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219-111
1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: FCO/Install Screens 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 14,120 feet NA feet true vertical 3,637 feet NA feet 4,202, Effective Depth measured 14,115 feet 4,775 and 4,829 feet true vertical 3,637 feet 3,720, 3,826 and 3,830 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 4,827' 3,830' 7" Retrievable Packers and SSSV (type, measured and true vertical depth) and SLZXP LTP NA See Above NA 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: SAME 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title:Wells Manager Contact Phone: 5,410psi NA NA 5,750psi 7,240psi NA 4,942' 3,838' Burst Collapse NA 3,090psi Slotted Liner 4,784' 9,345' Casing Structural 3,826' 3,637' 4,784' 14,120' 4,942' 80'Conductor Surface Tie-Back 20" 9-5/8" 80' measured TVD 7" 6-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-111 50-029-23645-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0025514, ADL0355023 MILNE POINT / SCHRADER BLUFF OIL MILNE PT UNIT M-22 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 871 Gas-Mcf MD 3433 Size 80' 310 2932157 221 34046 344 323-436 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 19 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Todd Sidoti todd.sidoti@hilcorp.com 907-777-8443 N/A Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 8:13 am, Nov 16, 2023 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.11.15 16:14:40 - 09'00' Taylor Wellman (2143) WCB 4-29-2024 DSR-11/16/23 RBDMS JSB 111623 Well Name Rig API Number Well Permit Number Start Date End Date MP M-22 Thunderbird 50-029-23645-00-00 219-111 9/17/2023 10/16/2023 9/20/2023 - Wednesday MU Landing Joint and function test brakes for 30 mins up to 100K. Inspect brakes. No issues or further adjustment needed. Rig back to operable status. Test BOPE 250/2500 psi per Sundry. Zero Failures. 5hr Test Time. Tested w/ 2.-7/8" & 4-1/2" Test Joints. Rig down test equipment. Pull TWC & MU Landing Joint. Rig up Eline & Welltec. MU landing joint, BOLDS. Pull Tbg in tension 9k over (70k) and set in slips. Rig up Eline & Welltec w/ pump-in sub & packoff on landing joint. RIH w/ Welltec 2-3/8" Mechanical Cutter. Log up and cut Tbg @ 4186' (Ref Tbg Tally 11/23/19) depth. Pull Tbg free @ 61K (~4K over) RD E- line. Bullhead IA w/ 78 bbls tand 80 bbls down Tbg. Pull Tbg hanger to floor and terminate I-wire. Establish continuous hole fill at 1.25 bbl/hr. Install Washington Head. Obtain nubbins for semi-flush joint connections. TB elevators sticking severly on upset. Clean and Inspect. Found broken bolt in setting plate. Stby for replacements from YellowJacket. Start pulling Tbg w/ I- wire. Hilcorp Alaska, LLC Weekly Operations Summary Continue Standby while waiting on brake parts. Repaired nd replaced hand rails. Service rig. CanRig troubleshoot and repair Operator's monitor. Install replacement brake parts and adjust brakes. PU blocks. Function test and inspect brake and drawworks. Inspect drill line. Tbg and IA on a vac. Bullhead IA w/ 110 bbls 1% KCL 4 bpm @ 145 psi. Bullhead Tbg w/ 80 bbls 4 bpm 130 psi. TBg and IA on a vac. Open blinds to MU landing joint to pull and test brakes. Install replacement turnbuckle end. Function test brake actuation. Straighten loose drill line wraps on drum and lift blocks and test brakes while blocks were secured w/ tugger line. Secure blocks in derrick. Stop hole fill. IA Vac. Tbg Zero. Bullhead Tbg w/ 100 bbls 1% KCL 4.4 bpm @ 180 psi. Tbg and IA on a vac. Remove landing joint and close blind rams. Set TWC, Test Hanger Seals to 1000psi - Good Test. Pull TWC. Close blind rams. Set TWC and test hanger seal to 1000 psi 5 mins. Good test. Pull TWC close blinds. Clean draw works and brake assy for repair and inspection. Send AOGCC BOP test notification for early test @ 10 pm. Continue Stby for repairs. 9/19/2023 - Tuesday 9/17/2023 - Sunday BOP Function Test Complete. All rams and HCR functioning correctly @ koomey and remote panel. Test BOPE to 250/2500 psi per Sundry. Witness waived by Brian Bixby 9/15/23. Zero Failures. 4hr Test Time. Rig down test equipment. Prep rig floor to pull tubing. Verify XO below TIW for Floor Valve. Pull CTS Plug. Bullhead 83 bbls source water down IA. Bullhead 152 bbls source water down Tbg. Tbg/IA on Vac. MU Landing Jt, BOLDS. Pull hanger free at 70k. Work pipe up to 145k to attempt to shear/release packer. After ~40 cycles, the blocks were being slacked of from 131k, the driller braked while slacking off @ 96k, and 58k. on the last application of the brakes, the anchor side of one brake band broke reducing the braking capability at least 50%. The blocks continued to travel down an additional 2' which landed the Tbg hanger. The elevators stopped at a coupling on the landing joint, The bales leaned over to 45 deg, and the blocks topped tilted @ ~45 degress. The bales made contact with the handrails damaging two of them. Previously installed FOSV was closed. Landing joint inspected to confirm no integrity issues. The LDS were run in on the hanger to full engagement, blocks we secured w/ two air tuggers and contant hole fill started down the IA @ 1.25 bpm. Incident reported to Hilcorp and TB Safety and Wells Foreman. 9/18/2023 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP M-22 Thunderbird 50-029-23645-00-00 219-111 9/17/2023 10/16/2023 Hilcorp Alaska, LLC Weekly Operations Summary MU BHA #1 Baker 5-3/4" overshot, 4-3/4" safety joint, Rattler, Bumper sub, Oil Jar, (6) 4-3/4" DC's, and Accelerator OAL 261'. Swap out tongs, Run in w/ 2-7/8" WS. Tag @ 4197.8' ORKB. Getting just a friction bite w/ grapple or sticking in fill. Slipping off the fish @ 64K overpull and less. Pump and work down 2'to 4199.5'w/ same result. Pumping ineffective due to most of the flow exiting drain sub on Rattler. POH and start laying down BHA. Back-ups failed on McCoy tongs. No heads and dies to break 4-3/4'BHA w/ back-up tongs. Call out and rig up GBR tongs. Maintain continuous hole-fill @ 1.1 bpm. 9/23/2023 - Saturday Stby for GBR after back-ups on McCoy tongs failed. RU GBR. Laydown BHA #1 Overshot Assy. MU BHA #2 6" OD x 12.5' Shoe/ washpipe extension, 4-3/4 Bumper Sub, Oil Jars OAL 48'. Tag @ 4195'. Start pump to wash over. ROD seal failure. Replace all. 6.5 hrs NPT. 4.5 hrs actual NPT due to RU power swivel during rig repair. Bullhead down WS @ 4.2 bpm @ 550 psi. HCR close to prevent potential returns. UP/Dn Wt rotating 33/26K. Wash/rotate down 7.2' to top of packer 4202.2'. 2k down and ~500 Ft/Lbs extra torque. PU and continue pumping and working down length of stub to same depths. pumped additonal 156 bbls after tagging top of packer to push any solids to below 8500' to clean out w/ VACS tool. Tie-back swivel and TOH to derrick. On continuous hole fill 1.1 bpm. 9/24/2023 - Sunday Cont TOH w/ BHA # 2 Washpipe/Shoe assy after washing over tbg stub to top of packer. RD TB Tbg tongs and RU GBR. D BHA #2, MU BHA #3 Itco Spear w/ 3.947" nominal grapple, 4-3/4 Bumper sub, Oil Jar, (6) DC's. Accelerator OAL 236.56'. Cut and slip drill line due to broken strands. 8.5 Hrs NPT. Up/Dn Wts 43/30K Tag top of stub @ 4195' unable to latch up. Pump and wash down @ 4.5 bpm and index to multiple orientations. Unable to latch up. Order overshot w/ hollow mill and POH to derrick to PU overshot w/ hollow mill. 9/21/2023 - Thursday Completed pulling 4-1/2 completion recovered 60 full, 5 half clamps and 125 pins. Cleanly cut pup joint length recovered= 1.86' Leaving 7.2' Tbg stub. Top o stub 4186.25'. Photo's taken and sent to Todd Sidoti, Cleared floor, prep for MU of Baker fishing assembly. Generator for Koomy Unit went down with an error code at 3 PM. Replacement on loaction, wired in, and wrangler and pipe racks back in position @ 9:30 PM. Stby 1 hr 45 mins for Baker Rattler (fishing hand suggested this addition to BHA). Start to MU BHA #1 9/22/2023 - Friday Completed pulling 4-1/2 completion recovered 60 full, 5 half clamps and 125 pins. Cleanly cut pup joint length recovered= 1.86' Leaving 7.2' Tbg stub. Top o stub 4186.25'. Well Name Rig API Number Well Permit Number Start Date End Date MP M-22 Thunderbird 50-029-23645-00-00 219-111 9/17/2023 10/16/2023 Hilcorp Alaska, LLC Weekly Operations Summary Continue FCO w/ Baker VACS tool from 4618' (started @ 4187' end @ 5602') POOH with WS and BHA #5, pulling slow wet using mud bucket, well on 39 BPH losses, @ 5 stands in hole hit sand in tubing compacted had to beat out of tubing, ND washington head, install Test plug, Prep for BOPE test, obtain a passing shell test, Perform Bope test with 2 7/8" & 4.5" test subs (witness waived by AOGCC inspector Guy Cook) currenty on test 4 at time of report. 9/28/2023 - Thursday Completed BOPE testing with 2 7/8" & 4.5" test subs 250 psi low/2500 psi high, RD test equip, pull test plug, install 9" ID wear bushing, NU washington head, PU/MU Bha #6 and run in hole, Start Cleaning @ 5585' Pumping 4 BPM reciprocating every 10 Jts, Jnt # 250 in hole at time of report end. 9/29/2023 - Friday Continue to cleanout from 7736' 4 BPM @ 850 psi, 1 BPM losses, reciprocate every 10 Jts, obtain new ICP every 1000', Cleaned to 8843' started getting 1:1 returns indicating full tail pipe, POOH with string Hit Compacted sand in tail W/ 34 joints in hole, beat sand out of tail pipe as pulling, Cleaned sand & fluid out of BB tank 35 BBLS,Inspect flapper valves and begin to run back in hole with same configuration. 9/25/2023 - Monday OOH w/ BHA #3 after failing to engage tbg stub w/ spear. RU GBR. LD BHA #3 and MU BHA #4 Overshot w/ 4.8' extension and 6'OD x 4.50'ID dressing shoe, 4-3/4 Bumper sub, Oil Jar, (6) DC's. Accelerator OAL 236.75'. RD GBR and RU Tbg tongs and TIH.Up/down weights 45k-lbs/32k-lbs. Establish circulation. 4 bpm/517 psi and rotation, 35 RPM Slowly move down... 4193.5' started to see reactive roque. 200-1800 over free spin. stop rotation at 4195.5' contined down to 4198' Started taking weight 10k-lbs down weight. PU 75k-lbs/ 30k-lbs over bleed jars and pull up to 100k-lbs/ 55k-bls over. Pull up 110kk-lbs / 65k- lbs over and let jars go off. SD to neutral and prepair to LD swivel. Flow check returns slowed but kept flowing. Standpipe @ 150 psi. Closed bag lined up down work string and bullheaded to top slot in 6-5/8" LNR Bullheaded down backside of work string and swept Csg to top slot in 6-5/8" LNR. PKR moved up hole 17' after pumping and released more gas. Messed around trying to get it circ'd out. Finally stopped and let gas migrate up hole leaving the backside open for one hour. Able to finally get swivel off and FOSV on then start TOOH. 9/26/2023 - Tuesday POH slowly to prevent swabbing. Stop 3 Stds from surface w/ end of Tbg @ ~1100¿. SI and bullhead 300 bbls 3.8 bpm @ 850 psi. Sent 24 hr AOGCC notice for weekly BOP test 03:40 Hrs. Pull last 3 Stds and RU GBR and LD DC's and LD BHA #4. LD PKR and 15 jt's of 4-1/2" Hydril 521 Tbg. Clear floor and clean up. TIH w/ BHA #5 3-3/4" Mule shoe, ~2000' of 2-7/8" PH-110. Stop at stand # 33 and split. 65 Jt's in hole. Clean crude from Pits and UR tanks. MU head pin and circulate to clean crude from upper wellbore. MU 6.0' pup on top of Baker 5-3/4" VACS and Jt #66 continue in hole. Stop @ 4187'and pick up power swivel. Static losses ~6 bpm. Start FCO/wash down 4 bpm @ 745 psi. Losing ~1 bpm while circulating. Cleanout to 4618' (Target Depth ~5458') Up/Dn Wts 42/27k. 4 bpm @ 780 psi. 9/27/2023 - Wednesday Cleanout to 4618' (Target Depth ~5458') PKR moved up hole 17' after pumping and released more gas Well Name Rig API Number Well Permit Number Start Date End Date MP M-22 Thunderbird 50-029-23645-00-00 219-111 9/17/2023 10/16/2023 Hilcorp Alaska, LLC Weekly Operations Summary 10/5/2023 - Thursday Rig is currently on Non Productive Time waiting on replacement part to repair traveling block. CHF and monitor well, 21-22 BPH losses. Repair block and install on rig floor. TOH w/BHA #7, RBWS (14 stands & single). L/D Baker VACS BHA and continue TOH w/2-7/8" work string, found compacted sand in recovery string 4 joints still in hole. Beat sand out of joints and load in trip tank for Cusco. ND BIW head, Retrieve wear bushing, Set test plug and prep for BOPE test, Begin BOPE shell test ( witness waived by AOGCC rep Kam St John). 10/6/2023 - Friday Completed BOPE test w/2-7/8" & 4-1/2" test joints to 2,500 psi as per sundry (Witness waived by AOGCC Inspector: Kam St John). Pulled test plug. Set Wear bushing (9" ID). Discuss plan forward w/OE. M/U & TIH BHA #8 - MS, Dual Flapper Valves, 32 stands 2-7/8" PH6, Baker VACS. Continue TIH w/BHA #8 on 2-7/8" PH6 stands. @7,993' EOT 10K dwn/60k up cant slide any longer, LD 30 Jts 2-7/8" PH-6, TIH w/ 15 stands 2-7/8" PH-6, Begin to RU Power Swivel. Continue to change out BIW head, Resume POOH W/ 2-7/8" work string VACS tool 1 Jt below surface, found a problem with the blocks on the rig requireing parts to be sent from Lower 48, while keeping hole full with 21 BPH losses had a spill of 210 Gal sea water to pad, report and clean spill per MPU enviromental rep, spread out lower completion to prep and tally, 21 BPH losses currently. 10/3/2023 - Tuesday Rig is Currently down waiting on parts, monitor well losses @ 21-22 BPH losses, spread out lower completion, safety training 10/4/2023 - Wednesday Rig is currently on Non Productive Time waiting on replacement part to repair traveling block. Part will be on the slope first flight 10/5/23. Sent 24 hr BOPE test notification to AOGCC and discussed rig status and plan forward w/inspector. Continue CHF and monitor well, 21-22 BPH losses. 9/30/2023 - Saturday Continue to trip in hole from derrick with BHA#7 Vacs assembly, ND wahington head, NU BIW, RU swivel, 3.5" rental work string had obstructions inside, wait on clean pipe to arrive, Prep and Tally new pipe, continue to clean out from 8935', at time of report end tail depth @ 9373', ICP- 1 BPM @ 78 psi, Up wt 51k down wt 32k @ 10 RPM 24 BPH losses. 10/1/2023 - Sunday Continue to Cleanout liner with split string 2.875" and 3.5" PH-6 P-110 from 8935', getting ICP every 1000', reciprocating every 10 Jts, rotating at 10 RPM, 4 BPM @ 1000 psi free torque 2500 lb-ft, pump 50 BBL pill of safelube, made it to 10467' feels like driving pipe in hole POOH with 3.5"Work string, Change over to 2-7/8" equipment, change out BIW head. 10/2/2023 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP M-22 Thunderbird 50-029-23645-00-00 219-111 9/17/2023 10/16/2023 Hilcorp Alaska, LLC Weekly Operations Summary 10/10/2023 - Tuesday Continue RIH w/3-1/2" JFE Bear screened liner completion as per run tally. Ran 150 straight screens in hole then alternate between screens & blanks up to 6-5/8" Liner Pkr Assy. 69 joints of 3-1/2" PH6 in hole, PUW 72k, SOW 24k, 134 Joints in hole = 9,756.29' ORKB at bullet nose, PUW 82K, SOW 9K , 13BPH losses, RU pump lines pump 50 bbls safe lube down tubing and chase with 30 bbls safe lube, ensure we can make it to Packer set depth, drop ball and rod, RU power swivel, get packer to depth @ 4,850' COE and EOT @ 10,396'. Unable to get ball & rod on seat pumping up to 6 bpm. Surge the pump while working the pipe up & down, no luck. Discuss w/ OE. Pull out Jt #155. Bottom of 3-1/2" Liner = 1,0378.69'. Packer COE = 4832.78'. Rig up Slickline. Rih w/ 2.0" JU inside 2.56" Bell Guide. Deviate out at ~ 4,400'. Pump down SL at 3 bpm. Tag at 4,584' SLM. Ball & Rod landed. Pressure up to 3,100psi. Set 6-5/8" x 3-1/2" Tripoint Packer. Hold for 15 mins. Bleed off pressure. Slickline pooh. SL did not recover ball & rod. Rig down SL. Release off of anchor latch 5,000 lb/ft torque then 13 rotations to the right, Began taking losses 13BPH, RD swivel POOH and LD 3.5" workstring, 15 Jts out hit fluid in TBG, try to pump hit pressure immediately 500 PSI and no returns, try to reverse Circ no returns @ 3 BPM, Contact OE, decided to POOH wet, wait for milne vac truck, POOH wet with vac truck on mud bucket, 13 BPH losses, 50 Jts out at time of report. 10/11/2023 - Wednesday Continue TOH w/ 3-1/2" P-110 workstring. Tripoint Anchor Latch engagement threads damaged on one side. Tripoint redress Anchor Latch. MU & RIH w/ BHA #10 - Tripoint Anchor Latch. TIH on 3-1/2" P-110 Workstring. Pick up Jt# 96. Tag Packer at 2,989' ORKB. Stack down 8k, latch Packer. Pull freely at 75k (38k over). Packer to surface, Initial inspection showed Indicators of packer setting and not shear released,Get packer to Northern Solutions in deadhorse to get re assembled with new 7" packer, Prep upper completion Monitor CHF 13 BPH losses. Continue to R/U power swivel, install swivel on joint #257 = 7,948' Tbird Rkb / 7,960' ORkb. PUW 56K, SOW 15K. ICP 1 BPM @ 90 psi/ 4 BPM @ 1,200 psi. Pumped 60 bbls SW to clean around VACS tool. Pumped 100 bbls of SW w/SafeLube and chase with 31 bbls to get friction reducer in slotted liner. Free spin 2,000 ft-lbs, 4 bpm / 1,200 psi, Begin VACS cleanout 8,000', Joint 323 before coming down EOT@ 9,977' still free torque @ 4,300 lb/ft pump 75 bbl safe lube@ 2 BPM chase with tubing volume of sea water ( note started having same problem in same spot on previous run) came down 10,008' torque back to 2700 lb/ft 23k down, Continue to cleanout. Time of report at JT# 338 =10,477' 24K down 3,800 lb/ft torque reciprocate pumping 50 BBL safe lube pill chased by 45 BBL, 10/8/2023 - Sunday Attempt to work VACS BHA in hole with JT# 338, stalling out @ 10,471'. Worked down to 10,477' with consistent stalls. Unable to make any hole pumping SafeLube and adjusting pump rates. Discuss plan forward w/OE. TOH w/BHA #8 LDSW. L/D VACS tool. Pull & L/D 64 joints of 2-7/8" PH6 workstring, unload sand 36' total. 3.75" carbide mule shoe show alot of wear and measured at 3.31-3.58", Preping pipe to run 3-1/2" JFE Bear screened liner completion. 10/9/2023 - Monday Sort and prep Lower completion. RIH w/3-1/2" JFE Bear screened liner completion as per run tally,Ran 150 straight screens in hole then alternate between screens & blanks up to 6-5/8" Liner Pkr Assy. Slickline set 2.81" RHCM plug in X-nipple below packer, pick up 3.5" PH-6 workstring to get packer to depth 4,850'. 10/7/2023 - Saturday Packer set depth, drop ball and rod, RU power swivel, get packer to depth @ 4,850' COE and EOT @ 10,396'. Unable to get ball & rod on seat pumping up to 6 bpm. Surge the pump while working the pipe up & down, no luck. Discuss w/ OE. Guide. Deviate out at ~ 4,400'. Pump down SL at 3 bpm. Tag at 4,584' SLM. Ball & Rod landed. Pressure up to 3,100psi. Set 6-5/8" x 3-1/2" Tripoint Packer. Hold for 15 mins. Bleed off pressure. Slickline pooh. SL did not recover ball & rod Tag Packer at 2,989' ORKB. Stack down 8k, latch Packer. Pull freely at 75k (38k over). Packer to surface, Initial inspection showed Indicators of packer setting and not shear released,Get packer to Northern Solutions in deadhorse to get re assembled with new 7" packer, Prep upper completion Sort and prep Lower completion. RIH w/3-1/2" JFE Bear screened liner completion as per run tally,Ran 150 straight screens in hole then alternate between screens & blanks up to 6-5/8" Liner Pkr Assy. Slickline set 2.81" RHCM plug in X-nipple below packer, pick up 3.5" PH-6 workstring to get packer to depth 4,850' Well Name Rig API Number Well Permit Number Start Date End Date MP M-22 Thunderbird 50-029-23645-00-00 219-111 9/17/2023 10/16/2023 Hilcorp Alaska, LLC Weekly Operations Summary 10/15/2023 - Sunday Land 11 x 4-1/2" Tubing hanger, RILDS, Set H BPV, Rig crews NIpple down BOPS, Nipple up tree and adapter, Tested adapter void to 500 / 5000 psi for 10 mins, Pull H BPV with Dry rod, RDMO, 10/16/2023 - Monday SHIFT OPEN XD-SS AT 4,162' MD W/ 4-1/2" 42BO. PULL BALL & ROD, 4-1/2" RHC FROM XN-NIPPLE AT 4,220' MD. CONFIRM OPEN XD-SS AT 4,162' MD W/ 4-1/2" 42BO. SET 3" JETPUMP (ratio: 13B) IN XD-SS AT 4,162' MD. Wait for New packer to AOL, pin shear release for 40K and install 5K shear on anchor latch, Make up Tripoint DLH Packer. Deploy Liner on 3-1/2" P-110 Workstring. After stand 41, have issues sliding in hole. Btm of Liner depth = 8124'. Circulate 100 bbls Safelube. Up wt= 75k / SOW= 16k. Weights improved. Resume TIH. Stop sliding after Joint #109. Btm Depth = 8968'. Circulate Safelube 121 bbls Safelube. ~ 70% returns. Weights improved. Resume TIH. Stop sliding after Joint # 137. Circulate 50 bbls. Jt 146 EOT A 10,124 COE @ 4,584' stop slide pump 30 BBL, Jt 147 didnt move Pump 50 bbls moveing 11K down/ 82K up, 149 down COE 4,679', cant slide 150 pump 50 BBLS safelube. Stacking out on Jt 153 RU power swivel, found an issue with Power swivel, Pump 50 BBL safelube while troubleshooting swivel, Swivel operational. At time of report: sliding Jt 154 in hole to packer set depth depth. 10/13/2023 - Friday Run in Joint 154 to put Packer on depth. Up wt= 82k / SOW= 9k. Rig up Swivel. Pump 20 bbls down backside to clear any potential debris at packer. Pump 20 bbls down Tbg to clear any workstring debris. Drop 1.50" phenolic ball. Chase at 1 bpm. Caught pressure at 20 bbls. Pressure up to 3500psi to set Packer. Hold for 30 mins. Bleed off pressure. Pressure up backside to 500psi for 5 mins - good indication packer is set. Pull up to 50k. Rotate to the right to shear/release from the packer. Swivel out while picking up 30'. Up wt= 56k, free from Liner. Begin TOH w/ 3-1/2" workstring. Top of Liner Depth = 4824'. Liner 7" Packer Center Element Depth = 4,831.59' ORKB. Liner Bottom Depth= 10,371.68' ORKB. Packer pinned for 40k to Release. Recover 1-1/2" ball. Setting tool all intact. Set Test Plug in Hanger. Prep for BOP Test. BOP Test Waived by Inspector Guy Cook. Prep to run upper completion, Begin to run upper completion. 10/14/2023 - Saturday Continue to run 4.5" BTC Completion per approved run Tally. Make up the last Full Joint #110. Up wt= 54k / SOW= 44k Make up 2 space out Pups. Cut I-wire/control line with long tail excess. 56 Total Cannon Clamps. Strip off washington head. Make up Hanger/Landing Joint. Wrap I-wire/control line on top of a hanger neck. Land Hanger. RILDS. LRS bullhead 60/40 Meth to 500' TVD down Tbg & IA. Drop Ball & Rod ( 6.3' OAL, 1-3/8" F-neck, 1-7/8" ball). Pressure up to 3500psi and set 4-1/2" x 7" Tripoint Packer (pinned for 40k to shear/release). Perform charted MIT-T to 3610psi - Passed. Perform charted MIT-IA to 3750psi - Passed. Bleed off pressures. Set BPV. Begin Rig Down Operations. 10/12/2023 - Thursday Pressure up to 3500psi to set Packer. Hold for 30 mins. Bleed off pressure. Pressure up backside to 500psi for 5 mins - good indication packer is set. Pull up to 50k. Rotate to the right to shear/release from the packer. Continue to run 4.5" BTC Completion per approved run Tally. Make up the last Full Joint #110. Up wt= 54k / SOW= 44k Make up 2 space out Pups. Cut I-wire/control line with long tail excess. 56 Total Cannon Clamps. Strip off washington head. Make up Hanger/Landing Joint. Wrap I-wire/control line on top of a hanger neck. Land Hanger. RILDS. LRS bullhead 60/40 Meth to 500' TVD down Tbg & IA. Drop Ball & Rod ( 6.3' OAL, 1-3/8" F-neck, 1-7/8" ball). Pressure up to 3500psi and set 4-1/2" x 7" Tripoint Packer (pinned for 40k to shear/release). Perform charted MIT-T to 3610psi - Passed. Perform charted MIT-IA to 3750psi - Passed. SET 3" JETPUMP _____________________________________________________________________________________ Revised By: DH 11-15-23 SCHEMATIC Milne Point Unit Well: MP M-22 Last Completed: 10/15/2023 PTD: 219 - 111 GENERAL WELL INFO API: 50-029-23645-00-00 Drilled, Cased & Completed by Doyon 14 – 9/13/2019 Converted to Jet Pump by ASR#1 – 11/23/2019 Replace Tubing/Install Screens by AS#1 – 10/15/2023 TREE & WELLHEAD Tree Cameron 3 1/8" 5M Wellhead FMC 11" 5M TC-1A w/11" x 4 1/2" TC-II Top and Bottom Tubing Hanger with 3" CIW "H" BPV profile. 2ea 3/8" NPT control lines. OPEN HOLE / CEMENT DETAIL 20” x 34” 270 ft3 Cement to surface in a 42” hole 9-5/8” 1st stage L – 275 sx / T – 400 sx in a 12-1/4” hole 9-5/8” 2nd stage L – 536 sx / T – 270 sx in a 12-1/4” hole 6-5/8”” Cementless Slotted Liner in 8-1/2” hole CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20"x34” Conductor (Insulated) 215 / X-42 / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835” Surface 4,942' 0.0758 7” Tieback 26/ L-80 / TXP 6.276” Surface 4,784' 0.0383 6-5/8” Liner (Slotted) 20 / L-80 / Hydril 563 6.049” 4,775’ 14,120’ 0.0355 Slotted Liner Pattern: 4 rows, 8 slots/row, 32 slots/ft, 2” x 0.125” slots, slots on 6” centers, no slot overlap 3-1/2” Insert Screens 100ђ TUBING DETAIL 4-1/2” Tubing 12.6 / L-80 / BTC 3.958” Surface 4,774’ 0.0152 3-1/2” Screen Liner 9.2# / L-80 / JFE Bear 2.992” 4,824’ 10,372’ 0.0087 TD = 14,120’ MD / 3,637’ TVD PBTD = 14,115’ MD / 3,637’ TVD 20” Orig. KB Elev.: 58.8’/ GL Elev.: 24.9’ 7” 9-5/8” 1 2 9-5/8” ‘ES’ Cementer @ 2,152’ 6,7,8,&9 12 Min ID 3.725” @ 4,216’ 8-1/2” Hole 3 See Solid / Slotted Liner Detail 5 6-5/8” 4 10 11 WELL INCLINATION DETAIL KOP @ 393’ Max Hole Angle = 98.45° @ 7,243’ JEWELRY DETAIL No. Top MD Item ID Upper Completion 1 29’ Tubing Hanger: 4-4/2" FMC TC1A 2 4,162’ 4-1/2" HES Sliding Sleeve 3.813” 3 4,183’ 4-1/2” Gauge Carrier 3.813” 4 4,202’ 7" x 4-1/2" Tripoint Hydratrieve Packer 3.890” 5 4,220 4-1/2" x 3.813" XN Nipple w/3.725" NO-GO) 3.725” 6 4,773’ Locator Sub, TC-II Box x Box (8.25” OD No-Go) 6.200” 7 4,775’ Bullet Seals (TBSA), Mule Shoe 6.090” 8 4,775’ SLZXP LTP with DG slips (11.27' tie back sleeve) TOL 6.190” 9 4,773’ Locator Sub, TC-II Box x Box (8.25” OD No-Go) 6.200” 10 4,829’ 7" x 3-1/2" Tripoint DLH Packer 2.990” 11 10,372’ Bullnose for 3-1/2” Screens 2.992” SLOTTED LINER DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Schrader Bluff OA 4,960’ 6,975’ 3,840’ 3,803’ 2,015’ 9/10/2019 Open 7,257’ 9,264’ 3,773’ 3.654’ 2,007’ 9/10/2019 Open 9,343’ 10,469’ 3,652’ 3,622’ 1,126’ 9/10/2019 Open 11,188’ 14,074’ 3,664’ 3,635’ 2,886’ 9/10/2019 Open Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/17/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20231017 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 212-26 50283201820000 220058 9/2/2023 AK E-LINE Perf KBU 14-6Y 50133205720000 207149 9/18/2023 AK E-LINE GPT/Plug KBU 23-05 50133206300000 214061 9/9/2023 AK E-LINE GPT/Perf MP S-21 50029230650000 202009 10/7/2023 READ CaliperSurvey MPU C-23 50029226430000 196016 9/21/2023 AK E-LINE Perf MPU M-22 50029236450000 219111 9/20/2023 AK E-LINE Mechanical Cutter Paxton 7 50133206430000 214130 9/8/2023 AK E-LINE Tubing Punch/RCT PBU 06-16B 50029204600200 223072 10/7/2023 HALLIBURTON RBT PBU D-18B 50029206940200 215001 9/14/2023 BAKER RPM PBU J-19 50029216290000 186135 9/26/2023 AK E-LINE TTBP/Cement PBU J-23A 50029217120100 204193 10/4/2023 BAKER SPN PBU N-18A 50029209060100 208175 9/4/2023 BAKER SPN PBU P1-02A 50029217790100 202065 9/11/2023 BAKER SPN PBU P1-13 50029223720000 193074 9/15/2023 HALLIBURTON IPROF PBU R-12A 50029209210100 211055 9/7/2023 BAKER SPN Please include current contact information if different from above. T38062 T38063 T38065 T38064 T38066 T38067 T38068 T38069 T38070 T38071 T38072 T38073 T38074 T38075 T38076 10/20/2023 Mechanical MPU M-22 50029236450000 219111 9/20/2023 AK E-LINE Cutter Kayla Junke Digitally signed by Kayla Junke Date: 2023.10.20 08:34:04 -08'00' 2023-1013_Well_Control Drill_Hilcorp_Thunderbird1_MPU_M-22_gc Page 1 of 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO:Jim Regg DATE:10/13/23 P. I. Supervisor FROM:Guy Cook SUBJECT:Well Control Drill Petroleum Inspector Thunderbird Rig 1 MPU M-22 Hilcorp Alaska LLC. PTD 2191110; Sundry 323-436 10/13/23: I stopped by Hilcorp’s Thunderbird 1 rig to witness an unannounced kick-drill. I asked the company representative, Tim Atkinson, to accompany me to the rig floor to inform the driller to start the kick-drill by announcing it over the rigs two-way radios. After the driller announced we were having a kick-drill, I started the timer to see how long it took for the rig hands to get into their places and secure the well by simulating the installation of a floor valve and the closing of the annular. It took 2 minutes 41 seconds for the well to be “secured” and most of the rig hands to be in their positions. It took 2 minutes before any rig hands made it to the rig floor to simulate the installation of the floor valve. A few of the rig hands were not aware the drill was happening due to not having radios and as a result did not participate. The crew’s performance in this drill made it clear they don’t do this drill regularly and they need to practice this drill more often in the future. After the drill was over, I spoke with the crew about being prepared in the future to respond to an actual well control situation. I pointed out the value of having communication via radio, or some other means, as several of the rig hands had to be located to be informed the drill was taking place. While two of the rig hands did well during the drill, by radioing in the pressure on the accumulator and being ready in the pits, the rest of the crew clearly was at a loss of where to be and what their roll would be in this kind of situation. I asked how often they performed this well control drill. I was told the drill gets forgotten at times and they need to do it more. I agreed that the rig crew about doing more drills. I spoke with Tim Atkinson some more about the importance of taking this seriously and getting the rig crew prepared to respond to this kind of incident and then left location. Attachments: none 9 9 9 9 9 9 9 9 unannounced kick-drill. The crew’s performance in this drill made it clear they don’t do this drill regularly andpy they need to practice this drill more often in the future. y gp crew clearly was at a loss of gy p, where to be and what their roll would be in this kind of situation. James B. Regg Digitally signed by James B. Regg Date: 2023.12.01 15:59:29 -09'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Todd Sidoti Subject:RE: MPU M-22 (PTD 219-111) Revised BOP Schematic Date:Thursday, September 14, 2023 11:16:00 AM Todd, The 2-ram BOP stack is approved for use under sundry 323-436. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Todd Sidoti <Todd.Sidoti@hilcorp.com> Sent: Thursday, September 14, 2023 10:34 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: MPU M-22 (PTD 219-111) Revised BOP Schematic Hi Bryan, We will be dropping the extra set of VBR rams for well M-22 which are indicated on the BOP schematic for Sundry 323-436. We are using Prudhoe’s rig for this job and I thought that their standard BOP configuration always included 3 sets of rams. I was incorrect and we are going to drop the bottom set for handling and inspection purposes. We are not dealing with much surface pressure on this well. Please let me know if you need any additional information and I hope that you are doing well. Thanks, Todd Todd Sidoti | Operations Engineer | Hilcorp Alaska | 907-632-4113 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby 2-7/8" x 5" VBRs J-4 IlLSIDE TO I IMIDE 4•ilir SM x 34m, sm ADAPM SPOOL 1}sf e' WUD CROSS w/ a- rfia^ oulmEts APROX WEiGHT.1,SOGLOS $19' 4PHI! RICAL AMMULAR ;Kr as2r" laKn iz,ROi Lis L'")r TYPE U DOUiLE GOP MEIGKT: SS.Rl' WLgGKr 14,ROD m ihMDE TO OUTSIDE d Lila"SMxs-SiMOSMADMrEMSPOOL !� � 3{i' sM r�Rnw1 rasr v�vr 3-lAr SM MIGR H E IG HT A DDITI 0 N FOR RING GASKETS: 0" BOP TOTAL HEIGHT, 1371" BOP TOTAL WEIGHT: 30,016 LB5 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: FCO / INSTALL SCREENS 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number): 10. Field: Current Pools: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 14,120'N/A Casing Collapse Conductor N/A Surface 3,090psi Tie-Back 5,410psi Slotted Liner 3,470psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 7"4,784' 9,345'6-5/8" 9-5/8"4,942' 6,090psi MD N/A 7,240psi 5,750psi3,838' 3,826' 4,942' 3,637'14,120' 4,784' Length Size Proposed Pools: 114'114' TVD Burst PRESENT WELL CONDITION SUMMARY 3,637'14,115'3,637'1,130 N/A 114'20" Milne Point Field STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025514 / ADL355023 219-111 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23645-00-00 Hilcorp Alaska LLC Schrader Bluff Oil Pool N/A C.O. 477.05 Milne Point Unit M-22 Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):Tubing Size: 12.6# / L-80 / Hydril 4,827' 9/1/2023 RH Retrievable & SLZXP LTP and N/A 4,193 MD/ 3,716 TVD & 4,775 MD/ 3,826 TVD and N/A See Schematic See Schematic 4-1/2" Perforation Depth MD (ft): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY todd.sidoti@hilcorp.com 777-8443 Todd Sidoti Wells Manager m n P s 66 t S Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 3:02 pm, Aug 01, 2023 323-436 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.08.01 09:22:32 - 08'00' Taylor Wellman (2143) * Approved for reverse circulating jet pump. * IA SSV high pressure trip not to exceed 3650 psi. * IA SSV low pressure trip not to be lower than 50% of maximum header injection pressure. * Production tubing SSV low pressure trip not to be lower than 100 psi. * SSV closure on IA will initiate closure within 2 minutes on SSV on production tubing and visa versa. * BOPE test to 2500 psi. SFD 8/22/2023 1,130 DSR-8/4/23MGR02AUG2023 10-404 GCW 08/22/2023JLC 8/23/2023 08/23/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.08.23 09:19:50 -08'00' RBDMS JSB 082423 RWO FCO Recomplete Well: MPU M-22 Date: 28 July 2023 Well Name: MPU M-22 API Number: 50-029-23645-00-00 Current Status: Producer Pad: M-Pad Estimated Start Date: September 1, 2023 Rig: Thunderbird Rig 1 Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 219-111 First Call Engineer: Todd Sidoti (907) 777-8420 (O) (907) 632-4113 (M) Second Call Engineer: Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) Current Bottom Hole Pressure: 1500 psi @ 3700’ TVD Extrapolated Gauge Data: 7.8 PPGE MPSP: 1130 psi Gas Column Gradient (0.1 psi/ft) Brief Well Summary & Objective: MPU well M-22 was drilled and completed as a Schrader Bluff OA producer in September 2019. The oil quality has been better than anticipated and is accompanied by higher gas volumes of ~1mmscf. Gas limited drawdown on the well and in November 2019 the completion was changed from ESP to jet pump. The well developed a sanding event in September 2022 and we are unable to draw the well down effectively without producing sand. A coiled tubing cleanout with N2 was attempted in December 2022 but was only able to make it down to 8500’ before encountering lock-up. The objective of this program is to pull the completion, clean the well out, run screens in the 6-5/8” slotted liner and run a new upper jet pump completion. Notes Regarding Well x Passing MIT-IA to 3300 psi on 11/22/2019 x Minimum ID: 3.725” XN @ 4216’ x 11” wellhead will require adapter to 13-3/8” BOP stack Brief RWO Procedure: Well Support (Well support steps are pre-sundry work) 1. Perform MIT-OA to 1500 psi. 2. MIRU slickline and pressure test lubricator to 250 psi low / 2000 psi high. 3. Pull JP and open SS. 4. RD well house and flowlines. 5. Clear and level pad area around well. 6. Spot rig mats and full containment for Thunderbird rig spread. Will need to be fully lined with herculite to the cellar. 7. RU crane. Set BPV. ND tree and NU dry hole tree. RD Crane. 8. PT tree to 250 psi low / 2500 psi high. Rig Up and Test BOPE 9. MIRU Thundrbird Rig 1 and ancillary equipment including 400 bbl open top tank. 10. Confirm injectivity down IA and tubing. 11. Bullhead 300 bbls of produced water down the IA and tubing. 12. ND dry hole tree and NU BOPE configured from top to bottom as follows: 2-7/8” x 5” VBRs, blind ram, 2-7/8” x5” VBRs, annular preventer. 13. Set CTS plug. 14. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. pull the completion, clean the well out, run screens in the 6-5/8” slotted liner and run a new upper jet pump completion. RWO FCO Recomplete Well: MPU M-22 Date: 28 July 2023 a. Perform Test per Thunderbird Rig 1 BOP Test Procedure b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry conditions of approval. d. Test VBR rams on 2-7/8”, 3-1/2” and 4-1/2” test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 15. Pull CTS plug. Bleed any pressure off tubing to the returns tank. Pull BPV. 16. Bleed off OA and monitor pressure throughout job. Pull Upper Completion 17. Rig up Centralift spooler and sheave for I-wire. 18. MU landing joint or spear and PU on the tubing hanger. a. Pick-up string weight was 52k lbs and slack-off was 35k. b. The packer was pinned to release at 41k lbs. 19. Recover the tubing hanger and disconnect I-wire. 20. POOH and lay down the 4-1/2” tubing. Number all joints. a. Inspect all tubulars and jewelry for re-run. b. Recover 60 canon clamps. c. Recover 5 half-clamps. d. Recover and test I-wire for re-run. Cleanout 6-5/8” Lateral 21. Spot in vac truck and rig up mud bucket to handle wash pipe fill. 22. Rig up Baker VACS cleanout assembly. A 4-1/2” Mule Shoe 1 Joint 4-1/2” Wash Pipe Flapper Valve 5 joints of 4-1/2” Wash Pipe B Flapper valve 5 joints of 4-1/2” Wash Pipe Crossover Sub 1 Joint 4-1/2” Wash Pipe Jet Sub Top Bushing Ball Drop Circulation Sub 23. Ensure that enough circ sub shear discs are available for multiple runs. 24. Pick up and RIH with 4” drillpipe. a. Ensure that floor valves are available. 25. Dry tag fill at ~8500’. 26. Pick up to closest connection and come online down tubing with pump at 5 BPM. Establish pumping parameters. We do not anticipate taking returns while running the venturi assembly. 27. Clean out taking one joint bites of fill as necessary with pump engaged. RWO FCO Recomplete Well: MPU M-22 Date: 28 July 2023 28. Continue pumping once joint is fully tripped to ensure sand travels to uphole end of washpipe. 29. Continue to dry drift and vacuum up sand as necessary until PBTD is reached. 30. If progress stops it will be necessary to trip OOH and empty out wash pipe. 31. Drop ball and pressure up per vendor recommendation to open circulation port before POOH. 32. When breaking wash pipe connections we will need to be ready to deal with a slurry, ensure that mud bucket is ready to go with vac truck support. 33. Take vac truck partial loads to 400 bbl tank for dilution and skimming. Run 3-1/2” Screen Completion 34. Make up and RIH with 3.5” screen lower completion on 4” DP. a. Alternate between screens and blank pipe. A 3-1/2” Bullnose Pup Joint, 3-1/2" ~155 Joints Tubing, 3-1/2" w/ 5.75” spiral vane centralizer ~155 Joints 3-1/2” Screen w/ 5.75” spiral vane centralizer B Pup Joint, 3-1/2" 6-5/8” x 3-1/2” Packer @ ~4850’ Hydraulic setting tool c. Tag PBTD, space out, drop ball and set packer per vendor instructions. d. POOH laying down DP and setting tool. Run 4.5” Upper Completion 36. Rig up Centralift spooler and sheave for I-wire. 37. RIH with 4-1/2” reverse circulating JP completion to ~4600’. a. Install 1 cannon clamp every other connection and test I-wire every 1000’. A 4-1/2” Mule Shoe Pup Joint, 4-1/2" ~9 Joints Tubing, 4-1/2" B Pup Joint, 4-1/2” 4-1/2” XN Nipple with RHC Plug Installed Pup Joint, 4-1/2” C Pup Joint, 4-1/2" 7” x 4-1/2” Packer @ ~4200’ Pup Joint, 4-1/2" 1 Joint Tubing, 4-1/2" D Pup Joint, 4-1/2" Gauge Carrier, Baker, Zenith Gauge Installed Pup Joint, 4-1/2" 1 Joint Tubing, 4-1/2" E Pup Joint, 4-1/2" RWO FCO Recomplete Well: MPU M-22 Date: 28 July 2023 Sliding Sleeve, 3.813" X profile, covered ports for I-wire bypass Pup Joint, 4-1/2" ~124 Joints Tubing, 4-1/2" 38. Make up tubing hanger. Terminate I-wire to hanger. Test I-wire. RILDS. Note PU and SO weights on tally. 39. Circulate 80 bbls corrosion inhibited source water down backside followed by 50 bbls freeze protect taking returns from the tubing. 40. Bullhead 40 bbls freeze protect down tubing. 41. Drop ball & rod and pressure up to set packer per vendor instructions. 42. Perform 30 minute charted MIT-IA to 3650 psi. The jet pump header pressure at M pad is set at 3500 psi. 43. Set BPV & CTS plug. ND BOPE and NU dry hole tree. 44. PT tree to 250 psi low / 2500 psi high. 45. RDMO Thunderbird Rig 1. Post-Rig Procedure: Well Support 46. RU crane. ND dry hole tree and NU production tree. 47. Test tree to 500 psi low/5,000 psi high. Pull CTS plug & BPV. 48. RD crane. 49. RU well house and flowlines. Slickline 50. MIRU slickline and PT lubricator to 250 psi low / 2500 psi high. 51. Pull ball & rod and RHC plug. 52. Shift sliding sleeve open. 53. Set 13B jet pump. 54. RD SL Unit. 55. Turn Well over to production. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOPE Schematic _____________________________________________________________________________________ Revised By: TDF 7/28/2023 SCHEMATIC Milne Point Unit Well: MP M-22 Last Completed: 11/23/2019 PTD: 219 - 111 GENERAL WELL INFO API: 50-029-23645-00-00 Drilled, Cased & Completed by Doyon 14 – 9/13/2019 Converted to Jet Pump by ASR#1 – 11/23/2019 TREE & WELLHEAD Tree Cameron 3 1/8" 5M Wellhead FMC 11" 5M TC-1A w/11" x 4 1/2" TC-II Top and Bottom Tubing Hanger with 3" CIW "H" BPV profile. 2ea 3/8" NPT control lines. OPEN HOLE / CEMENT DETAIL 20” x 34” 270 ft3 Cement to surface in a 42” hole 9-5/8” 1st stage L – 275 sx / T – 400 sx in a 12-1/4” hole 9-5/8” 2nd stage L – 536 sx / T – 270 sx in a 12-1/4” hole 6-5/8”” Cementless Slotted Liner in 8-1/2” hole CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20"x34” Conductor (Insulated) 215 / X-42 / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835” Surface 4,942' 0.0758 7” Tieback 26/ L-80 / TXP 6.276” Surface 4,784' 0.0383 6-5/8” Liner (Slotted) 20 / L-80 / Hydril 563 6.049” 4,775’ 14,120’ 0.0355 Slotting Pattern: 4 rows, 8 slots/row, 32 slots/ft, 2” x 0.125” slots, slots on 6” centers, no slot overlap TUBING DETAIL 4-1/2” Tubing 12.6 / L-80 / HYD521 3.958” Surface 4,827 0.0087 TD = 14,120’ MD / 3,637’ TVD PBTD = 14,115’ MD / 3,637’ TVD 20” Orig. KB Elev.: 58.8’/ GL Elev.: 24.9’ 7” 9-5/8” 1 4 9-5/8” ‘ES’ Cementer @ 2,152’ 2 6 9, 10 & 11 15 3 Min ID 3.725” @ 4,216’ 8-1/2” Hole 5 12 See Solid / Slotted Liner Detail 8 6-5/8” 7 13 14 WELL INCLINATION DETAIL KOP @ 393’ Max Hole Angle = 98.45° @ 7,243’ JEWELRY DETAIL No. Top MD Item ID Upper Completion 1 29’ Tubing Hanger: 4-4/2" FMC TC1A 2 2,305’ Sta#1: 4-1/2" x 1" GLM w/shear-out valve 3 4,144’ 4-1/2” SGM Multi Drop 3.874” 4 4,153’ 4-1/2" HES Sliding Sleeve (12A JP Set 3-20-22)3.813” 5 4,161’ 4-1/2" SGM Single 3.813” 6 4,180’ 4-1/2" x 3.813" X-Nipple 3.889” 7 4,193’ 7"x4-1/2" Bluepack RH Retrievable Packer 3.890” 8 4,216 4-1/2" x 3.813" XN Nipple w/3.725" NO-GO)3.725” 9 4,773’ Locator Sub, TC-II Box x Box (8.25” OD No-Go) 6.200 10 4,775’ Bullet Seals (TBSA), Mule Shoe 6.090 11 4,775’ SLZXP LTP with DG slips(11.27' tie back sleeve)TOL 6.190 12 4,773’ Locator Sub, TC-II Box x Box (8.25” OD No-Go) 6.200 13 4,786’ WLEG: w/ Cut Muleshoe – Bottom @ 4,827’ 3.958” 14 4,797’ Crossover, 7" Hydril 563 Box x 6-5/8" Hydril 563 Pin 6.000 15 14,115’ WIV – Ball on Seat –Bottom of Float Shoe @ 14,120’- SLOTTED LINER DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Schrader Bluff OA 4,960’ 6,975’ 3,840’ 3,803’ 2,015’ 9/10/2019 Open 7,257’ 9,264’ 3,773’ 3.654’ 2,007’ 9/10/2019 Open 9,343’ 10,469’ 3,652’ 3,622’ 1,126’ 9/10/2019 Open 11,188’ 14,074’ 3,664’ 3,635’ 2,886’ 9/10/2019 Open _____________________________________________________________________________________ Revised By: DH 7-31-23 SCHEMATIC Milne Point Unit Well: MP M-22 Last Completed: 11/23/2019 PTD: 219 - 111 GENERAL WELL INFO API: 50-029-23645-00-00 Drilled, Cased & Completed by Doyon 14 – 9/13/2019 Converted to Jet Pump by ASR#1 – 11/23/2019 TREE & WELLHEAD Tree Cameron 3 1/8" 5M Wellhead FMC 11" 5M TC-1A w/11" x 4 1/2" TC-II Top and Bottom Tubing Hanger with 3" CIW "H" BPV profile. 2ea 3/8" NPT control lines. OPEN HOLE / CEMENT DETAIL 20” x 34” 270 ft3 Cement to surface in a 42” hole 9-5/8” 1st stage L – 275 sx / T – 400 sx in a 12-1/4” hole 9-5/8” 2nd stage L – 536 sx / T – 270 sx in a 12-1/4” hole 6-5/8”” Cementless Slotted Liner in 8-1/2” hole CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20"x34” Conductor (Insulated) 215 / X-42 / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835” Surface 4,942' 0.0758 7” Tieback 26/ L-80 / TXP 6.276” Surface 4,784' 0.0383 6-5/8” Liner (Slotted) 20 / L-80 / Hydril 563 6.049” 4,775’ 14,120’ 0.0355 Slotted Liner Pattern: 4 rows, 8 slots/row, 32 slots/ft, 2” x 0.125” slots, slots on 6” centers, no slot overlap 3-1/2” Insert Screens 100ђ TUBING DETAIL 4-1/2” Tubing 12.6 / L-80 / HYD521 3.958” Surface ~4,300 0.0087 TD = 14,120’ MD / 3,637’ TVD PBTD = 14,115’ MD / 3,637’ TVD 20” Orig. KB Elev.: 58.8’/ GL Elev.: 24.9’ 7” 9-5/8” 1 2 9-5/8” ‘ES’ Cementer @ 2,152’ 6 7, 8, & 9 12 Min ID 3.725” @ 4,216’ 8-1/2” Hole 3 See Solid / Slotted Liner Detail 5 6-5/8” 4 10 11 WELL INCLINATION DETAIL KOP @ 393’ Max Hole Angle = 98.45° @ 7,243’ JEWELRY DETAIL No. Top MD Item ID Upper Completion 1 29’ Tubing Hanger: 4-4/2" FMC TC1A 2 ~4,153’ 4-1/2" HES Sliding Sleeve 3.813” 3 ~4,161’ 4-1/2” Gauge Carrier 3.813” 4 ~4,193’ 7" x 4-1/2" Retrievable Packer 3.890” 5 ~4,216 4-1/2" x 3.813" XN Nipple w/3.725" NO-GO) 3.725” 6 4,773’ Locator Sub, TC-II Box x Box (8.25” OD No-Go) 6.200” 7 4,775’ Bullet Seals (TBSA), Mule Shoe 6.090” 8 4,775’ SLZXP LTP with DG slips(11.27' tie back sleeve)TOL 6.190” 9 4,773’ Locator Sub, TC-II Box x Box (8.25” OD No-Go) 6.200” 10 ~4,850’ 6-5/8" x 3-1/2" Packer 3.813” 11 4,786’ WLEG: w/ Cut Muleshoe – Bottom @ 4,827’ 3.958” 12 4,797’ Crossover, 7" Hydril 563 Box x 6-5/8" Hydril 563 Pin 6.000” 13 14,115’ WIV – Ball on Seat - SLOTTED LINER DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Schrader Bluff OA 4,960’ 6,975’ 3,840’ 3,803’ 2,015’ 9/10/2019 Open 7,257’ 9,264’ 3,773’ 3.654’ 2,007’ 9/10/2019 Open 9,343’ 10,469’ 3,652’ 3,622’ 1,126’ 9/10/2019 Open 11,188’ 14,074’ 3,664’ 3,635’ 2,886’ 9/10/2019 Open 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Coil FCO w/ N2 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 14,120 feet NA feet true vertical 3,637 feet NA feet Effective Depth measured 14,115 feet 4,193 and 4,775 feet true vertical 3,637 feet 3,716 and 3,826 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 4,827' 3,830' RH Retrievable Packers and SSSV (type, measured and true vertical depth) and SLZXP LTP NA See Above NA 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: SAME 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title:Operations Manager Contact Phone: 5,410psi 3,470psi NA 5,750psi 7,240psi 6,090psi 4,942' 3,838' Burst Collapse NA 3,090psi Slotted Liner 4,784' 9,345' Casing Structural 3,826' 3,637' 4,784' 14,120' 4,942' 80'Conductor Surface Tie-Back 20" 9-5/8" 80' measured TVD 7" 6-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-111 50-029-23645-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0025514, ADL0355023 MILNE POINT / SCHRADER BLUFF OIL MILNE PT UNIT M-22 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 358 Gas-Mcf MD 2550 Size 80' 273 2098339 569 2936 311 322-678 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 220 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Todd Sidoti todd.sidoti@hilcorp.com 907-777-8443 N/A PL G Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Samantha Carlisle at 3:36 pm, Jan 12, 2023 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2023.01.12 15:02:22 -09'00' David Haakinson (3533) RBDMS JSB 011323 DSR-1/12/23WCB 11-1-2023 219-111 MILNE PT UNIT M-22 Coil FCO w/ N2 322-678 MILNE POINT / SCHRADER BLUFF OIL Sundry Number Well Name Rig API Number Well Permit Number Start Date End Date MP M-22 Coil 50-029-23645-00-00 219-111 12/10/2022 12/15/2022 12/14/2022 - Wednesday Complete freeze protect of surface lines and prep for BOP test. Complete weekly BOP test 250/4000psi. (PASS) RIH w/ 2" CTC, 2.25" no-go, 2.13" Baker MHA', (2) 4' stingers, 2.80" nozzle (OAL 11.6'). RIH to dry tag. Hit refusal (lock-up) @ 8500'. Repeat and unable to RIH below 8370'. POOH & RDMO. 12/15/2022 - Thursday WELL SHUT-IN ON ARRIVAL. SHIFT XD-SS AT 4,153' MD W/ 4-1/2" 42BO (Appears open). SET 3" JETPUMP (serial# - HC-00032, ratio: 12B) IN XD-SS AT 4,153' MD. WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED. 12/9/2022 - Friday WELL FLOWING ON ARRIVAL. PULL 3'' JET PUMP @ 4157' SLM / 4153' MD. LRS FREEZE PROTECT IA. CLOSE SLEEVE @ 4157' SLM / 4153' MD. LRS FREEZE PROTECT TUBING. WELL S/I ON DEPARTURE. Hilcorp Alaska, LLC Weekly Operations Summary 12/8/2022 - Thursday LRS CTU 2, 2.0" Blue Coil, Job Objective: Nitirifed Fill Clean Out. Travel from LRS shop in Deadhorse to MPM-22. MIRU. Job Continued on 12/11/2022. Continue fill cleanout from 6227'. N2 rate adjusted to 1200scfm. Solids content of gel samples ranged from 3-5%, at times up to 15% Continue cleanout down to 7755. Lost returns PUH to tubing tail and re-estblish returns to surface. RBIH and pump large gel sweep across heel starting from 5605 - 1.4% solids. Pump additional gel pill at tbg tail and chase to surface. POOH for weekly BOP test. Pump 5 bbl diesel cap on well. Freeze protect surface lines and prep for weekly BOP test. LRS CTU 2, 2.0" Blue Coil, Job Objective: Nitirifed Fill Clean Out. Travel from LRS shop in Deadhorse to MPM-22. MIRU. 12/10/2022 - Saturday Continue fill cleanout from 5000'. At 5330 tools failed and circ pressure spiked. POOH. Make up 2.80 JSN and RIH and cleaned out to 6230. 12/13/2022 - Tuesday 12/11/2022 - Sunday Complete rig up. Malke up Baker 2.125" MHA with tempress and 2.80" JSN. Tag at 7835. PBUH to tubing tail to begin pumping N2 and KCL. Tempress locked up when N2/KCL reached BHA. POOH swap tools. RIH to tbg tail and begin circulating N2 and KCL. Well would not surface fluids at portable test separator, and only partial gas returns. Open up to tanks and get flow to surface. Stabilize well and get resume shipping gas returns to M-26. Stabilize at clean out rates and begin cleaning out 6-5/8" liner. 12/12/2022 - Monday Complete rig up. Malke up Baker 2.125" MHA with tempress and 2.80" JSN. Tag at 7835. WELL FLOWING ON ARRIVAL. PULL 3'' JET PUMP @ 4157' SLM Target depth for FCO was PBTD, @14,115'. 8500' as reached. -WCB RIH w/ 2" CTC, 2.25" no-go, 2.13" Baker MHA', (2) 4' stingers, 2.80" nozzle (OAL 11.6'). RIH to dry tag. Hit refusal (lock-up) @ 8500'. Repeat and unable to RIH below 8370'. POOH & RDMO. Continue fill cleanout from 6227'. LRS CTU 2, 2.0" Blue Coil, Job Objective: Nitirifed Fill Clean Out _____________________________________________________________________________________ Revised By: NLW 3-20-22 SCHEMATIC Milne Point Unit Well: MP M-22 Last Completed: 11/23/2019 PTD: 219 - 111 GENERAL WELL INFO API: 50-029-23645-00-00 Drilled, Cased & Completed by Doyon 14 – 9/13/2019 Converted to Jet Pump by ASR#1 – 11/23/2019 TREE & WELLHEAD Tree Cameron 3 1/8" 5M Wellhead FMC 11" 5M TC-1A w/11" x 4 1/2" TC-II Top and Bottom Tubing Hanger with 3" CIW "H" BPV profile. 2ea 3/8" NPT control lines. OPEN HOLE / CEMENT DETAIL 20” x 34” 270 ft3 Cement to surface in a 42” hole 9-5/8” 1st stage L – 275 sx / T – 400 sx in a 12-1/4” hole 9-5/8” 2nd stage L – 536 sx / T – 270 sx in a 12-1/4” hole 6-5/8”” Cementless Slotted Liner in 8-1/2” hole CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20"x34” Conductor (Insulated) 215 / X-42 / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835” Surface 4,942' 0.0758 7” Tieback 26/ L-80 / TXP 6.276” Surface 4,784' 0.0383 6-5/8” Liner (Slotted) 20 / L-80 / Hydril 563 6.049” 4,775’ 14,120’ 0.0355 Slotting Pattern: 4 rows, 8 slots/row, 32 slots/ft, 2” x 0.125” slots, slots on 6” centers, no slot overlap TUBING DETAIL 4-1/2” Tubing 12.6 / L-80 / HYD521 3.958” Surface 4,827 0.0087 TD = 14,120’ MD / 3,637’ TVD PBTD = 14,115’ MD / 3,637’ TVD 20” Orig. KB Elev.: 58.8’/ GL Elev.: 24.9’ 7” 9-5/8” 1 4 9-5/8” ‘ES’ Cementer @ 2,152’ 2 6 9, 10 & 11 15 3 Min ID 3.725” @ 4,216’ 8-1/2” Hole 5 12 See Solid / Slotted Liner Detail 8 6-5/8” 7 13 14 WELL INCLINATION DETAIL KOP @ 393’ Max Hole Angle = 98.45° @ 7,243’ JEWELRY DETAIL No. Top MD Item ID Upper Completion 1 29’ Tubing Hanger: 4-4/2" FMC TC1A 2 2,305’ Sta#1: 4-1/2" x 1" GLM w/shear-out valve 3 4,144’ 4-1/2” SGM Multi Drop 3.874” 4 4,153’ 4-1/2" HES Sliding Sleeve (12A JP Set 3-20-22)3.813” 5 4,161’ 4-1/2" SGM Single 3.813” 6 4,180’ 4-1/2" x 3.813" X-Nipple 3.889” 7 4,193’ 7"x4-1/2" Bluepack RH Retrievable Packer 3.890” 8 4,216 4-1/2" x 3.813" XN Nipple w/3.725" NO-GO)3.725” 9 4,773’ Locator Sub, TC-II Box x Box (8.25” OD No-Go) 6.200 10 4,775’ Bullet Seals (TBSA), Mule Shoe 6.090 11 4,775’ SLZXP LTP with DG slips(11.27' tie back sleeve)TOL 6.190 12 4,773’ Locator Sub, TC-II Box x Box (8.25” OD No-Go) 6.200 13 4,786’ WLEG: w/ Cut Muleshoe – Bottom @ 4,827’ 3.958” 14 4,960’ Crossover, 7" Hydril 563 Box x 6-5/8" Hydril 563 Pin 6.000 15 14,115’ WIV – Ball on Seat - SLOTTED LINER DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Schrader Bluff OA 4,960’ 6,975’ 3,840’ 3,803’ 2,015’ 9/10/2019 Open 7,257’ 9,264’ 3,773’ 3.654’ 2,007’ 9/10/2019 Open 9,343’ 10,469’ 3,652’ 3,622’ 1,126’ 9/10/2019 Open 11,188’ 14,074’ 3,664’ 3,635’ 2,886’ 9/10/2019 Open 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Coil FCO w/ N2 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field: Current Pools: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 14,120'N/A Casing Collapse Conductor N/A Surface 3,090psi Tie-Back 5,410psi Slotted Liner 3,470psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 7"4,784' 9,345' 6-5/8" 9-5/8"4,942' 6,090psi MD N/A 7,240psi 5,750psi3,838' 3,826' 4,942' 3,637'14,120' 4,784' Length Size Proposed Pools: 114' 114' TVD Burst PRESENT WELL CONDITION SUMMARY 3,637' 14,115' 3,637' 737 N/A 114' 20" Milne Point Field STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025514 / ADL355023 219-111 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23645-00-00 Hilcorp Alaska LLC Schrader Bluff Oil Pool N/A C.O. 477.05 Milne Point Unit M-22 Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: 12.6# / L-80 / Hydril 4,827' 12/14/2022 RH Retrievable & SLZXP LTP and N/A 4,193 MD/ 3,716 TVD & 4,775 MD/ 3,826 TVD and N/A See Schematic See Schematic 4-1/2" Perforation Depth MD (ft): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior writt en approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY todd.sidoti@hilcorp.com 777-8443 Todd Sidoti Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2022.11.29 10:52:58 -09'00' David Haakinson (3533) DSR-12/1/22MGR07DEC22 DLB 11/30/2022 10-404 737 X GCW 12/08/22 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.12.08 11:15:06 -09'00' RBDMS JSB 120922 Coil N2 FCO MPM-22 Well Name:MPM-22 API Number:50-029-23645-00-00 Current Status:JP Producer Rig:Coil Estimated Start Date:12/14/22 Estimated Duration:2 days Yes TBD Regulatory Contact:Tom Fouts Permit to Drill Number:219-111 First Call Engineer:Todd Sidoti 907-632-4113 Second Call Engineer:Taylor Wellman 907-947-9533 AFE Number:TBD Predicted Bottom Hole Pressure: 1107 psi @ 3701 BHPG reading 7/17/21 (5.75ppg EMW) Max. Anticipated Surface Pressure: 737 psi Gas Column Gradient (0.1 psi/ft) Min ID: 3.7504216 MD XN Brief Well Summary MPU well M-22 was drilled and completed as a Schrader Bluff OA producer in September 2019. The oil quality has been better than anticipated and is accompanied by higher gas volumes of ~1mmscf. Gas limited drawdown on the well and in November 2019 the completion was changed from ESP to jet pump. The well likely partially sanded off sometime in October 2022. Objective The primary objective is to clean the well out to TD with N2 lift. Notes Regarding Wellbore Condition MIT-IA on 7 x 4-1/2 to 3300 psi passed on 11/22/2019 MIT on 9-5/8 to 2600 psi passed on 9/31/2019 Coiled Tubing 1. MIRU coiled tubing, N2 pump and ancillary equipment. Rig up to take returns straight to tanks or through a portable test separator. 2. Pressure test BOPE to 4000 psi high / 250 psi low. 3. RIH with BHA including JSN. 4. RIH and dry tag fill. 5. Come online with 1%KCl and N2 at 600 scf/min. Begin FCO to PBTD @ 14,115 . Adjust N2 rate as needed to establish returns. a. If unable to establish returns contact OE for plan forward. 6. Chase a 10 barrel gel sweep into the tubing tail for every 1bbl of fill removed. 7. Chase final sweep to surface at 80%. 8. RIH and dry tag PBTD 9. P POOH pumping freeze protect. 10. RDMO coil, N2 and ancillary equipment. Slickline 1. MIRU slickline. 2. Pressure test lubricator to 300psi low and 2,800psi high. 3. Shift Sliding Sleeve open 4. Set 12B Jet pump in Sliding sleeve. RDMO. Attachments: 1. Wellbore Schematic 2. Coil Tubing BOPE Schematic 3. Hilcorp Nitrogen Standard Wells Procedure 737 psi _____________________________________________________________________________________ Revised By: NLW 3-20-22 SCHEMATIC Milne Point Unit Well: MP M-22 Last Completed: 11/23/2019 PTD: 219 - 111 GENERAL WELL INFO API: 50-029-23645-00-00 Drilled, Cased & Completed by Doyon 14 – 9/13/2019 Converted to Jet Pump by ASR#1 – 11/23/2019 TREE & WELLHEAD Tree Cameron 3 1/8" 5M Wellhead FMC 11" 5M TC-1A w/11" x 4 1/2" TC-II Top and Bottom Tubing Hanger with 3" CIW "H" BPV profile. 2ea 3/8" NPT control lines. OPEN HOLE / CEMENT DETAIL 20” x 34” 270 ft3 Cement to surface in a 42” hole 9-5/8” 1st stage L – 275 sx / T – 400 sx in a 12-1/4” hole 9-5/8” 2nd stage L – 536 sx / T – 270 sx in a 12-1/4” hole 6-5/8”” Cementless Slotted Liner in 8-1/2” hole CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20"x34” Conductor (Insulated) 215 / X-42 / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835” Surface 4,942' 0.0758 7” Tieback 26/ L-80 / TXP 6.276” Surface 4,784' 0.0383 6-5/8” Liner (Slotted) 20 / L-80 / Hydril 563 6.049” 4,775’ 14,120’ 0.0355 Slotting Pattern: 4 rows, 8 slots/row, 32 slots/ft, 2” x 0.125” slots, slots on 6” centers, no slot overlap TUBING DETAIL 4-1/2” Tubing 12.6 / L-80 / HYD521 3.958” Surface 4,827 0.0087 TD = 14,120’ MD / 3,637’ TVD PBTD = 14,115’ MD / 3,637’ TVD 20” Orig. KB Elev.: 58.8’/ GL Elev.: 24.9’ 7” 9-5/8” 1 4 9-5/8”‘ES’ Cementer @ 2,152’ 2 6 9,10 & 11 15 3 Min ID 3.725” @ 4,216’ 8-1/2” Hole 5 12 See Solid / Slotted Liner Detail 8 6-5/8” 7 13 14 WELL INCLINATION DETAIL KOP @ 393’ Max Hole Angle = 98.45° @ 7,243’ JEWELRY DETAIL No. Top MD Item ID Upper Completion 1 29’ Tubing Hanger: 4-4/2" FMC TC1A 2 2,305’ Sta#1: 4-1/2" x 1" GLM w/shear-out valve 3 4,144’ 4-1/2” SGM Multi Drop 3.874” 4 4,153’ 4-1/2" HES Sliding Sleeve (12A JP Set 3-20-22)3.813” 5 4,161’ 4-1/2" SGM Single 3.813” 6 4,180’ 4-1/2" x 3.813" X-Nipple 3.889” 7 4,193’ 7"x4-1/2" Bluepack RH Retrievable Packer 3.890” 8 4,216 4-1/2" x 3.813" XN Nipple w/3.725" NO-GO)3.725” 9 4,773’ Locator Sub, TC-II Box x Box (8.25” OD No-Go) 6.200 10 4,775’ Bullet Seals (TBSA), Mule Shoe 6.090 11 4,775’ SLZXP LTP with DG slips(11.27' tie back sleeve)TOL 6.190 12 4,773’ Locator Sub, TC-II Box x Box (8.25” OD No-Go) 6.200 13 4,786’ WLEG: w/ Cut Muleshoe – Bottom @ 4,827’ 3.958” 14 4,960’ Crossover, 7" Hydril 563 Box x 6-5/8" Hydril 563 Pin 6.000 15 14,115’ WIV – Ball on Seat - SLOTTED LINER DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Schrader Bluff OA 4,960’ 6,975’ 3,840’ 3,803’ 2,015’ 9/10/2019 Open 7,257’ 9,264’ 3,773’ 3.654’ 2,007’ 9/10/2019 Open 9,343’ 10,469’ 3,652’ 3,622’ 1,126’ 9/10/2019 Open 11,188’ 14,074’ 3,664’ 3,635’ 2,886’ 9/10/2019 Open STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 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 O2 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. DATA SUBMITTAL COMPLIANCE REPORT 1/14/2020 Permit to Drill 2191110 Well NamelNo. MILNE PT UNIT M-22 ?p I1 * Operator Hilcorp Alaska LLC MD 14120 TVD 3637 Completion Date 9/13/2019 Completion Status REQUIRED INFORMATION Mud Log No V/ Samples No V/ 1-0I1. Current Status 1 -OIL DATA INFORMATION List of Logs Obtained: ROP/ABG/DGR/EWR/ADR 2"/5' MD ... ABG/DGR/EWR/ADR 275' TVD PB1 Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH I Type Med/Frmt Number Name Scale Media No Start Stop CH ED C 31402 Digital Data 105 14120 1 ED C 31402 Digital Data I ED C 31402 Digital Data ED C 31402 Digital Data ED C 31402 Digital Data ED C 31402 Digital Data ED C 31402 Digital Data ED C 31402 Digital Data ED C 31402 Digital Data ED C 31402 Digital Data ED C 31402 Digital Data ED C 31402 Digital Data ED C 31402 Digital Data ED C 31402 Digital Data ED C 31402 Digital Data I ED C 31402 Digital Data ED C 31402 Digital Data Log Electronic File: Readme.txt 31402 Log Header Scans AOGCC Page I of 3 4930 14082 0 0 API No. 50-029-23645-00-00 UIC No Directional Survey Yes (from Master Well Data/Logs) Received Comments 11/1/2019 Electronic Data Set, Filename: MPU M-22 LWD Tuesday, January 14, 2020 Final.las 11/1/2019 Electronic Data Set, Filename: MPU M-22 ADR Quadrants All Curves.las 11/1/2019 Electronic File: MPU M-22 LWD Final MD.cgm 11/1/2019 Electronic File: MPU M-22 LWD Final TVD.ogm 11/1/2019 Electronic File: MPU M-22 - Definitive Survey Report.pdf 11/1/2019 Electronic File: MPU M-22_DSR.txt 11/1/2019 Electronic File: MPU M-22 GIS.txt 11/1/2019 Electronic File: MPU M-22 LWD Final MD.emf 11/1/2019 Electronic File: MPU M-22 LWD Final TVD.emf 11/1/2019 Electronic File: MPU M-22 Geosteering.dlis 11/1/2019 Electronic File: MPU M-22 Geosteering.ver 11/1/2019 Electronic File: MPU M-22 LWD Final MD.pdf 11/1/2019 Electronic File: MPU M-22 LWD Final TVD.pdf 11/1/2019 Electronic File: MPU M-22 LWD Final MD.tif 11/1/2019 Electronic File: MPU M-22 LWD Final TVD.tif 11/1/2019 Electronic File: EMFView3_1.zip 11/1/2019 Electronic File: Readme.txt 2191110 MILNE PT UNIT M-22 LOG HEADERS Tuesday, January 14, 2020 DATA SUBMITTAL COMPLIANCE REPORT 1/1412020 Permit to Drill 2191110 Well NamelNo. MILNE PT UNIT M-22 Operator Hilcorp Alaska LLC API No. 50-029-23645-00-00 MD 14120 TVD 3637 Completion Date 9/13/2019 Completion Status 1 -OIL Current Status 1 -OIL UIC No Log 31403 Log Header Scans 0 0 2191110 MILNE PT UNIT M-22 P61 LOG HEADERS ED C 31403 Digital Data 105 12932 11/1/2019 Electronic Data Set, Filename: MPU M-22PB1 LWD Final.las ED C 31403 Digital Data 4930 12895 11/1/2019 Electronic Data Set, Filename: MPU M-22PB1 ADR Quadrants All Curves.las ED C 31403 Digital Data 11/1/2019 Electronic File: MPU M-221381 LWD Final MD.cgm ED C 31403 Digital Data 11/1/2019 Electronic File: MPU M-22PB1 LWD Final TVD.cgm ED C 31403 Digital Data 11/1/2019 Electronic File: MPU M-22PB1 - Definitive Survey Report.pdf ED C 31403 Digital Data 11/1/2019 Electronic File: MPU M-22PB1 DSR.txt ED C 31403 Digital Data 11/1/2019 Electronic File: MPU M-22PB1_GIS.txt ED C 31403 Digital Data 11/1/2019 Electronic File: MPU M-22PB1 LWD Final MD.emf ED C 31403 Digital Data 11/1/2019 Electronic File: MPU M -22P61 LWD Final TVD.emf ED C 31403 Digital Data 11/1/2019 Electronic File: MPU M-22PB1 Geosteedng.dlis ED C 31403 Digital Data 11/1/2019 Electronic File: MPU M-22PB1 Geosteering.ver ED C 31403 Digital Data 11/1/2019 Electronic File: MPU M-22PB1 LWD Final MD.pdf ED C 31403 Digital Data 11/1/2019 Electronic File: MPU M-22PB1 LWD Final TVD.pdf ED C 31403 Digital Data 11/1/2019 Electronic File: MPU M -22P61 LWD Final MD.tif ED C 31403 Digital Data 11/1/2019 Electronic File: MPU M-22PE1 LWD Final TVD.tif ED C 31403 Digital Data 11/1/2019 Electronic File: EMFVim3_1.zip ED C 31403 Digital Data 11/1/2019 Electronic File: Readme.txt Well Cores/Samples Information: Sample Interval Set Name start Stop Sent Received Number Comments INFORMATION RECEIVED AO(,( < Page 2 of 3 Tuesday, January 14, 2020 DATA SUBMITTAL COMPLIANCE REPORT 1/14/2020 Permit to Drill 2191110 Well Name/No. MILNE PT UNIT M-22 Operator Hilcorp Alaska LLC API No. 50-029-23645-00-00 MD 14120 TVD 3637 Completion Date 9/13/2019 Completion Status 1-0I1- Current Status 1-0I1- UIC No Completion Report 0 Directional / Inclination Data OY Mud Logs, Image Files, Digital Data Y Core Chips y/0 Production Test Informatiore) NA Mechanical Integrity Test Information Y / NA Composite Logs, Image, Data Files 0 Core Photographs Y /e) Geologic Markers/Tops / Y / Daily Operations Summary Cuttings Samples YN9 Laboratory Analyses Y&) COMPLIANCE HISTORY Completion Date: 9/13/2019 Release Date: 8/20/2019 Description Date Comments Comments: Compliance Reviewed Date: �ll�(zaw AOG(V Page 3 of 3 Tuesday. January 14. 2020 STATE OF ALASKA I ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS DEC - 6 2019 LTiri iriTi7 1. Operations Abandon LJ Plug Perforations LJ Fracture StimulatLi Pull Tubing ✓ Operations shu down LJ Performed: Suspend ❑ Perforate ❑ Other SlimulatQ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ arforate New Pool ❑ Repair Well Re-enter Susp Well ❑ Other: Jet Pump Completion ❑✓ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska LLC Development Q Stratigraphic ❑ Exploratory ❑ Service ❑ 219-111 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-029-23645-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL025514 / ADL355023 Milne Point Unit M-22 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Milne Point Field / Schrader Bluff Oil Pool 11. Present Well Condition Summary: Total Depth measured 14,120 feet Plugs measured N/A feet true vertical 3,637 feet Junk measured N/A feel Effective Depth measured 14,115 feet Packer measured 4,193 & 4,775 feet true vertical 3,637 feet true vertical 3,716 & 3,826 feet Casing Length Size MD TVD Burst Collapse Conductor 114' 20" 114' 114' N/A N/A Surface 4,942' 9-5/8" 4,942' 3,838' 5,750psi 3,090psi Tie -Back 4,784' 7" 4,784' 3,826' 7,240psi 5,410psi Slotted Liner 9,345' 6-5/8" 14,120' 3,637' 6,090psi 3,470psi 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/ HY0521 4,827' 3,830' RH Retrievable Packers and SSSV (type, measured and true vertical depth) SLZXP LTP N/A See Above 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: 1,196 1,061 0 330 332 Subsequent to operation: 2,036 760 0 2,750 341 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 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 ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-506 Authorized Name: Chad Helgeson Contact Name: David Haakinso ( Authorized Title: Operations Manager Contact Email: dhaakinson(alhilcoro.com Authorized Signature: Date: 12/4/2019 Contact Phone: 777-8343 Form 10-404 Revised 4/2017 1BDMS tL6*) DEC 0 6 2019 Submit Original Only n Ilihwo Alaska. LLC Ong. KB Flee.: 58.8'/GLEIev.: 24.9' TD=14,120(MD/ 3,637 TVD PBTD=14,115' MD / 3,637 TVD SCHEMATIC TREE & WELLHEAD Milne Point Unit Well: MP M-22 Last Completed: 11/23/2019 PTD: 219 - 111 Tree Cameron 31/8" 5M Wellhead FMC 11" 5M TC -SA w/11" x 41/2" TC -11 Top and Bottom Tubing Hanger with 3" CI W "H" BPV profile. Zea 3/8" NPT control lines. OPEN HOLE/ CEMENT DETAIL 20"x34"270 W Cemen't0 surface in a 42"hole 9-5/8"lststage L-275 sx/T-400 sx ina 12-1/4" hole 9-5/8" 2nd stage L-536sx/T-270sxina 12-1/4' hole 6-5/811" Cementless Slotted Liner in 8-1/2" hole CASING DETAIL Size Type Wt/ Grade/ Conn 10 Top Btm BPF 20"x34" Conductor (insulated) 215/X-42/Weld N/A Surface 80' N/A 9-5/8" Surface 40/L-80/TXP 8.835" Surface 4,942' 0.0758 7" Tieback 26/L-80/TXP 6.276" Surface 4,784' 0.0383 6-5/8" Liner (Slotted) 20/L-80/Hydril 563 6.049" 4,775' 14,120' 0.0355 Slotting Pattern: 4 rows, 8 slots/row, 32 slots/ft, 2" x 0.125" slots, slots on 6" centers, no slot overlap TUBING DETAIL 41/2" Tubing 12.6/L-80/HYD521 1 3.958" 1 Surface 1 4,827 1 0.0087 SLOTTED LINER DETAIL Sands Top (MD) Btm (MD) Top (TVD) (Np) FT Date Status 1 4,960' 6,975' 3,840' 3,803' 2,015' 9/10/2019 Open Schrader Bluff 7,257' 9,264' 3,773' 3.654' 2,007' 9/10/2019 Open OA 9,343' 10,469' 3,652' 3,622' 1,126' 9/10/2019 Open 7 11,188' 14,074' 3,664' 3,635' 2,886' 9/10/2019 Open WELL INCLINATION DETAIL KOP @ 393' Max Hole Angle= 98.45° @ 7,243' JEWELRY DETAIL No. Top MD Item ID Upper Completion 1 29' Tubing Hanger: 4-4/2" FMC TC1A 2 2,305' Sta#1:4-1/2" x 1" GLM w/shear-out valve 3 4,144' 4-1/2" SGM Multi Drop 3.874" 4 4,153' 4-1/2" HES Sliding Sleeve w/ Weatherford 11D let Pump 3.813" 5 4,161' 4-1/2" SGM Single 3.813" 6 4,180' 41/2" x 3.813" X -Nipple 3.889" 7 4,193' 7"x4-1/2" Bluepack RH Retrievable Packer 3.890" 8 4,216 4-1/2" x 3.813" XN Nipple w/3.725" NO-GO) 3.725" 9 4,773' Locator Sub, TC -II Box x Box (8.25" OD No -Go) 6.200 10 4,775' Bullet Seals (TBSA), Mule Shoe 6.090 11 4,775' SLZXP LTP with DG slips(11.27'tie back sleeve)TOL 6.190 12 4,773' Locator Sub, TC -11 Box x Box (8.25" OD No -Go) 6.200 13 4,786' WLEG: w/ Cut Muleshoe — Bottom @ 4,827' 3.958" 14 4,960' Crossover, 7" Hydril 563 Box x 6-5/8" Hydril 563 Pin 6.000 15 14,115' WIV — Ball on Seat GENERAL WELL INFO API: 50-029-23645-00-00 Drilled, Cased & Completed by Doyon 14 — 9/13/2019 Converted to Jet Pump by ASR#1 — 11/23/2019 Revised By: TDF 12/4/2019 Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date M-22 ASR #1 50-029-23645-00-00 219-111 11/20/2019 1 11/23/2019 11/20/2019- Wednesday MIRU, Torque up BOPE, Start to lay Containment, Spot dog house and Company Rep shack, tool skid, and Parts house. RU ASR over the well. Set Rack Pins. Level out Rig. Rig Forced air Winterization Continue winterization of the rig. Putting on skirting and thermal wraps around every thing. Saftey MTG, Crew Change. Hook up new Flow Lines. Build Suction Manifold for new set up. Run Glycols lines. Rig Up Certek Unit. Continue winterization of the rig and equipment. 300k generator ran out of fuel. Waiting on fuel truck to arrive. Picked Up 3-1/2" Test Mandrel. Function Test BOPE. Check Accumulator Pressures. Filled lines & BOPE Stack. Circulated Fluid through Stack & Lines. Shell Test. 250 PSI Low/2,500 PSI High. Tighten Annular Connection. Good 11/21/2019 -Thursday Checked fluids serviced rig. Tested BOPE as following, Valves, Rams and Annular 250 psi Low/2,500 si High held each test 5mins and charted. Preformed Kommey drawdown test and tested gas detection. No failures were recorded. AOGCC witness waived by Guy Cook. L/D BOP Testing equipment and blew lines dry. PU Handling tools to 3-1/2" completion string. Spotted ESP Spooler and RU the elephant truck. Lost air supply to the rig. Troubleshot problem with VMS Mechanic and found air fitting leak Repaired. Slight blow on the tbg, Pumped 20 bbls of 8.9# Brine down tbg. Monitored and Tbg on vac. Pulled the BPV. MU the 3-1/2" landing joint BOLDS and Pulled hanger to surface Off -seat Cd 38k PU was 48k. _ Decompleted and L/D Hanger and Test A. Thread cable and cap string thru sheave to spoolers. POOH with 3-1/2" ESP completion string. Displacing every 15jts. PJSM, Checked fluids serviced rig. POOH with 3-1/2" ESP completion string. Displacing every 15jts. w/8.9# Brine Transfer 3-1/2" to Pipe Tub. Decompleted and LD ESP assembly. No sand or scaling was seen on Discharge Head or Pump Asby. Send assembly to Baker's shop and final inspection report will be sent out. Rig Down ESP Handling Eq. and Swap 3-1/2" handling Eq. to 4-1/2". Rack & Tally 4-1/2" Completion. 11/22/2019 - Friday Held PJSM, Checked fluids and serviced rig. SLB Personnel on locations to run Jet Pump Completion, Tallied and verified Completion Jewelry in running order. Racked and tallied the 4-1/2" completion tbg. Spotted SLB Spooler RU Handling equipment on rig floor. Hung sheave for the Tech -wire. Electrician was called out to repair lights on Rig floor. TIH w/4-1/2" 12.6# L-80 HYDR521 Tbg w/Cut Muleshoe WLEG on bottom, 14'oints of /4-1/2" 12.6# L-80 HYDR521 Completion BHA as following: XN-nipple (RHC Plug loaded), Hydraulic Packer, X -Nipple, Lower SGM, Sliding Sleeve and Upper SGM. MU Tech -wire connections had trouble seeing the gauges due to grounding issues that we had to work thru. Pressure tested the top gauge set screw to 5,000psi-good test. TIH w/completion Jewelry and Tech -wire on 4-1/2" 12.6# L- 80 HYDR521 Tbg. Clamping the first 16th joints (Joint #31 in on tally) then every other jt after, testing Tech -wire every 1,000'. PU TBG Hngr. Terminated Tech -Wire through Hngr. Land TBG Hngr. 35K Down. Putting the EDT @ 4,829'. RILDS. Drop Ball & Rod. Fill TBG with 11bbls. Spotted the Packer Fluid down IA. Pressure up on TBG to 3,500PSI 30 min Chart & Set Packer @ 4,193' Bled TBG down to 2100PSI. MIT IA Pressure up to 3,300 PSI Chart for 30 min -Good Test. Bleed off TBG and Shear out Valve @ 2,304' Equalize and bleed off. 11/23/2019 -Saturday PJSM, Checked Fluids and serviced equipment. Pumped 80bbls of diesel down IA and U -tubed the tbg to freeze protect the well. Set BPV. Started RD ASR 1 and associated equipment, Cleaned and cleared rig floor, Crew move Pipe Racks and RU pipe handler. De -Winterize Equipment Disconnect Flow Lines and accumulator hoses Loosen BOPE's. RD Stairwells and pulled rack pins and LD rig. RU Crane Fly off work floor, and well house. Loaded trailers, Work w/Roads & Pads to Load & Road Equipment to C -Pad. Cont. N/D BOPE N/U tree test void t/ 500/5000 good test tree t/ 5000 good, pull BPV check & plug,. Cont. r/d, prep & load eq. 11/24/2019 -Sunday No operations to report. 9- THE STATE OIALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-22 Permit to Drill Number: 219-111 Sundry Number: 319-506 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.olaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Jeremy M. Price Chair DATED this'�5 day of November, 2019. 3BDMS ld�✓ NOV 14 2019 SCANNED W/ 2 5 2019 ECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION NOV 0 7 2019 APPLICATION FOR SUNDRY APPROVALS /� 20 AAC 25.280 AOG r. C 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑✓ • Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Jet Pump Completion El 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development Q • Stratigraphic ❑ Service ❑ 219-111 . 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23645-00-00 ' 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 Will planned perforations require a spacing exception? Yes ❑ No ❑� Milne Point Unit M-22 9. Property Designation (Lease Number): 10. Field/Pool(s): ' ADL025514 / ADL355023 Milne Point Field / Schrader Bluff Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 14,120' 3,637' 14,115' 3,637' 1,392 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 114' 20" 114' 114' N/A N/A Surface 4,942' 9-5/8" 4,942' 3,838' 5,750psi 3,090psi Tie -Back 4,784' 7" 4,784' 3,826' 7,240psi 5,410psi Slotted Liner 9,345' 6-5/8" 14,120' 3,637' 6,090psi 3,470psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 3-1/2" 9.2# / L-80 / EUE 8rd 4,727' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): SLZXP LTP and N/A 4,775 MD / 3,826 TVD and N/A 12. Attachments: Proposal Summary � Wellbore schematic M 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Exploratory ❑ Stratigraphic ❑ Development ❑� • Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 11/20/2019 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: David Haakinson Authorized Title: Operations Manager Contact Email: dhaakinson(@hXorp.com % Contact Phone: 777-8343 Authorized Signature: Date: 11/7/2019 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: f 2 500 7lJS c 16o /0 '-7,s (— y n� I,I 2019 � 'rOV 14 Post Initial Injection MIT Req'd? Yes ❑ No ❑ lB�r•'�) Spacing Exception Required? Y`es, ❑ Subsequent Form Required: ' k-1 0 y APPROVED BY \ \ Approved by: COMMISSIONER THE COMMISSION Date: I J ubmit Form and Form 10-403 Revised 4/2017 Approved application is val o 1 on s from the date of approval. Attachments in Duplicate U Itilwrn Al.ka, LD Convert to Jet Pump Well: MPU M-22 Date: 11-07-19 Well Name: MPU M-22 API Number: 50-029-23645-00 Current Status: ESPProducer-Online Pad: M -Pad Estimated Start Date: Nov 20, 2019 Rig: ASR #1 Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 219-111 First Call Engineer: David Haakinson (907) 777-8343 (0) (307) 660-4999 (M) Second Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) AFE Number: Job Type: ESP Swap Current Bottom Hole Pressure: 1,774 psi @ 3,820' TVD Downhole Gauge (Before online - 9/19/19) 8.9 PPG Maximum Expected BHP: 1,774 psi @ 3,820' TVD Downhole Gauge (Before online - 9/19/19) 8.9 PPG MPSP: 1,392 psi Gas Column Gradient (0.1 psi/ft) Max Inclination 98' @ 7,244' MD (Reaches 70" at 4,200' md) Max Dogleg: 9X/100ft @ 4,291' MD BPV Profile: 3-1/8" CIW Type H Brief Well Summary: MPU well M-22 was drilled and completed as a Schrader Bluff OA producer in September 2019. The oil quality has been better than anticipated and is accompanied by higher gas volumes of-immscf. The gas has limited drawdown on the well due to ESP gas separator limitations. The conversion to a jet pump well will allow the well to reach the desired target drawdown on the well. Notes Regarding Wellbore Condition • The 9-5/8"0" annulus passed an MIT to 1,000 psig on 9/12/19 Objective: • Pull 3-1/2" Tubing String and ESP • Install a 4-1/2" Jet Pump completion Pre -Rig Procedure: Non-Sundried Operations ptiT-l.a- -{s j�nov rs-, 1. RU SL and shift sliding sleeve at 4,179' and to the open position (Down to open). RD SL. 2. RU LRS and PT lines to 3000 psi. 3. Begin pumping down the tubing to circulate 8.9ppg brine down the tubing while taking returns from the IA to tanks. a. Tbg vol (36.4 bbls) + IA vol (110.2 bbls) = 146.6 bbls to the sliding sleeve. 4. Clear and level pad area in front of well. Spot rig mats and containment. 5. RD well house and flowlines. Clear and level area around well. 6. Bleed off any residual pressure and confirm well is dead. Freeze protect tubing/casing as needed with 60/40 McOH. a. Freeze protect is up to the discretion of the Wellsite Supervisor depending on timing for arrival of the ASR. 7. RD Little Red Services. 8. RU crane. Set BPV. ND Tree. NU BOPE. RD Crane. 9. NU BOPE house. Spot mud boat. Convert to Jet Pump Well: MPU M-22 IIH.P Al..L,, LI: Date: 11-07-19 Brief RWO Procedure: Sundried Operations (Approved 10-403 required prior to starting) 10. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines to returns tank. 11. Check for pressure and if needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/ 8.9 ppg brine. 12. Set BPV plug (converting BPV to TWC). 13. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5 -min). Record accumulator pre -charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Perform Test per ASR 1 BOP Test Procedure dated 11/03/2015. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR rams on 3-1/2" and 4-1/2" test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 14. Contingency: If BOPE test fails Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 15. Bleed any pressure off casing to returns tank. Pull BPV plug and BPV. Kill well w/ 8.9 ppg brine as needed. 16. Rig up spoolers for ESP #2 RD cable and 3/8" capillary string a. Baker Hughes representative should be onsite for ESP pull. b. Inspect the ESP cable carefully and plan for re -use. c. Keep capillary tubing for re -use. 17. MU landing joint or spear and PU on the tubing hanger. a. The PU weight during the 2019 ESP completion was 90K lbs / SOF = 75K lbs (block wt = 35k lbs). b. If needed, circulate (long or reverse) pill with lubricant, 8.9 ppg brine, and/or baraclean pill prior to laying down the tubing hanger. I 18. Recover the tubing hanger. Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re -land hanger (or test plug) in tubing head. Test BOPE per standard procedure. 19. POOH and lay down the 3-1/2" tubing. Lay down ESP and motor. a. ESP will be sent to Baker Hughes for inspection and reuse on another well. Convert to Jet Pump Well: MPU M-22 f &.P Alaska, Lb Date: 31-07-19 b. Send all tubing to G&I for washing and reuse. If tubing shows signs of damage/corrosion send "'S% of random joints to Tuboscope for full inspection. c. Note any sand or schmoo/asphaltenes inside or on the outside of the ESP on the morning report. d. Look for over -torqued connections from previous tubing runs. e. The completion has the following amount of clamps/guards/cap-string: i. 84 Cross Collar Cannon Clamps ii. 8 Pump Clamps 20. Depending on wellbore conditions and evaluation of ESP for solids and fill, consider PU 7" casing scraper BHA and TIH. ! a. If casing scraper is run, TIH and reciprocate around 4,100'-4,250' MD. �© v b. Circulate a minimum of x1.5BU or until returns are clean from above the bullet seal assembly at 4,773' MD. TOOK 21. RU spoolers, MU 4-1/2" completion and deploy as per the finalized Completion Running Order. Approx Top Depth (md) Component 2,300' GLM (Shear -out valve installed & set to 2000psi) rD M P 7 1VC- Pup Joint 4,180' 7" x 4-1/2" Packer Pup Joint Pup Joint 4,200' XN Nipple (RHC Plug pre -loaded) Pup Joint Full Joints 4,820' WLEG 22. Record PU and SO weights prior to spacing out the WLEG to be below the 7"x9-5/8" liner top packer at ±4,820' MD. 23. Reverse circulate 80bbls of 8.9ppg brine with corrosion inhibitor down the annulus. 24. Land tubing hanger. RILDS. Lay down landing joint. Test tubing hanger pack -off to S,OOOpsi. 25. Drop the ball & rod to set the packer. Increase the pressure and test the tubing to 3,500psi. Full Joints Pup Joint 4,120' Gauge Mandrel Pup Joint 4,125' XD Sli . Sleeve Pup Joint 4,150' X Nipple Pup Joint 4,155' Gauge Mandrel Pup Joint rD M P 7 1VC- Pup Joint 4,180' 7" x 4-1/2" Packer Pup Joint Pup Joint 4,200' XN Nipple (RHC Plug pre -loaded) Pup Joint Full Joints 4,820' WLEG 22. Record PU and SO weights prior to spacing out the WLEG to be below the 7"x9-5/8" liner top packer at ±4,820' MD. 23. Reverse circulate 80bbls of 8.9ppg brine with corrosion inhibitor down the annulus. 24. Land tubing hanger. RILDS. Lay down landing joint. Test tubing hanger pack -off to S,OOOpsi. 25. Drop the ball & rod to set the packer. Increase the pressure and test the tubing to 3,500psi. Convert to Jet Pump Well: MPU M-22 IliI.P Alaska. LI) �� , / Date: 11-07-19 26. Bleed down the tubing pressure to 2,000 psi and pressure test the IA to 3,000 psi for 30 min (charted). 27. Bleed down the tubing pressure to shear out the shear out GLV from Station #1 at ±2,300' MD. Pump 80bbls of diesel down the IA and U -Tube to the tubing to freeze protect the well. 28. Set BPV. Post -Rig Procedure: 29. RD mud boat. RD BOPE house. Move to next well location. 30. RU crane. ND BOPE. 31. NU new 4-1/8" 5,000# tree. Test tubing hanger void to 500 psi low/5,000 psi high. 32. Pull BPV. 33. RD crane. Move 500 bbl returns tank and rig mats to next well location. 34. Replace gauge(s) if removed. 35. Turn well over to production. RU well house and flo�wliness.. Attachments: / 1. As -built Schematic 2. Proposed Schematic 3. BOP Schematic ..K f Dlenrn Alk.. LLC. Orig. KB Bev.: 58.8'/ GL Elev.: 24.5 TD =14,124 MD/ 3,637' TVD PBTD=14,115' MD / 3,637' TVD SCHEMATIC TREE & WELLHEAD dlilne Point Unit Well: MP M-22 Last Completed: 9/13/2019 PTD: 219 - 111 Tree Cameron 31/8" SM 9-5/8"1st stage FMC 11" SM TC-lA w/11" x 4 1/2" TC -II Top and Bottom Tubing Wellhead Hanger with 3" CI W "H" BPV profile. Zea 3/8" NPT control lines. OPEN HOLE / CEMENT DETAIL 20"x34" 270f2Cement to surface in a 42" hole 9-5/8"1st stage L-275 sx/T-400 sx in 12-1/4" hole 9-5/8" 2nd stage L-536 sx/T-270 sx in l2-1/4"hole 6-5/8"" Cementless Slotted Liner in 8-1/2" hole CASING DETAIL Size Type Wt/Grade/Conn I ID I Top Btm BPF 20N34" Conductor(Insulated) 215/X-42/Weld N/A Surface 80' N/A 9-5/8" Surface 40/L-80/TXP 8.835" Surface 4,942' 0.0758 7" Tieback 26/L-80/TXP 6.276" Surface 4,784' 0.0383 6-5/8" Uner(Slotted) 20/L-80/Hydril563 6.049" 4,775' 14,120' 0.0355 Slotting Pattern: 4 rows, 8 slots/row, 32 slots/ft, 2" x 0.125" slots, slots on 6" centers, no slot overlap TUBING DETAIL 3-1/2" Tubing 9.2 / L-80 / EUE SRd 2.992" Surface 4,727' 0A087 3/8" Capillary S[ ring Stainless Steel N/A Surface F 4,727 N/A SLOTTED LINER DETAIL Sands Top (MD) Stm (MD) Top (TVD) (Np) FT Date Status 1 4,960' 6,975' 3,840' 3,803' 2,015' 9/10/2019 Open Schrader Bluff 7,257' 9,264' 3,773' 3.654' 2,007' 9/10/2019 Open OA 9,343' 10,469' 3,652' 3,622' 1,126' 9/10/2019 Open 7 11,188' 14,074' 3,664' 3,635' 2,886' 9/10/2019 Open WELL INCLINATION DETAIL E @ 393' Max Hole Angle = 98.45° @ 7,243' IFWELRY DETAIL No. Top MD Item ID Upper Completion 1 29' Tubing Hanger Gen 5 FMC 11"X 4-1/2" TC -II Top & Bottom 2 4,179' 3-1/2" X -Line Sliding Sleeve (in closed positon) 2.803 3 4,235' XN Nipple- ID = 2.750" no go 2.750 4 4,624.7' Discharge Head: PMP 400 - 5 4,625' Ported Discharge Head (Zenith): 400P 6 4,626' Pump 3: PMSXD 134 FLEX 17.5 H6 FER STD - 7 4,649' Pump 2: PMSXD 134 FLEX 17.5 H6 FER STD - 8 4,673' Pump 1: 40OPMSXD 024 GINPSHL H6 FER STD - 9 4,683' Gas Separator: 538GSTHVV MT H6 FER - 10 4,689' Gas Avoider:513HDHS - 11 4,692' Upper Tandem Seal: GSB3DB H6 SB/AB PFSA - 12 4,698' Lower Tandem Seal: GSB3DB H6 SB/AB PFSA 13 4,705' Motor: 562XP 250Hp/ 2,505V/ 61A - 14 4,722' Motor Gauge: Zenith & Centralizer- Bottom @ 4,727' - Lower Completion Locator Sub, TC -II Box x Box (8.25" OD No -Go) 6.200 Bullet Seals (TBSA), Mule Shoe 6.090 E174,775' SLZXP LTP with OG slips(11.27'tie back sleeve)TOL 6.190 Crossover, 7" Hydril 563 Box z 6-5/8" Hydil 56Pin 6.000WIV-Ball on Seat GENERAL WELL INFO API: 50-029-23645-00-00 Drilled, Cased & Completed by Doyon 14 - 9/13/2019 Revised By: TDF 9/20/2019 ..K hila" Alaska. LLC. Orig IB Bev.: 5&8/ GL Elev.: 24.9 n li t A zn' ! 9-W'ES' Cencrter@ 2,152' 7` MnID 2.750"@ 9-5/8" 3011� 2 Q;6 3 CLd TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / TXP 1 3.958" 1 Surface ± 0.0087 Q SLOTTED LINER DETAIL PROPOSED TREE & WELLHEAD dlilne Point Unit Well: MP M-22 Last Completed: 9/13/2019 PTD: 219 - 111 Tree Cameron 31/8" 5M Wellhead FMC 11" 5M TC -3A w/11" x 4 1/2" TC -II Top and Bottom Tubing 9-5/8" 2nd stage Hanger with 3" ClVV "H" BPV profile. Zea 3/8" NPT control lines. OPEN HOLE/ CEMENT DETAIL 20"x34" 270 ft3 Cement to surface in a 42" hole 9-5/8"1st stage L-275 sx/T-400 sx i n a 12-1/4" hole 9-5/8" 2nd stage L-536sx/T-270sxina 12-11C hole 6-5/8"" Cementless Slotted Liner in 8-1/2" hole r"i t.T�lnn 0lic Size Type Wt/ Grade/ Conn ID Top Btm BPF 20"x34" Conductor (insulated) 215/X-42/Weld N/A Surface 80' N/A 9-5/8" Surface 40 / L-80 /TXP 8.835" Surface 4,942' 0.0758 7" Tieback 26/L-80/TXP 6.276" Surface 4,784' 0.0383 ✓t-5/8" Liner (Slotted) 20/L-80/Hydril 563 6.049" 4,775' 14,120' 0.0355 Slotting Pattern: 4 rows, 8 slots/row, 32 slots/ft, 2" x 0.125" slots, slots on 6" centers, no slot overlap 4 5 6 7 8 12 13 so Solidi Slatted Urex Detail 9,10&11 Hole ' 6.5/8" de 14 To= 14,1W MD/3,637TVD PBTD =14,115' MD/ 3,637 TVD Sands Top (MD) Btm (MD) Top (TVD) (Np) FT Date Status 1 4,960' 6,975' 3,840' 3,803' 2,015' 9/10/2019 O en Schrader Bluff 7,257' 9,264' 3,773' 3.654' 2,007' 9/10/2019 Open OA 9,343' 10,469' 3,652' 3,622' 1,126' 9/10/2019 Open 7 11,188' 14,074' 3,664' 3,635' 2,886' 1 9/10/2019 Open WELL INCLINATION DETAIL KOP@ 393' Max Hole Angle = 98.45° JEWELRY DETAIL No. TOP MD Item ID Upper Completion 1 ±29' Tubing Hanger Gen 5 FMC 11"X 4-1/2" TC -II Top & Bottom 3.970" 2 ±2,300' GLM (Shear out valve pre -loaded) 3 ±4,120' 4.5" Discharge Pressure Gauge Mandrel (Discharge Gauge) 3.874" 4 ±4,125' 4.5" XD Sliding Sleeve (m JP set on xx/xx/xx) 3.813" 5 ±4,150' 4.5" X Nipple (3.813" Packing Bore) 3.813" 6 ±4,155' 4.5" Gauge Mandrel w//°" Wire (Intake Gauge) 3.889" 7 ±4,180' 7" x4.5" PHL Retrievable Packer 3.890" 8 ±4,200 4.5" XN Nipple (MIN ID = 3.725") (RHC plug body) 3.725" 9 4,773' Locator Sub, TC -II Box x Box (8.25" OD No -Go) 6.200 10 4,775' Bullet Seals (TBSA), Mule Shoe 6.090 11 4,775' SLZXP LTP with DG slips(11.27'tie back sleeve)TOL 6.190 12 ±4,820 4.5" WLEG 3.958" 13 4,960' Crossover, 7" Hydril 563 Box x 6-5/8" Hydril 563 Pin 6.000 14 14,115' WIV — Ball on Seat GENERAL WELL INFO API: 50-029-23645-00-00 Drilled, Cased & Completed by Doyon 14 —9/13/2019 Revised By: TDF 11/6/2019 Milne Point ASR Rig 1 BOP@ 2019 11" B®PE Updated 1/05/2018 >-7/8" x 5" VBR. m 'es a a s F\ N N a d 3 v v O a a c 7 0 a CL a w U) 0) c A r V v d a y i I x it d O •• d NCo U C U d E� E U " C (DE d 3 0- >-E v � c � o N d o n o d n'� a o - m a� cm m O d w NC M co L C C U 6 d L U w `o o CL N O" 0 OCL c a 3 mU c Q d E d U d a m d c 3 v v� C =� No o� d d �o l0 o 3 N O d U � C E0 U U co QQ c d ad+ d � R r U � V @ C a 0 12 Q Cd Qa dN R a° x o. — a am .0 xuaic am d Ol C s U d 0 CL` 0 d CL a Y fq cc 0 CL o_ El Y R v m CL a Hilcorp �InrL::. IL(. DATE 10/25/2019 Deura Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 MPU M-22 (219-111 MPU M-22 PB1]MI Halliburton LWD FINAL 15 SEP 2019 M-22 61 HALLIBURTON FINAL LOGS > MPU M-22 v rl Search M Name Date modified 7 CGM 10/25!201911:46... F Definitive Survey 10/25/201911:46... F EMF 10/25/201911:46 ... F LAS 10125/201911:46 ... F PDF 10/25/201911:46 ... F TIFF 1D.%25/201911:46... F M-22 PB1 M FINAL LOGS , MPU M-22 PBl v i'J Search Nzme Date modified CGM 10/25/201911:48 ... Definitive Survey 10/25/201911:48... EMF 10/25/201911:48 ... LAS 10/25/201911:48 ... PDF 1 0/25/201 9 11:48 ... TIFF 10/25.201911:48 ... Please include current contact information if different from above. RECEIVED NOV 01 2019 AOGCC 21 91 11 31402 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 DATE 10/25/2019 I _ora Oudean Hilcorp Alaska, LLC GcoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 MPU M-22 (219-111) Name MPU M-22 PB1 10,27; 901911:45... F Definitive Survey 1C�'25,2D1911:46... F EMF Halliburton LWD FINAL 15 SEP 2019 M-22 Bt_HALLIBURTON FINAL LOGS > MPU M-22 v Search Iv1 Name Date modified T CGM 10,27; 901911:45... F Definitive Survey 1C�'25,2D1911:46... F EMF 10/25/21)1911:46 F LAS 1G..`25!2G1911:4E... F PDF 10/2V201911:415... F TIFF 1C4'2:/201911:46... F M-22 PBS IN FINAL LOGS > MPU M-22 PB1 v t1 Search Name Date modified CGM 10/25/2019 11:48 ... Definitive Survey 10;2 201411:49... EMF 1025'_311911:43... LAS 1C;:_ 2=1911:46.,, PDF 10':_ _15 11:48,.. TIFF 10/2�:12C;1� 11:49.... Please include current contact information if different from above. RECEIVED NOV 0 1 2019 AOGCC 219111 31403 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG_ 1a. Well Status: Oil Q Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ suspended[] 1b. Well Class: 20 C 25.105 20AAC 25.110 Development Q '' Exploratory ❑ GINJ ❑ WINJ ❑ WAG❑ 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 Abend.: 9/13/2019 219-111 ' 3. Address: 7. Date Spudded: 15. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 August 24, 2019 50-029-23645-00-00 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: 5039' FSL, 500' FEL, Sec 14, T13N, R9E, UM, AK September 7, 2019 MPU M-22 Top of Productive Interval: 9. Ref Elevations: KB: 58.8' 17. Field / Pool(s): Milne Point Field 653' FNL, 709' FEL, Sec 14, T13N, R9E, UM, AK GL:24.9' BF:24.9' Schrader Bluff Oil Pool Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 782' FSL, 1344' FEL, Sec 23, T1 3N, R9E, UM, AK 14,115' MD / 3,637' ND ADL025514 / ADL355023 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- 533663 y- 6027889 Zane- 4 14,120' MD / 3,637' ND LONS 16-004 TPI: x- 533457 y- 6027476 Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MDITVD: Total Depth: x- 532871 y- 6018350 Zone- 4 N/A 2,01 VMD / 1,856' ND 5. Directional or Inclination Survey: Yes ✓ (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/ABG/DGR/EWR/ADR 2"/5" MD ABG/DGR/EWR/ADR 275" ND PB1 23. CASING, LINER AND CEMENTING RECORD WT. PER CASING FT GRADE D SETTING DEPTH MD SETTING DEPTH NHOLE SIZE AMOUNT CEMENTING RECORD PULLED TOP BOTTOM TOP BOTTOM 20" 216# X-52 Surface 114' Surface 114' 42" ±270 ft3 9-5/8" 40# L-80 Surface 4,942' Surface 3,838' 12-1/4" Stg 1 L - 275 sx / T - 400 sx Stg 2 L - 536 sx / T - 270 sx 241 bbls 7" 26# L-80 Surface 4,784' Surface 3,826' Tieback Tieback Assy. 6-5/8" 20# L-80 4,775' 14,120' 3,825' 3,637' 8-1/2" Cementless Slotted Liner 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): 3-1/2" 4,727' MD 4,775' MD 13,825- ND "Please see attached schematic for slotted liner detail" Liner run on 9/10/19 COMPLETION 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. D T ( &I V Hj I � --QTS=PRODUCTION Was hydraulic fracturing used during completion? Yes ❑ No ✓ Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): 9/22/2019 ESP Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: 9/28/2019 24 Test Period 960.8 738.9 0 N/A 769 Flow Tubing Casing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 324 310 24 -Hour Rate --► 960.8 738.9 0 16 Form 10-407 Revised 5/2017 "�' /;i I CONTINUED ON PAGE 2 -ASDMSI*v OCT 9 7 2019 Submit ORIGINAL onl 0 14 - .Z-7 -15 1 28. CORE DATA Conventional Core(s): Yes ❑ No Q Sidewall Cores: Yes ❑ No Q If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑� If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 2,011' 1,856' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval SB OA 4,960' 3,840' information, including reports, per 20 AAC 25.071. SV5 1,384' 1,314' ` SV1 2,050' 1,890' Ugnu LA3 3,387' 3,150' SB NA 4,077' 3,657' SB OA 4,867' 3,833' Formation at total depth: SB OA ` 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Report, OH Sidetrack Summary. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email:.cdinger@h'ilcorp.com Authorized Contact Phone: 777-8389 Signature: Date: f o. 3 • 1 C7 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 (Tap 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 H corp Alaska, LLC Orig. KB Elev.: 58.9/ GL Elev.: 24.9' TD=14,124 MD / 3,637 TVD PBTD=14,115' MD / 3,637 TVD SCHEMATIC TREE & WELLHEAD Milne Point Unit Well: MP M-22 Last Completed: 9/13/2019 PTD: 219 - 111 Tree Cameron 31/8" SM 9-5/8" 1st stage FMC 11" SM TC -1A w/11" x 41/2" TC -II Top and Bottom Tubing Wellhead Hanger with 3" CIW "H" BPV profile. Zea 3/8" NPT control lines. OPEN HOLE / CEMENT DETAIL 20" x 34" 270 ft3 Cement to surface in a 4Y' hole 9-5/8" 1st stage L-275 sx / T-400 sx in a 12-1/4" hole 9-5/8" 2nd stage L-536 sx / T-270 sx in a 12-1/4" hole 6-5/8"" Cementless Slotted Liner in 8-1/2" hole CASING DETAIL Size Type Wt/Grade/Conn ID Top I Btm BPF 20"x34" Conductor (Insulated) 215/X-42/Weld N/A Surface 80' N/A 9-5/8" Surface 40/L-80/TXP 8.835" Surface 4,942' 0.0758 7" Tieback 26/L-80/TXP 6.276" Surface 4,784' 0.0383 6-5/8" Uner(Slotted) 20 / L-80 / Hydril 563 6.049" 4,775' 14,120' 0.0355 Slotting Pattern: 4 rows, 8 slots/row, 32 slots/ft, 2" x 0.125" slots, slots on 6" centers, no slot overlap TUBING DETAIL 3-1/2" Tubing 9.2/L-g0/EUE8Rd 2.992" Surface 4,727' 0.0087 3/8" Capillary String Stainless Steel N/A Surface 1 4,727' N/A SLOTTED LINER DETAIL Sands Top (MD) Btm (MD) Top (TVD) (Np) FT Date Status 1 4,960' 6,975' 3,840' 3,803' 2,015' 9/10/2019 Open Schrader Bluff 7,257' 9,264' 3,773' 3.654' 2,007' 9/10/2019 Open OA 9,343' 10,469' 3,652' 3,622' 1,126' 9/10/2019 Open 7 11,188' 14,074' 3,664' 3,635' , 2,886' 9/10/2019 Open WELL INCLINATION DETAIL KOP @ 393' Max Hole Angle= 98.45° @ 7,243' JEWELRY DETAIL No. Top MD Item ID Upper Completion 1 29' Tubing Hanger Gen 5 FMC 11"X 4-1/2" TC -II Top & Bottom 2 4,179' 3 -1/2"X -Line Sliding Sleeve (in closed positon) 2.803 3 4,235' XN Nipple- ID=2.750" no go 2.750 4 4,624.7' Discharge Head: PMP 400 - 5 4,625' Ported Discharge Head (Zenith): 400P - 6 4,626' Pump 3: PMSXD 134 FLEX 17.5 H6 FER STD - 7 4,649' Pump 2: PMSXD 134 FLEX 17.5 H6 FER STD - 8 4,673' Pump 1: 400PMSXD 024 GINPSHL H6 FER STO - 9 4,683' Gas Separator: 538GSTHVV MT H6 FER - 10 4,689' Gas Avoider: 513HD HS - 11 4,692' Upper Tandem Seal: GSB3DB H6 SB/AB PFSA 12 4,698' Lower Tandem Seal: GSB3DB H6 SB/AB PFSA - 13 4,705' Motor: 562XP 25OHp/ 2,505V/ 61A - 14 4,722' Motor Gauge: Zenith & Centralizer- Bottom @ 4,727' - Lower Completion 15E4,773'Locator Sub, TC -II Box x Box (8.25" OD No -Go) 6.200 16Bullet Seals(TBSA), Mule Shoe 6.090 17SLZXP LTP with DGslips(11.27'tie back sleeve)TOL 6.190 18Crossover, 7" Hydril 563 Box x 6-5/8" Hydril 563 Pin 6.000 19WIV-Ball on Seat GENERAL WELL INFO API: 50-029-23645-00-00 Drilled, Cased &Completed by Doyon 14-9/13/2019 Revised By: 9/20/2019 MPU M-22 OH Sidetrack Summary PB1 TD 12,932' MD / 3,613' TVD KOP 12,700' MD Date 9/6/2019 PTD: 219-111 / API: 50-029-23645-00-00 n Well Name: MP M-22 Field: Milne Point County/State: , Alaska (LAT/LONG): avation (RKB): API #: Spud Date: Job Name: 1913621 D MPU M-22 Drilling Contractor Doyon 14 AFE #: Hilcorp Energy Company Composite Report Activity Date.. Ops Summary 8/2 312 01 9 P/U 9 joints & rack back 3 stands in the derrick. Process 42 more joints of 5" drill pipe. P/U 12 joints & rack back 4 stands In the derrick. 26 of 51 stands.;P rform diverter test w/ AOGCC representative Jeff Jones witnessing testing. Close 21-1/4" annular on 5" drill pipe. 9 sec. knife valve opening & 27 sec. annular closing. 3075 PSI system pressure, 1875 PSI after closing, 34 sec. 200 PSI recovery & 157 sec. full recovery.;Test gas alarms - one Fail / Pass on #2 H2S sensor - recalibrate & retest good. 212' total 16" diverter line, 20T from substructure & 188' from nearest ignition source. - Initial notification for inspection at 10:56 on 21 August 2019 "';P/U 30 joints & rack back 10 stands in the derrick. Process 42 more joints of 5" drill pipe. P/U 42 joints & rack back 14 stands in the derrick. Process final 27 joints of drill hydraulic leak on pipe skate manual control valve. Adjust brakes on draw works.;P/U 27 joints & rack pipe.;Repair back 9 stands in the derrick utilizing single joint elevators w/ the tugger. Write procedure for this operation and practice with crew.;P/U 17 joints of 5" HWDP and jars & rack back 6 stands in the deuick.;Mobilize BHA components to the rig floor. Conduct pre -spud meeting with all parties involved. M/U 12-1/4" KMX633 Kymera bit, 8" mud motor, bottleneck XO to 36 and one stand of HWDP.;Hilcorp operations instructed rig to switch from high line power to generator power due to turbine issues. Start two generators and call out rig electrician from camp. Go off high line power and power rig with #1 Cat generator.; Unable to close breaker on #2 or #3 Cat generator. Unable to drill with only one generator. Rig electrician trouble shooting breaker. Sim ops: Process 9-5/8" casing. 812412019 Continue to Trouble shoot Gen #2 & Gen #3 Breakers. Process casing while waiting. Breaker issue resolved and temp sensor bypassed on #3.;P/U NMFDC & stand back in the derrick. M/U MWD tools and stand back in the denick.;PSM with all hands. Flood stack with water & fill conductor. Tighten 4" dump valves. Test lines to 3500 psi. Good. RIH & tag atm of conductor at 114'.;Drill to 120 & displace to Spud mud. Drill to 220' at 335-450. 20- 40 RPM. Back ream up to conductor & circ clean. POOH & stand back HW DP.;Inspect Kymem bit. Good. WU MWD from derrick to 84'.;Attempt to upload tools. Failed. PDC low voltage. Break down MWD tools and change out PWD & HICM. Make back up and upload. Good. Make up remainder of BHA to 174'. Calibrate blocks and T1 to 220'.; Drill 12-114" surface hole f/ 220' V 731', 511' drilled, 79'/hr AROP. 450 GPM, 1130 PSI, 40 RPM, 5K TO, 10-15K WOB. 83K PU / 82K SO 181 K ROT. 8.8 ppg MW, 167 vis, 10.1 ECD. Began 4°/100' build at 330r.; Drill 12-114" surface hole f/ 731' U 1309, 569' drilled, 1 267h AROP. 450 GPM, 1280 PSI, 60 RPM, 5K TO, 9-15K WOB. 90K PU / 86K SO / 88K ROT. 9.15 MW, 100 vis, 10.3 ECD. Hold 28.95° tangent from 1150'. Last survey at 1244.42' MD / 1190.98' TVD, 29.05° inc, 359.69° azm, 5.16' from plan, 4.21' high.;Top drive VFD tripping and difficult to reset. Call out electrician to troubleshoot. Work pipe and circulate occasionally to ensure pipe is free - no problems. Power down entire system, restart and system working properly.;Hauled 1540 bbis H2O from L - Pad Lake for total = 1540 bbls 8/25/2019 Hauled 230 bbis cuttin /li uids to MPU G&I for total= 230 bbis Drill 12-1/4" surface hole f/ 1300't/ 1398', 98' drilled-, 987hr AROP. 500 GPM, 1460 PSI, 60 RPM, 7K TO, 15-17K WOB. 95K PU / 86K SO / 91 K ROT. 9.1 ppg MW, 117 vis, 10.5 ECD.;Trouble shoot top drive VFD, reset.;Drill 12-114" surface hole f/ 1398't/ 1493', 95' drilled, 957hr AROP. 490 GPM, 1470 PSI, 60 RPM, 7K TO, 7-10K WOB. 95K PU / 86K SO / 91 K ROT. 9.15 ppg MW, 195 vis, 10.5 ECD.;Trouble shoot top drive VFD. Change out top drive blower motor.;Drill 12-1/4" surface hole fl 1493't/ 1589, 96' drilled, 192'/hr AROP. 500 GPM, 1600 PSI, 60 GPM, 7K TO, 12K WOB.;Top drive shut down again. Bypass fault.;Drill 12-1/4" surface hole V 1589' V 2003', 414' drilled, 11 87h AROP. 500 GPM, 1600 PSI, 60 RPM, 7K TO, 10-1 SK WOB. 110K PU / 92K SO / 96K ROT. 9.1 ppg MW, 127 vis, 10.1 ECD, 126u max gas.;Drill 12-1/4" surface hole f/ 2003't/ 2824', 821' drilled, 1377hr AROP. 530 GPM, 1560 PSI, 80 RPM, 7K TO, 10K WOB. 130K PU / 107K SO / 115K ROT. 9.1. ppg MWD, 76 vis, 9.9 ECD, 108u max gas.;Drill 12-114" surface hole V 2824'V 3587', 763' drilled, 127'/hr AROP. 550 GPM, 1910 PSI, 80 RPM, 7K TO, 8-20K WOB. 153K PU / 113K SO / 131 K ROT. 9.2 ppg MWD, 135 vis, 9.9 ECD, 29u max gas. Survey @ 3525.31' MD / 3273.37' TVD, 34:82" inc, 184.54° azm, 20.38' from plan, 19.27' low, 6.63' right.;Hauled 415 bbis H2O from L -Pad Lake for total = 1955 bbis Hauled 300 bbls H2O from A -Pad for total = 300 bbis Hauled 1224 bbis cuttinc0quids to MPU G&I for total= 1454 bbis 8/26/2019 Drill 12-1/4" surface hole f/ 3587' V 4158'. 571' drilled, 95' /hr AROP. 550 GPM, 2010 PSI, 80 RPM, 18K TO, 18-20K WOB. 170K PU / 111 K SO / 135K ROT. 9.1 ppg MW, 60 vis, 10.1 ppg ECD. Max gas 336u.;Drill 12-1/4" surface hole fl 4158' V 4700', 542' drilled, 907hr AROP. 530 GPM, 1740 PSI, 80 RPM, 16K TO, 20-25K WOB. 160K PU / 105K SO / 120K ROT. 9.3 ppg MW, 60 vis, 10.1 ppg ECD. Max gas 313u.;Drill 12-1/4" surface hole f/ 4700't/ 494T, 247' drilled, 827hr AROP. 450 GPM, 1720 PSI, 40 RPM, 15K TO, 20K WOB. Reduced parameters to keep assembly from dropping during the ESP pump tangent. 153K PU / 102K SO / 115K ROT. 9.2 ppg MW, 99 vis, 11.0 ppg ECD. Max gas 127u.;Survey @ 4888.78' MD 13834.50' TVD, 85.61' inc, 184.76" azm, 15.68' from plan, 12.33' high, 9.69' left. ESP pump tangent from 4672' to 4920' = 248'. SB OA -1 at 4883' MD / 3834' TVD.;Obtain final survey & add water to pit #4 for low vis sweep. Pump tandem low vis / high vis sweeps. 550 GPM, 1900 PSI, 80 RPM, 14K TO. Reciprocate 80'. Zero increase from sweep, observed 2000 strokes late. Rack a stand back each bottoms up to 4668' & continue conditioning the mud for 4x bottoms up.;Trip in hole f/ 4668'V 4947' on elevators. Perform 5 min. flow check - static.;Back ream out of the hole It 494T 113533'. 550 GPM, 1770-1900 PSI, 80 RPM, 13-20K TO at 5 ministand. Slow to 10 - 15 min/stand due to torque which corresponds to slide intervals.;Hauled 1250 bbis H2O from L -Pad Lake for total = 3205 bbis Hauled 1200 bbis H2O from A -Pad for total = 1500 bats Hauled 2158 bbis cutting/liquids to MPU G&I for total= 3612 bbis 827/2019 Back ream out of the hole f/ 3533' t/ 1685' pumping 550 GPM, 1750 PSI, 80 RPM, 13K TO at 5 min/stand. Slow to 10 -15 min/std to cleanup slide intervals. Hole unloaded @ 1750' slow rate to 400 GPM and let cleanup before continuing. Avg 10.2 ppg ECD. No losses BROOH.;Continue BROOH f/ 1685 to 73T at HWDP pumping 550 GPM, 1750 PSI, 80 RPM, 13-4.6K TO. at 5 min/std, slow down cleaning up slide intervals or when ECDs start climbing above 10.2 ppg.;Flow check well, static. POOH on elevators f/ 733't/86' Racking HWDP & Jars in the Derrick and laying down the flex collars.;Down load MWD data, UD BHA & Drain motor. Break out bit. Bit grade- 0 -1 -WT -A -E -1 -NO -TD. Clean and clear rig floor.;Service rig, grease top drive and draw works.;Mobilize casing equipment to the rig floor. R/U Volante, strap tongs, long bails, 9-5/8" side door elevators and 350T 9-5/8" spiders. M/U FOSV to casing XO. 1.5 BPH static Iosses.;PJSM. M/U shoe track to 202'. Pump through shoe track - good. Check floats - holding. Torque 9-5/8" 40# L-80 TXP-BTC to 20,960 ft/lbs w/ Volante. Two 9-5/8"02-1/4" Expando-lizers on shoe joint & one each on Baker -Loc, float collar, baffle adapter & joint #5. 5.6 bbl lost, 1.8 BPH.;Run 9-5/8" 40# L-80 TXP-BTC surface casing f/ 202' t/ 2764'. Torque to 20,960 ft/lbs with the Volante tool. One 9-5/8"x12-1/4" Expand-o-lizer on joints #6 to #26, then every other joint to #64 and every joint #66 to #70. 17.6 bbis lost for casing run to this point.; Hauled 715 bbls H2O from L -pad lake for total= 3920 bbls Hauled 0 bbis H2O from A -pad for total = 1500 bbis Hauled 280 bbis Source Water from G&I for total = 280 bbis Hauled 899 bbis cuttings/liquid to MPU G&I for total = 4511 bbis 8/2 812 01 9 CBU @ 2764' staging pump to 6 bpm, 180 psi, 2 bbl Iosses.;M/U ESIPC as per HES rep, continue to Run 9-58" 40# L-80 TXP-BTC csP f/ 2802' to 3159' @ jt 79 TO to 20,960 ft/lbs, joint 79 pin and jt 80 box damaged while M/U. Install 1 centralizer ea on 6 jts above and below ESC. Fill on the fly and top off every 10 jts ran.; UD damaged joints 79 and 80, replace with jts 131 and 142, C/O collar on jt 78.;Continue to Run 9-5/8" 409 L-80 TXP-BTC csg f/ 3159' tt 4850' @ jt 122. damaged pin from M/U, UD jt 122 and replace w/ jt 126, C/O collar on jt 121. TO to 20,960 fUlbs. Install centralizer on every other It f/ 77 to 121, with last centralizer on jt 122. Loss rate 3 bph, 25 bbls total.;Damaged pin and box from M/U, UD jt 122 and replace wl jt 126, C/O collar on jt 121.;Wash last 2 joints, 5' and 15' csg pups down to 4942' pumping 2 bpm, 150 psi, verify pipe count. ( 82 centralizers total ) (124 jts casing ran ). PU/SO 2401k/1401k.;Circulate and condition, stage pump slowly to 6 bpm, 160 psi, rotate 1.2 rpm 20k torque while reciprocating pipe 20'. "" 24 hour notification to AOGCC of upcoming BOP test at 18:21 on 28 August 2019 "';Break out Volant, blow down top drive and rig up cement Iines.;Continue to circulate & condition the mud through cement line, 6 BPM, 260 PSI, 2 RPM, 20K TO. Reciprocate 20'. Hold PJSM with all parties involved. Verify lines from cement unit to rig floor are clear.;Perform 1st stage cement job. Pump 5 bbis water @ 3.5 BPM, 170 PSI. Pressure test lines 1500 PSI / 4000 PSI. Mix & pump 55 bbis 10.0 ppg Tuned Spacer - 4# red dye & 5# Pol-E-Flake in tat 10 bbls, 3.5 BPM, 140 PSI. Load by-pass bottom olua.:Miz & Pump 115 bbls 12.0 ppa lead cement 275 sks, 2.349 ftA3/siryield) 4.0 BPM, 230 PSI. Mix & pump 82.4 bbls 15.8 ppq tail cement 400 sks 1.157 ftAXskyield) 3.35 BPM 345 PSI. Loa shut -oft plug.;Pump 20 bbis of water, 5.2 BPM, 265 PSI. Displace from rig w/ 9.3 ppg spud mud,5 BPM, 140 PSI - 172.1 bbls. Displace from Halliburton w/ 9.4 .. / ppg Tuned Spacer, 3.5 BPM, 220 PSI - 80 bbls. Displace from rig w/ 9.3 ppg spud mud, 5 BPM, 550-690 PSI -80 bbis. Reciprocate pipe 20' & rotate 2 RPM 5 @ 20K TQ.;SIow to 3 BPM, 590-640 PSI - bumped plug @ 91.61 bbis (907 stirs): 1.94 bbis (19 stks) early. CIP @ 00:14. Pressure up 1100 PSI - holding good. Bleed off to check floats - holding. Pump at 2 BPM: observed packer start to inflate @ 2200 PSI, cementer opened @ 3130 PSI.29 bbls lost during displacement.;lncrease rate to 10 BPM, 2600 PSI through cementer @ 2152'. Observe trace Pol-E-Flake @ 770 stirs. Began overboarding interface @ 1200 stks. Slow to 8 BPM, 1850 PSI. Cement interface @ 1900 stks & cement @ 1986 stks. Back to interface at 2065 stks, 8 bbls of cement & 130 bbis of spacer back.;Retum to pits @ 3200 stks. Increase to 13 BPM, 2800 PSI. At 4800 stks the pressure dropped to 1250 PSI. Shut down check both pumps - good. Cementer appeared to fully open. Continue to circulate @ 13 BPM to 8000 stks. No losses while circulating.;Disconnect knife valve accumulator lines. Flush stack with black water, function annular three times. Clean surface equipment. Reconnect knife valve accumulator Iines.;Continue to circulate through cementer at 2152' at 6 BPM, 225 PSI. Empty pits, rockwasher, vac trucks and super suckers preparing for 2nd stage cement job. Cement crews resting. Cement will be at 100 PSI compressive strength at 07:14 No losses while circulating.;Wait on super suckers and vac trucks to return from G&I. Milne lost turbine 07 and G&I was down from 22:00 to 24:00 and 02:15 to 03:30 backing up disposal.;Hauled 120 bbis H2O from L -Pad Lake for total = 4040 bbis Hauled 0 bbis H2O from A -Pad for total = 1500 bbis Hauled 290 bbis Source Water from G&I = 570 bbis Hauled 585 bbis cutting/liquids to MPU G&I for total = 5096 bbls Daily (midnight) losses = 68.5 bbis, cumulative losses = 68.5 bbis . 8/29/2019 Continue to circulate through cementer at 2152' at 6 BPM, 225, W/O super suckers to arrive back from G & I for 2nd stage cement job. Cement will be at 100 PSI compressive strength at 07:14. No losses while circulatina.:Continue to circ at 6 bpm while wafting on cmt. Conduct PJSM for 2nd stage with all parties involved at 0800. Break out volant, clean, re -dope cup, M/U volant .;Line up to HES Pump 5 bbl H2O, PT Lines. Pump 60 bbl 10# spacer with red dye and SX) 5.5 BPM, 460 flake 225 bbls .5 ppb Poly flake in the firs 10 bbis 3.5 bpm 150 psi. Pump 420 bbis of 10.7# lead Perm L Cmt. ( 536 psi.;Seeing poly @ 2 away, good mud push back at 294 bbis away. Got good cmt back at 400 bbis away.;Pump 56.2 bbl of 15.8 Tail cmt 4 bpm, 160 psi ICP, 370 psi PSI FCP (270 SX). Drop closing plug and chase with 20 bbl H2O From HES. Line up to rig, Pump 134.8 bbis 9.3 mud, 1335 strokes at 6 BPM 350 ICP, 650 FCP, last 10 bbis slow to 3 bpm 430 psi.;Bump plug @ 141 bbis away, 1396 strokes, 39 strokes early. Pressure up to 1360 psi over FCP at 430 psi, shifting cementer tool closed, check floats, good, bleed off pressure, CIP @ 11:35. (60 bbis tuned spacer and 241 bbis good cement returned to surface ). No Iosses.;Flush all surface equipment with black water. Drain stack, clean cellar box. UD both mouse holes. Remove diverter pipe. R/D Volant, Clean and clear rig floor of casing tools and equipment.;N/D diverter and lift diverter equipment. Install casing slips as per wellhead rep. with 105K on slips. Rough cut casing. N/D surface diverter stack, riser, bell nipple & diverter tee.;Perform final out of 93/8" casing (16.63' total cut). Install FMC slip lock head, tubing spool and casing spool. Test slip lock head to 500 PSI for 5 min. and 2475 PSI for 10 min. - good tests.;lnstall MPD head on annular with BOP stack on the stump. Rig and hoist into place. Install studs and torque bolts with Sweeney wrench. Install test plug in the casing head.;N/U BOP stack - align to accommodate new 90' mousehole. Sim -ops: inspect saver sub - worn. Begin changing out.;Hauled 205 bbis H2O from L -Pad Lake for total = 4245 bbls Hauled 0 bbis H2O from A -Pad for total = 1500 bbis Hauled 250 bbis Source Water from G&I = 820 bbis Hauled 1646 bbis cutting/liquids/cement to MPU G&I for total = 6742 bbis Daily (midnight) losses = 0 bbls, cumulative losses = 68.5 bbls 813012019 N/U BOPE, install choke and kill Iines.;Safety stand down, shut down operations to investigate hand injury while torqueing BOP flange bolts.;Continue to NIU BOPE, install choke and kill lines, install stack anchors, R/U MPD lines, install accumulator lines, power up koomy. Install mouse hole. Smops: C/O saver sub, inspect and C/O grabber dies.;R/U to test BOPE, flood stack and lines with water, with MPD test cap in place pressure test RCD spool to 250 psi low, 1500 psi high, good.;Remove test cap, install trip nipple and leak test, good. Obtain stack measurements.; Install 5" test joint, R/U test equipment. Attempt BOP shell test, leaking on choke line flange under rig floor, tighten same and re-test: good shell test.;Perform initial BOP testing as per AOGCC & Hilcorp requirements. AOGCC rep. Matthew Herrera witnessing testing. All testing performed with water to 250 PSI low & 3000 PSI high for 5 min. each. #1: Upper 4.6'x7" VBR on 5" test joint, valves #1, 12, 13, 14, 3" kill Demco, upper IBOP - #1 valve failed.;#2: Valves #9, 11, kill HCR, lower IBOP - passed. #3: Valves #5, 8, 10, kill manual, 5" FOSV #1 - valve 98 F/P - service, function, retest- passed. #4: Valves #4, 6, 7, 5" FOSV #2 - passed. #5: Valve #2, 5" dart valve - passed. #6: Lower 2.875"x5" VBR on 5" test joint - passed.;#7: Annular on 3.5" test joint, choke HCR - passed. #8: Lower 2.875"x5" VBR on 3.5" test joint - passed. #9: Upper 4.5"x7" VBR on 7" test joint, choke manual - passed. #10: Blind rams, valve #3 - passed. #11: Hyd choke "A" - passed. #12: Hyd choke "B" passed.;Accumulator test on 5" test joint: System pressure: 3025 PSI, after closure: 1700 PSI, 200 PSI recovery: 43 sec., full recovery: 207 sec. 6 nitrogen bottles: 1975 PSI average. Test 142S & LEL gas alarms - passed. Test PVT & flow alarms - passed.;Replace choke valve #1 on choke manifold after test failure.;Retest choke valve #1 after replacement. Test against upper 4.5"x7" VBR on 5" test joint, valves #1, 12, 13 & 14 All testing performed with water to 250 PSI low & 3000 PSI high for 5 min. each. Testing complete - 10 hours total test time.;R/D test equipment. Remove test plug, install 9.125" 1. D. wear bushing and UD test joint. Blow down choke & kill lines and choke manifold.; Hauled 50 bbis H2O from L-Pad Lake for total = 4295 bbis Hauled 0 bbis H2O from A-Pad for total = 1500 bbls Hauled 0 bbis Source Water from G&I = 820 bbis Hauled 0 bbls cutting/liquids/cement to MPU G&I for total = 6742 bbis Daily (midnight) losses = 0 bbis, cumulative losses = 68.5 bbis 8/3112019 Finish installing 9 1/8" WB, RI 4 LDS. install split bushing, mobilize mpd bearing to rig floor, install mouse hole.;PJSM, M/U cleanout BHA #2, 8 1/2" MT bft, dial mud mtr down If 1.5 to 1.15 deg, 5 stds 5" HWDP, jar std to 590.63'.;Make a practice connection in mouse hole to ensure ST80 will fit With enough clearance from drill string while drilling.;TIH f! 590' to 2113', M/U TD, fill pipe, wash down 2.5 bpm, 170 psi, tag @ 2147'.; Drill out cmt and plug, Drill ESI PC on depth f/ 2152' to 2155' pumping 436 gpm, 900 psi, 60 rpm, 3-51k torque, 2-6k wob, Ream and cleanup 2 times, pass thru w/ no issues w/ pump off. PU/5O/ROT 102K/90K/98K.;25k down drag, ream 1 stand down U 2208' to 2303' 450 gpm, 900 psi, 60 rpm, 5k torque until no more down drag. BD TD.;TIH on elevators f/ 2303to 3732', conduct trip drill while WU stand, well secure in 4 min.;PJSM, Rig and Hilcorp Electricians put rig on Hi Line power at 13:50 hrs.;Continue to TIH f/ 3732', tag TCC with 20k set down, 51' above BA @ 4767'. Correct displacement on TIH.;M/U TD. Fill pipe. Get parameters, Circulate 1� �/ 11 (/ 270 gpm, 550 psi dumping thick mud returns to rock washer increase to 400 gpm, 900 psi, 20 rpm working pipe. Drill soft cmt f/ 4767' to 4777 450 gpm, 30 rpm, 15k TQ, 5k WOB. PU/SO/ROT 180K175K/110K.;CBU 450 GPM, 1080 psi, reciprocate and rotate 20 rpm treating contaminated returns to pits.;Poskion tool joint above table parking at 4747', R/U test equipment, close UPR. flood lines. Test 9 5/8" casing to 2600 psi for 30 charted min. good test, bleed off pressure, open UPR. R/D test equipment, BD lines. 4.5 bbis pumped, 4.5 bbis bled back.;Drill cement f/ 4777' U 4818' w/ 450 GPM, 1100 PSI, 60 RPM, 16K TO. Drilled baffle adapter on depth f/ 4818'1/ 4820' & float collar fl 4659't) 4860'. Reamed through 3x times & slack off w/ no drag. Drilled cement It 4860'1/ 4940' then drilled float collar to 4942'. Cleaned out rat hole to 4947' Drill 20' of new 8-1/2" hole f/ 4947't' 4967'.;Circulate and condition mud for FIT 450 GPM, 1080 PSI, 60 RPM, 14k TQ. 9.0 ppg / 41 vis in and 9.0 ppg 46 vis out. Max gas 320u. Rack back stand to 4875'. Perform flow check - static.;Rig up test \ equipment & close upper 4.5'x7" VBR on 5" drill pipe and pump down drill string & kill line. Attempt FIT, pressure building good but bleeding off too fast and too low. Appears to be air in the system. Circulate the drill pipe volume at 360 GPM, 850 PSI.;Perform FIT to 12.0 ppg, close upper 4.5"x7" VBR on 5" drill pipe 51\/ and pump down drill string & kill line. Pressure up to 600 PSI with 9.0 ppg mud 9-5/8" casing shoe at 4942' MD / 3839' TVD. 1.1 bbis pumped 11.1 bbis bled back.;POOH from 4875' to 590'. Monitor well - static. UD 15 excess joints of 5" HWDP and rack back stand of HWDP w/ jars to 32'. No losses on trip. UD BHA 92: mud motor and bit. Bit grade: 1-1 WT-A-E-1-NO-BHA.;Mobilize BHA to the rig floor. PJSM. M/U BHA #3: 8-112" bit, bit sleeve, Geo-Pilot, MWD w! EWR, DGR, PWD and directional to 85'. Plug in and initialize tools.;Hauled 250 bbis H2O from L-Pad Lake for total = 4545 bbls Hauled 0 bbis H2O from A-Pad for total = 1500 bbis Hauled 0 bbis Source Water from G&I = 820 bbis Hauled 169 bbis cutting/liquids/cement to MPU G&I for total = 6911 bbis 9/1/2019 Finish initializing MWD tools, M/U 3 NMFCs and jar stand, TIH to 930' ,test MPD lines to 250/1000 psi, test Geo span to 3000 psi, break in geo-pilot, shallow test MWD tools. BD TD.;TIH w/ stds 5" DP f/ 930' to 4742' ( fill pipe @ 3000' and 4742) BD TD. Correct displacement on TIH.;PJSM, install FOSV and 5' pup joint, Hang blocks, slip and cut 53' drlg line. recalibrate block height. Monitor well with trip tank, static.;PJSM, remove trip nipple, install RCD bearing.;TIH 1 std f/ 4742' to 4842', PJSM for displacing.;Pump 30 bbis spacer then displace to 8.8 ppg FloPro mud, 8 BPM, 650 PSI, 60 RPM, 15K TQ.;Shut down, close MPD choke with no pressure observed. Clean underneath shakers and mud trough to pit #4.;Drill 8-1/2" production lateral f/ 4967' t/ 5378', 411' drilled, 10371hr AROP. 550 GPM, 1550 PSI, 120 RPM, 17K TO, 5-15K WOB. 165K PU / 82K SO / 122K ROT, 8.8 ppg MW, 47 vis, 10.1 ECD, 41 u max gas. Entered OA-2 at 5100' MD 13848' TVD & OA-3 at 5230' MD 13856' ND.;MPD open chokes while drilling 30-50 PSI line pressure, close choke on connections maintaining 30-50 PSI w/ no build up.;Drill 8-1/2" production lateral f/ 5378't/ 6075', 697 drilled, 119/hr AROP. 550 GPM, 1540 PSI, 120 RPM, 19k TO, 10-15K WOB. 176K PU 174K SO / 117K ROT. 8.9 ppg MW, 44 vis, 10.1 ECD, 219u max gas. Up out of OA-3 to OA-2 at 5655' MD / 3853' TVD & OA-1 at 5870' MD / 3842' TVD.;MPD open chokes while drilling 50-60 PSI line pressure, close choke on connections maintaining 50-60 PSI w/ no build up. Last survey at 6006.47 MD ! 3838.21' ND, 90.00° inc, 182.01' azm, 6.44' from plan, 1.19' high & 6.33' right.;Hauled 75 bbis H2O from L-Pad Lake for total = 4620 bbis Hauled 0 bbis H2O from A-Pad for total = 1500 bbis Hauled 0 bbis Source Water from G&I = 820 bbis Haluled 837 bbis cuttings/mud/cement = 7752 bbis Daily (midnight) losses = 0 bbls, cumulative losses for interval = 0 bbis 9/2/2019 Drill 8-1/2" production lateral f/ 6075't/6741', 666' drilled, 1117hr AROP. ddg in OA-1. 550 GPM, 1700 PSI, 120 RPM, 20k TQ, 10-15K WOB. 185K PU / OK SO/ 115K ROT. 9 ppg MW, 45 vis, 10.5 ECD, 525u max gas.;MPD choke fully open drlg w/50-60 PSI line pressure, closed choke on connections maintaining 50-60 PSI w/ no buildup. Pump 30 bbl hi vis sweeps @ 6078' and 6553', 1st back on time w/50% increase, 2nd back 200 stks late w/ 50% increase. Lost S/O wt @ 6600'.;Drill 8-1/2" production lateral V 6741't/ 7313', 572' drilled, 9571hr AROP. 550 GPM, 1830 PSI, 120 RPM, 18k TQ, 5-15K WOB. 152K PU /65K SO / 116K ROT. 8.9 ppg MW, 55 vis, 10.84 ECD, 57u max gas.;MPD choke fully open drlg w/ 60 PSI line pressure, closed choke on connections building to 110 PSI. At 6900' tq increasing to 26k, add 6 drums to-tork to sys, increase lubes fl .25% to 1% lowering tq to 19-20k and S/O wt back @ 75k.;While drilling in OA-1 Encountered fault @6909 with 25' DTN throw & crossed into the shale below OA sands at 6950', aim up 96° inc. Back in OA-4 @7269. Pump 30 bbl hi vis sweep @ 7029', back 200 stks late, 200% increase.;Drill 8-1/2" production lateral f/ 7313't/7593', 280' drilled, 93'/hr AROP. 550 GPM, 1860 PSI, 120 RPM, 17K TQ, 8-15K WOB. 145K PU / 75K SO / 107K ROT. 8.95 ppg MW, 50 vis, 10.91 ECD, 244u max gas.;MPD choke fully open drlg w/ 60 PSI line pressure, closed choke on connections building to 85 PSI, trap 100 PSI. Mud check @ 21:00 = 6.5 MBT. Entered OA-3 @ 7382'.;Milne Point lost turbine & kicked rig off highline power @ 21:14. Start rig generators & begin warming up. Lights on @ 21:27. Two generators @ 21:29. Pick off bottom & circulate 2 BPM, 380 PSI. Third generator online at 21:56, ready to resume drilling. G&I lost power briefly, did not affect drilling;Drill 8-1/2" production lateral f/ 7593' U 7759', 166' drilled, 837hr AROP. 550 GPM, 1850 PSI, 120 RPM, 18K TQ, 5-15K WOB, 145K PU / 75K SO 1110K ROT. 8.8 ppg MW, 49 vis, 10.9 ECD, 240u max gas. Pumped high vis sweep @ 7500', strung out while power off / low flow- not seen at shakers.;MPD choke fully open drlg w/ 60 PSI line pressure, closed choke on connections at 100 PSI with no build up.;Drill 8-1/2" production lateral f/ 7759' U 8552', 793' drilled, 1327hr AROP. 550 GPM, 1940 PSI, 120 RPM, 17K TQ, 7-13K WOB. 158 PU 160K SO 1110K ROT. 9.0 ppg MW, 44 vis, 11.2 ECD, 412u max gas.;Pumped high vis sweep @ 7981', 300 stks late w/ 50% increase. Mud check at 03:00 = 7.2 MBT. Perform 290 bbl dump & dilute at 8267' Entered OA-2 @ 7785'& OA-1 @ 7995'. Last survey @ 8386.51' MD / 3693.55' TVD, 90.87' inc, 184.34° azm, 5.35' from plan, 3.67low, 3.90' right.;MPD choke fully open drlg w/ 60 PSI line pressure, closed choke on connections at 100 PSI with no build up.;Hauled 1075 bbls H2O from L-Pad Lake for total = 5695 bbls Hauled 0 bola H2O from A-Pad for total = 1500 bbls Hauled 0 bbls Source Water from G&I = 820 bbls Haluled 1131 bbls cuttings/mud/cement = 8883 bbls Daily (midnight) losses = 0 bbls, cumulative losses for interval = 0 bola 9/3/2019 Drill 8-112" production lateral f/ 8552' U 9224', ' drilled, 6727112' hr AROP. 550 GPM, 1990 PSI, 120 RPM, 20K TO, 13K WOB. 155 PU / 58K SO / 106K ROT. 9.1 ppg MW, 44 vis, 11.01 ECD, 341 u max gas.;MPD choke fully open drlg w/ 60 PSI line pressure, closed choke on connections at 100 PSI building to 130 psi. Pumped high vis sweep @ 8552'and 9025' 1st 100 silks late w/ 100% inc, 2nd 250 stks late, 50% inc. Drilling in OA-1 Rig back on high line @ 11:OO.;Drill 8-1/2" production lateral f/ 9224't] 9930', (3655' TVD) 706' drilled, 117' hr AROP. 500 GPM, 1880 PSI, 120 RPM, 22K TQ, 5-10K WOB. 155K PU 155K SO / 110K ROT. 9.1 ppg MW, 47 vis, 11.3 ECD, 691u max gas.;MPD choke fully open drlg w/ 60 PSI line pressure, closed choke on connections at 100 PSI building to 145 psi. 9238' entered shale above OA-1, target 88 deg inc, back in OA-1 @ 9355', Undulate to OA-3, cross OA-2 @ 9460' Pump 30 bbl hi vis sweep @ 9500', back 400 silks late w/ no increase.;Mud check @ 15:00 MBT @ 7.5, Perform a dump and dilute @ 9884' with 290 bbls new 8.8 Flo pro mud.;Drill 8-1/2" production lateral f/ 9930' t/ 10501', (3625' TVD) 571 'drilled, 95' hr AROP. 550 GPM, 2100 PSI, 120 RPM, 23K TO, 12K WOB. 160K PU / 40K SO / 107K ROT. 9.0 ppg MW, 42 vis, 11.12 ECD, 409u max gas.;MPD choke fully open drlg w/ 60 PSI line pressure, closed choke on connections at 100 PSI building to 125 psi. Encountered fault at 10469, start to drop inclination, targeting 83°. Projecting a 50' DTS throw. Pump tandems sweeps @ 9979', back 300 stks late w/ 20% increase. Lost down wt. at 10266; Drill 8-1/2" production lateral f/ 10501' t/11124', (3672' TVD) 623' drilled, 104' hr AROP. 450 GPM, 1670 PSI, 120 RPM, 22K TQ, 13K WOB. 160K PU / 50K SO / 107K ROT. 9.1 ppg MW, 46 vis, 11.24 ECD, 267u max gas.;MPD choke fully open drlg w/ 60 PSI line pressure, closed choke on conn at 100 PSI building to 125 psi. Cont to drop inc to 83° at 10715' then build and hold 85-87°. Pump 30 bbl sweep @ 10541', back 350 stks late w/ 0% increase. Increase lube to 1.5%. Tq drop 5k and regained Dn Wt.;Mud check @ 03:00 MBT @ 7.25. Perform a dump and dilute @ 10955with 290 bbls new 8.8 flo pro mud. Last survey @ 10957.96' MD / 3653.52' TVD, 86.61 °inc, 179.68° azm, 26.1' from plan, 25.8' low, 4.06' Ieft.;Hauled 890 bbls H2O from L-Pad Lake for total = 6585 bbls Hauled 0 bbls H2O from A-Pad for total = 1500 bbls Hauled 0 bbls Source Water from G&I = 820 bbls Haluled 1650 bbls cuftings/mud/cement 10533 bbis Daily (midnight) losses = 0 bbls, cumulative losses for interval = 0 bbls 9/4/2019 Drill 8-1/2" production lateral f/ 11124't/11505', (3660' TVD) 379' drilled, 84.2' hr AROP. 525 GPM, 2100 PSI, 120 RPM, 23K TQ, 6K WOB. 165K PU /401K SO/ 105K ROT. 9.2 ppg MW, 48 vis, 11.4 ECD, 362u max gas.;MPD choke fully open drlg w/ 50-60 PSI line pressure, closed choke on conn at 125 PSI building to 140 psi. Pump 30 bbl hi vis sweep at 11310', sweep back on time w/ 25% inc. Entered OA-1 @ 11171'.;Hyd actuator for shot pin where rotating link adaptor locks in during connections leaking hydraulic oil when actuated, decision made to BROOH to shoe and make repairs. Take survey, CBU 515 GPM, 1950 PSI, 100 RPM, 20K torque, reciprocating string . Break out TD, rack std in mousehole back in drk.;Last survey: 52.7' below the line, 7.1' Ieff.;BROOH 3-5 min stand 1111503' to 10836' 525 gpm, 1900 psi, 120 rpm, 18k torque, MPD maintain 130 psi during connections.;Found washout at connection between bottom joint on stand 112 and top joint on stand 111, tool face had slight wash out. UD and replace the 2 washed joints DP. Maintain 130 pisi shut in pressure w/ MPD.;Continue to BROOH 3-5 min stand It 10836' to 9314' 525 gpm, 1800 psi, 120 rpm, 1S torque, MPD maintain 130 psi during connections.;Continue to BROOH 3-5 min stand f/ 9314' to 6839'500 gpm, 1600 psi, 120 rpm, 12k torque, MPD maintain 130 psi during connections, Packing off at 7250', reduce pulling speed until above the fault @ 6900'.;Continue to BROOH 3-5 min stand f/ 6839 to 4938'550 gpm, 1650 psi, 120 rpm, 10-15k torque, MPD maintain 130 psi during connections. Packing off at 6285', 6219', 5740' & 5180', reduce pulling speed as needed.;Hauled 645 bbls H2O from L-Pad Lake for total = 7230 bbls Hauled 0 bbls H2O from A-Pad for total = 1500 bbls Hauled 0 bola Source Water from G&I = 820 bola Haluled 884 bbls cuttings/mud/cement 11417 bbls Dail idni ht losses = 61 bbls cumulative losses for interval = 61 bbl 9/5/2019 Pump 30 bbl hi vis sweep around @ 4937' at 550 gpm, 1650 psi, 100 rpm, 10-15k tq, reciprocate pipe, cleanup 9 5/8" csg, sweep back on time w/ 25% increase, shut down pump, line up and pump across top of hole @ 2.5 bpm, 240 psi, MPD hold 130 psi back pressure.;MPD holding 130 psi back pressure, Make TD repairs, remove shot pin actuator, rig mechanic rebuild actuator, re-install and function test same, test making and breaking out several connections, good. PU 140K, SO 1 tOK.;Crew change, PJSM, TIH on elevators f/ 4937' to 7347' w/20k set down, PIU and work thru easily, RIH to 8056', UD and replace top jts on stands 82, 83 and 84 due to worn hard bands, RIH on elevators to 11029' where down wt was Iost.;Circulate 1.5 bpm across top with 30 psi line pressure, MPD hold 100 psi shut in pressure during connections while TIH, Fill pipe every 2000'. Correct displacement TIH on elevators.;Wash and ream in hole f/ 11029't/ 11505'. 400 GPM - 1350 psi, 50 RPM - 171k Tq.;Drill 8-1/2" production lateral f/ 11505' U71868, (3639' TVD) 363' drilled, 104' hr AROP. 500 GPM, 1840 PSI, 120 RPM, 23K TO, 5-15K WOB. 165K PU / 40K SO / 110K ROT. 8.9 ppg MW, 45 vis, 10.85 ECD, 313u max gas.;Last MBT check = 11.5. Perform 580 bbl mud dilution when back on bottom. MPD choke fully open drlg wl 50-60 PSI line pressure, closed choke on connections at 130 PSI building to 135 psi. Maintain trajectory through the OA-1.;Drill 8-112" production lateral 1111868! V 12500', (3634' TVD) 632' drilled, 105' hr AROP. 540 GPM, 2150 PSI, 100 RPM, 27K TO, 10K WOB. 170K PU / 40K SO / 105K ROT. 9.0 ppg MW, 45 vis, 11.33 ECD, 1031 u max gas.;MPD holding 100 PSI line pressure while Drlg, closed choke on connections at 150 PSI. Pump 30 bbl hi vis sweep at 11980', sweep back 750 stks Tale w/ 0% increase in cuttings.;Maintain OA-1 to 11 918'then drop through OA-2 into the OA-3 at 12105'. Last survey @ 12386.71' MD / 3636.66' TVD, 91.06x° inc, 182.43° mm, 34.2' from plan, 34.2' low, 1.7' left.; Hauled 125 blols H2O from L-Pad Lake for total = 7355 bbls Hauled 0 bbls H2O from A-Pad for total = 1500 bbis Hauled 0 blols Source Water from G&I = 820 bbls Haluled 802 bbls cuttings/mud/cement 12219 blots Daily (midnight) losses = 42 bbis, cumulative losses for interval = 103 bbls 9/6/2019 Drill 8-1/2" production lateral f/ 12500't/ 12932', (3613' TVD) 432' drilled, 78.5' hr AROP. 540 GPM, 2150 PSI, 120 RPM, 24K TO. 5-15K WOB. 170K PU / 40K SO / 107K ROT. 9.1 ppg MW, 48 vis, 11.22 ECD, 719u max gas.;MPD holding 100 PSI line pressure while Drlg, closed choke on connections at 190 PSI.;Drill in the OA-3, formation dip 91 deg, target 90.5 deg, 12750' undulate up, encountered fault #3 around 12608' with 12' throw DTS, entered shale above OA-1 @ 12840', Target 87 deg looking to regain OA-1, decision made to side track f/ 12700' Take final survey: 39.23' below the line, 10.28' right.;BROOH It 12932' to 12650' pulling 5-10 min std, 540 gpm, 2150 psi, 100 rpm, 21 k tQq. MPD holding 100 PSI line pressure while BR, , closed choke on connections at 190 PSI.;Time drill for sidetrack f/ 12700' @ 16 fph to 12720', then slow to 7 fph U 12725', down to 5 fph V 12730'. Increase rate to 15 fph V 12742'. PU U12690' and pass through sidetrack point with no issues. 535 gpm, 2080 psi, 120 rpm, 27.7k torque, 4K wob, target 90 deg inc.;Drill 8-1/2" production lateral f/ 12742' t/12839', (3628' TVD)97' drilled, 65' hr AROP. 550 GPM,2200 PSI, 120 RPM,24K TQ, I0K WOB. 175K PU / 40K SO / 106K ROT. 9.0 ppg MW, 45 vis, 11.24 ECD, 190u max gas. Svy at 12767.71' show 1.99' of separation f/ PB. At 12861.46'the separation is 8.98'.;MPD holding 100 PSI line pressure while driting, closed choke on connections at 190 PSI. Drilling in the OA-1.;Drill 8-1/2" production lateral f/12839 t113424', (3625' TVD) 585' drilled, 97' hr AROP. 540 GPM, 2120 PSI, 110 RPM,26K TQ, 11 K WOB. 170K PU / 40K SO / 101K ROT. 8.9 ppg MW, 45 vis, 11.29 ECD, 287u max gas.;MPD holding 70-100 PSI line pressure while drilling, closed choke on connections at 190 PSI Mud check @21:00 MBT @ 7.25. Perform a dump and dilute @ 13220' with 290 bbls new 8.8 Flo pro mud. Maintain trajectory in the OA-1.;Drill 8-1/2" production lateral V13424't/ 14048 ', (3639' TVD) 624' drilled, 104' hr AROP. 540 GPM, 2100 PSI, 100 RPM, 28K TQ, 1 OK WOB. 180K PU 1 40KSO / 103K ROT. 9.0 ppg MW, 42 vis, 11.34 ECD, 766u max gas.;MPD holding 70.100 PSI line pressure while drilling , closed choke on connections at 185 PSI. Tq increasing to 28k, at 14035', start adding lubes to mitigate. Last survey @ 13912.02' MD / 3639.80' TVD, 90.20' inc, 184.65' mm, 50.12' from plan, 50.04' low, 2.85' Ieft.;Hauled 1075 bbls H2O from L-Pad Lake for total = 8340 bbls Hauled 0 bbls H2O from A-Pad for total = 1500 bbls Hauled 0 bbis Source Water from G&I = 820 blots Haluled 1197 bbis cuttings/mud/cement 13416 bbis Daily (midnight) losses = 90 bbis, cumulative losses for interval = 193 bbls 9/7/2019 Drill 8-1/2" production lateral f/14048't/ 14120 ', ( 3637' TVD )72' drilled. 536 GPM. 2160 PSI, 110 RPM, 26K TO, 10K WOB. 9.1 ppg MW, 42 vis, 11.3 ECD, 766u max gas. 175K PU 140K SO / 104K ROT MPD holding 70-100 PSI line pressure while drilling.;Drill in the OA-1, at 14094' encountered fault #4 w/ 70-80' OTN throw, Geo called TO @ 14120' MD, 3637' TVD in shale below OA-4. Final survey: Projection to TD, 49.33' Below the line, 6.06 Right.;Pump tandem low As / high vis sweeps. 550 GPM, 2300 PSI, 120 RPM, 24K TO, Reciprocate pipe, Sweeps back 1300 strokes late w/ no increase. Circulate a total of 4x bottoms up, racking back a stand every BU to 13792'. No Iosses.;Wash and ream back to TD 550 GPM, 2160 PSI, 120 RPM, 24-26K TQ.;Continue pumping and working pipe 550 gpm, 120 rpm, PJSM for Pumping SAPP train and displacing to brine, Ready pits, SAPP pill and 2nd truck w/ 290 bbis seawater to arrive.;Pump SAPP pill treatment. Three 40 blot SAPP pills with 50 bbl seawater spacer followed by 30 bbl high vis spacer, 7.5 BPM, 1080 psi. Chase with 290 blots seawater.; Displace well w/920 bbls 8.5 hi vis brine w/ 4% tube, 5-7 bpm, 850 psi, 100 rpm, 26-29k torque, reciprocate pipe, divert all mud. SAPP trains and seawater to rock washer, w/ 8.5 ppg at returns MPD hold 100 psi back pressure (10.3 ppg ECD ) pump until clean brine retums.;PU/SO/ROT in mud 175k/none/103k . PU/SO/ROT in brine 170k/501k/113k.;Obtain slow pump rates. Shutdown pumps with MPD chokes open. bleed MPD pressure to 13 PSI, shut choke and pressure built to 125 PSI in 20 min. 12 PSI @ 3637' TVD with 8.5 ppg mud = 9.1 ppg EMW. SimOps- PJSM on BROOH & UD OP.;BROOH f/ 14120'V 12267' pumping 500 GPM, 1300 PSI, 120 RPM, 19K TO. 10.01 ECD at 8-10 min/std. Chokes full open w/ 50-60 PSI line pressure & shut in 180 PSI on connections (9.4 ppg EMW). Increase pulling speed to 5-7 min/std at 13109. Loss rate 8.1 bph.;BROOH If 12267't/ 10350' pumping 500 GPM, 1300 PSI, 120 RPM, 19K TQ, 10.37 ECD at 5-10 min/std. Chokes full open w/ 50-60 PSI line pressure & shut in 170-180 PSI on connections (9.4 ppg EMW).;Pack off at 10840', slack off V 10855' and reduce flow U 400 GPM. Increase back to 500 GPM and continue pulling when full returns seen. Shakers began to unload @ 10720'. Reduce pulling speed to 15 min/std.;Hauled 450 bbis H2O from L-Pad Lake for total = 8880 blots Hauled 0 blots H2O from A-Pad for total = 1500 bbls Hauled 0 blots Source Water from G&I = 820 blots Haluled 2371 bbis cuttings/mud/cement 15781 blots Daily (midnight) losses = 41.6 bbls, cumulative losses for interval = 234.6 bbis 9/8/2019 BROOH f/ 10350'V 8934' pumping 500 GPM, 1300 PSI, 120 RPM, i5K TO, 10.35 ECD at 5-10 min/std. Chokes full open w/ 50 PSI line pressure & shut in 170 PSI on connections, UD stds DP using mouse hole. Loss rate 7-8 bph BR.;Continue BROOH fl 8934' to 4937' at 500 GPM, 1310 PSI, 120 RPM, 11-15K TO, 10.10 ECD at 5-10 min/std. Holding 110 PSI back pressure with MPD while BROOH & shut in 220 PSI on connections, UD stds DP using mouse hole. Note: increase in TO BR thm exposed shales f/ 7370' to 6900'. Max Gas- 99u.; Loss rate 5 bph slowing to no losses @ 6400'. Total of 107 bbls loss during BROOH.;Pump 30 bbl high viscosity sweep at 557 GPM, 1300 PSI, 80 RPM, 5K torque, reciprocating f/ 4930' t/ 4842'. Sweep back on Calc stks with 30% increase observed. Continue to circulate 2x bottoms up with minimal cuttings observed at shakers. Lost 6 bbis while circulating.;Open MPD choke and bled off pressure to 18 PSI, close choke and pressure built to 65 PSI in 10 min. Open MPD choke and bled off pressure again to 18 PSI, close choke and pressure built to 65 PSI in 10 min. SimOps: Start weight up brine in pit t/ 9.1 ppg.;Weight up from 8.7 ppg to 9.1 ppg from 4930'. 9 BPM, 750 PSI, 80 RPM, 5K Tq.;Shut down pumping with open choke. Flow decrease to slight stream at possum belly after 10 min. Open 2' bleed valve and monitor for flow. Flow diminished from 2.2 BPH to static in 30 min. Sim -ops: PJSM on R/D RCD.;Remove RCD bearing and install trip nipple. Check for leaks - good. Monitor well - static.; Install FOSV. Slip and cut 92' of drilling line. Service TopDrive & Drawworks. Well Static.; POOH on elevators If 4930' to 3800' Rack 5" DP in Derrick. Hole taking proper displacement.; Hauled 575 bbls H2O from L -Pad Lake for total = 9455 bbls Hauled 0 bbls H2O from A -Pad for total = 1500 bbls Hauled 0 bbls Source Water from G&I = 820 bbls Haluled 680 bbls cuttings/mud/cement 16461 bbls Daily (midnight) losses = 130 bbls, cumulative losses for interval = 364.6 bbls 9/9/2019 POOH on elevators racking stds of 5" DP in drk f/ 3800'to 274' to HWDP. Monitor well, 1.5 bph loss rate. 12 bbl losses TOOH it shoe.;Monitor well, 1.5 bph loss rate. UD 2 joints HWDP, jars, 3 NM drill collars, 2 float subs to 82'. Read MWD tools, UD remaining BHA. Bit graded: 1 -3 -BT -C -X -I -WT -TD. ILS had wear on upper part of blades f/ back reaming.;Monitor well with trip tank, 1 bph loss rate. Clear and clean rig floor. R/U to P/U HWDP.;PJSM, Drift and P/U 153 jts 5" HWDP utilizing mouse hole to M/U stands, rack 51 stds in derrick. Monitor well with trip tank, 1.510 2 bph static loss rate.;Mobilize 6-5/8" casing equipment to rig floor & R/U. Bring safety joint to rig floor and position in the mousehole. Conduct PJSM for running 6-5/8" liner. Loss rate 1.5 BPH.;P/U 4 1/2" shoe joint w/ WIV, DPO & XO. PIU and RIH w/ 6-5/8", 20#, L-80, Hydril 563, Slotted liner as per tally U 1246'. Install Centralizer every joint. M/U Tq = 7100 ft/lbs. Loss rate running liner 1.5 bph.;P/U and RIH w/ 6-5/8", 209, L-80, Hydril 563, Slotted liner as per tally f/ 1246' to 6154'. Install Centralizer every joint. M/U Tq = 7100 ft/lbs. PU/SO before exiting shoe @ 4942'= 115000k. Loss rate running liner at 1.8-2.3 bph. 14 bbl loss total for liner run.;Hauled 20 We H2O from L -Pad Lake for total = 9475 bbls Hauled 0 bbls H2O from A -Pad for total = 1500 bbls Hauled 0 bbls Source Water from G&I = 820 bbls Haluled 0 bbls cuttings/mud/cement 16461 bbls Dail midni ht losses = 32.6 bbls cumulative losses for interval = 397.2 bbls 9/10/2019 P/U and RIH w/ 6-5/8", 20#, L-80, Hydril 563, Slotted liner as per tally f/ 6154' to 9313'. Install Centralizer every joint. M/U Tq = 7100 ft/lbs. Loss rate running liner at 1.8-2.3 bph.;R/D Liner handling equipment and R/U 5" DP handling equipment. PU/MU Liner Hgr/Pkr assy as per BOT Rep. RIH with tat std of HWDP. Break circulation and establish circ. Unable to Rotate. PUW148K, SOW 85K. Clean floor and R/U fill up hose.;RIH with 6 5/8" Slotted Liner on 5" DP from 9448'to 13,988' with no issues running in hole.;Obtain parameters and RIH & Tag @ 14,120' MD.PUW 270K, SOW 167K. Drop 1.5" setting ball and pump on seat @ 2bpm1220 psi. Press up to 1000 psi and check lines. Press up to 2450 and see pusher tool set. Press up to 4350 psi and set Liner Hgr. Press up to 5000 psi and shear rupture disc Set down 50K.;PU 225K and confirm release. TOL @ 4775'.;Shut Top Pipe Rams, PT IA to 1500 psi for 10 minutes on chart. Test Good.;R/D Test equipment. POOH to 4714'. CBU @ 6.4 bpm/830 psi. Slug Pipe.;POOH laying down 5" HWDP if 4714' t/ surface. UD and inspect running tool. 2.5 BPH loss rate. 15 bbis loss on TOOH.;M/U 3-1/2" perforated orange peeled joint with 8.31" no-go and XO to 15.84'. TIH with 49 stds 5" stands DP to 4681', single in hole w/ 4Its 5" DP and tag top of liner with no-go on depth at 4775' putting flush tool @ 4791'. 4.5 bbl losses on TIH.;Flush seal bore assy 5.5 bpm, 200 psi P/U slowly to above TL @ 4775', Circulate 2x BU - 550 GPM 440 psi, 30 rpm, 2-4k tq. Hold PJSM on displacing to clean brine.; Hauled 15 bbls H2O from L -Pad Lake for total = 9,470 bbls Hauled 0 bbls H2O from A -Pad for total = 1,500 bbls Hauled 0 bbls Source Water from G&I = 820 bbls Hauled 58 bbls cuttings/mudlcement = 16,519 bbls Daily (midnight) losses = 44 bbls, cumulative losses for interval = 441 bbls ILA Well Name: MP M-22 Field: Milne Point County/State: , Alaska (LAT/LONG): rvation (RKB): API #: Hilcorp Energy Company Composite Report Spud Date: Job Name: 1913621C MPU M-22 Completion Contractor APE #: AFE $: Activity Date '. -., . Ops Summary _ 9/11/2019 Pump 30 bbl sweep. Displace w/ clean 9.1 ppg brine, 330 bbls total. 285 GPM - 150 psi. SinnOps: Clean trip tank & fill w/ clean 9.1 ppg brine., Monitor Well - 2 3 BPH losses. Blow down TopDrive. POOH from 4770' laying down 5" DP, no-go & 3-1/2" wash tool. 13 bbls lost on TOOH.,Pull wear bushing, perform dummy run with 7" Hanger, Hanger on depth @ 31.26. Lay down hanger, Rig up to run 7" tie back. M/U 7" XO U FOSV.,P/U Baker Bullet Seal assembly with 8.24" locator sub to 16. Run 7" 260 L-80 TXP BTC -SR liner from 15' to 4739' at it # 115' above TOL. WU to 14,750 ft/lbs Tq w/ Doyon double stack tongs. RIH with #116 & 5.29' w/117 tagging no go on depth @ 4775' putting mule shoe @ 4785' set down 8k, close bag, pressure to 280 psi to verify seals landed, good. Bleed off and open bag. 6 bbls lost while running liner. PU/SO - 140023k.,Space out liner. UD joints #117, 116 and 115. M/U 9.86' pup joint then joint #115 M/U 7" hanger and landing joint. Land liner on hanger at 4784.2' (0.70' off no-go), 140 PU / 123 SO. R/U Pump sub and XO. Close annular & pressure up to 250 PSI. P/U 7', observe pressure bleed off through circulation ports.,PJSM with Doyon, M-1 and Peak. Reverse circulate 75.5 bbls corrosion inhibited 9.1 ppg brine @ 3 BPM, 250 PSI, Pump through injection line to the OA taking returns out of the 7" liner, Line up and reverse circ 68 bbls diesel from vac truck 3 bpm, 420 psi freeze protecting 9 5/8" x 7" annulus to 23001, Land hanger w/ 83k on Hanger.,Bleed down to cellar and verify seals engaged. Good. Back side dead. Open annular & drain stack. R/D landing joint.. M/U Pack off running tool on it of 5" DP. RIH & set pack off. RILD as per Wellhead rep. UD running tool. Test Void to 3000 psi, 10 min - good.,Test 7" X 9-5/8" annulus to 1000 psi for 30 charted min. Good. Bleed of pressure, R/D test equipment. BD kill and injection lines. Note: 5.3 bbls to fill hole.,Flush diesel from Mud Pump. R/D test equipment. BD cutting box and injection lines, R/D test equipment. BD kill and injection lines. Install gauge on OA - 0 psi @ 04:15.,De-Mobilize 7" handling equpiment, Mobilize 3-1/2" tubing equipment to rig floor. Make up FOSV t/ 3-1/2" EUE XO. Bring ESP Completion Equip to rig floor. 1.5 BPH static Iosses.,Hauled 85 bbis H2O from L -Pad Lake for total = 9,555 bbis Hauled 0 bbls H2O from A -Pad for total = 1,500 bbls Hauled 0 bbls Source Water from G&I = 820 bible Hauled 911 bbis cuttings/mud/cement = 17,430 bbls Daily (midnight) losses = 19 bbls, cumulative losses for interval = 460.2 bbls 9/12/2019 PJSM with Centrilift and rig crew. Rig up ESP sheave, string ropes through sheaves and bring ESP motor to rig floor.,Pick up and Make up ESP/Motor assembly. Service motor and seal assembly. Pull ESP and 1/4" gauge line from spooling unit to rig floor.,Connect ESP cable, 1/4" chemical line & 1/4" x 100' control line discharge, to motor and gauge assembly. Install bolt on clamps to motor assembly. Perform tests on ESP cable and 1/4" chemical line. Good test.,Pick up last Centrilift pump, P/U 3.6'8 Rind Pup, M/U bolt on flange XO to 2-7/9'8 Rnd X 3.5" 8 Rind to bottom of pup jt. P/U and install 8x pump clamps onto the pump assembly. Connect 1/4" gauge line to discharge head and test. Good Test.,RIH with ESP on 3-1/2" 9.3# L-80 EUE Tubing f/ 11 3'to 1080'. Install cannon clamp every connection for first 10 its. Install cannon clamp every other connection from it #10 on. Test cable connection. Test failed.,POOH from 1080'to 927' and re -test cable. Test failed again.,POOH U 551' racking 3-1/2" tubing in Derrick. Observe cable damaged at side of GLM. Discuss options with Engineer. Decision made to replace GLM w/ sliding sleeve. 1.5 BPH Iosses.,Cut cable and test prior to splicing. Test Failed. POOH f/ 551' U 113' laying down GLM & x -nipple, racking 3-112" tubing in Derrick. Test cable at top of ESP assembly - test failed -Break out XO & Lay down 3-1/2" pup it. Pull ESP assembly to motor, remove and stage in mouse hole.,Test motor- failed test. Lay down motor and P/U a new motor. Install stabilizer and gauge. Hook up 1/4" gauge & chemical lines. Service new motor. Loses at 1 BPH.,Make up pumps to motor, install new ESP pig tail, test new cable & motor - good good. RIH with ESP assembly. Install 8x pump clamps.,Splice flat motor lead to round ESP cable.,M/U 2-7/8" pup it and XO to 3-1/2" EUE. RIH with 3-1/2" 9.3# L-80 EUE tubing f/ 113' 1/ 1140' Install cannon clamp every connection for first 12 its. Install cannon clamp every other connection from it #12 on. Test cable every 1000'. Tq 3-1/2" tubing to 3100 ft/lbs. 2-7/8" connections to 2250 ft/lbs. Loses at i BPH.,Hauled 30 bbls H2O from L -Pad Lake for total = 9,585 bbis Hauled 0 bible H2O from A -Pad for total = 1,500 bbls Hauled 0 bbis Source Water from G&I = 820 bbis Hauled 222 bbis cuttings/mud/cement = 17,652 bible Daily (midnight) losses = 36 bbls, cumulative losses for interval = 515.2 bible 9/13/2019 RIH with ESP assembly on 3-1/2" 9.3# L-80 EUE tubing f/ 11 40' t/ 4693' Install cannon clamp every other connection. Test cable every 1000'. Tq 3-1/2" tubing to 3130 fl/lbs. Total of 84 Cross coupler cannon clamps installed & 8 pump clamps.,Blow down choke / kill / hole f11 lines. Rig up landing joint with cross overs to hanger. SimOps: Empty Mud Pits of fluid & prep pits for move. Prep mud pumps for rig move.,Terminate ESP cable. Prep for nipple down. Off Hi - Line and on rig Cat power @ 16:00.,RIH and Land Hanger. ESP centralizer at 4726.83', XN Sliding sleeve at 4179.42'. PUW = 90k, SOW = 75k. 35k on Hanger. RILDS, Pull landing it & install BPV.,Nipple down BOPS. SimOps: Rig down ESP cable and sheaves. Clear rig floor of ESP & tubing handling equipment., Nipple up Tree. Centrilift perform final checks on cable -good test. SimOps: Continue clear rig floor and prep for Rig move.,Terminate control line on tubing spool tree adapter. Trouble installing control line termination sleeve. Nipple down Tree and move away from Well Head. Redress threads on control line termination port in tubing head adapter. Unable to install termination sleeve again. Pull Tree off second time and redress treads on port. Attempt to mate up termination sleeve again unsuccessfully., Lift tree up and re -position control line in tubing head adapter so tubing puts less side pressure on termination sleeve. Install termination sleeve and Nipple tree back up.,Test hanger void 500 psi low /5000 psi high for 10 min - Good test. Install TWC, R/U and test tree 500 psi low 15000 psi high charted. Good test.,Hauled 0 bbis H2O from L -Pad Lake for total = 9,585 bbis Hauled 0 bbis H2O from A -Pad for total = 1,500 bbls Hauled 0 bible Source Water from G&I = 820 bbis Hauled 145 bbls cuttings/mud/cement = 17,797 bbls Daily (midnight) losses = 6 bbis, cumulative losses for interval = 517 bbis Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-22 500292364500 Sperry Drilling Definitive Survey Report 13 September, 2019 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hiloorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-22 Proiect: Milne Point TVD Reference: MPU M-22 Actual RKB @ 58.85usft Site: M Pt Moose Pad MD Reference: MPU M-22 Actual IRKS @ 58.85usft Well: MPU M-22 North Reference: True Wellbore: MPU M-22 Survey Calculation Method: Minimum Curvature Design: MPU M-22 Database: NORTH US+CANADA Prefect Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Uslno Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPU M-22 Well Position +N/ -S +E/ -W Position Uncertainty 0.00 usft Northing: 6,027,889.83 usft Latitude: 0.00 usft Eastinq: 533,663.95 usft Longitude: 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: Wellbore MPU M-22 Magnetics Model Name Sample Date Declination Dip Angle C) (usft) BGGM2018 9/11/2019 C) 16.46 Desiqn MPU M-22 2_MWD+IFR2+MS+Sag A013Mb: IIFRdec&multi-station analysis+sag 08/1512019 Audit Notes: 12,672.26 MPU M-22PB1 MWD+IFR2+MS+Saq(2)(M 2_MWD+IFR2+MS+Sag A013Mb: IIFRdec&multi-station analysis+sag 09/03/2019 Version: 1.0 Phase: ACTUAL Tie On Depth: Vertical Section: Depth From (TVD) +N/S +E/ -W Azi (1) TVD Nall) (usft) (usft) (usft] Northing (ftl Easting (ft) 33.95 0.00 0.00 0.00 0.00 33.95 -24.90 0.00 80.95 70° 29'14.012 N 149° 43'29.45W W 24.90 usft Field Strength (nT) 57,414.22079212 12,672.26 Direction (°l 185.01 Survey Program Data 9/1312019 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 208.09 4,888.78 MPU M-22PB1 MWD+IFR2+MS+Saa (1) M 2_MWD+IFR2+MS+Sag A013Mb: IIFRdec&multi-station analysis+sag 08/1512019 4,956.29 12,672.26 MPU M-22PB1 MWD+IFR2+MS+Saq(2)(M 2_MWD+IFR2+MS+Sag A013Mb: IIFRdec&multi-station analysis+sag 09/03/2019 12,700.00 14,049.16 MPU M-22 MWD+IFR2+MS+Saq(3)(MPU 2_MWD+IFR2+MS+Sag A013Mb: IIFRdec&multi-station analysis+sag 09/11/2019 9/132019 1:27:54PM Pace 2 COMPASS 5000.15 Build 91 Survey Map Map Vertical MD (usft) Inc (') Azi (1) TVD Nall) TVDSS (usft) +N/ -S (usft) +El -W (usft) Northing (ftl Easting (ft) DLS (°1100') Section (ft) Survey Tool Name 33.95 0.00 0.00 33.95 -24.90 0.00 0.00 6,027,889.83 533,663.95 0.00 0.00 UNDEFINED 208.09 0.22 5.16 208.09 149.24 0.33 0.03 6,027,890.16 533,663.98 0.13 -0.33 2_MWD+IFR2+MS+Sag(1) 301.37 0." 349.20 301.37 242.52 0.86 -0.02 6,027,890.69 533,663.93 0.25 -0.86 2_MWD+IFR2+MS+Sag(1) 393.39 2.79 346.28 393.34 334.49 3.39 -0.62 6,027,893.21 533,663.32 2.55 3.32 2_MWD+IFR2+MS+Sag(1) 486.96 5.22 345.67 486.68 427.83 9.72 -2.21 6,027,899.54 533,661.69 2.60 -9.49 2_MWD+IFR2+MS+Sag(1) 579.70 9.00 349.26 578.69 519.84 20.94 4.61 6,027,910.75 533,659.25 4.10 -20.46 2 MWD+IFR2+MS+Sag(1) 673.33 13.67 351.21 670.47 611.62 39.Oa -7.67 6,027,928.87 533,656.11 5.00 -38.26 2_MWD+IFR2+MS+Sag(1) 769.77 17.77 355.35 763.28 704.43 65.02 -10.60 6,027,954.80 533,653.05 4.40 -63.85 2_MWD+IFR2+MS+Sag(1) 864.53 23.01 357.34 852.08 793.23 97.96 -12.64 6.027,987.72 533.650.87 5.58 -96.48 2_MWD+IFR2+MS+Sag(1) 959.79 26.06 358.81 938.73 879.88 137.49 -13.93 6,028,027.24 533,649.40 3.27 -135.74 2_MWD+IFR2+MS+Sag(1) 1,055.34 26.21 359.48 1,024.51 965e6 179.57 -14.56 6,028,069.32 533,648.58 0.35 -1T/.61 2_MWD+IFR2+MS+Sag(1) 1,150.34 28.95 359.06 1,108.70 1,049.85 223.55 -15.13 6,028,113.28 533,647.81 2.89 -221.37 2_MWD+IFR2+MS+Sag(1) 9/132019 1:27:54PM Pace 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-22 MPU M-22 MPU M-22 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU M-22 MPU M-22 Actual IRKS @ 58 85usft MPU M-22 Actual RKB @ 58.85usft True Minimum Curvature NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N1 -S +E/ -W Northing Easting DIS Section (usft) M (1) (usft) ("eft) (usft) (usft) R11 lftt (-/100') 1ft1 Survey Tool Name 1,244.42 29.05 359.69 1,190.99 1,132.14 269.15 -15.63 6,028,15888 533,647.11 0.34 -266.76 2_MWD+IFR2+MS+Sag(1) 1,341.48 28.53 0.22 1,276.05 1,217.20 315.90 -15.66 6,028,205.62 533,646.86 0.60 V3.32 2_MWD+IFR2+MS+Sag(1) 1,436.03 2004 358.13 1,359.00 1,300.15 361.27 -16.32 6,028,250.99 533,645.99 1.11 558.46 2_MWD+IFR2+MS+Sag(1) 1,530.93 30.86 357.12 1,441.31 1,382.46 408.46 -18.29 6,028,298.16 533,643.81 2.19 305.30 2_MWD+IFR2+MS+Sag(1) 1,626.12 30.79 357.37 1,523.05 1,464.20 457.18 -20.64 6,028,346.87 533,641.25 0.15 353.63 2_MWD+IFR2+MS+Sag(1) 1,721.40 2995 357.86 1,605.25 1,54640 505.31 -22.64 6,028,394.98 533,639.02 0.92 501.40 2_MWD+IFR2+MS+Sag(1) 1,816.01 29.48 356.80 1,687.42 1,628.57 552.15 -24.83 6,028,441.81 533,636.63 0.75 547.87 2_MWD+IFR2+MS+Sag(1) 1,911.22 30.23 355.13 1,770.00 1,711.15 59943 -28.17 6,028,489.06 533,633.07 1.18 -594.68 2_MWD+IFR2+MS+Sag(1) 2,005.89 29.87 355.60 1,851.94 1,793.09 646.68 -32.00 6,028,536.29 533,629.03 0.45 -641.41 2_MWD+IFR2+MS+Sag(1) 2,101.25 30.58 356.96 1,934.34 1,875.49 694.58 -35.11 6,028,584.17 533,625.70 1.03 -688.86 2_MWD+IFR2+MS+Sag(4) 2,195.78 30.81 357.74 2,015.63 1,956.78 742.78 57.34 6,028,632.36 533,623.25 0.49 -736.68 2_MWD+IFR2+MS+Sag(1) 2,291.26 30.32 358.07 2,097.84 2,038.99 791.30 -39.11 6,028,680.87 533,621.26 0.54 -784.86 2_MWD+IFR2+MS+Sag(1) 2,386.52 25.46 358.72 2,182.01 2,123.16 835.83 40.38 6,028,725.38 533,619.79 5.11 -829.11 2_MWD+IFR2+MS+Sag(1) 2,481.47 21.59 356.28 2,269.05 2,210.20 873.68 4197 6,028,763.22 533,618.03 4.20 -866.67 2_MWD+IFR2+MS+Sag(1) 2,575.86 16.81 350.20 2,358.18 2,299.33 904.48 4542 6,028,794.01 533,614.44 5.48 -897.06 2_MWD+IFR2+MS+Sag(1) 2,671.70 13.62 348.67 2,450.65 2,391.80 929.21 -5000 6,028,818.71 533,609.75 3.35 -921.29 2_MWD+IFR2+MS+Sag(1) 2,766.84 8.97 348.19 2,543.92 2,485.07 947.46 -53.72 6,028,836.94 533,605.95 4.89 -939.15 2_MWD+11`112+1VIS+Sag(1) 2,861.58 4.88 335.43 2,637.95 2,579,10 958.36 -56.91 6,028,847.83 533,602.71 4.59 -949.73 2_MWD+IFR2+MS+Sag(1) 2,957.59 4.78 284.66 2,733.66 2,67481 963.09 -62.48 6,028,852.53 533,597.12 4.31 -953.95 2MWD+IFR2+MS+Sag(1) 3,053.26 9.29 255.44 2,828.61 2,769.76 962.15 -73.82 6,028,851.55 533,565.78 5.88 -952.03 2_MWD+IFR2+MS+Sag(1) 3,148.28 11.69 228.14 2,922.10 2,863.25 953.80 -88.42 6,028,843.12 533,571.22 5.74 -942.43 2 MWD+IFR2+MS+Sag(1) 3,243.20 14.51 200.88 3,014.62 2,955.T 936.25 -99.84 6,028,825.53 533,559.89 7.07 -923.95 2_MWD+IFR2+MS+Sag(1) 3,338.82 21.38 186.25 3,105.58 3,046.73 907.68 -106.01 6,028,796.93 533,553.84 8.54 -894.95 2 MWD+IFR2+MS+Sag(1) 3,434.12 27.96 185.15 3,192.14 3,133.29 868.12 -109.92 6,028,757.36 533,550.12 6.92 455.20 2_MWD+IFR2+MS+Sag(1) 3,529.31 34.82 184.54 3,273.35 3,214.50 818.75 -114.07 6,028,707.97 533,546.18 7.21 -805.65 2_MWD+IFR2+MS+Sag(1) 3,624.38 39.83 184.65 3,348.92 3,290.07 761.31 -118.69 6,028,650.51 533,541.82 5.27 -748.03 2_MWD+IFR2+MS+Sag(1) 3,719.48 42.35 185.21 3.420.59 3,361.74 699.04 -124.07 6,028,588.23 533,536.73 2.68 -685.53 2_MWD+IFR2+MS+Sag(1) 3,814.76 44.72 187.33 3,489.67 3,430.82 633.82 -131.27 6,028,522.98 533,529.83 2.92 -619.93 2_MWD+1FR2+MS+Sag(1) 3,909.96 47.92 186.20 3,555.41 3,496.56 565.46 -139.36 6,028,454.59 533,52205 3.47 -551.12 2_MWD+IFR2+MS+Sag(1) 4,005.38 53.05 183.08 3,616.11 3,557.26 492.12 -145.23 6,028,381.24 533,516.50 5.94 477.55 2_MWD+IFR2+MS+Sag(1) 4,100.43 57.86 181.79 3,669.99 3,611.14 413.92 -148.53 6,028,303.04 533,513.56 5.18 -399.37 2_MWD+IFR2+MS+Sag(1) 4,196.26 62.59 182.09 3,717.57 3,658.72 330.82 -151.35 6,028,219.93 533,511.11 4.94 -316.33 2_MWD+IFR2+MS+Sag(1) 4,291.61 71.12 183.73 3,755.01 3,696.16 243.34 -155.84 6,028,132.44 533,507.02 9.08 -228.80 2_MWD+IFR2+MS+Sag(1) 4,386.22 77.81 183.54 3,780.34 3,721.49 152.42 -161.61 6,028,041.51 533,501.66 7.07 -137.72 2_MWD+IFR2+MS+Sag(1) 4,481.87 84.01 184.44 3,795.44 3,736.59 58.25 -168.19 6,027,947.31 533,495.52 6.55 43.34 2_MWD+IFR2+MS+Sag(1) 4,M.26 62.70 184.69 3,806.48 3,747.63 56.20 -175.73 6,027,852.84 533,488.40 1.40 51.41 2_MWD+IFR2+MS+Sag(1) 4,672.01 84.87 185.00 3,816.74 3,757.89 -130.05 -183.69 6,027,758.97 533,480.87 2.31 145.59 2_MWD+IFR2+MS+Sag(1) 4,767.02 85.18 185.01 3,824.98 3,766.13 -224.34 -191.94 6,027,664.65 533,473.04 0.33 240.25 2_MWD+IFR2+MS+Sag(1) 4,862.38 8534 184.53 3.832.53 3,773.68 -319.07 -199.85 6,027,569.89 533,465.57 0.77 335.30 2_MWD+IFR2+MS+Sag(1) 4,888.78 85.61 184.76 3,834.52 3,775.67 -345.31 -201.98 6,027,543.65 533,463.55 1.00 361.63 2_MWD+IFR2+MS+Sag(1) 9/13!2019 1:27:54PM Page 3 COMPASS 5000.15 Build 91 Company: Prosect Site: Well: Wellbore: Desiqn: Survey Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-22 MPU M-22 MPU M-22 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU M-22 MPU M-22 Actual RKB @ 58.85usft MPU M-22 Actual RKB @ 58.85usft True Minimum Curvature NORTH US +CANADA Map Map Vertical MD Inc An TVD TVDSS +N/3 +E/ -W Northing Easting DLS Section (usft) (°) (I (usft) (usft) (usft) (usft) Ift1 1ft) (-11001 an, Survey Tool Name 4,955.29 86.05 186.08 3,839.43 3,780.58 412.34 -208.34 6,027,476.60 533,457.50 2.06 428.96 2_MWD+1FR2+10S+Sag(2) 5,049.86 86.73 184.48 3,845.32 3,786.47 -505.32 -216.93 6,027,383.58 533,449.33 1.85 522.34 2_MWD+IFR2+MS+Sag(2) 5,148.43 86.61 181.83 3,851.04 3,792.19 -603.57 -222.35 6,027,285.32 533,444.36 2.69 620.68 2_MWD+IFR2+MS+Sag(2) 5,246.36 86.98 183.23 3,856.52 3,797.67 -701.24 -226.66 6,027,187.64 533,440.48 1.48 718.36 2_MWD+IFR2+MS+Sag(2) 5,338.32 90.20 186.03 3,858.78 3,799.93 -792.86 -234.08 6,027,096.00 533.433.48 4.64 810.27 2_MWD+IFR2+MS+Sag(2) 5,43].07 90.13 184.99 3,8s850 3,79965 -891.15 -243.57 6,026,997.68 533,424.44 1.06 909.02 2_MWD+1FR2+MS+Sag(2) 5,532.00 90.44 186.22 3,858.03 3,799.18 -985.62 -252.84 6,026,903.17 533,41560 1.34 1,003.94 2_MWD+IFR2+MS+Sag(2) 5,625.72 93.66 182.78 3,854.67 3,795.82 -1,078.97 -260.19 6,026,809.80 533,408.67 5.03 1,097.57 2_MWD+IFR2+MS+Sag(2) 5,721.68 93.22 184]6 3,848.91 3,790.06 -1,174.54 -266.49 6,026,714.21 533,402.81 2.11 1,193.33 2_MWD+IFR2+MS+Sag(2) 5,816.19 92.04 184.46 3,844.58 3,785.73 -1,268.64 -274.07 6,026,620.08 533,395.65 1.29 1,287.73 2_MWD+IFR2+MS+Sag(2) 5,910.39 92.79 184.97 3,840.61 3,781.76 -1,362.44 -281.81 6,026,526.26 533,388.34 0.96 1,381.85 2_MWD+IFR2+MS+Sag(2) 6,006.47 90.00 182.01 3.83627 3,779.42 -1,458.29 -287.65 6,026,430.39 533,382.93 4.23 1,477.84 2_MWD+IFR2+MS+Sag(2) 6,101.95 89.95 181.37 3,838.31 3,779.46 -1,553.73 -290.47 6,026,334.95 533,380.54 0.67 1,573.16 2_MWD+IFR2+MS+Sag(2) 6,196.91 90.81 182.03 3,837.68 3,778.83 -1,648.65 -293.29 6,026,240.04 533,378.16 1.14 1,667.96 2_MWD+IFR2+MS+Sag(2) 6,291.55 90.75 183.80 3,836.39 3,777.54 -1,743.15 -298.10 6,026,145.52 533,373.77 1.87 1,762.53 2_MWD+IFR2+MS+Sag(2) 6,386.82 92.30 187.89 3,833.86 3,775.01 -1,837.87 -307.79 6,026,050.77 533,366.51 4.59 1,857.73 2_MWD+IFR2+MS+Sag(2) 6,481.64 93.97 188.44 3,828.67 3,769.82 -1,931.58 -321.24 6,025,957.00 533,351.49 1.85 1,952.26 2_MWD+IFR2+MS+Sag (2) 6,577.07 9297 18695 3,822.89 3764.04 -2,025.98 -333.99 6,025,862.56 533,339.16 1.88 2,047.41 2_MWD+IFR2+MS+Sag(2) 6,672.10 92.17 185.05 3,818.63 3,759.78 -2,120.39 -343.92 6,025,768.12 533,329.67 2.17 2,142.32 2_MWD+IFR2+MS+Sag(2) 6,76583 93.22 184.52 3,814.23 3,755.38 -2,213.69 -351.73 6,025,674.79 533,322.28 1.25 2,235.95 2_MWD+IFR2+MS+Sag(2) 6,861.22 93.72 188.02 3,808.45 3,749.60 -2,308.32 -362.12 6,025,580.13 533,312.32 3.70 2,331.12 2_MWD+IFR2+MS+Sag(2) 6,958.55 91.98 187.55 3,803.61 3,744.76 -2,404.63 ]75.29 6,025,483.77 533,299.59 1.85 2,426.21 2_MWD+IFR2+MS+Sag(2) 7,054.21 94.65 186.38 3,798.08 3,739.23 -2,499.41 4186.87 6,025,388.94 533,288.44 3.05 2,523.65 2_MWD+IFR2+MS+Sag(2) 7,148.20 97.45 183.64 3,788.17 3,729.32 -2,592.50 -395.04 6,025,295.82 533,280.69 4.16 2,617.10 2_MWD+IFR2+MS+Sag(2) 7,243.53 98.45 183.41 3,774.99 3,716.14 -2,686.73 400.84 6,025,201.57 533,275.31 1.08 2,711.48 2_MWO+IFR2+MS+Sag(2) 7,340.17 96.57 182.86 3,762.36 3,703.51 -2,782.40 406.08 6,025,105.90 533,270.51 2.03 2,807.23 2_MWD+IFR2+MS+Sag(2) 7,435.63 96.38 182.62 3,751.59 3,692.74 -2,877.14 110.61 6,025,011.14 533,266.40 0.32 2,902.01 2_MWD+IFR2+MS+Sag(2) 7,530.17 94.76 182.49 3,742.42 3,683.57 -2,971.14 414.81 6,024,917.14 533,262.63 1.72 2,996.01 2_MWD+IFR2+MS+Sag(2) 7,624.81 93.10 183.03 3,735.93 3,677,08 -3,065.44 419.35 6,024,822.82 533,258.52 1.84 3,090.35 2_MWD+IFR2+MS+Sag(2) 7,720.33 92.97 182.36 3,730.87 3,67292 -3,160.72 423.84 6,024,727.53 533,254.46 0.71 3,185.66 2_MWD+IFR2+MS+Sag(2) 7,816.12 92.91 182.07 3,725.96 3,667.11 -3,256.31 427.54 6,024,631.94 533,251.20 0.31 3,281.21 2_MWD+IFR2+MS+Sag(2) 7,911.11 95.02 181.96 3,719.39 3,660.54 -3,351.01 430.87 6,024,537.23 533,248.30 2.22 3,375.84 2_MWD+IFR2+MS+Sag(2) 8,006.15 95.52 181.20 3,710.66 3,651.81 -3,445.61 -433.48 6,024,442.63 533,246.11 0.95 3,470.31 2_MWD+IFR2+MS+Sag(2) 8,101.35 93.96 181.39 3,702.80 3,643.95 -3,540+46 435.62 6.024,347.78 533,244.40 1.65 3,564.98 2_MWD+IFR2+MS+Sag(2) 8,195.55 92.29 183.18 3,697.66 3,638.81 -3,634.44 439.37 6,024,253.80 533,241.07 2.60 3,658.93 2_MWD+IFR2+MS+Sag(2) 8,290.92 90.87 184.20 3,695.03 3,636.18 ],729.57 445.51 6,024,158.65 533,235.37 1.83 3,754.23 2_MWD+IFR2+MS+Sag(2) 8,386.51 90.87 184.34 3,693.58 3,634.73 -3,824.88 452.63 6,024,063.31 533,228.69 0.15 3,849.80 2_MWD+IFR2+MS+Sag(2) 8,481.58 92.05 185.02 3,691.16 3,632.31 -3,919.60 460.38 6,023,968.57 533,221.36 1.43 3,944.84 2_MWD+IFR2+MS+Sag(2) 8,576.84 9236 185.15 3,687.49 3,628.64 4.014.42 468.82 6,023,873.73 533,213.35 0.35 4,040.03 2_MWD+IFR2+MS+Sag(2) 8,672.51 92.60 184.93 3,683.35 3,624.50 -4,109.63 477.21 6,023,778.49 533,205.39 0.34 4,135.61 2_MWD+IFR2+MS+Sag(2) 9.1132019 1:27:54PM Pow 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-22 MPU M-22 MPU M-22 Local Co-ordinate Reference: Well MPU M-22 ND Reference: MPU M-22 Actual RKB @ 58.85usft MD Reference: MPU M-22 Actual IRKS @ 58.85usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US+CANADA Survey Map Map vertical MD Inc Azi ND T/DSS +N/ -S +E/ -W Northing Easting DLS Section (usft) V) (1) (usft) (usft) (usft) (usft) inn inn (-/100-) iftt Survey Tool Name 8.767.50 91.61 182.96 3,679.86 3,621-01 4,204.33 483.74 6,023,683.77 533,199.29 2.32 4,230.51 2_MWD+IFR2+MS+Sag(2) 8,862.72 91.68 181.64 3,677.13 3,618.28 4.299.43 487.56 6,023,588.66 533,195.90 1.39 4,325.58 2_MWD+IFR2+MS+Sag(2) 8,957.92 92.42 181.20 3,673.72 3,614.87 4,394.54 489.92 6,023.493.56 533,193.97 0.90 4,420.53 2_MWD+IFR2+MS+Sag(2) 9,053.43 92.54 181.92 3,669.59 3,610.74 4,489.92 492.52 6,023,398.17 533,191.81 0.76 4,515.78 2_MWD+IFR2+MS+Sag(2) 9,148.75 93.34 183.49 3,664.70 3,60585 4,585.01 497.01 6,023,303.07 533,187.75 1.85 4,610.89 2_MWD+IFR2+MS+Sag(2) 9.243.67 93.72 184.73 3,656.86 3,600.01 4,679.50 -503.80 6,023,208.56 533,181.38 1.36 4,705.62 2_MWD+IFR2+MS+Sag(2) 9,339.06 90.25 183.64 3,655.55 3,596.70 4,774.56 -510.76 6,023,113.48 533,174.86 3.81 4,800.93 2_MWD+IFR2+MS+Sag(2) 9,433.44 88.52 182.80 3,656.57 3,597.72 4,868.78 -516.06 6,023,019.24 533,169.99 2.04 4,895.25 2_MWD+IFR2+MS+Sag(2) 9,530.02 91.19 184.16 3,656.81 3,597.96 4,965.17 -521.92 6,022,922.83 533,164.56 3.10 4,991.78 2 MWD+IFR2+MS+Sag(2) 9,624.93 91.61 184.88 3,654.49 3,595.64 -5,059.76 -529.40 6,022,828.23 533,157.51 0.88 5,086.66 2_MWD+IFR2+MS+Sag(2) 9,718.84 90.38 185.26 3,652.86 3,594.01 5,153.29 -537.69 6,022,734.67 533,149.64 1.37 5,180.56 2_MWD+IFR2+MS+Sag(2) 9,815.28 89.33 185.32 3,653.11 3,594.26 -5,249.31 -546.58 6,022,638.61 533,141.18 1.09 5,276.99 2_MWD+IFR2+MS+Sag(2) 9,907.63 88.46 185.47 3,654.89 3,596.04 -5,341.24 -555.27 6,022,546.66 533,132.92 0.96 5,369.32 2_MWD+IFR2+MS+Sag(2) 10.005.48 91.37 187.11 3,655.03 3,596.18 -5,438.48 -565.98 6,022,449.38 533,122.64 3.41 5,467.13 2_MWD+IFR2+MS+Sag(2) 10,100.64 93.66 187.31 3,650.86 3,592.01 -5,532.79 -577.92 6,022,355.02 533,111.14 2.42 5,562.13 2_MWD+IFR2+MS+Sag(2) 10,196.48 95.39 186.39 3,643.29 3,584.44 -5,627.65 -589.31 6,022,260.13 533,100.17 2.04 5,657.61 2_MWD+IFR2+MS+Sag(2) 10,291.49 93.65 185.20 3,635.81 3,576.96 -5,721.87 598.87 6,022,16587 533,091.04 2.22 5,752.31 2_MWD+IFR2+MS+Sag(2) 10,386.80 92.97 184.45 3,630.30 3,571.45 -5,816.69 4i06.88 6,022,071.03 533,083.47 1.06 5,847,46 2_MWOAFR2+MS+Sag(2) 10,479.91 92.79 182.65 3,625.63 3,566.78 5,909.50 -612.63 6,021,978.20 533,078.13 1.94 5,940.42 2_MWD+IFR2+MS+Sag(2) 10,576.05 88.21 180.72 3,624.79 3,565.94 -6,005.56 -615.46 6,021,882.14 533,075.74 5.17 6,036.37 2_MWD+IFR2+MS+Sag(2) 10,671.88 83.63 178.58 3,631.60 3,572.75 -6,101.12 -614.88 6,021,786.60 533,076.75 5.27 6,131.50 2_MWD+IFR2+MS+Sag(2) 10,767.49 84.76 178.57 3,641.27 3,582.42 -6,196.20 612.51 6,021,691.53 533,079.55 1.18 6,226.02 2_MWD+IFR2+MS+Sag(2) 10,862.64 86.93 179.21 3,648.17 3,589.32 -6,291.08 610.68 6,021,596.67 533,081.81 2.38 6,320.38 2_MWD+IFR2+MS+Sag(2) 10,957.96 86.61 179.68 3,653.54 3,594.69 -6,386.24 -609.76 6,021,501.52 533,083.17 0.60 6,415.10 2_MWD+IFR2+MS+Sag(2) 11,053.70 84.87 180.65 3,660.65 3,601.80 -6,481.71 -610.03 6,021,406.06 533,083.32 2.08 6,510.23 2_MWD+IFR2+MS+Sag(2) 11,148.78 87.17 482.82 3,667.25 3,608.40 -6,576.51 612.90 6,021,311.26 533,080.88 3.32 6,604.91 2_MWD+IFR2+MS+Sag(2) 11,243.65 89.89 184.17 3,669.68 3,610.83 -6,671.16 -618.68 6,021,216.60 533,075.53 3.20 6,699.70 2_MWD+IFR2+MS+Sag(2) 11,339.04 92.67 185.85 3,667.55 3,608.70 6,766.15 -627.01 6,021,121.58 533,067.63 3.40 6,795.06 2_MWD+IFR2+M8+Ssg(2) 11,433.07 93.72 186.12 3,662.31 3,603.46 -6,859.52 -636.80 6,021,028.17 533,058.27 1.15 6,888.93 2_MWD+IFR2+MS+Sag(2) 11,529.06 92.85 185.93 3,656.81 3,597.96 -6,954.82 -646.86 6,020,932.84 533,048.64 0.93 6,984.74 2_MWD+IFR2+MS+Sag(2) 11,624.96 92.72 184.86 3,652.15 3,593.30 -7,050.18 655.86 6,020,837.45 533,040.07 1.12 7,080.53 2_MWD+IFR2+MS+Sag(2) 11,720.22 92.91 184.95 3,647.47 3,588.62 -7,144.98 664.00 6,020,742.62 533,03236 0.22 7,175.67 2_MWD+IFR2+MS+Sag(2) 11,815.67 90.62 184.33 3,644.53 3,585.68 -7,240.07 -671.72 6,020,647.51 533,025.08 2.49 7,271.07 2_MWD+IFR2+MS+Sag(2) 11,910.50 90.57 184.30 3,643.55 3,584.70 -7,334.62 -678.85 6,020,552.94 533,018.37 0.06 7,365.88 2_MWD+1FR2+MS+Sag(2) 12,005.74 90.63 184.37 3,642.55 3,583.70 -7,429.58 686.05 6,020,457.95 533,011.60 0.10 7,461.11 2_MWD+IFR2+MS+Sag(2) 12,100.88 90.32 183.66 3,641.76 3,582.91 -7,524.49 692.71 6,020,363.03 533,005.37 0.81 7,556.23 2_MWD+IFR2+MS+Sag(2) 12,196.09 91.25 183.17 3,640.46 3,581.61 -7,619.52 -698.38 6,020,267.98 533,000.13 1.10 7,651.40 2_MWD+IFR2+MS+Sag(2) 12,291.70 91.12 182.66 3,638.48 3,579.63 -7,714.98 -703.24 6,020,172.51 532,995.70 0.55 7,746.92 2_MWD+IFR2+MS+Sag(2) 12,386.71 91.06 182.43 3.M13A7 3,577.82 -7,809.88 -707.46 6,020,077.60 532,991.91 0.25 7,841.83 2_MWD+IFR2+MS+Sag(2) 12,481.61 91.80 184.04 3,634.31 3,575.46 -7,904.60 -712.81 6,019,982.87 532,986.99 1.87 7,936.65 2_MWD+IFR2+MS+Sag(2) 9/13/2019 1:27:54PM Page 5 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-22 Project: Milne Point TVD Reference: MPU M-22 Actual RKB @ 5B.85usft Site: M Pt Moose Pad MD Reference: MPU M-22 Actual RKB @ 58.85usft Well: MPU M-22 North Reference: True Wellbore: MPU M-22 Survey Calculation Method: Minimum Curvature Design: MPU M-22 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) Iftl 1111 (°1100) rftl Survey Tool Name 12,577.24 90.13 187.08 3,632.69 3,573.84 -7,999.75 -722.08 6.019,887.68 532,978.16 3.63 8,032.24 2_MWD+IFR2+MS+Sag(2) 12,672.26 92.42 187.33 3,630.58 3,571.73 -8,093.99 -733.99 6,019,79340 532,966.67 2.42 8,127.17 2 M _WD+IFR2+MS+Sag(2) 12,700.00 92.74 186.89 3,629.33 3,570.48 -8,121.49 -737.42 6,019,765.89 532,963.37 1.96 8,154.86 2_MWD+IFR2+MS+Sag(3) 12,767.71 90.38 186.98 3,627.49 3,568.64 -8,188.67 -745.59 6,019,698.87 532,955.50 3.49 8,222.50 2_MWD+IFR2+MS+Sag(3) 12,861.46 89.64 185.30 3,627.47 3,568.62 -8,281.88 -755.62 6,019,605.43 532,945.90 1.96 8,316:23 2_MWD+IFR2+MS+Sag(3) 12,957.23 90.20 184.63 3,627.61 3,568.76 -8,377.29 -763.91 6,019,509.99 532,938.04 0.91 8,412.00 2_MWD+IFR2+MS+Sag(3) 13,054.35 90.01 184.49 3,627.43 3,56858 -8,474.10 -771.63 6,019,413.16 532,930.76 0.24 8,509.11 2_MWD+IFR2+MS+Sag(3) 13,147.80 90.69 184.01 3,626.86 3,568.01 -8,567.29 -778.55 6,019,319.95 532,924.26 0.89 8,602.55 2_MWD+IFR2+MS+Sag(3) 13,244.35 91.00 113.69 3,625.43 3,566,58 -8,663.61 -785.04 6,019,223.61 532,918.21 0,46 8,699.07 2_MWD+IFR2+MS+Ssg(3) 13,339.60 89.88 182.73 3,624.70 3,565.85 -8,758.71 -790.37 6,019,128.50 532,913.31 1.55 8,794.27 2_MWD+IFR2+MS+Sag(3) 13,434.03 88.40 182.62 3,626.12 3,56727 -8,853.02 -794.78 6,019,034.17 532,909.33 1.57 8,888.61 2_MWD+IFR2+MS+Sag(3) 13,529.39 87.72 182.01 3,629.35 3,570.50 -8,948.25 -798.63 6.018,938.94 532,905.91 0.96 8,983.81 2_MWD+IFR2+MS+Sag(3) 13,625.17 87.35 181.84 3,633.47 3,574.62 -9,043.89 501.84 6,018,843.30 532,903.13 0.43 9,079.36 2_MWD+IFR2+MS+Sag(3) 13,720.03 88.78 181.69 3,636.67 3,577.82 -9,138.65 -804.76 6,018,748.54 532,900.64 1.52 9,174.01 2_MW13+1FR2+10S+Sag(3) 13,816.07 88.65 181.63 3,638.82 3,579.97 -9,234.62 -807.54 6,018,652.56 532,898.29 0.15 9,269.86 2_MWD+IFR2+MS+Ssg(3) 13,912.02 90.20 184.65 3,639.79 3,580.94 -9,330.41 512.80 6,018,556.76 532,893.47 3.64 9,365.74 2_1WJD+IFR2+MS+Sag(3) 14,005.44 90.38 186.57 3,639.31 3,580.46 -9,423.38 521.93 6,018,463.76 532,884.76 2.06 9,459.15 2_MWD+IFR2+MS+Sag(3) 14,049.16 91.18 187.30 3,638.72 3,579.87 -9,466.77 4327.21 6,018,42035 532,879.68 2.48 9,502.84 2_MWD+IFR2+MS+Sag(3) 14,120.00 91.18 187.30 3,637.26 3,578.41 -9,537.02 -836.21 6,018,350.06 532,871.00 0.00 9,573.61 PROJECTED10 TD MME By: Chelsea Wright .a�.,..:m.,- Approved By: Benjamin Hand _-.-.._... -----M Date: 9/13/19 9/132019 1:27:54PM Peas 6 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-22PB1 500292364570 Sperry Drilling Definitive Survey Report 11 September, 2019 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-22 Project: Milne Point TVD Reference: MPU M-22 Actual RKB @ 58.85usft Site: M Pt Moose Pad MD Reference: MPU M-22 Actual RKB @ 58.85usft Well: MPU M-22 North Reference: True Wellbore: MPU M-22PBl Survey Calculation Method: Minimum Curvature Design: MPU M-22PB1 Database: NORTH US+CANADA rroject Milne Point, ACT, MILNE POINT Aap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level ieo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Aap Zone: Alaska Zone 04 Using geodetic scale factor Well MPU M-22 Well Position +N/S +E/ -W Position Uncertainty Wellbore MPU M-22PB1 Magnetics Model Name Design MI Audit Notes: Version: 1.0 Vertical Section: 0.00 usft Northing: 6,027,889.83 usft 0.00 usft Easting: 533,663.95 usft 0.00 usft Wellhead Elevation: 0.00 usft Sample Date Declination (`) BGGM2018 8/17/2019 M-22PB1 Phase: ACTUAL Depth From (TVD) +N/ -S (usft) (usft) 33.95 0.00 16.50 Latitude: Longitude: Ground Level: Dip Angle M 80.95 Tie On Depth: 33.95 +FJ -W Direction (usft) (1) 0.00 184.00 70°29'14.012N 149° 43'29.456 W 24.90 usft Field Strength (nT) 57,416.77654023 Survey Program Date 9/11/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 208.09 4,888.78 MPU M-22PB1 MWD+IFR2+MS+Sag (1) 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +as 08/15/2019 4,956.29 12,862.33 MPU M-22PB1 MWD+IFR2+MS+Sag (2) 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sa 09/03/2019 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +EI -W Northing Easting DLS Section (usft) (1) (`) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 33.95 0.00 0.00 33.95 -24.90 0.00 0.00 6,027,889.83 533,663.95 0.00 0.00 UNDEFINED 208.09 0.22 5.16 208.09 149.24 0.33 0.03 6,027,890.16 533,663.98 0.13 -0.33 2_MWD+IFR2+MS+Sag(1) 301.37 0.44 349.20 301.37 242.52 0.86 -0.02 6,027,890.69 533,663.93 0.25 M -0.86 2_WD+IFR2+MS+Sag(1) 393.39 2.79 346.28 393.34 334.49 3.39 -0.62 6,027,893.21 533,663.32 2.55 -3.33 2_MWD+IFR2+MS+Sag(1)M 486.96 5.22 345.67 486.68 427.83 9.72 -2.21 6,027,899.54 533,661.69 2.60 -9.55 2_WD+1FR2+MS+Sag(1) 579.70 9.00 349.26 578.69 519.84 20.94 4.61 6,027,910.75 533,659.25 4.10 -20.57 2_MWD+IFR2+MS+Sag(1) 673.33 13.67 351.21 670.47 611.62 39.08 -7.67 6,027,928.87 533,656.11 5.00 -38.45 2_MWD+IFR2+MS+Sag(1) 769.77 17.77 355.35 763.28 704.43 65.02 -10.60 6,027,954.80 533,653.05 4.40 -64.13 2_MWD+IFR2+MS+Sag(1) 864.53 23.01 357.34 852.08 793.23 97.96 -12.64 6,027,987.72 533,650.87 5.58 -96.84 2_MWD+IFR2+MS+Sag(1) 959.79 26.06 358.81 938.73 879.88 137.49 -13.93 6,028,027.24 533,649.40 3.27 -136.18 2_MWD+1FR2+MS+Sag(1) 1,055.34 26.21 359.48 1,024.51 965.66 179.57 -14.56 6,028,069.32 533,648.58 0.35 -178.12 2_MWD+IFR2+MS+Sag(1) 1,150.34 28.95 359.06 1,108.70 1,049.85 223.55 -15.13 6,028,113.28 533,647.81 2.89 -221.95 2_MWD+IFR2+MS+Sag (1) 1,244.42 29.05 359.69 1,190.99 1,132.14 269.15 -15.63 6,028,158.88 533,647.11 0.34 -267.41 2 MWD+IFR2+MS+Sag (1) 9/112019 12.40:34PM Page 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-22 Project: Milne Point TVD Reference: MPU M-22 Actual RKB @ 58.85usft Site: M Pt Moose Pad MD Reference: MPU M-22 Actual RKB @ 58.85usft Well: MPU M-22 North Reference: True Wellbore: MPU M-22PB1 Survey Calculation Method: Minimum Curvature Design: MPU M-22PB1 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +EI -W Northing Easting DLS Section (usft) (') (1) (usft) (usft) (usft) (usft) (ft) (ft) ('Noo-) (ft) Survey Tool Name 1,341.48 28.53 0.22 1,276.05 1,217.20 315.90 -15.66 6,028,205.62 533,646.86 0.60 -314.04 2_MWD+IFR2+MS+Sag(1) 1,436.03 28.84 358.13 1,359.00 1,300.15 361.27 -16.32 6,028,250.99 533,645.99 1.11 -359.25 2_MWD+IFR2+MS+Sag(1) 1,530.93 30.86 357.12 1,441.31 1,382.46 408.46 -18.29 6,028,298.16 533,643.81 2.19 -406.19 2_MWD+IFR2+MS+Sag(1) 1,626.12 30.79 357.37 1,523.05 1,464.20 457.18 -20.64 6,028,346.87 533,641.25 0.15 -454.63 2_MWD+IFR2+MS+Sag(1) 1,721.40 29.95 35786 1,605.25 1,546.40 505.31 -22.64 6,028,394.98 533,639.02 0.92 -502.50 2_MWD+IFR2+MS+Sag(1) 1,816.01 29.48 356.80 1,687.42 1,628.57 552.15 -24.83 6,028,441.81 533,636.63 0.75 -549.08 2_MWD+IFR2+MS+Sag(1) 1,911.22 30.23 355.13 1,770.00 1,711.15 599.43 -28.17 6,028,489.06 533,633.07 1.18 -596.00 2_MWD+IFR2+MS+Sag(1) 2,005.89 29.87 355.60 1,851.94 1,793.09 646.68 -32.00 6,028,536.29 533,629.03 0.45 -642.87 2_MWD+IFR2+MS+Sag(1) 2,101.25 30.58 356.96 1,934.34 1,875.49 694.58 -35.11 6,028,584.17 533,625.70 1.03 -690.44 2_MWD+IFR2+MS+Sag(1) 2,195.78 30.81 357.74 2,015.63 1,956.78 742.78 -37.34 6,028,632.36 533,623.25 0.49 -738.37 2_MWD+IFR2+MS+Sag(1) 2,291.26 30.32 358.07 2,097.84 2,038.99 791.30 -39.11 6,028,680.87 533,621.26 0.54 -786.64 2_MWD+IFR2+MS+Sag(1) 2,386.52 25.46 358.72 2,182.01 2,123.16 835.83 -40.38 6,028,725.38 533,619.79 5.11 -830.98 2_MWD+IFR2+MS+Sag (1) 2,481.47 21.59 356.28 2,269.05 2,210.20 873.68 41.97 6,028,763.22 533,618.03 4.20 -868.62 2_MWD+IFR2+MS+Sag(1) 2,575.86 16.81 350.20 2,358.18 2,299.33 904.48 -45.42 6,028,794.01 533,614.44 5.48 -899.11 2_MWD+IFR2+MS+Sag(1) 2,671.70 13.62 348.67 2,450.65 2,391.80 929.21 -50.00 6,028,818.71 533,609.75 3.35 -923.46 2_MWD+IFR2+MS+Sag(1) 2,766.84 8.97 348.19 2,543.92 2,485.07 947.46 -53.72 6,028,836.94 533,605.95 4.89 -941.40 2_MWD+IFR2+MS+Sag(1) 2,861.58 4.88 335.43 2,637.95 2,579.10 958.36 -56.91 6,028,847.83 533,602.71 4.59 -952.06 2_MWD+IFR2+MS+Sag(1) 2,957.59 4.78 284.66 2,733.66 2,674.81 963.09 -62.48 6,028,852.53 533,597.12 4.31 -956.38 2_MWD+IFR2+MS+Sag(1) 3,053.26 9.29 255.44 2,828.61 2,769.76 962.15 -73.82 6,028,851.55 533,585.78 5.88 -954.66 2_MWD+IFR2+MS+Sag (1) 3,148.28 11.69 228.14 2,922.10 2,863.25 953.80 -88.42 6,028,843.12 533,571.22 5.74 -945.31 2_MWD+IFR2+MS+Sag(1) 3,243.20 14.51 200.88 3,014.62 2,955.77 936.25 -99.84 6,028,825.53 533,559.89 7.07 -927.00 2_MWD+IFR2+MS+Sag(1) 3,338.82 21.38 186.25 3,105.58 3,046.73 907.68 -106.01 6,028,796.93 533,553.84 8.54 -898.08 2_MWD+IFR2+MS+Sag(1) 3,434.12 27.96 185.15 3,192.14 3,133.29 868.12 -109.92 6,028,757.36 533,550.12 6.92 -858.34 2 MWD+IFR2+MS+Sag(1) 3,529.31 34.82 184.54 3,273.35 3,214.50 818.75 -114.07 6,028,707.97 533,546.18 7.21 -808.79 2_MWD+IFR2+MS+Sag(1) 3,624.38 39.83 184.65 3,348.92 3,290.07 761.31 -118.69 6,028,650.51 533,541.82 5.27 -751.17 2_MWD+IFR2+MS+Sag(1) 3,719.48 42.35 185.21 3,420.59 3,361.74 699.04 -124.07 6,028,588.23 533,536.73 2.68 -688.68 2_MWD+IFR2+MS+Sag(1) 3,814.76 44.72 187.33 3,489.67 3,430.82 633.82 -131.27 6,028,522.98 533,529.83 2.92 -623.12 2 MWD+IFR2+MS+Sag(1) 3,909.96 47.92 186.20 3,555.41 3,496.56 565.46 -139.36 6,028,454.59 533,522.05 3.47 -554.36 2_MWD+IFR2+MS+Sag (1) 4,005.38 53.05 183.08 3,616.11 3,557.26 492.12 -145.23 6,028,381.24 533,516.50 5.94 -480.79 2_MWD+IFR2+MS+Sag(1) 4,100.43 57.86 181.79 3,669.99 3,611.14 413.92 -148.53 6,028,303.04 533,513.56 5.18 402.56 2_MWD+IFR2+MS+Sag(1) 4,196.26 62.59 182.09 3,717.57 3,658.72 330.82 -151.35 6,028,219.93 533,511.11 4.94 -319.45 2_MWD+IFR2+MS+Sag(1) 4,291.61 71.12 183.73 3,755.01 3,696.16 243.34 -155.84 6,028,132.44 533,507.02 9.08 -231.88 2_MWD+IFR2+MS+Sag(1) 4,386.22 77.81 183.54 3,780.34 3,721.49 152.42 -161.61 6,028,041.51 533,501.66 7.07 -140.78 2_MWD+IFR2+MS+Sag(1) 4,481.87 84.01 184.44 3,795.44 3,736.59 58.25 -168.19 6,027,947.31 533,495.52 6.55 -46.38 2_MWD+IFR2+MS+Sag(1) 4,577.26 82.70 184.69 3,806.48 3,747.63 -36.20 -175.73 6,027,852.84 533,488.40 1.40 48.37 2_MWD+IFR2+MS+Sag(1) 4,672.01 84.87 185.00 3,816.74 3,757.89 -130.05 -183.69 6,027,758.97 533,480.87 2.31 142.54 2_MWD+IFR2+MS+Sag(1) 4,767.02 85.18 185.01 3,824.98 3,766.13 -224.34 -191.94 6,027,664.65 533,473.04 0.33 237.18 2_MWD+IFR2+MS+Sag(1) 4,862.38 85.74 184.53 3,832.53 3,773.68 -319.07 -199.85 6,027,569.89 533,465.57 0.77 332.23 2_MWD+IFR2+MS+Sag(1) 4,888.78 85.61 184.76 3,834.52 3,775.67 -345.31 -201.98 6,027,543.65 533,463.55 1.00 358.56 2_MWD+IFR2+MS+Sag(1) 4,956.29 86.05 186.08 3,839.43 3,780.58 -412.34 -208.34 6,027,476.60 533,457.50 2.06 425.86 2_MWD+IFR2+MS+Sag(2) 9/112019 12.40:34PM Page 3 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-22 Project: Milne Point TVD Reference: MPU M-22 Actual RKB @ 58.85usft Site: M Pt Moose Pad MD Reference: MPU M-22 Actual RKB @ 58.85usft Well: MPU M-22 North Reference: True Wellbore: MPU M-22PB1 Survey Calculation Method: Minimum Curvature Design: MPU M-22PB1 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi ND TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) V) M (usft) (usft) (usft) (usft) (ft) (ft) (-/IGO-) (ft) Survey Tool Name 5,049.86 86.73 184.48 3,845.32 3,786.47 -505.32 -216.93 6,027,383.58 533,449.33 1.85 519.22 2_MWD+IFR2+MS+Sag(2) 5,148.43 86.61 181.83 3,851.04 3,792.19 -603.57 -222.35 6,027,285.32 533,444.36 2.69 617.61 2_MWD+IFR2+MS+Sag (2) 5,246.36 86.98 183.23 3,856.52 3,797.67 -701.24 -226.66 6,027,187.64 533,440.48 1.48 715.35 2_MWD+1FR2+MS+Sag(2) 5,338.32 90.20 186.03 3,858.78 3,799.93 -792.86 -234.08 6,027,096.00 533,433.48 4.64 807.25 2_MWD+IFR2+MS+Sag(2) 5,437.07 90.13 184.99 3,858.50 3,799.65 -891.15 -243.57 6,026,997.68 533,424.44 1.06 905.97 2_MWD+IFR2+MS+Sag(2) 5,532.00 90.44 186.22 3,858.03 3,799.18 -985.62 -252.84 6,026,903.17 533,415.60 1.34 1,000.86 2_MWD+IFR2+MS+Sag (2) 5,625.72 93.66 182.78 3,854.67 3,795.82 -1,078.97 -260.19 6,026,809.80 533,408.67 5.03 1,094.49 2_MWD+IFR2+MS+Sag(2) 5,721.68 93.22 184.76 3,848.91 3,790.06 -1,174.54 -266.49 6,026,714.21 533,402.81 2.11 1,190.27 2_MWD+IFR2+MS+Sag(2) 5,816.19 92.04 184.46 3,844.58 3,785.73 -1,268.64 -274.07 6,026,620.08 533,395.65 1.29 1,284.67 2_MWD+IFR2+MS+Sag (2) 5,910.39 92.79 184.97 3,840.61 3,781.76 -1,362.44 -281.81 6,026,526.26 533,388.34 0.96 1,378.78 2_MWD+IFR2+MS+Sag(2) 6,006.47 90.00 182.01 3,838.27 3,779.42 -1,458.29 -287.65 6,026,430.39 533,382.93 4.23 1,474.81 2_MWD+IFR2+MS+Sag(2) 6,101.95 89.95 181.37 3,838.31 3,779.46 -1,553.73 -290.47 6,026,334.95 533,380.54 0.67 1,570.21 2 MWD+IFR2+MS+Sag (2) 6,196.91 90.81 182.03 3,837.68 3,778.83 -1,648.65 -293.29 6,026,240.04 533,378.16 1.14 1,665.09 2_MWD+IFR2+MS+Sag (2) 6,291.55 90.75 183.80 3,836.39 3,777.54 -1,743.15 -298.10 6,026,145.52 533,373.77 1.87 1,759.70 2 MWD+IFR2+MS+Sag(2) 6,386.82 92.30 187.89 3,833.86 3,775.01 -1,837.87 -307.79 6,026,050.77 533,364.51 4.59 1,854.86 2_MWD+IFR2+MS+Sag(2) 6,481.64 93.97 188.44 3,828.67 3,769.82 -1,931.58 -321.24 6,025,957.00 533,351.49 1.85 1,949.29 2_MWD+IFR2+MS+Sag(2) 6,577.07 92.97 186.95 3,822.89 3,764.04 -2,025.98 -333.99 6,025,862.56 533,339.16 1.88 2,044.34 2_MWD+IFR2+MS+Sag(2) 6,672.10 92.17 185.05 3,818.63 3,759.78 -2,120.39 -343.92 6,025,768.12 533,329.67 2.17 2,139.21 2 MWD+IFR2+MS+Sag(2) 6,765.83 93.22 184.52 3,814.23 3,755.38 -2,213.69 -351.73 6,025,674.79 533,322.28 1.25 2,232.83 2_MWD+IFR2+MS+Sag(2) 6,861.22 93.72 188.02 3,808.45 3,749.60 -2,308.32 -362.12 6,025,580.13 533,312.32 3.70 2,327.95 2_MWD+IFR2+MS+Sag(2) 6,958.55 91.98 187.55 3,803.61 3,744.76 -2,404.63 -375.29 6,025,483.77 533,299.59 1.85 2,424.95 2_MWD+IFR2+MS+Sag(2) 7,054.21 94.65 186.38 3,798.08 3,739.23 -2,499.41 -386.87 6,025,388.94 533,288.44 305 2,520.31 2_MWD+IFR2+MS+Sag(2) 7,148.20 97.45 183.64 3,788.17 3,729.32 -2,592.50 -395.04 6,025,295.82 533,280.69 4.16 2,613.74 2_MWD+IFR2+MS+Sag (2) 7,243.53 98.45 183.41 3,774.99 3,716.14 -2,686.73 -400.84 6,025,201.57 533,275.31 1.08 2,708.15 2_MWD+IFR2+MS+Sag(2) 7,340.17 96.57 182.86 3,762.36 3,703.51 -2,782.40 406.08 6,025,105.90 533,270.51 2.03 2,803.95 2_MWD+IFR2+MS+Sag(2) 7,435.63 96.38 182.62 3,751.59 3,692.74 -2,877.14 -410.61 6,025,011.14 533,266.40 0.32 2,898.77 2_MWD+IFR2+MS+Sag (2) 7,530.17 94.76 182.49 3,742.42 3,683.57 -2,971.14 -414.81 6,024,917.14 533,262.63 1.72 2,992.84 2_MWD+IFR2+MS+Sag (2) 7,624.81 93.10 183.03 3,735.93 3,677.08 -3,065.44 419.35 6,024,822.82 533,258.52 1.84 3,087.23 2_MWD+IFR2+MS+Sag(2) 7,720.33 92.97 182.36 3,730.87 3,672.02 3,160.72 323.84 6,024,727.53 533,254.46 0.71 3,182.59 2_MWD+IFR2+MS+Sag(2) 7,816.12 92.91 182.07 3,725.96 3,667.11 -3,256.31 327.54 6,024,631.94 533,251.20 0.31 3,278.20 2_MWD+IFR2+MS+Sag (2) 7,911.11 95.02 181.96 3,719.39 3,660.54 -3,351.01 3 6,024,537.23 533,248.30 2.22 M30.87 3,372.91 2_WD+IFR2+MS+Sag(2) 8,006.15 95.52 181.20 3,710.66 3,651.81 -3,445.61 333.48 6,024,442.63 533,246.11 0.95 3,467.46 2_MWD+IFR2+MS+Sag(2) 8,101.35 93.96 181.39 3,702.80 3,643.95 -3,540.46 335.62 6,024,347.78 533,244.40 1.65 3,562.22 2 MWD+IFR2+MS+Sag (2) 8,195.55 92.29 183.18 3,697.66 3,638.81 -3,634.44 339.37 6,024,253.80 533,241.07 2.60 3,656.23 2_MWD+IFR2+MS+Sag(2) 8,290.92 90.87 184.20 3,695.03 3,636.18 -3,729.57 -445.51 6,024,158.65 533,235.37 1.83 3,751.56 2_MWD+IFR2+MS+Sag(2) 8,386.51 90.87 184.34 3,693.58 3,634.73 -3,824.88 352.63 6,024,063.31 533,228.69 0.15 3,847.14 2_MWD+IFR2+MS+Sag (2) 8,481.58 92.05 185.02 3,691.16 3,632.31 -3,919.60 460.38 6,023,968.57 533,221.36 1.43 3,942.17 2_MWD+IFR2+MS+Sag (2) 8,576.84 92.36 185.15 3,687.49 3,628.64 3,014.42 368.82 6,023,873.73 533,213.35 0.35 4,037.34 2_MWD+IFR2+MS+Sag(2) 8,672.51 92.60 184.93 3,683.35 3,624.50 3,109.63 477.21 6,023,778.49 533,205.39 0.34 4,132.91 2_MWD+IFR2+MS+Sag(2) 8,767.50 91.61 182.96 3,679.86 3,621.01 3,204.33 383.74 6,023,683.77 533,199.29 2.32 4,227.83 2_MWD+IFR2+MS+Sag(2) 9/112019 12:40:34PM Page 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilwrp Alaska, LLC Local Co-ordinate Reference: Well MPU M-22 Project: Milne Point TVD Reference: MPU M-22 Actual RKB @ 58.85usft Site: M Pt Moose Pad MD Reference: MPU M-22 Actual RKB @ 58.85usft Well: MPU M-22 North Reference: True Wellbore: MPU M-22PB1 Survey Calculation Method: Minimum Curvature Design: MPU M-22PB1 Database: NORTH US+CANADA Survey - -- Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +EI -W Northing Easting DLS Section (usft) V) (I (usft) (usft) (usft) (usft) (ft) (ft) (°1190') (ft) Survey Tool Name 8,862.72 91.68 181.64 3,677.13 3,618.28 4,299.43 -487.56 6,023,588.66 533,195.90 1.39 4,322.96 2_MWD+IFR2+MS+Sag (2) 8,957.92 92.42 181.20 3,673.72 3,614.87 -4,394.54 -489.92 6,023,493.56 533,193.97 0.90 4,418.01 2_MWD+IFR2+MS+Sag(2) 9,053.43 92.54 181.92 3,669.59 3,610.74 4,489.92 -492.52 6,023,398.17 533,191.81 0.76 4,513.34 2_MWO+IFR2+MS+Sag (2) 9,148.75 93.34 183.49 3,664.70 3,605.85 4,585.01 -497.01 6,023,303.07 533,187.75 1.85 4,608.51 2_MWD+IFR2+MS+Sag (2) 9,243.67 93.72 184.73 3,658.86 3,600.01 -4,679.50 -503.80 6,023,208.56 533,181.38 1.36 4,703.24 2_MWD+IFR2+MS+Sag (2) 9,339.06 90.25 183.64 3,655.55 3,596.70 -4,774.56 -510.76 6,023,113.48 533,174.86 3.81 4,798.56 2_MWD+IFR2+MS+Sag(2) 9,433.44 88.52 182.80 3,656.57 3,597.72 4,868.78 -516.06 6,023,019.24 533,169.99 2.04 4,892.92 2 MWD+IFR2+MS+Sag (2) 9,530.02 91.19 184.16 3,656.81 3,597.96 4,965.17 -521.92 6,022,922.83 533,164.56 3.10 4,989.49 2_MWD+IFR2+MS+Sag (2) 9,624.93 91.61 184.88 3,654.49 3,595.64 -5,059.76 -529.40 6,022,828.23 533,157.51 0.88 5,084.36 2_MWD+IFR2+MS+Sag(2) 9,718.84 90.38 185.26 3,652.86 3,594.01 -5,153.29 -537.69 6,022,734.67 533,149.64 1.37 5,178.24 2_MWD+IFR2+MS+Sag(2) 9,815.28 89.33 185.32 3,653.11 3,594.26 -5,249.31 -546.58 6,022,638.61 533,141.18 1.09 5,274.65 2_MWD+IFR2+MS+Sag (2) 9,907.63 88.46 185.47 3,654.89 3,596.04 -5,341.24 -555.27 6,022,546.66 533,132.92 0.96 5,366.96 2_MWD+IFR2+MS+Sag(2) 10,005.48 91.37 187.11 3,655.03 3,596.18 -5,438.48 -565.98 6,022,449.38 533,122.64 3.41 5,464.72 2_MWD+IFR2+MS+Sag (2)M 10,100.64 93.66 187.31 3,650.86 3,592.01 -5,532.79 -577.92 6,022,355.02 533,111.14 2.42 5,559.63 2_WD+IFR2+MS+Sag (2) 10,196.48 95.39 186.39 3,643.29 3,584.44 -5,627.65 -589.31 6,022,260.13 533,100.17 2.04 5,655.05 2_MWD+IFR2+MS+Sag(2) 10,291.49 93.65 185.20 3,635.81 3,576.96 -5,721.87 -598.87 6,022,165.87 533,091.04 2.22 5,749.71 2_MWD+IFR2+MS+Sag(2) 10,386.80 92.97 184.45 3,630.30 3,571.45 -5,816.69 -606.88 6,022,071.03 533,083.47 1.06 5,844.85 2_MWD+IFR2+MS+Sag (2) 10,479.91 92.79 182.65 3,625.63 3,566.78 -5,909.50 -612.63 6,021,978.20 533,078.13 1.94 5,937.84 2_MWD+IFR2+MS+Sag(2) 10,576.05 88.21 180.72 3,624.79 3,565.94 -6,005.56 -615.46 6,021,882.14 533,075.74 5.17 6,033.86 2_MWD+IFR2+MS+Sag(2) 10,671.88 83.63 178.58 3,631.60 3,572.75 -6,101.12 -614.88 6,021,786.60 533,076.75 5.27 6,129.15 2_MWD+IFR2+MS+Sag (2) 10,767.49 84.76 178.57 3,641.27 3,582.42 -6,196.20 -612.51 6,021,691.53 533,079.55 1.18 6,223.84 2_MWD+IFR2+MS+Sag (2) 10,862.64 86.93 179.21 3,648.17 3,589.32 -6,291.08 -610.68 6,021,596.67 533,081.81 2.38 6,318.35 2_MWD+IFR2+MS+Sag(2) 10,957.96 86.61 179.68 3,653.54 3,594.69 -6,386.24 -609.76 6,021,501.52 533,083.17 0.60 6,413.22 2_MWD+IFR2+MS+Sag (2) 11,053.70 84.87 180.65 3,660.65 3,601.80 -6,481.71 -610.03 6,021,406.06 533,083.32 2.08 6,508.48 2_MWD+IFR2+MS+Sag (2) 11,148.78 87.17 182.82 3,667.25 3,608.40 -6,576.51 -612.90 6,021,311.26 533,080.88 3.32 6,603.24 2_MWD+IFR2+MS+Sag(2) 11,243.65 89.89 184.17 3,669.68 3,610.83 -6,671.16 -618.68 6,021,216.60 533,075.53 3.20 6,698.07 2_MWD+IFR2+MS+Sag (2) 11,339.04 92.67 185.85 3,667.55 3,608.70 -6,766.15 -627.01 6,021,121.58 533,067.63 3.40 6,793.41 2_MWD+IFR2+MS+Sag (2) 11,433.07 93.72 186.12 3,662.31 3,603.46 -6,859.52 -636.80 6,021,028.17 533,058.27 1.15 6,887.23 2_MWD+IFR2+MS+Sag(2) 11,529.06 92.85 185.93 3,656.81 3,597.96 -6,954.82 -646.86 6,020,932.84 533,048.64 0.93 6,983.00 2_MWD+IFR2+MS+Seg (2) 11,624.96 92.72 184.86 3,652.15 3,593.30 -7,050.18 -655.86 6,020,837.45 533,040.07 1.12 7,078.76 2_MWD+IFR2+MS+Sag (2) 11,720.22 92.91 184.95 3,647.47 3,588.62 -7,144.98 -664.00 6,020,742.62 533,032.36 0.22 7,173.89 2_MWD+IFR2+MS+Sag (2) 11,815.67 90.62 184.33 3,644.53 3,585.68 -7,240.07 -671.72 6,020,647.51 533,025.08 2.49 7,269.29 2_MWD+IFR2+MS+Sag(2) 11,910.50 90.57 184.30 3,643.55 3,584.70 -7,334.62 -678.85 6,020,552.94 533,018.37 0.06 7,364.11 2_MWD+IFR2+MS+Sag (2) 12,005.74 90.63 184.37 3,642.55 3,583.70 -7,429.58 -686.05 6,020,457.95 533,011.60 0.10 7,459.34 2_MWD+IFR2+MS+Sag (2) 12,100.88 90.32 183.66 3,641.76 3,582.91 -7,524.49 -692.71 6,020,363.03 533,005.37 0.81 7,554.48 2_MWD+IFR2+MS+Sag (2) 12,196.09 91.25 183.17 3,640.46 3,581.61 -7,619.52 -698.38 6,020,267.98 533,000.13 1.10 7,649.67 2_MWD+IFR2+MS+Sag (2) 12,291.70 91.12 182.66 3,638.48 3,579.63 -7,714.98 -703.24 6,020,172.51 532,995.70 0.55 7,745.25 2_MWD+IFR2+MS+Sag (2) 12,386.71 91.06 182.43 3,636.67 3,577.82 -7,809.88 -707.46 6,020,077.60 532,991.91 0.25 7,840.21 2 MWD+IFR2+MS+Sag(2) 12,481.61 91.80 184.04 3,634.31 3,575.46 -7,904.60 -712.81 6,019,982.87 532,986.99 1.87 7,935.07 2_MWD+IFR2+MS+Sag(2) 12,577.24 90.13 187.08 3,632.69 3,573.84 -7,999.75 -722.08 6,019,887.68 532,978.16 3.63 8,030.63 2_MWD+IFR2+MS+Sag (2) 9/112019 12:40:34PM Page 5 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-22 Project: Milne Point TVD Reference: MPU M-22 Actual RKB @ 58.85usft Site: M Pt Moose Pad MO Reference: MPU M-22 Actual IRKS @ 58.85usft Well: MPU M-22 North Reference: True Wellbore: MPU M-22PB1 Survey Calculation Method: Minimum Curvature Design: MPU M-22PB1 Database: NORTH US+CANADA Survey Checked By: Chelsea Wright..�.;�,.�,:„`E— Approved By: Benjamin Hand -EMT.---- Date: 09-11-2019 9/11/2019 12:40:34PM Page 6 COMPASS 5000.15 Build 91 Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +El -W Northing Easting DLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) ("/100') (ft) Survey Tcol Name 12.672.26 92.42 187.33 3,630.58 3,571.73 -8,093.99 -733.99 6,019,793.40 532,966.67 2.42 8,125.47 2_MWD+IFR2+MS+Sag (2) 12,767.16 93.53 185.81 3,625.66 3,566.81 -8,188.13 -744.83 6,019,699.22 532,956.26 1.98 8,220.15 2_MWD+IFR2+MS+Sag (2) 12,862.33 94.52 183.50 3,618.97 3,560.12 -8,282.75 -752.54 6,019,604.58 532,948.98 2.64 8,315.07 2_MWD+IFR2+MS+Sag(2) 12,932.00 94.52 183.50 3,613.48 3,554.63 -8,352.07 -756.78 6,019,535.24 532,945.06 0.00 8,384.52 PROJECTEDto TD Checked By: Chelsea Wright..�.;�,.�,:„`E— Approved By: Benjamin Hand -EMT.---- Date: 09-11-2019 9/11/2019 12:40:34PM Page 6 COMPASS 5000.15 Build 91 Lease & Well No. County Hifcorp Energy Company CASING & CEMENTING REPORT MP M-22 Date Run 27 -Aug -19 State Alaska Supv. S. Sunderland/C. Demoski CASING RECORD Su face Tft d Od] nn .... ,.a9 .., ern noos: 4au,uuu 1 ype Float Collar Antelope No. His to Run: 19 Csg M. On Slips: 105,000 Type or Shoe. Antelope _ Casing Crew Doyon Rotate Csg X Yes _ No Recip Csg X Yes _ No 50 Ft. Min. 9.3 PPG Fluid Description: Spud Mud Liner hanger Info (MakeNodel): Liner top Packer?: Yes No Liner hanger test pressure: Floats Held X Yes_ No Centralizer Placement: 82 total 9-518'k12-114" Expand -O -Liter centralizers ran with 10 total stop rings. 22 o� #1 w/ 4 stop rings, 1 on joint #2, 1 each w/ 2 stop rings each on ioints #3 & #4. Shoe ush (Spacer) Slurry FC CEMENTING REPORT Top of Liner Density (ppg) Volume pumped (BBLs) Sacks: 275 Yield 12 Volume pumped (BBLs) 115 Mixing/ Pumping Rate(bpm): 4 Density (ppg) 15.8 Volume pumped (BBLs) Post Flush (Spacer) e Type: Clean Spacer Density Sacks: 400 Yield: 82.4 Mixing/ Pumping Rate (bpm): 10 Rate (bpm): 3.5 Volume: 4 3.35 Spud Mud Density(ppg) 9.3 Rate bpm): 5 Volume (actual /calculated): Casing (Or Liner) Detail Rig Bump Plug? X Yes No Setting Depths As. Component Size Wt, Grade THD Make Length Bottom Top 1 Shoe 103/4 50.0 TXP BTC -SR Innovex 1.59 4,942.00 4,940.41 2 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 79.62 4,940.41 4,860.79 1 Float Collar 103/4 50.0 Type: Type G TXP BTC -SR Innovex 1.30 4,860.79 4,859.49 1 Casing95/8 56.2 40.0 L-80 TXP BTC -SR Tenaris 39.70 4,859.49 4,819.79 1 Baffle Adapter 103/4 50.0 10 TXP BTC -SR HES 1.47 4,819.79 4,818.32 67 Casing 95/8 40.0 L-80 TXP BTC -SR Tenaris 2,640.57 1 4,818.32 2,177.75 1 Pup Joint 95/8 40.0 L-80 TXP BTC -SR Tenaris 13.72 2,177.75 2,164.03 1 ESIPC Cementer 103/4 X Vas_ No Vol to Suff. TXP BTC -SR HES 11.90 2,164.03 21152.13 1 Pup Joint 95/8 40.0 L-80 TXP BTC -SR Tenaris 13.08 2,152.13 2,139.05 53 Casin 95/8 40.0 L-80 TXP BTC -SR Tenaris 2,083.88 2,139.05 55.17 1 ut Joint of Casin 95/8 40.0 L-80 TXP BTC -SR Tenaris 23.56 55.17 31.61 ,.a9 .., ern noos: 4au,uuu 1 ype Float Collar Antelope No. His to Run: 19 Csg M. On Slips: 105,000 Type or Shoe. Antelope _ Casing Crew Doyon Rotate Csg X Yes _ No Recip Csg X Yes _ No 50 Ft. Min. 9.3 PPG Fluid Description: Spud Mud Liner hanger Info (MakeNodel): Liner top Packer?: Yes No Liner hanger test pressure: Floats Held X Yes_ No Centralizer Placement: 82 total 9-518'k12-114" Expand -O -Liter centralizers ran with 10 total stop rings. 22 o� #1 w/ 4 stop rings, 1 on joint #2, 1 each w/ 2 stop rings each on ioints #3 & #4. Shoe ush (Spacer) Slurry FC CEMENTING REPORT Top of Liner Density (ppg) Volume pumped (BBLs) Sacks: 275 Yield 12 Volume pumped (BBLs) 115 Mixing/ Pumping Rate(bpm): 4 Density (ppg) 15.8 Volume pumped (BBLs) Post Flush (Spacer) e Type: Clean Spacer Density Sacks: 400 Yield: 82.4 Mixing/ Pumping Rate (bpm): 10 Rate (bpm): 3.5 Volume: 4 3.35 Spud Mud Density(ppg) 9.3 Rate bpm): 5 Volume (actual /calculated): 364.12/365.1 (psi): 640 Pump used for disp: Rig Bump Plug? X Yes No Bump press 11 1g Rotated? X Yes _No Reciprocated? X Yes _No % Ret urns during job 92 ant returns to surface? X Yes No Spacer returns? X Ves _No Vol to Surf. 88 antlnPlace At: 014 Date: 8/29/2019 Estimated TOC: �- 2,152 od Used To Determine TOC: Cement circ to surface Post lob Calculations: Calculated Cmt Vol @ 0% excess: 137.9 Total Volume. cmt Pumped: Cmt returned to surface: 241 Calculated cement left in wellbore: 2352 OH volume Calculated: 137.9 OH volume actual: 235.2 Actual % Washout www.weliez.net WellEz Information Management LLC ver Stage Collar@ Type Closure OK Preflush (Spacer) Type: Density ppg) Volume pumped (BBLs) Lead Slurry Type: Perm L Sacks: 536 Yield: 4.41 Density (ppg) 10.7 Volume pumped (BBLs) 420 Mixing / Pumping Rale (bpm): 5.5 Tail Slurry �0 Type: Type G Sacks: 270 Yield: 1.17 w Density (ppg) 15.8 Volume pumped ( BBLs) 56.2 Mixing/ Pumping Rate (bpm): 4 z Post Flush (Spacer) w Type: Tuned Spacer Density (ppg) 10 Rate (bpm)60 Volume' 3.5 " Displacement: Type: Spud Mud Density (ppg) 9.3 Rate (bpm): 6 Volume (actual /calculated): 161/165 FCP (psi): 430 Pump used for disp: Rig Bump Plug? X Yes No Bump press 13i Casing Rotated? _Yes X No Reciprocated? Yes X _ No % Returns during job 100 Cement returns to surtac ? X Ves _ No Spacer returns? X Vas_ No Vol to Suff. 241 Cement In Plans Al: 35 11: Date'. 8/29/2019 Estimated TOC: 0 Method Used To Determine TOC: Visual Post lob Calculations: Calculated Cmt Vol @ 0% excess: 137.9 Total Volume. cmt Pumped: Cmt returned to surface: 241 Calculated cement left in wellbore: 2352 OH volume Calculated: 137.9 OH volume actual: 235.2 Actual % Washout www.weliez.net WellEz Information Management LLC ver THE STATE °fALAS- A GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-22 Permit to Drill Number: 219-111 Sundry Number: 319-385 Dear Mr. Helgeson: i Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v .00gcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, _ Chmielowski Commissioner DATED this 2Z day of August, 2019. RBDMSL uJAUG 2 3 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25 280 OTS �V%2-2./ I 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing n / Change Approved Program ElPlug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well E] Alt Casin t7/�"' g �] Other: ESP Completion ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: r-4" Hilcorp Alaska LLC Exploratory ❑ Development ❑✓ Stratigraphic ❑ Service ❑ xxx-XXX 2-161-111 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: 56 02 q - 23W49 - Anchorage Alaska 99503 50-029-XXXXX-00-00 oil . ao 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 ' Will planned perforations require a spacing exception? Yes ❑ No 0 MPU M-22 9. Property Designation (Lease Number): , 10. Field/Pool(s): ADL025514 / ADL355023 Milne Point Field / Schrader Bluff Oil Pool it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): ±14,270 ±3,587 ±14,270 ±3,587 1,514 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor ±113' 20" ±113' 113' N/A N/A Surface ±5,049' 9-5/8" ±5,049' 3,900' 5,750psi 3,090P si Tie -Back ±4,950' 7" ±4,900' 3,887' 7,240psi 5,410psi Slotted Liner ±9,370' 6-5/8" ±14,270' 3,587' 6,090psi 3,470psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 3-1/2" 9.2# / L-80 / EUE 8rd ±4,850 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): BOT SLZXP LTP and N/A ±4,950 MD /±3,853 TVD and N/A 12. Attachments: Proposal Summary LJ Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch ❑✓ Exploratory p ry ❑ Stratigraphic ❑ Development ❑� Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 9/4/2019 OIL ❑✓ ` WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson Contact Name: Taylor Wellman T Authorized Title: Opera ons Manager Contact Email: tWelhan(Whilcorp.corin Contact Phone: 777-8449 Authorized Signature: Date: 8/20/2019 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: -33 �? I LI y S Plug Integrity ❑ BOP Test LTJ Mechanical Integrity Test ❑ Location Clearance ❑ Other: -if3QDU P S;, 'goro RBDMS1�AUf 2 3 P019 Post Initial Injection MIT Req'd? Yes ❑ No �❑/ Spacing Exception Required? Yes ❑ FBI' Subsequent Form Required: / O _ u 07 i APPROVED BY Approved by, _ ,��. COMMISSIONER THE COMMISSION Date: 2-2� i ?10-403 Fd Revised 412017 f-2.47 ORIGINAL Submit Form and Approved application is valid for 12 months from the date of approval.Attachments in Duplicate ���� K flil.m Alaska, Lb Initial ESP Completion Well: MP M-22 Date: 06/20/2019 Well Name: MP M-22 API Number: 50-029-xxxxx-00 Current Status: New Well Pad: M -Pad Estimated Start Date: September 4, 2019 Rig: Doyon 14 Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 219-083 First Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) Second Call Engineer: David Haakinson (907) 777-8343 (0) (307) 660-4999 (M) AFE Number: 1913621C Job Type: Initial Completion Current Bottom Hole Pressure: 1,914 psi @ 4,000' TVD (Estimated reservoir pressure / 9.2 ppg EMW) Maximum Expected BHP: 1,914 psi @ 4,000' TVD (Estimated reservoir pressure / 9.2 ppg EMW) MPSP: 1,514 psi (0.1 psi/ft gas gradient) Brief Well Summary: The Milne Point M-22 well is to be a grassroots drilled Schrader Bluff OA sand production well. The PTD for this well has been submitted for M-22 and is scheduled to be drilled. The M-22 well is a similar well design to the recently drilled Moose Pad production wells: M-14, M-16, & M-18. Original plans were to complete the well utilizing the ASR but key wells have developed integrity issues which the ASR will be mobilized to conduct RWO's on. This Sundry Application would replace steps 17.2 —17.2 and all of sections 18 from PTD for M-22. Objective: • Run the 7" tieback to surface and pressure test the 9-5/8"x7" annulus to 1,000psi. • Run the 3-1/2" tubing and ESP completion BOP Testin¢: • This is an extension of the drilling activities with the same rig as submitted in the PTD for M-22. The normal BOP testing timeframe will be followed. If a BOP test is due, it will be conducted at the needed timeframe. Completion Procedure: 17.0 Run 7" Tieback 17.1 RIH w/ 3.5" washpipe on 5" dp to clean out liner top. POOH LDDP. 17.2 R/U and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie -back space out calculation. Install and test 7" (250/3000 psi) solid body casing rams. 17.3 R/U 7" casing handling equipment. Ensure XO to DP made up to FOSV and ready on rig floor. Rig up computer torque monitoring service. • String should stay full while running, r/u fill up line and check as appropriate. Initial ESP Completion Well: MP M-22 Hilcurp Alaska, LU Date: 06/20/2019 17.4 P/U tieback seal assembly and set in rotary table. Ensure 7" seal assembly has x4 1" holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8" x 7" annulus. 17.5 M/U first joint of 7" to seal assy. 17.6 Run 7" 26# TXP tieback to position seal assembly two joints above tieback sleeve. Record up & down weights. 7" 26# TXP MUT OD Minimum Optimum Maximum Yield Torque 7" 13,280 ft -lbs 14,750 ft -lbs 16,230 ft -lbs 23,400 ft -lbs 17.7 M/U 7" to DP crossover. 17.8 M/U stand of DP to string, and M/U top drive. 17.9 Break circulation at 1 bpm and begin lowering string. 17.10 Note seal assembly entering tieback sleeve with a pressure increase, Stop pumping and bleed off pressure, leave standpipe bleed off valve open. 17.11 Continue lowering string and land out on no-go. Set down 5 —10k lbs. Mark the pipe at this depth as "NO-GO DEPTH". 17.12 P/U string & remove unnecessary 7" joints. 17.13 P/U hanger assembly and space out. M/U (or L/D) necessary joints and pup joints to position seal assembly 1 ft above "NO-GO DEPTH" when tie -back hanger lands out in wellhead. 17.14 Ensure circulation is possible through 7" string. 17.15 RU and circulation corrosion inhibited brine in the 9-5/8" x 7" annulus. 17.16 With seals stabbed into SBE, Spot diesel freeze protection from 2100' TVD to surface in 7" x 9-5/8" annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent casing collapse of 7", verify collapse pressure of 7" tie back. 17.17 Slack off and land hanger. U I[ilc.m Alaska, LU Initial ESP Completion Well: MP M-22 Date:06/20/2019 17.18 Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning rpt. 17.19 Back out landing joint. M/U packoff running tool and install packoff on bottom of landing joint. Set tubing hanger pack off. RILDS. Test void to 3000 psi / 10 min. 17.20 R/D casing running tools. 17.21 Test 7" x 9-5/8" production annulus to 1000 psi /30 min. 17.22 Set test plug and change top rams from 7" to 2-7/8" x 5-1/2" VBR. Test annular and lower rams to 2-7/8" test joint, 250 low / 3000 psi high. 18.0 Run ESP Completion 18.1 Change upper pipe rams back to 2-7/8" x 5" VBR. Test same. Verify the ESP components. 18.2 RU spoolers to run ESP cable and single 3/8" cap string. 18.3 PU new ESP and RIH on 3-1/2", 9.2#, L-80 EUE tubing. Set base of ESP at ±4,850 md. a. Check ESP cable continuity and cap string integrity every 2,000' md. b. 3-1/2" 9.3# L-80 EUE 8RD Makeup torque: Tbg OD Minimum Optimum Max Operating Torque 3-1/2" 2,350 ft -lbs 3,130 ft -lbs 3,910 ft -lbs c. Completion components: i. Base of ESP centralizer at ±4,850 md. ii. Zenith Motor Gauge iii. 250 HP Baker Hughes 562XP Motor iv. Tandem Gas Separator with Gas Avoider v. Baker Hughes 40OPMSXD GIN Pump Section #1 vi. Baker Hughes 134 stage Flex17.5 Pump Section #2 vii. Baker Hughes 134 stage Flex17.5 Pump Section #3 viii. Downhole gauge for discharge temperature and pressure. 1. Connected with a jumper from the lower sensor. Does not require a separate tech -wire. ix. Multiple joints of 3-1/2", 9.2#, L-80 EUE 8rd tubing (until <68deg) x. 3-1/2" XN (Min ID=2.75") Nipple A 2 joints of 3-1/2", 9.2#, L-80 EUE 8rd tubing A. Lower 3-1/2" x 1-1/2" side pocket GLM w/ dummy GLV Initial ESP Completion Well: MP M-22 na.•„ , niati� L1,- Date: 06/20/2019 xiii. Multiple joints of 3-1/2", 9.2#, L-80 EUE 8rd tubing Av. Upper 3-1/2" x 1-1/2" side pocket GLM w/ orifice at ±200' and xv. Multiple joints of 3-1/2", 9.2#, L-80 EUE 8rd tubing 18.4 PU and MU tbg hanger with landing joint. Land tbg hanger and RILDS. Lay down landing joint. a. Note PU and SO weights in tally. 18.5 Bullhead freeze protect down the IA (60bbls to 2100' tvd) and down the tbg (20bbls). a. Do not exceed lbpm through the ESP for tubing freeze protect. 18.6 Set BPV and set BPV plug. N/D BOP. 18.7 N/U tree / adapter and tree. Test tubing hanger void to 500 psi low / 5000 psi high. Terminate the cap string and ESP cable. 18.8 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 19.0 RDMO 19.1 RDMO Doyon 14 Attachments: 1. Proposed Schematic 2. BOPE Schematic ff Ifilcorn Aloska, LLC. 04 KB Elev.: 58.7/ GL Bev.: 24.9 TD=13,950' (ND) /TD=3,S10' (IND) PBTD=13,959 (MD) /TD=3,519(M) PROPOSED TREE & WELLHEAD Milne Point Unit Well: MP M-22 Last Completed: Future PTD: TBD Tree Cameron 31/8" 5M Wellhead FMC 11" 5M TC -3A w/11" x 41/2" TC -II Top and Bottom Tubing Hanger with 3" CIVV "H" BPV profile, Zea 3/8" NPT control lines. OPEN HOLE/ CEMENT DETAIL 42" ILO (14 Yards Piilecrete dumped down backside) 12-1/4" 1st stage L—±805 ft3 / T —1458 ft3 12-1/4" 2nd stage L—± 1937 ft3 / T—±314 ft3 8-1/2" Cementless Slotted Liner in 8-1/2" hole CASING DETAIL Size Type Wt/ Grade/ Conn I Drift ID Top Btm BPF 20"x34" Conductor (Insulated) 215.5/A-53/Weld N/A Surface ±113' N/A 9-5/8" Surface 40/L-80/7XP 8.679" Surface ±5,049' 0.0758 7" Tieback 26/L-80/TXP 6.151" Surface ±4,950' 0.0383 6-5/8" Liner (Slotted) 20 / L-80 / Hydril 563 5.924" ±5,338' ±14,270' 0.0355 Slotting Pattern: 4 rows, 8 slots/row, 32 slots/ft, 2" x 0.125" slots, slots on 6" centers, no slot overlap TUBING DETAIL 3-1/2" Tubing 9.2 / L-80 / EUE 8Rd 1 2.992" 1 Surface 1 ±4,850' 0.0087 WELL INCLINATION DETAIL KOP @ ±408' Max Hole Angle = @ Jet Pump Max Hole Angle = @ XN profile Max Hole Angle = @ Tubing tail Max Hole Angle =±89.9 JEWELRY DETAIL No. Top MD Item Drift ID Upper Completion 1 ±29' Tubing Hanger (4-1/2" TC -II Top & Btm) w/ Blast Rings on hanger pup 2 ±168 3-1/2" GLM w/ 1-1/2" w/ SO Valve 3 ±4,210' 3-1/2" GLM w/ 14/2" DGLV 4 ±4,250' 3-1/2" XN-Ni le -Min ID= 2.75" No-go ID 5 ±4,789' Discharge Head 6 ±4,799' Pump 3: 134stage Flex 17.5 7 ±4,810' Pump 2: 134stage Flex 17.5 8 ±4,820' Pum 1: Baker 40OPMSXD GIN 9 ±4,825' Tandem Seal Sections w/ Gas Avoider 10 ±q, 835' Motor: Baker 250Hp 562XP 11 ±4,847' Sensor w/ 6 Fin Centralizer —Bottom@4,850' Lower Completion 12 ±4,950' BOT SLZXP LinerTop Packer w/BD Slips 7-5/8" x 9-5/8" 6.170" 13 ±4,950' 7" Tieback Assy. (8.25" OD No -Go) 6.151" 14 ±4,960' 7" Hydril 563 L-80 x 6-5/8" Hydril 563 L-80 XO 5.924" 15 ±5,100' 6-5/8" Slatted Liner 5,924" 16 ±14,270' Shoe GENERAL WELL INFO API: TBD Drilled and Cased by Future Completed with ESP by Future Revised By: TDF 8/12/2019 H Hilcorp ��Wy 20.0 Doyon 14 BOP Schematic KA One---' Page 39 Milne Point Unit M-22 SB Producer Drilling Procedure 2-7/8" x 5" VBR Blind Rams x 5M HCR awke Lm N Gate Valve 2-7/8" x 5" VBR Schwartz, Guy L (CED) From: Ted Kramer <tkramer@hilcorp.com> Sent: Tuesday, August 20, 2019 9:14 AM To: Schwartz, Guy L (CED) Cc: Donna Ambruz Subject: BCU-04RD PTD 219-011 Attachments: BCU-04RD Schematic 08-07-19.pdf Follow Up Flag: Follow up Flag Status: Flagged Guy, I need to ask the question if AOGCC would be amenable to Hilcorp dummying off the GLM's in the tubing string, blowing down the tubing with Nitrogen, pulling the plug, and flowing the above well at a reduced rate. The reason for doing this is that we are concerned that we may have water below the plug set in the X -nipple at14,932'. This water could swap and get on the formation. It is Hilcorp's belief that the reservoir is sensitive to water and it could damage the formation. This is based on the fact that when Marathon drilled with water based mud when they operated the field the results from BCU oil were greatly diminished. Hilcorp has gone to considerable efforts to keep water away from the zones of interest ie. Drilling with oil based mud and completing with diesel as the completion fluid. This water flow at 11,021 feet did flow water into the tubing string which had a flow path to the formation until we set the plug into the tubing. Hilcorp is working on a plan to remediate the leak at 11,021'. This plan involves bringing Rig 169 back onto that well as soon as tools are procured and a plan is finalized and approved by AOGCC. This will be a temporary step to preserve the formation until the plan can be put in place. Steps would be: RU Slickline and dummy off all 13 GLM's to isolate the water leak behind tubing. RU Coil and Blow the tubing dry with nitrogen. Pull plug in the X nipple at 14,932'. Open the well to the production unit. Bleed down nitrogen to establish flow. Preserving the reservoir is paramount. Determining if the reservoir is already damaged will also affect how we approach the remediation of the well (stimulation or not). Please give me a call to discuss further if needed. Sincerely, Ted Kramer Sr. Operations Engineer 20' ( Beaver Creek Unit a3/8' CASING DETAIL No. Well: BCU RD ACTUAL SCHEMATIC Completed: 6/2 Type PTD: 2199-012/2019 Hilc=ro d.0 API: 50-133-20239-01-00 IBB Dev.:1662'/ BF/GL 17ev.: 148.Y 7 20" B 20' , 17 HPW @ 14,985' - 15,155' MD ta' 1. `F 22 i-, Mat Fbn* b 41/2' TD =16,642 (MD) /TD=15,652'(IVD) PHID=16,512' (MD) / PBm=15,52r (IYD) 2 a3/8' CASING DETAIL No. Depth ID 4 Type 5 I Grade I Conn. s 9-5/3- 7 20" B 94 H-40 Possible leak 7D PdM ea.nr 13-3/8" Surface 72 �— 12 Surface 13 9-5/8" 14 47 & 53.5 u 8,681 is BCU -04 7" 7" 29 roc ip 6.059 xw ma 15,193' , 17 HPW @ 14,985' - 15,155' MD ta' 1. `F 22 i-, Mat Fbn* b 41/2' TD =16,642 (MD) /TD=15,652'(IVD) PHID=16,512' (MD) / PBm=15,52r (IYD) Zone To (MD) Btm(MD) To (TVD) CASING DETAIL No. Depth ID Size Type Wt I Grade I Conn. Drift ID Top Btm 20" Conductor 94 H-40 N/A Surface 2a8' 13-3/8" Surface 72 N-80 12.415 Surface 2,989' 9-5/8" Production 47 & 53.5 N -80,S-95, P-110 8,681 Surface 12,521' 7" Liner 29 P-110 IC/TXP BTC 6.059 10,991' 15,193' 4-1/2" Liner 12.6 L-80 DWC/C 3.833 14,974' 16,607' 9 9,606' 2.920" TUBING DETAIL 3-1/2" FO -1 Mandrel 8RD 10 10,278' 3-1/2" Tubing 9.3 P-110 8RD EUE 2.867 Surt 14,978' Zone To (MD) Btm(MD) To (TVD) JEWELRY DETAIL No. Depth ID OD Item 1 18' 2.992" - Tubing Hanger 2 2,418' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 3 4,367' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8111) 4 5,921' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 5 7,150' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8111) 6 7,495' 2.920" 5.375" 3-1/2" Cl Mandrel 8RD 7 8,134' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 8 8,934' 2.920" 5.375" 1 3-1/2" FO -1 Mandrel 8RD 9 9,606' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 10 10,278' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 11 10,991' 7" Liner Top Packer 12 30,954 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 13 11,128' Water Swell Packer 14 11,665' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 15 12,392' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 16 13,195' 1 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD-Orifice 17 14,888' 4.0" 5.875" Tripoint 7" 26-32# Permanent 18 14,974' 4-1/2"Uner Top Packer 19 14,932' 2.813" 4.50" %-Nipple 20 14,973' 4.276" 5.750" Packer Tie Back Bullet Seals stripped 21 15,067' Water Swell Packer 22 15,810' Plug (7/16/19) Zone To (MD) Btm(MD) To (TVD) Btm(TVD) Amt Status Date Tyonek GlB 15,216 15,234' 14,419' 14,433' 18' Open 7/17/2019 Hemlock 15,900' 15,933' 14,984' 15,013' 33' Isolated w/ plug 7/11/2019 7/16/2019 West Foreland 16,408' 16,474' 15,430' 15,491' 66' I solated w/ plug 7/02/2019 7/16/2019 Updated by DMA 08-07-19 THE STAT _ °fALASKA GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alasko.gov Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-22 Hilcorp Alaska, LLC Permit to Drill Number: 219-111 Surface Location: 5039' FSL, 500' FEL, SEC. 14, T13N, R9E, UM, AK Bottomhole Location: 658' FSL, 1347' FEL, SEC. 23, TI 3N, R9E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this ZUday of August, 2019. STATE OF ALASKA AL. AKA OIL AND GAS CONSERVATION COM%wSION PERMIT TO DRILL 20 AAC 25.005 1a. Type of Work: 11b. Proposed Well Class: Exploratory - Gas Service- WAG Ll Service - Disp ❑ 1c. Specify if well is proposed for: Drill ❑Q Lateral ❑ Stratigraphic Test ❑ Development -Oil ❑Q Service- Winj ❑ Single Zone ❑' Coalbed Gas El Gas Hydrates ❑ Redrill ❑ Reentry ❑ 1 Exploratory -Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket 0 Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 MPU M-22 ' 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 14,270' TVD: 3,587' Milne Point Field ' Bluff Oil Pool , 4a. Location of Well (Governmental Section): 7. Property Designation:.Schrader Surface: 5039' FSL, 500' FEL, Sec 14, T13N, R9E, UM, AK ADL025514,ADL355023 8. DNR Approval Number: 13. Approximate Spud Date: Top of Productive Horizon: 719' FNL, 709' FEL, Sec 14, T13N, R9E, UM, AK LONS 16-004 8/17/2019 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 658' FSL, 1347' FEL, Sec 23, T13N, R9E, UM, AK 5815 719' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 58.7' 15. Distance to Nearest Well Open Surface: x- 533663 y- 6027889 Zone -4 GL / BF Elevation above MSL (ft): 25.0' to Same Pool: 1585'to MPU M-20 16. Deviated wells: Kickoff depth: 350 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 97.1 degrees Downhole: 1705 Surface: 1326 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade I Coupling Length MD TVD MD TVD (including stage data) Cond 20" 215# X-42 Weld 113' Surface Surface 113' • 113' ±270 ft3 Stg 1 L- 630.5 ft3/T-458 ft3 12-1/4" 9-5/8" 40# L-80 TXP SR 5,049' Surface Surface 5,049' • 3,900' Stg 2 L - 1937 ft3 / T - 314 ft3 Tieback 7" 26# L-80 TXP SR 4,900' Surface Surface 4,900' 3,887' Tieback Assy. 8-1/2" 6-518" 20# L-80 Hyd 563 9,370' 4,900' 3,887' 14,270" 3,587' Cementless Slotted Liner 19. PRESENT WELL CONDITION SUMMARY (To be completed for Reddll and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Hydraulic Fracture planned? Yes❑ No ❑� 20. Attachments: Property Plat O BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch B Seabed Report B Drilling Fluid Program B 20 AAC 25.050 requirementsB 21. Verbal Approval: Commission Representative: Dale 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: 'en el hilCof .COM Authorized Title: Drilling Manager Contact Phone: 777-8395 {.� wwwT l' nn rEa'S $ /% %2019 Authorized Signature: Date: Commission Use Only Permit to Drill API Number:Permit Approval See cover letter for other Number: a " 4 50- — — 00_l _ Q Date: 11 requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed thane, gas hydrates, or gas contained in shales: Other: �P TSS. Samples req'd: Yes ❑ No[� r Mud log req'd: Yes E] NoL� coo PSL HzS measures: Yes ❑ NO[R' Directional svy req'd: Yes Ls No❑ Spacing exception req'd: Yes ❑ No[9/ Inclination -only svy req'd: Yes L] NorWr Post initial injection MIT req'd: Yes ❑ No❑ APPROVED BY 1 I Approved COMMISSIONER THE COMMISSION Dater 1 auomn roan ana � „�y11 jY, /2017 This permit is valid f/R24rrpr�tl�gn� drRe �pproval per 20 AAC �0,5(�gJ gnacnments in Du licate (IJV y'�a f1 ORTUT H �a�19 ��aaja/�v Hilcorp Alaska, LLC Milne Point Unit (MPU) M-22 Drilling Program Version 1 8/7/2019 Table of Contents 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summary.....................................................................................................8 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................9 9.0 R/U and Preparatory Work.........................................................................................................11 10.0 N/U 21-1/4" 2M Diverter System.................................................................................................12 11.0 Drill 12-1/4" Hole Section.............................................................................................................14 12.0 Run 9-5/8" Surface Casing...........................................................................................................17 13.0 Cement 9-5/8" Surface Casing.....................................................................................................22 14.0 BOP N/U and Test.........................................................................................................................27 15.0 Drill 8-1/2" Hole Section...............................................................................................................28 16.0 Run 6-5/8" Production Liner.......................................................................................................33 17.0 Liner Top Clean Out & Run Kill String.....................................................................................37 18.0 RDMO............................................................................................................................................37 19.0 Doyon 14 Diverter Schematic.......................................................................................................38 20.0 Doyon 14 BOP Schematic.............................................................................................................39 21.0 Wellhead Schematic......................................................................................................................40 22.0 Days Vs Depth...............................................................................................................................41 23.0 Formation Tops & Information...................................................................................................42 24.0 Anticipated Drilling Hazards.......................................................................................................43 25.0 Doyon 14 Layout............................................................................................................................46 26.0 FIT Procedure...............................................................................................................................47 27.0 Doyon 14 Choke Manifold Schematic.........................................................................................48 28.0 Casing Design................................................................................................................................49 29.0 8-1/2" Hole Section MASP............................................................................................................50 30.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................51 31.0 Surface Plat (As Built) (NAD 27).................................................................................................52 32.0 Schrader Bluff OA Sand Offset MW vs TVD Chart ..................................................................53 33.0 Drill Pipe Information 5" 19.5#1 5-135 DS -50 & NC50..............................................................54 n Hilcorp �C—pw" 1.0 Well Summary Milne Point Unit M-22 SB Producer Drilling Procedure Well MPU M-22 Pad Milne Point "M" Pad Planned Completion Type ESP Target Reservoir(s) Schrader Bluff OA Sand Planned Well TD, MD / TVD 14,269' MD / 3,900' TVD PBTD, MD / TVD 14,279' MD / 3,586' TVD Surface Location (Governmental) 241' FNL, 500' FEL, Sec 14, TON, R9E, UM, AK Surface Location (NAD 27) X= 533663.9, Y= 6027889.8 Top of Productive Horizon (Governmental) 719' FNL, 709' FEL, Sec 14, TON, R9E, UM, AK TPH Location (NAD 27) X= 533458 Y= 6027411 BHL (Governmental) 658' FSL, 1347' FEL, Sec 23, T13N, R9E, UM, AK BHL (NAD 27) X= 532869, Y=6018226 AFE Number 1913621 AFE Drilling Das 20 AFE Completion Das 4 AFE Drilling Amount $4,146,330 AFE Completion Amount $1,900,525 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1326 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1705 psig Work String 5" 19.5# S-135 & NC 50 KB Elevation above MSL: 33.7 ft + 25.0 ft = 58.7 ft GL Elevation above MSL: 25.0 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 H Hilcorp EvnW Compmy 2.0 Milne Point Unit M-22 SB Producer Drilling Procedure Management of Change Information H Hilcorp Alaska, LLC EWCo.o., Hi t Cr Changes to Approved Permit to Drift Date: 817/2019 Subject: Changes to Approved Permit to Drill for MPU M-22 File #: MPU M-22 Drilling and Completion Program Any modifications to MPU M-22 Drilling & Completion Program will be documented and approved below Changes to an approved APD will be approved in advance to the AOGCC4 Approval: Prepared: Page 3 Drilling Manager Date Drilling Engineer Date H Hilcorp 3.0 Tubular Program: Milne Point Unit M-22 SB Producer Drilling Procedure 4.0 Drill Pipe Information: All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 Dri l? Gr _7Hydn11563 Burst Collapse (psi)(k-lb Tensi ' i) Cond 20" 19.25" X-52 We 12-1/4" 9-5/8" 8.835" 8.679" 10.625" 40 L-805,750 3,090 916 Tieback 7" 6.276" 6.151" 7.656 26 L-807,240 5410 604 8-1/2" 6-5/8" Slotted 6.049 5.924 7.390 20 L-80 6,090 3,470 459 4.0 Drill Pipe Information: All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 H Hilcorp s W am,m, 5.0 Internal Reporting Requirements Milne Point Unit M-22 SB Producer Drilling Procedure 5.1 Fill out daily drilling report and cost report on WellEz. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@bilcom iengel@hilcorp.com and cdingerohilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting • Health and Safety: Notify EHS field coordinator. • Environmental: Drilling Environmental Coordinator • Notify Drilling Manager & Drilling Engineer on all incidents • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to mmyers@hilcorn com 'engel@hilcorp.com and cdin er .hilcorp.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mmyers@hilcorp.com jen eg�hilcorp.com and cdineer ct7i hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmversPhilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jenael@hilcorp.com Completion Engineer Taylor Wellman 907.777.8449 907.947.9533 twellman@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 caionesCaMilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdineer@hilcorp.com Page 5 Milne Point Unit M-22 SB Producer Hililcorrp Drilling Procedure 6.0 Planned Wellbore Schematic Well:MIPne Unit Well; PT Proposed SCHEMATIC Last Cor 110 111 PTo� nrw leiF .U91rl 9l -]19' TREE & WELLHEAD 'ree CBmeMn4 111W 5M IB¢ad FMC it"5MTC-fAw(]1'%4 TCdl Tap and8 Tubing 12-1/4"2nds14ge fon with 3"dW"M"BPV praBie-Tee 3/B' �Mrel line OPEN HOLE / CEM�7QT DETAIL Q.1 wbwjwvardsdumped down badsidej 12-L4"l .nR I L-6 5fL31T 456113 12-1/4"2nds14ge L-1937% -3UM 8-1/2" SI=e linerin &I/Y hale WG DETAIL ype rade/Conn I nID Tap TubBg Hangert&VV TOP &BDn} BPF (In5uI:1H11 5.5/x32/Wild WA 5tRF40 314' WA Su [e 40/L-!0(TIIP A -M- Swim S,fkl9' O.OTSB Ti@b k ZO/Ld0/Tzp C01" Surface 4,900 0.0383 Owd1 H 20/480/t�Qp�50 5924" 4.900' 14,2]0 0.0355 TUBING DETAIL Tubft X I 9.3/L-0 /EUEMD 2992" Surface 12,BW 00086 WELL INCLINATION DETAIL OP 0 550 sale =17 @ lex Pump - =21 Fi01e Angle = d+ xN prcBle Mex Ie AngleeATubirauii Mix le angle= JEWELRYDETAIL item ID upprCorrpinian TubBg Hangert&VV TOP &BDn} 3.92fF' CP n BDT SLZ1R user Tap x r E �psT %35e 8.1 T [ Aay. 6.25 Do 8.151 T Mt.QLBSW L-80x53/B" 563 L-Wz0 5.926' WIV (Ball On Seal) LINER DETAIL --........ _........ TD=1a,X`(M0/TD=3,5UITv j PBID:14,243 jME$/7D=3-WVM Page 6 GENERAL WELL INFO API: ISO I lied and Campleted bV Dayan U -Funs H Hilcorp Uma u Orig 183 Elev.: SRS;l GLElw..: 249 A 11"d VA— 96H is I Cameron 4316SM Wellhead FMCil"SMTC-S W/11'x41/2"IGITopar45ott=Tobing Manila with 3" d "M' WV pm61e. 2aa 316' Npr=ml line:. Cmvm •�_ ? L-U/T-M 311r < Condu=(Insulated) 235.5(%-52/Weld WA S"Ria L NIA 3516" Surface 40/L-BOJT%P &679" Surras 5,049' ams 7" Tieback 2rV L-PA/TXP 6.131" Surface 4,900' 0.0383 i Slotted Liner 20/L-1110/tIli j)563 5.92A" I i 34,270' 0.0355 3.6i3 9 =5. 4.5 WIZG 3.058 L Ixrwer C.Ompletxin 104,- 6OTSLZXP Liner Top Patern BO Ips? x3518 i IS 4,915' i Any.(8.25 OD No 110) x 12 "s T ,h,1563 L-80 z 63 n 563 L -BO %O 5.924' ) 14,265 c L 7 A 2JStl' 4 SU2" -�- 111111 TD=34270 Nq/TD=3.5? VVD) MrD=34269 (NO}/TD=3,WfM) Milne Point Unit M-22 SB Producer Drilling Procedure Milne Milne Point Unit VCell: MPU M-2.2 Proposed SCHEMATIC La5t Completed: Future PTD: TBD TREE & WELLHEAD Tea I Cameron 4316SM Wellhead FMCil"SMTC-S W/11'x41/2"IGITopar45ott=Tobing Manila with 3" d "M' WV pm61e. 2aa 316' Npr=ml line:. OPEN HOLE / CEMENT DETAIL 42" SO O&110yards dumped down backsides 12-1/4`=stage L—WT-3 12-1/4'2M Rage L-U/T-M 311r S=_KtGkk5lctted Liner in 8-1/2- hole CASING DETAIL Size Type yXGMde/Conn Drift ID I Top $TOS 8PF 20'X34'' Condu=(Insulated) 235.5(%-52/Weld WA S"Ria 114' NIA 3516" Surface 40/L-BOJT%P &679" Surras 5,049' ams 7" Tieback 2rV L-PA/TXP 6.131" Surface 4,900' 0.0383 6-5/8" Slotted Liner 20/L-1110/tIli j)563 5.92A" I 4,900 34,270' 0.0355 TUBING DETAIL 4-1/2" Tubing 12.61 L-80/TXP 13.956" 1 SurrarE S,Ofid O.QO67 WELL INCLINATION DETAIL KOP S 3W Max tole Angle= i let pump Max We Angle: 9 XN pr46k Max Noleaingle= Tubing ail Max Hole mgle= JEWELRY DETAIL W. I Top MD nem Drift ID (MD) (TVD) Upper Complepan TVD {TVD} 1 29' TuLfrg hanger I&I/2'' TC41 Top &Bbn) 3070" 3 _'4,709' 4.5" Dis.ha.Te Pressure Gi Lge Mandrel (Oischa%e GaLV) 3-874" 4 -A,7 &5=SlidinjlSleffve 3.813' 5 ±4, 4.5 wile Man rew Mre IMke Gauge 3.869 6 14,747 4.5"%Nipple 13.913"Packing B"el 3.613" .4,77 x4.5 PhLRa6nevb eN 3. B .4,]9 4S XN NippleRNOP set 3.6i3 9 =5. 4.5 WIZG 3.058 Ixrwer C.Ompletxin 104,- 6OTSLZXP Liner Top Patern BO Ips? x3518 IS 4,915' i Any.(8.25 OD No 110) 6.151 12 493 T ,h,1563 L-80 z 63 n 563 L -BO %O 5.924' 13 14,265 WIV jeall On seat) G s/p r .n t�LID LINER DETAIL Tap ToP {LtQ (MD) (TVD) {MD} TVD {TVD} TBD GENERAL WELL INFO API: T80 Drilled and completed by argon 14 -Furore rr G 6 ,4.�Slotted LINER DETAIL MD Top (TVD) @= (MD) 6=1 L) TBD -_.sed 5•:'. ii D29r'_i 19 ug., r H Hilcorp F .By c�mv.oy 7.0 Drilling / Completion Summary Milne Point Unit M-22 SB Producer Drilling Procedure MPU M-22 is a grassroots ESP producer planned to be drilled in the Schrader Bluff OA sand. M-22 is part of a multi well program targeting the Schrader Bluff sand on M -Pad. The directional plan is a catenary well path build, 12.25" hole with 9-5/8" surface casing set into the top of the Schrader Bluff OA sand. An 8.5" lateral section will then be drilled. A 6-5/8" slotted liner will be run in the open hole section and the well produced with an ESP assembly. The M-22 directional plan has the surface hole crossing the unity boundary to the north, in to KRU, and then /returning to MPU before landing in the target zone. M-22 will not be producing hydorcarbons from KRU 'I and no pay zone will be open with 500 feet of the MPU boundary, in compliance with AOGCC regulations. A wellbore easement application has been approved. The Doyon 14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately August 18, 2019, pending rig schedule. Surface casing will be run to 5,048 MD / 3,900' TVD and cemented to surface via a 2 sta Lpnmary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to sur acf e are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point `B" pad G&I facility. General sequence of operations: 1. MIRU Doyon 14 to well site 2. N/U & Test 21-1/4" Diverter and 16" diverter line 3. Drill 12-1/4" hole to TD of surface hole section. Run and cement 9-5/8" surface casing 4. N/D diverter, N/U & test 13-5/8" x 5M BOP 5. Drill 8-1/2" lateral to well TD. Run 6-5/8" production liner 6. Clean Liner Top 7. $ —5 -3tring 6, J;SP Sur 8. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) Page 8 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply 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 M-22. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day 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". o Ensure the diverter vent line is at least 75' away from potential ignition sources • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: No variances are requested at this time. See note in Section 7 regarding wellbore easement application. Page 9 Milne Point unit M-22 SB Producer Hilcorp Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply 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 M-22. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day 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". o Ensure the diverter vent line is at least 75' away from potential ignition sources • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: No variances are requested at this time. See note in Section 7 regarding wellbore easement application. Page 9 n Hilcorp Summary of BOP Equipment & Notifications Milne Point Unit M-22 SB Producer Drilling Procedure Hole Section Equipment Test Pressure(psi) 12 1/4" • 21-1/4" 2M Diverter w/ 16" Diverter Line Function Test Only • 13-5/8" x 5M Hydril "GK" Annular BOP 304)0 • 13-5/8" x 5M Hydril MPL Double Gate Initial Test: 250 0 Blind ram in btm cavity • Mud cross w/ 3" x 5M side outlets 8-1/2" • 13-5/8" x 5M Hydril MPL Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/AOr • 3-1/8" x 5M Choke manifold 30c"D • Stand i e, floor valves, etc Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event (BOPs utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.reggna alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz(a alaska. ov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: htto://doa.alaska.gov/ogc/forms/TestWitnessNotifhtml Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 9.0 R/U and Preparatory Work Milne Point Unit M-22 SB Producer Drilling Procedure 9.1 M-22 will utilize a newly set 20" conductor on M -Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4" nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and RAJ. 9.6 Rig mat footprint of rig. 9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4" surface hole section. Ensure mud temperatures are cool (<800F). 9.10 Ensure 6" liners in mud pumps. • Continental EMSCO FB -1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. Page 11 H Hilcorp E.,� Compmy 10.0 N/U 21-1/4" 2M Diverter System Milne Point Unit M-22 SB Producer Drilling Procedure 10.1 NIU 21-1/4" Hydril MSP 2M Diverter System (Diverter Schematic attached to program). • NIU 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead. • N/U 21-1/4" diverter "T". • Knife gate, 16" diverter line. • Ensure diverter RAJ complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ienition source • Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking • A prohibition on ignition sources or running equipment • A prohibition on staged equipment or materials • Restriction of traffic to essential foot or vehicle traffic only. Page 12 10.4 Rig & Diverter Orientation: r May change on location i M_11 M-13 ■ i M-12 I M-14 0 M-26 ■ M-15 1 M-21 4- E17 M-22 ♦ r 75' Radius Clear of Ignition Sources MPU M -Pad Page 13 Diverter Line Drawing Not To Scale Diverter Line May Be Oriented Different On Location Milne Point unit M-22 SB Producer Hilcorp Enmp'C®p�uy Drilling Procedure 10.4 Rig & Diverter Orientation: r May change on location i M_11 M-13 ■ i M-12 I M-14 0 M-26 ■ M-15 1 M-21 4- E17 M-22 ♦ r 75' Radius Clear of Ignition Sources MPU M -Pad Page 13 Diverter Line Drawing Not To Scale Diverter Line May Be Oriented Different On Location H Hilcorp EncgyCompavy 11.0 Drill 12-1/4" Hole Section Milne Point Unit M-22 SB Producer Drilling Procedure 11.1 P/U 12-1/4" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside 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 for wireline gyro • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.54 5-135. • Run a solid float in the surface hole section. 11.2 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4" hole section to section TD, in the Schrader OA sand. Confine 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. • Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. • Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen • Slow in/out of slips and while tripping to keep swab and surge pressures low • Ensure shakers are functioning properly. Check for holes in screens on connections. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. • Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). f • Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. Page 14 n Hilcorp en<� comv.�y Milne Point Unit M-22 SB Producer Drilling Procedure • Gas hydrates have not been seen on M -Pad. However, be prepared for them. In MPU they have been encountered typically around 2100-2400' TVD (just below permafrost). Be prepared for hydrates: • Gas hydrates can be identified by the gas detector and a decrease in MW or ECD • Monitor returns for hydrates, checking pressurized & non -pressurized scales • 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 Lecithin to allow the gas to break out. • Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. 11.4 12-1/4" hole mud program summary • Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW ( g) Surface — Base Permafrost 8.9+ Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells) MW can be cut once —500' below hydrate zone • PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high -clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 — 9.0 range with caustic soda. Daily additions of ALDACIDE G / X- CIDE 207 MUST be made to control bacterial action. • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Page 15 H Hilcorp Encs Com, Milne Point Unit M-22 SB Producer Drilling Procedure Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type: 8.8 — 9.2 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties. Section DensltV Viscosity Plastic Viscosity Yield Point AN FL I pH Tem Surface 8.8-9.8 75-175 20-40 25-45 <10 1 8.5 0.08 System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or M liquids) M -I Gel 50 lb sx 25 Soda Ash 50 Ib sx 0.25 Pol Pac Supreme LTL. 50 Ib sx 0.08 Caustic Soda 50 Ib sx 0.1 SCREENCLEEN 55 gal dm 1 0.5 11.5 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.6 RIH t/ bottom, proceed to BROOH t/ HWDP • Pump at full drill rate (400-600 gpm), and maximize rotation. • Pull slowly, 5 —10 ft / minute, adjust as dictated by hole conditions • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 16 H Hilcorp Enu Co T 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull wearbushing. Milne Point Unit M-22 SB Producer Drilling Procedure 12.2 R/U Weatherford 9-5/8" casing running equipment (CRT & Tongs) • Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking 120' shoe track assembly consisting of: 9-5/8" Float Shoe 1 joint — 9-5/8" TXP, 2 Centralizers 10' from each end w/ stop rings I joint — 9-5/8" TXP, I Centralizer mid joint w/ stop ring 9-5/8" Float Collar w/ Stage Cementer Bypass Baffle 'Top Hat' 1 joint — 9-5/8" TXP, 1 Centralizer mid joint with stop ring 9-5/8" HES Baffle Adaptor • Ensure bypass baffle is correctly installed on top of float collar. This end up. Bypass Baffle • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 17 12.5 Float equipment and Stage tool equipment drawings: Type H ES Cementer Part No. SO Na. Closing Sleeve No. Shear Pins Opening Sleeve No. Shear Pins ES Cementer Depth Baffle Adapter (if used) ID Depth Y - Bypass or ShuFOR Baffle ID Depth Float Collar Depth Float Shoe Depth Hole TD _... "Reference Casing Sales Manual Section 5 Page 18 »A Overall Length B Men. ID After Orilloul C Me.. Toal OD D Opemaug Seat ID E Closimg Seat 1D Plug Set Part No. . Closing Plug b— OD Owning Plug OD OD Shut-off Plug OD Bypass Plug (H used) OD Milne Point Unit M-22 SB Producer Drilling Procedure Ilikmp ES41 Running ONer Eill Cemenew : shut Off Plug Baffle Adapter By Pass Rug 7 I By Pass Baffle Float Collar Float shoe H Hilcorp � W �,, Milne Point Unit M-22 SB Producer Drilling Procedure 12.6 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: • 1 centralizer every ioint t/ — 1000' MD from shoe • 1 centralizer every 2 joints to 2,000' above shoe (Top of Ugnu) • Verify depth of lowest Ugnu water sand for isolation with Geologist • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.7 Install the Halliburton Type H EStage tool so that it is positioned at least 100' TVD below the permafrost (— 2,500' MD). (Halliburton ESIPC with packer element may be used). • Install centra rzT ers over couplings on 5 joints below and 5 joints above stage tool. • Do not place tongs on ES cementer, this can cause damaged to the tool. • Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. • ESIPC: Ensure tool is pinned properly. ESIPC packer to inflate at — 2080 psi, and the tool to open at — 3000 psi. Reference ESIPC Procedure. 9-5/8" 40# L-80 TXP Make Up Torques: Casing OD Minimum Optimum Maximum 9-5/8" 18,860 ft -lbs 20,960 ft -lbs 23,060 ft -lbs Page 19 l H HilmE, Milne Point Unit M-22 SB Producer Drilling Procedure TXPCR) BTG Threads per's 5 conneo6pn OD Doon REGULAR d,,,lvoarzola Outside Diameter 9.625ia Min. 6Ya11 87.545 Dna Plain End b`kight 8.679 38.971bYt 916.000x1000 tntemai Pressure Capacity l' i Thickness I-)GniLED Its compression ErTni iii 10'.ro cnmpressian svength Type Ii Allolwble Bending 38 `1100 ft Wali Thickness 0395+n. Connection OD REGULAR OpePn COUPLING PIPE BODY Edi Red lst Sant Red I Grade L80 Type 1' Drift API 9tantlard IV Bard: Groves 2nd Lard: 2nd Bard: - Brown Type Casing 3m Band: - 3rd Sand: - 40r Band: - GEOMETRY Threads per's 5 conneo6pn OD Doon REGULAR PERFORMANCE r inai OD Nominal ID 9.625 in. 9835 in. Nominal P'kight WaliTMOmim 40 Ii 0.395m Dna Plain End b`kight 8.679 38.971bYt OD Toerance API PERFORMANCE Body Yiex Sne.,,Irih 916 x1000 the haemal Vitr! 57501 ShIYs 80000 psi Copme 3090 psi GEOMETRY I ccsnei 00 10.68 in. Cn phi Lei 10.825 m eenneedon 10 8,823 in. Ma e -up Loss 0.891 in. Threads per's 5 conneo6pn OD Doon REGULAR PERFORMANCE TeEsion Effpienep 100.0% -mtYr'1 stresgdl 916.000x1000 tntemai Pressure Capacity l' i 5750.000 psi Its compression ErTni iii 10'.ro cnmpressian svength 916.000 x1000 Ii Allolwble Bending 38 `1100 ft Cs Eremal F -ssme Capacity 3090.000 Ps MAKE-UPTORQUES Mmimum 18960it-2e Optimum 20950 hi Ma num 23060 Oabs OPERATION LIMB TORQUES Operarmg Tan{ve 356001t4bs Yield Torque 43400 hits Notes This connection is fully interchangeable with: TXPO BTC - 9.625 in - 361 43.5147153.5158.4 IbsrYt [t] Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API 5C31130 10400 - 2007. Datasheet is also valid for Special Bevel option when applicable - except for Coupling Face Load, which will be reduced. Please contact a local Tenans technical sales representative. Page 20 H Hilcorp E,cw Compmy Milne Point Unit M-22 SB Producer Drilling Procedure 12.8 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10' from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 21 N Hilcorp EMagy Company 13.0 Cement 9-5/8" Surface Casing Milne Point Unit M-22 SB Producer Drilling Procedure 13.1 Hold a pre job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. • How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pumps will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) — HEC rep to witness. Mix and pump cement per below calculations for the 1" stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated 111 Stage Total Cement Volume: 8131LI, Page 22 t•t� s F Section Calculation Vol (bbl) Vol (ft3) 12-1/4" OH x 9-5/8" t 9 v (4,048'- 2500') x .0558 bpf x 1.3 = 112.3 630.5 J Casing Total Lead 112.3 630.5 12-1/4" OH x 9-5/8" (5,048' - 4,048') x .0558 bpf x 1.3 = 72.5 407 Casing ~ 9-5/8" Shoe Track 120'x .0758 bpf = 9.1 51.09 Total Tail 81.6 458 Page 22 t•t� s F H Hileor .... urp Milne Point Unit M-22 SB Producer Drilling Procedure Cement Slurry Design (1St Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: ✓ 4,928' x .0758 bpf = 373.5 bbls 80 bbls of tuned spacer to be left behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, t4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confine float< are holding. If floats do not hold, pressure up string to final circulating pressure and hold until Page 23 Lead Slurry Tail Slurry System EXtendaCEM TM System SwiftCEM `M System Density 11.7 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed Water 21.13 gal/sk 5.04 gal/sk 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: ✓ 4,928' x .0758 bpf = 373.5 bbls 80 bbls of tuned spacer to be left behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, t4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confine float< are holding. If floats do not hold, pressure up string to final circulating pressure and hold until Page 23 n Hilcorp Milne Point Unit M-22 SB Producer Drilling Procedure cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 24 H Hilcorp Second Stage Surface Cement Job: Milne Point Unit M-22 SB Producer Drilling Procedure 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre job safety meeting. • Past wells have seen pressure increase while circulating through stage tool after reduced rate 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2"d stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2"d Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): Section Calculation Vol (bbl) Vol (ft3) v 20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1= 28.6 161 J 12-1/4" OH x 9-5/8" Casing (2000'- 110') x .0558 bpf x 3 = 316.4 1776.3 Total Lead 345 1937 12-1/4" OH x 9-518" Casing (2500'- 2000') x .0558 bpf x 2 = 55.8 314 ~ Total Tail 55.8 314 Cement Slurry Design (2nd stage cement job): Page 25 Lead Slurry Tail Slurry System Permafrost L SwiftCEM •" System (Hal Cem) Density 10.7 lb/gal 15.8 lb/gal Yield 4.3279 ft3/sk 1.16 ft3/sk Mixed Water 21.405 gal/sk 5.08 gal/sk Page 25 n Hilcorp Milne Point Unit M-22 SB Producer Drilling Procedure 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 2500' x .0758 bpf = 190 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1000 —1500 psi to ensure stage tool closes Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8" final joint. L/D cut joint. Make final cut on 9-5/8". Dress off stump. Install 9-5/8" wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns duringjob, 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 iengelkhilcorp.com and cdinger@hilcorp. com This will be included with the EOW documentation that goes to the AOGCC Page 26 14.0 BOP N/U and Test 14.1 N/D the diverter T, knife gate, diverter line & N/U 11" x 13-5/8" 5M casing spool. 14.2 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" x 5M single gate • Double gate ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in bottom cavity. • Single ram can be dressed with 2-7/8" x 5" VBRs • N/U bell nipple, install flowline. • Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 RU MPD RCD and related equipment 14.4 Run 5" BOP test plug 14.5 Test BOP to 250/30' 00 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Test 5" test joints / • Confirm test pressures with PTD T6 ej • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.6 R/D BOP test equipment 14.7 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.8 Mix 8.9 ppg F1oPro fluid for production hole. 14.9 Set wearbushing in wellhead. 14.10 If needed, rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.11 Ensure 6" liners in mud pumps. J Page 27 Milne Point unit M-22 SB Producer H Hilco Drilling Procedure 14.0 BOP N/U and Test 14.1 N/D the diverter T, knife gate, diverter line & N/U 11" x 13-5/8" 5M casing spool. 14.2 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" x 5M single gate • Double gate ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in bottom cavity. • Single ram can be dressed with 2-7/8" x 5" VBRs • N/U bell nipple, install flowline. • Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 RU MPD RCD and related equipment 14.4 Run 5" BOP test plug 14.5 Test BOP to 250/30' 00 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Test 5" test joints / • Confirm test pressures with PTD T6 ej • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.6 R/D BOP test equipment 14.7 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.8 Mix 8.9 ppg F1oPro fluid for production hole. 14.9 Set wearbushing in wellhead. 14.10 If needed, rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.11 Ensure 6" liners in mud pumps. J Page 27 n Hilcorp E—gy c�mm�y 15.0 Drill 8-1/2" Hole Section 15.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.220 PDM) Milne Point Unit M-22 SB Producer Drilling Procedure 15.2 TIH w/ 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool or ESIPC. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every '/4 bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = —2875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry G5� Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20' of new formation. 15.6 CBU and condition mud for FIT. 115.7 Conduct FIT to 12.0 ppg EM_W. Chart Test. Ensure test is recorded on same chart as FIT. mental vo Document increlume pumped (and subsequent pressure) and volume returned. 15.8 POOH & LD Cleanout BHA 15.9 PIU 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# 5-135 DS50 & NC50. • Run a ported float in the production hole section. 15.10 8-1/2" hole section mud program summary: • Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Use appropriate SAFECARB blend on this well Page 28 H Hilcorp Milne Point Unit M-22 SB Producer Drilling Procedure • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Keep viscosifier additions to an absolute minimum (N -VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleanine • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 8.9 — 9.5 ppg FloPro drilling fluid Pro erties: Interval en's PV I YP LSYP Total Solids I MBT I HPHT Hardness Production 8.9-9.5 1 15-25 - ALAP 1 15-30 4-6 1 <10% 1 <8 1 <11.0 I <too System Formulation: Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 Ib sx 6 CONQOR 404 WH (8.5 gal/ 100 bbls) 55 gal dm 0.2 FLO-VIS PLUS 25 lb sx 0.7 KCI 50 lb sx 10.7 SMB 50 Ib sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify) 50 lb sx 10 SAFE-CARB 20 (verify) 50 Ib sx 10 Soda Ash 50 1b sx 0.5 Page 29 K Hilcorp 15.11 T1H with 8-1/2" directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Flo Pro drilling fluid Milne Point Unit M-22 SB Producer Drilling Procedure 15.13 Begin drilling 8.5" hole section, on -bottom staging technique: • Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. • Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations • If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. If stick slip continues, consider adding .5% lubes 15.14 Drill 8-1/2" hole section to section TD per Geologist and Drilling Engineer. • Flow Rate: 350-550 gpm, target min. AV's 200 ft/min, 385 gpm • RPM: 120+ • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low • Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection • Monitor Torque and Drag with pumps on every 5 stands • Monitor ECD, pump pressure & hookload trends for hole cleaning indication • Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. • Use ADR to stay in section. Reservoir plan is to undulate between Schrader OAl & OA3 lobes in 1000-1500' MD increments, and keeping DLS <3° when moving between lobes • Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. • Target ROP is as fast as we can clean the hole without having to backream connections • Schrader Bluff OA Concretions: 5-10% of lateral • L-47: 6%, L-50 9.5% • F-106: 6.1%, F-107: 4.7%,F-018: 9.9%, F-109: 10%, F-110: 10.1% • Offset injection and abnormal pressure has been seen on M-10, -11, -12. MPD will be utilized to monitor pressure build up on connections. • Close Approaches: • There are no close approaches on M-20 15.15 Reference: Open hole sidetracking practice: • If a known fault is coming up, put a slight "kick-off ramp" in wellbore ahead of the fault so we have a nice place to low side. • Attempt to lowside in a fast drilling interval where the wellbore is headed up. • Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for avorox. 30 min. Page 30 H Hilcorp Milne Point Unit M-22 SB Producer Drilling Procedure Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump tandem sweeps if needed • Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary • If seepage losses are seen while drilling, consider reducing MW at TD to 9.Oppg minimum 15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. 15.18 Displace 1.5 OH + Liner volume with viscosified brine. Proposed brine blend (same as used on M-16, aiming for an 8 on the 6rpm reading) - KCl: 7.1bbp for 2% NaCl: 60.9ppg for 9.4ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42ppb Flo -Vis Plus: 1.25ppb • Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 15.19 BROOH with the drilling assembly to the 9-5/8" casing shoe • Circulate at full drill rate (less if losses are seen, 350 gpm min). • Rotate at maximum rpm that can be sustained. Pulling speed 5 — 10 min/std (slip to slip time, not including connections), adjust as dictated by hole conditions If backreaming operations are commenced, continue backreaming to the shoe 15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 15.21 CBU minimum two times at 9-5/8" shoe and clean casing with high vis sweeps. Page 31 Milne Point Unit M-22 SB Producer Drilling Procedure 15.22 Monitor well for flow / monitor for pressure build up with MPD. Increase fluid weight if necessary Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise 15.23 POOH and LD BHA. 15.24 Continue to POH and stand back BHA if possible. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 32 H Hilcorp 16.0 Run 6-5/8" Production Liner Milne Point Unit M-22 SB Producer Drilling Procedure 16.1. Well control preparedness: In the event of an influx of formation fluids while running the 6- 5/8" pre drilled liner, the following well control response procedure will be followed: • P/U & M/U the 5" safety joint (with 6-5/8" crossover installed on bottom, TIW valve in open position on top, 6-5/8" handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 6-5/8" Predrilled liner. • Slack off and with 5" DP across the BOP, shut in ram or annular on 5" DP. Close TIW. • Proceed with well kill operations. 16.2. R/U 6-5/8" liner running equipment. • Ensure 6-5/8" 20# Hydril 563 x DS -50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 16.3. Run 6-5/8" slotted production liner • Use API Modified or "Best O Life 2000 AG" thread compound. Dope pin end only w/ paint brush. Wipe off excess. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Run round nose float shoe on bottom. • 6-5/8" slotted liner will auto —fill • 6-5/8" Liner will be centralized with 1/joint free floating • If needed, install swell packers as per the lower completion tally. • Remove protective packaging on swell packers just prior to picking up • Do not place tongs or slips on the packer element 6-5/8" 20 # Hydril 563 Torque OD Minimum Optimum Maximum Yield Tor ue 6-5/8 5,900 ft -lbs 7,100 ft -lbs 10,300 ft -lbs 36,000 ft -lbs Page 33 Milne Point Unit M-22 SB Producer Drilling Procedure Wedge 563rR1 n a. 11*W2018 - OWsa64 Diamnn 8.BY5 �. Min. WSII 87.5-: _ u,,, cc_.. 7.a99,: cPaP1�t; _Onglc s.zs.�. cpnpeu..am ThIa.. AMsic-uP Lo::. I'I GNhI LOD spro 329 C.M,p.m DD IXna1 FEfiatAR j PERFORMANCE TypeI 4 Wall ThICLnCa!i 0.788 n. Connection O6 BLGD:AR 439E63,bYvJ V1.n Prc-.xom GaPac43 6964900 Ps D9uien ILs COWDHa PIPEe0el' LCmprss:an E»crn��r 10A9'?. Zampnssian sVervyh 459.640.10Y 1Aas. A"c ba ewrvarr) 61. i llod 151 L4v1d Red Orale LAO Type 1- Drift API Standard IV. Dvm , Brown 2rd Daut 3suploy Xaca Load 31643A 9:c $r1 Dai¢ . B.. TYPO Casing i,d DanC $d Anr , - ,_, ,:nurci 59N tws DEamum ?IN #ms 40 pard. 19366 hAAs OPERATION LIMIT TORQUES l Cm,.,,q T..a 31W4 R, IC2 `fl.o Tttpuc 36W4»4DS GEOMETRY RUCK -ON �= 9.f I5 Vsminst V(ngM 30.N't"11 DO 5.9L:n +la:mnal Kr C 04 a:. 'will TM1CAnesx 0.16 m. F1am End wn:ya 1931;N:m F.= Tdlmowr.• MI PERFORMANCE _ . I „om9 4sECC 1„ r1u..v rme 699m.. 11s ea9Nv Notes This connection is fully interchangeable with.: Wedge 563s� - 6.625 in. - 24128,'32 Ib9fa Conlnectims with Lopeless2M Technology are fully compatible with the same connection in its Standard version Page 34 GEOMETRY _ u,,, cc_.. 7.a99,: cPaP1�t; _Onglc s.zs.�. cpnpeu..am s599:r: AMsic-uP Lo::. 4.O%.i,. TCrutls W In 329 C.M,p.m DD IXna1 FEfiatAR j PERFORMANCE In ,hn ElD.c-r 93.7 Fcld 51,v M 439E63,bYvJ V1.n Prc-.xom GaPac43 6964900 Ps ILs LCmprss:an E»crn��r 10A9'?. Zampnssian sVervyh 459.640.10Y 1Aas. A"c ba ewrvarr) 93.6'!144» mn :Gxmal P,m�wc Cay , 3470.@00 pe 3suploy Xaca Load 31643A 9:c MAKE-UP TORQUES ,_, ,:nurci 59N tws DEamum ?IN #ms ataumum 19366 hAAs OPERATION LIMIT TORQUES l Cm,.,,q T..a 31W4 R, IC2 `fl.o Tttpuc 36W4»4DS RUCK -ON ib•.rnmn SOON »Jts Naumw_ 11300 a t/. Notes This connection is fully interchangeable with.: Wedge 563s� - 6.625 in. - 24128,'32 Ib9fa Conlnectims with Lopeless2M Technology are fully compatible with the same connection in its Standard version Page 34 Milne Point Unit M-22 SB Producer Drilling Procedure 16.6. Ensure to run enough liner to provide for approx 150' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. • AOGCC regulations require a minimum 100' overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8" connection. • Consider having a joint of solid pipe across BOPE Stack while running inner string 16.7. Before picking up Baker SLZXP liner hanger/ packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.8. M/U Baker SLZXP liner top packer to inner string and 6-5/8" liner. 16.9. Note PUW, SOW, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.10. RIH w/ liner on 5" HWDP no faster than 30 ft/min —this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. • Ensure 5" HWDP has been drifted • There is no inner string planned to be run, as opposed to previous wells. The DP should auto fill. Monitor FL and if filling is required due to losses/surging. 16.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 rpm 16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.15. Rig up to pump down the work string with the rig pumps. 16.16. Break circulation. Begin circulating at —1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker. Page 35 n Hilcorp ..Wm Milne Point Unit M-22 SB Producer Drilling Procedure 16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.18. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool and not at the WIV) down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 16.19. Continue pressuring up to 2700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the ZXP liner hanger to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4500 psi to release the HRDE running tool. 16.20. Bleed DP pressure to zero. Pick up to expose Rotating Dog Sub and set down 50k# without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 rpm and set down 50k4 again, 16.21. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.23. PIU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 16.24. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. 16.25. M/U 3.5" wash tool & RIH w/ remaining DP out of derrick to liner top. 16.26. Wash through liner top at max rate & circulate hole clean. Pump sweeps around. Displace well to clean filtered brine after no solids are returned. 16.27. POOH & L/D remaining 5" HWDP & Inner string 16.28. Once inner string is L/D swan to the completion AFE Page 36 H ' Hilcorp F RY Camp.ny 17.0 Liner T 17.1 RIH w/ 3.5" 17.2 WU casing r 17.3 RIH w/ 3.5" Milne Point Unit M-22 SB Producer Drilling Procedure an Out &/can Kill String pe on 5" dp tout liner top. POOH LDDP. equipment. to —2,_00' TVD 17.4 Land tubing hanger. 17.5 RILDS and test hanger LI 17.6 Install BPV. N/D B P. 17.7 N/U tree / adapt and tree. 17.8 Freeze protect ell. landing joint. tubing hanger void to 500 psi low / 5000 psi high. 17.9 Set BPV d . Test tree to 250 psi low / 5000 psi high. Pull BPV dart and BPV 18.0 RDMO 18.1 RDMO Doyon 14 18.2 ASR will run completion once D14 has moved offA8X'operations to be submitted on a separate Sundry 7 r' zl�-1 S Page 37 w 19.0 Doyon 14 Diverter Schematic 21-N4' 2M Roe — 214 N' 2M - 0"e T 21-U4' 2N Spier Spm l6.W4' 7M . 21-1u4' 21A DSA Page 38 —16' i.e OpMng KnAe VN" 15' DnMer ben¢ Milne Point unit M-22 SB Producer Hilcorp rn.� Cmnp.ny Drilling Procedure 19.0 Doyon 14 Diverter Schematic 21-N4' 2M Roe — 214 N' 2M - 0"e T 21-U4' 2N Spier Spm l6.W4' 7M . 21-1u4' 21A DSA Page 38 —16' i.e OpMng KnAe VN" 15' DnMer ben¢ H HilcoT EIww Comgny 20.0 Doyon 14 BOP Schematic K.H One Page 39 Milne Point Unit M-22 SB Producer Drilling Procedure 2-7/8" x 5" VBR Blind Rams x 5M HCR 'hoke lute )I Gate Vatve 2-7/8" x 5" VBR H Hilcoip EmW �v m 21.0 Wellhead Schematic 1 1 i Milne Point Unit M-22 SB Producer Drilling Procedure Page 40 i L: 3_s v I 16 i. Page 40 H Hilcorp 22.0 Days Vs Depth I urun 4000 w 6000 J N y 10000 0 Page 41 14000 16000 Milne Point Unit M-22 SB Producer Drilling Procedure MPU M-22 5B OA Producer Days vs Depth 0 5 10 15 20 25 Days n Hilcorp ewwcaspay 23.0 Formation Tops & Information Milne Point Unit M-22 SB Producer Drilling Procedure MPU M-22 Formations (Wp05) MD (ft) TVDss (ft) TVD (ft) Formation Pressure (psi) EMW (ppg) Base Permafrost 2014 -1803 1861 818.84 8.46 LA3 3441 -3143 3201 1408.44 8.46 Schrader Bluff NA 4125 -3645 3703 1629.32 8.46 Schrader Bluff OA 4750 -3816 3874 1704.56 8.46 L -Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad) GENERALIZED GEOLOGICAL _— __---- FARE AST SS GEOLOGICAL TVD FM UTH DESCRIPTION COMMENTS upw NOTE: Soo Individual Well Program for ♦a:aw GWtk s w.M. casing design, depths, sixes, tx weights. grades and connections. o ' coarse to modarm sasandabmve small ¢lel Uncoelor ¢ .led .SN Mnw ltbtono. 1,000' - - IF SIGNIFICANT AMOUNTS OF GRAVEL ARE ENCOUNTERED WHEN DRILLING THE -411fileal SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE nso Base permafrost EFFECTIVE HOLE CLEANING. 2.000 hbrbodaof sand.cloysand se r.Ilnoocaslonal Now coal. Watch coWatch pmb sibaidetracackirp wNle id wasNnyramronp W 3 8 L-15. saga. mss, -oltm No hydrates encountered on L -Pad wells drilled to date. COMlnwd Irdmheds of aartl. cloys and Yasbnei with occasbr.l shows of cele. Tncas of pyrib al •/ 3100 tt 0.000• L can be se nwn,alal•34M t1 ckyand light (1,41) Gay h1arbods bebveon 3000 and 4500 It C 3412- L A 36s7- lean. y ttiaNLl: Serlee ofcmrsonlrg upward sands wnicnare lAscot 1 made up a. (hom top b babm) mane said, fine sand. slnyshale eeeor dovoivpod imorvmir�g shales as you UGNU progress Into the Land M(dmper). ugrw and Schrader&ab Pmsiblo IV& ocarbons liMlod t- 0* bsW comer of Milne development Northernareais (AS) dowmhucture and wol. '31H' LLsan. 1-a�Ci '4000' Ira) Schrader Bluff Sands: 4,000 N� ,a IAO.C.p. cem'—dis3eringcoananhgupwardsandsaaUovs -Ilfm Schrader Bluff: Possible lost circulation F.n eacepl.- Corderlaed am with OCCdalglj coal. Oat, rich ehab lmorval u00 10 4600 It zone while drilling long strings and running -4170 0. n. Ugmr and schramr Blurt Poeslda Mnocarbom Lmaed casing. Recommend deep setting surface ION (AMC. WSW..., of MD. avvelolaront LJ7 and L. aro casing for Kuparuk long strings. Also, the Schrader mmploted In the Schradermal sand. Nodhem areas Schrader Bluff sands area potential L.Padledewn.thxlumaW.1. p° differential stuck pipe interval if left un -cased Bluff `+ Sufiwe Gsirlg Point h'Pala bob. for Kuparuk long strings. Sands: Srhnder Blot oBsard ler longer reach.oib. Page 42 24.0 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 Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non -pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb Lecithin 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 no known wells in immediate proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. 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 between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 43 Milne Point Unit M-22 SB Producer Hilcorp Drilling Procedure 24.0 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 Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non -pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb Lecithin 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 no known wells in immediate proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. 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 between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 43 H Hilcorp E -W Cmopeny Milne Point Unit M-22 SB Producer Drilling Procedure The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event 1-12S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 44 B Hilcorp R� C. -My 8-1/2" Hole Section: Milne Point Unit M-22 SB Producer Drilling Procedure Hole Cleaning: Maintain rheology of mud system. Sweep hole with low -vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of> 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a "ramp" in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we'll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for 1-12S. No 1-12S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm 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: Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M - Pad. Utilize MPD to mitigate any abnormal pressure seen. Anti -Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Page 45 ff Hilcorp Fae�' Campny 25.0 Page 46 n 14 Layout O mro TM 0 �t, ���li. � ) VEiy�u�" OWN Milne Point Unit M-22 SB Producer Drilling Procedure N V N Hilcorp lnugy Compmy 26.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: Milne Point Unit M-22 SB Producer Drilling Procedure 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 47 ff Hilcorp EmW Compny 27.0 Doyon 14 Choke Manifold Schematic Milne Point Unit M-22 SB Producer Drilling Procedure Z r ; <0 o ® r W W ^m^ U/ tiN _. n 0 N O a 0 O S Z 3 3 n Q o w-ind G 6rco n in3y 3 330 3 '" < o y05 n n O _ A 7 C D n � n v c � V W W N o T W .. o a TV .. V rJ Q I m G v Page 48 H Hilcorp Milne Point Unit M-22 SB Producer Drilling Procedure 28.0 Casing Design 11 Calculation & Casing Design Factors H'Ico�r DATE: 81712019 WELL: MPU M-22 DESIGN BY: Joe Engel Design Criteria: Hole Size 12-114" Mud Density: 9.2 ppo Hole Size 8-112" Mud Density: 9.2 ppg Hole Size Mud Density: Drilling Mode MASP: 1326 psi (see attached hIASP determination & calculation) MASP: Production Mode MASP: 1326 psi (see attached HASP determination & calculation) Collapse Calculation: Section Calculation 7 Normal gradient external stress (0.494 psVit) and the casing evacuated for the internal stress Page 49 n Hilcotp GnT Co T Milne Point Unit M-22 SB Producer Drilling Procedure 29.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 11 8-1/2" Hole Section Hilcorp MPU M-22 Milne Point Unit Ir MD ND Planned Top: 5048 3900 Planned TD: 14269 3586 Co, vsZ,) C3400 8'+6CMI..% Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OB Sand 3,900 1716 Oil 8.46 0.440 Offset Well Mud Densities Well MW ranee Too (TVDI Bottom (TV DI Date L-50 8.8-9.1 Surface 4125 2015 L-49 9.0-9.2 Surface 4196 2015 L-48 8.9-9.2 Surface 4147 2015 L-47 8.8-9.0 Surface 4158 2015 L-46 9.0-9.3 Surface 4177 2015 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3,900 (ft) x 0.78(psi/ft)= 3042 3042(psi) - [0.1(psi/ft)*3900(ft)]= 2652 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff CIA sand) 3900 (ft) x 0.44(psi/ft)= 1716 psi 1716(psi)-0.1(psi/ft)*3900(ft) 1326 psi ✓ Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore togas at 0.1 psi/ft. Page 50 H Hilcorp E -W Company 30.0 Spider Plot (NAD 27) (Governmental Sections) _ 1 I r /rI / ADL025513-- Sec,22 1144, M» LUW: Il =" Page 51 Milne Point Unit M-22 SB Producer Drilling Procedure Sec. l' `•�z '�ADL389235 •' Sec~f2 L3a•16• Legend \\\\\ KUPARUK RIVET Other Surface Holes (SHL) • MPU M-22_SHL Other Bottom Holes (Ei X MPU M-22 TPH ADL025519 sec. 26 _ _ _ Other Well Patin Coastline (USGS 1:63k) 7 MPU M-22_OHL r Q OI and Gas Unit Boundary Pad Foolpnnl Milne Point Unit Alaska State Plane Zone 4 HAD 1927 MPU M-22 Well D 1,D00 2.000 wp_05 Feet `� � �4 `• 1 K1XR1 �, / 1Qo 1 % \ � 1 \ 1 1 \ , 1 Y, `sec: �1 Ir , \I 13, , \ � 1 i I L\ 11 Q � \ f \ 1 Z 1 • 1 ,1 POINT UNIT 1 1:02,55114 t, v 'IiMJ 1 J •• 1 V19 Ga 1 1 ' 1 I S;: 2. 1 1 1 1 1 1 1 , 1 I 1 , 1 , 1 , Lace- =..eve dl 311L Iru nt-„ Legend \\\\\ KUPARUK RIVET Other Surface Holes (SHL) • MPU M-22_SHL Other Bottom Holes (Ei X MPU M-22 TPH ADL025519 sec. 26 _ _ _ Other Well Patin Coastline (USGS 1:63k) 7 MPU M-22_OHL r Q OI and Gas Unit Boundary Pad Foolpnnl Milne Point Unit Alaska State Plane Zone 4 HAD 1927 MPU M-22 Well D 1,D00 2.000 wp_05 Feet 31.0 Surface Plat (As Built) (NAD 27) Milne Point Unit M-22 SB Producer Drilling Procedure Page 52 12 l .7s PROJECT MPaf I i SEGI --BEG BEG I- _ -I- AA SEG I, 1T o I M-10 M-10 ■ f' M-11 ■ I I . M_12 I >� I M-12 , ■ M^f4 F I% r ,V tt 'l I 1 23 M -M ■ I i NINE SI` tE F t I ■ M -l5 M-21 ■ M-16 NCINM MAP'S M-22 + 1 NTS I M-17 _ Y I M-,8 I f:...F. . M_as ■ �" ROD tt F. Banlwrt 200 GRAPHIC SCALEI MOOSE PAD I ,Ay,_ 0 102 200 AOG"•iQIOY>• ( IN FEET) 1 Ino, • 200 N. SURVEYOR'S CERTIFICATE : LEGEND, NOTES- I IUE9Y CERTIFY 1MAT I AM AS -OI CCMOVCTgt 1, AU9RA STATE PURE COORDINATES AM NA:27, IME A. PRDPMY REDSRRED ATA UCENSFD TO PRACTICE l O SUR�EYIND IN 2 LEOBD �RMB ARE NA027. INE STATE OF A A MO TNAT ■ flOSTINC CONOUCTURMIS 1 CARS a 11011:2AMID VERTIm CMIRO. 6 M -BUILT REPRESEN13 A SURREY MADE BY WE OR UNDER MY DIRECT 91.ALAP BMD K SUPERN3tN AND TIAT All 4. MPU MOOSE AM71AE PAD WALE FACTOR IR 02991011 DIMENSIONS AND 0M01 OETAAS ARE CCRRBCT AS CF MAY t, 20[9. S DARES OT WUR1 , MAY I t 16, Mt 6. ROERSIDE FRUC 9:tl1: H04-03 P 14-15, M-24 LOCATED WITHIN PROTRACTED SEC, 14, T. 13 N., R. 9 E., UMIAT MERIDIAN, ALASKA WELL A.S.P. PLANT GEODETIC GEODETIC SECTION PAD CELLAR N0, COORDINATES COORDINATES POSITION OMS P05111ON(W)D OFFSETS ELEVATION BOX EL M-17 Y- 6,027,765.65 N= 1,168.00 70'29'12.792" 70.4968866' 4,914' FSL 248, 24.9, X= 533,633.87 E- 1,635.03 149'43'30.357" 149.7250993' 531' FEL M-18 Y= 6,027,765.61 N= 1,167.96 70'29'12.793" 70.4858868' 4,315' FSL 246' 24.7' X- 533.603.87 E- 1,605.02 14943'31,240" 149.7253445• 561' FEL M-19 Y- 6,027.765.55 N= 1,167.90 7529'12.796" 70.4868878' 4,915' FSL 24.9' 25.1' X= 533,513.82 E= 1,514.96 149.43'33.890" 149.7260805' 651' FEL M-21 Y= 6,027,889.77 N- 1,292.14 70'29'14.007" 70.4872242' 5038' FSL 24.9' 25-0' X- 533,753.82 E- 1,754.99 149'43"26.811" 149.7241143' 1 411' FEL M-22 Y". 6,027,8 292.20 70'29'1 a,012" 70.4872255' 5,0039' FSLL8 25A 24.9 4 533.663.95= 1,X= 665.11 149'43'29.456" 1 149.72489' 1 5 F R NH Rr Hucor Alaska B�n9 belle MPU MOOSE Pill M �QMO�P'041 AS -BUILT CONDUCTORS 1• " aTD' m ME. Ts RTRTOI AR,1 WELLS 17,115,19,21,22 Page 52 32.0 Schrader Bluff OA Sand Offset MW vs TVD Chart Schrader Bluff OA Sand Offset MW vs TVD MW, PPB 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5 0 1 500 1000 1500 2000 0 2500 3000 3500 4000 4500 Page 53 -MPU L-46 (2015) -MPU L-47 (2015) -MPU L-48 (2015) ---MPU L-49 (2015) -MPU L-50 (2015) -MPU F-106 (2017) -MPU F-107 (2017) -MPU F-108 (2017) -MPU F-109 (2017) -MPU F-110 (2017) Milne Point Unit M-22 SB Producer Hilmw tneegyComp.ny Drilling Procedure 32.0 Schrader Bluff OA Sand Offset MW vs TVD Chart Schrader Bluff OA Sand Offset MW vs TVD MW, PPB 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5 0 1 500 1000 1500 2000 0 2500 3000 3500 4000 4500 Page 53 -MPU L-46 (2015) -MPU L-47 (2015) -MPU L-48 (2015) ---MPU L-49 (2015) -MPU L-50 (2015) -MPU F-106 (2017) -MPU F-107 (2017) -MPU F-108 (2017) -MPU F-109 (2017) -MPU F-110 (2017) H Hilcorp Milne Point Unit M-22 SB Producer Drilling Procedure 33.0 Drill Pipe Information 5" 19.5# S-135 DS -50 & NC50 Drill Pipe Configuration i Pipe Body OD Ion 5.000 Pipe Body Wall Ttitlaless M 0.362 Pipe Body Grade S-135 Dnll Pipe Length Tool Joint SMYS Connection GPDS50 Topa Joint OD 6.625 Tod Joint 1D 'm. 3250 Pin Tong 9 Box Tong cm 12 80 % Impeach Class Nominal Nominal Weight Designation 19.50 Drill Pipe Approximate Length m)[31.5 SmoottiEdge Height <m YJ2 RNsed Tool Joint SMYS anll 120 000 Upset Type IEU Max Upset OD (DTE) na 5.125 Friction Factor 11.0 124 N. Torp iwce m., .0.OYTxcIrD. Drill Pipe Performance Drill -Pipe Length Rangel Drill Pipe with Pipe Bodv at Tension Tension Only 10 560800 ccmarce were 32100 1467AW mim. oNi Rw smersnrvams: Connection Performance GPOS50 Nrp Tu myNnCe Lmx�eeTopma`u.m Iini1G i M.�T nn - 3' [CGYmJ05� i�ouN m[ iGNM. Tool Joint Torslenal Strenoth tan:l 71.800 Tool JointTonsdle Strergtll cma 1,250.000 Elevator Shoulder Information _ S tlge Height Rased l 3+32 Raised Box OD oP 6.812 E Elevator Cavadly ew 1658,000 1 Ndc Nominal tba mmee> 2329 0.36 0.0085 0.72 00172 Nom. ou xelm emva exuas as us aNlws. ass+. vstlaass vnv rti+Y 1a d- m Ops t..ry mx ralnaru. umr.ui Llms:ccovwio. Tv ouisr rsla:- 6.625 rhr OD X 3.250 ON ID ) 120,000 oeo Pipe Body Slip Crushing Capacity ,V Tool Joint Dimensions Balanced DIl Ion 6.435 Mnnxxn TmlJwlCOt M30 Prt um cuss M 5' ...T.Jmncoar M5,g3 anh p D IEYM77 7 Diameter 6.612 mi to Min TJ OD for Prernium Mal NOM' 4Lalsem MVYw DD IRfNseselsvml[r cLpmy wtlrwt oRezlTe n+w4e.up toque. Pipe Body conagureEion ( 5 mn OD 0.362 wl Wall S-135) Pipe Bodv Performance Page 54 Pipe Body Configwation ( 5 tml OD 0.362 mt Wall S-135) Nom: NpiN R6W W 0)D'w 15 J kjH mr Mr OPI. Nominal 80% Inspection class API Prermin class Pipe Tensile StrenGth712.100 560800 560.800 Pipe Torsional Strength rxausr 74.100 58100 58,100 TXRpeBOdy Torsional Ralb 0.97 124 124 80% Pipe Torsional Strength (11 s159.300 46,500 46,500 Burst Psi 17.105 15,638 15638 Collapse ro=e 15.672 10,029 10.029 Pipe OD mr 5.000 4.855 4.855 Wall Thickness Iml 0.362 0.290 0290 Norinsi Pipe ID mo 4276 4276 4276 Cross Sectional Area or Pipe Body ton^n 5275 4.154 4.154 Cross Sectional Area of DO tiv-zr 19.635 18.514 18.514 Cmss Sectional Area of ID (,,-2,114.360 114.360 14.360 Section Modukrs o+^n 5.708 14.476 14.476 Polar Section Modulus Ion•al 71.413 8.953 18.953 Nom: NpiN R6W W 0)D'w 15 J kjH mr Mr OPI. 500204050016200 Weatherford 5' 19.50 Ib/ft S-135 w/ NC 50 6-5/8" OD x 3-1/4" ID Tool Joint DRILL PIPE SPECIFICATIONS Grade I S-135 Connection NC 50 Milne Point unit 5" XH t4 -1/2" IF Upset Type IEU M-22 SB Producer 19.50 lbs it Hilcorp Drilling Procedure 500204050016200 Weatherford 5' 19.50 Ib/ft S-135 w/ NC 50 6-5/8" OD x 3-1/4" ID Tool Joint DRILL PIPE SPECIFICATIONS Grade I S-135 Connection NC 50 Interchangeable With 5" XH t4 -1/2" IF Upset Type IEU Nominal Weight per Foot 19.50 lbs Adjusted Weight With Tool Joint per Foot 23.08 lbs TOOL JOINT DATA Outside Diameter 6-5l8' Inside Diameter 3 -1/4 - API Drift 3-118' Rabbit OD, Suggested 3-1/16" Minimum Make-up Torque 25.900 ft -lbs Maximum Recommend Make-up Torque 26.800 ft -lbs Torsional Yield Strength 51,700 ft -lbs Tensile Strength 1.269.000 lbs TUBE DATA New Premium Outside Diameter 5-000" 4.855" Inside Diameter 4 276" 4.276' Wall Thickness 0.362" 0.290" Cross Sectional Area 5.275 sq in 4.154 sq in Maximum Hook LoadlTensile Strength 712,000 lbs 560,800 lbs Slip Crushing /Slip Type (SDXL) 572.100 lbs 453,500 lbs Burst Pressure 17,100 psi 16,100 psi Collapse Pressure 15,700 psi 10.000 psi Torsional Yield Strength 74.100 ft -lbs 58.100 ft -lbs Capacity WI Tool Joint0.726 US avtt 0.726 US altft Displacement W1 Tool 1-1 0.353 US davft 0.322 US gallft Excessive heat or pulling when tube is torqued can cause the maximum pull to decrease. Where possible all figures are obtained from OEM data source. NOTE: Weatherford in no way assumes responsibility or liability for any loss, damage or injury resulting from the use of the information listed above. All applications are for guidelines and the data described are at the user's own risk and are the user's responsibility. Page 55 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-22 MPU M-22 Plan: MPU M-22 wp05 Standard Proposal Report 18 July, 2019 HALLIBURTON Sperry Grilling Services Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPUM-22 Wellbore: MPU M-22 Design: MPU M-22 wp05 Hilcorp Alaska, LLC Calculation Method: Minimum Curvature DDI = Error System: ISCWSA Scan Method: Closest Approach 3D 7,19 Error Surface: Pedal Curve Warning Method: Error Ratio REFERENCE INFORMATION Coordinate (N/E) Reference: Well Plan: MPU M-22, True North Vertical (WD) Reference: MPU M-22 Planned RKB @ 58.60ust Measured Depth Reference: MPU M-22 Planned RKB (03 58.60ust Calculation Method: Minimum Curvature FORMATION TOP DETAIIS W formabon dela is available CASING DETAILS WD WDSS MD Size Name 3900.42 3841.82 5048.87 9-5/8 9518"x12114" 3586.60 3528.00 14269.53 6-5/8 6518-x81/2" ® HALL�IBURTON T . �IT +N/ -SE/ -W 0.00 +0.00 Sec MD Inc A,d WD +N/ -S +E/ -W Dleg TFace VSect 1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00 2 350.00 0.00 0.00 3WOO 0.00 0.00 0.00 0.00 0.00 3 1086.43 29.46 357.44 1054.42 184.99 -8.26 4.00 357.44 -183.97 4 2363.19 29.46 357.44 2166.11 812.25 -36.25 0.00 0.00 -807.74 5 4648.87 85.00 183.52 3865.56 -80.21 -183.67 SOO -173.36 92.83 6 5048.87 85.00 183.52 3900.42 477.94 .208.14 0.00 0.00 491.29 7 5083.77 86.60 184.22 3902.98 -512.66 -210.49 5.00 23.76 526.10 8 5198.82 86.60 184.22 3909.80 -627.19 -218.95 0.00 0.00 640.94 9 5412.37 93.00 184.00 3910.55 .840.08 -234.25 3.00 -2.01 854.37 10 5812.37 93.00 184.00 3889.62 -1238.56 -262.11 0.00 0.00 1253.83 11 5909.56 95.91 184.21 3882.07 -1335.20 -269.05 3.00 4.07 1350.72 12 6241.06 95.91 184.21 3847.95 .1664.05 -293.24 0.00 D.00 1680.46 13 6264.07 95.25 184.00 3845.71 -1686.89 -294.88 3.00 -162.53 1703.36 14 6664.07 95.25 184.00 3809.11 -2084.25 -322.67 0.00 0.00 2101.68 15 6765.95 92.20 184.10 3802.50 -2185.65 -329.85 3.00 178.17 2203.33 16 6966.18 92.20 184.10 3794.83 -2385.22 -344.14 0.00 0.00 2403.41 17 7013.01 93.60 184.10 3792.46 -2431.87 -347.49 3.00 0.09 2450.18 18 8113.01 93.60 184.10 3723.39 -3526.89 425.98 0.00 0.00 3548.01 19 8231.31 97.13 184.43 3712.33 -3644.32 434.74 3.00 5.29 3665.77 20 8495.00 97.13 184.43 3679.58 3905.19 454.94 0.00 0.00 3927.41 21 8616.12 93.50 184.45 3668.36 4025.41 464.28 3.00 179.68 4047.99 22 9616.12 93.50 184.45 3607.31 -5020.54 -541.72 0.00 0.00 5046.09 23 9763.23 89.09 184.47 3603.99 .5167.12 -553.15 3.00 179.80 5193.12 24 9976.41 89.09 184.47 3607.39 -5379.62 -569.74 0.00 0.00 5406.26 25 10056.84 91.50 184.45 3606.98 -5459.81 -576.00 3.00 -0.36 5486.69 26 10256.84 91.SD 184.45 3601.74 -5659.14 -591.51 0.00 0.00 5686.62 27 10448.47 86.86 181.06 3604.49 -5850.45 -600.72 3.00 .143.90 5878.10 28 10816.66 86.86 181.06 3624.69 6218.02 .607.53 0.00 0.00 6245.25 29 11015.96 92.25 183.64 3626.25 6417.06 -615.70 3.00 25.57 6444.37 30 11615.96 92.25 183.64 3602.69 -7015.39 -653.76 0.00 0.00 7043.90 31 11765.96 87.77 184.10 3602.66 -7165.00 -663.88 3.00 174.17 7193.86 32 11916.75 87.77 184.10 3608.52 -7315.29 -674.65 0.00 0.00 7344.53 33 12016.02 90.75 184.00 3609.80 -7414.30 -681.65 3.00 -1.87 7443.79 34 12316.02 90.75 184.00 3605.87 -7713.54 -702.58 0.00 0.00 7743.76 35 12404.01 93.39 184.00 3602.69 .7801.25 -708.71 3.00 0.00 7831.68 36 12728.57 93.39 184.00 3583.50 6124.46 .731.31 0.00 0.00 8155.68 37 12816.56 90.75 184.00 3580.32 6212.16 -737.45 3.00 180.00 8243.60 38 13316.56 90.75 184.00 3573.78 6710.90 -772.32 0.00 0.00 8743.56 39 13452.30 86.68 184.00 3576.83 -8846.25 -781.79 3.00 179.99 8879.24 40 13642.12 86.68 184.00 3587.83 -9035.29 -795.01 0.00 0.00 9068.74 41 13769.53 90.50 184.00 3590.96 -9162.32 -803.89 3.00 -0.01 9196.08 42 14269.53 90.50 184.00 3586.60 -9661.09 -838.77 0.00 0.00 9696.06 WELL DETAILS: Plan: MPU M-22 5DD Sted Dlr4°/100': 350' MO. 291AWD End Dir :1086.43' MD, 995.82 TVD 7,000' ^,c 7500 Zle�O 'L 4" �ryA c'A0w ^A^"�Kyn"'o,�' ^'Z Poo�`F2q n,"Po' n'�^ 2O�ay'� �o Qyy oFo o"Y yFo�?eb 6 p0 ZSO 0 g 4, 4 . , ab oro .; &. ro'p, 3000 ,$' m' � r§ b1' ;0 €jw °�8 p1 �c° ca g ,S m`� m� c° y `� tv gar h y , o r e r r r g . ymr a. oT r" m` i Il Ih MPU M-22 W305 YI N w o 1m" 0 0 0 l 0 0 0 1 00 0 0 0 o o 0o h o 0 6 5/8" x 8 1/2" 95/8"x 12 1/4', o o hY22 WPM W- WPM P I W22 v105 CM M-22 w'PD5 CP8 h1 M-22 WPM CP1 M-22 wp05 CP2 M-22 wp05 CP3 1-22 wpW CP5 Wn w905 CP7 M-22 w,05 Toa Ground Level: 24.90 Northing Easting Latitude Longitude 6027889.83 533663.95 70° 29' 14.012 N 149° 43'29.456 W Target Annotation StartDir 4°/100' : 350' MD, 291 XTVD End Dir :1086.43- MD, 995.82' WD Start Dir 5°/100' : 2363.19' MD, 2107.517VD End Dir :4648.87' MD, 3806.96' ND -start ESP tang M-22 wpO5 Heel Start Dir 5-1100': 5048.87' MD, 3a41.82'WD End Dir : 5083.77' MD, 3844.38' TVD Start Dir 3-/100': 5198.82' MD, 3851.2'ND End Dir : 5412.37' MD, 3851.95' W D M-22 wpOS CP1 Start Dir 3-1100': 5812.37'MD, 3831b2 -TVD End Dir : 5909.56' MD, 3823AT TVD Start Dir 3'/100': 6241.06' MD, 3789.35'WD End Dir :6264.07' MD, 3787.11' WD M-22 wpO5 CP2 Start Dir 3"/100': 6664.07' MD, 3750.517VD End Dir : 6765.95' MD, 3743.9' WD Start Dir 3°/1 DP: 6966.18' MD, 3736.23'WD End Dir : 7013.01' MD, 3733.86' WD M-22 wpOS CPS Start Dir 3-1100': 8113.01' MD, 3664.79T/D End Dir : 8231.31' MD, 3653.73' WD Start Dir 3°/109 : 8495' MD, 3620.98'WD End Dir :8616.12' MD, 3609.76' WD M-22 wpO5 CP4 Start Dir 3°/100' : 9616.12' MD, 3548.71'WD End Dir :9763.23- MD, 3545.39' WD Start Dir 3°/1 DO' : 9976.41' MD, 354B.79'WD End Dir : 10056.84' MD, 3548.38' TVD M-22 wp05 CP5 Start Dir 3-/100r: 10256.84' MD, 3543.14'TVC End Dir : 10448.47' MD, 3545.89' W D Start Dir 3-1100': 10816.66' MD, 3566.09'WD End Dir : 11015.96' MD, 3567.65' WD M-22 wpO5 CP6 Start Dir 3°/100' : 11615.96' MD, 3544.097VD End Dir : 11765.96' MD, 3544.06' WD Start Dir 3'/100': 11916.75' MD, 3549.92'WD End Dir : 12016.02' MD, 3551.2' WD W22 wp05 CP7 Start Dir 3°/100': 12316.02' MD, 3547.27TVD End Dir : 12404.01' MD, 3544.09' WD Stars Dir 3°/100' : 12728.57' MD, 3524.97VD End Dir : 12816.56' MD, 3521.72' WD M-22 wp05 CP8 Stan Dir 3°/100': 13316.56' MD, 3515.18RVD End Dir : 13452.3' MD, 3518.23' W D Stan Dir 3°/100' : 13642.12' MD, 3529.23TVD End Dir : 13769.53' MD, 3532.36' WD M-22 wpO5 Toe Total Depth : 14269.53' MD, 3528' TVD SURVEY PROGRAM Date: 2016-06-22700:00:00 Validated: Yes Version. Depth From Depth To Survey/Plan 33.70 5048.87 MPU M-22 x 5048.87 14269.53 MPU M-22 v, -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 Vertical Section at 184.00° (1500 usfYin) 12750 1350[ WELL DETAILS: Plan: M' 22 +N/-S��-W Croand Leecl: 24..., 000 Nodhing Fa lin6 latittude Lungiludc 0.00 602]88983 53366395 0 -600 -1200 70 29' 14.012 N 1491 43' 29.456 W CASINO DETAILS TVD TVDSS MD Sizc Name 3900.42 3841.82 5048.87 9-5/8 95/8" x 121/4" 3586.60 3528.00 14269.53 6-5/8 6 5/8" x 8 1/2" Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-22 Wellbore: MPU M-22 M -z2 ayos Reer Plan: MPU M-22 wpO5 HALLIBUATON 6pa11y OHM., REFERENCE INFORMATION Coordinate (NE) Reference: Well Plan: MPU M-22, Time North Vertical (ND) Reference: MPU M-22 Planned RKB ® 58.60us6 Measured Depth Reference: MPU M-22 Planned RKB ® 58.60usfl Calculation Meacel Minimum Curvature M-22 wp05 CP1_ M-22 wp05 CPI _ Start Dir 4"/10(1' : 350' MD, 2914TV13 End Dir : 108643' MD, 995.82' TVD Stan Dir5°/100': 2363.19'101), 2107.51TVD End Dir : 4648.8]' MD, 3806.96 TVD - spit ESP tangent Start Dir 5"/100' : 5048.87' MD, 3841 82TVD _ End Dir :5083.7T MD, 3844.38' TVD Slan Dir 3-1100': 5198.82' MD, 3851.2TVD _End Dir : 5412.37' MD, 3851.95' TVD Stan Dir 3°/100' : 5812.3T MD, 3831.02 -TVD _ "Er d Da:5909.56 MD, 3823.47'TVD Stan Dir 3"/100' : 6241.06' MD, 3789.357VD _ End Dir : 6264.07 MD, 3787.11' TVD Sal Dir 3"/100' : 6664.07' MD, 3750.51TVD End Dir :6765.951 MD, 3743.9' TVD "Siad Dir YAW': 6966.18' MD, 3736.33TVD 6td Dir : 7013.01' MD, 3733.86' TVD Stan Dir 3"/100' : 8113.01' MD, 3664.79TVD M-22 wpO5 CP3- ' ad Dir :8231.31' MD, 3653.73' TVD Stan Dir 3°/100' : 8495' MD, 3620.98TVD End Dir 8616.12'MD,360926TVD -4800 Sian Dir 3"/100' : 9616.12' MD, 3548.71TVD M-22 wp05 CP4- -"- End Du: 976323' ME, 545.39' TVD " Stan Dir3°/100': 9976.41'MD, 3548.79'TVD -5400 Stan Dir 3"/100': 10256.84' MD, 3543.14WD M-22 %p05 CP5 Pad Dir : 10448.47 MD, 3545.89' TVD -6000 Sunt Dir3"/100': 10816.66MD, 3566.W'TVD " End Dir : 11015.96' MD, 3567.65' TVD -6600 Stan Dir 3°/100' : 11615.96' MD, 3544.09TVD M-22 wp05 CP6 - - End Dir : 11765.96 MD, 3544.06' TVD -7200 -� Stan Dir 3"/100': 11916]5' MD, 3549.92TVD _ ___ End Dir: 12016.02' MD, 3551.2' TVD Sal Dir 3"/100': 12316.02' MD, 3547.27TVD 7800 M-22 W05 CPT _ _ _ End Dir : 12404.01' MD, 3544.09' l V ) Sat Dir 3"/100' : 12728.57' MD, 3524.9TVD _ - End Dir : 1281656' MD, 3521.72' TVD -8400 Stan Dir 3"/100' : 13316.56MD, 3515.18'TVD M-22 wp05 CP8- """End Di r: 13452.3' MD, 3518.23' TVD - "Stan Dir YAM: 13642.12' MD, 3529.23'TVD -9000 - - - - - - End Dir : 13769.53' MD, 3532.36' TVD M--22 wp03 Toe " -Total Dnpth :14269.53' MD, 3$28' TVD 6 5/8" x 8 I/2" WU M-22 wp05 00 -1200 -600 0 600 1200 1800 2400 West( -)/East(+) (1200 usft/in) 3000 3600 3413 ;C�° .i° e ° .i° a O !�O ° h,° .i° ° �'° �p o ,°o yo -y h o �Y oy mry ry o-^� o-' ^� ti° y' ti� ti O ^o°j o^ �O O ^0 �° �`� �° yo -lb 00 °. 00o- p- n43' O' y M ,�"e° �p°j may" o p"�" oy`1" o�o"ryo ti? o 3450 A- o' y O' ly a m b ti b 43' F F ^' F O• F F F F p n ,� o• n 1�' ^ o ^ o' o- m" F o• o' 'v o• b o• F oy o o F y y F b cryo ob m ^I , `' o• p o^ ti"y o do 0 M o' yyti > na^ o^ ° -Fp ej o^ °• h o' 0' iF °' ooyyl o ouoR' o FO' ^n`O ^mr ,ro ti "' ^o-� ^ ,�^� yry dry. O• 3488 Fp. yrv. FO' yv �F Fp• F �°' ti ^6N. ob' `�, ob. `" ob yA 8 o �' 'vo -N �o oo. ^ �y ^��' yF 00 0` o`o ori° o ro M d' o Bi p o p >\ o � � , s I � "^ s$ ` b � 0. ^ ! y n' � ' ob may' o a y a "' s ; >\ O' $ • _ , a , ` y >\ o o o '✓ to O t O C l r l A M n o I c o no nJ a n n/ ry o o y ; e p, 4/ O 20 O e = ` c . ,b ,y i' i �' cn ar '1 ,�r . mr, o O i 4/c o 4/c o O • 0 , o O 3525 O' r O ca �h O O O p i t-�p 4/ I� h i 0 cn y r0 i i 0'9 i i / / h y rpr , 0� .°yQ Hca 0 ca 5 0 0ca mr 0r ,0 ' 40 01 ' 0 �y , N 3563 q 6 5/8" x 8 1/2" 3600 1, i.T o ' o MPU M-22 wp05 o ' M-22 wpO5 CPS N 1 0 11 1 -v \ O 1 3638 o M-22 wp05 Toe M-22 wp05 CP4 M-22 wp05 CP6�1 o 3675— M-22 1, � ' I' � � I M-22 wp05 CPS , I , � M-22 wp05 CP7 I I I CO i o 3 3713` h° \OI OM WELL DETAILS: Plan: MPU M-22 F O• M N'I/� `7�0 F y^ Ground Level: 24.90 +N/-5 X0.00 Northing E5336 Latitude Longitude29.4 M-22 wp05 CP3 9 3750 0.00 0.00 6027889.83 533663.95 70° 29' 14.012 N 149° 43' 29.466 W 0o- I F I I I I O p 4r � o M-22 wp05 CP2 Ir I I 'i o NALLIBURTON 9 5/8" X 12 114" ' I � 3900 M-22 wp05 CP1 M-22 wpO5 Heel o y o 0 600 1200 BP." Orimn9 DDI = 7.019 Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-22 Wellbore: MPU M-22 Design: MPUM-22 wp05 Uale: [onbi L TUOOO:00 4§fdalel Vee Version: Depth From Depth To Sumyl%an Tool 33,70 504887 MPU M-22 wpOS(MPU M-22) 2_MWD+IFR2+MS+Sag 5048.87 14269.53 MPU M-22 n06 (MPU M-22) 2 MWD+IFR2+MS+Saq TOP DETAILS No formation data is available REFERENCE INFORMATION C"rdimte (N/E) Reference: Well Plan: MPU M-22, True North Vertical (TVD) Reference: MPU M-22 Planned RKI3 @ 58.60usfl Measured Depth Reference: MPU M-22 Planned RKS @ 58.60usN Calculation Method: Minimum Curvature EM CASING DETAILS Cilcorp Alaska LLC ND TVDSS MD Size Name Calculation Method: Minimum Curvature 300.d2 3841.82 5046.87 9-5/6 95/8"z 121/4" Error System: ISCWSA 3 86.60 3528.00 14269.53 6-5/8 65/8" x 8 1/2" Scan Method: Closest Approach 3D Enor Surtace: Pedal Curve Warnin Method: Enor Retio 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 Vertical Section at 184.00° (1200 ustt in) HALLIBUR'T O Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-22 Wellbore: MPU M-22 Design: MPU M-22 wp05 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M-22 TVD Reference: MPU M-22 Planned RKB @ 58.60usft MD Reference: MPU M-22 Planned RKB @ 58.60usft North Reference: True Survey Calculation Method: Minimum Curvature Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site M Pt Moose Pad PLAN Depth From (TVD) +N/ -S Site Position: Northing: 6,027,877.65usft Latitude: 70° 29' 13.905 N From: Map Easting: 533,363.92 usft Longitude: 149° 43'38.286 W Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: 0.26 ° Well Plan: MPU M-22 Well Position +N/ -S 0.00 usft Northing: 6,027,889.83 usll Latitude: 70° 29'14.012 N +EI -W 0.00 usft Easting: 533,663.95 usft Longitude: 149° 43'29.456 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 Usti Ground Level: 24.90usft Wellbore Magnetics Design Audit Notes: Version: Vertical Section: MPU M-22 Model Name BGGM2018 MPU M-22 wp05 Sample Date Declination (`) 8/17/2019 16.50 Phase: PLAN Depth From (TVD) +N/ -S (usft) (usft) 33.70 0.00 Dip Angle Tie On Depth: +E/ -W (usft) 0.00 80.95 33.70 Direction (I 184.00 Field Strength (nT) 57,416.77654023 7/18/2019 7:07:48PM Page 2 COMPASS 5000.15 Build 91 Plan Sections Measured Halliburton HALLIBURTON TVD Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-22 Company: Hilcorp Alaska, LLC TVD Reference: MPU M-22 Planned RKB @ 58.60usft Project: Milne Point MD Reference: MPU M-22 Planned RKB @ 58.60usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-22 Survey Calculation Method: Minimum Curvature Wellbore: MPU M-22 (usft) (°) Design: MPU M-22 wp05 (usft) usft 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) (°1100usft) (°) 33.70 0.00 0.00 33.70 -2490 0.00 0.00 0.00 0.00 0.00 0.00 350.00 0.00 0.00 350.00 29140 0.00 0.00 0.00 0.00 0.00 0.00 1,086.43 29.46 357.44 1,054.42 995.82 184.99 -8.26 4.00 4.00 0.00 357.44 2,363.19 29.46 357.44 2,166.11 2,107.51 812.25 -36.25 0.00 0.00 0.00 0.00 4,648.87 85.00 183.52 3,865.56 3,806.96 -80.21 -183.67 5.00 2.43 -7.61 -173.36 5,048.87 85.00 183.52 3,900.42 3,841.82 -477.94 -208,14 0.00 0.00 0.00 0.00 5,083.77 86.60 184.22 3,902.98 3,844.38 -512.66 -210.49 5.00 4.58 2.02 23.76 5,198.82 86.60 184.22 3,909.80 3,851.20 -627.19 -218.95 0.00 0.00 0.00 0.00 5,412.37 93.00 184.00 3,910.55 3,851.95 -840.08 -234.25 3.00 3.00 -0.10 -2.01 5,812.37 93.00 184.00 3,889.62 3,831.02 -1,238.56 -262.11 0.00 0.00 0.00 0.00 5,909.56 95.91 184.21 3,882.07 3,823.47 -1,335.20 -269.05 3.00 2.99 0.21 4.07 6,241.06 95.91 184.21 3,847.95 3,789.35 -1,664.05 -293.24 0.00 0.00 0.00 0.00 6,264.07 95.25 184.00 3,845.71 3,787.11 -1,686.89 -294.88 3.00 -2.86 -0.90 -162.53 6,664.07 95.25 184.00 3,809.11 3,750.51 -2,084.25 -322.67 0.00 0.00 0.00 0.00 6,765.95 92.20 184.10 3,802.50 3,743.90 -2,185.65 -329.85 3.00 -3.00 0.10 178.17 6,966.18 92.20 184.10 3,794.83 3,736.23 -2,385.22 -344.14 0.00 0.00 0.00 0.00 7,013.01 93.60 184.10 3,792.46 3,733.86 -2,431.87 -347.49 3.00 3.00 0.00 0.09 8,113.01 93.60 184.10 3,723.39 3,664.79 -3,526.89 -425.98 0.00 0.00 0.00 0.00 8,231.31 97.13 184.43 3,712.33 3,653.73 -3,644.32 -434.74 3.00 2.99 0.28 5.29 8,495.00 97.13 184.43 3,679.58 3,620.98 -3,905.19 -454.94 0.00 0.00 0.00 0.00 8,616.12 93.50 184.45 3,668.36 3,609.76 -4,025.41 -464.28 3.00 -3.00 0.02 179.68 9,616.12 93.50 184.45 3,607.31 3,548.71 -5,020.54 -541.72 0.00 0.00 0.00 0.00 9,763.23 89.09 184.47 3,603.99 3,545.39 -5,167.12 -553.15 3.00 -3.00 0.01 179.80 9,976.41 89.09 184.47 3,607.39 3,548.79 -51379.62 -569.74 0.00 0.00 0.00 0.00 10,056.84 91.50 184.45 3,606.98 3,548.38 -5,459.81 -576.00 3.00 3.00 -0.02 -0.36 10,256.84 91.50 184.45 3,601.74 3,543.14 -5,659.14 -591.51 0.00 0.00 0.00 0.00 10,448.47 86.86 181.06 3,604.49 3,545.89 -5,850.45 -600.72 3.00 -2.42 -1.77 -143.90 10,816.66 86.86 181.06 3,624.69 3,566.09 -6,218.02 -607.53 0.00 0.00 0.00 0.00 11,015.96 92.25 183.64 3,626.25 3,567.65 -6,417.06 -615.70 3.00 2.71 1.29 25.57 11,615.96 92.25 183.64 3,602.69 3,544.09 -7,015.39 -653.76 0.00 0.00 0.00 0.00 11,765.96 87.77 184.10 3,602.66 3,544.06 -7,165.00 -663.88 3.00 -2.98 0.30 174.17 11,916.75 87.77 184.10 3,608.52 3.54992 -7,315.29 -674.65 0.00 0.00 0.00 0.00 12,016.02 90.75 184.00 3,609.80 3,551.20 -7,414.30 -681.65 3.00 3.00 -0.10 -1.87 12,316.02 90.75 184.00 3,605.87 3,547.27 -7,713.54 -702.58 0.00 0.00 0.00 0.00 12,404.01 93.39 184.00 3,602.69 3,544.09 -7,80125 -708.71 3.00 3.00 0.00 0.00 12,728.57 93.39 184.00 3,583.50 3,524.90 -8,124.46 -731.31 0.00 0.00 0.00 0.00 12,816.56 90.75 184.00 3,580.32 3,521.72 -8,212.16 -737.45 3.00 -3.00 0.00 180.00 13,316.56 90.75 184.00 3,573.78 3,515.18 -8,710.90 -772.32 0.00 0.00 0.00 0.00 13,452.30 86.68 184.00 3,576.83 3,518.23 -8,846.25 -781.79 3.00 -3.00 0.00 179.99 13,642.12 86.68 184.00 3,587.83 3,529.23 -9,035.29 -795.01 0.00 0.00 0.00 0.00 13,769.53 90.50 184.00 3,590.96 3,532.36 -9,162.32 -803.89 3.00 3.00 0.00 -0.01 14,269.53 90.50 184.00 3,586.60 3,528.00 -9,661.09 -838.77 0.00 0.00 0.00 0.00 7/1812019 7:07:48PM Page 3 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-22 Wellbore: MPU M-22 Design: MPU M-22 wp05 Planned Survey Measured MPU M-22 Planned RKB @ 58.60usft MD Reference: Vertical North Reference: Depth Inclination Azimuth Depth TVDss (usft) (1) (_) (usft) usft 33.70 0.00 0.00 33.70 -24.9C 100.00 0.00 0.00 100.00 41.40 200.00 0.00 0.00 200.00 141.40 300.00 0.00 0.00 300.00 241.40 350.00 0.00 0.00 350.00 291.40 Start Dir 40/100' : 350' MD, 291.4'TVD 0.00 0.00 400.00 2.00 357.44 399.99 341.39 500.00 6.00 357.44 499.73 441.13 600.00 10.00 357.44 598.73 540.13 700.00 14.00 357.44 696.53 637.93 800.00 18.00 357.44 792.63 734.03 900.00 22.00 357.44 886.58 827.98 1,000.00 26.00 357.44 977.92 919.32 1,086.43 29.46 357.44 1,054.41 995.81 End Dir : 1086.43' MD, 995.82' TVD 6,028,034.61 1,100.00 29.46 357.44 1,066.23 1,007.63 1,200.00 29.46 357.44 1,153.30 1,094.70 1,300.00 29.46 357.44 1,240.37 1,181.77 1,400.00 29.46 357.44 1,327.45 1,268.85 1,500.00 29.46 357.44 1,414.52 1,355.92 1,600.00 29.46 357.44 1,501.59 1,442.99 1,700.00 29.46 357.44 1,588.66 1,530.06 1,800.00 29.46 357.44 1,675.73 1,617.13 1,900.00 29.46 357.44 1,762.81 1,704.21 2,000.00 29.46 357.44 1,849.88 1,791.28 2,100.00 29.46 357.44 1,936.95 1,878.35 2,200.00 29.46 357.44 2,024.02 1,965.42 2,300.00 29.46 357.44 2,111.09 2,052.49 2,363.19 29.46 357.44 2,166.12 2,107.52 Start Dir 501100': 2363.19' MD, 2107.51'TVD 2,400.00 27.63 356.99 2,198.45 2,139.85 2,500.00 22.68 355.40 2,288.94 2,230.34 2,600.00 17.74 352.98 2,382.76 2,324.16 2,700.00 12.87 348.79 2,479.18 2,420.58 2,800.00 8.13 339.73 2,577.49 2,518.89 2,900.00 4.08 310.20 2,676.92 2,618.32 3,000.00 4.14 235.20 2,776.73 2,718.13 3,100.00 8.22 206.47 2,876.15 2,817.55 3,200.00 12.96 197.57 2,974.42 2,915.82 3,300.00 17.84 193.43 3,070.81 3,012.21 3,400.00 22.77 191.04 3,164.57 3,105.97 3,500.00 27.73 189.46 3,254.99 3,196.39 3,600.00 32.69 188.33 3,341.38 3,282.78 3,700.00 37.67 187.47 3,423.09 3,364.49 3,800.00 42.65 186.78 3,499.49 3,440.89 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M-22 TVD Reference: MPU M-22 Planned RKB @ 58.60usft MD Reference: MPU M-22 Planned RKB @ 58.60usft North Reference: True Survey Calculation Method: Minimum Curvature 829.81 -37.11 Map Map 5.00 -825.20 +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) -24.90 -901.34 0.00 0.00 6,027,889.83 533,663.95 0.00 0.00 0.00 0.00 6,027,889.83 533,663.95 0.00 0.00 0.00 0.00 6,027,889.83 533,663.95 0.00 0.00 0.00 0.00 6,027,889.83 533,663.95 0.00 0.00 0.00 0.00 6,027,889.83 533,663.95 0.00 0.00 0.87 -0.04 6,027,890.70 533,663.91 4.00 -0.87 7.84 -0.35 6,027,897.67 533,663.56 4.00 -7.80 21.74 -0.97 6,027,911.56 533,662.88 4.00 -21.62 42.51 -1.90 6,027,932.32 533,661.86 4.00 -42.27 70.04 -3.13 6,027,959.84 533,660.51 4.00 -69.65 104.20 -4.65 6,027,994.00 533,658.83 4.00 -103.62 144.82 -6.46 6,028,034.61 533,656.83 4.00 -144.02 184.99 -8.26 6,028,074.76 533,654.86 4.00 -183.96 191.66 -8.55 6,028,081.43 533,654.53 0.00 -190.59 240.79 -10.75 6,028,130.54 533,652.11 0.00 -239.45 289.92 -12.94 6,028,179.66 533,649.70 0.00 -288.31 339.04 -15.13 6,028,228.77 533,647.28 0.00 -337.16 388.17 -17.33 6,028,277.88 533,644.87 0.00 -386.02 437.30 -19.52 6,028,327.00 533,642.45 0.00 -434.87 486.43 -21.71 6,028,376.11 533,640.04 0.00 -483.73 535.56 -23.90 6,028,425.22 533,637.63 0.00 -532.59 584.69 -26.10 6,028,474.34 533,635.21 0.00 -581.44 633.82 -28.29 6,028,523.45 533,632.80 0.00 -630.30 682.95 -30.48 6,028,572.56 533,630.38 0.00 -679.16 732.07 -32.67 6,028,621.68 533,627.97 0.00 -728.01 781.20 -34.87 6,028,670.79 533,625.55 0.00 -776.87 812.25 -36.25 6,028,701.82 533,624.02 0.00 -807.74 829.81 -37.11 6,028,719.39 533,623.09 5.00 -825.20 872.21 -39.87 6,028,761.77 533,620.13 5.00 -867.30 906.57 -43.29 6,028,796.11 533,616.57 5.00 -901.34 932.63 47.32 6,028,822.15 533,612.42 5.00 -927.06 950.20 -51.93 6,028,839.69 533,607.72 5.00 -944.26 959.13 -57.10 6,028,848.60 533,602.51 5.00 -952.81 959.37 -62.79 6,028,848.81 533,596.83 5.00 -952.65 950.91 -68.94 6,028,840.32 533,590.72 5.00 -943.78 933.81 -75.51 6,028,823.19 533,584.22 5.00 -926.27 908.20 -82.46 6,028,797.56 533,577.39 5.00 -900.24 874.29 -89.73 6,028,763.62 533,570.28 5.00 -865.90 832.32 -97.26 6,028,721.62 533,562.94 5.00 -823.51 782.62 -105.00 6,028,671.89 533,555.42 5.00 -773.39 725.57 -112.88 6,028,614.81 533,547.79 5.00 -715.93 661.60 -120.86 6,028,550.81 533,540.11 5.00 -651.55 711812019 7:07:48PM Page 4 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-22 Wellbore: MPU M-22 Design: MPU M-22 wp05 Planned Survey Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Measured Map Map Vertical +E/ -W Depth Inclination Azimuth Depth TVDss +N/ -S (usft) (°) (°) (usft) usft (usft) 3,900.00 47.63 186.21 3,570.00 3,511.40 591.19 4,000.00 52.62 185.73 3,634.09 3,575.49 514.88 4,100.00 57.61 185.31 3,691.27 3,632.67 433.26 4,200.00 62.60 184.93 3,741.10 3,682.50 346.94 4,300.00 67.59 184.58 3,783.21 3,724.61 256.58 4,400.00 72.58 184.26 3,817.26 3,758.66 162.87 4,500.00 77.57 183.95 3,843.01 3,784.41 66.53 4,600.00 82.56 183.66 3,860.26 3,801.66 -31.73 4,648.87 85.00 183.52 3,865.56 3,806.96 -80.21 End Dir : 4648.87' MD, 3806.96' TVD - start ESP tangent 4,700.00 85.00 183.52 3,870.01 3,811.41 -131.05 4,800.00 85.00 183.52 3,878.73 3,820.13 -230.48 4,900.00 85.00 183.52 3,887.44 3,828.84 -329.91 5,000.00 85.00 183.52 3,896.16 3,837.56 -429.34 5,048.87 85.00 183.52 3,900.42 3,841.82 -477.94 Start Dir 5-1100': 5048.87' MD, 3841.82'TVD - 9 5/8" x 12 1/4" 5,083.77 86.60 184.22 3,902.98 3,844.38 -512.66 End Dir : 5083.77' MD, 3844.38' TVD -234.25 6,027,048.78 5,100.00 86.60 184.22 3,903.94 3,845.34 -528.82 5,198.82 86.60 184.22 3,909.80 3,851.20 -627.20 Start Dir 301100': 5198.82' MD, 3851.2'TVD 533,414.79 0.00 5,200.00 86.63 184.22 3,909.87 3,851.27 -628.37 5,300.00 89.63 184.12 3,913.13 3,854.53 -728.04 5,400.00 92.63 184.01 3,911.16 3,852.56 -827.76 5,412.37 93.00 184.00 3,910.55 3,851.95 -840.08 End Dir : 5412.37' MD, 3851.95' TVD -290.25 6,026,265.37 5,500.00 93.00 184.00 3,905.97 3,847.37 -927.38 5,600.00 93.00 184.00 3,900.73 3,842.13 -1,027.00 5,700.00 93.00 184.00 3,895.50 3,836.90 -1,126.62 5,800.00 93.00 184.00 3,890.27 3,831.67 -1,226.24 5,812.37 93.00 184.00 3,889.62 3,831.02 -1,238.56 Start Dir 30/100' : 5812.37' MD, 3831.02'TVD 5,909.56 95.91 184.21 3,882.07 3,823.47 -1,335.20 End Dir : 5909.56' MD, 3823.47' TVD 6,000.00 95.91 184.21 3,872.76 33814.16 -1,424.92 6,100.00 95.91 184.21 3,862.47 3,803.87 -1,524.12 6,200.00 95.91 184.21 3,852.17 3,793.57 -1,623.32 6,241.06 95.91 184.21 3,847.95 3,789.35 -1,664.05 Start Dir 3-1100': 6241.06' MD, 3789.35'TVD 6,264.07 95.25 184.00 3,845.71 3,787.11 -1,686.89 End Dir : 6264.07' MD, 3787.11' TVD 6,300.00 95.25 184.00 3,842.42 3,783.82 -1,722.58 6,400,00 95.25 184.00 3,833.27 3,774.67 -1,821.92 6,500.00 95.25 184.00 3,824.12 3,765.52 -1,921.26 6,600.00 95.25 184.00 3,814.97 3,756.37 -2,020.60 Halliburton Standard Proposal Report Well Plan: MPU M-22 MPU M-22 Planned RKB @ 58.60usft MPU M-22 Planned RKB @ 58.60usft True Minimum Curvature 7/18/2019 7:07:48PM Page 5 COMPASS 5000.15 Build 91 Map Map +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) 3,511.40 -128.86 6,028,480.37 533,532.43 5.00 -580.76 -136.83 6,028,404.04 533,524.80 5.00 -504.08 -144.71 6,028,322.39 533,517.30 5.00 -422.11 -152.43 6,028,236.04 533,509.97 5.00 -335.46 -159.94 6,028,145.66 533,502.87 5.00 -244.80 -167.18 6,028,051.93 533,496.05 5.00 -150.81 -174.09 6,027,955.56 533,489.58 5.00 -54.22 -180.63 6,027,857.29 533,483.48 5.00 44.25 -183.67 6,027,808.80 533,480.66 5.00 92.83 -186.80 6,027,757.95 533,477.77 0.00 143.76 -192.91 6,027,658.50 533,472.10 0.00 243.38 -199.03 6,027,559.05 533,466.43 0.00 342.99 -205.15 6,027,459.61 533,460.77 0.00 442.61 -208.14 6,027,411.00 533,458.00 0.00 491.29 -210.49 6,027,376.27 533,455.81 5.00 526.09 -211.68 6,027,360.11 533,454.69 0.00 542.30 -218.95 6,027,261.71 533,447.87 0.00 640.94 -219.03 6,027,260.54 533,447.79 3.01 642.12 -226.30 6,027,160.84 533,440.97 3.00 742.05 -233.39 6,027,061.10 533,434.33 3.00 842.02 -234.25 6,027,048.78 533,433.53 3.00 854.38 -240.35 6,026,961.46 533,427.82 0.00 941.89 -247.32 6,026,861.82 533,421.30 0.00 1,041.75 -254.29 6,026,762.18 533,414.79 0.00 1,141.61 -261.25 6,026,662.54 533,408.28 0.00 1,241.48 -262.11 6,026,650.22 533,407.47 0.00 1,253.83 -269.05 6,026,553.56 533,400.97 3.00 1,350.72 -275.65 6,026,463.82 533,394.78 0.00 1,440.67 -282.95 6,026,364.60 533,387.93 0.00 1,540.14 -290.25 6,026,265.37 533,381.08 0.00 1,639.61 -293.24 6,026,224.63 533,378.27 0.00 1,680.45 -294.88 6,026,201.79 533,376.73 3.00 1,703.35 -297.38 6,026,166.09 533,374.40 0.00 1,739.13 -304.33 6,026,066.73 533,367.90 0.00 1,838.71 -311.27 6,025,967.37 533,361.41 0.00 1,938.29 -318.22 6,025,868.01 533,354.91 0.00 2,037.87 7/18/2019 7:07:48PM Page 5 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-22 Wellbore: MPU M-22 Design: MPU M-22 wp05 Planned Survey Measured Map Vertical Depth Inclination Azimuth Depth TVDss (usft) (^) (0) (usft) usft 6,664.07 95.25 184.00 3,809.11 3,750.51 Start Dir 301100' : 6664.07' MD, 3750.51TVD 6,700.00 94.17 184.03 3,806.16 3,747.56 6,765.95 92.20 184.10 3,802.50 3,743.90 End Dir : 6765.95' MD, 3743.9' TVD 2,203.33 6,800.00 92.20 184.10 3,801.19 3,742.59 6,900.00 92.20 184.10 3,797.36 3,738.76 6,966.18 92.20 184.10 3,794.83 3,736.23 Start Dir 30/100': 6966.18' MD, 3736.23TVD 7,000.00 93.21 184.10 3,793.23 3,734.63 7,013.01 93.60 184.10 3,792.46 3,733.86 End Dir : 7013.01' MD, 3733.86' ND 2,450.18 7,100.00 93.60 184.10 3,787.00 3,728.40 7,200.00 93.60 184.10 3,780.72 3,722.12 7,300.00 93.60 184.10 3,774.44 3,715.84 7,400.00 93.60 184.10 3,768.16 3,709.56 7,500.00 93.60 184.10 3,761.88 3,703.28 7,600.00 93.60 184.10 3,755.60 3,697.00 7,700.00 93.60 184.10 3,749.32 3,690.72 7,800.00 93.60 184.10 3,743.04 3,684.44 7,900.00 93.60 184.10 3,736.77 3,678.17 8,000.00 93.60 184.10 3,730.49 3,671.89 8,100.00 93.60 184.10 3,724.21 3,665.61 8,113.01 93.60 184.10 3,723.39 3,664.79 Start Dir 30/100': 8113.01' MD, 3664.79'TVD 8,200.00 96.20 184.34 3,715.96 3,657.36 8,231.31 97.13 184.43 3,712.33 3,653.73 End Dir : 8231.31' MD, 3653.73' TVD 533,247.99 8,300.00 97.13 184.43 3,703.80 3,645.20 8,400.00 97.13 184.43 3,691.38 3,632.78 8,495.00 97.13 184.43 3,679.58 3,620.98 Start Dir 301100' : 8495' MD, 3620.98'TVD 533,233.59 8,500.00 96.98 184.43 3,678.97 3,620.37 8,600.00 93.98 184.45 3,669.41 3,610.81 8,616.12 93.50 184.45 3,668.36 3,609.76 End Dir : 8616.12' MD, 3609.76' TVD 533,219.12 8,700.00 93.50 184.45 3,663.24 3,604.64 8,800.00 93.50 184.45 3,657.13 3,598.53 8,900.00 93.50 184.45 3,651.03 3,592.43 9,000.00 93.50 184.45 3,644.92 3,586.32 9,100.00 93.50 184.45 3,638.82 3,580.22 9,200.00 93.50 184.45 3,632.71 3,574.11 9,300.00 93.50 184.45 3,626.61 3,568.01 9,400.00 93.50 184.45 3,620.50 3,561.90 9,500.00 93.50 184.45 3,614.40 3,555.80 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU M-22 MPU M-22 Planned RKB @ 58.60usft MPU M-22 Planned RKB @ 58.60usft True Minimum Curvature 7/18/2019 7:07:48PM Page 6 COMPASS 5000.15 Build 91 Map Map +NI -S +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) 3,750.51 -2,084.24 -322.67 6,025,804.35 533,350.75 0.00 2,101.68 -2,119.96 -325.18 6,025,768.62 533,348.40 3.00 2,137.48 -2,185.64 -329.85 6,025,702.93 533,344.03 3.00 2,203.33 -2,219.58 -332.28 6,025,668.99 533,341.75 0.00 2,237.35 -2,319.25 -339.42 6,025,569.29 533,335.07 0.00 2,337.28 -2,385.21 -344.14 6,025,503.32 533,330.64 0.00 2,403.41 -2,418.91 -346.56 6,025,469.61 533,328.38 3.00 2,437.19 -2,431.86 -347.49 6,025,456.66 533,327.51 3.00 2,450.18 -2,518.46 -353.69 6,025,370.04 533,321.69 0.00 2,537.00 -2,618.01 -360.83 6,025,270.47 533,315.01 0.00 2,636.80 -2,717.55 -367.97 6,025,170.91 533,308.32 0.00 2,736.60 -2,817.10 -375.10 6,025,071.34 533,301.64 0.00 2,836.41 -2,916.65 -382.24 6,024,971.77 533,294.96 0.00 2,936.21 -3,016.20 -389.37 6,024,872.20 533,288.27 0.00 3,036.01 -3,115.74 -396.51 6,024,772.63 533,281.59 0.00 3,135.81 -3,215.29 -403.64 6,024,673.06 533,274.90 0.00 3,235.62 -3,314.84 -410.78 6,024,573.49 533,268.22 0.00 3,335.42 -3,414.39 -417.92 6,024,473.92 533,261.53 0.00 3,435.22 -3,513.93 -425.05 6,024,374.36 533,254.85 0.00 3,535.02 -3,526.88 -025.98 6,024,361.40 533,253.98 0.00 3,548.01 -3,613.31 -432.36 6,024,274.95 533,247.99 3.00 3,634.67 -3,644.32 -434.74 6,024,243.94 533,245.76 3.00 3,665.77 -3,712.28 -440.00 6,024,175.97 533,240.80 0.00 3,733.93 -3,811.20 -447.66 6,024,077.01 533,233.59 0.00 3,833.15 -3,905.19 -454.94 6,023,983.01 533,226.73 0.00 3,927.41 -3,910.14 -455.33 6,023,978.06 533,226.37 3.00 3,932.37 -4,009.37 463.03 6,023,878.80 533,219.12 3.00 4,031.90 -4,025.40 -064.28 6,023,862.76 533,217.94 3.00 4,047.99 4,108.88 -470.77 6,023,779.27 533,211.82 0.00 4,131.71 -4,208.39 -478.52 6,023,679.73 533,204.53 0.00 4,231.52 -4,307.90 486.26 6,023,580.20 533,197.24 0.00 4,331.33 -4,407.41 -494.01 6,023,480.66 533,189.95 0.00 4,431.14 4,506.93 -501.75 6,023,381.12 533,182.65 0.00 4,530.95 4,606.44 -509.50 6,023,281.59 533,175.36 0.00 4,630.76 -4,705.95 -517.24 6,023,182.05 533,168.07 0.00 4,730.57 -4,805.46 -524.98 6,023,082.51 533,160.77 0.00 4,830.38 -4,904.98 -532.73 6,022,982.98 533,153.48 0.00 4,930.19 7/18/2019 7:07:48PM Page 6 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-22 Wellbore: MPU M-22 Design: MPU M-22 wp05 Planned Survey Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU M-22 MPU M-22 Planned RKB @ 58.60usft MPU M-22 Planned RKB @ 58.60usft True Minimum Curvature 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) 3,549.69 9,600.00 93.50 184.45 3,608.29 3,549.69 -5,004.49 -540.47 6,022,883.44 533,146.19 0.00 5,030.00 9,616.12 93.50 184.45 3,607.31 3,548.71 -5,020.53 -541.72 6,022,867.39 533,145.01 0.00 5,046.09 Start Dir 30/100' : 9616.12' MD, 3548.71 TVD 9,700.00 90.98 184.46 3,604.03 3,545.43 -5,104.09 -548.23 6,022,783.82 533,138.88 3.00 5,129.90 9,763.23 89.09 184.47 3,603.99 3,545.39 -5,167.12 -553.15 6,022,720.77 533,134.25 3.00 5,193.12 End Dir : 9763.23' MD, 3545.39' TVD 9,800.00 89.09 184.47 3,604.58 3,545.98 -5,203.78 -556.01 6,022,684.10 533,131.55 0.00 5,229.88 9,900.00 89.09 184.47 3,606.17 3,547.57 -5,303.46 -563.80 6,022,584.40 533,124.22 0.00 5,329.87 9,976.41 89.09 184.47 3,607.39 3,548.79 -5,379.63 -569.74 6,022,508.21 533,118.62 0.00 5,406.27 Start Dir 301100' : 9976.41' MD, 3548.79'TVD 10,000.00 89.79 184.46 3,607.62 3,549.02 -5,403.14 -571.58 6,022,484.69 533,116.89 3.00 5,429.85 10,056.84 91.50 184.45 3,606.98 3,548.38 -5,459.81 -576.00 6,022,428.01 533,112.73 3.00 5,486.69 End Dir : 10056.84' MD, 3548.38' TVD 10,100.00 91.50 184.45 3,605.85 3,547.25 -5,502.82 -579.34 6,022,384.98 533,109.58 0.00 5,529.83 10,200.00 91.50 184.45 3,603.23 3,544.63 -5,602.49 -587.10 6,022,285.30 533,102.27 0.00 5,629.79 10,256.84 91.50 184.45 3,601.74 3,543.14 -5,659.14 -591.51 6,022,228.63 533,098.12 0.00 5,686.61 Start Dir 3°/100' : 10256.84' MD, 3543.14'TVD 10,300.00 90.45 183.69 3,601.00 3,542.40 -5,702.18 -594.57 6,022,185.58 533,095.25 3.00 5,729.77 10,400.00 88.03 181.92 3,602.33 3,543.73 -5,802.04 -599.46 6,022,085.71 533,090.82 3.00 5,829.72 10,448.47 86.86 181.06 3,604.49 3,545.89 -5,850.44 -600.72 6,022,037.30 533,089.78 3.00 5,878.10 End Dir : 10448.47' MD, 3545.89' TVD 10,500.00 86.86 181.06 3,607.32 3,548.72 -5,901.89 -601.67 6,021,985.86 533,089.06 0.00 5,929.48 10,600.00 86.86 181.06 3,612.80 3,554.20 -6,001.72 -603.52 6,021,886.03 533,087.66 0.00 6,029.20 10,700.00 86.86 181.06 3,618.29 3,559.69 -6,101.55 -605.37 6,021,786.20 533,086.26 0.00 6,128.92 10,800.00 86.86 181.06 3,623.78 3,565.18 -6,201.38 -607.22 6,021,686.37 533,084.86 0.00 6,228.64 10,816.66 86.86 181.06 3,624.69 3,566.09 -6,218.02 -607.53 6,021,669.74 533,084.63 0.00 6,245.25 Start Dir 301100': 10816.66' MD, 3566.09'TVD 10,900.00 89.11 182.14 3,627.62 3,569.02 -6,301.27 -609.86 6,021,586.49 533,082.68 3.00 6,328.46 11,000.00 91.82 183.43 3,626.81 3,568.21 -6,401.13 -614.72 6,021,486.61 533,078.27 3.00 6,428.42 11,015.96 92.25 183.64 3,626.25 3,567.65 -6,417.05 -615.70 6,021,470.69 533,077.36 3.00 6,444.37 End Dir : 11015.96' MD, 3567.65' TVD 11,100.00 92.25 183.64 3,622.95 3,564.35 -6,500.86 -621.03 6,021,386.87 533,072.41 0.00 6,528.34 11,200.00 92.25 183.64 3,619.02 3,560.42 -6,600.58 -627.38 6,021,287.13 533,066.52 0.00 6,628.26 11,300.00 92.25 183.64 3,615.09 3,556.49 -6,700.30 -633.72 6,021,187.39 533,060.63 0.00 6,728.19 11,400.00 92.25 183.64 3,611.17 3,552.57 -6,800.02 -640.06 6,021,087.65 533,054.73 0.00 6,828.11 11,500.00 9225 183.64 3,607.24 3,548.64 -6,899.74 -646.41 6,020,987.91 533,048.84 0.00 6,928.03 11,600.00 92.25 183.64 3,603.32 3,544.72 -6,999.47 -652.75 6,020,888.17 533,042.95 0.00 7,027.95 11,615.96 92.25 183.64 3,602.69 3,544.09 -7,015.38 -653.76 6,020,872.25 533,042.01 0.00 7,043.90 Start Dir 30/100' : 11615.96' MD, 3544.09TVD 11,700.00 89.74 183.90 3,601.23 3,542.63 -7,099.22 -659.28 6,020,788.40 533,036.87 3.00 7,127.92 11,765.96 87.77 184.10 3,602.66 3,544.06 -7,165.00 -663.88 6,020,722.61 533,032.57 3.00 7,193.86 End Dir : 11765.96' MD, 3544.06' TVD 11,800.00 87.77 184.10 3,603.98 3,545.38 -7,198.93 -666.31 6,020,688.67 533,030.29 0.00 7,227.87 11,900.00 87.77 184.10 3,607.87 3,549.27 -7,298.60 -673.45 6,020,588.98 533,023.61 0.00 7,327.80 7/182019 7:07:48PM Page 7 COMPASS 5000.15 Build 91 HALLPRURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M-22 Wellbore: MPU M-22 Design: MPU M-22 wp05 Planned Survey Measured Map Vertical Depth Inclination Azimuth Depth TVDss (usft) (0) (0) (usft) usft 11,916.75 87.77 184.10 3,608.52 3,549.92 Start Dir 3°/100' : 11916.75' MD, 3549.92'TVD 12,000.00 90.27 184.02 3,609.94 3,551.34 12,016.02 90.75 184.00 3,609.80 3,551.20 End Dir : 12016.02' MD, 3551.2' TVD -687.51 12,100.00 90.75 184.00 3,608.70 3,550.10 12,200.00 90.75 184.00 3,607.39 3,548.79 12,300.00 90.75 184.00 3,606.08 3,547.48 12,316.02 90.75 184.00 3,605.87 3,547.27 Start Dir 30/100' : 12316.02' MD, 3547.27'TVD 12,404.01 93.39 184.00 3,602.69 3,544.09 End Dir : 12404.01' MD, 3544.09' TVD 532,984.37 12,500.00 93.39 184.00 3,597.02 3,538.42 12,600.00 93.39 184.00 3,591.10 3,532.50 12,700.00 93.39 184.00 3,585.19 3,526.59 12,728.57 93.39 184.00 3,583.50 3,524.90 Start Dir 301100': 12728.57' MD, 3524.9'TVD 12,800.00 91.25 184.00 3,580.61 3,522.01 12,816.56 90.75 184.00 3,580.32 3,521.72 End Dir : 12816.56' MD, 3521.72' TVD 6,019,591.98 12,900.00 90.75 184.00 3,579.23 3,520.63 13,000.00 90.75 184.00 3,577.92 3,519.32 13,100.00 90.75 184.00 3,576.61 3,518.01 13,200.00 90.75 184.00 3,575.31 3,516.71 13,300.00 90.75 184.00 3,574.00 3,515.40 13,316.56 90.75 184.00 3,573.78 3,515.18 Start Dir 301100': 13316.56' MD, 3515.18'TVD 13,400.00 88.25 184.00 3,574.51 3,515.91 13,452.30 86.68 184.00 3,576.83 3,518.23 End Dir : 13452.3' MD, 3518.23' TVD 3.00 13,500.00 86.68 184.00 3,579.59 3,520.99 13,600.00 86.68 184.00 3,585.39 3,526.79 13,642.12 86.68 184.00 3,587.83 3,529.23 Start Dir 3-1100': 13642.12' MD, 3529.23'TVD 13,700.00 88.41 184.00 3,590.30 3,531.70 13,769.53 90.50 184.00 3,590.96 3,532.36 End Dir : 13769.53' MD, 3532.36' TVD -9,192.72 13,800.00 90.50 184.00 3,590.70 3,532.10 13,900.00 90.50 184.00 3,589.82 3,531.22 14,000.00 90.50 184.00 3,588.95 3,530.35 14,100.00 90.50 184.00 3,588.08 3,529.48 14,200.00 90.50 184.00 3,587.21 3,528.61 14,269.53 90.50 184.00 3,586.60 3,528.00 Total Depth : 14269.53' MD, 3528' TVD 532,869.00 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU M-22 MPU M-22 Planned RKB @ 58.60usft MPU M-22 Planned RKB @ 58.60usft True Minimum Curvature 7/1812019 7:07:48PM Page 8 COMPASS 5000.15 Build 91 Map Map +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) 3,549.92 -7,315.29 -674.65 6,020,572.28 533,022.49 0.00 7,344.53 -7,398.31 -680.53 6,020,489.24 533,016.98 3.00 7,427.76 -7,414.29 -681.65 6,020,473.26 533,015.93 3.00 7,443.78 -7,498.06 -687.51 6,020,389.47 533,010.45 0.00 7,527.76 -7,597.81 -694.49 6,020,289.70 533,003.93 0.00 7,627.75 -7,697.56 -701.46 6,020,189.94 532,997.41 0.00 7,727.74 -7,713.54 -702.58 6,020,173.95 532,996.36 0.00 7,743.76 -7,801.25 -708.71 6,020,086.22 532,990.62 3.00 7,831.68 -7,896.84 -715.40 6,019,990.62 532,984.37 0.00 7,927.50 -7,996.42 -722.36 6,019,891.01 532,977.86 0.00 8,027.33 -8,096.00 -729.32 6,019,791.41 532,971.35 0.00 8,127.15 -8,124.45 -731.31 6,019,762.95 532,969.49 0.00 8,155.67 -8,195.65 -736.29 6,019,691.75 532,964.83 3.00 8,227.04 -8,212.16 -737.45 6,019,675.22 532,963.75 3.00 8,243.60 -8,295.39 -743.27 6,019,591.98 532,958.31 0.00 8,327.03 -8,395.14 -750.24 6,019,492.21 532,951.79 0.00 8,427.02 -8,494.89 -757.22 6,019,392.44 532,945.27 0.00 8,527.02 -8,594.64 -764.19 6,019,292.67 532,938.74 0.00 8,627.01 -8,694.38 -771.17 6,019,192.90 532,932.22 0.00 8,727.00 -8,710.90 -772.32 6,019,176.38 532,931.14 0.00 8,743.56 -8,794.13 -778.14 6,019,093.14 532,925.70 3.00 8,826.99 -8,846.25 -781.79 6,019,041.01 532,922.29 3.00 8,879.23 -8,893.75 -785.11 6,018,993.49 532,919.18 0.00 8,926.85 -8,993.34 -792.07 6,018,893.88 532,912.67 0.00 9,026.69 -9,035.29 -795.01 6,018,851.93 532,909.92 0.00 9,068.73 -9,092.97 -799.04 6,018,794.23 532,906.15 3.00 9,126.56 -9,162.32 -803.89 6,018,724.87 532,901.62 3.00 9,196.08 -9,192.72 -806.02 6,018,694.46 532,899.63 0.00 9,226.55 -9,292.47 -812.99 6,018,594.69 532,893.10 0.00 9,326.55 -9,392.22 -819.97 6,018,494.92 532,886.58 0.00 9,426.54 -9,491.98 -826.94 6,018,395.14 532,880.06 0.00 9,526.54 -9,591.73 -833.92 6,018,295.37 532,873.54 0.00 9,626.54 -9,661.09 -838.77 6,018,226.00 532,869.00 0.00 9,696.06 7/1812019 7:07:48PM Page 8 COMPASS 5000.15 Build 91 Halliburton 1-1.x► L L I B U R TO N Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-22 Company: Hilcorp Alaska, LLC TVD Reference: MPU M-22 Planned RKB @ 58.60usft Project: Milne Point MD Reference: MPU M-22 Planned RKB @ 58.60usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-22 Survey Calculation Method: Minimum Curvature Wellbore: MPU M-22 Design: MPU M-22 wp05 Targets Target Name - hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting - Shape (°) (°) (usft) (usft) (usft) (usft) (usft) M-22 wp05 CPI 0.00 0.00 3,889.62 -1,238.56 -262.11 6,026,650.22 533,407.47 - plan hits target center - Point M-22 wp05 CP8 0.00 0.00 3,573.78 -8,710.90 -772.32 6,019,176.38 532,931.14 - plan hits target center - Point M-22 wp05 CP4 0.00 0.00 3,607.31 -5,020.54 -541.72 6,022,867.39 533,145.01 - plan hits target center - Point M-22 wp05 CP7 0.00 0.00 3,605.87 -7,713.54 -702.58 6,020,173.95 532,996.36 - plan hits target center - Point M-22 wp05 Toe 0.00 0.00 3,586.60 -9,661.09 -838.77 6,018,226.00 532,869.00 - plan hits target center - Point M-22 wp05 CP3 0.00 0.00 3,723.39 -3,526.89 -425.98 6,024,361.40 533,253.98 - plan hits target center - Point M-22 wp05 CP2 0.00 0.00 3,809.11 -2,084.25 -322.67 6,025,804.35 533,350.75 - plan hits target center - Point M-22 wp05 Heel -1.45 183.85 3,900.42 -477.94 -208.14 6,027,411.00 533,458.00 - plan hits target center - Circle (radius 30.00) M-22 wp05 CP5 0.00 0.00 3,601.74 -5,659.14 -591.51 6,022,228.63 533,098.12 - plan hits target center - Point M-22 wp05 CP6 0.00 0.00 3,602.69 -7,015.39 -653.76 6,020,872.25 533,042.01 - plan hits target center - Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 14,269.53 3,586.60 6 5/8" x 8 1/2" 6-518 8-1/2 5,048.87 3,900.42 9 5/8" x 12 1/4" 9-5/8 12-1/4 7/1812019 7:07: 48PM Page 9 COMPASS 5000.15 Build 91 Plan Annotations Measured Vertical Halliburton H A L L I B U R TO N Depth Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M-22 Company: Hilcorp Alaska, LLC TVD Reference: MPU M-22 Planned RKB @ 58.60usft Project: Milne Point MD Reference: MPU M-22 Planned RKB @ 58.60usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M-22 Survey Calculation Method: Minimum Curvature Wellbore: MPU M-22 -8.26 End Dir : 1086.43' MD, 995.82' TVD Design: MPU M-22 wp05 2,166.12 812.25 Plan Annotations Measured Vertical Local Coordinates Depth Depth +NIS +EI -W (usft) (usft) (usft) (usft) Comment 350.00 350.00 0.00 0.00 Start Dir 401100' : 350' MD, 291.4'TVD 1,086.43 1,054.41 184.99 -8.26 End Dir : 1086.43' MD, 995.82' TVD 2,363.19 2,166.12 812.25 -36.25 Start Dir 50/100': 2363.19' MD, 2107.5l'TVD 4,648.87 3,865.56 -80.21 -183.67 End Dir : 4648.87' MD, 3806.96' TVD - start ESP tangent 5,048.87 3,900.42 -477.94 -208.14 Start Dir 50/100': 5048.87' MD, 3841.82'TVD 5,083.77 3,902.98 -512.66 -210.49 End Dir : 5083.77' MD, 3844.38' TVD 5,198.82 3,909.80 -627.20 -218.95 Start Dir 30/100' : 5198.82' MD, 3851.2'TVD 5,412.37 3,910.55 -840.08 -234.25 End Dir : 5412.37' MD, 3851.95' TVD 5,812.37 3,889.62 -1,238.56 -262.11 Start Dir 30/100': 5812.37' MD, 3831.02'TVD 5,909.56 3,882.07 -1,335.20 -269.05 End Dir : 5909.56' MD, 3823.47' TVD 6,241.06 3,847.95 -1,664.05 -293.24 Start Dir 301100': 6241.06' MD, 3789.35'TVD 6,264.07 3,845.71 -1,686.89 -294.88 End Dir : 6264.07' MD, 3787.11' TVD 6,664.07 3,809.11 -2,084.24 -322.67 Start Dir 30/100': 6664.07' MD, 3750.51'TVD 6,765.95 3,802.50 -2,185.64 -329.85 End Dir : 6765.95' MD, 3743.9' TVD 6,966.18 3,794.83 -2,385.21 -344.14 Start Dir 301100': 6966.18' MD, 3736.23'TVD 7,013.01 3,792.46 -2,431.86 -347.49 End Dir : 7013.01' MD, 3733.86' TVD 8,113.01 3,723.39 -3,526.88 -425.98 Start Dir 30/100': 8113.01' MD, 3664.797VD 8,231.31 3,712.33 -3,644.32 -434.74 End Dir : 8231.31' MD, 3653.73' TVD 8,495.00 3,679.58 -3,905.19 454.94 Start Dir 30/100r: 8495' MD, 3620.98'TVD 8,616.12 3,668.36 -4,025.40 -464.28 End Dir : 8616.12' MD, 3609.76' TVD 9,616.12 3,607.31 -5,020.53 -541.72 Start Dir 3-/100': 9616.12' MD, 3548.71'TVD 9,763.23 3,603.99 -5,167.12 -553.15 End Dir : 9763.23' MD, 3545.39' TVD 9,976.41 3,607.39 -5,379.63 -569.74 Start Dir 30/100': 9976.41' MD, 3548.79'TVD 10,056.84 3,606.98 -5,459.81 -576.00 End Dir : 10056.84' MD, 3548.38' TVD 10,256.84 3,601.74 -5,659.14 -591.51 Start Dir 30/100': 10256.84' MD, 3543.14'TVD 10,448.47 3,604.49 -5,850.44 -600.72 End Dir : 10448.47' MD, 3545.89' TVD 10,816.66 3,624.69 -6,218.02 -607.53 Start Dir 30/100': 10816.66' MD, 3566.09'TVD 11,015.96 3,626.25 -6,417.05 -615.70 End Dir : 11015.96' MD, 3567.65' TVD 11,615.96 3,602.69 -7,015.38 -653.76 Start Dir 30/100' : 11615.96' MD, 3544.091TVD 11,765.96 3,602.66 -7,165.00 -663.88 End Dir : 11765.96' MD, 3544.06' TVD 11,916.75 3,608.52 -7,315.29 -674.65 Start Dir 30/100'; 11916.75' MD, 3549.92'TVD 12,016.02 3,609.80 -7,414.29 -681.65 End Dir : 12016.02' MD, 3551.2' TVD 12,316.02 3,605.87 -7,713.54 -702.58 Start Dir 30/100' : 12316.02' MD, 3547.27'TVD 12,404.01 3,602.69 -7,801.25 -708.71 End Dir : 12404.01' MD, 3544.09' TVD 12,728.57 3,583.50 -8,124.45 -731.31 Start Dir 30/100': 12728.57' MD, 3524.9'TVD 12,816.56 3,580.32 -8,212.16 -737.45 End Dir : 12816.56' MD, 3521.72' TVD 13,316.56 3,573.78 -8,710.90 -772.32 Start Dir 30/100' : 13316.56' MD, 3515.18'TVD 13,452.30 3,576.83 -8,846.25 -781.79 End Dir : 13452.3' MD, 3518.23' TVD 13,642.12 3,587.83 -9,035.29 -795.01 Start Dir 30/100': 13642.12' MD, 3529.23'TVD 13,769.53 3,590.96 -9,162.32 -803.89 End Dir : 13769.53' MD, 3532.36' TVD 14,269.53 3,586.60 -9,661.09 -838.77 Total Depth : 14269.53' MD, 3528' TVD 7/182019 7:07:48PM Page 10 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-22 MPU M-22 MPU M-22 wp05 Sperry Drilling Services Clearance Summary Anticollision Report 18 July, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-22 - MPU M-22 - MPU M-22 wp05 Well Coordinates: 6,027,889.83 N, 533,663.95 E (70" 29' 14.01" N, 149" 43' 29.46" W) Datum Height: MPU M-22 Planned RKB @ 58.60usft Scan Range: 33.70 to 5,048.87 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: Scan Type: 25.00 HALLIBURTON Sperry Drilling Services Hilcorp Alaska, LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU M-22 - MPU M-22 wp05 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-22 - MPU M-22 - MPU M-22 wp05 Scan Range: 33.70 to 5,048.87 usft. Measured Depth. Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft EX Simpson Lagoon M Pt Moose Pad MPU M-03 - MPU M-03 - MPU M-03 610.32 286.70 610.32 281.96 611.62 60.590 Centre Distance Pass - MPU M-03 - MPU M-03 - MPU M-03 633.70 286.61 633.70 281.91 633.26 58.577 Ellipse Separation Pass - MPU M-03 - MPU M-03 - MPU M-03 933.70 330.49 933.70 323.50 869.93 47.228 Clearance Factor Pass - MPU M-04 - MPU M-04 - MPU M-04 621.06 262.06 621.06 257.35 628.75 55.403 Centre Distance Pass - MPU M-04 - MPU M-04 - MPU M-04 633.70 262.11 633.70 257.29 640.19 54.381 Ellipse Separation Pass - MPU M-04 - MPU M-04 - MPU M-04 908.70 298.19 908.70 291.35 871.25 43.597 Clearance Factor Pass - MPU M-16 - MPU M-16 - MPU M-16 33.70 138.25 33.70 137.33 34.18 151.610 Centre Distance Pass - MPU M-16 - MPU M-16 - MPU M-16 358.70 139.09 358.70 136.19 359.35 48.064 Ellipse Separation Pass - MPU M-16 - MPU M-16 - MPU M-16 608.70 167.24 608.70 162.60 597.08 35.990 Clearance Factor Pass - MPU M-18 - MPU M-18 - MPU M-18 33.70 138.00 33.70 137.09 34.42 151.340 Centre Distance Pass - MPU M-18 - MPU M-18 - MPU M-18 108.70 138.21 108.70 136.90 108.45 105.232 Ellipse Separation Pass - MPU M-18 - MPU M-18 - MPU M-18 608.70 167.32 606.70 162.53 600.39 34.953 Clearance Factor Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 33.70 138.00 33.70 137.09 34.42 151.340 Centre Distance Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 108.70 138.21 108.70 136.90 108.45 105.232 Ellipse Separation Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 608.70 167.32 608.70 162.53 600.39 34.953 Clearance Factor Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 33.70 138.00 33.70 137.09 34.42 151.340 Centre Distance Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 108.70 136.21 108.70 136.90 108.45 105.232 Ellipse Separation Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 608.70 167.32 608.70 162.53 600.39 34.953 Clearance Factor Pass - MPU M-20 - MPU M-20 - MPU M-20 33.70 179.73 33.70 178.82 34.23 197.101 Centre Distance Pass - MPU M-20 - MPU M-20 - MPU M-20 383.70 179.96 383.70 176.90 383.27 58.757 Ellipse Separation Pass - MPU M-20 - MPU M-20 - MPU M-20 1,583.70 360.49 1,583.70 346.08 1,531.11 25.022 Clearance Factor Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB1 33.70 179.73 33.70 178.62 34.23 197.101 Centre Distance Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB1 383.70 179.96 383.70 176.90 383.27 58.757 Ellipse Separation Pass - MPU M-20 - MPU M-20PB1 - MPU M-20PB1 1,583.70 360.49 1,583.70 346.08 1,531.11 25.022 Clearance Factor Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 33.70 179.73 33.70 178.82 34.23 197.101 Centre Distance Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 383.70 179.96 383.70 176.90 383.27 58.757 Ellipse Separation Pass - 18 July, 2019 - 19:09 Page 2 of 7 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-22 - MPU M-22 wp05 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-22 - MPU M-22 - MPU M-22 wp05 Scan Range: 33.70 to 5,048.87 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Hilcorp Alaska, LLC Milne Point Plan: MPU M -19i - MPU M -19i - Jeb Stuart - MPU M-1 Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Pass - Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name -Wellbore Name - Design (usft) (usft) (usft) (usft) usft 41.337 Clearance Factor Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 1,583.70 360.49 1,583.70 346.08 1,531.11 25.022 Clearance Factor Pass - Plan: Kup S1 Deep KOP - Slot 17 - Wellbore #1 - Kup 333.70 172.42 333.70 169.35 333.80 56.297 Centre Distance Pass - Plan: Kup S1 Deep KOP - Slot 17 - Wellbore #1 - Kup 358.70 172.44 358.70 169.19 358.80 53.190 Ellipse Separation Pass - Plan: Kup S1 Deep KOP - Slot 17 - Wellbore #1 - Kup 783.70 222.09 783.70 215.77 777.20 35.118 Clearance Factor Pass - Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku 261.37 216.46 261.37 215.94 261.47 86.512 Centre Distance Pass - Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku 308.70 218.56 308.70 215.70 307.32 76.370 Ellipse Separation Pass - Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku 763.70 302.27 783.70 294.70 722.24 39.894 Clearance Factor Pass - Plan: MPU M -15i - M -15i - M -15i wp04 333.70 194.66 333.70 191.42 333.50 60.032 Centre Distance Pass - Plan: MPU M -15i - M -15i - M -15i wp04 358.70 194.66 358.70 191.25 358.50 56.643 Ellipse Separation Pass - Plan: MPU M -15i - M -15i - M -15i wp04 708.70 236.73 708.70 230.63 683.07 38.807 Clearance Factor Pass - Plan: MPU M-151 P2 - M-15 Phase 2 - M -15i P2 wp02 333.70 218.54 333.70 215.05 333.80 62.532 Centre Distance Pass - Plan: MPU M-1 5i P2 - M-15 Phase 2 - M -15i P2 wp02 358.70 218.56 358.70 214.89 356.80 59.486 Ellipse Separation Pass - Plan: MPU M-1 5i P2 - M-15 Phase 2 - M-151 P2 wp02 663.70 262.85 683.70 256.99 648.51 44.863 Clearance Factor Pass - Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w 333.70 153.13 333.70 149.63 333.80 43.814 Centre Distance Pass - Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w 358.70 153.15 358.70 149.47 358.80 41.682 Ellipse Separation Pass - Plan: MPU M-16 P2 - M-16 Phase 2 - MPU M-16 P2 w 583.70 177.35 583.70 172.12 567.08 33.909 Clearance Factor Pass - Plan: MPU M-1 7i - MPU M-171 - MPU M-17 wp04 333.70 127.78 333.70 124.72 333.80 41.723 Centre Distance Pass - Plan: MPU M -17i - MPU M-1 7i - MPU M-17 wp04 358.70 127.81 358.70 124.57 358.80 39.422 Ellipse Separation Pass - Plan: MPU MAT - MPU M -17i - MPU M-17 wp04 583.70 152.80 583.70 147.97 571.67 31.660 Clearance Factor _ Pass - Plan: MPU M-1 T P2 - M112 Phase 2 - M-1 7i P2 wp02 261.37 123.84 261.37 120.87 261.47 41.608 Centre Distance Pass - Plan: MPU M-171 P2 - M112 Phase 2 - M-1 7i P2 wp02 263.70 123.85 283.70 120.71 283.56 39.503 Ellipse Separation Pass - Plan: MPU M-1 7i P2 - M112 Phase 2 - M -17i P2 wp02 506.70 144.70 508.70 140.00 493.59 30.806 Clearance Factor Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 283.70 153.07 283.70 150.38 279.80 56.906 Centre Distance Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 308.70 153.17 308.70 150.31 303.50 53.552 Ellipse Separation Pass - Plan: MPU M-18 P2 - M-18 P2 - M-18 P2 wp03 608.70 191.77 608.70 186.83 579.70 38.791 Clearance Factor Pass - Plan: MPU M -19i - MPU M -19i - Jeb Stuart - MPU M-1 333.70 194.92 333.70 191.67 329.80 63.942 Centre Distance Pass - Plan: MPU M -19i - MPU M -19i - Jeb Stuart - MPU M-1 358.70 194.93 358.70 191.70 354.80 60.397 Ellipse Separation Pass - Plan: MPU M-1 9i - MPU M -19i - Jeb Stuart - MPU M-1 708.70 233.93 706.70 228.27 682.78 41.337 Clearance Factor Pass - Plan: MPU M -19i P2 - Slot 27 - M -19i P2 - M -19i P2 wt 283.70 127.44 283.70 124.75 279.80 47.377 Centre Distance Pass - Plan: MPU M -19i P2 - Slot 27 - M-1 9i P2 - M-1 9i P2 wt 308.70 127.59 308.70 124.73 303.26 44.613 Ellipse Separation Pass - Plan: MPU M -19i P2 - Slot 27 - M -19i P2 - M-1 9i P2 wl 533.70 154.01 533.70 149.59 511.38 34.825 Clearance Factor Pass - 18 July, 2019 - 19:09 Page 3 of 7 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-22 - MPU M-22 wp05 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-22 - MPU M-22 - MPU M-22 wp05 Scan Range: 33.70 to 5,048.87 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Hilcorp Alaska, LLC Milne Point 18 July, 2019 - 19:09 Page 4 of COMPASS Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 333.70 210.07 333.70 206.58 333.80 60.107 Centre Distance Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 483.70 210.46 483.70 205.90 483.61 46.117 Ellipse Separation Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 5,048.87 1,455.73 5,048.87 1,400.23 4,982.42 26.230 Clearance Factor Pass - Plan: MPU M-21 i - M-21 i - M -21i wp02 333.70 89.88 333.70 86.82 333.80 29.347 Centre Distance Pass - Plan: MPU M-21 i - M-21 i - M -21i wp02 458.70 90.18 458.70 86.22 458.70 22.807 Ellipse Separation Pass - Plan: MPU M-21 i - M-21 i - M-21 i wp02 5,048.87 762.78 5,048.87 709.33 4,789.75 14.272 Clearance Factor Pass - Plan: MPU M -21i P2 - M-21 i Phase 2 - M-21 i P2 wp02 333.70 60.06 333.70 56.56 333.80 17.184 Centre Distance Pass - Plan: MPU M-21 i P2 - M-21 i Phase 2 - M-21 i P2 wp02 458.70 60.39 458.70 56.01 458.67 13.771 Ellipse Separation Pass - Plan: MPU M-211 P2 - M-211 Phase 2 - M-21 i P2 wp02 5,048.87 438.84 5,048.87 386.47 4,548.51 8.379 Clearance Factor Pass - Plan: MPU M-22 P2 - M-22 Phase 2 - M-22 P2 wp02 351.15 29.95 351.15 26.33 351.24 8.274 Centre Distance Pass - Plan: MPU M-22 P2 - M-22 Phase 2 - M-22 P2 wp02 408.70 30.21 408.70 26.18 408.48 7.497 Ellipse Separation Pass - Plan: MPU M-22 P2 - M-22 Phase 2 - M-22 P2 wp02 608.70 35.48 608.70 30.03 607.41 6.512 Clearance Factor Pass - Plan: MPU M -23i - Slot 22 - M -23i - M -23i wp03 439.43 60.02 439.43 56.42 439.47 16.652 Centre Distance Pass - Plan: MPU M -23i - Slot 22 - M -23i - M -23i wp03 483.70 60.12 483.70 56.20 483.61 15.341 Ellipse Separation Pass - Plan: MPU M -23i - Slot 22 - M -23i - M -23i wp03 708.70 70.13 708.70 64.58 707.00 12.648 Clearance Factor Pass - Plan: MPU M -23i P2 - Slot20 - M -23i Phase 2 - M -23i F 455.06 89.65 455.06 85.49 455.01 20.606 Centre Distance Pass - Plan: MPU M -23i P2 - Slot20 - M-231 Phase 2 - M -23i F 483.70 89.92 483.70 85.35 483.29 19.708 Ellipse Separation Pass - Plan: MPU M -23i P2 - Slot20 - M -23i Phase 2 - M -23i F 758.70 103.57 758.70 97.03 750.47 15.828 Clearance Factor Pass - Plan: MPU M-24 - Slot 16 - M-24 - M-24 wp03 - Lower 384.14 150.05 384.14 146.63 384.08 43.843 Centre Distance Pass - Plan: MPU M-24 - Slot 16 - M-24 - M-24 wp03 - Lower 408.70 150.12 408.70 146.51 407.70 41.598 Ellipse Separation Pass - Plan: MPU M-24 - Slot 16 - M-24 - M-24 wp03 - Lower 2,208.70 552.69 2,208.70 529.46 2,092.14 23.795 Clearance Factor Pass - Plan: MPU M-24 P2 - Slot 14 - M-24 Phase 2 - M -24P, 311.37 179.97 311.37 176.63 311.47 53.966 Centre Distance Pass - Plan: MPU M-24 P2 - Slot 14 - M-24 Phase 2 - M -24P: 358.70 180.07 358.70 176.40 357.49 49.080 Ellipse Separation Pass - Plan: MPU M-24 P2 - Slot 14 - M-24 Phase 2 - M -24P: 833.70 216.12 833.70 209.09 800.00 30.761 Clearance Factor Pass - Plan: MPU M -25i - Slot 18 - M -25i - M -25i wp03 481.83 119.81 481.83 115.69 481.74 29.092 Centre Distance Pass - Plan: MPU M-251- Slot 18 - M -25i - M -25i wp03 533.70 119.97 533.70 115.48 532.85 26.748 Ellipse Separation Pass - Plan: MPU M -25i - Slot 18 - M -25i - M -25i wp03 758.70 137.40 758.70 131.33 741.19 22.629 Clearance Factor Pass - Plan: MPU M-251 P2 - Slot 12 - M -25i Phase 2 - M -25i 261.37 209.97 261.37 206.99 261.47 70.545 Centre Distance Pass - Plan: MPU M -25i P2 - Slot 12 - M-251 Phase 2 - M -25i 308.70 210.07 308.70 206.76 307.28 63.468 Ellipse Separation Pass - Plan: MPU M -25i P2 - Slot 12 - M-251 Phase 2 - M -25i 933.70 280.59 933.70 272.92 860.11 36.548 Clearance Factor Pass - 18 July, 2019 - 19:09 Page 4 of COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-22 - MPU M-22 wp05 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-22 - MPU M-22 - MPU M-22 wp05 Scan Range: 33.70 to 5,048.87 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Hileorp Alaska, LLC Milne Point RHAMWA.. . r. .ui From To Survey/Plan SurveyTool (usft) (usft) 33.70 5,048.87 MPU M-22 wp05 2_MWD+IFR2+MS+Sag 5,048.87 14,269.53 MPU M-22 wp05 2_MWD+IFR2+MS+Sag Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 18 July, 2019 - 19:09 Page 5 of 7 COMPASS Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - M-57 333.70 149.88 333.70 146.82 323.10 48.934 Centre Distance Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - M-57 458.70 150.15 458.70 146.19 448.00 37.970 Ellipse Separation Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - M-57 858.70 178.49 858.70 171.65 835.78 26.093 Clearance Factor Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - M -XX - m 333.70 29.80 333.70 26.74 333.80 9.727 Centre Distance Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - M -XX - H 433.70 30.04 433.70 26.27 433.75 7.953 Ellipse Separation Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - M -XX - H 533.70 32.66 533.70 28.17 533.30 7.274 Clearance Factor Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup Ni 1,314.01 70.78 1,314.01 58.50 1,319.91 5.765 Ellipse Separation Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 1,333.70 71.06 1,333.70 58.70 1,338.36 5.751 Clearance Factor Pass - Slot 33 - Placeholder - Slot 33 - Placeholder - Slot 33 - 333.70 172.49 333.70 169.42 296.10 56.326 Centre Distance Pass - Slot 33 - Placeholder - Slot 33 - Placeholder - Slot 33 - 356.70 172.51 358.70 169.27 321.10 53218 Ellipse Separation Pass - Slot 33 - Placeholder - Slot 33 - Placeholder - Slot 33 - 783.70 225.58 783.70 219.27 739.50 35.796 Clearance Factor Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 333.70 240.04 333.70 236.98 296.10 78.387 Centre Distance Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 483.70 240.46 483.70 236.33 445.91 58.208 Ellipse Separation Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 1,033.70 295.62 1,033.70 287.45 970.43 36.151 Clearance Factor Pass - RHAMWA.. . r. .ui From To Survey/Plan SurveyTool (usft) (usft) 33.70 5,048.87 MPU M-22 wp05 2_MWD+IFR2+MS+Sag 5,048.87 14,269.53 MPU M-22 wp05 2_MWD+IFR2+MS+Sag Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 18 July, 2019 - 19:09 Page 5 of 7 COMPASS HALLIBURTON Project: Milne Point REFERENCE INFORMATION WELLDEfA1LSTIan:MPUM-22 NAD 1927(NADCON COWS) Alaska Zone() Cooroinate (N/E) Reference: Well Plan: MPU M-22, True Noeh Vertical (TVD) Refereme: MPU M-22 Planned RKB @ 56.60wfl Measured Depth Re%mnm MPU M -M Planned RKB Q 56.60usfl Cakuladpn Memos Minimum Curvature Site: M Pt Moose Pad Sperry 0riflin' Well: Plan: MPU M-22 Wellbore: MPU M-22 Ground Level: 24.90 +N/ -S +FJ -W gi de 0.00 0.00 Northing Fasting 9' 14.01 Lon 6 W 602]889.81 53663.95 70°29'14.012N 149"43'29.456W Plan: MPU M-22 wp05 SURVEY PROGRAM NO GLOBAL FILTER: Using user defined selection 8 filtering criteria Date: 2016-06-22T00:00:00 Validated: Yes Version: 1 33.70 To 14269.53 Ladder/S.F. Plots Depth From Depth To Survey/Plan 2 MWD+IFR2+MS+Sag 33.70 5048.87 MPU M-22 wp05 (MPU M-22) CASING DETAILS TVD TVDSS MD Si7.e Name SH (1 of 2) 5048.87 14269.53 MPU M-22 Wp05(MPU M-22) 2_MWD+IFR2+MS+Sag 3900.42 3841,82 5048.87 9-5/8 9 5/8" x 12 1/4" 3586,60 3528.00 14269.53 6-5/8 6 5/8" x 8 1/2" y X150.00 - -- yIV A � i p 5120.00 ,5120.00- rD C 0 M -23i m 90.00 2 WP03 m NM -21i v p02 up ro o ry M-211 60.00— wp02 i C) M -23i 03 O 30.00 .- -IRA M-22 P2 p02 M-Xw02 I!. 0.001 0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675 4950 5225 Measured Depth (550 usft/in) I O i> 3.00 i I I LL i C 2.00 - Collision Risk Procedures Req. _ - i I. Collision Avoidance Req. 1.00 '_ No -Go Zone - Stop Drillin I NOERRORS o.00 0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675 4950 5225 Measured Depth (550 usft/in) Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M-22 MPU M-22 MPU M-22 wp05 Sperry Drilling Services Clearance Summary Anticollision Report 18 July, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-22 - MPU M-22 - MPU M-22 wp05 Well Coordinates: 6,027,889.83 N, 533,663.95 E (70° 29'14.01" N, 149° 43'29.46" W) Datum Height: MPU M-22 Planned RKB @ 58.60usft Scan Range: 5,048.87 to 14,269.53 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: • • - Scan Type: 25.00 HALLIBURTON Sperry Drilling Services 18 July, 2019 - 19:14 Page 2 of 5 COMPASS Hilcorp Alaska, LLC H ALL I B U RTO N Milne Point Anticollision Report for Plan: MPU M-22 - MPU M-22 wp05 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-22 - MPU M-22 - MPU M-22 wp05 Scan Range: 5,048.87 to 14,269.53 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft EX Simpson Lagoon SIMPSON LAGOON 32-14 - SIMPSON LAGOON 32-1 6,541.76 677.31 6,541.78 605.01 3,758.15 9.368 Centre Distance Pass - SIMPSON LAGOON 32-14 - SIMPSON LAGOON 32-1 6,548.87 677.34 6,548.87 604.92 3,760.31 9.352 Ellipse Separation Pass - SIMPSON LAGOON 32-14 - SIMPSON LAGOON 32-1 6,623.87 681.72 6,623.87 608.13 3,784.04 9.264 Clearance Factor Pass - SIMPSON LAGOON 32-14 - SIMPSON LAGOON 32-1 6,541.78 677.31 6,541.78 605.01 3,758.15 9.368 Centre Distance Pass - SIMPSON LAGOON 32-14 - SIMPSON LAGOON 32-1 6,548.87 677.34 6,548.87 604.92 3,760.31 9.352 Ellipse Separation Pass - SIMPSON LAGOON 32-14 - SIMPSON LAGOON 32-1 6,623.87 661.72 6,623.87 606.13 3,784.04 9.264 Clearance Factor Pass - SIMPSON LAGOON 32-14 - SIMPSON LAGOON 32-1 6,541.78 677.31 6,541.78 604.75 3,758.15 9.334 Centre Distance Pass - SIMPSON LAGOON 32-14 - SIMPSON LAGOON 32-1 6,548.87 677.34 6,548.87 604.65 3,760.31 9.318 Ellipse Separation Pass - SIMPSON LAGOON 32-14 - SIMPSON LAGOON 32-' 6,623.87 681.72 6,623.87 607.86 3,764.04 9.231 Clearance Factor Pass - M Pt Moose Pad MPU M-03 - MPU M-03 - MPU M-03 8,865.07 239.64 8,865.07 124.32 6,103.72 2.078 Centre Distance Pass - MPU M-03 - MPU M-03 - MPU M-03 8,873.87 239.76 8,873.87 124.17 6,108.33 2.074 Clearance Factor Pass - MPU M-04 - MPU M-04 - MPU M-04 5,048.87 1,241.63 5,048.87 1,227.37 2,706.00 87.103 Ellipse Separation Pass - MPU M-04 - MPU M-04 - MPU M-04 5,723.87 1,486.93 5,723.87 1,464.93 2,706.00 67.600 Clearance Factor Pass - Plan: Kup S1 Deep KOP - Slot 17 - Wellbore #1 - Kup 6,628.72 1,242.01 6,628.72 1,184.71 4,119.01 21.673 Centre Distance Pass - Plan: Kup S1 Deep KOP - Slot 17 - Wellbore #1 - Kup 6,673.67 1,242.54 6,673.87 1,183.85 4,146.67 21.172 Ellipse Separation Pass - Plan: Kup S1 Deep KOP - Slot 17 - Wellbore #1 - Kup 7,448.87 1,407.26 7,448.87 1,328.69 4,639.63 17.910 Clearance Factor Pass - Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku 9,727.93 399.62 9,727.93 247.23 6,567.41 2.622 Centre Distance Pass - Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku 9,798.87 400.95 9,798.87 245.64 6,631.35 2.582 Ellipse Separation Pass - Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku 9,873.87 404.88 9,873.87 247.38 6,699.11 2.571 Clearance Factor Pass - Plan: MPU M-1 9i - MPU M -19i - Jeb Stuart - MPU M-1 8,577.81 1,490.18 8,577.81 1,388.25 5,413.33 14.619 Centre Distance Pass - Plan: MPU M -19i - MPU M-1 9i - Jeb Stuart - MPU M-1 8,798.87 1,495.91 8,798.87 1,384.79 5,611.40 13.462 Ellipse Separation Pass - Plan: MPU M -19i - MPU M-1 9i -Jeb Stuart- MPU M-1 8,873.87 1,499.36 8,873.87 1,385.15 5,676.65 13.126 Clearance Factor Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 5,048.87 1,455.73 5,048.87 1,400.23 4,982.42 26.230 Ellipse Separation Pass - Plan: MPU M-20 P2 - M-20 Phase 2 - M-20 P2 wp03 6,648.87 1,499.88 6,648.67 1,413.27 6,569.74 17.319 Clearance Factor Pass - Plan: MPU M -21i - M-21 i - M-21 i wp02 5,048.67 762.78 5,048.87 709.33 4,789.75 14.272 Centre Distance Pass - Plan: MPU M-21 i - M-21 i - M-21 i wp02 14,248.87 849.11 14,248.87 571.47 13,966.19 3.058 Clearance Factor Pass - 18 July, 2019 - 19:14 Page 2 of 5 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M-22 - MPU M-22 wp05 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-22 - MPU M-22 - MPU M-22 wp05 Scan Range: 5,048.87 to 14,269.53 usft. Measured Depth. Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Hileorp Alaska, LLC Milne Point From To Survey/Plan Survey Tool (usft) (usft) 33.70 5,048.87 MPU M-22 wp05 2_MWD+IFR2+MS+Sag 5,048.87 14,269.53 MPU M-22 wp05 2_MWD+IFR2+MS+Sag Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles /(Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 18 July, 2019 - 19:14 Page 3 of 5 COMPASS Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name -Wellbore Name - Design (usft) (usft) (usft) (usft) usft Plan: MPU M -21i P2 - M-21 i Phase 2 - M-21 i P2 wp02 5,048.87 438.84 5,048.87 386.47 4,548.51 8.379 Ellipse Separation Pass - Plan: MPU M-21 i P2 - M-21 i Phase 2 - M-21 i P2 wp02 14,269.53 931.66 14,269.53 645.50 13,733.96 3.256 Clearance Factor Pass - Plan: MPU M -23i - Slot 22 - M -23i - M -23i wp03 10,296.57 786.70 10,296.57 631.16 10,024.03 5.058 Centre Distance Pass - Plan: MPU M -23i - Slot 22 - M-231 - M -23i wp03 13,548.67 806.14 13,548.87 561.80 13,256.21 3.299 Ellipse Separation Pass - Plan: MPU M -23i - Slot 22 - M-231 - M-231 wp03 13,573.87 806.86 13,573.87 562.29 13,256.21 3.299 Clearance Factor Pass - Plan: MPU M -23i P2 - Slot20 - M -23i Phase 2 - M -23i F 14,269.53 896.12 14,269.53 613.11 14,210.97 3.166 Clearance Factor Pass - Plan: MPU M-24 - Slot 16 - M-24 - M-24 wp03 - Lower 5,048.87 1,483.39 5,048.87 1,430.88 5,039.62 28.247 Ellipse Separation Pass - Plan: MPU M-24 - Slot 16 - M-24 - M-24 wp03 - Lower 5,298.87 1,498.72 5,298.87 1,445.07 5,288.90 27.935 Clearance Factor Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - M-57 5,048.87 1,470.98 5,048.87 1,435.42 3,532.61 41.368 Clearance Factor Pass - Plan: MPU M-58(IRA) - Slot 28 -MPU M -58 -M -XX -v 5,295.12 1,367.54 5,295.12 1,329.12 3,575.01 35.591 Centre Distance - Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - M -XX - v 5,348.87 1,367.95 5,348.87 1,328.54 3,596.85 34.711 Ellipse Separation Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - M -XX - v 6,023.87 1,497.81 6,023.87 1,446.06 3,843.03 28.942 Clearance Factor Pass - From To Survey/Plan Survey Tool (usft) (usft) 33.70 5,048.87 MPU M-22 wp05 2_MWD+IFR2+MS+Sag 5,048.87 14,269.53 MPU M-22 wp05 2_MWD+IFR2+MS+Sag Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles /(Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 18 July, 2019 - 19:14 Page 3 of 5 COMPASS NALLIBl1FiTON Project: Milne Point REFERENCE INFORMATION WELLDEfAIIS:PIan:MPUM-22 NAD192] ADCONCONUS) Alaska Zone 04 M Cooans ate NuE) Reference: Wel Plan: MPU M-22. True harm W.N Viamull (ND) Reference: MPU M-22 Planned RKI3 @ 58.60usfl Meesuretl Depth Reference: MPU M -II Plannetl RKB (ry 58.60usfl Calculation Method: Minimum Curvature Site: M Pt Moose Pad BPerry Orttling Well: Plan: MPU M-22 Wellbore: MPU M-22 Ground Level: 24.90 +N/-$ +H_W Northing Fasting Is6tNde InngiNdc 0.00 0.00 6027889.83 533663.95 70°29'14U12N 149'43'29A56M Plan: MPU M-22 wp05 SURVEY PROGRAM NO GLOBAL FILTER: using user defined selection 8 filtering criteria Date: 2016-06-22T00:00:00 Validated: Yes Version: ' 33.70 To 14269.53 Ladder/S.F. Plots PH (2 of 2) Depth From Depth To Survey/Plan Tool 33.70 5048.87 MPU M-22 vp05 (MPU M-22) 2_MW D+IFR2+MS+Sag 5048.87 14269.53 MPU M-22 wpO5(MPU M-22) 2_MWD+IFR2+MS+Sag CASING DETAILS TVD TVDSS MD Size Na.... 3900.42 3841.82 5048.87 9-5/8 95/8"x12114" 3586.60 3528.00 14269.53 6-5/8 6 5/8" x 8 1/2" .9150.00-- 150.00 612D00- o1zo.0o --- ----.... - ---- ----- M-03 I I- I o 30.00 U - __....-'t--- --------- -- I ; 0.00 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 Measured Depth (1000 usft/in) 3.00 ILL Collision Risk Procedures Req. 2.00 n Collision Avoidance Req. W No -Go Zone -Stop Drilling 1.00 NOERRORS 0.00 5000 55006000 6500 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 Measured Depth (1000 usft/in) Transform Points X Source coordinate system M P ardiatem State Plane 1927 - Alaska Zone 4 Albers Equal Area (156) Datum: NAD 1927 - North America Datum of 1927 (Mean) NAD 1927 - North America Datum of 1927 (Mean) 5993905.62 '.. 476227.35 ® Easting Northing 1 16027889 533x63 P21 10465.0 2278272.4 2 J, cype values into the spreadsheet or copy and paste columns of data from a spreadsheet using the keyboard shortcuts Ctd+C to opy and Ctrl+V to paste Then dick on the appropriate arrow button to transform the points to the desired coordinate system. '. _— < Back Finish __. '�, Cancel ,L— TRANSMITTAL LETTER CHECKLIST WELL NAME: M P U, ( - ( - ;� a PTD: - I Vbevelopment —Service Exploratory _ Stratigraphic Test Non -Conventional FIELD: M I l NPS 1 O I i' + POOL: SG k rJE,//' JJ I u 17' (D I I Check Bog 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), ail 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 l Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sam le intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements J Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BUFF OIL - 525140 PTD#:2191110 Company Hilcorp Alaska LLC Initial Class/Type Well Name: MILNE�T tZNIT M-22 Program DEV Well bore seg DEV/PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Disposal Administration 1 Permit fee attached_ . NA.- -------- -------------------------------- 2 Lease number appropriate. _ .. - - - - - - - - - - - - - - - - - - Yes 3 Unique well. name and number - - - - - - - - - Yes 4 Well located in a. defined pool _ _ _ _ _ _ Yes 5 Well Jocated proper distance_ from drilling unit boundary- - ......... _ _ Yes 6 Well located proper distance from other wells. . .... . . ... . . . . ... . ... Yes 7 Sufficient acreage available in drilling unit _ _ _ _ _Yes ---------- 8 If deviated, is wellbore plat included _ _ _ _ _ _ _ _ _ _ _ Yes 9 Operator only affected party_ ............ ....... Yes. 10 Operator has. appropriate bond in force . ........... . ....... . . Yes 11 Permit can be issued without conservation order_ _ _ _ _ _ _ _ _ _ _ _ _ .. _ Yes Appr Date 12 Permit can be issued without administrative.approval _ _ _ _ _ _ .... Yes 13 Can permit be approved before 15 -day wait Yes __..._..... ................. DLB 8/8/2019 _ _ _ _ ______.............. .... 14 Well located within area and strata authorized by Injection Order # (put. IO# in_comments) _(For NA . . ................... 15 AJI wells within 114. mile area of review identified (For service well only). _ _ .. _ _ _ _ _ _ _ NA _ _ . . ........... . . . . . . . . 16 Pre -produced injector; duration of pre production less than 3 montha(For sery(ee well only) .. NA_ . _ . . . . .............. 17 Nonoonven, gas conforms to AS31,05,03Q0,1.A)& 2.A -D) . . . . . . .................NA.. 118 Conductor string. provided _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ... Yes . _ _ Conductor set. at 113' _ _ ........... . Engineering 19 Surface casing protects all known USDWs .. _ _ _ . _ _ . .... ... NA _ _ No aquifers._. permafrost exempt _ . X20 CMT vol adequate to circulate.on.conductor & Surf _csg Yes _ _ _ 2 stage on 9 518" casing planned .. ES at2500 it . 21 CMT vol adequate. to tie-in long string to surf csg_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No.. 22 CMT wilt Coyer all known productive horizons . . . . ...................... . . . Yes _ _ _ 6 5/8" slotted liner planned., 7" tieback for 2nd barrier.. 23 Casing designs adequate for C, T, B &_permafrost_ _ .. . . . . . .............. Yes 24 Adequate tankage or reserve pit _ _ _ ............... Yes 25 If a,re-drill, has_a 10403 for abandonment been approved _ _ _ _ _ _ _ _ _ _ _ _ _ _ _______ NA 26 Adequate wellbore separation proposed_.... ......................... Yes ... 27 27 If divener required, does it meet regulations _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ . _ _ _ _ _ _ . .. _ ......... ..... Appr Date 28 Drilling fluid, program schematic & equip list adequate _ _ _ ... _ Yes Max formation. press= 1705_psi _(8.6 ppg EMW) will drill. with 8,9r 9.$ ppg mud. _ GLS 8/20/2019 29 BOPEs, do they meet regulation _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 30 BOPS.press rating appropriate; test to (put psig in comments)..... _ _ _ _ Yes _ _ _ _ MASP = 1326psi. Will test BOPE to 3000 psi 31 Choke manifold complies w/API_ RP -53 (May 84) . . . .... . . ............. . . . Yes 32 Work will occur without operation shutdown _ _ .... Yes 33 Is presence of H2S gas probable -- - ----- - - - - - - - - - - - - - - - - - - .. _ . _ . No... _ - - - - - - - - _ _ _ .... _ 34 Mechanical condition of wells within AOR verified (Focservice well only) .... ........NA_ 35 Permit can be issued w/o hydrogen. sulfide measures _ _ _ _ _ _ _ _ _ .. Yes - - _ _ _ H28 not anticipated from drilling of offset wells; however, rig will have H2S sensors and alarms. Geology 36 Data presented on potential overpressure zones _ _ _ _ _ _ _ _ _ .. Yes ........ Appr Date 37 Seismic analysis. of shallow gas zones_ _ _ _ _ _ _ NA_ DLB 8/8/2019 38 Seabed condition survey (if off -shore) .............................. ... NA..........._-_--____________. _....._... .. 39 Contact name/phone for weekly_progress reports _[exploratory only]___ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ .......... Geologic Engineering Public ESP planned with no packer. 7" tieback to surface. Sundry needed for completion ops. GIs Commissioner: Date: Commissioner: -Date / Commissioner Date �'C cFI�ll Gl ❑N7
