Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation
Commission
HOME
EVENTS
DATA
Data List
Drilling
Production
Orders
Data Miner
Document Search
REPORTS
Reports and Charts
Pool Statistics
FORMS
LINKS
Links
Test Notification
Data Requests
Regulations
Industry Guidance Bulletins
How to Apply
ABOUT US
History
Staff
HELP
Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
220-005
MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, October 16, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC L-59 MILNE PT UNIT L-59 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 10/16/2024 L-59 50-029-23680-00-00 220-050-0 W SPT 3965 2200500 1500 272 273 272 272 4YRTST P Adam Earl 8/31/2024 MIT IA Monobore well 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT L-59 Inspection Date: Tubing OA Packer Depth 268 1705 1655 1638IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE240901134543 BBL Pumped:2.4 BBL Returned:2.4 Wednesday, October 16, 2024 Page 1 of 1 9 9 9 9 9 9 9 999 9 9 9 9 Monobore well James B. Regg Digitally signed by James B. Regg Date: 2024.10.16 15:04:44 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, August 16, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Bob Noble P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC M-35 MILNE PT UNIT M-35 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 08/16/2024 M-35 50-029-23665-00-00 220-005-0 W SPT 3928 2200050 1500 692 691 691 691 4YRTST P Bob Noble 7/5/2024 Monobore 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT M-35 Inspection Date: Tubing OA Packer Depth 250 1702 1638 1620IA 45 Min 60 Min Rel Insp Num: Insp Num:mitRCN240706092820 BBL Pumped:2.3 BBL Returned:2.3 Friday, August 16, 2024 Page 1 of 1 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2024.08.16 15:50:37 -08'00' Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 10/16/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-35 (PTD 220-005) COIL FLAG 07/07/2020 Please include current contact information if different from above. PTD: 2200050 E-Set:34111 Received by the AOGCC 10/16/2020 Abby Bell 10/20/2020 Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 10/01/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-35 (220-005) Injection Profile 04/16/2020 Please include current contact information if different from above. Received by the AOGCC 10/01/2020 PTD: 2200050 E-Set: 34019 Abby Bell 10/01/2020 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 8/27/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-35 (220-005) Halliburton GEOSTEERING 18 FEB 2020 MPU M-35 PTD:2200050 E-Set: 33715 Received by the AOGCC 08/31/2020 Abby Bell 08/31/2020 MEMORANDUM 'To: Jim Regg 11.1. Supervisory FROM: Jeff Jones Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, July 29, 2020 SUBJECT: Mechanical Integrity Tests Hilcorp Alaska, LLC M-35 MILNE PT UNIT M-35 Sre: Inspector Reviewed By: P.1.5upry Jt�t Comm Well Name MILNE PT UNIT M-35 API Well Number 50-029-23665-00-00 Inspector Name: Jeff Jones Permit Number: 220-005-0 Inspection Date: 7/26/2020 Insp Num: mitJJ200727111428 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min " Well M-35 'Type Inj 3928T g 493 495 494 493 PTD 2200050 Type Test' SPT Test psi 1500 - I IA 173 1665 1596 1577 BBL Pumped: 2.4 BBL Returned: 2.4 OA Interval, INITAL P/F P ✓ Notes: Monobore injector, no OA. One well inspected, no exceptions noted. .-----'7 Wednesday, July 29, 2020 Page I of I 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: MBE Conformance Treatment Hilcorp Alaska Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 17,900 feet N/A feet true vertical 3,832 feet N/A feet Effective Depth measured 17,900 feet 6,228 & 6,239 feet true vertical 3,832 feet 3,930 & 3,931 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3 / L-80 / EUE 8rd 6,242' 3,932' Packers and SSSV (type, measured and true vertical depth)SLZXP LTP (2) N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Chad Helgeson Contact Name: Authorized Title:Operations Manager Contact Email: Contact Phone: WINJ WAG 0 Water-Bbl MD 80' 6,398' 17,900' TVD 80' Oil-Bbl measured true vertical Packer Size N/A Junk measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 00 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-005 50-029-23665-00-00 Plugs ADL025514, ADL025515 & ADL025517 5. Permit to Drill Number: Milne Point Field / Schrader Bluff Oil Pool 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-210 393 Authorized Signature with date: Authorized Name: David Haakinson dhaakinson@hilcorp.com 10 MILNE PT UNIT M-35 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 0 Casing Pressure Tubing Pressure 0 N/A measured Casing Conductor Length 80' 6,398' 11,672' Surface Liner 777-8343 20" 9-5/8" 4-1/2" 3,943' 3,832' 8,540psi 850 2. Operator Name Senior Engineer: Senior Res. Engineer: Collapse N/A 3,090psi Burst N/A 5,750psi 9,020psi Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Jody Colombie at 3:40 pm, Jul 23, 2020 Chad A Helgeson 2020.07.23 14:34:47 -08'00' SFD 7/28/2020DSR-7/23/2020 RBDMS HEW 7/23/2020 MGR30JUL2020 _____________________________________________________________________________________ Revised By: TDF 7/23/2020 SCHEMATIC Milne Point Unit Well: MP M-35 Last Completed: 2/24/2020 PTD: 220-005 GENERAL WELL INFO API: 50-029-23665-00-00 Drilled & Completed by Doyon 14 (2/24/2020) MBE Conformance Treatment – 7/8/2020 TREE & WELLHEAD Tree Cameron 3 1/8" 5M Wellhead CIW 11" 5M T103 w/11" x 3 1/2" EUE 8rd 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 – 505 sx / T – 400 sx in a 12-1/4” hole 9-5/8” 2nd stage L – 550 sx / T – 270 sx in a 12-1/4” hole 4-1/2”” Cementless 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 SR 8.835” Surface 6,398’ 0.0758 4-1/2” Liner 13.5/ L-80 / Hyd 625 3.920” 6,228’ 17,900' 0.0149 TUBING DETAIL 3-1/2” Tubing 9.3 / L-80 / EUE 8rd 2.992” Surface 6,242 0.0087 WELL INCLINATION DETAIL KOP @ 224’ JEWELRY DETAIL No. Top MD Item 1 5,654’ 3.5” Gauge Mandrel w/ Zenith Gauge & ¼” Wire 2 5,707’ 3.5” XN Nipple (2.813” Packing Bore; 2.75” No-Go) 3 6,226’ 8.26” No Go Locater w/ 7.375” Seal Assembly 4 6,228’ 7.375” ID Tieback above the SLZXP Liner Top Packer – TVD= 3,930’ 5 6,239’ SLZXP Liner Top Packer – TVD= 3,931’ 6 17,898’ 4.5” Eccentric Guide Shoe Depth MD Depth TVD ICD/Swell Packer Detail 6,468’ 3,942’ Water Swell Packer 6,532’ 3,942’ ICD w/ 250L mesh, Sliding Sleeve 6,971’ 3,943’ Water Swell Packer 7,451’ 3,932’ ICD w/ 250L mesh, Sliding Sleeve 7,686’ 3,926’ Water Swell Packer 8,290’ 3,927’ AICD w/ 250L mesh 8,641’ 3,933’ Water Swell Packer 8,869’ 3,938’ AICD w/ 250L mesh 9,057’ 3,938’ Water Swell Packer 9,325’ 3,931’ AICD w/ 250L mesh 9,429’ 3,932’ Water Swell Packer 9,787’ 3,940’ AICD w/ 250L mesh 10,262’ 3,921’ Water Swell Packer 10,951’ 3,924’ AICD w/ 250L mesh 11,137’ 3,930’ Water Swell Packer 11,406’ 3,937’ AICD w/ 250L mesh 12,050’ 3,895’ Water Swell Packer 12,571’ 3,855’ AICD w/ 250L mesh 12,717’ 3,853’ Water Swell Packer 12,984’ 3,848’ AICD w/ 250L mesh (Treated Interval with H2Zero) 13,417’ 3,847’ Water Swell Packer 14,020’ 3,859’ AICD w/ 250L mesh 14,461’ 3,859’ Water Swell Packer 14,984’ 3,860’ AICD w/ 250L mesh 15,500’ 3,860’ Water Swell Packer 16,054’ 3,857’ AICD w/ 250L mesh 16,489’ 3,852’ Water Swell Packer 17,005’ 3,839’ AICD w/ 250L mesh 17,486’ 3,831’ Water Swell Packer 17,757’ 3,831’ AICD w/ 250L mesh Well Name Rig API Number Well Permit Number Start Date End Date MP M-35 CTU 50-029-23665-00-00 220-005 7/7/2020 7/8/2020 7/3/2020 - Friday No operations to report. 7/1/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 7/2/2020 - Thursday No operations to report. MIRU SLB CTU #6 2" CT .156 WT RIH with Memory Gamma/CCL w/ 2.5" JSN Drift TBG & Liner down to 13,100' Log up @ 40 fpm stop at 12,980' paint white flag on CT for depth corrolation. Continue logging up to 12,900' POOH. Recoverd good data with a -36' correction. Corrected EOP @ 12,932.2' RIH with 2.5" Baker Hughes Treating PKR tie-in to white flag on CT Correct depth to mid point of bottom element. Run past set depth and pull back up to it using lower element depth of 13,000.71' Dropped 1/2" steel ball in CT reel and circulate down to set Treating PKR. Reduced pump rate a 70% of CT volume. Ball landed on seat and pressure was brought up to 1,600psi set down 3k on PKR, 2,100psi set down another 3k, 2600psi set down 3k, Brought pressure up and seen rupture disk burst. Started injection base line using 2% KCL for 30 min 0.5 bpm @ 800psi average. Called OE continue with 100 cP Linear gel injection. HES on line with 10 bbls of linear gel chasing with 2% KCL. No operations to report. 7/4/2020 - Saturday No operations to report. 7/7/2020 - Tuesday 7/5/2020 - Sunday No operations to report. 7/6/2020 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP M-35 CTU 50-029-23665-00-00 220-005 7/7/2020 7/8/2020 7/10/2020 - Friday No operations to report. 7/8/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Continue Well Service Report from 7/7/2020 Treating PKR set @ 13,000.71' continue circlating 10 bbl pill of 100cP gel down CT string with 2% KCL Gel entering AICD and into formation with little indication of issures Circ pressure before get 534. After 10 bbls was pumped into formation pressure dropped to 435 Delta p loss of 99psi. Shut down and mix up 21 bbls of H2Zero and pump down CT to Treating PKR. Load CT with 21 bbls of gel and chase w/ KCL down to AICD at 12,984' H2Zero gel at AICD pressure slowly dropped 100 psi and leveled out during injection. Pulled 5500# over pull Treating PKR pulled free. Stop and wait 30 min to relax elements. POOH Recovered all six elements on Treating PKR. Recoverd 1/2" steel ball. RIH to 2,500' and freezeprotect well with Diesel. Well is not to be put on injection for 2 weeks to allow H2Zero Gel to set. 7/9/2020 - Thursday No operations to report. No operations to report. No operations to report. 7/11/2020 - Saturday No operations to report. 7/14/2020 - Tuesday 7/12/2020 - Sunday No operations to report. 7/13/2020 - Monday 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: Conformance Treatment 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Hilcorp Alaska LLC Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 17,900'N/A Casing Collapse Conductor N/A Surface 3,090psi Liner 8,540psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name: David Haakinson Operations Manager Contact Email: Contact Phone: 777-8343 Date: 5/22/2020 Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng See Schematic See Schematic Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 17,900' Authorized Signature: 6/1/2020 3-1/2" Perforation Depth MD (ft): See Schematic See Schematic 20" 9-5/8" 80' 4-1/2"11,672' 6,398' N/A 5,750psi 80' 3,943' 3,832' 80' 6,398' 9.3 / L-80 / EUE 8rd TVD Burst 6,242' MD 9,020psi 50-029-23665-00-00 Length Size 3,832' 17,900' 3,832' 1,248 N/A MPU M-35 Milne Point Field / Schrader Bluff Oil Pool Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025514, ADL025515 & ADL025517 220-005 C.O 477.05 dhaakinson@hilcorp.com COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:10 am, May 26, 2020 320-210 Chad A Helgeson 2020.05.22 18:41:37 -05'00' SFD 5/26/2020 10-404 DSR-5/26/2020 Conformance Treatment MBE gls 5/28/20 Comm Required? Yes 5/28/2020 dts 5/28/2020 RBDMS HEW 6/4/2020 CTU Conformance Treatment Well: MP M-35 PTD: 220-005 Well Name:MP M-35 API Number: 50-029-23665-00-00 Current Status:Injector (Shut In)Wellwork Unit:CTU, Pump Estimated Start Date:June 1st, 2020 Estimated Duration:1 day Reg.Approval Req’std?Yes Date Reg. Approval Rec’vd:N/A Regulatory Contact:Tom Fouts 777-8398 Permit to Drill Number:220-005 First Call Engineer:David Haakinson (907) 777-8343 (O) (307) 660-4999 (M) Second Call Engineer:Ian Toomey (907) 777-8434 (O) (907) 903-3987 (M) AFE Number: WellEZ Entry Required? SBHP: 1,636 psig at 3,885’ TVD | 8.3 PPG EMW MPSP: 1,248 psig (0.1 ppg gas gradient) Max Deviation: 98° at 11,912’ MD | Horizontal at 6,300’ MD Max Dogleg:6.5°/100’ at 6,364’ MD Last Tag:15,090’ MD on E-line Tractor | 4/17/2020 Minimum ID:2.813” XN Nipple at 5,707’ MD Max Injection Rate:1,500 BWIPD Max Wellhead Injection Pressure: 800 psig (Before Frictional Drops-TBD) Max Sandface Treatment Pressure: 2,400 psig. Minimum ID in the CT BHA:0.625” Through Treatment Packer Brief Well Summary: MP M-35 is a Schrader Bluff injection well drilled and completed in the OB sand. On 2/28/2020, a breakthrough occurred from M-35 to producer M-18. Producer M-18 was completed in the OA sands and due to close proximity to a fault between the two wells, it is suspected that injector to producer communication is occurring via the fault with both wellbores within 15 feet TVD. An IPROF was completed on M-35 to locate the area of communication, however, there was not a clear indication. ICD #12 at 14,984’ was suspect for passing too much flow for the AICDs at greater than 700 BPD. A subsequent injectivity test was completed on M-35 in attempt to trip the AICDs, but with no obvious changes. As a resultant of that test, it is believed that the swell packers are not holding near the fault in question at 13,378’ MD where drilling lost returns. Due to the projected inability to reach the AICDs at 14,020’ MD or 14,980’ MD with coiled tubing, combined with a swell packer ‘restriction’ at 13,417’ MD, the conformance treatment is proposed at the AICD at 12,984’ MD. This work will be setup to pump using a Schlumberger CTU unit and Halliburton Mixing Unit Objective: 1) Pump Conformance Treatment to isolate conductivity between M-35 and M-18. Risks: x Risk of not reaching the achieved depth on CTU. o Coil-Cade analysis suggests a depth of 13,334’ can be reached with safe-lube. o If the ICD at 12,984’ MD is not reached, engineering may increase the volume of the H2Zero treatment. x Treatment of Incorrect ICD o If ICDs #11 and #12 are in communication with the fault conduit, the treatment could preferentially flow to those ICDs. Note that the liner volume from ICD #10 to ICD #12 is ~30.2 bbls. The treatment volume could isolate injection in the toe of the lateral from ICD #10 to TD. ICD #12 at 14,984’ was suspect for passing too much flow for the AICDs a Note: OBtoOAMBE event through suspected fault. gls On 2/28/2020, a breakthrough occurred from M-35 to producer M-18. CTU Conformance Treatment Well: MP M-35 PTD: 220-005 o Note that a straddle system was considered but difficult to place across and ICD on CTU. x Exceeding fracture pressure o The proposed fluid density of the H2Zero fluid is ~8.5 ppg (0.442 psi/ft) o Assuming a 0.66 psi/ft fracture gradient, do not exceed 800 psig surface injection pressure before accounting for frictional pressure. x Early Setup of Crosslinked Gel Causing stuck coiled tubing. o The use of a treatment packer should reduce risk of gel setup in coiled tubing annular space. o If the treatment packer becomes stuck, pump a ball to disconnect and leave downhole. x Early Release of Treatment Packer o It is important to maintain consistent temperatures throughout the job (source water, H2Zero gel) to avoid early release of the treatment packer. x Cross-Link Gel Screen-out o The goal is to leave plenty of treating pressure room to work with in the event we encounter a screenout. Note that the pumping viscosity is estimated to be 30 cP, so this is not anticipated. x Cross-linked Polymer Production o Producer M-18 must be shut in at the time the H2Zero conformance gel is pumped. o After the completion of the conformance job, M-18 should be brought online to tanks. Rig up three 400-bbl tanks for M-18 production If M-18 polymer or emulsion is seen, divert M-18 to tanks and attempt to keep the well online as long as possible to keep wellbore clean. o Note that there is a risk of M-18 lateral plugging off. The fault in question crosses the M-18 wellbore at 13,902’ MD. Coil-Cade analysis suggests a depth of 12,955’ MD can be reached for M-18 CTU FCO. This falls short for a potential fill cleanout. The volume of treatment for the M-18 to M- 35 is estimated at 22 bbls. Procedure: CTU & Pumping Unit 1. Verify M-35 has remained shut-in. 2. Rig up two 400 bbl uprights for source water, a trip tank for ~50 bbls of diesel, and a vac truck for ~30 bbls of source water for mixing H2Zero product. 3. MIRU SLB CTU unit with 2” coiled tubing. 4. If BOPE test has not been completed in last 7 days, test BPE to 250 psig low / 3,500 psig high. 5. RU Halliburton mixing and pumping equipment. 6. Establish site control and a separate radio channel for crews so that proper and clear communication will exist throughout the job. 7. MU BHA w/ 2” CT, CTC, DBPVk, hydraulic disconnect, treatment packer and a Nozzle with a minimum 1.0” port. 8. RIH to ~2000’ MD. Displace well freeze protect to tanks. 9. RIH to place the nozzle ~60’ above the AICD at 12,982’ MD. Pump lubes as necessary to reach depth. 10. Verify Halliburton mixing crew is ready for ‘on-the-fly’ mixing of H2Zero Product. 11. Bring up pumps, isolating the CTxT annulus and inject source water into the well. Start injection rate at 1 BPM and look for stabilization on injection pressure. a. Monitor rate and treating pressure. Maintain as constant rate as possible. b.DNE an equivalent downhole pressure of 2275 psig. treating packer (treating packer approx 12900 ft. ) CTU Conformance Treatment Well: MP M-35 PTD: 220-005 c. Document stabilized CT surface pressures and injection rates. 12. Pump a 0.5” ball downhole to set the treatment packer. As the ball nears the landing sleeve, slow the pump rate down to prevent over-pressure and tripping of the AICDs. The ball is to set @ 2,500 psig. a. Assuming 2” x 0.156” WT CT, internal displacement volume is 0.002768 BBL/FT. b. Note that once the treatment packer sets properly, all AICDs up-hole will be isolated from the treatment. 13. PU CT slightly (1Klbs) to confirm isolation packer is set. Note the packer is pinned at 5,500# upward force to release. 14. After the treatment packer has set, slowly roll the pumps back online to obtain a new baseline injectivity. a.DNE an equivalent downhole pressure of 2275 psig. Account for frictional pressure on surface. 15. After a baseline injectivity rate has been established, contact engineering for review of all injectivities. Confirm no changes are necessary from the Engineer. 16. Shut in M-18 Producer. 17. Begin mixing the H2Zero product and begin pumping downhole. When the H2Zero product begins exiting the nozzle, monitor the treatment pressure for any indications of ICD plugging. a. The goal is to pump the treatment at 1 BPM. 18. Plan to pump a total volume of ~30 bbls of H2Zero product at 1 BPM. If the treating pressure response indicates plugging or screening off, a flush stage may be called. a. If screen-out indication is seen, shift to source water and plan to PU 5,500 lb-force to release the retrievable packer. Note that more force will likely be needed to release due to pipe friction. 19. When called, swap to source water. 20. If the entire ~30 bbl volume of H2Zero is pumped, pump an additional 2 bbls of flush (source water) and calculate displacement to the AICD. 21. At this time, attempt to reduce fluid injection into the well as much as possible; take all returns to surface. 22. PU 5,500 lb-force to release retrievable packer. Allow elastomers to relax prior to pulling up- hole. 23. POOH to 2500’ MD. 24. Pump Diesel freeze protect and 1 CT line volume to freeze protect the CT and well. 25. RDMO CTU and Mixing Unit 26. Allow M-35 H2Zero product to setup for 48 hours prior to returning the well to injection or restarting M-18 production. _____________________________________________________________________________________ Revised By: TDF 5/22/2020 SCHEMATIC Milne Point Unit Well: MP M-35 Last Completed: 2/24/2020 PTD: 220-005 GENERAL WELL INFO API: 50-029-23665-00-00 Drilled & Completed by Doyon 14 (2/24/2020) TREE & WELLHEAD Tree Cameron 3 1/8" 5M Wellhead CIW 11" 5M T103 w/11" x 3 1/2" EUE 8rd 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 – 505 sx / T – 400 sx in a 12-1/4” hole 9-5/8” 2nd stage L – 550 sx / T – 270 sx in a 12-1/4” hole 4-1/2”” Cementless 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 SR 8.835” Surface 6,398’ 0.0758 4-1/2” Liner 13.5/ L-80 / Hyd 625 3.920” 6,228’ 17,900' 0.0149 TUBING DETAIL 3-1/2” Tubing 9.3 / L-80 / EUE 8rd 2.992” Surface 6,242 0.0087 TD = 17,900’ MD / 3,832’ TVD PBTD = 17,900’ MD / 3,832’ TVD 20” Orig. KB Elev.: 59.7’/ GL Elev.: 25.3’ 9-5/8” 3 9-5/8” ‘ES’ Cementer @ 2,460’ 1 5 2 Min ID 2.75” @ 5,707’ 8-1/2” Hole 4 12 4-1/2”6 13 14 WELL INCLINATION DETAIL KOP @ 224’ JEWELRY DETAIL No. Top MD Item 1 5,654’ 3.5” Gauge Mandrel w/ Zenith Gauge & ¼” Wire 2 5,707’ 3.5” XN Nipple (2.813” Packing Bore; 2.75” No-Go) 3 6,226’ 8.26” No Go Locater w/ 7.375” Seal Assembly 4 6,228’ 7.375” ID Tieback above the SLZXP Liner Top Packer – TVD= 3,930’ 5 6,239’ SLZXP Liner Top Packer – TVD= 3,931’ 6 17,898’ 4.5” Eccentric Guide Shoe Depth MD Depth TVD ICD/Swell Packer Detail 6,468’ 3,942’ Water Swell Packer 6,532’ 3,942’ ICD w/ 250L mesh, Sliding Sleeve 6,971’ 3,943’ Water Swell Packer 7,451’ 3,932’ ICD w/ 250L mesh, Sliding Sleeve 7,686’ 3,926’ Water Swell Packer 8,290’ 3,927’ AICD w/ 250L mesh 8,641’ 3,933’ Water Swell Packer 8,869’ 3,938’ AICD w/ 250L mesh 9,057’ 3,938’ Water Swell Packer 9,325’ 3,931’ AICD w/ 250L mesh 9,429’ 3,932’ Water Swell Packer 9,787’ 3,940’ AICD w/ 250L mesh 10,262’ 3,921’ Water Swell Packer 10,951’ 3,924’ AICD w/ 250L mesh 11,137’ 3,930’ Water Swell Packer 11,406’ 3,937’ AICD w/ 250L mesh 12,050’ 3,895’ Water Swell Packer 12,571’ 3,855’ AICD w/ 250L mesh 12,717’ 3,853’ Water Swell Packer 12,984’ 3,848’ AICD w/ 250L mesh 13,417’ 3,847’ Water Swell Packer 14,020’ 3,859’ AICD w/ 250L mesh 14,461’ 3,859’ Water Swell Packer 14,984’ 3,860’ AICD w/ 250L mesh 15,500’ 3,860’ Water Swell Packer 16,054’ 3,857’ AICD w/ 250L mesh 16,489’ 3,852’ Water Swell Packer 17,005’ 3,839’ AICD w/ 250L mesh 17,486’ 3,831’ Water Swell Packer 17,757’ 3,831’ AICD w/ 250L mesh zones above 12984 ' are isolated from MBE treatment. 12,984’3,848’AICD w/ 250L meshtreating pkr at 12900' SAFETY DATA SHEET Product Trade Name:H2ZERO Gelant Revision Date:25-Aug-2017 Revision Number:10 1. Identification 1.1. Product Identifier Product Trade Name:H2ZERO Gelant Synonyms None Chemical Family:Blend Internal ID Code HM004101 1.2 Recommended use and restrictions on use Application:System Uses advised against No information available 1.3 Manufacturer's Name and Contact Details Manufacturer/Supplier Halliburton Energy Services, Inc. P.O. Box 1431 Duncan, Oklahoma 73536-0431 Telephone: 1-281-871-6107 Halliburton Energy Services, Inc. 645 - 7th Ave SW Suite 1800 Calgary, AB T2P 4G8 Canada Prepared By Chemical Stewardship Telephone: 1-281-871-6107 e-mail: fdunexchem@halliburton.com 1.4. Emergency telephone number: Emergency Telephone Number 1-866-519-4752 or 1-760-476-3962 Global Incident Response Access Code: 334305 Contract Number: 14012 2. Hazards Identification 2.1 Classification in accordance with paragraph (d) of §1910.1200 As adopted by the competent authority, this product does not require an SDS or hazard warning label. Not classified 2.2. Label Elements Hazard Pictograms Signal Word:Not Classified Hazard Statements Not Hazardous _____________________________________________________________________________________________ Page 1 / 8 _____________________________________________________________________________________________ H2ZERO Gelant Revision Date:25-Aug-2017 Precautionary Statements Prevention None Response None Storage None Disposal None 2.3 Hazards not otherwise classified None known 3. Composition/information on Ingredients Substances CAS Number PERCENT (w/w) GHS Classification - US Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA 60 - 100% Not classified The exact percentage (concentration) of the composition has been withheld as proprietary. 4. First Aid Measures 4.1. Description of first aid measures Inhalation If inhaled, remove from area to fresh air. Get medical attention if respiratory irritation develops or if breathing becomes difficult. Eyes In case of contact, immediately flush eyes with plenty of water for at least 15 minutes and get medical attention if irritation persists. Skin Wash with soap and water. Get medical attention if irritation persists. Ingestion Under normal conditions, first aid procedures are not required. 4.2 Most important symptoms/effects, acute and delayed No significant hazards expected. 4.3. Indication of any immediate medical attention and special treatment needed Notes to Physician Treat symptomatically. 5. Fire-fighting measures 5.1. Extinguishing media Suitable Extinguishing Media Water fog, carbon dioxide, foam, dry chemical. Extinguishing media which must not be used for safety reasons None known. 5.2 Specific hazards arising from the substance or mixture Special exposure hazards in a fire Decomposition in fire may produce harmful gases. 5.3 Special protective equipment and precautions for fire-fighters Special protective equipment for firefighters Full protective clothing and approved self-contained breathing apparatus required for fire fighting personnel. 6. Accidental release measures _____________________________________________________________________________________________ Page 2 / 8 _____________________________________________________________________________________________ H2ZERO Gelant Revision Date:25-Aug-2017 6.1. Personal precautions, protective equipment and emergency procedures Use appropriate protective equipment. See Section 8 for additional information 6.2. Environmental precautions None known. 6.3. Methods and material for containment and cleaning up Isolate spill and stop leak where safe. Contain spill with sand or other inert materials. Scoop up and remove. 7. Handling and storage 7.1. Precautions for safe handling Handling Precautions Avoid contact with eyes, skin, or clothing. Hygiene Measures Handle in accordance with good industrial hygiene and safety practice. 7.2. Conditions for safe storage, including any incompatibilities Storage Information Store away from oxidizers. Store in a cool, dry location. Store at temperature above 32 F (0 C). Do not freeze. 8. Exposure Controls/Personal Protection 8.1 Occupational Exposure Limits Substances CAS Number OSHA PEL-TWA ACGIH TLV-TWA Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA Not applicable Not applicable 8.2 Appropriate engineering controls Engineering Controls None known. 8.3 Individual protection measures, such as personal protective equipment Personal Protective Equipment If engineering controls and work practices cannot prevent excessive exposures, the selection and proper use of personal protective equipment should be determined by an industrial hygienist or other qualified professional based on the specific application of this product. Respiratory Protection Not normally needed. But if significant exposures are possible then the following respirator is recommended: Dust/mist respirator. (N95, P2/P3) Hand Protection Normal work gloves. Skin Protection Normal work coveralls. Eye Protection Wear safety glasses or goggles to protect against exposure. Other Precautions None known. 9. Physical and Chemical Properties 9.1. Information on basic physical and chemical properties Property Values Physical State:Liquid Color Yellowish Odor:Mild amine Odor Threshold: No information available _____________________________________________________________________________________________ Page 3 / 8 _____________________________________________________________________________________________ H2ZERO Gelant Revision Date:25-Aug-2017 Remarks/ - Method pH:10.6 Freezing Point / Range -15°C/5°F Melting Point / Range No data available °C Boiling Point / Range 100 °C / 212 °F Flash Point >93/Opencup Flammability (solid, gas)No data available Upper flammability limit No data available Lower flammability limit No data available Evaporation rate No data available Vapor Pressure No data available Vapor Density No data available Specific Gravity 1.02 Water Solubility Soluble in water Solubility in other solvents No data available Partition coefficient: n-octanol/water No data available Autoignition Temperature No data available Decomposition Temperature No data available Viscosity No data available Explosive Properties No information available Oxidizing Properties No information available 9.2. Other information VOC Content (%)No data available 10. Stability and Reactivity 10.1. Reactivity Not expected to be reactive. 10.2. Chemical stability Stable 10.3. Possibility of hazardous reactions Will Not Occur 10.4. Conditions to avoid None anticipated 10.5. Incompatible materials Strong oxidizers. 10.6. Hazardous decomposition products Oxides of nitrogen. Carbon monoxide and carbon dioxide. 11. Toxicological Information 11.1 Information on likely routes of exposure Principle Route of Exposure Eye or skin contact, inhalation. 11.2 Symptoms related to the physical, chemical and toxicological characteristics Acute Toxicity Inhalation May cause mild respiratory irritation. Eye Contact May cause mechanical irritation to eye. Skin Contact None known. Ingestion None known. _____________________________________________________________________________________________ Page 4 / 8 _____________________________________________________________________________________________ H2ZERO Gelant Revision Date:25-Aug-2017 Chronic Effects/Carcinogenicity No data available to indicate product or components present at greater than 0.1% are chronic health hazards. 11.3 Toxicity data Toxicology data for the components Substances CAS Number LD50 Oral LD50 Dermal LC50 Inhalation Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA No data available No data available No data available 12. Ecological Information 12.1. Toxicity Substance Ecotoxicity Data Substances CAS Number Toxicity to Algae Toxicity to Fish Toxicity to Microorganisms Toxicity to Invertebrates Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA No information available No information available No information available No information available 12.2. Persistence and degradability Substances CAS Number Persistence and Degradability Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA No information available 12.3. Bioaccumulative potential Substances CAS Number Log Pow Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA No information available 12.4. Mobility in soil Substances CAS Number Mobility Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA No information available 12.5 Other adverse effects _____________________________________________________________________________________________ Page 5 / 8 No information available _____________________________________________________________________________________________ H2ZERO Gelant Revision Date:25-Aug-2017 13. Disposal Considerations 13.1. Waste treatment methods Disposal methods Disposal should be made in accordance with federal, state, and local regulations. Contaminated Packaging Follow all applicable national or local regulations. 14. Transport Information US DOT UN Number Not restricted UN proper shipping name:Not restricted Transport Hazard Class(es): Not applicable Packing Group:Not applicable Environmental Hazards:Not applicable Canadian TDG UN Number Not restricted UN proper shipping name:Not restricted Transport Hazard Class(es):Not applicable Packing Group:Not applicable Environmental Hazards:Not applicable IMDG/IMO UN Number Not restricted UN proper shipping name:Not restricted Transport Hazard Class(es):Not applicable Packing Group:Not applicable Environmental Hazards:Not applicable IATA/ICAO UN Number Not restricted UN proper shipping name: Not restricted Transport Hazard Class(es):Not applicable Packing Group:Not applicable Environmental Hazards:Not applicable Transport in bulk according to Annex II of MARPOL 73/78 and the IBC Code Not applicable Special Precautions for User None 15. Regulatory Information US Regulations US TSCA Inventory All components listed on inventory or are exempt. TSCA Significant New Use Rules - S5A2 Substances CAS Number TSCA Significant New Use Rules - S5A2 Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA Not applicable EPA SARA Title III Extremely Hazardous Substances Substances CAS Number EPA SARA Title III Extremely Hazardous Substances Contains no hazardous substances in concentrations NA Not applicable _____________________________________________________________________________________________ Page 6 / 8 _____________________________________________________________________________________________ H2ZERO Gelant Revision Date:25-Aug-2017 above cut-off values according to the competent authority EPA SARA (311,312) Hazard Class None EPA SARA (313) Chemicals Substances CAS Number Toxic Release Inventory (TRI) - Group I Toxic Release Inventory (TRI) - Group II Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA Not applicable Not applicable EPA CERCLA/Superfund Reportable Spill Quantity Substances CAS Number CERCLA RQ Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA Not applicable EPA RCRA Hazardous Waste Classification If product becomes a waste, it does NOT meet the criteria of a hazardous waste as defined by the US EPA. California Proposition 65 Substances CAS Number California Proposition 65 Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA Not applicable U.S. State Right-to-Know Regulations Substances CAS Number MA Right-to-Know Law NJ Right-to-Know Law PA Right-to-Know Law Contains no hazardous substances in concentrations above cut-off values according to the competent authority NA Not applicable Not applicable Not applicable NFPA Ratings:Health 0, Flammability 0, Reactivity 0 HMIS Ratings:Health 0, Flammability 0, Reactivity 0 Canadian Regulations Canadian Domestic Substances List (DSL) All components listed on inventory or are exempt. 16. Other information Preparation Information Prepared By Chemical Stewardship Telephone: 1-281-871-6107 e-mail: fdunexchem@halliburton.com Revision Date:25-Aug-2017 Reason for Revision SDS sections updated: 2 _____________________________________________________________________________________________ Page 7 / 8 Additional information For additional information on the use of this product, contact your local Halliburton representative. For questions about the Safety Data Sheet for this or other Halliburton products, contact Chemical Stewardship at 1-580-251-4335. _____________________________________________________________________________________________ H2ZERO Gelant Revision Date:25-Aug-2017 Key or legend to abbreviations and acronyms used in the safety data sheet EZ±ERG\ZHLJKW &$6±&KHPLFDO$EVWUDFWV6HUYLFH d - day (&±(IIHFWLYH&RQFHQWUDWLRQ (U&±(IIHFWLYH&RQFHQWUDWLRQJURZWKUDWH h - hour /&±/HWKDO&RQFHQWUDWLRQ /'±/HWKDO'RVH //±/HWKDO/RDGLQJ PJNJ±PLOOLJUDPNLORJUDP PJ/±PLOOLJUDPOLWHU mg/m3 - milligram/cubic meter mm - millimeter mmHg - millimeter mercury 1,26+±1DWLRQDO,QVWLWXWHIRU2FFXSDWLRQDO6DIHW\DQG+HDOWK 173±1DWLRQDO7R[LFRORJ\3URJUDP 2(/±2FFXSDWLRQDO([SRVXUH/LPLW 3(/±3HUPLVVLEOH([SRVXUH/LPLW SSP±SDUWVSHUPLOOLRQ 67(/±6KRUW7HUP([SRVXUH/LPLW 7:$±7LPH:HLJKWHG$YHUDJH 81±8QLWHG1DWLRQV w/w - weight/weight Key literature references and sources for data www.ChemADVISOR.com/ Disclaimer Statement This information is furnished without warranty, expressed or implied, as to accuracy or completeness. The information is obtained from various sources including the manufacturer and other third party sources. The information may not be valid under all conditions nor if this material is used in combination with other materials or in any process. Final determination of suitability of any material is the sole responsibility of the user. End of Safety Data Sheet _____________________________________________________________________________________________ Page 8 / 8 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23665-00-00Well Name/No. MILNE PT UNIT M-35Completion Status1WINJCompletion Date2/23/2020Permit to Drill2200050Operator Hilcorp Alaska, LLCMD17900TVD3832Current Status1WINJ4/14/2020UICYesWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, DGR, AGR, ABG, ADR, EWR MD and TVD /PB1NoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleC3/25/20200 17900 Electronic Data Set, Filename: MPU M-35 LWD Final.las32305EDDigital DataC3/25/20206386 17862 Electronic Data Set, Filename: MPU M-35 ADR Quadrants All Curves.las32305EDDigital DataC3/25/2020 Electronic File: MPU M-35 LWD Final MD.cgm32305EDDigital DataC3/25/2020 Electronic File: MPU M-35 LWD Final TVD.cgm32305EDDigital DataC3/25/2020 Electronic File: MPU M-35i_Definitive Survey Report.pdf32305EDDigital DataC3/25/2020 Electronic File: MPU M-35i_Definitive Survey Report.txt32305EDDigital DataC3/25/2020 Electronic File: MPU M-35i_GIS.txt32305EDDigital DataC3/25/2020 Electronic File: MPU M-35 LWD Final MD.emf32305EDDigital DataC3/25/2020 Electronic File: MPU M-35 LWD Final TVD.emf32305EDDigital DataC3/25/2020 Electronic File: MPU_M-35_Geosteering.dlis32305EDDigital DataC3/25/2020 Electronic File: MPU_M-35_Geosteering.ver32305EDDigital DataC3/25/2020 Electronic File: MPU M-35 LWD Final MD.pdf32305EDDigital DataC3/25/2020 Electronic File: MPU M-35 LWD Final TVD.pdf32305EDDigital DataC3/25/2020 Electronic File: MPU M-35 LWD Final MD.emf.tif32305EDDigital DataC3/25/2020 Electronic File: MPU M-35 LWD Final TVD.emf.tif32305EDDigital Data0 0 2200050 MILNE PT UNIT M-35 LOG HEADERS32305LogLog Header ScansC3/25/20200 6954 Electronic Data Set, Filename: MPU M-35PB1 LWD Final.las32306EDDigital DataTuesday, April 14, 2020AOGCCPage 1 of 3PB1~MPU M-35 LWD Final.lasMPU M-35PB1 LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23665-00-00Well Name/No. MILNE PT UNIT M-35Completion Status1WINJCompletion Date2/23/2020Permit to Drill2200050Operator Hilcorp Alaska, LLCMD17900TVD3832Current Status1WINJ4/14/2020UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsSentSample SetNumberNameIntervalINFORMATION RECEIVEDC3/25/20206386 6916 Electronic Data Set, Filename: MPU M-35PB1 ADR Quadrants All Curves.las32306EDDigital DataC3/25/2020 Electronic File: MPU M-35PB1 LWD Final MD.cgm32306EDDigital DataC3/25/2020 Electronic File: MPU M-35PB1 LWD Final TVD.cgm32306EDDigital DataC3/25/2020 Electronic File: MPU M-35PB1_Definitive Survey Report.pdf32306EDDigital DataC3/25/2020 Electronic File: MPU M-35PB1_Definitive Survey Report.txt32306EDDigital DataC3/25/2020 Electronic File: MPU M-35PB1_GIS.txt32306EDDigital DataC3/25/2020 Electronic File: MPU M-35PB1 LWD Final MD.emf32306EDDigital DataC3/25/2020 Electronic File: MPU M-35PB1 LWD Final TVD.emf32306EDDigital DataC3/25/2020 Electronic File: MPU_M-35PB1_Geosteering.dlis32306EDDigital DataC3/25/2020 Electronic File: MPU_M-35PB1_Geosteering.ver32306EDDigital DataC3/25/2020 Electronic File: MPU M-35PB1 LWD Final MD.pdf32306EDDigital DataC3/25/2020 Electronic File: MPU M-35PB1 LWD Final TVD.pdf32306EDDigital DataC3/25/2020 Electronic File: MPU M-35PB1 LWD Final MD.tif32306EDDigital DataC3/25/2020 Electronic File: MPU M-35PB1 LWD Final TVD.tif32306EDDigital Data0 0 2200050 MILNE PT UNIT M-35 PB1 LOG HEADERS32306LogLog Header ScansTuesday, April 14, 2020AOGCCPage 2 of 3 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23665-00-00Well Name/No. MILNE PT UNIT M-35Completion Status1WINJCompletion Date2/23/2020Permit to Drill2200050Operator Hilcorp Alaska, LLCMD17900TVD3832Current Status1WINJ4/14/2020UICYesCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date: 2/23/2020Release Date:1/21/2020Tuesday, April 14, 2020AOGCCPage 3 of 3M.Guhl 4/14/2020 DATE 03/23/2020 Debra 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-35 (220-005) MPU M-35 PB1III Halliburton LWD FINAL 21 FEB 2020 MPU M-35 & P131 CGM Definifive Survey EMF LAS PDF TIFF 2,121/20204:54PNI Filefolder 2/21/20264:54 PPA Filefcider 2/21120204,;4 PPA File folder 221/20204:54 PPA File folder 2121120204:54 PM File folder 2/21/20204:74 PM File folder RECEIVE MAR 2 5 2020 AOGCC 220005 32306 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 03/23/2020 Debra 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-35 (220-005) MPU M-35 PB1III Halliburton LWD FINAL 21 FEB 2020 MPU M-35 & P131 CGM Definifive Survey EMF LAS PDF TIFF 2,121/20204:54PNI Filefolder 2/21/20264:54 PPA Filefcider 2/21120204,;4 PPA File folder 221/20204:54 PPA File folder 2121120204:54 PM File folder 2/21/20204:74 PM File folder RECEIVE MAR 2 5 2020 AOGCC 220005 32306 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: 4/14/2020 GDLB 04/14/2020 PrN ZS G' Regg, James B (CED) From: Doug Yessak - (C) <dyessak@hilcorp.com> Sent: Sunday, February 23, 2020 10:34 AM ZZ��Z� To: Regg, James B (CED); DOA AOGCC Prudhoe Bay; Brooks, PhoeE e L (CED); Wallace, Chris D (CED) Cc: Ian Toomey - (C); Cody Dinger; Claude Demoski - (C) Subject: BOPE test report Attachments: MIT MPU M-35 02-23-20.xlsx DOUG YESSAK HILCORP DSM DOYON RIG 14 907-670-3090 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.regn0alaska.gow AOGCC.Insoectors(cDalaska.gow phoebe. brooks(cDalaska.gov OPERATOR: Hilcorp Alaska LLC FIELD / UNIT / PAD: Milne Point, MPU, M pad DATE: 02/23/20 OPERATOR REP: Doug Yessak AOGCC REP: chds. wallace(cDa I aska. gov 2 r Zl 24tullo Well M35 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. S = Slurry PTD 220-005 Type Inj I N Tubing 0 0 0 0 Form 10-426 (Revised 01/2017) Type Test P Packer TVD 3928 BBL Pump 5.1 - IA 0 2650 • 2600 2590 Interval 0 Test psi 1500 - BBLReturnl 5.1 OA Result P Notes: Witness waived by Brian Bixby on 02/22/2020 at 08:17 AM. Initial, pre-injection MIT -IA performed on the rig. Monobore injector, no OA. Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTO Type Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Notes: TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Form 10-426 (Revised 01/2017) 2020-0223_MIT _MPU_M-35 THE STATE I 341-1MLAW"s GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-35 Hilcorp Alaska, LLC Permit to Drill Number: 220-005 Alaska Oil and Gas 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.claska.gov Surface Location: 4913' FSL, 291' FEL, SEC. 14, T13N, R9E, UM, AK Bottomhole Location: 2441' FNL, 1533' FEL, SEC. 30, T13N, RIOE, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced service 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, ere . Price it DATED this day of January, 2020. , two %W�ArsaiJ STATE OF ALASKA AL., -KA OIL AND GAS CONSERVATION COMMIJoiON JAN 13 2020 PERMIT TO DRILL 20 AAC 25.005 1 a. Type of Work: 1b. Proposed Well Class: Exploratory -Gas ❑ Service - WAG ❑ Service - Disp ❑ 1 c. Specify if well is proposed for: Drill El R Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑ Service - Winj Single Zone Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q . Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022224484 MPU M-35 ' 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 17,558' - TVD: 3,819' - Milne Point Field Schrader Bluff Oil Pool - 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 4913' FSL, 291' FEL. Sec 14, T13N, R9E, UM, AK ADL025514, ADL025515, ADL025517 8. DNR Approval Number: 13. Approximate Spud Date: Top of Productive Horizon: 1096' FSL, 2160' FWL, Sec 13, T13N, R9E, UM, AK LONS 16-004 1/28/2020 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 2441' FNL, 1533' FEL, Sec 30, T13N, R10E, UM, AK 7659 4709' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 59' • 15. Distance to Nearest Well Open Surface: x-533873 y- 6027765 • Zone -4 GL / BF Elevation above MSL (ft): 25.3' • to Same Pool: 800' to MPM-34 16. Deviated wells: Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 96.2 degrees Downhole: 1722 - Surface: 1329 - 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 20" - X52 Weld 114' Surface Surface 114' 114' -270 ft3 Stg 1 - L - 1181 ft3 ! T - 458 ft3 J8-1/2" 9-5/8" 40# L-80 TXP 6,400' Surface Surface 6,400' 3,914' Stg 2 - L - 1937 ft3 / T - 314 ft3 4-1/2" 13.5# L-80 Hyd 625 11,308' 6,250' 3,900' 17,558' 3,819' Cementless Injection Linerw ICDs 3-1/2" 9.3# L-80 EUE 8RD 6,250' Surface Surface 6,250' 3,900' Tieback 19.jp PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total DYpth 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 M- 20. 20. Attachments: Property Plat ❑ BOP Sketch Drilling Program e Time v. Depth Plot ❑ ❑✓ Shallow Hazard Analysis ❑ Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: 'erl el hIICOr .COm Authorized Title: Drilling Manager Contact Phone: 777-8395 Authorized Signature: Date: 1 .1,3, Z O Z o Commission Use Only Permit to Drill _ PI Number: _ _ L 77S Permit Approval � See cover letter for other Number: 50-�'�-! ��5(�'� — Date: I I �11 requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane gas hydrates, or gas contained in shales: Q Other: 30M �s _. �� P t- Samples req'd: Yes E]Noy Mud log req'd: Yes E]No 12 t H2S measures: Yes ❑ Noll Directional svy req'd: Yes [✓] No ❑ 4C 90-110-r C-'L_k `^''_ Spacing exception req'd: Yes ❑ No0 Inclination -only svy req'd: Yes ❑ o❑ A10 / G Post initial injection MIT req'd: Yes LJ No ❑ j APPROVED BY I Approved by: COMMISSIONER THE COMMISSION Date: (�V Form 10-40 5/2017 d ' L �4 This permit is valid for Submit Firm and }-oin h tAf pproval per 20 AAC 25.005(g) Attachments in Duplicate n e (1,2_11)'J" I�l1� V �r'"'�� 0 M-03 M-2 0 L-39 F-108 PESAD01 L-37 L PESADO1A F- 10 F-109 / 1\ I AM -35 p06\ _� \ .\ A ' \ LIVIANO 1 LIVI \ \ \ L-35 0 HILCORP ALASKA LLC MILNE POINT FIELD AOR MAP M-35 Injector (Proposed) 0 1000 IOW 3 FEET WELL SYMBOLS ® �rOvwv Flma� .Pm REM Well Symbols at top of Schrader Bluff OBa Sand Black dash circle =1320' radius from OBa sand in heel and toe of proposed M-35 drill well. Well syymbols at TD of well denote well that never reached OBa sand but is in the Schrader Bluff. \ J- • KUPARUK J-2 RIVER G UNIT L-45 \ J-24LT M-16 J -24A \ • c, M \ o, M-17 -18 Z ' J-20\ 1 _\ 3A\ / V-19. \ • V-231-1 / J-2 \ ' N-01 1 • J-28 \k 0 1 • `N -01'B �/ M-10 3 • M-11 m M-12 M-13• 0 M-14 M-15 J-24 J-261-2 • J-20 0 1-14L1 • k y m� 00 � V a) U aj al ^ L O a u-^ 3 N o � • c L v¢ O a c N lD O to 00 H^ o u m_ oo a i a C^ u N ra c t�D `t N N ca ¢ +- t C C x v co v o a bo v o o d^ @) m U N 0 N¢ N v E O Y a 0 N n C In aL.+ U N Ln L h U N\ di L y0 a1 O fl. O `n o o 0 'to CP t6 �m L L Q/ f0 O y0 o w a. m N m� m_ a 3 u a c @ c 3 u-0 CC �, v E' m w ,«- m 3 u c ai o c Y m v .� 3 c u o o -aa aL+ Q 3 0zi Ln Q 06 tn a U rn v E c o� u u v a xa nr� rn v p xa m v i m ZD a u u No v v 3 3 m t a c n a a E c� 2i 0 d O CL O Q tLo f6 L fa o d c c n Q v •n °�° ~ E m toom m v E v N rn E v v c fl- '^ CD `o v c @ T 4- N T 4-: N O n y v n '3 aa) n o u vo o u voo� c E m c@ u00 o a,- " v v @ c m v O E 3 4- E N ai g E uv o o m oCc a c�= m m 'opo o c�-2 m m m1D� vin a c �c U o .� u v19�� � v u 3 a v> o a a) U a) j U m c° a m i c n Q m E v a m E v ¢a.� u ¢ v o" o x Cl i� c @ v E as Ca o.w 3 t CL H u� u a aEi a o U s u v rl O ¢ m O _0 _0 v a Q a a) _0 a) a v m o Q o 0 0 o z o 0 0 s u V u u u u u U 0 I - E m `� m m `C m m `� m `- m m m mJ a u "' N N N V) N N N N in U O 4, O. C U U U U U U U U U aC) O m m m m to m m m m G m u N N N N N Ln N N N Co o H l Q N C Ln W O W 000 il 0000 n Cl z O Ol O Q) W CL m 0 m m m m ori m m m O Ln riN 00 M Ln Q ILD f- Ln O� Co0. 00 m m 00 m L' Z O Ili 00 m 00 m m z in co06 a a v a o a a v 06 06 06 06 06 co 66 N a a a a a a a a O O c -I ca rl J O Q Om J N O O N N O OCL N 2 2 J J O O O O O O O O O O O �- A O O N O O O .-i O O O MO O 1?9 O O N M Ln M l0 lD m M O d m Ln O Ln h I:t cf• r - Q m o O rn rn m m m N N i rl N N Q1 ri N N N N N m N m N N N 0) Ol N Ql a) Ql 0) Ql Q1 N N O N N N N N N O O O� O O O O O O O O O O O O O O In Ln Ln Ln Ln N Ln Ln O� 00 O �' .moi N rV 1 i ri O O 1- O O 1� O O m d' 't O O n n O a O 0000 0000 0 000 o O O O O k 2 '.13 t .0 N uw E0 o CL Q j O m O 006oo W n' � t m m m m a a a a a aoq N p O^ d m j z z z z 0 0 0 0 0 0 c u Ln O f0 co O •(0.f6 f0 f0 !6 .!O .f6 !0 .f6 (D 3 N N D C_ L L L L L L L L L L. N ra 0 N @ d n3 J (6 J (6 J f0 J m J f0 J m J f0 J L0 _1 m J •� 0 C m U U O N d C ° 2 Q 7 v d= to 0 a a a a a a a a a a a z z z z z z z z z z z 0 a) U U U UU U U U U U U U It N Ln Ln Ln N Ln Ln Ln N Ln Ln N Q) a) a) a) a) a) a) a) a) a) N a) U U U U U U U U U U U U ro f0 f0 m m m m m m m m m n 7 O 7 7 7 7 3 7 ' N (n (n V) N N Ln In In (n V) n (n) a aaaaaaaaaaL^ j z zzzzzzzzzz00 m a aaaaaaaaaa00 0 z z z z z z z z z z z a) a m m m m a a a a a a o z z z z 0 0 0 0 0 0 a � au L L M u `i a ^ a m LD r, 00 rn t m m N Gi' N ri e -i i ri rl M a a a a a- m a a a a a a- 0 0 0 0 0 o O O 0 0 0 0 0 0 0 0 0 0 0 0 0 � o-1 0 0 0 9 0 6 0 0 0 O 0 0 0 0 0 0 0 0 0 0 0 O n W 00 Ln M O 00 O Ln N O^ n Ln r- m N Ln rl d' N Ln LO rn Ln am Ln 0 0 M w M Lo w N M N m m m LD M Lo m M N N N N N N N M N M N N N Ol Ol O1 O1 O1 Q1 O1a) 0) Ol N N N N N N 0) N Ol N N NO 0 0 0 0 0 0 0 " 0 0 O O O O O O 9 O O O 0 Ln Ln Ln Ln Ln Ln O Ln � Ln Ln 0 0 ri -�t m O n O 11 r-1 Ln O C}' M N Ln Ln N Ln [r -�t LO N 1- Ln 0) ri 1- rI 1 rI O rI O 1- O 1i 1i O LIlLn LD Ln Ol mOl Ql mOl 0) O i -I r -I r -I r -I r -I c -I r -I r -I r -I r -I r -I N N N N N N N N N N N N 150' - 15.7 ppg Arctic Set NOTE: Surface casing and con- ductor casing to be cut below ground level and removed. An Orig. KB Elev. = 54.3' ✓i a n o �O Orig. GL Elev. = 23.2' "L-20" Conductor Casing at -80' MD 9-5/8" Cement Retainer (150' MD) (possible use of) ---- 9.0-9.4 ppg Mud/Brine Abandonment Marker wUl be 50' Cement Above Retainer to -2475' MD installed per AOGCC regulations. %^95/8" Cement Retainer (-2525' MD) "Planned" TOC 2525' MD —9-5/8', 40#/ft., L-80 BTC at -2625' MD 8-1/2" KOP -2628' MD (Fully Cemented to Surface) (Liviano-01 A) 15.8 ppg G Cement - u' (/2725' to2525' MD ' ' - 17.0 ppg G Cement Kick -Off Plug _ _ U284T MD r- Top 7" Stub 2720' MD 9.0-9.4 ppg Mud/Brine —15.8 ppg G Cement x _ f/3040'- 2847' MD (above retainer) 500' above top Hydrocarbon 77' Cement Retainer (-3040' MD) 2909' MD (Top Ugnu at 3409' MD) 9,�'' a'.' % �- s -15.8 ppg G Cement 3 F � 7" 26#/ft., L-80 BTC -production casing, (Drift ID = 6.151", 15.8 ppg G Cement it cap. = 0.0383 bpf) fNVell TD -4239' to — 500' aoove top Ugnu g at 2909' MD o "—CementelUgn_u Rerfs (-3520'- 3532' MD) — 7" Float Collar 3650' MD (7" Shoe Track f/3650'- 4306' MD) —7" Float Shoe 4306' MD Liviano-OtA� Planned Liviano-01 Open-HoleTD TD - 4239' MD 4314' MDI 4169' TVD DATE I REV. BY COMMENTS MILNE POINT UNIT 01/25/07 JGR Final P&A Schematic Liviano-01 A 03/19/07 1 JGR Application f/Sundry Approval Wellbore Hilcorp Alaska, LLC Milne Point Unit (MPU) M-35 Drilling Program Version 1 1/6/2020 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.....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 R/U and Preparatory Work..........................................................................................................10 10.0 N/U 21-1/4" 2M Diverter System.................................................................................................11 11.0 Drill 12-1/4" Hole Section.............................................................................................................13 12.0 Run 9-5/8" Surface Casing...........................................................................................................16 13.0 Cement 9-5/8" Surface Casing.....................................................................................................21 14.0 BOP N/U and Test.........................................................................................................................26 15.0 Drill 8-1/2" Hole Section...............................................................................................................27 16.0 Run 4-1/2" Injection Liner (Lower Completion)........................................................................32 17.0 Run 3-1/2" Tubing (Upper Completion).....................................................................................37 18.0 RDMO............................................................................................................................................38 19.0 Doyon 14 Diverter Schematic.......................................................................................................39 20.0 Doyon 14 BOP Schematic.............................................................................................................40 21.0 Wellhead Schematic......................................................................................................................41 22.0 Days Vs Depth................................................................................................................................42 23.0 Formation Tops & Information...................................................................................................43 24.0 Anticipated Drilling Hazards.......................................................................................................44 25.0 Doyon 14 Layout............................................................................................................................47 26.0 FIT Procedure................................................................................................................................48 27.0 Doyon 14 Choke Manifold Schematic..........................................................................................49 28.0 Casing Design.................................................................................................................................50 29.0 8-1/2" Hole Section MASP............................................................................................................51 30.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................52 31.0 Surface Plat (As Built) (NAD 27).................................................................................................53 32.0 Schrader Bluff OA Sand Offset MW vs TVD Chart..................................................................54 1.0 Well Summary Milne Point Unit M-35 SB Injector Drilling Procedure Well MPU M-35 Pad Milne Point "M" Pad Planned Completion Type 3-1/2" Injection Tubing Target Reservoir(s) Schrader Bluff OB Sand Planned Well TD, MD / TVD 17,558' MD / 3,819' TVD PBTD, MD / TVD 17,558' MD / 3,819' TVD Surface Location (Governmental) 4913' FSL, 291' FEL. Sec 14, T13N, R9E, UM, AK Surface Location (NAD 27) X= 533,873.8 Y= 6,027,765.6 Top of Productive Horizon (Governmental) 1096' FSL, 2160' FWL, Sec 13, T13N, R9E, UM, AK TPH Location (NAD 27) X= 536,345.3 Y= 6,023,959.7 BHL (Governmental) 2441' FNL, 1533' FEL, Sec 30, T13N, R10E, UM, AK BHL (NAD 27) X= 543,223 Y=6,015,180 AFE Number 2010035M (D,C,F) AFE Drilling Days 17 days AFE Completion Das 3 days AFE Drilling Amount $3,937,378 AFE Completion Amount $1,601,889 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1329 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1722 psi Work String 5" 19.5# 5-135 DS -50 & NC 50 KB Elevation above MSL: 33.7 ft + 25.3 ft = 59 ft GL Elevation above MSL: 25.3 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 2.0 Milne Point Unit M-35 SB Injector Drilling Procedure Management of Change Information Hilcorp Alaska, LLC Hililc rp Changes to Approved Permit to Drill Date: 116/2020 Subject: Changes to Approved Pennit to Drill for MPU M-35 File #: MPU M-35 Drilling and Completion Program Any modifications to MPU M-35 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be approved in advance to the AQGCC. / Approval: Prepared: Page 3 Drilling Manager Date Drilling Engineer Date By 3.0 Tubular Program: Milne Point Unit M-35 SB Injector Drilling Procedure Hole OD (in) ID (in) Drift in Conn OD in Wt #(psi) Grade Conn Burst Collapse (psi) Tension (k -lbs) Cond 20" 19.25" - - - X-52 Weld k lbs Surface & 5" 12-1/4" 9-5/8" 8.835" 8.679" 10.625" 40 L-80 TXP 5,750 3,090 916 8-1/2" 4-1/2" 3.96" 3.795" 4.714" 13.5 L-80 H625 9020 8540 279 Tubing 3-1/2" 2.992" 2.867" 4.500" 9.3 L-80 EUE 8RD 9289 7399 163 4.0 Drill Pipe Information: Hole OD ID (in) TJ ID TJ OD Wt Grade Conn M/U M/U Tension Section in in in(#/ft) � " '� _ ' Min Max k lbs Surface & 5" 4.276" 3.25" 6.625" 19.5 5-135 GPDS50 36,100 43,100 560klb Production 5" 4.276" 3.25" 6.625" 19.5 5-135 NC50 31,032 34,136 560k1b All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 5.0 Internal Reporting Requirements Milne Point Unit M-35 SB Injector 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 pmazzolinighilcorp.com, mmyers(a,hilcorp, jenael@hilcorp.com and cdinger@hilcorp.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 -Rud' Casing tally to mmyersng,hilcorp,com jengelghilcorp.com and cdingerghilcorp.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mmyers2hilcotp.com jengelghilcorp.com and cdingerghilcorp.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 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 lengel@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 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 Milne Point Unit M-35 SB Injector Drilling Procedure 6.0 Planned Wellbore Schematic Milne Point Unit Well: MPU M-35 Proposed Schematic PTD: TBD API: TBD Q KB Eek :5Y/GL Eat:25-V TD=174W JrM }TD=3,B1V iTM PBTD= 57,556' JtM / PM=3,511-ITM Page 6 r--------------------------- ------------------------------ TREE & UVELLFIEAD TreeWhig Westhead Cameron 11' SK x bottom wJ 121 2-1136" SK outs --------------------------------------------------------------------------- OPEN HOLE/ CEMENT DETAIL 42" It 'M U 5% 1 -Lead 1145 R3 1 Tail 458 R3 12-1/4 Stg 2 -Lead 1937 R3 / Tail 314 ft3 9-1/2" 1 Cts Irt ection Liner in 8-112" hale -------------------------------------------------------- CASING DETAIL Size Type &V Grade] Conn DriftlD Top M BPF 20"x34" ConduttorIInsidatedl 215.5/)t-52/Well N/A Surface 114' IVA 9 -vv, Surfwr 40/L-90/TO 8.679" Surface 6,400' 0.0758 4-1/2^^ Liner 135 J L -BO } 62S 3-795" 6,250' 17^5S8' 0.0149 TUBING DETAIL 3-1 Tubin 93 L-Bti [UE PRD 1 2.867— 1 Surf 1 6.259 1 0A670 WELL INCLINATION DETAIL KOP @ 300' tluleAn le@%N=TBD' ilDleAn le@Liner Tap=TBD' Max dole Angle =TBD` ----------------r--------• JEWELRY DETAIL No Top MO n m 10 upper Comp etion 1 TBD 3-112" %Ni Ir 2.913" Packin Buml 2.813" 2 TBD 3-1}2" XN Nipplq 2.613" Packin Bcre, 2.75' No -Ga, wJRhC 2.750' 3 TBD 3-112" Gauge Mtandrel5GNi-XPQG w/ V Wire 2.992" 4 TBD 8.25' ND Ga Lacater Sub 12.76 off No- of 6.170" 5 TOO 7.375" Tieback above the SMP Liner Tap Packer 6.170" Lower Contp ion 6 A259 7' x 9-518" SMP Liner Tap Packer with 7.38' Seal Bare 6.180" 7 17,558^ Shoe 3.970' Depth Depth ICD/Sewell Packer Detail MD TVD Teo --------------------------------------- GENERALWELL INFO APht TBD Completed tyf Down 14_ TBD Milne Point Unit M-35 SB Injector Hilcorp Drilling Procedure 7.0 Drilling / Completion Summary f MPU M-35 is a grassroots injector planned to be drilled in the Schrader Bluff OB sand. M-35 is partof 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 4-1/2" ICD injection liner will be run in the open hole section. The Doyon 14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately January 28, 2020, pending rig schedule. Surface casing will be run to 6,400' MD / 3,914' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, ° 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. Install MPD Riser 5. Drill 8-1/2" lateral to well TD. Run 4-1/2" injection liner. 6. Run 3 -1/2" tubing. 7. 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 7 Milne Point Unit M-35 SB Injector 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. v • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU M-35. 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: Hilcorp Alaska LLC does not request any variances at this time. Page 8 Hilcorp E-V,L Summary of BOP Equipment & Notifications Milne Point Unit M-35 SB Injector 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 • 13-5/8" x 5M Hydril MPL Double Gate Initial Test: 250/3000 o Blind ram in btm cavity • Mud cross w/ 3" x 5M side outlets 8-1/2" • 13-5/8" x 5M Hydril MPL Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/3000 • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 3 0: 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.regg_@alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartzgalaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loepp(cr�,alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectorsgalaska.gov Test/Inspection notification standardization format: hqp://doa.alaska.gov/oac/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 9.0 RX and Preparatory Work Milne Point Unit M-35 SB Injector Drilling Procedure 9.1 M-35 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 (<80°F). 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 10 10.0 NX 21-1/4" 2M Diverter System Milne Point Unit M-35 SB Injector Drilling Procedure 10.1 N/U 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 R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. 10.2 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 11 10.4 Rig & Diverter Orientation: • May change on location M-20 ■ iM 4 M -S8 ■ M-22 ■ ■ M-17 M-23 ■ ■ M-18 M-25 ■ M-24 ■ ■ M-19 U-26 ■ Milne Point Unit M-35 SB Injector Drilling Procedure 75' Radius Clear of Ignition Sources Diverter Line MPU M -Pad *Drawing Not To Scale Page 12 Milne Point Unit M-35 SB Injector Hilco Drilling Procedure F-- 11.0 Drill 12-1/4" Hole Section 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" 19.5# 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. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • 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). • Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. Page 13 Milne Point Unit M-35 SB Injector 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 • Past wells on E pad have increased MW and added 1-1.5ppb of Lecithin & .5% lube. After drilling through hydrate sands, MW was cut back to normal • 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. AC: There are no offset wells with a clearance factors <1.0 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 (ppg) 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. Page 14 ti Milne Point Unit M-35 SB Injector Hilcorp Drilling Procedure E -W C-pAy • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type: 8.8 - 9.2 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH I Tem Surface 8.8 - 9.8 ' 75-175 20-40 25-45 510 8.5-9.0 1 System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M -I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 Pol Pac Supreme LJL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 1 55 1 gal dm 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. • 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 15 Hilcorp Energy Company 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull wearbushing. Milne Point Unit M-35 SB Injector 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 4 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 assemblv consistiniz of - 9 -5/8" Float Shoe 1 joint — 9-5/8" TXP, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" TXP, 1 Centralizer mid joint w/ stop ring 9-5/8" Float Collar w/ Stage Cementer Bypass Baffle `Top Hat' 1 joint — 9-5/8" TXP, 1 Centralizer mid joint with stop ring 9-5/8" HES Baffle Adaptor • Ensure bypass baffle is correctly installed on top of float collar. This end up. Bypass Baffle • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 16 12.5 Float equipment and Stage tool equipment drawings: Type H ES Cementer Part No_ SO No_ Closing Sleeve No. Shear Pins Opening Sleeve No. Shear Pins ES Cementer Depth Baffle adapter (if used) ID Depth Bypass or Shut-off Baffle ID Depth Float Collar Depth Float Shoe AT Depth Hole TD "Reference Casing Sales Manual Section 5 Page 17 "A Overall Length B Min. ID After Drillout C Max. Tool OD D Opening Seat ID E Cie -sing Seat ID Plug Set Part No. SO No. Closing Plug OD Opening Plug OD OD Shut-off Plug OD Bypass Plug (if used) OD Milne Point Unit M-35 SB Injector Drilling Procedure Hikorp ES41 Running Order ES41 Cementer Shut Off Plug Baffle Adapter By -Pass Plug By Pass Baffle Float Collar Float Shoe Milne Point Unit M-35 SB Injector 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: • Verify depth of lowest Ugnu water sand for isolation with Geologist Depth Interval Centralization Shoe — 1000' Above Shoe 1/jt 1000' above Shoe — 2000' above Shoe l/ 2 jts (Top of Ugnu) • 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 ES -II Stage 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 centralizers 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 18 Hilcorp TXPG BTC Outside Diameter 9.625 in. Wall Thickness 0.395:in. Grade LBO Type 1 Min. Wall 87.5% Thickness Connection OD REGULAR Option Drift API Standard Type Casing Milne Point Unit M-35 SB Injector Drilling Procedure ,,.,.eon 11108/2018 (') Grade LBO low Type i COUPLING PIPE BODY Body: Red 1st Sand: Red 1st Sand: Brown 2nd Sand: 2nd Barad: - Brown 3rd Sand:- 3rc Band: - 38.97 IbVIt 41h Band- - GEOMETRY Nominal CEJ 9.625 in. Norninal Weight 40 lbs,lt Drift 8.679 in. Rcminal ID 8.835 in. 'r'W Thickness 0.195111. Plair, End Vieight 38.97 IbVIt OD 7c4srasoe AR REGULAR PERFORMANCE PERFORMANCE Body'r*tSm,.gh 916x10001ts Interna "•'ed 5750 psi S.hl'yS 86000 psi caiapse 3090 psi GEOMETRY conneotan DD 10.625 in. Coupling Length 10.625 -1 Connection ID 8.823 in. hta�Ke-up Loss 4.991 in. Thread's per in 5 Connection OD Option REGULAR PERFORMANCE Tansien Eff6encj 100.0% binTYiaU Sbwglh 916.000 x1000 Internal Pressure Capacitor In 5750.000 psi lbs Compression Eirx:iency 100 Compression Shangsh 916.000 x1000 Max. A11olvabie Bending 38'4100 ft Ibs Ex€emal=-ess�-e Ca^,.acity 3090.0911 ps MAKE-UP TORQUES V,i.murr 188603-_s Optimum 20990h4bs Maximum 22CcrF-Ibs OPERATION LIMIT TORQUES Oper3brg Toque, 356001t-Tts Yield Torque 43400 k -lbs Notes This connection is full', interchangeable with: TXn� BTC - 9.625 in- - 36 143.5 147 153.5 d 58.4 Ibslft [1] Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API 5031 ISO 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 Tenarts technical sales representative. Page 19 Milne Point Unit M-35 SB Injector 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 20 13.0 Cement 9-5/8" Surface Casing Milne Point Unit M-35 SB Injector 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 1St 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 1St Stage Total Cement Volume: Section Calculation Vol (bbl) Vol (ft3) 12-1/4" OH x 9-5/8" Casing (5,400'- 2500') x .0558 bpf x 1.3 = 210.4 1181.2 Total Lead 210.4 1181.2 12-1/4" OH x 9-5/8" Casing (6,400'- 5,400') x .0558 bpf x 1.3 = 72.5 407 9-5/8" Shoe Track 120' x .0758 bpf = 9.1 51.09 Total Tail 81.6 458 Page 21 Milne Point Unit M-35 SB Injector Drilling Procedure Cement Slurry Design (1st Stage Cement Job): Note: Lead Cement Viscosity to be lowered to prevent poor interface once stage tool is opened and cement is circulated to surface 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. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 6,192' x.0758 bpf = 469.4 bbls 80 bbls of tuned spacer to be left behind stage tool, confirm spacer is compatible with cement behind stage tool & that sufficient spacer will be above the tool to exit when circulation is established. 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, ±4.5 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 confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until Page 22 Lead Slurry Tail Slurry Density 12.0 Ib/gal 15.8 Ib/gal Yield 2.35 ft3/sk o/ 1.16 ft3/sk t/ Mixed Water 13.92 gal/sk 4.98 gal/sk Note: Lead Cement Viscosity to be lowered to prevent poor interface once stage tool is opened and cement is circulated to surface 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. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 6,192' x.0758 bpf = 469.4 bbls 80 bbls of tuned spacer to be left behind stage tool, confirm spacer is compatible with cement behind stage tool & that sufficient spacer will be above the tool to exit when circulation is established. 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, ±4.5 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 confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until Page 22 Milne Point Unit M-35 SB Injector Hilco+T�� Drilling Procedure E� Campmy 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. If ESIPC is ran, pressure up to 3000 psi to open tool and function as an ES -II Stage tool 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 23 Milne Point Unit M-35 SB Injector Hilco Drilling Procedure Energy cm� Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Hold pre job safety meeting. 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 2nd stage. i 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. t, -,D v Estimated 2°d Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): Section Calculation Vol (bbl) Vol (ft3) FU 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 11 1937 — 12-1/4" OH x 9-5/8" Casing (2500' - 2000') x .0558 bpf x 2 = 55. 314 ~ Total Tail 55. 314 Cement Slurry Design (2nd stage cement job): Page 24 Lead Slurry Tail Slurry System Permafrost L Density 10.7 Ib/gal 15.8 Ib/gal Yield 4.41 ft3/sk 1.17 ft3/sk - Mixed Water 22.02 gal/sk 5.08 gal/sk Page 24 Milne Point Unit M-35 SB Injector Hilco+ry��+ Drilling Procedure Energy cmnpauy 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 during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As -Run "casing tally & casing and cement report to jengelghilcorp. com and cdingerkhilcorp. com This will be included with the EOW documentation that goes to the AOGCC. J Page 25 14.0 BOP NX and Test Milne Point Unit M-35 SB Injector Drilling Procedure 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 Run 5" BOP test plug 14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Test 5" test joints • Confirm test pressures with PTD • 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 14.5 R/D BOP test equipment 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 8.9 ppg F1oPro fluid for production hole. - 14.8 Set wearbushing in wellhead. 14.9 If needed, rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.10 Ensure 6" liners in mud pumps. Page 26 Hileorp 15.0 Drill 8-1/2" Hole Section 15.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.22° PDM) Milne Point Unit M-35 SB Injector 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. 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 1/4 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 Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20' of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH & LD Cleanout BHA 15.9 P/U 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# S-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 27 Hilcorp Energy Cmnpany Milne Point Unit M-35 SB Injector 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 sufficient hole cleaning • 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 F1oPro drilling fluid Properties: Interval pensit PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 15-30 4-6 <10% <8 <1 1.0 <100 System Formulation: Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gal/ 100 bbls) 55 gal dm 0.2 FLONIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify) 50 lb sx 10 SAFE-CARB 20 (verify) 50 lb sx 10 Soda Ash 50 lb sx 0.5 Page 28 Hilcorp 15.11 TIH with 8-1/2" directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Flo Pro drilling fluid Milne Point Unit M-35 SB Injector 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. e • 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 OA & 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 • Offset injection pressure from F-110 & L-50 has been seen on recent M -Pad wells. Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up on connections • AC: • M-16, 17, 18, & 19 have clearance factors <1.0, but are in the OA sand, — 50' TVD above target OB sand for M-35 • J-24 is an abandoned OB producer. The only risk is damage to the bit • J -24A is abandoned. • J-23 is an abandoned OB injector. The only risk is damage to the bit • J -23L1 is abandoned. • J -23A is a lateral injector in the NB sand, — 220' TVD above M-35 • Schrader Bluff OA Concretions: 5-10% of lateral • L-47: 6%, L-50 9.5% Page 29 V/ Milne Point Unit M-35 SB Injector Drilling Procedure • F-106: 6.1%, F-107: 4.7%, F-018: 9.9%, F-109: 10%, F-110: 10.1% 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 approx. 30 min. • Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 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 • Ensure mud has necessary lube % for running liner • If seepage losses are seen while drilling, consider reducing MW at TD to 9.Oppg minimum 15.17 Once hole is clean, displace to lubricated, viscosified 8.8 ppg 2% KCl brine. 15.18 Monitor the returned fluids carefully while conditioning the mud. After 4 (or more) BU, Perform production screen test (PST). The mud has been properly conditioned when the mud will pass the production screen test (0 350ml samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure • Injection Control Devices (ICDs) are wire wrapped, and require passing PST with 250µ Coupons • Circulate and condition mud as much as needed to pass the production screen test • If not passing after first test, call Completion Engineer 15.19 BROOH with the drilling assembly to the 9-5/8" casing shoe • Circulate at full drill rate (385 gpm max). • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe 15.20 CBU minimum two times at 9-5/8" shoe and clean casing with high vis sweeps. 15.21 Monitor well for flow. Increase mud 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 If necessary, increase MW at shoe for any higher than expected pressure seen 1�/ Page 30 Milne Point Unit M-35 SB Injector Drilling Procedure 15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. 15.23 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 31 16.0 Run 4-1/2" Injection Liner (Lower Completion) Milne Point Unit M-35 SB Injector Drilling Procedure 16.1. Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2" liner with ICD and swell packers, the following well control response procedure will be followed: • With ICD across the BOP: P/U & M/U the 5" safety joint (with 4-1/2" crossover installed on bottom, TIW valve in open position on top, 4-1/2" handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2" liner. • With 4-1/2" solid joint across BOP: Slack off and position the 4-1/2" solid joint to MU the TIW valve. Shut in ram or annular on 4-1/2" solid joint. Close TIW valve. 16.2. Confirm VBR have been tested on 4-1/2" and 5" test joints to 250 psi low/3000 psi high. 16.3. Well control preparedness: In the event of an influx of formation fluids while running the 2- 3/8" inner string inside the 4-1/2" liner: • P/U & M/U the 5" safety joint (with 4-1/2" x 2-3/8" triple connect crossover installed on bottom, TIW valve in open position on top, 2-3/8" handling joint above TIW). M/U 2-3/8" and then 4-1/2" to triple connect. • This joint shall be fully M/U with crossovers and available prior to running the first joint • Slack off and position the 5" DP across the BOP, shut in ram or annular on 5" DP. Close TIW valve. Proceed with well kill operations. 16.4. R/U 4-1/2" liner running equipment. • Ensure 4-1/2" Hydril 625 x DS -50 crossover is on rig floor and M/U to FOSV. • Ensure the liner has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 16.5. Run 4-1/2" injection liner. • Use API Modified or "Best O Life 2000 AG" thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the ICDs. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Use lift nubbins and stabbing guides for the liner run. • Fill 4-'/2" liner with PST passed mud (to keep from plugging ICDs with solids) • Install ICDs and swell packers as per the Running Order • (From Completion Engineer post TD). • Do not place tongs or slips on swell packer elements or ICDs. • ICD and swell packer placement ±40' • The ICD connection is 4-1/2" 13.5# Hydril 625 • Remove protective packaging on swell packers just prior to picking up If liner length exceeds surface casing length, ensure centralizers are placed I Jt for each joint outside of the surface shoe. This is to mitigate difference sticking risk while running inner Page 32 ff Hilcorp Fnergy Company Milne Point Unit M-35 SB Injector Drilling Procedure • Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm 4-1/2" 13.5# L-80 H625 Casing OD Minimum Optimum Maximum Operating Torque 4.5" 8,000 ft -lbs 9,600 ft -lbs 12,800 ft -lbs Page 33 For the latest performance data. always visit our website: www.tenarts.com Wedge 625® OutsweDiameter 4.500®. Wall Thickness 0290 in. Grade L80 Type 1' GEOMETRY Min_ Wall 87.56 Thickness Connection OD REGULAR Option Drift API Standard Type Casing Milne Point Unit M-35 SB Injector Drilling Procedure ,— —.12/04/2017 (`) Grade LBO 4.500. Type 1 13.50 -'ft COUPLING PIPE BODY Body: Red tet Band: Red "st Band: Brown 2nd Band: 2nd Band: - Brown 3rd Bane: - 37d Band: - 41h Band- - Nominal OD 4.500. Nominal Weia*t 13.50 -'ft Drift 3.795 ,r:- Nominal ID 3.920 n:. watThickness 0290 -n. Hain E^d Weight 13.05%s"t CO Tck ance API PERFORMANCE Body Y'* d Ctrengn 307 x1XC, lbs internal Yield 902D ps SMYS 80000 ps'. Collapse 6540 ps _ .. _ta r , _.. GEOMETRY C:annedtrc OD 4.714 c+. ConneCtICM ID 3.849 n. Make-up Loss 4.830 m Threads,„ re in 3.59 Connectors OD Option REGULAR PERFORMANCE Tension Efiicie cy 91.0% Jaint Yek1 Strength 279.370 x1000 Internal Pressure Capacity 9020.000 psi Ibs Compression ErTicie^cy 94.5 % Compression strength 290.115 x*X Max..,'•Ta able Bending 73.7'MC0 ft lbs External Pneessure Capacity 8540.000 psi MAKE-UP TORQUES Minimum 8000 ft -lbs Cpamum 9600 4-Ibs btaxim�m 12800 ftAbs OPERATION LIMIT TORQUES Cperam,g Ibrclue 12800 5-Ibs Yield Tarq.:e 15000 `tabs Notes For further information on concepts indicated in this datasheet, download the Datasheet Manual from www.tenafis.com 16.6. Ensure that the liner top packer is set — 150' MD above the 9-5/8" shoe. • AOGCC regulations require a minimum 100' overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8" connection. 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. Page 34 Hilcorp Milne Point Unit M-35 SB Injector Drilling Procedure 16.8. M/U Baker SLZXP liner top packer to inner string and 4-1/2" liner. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 16.9. Note weight 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 DP no faster than 30 ft/min —this is to prevent buckling the liner and drill string. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 16.11. The liner will auto fill. Top off DP every 5 stands, more frequently if SOW trend indicates. 16.12. 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. 16.13. 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. 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. 16.17. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. 16.18. Continue 12ressurinj4 up to 2700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the ZXP to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4100 psi to neutralize and release running tools. 16.19. 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 50k# again, 16.20. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.21. 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. Page 35 Milne Point Unit M-35 SB Injector Drilling Procedure 16.22. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. Rack back enough 5" drill pipe for liner top clean out run 16.23. Make up 3.5" wash tool & RIH on 5" DP to 4.5" liner top. 16.24. Flush liner top at max rate while displacing out well to clean brine. 16.25. POOH LD Remaining 5" DP. 16.26. Once running tools are L/D, Swap to Completion AFE. Page 36 17.0 Run 3-1/2" Tubing (Upper Completion) Milne Point Unit M-35 SB Injector Drilling Procedure 17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to wrivard(a,hilcorp.com for submission to AOGCC. 17.2 17.3 17.4 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min. • Ensure wear bushing is pulled. • Ensure 3-1/2" EUE 8RD x NC -50 crossover is on rig floor and M/U to FOSV. • Ensure all tubing has been drifted in the pipe shed prior to running. • Be sure to count the total # of joints in the pipe shed before running. • Keep hole covered while RAJ casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. • Monitor displacement from wellbore while RIH. 3-1/2" 9.3# L-80 EUE 8RD Casing OD Minimum Optimum Maximum Operating Torque 3.5" 2,350 ft -lbs 3,130 ft -lbs 3,910 ft -lbs 3-Y2" Upper Completion Running Order • 3-1/2" Baker Ported Bullet Nose seal (stung into the tie back receptacle) • 3 joints (minimum, more as needed) 3-1/2" 9.3#/ft, L-80 EUE 8RD tubing • 3—%2" "XN" nipple at TBD • 3-1/2" 9.3#/ft, L-80 EUE 8RD tubing • 3—%2" "X" nipple at TBD MD • 3-1/2" 9.34/ft, L-80 EUE 8RD space out pups • 1 joint 3-1/2" 9.3#/ft, L-80 EUE 8RD tubing • Tubing hanger with 3-1/2" EUE 8RD pin down Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals engaged. Bleed pressure and open annular. Space out the completion (+/- 1' to 2' above No -Go). Place all space out pups below the first full joint of the completion. Page 37 Milne Point Unit M-35 SB Injector Drilling Procedure 17.5 Makeup the tubing hanger and landing joint. 17.6 RIH. Close annular and test to 400 — 500 psi to confirm seals are engaged. Bleed pressure down to 250 psi. PU until ports in seal assembly exposed. 17.7 Reverse circulate the well with brine and I% corrosion inhibitor. 17.8 Freeze protect the tubing and IA to 3000' MD with ±210 bbl of diesel. \ 17.9 Land hanger. RILDs and test hanger. til 17.10 Continue pressurizing the annulus to 2500 psi and test for 30 charted minutes. i. Note this test must be witnessed by the AOGCC representative. 17.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and tree. 17.12 Pull BPV. Set TWC. Test tree to 5000 psi. 17.13 Pull TWC. Set BPV. Bullhead tubing freeze protect. 17.14 Secure the tree and cellar. 18.0 RDMO 18. RDMO Doyon 14 Page 3 8 19.0 Doyon 14 Diverter Schematic 1r4' 2M Risw — 21.1!4' 2M-- Diverter 'i• 21-1W A Spacer Spm 16-34'3M a 21-1W 2M DSA Page 39 Milne Point Unit M-35 SB Injector Drilling Procedure –16' fug Opening Knda Valve 16- DMeder Lina 20.0 Doyon 14 BOP Schematic Kid Lias ------ Page 40 Milne Point Unit M-35 SB Injector Drilling Procedure 2-7/8" x 5" VBR Blind Rams x SM HCR :hone Line it Gate Valve 2-7/8" x 5" VBR Milne Point Unit M-35 SB Injector Hilco Drilling Procedure E --W ,—R 21.0 Wellhead Schematic CAMERON 11 " 5K A4BS A Schlumberger Company 4-1/16"5K 16.09" 11" 5K ?-1/16" 5i: 37.3411 2125" a 4 �/sGJ s Control Line:✓^ GC wt1 c 24.87" Nate: Dim...•;., ag mfo=ata n redge ted on this drawing ase c -t m ted measvr tz Cray- . Page 41 Hilcorp Energy Czi 22.0 Days Vs Depth N m mm 6000 t Y Cu 8000 .a G1 �5 10000 d 2 12000 14000 16000 MPU M-35 SB Ob Injector Days vs Depth Milne Point Unit M-35 SB Injector Drilling Procedure jector 18000 0 5 10 15 20 25 Days Page 42 23.0 Formation Tops & Information Milne Point Unit M-35 SB Injector Drilling Procedure MPU M-35 Formations (wp04) MD (ft) TVDss (ft) TVD (ft) Formation Pressure (psi) EMW (ppg) Base Permafrost 2267 -1797 1855 816.2 8.46 LA3 4424 -3063 3121 1373.24 8.46 Ugnu MB 4891 -3337 3395 1493.8 8.46 Schrader Bluff NA 5280 -3565 3623 1594.12 8.46 Schrader Bluff OB 6440 -3857 3915 1722.6 8.46 L -Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad) GENERALIZED GEOLOGICAL FORECAST___ SS GEOLOGICAL TVD FM LITH DESCRIPTION COMMENTS oar w« NOTE: Soo individual Well Program for T Gu bk specific casing design, depths. sizes. .r--100' 6-n weights, grades and connections. • • Unconsolidated coarse to modum sand and small gravel with minor siltstone. 1,000' IF SIGNIFICANT AMOUNTS OF GRAVEL a ARE ENCOUNTERED WHEN DRILLING THE -4*m SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. ,Iso• Base permafrost kitorbods of sand. clays and slltstoms with occasional 2.000' show of cwt. Watch possible sidetracking while ahing"aming. L31 d L•15. waro Sagava irklok .rq*= No hydrates encountered on L -Pad wells drilled to date. Continued intozbods of sand. clays and sittstones with occasional shows of coal. Traces of pyrite at N- 3100 It 3,000, Interval at +1. 3400 it can be sticky and tight (L-01). ' Clay Interbods between 3000 and 4500 It C 3472'• L A 3657' kasnea y UGNU: Series of coarsening upward sands which aro (•AB.CAI made up of: (from top to bottom) coarse sand firm sand. silty shale. Better developed intervening shales as you UGNU progress into the Land M (doeper), Ugnu and Schrader Bluff: Possible hydrocarbons limited to S W corner of Milne development Northern area is (aAef downstructure and wet. •3739• M -sines t•AB C! •4000' (NA) Schrader Bluff Sands: 4,000' ri (-AB.C.D. Continued layering coarsening upward sands as above 4- Schrader Bluff: Possible lost circulation E.Fl except more condensed and with occasional coal. zone while drilling long strings and running •4170' os -m Clay rich shale interval 4100 to 4600 ft Ugnu and Schrader Bluff: Pmsiblo hydrocarbons limited casing. Recommend deep setting surface lOA) hAB.C. to S W tomer of Milne development L37 and L-45 aro casing for Kuparuk long strings. Also, the O.E.F) completed in the Schrader Bluff sand. Northern ares of Schrader Bluff sands are a potential Schrader L -Pad Is downstructum and wet. differential stuck pipe interval if left un -cased Bluff C Surface casing point in shale below for Kuparuk long strings. Sands: I I Schrader Bluff OB sand for longer reach wells. Page 43 24.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Milne Point Unit M-35 SB Injector Drilling Procedure Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates 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 a number of wells in close 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. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations 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 44 Milne Point Unit M-35 SB Injector Drilling Procedure 1. 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 H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 45 Milne Point Unit M-35 SB Injector Hilcox Drilling Procedure EneW Comvy 8-1/2" Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low -vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor EGDs 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: ,f 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 112S 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 f drilling operations. 2. The rig will have fully functioning automatic 1-12S 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. 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. Specific AC risk addressed in 8.5" hole section, 15. Page 46 11 Hilc x F—W Compmy 25.0 Dovon 14 Lavout i— Q �Io I Page 47 Milne Point Unit M-35 SB Injector Drilling Procedure 26.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: Milne Point Unit M-35 SB Injector 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 48 27.0 Doyon 14 Choke Manifold Schematic Milne Point Unit M-35 SB Injector Drilling Procedure Page 49 Milne Point Unit M-35 SB Injector Drilling Procedure 28.0 Casing Design 14 x�it��rp Calculation & Casing Design Factors Hole Size 12-1/4" Hole Size 8-1/2" Hole Size DATE: 1/612020 WELL: MPU M-35 DESIGN BY: Joe Engel Design Criteria: Mud Density: 9.2 ppg Mud Density: 9.2 ppg Mud Density: Drilling Mode MASP: 1329 psi (see attached MASP determination & calculation) MASP: Production Mode MASP: 1329 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress Page 50 Casing Section Calculation/Specification 1 2 3 4 Casing OD 9-5/8" 6-5/8" Top (MD) 0 6,250 Top (TVD) 0 3,900 Bottom (MD) 6,400 17,558 Bottom (TVD) 3,914 3,819 Length 6,400 11,308 Weight (ppf) 40 20 Grade L-80 L-80 Connection TX' H563 Weight w/o Bouyancy Factor (lbs) 256,000 226,160 Tension at Top of Section (Ibs) 256,000 226,160 Min strength Tension (1000 lbs) 916 459 Worst Case Safety Factor (Tension) 3.58 2.031/ Collapse Pressure at bottom (Psi) 1,934 1,887 Collapse Resistance w/o tension (Psi) 3,090 3,470 Worst Case Safety Factor (Collapse) 1.60 1.84 MASP (psi) 1,329 1,329 Minimum Yield (psi) 5,750 6,090 Worst case safety factor (Burst) 4.33 4.58 Page 50 Milne Point Unit M-35 SB Injector Hiloo Drilling Procedure E -W 29.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation Hilt 8-1/2" Hole Section MPU M-35 Milne Point Unit MD TVD Planned Top: 6400 3908 Planned TD: 17558 3819 ►nticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad ichrader Bluff OB Sand 3,908 1720 1 Oil 8.46 0.440 Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date J-23 9.1 Surface 3864 2000 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: 3908 (ft) x 0.78(psi/ft)= 3048 3048(psi) - [0.1(psi/ft)*3908(ft)]= 2657 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff OA sand) 3908 (ft) x 0.44(psi/ft)= 1720 psi 1720(psi) - 0.1(psi/ft)*3908(ft) 1329 psi Summary: -- 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Page 51 30.0 Spider Plot (NAD 27) (Governmental Sections) Milne Point Unit M-35 SB Injector Drilling Procedure Sec. 12 r r r`t rr `� r `-C-- s F. r t ADL388235 r C ' ADL'025509 '. 16281 4 , r ADL355023 rr ti r ,*s "\ L.,- _ '�-_ •` �s'\ rf r--r-r-- �a-_� f—�_r �i •____`�'. {�L-g8F13.r . r't11'L'At-341 S14L r r '- •.-',.riY'� 1 ,�/r ! tr / y� r• f / _ �' r °,_Re; .F r� r +" �-tas / 1t 1 a, Z� r �. /PESADC�,fi " / " of ♦ 10 < la � y r a lf" �.re tP.-OD, as t ♦ r Sec. 13 // r~� r a f ♦ f/ I Sec. 18 f `. 4 Sec.,14 i t 4 "> / r .r , ♦ 63Dj r rr r irr'rj � i t � t� ttttyr //Waahr .� , @�ue1cPa4 .1 1 1 1 t I�it',t / r♦ A� t 4 "a -r 1tFt_; t%i aPH f • ,,, !tea i r i ��+r a`ra It t'tt ` ^ '-�: .. 1 1 r.1.C3 f ! 1 a, I ♦♦♦ 1 r 1 a R / ♦ I,a MIE L �aaaAC31NTUNIT'a r r 1 '" r ,a / , ♦a 'r♦ ADL0255;5 t r r ADL02551.4 + • 'a f `. 1 r A a♦ r ! ! a r ♦/ r r •+ _. a r rrc . ♦ , 41 ar �t_ Pei. f ♦` NUO13NO09E� „' '^ _ a,r 6013N010Ea` .a '.a ♦ 1 mal • .. / 1 1 j Sec. 23 t ft[i=, � 1 • 5-,- 24 �` ♦ ♦ a ♦ Sec. 19. ♦ 1;6331 _ 9n Z.—sI ` f � L-3s4Pr,-. �. 1 --sem, L.3E:PE.I a a • M2G _ . . ~.. J-2ALti-34Li?81 L-354 J It1V♦ •' • ttin ••. w J.:i a ` EC11t1PralEhdT. .a.-_�_ `•� _ _ _ _ � � M-173K.3a. PAD ` a . Legend_ `E_ _ _ _ - _ KUPARI f MPUM-35i SHL ! -" -�a _a JZOA^ RIVEF X MPU M-35i_TPH a UNIT _ 1. ! Seca 30 Sec. 25 rr ADL025519 MPU M 35i_BHL - (636). _ - - - c r r Other Surface Hates (SHL} 23 *•AT)L-025517— Other Bottom Holes tB:HLt MPU \9-35i HHL r Other Well Paths r, .Jas, r r oil and Gas Unit Boundary ++ . i r r r L Pad footprint r ' t t r r y r r Ir1J11 r \ Page 52 Milne Point Unit MPU M-35 Well wp,08 .Alaska State Plane Zone 4 NAD 1927 0 1,000 2,000 Feet Eip 31.0 Surface Plat (As Built) (NAD 27) I A.S.P. COORDINATES i , —0,'—z I_--___-_---- SECTION OFFSETS PAD ELEVATION _ SEC. 12_ I —� SEC. 13 ..® SEC. 17 1 I M-44 ■ SEC. 14 I M -i0 ■ X= 533,783.96 E= 1,785.13 M-43 ■ I I M -t1 ■ M -3S Y= 6,027,765.69 ■ M-13 I M -i2 ■ I 25.0' 25.3' ■ M-14 I I E= 1,875,01 M-35 149.7231381' M-20 ■ M-57 ■ ■ M-15 +M-34 M-21 ■ I ■ M-16 Y-22 ■ i ■ N-/7 M-23 ■ ■ M-18 I M-25 ■ 'ui.rri' I M-24 ■ ■ M-17 I I M-26 ■ M-04 ■ M-03 ■ I ■ M-06 I ■ M-©8 MOOSE PAD GRAPHIC SCALE 0 t00 21:0 400 ( IN FEET ) 1 Inch - 200 1L NOTES: d 23 Milne Point Unit M-35 SB Injector Drilling Procedure M PAD— 181 SURVEYOR'S CERTIFICATE I HEREBY CERTIFY THAT 1 AM PROPERLY REGISTERED AND LICENSED TO PRACTICE LAND VEY SURING IN THE STATE OF ALASKA AND THAT TKOS AS -BUILT REPRESENTS A SURVEY MADE BY ME OR UNDER MY DIRECT SUPERVISION AND THAT ALL DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF DECEMBER 22. 2019. AS -BUILT CCNCItCTCR 1. ALASKA STATE PLANE COORDINATES ARE NAO27. ZONE 4. 2 C:E000C POSITIONS ARE NA1327. ■ EXISTING CONDUCTOR i BASIS OF HOMZWTAL AND VERMOL CONTROL ARE MOOSE PAD MCNUMENTS SMJRCAP MD NE AND SM-ACAP SM SE.. 4. WU MOOSE AVMGAE PAD SCALE FACTOR IS: 0,9979613. S DATE OF SURVEY: DECEMBER 2Z 2019. & REFERENCE FED BOOK: HOO-03 PW 69-74 LOCATED WITHIN PROTRACTED SEC. 14, T. 13 N., R. 9 E.. UMIAT MERIDIAN, ALASKA WELL NO. A.S.P. COORDINATES PLANT COORDINATES GEODETIC POSITION OMS GEODETIC POSITION D.DD SECTION OFFSETS PAD ELEVATION CELLAR 8OX EL. M-34 Y= 6,027,765.77 N- 1,168.12 70'29'12.786" 70.4868851' 4.914' FSL 24.8 25.4' X= 533,783.96 E= 1,785.13 149'43'25.941" 149.7238726' 381' FEL M -3S Y= 6,027,765.69 N= 1,168.04 70'29'12.781' 70.4868837' 4.913' FSL 25.0' 25.3' X= ., 533,873.83 E= 1,875,01 149'43'23.297" 149.7231381' 291' FEL I— DPAPEY ,�,ANreu I u 9 3 4 9 u6aff ex mell .w Ma o yr nw®u c Oak .041AM NAM u wlae Page 53 LHUcorp Alaska MPU MOOSE PAD AS -BUILT CONDUCTORS WELLS M-34 & M-35 t" Milne Point Unit M-35 SB Injector Drilling Procedure 32.0 Schrader Bluff OA Sand Offset MW vs TVD Chart SB OB wells are expected to be normally pressured, same gradient as OA 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 10.110.3 10.5 0 1 11111 500 1000 1500 2000 d 2500 3000 3500 4000 4500 Page 54 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) Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M -35i MPU M -35i Plan: MPU M-35 wp08 Standard Proposal Report 08 January, 2020 HALLIBURTON Sperry Drilling Services -75 -300 -3 Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -35i Wellbore: MPU M -35i Plan: MPU M-35 wp08 WELL DETAILS: Plan: MPU M -35i 25.30 +N/ -S +E/ -W Northing Easting Latittude Longitude 0.00 0.00 6027765.69 533873.83 700 29' 12.781 N 1490 43'23,297 W REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well Plan: MPU M -35i, True North Vertical (TVD) Reference: MPU M -35i As -built RKB @ 59.00usft Measured Depth Reference: MPU M -35i As -built RKB 59.00usft Calculation Method Minimum Curvature 0 Start Dir 4'/100'. 600' MD, 598.77TVD \5p0 - - -End Dir : 1752.3'MD, 1553.4l'TVD 0 \�5� 1ti5� 0- 0- 0— 50� 'L 0 9� gS� 0 SQ End Dir : 6100.4' MD, 3887.85' TVD Start Dir 4'/100': 6400.4' MD, 39141 -VD 9 5/8" x 12 1/4"_ End Dir : 6532.21' MD, 3919.43' TVD MPU M -35i wp08 Heel ti 0 -5250 -6000 0 � -6750 CASING DETAILS TVD TVDSS MD Size Name 3914.00 3855.00 6400.40 9-5/8 9 5/8" x 12 1/4" 3819.00 3760.00 17557.63 4-1/2 4 1/2" x 8 1/2" HALLIBURTON Sperry Drilling 7500 \C- 9750 11883.38' MD, 3894'TVD 12041.54' MD, 3885.04' TVD 8250—MPU M -35i wp06ir 40/100' : 12399.55' MD, 3846.2TVD End Dir : 12557.63' MD, 3837.33' TVD 9000 MPU M 9750 - - - - - --- -- - - -- 0500- -11250 MPU Lease line - full \Toe-- NOUM-35 : 17557.63' MD, 3819' TVD I -12000 I 4 1/2" x 8 1/2" -12750 I MPU M-3 5i wp08 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 West( -)/East(+) (1500 usft/in) to I 0 I I Start Dir 3x/100' : 300' MD, 300'TVD Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -35i Wellbore: MPU M -35i Plan: MPU M-35 wp08 WELL DETAILS: Plan: MPU M -35i 25.30 +N/ -S +E/ -W Northing Easting Latittude Longitude 0.00 0.00 6027765.69 533873.83 700 29' 12.781 N 1490 43'23,297 W REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well Plan: MPU M -35i, True North Vertical (TVD) Reference: MPU M -35i As -built RKB @ 59.00usft Measured Depth Reference: MPU M -35i As -built RKB 59.00usft Calculation Method Minimum Curvature 0 Start Dir 4'/100'. 600' MD, 598.77TVD \5p0 - - -End Dir : 1752.3'MD, 1553.4l'TVD 0 \�5� 1ti5� 0- 0- 0— 50� 'L 0 9� gS� 0 SQ End Dir : 6100.4' MD, 3887.85' TVD Start Dir 4'/100': 6400.4' MD, 39141 -VD 9 5/8" x 12 1/4"_ End Dir : 6532.21' MD, 3919.43' TVD MPU M -35i wp08 Heel ti 0 -5250 -6000 0 � -6750 CASING DETAILS TVD TVDSS MD Size Name 3914.00 3855.00 6400.40 9-5/8 9 5/8" x 12 1/4" 3819.00 3760.00 17557.63 4-1/2 4 1/2" x 8 1/2" HALLIBURTON Sperry Drilling 7500 \C- 9750 11883.38' MD, 3894'TVD 12041.54' MD, 3885.04' TVD 8250—MPU M -35i wp06ir 40/100' : 12399.55' MD, 3846.2TVD End Dir : 12557.63' MD, 3837.33' TVD 9000 MPU M 9750 - - - - - --- -- - - -- 0500- -11250 MPU Lease line - full \Toe-- NOUM-35 : 17557.63' MD, 3819' TVD I -12000 I 4 1/2" x 8 1/2" -12750 I MPU M-3 5i wp08 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 West( -)/East(+) (1500 usft/in) Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -35i Wellbore: MPUM-35i Design: MPU M-35 wp08 MALLIBURTON en.m,., rnanrro Hilcorp Alaska, LLC Calculation Method: Minimum Curvature WELL DETAILS: Plan: MPU M-351 SECTION DETAILS Error System: ISCWSA Sec MD Inc Azi ND +N/ -S +E/ -W Deg TFace VSect Target Annotation 1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00 Tool 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 DOD 400.00 StartDir 3°/100'' 300' MD, 300'ND 3600.00 3 MWD++IFRIFR2++MS+S 9.00 165.00 598.77 -22.71 6.09 3.00 165.00 21.64 Start Dir4°/100': 600'MD, 598.77'TVD 4 1752.30 54.63 147.61 1553.41 -534.35 29696 4.00 -19.78 603.87 End Dir : 1752.3' MD, 1553.41' ND 5 5331.62 54.63 147.61 3625.50 -2998.73 1860.55 0.00 0.00 3508.37 Start Dir 4°/100' : 5331.62' MD, 3625.5'ND 6 6100.40 85.00 142.40 3887.85 -3580.81 2272.03 4.00 -10.18 4220.38 End Dir : 6100.4' MD, 3887.85' ND 7 6400.40 85.00 142.40 3914.00 -3817.59 2454.38 0.00 0.00 4519.23 MPU M -35i wp08 Heel Start Dir 4°/100' : 6400.4' MD, 3914'ND 86532.21 90.27 142.37 3919.43 -3921.88 2534.73 4,00 -0.29 4650.88 End Dir : 6532.21' MD, 3919.43' ND 9 11883.38 90.27 142.37 3894.00 -8160.00 5801.64 0.00 0.00 10001.86 MPU M -35i wp06 CPI Start Dir4°/100' : 11883.38' MD, 3894'TVD 10 12041.54 96.23 140.23 3885.04 -8283.19 5900.30 4.00 -19.67 10159.67 End Dir : 12041.54' MD, 3885.04' ND 11 12399.55 96.23 140.23 3846.20 -8556.75 6127.95 0.00 0.00 10515.40 Start Dir4°/100': 12399.55' MD, 3846.2'TVD 12 12557.63 90.21 142.18 3837.33 -8679.71 6226.77 4.00 162.05 10673.14 End Dir : 12557.63' MD, 3837.33' ND 13 17557.63 90.21 142.18 3819.00 -12629.39 9292.67 0.00 0.00 15673.07 MPU M -35i wp06 Toe Total Depth : 17557.63' MD, 3819' ND Calculation Method: Minimum Curvature WELL DETAILS: Plan: MPU M-351 SURVEY PROGRAM Error System: ISCWSA S. Method: Cl os est Approach 3D Error Surface: Pedal Curve +NI -3 +EI -W 25.30 Longitutle Northing Easting tatittuda Date: 2019-12-IIT00:D0:00 Validated: Yes Version: Warning Method: Error Ratio a.Se 6o2165.69 533873.83 70' 29 12.781 N 149' 43' 23297 W Depth From Depth To Survey/Plan Tool 33.70 400.00 MPU M-35 "G8 (MPU M -35i) 3_Gyro-GC_Csg REFERENCE INFORMATION 400.00 6400.40 MPU M-35 wp08 (MPU M -35i) 3 MWD++IFRIFR2++MS+S FORMATION TOP DETAILS Co-ordinate (NIE) Reference: Well Plan: MPU -5i. True NOM 6400.40 17557.63 MPU M-85 wp08 (MPU M -35i) 3 -MWD 2 MS+S NOPaN NOssPo1h MDPsth Fgrmatlan Vertical(ND) R.N.- MPUM-35i As-buift RKB@59.00usft 1311.00 1252.00 1392.86 SVS 1858.00 1797.00 2275.00 BPRF Maesuretl DepiM1 Reference: MPU M-35iA Wit IRKS @ 5900usft 1887.00 1828.°° 2328.54 SW Calculation Malhod: Minimum Curvature 312200 3063.00 4461.88 LA3 339600 3337.0° 4935.19 UGNU MB 3624 Do 3565.00 5329.04 SS NA CASING DETAILS 3.16-3857.00 6425.96 SBOB(_s TVD SSMD Size 3914.00 3855.00 6400.40 9-5/8 3819.00 3760.00 17557.63 4-12 Name 9 518' x 12 1/4" 4 12".8 12" Start Dir 3°/100' : 300' MD, 3oo-rVD �O 0- StartDir 4°/100' :600' MD, 598.7TND y c <� 500" End Dir : 1752.3' MD, 1553.41' ND FO. O 0 1000 �p00 mti °j 00 , ' n m%n n �O po SV5 ... �h 41 N BPRF IV s - -__ _. by o g^ o ", Q 2000- - 000 \SV7 h 6 ti cti I& O 5 O Op 6y�ti. r LA3 h0 D m 3000 - _ - _ - _ - _ - _ N UGNU MB_ _ _ _ _ _ _ - _ H SB_NA 9 ° 4000 SS_ OB (heel) 9 5/8" x 12 1/4' o 0 0 0 0 0 0 5000 MPU M -35i wp08 Heel O O 0 o Q D � i tai MPU M-35 wp08 _ .. .. o a o kir 4 1/2"x 8 1/2" 0 0 0 0 0 0 0 MPU M -35i wp06 CP, 4` MPU M-35 wp06 CP2 MPU M-351 wp06 Toe 0 1000 2000 3000 4000 5000 6000 7000 6000 9000 10000 11000 12000 13000 14000 15000 16000 17000 18000 19000 Vertical Section at 141.98° (2000 usft/in) HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -35i Wellbore: MPU M -35i Design: MPU M-35 wp08 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -35i TVD Reference: MPU M -35i As -built RKB @ 59.00usft MD Reference: MPU M -35i As -built RKB @ 59.00usft 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 Site Position: From: Map Position Uncertainty: 5.00 usft Well Plan: MPU M -35i Well Position +N/ -S 0.00 usft +E/ -W 0.00 usft Position Uncertainty 0.00 usft Wellbore Magnetics Design Audit Notes: Version: Vertical Section: Plan Sections Northing: 6,027,877.65 usft Latitude: Easting: 533,363.92 usft Longitude: Slot Radius: 13-3/16" Grid Convergence: Northing: 6,027,765.69 usfi Latitude: Easting: 533,873.83 usfi . Longitude: Wellhead Elevation: usft Ground Level: MPU M -35i Model Name Sample Date BGGM2019 2/2/2020 MPU M-35 wp08 Declination Dip Angle 16.15 80.90 Phase: PLAN Depth From (TVD) +N/ -S (usft) (usft) 33.70 0.00 Measured Dogleg Vertical TVD Depth Inclination Azimuth Depth System (usft) (°) (I (usft) usft 33.70 0.00 0.00 33.70 -25.30 300.00 0.00 0.00 300.00 241.00 600.00 9.00 165.00 598.77 539.77 1,752.30 54.63 147.61 1,553.41 1,494.41 5,331.62 54.63 147.61 3,625.50 3,566.50 6,100.40 85.00 142.40 3,887.85 3,828.85 6,400.40 85.00 142.40 3,914.00 3,855.00 6,532.21 90.27 142.37 3,919.43 3,860.43 11,883.38 90.27 142.37 3,894.00 3,835.00 12,041.54 96.23 140.23 3,885.04 3,826.04 12,399.55 96.23 140.23 3,846.20 3,787.20 12,557.63 90.21 142.18 3,837.33 3,778.33 17,557.63 90.21 142.18 3,819.00 3,760.00 Tie On Depth: 33.70 +El -W Direction (usft) (I 0.00 141.98 70° 29' 13.905 N 149° 43'38.286 W 0.26 ° 70° 29' 12.781 N 149° 43'23.297 W 25.30 usft Field Strength (nT) 57,399.24018752 1/8/2020 4:03:53PM Page 2 COMPASS 5000.15 Build 91E Dogleg Build Turn +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) (usft) (°/100usft) (°/100usft) (°/100usft) (°) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 -22.71 6.09 3.00 3.00 0.00 165.00 -534.35 296.96 4.00 3.96 -1.51 -19.78 -2,998.73 1,860.55 0.00 0.00 0.00 0.00 -3,580.81 2,272.03 4.00 3.95 -0.68 -10.18 -3,817.59 2,454.38 0.00 0.00 0.00 0.00 -3,921.88 2,534.73 4.00 4.00 -0.02 -0.29 -8,160.00 5,801.64 0.00 0.00 0.00 0.00 -8,283.19 5,900.30 4.00 3.77 -1.35 -19.67 -8,556.75 6,127.95 0.00 0.00 0.00 0.00 -8,679.71 6,226.77 4.00 -3.81 1.23 162.05 -12,629.39 9,292.67 0.00 0.00 0.00 0.00 1/8/2020 4:03:53PM Page 2 COMPASS 5000.15 Build 91E Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -35i Wellbore: MPU M -35i Design: MPU M-35 wp08 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -35i TVD Reference: MPU M -35i As -built RKB @ 59.00usft MD Reference: MPU M -35i As -built RKB @ 59.00usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -25.30 33.70 0.00 0.00 33.70 -25.30 0.00 0.00 6,027,765.69 533,873.83 0.00 0.00 100.00 0.00 0.00 100.00 41.00 0.00 0.00 6,027,765.69 533,873.83 0.00 0.00 200.00 0.00 0.00 200.00 141.00 0.00 0.00 6,027,765.69 533,873.83 0.00 0.00 300.00 0.00 0.00 300.00 241.00 0.00 0.00 6,027,765.69 533,873.83 0.00 0.00 Start Dir 3°/100' : 300' MD, 300'TVD 400.00 3.00 165.00 399.95 340.95 -2.53 0.68 6,027,763.17 533,874.52 3.00 2.41 500.00 6.00 165.00 499.63 440.63 -10.11 2.71 6,027,755.60 533,876.58 3.00 9.63 600.00 9.00 165.00 598.77 539.77 -22.71 6.09 6,027,743.01 533,880.02 3.00 21.64 Start Dir 4°/100' : 600' MD, 598.77'TVD 700.00 12.84 158.90 696.94 637.94 -40.64 12.11 6,027,725.11 533,886.12 4.00 39.47 800.00 16.75 155.59 793.61 734.61 -64.13 22.07 6,027,701.67 533,896.19 4.00 64.11 900.00 20.69 153.52 888.31 829.31 -93.07 35.90 6,027,672.79 533,910.15 4.00 95.44 1,000.00 24.65 152.08 980.56 921.56 -127.33 53.55 6,027,638.62 533,927.96 4.00 133.29 1,100.00 28.62 151.02 1,069.93 1,010.93 -166.73 74.93 6,027,599.32 533,949.51 4.00 177.50 1,200.00 32.60 150.20 1,155.97 1,096.97 -211.08 99.94 6,027,555.09 533,974.72 4.00 227.84 1,300.00 36.59 149.54 1,238.28 1,179.28 -260.17 128.44 6,027,506.14 534,003.44 4.00 284.07 1,392.86 40.29 149.03 1,311.00 1,252.00 -309.78 157.92 6,027,456.66 534,033.15 4.00 341.32 SV5 1,400.00 40.57 149.00 1,316.44 1,257.44 -313.75 160.31 6,027,452.70 534,035.55 4.00 345.91 1,500.00 44.56 148.53 1,390.07 1,331.07 -371.57 195.38 6,027,395.05 534,070.89 4.00 413.07 1,600.00 48.55 148.13 1,458.83 1,399.83 -433.35 233.50 6,027,333.45 534,109.28 4.00 485.21 1,700.00 52.54 147.78 1,522.36 1,463.36 -498.78 274.46 6,027,268.22 534,150.53 4.00 561.99 1,752.30 54.63 147.61 1,553.41 1,494.41 -534.35 296.96 6,027,232.75 534,173.19 4.00 603.86 End Dir : 1752.3' MD, 1553.41' ND 1,800.00 54.63 147.61 1,581.02 1,522.02 -567.19 317.79 6,027,200.01 534,194.17 0.00 642.57 1,900.00 54.63 147.61 1,638.91 1,579.91 -636.04 361.48 6,027,131.37 534,238.17 0.00 723.72 2,000.00 54.63 147.61 1,696.80 1,637.80 -704.89 405.16 6,027,062.72 534,282.16 0.00 804.86 2,100.00 54.63 147.61 1,754.69 1,695.69 -773.74 448.85 6,026,994.08 534,326.15 0.00 886.01 2,200.00 54.63 147.61 1,812.58 1,753.58 -842.59 492.53 6,026,925.43 534,370.14 0.00 967.16 2,275.00 54.63 147.61 1,856.00 1,797.00 -894.23 525.29 6,026,873.95 534,403.14 0.00 1,028.01 BPRF 2,300.00 54.63 147.61 1,870.48 1,811.48 -911.44 536.21 6,026,856.79 534,414.14 0.00 1,048.30 2,328.54 54.63 147.61 1,887.00 1,828.00 -931.09 548.68 6,026,837.20 534,426.69 0.00 1,071.47 SV1 2,400.00 54.63 147.61 1,928.37 1,869.37 -980.29 579.90 6,026,788.15 534,458.13 0.00 1,129.45 2,500.00 54.63 147.61 1,986.26 1,927.26 -1,049.14 623.58 6,026,719.50 534,502.12 0.00 1,210.60 2,600.00 54.63 147.61 2,044.15 1,985.15 -1,117.99 667.27 6,026,650.86 534,546.12 0.00 1,291.74 2,700.00 54.63 147.61 2,102.04 2,043.04 -1,186.84 710.95 6,026,582.21 534,590.11 0.00 1,372.89 2,800.00 54.63 147.61 2,159.93 2,100.93 -1,255.69 754.63 6,026,513.57 534,634.10 0.00 1,454.04 2,900.00 54.63 147.61 2,217.82 2,158.82 -1,324.54 798.32 6,026,444.93 534,678.09 0.00 1,535.18 3,000.00 54.63 147.61 2,275.71 2,216.71 -1,393.39 842.00 6,026,376.28 534,722.09 0.00 1,616.33 3,100.00 54.63 147.61 2,333.60 2,274.60 -1,462.24 885.69 6,026,307.64 534,766.08 0.00 1,697.48 3,200.00 54.63 147.61 2,391.49 2,332.49 -1,531.10 929.37 6,026,238.99 534,810.07 0.00 1,778.62 3,300.00 54.63 147.61 2,449.38 2,390.38 -1,599.95 973.06 6,026,170.35 534,854.07 0.00 1,859.77 3,400.00 54.63 147.61 2,507.27 2,448.27 -1,668.80 1,016.74 6,026,101.71 534,898.06 0.00 1,940.92 1/8/2020 4:03:53PM Page 3 COMPASS 5000.15 Build 91E HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -35i Wellbore: MPU M -35i Design: MPU M-35 wp08 Planned Survey Measured Vertical Depth Inclination Azimuth Depth (usft) (1) (1) (usft) Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -35i TVD Reference: MPU M -35i As -built RKB @ 59.00usft MD Reference: MPU M -35i As -built RKB @ 59.00usft North Reference: True Survey Calculation Method: Minimum Curvature TVDss +N/ -S usft (usft) 3,500.00 54.63 147.61 2,565.16 2,506.16 -1,737.65 3,600.00 54.63 147.61 2,623.05 2,564.05 -1,806.50 3,700.00 54.63 147.61 2,680.94 2,621.94 -1,875.35 3,800.00 54.63 147.61 2,738.83 2,679.83 -1,944.20 3,900.00 54.63 147.61 2,796.72 2,737.72 -2,013.05 4,000.00 54.63 147.61 2,854.61 2,795.61 -2,081.90 4,100.00 54.63 147.61 2,912.50 2,853.50 -2,150.75 4,200.00 54.63 147.61 2,970.40 2,911.40 -2,219.60 4,300.00 54.63 147.61 3,028.29 2,969.29 -2,288.45 4,400.00 54.63 147.61 3,086.18 3,027.18 -2,357.30 4,461.88 54.63 147.61 3,122.00 3,063.00 -2,399.91 LA3 535,365.21 0.00 2,802.60 1,497.26 6,025,346.62 4,500.00 54.63 147.61 3,144.07 3,085.07 -2,426.15 4,600.00 54.63 147.61 3,201.96 3,142.96 -2,495.00 4,700.00 54.63 147.61 3,259.85 3,200.85 -2,563.85 4,800.00 54.63 147.61 3,317.74 3,258.74 -2,632.70 4,900.00 54.63 147.61 3,375.63 3,316.63 -2,701.55 4,935.19 54.63 147.61 3,396.00 3,337.00 -2,725.78 UGNU MB 3,320.41 1,803.05 6,024,866.11 535,689.93 0.00 5,000.00 54.63 147.61 3,433.52 3,374.52 -2,770.40 5,100.00 54.63 147.61 3,491.41 3,432.41 -2,839.25 5,200.00 54.63 147.61 3,549.30 3,490.30 -2,908.10 5,300.00 54.63 147.61 3,607.19 3,548.19 -2,976.96 5,329.04 54.63 147.61 3,624.00 3,565.00 -2,996.95 SB NA 2,041.12 6,024,507.57 535,929.61 4.00 3,831.54 5,331.62 54.63 147.61 3,625.50 3,566.50 -2,998.73 Start Dir 41/100': 5331.62' MD, 3625.5'TVD 4,022.61 2,211.65 5,400.00 57.32 147.03 3,663.76 3,604.76 -3,046.42 5,500.00 61.26 146.25 3,714.81 3,655.81 -3,118.21 5,600.00 65.21 145.53 3,759.84 3,700.84 -3,192.11 5,700.00 69.16 144.85 3,798.60 3,739.60 -3,267.77 5,800.00 73.11 144.20 3,830.93 3,771.93 -3,344.82 5,900.00 77.07 143.59 3,856.65 3,797.65 -3,422.88 6,000.00 81.03 142.99 3,875.64 3,816.64 -3,501.56 6,100.40 85.00 142.40 3,887.85 3,828.85 -3,580.81 End Dir : 6100.4' MD, 3887.85' ND 6,200.00 85.00 142.40 3,896.53 3,837.53 -3,659.42 6,300.00 85.00 142.40 3,905.25 3,846.25 -3,738.35 6,400.40 . 85.00 142.40 3,914.00 3,855.00 -3,817.59 Start Dir4°/100':6400.4'-MD, 3914' -TVD -9 5/8" x12 1/4" -- 6,425.96-.: 86.02 142.39 3,916.00 3,857.00 -3,837.78 SB_OB el) 88.98 142.38 3,919.23 3,860.23 3,896.37 6,532.21 90.27 142.37 3,919.43 3,860.43 -3,921.88 End Dir : 6532.21' MD, 3919.43' TVD 1/8/1020 4:03:53PM Page 4 COMPASS 5000.15 Build 91E Map Map +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) 2,506.16 1,060.42 6,026,033.06 534,942.05 0.00 2,022.06 1,104.11 6,025,964.42 534,986.04 0.00 2,103.21 1,147.79 6,025,895.77 535,030.04 0.00 2,184.36 1,191.48 6,025,827.13 535,074.03 0.00 2,265.50 1,235.16 6,025,758.49 535,118.02 0.00 2,346.65 1,278.84 6,025,689.84 535,162.02 0.00 2,427.80 1,322.53 6,025,621.20 535,206.01 0.00 2,508.94 1,366.21 6,025,552.55 535,250.00 0.00 2,590.09 1,409.90 6,025,483.91 535,293.99 0.00 2,671.24 1,453.58 6,025,415.27 535,337.99 0.00 2,752.38 1,480.61 6,025,372.79 535,365.21 0.00 2,802.60 1,497.26 6,025,346.62 535,381.98 0.00 2,833.53 1,540.95 6,025,277.98 535,425.97 0.00 2,914.68 1,584.63 6,025,209.33 535,469.97 0.00 2,995.83 1,628.32 6,025,140.69 535,513.96 0.00 3,076.97 1,672.00 6,025,072.05 535,557.95 0.00 3,158.12 1,687.37 6,025,047.89 535,573.43 0.00 3,186.67 1,715.68 6,025,003.40 535,601.94 0.00 3,239.27 1,759.37 6,024,934.76 535,645.94 0.00 3,320.41 1,803.05 6,024,866.11 535,689.93 0.00 3,401.56 1,846.74 6,024,797.47 535,733.92 0.00 3,482.71 1,859.42 6,024,777.54 535,746.70 0.00 3,506.27 1,860.55 6,024,775.76 535,747.83 0.00 3,508.36 1,891.15 6,024,728.22 535,778.65 4.00 3,564.78 1,938.43 6,024,656.65 535,826.25 4.00 3,650.46 1,988.50 6,024,582.98 535,876.65 4.00 3,739.52 2,041.12 6,024,507.57 535,929.61 4.00 3,831.54 2,096.03 6,024,430.78 535,984.86 4.00 3,926.05 2,152.96 6,024,352.99 536,042.15 4.00 4,022.61 2,211.65 6,024,274.58 536,101.18 4.00 4,120.75 2,272.03 6,024,195.62 536,161.92 4.00 4,220.37 2,332.57 6,024,117.29 536,222.81 0.00 4,319.59 2,393.35 6,024,038.65 536,283.95 0.00 4,419.21 2,454.38 6,023,959.69 536,345.33 0.00 4,519.22 2,469.93 6,023,939.58 536,360.96 4.00 4,544.70 2,515.07 6,023,881.20 536,406.37 4.00 4,618.67 2,534.73 6,023,855.78 536,426.14 4.00 4,650.87 1/8/1020 4:03:53PM Page 4 COMPASS 5000.15 Build 91E Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -35i Wellbore: MPU M -35i Design: MPU M-35 wp08 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -35i TVD Reference: MPU M -35i As -built RKB @ 59.00usft MD Reference: MPU M -35i As -built RKB @ 59.00usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,860.11 6,600.00 90.27 142.37 3,919.11 3,860.11 -3,975.57 2,576.12 6,023,802.29 536,467.77 0.00 4,718.66 6,700.00 90.27 142.37 3,918.64 3,859.64 -4,054.77 2,637.17 6,023,723.37 536,529.18 0.00 4,818.66 6,800.00 90.27 142.37 3,918.16 3,859.16 -4,133.97 2,698.22 6,023,644.46 536,590.58 0.00 4,918.65 6,900.00 90.27 142.37 3,917.69 3,858.69 -4,213.17 2,759.27 6,023,565.55 536,651.98 0.00 5,018.65 7,000.00 90.27 142.37 3,917.21 3,858.21 -4,292.37 2,820.32 6,023,486.63 536,713.39 0.00 5,118.65 7,100.00 90.27 142.37 3,916.74 3,857.74 -4,371.57 2,881.37 6,023,407.72 536,774.79 0.00 5,218.64 7,200.00 90.27 142.37 3,916.26 3,857.26 -4,450.77 2,942.42 6,023,328.81 536,836.20 0.00 5,318.64 7,300.00 90.27 142.37 3,915.79 3,856.79 -4,529.97 3,003.47 6,023,249.89 536,897.60 0.00 5,418.64 7,400.00 90.27 142.37 3,915.31 3,856.31 -4,609.17 3,064.52 6,023,170.98 536,959.01 0.00 5,518.63 7,500.00 90.27 142.37 3,914.83 3,855.83 -4,688.37 3,125.57 6,023,092.07 537,020.41 0.00 5,618.63 7,600.00 90.27 142.37 3,914.36 3,855.36 -4,767.57 3,186.62 6,023,013.15 537,081.82 0.00 5,718.63 7,700.00 90.27 142.37 3,913.88 3,854.88 -4,846.77 3,247.67 6,022,934.24 537,143.22 0.00 5,818.62 7,800.00 90.27 142.37 3,913.41 3,854.41 -4,925.97 3,308.72 6,022,855.33 537,204.62 0.00 5,918.62 7,900.00 90.27 142.37 3,912.93 3,853.93 -5,005.17 3,369.77 6,022,776.41 537,266.03 0.00 6,018.62 8,000.00 90.27 142.37 3,912.46 3,853.46 -5,084.37 3,430.82 6,022,697.50 537,327.43 0.00 6,118.61 8,100.00 90.27 142.37 3,911.98 3,852.98 -5,163.57 3,491.87 6,022,618.59 537,388.84 0.00 6,218.61 8,200.00 90.27 142.37 3,911.51 3,852.51 -5,242.77 3,552.92 6,022,539.68 537,450.24 0.00 6,318.60 8,300.00 90.27 142.37 3,911.03 3,852.03 -5,321.97 3,613.97 6,022,460.76 537,511.65 0.00 6,418.60 8,400.00 90.27 142.37 3,910.56 3,851.56 -5,401.17 3,675.02 6,022,381.85 537,573.05 0.00 6,518.60 8,500.00 90.27 142.37 3,910.08 3,851.08 -5,480.37 3,736.07 6,022,302.94 537,634.45 0.00 6,618.59 8,600.00 90.27 142.37 3,909.61 3,850.61 -5,559.57 3,797.12 6,022,224.02 537,695.86 0.00 6,718.59 8,700.00 90.27 142.37 3,909.13 3,850.13 -5,638.77 3,858.17 6,022,145.11 537,757.26 0.00 6,818.59 8,800.00 90.27 142.37 3,908.66 3,849.66 -5,717.97 3,919.22 6,022,066.20 537,818.67 0.00 6,918.58 8,900.00 90.27 142.37 3,908.18 3,849.18 -5,797.17 3,980.27 6,021,987.28 537,880.07 0.00 7,018.58 9,000.00 90.27 142.37 3,907.70 3,848.70 -5,876.37 4,041.33 6,021,908.37 537,941.48 0.00 7,118.58 9,100.00 90.27 142.37 3,907.23 3,848.23 -5,955.57 4,102.38 6,021,829.46 538,002.88 0.00 7,218.57 9,200.00 90.27 142.37 3,906.75 3,847.75 -6,034.77 4,163.43 6,021,750.54 538,064.29 0.00 7,318.57 9,300.00 90.27 142.37 3,906.28 3,847.28 -6,113.97 4,224.48 6,021,671.63 538,125.69 0.00 7,418.57 9,400.00 90.27 142.37 3,905.80 3,846.80 -6,193.17 4,285.53 6,021,592.72 538,187.09 0.00 7,518.56 9,500.00 90.27 142.37 3,905.33 3,846.33 -6,272.37 4,346.58 6,021,513.80 538,248.50 0.00 7,618.56 9,600.00 90.27 142.37 3,904.85 3,845.85 -6,351.57 4,407.63 6,021,434.89 538,309.90 0.00 7,718.56 9,700.00 90.27 142.37 3,904.38 3,845.38 -6,430.77 4,468.68 6,021,355.98 538,371.31 0.00 7,818.55 9,800.00 90.27 142.37 3,903.90 3,844.90 -6,509.97 4,529.73 6,021,277.06 538,432.71 0.00 7,918.55 9,900.00 90.27 142.37 3,903.43 3,844.43 -6,589.17 4,590.78 6,021,198.15 538,494.12 0.00 8,018.55 10,000.00 90.27 142.37 3,902.95 3,843.95 -6,668.37 4,651.83 6,021,119.24 538,555.52 0.00 8,118.54 10,100.00 90.27 142.37 3,902.48 3,843.48 -6,747.57 4,712.88 6,021,040.32 538,616.93 0.00 8,218.54 10,200.00 90.27 142.37 3,902.00 3,843.00 -6,826.77 4,773.93 6,020,961.41 538,678.33 0.00 8,318.54 10,300.00 90.27 142.37 3,901.53 3,842.53 -6,905.97 4,834.98 6,020,882.50 538,739.73 0.00 8,418.53 10,400.00 90.27 142.37 3,901.05 3,842.05 -6,985.17 4,896.03 6,020,803.58 538,801.14 0.00 8,518.53 10,500.00 90.27 142.37 3,900.58 3,841.58 -7,064.37 4,957.08 6,020,724.67 538,862.54 0.00 8,618.52 10,600.00 90.27 142.37 3,900.10 3,841.10 -7,143.57 5,018.13 6,020,645.76 538,923.95 0.00 8,718.52 10,700.00 90.27 142.37 3,899.62 3,840.62 -7,222.77 5,079.18 6,020,566.84 538,985.35 0.00 8,818.52 10,800.00 90.27 142.37 3,899.15 3,840.15 -7,301.97 5,140.23 6,020,487.93 539,046.76 0.00 8,918.51 10,900.00 90.27 142.37 3,898.67 3,839.67 -7,381.17 5,201.28 6,020,409.02 539,108.16 0.00 9,018.51 11,000.00 90.27 142.37 3,898.20 3,839.20 -7,460.37 5,262.33 6,020,330.10 539,169.57 0.00 9,118.51 1/812020 4:03:53PM Page 5 COMPASS 5000.15 Build 91E Planned Survey Measured Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M -35i Company: Hilcorp Alaska, LLC TVD Reference: MPU M -35i As -built RKB @ 59.00usft Project: Milne Point MD Reference: MPU M -35i As -built RKB @ 59.00usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M -35i Survey Calculation Method: Minimum Curvature Wellbore: MPU M -35i (usft) (1) Design: MPU M-35 wp08 (usft) usft Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (1) (1) (usft) usft (usft) (usft) (usft) (usft) 3,838.72 11,100.00 90.27 142.37 3,897.72 3,838.72 -7,539.56 5,323.38 6,020,251.19 539,230.97 0.00 9,218.50 11,200.00 90.27 142.37 3,897.25 3,838.25 -7,618.76 5,384.43 6,020,172.28 539,292.37 0.00 9,318.50 11,300.00 90.27 142.37 3,896.77 3,837.77 -7,697.96 5,445.48 6,020,093.36 539,353.78 0.00 9,418.50 11,400.00 90.27 142.37 3,896.30 3,837.30 -7,777.16 5,506.53 6,020,014.45 539,415.18 0.00 9,518.49 11,500.00 90.27 142.37 3,895.82 3,836.82 -7,856.36 5,567.58 6,019,935.54 539,476.59 0.00 9,618.49 11,600.00 90.27 142.37 3,895.35 3,836.35 -7,935.56 5,628.64 6,019,856.63 539,537.99 0.00 9,718.49 11,700.00 90.27 142.37 3,894.87 3,835.87 -8,014.76 5,689.69 6,019,777.71 539,599.40 0.00 9,818.48 11,800.00 90.27 142.37 3,894.40 3,835.40 -8,093.96 5,750.74 6,019,698.80 539,660.80 0.00 9,918.48 11,883.38 90.27 142.37 3,894.00 3,835.00 -8,160.00 5,801.64 6,019,633.00 539,712.00 0.00 10,001.86 Start Dir 4°/100' : 11883.38' MD, 3894'TVD 11,900.00 90.90 142.15 3,893.83 3,834.83 -8,173.14 5,811.81 6,019,619.91 539,722.23 4.00 10,018.48 12,000.00 94.66 140.80 3,888.98 3,829.98 -8,251.27 5,874.01 6,019,542.07 539,784.78 4.00 10,118.33 12,041.54 96.23 140.23 3,885.04 3,826.04 -8,283.19 5,900.30 6,019,510.28 539,811.21 4.00 10,159.67 End Dir : 12041.54' MD, 3885.04' TVD 12,100.00 96.23 140.23 3,878.69 3,819.69 -8,327.86 5,937.48 6,019,465.78 539,848.59 0.00 10,217.76 Fault 12,200.00 96.23 140.23 3,867.85 3,808.85 -8,404.27 6,001.06 6,019,389.67 539,912.51 0.00 10,317.12 12,300.00 96.23 140.23 3,857.00 3,798.00 -8,480.68 6,064.65 6,019,313.55 539,976.44 0.00 10,416.49 12,399.55 96.23 140.23 3,846.20 3,787.20 -8,556.75 6,127.95 6,019,237.78 540,040.08 0.00 10,515.40 Start Dir 4°/100' : 12399.55' MD, 3846.2'TVD 12,500.00 92.40 141.47 3,838.64 3,779.64 -8,634.42 6,191.17 6,019,160.41 540,103.65 4.00 10,615.53 12,557.63 90.21 142.18 3,837.33 3,778.33 -8,679.71 6,226.77 6,019,115.28 540,139.46 4.00 10,673.14 End Dir : 12557.63' MD, 3837.33' TVD 12,600.00 90.21 142.18 3,837.17 3,778.17 -8,713.18 6,252.76 6,019,081.93 540,165.59 0.00 10,715.51 12,700.00 90.21 142.18 3,836.80 3,777.80 -8,792.18 6,314.07 6,019,003.23 540,227.26 0.00 10,815.51 12,800.00 90.21 142.18 3,836.44 3,777.44 -8,871.17 6,375.39 6,018,924.52 540,288.93 0.00 10,915.51 12,900.00 90.21 142.18 3,836.07 3,777.07 -8,950.16 6,436.71 6,018,845.82 540,350.60 0.00 11,015.50 13,000.00 90.21 142.18 3,835.70 3,776.70 -9,029.16 6,498.03 6,018,767.11 540,412.27 0.00 11,115.50 13,100.00 90.21 142.18 3,835.34 3,776.34 -9,108.15 6,559.34 6,018,688.41 540,473.94 0.00 11,215.50 13,200.00 90.21 142.18 3,834.97 3,775.97 -9,187.14 6,620.66 6,018,609.70 540,535.61 0.00 11,315.50 13,300.00 90.21 142.18 3,834.60 3,775.60 -9,266.14 6,681.98 6,018,530.99 540,597.28 0.00 11,415.50 13,400.00 90.21 142.18 3,834.24 3,775.24 -9,345.13 6,743.30 6,018,452.29 540,658.95 0.00 11,515.50 13,500.00 90.21 142.18 3,833.87 3,774.87 -9,424.12 6,804.62 6,018,373.58 540,720.62 0.00 11,615.50 13,600.00 90.21 142.18 3,833.51 3,774.51 -9,503.12 6,865.93 6,018,294.88 540,782.29 0.00 11,715.50 13,700.00 90.21 142.18 3,833.14 3,774.14 -9,582.11 6,927.25 6,018,216.17 540,843.97 0.00 11,815.49 13,800.00 90.21 142.18 3,832.77 3,773.77 -9,661.11 6,988.57 6,018,137.47 540,905.64 0.00 11,915.49 13,900.00 90.21 142.18 3,832.41 3,773.41 -9,740.10 7,049.89 6,018,058.76 540,967.31 0.00 12,015.49 14,000.00 90.21 142.18 3,832.04 3,773.04 -9,819.09 7,111.21 6,017,980.05 541,028.98 0.00 12,115.49 14,100.00 90.21 142.18 3,831.67 3,772.67 -9,898.09 7,172.52 6,017,901.35 541,090.65 0.00 12,215.49 14,200.00 90.21 142.18 3,831.31 3,772.31 -9,977.08 7,233.84 6,017,822.64 541,152.32 0.00 12,315.49 14,300.00 90.21 142.18 3,830.94 3,771.94 -10,056.07 7,295.16 6,017,743.94 541,213.99 0.00 12,415.49 14,400.00 90.21 142.18 3,830.57 3,771.57 -10,135.07 7,356.48 6,017,665.23 541,275.66 0.00 12,515.49 14,500.00 90.21 142.18 3,830.21 3,771.21 -10,214.06 7,417.79 6,017,586.53 541,337.33 0.00 12,615.48 14,600.00 90.21 142.18 3,829.84 3,770.84 -10,293.05 7,479.11 6,017,507.82 541,399.00 0.00 12,715.48 14,700.00 90.21 142.18 3,829.47 3,770.47 -10,372.05 7,540.43 6,017,429.12 541,460.67 0.00 12,815.48 1/82020 4:03:53PM Page 6 COMPASS 5000.15 Build 91E Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -35i Wellbore: MPU M -35i Design: MPU M-35 wp08 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -35i TVD Reference: MPU M -35i As -built RKB @ 59.O0usft MD Reference: MPU M -35i As -built RKB @ 59.00usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Map Map Vertical Depth Inclination Azimuth Depth TVDss +N/ -S (usft) (1) (1) (usft) usft (usft) 14,800.00 90.21 142.18 3,829.11 3,770.11 -10,451.04 14,900.00 90.21 142.18 3,828.74 3,769.74 -10,530.03 15,000.00 90.21 142.18 3,828.37 3,769.37 -10,609.03 15,100.00 90.21 142.18 3,828.01 3,769.01 -10,688.02 15,200.00 90.21 142.18 3,827.64 3,768.64 -10,767.02 15,300.00 90.21 142.18 3,827.27 3,768.27 -10,846.01 15,400.00 90.21 142.18 3,826.91 3,767.91 -10,925.00 15,500.00 90.21 142.18 3,826.54 3,767.54 -11,004.00 15,600.00 90.21 142.18 3,826.18 3,767.18 -11,082.99 15,700.00 90.21 142.18 3,825.81 3,766.81 -11,161.98 15,800.00 90.21 142.18 3,825.44 3,766.44 -11,240.98 15,900.00 90.21 142.18 3,825.08 3,766.08 -11,319.97 16,000.00 90.21 142.18 3,824.71 3,765.71 -11,398.96 16,100.00 90.21 142.18 3,824.34 3,765.34 -11,477.96 16,200.00 90.21 142.18 3,823.98 3,764.98 -11,556.95 16,300.00 90.21 142.18 3,823.61 3,764.61 -11,635.94 16,400.00 90.21 142.18 3,823.24 3,764.24 -11,714.94 16,500.00 90.21 142.18 3,822.88 3,763.88 -11,793.93 16,600.00 90.21 142.18 3,822.51 3,763.51 -11,872.92 16,700.00 90.21 142.18 3,822.14 3,763.14 -11,951.92 16,800.00 90.21 142.18 3,821.78 3,762.78 -12,030.91 16,900.00 90.21 142.18 3,821.41 3,762.41 -12,109.91 17,000.00 90.21 142.18 3,821.04 3,762.04 -12,188.90 17,100.00 90.21 142.18 3,820.68 3,761.68 -12,267.89 17,200.00 90.21 142.18 3,820.31 3,761.31 -12,346.89 17,300.00 90.21 142.18 3,819.94 3,760.94 -12,425.88 17,400.00 90.21 142.18 3,819.58 3,760.58 -12,504.87 17,500.00 90.21 142.18 3,819.21 3,760.21 -12,583.87 17,557.63 90.21 142.18 3,819.00 . 3,760.00 -12,629.39 Total Depth : 17557.63' MD, 3819' TVD 1/8/2020 4.03:53PM Page 7 COMPASS 5000.15 Build 91E Map Map +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) 3,770.11 7,601.75 6,017,350.41 541,522.35 0.00 12,915.48 7,663.07 6,017,271.70 541,584.02 0.00 13,015.48 7,724.38 6,017,193.00 541,645.69 0.00 13,115.48 7,785.70 6,017,114.29 541,707.36 0.00 13,215.48 7,847.02 6,017,035.59 541,769.03 0.00 13,315.48 7,908.34 6,016,956.88 541,830.70 0.00 13,415.47 7,969.66 6,016,878.18 541,892.37 0.00 13,515.47 8,030.97 6,016,799.47 541,954.04 0.00 13,615.47 8,092.29 6,016,720.76 542,015.71 0.00 13,715.47 8,153.61 6,016,642.06 542,077.38 0.00 13,815.47 8,214.93 6,016,563.35 542,139.06 0.00 13,915.47 8,276.24 6,016,484.65 542,200.73 0.00 14,015.47 8,337.56 6,016,405.94 542,262.40 0.00 14,115.46 8,398.88 6,016,327.24 542,324.07 0.00 14,215.46 8,460.20 6,016,248.53 542,385.74 0.00 14,315.46 8,521.52 6,016,169.82 542,447.41 0.00 14,415.46 8,582.83 6,016,091.12 542,509.08 0.00 14,515.46 8,644.15 6,016,012.41 542,570.75 0.00 14,615.46 8,705.47 6,015,933.71 542,632.42 0.00 14,715.46 8,766.79 6,015,855.00 542,694.09 0.00 14,815.46 8,828.11 6,015,776.30 542,755.76 0.00 14,915.45 8,889.42 6,015,697.59 542,817.44 0.00 15,015.45 8,950.74 6,015,618.88 542,879.11 0.00 15,115.45 9,012.06 6,015,540.18 542,940.78 0.00 15,215.45 9,073.38 6,015,461.47 543,002.45 0.00 15,315.45 9,134.70 6,015,382.77 543,064.12 0.00 15,415.45 9,196.01 6,015,304.06 543,125.79 0.00 15,515.45 9,257.33 6,015,225.36 543,187.46 0.00 15,615.45 9,292.67 6,015,180.00 543,223.00 0.00 15,673.07 1/8/2020 4.03:53PM Page 7 COMPASS 5000.15 Build 91E Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M -35i Company: Hilcorp Alaska, LLC TVD Reference: MPU M -35i As -built RKB @ 59.00usft Project: Milne Point MD Reference: MPU M -35i As -built RKB @ 59.00usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M -35i Survey Calculation Method: Minimum Curvature Wellbore: MPU M -35i Design: MPU M-35 wp08 Targets Target Name hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting Shape (°) (°) (usft) (usft) (usft) (usft) (usft) MPU M -35i wp06 CPI 0.00 0.00 3,894.00 -8,160.00 5,801.64 6,019,633.00 539,712.00 plan hits target center Point MPU M -35i wp06 Toe 0.00 0.00 3,819.00 -12,629.39 9,292.67 6,015,180.00 543,223.00 plan hits target center Point MPU M-35 wp06 CP2 0.00 0.00 3,839.00 -8,638.84 6,194.50 6,019,156.00 540,107.00 plan misses target center by 0.60usft at 12505.53usft MD (3838.42 TVD, -8638.74 N, 6194.61 E) Point MPU M -35i wp08 Heel 0.00 0.00 3,914.00 -3,817.59 2,454.38 6,023,959.69 536,345.33 plan hits target center Circle (radius 30.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 17,557.63 3,819.00 4 1/2" x 8 1/2" 4-1/2 8-1/2 6,400.40 3,914.00 9 5/8" x 12 1/4" 9-5/8 12-1/4 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology 4,461.88 3,122.00 LA3 5,329.04 3,624.00 SB_NA 1,392.86 1,311.00 SV5 6,425.96 3,916.00 SB_OB (heel) 2,328.54 1,887.00 SV1 4,935.19 3,396.00 UGNU MB 2,275.00 1,856.00 BPRF 1/8/2020 4:03:53PM Page 8 COMPASS 5000.15 Build 91E Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -35i Wellbore: MPU M -35i Design: MPU M-35 wp08 Plan Annotations Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) 300.00 300.00 0.00 0.00 600.00 598.77 -22.71 6.09 1,752.30 1,553.41 -534.35 296.96 5,331.62 3,625.50 -2,998.73 1,860.55 6,100.40 3,887.85 -3,580.81 2,272.03 6,400.40 3,914.00 -3,817.59 2,454.38 6,532.21 3,919.43 -3,921.88 2,534.73 11,883.38 3,894.00 -8,160.00 5,801.64 12,041.54 3,885.04 -8,283.19 5,900.30 12,100.00 3,878.69 -8,327.86 5,937.48 12,399.55 3,846.20 -8,556.75 6,127.95 12,557.63 3,837.33 -8,679.71 6,226.77 17,557.63 3,819.00 -12,629.39 9,292.67 Comment Well Plan: MPU M -35i MPU M -35i As -built RKB @ 59.00usft MPU M -35i As -built RKB @ 59.00usft True Minimum Curvature Start Dir 31/100' : 300' MD, 300'TVD Start Dir 41/100' : 600' MD, 598.77'TVD End Dir : 1752.3' MD, 1553.41' TVD Start Dir 4'/100': 5331.62' MD, 3625.5'TVD End Dir : 6100.4' MD, 3887.85' TVD Start Dir 41/100': 6400.4' MD, 3914'TVD End Dir : 6532.21' MD, 3919.43' TVD Start Dir 41/100' : 11883.38' MD, 3894'TVD End Dir : 12041.54' MD, 3885.04' TVD Fault Start Dir 41/100' : 12399.55' MD, 3846.2'TVD End Dir : 12557.63' MD, 3837.33' TVD Total Depth : 17557.63' MD, 3819' TVD 1/8/2020 4:03:53PM Page 9 COMPASS 5000.15 Build 91E Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M -35i MPU M -35i MPU M-35 wp08 Sperry Drilling Services Clearance Summary Anticollision Report 08 January, 2020 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -35i - MPU M -35i - MPU M-35 Wp08 Well Coordinates: 6,027,765.69 N, 533,873.83 E (700 29' 12.78" N, 1490 43' 23.30" W) Datum Height: MPU M -35i As -built RKB @ 59.00usft Scan Range: 33.60 to 6,400.40 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: 91E Scan Type: NO GLOBAL Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU M -35i - MPU M-35 wp08 Hileorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-351 - MPU M -35i - MPU M-35 wp08 Scan Range: 33.60 to 6,400.40 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 M Pt J Pad M Pt L Pad MPL-36 - MPL-36 - MPL-36 MPL-36 - MPL-36 - MPL-36 MPL-36 - MPL-361-1 - MPL-361-1 MPL-36 - MPL-361-1 - MPL-361-1 MPL-36 - MPL-36L1 PB1 - MPL-361-1 PB1 MPL-36 - MPL-361-1 PB1 - MPL-36L1 PBI MPL-36 - MPL-36PB1 - MPL-36PB1 MPL-36 - MPL-36PB1 - MPL-36PB1 M Pt Moose Pad MPU M-11 - MPU M-11 - MPU M-11 MPU M-11 - MPU M-11 - MPU M-11 MPU M-11 -MPU M-11 -MPU M-11 MPU M-12 - MPU M-12 - MPU M-12 MPU M-12 - MPU M-12 - MPU M-12 MPU M-12 - MPU M-12 - MPU M-12 MPU M-12 - MPU M-12PB1 - MPU M-12PB1 MPU M-12 - MPU M-12PB1 - MPU M-12PB1 MPU M-12 - MPU M-12PB1 - MPU M-12PB1 MPU M-12- MPU M-12PB2 - MPU M-12PB2 MPU M-12 - MPU M-12PB2 - MPU M-12PB2 MPU M-12 -MPU M-12PB2 - MPU M-12PB2 MPU M-13- MPU M -13i - MPU M-13 MPU M-13 - MPU M -13i - MPU M-13 MPU M-13 - MPU M -13i - MPU M-13 MPU M-14 - MPU M-14 - MPU M-14 6,008.60 761.27 6,008.60 638.01 13,459.92 6.176 Clearance Factor Pass - 6,400.40 602.04 6,400.40 529.09 13,484.68 8.253 Ellipse Separation Pass - 5,983.60 778.17 5,983.60 647.58 13,457.90 5.959 Clearance Factor Pass - 6,400.40 602.04 6,400.40 528.99 13,484.68 8.241 Ellipse Separation Pass - 5,983.60 778.17 5,983.60 644.10 13,457.90 5.804 Clearance Factor Pass - 6,400.40 602.04 6,400.40 528.91 13,484.68 8.232 Ellipse Separation Pass - 6,008.60 761.27 6,008.60 638.03 13,459.92 6.177 Clearance Factor Pass - 6,400.40 602.04 6,400.40 529.09 13,484.68 8.253 Ellipse Separation Pass - 367.85 190.12 367.85 187.46 371.02 71.389 Centre Distance Pass - 383.60 190.17 383.60 187.42 386.12 68.959 Ellipse Separation Pass - 808.60 251.57 808.60 246.54 758.43 50.007 Clearance Factor Pass - 204.37 137.68 204.37 135.58 204.62 65.391 Centre Distance Pass - 308.60 137.75 308.60 134.82 308.48 47.045 Ellipse Separation Pass - 583.60 166.73 583.60 161.90 564.92 34.504 Clearance Factor Pass - 204.37 137.68 204.37 135.58 204.62 65.391 Centre Distance Pass - 308.60 137.75 308.60 134.82 308.48 47.045 Ellipse Separation Pass - 583.60 166.73 583.60 161.90 564.92 34.504 Clearance Factor Pass - 204.37 137.68 204.37 135.58 204.62 65.391 Centre Distance Pass - 308.60 137.75 308.60 134.82 308.48 47.045 Ellipse Separation Pass - 583.60 166.73 583.60 161.90 564.92 34.504 Clearance Factor Pass - 58.60 120.03 58.60 119.01 58.37 117.640 Centre Distance Pass - 758.60 120.89 758.60 116.01 751.05 24.759 Ellipse Separation Pass - 1,083.60 150.45 1,083.60 142.68 1,052.36 19.362 Clearance Factor Pass - 58.60 29.99 58.60 28.97 58.34 29.387 Centre Distance Pass - 08 January, 2020 - 16:18 Page 2 of 9 COMPASS Hilcorp Alaska, LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU M -35i - MPU M-35 wp08 58.60 239.99 58.60 238.97 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 235.159 Centre Distance Pass - MPU M -17i - MPU M -17i - MPU M -17i 308.60 240.50 Reference Design: M Pt Moose Pad - Plan: MPU M-351- MPU M-351- MPU M-35 wp08 238.12 307.46 101.137 Ellipse Separation Pass - MPU M -17i - MPU M -17i - MPU M -17i Scan Range: 33.60 to 6,400.40 usft. Measured Depth. 1,263.62 6,400.40 1,097.51 6,633.89 7.607 Clearance Factor Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft MPU M-18 - MPU M-18 - MPU M-18 58.60 270.01 58.60 Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on 108.60 Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft 3,408.60 778.16 MPU M-14 - MPU M-14 - MPU M-14 158.60 30.31 158.60 28.80 158.20 20.152 Ellipse Separation Pass - MPU M-14 - MPU M-14 - MPU M-14 1,333.60 74.45 1,333.60 62.27 1,324.70 6.116 Clearance Factor Pass - MPU M -15i - MPU M-15 - MPU M-1 5i 58.60 59.97 58.60 58.50 58.20 40.560 Centre Distance Pass - MPU M -15i - MPU M-15 - MPU M -15i 5,683.60 167.71 5,683.60 43.02 5,914.65 1.345 Ellipse Separation Pass - MPU M -15i - MPU M-15 - MPU M -15i 5,708.60 171.50 5,708.60 43.80 5,935.65 1.343 Clearance Factor Pass - MPU M-1 5i - MPU M-15PB1 - MPU M-15PB1 58.60 59.97 58.60 58.50 58.20 40.560 Centre Distance Pass - MPU M -15i - MPU M-15PB1 - MPU M-15PB1 5,683.60 167.71 5,683.60 42.80 5,914.65 1.343 Ellipse Separation Pass - MPU M -15i - MPU M-15PB1 - MPU M-15PB1 5,708.60 171.50 5,708.60 43.57 5,935.65 1.341 Clearance Factor Pass - MPU M-16 - MPU M-16 - MPU M-16 58.60 149.79 58.60 148.77 58.18 146.785 Ellipse Separation Pass - MPU M-16 - MPU M-16 - MPU M-16 6,400.40 457.98 6,400.40 298.16 6,690.28 2.866 Clearance Factor Pass - MPU M -17i - MPU M -17i - MPU M-171 58.60 239.99 58.60 238.97 58.34 235.159 Centre Distance Pass - MPU M -17i - MPU M -17i - MPU M -17i 308.60 240.50 308.60 238.12 307.46 101.137 Ellipse Separation Pass - MPU M -17i - MPU M -17i - MPU M -17i 6,400.40 1,263.62 6,400.40 1,097.51 6,633.89 7.607 Clearance Factor Pass - MPU M-18 - MPU M-18 - MPU M-18 58.60 270.01 58.60 268.99 58.28 264.754 Centre Distance Pass - MPU M-18 - MPU M-18 - MPU M-18 108.60 270.17 108.60 268.93 107.39 218.045 Ellipse Separation Pass - MPU M-18 - MPU M-18 - MPU M-18 3,408.60 846.36 3,408.60 778.16 3,420.96 12.411 Clearance Factor Pass - MPU M-18 - MPU M -18P81 - MPU M-18PB1 58.60 270.01 58.60 268.99 58.28 264.754 Centre Distance Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 108.60 270.17 108.60 268.93 107.39 218.045 Ellipse Separation Pass - MPU M-18 - MPU M-18PB1 - MPU M -18P81 3,408.60 846.36 3,408.60 778.15 3,420.96 12.410 Clearance Factor Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 58.60 270.01 58.60 268.99 58.28 264.754 Centre Distance Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 108.60 270.17 108.60 268.93 107.39 218.045 Ellipse Separation Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 3,408.60 846.36 3,408.60 778.16 3,420.96 12.411 Clearance Factor Pass - MPU M -19i - MPU M -19i - MPU M -19i 623.61 357.20 623.61 352.93 640.62 83.654 Centre Distance Pass - MPU M-1 9i - MPU M-191 - MPU M-191 633.60 357.22 633.60 352.88 650.51 82.341 Ellipse Separation Pass - MPU M -19i -MPU M -19i - MPU M-1 9i 4,058.60 1,361.33 4,058.60 1,281.04 3,909.65 16.955 Clearance Factor Pass - MPU M -19i - MPU M-19PB1 - MPU M-19PB1 623.61 357.20 623.61 352.93 640.62 83.653 Centre Distance Pass - MPU M -19i - MPU M-19PB1 - MPU M-19PB1 633.60 357.22 633.60 352.88 650.51 82.340 Ellipse Separation Pass - MPU M -19i -MPU M -19P81 - MPU M-19PB1 4,058.60 1,361.33 4,058.60 1,281.02 3,909.65 16.951 Clearance Factor Pass - MPU M-20 - MPU M-20 - MPU M-20 308.60 127.22 308.60 124.93 308.84 55.568 Ellipse Separation Pass - MPU M-20 - MPU M-20 - MPU M-20 5,283.60 885.24 5,283.60 777.36 8,188.50 8.206 Clearance Factor Pass - 08 January, 2020 - 16:18 Page 3 of 9 COMPASS HALLIBURTION Hilcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU M -35i - MPU M-35 wp08 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -35i - MPU M -35i - MPU M-35 wp08 Scan Range: 33.60 to 6,400.40 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 MPU M-20 - MPU M-20PB1 - MPU M-20PB1 308.60 127.22 308.60 124.93 308.84 55.568 Ellipse Separation Pass - MPU M-20 - MPU M-20PB1 - MPU M -20P61 5,283.60 885.24 5,283.60 777.37 8,188.50 8.206 Clearance Factor Pass - MPU M-20 - MPU M-20PB2 - MPU M -20P62 308.60 127.22 308.60 124.93 308.84 55.568 Ellipse Separation Pass - MPU M-20 - MPU M-20PB2 - MPU M-20PB2 5,283.60 885.24 5,283.60 777.36 8,188.50 8.206 Clearance Factor Pass - MPU M -21i - MPU M -21i - MPU M-211 58.60 172.64 58.60 171.16 58.44 116.671 Centre Distance Pass - MPU M -21i - MPU M -21i - MPU M -21i 308.60 172.75 308.60 170.28 308.73 69.843 Ellipse Separation Pass - MPU M-21i-MPUM-21i- MPU M -21i 4,808.60 1,497.64 4,808.60 1,409.39 7,053.02 16.969 Clearance Factor Pass - Plan: MPU M-07WSW- MPU M-07 (WSW) - M-07WS 1,564.91 280.74 1,564.91 268.63 1,861.41 23.181 Centre Distance Pass - Plan: MPU M-07WSW - MPU M-07 (WSW) - M-07WS 1,583.60 281.02 1,583.60 268.55 1,877.65 22.544 Ellipse Separation Pass - Plan: MPU M-07WSW - MPU M-07 (WSW) - M-07WS 2,458.60 586.55 2,458.60 547.17 2,630.32 14.895 Clearance Factor Pass - Plan: MPU M-27 - M-27 - M-27 wp02 575.29 177.41 575.29 173.37 550.00 43.866 Centre Distance Pass - Plan: MPU M-27 - M-27 - M-27 wp02 583.60 177.42 583.60 173.34 557.60 43.481 Ellipse Separation Pass - Plan: MPU M-27 - M-27 - M-27 wp02 3,533.60 1,499.03 3,533.60 1,440.51 2,947.09 25.615 Clearance Factor Pass - Plan: MPU M -28i - M -28i - M -28i wp01 462.48 208.91 462.48 205.38 438.17 59.291 Centre Distance Pass - Plan: MPU M -28i - M -28i - M -28i wp01 483.60 208.99 483.60 205.37 457.17 57.756 Ellipse Separation Pass - Plan: MPU M -28i - M -28i - M -28i wp01 3,208.60 1,487.97 3,208.60 1,436.72 2,533.06 29.031 Clearance Factor Pass - Plan: MPU M-29 - M-29 - M-29 wp02 488.90 238.69 488.90 235.05 463.20 65.536 Centre Distance Pass - Plan: MPU M-29 - M-29 - M-29 wp02 508.60 238.74 508.60 235.01 481.30 64.005 Ellipse Separation Pass - Plan: MPU M-29 - M-29 - M-29 wp02 3,258.60 1,484.72 3,258.60 1,432.33 2,497.32 28.336 Clearance Factor Pass - Plan: MPU M-43 - Slot 52 - MPU M-43 - MPU M-43 wF 261.50 218.55 261.50 216.43 261.20 103.349 Centre Distance Pass - Plan: MPU M-43 - Slot 52 - MPU M-43 - MPU M-43 wF 283.60 218.55 283.60 216.32 282.99 97.974 Ellipse Separation Pass - Plan: MPU M-43 - Slot 52 - MPU M-43 - MPU M43 wF 6,400.40 1,464.32 6,400.40 1,334.93 10,164.34 11.317 Clearance Factor Pass - Plan: MPU M -44i - Slot 58 - MPU M -44i - MPU M -44i H 261.50 297.15 261.50 295.04 261.20 140.863 Centre Distance Pass - Plan: MPU M -44i - Slot 58 - MPU M44i - MPU M44i H 283.60 297.15 283.60 294.93 282.93 133.561 Ellipse Separation Pass - Plan: MPU M -44i - Slot 58 - MPU M -44i - MPU M -44i H 6,400.40 579.52 6,400.40 453.11 9,613.79 4.584 Clearance Factor Pass - Plan: MPU M-45 -Slot 48 - MPU M-45 - MPU M45 wpi 5,558.60 154.49 5,558.60 51.97 8,264.24 1.507 Clearance Factor Pass - Plan: MPU M-45 -Slot 48 - MPU M-45 - MPU M-45 wpi 5,583.60 148.19 5,583.60 50.19 8,281.58 1.512 Ellipse Separation Pass - Plan: MPU M-45 -Slat 48 - MPU M-45 - MPU M45 wpi 5,661.90 139.37 5,661.90 64.59 8,336.56 1.864 Centre Distance Pass - Plan: MPU M46 (MPU M-20 P2 - Slot 40) - M-20 Pha; 283.60 124.32 283.60 121.28 283.30 40.866 Centre Distance Pass - Plan: MPU M46 (MPU M-20 P2 - Slot 40) - M-20 Pha; 308.60 124.34 308.60 121.15 308.30 39.005 Ellipse Separation Pass - Plan: MPU M46 (MPU M-20 P2 - Slat 40) - M-20 Phaa 5,158.60 881.03 5,158.60 767.14 7,416.96 7.736 Clearance Factor Pass - 08 January, 2020 - 16. 18 Page 4 of 9 COMPASS HALLIBURTON Hilcorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU M -35i - MPU M-35 wpO8 283.60 218.60 283.60 216.00 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 84.135 Centre Distance Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M= 308.60 218.62 Reference Design: M Pt Moose Pad - Plan: MPU M-351 - MPU M-351- MPU M-35 wp08 215.87 308.30 79.690 Ellipse Separation Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M-! Scan Range: 33.60 to 6,400.40 usft. Measured Depth. 309.26 908.60 303.02 896.04 49.591 Clearance Factor Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 2,858.60 111.39 Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft 5,208.60 70.36 Plan MPU M-47 (MPU M -21i P2 - Slot 30) - M-21 i Pha 283.60 194.70 283.60 191.67 283.30 64.238 Centre Distance Pass - Plan MPU M-47 (MPU M -21i P2 - Slot 30) - M-21 i Pha 308.60 194.72 308.60 191.54 308.30 61.308 Ellipse Separation Pass - Plan: MPU M-47 (MPU M-21 i P2 - Slot 30) - M-21 i Pha 658.60 231.94 658.60 226.93 639.14 46.263 Clearance Factor Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU 283.60 137.78 283.60 134.79 283.40 46.102 Centre Distance Pass - Plan: MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU 308.60 137.80 308.60 134.62 308.40 43.350 Ellipse Separation Pass - Plan MPU M-57 (SMGO) - Slot 36 - MPU M-57 - MPU 608.60 162.31 608.60 157.06 607.06 30.936 Clearance Factor Pass - Plan MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M-! 08 283.60 218.60 283.60 216.00 283.30 84.135 Centre Distance Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M= 308.60 218.62 308.60 215.87 308.30 79.690 Ellipse Separation Pass - Plan: MPU M-58(IRA) - Slot 28 - MPU M-58 - MPU M-! 908.60 309.26 908.60 303.02 896.04 49.591 Clearance Factor Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 2,858.60 111.39 2,858.60 59.59 3,067.84 2.150 Ellipse Separation Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 2,992.21 109.17 2,992.21 62.95 3,199.60 2.362 Centre Distance Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 5,208.60 214.27 5,208.60 70.36 5,457.73 1.489 Clearance Factor Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 261.50 153.39 261.50 151.05 261.20 65.689 Centre Distance Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 283.60 153.39 283.60 150.92 283.08 62.039 Ellipse Separation Pass - Proposal: N1 Kuparuk - Slot 34 - MPU M -N1 - Kup N1 533.60 181.03 533.60 177.16 512.86 46.807 Clearance Factor Pass - Rig: MPU M-34 - MPU M-34 - MPU M-34 wp06 663.89 87.62 663.89 83.55 668.95 21.562 Centre Distance Pass - Rig: MPU M-34 - MPU M-34 - MPU M-34 wp06 683.60 87.66 683.60 83.51 688.82 21.130 Ellipse Separation Pass - Rig: MPU M-34 - MPU M-34 - MPU M-34 wp06 6,400.40 735.70 6,400.40 569.83 6,316.39 4.435 Clearance Factor Pass- ass-Slot Slot25 - Placeholder - Slot 25 - Placeholder - Slot 25 F 283.60 209.85 283.60 207.39 245.60 85.302 Centre Distance Pass - Slot 25 - Placeholder - Slot 25 - Placeholder - Slot 25 F 333.60 209.93 333.60 207.16 295.60 75.752 Ellipse Separation Pass - Slot 25 - Placeholder - Slot 25 - Placeholder - Slot 25 F 958.60 279.81 958.60 273.13 904.69 41.853 Clearance Factor Pass - Slot 27 - Placeholder - Slot 27 - Placeholder - Slot 27- 283.60 179.85 283.60 177.39 245.60 73.107 Centre Distance Pass - Slot 27 - Placeholder - Slot 27 - Placeholder - Slot 27- 333.60 179.93 333.60 177.16 295.60 64.926 Ellipse Separation Pass - Slot 27 - Placeholder - Slot 27 - Placeholder - Slot 27- 908.60 237.78 908.60 231.48 858.34 37.783 Clearance Factor Pass- ass-Slot Slot31 - Placeholder - Slot 31 - Placeholder - Slot 31- 283.60 119.84 283.60 117.38 245.60 48.715 Centre Distance Pass - Slot 31 - Placeholder - Slot 31 - Placeholder - Slot 31- 333.60 119.92 333.60 117.15 295.60 43.273 Ellipse Separation Pass - Slot 31 - Placeholder - Slot 31 - Placeholder - Slot 31- 758.60 147.76 758.60 142.56 715.80 28.379 Clearance Factor Pass - Slot 37 - Placeholder - Slot 37 - Placeholder - Slot 37- 283.60 29.83 283.60 27.37 245.60 12.127 Centre Distance Pass - Slot 37 - Placeholder- Slot 37 - Placeholder - Slot 37- 333.60 29.92 333.60 27.15 295.60 10.795 Ellipse Separation Pass - Slot 37 - Placeholder - Slot 37 - Placeholder - Slot 37- 483.60 33.34 483.60 29.73 445.32 9.228 Clearance Factor ass- Pass- 08 January, 2020 - 16:18 Page 5 of 9 COMPASS Hilcorp Alaska, LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU M -35i - MPU M-35 wp08 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -35i - MPU M -35i - MPU M-35 wp08 Scan Range: 33.60 to 6,400.40 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 Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 283.60 126.64 283.60 124.17 245.60 51.103 Centre Distance Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 308.60 126.66 308.60 124.03 270.60 48.081 Ellipse Separation Pass - Slot 42 - Placeholder - Slot 42 - Placeholder - Slot 42 - 733.60 171.50 733.60 166.51 691.62 34.332 Clearance Factor Pass - Slot 43- Placeholder - Slot 43 - Placeholder - Slot 43 - 543.80 58.14 543.80 54.23 505.14 14.871 Centre Distance Pass - Slot 43- Placeholder - Slot 43 - Placeholder - Slot 43 - 558.60 58.17 558.60 54.19 519.81 14.608 Ellipse Separation Pass - Slot 43- Placeholder - Slot 43 - Placeholder - Slot 43 - 708.60 63.62 708.60 58.77 667.32 13.124 Clearance Factor Pass - Slot 45 - Placeholder - Slot 45 - Placeholder - Slot 45- 605.53 87.07 605.53 82.85 566.23 20.627 Centre Distance Pass - Slot 45 - Placeholder - Slot 45 - Placeholder - Slot 45- 633.60 87.13 633.60 82.74 593.89 19.847 Ellipse Separation Pass - Slot 45 - Placeholder - Slot 45 - Placeholder - Slot 45- 833.60 97.13 833.60 91.40 787.67 16.970 Clearance Factor Pass - Slot 46 - Placeholder - Slot 46 - Placeholder - Slot 46 - 283.60 153.58 283.60 151.11 245.60 62.113 Centre Distance Pass - Slot 46 - Placeholder - Slot 46 - Placeholder - Slot 46 - 308.60 153.60 308.60 150.97 270.60 58.434 Ellipse Separation Pass - Slot 46 - Placeholder - Slot 46 - Placeholder - Slot 46 - 883.60 219.50 883.60 213.49 834.93 36.530 Clearance Factor Pass - Slot 49 - Placeholder - Slot 49 - Placeholder - Slot 49 - 775.94 142.99 775.94 137.65 732.52 26.823 Centre Distance Pass - Slot 49 - Placeholder - Slot 49 - Placeholder - Slot 49 - 783.60 143.00 783.60 137.61 739.88 26.556 Ellipse Separation Pass - Slot 49 - Placeholder - Slot 49 - Placeholder - Slot 49 - 1,008.60 161.09 1,008.60 153.97 950.37 22.618 Clearance Factor Pass - Slot 54 - Placeholder - Slot 54 - Placeholder - Slot 54 - 283.60 244.21 283.60 241.74 245.60 99.067 Centre Distance Pass - Slot 54 - Placeholder - Slot 54 - Placeholder - Slot 54 - 333.60 244.28 333.60 241.51 295.60 87.992 Ellipse Separation Pass - Slot 54 - Placeholder - Slot 54 - Placeholder - Slot 54 - 1,058.60 309.32 1,058.60 301.83 995.31 41.307 Clearance Factor Pass - M Pt N Pad Milne Point Exploration 08 January, 2020 - 16:18 Page 6 of g COMPASS HALLIBURTON Anticollision Report for Plan: MPU M -35i - MPU M-35 wp08 Survey tool l2rogram From (usft) 33.70 400.00 6,400.40 To (usft) 400.00 MPU M-35 wp08 6,400.40 MPU M-35 wp08 17,557.63 MPU M-35 wp08 Survey/Plan Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Survey Tool 3_Gyro-GC_Csg 3_M WD+IFR2+M S+Sag 3_M WD+IFR2+MS+Sag Hilcorp Alaska, LLC Milne Point 08 January, 2020 - 16:18 Page 7 of 9 COMPASS FiALLIBURTON Project: Milne Point REFERENCE INFORMATION WELL DEIAIIS:PIan: MPUM-35i NAD1927 MADCONCONUS Alaskg Zone 04 Corortlinate (NTE) Reference: Well Phn: MPU M -35i, Tina North V-.1(TVD) Reference: MPU MTI A5-blM RKB @ 59.c0u fr Mea _d Depth Reference: MPU M -Mi As buig RKB @ 59.00ustt 2$.30 +N/ -S +E1 -W NONunC F rung Latiftude LonANde Sperry OrlAina Site: M Pt Moose Pad Well: Plan: MPU W351 Wellbore: MPU M -35i Plan: MPU M-35 wp08 caiaiaioe Merom: Mbl- cary . 0.00 0.00 6027765.69 533873.83 70° 29 12 781 N 149° 43'23.297 6URVEY PROGRAM NO GLOBAL FILTER: Using user defined selection & filtering criteria Dam: 201x12-16TCD:Oo:oo Vagtlatatl: Ya version: 33.70 To 17557.98 Ladder/S. F. Plots CASING DETAILS DepM From Daptb To 6urveylPlan Tool 33.70 40n00 MPUM-35w08(MPUM-35i) 3_Gyro-GC_Csg TVD TVDSS MD Size Name 1 oft 40000 6400.40 MPUM-35 wp08(MPUM-350-1-IFR21--g 6400.40 1]55].63 MPUM-35 wp08 (MPU MJ5) 3_MWOfIFR2 MB Bag 3914.00 3855.00 6400.40 9-5/8 9 5/8" s 12 1/4" 3819.00 3760.00 17557.63 4-1/2 4 1/2" r 8 1/2" 180.00 - I �� �. 08DSW 2 McLaws I i I y150.00 o cv120.00 o ��, - m Slot 4 Placehold r n 90.00 MPU -34 wp06- 4- Placehold r 11 I I I cSlot Q) 60.00 U MPU l5i II m Slot 37 Placehold9r 15 30.00 U MPU - .14 ! -- T- _ 0.00 0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300 6650 Measured Depth (700 usft/in) 4.00 o is 3.00 - co LL o T 2.00 C Collision Risk Procedures Req. 1.00 Collision Avoidance Req. No -Go Zone - Stop Drilling I ' NOERRORS I I 0.00 0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300 6650 Measured Depth (700 usft/in) Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M -35i MPU M -35i MPU M-35 wp08 Sperry Drilling Services Clearance Summary Anticollision Report 08 January, 2020 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -35i - MPU M -35i - MPU M-35 wp08 Well Coordinates: 6,027,765.69 N, 533,873.83 E (70° 29' 12.78" N, 149° 43' 23.30" W) Datum Height: MPU M -35i As -built RKB @ 59.00usft Scan Range: 6,400.40 to 17,557.63 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: 91E Scan Type: • - - Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU M -35i - MPU M-35 wp08 Hilcorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -35i - MPU M -35i - MPU M-35 wp08 Scan Range: 6,400.40 to 17,557.63 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 M Pt J Pad MPJ -20 - MPJ -20A - MPJ -20A MPJ -20 - MPJ -20A - MPJ -20A MPJ -20 - MPJ -20A - MPJ -20A MPJ -23 - MPJ -23 - MPJ -23 MPJ -23 - MPJ -23 - MPJ -23 MPJ -23 - MPJ -23 - MPJ -23 MPJ -23 - MPJ -23A - MPJ -23A MPJ -23 - MPJ -23A - MPJ -23A MPJ -23 - MPJ -23A - MPJ -23A MPJ -23 - MPJ -231-1 - MPJ -23L1 MPJ -23 -MPJ -231-1 -MPJ-23L1 MPJ -23 - MPJ -231-1 - MPJ -23L1 MPJ -24 - MPJ -24A - MPJ -24A MPJ -24 - MPJ -24A - MPJ -24A MPJ -24 - MPJ -24L1 - MPJ -241-1 MPJ -24 -MPJ -241-1 -MPJ-24L1 MPJ -24 -MPJ -241-1 -MPJ-241-1 MPJ -24 - MPU J-24 - MPJ -24 MPJ -24 - MPU J-24 - MPJ -24 MPJ -27 - MPJ -27 - MPJ -27 MPJ -27 - MPJ -27 - MPJ -27 MPJ -27 - MPJ -27 - MPJ -27 MPJ -28 - MPJ -28 - MPJ -28 M Pt L Pad MPL-35 - MPL-35 - MPL-35 MPL-35 - MPL-35 - MPL-35 MPL-35 - MPL-35 - MPL-35 16,627.05 810.21 16,627.05 290.62 11,176.00 1.559 Centre Distance Pass - 16,775.40 823.68 16,775.40 271.19 11,176.00 1.491 Ellipse Separation Pass - 16,800.40 828.54 16,800.40 272.31 11,176.00 1.490 Clearance Factor Pass- ® ® ®®® 17,058.46 216.66 17,058.46 115.53 10,748.75 2.143 Centre Distance Pass - 14,032.06 221.94 14,032.06 131.26 12,993.35 2.448 Centre Distance Pass - 14,502.05 840.63 14,502.05 290.59 12,115.00 1.528 Centre Distance Pass - 14,650.40 853.62 14,650.40 270.73 12,115.00 1.464 Ellipse Separation Pass - 14,675.40 858.32 14,675.40 271.68 12,115.00 1.463 Clearance Factor Pass- ® ®®®® 15,555.56 202.55 15,555.56 120.52 12,051.05 2.469 Centre Distance Pass - 15,750.40 260.40 15,750.40 42.93 11,943.97 1.197 Ellipse Separation Pass - 15,775.40 274.11 15,775.40 44.65 11,930.51 1.195 Clearance Factor Pass - 17,557.63 799.58 17,557.63 473.13 10,595.76 2.449 Clearance Factor Pass - 8,400.40 1,218.53 8,400.40 1,079.37 13,562.70 8.756 Clearance Factor Pass - 9,050.40 1,005.00 9,050.40 915.74 13,704.02 11.259 Ellipse Separation Pass - 9,111.93 1,003.23 9,111.93 916.77 13,717.78 11.603 Centre Distance Pass - 08 January, 2020 - 16:21 Page 2 of 7 COMPASS Hilcorp Alaska, LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU M -35i - MPU M-35 wpO8 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M -35i - MPU M -35i - MPU M-35 wp08 Scan Range: 6,400.40 to 17,557.63 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 MPL-35 - MPL-35A - MPL-35A 8,400.40 1,218.53 8,400.40 1,079.08 13,563.50 8.738 Clearance Factor Pass - MPL-35 - MPL-35A - MPL-35A 9,050.40 1,005.00 9,050.40 915.72 13,704.82 11.256 Ellipse Separation Pass - MPL-35 - MPL-35A - MPL-35A 9,111.93 1,003.23 9,111.93 916.76 13,718.58 11.602 Centre Distance Pass - MPL-35-MPL-35AP81-MPL-35APB1 8,400.40 1,218.53 8,400.40 1,078.94 13,563.50 8.730 Clearance Factor Pass - MPL-35 - MPL-35APB1 - MPL-35APB1 9,050.40 1,005.00 9,050.40 915.60 13,704.82 11.242 Ellipse Separation Pass - MPL-35 - MPL-35APB1 - MPL-35APB1 9,111.93 1,003.23 9,111.93 916.65 13,718.58 11.587 Centre Distance Pass - MPL-35 - MPL-35APB2 - MPL-35APB2 8,400.40 1,218.53 8,400.40 1,078.94 13,563.50 8.730 Clearance Factor Pass - MPL-35 - MPL-35AP132 - MPL-35APB2 9,050.40 1,005.00 9,050.40 915.60 13,704.82 11.242 Ellipse Separation Pass - MPL-35-MPL-35APB2-MPL-35APB2 9,111.93 1,003.23 9,111.93 916.65 13,718.58 11.587 Centre Distance Pass - MPL-35 - MPL-35APB3 - MPL-35APB3 8,400.40 1,218.53 8,400.40 1,078.94 13,563.50 8.730 Clearance Factor Pass - MPL-35 - MPL-35APB3 - MPL-35APB3 9,050.40 1,005.00 9,050.40 915.60 13,704.82 11.242 Ellipse Separation Pass - MPL-35 - MPL-35APB3 - MPL-35APB3 9,111.93 1,003.23 9,111.93 916.65 13,718.58 11.587 Centre Distance Pass - MPL-36 - MPL-36 - MPL-36 6,455.55 598.47 6,455.55 525.65 13,487.86 8.219 Centre Distance Pass - MPL-36 - MPL-36 - MPL-36 6,500.40 600.84 6,500.40 524.68 13,490.20 7.889 Ellipse Separation Pass - MPL-36 - MPL-36 - MPL-36 6,925.40 778.27 6,925.40 637.43 13,509.71 5.526 Clearance Factor Pass - MPL-36 - MPL-361-1 - MPL-361-1 6,455.55 598.47 6,455.55 525.62 13,487.86 8.214 Centre Distance Pass - MPL-36 - MPL-36L1 - MPL-361-1 6,500.40 600.84 6,500.40 524.33 13,490.20 7.853 Ellipse Separation Pass - MPL-36 - MPL-361-1 - MPL-361-1 6,925.40 778.27 6,925.40 632.18 13,509.71 5.327 Clearance Factor Pass - MPL-36 - MPL-361-1 P131 - MPL-361-1 PB1 6,455.55 598.47 6,455.55 525.59 13,487.86 8.211 Centre Distance Pass - MPL-36 - MPL-36L1 P61 - MPL-361-1 PB1 6,525.40 604.19 6,525.40 523.99 13,491.41 7.533 Ellipse Separation Pass - MPL-36 - MPL-361-1 PB1 - MPL-361-1 PB1 6,925.40 778.27 6,925.40 628.26 13,509.71 5.188 Clearance Factor Pass - MPL-36 - MPL-36PB1 - MPL-36PB1 6,455.55 598.47 6,455.55 525.65 13,487.86 8.219 Centre Distance Pass - MPL-36 - MPL-36PB1 - MPL-36PB1 6,500.40 600.84 6,500.40 524.68 13,490.20 7.890 Ellipse Separation Pass - MPL-36 - MPL-36PB1 - MPL-36PB1 6,925.40 778.27 6,925.40 637.46 13,509.71 5.527 Clearance Factor Pass - MPU L-53 - MPU L-53 - MPU L-53 9,150.40 542.69 9,150.40 343.68 14,800.00 2.727 Clearance Factor Pass - MPU L-53 - MPU L-53 - MPU L-53 9,225.40 525.74 9,225.40 335.39 14,800.00 2.762 Ellipse Separation Pass - MPU L-53 - MPU L-53 - MPU L-53 9,308.64 519.11 9,308.64 340.59 14,800.00 2.908 Centre Distance Pass - M PU L-56 - M PU L-56 - M PU L-56 9,725.40 963.98 9,725.40 756.82 14,330.00 4.653 Clearance Factor Pass - MPU L-56 - MPU L-56 - MPU L-56 9,900.40 936.31 9,900.40 741.07 14,330.00 4.796 Ellipse Separation Pass - MPU L-56 - MPU L-56 - MPU L-56 9,963.14 934.20 9,963.14 744.19 14,330.00 4.917 Centre Distance Pass - 08 January, 2020 - 16:21 Page 3 of 7 COMPASS Hilcorp Alaska, LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU M -35i - MPU M-35 wp08 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-351- MPU M-351- MPU M-35 wp08 Scan Range: 6,400.40 to 17,557.63 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 M Pt Moose Pad MPU M-14- MPU M-14 - MPU M-14 6,400.40 1,207.63 6,400.40 1,061.73 6,645.41 8.277 Ellipse Separation Pass - MPU M-14- MPU M-14 - MPU M-14 6,600.40 1,260.06 6,600.40 1,103.77 6,974.57 8.063 Clearance Factor Pass - MPU M -15i - MPU M-15 - MPU M -1 5i6,400.40 366.49 6,400.40 216.15 6,581.99 2.438 Clearance Factor Pass - MPU M -15i - MPU M-15PB1 - MPU M-15PB1 6,400.40 371.55 6,400.40 222.55 6,567.60 2.494 Clearance Factor Pass - MPU M-16 - MPU M-16 - MPU M-16 7,877.06 65.75 7,877.06 22.39 8,099.32 1.516 Centre Distance Pass - MPU M-16 - MPU M-16 - MPU M-16 ® ® ®®® ® MPU M-16- MPU M-16 - MPU M-16 ® ®®®® I® ®_ MPU M -17i - MPU M -17i - MPU M -17i 10,870.91 76.28 10,870.91 17.10 11,218.56 1.289 Centre Distance Pass - MPU M -17i - MPU M -17i - MPU M -17i ®®®® MPU M -17i - MPU M -17i - MPU M -17i ®®®� MPU M-18 - MPU M-18 - MPU M-18 ®® MPU M-18- MPU M -I8- MPU M-18 ® ®® MPU M -18 -MPU M -18 -MPU M-18 ® ®® MPU M-18 - MPU M-18PB1 - MPU M-18PB1 9,944.06 1,106.41 9,944.06 846.54 10,361.00 4.257 Centre Distance Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 9,975.40 1,106.86 9,975.40 846.09 10,361.00 4.245 Ellipse Separation Pass - MPU M-18 - MPU M-18PB1 - MPU M-18PB1 10,025.40 1,109.40 10,025.40 847.62 10,361.00 4.238 Clearance Factor Pass - MPU M-18 - MPU M-18PB2 - MPU M-18PB2 11,285.46 706.33 11,285.46 424.37 11,767.00 2.505 Centre Distance Pass - MPU M-18- MPU M-18PB2 - MPU M-18PB2 11,300.40 706.49 11,300.40 424.04 11,767.00 2.501 Ellipse Separation Pass - MPU M -I8- MPU M-18PB2- MPU M-18PB2 11,325.40 707.46 11,325.40 424.47 11,767.00 2.500 Clearance Factor Pass - MPU M -19i - MPU M-191 - MPU M-191 S MPU M -19i - MPU M-191 - MPU M-191 MPU M -19i - MPU M-191 - MPU M-191 MPU M -19i - MPU M-19PB1 - MPU M-19PB1 13,889.75 731.16 13,889.75 352.58 14,561.00 1.931 Centre Distance Pass - MPU M -19i - MPU M-19PB1 - MPU M-19PB1 13,900.40 731.24 13,900.40 352.46 14,561.00 1.931 Clearance Factor Pass- ass-Plan: Plan:MPU M-43 - Slot 52 - MPU M-43 - MPU M-43 wp 8,300.40 286.86 8,300.40 170.99 11,579.80 2.476 Clearance Factor Pass - Plan: MPU M-43 - Slot 52 - MPU M-43 - MPU M-43 wp 8,425.40 243.01 8,425.40 153.76 11,672.93 2.723 Ellipse Separation Pass - Plan: MPU M43 - Slot 52 - MPU M-43 - MPU M-43 wp 8,571.86 222.51 8,571.86 168.21 11,782.06 4.098 Centre Distance Pass - Plan: MPU M -44i - Slot 58 - MPU M -44i - MPU M -44i H 6,925.40 296.18 6,925.40 196.89 10,004.05 2.983 Clearance Factor Pass - Plan: MPU M -44i - Slot 58 - MPU M -44i - MPU M -44i H 7,075.40 247.50 7,075.40 177.50 10,115.62 3.535 Ellipse Separation Pass- ass-08 08January, 2020 - 18:21 Page 4 of 7 COMPASS HALLIBURTON Anticollision Report for Plan: MPU M -35i - MPU M-35 wp08 Hileorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - Plan: MPU M-351 - MPU M -35i - MPU M-35 wp08 Scan Range: 6,400.40 to 17,557.63 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 Plan: MPU M -44i - Slot 58 - MPU M -44i - MPU M44i H 7,197.84 233.58 7,197.84 187.56 10,206.70 5.075 Centre Distance Pass - Plan: MPU M-45 -Slot 48 - MPU M-45 - MPU M-45 wpl 6,400.40 473.37 6,400.40 364.93 8,878.22 4.365 Clearance Factor Pass - Proposal: MPU M-08DSW - McLaws - M-08DSW - Mc 6,400.40 968.15 6,400.40 914.56 5,910.50 18.069 Clearance Factor Pass - Rig: MPU M-34 - MPU M-34 - MPU M-34 wp06 6,400.40 735.70 6,400.40 569.83 6,316.39 4.435 Centre Distance Pass - Rig: MPU M-34 - MPU M-34 - MPU M-34 wp06 17,557.63 785.96 17;557.63 257.87 17,523.17 1.488 Clearance Factor Pass - M Pt N Pad MPN-01 - MPN-01 - MPN-01 17,557.63 226.37 17,557.63 165.94 3,813.66 3.746 Clearance Factor Pass - MPN-0I-MPN-01A-MPN-01A 17,557.63 593.65 17,557.63 501.02 3,562.53 6.408 Clearance Factor Pass - MPN-0I-MPN-01B-MPN-01B 17,557.63 482.34 17,557.63 277.39 3,645.08 2.354 Clearance Factor Pass - Milne Point Exploration MPU-Liviano-01 - Liviano-01 - Liviano-01 MPU-Liviano-01 - Liviano-01A- Liviano-01A Survey tool program IIIA ®®®®IIIIIIIIIIIII! 9,388.65 171.16 9,388.65 38.94 3,997.04 1.295 Clearance Factor Pass - From To Survey/Plan (usft) (usft) 33.70 400.00 MPU M-35 wp08 400.00 6,400.40 MPU M-35 wp08 6,400.40 17,557.63 MPU M-35wp08 Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method Survey Tool 3_Gyro-GC_Csg 3 1AWD+]FR2+1VIS+Sag 3_M WD+I FR2+M S+Sag 08 January, 2020 - 16:21 Page 5 of 7 COMPASS HALUBURTON $PPrrY Grilling 4.00– o YS 3.00– co ILL0 0 2.00- 22 U) 1.00- 0.00– Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -35i Wellbore: MPU M -35i Plan: MPU M-35 wpO8 Ladder/ S.F. Plots 2of2 REFERENCE INFORMATION ! NAD 1927(NADCON CONUS) Alaska Zone 04 Coordinate (NIE) Reference: Well Plan: MPU M -35i, True North Vertical (IVD) Remrence: MPU Ml IRKS @ Sg.GOusR Measured Depth Reference: MPV M-35iAo-WR RKe @ Se.00uelt Calculation Method: Minimum Curvature 533873.83 70° 29 12.781 N 149° 43'2: SURVEY PROGRAM Dam: 201x12-16700:00:00 Validated: Ye. Version: DepN From Depth To SUNayIPlan Tool 33.70 400.00 MPU M-35 wP08 (MPU M- ') 3 Gyro-GC_Cag 400.00 6400.40 MPU M-3S.V08 (MPU M-3513 UM40 1755163 MPUM-35wp08(MPUM-35i) 3 MWD+IFR2+MS+Sag 3_MWD+IFR3+MS+Seg 1 WELL DEIAILSTI.: MPU M -35i NAD 1927(NADCON CONUS) Alaska Zone 04 25.30 +N/S +p/ -W NoNting F e'ng LatiftU& Coagil 0.00 0.00 6027765.69 533873.83 70° 29 12.781 N 149° 43'2: NO GLOBAL FILTER: Using user defined selection & filtering criteria 33.70 To 17557.98 i CASING DETAILS TVD TVDSS ame MD Site N- 3914.00 3855.00 39 6400.40 9-5/8 9 5/8" . 12 1/4" 3819.00 3760.00 17557.63 4-1/2 4 12" s 8 l2" Collision Risk Procedures I 1 i I � I 'ill III Will i Ill µlllll}IIIIµII IIIIIIIµµll 1111111 Yllllµlll/, IIII ' I 4 1 dl l � IIII II i III �' � I ISI I� I 71 I IIII I III i II I' � I � jj i I I I I^ III i � I n 11 l I�� � I II I I I JII � ifi I I !I I , . II III,,, Ill 6111';1 II '11 i 11400 12000 12600 13200 13800 14400 15000 15600 16200 16800 17400 Measured Depth (1200 usft/in) 6600 7200 7800 8400 9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200 16800 17400 Measured Depth (1200 usft/in) I I i I I Collision Risk Procedures I I i No -Go Zone - Stop Drill NOERRORS g r I -- Collision Avoidance Req.l j 6600 7200 7800 8400 9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200 16800 17400 Measured Depth (1200 usft/in) Davies, Stephen F (CED) From: Cody Dinger <cdinger@hilcorp.com> Sent: Tuesday, January 14, 2020 4:40 PM To: Davies, Stephen F (CED) Cc: Joseph Engel Subject: Re: [EXTERNAL] RE: MPU M-35 Permit (PTD 220-005) Steve, Hilcorp will not pre produce MPU M-35. We will have enough mud supplies in location to raise the mud weight 1 ppg if necessary. Thanks, Cody Get Outlook for iOS<https://ur!defense.com/v3/_https://aka.ms/o0ukef_;!!J2_8gdp6gZQ!9d!p7RbORYs5vxVZVflnhldVRuNmmBI16n DHEeV_vOhevGawNT2lY18-K2tVlwgBATyiuQ$ > From: Davies, Stephen F (CED) <steve.davies@alaska.gov> Sent: Tuesday, January 14, 2020 4:07 PM To: Cody Dinger Subject: [EXTERNAL] RE: MPU M-35 Permit (PTD 220-005) Cody, Quick questions: Will this injector be pre -produced for 30 days or more, or will it be briefly flowed back for clean up? Will Hilcorp have mud supplies on hand to increase mud weight 1 ppg above maximum expected weight? Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov<mailto:steve.davies@alaska.gov>. From: Cody Dinger <cdinger@hilcorp.com> Sent: Monday, January 13, 2020 11:23 AM To: Boyer, David L (CED) <david.boyer2@alaska.gov>; Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: MPU M-35 Permit David/Steve, Here is the directional plan for MPU M-35, I will drop the permit off this afternoon. Thanks! Cody Dinger Hilcorp Alaska, LLC Drilling Tech 907-777-8389 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. TRANS) 'ITA.L LETTER CHECKLIST WELL NAAM: PTD: — Development _ ` Service Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: �( POOL: Check Box for Appropriate Letter I Paragraphs to be Included in Transmittal Letter CHECK7�AT ONS TEXT FOR APPROVAL LETTER The permit is for a new wellbore segment of existing well Permit L No. API No. 50- -_ ---------------------- o digits Production should continue to be reported as a func the original mber are API number stated above. Z: 60-69) 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 In accordance with 20 AAC 25.005(f), all records, data andlogs acquired for the pilot hole must be clearly differentiated in Pilot Hole name both well PIS and API number (50- from records, data and logs acquired for well e on namrmit . The permit is approved subject to full compliance with 20 AAC 25.055. Spacing Exception Approval to produceliuject is contingent upon issuance of a conservation order approving a spacing exception. (ComnanV Name) Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sam le intervals throuRh target zones. Please note the following special condition of this permit: Non -Conventional production or production testing of coal bed methane is not allowed for Lname of well) until Well after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Companv Name) must contact the AOGCC to obtain advance approval of such water well IgAhng program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify typ1by well logs to be run. In addition to the well logging program propose(COffiDanyName) in the attached application, the following well log also required for this well: Well Logging f Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140 Well Name: MILNE PT UNIT M-35 Program SER Well bore seg ❑ PTD#: 2200050 Company Hilcorp Alaska LLC Initial Class/Type SER/PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached_ - - - - - - - - - - - - - - - - - - --NA_ - - - - _ _ . 2 Lease number appropriate_ - _ _ - - - - - - - - - - - - _Yes - - - - - - - Surf_ Loc &_Top Prod Int lie in ADL0025514; Portion -of Productive Intervallies in ADL0025515; 3 Unique well -name and number - - - - - - - - - - - - - - - - - - - - - - -- - - - Yes - - - - - - - TD Lies in ADL0025517-_ - - - - - - - - _ - - _ . 4 Well located in a_definedpool - - - ------------------ - _ Yes - - - - _ Milne Point Schrader Bluff_ Oil Pool (525140), governed by_CO 477, amended by CO 477_.05. 5 Well located proper distance_ from drilling unit -boundary--------------- - - Yes _ - - - - - _ CO 477.05 specifies: "There are no restrictions as to well spacing except that no pay shall_ - - - - 6 Well located proper distance_ from other wells_ - - . - . . _ . - - Yes -- - - - - _ be opened_in a well closer than_ 500 feet from the exterior boundary of -the -affected area." 7 Sufficient acreage -available in -drilling unit - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - As planned, well conforms to spacing requirements. 8 If-deviated,is-wellboreplat_included - _ - - - - - _- - - - - - -------------- Yes - - - - -- - - - - - - - - - - _ . ---------------------------------- 9 Operator only affected party - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 10 Operator has -appropriate- bond in force _ - - - - - _ - - ---- Yes - - - - - - _ _ . _ ------------------------------------- ------------- 11 Permitc_an be issued without conservation order- - - - - - - - - - - - - - - - Yes - - - - - - - - - - - Appr Date 12 Permit_can be issued without administrativ_e_approval - - - - - - - - - - - - - - - - - -- - - - Yes - - - - _ _ _ _ - _ _ _ _ _ _ . _ _ _ _ - - - - - ---------------------------- 13 Can permit be approved before 15-day_wait _ - - -- - - - Yes- - - - - - _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - SFD 1/14/2020 14 Well.located within area and -strata authorized by Injection Order # (put -10# in_comments)_(For_ Yes - - - - - - _ Area Injection Order N 10 -B - - _ _--------------------- - - - --- 15 All wells within 1/4 mile area of review identified (For service well only) - - - - - - - - - - - - - - No_ - - . - _ _ AOR:_MPU J -20A, J-23, J -23A, J-24, J -24A, J -24L1_, J -27,-J-28, Liviano_01, Liviano 01A,- 16 Pre -produced injector: duration -of pre production Less than 3 months _(For service well only) - N_o_ - - - - - M -14,-M-15, M-16, 9-1.7, M-18, M -19,_M-34, N-01, N-01A,_and N-0113- - - - - - - - - - - - - 17 Nonconve,n, gas conforms to AS31.05.030Q.1_.A),0.2_.A-D) -- - - - - - - - - - - - - - - - - - Yes - _ _ - - - - - - - Well will NOT be ------------ 18 18_ Conductor string -provided - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - _ - 20_" conductor set at 115 ft _ _ - - - - - _ - _ - - - - - - - - - - Engineering 19 Surface casing_ protects all -known- USDWs -- - - - - - - - - - - - - - - - - - - - - - - - - - - - NA_ - - . - - - _ No aquifers in -area --------- - - - - - - - - - - 20 CMT -vol adequate -to circ ulate_on conductor _& surf_csg - - - - - - _ . - - - _ Yes - . - - - - 9 5/8"will be fully_ cemented. Landed in OB sand... at 6400 ft (3800 TVD)_ _ _ - - - - - - - - - 21 CMT vol- adequate_ to tie-in long string to surf csg_ NA_ - - - - - - ES tool -at 2500 ft_md - - - - - - - - - - - - - - - - - - - - _ _ _ _ . - 22 CMT -will coverall known -productive horizons_ - - - - Yes - - - - 23 Casing designs adequate for C, T, B &_permafr_ost_ - - Yes - - - - - - - BTC calc-provided-- - - - - - - - - - - - - ,24 Adequate -tan _kage_or reserve pit - - - - - -- - - - - - - - - - - - - - - - _ Yes _ . - - - - - Rig has steel pits_. _ _ _ _ _ - _ _ _ _ _ - - - - - - - 25 If_a_re-drill_, has_a 10-403 for abandonment been approved _ _ _ - _ NA- _ _ 26 Adequate wellbore separatlon_proposed- - - - - - - - - - - - _ - - - _ Yes - - _ - - - - Fails anti- collision- but drilling OB -sand just above existing OA -sand laterals. - - - - - - - - - - 27 If-diverterrequired, does it meet_ regulations _________________ - - -- Yes --_-Diverterlayout shown._ 16" line __________-----------..------------___-- Appr Date 128 Drilling fluid_ program schematic-&- equip list adequate_ - - Yes - - - - Max formation_ pressure =_1722 psi (8.6-ppg EMW) _will drill with 8.9- 9.5 ppg-mud. GLS 1/16/2020 29 BOPEs,_do-they meet regulation - - - - - - - - - - - - - - - - - - - ... - - - - _ _ - _ - - Yes. - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ . _ . - - - - - - - - 30 BOPE_press rating appropriate; test to -(put psig in comments)_ Yes . - - - - - - MASP= 1329 psi Will test BOPE_to 3000 -psi- 14_ day test cycle 31 Choke -manifold complies w/API_RP-53 (May 84)- - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ -- - - . _ _ _ _ - _ - ------------------- - - - - - - - - - - - - - .. - - - - - - - - - - - - 32 Work will occur without operationshutdown_ - - -- Yes- - - - - - - - - - - - - - - - - - - - - . - - - - - _ - - - - 33 Is presence. of H2S gas- probable - _ _ - - - - - - - - No_ - - - - H2S not expected but rig has -sensors -and alarms. 34 Mechanical -condition of wells within AOR verified (For service well only) - - - - - - - - - - - - - Yes - _ _ _ _ - _ AOR spreadsheet is supplied. _No_issues- - - - - - - - - . - - . - - _ - - - - - - - - - - - - - - - - - - - - - 35 Permitcan be issued w/o hydrogen sulfide measures - - Yes _ . - - - - - H2S not anticipated from drilling of offset wells; however, rig has H2S sensors and alarms. Geology 36 Data_presented on potential overpressure zones _ - - - - - - - - - - - Yes . _ - - - - - Gas_ hydrates not expected from drilling -of offset wells._However, mitigation_measures are discussed in Appr Date 37 Seismic_analys_is_ of shallow gas_zones_ - - _ _ - - - - - - - - - - - - - - - - - - - - - NA- _ - - - - - Anticipated_D_ril_ling Hazards"_s_ection._Ab_nor_m_al pressure has been encountered in -M -Pad_ wells - - - - SFD 1/14/2020 I38 Seabed condition survey (if off_ -shore) - - - - - - - - - - - - - - - - - - - - - - - - - NA_ - - _ - - _ - due to nearby injection. Managed Pressure Drilling will be used -to monitor and -control pressure. 39 Contact name/phone for weekly -progress reports_ [exploratory only] - - - - - - - - _ _ NA_ _ - - - - _ _ Onsite materials sufficient -to build system to_1_ ppg above highest anticipated mud weight. _ i Geologic Engineering Public Schrader Bluff OB injector. o Commissioner: Date: Commissioner: Date Commis r Date s .X71 ��� 1�2,r� VVV >>�,�1
