size(O.D.): Weight(Wall): Grade: DWC/C Casing 9-5/8 in 40.00 lb/ft (0.395 in) L-80 standard Material L-80 Grade 80,000 Minimum Yield Strength (psi) `"'L J SA 95.000 Minimum Ultimate Strength (psi) VARA USA 4424 W.Sam Houston Pkwy.Surto 150 Pipe Dimensions Houston,TX 77041 Phone:713-479-3200 9.625 Nominal Pipe Body O.D. (in) Fax:713-479-3234 8.835 Nominal Pipe Body 1_D.(in) E-mate VAMUSAsatestevam-usa_com 0.395 Nominal Wall Thickness (in) 40.00 Nominal Weight (lbs/ft) 38.97 Plain End Weight (lbs/ft) 11.454 Nominal Pipe Body Area (sq in) Pipe Body Performance Properties 916.000 Minimum Pipe Body Yield Strength (lbs) 3,090 Minimum Collapse Pressure (psi) 5,750 Minimum Internal Yield Pressure (psi) 5,300 Hydrostatic Test Pressure (psi) Connection Dimensions 10.625 Connection O.D. (in) 8.835 Connection I.D. (in) 8.750 Connection Drift Diameter (in) 4.81 Make-up Loss (in) 11.454 Critical Area (sq in) 100.0 Joint Efficiency (%) Connection Performance Properties 916,000 Joint Strength (lbs) 16,360 Reference String Length (ft) 1.4 Design Factor 947,000 API Joint Strength (lbs) 916,000 Structural Compression Rating (lbs) 3,090 API Collapse Pressure Rating (psi) 5,750 API Internal Pressure Resistance (psi) 19.0 Maximum Uniaxial Bend Rating [degrees/100 ft) Appoximated Field End Torque Values 29.800 Minimum Final Torque (ft-lbs) 34,800 Maximum Final Torque (ft-lbs) 39,800 Connection Yield Torque (ft-lbs) 13.14 R/U circulating equipment and circulate B/U. Reduce YP to <20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. 13.15 Hold casing string and attempt to reciprocate casing while pumping cement if possible. Page 20 Version 1 Feb 2017 • • Milne Point Unit B-30 Drilling Procedure Hilcorp EnagY Company 14.0 Cement 9-5/8" Surface Casing 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 cementing unit at acceptable rates. • How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cementing operation. • 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 head (if not already done so). Witness loading of the top and bottom plugs to ensure done in correct order. 14.5 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cement lines. 14.6 Pump remaining 55 bbls 10.5 ppg tuned spacer. 14.7 Drop bottom plug (flexible bypass plug). Mix and pump cement per below calculations for the 1St stage. 14.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated Total Cement Volume: rA6t� Section: Calculation: Vol(BBLS) Vol(ft3) 12-1/4" OH x 9-5/8" Casing (4700'- 1900')x .0558 bpf x 1.3 = 203 bbls 1140 ft3 annulus: Total LEAD: 203 bbls 1140 ft3 12-1/4" OH x 9-5/8" Casing (5200'- 4700')x .0558 bpf x 1.3 = 37 bbls 207.7 ft3 annulus: 9-5/8" Shoe track: 90' x .0758 bpf = 6.8 bbls 38.3 ft3 Total TAIL: 43.8 bbls 246 ft3 .?°( 7 !»` • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company Cement Slurry Design (both 1st and 2nd stage cement jobs): Lead Slurry Tail Slurry System ArcticCEM TM System SwiftCEM TM System Density 10.7 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed 21.13 gal/sk 5.04 gal/sk Water 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. If the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 14.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits. 14.11 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. per 40 14.12 Displacement calculation: ./ ci- (5200'-90') x .0758 bpf= 387 bbls total (243 bbl mud+ 80 bbl water+ 64 bbl mud) ./—The 80 bbls of water must be left across stage tool to ensure proper operation once opened. 14.13 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Be prepared to pump out fluid from cellar. Have retarder available to contaminate the cement. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Overdisplace by no more than 50% of shoe track volume, 3.4 bbls before consulting with Drilling Engineer. 14.15 If plug is not bumped consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 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. Page 22 Version 1 Feb 2017 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 14.17 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface. Circulate until YP <20 again in preparation for the 2nd stage of the cement job. 14.18 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have sacks of sugar 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. Second Stage: 14.19 Prepare for the 2nd stage as necessary. Hold another pre job meeting if crew change has occurred. 14.20 Witness the loading of the ES cementer closing plug in the cementing head. 14.21 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cementing lines. 14.22 Pump remaining 55 bbls 10.5 ppg tuned spacer. 14.23 Mix and pump cement per below recipe for the 2nd stage. 14.24 Cement volume based on annular volume+200% open hole excess. Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated Total Cement Volume: 5124G.- Section: Calculation: Vol (BBLS) Vol (ft3) 20" Conductor x 9-5/8" (110') x .24 bpf x 1 = 26.5 bbls 148.2 ft3 casing annulus: • 12-1/4" OH x 9-5/8" Casing (1400'- 110') x .0558 bpf x 2 = 144 bbls 808.3 ft3 annulus: Total LEAD: 170.5 bbls 956.5 ft3 12-1/4" OH x 9-5/8" Casing (1900'- 1400') x .0558 bpf x 2 = 56 bbls 313.2 ft3 annulus: Total TAIL: 56 bbls 313.2 ft3 Page 23 Version 1 Feb 2017 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 14.25 Continue pumping lead until uncontaminated spacer is seen at surface,then switch to tail. 14.26 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 6 4c- 14.27 Displacement calculation: 1900' x .0758 bpf= 144 bbls mud✓ 14.28 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 some sacks of sugar available to retard setting of cement. 14.29 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. 14.30 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. Set slips and back out and L/D landing joint. Flush out wellhead with FW and BOP stack thoroughly to ensure cement, mud and cuttings are removed. 14.31 M/U pack-off running tool and pack-off to bottom of the landing joint. Set casing hanger pack off Run in lock downs and inject plastic packing element. Pressure test to 5000 psi. 14.32 Lay down landing joint and pack-off running tool. Ensure to report the following on WellEz: • Pre flush type,volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing,bpm,note any shutdown during mixing operations with a duration a. Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume,whether plug bumped&bump pressure and if floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job.Final circulating pressure e. Note if pre flush or cement returns at surface&volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As-Run" casing tally & casing and cement report to pmazzolini(dhilcorp.corn and cdinger@hikorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 24 Version 1 Feb 2017 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 15.0 BOP N/U and Test 15.1 N/D the diverter T, 16"knife gate, 16"diverter line &N/U 11" 3M x 13-5/8", 5M casing spool. 15.2 N/U 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" Single gate • Double ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should be dressed with 5" Fixed rams • N/U bell nipple, install flowline. • Install (1)manual valve & (1) HCR valve on kill side of mud cross. (manual valve closest to mud cross). • Install (1)manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 15.3 Run 5" BOP test assembly, land out test plug (if not installed previously). • Test BOP to 250/4000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. • We will need to test on the following sizes: 5" (for 5"DP) 15.4 R/D BOP test assembly. 15.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 15.6 Mix 9.5 ppg Baradrill-N fluid for production hole. 15.7 Set 10"ID wear bushing in wellhead. 15.8 Rack back as much 5" DP in derrick as possible to be used while drilling the 8-1/2"hole section. 15.9 Keep 5" liners in mud pumps. Page 25 Version 1 Feb 2017 • I 11 Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 16.0 Drill 8-1/2" Hole Section 16.1 P/U 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure 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. • Install ported float in the BHA. 16.2 8-1/2" Mud Motor Directional Assembly (Includes triple combo LWD, PWD): j COMPONENT DATA °Item OD ID Gauge Weight Top Length Cumulative Description Serial Number IInp On) (in) (ibpl) Connection linv., Length 40) ® PDC 6.360 2.750 8.500 88.03 P 4-1'2'IF 0.91 0.91 ® 7'SperryDrll Lobe 7%8-6.0 stg IIIIIIII 7.000 4.952 93.13 B 4-1 2"IF 27.33 28.24 IIIIIIIIIIIIEIIIIIIIIIIIIIIIIIIIII 6.250 IIIIIIIIIIIIIIIIIIIIIIII� Ell 6 3i4"Integral Blade MI= 6.750 2813 8.313 100.78 B 4-1;2"IF 6.95 .3211 Q 6 34"DM Collar 6.750 3.125 Mini B 4-1 2"IF 921 44.40 in 6 34"DGR Collar IIIIIIM 6.750 MI= 9-.80 B 4-1.2"IF 6.75 IMMI 6 6X4"EWR-P4 Collar 6.750 2.000 104.30 B 4-1 2"IF 12.11 NEM MI 6 14"PWD Collar 11111= 6.750 1.905 MI 96.30 Inall 4.44 67.70 Ei 6 34"HCIM Collar 6.750 1.920 101-70 EC= 6.83 Mal gi 63!4'ALD Collar 111.1111 6.7 50 1.920 8.250 104 30 UM11 16.27 90.80 1111 Stabilizer 8.250 10 63,'4"CTN Collar 6.750 1.c105 102.30 6 4-1:2"IF 11.83 102.63 Ell 6 3'4'TM Collar 111111111MIEMEIMEMI 112.64 ® 6 34"Non Mag Flex Collar 6.700 2.813 98.98 6 4-1 2"IF 30.98 143.62 im 6 34"Non Mag Flex Co'<la' 111.111 6.880 2.813 MEM 6 4-1 2' IF 30.97 174.59 Ell 6 its x 5"X 3"HWDP 5.000 3-000 ® 42.83 184.00 358.59 MIIIIIIIMMIMINIIIIIIIII 6.250 2.250 mini" B 4-1 2` IF 31.79 Itrin 16 23 its x 5"X 3'HWDP 5.000 3.000 42.83 402.00 MEN qi 1 792.38 Page 26 Version 1 Feb 2017 • • II Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 16.3 Primary Bit: 8-1/2" PDC - .215.9rnrn) ,.. o A Aia vigator „....,,, Afti,i,. ',, vM 6 1 - , LACC Code M433 , , "---— ° - ° °,,,. — - °i-* - °- , - * ,•- -'',°- , , ,°. ° ..,,, i 1 k N PRODUCT SPECIFICATIONS % N lt d''' Cutter Size. 13 mm a'.-,, , Cutler Sack Up 13mnri PDC A Replaceable Shock Studs ...... Total Cutter Count: 76 l .1 ,,,4,0 0 a,... ' Face Cutter Count: 50 Connection 4 1,2"API Regular Nozzle 1 OtyiType 6-Series 55 Nozzle 2 OtyiTyper: - Junk Slot Asea 14 3irr (92.3,cm') 4 Gage Pad UpLength'Length; Shank Diameter OPERATING PAFtAMETERS* Rotary Speed, Fax all rotaryl5a2lin8-41d:1•21rno(11244876t8or4'3..8111mnalninprn:p:hcations Fl(3vviato Min-Max 250 - 75OGPM (0.95-2_84m4imin) Max Weight On Bel: 42000Ibs(18683daN) . Ar Makeup Torque: 12000-16000R-Lbs. (16270-21693Nm) f i64 * a - • * ar* 1 k '0** i .44f e a " itoitej asal co.ccc.Concsa..00,ccat,cc* Oto.Mi iCitao is,pacitc .,,,c-c-c*Ff0,09ogrc 4.,V460 ,4 --,ata. st, c-414*.C.,vcotscA#040 ,cm,.secyc,-arconot•Ircocolorcstat,eco Navigator Series Bits .Varets stri step design - manufacturing process utilizes CseoScience vnterpreteo los„ ProPTletarY dosigh riottware SPOT 30 modality)prow anis,CFO and specialized tn,anurat bong techniques to produce the best possible blit tor the appricatiori Navigator bets are engineered to a selectee Oirecoonat profile for a given application Navigator bets pasass the key des elerrients affecting bit stateablety and directional behavior helping you achieve your drilling objectives Bit Features P -Parliai PowerCutters rw provide extra cutter density oti the shoukter reducing eircessiiiiiii wear or cutting strucng 0 Marriage when rinsing interbedded tormations Shock Studs -Snook studs knit Orel bit vibration and increase stabliey allowing smooth buffing action increasing cutter Ka and*versa blitper0Yerrance., Usscirla Cutlers -PDC cutters sbetegicany pieced to tete reduce note proolems when up belling or back reaming Preilsilliala Gaits -The premium gage consists or trourriaity stab*poiyorystatirn.diernono and brie(poilyntystattina diamond compact)cutters: designed to insure that correct noire diameter is maintained wow inieritinti rem Page 27 Version 1 Feb 2017 S Milne Point Unit B-30 111 Drilling Procedure Hilcorp Enemy Company 16.4 8-1/2"hole section 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. • 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. • 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. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 9.5— 11.5 ppg KC1 Inhibited WBM Properties: Depths Densit Plastic Viscosity Yield Point LGS MBT HPHT pH 5200'-9512' 9.5— 15-25 15-20 <6% <20 <11.0 9-10 11.5 ppg ; System Formulation: Baradrill-N Product Concentration Water 0.94 bbl KCL 22 ppb Barazan D Plus 1.25 ppb(as req'd for YP) PAC L 1.0 ppb Dextrid LT 3.0 ppb Barotrol Plus 5.0 ppb BDF-515 4.0 ppb Caustic Soda 0.2 ppb Baroid 41 As req'd for MW Aldacide G 0.25 ppb 16.5 TIH w/ 8-1/2"directional assembly to stage tool. 16.6 Note depth TOC tagged on AM report. Drill out stage tool as follows: Page 28 Version 1 Feb 2017 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company • Do not exceed 75 rev/min rotation speed. A good range is 40 to 75 rpm. • Drilling with minimal WOB is recommended, 2-5 K# is enough. • Apply weight and allow it to drill off before applying more. • After drilling out, chase any remaining debris to bottom with the drill bit. 16.7 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 16.8 R/U and test casing to 2900 psi/30 min. Ensure to record volume/pressure and plot on FIT graph. AOGCC reg is 50%of burst= 5750/2 =2875 psi. Test pressure for the well is 2900 psi. 16.9 Drill out shoe track and 20' of new formation. p� 41il8 go.5- X 16.10 CBU and condition mud for FIT. (�� -+ gq SL' Lal 16.11 Conduct FIT to 12.5 ppg EMW. If 12.5 ppg EMW is not obtained call and discuss with Drilling Engineer. 16.12 Drill 8-1/2"hole section to section TD per Geologist and Drilling Engineer. • Pump at 500 gpm. • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Pump water or other low vis sweeps to aid in hole cleaning. • Closely monitor PWD information while drilling to minimize ECD, especially important when drilling the Miluveach and Kingak Formations. • Keep swab and surge pressures low when tripping, especially important when tripping through the Miluveach and Kingak Formations. • Make wiper trips if necessary. • Take MWD surveys every 90'. Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. 16.13 At TD; pump low vis sweeps, CBU at least 3 times at maximum circulation and rotation, and pull a wiper trip back to the 9-5/8" shoe. If back reaming is necessary: • Circulate at full drill rate (500 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 back reaming operations are commenced, continue back reaming to the shoe and circ at least a b/u once at the shoe. Back reaming is a last resort to clean up the hole in the Miluveach and Kingak Formations. 16.14 TOH with the drilling assembly, L/D BHA and DP on TOH. Page 29 Version 1 Feb 2017 • I Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 16.15 Rotary sidewall cores (RSWC) are planned in the Sag River Formation if hole conditions will allow. 16.16 A cleanout trip to TD will occur after the RSWC are obtained. 17.0 Run 7" Production Casing 17.1 R/U 7" casing running equipment. • Ensure 7"DWC/C x NC-50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been strapped& drifted in the pipe shed prior to running. • Be sure to count the total # of joints in the pipe shed 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 if available. 17.2 M/U&threadlock shoe track assembly consisting of: • (1) Float shoe joint w/float shoe bucked on. Install (2)hinged bow spring centralizers over a stop ring at 10' from each end. • (1) Baker locked joint. Install (1) hinged bow spring centralizer mid tube over a stop ring. • (1) Float collar joint w/float collar bucked on pin end. Install (1)hinged bow spring centralizer mid tube over a stop ring. • Ensure proper operation of float shoe and float collar. 17.3 Run 7"26# L-80 DWC/C casing. • Fill casing while running using CRT or fill up line. • Use"Besto Life 2000"thread compound. Dope pin end only w/paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install centralizers over couplings on every other joint to 7,000' MD. No centralizers required above that. 17.4 Watch displacement carefully and avoid surging the hole. Slow down running speed as necessary, especially through the Miluveach and Kingak Formations. 17.5 Slow in and out of slips. 17.6 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close+/- 10' from TD. Strap the landing joint while it is in the pipe shed and mark the joint at(1) ft intervals to use as a reference when landing the hanger. A dummy run of the landing joint and casing hanger prior to running casing is required. Page 30 Version 1 Feb 2017 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 17.7 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 17.8 Have emergency slips ready to go in the event we cannot land the hanger. 17.9 R/U circulating equipment and circulate B/U. Reduce YP to <20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. Elevate hanger slightly above hang off point while circulating to avoid plugging the flutes. 17.10 After circulating, lower string and land hanger in wellhead again. 7" DWC/C M/U Torque Min Casing MU Torque Max Casing MU Torque 18,300 ft-lbs 21,100 ft-lbs Connection Type: Sise(O.D.): Weight(Wall): Grade: DWG/C Casing 7 in 26.00 Ib/ft(0.382 in) L-80 2012 API SPEC 5CT COUPLING O.D. Material L-80 Grade 80,000 Minimum Yield Strength(psi.) 95,000 Minimum Ultimate Strength(psi.) sommensur IJ i" Pipe Dimensions VAM USA 7.000 Nominal Pipe Body O.D.(in.) 4424 W.Sam Houston Pkwy.Suite 150 6.276 Nominal Pipe Body LID. (in.) Houston. a 13-479 3200 0.362 Nominal Wall Thickness(in.) Fax 713-479-3234 26.00 Nominal Weight(lbs./ft.) E-mail.VAMUSAsales4@vam-usa.corn 25.69 Plain End Weight(lbs./ft.) 7.549 Nominal Pipe Body Area(sq.in.) Pipe Body Performance Properties 604,000 Minimum Pipe Body Yield Strength(lbs.) 5,410 Minimum Collapse Pressure(psi.) 7,240 Minimum Internal Yield Pressure(psi.) 6,600 Hydrostatic Test Pressure(psi.) Connection Dimensions 7.875 Connection 0.0.(in.) 6.276 Connection I.D. (in.) 6.151 Connection Drift.Diameter(in.) 4.50 Make-up Loss(in.) 7.549 Critical Area(sq. in) 100.0 Joint Efficiency(%) Connection Performance Properties 604,000 Joint Strength(lbs.) 16,590 Reference String Length(ft) 1.4 Design Factor 641,000 API Joint Strength (lbs.) 302,000 Compression Rating(lbs.) 5,410 API Collapse Pressure Rating(psi.) 7,240 API internal Pressure Resistance(psi.) 26.2 Maximum Uniaxial Bend Rating idegrees/100 ft) Approximated Field End Torque Values 18,300 Minimum Final Torque(ft-lbs.) 21,100 Maximum Final Torque(ft-lbs.) .>. 23,800 Connection Yield Torque(ft.-lbs.) For detailed information on performance properties.refer to DWG Connection Data Notes on following pagets). Page 31 Version 1 Feb 2017 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 18.0 Cement 7" Production Casing 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 is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cement operation. • Document efficiency of all possible displacement pumps prior to cement job. 18.2 R/U cementing head (if not already done so). Witness loading of top and bottom plugs to ensure they are loaded correctly. 18.3 Pump 5 bbls 13.5 ppg spacer. Close low torque on plug dropping head, test surface cementing lines to 4000 psi. 18.4 Pump remaining 35 bbls 13.5 ppg spacer. 18.5 Drop bottom plug, Mix and pump slurry per below calculations: Assume 25%excess cement until hole volume is established at TD. Section: Calculation: Vol (BBLS) Vol(ft3) LEAD: 8-1/2" OH x 7" csg: No Lead Total Lead: TAIL: (9512' —7000')x .0226 bpfx 1.25 = 71 398.5 ft3 8-1/2" OH x 7"csg: TAIL: 90' x .0382 bpf= 3.5 19.6 ft3 7" Shoe Track: Total Tail: 74.5 bbls 401.8 ft3 a�5� 5i'` Page 32 Version 1 Feb 2017 Milne Point Unit B-30 11 Drilling Procedure Hilcorp Eaergy company Slurry Information Stage Lead Tail System Conventional Density 14.5 lb/gal Yield 1.397 ft3/sk s Mixed Fluid 6.78 gal/sk Expected Thickening 5:00 HR:MIN Expected ISO/API Fluid Loss 13 mL in 30 min Additives Code Description Concentration G Cement 94 lb/sk WBWOB D110 Retarder 0.05 gaUsk VBWOC D046 Anti Foam 0.2%BWOB D202 Dispersant 1.5%BWOB D400 Gas Control Agent 0.8%BWOB D154 Extender 8.0%BWOB D174 Expanding Agent 1.5%BWOB 18.7 After pumping cement, drop top plug and displace cement with completion fluid. If it is not feasible to do this, use mud and a clean out trip will be made later. Use rig pumps for displacement. Ensure to have a good baseline measurement for pump displacement ahead of time. Displacement calculations: • 9422' x .0382 bpf= 360 bbls. 7' 18.8 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 18.9 Do not over displace by more than V2 shoe track volume. Total volume in shoe track is 3.5 bbls 18.10 There should be no cement returns to surface. TOC is planned to be+1- 7000' MD 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. Page 33 Version 1 Feb 2017 S 4110 Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 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 and if floats hold • Percent mud returns during job, if intermittent note timing during pumping of job.Final circulating pressure • Note if pre flush or cement returns at surface&volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Send final "As-Run" casing tally & casing and cement report to pmazzolini@hilcorp.com & cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 18.12 R/D cementing equipment. 18.13 Back out and L/D landing joint, flush out wellhead and BOP stack thoroughly with FW. 18.14 M/U pack-off running tool and pack-off to bottom of landing joint. Set casing hanger pack-off. Run in lock downs and inject plastic packing element. Test void to 250/5000 psi for 10 min. 18.15 Lay down landing joint and pack-off running tool. Page 34 Version 1 Feb 2017 0 s Milne Point Unit B-30 ti"� r �.� r• Drilling Procedure � Hilcarp V I' , 5''' c 19.0 Perforate & Run Production Tubing (Work to be completed�, under separate sundry) C/ ,,. d & / 19.1 PU 6" cleanout BHA and RIH on 2-7/8"tubing to PBTD `'. Circulate the wellbore clean with kill weight brine at maximum rate. Rotate and reciprocate work string as needed. Reverse circulate if needed get clean returns from wellbore. Test casing on chart to 3700 psi for 30 minutes. POOH and rack back tubing. 7./ erfi cid 19.2 Spot e-line unit and rig up. RU e-line lubricator to shooting flange. Test to 250 psi low/ 1500 psi high. 19.3 Run a CBL across the Sag River and up above the Kuparuk Formation and determine TOC near 7000' MD. 9) 19.4 Perforate the Sag River sand. Exact depths will be from the cased hole reference log. 19.5 RD e-line. 19.6 R/U and run completion with XN profile on tubing as per Completion Engineer. qv • Ensure appropriate well control crossovers on rig floor and ready. 0 01 • Monitor displacement from wellbore while RIH. '''1 • Placement of gas lift mandrels will be determined after receiving the final directional survey. 19.7 Land tubing hanger. RILDS. LD landing joint. Note PU/SO weights on tubing tally along with number of bands/clamps run. Test hanger. 19.8 Circulate freeze protect down IA and allow freeze protect to U-tube down tubing. 19.9 Bullhead diesel (or dead crude) freeze protection down 9-5/8"x 7" annulus with 60 bbls (2100') Leave well shut in, do not allow flowback to occur. 19.10 Install BPV and N/D BOP. 19.11 N/U tree adapter and tree. Conduct pressure tests of same to 500 psi low/5000 psi high. 9.12 Shut in well. Page 35 Version 1 Feb 2017 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 20.0 Contingency 4-1/2"Liner / 6-1/8" Hole: 20.1 Excessive MW may be required to stabilize the wellbore after opening up the Miluveach and Kingak shales, as they can are very reactive,prone to swelling and being unstable when drilled at higher hole angles, >40 deg. Minimize ECD's, reaming, swab and surge pressures through these formations to improve hole stability. 20.2 If significant overpulls are noted through theses sections and do not improve consult with Drilling Engineer and determine feasibility of drilling ahead with planned well design. 20.3 If it is not feasible to drill ahead, set the 7" casing through the Miluveach and Kingak shales. 20.4 Adjust cement program so that TOC remains at 7,000' MD, with 7" shoe at+/- 9000' MD. 20.5 After bumping the plug, pressure up to 3700 psi and test casing for 30 min. Record volume pumped and volume bled back,note in WellEz report. 20.6 R/D cement equipment, install and test pack off, bullhead freeze protect down annulus. 20.7 Install 2-7/8"x 5"VBR rams in both upper and lower BOP cavities. TEST BOP to 4000 psi/5 min. Annular to 2500 psi/5 min. 20.8 P/U 4" DP & 6-1/8" directional drilling BHA, drill out float equipment and 20' new formation. CBU and conduct FIT to 13.5 ppg EMW. 20.9 Drill 6-1/8"hole to well TD, 9512' MD. 20.10 Run and cement 4-1/2"production liner. Cement coverage will be from liner shoe to TOL. 20.11 Well completion will remain the same. A proposed well schematic is shown on the next page. Page 36 Version 1 Feb 2017 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 21.0 Wellbore with contingency 4-1/2" liner installed Milne Point Unit PROPOSED SCHEMATIC Well: MPU B-30 Last Completed:Proposed . IMI 'OWL- r�;,,.,,�1._ ,>.r�� PTD: TBD KBEec:X19.$/GLEes.:25 TREE&WELLHEAD RIZB-THF: '{Irro,2fcr' Tree CNN!7-1/16-SM ma *elread Seaboard Weir,3=pox Is,Will'x5Mflange •••tic tubing han_or•-• CASING DETAIL 0 size Tl'pe Wt/Grade/Conn C Top =tri 2c" conductor 78.E/-A-53/Weld 19 1,02 Surface sc. 9-5/8" Surface 40/L-SO/DWC1C E.679` Surface 5,20.7 7' Intermediate 25/L-sc/DWCIC 6.151" 5urfa_e 9,0zC' 4-1/2" Froduc on 13.5/L-80/VAM HTTC :.953` 13,83,a' 9,512' TUBING DETAIL I I I I I WELL INCLINATION DETAIL. KO g 726'MD Max Hole Angle=22.53 deg at 7,49L'MD Hwt,angle through perforated irterea':22' JEWELRY DETAIL Depth Item ASR will run Completion on separate sundry PERFORATION DETAIL sand Top{MD;+ etm{MDI Top(TVD) Btm F' ca.-, Status --- -AC CIAL 9 4 b 5 + 4-1.2 • TD=9,512{ht{/TD=asozTr'Da FBTD=RAW{M Di/RBrD=5,.575'rr c¢ -nosed 6y:CIO 2/23/11 Page 37 Version 1 Feb 2017 0 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 22.0 Innovation Rig Diverter Configuration a nit m rim m --13-5I8"5M Control Technology Annular BOP 7Lini i. Ki 1 .111 :: EL3 1 ! .E,?_2 !.. F-(3.-- "---13.518"5M Control cm Technology Double Ram 1-r'" r � . . 3-1I8"Kill Line rr��,: — 1.1: IQ r`' ` I{ ```--3.118"Choke Line 0 0 -- trI 13.518"5M Control—/' Technology Single Ram / 13-5/8"x 5M rr [1 ti 16"Diverter Line %1 ./� '`--13.518"x5M r r][r 1] ry. ryr � - " 21!16 x 5M 20"Casing Page 38 Version 1 Feb 2017 0 Milne Point Unit B-30 11 Drilling Procedure Hilcorp Energy Company 23.0 Innovation Rig BOP Schematic 4 - O 1111 ill im-rnm arn 13-5/8 5M Control Technology Annular BOP il --.,....I% 1ik tii 'll c —® I. F-473 .. ---------13-5/8"5M Control �i , /// Technology Double Ram 41011/4 3-118"Kill Line H.P6-134 ( f 'I . (;�AIN k 'r 3-118"Choke Line I —i :11 "--"` -------13-518"5M Control Technology Single Ram 13-518"x5M 11"x5M ' IRC 07 i -I [ t -I—I .i ; hI 9-518" DBL 0 Seal �'!lo►'l�``►'l 2-1116"x5M 014 Casing Hanger L ;�i ,fir , 13-5/8"x 5M 13-5/8"NOM 9-5/8"BTC Btm x S-22 1 -2-1116"x 5M 10.5"-4 SA Pin Top WI Primary Seal 20"Casing 9-5/8"Casing Page 39 Version 1 Feb 2017 0 Milne t U DrillingPoinProcedure nitB-30 Hilcorp Energy Company 24.0 Wellhead Schematic MPB-30 HlLCORMALASKA390A . LLC 4 0 41.3 3-1/8 5M EST X' *T 90 6 EST EST f 3-1/8 5M .. HYDRAULIC ACTUATED 43.3 EST 3-1/8 5M '=r X` Y ADAPTER. TUBING HEAD 0 ?AA 754.1 SM-E-2C1.N EST 11 5M X 3-1/8 5M (SPECIAL) ."^. . WITH TWO(2) 3/8 CL 3-1/8 51.0 6.t � $w. EST Ii 5M 1 TUBING HANGER. SM-E-2CL II X 3-1/2 EU 8R0 BOX TOP 17.2 X 3-1/2 OD API MOD BOX BTM `N1 1 EST WIN TWO(2) 3/8 LP PORTS • ? I 11 5 � M CASING HANGER. SMB-22 - - 11 X 7 I. 26.6/L-80 DWC/C BOX BTM 63.5 EST STUB ACME-2G-LH PIIN�TOP✓ *��Na 1 >•1; e .._110, EST W/SEAL ASSEMBLY �1 L..,'I 7.,/ 5y 9-5/8 DBL PS „40- 13-5/8 5M kti` t. r CASING HANGER, S-22 1, "Ia 11.+I° 20.5 13-5/8 X 9-5/8 i E 9 ESTI 1i- 13-3/8 CASING—. 9-5/8 CASING 7 CASING 3-1/2 TUBING 5.000 PSI WELLHEAD ASSEMBLY 13-3/8 X 9-5/8 X 7 X 3-1/2 [ NS IS 910911 ON 1145 DRAWNC ARE RESTRICTED CONFIDENTIAL DOCUMENT ESIMATES ONLY AND CAN VARY SIGNEtCANTLY wv„ ,aa„K t JS w 1-10 i 1/3/16 •' DEPENDAYG ON RAW MATERIAL LENGTHSsw. n wm+'n.+ ..» mw.w0°GUARANTEE AIRED '< K . `.9RE HEIGHT w. P—21576 A FDR REFERENCE PURPOSES DAILY. 2,1•21.o. w«x...,wk.an101.11r' r. Page 40 Version 1 Feb 2017 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Enmcgy Company 25.0 Days Vs Depth Days Vs Depth 0 lvMPB-30 2000 4000 6000 t 5000 10000 __ 12000 — — 14000 -- — 0 5 10 15 20 25 30 35 Days Page 41 Version 1 Feb 2017 • Milne Point Unit B-30 1 1 Drilling Procedure Hilcorp Energy• Company PHU' 26.0 B Pad Formation Description GENERALIZED GEOLOGICAL DRILLING DATA SUMMARY F7RF^_A-ST SS GEOLOGICAL CASING&OTHER The following summary remarks are from TVD FM LITH DESCRIPTION SUGGESTED MUD WT. DRILLING RELATED INFO. the eleven 8-Pad wells reviewed. These Aa Geo1 wells were drilled between 1982 and �~ Unconsolidated curiae to median, ivy a� 94 +q0 t0 3 NOTE:See individual Well 1989 Telerarct O"�t` as Plan for specific casing mar" 800 s •sand and small gravel with minor MUO PPG or design,depths.sizes. He Oilstone_e- Note:This , SURFACE HOLE: 4 s •' weights,Oradea and 1,000' .•Heavy gravel conglomerate to 1400•. is mud E •r•a•, Wood fragments throughout `mo, "' "w Join chart. <onMctbna. LOOSE CONDUC TO').. B.t4 and B-23 both had S} • permafrost zone. See individual Conductors that moved while dolling or running and well plan for cementing surface casing. iceg •'Base permafrost specific mud Smatter gravel In surface hole las compered to sr. Prudhoe Bay surface hole gravel)enables using Proposed 9-5/8"casing ols Iowa,mud tunnel mud vcbsny H initially and 2,000' C' ij Ifinal Of 45 to 55 sedgt. Caution'.it large amounts of n.- __ setting depth 2400 to gravels are encountered,immedutely raise Ine Sagavanirktok L 9.2 to 9.3 ppg 2500'TVO fol aruk funnel viscus, to 150 sect t.Kea the necessar ;•Predominantly clay to H.3090°with -KuP Y q p Y ` A interheds oI sand.clays and sin- J target wells with materials near and oeaddy available too miring. Stones with occasional snows of coal Surface casing point design set deapee In Mese �� 94 pg Schrader Bluff r.cent/9B5i9 wens at el-46003S coveting tin around 2700'.Pebbl2700°.y gravel(up to nos efts. Schrader Stool Sands. 'Mai- 50%)down to 2700'. P P 3,000 Continued interbed%of sand,clays and i -- - STUCK PIPE:B-4 p9a2lacca) slack 3-i 2 =u s with heavy coal sections oral' 26000-320-32 00. s at 409+SS,probable cause new BHA stuck KA while working to bottom.This incident is mentioned Ksartls here even though suttee.casing was set shallow at „"a I-A.B.0 0: UGNU- Series Cl coarsening upward 2300 and the Incident was actual in the faaut r"�sands which are made up of (from top intermediate hole section of the well UGNU L aye revel to bottom)coarse sand.fine sand,silty .om- tisanes shale and some coat.Better developed STUCKPIPE:B-14(1965weu).Stuck 4140 (Acc) mamma.intervening shales as you progress Into pipe at 3594 while while washing and teaming tight the L and M(deeper). spots In note. The hole then packed off and Inc 4.000' Possible hydrocarbon Dearing sands ••••' •' H formation was taking fluid. The BHA had to be abandoned and the well plugged back and NASchrader Bluff Sands 4300- PAH* Continued layered coarsening upward sands as sidetracked 4600• (-ARCA above except mom condensed. Passible SHALLOW GAS!!! OA, EO.--SSawas hydrocarbon belling and potentially productive There was no shallow reported in the weirs in the"O-and-N'sahee Tend to be water wet gas 1550- (ABC. ^�c more then a mile to the east. , reviewed.However,shallow hydrate gas has been 4600• D.E Fi V • Proposed 9-5/8"casing encountered at nearby E-Pad. BE ALERT FOR L Primarily clay with some gilt sandstone setting depth 4600- ANY SIGNS OF GAS AROUND 2000 TO below 0eetoi +f-0• 4700-TVD. 2400 FT. IT IS POSSIBLE THAT THESE a6o0-Top of._,.... r.5200 where sandstone begins making i 47e0` 4900'Seabee '( up 50%.the remainder ainstone and clay. __ ARE SHALLOW HYDRATES. `5,000 _ -- SHALLOW HYDROCARBONS; The U Seabee(Colville)Interval: Schrader Bluff sands may gnu and Predominancy Interbedded sihstone a N9 AE with solution gat I. Y contain n ydrocartlons to, clay with beds of sand.shale and IT IS GOOD DRILLING PRACTICE TO ALWAYS BE occasional seams of coal. The Seabee ALERT AND PREPARED FOR THE UNEXPECTED is generally uneventful until reachingPOSSIBILITY OF SHALLOW GAS OR the HRZ.Expect good penetration rates v Sea a ee I•t-100 tih). i HYDROCARBONS.. Bridges and tight hole occurred throughout ' all the wells in this section.See Well Summary ,6.000' r - - The best way to keep good hole conditions in the surface hole is to make bequent short trips and Continued Inter beds of sandstone_ circulate sweeps as required.Also.watch that the ' shale with some clay 5200 to 6500 l gravel concentration does not build up. Raise the Expect pyrite and tuffs at•..6200'. viscosity If It does.Sas Short Trip Guidelines. At woo to Esso•.10 b 20 t Totts. DIRECTIONAL: Under the de, iia C.-.,.id rate i, Continued intermittent Tuffs down to 9!7 PIN 8-23,1147 to 1542. Watch the base of the ♦t.6900'. permafrost at 1700•for Inclination change. CLAY sections: Heevy clays at Bead below the base o1 the permafrost to H.3000 ss and also below • i the Schrader Bluff after surface casing is set from 7000• Top HRZ HRZ: Highly Radioactive Zone.Very dark. I 4550 to 5200.For biVBHA bailing use SAPP and .;-100 t-'"'�7 thistle type shale.organic.good source rock. - • - COHOST. 7060• B..."R.......2- Tuff(bentondic)zone possible at top of HRZ. O¢ COAL' Eepect to encounter some coal in the at-100' I"—"'— Kalubik Shale'Marker MK19 good log SPY Uenu,Cl-3900 55. Kelubik parker.Gradually diminishing hing ROP. ( M-y u re s•TUCK PIPE SURFACE CASING. Lost returns on the 9-S•6" i 7.68,00; hi t h r cad surface casing Jobs was common on the B-Pad ( "D' Kuparuk Interval: .ri� NTERVAL ON .wens.vowmesvariedfrom 10 20 30bbista100• Shale The"D"Shale is the top Kuparuk sediment W'I It "'� a� bets.Acceptable tormatbn integrity tests were i:nd is known as the"Cap Rock". •.CIUse 4,B-9, B-23, '-..achieved. C C SANDS: Sandstone.shales of arboy SANDS Award.Oa beating(algal In e-idn -4 and four L !tris LCU: owKaenuwn.a U nformt della-) =ltd F-PAD INTERMEDIATE HOLE: B (12) Zone begins below LCU. + SANDS Fine b medium gr sands becoming ELLS!!.. ( / 4600-6800'): m0 shaley with depth.Hydrocarbon Th t val was generally trouble free roils bearing.Pinches out to the north and occasional tight hole and some reaming on a low of ' thickens to the southeast.Top sand, the wells. A 13-7.is target.Use controlled drip rate IGood practices thru this fast drilling SANDS in Kuparuk,60 lb.for LWD. I interval are to let hole conditions dictate A sands' Fine grain sandstone. short trip frequency. B-19 and 8-21 Potential hydrocarbon beating. drilled+1-4000 ft without short tripping Mibveach shales:predominantly silty and without any problems. Miluveach shale,(Casing Seat tot Kuparuk Look fon a definite change in ROP when the bottom Shale completion). ) i 10 2 of the Seabee clays(•r.6900)change into the 1102 1 1) shales.Expect a change from•,-100 to 25 Iph. VVI 1 I c13ing"a`f°` tion. Transition Interval: Kuparuk completion. 9.e as CS 100110A ' 'The above depths are based on the proposed (+/-6800-70001: 1996 B-Pad Development Drilling Program. Two Wells on B-Pad,one on E- Page 42 Version 1 Feb 2017 I Milne Point Unit B-30 Drilling Procedure Hllco Eau CepareV 27.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates. We do not want to drill through the hydrates with anything less than a 9.5 ppg MW however. 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. Utilize cold water when building any mud volume. 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 (>100 RPM's required for effective hole cleaning)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 90'. Additional surveys can be taken as required. 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 surge and swab pressures generated by the BHA. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase viscosity and/or MW to combat running sands and gravel formations. Page 43 Version 1 Feb 2017 Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company H2S: Treat every hole section as though it has the potential for H2S. Review offset wells for documented encouters of H2S. No H2S events have been documented when drilling wells on"B"Pad 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, the well will be secured, rig operations suspended and personnel evacuated until a detailed mitigation procedure can be developed. Mitigation efforts can include additives to the mud system, use of personal H2S monitors for rig crews and service personnel and training/deploying SCBA's throughout the rig. Page 44 Version 1 Feb 2017 • Milne Point Unit B-30 Drilling Procedure Hilcarp Energy Company 8-1/2" & Contingency 6-1/8" Hole Sections: 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 as required to maintain proper fluid properties. 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 (>100 RPM's required for most effective hole cleaning)when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of> 500 gpm. Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate or other LCM. Faulting: There is at least(1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When crossing faults monitor the hole closely for lost circulation(diminished returns) and wellbore stability issues (high or spikey torques, higher pick up weights). H2S: Treat every hole section as though it has the potential for H2S. Review offset wells for documented encounters of H2S. No 112S events have been documented when drilling wells on"B"Pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, the well will be secured, rig operations suspended and personnel evacuated until a detailed mitigation procedure can be developed. Mitigation efforts can include additives to the mud system, use of personal H2S monitors for rig crews and service personnel and training/deploying SCBA's throughout the rig. Abnormal Pressures and Temperatures: There are no abnormal pressures or temperatures expected while drilling this well./ ✓ Page 45 Version 1 Feb 2017 ill • is Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 28.0 Innovation Rig Layout 170'-33 I '� �,. a C 5 me frim €Kci 4 1 _� •� --# - .�Pi - ie is i - - ;,'---11'Pa I o I.,. E i. 0 t € F ; 1111 } • li RA .. .rte, 1.s . Alto 1 ID HAK 2 FOOT iil, - .� r, alelr ! PRINT ®x® I �, 05/21/16 -------- _ ,1 ---94110., � _It �_ — h1t' -. Linnir_ i _ • -r... i , 1 -..... ....) ,1 1 1 :. iiiii 113'-111 u 1 ti j aL 36'-14" Page 46 Version 1 Feb 2017 • I Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 29.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer(ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure.Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 47 Version 1 Feb 2017 • 1 Milne Point Unit B-30 Drilling Procedure Hilcorp Esaitg ComPanY 30.0 Innovation Choke Manifold Schematic .._ mu . . ..... , 4_, AIR :-.4-jr: Diii :11 4W .... .ill illi, ....mi c � C i i i , 111 1111 , E1 1: fel I. ocr— I Nom _ _ iii RI 2-9115'5M BB209 v 2-9115"5M BB209 Piper Ball Valves Piper Ball Valves X11 I_ r II_1 U Ai c-_--- lam ail 3 :ful :i r IF-los+,-1 : Mon mm 1 mini I Page 48 Version 1 Feb 2017 • •• Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 31.0 Casing Design Information Calculation & Casing Design Factors Milne Point Unit DATE: 2-21-2017 WELL: MPU B-30 DESIGN BY: Paul PJlazzolini Desi• n Criteria: 1 Hole Size 8-112" Mud Density: 10.5 ppg Hole Size 8-118' Mud Density: 10.5 ppg (Contingency) Hole Size Mud Density: Drilling Mode MASP(8-1:2"): 3478 psi(see attached HASP determination S: calculation) Production Mode MASP: 3.473 psi (see attached HASP determination S calculation) .... .......... Collapse Calculation: Section Calculation r 1, 2, 3 Max M'i' gradient external stress and the casing evacuated for the internal stress Note Contingency liner highlighted in yellow below Casing Section 0 Calculation/Specification 1 2 i 3 Casing 4D i 9-5/8" 7" i 4-1/2" 4 0 Top ..(MD) 0 0 9,000 Top(TVD) 00 0 0 8,478 a Bottom(MD) 5,200 9,512 9,512 Bottom(TVD) 4,868 8,902 8,902 4 ! Length 5,200 9,512 512 Weight(ppf) € 40 26 0 13. 5 a Grade E L-80 L-80 L-80 Connection ' DWC/C 'sI I VAM HTTC' a a o Weight w/o Bouyancy Factor(lbs) ' 208,000 i 247,312 i 6,912 Tension at Top of Section(lbs) ' 208,000 ' 247,312 ' 6,912 s a Min strength Tension (1000 lbs) ! 916 604 307 Worst Case Safety Factor(Tension) a:_ 4.40 • e 2.44 ' 0 44.42 ./ a Collapse Pressure at bottom(psi) E 2,191 4,540 4,540 Collapse Resistance w/o tension(psi) i 3,090 5,410 8,540 a Worst Case Safety Factor(Collapse) i 1.41 1.19 . 1.88 j a MASP(psi) 3,478 3,478 a 3, 478 a Minimum Yield(psi) i 5,750 7,240e 9,020 Worst case safety factor(Burst) 1.65 ' i 2.08 ' i 2.59 i Page 49 Version 1 Feb 2017 • • 11 Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 32.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation fititiii 8-1/2"Hole Section `"" MPU B-30 .......................... Milne Point Unit MD TVD Planned Top: 5200 4868 Planned TD: 9512 8902 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Top Kuparuk 0 Shale 6,800 3359 - 9.5 0.494 Top Kuparuk C Sand 6,875 3396 Oil 9.5 0.494 Top Kuparuk A Sand 7,020 3468 Water 9.5 0.494 Top Miluveach 7,150 3532 - 9.5 0.494 Top Jurassic 7,600 3754 - 9.5 0.494 Top Sag River 8,825 4360 Oil 9.5 0.494 Top Shublik 8,875 4384 - 9.5 0.494 Sag River Well Mud Density Well Max DrIg MW Top(TVD) Bottom(TVD) Date C-23 10.8 4603 8681 1996 C-15A 11.2 7319 9250 2016 5-90 10.9 6949 8761 2005 F-33 11 4420 8743 1996 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"hole section is 11.5 ppg for stabilization of Miluveach and Kingak Formations. 3. Calculations assume Sag River reservoir 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: 4868(ft)x 0.7(psi/ft)= 3408 psi 3408(psi)- (0.1(psi/ft)'4868(ft)]= 2921 psi (Dri l l ing Mode MASP IMASP from pore pressure(wellbore completely evacuated to gas) 8825(ft)x 0.494(psi/ft),--- 4360 psi 4360(psi)-(0.1(psi/ft)'8825(ft)]= 3478 psi Summary: 1. MASP while drilling 8-1/2"production hole is governed by wel;bore completely evacuated to gas from the Sag River Formation_ Page 50 Version 1 Feb 2017 • 0 II Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 33.0 Spider Plot (NAD 27) (Governmental Sections `, Legend `. .„ e MPU B-30_SHL - Other Surface Holes 1SHL) ` `. . MPU B-30_TPH Other Bottom Hogs(13141..) ` , - - - Other Well Paths % • MPU B-30_BHL Em Oni and Gas Unit Boundary `. ` Pad Footprint I ) _.ac_1$ -i Sec i :,.. I a (6 � U r1 - _ 4.. .. 4 1Ft r f yt['t 37--,ti >sil. ys- s I: Y r _ .-. ,.- _- - .. �� y-, ..!', r r 6Y k31§ fi k I .t ‘,' e 1 a MILNE POINT UNIT' + r 8r rc xt __-ADC-047437-- ~U013N010E--y i r r ADL047438j U013NO11 E t'` t r I I . i, a. \IN. 13-ti1 TN! ,r tfI - I E�. _ �1_, ,. - Irr �i t r t siva i \1f i E3-x1I 1�13E.,-�-'s r t e t I � x r -.... 3 t r F A 1 t - 4t p 1 ✓ kVA Y rr r 1 I J 1 * , -.: ` 4 .� .Y°�p I p h 8 I • ^zI-1 -'�"atotil�'q , r 1 I r 4 1 r 4 �, t i / a ty rr # .1"..E'_. 0 r 5 f Sec 24 rt f , 4 r I , t t I ,i I rrr If f rt r /4, l( 1' ._ t I t , i - f F/ f it 1 r dr t f f t r 1C � _ 1 V 1 , r1 r t t f e 4. tl t f r r f t1 t r t ,r I f r 1 r r l /r r 1 r 1 [ /r 1 t f r, 1 1 t „6 rr l / I t 4r/T4 e 1 r r I 1 , f I t I Id Milne Point Unit 0 500 1 MPB-30 Well .oE Feet et Page 51 Version 1 Feb 2017 • • 111 Milne Point Unit B-30 Drilling Procedure Hi1C011) Energy Company 34.0 Surface Plat (As Built) (NAD 27) ,.... i v. ..... 1 N 26011+ i ;PI -IN- M 0-PAO 14 13 18 'iilifF1 t B-PATJ 1HIS PRINECT.----,.., 1 .7, .... , \,.....„..„., .12 rii iI::' 0:2A1 1 i es 11112 , I . . v., j 24 le. 7, m14 (.-, 1 ,,,.. in 3 10 CRAWL STE 116 ..__,..„ RN 016 1 -------,„ \ 4 c vs ,o. A I VICINITY IlLA 7" in5A LEGEND; *3 46 .3 25411 -,ke rci... ,.-..,- ±AS-BUILT CONDUCTOR 16 ZAml ,50 1 .-..„.„_, 0 DOSING CONDOCTOR 0 4 I § *4 MA I OF A Ati10 4.4 +N 1130) ::.‘4tit , =*14•Ili . 0 / ,g 4,0 B-PAD r.: ,,,,........"e / 11.,If . ii. a ... row othy Fl ., (xi I ..t. 10200 -iri„,. ..:. .. _......... sokf- ,nlit''• ti1111 IA% NOTES: t ALASKA STATE PLANE COORDINATES ARE ZONE 4 NA.D24T SURVEYOR'S CERTIFICATE. 2 DEODETIC CCORDIN A TES ARE NA1327. I HEREBY CERTIFY THAT I AM 3. HCRIZON TN. AND VERTICAL CONTFt0t.ARE EIMED ON MP -PA)BPROPERLY REGISTERED AND iz.CENSEZ TO PRACTICE LAND SURVEYNG IA OPERATOR /40NUMEN TS E1-1 AND fi-2- TME STATE OF ALASKA AND THAT 4.. ELEVATORS ARE MP B-PAO DATUM, MEAN SEA LEVEL(M.S-0- ThtS AS-BUILT REPRESENTS A SURVEY MADE 8Y ME CR UNDER MY EARECT 5 MEAN PAD SCALE FACICR IS ELSRSISOSSEIT SL1PERMSON AND THAT ALL 6, DA TE OF SURVEY: SEPTEMBER 27-28, 2016. DIMENBINS AND °PIER DE TAILS ARE CORRECT AS CC SEPTEMBER 26, 2016 7. REFERENCE ow) BOOK: HC16-03. PGS. 24-33. LOCATED WITHIN PROTRACTED SEC. 18. 1 13 N. R. 11 E., UMIAT MERIDIAN, ALASKA WELL A.S.P. PLANT GEODETIC GEODETIC TOF OF SECTION -BASE FLANGE NO. COORDINATES COORDINATES POSITION(DMS) POSITION(D.O.3) GRAVEL PAD,OFFSETS ELEVATION V..6.023,208,86 N 1559.64 7078'25.298" 70.4736940" 86 FSL 8 -30 NA 571,962.86 E 600 00 1497443.916" 149.4121990' 23.1 4.328! FEL E = -- ..„.. -Mai v't,, " •"' ''. '"--- 11Hilcorp Alaska aims 6... = MIN .1.1 a tO.SiVi MOMPOO Vet I' MIMI __moos AMR 113 ous Roq, MILNE POINT B-PAD MIN MINI von------ AS-BUILT CONDUCTOR LOCATION ... IIIITir ,-;----7,-71.7-------- rim r-4,36' WELL B-30 1 rffl *A DAV *noon; are,.."1 Page 52 Version 1 Feb 2017 • • 11 Milne Point Unit B-30 Drilling Procedure Hileorp Energy Company 35.0 Offset MW vs TVD Chart MW vs TVD Offsets 0 6-21 (198& 6-25 (1997) \,,4 6-12 (1985) I 6-11 (1985) \. 6-15 (1985) (\ 6-1 (1985) 2000 6-13 (19S5) • r 6-17 (1985) 6-19 (1985) 3000 6-15(1485) I Vt F 't titki E lik, +w 5000 �' iii. A r 6000 11111 Illiarks\NI IliWitil.1111,.\ Ill 7000 immilmmimmoi •,,11011 ..,,E 8000 8.0 9.W 1C.0 11.0 12.0 Mud Weight(PPG) Page 53 Version 1 Feb 2017 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 36.0 Drill Pipe Information 5" 19.5# S-135 DS-50 Drill Pipe Configuration Pipe Body OD 1 n 5.000 80%Inspection Class Pipe Body Wall Thickness in:0.362 'Nominal Weight Designation 19-50 \ Pipe Body Grade ,S-135 'Drill Pipe Approximate Length ,r., 31.5 Drill Pipe Length Range2SrnoothEdge Height it 43/32 Raised Connection GPDS50 ;Tool Joint SMYS IPs,120.000 Tool Joint 00 6-625 Upset Type !EU iI Tool Join'. D to 3.250 ;Max Upset OD (DTE) Iln 5.125 Pin Tong 9 Friction Factor 11.0 Q Box Tong 1 n+12 Nc;r Tura 74...e,ray Include hardfaWl:O. Drill Pipe Performance Drill-Pipe Length Range2 Performance of Drill Pipe with Pipe Body at Best Estimates Nominal 80%Ins Inspection Class pu Coa agt (with Goat ngl cosi accurate) r V i A c - Drill Pipe Adlssted Weigh: (muni 24.11 23.29 , i ; r'''''''' O;�erational Max Tension '1hs} Torque in-G sl e,, Fluid Displacement tnarII,0.37 0.36 pp 43 100 Tension Only 0 560,600 Fluid Displacement cen+-nr 0 0088 ` 0.0085 1 u cnnnec Loxona 39.600 410,500 Fluid Capacity tw141)0.71 ...y0.70 0.72 Fluid Capacity Noecea4allpnlzml 0.0169 ;� 0.0167 0.0172 1 II 36,100 Tension G' ' 0 560.800 Mm mr.un Mur - Size 3.125 ccrnbtnad I.oa re 32.100 467.400 NOK Oa new harrN equal.,equal.,d:u5 s trite.Drfl tape assemtiy Values are hest estmaes and may ca,./due to pipe body m ll tolerance.Internal pla.ik coatingand other factors. Connection Performance GPDS50 ( 6.625 II1) OD X 3.250 f1nj ID ) 120,000 (P.1) Aap'tM 6hko-uy Tenson at 5'cO Ide' Tenslcn a;C.-^rrlec;ar, Tool Joint Dimensions •;;,; Torque Se"parabpn Veld _ _ rn_nrol at,.., s) Balanced OD r t 6.435 [Maximum Make-up Torque 43,100 Tensile United 1,046,900 Minrnum TOW Jont 00 forAPI 5.930 -_-.. Minimum Makeup Torque 36.100 1.202.500 1.250.000 Pren"pm c,ass m r to The axl-narrl make o rd-�.c sncO.id to accord nrcr-.>assbe Mtnlmum Tool Joint OD for 5.93 p.44a Note T m t,n o connected ocrraunal tense. IT a Or .Ta I•3 .{C';tats sh..uld to ayyir_"- Gounler6ore lent Tool Joint Torsional Strength of-teat 71,800 A/ Tool Joint Tensile Strength 050) 1,250.000 Elevator Shoulder information Elevator OD 3/32 Raised 6.812 lint SmoothEdge Height Nominal Tool Joint Worn to Bevel Worn to Min TJ DD for 3132 Raised OD Diameter API Premium Class i'Box DD ;ic,6.812 6.625 6.063 5.930 lElevator Capacity h:;1,658,000 1.440.2 823,600 685,600 _ "J .t Elnv .t.hared a.su ed Elevate Bore no wear factor.and enact stress of 110.100ps1 Assumed SIL Yz.:C4 Bore X31 ru n'�eter In-5.219..a.. l M-. A raised e;vats ODI crea.c.eloralc.capact(wtnaut affecting make-up torque Pipe Body Slip Crushing Capacity Pipe Body configuration( 5 rh> OD 0:362 lbs Wall 5-135) Nominal 80%Inspection Class API Premium Class T,[7 , Islip Crushing Capacity. ihs'498.300 396,500 396.500 iNote Sl50-..lin0 515crudity toed 1 cdkuated w11 Ore Spr.RcmJwld 0prat00 front Wly Dees Drill Paye Assumed Slip.Length In.i 16-5 Fat In re S00 Area-itbnd CO.1475 ler the se,length and transverse load rack.shown and Is for reference Transverse Load Factor iK? 4.2 •only 515 Loch O i5 dep"-r>,nert on the Sip de':'pn and cond0.01 Nett-lent of Motion Ioa500 cond".ton:.erne n atco oral Me DO and was vara n,and other factors Corrrrylwan tie So,rr'rnnacCuer GY ad110000 eformatier Pipe Body Performance Pipe Body Configuration( 5(.to1 OD 0.362 on) Wall S-135) Nominal 80%Inspection Class API Premium Class ' Pipe Tensile Strength 1hsb 712,100 560,800 560.800 Pipe Torsional S'rengtn .0.10-1 74.100 58.100 58.100 TJ PipeBody Torsional Ratio 0-97 124 1.24 80%Pape Torsional St ength "rtiest59.300 46.500 46.500 Burst ,ipvi 17.105 15.638 15,638 Not:Nominal Burst I i Collapse oau 1 15.672 10.029 10.029 calculated at 87 8.,,Rew per API I Pipe 00 ;int 5.000 4.855 4.855 t s Wall Thickness ',Ir�0.362 0.290 0.290 Nominal Pipe ID 0.14276 4.276 4.276 Cross Sectional Area of Pipe Body +.la^rt 5-275 _4.154 4.154 Cross Sectional Area of OD orteot 19.635 18.514 18.514 Cross Sectional Area of ID .10021 14.360 14.360 14.360 Sec.ion Modulus r1a`.3,1_5.708 4.476 4.476 Ploy Polar Section(Modulus (10031 11.415 8.953 8.953 Grant Page 54 Version 1 Feb 2017 0 Milne Point Unit B-30 11 Drilling Procedure Hilcorp Energy Company Operational Limits ofDrill Pipe Connection GPDS50 I Tool Joint OD „x_.16.625 Tool Joint ID ,n;3.250 Tool Joint Specified Minimum 120,000 Yield Strength 61:,n Pipe Body 80%Inspection Class Pipe Body OD ,;5 Wall Thickness . .,0.362 Pipe Body Grade 15-135 Combined Loading for Drill Pipe at Combined Loading for Drill Pipe at Maximum Make-up Torque= 43,100 (n-1,$) Minimum Make-up Torque= 36.100 -.iris PipeL1 rationa AssemblyPeer enoy cen:xct n Operational MaxAssTensiony Body Tension Man I Torque Max Tenion Mo,Tensmn Max Tension Torque Max MaxWax Tension tn4tsl abs ilnsl Ot51 MAtpt,; (n;sJ ticsl onsl 0 560,800 560,800 1,046.900 0 560.800 560.800 1.202.500 2,100 560,400 560,400 1,046,900 1,700 560,500 560,500 1,202,500 4,200 559.300 559,300 1,046.900 3.400 559.800 559.800 1,202.500 6,300 557,500 557,500 1,046,900 5,100 558,600 558,600 1.202.500 8,300 555,000 '555,000 1.046.900 6,800 556.900 556,900 1.202,500 10,400 551,700 551,700 1,046,900 8,400 554,900 554.900 1.202,500 12.500 547,600 547,600 1.046.900 10.100 552.200 552.200 1,202.50: 14.600 542.800 542,800 1,046,900 11.800 549,100 549,100 1,202,500 16,700 537,100 537,100 1.046.900 13.500 545.400 545.4:3 1.202.50_ , 18,800 530,600 530,600 1,046,900 15,200 541,200 541,200 1.202,500 20.800 523.600 523,600 1.046.900 16.900 536.500 536.500 1.202.50: 22,900 515,400 515,400 1,046.900 18.600 531,300 531,300 1,202.500 25.000 506.200 506,200 1.046.900 20.300 525.400 525.400 1.202,50: 27,100 496,100 496,100 1,046.900 22,000 519,000 519.000 1,202,500 29.200 484.800 484,800 1,046.900 23.700 512.000 512.000 1,202.500 31,300 472,500 472,500 1,046.900 25.300 504,800 504,800 1,202,500 33.300 459,600 459.600 1.046.900 27.000 496.600 496.600 1.202,500 35.400 444.700 444,700 1,046.900 28,700 487,600 487,600 1,202.500 37.500 428,400 428,400 1.046.900 30.400 477.900 477.900 1.202.500 39,600 410,500 410,500 1,046.900 32.100 467,400 467,400 1,202,500 Operational drilling torque is limited by the Make-up Torque. Operational drilling torque is limited by the Make-up Torque. Connection Niake-up Torque Range Make-up Torque Connection Max ,n_:,,;Tension ,,., -...." MinMUT 36,100 1,202,500 36,900 1,229,200 37,700 1,243,600 - 38,400 1.218,100 39,200 1,189,000 40,000 1,159,800 40,800 1,130,700 41,500 1,105,200 42,300 1,076,100 Max MUT 43,100 1,046,900 Page 55 Version 1 Feb 2017 i Milne Point Unit B-30 11 Drilling Procedure Hilcorp Energy Company Connection Wear Table Connection GPDS50 Tool Joint 00 „n;I6.625 Tool Joint ID „n,3.250 Tool Joint Specified Minimum 120,000 - Yield Strength (ml' Connection Wear Tool Connection Max Connection Max Min MUT Connection Max Joint OD Torsional MUT Tension Tension New OD Strength ,,,,,,i IflSbSi 11b51 17-;n�f Itn:? 6.625 71,800 43,100 1,046,900 35,900 1,195,900 6.562 71,800 43,100 1,034,900 35,900 1.208.700 6.499 71,800 43,100 1,022,600 35,900 1,222,400 6.435 71.800 43,100 1,009,800 35.900 1,237,500 6.372 71,200 42,700 1,008,100 35,600 1,245.200 4 s 6.309 68,000 40,800 1,057,300 34,000 1.207.700 i,,,. �`t.E.' i 6.246 64,800 38,900 1,104,800 32,400 1,169.800 6.183 61,700 37.000 1,150,40030,800 1.131,300 ,1004,={k6.12 58,600 35,200 1,190,900 29,300 1,096,100 6.056 55,500 33.300 1,232,300 27.800 1.060.800 Wom©D 5.993 52,600 31,500 1,227,200 26.300 1,024.600 5.93 49,600 29.800 1.187,100 "24,800 987.900 Pipe Body Combined Loading Table(Torque-Tension) Pipe Body 80%Inspection Class Pipe Body OD "°I5 Wall Thickness ,d0.362 Pipe Body Grade S-135 1"l Pipe Body Torque I, i Pipe Body Max 0 5.304 10,600 15,800 21.104 26.400 31.700 37.000 42.300 47.500 52800 58.100 Tension 560.800 558,400 551.400 539.600 522,500 499.600 470.000 432.400 384.500 323,100 234.300 12.200 at.,, 0 Page 56 Version 1 Feb 2017 • • 1 Hilcorp Alaska, LLC Milne Point ',' / MPtBPad Plan: MPU B-30 MPU B-30 Plan: MPU B-30 wp05 Standard Proposal Report 20 February, 2017 z i s. F" Ell HALLIBURTON Sperry Drilling Services HALLIBURTON [[ Hilcorp Alaska,LLC REFERENCE INFORMATION 1 111COrp Calculation Method: Minimum Curvature Co-ordinate(N/E)Reference: Well Plan:MPU 8-30,True North Sperry Drilling Error System: ISCWSA Vertical(TVD)Reference: MPB 30 A-Built @ 49.60usft(Innovation) Scan Method: Closest Approach 3D Measured Depth Reference: MPB 30 A-Built @ 49.60usft(Innovation) Error Surface: Elliptical Conic Warning Method: Error Ratio Calculation Method: Minimum Curvature Project: Milne Point Site: M Pt B Pad SECTION DETAILS Well: Plan:MPU B-30 Sec MD Inc Azi TVD +NI-5 +E/-W Dleg TFace VSect Target Wellbore: MPU B-30 1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.00 2 600.00 0.00 0.00 600.00 0.00 0.00 0.00 0.00 0.00 Design: MPU B-30 wp05 3 1026.50 17.06 230.00 1020.23 -40.51 -48.28 4.00 230.00 62.99 4 1191.89 21.40 214.71 1176.45 -80.96 -84.09 4.00 -56.64 116.67 5 4566.87 21.40 214.71 4318.71 -1093.34 -785.36 0.00 0.00 1315.54 6 4589.56 20.50 215.00 4339.90 -1100.00 -790.00 4.00 173.58 1323.44 MPB-30 wp5 SBOA 7 4639.12 18.53 215.75 4386.61 -1113.50 -799.58 4.00 173.06 1339.60 8 7142.86 18.53 215.75 6760.49 -1759.36 -1264.59 0.00 0.00 2117.52 9 7253.84 21.27 230.00 6864.90 -1786.64 -1290.34 5.00 67.40 2154.91 MPB-30 wp5 TKUC 10 7491.27 22.63 261.92 7085.89 -1820.86 -1368.83 5.00 98.54 2236.11 11 9310.29 22.63 261.92 8764.90 -1919.20 -2061.73 0.00 0.00 2816.40 MPB-30 wp5 TSAG 12 9512.99 22.63 261.92 8952.00 -1930.16 -2138.94 0.00 0.00 2881.07 _ WELL DETAILS: Plan:MPU B-30 _ Ground Level: 23.10 -750-- +N/-S +E/-W Northing Easting Latittude Longitude - 0.00 0.00 6023208.86 571962.88 70°28'25.298 N 149°24'43.916 W SURVEY PROGRAM 0- Date:2016-10-27T00:00:00 Validated:Yes Version: - Start Dir 4°/100':600'MD,600'TVD Depth From Depth To Survey/Plan Tool _ 26.50 600.00 MPU B-30 wp05 SRG-SSW - 50D---- 600.00 5200.00 MPU B-30 wp05 MD+IFR2+MS+sag End Dir: 1191.89'MD, 1176.45'TVD 5200.00 9512.99 MPU B-30 wp05 MWD+IFR2+MS+sag 750- - 10 - "---- CASING DETAILS Base permafrost 1500 ND TVDSS MD Size Name 1500- • -- - - - - - - 4900.00 4850.40 5180.60 9-5/8 95/8"X 12 1/4" 2000 8952.00 8902.40 9512.99 7 7"X 81/2" 2250- 2500 FORMATION TOP DETAILS - TVDPath TVDssPath MDPath Formation - 9000 1679.60 1630.00 1732.31 Base permafrost 3000- 4349.60 4300.00 4599.91 Schrader Bluff OA 6399.60 6350.00 6762.22 Base Colville - 3500 Start Dir 4°7100':4566.87'MD,4318.71'TVD 6599.60 6550.00 6973.16 Top HRZ _ 6699.60 6650.00 7078.63 Top Kalubik Gamma Marker y - 6799.60 6750.00 7184.21 Top Kuparuk D Shale 3 000 6874.60 6825.00 7264.25 Top Kuparuk C Sand 3750- Q 7209.60 7160.00 7625.29 Top Kuparuk A Sands o - ,-- MPB-30 wp5 SBOA 8824.60 8775.00 9374.97 Top Sag River LO Schrader Bluff OA 500 8874.60 8825.00 9429.14 Top Shublik --- , A"- End Dir :4639.12'MD,4386.61'ND o-4500- 0 5p00 0 p 5250- 9 5/8"X 12 1/4" 55 2 _ 5000 ~ Start Dir 5°/100':7142.86'MD,6760.49'TVD 6000- Base Colville 5y00 Top HRZ Top Kalubik Gamma Marker- _ - _ --099- MPB-30 wp5 TKUC 6750 --_Too Kuoaruk D Shams- _ = _ = _ . -- - Top Kuparuk C Sand 1-50--End Dir :7491.27'MD,7085.89'ND 7500- Top Kuparuk A Sands 8000 5500 - MPB-30 wp5 TSAG 8250- 9p00 - Top Sag River `- Total Depth:9512.99'MD,8952'ND 9000� _ _ _ _ _ _ _ _ _ _ _ _ _ _ -:-._ =_ _ ;ri,9513----- _ Top Shublik 7"X 8 1/2" MPU B-30 wp05 9750- ✓ iiilit iIiiriiiiiiiiierr II1 iiIiiiiii -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 Vertical Section at 227.94°(1500 usft/in) • HA1.I.IBUATON Project: Milne Point WELL DETAILS: Plan:MPU B-30 Site: M Pt B Pad Ground Level: 23.10 Sperry Drilling 6 6+N/-S +E/-W Northing Eason Iatittude Longitude Well: Plan:MPU B-30 Wellbore: MPU B-30 0.00 0,00 6023208.86 571962.88 70°28'25.298N 149°24'43.916W Plan: MPU B-30 wp05 REFERENCE INFORMATION IEll 1He(i 1 1 Co-ordinate(N/E)Reference:Well Plan:MPU B-30,True North Vertical(TVD)Reference:MPB 30 A-Built 6 49.60us8(Innovation) Measured Depth Reference:MPB 30 A-Built 61 49.60058(Innovation) Calculation Method:Minimum Curvature 600- 400— CASING DETAILS TVD TVDSS MD Size Name 200— 4900.00 4850.40 5180.60 9-5/8 9 5/8"X 12 1/4" 8952.00 8902.40 9512.99 7 7"X 8 1/2" -9 0- ......0 _ \000 - 1250'`.Start Dir 4°/100':600'MD,600TVD -200-- •f3� !�`f0 End Dir:1191.89'MD,1176.45'TVD <boo -400— - 22so _ 2500 -600— 23o 343, • 3''S -800— MPB-30 sops SBOA 0 3500 - • \•\\ 3'80 v-1000— 92 7 - 9 5/8"X 12 1/4" �� -1200— y 9 300 Start Dir 4°/100':4566.87'MD,4318.71'TVD 0 _ a 'r0 t% _ 5000 \\•. S End Dir:4639.12'MD,4386.61'TVD - -1400— 250 3300 - MPB-30 wp5 TKUC 6�,, 3�S0 -1600— 1 "'/O - t 6230 1 6003 - MPU B-30 wp05 MPB-30 wp5 TSAG \t t 1800_ `T X 8 1/2",/ A S O - 6953 / /' IN 1 - / -. J o i e 11 Start Dir 5°/100':7142.86'MD,6760.49'1VD C e $ o - 1 -2000— I 1 - I End Dir:7491.27'MD,7085.69'TVD - I I = Total Depth:9512.99'MD,8952'TVD -2200— -2400- -2600- -2800 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I. I 11 I I I I I I I I I I I I I 1 I III -2400 -2200 -2000 -1800 -1600 -1400 -1200 -1000 -800 -600 -400 -200 0 200 400 West(-)/East(+)(400 usft/in) • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU B-30 Company: Hilcorp Alaska,LLC TVD Reference: MPB 30 A-Built @ 49.60usft(Innovation) Project: Milne Point MD Reference: MPB 30 A-Built @ 49.60usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPU B-30 Survey Calculation Method: Minimum Curvature Wellbore: MPU B-30 Design: MPU B-30 wp05 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 B Pad,TR-13-11 Site Position: Northing: 6,021,548.49 usft Latitude: 70°28'8.986 N From: Map Easting: 571,775.55 usft Longitude: 149°24'49.895 W Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.55° Well Plan:MPU B-30 Well Position +NI-S 0.00 usft Northing: 6,023,208.86 usft Latitude: 70°28'25.298 N +E/-W 0.00 usft Easting: 571,962.88 usft Longitude: 149°24'43.916 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 23.10 usft Wellbore MPU B-30 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2016 10/27/2016 18.08 81.07 57,564 Design MPU B-30 wp05 Audit Notes: Version: Phase: PLAN Tie On Depth: 26.50 Vertical Section: Depth From(TVD) +NI-S +EI-W Direction (usft) (usft) (usft) (°) 26.50 0.00 0.00 311.00 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +NIS +E/-W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (1100usft) (1100usft) (°/100usft) (°) 26.50 0.00 0.00 26.50 -23.10 0.00 0.00 0.00 0.00 0.00 0.00 600.00 0.00 0.00 600.00 550.40 0.00 0.00 0.00 0.00 0.00 0.00 1,026.50 17.06 230.00 1,020.23 970.63 -40.51 -48.28 4.00 4.00 0.00 230.00 1,191.89 21.40 214.71 1,176.45 1,126.85 -80.96 -84.09 4.00 2.63 -9.24 -56.64 4,566.87 21.40 214.71 4,318.71 4,269.11 -1,093.34 -785.36 0.00 0.00 0.00 0.00 4,589.56 20.50 215.00 4,339.90 4,290.30 -1,100.00 -790.00 4.00 -3.97 1.28 173.58 4,639.12 18.53 215.75 4,386.61 4,337.01 -1,113.50 -799.58 4.00 -3.97 1.52 173.06 7,142.86 18.53 215.75 6,760.49 6,710.89 -1,759.36 -1,264.59 0.00 0.00 0.00 0.00 7,253.84 21.27 230.00 6,864.90 6,815.30 -1,786.64 -1,290.34 5.00 2.47 12.84 67.40 7,491.27 22.63 261.92 7,085.89 7,036.29 -1,820.86 -1,368.83 5.00 0.57 13.45 98.54 9,310.29 22.63 261.92 8,764.90 8,715.30 -1,919.20 -2,061.73 0.00 0.00 0.00 0.00 9,512.99 22.63 261.92 8,952.00 8,902.40 -1,930.16 -2,138.94 0.00 0.00 0.00 0.00 2/20/2017 5:11:37PM Page 2 COMPASS 5000.1 Build 81 • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Coordinate Reference: Well Plan:MPU 8-30 Company: Hilcorp Alaska,LLC TVD Reference: MPB 30 A-Built @ 49.60usft(Innovation) Project: Milne Point MD Reference: MPB 30 A-Built @ 49.60usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPU 8-30 Survey Calculation Method: Minimum Curvature Wellbore: MPU 8-30 Design: MPU B-30 wp05 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NI-S +E/-W Northing Easting DLS Vert Section (usft) C) C) (usft) usft (usft) (usft) (usft) (usft) -23.10 26.50 0.00 0.00 26.50 -23.10 0.00 0.00 6,023,208.86 571,962.88 0.00 0.00 100.00 0.00 0.00 100.00 50.40 0.00 0.00 6,023,208.86 571,962.88 0.00 0.00 200.00 0.00 0.00 200.00 150.40 0.00 0.00 6,023,208.86 571,962.88 0.00 0.00 300.00 0.00 0.00 300.00 250.40 0.00 0.00 6,023,208.86 571,962.88 0.00 0.00 400.00 0.00 0.00 400.00 350.40 0.00 0.00 6,023,208.86 571,962.88 0.00 0.00 500.00 0.00 0.00 500.00 450.40 0.00 0.00 6,023,208.86 571,962.88 0.00 0.00 600.00 0.00 0.00 600.00 550.40 0.00 0.00 6,023,208.86 571,962.88 0.00 0.00 Start Dir 4°i100':600'MD,600'TVD 700.00 4.00 230.00 699.92 650.32 -2.24 -2.67 6,023,206.59 571,960.23 4.00 0.55 800.00 8.00 230.00 799.35 749.75 -8.96 -10.68 6,023,199.80 571,952.29 4.00 2.18 900.00 12.00 230.00 897.81 848.21 -20.12 -23.98 6,023,188.51 571,939.10 4.00 4.90 1,000.00 16,00 230.00 994.82 945.22 -35.67 -42.51 6,023,172.79 571,920.72 4.00 8.68 1,026.50 17.06 230.00 1,020.23 970.63 -40.51 -48.28 6,023,167.89 571,915.00 4.00 9.86 1,100.00 18.83 222.37 1,090.16 1,040.56 -56.21 -64.54 6,023,152.03 571,898.89 4.00 11.83 1,191.89 21.40 214.71 1,176.45 1,126.85 -80.96 -84.09 6,023,127.10 571,879.58 4.00 10.35 End Dir:1191.89'MD,1176.45'TVD 1,200.00 21.40 214.71 1,184.00 1,134.40 -83.39 -85.77 6,023,124.65 571,877.92 0.00 10.03 1,300.00 21.40 214.71 1,277.10 1,227.50 -113.39 -106.55 6,023,094.46 571,857.44 0.00 6.03 1,400.00 21.40 214.71 1,370.21 1,320.61 -143.38 -127.33 6,023,064.26 571,836.95 0.00 2.03 1,500.00 21.40 214.71 1,463.31 1,413.71 -173.38 -148.11 6,023,034.07 571,816.47 0.00 -1.97 1,600.00 21.40 214.71 1,556.42 1,506.82 -203.38 -168.89 6,023,003.88 571,795.98 0.00 -5.97 1,700.00 21.40 214.71 1,649.52 1,599.92 -233.37 -189.67 6,022,973.68 571,775.50 0.00 -9.96 1,732.31 21.40 214.71 1,679.60 1,630.00 -243.07 -196.38 6,022,963.93 571,768.88 0.00 -11.26 Base permafrost 1,800.00 21.40 214.71 1,742.63 1,693.03 -263.37 -210.45 6,022,943.49 571,755.01 0.00 -13.96 1,900.00 21.40 214.71 1,835.73 1,786.13 -293.37 -231.22 6,022,913.30 571,734.52 0.00 -17.96 2,000.00 21.40 214.71 1,928.84 1,879.24 -323.36 -252.00 6,022,883.10 571,714.04 0.00 -21.96 2,100.00 21.40 214.71 2,021.94 1,972.34 -353.36 -272.78 6,022,852.91 571,693.55 0.00 -25.95 2,200.00 21.40 214.71 2,115.04 2,065.44 -383.36 -293.56 6,022,822.72 571,673.07 0.00 -29.95 2,300.00 21.40 214.71 2,208.15 2,158.55 -413.35 -314.34 6,022,792.52 571,652.58 0.00 -33.95 2,400.00 21.40 214.71 2,301.25 2,251.65 -443.35 -335.12 6,022,762.33 571,632.10 0.00 -37.95 2,500.00 21.40 214.71 2,394.36 2,344.76 -473.35 -355.90 6,022,732.14 571,611.61 0.00 -41.95 2,600.00 21.40 214.71 2,487.46 2,437.86 -503.35 -376.68 6,022,701.94 571,591.12 0.00 -45.94 2,700.00 21.40 214.71 2,580.57 2,530.97 -533.34 -397.45 6,022,671.75 571,570.64 0.00 -49.94 2,800.00 21.40 214.71 2,673.67 2,624.07 -563.34 -418.23 6,022,641.56 571,550.15 0.00 -53.94 2,900.00 21.40 214.71 2,766.78 2,717.18 -593.34 -439.01 6,022,611.36 571,529.67 0.00 -57.94 3,000.00 21.40 214.71 2,859.88 2,810.28 -623.33 -459.79 6,022,581.17 571,509.18 0.00 -61.93 3,100.00 21.40 214.71 2,952.98 2,903.38 -653.33 -480.57 6,022,550.98 571,488.70 0.00 -65.93 3,200.00 21.40 214.71 3,046.09 2,996.49 -683.33 -501.35 6,022,520.78 571,468.21 0.00 -69.93 3,300.00 21.40 214.71 3,139.19 3,089.59 -713.32 -522.13 6,022,490.59 571,447.72 0.00 -73.93 3,400.00 21.40 214.71 3,232.30 3,182.70 -743.32 -542.90 6,022,460.40 571,427.24 0.00 -77.93 3,500.00 21.40 214.71 3,325.40 3,275.80 -773.32 -563.68 6,022,430.20 571,406.75 0.00 -81.92 3,600.00 21.40 214.71 3,418.51 3,368.91 -803.31 -584.46 6,022,400.01 571,386.27 0.00 -85.92 3,700.00 21.40 214.71 3,511.61 3,462.01 -833.31 -605.24 6,022,369.82 571,365.78 0.00 -89.92 3,800.00 21.40 214.71 3,604.72 3,555.12 -863.31 -626.02 6,022,339.62 571,345.30 0.00 -93.92 2/20/2017 5:11:37PM Page 3 COMPASS 5000.1 Build 81 • 0 Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU B-30 Company: Hilcorp Alaska,LLC ND Reference: MPB 30 A-Built @ 49.60usft(Innovation) Project: Milne Point MD Reference: MPB 30 A-Built @ 49.60usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPU B-30 Survey Calculation Method: Minimum Curvature Wellbore: MPU B-30 Design: MPU B-30 wp05 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) 3,648.22 3,900.00 21.40 214.71 3,697.82 3,648.22 -893.30 -646.80 6,022,309.43 571,324.81 0.00 -97.92 4,000.00 21.40 214.71 3,790.93 3,741.33 -923.30 -667.58 6,022,279.24 571,304.33 0.00 -101.91 4,100.00 21.40 214.71 3,884.03 3,834.43 -953.30 -688.35 6,022,249.04 571,283.84 0.00 -105.91 4,200.00 21.40 214.71 3,977.13 3,927.53 -983.29 -709.13 6,022,218.85 571,263.35 0.00 -109.91 4,300.00 21.40 214.71 4,070.24 4,020.64 -1,013.29 -729.91 6,022,188.66 571,242.87 0.00 -113.91 4,400.00 21.40 214.71 4,163.34 4,113.74 -1,043.29 -750.69 6,022,158.46 571,222.38 0.00 -117.90 4,500.00 21.40 214.71 4,256.45 4,206.85 -1,073.28 -771.47 6,022,128.27 571,201.90 0.00 -121.90 4,566.87 21.40 214.71 4,318.71 4,269.11 -1,093.34 -785.36 6,022,108.08 571,188.20 0.00 -124.58 Start Dir 4°/100':4566.87'MD,4318.71'ND 4,589.56 20.50 215.00 4,339.90 4,290.30 -1,100.00 -790.00 6,022,101.38 571,183.63 4.00 -125.44 4,599.91 20.09 215.15 4,349.60 4,300.00 -1,102.94 -792.06 6,022,098.42 571,181.59 4.00 -125.81 Schrader Bluff OA . 4,600.00 20.09 215.15 4,349.69 4,300.09 -1,102.96 -792.08 6,022,098.40 571,181.58 4.00 -125.82 4,639.12 18.53 215.75 4,386.61 4,337.01 -1,113.50 -799.58 6,022,087.79 571,174.18 4.00 -127.07 End Dir :4639.12'MD,4386.61'ND 4,700.00 18.53 215.75 4,444.33 4,394.73 -1,129.21 -810.89 6,022,071.97 571,163.02 0.00 -128.84 4,800.00 18.53 215.75 4,539.14 4,489.54 -1,155.00 -829.46 6,022,046.00 571,144.70 0.00 -131.75 4,900.00 18.53 215.75 4,633.96 4,584.36 -1,180.80 -848.03 6,022,020.03 571,126.38 0.00 -134.65 5,000.00 18.53 215.75 4,728.77 4,679.17 -1,206.59 -866.60 6,021,994.06 571,108.06 0.00 -137.56 5,100.00 18.53 215.75 4,823.58 4,773.98 -1,232.39 -885.18 6,021,968.09 571,089.74 0.00 -140.47 5,180.60 18.53 215.75 4,900.00 4,850.40 -1,253.18 -900.15 6,021,947.15 571,074.98 0.00 -142.81 9 5/8"X 12 1/4" 5,200.00 18.53 215.75 4,918.40 4,868.80 -1,258.18 -903.75 6,021,942.11 571,071.42 0.00 -143.37 5,300.00 18.53 215.75 5,013.21 4,963.61 -1,283.98 -922.32 6,021,916.14 571,053.10 0.00 -146.28 5,400.00 18.53 215.75 5,108.03 5,058.43 -1,309.78 -940.89 6,021,890.17 571,034.78 0.00 -149.19 5,500.00 18.53 215.75 5,202.84 5,153,24 -1,335.57 -959.47 6,021,864.20 571,016.46 0.00 -152.09 5,600.00 18.53 215.75 5,297.65 5,248.05 -1,361.37 -978.04 6,021,838.23 570,998.14 0.00 -155.00 5,700.00 18.53 215.75 5,392.47 5,342.87 -1,387.16 -996.61 6,021,812.26 570,979.82 0.00 -157.91 5,800.00 18.53 215.75 5,487.28 5,437.68 -1,412.96 -1,015.19 6,021,786.28 570,961.50 0.00 -160.82 5,900.00 18.53 215.75 5,582.09 5,532.49 -1,438.76 -1,033.76 6,021,760.31 570,943.18 0.00 -163.72 6,000.00 18.53 215.75 5,676.91 5,627.31 -1,464.55 -1,052.33 6,021,734.34 570,924.86 0.00 -166.63 6,100.00 18.53 215.75 5,771.72 5,722.12 -1,490.35 -1,070.90 6,021,708.37 570,906.54 0.00 -169.54 6,200.00 18.53 215.75 5,866.53 5,816.93 -1,516.14 -1,089.48 6,021,682.40 570,888.22 0.00 -172.44 6,300.00 18.53 215.75 5,961.35 5,911.75 -1,541.94 -1,108.05 6,021,656.43 570,869.90 0.00 -175.35 6,400.00 18.53 215.75 6,056.16 6,006.56 -1,567.73 -1,126.62 6,021,630.45 570,851.58 0.00 -178.26 6,500.00 18.53 215.75 6,150.98 6,101.38 -1,593.53 -1,145.19 6,021,604.48 570,833.25 0.00 -181.16 6,600.00 18.53 215.75 6,245.79 6,196.19 -1,619.33 -1,163.77 6,021,578.51 570,814.93 0.00 -184.07 6,700.00 18.53 215.75 6,340.60 6,291.00 -1,645.12 -1,182.34 6,021,552.54 570,796.61 0.00 -186.98 6,762.22 18.53 215.75 6,399.60 6,350.00 -1,661.17 -1,193.89 6,021,536.38 570,785.21 0.00 -188.78 Base Colville 6,800.00 18.53 215.75 6,435.42 6,385.82 -1,670.92 -1,200.91 6,021,526.57 570,778.29 0.00 -189.88 6,900.00 18.53 215.75 6,530.23 6,480.63 -1,696.71 -1,219.48 6,021,500.59 570,759.97 0.00 -192.79 6,973.16 18.53 215.75 6,599.60 6,550.00 -1,715.59 -1,233.07 6,021,481.59 570,746.57 0.00 -194.92 Top HRZ 7,000.00 18.53 215.75 6,625.04 6,575.44 -1,722.51 -1,238.06 6,021,474.62 570,741.65 0.00 -195.70 2/20/2017 5:11:37PM Page 4 COMPASS 5000.1 Build 81 0 • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU B-30 Company: Hilcorp Alaska,LLC ND Reference: MPB 30 A-Built @ 49.60usft(Innovation) Project: Milne Point MD Reference: MPB 30 A-Built @ 49.60usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPU B-30 Survey Calculation Method: Minimum Curvature Wellbore: MPU B-30 Design: MPU B-30 wp05 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) 6,650.00 7,078.63 18.53 215.75 6,699.60 6,650.00 -1,742.79 -1,252.66 6,021,454.20 570,727.25 0.00 -197.98 Top Kalubik Gamma Marker 7,100.00 18.53 215.75 6,719.86 6,670.26 -1,748.31 -1,256.63 6,021,448.65 570,723.33 0.00 -198.60 7,142.86 18.53 215.75 6,760.49 6,710.89 -1,759.36 -1,264.59 6,021,437.52 570,715.48 0.00 -199.85 Start Dir 5°/100':7142.86'MD,6760.49'TVD 7,184.21 19.42 221.50 6,799.60 6,750.00 -1,769.84 -1,272.98 6,021,426.96 570,707.19 5.00 -200.39 Top Kuparuk D Shale 7,200.00 19.80 223.56 6,814.48 6,764.88 -1,773.75 -1,276.57 6,021,423.02 570,703.64 5.00 -200.25 7,253.84 21.27 230.00 6,864.90 6,815.30 -1,786.64 -1,290.34 6,021,410.00 570,690.00 5.00 -198.31 7,264.25 21.20 231.42 6,874.60 6,825.00 -1,789.02 -1,293.25 6,021,407.59 570,687.11 5.00 -197.67 Top Kuparuk C Sand 7,300.00 21.05 236.37 6,907.95 6,858.35 -1,796.61 -1,303.65 6,021,399.90 570,676.78 5.00 -194.80 7,400.00 21.38 250.18 7,001.23 6,951.63 -1,812.75 -1,335.77 6,021,383.45 570,644.82 5.00 -181.15 7,491.27 22.63 261.92 7,085.90 7,036.30 -1,820.86 -1,368.83 6,021,375.02 570,611.85 5.00 -161.52 End DIr :7491.27'MD,7085.89'ND 7,500.00 22.63 261.92 7,093.95 7,044.35 -1,821.33 -1,372.15 6,021,374.52 570,608.53 0.00 -159.32 7,600.00 22.63 261.92 7,186.26 7,136.66 -1,826.74 -1,410.24 6,021,368.75 570,570.50 0.00 -134.12 7,625.29 22.63 261.92 7,209.60 7,160.00 -1,828.10 -1,419.88 6,021,367.29 570,560.88 0.00 -127.75 Top Kuparuk A Sands 7,700.00 22.63 261.92 7,278.56 7,228.96 -1,832.14 -1,448.34 6,021,362.97 570,532.46 0.00 -108.92 7,800.00 22.63 261.92 7,370.86 7,321.26 -1,837.55 -1,486.43 6,021,357.20 570,494.43 0.00 -83.72 7,900.00 22.63 261.92 7,463.16 7,413.56 -1,842.95 -1,524.52 6,021,351.43 570,456.39 0.00 -58.52 8,000.00 22.63 261.92 7,555.47 7,505.87 -1,848.36 -1,562.61 6,021,345.65 570,418.36 0.00 -33.32 8,100.00 22.63 261.92 7,647.77 7,598.17 -1,853.77 -1,600.70 6,021,339.88 570,380.32 0.00 -8.11 8,200.00 22.63 261.92 7,740.07 7,690.47 -1,859.17 -1,638.80 6,021,334.10 570,342.29 0.00 17.09 8,300.00 22.63 261.92 7,832.37 7,782.77 -1,864.58 -1,676.89 6,021,328.33 570,304.26 0.00 42.29 8,400.00 22.63 261.92 7,924.68 7,875.08 -1,869.99 -1,714.98 6,021,322.56 570,266.22 0.00 67.49 8,500.00 22.63 261.92 8,016.98 7,967.38 -1,875.39 -1,753.07 6,021,316.78 570,228.19 0.00 92.69 8,600.00 22.63 261.92 8,109.28 8,059.68 -1,880.80 -1,791.16 6,021,311.01 570,190.15 0.00 117.89 8,700.00 22.63 261.92 8,201.59 8,151.99 -1,886.20 -1,829.25 6,021,305.24 570,152.12 0.00 143.09 8,800.00 22.63 261.92 8,293.89 8,244.29 -1,891.61 -1,867.35 6,021,299.46 570,114.09 0.00 168.30 8,900.00 22.63 261.92 8,386.19 8,336.59 -1,897.02 -1,905.44 6,021,293.69 570,076.05 0.00 193.50 9,000.00 22.63 261.92 8,478.49 8,428.89 -1,902.42 -1,943.53 6,021,287.92 570,038.02 0.00 218.70 9,100.00 22.63 261.92 8,570.80 8,521.20 -1,907.83 -1,981.62 6,021,282.14 569,999.98 0.00 243.90 9,200.00 22.63 261.92 8,663.10 8,613.50 -1,913.23 -2,019.71 6,021,276.37 569,961.95 0.00 269.10 9,300.00 22.63 261.92 8,755.40 8,705.80 -1,918.64 -2,057.81 6,021,270.59 569,923.91 0.00 294.30 9,310.29 22.63 261.92 8,764.90 8,715.30 -1,919.20 -2,061.73 6,021,270.00 569,920.00 0.00 296.90 9,374.97 22.63 261.92 8,824.60 8,775.00 -1,922.69 -2,086.36 6,021,266.27 569,895.40 0.00 313.20 Top Sag River 9,400.00 22.63 261.92 8,847.70 8,798.10 -1,924.05 -2,095.90 6,021,264.82 569,885.88 0.00 319.51 9,429.14 22.63 261.92 8,874.60 8,825.00 -1,925.62 -2,107.00 6,021,263.14 569,874.80 0.00 326.85 Top Shublik 9,500.00 22.63 261.92 8,940.01 8,890.41 -1,929.45 -2,133.99 6,021,259.05 569,847.85 0.00 344.71 9,512.99 22.63 261.92 8,952.00 8,902.40 -1,930.16 -2,138.94 6,021,258.30 569,842.90 0.00 347.98 Total Depth:9512.99'MD,8952'ND 2/20/2017 5:11:37PM Page 5 COMPASS 5000.1 Build 81 • i Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU B-30 Company: Hilcorp Alaska,LLC TVD Reference: MPB 30 A-Built @ 49.60usft(Innovation) Project: Milne Point MD Reference: MPB 30 A-Built @ 49.60usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPU B-30 Survey Calculation Method: Minimum Curvature Wellbore: MPU B-30 Design: MPU B-30 wp05 Targets Target Name -hit/miss target Dip Angle Dip Dir. ND +N/-S +E/-W Northing Easting -Shape (°) (°) (usft) (usft) (usft) (usft) (usft) MPB-30 wp5 TKUC 0.00 0.00 6,864.90 -1,786.64 -1,290.34 6,021,410.00 570,690.00 -plan hits target center -Point MPB-30 wp5 TSAG 0.00 0.00 8,764.90 -1,919.20 -2,061.73 6,021,270.00 569,920.00 -plan hits target center -Point MPB-30 wp5 SBOA 0.00 0.00 4,339.90 -1,100.00 -790.00 6,022,101.38 571,183.63 -plan hits target center -Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 5,180.60 4,900.00 9 5/8"X 12 1/4" 9-5/8 12-1/4 9,512.99 8,952.00 7"X 8 1/2" 7 8-1/2 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology (1 (`) 4,599.91 4,349.60 Schrader Bluff OA 6,762.22 6,399.60 Base Colville 6,973.16 6,599.60 Top HRZ 9,429.14 8,874.60 Top Shublik 7,184.21 6,799.60 Top Kuparuk D Shale 7,078.63 6,699.60 Top Kalubik Gamma Marker 1,732.31 1,679.60 Base permafrost 7,264.25 6,874.60 Top Kuparuk C Sand 7,625.29 7,209.60 Top Kuparuk A Sands 9,374.97 8,824.60 Top Sag River Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 600.00 600.00 0.00 0.00 Start Dir 4°/100':600'MD,600'TVD 1,191.89 1,176.45 -80.96 -84.09 End Dir:1191.89'MD,1176.45'TVD 4,566.87 4,318.71 -1,093.34 -785.36 Start Dir 4°/100':4566.87'MD,4318.71TVD 4,639.12 4,386.61 -1,113.50 -799.58 End Dir :4639.12'MD,4386.61'TVD 7,142.86 6,760.49 -1,759.36 -1,264.59 Start Dir 5°/100':7142.86'MD,6760.49'TVD 7,491.27 7,085.90 -1,820.86 -1,368.83 End Dir :7491.27'MD,7085.89'TVD 9,512.99 8,952.00 -1,930.16 -2,138.94 Total Depth:9512.99'MD,8952'TVD 2/20/2017 5:11:37PM Page 6 COMPASS 5000.1 Build 81 • • Hilcorp Alaska, LLC Milne Point M Pt B Pad Plan: MPU B-30 MPU B-30 MPU B-30 wp05 Sperry Drilling Services Clearance Summary Anticollision Report 20 February,2017 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: M Pt B Pad-Plan:MPU 0.30•MPU 8.30-MPU B-30 wp05 Well Coordinates:6,023,208.86 N,571,962.88 E 170°28'25.30"N,149°24'43.92"W) Datum Height: MPB 30 A-Built l 49.60usft(Innovation) Scan Range: 0.00 to 9,512.99 usft.Measured Depth. Scan Radius is 1,148.65 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version:5000.1 Build:81 Scan Type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU B-30-MPU B-30 wp05 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: M Pt B Pad-Plan:MPU B-30-MPU B-30-MPU B-30 wp05 Scan Range: 0.00 to 9512.99 usft.Measured Depth. Scan Radius is 1,148.65 usft.Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft M Pt B Pad MPB-01-MPB-01-MPB-01 1,421.28 268.32 1,421.28 253.63 1,386.57 18.272 Centre Distance Pass- MPB-01-MPB-01-MPB-01 1,450.00 268.51 1,450.00 253.51 1,413.45 17.902 Ellipse Separation Pass- MPB-01-MPB-01-MPB-01 5,075.00 1,145.30 5,075.00 1669.18 4,942.78 15.046 Clearance Factor Pass- MPB-02-MPB-02-MPB-02 898.13 87.28 898.13 79.37 891.88 11.027 Centre Distance Pass- MPB-02-MPB-02-MPB-02 900.00 87.28 900.00 79.36 893.70 11.012 Ellipse Separation Pass- MPB-02-MPB-02-MPB-02 1,000.00 90.76 1,000.00 82.19 990.54 10.589 Clearance Factor Pass- MPB-02-Plan MPB-02A-MPB-02Awp03 702.83 86.49 702.83 82.49 698.32 21.659 Ellipse Separation Pass- MPB-02-Plan MPB-02A-MPB-02Awp03 775.00 87.67 775.00 83.54 767.95 21.247 Clearance Factor Pass- MPB-04-MPB-04A-MPB-04A 695.62 362.86 695.62 354.41 709.17 42.987 Centre Distance Pass- MPB-04-MPB-04A-MPB-04A 750.00 363.09 750.00 354.24 762.04 41.038 Ellipse Separation Pass- MPB-04-MPB-04A-MPB-04A 4,500.00 542.53 4,500.00 449.20 4,733.84 5.813 Clearance Factor Pass- MPB-05-MPB-05-MPB-05 564.20 224.19 564.20 216.97 573.62 31.024 Centre Distance Pass- MPB-05-MP8-05-MPB-05 600.00 224.27 600.00 216.64 608.13 29.373 Ellipse Separation Pass- MPB-05-MPB-05-MPB-05 825.00 245.38 825.00 235.91 816.50 25.892 Clearance Factor Pass- MPB-05-MPB-05A-MPB-05A 564.20 224.19 564.20 21697 573.62 31.024 Centre Distance Pass- MPB-05-MPB-05A-MPB-05A 600.00 224.27 600.00 216.64 608.13 29.373 Ellipse Separation Pass- MPB-05-MPB-05A-MPB-05A 825.00 245.38 825.00 235.91 816.50 25.892 Clearance Factor Pass- MPB-06-MPB-06-MPB-06 237.39 30.16 237.39 27.06 246.79 9.731 Centre Distance Pass- MPB-06-MPB-06-MPB-06 2,150.00 51.48 2,150.00 15.24 2,185.68 1.421 Clearance Factor Pass- MPB-09-MPB-09-MPB-09 482.61 269.08 482.61 262.97 492.04 44.080 Centre Distance Pass- MPB-09-MPB-09-MPB-09 600.00 269.52 600.00 262.01 607.45 35.902 Ellipse Separation Pass- MPB-09-MPB-09-MPB-09 2,600.00 385.37 2,600.00 328.51 2,637.32 6.777 Clearance Factor Pass- MPB-10-MPB-10-MPB-10 90.65 150.36 90.65 149.30 100.05 141.756 Centre Distance Pass- MPB-10-MPB-10-MPB-10 350.00 151.62 350.00 148.29 357.95 45.512 Ellipse Separation Pass- MPB-10-MPB-10-MPB-10 875.00 183.16 875.00 175.63 870.83 24.328 Clearance Factor Pass- MPB-15-MPB-15-MPB-15 705.10 257.32 705.10 250.40 733.20 37.169 Centre Distance Pass- MPB-15-MPB-15-MPB-15 725.00 257.38 725.00 250.34 754.95 36.549 Ellipse Separation Pass- MPB-15-MPB-15-MPB-15 975.00 279.06 975.00 270.56 1,002.06 32.839 Clearance Factor Pass- 20 February,2017- 17:47 Page 2 of 6 COMPASS S • Hilcorp Alaska,LLC HALLI BURTO N Milne Point Anticollision Report for Plan: MPU B-30 -MPU B-30 wp05 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: M Pt B Pad•Plan:MPU B-30-MPU 6-30-MPU B-30 wp05 Scan Range: 0.00 to 9,512.99 usft.Measured Depth. Scan Radius is 1,148.65 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft MPB-17-MPB-17-MPB-17 3,210.77 76.99 3,210.77 20.37 3,248.09 1.360 Centre Distance Pass- MPB-17-MPB-17-MPB-17 3,275.00 79.78 3,275.00 16.12 3,308.79 1.253 Clearance Factor Pass- MPB-20-MPB-20-MPB-20 5,933.16 771.84 5,933.16 587.81 6,513.27 4.194 Centre Distance Pass- MPB-20-MPB-20-MPB-20 6,225.00 784.07 6,225.00 571.21 6,759.06 3.683 Ellipse Separation Pass- MPB-20-MPB-20-MPB-20 6,750.00 873.01 6,750.00 617.69 7,214.14 3.419 Clearance Factor Pass- MPB-21-MPB-21-MPB-21 3,378.22 379.64 3,378.22 243.60 3,926.13 2.791 Centre Distance Pass- MPB-21-MPB-21-MPB-21 3,500.00 384.19 3,500.00 236.63 4,035.41 2.604 Ellipse Separation Pass- MPB-21-MPB-21-MPB-21 3,600.00 395.77 3,600.00 241.70 4,120.16 2.569 Clearance Factor Pass- MPB-21-MPB-21PB1-MPB-21PB1 3,378.22 379.64 3,378.22 243.60 3,926.13 2,791 Centre Distance Pass- MPB-21•MPB-21PB1-MPB-21PB1 3,500.00 384.19 3,500.00 236.63 4,035.41 2.604 Ellipse Separation Pass- MPB-21-MPB-21PB1-MPB-21 P61 3,600.00 395.77 3,600.00 241.70 4,120.16 2.569 Clearance Factor Pass- MPB-22-MPB-22-MPB-22 2,680.59 156.99 2,680.59 98.72 2,778.18 2.694 Centre Distance Pass- MPB-22-MPB-22-MPB-22 2,725.00 158.03 2,725.00 97.54 2,817.66 2.613 Ellipse Separation Pass- MPB-22-MPB-22-MPB-22 2,775.00 161.57 2,775.00 98.98 2,863.63 2.581 Clearance Factor Pass- MPB-22-MPB-22A-MPB-22A 2,680.59 156.99 2,680.59 98.72 2,778.18 2.694 Centre Distance Pass- MPB-22-MPB-22A-MPB-22A 2,725.00 158.03 2,725.00 97.54 2,817.66 2.613 Ellipse Separation Pass- MPB-22-MPB-22A-MPB-22A 2,775.00 161.57 2,775.00 98.98 2,863.63 2.581 Clearance Factor Pass- MPB-22-MPB-22APB1-MPB-22AP61 2,680.59 156.99 2,680.59 98.72 2,778.18 2.694 Centre Distance Pass- MPB-22-MPB-22APB1-MPB-22APB1 2,725.00 158.03 2,725.00 97.54 2,817.66 2.613 Ellipse Separation Pass- MPB-22-MPB-22APB1-MPB-22APB1 2,775.00 161.57 2,775.00 98.98 2,863.63 2.581 Clearance Factor Pass- MPB-23-MPB-23-MPB-23 628.28 92.16 628.28 87.09 633.09 18,161 Centre Distance Pass- MPB-23-MPB-23-MPB-23 675.00 92.38 675.00 86.79 679.95 16.530 Ellipse Separation Pass- MPB-23-MPB-23-MPB-23 1,050.00 112.80 1,050.00 103.46 1,055.13 12.077 Clearance Factor Pass- MPB-25-MPB-25-MPB-25 1,575.00 54.42 1,575.00 42.66 1,560.09 4.627 Clearance Factor Pass- MPB-25-MPB-25-MPB-25 1,600.00 52.71 1,600.00 41.36 1,582.89 4.645 Ellipse Separation Pass- MPB-25-MPB-25-MPB-25 1,612.05 52.50 1,612.05 41.42 1,593.83 4.738 Centre Distance Pass- MPB-27-MPB-27-MPB-27 796.19 112.59 796.19 106.38 802.47 18.131 Centre Distance Pass- MPB-27-MPB-27-MPB-27 800.00 112.60 800.00 106.38 806.11 18.115 Ellipse Separation Pass- MPB-27-MPB-27-MPB-27 850.00 113.57 850.00 107.26 853.44 17.998 Clearance Factor Pass- MPB-28-MPB-28-MPB-28 3,725.00 88.06 3,725.00 58.95 3,733.38 3.026 Clearance Factor Pass- 20 February,2017-17:47 Page 3 016 COMPASS • • • • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU B-30-MPU B-30 wp05 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: M Pt B Pad-Plan:MPU B-30-MPU B-30-MPU B-30 wp05 Scan Range: 0.00 to 9,512.99 usft.Measured Depth. Scan Radius is 1,148.65 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft MPB-28-MPB-28-MPB-28 3,825.00 82.52 3,825.00 56.79 3,835.46 3.207 Ellipse Separation Pass- MPB-28-MPB-28-MPB-28 3,900.27 80.69 3,900.27 58.79 3,910.78 3.684 Centre Distance Pass- MPB-29-MPB-29-MPB-29 1,384.41 74.17 1,384.41 64.17 1,375.89 7.421 Clearance Factor Pass- Plan:MPU 8-31-MPU B-31-MPU B-3t wp05 1,000.00 69.50 1,000.00 60.57 1,003.46 7.786 Clearance Factor Pass- Plan:MPU 5-31-MPU B-31-MPU B-31 wp05 1,006.02 69.44 1,006.02 60.57 1,008.58 7.826 Ellipse Separation Pass- Plan:MPU B-33-MPU 5-33-MPU B-33 wp04 738.49 38.62 738.49 32.16 740.45 5.978 Clearance Factor Pass- Rig:MPU 5-32-MPU B-32-MPB-32 wp05 250.36 30.26 250.36 27.62 250.16 11.431 Centre Distance Pass- Rig:MPU B-32-MPU B-32-MPB-32 wp05 325.00 30.46 325.00 27.16 324.60 9.228 Ellipse Separation Pass- Rig:MPU B-32-MPU 5-32-MPB-32 wp05 500.00 36.06 500.00 31.22 497.67 7.452 Clearance Factor Pass- Rig:MPU B-32-MPU B-32-MPU B-32 26.50 30.26 26.50 29.57 26.40 43.338 Centre Distance Pass- Rig:MPU B-32-MPU B-32-MPU B-32 225.00 31.04 225.00 28.83 224.43 14.050 Ellipse Separation Pass- Rig:MPU B-32-MPU B-32-MPU B-32 500.00 40.71 500.00 35.99 497.24 8.617 Clearance Factor Pass- Survey tool program From To Survey/Plan Survey Tool (usft) (usft) 26.50 600.00 MPU B-30 wp05 SRG-SS 600.00 5,200.00 MPU B-30 wp05 MWD+IFR2+MS+sag 5,200.00 9,512.99 MPU B-30 wp05 MWD*IFR2*MS*sag Ellipse error terms are correlated across survey tool tie-on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor=Distance Between Profiles/(Distance Between Profiles-Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 20 February,2017-17:47 Page 4 of 6 COMPASS ID S Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU B-30-MPU B-30 wp05 Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to MPB 30 A-Built @ 49.60usft(Innovation). Northing and Easting are relative to Plan:MPU B-30. Coordinate System is US State Plane 1927(Exact solution),Alaska Zone 04. Central Meridian is-150.00°,Grid Convergence at Surface is: 0.55°. LFGEND Ladder Plot -4- MP B-01,MPB-01,MPB-01 V1 -0- MPB-02,MPB-02,MPB-02 V10 `----r- r---- r 1 $ MPB-02,Plan NPB-02A,fvPB-02Avp03V26 I 1 C i • 1 A -Ir MPB-04,MPB-04A,MPB-04A V1 ,-.7.. qr, 1 N1050 vgip D/ij [ , / i l' 1 I� $ MPB-05,MPB-0S,MPB-05 V1 7 1, it , • fIi� - -• MPB-05,MPB-05A,NPB-05AV2 O ,� l.iy , ` �� -X- MPB-06,MPB-06,MPB-06 V1 Ln iI,-+"!g !. __ r�/ �� 11. . I -X- MPB-09,MPB-09,MPB-09 V1 4� �� j; 7�. p -0- MPB-10,MPB-10,MPB-10V18 i I r//, I� 1, �i� ? c -0- MPB-15,MPB-15,MPB-15 V21 N 7� i 7Ll i� •, 1 11� i 1 �MPB-17,MPB-17,MPB-17 V1 as N 1''ai A"2�. ,\ I/ I $ MPB-20,MPB-20,MPB-20 V1 1/, �� Ij4t'' 14 /�� $ MPB-21,MP8-21,MPB-21 V1 N 11 r'ri� /i!1 0!- -1-- MPB-21,NPB-21PB1,NPB-21PB1V4 c> i -1- MPB-22,MPB-22,MPB-22 V1 („) 3 1 -0.1/i. r, tioi II MPB-22,MPB-22A,MPB-22A V2 e/r.A"i 3•- MPB-22,MPB-22APB1,NPB-22APB1V2 1 i `_ I ',t ♦- MPB-23,MPB-23,MP8-23V1 cf da"`�.e _ _ $ MPB-25,MPB-25,MPB-25 V1 U ". is''t - I/ $ MPB-27,MPB-27,MPB-27V12 �•5 $ MPB-28,MPB-28,MPB-28 V0 0 {- MPB-29,MPB-29,MPB-29V0 0 1500 3000 4500 6000 7500 -B- Plan:MPU B-31,MPU B-31,MPU B-31wp05V0 usft/in -d- Plan:MPU B-33,MPU B-33,MPU B-33 wp04 VO DepthMred (1500 � Rig:MPU B-32,MPU 8-32,MPB-32 wp05 VO d., rag:Niru r5-3L,Nru ti-3L,NIru t3-3L VV 20 February,2017-17:47 Page 5 of 6 COMPASS • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU B-30-MPU B-30 wp05 Clearance Factor Plot: Measured Depth versus Separation(Clearance)Factor LEGEND IIiI1I1LiII1F 1 ill.. ® _. -4-MPB-01,MPB-01,MP B-01 V1 10.00 1111 III 111 -4- MPB-02,MPB-02,MPB-02 V10 $ MPB-02,PIanMPB-02A,MPB-02Awp03V26 1�1 /.8.75 MPB-04,MPB-04A,MPB-04AV1$ MPB-05,MPB-05,MPB-05V1 -!- MPB-05,MPB-0SA,MPB-05AV2�.1 II/1 --_111 ��' �f MPB-O6,MPB-06,MPB-06V1 7.50 - N IWIMU MPB09,MP89MPB9V1 o 625°mc 500 -L.L° .. 21MPB-21MP8-21 V1 i �- MPB- V4 ►1 111 / 1, * i it- MP B-22,MPB-22,MPB-22 V1 �' MPB-22,MPB-22A,MPB-22AV2 2.50 i !! t f, ♦- • MPB-23,MPB 2 PB-23 B12AP61 V2 Ilf -e- MPB-25,MPB-25,MPB-25V1 Colrain Avoidance Req 1111 _• CoZoon-vd ng MPB-27,MPB-27,MPB-27 V12 125 -- _ _ -�r� $ MPB-28,MPB-28,MPB-28V0 - - -11- MPB-29,MPB-29,MPB-29V0 '... -9- Plan:MPU B-31,MPU B-31,MPU B-31 wp05 VO 0.00 , , , , li r „ 1 , , , 11 , , , , ,T11 , , , , , , , I I I „ 1111 1111 1111 „ „ I I -a- pIan:MPU B-33,MPUB-33,MPUB-33wp04VO 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 Rig:MPU B-32,MPU 6-32,MPB-32 wp05 V0 MeasUed Depth(1500 us1Vn) , Rig:MPU B-32,MPU B-32,MPU B-32 VO 20 February,2017- 17:47 Page 6 of 6 COMPASS • • TRANSMITTAL LETTER CHECKLIST WELL NAME: in i k . -30 CANt'si,d) PTD: Q,IC - 1S•3 /Development Service _Exploratory Stratigraphic Test _Non-Conventional FIELD: � t'►E ?c (\i 6()1r 1 POOL: , III 2HlF) -c646 1- 64 Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - . (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - - ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10'sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non-Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a)authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application,the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 0 111 [1]II , , ; , , a) O- pp a), a) ! . •V, OJ V1• 1 a, °' c Z of O. L ¢ 0 . -. 0, a N. 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E " c , 20U »- C 0 0 0 - o 0. 0ao0 = ca, ua 0. ; N C a 0 , d 0 0 0 . , Is i V or Tit 0 • hw\��\�y7,*• THE STATE Alaska Oil and Gas �w "t�� 9.4 Of Q T Q T Conservation Commission ' r`�sia� 1 1L1 lS]�`�1 1 i }£: �� 333 West Seventh Avenue l"r*'`'ley r. GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 __,..7.7.._ Main: 907.279.1433 OF ALAS�� Fax: 907.276.7542 www.aogcc.alaska.gov Luke Keller Drilling Engineer Hilcorp Alaska, LLC /f,,; 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 e kN Re: Milne Point Field, Kuparuk River Oil Pool, MPU B-30 ill A Hilcorp Alaska, LLC \ � l V °' Permit to Drill Number: 216-153 ,K Surface Location: 86' FSL, 4328' FEL, Sec. 18, T13N,R11E, UM, AK Bottomhole Location: 1395' FNL, 1744' FWL, Sec. 13, T13N, R10E, UM, AK Dear Mr. Keller: Enclosed is the approved application for permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B)and Regulation 20 AAC 25.071,composite curves for well logs run must be submitted to the AOGCC within 90 days after completion,suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition,the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20,Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, i )9-t,4 52 __ Cathy P Foerster Chair DATED this j 'y of December, 2016. RECEWED STATE OF ALASKA 41111/A OIL AND GAS CONSERVATION COMIN NOV 10 2016 PERMIT TO DRILL 20 AAC 25.005 AOGCG 1 a.Type of Work: lb.Proposed Well Class: Exploratory-Gas ❑ Service- WAG ❑ Service-Disp ❑ 1 c.Specify if well is proposed for: Drill El 'Lateral ❑ Stratigraphic Test ❑ Development-Oil 0 t Service- Winj ❑ Single Zone 2 ' Coalbed Gas ❑ Gas Hydrates ❑ Redrill❑ Reentry❑ Exploratory-Oil ❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket Q Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC Bond No. 022035244 MPU B-30 t 3.Address: 6.Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 MD: 9718.92' • TVD: 7,500' • Milne Point Unit ‘ 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Kuparuk Oil Pool - Surface: 86'FSL,4328'FEL,Sec 18,T13N,R11 E,UM,AK 1 (SHL)ADL047438/(TPH/BHL)ADL 047437 ' Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 1522'FNL, 1896'FWL,Sec 13,T13N,R10E,UM,AK N/A 2/28/2017 Total Depth: 9.Acres in Propertv: AIS 14.Distance to Nearest Property: 1395'FNL,1744'FWL,Sec 13,T13N,R10E,UM,AK r 4$'4 Acres '57 'j 8,657'to nearest unit boundary 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL(ft): 49.6✓ 15.Distance to Nearest Well Open Surface: x-571962 y- 6023208 Zone-4 ,( GL Elevation above MSL(ft): 23.1 ' to Same Pool: 1660'MPU B-19 16.Deviated wells: Kickoff depth: 326 feet • 17.Maximum Potential Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 43.75 degrees k Downhole: 3436 t Surface: 2741 k 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD ND MD ND (including stage data) 42" 20" 78.6# A-53 Weld 80' Surface Surface 80' 80' 50 bbls from Cement Truck Stg 1 L-1415ft3/T-240ft3 12-1/4" 9-5/8" 40# L-80 DWC/C 6,373' Surface Surface 6,373' 4,900' Stg 2 L-1846 ft3/T-314 ft3 8-1/2" 7" 26# L-80 DWC/C 9,718.92' Surface Surface 9,718.92' 7,500' 390 ft3 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth ND(ft): Plugs(measured): Effect.Depth MD(ft): Effect.Depth ND(ft): Junk(measured): Casing Length Size Cement Volume MD ND Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth ND(ft): 20. Attachments: Property Plat E BOP Sketch Q Drilling Program Q Time v.Depth Plot ❑✓ Shallow Hazard Analysis❑ Diverter Sketch E Seabed Report ❑ Drilling Fluid Program E 20 AAC 25.050 requirements❑Q 21. Verbal Approval: Commission Representative: Date 22.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Email Ikellerc hilcorp.com Printed Name Luke Keller Title Drilling Engineer Signature L�� 221t-- Phone 777-8395 Date I t ( `'0/2-D/�j Commission Use Only Permit to Drill API Number: Permit Approval , See cover letter for other CD Number: Q' /S� 50- 0 a7_ ons?/ '00-60 Date: ,a `G� Wn t 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: lif Other: L.1VCO , �4')t f / > t— Samples req'd: Yes ❑ No R( Mud log req'd:Yes❑ o V A.... ! i7 / H2S measures: Yes V-No❑ Directional svy req'd:Yes�NNo❑ +t /��`� /� .4_,��t� 1—b Spacing exception req'd: Yes❑ No R Inclination-only svy req'd:Yes❑ No Z /) e4---46--t&—./ L� , • Post initial injection MIT req'd:Yes❑ No❑ APPROVED BY 4 Approved by COMMISSIONER THE COMMISSION Date: `Z—''�h 446715° i- ^! t` / -f I Submit Form and Form 10-401(Revised 11/2015) This permit i1v lid rAn onths from the date of appy val(20 AAC 25.005(g)) Attachments in Duplicate t/ /4 /1 16 Luke Keller Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Anchorage,AK 99524-4027 Tel 907 777 8395 Email Ikeller@hilcorp.com Hilcorp Alaska,LLC 11/10/2016 Commissioner RECEIVED Alaska Oil &Gas Conservation Commission 333 W. 7th Avenue NOV 10 2016 Anchorage, Alaska 99501 AOGCC Re: MPB-30 Dear Commissioner, Enclosed for review and approval is the Permit to Drill for M7-30 well. MPU B-30 is a grassroots producer targeting the Kuparuk C sands to test undrilled fault block at B-19/D-02. The directional plan is a slant well with the kick off point at 326' MD/TVD. Maximum hole angle is 43.75 degrees. After penetrating the base of the Colville, hole angle will be reduced to 20 deg. TD will be just through the Kuparuk sands. Drilling operations are expected to commence approximately Feb 28th, 2017. The Hilcorp"Innovation"will be used to drill and complete the wellbore. If you have any questions, please don't hesitate to contact myself at 777-8395 or Paul Mazzolini at 777-8369. Sincerely, Luke Keller Drilling Engineer Hilcorp Alaska,LLC Page 1 of 1 • • Hilcorp Alaska, LLC Milne Point Unit (MPU) B-30 Drilling Program Version 1 Oct 27th, 2016 1111 • Milne Point Drilling Procedure Hilcorp Energy Company Contents 1.0 Well Summary 2 2.0 Management of Change Information 3 3.0 Tubular Program: 4 4.0 Drill Pipe Information: 4 5.0 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 13-5/8"5M Diverter System 10 12.0 Drill 12-1/4"Hole Section 12 13.0 Run 9-5/8"Surface Casing 17 14.0 Cement 9-5/8"Surface Casing 21 15.0 BOP N/U and Test 26 16.0 Drill 8-1/2"Hole Section 27 17.0 Run 7"Production Casing 31 18.0 Cement 7"Production Casing 33 19.0 Run Production Tubing. 35 20.0 Contingency String• 36 21.0 Wellbore with contingency 4-1/2"liner installed 37 22.0 Diverter Schematic 38 23.0 BOP Schematic 39 24.0 Wellhead Schematic 40 25.0 Days Vs Depth 41 26.0 Formation Description 42 27.0 Formation Tops 43 28.0 Anticipated Drilling Hazards 44 29.0 Innovation Rig Layout 47 30.0 FIT Procedure 48 31.0 Choke Manifold Schematic 49 32.0 Casing Design Information 50 33.0 8-1/2"Hole Section MASP 51 34.0 Spider Plot(NAD 27)(Governmental Sections) 52 35.0 Surface Plat(As Built)(NAD 27) 53 36.0 Offset MW vs TVD Chart 54 37.0 Drill Pipe Information 5" 19.5#S-135 DS-50 55 • • 111 Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 1.0 Well Summary Well MPU B-30 Pad Milne Point"B"Pad Planned Completion Type 3-1/2"gas lift Target Reservoir(s) Kuparuk Planned Well TD, MD/TVD 9,718.92' MD/7,500' TVD PBTD, MD/TVD 9,618' MD/7,406' TVD Surface Location(Governmental) 86' FSL, 4,328' FEL, Sec18, T13N, R11E,UM,AK Surface Location(NAD 27—Zone 4) X=571,962.88, Y=6,023,208.86 Surface Location(NAD 83) Top of Productive Horizon (Governmental) 1522'FNL, 1896'FWL, Sec 13,T13N,R10E,UM,AK TPH Location(NAD 27) X=567,659.99, Y=6,026,840.00 TPH Location(NAD 83) BHL(Governmental) 1395'FNL, 1744'FWL, Sec 13,T13N, R10E,UM,AK BHL(NAD 27) X=567,507.26, Y=6,026,965.66 BHL(NAD 83) AFE Number 1612657D AFE Drilling Days 20 Days AFE Completion Days AFE Drilling Amount $4,257,000 AFE Completion Amount $1,193,500 AFE Facility Amount $300,000 Maximum Anticipated Pressure (Surface) 2741 psi Maximum Anticipated Pressure (Downhole/Reservoir) 3436psi 5" 19.5# S-135 DS-50(Weatherford Rental) Work String 4" 14# S-135 HT-38(Weatherford Rental—Contingency) KB Elevation above MSL: 26.5 ft+23.1 ft=49.6 ft GL Elevation above MSL: 23.1 ft BOP Equipment 13-5/8"x 5M Annular, (3)ea 13-5/8"x 5M Rams Page 2 Version 1 Nov, 2016 z .,t Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 2.0 Management of Change Information Hilcorp Alaska, LLC Hilcorp PeggyChanges to Approved Permit to Drill Date: Subject: Changes to Approved Permit to Drill for MPU B-030 File#: B-030 Drilling and Completion Program Any modifications to 6-030 Drilling&Completion Program will be documented and approved below. Changes to an approved APD will be communicated to the AOGCC. Sec Page Date Procedure Change Approved Approved By By Approval Drilling Manager Date Prepared Drilling Engineer Date Page 3 Version 1 Nov, 2016 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 3.0 Tubular Program: Hole OD(in) ID (in) Drift Conn Wt Grade Conn Burst Collapse Tension Section (in) OD (in) (#/ft) (psi) (psi) (k-lbs) Cond 20" 19.25" - - 78.6 A-53 Weld 12-1/4" 9-5/8" 8.835" 8.75" 10.235" 40 L-80 DWC/C 5,750 3,090 916 8-1/2" 7" 6.276" 6.151" 7.875" 26 L-80 DWC/C 7,240 5,410 641 *6-1/8" 4.5" 3.920" 3.795" 4.93" 13.5# L-80 VAM 9,020 8,540 307 HTTC *Note: Contingency string highlighted in yellow. 4.0 Drill Pipe Information: Hole OD ID (in) TJ ID TJ OD Wt Grade Conn M/U M/U Tension Section (in) (in) (in) (#/ft) (Min) (Max) (k-lbs) Surface& 5" 4.276" 3.25" 6.625" 19.5 S-135 GPDS50 36,100 43,100 560k Intermediate *6-1/8" 4" 3.34" 2.5625" 4.875" 14 S-135 HT-38 12,200 17,700 649,200 *Note: Contingency drill pipe workstring highlighted in yellow 5.0 Casing Inspection All casing will be new, PSL 1 (100%mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Version 1 Nov, 2016 • ! Milne Point Unit B-30 Drilling Procedure Hilcorp En«sr Company 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 pmazzolini@hilcorp.com, lkeller@hilcorp.com and cdinger@hilcorp.com 6.3 Intranet Home Page Morning Update • Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 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 lkeller@hilcorp.com and cdinger@hilcorp.com 6.6 Casing and Cmt report • Send casing and cement report for each string of casing to lkeller@hilcorp.com and cdinger@hilcorp.com 6.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Paul Mazzolini 907.777.8369 907.317.1275 pmazzolini@hilcorp.com Drilling Engineer Luke Keller 907.777.8395 832.247.3785 lkeller@hilcorp.com Geologist Matt Brown 907.777.8448 713.458.8667 mbrown@hilcorp.com Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Coordinator Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 Version 1 Nov,2016 ,/ • •• Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 7.0 Planned Wellbore Schematic Orig.K BElev.:49.6'/aElev.:23.1' TREE&WELLHEAD r Tree Seaboard 2-9/16",5K a,j 'r' Seaboard 16 3/4"3M x 11"5M Muitibowl w/11"x 2-7/8"Tbg Hgr EUE 8rd 20 Wellhead Top and Bottom with 4"CIW"H"BPV profile.2ea 3/8"NPTcontrol lines.3- 1/2"WE x IBT X0 on pup. J` E R CASING DETAIL . Size Type Wt/Grade/Conn Drift ID top Btm i 20" Conductor 78.6/A-53/Weld - Surface 80' • 9 9-5/8" Surface 40/L-80/DWC/C 8.75" Surface 6,373' 7" Production 26/L-80/DWC/C 6.151" Surface 9,718.92' 9-5,,„ a 0; _ TUBING DETAIL 3-1/2" I Tubing I 9.3/L-80/EUE 8rd I 2.867 I Surf I 9,100' .. JEWELRY DETAIL {= TOO!4'D Item ID 1 1,000' 3.5"X Nipple Assembly,2.813"Packing Bore 2.813" 2 2,000' 3.5"GLM Dummy valve w 1"BK Latch 3-1/2"x 1"Pocket 2.962" 3 5,000' 3.5"GLM Dummy valve w 1"BK Latch 3-1/2"x 1"Pocket 2.962" 4 5 6 7,000' 3.5"GLM Dummy valve w 1"BK Latch 3-1/2"x 1"Pocket 2.962" 8,900' 3.5"GLM Dummy valve w 1"BK Latch 3-1/2"x 1"Pocket 2.962" 9,000' 3.5"Sliding Sleeve,X profile,2.813"seal bore 2.813" 7 9,050' 7"Halliburton PHL Packer 2.885" 8 9,070' 3.5"XN Nipple w/RHC ball catcher,2.750"No-Go,2.813" 2.992" Packing Bore 3 9 9,100' 3-1/2"Mule Shoe joint 2.992" I OPEN HOLE/CEMENT DETAIL Cond Cmt to surface 12-1/4"1st Stage 252 401s 10.7 ppg lead,43 bbls 15.8 ppg tail 12-1/4"2nd Stage 329 bbls 10.7 ppg lead,56 bbls 15.8 ppg tail 8-1/2" 69.5 bbls 15.8 ppg HaIfgm Est TOC @ 7.500 4 • WELL INCLINATION DETAIL KOP @ 326' Max Hole Angle=43.75 deg.f/1387' MD to 8665'MD z' PERFORATION DETAIL Sands Top(MD) Btm(MD) Top(TVD) Btrn(TVD) FT Size/SPF/Status ,_ _ Kup.C Sands 9,143' 9,200' 6,959' 7,012' t 7 is I', 8 `,w k e g t KUP C Sards w .fS r �' Ir TD=9,718.97(ND)/TD=7,50C7(TVD) PBTD=9,618'(ND)/PBTD=7,406'(TVD) Page 6 Version 1 Nov, 2016 • • 11 Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 8.0 Drilling / Completion Summary MPU B-30 is a grassroots producer targeting the Kuparuk C sands to test undrilled fault block at B-19/D-02. The directional plan is a slant well with the kick off point at 326' MD/TVD. Maximum hole angle is 43.75 degrees. After penetrating the base of the Colville,hole angle will be reduced to 20 deg. TD will be just through the Kuparuk sands. Drilling operations are expected to commence approximately Feb 28th, 2017. The Hilcorp Innovation will be used to drill and complete the wellbore. After reviewing the LWD logs obtained while drilling the well, and a stable production from the well, a determination will be made whether or not fracture stimulation will be required at a later date. In all likelihood, the well will be fracture stimulated. A CBL will be run on the 7" production casing in the event fracture stimulation is required at a later date. Surface casing will be run to 6,373' MD/4,900' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6— 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility located on`B"pad. General sequence of operations: 1. MOB Innovation to well site 2. N/U 13-5/8" Diverter and 16" diverter line. 3. Drill 12-1/4"hole to TD of surface hole section. Run and cmt 9-5/8" surface casing. 4. N/D diverter,N/U &test 13-5/8"x 5M BOP. 5. Drill 8-1/2"hole to TD. 6. Run and cmt 7"production casing. 7. Run gas lift completion. 8. N/D BOP,N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: / 1. Surface hole: No mud logging. On Site geologist. LWD: GR+Res 2. Production Hole: No mud logging. On site geologist. LWD: GR+Res + Den Neu 7 3. Cased Hole Logs: CBL over 7"production casing Page 7 Version 1 Nov, 2016 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy COY 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at(2)week intervals during the drilling and completion of MPU B-030. 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, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • There are no variance requests at this time. ✓ Page 8 Version 1 Nov, 2016 • • 11 Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 12-1/4" • 13-5/8"5M diverter w/16"diverter line Function Test Only • 13-5/8"x 5M Control Technology Inc Annular BOP • 13-5/8"x 5M Control Technology Inc Double Gate Initial Test:250/4000 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross w/3"x 5M side outlets 8-1/2" • 13-5/8"x 5M Control Technology Single ram • 3-1/8"x 5M Choke Line Subsequent Tests: • 3-1/8"x 5M Kill line 250/4000 • 3-1/8"x 5M Choke manifold (Annular 2500 psi) • Standpipe,floor valves,etc Primary closing unit: Control Technology Inc, 6 station, 20 bottle, 3000 psi, 220 gal EHPLC Primary & secondary closing hydraulics are provided by electrically driven triplex pumps. Emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email:jim.regg@alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-301-4533 /Email: guy.schwartz@alaska.gov / Victoria Loepp/Petroleum Engineer/(0): 907-793-1247/Email: Victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone: 907-793-1236(During normal Business Hours) Notification/Emergency Phone: 907-659-2714(Outside normal Business Hours) Page 9 Version 1 Nov,2016 S Milne Point Unit B-30 II Drilling Procedure Hilcorp Energy Company 10.0 R/U and Preparatory Work 10.1 A new insulated conductor has been set for B-030, the surface location is to the South of the existing well, B-06, and to the North of B-32. 10.2 Dig out and set impermeable cellar inside existing culvert. 10.3 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 10.4 Install Seaboard slip-on 13-5/8" 5M "A" section. Ensure to orient wellhead so that tree will line up with flowline later. 10.5 Insure (2) 3"threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. These will be used to take cement returns to the cellar during the surface cmt job, and also to wash out the diverter and hanger in preparation for running the pack-off. 10.6 Level pad and ensure enough room for layout of rig footprint and R/U. 10.7 MIRU Hilcorp Innovation. 10.8 Mud loggers WILL NOT be used on either hole section. 10.9 Mix spud mud for 12-1/4" surface hole section. Keep mud cool. 10.10 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 10.11 Keep 5" liners in mud pumps. • White Star 1300 HP Quatro mud pumps are rated at 4097 psi, 380 gpm @ 140 spm @ 90% mechanical efficiency& 100%volumetric efficiency. 11.0 N/U 13-5/8" 5M Diverter System 11.1 N/U 13-5/8" Control Technology 5M diverter System(Diverter Schematic at Sec 20 at back of program). • N/U 13-5/8" 5M diverter"T". J • Install 16" knife gate and 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. Page 10 Version 1 Nov, 2016 • ' Milne Point Unit B-30 Drilling Procedure Hilcorp any ComPanY 11.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 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. 11.5 Pad Drawin_ L # 1GO.n043'-41••• I 111101 / ■U //�i%j L4■ r % •! 1r," rlivarter I ins " ,/% Ft; I.-.��: — irl ra.._:{.,_:r ;— TIM; ■ L ��.•—+�� a' -?']q P r:du'Cer (1,FPPHI(i. P.LE 30 6u 17':, ICI r. ( IM FEET 1 1 it =6D tt. ; rJ■ I --. ■ Page 11 Version 1 Nov, 2016 0 • II Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 12.0 Drill 12-1/4" Hole Section 12.1 P/U 12-1/4" directional drilling assy: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub so that wireline orientation is possible if necessary. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 5" 19.5# S-135. • Run a solid float in the surface hole section. 12.2 12-1/4"BHA(GR+Res LWD and PWD planned in surface hole): COMPONENT DATA 41111111111110 Item OD ID Gauge Weight Top Length" Cumulative # Description Serial Number (in) (in) (in) (lbpf) Connection (n) Length 4n) 1 Hughes VMD-3 Tricone 7.750 3.125 12.250 134.63 P 6-518"REG 1.02 1.02 2 8 SperryDrill Lobe 4.+5-5.3 stg 8.000 5.000 121.08 B 6-518"REG 32.07 33.09 Stabilizer -__ 12.125 _ _ 3 8' Integral Blade Stab 8.000 3.250 10.750 143.03 B 6-518"REG 7.84 40.93 4 8'DM Collar(Directional) 8.010 3.500 147.40 B 6-5-'8"REG 9.22 50.15 5 8"DGR Collar(Gamma) 7.900 1.920 142.70 B 6-5,8"REG 6.93 57.08 6 8'EWR-P4 Collar(Resistivityi 7.920 2.000 151.00 B 6-518"REG 12.17 69.25 7 8"PWD Collar(Pressure) 7.940 1.920 143.40 B 6-5,8"REG 4.38 73.63 8 8"HCIM Collar(Processor) 7.950 1.920 149.90 B 6-518"REG 7.75 81.38 9 8"TM HOC(Telemetry) 8.050 3.500 145.20 B 6-5,8"REG 9.23 90.61 10 8"Flex Collar 7.670 2.813 136.28 B 6-518"REG 30.00 120.61 11 8"Flex Collar 7.670 2.813 ® 136.28 B 6-5.8"REG 30.05 150.66 12 8"Flex Collar 7.670 2.813 136.28 B 6-5'8"REG 29.97 180.63 13 8"Bottleneck X-Over Sub IIIIIIIIIIIIIIII 7.390 2.813 125.00 B 4-112"IF 1.83 182.46 14 6 jts 5"X 3"HWDP#49.3-4.51 F 5.000 3.000 49.30 187.39 369.85 15 6 1 4"Weatherford Combo Jar 6.260 2.313 90.58 B 4-112"IF 30.39 400.24 Ei 11 jts 5'X 3"HWDP#49.3-4.51F 5.000 3.000 49.30 342.10 742.34 ; ,.„.e 742.34 Page 12 Version 1 Nov, 2016 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 12.3 Primary Bit: 12 1/4" (311.2mm) Assembly: A09591 '.s` 16 'a Raider IADC Code: 3323 :.,.,,i-R l E.' PRODUCT SPECIFICATIONS o 0 100* Cutter Size: 16 mm a < Cutter Back Up: Carbide Shock Studs se Total Cutter Count: 53 Face Cutter Count: 47 Connection: 65/Er API Regular Nozzle 1 Qty/Type: 9-Series 65 Nozzle 2 Qty/Type: - Junk Slot Area: 29.1in2(187.7cm2) J", Gage Pad Length: 6"(152mm) w 41 Make Up Length: 12.5"(316.2mm) *41,�, ''"`.� Shank Diameter: 7.6"(193mm) ,•• ;�,, ',V, � OPERATING PARAMETERS* cl i• r h Rotary Speed: For all rotary and motor applications Flowrate Min-Max: 300-900GPM(1.14-3.41m3/min) Max Weight On Bit: 36,0001bs(16014daN) Makeup Torque: "O28,icalfor000-32 "Operating (37963-43386Nm) perating parameters shownhorn are typthe hti typspecified. For rer_omrnendatiorrs on your speck applicatron.contact your Varei International representafise_ Bit Features H -Increased number of nozzles for improved bit cleaning. X -Shock studs limit drill bit vibration and increase stability allowing smooth cutting action increasing cutter life and overall bit performance. 12.4 5" Workstring, HWDP, and Jars will come from Weatherford. 12.5 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. 12.6 Drill 12-1/4"hole section to TD per the geologist and drilling engineer. • 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. Page 13 Version 1 Nov,2016 • • II Milne Point Unit B-30 Drilling Procedure Hilcorp Energy cry • 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 700-800 gpm. Ensure shaker screens are set up to handle this flowrate. • Keep swab and surge pressures low when tripping. • Make wiper trips if necessary. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. • Ensure TD of the hole section will cover up the Schrader Bluff sands + 100' MD. • Take MWD surveys every stand drilled (95' intervals). • Be prepared for GAS HYDRATES below the base of the permafrost (2,185' TVD) and as deep as 3500' TVD. Previous wells have experienced hydrates on"B"pad at these depths. 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 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. • 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. / Page 14 Version 1 Nov, 2016 • S Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 12.7 12-1/4"hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system(1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. • PVT System: An electronic 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. • Hydrates: Hydrates have been encountered on previous "B" Pad wells drilled to date. At 2185' TVD and again at 3500' TVD. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBsBAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 —9.0 range with caustic soda. Daily additions of ALDACIDE G/X-CIDE 207 MUST be made to control bacterial action. • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP <20 (check with the cementers to see what YP value they have targeted). System Type: 8.8—9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL Temp pH Surface 8.8-9.5 75-175 20-40 25-45 <10 < 70°F 8.5-9.0 Page 15 Version 1 Nov, 2016 • • Milne Point Unit B-30 14 Drilling Procedure Hilcorp Energy Company System Formulation: Gel + FW spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 -20 ppb caustic soda 0.1 ppb(8.5—9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8—9.5 ppg PAC-L/DEXTRID LT if required for<10 FL ALDACIDE G 0.1 ppb 12.8 At TD; pump sweeps, CBU, and pull a wiper trip back to the 20" conductor shoe. 12.9 Should backreaming be necessary to get out of the hole: • Prior to initiating backreaming, ensure at least 3 —4 B/U have been circulated to get hole as clean as possible. • Pump at full drill rate (600—700 gpm), and maximize rotation. • Pull slowly, 5 — 10 ft/minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 12.10 TOH with the drilling assy, handle BHA as appropriate. 12.11 No open hole logging program planned. Page 16 Version 1 Nov,2016 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 13.0 Run 9-5/8" Surface Casing 13.1 R/U and pull wear bushing. 13.2 R/U Weatherford 9-5/8" casing running equipment. • Ensure 9-5/8"DWC/C x DS50 XO on rig floor and M/U to FOSV. • Use "BOL 2000"thread compound. Dope pin end only w/paint brush. • Consider R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. 13.3 P/U shoe joint, visually verify no debris inside joint. 13.4 Continue M/U &thread locking shoe track assy consisting of: • (1) Shoe joint w/float shoe bucked on (thread locked). Install (2) centralizers on shoe joint over stop collars 10' from each end. • (1) Joint with float collar bucked on pin end& thread locked. Install (1) centralizer mid tube over a stop collar. • Ensure bypass baffle is correctly installed on top of float collar. Bypass Baffle This end up. /4115 OtionAki • (1) Joint with Halliburton bypass baffle adapter bucked on pin&threadlocked. Install (1) centralizer mid tube over a stop collar. • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 17 Version 1 Nov, 2016 0 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 13.5 Float equipment and Stage tool equipment drawings: "A - Overall Length Type H ES Cementer B Part No. Min.ID After Ori lout V. SO No. C Max.Tool OD J 0 'I D — Hileorp ES-II Running Order A E F Closing Sleeve Opening Seat ID ! No.Shear Pins E Closing Seat ID I13 . Opening Sleeve C _ No.Shear Pins Rug Set IES-H Cementer ES Cementer Part No. ..t-B-; Depth .24004 SONo. / f Plug I- i I l'il Baffle Adapter(if used) OD Shut Off Plug _l l - I D Opening Plug Depth OD Baffle Adapter OD III 1"'""` Bypass or Shut-off Baffle 4 ID _._ By-Pass Plug Depth 0Shut-off Plug ✓ —Float Collar Depth By Pass Baffle I OD Float Collar tt Float Shoe fitj. Depth y Bypass Plug 11111 (f used) T Hole TD T Float Shoe "Reference Cas,nglel OD Sales Manual Section 5 Page 18 Version 1 Nov, 2016 i • Milne Point Unit B-30 Drilling Procedure Hilcorp Enemy Company 13.6 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Install (1) centralizer every other joint for the first 15 joints. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values required to achieve this position. Estimated torque to reach base of triangle: 10,750 ft-lbs. • After making up several connections, use the torque required to M/U to base of triangle as the M/U torque and continue running string. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cmt returns to surface. 13.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at 2400' MD/2030' TVD. This will position the stage collar comfortably below the permafrost. • Install centralizers over couplings on 3 joints below and above stage tool. • Do not place tongs on ES cementer,this can cause damage to the tool. • Ensure tool is pinned with 6 opening shear pins. There are 6 holes,the tool is normally sent with only 4 pins installed. This will allow the tool to open at 3300 psi. 9-5/8" 40#L-80 DWC/C Make Up Torques: Casing OD Min M/U Torque Max M/U Torque 9-5/8" 29,800 ft-lbs 34,800 ft-lbs 13.8 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 13.9 Slow in and out of slips. 13.10 Make sure a coupling is not across the wellhead once casing is on bottom. 13.11 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. Page 19 Version 1 Nov, 2016 S Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company Technical Specifications Connection Type: Size(O.D.): Weight(Wail): Grade: DWC/C Casing 9-5/8 in 40.00 Ib/ft(0.395 in) L-80 standard Material L-80 Grade "VAPIX 80.000 Minimum Yield Strength (psi) BA 95.000 Minimum Ultimate Strength (psi) VAM USA 4424 W.Sam Houston Pkwy.Suite 150 Pipe Dimensions Houston,TX 77041 9.625 Nominal Pipe Body O.D. (in) Fe:713-179-3234713-479-3200 13 -4 g 3234c0 8.835 Nominal Pipe Body I.D.(in) E-mail:VAMUSAsalesavam-usa_com 0.395 Nominal Wall Thickness (in) 40.00 Nominal Weight (lbs/ft) 38.97 Plain End Weight(lbs./ft) 11.454 Nominal Pipe Body Area (sq in) Pipe Body Performance Properties 916.000 Minimum Pipe Body Yield Strength (ibs) 3.090 Minimum Collapse Pressure (psi) 5.750 Minimum internal Yield Pressure (psi) 5,300 Hydrostatic Test Pressure (psi) Connection Dimensions 10.625 Connection O.D. (in) 8.835 Connection I.D. (in) 8.750 Connection Drift Diameter(in) 4.81 Make-up Loss (in) 11.454 Critical Area (sq in) 100.0 Joint Efficiency (%o) Connection Performance Properties _ 916,000 Joint Strength (lbs) 16.360 Reference String Length (ft) 1.4 Design Factor 947,000 API Joint Strength (lbs) 916,000 Structural Compression Rating (lbs) 3,090 API Collapse Pressure Rating (psi) 5.750 API Internal Pressure Resistance (psi) 19.0 Maximum Uniaxial Bend Rating [degrees/100 ft] Appoxlmated Field End Torque Values 29,800 Minimum Final Torque (ft-lbs) 34,800 Maximum Final Torque(ft-lbs) 39.800 Connection Yield Torque (ft-lbs) Page 20 Version 1 Nov, 2016 1111 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 14.0 Cement 9-5/8" Surface Casing 14.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud& water can be delivered to the cmt unit at acceptable rates. • How to handle cmt returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cmt operation. • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all iron 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 cmt pump or treating iron will not be pumped downhole. 14.4 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 14.5 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 14.6 Pump remaining 55 bbls 10.5 ppg tuned spacer. 14.7 Drop bottom plug(flexible bypass plug). Mix and pump cmt per below calculations for the 1st stage. 14.8 Cement volume based on annular volume+ 30% open hole excess. Job will consist of lead& tail, TOC brought to stage tool. Z`t°a c,I- S\-- Estimated Total Cement Volume: Section: Calculation: Vol(BBLS) Vol(ft3) 12-1/4" OH x 9-5/8" Casing (5873'- 2400') x .0558 bpf x 1.3 = 252 bbls 1415 ft3 annulus: Total LEAD: 252 bbls 1415 ft3 3Z1 5 12-1/4" OH x 9-5/8" Casing (6373'- 5873') x .0558 bpf x 1.3 = 36 202 annulus: 9-5/8" Shoe track: 90 x .0758 bpf = 6.8 38 Total TAIL: 43 bbls 240 ft3 zoo Page 21 Version 1 Nov,2016 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company Cement Slurry Design (both 1st and 2"1 stage cement jobs): Lead Slurry Tail Slurry System ArcticCEM TM System SwiftCEM TM System Density 10.7 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed Water 21.13 gal/sk 5.04 gal/sk 14.9 Attempt to reciprocate/rotate casing during cement pumping if hole conditions allow. 14.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits. 14.11 Ensure rig pump is used to displace cmt. To operate the stage tool hydraulically,the plug must be bumped. 14.12 Displacement calculation: 6273' x .0758 bpf=475.5 bbls total (253.5 bbl mud+ 80 bbl water+ 142 bbl mud) The 80 bbls of water must be left across stage tool to ensure proper operation once opened. 14.13 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Overdisplace by no more than 10 bbls before consulting with drilling engineer. 14.15 If plug is not bumped consult with drilling engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 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. 14.17 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface. Circulate until YP <20 again in preparation for the 2nd stage of the cement job. Page 22 Version 1 Nov, 2016 S • 11 Milne Point Unit B-30 Drilling Procedure Hilcorp Emgy Company NNW 14.18 Be prepared for cement returns to surface. Dump cmt returns in the cellar or open the shaker bypass line to the cuttings tank. Have sacks of sugar available and vac trucks ready to assist. Ensure to flush out any rig components used to route cmt. Page 23 Version 1 Nov, 2016 • S Milne Point Unit B-30 Drilling Procedure Hilcorp Second Stage: 14.19 Prepare for the 2nd stage as necessary. Hold another pre job meeting if crew change has occurred. 14.20 Load ES cementer closing plug in cmt head/ 14.21 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 14.22 Pump remaining 55 bbls 10.5 ppg tuned spacer. 14.23 Mix and pump cmt per below recipe for the 2nd stage. 14.24 Cement volume based on annular volume +200% open hole excess. Job will consist of lead& tail, TOC brought to surface. However cmt will continue to be pumped until clean spacer is observed at surface. Estimated Total Cement Volume: a~ SA ' Section: Calculation: Vol(BBLS) Vol(ft3) 20" Conductor x 9-5/8" (106.5') x .27 bpf x 1 = 29 bbls 163 ft3 casing annulus: 12-1/4" OH x 9-5/8" Casing (1900'- 110')x .0558 bpf x 3 = 300 bbls 1683 ft3 annulus: Total LEAD: 329 bbls 1846 ft3 z`i 12-1/4" OH x 9-5/8" Casing (2400'- 1900') x .0558 bpf x 2 = 56 314 ft3 annulus: Total TAIL: 56 bbls 314 ft3 270 5x. 14.25 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 14.26 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 14.27 Displacement calculation: 4/, 2400' x .0758 bpf= 182 bbls mud 14.28 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. Page 24 Version 1 Nov, 2016 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 14.29 Decide ahead of time what will be done with cmt returns once they are at surface. We should get back approx. 150 bbls of cmt slurry. 14.30 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. Back out and L/D landing joint. Flush out wellhead with FW. 14.31 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 14.32 Lay down landing joint and pack-off running tool. Ensure to report the following on WellEz: • Pre flush type, volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume,whether plug bumped&bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface&volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As-Run" casing tally & casing and cement report to lkeller@hilcorp.corn and cdinger(&,hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 25 Version 1 Nov,2016 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 15.0 BOP N/U and Test 15.1 N/D the diverter"T" &N/U 11" 5M tubing spool. 15.2 N/U 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" Single gate • Double ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should be dressed with 5" Fixed rams • N/U bell nipple, install flowline. • Install (1) manual valve & (1) HCR valve on kill side of mud cross. (manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 15.3 Run 5"BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/4000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. • We will need to test on the following sizes: 5" (for 5" DP workstring) 15.4 R/D BOP test assy. 15.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 15.6 Mix 10.0 ppg Baradrill-N fluid for production hole. 15.7 Set 10" ID wearbushing in wellhead. 15.8 Rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 15.9 Keep 5" liners in mud pumps. Page 26 Version 1 Nov, 2016 • • 11 Milne Point Unit B-30 Drilling Procedure Hilco r Energy Caq 16.0 Drill 8-1/2" Hole Section 16.1 P/U 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 5" 19.5# S-135. • Install ported float in the BHA. / 16.2 8-1/2" Mud Motor Directional Assy(Includes triple combo LWD, PWD): COMPONENT DATA Item` OD ID Gauge Weight Top Length Cumulative Description Serial Number Connection # tint tins (in) (Ibp1) (ft) Length (i1) 1 HDBS MM65 PDC 7.620 3.250 8.500 127.15 P 4-V2"REG 0.90 0.90 2 T SperryDrill Lobe 7/8-6.0 stg 7.000 4.952 93.13 B 4-112"IF 26.51 27.41 Stabilizer 8.375 3 Integral Blade Stabiiizer 6.750 2.810 8.250 100.82 B 4-112"IF 6.95 34.36 4 6-14"DM Collar(Directional; 6.740 3.125 103.40 B 4-112"IF 9.20 43.56 5 6-314"DGR(Gamma' 6.740 1.920 ® 97.80 B 4-112"IF 6.29 49.85 6 6 314"EWR-P4 Collar(Resistivity( 6-750 2.000 104.30 B 4-112"IF 11.97 61.82 7 6-14"PWD (Pressure; 6.700 1.920 ® 96.30 B 4-1.2"IF 4.43 66.25 8 6 314"HCIM Collar(Processor) 6.750 1.920 101.70 B 4-112"IF 6.84 73.09 9 6-314"TM Collar(Telemetry) 6.760 3.250 103.60 B 4-12"IF 10.38 83.47 10 6 314"Float Sub 6.750 2.810 100.82 B 4-112"IF 3.00 86.47 11 NMDC 6.900 2.875 105.31 B 4-12"IF 31.00 117.47 12 NMDC 6.900 2.875 105.31 B 4-1.2"IF 30.84 148.31 13 NMDC 6.900 2.875 105.31 B 4-1 2"IF 31.09 179.40 14 3jt x 5"X 3"HWDP#49.3-4.5IF 5.000 3.000 49-30 93.45 272.85 15 Weatherford 6 114"Combo Jar 6.260 2.313 90.57 B 4-1 2"IF 30.39 303.24 16 5it x 5 X 3'HWDP#49.3-4.5IF 5.000 3.000 49.30 155.46 458.70 '' 458.7 Page 27 Version 1 Nov, 2016 11110 • 11 Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 16.3 Primary Bit: KeY ell norlogie Design Specifications Make up Length(ft): .92 " :f ;r Shank Bore(ins): 2.300 r ,r ` Shank Diarn(ins): 6.400 4t$ Connection std: Y ° r Connection Size(ins): 4.500 " >4 - os Connection Type: Api Reg Pin 11 ' ' a ' Make up Torque(ft-lbs): 20000 IADC Code: M422 Diameter:(ins) 8 '!z" Body Material: Matrix HDK JSA .440 8 '/2" SK616M-J1 D Face'Volume:(in') 78® .6 Design Features of this bit Normalised Face ml: 53.26% Seeker"'Directional Drill Bits Seeker"'directional drill bits are designed to overcome directional drilling challenges for both motor or RSS tools in a wide range of directional applications. Blade Qty: 6 s Specialized cutter technology Gauge Length:(ins) 4.000 Helios"''Inferno"'Cutter okx�y engineered for specific applications that may require increased thermal resistance,increased abrasion resistance or increased toughness. Gauge Geometry: Spiral-Trailing Each Helios'"Infemo"'cutter has a unique cutter index value indicating performance characteristics. Gauge Profile: SmoothSteer Smooth-Torque"'Torque Control Components-Smoa1hTorque""torque control components are Gauge Protection: TSP Tiled inserts placed between primary cutters to provide a predictable torque response to applied weight-on-bit and reduction in torque variance. Bit Profile: short Taper-Shegow cone SmoothSteer'"Gauges-SmoothSteerl"gauges deliver maximum gauge contact.lowering resistance to steer by reducing torque.and leading to improved ROP and extended bit and tool life. Recommended Operating TSP Gauge Protection-Thermally stable product(TSP)tiles and welded hardmetal gauge Parameters protection give both a highly durable and ultra-smooth gauge. Max Operating WOB(klbs):38 Spiral Gauge-Stability is improved by increasing the circumferential contact of the bit gauge. Min TFA(in2): 0.2946 Improved stability enhances steerability and ROP. Max TFA(in2): 2.2272 Max Flow(gpm): 934 This bitrunit can accommodate BlackBox"°HD dnlling recorder. HSI: 2-7 This bodied PDC bit features computer aided cutter placement and hydraulics optimized by nozzle location to deliver high performance and longer bit life. Bit Breaker Thick 1 W' In some appYcaeo,m Ulm ria As run...rasa*,beyond Mese parameters.Contact your NOV ReadNimabg RepecsdnfoMm ser recommended oPereeMIT parameters in your appecabon.NOV ReeoNyrabg reserves Ute riphr Jo rends."geese specettcabms.based on advances and mgxpmments er technology. This report is sa'-id for 30 day from O2-Sep-2015 Cutting Structure Nozzles&Ports Type Oty-_.- Location Diameter Shape git. Vitillt$31KIM1101WW7a1,73j11, Primary 31 FACE 16 mm CYLINDER 6 TNZ VARIABLE Primary 12 GAGE 13 mm CYLINDER Primary 6 BACK-ANGLE 13 mm CYLINDER TCC 6 FACE 11 mm DOME TOPPED Page 28 Version 1 Nov, 2016 • Milne Point Unit B-30 111 Drilling Procedure Hilcorp Enema,Company 16.4 8-1/2"hole section 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. • 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. • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Electronic PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 10.0— 10.5 ppg 3%KC1 Inhibited LSND fluid system Properties:_ Section / Density Plastic Viscosity Yield Point LGS MBT HPHT pH Production 10.0- 10-20 15-25 <6% <15 <11.0 9-10 10.5 pp System Formulation: Baradrill-N Product Concentration Water 0.94 bbl KCL 22 ppb Barazan D Plus 1.25 ppb(as req'd for YP) PAC L 1.0 ppb Dextrid LT 3.0 ppb Barotrol Plus 5.0 ppb BDF-515 4.0 ppb Caustic Soda 0.2 ppb Baroid 41 As req'd for MW Aldacide G 0.25 ppb 16.5 TIH w/ 8-1/2" directional assy to stage tool. 16.6 Note depth TOC tagged on AM report. Drill out stage tool as follows:v/ • Do not exceed 75 rev/min rotation speed. A good range is 40 to 75 rpm. • Drilling with minimal WOB is recommended. Approx 2-5 k is enough. • Apply weight and allow it to drill off before applying more. Page 29 Version 1 Nov, 2016 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company lf " • After drilling out, chase any remaining debris to bottom with the drill bit. I$ 16.7 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 16.8 R/U and test casing to 2700 psi/30 min. ,Ensure to record volume/pressure and plot on FIT graph. AOGCC reg is 50% of burst= 5210/2 =—2605 psi. Test pressure for the well is 2700 psi. 16.9 Drill out shoe track and 20' of new formation. 9-'joo /. .� (IZ s- -I°. 14- 16.10 16.10 CBU and condition mud for FIT. 0 16.11 Conduct FIT to 12.5 ppg EMW. _ 16.12 Drill 8-1/2" hole section to section TD per Geologist and Drilling Engineer. • Pump at 550-650 gpm. • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Pump water or other low vis sweeps to aid in hole cleaning. • Keep swab and surge pressures low when tripping. • Make wiper trips if necessary. • Take MWD surveys every stand drld. Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. of 16.13 At TD; pump low vis sweeps,CCBU at least 3 times at maximum circulation and rotation, and pull a wiper trip back to the 10--374" shoe. If backreaming is necessary: • Circulate at full drill rate (550—650 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. 16.14 TOH with the drilling assy, L/D BHA and DP on TOH. 16.15 No open hole wire line logs are planned for the production hole section. Page 30 Version 1 Nov, 2016 • • 14 Milne Point Unit B-30 Drilling Procedure Hilcorp Enemy Company 17.0 Run 7" Production Casing 17.1 R/U 7" casing running equipment. • Ensure 7"DWC x NC-50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor& model info. • R/U CRT if available. 17.2 M/U &threadlock shoe track assy consisting of: • (1)Float shoe joint w/float shoe bucked on. Float shoe should have (1) solid body centralizer installed, free floating. • (1) Baker locked joint. BL joint should have (1) solid body centralizer installed, free floating. • (1) Float collar joint. FC joint should have (1) solid body centralizer installed, free floating. • Ensure proper operation of float shoe and float collar. 17.3 Run 7"26# L-80 DWC/C 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 over couplings on every joint to 9,000' MD. No centralizers required above that. 17.4 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 17.5 Slow in and out of slips. 17.6 P/U landing joint and M/U to string. Position the shoe as close to TD as possible. 17.7 Plan is to use E-slips as primary landing mechanism. 17.8 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. 7" DWC Estimated M/U torques Casing OD Min M/U Torque Max M/U Torque 7" 18,300 ft-lbs 21,100 ft-lbs Page 31 Version 1 Nov, 2016 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company Connection Type: Size(O.D.): Weight(Wall): Grade: DWC/C Casing 7 in 26.00 lb/ft(0.362,n) L-80 2012 API SPEC 5CT CCUPi.NG 0.D Material L-80 Grade 80,000 Minimum Yield Strength(psi.) 95,000 Minimum Ultimate Strength(psi.) u SA Pipe Dimensions VAM USA 7 000 Nominal Pipe Body O.D. (in.) 4424 W Sam Houston Pkwy.Suite 150 6.276 Nominal Pipe Body I D. (in) Houston.iia-4ias200 0.362 Nominal Wall Thickness(in) Fax 713-479-3234 26-00 Nominal Weight(lbs./ft} Email:VAMUSAsalescL2vam-asa.corn 25.69 Plain End Weight(lbs./ft.) 7.549 Nominal Pipe Body Area(sq. in.) Pipe Body Performance Properties 604,000 Minimum Pipe Body Yield Strength(lbs) «� r 5,410 Minimum Collapse Pressure(psi.) 7,240 Minimum Internal Yield Pressure(psi) 6,600 Hydrostatic Test Pressure(psi ) Connection Dimensions r' 7.875 Connection O.D. (in.) 6.276 Connection I.D. (in) 6 151 Connection Drift Diameter(in.) 4.50 Make-up Loss(in.) 7.549 Critical Area(so. in) 100.0 Joint Efficiency(%) ;, Connection Performance Properties 604,000 Joint Strength(lbs.) 16,590 Reference String Length(ft) 1.4 Design Factor 641,000 API Joint Strength (lbs) 302,000 Compression Rating(lbs.) 5,410 API Collapse Pressure Rating(psi.) 7,240 API Internal Pressure Resistance(psi.) 26.2 Maximum Uniaxial Bend Rating[degrees/100 ft] Approximated Field End Torque Values I` 18.300 Minimum Final Torque(ft.-lbs) 21,100 Maximum Final Torque(ft-lbs.) 23.800 Connection Yield Torque(ft.-lbs.) For detailed information on performance properties,refer to DWC Connection Data Notes on following page's). Page 32 Version 1 Nov, 2016 • Milne Point Unit B-30 14 Drilling Procedure Hilcorp Energy CningenY 18.0 Cement 7" Production Casing 18.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 18.2 R/U cmt head(if not already done so). Ensure top and bottom plugs are loaded correctly. 18.3 Pump 5 bbls 13.5 ppg spacer. Close low torque on plug dropping head,test surface cmt lines to 4000 psi. 18.4 Pump remaining 35 bbls 13.5 ppg spacer. 18.5 Drop bottom plug, Mix and pump slurry per below calculations: Section: Calculation: Vol(BBLS) Vol(ft3) LEAD: 8-1/2" OH x 7" csg: No Lead Total Lead: TAIL: -re{ 8-1/2" OH x 7" csg: (9,719' -7,500')x .023 bpf x 1.3 = 66 bbls 370.5 ft3 ✓- TAIL: 7" Shoe Track: 90' x .0383 bpf= 3.5 bbls 19.7 ft3 Total Tail: 69.5 bbls 390 ft3 Tail Slurry -+t—I System HaICEM TM System Density 15.8 lb/gal Yield 1.156 ft3/sk Mixed 4.97 gal/sk Water Page 33 Version 1 Nov, 2016 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 18.7 After pumping cement, drop top plug and displace cement with completion fluid. If it is not feasible to do this, use mud and a clean out trip will be made later. Use rig pumps for displacement. Ensure to have a good baseline measurement for pump displacement ahead of time. Displacement calcs: • 10,400' x .0383 bpf= 398 bbls. 18.8 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 18.9 Do not overdisplace by more than %2 shoe track volume. Total volume in shoe track is 3.5 bbls 1cty, 18.10 There should be no cmt returns to surface. TOC is planned to be atiliaCr MD. 18.11 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. • If this is the case, monitor the pressure on the casing and do not let it exceed 500 psi over the final pump pressure. Ensure to report the following on wellez: • Pre flush type,volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing,bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped&bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface&volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Send final "As-Run" casing tally & casing and cement report to lkeller@,hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 18.12 R/D cement equipment. Flush out wellhead with FW. 18.13 Break and lift BOP, set slips and make rough cut on casing. Test slips to 3000 psi/15 min. 18.14 Lay down cut joint joint. Page 34 Version 1 Nov, 2016 S Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 19.0 Run Production Tubing. -ice 19.1 Run a CBL across the Kuparuk interval and determine TOC near$6(f' MD. 19.2 R/U and run gas lift assy with GLM and XN profile on 3-1/2"EUE-8rd L-80 tubing as per completion engineer. • Ensure appropriate well control crossovers on rig floor and ready. • Monitor displacement from wellbore while RIH. • Final set depth of the production packer will be determined after receiving the final directional survey. 19.3 Land tubing hanger. RILDS. LD landing joint. Note PU/SO weights on tubing tally. Test hanger. 19.4 Circulate freeze protect down IA and allow freeze protect to U-tube down tubing. i ��_ < i A- 19.5 Bullhead diesel (or dead crude) freeze protection down 9-5/8"x 7" annulus—(80 bbls). Leave well shut in, do not allow flowback to occur. 19.6 Install BPV and N/D BOP. 19.7 N/U tree adapter and tree. Conduct pressure tests of same to 500 psi low/4000 psi high. 19.8 Shut in well. e� Ozrl) cu cc w � I`� u.c/t�-sem den- /`-1^ J Page 35 Version 1 Nov,2016 • Milne Point Unit B-30 Drilling Procedure Hilcorp Enorgy Company 20.0 Contingency String: 20.1 Excessive MW may be required to stabilize the well after opening up the Kalubik and/or Kuparuk shales, they could be charged up from offset injectors in the area even though this well is in a different fault block from the bulk of the injection in the area. 20.2 If minimal or no ballooning is observed when bringing on/ shutting off mud pumps, consult with Anchorage drill team and determine feasibility of drilling ahead with planned well design. 20.3 If it is not feasible to drill ahead, set the 7" casing through the Kalubik and/or Kuparuk shale. 20.4 Adjust cement program so that TOC is 7,500' MD, with 7" shoe +/- 9,000' MD. 20.5 After bumping the plug, pressure up to 3500 psi and test casing for 30 min. Record volume pumped and volume bled back, note in wellez report. 20.6 R/D cmt equipment, install and test packoff, bullhead freeze protect down annulus. 20.7 Install 2-7/8"x 5" VBR rams in both upper and lower BOP cavities. TEST BOP to 4000 psi/5 min. Annular to 2500 psi/5 min. 20.8 P/U 6-1/8" directional drilling assy, drill out float equipment and 20' new formation. Circ B/U and conduct FIT to 14 ppg EMW. 20.9 Drill 6-1/8"hole section to well TD. 20.10 Run and cmt 4-1/2"production liner. Cement coverage will be from liner shoe to TOL. 20.11 Well completion will remain the same. A proposed well schematic is shown on the next page. Page 36 Version 1 Nov, 2016 • Milne Point Unit B-30 II Drilling Procedure Hilcorp Energy Company 21.0 Wellbore with contingency 4-1/2" liner installed Orig.KBElev.:49.6'/CiElev.:23.1' TREE&WELLHEAD Tree Seaboard 2-9/16",5K Seaboard 16 3/4"3M x 11"5M Multibpwl will"x 2-7/8"Tbg Hgr EUE 8rd 20' • Wellhead Top and Bottom with 4"CIW"H"BPV profile.2ea 3/8"NPT control lines.3- 1/2"EUE x IBT XO on pup. " CASING DETAIL d Size type Wt/Grade/Conn Drift ID Top Btm 20" Conductor 78.6/A-53/Weld - Surface 80' 9-5/8" Surface 40/L-80/DWC/C 8.75" Surface 6,373' t 7" Production 26/L-80/DWC/C 6.151" Surface 9,000' Y"E a 4-1/2" Production 13.5/L-80/HTTC 3.75" 8,800' 7,718.92' 1 TUBING DETAIL 3-1/2" I Tubing I 9.3/L-80/EUE 8rd 1 2.867 I Surf I 9,100' i. 2 JEWELRY DETAIL No. foo t,'D Item ID 1 1,000' 3.5"X Nipple Assembly,2.813" Packing Bore 2.813" 2 2,000' 3.5"GLM Dummy valve w 1"BK Latch 3-1/2"x 1"Pocket 2.962" TC�Q 3 5,000' 35"GIM Dummy valve w 1"BK latch 3-1/2"x 1"Pocket 2.962" Est 7.500 4 7,000' 3.5"GLM Dummy valve w 1"BK Latch 3-1/2"x 1"Pocket 2.962" 0 _„� 5 8,400' 3.5"GIM Dummy valve w 1"BK latch 3-1/2"xl"Pocket 2.962" 6 8,500' 3.5"Sliding Sleeve,X profile,2.813"seal bore 2.813" 7 8,550' 7"Halliburton PHL Packer 2.885" 3.5"XN Nipple w/RHC ball catcher,2.750"No-Go,2.813" 8 8,570' 2.992" Packing Bore 9 8,600' 3-1/2"Mule Shoe Joint 2.992" 10 8,800 4-1/2"x 7"ZXP Hanger/liner top packer 3.75" OPEN HOLE/CEMENT DETAIL Cond Cmt to surface V 12-1/4"1st Stage 252 bbls 10.7 ppg lead,43 bbls 15.8 ppg tail 12-1/4"2nd Stage 329 bbls 10.7 ppg lead,56 bbls 15.8 ppg tail 8-1/2" 69.5 bbls 15.8 ppg HalCem .I 0 WELL INCLINATION DETAIL KOP@326' 'I Max Hole Angle=43.75 deg.f/1387'MD to 8665'MD 22,; +:' 8 `' PERFORATION DETAIL 9 Sands Top(MD) Btm(MD) Top(TVD) Btm_(TVD) FT Size/SPF/Status 7" isI 10 Kup.C Sands 9,143' 9,200' 6,959' 7,012' RlJP C Sant. ry t ' ' 41/2" TD=9,718.92'(ND)/TD=7,500'(ND) PBTD=9,618'(ND)/PBTD=7,406'(TV)) Page 37 Version 1 Nov, 2016 • • Et Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 22.0 Diverter Schematic turitim 1frITI1 m14iI1 -----`'----13-5/8"5M Control Technology Annular BOP ;;; (� iII u.�L. si ED ll JIA rttc " –'�--13-5/8"5M Control << > Technology Double Ram • kb--- 3-1/8" Kill Line �`%r �� •1\`r' ti ~� " " —� ----''-----3-1/8"Choke Line 1 NI ID ED o -- e I lo 13-5/8" 5M Control—" Technology Single Ram ri to 13-5/8"x 5M €--14 F € A € € A € e y € -------------16"Diverter Line ia, j 13-5/8"x 5M 4: r r l�[(r 1 \-2-1/16"x 5M 20"Casing Page 38 Version 1 Nov, 2016 • • 111 Milne Point Unit B-30 Drilling Procedure Hilcorp Energy company 23.0 BOP Schematic 0. [firm am-mi mr 111 13-5/8"5M Control Technology Annular BOP I1 1 „1° od iii Fi , e ac Fri ---------------13-5/8"5M Control Technology Double Ram G 3-1/8"Kill Line 44 L_- C_ �' 3-1/8" Choke Line AiWe . o Mie .i; a; 13-5/8"5M Control • Technology Single Ram MIIII 13-5/8" x 5M 11"x5M /oh i] Ilk imp --13.11i g , u ' _ 1 L( j jj•j 9-5/8" DBL D Seal—N, LIr►'�L. �� 2-1/16"x 5M CasingHanger ��•�� 13-518"x 5M S-22 -SIN III I '\S.' 13-5/8" NOM A LI 9-5/8" BTC Btm x 2-1/16"x 5M 10.5"-4 SA Pin Top W/Primary Seal 20"Casing 9-5/8" Casing Page 39 Version 1 Nov, 2016 • •• Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 24.0 Wellhead Schematic HILCORP ALASKA, LLC MPB-30 MQ-390 (m rrirri 4 41.3 3-1/8 5M- EST \9014 �..,.. 0( 90.6 EST [07: 3-1/8 5M HYDRAULIC ACTUATED tt4, X 43.3 EST ,,,,, ,, 3-1/8 5M ADAPTER, TUBING HEAD Al `'.. 154.1 SM-E-2CLN w` EST 11 5M X 3-1/8 5M (SPECIAL) 411:4410 WITH TWO(2) 3/8 CL 3-1/8 SM 6.1 ,,_ 11 . EST SM � . 1 TUBING HANGER, SM-E-2CL 11 X 3-1/2 EU 8RD BOX TOP 17.2 X 3-1/2 OD API MOD BOX BTM i - EST TWO (2) 3/8 LP POR - I I T WITHTS , ,. im .,,,,,, ,. a. 'I i CASING HANGER, SMB-22 �' t 2-1 '1E ,- 11 X 7 101 i_) j 1n1 26.D#L-80 DWC/C BOX BTM - 4_ 25.8 X 8.500-4 - i - - 63.5 EST STUB ACME-2G-LH PIN TOP [_ d �! EST W/SEAL ASSEMBLY I I I o uT 1n 9-5/8 DBL IPS ,_ ,..y, 2-1/16 5M 13-5/8 5M .,j , CASING HANGER, S-22 1�s 1 is 2-1/16 5M 20.5 13-5/8 X 9-5/8 i EST ,t,,,:,11, I.I = „:„. ./ , , Conductor-20” a II WEN7 CASING 3-1/2 TUBING 5,000 PSI WELLHEAD ASSEMBLY NOTE. 13-3/8 X 9-5/8 X 7 X 3-1/2 DIMENSIONS SHOWN ON THIS DRAWING ARE RESTRICTED CONFIDENTIAL DOCUMENT ESTIMATES ONLY AND CAN VARY SIGNIFICANTLY ey v.�w u mown. „MO„•o„K li". US f°"" 1-10 I'-11/3/16 .t. DEPENDING ON RAW MATERIAL LENGTHS. wvnm an cosmos. P sass ows. sr s...o , NO GUARANTEE OF STICKUP HEIGHT IS IMPLIED. snma.<au moms,.snow�*uo.suxn..soCOMM A DIMENSIONS SHOWN SHOULD BE CONSIDERED b"160"'P a w "'K PAK I0 II PPP PPM,K"PPM,0"'•""1 WOwt.Ostnx. neoperi P—215 76 FOR REFERENCE PURPOSES ONLY. POI , ..0010 o"o"ena.c Page 40 Version 1 Nov, 2016 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 25.0 Days Vs Depth Days Vs Depth 0 •mme8-030 —K-44 2000 4000 � 6000 i yE O ■ 8000 10000 12000 14000 0 5 10 15 20 25 Oats Page 41 Version 1 Nov, 2016 • 0 11 Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 26.0 Formation Description GENERALIZED GEOLOGICAL DRILLING DATA SUMMARY FORE:AST SS TVD GEOLOGICAL CASING&OTHER (The following summary remarks are from FM LITH DESCRIPTION SUGGESTED MUD WT. ;the eleven 8-Pad wells reviewed. These DRILLING RELATED INFO. t. .. OS (wells were drilled between 1982 and al tett. es a s 1400 +os beets Cub& unconsolidated coarse to medium Tv: k • 1 NOTE See ind u�duai Weis 11989 �eu.eicx gog . . • sand and small gravel with minor ss 1 MUD PPG I Plan for specific casing a rhe- ,. Mole:This H design,depths,sizes. .slastone. weights, connections. i tdeg M .Heavy gravel conglomerate to 1400'. i a generic mud g SURFACE HOLE: 1.000' woos fragments mrougMit i.w- 'weight<had. 1.14 and 8-23 both had y ` permafrost zone. ' see indivIdual ,;e drilling or running and well plan for • 1700' i :Base permafrost specific mud Smaller gravel in surface hole las compared to swiynts. Prudhoe Bay surface hole gravel)enables using c : Proposed 9-518"casing lower mud funnel mud wiscoatty el-B0 initially and 2,000' "°`- _� I setting depth 2400 to final 0145 to 55 stmt .2aution:d fart Sagavanhktok L 1129011.3 Vim.•:..;..:,, .,:c J.immediately raise nor ;•Predominantly clay to•r•s000•with 2500'TVD for Kuparuk funnel viscosity to 154 wUgt.Keep Uwe ria y A , mterbeds of sand.clays and silt• target wells with materials near and readily available for mixing. Surface using point design set deeper In these •,11ns stones with occasional snows of coal Schrader Bluff recent 7965-09 wells at•i-4600 55 covering the -Y�around 2700'.Pebbley gravel lip to r03 ¢Ct4. Schrader Bluff Sands. 9 50:'•)down to 2700•. P P 3,000 eonbnued Inte,beds of send,clays and mnm sdtstonei with heavy coal sections w.r -' STUCK PIPE:B-4(1962 welt).Stuck 3.1'2 2600-3200 hours at 4001 SS.probable cause new BHA stuck K0. while working to bottom.This incident is mentioned Ksar,es here even though surface casing was set shallow at "" I.A.BC.01 UGNU: Series of coarsening upward 2300 and the Incident was actually to the UGNIi Lend. sands which are made up of (from top intermediate hole section of the wall. MA: 1-0.81 to bo8oml coarse sand.fine sand.silty STUCK PIPE:B-140oes wan.Stuck 4070. Mends shale and some coal.Bette,developed 4740 4vka C) intervening shahs as you progress Into • pipe at 3594wwashing and reaming tight=moms=moms spots in hole..The hole then packed on and the the L and M(deeper). 4,000' hydrocarbon bearing sands •..a-r -- formation was taking fluid. The BHA had to be abandoned and Its.well plugged back and NA: Schrader Bluff Sands sidetracked. 4.3,0_ *Banes Continued layered Coarsening upward sands Of .600. i-A.B.o.D aboeeexceptmore condensed. Possible SHALLOW GAS!!! E hyuii._..,,i,,_-,bearing and potentially productive OA. O in the"'O-and'N'sands. Tend to be water wet There was no shallow gas reported In the wells 4550. fvs.B.c. ^moot than a mile to the soot. reviewed.However.shallow hydrate gas has been 4940 o'E-cr Ca 9.i Proposed 9-518"casing encountered at nearby E-Pad. BE ALERT FOR Primarily day with some silty sandstone setting depth 4600- ANY SIGNS OF GAS AROUND 2000 TO www whenSchraa and to lasso)to 47 4600' 4700'TVD. 2400 FT. IT IS POSSIBLE THAT THESE 4600-Top of — •I.5200 where sandstone begins making 4000' 4900•Seabee up 504,the remainder siltstone and clay. s..r _ _ --Li, ARE SHALLOW HYDRATES. 5.000 SHALLOW HYDROCARBONS: The Ugnu and Seabee(Colville)Interval: Schrader Bluff sands may contain hydrocarbons(orf Predominantly Interbedded siltstonegr RB with solution gas). and clay with beds of sand.shale and IT IS GOOD DRILLING PRACTICE TO ALWAYS BE occasional seams of coal.The Seabee ALERT AND PREPARED FOR THE UNEXPECTED is generally uneventful until reachingare POSSIBILITY OF SHALLOW GAS OR the HRZ Expect good penetration rates hap Sea•ee (•t-too lett) HYDROCARBONS. r Bridges and tight hole occurred throughout Me the wells in this section.See Well Summary. 6,000' a .. The best way to keep good hole conditions in the surface hole is to make frequent short trips and Continued interbeds of sandstone. circulate sweeps as required.Also,watch that the shale with some clay 5200 to 6500. gravel concentration does not build up.Raise the Expect pyrite and tufts al al-6200'. vheoShort sfty N It does.Soo Trip Guidelines. At 6400 to 6550',10 to 20 S:Tuns. • Continued intermittent Tuft _s downto pp. DIRECTIONAL: Under the des( roil • 6900 8-23,1147 to 1542. Watch the base e•. permafrost at 1700'for inclination• CLAY sections: H.ary clays at B-Pad below Me base of the permafrost to el.3000 ss and also below the Schrader Bluff after surface casing is set from 7000' Top HRZ HRZ: Highly Radioactive Zone.Very dark, 4550 to 5200.For bitiBHA balling use SAPP and 0.100 ' rthistle type shah.organic.good source rock. COHOST. Base HRZ ( possible at top of HRZ. Q pp, COAL' Expect to encounter some coal in the 7060' Tun bentonrtic)zona 01.160' r—r Kalubik Shah. Marker 1.619 good log ! Ugnu..f-3900 SS. Kalubik marker.Gradually diminishing ROP. I M8y TUCK PIPE SURFACE CASING. Lost returns on the 9.5,0' 7300• --. hther surface teeing lobe was common on the a-Pad e,.,gg-D- Kuparuk Interval: ��,�,,aa..�� . NTERVAL ON wells.Volumes varied from 10,20.30 blots to 100• Shale The-D-Shah is the top Kuparuk sediment w •V•` bels.Acceptable formation integrity tests were and IS known as the-cap Rock-. Weal/ -4,13-9,B-23, ecnieved. C -�. C SANDS: Sandstone.shales of nee SANDS upward.Of bearing target. of neiniece -4 and four L (t-CLL LCU:Lower Cretaceous Unconlormdy nd F-PAD .INTERMEDIATE HOLE: 8 Sands. Also known as the laminated Wall )1 B (LZ) Zone begins below LCU. ! SANDS Fine to medium gr sands becoming ELLSl. (+/-4600-6800'): f more shaley with depth.Hydrocarbon This interval was generally trouble nee withII bearing.Pinches out to the north and occasional tight note and some reaming on a few of thickens to the southeast.Top sand. the wells. A 13-7.is target.Use controlled drag rate Good practices thru this fast drilling SANDS in Kuparuk.60 fin.for LWD. interval are to let hole conditions dictate A Sands. Fine gram sandstone. short trip frequency. 8-19 and 8-21 Potential hydrocarbon bearing. drilled+/-4000 ft without short tr upping Miluveach shales.predominantly silly and without any problems. Mituveach shale.(Casing Seat for Kuparuk Look for a definite change in ROP when the bottom Shale completion). 10 2 of the Seabee clays(02 6600)change into the MR/ shales.Expect a change from.1-100 to 25 fph. PP9 I / c","..."---- Transition Interval: r Kuparuk completion. 6.6 u 10.5 - - 'The above depths are based on the proposed +/ 68007000' - �• 1996 Et-Pad Development Drilling Program. Two Wells on B-Pad,one on E- Page 42 Version 1 Nov,2016 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 27.0 Formation Tops Formation Top Formation Top MD TVD Thickness Base permafrost 1915 1,679.60 1915 Schrader Bluff OA 5749 4,449.60 20 Base Colville 8449 6,399.60 - Top HRZ 8724 6,599.60 30 Top Kalubik Gamma Marker 8851 6,699.60 10 Top Kuparuk D Shale 8968 6,799.60 50 Top Kuparuk C Sand 9143 6,959.60 80 Top Kuparuk A Sands 9452 7,249.60 100 Page 43 Version 1 Nov, 2016 • • Milne Point Unit B-30 Drilling Procedure Hilcorp Enema Company 28.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates. If 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: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 44 Version 1 Nov,2016 • i 11 Milne Point Unit B-30 Drilling Procedure Hilcorp Enemy Company 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the 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 45 Version 1 Nov, 2016 Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 8-1/2" Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore,pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of>500 gpm. Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There may be several faults crossed while drilling the well. The throw of these faults is not well understood at this point in time. Shale Instability: Above the Kuparuk,there are several shales that can prove problematic. The HRZ, Kalubik, and Kuparuk"D" shale. Ensure adequate concentration of KCL is maintained in fluid system. Treat mud with shale stabilizers as appropriate(2-4 ppb BAROTROL+and 2-4 ppb BDF-515). Follow good drilling and tripping practices when passing through these intervals. Avoid sliding through this interval unless necessary. After penetrating the HRZ, MBT concentrations will be on the rise. Run solids control equipment continuously, and dilute as necessary. Bit Balling: Bit balling has occurred on several wells due to the large amount of shales drilled. Use Walnut/Condet sweeps when bit balling is suspected. Add drill-n-slide as necessary to aid in keeping bit clear. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on"B"pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Overpressure may be encountered in the Kuparuk interval, including the shales above from years of water injection. If overpressure is encountered,treat flow from well with standard well control response and shut in well. After confirming Page 46 Version 1 Nov, 2016 0 0 Milne Point Unit B-30 II Drilling Procedure Hilcorp car 29.0 Innovation Rig Layout 1 170'-3 " I — 1 i411 i ipipm 411111•1111 z '7'iI .r.0 . k_. -; .• TI1Dre- I-- wr'r i 1 111444119 I■• , ferir i 1=51 IT= I 4. 4 r' . j_mr--syse • , 1 N [� il i ,k— _..A 4IP' I 1 1 6' c N;t ' I a U v "' 1. 1 I 56'-4" i is HAK 2 FOOT -1r I'S:l:' _, - I � PRINT ijII1 05/21/16 1iiJ ; PER 1 - 1 To _,„, 1 iaunnu u Ir 113'-112 U - � 36'-1 " Page 47 Version 1 Nov, 2016 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 30.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer(ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 48 Version 1 Nov, 2016 • • 14 Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Comp.), 31.0 Choke Manifold Schematic ir 17. ==. ,-, b q bp QLi p—q 13-1:1p d w 171 'nes =/' '�S a.. .. , .... . . , -,i , lit . 0 11 : 0, tem Iasi, ; lio 0 ___ , on , I I • •A• . . . Ill1111 ...). l _ 2-9116"5M BB2O9 2AJ16 5M 882(76 nh Piper Ban Valves -101- Piper Ban Valves �. 1111 11 EllIISITISAffr /71 1 W"." Mi 4111111114E *a ti ,41)1! 1111111111111111111 , loirii11:+:1111ii111111111111 I :4 +. p NUM MEE La Qac P'—'—1 r--—1 Page 49 Version 1 Nov,2016 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 32.0 Casing Design Information Calculation & Casing Design Factors DATE: 11/4/2016 WELL: MPU B-30 DESIGN BY:Luke Keller Design Criteria: Hole Size 8-112" Mud Density: 10.5 ppg Hole Size Mud Density: Hole Size Mud Density: Drilling Mode MASP: 2741 psi(see attached MASP determination &calculation) MASP: Production Mode MASP: 2741 psi(see attached MASP determination&calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress(0.494 psi/ft)and the casing evacuated for the internal stress 2,3 10.5 ppg gradient external stress(0.546 psi/ft)and the casing evacuated for the internal stress Casing Section CalculationlSpecification 1 2 3 4 Casing OD 9-5/8" 7" 4-112" Top(MD) 0 0 8,800 Top(TVD) 0 0 6,658 Bottom (MDI 6,373 9.719 9,719 Bottom (TVD) 4,900 7.500 7,500 Length 6,373 9.719 919 Weight(ppf) 40 26 13.5 Grade L-80 L-80 L-80 Connection DWC/C DWC/C HTTC Weight w/o Bouyancy Factor(lbs) 254.920 252,692 12.407 Tension at Top of Section(lbs) 254.920 252,692 - 12,407 Min strength Tension (1000 lbs) 916 604 307 Worst Case Safety Factor(Tension) 3.59 2.39 24.75 Collapse Pressure at bottom(Psi) 2,421 4.095 4,095 Collapse Resistance w/o tension(Psi) 3,090 5,410 8,540 Worst Case Safety Factor(Collapse) 1.28 1.32 2.09 MASP(psi) 2,741 2,741 2,741 Minimum Yield (psi) 5,750 7,240 9,020 Worst case safety factor(Burst) 2.10 2.64 3.29 -Note: Contingency string highlighted in yellow Page 50 Version 1 Nov, 2016 • Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 33.0 8-1/2" Hole Section MASP t Maximum Anticipated Surface Pressure Calculation 8-1/2"Hole Section Ililccl p MPU B-30 Milne Point Unit MD ND Planned Top: 6,373 4,900 Planned TD: 9,719 7,500 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OA 4.446.50 1965 Water 8.5 0.442 Base Colville &396.50 Top HRZ 6.596.50 Top Kalubtk Gamma Marker 6.696.50 Top Kuparuk D Shale 6.796.50 Top Kuparuk C Sand 6.956.50 3437 Oil 9.5 0,494 Top Kuparuk A Sands 7.246.50 3580 Water 9.5 0.494 Offset Well Mud Densities Well MW range Top(ND) Bottom(TVD) Date MPB-11 9.5-10.4 4,750 7,241 1985 MPB-12 9.5-10.5 4,680 7,340 1985 MPB-13 9.7-10.3 4,558 7,379 1985 MPB-14 9.4-10.3 4,719 7,348 1985 MPB-15 9.8-10.4 4,633 7,192 1985 MPB-16 9.5-10.4 4,670 7,175 1985 MPB-17 9.8-10.5 4,638 7,118 1985 MPB-19 9.3-10.7 4,727 7,505 1985 MPB-21 9.4-10.4 4,771 7,120 1986 MPB-25 8.8-10 4,585 7,488 1997 Assumptions: 1. Field test data suggests the Fracture Gradient at the 9-5/8"shoe is 0.8 psi/ft. 2. Maximum planned mud density for the 8-1/2"hole section is 10.5 ppg. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8"shoe considering a full column of gas from shoe to surface: 4900(ft)x 0.8(psi/ft)= 3920 psi 3920(psi)-[0.1(psi/ft)*4900(ft)]= 3430 psi MASP from pore pressure(complete evacuation of wellbore to gas from Kuparuk"C") 6956(ft)x 0.494(psi/ft)= 3436 psi 3436(psi)-0.1(psi/ft)*6956(ft)= 2741 psi Summary: 1. MASP while drilling 8-1/2"production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Page 51 Version 1 Nov, 2016 • 0 II Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 34.0 Spider Plot (NAD 27) (Governmental Sections) Legend MPU B-30_SHL Other Surface Holes(SHL) ' • MPU B-30_TPH • Other Bottom Holes(BHL) ' ,,.E,P y Other Well Paths I ; MPU B•30 BHL 1 : ` Oil and Gas Unit Boundary IADL392703 Sec 7 :• Pad Footprint �® (A1 628) ' 1 r 1 , .0. I , 4 Z-.-OD 1 i 4 OM MPU B-30 BHL .`' r ,' C^, _ I , 24 " ,i AIPI'B-30 TPI I ,' } (2-.3413 emt,(E) ) Y )8 a-- - - _,,._ , 11f,<<MILNE POINT UNIT U013N010E \, , ---, ' ' ,/U013N011E — \ -;,I, 4C',3a. -'4 MPU B-30_SHL ADL047437 -. MPB-25` r. _ 1/ , ♦ wy _. p .04A i . Oa Q V' �' t�.i fQ' c.i.t *cw '�i *c , MPE r:, ,PBI, \ I MPE-tae W\a,t�'�:ea , \ \ ,VMPB 16 \ ,.� I ','\ 7(/I \/ 1.0 4> .PAPE is :`, ,. I' Ir '(f Y�r �:.'.wn�� I I ,CatEOMPB \ n i MPE-1• = r'7 I / .i 4 \hi 4 Q JI f -1/ CJWLV CgAn / //'' = 1 •1PC-atLt �-_ APE""[JALI l �. __ \\\ 1 tied 21Pd'� �. p/{' '1612 - MTELBER 1 .-.ti1Pt,E-r-._z__ _ 4 v ADL025518 Sec.26 --- Sec.25 MPB-22APB�M Oh __ -ADL028 4 • h1PG.11_ �/ -- / \�'- --- --= •M- I- Q - AIPE,15'- � \M � � ' +,SPG-16L1 MPG 16A 4-- / 1 ",\ \\." 2/MPG-16 I I \\ \\ Milne Point Unit N MPB-30 Well 0 1,000 2,000 1.16.DI. 11'4.015 Feet Page 52 Version 1 Nov, 2016 0 Milne Point Unit B-30 Drilling Procedure Hilcorp Energy Company 35.0 Surface Plat (As Built) (NAD 27) / N 2800-}- -up f if D—PIIO' ! t r 14�r` 1 13 18 m o � lio �.;r I �.•r r,9-PAD w 20■ 6J •21 g7fY�1lV, t 1 18• •3+ •A—PAD 244 ^- I 80 ■12 1 .2 x 24 19 11 / 7• •14 0 a •13 TO GRAVEL SITE ` ..r g• •16 j,,. ... CFP .-.._./ �� A�E—PAD i 10• •15 ,/ 23• �6 I '25 k 30 ` B-30,21 •22 VICINITY MAP —J,3: USA N.T.S. Ni LEGEND; 17• •3 SFC I 25■ c �, 4. AS-BUILT CONDUCTOR 28• •50 19 1• •4 �"_ • EX'STING CONDUCTOR 1 , ,OFI�1 1,, �w ,, 44 i k� t_ _ %ft�I /.� B-PAD • • % ,�'••• r i. . ..f111:""-•/ • _• l• othy F. :;/nhart 4. 10200 4... it NOTES: �� 1. ALASKA STATE PLANE COORDINATES ARE ZONE 4 NAD27. SURVEYOR'S CERTIFICATE 2. GEODETIC COORDINATES ARE NAD27. I HEREBY CERTIFY THAT I AM 3. HORIZONTAL AND VERTICAL CONTROL ARE BASED ON MP B-PAD PROPERLY REGISTERED AND LICENSED TO PRACTICE LAND SURVEYING IN OPERATOR MONUMENTS B-1 AND B-2. THE STATE OF ALASKA AND THAT 4. ELEVATIONS ARE MP B-PAD DATUM, MEAN SEA LEVEL(M.S.L). THIS AS-BUILT REPRESENTS A SURVEY MADE BY ME OR UNDER MY DIRECT 5. MEAN PAD SCALE FACTOR IS: 0.999905887 SUPERISION AND THAT ALL 6. DATE OF SURVEY: SEPTEMBER 27-28, 2016. DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF SEPTEMBER 28, 2016. 7. REFERENCE FIELD BOOK: HC16-03, PGS. 24-33. LOCATED WITHIN PROTRACTED SEC. 18, T. 13 N., R. 11 E., UMIAT MERIDIAN, ALASKA WELL A.S.P. PLANT GEODETIC GEODETIC TOP OF SECTION BASE FLANGE NO. COORDINATES COORDINATES POSITION(DMS) POSIT1ON(D.DD) GRAVEL PAD OFFSETS ELEVATION Y=6,023,208.86 N 1559.64 70'28'25.298" 70.4736940' 86' FSL B-30X= 571,962.88 E 600.00 149'24`43.916" 149.4121990' 23.1 4,328' FEL NA 04Ark KIFW • - OM JACOBS CI Hilcorp Alaska ______ lb II Ortt. 10/ane O11 NO MPS MILNE POINT B-PAD 1� "-K AS-BUILT CONDUCTOR LOCATION I o, ,0nl+aawmfart PU UTAaaN .. L.&. 1•-400' WELL B-30 1 a 1 .01 ..IT WV 4. OK Cwt Page 53 Version 1 Nov, 2016 0 • 111 Milne Point Unit B-30 Drilling Procedure Hilcorp Ena8Y ComW Y 36.0 Offset MW vs TVD Chart MW vs ND Offsets 0 B-21(1986) 8 ( 111\,\ .--B13--2152 -12-25(1985)1997) 1000 ' —B-11(1985) \ B-15(1985) B-14(1985) 2000 ‘ —B-13(1985) -m -B-17(1985) B-19(1985) 3000 ° --- -.B-16(1985) Itif 0 4000 \ IN:\ 5000 •0 4fi 6000 \s, 7000 8000 8.0 9.0 10.0 1L0 12.0 Mud Weight(PPG) Page 54 Version 1 Nov,2016 0 Milne Point Unit B-30 rill II Drilling Procedure Hilcorp Energy Company 37.0 Drill Pipe Information 5" 19.5# S-135 DS-50 Drill Pipe Configuration I f ,,\ Pipe Body OD In,5.000 80%Inspection Class 1 Pipe Body Wad Thickness in,0.362 Nominal Weight Designation 19.50 Pipe Body Grade 5-135 Drill Pipe Approximate Length ^>31.5 Drill Pipe Length Range2 5moottiEdge Height an,(3132 Raised Connection GPDS50 Tool Joint SMYS 9st,120,000 \ Iii Tool Joint OD 6.625 Upset Type Max Upset OD {DIE) IEU Tool Joint ID l 3.250 5.125 Pin Tong 9 Friction Factor 1.0 Box Tong n,12 Nobe Torq space slab.mdl de nar4Yaclyd Drill Pipe Performance Drill-Pipe Length Range2 Performance of Drill Pipe with Pioe Body at Best Estimates I Nominal •.,w1tU Ccaim, .4 VI Coallro. slat accurate) 8D%Inspection Class A9piwidii .o �__rarana Max Tension Drill PipeAdµnfedWeightl rttaiR124.11 23.29 romuc nt+p:s TorGa_ ,h-:•:, ues> Fluid Displacement •,o1'n10.37 0.36 Tension Only 0 564,800 Fluid Displacement Mb''ns POW 0.0085 *�+ aT 43,100 combined 39,600 410,500 Fluid Capacitytwvnr .T 1 0.70 0.72 Fluid Capacity ff3pts ri 0.0169 0.0167 0.0172 38.100 Tension Only 0 560.800 Drift Size ,mI 3.125 Marmon slur36,100Lcadria 32,100 467,400 --- Nate.OIt 1010 barrel equals 42 US gaticnr.. ' Note:Orn Pepe assert-day waIjec are nest estimates and may vary due to L pe booty hill baerarce.Internal ptastx coaling and alter factors. Connection Performance GPDS54 ( 6.625 oar OD X 3.250(to ID ) 120,000 10.11 A„plea make-ao Ter so9 al Cnculer Yemen at connector Tool Joint Dimensions Toque Separarnr Veld ta-nat ;Ins: toss Balanced 00 ;In:6.435 t_.Maximum Melee-up Torque 43,100 Tensile Limited 1,046.900 hanrnum Tool Joint 00 nor API 5.930 futinimum Mace-up Torque 36,100 1.202,500 1.250.000 Premum Cuss tart Nae The maximum makeup taloa.11404 be app0d ester Corsbe Minimum Topa Jana 00 nor 5.93 No, To maxf-nue cannecf'o operational tens le a rd_T ITO,-37.500{a.lhs,should be 09{104 Tool Joint Torsional Strength Ie fbsl 71.800 Tool Joint Tensile Strength 1;no' 1.250.000 Cocnfernare lir; Elevator Shoulder Information Elevator OD 3132 Raised 6.812 tn, SmoothEdqe Height Nominal Tool Joint Worn to Bevel Worn to Min TJ CD for 13,32 Raised OD Diameter API Premium Class Box OD 6.812 6.625 6.063 5.930 Elevator Capacity in-1 1,658.000 1.440,200 823.600 685,600 fye�. 415219 Note Eleva caoac t-,ratec on assun a :_.r 2 C near Tactor,and contact stress or 110,twysl. - Assumed Elevator Bore DiameterNote A raised ee•alar 00 Ir,.rease`.rte '.ur cap..n Ad.'Jt affecting rake-up torque. Pipe Body Slip Crushing Capacity Pipe Body Confguration( 5 t*> OD 0.362 111 Wall S-135) (f Nominal 80%Inspection Class API Premium Class Slip Crushing Capacity Assumed 396.500 396.500 Note.Sip CrusNm S10 racsNno load Is calculated n n tae Sprte.Renhold equi tic ba "lett" Gb Ppe Assumed Slip Length inn 16.5 Palm to SIP Area"Able Cl 1195a<Cf the Op tenon anti fransteme load factor Most ale a tor refrence Transverse Load Factor(Ki 4 2 an Siperoskrwsxxncbenlor•thesip&sohand0Areltar oealclemarOtor,iodrtacondpo-u ti-n r fn, pee 013 and NW a,attibor,and dila tarter. CansJt'MN the-p ma otunlxr'c'adenara itttmabon. Pipe Body Performance Pipe Body Configuration( 5 rrts OD 0.362 an) Wall S-135) Nominal 80%Inspection Class API Premium Class Pipe Tensile Strength ,1111 712,100 560,800 560,800 Pipe Torsional Strength 74.100 58.100 58,100 TJiPipeBody Torsional Ratio 0.97 1-24 1.24 80%Pipe Torsional Strength ,ti-it-.,59 3gp 46,500 46,504 Burst brit 17,105 15.638 15,638 Nota Nominal euro Collapse ,i---, 15.672 10.029 10,029 calculated of 57.3 o Rew per API Pipe OD mI 5.000 4.855 4.855 Wall Thickness 0.3&2 0.290 0.290 Nominal Pipe ID ,m1 4.276 4.276 4.276 Cross Sectional Area of Pipe Body .l'l'Jl 5.275 4.154 4.154 Cross Sectional Area of OD 0,02) 19.635 _ 18.514 18.514 Cross Sectional Area of ID +"-2, 14.360 14.360 14.360 Section Modulus 101031 5.708 4-476 4.476 <-y Polar Section Modulus ,n°3 11.415 8.953 8.953 Grant Page 55 Version 1 Nov, 2016 • Milne Point Unit B-30 til Drilling Procedure Hilcorp Energy Company 16 operational Limits of Drill Pipe Connection GPDS50 Tool Joint 00 30,;16.625 Tool Joint IDt,113250 Tool Joest Specified M nimurn 120,000 Yield Strength pv, Pipe Body 80%Inspection Class Pipe Body OD „,;5 Wall Thickness e„X10.362 Pipe Body Grade S-135 Combined Loading for Drill Pipe at Combined Loading for Drill Pipe at Maximum Make-up Torque= 43,100 Cees) Minimum Make-up Torque= 36,100 t a» Cperationa' Assembly Pipe Body Connection Max Assembly Poe Bed), co-PA.rc- Torque Max Tension Max Tension Tam I Torquesi Max Tenon M renvan • Of-InNi ;. , fes] 42sr MA.,,, Otsi 0C2 ir:, 0 560.800 560,800 1.046.900 0 560.800 560.800 1.202.500 .2,100 560,400 560,400 1,046,900 1,700 560.500 560.500 1,202.500 4,200 559.300 559,300 1.046.900 3.400 559.800 559.300 1.202,500 6,300 557,500 557.500 1,046.900 5,100 558.600 558.600 1.202,500 8,300 555.000 555,000 1.046.900 6.800 556.900 556.900 1.202.500 10.400 551,700 551,700 1,046,900 8.400 554.900 554,900 1.202,500 r 12,500 547.600 547,600 1.046.900 10.100 552.200 552.200 1.202.500 14,600 542.800 542,800 1.046.900 11.800 549.100 549,100 1,202,500 16.700 537,100 537,100 1.046.900 13.500 545.400 545.400 1.202,500 18,800 530,600 530,600 1.046.900 15.200 541.200 541,200 1.202,500 20,800 523.600 523,600 1-046.900 16.900 536.500 536.500 1202,500 22,900 515,400 515,400 1.046.900 18.600 531.300 531.300 1,202.5000 25.000 506.200 506,200 1.046.900 20.300 525.400 525.400 1.202.50_ 27.100 496.100 496,100 1.046.900 22.000 519.000 519.000 1.202.500 29,200 484,800 484.800 1.046.900 23.700 512.000 5'2.000 1202.5x: 31,300 472,500 472,500 1.046.900 25.300 504.800 504.800 1,202,500 33,300 459,600 459,600 1.046.900 27,000 496.600 496=30 1_202.5C 35,400 444.700 444,700 1.046.900 28.700 487.600 487.600 1.202.500 37.500 428,400 428,400 1-046.900 30.400 477.900 477.900 1 20250 39,600 410,500 410,500 1.046.900 32.100 467.400 467.400 1,202.500 Operational driiling torque is limited by the Make-up Torque. Operational drilling torque is limited by the Make-up Torque. Connection Make-up Torque Range Make-up Torque Connection Max ,,,_es;Tension ,r;. Min MUT 36,100 1,202,500 ff 36,900 1,229,200 ..4. 37,700 1,243,600 38,400 1,218,100 39.200 1,189,000 40,000 1,159,800 40.800 1,130,700 41.500 1,105,200 42,300 1,076,100 Max MUT 43,100 1,046,900 Page 56 Version 1 Nov, 2016 • ,,g . Milne Point Unit B-30 4`' Drilling Procedure Hilcorp Energy Company Connection Wear Table Connection GPDS50 Tool Joint OD „,16.625 Tool Joint ID .,,,: 3.250 ?col Je{rt Specified Gh^imam 120.000 Yield Strength 'v'ii Connection Wear -- - Tool Connection Max Con,ec.tica Max Min MUT Connection Max New OD Joint OD Torsional MUT Tensic Tension Strength n-r..,:, -.dx r.•s: r:.es , ,,, 'i 6.625 71,800 43,100 1,046,900 35.900 1.195.900 6.562 71,800 43,100 1,034.900 35,900 1.208.700 6.499 71,800 43,100 1,022,600 35,900 1.222.400 6.435 71,800 43.100 1,009,800 35.900 1.237.500 6.372 71,200 42,700 1,008,100 35,600 1.245.200 6.309 68,000 40,800 1,057.300 34.000 1.207.700 6.246 64,800 38,900 1,104,800 32.400 1.169.800 1 6.183 61,700 37,000 1.150.400 30.800 1.131.300 6.12 58,600 35,200 1,190,900 29.300 1.096.100 ` 6.056 55,500 33,300 1,232,300 27.800 1.060.800 Want OD 5.993 52,600 31,500 1,227,200 26,300 1.024.600 5.93 49,600 29,800 1.187.100 24.800 987.900 Pipe Body Combined Loading Table(Torque-Tension) Pipe Body 80%Inspection Class Pipe Body OD tn)15 Wail Thickness nr010.362 Pipe Body Grade 1S-135 Pipe Body Torque 0 10.600 15.800 21.100 28,400 31,700 37.000 42.300 47.500 52.800 58.100 p1�sY Pipe Body Max Tension taxi 560,800 558.400 551.400 539,800 522.500 499,800 470.000 432.400 384.500 323.100 234.300 12.200 Page 57 Version 1 Nov, 2016 S • U`: Hilcorp Energy Company Milne Point MPtBPad Plan: MPU B-30 MPU B-30 k t Plan: MPU B-30 wp02 ry Standard Proposal Report 04 November, 2016 HALLIBURTON Sperry Drilling Services - ------------- •ect Milne Point WELL DETAILS: Plan. -30 NAD 1927(NADCON CONUS) Alaska Zone 04 HALLIBURT Site: M Pt B Pad Ground Level: 23.10 Well: Plan: MPU B-30 +N/-s +E/-W Northing Easting Latittude Longitude Spgzre v o,11.,.a 0.00 0.00 6023208.86 571962.88 70°28'25.298 N 149°24'43.916 W Wellbore: MPU B-30 Plan: MPU B-30 wp02 REFERENCE INFORMATION III liter) j) Co-ordinate(N/E)Reference:Well Plan:MPU B-30,True North Vertical(TVD)Reference:MPB 30 A-Built©49.60usft(Innovation) _ Measured Depth Reference:MPB 30 A-Built©49.60usft(Innovation) _ Calculation Method:Minimum Curvature -1500- _ _ SECTION DETAILS - Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target -1000- 1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.00 -_ 2 326.50 0.00 0.00 326.50 0.00 0.00 0.00 0.00 0.00 3 826.50 17.50 290.00 818.76 25.91 -71.20 3.50 290.00 70.73 4 1387.26 43.75 311.33 1298.32 186.01 -300.61 5.00 32.35 348.90 - -500- 5 8665.38 43.75 311.33 6555.87 3509.85 -4079.66 0.00 0.00 5381.62 - _ 6 9140.54 20.00 310.00 6956.50 3672.92 -4267.97 5.00 -178.87 5630.73 MPB-30wp01 - /1 7 9718.92 20.00 310.00 7500.00 3800.08 -4419.51 0.00 0.00 5828,52 - �� 0- Start Dir 3.5°/100':326.5'MD,326.5'TVD - _ ----- FORMATION TOP DETAILS - 0° TVDPath MDPath Formation °/ ' 826.5' 818.76' TVD��0 Start Dir 5_100 : MD, 1679.60 1915.08 Base permafrost - 10° -- "-" 4449.60 5749.64 Schrader Bluff OA 15i°-"-" 6399.60 8449.06 Base Colville 2 ®0 End Dir :1387.26'MD,1298.32'TVD 6599.60 8724.49 Top HRZ 1000- """- 6699.60 8850.83 Top Kalubik Gamma Marker - °,0"- 6959.60 9143.84 Top Kuparuk C Sand - 7249.60 9452.45 Top Kuparuk A Sands 1500- 00 rL0 _- Base permafrost 00 CASING DETAILS 2000- tib TVD MD Name Size - 4900.00 6373.13 9 5/8" 9-5/8 0000 7500.00 9718.92 7" 7 2500- 2 _ 6cp 0 _ 3000- b000 0 _ _ 00 3500- C., L -_ a) `0000 4000- 00 0- 66 j 4500- -_ 6000 N _ Schrader Bluff OA 7 O_ H - ; pb� 5000- 9 5/8-- Start Dir 5°/100':8665.38'MD,6555.87'TVD 00 _, 1O 5500- 600 1 000 End Dir :9140.54'MD,6956.5'TVD 6000- 0 Base Colville 6500- Top HRZ -Top Kalubik Gamma Marker 06° Top Kuparuk D Shale __MPB-30wp01 7000-- - Top Kuparuk C Sand 2p 00 Total Depth:9718.92'MD,7500'TVD - 7500-- Top Kuparuk A Sands ' ,91-19 _ 7- - 8000- SURVEY PROGRAM 02 _Date:2016-10-27T00:00:00 Validated:Yes Version: MpV 8,30 v+P 8500-- Depth From Depth To Survey/Plan Tool _ 26.50 800.00 MPU B-30 wp02 SRG-SS - 800.00 6373.00 MPU B-30wp02 MWD+IFR2+MS+sag - 6373.00 9718.91 MPU B-30wp02 MWD+IFR2+MS+sag 9000- - I I I I I 1 I I I i I I I i i i I 1 1 I 1 I I I i I I I I I I I I I I I I I I i I I I I i 1 1 I 1 I 1 1 1 1 I 1 1 1 1 i 1 1 1 1 I 1 1 1 1 I 1 I 1 1 I 1 1 1 1 i 1 I I I I 1 I I 1 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 Vertical Section at 311.00° (1250 usft/in) Project: Milne Point • WELL DETAILS: Plan:MPUB-30 Hilcorp Site: M Pt B Pad Sperry Drilling Services Gromd Level: 23.10 Well: Plan: MPU B-30 +xi-s +EJ-w Northing Basting Lacunae Longitude I/ 7Wellbore: MPU B-30 0.00 0.00 6023208.86 571962.88 70°za'25.298 N lag°24'43.916 W Plan: MPU B-30 wp02 REFERENCE INFORMATION Co-ordinate(N/E)Reference:Well Plan:MPU B-30,True North Vertical(TVD)Reference:MPB 30 A-Built fa 49.60usft(Innovation) Measured Depth Reference: MPB 30 A-Built©49.60usft(Innovation) Calculation Method:Minimum Curvature 5600— CASING DETAILS TVD TVDSS MD Size Name 4900.00 4850.40 6373.13 9-5/8 9 5/8" - 5200— 7500.00 7450.40 9718.92 7 7" - T M Azimuths to True North 4800— Magnetic North:18.08° Total Depth:9718.92'MD,7500'TVD _ Magnetic Field Strength:57564.1 snT Dip Angle:81.07° 4400— Date:10/27/2016 – End Dir:9140.54'MD,6956.5'TVD Model:BGGM2016 4000— MPU B-30 wp02 – Start Dir 5°/100':8665.38'MD,6555.87TVD – n5 tt� 3600—- 7" yo – b - MPB-30wp0ll ry5o - b 3200— OP - yo - 0i - o° - y5 2800— yo 4 - 5ry o - 5 00 2400— a'`' r + – 9 5/8" p5CP 40, t �e'• S • – b1�° J38j26, 'rib. US% S�d'I' 2000— �Q Jz J06., �'. – tha__ ° ` 983.1. 8168'712j ,,11` ''00 CID ";' r 8J8 J �6:,t, 6 03 1600— °� o '26s yo \ r O i n r 1200— 5° ry ‘ cP 5 'y t 4) 800— ryry r cV r N. r r 400- - e m ti~4� 0— 250 -400- -800— -1200— I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I i -5200 -4800 -4400 -4000 -3600 -3200 -2800 -2400 -2000 -1600 -1200 -800 -400 0 400 West(-)/East(+)(800 usft/in) • • Halliburton HALLIBU RTOFJ Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU B-30 Company: Hilcorp Energy Company TVD Reference: MPB 30 A-Built @ 49.60usft(Innovation) Project: Milne Point MD Reference: MPB 30 A-Built @ 49.60usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPU B-30 Survey Calculation Method: Minimum Curvature Wellbore: MPU B-30 Design: MPU B-30 wp02 xt 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 B Pad,TR-13-11 Site Position: Northing: 6,021,548.49usft Latitude: 70°28'8.986 N From: Map Easting: 571,775.55 usft Longitude: 149°24'49.895 W Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.55° Well Plan:MPU B-30 Well Position +NI-S 0.00 usft Northing: 6,023,208.86 usft Latitude: 70°28'25.298 N +El-W 0.00 usft Easting: 571,962.88 usft Longitude: 149°24'43.916 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 23.10 usft Wellbore MPU B-30 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2016 10/27/2016 18.08 81.07 57,564 Design MPU B-30 wp02 Audit Notes: II Version: Phase: PLAN Tie On Depth: 26.50 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 26.50 0.00 0.00 311.00 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/-S +E/-W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (°/100usft) (°1100usft) (°/100usft) (°) 26.50 0.00 0.00 26.50 -23.10 0.00 0.00 0.00 0.00 0.00 0.00 326.50 0.00 0.00 326.50 276.90 0.00 0.00 0.00 0.00 0.00 0.00 826.50 17.50 290.00 818.76 769.16 25.91 -71.20 3.50 3.50 0.00 290.00 1,387.26 43.75 311.33 1,298.32 1,248.72 186.01 -300.61 5.00 4.68 3.80 32.35 8,665.38 43.75 311.33 6,555.87 6,506.27 3,509.85 -4,079.66 0.00 0.00 0.00 0.00 9,140.54 20.00 310.00 6,956.50 6,906.90 3,672.92 -4,267.97 5.00 -5.00 -0.28 -178.87 9,718.92 20.00 310.00 7,500.00 7,450.40 3,800.08 -4,419.51 0.00 0.00 0.00 0.00 11/4/2016 1:56:08PM Page 2 COMPASS 5000.1 Build 81 • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU B-30 Company: Hilcorp Energy Company TVD Reference: MPB 30 A-Built @ 49.60usft(Innovation) Project: Milne Point MD Reference: MPB 30 A-Built @ 49.60usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPU B-30 Survey Calculation Method: Minimum Curvature Wellbore: MPU B-30 Design: MPU B-30 wp02 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NI-S +E/-W Northing Easting DLS Vert Section (usft) (^) (°) (usft) usft (usft) (usft) (usft) (usft) -23.10 26.50 0.00 0.00 26.50 -23.10 0.00 0.00 6,023,208.86 571,962.88 0.00 0.00 100.00 0.00 0.00 100.00 50.40 0.00 0.00 6,023,208.86 571,962.88 0.00 0.00 200.00 0.00 0.00 200.00 150.40 0.00 0.00 6,023,208.86 571,962.88 0.00 0.00 300.00 0.00 0.00 300.00 250.40 0.00 0.00 6,023,208.86 571,962.88 0.00 0.00 326.50 0.00 0.00 326.50 276.90 0.00 0.00 6,023,208.86 571,962.88 0.00 0.00 Start Dir 3.5°/100':326.5'MD,326.5'TVD 400.00 2.57 290.00 399.98 350.38 0.56 -1.55 6,023,209.41 571,961.32 3.50 1.54 500.00 6.07 290.00 499.68 450.08 3.14 -8.63 6,023,211.92 571,954.22 3.50 8.58 600.00 9.57 290.00 598.73 549.13 7.80 -21.42 6,023,216.45 571,941.39 3.50 21.28 700.00 13.07 290.00 696.77 647.17 14.51 -39.87 6,023,222.98 571,922.88 3.50 39.61 800.00 16.57 290.00 793.43 743.83 23.26 -63.90 6,023,231.50 571,898.76 3.50 63.49 826.50 17.50 290.00 818.76 769.16 25.91 -71.20 6,023,234.08 571,891.44 3.50 70.73 Start Dir 5°/100':826.5'MD,818.76'TVD , 900.00 20.70 295.57 888.21 838.61 35.30 -93.30 6,023,243.25 571,869.25 5.00 93.58 1,000.00 25.24 300.91 980.27 930.67 53.89 -127.56 6,023,261.51 571,834.82 5.00 131.63 1,100.00 29.93 304.69 1,068.88 1,019.28 79.06 -166.40 6,023,286.30 571,795.74 5.00 177.45 1,200.00 34.70 307.52 1,153.38 1,103.78 110.62 -209.51 6,023,317.43 571,752.33 5.00 230.69 1,300.00 39.52 309.74 1,233.11 1,183.51 148.31 -256.58 6,023,354.67 571,704.90 5.00 290.95 1,387.26 43.75 311.33 1,298.31 1,248.71 186.00 -300.60 6,023,391.93 571,660.52 5.00 348.90 End Dir :1387.26'MD,1298.32'TVD 1,400.00 43.75 311.33 1,307.52 1,257.92 191.82 -307.22 6,023,397.68 571,653.85 0.00 357.71 1,500.00 43.75 311.33 1,379.76 1,330.16 237.49 -359.14 6,023,442.84 571,601.49 0.00 426.86 1,600.00 43.75 311.33 1,451.99 1,402.39 283.16 -411.07 6,023,488.01 571,549.13 0.00 496.00 1,700.00 43.75 311.33 1,524.23 1,474.63 328.83 -462.99 6,023,533.17 571,496.78 0.00 565.15 1,800.00 43.75 311.33 1,596.47 1,546.87 374.50 -514.91 6,023,578.33 571,444.42 0.00 634.30 1,900.00 43.75 311.33 1,668.71 1,619.11 420.17 -566.84 6,023,623.49 571,392.06 0.00 703.45 1,915.08 43.75 311.33 1,679.60 1,630.00 427.05 -574.67 6,023,630.30 571,384.17 0.00 713.88 Base permafrost 2,000.00 43.75 311.33 1,740.94 1,691.34 465.84 -618.76 6,023,668.65 571,339.70 0.00 772.60 2,100.00 43.75 311.33 1,813.18 1,763.58 511.50 -670.68 6,023,713.81 571,287.35 0.00 841.75 2,200.00 43.75 311.33 1,885.42 1,835.82 557.17 -722.61 6,023,758.97 571,234.99 0.00 910.90 2,300.00 43.75 311.33 1,957.66 1,908.06 602.84 -774.53 6,023,804.13 571,182.63 0.00 980.05 2,400.00 43.75 311.33 2,029.90 1,980.30 648.51 -826.45 6,023,849.29 571,130.27 0.00 1,049.19 2,500.00 43.75 311.33 2,102.13 2,052.53 694.18 -878.38 6,023,894.45 571,077.92 0.00 1,118.34 2,600.00 43.75 311.33 2,174.37 2,124.77 739.85 -930.30 6,023,939.61 571,025.56 0.00 1,187.49 2,700.00 43,75 311.33 2,246.61 2,197.01 785.52 -982.22 6,023,984.77 570,973.20 0.00 1,256.64 2,800.00 43.75 311.33 2,318.85 2,269.25 831.19 -1,034.15 6,024,029.93 570,920.84 0.00 1,325.79 2,900.00 43.75 311.33 2,391.08 2,341.48 876.86 -1,086.07 6,024,075.09 570,868.48 0.00 1,394.94 3,000.00 43.75 311.33 2,463.32 2,413.72 922.53 -1,137.99 6,024,120.25 570,816.13 0.00 1,464.09 3,100.00 43.75 311.33 2,535.56 2,485.96 968.19 -1,189.92 6,024,165.41 570,763.77 0.00 1,533.23 3,200.00 43.75 311.33 2,607.80 2,558.20 1,013.86 -1,241.84 6,024,210.57 570,711.41 0.00 1,602.38 3,300.00 43.75 311.33 2,680.04 2,630.44 1,059.53 -1,293.76 6,024,255.73 570,659.05 0.00 1,671.53 3,400.00 43.75 311.33 2,752.27 2,702.67 1,105.20 -1,345.69 6,024,300.89 570,606.70 0.00 1,740.68 3,500.00 43.75 311.33 2,824.51 2,774.91 1,150.87 -1,397.61 6,024,346.06 570,554.34 0.00 1,809.83 3,600.00 43.75 311.33 2,896.75 2,847.15 1,196.54 -1,449.54 6,024,391.22 570,501.98 0.00 1,878.98 11/4/2016 1:56:08PM Page 3 COMPASS 5000.1 Build 81 • • Halliburton HALLIBURTDN Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU B-30 Company: Hilcorp Energy Company MND Reference: MPB 30 A-Built @ 49.60usft(Innovation) Project: Milne Point %MD Reference: MPB 30 A-Built @ 49.60usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPU B-30 Survey Calculation Method: Minimum Curvature Wellbore: MPU B-30 Design: MPU B-30 wp02 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NIS +EI-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 2,919.39 3,700.00 43.75 311.33 2,968.99 2,919.39 1,242.21 -1,501.46 6,024,436.38 570,449.62 0.00 1,948.13 3,800.00 43.75 311.33 3,041.22 2,991.62 1,287.88 -1,553.38 6,024,481.54 570,397.27 0.00 2,017.28 3,900.00 43.75 311.33 3,113.46 3,063.86 1,333.55 -1,605.31 6,024,526.70 570,344.91 0.00 2,086.42 4,000.00 43.75 311.33 3,185.70 3,136.10 1,379.21 -1,657.23 6,024,571.86 570,292.55 0.00 2,155.57 4,100.00 43.75 311.33 3,257.94 3,208.34 1,424.88 -1,709.15 6,024,617.02 570,240.19 0.00 2,224.72 4,200.00 43.75 311.33 3,330.18 3,280.58 1,470.55 -1,761.08 6,024,662.18 570,187.83 0.00 2,293.87 4,300.00 43.75 311.33 3,402.41 3,352.81 1,516.22 -1,813.00 6,024,707.34 570,135.48 0.00 2,363.02 4,400.00 43.75 311.33 3,474.65 3,425.05 1,561.89 -1,864.92 6,024,752.50 570,083.12 0.00 2,432.17 4,500.00 43.75 311.33 3,546.89 3,497.29 1,607.56 -1,916.85 6,024,797.66 570,030.76 0.00 2,501.32 4,600.00 43.75 311.33 3,619.13 3,569.53 1,653.23 -1,968.77 6,024,842.82 569,978.40 0.00 2,570.47 4,700.00 43.75 311.33 3,691.36 3,641.76 1,698.90 -2,020.69 6,024,887.98 569,926.05 0.00 2,639.61 4,800.00 43.75 311.33 3,763.60 3,714.00 1,744.57 -2,072.62 6,024,933.14 569,873.69 0.00 2,708.76 4,900.00 43.75 311.33 3,835.84 3,786.24 1,790.24 -2,124.54 6,024,978.30 569,821.33 0.00 2,777.91 5,000.00 43.75 311.33 3,908.08 3,858.48 1,835.90 -2,176.46 6,025,023.46 569,768.97 0.00 2,847.06 5,100.00 43.75 311.33 3,980.32 3,930.72 1,881.57 -2,228.39 6,025,068.62 569,716.61 0.00 2,916.21 5,200.00 43.75 311.33 4,052.55 4,002.95 1,927.24 -2,280.31 6,025,113.78 569,664.26 0.00 2,985.36 5,300.00 43.75 311.33 4,124.79 4,075.19 1,972.91 -2,332.23 6,025,158.94 569,611.90 0.00 3,054.51 5,400.00 43.75 311.33 4,197.03 4,147.43 2,018.58 -2,384.16 6,025,204.11 569,559.54 0.00 3,123.65 5,500.00 43.75 311.33 4,269.27 4,219.67 2,064.25 -2,436.08 6,025,249.27 569,507.18 0.00 3,192.80 5,600.00 43.75 311.33 4,341.50 4,291.90 2,109.92 -2,488.00 6,025,294.43 569,454.83 0.00 3,261.95 5,700.00 43.75 311.33 4,413.74 4,364.14 2,155.59 -2,539.93 6,025,339.59 569,402.47 0.00 3,331.10 5,749.64 43.75 311.33 4,449.60 4,400.00 2,178.26 -2,565.70 6,025,362.00 569,376.48 0.00 3,365.42 Schrader Bluff OA 5,800.00 43.75 311.33 4,485.98 4,436.38 2,201.26 -2,591.85 6,025,384.75 569,350.11 0.00 3,400.25 5,900.00 43.75 311.33 4,558.22 4,508.62 2,246.92 -2,643.78 6,025,429.91 569,297.75 0.00 3,469.40 6,000.00 43.75 311.33 4,630.46 4,580.86 2,292.59 -2,695.70 6,025,475.07 569,245.40 0.00 3,538.55 6,100.00 43.75 311.33 4,702.69 4,653.09 2,338.26 -2,747.62 6,025,520.23 569,193.04 0.00 3,607.70 6,200.00 43.75 311.33 4,774.93 4,725.33 2,383.93 -2,799.55 6,025,565.39 569,140.68 0.00 3,676.84 6,300.00 43.75 311.33 4,847.17 4,797.57 2,429.60 -2,851.47 6,025,610.55 569,088.32 0.00 3,745.99 6,373.13 43.75 311.33 4,900.00 4,850.40 2,463.00 -2,889.44 6,025,643.58 569,050.03 0.00 3,796.56 9 5/8" 6,400.00 43.75 311.33 4,919.41 4,869.81 2,475.27 -2,903.39 6,025,655.71 569,035.96 0.00 3,815.14 6,500.00 43.75 311.33 4,991.64 4,942.04 2,520.94 -2,955.32 6,025,700.87 568,983.61 0.00 3,884.29 6,600.00 43.75 311.33 5,063.88 5,014.28 2,566.61 -3,007.24 6,025,746.03 568,931.25 0.00 3,953.44 6,700.00 43.75 311.33 5,136.12 5,086.52 2,612.28 -3,059.16 6,025,791.19 568,878.89 0.00 4,022.59 6,800.00 43.75 311.33 5,208.36 5,158.76 2,657.95 -3,111.09 6,025,836.35 568,826.53 0.00 4,091.74 6,900.00 43.75 311.33 5,280.60 5,231.00 2,703.61 -3,163.01 6,025,881.51 568,774.18 0.00 4,160.88 7,000.00 43.75 311.33 5,352.83 5,303.23 2,749.28 -3,214.93 6,025,926.67 568,721.82 0.00 4,230.03 7,100.00 43.75 311.33 5,425.07 5,375.47 2,794.95 -3,266.86 6,025,971.83 568,669.46 0.00 4,299.18 7,200.00 43.75 311.33 5,497.31 5,447.71 2,840.62 -3,318.78 6,026,016.99 568,617.10 0.00 4,368.33 7,300.00 43.75 311.33 5,569.55 5,519.95 2,886.29 -3,370.70 6,026,062.16 568,564.75 0.00 4,437.48 7,400.00 43.75 311.33 5,641.78 5,592.18 2,931.96 -3,422.63 6,026,107.32 568,512.39 0.00 4,506.63 7,500.00 43.75 311.33 5,714.02 5,664.42 2,977.63 -3,474.55 6,026,152.48 568,460.03 0.00 4,575.78 7,600.00 43.75 311.33 5,786.26 5,736.66 3,023.30 -3,526.47 6,026,197.64 568,407.67 0.00 4,644.93 7,700.00 43.75 311.33 5,858.50 5,808.90 3,068.97 -3,578.40 6,026,242.80 568,355.31 0.00 4,714.07 11/4/2016 1:56:08PM Page 4 COMPASS 5000.1 Build 81 • • Halliburton H ALL I B U R TO N Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU B-30 Company: Hilcorp Energy Company TVD Reference: MPB 30 A-Built @ 49.60usft(Innovation) Project: Milne Point MD Reference: MPB 30 A-Built @ 49.60usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPU B-30 Survey Calculation Method: Minimum Curvature Wellbore: MPU B-30 Design: MPU B-30 wp02 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NI-S +E/-W Northing Easting DLS Vert Section (usft) (^) (°) (usft) usft (usft) (usft) (usft) (usft) 5,881,14 I 7,800.00 43.75 311.33 5,930.74 5,881.14 3,114.64 -3,630.32 6,026,287.96 568,302.96 0.00 4,783.22 7,900.00 43.75 311.33 6,002.97 5,953.37 3,160.30 -3,682.25 6,026,333.12 568,250.60 0.00 4,852.37 8,000.00 43.75 311.33 6,075.21 6,025.61 3,205.97 -3,734.17 6,026,378.28 568,198.24 0.00 4,921.52 8,100.00 43.75 311.33 6,147.45 6,097.85 3,251.64 -3,786.09 6,026,423.44 568,145.88 0.00 4,990.67 8,200.00 43.75 311.33 6,219.69 6,170.09 3,297.31 -3,838.02 6,026,468.60 568,093.53 0.00 5,059.82 8,300.00 43.75 311.33 6,291.92 6,242.32 3,342.98 -3,889.94 6,026,513.76 568,041.17 0.00 5,128.97 8,400.00 43.75 311.33 6,364.16 6,314.56 3,388.65 -3,941.86 6,026,558.92 567,988.81 0.00 5,198.12 8,449.06 43.75 311.33 6,399.60 6,350.00 3,411.05 -3,967.33 6,026,581.08 567,963.13 0.00 5,232.04 Base Colville 8,500.00 43.75 311.33 6,436.40 6,386.80 3,434.32 -3,993.79 6,026,604.08 567,936.45 0.00 5,267.26 8,600.00 43.75 311.33 6,508.64 6,459.04 3,479.99 -4,045.71 6,026,649.24 567,884.10 0.00 5,336.41 8,665.38 43.75 311.33 6,555.87 6,506.27 3,509.85 -4,079.66 6,026,678.77 567,849.86 0.00 5,381.62 Start Dir 5°/100':8665.38'MD,6555.87'TVD 8,700.00 42.02 311.28 6,581.23 6,531.63 3,525.40 -4,097.35 6,026,694.15 567,832.02 5.00 5,405.18 8,724.49 40.79 311.24 6,599.60 6,550.00 3,536.08 -4,109.53 6,026,704.71 567,819.74 5.00 5,421.38 Top HRZ 8,800.00 37.02 311.11 6,658.35 6,608.75 3,567.30 -4,145.22 6,026,735.58 567,783.76 5.00 5,468.79 8,850.83 34.48 311.01 6,699.60 6,650.00 3,586.81 -4,167.60 6,026,754.87 567,761.18 5.00 5,498.49 Top Kalubik Gamma Marker 8,900.00 32.02 310.90 6,740.72 6,691.12 3,604.48 -4,187.96 6,026,772.34 567,740.66 5.00 5,525.44 8,968.22 28.61 310.72 6,799.60 6,750.00 3,626.98 -4,214.02 6,026,794.59 567,714.39 5.00 5,559.87 Top Kuparuk D Shale 9,000.00 27.02 310.62 6,827.71 6,778.11 3,636.64 -4,225.27 6,026,804.14 567,703.05 5.00 5,574.70 9,100.00 22.03 310.22 6,918.66 6,869.06 3,663.56 -4,256.85 6,026,830.74 567,671.21 5.00 5,616.20 9,140.54 20.00 310.00 6,956.50 6,906.90 3,672.92 -4,267.97 6,026,840.00 567,660.00 5.00 5,630.73 End Dir :9140.54'MD,6956.5'TVD 9,143.84 20.00 310.00 6,959.60 6,910.00 3,673.65 -4,268.84 6,026,840.72 567,659.13 0.00 5,631.86 Top Kuparuk C Sand 9,200.00 20.00 310.00 7,012.37 6,962.77 3,685.99 -4,283.55 6,026,852.92 567,644.30 0.00 5,651.06 9,300.00 20.00 310.00 7,106.34 7,056.74 3,707.98 -4,309.75 6,026,874.65 567,617.89 0.00 5,685.26 9,400.00 20.00 310.00 7,200.31 7,150.71 3,729.96 -4,335.95 6,026,896.38 567,591.48 0.00 5,719.46 9,452.45 20.00 310.00 7,249.60 7,200.00 3,741.49 -4,349.69 6,026,907.77 567,577.63 0.00 5,737.39 I Top KuparukA Sands 9,500.00 20.00 310.00 7,294.28 7,244.68 3,751.95 -4,362.15 6,026,918.10 567,565.07 0.00 5,753.65 9,600.00 20.00 310.00 7,388.25 7,338.65 3,773.93 -4,388.35 6,026,939.83 567,538.66 0.00 5,787.85 9,700.00 20.00 310.00 7,482.22 7,432.62 3,795.92 -4,414.55 6,026,961.56 567,512.25 0.00 5,822.05 9,718.92 20.00 310.00 7,500.00 7,450.40 3,800.07 -4,419.51 6,026,965.67 567,507.26 0.00 5,828.52 Total Depth:9718.92'MD,7500'TVD-7" 11/4/2016 1:56:08PM Page 5 COMPASS 5000.1 Build 81 • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU B-30 Company: Hilcorp Energy Company TVD Reference: MPB 30 A-Built @ 49.60usft(Innovation) Project: Milne Point MD Reference: MPB 30 A-Built @ 49.60usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPU B-30 Survey Calculation Method: Minimum Curvature Wellbore: MPU B-30 Design: MPU B-30 wp02 " Targets Target Name -hit/miss target Dip Angie Dip Dir. TVD +N/-S +E/-W Northing Easting -Shape (°) (°) (usft) (usft) (uaft) (usft) (usft) MPB-30wp01 0.00 0.00 6,956.50 3,672.92 -4,267.97 6,026,840.00 567,660.00 -plan hits target center -Point L Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 9,718.92 7,500.00 7" 7 8-1/2 6,373.13 4,900.00 9 5/8" 9-5/8 12-1/4 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology (°) (1 9,452.45 7,249.60 Top Kuparuk A Sands 0.00 5,749.64 4,449.60 Schrader Bluff OA 0.00 1,915.08 1,679.60 Base permafrost 0.00 9,143.84 6,959.60 Top Kuparuk C Sand 0.00 8,724.49 6,599.60 Top HRZ 0.00 8,968.22 6,799.60 Top Kuparuk D Shale 0.00 8,449.06 6,399.60 Base Colville 0.00 8,850.83 6,699.60 Top Kalubik Gamma Marker 0.00 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/.S +E/-W (usft) (usft) (usft) (usft) Comment 326.50 326.50 0.00 0.00 Start Dir 3.5°/100':326.5'MD,326.5'TVD 826.50 818.76 25.91 -71.20 Start Dir 5°/100':826.5'MD,818.76'TVD 1,387.26 1,298.31 186.00 -300.60 End Dir :1387.26'MD,1298.32'TVD 8,665.38 6,555.87 3,509.85 -4,079.66 Start Dir 5°/100':8665.38'MD,6555.87'TVD 9,140.54 6,956.50 3,672.92 -4,267.97 End Dir :9140.54'MD,6956.5'TVD 9,718.92 7,500.00 3,800.08 -4,419.51 Total Depth:9718.92'MD,7500'TVD 11/4/2016 1:56:08PM Page 6 COMPASS 5000.1 Build 81 S 0 ki i-4 Hilcorp Energy Company ,, Milne Point MPtBPad Plan: MPU B-30 MPU B-30 ;ry MPU B-30 wp02 Sperry Drilling Services Clearance Summary Anticollision Report 04 November,2016 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: M Pt B Pad-Plan:MPU B-30-MPU B-30-MPU B-30 wp02 Well Coordinates: 6,023,208.86 N,571,962.88 E (70°28'25.30"N,149°24'43.92"W) Datum Height: MPB 30 A-Built @ 49.60usft(Innovation) Scan Range:0.00 to 9,718.92 watt.Measured Depth. Ae . Scan Radius is 1,169.24 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build: 81 Scan Type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services al • HALLIBURTON Project: Milne Point REFERENCE INFORMATION WELL DETAILS:Plan:MPU B-30 NAD 1927(NADCONCONUS) Alaska Zone 04 Site: M Pt B Pad Coordinate(N/E)Reference:Well Plan:MPU B-30,True North Ground Level: 23.10 Well: Plan:MPU B-30 Vertical(IVD)Reference:MPB3OA-euin/849.60uan(nnovation) 4168 +E/-w Northing Fasting Letittude LongitudeSF rrrvv Ori111rtr{ Measures Depth Reference MPB3oA-Bultt�a9.611usn(Innovation) 4168 0.00 6023208.86 571962.88 7W 28'25298N 149°24'43.916W Wellbore: MPU B-30 CzkuWtlon Method:Minimum Curvature Plan: MPU B-30 wp02II r GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference SURVEY PROGRAM 28.50 TO 9718.92 Fi 1 I C O i"J) Dote:2016-10-2770000:00 Validated.yes Version:Ladder/S.F. Plots _ CASING DETAILS Depth From Depth To Survey/Plan Tool 26.50 800.00 MPU 8-30 wp02 SRG-SS TVD TVDSS MD Size Name 800.00 6373.00 MPU 8-30 wp02 MWD+IFR2+MS+e09 490000 4850.40 6373.13 9-5/8 9 5/9 6373.00 9718.91 MPU B-30wp02 MWD+IFR2+MS+eag 7500.00 7450.40 9718.92 7 7" 150.00— I' - - 7c 11l MPB-08 w _ ." .rr,•1 7 I 'I 11 0120.00 1 O• - c - ___/MI;r i. I l • .� „„1.03 c 90.00 � NI __ 1 I 00- 1 N r . N60.00 ' " MP9-23- MP wp02 0) N C' 1 O 0 0.00 illi 1Il VIII 1111 1111 1111 1111 1111 1111 1111 1111 111 111111 11111111111111 11111111 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 Measured Depth(1500 usft/in) ,- 6.00—- .._ III. I_. _ i ,- 4.50— — O ',. U of C �' illiii. -.--- ..1 3.00 ',. a - N W _Collision Avoidance Req. 1.50—No-Go Zone-Stop Drillhry 0.00- . 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 ! 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 TI 1 1 1 1 1 1 it r 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 Measured Depth • • Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan: MPU B-30-MPU B-30 wp02 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: M Pt B Pad-Plan:MPU B-30-MPU B30-MPU B-30 wp02 Scan Range: 0.00 to 9,718.92 usft.Measured Depth. Scan Radius is 1,169.24 usft.Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft M Pt B Pad MPB-02-MPB-02-MPB-02 26.50 91.31 26.50 90.51 22.90 113.637 Centre Distance Pass- MPB-02-MPB-02-MPB-02 350.00 92.06 350.00 88.50 346.18 25.858 Ellipse Separation Pass- MPB-02-MPB-02-MPB-02 675.00 119.11 675.00 112.36 668.29 17.651 Clearance Factor Pass- MPB-02-Plan MPB-02A-MPB-02Awp03 336.68 91.29 336.68 88.87 333.44 37.742 Centre Distance Pass- MPB-02-Plan MPB-02A-MPB-02A wp03 350.00 91.30 350.00 88.83 346.91 36.966 Ellipse Separation Pass- MPB-02-Plan MPB-02A-MPB-02Awp03 625.00 107.18 62500 103.40 619.24 28.373 Clearance Factor Pass- MPB-05-MPB-05-MPB-05 330.50 225.60 330.50 221.10 340.60 50.173 Centre Distance Pass- MPB-05-MPB-05-MPB-05 350.00 225.68 350.00 220.96 360.43 47.852 Ellipse Separation Pass- MPB-05-MPB-05-MPB-05 825.00 306.24 825.00 296.14 806.32 30.324 Clearance Factor Pass- MPB-05-MPB-05A-MPB-05A 330.50 225.60 330.50 221.10 340.60 50.173 Centre Distance Pass- MPB-05-MPB-05A-MPB-05A 350.00 225.68 350.00 220.96 360.43 47.852 Ellipse Separation Pass- MPB-05-MPB-05A-MPB-05A 825.00 306.24 82500 296.14 806.32 30.324 Clearance Factor Pass- MPB-06-MPB-06-MPB-06 563.10 24.73 563.10 17.83 571.55 3.585 Centre Distance Pass- MPB-06-MPB-06-MPB-06 575.00 24.80 575.00 17.76 583.28 3.524 Ellipse Separation Pass- MPB-06-MPB-06-MPB-06 625.00 26.44 625.00 18.80 633.05 3.460 Clearance Factor Pass- MPB-07-MPB-07-MPB-07 1,749.06 185.21 1,749.06 164.21 1,664.66 8.822 Clearance Factor Pass- MPB-08-MPB-08-MPB-08 1,769.90 454.64 1,769.90 430.95 1,564,18 19.193 Centre Distance Pass- MPB-08-MPB-08-MPB-08 5,275.00 592.93 5,275.00 364.67 5,084.79 2.598 Ellipse Separation Pass- MPB-08-MPB-08-MPB-08 6,325.00 707.25 6,325.00 406.15 6,091.16 2.349 Clearance Factor Pass- MPB-09-MPB-09-MPB-09 1,310.50 85.23 1,310.50 70.42 1,293.79 5.754 Clearance Factor Pass- MPB-10-MPB-10-MPB-10 1,210.90 90.15 1,210.90 79.00 1,196.95 8.086 Ellipse Separation Pass- MPB-10-MPB-10-MPB-10 1,250.00 91.21 1,250.00 79.84 1,234.30 8.025 Clearance Factor Pass- MPB-11-MPB-11-MPB-11 1,340.92 286.84 1,340.92 271.44 1,273.13 18.621 Centre Distance Pass- MPB-11-MPB-11-MPB-11 1,350.00 286.90 1,350.00 271.38 1,279.85 18.485 Ellipse Separation Pass- MPB-11-MPB-11-MPB-11 1,475.00 300.22 1,475.00 283.20 1,370.83 17.639 Clearance Factor Pass- MPB-15-MPB-15-MPB-15 350.00 262.97 350.00 259.41 360.27 73.795 Centre Distance Pass- MPB-15-MPB-15-MPB-15 400.00 263.24 400.00 259.19 410.16 65.085 Ellipse Separation Pass- MPB-15-MPB-15-MPB-15 900.00 286.81 900.00 277.84 915.06 31,977 Clearance Factor Pass- 04 November,2016- 13:53 Page 2 of 6 COMPASS • ! Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan: MPU B-30-MPU B-30 wp02 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: M Pt B Pad-Plan:MPU B-30-MPU B-30-MPU B-30 wp02 Scan Range: 0.00 to 9,718.92 usft.Measured Depth. Scan Radius is 1,169.24 usft.Clearance Factor cutoff Is Unlimited.Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft MPB-17-MPB-17-MPB-17 128.58 199.97 128.58 198.12 132.48 107.967 Centre Distance Pass- MPB-17-MPB-17-MPB-17 375.00 201.48 375.00 196.67 379.90 41.884 Ellipse Separation Pass- MPB-17-MPB-17-MPB-17 825.00 249.78 825.00 239.49 823.62 24271 Clearance Factor Pass- MPB-18-MPB-18-MPB-18 3127.60 139.74 3,127.60 97.12 3,008.72 3279 Centre Distance Pass- MPB-18-MPB-18-MPB-18 3,250.00 151.38 3,250.00 85.91 3,116.06 2.312 Ellipse Separation Pass- MPB-18-MPB-18-MPB-18 3,350.00 174.23 3,350.00 94.64 3,205.32 2.189 Clearance Factor Pass- MPB-22-MPB-22-MPB-22 328.64 205.65 328.64 201.14 338.33 45.637 Centre Distance Pass- MPB-22-MPB-22-MPB-22 350.00 205.72 350.00 200.98 359.86 43.382 Ellipse Separation Pass- MPB-22-MPB-22-MPB-22 850.00 247.90 850.00 237.24 878.29 23.253 Clearance Factor Pass- MPB-22-MPB-22A-MPB-22A 328.64 205.65 328.64 201.14 338.33 45.637 Centre Distance Pass- MPB-22-MPB-22A-MPB-22A 350.00 205.72 350.00 200.98 359.86 43.382 Ellipse Separation Pass- MPB-22-MPB-22A-MPB-22A 850.00 247.90 850.00 237.24 878.29 23.253 Clearance Factor Pass- MPB-22-MPB-22APB1-MPB-22APB1 328.64 205.65 328.64 201.14 338.33 45.637 Centre Distance Pass- MPB-22-MPB-22APB1-MPB-22APB1 350.00 205.72 350.00 200.98 359.86 43.382 Ellipse Separation Pass- MPB-22-MPB-22APB1-MPB-22APB1 850.00 247.90 850.00 237.24 878.29 23253 Clearance Factor Pass- MPB-23-MPB-23-MPB-23 874.67 62.34 874.67 53.78 875.56 7.285 Centre Distance Pass- MPB-23-MPB-23-MPB-23 875.00 62.34 875.00 53.78 875.89 7283 Ellipse Separation Pass- MPB-23-MPB-23-MPB-23 925.00 63.46 925.00 54.56 924.83 7.132 Clearance Factor Pass- MPB-25-MPB-25-MPB-25 100.00 231.52 100.00 230.35 104.20 198.556 Centre Distance Pass- MPB-25-MPB-25-MPB-25 225.00 231.88 225.00 229.89 227.78 116.113 Ellipse Separation Pass- MPB-25-MPB-25-MPB-25 2,775.00 1,161.55 2,775.00 1,112.00 2,625.96 23.441 Clearance Factor Pass- MPB-27-MPB-27-MPB-27 100.00 121.74 100.00 119.89 107.30 65.695 Centre Distance Pass- MPB-27-MPB-27-MPB-27 350.00 123.64 350.00 119.70 357.33 31.379 Ellipse Separation Pass- MPB-27-MPB-27-MPB-27 625.00 137.45 625.00 131.54 634.34 23.264 Clearance Factor Pass- MPB-29-MPB-29-MPB-29 26.50 171.67 26.50 170.75 34.43 187.816 Centre Distance Pass- MPB-29-MPB-29-MPB-29 375.00 172.18 375.00 167.59 384.15 37.521 Ellipse Separation Pass- MPB-29-MPB-29-MPB-29 5,700.00 316.26 5,700.00 201.57 7,285.44 2.758 Clearance Factor Pass- Plan:MPU B-31-MPU 8-31-MPU 8-31 wp02 325.00 146.64 325.00 143.30 324.70 43.904 Centre Distance Pass- Plan:MPU B-31-MPU B-31-MPU B-31 wp02 350.00 146.74 350.00 143.17 349.70 41.146 Ellipse Separation Pass- Plan:MPU B-31-MPU 8-31-MPU 8-31 wp02 800.00 193.12 800.00 185.21 806.87 24.417 Clearance Factor Pass- 04 November,2016- 13:53 Page 3 of 6 COMPASS • al Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan: MPU B-30-MPU B-30 wp02 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: M Pt B Pad-Plan:MPU B-30-MPU 8-30-MPU B-30 wp02 Scan Range: 0.00 to 9,718.92 usft.Measured Depth. Scan Radius is 1,169.24 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (ash) (usft) (usft) (usft) usft Plan:MPU B-32 Prod-MPB-32 NC Prod-MPB-32 wp 250.36 30.26 250.36 28.06 250.16 13.755 Centre Distance Pass- Plan:MPU B-32 Prod-MPB-32 NC Prod-MPB-32 wp 325.00 30.46 325.00 27.76 324.60 11.270 Ellipse Separation Pass- Plan:MPU B-32 Prod-MPB-32 NC Prod-MPB-32 wp 450.00 34.94 450.00 31.42 448.86 9.921 Clearance Factor Pass- Plan:MPU 8-33 In)-MPB-33 NC In)-MPB-33 wp03 455.58 58.43 455.58 53.90 458.31 12.893 Centre Distance Pass- Plan:MPU 8-33 In)-MPB-33 NC In)-MPB-33 wp03 475.00 58.50 475.00 53.79 477.90 12.424 Ellipse Separation Pass- Plan:MPU 8-33 In)-MPB-33 NC In)-MPB-33 wp03 5,725.00 218.95 5,725.00 107.08 6,900.08 1.957 Clearance Factor Pass- Survey fool pronram From To Survey/Plan Survey Tool (usft) (usft) 26.50 800.00 MPU B-30 wp02 SRG-SS 800.00 6,373.00 MPU B-30 wp02 MWD+IFR2+MS+sag 6,373.00 9,718.91 MPU B-30 wp02 MWD+IFR2+MS+sag Ellipse error terms are correlated across survey tool tie-on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor=Distance Between Profiles/(Distance Between Profiles-Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 04 November,2016- 13:53 Page 4 of 6 COMPASS ,11111 • • TRANSMITTAL LETTER CHECKLIST WELL NAME: in13k 3'c PTD: a►(ci — /S-3 /Development Service Exploratory Stratigraphic Test Non-Conventional FIELD: 11/1h.. 7ti r f POOL: t {+j(l� To:nT gRi ,') U Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - - ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10'sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non-Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of 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 • 1110 r� To 0 O a) fz , N N_ a) o ui C, - C 0} Q a , a , 3. C. C O. j; O Z. O E. fU , 0 a). O y. n -c �. �. a 0. w Cn Q P '0 O O. c a) c. c •�� C O. a CJ cCL y. CO o+ C .01 y 0 C n a a o 3, .0 c en v 0, os 4 ,n, 2a O, a o, >. II), c 0, a) a , a (.0, co, , a), )n �, a ai N. 2, 0, , o, Q. a TY 0. _. g CO �. p f3 N 3, v) CO rn o , Hi , 3. o . N. o. 4 aci,o o, io. to y.E, co, N Q n. y. 0. C. .O E, Z. c. N. ai a), c, a), �. o, a, y. , > 0O' m 3. y. 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