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Home My WebLink About226-002Alaska 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, Eider Oil Pool, DIU MPI 2-56B Hilcorp Alaska, LLC Permit to Drill Number: 226-002 Surface Location: 3193' FSL, 2333' FEL, Sec. 36, T12N, R16E, UM, AK Bottomhole Location: 2445' FSL, 108' FEL, Sec. 28, T12N, R16E, 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, Jessie L. Chmielowski Commissioner DATED this th day of 2026. Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2026.01.13 17:00:06 - 09'00' Sean McLaughlin (4311) 226-002 By Grace Christianson at 8:27 am, Jan 14, 2026 SFD 2/2/2026 By Grace Christianson at 8:27 am, Jan 14, 2026 DSR-1/22/26 *Variance 20 AAC 25.036 (c)(2)(A)(iv) with compliance to rules in CO 823 *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. *Variance to 20 AAC 25.412(b) for packer depth with CBL and cement to top of liner. *AOGCC Witnessed BOP Test to 4000 psi, Annular 2500 psi minimum. *Post rig service coil perforating approved for max gun length of 500'. *Window milling approved on service coil. *FIT after window is milled and 10-20' of formation cut. 50-029-22863-02-00 *Ensure mitigations and controls in place for high H2S. *CBL to demonstrate isolation of the injected fluids to the approved interval. Send results to AOGCC. J.Lau 2/4/26 ByBy GrraceGrace ChristiansosonChrriistianson atat 8:8:278:28:7 am,am,JanJan 14,14,2020226622202206By Grace Christianson at 8:27 am, Jan 14, 2026 02/05/26 02/05/26 Area of Review F-69PTD API WELL STATUSTop of PoolIsolatingStage(s) TOC Method TOC Determined Losses Returns verified Zonal IsolationComments198188 50-029-22228-01 END 2-30APlugged andAbandoned15,840' MD /-9472 SSTVD/9528 TVDFirst stage of 7"Intermediatecasing13,005' MDVolumetrics, 1st stage: 84bbls 15.8 ppg Class G w/30% washoutNot reported No YesData used in this analysis came exclusively from theAOGCC 10-407.198204 50-029-22863-00 END 2-56Plugged andAbandoned16,455' MD /-9398 SSTVD/9,452' TVDFirst stage of 7"Intermediatecasing15,162' MDVolumetrics, 1st stage: 41bbls 15.8 ppg Class G w/30% washoutNot reported No YesData used in this analysis came exclusively from theAOGCC 10-407.198058 50-029-22863-01 END 2-56AOperableArtificial LiftProducer16,784' MD /-9431 SSTVD/ 9486 TVDFirst stage of 4-1/2" Liner16,020' MD CBL of 2/27/1999 Not reported No YesSingle stage, single slurry cement job. TOC pick fromCBL.224-024 50-029-23785-00 END 2-74Not OperableProducer14,648' MD /-9428 SSTVD/ 9469 TVDFirst stage of 7"Intermediatecasing13,895' MDVolumetrics, 1st stage: 24bbls 15.8 ppg Class G w/30% washoutNone Yes - 100% returns YesSingle stage, single slurry cement job. TOC calculatedvolumetrically using a 30% wash out.Area of Review END 2-56BAgree: The Eider Oil Pool isolated by casing and cement from overlying strata in these wells within the AOR and in their associated plugbacks. SFD To: Alaska Oil & Gas Conservation Commission From: Ryan Ciolkosz Drilling Engineer Date: January 13, 2026 Re:MPI 2-56B Permit to Drill Approval is requested for drilling a CTD sidetrack lateral from well 2-56A with the Nabors CDR2/CDR3 Coiled Tubing Drilling. Proposed plan for MPI 2-56B Injector: See 2-56A Sundry request for complete pre-rig details - Prior to drilling activities, screening will be conducted to drift for whipstock. E-line will set a 4-1/2" whipstock. If unable to set the whipstock pre-rig, the rig will perform that work. A coil tubing drilling sidetrack will be drilled with the Nabors CDR3/CDR2 rig. The rig will move in, test BOPE and kill the well. If unable to pre-rig, the rig will set the 4-1/2" whipstock and mill 3.80" window + 10' of formation. The well will kick off drilling in the HRZ and top set the Sag River with a 3-1/4" pre-perforated liner. CDR3 will then freeze protect the well and rig down move off to 2-74A Sidetrack (Approximately 20 days). CDR3 will return to 2-56B, move in, test BOPE and kill the well. The rig will then mill out the 3-1/4" aluminum shoe with a 2.74" mill. The 3.25" lateral will be drilled through the upper and lower Ivishak. The proposed sidetrack will be completed with a 3-1/2"x2-3/8 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 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 2-56A Sundry submitted in concert with this request for full details. 1 Fullbore MIT-T and CMIT TxIA (done, passed to 3850 psi/3708 psi respectively) 2 Coiled Tubing Mill XN, FCO 3 Slickline Drift f/ WS, Caliper tbg/liner. Run SCMT CBL from planned KOP to tubing tail. 4 E-Line Set 4-1/2" Whipstock at 16,580' MD at 180 degrees ROHS 5 Valve Shop Pre-CTD Tree Work 6 Operations Remove wellhouse and level pad. Rig Work: (Estimated to start in Feb 20, 2026) 1 MIRU and test BOPE 250 psi low and 4000 psi high (MASP 3610 psi). Give AOGCC 24hr notice prior to BOPE test. 2 Mill 3.80 Single String Window 3 Drill 4.25" OH to Top Sag River, ~150' (15 deg DLS planned). 4 Run 3-1/4" pre-perforated Liner with aluminum bullnose shoe to TD 5 Release off liner, freeze protect well. Close Tree, RDMO to 2-74 6 MIRU and test BOPE 250 psi low and 4000 psi high (MASP 3610 psi). Give AOGCC 24hr notice prior to BOPE test. 7 Mill out aluminum shoe with 2.74" mill. 8 Drill Build section: 3.25" OH, ~134' (15 deg DLS planned). 9 Drill production lateral: 3.25" OH, ~1387' (12 deg DLS planned). Swap to KWF for liner. 10 Run 3-1/2 x 2-3/8 13Cr solid liner , , g 3.25" lateral will be drilled through the upper and lower Ivishak. p g, g p kick off drilling in the HRZ and top set the Sag River with a 3-1/4" pre-perforated liner. , p y p p g ( This completion will completely isolate and abandon the parent perfs. 11 Pump primary cement job*: 20 bbls, 15.3 ppg Class G, 1.24 (ft3/sk), TOC at TOL. 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). 12 Only if not able to do with service coil extended perf post rig Perforate Liner with 1" or 1-1/4" CS Hydril 13 Freeze protect well to a min 2,200' TVD. 14 Close in tree, RDMO. Post Rig Work: 1 Valve Shop Valve & tree work. 2 Slickline SBHPS, set LTP* (if necessary). AOGCC Witnessed MIT. Set live GLVs. 3 Service Coil Post rig RPM, CBL, and perforate (~1000) - see extended perf procedure attached. 4 Testing Portable test separator flowback. 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: 4.25 Hole MPD Pressure at the Planned Window (16,570 MD -9404' TVD) Pumps On Pumps O A Target BHP at Window (ppg)5770 psi 5770 psi 11.8 B - 994 psi 0 psi 0.09 C 4646 psi 4646 psi 9.5 B+C Mud + ECD Combined 5640 psi 4646 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain 131 psi 1125 psi Target BHP at window and deeper minimum 8.4 ppg drilling fluid g g Managed pressure drilling techniques will be employed on this wellg q 3.25 Hole MPD Pressure at the Planned Shoe (16,740 MD - 9507' TVD) Pumps On Pumps O A Target BHP at Shoe (ppg)4845 psi 4845 psi 9.8 B -597 psi 0 psi 0.035 C 4252 psi 4252 psi 8.6 B+C Mud + ECD Combined 4848 psi 4252 psi (no choke pressure) A-(B+C)Choke Pressure Required to Maintain -3 psi 593 psi Target BHP at window and deeper Operation Details: Reservoir Pressure: The estimated reservoir pressure is expected to be 4580 psi at 9700 TVDSS. (9.1 ppg equivalent). Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 3610 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: 4.25" for shale drilling and 3.25" hole for the entirety of the production hole section. Liner Program: 3-1/4", 6.6#, L80 pre-perforated: 16,480' MD 16,720 MD (240' liner) 3-1/2", 9.2#, 13Cr solid: 16,105' MD 16,470 MD (365' liner) 2-3/8", 4.6#, 13Cr solid: 16,470' MD 18,300 MD (1830' 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. 20 AAC 25.030 (d)(5) intermediate and production casing must be cemented with sufficient cement to fill the annular space from the casing shoe to a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, above all significant hydrocarbon zones and abnormally geo-pressured strata or, if zonal coverage is not required under (a) of this section, from the casing shoe to a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, above the casing shoe; if indications of improper cementing exist, such as lost returns, or if the formation integrity test shows an inadequate cement job, 20 AAC 25.030 (c)(5) production casing must be set and cemented through, into, or just above the production interval; 20 AAC 25.030 (c)(6) slotted liners, pre-perforated liners, and screens installed below a production packer are considered production equipment and not casing. The window will be milled and 02-56B kicked off in the HRZ shale at 16,570 MD (9404 TVDss). Records indicate that 60 bbls of 15.8 Class G cement were pumped behind the 4-1/2 liner in the 02-56A wellbore. No Losses were reported while cementing. A CBL run on 02/27/1999 indicates TOC at 16,020 MD. This provides ~550 MD and 328 TVD of lateral cement isolation behind the 4-1/2 liner just above the top of reservoir. Hilcorp Requests a variance to 20 AAC 25.412(b):.The packer must be placed within 200 feet measured depth above the top of the perforations, unless the commission approves a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone. The current MPI 2-56A packer was set at 15,119 MD. This is ~1593 MD above the predicted top of pool (Sag River) at 16,715 MD. MPI 2-56A was previously converted to an injector and converted back to a producer in 2004. No integrity anomalies have been noted on this well. A CBL run on 02/27/1999 indicates TOC at 16,020 MD. This provides ~550 MD and 328 TVD of lateral cement isolation behind the 4-1/2 liner just above the top of reservoir. In addition, records indicate that 41 bbls of cement was displaced behind the 7 casing with a calculated cement top at ~15,055 MD. No losses were noted in the report while cementing. 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 02-74A. 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). * 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 91°. Inclination at kick off point is 65°. Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. Distance to nearest property line 200 Distance to nearest well within pool 800' 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: ~1000' 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 Eider Pool. Formations: Top of Eider pool at 16,742 MD in the parent Anti-Collision Failures: All Wells Pass AC scan 02-56B SFD Hazards: DS/Pad is an H2S pad. The last H2S reading on 2-56A: 425 ppm on 01/04/2025. Max H2S recorded on DS/Pad: 550 ppm. 2 fault crossings expected. Low lost circulation risk. Ryan Ciolkosz CC: Well File Drilling Engineer Joseph Lastufka (907-244-4357) 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 9.2 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 9.2 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 Eider 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 1/13/2026 SCHEMATIC Endicott Unit Well: END 2-56A Last Completed: 5/28/1998 PTD: 198-058 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 30"Conductor N/A / N/A / N/A N/A Surface 160'NA 9-5/8"Surface 47# / L80 / BTC 8.861 Surface 7,0800.0732 7"Intermediate 29# / L80 /BTC 6.184 Surface 15,9580.0371 4-1/2"Liner 12.6# / 13Cr / NSCT 3.958 15,65217,9880.0152 TUBING DETAIL 4-1/2Tubing 12.6#/ L80 / IBM 3.958 Surface 15,1760.0152 JEWELRY DETAIL No Depth Item 1 1,5744-1/2 SSSV Landing Nipple HES HXO, ID= 3.813 Gas Lift Mandrels Detail 4-1/2 X 1 Camco KBG-2-LS Mod 2 5,101ST 6: Dev.= 60, Latch = INT, TVD= 3,546, VLV = Dome, 4/7/05 3 8,748ST 5: Dev.= 62, Latch = INT, TVD= 5,298, VLV= SO, 11/12/05 4 10,902ST 4: Dev.= 61, Latch = INT, TVD= 6,350, VLV = DMY, 5/28/98 5 12,320ST 3: Dev.= 59, Latch = INT, TVD= 7,058, VLV = DMY, 5/28/98 6 13,699ST 2: Dev.= 59, Latch = INT, TVD= 7,757, VLV = DMY, 5/28/98 7 15,040ST 1: Dev.= 59, Latch = INT, TVD= 8,450, VLV = DMY, 5/28/98 8 15,108 HES X Nipple, ID = 3.813 9 15,119 7 Baker S-3 Packer 10 15,142 HES X Nipple, ID = 3.813, pulled baited prong and plug 10/29/2025 11 15,164 HES XN Nipple, ID = 3.725 12 15,175 WLEG, ID = 3.958, Bottom @ 15,176 13 15,652 ZXP Liner Top Packer and Hanger, ID= 4.25 14 17,000 4-1/2 CIBP (5/9/2013) 15 17,585 4-1/2 WFD CIBP (10/29/2005) 16 17,693 4-1/2 BKR CIBP (7/3/2004) PERFORATION DETAIL END Oil Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Sag 16,790 16,850 9,488 9,51160 3/31/13 Open Sag 16,890 16,980 9,526 9,56090 3/31/13 Open UPR IVI 17,400 17,420 9,724 9,73320 10/30/05 Closed UPR IVI 17,410 17,430 9,729 9,73720 11/7/04 Closed MID IVI 17,610 17,630 9,814 9,82320 7/3/04 Closed LWR IVI 17,714 17,904 9,861 9,958190 5/25/98 Closed CASING SIZE / CEMENT DETAIL 30Driven 9-5/82,008 sx Lite Lead PF, 250 sx G in 12- 1/4 Hole 7200 sx Class G in 8-1/2 Hole 4-1/2293 sx Class G in 6 Hole WELL INCLINATION DETAIL Max Hole Angle = 68 deg. @ 16,637 Angle at Top Perf = 67Deg @ 16,790 TREE & WELLHEAD Tree 4-1/16, 5,000psi, Cameron Wellhead 11, 5,000psi, Gen. V GENERAL WELL INFO API: 50-029-22863-01-00 Original TD Reached 3/15/1998 Sidetrack TD Reached 5/17/1998 Original Completion 5/28/98 SAFETY NOTES H2S Readings Average 230-260 PPM on A/L & Gas Injectors. Well requires as SSSV. 4-1/2 chrome Nipples and Liner. _____________________________________________________________________________________ PROPOSED SCHEMATIC Duck Island Unit Well: END 2-56B Last Completed: TBD PTD: TBD TD = 1 (MD) / TD = 9,840(TVD) 30 KBE = 54.7, GL = 14.0 7 2 PBTD = 18,250 (MD) / PBTD = 9,841(TVD) 11 9-5/8 3 4 5 6 7 9 10 12 13 8 ES Cementer @ 1,915' 4-1/2 Whipstock @ 16,570 op protection ng at 16,480 MD 3-1/2 x 2-3/8 XO @ 16,470 Mill XN to 3.80 3-1/4 Pre- Perforated Liner (Protection String) at 16,720 TOL/TOC at 16,105 2-3/8 Solid Liner at 18,293 MD 1 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 30"Conductor N/A / N/A / N/A N/A Surface 160'NA 9-5/8"Surface 47# / L80 / BTC 8.861 Surface 7,0800.0732 7"Intermediate 29# / L80 /BTC 6.184 Surface 15,9580.0371 4-1/2"Liner 12.6# / 13Cr / NSCT 3.958 15,65217,9880.0152 3-1/4Protection 6.6# / 13Cr / TCII 16,480 16,720 3-1/2 x2-7/8Liner 9.3#x6.5#/13Cr/STLxH511 16,105 18,300 TUBING DETAIL 4-1/2Tubing 12.6#/ L80 / IBM 3.958 Surface 15,1760.0152 JEWELRY DETAIL No Depth Item 1 1,5744-1/2 SSSV Landing Nipple HES HXO, ID= 3.813 Gas Lift Mandrels Detail 4-1/2 X 1 Camco KBG-2-LS Mod 2 5,101ST 6: Dev.= 60, Latch = INT, TVD= 3,546, VLV = Dome, 4/7/05 3 8,748ST 5: Dev.= 62, Latch = INT, TVD= 5,298, VLV= SO, 11/12/05 4 10,902ST 4: Dev.= 61, Latch = INT, TVD= 6,350, VLV = DMY, 5/28/98 5 12,320ST 3: Dev.= 59, Latch = INT, TVD= 7,058, VLV = DMY, 5/28/98 6 13,699ST 2: Dev.= 59, Latch = INT, TVD= 7,757, VLV = DMY, 5/28/98 7 15,040ST 1: Dev.= 59, Latch = INT, TVD= 8,450, VLV = DMY, 5/28/98 8 15,108 HES X Nipple, ID = 3.813 9 15,119 7 Baker S-3 Packer 10 15,142 HES X Nipple, ID = 3.813 11 15,164 HES XN Nipple, ID = 3.725 Milled XN to 3.80 pre-rg 12 15,175 WLEG, ID = 3.958, Bottom @ 15,176 13 15,652 ZXP Liner Top Packer and Hanger, ID= 4.25 PERFORATION DETAIL END Oil Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status CASING SIZE / CEMENT DETAIL 30"Driven 9-5/8"2,008 sx Lite Lead PF, 250 sx G in 12- 1/4 Hole 7"200 sx Class G in 8-1/2 Hole 4-1/2293 sx Class G in 6 Hole WELL INCLINATION DETAIL Max Hole Angle = 68 deg. @ 16,637 Angle at Top Perf = 67Deg @ 16,790 TREE & WELLHEAD Tree 4-1/16, 5,000psi, Cameron Wellhead 11, 5,000psi, Gen. V GENERAL WELL INFO API: 50-029-22863-02-00 Original TD Reached 3/15/1998 Sidetrack TD Reached 5/17/1998 Original Completion 5/28/98 CDR2 B ST- TBD SAFETY NOTES H2S Readings Average 230-260 PPM on A/L & Gas Injectors. Well requires as SSSV. 4-1/2 chrome Nipples and Liner. 8,300 Duck Island Unit Prudhoe Bay Unit ADL312828 ADL034636 ADL034634 ADL034633 ADL028337 ADL390314 Sec. 14Sec. 16 Sec. 22 Sec. 35 Sec. 24 Sec. 21 Sec. 15 Sec. 23 Sec. 25Sec. 26 Sec. 13 Sec. 33 Sec. 4 Sec. 27 Sec. 11 Sec. 3 Sec. 12 Sec. 28 Sec. 36 Sec. 34 Sec. 9 Sec. 2 Sec. 10 Sec. 1 Sec. 18 (583) Sec. 19 (585) Sec. 30 (588) Sec. 7 (596) Sec. 6 (593) Sec. 31 (591) U012N016E U012N017E U011N016E MPI ENDEAVOR ISLAND 2-56B_SHL 2-56B_TPH2-56B_BHL Legend Well_Desc 2-56B_BHL 2-56B_SHL 2-56B_TPH Other Surface Holes (SHL) Other Bottom Holes (BHL) Other Well Paths Pad Footprint Oil and Gas Unit Boundary Map Date: 1/13/2026 0 1,100 2,200 Feet Document Path: O:\AWS\GIS\Dropbox\Julieanna Potter\Project_Handoff\Project_Handoff.aprxDuck Island Unit MPI 2-56B wp021:33,000 Plan: 2-56B True Vertical Depth (400 usft/in)12200 12400 12600 12800 13000 13200 13400 13600 13800 14000 14200 14400 14600 14800 15000 15200 15400 15600 15800 16000 South(-)/North(+) (1000 usft/in)-15000 -14500 -14000 -13500 -13000 -12500 -12000 -11500 -11000 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 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Ryan Ciolkosz To:Davies, Stephen F (OGC) Cc:Dewhurst, Andrew D (OGC); Starns, Ted C (OGC); Joseph Lastufka Subject:RE: [EXTERNAL] DUCK IS UNIT MPI 2-56B (PTD 226-002) - Question Date:Friday, January 30, 2026 9:13:07 AM Attachments:image001.png Steve, 2-56B will not be pre-produced, just at brief post drilling and completion well cleanup. Let me know if you have any other questions. Thanks, Ryan Ciolkosz Drilling Engineer | C: 907.244.4357 3800 Centerpoint Dr. Suite 1400 | Anchorage, Alaska 99503 44.4357 | O: 907.564.4413 H From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Thursday, January 29, 2026 3:26 PM To: Ryan Ciolkosz <ryan.ciolkosz@hilcorp.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov> Subject: [EXTERNAL] DUCK IS UNIT MPI 2-56B (PTD 226-002) - Question Ryan, I'm reviewing Hilcorp's Sundry Application for the planned DUCK IS UNIT MPI 2-56B injector and I have a question. Will this well be pre-produced for an extended period, or will it be simply flowed back briefly for cleanup? Thanks and Be Well, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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. DIU MPI 02-56B Endicott Eider Oil 226-002 WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name: DUCK IS UNIT MPI 2-56BInitial Class/TypeSER / PENDGeoArea890Unit10450On/Off ShoreOffProgram SERWell bore segAnnular DisposalPTD#:2260020Field & Pool:ENDICOTT, EIDER OIL - 220165NA1 Permit fee attachedYes Surface Location lies within ADL0034633; Top Prod Int & TD lie within ADL0034634.2 Lease number appropriateYes3 Unique well name and numberYes ENDICOTT, EIDER OIL - 220165 - governed by CO 4494 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 waitYes14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For sYes15 All wells within 1/4 mile area of review identified (For service well only)No CPAI email dated 30-Jan: Well will not be pre-produced.16 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 82329 BOPEs, do they meet regulationYes 5K30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes CTD will leave after running protection and return to drill lateral.32 Work will occur without operation shutdownYes Ensure mitigations in place for High H2S33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)No H2S Measures Required: High risk; 425 ppm H2s measured in Jan 2025; see p. 9.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure is 0.473 psi/ft (9.1 ppg EMW). Operator's planned mud and MPD programs36 Data presented on potential overpressure zonesNA appear sufficient to control anticipated pressures and maintain wellbore stability.37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate2/2/2026ApprJJLDate2/3/2026ApprSFDDate1/23/2026AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 2/5/2026