The URL can be used to link to this page

Home My WebLink About224-109Alaska 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: Prudhoe Bay Field, Prudhoe Oil Pool, PBU 13-26A Hilcorp Alaska, LLC Permit to Drill Number: 224-109 Surface Location: 1872' FSL, 1485' FEL, Sec 14, T10N, R14E, UM, AK Bottomhole Location: 718' FSL, 649' FWL, Sec 23, T10N, R14E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 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, Jessie L. Chmielowski Commissioner DATED this 14th day of August 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.14 13:11:22 -08'00' Drilling Manager 08/07/24 Monty M Myers By Grace Christianson at 3:24 pm, Aug 07, 2024 A.Dewhurst 08AUG24 224-109 50-029-20746-01-00 DSR-8/12/24 * BOPE test to 3500 psi. Annular to 2500 psi. * Casing tests and FIT(s) digital data to AOGCC upon completion of FIT. MGR07AUG2024*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.14 13:11:35 -08'00' 08/14/24 08/14/24 RBDMS JSB 081524 Prudhoe Bay Unit PBU 13-26A Permit to Drill Application Version 2 8/6/2024 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 Current & Proposed Wellbore Schematic................................................................................ 6 7.0 Drilling / Completion Summary ............................................................................................... 9 8.0 Mandatory Regulatory Compliance / Notifications ............................................................... 10 9.0 MIRU & Test BOPE ............................................................................................................... 13 10.0 Pull 4-1/2” Tubing, Set Whipstock, Mill Window .................................................................. 15 11.0 Drill 8-1/2” x 9-7/8” Hole Section .......................................................................................... 19 12.0 Run & Cement 7” Intermediate Casing ................................................................................. 23 13.0 Drill 6-1/8” Hole Section ......................................................................................................... 27 14.0 Run 4-1/2” Liner ..................................................................................................................... 30 15.0 Run Upper Completion/ Post Rig Work ................................................................................ 34 16.0 Innovation Rig BOP Schematic .............................................................................................. 36 17.0 Wellhead Drawing .................................................................................................................. 37 18.0 Tubular Data Sheets ............................................................................................................... 38 19.0 Days Vs Depth ......................................................................................................................... 41 20.0 Formation Tops & Information.............................................................................................. 42 21.0 Anticipated Drilling Hazards ................................................................................................. 44 22.0 Innovation Rig Layout ............................................................................................................ 47 23.0 FIT Procedure ......................................................................................................................... 48 24.0 Innovation Rig Choke Manifold Schematic ........................................................................... 49 25.0 Casing Design .......................................................................................................................... 50 26.0 MASP ...................................................................................................................................... 51 27.0 Spider Plot (NAD 27) (Governmental Sections) ..................................................................... 53 28.0 Surface Plat (As-Built) (NAD 27) ........................................................................................... 54 Page 2 Prudhoe Bay East 13-26A Producer Drilling Procedure 1.0 Well Summary Well 13-26A Pad PBE DS13 Planned Completion Type 4-1/2” Tubing Target Reservoir(s) Sag River Planned Well TD, MD / TVD 19,132’ MD / 9,013’ TVD PBTD, MD / TVD 19,122’ MD / 9,013’ TVD Surface Location (Governmental) 1873' FSL, 1485' FEL, Sec 14, T10N, R14E, UM, AK Surface Location (NAD 27) X= 685733.45, Y=5931902.5 Top of Productive Horizon (Governmental)2291' FNL, 991' FEL, Sec 15, T10N, R14E, UM, AK TPH Location (NAD 27) X= 680,920.5, Y=5925394.2 BHL (Governmental) 718' FSL, 649' FWL, Sec 23, T10N, R14E, UM, AK BHL (NAD 27) X= 682753.18, Y=5925394 AFE Drilling Days 47 AFE Completion Days 3 Maximum Anticipated Surface Pressure (intermediate) 2373 psi Maximum Anticipated Surface Pressure (production) 2647 psi Maximum Anticipated Pressure (Downhole/Reservoir Intermediate) 3227 psig Maximum Anticipated Pressure (Downhole/Reservoir Production) 3561 psig Work String 5” 19.5# S-135 NC 50 & 4” 14# XT39 Innovation KB Elevation above MSL: 26.5 ft + 47.29 ft = 73.79 ft Cellar Box Elevation above MSL: 47.29 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Prudhoe Bay East 13-26A Producer Drilling Procedure 2.0 Management of Change Information Page 4 Prudhoe Bay East 13-26A 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) 8-1/2” x 9-7/8”7” 6.184 6.125 7.644 29 L-80 VAMTOP 8160 7030 676 6-1/8 4-1/2” 3.958 3.833 5.2 12.6 L-80 H563 8,430 7,500 288 Tubing 4-1/2” 3.958 3.833 5 12.6 13Cr VAMTOP 8,430 7,500 288 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) Intermediate 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 Production 4”3.34 2.688 4.875 14 S-135 XT-39 17,700 21,200 553klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Prudhoe Bay East 13-26A Producer Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellView. 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 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 mmyers@hilcorp,com jengel@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 mmyers@hilcorp.com jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Contact List: Title Name Work Phone Email Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com Completion Engineer Jerry Lau 907.564.4280 Jerry.Lau@hilcorp.com Geologist Russ Edge 907.564.4780 Russell.Edge@hilcorp.com Reservoir Engineer Josh Wilcox 907.564.4331 Joshua.Wilcox@hilcorp.com EHS Manager Laura Green 907.777.8314 lagreen@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com Page 6 Prudhoe Bay East 13-26A Producer Drilling Procedure 6.0 Current & Proposed Wellbore Schematic Current: Page 7 Prudhoe Bay East 13-26A Producer Drilling Procedure Proposed Reservior P&A (Sundry 324-391): Page 8 Prudhoe Bay East 13-26A Producer Drilling Procedure Proposed: ID = 6.184" -mgr Page 9 Prudhoe Bay East 13-26A Producer Drilling Procedure 7.0 Drilling / Completion Summary PBE 13-26A is a sidetrack producer planned to be drilled in the Sag River sands. 13-26A is part of a multi- well program on DS13. The parent bore, 13-26, will be reservoir abandoned on a prior sundry (324-391). The directional plan is two hole section sidetrack. A 8-1/2” x 9-7/8” intermediate hole exiting the 9-5/8” casing at ~9000’ MD drilled into the top of the Sag River, with 7” long string ran and cemented. A 6-1/8” lateral will be drilled in the Sag River. A 4-1/2” cemented liner will be run in the open hole section, followed by 4-1/2” tubing. The Innovation Rig will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately August 20, 2024, pending rig schedule. Intermediate casing will be run to 10,845’ MD / 8815’TVD, and cemented 500’ above the Sag River All cuttings & mud generated during drilling operations will be hauled to one of two locations: Primary: Prudhoe G&I on Pad 4 General sequence of operations: 1. MIRU Innovation Rig to well site 2. N/U & Test 13-5/8” BOPE 3. Pull 4-1/2” Tubing 4. Set 9-5/8” Whipstock, mill 8-1/2” window & FIT 5. Drill 8-1/2” x 9-7/8” Intermediate hole to TD 6. Run and Cement 7” Casing 7. Drill 6-1/8” lateral to well TD 8. Run and cement 4-1/2” liner 9. Run Upper Completion 10. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Intermediate hole: No mud logging. Wellsite geologist. LWD: GR + Res, At Bit Gamma 2. Production Hole: No mud logging. Wellsite geologist. LWD: GR + Res + Azimuthal Res + Density + Neutron Page 10 Prudhoe Bay East 13-26A Producer Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that all drilling and completion operations comply with all applicable AOGCC regulations. Operations stated in this PTD application may be altered based on sound engineering judgement as wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from the AOGCC. 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 Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. x BOPs shall be tested at (2) week intervals during the drilling and completion of PBU 13-26A. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3,500 psi & subsequent tests of the BOP equipment will be to 250/3,500 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)”. Page 11 Prudhoe Bay East 13-26A Producer Drilling Procedure AOGCC Variance Requests: Hilcorp does not request any variances at this time. Page 12 Prudhoe Bay East 13-26A Producer Drilling Procedure Summary of Innovation BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 8-1/2” x 9-7/8” & 6-1/8” 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: 250/3500 Subsequent Tests: 250/3500 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 13 Prudhoe Bay East 13-26A Producer Drilling Procedure 9.0 MIRU & Test BOPE 9.1 13-26 is the parent well for this sidetrack. Ensure to review attached surface plat and make sure rig is over appropriate well. 9.2 13-26 reservoir abandonment has been completed pre rig on a separate sundry. 9.3 Ensure PTD, COAs, and drilling program are posted in the rig office and on the rig floor. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Rig mat footprint of rig. 9.6 MIRU Innovation. Ensure rig is centered over wellhead to prevent any wear to BOPE or wellhead. 9.7 Mud loggers WILL NOT be used on either hole section. 9.8 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. 9.9 Give AOGCC 24hr notice of BOPE test, for test witness opportunity 9.10 Install BPV, ND Tree, NU 13-5/8” x 5M BOP as follows: 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 4-1/2” x 7” 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. 9.11 RU MPD RCD and related equipment 9.12 Run 5” BOP test plug 9.13 Test BOP to 250/3,500 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Test with 5 & 5-1/2” test joints x Confirm test pressures with PTD x Ensure to monitor annulus valve pressure gauges to ensure no pressure is trapped underneath test plug Page 14 Prudhoe Bay East 13-26A Producer Drilling Procedure x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 9.14 RD BOP test equipment 9.15 Dump and clean mud pits, send spud mud to G&I pad for disposal. 9.16 Mix 9.5 ppg mud to be used wellwork operations 9.17 Set wearbushing in wellhead. 9.18 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. Page 15 Prudhoe Bay East 13-26A Producer Drilling Procedure 10.0 Pull 4-1/2” Tubing, Set Whipstock, Mill Window 10.1 Verify fluid type left in the well after plugging operations engineer and check for risk of trapped pressure. Lubricate BPV if risk of pressure exists. 10.2 RU and circulate out any diesel freeze protect and get even MW in and out 10.3 RU tubing handling equipment x Tubing is 4-1/2” 12.6# L-80 x Tubing cut depth: ~10,410’ MD, confirm with pre rig well work report 10.4 PU landing joint or spear and engage tubing hanger 10.5 Backout lock down screws 10.6 Pull tubing hanger with landing joint to the rig floor, have appropriate protectors ready. 10.7 If necessary, circulate at least 1.5x BU after pulling the hanger to the floor. If desired, circulate a soap sweep surface-to-surface to clean the tubing. 10.8 POOH laying down 4-1/2” tubing. RD tubing handling equipment 10.9 RD casing handling equipment 10.10 MU 9-5/8” casing scraper assembly and RIH to ~10,400, top of 4-1/2” cut 10.11 RU E-line, and RIH with CCL to whipstock setting depth t/ 9200 MD 10.12 RU casing testing equipment and PT 9-5/8” casing to 2500 psi for 30 min, chart test. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. x 9-5/8” Casing has been tested pre rig to 2500 psi for 30 minutes pre 4-1/2” cut March 2023. TxIA will be tested to 1000 psi after the cut. x Have 9-5/8” CIBP available if unable to achieve casing test 10.13 Whipstock Set Depth Information x Planned TOW: TBD based on CBL results, estimating TOW at 9,000’ MD +/- x WS should be set to avoid a collar while milling the window x Drilling Foreman, Whipstock hand and drilling engineer to agree on the set depth 10.14 MU 9-5/8” hydraulic anchor/mill/whipstock assembly as per WIS tally x MU HWDP, string magnets and float sub x Ensure magnets are in trough, under shakers and flow area to capture metal shavings circulated 10.15 Install MWD and orient. Rack back mill assembly suggest +200' past WS setting depth. -mgr Page 16 Prudhoe Bay East 13-26A Producer Drilling Procedure x Ensure a dedicated MWD is available for the orientation of the whipstock 10.16 Verify offset between WD, and the whipstock tray, witnessed by the Drilling Foreman, MWD/DD and WIS rep. Document and record offset in well file. 10.17 Slowly run in the hole as per WIS Rep. 10.18 Run in hole at 1 ½ to 2 minutes per stand, or per contractor rep. Ensure work string is stationary prior to setting the slips to avoid weakening the shear bolt and prematurely setting the anchor. 10.19 Shallow test MWD at first drill pipe fill up depth. 10.20 Stop at least 30-45’ above planned set depth, obtain survey with MWD. 10.21 Milling fluid will be 9.5 ppg mud 10.22 With the bottom of the whipstock 30 – 45’ above the set depth, work torque out of string, measure and record P/U and S/O weights. Obtain good survey to orient whipstock face. 10.23 Orient whipstock to desired direction by turning DP in ¼ round increments. P/U and S/O on DP to work all torque out after oriented. (Being careful not to set trip anchor). Target orientation is 45q LOHS – Consult with milling hand 10.24 Whipstock Orientation Diagram: Desired orientation of the whipstock face is 40L to 50L, target is 45 LOHS Hole Angle at window interval (@ 9,000’, 42.5° inc, 284° azi). Sidetrack tangent section is 35q inclination and 242q azimuth 10.25 Once whipstock is in desired orientation, set WS per WIS rep. 10.26 CBU and confirm 9.5 ppg MW in/out x Ensure Mud properties are sufficient for transporting metal cuttings 45L 50-40* range Page 17 Prudhoe Bay East 13-26A Producer Drilling Procedure x Visc: 40-60, YP: 18-20 10.27 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window as per whipstock contractor representative. Pump high visc sweeps as necessary. 10.28 If possible, install catch trays in shaker underflow chute to help catch metal cuttings. 10.29 Clean catch trays and ditch magnets frequently while milling window. 10.30 Mill window until the uppermost mill has passed across the entire tray. Dress and polish window as needed. 10.31 With upper mill at the end of the tray, drill ~ 20’ of new hole. 10.32 After window is milled but before POOH, shut down pumps and work milling assembly through window watching for drag. Dress and polish window as needed. After reaming, shut off pumps and rotary and dry drift window. 10.33 Circulate bottoms up until even MW in/out and hole is clean of metal shavings. Reduce mud properties for drilling. 10.34 RU and perform FIT PP and MPD pressure Conduct FIT to 11.5 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. x Historical uncemented casing exists on DS13 have seen between 12-12.7 FIT values x Est TOC on 9-5/8” is 9519’ MD x 11.5 ppg provides >25 bbls based on 10.3ppg MW, 7.05 ppg Pore Pressure (swab kick). x 13-26 parent bore 13-3/8” FIT was 12.5 ppb EMW at 2586’ TVD May 1982. xx Email digital data for casing test and FIT to AOGCC upon completion – Melvin.rixse@alaska.gov Page 18 Prudhoe Bay East 13-26A Producer Drilling Procedure 10.35 POOH & LD milling BHA. Gauge mills for wear. If undergauge, RIH with new mills to clean out window 10.36 PU stack washer and wash BOPE stack. Function all rams to clear any potential milling debris. Page 19 Prudhoe Bay East 13-26A Producer Drilling Procedure 11.0 Drill 8-1/2” x 9-7/8” Hole Section 11.1 P/U 8-1/2” Kickoff BHA x Motor, GWD, MWD 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 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill string will be 5” 19.5# S-135. 11.2 RIH with Motor BHA on 5” DP 11.3 Above Whipstock, orient BHA and trip through window WITH PUMPS OFF 11.4 Drill enough hole to bury complete RSS BHA, ensuring UR is 20-50’ outside Window 11.5 POOH, with pumps off through the window 11.6 LD Motor BHA 11.7 P/U 8-1/2” directional drilling assembly: x BHA will be an RSS with Underreamer x LWD: Gamma / Resistivity, At Bit Gamma 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 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 floats in the intermediate hole section. x Ensure Underreamer has nozzle plugged to be able to utilize MPD 11.8 TIH to above window 11.9 Trip through window with pumps off 11.10 Drop ball and activate 9-7/8” underreamer 11.11 Drill 8-1/2” x 9-7/8” hole section to 200’ above HRZ ~ 9678 MD. Confirm this depth with the Geologist and Drilling Engineer while drilling the well. x Hold a safety meeting with rig crews to discuss: x Well control procedures x Flow rates, hole cleaning, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Page 20 Prudhoe Bay East 13-26A Producer Drilling Procedure x Pump at 600-700 gpm with under reamer open for 200 ft/min AV. 120 rpm x MW 6rpm reading = 9-15 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 Adjust MW and viscosity as necessary to maintain hole stability, x Survey frequency each stand, with more surveys taken as needed x Intermediate Hole AC: x There are no wells with CF <1.0 in the intermediate hole section 11.12 8-1/2” 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. Depth Interval MW (ppg) Window –Top HRZ 9.5+ Top HRZ –TD 10.3+ 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. Ensure 6rpm reading is 1-1.5x of hole diameter, 8.5-12.75 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. 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 21 Prudhoe Bay East 13-26A Producer Drilling Procedure System Type:9.5 – 11.0 ppg 3% Kcl LSND Properties: Section Density Viscosity Plastic Viscosity Yield Point MBT pH LGS Intermediate 9.5 –11.0 40-53 20 - 40 15-25 <15 9-10 6% 11.13 Once at ~300’ MD above HRZ, CBU x3-4 at full rate and rpm 11.14 Perform a short trip to the surface casing shoe x BROOH if necessary 11.15 TIH to bottom 11.16 Install MPD RCD Element 11.17 Weight up to ~ 10.3ppg x MW to be finalized by Drilled ECDs, target ~ 11.5ppg EMW x Ensure black product has been added for shale stability 11.18 Drill 8-1/2” x 9-7/8” hole section to TD in top of the Sag River to be called by geologist, ~ 10,845’ MD as per TSAG Casing Point Plan x Flow Rate: 600-700 GPM x RPM: 120 x Utilizing MPD, maintain constant bottom hole pressure on connections, target ecd 11.5ppg EMW 11.19 Intermediate Casing Pick Technique: x At Bit Gamma to be utilized x 100’MD from TSGR, alert Wellsite Geo alerts Anchorage Geo to watch live feed x Communicate with Geologist in town about how formation tops are coming in relative to prognosis x Plan to make the pick on seeing ‘upper rabbit ear’ appears on logs. Ideal casing point is ~3-4 feet TVD into the TSGR, above the porosity zone. x Pick then confirmed with samples analyzed on surface x As we approach casing point, may drill in 5’MD – 10’MD intervals, CBU for samples as needed. Watch for any drilling breaks, reverse or normal. x In general, better to be a little too deep than too shallow, but deep or shallow to planned location will have serious implications for the production section x Risk of setting too shallow: x Exposed Kingak in the production hole could severely limit our ability to drill the lateral. Could potentially lose the well. x Risks of setting too deep: Page 22 Prudhoe Bay East 13-26A Producer Drilling Procedure x Lost circulation risk in the porosity zone of the Sag, though gas presence is unlikely. 11.20 At TD CBU x 3-4, full rate and rpm, not to exceed 11.5 ppg EMW, x Weight up to 10.8-11.0 ppg, Based upon Shale Stability Polar Plot x Drop Ball and close underreamer after all BU have been circulated 11.21 POOH to above HRZ, then POOH or BROOH to window depth x Pump at full drill rate and maximize rotation, do not exceed 11.5 ppg EMW at HRZ x Ensure pulling speeds have been modeled to ensure swab pressures do not drop below 10.5ppg emw 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 If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.22 Pull through window 11.23 TOOH and LD BHA 11.24 No wireline logging program planned Page 23 Prudhoe Bay East 13-26A Producer Drilling Procedure 12.0 Run & Cement 7” Intermediate Casing 12.1 R/U and pull wearbushing. 12.2 R/U 7” casing running equipment (CRT & Tongs) x Ensure 7” 29# VAMTOP x NC50 XO on rig floor and M/U to FOSV. x Use correct 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. 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. x Plan to land the 7” casing on a mandrel hanger. 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: 7” Float Shoe 1 joint – 7”, 2 Centralizers 10’ from each end w/ stop rings 1 joint –7”, 1 Centralizer mid joint w/ stop ring 1 joint – 7”, 1 Centralizer mid joint with stop ring 7” Float Collar 12.5 Continue running 7” intermediate casing x Fill casing while running using fill up line on rig floor. x Use correct thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every other joint to ~ 500’ MD above Sag 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. 7” 29# Special Drift L-80 VAMTOP Make-Up Torques Casing OD Minimum Optimum Maximum 7”8,460 ft-lbs 9,400 ft-lbs 10340 ft-lbs Page 24 Prudhoe Bay East 13-26A Producer Drilling Procedure 12.6 Circulate BU at predetermined intervals, every ~ 1000’ MD to remove any thickened mud while out of the hole: x Above 9-5/8” Window ~ 8800 x ~9800’ MD (Above HRZ) 12.7 Ensure Running speeds have been modeled to avoid surging the wellbore above drilling ECDs, ~ 11.5ppg EMW. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.8 Attempt to not circulate across HRZ/Kingak. Lower running speeds to hole conditions 12.9 Slow in and out of slips. 12.10 Position the casing shoe +/- 10’ from TD 12.11 PU hanger and landing joint 12.12 Lower casing to setting depth. Confirm measurements. 12.13 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. 12.14 Hold a pre-job safety meeting over the upcoming casing 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 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. 12.15 Document efficiency of all possible displacement pumps prior to cement job. 12.16 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. 12.17 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. 12.18 Fill surface lines with water and pressure test. Page 25 Prudhoe Bay East 13-26A Producer Drilling Procedure 12.19 Pump 60 bbls 11 ppg tuned spacer. 12.20 Mix and pump cmt per below recipe. 12.21 Cement volume based on annular volume + open hole excess (30%). Job will consist of tail, TOC brought to 500’ MD above Sag River x Prognosed Sag River Top: 10,842’ MD, Planned TOC: 10,342’ MD Estimated Total Cement Volume: Cement Slurry Design (Single Stage Cement Job) 12.22 After pumping cement, drop top plug and displace cement with mud out of mud pits. x Displacement: x = (10845’ – 120’) * .0372 = x = 399 bbl 12.23 Monitor returns closely while displacing cement. Lower pump rate before plug bump. Adjust pump rate if necessary. 12.24 Land top plug and pressure up to 500 psi over bump pressure. Bleed pressure and check floats. If floats are not holding, shut in and hold 500 psi over bump pressure until cement builds compressive strength after releasing running tool. Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 8.5" Pilot Hole x 7" (120') (10845 - 10725)' x 0.0226 bpf x 1.3 = 3.6 20.2 9.875" OH x 7" (10725 - 10,342) x .0471bpf x 1.3 = 23.6 132.4 7" Shoetrack 120' x 0.0372 bpf = 4.5 25.2 Total Tail 31.7 177.8 153.3Tail Tail Slurry System HalCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mixed Water 5.06 gal/sk Page 26 Prudhoe Bay East 13-26A Producer Drilling Procedure 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, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement, 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 time cement in place & calculated top of cement Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 27 Prudhoe Bay East 13-26A Producer Drilling Procedure 13.0 Drill 6-1/8” Hole Section 13.1 MU 6-1/8” RSS directional BHA. x LWD: Gamma/Res, Density Neutron, Azimuthal Resisivity 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 4” 14# XT39 x Run a solid float in the production hole section. 13.2 TIH 13.3 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. 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. 13.4 Drill out shoe track and 20’ of new formation. 13.5 CBU and condition mud for FIT. 13.6 Conduct FIT to 10.5 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. x 10.5 ppg provides >25 bbls based on 8.8 ppg MW, 7.1ppg PP (swabbed kick) x Minimum 9.2 ppg FIT required to drill ahead for ECD x Email digital data for casing test and FIT to AOGCC upon completion – Melvin.rixse@alaska.gov 13.7 6-1/8” 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. Page 28 Prudhoe Bay East 13-26A Producer Drilling Procedure 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. 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:8.8 – 9.5 ppg 3% Kcl Baradril-N Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Production 8.8 – 9.5 15-25 - ALAP 15 - 25 4-6 <8% <7 <11.0 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 6 ppb 6 ppb 2 ppb 1.0 ppb 0.5 ppb 0.015 ppb 13.8 Install MPD RCD 13.9 Displace wellbore to 8.8 ppg Baradrill-N drilling fluid 13.10 Begin drilling 6-1/8” 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 Page 29 Prudhoe Bay East 13-26A Producer Drilling Procedure 13.11 Drill 6-1/8” hole section as per Directional Plan, Geologist and Drilling Engineer. x Flow Rate: 150-250 GPM, target min. AV’s 200 ft/min, 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 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 Occasionally place speed bumps in the lateral section to be used of an OHST is needed x MPD will be utilized to monitor wellbore conditions x 6-1/8” Section A/C: x There are no wells with a CF < 1.0 13.12 Once at TD, CBU 2-3, x MW at TD may be adjusted based upon drilling x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary 13.13 POOH with the drilling assembly to the 7” casing shoe x Ensure swab pressures do not drop below .5 ppg EMW at TD 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, maintinaing a constant bottom hole pressure 13.14 CBU minimum two times at 7” shoe and clean casing with high vis sweeps. 13.15 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary. x Wellbore breathing has been seen on past 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 13.16 POOH and LD BHA. 13.17 Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. x Only LWD open hole logs are planned for the hole section. There will not be any additional logging runs conducted. Page 30 Prudhoe Bay East 13-26A Producer Drilling Procedure 14.0 Run 4-1/2” Liner 14.1 Well control preparedness: In the event of an influx of formation fluids while running the liner, the following well control response procedure will be followed: x P/U & M/U the 4” 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. x Slack off and with 4” DP across the BOP, shut in ram or annular on 4” DP. Close TIW. x Proceed with well kill operations. 14.2 R/U 4-1/2” liner running equipment. x Ensure 4-1/2” 12.6# L-80 H563 x 4” dp 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. x Sliding sleeve may be placed in the heel for remedial optionality 14.3 Run 4-1/2” 12.6# L-80 H53 w/ NCS Sleeves x Use Tenaris approved thread compound. Dope pin end only w/ paint brush. Wipe off excess. 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 Run NCS Sleeves as per draft tally provided by Completion Engineer x Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm x Make Up Torque Table (See data sheets attachments) x 4-1/2” 12.6# L-80 L-80 H563 Make-Up Torques: Casing OD Minimum Optimum Maximum 4-1/2”3200 3800 5600 14.4 Ensure to run enough liner to provide for setting the liner hanger at ~ 10,407 MD x Confirm set depth with completion engineer. 14.5 Ensure hanger/pkr will not be set in a 7” 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 7” connection. Page 31 Prudhoe Bay East 13-26A Producer Drilling Procedure 14.6 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. 14.7 M/U Baker SLZXP liner top packer to liner. 14.8 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. 14.9 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 4” DP/HWDP has been drifted x Fill drill pipe on the fly. Monitor FL and if filling is required due to losses/surging. 14.10 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. 14.11 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 14.12 TIH to planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 14.13 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 14.14 With liner at TD Circulate and condition mud, 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. 14.15 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 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. 14.16 Document efficiency of all possible displacement pumps prior to cement job. Page 32 Prudhoe Bay East 13-26A Producer Drilling Procedure 14.17 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 14.18 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. 14.19 Fill surface lines with water and pressure test. 14.20 Pump 30 bbls 11 ppg tuned spacer. 14.21 Mix and pump cmt per below recipe. 14.22 Cement volume based on annular volume + open hole excess (30%). Job will consist of tail, TOC brought to the liner top 150’ inside the 7” casing shoe, 10695’ MD Cement Slurry Design (Single Stage Cement Job) 14.23 After pumping cement, drop dart and displace cement with mud out of mud pits. x (19,132’-120’-10695’) * .0152bpf + 10695’ * .0103 bpf (4” dp capacity) = 126.4 + 110.15 x = 236.6 bbls 14.24 Monitor returns and pump pressure closely while displacing, slow down pumps when dart latches onto liner wiper plug. 14.25 Land liner wiper plug and pressure up to 500 psi over bump pressure. Bleed pressure and check floats. If floats are not holding, shut in and hold 500 psi over bump pressure until cement builds compressive strength. 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 Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 6.125" OH x 4-1/2" (19,132 - 10845)' x 0.0168 bpf x 1.3 = 181.0 1015.4 7" x 4-1/2" (10845 - 10695)' x 0.0175 bpf = 2.6 14.6 4-1/2" Shoetrack 120' x 0.0152 bpf = 1.8 10.1 Total Tail 185.4 1040.1 896.6Tail Tail Slurry System HalCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mixed Water 5.06 gal/sk Page 33 Prudhoe Bay East 13-26A Producer Drilling Procedure x Pump rate while displacing, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement, 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 time cement in place & calculated top of cement Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 14.26 Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SLZXP 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. 14.27 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. 14.28 PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 14.29 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. 14.30 PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 14.31 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 34 Prudhoe Bay East 13-26A Producer Drilling Procedure 15.0 Run Upper Completion/ Post Rig Work 15.1 RU to run 4-1/2”, 12.6# 13Cr VAMTOP tubing. x Ensure wear bushing is pulled. x Ensure 4-1/2”, L-80, 12.6#,VAMTOP x XT39 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info. x Monitor displacement from wellbore while RIH. Make Up Torque Table (See data sheets attached) 4-1/2” 12.6# L-80 13Cr VAMTOP Make-Up Torques: Casing OD Minimum Optimum Maximum 4-1/2”4000 4440 4880 15.2 PU, MU and RH with the following 4-1/2” completion jewelry (tally to be provided by Operations Engineer): x Tubing Jewelry to include: x X1 X Nipple x X4 GLM x X1 X Nipple x X1 Production Packer x X1 XN Nipple x 1x WLEG, set as close to 7” x 4-1/2” liner xo as possible *Note the packer setting and pressure testing procedure has been changed to reflect running TBG with live gas lift valve. Please consult the OE/DE if there are any questions before proceeding. 15.3 PU and MU the 4-1/2” tubing hanger. 15.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 15.5 Land the tubing hanger and RILDS. Lay down the landing joint. 15.6 Install 4” HP BPV. ND BOP. Install the plug off tool. 15.7 NU the tubing head adapter and NU the tree. 15.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. Page 35 Prudhoe Bay East 13-26A Producer Drilling Procedure 15.9 Pull the plug off tool and BPV. 15.10 Forward circulate the well over to corrosion inhibited KCL follow by diesel freeze protect for both tubing and IA to base permafrost MD. 15.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per setting procedure 15.12 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. While holding pressure on the tubing pressure the IA up to 3,500psi. Test the IA to 3500 psi for CMIT-TxIA. Record and notate all pressure tests (30 minutes) on chart. 15.13 Bleed both the IA pressure to 0psi and tubing to 200 psi. 15.14 Rig up jumper from IA to tubing to allow freeze protect to swap. 15.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 15.16 RDMO Innovation i. POST RIG WELL WORK 1. Wireline a. Pull Ball & Rod, RHC Plug 2. Well Tie in 3. Post Rig Coil Sundry to be submitted Page 36 Prudhoe Bay East 13-26A Producer Drilling Procedure 16.0 Innovation Rig BOP Schematic Page 37 Prudhoe Bay East 13-26A Producer Drilling Procedure 17.0 Wellhead Drawing Page 38 Prudhoe Bay East 13-26A Producer Drilling Procedure 18.0 Tubular Data Sheets Intermediate Casing 7” 29# L-80 VamTop Special Drift 6.125” Page 39 Prudhoe Bay East 13-26A Producer Drilling Procedure Lower Completion 4-1/2” L-80 12.6# H563 Page 40 Prudhoe Bay East 13-26A Producer Drilling Procedure Upper Completion 4-1/2” 13Cr Vamtop Page 41 Prudhoe Bay East 13-26A Producer Drilling Procedure 19.0 Days Vs Depth Page 42 Prudhoe Bay East 13-26A Producer Drilling Procedure 20.0 Formation Tops & Information Reference Plan: CM3 Colville (Shale) 7582 6,320.9 -6247 682,889 5,932,950 2794 8.6 CM2 Colville (Shale) 8456 6,917.6 -6844 682,267 5,933,093 3416 9.6 CM1 Colville (Shale) 9423 7,647.2 -7573 681,648 5,933,221 3781 9.6 THRZ HRZ (Shale) 9878 8,023.5 -7950 681,402 5,933,174 4134 10.0 TKNG Kingak (Shale) 10138 8,236.9 -8163 681,272 5,933,101 4245 10.0 TSGR Sag (sand) Oil 10842 8,813.9 -8740 680,920 5,932,902 3227 7.1 TSHU Shublik (shale / carbonate) 10864 8,831.3 -8757 680,910 5,932,896 3415 7.5 TSAD Ivishak (sand) Water 10954 8,903.5 -8830 680,865 5,932,867 3263 7.1 Aquifer Fluid Contact Water 11237 9,093.9 -9020 680,724 5,932,715 3550 7.6 TCGL Ivishak (conglomerate) Water 11285 9,119.1 -9045 680,702 5,932,681 3561 7.6 Fault 1 11604 TCGL (invert)Ivishak (sand) Water 12294 9,144.9 -9071 680,585 5,931,749 Aquifer Fluid Contact Water 12458 9,093.9 -9020 680,671 5,931,620 TSAD (invert)Shublik (shale / carbonate) 12926 8,928.9 -8855 680,978 5,931,308 TSHU (invert) Sag (sand) Oil 13233 8,859.9 -8786 681,152 5,931,067 Fault 2 15198 TD Sag (sand) Oil 19133 9,013.9 -8940 682,753 5,925,396 TOP NAME LITHOLOGY 13-26A wp6ANTICIPATED FORMATION TOPS & GEOHAZARDS EASTING Est. ML Pressure GradientEXPECTED FLUID MD (FT) TVD (FT) TVDSS (FT)NORTHING Page 43 Prudhoe Bay East 13-26A Producer Drilling Procedure DS13 Pad Data Sheet Information: Page 44 Prudhoe Bay East 13-26A Producer Drilling Procedure 21.0 Anticipated Drilling Hazards 8-1/2” x 9-7/8” 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 > 600gpm, 200 ft/min AV, 120 rpm, 6 rpm reading of greater than hole diameter. Lost Circulation/ Breathing: 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. Losses/breathing seen in the colville sections above 10.8 ppg Faulting: Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and casing/liner runs. Talk with Geologist to ensure all known faults are identified Abnormal Pressures and Temperatures: Reservoir pressures are expected to be subnormal. Utilize MPD to mitigate any abnormal pressure seen. Gas Cut Mud Gas cut mud as been seen, ensure sufficient MW is used during hole section. Ensure gas detectors are always functioning. Watch swab effect. Shale Stability: Intermediate Hole will cross multiple shale formations, ensure black product is in the mud system, sufficient MW is used, MPD is used to maintain constant bottomhole pressure, and surge/swab pressures are modeled and kept in mind during casing run. Make sure sufficient mw is left after well is TD. 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. 8-1/2” Section specific A/C: x There are no wells with CF <1.0 in the intermediate hole section Page 45 Prudhoe Bay East 13-26A Producer Drilling Procedure 6-1/8” 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. 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. Have sufficient fluid available if major losses are seen. Faulting: Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. Abnormal Pressures and Temperatures: Lower than normal pressures in the target reservior. Ensure LCM in the mud system and monitor well for flow. Have sufficient fluid available if major losses are seen. Shale Stability: Production Hole could potentially cross multiple shale formations, if crossed make sure sufficient MW is used, MPD is used to maintain constant bottomhole pressure, and surge/swab pressures are modeled and kept in mind 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. 6-1/8” A/C: x There are no wells with a CF < 1.0 Page 46 Prudhoe Bay East 13-26A Producer Drilling Procedure Entire Hole Section H2S: Treat every hole section as though it has the potential for H2S. DS13 has a history of H2S. Current H2S Data on Next Page. 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 47 Prudhoe Bay East 13-26A Producer Drilling Procedure 22.0 Innovation Rig Layout Page 48 Prudhoe Bay East 13-26A Producer Drilling Procedure 23.0 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 49 Prudhoe Bay East 13-26A Producer Drilling Procedure 24.0 Innovation Rig Choke Manifold Schematic Page 50 Prudhoe Bay East 13-26A Producer Drilling Procedure 25.0 Casing Design Page 51 Prudhoe Bay East 13-26A Producer Drilling Procedure 26.0 MASP Page 52 Prudhoe Bay East 13-26A Producer Drilling Procedure Page 53 Prudhoe Bay East 13-26A Producer Drilling Procedure 27.0 Spider Plot (NAD 27) (Governmental Sections) Page 54 Prudhoe Bay East 13-26A Producer Drilling Procedure 28.0 Surface Plat (As-Built) (NAD 27) 6WDQGDUG3URSRVDO5HSRUW -XO\ 3ODQ$ZS +LOFRUS1RUWK6ORSH//& 3UXGKRH%D\ 3ODQ 3ODQ$ 6750720076508100855090009450True Vertical Depth (900 usft/in)-3150 -2700 -2250 -1800 -1350 -900 -450 0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400Vertical Section at 165.00° (900 usft/in)13-26A wp03 - ICP Polygon13-26A wp03 tgt02 - ICP13-26A wp03 tgt03 - SUMP13-26A wp03 tgt04 - SUMP EXIT (TSAD)13-26A wp03 tgt05 - SAG LATERAL13-26A wp03 tgt06 - setup fault 213-26A wp03 tgt07 - post fault 213-26A wp03 tgt0813-26A wp03 tgt09 - TD13-26A wp03 tgt01 - top HRZ8500900095001000010500110001146613-269 5/8" x 12 1/4" TOW7" x 8 1/2"4 1/2" x 6 1/8"90009500100001050011000115001 2 0 0 0 1 2 5 0 0 1 3 0 0 013500140001450015000155001600016500170001750018000185001900019133 13-26A wp06KOP : Start Dir 12º/100' : 9000' MD, 7314.13'TVD : 45° LT TFEnd Dir : 9017' MD, 7326.53' TVDStart Dir 4.6º/100' : 9037' MD, 7340.94'TVDEnd Dir : 9216.69' MD, 7478.96' TVDStart Dir 4.6º/100' : 9374.09' MD, 7606.89'TVDEnd Dir : 9877.56' MD, 8023.37' TVDStart Dir 8º/100' : 10882.47' MD, 8846.45'TVDEnd Dir : 11708.16' MD, 9227.79' TVDStart Dir 8º/100' : 11731.17' MD, 9227.79'TVDEnd Dir : 12512.21' MD, 9074.79' TVDStart Dir 8º/100' : 12936.86' MD, 8925.25'TVDEnd Dir : 13321.81' MD, 8855.79' TVDStart Dir 3º/100' : 13371.81' MD, 8855.79'TVDEnd Dir : 13532.48' MD, 8858.03' TVDStart Dir 3º/100' : 14960.8' MD, 8897.79'TVDEnd Dir : 15239.3' MD, 8909.94' TVDStart Dir 3º/100' : 15323' MD, 8918.97'TVDEnd Dir : 15502.74' MD, 8929.92' TVDStart Dir 3º/100' : 17132.74' MD, 8952.68'TVDEnd Dir : 17164.7' MD, 8953.39' TVDTotal Depth : 19132.67' MD, 9013.76' TVDCM1THRZBHRZLCUTSGRTSHUTSADTCGLHilcorp North Slope, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: 13-26Ground Level: 47.29+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.005931902.53685733.45 70° 13' 8.1621 N 148° 30' 5.5923 WSURVEY PROGRAMDate: 2024-06-13T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool86.79 9000.00 GyroData Survey (13-26) 3_Gyro-CT_Drill pipe9000.00 9642.00 13-26A wp06 (Plan: 13-26A) GYD_Quest GWD9642.00 10845.00 13-26A wp06 (Plan: 13-26A) 3_MWD+IFR2+MS+Sag10845.00 19132.67 13-26A wp06 (Plan: 13-26A) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation6917.51 6843.72 8456.06 CM27647.07 7573.28 9423.32 CM18023.37 7949.58 9877.56 THRZ8178.94 8105.15 10067.50 BHRZ8236.60 8162.81 10137.89 LCU8813.60 8739.81 10842.37 TSGR8831.23 8757.44 10863.89 TSHU8903.35 8829.56 10953.63 TSAD9119.00 9045.21 11285.04 TCGLREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: 13-26, True NorthVertical (TVD) Reference:13-26A planned RKB @ 73.79usftMeasured Depth Reference:13-26A planned RKB @ 73.79usftCalculation Method: Minimum CurvatureProject:Prudhoe BaySite:13Well:Plan: 13-26Wellbore:Plan: 13-26ADesign:13-26A wp06CASING DETAILSTVD TVDSS MD SizeName7314.14 7240.35 9000.01 9-5/8 9 5/8" x 12 1/4" TOW8815.76 8741.97 10845.00 7 7" x 8 1/2"9013.76 8939.97 19132.67 4-1/2 4 1/2" x 6 1/8"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 9000.00 42.45 284.33 7314.13 1363.52 -3797.86 0.00 0.00 -2300.01 KOP : Start Dir 12º/100' : 9000' MD, 7314.13'TVD : 45° 2 9017.00 43.89 282.22 7326.53 1366.18 -3809.18 12.00 -45.00 -2305.52 End Dir : 9017' MD, 7326.53' TVD3 9037.00 43.89 282.22 7340.94 1369.12 -3822.73 0.00 0.00 -2311.86 Start Dir 4.6º/100' : 9037' MD, 7340.94'TVD4 9216.69 35.63 282.62 7478.96 1393.78 -3934.88 4.60 178.38 -2364.71 End Dir : 9216.69' MD, 7478.96' TVD5 9374.09 35.63 282.62 7606.89 1413.81 -4024.35 0.00 0.00 -2407.21 Start Dir 4.6º/100' : 9374.09' MD, 7606.89'TVD6 9877.56 35.01 242.00 8023.37 1377.55 -4298.72 4.60 -108.25 -2443.20 13-26A wp03 tgt01 - top HRZ End Dir : 9877.56' MD, 8023.37' TVD7 10841.73 35.01 242.00 8813.08 1117.85 -4787.13 0.00 0.00 -2318.76 13-26A wp03 tgt02 - ICP8 10882.47 35.01 242.00 8846.45 1106.88 -4807.77 0.00 0.00 -2313.51 Start Dir 8º/100' : 10882.47' MD, 8846.45'TVD9 11708.16 90.00 197.03 9227.79 536.29 -5179.94 8.00 -50.66 -1858.68 End Dir : 11708.16' MD, 9227.79' TVD10 11731.17 90.00 197.03 9227.79 514.28 -5186.68 0.00 0.00 -1839.17 13-26A wp03 tgt03 - SUMP Start Dir 8º/100' : 11731.17' MD, 9227.79'TVD11 12512.21 110.62 136.60 9074.79 -196.60 -5034.52 8.00 -66.60 -1113.13 End Dir : 12512.21' MD, 9074.79' TVD12 12936.86 110.62 136.60 8925.25 -485.40 -4761.46 0.00 0.00 -763.50 Start Dir 8º/100' : 12936.86' MD, 8925.25'TVD13 13321.81 90.00 160.00 8855.79 -804.89 -4567.17 8.00 129.14 -404.60 End Dir : 13321.81' MD, 8855.79' TVD14 13371.81 90.00 160.00 8855.79 -851.88 -4550.07 0.00 0.00 -354.79 13-26A wp03 tgt05 - SAG LATERAL Start Dir 3º/100' : 13371.81' MD, 8855.79'TVD15 13532.48 88.40 164.55 8858.03 -1004.86 -4501.17 3.00 109.35 -194.37 End Dir : 13532.48' MD, 8858.03' TVD16 14960.80 88.40 164.55 8897.79 -2381.03 -4120.79 0.00 0.00 1233.36 Start Dir 3º/100' : 14960.8' MD, 8897.79'TVD17 15032.68 90.00 166.00 8898.79 -2450.53 -4102.52 3.00 42.30 1305.22 13-26A wp03 tgt06 - setup fault 218 15239.30 83.81 166.32 8909.94 -2650.77 -4053.18 3.00 177.09 1511.40 End Dir : 15239.3' MD, 8909.94' TVD19 15323.00 83.81 166.32 8918.97 -2731.61 -4033.50 0.00 0.00 1594.58 Start Dir 3º/100' : 15323' MD, 8918.97'TVD20 15502.74 89.20 166.45 8929.92 -2905.91 -3991.28 3.00 1.42 1773.88 End Dir : 15502.74' MD, 8929.92' TVD21 17132.74 89.20 166.45 8952.68 -4490.39 -3609.42 0.00 0.00 3403.20 13-26A wp03 tgt08 Start Dir 3º/100' : 17132.74' MD, 8952.68'TVD22 17164.70 88.24 166.41 8953.39 -4521.44 -3601.92 3.00 -177.61 3435.13 End Dir : 17164.7' MD, 8953.39' TVD23 19132.67 88.24 166.41 9013.76 -6433.41 -3139.72 0.00 0.00 5401.58 13-26A wp03 tgt09 - TD Total Depth : 19132.67' MD, 9013.76' TVD -6300 -5850 -5400 -4950 -4500 -4050 -3600 -3150 -2700 -2250 -1800 -1350 -900 -450 0 450 900 1350 1800 South(-)/North(+) (900 usft/in)-5850 -5400 -4950 -4500 -4050 -3600 -3150 -2700 -2250 -1800 -1350 -900 -450 0 West(-)/East(+) (900 usft/in) 13-26A wp03 tgt01 - top HRZ 13-26A wp03 tgt09 - TD 13-26A wp03 tgt08 13-26A wp03 tgt07 - post fault 2 13-26A wp03 tgt06 - setup fault 2 13-26A wp03 tgt05 - SAG LATERAL 13-26A wp03 tgt04 - SUMP EXIT (TSAD) 13-26A wp03 tgt03 - SUMP 13-26A wp03 tgt02 - ICP 13-26A wp03 - ICP Polygon13-269 5/8" x 12 1/4" TOW 7" x 8 1/2" 4 1/2" x 6 1/8"750077508000825085009000 901 4 13-26A wp06 KOP : Start Dir 12º/100' : 9000' MD, 7314.13'TVD : 45° LT TF End Dir : 9017' MD, 7326.53' TVD Start Dir 4.6º/100' : 9037' MD, 7340.94'TVD End Dir : 9216.69' MD, 7478.96' TVD Start Dir 4.6º/100' : 9374.09' MD, 7606.89'TVD Start Dir 8º/100' : 10882.47' MD, 8846.45'TVD End Dir : 11708.16' MD, 9227.79' TVD Start Dir 8º/100' : 11731.17' MD, 9227.79'TVD End Dir : 12512.21' MD, 9074.79' TVD Start Dir 8º/100' : 12936.86' MD, 8925.25'TVD End Dir : 13321.81' MD, 8855.79' TVD Start Dir 3º/100' : 13371.81' MD, 8855.79'TVD End Dir : 13532.48' MD, 8858.03' TVD Start Dir 3º/100' : 14960.8' MD, 8897.79'TVD End Dir : 15239.3' MD, 8909.94' TVD Start Dir 3º/100' : 15323' MD, 8918.97'TVD End Dir : 15502.74' MD, 8929.92' TVD Start Dir 3º/100' : 17132.74' MD, 8952.68'TVD End Dir : 17164.7' MD, 8953.39' TVD Total Depth : 19132.67' MD, 9013.76' TVD CASING DETAILS TVD TVDSS MD Size Name 7314.14 7240.35 9000.01 9-5/8 9 5/8" x 12 1/4" TOW 8815.76 8741.97 10845.00 7 7" x 8 1/2" 9013.76 8939.97 19132.67 4-1/2 4 1/2" x 6 1/8" Project: Prudhoe Bay Site: 13 Well: Plan: 13-26 Wellbore: Plan: 13-26A Plan: 13-26A wp06 WELL DETAILS: Plan: 13-26 Ground Level: 47.29 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 5931902.53 685733.45 70° 13' 8.1621 N 148° 30' 5.5923 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: 13-26, True North Vertical (TVD) Reference:13-26A planned RKB @ 73.79usft Measured Depth Reference:13-26A planned RKB @ 73.79usft Calculation Method:Minimum Curvature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eparation Factor9350 9900 10450 11000 11550 12100 12650 13200 13750 14300 14850 15400 15950 16500 17050 17600 18150 18700 19250Measured Depth (1100 usft/in)13-30B13-1513-31A13-1413-1213-2413-24A13-24B13-24B wp1013-2913-26No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: 13-26 NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 47.29+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005931902.53 685733.4570° 13' 8.1621 N148° 30' 5.5923 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: 13-26, True NorthVertical (TVD) Reference: 13-26A planned RKB @ 73.79usftMeasured Depth Reference:13-26A planned RKB @ 73.79usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2024-06-13T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool86.79 9000.00 GyroData Survey (13-26) 3_Gyro-CT_Drill pipe9000.00 9642.00 13-26A wp06 (Plan: 13-26A) GYD_Quest GWD9642.00 10845.00 13-26A wp06 (Plan: 13-26A) 3_MWD+IFR2+MS+Sag10845.00 19132.67 13-26A wp06 (Plan: 13-26A) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)9350 9900 10450 11000 11550 12100 12650 13200 13750 14300 14850 15400 15950 16500 17050 17600 18150 18700 19250Measured Depth (1100 usft/in)GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference9000.00 To 19132.98Project: Prudhoe BaySite: 13Well: Plan: 13-26Wellbore: Plan: 13-26APlan: 13-26A wp06CASING DETAILSTVD TVDSS MD Size Name7314.14 7240.35 9000.01 9-5/8 9 5/8" x 12 1/4" TOW8815.76 8741.97 10845.00 7 7" x 8 1/2"9013.76 8939.97 19132.67 4-1/2 4 1/2" x 6 1/8" Revised 7/2022 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 Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The 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-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot 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 this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a 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 the Operator 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 all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. PRUDHOE OIL 224-109 PBU 13-26A PRUDHOE BAY WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UNIT 13-26AInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241090PRUDHOE BAY, PRUDHOE OIL - 640150NA1 Permit fee attachedYes ADL028315 and ADL0283142 Lease number appropriateYes3 Unique well name and numberYes PRUDHOE BAY, PRUDHOE OIL - 640150 - governed by CO 341J4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes This is a sidetrack from an existing parent well with wellbore integrity.18 Conductor string providedYes This is a sidetrack from an existing parent well with wellbore integrity.19 Surface casing protects all known USDWsYes This is a sidetrack from an existing parent well with wellbore integrity.20 CMT vol adequate to circulate on conductor & surf csgYes This is a sidetrack from an existing parent well with wellbore integrity.21 CMT vol adequate to tie-in long string to surf csgYes Cemented 7" intermediate casing from TSAG across confing zones. Fully cemented prod liner.22 CMT will cover all known productive horizonsYes This is a sidetrack from an existing parent well with wellbore integrity.23 Casing designs adequate for C, T, B & permafrostYes Hilcorp Innvovation rig has adequate tankage and good trucking support24 Adequate tankage or reserve pitYes Sundry 324-39125 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan shows no close approaches with HSE risk.26 Adequate wellbore separation proposedNA Halliburton collision scan shows no close approaches with HSE risk.27 If diverter required, does it meet regulationsYes This is a sidetrack from an existing parent well with wellbore integrity.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulationYes 13-5/8" , 5000 psi stack tested to 3500 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes Hilcorp Innovation Rig has 10X 2-9/16"" manual gate valves, 1 x 3-1/8" manual choke and 1 x 3-1/8"31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes MPU R pad has no H2S history. Monitoring will be required.33 Is presence of H2S gas probableNA This well is a Oil Development well.34 Mechanical condition of wells within AOR verified (For service well only)No DS 13 wells are H2S-bearing. H2S measures are required. (Max H2S on pad in 13-02A: 300 ppm in 2001.)35 Permit can be issued w/o hydrogen sulfide measuresYes Sag River target anticipated at 7.1 ppg EMW with Ivishak reservoir anticipated at 7.6 ppg EMW.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate8/7/2024ApprMGRDate8/8/2024ApprADDDate8/7/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateMaximum gradient of 10 ppg EMW expected through HRZ and Kingak.*&:JLC 8/14/2024