The URL can be used to link to this page

Home My WebLink About220-0431. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: CTCO, N2 Development Exploratory 3. Address:Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 7,485 feet 5,757 feet true vertical 6,949 feet 5,715 (fill) feet Effective Depth measured 5,742 feet 2,494 feet true vertical 5,235 feet 2,312 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)N/A N/A N/A N/A Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 2,494' MD 2,312' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: 8,730psi 2,980psi 5,750psi 10,600psi 2,739'2,526' Burst Collapse 1,410psi 3,090psi Production Liner 7,475' Casing Structural 6,759'7,475' 120'Conductor Surface Intermediate 16" 9-5/8" 120' 2,739' measured TVD 5-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-043 50-283-20180-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL021128 Beluga River / Sterling-Beluga Gas Beluga River Unit (BRU) 222-24 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 5 Size 120' 0 51816 0 6400 62 Chad Helgeson, Operations Engineer 325-216 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A chelgeson@hilcorp.com 907-777-8405 p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 1:32 pm, May 16, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.05.16 11:40:01 - 08'00' Noel Nocas (4361) RBDMS JSB 052125 BJM 8/12/25 DSR-6/3/25 Page 1/1 Well Name: BRU 222-24 Report Printed: 5/16/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-283-20180-00-00 Field Name:Beluga River State/Province:ALASKA Permit to Drill (PTD) #:220-043 Sundry #:325-216 Rig Name/No: Jobs Actual Start Date:3/20/2025 End Date: Report Number 10 Report Start Date 4/20/2025 Report End Date 4/21/2025 Last 24hr Summary PJSM, Crew travel to location, Rig down & mob to K-pad, Spot in & rig up, Work valves & grease to seal, Nipple up lube & BOPE, Secure well for the night. Report Number 11 Report Start Date 4/21/2025 Report End Date 4/22/2025 Last 24hr Summary PJSM, Crew travel to location, Load & test lines, Perform shell test 3000 psi-good, Perform BOPE test 250-low, 3000-high, Witness waived by Jim Regg, Batch mix 90 bbls 6% kcl w/ 3 gal condent, Make up BHA (1 x nozzle 3.4, 1 x 2.12 x 5' monel, 1 x coil connector), Run in the hole to dry tag @ 3523, Pick up establish circulation with 500scfs/min with .4 bbls of 6% kcl, Run in hole & Wash down f/ 3523'-t/3560', Short trip to 2700', Wash f/2700'-t/4211', Circulate bottoms up, Pull out of the hole, Secure well, Lay down lube & injector for the night Report Number 12 Report Start Date 4/22/2025 Report End Date 4/23/2025 Last 24hr Summary R/u Slick line. PT lubricator 250/3000psi, good test. SITP 727psi. RIH w/ 3.7" LIB, tag at 3500'KB, see 200# overpull, falls off at 3320' KB. POOH, wire marks on LIB. RIH w/, 3 prong wire grab, grab wire at 3320' KB. POOH w/ ~50' of wire. RIH w/ 3.7" LIB, tag at 4197' KB, POOH with impression of side of rope socket and wire. RIH w/ 3 prong wire grab, sat down at 4208' KB. POOH w/ ~2' of wire. RIH w/ 3.7" LIB, tag at 4197' KB, POOH w/ impression of clean rope socket. RIH w/ 2-12" JDC w/3-1/4" bell guide, latch fish at 4197' KB, p/u and set off jars, POOH w/ fish, full recovery. RIH w/ 3.7" LIB, tag at 4220' KB, POOH, LIB clean. Secure well. Final SITP 612psi. R/d slick line. Report Number 13 Report Start Date 4/23/2025 Report End Date 4/24/2025 Last 24hr Summary PJSM, Crew travel to location, Pick up injector & lube, Pick up BHA 3.7" nozzle, 2.12" monel, 2.12” check valve, Pressure test 3000-good, Run in the hole, Check weight @ 3000', Kick in N2 @ 400 scfs/min with .4 BPM fluid, Tag @ 4254', Wash hard fill f/ 4254-t/5715, Kick out fluid & blow well dry, Pull out of hole, Lay down lube & injector, Nipple down BOPE, Secure well for the night Report Number 14 Report Start Date 4/24/2025 Report End Date 4/25/2025 Last 24hr Summary PJSM, Crew travel to location, Rig down and stage equipment at edge of location, Transfer fluids to disposal. Fox released Updated by DMA 05-14-25 SCHEMATIC Beluga River Unit BRU 222-24 PTD: 220-043 API: 50-283-20180-00-00 PBTD = 7,388’ MD / TVD = 6,854’ TD = 7,485’ MD / TVD = 6,949’ RKB to GL = 18’ PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Comments Bel G1 5,289’ 5,293’ 4,800' 4,804' 4' 8/8/2024 Open Bel G1 5,296’ 5,301’ 4,806' 4,811' 5' 8/8/2024 Open Bel G1 5,314’ 5,320’ 4,823' 4,829' 6' 8/8/2024 Open Bel G2 5,345’ 5,352’ 4,853' 4,859' 7' 8/8/2024 Open Bel H2 5,657’ 5,673’ 5,152' 5,168' 16' 8/8/2024 Open Bel H5 5,767' 5,786' 5,260' 5,269' 9' 8/7/2020 Plugged Bel H12 6,044' 6,057' 5,531' 5,544' 13' 8/7/2020 Plugged Bel H15 6,175' 6,195' 5,659' 5,679' 20' 8/7/2020 Plugged Bel I2 6,336' 6,343' 5,817' 5,824' 7' 8/7/2020 Plugged Bel I6 6,472' 6,493' 5,951' 5,972' 21' 8/7/2020 Plugged CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,739’ 5-1/2" Prod Csg 17 P-110 ICY TXP BTC 4.892” Surf 7,475’ 1 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,494’ - - Swell Packer 2 5,757’ - - CIBP w/ 15ft of cement. TOC @ 5,742’ 08/01/24 8-1/2” hole Bel H5 Bel I2, I6 Tag fill at 5820’ (11-11-22) Bel H12 Bel H15 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface (45 bbls to surface 10/2/22) 4-1/2” CBL TOC @ 3260’ (10/23/22) Notes: Restriction unable to mill through at 5838’. Tight spot @ 5791’. SL tool string stuck POOH @ 3520’. Dropped cutter bars (cut wire @ ~3086’) Bel G1 Bel H2 Bel G2 2 Tagged fill 5715 on 4/23/25 Fish 3610’ SL tools recovered. -bjm 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,485'3,520' Casing Collapse Structural Conductor 1,410psi Surface 3,090psi Intermediate Production 8,730psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Other: CTCO, N2 chelgeson@hilcorp.com 907-777-8405 Chris Kanyer, Asset Team Leader Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL021128 220-043 50-283-20180-00-00 Hilcorp Alaska, LLC Proposed Pools: N/A TVD Burst N/A 10,600psi 2,526' Size 120' 2,739' MD See Schematic 2,980psi 5,750psi 120'120' 2,739' April 24, 2025 N/A 7,475' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 222-24CO 802A Same 6,759'5-1/2" 2,053psi 7,475' N/A Length Swell Pkr & N/A 2,494 (MD) 2,312 (TVD) & N/A 6,949' 3,520' 3,215' Beluga River Sterling-Beluga Gas 16" 9-5/8" See Schematic No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 325-216 By Gavin Gluyas at 8:04 am, Apr 11, 2025 Digitally signed by Chris Kanyer (1235) DN: cn=Chris Kanyer (1235) Date: 2025.04.10 16:58:32 - 08'00' Chris Kanyer (1235) A.Dewhurst 11APR25 10-404 DSR-4/11/25 CT BOP test to 3000 psi. If plugs are set, dump bail 25' of cement on top of plug before adding perforations. BJM 4/14/25 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.14 16:52:16 -08'00'04/14/25 RBDMS JSB 041525 Well Prognosis Well Name: BRU 222-24 API Number: 50-283-20180-00-00 Current Status: SI Gas Well Permit to Drill Number: 220-043 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Scott Warner (907) 830-8863 Maximum Expected BHP:2235 psi @ 5198’ TVD (Based on 0.43 psi/ft gradient)) Max. Potential Surface Pressure:2053 psi (Based on 0.035 psi/ft gas gradient to surface) Applicable Frac Gradient:0.706 psi/ft using 13.57 ppg EMW FIT at 2524TVD 7/8/20 Shallowest Potential Perf TVD:MPSP/(0.706-0.035) = 2053 psi / 0.671 = 3059‘ TVD Top of Pools per CO 802a:Sterling-Beluga Gas Pool: 3,309’ MD, ~3027' TVD Well Status:SI gas well with a SL fish & wire Brief Well Summary: 222-24 was drilled in 2020 and completed as a Beluga H and I producer. The well location is close to the crest of the H and I sands. The well was completed as a 5.5” monobore in the Beluga H and I sands. The Beluga H sands were plugged/isolated in 2024 and additional G sands were perforated. The rate was very flat at 2 mmscfd and went to 0mcfd on March 11th. SL was put on the well, and while POOH the tools became stuck. SL cutter bars were deployed to free the wire. SL began fishing operations of the wire and have recovered ~400 of wire from the well, and we expect there to be an additional ~50ft of wire in the well with a 22’ SL tool string in well. Below this tool string, there is also a sand bridge above the perforations. The objective of this sundry is to cleanout & recover the fish, blow well dry with N2 and add more perforations to return the well to production. All proposed sands lie in the Sterling-Beluga Gas Pool. Wellbore Conditions: Current flowrate: SI, TP- 597 psi The well is a 5.5” monobore Current open perfs to Beluga G1-H2 Sands @ 5289-5168’ SL tag depth: 3449’ on 4/10/25 SL Fish in well – Tool string @ 3520’ is a 2.5” DD bailer with 1.75” OD tool string (22’ OAL) Procedure: 1. Review all approved COAs 2. MIRU Fox Coil Tubing unit with 1.75” Coil and pressure control equipment (enough lubricator to cover tools and 22’ fish) 3. PT lubricator to 250 psi low/ 3000 psi high a. Provide AOGCC 48 hr notice for BOP test 4. RIH and clean out wellbore to top of fish (~3520’ MD), keep well full with 8.4 ppg water (6% KCl) 5. POOH and PU fish assembly 6. RIH and fish SL tool string with coil x Latch/bait fish w/ SL if necessary x Potential when fishing wire that the SL tools come with wire and are longer than the lubricator Contingency (Open Hole fishing procedure If unable to close well with fish attached to coil -i.e. fish is too long) i. Once fish at surface and valves will not close Well Prognosis ii. Confirm fluid at surface by pumping across flow cross iii. Shut down pump and monitor well for 15 minutes (no flow check) iv. Hold safety meeting 1. Crew and WSS to discuss plan and procedure in case of kick with lubricator removed 2. Review kick contingencies and cover the following options: a. Lift fish clear and close tree valves valves b. Lift fish clear and close BOP shear valves c. Stab back on to well v. Once well is confirmed dead and personnel monitoring trip tank while pumping across flow cross vi. Break off lubricator and lift tool string out of well. vii. Once tool string clear of tree valves close swab. 7. Once fish is removed, PU wash nozzle, RIH and clean well out to CIBP at 5757’ with 6% KCl water 8. Once cleanout is complete, blow well down with N2 maintaining 250 psi of back pressure and pumping at rate around 1000sfm (pump gel sweeps as necessary for hole cleaning) a. Coil reel volume ~ 36 bbls (0.0023 bbl/ft x 16000ft) b. Coil/tubing annulus = 116.7 bbls (0.0203 bbl/ft x 5757ft) c. Recover an estimated 153 bbls of fluid 9. SI well and pressure up to 500 psi with N2 10. MIRU E-line and pressure control equipment 11. PT lubricator to 250psi low / 2500psi high 12. Ops will bleed pressure off well to planned perforating pressure determined by OE/RE 13. Perforate and test Beluga sands within the interval below, from the bottom up: Well Prognosis a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. b. Pending well production, all perf intervals may not be completed c. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations d. Above perfs are in the Sterling-Beluga Gas Pool governed by CO 802A 14. RDMO Eline Formation MD TOP MD BASE TVD TOP TVD BASE H Top Of Pool: 3309 MD, 3027’ TVD Beluga D1 ±4,252 ±4,255 ±3,865 ±3,868 ±3 Beluga D1 ±4,278 ±4,281 ±3,889 ±3,891 ±3 Beluga D3 ±4,304 ±4,307 ±3,912 ±3,915 ±3 Beluga D3 ±4,311 ±4,312 ±3,918 ±3,919 ±1 Beluga D3 ±4,318 ±4,320 ±3,925 ±3,926 ±2 Beluga D5 ±4,373 ±4,377 ±3,974 ±3,978 ±4 Beluga D5 ±4,388 ±4,393 ±3,987 ±3,992 ±5 Beluga D6 ±4,427 ±4,444 ±4,022 ±4,037 ±17 Beluga E1 ±4,495 ±4,502 ±4,083 ±4,089 ±7 Beluga E1 ±4,508 ±4,510 ±4,094 ±4,096 ±2 Beluga E1 ±4,513 ±4,520 ±4,099 ±4,105 ±7 Beluga E1 ±4,533 ±4,549 ±4,117 ±4,131 ±16 Beluga E2 ±4,564 ±4,572 ±4,144 ±4,151 ±8 Beluga E4 ±4,630 ±4,633 ±4,203 ±4,206 ±3 Beluga E5 ±4,640 ±4,645 ±4,212 ±4,216 ±5 Beluga E5 ±4,656 ±4,660 ±4,226 ±4,230 ±4 Beluga E6 ±4,706 ±4,712 ±4,271 ±4,276 ±6 Beluga E6 ±4,721 ±4,726 ±4,284 ±4,289 ±5 Beluga E6 ±4,737 ±4,742 ±4,298 ±4,303 ±5 Beluga E6 ±4,754 ±4,760 ±4,314 ±4,319 ±6 Beluga F ±4,793 ±4,798 ±4,349 ±4,353 ±5 Beluga F ±4,810 ±4,813 ±4,364 ±4,366 ±3 Beluga F4 ±4,855 ±4,858 ±4,404 ±4,407 ±3 Beluga F5 ±4,964 ±4,967 ±4,502 ±4,505 ±3 Beluga F6 ±5,013 ±5,017 ±4,546 ±4,550 ±4 Beluga F7 ±5,104 ±5,112 ±4,629 ±4,636 ±8 Beluga F7 ±5,175 ±5,179 ±4,694 ±4,698 ±4 Beluga F10 ±5,215 ±5,233 ±4,731 ±4,748 ±18 Beluga G3 ±5,374 ±5,384 ±4,880 ±4,890 ±10 Beluga G4 ±5,410 ±5,416 ±4,914 ±4,920 ±6 Beluga G8 ±5,486 ±5,491 ±4,987 ±4,992 ±5 Beluga G10 ±5,560 ±5,571 ±5,058 ±5,069 ±11 Beluga H3 ±5,693 ±5,704 ±5,187 ±5,198 ±11 If setting a plug, dump bail 25' of cement on top. -bjm Well Prognosis 15. Turn well over to production & flow test well 16. Test SVS as necessary once well has reached stabile flow rates Coil Procedure (Contingency) If necessary to cleanout or unload well with coiled tubing: 1. MIRU Coiled Tubing Unit, PT BOPE to 3,000 psi High/250 psi Low 2. Provide AOGCC 24hrs notice of BOP test 3. PU wash nozzle, RIH and cleanout well to below perfs or proposed plug depth 4. PU CT jet nozzle and RIH, unload fluid from the wellbore with nitrogen a. Reverse circ out any fluid if perfs are isolated/plugged back and in cased hole 5. RDMO coil tubing Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Fox CT BOP Drawing 4. Nitrogen procedure Updated by CAH 4-10-25 SCHEMATIC Beluga River Unit BRU 222-24 PTD: 220-043 API: 50-283-20180-00-00 PBTD = 7,388’ MD / TVD = 6,854’ TD = 7,485’ MD / TVD = 6,949’ RKB to GL = 18’ PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Comments Bel G1 5,289’ 5,293’ 4,800' 4,804' 4' 8/8/2024 Open Bel G1 5,296’ 5,301’ 4,806' 4,811' 5' 8/8/2024 Open Bel G1 5,314’ 5,320’ 4,823' 4,829' 6' 8/8/2024 Open Bel G2 5,345’ 5,352’ 4,853' 4,859' 7' 8/8/2024 Open Bel H2 5,657’ 5,673’ 5,152' 5,168' 16' 8/8/2024 Open Bel H5 5,767' 5,786' 5,260' 5,269' 9' 8/7/2020 Plugged Bel H12 6,044' 6,057' 5,531' 5,544' 13' 8/7/2020 Plugged Bel H15 6,175' 6,195' 5,659' 5,679' 20' 8/7/2020 Plugged Bel I2 6,336' 6,343' 5,817' 5,824' 7' 8/7/2020 Plugged Bel I6 6,472' 6,493' 5,951' 5,972' 21' 8/7/2020 Plugged CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,739’ 5-1/2" Prod Csg 17 P-110 ICY TXP BTC 4.892” Surf 7,475’ 1 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,494’ - - Swell Packer 2 5,757’ - - CIBP w/ 15ft of cement. TOC @ 5,742’ 08/01/24 8-1/2” hole Bel H5 Bel I2, I6 Tag fill at 5820’ (11-11-22) Bel H12 Bel H15 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface (45 bbls to surface 10/2/22) 4-1/2” CBL TOC @ 3260’ (10/23/22) Notes: Restriction unable to mill through at 5838’. Tight spot @ 5791’. SL tool string stuck POOH @ 3520’. (Wire/Fill @ ~3449’) Bel G1 Bel H2 Bel G2 2 Tagged fill 4181 on 3/9/25 Fish 3520’ Updated JLL 04/08/25 PROPOSED Beluga River Unit BRU 222-24 PTD: 220-043 API: 50-283-20180-00-00 PBTD = 7,388’ MD / TVD = 6,854’ TD = 7,485’ MD / TVD = 6,949’ RKB to GL = 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,739’ 5-1/2" Prod Csg 17 P-110 ICY TXP BTC 4.892” Surf 7,475’ 1 16” 9-5/8” 12-1/4” hole 5-1/2” 8-1/2” hole Bel H5 Bel I2, I6 Tag fill at 5820’ (11-11-22) Bel H12 Bel H15 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface (45 bbls to surface 10/2/22) 4-1/2” CBL TOC @ 3260’ (10/23/22) Notes: Restriction unable to mill through at 5838’. Tight spot @ 5791’. Bel H Bel G 2 Tagged fill 4181 on 3/9/25 Fish 3610’ PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Comments Top Of Pool: 3309 MD, 3027’ TVD ôīŪČÍώ"͐ ѷ͓Ϡ͔͑͑ ѷ͓Ϡ͔͔͑ ѷ͒Ϡ͕͔͗ ѷ͒Ϡ͕͗͗ ѷ͒Future Proposed ôīŪČÍώ"͐ ѷ͓Ϡ͖͑͗ ѷ͓Ϡ͑͗͐ ѷ͒Ϡ͗͗͘ ѷ͒Ϡ͗͐͘ ѷ͒Future Proposed ôīŪČÍώ"͒ ѷ͓Ϡ͒͏͓ѷ͓Ϡ͒͏͖ ѷ͒Ϡ͐͑͘ ѷ͒Ϡ͔͐͘ ѷ͒Future Proposed ôīŪČÍώ"͒ ѷ͓Ϡ͒͐͐ ѷ͓Ϡ͒͐͑ ѷ͒Ϡ͐͗͘ ѷ͒Ϡ͐͘͘ ѷ͐Future Proposed ôīŪČÍώ"͒ ѷ͓Ϡ͒͐͗ ѷ͓Ϡ͒͑͏ ѷ͒Ϡ͔͑͘ ѷ͒Ϡ͕͑͘ ѷ͑Future Proposed ôīŪČÍώ"͔ ѷ͓Ϡ͖͒͒ ѷ͓Ϡ͖͖͒ ѷ͒Ϡ͖͓͘ѷ͒Ϡ͖͗͘ ѷ͓Future Proposed ôīŪČÍώ"͔ ѷ͓Ϡ͒͗͗ ѷ͓Ϡ͒͒͘ ѷ͒Ϡ͖͗͘ ѷ͒Ϡ͑͘͘ ѷ͔Future Proposed ôīŪČÍώ"͕ ѷ͓Ϡ͓͖͑ ѷ͓Ϡ͓͓͓ѷ͓Ϡ͏͑͑ ѷ͓Ϡ͏͖͒ ѷ͖͐Future Proposed ôīŪČÍώ(͐ ѷ͓Ϡ͓͔͘ ѷ͓Ϡ͔͏͑ ѷ͓Ϡ͏͗͒ ѷ͓Ϡ͏͗͘ ѷ͖Future Proposed ôīŪČÍώ(͐ ѷ͓Ϡ͔͏͗ ѷ͓Ϡ͔͐͏ ѷ͓Ϡ͏͓͘ѷ͓Ϡ͏͕͘ ѷ͑Future Proposed ôīŪČÍώ(͐ ѷ͓Ϡ͔͐͒ ѷ͓Ϡ͔͑͏ ѷ͓Ϡ͏͘͘ ѷ͓Ϡ͐͏͔ ѷ͖Future Proposed ôīŪČÍώ(͐ ѷ͓Ϡ͔͒͒ ѷ͓Ϡ͔͓͘ ѷ͓Ϡ͖͐͐ ѷ͓Ϡ͐͒͐ ѷ͕͐Future Proposed ôīŪČÍώ(͑ ѷ͓Ϡ͔͕͓ѷ͓Ϡ͔͖͑ ѷ͓Ϡ͓͓͐ѷ͓Ϡ͔͐͐ ѷ͗Future Proposed ôīŪČÍώ(͓ ѷ͓Ϡ͕͒͏ ѷ͓Ϡ͕͒͒ ѷ͓Ϡ͑͏͒ ѷ͓Ϡ͑͏͕ ѷ͒Future Proposed ôīŪČÍώ(͔ ѷ͓Ϡ͕͓͏ ѷ͓Ϡ͕͓͔ ѷ͓Ϡ͑͐͑ ѷ͓Ϡ͕͑͐ ѷ͔Future Proposed ôīŪČÍώ(͔ ѷ͓Ϡ͕͔͕ ѷ͓Ϡ͕͕͏ ѷ͓Ϡ͕͑͑ ѷ͓Ϡ͑͒͏ ѷ͓Future Proposed ôīŪČÍώ(͕ ѷ͓Ϡ͖͏͕ ѷ͓Ϡ͖͐͑ ѷ͓Ϡ͖͑͐ ѷ͓Ϡ͖͕͑ ѷ͕Future Proposed ôīŪČÍώ(͕ ѷ͓Ϡ͖͑͐ ѷ͓Ϡ͖͕͑ ѷ͓Ϡ͓͑͗ѷ͓Ϡ͑͗͘ ѷ͔Future Proposed ôīŪČÍώ(͕ ѷ͓Ϡ͖͖͒ ѷ͓Ϡ͖͓͑ ѷ͓Ϡ͑͗͘ ѷ͓Ϡ͒͏͒ ѷ͔Future Proposed ôīŪČÍώ(͕ ѷ͓Ϡ͖͔͓ѷ͓Ϡ͖͕͏ ѷ͓Ϡ͓͒͐ѷ͓Ϡ͒͐͘ ѷ͕Future Proposed ôīŪČÍώ> ѷ͓Ϡ͖͒͘ ѷ͓Ϡ͖͗͘ ѷ͓Ϡ͓͒͘ ѷ͓Ϡ͔͒͒ ѷ͔Future Proposed ôīŪČÍώ> ѷ͓Ϡ͗͐͏ ѷ͓Ϡ͗͐͒ ѷ͓Ϡ͕͓͒ѷ͓Ϡ͕͕͒ ѷ͒Future Proposed ôīŪČÍώ>͓ ѷ͓Ϡ͔͔͗ ѷ͓Ϡ͔͗͗ ѷ͓Ϡ͓͏͓ѷ͓Ϡ͓͏͖ ѷ͒Future Proposed ôīŪČÍώ>͔ ѷ͓Ϡ͕͓͘ѷ͓Ϡ͕͖͘ ѷ͓Ϡ͔͏͑ ѷ͓Ϡ͔͏͔ ѷ͒Future Proposed ôīŪČÍώ>͕ ѷ͔Ϡ͏͐͒ ѷ͔Ϡ͏͖͐ ѷ͓Ϡ͔͓͕ ѷ͓Ϡ͔͔͏ ѷ͓Future Proposed ôīŪČÍώ>͖ ѷ͔Ϡ͐͏͓ѷ͔Ϡ͐͐͑ ѷ͓Ϡ͕͑͘ ѷ͓Ϡ͕͕͒ ѷ͗Future Proposed ôīŪČÍώ>͖ ѷ͔Ϡ͖͔͐ ѷ͔Ϡ͖͐͘ ѷ͓Ϡ͕͓͘ѷ͓Ϡ͕͗͘ ѷ͓Future Proposed ôīŪČÍώ>͐͏ ѷ͔Ϡ͔͑͐ ѷ͔Ϡ͑͒͒ ѷ͓Ϡ͖͒͐ ѷ͓Ϡ͖͓͗ ѷ͐͗Future Proposed Bel G1 5,289’ 5,293’ 4,800' 4,804' 4' 8/8/2024 Open Bel G1 5,296’ 5,301’ 4,806' 4,811' 5' 8/8/2024 Open Bel G1 5,314’ 5,320’ 4,823' 4,829' 6' 8/8/2024 Open Bel G2 5,345’ 5,352’ 4,853' 4,859' 7' 8/8/2024 Open ôīŪČÍώ@͒ ѷ͔Ϡ͖͓͒ѷ͔Ϡ͓͒͗ѷ͓Ϡ͗͗͏ ѷ͓Ϡ͗͘͏ ѷ͐͏Future Proposed ôīŪČÍώ@͓ ѷ͔Ϡ͓͐͏ ѷ͔Ϡ͓͕͐ ѷ͓Ϡ͓͐͘ѷ͓Ϡ͑͘͏ ѷ͕Future Proposed ôīŪČÍώ@͗ ѷ͔Ϡ͓͕͗ ѷ͔Ϡ͓͐͘ ѷ͓Ϡ͖͗͘ ѷ͓Ϡ͑͘͘ ѷ͔Future Proposed ôīŪČÍώ@͐͏ ѷ͔Ϡ͔͕͏ ѷ͔Ϡ͔͖͐ ѷ͔Ϡ͏͔͗ ѷ͔Ϡ͏͕͘ ѷ͐͐Future Proposed Bel H2 5,657’ 5,673’ 5,152' 5,168' 16' 8/8/2024 Open ôīŪČÍώF͒ ѷ͔Ϡ͕͒͘ ѷ͔Ϡ͖͏͓ѷ͔Ϡ͖͐͗ ѷ͔Ϡ͐͗͘ ѷ͐͐Future Proposed Bel H5 5,767' 5,786' 5,260' 5,269' 9' 8/7/2020 Plugged Bel H12 6,044' 6,057' 5,531' 5,544' 13' 8/7/2020 Plugged Bel H15 6,175' 6,195' 5,659' 5,679' 20' 8/7/2020 Plugged Bel I2 6,336' 6,343' 5,817' 5,824' 7' 8/7/2020 Plugged Bel I6 6,472' 6,493' 5,951' 5,972' 21' 8/7/2020 Plugged Bel D Bel E Bel F JEWELRY DETAIL No. Depth ID OD Item 1 2,494’ - - Swell Packer 2 5,757’ - - CIBP w/ 15ft of cement. TOC @ 5,742’ 08/01/24 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: N2 Development Exploratory 3. Address: Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 7,865 feet 5,757 feet true vertical 6,949 feet 5,618' (fill) feet Effective Depth measured 5,742 feet 2,494 feet true vertical 5,235 feet 2,312 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) N/A N/A N/A N/A Packers and SSSV (type, measured and true vertical depth) Swell Pkr; N/A 2,494' MD 2,312' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: 8,730psi 2,980psi 5,750psi 10,600psi 2,739' 2,526' Burst Collapse 1,410psi 3,090psi Production Liner 7,475' Casing Structural 6,759'7,475' 120'Conductor Surface Intermediate 16" 9-5/8" 120' 2,739' measured TVD 5-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-043 50-283-20180-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL021128 Beluga River / Sterling-Beluga Gas Beluga River Unit (BRU) 222-24 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 5 Size 120' 0 53135 0 4411 116 Chad Helgeson, Operations Engineer 324-384 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 702 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A chelgeson@hilcorp.com 907-777-8405 p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 12:06 pm, Oct 14, 2024 Page 1/1 Well Name: BRU 222-24 Report Printed: 10/2/2024www.peloton.com Alaska Weekly Report - Operations Jobs Actual Start Date:7/24/2024 End Date: Report Number 1 Report Start Date 7/24/2024 Report End Date 7/25/2024 Last 24hr Summary PJSM, Mobilize equipment to location, Spot in & rig up, Nipple up BOPE, Function test-good, Pressure test BOPE 250-low, 2500-high-no failures-good test, batch mix 400 bbls of 6% KCL, Secure well for the night. Report Number 2 Report Start Date 7/25/2024 Report End Date 7/26/2024 Last 24hr Summary PJSM, Crew travel to location, Pick up injector & lube, Pressure test 250/2500-good, Perform accumilator draw down-good, Run in hole to tag @ 4804', Clean out f/ 4804' to 5785' unable to clean out past 5785', Pull out of hole to 1200' & stage in hole while unloading with N2, Kill N2 & establish rate, Pull out of hole maintaining rate, Turn over to production, Rig down for the night. Report Number 3 Report Start Date 7/26/2024 Report End Date 7/27/2024 Last 24hr Summary PJSM, Crew travel to location, Batch mix 300 bbls 6% kcl, Pick up injector & lube, Cut 60' of tubing, Make up coil connector & bha, Run in hole & tag @ 5782', Filled hole with 73 bbls, Clean out f/ 5782' to 5879', Circulate hole clean, Pull out of the hole & rig down for the night. Report Number 4 Report Start Date 7/27/2024 Report End Date 7/28/2024 Last 24hr Summary PJSM, Crew travel to location, Batch mix 200 bbls, PIck up injector & lube, Pick up & make up BHA, Run in the hole & tag @ 5771', Clean out hole to 5893' (tight spots, work string free), Pull out of hole & inspect bha (bit worn lndicates junk in hole), PIck up venturi and run in hole to tag @ 5791', Work Venturi thru tight spot, Cont. running in hole to tag @ 5838', Unable to pass, Pull out of hole, Jar & work thru 5791', Pull free, pull to surface, secure well & rig down. Report Number 5 Report Start Date 7/28/2024 Report End Date 7/29/2024 Last 24hr Summary PJSM, Crew travel to location, Perform maintence to hydrolics and pump, Pick up BHA, Surface test equipment-good, Run in hole to tag @ 5829', Clean out f/ 5829 -5910, Pull out the hole, Secure well, Rig down coil for the night Report Number 6 Report Start Date 8/1/2024 Report End Date 8/2/2024 Last 24hr Summary PJSM, Crew travel to location, Spot in & rig up equipment, PIck up lube & CCL/GR/PLUG (4.25"), Pressure test lube 250/2500-good, Run in hole & correlate, Set plug @ 5757', Tag & log off-good, Pick up & make up bailer, Bail 15 gal cmt on plug (TOC @ 5742'), Pull out hole & rig down, Release Eline Field: Beluga River Sundry #: 324-384 State: Alaska Rig/Service:Permit to Drill (PTD) #:220-043Permit to Drill (PTD) #:220-043 Wellbore API/UWI:50-283-20180-00-00 Page 1/1 Well Name: BRU 222-24 Report Printed: 10/9/2024www.peloton.com Alaska Weekly Report - Operations Jobs Actual Start Date:8/7/2024 End Date: Report Number 1 Report Start Date 8/7/2024 Report End Date 8/8/2024 Last 24hr Summary PJSM, Crew travel to location, Load reel, Pressure test BOPE 250-low, 2500-high,No Failures, Run in hole to tag @ 5737', Kick in N2 & reverse circulate 133 bbls to surface, Blow N2 for 30 min, Pull out of hole & trap 1000 psi on wellhead, Rig down & release fox coil. Report Number 2 Report Start Date 8/8/2024 Report End Date 8/9/2024 Last 24hr Summary PJSM, Crew travel to location, Spot in & rig up, Pick up CCL/GR/Gun (2.75"), Pressure test 250/2500-good, Run in hole & tag 5719', Correlate, Perf H2 (5657- 5673), Pull out of the hole, Run in & perf G2 (5345-5352), Pull out of hole, Run in & perf G1 (5314-5320), Pull out of hole, Run in hole & perf G1 (5296-5301), Pull out of the hole, Run in hole & perf G1 (5289-5293), Pull out of hole & rig down for the night. Report Number 3 Report Start Date 8/14/2024 Report End Date 8/14/2024 Last 24hr Summary Estimated fuel Costs Report Number 4 Report Start Date 8/22/2024 Report End Date 8/22/2024 Last 24hr Summary Tag at 5713'KB with 2.5" drive down bailer. Run P/T survey Report Number 5 Report Start Date 10/2/2024 Report End Date 10/2/2024 Last 24hr Summary Reservoir team (RE/GEO) determined that the additional perfs included in this sundry would not be executed until 2025, so decision made to close out Sundry. Field: Beluga River Sundry #: 324-384 State: Alaska Rig/Service:Permit to Drill (PTD) #:220-043Permit to Drill (PTD) #:220-043 Wellbore API/UWI:50-283-20180-00-00 Updated by DMA 10-08-24 SCHEMATIC Beluga River Unit BRU 222-24 PTD: 220-043 API: 50-283-20180-00-00 PBTD = 7,388 MD / TVD = 6,854 TD = 7,485 MD / TVD = 6,949 RKB to GL = 18 PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Comments Bel G1 5,289 5,293 4,800' 4,804' 4' 8/8/2024 Open Bel G1 5,296 5,301 4,806' 4,811' 5' 8/8/2024 Open Bel G1 5,314 5,320 4,823' 4,829' 6' 8/8/2024 Open Bel G2 5,345 5,352 4,853' 4,859' 7' 8/8/2024 Open Bel H2 5,657 5,673 5,152' 5,168' 16' 8/8/2024 Open Bel H5 5,767' 5,786' 5,260' 5,269' 9' 8/7/2020 Plugged Bel H12 6,044' 6,057' 5,531' 5,544' 13' 8/7/2020 Plugged Bel H15 6,175' 6,195' 5,659' 5,679' 20' 8/7/2020 Plugged Bel I2 6,336' 6,343' 5,817' 5,824' 7' 8/7/2020 Plugged Bel I6 6,472' 6,493' 5,951' 5,972' 21' 8/7/2020 Plugged CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16 Conductor Driven to Set Depth 84 X-56 Weld 15.01 Surf 120' 9-5/8" Surf Csg 47 L-80 BTC 8.681 Surf 2,739 5-1/2" Prod Csg 17 P-110 ICY TXP BTC 4.892 Surf 7,475 1 16 9-5/8 12-1/4 hole 5-1/2 JEWELRY DETAIL No. Depth ID OD Item 1 2,494 - - Swell Packer 2 5,757 - - CIBP w/ 15ft of cement. TOC @ 5,742 08/01/24 8-1/2 hole Bel H5 Bel I2, I6 Tag fill at 5820 (11-11-22) Bel H12 Bel H15 OPEN HOLE / CEMENT DETAIL 7-5/8" TOC @ Surface (45 bbls to surface 10/2/22) 4-1/2 CBL TOC @ 3260 (10/23/22) Notes: Restriction unable to mill through at 5838. Tight spot @ 5791. Bel G1 Bel H2 Bel G2 2 Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 8/27/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240827 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 23 50133206350000 214093 7/18/2024 AK E-LINE PPROF BRU 222-24 50283201800000 220043 8/8/2024 AK E-LINE Perf BRU 222-26 50283201950000 224035 8/6/2024 AK E-LINE Perf BRU 222-26 50283201950000 224035 7/16/2024 AK E-LINE Perf BRU 241-26 50283201970000 224068 8/12/2024 AK E-LINE Perf BRU 241-34S 50283201980000 224077 8/2/2024 AK E-LINE Perf BRU 241-34S 50283201980000 224077 7/28/2024 HALLIBURTON CAST-CBL IRU 44-36 50283200890000 193022 8/10/2024 AK E-LINE PlugPerf PBU 18-13D 50029217560400 224039 8/2/2024 HALLIBURTON RBT PBU 18-33A 50029225980100 204070 8/13/2024 HALLIBURTON RBT PBU Z-228 50029237180000 222055 7/28/2024 HALLIBURTON PPROF PBU Z-234 50029237620000 223065 7/29/2024 HALLIBURTON IPROF PCU 2 50283200229000 179009 7/9/2024 AK E-LINE TubingCut TBU M-02 50733203890000 187061 8/6/2024 AK E-LINE CBL TBU M-02 50733203890000 187061 8/12/2024 AK E-LINE Perf Please include current contact information if different from above. T39491 T39492 T39493 T39493 T39494 T39495 T39495 T39496 T39497 T39498 T39499 T39500 T39501 T39502 T39502 BRU 222-24 50283201800000 220043 8/8/2024 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.08.27 11:27:22 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 8/13/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240813 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 222-24 50283201800000 22Ϭ043 8/1/2024 AK E-LINE CIBP BRU 222-26 50283201950000 224035 7/21/2024 AK E-LINE Plug BRU 232-04 50283100230000 162037 7/25/2024 AK E-LINE Perf BRU 241-26 50283201970000 224068 7/24/2024 AK E-LINE CBL BRU 241-26 50283201970000 224068 7/31/2024 AK E-LINE CBL BRU 241-34S 50283201980000 224077 7/10/2024 AK E-LINE CBL BRU 241-34S 50283201980000 224077 7/18/2024 AK E-LINE CBL BRU 241-34S 50283201980000 224077 7/23/2024 AK E-LINE CBL BRU 241-34S 50283201980000 224077 7/28/2024 AK E-LINE Hoist IRU 44-36 50283200890000 193022 8/3/2024 AK E-LINE CBL IRU 44-36 50283200890000 193022 7/31/2024 AK E-LINE CIBP IRU 44-36 50283200890000 193022 7/29/2024 AK E-LINE RCT MPU I-01 50029220650000 190090 7/20/2024 AK E-LINE CBL MRU M-02 50733203890000 187061 7/20/2024 AK E-LINE Plug PBU PTM P1-08A 50029223840100 202199 7/23/2024 AK E-LINE CBL PBU V-220 50029233830000 208020 6/28/2024 READ InjectionProfileAnalysis PTU DW-01 50089200320000 214206 7/16/2024 READ CaliperSurvey PTU DW-0ϭ 50089200320000 214206 7/17/2024 READ TemperatureSurvey Please include current contact information if different from above. T39418 T39419 T39420 T39421 T39421 T39422 T39422 T39422 T39422 T39423 T39423 T39423 T39424 T39425 T39426 T39427 T39428 T39428 BRU 222-24 50283201800000 22Ϭ043 8/1/2024 AK E-LINE CIBP Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.08.13 13:58:22 -08'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: CTCO, N2 2.Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,485'5,618' (fill) Casing Collapse Structural Conductor 1,410psi Surface 3,090psi Intermediate Production 8,730psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Swell Pkr & N/A 2,494 (MD) 2,312 (TVD) & N/A 6,949'7,388'6,854' Beluga River Sterling-Beluga Gas 16" 9-5/8" See Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 222-24CO 802 Same 6,759'5-1/2" ~2167psi 7,475' N/A Length July 15, 2024 N/A 7,475' Perforation Depth MD (ft): See Schematic 2,980psi 5,750psi 120'120' 2,739' Size 120' 2,739' MD Hilcorp Alaska, LLC Proposed Pools: N/A TVD Burst N/A 10,600psi 2,526' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL021128 220-043 50-283-20180-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Jake Flora, Operations Engineer AOGCC USE ONLY Tubing Grade: jake.flora@hilcorp.com 907-777-8442 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 66 t 2 N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.07.02 14:15:42 - 08'00' Noel Nocas (4361) 324-384 By Grace Christianson at 2:32 pm, Jul 02, 2024 10-404 X BJM 7/8/24 A.Dewhurst 10JUL24 CT BOP test to 2500 psi DSR-7/8/24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.07.11 10:22:01 -08'00'07/11/24 RBDMS JSB 071624 Well Prognosis Well Name: BRU 222-24 API Number: 50-283-20180-00 Current Status SI Gas Producer Permit to Drill Number: 220-043 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (M) Second Call Engineer: Chad Helgeson (907) 777-8420 (O) (907) 229-4824 (M) Maximum Expected BHP: ~ 2782 psi @ 6156’ TVD (0.452 psi/ft gradient to bottom perf) Max. Potential Surface Pressure: ~2167 psi (Max expected BHP minus gas to surface) Well Status: SI with fill over perfs Last well test: 2300 MCFD / 12 BWPD / 138# (06/14/2024) Brief Well Summary 222-24 was drilled in 2020 and completed as a Beluga H and I producer. The well location is close to the crest of the H and I sands. The well was completed as a 5.5” monobore. RFT data indicated limited depletion in H and I and some less depleted zones in the G sands. No wellwork has been completed on the well and it has produced 2.6 BCF. Based on decline curve analysis, the well is expected to produce and additional 2.5 BCF from the current perforations. 222-24 is currently offline with fill covering the perforations. The objective of this sundry is to clean out the wellbore and increase rate by perforating additional Beluga sands. Last Downhole Operation: 6/25/2024 3” DDB to 5618’ 8/07/2020 Perforated Beluga H5 sands 5767-5786’ Procedure: Procedure: 1. Review all approved COAs 2. Provide AOGCC 48hrs notice for BOP test 3. MIRU Coiled Tubing, PT BOPE to 2500 psi. 4. Clean out wellbore to PBTD, jet dry with nitrogen 5. MIRU E-line, PT Lubricator to 2500 psi 6. Log caliper from PBTD to surface 7. Perforate Beluga sands within the below interval: Pool Top (Sterling A1) 3604’ MD 3290’ TVD Planned Interval (Beluga F – I) 4810’ – 6680’ MD 4364’ – 6156’ TVD a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. b. Frac Calcs: Using 13.57 ppg EMW FIT at the surface casing shoe (0.705 psi/ft frac grad) c. Shallowest Allowable Perf TVD = MPSP/(0.705-0.1) = 2167 psi / 0.605 = 3582‘ TVD Well Prognosis 8. Return to production Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Coil Tubing BOP Diagram 4. Nitrogen SOP Updated by JMF 07-01-24 SCHEMATIC Beluga River Unit BRU 222-24 PTD: 220-043 API: 50-283-20180-00-00 PBTD = 7,388’ MD / TVD = 6,854’ TD = 7,485’ MD / TVD = 6,949’ RKB to GL = 18’ PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Comments Beluga H5 5,767' 5,786' 5,260' 5,269' 9' 8/7/20 2-7/8” Beluga H12 6,044' 6,057' 5,531' 5,544' 13' 8/7/20 2-7/8” Beluga H15 6,175' 6,195' 5,659' 5,679' 20' 8/7/20 2-7/8” Beluga I2 6,336' 6,343' 5,817' 5,824' 7' 8/7/20 2-7/8” Beluga I6 6,472' 6,493' 5,951' 5,972' 21' 8/7/20 2-7/8” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,739’ 5-1/2" Prod Csg 17 P-110 ICY TXP BTC 4.892” Surf 7,475’ 1 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,494’ - - Swell Packer 8-1/2” hole Bel H5 Bel I2, I6 Tag fill at 5820’ (11-11-22) Bel H12 Bel H15 Tag fill at 5618’ (6-25-24) Updated by DMA 07-01-24 PROPOSED Beluga River Unit BRU 222-24 PTD: 220-043 API: 50-283-20180-00-00 PBTD = 7,388’ MD / TVD = 6,854’ TD = 7,485’ MD / TVD = 6,949’ RKB to GL = 18’ PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Comments Beluga F-I ±4,810' ±6,680’ ±4,364’ ±6,156 Proposed 2-7/8” Beluga H5 5,767' 5,786' 5,260' 5,269' 9' 8/7/20 2-7/8” Beluga H12 6,044' 6,057' 5,531' 5,544' 13' 8/7/20 2-7/8” Beluga H15 6,175' 6,195' 5,659' 5,679' 20' 8/7/20 2-7/8” Beluga I2 6,336' 6,343' 5,817' 5,824' 7' 8/7/20 2-7/8” Beluga I6 6,472' 6,493' 5,951' 5,972' 21' 8/7/20 2-7/8” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,739’ 5-1/2" Prod Csg 17 P-110 ICY TXP BTC 4.892” Surf 7,475’ 1 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,494’ - - Swell Packer 8-1/2” hole Bel H5 Bel I2, I6 Tag fill at 5820’ (11-11-22) Bel H12 Bel H15 Tag fill at 5618’ (6-25-24) STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number): 10. Field: Current Pools: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 7,485'N/A Casing Collapse Structural Conductor 1,410psi Surface 3,090psi Intermediate Production 8,730psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY Jake Flora, Operations Engineer jake.flora@hilcorp.com 907-777-8442 Noel Nocas, Operations Manager 907-564-5278 Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):Tubing Size: N/A N/A June 15, 2023 Swell Pkr & N/A 2,494 (MD) 2,312 (TVD) & N/A See Schematic See Schematic N/A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL021128 220-043 50-283-20180-00-00 Beluga River Sterling-Beluga Gas Same CO 802 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 222-24 Length Size Proposed Pools: TVD Burst PRESENT WELL CONDITION SUMMARY 6,949'7,388'6,854'2,243 N/A MD 2,980psi 5,750psi 120' 2,526' 120' 2,739' Perforation Depth MD (ft): 7,475'5-1/2" 16" 9-5/8" 120' 2,739' 10,600psi6,759'7,475' m n P s t 66 Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 8:15 am, Jun 02, 2023 323-325 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.06.01 17:03:01 - 08'00' Noel Nocas (4361) BJM 6/7/23 SFD 6/6/2023 10-404 GCW 06/08/2023 DSR-6/6/23 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.06.08 14:39:56 -08'00' RBDMS JSB 060823 Well Prognosis Well Name: BRU 222-24 API Number: 50-283-20180-00 Regulatory Contact: Donna Ambruz Permit to Drill Number: 220-043 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (M) Second Call Engineer: Chad Helgeson (907) 777-8420 (O) (907) 229-4824 (M) Maximum Expected BHP: ~ 2880 psi @ 6372’ TVD (0.452 psi/ft gradient to bottom perf) Max. Potential Surface Pressure: ~2243 psi (Max expected BHP minus gas to surface) Well Status: Online Gas Producer: Last well test - 2000 MCFD / 1 BWPD / 150# Brief Well Summary 222-24 was drilled in 2020 and completed as a Beluga H and I producer. The well location is close to the crest of the H and I sands. The well was completed as a 5.5” monobore. RFT data indicated limited depletion in H and I and some less depleted zones in the G sands. No wellwork has been completed on the well and it has produced 2.6 BCF. Based on decline curve analysis, the well is expected to produce and additional 2.5 BCF from the current perforations. 222-24 is currently ~1.5 mmscf below unloading rate. The rate would need to be ~4.2mmscfd or higher to be over unloading rate at current pressures. The objective of this sundry is to increase rate by adding perforations after the wellbore has been cleaned out with coil tubing. The coil cleanout is currently approved under Sundry 323-209. Last Downhole Operation: 11-11-22 2” DDB to 5820’, tag fill Procedure 1. Review approved COAs 2. MIRU E-line, PT BOPE to 3000 psi 3. Perforate the below sands while flowing: Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom Sand Name MD Top MD Bot MD Tot TVD Top TVD Bot Beluga G1 ±5,289' ±5,293' 4' ±4,800' ±4,804' Beluga G1 ±5,295' ±5,300' 5' ±4,806' ±4,811' Beluga G1 ±5,313' ±5,320' 7' ±4,822' ±4,829' Beluga G2 ±5,345' ±5,352' 7' ±4,852' ±4,859' Beluga G3 ±5,373' ±5,383' 10' ±4,880' ±4,890' Beluga G4 ±5,410' ±5,416' 6' ±4,914' ±4,920' Beluga G8 ±5,485' ±5,490' 5' ±4,986' ±4,991' Beluga G10 ±5,560' ±5,571' 11' ±5,058' ±5,069' Beluga H2 ±5,657' ±5,673' 16' ±5,152' ±5,168' Beluga H3 ±5,693' ±5,703' 10' ±5,188' ±5,198' Well Prognosis a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. 4. Return to production Attachments: 1. Actual Schematic 2. Proposed Schematic Beluga H4 ±5,753' ±5,760' 7' ±5,247' ±5,254' Beluga H7 ±5,832' ±5,846' 14' ±5,323' ±5,337' Beluga H8 ±5,861' ±5,878' 17' ±5,352' ±5,369' Beluga H11 ±5,999' ±6,002' 3' ±5,486' ±5,489' Beluga H12 ±6,024' ±6,029' 5' ±5,511' ±5,516' Beluga I ±6,256' ±6,269' 13' ±5,738' ±5,751' Beluga I1 ±6,300' ±6,306' 6' ±5,782' ±5,788' Beluga I8 ±6,536' ±6,555' 19' ±6,014' ±6,033' Beluga I11 ±6,660' ±6,680' 20' ±6,137' ±6,157' Beluga I12 ±6,736' ±6,742' 6' ±6,210' ±6,216' Beluga I12 ±6,759' ±6,766' 7' ±6,234' ±6,241' Beluga J1 ±6,819' ±6,835' 16' ±6,293' ±6,309' Beluga J2 ±6,891' ±6,899' 8' ±6,364' ±6,372' Updated by JMF 04-03-23 SCHEMATIC Beluga River Unit BRU 222-24 PTD: 220-043 API: 50-283-20180-00-00 PBTD = 7,388’ MD / TVD = 6,854’ TD = 7,485’ MD / TVD = 6,949’ RKB to GL = 18’ PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Comments Beluga H5 5,767' 5,786' 5,260' 5,269' 9' 8/7/20 2-7/8” Beluga H12 6,044' 6,057' 5,531' 5,544' 13' 8/7/20 2-7/8” Beluga H15 6,175' 6,195' 5,659' 5,679' 20' 8/7/20 2-7/8” Beluga I2 6,336' 6,343' 5,817' 5,824' 7' 8/7/20 2-7/8” Beluga I6 6,472' 6,493' 5,951' 5,972' 21' 8/7/20 2-7/8” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,739’ 5-1/2" Prod Csg 17 P-110 ICY TXP BTC 4.892” Surf 7,475’ 1 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,494’ - - Swell Packer 8-1/2” hole Bel H5 Bel I2, I6 Tag fill at 5820’ (11-11-22) Bel H12 Bel H15 Updated by DMA 06-01-23 PROPOSED Beluga River Unit BRU 222-24 PTD: 220-043 API: 50-283-20180-00-00 PBTD = 7,388’ MD / TVD = 6,854’ TD = 7,485’ MD / TVD = 6,949’ RKB to GL = 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,739’ 5-1/2" Prod Csg 17 P-110 ICY TXP BTC 4.892” Surf 7,475’ 1 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,494’ - - Swell Packer 8-1/2” hole Bel H5 Bel I2, I6 Bel H12 Bel H15 PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Comments Beluga G1 ±5,289' ±5,293' ±4,800' ±4,804' 4' Proposed TBD Beluga G1 ±5,295' ±5,300' ±4,806' ±4,811' 5' Proposed TBD Beluga G1 ±5,313' ±5,320' ±4,822' ±4,829' 7' Proposed TBD Beluga G2 ±5,345' ±5,352' ±4,852' ±4,859' 7' Proposed TBD Beluga G3 ±5,373' ±5,383' ±4,880' ±4,890' 10' Proposed TBD Beluga G4 ±5,410' ±5,416' ±4,914' ±4,920' 6' Proposed TBD Beluga G8 ±5,485' ±5,490' ±4,986' ±4,991' 5' Proposed TBD Beluga G10 ±5,560' ±5,571' ±5,058' ±5,069' 11' Proposed TBD Beluga H2 ±5,657' ±5,673' ±5,152' ±5,168' 16' Proposed TBD Beluga H3 ±5,693' ±5,703' ±5,188' ±5,198' 10' Proposed TBD Beluga H4 ±5,753' ±5,760' ±5,247' ±5,254' 7' Proposed TBD Beluga H5 5,767' 5,786' 5,260' 5,269' 9' 8/7/20 2-7/8” Beluga H7 ±5,832' ±5,846' ±5,323' ±5,337' 14' Proposed TBD Beluga H8 ±5,861' ±5,878' ±5,352' ±5,369' 17' Proposed TBD Beluga H11 ±5,999' ±6,002' ±5,486' ±5,489' 3' Proposed TBD Beluga H12 ±6,024' ±6,029' ±5,511' ±5,516' 5' Proposed TBD Beluga H12 6,044' 6,057' 5,531' 5,544' 13' 8/7/20 2-7/8” Beluga H15 6,175' 6,195' 5,659' 5,679' 20' 8/7/20 2-7/8” Beluga I ±6,256' ±6,269' ±5,738' ±5,751' 13' Proposed TBD Beluga I1 ±6,300' ±6,306' ±5,782' ±5,788' 6' Proposed TBD Beluga I2 6,336' 6,343' 5,817' 5,824' 7' 8/7/20 2-7/8” Beluga I6 6,472' 6,493' 5,951' 5,972' 21' 8/7/20 2-7/8” Beluga I8 ±6,536' ±6,555' ±6,014' ±6,033' 19' Proposed TBD Beluga I11 ±6,660' ±6,680' ±6,137' ±6,157' 20' Proposed TBD Beluga I12 ±6,736' ±6,742' ±6,210' ±6,216' 6' Proposed TBD Beluga I12 ±6,759' ±6,766' ±6,234' ±6,241' 7' Proposed TBD Beluga J1 ±6,819' ±6,835' ±6,293' ±6,309' 16' Proposed TBD Beluga J2 ±6,891' ±6,899' ±6,364' ±6,372' 8' Proposed TBD Bel H7-H12 Bel I8-J2 Bel I-I1 Bel G1-H4 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: CTCO, N2 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field: Current Pools: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 7,485'N/A Casing Collapse Structural Conductor 1,410psi Surface 3,090psi Intermediate Production 8,730psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY Jake Flora, Operations Engineer jake.flora@hilcorp.com 907-777-8442 Noel Nocas, Operations Manager 907-564-5278 Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: N/A N/A May 1, 2023 Swell Pkr & N/A 2,494 (MD) 2,312 (TVD) & N/A See Schematic See Schematic N/A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL021128 220-243 50-283-20180-00-00 Beluga River Sterling-Beluga Gas Same CO 802 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 222-24 Length Size Proposed Pools: TVD Burst PRESENT WELL CONDITION SUMMARY 6,949' 7,388' 6,854' 2,243 N/A MD 2,980psi 5,750psi 120' 2,526' 120' 2,739' Perforation Depth MD (ft): 7,475' 5-1/2" 16" 9-5/8" 120' 2,739' 10,600psi6,759'7,475' m n P s t 2 66 Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 323-209 By Kayla Junke at 11:49 am, Apr 06, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361), ou=Users Date: 2023.04.06 09:45:30 -08'00' Noel Nocas (4361) GCW 04/14/23 JLC 4/14/2023 04/17/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.04.17 18:06:13 -08'00' 220043 RBDMS JSB 041823 Well Prognosis Well Name: BRU 222-24 API Number: 50-283-20180-00 Regulatory Contact: Donna Ambruz Permit to Drill Number: 220-043 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (M) Second Call Engineer: Chad Helgeson (907) 777-8420 (O) (907) 229-4824 (M) Maximum Expected BHP: ~ 2689 psi @ 5951’ TVD (0.452 psi/ft gradient to bottom perf) Max. Potential Surface Pressure: ~2094 psi (Max expected BHP minus gas to surface) Well Status: Online Gas Producer: Last well test on 3/23/2022: 2525 MCFD / 9 BWPD / 347# Brief Well Summary 222-24 was drilled in 2020 and completed as a Beluga H and I producer. The well location is close to the crest of the H and I sands. The well was completed as a 5.5” monobore. RFT data indicated limited depletion in H and I and some less depleted zones in the G sands. No wellwork has been completed on the well and it has produced 2.6 BCF. Based on decline curve analysis, the well is expected to produce and additional 2.5 BCF from the current perforations. 222-24 is currently ~1.5 mmscf below unloading rate. The rate would need to be ~4.2mmscfd or higher to be over unloading rate at current pressures. The objective of this sundry is to increase rate by cleaning out the wellbore. Last Downhole Operation: 11-11-22 2” DDB to 5820’, tag fill Procedure 1. Review approved COAs 2. Provide 48hrs notice to AOGCC of BOP test 3. MIRU Coiled Tubing, PT BOPE to 3000 psi Hi 250 Low 4. SI well 5. Route well production to open top diffuser tank 6. RIH w/ 1.75” coil w/ jet nozzle BHA a. Top of fill was recorded to be @ 5820’. Engage fill and clean out to ~7000’ (below bottom perf) using nitrogen and gel sweeps as necessary to lift solids b. Blow well dry while holding back pressure to prevent more solids from entering well bore 7. Leave 1,000 psi on well. RDMO CTU 8. Return to production Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Coil Tubing BOP Diagram 4. Nitrogen SOP Updated by JMF 04-03-23 SCHEMATIC Beluga River Unit BRU 222-24 PTD: 220-043 API: 50-283-20180-00-00 PBTD = 7,388’ MD / TVD = 6,854’ TD = 7,485’ MD / TVD = 6,949’ RKB to GL = 18’ PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Comments Beluga H5 5,767' 5,786' 5,260' 5,269' 9' 8/7/20 2-7/8” Beluga H12 6,044' 6,057' 5,531' 5,544' 13' 8/7/20 2-7/8” Beluga H15 6,175' 6,195' 5,659' 5,679' 20' 8/7/20 2-7/8” Beluga I2 6,336' 6,343' 5,817' 5,824' 7' 8/7/20 2-7/8” Beluga I6 6,472' 6,493' 5,951' 5,972' 21' 8/7/20 2-7/8” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,739’ 5-1/2" Prod Csg 17 P-110 ICY TXP BTC 4.892” Surf 7,475’ 1 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,494’ - - Swell Packer 8-1/2” hole Bel H5 Bel I2, I6 Tag fill at 5820’ (11-11-22) Bel H12 Bel H15 Updated by JMF 04-03-23 PROPOSED Beluga River Unit BRU 222-24 PTD: 220-043 API: 50-283-20180-00-00 PBTD = 7,388’ MD / TVD = 6,854’ TD = 7,485’ MD / TVD = 6,949’ RKB to GL = 18’ PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Comments Beluga H5 5,767' 5,786' 5,260' 5,269' 9' 8/7/20 2-7/8” Beluga H12 6,044' 6,057' 5,531' 5,544' 13' 8/7/20 2-7/8” Beluga H15 6,175' 6,195' 5,659' 5,679' 20' 8/7/20 2-7/8” Beluga I2 6,336' 6,343' 5,817' 5,824' 7' 8/7/20 2-7/8” Beluga I6 6,472' 6,493' 5,951' 5,972' 21' 8/7/20 2-7/8” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,739’ 5-1/2" Prod Csg 17 P-110 ICY TXP BTC 4.892” Surf 7,475’ 1 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,494’ - - Swell Packer 8-1/2” hole Bel H5 Bel I2, I6 Bel H12 Bel H15 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport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y Samantha Carlisle at 8:08 am, Apr 06, 2022 'LJLWDOO\VLJQHGE\'DQ0DUORZH '1FQ 'DQ0DUORZH RX 8VHUV 'DWH 'DQ0DUORZH '656)' 6WHUOLQJ%HOXJD*DV3RRO6)' &26)' %-0 -/& Gregory Wilson Digitally signed by Gregory Wilson Date: 2022.09.26 14:40:07 -08'00' RBDMS JSB 092922 tĞůůWƌŽŐŶŽƐŝƐ tĞůůEĂŵĞ͗ZhϮϮϮͲϮϰW/EƵŵďĞƌ͗ϱϬͲϮϴϯͲϮϬϭϴϬͲϬϬ ZĞŐƵůĂƚŽƌǇŽŶƚĂĐƚ͗:ƵĂŶŝƚĂ>ŽǀĞƚƚϳϳϳͲϴϯϯϮWĞƌŵŝƚƚŽƌŝůůEƵŵďĞƌ͗ϮϮϬͲϬϰϯ &ŝƌƐƚĂůůŶŐŝŶĞĞƌ͗:ĂŬĞ&ůŽƌĂ;ϵϬϳͿϳϳϳͲϴϰϰϮ;KͿ;ϳϮϬͿϵϴϴͲϱϯϳϱ;DͿ ^ĞĐŽŶĚĂůůŶŐŝŶĞĞƌ͗ŚĂĚ,ĞůŐĞƐŽŶ;ϵϬϳͿϳϳϳͲϴϰϮϬ;KͿ;ϵϬϳͿϮϮϵͲϰϴϮϰ;DͿ DĂǆŝŵƵŵǆƉĞĐƚĞĚ,W͗ΕϮϴϴϬƉƐŝΛϲϯϳϮ͛ds ;Ϭ͘ϰϱϮƉƐŝͬĨƚŐƌĂĚŝĞŶƚƚŽďŽƚƚŽŵƉĞƌĨͿ DĂǆ͘WŽƚĞŶƚŝĂů^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ͗ΕϮϮϰϯƉƐŝ ;DĂǆĞǆƉĞĐƚĞĚ,WŵŝŶƵƐŐĂƐƚŽƐƵƌĨĂĐĞͿ tĞůů^ƚĂƚƵƐ͗ KŶůŝŶĞ'ĂƐWƌŽĚƵĐĞƌ͗>ĂƐƚǁĞůůƚĞƐƚŽŶϯͬϮϯͬϮϬϮϮ͗ϮϱϮϱD&ͬϵtWͬϯϰϳη ƌŝĞĨtĞůů^ƵŵŵĂƌǇ ϮϮϮͲϮϰǁĂƐĚƌŝůůĞĚŝŶϮϬϮϬĂŶĚĐŽŵƉůĞƚĞĚĂƐĂĞůƵŐĂ,ĂŶĚ/ƉƌŽĚƵĐĞƌ͘dŚĞǁĞůůůŽĐĂƚŝŽŶŝƐĐůŽƐĞƚŽƚŚĞĐƌĞƐƚ ŽĨƚŚĞ,ĂŶĚ/ƐĂŶĚƐ͘dŚĞǁĞůůǁĂƐĐŽŵƉůĞƚĞĚĂƐĂϱ͘ϱ͟ŵŽŶŽďŽƌĞ͘Z&dĚĂƚĂŝŶĚŝĐĂƚĞĚůŝŵŝƚĞĚĚĞƉůĞƚŝŽŶŝŶ, ĂŶĚ/ĂŶĚƐŽŵĞůĞƐƐĚĞƉůĞƚĞĚǌŽŶĞƐŝŶƚŚĞ'ƐĂŶĚƐ͘EŽǁĞůůǁŽƌŬŚĂƐďĞĞŶĐŽŵƉůĞƚĞĚŽŶƚŚĞǁĞůůĂŶĚŝƚŚĂƐ ƉƌŽĚƵĐĞĚϮ͘ϲ&͘ĂƐĞĚŽŶĚĞĐůŝŶĞĐƵƌǀĞĂŶĂůǇƐŝƐ͕ƚŚĞǁĞůůŝƐĞǆƉĞĐƚĞĚƚŽƉƌŽĚƵĐĞĂŶĚĂĚĚŝƚŝŽŶĂůϮ͘ϱ&ĨƌŽŵ ƚŚĞĐƵƌƌĞŶƚƉĞƌĨŽƌĂƚŝŽŶƐ͘ϮϮϮͲϮϰŝƐĐƵƌƌĞŶƚůǇΕϭ͘ϱŵŵƐĐĨďĞůŽǁƵŶůŽĂĚŝŶŐƌĂƚĞ͘dŚĞƌĂƚĞǁŽƵůĚŶĞĞĚƚŽďĞ Εϰ͘ϮŵŵƐĐĨĚŽƌŚŝŐŚĞƌƚŽďĞŽǀĞƌƵŶůŽĂĚŝŶŐƌĂƚĞĂƚĐƵƌƌĞŶƚƉƌĞƐƐƵƌĞƐ͘ dŚĞŽďũĞĐƚŝǀĞŽĨƚŚŝƐƐƵŶĚƌǇŝƐƚŽŝŶĐƌĞĂƐĞƌĂƚĞďǇƉĞƌĨŽƌĂƚŝŶŐĂĚĚŝƚŝŽŶĂůĞůƵŐĂƐĂŶĚƐ͘ >ĂƐƚŽǁŶŚŽůĞKƉĞƌĂƚŝŽŶ͗ ϴͬϳͬϮϬϮϬ WĞƌĨŽƌĂƚĞĚĞůƵŐĂ,ϱƐĂŶĚƐϱϳϲϳͲϱϳϴϲ͛ WƌŽĐĞĚƵƌĞ͗ ϭ͘D/ZhͲůŝŶĞ͕WdůƵďƌŝĐĂƚŽƌƚŽϮϱϬϬƉƐŝ Ϯ͘WĞƌĨŽƌĂƚĞĞůƵŐĂƐĂŶĚƐǁŝƚŚŝŶƚŚĞďĞůŽǁŝŶƚĞƌǀĂů͗ Ă͘ĞůƵŐĂ'ϭƚŽĞůƵŐĂ:ϮƐĂŶĚƐ͗ΕϱϮϴϵ͛Ͳϲϴϵϵ͛D;ΕϰϴϬϬ͛ͲϲϯϳϮ͛dsͿ ď͘ůůƐĂŶĚƐůŝĞŝŶƚŚĞ>h'Z/sZhE&/E'^WKK> ϯ͘ZĞƚƵƌŶƚŽƉƌŽĚƵĐƚŝŽŶ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ĐƚƵĂů^ĐŚĞŵĂƚŝĐ Ϯ͘WƌŽƉŽƐĞĚ^ĐŚĞŵĂƚŝĐ ΕϱϮϴϵ͛Ͳϲϴϵϵ͛D;ΕϰϴϬϬ͛ͲϲϯϳϮ͛dsͿ ŽŝŶĐƌĞĂƐĞƌĂƚĞďǇƉĞƌĨŽƌĂƚŝŶŐĂĚĚŝƚŝŽŶĂůĞůƵŐĂƐĂŶĚƐ͘ %HOXJD5LYHU6WHUOLQJ%HOXJD*DV3RROJRYHUQHGE\&2LVVXHG0D\ 6)' hƉĚĂƚĞĚďǇ:ϬϴͲϮϰͲϮϬ ^,Dd/ ĞůƵŐĂZŝǀĞƌhŶŝƚ ZhϮϮϮͲϮϰ Wd͗ϮϮϬͲϬϰϯ W/͗ϱϬͲϮϴϯͲϮϬϭϴϬͲϬϬͲϬϬ Wdсϳ͕ϯϴϴ͛Dͬdsсϲ͕ϴϱϰ͛ dсϳ͕ϰϴϱ͛Dͬdsсϲ͕ϵϰϵ͛ Z<ƚŽ'>сϭϴ͛ WZ&KZd/KEd/> ^ĂŶĚdŽƉDƚŵDdŽƉdsƚŵds&ƚĂƚĞŽŵŵĞŶƚƐ ĞůƵŐĂ,ϱϱ͕ϳϲϳΖϱ͕ϳϴϲΖϱ͕ϮϲϬΖϱ͕ϮϲϵΖϵΖϴͬϳͬϮϬϮͲϳͬϴ͟ ĞůƵŐĂ,ϭϮϲ͕ϬϰϰΖϲ͕ϬϱϳΖϱ͕ϱϯϭΖϱ͕ϱϰϰΖϭϯΖϴͬϳͬϮϬϮͲϳͬϴ͟ ĞůƵŐĂ,ϭϱϲ͕ϭϳϱΖϲ͕ϭϵϱΖϱ͕ϲϱϵΖϱ͕ϲϳϵΖϮϬΖϴͬϳͬϮϬϮͲϳͬϴ͟ ĞůƵŐĂ/Ϯϲ͕ϯϯϲΖϲ͕ϯϰϯΖϱ͕ϴϭϳΖϱ͕ϴϮϰΖϳΖϴͬϳͬϮϬϮͲϳͬϴ͟ ĞůƵŐĂ/ϲϲ͕ϰϳϮΖϲ͕ϰϵϯΖϱ͕ϵϱϭΖϱ͕ϵϳϮΖϮϭΖϴͬϳͬϮϬϮͲϳͬϴ͟ ^/E'd/> ^ŝǌĞdǇƉĞtƚ'ƌĂĚĞŽŶŶ͘/dŽƉƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌʹƌŝǀĞŶ ƚŽ^ĞƚĞƉƚŚϴϰyͲϱϲ tĞůĚ ϭϱ͘Ϭϭ͟^ƵƌĨϭϮϬΖ ϵͲϱͬϴΗ^ƵƌĨƐŐϰϳ>ͲϴϬdϴ͘ϲϴϭ͟^ƵƌĨϮ͕ϳϯϵ͛ ϱͲϭͬϮΗWƌŽĚƐŐϭϳWͲϭϭϬ/zdyWdϰ͘ϴϵϮ͟^ƵƌĨϳ͕ϰϳϱ͛ ϭ ϭϲ͟ ϵͲϱͬϴ͟ ϭϮͲϭͬϰ͟ ŚŽůĞ ϱͲϭͬϮ͟ :t>Zzd/> EŽ͘ĞƉƚŚ/K/ƚĞŵ ϭϮ͕ϰϵϰ͛ͲͲ^ǁĞůůWĂĐŬĞƌ ϴͲϭͬϮ͟ ŚŽůĞ Ğů, Ğů/ hƉĚĂƚĞĚďǇ:>>ϬϰͬϬϱͬϮϮ WZKWK^ ĞůƵŐĂZŝǀĞƌhŶŝƚ ZhϮϮϮͲϮϰ Wd͗ϮϮϬͲϬϰϯ W/͗ ϱϬͲϮϴϯͲϮϬϭϴϬͲϬϬͲϬϬ Wdсϳ͕ϯϴϴ͛Dͬdsсϲ͕ϴϱϰ͛ dсϳ͕ϰϴϱ͛Dͬdsсϲ͕ϵϰϵ͛ Z<ƚŽ'>сϭϴ͛ WZ&KZd/KEd/> ^ĂŶĚ dŽƉD ƚŵD dŽƉds ƚŵds &ƚ ĂƚĞ ŽŵŵĞŶƚƐ >'ϭʹ >:Ϯ цϱ͕Ϯϴϵ͛ цϲ͕ϴϵϵ͛ цϰϴϬϬ͛ цϲϯϳϮ͛ цϭ͕ϲϭϬ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ ĞůƵŐĂ,ϱ ϱ͕ϳϲϳΖ ϱ͕ϳϴϲΖ ϱ͕ϮϲϬΖ ϱ͕ϮϲϵΖ ϵΖ ϴͬϳͬϮϬ ϮͲϳͬϴ͟ ĞůƵŐĂ,ϭϮ ϲ͕ϬϰϰΖ ϲ͕ϬϱϳΖ ϱ͕ϱϯϭΖ ϱ͕ϱϰϰΖ ϭϯΖ ϴͬϳͬϮϬ ϮͲϳͬϴ͟ ĞůƵŐĂ,ϭϱ ϲ͕ϭϳϱΖ ϲ͕ϭϵϱΖ ϱ͕ϲϱϵΖ ϱ͕ϲϳϵΖ ϮϬΖ ϴͬϳͬϮϬ ϮͲϳͬϴ͟ ĞůƵŐĂ/Ϯ ϲ͕ϯϯϲΖ ϲ͕ϯϰϯΖ ϱ͕ϴϭϳΖ ϱ͕ϴϮϰΖ ϳΖ ϴͬϳͬϮϬ ϮͲϳͬϴ͟ ĞůƵŐĂ/ϲ ϲ͕ϰϳϮΖ ϲ͕ϰϵϯΖ ϱ͕ϵϱϭΖ ϱ͕ϵϳϮΖ ϮϭΖ ϴͬϳͬϮϬ ϮͲϳͬϴ͟ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘ / dŽƉ ƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌʹƌŝǀĞŶ ƚŽ^ĞƚĞƉƚŚ ϴϰ yͲϱϲ tĞůĚ ϭϱ͘Ϭϭ͟ ^ƵƌĨ ϭϮϬΖ ϵͲϱͬϴΗ ^ƵƌĨƐŐ ϰϳ >ͲϴϬ d ϴ͘ϲϴϭ͟ ^ƵƌĨ Ϯ͕ϳϯϵ͛ ϱͲϭͬϮΗ WƌŽĚƐŐ ϭϳ WͲϭϭϬ/z dyWd ϰ͘ϴϵϮ͟ ^ƵƌĨ ϳ͕ϰϳϱ͛ ϭ ϭϲ͟ ϵͲϱͬϴ͟ ϭϮͲϭͬϰ͟ ŚŽůĞ ϱͲϭͬϮ͟ :t>Zzd/> EŽ͘ ĞƉƚŚ / K /ƚĞŵ ϭ Ϯ͕ϰϵϰ͛ Ͳ Ͳ ^ǁĞůůWĂĐŬĞƌ ϴͲϭͬϮ͟ ŚŽůĞ Ğů, Ğů/ >'ϭ ƚŚƌƵ>:Ϯ D7HVW,QLWLDO $QQXDO 6SHFLDO E7\SH7HVW 6WDELOL]HG 1RQ6WDELOL]HG 0XOWLSRLQW &RQVWDQW7LPH ,VRFKURQDO 2WKHU 2SHUDWRU1DPH'DWH&RPSOHWHG 3HUPLWWR'ULOO1XPEHU $GGUHVV'DWH7'5HDFKHG $3,1XPEHU D/RFDWLRQRI:HOO*RYHUQPHQWDO6HFWLRQ.%(OHYDWLRQDERYH06/IHHW :HOO1DPHDQG1XPEHU 6XUIDFH 7RSRI3URGXFWLYH+RUL]RQ3OXJ%DFN'HSWK0'79' )LHOG3RROV 7RWDO'HSWK7RWDO'HSWK0'79' E/RFDWLRQRI:HOO6WDWH%DVH3ODQH&RRUGLQDWHV1$'/DQG8VH3HUPLW 3URSHUW\'HVLJQDWLRQ 6XUIDFH[ \ =RQH 73,[ \ =RQH 7\SHRI&RPSOHWLRQ'HVFULEH 7RWDO'HSWK[ \ =RQH &DVLQJ6L]H :HLJKWSHUIRRWOE,'LQLQFKHV 6HWDWIW 3HUIRUDWLRQV )URP 7XELQJ6L]H :HLJKWSHUIRRWOE,'LQLQFKHV 6HWDWIW 3DFNHUVHWDWIW*25FIEEO $3,/LTXLG+\GURFDUGERQV 6SHFLILF*UDYLW\)ORZLQJ)OXLG* D3URGXFLQJWKURXJKE5HVHUYRLU7HPS F5HVHUYRLU3UHVVXUH G%DURPHWULF3UHVVXUH3D 7XELQJ &DVLQJ )R SVLD#'DWXP 79'66 SVLD /HQJWKRI)ORZ&KDQQHO/9HUWLFDO'HSWK+1+6 ; ; ; ; ; IRU6HSDUDWRU *DV *J IRU)ORZLQJ )OXLG * ] 'LII +Z *J&2 7HPS )R 1$ 7R 0' 0' 1$ 0' 79' 0HWHU5XQ7DSV3URYHU %HOXJD5LYHU8QGHI*DV 3URGXFWLRQ6WULQJ3HUIRUDWHG $'/ &$6,1*'$7$78%,1*'$7$ 67$7(2)$/$6.$ $/$6.$2,/$1'*$6&216(59$7,21&200,66,21 *$6:(//23(1)/2:327(17,$/7(675(3257 +LOFRUS$ODVND//& &HQWHUSRLQW'ULYH6XLWH$QFKRUDJH$. )1/ ):/6HF715:60$. )1/ ):/6HF715:60$. )1/ ):/6HF715:60$. 7HPS )R 3UHVVXUH SVLJ 7HPS )R 3UHVVXUH SVLJ 3UHVVXUH 3P )ORZ7HPS )DFWRU )W *UDYLW\)DFWRU )J 6XSHU&RPS )DFWRU )SY 5DWHRI)ORZ 40FIG )/2:'$7$ 'XUDWLRQRI)ORZ +U KZ3P 3UHVVXUH SVLJ 3URYHU /LQH 6L]HLQ 1R &KRNH 2ULILFH 6L]HLQ ; 1R %DVLF&RHIILFLHQW +RXU )ERU)S 1R3U 7HPSHUDWXUH 7 7U &ULWLFDO3UHVVXUH &ULWLFDO7HPSHUDWXUH 1RGDOBBBBBBBBBBBB %58 %HOXJD5LYHU ,QL $Q ,VR 0X6S6WD &R 1R 7X & 2W )RUP5HY &217,18('215(9(56(6,'( 6XEPLWLQ'XSOLFDWH By Hugh Winston at 12:00 pm, Mar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anual of Back- Pressure Testing of Gas Wells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amuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 01/27/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 222-24 (PTD 220-043) RCBL MAIN PASS FINAL PASS 08/01/2020 Please include current contact information if different from above. Received by the AOGCC 01/27/2021 PTD: 2200430 E-Set: 34625 Abby Bell 01/27/2021 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-283-20180-00-00Well Name/No.BELUGA RIV UNIT 222-24Completion Status1-GASCompletion Date8/7/2020Permit to Drill2200430OperatorHilcorp Alaska, LLCMD7485TVD6949Current Status1-GAS11/12/2020UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:CBL 8-1-20 / ROP, DGR, AGR, ABG, ADR, EWR MD & TVD, GeoTap, Mud logNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF9/11/202010 7550 Electronic Data Set, Filename: BRU 222-24 las Data.las33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Geolog AM Reports.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - Final Well Report.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - 5in Drilling Dynamics Log MD.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - 5in Drilling Dynamics Log TVD.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - 5in Formation Log MD.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - 5in Formation Log TVD.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - 5in Gas Ratio Log MD.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - 5in Gas Ratio Log TVD.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - 5in LWD Combo Log MD.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - 5in LWD Combo Log TVD.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - Drilling Dynamics Log MD.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - Drilling Dynamics Log TVD.pdf33830EDDigital DataThursday, November 12, 2020AOGCC Page 1 of 6BRU 222-24 las Data.lasSupplied by OPSupplied by OP DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-283-20180-00-00Well Name/No.BELUGA RIV UNIT 222-24Completion Status1-GASCompletion Date8/7/2020Permit to Drill2200430OperatorHilcorp Alaska, LLCMD7485TVD6949Current Status1-GAS11/12/2020UICNoDF9/11/2020 Electronic File: BRU 222-24 - Formation Log MD.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - Formation Log TVD.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - Gas Ratio Log MD.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - Gas Ratio Log TVD.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - LWD Combo Log MD.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - LWD Combo Log TVD.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - 5in Drilling Dynamics Log MD.tif33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - 5in Drilling Dynamics Log TVD.tif33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - 5in Formation Log MD.tif33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - 5in Formation Log TVD.tif33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - 5in Gas Ratio Log MD.tif33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - 5in Gas Ratio Log TVD.tif33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - 5in LWD Combo Log MD.tif33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - 5in LWD Combo Log TVD.tif33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - Drilling Dynamics Log MD.tif33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - Drilling Dynamics Log TVD.tif33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - Formation Log MD.tif33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - Formation Log TVD.tif33830EDDigital DataThursday, November 12, 2020AOGCC Page 2 of 6 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-283-20180-00-00Well Name/No.BELUGA RIV UNIT 222-24Completion Status1-GASCompletion Date8/7/2020Permit to Drill2200430OperatorHilcorp Alaska, LLCMD7485TVD6949Current Status1-GAS11/12/2020UICNoDF9/11/2020 Electronic File: BRU 222-24 - Gas Ratio Log MD.tif33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - Gas Ratio Log TVD.tif33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - LWD Combo Log MD.tif33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 - LWD Combo Log TVD.tif33830EDDigital DataDF9/11/2020 Electronic File: BRU222-24.dbf33830EDDigital DataDF9/11/2020 Electronic File: bru222-24.hdr33830EDDigital DataDF9/11/2020 Electronic File: BRU222-24.mdx33830EDDigital DataDF9/11/2020 Electronic File: bru222-24r.dbf33830EDDigital DataDF9/11/2020 Electronic File: bru222-24r.mdx33830EDDigital DataDF9/11/2020 Electronic File: BRU222-24_SCL.DBF33830EDDigital DataDF9/11/2020 Electronic File: BRU222-24_SCL.MDX33830EDDigital DataDF9/11/2020 Electronic File: BRU222-24_tvd.dbf33830EDDigital DataDF9/11/2020 Electronic File: BRU222-24_tvd.mdx33830EDDigital DataDF9/11/2020 Electronic File: English.scl33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 1 3605-3629.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 10 5833-5846.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 11 5860-5890.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 12 5954-5984.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 13 6040-6060.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 14 6063-6113.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 15 6176-6197.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 16 6258-6270.pdf33830EDDigital DataThursday, November 12, 2020AOGCC Page 3 of 6 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-283-20180-00-00Well Name/No.BELUGA RIV UNIT 222-24Completion Status1-GASCompletion Date8/7/2020Permit to Drill2200430OperatorHilcorp Alaska, LLCMD7485TVD6949Current Status1-GAS11/12/2020UICNoDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 17 6300-6307.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 18 6338-6346.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 19 6470-6496.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 2 3644-3649.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 20 6540-6559.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 21 6733-6745.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 22 6818-6838.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 23 6880-6927.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 24 7307-7332.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 3 4012-4032.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 4 4041-4072.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 5 4535-4547.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 6 5216-5232.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 7 5286-5293.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 8 5659-5678.pdf33830EDDigital DataDF9/11/2020 Electronic File: BRU 222-24 Gas Show Report 9 5769-5786.pdf33830EDDigital Data0 0 2200430 BELUGA RIV UNIT 222-24 LOG HEADERS33830LogLog Header ScansDF9/14/202082 7485 Electronic Data Set, Filename: BRU 222-24 LWD Final.las33834EDDigital DataThursday, November 12, 2020AOGCC Page 4 of 6BRU 222-24 LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-283-20180-00-00Well Name/No.BELUGA RIV UNIT 222-24Completion Status1-GASCompletion Date8/7/2020Permit to Drill2200430OperatorHilcorp Alaska, LLCMD7485TVD6949Current Status1-GAS11/12/2020UICNoDF9/14/2020 Electronic File: BRU 222-24 Geo-Tap Pressure Test Time.cgm33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 LWD Final MD.cgm33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 LWD Final TVD.cgm33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 XBAT Final MD.cgm33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 XBAT Final TVD.cgm33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 - Definitive Survey Report.pdf33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 Surveys.xlsx33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24_DSR.txt33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24_GIS.txt33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 Geo-Tap Pressure Test Time.emf33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 LWD Final MD.emf33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 LWD Final TVD.emf33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 XBAT Final MD.emf33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 XBAT Final TVD.emf33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 Geo-Tap Pressure Test Time.pdf33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 LWD Final MD.pdf33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 LWD Final TVD.pdf33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 XBAT Final MD.pdf33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 XBAT Final TVD.pdf33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 Geo-Tap Pressure Test Time.tif33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 LWD Final MD.tif33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 LWD Final TVD.tif33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 XBAT Final MD.tif33834EDDigital DataDF9/14/2020 Electronic File: BRU 222-24 XBAT Final TVD.tif33834EDDigital Data0 0 2200430 BELUGA RIV UNIT 222-24 LOG HEADERS33834LogLog Header ScansThursday, November 12, 2020AOGCC Page 5 of 6 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-283-20180-00-00Well Name/No.BELUGA RIV UNIT 222-24Completion Status1-GASCompletion Date8/7/2020Permit to Drill2200430OperatorHilcorp Alaska, LLCMD7485TVD6949Current Status1-GAS11/12/2020UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:8/7/2020Release Date:4/30/2020DF11/6/20207402 2326 Electronic Data Set, Filename: BRU 222-24 RCBL 08-01-2020.las34197EDDigital DataDF11/6/2020 Electronic File: BRU 222-24 RCBL 08-01-2020.pdf34197EDDigital Data0 0 2200430 BELUGA RIV UNIT 222-24 LOG HEADERS34197LogLog Header Scans9/10/20202747 748541765CuttingsThursday, November 12, 2020AOGCC Page 6 of 6M. Guhl11/12/2020 David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: Date: 11/06/2020 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 222-24 (PTD 220-043) 1.RCBL – Radial Cement Bond Log (08/01/2020) Folder Contents: Please include current contact information if different from above. Received by the AOGCC 11/06/2020 PTD: 2200430 E-Set: 34197 Abby Bell 11/06/2020 Dvid Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-5256 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE 9/14/2020 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 222-24 (PTD 220-043) BRU 222-24_FINAL_DATA_CD 1> LWD – DGR – EWR4 - ADR – CTN - ALD 2>XBAT – Bi-Modal Acoustic 3>GeoTap – Formation Pressures 4>Definitive Directional Survey Please include current contact information if different from above. Received by the AOGCC 09/14/2020 PTD: 2200430 E-Set: 33834 Abby Bell 09/14/2020 Dvid Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-5256 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE 9/11/2020 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 222-24 (PTD 220-043) FINAL CD – EOW DRILL REPORTS-LWD LOGS-MUDLOGS Please include current contact information if different from above. Received by the AOGCC 09/11/2020 PTD: 2200430 E-Set: 33830 Abby Bell 09/11/2020 DATE 9/09/2020 David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 CenterPoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 222-24 (PTD 220-043) WELL BOX SAMPLE INTERVAL (FEET / MD) BRU 222-24 BOX 1 OF 4 2747'- 3930' MD BRU 222-24 BOX 2 OF 4 3930'- 5460' MD BRU 222-24 BOX 3 OF 4 5460' - 6900' MD BRU 222-24 BOX 4 OF 4 6900'- 7485' MD (TD) Please include current contact information if different from above. RECEIVED SEP 10 2020 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal via Email or FAX to: (907)777-8510 Received � �� Date: (� I v' 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): GL: 74.2' BF:74.2' Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22. Logs Obtained: 23. BOTTOM 16" X-56 120' 9-5/8" L-80 2,526' 5-1/2" P-110 6,937' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate1200 July 13, 2020 July 2, 2020 ADL021128 N/A N/A N/AN/A N/A 7,485' MD / 6,949' TVD CBL 8-1-20 / ROP, DGR, AGR, ABG, ADR, EWR MD & TVD, GeoTap, Mud log Sr Res EngSr Pet GeoSr Pet Eng N/A N/A Oil-Bbl: Water-Bbl: 007510 Oil-Bbl: suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary N/A7510 Flowing **Please see attached schematic for perforation detail** 0 Water-Bbl: PRODUCTION TEST 8/7/2020 Date of Test: 380 8/16/2020 24 Flow Tubing 0 84# 47# 120' Surface 7,475' Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information 17# Surface DEPTH SET (MD) PACKER SET (MD/TVD) Surface CASING WT. PER FT.GRADE 325450 325750 TOP SETTING DEPTH MD Surface SETTING DEPTH TVD 2634156 BOTTOM TOP 8-1/2" 68 bbls Surface 12-1/4" HOLE SIZE AMOUNT PULLED 50-283-20180-00-00 BRU 222-24 323354 2633581 1512' FNL, 2106' FWL, Sec 24, T13N, R10W, SM, AK CEMENTING RECORD 2634087 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 8/7/2020 2049' FNL, 17' FWL, Sec 24, T13N, R10W, SM, AK 1438' FNL, 2404' FWL, Sec 24, T13N, R10W, SM, AK 220-043 / 320-309 Beluga River / Beluga River Undef Gas 92.6' 7,388' MD / 6,854' MD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas Conductor Surface 2,739' L - 459 sx / T - 235 sx Driven L - 555 sx / T - 115 sx N/A SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, TUBING RECORD WINJ SPLUGOther Abandoned Suspended Stratigraphic Test No No (attached) No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 4:40 pm, Aug 24, 2020 RBDMS HEW 8/25/2020 Completion Date 8/7/2020 HEW DSR-10/14/2020DLB 08/25/2020 gls 10/22/20 7510 G SFD 9/1/2020 G Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A N/A Top of Productive Interval Bel H5 5,767' 5,260' 3,812' 3,479' 3,983' 3,630' 4,237' 3,856' 4,459' 4,055' 4,777' 4,339' 5,261' 4,778' 5,576' 5,078' 6,243' 5,730' 6,775' 6,253' Beluga J7 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Cody Dinger Contact Email:cdinger@hilcorp.com Authorized Contact Phone: 777-8389 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Beluga J Formation at total depth: Beluga E Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Report. Signature w/Date: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. INSTRUCTIONS Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME Beluga I Beluga F Sterling C Beluga D Sterling B This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager Beluga G Beluga H Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS Permafrost - Top No NoSidewall Cores: Yes No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment Digitally signed by Cody Dinger DN: cn=Cody Dinger, ou=Users Date: 2020.08.24 16:00:07 - 08'00' Cody Dinger Updated by CJD 08-24-20 SCHEMATIC Beluga River Unit BRU 222-24 PTD: 220-043 API: 50-283-20180-00-00 PBTD = 7,388’ MD / TVD = 6,854’ TD = 7,485’ MD / TVD = 6,949’ RKB to GL = 18’ PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Comments Beluga H5 5,767' 5,786' 5,260' 5,269' 9' 8/7/20 2-7/8” Beluga H12 6,044' 6,057' 5,531' 5,544' 13' 8/7/20 2-7/8” Beluga H15 6,175' 6,195' 5,659' 5,679' 20' 8/7/20 2-7/8” Beluga I2 6,336' 6,343' 5,817' 5,824' 7' 8/7/20 2-7/8” Beluga I6 6,472' 6,493' 5,951' 5,972' 21' 8/7/20 2-7/8” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 2,739’ 5-1/2" Prod Csg 17 P-110 ICY TXP BTC 4.892” Surf 7,475’ 1 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 2,494’ - - Swell Packer 8-1/2” hole Bel H Bel I SFD 9/1/2020 CBL shows TOC at 2450 ft. Good cement from 2500-5350 ft Poor cement from 5500-7500 ft (gls 10/22/20) (2494 ft)swell packer 5,278' 19' 2739 ft Activity Date Ops Summary 6/30/2020 Start AFE f/ 222-24, cont working on rig acceptance checklist, bring in and offload diverter equipment trailers, tested mudline, stand pipe and Kelly hose connections, Set in DSA on wellhead N/U Spool and T, Set annular on top, run diverter line, install knoife valve on T, install riser and flow;line, hook up chains and center riser over well, finish tightening all bolts, off load water into pits and upright water tank, continue rigging up rig components;Continue Rigging up modules, titghten bolts on diverter system, Install koomey lines and test function of annular, perform diverter test as per AOGCC Regulations. Load strap and tally DP on racks prep floor to pick up DP and stand back in derrick 7/1/2020 Set pipe racks, brought in, racked and tallied 4 1/2" DP. Replaced plugs on Pason "J" box to heal up hookload tracking and trip tank sensor. Replaced leaking annular 4 way valve on koomey unit, function tested diverter at 41 seconds closure for bag, 2 seconds opening for knife valve. Installed wear;ring in wellhead, MU muleshoe on DP, eased in and tagged bottom at 131’. Start PU racked back 85 stands DP (170 jnts of 220 planned). SLB Coil unit got BOP’s tested and RU, will not be done evacuating fluid from BRU 212-24T today. Quadco here at 17:00 hrs rigging up gas alarm system.;One Mud Engineer, four Sperry Reps and two GeoLog Reps in field as well.;Cont rack and tally 4 1/2" DP 202 jts total and 8 stands of HWDP;Continue building and mixing spud mud, and cleaning and organizing around rig, perform oil change on draw works motor, Service top drive and blocks, grease and inspect crown, perform derrick inspection, check suction and discharge screens in pumps, check pulsation dampers, repin pop offs t/ 3200 psi 7/2/2020 Cont wait on coil to finish BRU 212-24T. Prep slips and dog collar for drilling assembly, replaced o-ring on topdrive hydraulic hose, RU splash guard tarp around flow riser, hung floor drain hoses, RU liner wash hose to cuttings box, installed fluid discharge hose from centrifuge to pit #1, flooded;stack/conductor with spud mud (no leaks), prepped lift sub and XO’s for BHA, installed short mousehole, gen #1 wouldn’t start-replaced trickle charger, completed brake band, catwalk, iron roughneck, BOP hoist, floor motor transmission, all three gens PM’s. Coil pulled to surface and started RD.;Held PJSM with Sperry Reps, MU Smith 12 1/4" tri-cone and 8” mud motor, DM, RLL and TM collars (RFO= 52.95°), MU XO and first of two 6 1/2" NM Flex DC's. Plugged in and uploaded MWD, while coil unit finished RDMO. Shallow pulse tested tools at 113' with no issue.;SLB coil equipment pulled off location, re-located Peak crane and float on pad, barricaded off backside of location 75' from diverter vent line outlet and placed "well on diverter" signs. Prepped all hands for spud. NOTE: Barge loaded at OSK at 15:00 hrs with Halliburton cement/silo/compressor;Began circ at 350 gpm-224 psi, 45 rpm-1310 ft/lbs off bott torque. Eased down and tagged bottom, resumed drilling 12 1/4" surface hole from 131' to 546'. Rot WOB 1-6K, 450 gpm-724 psi, 40 rpm-1800 ft/lbs on bott torque, 45 to 180 ft/hr ROP, MW 8.9/vis 140, ECD's at 9.0 ppg. Began kick off at;300', building 3°/100';Drilling Ahead f/ 546' t/ 1050' 450 gpm 880 psi, 40 RPM 1500k tq on, 1300 k tq off, WOB 2-6k, 80-160 ROP, 9.33 ppg ECD, MW 8.8 ppg, Building 3° per 100', PUW 48k SOW46k ROT 46k Distance to plan 16.2' 16.1' low 1.8' Left;Cuttings Hauled - 145 bbls Cuttings Total Hauled - 145 Fluid Hauled - 0 bbls Fluid Hauled Total - 0 bbls Cement Hauled - 0 bbls Cement Total - 0 bbls Losses Daily - 0 bbls Total Losses - 0 bble 7/3/2020 Cont directionally drilling 12 1/4" surface hole from 1050' to 1384'. Rot wob 1-6K, 479 gpm-1156 psi, 60 rpm-3700 ft/lbs on bott torque, 160 ft/hr ROP. Sliding wob 3-9K, 480 gpm-1257 psi, 142 psi diff, 280 ft/hr ROP. MW 8.9/vis 170, ECD's at 9.8 ppg, BGG 0 units.;Started directionally turning to the left 3°/100’ at 1100’ md.;CBU one time at 480 gpm-1155 psi, 70 rpm-4361 ft/lbs off bott torque. Obtained survey.;Pulled up hole on elevators from 1384’ to 344’ with no issue, up wt 69K.;Serviced rig and topdrive. Received 642 sacks lead cement (478 in silo) then staged trucks for return trip to OSK on barge, flew cementers back to Tyonek Platform.;TIH on elevators from 410’ to 1316’ and tagged up solid numerous times. MU topdrive and washed to bottom at 1384’. Down wt 40K.;Pumped 20 bbl hi- vis sweep around at 459 gpm-1175 psi, 30 rpm-2756 ft/lbs off bott torque, back on time with 10% increase of sand. Made connection.;Cont directionally drilling 12 1/4" surface hole from 1384' to 1757', Rot wob 4K, 481 gpm-1358 psi, 73 rpm-5626 ft/lbs on bott torque, 130 ft/hr ROP. Sliding wob 6K, 480 gpm-1397 psi, 118 psi diff, 230 ft/hr ROP. MW 8.9/vis 160, ECD's at 9.7 ppg, BGG 0 units.;Drill 12 1/4" hole from 1757' to 2746' 480 gpm 1550 psi 68 rpm 9.2k on 8.8k off, 82k PUW 50k SOW 62k ROT, 9.0 ppg MW 9.58 ppg ECD, BGG Max 2.5 units, Distance to plan 16.0' Above 16' Left 4';Cuttings Hauled to A Pad - 605 bbls Cuttings Total Hauled - 750 Fluid Hauled to BRWD/1 Pad - 0 bbls Fluid Hauled Total - 0 bbls Cement Hauled - 0 bbls Cement Total - 0 bbls Losses Daily - 0 bbls Total Losses - 0 bbls Daily Metal - Total Metal - n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: BRU 222-24 Beluga River Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:2011738D BRU 222-24 Drilling Spud Date: ppg gggpgp and test function of annular, perform diverter test as per AOGCC Regulations. Cont directionally drilling 12 1/4" surface hole from 1050' to 1384'. ppg p g function tested diverter at 41 seconds closure for bag, 2 seconds opening for knife valve. 7/4/2020 CBU one time at 516 gpm-1704 psi, 65 rpm-7620 ft/lbs off bott torque, MW 9.0/vis 186, ECD's at 9.4 ppg, BGG 0 units. Obtained survey on bottom, then pumped a 20 bbl hi-vis sweep around. Sweep back on time with no increase in cuttings. Shut down monitored well 15 min, well static.;Pulled up hole on elevators from 2746' to 333' with no issue. Up wt coming off bottom 84K.;Put well on trip tank and serviced rig and topdrive. Replaced leaking "set torque" sun cartridge on topdrive. Cleaned suction and discharge screens on both mud pumps. Lost 2 bbls in trip tank during one hour rig service.;TIH on elevators from 333' to 1380', fille dpipe, TIH from 1380' to 2746' with no issue, no fill. Down wt 50K.;Filled pipe and pumped a 20 bbl hi-vis sweep around. 491 gpm-1501 psi, 60 rpm-7303 ft/lbs off bott torque. Sweep back on time and no increase in cuttings. Shut down and monitored well, well static.;POOH on elevators from 2746' to TM HOC collar at 83'. Racked back HWDP, jars and NM Flex DC's. Plugged in downloaded MWD data. LD TM, RLL and DM collars. Drained motor, broke off bit and LD motor. Weatherford Reps and Wellhead Rep in field at 16:00 hrs. Bit grade:1-2-WT-A-E-I-NO-TD.;Clean and clear rig floor, drained stack, RU and removed wear ring, MU hanger on landing joint while level up sub base. Staged Weatherford power pack.;R/U Weatherford and Casing equipment, load racks with casing, PJSM;Run 9 5/8'' L-80 40# Surface casing as per detail installing centralizers every jt to jt # 58, M/U float equipment check floats, floats good, Continue RIH filling on the fly t/ 2708' M/U Hanger and landing jt land on hanger @ 2738' R/U Circulating equipment;Establish circulation @ 138 gpm 100 psi stage pumps t/ 6 bpm 250 psi continue to move pipe periodically to ensure free pipe movement no loss while circulating.;Cuttings Hauled to A Pad - 225 bbls Cuttings Total Hauled - 975 bbls Fluid Hauled to BRWD/1 Pad - 0 bbls Fluid Hauled Total - 0 bbls Cement Hauled - 0 bbls Cement Total - 0 bbls Losses Daily - 0 bbls Total Losses - 0 bbls Daily Metal - Total Metal - 7/5/2020 Cont waiting on cement transport to be barged to Beluga River. Cont circulating with 9 5/8” casing on bottom at 6 bpm-250 psi, 2 bph loss rate. Trouble shot topdrive extend circuit then replaced extend solenoid. RD casing fill up line and cleaning throughout the rig.;Transported excess surface casing to staging pad, transported 5 1/2" casing to location, racked, tallied and drifted same. Brought in 5 1/2" landing joint, hanger and packoff assembly. Sent Weatherford Reps back to Kenai, brought cement crew out at 16:00. Layed out liner for cementers and staged;dogbone bails, cement manifold and plug launcher on catwalk. Reduced circ rate to 4 bpm-0 psi with a loss rate of 1 bph, then reduced to 3 bpm-0 psi while staging and RU cementers, with a loss rate of 1 bph.;Staged Halliburton pump truck, loaded plugs in plug launcher, installed dog bones, landed hanger, shut down rig pump, Trouble shoot top drive robotics, link tilt grabber and IBOP not functioning, change out Extend clinoid, function all robotics everything working.;R/U Cement head and lines, establish circulation 5 bpm 150 psi, continue waiting on cement truck off barge, continue working pipe and circulating 3 bpm 50 psi, housekeeping and rig maintenance.;Cuttings Hauled to A Pad - 130 bbls Cuttings Total Hauled - 1105 bbls Fluid Hauled to BRWD/1 Pad - 0 bbls Fluid Hauled Total - 0 bbls Cement Hauled - 0 bbls Cement Total - 0 bbls Losses Daily - 16 bbls Total Losses - 16 bbls Daily Metal - Total Metal - 7/6/2020 Cont circulating through bottom of plug launcher at 3 bpm while waiting for barge to unload cement transport. Barge landed at 06:00, transport on location at 06:30. Staged truck and tied in to pump truck. Held PJSM with rig team and cementers.;Halliburton loaded lines with 5 bbls water and checked for leaks. Halliburton pressure tested lines at 1000 low 4000 high, good tests. Halliburton pumped 60 bbls 10.5 ppg Tuned Spacer at 4.5 bpm-170 psi and shut down. Halliburton dropped bottom plug and pumped 200 bbls (459 sx) 12 ppg Type I II lead;cement at 5 bpm-166 psi, followed by 49 bbls (235 sx) 15.8 ppg Class G tail cement at 4 bpm-142 psi. Halliburton dropped top plug, then displaced with 8.9 ppg Spud Mud at 6.5 bpm. Slowed to 3 bpm with 20 bbls to go. Did bump the plug 198 bbls into displacement (calculated 201.4 bbls), held 1047 psi;(FCP of 715 psi) for 3 minutes, bled off and floats held. Bled back .75 bbls to truck. Had 60 bbls Spacer and 68 bbls lead cement to surface. Added LCM at 5.6 ppb lead, 4 ppb tail. Mix water temp 56 deg. Pumped 50% excess on both lead and tail. Lost 38.4 bbls during displacement. Did reciprocate;pipe until lead cement to shoe, up wt 160K, dwn wt 68K at point of landing hanger. CIP at 09:51, 7-6- 20.;Monitored cement level in wellbore 15 minutes, level slowly dropped approx 1' then held steady. Added black water to cellar box and drained stack. Flushed stack via hole fill and black water, then flushed out with water hose. Halliburton washed up to cuttings box, RD plug launcher etc and released.;Backed out landing joint and flushed out inside with water hose. Pulled to rig floor, MU run tool and pack off assembly. Wellhead Rep removed lock down pin to verify landing. RIH and landed packoff but sat 1" high in wellhead. Set down topdrive weight numerous times on top of landing joint,;packoff still 3/8" to high to engage lockdowns. Pulled to floor, flushed hanger top and inspected packoff assembly, repeated twice. Pulled to floor and removed seals, landed and still sat too high. Swapped out packoff assembly and no change, cannot RILD's. Hanger may be off seat an inch.;Notified Drilling Manager and Sr Wellhead Rep. Cement samples set up firm, decision made to ND diverter stack and check hanger for seat. LD landing joint and packoff, PU joint of 4 1/2" DP and stack wash tool, flushed annular, diverter "T" and hanger/wellhead taking returns down flowline.;LD wash tool and joint. Drained stack. PU landing joint and packoff with no seals. Landed packoff and set topdrive weight on landing joint to hold hanger down from any further movement possibly due to heat expansion. Checked conductor annulus fluid height, full at 4" outlet.;ND diverter vent line, flowline, removed all but 4 bolts on flow riser, annular and spacer spool under diverter "T", removed 4 way chains. Conductor annulus still full, no loss. Pulled and LD landing joint and packoff. Removed flow riser, annular, diverter "T", and spacer spool/DSA. Clean, inspect;hanger, hanger 3/4" off seat. Cleaned up diverter components, transported vent line and anchor blocks off location to staging area.;Installed packoff assembly over surface hanger, installed RX-66 ring gasket, installed "B" section on wellhead, MU 11" test plug on stand HWDP, MU topdrive and set down topdrive weight on "B" section. Notified Sr Wellhead Rep "B" section sitting good on ring gasket. Torque up same.;Wellhead Rep tested neck seals and void 500 low for 5 min 3000 psi f/ 15 min, Peak brought in BOP stack on cradle and staged same at cellar entrance.;N/U BOP Stack, and choke and kill lines, N/U flow box and riser, N/U flow lines and turn buckles, hammer up flanges, hook up koomey lines and function test ram operations;R/U Geo Span Unit in cellar, set test plug and M/U test equipment, fill stack and lines and shell test all breaks t/ 2500 psi, Mixing mud as per mud engineer f/ next section.;Cuttings Hauled to A Pad - 552 bbls Cuttings Total Hauled - 1657 bbls Fluid Hauled to BRWD/1 Pad - 0 bbls Fluid Hauled Total - 0 bbls Cement Hauled - 68 bbls Cement Total - 68 bbls Losses Daily - 38 bbls Lost 38.4 bbls during displacement. ggj p g pp ;Run 9 5/8'' L-80 40# Surface casing as per detail installing centralizers every jt to jt # 58, M/U pg p ;Halliburton loaded lines with 5 bbls water and checked for leaks.gpp g Halliburton pressure tested lines at 1000 low 4000 high, good tests. Halliburton pumped 60 bbls 10.5 ppg Tuned Spacer at 4.5 bpm-170 psi and shut down. pggppppgppp Halliburton dropped bottom plug and pumped 200 bbls (459 sx) 12 ppg Type I II lead;cement at 5 bpm-166 psi, followed by 49 bbls (235 sx) 15.8 ppg Class Gpp p g p p ( ) ppg yp p p y ( ) ppg tail cement at 4 bpm-142 psi. Halliburton dropped top plug, then displaced with 8.9 ppg Spud Mud at 6.5 bpm. Slowed to 3 bpm with 20 bbls to go. Did bump thep p pp p p g p ppg p p p gp plug 198 bbls into displacement (calculated 201.4 bbls), held 1047 psi;(FCP of 715 psi) for 3 minutes, bled off and floats held. Bled back .75 bbls to truck. Had pg p ( 60 bbls Spacer and 68 bbls lead cement to surface. Ap cement surface csg 7/7/2020 Function tested BOP’s, flooded stack and purged air, shell tested at 3000 psi. Greased valves in prep for BOP test, witness waived by AOGCC Jim Regg at 09:19 on 7-7-20. Finished mixing the last of 600 bbls 6% KCL mud in pits. Conductor annulus static.;Tested all BOPE at 250/3500 for 5 min each (including annular) with no issue, performed drawdown test. 3.5 hr test time with no failures.;RD BOP test equipment, RU and tested 9 5/8" surface casing at 3000 psi for 30 min on chart, good test. Pumped 2.2 bbls, bled back 2.2 bbls,;Drained water from stack and pulled test plug. RD test equipment and lined up for drilling. Installed 9” ID wear ring while staging directional BHA #2. Held PJSM with Sperry reps and drill crew.;PU 6 3/4" motor, MU HDBS PDC jetted with 5 x 14's, MU DM, DGR, PWD, ADR, ILS, ALD, CTN, GeoTap, and HOC collars to 148' as per Sperry. RFO = 282.66°. MU XO and topdrive on HOC collar and attempted shallow pulse test. No pulse. Circ through pump bleeders and;checked pulsation dampeners, no issues found. Attempted second shallow pulse test, no pulse. Attempted third shallow pulse test, no pulse. Decision made to go to backup tools. Shut down broke off topdrive and XO, LD HOC, GeoTap, CTN, ALD, ILS, ADR, PWD, DGR, and DM collars. Will re-run GeoTap.;Started testing MWD back up tools on the ground, while replacing both TD extend cylinders & adjusted TQ tube alignment.;Held PTSM, crew change. cont. testing MWD tools, and working on house keeping on rig.;Began P/U BHA #2 again, P/U the complete set of back up MWD tools and re-ran bit, motor, & Geo-Tap tool. Shallow tested tools (ok), and loaded sources. uploaded data to XBAT tool.;TIH out of derrick w/ flex collars, jars, & HWDP T/811'.;Hung blocks, currently slip & cut drill line.;Cuttings Hauled to A Pad - 60 bbls Cuttings Total Hauled - 1717 bbls Fluid Hauled to BRWD/1 Pad - 0 bbls Fluid Hauled Total - 0 bbls Cement Hauled - 0 bbls Cement Total - 68 bbls Losses Daily - 0 bbls Total Losses - 54 bbls Daily Metal - 0 lbs Total Metal - 0 lbs 7/8/2020 At 811’, hung off blocks/topdrive. Cut and slipped 45' of drill line. Checked crown saver. Greased blocks, topdrive, draw-works. Pressured up on Geo-Span connections to 1970 psi, no leaks, bled off.;TIH from 811' to 2650', filling pipe at 1736'. MU topdrive at 2650' and filled pipe. Calculated displacement = 36 bbls, actual displacement = 33.3 bbls. S/O and tagged cement/wiper plugs at 2653' (FC at 2657'). Up wt 70K, dwn wt 47K, rot wt 54K.;Drilled out wiper plugs, float collar, shoe track, shoe, rathole to 2746’. rot wob 4-6K, 460 gpm-1587 psi, 40 rpm-6600 ft/lbs on bott torque. Had some issue with differential pressures and wob increase, acted like we had rubber around bit but cleared up after;working pipe a few times. Once through float collar, it drilled off good remainder of shoe track. Good hard cement chips/cuttings on shakers. Pumped 20 bbl hi-vis spacer and chased with 6% KCL mud as we started drilling rathole cement, taking returns to cuttings box.;Cont drilling 20' new formation from 2746' to 2766' while displacing well to 6% KCL mud, rot wob 1-3K, 468 gpm-1520 psi, 40 rpm-6683 ft/lbs on bott torque. At 2766' cont to circ out spud mud to cuttings box and work pipe, until good KCL mud to surface. CBU 2 times to help shear new mud.;Obtained SPR's with new 9.0 ppg mud in hole, downed pumps, racked back one stand and parked string inside surface casing just above shoe. Cont to haul off spud mud and cement cuttings.;Closed rams and RU to pump down drillstring and backside simultaneously with test pump, for FIT of surface shoe. Pumped 35.6 gallons to achieve 600 psi with 9.0 mud, for a 13.5 ppg EMW, bled to 305 psi over 10 minutes. Bled remainder off, total of 21 gallons and RD test equipment.;Resumed directional drilling 8 1/2" production section from 2766’ to 3042'. Rot wob 6K, 425 gpm-1132 psi, 80 rpm-8644 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 5K, 422 gpm-1033 psi, 119 psi diff, 170 ft/hr ROP. MW 9.0/vis 43, ECD's at 9.3 ppg, BGG 1 unit.;Cont drilling 8 1/2" hole F/3042'-T/3444', pumped Hi-Vis sweep @ 3227', sweep came back on time w/ a 25% increase in cuttings, got SPR's @ 3288'. P/U-74K S/O-50K ROT-60K SPP-1450 psi GPM- 475 RPM-80 TQ-7-8K;Held PTSM, crew change. Cont drilling 8 1/2" hole F/3444'-T/3661', P/U-77K S/O-52K ROT-62K SPP-1423 psi GPM-480 RPM-80 TQ-8- 9K Max gas 411 units.;Cont drilling 8 1/2" hole F/3661'-T/3789', P/U-77K S/O-52K ROT-62K SPP-1479 psi GPM-480 RPM-80 TQ-8-9K.;Pumped 20 bbl Hi-Vis sweep, sweep came back 20 bbls early, w/ a 20% increase in cutting. Currently perform wiper trip @ 3669' Distance to well plan- 17.75' 14.35' High 10.45' Left.;Cuttings Hauled to A Pad - 615 bbls Cuttings Total Hauled - 2332 bbls Fluid Hauled to BRWD/1 Pad - 0 bbls Fluid Hauled Total - 0 bbls Cement Hauled - 0 bbls Cement Total - 68 bbls Losses Daily - 0 bbls Total Losses - 54 bbls Daily Metal - 0 lbs Total Metal - 0 lbs pg pp Pumped 35.6 gallons to achieve 600 psi with 9.0 mud, for a 13.5 ppg EMW, (g RU and tested 9 5/8" surface casing at 3000 psi FIT to 13.5 ppg Function tested BOP’s, p r, it drilled off good remainder of shoe track. Good hard cement chips/cuttings on shakers. 7/9/2020 Pulled wiper trip on elevators from 3789’ to 2799’ with no issue. Calculated hole fill = 7.9 bbls, actual hole fill = 10.2 bbls. Up wt 86K.;Serviced rig, topdrive, crown, draw-works, driveline, brake linkage and iron roughneck. Hole took .5 bbls over 30 min on trip tank.;TIH on elevators from 2799’ to 3726’ with no issue, MU topdrive, filled pipe then washed/reamed down to bottom at 3789’. Calculated displacement = 7.9 bbls, actual displacement = 6.3 bbls. Made hook and started 20 bbl hi-vis nutplug sweep down drill pipe. Trip gas = 20 units.;Cont drilling 8 1/2" hole from 3789' to 4030'. Rotating wob 2-5K, 468 gpm-1395 psi, 80 rpm-8000 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 6K, 478 gpm-1489 psi, 95-150 psi diff, 73 to 170 ft/hr ROP.MW 9.0/vis 48, ECD’s at 9.5 ppg, BGG 12 units, max gas 150 units (from STERLING_B).;Sweep was back on time with 10% increase in cuttings to surface. Halliburton cementers on location and offloaded 40 bbls worth tuned spacer, 200 sx lead cement into silo and staged transport truck loaded with 200 sx tail cement. cementers staged empty transport for return to OSK ASAP.;Cont drilling 8 1/2" hole from 4030' to 4403'. Rotating wob 2-3K, 475 gpm-1471 psi, 85 rpm-8300 to 10,000 ft/lbs on bott torque, 130 ft/hr ROP. Sliding wob 3-4K, 483 gpm-1473 psi, 150 psi diff, 57 to 120 ft/hr ROP.MW 9.1/vis 56, ECD’s at 9.5 ppg, BGG 27 units, max gas 354 units (from BELUGA_D1).;Getting into considerably more coals, torque erratic on backreams prior to connections, started backreaming twice before each connection and torque smoothed out. Lot's of pepper grain size coal on shakers, no large chips or chunks. BHA was building slightly in rotary, then started to drop slightly.;Cont drilling 8 1/2" hole F/4403' to wiper depth @ 4776', pumped 20 bbl Hi-Vis sweep @ 4278', sweep came back on time w/ a 10% increase in cuttings, P/U-98K S/O- 63K ROT-78K TQ on bottom-9-11K TQ off bottom-8K SPP-1517 psi GPM-480 Max gas 523 units.;Held PTSM, crew change. Pumped 20 bbl Hi-Vis sweep @ 4776', sweep came back on time w/ a 10% increase in cuttings, Flow check (static).;POOH on elevators F/4776-T/3784' w/ no issues. Cal Disp.=7.1 bbls Act Disp=8.6 bbls Diff=1.7 bbls.;Serviced rig- Greased crown, blocks, TD, DWKS, break linkage, drive shaft, & iron roughneck. Cleaned both suction & discharge screen on MP's. Changed HYD hose on TD and extend solenoid/directional valve.;TIH to bottom, had 20K set down @ 4614' (coal), worked through on elevators. P/U-95K S/O-63K ROT-78K Cal Disp.=19.2 bbls Act Disp=16.4 bbls Diff=3.2 bbls.;CBU @ 4776' hole unloaded, max gas of 2488 units. Started dusting up MW to 9.3 ppg, while con. to directional drill 8.5" hole to current depth of 4829'. Distance to well plan: 10.17' 9.08' Low 4.59' Right.;Cuttings Hauled to A Pad - 330 bbls Cuttings Total Hauled - 2662 bbls Fluid Hauled to BRWD/1 Pad - 0 bbls Fluid Hauled Total - 0 bbls Cement Hauled - 0 bbls Cement Total - 68 bbls Losses Daily - 0 bbls Total Losses - 54 bbls Daily Metal - 1 lbs Total Metal - 1 lbs 7/10/2020 Cont directional drilling 8 1/2" hole from 4829’ to 5150'. Rot wob 5-6K, 480 gpm-1759 psi, 85 rpm-9450 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 7K, 480 gpm-1817 psi, 198 psi diff, 103 ft/hr ROP, MW 9.3/vis 47, ECD’s at 9.8 ppg, BGG 31 units, max gas 387 units from BELUGA_F2.;Increased MW from 9.1 to 9.3. No connection gas since 4962’ and that was 3 units.;Cont directional drilling 8 1/2" hole from 5150' to 5271'. Rot wob 4-5K, 482 gpm-1821 psi, 80 rpm-10,500 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 2-3K, 477 gpm-1685 psi, 84-170 psi diff, 30-106 ft/hr ROP, MW 9.3/vis 51, ECD’s at 9.9 ppg, BGG 24 units, max gas 483 units from BELUGA_F8.;DD had to fight trying to slide last stand down. Trouble holding tool face, diff spikes, stick slip etc. Drilling in sand, claystone and coal beds.;Pumped 20 bbl hi-vis nutplug sweep around while rotating/reciprocating string. 481 gpm-1698 psi, 80 rpm-9594 ft/lbs off bott torque, up wt 102K, dwn wt 68K, rot wt 82K. Sweep back 200 strokes early and 25% increase in cuttings.;Cont directional drilling 8 1/2" hole from 5271' to 5394'. Rot wob 3-5K, 481 gpm-1810 psi, 80 rpm-9700 to 11,000 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 4K, 483 gpm-1829 psi, 202 psi diff, 100 ft/hr ROP, MW 9.3+/vis 57. ECD's at 9.8 ppg, BGG 50 units, max gas 224 units. Sliding was;exceptionally better after cleanup cycle. Unsure if formation change or cleaner hole.;Cont directional drilling 8 1/2" hole F/5394'-T/5708'. P/U-107K S/O-68K ROT-84K TQ on bottom-9.7K TQ off bottom-12.1K SPP-1966 psi GPM-480 Max gas-563 units came from Beluga H4.;Held PTSM, crew change. Cont directional drilling 8 1/2" hole F/5708'-T/5768'. P/U-107K S/O-68K ROT-84K TQ-12.1K SPP-1995 psi GPM- 480;Pumped 20 bbl Hi-Vis weighted sweep, sweep came back 14 bbs early, w/ a 10% increase in cuttings, got SPR's, and flow checked well (slight seepage).;Performed wiper trip F/5768'-T/4897', had 5/10K drag. Kelley up and started pumping OOH due well swabbing. Pumped OOH F/4897'-T/4760'. P/U- 110K SPP-335 psi GPM-138 SPM-47.;CBU @ 4760' while rotating & reciprocating pipe to free BHA of clay & clean up hole, at BU hole unloaded (clay) and had a max gas of 2074 units. SPP-1654 psi GPM-474 RPM-80;Finished circ. out gas, shut down & monitored well on TT. Performed rig service, greased crown, blocks, TD, DWKS, drive shaft, brake linkage, & iron roughneck. Cleaned suction & discharge screen, recharged both pulsation dampeners to 450 psi.;TIH on elevators F/4760'-T/5768', washed last stand down, CBU to clean up hole and circ. out gas, hole unloaded (clay), had max gas of 2304 units. Cont. circ. till shakers cleaned up at report time. P/U-100K S/O-80K ROT-84K TQ-10K SPP-1869 Distance to well plan: 10.17' 9.08' Low 4.59' Right.;Cuttings Hauled to A Pad - 385 bbls Cuttings Total Hauled - 3047 bbls Fluid Hauled to BRWD/1 Pad - 0 bbls Fluid Hauled Total - 0 bbls Cement Hauled - 0 bbls Cement Total - 68 bbls Losses Daily - 0 bbls Total Losses - 54 bbls Daily Metal - 0 lbs Total Metal - 1 lbs Cont directional drilling 8 1/2" hole from 4829’ to 5150' 7/11/2020 Made connection at 5768’, started a 20 bbl hi-vis nutplug sweep down drill string and resumed drilling ahead from 5768' to 6006'. Rot wob 5K, 482 gpm-1988 psi, 83 rpm-11,800 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 5K, 482 gpm-1882 psi, 169 psi diff, 38 ft/hr ROP. MW 9.3/vis 53,;ECD's at 10 ppg, BGG 38 units, max gas 2857 units with sweep to surface (21 bbls early and 20% increase). Mud logger determines gas is from the BELUGA_H6. Started increase of MW from 9.3+ to a 9.5 ppg. Cont backreaming twice due to erratic torque. Second pass good and clean.;Cont drilling 8 1/2" hole from 6006' to 6224'. Rot wob 5K, 480 gpm-1929 psi, 80 rpm-12,300 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 10-13K, 481 gpm-1855 psi, 133 psi diff, 16 to 80 ft/hr ROP after adding 3 drums lube to suction pit. MW 9.5/vis50, BGG 42 units, max gas 1468 units.;determined to be from the BELUGA_H12. Had additional spikes of 464 and 1159 units. All gas spikes appear to be from sands.;Cont drilling 8 1/2" hole F/6224'-T/6513', pumped Hi-Vis sweep w/ walnut @ 6263', sweep came back 13 bbls early w/ 10% increase in cuttings, added 3 drums on Bara-lube gold seal to help w/ sliding. P/U-120K S/O-74K ROT-94K SPP-2068 GPM-480 RPM-80 TQ- 12/14K Max gas 1295 units from Beluga I-6.;Held PTSM, crew change. Cont drilling 8 1/2" hole F/6513'-T/6634'. P/U-122K S/O-72K ROT-92K SPP-2206 GPM-480 WOB 7K RPM-80 TQ-13.5 K.;Pumped Hi-Vis sweep w/ walnut & condet @ 6634', sweep came back 14.5 bbls early w/ 10% increase in cuttings, got SPR's, racked back 1 std. Flow check (slight seepage).;POOH F/6634'-T/5575', started swabbing w/ 5/10K drag. P/U-132K S/O-69K.;Kelley up and started pumping OOH F/5575'-T/5259' (5 std.), attempted to pull on elevators w/ no luck, cont. pumping OOH F/5136' to current depth of 4958'.;Distance to well plan: 9.36' 7.53 High 5.55 Left;Cuttings Hauled to A Pad - 440 bbls Cuttings Total Hauled - 3487 bbls Fluid Hauled to BRWD/1 Pad - 0 bbls Fluid Hauled Total - 0 bbls Cement Hauled - 0 bbls Cement Total - 68 bbls Losses Daily - 0 bbls Total Losses - 54 bbls Daily Metal - 0 lbs Total Metal - 1 lbs 7/12/2020 Cont pumping up hole from 4968’ to 4690’ with no rotation, 162 gpm-396 psi, up wt 110K, dwn wt 60K, ECD's at 10.2 ppg, BGG 2 units. At 4690', top stab (8.38" OD) was into the lowest large coal and started seeing more overpull. Could not work through on elevators. Increased to 480 gpm-1785 psi.;65 rpm-11,000 to 15,000 ft/lbs and backreamed up to 4670', then reduced to 40 rpm-8400 to 10,000 ft/lbs off bottom torque and cont backreaming to 3909'. Made occasional attempts to pump up hole but still had overpull issues through remaining two large coals. No large coal on shakers.;Cont backreaming from 3909' to 2744', up wt 100K, 480 gpm-1529 psi, 40 rpm-7300 to 14,000 ft/lbs off bottom torque, MW in 9.5/vis 50, MW out 9.6, ECD's down to 10.0 ppg, BGG 4 units, running water at 10 bph in pits and centrifuge on to control MW. At 3300' we could pull faster with little to no;torque spikes. NNo issue pulling stabilizers into casing shoe at 2738'. Up wt at shoe depth 60K. Parked motor and bit just outside shoe at 2744'. Fair amount on sand, silt, clay and small coal chips on shakers.;Pumped 20 bbl hi-vis nutplug sweep around at 491 gpm-1487 psi, 40 rpm-6510 ft/lbs torque. Sweep back on time with maybe 5% increase in cuttings. Pulled up to 2728' and parked string. Shut down pumps and put well on trip tank.;Greased blocks, topdrive, iron roughneck, crown, draw-works, cleaned suction and discharge screens on both pumps, checked pulsation dampeners. Hole taking 2 bph on trip tank.;TIH on elevators from 2728' to 4277' and filled pipe. Down wt 50K. Cont TIH and set down at 4321' 20K, coming into the upper large coal. Could not work through on elevators. MU topdrive and rot at 40 rpm-7947 ft/lbs torque. Reamed down into upper large coal, stalled topdrive, PU out of it,;reamed down and through twice, PU and went through, no rotary with no issue. Cont TIH on elevators to 4402'.;Cont TIH on elevators from 4402' to 6576', kelley up & washed last std. to bottom, had 20' of fill, Cal Disp.-73.2 bbls Act Disp.-62.73 bbls Diff-4.37 bbls;Pumped 20 bbls Hi-Vis sweep w/ condet & walnut, 140 bbls into circ. hole unloaded & had max gas of 234 units. At BU had minimal increase in cuttings. When sweep came back it was 10 bbls late w/ 25% increase in cuttings (Mostly fines & clay w/ some pea size coal pieces).;Cont. drilling 8.5" hole F/6634'- T/6825'. P/U-130K S/O-78K ROT-97K SPP-2047 psi GPM-480 RPM-80 WOB-7K TQ-12/15K Max gas 512 units from Beluga I-12.;Held PTSM & weekly safety meeting, crew change. Cont. drilling 8.5" hole F/6634'-T/7070'. P/U-135K S/O-78K ROT-98K SPP-2080 GPM-480 WOB-7K TQ-14.8K Max gas 676 units Beluga J2.;Cont. drilling 8.5" hole F/6634' to current depth of 7132 P/U-135K S/O-78K ROT-98K SPP-1876 GPM-466 WOB-7K TQ-14.8K. Distance to well plan: 8.76' 6.11' High 6.28' Left Off line: The lash 200 barge will be at the barge landing around 00:30 hrs tonight w/ CMT, mud products & misc items;Cuttings Hauled to A Pad - 280 bbls Cuttings Total Hauled - 3767 bbls Fluid Hauled to BRWD/1 Pad - 180 bbls Fluid Hauled Total - 180 bbls Cement Hauled - 0 bbls Cement Total - 68 bbls Losses Daily - 0 bbls Total Losses - 54 bbls Daily Metal - 2 lbs Total Metal - 3 lbs 7/13/2020 Cont drilling 8 ½” hole from 7431’ to TD at 7485’ md, 6949’ tvd. Rot wob 6-7K, 489 gpm-2135 psi, 85 rpm-14,000 to 16,300 ft/lbs on bott torque, 85 ft/hr ROP, MW 9.5+/vis 56, ECD’s at 10.0 ppg, BGG 42 units, max gas 277 units (connection gas). Survey at 7485’ md, 10.34° Inc, 75.26° Azi,;6948.8’ tvd puts TD 6’ high and 7’ left of the line. Had connection gas of 277-175-195-228 units with 9.5 MW, let MW increase to 9.5+ and had max of 104 connection gas.;Pumped 20 bbl hi-vis nutplug sweep around, 486 gpm-2054 psi, 80 rpm-14,737 ft/lbs off bott torque. Sweep back on time with no increase in cuttings. Shut down and flow check, well static.;Pulled up hole on elevators from 7485' to 6647' with no issue. Up wt 165K. S/O and parked at 6697', dwn wt 82K.;Serviced rig and topdrive with well on trip tank, hole taking 1 bph.;TIH on elevators from 6697' to 7447' with no issue. MU topdrive, filled pipe and washed to bottom at 7458'.;Pumped 20 bbl hi-vis nutplug sweep around at 485 gpm-1949 psi, 78 rpm-14,200 ft/lbs off bott torque. At 3523 strokes gas quickly climbed to 2287 units, dropped to 914 units, then at bottoms up climbed again to 2056 units, dropped to 1532 units, then just prior to sweep to surface climbed to 1658;units, then dropped to 26, all over 20 minutes time. Sweep back 14 bbls late. Increased MW to 9.6+.;Stopped rotating, cont pumping at 484 gpm-1758 psi, mad pass as directed by Sperry. Tested first 4 stations of 39 @ (#1 7319'), (#2 6912') ,(#3 6823') & (#4 6739').;Held PTSM, crew change. Cont. mad passing/Geo-Tapping OOH stations (#5 6664') (#6 6553') (#7 6488') (#8 6340'). Currently working on station #9 @ 6303'.;Cuttings Hauled to A Pad - 525 bbls Cuttings Total Hauled - 4292 bbls Fluid Hauled to BRWD/1 Pad - 0 bbls Fluid Hauled Total - 180 bbls Cement Hauled - 0 bbls Cement Total - 68 bbls Losses Daily - 0 bbls Total Losses - 54 bbls Daily Metal - 0 lbs Total Metal - 3 lbs TD well at 7485 ft p All gas spikes appear to be from sands. Cont drilling 8 ½” hole from 7431’ to TD at 7485’ md, g ;Cont drilling 8 1/2" hole F/6224'-T/6513' 7/14/2020 Mad passing/Geo-Tapping OOH stations (#9 6303') (#10 6265') (#11 6186') (#12 6053') (#13 5964') (#14 5878') (#15 5840'). Currently working on station #16 @ 5776'. Up wt 125k, Dn wt 75k, 480 GPM, 1820 Psi. BGG 7 units.;Mad passing/Geo-Tapping OOH stations (#16 5776’) (#17 5730’) (#18 5695) (#19 5670) (#20 5566’) (#21 5489') (#22 5315') (#23 5291') (#24 @ 5225’). Up wt 115k, Dn wt 75k, 478 GPM, 1730 Psi. BGG 7 units.;Cont. mad passing/Geo-tap logging OOH, stations-(#25 5107’) (#26 5015’).;Cont. mad passing/Geo-tap logging OOH, had 30K over pull @ 4958' (20' coal), slacked off, kicked in rotary at 40 RPM, washed & reamed through tight spot and cleaned up hole. P/U-103K S/O-72K GPM-490 SPP-1879 psi.;Resumed mad passing/Geo-tap logging OOH, stations- (#27 4642') (#28 4537') (#29 4390’) (#30 4210'). P/U-92K S/O-56K GPM-486 SPP-1810 psi BGG=6 units.;Held PTSM, crew change. Cont. mad passing/Geo- tap logging OOH, stations-(#31 4102') (#32 4061') (#33 4020') (#34 3968’) (#35 3940') (#36 3838’) (#37 3750') (#38 3648’), Finishing last Geo-Tap station #39 @ 3620' at report time. P/U-84K S/O-53K.;Cuttings Hauled to A Pad - 80 bbls Cuttings Total Hauled - 4372 bbls Fluid Hauled to BRWD/1 Pad - 0 bbls Fluid Hauled Total - 180 bbls Cement Hauled - 0 bbls Cement Total - 68 bbls Losses Daily - 0 bbls Total Losses - 54 bbls Daily Metal - 0 lbs Total Metal - 3 lbs 7/15/2020 Pump out of the hole f/ 3741 to just outsude the shoe at 2776'. 139 GPM 264 psi.;Circ hole clean getting back a couple vis cups full of silver dollar size coal. 479 GPM, 1445 psi, 40 RPMs. Check flow w/ well having very slight loss. Pump dry job.;POH on elevators to BHA. Stand back HWDP w/ jars and NM flex collars.;LD BHA #3. All the stabs were in gage. The bit was 1/16 out of gage and it had chipped teeth on both inner and outer rows. Pulled sources from the tools on the rig floor but downloaded the tools on the rack.;Monitor well on trip tank while clearing floor and installing long mouse hole. Serviced the rig. Looks like well is taking 3/4 BPH.;MU BHA #4 for the clean out run.;RIH to 9 5/8 csg shoe.;Cut and slip drilling line. Circ slow whil e cutting line.;Cont. RIH on elevators F/2736'-T/4337', set down 20K @ 4337'.;Kelley up and washed & reamed F/4337'-T/4467' to clean up coal areas. P/U-70K S/O-55K ROT-62K SPP-449 psi GPM-306 TQ-10/12K;Cont. RIH on elevators, F/4467'-T/7150', set down 20K @ 7150' (Tiff clay stone).;Kelley up and washed & reamed F/7150'-T/7485' to clean up swelled clay, had 73' of fill on bottom. P/U-100K S/O-60K ROT-80K RPM-40 TQ-12/15K SPP-713 psi GPM-320. Pipe Disp. Cal=137.9 Act=127.64 Diff=10.26 loss rate=.75 bph Max gas=1705 units;Held PTSM, crew change. CBU w/ minimal increase of cutting, pumped 20 bbl Hi-vis walnut sweep, sweep came back 35 bbls late w/ 20% increase in cutting (mostly fines w/ pea size coal). Dusted up active system from 9.7 ppg to 9.8 ppg to lower BGG.;Racked back 1 std. M/U head pin, circ. well while changing grabber box dies on TD. R/D head pin, flow check (slight seepage), pulled 5 std. on elevators T/7142'(no issues), RIH on elevators F/7142'-T/7448' , Kelley up & washed last down to 7485'(no issues).;Circ. STS, max gas 23 units, flow check (slight seepage). P/U-105K S/O- 59K ROT-76K SPP-1305 psi GPM-488 TQ-13K;Recalibrated weight indicator, began POOH to shoe, current depth 6208'. P/U-113K S/O-69K;Cuttings Hauled to A Pad - 0 bbls Cuttings Total Hauled - 4372 bbls Fluid Hauled to BRWD/1 Pad - 0 bbls Fluid Hauled Total - 180 bbls Cement Hauled - 0 bbls Cement Total - 68 bbls Losses Daily - 13 bbls Total Losses - 67 bbls Daily Metal - 0 lbs Total Metal - 3 lbs 7/16/2020 POH on elevators f/ 6208' t/ 3296'. Holes in good shape so we decided to start LD DP early. Monitor well. Pump dry job.;RU to LD DP using vac to suck balls through pipe on rig floor, and start LD 4 1/2 DP f/ 3296' t/ 1939'.;Continue POH LD 4 1/2 DP to the HWDP. Making sure pipe is clean and threads are doped.;LD the HWDP, jars, XOs, Flex collars and Bit. Clear floor.;M/U mule shoe on std. RIH w/ 34 std out of derrick. Pipe displacement- Cal=13.59 bbls Act=13.96 bbls Diff=.37 bbls. Pumped 10 bbl dry job, POOH L/D 67 jts. of 4.5" DP, rinsing ID of pipe w/ water, vacuuming wiper balls through pipe, cleaning threads, and installing thread protectors on tight.;Held PTSM, crew change. RIH w/ remaining 34 std out of derrick w/ mule shoe, Pipe displacement- Cal=13.5 bbls Act=14.5 bbls Diff=1 bbls, Pumped 10 bbl dry job, POOH L/D 67 jts. of 4.5" DP same. Hole fill- Cal=15.1 bbls Act=16.9 bbls Diff=1.8 bbls.;Cleared & cleaned rig floor.;Currently changing upper rams to 5.5";Cuttings Hauled to A Pad - 0 bbls Cuttings Total Hauled - 4372 bbls Fluid Hauled to BRWD/1 Pad - 80 bbls Fluid Hauled Total - 260 bbls Cement Hauled - 0 bbls Cement Total - 68 bbls Losses Daily - 16 bbls Total Losses - 83 bbls Daily Metal - 0 lbs Total Metal - 3 lbs Mad passing/Geo-Tapping OOH stations (#9 6303') (#10 6265') (#11 6186') (#12 6053') (#13 5964') (#14 5878') (#15 5840') Pump out of the hole f/ 3741 to just outsude the shoe at 2776'. 139 GPM 264 psi.;Circ hole clean getting back a couple vis cups full of silver dollar size coal. 479pj GPM, 1445 psi, 40 RPMs. Check flow w/ well having very slight 7/17/2020 Finish changing upper rams to 5 1/2, Pull wear ring and RU 5 1/2 test jt.;Test annular and rams on 5 1/2" t/ 250 low and 3500 psi high. Did have leak on test jt we had to retighten. RD test equip.;RU to run csg. Make dummy run with hanger and get good marks on the landing jt. When pulling landing jt up about 2 1/2' it would hang up in the lower rams, so we need to be careful if we move the pipe after landing out.;MU shoe track and attempt to check the float. Mud wasnt draining out like it normally would so we RU and pumped through it. Got good cir and floats worked good afterwards. RIH picking up 5 1/2 csg t/ 2715' , filling on the run and topping off every 10 jts. Putting slip on centralizers on every jt.;Cir and condition mud at 9 5/8 csg shoe. Max gas units were 7. up wt 48k, dn wt 41k, rt wt 43k. At 10 RPM=2100k, 20 RPM=2538k, 30 RPM=2680k. Circ at 6 BPM 67 psi.;Continue RIH PU 5 1/2 csg to 4241' with no issues.;M/U XO & TIW to 5.5" casing. Circ. STS, had max gas of 36 units, P/U-68K S/O-50K SPP-124 psi GPM-258;Cont. RIH w/ 5.5" TXP 17 ppf casing F/4240'-T/6006'.;M/U XO & TIW to 5.5" casing. CBU, had max gas of 83 units, P/U-90K S/O-60K SPP-166 psi GPM-240;Cont. RIH w/ 5.5" TXP 17 ppf casing F/6006'-T/7070'. P/U-110K S/O-70K Casing displacement: Cal-39.3 bbls Act-39.72 bbls Diff-.43 bbls;Held PTSM, crew change. Cont. RIH w/ 5.5" TXP 17 ppf casing F/6006'-T/7448', M/U XO & TIW to jt. # 175. Called out HES cmt & NOS wellhead Rep Sam to location.;M/U XO & TIW to jt. # 175, broke circ. staged up pump to 250 GPM while reciprocating pipe. SPP-221 psi Flow-23% Max gas 128 units P/U-110K S/O-70K Off line rack 2-7/8" PH-6 work string.;Shut down pump, broke out XO/TIW, M/U XO/TIW to landing jt. & 10-3/4" hanger & pup, M/U pup to stump, broke circ. and staged pump up to 250 GPM, washed down to set depth @ 7475', and landed out hanger.;Cont. circ. & conditioning mud on short system while R/U HES cmt, and hauling mud to tank farm.;Shut down pump, loaded plug in cmt head, M/U cmt head to stump, broke circ. through cmt head, Held PJSM w/ rig crew, HES cmt, Baroid, Peak, and DSM's. SPP-295 psi GPM-252 Flow- 23%;Went to pressure test cmt lines, noticed big air compressor hooked to cmt silo through the belts off, couldn't get belts back on, decided to use compressor on extra cmt truck at barge landing, HES cmt hands are currently going to barge landing to retrieve extra truck w/ compressor,;while cont. to circ. hole w/ rig pump.;Cuttings Hauled to A Pad - 0 bbls Cuttings Total Hauled - 4372 bbls Fluid Hauled to BRWD/1 Pad - 80 bbls Fluid Hauled Total - 260 bbls Hauled 80 bbls to J pad tank Farm Cumulative: 80 bbls Cement Hauled - 0 bbls Cement Total - 68 bbls Losses Daily - 16 bbls Total Losses - 83 bbls 7/18/2020 Cmt 5 1/2 csg. MU plug launcher and hardline, Halliburton loaded lines with 5 bbls water and checked for leaks. Halliburton pressure tested lines at 700 low 3900 high, good tests. Halliburton pumped 41 bbls 10.5 ppg Spacer at 4 bpm and shut down. Halliburton dropped;bottom plug and pumped 220 bbls (555 sx) 12 ppg Class A lead cement at 4 bpm, followed by 24 bbls (115 sx) 15.5 ppg Class A tail cement at 2.5 bpm. Halliburton dropped top plug, then displaced with 90 bbls 10 ppg 6% KCL PHPA at 6 bpm. Slowed to 3;bpm with 80 bbl to go. Did bump the plug 165 bbls into displacement (calculated 172 bbls), held 1641 psi (FCP of 980 psi) for 5 minutes, bled off and floats held. Bled back 1 bbl to truck. Had 0 bbls Spacer returns to surface and 0 bbls lead cement to surface. Added;LCM (Bridge Maker) to both lead and tail cement at 5.3 & 3.1 ppb. Mix water at ambient temp. Pumped 10% excess on both lead and tail. Lost 0 bbls during displacement. Did not reciprocate pipe due to hanger. CIP at 09:15, 7-18-20. RD Halliburton equip & clear floor.;Drain stack and pull landing jt. Wash out stack. PU Packoff and MU on landing jt. Run packoff and land putting TD on it . Run in lockdowns and test to 250 low and , 5000 high. Pull and LD landing jt.;Change upper rams back to VBRs.;MU test jt w/ TWC. Press up and dart valve started leaking. Pull and break out dart valve and replace it with the TIW valve. RU to test again and it was still leaking off. Had to pull the test jt again. This time we put a TWC in the hanger and a blanking sub. Then we got a test on both the;2 7/8 rams and the annular. 250 low and 3500 high.;RD test equip and pull TWC.;RU Weatherford equip and load 2 7/8 work string on catwalk racks.;MU bit, scrapper, and XO. RIH P/U 2 7/8" PH-6 7.9 ppf work string F/surface-T/2565'. Off line: Started injecting clean mud from J pad tank farm down injection well on pad BRWD-1 w/ Halliburton cmt truck. Current injection pressure 2100 psi & Rate-2.5 bpm Vol injected as of 23:00 hrs.;Kelley up, broke circ. staged up pump to 220 GPM, CBU x2, changed dies on grabber box on TD. SPP-822 psi MW-9.8 ppg P/U-28K S/O-22K;Cont. P/U & singling in the hole w/ 2 7/8" PH-6 7.9 ppf work string F/2565'-T/3203', while working on cleaning pits. P/U-30K S/O-27K Pipe displacement: Cal-8.52 bbls Act-7.4 bbls Diff-1.12 bbls;Held PTSM, crew change. Cont. P/U & singling in the hole w/ 2 7/8" PH-6 7.9 ppf work string F/3203'-T/4873'.;Broke circ. staged pump up to 260 GPM & CBU X2. SPP-1937 psi Flow-22% P/U-37K S/O-37K.;Cont. P/U & singling in the hole w/ 2 7/8" PH-6 7.9 ppf work string F/4873' to tagged depth @ 7388' , broke circ. staged up pump, washed down and set down 4K to confirm tag, run tally FC depth 7392', P/U-57K S/O-38K SPP-2323 psi GPM-240 Flow-21%;Off Line: Finished injecting clean mud from J pad tank farm down injection well on pad BRWD-1 w/ Halliburton cmt truck @ 04:00 hrs. Total vol=780 bbls, Injection pressure 2100 psi & Rate-1.6 bpm;Cuttings Hauled to A Pad - 110 bbls Cuttings Total Hauled - 4482 bbls Fluid Hauled to BRWD/1 Pad - 430 bbls Fluid Hauled Total - 690 bbls Hauled 670 bbls to J pad tank Farm Cumulative: 750 bbls Cement Hauled - 0 bbls Cement Total - 68 bbls Losses Daily - 0 bbls Total Losses - 83 bbls Test 5.5" rams Finish changing upper rams to 5 1/2, Pull wear ring and RU 5 1/2 test jt.;Test annular and rams on 5 1/2" t/ 250 low and 3500 psi high. Cmt 5 1/2 csg. Cement 5 1/2" casing p RIH picking up 5 1/2 csg t/ 2715' , filling on gy ppgg g the run and topping off every 10 jts. Putting slip on centralizers on every jt.;Cir and condition mud at 9 5/8 csg shoe. M hardline, Halliburton loaded lines with 5 bbls water and checked for leaks. Halliburton pressure tested lines at 700 low pg p 3900 high, good tests. Halliburton pumped 41 bbls 10.5 ppg Spacer at 4 bpm and shut down. Halliburton dropped;bottom plug and pumped 220 bbls (555 sx) 12 g g g p p ppg p p pp p g p p() ppg Class A lead cement at 4 bpm, followed by 24 bbls (115 sx) 15.5 ppg Class A tail cement at 2.5 bpm. Halliburton dropped top plug, then displaced with 90 ppg p y ( ) ppg p pp pp g p bbls 10 ppg 6% KCL PHPA at 6 bpm. Slowed to 3;bpm with 80 bbl to go. Did bump the plug 165 bbls into displacement (calculated 172 bbls), held 1641 psi ppg p p g p p g p () (FCP of 980 psi) for 5 minutes, bled off and floats held. Bled back 1 bbl to truck. Had 0 bbls Spacer returns to surface and 0 bbls lead cement to surface.(p)p Added;LCM (Bridge Maker) to both lead and tail cement at 5.3 & 3.1 ppb. Mix water at ambient temp. Pumped 10% excess on both lead and tail. Lost 0 bbls 7/19/2020 Displace well to KCL. Pump 20 bbl spacer pill followed by 6% KCL. Circ until clean. 6.3 GPM, 1909 psi.;Monitor well while RU to POH sideways. Peak hauling mud to tank farm.;POH LD 2 7/8 work string sucking foam balls through each jt & drying and re-doping the threads f/ 7388' t/ 5000'. Cleaning pits hauling mud to tank farm & cuttings to pit.;Continue POH LD 2 7/8 work string sucking foam balls through each jt & drying and re-doping the threads f/ 5000' t/ 3100'. [Halliburton is injecting mud at BRWD-1];Continue POOH L?D 2 -7/8" PH-6 work string vacuuming wiper balls through each jt. & drying and re-doping the threads F/ 3100' -T/ BHA #5/clean out assembly, inspected scraper & bit (ok), cont. flushing lines and equip w/ Barakleen/water in pits and cleaning tank bottoms.;L/D BHA #5, cleared & cleaned rig floor, R/D Weatherford casing equip. Off Line: Finished injecting clean mud from J pad tank farm down injection well on pad BRWD-1 w/ Halliburton cmt truck @ 23:30 hrs. Total vol=400 bbls of mud, Injection pressure 2200 psi & Rate-3.5 bpm;Held PTSM & weekly safety meeting, crew change. Called NOS wellhead Rep Sam to location. R/U test equip, flooded lines & purged air, tested 5.5" casing at 2500 psi on chart for 30 min (ok). Pumped in 2.0 bbls, bled back 1.6 bbls. R/D testing equip.;M/U T-bar, set BPV. Loaded up MWD & Geo-log shack onto trailers and hauled off location.;Flushed w/ Barakleen/water- TD, MP's, choke & kill lines, choke manifold, BOP stack, blow down same. changed gear oil in TD swivel & gear box, cleaned & removed XO's, subs, & TIW off floor.;N/D BOP's- R/D choke & kill lines, removed mouse hole, opened ram cavities, removed rams & performed monthly inspection on ram cavities (ok). Cont. to N/D BOP's at current time.;Cuttings Hauled to A Pad - 50 bbls Cuttings Total Hauled - 4532 bbls Fluid Hauled to BRWD/1 Pad -700 bbls Fluid Hauled Total - 1390 bbls Hauled 0 bbls to J pad tank Farm Cumulative: 750 bbls Cement Hauled - 0 bbls Cement Total - 68 bbls Losses Daily - 0 bbls Total Losses - 83 bbls 7/20/2020 Nipple dn BOPs. RD accumulator line and place lines back in tray. Clean and rack back BOP stack;Rig down tongs, standpipe manifold, bails, TD hyd, and choke manifold lines. (At 8:45 we got a call that we had a spill by the production Fuel storage containment. 5 gal was spilled when the support crew overfilled the ISO tank.);MU dry hole tree. Test void to 250 psi for 5 min, and 5000 psi for 15min. Good test. Pull BPV and install TWC. Test tree to 500 psi for 5 min and 5000 psi for 10 min. Another good test. RD test equip. Pull TWC Close master valve. No BPV installed.;PU BOP stack and set in cradle w/ crane. Remove Iron roughneck back windwall. Lay dn and haul off upright cmt silo, and water tank.;Change out robotics fittings on TD, RD TD, LD torque bushing, roll up electric lines, lower pit roofs,finish rigging dn mud pumps, Place TD in cradle and lower to catwalk. Clean out suction lines on mud pumps, clean out cellar area, Prep to scope dn derrick and scope derrick dn.;Prep derrick to be lowered dn on carrier. [Pulling water and light mud off top of cuttings disposal pit and hauling it to J pad tank farm tank 4];Loaded MP modules 1 & 2, Gen #3 and sent to staging area, removed vent line from poor boy gas buster, unspooled drill line from drum, disconnected all Pason lines, loaded gas buster, pit module #2 & 3, HPU/combo module, and sent to staging area. Removed drive line off brake linkage,;laid over derrick onto carrier, removed pins from lift cylinders & pins from sub, scoped dog house into rig water tank, finished disconnecting remaining electrical cords, disconnected HYD lines from carrier, removed choke house from sub & loaded onto truck, removed iron roughneck from rig floor and;pinned on iron roughneck carrier, laid down V-door wind wall. spotted cranes and loaded derrick, carrier, & sub onto trucks and staged on perimeter of K -Pad, Had day crew stay over two hour during R/D.;Brought night crew out two hour early, sent half of night crew to F-Pad to lay felt, liner, & set rig mats, brought remainder of night crew hands to K-Pad to load remaining of rig mats onto trailer, clean up liner, felt, and Load misc equip onto trailer.;Currently setting pony subs on F-pad, and cont. to clean up liner, felt, and load misc equip on K-pad. Removed 400 bbls of mud from solids waste cell w/ vac truck and stored into RFR tank # 4 on J Pad to be injected. Final report for BRU 222-24, changing to BRU 241-34T AFE @ 06:00 hrs.;Cuttings Hauled to A Pad - 55 bbls Cuttings Total Hauled - 4587 bbls Fluid Hauled to BRWD/1 Pad -0 bbls Fluid Hauled Total - 1390 bbls Hauled 485 bbls to J pad tank Farm Cumulative: 485 bbls Cement Hauled - 0 bbls Cement Total - 68 bbls Losses Daily - 0 bbls Total Losses - 83 bbls MIT casing pp yy tested 5.5" casing at 2500 psi on chart for 30 min gg (ok). Pumped in 2.0 bbls, bled back 1.6 bbls. Displace well to KCL. Activity Date Ops Summary 7/31/2020 Transport yellow jacket hands to 222-24 BRU and Spot All Yellow equipment on 222-24 on site 8/1/2020 PJSM,Rig up Yellow jacket equipment w/ CBL and RIH and log f/ 7392' t 2600' / WLM R/D Yellow Jacket Equipment and move off to the side of pad 8/2/2020 Waiting on Halliburton N2Hands, Petrospec coil hands to arrive @14:00 Hrs BRU Hold BRU Safety orientation with crews . (Due to plan delayed on weather.),Move and stage Petrospec coil unit t/ K Pad and move coil reel on location and peak crane set up to change out coil reel tomorrow . 8/3/2020 PJSM with Coil crew and peak crane operator,Continue to C/O coil reel on the coil unit.Notice the spool that came off had a small egg shaped on the coil and stalled the new coil spool Petrospec order a new set of chain block will arrive bru @ noon on the 8-4-20,Continue N/U BOP and test BOP t/ 250 low 4000 PSI high 5 mins each test AOGCC Jim Rigg Waived witness.and Test IA 9 5/8"X 5 1/2"2500 PSI F/ 30 mins on a digital chart.All Good 8/4/2020 PJSM / Due to delay on petrospec coil unit parts Customs through seattle airport .Continued rig up Halliburton N2 truck and hook up hard lines to flow back tank and coil unit Parts will arrive @ 09:30 AM Today 8/5/2020 PJSM Crew / Continue waiting on petrospec parts Test IA on 222-24 2500 PSI and file chart on O drive 1 hr No loss R/D test equipment Continue to stay in contact with shipping 8/6/2020 PJSM w/ Crew Received chains for the Coil Tubing unit and Installed same,Continue R/U Inj head on well ,head lines to Halliburton t/ spool test lines t/ 250- 3000 psi all good RIH and pumping N2 as go @ 3500' Tubing string plug off very little returns . POOH and Drop out 2 check valves out of string Re-head RIH T/ PBTD @ 7420'CTM Recovered 175 bbls (9.0 calc-water POOH and with no issue,leave 2000 psi on well R/D petrospec coil unit.,R/U Yellow jacket E- line, P/U 21'perf- Guns and test Lubricator 2000 PSI all Good RIH 8/7/2020 Continue to RIH w/ 21'Gun and log on depth w/ engineers in town spot gun @ Beluga 16 sands 21' 6472't/6493' and Fire guns with 1950 psi on well after shots pres increase by 50 psi POOH L/D guns and notice that the nose of gun wet R/D yellow jacket and turn over well to production . Start flow N2 cap off the pressure1955 @600 psi had 99% gas 2 hrs 350 PSI 1 MM units of gas,Town Engineers decided to make a wireline run with GPT with yellow jacket E-line R/U and RIH w/ GPT and Tag water @ 6730' POOH and L/D GPT. Well shut 350 psi , at 1 5 hrs building t/ 1300 psi and still building .,Continue to run perforate Run # 2 Beluga 12 f/6336't/ 6343' tot 7' shots Run #3 6175't/6195' 20' shots pressure increase 300 PSI F/2000/2300 Run #4 f/ 6044' t/6057'13' shots w/ dry gun # 5- RIH shot @ 5767't/5786' w/ POOH R/D Yellow Jacket E-line. Bottom pressure stayed 2300 PSI 8/8/2020 PJSM Clean up 222-24 around well and staged all equipment @ BRU stationary , Production operator checked off location all good / Released Yellow jacket,Halliburton and Myself Transported to kenai n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: BRU 222-24 Beluga River Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:2011738C BRU 222-24 Completion Spud Date: equipment w/ CBL and RIH and log f/ 7392' t 2600' / WLM chart on O drive 1 hr No loss R/D Run # 2 Beluga 12 f/6336't/ 6343' tot g on petrospec parts Test IA on 222-24 2500 PSI and file n spot gun @ Beluga 16 sands 21' 6472't/6493' Completion reports RIH shot @ 5767't/5786' pg 6175't/6195' 20' shots pressure increase gp Run #4 f/ 6044' t/6057'13' shots w/ dry gun !" #$%$ &'( )( "* ( +, ( ( - .( .-( /0*( !! "#$%&'()%#* (-(+,-. + / ( "#$%&'()%#* 10 ( / - / )( 2 )( &' /3( ) )( 0 )#1'(2 * + )#1'+ ,+,+* 3& /0 4 . .& *( *( 4 ( 10 ( 546". 516" &! 2 *( &$&& &$&& %55 67)$7% 55 56$&7 1$&.0*4(&$6& %)8)9)%$5%+ )6)8&96$7#/ .- 789 :* 0 7+9 ) 789 /*1)/ :: && 1;)&;&& )6$%% 1$& 66 51$5616)%5& &0(,( *1( )$& - , ( 0:)7+,9 7 9 516" 7 9 789 546". 7 9 +;0()7$& 1%$&&&$&&&$&&)7$& :) 7 9 & ) +1) 7.-9 + 7 9 1;);&& 5< /. =. && >;?@:: 4A 2 . $)##$)5 1&7$15 /. =. ')*'*&%;%;&& 5< /. =. && >;?@:: 4A 2 . $ 165$71 1 6$ /. =. '*'*&1;&#;&& / 7 9 < 789 = 789 546". 7 9 516" 7 9 +, 7 9 +, 7 9 / 10 79 / 4 79 , 79 786>9 +1) )7$& &$&& &$&& )7$& &$&& &$&&1$& %55 67)$7% 55 56$&7 &$&& &$&& +(B?+( )##$)5 &$) 5)6$11 )##$)5 &$% &$6)&%$65 %55 67$55 55 565$% &$5 &$55 5< /. =. ')* 6#$5 &$1 56%$5 6#$5 &$7% &$%)%%$75 %55 67$15 55 565$7 &$6 &$5# 5< /. =. ')* 5)#$1# &$5% 1)$#& 5)#$1# )$)1 &$61$)# %55 675$& 55 565$%6 &$76 &$)% 5< /. =. ')* 561$6 &$)5 1$6 561$6 )$ &$5)%$# %55 675$)& 55 565$1# &$%% &$&& 5< /. =. ')* )$%5 &$%& )&6$ )$% )$& &$&15#$& %55 675$&6 55 56$)1 &$76 &$5% 5< /. =. ')* 7)$16 $1 )&#$7 7)$1 &$%5 )$1)57#$) %55 67$% 55 566$7& 5$65 )$7 5< /. =. ')* 65$7& $11 )))$1 65$%5 &$7) 6$6&6)$&5 %55 67&$#% 55 56#$61 5$5) 6$) 5< /. =. ')* %&6$&) %$57 )))$1 %&$66 5$&) ))$&56))$#6 %55 617$%# 55 5%6$&% $%5 #$#1 5< /. =. ')* %%6$)7 #$56 )))$76 %%$)6 %$&% )7$%161)$66 %55 616$6) 55 51$%% $# )%$%6 5< /. =. ')* 11$ ))$%% )))$#5 16$5% )&$# #$)%5$1% %55 61)$) 55 575$) 5$1) 6$76 5< /. =. ')* 17#$& )6$&6 ))$61 176$ )6$1& $&%#$7 %55 6%6$6) 55 5#%$5 6$# 51$5 5< /. =. ')* 76&$1 )1$71 )))$) 7$6 $)7 67$6#16)$76 %55 667$1# 55 )$5 $%5 6)$# 5< /. =. ')* &'( )( "* ( +, ( ( - .( .-( /0*( !! "#$%&'()%#* (-(+,-. + / ( "#$%&'()%#* 10 ( / - / 7 9 < 789 = 789 546". 7 9 516" 7 9 +, 7 9 +, 7 9 / 10 79 / 4 79 , 79 786>9 +1) #)$6& )$5) ))&$)# #&$%5 #$1 11$#17)&$&5 %55 66)$& 55 5)$67 6$6# %7$6 5< /. =. ')* #16$65 5$%# )&7$7# #%&$7% 51$6 )&&$1&7%7$% %55 6$7& 55 6$)# 5$7% 77$%5 5< /. =. ')* ) &5%$#& $7& ))&$ ) &)1$ 6$%5 )5$6#$% %55 65$56 55 1%$77 )$%7 )&7$7 5< /. =. ')* ) &##$1 $1% )&1$51 ) &1$# 65$5 )%$6#7$5 %55 6%$& 55 ##$%# )$1% )#$)7 5< /. =. ')* ) )%)$&1 $1) )&$% ) )5)$16 6#$#% )%#$5) &5#$)6 %55 6)#$5 55 6$1 )$75 )#$7& 5< /. =. ')* ) $%& 5$5 )&$&) ) )77$57 %6$% )#$1%) &#6$17 %55 6)5$% 55 66$7) )$7% )1)$& 5< /. =. ')* ) 75$61 $& #1$ ) $)7 %#$6# )%$#1) )6)$67 %55 6&7$#% 55 6%#$# 5$55 )#5$%# 5< /. =. ')* ) 51$17 $77 #$& ) 5&$%& 1)$17 5$6) )&$&& %55 6&%$51 55 6#%$% 5$%6 )7$# 5< /. =. ')* ) &1$& 6$67 77$&) ) 56%$56 1)$11 %7$7) %5$16 %55 6&6$#7 55 %)$11 5$) 5$# 5< /. =. ')* ) 1)$ 6$6) 75$7% ) )$) %#$7 #%$51) 5)$6 %55 6&1$6) 55 %#$5 $7& 1&$%1 5< /. =. ')* ) 655$76 6$1# 7&$1) ) 1&$67 %%$)7 55$)) 511$#7 %55 6)&$1 55 %1%$ $ #1$%& 5< /. =. ')* ) 6#6$5# %$1 11$)1 ) 66$17 %&$# 5#$#) 55$)7 %55 6)6$61 55 1&5$&& $#% 5$17 5< /. =. ')* ) %67$6& 1$)& 15$% ) 67$&% 65$1 511$66) 7#$% %55 6$5 55 15&$15 $%& 565$55 5< /. =. ')* ) 1&$15 1$) 1&$# ) %51$5 6$)) &$%&) 6$75 %55 65&$6% 55 161$#) )$## 57)$%% 5< /. =. ')* ) 17$1 %$7 1&$%7 ) %#$5 56$7# 5)$&#) 6##$75 %55 65#$57 55 17$6 &$%5 &#$%& 5< /. =. ')* ) 75$%5 7$55 1$) ) 1%$%5 %$#5 61$#6) %6$&5 %55 61$# 55 7))$6 $11 51$7 5< /. =. ')* ) #&6$& 7$)7 1$% ) 7&)$& )7$&% 76$7) 1&7$ %55 66%$5% 55 75#$65 &$1 %1$& 5< /. =. ')* ) #%7$&6 7$1 1$&1 ) 76%$ 7$#7 6)$&) 1%5$% %55 6%6$&& 55 7%1$71 &$& #%$67 5< /. =. ')* &#$6& 7$7 1$5% ) #)&$ &$&) 6)$#7) 7)1$% %55 615$6 55 7#6$#% &$# 66$77 5< /. =. ')* &#&$#) #$6& 1$&5 ) #%5$76 #$) 61&$1) 71)$6 %55 67$6 55 #$6# )$) 666$1 5< /. =. ')* )65$55 5&$)7 1)$# &)7$&& )7$1 %&&$&)) #6$& %55 6#)$) 55 #6$1 )$&# 67%$1 5< /. =. ')* )6$16 5)$) 1)$1% &1)$%1 7$%1 %5&$7) #1#$&1 %55 %&&$71 55 #7$%# )$%% %)7$6& 5< /. =. ')* 11$ 5&$ 1$)5 )$6 57$& %%&$)5 &5)$# %55 %)&$) 5 &)$%7 )$% %#$7 5< /. =. ')* 55#$6 5&$#) 1)$5% )17$)7 7$55 %#&$5 &76$67 %55 %)#$%) 5 &$# )$1 %7)$ 5< /. =. ')* &&$)) #$%6 1$)% 5&$7 61$7# 1)#$5 )51$77 %55 %7$1 5 &1$&1 $)7 1))$71 5< /. =. ')* %5$56 #$5 1$6& 76$65 %1$5 17$7# )#$#5 %55 %51$1) 5 )&5$71 &$6# 1$# 5< /. =. ')* 6$7) #$#% 1)$7 557$#6 1%$%6 111$7 %$56 %55 %%$67 5 )5$# )$)1 115$% 5< /. =. ')* 671$&% 7$#1 1)$5& 5#5$)6 7%$55 7&%$71 5&&$66 %55 %66$7) 5 )%$)5 )$%6 7&5$1# 5< /. =. ')* %7$1& 7$%5 1&$65 1$)% #%$&5 75$# 56$6% %55 %%6$&# 5 )#&$5 &$7 755$51 5< /. =. ')* 1&7$15 #$1) %#$## ##$67 )&6$# 7%$7 &%$#7 %55 %1$66 5 )7$& )$76 7%$7 5< /. =. ')* 165$71 5&$5 %#$# 657$% ))5$%1 775$1 %$& %55 %7)$#1 5 5#$57 )$%& 77$#1 5< /. =. '* 7)%$) #$1 %#$# 6#$6) )$51 #)5$& ##$#) %55 %#$ 5 %7$7 )$) #)6$## 5< /. =. '* 717$)) #$#% %#$57 %%$7 )56$)& #)$# 665$%7 %55 1&$6& 5 #1$# &$67 #%$%6 5< /. =. '* #&$5 1$77 %#$65 1&&$15 )6$%% #1&$)) %&7$)5 %55 1)$%5 5 5%$6 5$56 #1%$65 5< /. =. '* 5 &&5$&& 1$1% %#$&1 16%$)1 )6%$&& ##1$7 %%5$61 %55 1$66 5 565$11 &$5# ) &&6$6# 5< /. =. '* 5 &%$7 1$6 %7$#6 7)&$1 )%%$)1 ) &5$## 1)1$71 %55 15$5) 5 57&$5 &$6) ) &55$11 5< /. =. '* 5 )%$& 1$6# %7$ 7%6$ )1%$6 ) &6&$61 11$% %55 1$1 5 &1$)1 &$ ) &%$&7 5< /. =. '* 5 )71$%& 1$#& %7$&) #)#$15 )71$)1 ) &11$)# 71$)5 %55 16$# 5 55$# &$%& ) &#&$1 5< /. =. '* 5 6&$5# 1$1 %1$# #16$% )#7$)% ) )&$5 77$%% %55 1%5$&1 5 %)$% &$# ) ))#$7 5< /. =. '* 5 5)$77 1$&1 %#$7% 5 &5&$16 &7$6 ) )5)$)% #57$)6 %55 115$&) 5 77$5 )$11 ) )7$&& 5< /. =. '* &'( )( "* ( +, ( ( - .( .-( /0*( !! "#$%&'()%#* (-(+,-. + / ( "#$%&'()%#* 10 ( / - / 7 9 < 789 = 789 546". 7 9 516" 7 9 +, 7 9 +, 7 9 / 10 79 / 4 79 , 79 786>9 +1) 5 515$%& 1$&) %#$7 5 &7$75 )7$&5 ) )61$&1 ##$5 %55 17$)5 5 6)$7 &$)& ) )16$6 5< /. =. '* 5 56$)# 1$6# %#$)7 5 )5#$6% 1$#5 ) )75$655 &%$#% %55 1#)$%) 5 6&$7# )$&% ) &5$6 5< /. =. '* 5 #1$5# %$15 1)$6 5 )#$#& 51$6 ) )&$5 )&$5& %55 7&&$7 5 6%1$1 $&6 ) 5)$1% 5< /. =. '* 5 6%&$& 1$7 1)$1 5 6&$1 %$%5 ) 51$&5 )67$) %55 7&#$6& 5 6#$75 &$7# ) %&$)) 5< /. =. '* 5 %&$)) 7$&6 1)$57 5 5&5$# 66$6 ) %5$%55 ))$5 %55 7)1$#1 5 %)$& )$7 ) 71$#) 5< /. =. '* 5 %75$6) %$%# 1$6 5 5%&$5 %$61 ) #)$55 %1$%5 %55 7%$%& 5 %#$ $7 ) 5)%$## 5< /. =. '* 5 1%$% 1$&1 1$66 5 )%$51 15$)5 ) 5)7$75 55$11 %55 75$1 5 %1%$6) &$%) ) 56$5# 5< /. =. '* 5 7&6$61 1$) 1$5 5 %7$#5 7)$5& ) 5$75 51%$55 %55 7$6) 5 1&$ &$%& ) 51$& 5< /. =. '* 5 7%#$& 7$& 1$&& 5 66$&6 #&$5% ) 51$65 5$6 %55 76)$)6 5 15&$15 )$1 ) &)$#5 5< /. =. '* 5 ##$7# 7$%6 1)$6# 5 617$67 ##$ ) 5##$#15 76$#7 %55 76#$17 5 167$57 &$7) ) 5&$7 5< /. =. '* 5 ##5$ 1$16 1&$7 5 %5$& 5&#$&6 ) 7$5)5 6)$7& %55 7%7$#1 5 17%$7% )$65 ) %&$% 5< /. =. '* &66$&# 1$#% 1&$5% 5 %7#$)& 5)7$%6 ) 66$615 6#%$6& %55 717$)% 5 7)$1 &$6& ) 7#$ 5< /. =. '* ))%$5 %$6 1&$11 5 15$%& 51$# ) 7)$775 %6)$&& %55 771$& 5 7&$1) $7) ) 6)1$)# 5< /. =. '* )17$% %$&6 1&$&6 5 1##$6 551$)6 ) 6&1$165 1&%$# %55 7#6$76 5 7%%$1 &$%& ) 6$65 5< /. =. '* &$7% %$% %#$67 5 766$5# 5%$%) ) 655$6&5 1%$1# %55 #&$# 5 7#$%) &$1 ) 61)$7& 5< /. =. '* 5&$6 %$&# %#$) 5 #)$% 56%$6& ) 66#$15 7)#$7% %55 #)$& 5 #)#$&& &$ ) 6##$%% 5< /. =. '* 5%6$#5 %$)1 %#$56 5 #%1$%% 5%%$)& ) 676$&%5 716$&% %55 #5$%) 5 #$% &$) ) %%$66 5< /. =. '* 7$&) %$# 1)$16 &5$)# 516$55 ) %))$55 #5&$6# %55 #5$ 5 #1&$1% $)5 ) %6$)1 5< /. =. '* 7#$11 %$#% 1)$5 &17$ 57$& ) %51$175 #76$% %55 #&$#& 5 ##1$ &$5 ) %7$&1 5< /. =. '* 66)$65 1$51 1)$6% )55$)# 5#5$)1 ) %%$6) &&$6# %55 ##$% 56 &$5) &$%# ) 1)&$)7 5< /. =. '* %)$# 1$&6 1)$1 )71$7& &$) ) %#)$) &#6$& %55 #67$&& 56 &6)$&% &$6% ) 157$)1 5< /. =. '* %16$&6 %$#% 1&$17 5$) ))$# ) 1)1$1# )6&$6 %55 #%%$1% 56 &11$7% &$5# ) 1%%$1 5< /. =. '* 156$#7 %$65 1&$% #1$66 &$5# ) 15$%% &$#6 %55 #16$% 56 )&5$7% &$1 ) 1#5$61 5< /. =. '* 1#1$# %$%7 %#$#% 56$#5 #$17 ) 1%#$1% %&$55 %55 #7$6 56 )5&$)& &$ ) 7)$)% 5< /. =. '* 7%&$&& %$&# %#$5# &7$66 5#$5% ) 1#6$%5 5)6$#6 %55 ##5$% 56 )6%$)) )$&5 ) 77$67 5< /. =. '* #5$6 %$)5 %#$&1 %6$6 #$1 ) 7)$1 51$# %5 &&5$) 56 )7$51 &$5 ) 71%$5) 5< /. =. '* #75$57 6$7% %7$6) 6)#$5# 67$11 ) 7%$5 %$1# %5 &)$% 56 &1$&& &$%) ) #&$51 5< /. =. '* 6 &1$)% $# %7$5# 611$&) %7$7) ) 71)$%% 7$) %5 &)$# 56 5$67 )$7 ) ##$7 5< /. =. '* 6 )&7$#% 5$# %7$5 %55$1 17$ ) 7#6$ 6&$%1 %5 &5&$#1 56 6%$7 )$6# ) #6$7) 5< /. =. '* 6 )1)$)% $%5 %#$)& %#&$) 71$)% ) #)7$55 6#1$7) %5 &5#$66 56 1#$6 $)% ) #1#$& 5< /. =. '* 6 5)$#% )$7) %1$%7 1%$%# #6$%5 ) #5#$1) %6$&# %5 &1$%7 56 5&)$&5 )$%) &&)$## 5< /. =. '* 6 #6$&5 &$)% %#$7 7&6$67 6&5$7# ) #%&$1 1)$#7 %5 &66$% 56 5$)1 $7) &$57 5< /. =. '* 6 561$& )7$6# 1$&# 7%$) 6)&$1) ) #7&$6 11)$7) %5 &%$) 56 5)$7& $71 &$#7 5< /. =. '* 6 )7$#6 )1$6 1$57 #$#5 6)%$ ) ##7$6) 75&$55 %5 &%1$51 56 5%&$) $&# &%$&5 5< /. =. '* 6 7)$ )%$ 11$)5 #7$15 6&$1& &)%$&# 7#&$)5 %5 &1)$67 56 511$17 $) &7$)1 5< /. =. '* 6 65$6 )6$56 1%$%) 6 &$# 6$6 &5$66 ##$7# %5 &16$)1 56 5#$5& )$6 &##$&1 5< /. =. '* 6 %&6$1 )$ 11$&) 6 )&$% 67$)1 &7$&)6 &)&$& %5 &17$6% 56 &#$7) )$1# ))$#6 5< /. =. '* 6 %%7$5 )5$55 11$&1 6 )%5$& 65)$6) &%$666 &1&$7& %5 &7)$%7 56 $5# )$6 )#$7% 5< /. =. '* 6 17$1 )$1 11$56 6 $5 65$1 &16$%&6 )#$1 %5 &7$ 56 51$# )$1% )5$6 5< /. =. '* 6 1#$ )$55 11$56 6 7$5% 651$ &77$7&6 )#)$1% %5 &71$& 56 6&$15 &$&# )6%$11 5< /. =. '* &'( )( "* ( +, ( ( - .( .-( /0*( !! "#$%&'()%#* (-(+,-. + / ( "#$%&'()%#* 10 ( / - / 7 9 < 789 = 789 546". 7 9 516" 7 9 +, 7 9 +, 7 9 / 10 79 / 4 79 , 79 786>9 +1) 6 76$6 )$5 1%$11 6 56$5 6&$& )&)$1)6 6$%5 %5 &7#$#1 56 %5$%# &$6 )1&$& 5< /. =. '* 6 #)%$&% )$) 16$#1 6 &6$51 65$% ))$56 5)$11 %5 &#$75 56 1%$5 &$55 )7$## 5< /. =. '* 6 #11$1) )$) 16$% 6 %6$% 6%$%6 )%$#6 515$& %5 &#6$75 56 77$#7 &$)7 )#6$#7 5< /. =. '* % &&$55 ))$6& 1%$5 6 6%$# 6#$1% )5#$&6 5$5 %5 &#7$16 56 6&)$6) )$)% &7$76 5< /. =. '* % )&5$)5 ))$5# 1%$65 6 677$1 66$%# )6)$6)6 #6$71 %5 )&)$# 56 6)5$%1 &$)# )$5) 5< /. =. '* % )%$1 ))$% 1%$&% 6 %7$7 666$%& )%5$66 66%$ %5 )&$ 56 66$%6 &$5 55$%& 5< /. =. '* % %$## )&$77 17$6% 6 1&#$7# 667$7 )16$5)6 %)1$# %5 )&%$1) 56 651$66 )$6 6$1% 5< /. =. '* % 77$55 )&$65 17$1 6 11&$)% 6%&$6 )7%$76 %11$6% %5 )&7$17 56 67$16 &$61 61$) 5< /. =. '* % 56&$55 )&$1) 17$&5 6 75)$)& 6%$7 )#1$%16 157$6& %5 ))&$#) 56 66#$#7 &$5% %7$66 5< /. =. '* % ))$#5 #$7% 11$1 6 7#)$1) 6%6$)5 &7$56 1##$)) %5 ))5$&% 56 61&$1% )$57 1#$66 5< /. =. '* % 15$77 #$7% 1%$&7 6 #6$16 6%1$65 )7$1%6 7%&$)6 %5 ))6$5& 56 67)$)5 &$% #&$)6 5< /. =. '* % 65%$) #$#5 1%$) % &)$&7 61&$)& #$)66 #)$7 %5 ))1$1) 56 6#)$66 &$)) 5&&$76 5< /. =. '* % 6#7$#5 #$1) 1%$ % &16$#6 61$% 5#$666 #75$56 %5 )&$&# 56 %&)$## &$5% 5))$6% 5< /. =. '* % %%&$) #$#& 16$1) % )5%$6 616$)6 #$%%% &5$%6 %5 )$ 56 %)$) &$51 5)$#7 5< /. =. '* % 1$%1 #$15 16$51 % )#1$77 611$7) 6#$##% )&6$7 %5 )$#6 56 %$6) &$# 55$% 5< /. =. '* % 176$&7 #$15 1$#1 % 6#$5# 67&$6) 1&$)7% )%%$1# %5 )1$# 56 %5$1 &$)) 55$)# 5< /. =. '* % 7%$% #$11 1$#5 % 5&$&% 675$ 7&$6% 1$% %5 )5&$& 56 %$76 &$&1 565$%) 5< /. =. '* % #&#$& #$%7 16$) % 57)$61 676$# #&$% 77$#1 %5 )5$%& 56 %65$&7 &$)% 5%$)6 5< /. =. '* % #1&$1) #$76 16$5% % $5 677$6# 5&&$66% 5#$1 %5 )56$)& 56 %%5$5 &$7 51$%) 5< /. =. '* 1 &5$5 #$#5 16$6 % 6&5$)6 6#)$7 5)&$7)% )&$66 %5 )51$%5 56 %15$6 &$)5 576$) 5< /. =. '* 1 &#$5) #$77 16$)# % 6%$)) 6#$&& 5)$)&% 1)$6) %5 )&$)# 56 %75$7% &$&7 5#6$76 5< /. =. '* 1 )6%$7 #$7 16$6 % %6$)% 6#%$%7 55)$5%% 65$6% %5 )$1) 56 %#$)6 &$) &%$6 5< /. =. '* 1 )#$5& #$#6 16$ % %71$6 6##$5# 5)$75% 6#$%6 %5 )6$% 56 1&$%1 &$) )1$1 5< /. =. '* 1 7$)% #$#6 16$# % 1#$)% %&$)) 56$5% %6%$6% %5 )1$75 56 1)6$ &$&) 7$)5 5< /. =. '* 1 56$)6 )&$)& 16$51 % 7))$)# %&$71 5%$#%% 1)7$6# %5 )6&$ 56 16$71 &$ 5#$)& 5< /. =. '* 1 &%$1% )&$ 16$56 % 71)$75 %&1$% 515$7% 11#$5 %5 )65$&) 56 15%$ &$5 #$#7 5< /. =. '* 1 6$ )&$5 16$% % #&#$7# %&#$51 57&$)%% 7)1$# %5 )6$%% 56 15$)6 &$% 6%$77 5< /. =. '* 1 76$&& )&$5 16$% % #7$7) %))$)7 571$&5% 76%$) %5 )6%$5% 56 16&$& &$&& %5$#7 0,C(-(- 4@D4@ @ Benjamin Hand Digitally signed by Benjamin Hand Date: 2020.07.16 11:20:10 -08'00'Chelsea Wright Digitally signed by Chelsea Wright Date: 2020.07.16 14:02:59 -08'00' TD Shoe Depth: PBTD: Jts. 2 63 Yes X No Yes X No Fluid Description: Liner hanger Info (Make/Model): Liner top Packer?: Yes X No Liner hanger test pressure:Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg)Rate (bpm):Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Casing (Or Liner) Detail Shoe 10 146.44146.44 Rotate Csg Recip Csg Ft. Min.PPG8.9 Shoe @ 2738.61 FC @ Top of Liner2,657.13 Floats Held 161.2 249 68 181 Spud Mud CASING RECORD County State Alaska Supv.R. Pederson / J. Riley Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.BRU 222-24 Date Run 5-Jul-20 Setting Depths Component Size Wt.Grade THD Make Length Bottom Top BTC Innovex 1.59 2,738.61 22.45 Csg Wt. On Hook:Type Float Collar:Innovex No. Hrs to Run:6 8.9 6.5 100 715FIRST STAGE10.5Tuned Spacer 60 198/201 1047 68 Halliburton 15.8 49 Bump press Returns to Surface Bump Plug? 9:51 7/6/2020 23 2,738.612,746.00 CEMENTING REPORT Csg Wt. On Slips: Spud Mud 12 200 Type of Shoe:Innovex Bullnose Casing Crew:Weatherford www.wellez.net WellEz Information Management LLC ver_04818br 4 One per joint up to 300' (two on shoe joint), total 59 composite spiral centralizers. Casing 9 5/8 40.0 L-80 BTC Vallourec 78.59 2,737.02 2,658.43 Float Collar 10 BTC Innovex 1.30 2,658.43 2,657.13 Casing 9 5/8 40.0 L-80 BTC Vallourec 2,631.51 2,657.13 25.62 Casing Pup 9 5/8 40.0 L-80 BTC Vallourec 2.22 25.62 23.40 Casing Hanger 16 BTC 0.95 23.40 22.45 Type I II 459 2.4 Class G 235 1.16 5 TD Shoe Depth: PBTD: Jts. 2 115 58 Yes X No Yes X No 40 Fluid Description: Liner hanger Info (Make/Model): Liner top Packer?: Yes No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg)Rate (bpm):Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface? Yes X No Spacer returns?Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Class A 555 2.23 Class A 115 1.24 4 20.35 Hanger 10 3/4 BTC 0.69 20.35 19.66 2,487.53 22.57 Pup 5 1/2 17.0 P-110 BTC Tenaris 2.22 22.57 6.51 2,494.04 2,487.53 Casing 5 1/2 17.0 P-110 BTC Tenaris 2,484.62 Pup 5 1/2 17.0 P-110 BTC Tenaris 2,505.08 Swell Packer 7 3/4 BTC 11.04 2,505.08 2,494.04 7,392.01 2,507.72 Pup 5 1/2 17.0 P-110 BTC Tenaris 2.64 2,507.72 1.25 7,393.26 7,392.01 Casing 5 1/2 17.0 P-110 BTC Tenaris 4,884.29 Float collar 6 API BC Casing 5 1/2 17.0 P-110 BTC Tenaris 80.36 7,473.62 7,393.26 www.wellez.net WellEz Information Management LLC ver_04818br 2.5 Type of Shoe:Innovex Casing Crew:Weatherford 12 220 7,475.407,485.00 CEMENTING REPORT Csg Wt. On Slips:95,500 6% KCL PHPA 9:15 7/18/2020 2,492 15.3 24 Bump pressBump Plug? 165/172 1650 300 HalliburtonFIRST STAGE10.5Tune spacer 41 9.8 3 100 9154 Csg Wt. On Hook:110,000 Type Float Collar:Innovex No. Hrs to Run:15 API BC 1.78 7,475.40 7,473.62 Setting Depths Component Size Wt.Grade THD Make Length Bottom Top Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.BRU 222-24 Date Run 18-Jul-20 CASING RECORD County State Alaska Supv.M. Rogers / J Richardson 7,392.00 Floats Held 220 244 0 244 6% KCL PHPA mud Rotate Csg Recip Csg Ft. Min.PPG9.8 Shoe @ 7475 FC @ Top of Liner 194 229 18.5 Casing (Or Liner) Detail Float shoe 6 Also added LCM to lead and tail. gls 10/22/20Note: Swell Packer at 2494 ft. Poor bond over most of interval from 5500 - 7500 ft per CBL. Good cement from 2700-5500 ft gls ) 1.Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 7,485'N/A Casing Collapse Structural Conductor 1,410psi Surface 3,090psi Intermediate Production 8,730psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ted Kramer Operations Manager Contact Email: Contact Phone: 777-8420 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng tkramer@hilcorp.com 6,767'7,388'6,680'2,400 N/A Swell Pkr; N/A 2,494' MD/ 2,312' TVD; N/A, N/A Perforation Depth TVD (ft):Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL021128 220-043 50-283-20180-00-00 Beluga River Unit (BRU) 222-24 Beluga River Unit / Beluga River Undefined Length Size State Wide Spacing Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY N/A TVD Burst N/A 10,600psi MD 2,980psi 5,750psi 120' 2,525' 120' 2,738' 7,088'5-1/2" 16" 9-5/8" 120' 2,738' 7,413' Perforation Depth MD (ft): See Attached Schematic 7,627' Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: August 3, 2020 N/A m n P 66 t n Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Jody Colombie at 9:40 am, Jul 21, 2020 320-309 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.07.20 19:29:46 -08'00' Taylor Wellman X BOP test to 4000 psig 10-407 DSR-7/21/2020 Gas DLB DLB 07/21/2020VTL 7/23/20 X CBL to be submitted to AOGCC as soon as available. AOGCC approval required to proceed with perforating. X Comm 7/23/2020 dts 7/23/2020 JLC 7/23/2020 RBDMS HEW 7/24/2020 Well Prognosis Well: BRU 222-24 Date: 7-20-2020 Well Name: BRU 222-24 API Number: 50-283-20180-00 Current Status: New Grassroots Well Leg: N/A Estimated Start Date: Aug 3, 2020 Rig: Coil Unit/ E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 220-043 First Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) Second Call Engineer: Ryan Rupert (907) 777-8503 (O) (907) 301-1736 (C) AFE Number: 2011738C Maximum Expected BHP: ~ 3,085 psi @ 6,853’ TVD (Based on geotap side wall tool data) Max. Potential Surface Pressure: ~ 2,400 psi @ 6,853’ TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary BRU 222-24 is a grass roots development well targeting gas sands in the Beluga formation. This new well TD was reached on 7-14-2020. The purpose of this work/sundry is to evaluate cement, jet the well dry with CT, and perforate. Notes Regarding Wellbore Condition x Well will be filled with 6% KCL x Rig cleaned out well to PBTD prior to rigging down. x E-line will complete CBL prior to starting sundry work. Electronic copy of CBL to be sent to AOGCC when completed. Safety Concerns x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. x Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) x Ensure all crews are aware of stop work authority Pre-Sundry Work 1. MIRU E-line unit. RU Stripping head. PU CBL. TIH to PBTD (7,388’). Run CBL log from PBTD up 100ft past the swell packer @ 2,500’. RDMO E-line unit. 2. MIT-IA to 2,500 psi. on chart for 30 min. Coiled Tubing Procedure (Start of Sundry work) 1. MIRU Coiled Tubing, PT BOPE to 4,000 psi Hi 250 Low. Notify AOGCC 48 hrs. in advance of BOP test. 2. MU Jet nozzle. 3. RIH W/ nozzle. RU N2 pumping unit. 4. Drop ball and come online with N2 and jet well dry. a) Estimated volume of displaced 6% KCl is (+/-) 172 bbls. (Based on estimated PBTD of 7,388’). 5. RIH w/ coiled tubing and jet nozzle BHA and tag PBTD. 6. Once well is dry, leave 1,900 psi. on the well for first perforation interval. Well Prognosis Well: BRU 222-24 Date: 7-20-2020 7. POOH w/ coil. LD BHA. 8. RDMO Coiled Tubing. E-Line Procedure 9. MIRU e-line and pressure control equipment. PT lubricator to 3,500 psi Hi 250 Low. Note that the well is pressurized with nitrogen. a) If necessary, bleed pressure down as requested by the OE to establish a drawdown on the formation. 10. PU RIH W/perf guns. Perforate each interval with 2-7/8” Perf guns 6 to 12 JSPF 60 degree phasing. 11. Proposed Perforated Intervals (NOTE: A plug will need to be set at 4,250’ between the Beluga and Sterling perforations Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom ST_A1 ±3,609' ±3,627' 18' ±3,293' ±3,311' ST_A1 ±3,634' ±3,637' 3' ±3,316' ±3,319' ST_A2 ±3,645' ±3,651' 6' ±3,326' ±3,332' ST_A3 ±3,681' ±3,690' 9' ±3,358' ±3,367' ST_A4 ±3,714' ±3,782' 68' ±3,388' ±3,456' ST_A5 ±3,795' ±3,799' 4' ±3,459' ±3,463' ST_B1 ±3,833' ±3,844' 11' ±3,494' ±3,505' ST_B3 ±3,938' ±3,946' 8' ±3,586' ±3,594' ST_B4 ±3,962' ±3,973' 11' ±3,607' ±3,618' ST_C ±4,005' ±4,007' 2' ±3,644' ±3,646' ST_C1 ±4,012' ±4,034' 22' ±3,651' ±3,673' ST_C2 ±4,040' ±4,072' 32' ±3,676' ±3,708' ST_C3 ±4,094' ±4,107' 13' ±3,723' ±3,736' ST_C5 ±4,151' ±4,162' 11' ±3,775' ±3,786' ST_C5 ±4,198' ±4,222' 24' ±3,817' ±3,841' Beluga D3 ±4,303' ±4,307' 4' ±3,911' ±3,915' Beluga D3 ±4,310' ±4,311' 1' ±3,917' ±3,918' Beluga D3 ±4,317' ±4,320' 3' ±3,924' ±3,927' Beluga D5 ±4,372' ±4,376' 4' ±3,973' ±3,977' Beluga D5 ±4,387' ±4,393' 6' ±3,987' ±3,993' Beluga D6 ±4,426' ±4,443' 17' ±4,021' ±4,038' Beluga E1 ±4,494' ±4,502' 8' ±4,082' ±4,090' Beluga E1 ±4,507' ±4,509' 2' ±4,093' ±4,095' Beluga E1 ±4,513' ±4,519' 6' ±4,098' ±4,104' Beluga E1 ±4,533' ±4,549' 16' ±4,116' ±4,132' Beluga E2 ±4,563' ±4,572' 9' ±4,144' ±4,153' Beluga E4 ±4,629' ±4,632' 3' ±4,202' ±4,205' Beluga E5 ±4,640' ±4,645' 5' ±4,212' ±4,217' Beluga E5 ±4,656' ±4,659' 3' ±4,226' ±4,229' Well Prognosis Well: BRU 222-24 Date: 7-20-2020 Beluga E6 ±4,706' ±4,711' 5' ±4,270' ±4,275' Beluga E6 ±4,721' ±4,725' 4' ±4,284' ±4,288' Beluga E6 ±4,737' ±4,741' 4' ±4,298' ±4,302' Beluga E6 ±4,754' ±4,759' 5' ±4,313' ±4,318' Beluga F ±4,793' ±4,797' 4' ±4,348' ±4,352' Beluga F ±4,810' ±4,813' 3' ±4,363' ±4,366' Beluga F4 ±4,855' ±4,858' 3' ±4,404' ±4,407' Beluga F4 ±4,964' ±4,967' 3' ±4,501' ±4,504' Beluga F6 ±5,012' ±5,016' 4' ±4,545' ±4,549' Beluga F7 ±5,103' ±5,112' 9' ±4,628' ±4,637' Beluga F7 ±5,175' ±5,178' 3' ±4,694' ±4,697' Beluga F7 ±5,182' ±5,184' 2' ±4,700' ±4,702' Beluga F10 ±5,214' ±5,233' 19' ±4,730' ±4,749' Beluga G1 ±5,289' ±5,293' 4' ±4,800' ±4,804' Beluga G1 ±5,295' ±5,300' 5' ±4,806' ±4,811' Beluga G1 ±5,313' ±5,321' 8' ±4,823' ±4,831' Beluga G2 ±5,345' ±5,352' 7' ±4,852' ±4,859' Beluga G3 ±5,378' ±5,383' 5' ±4,884' ±4,889' Beluga G8 ±5,486' ±5,490' 4' ±4,987' ±4,991' Beluga G10 ±5,559' ±5,571' 12' ±5,058' ±5,070' Beluga H ±5,590' ±5,594' 4' ±5,087' ±5,091' Beluga H2 ±5,657' ±5,683' 26' ±5,152' ±5,178' Beluga H3 ±5,697' ±5,703' 6' ±5,192' ±5,198' Beluga H4 ±5,723' ±5,737' 14' ±5,217' ±5,231' Beluga H4 ±5,753' ±5,759' 6' ±5,246' ±5,252' Beluga H5 ±5,767' ±5,788' 21' ±5,260' ±5,281' Beluga H7 ±5,832' ±5,846' 14' ±5,323' ±5,337' Beluga H8 ±5,860' ±5,892' 32' ±5,350' ±5,382' Beluga H10 ±5,917' ±5,923' 6' ±5,407' ±5,413' Beluga H10 ±5,953' ±5,984' 31' ±5,442' ±5,473' Beluga H10 ±5,999' ±6,003' 4' ±5,486' ±5,490' Beluga H12 ±6,039' ±6,059' 20' ±5,526' ±5,546' Beluga H13 ±6,084' ±6,114' 30' ±5,570' ±5,600' Beluga H14 ±6,141' ±6,144' 3' ±5,625' ±5,628' Beluga H15 ±6,173' ±6,194' 21' ±5,657' ±5,678' Beluga I ±6,256' ±6,269' 13' ±5,738' ±5,751' Beluga I1 ±6,298' ±6,306' 8' ±5,780' ±5,788' Beluga I2 ±6,335' ±6,346' 11' ±5,815' ±5,826' Beluga I3 ±6,390' ±6,405' 15' ±5,870' ±5,885' Beluga I6 ±6,466' ±6,495' 29' ±5,945' ±5,974' Beluga I7 ±6,508' ±6,513' 5' ±5,987' ±5,992' Beluga I8 ±6,534' ±6,558' 24' ±6,011' ±6,035' Well Prognosis Well: BRU 222-24 Date: 7-20-2020 Beluga I9 ±6,605' ±6,609' 4' ±6,082' ±6,086' Beluga I9 ±6,614' ±6,619' 5' ±6,091' ±6,096' Beluga I10 ±6,645' ±6,653' 8' ±6,121' ±6,129' Beluga I11 ±6,660' ±6,672' 12' ±6,136' ±6,148' Beluga I11 ±6,675' ±6,680' 5' ±6,151' ±6,156' Beluga I12 ±6,732' ±6,745' 13' ±6,208' ±6,221' Beluga I12 ±6,758' ±6,766' 8' ±6,233' ±6,241' Beluga J1 ±6,813' ±6,839' 26' ±6,287' ±6,313' Beluga J2 ±6,873' ±6,924' 51' ±6,346' ±6,397' Beluga J4 ±7,033' ±7,041' 8' ±6,504' ±6,512' Beluga J5 ±7,157' ±7,170' 13' ±6,626' ±6,639' Beluga J5 ±7,205' ±7,215' 10' ±6,674' ±6,684' Beluga J5 ±7,304' ±7,318' 14' ±6,771' ±6,785' Beluga J6 ±7,371' ±7,387' 16' ±6,837' ±6,853' a. Proposed perfs. also shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. d. Use Gamma/CCL to correlate. e. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run at 5 min., 10 min. and 15 min intervals post shot. f. Sand intervals may be grouped or shot one at a time and flow tested to the system. If a sand makes water, then a plug or an isolation patch may be set prior to moving up to the next sand interval. g. Sand intervals are governed by State Wide Spacing rules. 12. POOH. 13. RD e-line. 14. Turn well over to production to test. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Coil tubing BOPE 4. Standard Well Procedure – N2 Operations Updated by DMA 07-20-20 SCHEMATIC Beluga River Unit BRU 222-24 PTD: 220-043 API: 50-283-20180-00-00 PBTD = 7,388’ MD / TVD = 6,680’ TD = 7,485’ MD / TVD = 6,767’ RKB to GL = 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf ~2,750’ 5-1/2" Prod Csg 17 P-110 ICY CDC HTQ 4.892” Surf ~7,475’ 1 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 ±2,500’ 4.892” 6.875” Swell Packer 8-1/2” hole Updated by DMA 07-20-20 – Page 1 of 2 PROPOSED SCHEMATIC Beluga River Unit BRU 222-24 PTD: 220-043 API: 50-283-20180-00-00 PBTD = 7,388’ MD / TVD = 6,680’ TD = 7,485’ MD / TVD = 6,767’ RKB to GL = 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf ~2,750’ 5-1/2" Prod Csg 17 P-110 ICY CDC HTQ 4.892” Surf ~7,475’ 1 16” 9-5/8” 12-1/4” hole 5-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 ±2,500’ 4.892” 6.875” Swell Packer 2 CIBP - ±4,250 – If needed w/25’ Cement 3 CIBP 8-1/2” hole PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Comments ST_A1 ±3,609' ±3,627' ±3,293' ±3,311' 18' Proposed TBD ±3,634' ±3,637' ±3,316' ±3,319' 3' Proposed TBD ST_A2 ±3,645' ±3,651' ±3,326' ±3,332' 6' Proposed TBD ST_A3 ±3,681' ±3,690' ±3,358' ±3,367' 9' Proposed TBD ST_A4 ±3,714' ±3,782' ±3,388' ±3,456' 68' Proposed TBD ST_A5 ±3,795' ±3,799' ±3,459' ±3,463' 4' Proposed TBD ST_B1 ±3,833' ±3,844' ±3,494' ±3,505' 11' Proposed TBD ST_B3 ±3,938' ±3,946' ±3,586' ±3,594' 8' Proposed TBD ST_B4 ±3,962' ±3,973' ±3,607' ±3,618' 11' Proposed TBD ST_C ±4,005' ±4,007' ±3,644' ±3,646' 2' Proposed TBD ST_C1 ±4,012' ±4,034' ±3,651' ±3,673' 22' Proposed TBD ST_C2 ±4,040' ±4,072' ±3,676' ±3,708' 32' Proposed TBD ST_C3 ±4,094' ±4,107' ±3,723' ±3,736' 13' Proposed TBD ST_C5 ±4,151' ±4,162' ±3,775' ±3,786' 11' Proposed TBD ±4,198' ±4,222' ±3,817' ±3,841' 24' Proposed TBD Beluga D3 ±4,303' ±4,307' ±3,911' ±3,915' 4' Proposed TBD ±4,310' ±4,311' ±3,917' ±3,918' 1' Proposed TBD ±4,317' ±4,320' ±3,924' ±3,927' 3' Proposed TBD Beluga D5 ±4,372' ±4,376' ±3,973' ±3,977' 4' Proposed TBD ±4,387' ±4,393' ±3,987' ±3,993' 6' Proposed TBD Beluga D6 ±4,426' ±4,443' ±4,021' ±4,038' 17' Proposed TBD Beluga E1 ±4,494' ±4,502' ±4,082' ±4,090' 8' Proposed TBD ±4,507' ±4,509' ±4,093' ±4,095' 2' Proposed TBD ±4,513' ±4,519' ±4,098' ±4,104' 6' Proposed TBD ±4,533' ±4,549' ±4,116' ±4,132' 16' Proposed TBD Beluga E2 ±4,563' ±4,572' ±4,144' ±4,153' 9' Proposed TBD Beluga E4 ±4,629' ±4,632' ±4,202' ±4,205' 3' Proposed TBD Beluga E5 ±4,640' ±4,645' ±4,212' ±4,217' 5' Proposed TBD ±4,656' ±4,659' ±4,226' ±4,229' 3' Proposed TBD Beluga E6 ±4,706' ±4,711' ±4,270' ±4,275' 5' Proposed TBD ±4,721' ±4,725' ±4,284' ±4,288' 4' Proposed TBD ±4,737' ±4,741' ±4,298' ±4,302' 4' Proposed TBD ±4,754' ±4,759' ±4,313' ±4,318' 5' Proposed TBD Beluga F ±4,793' ±4,797' ±4,348' ±4,352' 4' Proposed TBD ±4,810' ±4,813' ±4,363' ±4,366' 3' Proposed TBD Beluga F4 ±4,855' ±4,858' ±4,404' ±4,407' 3' Proposed TBD ±4,964' ±4,967' ±4,501' ±4,504' 3' Proposed TBD Beluga F6 ±5,012' ±5,016' ±4,545' ±4,549' 4' Proposed TBD Beluga F7 ±5,103' ±5,112' ±4,628' ±4,637' 9' Proposed TBD ±5,175' ±5,178' ±4,694' ±4,697' 3' Proposed TBD ±5,182' ±5,184' ±4,700' ±4,702' 2' Proposed TBD **PERFORATION DETAIL Continued on following page** Bel E ST A ST B ST CA 2 Bel D Bel G Bel F Bel H Bel I Bel J Updated by DMA 07-20-20 – Page 2 of 2 PROPOSED SCHEMATIC Beluga River Unit BRU 222-24 PTD: 220-043 API: 50-283-20180-00-00 PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Ft Date Comments **PERFORATION DETAIL Continued from previous page** Beluga F10 ±5,214' ±5,233' ±4,730' ±4,749' 19' Proposed TBD Beluga G1 ±5,289' ±5,293' ±4,800' ±4,804' 4' Proposed TBD ±5,295' ±5,300' ±4,806' ±4,811' 5' Proposed TBD ±5,313' ±5,321' ±4,823' ±4,831' 8' Proposed TBD Beluga G2 ±5,345' ±5,352' ±4,852' ±4,859' 7' Proposed TBD Beluga G3 ±5,378' ±5,383' ±4,884' ±4,889' 5' Proposed TBD Beluga G8 ±5,486' ±5,490' ±4,987' ±4,991' 4' Proposed TBD Beluga G10 ±5,559' ±5,571' ±5,058' ±5,070' 12' Proposed TBD Beluga H ±5,590' ±5,594' ±5,087' ±5,091' 4' Proposed TBD Beluga H2 ±5,657' ±5,683' ±5,152' ±5,178' 26' Proposed TBD Beluga H3 ±5,697' ±5,703' ±5,192' ±5,198' 6' Proposed TBD Beluga H4 ±5,723' ±5,737' ±5,217' ±5,231' 14' Proposed TBD ±5,753' ±5,759' ±5,246' ±5,252' 6' Proposed TBD Beluga H5 ±5,767' ±5,788' ±5,260' ±5,281' 21' Proposed TBD Beluga H7 ±5,832' ±5,846' ±5,323' ±5,337' 14' Proposed TBD Beluga H8 ±5,860' ±5,892' ±5,350' ±5,382' 32' Proposed TBD Beluga H10 ±5,917' ±5,923' ±5,407' ±5,413' 6' Proposed TBD ±5,953' ±5,984' ±5,442' ±5,473' 31' Proposed TBD ±5,999' ±6,003' ±5,486' ±5,490' 4' Proposed TBD Beluga H12 ±6,039' ±6,059' ±5,526' ±5,546' 20' Proposed TBD Beluga H13 ±6,084' ±6,114' ±5,570' ±5,600' 30' Proposed TBD Beluga H14 ±6,141' ±6,144' ±5,625' ±5,628' 3' Proposed TBD Beluga H15 ±6,173' ±6,194' ±5,657' ±5,678' 21' Proposed TBD Beluga I ±6,256' ±6,269' ±5,738' ±5,751' 13' Proposed TBD Beluga I1 ±6,298' ±6,306' ±5,780' ±5,788' 8' Proposed TBD Beluga I2 ±6,335' ±6,346' ±5,815' ±5,826' 11' Proposed TBD Beluga I3 ±6,390' ±6,405' ±5,870' ±5,885' 15' Proposed TBD Beluga I6 ±6,466' ±6,495' ±5,945' ±5,974' 29' Proposed TBD Beluga I7 ±6,508' ±6,513' ±5,987' ±5,992' 5' Proposed TBD Beluga I8 ±6,534' ±6,558' ±6,011' ±6,035' 24' Proposed TBD Beluga I9 ±6,605' ±6,609' ±6,082' ±6,086' 4' Proposed TBD ±6,614' ±6,619' ±6,091' ±6,096' 5' Proposed TBD Beluga I10 ±6,645' ±6,653' ±6,121' ±6,129' 8' Proposed TBD Beluga I11 ±6,660' ±6,672' ±6,136' ±6,148' 12' Proposed TBD ±6,675' ±6,680' ±6,151' ±6,156' 5' Proposed TBD Beluga I12 ±6,732' ±6,745' ±6,208' ±6,221' 13' Proposed TBD ±6,758' ±6,766' ±6,233' ±6,241' 8' Proposed TBD Beluga J1 ±6,813' ±6,839' ±6,287' ±6,313' 26' Proposed TBD Beluga J2 ±6,873' ±6,924' ±6,346' ±6,397' 51' Proposed TBD Beluga J4 ±7,033' ±7,041' ±6,504' ±6,512' 8' Proposed TBD Beluga J5 ±7,157' ±7,170' ±6,626' ±6,639' 13' Proposed TBD ±7,205' ±7,215' ±6,674' ±6,684' 10' Proposed TBD ±7,304' ±7,318' ±6,771' ±6,785' 14' Proposed TBD Beluga J6 ±7,371' ±7,387' ±6,837' ±6,853' 16' Proposed TBD STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Beluga River Field, Beluga River Undefined Pool, BRU 222-24 Hilcorp Alaska, LLC Permit to Drill Number: 220-043 Surface Location: 2027’ FNL, 22’ FWL, SEC. 24, T13N, R10W, SM, AK Bottomhole Location: 1451’ FNL, 2386’ FWL, SEC. 24, T13N, R10W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jeremy M. Price Chair DATED this ___ day of April, 2020. y, 30 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 7,627' TVD: 7,088' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth:9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 92.3' 15. Distance to Nearest Well Open Surface: x-323359 y- 2633604 Zone-4 74.3' to Same Pool:1152' to BRU 212-24T 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 28 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Cond 16" 84# X-56 Weld 120' Surface Surface 120' 120' 12-1/4" 9-5/8" 47# L-80 BTC 2,750' Surface Surface 2,750' 2,551' 8-1/2" 5-1/2" 17# P-110 ICY TXP BTC 7,627' Surface Surface 7,627' 7,088' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:50- Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Sr Pet Eng Sr Pet Geo Sr Res Eng GL / BF Elevation above MSL (ft): See cover letter for other requirements. Perforation Depth MD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Perforation Depth TVD (ft): Commission Use Only Effect. Depth MD (ft): Authorized Signature: Surface Production Liner Casing Intermediate L- 1076 ft3 / T - 270 ft3 Effect. Depth TVD (ft): Conductor/Structural Length 3190 Total Depth MD (ft):Total Depth TVD (ft): Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) Driven STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 1234 ft3 / T - 138 ft3 2481 1535' FNL, 2052' FWL, Sec 24, T13N, R10W, SM, AK 1451' FNL, 2386' FWL, Sec 24, T13N, R10W, SM, AK N/A 489 BRU 222-24 Beluga River Unit Beluga River Undefined 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 2027' FNL, 22' FWL, Sec 24, T13N, R10W, SM, AK (Staked)ADL021128 022224484 4037' to nearest unit boundary 6/1/2020 Authorized Name: Monty Myers Authorized Title: Drilling Manager Monty Myers mmyers@hilcorp.com 777-8431 18. Casing Program:Top - Setting Depth - BottomSpecifications es N ype of W L l R L 1b S Class: os N ess No s N o D s h s sD h h 8 o : well is p G S S 20 A S S S ess No s No S G y E S es s No s Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.04.28 08:47:00 -08'00' Monty M Myers 4.28.2020 By Samantha Carlisle at 9:14 am, Apr 28, 2020 DSR-4/28/2020 X X X X 283-20180-00-00 X X X 220-043 - Separate sundry to perforate well is required - CBL over 5 1/2" casing to TOC -MIT-IA to 2500 psi on IA (5 1/2" x 9 5/8") after WOC - 3500 psi BOPE test DLB 04/29/2020gls 4/30/20 2500 psi on IA (5 1 4/30/20 4/30/2020 4/30/2020 BRU 222-24 Drilling Program Beluga River Unit Rev 0 April 27th, 2020 BRU 222-24 Drilling Procedure Contents 1.0 Well Summary ........................................................................................................................... 2 2.0 Management of Change Information ........................................................................................ 3 3.0 Tubular Program:...................................................................................................................... 4 4.0 Drill Pipe Information: .............................................................................................................. 4 5.0 Internal Reporting Requirements ............................................................................................. 5 6.0 Planned Wellbore Schematic ..................................................................................................... 6 7.0 Drilling / Completion Summary ................................................................................................ 7 8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8 9.0 R/U and Preparatory Work ..................................................................................................... 10 10.0 N/U 21-1/4” 2M Diverter ......................................................................................................... 11 11.0 Drill 12-1/4” Hole Section ........................................................................................................ 12 12.0 Run 9-5/8” Surface Casing ...................................................................................................... 15 13.0 Cement 9-5/8” Surface Casing ................................................................................................. 18 14.0 BOP N/U and Test.................................................................................................................... 21 15.0 Drill 8-1/2” Hole Section .......................................................................................................... 22 16.0 Run 5-1/2” Production Casing ................................................................................................. 26 17.0 Cement 5-1/2” Production Casing ........................................................................................... 29 18.0 RDMO ...................................................................................................................................... 32 19.0 BOP Schematic ........................................................................................................................ 33 20.0 Wellhead Schematic ................................................................................................................. 34 21.0 Days Vs Depth .......................................................................................................................... 35 22.0 Geo-Prog .................................................................................................................................. 36 23.0 Anticipated Drilling Hazards .................................................................................................. 37 24.0 Hilcorp Rig 169 Layout ........................................................................................................... 39 25.0 FIT Procedure .......................................................................................................................... 40 26.0 Choke Manifold Schematic ...................................................................................................... 41 27.0 Casing Design Information ...................................................................................................... 42 28.0 8-1/2” Hole Section MASP ....................................................................................................... 43 29.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 44 30.0 Surface Plat (NAD 27) ............................................................................................................. 45 31.0 Directional Plan (wp08) ........................................................................................................... 46 Page 2 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 1.0 Well Summary Well BRU 222-24 Pad & Old Well Designation BRU 222-24 is a grass roots well on BRU K Pad Planned Completion Type 5-1/2” Production Longstring (monobore) Target Reservoir(s) Sterling/Beluga Planned Well TD, MD / TVD 7,627 MD / 7,088’ TVD PBTD, MD / TVD 7,500’ MD / 6,963’ TVD Surface Location (Governmental) 2,027’ FNL, 22’ FWL, Sec 24, T13N, R10W, SM, AK Surface Location (NAD 27) X=323359.5 Y=2633604.3 Surface Location (NAD 83) Top of Productive Horizon (Governmental) 1535’ FNL, 2052’ F WL, Sec 24, T13N, R10W, SM, AK TPH Location (NAD 27) X=325396.16, Y=2634144.29 TPH Location (NAD 83) BHL (Governmental) 1451’ FNL, 2386’ F WL, Sec 24, T13N, R10W, SM, AK BHL (NAD 27) X=325731.28, Y=2634144.29 BHL (NAD 83) AFE Number 2011738 (D, C, F) AFE Drilling Days 10 MOB, 21 DRLG AFE Completion Days AFE Drilling Amount $4,500,000 AFE Completion Amount $1,500,000 Maximum Anticipated Pressure (Surface) 2481 psi Maximum Anticipated Pressure (Downhole/Reservoir) 3190 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB – GL 92.3’(74.3 + 18) Ground Elevation 74.3’ BOP Equipment 11” 5M Control Tech Type 90 Annular BOP 11” 5M Control Tech Type 82 Double Ram 11” 5M Control Tech Type 82 Single Ram Page 3 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 2.0 Management of Change Information Page 4 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 16” 15.01” 14.822 17” 84 J-55 Weld 2980 1410 - 12-1/4” 9-5/8” 8.835” 8.679” 10.625” 40 L-80 BTC 5750 3090 947 8-1/2” 5-1/2” 4.892” 4.767” 6.05” 17 P110HC USS-CDC 10600 8730 568 4.0 Drill Pipe Information: Hole Section OD (in) ID (in) TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2” 3.826 2.6875” 5.25” 16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). 5750 (p ) 2980 10600 Page 5 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry tab. 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. 5.2 Afternoon Updates x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp.com and cdinger@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. Each rig will be assigned a username to login with. 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. John Coston: O: (907) 777-6726 C: (907) 227-3189 b. Matt Hogge: O: (907) 777-8418 C: (907) 227-9829 2. Spills: Keegan Fleming: O:907-777-8477 C:907-350-9439 x Notify Drlg Manager 1. Monty M Myers: O: 907-777-8431 C: 907-538-1168 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 and cdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to mmyers@hilcorp.com and cdinger@hilcorp.com Page 6 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 6.0 Planned Wellbore Schematic MIT-IA to 2500 psi CBL required on 5 1/2" casing Page 7 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 7.0 Drilling / Completion Summary BRU 222-24 is an S-shaped directional grassroots development well to be drilled off of the BRU K pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Upper Sterling sands, as well as an area with little to no production in the Beluga sands. The base plan is a directional wellbore with a kick off point at 300’ MD. Maximum hole angle will be 29 deg. and TD of the well will be 7,627’ TMD/ 7,088’ TVD, ending with 10 deg inclination left in the hole. Vertical section will be 2500 ft. Drilling operations are expected to commence approximately June 1st 2020. The Hilcorp Rig # 169 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 2,750 MD / 2,550’ TVD and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6 – 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Hilcorp Rig # 169 to well site 2. N/U diverter and test. 3. Drill 12-1/4” hole to 2,750’ MD. Run and cmt 9-5/8” surface casing. 4. ND diverter, N/U & test 11” x 5M BOP. 5. Drill 8-1/2” hole section to 7,627’ MD. Perform Wiper trip. 6. Make cleanout run 7. POOH laying down drill pipe. 8. Run and cmt 5-1/2” production casing. 9. PU clean out assembly and RIH to clean out 5-1/2” to float collar 10. Displace well to 6% KCL completion fluid. 11. POOH and LD clean out assembly. 12. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: 1. Surface hole: GR + Res 2. Production Hole: GR + Res 3. Mud loggers from surface casing point to TD. Rig 169 BRU 222-24 is an S-shaped directional grassroots development well to be drilled off of the BRU K pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the pg p p yppgp Upper Sterling sands, as well as an area with little to no production in the Beluga sands. NOTE: Separate sundry to perforate well is required. Page 8 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling of BRU 222-24. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation, 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” x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. Regulation Variance Requests: Page 9 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4” x 21-1/4” x 2M Hydril MSP diverter Function Test Only 8-1/2” x 11” x 5M Townsend Annular BOP x 11” x 5M Townsend Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Townsend Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3500 (Annular 2500 psi) Subsequent Tests: 250/3500 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. 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. Additional requirements may be stipulated on APD and Sundry. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: victoria.loepp@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) gg p ( )jgg@ g Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Page 10 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 9.0 R/U and Preparatory Work 9.1 Set 16” conductor at +/-120’ below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install Seaboard slip-on 16-3/4” 3M “A” section. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 RU Mud loggers on surface hole section for gas detection only. No samples required 9.8 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.9 Mix mud for 12-1/4” hole section. 9.10 Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2” liners. Set 16” co nductor at +/-120’ below ground level. Page 11 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 10.0 N/U 21-1/4” 2M Diverter 10.1 N/U 21-1/4” Hydril MSP 2M diverter System. x N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead. x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). 10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking. x A prohibition on ignition sources or running equipment. x A prohibition on staged equipment or materials. x Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. 10.5 Rig 169 and estimated Diverter line Orientation on BRU K Pad: Rig 169 and estimated Diverter line Page 12 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 11.0 Drill 12-1/4” Hole Section 11.1 P/U 12-1/4” directional drilling assy: 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. Hydraulics calculations and recommended TFA is attached below. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 Primary Bit: Page 13 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 11.3 4-1/2” Workstring & HWDP will come from Hilcorp. 11.4 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor. 11.5 Drill 12-1/4” hole section to 2,750’ MD/ 2,550’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team. x Keep swab and surge pressures low when tripping. x Make wiper trips every 500’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x TD the hole section in a good shale between 2650’ MD and 2850’ MD. x Take MWD surveys every stand drilled (60’ intervals). 11.6 12-1/4” hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. Pason 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. System Type: 8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-2750’ 8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 See detailed pressure calculations on P. 43. DLB 04/29/20 8.8 – 9.5 Page 14 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.7 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.8 TOH with the drilling assy, handle BHA as appropriate. Page 15 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 12.0 Run 9-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 9-5/8” casing running equipment. x Ensure 9-5/8” BTC x CDS 40 XO on rig floor and M/U to FOSV. x R/U fill-up line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values required to achieve this position. x After making up several connections, use the torque required to M/U to base of triangle as the M/U torque and continue running string. x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 16 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 Page 17 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. Page 18 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 13.0 Cement 9-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt 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 cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls 10 ppg spacer. Test surface cmt lines. 13.5 Pump remaining 30 bbls of 10 ppg spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 50% open hole excess. Job will consist of lead & tail, TOC brought to surface. Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3) 12.0 ppg LEAD: 16” Conductor x 9-5/8” casing annulus: 120’ x .1125 bpf = 13.5 76 12.0 ppg LEAD: 12-1/4” OH x 9-5/8” Casing annulus: (2250’ – 120’) x .05578 bpf x 1.5 = 178.2 1000 Total LEAD: 191.7 1076 ft3 15.4 ppg TAIL: 12-1/4” OH x 9-5/8” Casing annulus: (2750’- 2250’) x .05578 bpf x 1.5 = 41.8 235 15.4 ppg TAIL: 9-5/8” Shoe track: 80 x .07582 bpf = 6.1 35 Total TAIL: 47.9 bbl 270 ft3 437 sx 221 sx Page 19 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 Cement Slurry Design: 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Displacement calculation: 2750’- 80’ = 2670’ x .07582 bpf = 203 bbls 13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. Lead Slurry (2250’ MD to surface) Tail Slurry (2750’ to 2250’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Concentration Code Description Concentration G Cement 94#/sk A Cement 94#/sk D110 Retarder 0.15 gal/sk BWOC D046 Anti Foam 0.2 % BWOC D046 Anti Foam 0.2 % BWOC D065 Dispersant 0.4 % BWOC D079 Extender 2.0 % BWOC S002 CaCl2 0.35 % BWOC D020 Extender 3.0 % BWOC D177 CaCl2 0.1 % BWOC Page 20 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 13.13 Do not overdisplace by more than ½ shoe track volume. Total volume in shoe track is 6.1 bbls. x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12 – 18 hours after CIP. x Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require us to run steel pipe through the hanger flutes. The ID of the flutes is 1.5”. 13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.15 R/D cement equipment. Flush out wellhead with FW. 13.16 Back out and L/D landing joint. Flush out wellhead with FW. 13.17 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.18 Lay down landing joint and pack-off running tool. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and mmyers@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 21 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 14.0 BOP N/U and Test 14.1 ND Diverter line and diverter 14.2 N/U multi-bowl wellhead assy. Install 9-5/8” packoff P-seals. Test to 3000 psi. 14.3 N/U 11” x 5M BOP as follows: x BOP configuration from Top down: 11” x 5M Type 90 annular BOP/11” x 5M Model 82 double ram /11” x 5M mud cross/11” x 5M Type 82 single ram x Double ram should be dressed with 4-1/2” solid body rams in top cavity, blind ram in btm cavity. x Single ram should be dressed with 4-1/2” solid body rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Run 4-1/2” BOP test assy, land out test plug (if not installed previously). x Test BOP to 250/3500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 R/D BOP test assy. 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 9.0 ppg 6% KCL PHPA mud system. 14.8 R/U mud loggers for production hole section. 14.9 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. Notify AOGCC 48 hrs prior BOPE test Page 22 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 15.0 Drill 8-1/2” Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TIH, Conduct shallow hole test of MWD and confirm Gamma Ray and Resistivity LWD functioning properly. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. 15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. Page 23 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 15.8 Primary Bit: Page 24 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 15.9 8-1/2” hole section mud program summary: Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason 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. System Type: 9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 2,750’- 7,627’ 9.0 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0 System Formulation: 6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 – 10.0 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.10 TIH w/ 8-1/2” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 15.11 R/U and test casing to 3000 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst. 9-5/8” burst is 5750 psi / 2 = 2875 psi. 15.12 Drill out shoe track and 20’ of new formation. 15.13 CBU and condition mud for FIT. 9.0 – 10.0 – g See detailed pressure calculations on P. 43. DLB 04/29/2020. 2500 psi gls Page 25 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 15.14 Conduct FIT to 13.5 ppg EMW. Note: Offset field test data predicts frac gradient at the 9-5/8” shoe to be between 11 - 13 ppg EMW. A 13.5 ppg FIT results in a 4 ppg kick margin while drilling with the planned MW of 9.5 ppg. Kick tolerance = (13.5-9.0)X(2550/7088) = 1.62 15.15 Drill 8-1/2” hole section to 7,627’ MD / 7,088’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. x Take (3) sets of formation samples every 20’. 15.16 At TD; pump sweeps, CBU, and pull a wiper trip back to the 9-5/8” shoe. 15.17 TOH with the drilling assy, standing back drill pipe. 15.18 LD BHA 15.19 PU 8-1/2”clean out BHA, and TIH to TD. 15.20 Pump sweep, CBU and condition mud for casing run. 15.21 POOH LDDP and BHA 15.22 Install 5-1/2” pipe rams in BOP stack and test. Kick tolerance = (13.5-9.0)X(2550/7088) = 1.62 FIT to 13.5 ppg 15.22 Install 5-1/2” pipe rams in BOP stack and test. Page 26 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 16.0 Run 5-1/2” Production Casing 16.1. R/U Weatherford 5-1/2” casing running equipment. x Ensure 5-1/2” CDC HTQ x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly 16.4. Continue running 5-1/2” production casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint across zones of interest, TBD after LWD. x Install solid body centralizers on every other joint to 9-5/8” shoe. Leave the centralizers free floating. x Pick up swell packer and place in string at approximately 1400’. 16.5. Continue running 5-1/2” production casing 5-1/2” CDC HTQ M/U torques Casing OD Minimum Maximum Yield Torque 5-1/2” 8,500 ft-lbs 11,500 ft-lbs 13,900 ft-lbs Page 27 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 Page 28 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 16.6. Run in hole w/ 5-1/2” casing to the 9-5/8” casing shoe. 16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.11. Set casing slowly in and out of slips. 16.12. PU 5-1/2” X 9-5/8” swell packer to be placed at approximately 2500’. Swell packer should have 10’ handling pups installed on both ends with bow spring centralizers on pups. 16.13. Swedge up and wash last 2 joints to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 16.14. Stage pump rates up slowly to circulating rate. Circ and condition mud with casing on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16.15. Reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. PU 5-1/2” X 9-5/8” swell packer to be placed at approximately 2500’ Page 29 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 17.0 Cement 5-1/2” Production Casing 17.1. Hold a pre-job safety meeting over the upcoming cmt 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 cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. x Document efficiency of all possible displacement pumps prior to cement job. 17.2. Attempt to reciprocate the casing during cmt operations until hole gets sticky 17.3. Pump 5 bbls of 12.5 ppg Mud Push spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining 30 bbls 12.5 ppg Mud Push spacer. 17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 10% OH excess. Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3) 12.0 ppg LEAD: 9-5/8” csg x 5-1/2” casing annulus: 500’ x .04644 bpf = 23.2 131 12.0 ppg LEAD: 8-1/2” OH x 5-1/2” annulus: (7127’ – 2750’) x .0408 bpf x 1.1 = 196.4 1103 Total LEAD: 219.6 1234 ft3 15.4 ppg TAIL: 8-1/2” OH x 5-1/2” annulus: (7627’- 7127’) x .0408 bpf x 1.1 = 22.4 126 15.4 ppg TAIL: 5-1/2” Shoe track: 80 x .02325 bpf = 2 12 Total TAIL: 24.4 bbl 138 ft3 501 sx 113 sx (swell packer at 2500 ft) Page 30 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 Cement Slurry Design: Lead Slurry (7127’ MD to 2250’ MD) Tail Slurry (7627’ to 7127’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Concentration Code Description Concentration G Cement 94#/sk A Cement 94#/sk D110 Retarder 0.15 gal/sk BWOC D046 Anti Foam 0.2 % BWOC D046 Anti Foam 0.2 % BWOC D065 Dispersant 0.4 % BWOC D079 Extender 2.0 % BWOC S002 CaCl2 0.35 % BWOC D020 Extender 3.0 % BWOC D177 CaCl2 0.1 % BWOC Page 31 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 17.7. Drop wiper plug and displace with drilling mud. 17.8. If hole conditions allow – continue reciprocating casing throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.9. If elevated displacement pressures are encountered, position casing at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 17.10. Bump the plug and pressure up to 500 psi over final lift pressure. Hold pressure for 3 minutes. 17.11. Do not overdisplace by more than ½ shoe track. Shoe track volume is 2 bbls. 17.12. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.13. RD cementers and flush equipment. 17.14. WOC minimum of 12 hours, test casing to 2500 psi and chart for 30 minutes. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to mmyers@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. MIT casing Page 32 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 18.0 RDMO 18.1. Install BPV in wellhead 18.2. N/D BOPE 18.3. N/U temp abandonment cap 18.4. RDMO Hilcorp Rig #169 - Separate sundry to perforate well is required - CBL over 5 1/2" casing to TOC -MIT-IA to 2500 psi on IA (5 1/2" x 9 5/8") after WOC Page 33 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 19.0 BOP Schematic Page 34 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 20.0 Wellhead Schematic ssv Page 35 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 21.0 Days Vs Depth Page 36 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 22.0 Geo-Prog Well Name:BRU 222-24 Survey Type KB Field Name:Beluga River Unit Surface Hole:92.3 Pool Name:BELUGA RIVER, UNDEFI Bottom Hole:HAK 169 State:Alaska 18 Field Location:Onshore Coord Ref Sys:74.3 County/Parish:Tyonek Borough Objective: Reference Plan: Sterling A Sands Sand / Coals Gas / Water 3535.59 3,215.8 -3197.79 2633865.01 324521.78 600.00 0.19 STERLING_B Sand / Coals Gas / Water 3741.04 3,400.2 -3382.22 2633885.38 324610.00 600.00 0.18 STERLING_C Sand / Coals Gas / Water 3909.96 3,551.8 -3533.84 2633902.13 324682.53 800.00 0.23 BELUGA_D Sand / Coals Gas / Water 4166.77 3,782.4 -3764.37 2633927.59 324792.80 900.00 0.24 BELUGA_E Sand / Coals Gas / Water 4393.61 3,986.0 -3967.98 2633950.08 324890.20 1600.00 0.40 BELUGA_F Sand / Coals Gas / Water 4733.70 4,291.3 -4273.27 2633983.81 325036.24 1200.00 0.28 BELUGA_G Sand / Coals Gas / Water 5212.63 4,721.2 -4703.18 2634031.29 325241.89 1600.00 0.34 BELUGA_H Sand / Coals Gas / Water 5526.40 5,006.8 -4988.76 2634060.47 325368.24 2244.94 0.45 BELUGA_H2 Sand / Coals Gas / Water 5607.10 5,082.3 -5064.26 2634066.88 325396.03 1400.00 0.28 BELUGA_H4 Sand / Coals Gas / Water 5674.41 5,145.8 -5127.81 2634071.87 325417.61 1400.00 0.27 BELUGA_H7 Sand / Coals Gas / Water 5767.98 5,235.0 -5216.99 2634078.24 325445.20 700.00 0.13 BELUGA_H8 Sand / Coals Gas / Water 5820.12 5,285.1 -5267.08 2634081.49 325459.30 1100.00 0.21 BELUGA_H15 Sand / Coals Gas / Water 6132.71 5,590.1 -5572.06 2634096.76 325525.40 2507.43 0.45 BELUGA_I1 Sand / Coals Gas / Water 6248.45 5,704.1 -5686.05 2634101.28 325544.98 2558.72 0.45 BELUGA_I8 Sand / Coals Gas / Water 6515.08 5,966.6 -5948.62 2634111.69 325590.09 2676.88 0.45 BRU_BELUGA_J6 Sand / Coals Gas / Water 7324.61 6,763.9 -6745.85 2634143.32 325727.05 3035.63 0.45 = Reservoir Objectives = Possible Geo Hazards TARGET RADIUS Mud Logging: LWD Data: Other Log Data: Coreing: Frac Half-Length SH Max Direction Surf. Inter. Prod. NOTES: Ground Elevation: GEOLOGICAL PROGNOSIS As-Staked x = 323,322.10 y = 2,633,544.10 TVD Ref Datum: TVD Ref Elevation: Planned Rig: Rig Height: x = 325,816.30 y = 2,634,163.77 7,627' MD 7,084' TVD NAD27 Zone 4 EASTING Est. Pressure GradientEXPECTED FLUID MD (FT) TVD (FT) TVDSS (FT)NORTHING ARTIFICIAL LIFT EQUIPMENT OD TUBING SIZE Drill a grassroots well off of K-pad at BRU targeting the Beluga H, I, and J gas sands. COMPLETION TYPE Monobore Fault Constraints 100 FT at TD Surface casing to total depth, 30 ft samples with 20' samples in zones of interest, two sets of dry cut cuttings, chromatograph, show reports, pixler plots. BRU 222-24 WP 08ANTICIPATED FORMATION TOPS & GEOHAZARDS Geo Summary/ Justification: H, I and J gas sands are under developed in the northern part of BRU. Additional untapped A sterling sands targets. TOP NAME LITHOLOGY DATA COLLECTION REQUIREMENTS: LWD GR/RES Pressure data collected throughout sands N/A ##% & 3 MMCFGPD - 2750 N/A 7627 - - PROSED PIPE SET DEPTHS Chance of Success & Anticipated Rate Page 37 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 23.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP between 25 – 45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to reduce the likelihood of washing out the conductor shoe. To help insure good cement to surface after running the casing, condition the mud to a YP of 25 –30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 38 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 8-1/2” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 39 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 24.0 Hilcorp Rig 169 Layout Page 40 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 25.0 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. NOTE: Follow AOGCC guidance doc 17-001 Page 41 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 26.0 Choke Manifold Schematic Page 42 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 27.0 Casing Design Information 12-1/4"Mud Density:9 ppg 8-1/2"Mud Density:10 ppg Mud Density: 2481 psi (see attached M ASP determination & calculation) 3190 psi (see attached M ASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.45 psi/ft) and the casing evacuated for the internal stress 1234 9-5/8" 5-1/2" 00 00 2,750 7,627 2,550 7,088 2,750 7,627 40 17 L-80 L-80 BTC CDC HTQ 110,000 129,659 110,000 129,659 916 428 8.33 3.30 1,193 3,083 3,090 6,290 2.59 2.04 645 2,481 5,750 7,740 8.91 3.12Worst case safety factor (Burst) DATE: 04/27/2020 WELL: BRU 222-24 FIELD: Beluga River Unit DESIGN BY: Monty M Myers Hole Size Hole Size Hole Size MASP: Production Mode Casing Section MASP: Drilling Mode MASP: Length Top (TVD) Minimum Yield (psi) Weight (ppf) Grade Connection Weight w/o Bouyancy Factor (lbs) Min strength Tension (1000 lbs) Collapse Resistance w/o tension (Psi) Worst Case Safety Factor (Collapse) MASP (psi) Worst Case Safety Factor (Tension) Collapse Pressure at bottom (Psi) Calculation & Casing Design Factors Calculation/Specification Casing OD Bottom (MD) Bottom (TVD) Top (MD) Tension at Top of Section (lbs) Design Criteria: 8.33 3.30 2.59 2.04 8.91 3.12 Page 43 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 28.0 8-1/2” Hole Section MASP MD TVD Planned Top: 0 0 Planned TD: 7627 7088 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Sterling A Sands 3215.79 600 Gas/Wet 3.6 0.19 STERLING_B 3400.22 600 Gas/Wet 3.4 0.18 STERLING_C 3551.84 800 Gas/Wet 4.3 0.23 BELUGA_D 3782.37 900 Gas/Wet 4.6 0.24 BELUGA_E 3985.98 1600 Gas/Wet 7.7 0.40 BELUGA_F 4291.27 1200 Gas/Wet 5.4 0.28 BELUGA_G 4721.18 1600 Gas/Wet 6.5 0.34 BELUGA_H 5006.76 2245 Gas/Wet 8.6 0.45 BELUGA_H2 5082.26 1400 Gas/Wet 5.3 0.28 BELUGA_H4 5145.81 1400 Gas/Wet 5.2 0.27 BELUGA_H7 5234.99 700 Gas/Wet 2.6 0.13 BELUGA_H8 5285.08 1100 Gas/Wet 4.0 0.21 BELUGA_H15 5590.06 2507 Gas/Wet 8.6 0.45 BELUGA_I1 5704.05 2559 Gas/Wet 8.6 0.45 BELUGA_I8 5966.62 2677 Gas/Wet 8.6 0.45 BRU_BELUGA_J6 6763.85 3036 Gas/Wet 8.6 0.45 Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date BRU 212-18 9 - 9.2 4,167 6,998 1975 BRU 214-35 9 - 9.2 3,262 6,000 1980 BRU 232-09 9 - 9.2 3,322 7,179 1984 Assumptions: 1. Fracture gradient at shoe (2550' TVD) is estimated at 17 ppg based on field test data. 2. Maximum planned mud density for the 8-1/2" hole section is 10.0 ppg. 3. Calculations assume "Unknown" reservoir contains 100% gas (worst case). 4. Calculations assume worst case event is 100% evacuation of wellbore to gas. Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: TVD Frac Grad 2550 ft X 0.884 psi/ft 2254 psi 1856(psi) - [0.1(psi/ft)*2550(ft)]= 1999 psi MASP from pore pressure during production mode (Complete evacuation to gas) 7088 ft X 0.450 psi/ft 3190 psi Downhol e 3190(psi) - [0.1(psi/ft)* 7088 (ft)]= 2481 psi Surface Summary: 1. MASP while drilling 8-1/2" production hole is governed by frac pressure at 9-5/8" shoe with entire wellbore evacuated to gas BRU 222-24 Beluga River Unit 8-1/2" Hole Section Maximum Anticipated Surface Pressure Calculation OK Page 44 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 29.0 Spider Plot (NAD 27) (Governmental Sections) Page 45 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 30.0 Surface Plat (NAD 27) Page 46 Version 0 April, 2020 BRU 222-24 Drilling Procedure Rev 0 31.0 Directional Plan (wp08) !" # !" # 0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400 5850 6300 6750 7200True Vertical Depth (900 usft/in)-900 -450 0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400 Vertical Section at 76.29° (900 usft/in) BRU 222-24 wp03 tgt1 BRU 222-24 wp03 tgt2 9 5/8" x 12 1/4" 5 1/2" x 8 1/2" 5 0 0 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 7 6 2 7 BRU 222-24 wp08 Start Dir 3º/100' : 300' MD, 300'TVD Start Dir 3º/100' : 966.67' MD, 953.21'TVD End Dir : 1691.01' MD, 1619.87' TVD Start Dir 2º/100' : 4865.25' MD, 4409.77'TVD End Dir : 5792.43' MD, 5281.4' TVD Total Depth : 7627' MD, 7088.09' TVD Sterling A Sands STERLING_B STERLING_C BELUGA_D BELUGA_E BELUGA_F BELUGA_G BELUGA_H BELUGA_H2 BELUGA_H4 BELUGA_H7 BELUGA_H8 BELUGA_H15 BELUGA_I1 BELUGA_I8 BRU_BELUGA_J6 Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Pedal Curve Warning Method: Error Ratio WELL DETAILS: Plan: BRU 222-24 74.30 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2633604.30 323359.50 61° 12' 16.658 N 151° 0' 5.745 W SURVEY PROGRAM Date: 2020-04-17T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.00 2750.00 BRU 222-24 wp08 (BRU 222-24) 3_MWD+AX+Sag 2750.00 7627.00 BRU 222-24 wp08 (BRU 222-24) 3_MWD+AX+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3290.30 3198.00 3591.56 Sterling A Sands 3474.30 3382.00 3800.91 STERLING_B 3626.30 3534.00 3973.85 STERLING_C 3856.30 3764.00 4235.53 BELUGA_D 4060.30 3968.00 4467.64 BELUGA_E 4365.30 4273.00 4814.65 BELUGA_F 4795.30 4703.00 5288.51 BELUGA_G 5081.30 4989.00 5587.80 BELUGA_H 5156.30 5064.00 5664.87 BELUGA_H2 5220.30 5128.00 5730.27 BELUGA_H4 5309.30 5217.00 5820.76 BELUGA_H7 5359.30 5267.00 5871.54 BELUGA_H8 5664.30 5572.00 6181.24 BELUGA_H15 5778.30 5686.00 6297.00 BELUGA_I1 6041.30 5949.00 6564.06 BELUGA_I8 6838.30 6746.00 7373.35 BRU_BELUGA_J6 REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: BRU 222-24, True North Vertical (TVD) Reference:As-Staked RKB @ 92.30usft (Original Well Elev) Measured Depth Reference:As-Staked RKB @ 92.30usft (Original Well Elev) Calculation Method:Minimum Curvature Project:Beluga RiverSite:Beluga River Well:Plan: BRU 222-24 Wellbore:BRU 222-24 Design:BRU 222-24 wp08 Beluga River Beluga River Plan: BRU 222-24 BRU 222-24 BRU 222-24 wp08 5.326 CASING DETAILS TVD TVDSS MD Size Name 2550.64 2458.34 2750.00 9-5/8 9 5/8" x 12 1/4" 7088.09 6995.79 7627.00 5-1/2 5 1/2" x 8 1/2" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD 3 966.67 20.00 122.00 953.21 -61.04 97.68 3.00 122.00 80.43 Start Dir 3º/100' : 966.67' MD, 953.21'TVD 4 1691.01 28.49 71.16 1619.87 -71.02 369.48 3.00 -92.72 342.13 End Dir : 1691.01' MD, 1619.87' TVD 5 4865.25 28.49 71.16 4409.77 417.83 1802.41 0.00 0.00 1850.09 Start Dir 2º/100' : 4865.25' MD, 4409.77'TVD 6 5792.43 10.00 76.12 5281.40 509.34 2092.38 2.00 177.30 2153.48 BRU 222-24 wp03 tgt1 End Dir : 5792.43' MD, 5281.4' TVD 7 7373.20 10.00 76.12 6838.15 575.18 2358.86 0.00 0.00 2427.97 BRU 222-24 wp03 tgt2 8 7627.00 10.00 76.12 7088.09 585.76 2401.65 0.00 0.00 2472.05 Total Depth : 7627' MD, 7088.09' TVD -600 -400 -200 0 200 400 600 800 1000 1200 South(-)/North(+) (300 usft/in)-200 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 West(-)/East(+) (300 usft/in) BRU 222-24 wp03 tgt2 BRU 222-24 wp03 tgt1 9 5/8" x 12 1/4" 5 1/2" x 8 1/2" 250500 75010001250150017502000225025002750300032503500375040004250450047505000525055005750600062506500675070007088BRU 222-24 wp08 Start Dir 3º/100' : 300' MD, 300'TVD Start Dir 3º/100' : 966.67' MD, 953.21'TVD End Dir : 1691.01' MD, 1619.87' TVD Start Dir 2º/100' : 4865.25' MD, 4409.77'TVD End Dir : 5792.43' MD, 5281.4' TVD Total Depth : 7627' MD, 7088.09' TVD Project: Beluga River Site: Beluga River Well: Plan: BRU 222-24 Wellbore: BRU 222-24 Plan: BRU 222-24 wp08 WELL DETAILS: Plan: BRU 222-24 74.30 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2633604.30 323359.50 61° 12' 16.658 N 151° 0' 5.745 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: BRU 222-24, True North Vertical (TVD) Reference:As-Staked RKB @ 92.30usft (Original Well Elev) Measured Depth Reference:As-Staked RKB @ 92.30usft (Original Well Elev) Calculation Method:Minimum Curvature CASING DETAILS TVD TVDSS MD Size Name 2550.64 2458.34 2750.00 9-5/8 9 5/8" x 12 1/4" 7088.09 6995.79 7627.00 5-1/2 5 1/2" x 8 1/2" -467 -233 0 233 467 700 933 1167 1400 1633 1867 South(-)/North(+) (350 usft/in)-467 -233 0 233 467 700 933 1167 1400 1633 1867 2100 2333 2567 West(-)/East(+) (350 usft/in)30 006374 BRU 212-24 50015001000 1 5 0 0 2000 2 5 0 060006540BRU 212-24T 5 0 0 0 5 50 0 6 0 0 0 6 5 0 0 7 0 1 3 BRU 224A-13 wp11000BRU 232-23 1000150020002500300035004000450050005500600065007000BRU 222-24 wp08 Azimuths to True North Magnetic North: 15.65° Magnetic Field Strength: 55372.4nT Dip Angle: 74.03° Date: 6/17/2020 Model: BGGM2019 T M Project: Beluga River Site: Beluga River Well: Plan: BRU 222-24 Wellbore: BRU 222-24 Plan: BRU 222-24 wp08 -200 -100 0 100 200 300 West(-)/East(+) (150 usft/in) -100 0 100 South(-)/North(+) (150 usft/in)4000 6374 BRU 212-24 10001000 2000 BRU 212-24T BRU 232-23 1000BRU 222-24 wp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eparation Factor0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400 5850 6300 6750 7200 7650 8100 Measured Depth BRU 224A-13 wp1 BRU 212-24 No-Go Zone - Stop Drilling Collision Avoidance Req. Collision Risk Procedures Req. NOERRORS WELL DETAILS:Plan: BRU 222-24 NAD 1927 (NADCON CONUS)Alaska Zone 04 74.30 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2633604.30 323359.50 61° 12' 16.658 N 151° 0' 5.745 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: BRU 222-24, True North Vertical (TVD) Reference:As-Staked RKB @ 92.30usft (Original Well Elev) Measured Depth Reference:As-Staked RKB @ 92.30usft (Original Well Elev) Calculation Method:Minimum Curvature SURVEY PROGRAM Date: 2020-04-17T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.00 2750.00 BRU 222-24 wp08 (BRU 222-24) 3_MWD+AX+Sag 2750.00 7627.00 BRU 222-24 wp08 (BRU 222-24) 3_MWD+AX+Sag 0.00 35.00 70.00 105.00 140.00 175.00 Centre to Centre Separation (60.00 usft/in)0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400 5850 6300 6750 7200 7650 8100 Measured Depth BRU 212-24T BRU 232-23 BRU 212-24 GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference 18.00 To 7627.00 Project: Beluga River Site: Beluga River Well: Plan: BRU 222-24 Wellbore: BRU 222-24 Plan: BRU 222-24 wp08 Ladder / S.F. Plots CASING DETAILS TVD TVDSS MD Size Name 2550.64 2458.34 2750.00 9-5/8 9 5/8" x 12 1/4" 7088.09 6995.79 7627.00 5-1/2 5 1/2" x 8 1/2" Revised 2/2015 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: ____________________________ POOL: ______________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such water well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (_______________________________) in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. BRU 222-24 X Beluga River Beluga River Undefined Gas X X 220-043 WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:BELUGA RIV UNIT 222-24Initial Class/TypeDEV / PENDGeoArea820Unit50220On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2200430BELUGA RIVER, UNDEFINED GAS - 92500NA1 Permit fee attachedYes2 Lease number appropriateYes3 Unique well name and numberYes4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 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)Yes18 Conductor string providedYes Surface casing will be set and fully cemented from 2700 ft.19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes 5 1/2" casing will be cemented up into the 9 5/8" surface casisng .. Using swell packer also.21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes BTC calculations are provided.23 Casing designs adequate for C, T, B & permafrostYes Rig 169 has steel tanks. All waste is transported to the KGF disposal wells.24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes No issues with close crossings.26 Adequate wellbore separation proposedYes 16" diverter on 169 .. Sketch of layout provided.27 If diverter required, does it meet regulationsYes Max formation press= 3190 psi (8.6 ppg EMW) will drill with 9 -10 ppg mud28 Drilling fluid program schematic & equip list adequateYes 169 has 13 5/8" 5000 psi WP BOP29 BOPEs, do they meet regulationYes MASP = 2481 psi Will test BOPE to 3500 psi30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes Sundry required to perforate well.32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S is not present in this field, per operator.35 Permit can be issued w/o hydrogen sulfide measuresYes36 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]ApprDLBDate4/29/2020ApprGLSDate4/30/2020ApprDLBDate4/29/2020AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateGrassroots well in the BRU field. Using cement packer concept with swell packer for the tubing/prod casing. GlsDaniel T. Seamount, Jr.Digitally signed by Daniel T. Seamount, Jr. Date: 2020.04.30 10:27:28 -08'00'JMP 4/30/2020JLC 4/30/2020