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Home My WebLink About225-146Alaska 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 Sean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Endicott Field, Endicott Oil Pool, DIU SDI 3-15A Hilcorp Alaska, LLC Permit to Drill Number: 225-146 Surface Location: 2526' FNL, 809' FEL, Sec. 08, T11N, R17E, UM, AK Bottomhole Location: 929' FNL, 1532 FWL, Sec.04, T11N, R17E, UM, AK Dear Mr. McLaughlin: 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, Commissioner DATED this 16 th day of January 2026. Joe Engel for Sean McLaughlin Digitally signed by Joseph Engel (2493) DN: cn=Joseph Engel (2493) Date: 2025.12.30 14:08:01 - 09'00' Joseph Engel (2493) 225-146 By Grace Christianson at 2:59 pm, Dec 30, 2025 *Variance as per 20 AAC 25.112(i): Approved for alternate abandonment plug placement on parent well contingent upon fully cemented liner on upcoming sidetrack. *Ensure controls and procedures are in place to address the risk of high H2S. DSR-1/2/26 12,654 *AOGCC Witnessed BOP Test to 3500 psi, Annular 2500 psi minimum. *Post rig service coil perforating approved for max gun length of 500'. *Window milling approved on service coil. A.Dewhurst 05JAN26 50-029-21751-01-00 *Variance to 20 AAC 25.036 (c)(2)(A)(iv) with compliance to rules in CO 823. J.Lau 1/15/26JLC 1/16/2026 01/16/26 01/16/26 To: Alaska Oil & Gas Conservation Commission From: Trevor Hyatt Drilling Engineer Date: December 30, 2025 Re:DIU SDI 3-15A Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well DIU SDI 3-15 with the Nabors CDR2/CDR3 Coiled Tubing Drilling. Proposed plan for DIU SDI 3-15A Producer: See END SDI 03-15 Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to drift for whipstock, caliper and MIT. E-line or coil will mill the XN-nipple. E-line will set a 3-1/2"x5-1/2" whipstock. Coil will mill window pre-rig (2.74"). If unable to set the whipstock or mill the window pre-rig, the rig will perform that work. A coil tubing drilling sidetrack will be drilled with the Nabors CDR2 or CDR3 rig. The rig will move in, test BOPE and kill the well. If unable to pre-rig, the rig will set the 3-1/2"x5-1/2" whipstock and mill a single string 2.74" window + 10' of formation. The well will kick off drilling and lands in the Kekiktuk. The lateral will continue in the Kekiktuk to TD. The proposed sidetrack will be completed with a 2-3/8 13Cr solid liner, cemented in place and selectively perforated post rig (will be perforated with rig if unable to post rig). This completion will completely isolate and abandon the parent Endicott Oil Pool perfs. The following describes the work planned. A wellbore schematic of the current well and proposed sidetrack is attached for reference. Pre-Rig Work: Reference DIU SDI 3-15 Sundry submitted in concert with this request for full details. 1. Slickline : Dummy WS drift (done; 12,668' MD), Caliper (done) 2. Fullbore : CMIT TxIA (done, passed 3140 psi), MITT (passed 3600 psi) 3. E-Line : Mill XN nipple to 2.75" and set 3-1/2" x 5-1/2" WS @ 12,654' MD 20 deg ROHS 4. Coil : Mill Window 5. Valve Shop : Pre-CTD Tree Work 6. Operations : Remove wellhouse and level pad. Rig Work: (Estimated to start in March 2026) 1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP 2,800 psi). Give AOGCC 24hr notice prior to BOPE test. 2. Mill 2.74 Single String 5-1/2" Window (if not already done pre-rig) 3. Drill production lateral: 3.25" OH, ~2,629' (12 deg DLS planned). Swap to KWF for liner. 4. Run 3-1/2 x 3-1/4 x 2-7/8 13Cr solid liner 5. Make up 1" CS Hydril inner string, 2-3/8" cement job BHA, with ORCA system and run in to PBTD. 6. Pump primary cement job*: 33.5 bbls, 15.3 ppg Class G, 1.24 (ft3/sk), TOC at TOL. Set LTP*. If high losses are encountered during cement job and it is deemed necessary, a cement down squeeze from TOL to loss zone will be performed with the rig or service coil (if performed by service coil see future sundry). 7. Only if not able to do with service coil extended perf post rig Perforate Liner with 1" CS Hydril 8. Freeze protect well to a min 2,200' TVD. 9. Close in tree, RDMO. Post Rig Work: 1. Valve Shop : Valve & tree work 2. Slickline : Set LTP* (if necessary). Set live GLVs. 3. Service Coil : Post rig RPM, CBL, and perforate (~50). Managed Pressure Drilling: Managed pressure drilling techniques will be employed on this well. The intent is to provide constant bottom hole pressure by using minimum 8.4 ppg drilling fluid in combination with annular friction losses and applied surface pressure. Constant BHP will be utilized to reduce pressure fluctuations to help with hole stability. Applying annular friction and choke pressure also allow use of lighter drilling fluid and minimizes fluid losses and/or fracturing at the end of the long well bores. A MPD choke for regulating surface pressure and is independent of the WC choke. Deployment of the BHA under trapped wellhead pressure may be necessary. Pressure deployment of the BHA will be accomplished utilizing BHA pipe/slip rams (see attached BOP configurations). The annular preventer will act as a secondary containment during deployment and not as a stripper. Operating parameters and fluid densities will be adjusted based on real-time bottom hole pressure measurements while drilling and shale behavior. The following scenario is expected: MPD Pressure at the Planned Window (12,654' MD -9,921' TVD) Pumps On Pumps O A Target BHP at Window (ppg)6,088 psi 6,088 psi 11.8 B -1,139 psi 0 psi 0.09 C 4,437 psi 4,437 psi 8.6 B+C Mud + ECD Combined 5,576 psi 4,437 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain 512 psi 1,651 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: The estimated reservoir pressure is expected to be 3,800 psi at 10,000 TVD. (7.3 ppg equivalent). Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2,800 psi (from estimated reservoir pressure). Mud Program: Drilling: Minimum MW of 8.4 ppg KCL with viscosifier for drilling. Managed pressure used to maintain constant BHP. Disposal: All Class l & II non-hazardous and RCRA-exempt drilling and completion fluids will go to GNI at DS 4. Fluids >1% hydrocarbons or flammables must go to GNI. Fluids >15% solids by volume must go to GNI. Fluids with solids that will not pass through 1/4 screen must go to GNI. Fluids with PH >11 must go to GNI. Hole Size: 2.74 to 3.25 hole for the entirety of the production hole section. Liner Program: 2-3/8", 4.6#, 13Cr/Solid: 11,723' MD 15,283' MD (3,560' liner) The primary barrier for this operation: Kill Weight Fluid to provide overbalance as necessary. A X-over shall be made up to a safety joint including a TIW valve for all tubulars ran in hole. Jointed Pipe Work String Program: 1-1/4" CS Hydril, 3.02#, P-110: up to 4,000' MD 1 CS Hydril, 2.25#, P-110: up to 4,000' MD Used for contingency CTD liner cleanout/logging runs, deployment of perforation guns (if performed by rig), inner string 2-3/8 liner cement jobs and contingency inner string 2-7/8 liner cement jobs. Well Control: BOP diagram is attached. MPD and pressure deployment is planned. Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3,500 psi. The annular preventer will be tested to 250 psi and 2,500 psi. 1.5 wellbore volumes of KWF will be on location at all times during drilling operations. A X-over shall be available to be made up to a safety joint, with the same OD as coiled tubing, including a TIW valve for all tubulars ran in hole. The safety joint will be utilized while running solid/slotted liner, perforation guns and CS Hydril jointed pipe. The desire is to keep the same standing orders for the entire liner run and not change shut in techniques from well to well (run safety joint with pre-installed TIW valve). When closing on a safety joint, 2 sets of pipe/slip rams will be available, above and below the flow cross providing better well control option. Hilcorp Requests a variance to 20 AAC 25.036(c)(2)(A)(iv) and that the requirements and privileges of CO823 be extended to END 3-15A. o CO823 Hilcorp CTD Qualification Blind-Shear Test: CDR2 test on 09/04/2025 (see Hilcorp Alaska CTD CO823 Qualification report previously sent to AOGCC for more information). o CO823 Safety Joint Drills: Provide AOGCC opportunity to witness once per well that a CTD liner is ran. Directional: Directional plan attached. Maximum planned hole angle is 93°. Inclination at kick off point is 58°. Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. Distance to nearest property line 1,659 ft Distance to nearest well within pool 545 ft Logging: MWD directional, Gamma Ray and Resistivity will be run through the entire open hole section. Real time bore pressure to aid in MPD and ECD management. Perforating: 50' perforated post rig See attached extended perforating procedure. 1.56" Perf Guns at 6 spf If post rig extended perforating with service coil is not an option, the well will be perforated with the rig or post rig under this PTD. The well will be perforated between the CTD whipstock and TD of the newly drilled CTD well, completely in the Endicott Oil Pool. Formations: Top of Endicott Oil Pool 12,605 MD in the parent Anti-Collision Failures: All Wells Pass AC scan Hazards: DS/Pad is an H2S pad. The last H2S reading on DIU SDI 3-15: 430 ppm on 1/10/2025. Max H2S recorded on DS/Pad: 1380 ppm. 1 fault crossings expected. High lost circulation risk. Trevor Hyatt CC: Well File Drilling Engineer Joseph Lastufka (907-223-3087) Pre-Rig Service Coil Window Milling The approved sundry and permit to drill will be posted in the Operations Cabin of the unit during the entire window milling operation. Notes for window milling: Window milling with service CTU operations will fully comply with 20 AAC 25.286(d)(3), including the use of pressure control equipment, all BHAs fully lubricated and at no point will any BHA be open-hole deployed. Window Milling Procedure: 1. Kill well with 1% KCL if necessary. Well may already be killed from previous operations. 2. MU and RIH with window milling assembly Window mill followed by string reamer. NOTE: Confirm milling BHA configuration prior to job execution due to variations in different service providers window milling BHAs. 3. RIH & TAG whipstock pinch point, calculate distance till string reamer is out of the window, paint coil flag and note in WSR. 4. Mill window per vendor procedure. Make note of any WHP changes while milling window in the WSR. 5. Make multiple reciprocating passes through the kickoff point to dress liner exit and eliminate all burs. Perform gel sweeps as necessary to keep window clean. Maximum approved distance to reciprocate beyond the window is 15 ft to ensure confidence the window is prepared for the sidetrack.DO NOT RECIPROCATE DEEPER than 15 ft. 6. Confirm exited liner & string reamer dressed entire window with coil flag and note bottom of window and total milled depth in WSR. 7. FP well to 2,500 TVD with 60/40 MeOH while POOH. 8. Once on surface inspect BHA, measure OD of mill and string reamer & document in WSR. 9. RDMO 10. Communicate to Operations to tag wing valve Do Not POP. Pre-Rig Service Coil Window Milling BOP Diagram Post-Rig Service Coil Perforating Procedure: Coiled Tubing Notes: Due to the necessary open hole deployment of Extended Perforating jobs, 24-hour crew and WSS coverage is required. Note: The well will be killed and monitored before making up the initial perfs guns. This will provide guidance as to whether the well will be killed by bullheading or circulating bottoms up throughout the job. If pressure is seen immediately after perforating, it will either be killed by bullheading while POOH or circulating bottoms up through the same port that opened to shear the firing head. Coil Tubing 1. MIRU Coiled Tubing Unit and spot ancillary equipment. 2. MU nozzle drift BHA (include SCMT and/or RPM log as needed). 3. RIH to PBTD. a. Displace well with weighted brine while RIH (minimum 8.4 ppg to be overbalanced). 4. POOH (and RPM log if needed) and lay down BHA. 5. After MU MHA and pull testing the CTC, tag-up on the CT stripper to ensure BHA cannot pull through the brass upon POOH with guns. 6. There will be no perforations to bullhead kill the well. Well will already be loaded w/ weighted brine or KCl per previous steps. Re-load well at WSS discretion. 7. At surface, prepare for deployment of TCP guns. 8.Confirm well is dead. Bleed any pressure off to return tank. Kill well w/ KWF, weighted brine as needed (minimum 8.4 ppg). Maintain continuous hole fill taking returns to tank until lubricator connection is reestablished. Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed and there is no excess flow. 9.Pickup safety joint and TIW valve and space out before MU guns.Review well control steps with crew prior to breaking lubricator connection and commencing makeup of TCP gun string. Once the safety joint and TIW valve have been spaced out, keep the safety joint/TIW valve readily accessible near the working platform for quick deployment if necessary. 10. Break lubricator connection at QTS and begin makeup of TCP guns and blanks per schedule below.Max BHA length per PTD is 500ft. Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed and there is no excess flow. a. Perforation details i.Perf Interval:The well will be perforated between the CTD whipstock and TD of the newly drilled CTD well, completely in the Endicott Oil Pool. ii.Perf Length:500 iii.Gun Length:500 iv.Weight of Guns (lbs):2300lbs (4.6ppf) 11. MU lubricator and RIH with perf gun and tie-in to coil flag correlation. Pickup and perforate perforation intervals (TBD). POOH. a. Note any tubing pressure change in WSR. 12. After perforating, PUH to top of liner or into tubing tail to ensure debris doesnt fall in on the guns and stick the BHA.Confirm well is dead and re-kill if necessary before pulling to surface. 13. Pump pipe displacement while POOH.Stop at surface to reconfirm well dead and hole full. 14. Review well control steps with crew prior to breaking lubricator connection and commencing breakdown of TCP gun string. Standing orders flow chart included with this sundry request. Ensure safety joint and TIW valve assembly are on-hand before breaking off lubricator to LD gun BHA. 15. Freeze protect well to 2,000 TVD. 16. RDMO CTU. Coiled Tubing BOPs Standing Orders for Open Hole Well Control during Perf Gun Deployment Equipment Layout Diagram _____________________________________________________________________________________ Revised By: GP 12/30/2025 Duck Island Unit Well: END 3-15 Last Completed: 4/28/2001 PTD: 187-094 SCHEMATIC CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 30"Conductor NA / NA / NA NA Surface 131 13-3/8Surface 68 / L-80 / Btrs 12.415 Surface 2,516 9-5/8"Intermediate 47 / N-80 / N/A 8.681 Surface 12,444 9-5/8"Intermediate 47 / NT95HS / N/A 8.681 12,44412,564 5-1/2Liner 17 / L-80 / Vam Ace 4.892 12,01414,585 TUBING DETAIL 3-1/2"Tubing 9.2 / 13CR-80 / Vam-Ace 2.992 Surface 11,785 5-1/2Tubing 17 / 13CR-80 / NSCC 4.890 11,78512,004JEWELRY DETAIL No Depth Item 1 1,5213.5 OTIS XDB SSSV Landing Nipple, ID=2.75 GLM DETAIL: 3.5 x 1.5 Camco MMG Mandrel 2 3,965STA 6: Vlv= Dome, Latch= RK, Port= 16, Dev= 9, TVD= 3,963, 9/24/18 3 5,850STA 5: Vlv= Dome, Latch= RK, Port= 16, Dev= 47, TVD= 5,565, 9/24/18 4 7,295STA 4:Vlv= Dome, Latch= RK, Port= 16, Dev= 49, TVD= 6,563, 9/24/18 5 8,677STA 3:Vlv= S/O, Latch= RK, Port= 28, Dev= 49, TVD= 7,455, 9/24/18 6 9,902STA 2:Vlv= Dummy, Latch= RK, Port= 0, Dev= 48, TVD= 8,251 7 11,221STA 1:Vlv= Dummy, Latch= RK, Port= 0, Dev= 54, TVD= 9,095 8 11,6593.5 HES X Nipple, ID= 2.750 9 11,713Baker 9-5/8 x 4.5 S-3 Packer 10 11,7403.5 HES X Nipple, ID= 2.750 11 11,7603.5 HES XN Nipple, Min ID= 2.635 (11767 ELM) 12 11,7813.5 NSCT x 4.5 NSCT Crossover -Bottom @ 11,783 13 11,7834.5 NSCT x 4.5 NSCT Crossover -Bottom @ 11,785 14 11,785 Machined Overshot (4.5 of swallow on stub) -Bottom @ 11,792 15 11,794 TIW 9-5/8 HBBP Packer w/ Latch 16 11,899 5-1/2 OTIS X Nipple, ID=4.56 17 11,952 5-1/2 OTIS XN Nipple, ID=4.46 18 11,998 5-1/2 Pup w/ Mule Shoe Bottom @ 12,004 19 12,000 9-5/8 x 7 TIW Liner Packer 20 12,670 Baker 2.5 Inflatable Cement Retainer (Set 2/11/18) 21 12,750Baker 5-1/2 Baker K-1 Cement Retainer Btm @ 12,916 Set 9/23/1999 22 12,825 Baker 3-3/8 IBP Set 4/2/1998 23 12,882 5-1/2 Ext Casing Packer Bottom Element @ 12,916 24 14,497Form-A-Plug PERFORATION DETAIL Sands MD TVD FT Status Perforated Squeezed K2B 12,620 12,636 9,902 9,91016 Squeezed 4/10/1998 10/18/1999 12,620 12,636 9,902 - 9,91016 Open 10/28/1998 N/A 12,620 12,654 9,902 9,92034 Open 1/21/2010 N/A 12,654 12,664 9,920 9,92510 Squeezed 4/10/1998 10/18/1999 12,654 12,664 9,920 - 9,92510 Open 10/28/1999 N/A 12,678 12,698 9,932 9,94320 Squeezed 3/27/1998 10/18/1999 12,678 12,688 9,932 9,93810 Squeezed 2/13/2018 N/A 12,770 12,774 9,975 9,9774 Squeezed 2/17/19992 2/18/1992 12,874 12,878 10,013 - 10,0154 Squeezed 2/17/19992 2/18/1992 K2A 13,050 13,710 10,052 10,97660 Isolated 12/1/1987 N/A K1 13,962 13,995 10,112 10,11433 Isolated 12/2/1987 N/A 14,022 14,050 10,116 10,11828 Isolated 12/3/1987 N/A 14,210 14,261 10,131 10,13651 Isolated 12/4/1987 N/A 14,460 14,490 10,158 10,16130 Isolated 12/5/1987 N/A Ref. Log: MWD-GR on 11/87 OPEN HOLE / CEMENT DETAIL 13-3/83,254 cu/ft Permafrost in 17.5 Hole 9-5/8"1,150 cu/ft Class G in a 12-1/4 Hole 7112 cu/ft Class G in 8-1/2 Hole 51,095 cu/ft Class G in 8-1/2 Hole WELL INCLINATION DETAIL Max Hole Angle = 86.8 deg. @ 13,600 TREE & WELLHEAD Tree 4-1/16 CIW Wellhead FMC GENERAL WELL INFO API: 50-029-21751-00-00 Drilled & Completed 12/3/1987 Workover by Doyon 15 - 4/28/2001 SAFETY NOTE: H2S Reading Average 230 260 PPM on A/L & Gas Injectors. Well Requires a SSSV. Chrome Tbg/ Liner & Jewelry _____________________________________________________________________________________ Revised By: GP 12/30/2025 Duck Island Unit Well: END 3-15A Last Completed: 4/28/2001 PTD: SCHEMATIC GENERAL WELL INFO API: 50-029-21751-00-00 Drilled & Completed 12/3/1987 Completed by Doyon 15 - 4/28/2001 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 30"Conductor NA / NA / NA NA Surface 131 13-3/8Surface 68 / L-80 / Btrs 12.415 Surface 2,516 9-5/8"Intermediate 47 / N-80 / N/A 8.681 Surface 12,444 9-5/8"Intermediate 47 / NT95HS / N/A 8.681 12,44412,564 5-1/2Liner 17 / L-80 / Vam Ace 4.892 12,01412,654 2-3/8Liner 4.4/13Cr/H511 1.995 11,72315,283 TUBING DETAIL 3-1/2"Tubing 9.2 / 13CR-80 / Vam-Ace 2.992 Surface 11,785 5-1/2Tubing 17 / 13CR-80 / NSCC 4.890 11,78512,004 JEWELRY DETAIL No Depth Item 1 1,5213.5 OTIS XDB SSSV Landing Nipple, ID=2.75 GLM DETAIL: 3.5 x 1.5 Camco MMG Mandrel 2 3,965STA 6: Vlv= Dome, Latch= RK, Port= 16, Dev= 9, TVD= 3,963, 9/24/18 3 5,850STA 5: Vlv= Dome, Latch= RK, Port= 16, Dev= 47, TVD= 5,565, 9/24/18 4 7,295STA 4:Vlv= Dome, Latch= RK, Port= 16, Dev= 49, TVD= 6,563, 9/24/18 5 8,677STA 3:Vlv= S/O, Latch= RK, Port= 28, Dev= 49, TVD= 7,455, 9/24/18 6 9,902STA 2:Vlv= Dummy, Latch= RK, Port= 0, Dev= 48, TVD= 8,251 7 11,221STA 1:Vlv= Dummy, Latch= RK, Port= 0, Dev= 54, TVD= 9,095 8 11,6593.5 HES X Nipple, ID= 2.750 9 11,713Baker 9-5/8 x 4.5 S-3 Packer 10 11,7403.5 HES X Nipple, ID= 2.750 11 11,760 3.5 HES XN Nipple, Mill XN Nipple to 2.75 12 11,781 3.5 NSCT x 4.5 NSCT Crossover -Bottom @ 11,783 13 11,783 4.5 NSCT x 4.5 NSCT Crossover -Bottom @ 11,785 14 11,785 Machined Overshot (4.5 of swallow on stub) -Bottom @ 11,792 15 11,794 TIW 9-5/8 HBBP Packer w/ Latch 16 11,899 5-1/2 OTIS X Nipple, ID=4.56 17 11,952 5-1/2 OTIS XN Nipple, ID=4.46 18 11,998 5-1/2 Pup w/ Mule Shoe Bottom @ 12,004 19 12,000 9-5/8 x 7 TIW Liner Packer PERFOATION DETAIL Sands MD TVD FT Status Perforated Squeezed K2B t t t OPEN HOLE / CEMENT DETAIL 13-3/83,254 cu/ft Permafrost in 17.5 Hole 9-5/8"1,150 cu/ft Class G in a 12-1/4 Hole 7112 cu/ft Class G in 8-1/2 Hole 51,095 cu/ft Class G in 8-1/2 Hole WELL INCLINATION DETAIL Max Hole Angle = TREE & WELLHEAD Tree 4-1/16 CIW Wellhead FMC SAFETY NOTE: H2S Reading Average 230 260 PPM on A/L & Gas Injectors. Well Requires a SSSV. Chrome Tbg/ Liner & Jewelry Map Date: 6/8/2025NAD 1927 StatePlane Alaska 4 FIPS 5004 True Vertical Depth (100 usft/in)5400 5600 5800 6000 6200 6400 6600 6800 7000 7200 7400 7600 7800 8000 8200 8400 8600 8800 9000 9200 South(-)/North(+) (1000 usft/in)1500 2000 2500 3000 3500 4000 4500 5000 5500 Well Date Quick Test Sub to Otis - Top of 7" Otis 0.0 ft Distances from top of riser Excluding quick-test sub Top of Annular CL Annular Bottom Annular CL Blind/Shears CL Coiled Tubing Pipe / Slips Kill Line Choke Line CL BHA Pipe / Slip CL Coiled Tubing Pipe / Slips TV1 TV2 T1 T2 Flow Tee Master Master LDS IA OA LDS Ground Level CDR#-AC BOP Schematic CDR Rig's Drip Pan Fill Line Normally Disconnected HP hose to Micromotion LP hose open ended to Flowline (optional) Hydril 7 1/16" Annular Blind/Shear CT Pipe/Slips 2 3/8" Pipe/Slips 2 3/8" Pipe/Slips 7-1/16" 5k Mud Cross CT Pipe/Slips BHA Pipe / Slips nneeeeeceeeeeeeeeeeeeeeeeeeeeeeeeeeeeee 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. ENDICOTT 225-146 DIU SDI 3-15A ENDICOTT OIL WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name: DUCK IS UNIT SDI 3-15AInitial Class/TypeDEV / PENDGeoArea890Unit10450On/Off ShoreOffProgram DEVWell bore segAnnular DisposalPTD#:2251460Field & Pool:ENDICOTT, ENDICOTT OIL - 220100NA1 Permit fee attachedYes ADL047502 and ADL0475032 Lease number appropriateYes3 Unique well name and numberYes ENDICOTT, ENDICOTT OIL - 220100 - governed by CO 4624 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) (For sNA15 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)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitYes *Variance as per 20 AAC 25.112(i): Approved for alternate abandonment plug placement w/ fully cemented liner.25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes *Variance to 20 AAC 25.036 (c)(2)(A)(iv) with compliance to rules in CO 823.29 BOPEs, do they meet regulationYes 5K.30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes The last H2S reading on DIU SDI 3-15: 430 ppm on 1/10/2025.33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)No Endicott Pool wells are H2S-bearing. H2S measures are required.35 Permit can be issued w/o hydrogen sulfide measuresYes Kekiktuk reservoir expected to be under-pressured at about 7.3 ppg.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]ApprADDDate1/5/2026ApprJJLDate1/16/2026ApprADDDate1/5/2026AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 1/16/2026