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Home My WebLink About221-067CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Joseph Lastufka To:AOGCC Permitting (CED sponsored) Cc:Nathan Sperry; Rixse, Melvin G (OGC) Subject:MPU I-29 (PTD #221-067) 10-401 Permit to Drill **Cancel** Date:Monday, January 24, 2022 11:54:10 AM Hello, Due to changing of the rig for drilling MPU I-29 (PTD #221-067) it has been requested that we cancel the current 10-401 Permit to Drill and resubmit a new 10-401. Please cancel PTD #221-067 for MPU I-29, a separate new 10-401 Permit to Drill will be submitted shortly. Please let me know if you have any questions. Thanks! Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC Office: (907)777-8400, Cell:(907)227-8496 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU I-29 Hilcorp Alaska, LLC Permit to Drill Number: 221-067 Surface Location: 2327' FSL, 3654' FEL, Sec. 33, T13N, R10E, UM, AK Bottomhole Location: 1793' FNL, 1191' FWL, Sec. 21, T13N, R10E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced 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, Jeremy M. Price Chair DATED this ___ day of 6HSWHPEHU, 2021. Jeremy Price Digitally signed by Jeremy Price Date: 2021.09.02 09:47:38 -08'00' 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil 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 Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 16,119' TVD: 4,150' 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 3166' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 59.9' 15. Distance to Nearest Well Open Surface: x-551717 y- 6009443 Zone- 4 33.4' to Same Pool: 959' 16. Deviated wells: Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Driven 20" 129.5# X-56 150' Surface Surface 180' 180' 47# L-80 TXP 2,500' Surface Surface 2,500' 2,235' 40# L-80 TXP 3,208' 2,500' 2,235' 5,708' 3,970' Tieback 7-5/8" 29.7# L-80 Hyd 521 5,558' Surface Surface 5,558' 3,957' 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 10,561' 5,558' 3,957' 16,119' 4,150' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Nathan Sperry Monty Myers Contact Email:nathan.sperry@hilcorp.com Drilling Manager Contact Phone:777-8450 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng September 20, 2021 12-1/4" 9-5/8" 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): Uncemented Tieback Uncemented Screen Liner Effect. Depth MD (ft): Effect. Depth TVD (ft): Authorized Title: Authorized Signature: Production Liner Intermediate Authorized Name: Conductor/Structural LengthCasing Cement Volume MDSize Plugs (measured): (including stage data) Stg 1 L - 898 ft3 / T - 458 ft3 6395 18. Casing Program: Top - Setting Depth - BottomSpecifications 1814 Total Depth MD (ft): Total Depth TVD (ft): 22224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Stg 2 L - 1935 ft3 / T - 313 ft3 1399 2113' FNL, 441' FEL, Sec. 32, T13N, R10E, UM, AK 1793' FNL, 1191' FWL, Sec. 21, T13N, R10E, UM, AK 88-004 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 2327' FSL, 3654' FEL, Sec. 33, T13N, R10E, UM, AK ADL 025906, 025517 & 315848 MPU I-29 Milne Point Field Schrader Bluff Oil Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 8.24.2021 By Samantha Carlisle at 9:12 am, Aug 24, 2021 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2021.08.24 08:51:10 -08'00' Monty M Myers 50-029-23698-00-00 DSR-8/25/21SFD 8/24/2021MGR30AUG2021 221-067 BOPE Test to 3000 psi. Annular to 2500 psi. dts 8/31/2021 JLC 8/31/2021 9/2/21 Jeremy Price Digitally signed by Jeremy Price Date: 2021.09.02 09:49:19 -08'00' Milne Point Unit (MPU) I-29 Drilling Program Version 1 8/17/2021 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 13-5/8” 5M 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 ................................................................................................. 22 14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 26 15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28 16.0 Run 4-1/2” Screened Liner ...................................................................................................... 33 17.0 Run 7-5/8” Tieback .................................................................................................................. 37 18.0 Run Upper Completion – ESP ................................................................................................. 40 19.0 Innovation Rig Diverter Schematic ......................................................................................... 42 20.0 Innovation Rig BOP Schematic ............................................................................................... 43 21.0 Wellhead Schematic ................................................................................................................. 44 22.0 Days Vs Depth .......................................................................................................................... 45 23.0 Formation Tops & Information............................................................................................... 46 24.0 Anticipated Drilling Hazards .................................................................................................. 48 25.0 Innovation Rig Layout ............................................................................................................. 51 26.0 FIT Procedure .......................................................................................................................... 52 27.0 Innovation Rig Choke Manifold Schematic ............................................................................ 53 28.0 Casing Design ........................................................................................................................... 54 29.0 8-1/2” Hole Section MASP ....................................................................................................... 55 30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 56 31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 57 Page 2 Milne Point Unit I-29 SB Producer Drilling Procedure 1.0 Well Summary Well MPU I-29 Pad Milne Point “I” Pad Planned Completion Type ESP Target Reservoir(s) Schrader Bluff OA Sand Planned Well TD, MD / TVD 16,119’ MD / 4,150’ TVD PBTD, MD / TVD 16,119’ MD / 4,150’ TVD Surface Location (Governmental) 2327' FSL, 1626' FWL, Sec 33, T13N, R10E, UM, AK Surface Location (NAD 27) X= 551717, Y=6009443 Top of Productive Horizon (Governmental)2113' FNL, 441' FEL, Sec 32, T13N, R10E, UM, AK TPH Location (NAD 27) X= 549643, Y=6010268 BHL (Governmental) 1793' FNL, 1191' FWL, Sec 21, T13N, R10E, UM, AK BHL (NAD 27) X= 551170, Y=6021158 AFE Number AFE Drilling Days 17 AFE Completion Days 4 Maximum Anticipated Pressure (Surface) 1399 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1814 psig Work String 5” 19.5# S-135 NC 50 Innovation KB Elevation above MSL: 26.5 ft + 33.4 ft = 59.9 ft GL Elevation above MSL: 33.4 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit I-29 SB Producer Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit I-29 SB Producer Drilling Procedure 3.0 Tubular Program: Hole Section OD (in)ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.25”---X-52Weld 12-1/4”9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916 9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086 Tieback 7-5/8” 6.875” 6.75” 7.947” 29.7 L-80 HYD 521 6,890 4,790 683 8-1/2”4-1/2” Screens 3.920 3.795 4.714 13.5 L-80 Hydril 625 9,020 8,540 279 4.0 Drill Pipe Information: Hole Section OD (in) ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surface & Production 5”4.276”3.25” 6.625”19.5 S-135 DS50 36,100 43,100 560klb 5”4.276”3.25” 6.625”19.5 S-135 NC50 30,730 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit I-29 SB Producer Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. x Report covers operations from 6am to 6am x 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. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp, nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 907.301.8996 nathan.sperry@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com Completion Engineer Ted Kramer 907.777.8420 985.867.0665 tkramer@hilcorp.com Completion Engineer David Gorm 907.777.8333 505.215.2819 dgorm@hilcorp.com Geologist John Salsbury 907.777.8481 907.350.1088 jsalsbury@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 cajones@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 Joseph.Lastufka@hilcorp.com Page 6 Milne Point Unit I-29 SB Producer Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Milne Point Unit I-29 SB Producer Drilling Procedure 7.0 Drilling / Completion Summary MPU I-29 is a grassroots producer planned to be drilled in the Schrader Bluff OA sand. I-29 is part of a multi well program targeting the Schrader Bluff sand on I-pad The directional plan is 12-1/4” surface hole and 9-5/8” surface casing set into the top of the Schrader Bluff OA sand. An 8-1/2” lateral section will be drilled. A 4-1/2” liner will be run in the open hole section and the well will be produced with an ESP. The Innovation Rig will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately September 20, 2021, pending rig schedule. Surface casing will be run to 5,708’ MD / 3,970’ 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 Innovation Rig to well site 2. N/U & Test 13-5/8” 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 wellhead, NU 13-5/8” 5M BOP & Test 5. Drill 8-1/2” lateral to well TD 6. Run 4-1/2” production liner 7. Run 7-5/8” tieback 8. Run Upper Completion 9. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) Page 8 Milne Point Unit I-29 SB Producer 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. x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU I-29. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x 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. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x 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 x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. AOGCC Regulation Variance Requests: x None Page 9 Milne Point Unit I-29 SB Producer Drilling Procedure Summary of Innovation BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4”x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only 8-1/2” x 13-5/8” x 5M Control Technology Inc Annular BOP x 13-5/8” x 5M Control Technology Inc Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Control Technology Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3,000 Subsequent Tests: 250/3,000 Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Milne Point Unit I-29 SB Producer Drilling Procedure 9.0 R/U and Preparatory Work 9.1 I-29 will utilize a newly set 20” conductor on I-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 R/U. 9.6 Rig mat footprint of rig. 9.7 MIRU Innovation. 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 (<80qF). 9.10 Ensure 5” liners in mud pumps. x White Star Quattro 1,300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @ 96.5% volumetric efficiency. Page 11 Milne Point Unit I-29 SB Producer Drilling Procedure 10.0 N/U 13-5/8” 5M Diverter System 10.1 N/U 13-5/8” CTI BOP stack in diverter configuration (Diverter Schematic attached to program). x N/U 20” x 13-5/8” DSA x N/U 13 5/8”, 5M diverter “T”. x NU Knife gate & 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 ft from nearest ignition source x Place drip berm at the end of diverter line. x Utilized extensions if needed. 10.2 Notify AOGCC. Function test diverter. x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x Ensure that the annular closes in less than 30 seconds (API Standard 64 3rd edition March 2018 section 12.6.2 for packing element ID less than or equal to 20”) 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: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. Page 12 Milne Point Unit I-29 SB Producer Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 13 Milne Point Unit I-29 SB Producer Drilling Procedure 11.0 Drill 12-1/4” Hole Section 11.1 P/U 12-1/4” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Consider running a UBHO sub for wireline gyro.GWD will be the primary gyro tool. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill string will be 5” 19.5# S-135. x 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. x 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. x Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x 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 x Slow in/out of slips and while tripping to keep swab and surge pressures low x Ensure shakers are functioning properly. Check for holes in screens on connections. x 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. x 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). x Perform gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. x Be prepared for gas hydrates. In MPU they have been encountered typically around 2,100- 2,400’ TVD (just below permafrost). Be prepared for hydrates: x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales Page 14 Milne Point Unit I-29 SB Producer Drilling Procedure x 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. x 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. x Take MWD and GWD surveys every stand until magnetic interference cleans up. After MWD surveys show clean magnetics, only take MWD surveys. x Surface Hole AC: x There are no wells with a clearance factor of <1.0 11.4 12-1/4” hole mud program summary: x 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 x PVT System: 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. x 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. x 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. x 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. x 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). Page 15 Milne Point Unit I-29 SB Producer Drilling Procedure System Type:8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F System Formulation: Gel + FW spud mud Product Concentration Fresh Water soda Ash AQUAGEL caustic soda BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G 0.905 bbl 0.5 ppb 15 - 20 ppb 0.1 ppb (8.5 – 9.0 pH) as needed as required for 8.8 – 9.2 ppg if required for <10 FL 0.1 ppb 11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem sweeps and drop viscosity. 11.6 RIH to bottom, proceed to BROOH to HWDP x Pump at full drill rate (400-600 gpm), and maximize rotation. x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 16 Milne Point Unit I-29 SB Producer Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x R/U of CRT if hole conditions require. x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8.75” on the location prior to running. x Top 2,000’ of casing 47# drift 8.525” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings 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 x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment and stage tool components. This end up. Bypass Baffle 2500' Page 17 Milne Point Unit I-29 SB Producer Drilling Procedure 12.5 Float equipment and Stage tool equipment drawings: Page 18 Milne Point Unit I-29 SB Producer Drilling Procedure 12.6 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every joint to ~ 1000’ MD from shoe x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu) x Verify depth of lowest Ugnu water sand for isolation with Geologist x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x 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). x Install centralizers over couplings on 5 joints below and 5 joints above stage tool. x Do not place tongs on ES cementer, this can cause damaged to the tool. x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. 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 9-5/8” 47# L-80 TXP MUT: Casing OD Minimum Optimum Maximum 9-5/8”21,440 ft-lbs 2,3820 ft-lbs 26,200 ft-lbs Page 19 Milne Point Unit I-29 SB Producer Drilling Procedure Page 20 Milne Point Unit I-29 SB Producer Drilling Procedure 12.8 Continue running 9-5/8” surface casing x Centralizers: 1 centralizer every 3rd joint to 200’ from surface x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 The last 2,000’ of 9-5/8” will be 47#, from 2,000’ to Surface x Ensure drifted to 8.525” 2,500' Page 21 Milne Point Unit I-29 SB Producer Drilling Procedure 12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.11 Slow in and out of slips. 12.12 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. 12.13 Lower casing to setting depth. Confirm measurements. 12.14 Have slips staged in cellar, along with necessary equipment for the operation. 12.15 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 22 Milne Point Unit I-29 SB Producer Drilling Procedure 13.0 Cement 9-5/8” Surface Casing 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. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. x 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 x Review test reports and ensure pump times are acceptable. x 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: 395 sx 382 sx Page 23 Milne Point Unit I-29 SB Producer Drilling Procedure Cement Slurry Design (1st Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 2,500’ x 0.0732 bpf + (5,588’-120’-2,500) x .0758 bpf = 417.2 bbls 80 bbls of tuned spacer to be left behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±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 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. Lead Slurry Tail Slurry Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk 5,708' MD Page 24 Milne Point Unit I-29 SB Producer Drilling Procedure 13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 25 Milne Point Unit I-29 SB Producer Drilling Procedure Second Stage Surface Cement Job: 13.18 Prepare for the 2 nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety meeting. x Past wells have seen pressure increase while circulating through stage tool after reduced rate 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2 nd stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): 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. Lead Slurry Tail Slurry System Permafrost L G Density 10.7 lb/gal 15.8 lb/gal Yield 4.41 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk 437 sx 270 sx Page 26 Milne Point Unit I-29 SB Producer Drilling Procedure 13.26 Displacement calculation: 2500’ x 0.0732 bpf = 183.0 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 1,000 – 1,500 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: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x 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 nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 14.0 ND Diverter, NU BOPE, & Test 14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool. 14.2 NU 13-5/8” x 5M BOP as follows: Page 27 Milne Point Unit I-29 SB Producer Drilling Procedure x 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 x Double gate ram should be dressed with 2-7/8” x 5-1/2” VBRs in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 2-7/8” x 5-1/2” VBRs or 5” solid body rams x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 RU MPD RCD and related equipment 14.4 Run 5” BOP test plug 14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Test with 5” test joint and test VBR’s with 3-1/2” test joint x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.6 RD BOP test equipment 14.7 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.8 Mix 8.9 ppg Baradrill-N fluid for production hole. 14.9 Set wearbushing in wellhead. 14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.11 Ensure 5” liners in mud pumps. Page 28 Milne Point Unit I-29 SB Producer Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM) 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 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 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 casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH and LD cleanout BHA 15.9 PU 8-1/2” directional BHA. x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5” 19.5# S-135 NC50. x Run a ported float in the production hole section. Schrader Bluff Bit Jetting Guidelines Formation Jetting TFA NB 6 x 14 0.902 OA 6 x 13 0.778 OB 6 x 13 0.778 Casing test and FIT digital data to AOGCC. Page 29 Milne Point Unit I-29 SB Producer Drilling Procedure 15.10 8-1/2” hole section mud program summary: x 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. x 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. x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning x Run the centrifuge continuously while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x 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 Baradrill-N drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPH T Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 System Formulation: Product Concentration Water KCL KOH N-VIS DEXTRID LT BARACARB 5 BARACARB 25 BARACARB 50 BARACOR 700 BARASCAV D X-CIDE 207 0.955 bbl 11 ppb 0.1 ppb 1.0 – 1.5 ppb 5 ppb 4 ppb 4 ppb 2 ppb 1.0 ppb 0.5 ppb 0.015 ppb Page 30 Milne Point Unit I-29 SB Producer Drilling Procedure 15.11 TIH with 8-1/2” directional assembly to bottom 15.12 Install MPD RCD 15.13 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid 15.14 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM x RPM: 120+ x 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. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x 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. x Use ADR to stay in section. Reservoir plan is to stay in OA sand. x 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. x Target ROP is as fast as we can clean the hole without having to backream connections x Schrader Bluff OA Concretions: 4-6% Historically x MPD will be utilized to monitor pressure build up on connections. x 8-1/2” Lateral A/C: x I-19L1 has a clearance factor of 0.161. I-19L1 is a reservoir abandoned leg (abandoned 4/17/2020 via coil cement job) from a Schrader well. There is no HSE risk due to a collision. x J-08 has a clearance factor of 0.243. J-08 was abandoned as part of the J-08A sidetrack in 1999. There is no HSE risk associated with a collision. x J-08A has a clearance factor of 0.886. J-08A is a Schrader Bluff producer that has been shut-in since 2017. There is no HSE risk due to a collision. 15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. Page 31 Milne Point Unit I-29 SB Producer Drilling Procedure x Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. x 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. x Attempt to lowside in a fast drilling interval where the wellbore is headed up. x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes. x 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 x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum 15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. 15.18 Displace 1.5 OH + liner volume with viscosified brine. x Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 RPM reading) - KCl: 7.1ppb for 2% NaCl: 60.9ppg for 9.4ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42ppb Flo-Vis Plus: 1.25ppb x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. Page 32 Milne Point Unit I-29 SB Producer Drilling Procedure 15.15 Monitor the returned fluids carefully while displacing to brine. After 1 (or more if needed) BU, Perform production screen test (PST). The brine has been properly conditioned when it will pass the production screen test (x3 350 ml samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure 15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe x Circulate at full drill rate (less if losses are seen, 350 GPM minimum). x Rotate at maximum RPM that can be sustained. x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x If backreaming operations are commenced, continue backreaming to the shoe 15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary. x 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 x If necessary, increase MW at shoe for any higher than expected pressure seen x Ensure fluid coming out of hole has passed a PST at the possum belly 15.23 POOH and LD BHA. 15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, 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 33 Milne Point Unit I-29 SB Producer Drilling Procedure 16.0 Run 4-1/2” Screened Liner 16.1 Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2” screened liner, the following well control response procedure will be followed: x 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” Predrilled liner. x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW. x Proceed with well kill operations. 16.2 R/U 4-1/2” liner running equipment. x Ensure 4-1/2” 13.5# Hydril 625 x NC50 crossover is on rig floor and M/U to FOSV. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.3 Run 4-1/2” screened production liner x 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 screens x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x Fill 4-½” liner with PST passed mud (to keep from plugging screens with solids) x Install screen joints as per the Running Order (From Completion Engineer post TD). o Do not place tongs or slips on screen joints o Screen placement ±40’ o The screen connection is 4-1/2” 13.5# Hydril 625 x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint outside of the surface shoe. This is to mitigate difference sticking risk while running inner string. x 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 Hydril 625 Torque OD Minimum Optimum Maximum 4-1/2 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Page 34 Milne Point Unit I-29 SB Producer Drilling Procedure Page 35 Milne Point Unit I-29 SB Producer Drilling Procedure 16.6. Ensure to run enough liner to provide for approx 150’ overlap inside 9-5/8” casing. Ensure hanger/pkr will not be set in a 9-5/8” connection. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection. 16.7. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.8. M/U Baker SLZXP liner top packer to 4-1/2” liner. 16.9. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.10. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. x Ensure 5” DP/HWDP has been drifted x There is no inner string planned to be run, as opposed to previous wells. The DP should auto fill. Monitor FL and if filling is required due to losses/surging. 16.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.15. Rig up to pump down the work string with the rig pumps. 16.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker 16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. Page 36 Milne Point Unit I-29 SB Producer Drilling Procedure 16.18. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool and not at the WIV) down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool. 16.20. Bleed DP pressure to 0 psi. 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. 16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.23. PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 16.24. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. Page 37 Milne Point Unit I-29 SB Producer Drilling Procedure 17.0 Run 7-5/8” Tieback 17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie-back space out calculation. Install 7-5/8” solid body casing rams in the upper ram cavity. RU testing equipment. PT to 250/3,000 psi with 7-5/8” test joint. RD testing equipment. 17.2 RU 7-5/8” casing handling equipment. x Ensure XO to DP made up to FOSV and ready on rig floor. x Rig up computer torque monitoring service. x String should stay full while running, RU fill up line and check as appropriate. 17.3 PU 7-5/8” tieback seal assembly and set in rotary table. Ensure 7-5/8” seal assembly has (4) 1” holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7- 5/8” annulus. 17.4 MU first joint of 7-5/8” to seal assy. 17.6 Run 7-5/8”, 29.7#, L-80 HYD 521 tieback tieback to position seal assembly two joints above tieback sleeve. Record PU and SO weights. 7-5/8”, 29.7#, L-80, Hyd 521 =Casing OD Torque (Min) Torque (Opt)Torque (Max)Torque (Operating) 7-5/8”8,400 ft-lbs 10,100 ft-lbs 14,700 ft-lbs 53,000 ft-lbs Page 38 Milne Point Unit I-29 SB Producer Drilling Procedure Page 39 Milne Point Unit I-29 SB Producer Drilling Procedure 17.7 MU 7-5/8” to DP crossover. 17.8 MU stand of DP to string, and MU top drive. 17.9 Break circulation at 1 BPM and begin lowering string. 17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off pressure. Leave standpipe bleed off valve open. 17.11 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO- GO DEPTH”. 17.12 PU string & remove unnecessary 7-5/8” joints. 17.13 Space out with pups as needed to leave the no-go 1 ft above fully no-go position when the casing hanger is landed. Ensure one full joint is below the casing hanger. 17.14 PU and MU the 7-5/8” casing hanger. 17.15 Ensure circulation is possible through 7-5/8” string. 17.16 RU and circulation corrosion inhibited brine in the 9-5/8” x 7-5/8” annulus. 17.17 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface in 9-5/8” x 7-5/8” annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent collapse of the 7-5/8” casing (verify collapse pressure of 7-5/8” tieback seal assembly). 17.18 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning report. 17.19 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes. 17.20 RD casing running tools. 17.21 PT 9-5/8” x 7-5/8” annulus to 1,000 psi for 30 minutes charted. 1,500 psi per AOGCC Page 40 Milne Point Unit I-29 SB Producer Drilling Procedure 18.0 Run Upper Completion – ESP 18.1 RU spooler with ESP power cable and heat trace. 18.2 Verify the ESP components as per Centrilift. Verify that the length of the motor lead flat cable will place the splice between the discharge head and the 10’ handling pup collar. A Centrilift rep shall be on the rig floor at all times during the running of the ESP. 18.3 Makeup new ESP assembly with new motor lead extension, seal section and motor. 18.4 Run the 3-1/2” ESP Completion as noted below. The completion includes two 3/8” capillary tube from surface to the centralizer on the motor. The capillary tube will be secured to the tubing with Cannon clamps. Function test the capillary tube every ~2,000’ by pumping ~2 gallons of hydraulic oil through the check valves. Record the pressure at each testing point 18.5 M/U ESP assy and RIH to setting depth. Confirm tally with Operations Engineer i. Ensure appropriate well control crossovers on rig floor and ready. ii. Monitor displacement from wellbore while RIH. x Centrilift ESP Assembly with bottom of assembly @ predetermined depth x 10’ 3-1/2” 9.3#, L-80 Pup Joint x 1 joint 3-1/2” 9.3#, L-80 EUE 8rd tubing x 3-1/2” “XN” nipple (2.813” packing bore / 2.75” No-Go ID) x 3 joints 3-1/2” 9.3#, L-80 EUE 8rd tubing x 10’ 3-1/2” 9.3#, L-80 Pup Joint x GLM 3-1/2” x 1” GLM w/ dummy installed x 10’ 3-1/2” 9.3#, L-80 Pup Joint x 3-1/2” 9.3#, L-80 EUE 8rd tubing x 10’ 3-1/2” 9.3#, L-80 Pup Joint x GLM 3-1/2” x 1” w/ SO @ ~140’ MD x 10’ 3-1/2” 9.3#, L-80 Pup Joint x 3 joints 3-1/2” 9.3#, L-80 EUE 8rd tubing x Tubing Hanger o Check the conductivity of electric cable every 2,000’ and every new splice while running in hole. o Use Cannon clamps on every joint to secure the capillary tube. Page 41 Milne Point Unit I-29 SB Producer Drilling Procedure o The make up torque values for 3-1/2” L-80 9.3# EUE 8rd tubing are: Minimum: 2350 ft-lb, Optimum: 3100 ft-lb, and maximum: 3910 ft-lb. o The 3-1/2” L-80 9.3# EUE 8rd tubing performance properties are: Body Yield: 159,000#, Burst: 10,160 psi, Collapse: 10, psi. 18.6 Fill tubing while splicing cable, mid-cable splices and tubing hanger splices. After tubing is full, break circulation by pumping 10 bbls down the tubing to clear any debris. 18.7 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 18.8 MU tubing hanger and landing joint. Splice ESP power cable and terminate control lines. Test cable. Install a brass-shipping cap on the ESP penetrator. 18.9 Land tubing with extreme care to minimize damaging the ESP penetrator, pigtail and alignment pin. 18.10 RILDS and test hanger. LD landing joint. 18.11 Install BPV and N/D BOP. 18.12 N/U tree / adapter and tree. Test tubing hanger void to 500 psi low / 5000 psi high. Terminate the cap strings. 18.13 Circulate diesel freeze protection down 3-1/2” x 7-5/8” annulus (Volume should equal capacity of tubing to 2500’ + tubing annulus to 2500’). Connect IA to tree and allow diesel freeze protect to “U- tube” into position. Note – this may be done post-rig. 18.14 Pull BPV. Set TWC. Test tree to 250 psi low / 5000 psi high. Pull TWC. Set BPV. 18.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 18.16 RDMO Innovation Page 42 Milne Point Unit I-29 SB Producer Drilling Procedure 19.0 Innovation Rig Diverter Schematic Page 43 Milne Point Unit I-29 SB Producer Drilling Procedure 20.0 Innovation Rig BOP Schematic Page 44 Milne Point Unit I-29 SB Producer Drilling Procedure 21.0 Wellhead Schematic Page 45 Milne Point Unit I-29 SB Producer Drilling Procedure 22.0 Days Vs Depth Page 46 Milne Point Unit I-29 SB Producer Drilling Procedure 23.0 Formation Tops & Information Page 47 Milne Point Unit I-29 SB Producer Drilling Procedure Page 48 Milne Point Unit I-29 SB Producer Drilling Procedure 24.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hydrates are generally not seen on I-pad. Remember that hydrate gas behaves 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. 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 ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Well Specific A/C: x There are no wells with a clearance factor of <1.0 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. Page 49 Milne Point Unit I-29 SB Producer Drilling Procedure H2S: Treat every hole section as though it has the potential for H2S. MPU I-pad is not known for H2S. I- 04A had 36 ppm in a 2012 sample. The next highest sample on the pad was 3.2 ppm on I-15 in 2009. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 50 Milne Point Unit I-29 SB Producer Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There are no planned fault crossings for I-29. H2S: Treat every hole section as though it has the potential for H2S. MPU I-pad is not known for H2S. I- 04A had 36 ppm in a 2012 sample. The next highest sample on the pad was 3.2 ppm on I-15 in 2009. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. 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. Well Specific AC: x I-19L1 has a clearance factor of 0.161. I-19L1 is a reservoir abandoned leg (abandoned 4/17/2020 via coil cement job) from a Schrader well. There is no HSE risk due to a collision. x J-08 has a clearance factor of 0.243. J-08 was abandoned as part of the J-08A sidetrack in 1999. There is no HSE risk associated with a collision. x J-08A has a clearance factor of 0.886. J-08A is a Schrader Bluff producer that has been shut-in since 2017. There is no HSE risk due to a collision. Page 51 Milne Point Unit I-29 SB Producer Drilling Procedure 25.0 Innovation Rig Layout Page 52 Milne Point Unit I-29 SB Producer Drilling Procedure 26.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 53 Milne Point Unit I-29 SB Producer Drilling Procedure 27.0 Innovation Rig Choke Manifold Schematic Page 54 Milne Point Unit I-29 SB Producer Drilling Procedure 28.0 Casing Design Page 55 Milne Point Unit I-29 SB Producer Drilling Procedure 29.0 8-1/2” Hole Section MASP Page 56 Milne Point Unit I-29 SB Producer Drilling Procedure 30.0 Spider Plot (NAD 27) (Governmental Sections) Page 57 Milne Point Unit I-29 SB Producer Drilling Procedure 31.0 Surface Plat (As Built) (NAD 27) 6WDQGDUG3URSRVDO5HSRUW $XJXVW 3ODQ038,ZS +LOFRUS$ODVND//& 0LOQH3RLQW 03W,3DG 3ODQ038, 038, 0650130019502600325039004550True Vertical Depth (1300 usft/in)-650 0 650 1300 1950 2600 3250 3900 4550 5200 5850 6500 7150 7800 8450 9100 9750 10400 11050 11700Vertical Section at 10.46° (1300 usft/in)MPI-Pea Ridge wp02 CP1MPI-Pea Ridge wp02 HeelMPI-Pea Ridge wp02 Toe9 5/8" x 12 1/4"4 1/2" x 8 1/2"50010001500200025003000350040004500500055006000 6500 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 140001450015000155001600016119MPU I-29 wp03Start Dir 3º/100' : 250' MD, 250'TVDStart Dir 4º/100' : 550' MD, 548.77'TVDEnd Dir : 1100' MD, 1067.14' TVDStart Dir 4º/100' : 1500' MD, 1423.23'TVDStart Dir 4º/100' : 1500' MD, 1423.23'TVDEnd Dir : 2149.58' MD, 1968.7' TVDStart Dir 4º/100' : 3256.38' MD, 2810.25'TVDEnd Dir : 5408.21' MD, 3943.74' TVDStart Dir 3º/100' : 5708.21' MD, 3969.89'TVDEnd Dir : 5862.71' MD, 3977.12' TVDStart Dir 3º/100' : 9010.06' MD, 3997.31'TVDEnd Dir : 9194.12' MD, 3999.89' TVDTotal Depth : 16118.98' MD, 4149.89' TVDSV3BPRFUG3 CoalLA3LA2LA1UG_MAUG MBUG MDUG MESB NASB NBSB NCSB NESB OAHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU I-2933.40+N/-S +E/-W NorthingEastingLatitudeLongitude0.00 0.006009442.87 551717.4270° 26' 11.5577307 N 149° 34' 42.0214187 WSURVEY PROGRAMDate: 2020-03-27T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool26.20 700.00 MPU I-29 wp03 (MPU I-29) 3_Gyro-GC_Csg700.00 5708.07 MPU I-29 wp03 (MPU I-29) 3_MWD+IFR2+MS+Sag5708.07 16118.98 MPU I-29 wp03 (MPU I-29) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1602.19 1542.29 1703.18 SV31779.12 1719.22 1911.41 BPRF2649.74 2589.84 3045.28 UG3 Coal3268.03 3208.13 3871.13 LA33293.41 3233.51 3907.27 LA23308.93 3249.03 3929.56 LA13493.54 3433.64 4209.73 UG_MA3496.11 3436.21 4213.88 UG MB3553.35 3493.45 4308.75 UG MD3667.06 3607.16 4515.13 UG ME3744.07 3684.17 4675.68 SB NA3763.48 3703.58 4720.16 SB NB3782.14 3722.24 4764.93 SB NC3810.81 3750.91 4838.42 SB NE3890.73 3830.83 5094.44 SB OAREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-29, True NorthVertical (TVD) Reference:MPU I-29 As-built RKB @ 59.90usft (Original Well Elev)Measured Depth Reference:MPU I-29 As-built RKB @ 59.90usft (Original Well Elev)Calculation Method:Minimum CurvatureProject:Milne PointSite:M Pt I PadWell:Plan: MPU I-29Wellbore:MPU I-29Design:MPU I-29 wp03CASING DETAILSTVD TVDSS MD SizeName3969.88 3909.98 5708.07 9-5/8 9 5/8" x 12 1/4"4149.75 4089.85 16118.98 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 26.20 0.00 0.00 26.20 0.00 0.00 0.00 0.00 0.002 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 250' MD, 250'TVD3 550.00 9.00 200.00 548.77 -22.10 -8.04 3.00 200.00 -23.19 Start Dir 4º/100' : 550' MD, 548.77'TVD4 900.00 22.24 218.63 885.26 -99.96 -59.02 4.00 30.00 -109.015 1100.00 27.10 233.98 1067.14 -156.41 -119.60 4.00 60.00 -175.52 End Dir : 1100' MD, 1067.14' TVD6 1500.00 27.10 233.98 1423.23 -263.57 -266.96 0.00 0.00 -307.66 Start Dir 4º/100' : 1500' MD, 1423.23'TVD7 2149.58 40.51 275.35 1968.70 -332.11 -602.43 4.00 78.47 -435.96 End Dir : 2149.58' MD, 1968.7' TVD8 3256.38 40.51 275.35 2810.25 -265.13 -1318.19 0.00 0.00 -500.04 Start Dir 4º/100' : 3256.38' MD, 2810.25'TVD9 5408.21 85.00 5.15 3943.74 1142.77 -2063.51 4.00 93.10 749.16 End Dir : 5408.21' MD, 3943.74' TVD10 5708.21 85.00 5.15 3969.89 1440.43 -2036.68 0.00 0.00 1046.73 MPI-Pea Ridge wp02 Heel Start Dir 3º/100' : 5708.21' MD, 3969.89'TVD11 5862.71 89.63 5.01 3977.12 1594.10 -2023.02 3.00 -1.77 1200.33 End Dir : 5862.71' MD, 3977.12' TVD12 9010.06 89.63 5.01 3997.31 4729.38 -1748.33 0.00 0.00 4333.38 Start Dir 3º/100' : 9010.06' MD, 3997.31'TVD13 9194.12 88.76 10.46 3999.89 4911.68 -1723.57 3.00 99.12 4517.14 MPI-Pea Ridge wp02 CP1End Dir : 9194.12' MD, 3999.89' TVD14 9262.55 88.76 10.46 4001.37 4978.95 -1711.15 0.00 0.00 4585.5515 16118.98 88.76 10.46 4149.89 11719.78 -466.21 0.00 0.00 11440.38 MPI-Pea Ridge wp02 Toe Total Depth : 16118.98' MD, 4149.89' TVD -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 South(-)/North(+) (1500 usft/in)-4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 West(-)/East(+) (1500 usft/in) MPI-Pea Ridge wp02 Toe MPI-Pea Ridge wp02 Heel MPI-Pea Ridge wp02 CP1 9 5/8" x 12 1/4" 4 1/2" x 8 1/2" 2505007501 0 0 0 1 2 5 01 50017502000225025002750300032503 5 0 0 3 7 5 0 4000 4150 MPU I-29 wp03 Start Dir 3º/100' : 250' MD, 250'TVD Start Dir 4º/100' : 550' MD, 548.77'TVD End Dir : 1100' MD, 1067.14' TVD Start Dir 4º/100' : 1500' MD, 1423.23'TVD Start Dir 4º/100' : 1500' MD, 1423.23'TVD End Dir : 2149.58' MD, 1968.7' TVD Start Dir 4º/100' : 3256.38' MD, 2810.25'TVD End Dir : 5408.21' MD, 3943.74' TVD Start Dir 3º/100' : 5708.21' MD, 3969.89'TVD End Dir : 5862.71' MD, 3977.12' TVD Start Dir 3º/100' : 9010.06' MD, 3997.31'TVD End Dir : 9194.12' MD, 3999.89' TVD Total Depth : 16118.98' MD, 4149.89' TVD CASING DETAILS TVD TVDSS MD Size Name 3969.88 3909.98 5708.07 9-5/8 9 5/8" x 12 1/4" 4149.75 4089.85 16118.98 4-1/2 4 1/2" x 8 1/2" Project: Milne Point Site: M Pt I Pad Well: Plan: MPU I-29 Wellbore: MPU I-29 Plan: MPU I-29 wp03 WELL DETAILS: Plan: MPU I-29 33.40 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 6009442.87 551717.42 70° 26' 11.5577307 N 149° 34' 42.0214187 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU I-29, True North Vertical (TVD) Reference: MPU I-29 As-built RKB @ 59.90usft (Original Well Elev) Measured Depth Reference:MPU I-29 As-built RKB @ 59.90usft (Original Well Elev) Calculation Method:Minimum Curvature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0.001.002.003.004.00Separation Factor0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 5850 6175Measured Depth (650 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU I-29 NAD 1927 (NADCON CONUS)Alaska Zone 0433.40+N/-S+E/-W NorthingEastingLatitudeLongitude0.000.006009442.87551717.4270° 26' 11.5577307 N149° 34' 42.0214187 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-29, True NorthVertical (TVD) Reference:MPU I-29 As-built RKB @ 59.90usft (Original Well Elev)Measured Depth Reference:MPU I-29 As-built RKB @ 59.90usft (Original Well Elev)Calculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2020-03-27T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.20 700.00 MPU I-29 wp03 (MPU I-29) 3_Gyro-GC_Csg700.00 5708.07 MPU I-29 wp03 (MPU I-29) 3_MWD+IFR2+MS+Sag5708.07 16118.98 MPU I-29 wp03 (MPU I-29) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 5850 6175Measured Depth (650 usft/in)MPI-09MPI-10MPI-01MPI-18MPU I-23i wp03MPU I-21iMPI-02MPI-15MPU I-30i wp04MPU I-35iMPI-16MPU I-36MPI-17MPU I-27MPU I-28iMPU I-22 wp03MPU I-22 wp03NO GLOBAL FILTER: Using user defined selection & filtering criteria26.20 To 16118.98Project: Milne PointSite: M Pt I PadWell: Plan: MPU I-29Wellbore: MPU I-29Plan: MPU I-29 wp03Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name3969.88 3909.98 5708.07 9-5/8 9 5/8" x 12 1/4"4149.75 4089.85 16118.98 4-1/2 4 1/2" x 8 1/2" &OHDUDQFH6XPPDU\$QWLFROOLVLRQ5HSRUW$XJXVW+LOFRUS$ODVND//&0LOQH3RLQW03W,3DG3ODQ038,038,038,ZS5HIHUHQFH'HVLJQ03W,3DG3ODQ038,038,038,ZS&ORVHVW$SSURDFK'3UR[LPLW\6FDQRQ&XUUHQW6XUYH\'DWD+LJKVLGH5HIHUHQFH:HOO&RRUGLQDWHV1( 1 :'DWXP+HLJKW038,$VEXLOW5.%#XVIW2ULJLQDO:HOO(OHY6FDQ5DQJHWRXVIW0HDVXUHG'HSWK*HRGHWLF6FDOH)DFWRU$SSOLHG9HUVLRQ%XLOG(6FDQ5DGLXVLV8QOLPLWHG&OHDUDQFH)DFWRUFXWRIILV8QOLPLWHG0D[(OOLSVH6HSDUDWLRQLVXVIW12*/2%$/),/7(58VLQJXVHUGHILQHGVHOHFWLRQ ILOWHULQJFULWHULD6FDQ7\SH6FDQ7\SH 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B0:',)5066DJ(OOLSVHHUURUWHUPVDUHFRUUHODWHGDFURVVVXUYH\WRROWLHRQSRLQWV6HSDUDWLRQLVWKHDFWXDOGLVWDQFHEHWZHHQHOOLSVRLGV&DOFXODWHGHOOLSVHVLQFRUSRUDWHVXUIDFHHUURUV&OHDUDQFH)DFWRU 'LVWDQFH%HWZHHQ3URILOHV'LVWDQFH%HWZHHQ3URILOHV(OOLSVH6HSDUDWLRQ'LVWDQFH%HWZHHQFHQWUHVLVWKHVWUDLJKWOLQHGLVWDQFHEHWZHHQZHOOERUHFHQWUHV$OOVWDWLRQFRRUGLQDWHVZHUHFDOFXODWHGXVLQJWKH0LQLPXP&XUYDWXUHPHWKRG$XJXVW &203$663DJHRI 0.001.002.003.004.00Separation Factor6050 6600 7150 7700 8250 8800 9350 9900 10450 11000 11550 12100 12650 13200 13750 14300 14850 15400 15950Measured Depth (1100 usft/in)MPI-19L1MPJ-08AMPJ-08MPU I-37iMPU I-37PB1No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU I-29 NAD 1927 (NADCON CONUS)Alaska Zone 0433.40+N/-S +E/-W Northing EastingLatitude Longitude0.000.006009442.87551717.4270° 26' 11.5577307 N149° 34' 42.0214187 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-29, True NorthVertical (TVD) Reference:MPU I-29 As-built RKB @ 59.90usft (Original Well Elev)Measured Depth Reference:MPU I-29 As-built RKB @ 59.90usft (Original Well Elev)Calculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2020-03-27T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.20 700.00 MPU I-29 wp03 (MPU I-29) 3_Gyro-GC_Csg700.00 5708.07 MPU I-29 wp03 (MPU I-29) 3_MWD+IFR2+MS+Sag5708.07 16118.98 MPU I-29 wp03 (MPU I-29) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)6050 6600 7150 7700 8250 8800 9350 9900 10450 11000 11550 12100 12650 13200 13750 14300 14850 15400 15950Measured Depth (1100 usft/in)MPJ-08MPJ-08NO GLOBAL FILTER: Using user defined selection & filtering criteria26.20 To 16118.98Project: Milne PointSite: M Pt I PadWell: Plan: MPU I-29Wellbore: MPU I-29Plan: MPU I-29 wp03CASING DETAILSTVD TVDSS MD Size Name3969.88 3909.98 5708.07 9-5/8 9 5/8" x 12 1/4"4149.75 4089.85 16118.98 4-1/2 4 1/2" x 8 1/2"Ladder / S.F. Plots2 of 2 Revised 2/2015 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: ____________________________ POOL: ______________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as 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' sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such water well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (_______________________________) in the attached application, the following well logs are also required for this 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. 221-067 MPU I-29 Milne Point Milne Point, Schrader Bluff Oil :(//3(50,7&+(&./,67&RPSDQ\+LOFRUS$ODVND//&:HOO1DPH0,/1(3781,7,,QLWLDO&ODVV7\SH'(93(1'*HR$UHD8QLW2Q2II6KRUH2Q3URJUDP'(9)LHOG 3RRO:HOOERUHVHJ$QQXODU'LVSRVDO37'0,/1(32,176&+5$'(5%/))2,/1$ 3HUPLWIHHDWWDFKHG<HV 6XUIDFH/RFDWLRQOLHVZLWKLQ$'/7RS3URGXFWLYH,QWHUYDOOLHVLQ$'/ /HDVHQXPEHUDSSURSULDWH<HV SURGXFWLYHLQWHUYDOFURVVHVDJDLQLQWR$'/7'OLHVLQ$'/ 8QLTXHZHOOQDPHDQGQXPEHU<HV 0LOQH3RLQW6FKUDGHU%OXII2LO3RROJRYHUQHGE\&2DPHQGHGE\&2 :HOOORFDWHGLQDGHILQHGSRRO<HV &2VSHFLILHV³7KHUHDUHQRUHVWULFWLRQVDVWRZHOOVSDFLQJH[FHSWWKDWQRSD\VKDOO :HOOORFDWHGSURSHUGLVWDQFHIURPGULOOLQJXQLWERXQGDU\<HV EHRSHQHGLQDZHOOFORVHUWKDQIHHWIURPWKHH[WHULRUERXQGDU\RIWKHDIIHFWHGDUHD´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dts8/31/2021JLC 8/31/2021