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Home My WebLink About219-011Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 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: 06/20/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230420 Well API #PTD #Log Date Log Company Log Type BCU 04RD 50133202390100 219011 5/16/2023 AK E-LINE Perf BCU 04RD 50133202390100 219011 5/17/2023 AK E-LINE Strip Guns NS-23 50029231460000 203050 4/25/2023 HALLIBURTON MFC PBU GNI-02A 50029228510100 206119 5/30/2023 READ Pressure Temperature Survey PBU GNI-03 50029228200000 197189 5/31/2023 READ Pressure Temperature Survey PBU J-29 50029234860000 213033 4/18/2023 BAKER SPN PBU A-06A 50029201180100 223015 4/6/2023 BAKER MRPM Please include current contact information if different from above. T37770 T37770 T37771 T37772 T37773 T37774 T37775 BCU 04RD 50133202390100 219011 5/16/2023 AK E-LINE Perf BCU 04RD 50133202390100 219011 5/17/2023 AK E-LINE Strip Guns Kayla Junke Digitally signed by Kayla Junke Date: 2023.06.21 13:29:44 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 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: 06/20/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230419 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 04RD 50133202390100 219011 5/10/2023 AK E-LINE PERF BRU 212-26 50283201820000 220058 5/31/2023 AK E-LINE PPROF NCI B-01A 50883200930100 198002 4/24/2023 AK E-LINE Cut CBL CIBP Paxton 12 50133207100000 223014 5/24/2023 AK E-LINE Perf Record Paxton 12 50133207100000 223014 4/27/2023 AK E-LINE GPT/PERF SRU 213B-15 50133206540000 215130 5/1/2023 AK E-LINE CIBP Perf TBU M-29A 50733204280100 212050 5/7/2023 AK E-LINE Drift Punch Please include current contact information if different from above. T37759 T37760 T37761 T37762 T37762 T37763 T37764 BCU 04RD 50133202390100 219011 5/10/2023 AK E-LINE PERF Kayla Junke Digitally signed by Kayla Junke Date: 2023.06.20 11:55:19 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Re-Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________ 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 16,642 feet 15,810 feet true vertical 15,652 feet ~15,808 (fish) feet Effective Depth measured 15,810 feet See Schematic feet true vertical 14,909 feet See Schematic feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet 3-1/2" 9.3# / P-110 10,954' MD 10,910' TVD Tubing (size, grade, measured and true vertical depth) 3-1/2" 9.3# / P-110 14,978' MD 14,230' TVD Packers and SSSV (type, measured and true vertical depth) See Schematic See Schematic 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: Liner 1,633' 4-1/2" 16,607' 15,618' 8,430psi 7,500psi 4,760psi 5,380psi 6,870psi 2,989' 2,989' Burst Collapse 2,670psi Production 12,521' 4,093' Casing Structural 12,357' 7 12,521' 15,193' 14,401' 288'Conductor Surface Intermediate 20" 13-3/8" 288' 2,989' measured TVD 11,220psi 9-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-011 50-133-20239-01-00 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: FEDA028083 Beaver Creek Field / Beaver Creek Oil Pool Beaver Creek Unit (BCU) 04RD 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) 305 Gas-Mcf MD 587 Size 288' 0 59012 246 820 85 Chad Helgeson, Operations Engineer 323-216 Sr Pet Eng: 8,530psi Sr Pet Geo: Sr Res Eng: WINJ WAG 14 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 chelgeson@hilcorp.com 907-777-8405 N/A Liner p k ft t Fra O s O 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 3:58 pm, May 30, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.05.30 14:44:57 - 08'00' Noel Nocas (4361) Rig Start Date End Date 5/9/23 5/17/23 05/15/2023 - Monday Arrive at Hilcorp Office, Complete PTW, Spot Equipment, RU, PT 250L/3500H. Laydown Lubricator and prep site for tomorrow. Shut down for night. AKE-line sign in, obtain PTW and hold PJSM. Discuss scope of work and focus on spill prevention. Move to location. RU equipment and MU tool string. Gun Gamma Ray/CCL, shock sub, 2.50"OD x 17' (6spf/60D) Hollow Carrier perf gun. PU tools and lubricator, stab on and PT 250L/3500H. Pass. Initial: 287.8 BOPD / 82 psi Open swab and RIH. Tool string falls slowly and sets down at 830'. Manually work tools up and down for 2 hrs. to 910' (no stickiness). RU triplex and pump 1.5 bbls of Xylene down IA to apply fluid through GL mandrels and up tubing. Work tools for 1/2 hour after pumping, with little improvement. POOH. OOH. LD perf gun. MU 1.68" OD tool string. (wt. bars (12'), CCL, spang jars & junk basket w/ no gauge ring. Open swab, RIH. Tools move freely through tubing and continue to tag PBTD at 15,796' (correlated). POOH. OOH. Add 2.30" OD gauge ring to junk basket tool string and RIH to 2500'. (No visible obstructions observed). POOH. OOH. Remove 2.30" GR and add 2.77" OD GR. RIH. Tools bobbled briefly at 900' but continued to 2500' w/o any trouble. POOH. OOH. LD lubricator and tools. Cut back 250' of kinked E-line and rehead. Make decision to shut down for night. Secure well and equipment on location. 05/09/2023 - Tuesday AKE-line meet at BC office, sign in, obtain PTW and hold PJSM. RU e-line wire/tools and MU 2.50" x 17' Titan HC perf gun loaded with 12 gm. charges (6spf/60D) to 1-11/16" Gun gamma ray/CCL and shock sub. CCL to T.S. - 11.5'. PU lub and tools and stab on well. Initial 284 BOPD / 82 psi. Open swab and RIH. Tag PBTD at 15,792' and PU, logging correlation pass and send to Geo/RE. Log pass is 2' deep (subtract 2') and pull into position at 15,676.5' (CCL depth) to shoot gun in the Tyonek G2B interval at 15,688'-15,705' (17'). Good indication of gun detonation. POOH. Initial: 82 psi. No change after 30 min. OOH. LD spent gun. All shots fired. MU Gun #2 - 2.50" x 18' HC. CCL to top shot - 11.5'. Open swab and RIH. Run correlation pass from 15,550' - 15,100'. Send in log pass to RE. Confirm on depth and perforate the TY-G1B interval at 15,216'-15,234'. Good indication that gun fired. POOH. No significant change in rate and pressure at this time. OOH. All shots fired. Secure well. RDMO E-line to BCU-19rd. Hand well over to production to flow test. 05/10/2023 - Wednesday Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 Rig Start Date End Date 5/9/23 5/17/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 05/16/2023 - Tuesday AKE-line arrive at BC office, sign in, obtain PTW and hold PJSM. Well flowing at 315 bopd/85 psi. 15-May-23 - spotted equipment, RU and PT lubricator 250L/3500H. 16-May-23 - PU sheaves, line and MU tool string: (R.S., 1-11/16" x 5' wt. bar, 1-9/16"x 7' impactor selector jars, 1-11/16" GR/CCL and 2.50" OD x 10' Spiral strip gun (4spf / 60D) (8' - CCL to top shot). PU tools and lubricator, move to well head. Open swab and RIH. Run to 15750' and log correlation to 14.900'. Send log to RE/Geo. Adjusted log -2'. Pulled into position to shoot the lower G2B interval at 15695' - 15705'. Fired gun. Good indication gun fired' POOH. OOH. LD spent strip gun (all shots fired). MU Gun Run #2 (10'). PU, stab on and RIH. (8' CCL to top shot) Tools set down briefly at overshot at 13,885'. Worked tools twice and RIH. Ran and sent correlation pass to RE/Geo and adjusted -2'. Positioned gun to shoot G2B at 15,688'-15,698'. Fired gun, POOH. OOH. LD spent strip gun (all shots fired). Hot check tools, GR/CCL failed to shoot through, change out to single 2-1/8" CCL. MU Gun #3 (10'). PU, stab on and RIH. (3' CCL to top shot). RIH. Tools set down at 13,885'@ 3-1/2" tubing overshot. Worked tool for 1 hour, with no success. POOH. OOH. Inspected strip gun and identified lower leading edge on strip did not have enough curvature to enter overshot. Will redress at WL shop. LD lubricator, secured well and SDFN. Flow rate TBD after perf completion, no change in rate or psi witnessed on site. 05/17/2023 - Wednesday AKE-line arrives at BC office, signs in, obtains PTW and holds PJSM. MU tool string with: R.S., 1.68"x 5' wt. bar, GR/CCL, Impact e-line jars, and 2-1/2" OD x 10' spiral gun loaded with Owen 26gm charges (4 spf / 60D phase). 15.2' CCL to T.S. PU tools and lubricator and stab on well head. Open swab and RIH (Gun #3) w/ well flowing at 311 BOPD / 85 psi. Run correlation pass from 15,400' to 14,900'. Send tie-in pass to RE/Geo. Confirmed on depth to shoot. Tried 4 attempts to pull into position slowly and tool string became stuck 5' short of shot depth at 15,224. Fifth pass, pulled up at a faster speed, pulled into position and shot the lower G1B interval at 15,224' - 15,234'. POOH. OOH. LD spent strip, all shots fired. MU Gun #4 (10'). Impact e-line jars failed surface check, removed from string. CCL to T.S. - 8.1'. PU tools, stab on and RIH. Run correlation pass and send to RE. Confirm on depth, pull into position and fire gun at 15,216' - 15,226'. Pulled into 3-1/2" tubing tail and through all restrictions with 400'-500 lb. overpulls. OOH. Strip bent and kinked badly, recovered all hardware. Secure well and RDMO E-line. Job complete. _____________________________________________________________________________________ Updated by DMA 05-25-23 SCHEMATIC Beaver Creek Unit Well: BCU 04RD Completed: 7/01/2021 PTD: 219-011 API: 50-133-20239-01-00 JEWELRY DETAIL No.Depth ID OD Item 18Cactus tubing hanger 2,446GLM #1 (live 8/19/21) 4,392GLM #2 (live 8/19/21) 5,881GLM #3 (live 8/19/21) 7,009GLM #4 (live 8/20/21) 1 7,453Chemical injection mandrel (live 8/17/21) 7,797GLM #5 (live 8/18/21) 8,403GLM #6 (live 8/20/21) 9,006GLM #7 (orifice 8/20/21) 9,607GLM #8 (dummy 8/20/21) 10,213GLM #9 (dummy 7/2/21) 10,818GLM #10 (dummy 7/2/21) 2 10,9032.813 4.300 Sliding sleeve (Up to close / Down to open) 3 10,9524.750 7.660 6 anchor latch seal assembly inside 5 tieback sleeve 4 10,9545.000 8.250 5.5 x 9.625 10k D&L permanent hydraulic packer 5 10,991 7 Liner Top Packer (behind 5.5 flush joint casing) 5.1 11,1287.000 7 Swell Packer 6 13,790 2.813 4.490 3.5 X Nipple 7 13,793 3.990 5.870 5.00 16ft SBR w snap latch seal bore 8 13,809 3.990 5.875 4.5 x 7 10k D&L permanent hydraulic packer 9 13,852 2.813 4.510 3.5 X Nipple 10 13,885 2.992 3.654 5.90 OD fluted overshot 11 14,8834.000 6.000 5.000 anchor latch w 3 seals / 5.000 SBR 12 14,8884.000 5.875 Tripoint 7 26-32# Permanent Liner Top Packer 13 14,9612.813 4.500 3.5 X Nipple 14 14,9734.000 5.750 10 Baker Seal Bore with seals removed 15 14,9745.750 4-1/2 Liner Top Packer w Tieback SBR 16 15,067Water Swell Packer 17 15,810Interwell 270-450 HPHT RBP Plug (7/16/19) PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Status Date Tyonek G1B 15,216 15,234 14,419 4,433 18Open 7/17/19, 4/7/22, 1/27/23, 5/10/23, 5/17/23 G2A 15,596 15,631 14,730 14,750 14 Open 2/2/23 Tyonek G2B 15,688 15,705 14,807 14,821 17Open 4/9/22, 1/27/23, 5/10/23, 5/16/23 Hemlock 15,900 15,933 14,984 15,013 33 Isolated w/ plug 7/16/2019 7/11/19 West Foreland 16,408 16,474 15,430 15,491 66 Isolated w/ plug 7/16/2019 7/02/19 CASING DETAIL Size Type Wt Grade Conn. Drift ID Top Btm 20Conductor 94 H-40 N/A Surface 288 13-3/8Surface 72 N-80 12.415 Surface 2,989 9-5/8" Production 47 53.5 N-80,S-95 P-110 8.681 8.535 Surface 9,938 9,938 12,521 7"CSG 29 P-110 IC/TXP BTC 6.059 11,10015,193 4-1/2"Liner 12.6 L-80 DWC/C 3.833 14,97416,607 CASING/LINER PATCH DETAIL 5-1/2Patch 23 P-110 EZGO FJ3 4.545 10,95913,780 TUBING DETAIL 3-1/2Tubing 9.3 P-110 8RD EUE 2.867 Surface 10,954 3-1/2Tubing 9.3 P-110 8RD EUE 2.867 13,32014,978 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Re-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): 16,642'~15,808 (fish) Casing Collapse Structural Conductor Surface 2,670psi Production 4,760psi Liner 8,530psi Liner 7,500psi 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 Chad Helgeson, Operations Engineer chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: 9.3# / P-110 10,954 & 14,978 April 27, 2023 See Schematic See Schematic See Schematic See Schematic 3-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 219-011 50-133-20239-01-00 Beaver Creek Beaver Creek Oil Same CO 237D Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beaver Creek Unit (BCU) 04RD Length Size Proposed Pools: TVD Burst PRESENT WELL CONDITION SUMMARY 15,652' 15,810' 14,909' ~3,070 psi 15,810' MD 6,870psi 5,380psi 288' 2,989' 12,357' 288' 2,989' 12,521' Perforation Depth MD (ft): 4,093' 4-1/2"1,633' 7" 9-5/8"12,521' 20" 13-3/8" 288' 2,989' 11,220psi14,401'15,193' 8,430psi16,607' 15,618' Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov DSR-4/13/23SFD 4/10/2023BJM 4/18/23 10-404 GCW 04/18/23 04/18/2023Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.04.18 14:11:05 -08'00' RBDMS JSB 041923 Well Prognosis Well Name: BCU-04RD API Number: 50-133-20239-01-00 Current Status: Producing Oil Well Permit to Drill Number: 219-011 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Maximum Expected BHP: ~8500 psi @ TVD (Based on G1B sand) Max. Potential Surface Pressure: ~3070 psi (Max expected BHP minus 0.375 psi/ft oil gradient) Well Status: Online gas lifted oil producer Brief Well Summary: In 2019 BCU-4RD drilled to a depth of 16,642 . After squeezed with Halliburton Epoxy Resin, successfully stopping the influx. The well was completed in the Tyonek and produced at this rate until it suddenly went to 100% water just three weeks later. A LDL reconfirmed the leak point and a TTP was set isolating the reservoir. Two failed workover attempts were made to squeeze the leak. A third attempt in 2021 successfully isolated the water leak with a straddle packer completion and the well has remained online since this intervention. The well was reperforated in February 2023 with no increase in rate and a greater decline rate than forecasted. The purpose of this sundry is to re-perforate Tyonek G2B, G2A and G1B to increase production. All sands lie in the same pool . Wellbore Conditions: 3/14/23 SL Tagged at 15, with Procedure: 1. RU E-line and test lubricator 250/3500H 2. Perforate the following: Zone Name Top Perf Depth MD Bottom Perf Depth MD Top Perf Depth TVD Bottom Perf Depth TVD Gun Length G1B (reperfs) ±15,216 ±15,234 ±14,419 ±14,434 ±18 G2A (reperfs) ±15,596 ±15,631 ±14,730 ±14,759 ±35 G2B (reperfs) ±15,688 ±15,705 ±14,804 ±14,821 ±17 3. Turn well over to production & flow test well E-line Procedure (Contingency if water is encountered after perforating) 1. If any zone produces water or needs isolated: 2. MIRU E-Line and pressure control equipment. PT lubricator to above MASP. 3. RIH and set plug above the perforations OR set patch over the wet perforations. Attachments: 1. As-built Well Schematic 2. Proposed Well Schematic _____________________________________________________________________________________ Updated by CAH 4-6-23 PROPOSED Beaver Creek Unit Well: BCU 04RD Completed: 7/01/2021 PTD: 219-011 API: 50-133-20239-01-00 JEWELRY DETAIL No.Depth ID OD Item 18 Cactus tubing hanger 2,446 GLM #1 (live 8/19/21) 4,392 GLM #2 (live 8/19/21) 5,881 GLM #3 (live 8/19/21) 7,009 GLM #4 (live 8/20/21) 1 7,453 Chemical injection mandrel (live 8/17/21) 7,797 GLM #5 (live 8/18/21) 8,403 GLM #6 (live 8/20/21) 9,006 GLM #7 (orifice 8/20/21) 9,607 GLM #8 (dummy 8/20/21) 10,213 GLM #9 (dummy 7/2/21) 10,818 GLM #10 (dummy 7/2/21) 2 10,903 2.813 4.300 Sliding sleeve (Up to close / Down to open) 3 10,952 4.750 7.660 eback sleeve 4 10,954 5.000 8.250 k D&L permanent hydraulic packer 5 (behind 5.5 flush joint casing) 5.1 11,128 7.000 7 Swell Packer 6 13,790 2.813 4.490 3.5 X Nipple 7 13,793 3.990 5.870 5.00 16ft SBR w snap latch seal bore 8 13,809 3.990 5.875 k D&L permanent hydraulic packer 9 13,852 2.813 4.510 10 13,885 2.992 3.654 D fluted overshot 11 14,883 4.000 6.000 12 4.000 5.875 Trip 6-32# Permanent Liner Top Packer 13 2.813 4.500 3.5 X Nipple 14 4.000 5.750 Baker Seal Bore with seals removed 15 14 5.750 4-w Tieback SBR 16 Water Swell Packer 17 15,8 Interwell 270-450 HPHT RBP Plug (7/16/19) PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Status Date Tyonek G1B 15,216 18 Open 7/17/19, 4/7/22, 1/27/23, April 23 G2A 15,596 15,631 14,730 14,750 14 Open 2/2/23, April 23 Tyonek G2B 15,688 15,705 14,807 14,821 17 Open 4/9/22, 1/27/23, April 23 Hemlock 1 Isolated w/ plug 7/16/2019 7/11/19 West Foreland 16,408 Isolated w/ plug 7/16/2019 7/02/19 CASING DETAIL Size Type Wt Grade Conn. Drift ID Top Btm Conductor 94 H-40 N/A Surface 13-Surface 72 N-80 12.415 Surface 9-5/8" Production 47 53.5 N-80,S-95 P-110 8.681 8.535 Surface 7"CSG 29 P-110 IC/TXP BTC 6.059 1 4-1/2"Liner 12.6 L-80 DWC/C 3.833 16,60 CASING/LINER PATCH DETAIL 5-Patch 23 P-110 EZGO FJ3 4.545 10,959 13,780 TUBING DETAIL 3-Tubing 9.3 P-110 8RD EUE 2.867 Surface 10,954 3-Tubing 9.3 P-110 8RD EUE 2.867 13, Kyle Wiseman Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 02/07/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230207 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPE-17 50029226870000 196115 1/17/2023 YELLOW JACKET LDL CLU 10RD 50133205530100 222113 2/3/2023 YELLOW JACKET GPT-PERF BCU 04RD 50133202390100 219011 1/27/2023 YELLOW JACKET PERF BCU 04RD 50133202390100 219011 2/2/2023 YELLOW JACKET PERF BCU 05RD2 50133202620200 218068 1/26/2023 YELLOW JACKET PERF BCU 12A 50133205300100 214070 2/1/2023 YELLOW JACKET PLUG Please include current contact information if different from above. By Meredith Guhl at 9:51 am, Feb 07, 2023 T37492 T37492 T37493 T37494 T37495 T37496 BCU 04RD 50133202390100 219011 1/27/2023 YELLOW JACKET PERF BCU 04RD 50133202390100 219011 2/2/2023 YELLOW JACKET PERF Meredith Guhl Digitally signed by Meredith Guhl Date: 2023.02.07 10:08:10 -09'00' 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: ______________________ 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 16,642 feet 15,810 feet true vertical 15,652 feet ~15,808 (fish) feet Effective Depth measured 15,810 feet 14974; 15067 feet true vertical 14,909 feet 10910; 10946; feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet 3-1/2" 9.3# / P-110 10,954' MD 10,910' TVD Tubing (size, grade, measured and true vertical depth) 3-1/2" 9.3# / P-110 14,978' MD 14,230' TVD 10954 10991 11128 13809 10910 10946 11078 13359 Packers and SSSV (type, measured and true vertical depth) N/A 14888 1497415067 MD 14160 14227 14300 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: Chad Helgeson, Operations Engineer 323-021 Sr Pet Eng: 8,530psi Sr Pet Geo: Sr Res Eng: WINJ WAG 31 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 chelgeson@hilcorp.com 907-777-8405 N/A D&L Perm, Liner Top, Swell, D&L Perm, Liner Top; Liner Top, Swell 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) 412 Gas-Mcf MD 645 Size 288' 0 64484 391 920 93 measured TVD 11,220psi 9-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-011 50-133-20239-01-00 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: FEDA028083 Beaver Creek Field / Beaver Creek Oil Pool Beaver Creek Unit (BCU) 04RD Plugs Junk measured Length Liner 12,521' 4,093' Casing Structural 12,357' 7 12,521' 15,193' 14,401' 288'Conductor Surface Intermediate 20" 13-3/8" 288' 2,989' 10954; 10991; 11128; 13809; 14888; 11078; 13359; 14160; 14227; 14300 Liner 1,633' 4-1/2" 16,607' 15,618' 8,430psi 7,500psi 4,760psi 5,380psi 6,870psi 2,989' 2,989' Burst Collapse 2,670psi Production p k ft t Fra O s O 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 Samantha Carlisle at 3:33 pm, Feb 21, 2023 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2023.02.21 15:19:14 -09'00' Dan Marlowe (1267) Rig Start Date End Date 1/27/23 2/2/23 01/27/2023- Friday Move from BCU-05RD2 to BCU-04RD. Open PTW & PJSM. Spot in equipment & support equipment. Pick up lubricator & BHA #1. Stab on the well. PT to 250/3500 psi, pass. Well is flowing @ 87 psi. RIH w/ 6.3' x 1.69" GR/CCL, 2' x 1.69" Shock Sub, 17' x 2 1/2" Geo Razor guns w/ 2 3/8" LS charges. 10.5' CCL to top shot. Pull correlation log, on depth. CCL stop depth = 15677.5' Shoot zone G2B, 15688' - 15705'. FTP = 90 psi, 5 min = 86, 10 min = 86, 15 = 88. POOH, Lay down BHA. All shots fired. Well is flowing @ 88 psi. RIH w/ 6.3' x 1.69" GR/CCL, 2' x 1.69" Shock Sub, 18' x 2 1/2" Geo Razor guns w/ 2 3/8" LS charges.14' CCL to top shot. Pull correlation log, on depth. CCL stop depth = 15202' Shoot zone G1B, 15216' - 15234'. FTP = 88 psi, 5 min = 88, 10 min = 87, 15 min = 88. POOH, lay down BHA. All shots fired. Lay down lubricator. Secure well. RDMO. YJ EL arrive on location. PJSM and PTW. MIRU. PU lubricator. MU 21' 2-3/4" HSC 6 spf gun and stab on. Pressure test to 250 and 3500 psi. RIH and correlate, send to town, on depth. Well is flowing. Perforate the G2A from 15,610'-15,631'. POOH. All shots fired. Pressure data: initial - 93 psi 5 min - 92.4 psi 10 min - 93.6 psi 15 min - 94.0 psi. MU 14' 2-3/4" HSC 6 spf gun. RIH, correlate, and send to town. On depth. Perforate the G2A from 15,596'-15,610'. POOH. All shots fired. Secure tree. RDMO. Pressure data: initial - 92 psi 5 min - 93.7 psi 10 min - 92.4 psi 15 min - 91.7 psi 02/02/2023 - Thursday Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 _____________________________________________________________________________________ Updated by DMA 02-16-23 SCHEMATIC Beaver Creek Unit Well: BCU 04RD Completed: 7/01/2021 PTD: 219-011 API: 50-133-20239-01-00 JEWELRY DETAIL No.Depth ID OD Item 18Cactus tubing hanger 2,446GLM #1 (live 8/19/21) 4,392GLM #2 (live 8/19/21) 5,881GLM #3 (live 8/19/21) 7,009GLM #4 (live 8/20/21) 1 7,453Chemical injection mandrel (live 8/17/21) 7,797GLM #5 (live 8/18/21) 8,403GLM #6 (live 8/20/21) 9,006GLM #7 (orifice 8/20/21) 9,607GLM #8 (dummy 8/20/21) 10,213GLM #9 (dummy 7/2/21) 10,818GLM #10 (dummy 7/2/21) 2 10,9032.813 4.300 Sliding sleeve (Up to close / Down to open) 3 10,9524.750 7.660 6 anchor latch seal assembly inside 5 tieback sleeve 4 10,9545.000 8.250 5.5 x 9.625 10k D&L permanent hydraulic packer 5 10,9917 Liner Top Packer (behind 5.5flush joint casing) 5.1 11,1287.000 7Swell Packer 6 13,790 2.813 4.490 3.5X Nipple 7 13,793 3.990 5.870 5.0016ft SBR w snap latch seal bore 8 13,809 3.990 5.875 4.5 x 7 10k D&L permanent hydraulic packer 9 13,852 2.813 4.510 3.5 X Nipple 10 13,885 2.992 3.654 5.90 OD fluted overshot 11 14,8834.000 6.000 5.000 anchor latch w 3 seals / 5.000 SBR 12 14,8884.000 5.875 Tripoint 7 26-32# Permanent Liner Top Packer 13 14,9612.813 4.500 3.5 X Nipple 14 14,9734.000 5.750 10 Baker Seal Bore with seals removed 15 14,9745.750 4-1/2 Liner Top Packer w Tieback SBR 16 15,067Water Swell Packer 17 15,810Interwell 270-450 HPHT RBP Plug (7/16/19) PERFORATION DETAIL Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Status Date Tyonek G1B 15,216 15,234 14,419 4,433 18 Open 7/17/19, 4/7/22, 1/27/23 G2A 15,596 15,631 14,730 14,750 14 Open 2/2/23 Tyonek G2B 15,68815,70514,80714,82117Open 4/9/22, 1/27/23 Hemlock 15,900 15,933 14,984 15,013 33 Isolated w/ plug 7/16/2019 7/11/19 West Foreland 16,408 16,474 15,430 15,491 66 Isolated w/ plug 7/16/2019 7/02/19 TD =16,642(MD) / TD = 15,652(TVD) 2000 KB Elev.:166.2/ BF/GLF Elev.: 148.2 7 TOC @ 12,767 4 1-2 TOC 15,322 PBTD =15,810(MD)/ PBTD = 14,909(TVD) 88 8 17 4-44 1/2 1 5.1 Hemlock West Forelands 11 14 16 7 @ 15,19377 tbg stub @13,888 6/23/21 2 13 15 5 9-5/8 TOW @ 11,356 CS @ 14,926 (8/21/19) PX @ 14,961 (8/6/19) Tyonek G1B tbg punch: 11,018 leak @ 11,021 3 9 10 7 4 12 Leak @ 11,021 6 Fish @ ~15,808 18 RHC plug body, unthreaded from x- lock, fell downhole (7/17/21) Tyonek G2A Tyonek G2B HPW @ 14,985 15,155 CASING DETAIL Size Type Wt Grade Conn. Drift ID Top Btm 20Conductor 94 H-40 N/A Surface 288 13-3/8Surface 72 N-80 12.415 Surface 2,989 9-5/8" Production 47 53.5 N-80,S-95 P-110 8.681 8.535 Surface 9,938 9,938 12,521 7"CSG 29 P-110 IC/TXP BTC 6.059 11,10015,193 4-1/2"Liner 12.6 L-80 DWC/C 3.833 14,97416,607 CASING/LINER PATCH DETAIL 5-1/2Patch 23 P-110 EZGO FJ3 4.545 10,95913,780 TUBING DETAIL 3-1/2Tubing 9.3 P-110 8RD EUE 2.867 Surface 10,954 3-1/2Tubing 9.3 P-110 8RD EUE 2.867 13,32014,978 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): 16,642'~15,808 (fish) Casing Collapse Structural Conductor Surface 2,670psi Production 4,760psi Liner 8,530psi Liner 7,500psi 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 Chad Helgeson, Operations Engineer chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):Tubing Size: 9.3# / P-110 10,954 & 14,978 January 27, 2023 See Schematic See Schematic See Schematic See Schematic 3-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 219-011 50-133-20239-01-00 Beaver Creek Beaver Creek Oil Same CO 237D Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beaver Creek Unit (BCU) 04RD Length Size Proposed Pools: TVD Burst PRESENT WELL CONDITION SUMMARY 15,652'15,810'14,909'~3,070 psi 15,810' MD 6,870psi 5,380psi 288' 2,989' 12,357' 288' 2,989' 12,521' Perforation Depth MD (ft): 4,093' 4-1/2"1,633' 7" 9-5/8"12,521' 20" 13-3/8" 288' 2,989' 11,220psi14,401'15,193' 8,430psi16,607'15,618' m n P s 66 t _ Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Samantha Carlisle at 2:03 pm, Jan 13, 2023 323-021 Digitally signed by Aras Worthington (4643) DN: cn=Aras Worthington (4643), ou=Users Date: 2023.01.13 13:31:32 -09'00' Aras Worthington (4643) DSR-1/17/23 10-404 BJM 1/18/23 SFD 1/17/2023GCW 01/18/23 JLC 1/18/2023 1/19/23Brett W. Huber. Sr.Digitally signed by Brett W. Huber. Sr. Date: 2023.01.19 08:26:17 -09'00' RBDMS JSB 011923 Well Prognosis Well Name: BCU-04RD API Number: 50-133-20239-01-00 Current Status: Producing Oil Well Permit to Drill Number: 219-011 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Maximum Expected BHP: ~8500 psi @ 14,477’ TVD (Based on G1B sand) Max. Potential Surface Pressure: ~3070 psi (Max expected BHP minus 0.375 psi/ft oil gradient) Well Status: Online gas lifted oil producer Brief Well Summary: In 2019 BCU-4RD was sidetracked out of the original 9.625” casing and drilled to a depth of 16,642’ MD. After cementing the 4.5” liner in place a casing leak was identified just below the 7” LTP with a noise log and was squeezed with Halliburton Epoxy Resin, successfully stopping the influx. The well was completed in the Tyonek and IP’d at over 900 bopd and produced at this rate until it suddenly went to 100% water just three weeks later. A LDL reconfirmed the leak point and a TTP was set isolating the reservoir. Two failed workover attempts were made to squeeze the leak. A third attempt in 2021 successfully isolated the water leak with a straddle packer completion and the well has remained online since this intervention. The well has declined and the purpose of this sundry is to add perforations to the Tyonek G2A and re-perforate Tyonek G2B and G1B, to increase production. All sands lie in the same pool . Wellbore Conditions: 9/1/22 Tagged at 15,797’ with 1.75” GR with 2.5” centralizer Procedure: 1. RU E-line and test lubricator 250/3500H 2. Perforate the following: Zone Name Top Perf Depth MD Bottom Perf Depth MD Top Perf Depth TVD Bottom Perf Depth TVD Gun Length G1B (reperfs) ±15,216 ±15,234 ±14,419 ±14,434 ±18 G2A (add) ±15,596 ±15,631 ±14,730 ±14,759 ±35 G2B (reperfs) ±15,688 ±15,705 ±14,804 ±14,821 ±17 3. Turn well over to production & flow test well E-line Procedure (Contingency if water is encountered after perforating) 1. If any zone produces water or needs isolated: 2. MIRU E-Line and pressure control equipment. PT lubricator to above MASP. 3. RIH and set plug above the perforations OR set patch over the wet perforations. Attachments: 1. As-built Well Schematic 2. Proposed Well Schematic _____________________________________________________________________________________ Updated by CRR 8-30-22 SCHEMATIC Beaver Creek Unit Well: BCU 04RD Completed: 7/01/2021 PTD: 219-011 API: 50-133-20239-01-00 JEWELRY DETAIL No.Depth ID OD Item 18’Cactus tubing hanger 2,446’GLM #1 (live – 8/19/21) 4,392’GLM #2 (live – 8/19/21) 5,881’GLM #3 (live – 8/19/21) 7,009’GLM #4 (live – 8/20/21) 1 7,453’Chemical injection mandrel (live – 8/17/21) 7,797’GLM #5 (live – 8/18/21) 8,403’GLM #6 (live – 8/20/21) 9,006’GLM #7 (orifice – 8/20/21) 9,607’GLM #8 (dummy – 8/20/21) 10,213’GLM #9 (dummy – 7/2/21) 10,818’GLM #10 (dummy – 7/2/21) 2 10,903’2.813 4.300 Sliding sleeve (Up to close / Down to open) 3 10,952’4.750 7.660 6” anchor latch seal assembly inside 5” tieback sleeve 4 10,954’5.000 8.250 5.5 x 9.625” 10k D&L permanent hydraulic packer 5 10,991’7” Liner Top Packer (behind 5.5” flush joint casing) 5.1 11,128’7.000 7” Swell Packer 6 13,790 2.813 4.490 3.5” X Nipple 7 13,793 3.990 5.870 5.00” 16ft SBR w snap latch seal bore 8 13,809 3.990 5.875 4.5 x 7” 10k D&L permanent hydraulic packer 9 13,852 2.813 4.510 3.5” X Nipple 10 13,885 2.992 3.654 5.90” OD fluted overshot 11 14,883’4.000 6.000 5.000” anchor latch w 3’ seals / 5.000” SBR 12 14,888’4.000 5.875 Tripoint 7” 26-32# Permanent Liner Top Packer 13 14,961’2.813 4.500 3.5 X Nipple 14 14,973’4.000 5.750 10’ Baker Seal Bore with seals removed 15 14,974’5.750 4-1/2” Liner Top Packer w Tieback SBR 16 15,067’Water Swell Packer 17 15,810’Interwell 270-450 HPHT RBP Plug (7/16/19) PERFORATION DETAIL Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Status Date Tyonek G1B 15,216 15,234’14,419’ 4,433’ ±18’Open 7/17/2019 4/7/2022 Tyonek G2B 15,688’15,705’14,807’14,821’17’Open 4/9/2022 Hemlock 15,900’15,933’14,984’ 15,013’ 33’ Isolated w/ plug 7/16/2019 7/11/2019 West Foreland 16,408’16,474’15,430’ 15,491’ 66’ Isolated w/ plug 7/16/2019 7/02/2019 CASING DETAIL Size Type Wt Grade Conn. Drift ID Top Btm 20”Conductor 94 H-40 N/A Surface 288’ 13-3/8”Surface 72 N-80 12.415 Surface 2,989’ 9-5/8" Production 47 53.5 N-80,S-95 P-110 8.681 8.535 Surface 9,938’ 9,938’ 12,521’ 7"CSG 29 P-110 IC/TXP BTC 6.059 11,100’15,193’ 4-1/2"Liner 12.6 L-80 DWC/C 3.833 14,974’16,607’ CASING/LINER PATCH DETAIL 5-1/2”Patch 23 P-110 EZGO FJ3 4.545 10,959’13,780’ TUBING DETAIL 3-1/2”Tubing 9.3 P-110 8RD EUE 2.867 Surface 10,954’ 3-1/2”Tubing 9.3 P-110 8RD EUE 2.867 13,320’14,978’ _____________________________________________________________________________________ Updated by CAH 1-13-22 PROPOSED Beaver Creek Unit Well: BCU 04RD Completed: 7/01/2021 PTD: 219-011 API: 50-133-20239-01-00 JEWELRY DETAIL No.Depth ID OD Item 18’Cactus tubing hanger 2,446’GLM #1 (live – 8/19/21) 4,392’GLM #2 (live – 8/19/21) 5,881’GLM #3 (live – 8/19/21) 7,009’GLM #4 (live – 8/20/21) 1 7,453’Chemical injection mandrel (live – 8/17/21) 7,797’GLM #5 (live – 8/18/21) 8,403’GLM #6 (live – 8/20/21) 9,006’GLM #7 (orifice – 8/20/21) 9,607’GLM #8 (dummy – 8/20/21) 10,213’GLM #9 (dummy – 7/2/21) 10,818’GLM #10 (dummy – 7/2/21) 2 10,903’2.813 4.300 Sliding sleeve (Up to close / Down to open) 3 10,952’4.750 7.660 6” anchor latch seal assembly inside 5” tieback sleeve 4 10,954’5.000 8.250 5.5 x 9.625” 10k D&L permanent hydraulic packer 5 10,991’7” Liner Top Packer (behind 5.5” flush joint casing) 5.1 11,128’7.000 7” Swell Packer 6 13,790 2.813 4.490 3.5” X Nipple 7 13,793 3.990 5.870 5.00” 16ft SBR w snap latch seal bore 8 13,809 3.990 5.875 4.5 x 7” 10k D&L permanent hydraulic packer 9 13,852 2.813 4.510 3.5” X Nipple 10 13,885 2.992 3.654 5.90” OD fluted overshot 11 14,883’4.000 6.000 5.000” anchor latch w 3’ seals / 5.000” SBR 12 14,888’4.000 5.875 Tripoint 7” 26-32# Permanent Liner Top Packer 13 14,961’2.813 4.500 3.5 X Nipple 14 14,973’4.000 5.750 10’ Baker Seal Bore with seals removed 15 14,974’5.750 4-1/2” Liner Top Packer w Tieback SBR 16 15,067’Water Swell Packer 17 15,810’Interwell 270-450 HPHT RBP Plug (7/16/19) PERFORATION DETAIL Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Status Date Tyonek G1B 15,216 15,234’14,419’ 4,433’ 18’ Open 7/17/2019 4/7/2022 G2A (add)±15,596 ±15,631 ±14,730 ±14,759 ±35 Proposed Tyonek G2B 15,688’15,705’14,807’14,821’17’Open 4/9/2022 Hemlock 15,900’15,933’14,984’ 15,013’ 33’ Isolated w/ plug 7/16/2019 7/11/2019 West Foreland 16,408’16,474’15,430’ 15,491’ 66’ Isolated w/ plug 7/16/2019 7/02/2019 CASING DETAIL Size Type Wt Grade Conn. Drift ID Top Btm 20”Conductor 94 H-40 N/A Surface 288’ 13-3/8”Surface 72 N-80 12.415 Surface 2,989’ 9-5/8" Production 47 53.5 N-80,S-95 P-110 8.681 8.535 Surface 9,938’ 9,938’ 12,521’ 7"CSG 29 P-110 IC/TXP BTC 6.059 11,100’15,193’ 4-1/2"Liner 12.6 L-80 DWC/C 3.833 14,974’16,607’ CASING/LINER PATCH DETAIL 5-1/2”Patch 23 P-110 EZGO FJ3 4.545 10,959’13,780’ TUBING DETAIL 3-1/2”Tubing 9.3 P-110 8RD EUE 2.867 Surface 10,954’ 3-1/2”Tubing 9.3 P-110 8RD EUE 2.867 13,320’14,978’ 2SHUDWLRQV $EDQGRQ 3OXJ3HUIRUDWLRQV )UDFWXUH6WLPXODWH 3XOO7XELQJ 2SHUDWLRQVVKXWGRZQ 3HUIRUPHG 6XVSHQG 3HUIRUDWH 2WKHU6WLPXODWH $OWHU&DVLQJ &KDQJH$SSURYHG3URJUDP 3OXJIRU5HGULOO 3HUIRUDWH1HZ3RRO 5HSDLU:HOO 5HHQWHU6XVS:HOO 2WKHUBBBBBBBBBBBBBBBBBBBBBB 'HYHORSPHQW ([SORUDWRU\ 6WUDWLJUDSKLF 6HUYLFH $3,1XPEHU 3URSHUW\'HVLJQDWLRQ/HDVH1XPEHU:HOO1DPHDQG1XPEHU /RJV/LVWORJVDQGVXEPLWHOHFWURQLFGDWDSHU$$&)LHOG3RROV 3UHVHQW:HOO&RQGLWLRQ6XPPDU\ 7RWDO'HSWK PHDVXUHG IHHW IHHW WUXHYHUWLFDO IHHW aILVK IHHW (IIHFWLYH'HSWK PHDVXUHG IHHW IHHW 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WƌŽƉŽƐĞĚtĞůů^ĐŚĞŵĂƚŝĐ 7HVW VOLFNOLQH OXEULFDWRU WR SVL 7HVW (OLQH OXEULFDWRU WR SVL EMP SVL # 79' VHH DWWDFKHG HPDLO IURP -DNH )ORUD EMP ŽĂĚĚƉĞƌĨŽƌĂƚŝŽŶƐƚŽƚŚĞdǇŽŶĞŬ'ϮĂŶĚ'Ϯ͕ĂŶĚƌĞͲ ƉĞƌĨŽƌĂƚĞƚŚĞdǇŽŶĞŬ'ϭ SVL EMP BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚďǇDϬϳͲϮϵͲϮϭ ^,Dd/ ĞĂǀĞƌƌĞĞŬhŶŝƚ tĞůů͗hϬϰZ ŽŵƉůĞƚĞĚ͗ϳͬϬϭͬϮϬϮϭ Wd͗ϮϭϵͲϬϭϭ W/͗ϱϬͲϭϯϯͲϮϬϮϯϵͲϬϭͲϬϬ :t>Zzd/> EŽ͘ĞƉƚŚ/K/ƚĞŵ ϭϴ͛ĂĐƚƵƐƚƵďŝŶŐŚĂŶŐĞƌ Ϯ͕ϰϰϲ͛'>Dηϭ;ůŝǀĞͿ ϰ͕ϯϵϮ͛'>DηϮ;ůŝǀĞͿ ϱ͕ϴϴϭ͛'>Dηϯ;ůŝǀĞͿ ϳ͕ϬϬϵ͛'>Dηϰ;ůŝǀĞͿ ϭ ϳ͕ϰϱϯ͛ŚĞŵŝĐĂůŝŶũĞĐƚŝŽŶŵĂŶĚƌĞů ϳ͕ϳϵϳ͛'>Dηϱ;ůŝǀĞͿ ϴ͕ϰϬϯ͛'>Dηϲ;ǀĂůǀĞͿ ϵ͕ϬϬϲ͛'>Dηϳ;ŽƌŝĨŝĐĞͿ ϵ͕ϲϬϳ͛'>Dηϴ;ĚƵŵŵǇͿ ϭϬ͕Ϯϭϯ͛'>Dηϵ;ĚƵŵŵǇͿ ϭϬ͕ϴϭϴ͛'>DηϭϬ;ĚƵŵŵǇͿ ϮϭϬ͕ϵϬϯ͛Ϯ͘ϴϭϯϰ͘ϯϬϬ^ůŝĚŝŶŐƐůĞĞǀĞ ϯϭϬ͕ϵϱϮ͛ϰ͘ϳϱϬϳ͘ϲϲϬϲ͟ĂŶĐŚŽƌůĂƚĐŚƐĞĂůĂƐƐĞŵďůǇŝŶƐŝĚĞϱ͟ƚŝĞďĂĐŬƐůĞĞǀĞ ϰϭϬ͕ϵϱϰ͛ϱ͘ϬϬϬϴ͘ϮϱϬϱ͘ϱǆϵ͘ϲϮϱ͟ϭϬŬΘ>ƉĞƌŵĂŶĞŶƚŚǇĚƌĂƵůŝĐƉĂĐŬĞƌ ϱϭϬ͕ϵϵϭ͛ϳ͟>ŝŶĞƌdŽƉWĂĐŬĞƌ;ďĞŚŝŶĚϱ͘ϱ͟ĨůƵƐŚũŽŝŶƚĐĂƐŝŶŐ Ϳ ϱ͘ϭϭϭ͕ϭϮϴ͛ϳ͘ϬϬϬϳ͟^ǁĞůůWĂĐŬĞƌ ϲϭϯ͕ϳϵϬϮ͘ϴϭϯϰ͘ϰϵϬϯ͘ϱ͟yEŝƉƉůĞ ϳϭϯ͕ϳϵϯϯ͘ϵϵϬϱ͘ϴϳϬϱ͘ϬϬ͟ϭϲĨƚ^ZǁƐŶĂƉůĂƚĐŚƐĞĂůďŽƌĞ 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)LVK#a¶ ´5+&SOXJERG\ XQWKUHDGHGIURP[ ORFNIHOOGRZQKROH ,WtΛ ϭϰ͕ϵϴϱ͛ʹϭϱ͕ϭϱϱ͛ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘ ƌŝĨƚ /dŽƉ ƚŵ ϮϬ͟ŽŶĚƵĐƚŽƌϵϰ,ͲϰϬEͬ^ƵƌĨĂĐĞϮϴϴ͛ ϭϯͲϯͬϴ͟^ƵƌĨĂĐĞϳϮEͲϴϬϭϮ͘ϰϭϱ^ƵƌĨĂĐĞϮ͕ϵϴϵ͛ ϵͲϱͬϴΗ WƌŽĚƵĐƚŝŽŶ ϰϳ ϱϯ͘ϱ EͲϴϬ͕^Ͳϵϱ WͲϭϭϬ ϴ͘ϲϴϭ ϴ͘ϱϯϱ ^ƵƌĨĂĐĞ ϵ͕ϵϯϴ͛ ϵ͕ϵϯϴ͛ ϭϮ͕ϱϮϭ͛ ϳΗ^'ϮϵWͲϭϭϬ/ͬdyWdϲ͘Ϭϱϵϭϭ͕ϭϬϬ͛ϭϱ͕ϭϵϯ͛ ϰͲϭͬϮΗ>ŝŶĞƌϭϮ͘ϲ>ͲϴϬtͬϯ͘ϴϯϯϭϰ͕ϵϳϰ͛ϭϲ͕ϲϬϳ͛ ^/E'ͬ>/EZWd,d/> ϱͲϭͬϮ͟WĂƚĐŚϮϯWͲϭϭϬ'K&:ϯϰ͘ϱϰϱϭϬ͕ϵϱϵ͛ϭϯ͕ϳϴϬ͛ dh/E'd/> ϯͲϭͬϮ͟dƵďŝŶŐϵ͘ϯWͲϭϭϬϴZhϮ͘ϴϲϳ^ƵƌĨĂĐĞϭϬ͕ϵϱϰ͛ ϯͲϭͬϮ͟dƵďŝŶŐϵ͘ϯWͲϭϭϬϴZhϮ͘ϴϲϳϭϯ͕ϯϮϬ͛ϭϰ͕ϵϳϴ͛ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚďǇ͗:>>ϬϯͬϭϬͬϮϮ WZKWK^ ĞĂǀĞƌƌĞĞŬhŶŝƚ tĞůů͗hϬϰZ ŽŵƉůĞƚĞĚ͗ϳͬϬϭͬϮϬϮϭ Wd͗ϮϭϵͲϬϭϭ W/͗ϱϬͲϭϯϯͲϮϬϮϯϵͲϬϭͲϬϬ :t>Zzd/> EŽ͘ ĞƉƚŚ / K /ƚĞŵ ϭϴ͛ ĂĐƚƵƐƚƵďŝŶŐŚĂŶŐĞƌ Ϯ͕ϰϰϲ͛ '>Dηϭ;ůŝǀĞͿ ϰ͕ϯϵϮ͛ '>DηϮ;ůŝǀĞͿ ϱ͕ϴϴϭ͛ '>Dηϯ;ůŝǀĞͿ ϳ͕ϬϬϵ͛ '>Dηϰ;ůŝǀĞͿ ϭ ϳ͕ϰϱϯ͛ ŚĞŵŝĐĂůŝŶũĞĐƚŝŽŶŵĂŶĚƌĞů ϳ͕ϳϵϳ͛ '>Dηϱ;ůŝǀĞͿ ϴ͕ϰϬϯ͛ '>Dηϲ;ǀĂůǀĞͿ ϵ͕ϬϬϲ͛ '>Dηϳ;ŽƌŝĨŝĐĞͿ ϵ͕ϲϬϳ͛ '>Dηϴ;ĚƵŵŵǇͿ ϭϬ͕Ϯϭϯ͛ '>Dηϵ;ĚƵŵŵǇͿ ϭϬ͕ϴϭϴ͛ '>DηϭϬ;ĚƵŵŵǇͿ Ϯ ϭϬ͕ϵϬϯ͛ Ϯ͘ϴϭϯ ϰ͘ϯϬϬ ^ůŝĚŝŶŐƐůĞĞǀĞ ϯ ϭϬ͕ϵϱϮ͛ ϰ͘ϳϱϬ ϳ͘ϲϲϬ ϲ͟ĂŶĐŚŽƌůĂƚĐŚƐĞĂůĂƐƐĞŵďůǇŝŶƐŝĚĞϱ͟ƚŝĞďĂĐŬƐůĞĞǀĞ ϰ ϭϬ͕ϵϱϰ͛ ϱ͘ϬϬϬ ϴ͘ϮϱϬ ϱ͘ϱǆϵ͘ϲϮϱ͟ϭϬŬΘ>ƉĞƌŵĂŶĞŶƚŚǇĚƌĂƵůŝĐƉĂĐŬĞƌ ϱ ϭϬ͕ϵϵϭ͛ ϳ͟>ŝŶĞƌdŽƉWĂĐŬĞƌ;ďĞŚŝŶĚϱ͘ϱ͟ĨůƵƐŚũŽŝŶƚĐĂƐŝŶŐͿ ϱ͘ϭ ϭϭ͕ϭϮϴ͛ ϳ͘ϬϬϬ ϳ͟^ǁĞůůWĂĐŬĞƌ ϲ ϭϯ͕ϳϵϬ Ϯ͘ϴϭϯ ϰ͘ϰϵϬ ϯ͘ϱ͟yEŝƉƉůĞ ϳ ϭϯ͕ϳϵϯ ϯ͘ϵϵϬ ϱ͘ϴϳϬ ϱ͘ϬϬ͟ϭϲĨƚ^ZǁƐŶĂƉůĂƚĐŚƐĞĂůďŽƌĞ ϴ ϭϯ͕ϴϬϵ ϯ͘ϵϵϬ ϱ͘ϴϳϱ ϰ͘ϱǆϳ͟ϭϬŬΘ>ƉĞƌŵĂŶĞŶƚŚǇĚƌĂƵůŝĐƉĂĐŬĞƌ ϵ ϭϯ͕ϴϱϮ Ϯ͘ϴϭϯ ϰ͘ϱϭϬ ϯ͘ϱ͟yEŝƉƉůĞ ϭϬ ϭϯ͕ϴϴϱ Ϯ͘ϵϵϮ ϯ͘ϲϱϰ ϱ͘ϵϬ͟KĨůƵƚĞĚŽǀĞƌƐŚŽƚ ϭϭ ϭϰ͕ϴϴϯ͛ ϰ͘ϬϬϬ ϲ͘ϬϬϬ ϱ͘ϬϬϬ͟ĂŶĐŚŽƌůĂƚĐŚǁϯ͛ƐĞĂůƐͬϱ͘ϬϬϬ͟^Z ϭϮ ϭϰ͕ϴϴϴ͛ ϰ͘ϬϬϬ ϱ͘ϴϳϱ dƌŝƉŽŝŶƚϳ͟ϮϲͲϯϮηWĞƌŵĂŶĞŶƚ>ŝŶĞƌdŽƉWĂĐŬĞƌ ϭϯ ϭϰ͕ϵϲϭ͛ Ϯ͘ϴϭϯ ϰ͘ϱϬϬ ϯ͘ϱyEŝƉƉůĞ ϭϰ ϭϰ͕ϵϳϯ͛ ϰ͘ϬϬϬ ϱ͘ϳϱϬ ϭϬ͛ĂŬĞƌ^ĞĂůŽƌĞǁŝƚŚƐĞĂůƐƌĞŵŽǀĞĚ ϭϱ ϭϰ͕ϵϳϰ͛ ϱ͘ϳϱϬ ϰͲϭͬϮ͟>ŝŶĞƌdŽƉWĂĐŬĞƌǁdŝĞďĂĐŬ^Z ϭϲ ϭϱ͕Ϭϲϳ͛ tĂƚĞƌ^ǁĞůůWĂĐŬĞƌ ϭϳ ϭϱ͕ϴϭϬ͛ /ŶƚĞƌǁĞůůϮϳϬͲϰϱϬ,W,dZWWůƵŐ;ϳͬϭϲͬϭϵͿ WZ&KZd/KEd/> ŽŶĞ dŽƉ;DͿ ƚŵ;DͿ dŽƉ;dsͿ ƚŵ;dsͿ ŵƚ ^ƚĂƚƵƐ ĂƚĞ dǇŽŶĞŬ'ϭ цϭϱ͕Ϯϭϲ цϭϱ͕Ϯϯϰ͛ цϭϰ͕ϰϭϵ͛ цϭϰ͕ϰϯϯ͛ цϭϴ͛ KƉĞŶ ZĞƉĞƌĨƐ ϳͬϭϳͬϮϬϭϵ WƌŽƉŽƐĞĚ dǇŽŶĞŬ'Ϯ цϭϱ͕ϲϬϬ͛ цϭϱ͕ϲϮϵ͛ цϭϰ͕ϳϯϰ͛ цϭϰ͕ϳϱϴ͛ цϮϵ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ dǇŽŶĞŬ'Ϯ цϭϱ͕ϲϴϴ͛ цϭϱ͕ϳϬϱ͛ цϭϰ͕ϴϬϳ͛ цϭϰ͕ϴϮϭ͛ цϭϳ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ ,ĞŵůŽĐŬ ϭϱ͕ϵϬϬ͛ ϭϱ͕ϵϯϯ͛ ϭϰ͕ϵϴϰ͛ ϭϱ͕Ϭϭϯ͛ ϯϯ͛ /ƐŽůĂƚĞĚǁͬƉůƵŐ ϳͬϭϲͬϮϬϭϵ ϳͬϭϭͬϮϬϭϵ tĞƐƚ&ŽƌĞůĂŶĚ ϭϲ͕ϰϬϴ͛ ϭϲ͕ϰϳϰ͛ ϭϱ͕ϰϯϬ͛ ϭϱ͕ϰϵϭ͛ ϲϲ͛ /ƐŽůĂƚĞĚǁͬƉůƵŐ ϳͬϭϲͬϮϬϭϵ ϳͬϬϮͬϮϬϭϵdсϭϲ͕ϲϰϮ͛;DͿͬdсϭϱ͕ϲϱϮ͛;dsͿ ϮϬ´ <ůĞǀ͗͘ϭϲϲ͘Ϯ͛ͬ&ͬ'>ůĞǀ͗͘ϭϰϴ͘Ϯ͛ ϳ͟dKΛϭϮ͕ϳϲϳ͛ ´72& ¶ Wdс ϭϱ͕ϴϭϬ͛ ;DͿ ͬWdсϭϰ͕ϵϬϵ͛ ;dsͿ ϭϯͲϯͬϴ͟ ϰͲϭͬϮ͟ +HPORFN :HVW)RUHODQGV ϳ͟Λϭϱ͕ϭϵϯ͛ ƚďŐƐƚƵďΛϭϯ͕ϴϴϴ͛ ϲͬϮϯͬϮϭ ϵͲϱͬϴdKtΛ ϭϭ͕ϯϱϲ͛ ^Λϭϰ͕ϵϮϲ͛;ϴͬϮϭͬϭϵͿ WyΛϭϰ͕ϵϲϭ͛;ϴͬϲͬϭϵͿ 7\RQHN*% ƚďŐƉƵŶĐŚ͗ϭϭ͕Ϭϭϴ͛ ůĞĂŬΛϭϭ͕ϬϮϭ͛ >ĞĂŬΛϭϭ͕ϬϮϭ͛ )LVK #a¶ ´5+&SOXJERG\ XQWKUHDGHGIURP[ ORFNIHOOGRZQKROH 7\RQHN*$ 7\RQHN*% ,WtΛ ϭϰ͕ϵϴϱ͛ʹϭϱ͕ϭϱϱ͛ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘ ƌŝĨƚ /dŽƉ ƚŵ ϮϬ͟ ŽŶĚƵĐƚŽƌ ϵϰ ,ͲϰϬ Eͬ ^ƵƌĨĂĐĞ Ϯϴϴ͛ ϭϯͲϯͬϴ͟ ^ƵƌĨĂĐĞ ϳϮ EͲϴϬ ϭϮ͘ϰϭϱ ^ƵƌĨĂĐĞ Ϯ͕ϵϴϵ͛ ϵͲϱͬϴΗ WƌŽĚƵĐƚŝŽŶ ϰϳ ϱϯ͘ϱ EͲϴϬ͕^Ͳϵϱ WͲϭϭϬ ϴ͘ϲϴϭ ϴ͘ϱϯϱ ^ƵƌĨĂĐĞ ϵ͕ϵϯϴ͛ ϵ͕ϵϯϴ͛ ϭϮ͕ϱϮϭ͛ ϳΗ ^' Ϯϵ WͲϭϭϬ /ͬdyWd ϲ͘Ϭϱϵ ϭϭ͕ϭϬϬ͛ ϭϱ͕ϭϵϯ͛ ϰͲϭͬϮΗ >ŝŶĞƌ ϭϮ͘ϲ >ͲϴϬ tͬ ϯ͘ϴϯϯ ϭϰ͕ϵϳϰ͛ ϭϲ͕ϲϬϳ͛ ^/E'ͬ>/EZWd,d/> ϱͲϭͬϮ͟ WĂƚĐŚ Ϯϯ WͲϭϭϬ 'K&:ϯ ϰ͘ϱϰϱ ϭϬ͕ϵϱϵ͛ ϭϯ͕ϳϴϬ͛ dh/E'd/> ϯͲϭͬϮ͟ 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Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Cement Squeeze/Casing Patch Development Exploratory 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 16,642 feet 15,810 feet true vertical 15,652 feet ~15,808 (fish) feet Effective Depth measured 15,810 feet 14974; 15067 feet true vertical 14,909 feet 10910; 10946; feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 3-1/2" 9.3# / P-110 10,954' MD 10,910' TVD Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3# / P-110 14,978' MD 14,230' TVD 10954 10991 11128 13809 10910 10946 11078 13359 Packers and SSSV (type, measured and true vertical depth)N/A 14888 1497415067 MD 14160 14227 14300 TVD N/A, N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 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: Taylor Wellman 777-8449 Contact Name:Jake Flora Authorized Title:Operations Manager Contact Email: Contact Phone:777-8442 11078; 13359; 14160; 14227; 14300 10954; 10991; 11128; 13809; 14888; 8,530psiLiner4,202'7"15,193'14,401'11,220psi WINJ WAG 0 Water-Bbl MD 288' 2,989' 16,607' 0 D&L Perm, Liner Top, Swell, D&L Perm, Liner Top; Liner Top, Swell Oil-Bbl measured true vertical Packer 9-5/8" 4-1/2" 12,521'12,357' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Beaver Creek Field / Beaver Creek Oil PoolN/A measured TVD Tubing Pressure 00 Beaver Creek Unit (BCU) 04RD N/A FEDA028083 Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-011 50-133-20239-01-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-056 & 321-235 507 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 417 Gas-Mcf 0 Authorized Signature with date: Authorized Name: 211 Casing Pressure Liner 1,633' 0 15,618' 0 Representative Daily Average Production or Injection Data 2,989' 12,521' Conductor Surface Intermediate Production 288' 7,500psi 4,760psi Casing Structural 20" 13-3/8" Length 5,380psi Collapse 2,670psi jflora@hilcorp.com Senior Engineer:Senior Res. Engineer: 8,430psi Burst 6,870psi 288' 2,989' t Fra O Ot 6. A G L PG , R h Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 9:57 am, Aug 03, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.08.03 09:43:15 -08'00' Taylor Wellman (2143) RBDMS HEW 8/5/2021 SFD 8/13/2021DSR-8/3/21BJM 10/13/21 Rig Start Date End Date 3/10/20 7/17/21 Accept rig f/ BCU-19RD t/ BCU-04RD AFE # 2020368 @ 0600 hrs. Continue thawing rig mats and cleaning and prepping equipment and set 5k dry hole tree on BCU-19 rd and test void t/ 250L 5 min and 5000h 15 min while prepping pad 4. Lay felt and liner on BCU 04RD. Transport clean rig mats to pad 4 and lay same. Set pony walls on BCU-04, spot cranes, transport and set sub base on pony walls, level and center sub over wellhead, transport and set carrier on sub, transport and set drill line spool and derrick on carrier, transport and stage doghouse, cont loading rig mats on pad 3, transport to pad 4. Finished setting remainder of rig mats around rig, rased & inspected derrick at half mast, loaded out, moved & set TD HPU, Gen building, pit modules 1-3, MP 1-2, boilers 1-2, doghouse/rig water tank, raised dog house, R/U electrical & utilities, installed wind walls around rig floor & centrifuge, R/U pop off, suction & discharge lines between pits and pumps, R/U electrical to dog house, swung over grasshopper from carrier to gen skid & grasshopper from MP to gen skid, R/U electrical for pits, hoppers, pumps, boilers, sub, derrick, & koomey, fired gen & turned on lights. Held PTSM, crew change, removed suction line air boot flanges from both MP skids for hammer seal installation, installed end caps on MP suction manifold, R/U jumper lines between modules for air, steam, & water, cont. running electrical & utility lines from gens to other modules, run Pason & misc. lines to choke, doghouse, & pits, checked all connection prior to energizing system, preheated boiler # 1-2 prior to adding water, R/U HYD lines to rotary table, iron roughneck, & test pump, installed brake linkage/driveshaft, hung misc. pit & rig floor tarps, R/U centrifuge spanners & tarp, R/U camera system, charged air system & beginning to spool on drill line, cont. to thaw remainder of rig mats for storage of mud product & misc. equip & clean up rig liner & felt at Pad #3 (BCU-19RD). 03/10/2020 - Tuesday Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 03/11/2020 - Wednesday Raise poorboy degasser, lay down and shim under skid to better line up service lines. Hang off BOP stack on bridge crane trollies in cellar. Spool drill line on drum. Cont hook up jumper lines between pit modules. Cont staging up boiler #1 pressure, start pre-heating boiler #2 with jet heater. Set stairs on pits, plug in pit lighting and heaters. RD all four trailers and transported Foremans/Push shacks to pad 4. Spotted same, tied in gen set, RU comm tower. Lay out felt and liner for catwalk, set gen 3 skid, ISO tank/trailer, mud lab and upright tank. Staged aux fuel tank back of rig. Received pump #1 engine parts. Set catwalk and lay out beaver slide. Set sleeper and safety trailers, set change shack and power up same. Welder on location at 16:00 hrs working on pit projects. Pollard e-line ran CBL on BCU-19RD, tagged bottom at 12,792' WLM, TOC at 4054'. Held PJSM, scoped up derrick, installed lower torque tube & T-bar, stage topdrive on catwalk and RU to PU same, installed TQ bushing to TQ tube, finished welding projects in pits, blew air through steam lines, opened steam to rig system, installed disks in steam traps, R/U Kelley hose & service loop to TD, hooked up TD HYD to derrick lines, shimmed up gas buster to line up to choke house, ran heater on TD HPU to start warming up, cont. staging up pressure in boiler #2, ran koomey lines into sub, ran electrical wires for iron roughneck HPU, hammered up suction lines between pump mods, installed MP suction screens. Held PTSM, crew change, inspected TD, installed wire tie on block pin bolts on compensators, brought boiler #2 on line, started working on rig acceptance check list, installed crown -o- matic pin on DRWK, R/U bales, link tilt cylinders, elevators, and tongs, hung felt across V-door & under DRWK motor, Hooked up power to TD HPU, fixed leak on HYD hose for TD extend. R/D shipping beams in sub, adjust load collar on TD, started filling water tank, function test both rig water pumps, installed bull plugs in mix pump snails, R/U stand pipe manifold & centrifuge. Hauled 0 bbls solids to KGF G&I. Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 03/12/2020 - Thursday Installed standpipe manifold on rig floor, RU centrifuge pump, hoses and control panel, function tested both rig water pumps, removed shipping pin and function tested iron roughneck (electric issue), function tested topdrive. MI Rep removed shipping blocks from centrifuge and test ran same. Held pre-spud meeting at Beaver Creek office with Area Op’s Manager, Op’s Engineer, field operators, service company Reps, both rig crews. Torqued up saver sub and installed clamp, Handy Berm bermed entire rig footprint, welder upgraded floor plate at pump room entrance and various other small projects, installed choke hose at choke house to cellar, C/O deadline sensor and calibrated hookload/blockheight with Pason Rep, Pacific Power Rep and rig mechanic changing nozzles and fuel unit pumps on pump #1 engine. Built containment and set aux fuel tank back of rig. Wellhead Rep came out and installed BPV in wellhead. ND tree and removed from cellar. Wellhead Rep installed 2 way check plug into BPV. Obtained measurements of blanking plug vs lower rams, installed acme x 8 rnd XO into hanger neck. Put 30 bbls water in pits, started circulating through charge pumps, equalizers etc checking for leaks. Hoisted BOP stack and set over wellhead, cleaned ring grove, installed BOP studs & new API ring, stabbed BOP on well head, began N/U BOP's, hooked up choke, kill, koomey lines to BOP stack, installed flow nipple adapter & catch can. Total Safety Rep installed gas alarms, lights, & tested (ok), Held PTSM, crew change, cont. working on N/U BOP's, chained off stack, installed flow line, pressure test & function tested accumulator & remote BOP control, cont. working on rig acceptance check list. Serviced rig, greased choke manifold & inside choke & kill manuals in prep for BOP testing, interlinked ground cables for rig modules, service shack, and grounded to conductor, drove ground rods and ran cable for offices buildings & sleeper, repaired iron roughneck E-stop button on drillers console, Brought 220 bbls of OBM into pits to warm up & start weighting up to 12.7 ppg, set up pipe rack on catwalk, cont.. working on cleaning up Pad #4 (BCU-19RD). Hauled 0 bbls solids to KGF G&I. Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 Cont RU and finish up rig acceptance checklist, install bolts in hammer seal adaptor on top of annular, obtained RKB’s, installed rig floor drain hoses, tie in gen 3 fuel/electric lines, cont assemble motor on pump #1, Removed wire rope sections of BOP hoists for replacements and ensured sheaves functioned, working on PM’s, checked OD and lengths of all spare saver subs, set liner and upright tank for OBM diesel, swapped out office gen set and replaced sleeper gen set, off loaded dry mud product and staged on mud docks, start lay out of hose/hardline for OBM transfer line from tank farm to pits. Rig mechanic and Pacific Power Rep cont assemble of pump engine #1. Stage 3 1/2" test joint and landing joint on catwalk. Stage 4 1/2" test joint on catwalk, checked OD's on both test jts. (ok), accepted rig @ 18:00 hrs., installed flow line nipple between flow box & adaptor flange on top of annular, performed shell test on BOP's (ok), attempted to blow down back through MP, discovered an ice plug in vibrating line from MP to sub, broke vibrating line & thawed out with steam whip, replaced E-stop on BOP hoist on ODS, mixed 56 bbls of 3% KCL brine. Held PTSM, crew change, Finished thawing vibrating line & re-connected, blew down TD & choke manifold, worked on cleaning & organizing around rig, removed snow from tank farm containment, cont. clean up at Pad #3, worked on rig PM's, installed secondary containment under ISO tank, started constructing secondary containment around diesel vertical tank, started pre-heating gen #3 w/ jet heater, checked & re-charged pulsation dampeners on both MP's, cont. to warm up 1st batch of OBM in pits. Hauled 0 bbls solids to KGF G&I. 03/13/2020 - Friday Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 Fired up gen 3 with no issues, cont cleaning/organizing throughout the rig, MU TIW and dart valves on 4 ½” test joint, MU blanking plug XO’s on test joint with wellhead Rep and set same, flooded stack and choke manifold. Obtained another good shell test. Commenced testing BOPE at 10:00 am. Testing at 250/4500 for 5/10 min (250/2500 on annular). Witness of testing was waived by AOGCC Rep Adam Earl at 10:00 hrs and BLM Rep Amanda Eagle at 13:38. Total Safety tested gas audio and visual alarms. Tested with 4 1/2" test joint, performed drawdown test. SIMOPS: Removed bad pulsation dampener bladder on #1 mud pump. Pacific Power Rep drove halfway to Anchorage and intercepted their engine diagnostic computer that kept getting bumped off flights to Kenai. Received load of diesel for mud treatment. Started mixing OBM to 12.7 ppg. Changed to 3 1/2" landing jt, M/U 4.5" XO 8 RD EUE x acme threads bxb, screwed into 4 1/2" blanking sub extension to hanger, tested low rams (tested ok), pulled & L/D 4.5" blanking sub, XO, & 3.5" landing jt. , P/U 3.5" test jt., made up to hanger & tested 3.5". Had welder on site to replace screen in body of pulsation dampener on MP #1, replaced bladder & charged w/ nitrogen to 500 psi (ok), installed heat trace & insulation on suction and high pressure discharge line on MP's, installed new battery in MP #1. Cont. testing 3.5" Held PTSM, crew change, finished testing BOP's w/ 3.5" test jt. R/D testing equip., pulled 2 way check & BPV, gave Weatherford 2 hr. notice, blew down choke manifold & TD, M/U XO to top of landing jt, screwed landing jt. into hanger, M/U TD to landing jt. BOLD's, drained stack, pulled hanger off seat, pulled 10.75" hanger through stack, P/U-64K, aired out MP's, MP #2 motor showed fuel leak shut off code & shut down, couldn't get MP #2 motor fired. Lined up hole to MP #1, started circulating STS, GPM-279 SPP-761 psi SPM-115, had max gas of 1204 units, staged Weatherford equip. on floor, changed oil in DRWK motor, cont. working on cleaning up Pad #3. Lined up MP #2 on the hole, circulated down hole & commissioned MP#2 (ok). Hauled 0 bbls solids to KGF G&I. 03/14/2020 - Saturday pulled hanger off seat, Started mixing OBM to 12.7 ppg. Commenced testing BOPE at s waived by AOGCC Rep Adam Earl a Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 Cont PU single in hole with BHA #1 on 4-½” DP from 1,474’ to 3,948'. Filling pipe every 2,500’. Got pump #2 up and running with no issues, replaced air boot in suction line between pumps and pits prior to exposing line to OBM. Mix and weight up OBM to 12.7 ppg. PU single in hole with BHA #1 on 4-½” DP from 3,948' to 7,672', cont filling every 2,500'. Repaired handrail on hopper room #3 roof top, continued to mix and weight up OBM to 12.7 ppg. Cleaning, inspecting and doping threads on DP, also checking box end lengths with jig to reduce chance of damaging dies on topdrive grabber or iron roughneck. Have culled 3 joints thus far. PU single in hole with BHA #1 on 4-½” DP from 7,672', tagged up CIBP @ 10,945', set 4K and verified tag. P/U & Kelley up. Finished 2nd batch of 12.7 ppg OBM & started on 3rd batch. filled pipe and broke circulation, circulated well w/ 3% KCL while working on 3rd batch of OBM. P/U-102 S/O-100 GPM-206 SPM- 105 SPP-169. Held PTSM, crew change, cont. circulating well w/ 3% KCL brine while reciprocating pipe, had max gas of 128 units, cont. building 3rd batch of 12.7 ppg OBM & housekeeping around the rig. Resumed working on cleaning up Pad #3. Resumed circulating & reciprocating pipe, cont. building 3rd batch of OBM, had centrifugal pump in hopper house #3 start leaking by secondary packing, changed out packing (ok), Hauled 5 bbls solids to KGF G&I. Pressure test mud line from mud pumps to topdrive at 4,500 psi, good test. Trouble shoot pump #2 coolant sensor (shutting down pump engine). Blow down topdrive, standpipe, mud line to pumps. Finish RU Weatherford tongs and handling equipment, held PJSM with rig crew and Weatherford Reps. Pull out of hole LD 3-1/2" EUE tubing. Vac'ing residual brine from joints prior to LD, installing thread protectors and racking on bunk trailers. POOH from 10,793' to 7,675'. Change out gun line charge pump in hopper room #1. Cont POOH LD tubing from 7675' to 2,585'. Cont POOH LD 3.5" 9.3# EUE kill string F/2,585'-T/surface. R/D Weatherford equip., cleared & cleaned floor for P/U BHA #1. Gave 2 hr. notice to Yellow Jacket Rep Neal Crandall. Rig service-greased DWKS, TD, blocks, crown, iron roughneck, inspected brake linkage & drive line. Finished 1st batch of 12.7 ppg OBM. Staged BHA #1 on catwalk, strap/tally BHA, got OD's & ID's, drained stack, P/U test jt. test plug, & wear ring, verified ID=9", installed wear ring, closed annulus valve, greased choke manifold & L/D test jt. & plug. Held PTSM, crew change, R/U Yellow Jacket handling equip. held PJSM w/ Company Rep, toolpusher, Yellow Jacket, & rig crew on P/U BHA, started working 2nd batch of 12.7 ppg OBM. P/U & RIH w/ BHA #1 w/ 8-3/8" roller cone bit, F/0-T/239', BHA dry weight=13K, changed over & R/U to 4.5" DP handling equip. Brought in DP, rack & tally, start P/U & singling in the hole w/ 4.5 DP F/239' to current depth of 1474', cleaning, inspecting, & re-doping threads, check tool joint length with jig to ensure we have at least 7” to fit grabber and roughneck dies. Cont. to work on 2nd batch of OBM. Hauled 2 bbls solids to KGF G&I. 03/16/2020 - Monday 03/15/2020 - Sunday Finished 1st batch of 12.7 ppg OBM. f Pull out of hole LD 3-1/2" EUE tubing. circulated well w/ 3% KCL while working on 3rd batch of OBM. & RIH w/ BHA #1 w/ 8-3/8" roller cone bit single in hole with BHA #1 on 4-½” DP from 7,672', tagged up CIBP @ 10,945', s t POOH LD tubing from 7675' to 2,585'. Cont POOH LD 3.5" 9.3# EUE kill string F/2,585'-T/surface. Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 03/17/2020 - Tuesday Cont circulating 3% brine while building OBM to 12.7 ppg in pits 9 and 10. 206 gpm-204 psi. Cleaned excess brine from pits 1 and 2, transferred OBM into those pits and started on another batch OBM in pits 9 and 10. Will have 967 bbls OBM to displace with, displacement volume = 743 bbls. Replaced rope packing in hopper #3 centrifugal pump, installed short mousehole on rig floor. Cont circulating while building OBM to 12.7 ppg in pits 9 and 10. Changed gear end oil in test pump and inspected crankcase for cause of noise with pump under pressure, took on 4,258 gals diesel in upright tank for mud treatment, received 2 trailers of mud product, backhauled 2 trailers of 3.5" tubing. Staged dragon boxes near cuttings/hurricane vac, for displacement. Cont circulating while building 4th batch of OBM to 12.7 ppg in pits 9 & 10, worked on snow removal around rig & housekeeping. sealed rig floor winch pockets. Held PTSM, crew change, cont. circulating while building 4th batch of OBM to 12.7 ppg in pits 9 & 10, called out 2 extra Peak vac trucks for OBM displacement. Finished building 4th batch of 12.7 ppg OBM, had extra Peak vac trucks on location & staged in position, held PJSM on displacement w/ mud man & rig crew. Line both MP's on the hole, began displacing well over to 12.7 ppg OBM, GPM-312 SPP-0, caught pressure after 444 bbls pumped away (FCP=1,300 psi). Cal Disp.- 742 bbls Act Disp.-754 bbls, shut down pumps, cleaned ditches & shakers, lined up MP's to circulate on hole to condition & sheer mud. Cont. working on building additional volume in premix tank ,while condition & sheer mud down hole. Hauled 0 bbls solids to KGF G&I. 03/18/2020 - Wednesday Cont to circulate and shear OBM at 332 gpm-1,475 psi, cont building additional OBM volume to allow using vacuum degasser in pit #4, cont hauling off remaining 3% brine to G&I. Pason Rep was called out to troubleshoot block height reading on Pason system. Everything checked out at ground level. Had derrickman go to crown to check alignment of sensor. Found sensor to be loose and out of alignment. Upon tightening unit he discovered fast line sheave was cracked around it’s shaft. Made notifications. Held PJSM, LD single, MU topdrive on stump and hung off blocks. Cont to circ, still building OBM surface volume, called out Peak crane and spare sheave from BA yard. Removed fast line from sheave, prepped sheave for pick off crown. Received trailer of barite, received 8,517 gals diesel in upright for mud additions. Spotted Peak crane, held PJSM, RU and picked fast line sheave off crown and landed same. Removed sheave from bracket, drilled holes and mounted encoder ring on new sheave. Mounted new sheave in bracket. craned bracket & new sheave to crown, reinstalled new fast line sheave, cont. weighting up 5th batch of OBM while circulating & conditioning mud in hole. Held PTSM, crew change, unhung blocks, installed secondary weight indicator, greased & commissioned fast line sheave, installed Pason depth sensor box on crown, cont. weighting up 5th batch of OBM while circulating & conditioning mud in hole. P/U single off walk, Kelly up, established drilling parameters, adjusted block height in Pason. P/U-96K S/O-98K ROT-96K TQ-4,150 Flow-23 GPM-333 SPP-1,595 psi RPM-80. Finished weighting up 5th batch of OBM, transferred OBM into active system for additional volume. & commissioning degasser, while cont. to circulating & conditioning OBM down hole. Hauled 0 bbls solids to KGF G&I. began displacing well over to 12.7 ppg OBM, Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 03/19/2020 - Thursday Obtained rotating parameters at 10,940’ while circulating at 327 gpm-1,522 psi, off bott torque 4,763 ft/lbs at 80 rpm. Discussed with Driller on plan of action if we have gas under the plug. Eased down and began drilling out CIBP from 10,945’. 5 to 15K wob, 80 rpm-4178 ft/lbs on bott torque, alternating pump rates and weight on bit. Drilled through plug, shut down and checked for flow, no flow. PU two singles and chased down with no sign of plug. Eased down tagging top of 7” liner lap at 10,991’ a couple times. Both rotating and not rotating. PU 5’ and CBU at 440 gpm-2,488 psi. 9,600 strokes we saw rubber on the shakers, 11,090 strokes bottoms up saw no gas and no apparent water contaminated mud. Shut down and flow check, well static. Pumped dry job while filling trip tank. Racked back one stand and blew down topdrive. POOH on elevators from 10,956' to 6,215' racking back on off-side. Up wt 100K no pumps. Used air to test OBM transfer line to tank farm at 30 psi. Cont POOH LD 40 joints (20 on each side of catwalk) from 6,215' to 5,004'. Cont POOH from 5,004' to BHA #1, racking back on drillers side. Hole fill Cal Disp.-78.2 bbls Act Disp.- 79.0 bbls Diff Disp.-.8 bbls L/D Yellow Jacket BHA #1, bit, bit sub, boot basket, magnets, recovered 40 lbs. of metal off magnets & boot basket, bit was in gauge, but had multiple broken teeth on cones & two slightly loose cones (see photos). Bit grade=3-2 (Not re-runnable). P/U & M/U Yellow Jacket BHA #2 w/ 6" roller cone bit, RIH F/0-T/263' Held PTSM, crew change, performed rig service, checked TQ (283 ft/lbs) & inspected bolts on fast line sheave bracket along w/ greasing sheave bearing, cleared & cleaned rig floor. Con. TIH F/263'-T/4,965', filling pipe every 2,500'. worked on R/U power washer to LVT ISO, cont. w/ housekeeping around rig. Began P/U singles off cat walk F/4,965' to current depth of 5,313'. Cal Disp.-91.5 bbls Act Disp.-90.26 bbls Diff Disp.- -1.25 bbls Hauled 0 bbls solids to KGF G&I. tagging top of 7” liner lap at 10,991’ began drilling out CIBP from 10,945’. M/U Yellow Jacket BHA #2 w/ 6" roller cone bit, Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 03/20/2020 - Friday Cont TIH from 5,313’ to 10,991’, filled pipe at 7,663'. MU topdrive at 10,991', eased down into 7” liner top and tagged up on CIBP at 10,992’. PU 5' and filled pipe. Up wt 90K, dwn wt 90K. Took on rig fuel. Peninsula Pumping sewer truck backed into sleeper trailer and caused slight damage to exterior metal siding corner. Notified HSE Rep Matt Hogge, obtained written statement from driver + photos. Both pumps at idle 209 gpm-568 psi, 30 rpm-2,597 ft/lbs off bott torque, eased down and engaged plug at 10,992', increased to 50 rpm-3,450 to 6000 ft/lbs on bott torque, drilled on CIBP alternating weight on bit with occasional PU and re-engage. Plug is inside the seal bore receptacle (7.41" ID), worked plug down to bottom of receptacle at 11,002' and had to cont drilling it up (transitioning to 6.20" ID), cont working plug down through and out the bottom of liner hanger at 11,018'. Plug hung up a little in the first two casing couplers and went away by 11,045'. PU and singled in hole 26 joints from 11,045' to 11,812' with no issue and MU topdrive. Up wt 96K, dwn wt 95K. Filled pipe then increased pump rate to 300 gpm-1,463 psi, 30 rpm-2560 ft/lbs off bott torque, BGG held steady at 16 units even at bottoms up. Saw some fluctuation with e-stab of OBM just prior to and at bottoms up, no slug of water. Had a couple good sized chunks of rubber at bottoms up. Circulated a total 20,000 strokes (surf to surf = 14,500 stks). Shut down pumps, flow check = static, pump dry job and blew down topdrive, installed new check valve in fill up line. POOH from 11,812' to 6,983', no issue pulling BHA up through liner hanger. Cont. POOH L/D singles F/6983'-T/6396' (19 jts.) P/U-70K S/O-70K Cal Disp.-36.8 bbls Act Disp.-37.6 bbls Diff Disp.-.8 bbls. Held PTSM, crew change, cont. POOH L/D singles F/6,396'-T/4,815' (Total L/D=70 jts.), cleared & cleaned rig floor. Resumed POOH racking back on DS F/4,815'-T/BHA #2. Currently cont. to L/D BHA #2, recoverd 10 lbs of metal from boot baskets & magnet, had calculated hole fill during entire trip. Hauled 0 bbls solids to KGF G&I. drilled on CIBP a Cont TIH from 5,313’ to 10,991’, eased down into 7” liner top and tagged up on CIBP at 10,992’. Plug is inside the seal bore receptacle (7.41" ID), worked plug down to bottom of receptacle at 11,002' and had to cont drillingf it up Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 Drained BOP stack, removed wear ring from wellhead, blew through choke and kill lines to remove any possible debris from drilling out CIBP, flushed stack with ported sub on joint and topdrive, LD joint and sub, blew down topdrive, drained stack again. RU test equipment, PU test joint and set test plug. Replaced hopper #3 charge pump. Flooded stack and surface lines, purged air. Obtained shell test on BOP stack. Tested BOPE at 250/4,500 for 5 min each (250/2,500 on annular). Performed draw down test. Total Safety tested audio and visual alarms, then calibrated sensors. Had fail/pass on choke line HCR, greased and cycled valve and re-tested ok. Witness of BOP testing was waived by both BLM and AOGCC on 3-20-20. Cleaned pits 9 and 10 for holding diesel at a later date. RD test equipment, blow down choke manifold, drain stack, installed wear ring, MU 2.85' long-3.826" ID mule shoe on 1st stand 4-1/2" DP and RIH, MU topdrive and roll mud pump to fill standpipe and Kelly hose, break off topdrive, MU test sub on topdrive, test Kelly hose connection down to 4" standpipe valve at 4,500 psi (broke connection to adjust hose), good test, blew down topdrive, shuffled 3 stands DC's in derrick. Cont TIH F/surface-T/4.587' from drill side of derrick. Cont. RIH F/4.587'-T/6.756', P/U 4.5" DP off racks. P/U-70K S/O-70K Pipe Disp. Cal Disp.-48.3 bbls Act Disp.-45.5 bbls Diff Disp.-2.8 bbls Moved drill collars to DS of derrick. Held PTSM, crew change,resumed RIH out of the derrick (ODS), F/6.756'-T/10,987', Pipe Disp. Cal Disp.- 70 bbls Act Disp.-67.4 bbls Diff Disp.-2.6 bbls Kelley up, CBU to warm up mud, cleared & cleaned rig floor. P/U-94K S/O- 94K GPM-320 SPP-1156 Flow-22. Greased choke manifold, worked on PM's. Call out Pollard E-line. Spaced out w/ a 15' & 10" pup w/ final set depth @ 10,989', shut in annular & staged pressure up to 445 psi on well and watched for 10 min (Pressure held). Bleed off pressure, currently R/U Pollard E-line unit. Hauled 7 bbls solids to KGF G&I. 03/21/2020 - Saturday MU 2.85' long-3.826" ID mule shoe on 1st stand 4-1/2" DP and Tested BOPE at 250/4,500 Witness of BOP testing was waived by both BLM and AOGCC on 3-20-20. Spaced out w/ a 15' & 10" pup w/ final set depth @ 10,989', s Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 03/22/2020 - Sunday Spotted e-line truck, laid out and built lubricator and tool string, installed TIW and 4-½” IF to CDS-40 XO on stump. Held PJSM with e-line crew, rig crew and DSM. PU and MU lubricator on drill string. RU test pump on lubricator pump in sub, closed TIW, flooded lubricator and tested same at 4500 psi, good test. Bled off and RD test pump. Started RIH with liner punch/CCL but set down at +/- 100’. Made numerous attempts to go deeper with no luck. RU high press 2” hose from mud line to lubricator pump in sub, broke circ at 3 bpm with no issue, e-line would not go down, staged up to 10 bpm while cont to lower tool string, would not go. Shut down pump, e-line Rep feels it’s a cable sizing issue in grease head. Pulled tool string back into lubricator, LD lubricator, attempted to pull wire through grease head, first 100’ was ok then pulled tight in same spot of cable. Cut off cable and re-headed. PU lubricator and tool string, MU on stump, re-tested lubricator at 4500 psi, good test. Received rig fuel. RIH with no issue to 11,100’ with 2-1/8" - 60° x 6 spf BH gun, logged through 7” hanger assembly couple times to identify components, created log and sent to town, called Op’s Engineer and discussed gun placement, got approval with top shot at 11,012’, bottom at 11,013’. Closed annular, pressured up on wellbore with pump #1 to 520 psi and punched liner. Pressure dropped slowly from 520 psi to 458 psi over 45 min. POOH with e-line. 454 casing pressure as we started pulling, at 2000' pressure was down to 271 psi. Bled off pressure, pulled tool string to surface and inside lubricator. Received diesel in upright for backflow and negative testing at a later date. Close TIW valve, broke off lubricator and LD, swapped out liner punch assembly for another assembly. PU lubricator and MU on stump, tested lubricator at 4500 psi, good test. RIH to 11,078' with 2-1/8" - 60° x 6 spf, logged up to pup joint just below liner hanger assembly, top shot at 11,018', bottom at 11,020'. Closed annular, pressured up on wellbore with pump #1 to 600 psi and punched liner. No pressure drop from 600 psi over 15 min. POOH with E-line, pulled tool string to surface and inside lubricator, closed TIW valve, broke off lubricator and LD, swapped out spent liner punch assembly for another assembly. PU lubricator and MU on stump, tested lubricator at 4,500 psi, good test. RIH to 11,065' w/ 2-1/8" - 0° x 6 spf, logged up to pup joint just below liner hanger assembly, top shot at 11,018.5', bottom at 11,020', closed annular, pressured up on wellbore with pump #1 to 507 psi and punched liner, pressure dropped slowly from 507 psi to 495 psi over 10 min. POOH with E-line, pulled tool string to surface and inside lubricator, closed TIW valve, broke off lubricator, L/D spent tubing punches, made call to town, decision was made to cont. ahead as per work over program, R/D Alaska E-line unit. Held PTSM, crew change, finished R/D E-line, Kelley up, CBU, performed rig service, & cleared & cleaned rig floor. GPM- 400 SPP-1,840 psi. Flow check (static), pumped slug, L/D 15' & 10' pups, blew down TD, began POOH rack back in derrick 4.5" on ODS F/10,964'-T/10,037'. Pipe started pulling wet, shut down, mixed & pumped 15 bbl slug 2 lbs over MW, blew down TD. Resumed POOH & racking back 4.5" DP F/10,037' to current depth of 7,501'. Getting calculated hole fill. Hauled 0 bbls solids to KGF G&I. got approval with top shot at 11,012’, bottom at 11,013’ punched liner. punched liner, top shot at 11,018', bottom at 11,020' top shot at 11,018.5', bottom at 11,020', c punched liner. Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 03/23/2020 - Monday POOH racking in derrick from 7,501’ to 6,758’. LD 70 joints from 6,758’ to 4,589’. POOH racking in derrick from 4,589’ to surface and LD mule shoe. Clean and clear rig floor, stage Halliburton retainer, spot e-line truck. RU e-line and MU CCL with setting tool and 7” LW Fas Drill SVB Squeeze Packer (max 5.80” tool OD and 42.54” long). RIH with retainer and CCL on e-line, sat down on something at 7" liner lap. Made numerous attempts to enter liner top with no luck, had no overpull. Notified Operations Engineer, decision made to make a magnet run, called out tools, gave YellowJacket heads up on various mills, POOH with e-line. Off line- serviced & functioned portable choke manifold & tested to 1,500 psi. LD tool string, removed retainer form run tool, MU magnet, centralizers, CCL and spang jars, RIH to 11,002', set down w/ magnet, couldn't pass through bottom of seal bore receptacle in the 7" liner hanger, attempted to work down magnet (no luck), POOH w/ magnet, had fines on magnet (see photos). Notified Operations Engineer & discussed options, made decision to make 2nd run w/ magnet, M/U magnet, spang jars, bow spring centralizers, & CCL, RIH w/ magnet, set down @ 11,002', worked magnet F/11,002'-T/10,991' multiple time, POOH w/ magnet, retrieved half piece of inner mandrel from CIBP, 8" L x 5" W (see photos). Started changing out mix pump motor in hopper house #1 L/D magnet, P/U & M/U junk basket w/ 5.8" OD/ gauge ring, bow spring centralizer, spang jars, & CCL to drift 7" liner hanger. RIH w/ 5.8" OD gauge ring F/surface-T/8,700' Held PTSM, crew change, cont. RIH w/ 5.8" gauge ring F/8,700' to top of 7" liner hanger @ 10,991', drifted through hanger T/11,020 w/ no issues, POOH L/D drift assembly. P/U & MU CCL with setting tool and 7” LW Fas Drill SVB Squeeze Packer (max 5.80” tool OD and 42.54” long), RIH to 11,012' w/ cmt retainer, set top slips @ 11,009'. Cont. working on changing out mix pump motor in hopper house #1, checked pulsation dampeners on MP 1 & 2, had to re-charge #2, cleaned out suction & discharge screens on MP 1 & 2. POOH w/ E-line, L/D cmt retainer running tools, R/D Alaska E-line equip., Held PJSM w/ rig crew & HES, P/U & M/U HES cmt stinger, started RIH w/ stinger on 4.5 DP, current depth of 2,363'. Hauled 0 bbls solids to KGF G&I. & MU CCL with setting tool and 7” LW Fas Drill SVB Squeeze Packer (max 5.80” tool OD and 42.54” long), RIH to 11,012' w/ cmt retainer, set top slips @ 11,009'. Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 03/24/2020 - Tuesday Cont TIH with cement stinger on DP from 2,363' to 4,596' out of derrick. PU and single in hole 70 joints DP from 4,596' to 6,766' and shuffle DC's in derrick. Cont TIH from derrick, from 6,766' to 10,972', just above 7" liner lap. MU topdrive. Calculated displacement = 70 bbls, actual displacement = 70.7 bbls. Up wt 95K, dwn wt 95K. CBU 1 time followed with a surface to surface to even out mud in wellbore and reduce weight back to 12.7 ppg with diesel on short active system (couple dry jobs in the hole). Load pit #9 with diesel for backflow, stage vac truck with diesel at pit #9, RU HP 2" circ hoses to portable choke to control backflow and/or u-tube of mud later. Shut down circ w/good 12.7 in/out. Installed gauge on 9-5/8" by 13-3/8" annulus. Retainer Rep on location, held PJSM, MU stand and topdrive, washed down with pump #2 at idle, 46 spm-90 gpm-211 psi. No issue entering liner top, eased down and at 11,008' saw pressure increase, shut down pump. Cont SO and set down 25K on retainer, marked pipe for space out, PU and LD single. PU 10' pup and MU TIW with pump in sub. Installed "T" and low torque valve on pump in sub. MU on stump, 5' pup on top w/topdrive. Lay out liner for cementers to park on, spot pump truck and two bulk trucks, stage Peak trucks, stage and adjust cement manifold on rig floor, tie in 2" HP hoses from manifold to choke, from choke to pits 9-10 for diesel returns later. Tie in hard line from choke to cuttings box. Hardline from manifold to pump in sub. Unsting from retainer and break circ with pump #2 (4-1/2" liners), swap to diesel and pumped 150 bbls down drill string at 81 spm-159 gpm-469 initial circ psi, 12% flow. Slack off sting into Retainer w/ 3,300 psi differential pressure, bleed off drill pipe 5.5 bbl bled back monitor well f/ flow back flowing 1.1 bph, shut in well. Monitor pressure build up on DP 150 psi in the first hour, built to 1,300 psi in the next hour slack off on drill string t/ 50k down wt. Open well flow back to pit 10, 10 bph avg flow rate 56.5 bbl total flowed back. 03/25/2020 - Wednesday Monitor flow back to pit "pre-mix #2". At 06:00 had total 56.5 bbls diesel back with average of 4.4 bph. At 07:00 had total 66.3 bbls diesel back with average of 6 bph. Notified Operations Engineer, decision made to shut in and monitor pressure build for two hours. Pressure built from 0 psi to 1,200 psi over 30 minutes. and stabilized monitor same Resume flow back of diesel to a total of 92 bbls w/ high of 12.6 bph and low of 9.6 discuss options with town Shut in and monitor pressure build up t/ 1,200 psi in 45 min and monitored stabilized 1,200 psi for 15 min. Resumed flow back of diesel @ 11 bph high and 9.6 bph low to a total of 127 bbls shut in for 15 min w/ stabilized pressure build up t/ 850 psi. Resumed recovered total 147 bbl of 6.9 diesel. Then we had weight change to 7.2 , 7.3 and 8.3 ppg and slight color change diverted returns to cutting box and tested returns w/ 3,300 chlorides. Shut in well pressure built t/ 750 psi and stabilized, attempt to establish injection rate w/ the test pump, Pressure up t/ 3,600 psi pressure holding, not leaking off, Monitor pressure f 1 hr discuss options w/ town, pressure dropped t/ 3,400 psi in 2 hrs. Bleed off Dp t/ 2,000 psi pulled out of cement retainer 2,550 psi differential on the gauge, allowed DP to U-tube filling the back side w/ the mud controlling rate w/ choke. Line up and circulate surface to surface 220 gpm 750 psi 364 units of gas seen on bottoms up, M/W even 12.8 ppg shut down pumps, Pump dry job blow down top drive R/D Circulating lines and break off side entry sub TIW and pup jts L/D P/U Single in string Slip and Cut Drilling line. Unsting from retainer and break circ with pump #2 (4-1/2" liners), swap to diesel and pumped 150 bbls down drill string a d 8.3 ppg and slight color change diverted returns to cutting box and tested returns w/ 3,300 chlorides. Shut in well pressure built t/ 750 psi and stabilized, a one-way leak. Resume flow back of diesel to a total of 92 bbls w/ high of 12.6 bph and low of 9.6 df monitor pressure build up t/ 1,200 psi in 45 min and monitored stabilized 1,200 psi for 15 min. Shut down circ w/good 12.7 in/out. Open well flow back to pit 10, 10 bph avg flow rate 56.5 bbl total flowed back. No issue entering liner top, eased down and at 11,008' s M/W even 12.8 ppg s Monitor pressure build up on DP 150 psi in the first hour, built to 1,300 psi in the next hour s mpt to establish injection rate w/ the test pump, Pressure up t/ 3,600 psi pressure holding, not leaking off, Monitor pressure f 1 hr discuss options w/ town, pressure dropped t/ 3,400 psi in 2 hrs. Slack off sting into Retainer w bleed off drill pipe 5.5 bbl bled back monitor well f/ flow back flowing 1.1 bph, shut in well. Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 12/27/2020 - Sunday Operations Engineer developing a revised workover plan. Clear floor brk dn Tools Pull wear ring and set test plug w/ 3-1/2" test jt. fill stack and purge air & r/up test equipment Test Annular 250L/2,500H 5/10 min and test both sets VBR rams 250L/4,500 high 5/10 min on chart all test good. R/dn test equipment PJSM and r/up weatherford equipment P/up rabbit and strap rih w/ 3-1/2" 9.2# L-80 EUE Tbg Kill string as per drillers running tally and hung off on Tri point JS3A retrievable prk w/ storm valve @ 31.44' below Lock down screws Test above prk w/ diesel t/ 2,500 >2,300 psi and flat lined for 15 min on chart Back out of storm leaving mule shoe @ 3,350' and 3-1/2" if box top of storm valve @ 31.44' below LDS w/ dart pinned for 1,000 psi sheer. l/dn 2 jts of 4- 1/2" dp and running tool Flush all lines w/ soap pill, finish cleaning pits, remove all handling equipment f/ rig floor, cleaning pits and around rig. N/D kill and choke hoses, remove flow line and riser, remove flow box, N/D stack release rig t/ CLU-15 @ 2400hrs. 03/26/2020 - Thursday Continue Slip and Cut 60' Drilling line L/dn drill pipe cleaning ID and OD and servicing threads and transferring OBM to tank farm Service rig grease blocks, TDS, DWS, IR and adjust brakes and Clean ID of dp, flush and clean pits of OBM continue transferring OBM to upright tank farm. Continue POOH L/D DP f/ 5,280' t/surface cleaning ID and OD and servicing threads, L/D cement stinger. RIH W/ Drill collars f/ derrick POOH L/D, RIH w/ remaining DP f/ Derrick L/D and sucking wiper balls through pipe till clean, continue cleaning pits and transferring fluid to upright tanks, clear floor, P/U and break down jar and magnet jt. 03/27/2020 - Friday 06/02/2021 - Wednesday Both crews toured rig to see upgrades/changes, held PJSM, sent one crew to BCU-04 to lay felt, liner and mats, second crew began securing rig modules for tear out. Ran string line at BCU-04, rolled out felt and liner, returned first crew to CCI yard to assist RD and tear out. Cont to set rig mats on BCU-04. Tore out backyard of rig and staged for transport, shipped catwalk and topdrive HPU to field. Finished lay out of rig mats at BCU-04 and returned to CCI yard, layed derrick over and prepped for removal, spot cranes, removed derrick house and LD windwalls, RU and picked derrick off carrier, set on trailer, welder tacked bolster pockets to bolsters with derrick aligned for transport, shipped mud pump #1 to field, RU and removed carrier from sub base, transported derrick and water tank/doghouse to field, RU and removed sub from pony walls. Transported pits #2 and 3 to field. N/D stack release rig t/ CLU-15 @ 2400hrs. Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 Installed torque bushing on torque tube, pinned topdrive to blocks and torque bushing, RU office comm’s up, CO topdrive gooseneck, RU camera system, started dressing mud pumps, rig electrician troubleshooting electrical issue on sleeper trailer. Handy Bermed entire rig footprint, took on 3,505 gals rig fuel, staged mud product on mud dock, shimmed torque bushing to level topdrive, installed hardline from choke manifold to shakers and bluie line, offload water into pits for checking fluid paths and pumps, RU Pason system throughout the rig and office trailers, bermed in upright water tank on pad 5, installed saver sub, installed 6" jumper line from pit 3 to pit 2. Notified AOGCC for upcoming BOP test. Continue rigging up Pason systems, super choke seized up rebuild valve, continue dressing mud pumps, rolling water through pits checking for leaks and proper fuction, R/U rig floor handling equipment, nipple up bag and double gate in cellar tighten bolts, make up yoke between bag and double gate to pick stack. Contnue stacking BOP components, and tighten all flanges, finish dressing pumps, continue hooking up pits systems and function testing, work on rig acceptance checklist. organize location and connexes, Quadco Installing gas detection equipment. 06/03/2021 - Thursday Crews started PU stacking rig mats at CCI yard and cleaning up liner for disposal. Prepped office trailers for transport to field. Sent one crew to BCU-04 to set pony walls in prep for sub base. Obtained permit to transport sub at 09:00, shipped sub, pit #1 and change shack to field along with rig crew. Held PJSM on location with both rig crews, CCI crew, drill Foremen and HSE Rep John Coston. Spotted cranes, set sub base on pony walls and centered up over well, set carrier on sub. Staged derrick, set same on carrier, installed raising rams, transferred drill line spool to carrier. Flew iron roughneck to floor, raised "V" door wall, raised derrick windwalls and set derrick house, set pit #1 and raised roof, set choke house, raised mast. Set water tank/dog house and raised same, set pit/pump jig in place, set mud pump #1, set mud pump #2, set topdrive HPU, set office trailer and push shack, set. boiler skid, set gen 1-2 skid, set pit #2, set centrifuge feed pump and centrifuge, set pit #3, staged bang box and gen set for office trailers, set sleeper trailer and meeting room, set in mechanics shop and change shack, spot generator and power up. Layed out felt and liner for catwalk, set poorboy degasser skid, powered up foreman's and push shacks, could not get comm's, spot in catwalk and raise beaver slide, cut and spool up drilling line prep to raise derrick, continue hooking up modules and rig components, spot in mud lab and gen 3, spot diesel storage tank. Continue rigging up prep to scope derrick, hook up flare and vent lines and stand poorboy degasser, perform derrick inspection, hook up top drive rail and scope derrick up into position, rig up and prep to p/u top drive. Continue rigging up modules hooking up power air hydraulics and mud lines, organize locations. 06/04/2021- Friday Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 06/05/2021 - Saturday Cont to assemble BOP stack in cellar, Quadco Rep finished installing audio/visual gas alarms and tested same, test ran test pump in choke house, moved water from pit to pit to verify PVT's and gain/loss alarms working, ran mud pumps moving water through bleeders and pop off lines, RU geronimo line and anchor block, dressed derrick board with ropes, installed rebuilt auto choke on choke manifold and function tested OK, installed hyd fittings on BOP stack, opened doors and installed rams, started transport and offload of gel mud into pits 9-10, checked on status of Baker tools coming from slope (have not left slope yet), cont rig acceptance checklist. Buttoned up ram doors on stack, installed shaker screens, removed shipping beams in cellar, staged spill connex for easy access, installed windsock on skate house, re-installed Handy Berm near cellar entrance, removed shipping blocks from centrifuge and test ran same along with feed pump, tested rig ESD system, verified 0 psi on well, removed tree cap and topped off with 10 gals diesel, replaced tree cap and RU to test. Accepted rig at 16:00 hrs on 6-5-21. Tested 9.625" annulus and top of storm packer at 500 psi for 15 min on chart, good test, bled off and RD test equipment. ND dry hole tree, pick off wellhead and staged in cellar under mezz deck. Began mixing barite into gel mud. Install test plug in bowl, hoist 11" BOP stack and stab on wellhead, NU BOP's, obtained RKB's, N/U choke and kill lines, N/U flow box and flow line. Function test rams and HCR's, had lines swapped around fix lines, P/U test jt and R/U t/ test, continue mixing mud. Fill stack and lines with water, grease choke manifold and BOP valves, test mud lines 2,850 psi 4'' valve on mud pump #1 leaking, grease and retest leaking same, M/U TIW and Dart to test JT. Rebuild valve and test same, S pipe leaking on rig floor, 2'' 1502 leaking in pump room tighten and retest s pipe still leaking on the rig floor, remove S pipe and change gaskets, tighten back up and retest same. 06/06/2021 - Sunday Installed 4-1/2" test joint in stack, flooded stack and surface lines, attempt shell test, chased numerous leaks, were able to get with AOGCC Rep Matt Herrera and set up to witness BOP testing at 14:00 hrs. CCI reps rolled OBM upright tanks 1 and 2 with no issues, transferred tank #1 into 2 and 4 to make room for upcoming OBM displacement. Cont mixing barite in pits to give us 12.5 ppg water based mud. Cont mixing mud and chasing leaks, circulated water through choke manifold to flush manifold out using pill pit. Obtained good sh ell test to 5,000 psi. Quadco Rep on location at 13:00 hrs, AOGCC Rep on location at 13:45 hrs. Tested all audio/visual alarms with no issues and released Quadco Rep, began testing BOPE at 250 low, 5000 high (as per AOGCC Rep) for 5 min each. Had 3 F/P on manual inside kill valve, greased and cycled, re-tested good, Annular on 3 1/2'' Function the bag and retested good, HCR choke low pressure test wouldn't hold, replace HCR and retest breaks and valve tested good, perform Accumulator drawdown test and test PVT alarm. R/D BOP test equipment R/U and test stand pipe leaking connections change 2 seals and tighten and retest good, blow down lines and set wear ring, get equipment to floor to pull storm packer. M/U retrieval tool, and cross over to DP. RIH M/U retrieval tool 8 turns M/U TIW, turn to more turns and open By Pass fluid level dropped to packer, fill hole with trip tank took 2.5 bbls to fill hole, P/U on packer 5' 48k hook load, Allow packer elements to relax f/ 30 min, PJSM on pulling tubing with Weatherford, L/D TIW and jt of DP, soft break packer components and L/D storm Packer. began testing BOPE at 250 low, 5000 high (as per AOGCC Rep) f P/U on packer 5' 48k hook load, Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 06/07/2021 - Monday Break down and LD storm packer, catcher sub and storm valve, lost 1-1/4" x 1-1/4" collar slip die segment in hole. RU Weatherford tongs and handling equipment for 3-1/2" tubing, PU 10' and pulled bushings, found collar slip die laying in drip pan, retrieved same. POOH LD 3-1/2" P110 EUE tubing from 3,300' to 1,641'. Pulling vac on joints on rig floor, then CCI pulling wiper balls through joints on pipe rack to clean up residual OBM. At 1,641' stabbed TIW and closed upper rams, shut down for pre-ops meeting at Beaver Creek office. Rig mechanic and electrician watching rig. Held pre-op's meeting with rig team and Anchorage team on upcoming well work. Fresh crew on tour, opened rams and removed TIW, cont POOH LD 3-1/2" tubing from 1,641' to surface, LD mule shoe. RD Weatherford equipment and released Rep, clean rig floor, Baker tools arrived to location at 15:30 and offloaded same, Baker Rep on location at 16:30, cont mixing mud to 12.5 ppg, removed tubing trailer from location, brought in bunks CDS-40 DP, rack and tally 200 jts, flag Baker tools for first run. Bring components to rig floor, M/U Junk baskets and magnet w/ 6'' bit. Single in the hole w/ 4.5'' DP f/ 48' t/3,763. Empty trip tank and service rig. Continue RIH P/U 4.5'' DP f/ 3,763' t/ 5,117'. 06/08/2021 - Tuesday Cont PU single in hole with CDS-40 DP and BHA #1 from 5,117' to 8,404'. Getting good amount of back flow up drill string, shut down at 8,404' and MU topdrive. Circulated down drill string staging pump rate up to 81 spm-270 gpm-1,050 psi, cont to rack and tally DP, had wellsite visit and walk through with HSE Rep Carl Jones. Had a max of 14.0 ppg returns at bottoms up with 40 units gas reading on Pason gas trap. Cont to circ until 13+ ppg going in, 13 ppg out, shut down and broke off topdrive, drill string on vac. Cont PU single in hole with CDS-40 DP from 8,404', dwn wt 145K, cont MU and break out 3 times any DP with blue bands (re-cuts) cleaning threads and re-doping, going to half torque on first MU. Singled in hole to 10,568' and seeing drill string taking weight during slack off. At 10,568' up wt 160K, dwn wt 145K. MU topdrive and staged pump rate up to 90 spm-262 gom, 1,230 psi, rotated at 23 rpm-1,468 ft/lbs torque, 25% return flow. Had a max of 15.8 ppg at bottoms up. Just prior to bottoms up mud was thick, thinned right out and got heavy at bottoms up, max of 91 units gas. Cont to circ until we had 13.5 ppg in, 13 ppg out, shut down broke off topdrive, drill string on vac. Up wt 175K, dwn wt 165K, cont single in hole from 10,568' to 10,631' and string started taking weight, down weight at 145K, MU topdrive and slowly washed/reamed down from 10,631' to 10,664'. RIH one single to 10,695', PU next single and MU topdrive, attempted to wash/ream joint down but had no pump pressure on either pump, have good return flow, suspect washout. Pulled up hole on elevators from 10,695' to 10,409', up wt 165K. MU topdrive and idled pump, good returns, 0 psi pump pressure. Cont . POOH racking back in derrick from 10,409' to 8,559' while cont. to establish pump pressure with no luck. Called town and discussed options, made decision to pump string volume at idle (3.2 bpm), caught pressure 90 bbls away into a 117 bbl string volume, finished circ. string volume, GPM-137 SPP-144 psi, brought pump to GPM-272 SPP-855 psi, called town and made decision to TIH. Held PTSM, crew change. Cont. singling in the hole F/8,559'-T/10,320' P/U-172K S/O-174K. Cont. RIH out of derrick F/10,320'-T/10,724', started losing string weight while tripping ( barite fall out). Started washing & reaming stands to bottom F/10,724'-T/10,744', currently circ. to keep mud from U-tubing out of the pipe. GPM-268 SPP-1045 psi RPM-25 TQ-1450 P/U-170K S/O-173K ROT-168K. POOH LD 3-1/2" P110 EUE tubing f t POOH LD 3-1/2" tubing from 1,641'to surface, circ until we had 13.5 ppg in, 13 ppg out, Cont to circ until 13+ ppg going in, 13 ppg out, had wellsite visit and walk through with HSE Rep Carl Jones. Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 Washed and reamed down with stands from 10,744’ to 10,999’, 88 spm-257 gpm-828 psi, 20 rpm-1,800 to 2,100 ft/lbs torque. Did not see any indication of 7" liner top at 10,991'. PU kelly joint and MU topdrive, checked depth at crack, washed down and tagged plug at 11,013', PU 5' off plug and parked string. Circulated at 93 spm-273 gpm-1,363 psi. Initial MW 12.0 in/11.9 out, had a max of 47 units gas at bottoms up and MW evened out at 12.1 in/12.1+ out, pump pressure down to 637 units. Held PJSM with rig team and drivers on displacement, shut down pump, lined up on choke, choke manifold to frac tank and closed annular. Displaced well to 12.5 ppg water based mud, staged up to 100 spm-293 gpm-1,581 psi. CCI transferred 3 loads to tank farm from frac tank with vac truck during circ. Once hole displaced shut down pump, opened annular, closed choke HCR and cont to circ down flow line, 60 spm-177 gpm-795 psi. Offloaded 30+ bbls gel mud from G&I onto pit 10 and started weight up of that, and dusting up active volume to maintain 12.5 ppg. Had rig site visit and walk through with HSE Reps John Coston and Jacob Nordwall with no issues. Blew down choke manifold and vac'd out 2" HP hose to frac tank. Cont to increase pump rate as shaker would allow to 93 spm-273 gpm- 1,125 psi. With good 12.5 in/out shut down and obtained SPR's. Up wt 180K, down wt 168K, 4,600 ft/lbs off bottom torque at 80 rpm with new mud in hole. Shut down pump, LD Kelley joint and latched up stand. S/O pumping/rotating and tagged plug at 11,013’, Started drilling plug at 80 spm-256 gpm-1,103 psi, 84 rpm-4,400 ft/lbs torque, wob 2.5K, MW 12.5/vis 72. Drilled on plug approximately 30 min and it broke loose. Cont wash and ream down hole, initially occasionally setting down on plug to 11,369'. Saw no sign of plug for a couple stands, TIH on elevators to 11,803' and string started taking weight. Resumed washing reaming. from 11,803', fill got hard at 11,822' and seeing 4 to 7K weight on bit for a couple hundred feet. 96 spm-281 gpm-1,712 psi, 84 rpm-4,457 ft/lbs on bott torque, max gas 75 units. Brought in more water to pit #9 to build more volume. Cont. washing & reaming F/11,822'-T/12,145' P/U-180K S/O- 183K ROT-175K GPM-263 SPP-1,305 psi WOB 5-7K TQ-4.8K , at 12,145' we hit a hard spot and stopped washing off, lower to 176 GPM and slowed rotary to 25 RPM's, set 3K down on hard spot and started seeing small TQ spikes started drilling off F/12,145'-T/12,147' were it fell right through. Cont. washing & reaming down F/12,147'-T/12,486', P/U-203K S/O-175K ROT-185K GPM-243 SPP-1,500 psi WOB 7-10K TQ-10K RPM-52, circ. and worked pipe, shut down pump, performed flow check (static). Held PTSM, crew change. POOH and rack back in derrick F/12,486-T/12,177', had calculated hole fill, flow check (static). P/U-203K S/O-175K ROT-185K, flow check (static). Cont. building new batch of 12.5 ppg mud in reserve pit to increase active volume. P/U & RIH w/ 10 singles F/12,177'- T/12,489', had calculated pipe displacement. P/U-203K S/O-175K ROT-190K. Resumed washing & reaming F/12,489' to current depth of 12,736'. P/U-205K S/O-175K ROT-190K GPM-275 SPP-1660 psi WOB 5-7K TQ-4-7K RPM-30. Hauled 4 bbls of solids to KGF G&I Cumulative: 4 bbls Hauled 81 bbls of fluid to KGF G&I Cumulative: 146 bbls 06/09/2021 - Wednesday & reaming down F/12,147'-T/12,486', Started drilling plug at 811,013’, Displaced well to 12.5 ppg water based mud, Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 06/10/2021 - Thursday Cont to wash and ream down to 12,748' at 47 spm-137 gpm-818 psi, 30 rpm-4,200 ft/lbs on bott torque, wob 10K. Up wt 215K, down wt 195K. Shut down pump, rotated at 20 rpm-3600 to 4,800 ft/lbs on bott torque, dry drilled on top of sand buffer to 12,753', PU with pump on, shut down pump, eased down to 12,755' no rotary and set down 17K, PU then S/O rotating to 12,755' as per Baker Rep. Racked one stand back and CBU at 91 spm-266 gpm-1,408 psi, 21 rpm-2625 ft/lbs off bott torque, reciprocated pipe slowly. Had a max of 34 units gas at bottoms up. After bottoms up obtained SPR's, flow check was static, then blew down topdrive and mudline. POOH racking 77 stands back on offside, up wt 210K, from 12,731' to 8,436'. Spun elevators and held PJSM, LD 104 joints DP and staged on drillers side pipe rack. CCI vacuuming wiper balls and installing thread protectors. Tied in centrifuge to frac tank and test ran that 2 hours. Mixed & pumped 20 bbl dry job 1 lb over MW. Cont .POOH racking back in derrick F/7,111'-T/566', crew held trip drill at 6,498'. Cont. spinning out MW from OBM in frac tank. Held PTSM, crew change, Cont. POOH F/566' to BHA #1, Cal Disp. = 35.08 bbls Act Disp. = 32.74 bbls Diff = 2.34 bbls. Broke out 6" bit , cleaned Baker extrema magnet, and boot baskets, recovered 6lbs of metal fines & chunks from magnet/boot baskets (see photos), L/D Baker extrema magnet and pump out sub. Cleaned rig floor, P/U BHA #2- Baker RCJB, double pin, 3 boot baskets, bit sub, oil jars, and XO. TIH F/BHA #2- T/3,020', M/U TDS, broke circ. to break gel strengths. P/U-60K S/O-60K GPM-146 SPP-271 Blew down TDS. Cont. TIH out of the derrick F/3,020'-T/4,808', Hung blocks and current slip & cut drill line. Cont. to centrifuge back MW of OBM in frac tank. Hauled 49 bbls of solids to KGF G&I. Cumulative: 53 bbls. Hauled 61 bbls of fluid to KGF G&I. Cumulative: 207 bbls. Daily Metal: 6 lbs. Cumulative: 6 lbs. dry drilled on top of sand buffer to 12,753', Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 06/11/2021- Friday Finished up cut and slip of drill line at 4,808’, inspected derrick, checked crown saver, recalibrated hookload, serviced rig and topdrive. Cont centrifuging OBM in frac tank. PU and singled in hole with 104 jnts CDS-40 DP to 8,004’. MU topdrive and CBU at 63 spm-184 gpm-565 psi. Received rig fuel. Resumed TIH out of derrick from 8,004’ to 10,872'. Sent in BOP test notification for Monday the 14th, witness waived by AOGCC Rep Jim Regg at 14:03 on 6-11-21. Just above 7" liner top (10,991') circulated to condition mud prior to entering 7" liner at 61 spm-178 gpm-731 psi, up wt 177K, dwn wt 174K. Baker Rep on location. Cont to TIH from derrick, saw nothing entering 7" liner top, Getting back flow out top of drill string with stands half way down, S/O slow. At 12,667' MU topdrive and washed stand down slow to 12,730' (top of sand at 12,755'), pumping at 113 spm-334 gpm-2,307 psi, down wt 185K. Broke off topdrive, Baker Rep dropped 7/8" ball down drill string, made up last stand and topdrive. Pumped ball down at 108 spm-317 gpm-2,051 psi. for 1,500 strokes, then slowed pump rate to 55 spm-160 gpm-936 psi to seat the ball in reverse junk basket, rotated at 10 rpm- 2,860 to 3,400 ft/lbs off bottom torque. Cont centrifuging OBM in frac tank, MW in to centrifuge 12.7 ppg, MW coming out 8.4 ppg. Shut down pump, used 5' stick to tag depth at 12,759', P/U and kicked in MP-GPM-324 SPP-2,422 psi TQ-3K RPM-10. Began washing/reaming down with RCJB running GPM-324 SPP-2,480 psi 5-10K WOB TQ-3-7K F/12,759', walked rotary up to 60 RPM to smooth out TQ, cont. washing/reaming T/12,768' were is started stacking weight and not drilling off. SPP pressure increased from 2,400 psi to 2,950 psi (due to junk basket being full). Made multiple attempts to get it to wash/drill off, called town engineer and made decision to POOH and empty RCJB and boot baskets. Shut down MP, flow check (static), POOH and racked back 11 stds, pipe was pulling wet, mixed and pumped 20 bbl dry job 1.5 lbs over MW, Cont. POOH F/12,046'-8,029' racking back in the derrick 77 stds. Off line changed liners/swabs in MP #1 to 5" and MP #2 to 4.5". Cont. centrifuging OBM in frac tank. and rolled 12.5 ppg OBM in tank farm to keep barite from settling for 2 hrs. Held PTSM, crew change. Started L/D singles F/8,029'-T/4,837' while having CCI vacuuming wiper balls through and reinstalling thread protector on pipe. Resumed POOH racking back in the derrick F/4,837'-T/surface. Currently working on breaking out RCJB and boot baskets from BHA #2 at report time. Hauled 75 bbls of solids to KGF G&I Cumulative: 128 bbls. Hauled 75 bbls of fluid to KGF G&I. Cumulative: 282 bbls. Daily Metal: 15 lbs. Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 06/12/2021 - Saturday Finished cleanout of out RCJB assembly and recovered 2 lbs metal chunks. Re-assembled BHA leaving ball on seat for trip in hole. Serviced rig and topdrive, greased crown, checked driveline bolts, checked and cleaned mud pump suction and discharge screens, checked pulsation dampeners. TIH from 39' to 4800' 77 stands. PU single in hole 104 jnts from 4800' to 8028'. Start transferring 340 bbls of 8.7 ppg OBM from frac tank to upright tank farm. Circulate to condition mud at 92 spm-222 gpm-795 psi. Cont TIH on stands from 8028' to 10,879' just above 7" liner. Circulate to condition mud at 95 spm- 230 gpm-995 psi, 12.5+ in/out with a 49 vis. Cont TIH on stands from 10,879' to 11,287' and had to stop to replace broken air fitting on eaton brake drum. Cont TIH from 11,287' to 12,730'. Brought the remaining 339 bbls of 12.5 ppg OBM over from tank farm into the frac tank and started centrifuging it back. M/U TDS, broke circ. P/U-205K S/O-188K GPM-175 SPP-957 psi RPM-20 TQ-.5K, washed/reamed down to last tag depth at 12,769', set down 7K and TQ jumped to 8K, P/U off bottom, had 10K over pull. At this point the fishing hand felt we had swallowed junk into the RCJB tool. Brought both MP's on line to 412 GPM SPP-3437 psi, shut down the rotary. Washed F/12,769'-T/12,779' w/ no issues. P/U off bottom, kicked in the rotary-20 RPM TQ-3K. Cont. washing/reaming w/ no issues F/12,779'-T/12,783' P/U-205K S/O-188K GPM-412 SPP-3559 psi TQ-3K. Called town and made decision to POOH and clean out baskets. Shut down pumps, flow check (static) POOH wet racking back in the derrick F/12,783'-T/12,223', pumped 20 bbl dry job 2lbs over MW, Cont. POOH F/12,223'-T/8064', pipe came wet, mixed and pumped second dry job 2LBS over MW. Cleaned & cleared rig floor. Held PTSM. crew change. L/D 104 jts. of DP F/8064'-T/5943', vacuuming wiper balls through pipe and installing thread protectors. Encountered mud U-tubing out of pipe while L/D singles. M/U TDS broke circ. pumped X2 string volume and slugged pipe with 10 bbl dry job (pipe came dry). Cont. POOH L/D singles F/5943'-T/4832'. P/U-100K S/O-100K GPM-137 SPP-389 psi. Cont. racking back in derrick F/4832' to current depth of 4491'. Hauled 8 bbls of solids to KGF G&I Cumulative: 136 bbls Hauled 7 bbls of fluid to KGF G&I Cumulative: 289 bbls Daily Metal: 2 lbs Cumulative: 17 lbs Finished cleanout of out RCJB assembly and recovered 2 lbs metal chunks. Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 06/14/2021 - Monday 06/13/2021 - Sunday Cont POOH from 4,491' with Baker BHA #3. Had no CIBP junk in RCJB or boot baskets. Swapped out short barrel for a long barrel and LD entire assembly on catwalk. Cleaned up rig floor, blew down topdrive, drained BOP stack, PU 4-1/2" test joint and MU run tool, removed wear ring and set test plug, flooded surface lines and stack with water, purged air, RU chart recorder and test equipment, obtained shell test at 250/4,500 psi. Tested all BOPE at 250/4,500 for 5 min each. Annular at 250/2,500. Tested with both 3-1/2" and 4-1/2" test joints and performed draw down test on Koomey unit. Quadco tested audio/visual gas alarms on 6-12-21 at 20:30 pm. Witness waived by AOGCC Jim Regg on 6-11-21 at 14:03 pm. Had one F/P on outer mezz kill valve high test. Greased and cycled valve and re-tested OK. Had an occasional steady drip from annulus during testing. RD test equipment, LD test joint, broke down Baker RCJB assembly for BHA change, removed test plug and drained water from stack, installed wear bushing, shut in annulus valve. Staged Bakers model "L" retrieving head and bumper sub,. Cleaned & organized rig floor, M/U Bakers model "L" retrieving head and bumper sub- BHA #4. TIH w/ BHA #4 out of the derrick F/surface-T/3,391', M/U TDS & broke circ. GPM-224 SPP-221. Cont. TIH out of the derrick F/3391'-T/4670'. Cont. working on centrifuging OBM mud back in frac. tank. Switched elevators around, started P/U singles & RIH F/4,670'-T/5,256' P/U-100K S/O-100K. Held PTSM & Sunday safety meeting, crew change. Resumed P/U and singling in the hole F/5,256'-T/6,237', M/U TDS, broke circ. P/U-105K S/O-105K GPM-144 SPP-255 psi. Cont. P/U singles & RIH F/6,237'-T/8,003' for a total of 104 singles P/U. Cont. TIH out of the derrick F/8,003'-T/9,054', M/U TDS, broke circ. P/U-145K S/O-145 GPM-114 SPP-342 psi. held PJSM, M/U TDS to TIW and stump, hung off blocks slip & cut 16 wraps of drill line, and performed rig service. Cont. TIH out of the derrick F/9,054' to current depth of 9,362'. Hauled 39 bbls of solids to KGF G&I. Cumulative: 175 bbls. Hauled 86 bbls of fluid to KGF G&I. Cumulative: 375 bbls. Daily Metal: 0 lbs. Cumulative: 17 lbs. Had no CIBP junk in RCJB or boot baskets. Witness waived by AOGCC Jim Regg on Tested all BOPE at 250/4,500 for 5 min each. Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 TIH from 9,367’ to 10,967’ just above 7" liner. MU topdrive and CBU at 91 spm-220 gpm-591 psi. Cont ease into 7" and TIH slow from 10,967' to 12,709'. Prior to running last stand PU kelly joint and S/O to 12, 738', dwn wt 190K, MU TIW, pump in sub and 5' pup on top. Pulled up hole and LD assembly, up wt 205K. MU last stand and topdrive, start circ at 100 spm-242 gpm-1,050 psi and S/O to 12,768', dwn wt 190K, up wt 195K. Shut down pump, bled off and closed bag, up wt 205K, dwn wt 195K with no pump. Opened bag and S/O to 12,768', PU kelly joint, S/O to 12,786' and set down 5K. Marked pipe, RU low torque valve on pump in sub, swing, HP 2" hose to flow line, closed 4" stand pipe valve and lower manual IBOP, opened inside kill/HCR. Closed bag, using pump 1 on idle to establish reverse circ and check for any leaks, S/O slow at 50 spm-119 gpm-498 psi and S/O from 12,783' to 12,785', down wt 193K, staged up to 90 spm-217 gpm-825 psi, cont to ease down. At 12,787' had a spike in pressure to 1,400 psi, PU 2', pressure dropped, S/O slow to 12,785' and psi spiked again to 1360. PU 2', S/O to 12,788' pressure rising. PU 2' and parked string. CBU reverse circ at 73 spm-177 gpm-802 psi, saw no sign of course sand or calcium carbonate. Went well past bottoms up (175 bbls = 3040 strokes DP volume) shut down pump and bled off. Opened bag, PU on string and immediately pulled to 220K (15K over), S/O to 175K, PU to 215K, S/O to 175K, PU to 220K and appears we were latched into plug. RD reverse circ equipment, closed inside kill and HCR, Opened TIW , manual IBOP and 4" standpipe valve. PU and parked at 205K, rotated right 30 rounds while slowly PU on string, then worked string from 220K down to 185K 5 times with no release. Repeated this process two more times with no release, allowed rig transmission to cool down, lined up to pump long way at idle, pressure started climbing immediately. Shut down pump, PU and weight fell off. S/O to 12,789', 180K. PU to 230K getting weight back. Resumed pumping, S/O to 12,788', 180K, pressure climbing. PU to 205K, rotated right 30 rounds while PU slow. Worked pipe from 220K down to 175K then parked at 205K. Rotated left 3 rounds, worked pipe from 205K down to 175K twice and were released from plug. with pump at idle S/O to engage plug and repeated rotating while PU slow with no indication of plug release. Worked string hard from 220K down to 150K a dozen times, parked at 205K rotated right30 rounds while PU slow, saw string jump twice in those 30 rounds, cont PU slow and pulled up hole with no issue. Parked at 12,780'. Circulated at 47 spm-113 gpm-528 psi allowing plug to relax 15 minutes, then increased to 68 spm- 164 gpm-706 psi. S/O to 12,792' going deeper than plug set depth, pulled back up hole to 12,789' to finish bottoms up, plug is released. Up wt 205K, dwn wt 195K. Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 CCI has transferred all OBM into tank farm and removed frac tank from location. Centrifuge flushed with diesel then water. POOH racking back in derrick at 40' per/min F/12,789'-T/10,908' inside the 9.625". P/U-180K S/O-175K. Pumped 20 bbls dry job 2 lbs over MW, GPM-114 SPP-353 psi. Broke down reverse circ. equip. off E-Kelly. Cont. POOH racking back in derrick at 40' per/min F/10,908'-T/9,739' P/U-166K S/O-156K. Held PTSM, crew change. Cont. POOH racking back in derrick at 50' per/min F/9,739'-T/8,004'. L/D singles F/8,004'-T/4,782' (104 jts. total). P/U-90K S/O-85K. Swapped elevators around, cont. POOH F/4,782' to current depth 4,631'. Hauled 66 bbls of solids to KGF G&I. Cumulative: 241 bbls. Hauled 109 bbls of fluid to KGF G&I. Cumulative: 484 bbls. Daily Metal: 0 lbs. Cumulative: 17 lbs. 06/15/2021 - Tuesday Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 Continue to POOH on elevators from 4,631' to surface, L/D 7'' model G RBP. Calculated displacement on TOOH. Clear and clean rig floor, service top drive and rig. Monitor well, static. PJSM, P/U BHA 5, BOT 5-3/4'' overshot, upper extension dressed w/ 3-1/2'' bskt grapple- plain control, top sub and XO to 7.29', TIH with 77 stands 4 1/2'' DP to 4,777'. Swap elevators around, drift, P/U and single in the the hole with 4-1/2'' DP to 10,901'. (total of 126 jts.) Fill pipe at 4,930' and 7,600'. M/U TDS, broke circ. CBU. P/U-180K S/O-175K GPM-213 SPP-531 max gas 28 units. Cont. TIH out of derrick w/ 4.5" DP F/10,901'-T/13,196'. Cal pipe displacement during TIH. P/U-215K S/O-200K. Held PTSM, crew change. M/U TDS, broke circ. Washed down F/13,196'-T/13,310'. GPM-255 SPP-1,130 psi. Brought two MP's on line to bring up rate and CBU. P/U-200K S/O-195K GPM-338 SPP-1,865 psi. Had Baker fishing Rep on location @ 02:00 hrs, Washed down GPM-333 SPP-1,552 psi RPM-4 TQ-3K, located top of 3.5" tubing stub @ 13,313' (7' high), seen 200 psi increase while washing over 3.5" tubing stub (1,757 psi), shut down rotary, P/U 6' & cont. to circ. Pollard wireline on location @ 03:00 hrs, Shut down pumps, kicked in rotary 4 RPM, eased down and latched onto 3.5" tubing stub w/ over shot, P/U 10K & 20K over P/U weight to confirm latch, set slips w/ string in tension w/ 15K over pull. R/U Pollard wireline, M/U TIW, XO, and pin 3.5" IF to Bowen/stuffing box onto stump, M/U wireline tools-1-3/4" weight bars, 1-3/4" spang jars, 2.39" centralizer, 1-3/4" drive down bailer 8.5" long. RIH w/ wireline, tagged up @ 13,385', worked bailer , P/U-700, POOH w/ wireline tools, emptied bailer (mostly barite/drilling mud), removed 2.39" centralizer. Currently remaking wireline tools. Hauled 0 bbls of solids to KGF G&I. Cumulative: 241 bbls. Hauled 0 bbls of fluid to KGF G&I. Cumulative: 484 bbls. Daily Metal: 0 lbs. Cumulative: 17 lbs. overshot, upper extension dressed w/ 3-1/2'' bskt grapple- latched onto 3.5" tubing stub w/ over shot, located top of 3.5" tubing stub @ 13,313' L/D 7'' model G RBP. Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 06/16/2021 - Wednesday Continue RIH with 1-3/4'' drive bailer assy on wire line ( 2nd run ), tag at 13,385', work bailer in 3-1/2'' tubing. TOOH, empty bailer, recovered 1 gallon thick barite. Add 3rd wt bar, RIH, tag at 13,395', work bailer making 5', TOOH, recovered some thick barite and mud. M/U 2-1/4'' drive bailer, RIH, tag at 13,400', bail to 13,403', TOOH, recovered 1- 1/2'' x 1'' piece metal and small piece metal clip from a jet cutter, M/U 2-1/4'' magnet, RIH, tag several times at 13,403', POOH, nothing recovered, RD WL, L/D FOSV and XOs. PJSM with oncoming crew and BOT rep, M/U top drive, pull slips, removed bolts from elevator ears and set elevators on rig floor to spin elevators in preparation to come out of the hole, bails contacted rig floor shearing the bolt holding the load collar off of the quill assembly, broken piece of pin struck and cracked doghouse windshield. Shut down operations. Made notifications to town team and Hilcorp Rig foreman. Monitor well, static, Held PJSM with rig crew, replace broken load collar bolt, inspect top drive, good, Hilcorp Rig Foreman on location. Release grapple off 3-1/2'' tbg stub at 13,313' as per BOT rep, pull and rack back 5 stands 4-1/2'' DP to 13,009'. PU 212K, SO 195K. Monitor the well, fill trip tank, service the rig and top drive. Continue to TOOH on elevators f/ 13,009' to 8,678' racking stands 4-1/2'' DP. P/U-208K S/O-195K. Cont. POOH L/D singles F/8,678'-T/5,704', vacuuming wiper balls through pipe, cleaning threads and installing thread protectors. P/U-99K S/O-98K @ 5,704' Cal Disp.=48.3 bbls Act Disp.= 51.6 bbls Diff=3.3 bbls. Held PTSM, crew change. Resumed L/D singles F/5,704'-T/4,767' (Total of 126 jts.). P/U-83K S/O-85K. Racked back 4.5" DP on driller side F/4,767'-T/BHA #5 (Total of 77 stds.) L/D overshot, extension, and XO. Hole fill for the trip. Cal Disp.=81.4 bbls Act Disp.= 85.3 bbls Diff=-3.9 bbls. Cleaned & cleared rig floor, staged BHA #6 on catwalk & pipe racks, changed out handling equip, M/U safety jts. Held PJSM on P/U BHA #6, Currently M/U drag tooth shoe to wash pipe at report time. Hauled 0 bbls of solids to KGF G&I. Cumulative: 241 bbls. Hauled 15 bbls of fluid to KGF G&I. Cumulative: 499 bbls. Daily Metal: 0 lbs. Cumulative: 17 lbs. Release grapple off 3-1/2'' tbg stub at 13,313' Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 06/17/2021 - Thursday Continue to M/U wash pipe BHA #6- 6'' drag tooth shoe, 24 jts 5-3/4'' wash pipe, wash over boot bskt, bumper sub, oil jar, XO to 738.61'. RIH at a moderate speed with stands 4-1/2'' DP f/ 738' to 4,151'. Monitor well with the trip tank, PJSM, install FOSV, hang blocks, slip and cut 81' drlg line. L/D FOSV, recalibrate block height, function crown saver. Continue to RIH at moderate speed with stands 4-1/2'' DP f/ 4,151' to 5,501' @ 77 stands, turn elevators, single in with 4- 1/2'' DP to 9,409' @ 126 jts, Correct displacement TIH at this point. Turn elevators, continue RIH with stands 4-1/2'' DP from 9,409', went through liner top @ 10,991' w/ no issues, cont. RIH , @ 11,324', mud started U-tubing from top of DP, Started screwing into every std. letting mud U-tube through TDS. Cont. RIH F/11,324'-T/12,684'. P/U-203K S/O-193K Off line received 95 jts. and a pup of 5.5" 23 ppf P-110 casing on location. At 12,684' stopped an inspected saver sub due to hard breaks w/ TDS, had sharp threads on top side of saver sub, changed out saver sub, grabber dies, performed rig service, and set drill TQ on TDS to 8K. Cont. RIH F/12,684'-T/13,000', broke circ. established washing /reaming parameters GPM-210 SPP-1,600 psi Free -TQ @ 20 RPM-3.5K TQ @ 50 RPM-4.3K P/U-217K S/O-197K Pipe displacement Cal disp.=97.52 bbls Act disp.=94.21 bbls Diff=3.31 bbls. Washed/reamed over 3.5" tubing F/13,313'-T/13,555' GPM-210 SPP-1,800 psi RPM-20 TQ-4-8K. Held PTSM, crew change. Cont. washed/reamed over 3.5" tubing F/13,555'-T/13,615'. At our first BU, MW climbed to 12.9 ppg and we observed an increase in barite coming across the shakers (See photos). GPM-205 SPP-1,625 psi RPM-30 TQ-4K P/U-180K S/O-163K. Established parameter for future cut & fish work @ 13,615'. Increased T/257 GPM SPP-2,200 psi RPM-30 Pumps on P/U-177K S/O-153K ROT-153K. Cont. washing/reaming over 3.5" tubing F/13,615-T/14,026'. Washed over 713' of 3.5" tubing, tagged w/ good indication @ 14,026'. WOB-4/8K TQ-4.5K. Pumped 20 bbl Hi-Vis sweep. Currently circ. around sweep at report time. P/U-180K S/O-155K GPM-265 SPP-2675 Max gas 30 units. Hauled 1 bbls of solids to KGF G&I. Cumulative: 242 bbls. Hauled 84 bbls of fluid to KGF G&I. Cumulative: 583 bbls. Daily Metal: 0 lbs. Cumulative: 17 lbs. 06/18/2021- Friday Washed over 713' of 3.5" tubing, tagged w/ good indication @ 14,026' Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 Continue to circulate sweep around @ 14,026' pumping 265 gpm, 2,675 psi, sweep strung out, no indication or increase, MW out 12.5+, shut down, flow check well, static. P/U-180K S/O-155K. TOOH on elevators racking stds 4-1/2'' DP f/ 14,026' to above TOL @ 10,991', slight flow out DP, continue TOOH to 9,407' M/U TD each std while mixing dry job. Submit 24 hr BOP test notification to AOGCC. Turn elevators and R/U to L/D DP. Pump 20 bbl dry job. TOOH L/D 4-1/2'' DP from 9,407' to 8,569', vacuum wiper balls through pipe, cleaning threads and installing thread protectors. Held PTSM with on coming, crew change, Continue TOOH L/D 4-1/2'' DP from 8,569' to 5,501' @ 126 jts total, turn elevators. TOOH racking 77 stands 4-1/2'' DP to BHA @ 738'. P/U-25K S/O-25K Hole fill Cal Disp.=98.9 bbls Act Disp.=95.8 bbls Diff= -3.1 bbls. Had PJSM on L/D BHA, L/D BHA #6, oil jars, bumper sub, boot basket, and 16 jts. of 5-3/4" wash pipe, racking back 3 stds of wash pipe in the derrick. P/U BHA#7, outside cutter shoe , 9 jts. of 5-3/4" wash pipe, boot basket, bumper sub, and XO back to 4.5" CDS-40 DP. Cleared & cleaned rig floor, serviced rig. RIH out of the derrick F/284'-T/1,213'. P/U-33K S/O-34K. Held PTSM, crew change, Cont. RIH out of the derrick, F/1,213'-T/5,044' (77 stds). P/U-88K S/O-90K. P/U and singles in the hole F/5,044'-T/8,952' (126 jts.). Turned around elevators. P/U-147K S/O- 148K. Cont. RIH out of the derrick F/8,952' to current depth of 9,449'. Hauled 0 bbls of solids to KGF G&I. Cumulative: 242 bbls. Hauled 0 bbls of fluid to KGF G&I. Cumulative: 583 bbls. Daily Metal: 5 lbs. Cumulative: 23 lbs. 06/19/2021 - Saturday Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 Cont. RIH with BHA #7, outside tubing cutter/wash pipe assy with stds 4-1/2'' DP f/ 9,449', no issues entering 7'' TOL @ 10,991', RIH to 12,850', mud running out DP, M/U TD ea. stand with bleeder open, continue RIH to 13,300', RIH over 3- 1/2'' tbg stub @ 13,313' to 13,347'. Correct displacement TIH. PU 216, SO 204K. TD grabber dies started slipping, inspect and C/O rear grabber dies and backup tong dies. Continue RIH slow tagging @ 13,583', locate collar @ 13,560', SO to neutral wt, establish rotate parameters, 30 rpm, free torque 4-5k, 207k rot wt. Cut 3-1/2'' P110, 9.3# tbg @ 13,561' @ 1.13' below tbg collar, 30 rpm, 4-7k torque, PU hole slow to 13,532' racking back stand, PU wt @ 220k w/ 3-4k increase. PJSM, TOOH with fish racking stands back f/ 13,532' to 13,156' pulling no faster than 30 fpm, easy in/out slips, using caution not to S/O or rotate pipe. Off line received 350 jts of 3.5" 9.3 ppf P-110 EUE 8RD tubing in field. PTSM, Crew change, review plan for TOOH with Baker rep, continue TOOH racking stds back f/ 12,315' to 8,952' pulling no faster than 30 fpm, easy in/out slips, using caution not to S/O or rotate pipe, at 10,900' started pulling wet. Note: Quadco on location @ 14:00 -calibrate and test rig gas alarms. Turn elevators and R/U to L/D DP. TOOH L/D 4-1/2'' DP from 8,952' to 5,049'. (Total 126 jts.) P/U-91K S/O-91K. Cont. POOH w/ fish F/5,049'-T/3,387', 30'/min pulling speed. P/U-65K S/O-65K. Held PTSM, crew change. Resumed POOH w/ fish F/3,387'-T/284', 30'/min pulling speed. Cal hole fill for the trip. B/O bumper sub & boot basket, M/U oil jars, intensifier, and spear to bottom of bumper sub. R/U false rotary table on wash pipe stump, eased down into wash pipe with spear, stung into 3.5" tubing fish w/ spear and pulled through table. B/O of spear, L/D jar combo, M/U lift sub to spear and hoisted 3.5" tubing to connection. Cleaned & cleared rig floor. Currently R/U Weatherford power tongs. Hauled 0 bbls of solids to KGF G&I. Cumulative: 242 bbls. Hauled 0 bbls of fluid to KGF G&I. Cumulative: 583 bbls. Daily Metal: 0 lbs. Cumulative: 23 lbs. Cut 3-1/2'' P110, 9.3# tbg @ 13,561' Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 06/20/2021 - Sunday Finish R/U 3-1/2'' power tongs, Held PJSM for L/D fish, review plan for well control, wearing PPE, using air drill and protective rubber belting wrapped around tbg, drill 1/4'' hole just above ea. collar on tbg, No trapped pressure observed, L/D 7 full length jts, upper and lower cut jts 3-1/2'' 9.3# P110 tubing, all joints packed full of thick settled out barite ( 248' tubing recovered ). No tubing punch observed on joint # 6 which would have been @ 13,511', some damage on jt #5 top of tbg collar from milling- see pics in O-Drive,. R/D power tongs and false table. C/O handling equipment, TOOH f/ 270', L/D 1 jt 5-3/4'' wash pipe, rack 4 stds wash pipe in derrick, L/D and inspect OS cutter, no damage observed. Clear and clean rig floor, Drain the stack, MU run tool, remove 9" ID wear bushing, R/U jet tool and flush BOP, stage 3-1/2'' and 4-1/2" test joints on catwalk, Note: support crew clean and flush barite out tubing recovered and sift thru. PTSM with oncoming crew, rig crew change, install test plug. flood surface lines and stack with water, purged air, RU chart recorder and test equipment, obtained shell test at 250/4,500 psi. Tested all BOPE at 250/4,500 for 5 min each. Annular at 250/2,500. Tested with both 3-1/2" and 4-1/2" test joints and performed draw down test on koomey unit. Had two Fail/Pass during BOP test. Test #1 high test- Attempted to bump up pressure and had erratic needle, falsely showed dropping below 2,500 psi, bled off and retested. Test #4- Manual inside kill valve, functioned and retested. Quadco tested audio/visual gas alarms on 6-19-21 at 14:30 pm. Witness waived by AOGCC Jim Regg on 6-18-21 @ 09:38 am. RD test equipment, removed test plug and drained water from stack, blew down mud lines & choke manifold, greased choke, installed wear bushing and RILD's, shut in annulus valve. P/U and broke out oil jars, intensifier, and bumper sub and L/D. P/U & M/U BHA #8- new outside cutting shoe, 11 jts of 5-3/4" wash pipe, 2 extensions, boot basket, bumper sub, & XO back to 4.5" DP. P/U-22K S/O-22K. RIH out of derrick w/ 4/5" DP F/357'-T/4,698'. P/U-85K S/O-84K. Held PTSM, crew change. Had weekly safety meeting with rig hands. Cont. RIH out of derrick w/ 4/5" DP F/4,698'-T/5,128'. P/U-90K S/O-91K. Hung blocks, slipped on 5 wraps, unspooled & cut 21 wraps of drill line, checked crown-0-matic. Turned elevators around. P/U & singled into hole F/5,128'-T/9,150' (130 jts.) P/U-153K S/O-154K. RIH out of derrick w/ 4/5" DP F/9,150' to current depth of 10,571'. Hauled 5 bbls of solids to KGF G&I. Cumulative: 247 bbls. Hauled 85 bbls of fluid to KGF G&I. Cumulative: 668 bbls. Daily Metal: 0 lbs. Cumulative: 23 lbs. 06/21/2021 - Monday L/D 7 full length jts, upper and lower cut jts 3-1/2'' 9.3# P110 tubing, all joints packed full of thick settled out barite 248' tubing recovered Tested all BOPE at 250/4,500 f Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 Continue RIH with OS cutter/wash pipe BHA #8 with stds 4-1/2'' DP F/10,571', entering 7'' TOL @ 10,991' mud overflowing out DP, cont. RIH M/U TD ea. stand to 13,547' get parameters, RIH over 3-1/2'' tbg stub @ 13,561' to 13,897'. Correct displacement RIH. PU 223K, SO 203K. Line up and pump 3 bpm, 780 psi, pump 20 bbls to clear out wash pipe, shut down pump. Establish rotate parameters, tag at 13,905', locate tbg collar at 13,885', make tbg cut @ 13,886' @ 1.6' below collar, 30 rpm, 5-7k tq. as per Baker rep, Rack std back to 13,853', seeing 4k wt increase. PU 225K, SO 203K, ROT 212K. Flowcheck the well, static, TOOH with fish racking stds DP f/ 13,853' to 13,234' pulling no faster than 30 fpm, using caution not to rotate or S/O with pipe, easy in/out of slips. Off line got in 9 more jts. of 5.5" 23 ppf P-110 EZGO F13. PTSM with oncoming crew, rig crew change, continue TOOH with stds 4-1/2'' DP f/ 13,234' to 9,150', Turn elevators, Continue TOOH L/D singles 4-1/2'' DP from 9,150' to 5,120' @ 130 jts P/U-93K. Racked back 4.5" DP in derrick F/5,120'-T/2,842' at 30' per/min P/U-59K. Held PTSM, crew change. Gave Weatherford tubing hands 2 hr. notice. Cont. racking back 4.5" DP in the derrick F/2,842'-T/BHA #8. Cal hole fill for the trip. B/O and L/D bumper sub & boot basket, M/U lifting nub into wash pipe, R/U false table, P/U bumper sub, jars, and spear, run inside wash pipe and speared 3.5" tubing/fish, pulled fish to top of wash pipe stump. B/O and L/D jars & bumper sub, M/U lifting sub to spear, R/U Weatherford tongs. Started L/D 3.5" tubing/fish, air drilling above each 3.5" tubing connect (No trap pressure) and noting B/O TQ on connection. TQ on each connection ranged from 8K to 700 ft/bls. All 9 jts. and the two cut jts. of the 3.5" tubing were packed off with barite. There were no tubing punches observed in any of the 324' of the fish recovered. On 5 jts of the 3.5" tubing there were slight dimples in the tubular 4" apart from each, from top to bottom of each jt. Currently L/D remainder of BHA #8 at report time. Hauled 0 bbls of solids to KGF G&I. Cumulative: 247 bbls. Hauled 0 bbls of fluid to KGF G&I. Cumulative: 668 bbls. Daily Metal: 0 lbs. Cumulative: 23 lbs. make tbg cut @ 13,886' There were no tubing punches observed in any of the 324' of the fish recovered. Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 Continue to install the new transmission on rig floor draworks motor, fill with oil. Test run new transmission with no issues, Crane re-install engine cover. PJSM, single in with 4-1/2'' DP from 13,629' to 13,877' just above the 3-1/2'' tbg stub. M/U TD. PU 230K, SO 220K, Pump 2.7 bpm, 520 psi, establish rotate parameters, 60 rpm, 6k tq. @ 207k ROT wt, with rotary off S/O and tag @ 13,896' swallowing 8' tagging top 3-1/2'' tbg stub on depth @ 13,888', dress tbg stub @ per Baker rep. Ream 2 times, tag 1 time w/ no rotary, L/D 2 singles DP to 13,846'. Pump 20 bbl high vis sweep around @ 6 bpm, 2200 psi, 30 rpm, 4k tq. working pipe slow, Back on time, no change, Flow check well, static, pump 20 bbl dry job. TOOH on elevators L/D 4-1/2'' DP from 13,846' to to 11,435' @ 80 jts, turn elevators, POOH racking stds 4-1/2'' DP from 11,435' to BHA, L/D Dress Off Mill Assembly, good markings on mill, clean and clear floor. R/U Weatherford tubing tongs. P/U Lower Packer completion as per Tripoint Rep, Install 3 shear screws in overshot 10k shear, Overshot 1, jt of 3.5''tubing, X nipple, 1 jt 3.5'' tubing and packer assembly, bumper sub and cross over t/ 117'. RIH w/ Lower Packer Assembly on 4.5'' DP f/ 117' t/ 2,300'. 06/22/2021 - Tuesday Currently L/D remainder of BHA #8, L/D 1 jt 5-3/4'' wash pipe, rack 5 stds of wash pipe in the derrick, L/D and inspect outside cutter, no damage. Clear and clean the rig floor, inspect tubing, cut 2 sample pieces above and below collars leaving tbg stubs on ea. end. Drift dimpled tubing samples with 2.84" drift, no issues, Rig crew service and inspect TD, Blocks and crown, draworks and brake linkage. Support crew work on cleaning barite from tbg on pipe rack. PJSM, M/U stand DP, Hang blocks, COM functioning slowly, investigate and found debris, partially plugging airline on the exhaust side of the COM, Replace airline and cleanout shuttle valve, Slip and cut 41' drlg line, re-set and test COM, good. Decision made to run in and dress 3-1/2'' tbg stub, PJSM, RIH with 5 stands 5 3/4'' wash pipe to 305', POOH L/D remainder of BHA #8. Cleaning barite from 3-1/2'' tbg on pipe rack recovered 3 pieces of metal in the last 2 jts, see pics in O-Drive. PTSM with oncoming crew, rig crew change, PJSM, C/O handling equipment. Load tools to the rig floor, M/U 6'' dress off shoe, 2- 5-3/4'' extensions, wash over BB, bumper sub, jar, XO, bit sub with ported flt. to 37.91' @ 8.33' swallow. TIH with 4-1/2'' stands DP to 13,629', fill pipe every 2,200'. Transmission started acting up wouldn't move the blocks while clutch was engaged, switch gears and trouble shoot transmission. Service rig and top drive, trouble shoot transmission. Circulate 113 gpm 733 psi even out mw while trouble shooting transmission, decision made to change out transmission, ETA crane 0300 hrs spot in and prep to hoist out transmission, mechanic pulling apart old transmission to replace, pull transmission swap parts to new transmission for reinstallation, hoist new transmission into position and install same. 06/23/2021 - Wednesday Overshot 1, jt of 3.5''tubing, X nipple, 1 jt 3.5'' tubing and packer assembly, Decision made to run in and dress 3-1/2'' tbg stub, tag @ 13,896' swallowing 8' tagging top 3-1/2''tbg stub on depth @ 13,888', dress tbg stub @ Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 06/24/2021 - Thursday RIH w/ Lower Packer Assembly 60 fpm on stands 4.5'' DP f/ 2,300' to 6,746' @ 107 stds, turn elevators, single in with 80 jts 4-1/2'' DP f/ 6,746' to 8,438'. PTSM with oncoming crew, rig crew change, continue to single in with DP f/ 8,438' to 9,225', RIH on stands to 13,865' no issues at 7'' TOL. Set depth get PU 220k SOW 202K slack off tag tubing stub @ 13,888' took wt 7k and fell off, slack off 4' and see first set of shear pins sheared @ 7k slack off another 4' and observe second set of shear pins sheared @ 18k Slack off to No Go set 20k down wt, P/U and reverify tag 13,901' w/ 13' of swallow, P/U and break joint, drop ball and rod, M/U Jt tag and P/U 1' off NoGo. Line up to pressure up on packer to set as per TriPoint rep, Pressure up to 3,800 psi and hold f/ 30 min, bleed pressure off and Pull 10k over pull and set down 10k repeat w/ 20k packer set. R/U Pollard wire line to retrieve ball and rod, RIH set down work tools and POOH didn't retrieve ball and rod, RIH set down work tools POOH retrieved ball and rod, R/D and release slickline. M/U top drive and turn 14 turns to right work torque down, turn and additional 14 turns working torque down observe weight drop and release from packer, P/U new PUW 212k rack back stand, flow check well, static. POOH L/D 4.5'' DP vacuuming wiper balls through pipe and reinstalling thread protectors f/ 13,831' t/ 9,933'. 06/25/2021- Friday Continue POOH L/D 4.5'' DP vacuuming wiper balls through pipe and reinstalling thread protectors f/ 9,933' to 5,467'. PTSM with oncoming crew, rig crew change, Continue POOH L/D 4.5'' DP vacuuming wiper balls through pipe and reinstalling thread protectors f/ 5,467' surface, L/D running tools. M/U stack washer and flush stack with water, L/D and P/U test jt to pull wear ring, set test plug. Change upper rams t/ 5.5'' solid body, grease and tighten doors, R/U to test BOP's. Test BOP's w/ 3.5'' and 5.5'' t/ 250/4,500 psi, test annular t/ 250/2,500 psi test CMV 1-15 auto and man IBOP, HCR choke and kill, Man choke and kill, TIW and Dart, perform accumulator test, Jim Regg waived witness. R/D test equipment pull test plug and L/D. Slip and cut drilling line 95'. M/U thread test pup jts, threads look good, M/U seal assembly and snap latch anchor RIH on 23# FJ 5.5'' casing 217'. 06/26/2021 - Saturday RIH with seal assembly and snap latch anchor on 23# FJ 5.5'' casing from 217' to 2,011', swap out power tongs due to slow running speed, continue running 5.5'' casing to 2,834' (69 joints ), torque connections to 4,200 ft/lbs. C/O to 3-1/2'' handling equipment. PU 9-5/8'' x 5-1/2'' packer/ 6'' tie back sleeve/6'' anchor latch seal assy w/ XO/ pup jt, 1 jt 3-1/2'' tbg, and sliding sleeve w/ pup jts to 2,888' as per Tri Point rep. RIH with 3-1/2'' EUE, 9.3# P-110 tbg with dummied GLMs as per tally f/ 2,888' to 3,132', torque connections to 4,230 ft/lbs. Air leaking on Clutch lever for the Eaton air brake, Mechanic replace valve, tested good. Continue RIH with 3-1/2'' EUE, 9.3# P-110 tbg with dummied GLMs as per tally f/ 3,132'' to 6,330', torque connections to 4,230 ft/lbs. M/U chemical injection mandrel, R/U control line spooler and line, terminate line to mandrel and test line. Continue RIH w/ upper completion f/ 6,330' t/ 10,670' installing cannon clamps every other jt and torqueing to 4,230 ft/lbs. y tag 13,901' Supposed to pressure test tubing to 2500 psi to test lower packer from below per sundry. f tag tubing stub @ 13,888' t pressure up on packer to set Test BOP's w/ 3.5'' and 5.5'' t/ 250/4,500 psi, w/ 13' of swallow, s POOH retrieved ball and rod, RIH with 3-1/2'' EUE, 9.3# P-110 tbg with dummied GLMs Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 RIH PX plug w/ longer bull nose profile and brush, tag @10,960' WLM, attempt to work past tight spot, POOH, L/D PX plug and brush, no markings, brush clean. Remove packing from the RHC plug, OD 2.75'', RIH with RHC plug tag at 10,960', work tools, after several attempts able to work past. RIH to 13,890' WLM, attempt to shear and set plug in upper X nipple, after several attempts, POOH, no issues thru tight spot at 10,960', POOH, inspect tools, no markings, pin almost sheared, Install knuckle jt above RHC running tool, RIH, tag at 10,960', work tools, plug set in sliding sleeve, POOH. MU retrieving tool, RIH, latch plug @ 10,960', POOH retrieving plug, redress tools, MU, RIH with X-line & 2.71'' OD X-lock tool, tag @ 10,960', work tool, unable to get past tight spot. Consult with engineer, decision made to R/D wire line and POOH with upper completion. POOH, X-Lock left in the hole, L/D X-line, MU retrieval tool, RIH, latch onto plug, POOH, LD tools, RD wire line. Mobilize Weatherford and Pollard for control line, wellhead hand BOLDS, pull hanger to the floor 20k over pull to snap out of anchor latch, terminate control line, R/U Weatherford and pollard. POOH Standing back tubing and spooling up control line removing cannon clamps L/D gas lift mandrels, terminate control line at chemical injection mandrel, continue POOH racking back stands of 3.5'' tubing @ 5,016'. 06/27/2021 - Sunday Continue RIH w/ upper completion f/ 10,670', tag 7'' TOL @ 10,991', PU 127K, SO 125K, work pipe several times getting past TOL, continue RIH to 13,731' @ jt 327. Install cannon clamps every other jt, TQ 3-1/2'' tbg to 4,230 ft/lbs, hold 500 psi on injection line. Correct displacemnt running completion. R/U to circulate down the tubing, Break circulation, pump 2 bpm with pump at idle, start seeing returns, tbg psi @ 950 psi and climbing, shut down pump, R/D circ equipment. M/U joints #328 and #329, S/O tagging at 13,792' with 12.30' swallow, L/D jts 329 and 328, space out as per Tri Point rep with 3.90' pup jt, M/U jt 398, pup, tbg hanger and 3-1/2'' landing jt. thread injection line thru hanger, hold 800 psi on line. Drain stack, land out hanger with 115k on hanger and seals landed at 13,790', RILDS @ per WHR. (82 cannon clamps ran) PU 150K, SO 130K. Clear and cleanup the rig floor, R/D power tongs, R/U Cross overs f/ slickline, R/U Slickline unit and hang top sheave. RIH w/ X selective plug, hang up @ 10,960'WLM work tools over pull 1,200 lbs, Work string 1 jar hit popped loose, attempt to slack off through tight spot unable to pass through lost 50lbs on PUW, POOH, Plug gone, RIH w/ pulling tool set down @ 10,960' latch plug and pull free, POOH, L/D Plug and pulling tool, RIH w/ 2.799 OD gauge ring work through tight spot continue RIH w/ gauge ring t/ 13,870' WLM no issues, POOH seen. tight spot on the way out work through with just over pull, POOH, no scarring on gauge ring, RIH w/ X selective plug set down @ 10,960' attempt t/ work through tight spot not going, POOH, L/D plug, RIH w/ RHC pulling tool t/ 13,940' WLM set down P/U over pull and fire jars, 100 lbs over pull and free POOH, drag seen through tight spot but pulled free, Hand ran back to shop f/ RHC running tool plan to rerun RHC in upper. profile, continue POOH break down pulling tool and RHC Plug, RIH w/ RHC plug set down at same spot 10,960' WLM work tools attempt to work through tight spot with no luck, POOH to inspect plug and running tool, no markings on tools, Install knuckle jt above RHC running tool, RIH set down at the same spot 10,960' WLM work string unable to get past, over pull pulling off tight spot, POOH inspect Plug and running tool. No markings on plug, discuss options, M/U PX plug w/ brush on the bottom and RIH, PX plug has longer bull nose profile and brush will help centralize plug. 06/28/2021 - Monday POOH Standing back tubing and spooling up control line S/O tagging at 13,792' with 12.30' swallow, land out hanger with 115k on hanger and seals landed at 13,790', Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 06/29/2021 - Tuesday Continue POOH racking back stands of 3.5'' tubing f/ 5,016' to 2,921', correct displacement on TOOH. L/D jt above sliding sleeve, inspect and L/D sliding sleeve with pup jts. L/D the jt tbg below the sliding sleeve, inspect and drift the tbg pups and 2 joints with 2.85'' drift, the sliding sleeve was partially shifted open, found piece of metal wedged in the port of SS resembling piece of tbg thread. Inspect new SS with longer pups, drift the pup jts, (new SS is up to close, down to open). Pollard slick line on location, spot slickline unit, RU XO/TIW assembly on tubing stump, Pollard RU and RIH with RXCP plug and set same in X nipple sitting at 2,843’, POOH RD slickline. Break off XO/TIW LD same, pulled up hole (up wt 68K) and Tri-Point Rep inspected packer (OK). PU and RIH 1 single, PU MU 2.81" ID sliding sleeve with pups, RIH installing GLM’s as per run tally, torqued to 4,230 ft/lbs, drifting stands in derrick with 2.86" drift, TIH slow getting backflow up tubing 30' off the rig floor. MU chemical injection mandrel at 6,340', RU Pollard spooler and control line, cont RIH slow t/ 11834' installing cannon clamps on every other jt. 06/30/2021 - Wednesday Cont TIH slowly from 11,834’ to 13,776’, PU single, S/O and latched seal assembly into SBR at 13,793’. Up wt 150K, dwn wt 130K. Cleaned, marked and measured pipe for space out, PU to 160K and saw anchor release, LD two singles. Needed 27.26’ for space out, MU 28.25’ of drifted pup joints, MU hanger and landing joint. Wellhead Rep terminated control line at hanger, opened annulus and drained BOP stack. S/O and saw anchor tag 1’ off hanger seat, cont S/O seeing 10K on anchor as hanger landed. Ran total 115 cannon clamps and 5 bands on upper completion string. Wellhead Rep RILD’s, Tri- Point Rep dropped ball/rod down landing joint., cleaned and removed Weatherford equipment from rig floor, cleaned rig floor, removed landing joint, flooded stack and surface lines, RU test equipment and chart recorder on choke manifold, closed manual kill and HCR, closed blinds, annulus open to atmosphere. Pumped 75.9 gallons through top of hanger to achieve 4,313 psi on tubing, setting Tri-Point packer and performing MIT-T for 30 min on chart, bled down to 4,307 psi over 30 min, good test. Bled off and RD test equipment. Bled back 63 gallons to trip tank. Witness of MIT-T was waived by AOGCC Rep Jim Regg on 6-30-21 at 09:40. Pollard slickline on location and spotted, installed landing joint in hanger with XO and TIW for guide, RIH and retrieved ball/rod, RIH and retrieved RHCP plug, RIH and shifted sliding sleeve open at 10,903', pulled up hole +/- 100' and parked Pollard, RU test pump on pump in sub and pumped down tubing to verify sleeve was open to annulus, getting returns out annulus, sleeve is open. POOH, RD and released Pollard. RU topdrive on landing joint, 2" HP hose from annulus to flow line. Broke circulation through sliding sleeve circulate 127 gpm ICP 975 psi FCP 350 psi MW dropped f/ 12.5ppg t/ 11.8ppg. Wellhead Rep RILD’s, RXCP p dropped ball/rod down landing joint s hanger landed. verify sleeve was open to annulus, getting returns out annulus, sleeve is open. Pumped 75.9 gallons through top of hanger to achieve 4,313 psi on tubing, setting Tri-Point packer and performing MIT-T for 30 min on chart, Witness of MIT-T was waived by AOGCC Rep Jim Regg on 6-30-21 a plug and set same in X nipple sitting at 2,843’, Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 07/01/2021 - Thursday Cont circulating through sliding sleeve long way at 127 gpm-473 psi, centrifuging MW down from 11.8 ppg, increased volume of 10 ppg spacer in pit 9 from 50 bbls to 80 bbls (70 pumpable) at 123 vis/10 ppg, loaded 2nd clean vac truck with fresh water for well displacement later, called wellhead Rep for 2 hr notice, attended Seaview spud meeting at BC office. Shut down centrifuge and cont to circ and balance mud at 141 gpm-406 psi. With a 10.8+ in and a 10.8 out shut down and broke off topdrive, well static, L/D landing joint and XO. Cleaned rig floor while circulating. Wellhead Rep installed BPV in hanger. MU wash tool and pup on topdrive, flushed BOP stack, topdrive, choke manifold and surface lines with BARAKLEAN pill. Shut down koomey unit, opened upper ram doors and replaced 5-1/2" rams with variables. Opened blind and lower rams doors, inspected, cleaned and greased then buttoned up doors. Removed flowline and riser, removed drip pan, RU trollys and hoisted BOP stack off wellhead. Wellhead Rep cleaned and prepped wellhead for tree, cleaned and stabbed tree. Bolted up then terminated control line, tested neck seals, hanger and void, ring gasket and lockdowns at 5,000 psi for 10 minutes. Pulled BPV and released wellhead Rep. Held PJSM, RU pump #2 on 400 bbl upright tanks with fresh water, RU circ hose from mezz kill to top of tree, return hose from annulus to flow line. Pumped the long way 53 bbls hi-vis 10 ppg spacer followed with fresh water, taking initial returns to pits. ICP 164 psi climbed to 1,518 psi max at 165 gpm. Offloaded two additional vac trucks of water into upright as room allowed. Monitor well for flow well static, clean pits and load diesel into up rights 4 loads so far off loaded approx. 18,600 gal of 28,500. 07/02/2021- Friday Cont to offload diesel into upright tanks while monitoring well (20 psi on tubing, 0 psi on annulus). Cont offloading mud from pits and cleaning same. RU to reverse circ diesel down IA. Held PJSM, pumped 697 bbls diesel at 3 bpm with a max of 1,016 psi and FCP of 523 psi, taking fresh water returns to cuttings box. Offloaded 4 vac trucks into production open top tank in field, hauled remainder to G&I for disposal. Shut down and shut in well. RU Pollard slickline and lubricator on tree. RIH with shift tool to 10,903’ and shifted sliding sleeve closed. Pulled up hole 100’ and parked, RU test pump on IA and pressured up to 800 psi with tubing open to atmosphere. IA held, no flow from tubing, bled off IA, POOH RD and released Pollard. Opened master and topped off 3-1/2" tubing, monitored well in cellar, IA open to cuttings box with no flow from either side, to achieve a 1 hour negative test on the 9-5/8" packer with diesel in the hole. Good test. Flushed water through mud pump and circ hoses to clear out any diesel. RU test equipment and chart recorder. Using rig test pump, tubing open to atmosphere, pumped down IA total of 7.66 bbls to achieve 2,015 psi on chart. Lost 15 psi over 30 minutes, good test, bled back 7.4 bbls. Witness of MIT-IA and negative test was waived by AOGCC Rep Jim Regg on 7-1- 21 at 22:04. Topped off 3-1/2" tubing, installed gauges on tree top and IA to monitor well as we rig down tubing 360 psi IA 0 psi , cont cleaning pits and pumps. RD topdrive torque bushing and removed from rig floor, prep and scope derrick down, prep t/ lay over, R/D gen 3, remove lower torque tube. Change gauge on tubing and bleed off pressure f/ 360psi t/ 300 psi, shut in and Continue Monitor tubing and IA, 390 psi tubing 0 psi IA @ 0500, Rig down modules, pull wires, continue cleaning pits, pull wires, blow through mud lines and disconnect, redress pumps and clean suction and discharge chambers, install shipping. beam on roughneck, R/D roughneck, pull camera system, R/D choke house utility lines, unspool drilling line and coil in derrick w/ Kelly hose, cut off 11 wraps. Change gauge on tubing and bleed off pressure f/ 360psi t/ 300 psi, shut in and Continue Monitor tubing and IA, 390 psi tubing 0 psi IA @ 0500, and shifted sliding sleeve closed. RU test pump on IA and pressured up to 800 psi with tubing open to atmosphere. cleaned and stabbed tree. Bolted up then terminated control line, tested neck seals, hanger and void, ring gasket and lockdowns at 5,000 psi for 10 minutes. Good test. good test, RU to reverse circ diesel down IA. Held PJSM, pumped 697 bbls diesel at 3 bpm with a max of 1,016 psi and FCP of 523 psi, taking fresh water returns to cuttings box. RIH with shift tool to 10,903’ pumped down IA total of 7.66 bbls to achieve 2,015 psi on chart. IA held, no flow from tubing, bled off IA, . Pumped the long way 53 bbls hi-vis 10 ppg spacer followed with fresh water, taking initial returns to pits. ICP 164 psi climbed to 1,518 psi max at 165 gpm. O . Witness of MIT-IA and negative test was waived by AOGCC Rep Jim Regg o IA open to cuttings box with no flow from either side, to achieve a 1 hour negative test on the 9-5/8" packer with diesel in the hole. Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 RD and removed hurricane vac unit, removed handy berm from around catwalk and tore out catwalk, laid over poorboy degasser and removed vent line, RD gas sensors and alarms, brought in crane, removed clam shell behind iron roughneck, picked the two upright tanks from rig containment, staged both on pad 1, staged BOP cradle at cellar, re- locate crane, transferred BOP stack from bridge cranes to cradle then off location, thoroughly cleaned out cellar box, installed shipping blocks on centrifuge and spooled up cords, finished pit cleaning. Released rig at 12:00 on 7-3-21. 07/04/2021 - Sunday No activity to report. 07/05/2021 - Monday At 06:00 found BCU-04RD had 1,000 psi on tubing, over 1,000 psi on the 1,000 psi gauge mounted on IA, brought in productions small bleed tank, tied in to IA and bled off 130 gallons to achieve 600 psi on IA, bled tubing off 20 gallon to achieve zero psi. Notified Workover Engineer, decision made to attempt to bleed IA to zero. Brought in productions large bleed tank and RU on IA. Assisted Wellhead Rep and Production Foremen in stacking tree on master valve, then assembly of flowline while bleeding IA. IA would not bleed any less than 95 psi, with a steady rate of 6.7 bph. Bled a total of 26 bbls from IA. Notified Workover Engineer, decision made to shut in tubing and IA and monitor/document pressure vs time. Shut in IA at 95 psi, bled 6 gallons off tubing, 150 psi to zero and shut in. Tubing built from zero to 380 psi over 4 hours, IA built from 95 to 1,450 psi over 4 hours. Tri-Point Rep, Pollard Slickline crew, boom truck and unit and Hot Oil truck on location at 18:00 hrs. Spotted units. Pollard RU lubricator and PX plug, stabbed lubricator on tree, brought in production tri-plex pump and tested lubricator. Pollard RIH and set plug at 13,790', unable to locate profile, POOH check plug dogs, setting pin sheared (brass), repin (brass) and dress plug RIH and attempt to set, unable to locate profile again work string pull out of hole and pin was sheared, redress tool with steel pin, rerun plug locate nipple. work tools attempt to set plug looked like plug set P/U over pull and spang off plug, set back down verify plug set not setting down in same place worked tools unable to set plug POOH, Pins unsheared, discuss option w/ Wireline supervisor, decision made to run knuckle jt above plug, Redress plug RIH, Locate profile and work tool string, POOH plug not set, Send hand to get pack off plug. 07/03/2021 - Saturday tied in to IA and bled off 130 gallons to achieve 600 psi on IA, bled tubing off 20 gallon to achieve zero psi. Tubing built from zero to 380 psi over 4 hours, IA built from 95 to 1,450 psi over 4 hours. T t 06:00 found BCU-04RD had 1,000 psi on tubing, Bled a total of 26 bbls from IA. IA would not bleed any less than 95 Shut in IA at 95 psi, bled 6 gallons off tubing, 150 psi to zero and shut Released rig at 12:00 on 7-3-21. over 1,000 psi on the 1,000 psi gauge mounted on IA, Notified Workover Engineer, decision made to attempt to bleed IA to zero. Brought in productions N large bleed tank and RU on IA. A psi, with a steady rate of 6.7 bph p Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 07/06/2021 - Tuesday Cont POOH with slickline, plug would not set, once OOH waited on packoff plug and checking with AK e-line on composite plug. RD released slickline crew and unit, AK e-line on location at 10:30, spotted and RU lubricator. MU 2.734" OD composite plug with CCL and gama tool string +/- 29' long, stabbed lubricator on tree, RU and tested lubricator to 1,500 psi with production tri-plex pump. RIH to 13,665' and shut down, not enough e-line cable on spool, called out second e-line unit. Need to get to +/- 13,800' then pull up hole to +/- 13,783' to set plug in 7' pup jnt. Started POOH and tool snagged. coming out of 5-1/2" into 3-1/2" sliding sleeve area. Lost entire 29' tool downhole. Cont POOH and RD e- line unit, called out slickline to RU, RIH and retrieve tool. Wait on slickline, 1,480 psi on IA, 160 psi on tubing. Slickline on location at 20:30. Spot unit, RU lubricator and M/U JD pulling tool w/ bell guide (2.705" OD on bell guide), spang jars, oil jars, & 10' of weight bar back to rope socket. stab lubricator on tree, RU production tri-plex and test lubricator, 250 psi Low & 3,000 psi High. RIH w/ slickline and fishing assembly, got P/U weight @ 10,782' -P/U-600 LBS. Cont. RIH w/ slickline F/10,782', latched onto fish @ 10,834' WLM, attempted to move fish up hole w/ no luck, started jarring on fish w/ 650 lbs. over pull multiple time w/ no luck, cont. staging up over pull weight, w/ 1150 lbs. of over pull fish came free. and started moving up hole w/ 230 lbs. of extra weight on the hook. POOH w/ slickline tools and fish F/10,834'- T/Surface. 1480 psi on IA. Blew down lubricator, broke Bowen connection, L/D E-line tools w/ plug shearing tool but no plug. M/U 2.79" gauge ring, spang jars, oil jars, and 18' of weight bars back to rope socket, stab lubricator on tree, RU production tri-plex and test lubricator, 250 psi Low & 3,000 psi High. RIH w/ slickline assembly F/Surface-T/10,791', got new P/U weight-660 lbs. Cont. RIH and tagged top of plug @ 10,853'. Attempted to free plug and move down hole multiple times w/ no luck. POOH w/ slickline F/10,853'-T/Surface. IA pressure 1,480 psi. R/D Pollard slickline unit & lubricator. Released Pollard slickline. Cont. monitoring well while waiting on orders. IA pressure-1,480 psi and tubing pressure 40 psi. IA pressure-1,480 psi a Need to get to +/- 13,800' then pull up hole to +/- 13,783' to set plug i not enough e-line cable on spool, Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 PTW, JSA with SLB coil , Cruz crane and vac truck operator, and Hilcorp Rep. MIUR SLB CTU 13 with 1.75" CT. Spot 2 x 400 bbl supply tanks and 2 x 400 bbl return tanks. Build containment berm around tanks. Start hauling water. roll in friction reducer with hot oil truck. 24 hour BOPE test witness notification sent 7/7/21 @ 1231 hrs. Witness waived by Jim Regg 7/8/21 @ 0932 hrs. Test all rams and vavles 250 low and 4,500 high. Pick injector head. Trim pipe. YJOS thru tubing hand on location. Make up 2.125" external slip coil connector. Pull test 25K. Make up DFCV, Circ sub, Hyd disconnect, and test plate. Fluid pack coil with 40 bbls water. Pressure test MHA. Coil connector leaking. Attempt to tighten slips in connector with no luck. Cut off coil connector and install new assembly. Re tested good. Stack down injector. Continue circulating supply fluid to shear in Friction reduer. 800 bbl fuild system loaded and ready. Location walk around completed with SLB supervisor. All ground valves closed. SDFN. 07/07/2021 - Wednesday Discussed forward plan with town, prepped to bring in Hot Oil truck and RU on tree. Started bleeding 3-1/2" x 9-5/8" IA off into productions large bleed tank while stage hot oil truck and RU on tree top. Bled a total of 13.3 bbls off IA and down to 95 psi. With hot oil truck, pressured up on tubing to 4,950 psi and started to capture flow rate from IA in bleed tank. Initial flow rate at 8.5 bph, at 4,760 psi tubing, flow rate at 6.9 bph, at 4,846 psi tubing, flow rate was very little and showing nothing on IA gauge, at 4,950 psi on tubing we shut down pump, flow rate just a dribble. Monitored IA for flow 1 hour and was down to an occasional drip. Bled tubing back to hot oil truck and saw nothing for flow at IA. Pressured back up on tubing to 5,300 psi, notified Area Ops Manager and Workover Foreman, then held for 1 hour. Initially had a pencil size stream from IA that died off over 15 minutes to an occasional drip. After 1 hour, tubing at 5,242 psi, no sign of flow at IA, bled tubing to zero, back to hot oil truck. Monitored IA 1 hour while. RD hot oil truck. After 1 hour we had no flow and no drips at IA. Closed in IA on two gauges, one being productions digital recording gauge. After 1 hour we had 0 psi on IA, 160 psi on tubing, bled off 5 gallons from tubing, Notified Area Ops Manager and got approval to move rig to Seaview Pad at 13:00 hrs. Will continue to monitor BCU-04RD for any changes. Pollard slickline on location at 17:30 to attempt to retrieve composite plug setting sleeve left in hole, on top of plug. Spotted unit, built lubricator and tool string with 2.5" OD magnet. RIH to 10,925' WLM and tagged fish. POOH with nothing on magnet. MU wirebrush, RIH and tagged fish at 10,925', pulled up hole noticeably less drag , POOH, broke off lubricator, recovered setting sleeve. RD and released slickline. Tubing and IA at 0 psi at 22:00 hrs. Cont. monitoring wellbore, tubing and IA at 0 psi at 06:00 hrs. Final report for BCU-04RD, moving rig to Seaview 9. 07/08/2021 - Thursday at 4,760 psi tubing, flow rate at 6.9 bph, at 4,846 psi tubing, flow rate was very little and showing nothing on IA gauge, at 4,950 psi on tubing we shut down pump, flow rate just a dribble. moving rig to Seaview 9. Initial flow rate at 8.5 bph, After 1 hour we had 0 psi on IA, 160 psi on tubing, bled off 5 gallons from tubing, Started bleeding 3-1/2" x 9-5/8" IA off into productions large bleed tank while stage hot oil truck and RU on tree top. Bled a total of 13.3 bbls off IA and down to 95 psi. With hot oil truck, pressured up on tubing to 4,950 psi and started to capture flow rate from IA in bleed W Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 07/09/2021- Friday PTW, JSA with SLB coil, Cruz Crane and Vac operators, YJOS tool hand and Hilcorp wellsite leader. Fire equipment. Location walk around complete. IA 0 psi, OA 0 psi, Tubing 300 psi. Bleed off wellhead pressure. Pick injector head and stab 30' of lubricator. Make up YJOS Milling assembly. 2.125" OD tools. Ext slip coil connector, DFCV, HYD jars, Circ sub, Hyd disconnect, Mud motor, 2.75" fluted junk mill. MHA was pressure tested to 250/4,500 psi. Stab on well and fluid pack. Confirm motor spinning. Close choke for stack PT. 250 psi low crew noticed drip from lubricator O-ring. Bleed pressure and blow down stack. Pop off and install new lubricator O ring. Re test 250/4,500psi. Open well 23.5 swab and upper master. Initial WHP 300 psi. Crack choke and bleed down. 0 psi well is static. RIH dry. Tag Composite bridge plug at 10,850' CTMD. RIH weight 16.8K. Pick up weight 22k. Online with slick water at 1.4 bbls/min 2,750 psi circ pressure. Confirmed 1:1's. Work motor and mill to establish pattern. 10,850.1 stall motor. Time mill showing good motor work. Plug moving down freely for 15'. Engage plug at 10,865.1' . Continue milling for .7' and plug moving in hole freely to 10,888'. WHP jumped from 120 psi to 550 psi upon 5 bbl gel sweep bottoms up. Swap to left side choke manifold and isolate right side. Remove choke and collect composite material from BP. Milled from 10,888' CTMD to 10,900' CTMD. Circ pressure back to initial rates and weight normal. Increase coil speed. Through plug and entering 5.5 casing. IA pressure remained 0 psi while milling plug in sliding sleeve window. Shut down pump and continue RIH. 257 bbls pumped during plug milling. Dry tag at 13,753' CTMD. PU and circulate out drilling mud to surface. Circ pressure dropping. 12.6 ppg drilling mud bottoms up complete. Establish milling parameters. Multiple stalls at 13,753' to 13,777.9' CTMD. Milled the remainder of the CBP in the 5.5 x 3.5" x over and x nipple as per tally. Work mill in hole and engage Barite at 13,852' CTMD. Take 50' bites and 100' wiper trips up hole. Repeat process until hard tag and stall at 14,875' CTMD. PU and engage depth slower 300-500 lb weight stack and 200-600 psi motor work. Noticed no mill off or weight gains. Continued to engage at depth. 10 bbl gel sweep out of coil. Possibly on catcher sub. Dry tag and pick up off sub 1". continue to circulate just above catcher sub fish neck profile to clean Barite. Gel sweep at surface. Fluid returns changed to crude oil and water. return micro motion not reliable during intervention. Perform 10 minute flow test and putting in 1 and getting 1.5 back. Well is underbalanced. Pick up from 14,875' CTMD and POOH to surface chasing up hole and back reaming at 1.5 bbl/min. to 14,000' CTMD. Shut down pump and stop coil to see how returns react. Returns slowed down but continued to flow. Calibrated eye ball estimation of .5 bbl/min. Crude and water mix no signs of gas. Continue OOH. Tagged up at surface. Close master and swab. all tubulars showing 0 psi at closure. Blow down lubricator stack. Pop off well. Milk YJOS motor. Condition of stator and rotor feels good. Carbide on mill normal wear on outside edges. Center of mill had little to no engagement. Outside of mill had even wear pattern possibly caused by catcher sub G fish neck profile. Stack down lubricator/injector. Move equipment and Cruz crane to make room for slick line unit. 807 bbls pumped. Hold tailgate meeting with personnel to discuss post job journey management and look for signs of fatigue. SLB, Cruz and YJOS leave in convoy. continue to circulate just above catcher sub fish neck profile to clean Barite. Tag Composite bridge plug at 10,850' CTMD. Dry tag at 13,753' CTMD. Fluid returns changed to crude oil and water. IA pressure remained 0 psi while milling plug in sliding sleeve window. Returns slowed down but continued to flow. Calibrated eye ball estimation of .5 bbl/min. Crude and water mix no signs of gas. Work mill in hole and engage Barite at 13,852' CTMD. Take 50' bites and 100' wiper trips up hole. Repeat process until hard tag and stall at 14,875' CTMD. Milled from 10,888' CTMD to 10,900' CTMD. Circ pressure back to initial rates and weight normal. Work motor and mill to establish pattern. 10,850.1 stall motor. Time mill showing good motor work. Plug moving down freely for 15'. Engage plug at 10,865.1' . Continue milling for .7' and plug moving in hole freely to 10,888'. W Milled the remainder of the CBP in the 5.5 x 3.5" x Perform 10 minute flow test and putting in 1 and getting 1.5 back. Well is underbalanced. Pick Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 07/11/2021 - Sunday PTW, JSA with SLB coil, Cruz crane operator, YJOS tool hand, and Hilcorp Rep. Fire equipment. Pick injector and 30' of lubricator. Make up to existing coil connector. BHA 2.125" OD . Ext slip connector, DFCV, Down jars, weight bar, Hyd Disco, Circ sub, X over, Hydraulic GS spear (flow through). BHA 28.5' long. MHA pressure tested 250/4,500 psi. Stab on well. PT stack 250/4,500 psi. Open upper master and swab 23.5 turns. WHP 3,100-3,200 psi. IA 280 psi (possible ballooning from tubing pressure) OA 0 psi. Bleed down WHP to open top diffuser tank. Returns are crude oil. Online down coil to test flow rate through GS spear nozzle. 1.5 bbls/min 4,100 psi. RIH. Perform weight checks as needed. 13,500' pick up weight 31,644 lbs clean. RIH dry tag 13,854' CTMD. Pick up to 13,500'. Online down CT 1.6 bbls/min @ 4,186 psi. WHP 344 psi with pinched choke. Returns Micro motion showing 2.3 bbls/min. No weight stack at previous tag at 13,854' CTMD. 14,000' sent 5 bbls Flo-Visc-L gel sweep. 14,095' CTMD gel at nozzle. FCO to 14,179' CTMD . Perform wiper trip up to 13,800' CTMD. RIH send 5 bbl gel sweep. FCO to 14,375' gel out of nozzle. 14,412' wiper trip to 14,000' CTMD. RIH Continue FCO. Send gel sweep. No significant weight stack or large increase in Circ pressure. Gel out of nozzle at 14,543' CTMD. Continue to FCO 2.4-2.7 bbls/min on return micro motion. Tag 14,898' CTMD. RKB 14,906'. Stacked 10k down. Circ pressure increased 350 psi. Good indication GS nose entered fish neck of catcher sub. Pick up slack off weight but remain at fish neck and continue jetting. Gel sweep at nozzle. (30 bbls of gel pumped total). Bottoms up and 30 additional bbls pumped. Pick up to 14,800' Shut down pump. RIH and stack 10K down at 14,903' CTMD. Pick up 2,700 lbs over. RIH and stack 13K at depth. Pick up slow to 37K (5,000 lbs over). POOH with Fishing BHA. Slow down for x nipples, 3.5"x 5.5" x overs, and sliding sleeve. No noticeable over pulls while POOH. Tag up at surface. Shut master and swab 23.5 turns. Bleed down and blow stack dry with rig air. Pollard Slick line on location rigging up next to coil unit. Pop off. Catcher sub not recovered. Break down tools Clean and inspect GS spear. Spear dogs have multiple marks. Look to be getting into fish neck profile. Take pictures of GS spear nose and dogs. Break down lubricator and set injector on the deck. SITP 0 psi, IA 500 psi. (Pressure increase could be due to flowing crude from formation causing IA to gain temperature and thermally expand diesel.) OA 0. Location walk around with SLB coil crew complete. Area cleaned up. Move Cruz crane. Pollard slick line making up GS spear. Stab on well with Slick line. Fluid pack for PT. Leak on lubricator collar. Bleed down. Pop off and change out o-ring. Stab on well and test 250 low 4500 high. RIH W/ 3-1/2" GS to 14,920'KB- W/T- No overpull- POOH W/ Metal shavings on tool. RIH W/ 2.71 LIB to 13,880'KB- W/T- Cannot pass- POOH W/ Fishing neck impression. RIH W/ 3 -1/2"GS to 13,880'KB- W/T- Gain overpull- perform 1 jarlick & come free- POOH- No Catcher. RIH W/ 3 -1/2"GS under KJ to 13,880'KB- W/T- Latch- Perform 3 jar licks & come free-POOH- Sheared. RIH W/ Same- Sit @ 10,872'KB- W/T- Fall to 13,880'KB- W/T- Latch- perform 1 jar lick & come free. POOH- No Catcher sub. RIH W/ Flared wire brush W/KJ to 5811'KB W/T- Fall to 10200'KB-W/T-Fall to 14920'KB -W/T. Gain overpull- POOH to 13,880'KB- Hang up- W/T- POOH till 12,380'- W/T- POOH till 10,200'KB- W/T. POOH Till 8,820'KB- W/T- POOH W/Less weight- continue pooh. Crew c/o Returns are crude oil. RIH dry tag 13,854' CTMD. Tag 14,898' CTMD. Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 PTW, JSA with SLB coil crew, Cruz crane op and vac truck, and Hilcorp rep. Fire equipment and pick injector head. Make up 30' lubricato,. Trim 30' 1.75" CT Dress CT for new CC. Stab on well. Circulate out remaining water. and fluid pack CT reel with 33 bbls of diesel. Make up YJOS BHA. Install external slip coil connector 2.125" OD Pull test 35K. Make up DFCV, BI di Jars, Hyd disco, Circ sub. Pressure test MHA 250/4,500 psi. Make up thru tubing motor and 2.75" junk mill with flat sides and deep water courses. Stab on well. Fluid pack and confirm motor spinning. Close choke. Pressure test lubricator stack 250/4,500 psi. Open Master and swab. 23.5 turns. WHP 3,500 psi. Crack choke to bleed down WHP. RIH with motor and mill. Perform weight checks as needed. Perform weight check 14,600' Pick up clean 32K. Online with #2 diesel down Ct to establish parameters. 1.1 bbls/min @ 2,678 psi. Choke back WHP 230 psi. Tag top of X nipple at 14,908.6' CTMD. Start milling attempts. Time milling to start pattern, stalls are fast. 14,907.3' stall higher up. Worked 14,907.3' to 14,908.44'. PX lock external packing chevron seals and X lock male and female back up rings (steel) did not return to surface. With multiple stalls at different depths and no pressure break after motor work indicates loose items . Packing seals, metal back up rings. 14,909' CTMD 400 psi of motor work. Pressure dropping back to initial circulation pressure. Mill pattern started. During milling operations attempts were made to stack weight and jar down post milling stall. 22 down jar licks performed to 80% coil yield limit. -35K down at surface gives 4,580 lbs weight on bit. Jars firing at 2 minutes. Mill appears to be loosing its cutting surface. when engaging fish weight stacks and circ pressure climbs indicating motor work. Weight nor pressure is breaking back. No mill off. Shut down fluid pump. POOH to surface. 200 bbls of #2 diesel fuel pumped from Weaver/Doyle's fuel tanker truck. 65 bbls of dirty diesel recycled from top of return tanks and used for milling operations. Total fluid pumped for milling 265 bbls. Tagged up. 0 psi on tubing. IA 50 psi, OA 0 psi. close master and swab 23.5 turns. Bleed down /blow down stack. Pop off well. Break down BHA. Mill cut-rite worn with little cutting edge left. Mill still measures 2.75" OD. From outside area of mill and towards center shows 7/8" Area of plug contacted by mill. Location secure. SDFN. Plan to run tapered mill in the AM to continue milling bottom sub of PX plug. 07/12/2021 - Monday Continue SL operations from previous report. Rih w/ 3 1/2'' GR to2,600' noticed tree flange leaking oil & gas pooh lay down lub. Re-head fix flange. Rih w/ same to 10,955 sit down w/ tool fell to 11,002' sit w/ tool fell to 13,880' 13,922' 13,957' would not pass pooh. remove knuckle joint rih w/ 3 1/2'' gr to 13,957' sit w/ tool would not pass pooh discuss plan forward. Rih w/ 1.8'' spear baited w/ 1.75'' rope socket w/ 2.5'' juc to 13,958' w/ tool fell to 14,917'kb w/ tool. pooh no sub. Rih w/ 2.6'' spear baited w/ 2.5'' juc to 13,957' w/ tool can not pass pooh juc sheared. rih w/ 2.5'' juc to 13,957' sit w/ tool would not fall pooh. Rih w/ bowspring centralizer w/ 2.5'' juc to 13,957' sit w/ tool fell to 14,915'kb w/ tool pooh w/60# over no grapple. Crew C/O Bow & 2.5 JDC to 13,879'KB- W/T- Fall to 14,825'KB- W/T- Latch- POOH W/ Internal Grapple RIH W/ Bow W/ 2 prong solid state grab to 1,3879'KB- W/T- Cannot Pass- POOH. RIH W/ Same W/ KJ to 13,879'KB- W/T- Fall to 14,825'KB- W/T- Gain Overpull- POOH W/ Catcher sub. CATCHER SUB ON THE BEACH!! 07/14/2021 - Wednesday Tag top of X nipple at 14,908.6' CTMD. Start milling attempts. T CATCHER SUB ON THE BEACH!! Rig Start Date End Date 3/10/20 7/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-04RD 50-133-20239-01-00 219-011 07/17/2021 - Saturday Arrive on location meet w/ Mike jsa permit. P/U equip. drive to location rig up slickline p/t lub. To 4,000psi flange above swab leaking call mike for hammer wrenches & fix. Rih w/ 3 1/2'' braided line brush to 14,919'kb w/ tool pooh nothing on brush. Rih w/ 2.5'' cent. w/ 2.25'' magnet to 13,875'kb w/ tool fell to 14,919' w/tool pooh w/ small pieces of wire. Rih w/ 2.25'' x 7' pump bailer to 14,919'kb w/ tool pooh empty discuss plan forward. Rih w/ 2.25' 'x 7' pump bailer to 14,919'kb w/ tool pooh empty discuss plan forward. w/ 2'' hydrostatic bailer to 14,919'kb w/ tool pooh w/ 1 metal packing ring small pieces of rubber. Rih w/ same to 15,252'kb no obstruction plug body fell - did not tag w/ hydrostatic bailer pooh. Rih w/ 2.5'' cent. w/ 1-1/4'' x 15'' prong to 15,804'kb tag no obstruction pooh, no obstruction Pushed PX plug EQ port to bottom. Ooh rig down slickline. depart field head to shop. Bring well online. 07/15/2021 - Thursday PTW, JSA with SLB coil, Cruz crane op, YJOS tool hand, and HAK Representative. Pick injector head. Stab 30' lubricator. Make up milling BHA on 1.75" Coil . Pressure test MHA 250/4500 psi. make up motor and mill 2.725" Taper mill with 1 centeral down jet. BHA 30.2' Stab on well. Fluid pack reel with dirty diesel. PT lubricator 250/4,000 psi. Bleed down. Open master and swab 23.5 turns. WHP 1700 psi, IA 425 psi, OA 0 psi. RIH. Bleeding down WHP. PU weight at 14,750', 35K. RIH WT 25K. RIH dry tag @ 14,914' CTMD. Pick up online with pump down CT. 3600 psi circ pressure at 1.4 bbls/min. RIH turning mill tag and stall at 14,910.347' . PU clean. Attempt to work mill through PX plug sub. Not able to make any footage. Max coil depth 14,910.85' CTMD. POOH. Tagged up. Close master and swab 23.5 turns. Blow down stack. Pop off well. Break down MHA. No marks on cut-rite. No wear marks on mill at all. With only down jet its possible mill was hydraulic-ing bit out of hole. Rack back injector head. Discuss with town the possibility of packing seals from PX plug on top of PX equalizing prong sub. Decision to run Ventrui Junk basket below mill. Location secure. Send 24 hour BOPE test witness notification for 7 day BOPE test. 07/16/2021- Friday PTW, JSA. Rig up to perform BOPE test. 24 Hr BOPE test witness notification sent 7/15/21 @ 1953 hrs. Witness waived by Jim Regg 7/15/21 @ 2200 hrs. Test BOPE 250/4,500 psi. Good BOPE test. Shut down. Decision to wait for Baker coil tools. Call out slick line to see if PX plug packing can be removed from above PX plug equalizing sub (fish). Back out Cruz crane and move in field triplex and bleed down tank. Rih w/ 2.5'' cent. w/ 1-1/4'' x 15'' prong to 15,804'kb tag no obstruction pooh, no obstruction Pushed PX plug EQ port to bottom. Ooh rig down slickline. Test BOPE 250/4,500 24 Hr BOPE test witness notification sent RIH turning mill tag and stall at 14,910.347' _____________________________________________________________________________________ Updated by DMA 07-29-21 SCHEMATIC Beaver Creek Unit Well: BCU 04RD Completed: 7/01/2021 PTD: 219-011 API: 50-133-20239-01-00 JEWELRY DETAIL No. Depth ID OD Item 18’ Cactus tubing hanger 2,446’ GLM #1 (dummy) 4,392’ GLM #2 (dummy) 5,881’ GLM #3 (dummy) 7,009’ GLM #4 (dummy) 1 7,453’ Chemical injection mandrel 7,797’ GLM #5 (dummy) 8,403’ GLM #6 (dummy) 9,006’ GLM #7 (dummy) 9,607’ GLM #8 (dummy) 10,213’ GLM #9 (dummy) 10,818’ GLM #10 (dummy) 2 10,903’ 2.813 4.300 Sliding sleeve 3 10,952’ 4.750 7.660 6” anchor latch seal assembly inside 5” tieback sleeve 4 10,954’ 5.000 8.250 5.5 x 9.625” 10k D&L permanent hydraulic packer 5 10,991’ 7” Liner Top Packer (behind 5.5” flush joint casing) 5.1 11,128’ 7.000 7” Swell Packer 6 13,790 2.813 4.490 3.5” X Nipple 7 13,793 3.990 5.870 5.00” 16ft SBR w snap latch seal bore 8 13,809 3.990 5.875 4.5 x 7” 10k D&L permanent hydraulic packer 9 13,852 2.813 4.510 3.5” X Nipple 10 13,885 2.992 3.654 5.90” OD fluted overshot 11 14,883’ 4.000 6.000 5.000” anchor latch w 3’ seals / 5.000” SBR 12 14,888’ 4.000 5.875 Tripoint 7” 26-32# Permanent Liner Top Packer 13 14,961’ 2.813 4.500 3.5 X Nipple 14 14,973’ 4.000 5.750 10’ Baker Seal Bore with seals removed 15 14,974’ 5.750 4-1/2” Liner Top Packer w Tieback SBR 16 15,067’ Water Swell Packer 17 15,810’ Interwell 270-450 HPHT RBP Plug (7/16/19) PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Status Date Tyonek G1B 15,216 15,234’ 14,419’ 14,433’ 18’ Open 7/17/2019 Hemlock 15,900’ 15,933’ 14,984’ 15,013’ 33’ Isolated w/ plug 7/16/2019 7/11/2019 West Foreland 16,408’ 16,474’ 15,430’ 15,491’ 66’ Isolated w/ plug 7/16/2019 7/02/2019 CASING DETAIL Size Type Wt Grade Conn. Drift ID Top Btm 20” Conductor 94 H-40 N/A Surface 288’ 13-3/8” Surface 72 N-80 12.415 Surface 2,989’ 9-5/8" Production 47 53.5 N-80,S-95 P-110 8.681 8.535 Surface 9,938’ 9,938’ 12,521’ 7" CSG 29 P-110 IC/TXP BTC 6.059 11,100’ 15,193’ 4-1/2" Liner 12.6 L-80 DWC/C 3.833 14,974’ 16,607’ CASING/LINER PATCH DETAIL 5-1/2” Patch 23 P-110 EZGO FJ3 4.545 10,959’ 13,780’ TUBING DETAIL 3-1/2” Tubing 9.3 P-110 8RD EUE 2.867 Surface 10,954’ 3-1/2” Tubing 9.3 P-110 8RD EUE 2.867 13,320’ 14,978’ P7 -b Z-110110 Reqq, James B (CED) From: Rance Pederson - (C) <rpederson@hilcorp.com> Sent: Friday, July 2, 2021 8:31 PM To: Regg, James B (CED); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (CED); Wallace, Chris D (CED) Cc: Jake Flora - (C); Michael Morgan; Mike Chivers; Chris Walgenbach; Chad Johnson Subject: Hilcorp Rig 169 MIT Test Report Attachments: Hilcorp 169 MIT 07-02-21.xlsx; BCU-04RD RWO MIT -T and MIT -IA Chart.pdf Please see the attached MIT form and chart for BCU-04RD. Rance Pederson Drilling Foreman Beaver Creek Unit 907-776-6776 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.reoo(Malaska.00v: AOGCC.Inspectors0alaska.cow Phoebe. brooks0alaska.0ov OPERATOR: Hilcorp Alaska LLC FIELD / UNIT / PAD: Beaver Creek Unit / Pad 4 DATE: 06-30-21 and 07-02-21 OPERATOR REP: Pederson / Riley AOGCC REP: Well BCU-04RD Pressures: Pretest PTD 219-011 Type Inj N Tubing 0 Packer TVD 10,914' BBL Pump 1.8 - IA Test psi 4300. BBL Return 1.5 OA Notes: Tested 3 1/2" tubing on 6-30-21 Sundry #321-235 Well BCU-04RD Pressures: Pretest PTD 219-011, Type Inj N Tubing Packer TVD 10,914'- BBL Pump 7.7 - IA 0 Test psi 2000 - BBL Return 7.4 - OA Notes: Tested 3 1/2" x 9 5/8" IA on 7-2-21 Sundry #321-235 ✓ Well Pressures: Pretest PTD Type Inj Tubing Packer TVD BBLPumpj IA Test psi BBL Return OA Notes: Well Pressures: Pretest PTD Type Inj Tubing Packer TVD BBI -Pump IA Test psi BBL Return OA Notes: Well Pressures: Pretest PTD Type Inj Tubing Packer TVD BBI -Pump IA Test psi BBL Return OA Notes: Well Pressures: Pretest PTD Type Inj Tubing Packer TVD BBL Pump IA Test psi BBL Return OA Notes: Well Pressures: Pretest PTD Type Inj Tubing Packer TVD BBL Pump IA Test psi BBL Return OA Notes: Well Pressures: Pretest PTD Type Inj Tubing Packer TVD BBL Pump IA Test psi BBL Return OA Notes: TYPE INJ Codes W = Water G=Gas S = Slurry I = Industrial Wastewater N = Not Injecting Form 10-426 (Revised 01/2017) chris. wallace�(cbaalllaaska, gov Initial 15 Min. 30 Min. 45 Min, 60 Min. 4313, 1 4309- 4307 Type Test P Interval I Result P Initial 15 Min. 30 Min. 45 Min. 60 Min. Type Test P 2015 - 2000 2000 Interval I Result P Initial 15 Min. 30 Min. 45 Min. 60 Min. Type Test Interval Result Initial 15 Min. 30 Min. 45 Min. 60 Min. Type Test Interval Result Initial 15 Min. 30 Min. 45 Min. 60 Min. Type Test Interval Result Initial 15 Min. 30 Min. 45 Min. 60 Min. Type Test Interval Result Initial 15 Min. 30 Min. 45 Min. 60 Min. ype Test Interval Result Initial 15 Min. 30 Min. 45 Min. 60 Min. Type Test -�� Interval Result TYPE TEST Codes INTERVAL Codes P = Pressure Test 1 = Initial Test O = Other (describe in Notes) 4 = Four Year Cycle V = Required by Variance O = Other (describe in notes) Hilcorp 169 MIT 07-02-21 Result Codes P=Pass F = Fail I =Inconclusive 1 McLellan, Bryan J (CED) From:McLellan, Bryan J (CED) Sent:Monday, June 28, 2021 2:43 PM To:Jake Flora - (C) Subject:RE: BCU-04rd negative test (PTD 219-011) (Sundry 321-235) Thanks Jake. You have approval to proceed with the changes outlined below. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250‐9193 ‐‐‐‐‐Original Message‐‐‐‐‐ From: Jake Flora ‐ (C) <Jake.Flora@hilcorp.com> Sent: Monday, June 28, 2021 2:07 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: RE: BCU‐04rd negative test (PTD 219‐011) (Sundry 321‐235) Bryan, After setting the upper packer, we will install and test the tree prior to circulating the well from 12.5ppg mud to water. Thanks, Jake Flora ‐‐‐‐‐Original Message‐‐‐‐‐ From: Jake Flora ‐ (C) Sent: Friday, June 25, 2021 6:14 PM To: McLellan Bryan <bryan.mclellan@alaska.gov> Subject: BCU‐04rd negative test (PTD 219‐011) (Sundry 321‐235) Hello Bryan, The BCU‐04RD has moved along well. We made it down to the tubing stub and made two external cuts of the 3.5 tubing stub. Per the Contingency A diagram in the Sundry we have ran the overshot and lower packer assembly over the new tubing stub depth of 13,901’, and are currently laying down drill pipe in preparation to run the upper completion including the seal assembly, 5.5” flush joint, and upper 9‐5/8 packer. The sundry has us running the upper completion, performing a MIT‐T to 4210psi, a MITIA to 2000psi, prior to RDMO. Then the first post rig step is to open the sliding sleeve and displace the well to diesel, and then performing a negative test of the IA and 9‐5/8 packer. 2 In effort to obtain the negative test while the rig is still over the well, after setting the packer, testing the hanger, and Performing the MIT‐T to 4210psi, we are planning on opening the sliding sleeve above the packer (~10,900’) and circulating the IA & TBG to water, and then performing a witnessed negative test. This order will allow us to confirm the straddle packer integrity prior to moving the rig. After the negative test with water passes we plan on displacing the IA to diesel down to the sliding sleeve depth, and then closing the sliding sleeve and MITIA to 2000psi as required by the Sundry. This will ensure there’s no issue w the sliding sleeve prior to moving the rig. Please advise is these timing changes to the program are acceptable. Thanks for your time, Jake Flora 720‐988‐5375 ________________________________ The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. ________________________________ MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg C)(igZCZ1 DATE: 6/27/2021 P. I. Supervisor FROM: Bob Noble SUBJECT: Well Integrity Petroleum Inspector BCU 4RD Hilcorp Alaska LLC PTD 2190110,7Sundry 321-235 6/27 - 6/28/2021: 1 traveled to Hilcorp's Beaver Creek Unit (BCU) to witness MIT -T, r MIT -IA and a negative pressure test on well 4RD. On arrival I met with Hilcorp representative Josh Riley. Josh told me that they were in the process of running in the hole with slickline to set the plug to test against. Slickline set down on something and started out of the hole. When they got out of the hole, they had lost the plug and had not gone to the planned setting depth. A fishing run was rigged up, run in the hole and the plug was found at the sliding sleeve. The plug was grabbed and brought to surface, cleaned, and re -run. Hilcorp could not get past the sliding sleeve with the second attempt. A gauge ring was run and able to pass through the sliding sleeve with it. The slickline operator went back to their shop and got 2 more plugs. Neither plug was able to pass through the sliding sleeve. Hilcorp decided to pull the tubing to figure out why they were not able to get the plug past the sliding sleeve. Summary: No pressure tests were witnessed. Spent 2 days observing unsuccessful V, attempts to set a plug in BCU 4RD with slickline. Attachments: none 2021-0628_WeI 1_1ntegrity_BCU-04RD_bn.docx Page 1 of 1 STATE OF ALASKA Reviewed By:j�-C— OIL AND GAS CONSERVATION COMMISSION P. 1. Supry 21Z -6 Z,-?-( BOPE Test Report for: BEAVER CK UNIT 04RD Comm Contractor/Rig No.: Hilcorp 169 - PTD#: 2190110 ' DATE: 6/6/2021 Inspector Matt Herrera ' Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: Pederson/Riley Rig Rep: Vanevera/Lynch Inspector Type Operation: WRKOV Sundry No: Test Pressures: Inspection No: bopMFH210607183355 Rams: Annular: Valves- MASP: Type Test: [NIT 321-235 ' -- - -- ---- -- Related INo: 25015000- 250/2500 250/5000 " 4210 - ns p TEST DATA MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: Upper Kelly 1 P/F Lower Kelly Visual Alarm Time/Pressure P/F Location Gen.: P Trip Tank P._- - P System Pressure 3025 P Housekeeping: P - Pit Level Indicators P P Pressure After Closure 1550 P " PTD On Location P-- Flow Indicator P P 200 PSI Attained 24 P ' Standing Order Posted P __ Meth Gas Detector P_- " P Full Pressure Attained 103 P " Well Sign P H2S Gas Detector P P Blind Switch Covers: YES P " Drl. Rig _P- MS Misc NA- NA- Nitgn. Bottles (avg): 4@2550-- _-P Hazard Sec. P Check Valve 0 ACC Misc _ 0 NA Misc NA NA FLOOR SAFTY VALVES: BOP STACK: Quantity P/F Upper Kelly 1 P Lower Kelly 1 P Ball Type _ 1 _ P Inside BOP 1 P FSV Misc 0 NA BOP STACK: CHOKE MANIFOLD: Quantity Size P/F Quantity P/F Stripper 0 NA No. Valves 15 - P - Annular Preventer 1- 11" FP Manual Chokes 1 P--- #1 Rams --1 - - 2 7/8" x 5" P - Hydraulic Chokes l P #2 Rams 1Blinds P CH Misc 0 NA #3 Rams 1 2 7/8" x 5" P #4 Rams 0 NA #5 Rams 0 _ NA INSIDE REEL VALVES: #6 Rams 0 NA (Valid for Coil Rigs Only) Choke Ln. Valves 1 3 1/8" P - Quantity P/F HCR Valves 2 -3 1/8-2 1/16 F Inside Reel Valves 0 NA Kill Line Valves 2 -21/16 FP - Check Valve 0 NA BOP Misc 0 NA Number of Failures: 3 '' Test Results Test Time 8 Remarks: High pressure test to 5000 PSI on Rams and Valves. Annular tested to 2500 PSI All PVT and Gas Alarms tested. Annular initially failed was functioned and retested good. Inside Manual Kill initially failed was serviced and functioned and retested good. HCR Choke Failed. New one replaced and retested on 6/7/21 after AOGCC left location. ALASKA OIL AND GAS CONSERVATION COMMISSION RIG INSPECTION REPORT INSPECT DATE 6/6/2021 P. 1. Supv AOGCC INSPECTOR Matt Herrera Comm: Rig 1169 Coil Tubing Unit? NO Rig Contractor ISaxon - Rig Representative Vanevera/Lynch Operator lHilcorp Alaska LLC Contractor Representative Pederson/Riley Well BCU-04RD Permit to Drill # 2190110 Sundry # 321-235 Operation lWorkover I I Inspection Location I Beaver Creek BOP STACK MUD SYSTEM GLUSING UNIT Working Pressure, W/H Flange P Pit Fluid Measurement P Working Pressure P Working Pressure, BOP Stack P Flow Rate Sensor P Operating Pressure P Annular Preventer P Mud Gas Separator P Fluid Level/Condition P Pipe Rams P Degasser P Pressure Gauges P Blind Rams P Separator Bypass P Sufficient Valves P Locking Devices, Rams P Gas Detectors P Regulator Bypass P Stack Anchored P Alarms Separate/Distinct P Actuators (4 -way valves) P Choke Line P Choke/Kill Line Connections P Blind Ram Handle Cover P Kill Line P Reserve Pits P Control Panel, Driller P Targeted Turns P Trip Tank P Control Panel, Remote P HCR Valve(s) P Firewall P Manual Valves P RIG FLOOR 2 or More Pumps P Flange/Hub Connections P Kelly or TD Valves P Independent Power Supply P Drilling Spool Outlets P Floor Safety Valves P N2 Backup P Flow Nipple P Driller's Console P Condition of Equipment P Control Lines P Flow Monitor P Flow Rate Indicator P CHOKE MANIFOLD MISCELLANEOUS Pit Level Indicators P Valves P PPE P Gauges P Remote Hydraulic Choke P Well Control Trained P Gas Detection Monitor P FOV Upstream of Chokes P Housekeeping P Hydraulic Control Panel P Targeted Turns P Well Control Plan P Kill Sheet Current P Bypass Line P FAILURES: 0 CORRECT BY: COMMENTS Accumulator 2 electric pumps. Hydraulic "Super" Choke electric hydraulic. Gas Alarm System Quadco remote sensors 2021-0606_Rig_Hi1corp169_BCU-4RD_mh rev. 5-16-16 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 Casing Patch 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): 16,642'N/A Casing Collapse Structural Conductor Surface 2,670psi Intermediate Production 4,760psi Liner 8,530psi Liner 7,500psi 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: Jake Flora Operations Manager Contact Email: Contact Phone: 777-8442 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 Authorized Signature: May 25, 2021 jake.flora@hilcorp.com 1,633'4-1/2"15,618'8,430psi 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. Perforation Depth MD (ft): See Attached Schematic 12,521' 7" 16,607' 15,193'4,202' 3-1/2" 14,401' 9-5/8" 20" 13-3/8" 288' 2,989' 288' 2,989' 288' 2,989' 12,357'12,521' 9.3# / P-110 TVD Burst 13,320' - 14,978' 6,870psi MD 5,380psi Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 15,652' 11,009' 10,962' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 219-011 50-133-20239-01-00 Beaver Creek 04RD Beaver Creek Field / Beaver Creek Oil Pool CO 237B COMMISSION USE ONLY Authorized Name: 11,220psi Tubing Grade:Tubing MD (ft): See Attached Schematic ~4,210psi 11009, 12800; 15810 Tri 7" Perm Pkr; 4.5" Liner Top Pkr; Wtr Swell Pkr; N/A 10,991'MD/10,954' TVD; 14,888' MD/14,160' TVD; 14,974' MD/14227' TVD Perforation Depth TVD (ft): Tubing Size: Length Size Perforate Reppair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 7:09 am, May 12, 2021 321-235 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.05.11 15:37:52 -08'00' Taylor Wellman (2143) BJM 5/20/21 MIT-T to 4210+ psi after installing upper completion. MITIA to 2000 psi. AOGCC witness required. BOP test to 4500 psi. Annular preventer test to 2500 psi. X X 10-404 DLB 05/12/2021 Notify AOGCC to witness negative pressure test on production packer. DSR-5/12/21 X Variance to 25.280(b)(4) for alternative MPSP calculation using oil gradient, supported by max observed SITHP of 3060 psi. dts 5/20/2021 JLC 5/21/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.05.21 09:46:33 -08'00' RBDMS HEW 6/2/2021 Well Prognosis Well: BCU-04RD Date: 5-10-21 1 Well Name: BCU-04RD API Number: 50-133-20239-01 Current Status: Oil Well Leg: N/A Estimated Start Date: May 25th, 2021 Rig: 169 Reg. Approval Req’d? 403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777 -8305 Permit to Drill Number: 219-011 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) AFE Number: Maximum Expected BHP: ~9,188 psi @ 14,370’ TVD (12.3 PPG MW to balance well) Max. Potential Surface Pressure: ~4,210 psi (BHP minus 0.346 psi/ft diesel gradient) Current Status SI Producer with a casing leak immediately below the 7” Liner Top Packer. Currently isolated from the leak with a storm packer and cement retainer. Currently isolated from the reservoir with a RBP & tubing tail plug. Brief Well Summary In 2019 BCU-4RD was sidetracked out of the original 9.625” casing and drilled to a depth of 16,642’ MD. After cementing the 4.5” liner in place a casing leak was identified just below the 7” LTP with a noise log and was squeezed with Halliburton Epoxy Resin, successfully stopping the influx. The well was completed in the Tyonek and IP’d at over 900 bopd and produced at this rate until it suddenly went to 100% water just three weeks later. A LDL reconfirmed the leak point and a TTP was set isolating the reservoir. A workover then jet cut and pulled the 3.5” tubing from 13,320’. A RBP was set in the 7” at 12,800’, a 9.625” CIBP at 10,960’, and a kill string to 2700’ before demobing the rig. A second work over was attempted in the spring of 2020 with the goal of cement squeezing the previously identified leak. A negative pressure test confirmed flow still existed, but no injection rate was achievable with the leak slowly bleeding off with 3600psi of applied pressure. It was determined the leak to be one-way and unable to be squeezed with cement. The well was then secured with a storm packer & kill string inside the 9.625” casing, and the rig demobilized. Objective The purpose of this work/sundry is to isolate the leak behind a 5.5” casing patch with packers above and below the leaking 7” LTP. In order to do this, the following will need to be done: 1) Pull the 9.625” storm packer & kill string 2) Drill the 7” LW FasDrill SVB cement retainer at 11009’ & CIBP debris from above the 7” RBP 3) Pull the 7” RBP from 12800’ 4) Engage and evaluate the 3.5” tubing stub 5) Run casing patch & 3 ½” completion: overshot, dual packer casing patch, anchor latch SA, and 3.5” tubing with GLMs Notes Regarding Wellbore Condition x Current Perforations: 15216’ – 15234’ (Tyonek G1B) x 3.5” plug is set in the X-nipple @ 14,932’ (isolating the 4-1/2” liner) x 7” RBP @ 12,800’ (09/06/19) x 7” HES FasDrill CMT Retainer @ 11009’ (03/24/20) Barrier From Water Leak x Kill string @ 3350’, 9-5/8” Storm Packer @ 31’ (3/28/20) Barrier From Water Leak The purpose of this work/sundry is to isolate the leak behind a 5.5” casing patch with packers above and below the leaking 7” LTP. Existing wellbore fluid is 12.5 ppg OBM. Well Prognosis Well: BCU-04RD Date: 5-10-21 2 PROCEDURE MIRU, BOP TEST, PULL STORM PACKER 1. MIRU Hilcorp Rig #169. Notify AOGCC 24 hrs in advance of BOP test. 2. ND Dry Hole Tree. NU 13.625” 3-1/2 x 5-1/2 VBR BOP Stack. 3. Test BOPE to 250 psi Low/ 4,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 10-min). Record accumulator pre-charge pressures and chart tests. a. Confirm test pressures per the Sundry Conditions of Approval b. Notify AOGCC 24hrs in advance of BOP test. c. Perform Test. d. Test VBR rams on 3-1/2” AND 4-1/2” test joints. e. Email completed 10-424 form to all AOGCC addresses listed on the form within 5 days of BOPE test. 4. MU packer retrieval tool to pull Tripoint JS3A retrievable packer with storm valve, engage and release storm packer, check for flow. POOH laying down the 3.5” kill string from 3350’. 5. MU 6” roller cone BHA to drill out the Halliburton 7” Fasdrill Squeeze Packer. TIH to Fasdrill at 11,009’, circulate the wellbore to 12.5 ppg water based mud. Drill out 7” Fasdrill from 11,009’. TOOH. 6. MU Reverse Circulating Junk Basket BHA to clean debris from above the 7” RBP at 12,800’. TIH, circulate debris, TOOH. Repeat until clean. 7. MU Baker RBP Retrieval BHA to pull 7” RBP from 12,800’. TIH, retrieve RBP, TOOH. 8. MU Overshot / Grapple BHA to engage 3 ½” tubing stub. TIH, wash down to stub, engage. 9. RU Slickline. Drift and tag with 1-11/16” bailer. Gauge up to accommodate a 2.5” jet cutter OD. Bail to evaluate fill. RD Slickline. a. If slickline is able to enter the 3 ½” tubing AND large enough for an e-ling cutter, rig up e-line and cut tubing as deep as possible, and recover tubing. b. If slickline is unable to fall in the KWM, displace the inside of the drill pipe to 10.5 ppg NaCL Brine to the overshot depth. RU Slickline Lubricator over TIW valve, test to 3500 psi, and proceed with evaluation runs inside of the drill pipe. 10. MU Wash-over / External Cutter BHA. TIH to tubing stub and wash over and cut as deep as possible. Repeat cutter runs as hole dictates, attempt to remove as much 3 ½” tubing as possible. If all the tubing is successfully removed to the existing anchor latch, run lower completion with snap latch on bottom to engage the existing seal bore. This will only affect the lower completion packer depth. If external cutting is problematic, and some or all of the tubing stub remains in the well, run lower completion with an overshot on bottom to engage the existing tubing stub per the CONTINGENCY A WELLBORE DIAGRAM. Brine density will be closer to 9.8 ppg, max for NaCl. 4.5" 16.6# drillpipe planned Hilcorp Rig #169. Pressure test tubing and IA to confirm plug is holding prior to ND tree. - bjm 4.a. Flow check after releasing packer, before POOH. - bjm RU SL lubricator and Test to 4500 psi before displacing to underbalanced fluid.-bjm displace the inside of the drill pipe to 10.5 ppg NaCL Brine t Pull plug from X-nipple before releasing storm packer to check for pressure and provide circulation path for KWF. - bjm Flow check before POOH. bjm Displace DP to 12.5 ppg KWF before POOH with workstring, while maintaining surface pressure to prevent influx. - bjm Well Prognosis Well: BCU-04RD Date: 5-10-21 3 RUN LOWER COMPLETION, SET PACKER, LDDP 13. Run lower completion: Snap latch locator without seals, full joint 3 ½” tubing, x-nipple ran with RHC plug body, full joint 3 ½” tubing, 4.5x7 packer, 20’ seal assembly, running tool w LH threads, 4.5” DP to surface. APPROXIMATE DEPTHS ARE ON WELLBORE SCHEMATIC. 14. Locate in seal bore with snap latch (or overshot tubing stub), space out TIW on rig floor. 15. RU Slickline. RIH w B&R, set in RHC plug body at x-nipple. 16. Pressure up to ~3000 psi to set lower packer. 17. Pull B&R, RD Slickline. 18. Pressure up to 2500 psi for 30 minutes to test lower packer from below. Bleed off pressure. 19. Rotate to the right, back out of packer running tool LH threads, pull out of running tool. 20. Flow Check. 21. TOOH while LDDP. RUN UPPER COMPLETION, RDMO 22. Notify AOGCC 24hrs in advance of BOP test. Change out upper BOP rams to 5 ½” pipe rams & test same. 23. Run upper completion: 20’ seal-bore, 5.5” FJ casing, 9.625” packer, anchor latch, sliding sleeve, 3.5” tubing with dummied GLMs & control line to chem mandrel. 24. Sting into SA, space out, MU hanger, landing joint. 25. MU TIW on landing joint, RU to pump brine. (Brine will allow slickline tools to open sleeve post rig) 26. Displace inside of completion to 11,000’ to 10.5# brine (below sliding sleeve) (~96 bbls). Will have ~1400 psi differential left on tubing. 27. Land hanger & seal assembly, RILDS, test packoff . 28. Pressure up to ~4000 psi to set upper packer (the well is plugged off downhole). 29. Bleed pressure to 0 psi, conduct 30 minute negative test (tests seal-bore seals). 30. MITIA 3-1/2 x 9-5/8 annulus to 1500 psi for 30 minutes, chart and record. 31. Set TWC in tubing hanger. 32. ND BOP, NU tree & test. 33. Pull TWC. 34. RDMO Rig 169. POST RIG 1. MIRU slickline, PT Lubricator 250 / 3500 psi. 2. RIH, pull RHC plug body from x-nipple. RIH, open sliding sleeve. Notify AOGCC to witness. - bjm Negative differential pressure based on difference in hydrostatic pressure tbg x IA.Last MITIA was to 2200 psi on 6/22/19 One set of rams must be sized for 3.5" tubing. This test does not confirm that the 9-5/8" packer is holding since the leak is a one-way leak. It will be negative tested post rig after circulating IA to diesel. MIT-T to 4210+ psi for 30 min. AOGCC witness. - bjm 2000 psi Well Prognosis Well: BCU-04RD Date: 5-10-21 4 3. Reverse in 800 bbls diesel. This will diesel pack the IA and tubing from the SS depth to surface. 4. RIH, close sliding sleeve. RDMO slickline. 5. Conduct negative test on straddle packers, monitor well for 60 minutes. 6. MIRU Coiled Tubing, PT BOPE to 4,500 psi Hi 250 Low. Notify AOGCC 24 hrs. in advance of BOP test. 7. Clean out to catcher sub at 14,926’ and retrieve same. 8. Pull and retrieve prong from 14,961’, retrieve PX plug from same. 9. RDMO Coiled Tubing. 10. RU slickline, run live GLV’s. 11. Return to production. Attachments 1. Current Schematic 2. Proposed Schematic with Snaplatch 3. Proposed Schematic with Overshot (CONTINGENCY A) 4. BOPE Schematic 5. Current Wellhead Schematic 6. Proposed Wellhead Schematic 7. Blank RWO Procedure Change Form This will test the 9-5/8" packer. Notify AOGCC to witness test. _____________________________________________________________________________________ Updated by JMF 03-09-21 SCHEMATIC Beaver Creek Unit Well: BCU 04RD Completed: 6/22/2019 PTD: 219-011 API: 50-133-20239-01-00 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Status Date Tyonek G1B 15,216 15,234’ 14,419’ 14,433’ 18’ Isolated w/ plug 9/6/2019 7/17/2019 Hemlock 15,900’ 15,933’ 14,984’ 15,013’ 33’ Isolated w/ plug 7/16/2019 7/11/2019 West Foreland 16,408’ 16,474’ 15,430’ 15,491’ 66’ Isolated w/ plug 7/16/2019 7/02/2019 TD =16,642’(MD) / TD = 15,652’(TVD) 20”00 KB Elev.: 166.2’/ BF/GL Elev.: 148.2’ 9 5/8 CIBP Debris 40’ sand cap 7” RBP @ 12,800’ PBTD = 10,960’ (MD) / PBTD = 10,916’ (TVD) 13-3/83”88 5 11 4-44 1/2” 1 4 Heml ock West Forelands 6 8 10 7” @ 15,193’ tbg stub @13,320’ 9/2/19 2 7 9 3 9 5/8” TOW 11,356’ 7” TOC @ 12,767’ tbg punch holes 13511’, 13836’ CS @ 14,926’ (8/21/19) PX @ 14,961’ (8/6/19) 15216 – 15234’ Tyonek G1B 15322’ 4-1/2” TOC 7”FasDrill @ 11,009’ tbg punch: 11,018’ suspected fill Leak @ 11,021’ HPW @ 14,985’ – 15,155’ CASING DETAIL Size Type Wt Grade Conn. Drift ID Top Btm 20” Conductor 94 H-40 N/A Surface 288’ 13-3/8” Surface 72 N-80 12.415 Surface 2,989’ 9-5/8" Production 47 53.5 N-80,S-95 P-110 8.681 8.535 Surface 9,938’ 9,938’ 12,521’ 7" CSG 29 P-110 IC/TXP BTC 6.059 11,100’ 15,193’ 4-1/2" Liner 12.6 L-80 DWC/C 3.833 14,974’ 16,607’ TUBING DETAIL 3-1/2” Tubing 9.2 L-80 8RD EUE 2.867 Surface 3,350’ 3-1/2” Tubing 9.3 P-110 8RD EUE 2.867 13,320’ 14,978’ JEWELRY DETAIL No. Depth ID OD Item 1 ~31’ Tri Point JS3A Retrievable Storm Packer 2 X-Nipple w Plug 3 10,991’ 7” Liner Top Packer 4 11,128’ Water Swell Packer (elements stripped) 5 12,800’ 6.059” 7” Baker Hughes Model G RBP (9/6/19) 6 14,888’ 4.0” 5.875” Tripoint 7” 26-32# Permanent Pkr 7 14,961’ Pollard PX Plug w/top load bottom w/ 2.50” SB w/ 2.75 Prong, 59” LDA-3X 2.25” Rollers (bottom roller on prong) 8 14,973’ Baker Seals (w/rubbers removed) 9 14,974’ 4-1/2” Liner Top Packer 10 15,067’ Water Swell Packer 11 15,810’ Interwell 270-450 HPHT RBP Plug (7/16/19) _____________________________________________________________________________________ Updated by JMF 05-10-21 PROPOSED Beaver Creek Unit Well: BCU 04RD Completed: 6/22/2019 PTD: 219-011 API: 50-133-20239-01-00 JEWELRY DETAIL No.Depth ID OD Item 1 ~7,450 2.920 5.375 Chemical injection mandrel 2 ~10,915’2.813 Sliding Sleeve 3 ~10,945’ 4.750 7.660 6” anchor latch seal assembly inside 5” tieback sleeve 4 ~10,950’5.000 8.125 5.5 x 9.625” 10k D&L permanent hydraulic packer 5 10,991’ 7” Liner Top Packer 6 11,128’Water Swell Packer 7 ~14,800’4.000 5.870 5.5”seal bore receptacle (20’) 8 ~14,820’4.000 5.870 4.5 x 7” 10k D&L permanent hydraulic packer 9 ~14,850’2.813 4.510 3.5” X Nipple 10 ~14,883’2.992 3.654 5.000”snap latch SA 11 14,883’4.000 6.000 5.000” seal bore receptacle (4.45’) 12 14,888’ 4.000 5.875 Tripoint 7” 26-32# Permanent Liner Top Packer 13 14,961’2.813 4.500 3.5 X Nipple 14 14,973’ 4.000 5.750 10’ Baker Seal Bore with seals removed 15 14,974’5.750 4-1/2” Liner Top Packer w Tieback SBR 16 15,067’Water Swell Packer 17 15,810’Interwell 270-450 HPHT RBP Plug (7/16/19) PERFORATION DETAIL Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Status Date Tyonek G1B 15,216 15,234’ 14,419’ 14,433’ 18’Isolated w/ plug 9/6/2019 7/17/2019 Hemlock 15,900’ 15,933’ 14,984’ 15,013’ 33’Isolated w/ plug 7/16/2019 7/11/2019 West Foreland 16,408’ 16,474’ 15,430’ 15,491’ 66’Isolated w/ plug 7/16/2019 7/02/2019 TD = 16,642’ (MD) / TD = 15,652’ (TVD) 20”00 KB Elev.:166.2’/ BF/GLF Elev.:148.2’ 7” TOC @ 12,767’ PBTD = 10,960’ (MD) / PBTD = 10,916’ (TVD) 13- 8 17 4-1/2” 1 6 Heml ock West Forelands 11 14 16 7” @ 15,193’77 tbg stub @13,320’ 9/2/19 2 13 15 5 9-5/8 TOW @ 11,356’ tbg punch holes 13511’, 13836’ CS @ 14,926’ (8/21/19) PX @ 14,961’ (8/6/19) 15216 – 15234’ Tyonek G1B 15322’ 4-1/2” TOC tbg punch: 11,018’ leak @ 11,021’ 3 9 10 7 4 12 Leak @ 11,021’ HPW @ 14,985’ – 15,155’ CASING DETAIL Size Type Wt Grade Conn.Drift ID Top Btm 20”Conductor 94 H-40 N/A Surface 288’ 13-3/8”Surface 72 N-80 12.415 Surface 2,989’ 9-5/8" Production 47 53.5 N-80,S-95 P-110 8.681 8.535 Surface 9,938’ 9,938’ 12,521’ 7"CSG 29 P-110 IC/TXP BTC 6.059 11,100’15,193’ 4-1/2"Liner 12.6 L-80 DWC/C 3.833 14,974’16,607’ CASING PATCH DETAIL 5-1/2”Patch 23 P-110 EZGO FJ3 4.545 ~10,950’~14,800’ TUBING DETAIL 3-1/2”Tubing 9.3 P-110 8RD EUE 2.867 Surface ~10,945’ 3-1/2”Tubing 9.3 P-110 8RD EUE 2.867 13,320’14,978’ 8-10 Gas Lift Mandrels will be run from ~2,000’ – 10,900’, exact depths TBD _____________________________________________________________________________________ Updated by JMF 05-10-21 PROPOSED Contingency A Beaver Creek Unit Well: BCU 04RD Completed: 6/22/2019 PTD: 219-011 API: 50-133-20239-01-00 JEWELRY DETAIL No.Depth ID OD Item 1 ~7,450 2.920 5.375 Chemical injection mandrel 2 ~10,915’2.813 Sliding sleeve 3 ~10,945’ 4.750 7.660 6” anchor latch seal assembly inside 5” tieback sleeve 4 ~10,950’5.000 8.125 5.5 x 9.625” 10k D&L permanent hydraulic packer 5 10,991’ 7” Liner Top Packer 6 11,128’Water Swell Packer 7 ~13,245 4.000 5.870 5.5” SBR 8 ~13,250 4.000 5.870 4.5 x 7” 10k D&L permanent hydraulic packer 9 ~13,285 2.813 4.510 3.5” X Nipple 10 ~13,320 2.992 3.654 5.90” OD fluted overshot 11 14,883’4.000 6.000 5.000” anchor latch w 3’ seals / 5.000” SBR 12 14,888’ 4.000 5.875 Tripoint 7” 26-32# Permanent Liner Top Packer 13 14,961’2.813 4.500 3.5 X Nipple 14 14,973’ 4.000 5.750 10’ Baker Seal Bore with seals removed 15 14,974’5.750 4-1/2” Liner Top Packer w Tieback SBR 16 15,067’Water Swell Packer 17 15,810’Interwell 270-450 HPHT RBP Plug (7/16/19) PERFORATION DETAIL Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Status Date Tyonek G1B 15,216 15,234’ 14,419’ 14,433’ 18’Isolated w/ plug 9/6/2019 7/17/2019 Hemlock 15,900’ 15,933’ 14,984’ 15,013’ 33’Isolated w/ plug 7/16/2019 7/11/2019 West Foreland 16,408’ 16,474’ 15,430’ 15,491’ 66’Isolated w/ plug 7/16/2019 7/02/2019 TD =16,642’ (MD) / TD = 15,652’ (TVD) 20” KB Elev.: 166.2’/ BF/GL Elev.: 148.2’ 7” TOC @ 12,767’ PBTD =10,960’ (MD) / PBTD = 10,916’ (TVD) -3/8”88 8 17 4-1/2” 1 6 Heml ock West Forelands 11 14 16 7” @ 15,193’77 tbg stub @13,320’ 9/2/19 2 13 15 5 9-5/8 TOW @ 11,356’ tbg punch holes 13511’, 13836’ CS @ 14,926’ (8/21/19) PX @ 14,961’ (8/6/19) 15216 – 15234’ Tyonek G1B 15322’ 4-1/2” TOC tbg punch: 11,018’ leak @ 11,021’ 3 9 10 7 4 12 Leak @ 11,021’ HPW @ 14,985’ – 15,155’ CASING DETAIL Size Type Wt Grade Conn.Drift ID Top Btm 20”Conductor 94 H-40 N/A Surface 288’ 13-3/8”Surface 72 N-80 12.415 Surface 2,989’ 9-5/8" Production 47 53.5 N-80,S-95 P-110 8.681 8.535 Surface 9,938’ 9,938’ 12,521’ 7"CSG 29 P-110 IC/TXP BTC 6.059 11,100’15,193’ 4-1/2"Liner 12.6 L-80 DWC/C 3.833 14,974’16,607’ CASING PATCH DETAIL 5-1/2”Patch 23 P-110 EZGO FJ3 4.545 10,950’13,245’ TUBING DETAIL 3-1/2”Tubing 9.3 P-110 8RD EUE 2.867 Surface ~10,945’ 3-1/2”Tubing 9.3 P-110 8RD EUE 2.867 13,320’14,978’ The lower completion including 5.5” SBR, 4-1/2” x 7” packer, x-nipple, and overshot depth will adjust accordingly based on tubing recovery efforts and ultimate tubing stub depth. 8-10 Gas Lift Mandrels will be run from ~2,000’ – 10,900’, exact depths TBD 4.5" pipe rams 2-7/8" x 5" VBR 2-7/8" x 5" VBR will be changed to a 5-1/2" pipe ram prior to running casing patch Superseded Need one set of blind rams CURRENT WELLHEAD DIAGRAM Beaver Creek Field BC #4RD 05/07/2021 Tubing head, FMC-TC-BG, 13 5/8 5M x 11 5M, w/ 2- 2 1/16 5M SSO Valve, Master, CIW-FLS, 3 1/8 5M FE, HWO, EE trim BHTA, Otis, 3 1/8 5M FE x 6.5'’ Otis quick union top 20'’ 9 5/8'’ Starting head, OCT-C22, 21 1/4'’ 2M x 20'’ SOW, w/ 2- 2 1/16 5M EFO Casing spool, OCT- C-22-BP- OO, 21 ¼'’ 2M x 13 5/8 5M, w/ 2- 2 1/16 5M SSO Beaver Creek BC #4RD 20 x 13 3/8 x 9 5/8 Adapter, FMC-A5P-CCL, 11 5M stdd x 3 1/8 5M, w/ 2- 1'’ npt control line exits 13 3/8'’ Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well BC-04RD (PTD 219-011) Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Asset Team Operations Manager Date Prepared: First Call Operations Engineer Date 2-7/8" x 5" VBR blind rams 2-7/8" x 5" VBR The upper VBR will be changed to a 5-1/2" pipe ram prior to running casing patch Proposed Rig 169 BOP 05-20-2021 BCU 04RD SHLBCU 12BEAVERCREEK UNITS007N010WBCU Pad 43433Beaver Creek UnitBCU 04RD660 ft Radius from SHL0150300FeetBCU 04RD Surface Well LocationBCU 04RD 660ft Radius BufferOil and Gas Unit BoundaryBCU Pad 3BCU Pad 1ABCU Pad 7BCU Pad 4BCU Pad 2BEAVER CREEK UNITBCU 4RD_SHL1 inch = 150 feetMap Date: 5/17/2021 Schwartz, Guy L (CED) From: Schwartz, Guy L (CED) Sent: Thursday, March 19, 2020 9:45 AM To: 'Ted Kramer' Cc: Donna Ambruz Subject: RE: BCU-04RD Remedial Repair Sundry -Updated- 3-18-20 PTD 219-011, Sundry # 320-056 Ted, You have approval to modify the sundry for BCU 4 RD as proposed. Update MOC as needed. Please keep me informed as you progress with the RWO with updates. Especially if the cmt squeeze is not successful and you need to run 7" tieback. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska aov). From: Ted Kramer <tkramer@hilcorp.com> Sent: Wednesday, March 18, 20201:53 PM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: BCU-04RD Remedial Repair Sundry -Updated- 3-18-20 PTD 219-011, Sundry # 320-056 Guy, Attached is an updated procedure for the BCU 4RD well workover. . We are currently on this well. The changes are in red on the attached copy. The reason for the changes are that we wanted to move the cement retainer above the Liner Hanger equalization ports in case they are leaking. This way it is a down squeeze through the retainer and we do not run the risk of getting cement behind us. Secondly, we are moving the test packer for performing the negative Test (post Squeeze) out of the liner top packer assembly and up into the 9-5/8" casing just above the liner top. This will accomplish the same test but will allow us to run the packer and not have to log it on depth. Please let me know if the AOGCC is in agreement with these changes. Status update: We have built our 12.7 PPG OEM mud system and are preparing to drill out the CIBP @ 10,960'. Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp-Alaska LLC Office — 907-777-8420 Cell— 985-867-0665 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. H Hllarey Alaska. LG Well Prognosis Well: BCU-04RD Date: 3-18-20 Well Name: BCU-04RD API Number: 50-133-20239-01 Current Status: Oil Well Leg: N/A Estimated Start Date: February 27, 2020 Rig: 169 Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-011 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) Second Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (M) AFE Number: Maximum Expected BHP: 9,188 psi @ 14,370' TVD (12.3 PPG MW to balance well) Max. Potential Surface Pressure: —4,210 psi (0.346 psi/ft diesel gradient) Brief Well Summary The BCU 4RD was sidetracked out of the BCU 4 well bore and drilled to a depth of 16,642' MD. A casing leak was identified during the original completion (June 2019) and was squeezed with Halliburton Resin. The well was completed and IP'd at over 900 bopd and produced at this rate until it suddenly went to 100% water in July of that year. A noise log identified a casing leak at 11,021' (depth squeezed with resin). A work over was attempted in fall of 2019. The goal was to identify the circumstances of the leak and repair if possible. During this workover the 3-1/2" tubing was cut at 13,320' and removed to that depth. An RBP was set in the 7" at 12,800' to isolate the deeper hole from the leak. After running diagnostics on the leak, it was determined that the correct materials to affect a repair were not available so a 9-5/8" CIBP was set at 10,960' to isolate the leak from the upper portion of the well and the rig was demobed. The purpose of this work/sundry is to repair the casing leak and return this well to production. In order to do this, the following will need to be done: 1) Shut off a water influx through a leak below the 7" liner hanger at 11,021' MD with a Cement Squeeze or by running a 7" tieback. 2) Remove the remaining 3-1/2" production TBG string. 3) Swap to Oil Based Mud. 4) Burn over and remove a Permanent Packer @ 14,888'. 5) Run anew completion. Note: After the cement squeeze is performed, it will be tested with a negative test. If the results are not favorable, the 7" liner top packer will be removed and a 7" Tieback will be ran and cemented in place. Notes Regarding Wellbore Condition BC 4RD has been perforated at 15,216' MD. A 7" X 3-1/2" permanent packer is is set at 14,888' with 3-1/2" tubing stub in a rotating latch assembly above it up to 13,320'. A plug is set in the X -nipple below the 7" permanent packer at 14,932'. This plug and packer isolate the 4-1/2" liner. A 7" RBP is set at 12,800' MD. N Hil.m Alaska, LL A 9-5/8" CIBP is set at 10960' MD. A 3-1/2" Kill string is set with bottom of TBG at 10,793' MD. Saxon #169 Procedure 1. MIRU Hilcorp Rig #169. Well Prognosis Well: BCU-04RD Date: 3-18-20 2. Test BOPE to 250 psi Low/ 4,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 10 -min). Record accumulator pre -charge pressures and chart tests. a. Confirm test pressures per the Sundry Conditions of Approval b. Perform Test. c. Notify AOGCC 24 hrs in advance of BOP test. d. Test VBR rams on 3-1/2" and 4-1/2" test joints. e. Email completed 10-424 form to all AOGCC addresses listed on the form within 5 days of BOPE test. 3. L/D BOP test equipment. 4. Check Well pressures. Note: The well is isolated by the 9-5/8" CIBP at 10,9601 . S. POOH laying down the 3-1/2" TBG (kill string). 6. PU BHA #1, 8-1/2" Bit and work string (singles), TIH to the top of the CIBP. Circulate 12.7 ppg kill mud to surface. 7. Drill out the 9-5/8" CIBP and clean out to the top of the 7" Liner hanger at 10,991' MD. Circulate and condition hole. TOOH. 8. PU BHA #2 - 6" bit and work string. TIH and clean out to 11,800' (1000' above the 7" RBP). Circulate and condition the well to KWM (12.7 ppg). POOH Racking Back Work string. Lay down Bit. 9. RIH with open ended work string and wireline guide shoe and set at 11,000' MD. RU E -Line, pressure test the lubricator 250 psi low/4,500 psi high, RIH to 11,023' with 2-1/8" tubing punches. Pressure up on well to 500 psi. Punch the 7" casing from 11,023' up to 11,015' (+/-) with tubing punches 0 degree phasing. POOH W/e-line. (Note: Could be Multiple Runs.) 10. Monitor the well for Pressure change. Re -balance MW to balance well. POOH. 11. PU 7" CMT retainer on a -line and RIH to 11,009'. (Note: Log on depth to set Retainer in Pup joint ✓ above Liner Hanger dogs.) Set retainer. POOH W -e -line. 12. RIH W/ Retainer stinger on 4-1/2" work string to right above the Cement Retainer. Circulate diesel down tbg to stinger. Stab into stinger, Flow well up tubing to tank catching diesel for future use. Back flow well two tubing volumes to tank (approx. 300 bbis). 13. Perform PIR Using water. 14. Un -sting from retainer, back flow water to tank and circulate well back to KWM. 15. RU Cementers and pressure test lines. Circ cement down to stinger, Stab into CMT retainer, and squeeze well with 70 barrels of cement (+/-) placing as much cement as possible behind pipe. 16. Un -sting from retainer and p ace 10' of cement on top of retainer. Pick up two joints and reverse out excess cement to tank. W C. Note: We will be real close to the transition zone back to 9-5/8" casing. Dumping too much cement on top of the retainer will cause us to have to drill up cement in the 9-5/8" casing prior to drilling in the 7" (additional run). 17. PU BHA #3, 6" bit. RIH to TOC and drill out cement squeeze. CBU. Close backside and pressure test to 2,000 psi for 30 min. on chart. Bleed off pressure. POOH W/bit. 18. PU 9-5/8" Test pkr. RIH to just above the Liner top packer (10,990' +/-). 19. Circ. diesel down to test pkr. Set same. Open well to flow back tank and perform negative test on cement squeeze. n Hilcocn Alaaka, LU Well Prognosis Well: BCU-04RD Date: 3-18-20 Note: Decision point- If the negative test is good, go to step 28. If negative test is bad (flow), then decide on re -squeeze or go to step # 20. 20. PU BHA #3, 8-1/2" Pilot mill. RIH on Work string to TOL @ 11,100'. Establish parameters, Mill up Baker ZXHD Liner top packer (+/- 17') according to fishing company's measurements. CBU POOH with pilot mill. 21. RU E -line, Pressure test lubricator to 250 psi low/3,000psi high. PU 7" Jet Cutter. RIH to 11,030' (+/-) and cut 7" casing below casing punches. 22. PU BHA #4— MU Spear/ Jar assembly, RIH and spear liner hanger @ 11,118' (+/-), pull / Jar Liner hanger out of well. Note: If Liner top Hanger will not pull, POOH, PU Pilot Mill and mill up Liner top hanger past tubing punches to 11,030'. 23. PU BHA # 5 — MU Polish mill. RIH to top of 7" casing (11,030'+/-) and dress off Stub. POOH With Polish Mill. 24. Make Wellhead modifications to allow for 7" tieback. Note: Wellhead will be set up according to Wellhead technician's procedure. Once the 7" is landed and hung off, a pack off will be set and the void space tested to 5,000 psi. 25. Test BOP rams on 7" Test joint. 26. PU BHA #6 — Casing Patch overshot W/ cementing tools on 7" 29" P-110 HC casing. Single in the well and over shot the 7" casing stub @ 11,130' (+/-). Shift cementing tool and prep to pump Cement. 27. RU Cementing services. Pressure test lines and pump cement according to Cementing Companies' procedure. Clean up cementing truck and RDMO Cementers. WOC. 28. BHA # 7 — PU 6" Bit, RIH on Work string and drill out cement to 11,150'. CBU, POOH W/ Bit. 29. RU E -line, Pressure test lubricator to 250 psi low/3,OOOpsi high. RIH W/ CBL to 11,140'. Run CBL F/ 11,140' up to 2,989' or TOC. POOH With E -line. 1� y3Q. MU BHA #8 — Reverse Circulating Junk Basket (RCJB) RIH to 12,800' to remove debris and sand from n l` top of RBP. POOH. l k'`iJ 31. MU BHA #9 — RBP Retrieving Tool. RIH to 12,800' and latch and Pull RBP. POOH W/ Same. 32. MU BHA #10—Ocean Wave Shoe and 1 joint of wash pipe and 5-3/4" OS. RIH to TOF @ 13,320'. Slip over TOF and lower to engage OS. (Note: If fill is encountered, then wash down to engage TOF W/ OS) Note: This area of the production tubing was subjected to the greatest amount of buckling in the tubing move simulations. It could be that this buckling and not fill prevented the cutter from getting deeper to make the cut. Some diagnostics here are warranted to determine if fill is actually present. 33. RU E -line, Pressure test lubricator to 250 psi low/3,000psi high. RIH W/ GR and see if we can get inside of Fish and how deep. POOH. Note: MASP is now lower because casing leak has now been repaired. 34. Kick on pump and step up in 500 psi increments to 2,500 psi and attempt to break circulation through tubing punch holes @ 13,501' (from previous workover). Note: OS sealing rubber is rated to 3,000 psi. 35. Attempt to PU and rotate pipe out of Rotating latch. If successful POOH W/pipe and go to step 42. Otherwise, go to next step. 36. RU Coil tubing Unit. Pressure test BOP to 250 psi low/ 3500 psi high RIH W/ jet nozzle on 1.75" coil string. Clean out 3-1/2" tubing from 13,320' to 14,888' (1,568'). POOH W/ Coil. 37. RU E -line, Pressure test lubricator to 250 psi low/3,OOOpsi high. PU RIH W/ Cutter to 14,879' (3' above pup joint lower connection). Pull tension into pipe and make cut. POOH W/ E -line. And stand back. Well Prognosis Well: BCU-04RD Hit,.rp Alaska. LL Date: 3-18-20 38. Attempt to Establish circulation and Jar 3-1/2" tubing out of well. Note: If unsuccessful, RU E -line and RIH and make a second cut at 14,000' and repeat process. If Successful, Go to step 41. Otherwise, go to next step. 39. Re -lease from tubing at 13,320' and pull out of hole with overshot. 40. PU BHA # 11 - outside cutter and 300' of wash pipe and RIH washing over tubing stub. Make cut and POOH. Repeat process until 3-1/2" pipe is recovered down to 14,879'. Lay down wash pipe. 41. PU RIH W/ BHA 12 — OS to Tubing Stub @ 14,879'. Latch Tubing stub and rotate out or break Latch assembly. Swap hole over to OBM. POOH W/ Latch and seals. 42. PU RIH with BHA #13- 6" shoe and mud motor. RIH to 14,884'. Set parameters and burn over permanent packer past slips. POOH W/ shoe. 43. PU BHA # 14 —OS/jar assembly. RIH and latch up to fish and POOH W/PKR, Baker Liner top seal assembly. CBU. Note: Consider RIH W/ E -line and shoot a hole in the tubing below packer to avoid having to pull a wet string. 44. PU RIH With locater sub, Packer, 3-1/2" production TBG and Dummied off mandrels. Space out and Pressure up to set packer. 45. RU Slick line and recover Ball and rod. 46. Pressure test 3-1/2" annulus to 2000 psi. 47. NO BOP, NU Well head and test. 48. RDMO Rig 169. Coiled Tubing Procedure 1. MIRU Coiled Tubing, PT BOPE to 4,500 psi Hi 250 Low. Notify AOGCC 24 hrs. in advance of BOP test. Note: MASP is higher here due to the Hydrostatic difference of the OBM and Diesel. 2. MU wash Nozzle. RIH to 15,810.' Swapping OBM to Diesel. 3. Circulate hole clean with 2 bottoms up, POOH W/Coil. 4. RDMO Coiled Tubing. 5. Turn well over to production to run GLV's. Attachments 1. Actual Schematic 2. Proposed Schematic W/Squeeze 3. Proposed Schematic W/7" Tieback 4. BOPE Schematic 5. Current Wellhead Schematic 6. Wellhead Schematic W/ 7" Tieback 7. Blank RWO Procedure Change Form THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Taylor Wellman Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission Re: Beaver Creek Field, Beaver Creek Oil Pool, Beaver Creek 04RD Permit to Drill Number: 219-011 Sundry Number: 320-056 Dear Mr. Wellman: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v .aogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, J re y rice C it Q'I DATED this day of February, 2020. RBDMB� F�E� o b 1D21i STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECYEAV-D JAN 2 9 20 �s Z/ 3f 26 A0GQQ 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well 10 Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑✓ Other: Chi Squeeze ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 219-011 ' 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20239-01-00 ' 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 2378 Will planned perforations require a spacing exception? Yes ElNo ❑Q Beaver Creek 04RD ' 9. Property Designation (Lease Number): 10. Field/Pool(s): FEDA028083 Beaver Creek Field / Beaver Creek Oil Pool it. PRESENT WELL CONDITION SUMMARY Total Depth MD (R): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): 10960; Junk (MD): 16,642' 15,652' 10,960' 10,916 -4,210psi 12800;15810 N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 288' 20" 288' 288' Surface 2,989' 13-318" 2,989 2,989' 5,380psi 2,670psi Intermediate Production 12,521' 9-5/8" 12,521' 12,357' 6,870psi 4,760psi Liner 4,202' 7" 15,193' 14,401' 11,220psi 8,530psi Liner 1,633' 4-1/2" 16,607' 15,618' 8,430psi 7,500psi Perforation Depth MD (ft): Perforation Depth TVD (tt):Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic I See Attached Schematic 3-1/2" 9.39 / P-110 10793 & 14978 Packers and SSSV Type: T' Liner Top Pkr; Wtr Swell Pkr; Packers and SSSV MD (ft) and TVD (ft): 10,991' MD/10,947' TVD; 11,128' MD/ Tri 7" Perm Pkr; 4.5" Liner Top Pkr; Wtr Swell Pkr; N/A 11,077' ND; 14,888' MD/14,160' TVD; 14,974' MD/14227' TVD; 15,067' MD/ 14,300' TVD; N/A, N/ 12. Attachments: Proposal Summary Q Wellbore schematic ❑✓ 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑Q Exploratory ❑ Stratigraphic ❑ Development 10 Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: February 27, 2020 OIL Q • WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Taylor Wellman 777-8449 Contact Name: Ted Kramer Authorized Title: OperationaMaugger Contact Email: tkramer hllcor .com Contact Phone: 777-8420 Authorized Signature: / Date: I aq iou+ CO MISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: O Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: .�C y5� P5- 3C>p '-7e:;,;`— VC 35-00 0t,:, 7" nAAL -��f RBDMS *A" FE3 0 y 1020 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes No d Subsequent Form Required: lo (A APPROVEDBY THE SSION Date: Approved by: COMMISSIONER THE COMMISSION • ^^ A Submit Form and For 1 Approved applicatioQvjljp I�r(`n�aJ� `date of approval. „/�� Attachments in Duplicate H Hilcorp Alaska, LLI Well Prognosis Well: BCU-04RD Date: 1-22-19 Well Name: BCU-04RD API Number: 50-133-20239-01 Current Status: Oil Well Leg: N/A Estimated Start Date: February 27, 2020 Rig: 169 Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219 -011= - First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) Second Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (M) AFE Number: Maximum Expected BHP: —9,188 psi @ 14,370' TVD (12.3 PPG MW to balance well) Max. Potential Surface Pressure: 4,210 psi (0.346 psi/ft diesel gradient) Brief Well Summary The BCU 4RD was sidetracked out of the BCU 4 well bore and drilled to a depth of 16,642' MD. A casing leak was identified during the original completion (June 2019) and was squeezed with Halliburton Resin. The well was completed and IP'd at over 900 bopd and produced at this rate until it suddenly went to 100% water in July of that year. A noise log identified a casing leak at 11,021' (depth squeezed with resin). A work over was attempted in fall of 2019. The goal was to identify the circumstances of the leak and repair if possible. During this workover the 3-1/2" tubing was cut at 13,320' and removed to that depth. An RBP was set in the 7" at 12,800' to isolate the deeper hole from the leak. After running diagnostics on the leak, it was determined that the correct materials to affect a repair were not available so a 9-5/8" CIBP was set at 10,960' to isolate the leak from the upper portion of the well and the rig was demobed. The purpose of this work/sundry is to repair the casing leak and return this well to production. In order to do this, the following will need to be done: 1) Shut off a water influx through a leak below the 7" liner hanger at 11,021' MD with a Cement Squeeze or by running a 7" tieback. 2) Remove the remaining 3-1/2" production TBG string. 3) Swap to Oil Based Mud. 4) Burn over and remove a Permanent Packer @ 14,888'. 5) Run a new completion. Note: After the em2n'f`squeeze is performed, it wil(be tested with a negative test. If the results are not favorable, the 7" liner top packer will be removed and a 7" Tieback will be ran and cemented in place. opt- $Z Notes Regarding Wellbore Condition BC 4RD has been perforated at 15,216' MD. g, Kati A 7" X 3-1/2" permanent packer is is set at 14,888' with 3-1/2" tubing stub in a rotating latch assembly above it up to 13,320'. A plug is set in the X -nipple below the 7" permanent packer at 14,932'. This plug and packer isolate the 4-1/2" liner. A 7" RBP is set at 12,800' MD. Well Prognosis Well: BCU-04RD Hilwra Alaska, LL' Date: 1-22-19 A 9-5/8" CIBP is set at 10960' MD. A 3-1/2" Kill string is set with bottom of TBG at 10,793' MD. Saxon #169 Procedure 1. MIRU Hilcorp Rig #169. 2. Test BOPE to 250 psi Low/ 4,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 10 -min). Record accumulator pre -charge pressures and chart tests. 6"ec a. Confirm test pressures per the Sundry Conditions of Approval u K" b. Perform Test. �t5 c. Notify AOGCC 24 hrs in advance of BOP test. d. Test VBR rams on 3-1/2" and 4-1/2" test joints. e. Email completed 10-424 form to all AOGCC addresses listed on the form within 5 days of BOPE test. 3. L/D BOP test equipment. 4. Check Well pressures. Note: The well is isolated by the 9-5/8" CIBP at 10,960'. p e 0 5. POOH laying down the 3-1/2" TBG (kill string). 1 6. PU BHA #1, 8-1/2" Bit and work string (singles), TIH to the top of the CIBP. Circulate 12.7 ppg kill mud to surface. 7. Drill out the 9-5/8" CIBP and clean out to the top of the 7" Liner hanger at 10,991' MD. Circulate and condition hole. TOOH. 8. PU BHA #2 - 6" bit and work string. TIH and clean out to 11,800' (1000' above the 7" RBP). Circulate and condition the well to KWM (12.7 ppg). POOH Racking Back Work string. Lay down Bit. 9. RIH with open ended work string and wireline guide shoe and set at 11,000' MD. RU E -Line, pressure test the lubricator 250 psi low/4,500 psi high, RIH to 11,021' with 2-1/8" tubing punches. �wr• Pressure up on well to 500 psi. Punch the 7" casing from 11,021 to 11,025with 4' of tubing GS� punches 0 degree phasing. POOH W/e-line. (Note: Could be two rens.) 10. Monitor the well for Pressure change. Re -balance MW to balance well. POOH. 11. PU 7" CMT retainer on a -line and RIH to 11,018'. Log on depth to set in sub right below the liner hanger ports. Set retainer. POOH W -e -line. 12. RIH W/ stinger on 4-1/2" work string to right above the Cement Retainer. Circulate diesel down tbg to stinger. Stab into stinger, Flow well up tubing to tank catching diesel for future use. Back flow well two tubing volumes to tank (approx. 300 bbls). 13. Perform PIR Using water. - to ,, V jri� +e' l- 14. Un -sting from retainer, back flow water to tank and circulate well back to KWM. 15. RU Cementers and pressure test lines. Circ cement down to stinger, Stab into CMT retainer, and �0 squeeze well with 70 barrels of cement placing as much cement as possible behind pipe. l^d 5 Q 16. Un -sting from retainer and place 15' of cement on top of retainer. Pick up two joints and reverse out excess cement to tank. WOC. Note: We will be real close to the transition zone back to 9-5/8" casing. Dumping too much cement on top of the retainer will cause us to have to drill up cement in the 9-5/8" casing prior to drilling in the 7" (additional run). �/ keg 17. PU BHA #3, 6" bit. RIH to TOC and drill out cement squeeze. CBU. Close backside and pressure 1l �fysy test to 2,000 psi for 30 min. on chart. Bleed off pressure. POOH W/bit. 6( 18. PU Test pkr. RIH to just below the Liner top packer. Note: Log packer on depth W/e-line. 5 19. Circ. diesel down to test pkr. Set same. Open well to flow back tank and perform negative test on t� cement squeeze. Vo .3r I1 ♦ srm'' )QQ 2xao k Well Prognosis Well: BCU-04RD Hamra Alaska, LU Date: 1-22-19 Note: Decision point- If the negative test is good must decide here if we are milling up Liner top packer or go to step 28. If negative test is bad (flow), then decide on re -squeeze or go to step # 20. 20. PU BHA #3, 8-1/2" Pilot mill. RIH on Work string to TOL @ 11,100'. Establish parameters, Mill up Baker ZXHD Liner top packer (+/- 17') according to fishing company's measurements. CBU POOH J with pilot mill. P 21. RU E -line, Pressure test lubricator to 250 psi low/3,000psi high. PU 7" Jet Cutter. RIH to 11,030' (+/-)and cut 7" casing below casing punches. 22. PU BHA #4- MU Spear/ Jar assembly, RIH and spear liner hanger @ 11,118' (+/-). Pull/Jar Liner hanger out of well. l u Note: If Liner top Hanger will not pull, POOH, PU Pilot Mill and mill up Liner top hanger past tubing punches to 11,030'. ( 23. PU BHA # 5- MU Polish mill. RIH to top of 7" casing (11,030'+/-) and dress off Stub. POOH With rC Polish Mill. v 24. Make Wellhead modifications to allow for 7" tieback. E Aa v C4,51 u y SPooi-) a Note: Wellhead will be set up according to Wellhead technician's procedure. Once the 7" is landed and hung off, a pack off will be set and the void space tested to 5,000 psi. 25. Test BOP rams on 7" Test joint. - 3500 p"" -i-l• st O�-A 26. PU BHA #6 - Casing Patch overshot W/ cementing tools on 7" 29" P-110 HC casing. Single in the well and over shot the 7" casing stub @ 11,130' (+/-). Shift cementing tool and prep to pump Cement. nc ) I, 31. MU BHA #9 - RBP Retrieving Tool. RIH to 12,800' and latch and Pull RBP. POOH W/ Same. to t� 32 MU BHA *In -0 W Sh d1 ' t f h ' d53/4"OS RIHto TOF@13320' a� 27. RU Cementing services. Pressure test lines and pump cement according to Cementing Companies' procedure. Clean up cementing truck and RDMO Cementers. WOC. 28. BHA # 7 - PU 6 Bit, R on or s ring an o en ,150'. CBU, POOH W/ Bit. 29. RU E -line, Pressure test lubricator to 250 psi low/3,000psi high. RIH W/ CBL to 11,140'. Run CBL F/ 11,140' up to 2,989' or TOC. POOH With E -line. A 130. MU BHA #8- Reverse Circulating Junk Basket (RCJB) RIH to 12,800' to remove debris and sand from top of RBP. POOH. cean ave oe an Jon o was pipe an 6 „� . Slip over TOF and lower to engage OS. (Note: If fill is encountered, then wash down to engage TOF 1''" W/ OS) Note: This area of the production tubing was subjected to the greatest amount of buckling in the tubing move simulations. It could be that this buckling and not fill prevented the cutter from getting deeper to make the cut. Some diagnostics here are warranted to determine if fill is actually present. �to1'6,� 33. RU E -line, Pressure test lubricator to 250 psi low/3,000psi high. RIH W/ GR and see if we can get �.I Few inside of Fish and how deep. POOH. �u PNote: MASP is now lower because casing leak has now been repaired. Qf 34. Kick on pump and step up in 500 psi increments to 2,500 psi and attempt to break circulation through tubing punch holes @ 13,501' (from previous workover). Note: OS sealing rubber is rated to 3,000 psi. 35. Attempt to PU and rotate pipe out of Rotating latch. If successful POOH W/pipe and go to step 42. Otherwise, go to next step. 36. RU Coil tubing Unit. Pressure test BOP to 250 psi low / 3500 psi high RIH W/jet nozzle on 1.75" coil string. Clean out 3-1/2" tubing from 13,320' to 14,888' (1,568'). POOH W/ Coil. 37. RU E -line, Pressure test lubricator to 250 psi low/3,000psi high. PU RIH W/ Cutter to 14,879' (3' above pup joint lower connection). Pull tension into pipe and make cut. POOH W/ E -line. And stand back. U Hilcorp Alaska, LU Well Prognosis Well: BCU-04RD Date: 1-22-19 38. Attempt to Establish circulation and Jar 3-1/2" tubing out of well. Note: If unsuccessful, RU E -line and RIH and make a second cut at 14,000' and repeat process. If Successful, Go to step 41. Otherwise, go to next step. 39. Re -lease from tubing at 13,320' and pull out of hole with overshot. 40. PU BHA # 11- outside cutter and 300' of wash pipe and RIH washing over tubing stub. Make cut and POOH. Repeat process until 3-1/2" pipe is recovered down to 14,879'. Lay down wash pipe. 41. PU RIH W/ BHA 12 —OS to Tubing Stub @ 14,879'. Latch Tubing stub and rotate out or break Latch assembly. Swap hole over to OBM. POOH W/ Latch and seals. f� 42. PU RIH with BHA #13- 6" shoe and mud motor. RIH to 14,884'. Set parameters and burn over jj permanent Dacker past slips. POOH W/ shoe. o " 43. PU BHA # 14— OS/ jar assembly. RIH and latch up to fish and POOH W/PKR, Baker Liner top seal P� assembly.CBU. Note: Consider RIH W/ E -line and shoot a hole in the tubing below packer to avoid having to pull a wet string. 44. PU RIH With locater sub, Packer, 3-1/2" production TBG and Dummied off mandrels. Space out and Pressure up to set packer. 45. RU Slick line and recover Ball and rod. 46. Pressure test 3-1/2" annulus to 2000 psi. jtn 1 T- i A 47. ND BOP, NU Well head and test. 48. RDMO Rig 169. Coiled Tubing Procedure 1. MIRU Coiled Tubing, PT BOPE to 4,500 psi Hi 250 Low. Notify AOGCC 24 hrs. in advance of BOP test. Note: MASP is higher here due to the Hydrostatic difference of the OBM and Diesel. 2. MU wash Nozzle. RIH to 15,810.' Swapping OBM to Diesel. 3. Circulate hole clean with 2 bottoms up, POOH W/Coil. 4. RDMO Coiled Tubing. 5. Turn well over to production to run GLV's. Attachments 1. Actual Schematic 2. Proposed Schematic W/Squeeze 3. Proposed Schematic W/7" Tieback 4. BOPE Schematic 5. Current Wellhead Schematic 6. Wellhead Schematic W/ 7" Tieback 7. Blank RWO Procedure Change Form K III Alaska. I.I.0 KB Dev.: 166.7/ BF/GL Bev.: 148.2' 20' 13-3/8- HPW @ 14,985'- 15,155' 7, f 1�� 1 lo9Lvr 2 3,��1� A) a Y roc rz,7as SCHEMATIC Beaver Creek Unit Well: BCU 04RD Completed: 6/22/2019 PTD: 219-011 API: 50-133-20239-01-00 2 s 1�✓" �4tiY4' 9pX P' 9 Zone Top(MD) JEWELRY DETAIL CASING DETAIL Depth ID OD Item -67 Size Type Wt Grade Conn. DID rift Top Btm 20" Conductor 94 H-40 N/A Surface 288' 13-3/8" Surface 72 N-80 12.415 Surface 2,989' 9-5/8" Production 47 & 53.5 N -80,S-95, P-110 8.681 Surface 12,521' 7" CSG 29 P-110 IC/TXP BTC 6.059 11,100' 15,193' 4-1/2" Liner 12.6 L-80 DWC/C 3.833 14,974' 16,607' 16,408' 16,474' 15,430' TUBING DETAIL 66' 7/16/2019 7/02/2019 3-1/2" Tubing 9.3 P-110 8RD EUE 2.867 Surface 10,793' 3-1/2" Tubing 9.3 P-110 8RD EUE 2.867 13,320' 14,978' 2 s 1�✓" �4tiY4' 9pX P' 9 Zone Top(MD) JEWELRY DETAIL No. Depth ID OD Item -67 10,960' 8.681" 9-7/8"MWB Tri -point CIBP(9/8/19) 2 10,991' 7" Liner Top Packer 3 11,128' Water Swell Packer 4 12,800' 6.059" 7" Model G Retrievable Bridge Plug (9/6/19) 5 14,888' 4.0" 5.875" Tripoint 7" 26-32# Permanent Pkr �5l 14,961' Pollard PX Plug w/top load bottom w/ 2.50" SB w/ 2.75 Prong, 59" LDA -3X 2.25" Rollers (bottom roller on prong) 7 14,973' Baker Seals (w/rubbers removed) 8 14,974' 4-1/2" Liner Top Packer 9 15,067' Water Swell Packer 10 15,810' Interwell 270-450 HPHT RBP Plug (7/16/19) 2 s 1�✓" �4tiY4' 9pX P' 9 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Status Date Tyonek GIB 15,216 15,234' 14,419' 14,433' 18' Isolated w/plug 7/17/2019 9/6/2019 Hemlock 15,900' 15,933' 14,984' 15,013' 33' Isolated w/ plug 7/11/2019 7/16/2019 Isolated w/ plug West Foreland 16,408' 16,474' 15,430' 15,491' 66' 7/16/2019 7/02/2019 10 rbe P7.1 -land. TD=16,642 (MD)/TD =15,652' (TVD) PBTD =10,960' (MDI/ PBTD=10,916' (TVD) Updated by DMA 11-12-19 20" 13-3/8" KPROPOSED SCHEMATIC 1 rnra Alaska. LLC 103 Elem 166.2/ BF/GL Dev.:148.2' 1 V, s 6 7 �qg•t Beaver Creek Unit Well: BCU 04RD Completed: Future PTD: 219-011 API: 50-133-20239-01-00 8 9 PurdeF 10 11,21 11 027 11 35/8.'' 12 LLL�� .�'.�✓' 13 116'& o � 9 1 ? a r .'Y BCU -04 7" Ta@ tz,7sm W HRM@ j testis-ts,tss �:? ND � 1s +.6 17 18 5a2G 21 Top(MD) Btm(MD) CASING DETAIL No. Depth ID Size Type Wt Grade Conn. D1riift Top Btm 20" Conductor 94 H-40 N/A Surface 288' 13-3/8" Surface 72 N-80 12.415 Surface 2,989' 9-5/8" Production 47& 53.5 N -80,S-95, P-110 8.681 Surface 12,521' 7" Uner 29 P-110 IC/TXP 8TC 6.059 10,991' 15,193' 4-1/2" Uner 12.6 L-80 DWC/C 3.833 14,974' 16,607' 9 ±9,609' 2.920" TUBING DETAIL 3-1/2" FO -1 Mandrel 8111) 10 ±10,276' 3-1/2" 5.375" 9.3 P-110 I 8RD EUE 10,991' surf ±15,050' 8 9 PurdeF 10 11,21 11 027 11 35/8.'' 12 LLL�� .�'.�✓' 13 116'& o � 9 1 ? a r .'Y BCU -04 7" Ta@ tz,7sm W HRM@ j testis-ts,tss �:? ND � 1s +.6 17 18 5a2G 21 PERFORATIONS Zone Top(MD) Btm(MD) JEWELRY DETAIL No. Depth ID OD Item 1 20' 2.998" - Tubing Hanger 2 ±2,400' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 3 ±4,350' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 4 ±5,900' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 5 ±7,150' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 6 ±7,500' 2.920" 5.375" 3-1/2" Cl Mandrel BRD 7 ±8,151' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 8 ±8,952' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 9 ±9,609' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8111) 10 ±10,276' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 11 10,991' 2-1/2" 6 7" Liner Top Packer 12 ±10,944' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 13 11,128' ±22 2-1/2" Water Swell Packer 14 ±11,669' 2.920" 5.375" 3-1/2" FC -1 Mandrel BRD 15 ±12,397' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 16 ±13,192' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD-Orifice 17 14,973' 4.0" 5.875" Tripoint 7" 26-32# Hydraulic Isolation Packer 18 14,974' 4.5" Liner Top Packer 19 15,012' 2.813" 4.50" X -Nipple 20 ±15,050' 4.276" 5.750" Packer Tie Back Bullet Seals 21 15,067' Water Swell Packer 22 15,820' Interwell 270-450 HPHT RBP 7/16/19 PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size SPF Phase Status Date Tyonek GIB ±15,216 ±15,234' 1:14,419' ±14,433' ±18' 2-1/2" 6 60 TBD Proposed Tyonek G2A ±15,590' ±15,629' ±14,725' ±14,757 ±39' 2-1/2" 6 60 TBD Proposed Tyonek G2A ±15,662' ±15,706' ±14,785' ±14,882' ±44' 2-1/2" 6 60 TBD Proposed Hemlock ±151900' ±15,933' ±14,984' ±15,013' ±33' 2-1/2" 6 60 TBD Proposed Hemlock 2A ±15,994 ±16,002' ±151065' ±15,073' ±8' 2-1/2" 6 60 TBD Proposed Hemlock 2B ±16,018 ±16,040 ±15,085' ±15,015' ±22 2-1/2" 6 60 TBD Proposed West Foreland 1 ±16,408' 1 ±16,474' 1 ±15,430' 1 ±15,491' I ±66' 1 2-1/2" 6 60 TBD I Proposed e^ TD=16,64Y(MD)/TD=15,657 (TVD) PBTD=16,512'(MD)/PBTD=15,453'(TVD)"""Y%�/�r•�2"`�, Updated by DMA 01-22-20 0 PROPOSED SCHEMATIC 2 "ru Almlia. LLC KB Bev.: 166.2/ BF/GL Deo.: 148.2' TD=16,642' (MD) / TD=15,652 (TVD) P13TD=16,512' (MD) / PBT) =15,453' DW) Jr^r' Beaver Creek Unit Well: BCU 04RD Completed: Future PTD: 219-011 API: SO -133-20239-01-00 PERFORATIONS Top(MD) Btm(MD) CASING DETAIL No. Depth ID Size Type Wt Grade Conn. Drift Top Btm 20" Conductor 94 H-40 N/A Surface 288' 13.3/8" Surface 72 N-80 12.415 Surface 2,989' 9.5/8" Production 47& N-80,5-95,53.5 P-110 8.681 Surface 12,521' 7" Tie Back 29 P-110 IC/TXP BTC 6.059 Surface 15,193' 4-1/2" Uner 12.6 L-80 DWC/C 3.833 14,974' 16,607' 9 ±9,609' 2.920" TUBING DETAIL 3-1/2" FO -1 Mandrel 8111) 10 ±10,276' 3±15,050'9.3 5.375" 3-1/2" FO -1 Mandrel 8RD P-110 8RD EUE ±11,018' Surf ±15,050' PERFORATIONS Top(MD) Btm(MD) JEWELRY DETAIL No. Depth ID OD Item 1 20' 2.998" - Tubing Hanger 2 ±2,400' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 3 ±4,350' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 4 ±5,900' 2.920" 5.375" 3-1/2" FO -1 Mandrel ORD 5 ±7,150' 2.920" 5.375" 3-1/2" FO -1 Mandrel ORD 6 ±7,500' 2.920" 5.375" 3-1/2" CI Mandrel ORD 7 ±8,151' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 8 ±8,952' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 9 ±9,609' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8111) 10 ±10,276' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 11 ±11,018' 2-1/2" 6 ES Cementing T 11A ±11,025' 28 ±16,018 Bowen OS 12 ±10,944' 2.920" 5.375" 3-1/2" FO -1 Mandrel ORD 13 11,128' Proposed land Water Swell Packer 14 ±11,669' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 15 ±12,397' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 16 ±13,192' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD - Orifice 17 14,973' 4.0" 5.875" Halliburton PHL Hydraulic Isolation Packer 18 14,974' 4.5" Liner Top Packer 19 15,012' 2.813" 4.50" X -Nipple 20 ±15,050' 4.276" 5.750" Packer Entry Guide 21 15,067' Water Swell Packer 22 15,820' Interwell 270-450 HPHT RBP 7/16/19 PERFORATIONS .,1ilr�y-✓4 `f'�e�zv t.!'!f y�i lf-ir6 t9 he�,, , 11-7 tC / YL Q !!�-? a --,I k Updated by DMA 03-22-20 Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size SPF Phase Status Date 11B ±15,216 ±15,234' ±14,419' ±14,433' ±18' 2-1/2" 6 60 TBD Proposed 12A ±15,590' ±15,629' ±14,725' ±14,757 ±39' 2-1/2" 6 60 TBD Proposed 12A ±15,662' ±15,706' ±14,785' ±14,882' ±44' 2-1/2" 6 60 TBD Proposed k ±15,900' ±15,933' ±14,984' ±15,013' ±33' 2-1/2" 6 60 TBD Proposed 2A ±15,994 ±16,002' ±15,065' ±15,073' ±8' 2-1/2" 6 60 TBD Proposed 28 ±16,018 ±16,040 ±15,085' ±15,015' ±22 2-1/2" 6 60 TBD Proposed land 1 ±16,408' 1 ±16,474' 1 ±15,430' 1 ±15,491' 1 ±66' 1 2-1/2" 1 6 1 60 j TBD I Proposed .,1ilr�y-✓4 `f'�e�zv t.!'!f y�i lf-ir6 t9 he�,, , 11-7 tC / YL Q !!�-? a --,I k Updated by DMA 03-22-20 Beaver Creels Field BC #4RD—Redrill 02/13/2019 Beaver Creek BC94RD 9detra,k Current Wellhead Beaver Creek Field BC #4RD nature A6 A..11.cr. 01/22/2020 Beaver Creek BCk4RD 20 x 133/8 x95/8 x 3K BHTA, Otis, 3 1/85M FE x 6S" Otis quick union top Valve, Swab, CI W -FLS, 31/85M FE, HWO, EE trim Valve, Master, CI W -FLS, 31/85M FE, HWO, EE trim Valve, Master, CIW-FLS, 31/85M FE, HWO, EE trim Tubing head, FMC -TC -BG, 13 5/8 5M x 115M, w/ 2- 2 1/16 5M 550 Casing spool, OCT- C -22 -BP - 00, 21 %" 2M x 13 5/8 SM, w/ 2- 2 1/16 5M 55O�v Starting head, OCT -C22, 211/4" 2M x 20" SOW, w/ 2- 21116 5M CFO 13 3/8" 9 5/8" Tubing hanger, FMC -TC -EN - CCI. 11 x 3 % EUE 8rd lift and susp, w/ 3" type H-BPV profile, 2-Snpt control line port, 6 X EN S,J, 60 Adapter, FMC -ASP -CCI, 115M stdd x 3 1/8 5M, w/ 2- 1" npt control line exits u Hilrory AEaJ., LIA: Proposed Wellhead W/ 7" Tieback Beaver Creek Field BC #4RD 01/22/2020 Sewer Creek Tubngh nger,FMGTOEN- BCMD CL 11 x 3 %EUE 8rd A and 28 x 133/8 x 95/8x3% wsp, w/3"type H -BN ,We, 2. %npt x.trd line port, 6 X EN BMA, OBq 31/3 5M FE 6.5-06, qU,k anlpn tap FS' xE 0t VaNe,3wab,OW-FE3, CO 0. JH`� 31/B EE tdmX>A,y1O �f�, aHee,fNlEm 911 d+¢ C ng aped, OCT -C -22 -U - OO, 22 W 2M x 13 5/85M, w/2 -211165M 56O,� &"I MA t OC 2, 222/4^2Mx2O' .w/ 2-21/163M EM U Adapter,FMC-ASp{q 215M itdd x 31/85M, w/1. rnpttw M111ne"its ;4 t. K4rif Valve, Master, CIWRS, 31/O 6M R HM, EEWm VeN<,Mxter,Clw-R5, 31/83M FE, HM, EEldm TubhS 115Mxad, It SK wl2.G, 11 5M165 M,w/b 3 165 51 abbe Need, FMC -TC -OO, 135/83Mx I33M, w/2- 2 L165M 330 C ng aped, OCT -C -22 -U - OO, 22 W 2M x 13 5/85M, w/2 -211165M 56O,� &"I MA t OC 2, 222/4^2Mx2O' .w/ 2-21/163M EM U Adapter,FMC-ASp{q 215M itdd x 31/85M, w/1. rnpttw M111ne"its ;4 t. K4rif HHilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well BCU 4RD (PTD 219-011) Sundry #: XXX -XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) 'first calf' engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By Initials HAK Approved By Initials AOGCC Written Approval Received (Person and Date) Approval: Asset Team Operations Manager Prepared: David Gorm Date First Call Operations Engineer Date Davies, Stephen F (CED) From: Ted Kramer <tkramer@hilcorp.com> Sent: Thursday, January 30, 2020 10:06 AM To: Davies, Stephen F (CED) Subject: RE: [EXTERNAL] Beaver Creek Unit 04RD (PTD 219-011; Sundry 320-056) - Question Steve, Sorry about that. The perf adds will be under a separate sundry that will be filed after the completion of this work. I guess we are thinking positively that this workover will be successful O. Ted Kramer Sr. Operations Engineer Hilcorp-Alaska LLC Office — 907-777-8420 Cell — 985-867-0665 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Thursday, January 30, 2020 10:03 AM To: Ted Kramer<tkramer@hilcorp.com> Subject: [EXTERNAL] Beaver Creek Unit 04RD (PTD 219-011; Sundry 320-056) - Question Hi Ted, I'm reviewing Hilcorp's recent Sundry Application for this well. I notice that on both of the proposed schematic drawings, the "Perforations' table lists seven intervals in red -colored text accompanied by the word "Proposed" in the "Date" column. I don't see any mention of perforating these intervals in the planned Saxon #169 procedure list. Does Hilcorp plan to perforate these intervals during the proposed operation, or will a separate Sundry Application be submitted for the perforation operations? Or have I overlooked something? Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesPalaska.aov. The information wntained in this e-mail message is confidential information intended only for the use of the recipients) named above. In addition, this communication maybe legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, DATA SUBMITTAL COMPLIANCE REPORT 9/20/2019 Permit to Drill 2190110 Well Name/No. BEAVER CK UNIT 04RD P61 Operator Hilcorp Alaska LLC API No. 50-133-20239-01-00 f MD 16642 TVD 15652 Completion Date 6/22/2019 Completion Status 1 -OIL Current Status 1 -OIL UIC No REQUIRED INFORMATION ''�. � Mud Log Imo • p Samples1�6 Directional Survey Yes ✓ DATA INFORMATION List of Logs Obtained: ROP, DGR, EWR-Ph4, CTN, ALD, ABG MD/TVD, DriDyn MD/TVD, Frm MD/TVD, GaRa MD/TVD, LWD MD/TVD, PB1 CBL (from Master Well Data/Logs) Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH/ Type Med/Fmtt Number Name Scale Media _ - No Start Stop CH Received Comments ED C 31081 Digital Data 11340 16642 8/8/2019 Electronic Data Set, Filename: BCU 04RD DGR EWR ALD CTN.Ias ED C 31081 Digital Data 8/8/2019 Electronic File: BCU 04RD LWD Final MD.cgm ED C 31081 Digital Data 8/8/2019 Electronic File: BCU 04RD LWD Final TVD.cgm ED C 31081 Digital Data 8/8/2019 Electronic File: BCU 4RD_Definitive Survey Report.pdf ED C 31081 Digital Data 8/8/2019 Electronic File: BCU 4RD DSR.txl ED C 31081 Digital Data 8/8/2019 Electronic File: BCU 4RD GIS.txt ED C 31081 Digital Data 8/8/2019 Electronic File: BCU 04RD LWD Final MD.emf ED C 31081 Digital Data 8/8/2019 Electronic File: BCU 04RD LWD Final TVD.emf ED C 31081 Digital Data 8/8/2019 Electronic File: BCU 04RD LWD Final MD.pdf ED C 31081 Digital Data 8/8/2019 Electronic File: BCU 04RD LWD Final TVD.pdf ED C 31081 Digital Data 8/8/2019 Electronic File: BCU 04RD LWD Final MD.tif ED C 31081 Digital Data 8/8/2019 Electronic File: BCU 04RD LWD Final TVD.tif ED C 31081 Digital Data 8/8/2019 Electronic File: EMFView3_1.zip ED C 31081 Digital Data 8/8/2019 Electronic File: Readme.t# Log 31081 Log Header Scans 0 0 2190110 BEAVER CK UNIT 04RD LOG HEADERS Log 31082 Log Header Scans 0 0 2190110 BEAVER CK UNIT 04RD PB1 LOG HEADERS ED C 31082 Digital Data 12029 14234 8/8/2019 Electronic Data Set, Filename: BCU-04RD PBI LWD Final.las AOGCC Page 1 of 24 Friday, September 20, 2019 DATA SUBMITTAL COMPLIANCE REPORT 9/20/2019 Permit to Drill 2190110 Well Name/No. BEAVER CK UNIT 04RD Operator Hilcorp Alaska LLC MD 16642 TVD 15652 Completion Date 6/22/2019 Completion Status 1 -OIL ED C 31082 Digital Data ED C 31082 Digital Data ED C 31082 Digital Data ED C 31082 Digital Data ED C 31082 Digital Data ED C 31082 Digital Data ED C 31082 Digital Data ED C 31082 Digital Data ED C 31082 Digital Data ED C 31082 Digital Data ED C 31082 Digital Data ED C 31082 Digital Data ED C 31082 Digital Data ED C 31083 Digital Data 11900 14330 ED C 31083 Digital Data 11200 16720 ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data API No. 50-133-20239-01-00 Current Status 1 -OIL UIC No 8/8/2019 Electronic File: BCU 04RD PBI LWD Final 8/8/2019 MD.cgm 8/8/2019 Electronic File: BCU 04RD PB1 LWD Final 8/8/2019 TVD.cgm 8/8/2019 Electronic File: BCU 4RDPB1_Definitive Survey 8/8/2019 Report.pdf 8/8/2019 Electronic File: BCU 4RDPB1 DSR.txt 8/8/2019 Electronic File: 8CU 04RD PB1 LWD Final MO.emf 8/8/2019 Electronic File: BCU 04RD PB1 LWD Final TVD.emf 8/8/2019 Electronic File: BCU 04RD P81 LWD Final MD.pdf 8/8/2019 Electronic File: BCU 04RD PB1 LWD Final TVD.pdf 8/8/2019 Electronic File: BCU 04RD PSI LWD Final MD.tif 8/8/2019 Electronic File: BCU 04RD PBI LWD Final TVD.tif 8/8/2019 Electronic File: myfile.log 8/8/2019 Electronic File: EMFView3_t.zip 8/8/2019 Electronic File: Readme.txt 8/8/2019 Electronic Data Set, Filename: BCU04RD- 'Y` 8/8/2019 Electronic Data Set Filename: BCU04RD.las V 8/8/2019 Electronic File: BCU04RD.dbf 8/8/2019 Electronic File: bcu04rd.hdr 8/8/2019 Electronic File: BCU04RD.mdx 8/8/2019 Electronic File: bcu04rdr.dbf 8/8/2019 Electronic File: bcu04rdr.mdx 8/8/2019 Electronic File: BCU04RD SCL.DBF 8/8/2019 Electronic File: BCU04RD SCL.MDX 8/8/2019 Electronic File: BCU04RD TVD.DBF AOGCC Page 2 of 24 Friday, September 20, 2019 DATA SUBMITTAL COMPLIANCE REPORT 9/20/2019 Permit to Drill 2190110 Well Name/No. BEAVER CK UNIT 04RD Operator Hilcorp Alaska LLC API No. 50-133-20239-01-00 MD 16642 TVD 15652 Completion Date 6/22/2019 Completion Status 1 -OIL Current Status 1 -OIL UIC No ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD_TVD.mdx ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - 5in Drilling Dynamics MD.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - 5in Drilling Dynamics TVD.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - 5in Formation Log MD.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - 5in Formation Log TVD.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PBI - 5in Gas Ratio Log MD.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - 5in Gas Ratio Log TVD.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - 5in LWD Combo Log MD.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 -5in LWD Combo Log TVD.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - Drilling Dynamics MD.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PBI - Drilling Dynamics TVD.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - Formation Log MD.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - Formation Log TVD.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - Gas Ratio Log MD.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - Gas Ratio Log TVD.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PBI - LWD Combo Log MD.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PBI - LWD Combo Log TVD.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - 5in Drilling Dynamics MD.tif A06CC Page 3 of 24 Friday, September 20, 2019 DATA SUBMITTAL COMPLIANCE REPORT 9/20/2019 Permit to Drill 2190110 Well Name/No. BEAVER CK UNIT 04RD Operator Hilcorp Alaska LLC API No. 50-133-20239-01-00 MD 16642 TVD 15652 Completion Date 6/22/2019 Completion Status 1-0I1- Current Status 1 -OIL UIC No ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - Nin Drilling Dynamics TVD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - 51n Formation Log MD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - 5in Formation Log TVD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - 5in Gas Ratio Log MD.fif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - 5in Gas Ratio Log TVD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - 5in LWD Combo Log MD.tif ED C 31083 Digital Data 8/8/2019 Electronic Fite: BCU04RD-PB1 - Sin LWD Combo Log TVD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - Drilling Dynamics MD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - Drilling Dynamics TVD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - Formation Log MD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - Formation Log TVD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - Gas Ratio Log MD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - Gas Ratio Log TVD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - LWD Combo Log MD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD-PB1 - LWD Combo Log TVD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 02-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 03-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 04-2019.pdf AOGCC Page 4 of 24 Friday, September 20, 2019 DATA SUBMITTAL COMPLIANCE REPORT 9/20/2019 Permit to Drill 2190110 Well NamelNo. BEAVER CK UNIT 04RD MD 16642 TVD 15652 Completion Date 6/22/2019 ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data Operator Hilcorp Alaska LLC API No. 50-133-20239.01.00 Completion Status 1 -OIL Current Status 1 -OIL UIC No 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 05-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 06-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 07-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 08-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 09-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 10-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 11-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 12-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 13-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 14-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 15-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 16-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 17-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 18-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 19-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 20-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 21-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 22-2019.pdf AOGCC Page 5 of 24 Friday, September 20. 2019 DATA SUBMITTAL COMPLIANCE REPORT 9/20/2019 Permit to Drill 2190110 Well Name/No. BEAVER CK UNIT 04RD MD 16642 TVD 15652 Completion Date 6/22/2019 ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data Operator Hilcorp Alaska LLC Completion Status 1 -OIL API No. 50-133-20239-01-00 Current Status 1-0I1- UIC No 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 23-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 24-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 25-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 26-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 27-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 28-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 29-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 30-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 03- 31-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 01-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 02-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 03-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 04-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 05-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 06-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 07-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 08-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 09-2019.pdf AOOC'C Page 6 of 24 Friday, September 20, 2019 DATA SUBMITTAL COMPLIANCE REPORT 9/20/2019 Permit to Drill 2190110 Well Name/No. BEAVER CK UNIT 04RD Operator Hilcorp Alaska LLC API No. 50-133-20239-01-00 MD 16642 TVD 15652 Completion Date 6/22/2019 Completion Status 1 -OIL Current Status 1 -OIL UIC No ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 09-2019.zip ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 10-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 11-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 12-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 13-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 14-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 15-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 16-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 17-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 18-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 19-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 20-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RO Nabors AM Report 04- 21-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 22-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 23-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 24-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 25-2019.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 26-2019.pdf AOGCC Page 7 of 24 Friday, September 20, 2019 DATA SUBMITTAL COMPLIANCE REPORT 9120/2019 Permit to Drill 2190110 Well Name/No. BEAVER CK UNIT 04RD Operator Hilcorp Alaska LLC MD 16642 TVD 15652 ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data Completion Date 6/22/2019 Completion Status 1 -OIL API No. 50-133-20239-01-00 Current Status 1-0I1- UIC No 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 27-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 28-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 29-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 04- 30-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 03-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 04-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 05-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 06-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 07-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 08-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 09-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 1-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 10-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 11-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 12-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 13-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 14-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 15-2019.pdf AOGCC Page 8 of 24 Friday, September 20, 2019 DATA SUBMITTAL COMPLIANCE REPORT 9/20/2019 Permit to Drill 2190110 Well Name/No. BEAVER CK UNIT 04RD MD 16642 TVD 15652 Completion Date 6/22/2019 ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C 31083 Digital Data 31083 Digital Data 31083 Digital Data 31083 Digital Data 31083 Digital Data 31083 Digital Data 31083 Digital Data 31083 Digital Data 31083 Digital Data 31083 Digital Data 31083 Digital Data 31083 Digital Data 31083 Digital Data 31083 Digital Data 31083 Digital Data 31083 Digital Data 31083 Digital Data 31083 Digital Data Operator Hilcorp Alaska LLC API No. 50-133-20239-01-00 Completion Status 1-0IL Current Status 1-0I1- UIC No 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 16-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 17-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 18-2019.pdf 8/8/2019 Electronic File: BCU-04RD Nabors AM Report 05- 2-2019.pdf 8/8/2019 Electronic File: BCU04RD-ST1.dbf 8/8/2019 Electronic File: bcu04rd-stl.hdr 8/8/2019 Electronic File: BCU04RD-ST1.mdx 8/8/2019 Electronic File: bcu04rd-st1 r.dbf 8/8/2019 Electronic File: bcu04rd-st1 r.mdx 8/8/2019 Electronic File: BCU04RD-STI SCL.DBF 8/8/2019 Electronic File: BCU04RD-STI SCL.MDX 8/8/2019 Electronic File: BCU04RD-ST1 tvd.dbf 8/8/2019 Electronic Fite: BCU04RD-ST1_tvd.mdx 8/8/2019 Electronic File: BCU 04RD Final Well Report.pdf 8/8/2019 Electronic File: BCU04RD - 5in Drilling Dynamics Log MD.pdf 8/8/2019 Electronic File: BCU04RD - 5in Drilling Dynamics Log TVD.pdf 8/8/2019 Electronic File: BCU04RD - 5in Formation Log MD.pdf 8/8/2019 Electronic File: BCU04RD - 5in Formation Log TVD.pdf 8/8/2019 Electronic File: BCU04RD - 5in Gas Ratio Log MD.pdf 8/8/2019 Electronic File: BCU04RD - 5in Gas Ratio Log TVD.pdf 8/8/2019 Electronic File: BCU04RD - 5in LW D Combo Log MD.pdf 8/8/2019 Electronic File: BCU04RD - 5in LWD Combo Log TVD.pdf AOGCC Page 9 of'24 Friday, September 20, 2019 DATA SUBMITTAL COMPLIANCE REPORT 9120/2019 Permit to Drill 2190110 Well Name/No. BEAVER CK UNIT 04RD MD 16642 TVD 15652 Completion Date 6/22/2019 ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data Operator Hilcorp Alaska LLC Completion Status 1 -OIL AGGCC Page 10 of 24 API No. 50.133-20239-01-00 Current Status 1-0I1- UIC No 8/8/2019 Electronic File: SCU04RD - Drilling Dynamics Friday, September 20, 2019 Log MD.pdf 8/8/2019 Electronic File: BCU04RD - Drilling Dynamics Log TVD.pdf 8/8/2019 Electronic File: BCU04RD - Formation Log MD.pdf 8/8/2019 Electronic File: BCU04RD - Formation Log TVD.pdf 8/8/2019 Electronic File: BCU04RD - Gas Ratio Log MD.pdf 8/8/2019 Electronic File: BCU04RD - Gas Ratio Log TVD.pdf 8/8/2019 Electronic File: BCU04RD - LWD Combo Log MD.pdf 8/8/2019 Electronic File: BCU04RD - LWD Combo Log TVD.pdf 8/8/2019 Electronic File: BCU04RD - 5in Drilling Dynamics Log MD.tif 8/8/2019 Electronic File: BCU04RD - Sin Drilling Dynamics Log TVD.tif 8/8/2019 Electronic File: BCU04RD - 5in Formation Log MD.tif 8/8/2019 Electronic File: BCU04RO - 5in Formation Log TVD.tif 8/8/2019 Electronic File: BCU04RD - 5in Gas Ratio Log MD.tif 8/8/2019 Electronic File: BCU04RD - 5in Gas Ratio Log TVD.tif 8/8/2019 Electronic File: BCU04RD - Sin LWD Combo Log MD.tif 8/8/2019 Electronic File: BCU04RD - 5in LWD Combo Log TVD.tif 8/8/2019 Electronic File: BCU04RD - Drilling Dynamics Log MD.Gf 8/8/2019 Electronic File: BCU04RD - Drilling Dynamics Log TVD.tif Friday, September 20, 2019 DATA SUBMITTAL COMPLIANCE REPORT 9/20/2019 Permit to Drill 2190110 Well Name/No. BEAVER CK UNIT 04RD Operator Hilcorp Alaska LLC API No. 50-133-20239-01-00 MD 16642 TVD 15652 Completion Date 6/22/2019 Completion Status 1 -OIL Current Status 1 -OIL UIC No ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD - Formation Log MD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD - Formation Log TVD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD - Gas Ratio Log MD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD - Gas Ratio Log TVD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD - LWD Combo Log MD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD - LWD Combo Log TVD.tif ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_13440.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_14555.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_15198.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_15202.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_15202_metal piece.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_15213.jpg ED C 31083 Digital Data 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DATA SUBMITTAL COMPLIANCE REPORT 9/20/2019 Permit to Drill 2190110 Well Name/No. BEAVER CK UNIT 04RD Operator Hilcorp Alaska LLC API No. 50-133-20239-01-00 MD 16642 TVD 15652 Completion Date 6/22/2019 Completion Status 1 -OIL Current Status 1 -OIL UIC No ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_15290.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_15295.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_15300.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_15305.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_15310.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_15315.jpg - ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_15320.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_15330.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_15335.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_15340.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: 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Well Name/No. BEAVER CK UNIT 04RD Operator Hilcorp Alaska LLC MD 16642 TVD 15652 ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data Completion Date 6/22/2019 Completion Status 1 -OIL API No. 50.133-20239-01-00 Current Status 1-0I1- UIC No 8/8/2019 Electronic File: BCU-04RD_16020.jpg 8/8/2019 Electronic File: BCU-04RD_16030.jpg 8/8/2019 Electronic File: 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IL IL I1 IL @ U U U U U U U U U U U U U U U .2 .2 U U U U Uc c C c c C C c C c c c c c C c c C c C C c c C @ o d Q o o Q Q o Q o o Q o Q Q o o Q Q Q o o Q o o Q Q Q o F N v v v v v v v v v v v d ii � d v v d ii v v ii v v v v v 'G v d d d d d d d d d d d d d d d d d d d d d d d d d d d d d w w w W W W Wm w W w W W W w W W W W w w W w W W IL w w w O " j rn rn rn rn rn rn rn rn rn rn rn rn rn rn rn rn rn rn rn rn rn rn rn rn M M M M m U 1i m o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 W N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N @ m m m m m m m m m m m m m m m m m m m m m m m m m m m w m n V V J S � Q O @ @ I J m C 0) o C-4 N Os EI V � U J o rnl, f o C 2 N W Y m U U) LLI LL' d Q ❑ Q W c 10 � r � Q u n 2 E Q o E U @ 2 @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ N N N N N A N N N N l0 N 10 l0 10 l0 W t0 l0 10 t0 A N 10 l0 N 10 N t0 t0 @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ @ Ol •m •OI .O� .O� .� Ol rn rn rn rn W 0 m W 0 OI 2)O1 N O1 m OI W 01 OI rn rn O1 O ❑ O O O O O O O O O O O O 0 0 O 0 O O O 0 O O > M m M m M M m m M M M m m M m m M m m M m m M m m M m M M F m m m m m m m mm m m m m m m m m m m m m m m m m m m m m 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 rn th m M M m M M fn M lh M M M m M M m M m M M M M M M M t7 M M N N p t0 d w w w w w w w w w w w w w w w w w w w w w w w w w w w w w DATA SUBMITTAL COMPLIANCE REPORT 9/20/2019 Permit to Drill 2190110 Well Name/No. BEAVER CK UNIT 04RD Operator Hilcorp Alaska LLC MD 16642 TVD 15652 ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data ED C 31083 Digital Data Completion Date 6/22/2019 Completion Status 1 -OIL API No. 50-133-20239-01-00 Current Status 1-011- UIC No 8/8/2019 Electronic File: BCU-04RD_035.jpg 8/8/2019 Electronic File: BCU-04RD_036.jpg 8/8/2019 Electronic File: BCU-04RD_037.jpg 8/8/2019 Electronic File: BCU-04RD_038.jpg 8/8/2019 Electronic File: BCU-04RD_039.jpg 8/8/2019 Electronic File: BCU-04RD_040.jpg 8/8/2019 Electronic File: BCU-04RD_041.jpg 8/8/2019 Electronic File: BCU-04RD_042.jpg 8/8/2019 Electronic File: BCU-04RD_043.jpg 8/8/2019 Electronic File: BCU-04RD_044.jpg 8/8/2019 Electronic File: BCU-04RD_045.jpg 8/8/2019 Electronic File: BCU-04RD_046.jpg 8/8/2019 Electronic File: BCU-04RD_047.jpg 8/8/2019 Electronic File: BCU-04RD_048.jpg 8/8/2019 Electronic File: BCU-04RD_049.jpg 8/8/2019 Electronic File: BCU-04RD_050.jpg 8/8/2019 Electronic File: BCU-04RD_051.jpg 8/8/2019 Electronic File: BCU-04RD_052.jpg 8/8/2019 Electronic File: BCU-04RD_053.jpg 8/8/2019 Electronic File: BCU-04RD_054.jpg 8/8/2019 Electronic File: BCU-04RD_055.jpg 8/8/2019 Electronic File: BCU-04RD_O56.jpg 8/8/2019 Electronic File: BCU-04RD_057.jpg 8/8/2019 Electronic File: BCU-04RD_058.jpg 8/8/2019 Electronic File: BCU-04RD_059.jpg 8/8/2019 Electronic File: BCU-04RD_060.jpg 8/8/2019 Electronic File: BCU-04RD_061.jpg 8/8/2019 Electronic File: BCU-04RD_062.jpg 8/8/2019 Electronic File: BCU-04RD_063.jpg AOGCC Page 19 of 24 Friday, September 20, 2019 DATA SUBMITTAL COMPLIANCE REPORT 9/20/2019 Permit to Drill 2190110 Well Name/No. BEAVER CK UNIT 04RD Operator Hilcorp Alaska LLC API No. 50-133.20239-01-00 MD 16642 TVD 15652 Completion Date 6/22/2019 Completion Status 1-0I1- Current Status 1-0I1- UIC No ED C 31083 Digital Data — 8/8/2019 -- - - ------ Electronic File: BCU-04RD_064.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_065.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_066.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_067.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_068.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_069.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_070.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_071.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_072.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_073.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_074.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_075.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_076.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_077.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_078.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_079.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_080.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_081.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_082.jpg —. ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_083.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_084.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_085.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_086.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_087.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_088.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_089.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_090.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_094.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_095.jpg AOGCC Page 20 of 24 Friday, September 20, 2019 DATA SUBMITTAL COMPLIANCE REPORT 9/20/2019 Permit to Drill 2190110 Well Name/No. BEAVER CK UNIT 04RD Operator Hilcorp Alaska LLC API No. 50-133-20239-01-00 MD 16642 TVD 15652 Completion Date 6/22/2019 Completion Status 1 -OIL Current Status 1 -OIL UIC No ED C 31083 Digital Data 8/8/2019 Electronic File:BCU-04RD_096.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_097.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_098.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_099.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_100.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_101.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_102.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_103.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_104.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_105.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_106.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_107.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_108.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_109.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_110.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_111.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_112.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_113.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_114.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_115.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_116.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_117.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_118.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_119.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_120.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_121.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_122.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_123.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_124.jpg AOGCC Page 21 of 24 Friday, September 20, 2019 DATA SUBMITTAL COMPLIANCE REPORT 9/20/2019 Permit to Drill 2190110 Well Name/No. BEAVER CK UNIT 04RD Operator Hilcorp Alaska LLC API No. 50.133-20239-01-00 MD 16642 TVD 15652 Completion Date 6/22/2019 Completion Status 1 -OIL Current Status 1 -OIL UIC No ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_125.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_126.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_127.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD 16-19.zip ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_016.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_017.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_018.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_019.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_020-23.zip ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_020.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_021.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_022.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_023.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_024.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_025.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_026.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_027.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_029.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_030.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_031.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_032-032 ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_032.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_033.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: BCU-04RD_034.jpg ED C 31083 Digital Data 8/8/2019 Electronic File: Doc1.docx ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD_Show#1.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD_Show#10.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD_Show#2.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCUD4RD_Show#3.pdf AO(iC(' Page 22 of 24 Friday, September 20, 2019 DATA SUBMITTAL COMPLIANCE REPORT 9/20/2019 Permit to Drill 2190110 Well Name/No. BEAVER CK UNIT 04RD Operator Hilcorp Alaska LLC API No. 50-133.20239-01-00 MD 16642 TVD 15652 Completion Date 6/22/2019 Completion Status 1-0I1- Current Status 1 -OIL UIC No ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD_Show84.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD_Show#5.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD_Show#6.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD_Show#7.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD_Show#8.pdf ED C 31083 Digital Data 8/8/2019 Electronic File: BCU04RD_Show#9.pdf Log 31083 Log Header Scans 0 0 2190110 BEAVER CK UNIT 04RD LOG HEADERS Log 31084 Log Header Scans 0 0 2190110 BEAVER CK UNIT 04RD LOG HEADERS ED C 31084 Digital Data 14686 10890 8/8/2019 Electronic Data Set, Filename: BC4RD CBL 6- MAY-2019.1as ED C 31084 Digital Data 8/8/2019 Electronic File: BC 4RD CBL 6-MAY-2019.pdf Well Cores/Samples Information: -- - - — - - - — - Sample Interval Set Name Start Stop Sent Received Number Comments Cuttings 11340 16640 8/8/2019 1720 mainbore - Cuttings 10080 14234 8/8/2019 1722 PB1 INFORMATION RECEIVED -- -- --- ---- -- - - -- ---- - Completion Report l./ Directional / Inclination Data Mud Logs, Image Files, Digital Dat NA Core Chips Y /!®� Production Test Informatioe) NA Mechanical Integrity Test Information Y / NA Composite Logs, Image, Data Files rrii�Y�� lo Core Photographs Y NrvA ) Geologic Markers/Tops O Daily Operations Summary Cuttings SamplesY© NA Laboratory Analyses Y COMPLIANCE HISTORY - -- Completion Date: 6/22/2019 Release Date: 2/5/2019 Description Date Comments AOGCC Page 23 of 24 Friday, September 20, 2019 DATA SUBMITTAL COMPLIANCE REPORT 9/20/2019 Permit to Drill 2190110 Well Name/No. BEAVER CK UNIT 04RD Operator Hilcorp Alaska LLC MD 16642 TVD 15652 Completion Date 6/22/2019 Completion Status 1-0I1 Current Status 1-011- Comments: -OIL Comments: Compliance Reviewed By: y t tI jj� API No. 50-133-20239-01-00 UIC No Date: (0 0 11 1 AOGCC Page 24 of 24 Friday, September 20, 2019 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission Re: Beaver Creek Field, Beaver Creek Oil Pool, Beaver Creek 04RD Permit to Drill Number: 219-011 Sundry Number: 319-388 Dear Mr. York: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .aogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 569aaA'; %Daniel T. Seamount, Jr. Commissioner �, DATED this L day of August, 2019. RBDMS-Fk--j AUG 3 01019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION n a APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well 0 Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing Q Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing Q Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q • Stratigraphic ❑ Service ❑ 219-011 ' 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20239-01-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 2378' Will planned perforations require a spacing exception? Yes ❑ No Beaver Creek 04RD 9. Property Designation (Lease Number): 10. Field/Pool(s): FEDA028083 ' Beaver Creek Field / Beaver Creek Oil Pool ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 16,642' 15,652' 16,512' 15,527'-2,906psi 15,810' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 288' 20" 288' 288' Surface 2,989' 13-3/8" 2,989' 2,989' 5,380psi 2,670psi Intermediate Production 12,521' 9-5/8" 12,521' 12,357'6,870psi 4,760psi Liner 4,202' 7" 15,193' 14,401' 11,220psi 8,530psi Liner 1,633' 4-1/2" 16,607' 15,618' 8,430psi 7,500psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 3-1/2" 9.3# / P-110 1 14,978' Packers and SSSV Type: 7" Liner Top Pkr; Wtr Swell Por; Packers and SSSV MD (h) and TVD (ft): 10,991' MD/10,947' TVD; 11,127' MD/ Tri 7" Perm Pkr; 4.5" Liner Top Pkr; Wtr Swell Pkr; N/A 11,078' ND; 14,888' MD/14,160' ND; 14,974' MD/14227' TVD; 15,067' MD/ 14,300' TVD; N/A, N/A 12. Attachments: Proposal Summary 21 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: August 29, 2019 OILWINJ ❑ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Be York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: t1krannerCEDhilcorp.corn ',A /J Contact Phone: 777-8420 Authorized Signatur_ . Date: 4-7 l.y 1'i COMMISSIO SE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 'LJ• (/� i✓• Plug Integrity ❑ BOP Test W Mechanical Integrity Test ❑ Location Clearance ❑ Other: y Soo dos: 3o Ps-f— RBDMSL'f�UG 3 0 2019 Post Initial Injection MIT Req'd? Yes ❑ No Spacing Exception Required? Yes ❑ No Subsequent Form Required: / C) -� `1 v 1 APPROVED BY Approved by2 OMMISSIONER THE COMMISSION Date: /'� ^ 1 /� I 1 A 1 Submit Form and Form 10-403 Revised 4/2017 ZApp�ved application! v/I�1/6�7c mot f l*tLate of ap royal. w/� attachments in Duplicate l 1 0 v H K mrD Alaska. LLC KB Elev.:166.7/ BF/GL Bev.: 148.2' 13-3/8" Possibleleak Pont @1V HPW @ 14,985'- 15,155' MD TD =16,642' (MD)/TD= 15,652'(TVD) PBTD=16,517 (NID) / PBTD = 15,527'(TVD) ACTUAL SCHEMATIC Beaver Creek Unit Well: BCU 04RD Completed: 6/22/2019 PTD: 219-011 AN: 50-133-20239-01-00 Zone Top(MD) Btm(MD) CASING DETAIL No. Depth ID Size Type Wt Grade Conn. Drift ID Top Btm 20" Conductor 94 H-40 N/A Surface 288' 13-3/8" Surface 72 N-80 12.415 Surface 2,989' 9-5/8" Production 478, 53.5 N -80,S-95, P-110 8,681 Surface 12,521' 7" Liner 29 P-110 IC/TXP BTC 6.059 10,991' 15,193' 4-1/2" Liner 12.6 L-80 DWC/C 3.833 14,974' 16,607' 9 9,606' 2.920" TUBING DETAIL 3-1/2" FO -1 Mandrel 8RD 10 10,278' 3-1/2" 1 Tubing 9.3 1 T-1101 8RD EUE I2.867 Surf 14,978' Zone Top(MD) Btm(MD) JEWELRY DETAIL No. Depth ID OD Item 1 18' 2.992" - Tubing Hanger 2 2,418' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8111) 3 4,367' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 4 5,921' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 5 7,150' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 6 7,495' 2.920" 5.375" 3-1/2" Cl Mandrel 8RD 7 8,134' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 8 8,934' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 9 9,606' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 10 10,278' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 11 10,991' 7" Liner Top Packer 12 10,950' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 13 11,128' Water Swell Packer 14 11,665' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 15 12,392' 2.920" 5.375" 1 3-1/2" FO -1 Mandrel 8RD 16 13,195' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD - Orifice 17 14,888' 4.0" 5.875" Tripoint 7" 26-32# Permanent 18 14,974' 4-1/2" Liner Top Packer 19 14,932' 2.813" 4.50" X -Nipple 20 14,973' 4.276" 5.750" Packer Tie Back Bullet Seals stripped 21 15,067' Water Swell Packer 22 15,810' Plug (7/16/19) Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Status Date Tyonek G18 15,216 15,234' 14,419' 14,433' 18' Open 7/17/2019 Hemlock 15,900' 15,933' 14,984' 15,013' 33' Isolated w/ plug 7/11/2019 7/16/2019 West Foreland 16,408' 16,474' 15,430' 15,491' 66' Isolated w/ plug 7/02/20197/16/2019 Updated by DMA 08-07-19 nProposed SCHEMATIC corp Alwka, LLC 7- wf i-_ _'-MM 20' 11b[ Fa9R10C 4-1/2" TD= 16,64Z (ND)/TD= 15,W (ND) PBID=16,517 (ND) / PBTD=15,527 (TVD) Beaver Creek Unit Well: BCU 04RD Completed: 6/22/2019 PTD: 219-011 API: 50-133-20239-01-00 Top(MD) Btm(MD) CASING DETAIL 2 s 13-3/8" Size Type Wt Grade Conn. 4 Top glum 20" 3 94 H-40 N/A Surface 4 13-3/8" Surface 72 N-80 5 Surface 2,989' 9-5/8" Production 6 N-805.95, P-110 4s/8 Surface 12,521' 7 CSG 29 -P-110 IC/TXP BTC 6.059 B 11,100' 7" CSG 29 9 `1 7°d 11,100' 15,193' 4-1/2" o 12.6 L-80 I DWC/C 3.833 14,974' 16,607' 6.184" 7" 9-5/8" X 7" Packer TUBING DETAIL 10,278' 2.920" 5.375" 12 Tubing 9.3 1 P-110 I 8RD EUE 2.867 Surf wI 13 7" ES cementer and Overshot Packoff seals 14 11,128' 14 Water Swell Packer 15 11,665' 2.920" 5.375" 15 16 12,392' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD is 13,195' BCU -04 5.375" 3-1/2" FO -1 Mandrel 8RD -Orifice 18 17 4.0" 7, Tripoint 7" 26-32# Permanent 19 14,974' roc @ 20 14,932' 2.813" 4.50" X -Nipple U,7W W 14,973' 4.276" 5.750" Packer Tie Back Bullet Seals stripped 22 15,067' Water Swell Packer 18 15,510' Plug (7/16/19) 19 20&21 HPW @ 22 14,985' - 15,155' MU 11b[ Fa9R10C 4-1/2" TD= 16,64Z (ND)/TD= 15,W (ND) PBID=16,517 (ND) / PBTD=15,527 (TVD) Beaver Creek Unit Well: BCU 04RD Completed: 6/22/2019 PTD: 219-011 API: 50-133-20239-01-00 Zone Top(MD) Btm(MD) CASING DETAIL No. Depth ID Size Type Wt Grade Conn. Drift ID Top glum 20" Conductor 94 H-40 N/A Surface 288' 13-3/8" Surface 72 N-80 12.415 Surface 2,989' 9-5/8" Production 47& 53.5 N-805.95, P-110 8.681 Surface 12,521' 7" CSG 29 -P-110 IC/TXP BTC 6.059 9,700' 11,100' 7" CSG 29 P-110 IC/TXP BTC 6.059 11,100' 15,193' 4-1/2" Uner 12.6 L-80 I DWC/C 3.833 14,974' 16,607' 6.184" 7" 9-5/8" X 7" Packer TUBING DETAIL 10,278' 2.920" 5.375" 3-1/2" Tubing 9.3 1 P-110 I 8RD EUE 2.867 Surf 14,978' Zone Top(MD) Btm(MD) JEWELRY DETAIL No. Depth ID OD Item 1 18' 2.992" - Tubing Hanger 2 2,418' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 3 4,367' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 4 5,921' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 5 7,150' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 6 7,495' 2.920" 5.375" 3-1/2" CI Mandrel 8RD 7 8,134' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 8 8,934' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 9 9,606' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 10 9,700' 6.184" 7" 9-5/8" X 7" Packer 11 10,278' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 12 10,950' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 13 11,100' 7" ES cementer and Overshot Packoff seals 14 11,128' Water Swell Packer 15 11,665' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 16 12,392' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 17 13,195' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD -Orifice 18 14,888' 4.0" 5.875" Tripoint 7" 26-32# Permanent 19 14,974' 4-1/2" Liner Top Packer 20 14,932' 2.813" 4.50" X -Nipple 21 14,973' 4.276" 5.750" Packer Tie Back Bullet Seals stripped 22 15,067' Water Swell Packer 23 15,510' Plug (7/16/19) Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Status Date Tyonek G18 15,216 15,234' 14,419' 14,433' 18' Open 7/17/2019 Hemlock 15,900' 15,933' 14,984' 15,013' 33' Isolated w/ plug 7/11/2019 7/16/2019 West Foreland 16,408' 16,474' 15,434 15,491' 66' Isolated w/ plug 7/02/2019 7/16/2019 dated bV DG 08-2649 B Ilih.." M.A.. Ll: Well Prognosis Well: BCU-04RD Date:8/26/19 Well Name: BCU-04RD API Number: 50-133-20239-01 Current Status: New Sidetrack Leg: N/A Estimated Start Date: August 29", 2019 Rig: 169 Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 172-013 First Call Engineer: David Gorm (907) 777-8333 (0) (505) 215-2819 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) AFE Number: Maximum Expected BHP: —6,742 psi @ 15,416' TVD (.437 psi/ft. gradient to the WF) Max. Potential Surface Pressure: —968 psi (0.374 psi/ft diesel gradient) Brief Well Summary The BCU 4RD is being sidetracked out of the BCU 4 well bore. This was drilled to a depth of 16,642' MD. The purpose of this work/sundry is to shut of a water influx through a leak below the 7" liner hanger at 11,021' MD. Notes Regarding Wellbore Condition BC 4RD has been perforated at 15,216' MD with a 3-1/2" TBG string tieback with GL mandrels. The well currently has water in -fluxing behind the 3-1/2" TBG string at 11,021' which was confirmed by a noise log. A plug is set in the X -nipple at 14,932' isolating the 4-1/2" liner. Saxon #169 Procedure 1. MIRU Hilcorp #169 Rig. 2. Test BOPE to 250 psi Low/ 4,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 10 -min). Record accumulator pre -charge pressures and chart tests. a. Confirm test pressures per the Sundry Conditions of Approval b. Perform Test. c. Notify AOGCC 24 hrs in advance of BOP test. d. Test VBR rams on 3-1/2" test joint. e. Email completed 10-424 form to all AOGCC addresses listed on the form within 5 days of HOPE test. 3. L/D BOP test equipment. 4. Kill the TBG and TBG annulus through lower most GL mandrel (Note: Kill weight fluid to be calculated after circulating clean fluids around). 5. Pull 3-1/2" Production TBG 6. RIH set 7" RBP at +/-12,800' MD. Dump 50' of sand on top of the plug. 7. RIH shoot one hole in the 7" CSG below the liner hanger packer +/- 11,021' MD. 8. Mill out the 7" liner hanger set at 10,991' MD. 9. Cut the 7" CSG below the liner hanger between 11,025'-11,105' MD 10. Pull the 7" Liner hanger, RIH dress the 7" CSG top. 11. Install test 7" BOP rams --i 77,F /,4Ms F- , 12. RIH 7" overshot/ES cementer/+/ -1,400' of 7" 29# P-110 Liner and 9-5/8"X 7" packer top of packer +/- 9,700' MD. Tie back into the 7" cut liner top, engage overshot seals. H H&.up .4k.,ku. W: Well Prognosis Well: BCU-04RD Date: 8/26/19 13. Open the ES cementer at 11,100' MD, bullhead 20 bbl cement down provided able to inject then pump 32 bbl 15.4 ppg cement to cover to the packer. 14. Install VBR ram and test. 15. Pressure test the new liner to 2,000 psi. 16. Pull the 7" plug. r« rs 5.4a o 17. Install 3-1/2" Test joint pressure test VBR rams. 18. RIH 3-1/2" production TBG and mandrels, tie back into seal bore @ 14,884' MD. 19. Pressure test 3-1/2" annulus to 2000 psi. 20. ND BOP, NU Well head and test. 21. RU Slickline and run GR to bottom. RIH and remove plug in the X -nipple. POOH and Rig down Slickline. 22. RDMO Rig 169. 23. Turn Well over to production for Testing. Attachments 1. Actual Schematic 2. Proposed Schematic 3. BOPE Schematic 4. Current Wellhead Schematic 5. Blank RWO Procedure Change Form u I61""j. lla.k". W.l: Beaver Creels Field BC #4RD—Redrill 02/13/2019 Beaver Creek BC04RD Sldet,ad Beaver Creels Field BC #4RD 11/20/2018 Ililn,rp ;11ndn.1.1.1: Beaver Creek BC#4RD 20 x 133/8 x 95/8 x 3•h BHTA, Otis, 3 1/8 5M FE x 6.5" Otis quick union top Valve, Master, CIW-FLS, 31/85M FE, HWO, EE trim Valve, Master, CIW-FLS, 3 1/8 5M FE, H WO, EE trim Tubing head, FMC -TC -BG, 13 5/8 SM x 115M, w/ 2- 2 1/16 5M SSO Casing spool, OCT- C -22 -BP - 00, 21 W 2M x 13 5/8 SM, w/ 2- 2 1/16 SM SSOi Starting head, OCT -C22, 211/4" 2M x 20" SOW, w/ 2- 2 1/16 SM EFO Tubing hanger, FMC -TC -EN. CCL. 11 x 3 % EUE 8rd lift and susp, w/ 3" type H-8PV profile, 2-SGnpt control line port, 614 EN 5, Jxt-0'` 1 01 S�, �Hdsa J,fso4+•� 101 0111 Jaffe g5� a�ot 4,E 3y� Qet Adapter, FMC -ASP -CCL, 115M stdd x 3 1/8 SM, w/ 2- I" not control line exits UHilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well BCU 4RD (PTD 219-011) Sundry #: XXX -XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first calf' engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By (I itials HAK Approved By Initials AOGCC Written Approval Received (Person and Date) Approval: Prepared: Asset i earn Uperations Manager Date First Call Operations Engineer Date 0 Hilrnrp Alaska. LLC Proposed SCHEMATIC TD=16,642' (MD)/TD=15,657 (TVD) PBTD=16,5]2' (MD) / PBTD =15,527 (ND) Beaver Creek Unit Well: BCU 04RD Completed: 6/22/2019 PTD: 219-011 API: 50-133-20239-01-00 FAR No. 1 2 3 Depth 18' 2,418' 4,367' I ' 20" CASING DETAIL 4 5,921 .920" Size Type Wt Grade ConX8.681 Drift Top Btm 20" Conductor 94 H-40 7 4' Surface 288' 3-3/8" Surface 72 N-80 5.375" 3-1/2" FO -1 Mandrel 8RD Surface 2,989' 3-5/8" Production 47 & 53.5 N-80,5-95, P-110 10,278' 2.920" Surface 12,521' 7" CSG 29 P-110 I IC STC 6.059 9,700' 15,193' 7" CSG 26 L-80 I lGfrXP BTC 6.059 Surface 9,700' t-1/2" Liner 12.6 L-80 DWC/C 3.833 14,974' 16,607' 3-1/2- FO -1 Mandrel 8RD 16 13,195' TUBING Ril 5.375" 3-1/2" FC -1 Mandrel 8RD-Orifice 17 14,888' I-1/2" Tubing 9.3 P- SRD EUE 2.867 1 Surf 1 14,978' FAR No. 1 2 3 Depth 18' 2,418' 4,367' I ' 20" JEWELRY DETAIL OD Item - Tubing Hanger 5. 3-1/2" FO -1 Mandrel 8RD 5 3-1/2" FO -1 Mandrel 8RD 4 5,921 .920" .375" 3-1/2" FO -1 Mandrel 8RD 5 7,IL02 2. 5.375" 3-1/2" FO -1 Mandrel 8RD 6 15,933' 2.910" 5.375" 3-1/2" Cl Mandrel 8RD 7 4' 2.920" 5.375" 3-1/2" FDA Mandrel 8RD S ,934' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 16,474' ,606' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 7/02/2019 10,278' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 10,950' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 12 11,100' 7" ES cementer and Overshot Packoff seals 13 11,125' Water Swell Packer 14 11,665' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 15 12,392' 2.920" 5.375" 3-1/2- FO -1 Mandrel 8RD 16 13,195' 2.920" 5.375" 3-1/2" FC -1 Mandrel 8RD-Orifice 17 14,888' 4.0" 5.875" Tripoint -7-26-32# Permanent 18 14,974' 4-1/2" Liner Top Packer 19 14,932' 2.813" 4.50" X -Nipple 20 14,973' 4.276" 5.750" Packer Tie Back Bullet Seals stripped 21 15,067' Water Swell Packer 22 15,810' Plug (7/16/19) Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Status Date 15,216 15,234' 14,419' 14,433' 18' Open 7/17/2019 15,900' 15,933' 14,984' 15,013' 33' Isolated w/plug 7/11/2019 7/16/2019 16,408' 16,474' 15,430'15,491' 66' Isolated w/ plug 7/02/2019 7/16/2019 Updated by DG08-21-19 .B Hilmm Alaska. M Well Prognosis Well: BCU-04RD Date: 8/21/19 Well Name: BCU-04RD API Number: 50-133-20239-01 Current Status: Shut -In Oil Well Leg: N/A Estimated Start Date: August 29`h, 2019 Rig: 169 Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 172-013 First Call Engineer: David Gorm (907) 777-8333 (0) (505) 215-2819 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) AFE Number: Maximum Expected BHP: —6,742 psi @ 15,416' TVD (.437 psi/ft. gradient to the WF) Max. Potential Surface Pressure: —2,906 psi (based on 12.3 ppg 14,370' TVD) Brief Well Summary VAS The BCU 4RDIs Wing sidetracked out of the BCU 4 well bore. This was drilled t depth of 16,642' MD. The purpose of this work/sundry is to shut of a water influx through leak low the 7" liner hanger at 11,021' i MD. Notes Regarding Wellbore Condition BC 4RD has been perforated at 15,216' MD with a 3-1/2" TB tring tieback with GL mandrels. The well currently has water in -fluxing behind the 3-1/2" TIL t 11,021' which was confirmed by a noise log. A plug is set in the X -nipple at 14,932' isolating the /2" ' er. Saxon #169 Procedure V� 1. MIRU Hilcorp #169 Rig. 2. Test BOPE to 250 si Low 4 500 si Hi h, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 10 -min). ecord accumulator pre -charge pressures and chart tests. a. Confirm test pressures p r the Sundry Conditions of Approval b. Perform Test. c. Notify AOGCC 24 hrs n advance of BOP test. d. Test VBR rams on 3 /2" test joint. e. Email complete 10 424 form to all AOGCC addresses listed on the form within 5 days of BOPE test. 3. L/D BOP test equi ent. 4. Kill the TBG and G annulus through lower most GL mandrel (Note: Kill weight fluid to be calculated after irculating clean fluids around). K,,wr , W� 5. Pull 3-1/2" Pr duction TBG 6. RIH set 7" R Pat + -12 800' MD. Dum 50' of sand on top of the plug. 7. RIH shoot ne hole in the 7" CSG below the liner hanger packer +/- 11,021' MD. 8. Mill out a 7" liner hanger set at 10,991' MD. 9. Cut th 7" CSG below the liner hanger between 11 025' -11 10. Pull a 7" Liner hanger,IH dress the 7" CSG top. 11. Ins II test 7" BOP rams k.3 5-vo p 5 :, lC*1 -lamas f-� 12. RIH 7" overshot/ES cementer/+/ -1,300' of 7" 29# P-110 Liner and 9-5/8"X 7" liner hanger. Tie back into the 7" cut liner top, engage overshot seals. 13. Cement the 7" liner. W 0 44 .H Hilmm 1U88kM r.rl 14. Install VBR ram and test. 15. Pressure test the new liner. 16. Pull the 7" plug. 17. Install 3-1/2" Test joint pressure test VBF 18. RIH 3-1/2" production TBG and mand s 19. Pressure test 3-1/2" annulus to 20 psi. 20. ND BOP, NU Well head and tes Well Prognosis Well: BCU-04RD Date: 8/21/19 tie back into seal bore @ 14,884' MD. 21. RU Slickline and run G=for nd remove plug in the X -nipple. POOH and Rig down Slickline. 22. RDMO Rig 169. 23. Turn Well over to pro Attachments 1. Actual Scl 2. Proposed 3. BOPE Sch 4. Current 5. Blank w Ilhead Schematic Procedure Change Form Schwartz, Guy L (CED) From: Mack Myers <mmyers@hilcorp.com> Sent: Friday, August 23, 2019 1:51 PM To: Schwartz, Guy L (CED); David Gorm Subject: RE: [EXTERNAL) BCU 04A (PTD 219-0110 RWO SUNDRY Guy, The plan is to hang the liner off above the 53.5# 9-5/8" at 9938' then cement it from the cut at approximately 11,105' to 9838' 20• 94 H-40 0 288' ST&C csg 13-3/8' 72 H-80 0 1942' BIRD csp ' 68 J-55 1942' 2989' ' 9-5/8• 17 H-80 0 7421' Butt. cs9 47 5-95 7421' 9938' • 53.3 P-110 9938' 12.321' 7• 29 P-110 12,217' 12.552' • 32 P-110 12.532' 15.921' S' 18 N-90 14,487' I4,813' Isotntion Leer 3-1/2' 9.3 L-80 0 14,482' ORD AB Hod Tbp The volume of cement needed for this operation is: 27 bbls, this will fill the entire annulus. After the cement is in place and casing/liner lap is tested for leaks, we will wait at least 12 hours prior to splitting the stack to remove the single gate ram and install the 7" bowl. We will re -test the break after everything is nippled up to 4000 psi. The entire well bore will be full of kill weight fluid during the milling operations and when we are nippling down BOP'S. The 7" X 9-5/8" annulus will be tested after the tie back is landed. Let me know if you have additional questions. Thank you! Monty M Myers Drilling Manager 907.538.1168 (c) 907.777.8431 (o) From: Schwartz, Guy L (CED)[mailto:guy.schwartz@alaska.gov] Sent: Friday, August 23, 2019 11:38 AM To: David Gorm <dgorm@hilcorp.com> Cc: Ted Kramer <tkramer@hilcorp.com> Subject: [EXTERNAL] BCU 04A (PTD 219-0110 RWO SUNDRY David, I am reviewing the sundry on BCU 4A to repair the 7" liner lap leak. I need more detail (volumes, planned .00 etc) on the cementing operation starting in step 13. Please provide details on installing the extra 7" casing spool also. How long are you waiting after cementing till you split stack? I know you mentioned you would have to drop on of the ram bodies due to height of wellhead. Are you planning to test the 7 x 9 5/8" annulus after WOC. ?? Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE., This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ( or (Guy schwanz@alaska,aov(. 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No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. � STATE OF ALASKA ' ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil Gas[—] SPLUG ❑ Other ❑ Abandoned ❑ Suspended 20AAc 25.105 20AAC 25.110 GINJ ❑ WINJ ❑ WAGE] WDSPL ❑ No. of Completions: _ 1 ' 1b. Well Class: Development Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Aband.: 6/22/2019 14. Permit to Drill Number/ Sundry: 219-011 / 319-099 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: March 17, 2019 15. API Number: 50-133-20239-01-00 - 4a. Location of Well (Governmental Section): Surface: 1641' FNL, 631' FEL, Sec 33, T7N, R10W, SM, AK Top of Productive Interval: 2405' FSL, 1223' FWL, Sec 34, T7N, R1 OW, SM, AK Total Depth: 1869' FSL, 1660' FWL, Sec 34, T7N, R10W, SM, AK 8. Date TD Reached: May 13, 2019 16. Well Name and Number: BCU-04RD 9. Ref Elevations: KB: 166.2' • • GL:148.2' BE: 148.2' 17. Field / Pool(s): Beaver Creek Field Beaver Creek Oil Pool - 10. Plug Back Depth MDrTVD: . 16,512' MD / 15,527' TVD - 18. Property Designation: FEDA028083 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 315181 y-2433577 Zone- 4 TPI: x- 317012 y- 2432322 Zone- 4 Total Depth: x- 317442 y- 2431779 Zone- 4 11 taLDep MD/TVD: '16,64ZM 15,652'TVD• 19. DNR Approval Number: N/A 12. SSSV Depth Ni N/A 20. Thickness of Permafrost MD/TVD: N/A 5. Directional or Inclination Survey: -Yes L4J (attached) No Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: - 11,373' MD / 11,315' TVD 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, 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 ROP, DGR, EWR-Phase 4, CTN, ALD, ABG MD/TVD, Drilling Dynamics Log MD/TVD, Formation Log MD/rVD, Gas Ratio Log MD/TVD, LWD Combo Log MD/TVD, (PB1) CBL 5/6/19 23. CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 7" 29# P-110 10,991' 15,193' 10,946' 14,401' 8-3/8" L - 400 sx / T - 215 sx 4-1/2" 12.6# L-80 14,974' 16,607' 14,227' 15,618' 6" L - 165 sx 24. Open to production or injection? Yes Q No ❑ - If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 16,408' - 16,474' MD / 15,430' - 15,491' TVD / 6 spf / 2-7/8" / 7/2/19 (Isolated with Plug) 15,900' - 15,933' MD / 14,984' - 15,013' TVD / 6 spf/ 2-1/2" / 7/11/19 (Isolated with Plug) 15,2161- 15,234' MD / 14,419'- 14,433' TVD / 6 spf / 2-1/2" / 7/17/19 Open COMPLETION DA E 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/rVD) 3-1/2" 14,978' 14,974' MD / 14,227' TVD Liner Top Packer 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes No Per 20 AAC 25.283 (i)(2) attach electronic and printed information p DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: 7/9/2019 Method of Operation (Flowing, gas lift, etc.): Gas Lift Date of Test: 7/25/2019 Hours Tested: 24 Production for Test Period Oil -Bbl: 934.5 Gas -MCF: 100 Water -Bbl: 0 Choke Size: N/A Gas -Oil Ratio: 107 Flow Tubing Press. 80 Casing Press: 824 Calculated 24 -Hour Rate --J� Oil -Bbl: 934.5 Gas -MCF: 100 Water -Bbl: 0 Oil Gravity - API (corr): 34 Form 10-407 Revised 5/2017 CONTINUEp,O P7A2 R$DMSI�'AUG 2 2 2019 SubmitdOR171NIAL only 28. CORE DATA Conventional Core(s): Yes ❑ No ❑Q Sidewall Cores: Yes ❑ No Q 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. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑✓ If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval G1 B 15,216' 14,419' information, including reports, per 20 AAC 25.071. HP H2O Sand 14,937' 14,235' GIA 15,158 14,373' GIB 15,211' 14,415' G2A 15,544' 14,686' G213 15,773' 14,878' Hemlock 15,852' 14,944' H6 16,215' 15,257' West Foreland 16,387' 15,410' Formation at total depth: West Foreland 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports. 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. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drillinq Manager Contact Email: cdin er2hilcor .conn, Authorized Baty �y A_(/! Contact Phone: 777-8389 (J Signature: Date: INSTRUCTIONS General: 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. Item 1 a: 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. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: 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. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: 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. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: 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). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: 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. Item 30: 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. 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. Form 10-407 Revised 5/2017 Submit ORIGINAL Only �ATC lI AI ACl/ LY LIF J I A I L VF ALP /111!1 I ) -2019 I AND GAS CONSERVATION COMMISSION F IM11 R RECOMPLETION REPORT AND LOGS 1a. Well Status: ()it [Z Gas F-1 SPLUG ❑ Other ❑ Abandoned ❑ Suspended[-] 20MC 25.105 20a C25.110 GINJ ❑ WINJ ❑ WAGE] WDSPL ❑ No. of Completions: _ 1 1b. Well Class: Development ❑✓ Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Aband.: 7/17/2019 14. Permit to Drill Number / Sundry: 219-011 / 319-099 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: March 17, 2019 Pb t 15. API Number: it jtE J 50-133-20239-N-00 4a. Location of Well (Governmental Section). Surface: 1641' FNL, 631' FEL, Sec 33, T7N, R10W, SM, AK Top of Productive Interval: 2405' FSL, 1223' FWL, Sec 34, T7N, R10W, SM, AK Total Depth: 1869' FSL, 1660' FWL, Sec 34, WN, RI OW, SM, AK 8. Date TD Reached: May 13, 2019 16. Well Name and Number: BCU-04RD 9. Ref Elevations: KB: 166.2' GL:148.2' BF: 148.2' 17. Field / Pool(s): Beaver Creek Field Beaver Creek Oil Pool 10. Plug Back Depth MD/TVD: 16,512' MD / 15,527' TVD 18. Property Designation: FEDA028083 41b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 315181 y- 2433577 Zone- 4 TPI: x- 317012 y- 2432322 Zone- 4 Total Depth: x- 217442 y- 2431779 Zone- 4 11. Total Depth MD1TVD: 16,642' MD / 15,652' TVD 19. DNR Approval Number: N/A 12. SSSV Depth MD1TVD: N/A 20. Thickness of Permafrost MD/TVD: N/A 5. Directional or Inclination Survey: Yes ✓ (attached) No ❑ Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 1 21. Re-drill/Lateral Top Window MD/TVD: 11,373' MD / 11,315' TVD 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, 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 ROP, DGR, EWR-Phase 4, CTN, ALD, ABG MD[TVD, Drilling Dynamics Log MD/TVD, Formation Log MD/TVD, Gas Ratio Log MD/rVO, LWD Combo Log MD(rVD, (PB1) CBL 5/6/19 23. CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MD SETTING DEPTH ND HOLE SIZE CEMENTING RECORD AMOUNT CASING FT TOP BOTTOM TOP BOTTOM PULLED 7" 29# P-110 10,991' 15,193' 10,946' 14,401' 8-3/8" L - 400 sx / T - 215 sx 4-1/2" 12.6# L-80 14,974' 16,607' 14,227' 15,618' 6" L-165 sx 24. Open to production or injection? Yes ❑✓ No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 16,408' - 16,474' MD / 15,430' - 15,491' TVD / 6 spf / 2-7/8" / 7/2/19 (Isolated with Plug) 15,900'- 15,933' MD / 14,984' - 15,013' TVD / 6 spf/ 2-1/2" / 7/11/19 (Isolated with Plug) 15,216' - 15,234' MD 114,419- - 14,433' TVD / 6 spf 12-1/2" / 7/17/19 Open COMPLETION DATE VF 1pir-n 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 3-1/2" 14,978' 14,974' MD / 14,227' TVD Liner Top Packer 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes ❑ No ✓ Per 20 AAC 25.283 (1)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: 7/9/2019 Method of Operation (Flowing, gas lift, etc.): Gas Lift Date of Test: 7/25/2019 Hours Tested: 24 Production for Test Period Oil -Bbl: 934.5 Gas -MCF: 100 Water -Bbl: 0 Choke Size: N/A Gas -Oil Ratio: 107 Flow Tubing Press. 80 Casing Press: 824 Calculated 24 -Hour Rate --J� Oil -Bbl: 934.5 Gas -MCF: 100 Water -Bbl: 0 Oil Gravity -API (corr): 34 Form 10-407 Revised 5/2017 CONTINUED ON PAGE 2RBDMS "AUG 2 12019 Submit ORIGINIAL only 28. CORE DATA Conventional Core(s): Yes ❑ No Q Sidewall Cores: Yes ❑ No Q 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. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No Q If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval GIB 15,216' 14,419' information, including reports, per 20 AAC 25.071. HP H2O Sand 14,937' 14,235' GIA 15,158 14,373' GIB 15,211' 14,415' G2A 15,544' 14,686' G2D 15,773' 14,878' Hemlock 15,852' 14,944- H6 16,215' 15,257' West Foreland 16,387' 15,410' Formation at total depth: 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports. 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. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: cdinger@hilcorp.com Authorized Contact Phone: 777-8389 Signature: —' Date: INSTRUCTIONS General: 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. Item 1 a: 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. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: 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. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: 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. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: 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). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: 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. Item 30: 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. 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 othertests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only Beaver Creek Unit Well: BCU 04RD :6/2 2/2019 PTD: 2199-0-0111 ACTUAL SCHEMATIC Completed: .... AI.A.. r.zc API: 50-133-20239-01-00 KB Elm: 166Y/ BF/GL Bev.:148.2' 1- t 20 Zone Top(MD) Btm(MD) CASING DETAIL 2 Depth 13.3/8' Size Type Wt Grade Conn. DriftTop 10 - Elm 20" 3 94 H-40 N/A 4 288' 13-3/8" Surface 5 N-80 12.415 Surface 6 9-5/8" Production 47 & 53.5 N -80,S-95, P-110 8,681 Surface 12,521' 9 Liner 29 P-110 IC/TXP BTC 6.059 9 15,193' 4-1/2" Liner 12.6 to 3.833 14,974' 16,607' 9 9,606' tt TUBING DETAIL 3-1/2" FO -1 Mandrel 8RD 10 10,278' 3-1/2" Tubing 22 1 P-110 I 8RD EUE 1 2.867 Surf 14,978' 7" Liner Top Packer 12 13 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 14 11,128' 19 14 11,665' 2.920" 5.375" 16 BCU04 12,392' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 16 13,195' 2.920" 5.375" 3-1/2" FO -1 Mandrel BIRD - Orifice ra@ 14,888' 4.0" 5.875" Tripoint 7" 26-32tt Permanent 12,6mmo 14,974' 4-1/2" Liner Top Packer 19 14,932' 2.813" 4.50" 17 20 14,973' 4.276" 5.750" Is 21 15,067' 791 Clik 15,810' 21 HPW C@ Y 14,985'- 15,155' MD yuck Gte ?2 west favlm 4-1/2' TD =16,642'(MD) / TD=15,652' (TVD) PBTD=16,512'(MD) / PBTD =15,527' (TVD) Zone Top(MD) Btm(MD) CASING DETAIL No. Depth ID Size Type Wt Grade Conn. DriftTop 10 - Elm 20" Conductor 94 H-40 N/A Surface 288' 13-3/8" Surface 72 N-80 12.415 Surface 2,989' 9-5/8" Production 47 & 53.5 N -80,S-95, P-110 8,681 Surface 12,521' 7" Liner 29 P-110 IC/TXP BTC 6.059 10,991' 15,193' 4-1/2" Liner 12.6 L-80 DWC/C 3.833 14,974' 16,607' 9 9,606' 2.920" TUBING DETAIL 3-1/2" FO -1 Mandrel 8RD 10 10,278' 3-1/2" Tubing 9.3 1 P-110 I 8RD EUE 1 2.867 Surf 14,978' Zone Top(MD) Btm(MD) JEWELRY DETAIL No. Depth ID OD Item 1 18' 2.992" - Tubing Hanger 2 2,418' 2.920" 5.375" 3-1/2" FO -1 Mandrel BIRD 3 4,367' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 4 5,921' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 5 7,150' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 6 7,495' 2.920" 5.375" 3-1/2" Cl Mandrel 8RD 7 8,134' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 8 8,934' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 9 9,606' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 10 10,278' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 11 10,991' 7" Liner Top Packer 12 10,950' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 13 11,128' Water Swell Packer 14 11,665' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 15 12,392' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 16 13,195' 2.920" 5.375" 3-1/2" FO -1 Mandrel BIRD - Orifice 17 14,888' 4.0" 5.875" Tripoint 7" 26-32tt Permanent 18 14,974' 4-1/2" Liner Top Packer 19 14,932' 2.813" 4.50" X -Nipple 20 14,973' 4.276" 5.750" Packer Tie Back Bullet Seals stripped 21 15,067' Water Swell Packer 22 15,810' Plug (7/16/19) Zone Top(MD) Btm(MD) Top(TVD) Stm(TVD) Amt Status Date Tyonek G1B 15,216 15,234' 14,419' 14,433' 18' Open 7/17/2019 Hemlock 15,900' 15,933' 14,984' 15,013' 33' Isolated w/ plug 7/11/2019 7/16/2019 Isolated w/ plug 7/02/2019 West Foreland 16,408' 16,474' 15,430' 15,491' 66' 7/16/2019 Updated by DMA 08-07-19 n �.Ops summary Well Name: BCU-04RD Field: Beaver Creek County/State: Kenai, Alaska (LAT/LONG): at 52" right. Up wt 175K, di wt 174K. S/O to 12,041', PU next single and MU topdrive. Pump at 412 gpm-1328 psi and orient whipstock at 46° right. S/O and oration (RKB): CIBP at 12,053' DPM. Set down 15K and engaged anchor. PU and pulled 10K over to 184K, S/O to 150K and had good indication anchor set. PU to API #: otagged 0K to verify anchor set, S/O to 130K,and had good indication shear bolt broke. Top of whipstock ramp at 12,030', bottom of ramp at 12,04T. PU 10' with no Spud Date: 3/17/2019 Job Name: 1910116D BCU-04RD Drilling Contractor HEC 169 AFE #: AFE $: Hill Energy Company Composite Report �.Ops summary 3/17/2019 Cont TIH with Baker Gen It whipstock/anchor assembly (ramp is 17.10' long), 8 3/8" starter mill, 8 1/4" lower mill, 9.05' flex joint, 8 3/8" upper mill, one jnt 5" HWDP, Sperry DM and TM collars, float sub w/float, XO, 18 jnts 4 1/2" HW DP. Total BHA length = 649.99'. SLM stands on off -side of derrick as we ran them. With 367 singles of 4 1/2" DP in the hole, MU topdrive at 12,014' and filled pipe.,Filled pipe then increased pump rate to 400 gpm-1300 psi to orient whipstock at 52" right. Up wt 175K, di wt 174K. S/O to 12,041', PU next single and MU topdrive. Pump at 412 gpm-1328 psi and orient whipstock at 46° right. S/O and CIBP at 12,053' DPM. Set down 15K and engaged anchor. PU and pulled 10K over to 184K, S/O to 150K and had good indication anchor set. PU to otagged 0K to verify anchor set, S/O to 130K,and had good indication shear bolt broke. Top of whipstock ramp at 12,030', bottom of ramp at 12,04T. PU 10' with no erpull, slow rotated with no increase in torque.,Held PJSM with Mud Engineer, rig crew and Peak drivers on displacing well to 9.5 ppg 6% KCL water based mud.,Lined up pumps and pits for displacement, pumped 20 bbl hi -vis spacer followed by 819 ball 9.5 ppg 6% KCL mud at 216 gpm-503 psi.,Empty pits of 00 production water and clean pits. Line up new active system with mud on hole. Set up surface equipment to take returns from milling window. Lay down single jt of 4-1/2" DP and M/U stand from Derrick., Establish flow and rotary parameters. Mill 8.375" window from 12030' V 12034'. 295 GPM, 1000 psi. 80 RPM, 2.8- 11.5k tq. 1-2k WOB. PIU = 174k, S/O = 160K, Rot = 160K 3/17/2019 Mill 8.375" window from 12034' U 12042'. 405 GPM, 1575psi. 90 RPM, 4-11.5k tq. 5-8 WOB. P/U = 174k, S/O = 11 Rot = 160K. Change out leaking Pop- off on #1 MP. Pump 20 bbl Hi Vis sweeps around @ 12031' & 12037'.;Capturing metal at end of shakers & via ditch magnets in shaker flow box. Seeing 15- 20% cement returns with cuttings sample @ 12035'. Trace amounts of formation with sample @ 12039'; -Hauled 0 bbls solids to KGF G&I Cumulative: 0 lbs -Hauled 340 bbls fluid to KGF G&I Cumulative: 1325 Will -Daily downhole losses: 0 bbls Cumulative:0 bbls -Daily metal: 10 lbs Cumulative: 65 Ibs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 3/18/2019 Continued milling window and new formation from 12,042' to 12,087'. Bottom of ramp is at 12,047'. Made 40' new hole to fit Sperry GeoPilot on next BHA. While milling window: WOB 4 to 8K, 405 gpm-1571 psi, 100 rpm -1500 to 9900 ft/lbs torque, 2-8 ft/hr ROP, MW 9.5 ppg/vis 47, BGG 14 units. At 12,044';we saw 60% formation (tuff claystone and siltstone) and 40% cement. We had a gas spike of 80 units after drilling through a 5' coal at +/- 12,052' then BGG dropped back to 16 units. Pumped 20 bbl sweep at 12,084'. While milling new formation: WOB 5-20K, 1500 to 15,000 ft/lbs on bott torque.;Cont to pump sweep around while working mills in/out of window. 406 gpm-1737 psi, 106 rpm -3400 ft/lbs off bolt torque. Up wt rotating 170K, dwn wt 170K, rot wt 170K. With sweep out of hole (no increase in cuttings) worked mills with no rotation, window nice and smooth. Worked mills with no;pump or rotation and upper mill was grabbing at top of window. Cont to work mills with various rpm's, pump on and off until it cleaned up and smoothed out. Pulled up into casing.;Obtained SPR's. Racked back one stand OP in derrick. Blow down TopDrive and service Iines.;RU pressure testing equip.. Shut the UPR and perform FIT targeting 12.5 ppg EMW with existing 9.5 ppg MW. At 1400 psi, 4.04 bbls pumped, a pressure loss was experienced. Pumped additional 0.17bbls and pressure drop to 1325psi. Shut in and line up to bleed off. Bled back 3.6 bbis.;Perform FIT again and pumped 6.13 bbls, achieving 1863 psi with no issues. Bled back 4.94 bbls. Open the UPR, blow down lines and RD the pressure testing equipment.;POOH from 12023' to 10501' laying down 49 jts 4-1/2" DP.;Continue pulling out of the hole from 10501' to 9073' racking stands in Derrick.; Inspect drilling line. Cut and slip 71'.;Continue POOH from 9073' to 7023?.; -Hauled 0 bbls solids to KGF G&I Cumulative: 0 Ibs -Hauled 540 bbls fluid to KGF G&I Cumulative: 1865 ball -Daily downhole losses: 0 bbls Cumulative:0 bbls -Daily metal: 525 lbs Cumulative: 590 lbs Conductor ann pressure- 0 psi 3/1912019 Cont to POOH with Baker milling assembly from 7023' to 897'. Floorhands heard iron roughneck pipe spinner roller making noise.; Inspected and replaced pipe spinner roller and bearings.;Cont POOH from 897' to surface, LD Sperry DM/TM collars and Baker mills. Upper mill in gauge, lower mill 114" under gauge. Called out a welder to repair crack in back of shaker #3.;PU joint 4 1/2" DP and johnny wacker. Flushed stack cavities and chokelkill line ports to clear any metal cuttings. Drained stack, LD jnt DP, PU test jnt, pull wear ring, installed test plug. Found debris sticking out from blind ram cavities. Opened both blind doors and removed loose strips of;rubber from each ram that may have affected lest. Sealing faces are fine. Buttoned up blind doors, back flushed kill and choke lines. RU for BOP test. Flooded surface lines and stack. Purged air and shell tested. Witness of BOP test waived by AOGCC Rep Jim Regg and BLM Rep Amanda Eagle.;Total Safety on location and tested gas alarms. Start BOP test, Test annular to 250 psi low, 5 min- 2500 psi high, 10 min, 4000 psi High for 10 min on all other tests. Test #1- Annular (Pass). Test #2 - Upper pipe rams, mezzanine kill valve, dart valve & hydraulic IBOP (Pass).;Test #3 - UPR, Kill HCR, TIW & Manual IBOP (Pass). Test #4 - UPR, manual kill, TIW. (Fail/Pass) - Chart sensor bladder failed during test, re-test good. Test #5 - UPR, manual kill, manual choke. (Pass).;Continue testing BOPE, 250 psi Low, 5 min - 4000 psi High, 10 min. Test #6 - UPR, manual kill, choke HCR, TIW. (Fail/Pass) - Observe pressure loss on low test. Bleed down and re-test good.;Test #7 - CMV # 1,3,4,5,&7, UPR, manual kill, TIW. (Fail). Troubleshoot pressure loss. Bleed air from system, isolate valves and found CMV #5 to be leaking. Test #8 - CMV #1,4,7&8, UPR, manual kill, TIW (Pass). Test #9 - CMV #6,7,11 &13, UPR, manual kill, TIW (Pass).;Test #10 - CMV #9,&12, UPR, manual kill, TIW (Pass).;-Hauled 0 bbls solids to KGF G&I Cumulative: 0 lbs -Hauled 180 bbls fluid to KGF G&I Cumulative: 2045 blots -Daily downhole losses: 0 bbls Cumulative:0 bbls -Daily metal: 48lbs Cumulative: 638 lbs Conductor ann pressure-0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 3/20/2019 Continue testing BOPE, 250 psi Low, 5 min - 4000 psi High, 10 min. After good test on CMV #2,3 &10, went back to choke manifold valve #5. Greased valve then applied some pressure and cycled to clear any potential debris or air caught in valve. Attempted a re-test with no further issue.;Obtain good test on lower pipe rams at 250 psi Low, 5 min - 4000 psi High, 10 min followed by good test on both Electric and Manual choke at 1500 psi . Performed draw down test on accumulator unit then tested blind rams at 250 psi Low, 5 min - 4000 psi High, 10 min (good test).;Removed flow riser, PU single with MPD RCD bearing. Install RCD and MU topdrive. Flood lines and inspect for leaks. Pressure test Beyond RCD and hardline at 250/1500 psi.;UD MPD RCD bearing then installed flow riser. R/D test equipment, blow down and vac'd out MPD hardline and rig choke line. Pulled test plug, installed wear ring with 9" 1D.;Mobilize BHA components to the rig floor. PJSM with rig crew and Sperry Reps on handling & M/U BHA.;M/U BHA #4 - 8 3/8" KM524 Kymera bit, 7600 Geo-Pilot, DM, ILS, DGR, EWR, PWD, HCIM, TM, Float Sub, 2x Flex Collars, Float Sub, XO, 4x HWDP jts. Obtain good MWD shallow hole test and blow down TopDdve.;Flow check MPD corealis, troubleshoot a calibration error. Consult with technicians while continue M/U BHA - DAH Jars & 15x HWDP jts.;Fill pipe and check MPD corealis, while lubricate and break in the RSS seals. Getting same calibration error.;Trip in hole with drilling assembly on 4-1/2" drillpipe stands from 763' to 5978'. Fill pipe every 2500'.;Trip in hole with drilling assembly on 4-1/2" drillpipe singles from 5978' to 8582'. Fill pipe every 2500'. Make and break connections with new cut threads 2x. 3/21/2019 Continued to PU and single in hole from 8582'to 10,755'. Any re-cut threads were made up/broke out twice at 80% and 100% of MU torque. Had no issue with re-cut threads, no joints were culled.;Cont TIH from derrick, from 10,755'to 11,936'.;MU topdrive at 11,936' and filled pipe. Hung blocks for cut and slip.;Cut and slipped 42.75' drill line to ensure we could drill section, POOH and run liner before next line cut. Calibrated block height, checked crown saver and inspected saver sub (OK).;Eased in hole from 11,936' to 12,060', exiting window at 12,047' with no issue. Began reaming under gauge hole from 12,060' at 0- 5K WOB, 525 gpm-2442 psi, 60 rpm-4565 to 4900 ft/lbs off bott torque, down to 12,087' (milling depth). Sperry had trouble communicating with Geo-Pilot as soon as pumps;were started. Attempted to turn on ABG with no success. Attempted HCIM sensor reset, HCIM seeing downlink. Attempted Geo-Pilot sensor reset with no success. Reset sensors with delay, cycled pumps to reset bus powered tools and had no change. Changed VDF mode to "B" via downlink, cycled pumps;to reset tool and had no change. Notified Drilling Manager. As a last ditch effort pulled Geo-Pilot back into casing and shut down pumps for 30 minutes. Upon re-start of pumps, sent TF correction, still no response from Geo-Pilot. Have to POOH. (Had 4 total downlink successes during TIH);Pump dry job and POOH from 12029'to 10759, racking stands in Derrick.;Continue POOH from 10750' to 5978'. Laying singles down to catwalk.;Service rig, level sub base due to ground settling.;-Hauled 0 bbls solids to KGF G&I Cumulative: 0 lbs -Hauled 90 bbls fluid to KGF G&I Cumulative: 2135 bbls -Daily downhole losses: 0 bbls Cumulative:0 blols -Daily metal: Olbs Cumulative: 638 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 3/22/2019 Re-connected MPD hardline that was broke loose to level up sub base.;Cont to POOH from 5971' to 300' racking DP, HWDP, jars, NM flex DC's back in derrick. Plugged in and downloaded MWD. Sperry Rep was able to read all tools down to Geo-Pilot, and the vibration sensor in the top of Geo-Pilot. Could not read anything below vibration sensor. Racked back smart iron;cluster in derrick, broke off bit (graded 0-0) and LD Geo-Pilot. Geo-Pilot also had some blue colored oil weeping from port in side of body. Possibly an internal seal failure.;PU replacement Geo-Pilot, MU Kymera 8 3/8" bit (re-run). MU smart tool cluster, plug in and upload MWD, MU NM flex DC's and 2 stands HWOP.;Service rig and topdrive, adjust Kelly hose while void of fluid.;Fill pipe and shallow test Sperry tools, good test.;R)H with jars and remaining HWDP. Cleaned draw works encoder, depth sensor eye & calibrated hook load, quadrature, and adjusted & set C.O.M to resolve depth tracking issue.;TIH out of derrick F/763'- T/3,247'.;Filled pipe and circulated to break in seals on Geo pilot, Pumped through MPD hard line with drilling mud & purged out air, PIT MPD hard iron 250 psi Low/ 1,500 psi High (Good).;Cont. TIH out of derrick F/3,247'-T/5,971', filled pipe and staged up pumps to turn on tools to insure we had good communication (Good).;Started P/U singles off walk , TIH F/5,971'-T/8.921', filled pipe, staged up pumps and sent down link to insure we still had communication to tools and Geo-pilot (Good).;Cont. P/U singles off walk & TIH F/8,921'-T/10,039'.; Hauled 0 bbls solids to KGF G&I Cumulative: 0 lbs -Hauled 0 bbls fluid to KGF G&I Cumulative: 2135 bbls -Daily downhole losses: 0 bbis Cumulative:O bbls -Daily metal: O lbs Cumulative: 638 lbs Conductor ann pressure- 0 psi 3/23/2019 Cont TIH with directional assembly from 10,039' to 11,889, MU topdrive.; Filled pipe, tested downlink to Geo-Pilot and obtained SPR's above the window.;PJSM, hung blocks, cut and slipped 42' drill line. Inspected kick back rollers and springs on brake bands. Calibrated block height and hook load. At 11,880' SPR's MP1 at 47 spm = 271 psi, MP2 at 46 spm = 268 psi.;Eased in hole to 12,000', MU topdrive and broke circ at 400 gpm-1535 psi, eased down and out the window exiting the ramp at 12,047'. SIO to 12,066' with no problem. MU next stand and washed reamed down to 12,087' at 400 gpm, 50 rpm-4000 fUlbs off bott torque.;Commence drilling 8 3/8" hole from 12,087' to 12,279'. WOB 14 to 20K, 510 to 510 gpm-2300 psi, 60 to 120 rpm-5900 to 7865 It/lbs on bott torque, 12 to 104 R/hr ROP, MW 9.5/vis 43, ECD's at 9.8 ppg, BGG 14 units, max gas 92 units. Trip gas of 23 units.;Cont drilling from 12,279' to 12,408', drilled through 5' coal seam @ 12,357', WOB-7115K GPM-500 SPP-2250-2350 psi RPM-100/120 TQ-7/8K ROP-40'/HR.;observed weight not drilling off @ 12,408', P/U and back reamed 30' w/ 10K over pull, figured stab 39' back in the BHA was hanging up on coal ledge, washed & reamed back down F/12,396'- T/12,408' w/ 7K WOB TQ-4.SK/5.5K RPM 120 to clean up coal seam @ 12,357' around stab,;had a fair amount of coal coming across the shaker upon BU. Drilled std down T/12,434', back reamed std w/ no issues. P/U- 178KS/0-172K ROT-172K w/ pumps on.;Cont. drilling F/12,441'-T/12,558', WOB 12K/15K GPM-515 SPP-2400 psi RPM-100/120 TQ-7/8K ROP-30740' PIU-176 S/0-168K ROT-170K.; Had lube pump light flashing on top drive control panel, checked oil pressure on top drive while continued to circulate, showed 90 psi w/ 100 RPM on rotary, tried to adjust, seen no increase in pressure. Greased top drive, blocks and draw works.;Cont. drilling F/12,558'-T/12,602' WOB-12/19K GPM-515 SPP-2425 psi RPM-100/120 TQ-6.5/7K ROP-15-25'/HR P/U-177K S/0- 168K ROT-170K.;Cumulative: 0 lbs -Hauled 0 bbls Fluid to KGF G&I Cumulative: 2310 bbls -Daily downhole losses: 0 bbls Cumulative:0 bbls -Daily metal: 15 lbs Cumulative: 653 lbs Conductor ann pressure-0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 3/24/2019 Cont drilling 8 3/8" hole from 12,602' to 12,830'. WOB 20 to 30K, 510 gpm-2390 psi, 130 rpm-9700 R/lbs on bott torque, 74 ft/hr ROP, MW 9.5/vis 42, ECD's at 9.8 ppg, BGG 23 units, max gas 32 units. Shipped water base mud from pits 9-10 and cleaned same for OBM weight up.;Cont drilling 8 3/8" hole from 12,830'to 13,115' (planned wiper trip depth). WOB 20 to 30K, 520 gpm-2564 psi, 140 rpm-10,440 ft/lbs on bolt torque, 70 to 80 R/hr ROP, MW 9.5/vis 47, ECD's at 9.9 ppg, BGG 26 units, max gas 167 units. Up wt 183K, dwn wt 170K, rot wt 178K.;Pumped 20 bbl hi-vis nut plug sweep around while rotating/reciprocating. 514 gpm-2490 psi, 82 rpm-4400 ft/lbs off bott torque. Had 10% increase in cuttings with sweep to surface. Obtained SPR's and survey.;Pulled up hole on elevators from 13,115' to 12,179', keeping tools outside the window, P/U- 194K SIO-176 ROT-178K, had two over pulls during wiper trip, F/12,943'-T/12,924' 15K & F/12,1354112,12620K, 3/0 and worked through both of them on elevators.;Once at 12,179', circulated w/ one pump @ 3 bpm, service rig, inspected top drive lube pump filter (OK) , replaced regulator for lube pressure and tested, still 90 psi line pressure.;TIH F/12,179'-T/13,085', set depth at crack, washed and reamed last std to bottom, set down 10K & pressured up @ 13,100' (ledge), at BU hole unloaded with silt, sand, and some small chunks of clay. Had good pipe displacement in & out during trip. Max gas after BU once back on bottom 1050 units.;Cont. drilling 8-3/8" hole F/13,115'- T/13,425', WOB-22-27K RPM-140 GPM-505 SPP-2400 TQ-7.5/11.5K ROP=80-110'/HR P/U-182K S/0-165K ROT-172K. Distance to plan: 11.90' Low 2.92' Right.;Cum ulative: 0 lbs -Hauled 205 bbls fluid to KGF G&I Cumulative: 2515 bbls -Daily downhole losses: 0 bbls Cumulative:0 bbls -Daily metal: 3 lbs Cumulative: 659 lbs Conductor ann pressure- 0 psi 3/25/2019 Cont drilling 8 3/8" hole from 13,425' to 13,713'. WOB 22K, 522 gpm-2694 psi, 140 rpm-9700 ft/lbs on bott torque, 35 to 90 ft/hr ROP, MW 9.5/vis 45, ECD's at 9.8 ppg, BGG 30 units, max gas 177 units. ;Cont drilling 8 3/8" hole from 13,713'to 13,930'. WOB 13K, 523 gpm-2684 psi, 140 rpm-9100 ft/Ibs on bolt torque, 65 to 100 R/hr ROP, MW 9.5/vis 46, ECU's at 9.9 ppg, BGG 20 units, max gas 159 units. 3 trailers of 7" casing (84 jnts) staged on pad #3. Replaced dodge coupler on pump #2.;Cont drilling 8 3/8" hole F/13,930'- T/13,955% brought mud weight up by two tenths (9.7 ppg) to help hold back coals, started seen more frequent slip/stick, not sure if it was coming from formation, tried changing drilling parameters multiple ways with no success,;tried adding one drum of NXS lube to suction pit, sending it down hole in pill form, seen a short window of decrease in slip/stick after lube came out the bit.;Cont. drilling 8-3/8" hole T/14,110', observed more frequent torque spikes (5K-14K)- slipistick, called town engineer and discussed possibility of adding lube, decision was made to bring active system up to 1% by volume of NXS lube to reduce slip/stick. WOB-15-25K RPM-100/140 GPM-510 SPP-2750 psi.;TQ-5-14K P/U-192K SIO- 165K ROT-175K. Once NXS lube rounded the bit, observed a definite decrease in slip/stick. Also working on laying out 7" liner, removing thread protectors, and drifting liner on Pad #3.;Cont. drilling F/14,110'-T/14,234' wiper trip depth, WOB-12-20K GPM-505 RPM-140 SPP-2650 psi TQ-8/13K P/U-182K S/0- 164K ROT-171 K.;Pumped 15 bbl Hi-vis sweep w/ walnut, had a 50% increase in cuttings, sweep came back 15 bbls late, mostly sand and coal, pumping additional BU, before TOOH to last wiper depth of 13,100'. Distance to plan: 2.52' high 2.57' left on Iine..;Cumulative: 0lbs -Hauled 34 bbls fluid to KGF G&I Cumulative: 2549 bbls -Daily downhole losses: 0 bbls Cumulative:0 bbls -Daily metal: 0lbs Cumulative: 659 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 3/26/2019 Crew change. Monitored well for flow, well static.;Pulled up hole on elevators from 14,234' to 14,000 and started seeing overpull. Went 20K -30K -40K over with no clean up. MU topdrive and attempted to pump ourselves up the hole. Still getting overpull starting at 14,012'. Rotating to backream at 90 rpm -5810 ftllbs off bott torque, 417 gpm-2070 psi.;Seeing some packoff and torque spikes. Worked entire stand backreaming, then worked stand with no rotation then no pump and was clean straight pull. MU topdrive and straight pulled next stand with no problem, then had to backream up to 13,919'. MU topdrive and straight pulled from 13,919 up to;13,857' and seeing overpull. Backreamed up to 13,816' and seeing packoff/stalling.;Cont to circulate at 410 gpm-2068 psi, rotate at 93 rpm - 4690 ff/Ibs torque while building sweep. Staged pump rate up to 454 gpm-2433 psi, getting fair amount coal chips on shakers. Pumped sweep prior to getting bottoms up. At bottoms up had +/- 25% increase in cuttings, gas went up to 88 units then;dropped back to 27 units. With sweep to surface had maybe 10% increase in cuttings. Rotating and reciprocating stand with no packoff or stalling.;Cont to pump out of hole F/13,816' -T/13,169', up wt while pumping 188K. At 13,169' pulled into tight spot, had to pulled 60K over P/U wt to cock jars, then sat down 30K below S/O wt, fired jars to free ourselves, once free cleaned up std and rack back in derrick.;Cont. to pump & ream F/13,169' -T/12,990', RPM -50 GPM -425 , reamed each std up/dn, after std cleaned up, pumped & pulled w/ no rotary, minimal overpull with no rotary (3K).;weighted whole mud system up to 10 ppg, pumped 20 bbl weighted Hi -Vis sweep, shaker started unloading 190 bbls into pumping sweep, shakers continued to unload till 462 bbls pumped, once sweep came back to surface at 12,616 stks,;shakers unloaded again with cuttings, 150% increase, mostly pea size coal, sand and some hard ball size pieces, sweep was 30 bbls Iate.;Sewiced rig while continuing to circulate well, greased crown, blocks, top drive and floor motor, checked drive line bolts and linkage (OK), inspected flow meter on top drive hydraulic fluid pump, reset VFD top drive screen due to being froze,;also replaced 2 hoses and O-ring on floor motor Chelsey PTO pump while continuing to circulate @ 500 GPM.;Washed & reamed F/12,990' -T/13,270', RPM -75 GPM -420 TQ -5/11 K SPP -2000/2200 psi, had to work through multiple tights spots, mostly coals and some sand stone areas.;Cont. to wash & ream F/13,270' -T/73,557', RPM -80 GPM -300/450 TQ -6.5/15K SPP -2000/3100, continued to have to work through multiple tight spot and some packing off, mostly coal areas with top stabilizer.;Once we reached our trip depth 13,557', pumped 15 bbl Hi -Vis weighted sweep while rotating (140 RPM) & reciprocating pipe, waiting from sweep to return to surface.; -Hauled 151 bbis solids to KGF G&I Cumulative: 317 lbs -Hauled 84 bbls fluid to KGF G&I Cumulative: 2633 bbls -Daily downhole losses: 0 bbls Cumulative:23 bbls -Daily metal: 6 lbs Cumulative: 665 Has Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 3/27/2019 Continue pump sweep around @ 13,557' rotating @ 140 rpm and reciprocating full std sweep back 50 bbls late w/ 25% increase.;Attempt make connection and unable to stab pipe in grabber box ( Clean and inspect grabber box Back die block hanging out) pull std on elevators and rack back same U 13,489' remove broken bolts and dutch men install key stock and new cap bolts.;wash and ream and work thru pack -off issues t/ 13,897'.;Pump 33 bbl high vis weighted sweep around and circ clean while rotating and reciprocating pipe back 57 bbls late and 50% increase.;Wash and ream and work thru pack off issues U 13998'.;At 13,998' got hung up w/ high kelley, racked back std and P/U working single, work and attempted to free pipe, pulled 60k-80K-t00k over and set down to 140K, fired jars multiple time before finally coming free in the down stroke, washed and reamed to clean up stand, racked std back in the derrick.; Had 500 units of gas while washing & reaming to clean up std, discovered we had lost cam to Geo pilot, tried to reset multiple time w/ no success, called town to discuss options, decision was made to TOOH and UD Geo pilot. GPM -380 SPP -1800/2500 psi RPM -100-140 TQ-5-18K.;Continued to wash and ream F/13,955'- T/13,859, UD the next single to replace our working single and gel back on even std.;At 13,859 lined up pumps, pumped a 32 bbl Hi -Vis high weight sweep, sweep came back 65 bbls late, with a 50% increase in cuttings, mostly pea & quarter size coal pieces w/ some sand and clay.;Cont. to wash & ream F/13859'- T/13,109, working through multiple tight spots and pack offs, P/U-180K S/0 -170K ROT -178K GPM -180012625 psi RPM -100/140 TQ -5/16.5K. 3/28/2019 Continue Backing reaming OOH f/ 13,100't/ 12,377' w/ no problems.;Cease rotation and Pump OOH and watch jars come into window and over pull @ 12,332' (bit depth w/ jars across window) discuss issue w/ town and slowly working over pull up to 90 k over and knocking free w/ do jar or torque and slump w/ free travel below.;lncreased over pull t/ 120k over once and Working on do jar and torque and slump to free pipe w/ no movement.;Monitor well static and let brakes cool do and inspect brakes.;Resume do jar @ 100k and torque slump w/ no movement.; Pump 17 bbl NXS lube pill @ 14% by volume and spot around bha and let brakes cool.;Resume do jar @ 100k and torque and slump w/ no movement.;Let pill soak brakes cool and preform derrick and TSD inspection.;Resume do jar @ 100k and stack wt V 130k and torque and slump w/ no movement.;Park pipe w/ 130k do wt w/ 101k trapped torque Adjust brake handle and dwk kickback rollers.;Resume do jar @ 100k and stack wt 1/130k and torque and slump and free pipe w/ free travel below.;New crew perform a complete inspection of derrick, tds, dwk & brakes while discussing plan fwd w/ town, decision was made to cont. to pull through window using slow rotary 10- Y'� 25 RPM and stage up to 60K over pull, trying to work BHA through window. Pumps off: P/U-166K S/0 -162K Pumps on: P/U-164K.;S/0-160K GPM -347 SPP- IJ 1440 psi Free TQ-2.6K.;Cont. to work though window, P/U weight 30, 40, and 50K over pull- increments, staging rotary up each time from 10-25 RPM'S, 5 gained 8' of pipe travel wl the same PIU weight of 210 T/12,324', started seeing quarter size pieces of coal at shakers at BU, 20% increase.; Pumped 31 bbl Hi - Vis weighted sweep @ 13,360' Kelley down, while rotating at 140 RPM and pumping 480 GPM , attempting to clean out any coal that may be obstructing us from pulling inside window, sweep came back on time, 25% increase in cuttings, mostly quarter/chunky size coal, sand,;and a hand full of hard ball size pieces after STS strokes.;Cont. to work pipe through window, got hung up again @ 12,332', started jarring again, P/U to 60K S/O and set down 100K and firing jars, got pipe free after several attempts. washed & reamed bottom of std to clean up hole.; P/U and washed and reamed two aids back in hole out of the derrick, attempting to clean up any coal beds around bottom and of BHA that maybe hanging us up, no issues getting back in hole T/12,490', had a couple tight spot, but no packing off.; Pumped 31 Hi -Vis weight sweep to clean up hole, while rotating & reciprocating pipe, RPM -140 GPM -480 SPP -2600 psi.;Washed & reamed std @ 12,490' while sweep was going around, observed a fair amount of chunky coal coming over shakers before sweep was half way back to surface. Racked first stand back in derrick, started washing second stand up and sweep started coming back,;sweep was on time with a 100% increase in cuttings, mostly pea size pieces of coal with some quarter size pieces along with sand. Racked back second std in derrick, started washing and reaming original working stand @ 12,356'.;Cont. to work back up inside window with rotary at 25 RPM GPM 480, made 5' more T/12,319', and got hung up again, started jarring, P/U to cock jar, set down to fire jars, setting down 100k to fire jars, got free and decided to let break cool. Noticed jars taking longer to fire (2-5 min).;Jars getting week, letting breaks cool down, doing a complete post jaring inspection. 3/29/2019 Continue circ and let jars and brakes cool down, Rig maintenance test rebuilt IBOP 250L & 4000H ok, clean MP liner wash boxes and clean suction and discharge / screens / repaired mp suction of pill pit chg out air line on dwk mtr.;Rih f/ 12, 356' U 13,333' looking for some resistance to store Bha on found ledge @ 41 degs and set 50k on twice w/ clean p/up @ 180k traveling plup w/ no pumps.;P/up t/ 13,303' and circ clean while waiting on E -line @ 430 gpm well started unloading coal 1/3rd of the way into btm up quarter to 1/2 dollar sized coal pieces.;Dn pump and set 50k do wt on ledge @ 13,333' PJSM and r/up Pollard E -line on DP.;Rih #1 w/ 3' X 2.125" pert gun loaded w/ 18 shots phased @ 6spf of 1/2" exit holes tied into Xo and jars logged tie in pass 12,000' and place gun on depth , fired w/ good indication . top shot @ 12,111.55' & bottom shot @ 12,114.5, POOH w/ w/ gun verified all 18 shots fred.;M/U Radial cutting torch, weight bars, 2 centralizers, CCL, and anchor, RIH #2 w/ RCT tool 4.2'X 2.5 OD, correlated to through tubing gun shots log and HWDP, set on depth @ 12,115.5', discharged torch to sever pipe , seen no weight loss on Pollard wireline when torch discharged,;estimated TOF 12,115.5', went to move tool up hole and noticed over pull. Neutral wP2,300 P/U wt- 2,500K, over pulled was 1,200.;Altempted to free Pollard wireline RCT, w/ no success, called town engineer, decision was made to try and move pipe up hole 5', cont. to free tool while waiting on wireline clamp from town. P/U wt was 2,500, the most we pulled was 4,100 due to rope socket separation was 4,500-5,000.;Pollard hand showed up w/ clamp, held PJSM, installed clamp on wireline at top of pack off on DP stump, move sheave from elevators to secondary spot in derrick on drillers side, removed short bails and installed long;bails (16). Removed clamp on wireline, latched elevators on pipe, pulled out of slips, P/U pipe 12' and seen 138K hanging weight, good indicator of severed pipe, original P/U weight before cut was 180K P/U weight. attempted again to free RCT tool from pipe with no success.;made call to town engineer, decision was made to pump down DP to free RCT tool, R/U hoses to side entry sub, started pumping, at 650 psi tools came free out end of cut pipe, tried multiple time to pass DP tools jt just above cut Point @ 12,092', finally after multiple attempts got tools through;first tool jt, , pulled up hole 200' and hung tools again, pumped free 2 times and finally passed tool jt, currently at 9,036' POOH.; -Hauled 151 bbls solids to KGF G&I Cumulative: 317 lbs -Hauled 84 bbls Fluid to KGF G&I Cumulative: 2633 bbls -Daily downhole losses: 0 bbls Cumulative:23 blots -Daily metal: 6lbs Cumulative: 665 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 3/30/2019 Continue Pooh w/ spent RTC f/ 9036' t/ surface w/ no more hang up. R/dn E -line and swap back to short bails (see photos of slag on RTC).;Pooh f/ 12,115' thru window and into csg w/ no issues t/ 11, 865' ( pulling out on single to swap brakes ).;Slip and cut 90' of drlg line and adjust brake linkage & monitor well, no losses static, service rig , chg/out grabber block bofts.;Circ btm and pump dry-job.;Continue Pooh on single rack back in derrick f/ 11,865'.;Trip sheet off Flow chk well ( notice rubbed Flat spots on dip, see photos).;Conl. POOH & UD 4.5" pipe, F/11,180'-T/7,074'.;Crew change, held PJSM, cont. POOH F/7,074' -T/4,189', had 4 tool its that were hard to break, observed some galled threads on the 4 stds, racked them back in the derrick to get second opinion from day light tour, went to continue POOH and;heard loud noise around draw works motor, chained down break, discovered quarter to dime size pieces of rubber all over draw works skid, started looking around and noticed a missing rubber 6"x6" pad between the oil cooler radiator & the glycol radiator.;Motor man also noticed missing nut on Floor motor alternator, replaced nut, cleaned out fan shroud and continued POOH.;Cont. POOH and had 4 tool jts that were hard to break, observed major galled threads and some missing chunks of threads on pin end, wrote on pin & box of each bad std. Stood back in derrick to UD bad jts after POOH w/ cut jt.;Cont. POOH F/4,189'-T/surface, inspected the last 900' of DP close for OD marks, no marks were observed only shine pipe, 6.55' was the cut-off length and we did have all 18 pert hole & cut looked (OK), cut point by drill pipe measurement was 12,111.88'.;Called out Weatherford fishing Rep Neal Crandall to put together a milling BHA to dress window.;Sewiced rig, greased top drive, draw works, iron roughneck and brake linkage, and changed dies on iron roughneck.;UD 4 bad jts out of the 4 stds, P/U the 4 good jts and racked back in the derrick.;Cleaned up rig Floor, started loading cat walk with milling BHA tools and strapping tools.; -Hauled 45 blots fluid to KGF G&I Cumulative: 2812 bbls -Hauled 30 bbls solids to KGF G&I Cumulative: 533 bbls -Daily downhole losses: 0 bbls Cumulative:23 bbls -Daily metal: 0lbs Cumulative: 675 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 3/31/2019 Continue strap tally She and confirm pipe count on location in stall splash guard on top of bopes.;shut do dwk mtr and Repair dwk mtr radiator . Disassembled radiator framework installed softeners between radiator core and inner cooler core reassembled trim top guard to prevent rubbing on inner cooler.;PJSM and p/up bha #6 (window mills dressing assy).;Rih w/ Bha #6 f/ 320' t/4470' also P/up bad jt w/ box OD of 5.24" and chk box deflection w/ Iron rough neck . low clamp = .001" and high clamp .004" ( see video in photo file ).;Rih from 4470't/ 4600' w/ 4 std marked for inspection and I/dn 4 jts and adjusted tally, cont. TIH F/4,600'-T/5,257'.;Crew change, held PJSM, continued RIH w/ BHA #6, P/U 120 jts off rack, RIH F/5,257' -T/8.907', filling pipe every 2,500', calibrated hook load after filling pipe. P/U-85K S/0-90K.;Filled pipe, calibrated hook load again, blew down top drive, and set depth at crack.;Started TIH out derrick, F/8.90T-T/9,938', went through P-110 53.5 Ib. casing @ 9,938' with 8.437" upper watermelon mill (OK), @ 11,706' were we had tight spot seen 5K drag over 6'. P/U-124K S/0-124K.;Cont. RIH F/11,706' -T/11,993', lined up to fill pipe (25 bbls), P/U-148K S/0 -145K.; Established circulation, P/U-155K S/0 - 153K ROT -158K SPM -95 GPM -230 SPP -681 psi TQ -3.3, shut down rotary, washed F/11,993' -T/12,084', were top mill 8.437 OD was at the top of window, seen down 5K & P/U of 3K, pulled back up to 12,072', turned on rotary to 70 RPM, started coming down slowly,;milling with very little torque till 12,078' (torque spikes), continued to mill T/12,088, using 3.2K as are low & 4K as our high, working our way to the bottom of the window with the upper mill, seeing occasional torque spikes F/12,078'- T/12,088' 5-7K TQ.; -Hauled 0 bbls fluid to KGF G&I Cumulative: 2812 bbls -Hauled 0 bola solids to KGF G&I Cumulative: 533 bbls -Daily downhole losses: 0 bbls Cumulative:23 bbls -Daily metal: 0 Ibs Cumulative: 675 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 4/1/2019 Continue Ream/mill and dress whip stock window w/ Bha # 6, tandem in line string mills top mill @ 8-7/16" and him mill @ 8-3/8" and 5" hwdp stinger w/ 8-3/8" bit f/ 12072't/ 12095' w/ 5-B.Sk torque spikes @ 12087, 12089.4', 12089.7' 12090.3 12094'& 12095'.;Drift in hole Ok with and w/out pump and rotation w/ 2k or less still getting slight 2-3k over pulls w/ top mill at top of window continue back mill and dress clean tell able drift ooh w/ no pump or rotation less then 2k.;wash in hole at 350 gpm f/ 12098' t/ 12,149' & tag fish deep @ with 8k Pump ooh and back into csg U 12,020'.;Circ 22 bbl high vis sweep around @ 500 gpm 2300 psi w/ no real in cress in cutting just some small coal pieces and recovered 5# iron off ditch magnets continue circ and finish chg/out spinner ODS bearing in iron rough neck.;flow chk static pooh 5 std f/ 12,020' t/ 11,865' Pump dry job.;Pooh F/ 11,865' U 6340' chk box OD of 5.25" and chk box deflection w/ Iron rough neck. low clamp = .001" and high clamp .003".;Crew change, held PJSM. POOH w/ BHA #6, UD singles, F/6340' -T/5158', P/0 -98K 8/O-101 K.;Conl. POOH F/5158' -T/323', racking back stds in derrick, check crown saver (Good), PIU -81 K S/0-82K.;UD BHA #6, racking back 3 stds of drill collars, noticed some fresh horizons[ & vertical scrapes on the drill collar (see photos of scrapes), cleaned extreme magnet, and recovered 24 lbs of metal, mostly fines w/ a small hand full of thin quarter to half dollar pieces. (see photos of recovered;pieces), no marking observed on jars, lower baker mill was in gauge 8-3/8" w/ little to no new wear (see photos of lower mill), upper Weatherford mill was 8-7/16" (new) and out of gauge by 1/16+ and showed a significant amount of wear (see photos of upper mill),;Sewiced rig, cleaned rig floor, fixed omni wrap on Kelley hose, greased draw works, brake linkage, blocks, top drive, and checked drive line bolts (Good).;Changing out saver sub on top drive, strap & tally fishing BHA #7.; -Hauled 166 bbls fluid to KGF G&I Cumulative: 2976 bbls -Hauled 16 bbls solids to KGF G&I Cumulative: 549 bbls -Daily downhole losses: 0 bbls Cumulative:23 bb[s -Daily metal: 31 lbs Cumulative: 706 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-518 ann pressure - 0 ns 4/2/2019 Crew chg and PJSM and continue chg out saver sub strap and tally fishing assy. Bha #7.;Pull wear ring.;PJSM w/ weatherford on p/up fishing assy bha #7 and p/up same t/ 233'.;Rih w/ bha #7 w/ dp out of derrick f/ 233' U 5106.;Continue rih p/up 120 jts 4-1/2" dp f/ 5105' U 9540'.;Crew change, held PJSM, resume rih out of derrick f/ 9540' t/11726'. filled pipe, calibrated block weight after filling pipe, P/U-129K 8/O -135K, held BOP drill, took 48 seconds for everyone to be in place (Good time).;Held PJSM, cut and slip 81' of drlg line (long cut), inspected brakes, kick rollers, and measured the block on the linkage bar, its at 1-1/16", tighten drive line bolts, run blocks up/down checking crown o matic.;Conl. TIH F111726' -T/12.020', just above top of window , recalibrated hook load again, P/U-160K S/0-162K.;Slaged up pumps F/220 -T/500 GPM, SPP- F/590 -T/1780 psi, circulated STS to warm up mud, no increase in cuttings while circulating STS.;Started washing down 17112,020', GPM -115, SPP -358 psi, went through window with no issues, cont. to wash down T/12,212', started taking weight w/ no pressure increase, kicked in rotary to 15 RPM, worked string multiple times up/down, P/U-158K S/0-156K.;TQ 4-6K, torqued up to 10K, P/U and torque broke over, brought pumps up, GPM -230 SPP -590 psi, TQ -3.2, cont. wash & ream down slowly, started to take weight @ 12,217', observed pump pressure increasing, killed pump and rotary, set down 40K, engaged fish, noticed definite weight increase.;P/U and bled jars w/ 20,40,60K over pull, started working fish OOH w/ no pump. P/U-208K S/0-1 95K, current depth of over shot 11,280'.: -Hauled 55 bbls fluid to KGF G&I Cumulative: 3031 bbls -Hauled 0 bb[s solids to KGF G&I Cumulative: 549 bb[s -Daily downhole losses: 0 bbls Cumulative:23 bbls -Daily metal: 0 lbs Cumulative: 706 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 4/3/2019 Continue work fish thru window and unable to pass 11,259' (O/Shot depth ) w/ no fishing jar action w/ over pulls t/ 110k and knocking loose w/ bumber sub ( 10 th jt of HWDP across window ) fish bit depth = 12462' and lost bite on fish discuses options w/ town ih found and engaged TOF @ 11,620' and work fish back thru window U 11,262' w/ no fishing jar action w/ over pulls U 110k and unable pass same and knocking loose w/ bumper, and torque sub and lost bit on fish 2nd time;Rih found and engaged TOF @ 11,602' and work fish back thru window t/ 11,261' wl no fishing jar action w/ over pulls U 110k and unable pass same and knocking loose w/ bumper, and torque sub and lost bite on fish 3rd time;Rih found and attempt to engaged TOF @ 11,561' unable to catch fish (slipping off) call town and discuss options;Circ him /up flow chk;Pooh /dn Emergency kelly and working single and rack back 2 std stand t/11,469';P/up test plug and hang off work string w/ 140k , blew down top drive, r/ up test jt and equipment, flooded BOP stack, choke, and test equip, functioned valves to purge trapped air, preformed shell test (OK).;Test witnessed by AOGCC Rep Austin McLeod, Started BOP test: Test #1 annular, inside choke, inside kill, dart valve (Pass).;Crew change, PJSM Test#2 upper pipe rams, choke manifold, CM 1,3,4,5,7 & HCR kill valve, dart valve, hydraulic IBOP, functioned valves and purged air (Fail/Pass). Test #3 upper pipe rams, cm 2,4,5,6,8 kill HCR, TIW, lower IBOP (Fail), high test held,;low test failed, functioned & serviced valves, purged air, retested w/ no luck, jumped to test #8 Lower pipe rams TIW valve, and lower IBOP (Pass). Tried retesting test 93 w/ no success;Pulled test plug P/U-140K, drained stack, inspected, changed out O-ring on test plug and re -dressed , no cut or wear marks on removed O-ring, run in test plug, seated in profile, filled stack w/ water, functioned rams and purged air.;Shell tested to 4,000 psi (Good), Retried test #3, good high test, still no low test, annuals valve had a very fine stream of mud coming out of it while test, determined water was leaking by test plug due to amount of string weight below plug causing it to not seat correctly in profile.; Pulled lest plug again, inspected (Good), redressed 0 -ring, run in and set, filled stack, tried re -testing #3, couldn't get test on low, high test jugged, decision was made to TOOH and rack back pipe to drop weight below test plug, RIO test equip, UD test plug & test jt.;TIH to verify fish depth before TOOH, TI F/11,469' -T/11,561' were we tagged TOF, started POOH F/11,561' -T/10,270'. P/U-140 S/0-142;Decision was made to shut down TOOH, preform LOT, R/U test equip, closed upper rams, pressured up to 2,500 psi with mud pump, bleed off F/2560 psi -T/1753 psi over 10 min, staged pressure up with test pump and reached max pressure before we seen a true injection rate. RID testing equip.; -Hauled 50 bb[s fluid to KGF G&I Cumulative: 3081 bbls -Hauled 0 bbls solids to KGF G&I Cumulative: 549 bbls -Daily downhole losses: 0 bbls Cumulative:23 bbls -Daily metal: 0lbs Cumulative: 706 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 4/4/2019 Continue bleed back of injection test pressure f/ 2035 psi seen 8.87 bbls back over all and injected total of 15.5 ppg. open well and chk flow (static) pump dry job blow do TDS and Iines;Continue pooh f/ 10,070' 118790' rack back on ODS;Continue Pooh I/dn 100 its jts f/ 8790' V 5709;Resume pooh racking back on DS V 5700' V 5006';Drain stack hang off trill string on test plug and r/ up testing equipment flood equipment and purge air and get good shell test 2501 -ow / 4000 High;test hopes as per regulations witnessed by AOGCC Austin McLeod. Test #1 -annular 250/Low for 5. 2,500/high for 10 (Pass). Test 92 - upper pipe rams, mez kill, dart, Hyd. IBOP, CM #1,3,4,5, &7 (FaiVPass). Test #3 -upper pipe rams, Kill HCR, TIW, Man, IBOP, CM #2,4,5,6,& 8 (Pass).;Test #4 -upper pipe rams, inside kill, TIW, CM #7,9,11,& 13, working on trouble shooting issues;Crew change, held PJSM, cont. to try and get test #4 with no luck, discussed with AOGCC rep Austin McLeod, decision was made to POOH, UD fishing tools and test wl no weight hanging below test plug.; R IH w/ 11 stds F/5,006'-T/5,66T to get back to our original 120 its to UD and stay on track. P/U-82K S/0-83K.;POOH BHA #7, UD 20 its, F/5,6634/5,043'. Cont. TOOH racking back in derrick F/5,070'-T/233';UD BHA #7, racking 3 stds of DC, inspected BHA for scars, DC had multiple areas with new scrapes/scars (see photos), the mandrel area on the jar area was pulled out 3/4" (see photos) , the bumper sub was in the closed postion when it came through the table (see photos),;and cut lip guide was missing a chuck of metal and very scared up (see photos), piece of the grapple was broke but held in tack and rubber pack off seal was gone (see photos);Serviced rig -greased crown, blocks, top drive, draw works, and iron roughneck, inspected breaks & break linkage 1-1/16" on block on break bar., tightened drive line bolts, replaced transmission cooler hoses.;Monitored well (static) P/U & M/U test it to TIW & dart, and test plug, check seals (Good), flooded chock manifold, lines, and stack, started purging air out of the system.; -Hauled 45 bbls fluid to KGF G&I Cumulative: 3,126 bbls -Hauled 0 bbls solids to KGF G&I Cumulative: 549 bbls -Daily downhole losses: 0 bbls Cumulative:23 bbls -Daily metal: 0lbs Cumulative: 706 lbs Conductor ann pressure- 0 psi 13.3/8 X 9-5/8 ann pressure - 0 psi 4/5/2019 Crew Change and PJSM let new crew re -purge air out system .; Re- Test hopes as per regulations witnessed by AOGCC Austin McLeod. w/ F/P on test #4 and 5 and Determine choke HCR is the culprit of Rouge bad test Finish test 6-11 Pass; Bleed down accumulator, changed out choke side 3-1/8" HCR.;Functioned new choke, reflooded BOP stack, choke manifold, purged air out, Tested #12- retested blinds, mez. kill, CM #7,10, & 12 250/Low 4000/high (Pass). Test #13 -retested blinds, mez, kill, choke HCR, 250/Low- 4000/high (Pass).;Pulled test plug/test it laid out same, closed annular valve, blew down choke manifold, R/D testing equip.,;Set 9" wear ring, tighten lock downs, clean up rig floor.;Crew change, held PJSM, inspected CM line up & BOP equip., break TIW & dart apart, strap & tally fishing BHA *8, get ID's, OD's, fish necks, and Iengths.;Held PJSM w/ SLB fishing hands, P/U & M/U BHA#8 and RIH, switched over to 4.5" DP elevators.;RIH w/ BHA #8 out of the derrick, F/233'-T/5,076'.;Cont. TIH P/U single off rack, F/5,076' -T/8,793" P/U-79K S/0-81 K; - Hauled 100 bbls fluid to KGF G&I Cumulative: 3,276 bbls -Hauled 0 bbls solids to KGF G&I Cumulative: 549 bbls -Daily downhole losses: 0 bbls Cumulative:23 bbls -Daily metal: 0lbs Cumulative: 706 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 ps' 4/6/2019 Crew change and PJSM, Rih out of derrick 8793't/ 11,467';Circ btm/up and warm mud;Blow do TDS and lines cut Wand slip 12 wraps ddg Iine;Swap TDS gen sets inspect and grease DWK's;Rih f/ 11,467' V 11,532' out derrick , Establish parameters wash ream in hole f/ 11,532' V 11,997' (fish was not at last tagged depth of 11,561' ) tagged fish @ 11,997 do pump and engaged and swallowed fish P/up 20k over bleed jars and over pull set grapple w/ 50k over;Work fish up hole for couple std w/ some Jar licks and up to 100k over pulls and knocking loose w/ bumper sub T/ Original tight spot of 11,261 and hung pipe establish circ at 504 gpm and was able work free w/ bumper sub and 180k stacked do weight work pipe cool brakes circ btm up;appeam we got some circ thru fish w/ small gas spike at btm up as per mud loggers w/ no real increase in cuttings mainly sand and still no response from smart tools;Crew change, held PJSM, cont. to circulate 525 GPM, SPP -2095 psi, called town engineer to discuss options, decision was made to try slow rotary with pumps, kick in rotary to 10-15 RPM, started working OOH F/11,25f7-T/11,248', TO-3K/12K P/U-190K S/O-182K ROT-188K;Pumped 22 bbl lube & spotted around drilling BHA, shut down and let soak.;Held PJSM w/ Beyond, Pulled trip nipple, P/U MPD rotating head/bearing and stabbed. Changed out the bladder in pump #1 pulsation dampener and cleaned mud pump 1 & 2 suction screen. P/U-190K S/0-182K;Staged pumps up to 510 GPM, SSP -2070 psi, started holding 200, 400,600, and 800 psi back pressure w/ MPD while working over pull up F/45k-85K, trying to work pipe up hole, got hung @ 11,245', cont. to work pipe free, pulling 180K up and s/d of 80K, while holding 800 psi back pressure (no luck),;bled off pressure, continued to free pipe w/ 180K P/U & 80K S/O, shucked fish out of grapple. P/U-155K S/0-156K;RIH to get latched back up to fish F/11,250' -T/11,343', noticed MPD's rotating bearing element was Ieaking.;Shut down, pulled MPD's rotating head, swapped back to there trip nipple;Continued TIH F/11,343' -T/11.966' , tagged TOF, P/U-160K S/O-161 K 115 GPM 322 psi;tried to engage fish, pushed fish F/11,966' -T/12,001', called town engineer, decision was made to push it down T/12,100', couldn't get latched on to TOF. P/U-161 K S/D-30K to push fish down hole w/ no success,; -Hauled 100 bbls fluid to KGF G&I Cumulative: 3,276 bbls -Hauled 0 bbls solids to KGF G&I Cumulative: 549 bbls -Daily downhole losses: 0 bbls Cumulative:23 bbls -Daily metal: 0 lbs Cumulative: 706 lbs Conductor ann pressure- 0 psi 13-318 X 9-5/8 ann pressure - 0 psi 4/7/2019 Crew Change and PTSM Continue circ w/ 130k do weight stacked on fish let brakes cool and preform post jarring inspection of complete rig;Attempt pull off fish and pooh but managed to get other bit on fish work free fish up hole few feet and still unable to get fish go do hole Kick in rotary and shucked fish work back do over fish couple times w/ no engagement ETOF @ 11,993';Pooh V 11,993't/ 11,830' flow chk static pump dry job continue pooh f/ 11,830' t/ 9727' w/ 37 std U DS of Mast;Rih f/ 9727' t/ 11,938'w/ 36 std dp from ODS of mast; Pooh Service break first 22 std (44) jts to complete thread inspection and all pipe in derrick has been service broke f/ 11,938' U 6500' total 88 std; Udn 90 jts dp f/ 6500'V 3709';Crew chg and PJSM Continue Pooh I/dn singles F/3,709'-T/2,775', 120 jts total.;Cont. POOH F/2,775'-T/233', racking stds back in demck.;Changed over to 5" elevators, UD BHA#8, no obvious damage to tools, just a small chunk of metal missing from the cut lip guide (see photos), grapple & pack off were in good condition (see photos);Cleaned up rig floor, prepped for R/U Pollard E-Line,;RIH w/ E-line, run #1- gamma ray, CCL, J-basket, & 8.25 gage ring. Tagged TOF @ 12,014' E-line depth, logged collars & coals on the way out F/12,014'-T/11,000'. P/U & WU tools for 2nd run on E-line, gamma ray, CCL, & Baker cement retainer.:-Hauled 100 bbis fluid to KGF G&I Cumulative: 3,276 bbls -Hauled 0 bbis solids to KGF G&I Cumulative: 549 bbis -Daily downhole losses: 0 bbis Cumulative:23 bbis -Daily metal: 0 lbs Cumulative: 706 lbs Conductor arm pressure- 0 psi 13-3/8 X 9-518 ann pressure - 0 psi 4/8/2019 Crew change and PJSM w/ E-Iine;Rih w/ E-line run #2 New Gamma Ray, CCL & BOT 9-5/8" cmt retainer f/ 53.5# csg @ 8.08" OD (Tie in to Duel induction log? , dated 6/29/72 w/ -23' correction down loaded from the state, GR tie in good and correlates w/ DPM) set do on fish 11,994' P/up 5' w/ top of Cmt retainer @ 11,987';six foot below collar @ 11,981' had good indication of set. Pooh Logging t/ 11,000' Continue pooh and chk running tool (ok) R/dn E-line ( place LAS file in DSM file under Logs );Service traveling equipment chk fluids in Motors;PJSM r/up to run tbg stinger;P/up BOT cmt stinger and 27 jts of 4 1/2" tbg = 826.85';Rih w/ Tbg stinger Bha #9 , on dp out of derrick to 5669'.;RIH w/ Tbg stinger Bha #9 on dp from 5669' to 6788' picking up singles;Continue RIH w/ Tbg stinger She #9 on dp out of derrick from 6788' to 11875'.;Establish circulation at 210 GPM, 500 psi. Shut down, Hold PJSM and line up on choke. Circulate through choke holding 1000 psi, training and practice with crew on working manual choke. Once proficient at maintaining back pressure, line back up on flow line and finish circulating bottoms up.;RIH from 11875' to 119391. P/U- 150k, S/O- 150K. Establish circulation at 2.7 BPM, 380 psi and RIH. Tag cmt retainer at 11983'. Set 20k down and continue pump to 1000 psi. Still seeing return flow.;Pull up and disengage stinger. Establish circulation at 2.7 BPM and SIC, to 11983'. Set 30k down. Pressure increase to 1000 psi, still getting return flow. P/U out of retainer and S/O with 2.7 BPM setting 50k down & 1500 psi. Still have return flow.;P/U and increase flow to 4 BPM, S/O slowly setting 50k down & 1000 psi. Still getting return flow. P/U and engage pump @ 2.7 BPM. SIO slowly until stinger sets plug in neutral position. Pressure increased to 1860 psi and held, flow ceased. Held 1860 psi for 5 min then S/O setting 20k down.;Pressure bled off to 550 psi and observe return flow. Determined there is comm around the outside of the cmt retainer. Pull up and pressure csg to 2000 psi, observe psi drop to 1700 psi, confirming leak around cmt retainer. Discuss options with Drilling Engineer. Decision made to set balanced plug;Rack 1 std back and P/U a single jt & 15' pup it. Position stinger 1' above cement retainer.;Hold PJSM with Halliburton and rig crew. Pressure test cement lines to 700 psi low 15000 psi high.;Pump cement plug as per plan. Pump 23 bbls 12.5 ppg spacer, 33.2 bbis 15.3 ppg cement, 7 bbls 12.5 ppg spacer & displace with 144 bible 10.2 ppg drilling mud.;Pump first spacer @ 1 BPM, Pump cement @ 2.5 BPM, Pump second spacer @ 3 BPM, Stage mud displacement from initial rate of 5 BPM - 108 psi to 6.5 BPM - 155 psi @ 118 bbls pumped, final rate of 5 BPM - 420 psi. CIP @ 05:51;- 5:51;Hauled Hauled30 bbls fluid to KGF G&I Cumulative: 3,306 bbls -Hauled 0 bible solids to KGF G&I Cumulative: 549 bbls -Daily downhole losses: 0 bbls Cumulative:23 bbis -Daily metal: 0 Ibs Cumulative: 706 lbs Conductor arm pressure- 0 psi 13-3/8 X 9-5/8 arm pressure - 0 psi 4/9/2019 Finished displacing with a total of 144 bbls 10.2 ppg 6% KCL mud. Broke off 15' pup and working single, LD same. Pulled up hole 8 stands at 30 ft/min, then pulled 8 more stands up to 10,934'.;Installed wiper ball in drill string, MU topdrive and circulated surface to surface to clear any cement from drill string and wellbore. Recovered wiper ball, had an increase in PH but not in mud weight. Shut down and flow check (static), pumped dry job and blew down topddve.;POOH from 10,934' to 8,144', pumped second dry job, cont POOH from 8,144' to 826' (LD 36 ints 4 1/2" DP), broke off XO's to 4 1/2" tubing, called out Baker Rep.;Swapped handling equipment from 4 1/2" DP to 4 1/2" tubing, RU Weatherford tubing tongs.;POOH LD 27 jnts 4 1/2" tubing from 826to surface. Baker cement stinger in very good condition.; RD Weatherford tubing tongs, swap handling equipment back to 4 1/2" DP. Crew change, RU test pump on kill line for casing test. Called out Pollard e-Iine.;Tested 9 5/8" casing at 2500 psi for 30 min on chart. Pumped 10.8 bbis, 9.5 bbls bled back.;R/U Pollard E- Line, RIH with 8.25" gauge ring, junk basket, GR & CCL. Tag cement at 11491'. GR & CCL logs correlate with previous runs. Confirm collar at 11388'. POOH and UD junk basket & gauge ring. 2' contaminated cement in junk basket.;M/U CIBP on E-Line and RIH to 11450'. CCL log from 11450' up to 11250' to confirm with previous runs. -good correlation- . Set CIBP with top of plug at 11383', good indication of set. POOH, check running tool and R/D E-Line equipment.;-Hauled 55 bbis fluid to KGF G&I Cumulative: 3,361 bbis -Hauled 0 bbis solids to KGF G&I Cumulative: 549 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bbls -Daily metal: 0b Cumulative: 706 lbs Conductor arm pressure- 0 psi 4/10/2019 RD and released Pollard a-line after setting CIBP in 9 5/8" casing at 11,383'.;Staged Baker whipstock assembly and mills, Sperry NM flex DC's and DM/TM collars, and new 4 1/2" HWDP on pipe racks for PU, held PJSM with Baker and Sperry Reps.;PU jnt 5" HWDP, MU 8.375" upper mill, 9' flex joint, 8.250" lower mill and 8.375" starter mill. PU whipstock assembly, removed 3 of 6 pins from anchor (set to shear at 20K), aligned and installed 45K shear boll installing starter mill to ramp. PU and MU DM and TM collars. MU float sub;and two jnts NM flex DC's. RFO = 279.10°. PU two jnts 4 1/2" HWDP, MU topdrive and performed a good shallow pulse test. Cont PU single in hole with total 18 jnts 4 1/2" HWDP to 711'.;Cont TIH from derrick on 4 1/2" DP, from 711' to 5,554' filling pipe every 2500'. MU topdrive and filled pipe.;Hung off blocks, cut and slipped 85' drill line, calibrated block height, checked crown saver. Held day crew over a bit to help new 4th crew get oriented to rig.;PU single in hole 36 jnts 4 1/2" DP from yard, from 5,554' to 6,673', then cont TIH from offside derrick to 8,494'.;Continue TIH with Whipstock on 4-1/2" DP stands from 8494' to 11200'.;Fill pipe, establish circulation and orient TF @ 37° right of highside. 412 GPM 2000psi. PU & SO = 158k.;RIH and tag CIBP @ 11378'. Set whipstock with good confirmation of shears (anchor @ 18k, Slide @ 38k). BOW = 11373', TON= 11356.;Circulate bottoms up at 440 GPM, 2165 psi.;-Hauled 0 bbis fluid to KGF G&I Cumulative: bbbis -Hauled 0 bbisle so solids to KGF G&I Cumulative: 549 boss tee -Daily downhole losses: 0 boss Cumulative: 23 bbls -Daily metal: 0lbs Cumulative: 706 lbs Conductor ann pressure- 0 psi - \ t k5 13-3/8 X 9-5/8 ann pressure - 0 psi 1AC'P 4/11/2019 Began milling window from 11,356' to 11 366' in 9 5/8" casin . Initial woo i-3K, 422 gpm-2070 psi, 80 rpm-3,100 to 10,000 ft/lbs torque, 0-2 It/hr ROP. MW 10.3/vis 49, BGG 2 units. At 11,360' had a trace of cement, at 11,365' had 50% metal-50% cement.;Cont milling window from 11,366' to 11,375'(2' into formation from bottom of ramp), web 6-19K, 421 gpm-2065 psi, 100 rpm-4600 to 11,000 fUlbs torque, 2-3 fUhr ROP, MW 10.3/vis 49, BGG 4 units. At 11,370' mud loggers are seeing 10% metal, 85% cement, 5% sandstone. Pumped 20 bbl hi-vis sweep at;11,373' with maybe 10% increase in cuttings. Recovered 372 lbs metal from TOW to BOW (1T).;Cont milling into new formation from 11375' to 11381', wob 21 K, 415 gpm-2154 psi, 100 rpm-6.6k to 6.9k torque, 0.5-2 ft/hr ROP, MW 10.3/vis 52, BGG 6 units.;Mud loggers seeing 30% metal, 40% cement and 30% tuffaceous claystone and sand at 11,376'. At 11,379', seeing 50% formation, 30% cement and 20% metal.;Cont milling into new formation from 11381' to 11382', WOB 5-22K, 340-420 gpm-1500-2150 psi, 60-125 rpm-5k to 13k tq, 0.5 ft/hr ROP, MW 10.3/vis 52, BGG 5 units. PU = 155k, SO = 160k, ROT = 160k. 11380', seeing 70% formation, 30% cement and trace metals.;Penetration rate dropping to <1'/hr. Vary parameters and work mills off bottom in attempt to increase PR. With no improvement after 3 hours, discuss options with Drilling Engineer. Decision made to POOH and replace the starter mill with a milltooth bit. 408 lbs total metal recovered at surface.;Rack 1 std in Derrick and lay down the working single. Monitor well -static-. Pull next stand t/ 11234' and pump a dry job.;Blow down TD & POOH on elevators from 11234' to 9873'. PU = 140k.:-Hauled 100 bbls fluid to KGF G&I Cumulative: 3,461 bbis -Hauled 0 bbls solids to KGF G&I Cumulative: 549 bbis -Daily downhole losses: 0 bbls Cumulative: 23 bbis -Daily metal: 394 lbs Cumulative: 1100 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 4/1212019 Stopped trip at 9873' and changed out back spinner roller on iron roughneck.;Cont POOH from 9873' to 6652' racking in offside derrick.;Cont POOH LD 4 1/2" singles from 6652' to 5532'.;Cont POOH racking back on drillers side from 5532'to 92'. Pulled pulser from DM/TM collars. LD DM collar. PU and broke off window mill (114" under gauge), MU mill tooth bit and racked mill assembly back in derrick. Pollard on location at 13:30.;Sewice rig and topdrive, staged Pollard e-line unit. Swapped topdrive gens. EV Cam Rep on location at 15:00 with caliper lools.;Hang sheave, MU 40 finger caliper tool string with 4 centralizers, function tool on surface, zero at caliper tool/rotary table, RIH at 14:20, got to 3700' and lost communication with the tool. Troubleshoot tool communication.;Continue troubleshoot loss communication with caliper tool. C/O telemetry module and comm box. M/U caliper tool string with 4 centralizers and function test tool on rig floor. Zero caliper tool at rotary table and RIH at 19:25.;Log 9-5/8" casing from 11253'to 8595'. Make second pass from 11250' to 10300' and third pass from 11250' to 10585'. POOH with Logging tools.;L/D caliper logging tools and R/D Pollard E-Line equipment.;RIH with mill assembly from Derrick, laying down the MWD Collar from top of 5" HWDP on the way in hole. 8-3/8" Milkooth bit, 8-1/4" lower mill, flex jt, 8-318" upper mill, 5" HWDP jt, float sub, 2x NM flex collars, XO, 18x 4-1/2" HDWP.;RIH with 8-3/8" Milltooth & Milling assembly on 4-1/2" DP out of Derrick from 670' to 2224'.;-Hauled 55 bbls fluid to KGF G&I Cumulative: 3,516 bbis -Hauled 0 bbls solids to KGF G&I Cumulative: 549 bbis -Daily downhole losses: 0 bbis Cumulative: 23 bbls -Daily metal: 14 lbs Cumulative: 1114 lbs Conductor ann pressure- 0 psi TIH with BHA #11 (milling/drilling assembly) from 2224' to 5512' from off side derrick, filling pipe every 2500'.;Single in hole from 5512' to 6632' with 36 joints.;TIH from 6632' to 11,34T filling pipe every 2500'.;MU topdrive and fill pipe. Obtained parameters while pumping 403 gpm-1727 psi. Up wt 153K, dwn wt 153K, rot wt at 80 rpm 158K, 3500 ft/lbs off bott torque. Stop rotation and S/O to 11,375' and tagged up (2' off bottom of ramp). Repeat and tagged at same depth. Rotate at 40 rpm and ease down; reaming previous milled hole from 11,375' to 11,382', increasing rpm to 80-4300 ft/lbs torque, 5K wob. Cont drilling new hole from 11,382'to 11,393' 5-12K wob, 515 gpm-2450 psi, 80 rpm -3700 ft/Ibs on bottom torque. Pumped 20 bbl hi -vis sweep at 11,390' while drilling ahead.;2-7 ft/hr ROP. Seeing 90% sandstone/10% cement in cuttings. No issues at all.;Cont to circ sweep out while working mills in/out of window 3 times. Torque smoothed out with each upstroke pass, had no increase in cuttings to surface with sweep. Worked string in/out window with no rotation, nice and smooth. Pulled into casing and obtained SPR's.;Racked back one stand, blew down topdrive and RU to perform FIT.;Perform FIT to 13.5 ppg EMW. Pumped 5.77 bbls, achieving 1880 psi. Bled back 4.78 bbls.;Blow down lines. R/D the pressure testing equipment.;Pump dryjob, and POOH f/ 11344' U 8010', racking stands in Derrick. L/D top single from std #160 to alternate connection breaks during trip. Changed out grabber dies on iron roughneck.;Continue POOH f/ 8010' U 1249'. Lay down 36 its from 6601' to 5482' then continue racking stands in Derrick.; -Hauled 45 bbls fluid to KGF G&I Cumulative: 3,561 bbls -Hauled 0 bbls solids to KGF G&I Cumulative: 549 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bbis -Daily metal: 12 Ibs Cumulative: 1126 Ibs Conductor arm pressure- 0 psi 13-3/8 X 9-5/8 arm pressure - 0 psi cont FUVH from 1249' to milling assembly. Tri -cone bit graded a 1-1, both Baker mills in gauge. LD all milling equipment and cleared from catwalk, staged Sperry RSS assembly at catwalk.;PU Sperry Geo -Pilot and MU HDBS MMD64C PDC bit. MU DM, ILS, DGR, EWR, PWD and HCIM collars, plugged in and uploaded MWD. MU TM float sub, NM flex DC's, float sub, XO and two stands 4 1/2" HWDP. MU topdrive and shallow tested OK. MU XO and SLB jars, cont TIH HWDP to 761 '.;Cont TIH from drillers side derrick 78 stands to 5600', filling pipe every 2500' and verifying Geo -Pilot is functioning properly after breaking in seals.;Cont PU single in hole 60 ints 4 1/2" DP from yard, 5600' to 7476'. Up wt 115K, dwn wt 116K.;Cont PU single in hole 60 jnts 4 1/2" DP from yard, 7476' to 9334'. Up wt 116K, dwn wt 120K.;Hold PJSM with Beyond MPD and drilling crew. P/U MPD RCD and stabbed jt drillpipe into element. LID the single with RCD head to the rack.;RIH with stands out of Derrick from 9334' to 11321'. Fill pipe and prep to cut & slip drlg Iine.;Cut and slip 76' of drilling Iine.;Remove MPD trip nipple and install RCD bearing. Test MPD.;Break circulation. 477 GPM, 2727 psi, slack off through window into 8-3/8" hole down to 11381'. Seen a 5k bobble as bit entered gauge hole, no other issues.;Make connection and establish drilling parameters. Slack off and tag bottom on depth. Drill f/ 11393' U 11411'. 480 GPM, 2800 psi, 60 RPM, 4k -9k tq. 5-15k WOB.; Hauled 0 bbls fluid to KGF G&I Cumulative: 3,561 bbls -Hauled 0 bbls solids to KGF G&I Cumulative: 549 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bbls -Daily metal: 0 Ibs Cumulative: 1126 Ibs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 arm pressure - 0 psi to a trom 17 417' to 11,413', 6-8K wob, 480 gpm-2800 psi, 60 rpm -5000 to 9000 ft/lbs on boft torque. Lost swab on #1 mud pump.; Pulled up hole and LD single used to install MPD element, then pulled up hole into window and parked string at 11,352', had a couple over pulls pulling BHA through window. Circulated with #2 pump at 225 gpm-812 psi while C/O swab on #1 pump.;With pump #1 back on line S/O back out the window, had a couple set downs as bit, geo-pilot and EWR moved across whipstock ramp/window. Drilled from 11,413'to 11,435' using same parameters as earlier. 6-8K wob, 480 gpm 2800 psi, 60 rpm -5000 to 9000 ft/lbs on bott torque, 1-50 fUhr ROP.;At 11,435' kept stacking weight with no drill off. Tried numerous parameters but kept stacking weight on bit, no drill off. The more weight on bit, the less on bottom torque. Slowed rotary to 30 rpm and decided to pull into casing to ensure we could. At 11,419' (EWR across ramp) seeing multiple;2 to 5K over pulls. Racked stand back and cont to pull with no rotary. Overpulled 2 to 3K as bit got to top of window. Up wt 170K while pumping, 180K with no pump. Pulled to 11,34T. S/O from 11,347' and set down 5K with bit at top of ramp, and again with bit 3' above bottom of ramp (11,379).;Down wt 164K no pump or rotary. Made connection with bit 6' off the ramp. S/O to 11,390' and set down 6K, broke free and at 11,402' set down 12K as ILS engaged the ramp, broke free and set down 14K at 11,416', as EWR assembly exited window had 4 or 5 more set downs as much as 14K.;Acts like the wear sleeves on EWR were snagging in window. PU and over pulled 30K immediately. Idled one pump and rotated at 35 rpm, S/O and weight fell off. Cont to S/O with a couple more slight set downs and torque spikes to 11,426' then nice and smooth down to 11,435'.;Cont drilling ahead from 11,435' to 11,445', 8K wob, 493 gpm-2895 psi, 60 rpm -4300 fUlbs on bott torque, 50 ft/hr ROP, MW 10.3/vis 50, ECD's at 11.0 ppg (MPD holding 192 psi back pressure), BGG 17 units. At 11,445' made connection.;Attempted to drill ahead from 11,445'. Kept stacking weight. Pumped a pre -built hi -vis nut plug sweep while working with various drilling parameters. Each time we PU we had 10 to 20K overpull, $/O to bottom with no drill off and no ROP. Acts like non- rotating sleeve is sticking in under gauge hole.;Still seeing more torque off bottom than on bottom. Had maybe 10% increase in cuttings to surface with sweep. Drilling 90% sand, 10% silt and coal. Tried 8 to 30K wob, 395 to 500 gpm- 50 to 140 rpm, on bottom torque 2800 ft/lbs, off bottom torque 3300 ft/lbs. Discussed with Drilling Manager,;decision made to POOH for mud motor and Kymera bit.;Racked back stand, Pulled up hole from 11,442', up wt 180K no pump and had immediate 30K overpull. Ran one pump at idle, rotated 35 rpm and inched our way up hole. Each time we saw any sign of overpull or torque, stopped upward movement until string freed up then cont to pull up hole until 11,379'.;With bit Gout window racked back stand, then pulled on elevators nice and smooth to 11,321'. Racked back stand, PU single, MU on string, SIO to put single in MPD element, removed element and LD single, installed trip nipple.;Flow checked well (static), pumped dry job, POOH from 11,321'to 9334' racking back on offside derrick, then LD singles from 9334' to 8806'.;Crew change, held PJSM, cont. POOH LD singles from 8806 to 5,604' (total 120 singles), then cont POOH racking back on drillers side derrick F/5,604 - T/4,237'.; Discovered hydraulic leak coming from TD, shut down to fix leak, preformed rig service while locating leak, lost all robotics to TD, called NOV Rep Chris to help work through TD issue, discovered main hydraulic feed from service loop had come loose at the quick disconnect,;reconnected hydraulic hose and got robotics back, discovered leak on TD in the electric over hydraulic pressure snubber on the main hydraulic manifold assembly, mitigated leak while working on locating replacement part. No parts found on Iocation.;Cont. TOOH F/4,237' -T/509'.; Hauled 0 bbls fluid to KGF G&I Cumulative: 3,561 bbls -Hauled 70 bbls solids to KGF G&I Cumulative: 619 bbls -Daily downhole losses: 0 bbls 4/16/2019 POOH with BHA #12 from 509', downloaded MWD tools, pulled pulser from TM collar, LD smart tools, racked back NM flex DC's, jars and HWDP. PDC bit graded a 2-2 (bit in gauge, Geo -Pilot seal protector sleeve was not).;Clean and clear rig floor, clear BHA items from catwalk, start staging next BHA at catwalk.;Lockout topdrive and hydraulic skid. Removed front cover from topdrive, removed pressure snubber (pressure control switch) and found small diaphragm disc had pin hole. Replaced diaphragm disc's and o -ring, re -installed and function tested topdrive with no issues.;PU Sperry mud motor and adjusted to 1.15° bend, MU Kymera 8.375" bit, DM, ADR, DGR, PWD, TM and float sub. Plugged in and uploaded MWD. Ran NM flex DC's. XO and 2 stands 4 112" HWDP. MU topdrive and performed shallow pulse test (OK). Ran jars and HWDP to 774'.;Cont TIH on DP from drill side derrick, 774'to 5432' filling pipe every 2500'.;Crew change, held PJSM, cont. TIH on DP from 5432' to 5617', P/U-92K S/0-100K.;Started P/U and singling in hole from 5617' to 9347'(120 jnts).;Cont. TIH out of derrick F/9,347'- T/ 11,330', didn't see a bobble while going to 53.5 Ib casing @ 9,938'.;Removed trip nipple, installed MPUs rotating head, LID single, filled pipe and MPUs lines, got new SPR's, orientated motor 37R, killed pumps/rotary, slid through window, seen 3K bobble @ 11,372', bottom of ramp. P/U-1601K S/O-156K GPM -350 SPP -1845 psi.;Washed to bottom F/11,396 -T/11,445', started drilling/siding ahead to current depth of 11,476. GPM -430 SPP -2,400 psi WOB-6-10K P/1.1 -1601K S/O-158K TQ -4.8K AVG ROP -10' an/hr sliding.; -Hauled 0 bbls fluid to KGF G&I Cumulative: 3,561 blots -Hauled 0 bbls solids to KGF G&I Cumulative: 619 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bbls -Daily metal: 9lbs Cumulative: 1135 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 4/17/2019 Cont directional drilling 8 3/8" hole from 11,476' to 11,659'. Sliding: web 20K, 450 gpm-2900 psi, diff 220 psi, 15 to 50 ft/hr ROP. Rotating: web 15 to 20K, 432 gpm-2700 psi, 60 rpm -4800 ft/lbs on bott torque, 27 ft/hr ROP. MW 10.3/vis 48, ECUs at 11.0 ppg holding 191 psi back pressure, BBG 10.;Dnlled from 11,659'to 11,767'. Sliding: web 26K, 466 gpm-3100 psi, diff 413 psi, 30 ft/hr ROP. Rotating: web 23K, 438 gpm-2839 psi, 50 rpm -6000 ft/lbs on bott torque, 50 to 80 R/hr ROP. MW 10.3/vis 48, ECUs at 11.0 ppg holding 194 psi back pressure. BBG 18, max gas 112 units. Pumped 20 bbl;hi-vis hi -wt nutplug sweep at 11,755' prior to stand drilled down. Received rig fuel.;Circulated sweep out while rotating/reciprocating 445 gpm-2600 psi, 80 rpm3200 ft/lbs off bottom torque. Called it 20% increase with sweep to surface, but hole pretty much unloaded entire time after all the slide drilling.; Drilled from 11,767'to 11,817'. Sliding: web 18 to 26K, 454 gpm-2936 psi, diff 250 psi, 30 to 35 ft/hr ROP. MW 10.3/vis 49, ECUs at 11.0 ppg holding 230 psi back pressure, BBG 24 units. MPD choke skid getting restricted with a few coal chunks. Having to swap chokes and cleanout.;Crew change, held PJSM, cont directional drilling 8 3/8" hole from 11,818' to 11,829' WOB-20125K GPM -450 SPP -2970 psi RPM -50 TQ-5-6K.;Changed swab on MP #1, fluid end #2, reciprocated pipe F/11,829' -T/11,770' @ GPM -245 SPP -1,400 psi RPM -30, while changing swab.;Cont. directional drilling F/11,829 -T/11,915'. GPM -446 SPP -3125 psi, TQ -2-51<, P/1.1-1 60K S/0 - 150K ROT -158K, while holding back pressure w/ ECUs of 11.2 ppg w/ Beyond.;Cont. directional drilling F/11,915' -T/11,998', pumped Hi -Vis /high wt sweep (11.4 ppg), sweep came back on time w/ no increase in cuttings, started bringing up MW in active system from 10.3 to 10.5 ppg. Current depth 12,035'.;Distance to plan -24.74' Low -18.57' Left -16.35'.; -Hauled 87 bbls fluid to KGF G&I Cumulative: 3,648 blols -Hauled 60 bola solids to KGF G&I Cumulative: 679 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bbis -Daily metal: 0lbs Cumulative: 1135 lbs Conductor ann pressure- 0 psi 13-318 X 9-5/8 ann pressure - 0 psi 4/18/2019 Cont directional drilling 8 3/8" hole from 12,035' to 12,198'. Sliding: web 23K, 435 gpm-2982 psi, 349 psi diff, 15 to 40 ft/hr ROP. Rotating: web 23K, 422 gpm- 3000 psi, 60 rpm -6500 fUlbs on bolt torque, 45 ft/hr ROP. MW 10.5/vis 50, ECUs at 11.2 ppg holding 230 psi backpressure, BGG 12, max 41.;Drilled from 12,198' to 12,265'. Sliding: web 30K, 448 gpm-3300 psi, 474 psi diff, 20 to 50 ft/hr ROP. Rotating: web 13K, 426 gpm-28500 psi, 60 rpm -5750 ft/lbs on bott torque, 58 ft/hr ROP. MW 10.5/vis 55, ECD's at 11.2 ppg holding 268 psi backpressure, BGG 16. Pumped 20 bbl hi -wt hi -vis sweep.;down drill string while changing bad swab on #2 mud pump, #2 pod.;With both pumps back online circulated sweep around at 443 gpm-2759 psi, 90 rpm -3800 ft/lbs off bolt torque. Hale unloading as soon as we started rotating, really no increase in cuttings with sweep to surface, but definitely cleaned up once sweep out of hole.;Drilled from 12,265' to 12,297'. Sliding: web 37K, 442 gpm-3200 psi, 400 psi diff, 40 ftlhr ROP. Lost swab in #1 pump, #2 pod.;PU off bottom, cut to one pump and rotated. 250 gpm-1467 psi, 50 rpm -3800 ft/lbs off bottom torque while replacing 5" swab and liner in #2 pump.;Drilled from 12,297to 12,304'. Sliding: web 22K, 460 gpm-3142 psi, 330 psi diff, 27 ft/hr ROP.;Drilled from 12,304' to 12,393'. GPM -460 SPP -3,200 psi WOB-20/25K TQ -6/8K RPM -60 MPD holding 11.2 ECD (125 psi). Sliding 80%, PIU -170K S/O-158K ROT -160K, brought MW up from 10.5 to 10.7 ppg to help with coals while preforming 1 st wiper trip into casing.;Lost MP swab in MP 92 on pod #i, racked back one std, circulated & reciprocated pipe @ 50 RPM, 250 GPM, SPP -1,300 psi.; PIU & MU std from derrick, RI to bottom, cont. directional drilling ahead F/12,393'-T/12,452'.;Pumped 1st high weight/high-Vis sweep, chase out of bit w/ whole mud from pit #7, pumped 2nd high weight/high-Vis sweep, pumped both sweep OOH, lost swab in MP #1/pod #3, dropped to one pump & cont. to circulate out sweep while fixing swab. Once fixed lined up second pump & finished circulating out;sweeps with both pumps, had 30% increase in cuttings on first sweep & 20% increase in cuttings on second sweep, mostly small chips wl very few quarter size pieces, circulated an additional BU, got new SPR's, held PJSM w/ Beyond on holding back pressure while POOH during wiper trip into casing.;Started POOH on elevators while holding back pressure w/ Beyond F/11,452% circulating across the hole holding 11.2 ppg ECD, current depth 11,826'. P/U-174K S/0 -148K. Distance to plan -48.66', 43.3671 -ow 22.10'lLeft.; Hauled 120 bbls fluid to KGF G&I Cumulative: 3,768 bbls -Hauled 120 bible solids to KGF G&I Cumulative: 799 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bible -Daily metal: 10 lbs Cumulative: 1135 Has Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 4/1 912 01 9 Continued pulling wiper trip from 11,826' holding 419 psi backpressure with MPD, using rig pump to circ across top of well. MU topdrive each stand. At 11,454' we found topdrive grabber die block was loose and bottom retainer plate bent. Up wt 164K.; Had no spare retainer plate so removed die block assembly from topdrive. While removing die blocks had MPD ease down on back pressure over 15 minutes and shut down mud pump.;Cont pulling on elevators from 11,454' to 11,413' where Sperry ADR collar snagged in window. Made a couple attempts to pull on elevators with no success. MU topdrive and pumped down drill string at an idle (2.3 bpm). Rotated at 20 rpm and eased up into window with no problem to 11,391'.;Pulled remainder of mudmotor and bit into casing, on elevators, with no issue to 11,244'. Up wt 155K.;Cleaned off stack, pulled bushings, removed RCD and LD single with bearing still on it, installed trip nipple and rotary bushings. Lined well up on trip tank.; Held PJSM, removed deadline sensors, cutislipped 224' drill line. Installed deadline sensors, calibrated block height and weights.;MU 4 1/2" test joint, XO's and wear ring running tool on stump. BID and retrieved wear ring. LD run tool/wear ring, MU test plug, backflushed kill and choke lines, hosed out wellhead profile, landed test plug hanging off drill string. RU to test BOPE. Total Safety tested gas alarms. Flooded surface;lines and purged air. Received 6 new grabber die block retainer plates from Dukowitz Machine. Shell tested BOP stack. Witness of BOP test was waived by Amanda Eagle with BLM and Jim Regg with AOGCC on 4-18-19.;Tested BOPE at 250 low f/5 min, 4000 psi high f/10 min. Tested annular at 250/2500. All 11 test passed besides test #7 fail/pass, due to air introduced to system, purged air and retested (Pass). Koomey draw down test-: Initial pressures- Acc: 2,950 psi Man: 1,600 psi Ann: 825.;Final pressures-Acc: 1,450 psi Man: 1,375 psi Ann:990 psi, Recharge time 200 psi -27 sec, Full charge- 3,000 psi- 154 sec., average pressure of the 4 nitrogen bottles 2,550 psi. Closing time-Ann=25 sec Closing time -UPR, LPR, BLDS= 5sec.;Serviced rig, checked drive line bolts, greased draw works, break linkage, iron roughneck, blocks, and top drive. Replaced hydraulic snubber pressure switch on TD.; Blew down TD & choke manifold, pulled and broke down test plug & test it, RID testing equip.; Pulled MPD's trip nipple, PIU single w/ MPD's rotating head and installed, lined up to MPD and flooded there lines. Held back pressure while TI H, 11.2 ppg ECD.;Started to TI and had issues w/ the TD pipe handler function, proceeded to trouble shoot, discovered we needed to adjust the new snubber pressure switch on the TD.;TIH F/11,242' -T/11,893'. had 25K set down, M/U top drive and worked through tight spot with pumps F/ I 1,893'-T/1 1,947'. GPM -361 SPP -2370 psi, RPM-20.;Cont. to R I H F/11,947' -T/12,021% set down 25K, M/U top drive and wash down F/12,021' -T/12,202'. P/U-165K S/0 -156K. Cont. to wash to bottom current depth of 12,262'.: -Hauled 80 bbis fluid to KGF G&I Cumulative: 3,848 bbis -Hauled 80 bbis solids to KGF G&I Cumulative: 879 bbis -Daily downhole losses: 0 bbis Cumulative: 23 bbis -Daily metal: 2 lbs Cumulative: 1147 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 arm pressure - 0 psi 4/20/2019 Cont to wash/ream from 12,261'to 12,448', 350 gpm-2086 psi, 20 rpm -2900 to 7600 ft/lbs off bottom torque. Had one spot we had to PU and work back down (claystone) but overall trip in went good.;At 12,448' pumped a 20 bbl hi -vis hi -wt sweep and started a cleanout cycle at 444 gpm-3036 psi, 90 rpm -4200 to 5000 Nibs off bottom torque. 4000 strokes into our 14,371 stroke circulation, hole started unloading with a 200% increase in cuttings and held until sweep returned to surface. Had a max;of 154 units trip gas at bottoms up. Circulated and extra 5000 strokes then made connection.;Cont directional drilling from 12,452' to 12,508'. Sliding: wob 18 to 20K, 460 gpm-3100 psi, 178 psi diff, 14 to 37 ft/hr ROP. Rotating: wob 15K, 448 gpm-3100 psi, 90 rpm -6200 ft/lbs on bott torque, 55 ft/hr ROP. MW 10.7+/vis 52, ECD's at 11.3, MPD holding 113 psi back pressure, BGG 15, max 16 units;Drilled from 12,508' to 12,686'. Rotating: wob 25K, 455 gpm-3058 psi, 60 to 90 rpm -5800 to 6700 ft/lbs on bott torque, 40 to 70 Nhr ROP. MW 10.8/vis 49, ECD's at 11.4, MPD holding W psi back pressure, BGG 20. Up wt 180K, dwn wt 170K, rot wt 175K.;Pumped 31 bbl weighted Hi -Vis sweep @ 12,686', cont. to drill ahead T/12,699' Kelley down, preformed clean up cycle, had a 100% increase in cuttings upon return, mostly superfnes. RPM -90 GPM -450 SPP -3050 psi. While having MPD 11.5 ECD/100 psi.;Lost swab on MP #2/Pod #3, dropped to one pump and cont. to circulate well while changing swab. Got pump back on line, cont. to directionally drill ahead. Brought up lube concentration in mud system from 2% to 3% by volume.;Cont. directionally drill F/12,699' -T/12,780', WOB 20-25K RPM -70/90 TQ - 6/8K GPM -450 SPP -3200 psi. MPD is holding 11.5 ppg ECD/139 psi, sliding 80%. PIU -179K S/0 -162K ROT-170K.;Cont. directionally drill F/12,780' - T/12,880'. WOB 20-25K RPM -70/90 TQ-6/BK GPM -440 SPP -3080 psi PIU -182K S/O-164K ROT -172K. Distance to well plan: 82.59' 69.42/Low 44.73'/Left.;- 4.73'/Left.;Hauled Hauled62 bbis fluid to KGF G&I Cumulative: 3,910 bbis -Hauled 93 bbls solids to KGF G&I Cumulative: 972 bbis -Daily downhole losses: 0 bbis Cumulative: 23 bbls -Daily metal: 0lbs Cumulative: 1147 lbs Conductor arm pressure -0 psi 13-3/8 X 9-5/8 arm pressure - 0 psi 4/21/2019 Cont drilling 8 3/8" hole from 12,880' to 12,949', rotating wob 25K, 445 gpm-3250 psi, 90 rpm -6400 ft/lbs on bott torque, 45 ft/hr ROP, MW 10.9/vis 51, ECUs at 11.5 ppg, BBG 14 units.;Pumped a 30 bbl hi -vis hi -wt nutplug sweep around (300 vis/11.9 ppg) at 450 gpm-3000 psi, 90 rpm -4250 ft/lbs off bolt torque. Had 10% increase in cuttings to surface of fine sand.;Cont drilling from 12,949 to 12,995', sliding wob 27K, 440 gpm-3280 psi, 369 psi diff, 23 ft/hr ROP, MPD running wide open choke gicing us 100 psi backpressure.;Cont drilling from 12,995' to 13,166'. Rotating: wob 13K, 439 gpm-3168 psi, 80 to 90 rpm -6400 to 7800 ft/lbs on bolt torque, 60 ft/hr ROP. Sliding: wob 19K, 442 gpm-3200 psi, 202 psi diff, 10 to 30 ft/hr ROP, MW 10.9/vis 50, ECUs at 11.4 ppg, 100 psi backpressure, BGG 16 units, max gas 75 units.;Hrs on bit = 50.2, KRevs = 448K, drilling sandstone with some claystone and coal stringers. Strapped 7' liner (101 jets) on pad 3. Received 3 trailers of barite.;Cont drilling from 13,166 to 13,258', pumped 30 bbl weighted Hi -Vis sweep, sweep came back on time w/ a 10% increase in cuttings, mostly super fines w/ very few coal chips. GPM -440 SPP -3244 psi RPM -90 TQ -5-7K WOB-20/25K P/U-194K S/0 -168K ROT -178K, MPD holding 11.55 ECD/152 psi.;After sweep came back, MP #1 pod #1 started leaking, dropped to one pump, cont, to circulate & reciprocate pipe while replacing swab.;Cont. directionally drilling ahead F/13,258' -T/13,277'. GPM -440 SPP -3244 psi RPM -90 TQ -5-7K WOB-20125K PIU -194K S/0 -168K ROT - 178K, MPD holding 11.55 ECD/152 psi.;MP #1 4" valve started leaking, shut down pumps, racked on std back, couldn't pump due to piping limitation, cont. to work pipe while replacing washed rubber seal in valve, line up pumps and tested valve (leaked), shut down and changed up valve w/ back up valve and tested (Good).;RIH w/ std out of derrick, cont. to directionally drilling ahead F/13,277 -T/13,319', had a swab start leaking on MP #1/pod #3, dropped to one pump and changed out swab.;Cont. to directionally drilling ahead F/13,319' to current depth of 13,377'. GPM -440 SPP -3204 psi TQ -6/7K WOB-18/22K PIU -188K S/0 - 162K ROT -174K. MPD holding back pressure 11.44 ECD/96 psi 50% sliding. Distance to well plan 116.17 107.32/Low 44.48/Left K-Revs=512.7.; Hauled 146 bbls fluid to KGF G&I Cumulative: 4,056 bbls -Hauled 219 bbls solids to KGF G&I Cumulative: 1191 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bbls -Daily metal: 0 lbs Cumulative: 1147 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 4/22/2019 Cont directional drilling from 13,377' to 13,397', sliding wob 17K, 433 gpm-3000 psi, 148 psi diff, 20-30 ft/hr ROP, MW 10.9/vis 52, ECUs at 11.3 ppg, MPD showing 95 psi backpressure, BGG 17 units. At 13,397' had to replace a swab on #2 pump while circ on #1 pump.;Drilled from 13,397'to 13,502'. Sliding wob 21 K. 437 gpm-3254 psi, 268 psi diff, 15 to 25 ft/hr ROP. Rotating wob 18K, 433 gpm-3336 psi, 90 rpm -6800 ft/lbs on bott torque, 50 to 70 ft/hr ROP, MW 10.9/vis 50, ECUs 11.5 ppg, BGG 13 units, 129 psi backpressure. Had Peak come in with small crane and;remove empty drill line spool off carrier. Sent spool to Pollard so new line can be spooled on. Bit has 550 on bottom k Revs, 60.3 hours.;Obtained survey at 13,502', pumped 30 bbl hi -vis hi -wt, nutplug sweep, chased with 1000 strokes then pumped a second 30 bbl sweep. Circulated at 449 gpm-3297 psi, 90 rpm -4900 ft/lbs off bott torque. Had 25% increase in fine sand to surface. Pumped an extra 5000 strokes and shut down.;Pulled wiper trip from 13,502' up to 12,511'. MU topdrive first three stands pulled, then pulled on elevators. Up wt 200K. Circulated across the top with MPD, 113 gpm-420 psi, MPD pressure 300 psi. At 12,511' pulled 30K over 3 times with no progress.;MU topdrive, lined up on drill string, pumped at 435 gpm-2800 psi. Pumped up hole one stand with only slight overpull to 12,454'. Pulled last stand on elevators to 12,393' then SIO to 12,454'. Had 10-30K over pulls at 13,416, 12,895', 12,735' to 12,720' on elevators.;Sewiced rig and topdrive, checked driveline bolts, changed #1 pump swabs over to new "southwest" swabs.;Crew change, held PJSM, TIH from 12,454' to 13,445', had one set down of 30K @ 12,668', tried to work through on elevators, had to Kelley up and wash & ream to clean it up. GPM -350 SPP -1600 psi RPM -20 P/U-182K S/0 -164K ROT- 168K.;Washed down last std F113,445' -T/13,503', pumped 30 bbl weighted Hi -Vis sweep, hole started unloading 462 bbis into STS circulation, 200% increase in cuttings, mostly super fine w/ some coal chunks. Sweep came back on time, w/ 100% increase in cuttings, mostly super fines.;Cont. directional drilling 8- 3/8" hole F/13,503' -T/13,596', shut down from pumping through MPD due to butterfly leaking mud into poor boy degasser, lined up to take returns conventionally to flow line w/ out going through MPD or holding any back pressure while replacing valve. GPM -420 SPP -2800 psi.;R PM -70 TQ -5/71< ECUs - 11.29 ppg P/U-190K S/0 -166K ROT-178K.;Cont. directionally drilling 8-3/8" hole F/13,596 -T/13,655' GPM -420 SPP -3040 psi RPM -90 TQ -6/7K Sliding 80% PIU -188K S/0 -166K ROT -176K K-Revs=589.1 Distance to well plan 119.71' 114.86/Low 33.74'/Left.;-Hauled 70 bbls fluid to KGF G&I Cumulative: 4,123 bbls -Hauled 55 bbls solids to KGF G&I Cumulative: 1246 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bbls -Daily metal: 6 lbs Cumulative: 1153 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 412312019 t' 8 3/8" hole from 13.655' to37 .818'. sliding wob 20K, 414 gpm-2960 psi, 310 psi diff, 48 ft/hr ROP. Rotating wob 16 to 20K, 420 gpm- 3223 psi, 65 to 80 rpm -7200 ft/lbs on bott torque, 24 to 65 ft/hr ROP, MW 10.9/vis 59, ECUs at 11.6 ppg, BGG 15 units, max 46 units.;Pumped a 30 bbl hi -vis hi -wt nutplug sweep at 13,752' after making connection, chased 1000 strokes and followed with a second 30 bbl sweep while drilling ahead. back on time w/ 100% increase.;Cont directional drilling 8 3/8" hole from 13,818' to 14,055', Rotating wob 16 to 20K, 427 gpm-3223 psi, 65 to 80 rpm -7400 ft/lbs on btm torque, 24 to 65 ft/hr ROP, MW 10.9/vis 59, ECUs at 11.6 ppg, BGG 15 units, max 64 units.;Pumped a 35 bbl hi -vis hi -wt w/ nutplug sweep at 13,998' after making connection, while drilling ahead. back on time w1100% increase. GPM -425 SPP -2980 psi TQ-5-6K.;Crew change, held PJSM, cont. directional drilling 8 3/8" hole F/l 4,055'-T/14,243', GPM -420 SPP -3250 psi RPM -80 TQ -7/8K P/U-194K S/0 -170K ROT -178K. Hold back pressure w/ MPD 11.5 ECD/120 psi.;Cont.. directional drilling 8 3/8" hole F/14,243' -T/14,313'. GPM -425 SPP -3360 psi RPM -80 TQ -7/8K P/U-196K S/0 -174K ROT -178K. Hold back pressure w/ MPD 11.5 ECD/120 psi.;Pumped 34 bbl weighted Hi -Vis sweep, cont. directional drilling 8 318" hole F/14,313' -T/14,373' while sweep was going around, sweep came back on time w/ 30% increase in cuttings, mostly sand, silt, clay, and some small chucks of coal.;Cont. directional drilling 8 3/8" hole F/14,373' to current depth of 14,433'. GPM -420 SPP -3338 psi RPM -80 TQ -7/8K PIU -196K S/0 -170K ROT -176K. Distance to well plan -94.68' 82.52'/Low 46.62/Left K- Revs=777.5.; Hauled 147 bbls fluid to KGF G&I Cumulative: 4,270 bbls -Hauled 108 bbls solids to KGF G&I Cumulative: 1354 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bbis -Daily metal: 0lbs Cumulative: 1153 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 4/24/2019 Cont directional drilling 8 3/8" hole from 14,433' to 14,497', sliding wob 18K, 415 gpm-3350 psi, 205 psi diff, 34 ft/hr ROP. MW 10.9/vis 59, ECUs at 11.6 ppg, BGG 15 units, max 17 units. Holding back pressure w/ MPD 120 on conn and full open choke drilling w/ 11.6 ECD.;Cont.. directional drilling 8 3/8" hole F/14,497' -T/14,555', and pump 30 bbis Hi vis Hi -Wt sweep while drilling GPM -415 SPP -3360 psi RPM -80 TQ -7/8K P/U-196K 51O -174K ROT -178K. Hold back pressure w/ MPD 120 on conn and full open choke drilling w/ 11.6 ECD.; Pump tandem low -vis low wt fallowed by hi wl hi -vis sweeps clean up cycle while rotating and reciprocating pipe sweep while drilling back on time w/125% increases and tandem sweep back on time w/30% increase.;Survey and pooh open hole on quill do to floats not holding and using MPD holding 350 psi @ 11.5 ppg ECD with just couple spots of over pulls 13,706' , 15.524' & 13382' wiped each one ok and pulled thru window & into csg with no issues.;Crew change, held PJSM, shut down pump, flow check well (ok), pulled & UD MPD's rotating head on single to change DP breaks, installed MPD's trip nipple, pumped dry job.;POOH F/11,241' -T/9,378', racking back stds in the derrick, blew down Kelley, sucked out MPS's hard Iine.;Cont. POOH F/9,378' -T/5,648', UD singles (120 jts).;Cont. TOOH racking back stds in the derrick F/5,648' -T/774' BHA #13.;Held PJSM, racked back HWDP, pulled corrosion ring, UD jars & P/U new set of jars & racked back in derrick, current depth of 313'. Distance to well plan 98.39' 82.9371 ow 52.96'/Left.;-Hauled 110 bbls fluid to KGF G&I Cumulative: 4,380 bbis -Hauled 75 bbls solids to KGF G&I Cumulative: 1429 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bbls -Daily metal: 4 lbs Cumulative: 1157 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 4/25/2019 Continue look for dropped dog collar pin in cellar area, around bop and in the rotary table crew chg PJSM.;Resume Udn and chk tithe Chg out TM collar, brk bit Grade 0 -1 -CT -G -1 -1 -NO -HR Udn mud mtr ( drained its self and had +1/4" play in thrust and throw).;P/up BOT bar magnet while draining stack and placed magnet across rams and functioned same ( pin was not retrieved or seen coming out of cavities ) don magnet assy.; PJSM w/ slick line crew and dup same rih #1 w/ 4-112" earth magnet and 5.35" centralizer on 1-3/4" tool string to TOM @ 11,356' pooh slowly with only metal shaving recovered r/dn slick Iine.;NOV hand inspect TOS chg out saver sub, serviced rig- greased crown, inspected draw works, break linkage, checked bolts on drive line & grabber block.;P/U mud motor, dialed up mud motor to 1.15 bend, MIN new 8-3/8" Kymera bit, P/U & M/U TM collar, started up loading tools.;Crew change, held PJSM, finished up loading tools, M/U BHA #14 F/90'-T/218'.;Shallow tested MWD tools, GPM -350 SSP -680 (Good test). RIH w/ HWDP & jars F/218' -T/775'. Shut down an adjusted service loop sock to keep TD from rubbing on service loop lines.;TIH out of derrick F/775'4/5,587% filling pipe every 2,500' and testing MWD tools.;Started P/U singles F/5,587' -T/10,306', P/U 24 new its of 4.5 DP, plus the original 120 jts to make TD. P/U-140K S/0 -130K ROT -135K.; -Hauled 40 bbls fluid to KGF G&I Cumulative: 4,420 bbls -Hauled 25 bbis solids to KGF G&I Cumulative: 1454 bbis -Daily downhole losses: 0 bbis Cumulative: 23 bbis -Daily metal: 0lbs Cumulative: 1157 lbs Conductor ann pressure- 0 psi 4/26/2019 Crew change PJSM continue Rih wl pipe out derrick U 10,334' ( right above window) and chk pipe count; Pulled flow nipple and install MPD bearing;Cut & slip 90' of drlg line & inspect brakes;Exit window w/ no issues rih on elevators working thru set downs U 11, 880' w/ MPD holding 120 psi;Kelly up, circ and warm mud, worked full stand and circ btm up ( well unloading coal chunks and fines) MPD holding 130 psi; Rih and wash and ream as needed t/ 13806; Kelly up circ and warm mud work full stand and circ clean( well unloading coal chunks and fines) MPD holding 130 psi;Rih and wash and ream as needed t/ 14060' Slide areas appear to be under gauge);Crew change, held PJSM, cont. to wash & ream F/14,060'-T/bottom 14,555', working through multiple tight spots (slides & small coal areas), hole was unloading while washing & reaming the whole time, mostly claystone, sand, and coal chunks/chips.;Pumped 50 bbl weighted/Hi- Vis sweep, preformed clean up cycle before drilling ahead, sweep came back 57 bbls late, wl a 150% increase in cuttings, mostly clay stone, sand, & small coal chips. GPM -460 SPP -3675 psi RPM -100 TQ-6/7K;Cont. to circulate remainder of sweep OOH, lost swab in MP #1/ pod #3 (South west style), cont. to circulate w/ one pump, changed swab, and got SPR's.;Cont. directionally drilling 8-318" hole F/14,555' -T/14,605', lost swab in MP #1/pod #1 (Southwest style), pulled of bottom, cont. to circulate w/ one pump, changed swab, cont. to drill ahead F/14,6064114,620', adding .5% NXS lube by volume to active system.;P/U-195K S/0 -160K ROT -175K SPP -3500 psi TQ -7/8K GPM -430 RPM -100 Distance to well plan 98.39' 82.9371 -ow 52.95'/Left K -Revs -17.00; Hauled 45 bbls fluid to KGF G&I Cumulative: 4,465 bbis -Hauled 30 bbls solids to KGF G&I Cumulative: 1484 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bbis -Daily metal: O His Cumulative: 1157 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 4/27/2019 Cont. directionally drilling 8-3/8" hole F/14,620' -T/14,810', and adding NXS lube to active system to help combat slip slick (retort only showing 2% by volume) up/dn/rot 195/160k/175 Tq 6-12k @ 92 rpm w/ 410 gpm @3535 psi and 11.5 ECD BGG @ 17 units and MPD holding 150 psi;Cont. directionally drilling 8- 3/8" hole F/14,810' -T/14,990', Pump 34 bbl hi -vis hi -weight sweep around while drilling @ 14813' back 58 bbis late w/ 50 % increase mainly fines. WOB-12 GPM -410 SPP -3450 psi DIF -150 RPM -90 TQ -10K P/U-182K S/0 -176K ROT-178K;Crew change, held PJSM, cont. directionally drilling F/14,990' -T/15,193' & called TD, seen top of water zone @ 14, 984' & bottom @ 15,043', increased back pressure w/ MPD to maintain 11.9 ppg ECD's while weighting up active system to 11.1 ppg. PIU -200K S/0 -170K ROT-177K;Pumped 50 bbl weighted Hi -Vis sweep while weighting up active system to 11.5 ppg to help control water influx, sweep came back 66 bbls late, w/ 100% increase in cuttings, mostly fines, sand, silt, clay, and some coal chunks. GPM -450 SPP -3550 psi RPM -8O TQ- 6/7K;Once we had a good even 11.5 ppg MW all the way around, flow checked well, flowing @ 28 bbis per/hr conventionally to flow line, cont. to weight up active system to 11.8 ppg while circulation through MPD chokes wide open. GPM -450 SPP -3550 RPM -80 TQ-6/7K;UD single used to make last 12'to TO, racked back 1 stand, cont. to weight up system to 11.8 ppg. P/U-210K S/0 -168K ROT -177K GPM -450 SPP -3550 ROT -80 TQ -6/7K Distance to well plan 124.25' 94.89/Low 80.21'/Left K-Rev's=196; Hauled 172 bbls fluid to KGF G&I Cumulative: 4,637 bbis -Hauled 98 bbis solids to KGF G&I Cumulative: 1582 bbis -Daily downhole losses: 0 bels Cumulative: 23 bbls -Daily metal: O lbs Cumulative: 1157 Iles Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 4/28/2019 Cont. to weight up system to 11.8 ppg. PIU -210K SIO -168K ROT -177K GPM -450 SPP -3550 ROT -80 TQ -6/7K w/ 137 units high gas and avg BBG @ 45 units and shut do pumps and flow chk well flowing @ 7.2 bph w/ no losses or sign of differential sticking;Short trip Pooh on quail do to floats not holding f/ 15,119't/ 14,12T w/ MPD holding 310 psi dynamic and 190 psi static and working thru 40-50k over pulls ( trip sheet off);Rotate and reciprocate full stand f/ 14,127 U 14,063' and circ clean w/ 25% increases in cutting @ John up w/ no losses Pump out cellar;Continue short trip pooh f/ 14, 063'V 13,546' w/ MPD holding 310 psi dynamic and 190 psi static and working thru 40-50k over pulls;MPD barring leaking (chg out same ), found broken wire on grabber box, installed new, flow checked well, 7.8 bbis per/hr.;Cont. POOH F/13,546' -T/11,770', while MPD holding 360 psi dynamic & 280 psi static, ECD=12.28, no tight spots or gains observed after adjusting back pressure.;Crew change, held PJSM, Lined up pumps, pumped BU, hole started unloading 461 bbis into pumping a BU, quarter to dime size pieces of coal, along with some fines, pumped a BU and a half before it cleaned up. GPM -400 SPP -2700 RPM -60 TQ -314K P/U- 160K S/O-135K ROT-147K;Lined up to pump across the hole through MPD chokes while TOOH F/11,770' -T/11,334', had no issues going through window into casing while holding 280 psi static & 360 psi dynamic with MPD.;TIH F/11,334' -T/13,014', started holding static back pressure @ 190 psi and dynamic @ 80 psi, increased static back pressure to 340 psi and dynamic to 160 psi, due to increased pipe displacement, trip speed 30'/min, had to wash down two tight spots, 12,754' & 12,869', both 30K set downs 4 times..;Lined up pumps and started circulating, staged pumps up to 400 GPM, brought on rotary @ 40, 60 then 80 RPM'S, pumped weighted Hi -Vis sweep w/ walnut, sweep came back 37 bbls late w/ 30% increase, almost all fines w/ very little coal.;GPM-408 SPP - 2950 RPM -80 TQ -4/5K P/U-170K S/O-150K ROT-160K;Cont. to TIH F/13,014', had to wash through tight spot @ 14,120', 50K set down 3 times, holding back pressure, dynamic -400 psi & static -280 psi, current depth of 14,126'.; -Hauled 90 bbls fluid to KGF G&I Cumulative: 4,727 bbis -Hauled 30 bbis solids to KGF G&I Cumulative: 1610 bbis -Daily downhole losses: 0 bbis Cumulative: 23 bbis -Daily metal: 2 lbs Cumulative: 1159 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 4/29/2019 Cont. to TIH washing and reaming F/13,126' t/ 14,61 T, holding back pressure, dynamic -400 psi & static -280 psi, and limiting surge and swab speeds t/ 30fpm gpm 410, rpm 90, SPP 3450 psi, ECD @ 12.5 ppg;Attempt Trip in hole on elevators f/ 14,617' U 14,762' ( appears that Bar has fell out as we look in some water );Resume RIH washing and reaming f/ 14,762' t/ TD tag of 15, 193' holding back pressure, dynamic -400 psi & static -280 psi, and limiting surge and swab speeds t/ 30fpm;work full std rotation and reciprocating @ 30 fpm and Pump Hi -vis High -wt 45 bbl sweep around and weight up f/ 11.9+ ppg t/ 12.2+ sweep back 98 bbis late w/ 25% increase (lost other South west swab chg out same w/ blue Iightin);W/ good 12.2+ppg back shut do pumps and released MPD pressure and performed Flow chk 20 min 3.5 >3.0 bph move pipe w/ no sign of differential sticking;Resume working full std w/ rotation and reciprocating @ 30 fpm and weight up f/ 12.2+ ppg t/ 12.5+ ppg;Crew change, held PJSM, cont. to circulate while weighting up active system from 12.2 to 12.5+ ppg. GPM -355 SPP -2650 psi RPM -90 TQ -7.5K P/U-210K SIO -168K ROT-18OK;Broke out single, preformed 45 min flow check, well was static, WU single, observed no over pull or sighs of differential sticking.;Cont. to circulate, called town engineer to discuss our plan forward, while circulating wash pipe started leaking. GPM -349 SPP -2500 RPM -90 TQ -7/8K ECO's 12.9;Shut down pumps, UD 15' pup jt, installed TIW valve, changed out wash pipe, cont. to flow check well for 45 min, well was static.;TOOH F/15,193' -T/14,977', UD single to change breaks, had 50K over pull @ 14,977', lined up & washed through tight spot.;lined up & washed through tight spot, cont. to Wash OOH F/14,997' -T/13,970, GPM -250 SPP -1600 psi, observed slight losses while washing OOH.;Lost all robotics to TD, rebooted VFD and got robotics back.;Cont. washing OOH F/13„970' -T/13,41 T, GPM -250 SPP-1600;Reflled trip tank , emptied cellar, flow checked well while circulating across the hole, no gain & no loss. GPM -115 wl open choke. Current depth of 13,391'; -Hauled 45 bbls fluid to KGF G&I Cumulative: 4,772 bbis -Hauled 20 bbis solids to KGF G&I Cumulative: 1630 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bbis -Daily metal: 3lbs Cumulative: 1162 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 4/30/2019 Remove MPD Bearing and I/dn same on jt and install flow nipple, visually flow check, well was static;Pooh pumping f/ 13, 417't/ 11,638' wl only one over pull @ 12,543' @ 20k w/ 1.3 bbls over cal.;Circ btm up @ 282 gpm and clean csg @ 1570 psi w/ 86 rpm w/ ECD @ 12.87 ppg w/ maybe 10 % increase in bar, fines, and few coal chips and Spot 18 bbl LCM pill just out pipe @ 60 ppb bar-carb , and 14 ppb bars fiber wl 3 bbls loss while pumping; Finish pulling thru window and into csg on elevators w/ no issues U 11,214';Monitor well on trip tank while slip and cut 76'& service rig, inspected dwks, kick back rollers, and break linkage. Greased blocks, TD, swivel & crown, opened & inspected grabber box assy.;POOH Fit 1,214'-T/9,375', racking back in derrick.;Crew change, held PJSM, POOH UD single F/9,375'-T/4,185'. Total single UD=210 jts. P/U120/80K S/0-120/70K;Cont. POOH F/4,185'-T/837', racking back stds in the derrick, flow checked, static, UD BHA #14,;POOH F/837'-T/157, racked back 4 stds of HWDP, UD 11 jts of HWDP & Jars, pulled 2.5 metal drift from top of flex collar & removed corrosion ring. Down loaded MWD tools & UD, static loss rate=l bbl per/hr. Hole fill CACL=65.6 bbls, Measured =82.9 bbls, Diff+17.5 bbls over.;-Hauled 75 bbls fluid to KGF G&I Cumulative: 4,847 bible -Hauled 35 bels solids to KGF G&I Cumulative: 1665 bbis -Daily downhole losses: 0 bbls Cumulative: 23 bbls -Daily metal: 1 lbs Cumulative: 1163 lbs Conductor ann pressure- 0 psi 5/1/2019 Crew chg and PJSM, Continue Udn an chk Bha #14 Udn TM collar , drained mtr, brk bit grade bit 2,2, WT, A, E, I, CT, TD.; P/up jars and brk out XO clean floor, drain stack wash out bowl. P/up m/up 7" test jt install test plug and set same.;Chg out lower rams U7" discovered XO on test plug was too Iong.;Service rig while waiting on other test jt repair oil leak on TDS grabber block.;P/up M/up new test jt and set test plug flood stack and purge air and test 7" 250 low for 5 min and 4000 psi high for 10 min.;Pulled test plug, broke down test jt, R/D testing equip, cleaned & cleared rig floor for running 7" Iiner.;Crew change, held PJSM w/ Weatherford, R/U Weatherford tongs, power pack, and 7" elevators, M/U XO to TIW, P/U liner hanger to TO connections to spec, UD hanger.;Held PJSM w/ tool pusher, rig crew, Weatherford hands, Peak, and Baker Rep on running liner. Verify shoe tract measurements per tally. Static loss rate 0.8 bbis/hr.;Re-strap/tally first 20 jts of TXP BTC 29.00 ppf T' liner due to discrepancy in shoe tract jt measurements.; P/U & M/U TXP BTC 29.00 ppf 7" liner shoe tract, tested floats (Good), P/U & MU first swell packer, RIH w/ TXP BTC 29.00 ppf 7" liner F/shoe- T/2,019', puffing hydro form composite centralizers on ever jt, connections TO to 17,640K, filling every 10 jts, running speed=30'/min.;M/U swedge/TIW, CBU breaking gel strength & warming mud, GPM-115 SPP- 212, w/ no loss or gain after circulation. P/U-50K 8I0-46K.;Cont RIH w/ TXP BTC 7" liner 29.00 ppf F/2,019 to current depth of 2,333'. Pipe Disp. CACL=23.5 bels, Meas. 24.8 bbls, Diff 1.3 bbls over.;-Hauled 0 bbls fluid to KGF G&I Cumulative: 4,847 bels -Hauled 0 bbls solids to KGF G&I c Cumulative: 1665 bels -Daily downhole losses: 0 bbls Cumulative: 23 bbis -Daily metal: lbs Cumulative: 1163 lbs 1 Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 5/2/2019 Cont RIH P/u 7" TXP BTC casing29.00 f P-1 0 er m, filling on the fly and topping off every 10 installing 8-1/8" fiberglass �� 1 lin F/2 333' T/41 GT (� 3t fi molded solid body centralizers Pipe Disp. CACL=42.3 bbls, Meas. 41.8 bbls, Diff 1/2 bbl off .;Circ btm up and warm mud w/ no Iosses.;P/up install B.O.T T' Drilling liner hanger assy install double wiper plugs mix and fill tieback sleeve w/ Xanplex up/dn/wt =84K both ways ( liner Wt = 64k ).;Circ liner volume @ 168 gpm @ 550 psi and r/dn weatherford casers and 7" running equipment.;Rih p/up singles off walk @ 301'pm filling on fly topping off every 10 its , F/4,172'- T/6,44S. P/U-110K S/0-109K.;Crew change, held PJSM, cont. RIH w/ singles F/6,445'-T/7,938'. PIU-123K S/0-120K.;M/U TD, break circulation, staged up pumps, CBU to break gel strengths and warm up mud. GPM-168, SPP-590 psi, SPM-66.;Cont. RIH w/ singles F/7,938'-T/10,731', total of 210 jts P/U.;Shuffled HWDP across to access 4.5" DP.;Cont. TIH out of derrick F/10,731'-T/11,287, just above window, M/U TD, CBU to warm mud & break gel strengths. GPM- 168 SPP-775 psi P/U-150K S/0-144K.;-Hauled 68 bbls fluid to KGF G&I Cumulative: 4,915 bbls -Hauled 7 bbis solids to KGF G&I Cumulative: 1672 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bbls -Daily metal: 2.5 lbs Cumulative: 1163 lbs Conductor ann pressure-0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 5/3/2019 Continue CBU to warm mud & break gel strengths. just above window @ 11,290' GPM -168 SPP -725 psi P/U-150K 8/O -144K and establish parameters @ 10 rpm @ 2800 TO, 20 rpm @ 3400 TQ, 30 rpm @ 3600 TQ.;Continue Rib w/ 7" 299 P-110 Liner on dip f/ 11,290' U 13,091' filling on the fly and was able Keep it top of and with in 3 bbls of cal displacement.;work full stand, stage up pump rate and CBU to warm mud & break gel strengths.@ 13,091' GPM -115- 168 SPP -700 - psi ( getting some rubber over shaker swell pkr).;Continue Rih w/ 7" 29# P-110 Liner on dp f/ 13,091' t/ 14,452' working thru multiple tight spots.;washed and reamed liner f/ 14, 452' Q14,503', varying all parameters w/ 15 max TQ, 1300 Max psi and from 80 k do t/ 110k over (still getting back swell prk rubber & also getting broken up pieces of fiberglass centra[izers).;crew chg and PJSM, cont. RIH w/ TXP BTC 7" 29.00 ppf P-110 liner on DP F/14,503' -T/14,734', washing down w/ no rotary. GPM -115 SPP -550, UD working single. got back on even stds.;Cont. to wash & ream down F114,734' - T/14,789', set/down 30K P/U working single started working tight hole washing & reaming attempting to work through tight spot, GPM -134 SPP -700 psi ROT -15-50 TQ -12-15K. P/U-190K S/0 -162K ROT-180K.;cont. to get back swell packer rubber & also broken up pieces of fiberglass centralizers on shakers, with no serious losses to hole, cont. to work tight hole @ current depth of 14,809.; Due to having trouble getting 7" liner to bottom, we tested gas alarms w/ total safety and also tested choke manifold valve #11 250 psi/ 5 min Low & 4,000 psi/ 10 min High (Pass), before midnight. Witness was waived AOGCC Jim Regg & BLM Amanda Eagle.; -Hauled 0 bbls fluid to KGF G&I Cumulative: 4,915 bbls -Hauled 0 We solids to KGF G&I Cumulative: 1672 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bbis -Daily metal: 1 lbs Cumulative: 1167 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 5/4/2019 Cont. to work through tight spots @ 14,809'-T/15,193' TD w/ rotary, seeing 10-20K set/downs. RPM -50 GPM -145 SPP -650 psi P/U-230K S/0 -160K TQ- 10/15K.;Circulated & conditioned hole for cement job while M/U cement head & XO's on walk, staged up pumps from 4 bpm to 6 bpm.;P/U & M/U cement head, pulled string intension for cement job-220K.;Cont. to circulate & condition hole while R/U Halliburton cement equip, circulating @ 252 -GPM w/ SPP - 1375 psi.;Held PJSM m Halliburton cementers, service hand, & rig crew, went over cementing procedure, R/U cement bales to cement head and back up line to stand pipe.;Flushed cement line to cutting box w/ 1 bbis, pumped 3 bbis to flood lines to cement head & confirm circulation down hole, shut in at cement head, PT lines @ 252 psi Low & 5823 psi High. Pumped 32.8 bbls 13 ppg of clean spacer III, @ 3 bbls per/min- 680 psi, Baker Rep releases bottom plug, fN m- followed;by 88 bbis of 15.3 class "G" lead cement (400 sks) @ 5 bpm -895/1300 psi, followed by 61 bbls of 15.3 class "G" tail cement 215 sks 5 bpm - 600/7'00 0.1 C Baker Rep top Halliburton 10 bbls to flush lines on top of 00 psi wl ppb of , re eased plug, cementer pumped of water cement plug, cementem;displaced cement w/ 12.5 ppg W BM @ 5 bbis ICP -399 psi. At 130 We of 12.5 ppg mud displaced, reduced rate to 3 bpm @ 400 psi, seen bottom V plug latch 146.5 bbis into displacement 1230 psi, brought pumps back up to 5 bpm, calculated was 299 bbis to bump, FCP =1093 psi, did not bump plug, pumped 1/2;the shoe tract (2 bbis), with still no bump, actual pumped 301 bbis of 12.5 ppg mud, 100% returns of mud during cement job, floats held, bled back 1 bbl to truck. CIP @ 15:35 his, we didn't rotate or reciprocated during cement job, due to limitations of rig, had to emergency off hanger due to;not bumping of plug, set down -110K, put 14 wraps to the right in the string, let 14 wraps out, P/U S to clear dogs, dogs did release, SIC, to 68K to set packer, seen good shear indication of pins, P/U and rotated @ 20 -RPM, 2,500 TO, S/O & set/down 100K to ensure packer was set, P/U-135K S/0-130K;Pressured up to 800 psi & held, P/U pulling running tool out of hanger, observed pressure drop, kicked in both pumps, 470 -GPM w/ 2150 psi, circulated BU, while RID Halliburton equip. Didn't see any signs clean spacer or cement returns 0 BU.;Crew change, held PJSM, racked back 1 std, inserted wiper ball in pipe, pumped another BU to wipe any residual cement oft from inside the pipe. GPM -478 SPP -2300, finished RID cementers equip., cleaned & cleared rig floor in prep to TOOH.;Performed flow check (Good), pumped 20 bbl slug.;Started TOOH racking back pipe in the derrick 17/10,993'-T/9,317'.;P/1J cement head, soft broke XO's & pup jts, UD cement head and removed pup & XO's from rig floor.;Started POOH UD singles F/9,31 T to 7" liner hanger running tool, dogs were out & verified packer pins sheared.;Break down running tools & UD, cleaned & cleared rig floor. cont. to clean pits for up and coming OBM.;Drained stack, bleed down accumulator, opened lower ram doors, removed 7" rams, installed 4.5" rams, pressured up accumulator.; -Hauled 279 bbis fluid to KGF G&I Cumulative: 5,194 bbis -Hauled 60 bbis solids to KGF G&I� Cumulative: 1732 bbis \l -Daily downhole losses: 0 bbis AJ Cumulative: 23 bbls -Daily metal: 2.51bs �oY Cumulative: 1169.5 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 5/5/2019 P/up 4-1/2" test jt, set test plug and rig up test equipment flood stack and choke manifold purge air and obtain a 250U4000H 5110 min good shell test & clean pits.;Test bopes as per regulations 250 psi low for 5 min /4000 psi high for 10 min had retest on Test # 2 ( do to test manifold leak, also could not close manual [BOP so changed it out off line) and continue clean pits chg/ out centrifugal set new spool drill line on carrier w/ crane.;Crew change, held PJSM, finished testing BOP'S, cont. to clean pits for OBM.;R/D testing equip, Blew down TO, choke manifo[d.;Changed out saver sub on TD, R/U MPD's hard line, PT there lines to 250/1ow & 1,500/High (Pass).;Pulled test plug & test jt, broke down & UD, drained stack, installed 9" wear ring, run in two lock downs.;R/U Pollard E -line, held PJSM w/ Pollard hand & rig crew, RIH w/ Gamma my, CBL, CCL, liner top @ 10,991', tagged TOC @ 14,670', seen TOC on back side @ 12,758'. Sim Ops: changed out oil in draw works motor, checked oil in TO gen (Good), re -sealed catch can on stack w/ silicone, redressed MP #2.;w/4.5" liners & swabs, and finished cleaning pits for OBM.;UD Pollard E -line tools, cleaned & cleared rig floor for P/U BHA #15.; -Hauled 482 bbis fluid to KGF G&I Cumulative: 5,676 bbis -Hauled 23 bbis solids to KGF G&I Cumulative: 1755 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bbis -Daily metal: 0lbs Cumulative: 1169.5 lbs Conductor ann pressure- 0 psi 13-3/8 X 95/8 ann pressure - 0 psi 5/6/2019 Crew Change PJSM finish ndn pollard E -line.; Housekeeping hazard hunt w/ crew focusing on Rig OBM ready. Gather tools to string new spool drlg line and PJSM/JSA with crew on non routine operations.; Hang off TDS and blocks and restring same tighten drill line anchor and hang weight indicatorswelder out got caught up on welding Iist.;Hold debrief meeting over restring capturing lessons learned, suggestions, and improvements.;clear floor and cat walk and stage drill out bha chk ID, OD & FN.;P/up & M/up Bha #15 dumb iron clean out & drill out assy.;RIH w/ DP out of Derrick f/ 320' 0 4980'.;Grease roughneck, Crown, TopDrive & blocks. Check drive line bolts & break linkage. Seal seams and cracks in on rig floor with polyurethane foam sealant in preparation for OBM.;Attempt to make up 4 its of drill pipe with re -cut threads. Threads galled on 6 of 7 its picked up. Proceed with previously run its from rack while 4 more Its of re -cut threads retrieved from staging pad.;Single in hole with 154 jts 4-1/2" Drill Pipe f/ 4980' U 9760'. Stagger in 4 re -cut thread joints between last 4 old joints with no issues.;RIH with 4-1/2" drill pipe f/ 9760'V 11003'. P/U = 136k, S/O = 134k. No issues passing through liner top at 10991'.; Hauled 125 bbis fluid to KGF G&I Cumulative: 5,801 bbls -Hauled 15 bbls solids to KGF G&I Cumulative: 1770 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bbls -Daily metal: 0lbs Cumulative: 1169.5 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 5/7/2019 Continue RIH f/ 11,003' t/ 5k tag @ 14,745', wash do last stand p/up and re -tag same (75' deep to wire line) space out.;Circ STS and stage up rate to warm up mud. Down pumps.;Broke off topdrive, MU TIW and pump in sub on stump, MU topdrive. RU circ line from stump to flow line bleeder, closed upper rams and broke circ to ensure we could reverse circ. Shut down pump, closed TIW and did a base line casing test t/1389 psi for 20 min while holding PJSM on mud swap.;PJSM w/ all involved on change over to 9.6 ppg OBM from 12.5 ppg WBM w/ reverse circ. Bled off well and opened TIW on stump.;Lined up on pill pit, pumped 20 bbls 500 vis spacer, followed with 9.6 ppg OBM from pit 6. Peak transferring OBM into pits 9-10 with vac trucks, pit watcher transferring OSM from pits 9-10 to pit 6. Initial pump rate of 169 gpm-1050 psi. At 2200 psi we reduced pump rate to 122 gpm-2000 psi (trying;to stay at or below 2500 psi), at 2200 psi reduced pump rate to 90 gpm-2064 psi (pump at idle). At 13,000 strokes (900 stks shy of rounding the corner) and 2578 psi pump stalled. Had to bleed off and re -start pump. Had to increase pump rate to be able to cont pumping at 116 gpm-2765 psi.;As OBM rounded the corner and started up the drill string, pump pressure started decreasing to the point we could increase pump rate. Once we got spacer to surface and shut down, pump rate at 200 gpm-992 psi. Saw no pressure on 13 3/8" x 9 5/8" annulus.;Emptied and cleaned remaining pits of WBM. RD circ hose from pump in sub, removed topdrive, pump in sub and TIW from stump, LD 15' pup, latched up next stand.; Establish circulation and rotary parameters. Drill plugs and cement f/ 14745' 0 14910' 6-16k WOB, 60-100 RPM - 4k Tq, 285 GPM - 1595 psi. PIU = 182k, S/O = 170k, ROT = 172k. Plugs encountered @ 14761'.;Continue drilling cement f/ 14910' U 15095' 6 10k WOB, 80 RPM - 4.4k Tq, 285 GPM - 1575 psi. PIU = 182k, S/O = 170k, ROT = 172k.;Circulate bottoms up. 340 GPM - 2038 psi. Rotate and recip string. 70 RPM - 4.2k Tq.;Rig up to test casing. PJSM, Test casing U 2500 psi for 30 min. Good Test. -Hauled 90 bbls solids to KGF G&I Cumulative: 1860 bbls p -Hauled 880 bbis Fluid to KGF G&I 1 ! Cumulative: 6681 bbls -Daily downhole losses: 0 bbls r�(, ✓//// Cumulative: 23 bbls -Daily metal: 0lbs Cumulative: 1169.5 Ips Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 5/8/2019 Bled off casing and RD testing equipment (good casing test of 2500 psi for 30 min on chart).;Racked back one stand, removed trip nipple, centered up stack better to rotary table, PU single with RCD bearing installed and MU on drill string, S/O and landed bearing in MPD head, clamped in place.;Resumed drilling cement in float equipmentfshoe track, from 15,094' to bottom of shoe at 15,193'. Wob 14K, 263 gpm-1329 psi, 60 rpm -4600 to 5100 ft/lbs torque. While working pipe prior to connection, saw 10K overpull at 15,107'. Worked pipe a couple times rotating and was clean. Stopped;rotation and had another overpull at same depth. S/O, rotated up through 15,107' and was clean. Stopped rotary and worked through with no issue. Up wt rotating/pumping 178K, dwn wt 170K. Oqce out the shoe drilled new formation from 15,193' to 15,198'. Wob 16K, 261 gpm-1374 psi, 62 rpm.;5400 to 6300 ft/lbs on bott torque, 15 to 50 R/hr ROP, BGG 26 units, no gain or loss. Reamed in/out of shoe a couple times, then with no rotary, no issues.;CBU at 260 gpm-1369 psi, 50 rpm4300 ft/lbs off bolt torque, with bit parked inside shoe joint. Increased pump rate to 302 gpm-1726 psi. ES had no change at bottoms up, no sign of water. Mud loggers captured consisting of 60% cement, 40% shale, sandstone, aluminum and coal. Down pump.;Monitored well for water flow for 1 hour. No flow, well static. /sample Notified Drilling Manager and Reservoir Engineer.;Resumed drilling 6" hole from 15,198' to 15,213'. WOB 16 to 18K, 264 gpm-1369 psi, 62 rpm -4600 to 7000 .j\ ft/lbs on bott torque, 2 to 30 R/hr ROP, BGG 26 units. 20' new formation drilled. Worked pipe numerous times and alternated parameters trying to make hole. Up wt 190K, dwn wt 170K.;CBU at 262 gpm-1385 psi, 83 rpm -4700 fUlbs off bolt torque, pulled bit back into shoe joint and increased pump rate to 302 gpm- 1722 psi, 53 rpm -3800 ft/lbs off bott torque. At bottoms up, mud logger sample was 20% cement, 80% sandstone, siltstone and claystone. Obtained SPR's. RU for FIT.:Crew change, pump LVT through test hoses and kill line to purge air, closed upper rams and cont pumping to top off drill string, then closed TIW. Lined up on chart and pumped 465 gals/11.07 bbls to achieve 2300 psIo�anE vMW of 12.57 ppg at 7" shoe. Rig down lest equipment & blow down Iines.;Pull MPD RCD bearing and install trip nipple. 30k overpull breaking string free after test. Worked jt 3x after free with no issues.;Pump dry job, blow down TopDrive and POOH U 15159' 09700'. Racking stands in Derrick.;Continue POOH, laying singles down, f/ 9700' 07277'. - Monitor hole fill on trip tank Hauled 15 bbls solids to KGF G&I Cumulative: 1875 bbls -Hauled 250 bbis fluid to KGF G&I Cumulative: 6931 bbis -Daily downhole losses: 0 bbls Cumulative: 23 bbls -Daily metal: 4.51bs Cumulative: 1174 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 5/912019 Cont POOH LD singles from 7277' to 5042'. Total 150 jnts LD. Received 3 Rain for Rent frac tanks for diesel tank farm and 4 1/2" liner/float equipment on pad 3.;At 5042' shut down the floor motor. Performed rig service while testing floor motor inner cooler core for air leaks. Found left side of inner cooler core is leaking from top to bottom. Pason Rep installed fluid level sensor in LVT upright tank.;Cont POOH racking back in derrick to BHA, racked back HWDP, jars and NM flex DC's, LD bit sub, inline stab and bit. Tricone bit graded a 2-2. Rig Foreman and Rig Mechanic went after temporary inner cooler core at BA yard. Loaded 119 bbls LVT into upright tank.;Clean and clear rig floor, put well on trip tank for monitoring. Pason Rep installed gas analyzer/gas trap in shaker #2 possum belly.;Hung topdrive, cut and slipped 50' drill line, inspect and adjusted kickback rollers, eyebolts and springs on brake bands. Calibrated hookload and block height, checked crown saver while staging temp inner cooler core, tools and equipment. Received rig fuel.; Removed 4" air plumbing from inner cooler core, turbo and intake. Mounted temporary inner cooler core to front of radiator. Installed 4" air plumbing and secured same, secured floor motor roof top and inner cooler. Test ran OK (new core ordered out of Canada, should be here Tuesday 5-14).;MU 6" directional BHA t/ 116' as follows: 6" Hughes Kymera Bit, 4-3/4" Strataforce Motor, 4-3/4" DM Collar, 5.82" ILS, 3P Collar, ALD & CTN, PWD, TM Collar & Float Sub w/ non ported plunger float installed.;Plug in, confidence test and download MWD, Perform shallow hole test & load nuclear sources.;Continue M/U directional BHA U 428' with 2x NM Flex Collars, 4x 4.5" HWDP, 4-3/4" Jars, 3x HWDP.;RIH with 4-1/2" drill pipe stands f/ 428' t/ 5151'. Fill pipe every 2500'. Hole taking proper displacement.;Continue RIH picking up 4-1/2" drill pipe singles f/ 5151' U 7939 . Fill pipe every 2500'. Hole taking proper displacement. BGG @ 17u while tripping.;-Hauled 0 bbls solids to KGF G&I Cumulative: 1875 bbis -Hauled 0 bbls fluid to KGF G&I Cumulative: 6931 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bbls -Daily metal: 0lbs Cumulative: 1174 lbs Conductor ann pressure- 0 psi 5/10/2019 Cont PU single in hole from 7939' to 10,581' with 6" directional assembly. At 10,581' had a bolt break on the iron roughneck torque block. Filled pipe every 2500'.;Sewice rig and topdrive while replacing broken bolt on iron roughneck.;Cont PU single in hole from 10,581' to 11,042'. Total PU 190 jnts. The last 40 jnts were re-cut pin ends so MU to 80% of MU torque, broke, cleaned re-doped and MU to 100% twice, with no issues. Saw no sign of 7" liner lap at 10,991'.;Cont TIH from derrick 11,042' to 15,046', filling every 2500'.;Removed MPD trip nipple, PU single with MPD element installed, MU single and landed element in MPD head. MU topdrive and filled pipe.;TIH from 15,046' to bottom at 15,213' washing last stand down. No issue going through shoe track. Up wt 195K, dwn wt 180K, rot wt 182K.;Resumed drilling 6" hole from 15,213'to 15,242'. WOB 13K, 222 gpm-2572 psi, 60 rpm-5900 ft/lbs on bott torque, 17 to 45 ft/hr ROP, MW 9.5+/vis 64, ECD's at 10.1 ppg, BGG 22 units. At 15,230' md/14,430' tvd started seeing a gain to the pits. PU off bottom and shut down pumps. 14 bph flow.;Lined up on MPD choke skid and pressure climbed to 662 psi over 10 minutes. Restarted pumps and held 278 psi back pressure while drilling ahead and brought MW up to 10.6 ppg going down hole. Drilled ahead slowly to 15,267 maintaining 10.6 ppg going in hole, holding back pressure to maintain 11.2 ppg;ECD's and weighting up pits 4-5-6 so we can utilize vacuum degasser. Gas climbed slowly to 4999 units at bottoms up (14,100 strokes) then dropped off to 2500 units at 20,000 strokes. Mud loggers saw crude oil on cuttings (sand) at bottoms up.;PU to 15,256' and rotate/reciprocate and cont to circ and Gond mud, maintaining weight in at 10.6 ppg. MPD holding 550 psi / 11.35 ECD. Taking —15 BPH gain. BGG @ 2600u.;Make a connection and continue drilling f/ 15,267' V 15,328'. 225 GPM - 2850 psi, 60 RPM - 6k Tq, 14k WOB, P/U = 195k, S/O = 180k, ROT = 182k. Increase mud wt U 10.8 ppg. MPD holding 550 psi / 12.0 ppg ECD while drilling, 850 psi back pressure during connection.;No gain from formation at 12 ppg ECD. BGG dropping from 2600u to 1400u.;Multiple attempts to get MWD detection for survey after connection. Try different pumps and MPD configurations before getting the pressures to smooth out long enough to obtain sumey.;Continue drilling it 15,328' V 15,392' . Increase mud wt U 11.0 ppg. MPD holding 400 psi / 12.0 ppg EMW. No gain from formation at 12 ppg ECD. BGG=1400u, Connection gas = 2400u 225 GPM - 2850 psi, 80 RPM - 6k Tq, 14k WOB, P/U = 186k, S/O = 162k, ROT = 169k. MW In = 11.0 ppg, MW Out = 10.85 ppg.;Total of 43.6 bbls gained from bpm-lam. No gain from formation seen after 12.0 ppg ECD obtained.;-Hauled 0 bbls solids to KGF G&I Cumulative: 1875 We -Hauled 0 bbls fluid to KGF G&I Cumulative: 6931 bbls -Daily downhole losses: 0 bbls Cumulative: 23 bbls -Daily metal: 0lbs Cumulative: 1174 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-518 ann pressure - 0 psi 5/11/20 5 92' to 15451' wob 6 to 14K, 235 gpm-3190 psi, 80 rpm-5700 ft/lbs on bott torque, 10 to 40 ft/hr ROP, MW in 11.01MW out 10.8 and holding 380 psi backpressure on MPD to achieve 12.1 ppg ECD, dusting MW up to 11.2 ppg, BGG 1038, max gas 2936 units.;After drilling down stand to 15,451' we took 4 rotational checkshots and one geospan checkshot to allow town to gel survey modeling (Casandra and IFR corrections).;Cont drilling 6" hole from 15,451'to 15,507', wob 13K, 236 gpm-3000 psi, 100 rpm-5400 to 5700 f1lbs on bott torque, 9 to 45 fUhr ROP, MW in 11.4/MW out 11.4 and 40 psi backpressure on MPD full open choke giving us 12.2 ppg ECD, BGG 1140, max gas 2411 units.;After drilling down stand to 15,507' we took 4 additional checkshots.;Cont drilling 6" hole from 15,507'to 15,637", wob 9-16K, 235 gpm-3225 psi, 100 rpm-5300 ft/lbs on bott torque, 11 to 55 ft/hr ROP, MW in 11.4/MW out 11.4, 80 psi backpressure on MPD full open choke giving us 12.3 ppg ECD, BGG 819, max gas 1854 units. No loss observed in the G2_A zone.;Cont drilling 6" hole from 15,637' to 15,736. wob 10-16K, 230 gpm-3030 psi, 80-100 rpm-5600 ft/lbs on bott torque, 8 to 45 ft/hr ROP, 80 psi back pressure on MPD full open choke giving us 12.3 ppg EGD, BGG 895, max gas 2236 units.;Cont drilling 6" hole from 15,736' to 15,861'. wob 10-16K, 237 gpm- 3241 psi, 80-100 rpm-5650 ft/lbs on bott torque, 8 to 45 ft/hr ROP, P/U= 202k, S/O= 166k, ROT= 180k.;80 psi back pressure on MPD full open choke giving us 12.35 ppg ECD, BGG 830, max gas 1677 units. Holding —400 psi back pressure with MPD during connections. Currently drilling in sandstone inter-bedded with siltstone, seeing traces of thin 1/2"-1/4" coals.;-Hauled 45 We solids to KGF G&I Cumulative: 1920 bbls -Hauled 45 bible fluid to KGF G&I Cumulative: 6976 bible -Daily downhole losses: 0 bbls Cumulative: 23 bbis -Daily metal: 0lbs Cumulative: 1174 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 5/12/2019 Cont drilling 6" hole from 15,861' to 15,884', web 12K, 225 gpm-3016 psi, 80 rpm -5700 ft/lbs on bott torque, 17-35 ft/hr ROP, MW 11.5/vis 59, BGG 830, max gas 1679 units, full open MPD choke at 64 psi back pressure, ECUs at 12.3 ppg. Obtained survey at 15,884'.;CBU at 244 gpm-3156 psi, 50 rpm -5000 It/fibs off bott torque, MW 11.51vis 61, ECU's at 12.3 ppg, BGG 1079 to clean up wellbore for wiper trip. Up wt 200K pumping but no rotation.;Shut down pump with 470 psi on backside. Line up MPD on annulus, idle pump #1 across backside, MPD increased back pressure to 750 psi, attempt to pull up hole on elevators. Pulled 50K over with no string movement. S/O and make second attempt with no movement. MU topdrive and line up to pump;down drill string, reduce back pressure to 290 psi, pulled 45K over and string came free, up wt 200K, pumping 142 gpm-1560 psi. Pulling nice and smooth. Held 470 psi while racking pipe back. Cont pumping up hole to 15,576'. Made second attempt to strip out of hole with same results. Pull 50K over;with no movement holding 750 psi on annulus. S/O, and redueced back pressure to 650, still no movement. MU topdrive, pump down drill pipe and reduce back pressure to 290 psi. Pipe pulled up hole with issue. Appears holding backpressure for stripping OOH may be differentially sticking us in the G2_A;which is the weaker zone. Cont pump OOH from 15,576' to 15,267'. Had a 10K over pull at 15,348' (claystone) and a 5K overpull at 15,303' (top of a coal). SIO to 15,328' and parked string for rig service holding 260 psi back pressure while pumping 182 gpm-2246 psi. ECD at 12.3 ppg.;Greased blocks, drawworks and topdrive, rig mechanic changed out a leaking hose on rig Floor transmission. Shut down pump holding 470 psi on backside, greased washpipe.; Lined MPD up on annulus, idled pump across annulus holding 290 psi backpressure and TIH on elevators from 15,328'to 15,720' and set down 10K, worked one time and was clean, TIH to 15,757' and set down 10K, worked twice and still set down, MU topdrive, lined up MPD to pump down DP, washed;down to 15,759'. Washed last two stands down to 15,884' with no issue. Down wl with no pump 170K. Circulated on bottom 10 minutes and made connection, then pumped a 20 bbl hi -vis nutplug sweep.;Cont drilling 6" hole from 15,884' to 15,949', web 12K, 227 gpm-3061 psi, 80 rpm -5778 fit/lbs on bolt torque, 5 to 40 ft/hr ROP, MW 11.5/vis 54, full open choke, ECD's at 12.3 ppg, At 7400 strokes into pumping (bott up = 14,310 stirs) gas increased to 4198 units, dropped off to 2113 units, then rose;again to 3924 units, then dropped to 1000 units over the next 75 minutes. At 9000 strokes we started seeing an increase in pea sized coal. By the time sweep came back at 19,045 strokes, coal had tapered off to little or nothing. Had 10% increase in fine cuttings with sweep back. Gas at 1000 units.;Dust MW up to 11.6 ppg, at 220 gpm-3047 psi and full open MPD choke we have 12.3 ppg ECD.;Cont drilling 6" hole from 15,949' to 16129'. 225 GPM - 3194 psi, 10-16k WOB, 80-100 RPM , 7.5k Tq. P/U= 200k, S!O = 168k, ROT = 176k.;Maintain full open MPD choke while drilling - ECUs @ 12.45, Holding —400 psi back pressure during connections. Max gas = 1629, BGG = 675. Adding 11 PPB Calc-Carb to control seepage Iosses.;Cont drilling 6" hole from 16,129 to 16275'. 230 GPM - 3203 psi, 12-17k WOB, 80-100 RPM ,6-7k Tq. P/U= 202k, SIO = 170k, ROT = 178k. Max gas = 1174, BGG = 650.;Maintain full open MPD choke while drilling - ECUs @ 12.40, Holding —400 psi back pressure during connections. Maintaining 12 PPB Calcium -Carbonate to mitigate any losses.; -Hauled 32 bbis solids to KGF G&I Cumulative: 1952 bbls -Hauled 48 bbis Fluid to KGF G&I Cumulative: 7024 bbls -Daily downhole losses: 17 bbis Cumulative: 17 bbis -Daily metal: 10 lbs Cumulative: 1184 be Conductor and pressure -0 Psi 5/13/2019 Cont drilling 6" hole from 16 275'to 16.433' wob 13 to 15K, 214 gpm-3000 psi, 90 rpm -6600 to 6900 ft/lbs on bott torque, 15 to 70 ft/hr ROP, MW 11.6/vis 61, full open MPD choke, ECUs at 12.4 ppg, BGG 695, max gas 1095 units.;Cont drilling 6" hole from 16,433'to 16,566', web 14K, 215 gpm-3304 psi, 100 rpm - 7150 Nibs on bott torque, 15 to 32 ft/hr ROP, MW 11.7/vis 61, full open MPD choke, ECUs at 12.6 ppg, BGG 660. MWD having trouble getting survey.;Cycled pumps individually with no survey, Tried downlinking with GeoSpan twice with no survey. Obtained SPR's then isolated pumps individually and checked suction/discharge screens. Got survey.;Cont drilling 6" hole from 16,566' to TD @ 16,642' 11 k WOB, 214 gpm 3300 psi, 100 RPM, 10k tq on, 7.5k off, MW 11.8ppg, Full open MPD choke, ECD 12.7ppg BGG 550u, 25.3 FPH ROP Avg.;Circulate bottoms up X2 222gpm 3100 psi 90 RPM, reciprocating pipe.;Short trip f/ 16,642't/ 15.205'142 gpm 1800 psi.; -Hauled 45 bbis solids to KGF G&I {� Cumulative: 1997 bbls -Hauled 45 bbls Fluid to KGF G&I Cumulative: 7069 bbls \y/ ��- -Daily downhole losses: 10 bbls Cumulative: 27 bbls -Daily metal: 0 Ibs Cumulative: 1184lbs Conductor ann pressure- 0 psi 113-3/8 9-5!8 and pressure - 0 ps 5/14/2019 Circulated with bit just outside shoe and above the GI—A at 15,205', while performing rig service and cleaning rig floor. 192 gpm-2380 psi, 50 rpm -0500 ft/lbs off bott torque, wide open MPD choke, ECU's at 12.4 ppg.;TIH on elevators from 15,205' to 15,440' and set down 10K, MU topdrive and washed/reamed to 15,480'. TIH to 15,827' and set down IOK, MU topdrive and washedireamed to 15,852', TIH to 16,505' and set down 40K, MU topdrive and washed reamed last two stands to bottom at 16,642'. 20' fill on bottom.;Circulated 5000 strokes then started a 30 bbl hi -vis nut plug sweep down drill string. Had 1444 units gas a 6237 strokes. With 1st sweep clear of bit started a 2nd 30 bbl sweep down drill string. Had 2124 units gas at 12,178 strokes (bott up = 14,552 stks), had 942 its at bottoms up. Pumping at;222 gpm-3131 psi, 100 rpm -6500 Nlbs off bott torque. 25% increase in pea sized material with first sweep to surface, 10% increase in fine sand like material with second sweep to surface. BGG 420 units. Pumped an additional 6000 strokes beyond second sweep and shut down /7 rotary and pump. Bled off.:Fully closed MPD choke and monitored well for pressure build. Over one hour we had SIDP of 370 psi and SICP of 516 psi. Noted Drilling Manager, decision made to increase MW from 11.8 to 12.3 ppg, Bled off, started pump and rotary.;Pumped at 220 gpm-2948 psi, 100 rpm -6000 ft/lbs t off bottom torque, start weight up of active system frpm 11.8 to 12.3 ppg. Had 3235 units gas at bottoms up.;Monitor well, shut in MPD Annulus psi built up V \ 165 psi in one hour 0 psi on DP, Bleed off psi, flow check well 1.1 bob flow rate.;P/U Single, Wash and ream last 16' to bottom 45 RPM 6k tq off, 140 GPM 1800 psi, no fill LID single.;POOH f/ 16,642' V 15,390' on elevators holding 200 psi on back side w/ MPD.; -Hauled 40 bbls solids to KGF G&I Cumulative: 2037 bbis -Hauled 40 bbls fluid to KGF G&I Cumulative: 7109 bbis -Daily downhole losses: 8 bbis Cumulative: 35 bbis -Daily metal: 0lbs Cumulative: 1184 his Conductor ann pressure- 0 psi 13-3/8 X 9-5/6 ann pressure - 0 psi 5/1512019 Cont POOH on elevators slowly from 15,460' to 7" casing shoe at 15,193' with no issue. Hole in good shape. Up wt 180K at shoe. MPD holding 125 psi back pressure on annulus gave us the closest proper pipe displacement of 2 bbls per 5 stands with 12.3 ppg mud in wellbore.;Cont POOH inside 7" casing, slowly to 11,507'. Flow check at 11,887' resulted in 1.7 bon. Clean rig floor and prep to LD singles. Cont POOH LD singles from 11,507' to 10,789 (inside 9 5/8" casing).;Al 10,798' MU topdrive, broke circ to warm up mud, then pumped and spotted 40 bbl hi -vis 13.5 ppg mud cap.;Pulled up hole LD 20 joints from 10789' to get bit clear of mud cap, still holding 125 psi on annulus with MPD choke, to 10, 17&.;Lined up well on flowline and flow check well. Initial flow rate at 2.2 bph, dropped to 1.7 bph, then back up to 1.9 bph over 30 minutes. Discussed with Drilling Manager and decided to pull up hole using MPD and spot another 15 ppg mud cap.;Cont POOH LD singles from 10, 178'to 4450' start standing back stands POOH U 2250' holding 125 psi backpressure with MPD choke.; -Hauled 0 bbls solids to KGF G&I Cumulative: 2037 bbls -Hauled 30 bbls fluid to KGF G&I Cumulative: 7139 bbls -Daily downhole losses: 0 bbls Cumulative: 35 bbls -Daily metal: 0lbs Cumulative: 1184 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann Pressure - 0 psi 5/16/2019 Cont POOH with 6" directional BHA #16 from 2250' to 1482' using MPD to hold 125 psi back pressure. At 1482' MU topdrive .;Pumped/spotted 110 bbls 15.0 ppg mud cap at 125 gpm- ps. ith 13.5 ppg mud back to surface captured returns in trip tank. With 15.0 ppg back to surface shut down pump.;Monitored well for flow. Initial flow rate 2 bph then dropped to 1.7 bph, but then increased to 1.9 bph over 30 minutes. Closed MPD choke and pressure built to 77 psi over 20 minutes and climbing. Discussed with Drilling Manager, decision made to TIH to 2000' and circ 15.0 ppg to surface. Bled off.;TIH with stands from 1482' to 2035' and MU topdrive. Closed in MPD choke to monitor pressure while weight up pit 7. We built no pressure. Opened MPD choke, lined up on flow line to monitor well, had no flow.;Pull up hole slowly from 2035' with good displacement per 5 stands. At 616' hole started taking less displacement on last 5 stands. At HWDP PU single, retrieved MPD bearing and installed trip nipple. Initial now check at 2 bph that dropped off to 1.2 bph. LD HWDP and jars, LD NM flex DC's, plugged;in and turned off MWD tools, then LD same to be downloaded on the ground (to expedite getting RU and run liner). drained motor and broke off Kymera bit (rough shape but in gauge). Bit graded: Roller: 2-6-LM-G-F-I-RO-TD PDC: 1-6-RO-T-X-1-CT-TD 463 on bottom K Rev's.;Closed blinds and 4" stand pipe valve, opened up on kill side of slack to monitor pressure build on stand pipe pressure gauge. Showing 208 psi over 30 minutes. Clean/clear rig floor.;RU Weatherford casing tongs, elevators and slips, RU fill up line, stage centralizers on rig floor, stage CDS-40 box x DWC pin XO on rig floor, Bleed off 405 psi build up on annulus.;PU and MU 4 1/2" DWC/C shoe track, check floats. Cont PU single in hole another 35 joints 12.60 L-80 liner (total 39 jnts) to 1598'. PU Baker 5" x 7" HRD-E ZXP W/RS liner top packer and DG Flex -Lock liner hanger assembly as per Baker Rep. Set up with 9 shear screws, shear force of 44,168 lbs.;Mixed and poured Pal Mix, RD Weatherford tongs/elevators, RIH w/ 2 stands DP t/ 1761' Remove trip nipple install bearing.;Slip and cut drilling line while circulating out 15 ppg mud cap 180 gpm 200 psi.;Continue RIH w/ 4.5" Liner on DP f/ 1761' t/ 2484' holding 50 psi on MPD choke.; -Hauled 0 bbls solids to KGF G&I Cumulative: 2037 bbls -Hauled 0 bbls fluid to KGF G&I Cumulative: 7139 bbls -Daily downhole losses: 0 bbls Cumulative: 35 bbls -Daily metal: 0 His Cumulative: 1184 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 5/17/2019 Cont TIH with 4 1/2" DWC liner from 2484' to 5611' on stands of 4 1/2" CDS40 DP, holding 50 psi backpressure with MPD. Increased back pressure to 200 psi to reduce pipe over -displacement. Top filling DP on the fly, then lopping off completely every 5 stands prior to measuring displacement.;At 5611' topped off DP with fill up hose, MU topdrive and eased into bottoms up circulation, staging up to 225 gpm-722 psi, holding 300 psi back pressure to maintain gpm outflow with rig pump rate. Initial gas at 87 units, climbed to 170 units which dropped to 58 units at bottoms up.;Started running centrifuge on pits 1-2 to reduce MW of the 15.0 ppg mud cap.;Shut down pump and resumed TIH PU singles from 5611'to 10,986', still holding 324 psi back pressure for proper pipe displacement, top filling on the fly and topping off every 10 joints.;At 10,986, topped off DP with fill up hose, MU topdrive and CBU at 225 gpm-695 psi, had a max of 5000+ units gas, Gas units spiked up @ 4100 stks, Oil and hi gas content till 300 stks past bottoms up then gas started dropping, Pumped 15,636 stks total, back ground gas 650 units.;Continue RIH PIU Singles f/ 10,986'1/ 13,062' holding 350 psi back pressure w/ MPD. Topped off DP and MU topdrive.;CBU. Broke circ at 200 gpm-600 psi, up wt 152K, dwn wt 148K. When BGG reached 2850 units we lined up returns from MPD to poorboy degasser. Current BGG 1526 units and dropping. Current MW in 12.3 ppg, MW out 12.3 ppg. Lots of crude oil to surface. -Hauled 0 bbls solids to KGF G8 Cumulative: -2037'15M_ -Hauled 0 bbls fluid to KGF G&I Cumulative: 7139 bbls -Daily downhole losses: 0 bbls Cumulative; 35 bbls -Daily metal: 0 lbs Cumulative: 1184 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 5/18/2019 At 13,065', cont CBU at 200 gpm-600 psi. With BGG at 2850 units we lined up returns from MPD through poorboy degasser. Lot's of crude to surface. MW in 12.3 ppg, MW out 12.2 ppg at 6900 strokes (half way into bolt up), MW in 12.3/out 12.1. MW out dropped as low as 7.2 ppg looking like straight;crude 4000 strokes before bottoms up, at which time we were circulating through poorboy degasser. Had a max of 5000 units. Circulated until MW out increasing at 11.8 ppg and BGG down to 1563 and dropping, holding 350 psi backpressure while circ. 434 psi static. Up wt 152K, dwn wt 148K.;Cont to TIH with stands from 13,069' to 15,111' holding 400 psi back pressure and top filling pipe completely every 5 stands. Held 400 psi back pressure while S/O and getting proper pipe displacement of 2 to 2.3 bbis per 5 stands.;At 15,111' PU single int and RIH, then PU Baker cement head and MU on single. Torqued 5' pup and XO's with topdrive, pulled up hole 30' and broke off, LD cement head and single as one unit, staged in "V" door. Up wt 198K, dwn wt 168K.;RIH one stand and top filled pipe. MU topdrive and broke circ with pump at idle. Obtained rotating parameters as follows: 10 rpm = 3500 ft/lbs torque, 20 rpm = 3400 fVlbs torque, 30 rpm = 3600 ft/Ibs torque. Up wt rot/pumping = 176K, dwn = 168K, no rot up = 184K, dwn = 164K. Down pump.;Exited 7" casing shoe at 15,193' and cont trip in open hole from 15,193' to 16,438' where we set down 20K. (claystone/siltstone transition into sandstone). Pulled 40K over and came loose, SIO and cont TIH to 16,618' nice and smooth. PU 15' pup and MU. PU cement head with single and MU topdrive.;Broke circ at an idle but started pressuring up just a couple minutes into circ. Able to rotate 20 rpm no problem, but still builds pressure and flow drops off, packing off. Worked pipe and pump with rotary making no headway. Worked back up hole and LD cement head, single and 15' pup.;Cont working pipe at 92 gpm-900 to 1200 psi, 25 rpm -4600 fVlbs torque and worked back down to 16,586, occasionally getting pup rate up to 136 gpm-1069 psi, but still fighting pack off, working pipe at 16,577' had to divert crude returns through poorboy degasser into pit's 1-2, gas up to 4398.;Continue working pipe 25 rpm 4-7k lq, 47-65 spm 880-1500 psi, packing off work string down V 16585' work string broke through without pumps slack off V 16602', attempt V stage pumps up V 3 bpm establish circ f/ 25 min began packing off, Pick up cement head attempt to work string still packing;off, discuss options w/ drilling manager, Continue circulating working pipe attempting to get circ rate without pack offs.; -Hauled 40 bible fluid to KGF G&I Cumulative: 7219 bbis -Daily downhole losses: 0 bbls Cumulative: 35 bbls -Daily metal: 0 Iles Cumulative: 1184 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 5/1 912 01 9 Circulate and condition mud, attempt to stage pumps V 3 bpm but packing off, LID cement head and single, UD another single, PIU cement head and single, slack off V 16,603' and establish circ rate of 2 bpm 950-1100 psi, 25rpm 4k tq, without pack offs, mixed and pumped 50 bbl NXS lube pill around.;Staged pumps V 3 bpm -1150 psi, 25 rpm 2.5-4k tq, held PJSM with rig team and Halliburton cementers, rig up hardline, manifold, chicksans and cleanup hose. Up wt 178K, rot wt 174K, dwn wt 168K while circulating. Shut down rig pump, close in upper TIW on cement head and lower on topdrive.; Halliburton pumped 3.5 -/ bbis water to flush lines to, then 3.5 bbis to fill lines. Shut in at Baker cement head and PT lines at 450 psi low 5000 psi high. Good tests. Lined up Baker cement head to pump truck, pumped 30 bbls 13 ppg spacer at 2.2 bpm -681 psi, taking returns down flow line;(did not use MPD but had bearing in place) followed with 35 bbis (165 sx)TT—ppg Class "G" Lead cement at 2-4 bpm, 196 to 1100 psi, with good returns, no indication of packoff and shut down. Had 2.5 l ppb LCM blended in cement prior to the job. Halliburton then displaced with 12.3 ppg OBM mud at 3.5; bpm -950 psi ICP. We did not see dart latch wiper plug. I With 20 bbis to go, reduced rate to 2 bpm -1500 psi and saw plug bump landing collar at 225 bbls into displacement (calculated at 235 bbis) and held 2360 psi w (FCP 1500 psi) for 3 minutes. Bled back 2 bbls to truck and floats held.;CIP at 13:30 on 5/19/19. Rotated string throughout the job at 25 rpm, up until anticipated 10 bbis to bump plug. Reciprocated string a couple times with no issue.;With pressure at 0 psi, slacked off on blocks from I 80 to 140K, indicating ,/✓ hanger was set. PU 10'to clear dogs from hanger top and had no indication we released liner string. Pump truck pressured up on string to 500 psi, pulled up to 205K and broke over, PU another 12' then SIO to 180K,;PU and pulled to 230K to beak over, S/O and string took no weight. Pump truck increased pressure to IVV' 4000 psi as per Baker Rep, held for a minute then had them bleed to 0 psi. Cont to work string with no indication we released from hanger. Pump truck pressured up to 5000 psi and held for a minute;then bled off to 3000 psi. Cont to work string but still appears we are moving entire liner string. Bled off and RD hardline to cement head, broke off cement head and LD same. PU single jnt DP and MU on string, MU topdrive. S/O to 120K, PU to 160K. With torque set at 5K, rotated to the left 4 rounds;PU to 170K, S/O to 120K, PU to 190K, S/O to 120K, turned to the left one more round, S/O to 110K, PU to 180K, S/O to 110K, PU to 170K, rotated 5 rounds to the right, PU 10% S/O and set down 5' higher indicating we had exposed dog sub and released from liner hanger. PU to 180K, rotated topdrive at;15 rpm, S/O and set down to 110K (60K applied to packer), PU and rotated at 25 rpm, set down 2 more times at 11 OK, PU and set down again with 80K applied to packer, PU and set down one more time with 100K applied to packer to transfer weight to packer. Top of liner hanger at 14.973.73'.:tOD of landina collar at 14,460.56'. shoe set at 6 0 '.;Pressured up with rig pump to 600 psi on liner/DP, PU 17' and once we saw pressure start to drop kicked on both rig pumps and CBU at 300 gpm-698 psi. Had no cement to surface, but we did see 13 ppg spacer contaminated mud. Racked back one stand, inserted wiper ball in string, MU topdrive and;did a second bottoms up at 296 gpm-710 psi. Shut down mud pumps.;Closed upper rams, ran one rig pump and pressured up on casino to test liner too Packer at 1800 psi for 10 minutes. Good test. Bled off, opened rams and pumped 20 bbl dry job.; POOH from 14,848'to 6440' UD Singles.; Pull wear ring set test plug, clean rig floor of OBM change out felt around walking surfaces, clean cellar with pressure washer, cleaning it pits and centrifuging mud down.; -Hauled 182 bbis fluid to KGF G&I Cumulative: 7401 bible -Daily downhole losses: 13 bbls Cumulative: 48 bbis -Daily metal: 0 lbs Cumulative: 1184 lbs Conductor ann pressure- 0 psi U Ops Summary Well Name: BCU-04RD Field: Beaver Creek County/State: Kenai, Alaska (LAT/LONG): Cumulative: 7685 bola ovation (RKB): 18 API #: Cumulative: 2566 bbls Hilcorp Energy Company Composite Report Spud Date: 3/3/2019 Job Name: 1910116C BCU-04RD Completion Contractor Hilcorp 169 AFE #: AFE $: ,.., ., . , # Ops Summary 5 /2 412 01 9 Accepted rig on afe 1910116C @ 00: 01 hrs,Reverse circulated well to balance out well, shut down pumps, flow check, no flow., Broke off 10' pup it side entry sub, and TIW, R/U 2" bleeder line, blew down TD to cuttings box, pumped 10 bbl water dryjoa.,Started POOH F/16,471', UD 4.5" DP, sucking football through tubulars and cleaning and re -doping threads. Current depth of 15,537', -Hauled 0 bola fluid to KGF G&I Cumulative: 7685 bola -Hauled 0 bible solids to KGF G&1 Cumulative: 2566 bbls -Daily downhole losses: 0 bible Cumulative: 48 bols -Daily metal: 0 lbs Cumulative: 1184 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-518 ann pressure - 0 psi 5/25/2019 Continued POOH Udn dp F/15,451' V 13,980' ) Wiping OD and Vacuuming football through ID and cleaning and re -doping threads.,Fill hole wl 6.2 bbls and Flow chk and Monitor well , set up to run continuous hole Ill pooh f/ 13,980't/ 12,463' crew change w/ 1.4 bats less then calculated displacement Wiping OD and Vacuuming football through ID and cleaning and re -doping threads -Continue pooh 1112,463, t/ 10 ,961' w/ 10.5 bbls bbls behind on displacement Wiping OD and Vacuuming football through ID and cleaning and re -doping threads and I/dn clean inspect Top 9-5/8" scraper assy,Monitor well bit above top of 7" liner 10 896' w/ 5.3 bph flow on back side and breathing w/ wet coffee filter on dp,Shut in well @ 15:41 hrs monitor for pressure build hr = 748 psi, 2 hrs = 1053 psi, 3 hrs = 1322 psi, 4 hrs = 1435 psi, 5 hrs = 1487 psi, were it seemed to stabalize.,Shut in kill HCR, lined up MP #1 to land/ and pipe, choke, and gas buster, equalized pressure, held PJSM, prepared to circulate through choke, lost air boot on MP suction line, changed same.,Preformed first stage of driller method, pumping @ 4 bpm w1 a ICP of 1800-1900 psi, maintain pressure w/ manual choke holding back pressure, circulated BU, had a max gas of 320 units, w/ no signs of water at BU. Lowest MW was 6.6+ ppg at BU, mud did turn milky with what appeared to be a very small skim of oil on top at BU.,Cont. circulating gas out after BU, once gas dropped out, shut down pump, trapping 1580 psi @ the choke, monitoring well.,Started clean pits 1-3, 7 & PP of OBM, while working on house keeping & cleaning around the rig. Current well bore pressure 1528 psi. 5 /2 612 01 9 Continued monitor SICP F/ 1500 psi - 1485_psi at noon. Continued to clean pits 1-3, 7 & PP of OBM, swap out rain for rent tank farm tanks Move pipe racks and DP back from KGF & cleaning around the rig. Start r/dn centrifuge install waste gate on dwk mtr,Continue monitor SICP fl 1485 psi V 1466 psi @ 15:30 hrs. Continue and finish cleaning pits, move diesel from pit 4,5&6 to 3 & 7, set up pipe racks, strap & tally DP, moving 6 full ISO back from dock face and attempting to get 6 MT iso tanks back to GPP to reload OBM, un able to load do to weathenOpen TIW SICP = 1452 psi, SIDPP = 1449 psi Bleed off pressure through choke/ gas buster w/ a total 10.2 bbls back,Monitor Gain while, P/up rabbit & strap singles rih V 10,897' Vi 1,918' did not see Top of 7",Cont. PIU ' singles & RIH F/1 1,918'-T/1 3,376'.,TIH of derrick F/13,376' -T/14,676', we were 33.7 obis over calculated on hole displacement for the trip. P/U-170K S10- 160K,Installed TIW valve, MW 5' pup to TD, shut in upper pipe rams, lined up to circulate through the choke taking return out of the gas buster.,Started ��.� .� circulating using first step of the driller method @ 4 bpm, building casing pressure to 1500 psi, ICP=2100 psi, 571 bols into CBU MW dropped from 6.7 ppg A (diesel) to 6.6+, cont+ to circulate out light mud & gas, 642 bola into BU, MW went from 6.7 ppg to 7.1 ppg, started over boarding mud„while cont. to circulate, 7 MW climbed to highest of 7.8 ppg, dumped a total of 87 bbls of diesel/water/oil- milky interface, once we got a 6.7 ppg MW back, brought it into the pits & cont. to circulate out the gas, once gas dropped out, shut down the pump & opened up the well, DP was on a vac„and had a small flow on the back side. Max gas of 596 units during circulation..Made decision to TIH to bottom, started PIU singles & RIH F/14,676' -T/14,973' TOL (4.5"), went through liner top w/ not even a bobble, cont. RIH PIU singles T/16,471', tagged up, we were 19 tools over calculated on hole displacement for the trip,Installed TIW, MN 5' pup to TD, shut in upper pipe rams, lined up to choke, taking returns out the gas busters, pumping @ 4 bpm. building casing pressure to 1500 psi, CP=2100 psi. Received 3,517 gals of diesel to for the rig., -Hauled 123 bbls fluid to KGF G&I Cumulative: 7833 bbls -Hauled 52 bols solids to KGF G&I Cumulative: 2673 bible -Daily downhole losses: 0 obls Cumulative: 48 bible -Daily metal: 0 lbs Cumulative: 1184 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 5/27/2019 Continue to circ thru choke @ 4 bpm holding 2100 psi on dp MW dropped from 6.7 ppg (diesel) to 6.6+, cont. to circulate out light mud & gas ,MW went from 6.7 ppg to 7.8 ppg, dumped a total of 203 bbis of diesel/waterloil- milky interface during displacement, had max gas of 1241 units,Circ total of 776 bbls w/ gas unit dropping t/ 61 units, shut do and shut in, monitored SICP while loading rig wl OBM and prep for chg over ISICP= 1580 psi. Monitored rising trend every 5 min to stabilization, after 2hrs & 40 min it stabilized at 1688 psi,Continued to monitor stabilized SICP @ 1688 psi, hang off blocks, changed out brakes pads & bands, inspected Eaton brake, slip & cut 35' of drill line, spotted Peak trucks for chg out,Held PJSM, performed modified version of second stage of drillers method, bleed of stand pipe pressure, primed mud lines, closed bleeder & equalized DP/CSG, opened TIW.,Started pumping 4 bpm through choke, taking return from gas buster, pumped 13 bbls Hi -Vis spacer, chased w/ KWM 9.0 ppg, KWM to bit 214 bbls, FCP=1100 psi, total stks=7890, once KWM turned the corner at the bit, held FICP constant @ 1200 psi till KWM reached surface, 923 bbls. Shut down pump.,Bled off trapped pressure, opened upper pipe rams, closed HCR choke, performed Flow check, well string was out of balance, shut in and monitored pressure. SICP=O psi, SIDP=95 psi,Lined up both pumps on the hole, circulated DP volume to balance well, GPM -275 SPP -3265. Shut down performed flow check, well was static,POOH F/16,473' -T/15,853', checking draw works break performance ( appears to be better)., Pulled rig service, greasedlinspected blocks/draw, works, adjusted break linkage & equalizer bar on draw work, slipped more drill line on drum.,Crew change, held PJSM, began POOH racking back stds in the derrick F115,858' -T712,219, pumped 10 bbl dry job 2 lbs. over MW.,Cont. POOH racking back in the derrick F/12,219' -T/11,701', getting calculated hole fll.,Started UD 4.5" singles F/11,701' to current depth 9,283', vacuuming footballs through pipe & cleaning threads before UD on rack, at report time we are 5.4 over calculated hole fill., -Hauled 110 bbls fluid to KGF G&I Cumulative: 7943 bbis -Hauled 5 bbls solids to KGF G&I Cumulative: 2678 bbls -Daily downhole losses: 0 bbis Cumulative: 48 bbis -Daily metal: O lbs Cumulative: 1184 Ibs Conductor ann pressure- 0 psi 13-318 X 9-5/8 ann pressure - 0 psi 5/28/2019 Continue UD 4.5" singles F/9,283' T/ 5806' , vacuuming footballs through pipe & cleaning threads before UD on rack„Continued pooh racking back T/ 9-518” scraper assy @ 5536' Clean and inspect I/dn same recovered (11 LBS iron on magnet),Continue pooh racking back F/ 5536'T/ 7" scraper assy @ 1558' Clean and inspect I/dn same recovered (6 LBS iron on magnet),PJSM R/up Weatherford tog tongs and m/up TUN XO,I/dn 2-7/8" dip wiping and vacuuming clean. T/ 4-1/2" scraper assy,Brk off and inspect 3-3/4" bit & XO Inspect and cleaned and I/dn scraper assy same recovered (1 LBS iron on magnet) 7.0 bbls over calculated hole fill for complete trip and no issues w/ brakes on trip out, R/D Weatherford equip. PIU 3.5" test jt, M/U test plug, opened CSG valve, set test plug, fill stack/choke line w/water, TIW/pump in sub to test jt, M/U pump in sub to TDS.,Performed full BOP test on 4.5" & 3.6', 5 min Low/250 psi & 10 min high/2500psi on annular, 5 min Low/250 psi & 10 min High/4000 psi on all other test, had Total Safety on location to test gas system (Good), only had one Fail/Pass during testing, test #2w/3.5", had air trapped in TIW, purged air out of TIW„Passed. Test witness waved by AOGCC Rep Jim Regg & BLM Rep Amanda Eagle. Finished testing BOP'S, pulled test plug, broke down & UD, drained stack, blew down choke manifold to cellar. R/D testing equipment. Received 3,401 gals of diesel for rig today.,lnstalled 9” wear ring, R/U Pollard E -line equip & tools. Replace inner cooler on draw work motor today, along w/ 4" Oteco valve MP #2., -Hauled 95 bbls Fluid to KGF G&I Cumulative: 8038 bbls -Hauled 5 bbis solids to KGF G&I Cumulative 2683 bbls -Daily downhole losses: 0 bbis Cumulative: 48 bbls -Daily metal: 2.5 lbs Cumulative: 1186.5 Ibis Conductor ann pressure -0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 5/29/2019 Rih w/ E -line Run #1 GR/CCL/CBL logging in and did not see 7" or 4-1/2" TOL Ta PBTD 16,487 WLM Lo u and Tie in w/ TOL 4-V2" 14,972' wlm Ion o cm TD depth of 16, 443' Sent log to town to confirm tie-in (ok) Pooh and rldn E- tine monitor well on trip tank w/ seepage Iosses,Stage bha on catwalk strap and tally (developed small leak in 1" hose on rig HPU do to chaffing and leaked less then 1 gal to rig containment clean up same) (monitor static well on trip tank @ .9 bph loss rate ),Rig service, grease traveling equipment inspect dwk brakes (Good),P/up bha #18 = Bull nose + 5- 1/4" sleeve pack -off + 3-112" IF DP pup + Nogo + tri point test ark w/ bypass + Xo = 25.34',Rih out of derrick f/ 25' t/4,250', P/U-35K S/0-32K,Lined up to pump, circulated @ 3 bpm due to seals on test packer, filled pipe & warmed up mud. GPM -128 SPP-80,RIH P/U singles F/4,250' -T/9,557', 3.2 this over calculated pipe displacement. PIU -135K S/0-125K,Crew change, held PJSM, cant. RIH P/U singles F19,55T-T110,146'. P/U-137K SIO -127K, Brought on pump to 3 bpm, filled pipe & warmed up mud. GPM -123 SPP-140,Cont. TIH out of derrick F110,146 to top of 7" liner @ 10,991', went right through 7' liner top w/ no issues, cont. TIH reducing trip speed to 60-70' a min inside 7" liner w/ test packer per Tripoint hand. RIH T/14,784', 300' above 4.5" liner top, lined up and started pumping @ 3 bpm, evening out MW's & warming mud.,Calculated pipe displacement total for the trip was 4.2 bbls over calculated.,Brakes on draw works started to get spongy per driller, called out rig foreman James Sweetsir, made decision to add 15 gals of glycol to reservoir tank and leave cap off tank to let pressure vent, original pressure was 21 psi, after removing cap pressure dropped to 15 psi. Cont. TIH brakes appeared to be better, and sponginess went away., -Hauled 0 bbls fluid to KGF G&I Cumulative: 8038 bbis -Hauled 0 bbis solids to KGF G&I Cumulative: 2683 bbls -Daily downhole losses: 0 bbls Cumulative: 48 bbls -Daily metal: 2.5 Iles Cumulative: 1186.5 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 5/30/2019 Continued pumping @ 3 bpm, evening out MW's & warming mud,Obtain parameters up/dn 184/175k set Prk @ 14,790' w/ 20k do wt r/ up TIW valve pump in sub w/ low torgue and 5' pup into TDS Pressure up V 1050 psi do pipe w/ 4.8 bbls and test prk and monitor pressure and chg out crew (good),Bleed off dp pressure V 390 psi P/up and open bypass w/ 6.75 of travel dump pressure w/ 1.4 bbls back and mark pipe slack off and re -close bypass w/ 20k do r/ up line to choke and fluid pack choke and gas buster and brk circ w/ 14 bbis pressure test line and do pipe V 1900 psi 15 min ok bleed 1:1350 psi p/up and open bypass,PJSM on pumping diesel tie m/p into vac trucks and pump 211 bbls of 6.7 ppg diesel do dp @ 3 bpm @ ICP 220 psi FCP @ 1824 psi wl total 211 bbis CBM 9.0 ppg returned,Attempt to close bypass did not take weight Re -set prk and close bag and apply 350 psi to to back side and monitor same Bleed do dp from 1832 psi V zero w/ 3.1 bbis retumed and monitored flow rate @ 1.5 bph & breathing shut in TIW,Remove TDS and r/up wire line and bump up pressure on back side V 605 psi,P/up Halliburton ABC bull nose capacitance temperature flow, Quartz pressure/collar locator, terminating bus, ACX -Leak detection receiver array/ Electronics , Xo Halliburton 1553 to ultra wire through tbg telemetry cartridge P/up inside Iubricator,Attempt test lubricator and chg out "O" ring X2 unable to test remove XO,Wait on replacement 4-1/2" IF X 3" bowen from pollard and chg out alternator on dwk mtr and service TDS generator,M/up new 4-1/2" IF X 3" bowen and pressure test lubricator to 2500 psi (ok) Bleed do trap 1000 psi and open TIW and equalize pressure @ 550 psi and continue monitoring back side pressure @ 620 psi,Rih w/ Halliburton ACX leak detection tool on Pollard E -line @ 200-220 fpm V 1,4,650', pressure on DP string built to 900 psi, bled off pressure .8 bbis, flow rate was 1.9 bph, BHT -189 BHP -4820 psi @ 14,650', flow rate slowed to .25 bph, cont. monitoring backside pressure -600 psi,Proceeded to RIH w/ E -line, flowing well, 18' per/min T/15,350% logging down, seen a small indication of noise at 4.5' liner top, POOH '115,350% logging up T/14,000', @ 18' per/min, seen smaller indication of noise on the up pass, but flow had diminished to .19 bbis per/hr. RIH @ 18' per/min T/15,107', Backside pressure=600 psi,Parked ACX tool @ 15,107', monitored flow rate, average flow rate .1 bph, backside pressure=580, installed 1000 psi gauge on E -line manifold & close in string at low torque valve, monitored pressure for 2 firs on gauge, with no increase in DP pressure.,R/U testing equip, started pressuring up casing to packer @ 14,790', seen hesitation in pressure build @ 1300 psi to 1550 psi, then pressure cont, to build to 2090 psi, seen pressure drop to 1450 psi while topping off test pump tank., monitored backside pressure on chart for an hour, pressure cont. to drop to 1325 psi,Made decision to POOH w/ E -line F/15,107', while cont. to monitor well pressures. 5/31/2019 Continue R/dn Pollard E-Iine,R/dn 2" hose and low torque valve and Wup TIW and pump in sub & pup it, found 4" MP isolation valve bad waiting on rig foreman to bring one.,Observed string to be low of diesel topped off dp w/ +-3 bbs of diesel and monitored string for losses (none),Bled annulus pressure back to original pressure before attempting csg test (550 psi) seen 2.2 bbls on bleed back (leaving 3 bbls shy of initial volume) Pump do annulus w/ mud pump and attempt to duplicate test #1 w/ 9 bbis V 550 psi V 2650 psi pressure bled do to 2100 psi in 40 min, Discussed options w/ town and Bump up pressure w/ test pump and 2.2 bbis water V 2100 psi V 2650 psi( seen 50 psi pressure loss in 35 min Test#3 ),R/up HP lines and test V 2200 psi to U -Tube out diesel thru choke and gas buster & applied 1650 psi to drill pipe, r/up LP hose from mud tank to annulus & sucked obm out of gas buster, changed out 4" isolation valve of MP #2,Crew change, held PJSM on u -tubing diesel OOH. P/up 9.25' and released or open by-pass w/ no psi change on work string, moved up and do wl free travel. Start to bleed off dp thru choke and gas buster & open mud tank to annulus, continued to bleed off dp and u -tube diesel out of hole monitoring BBUin/BBUout, @ 195 bbls of OBM U -tubed around, well balance out„line up and reversed circ. through open choke, GPM -91 SPP=0-228 psi, until we had 8.8+ CBM mud to surface, had 51 bbls of interface -Closed TIW, blew back 2" mud line, choke, & Kelley, R/D & removed 2" circ. hose/valve, worked string up/down, working packer free.,TIH F/14,790' -T/14,976', stabbed into 4.5" liner seals, set down 10K on nogo sub. R/U up test pump/chart recorder, prep for 4.5" liner test & back side 7' & 9-5/8 casing test.,Test #4, pressured up backside to 500 psi, shut in backside, lined up & pumped down DP, pumped wing pump to 2300 psi, used test pump to pressure up to 2650 psi, shut in DP, pressure slowly bleed down, bumped pressure back up one time, pressure held @ 2600 psi for 30 min on chart inside 4.5" liner (Good), pumped 5.6 bbls and bleed back 5.1 bbls.,Test #5, trapped 500 psi on DP string, shut in DP, lined up to pressure test down backside against 4.5" liner top to 2650 psi wl mud pump, had to bump pressure up two time, held 2600 psi on chart for 30 min (Good), pumped 12.4 bbis and bleed back 12.8 bbls.,TOOH F/14,976' -T/11,060', L/D one it & P/U 15' pup, M/U TIW, pump in sub, & 5' pup to TD, to displace DP to diesel. P/U- 195K S/0-185K,Set packer @ 11,042' in the middle of first it below hanger & packer assembly, applied 990 psi down DP to packer, verify packer was set, bleed pressure down to 310 psi, P/U to 135K pressure dropped off to 0 psi, confirmed by-pass was in open position. P/U-139K S/O-141 K,Lined up pump, displaced DP to diesel @ 3 bpm, 151 bbls total pumped, GPM -127 Final SPP -1347 psi, shut down pumps, slacked of to 115K, shut by-pass, had 1224 psi shut in DP, pressured up back side 480 psi, equalized pressure was 1322 psi, opened flow back line to trip tank, bleed of DP pressure to 0 psi, got back 3.7 bbis on inftial,bleed off, flow check, well was initially flowing @ .9 bbls per/hr, steadily dropped off to .2 bbls per/hr over, monitored well for 2.5 hrs. Gained 1 bbis from .9 to .2. 6/1/2019 Shut in drill pipe and monitor for build up. No pressure increase seen,R/up HP lines to choke and test V 1750 psi and R/up low pressure lines to annulus. Apply 1350 psi to DP and open bypass,U-tube Diesel from DP through choke to cutting box seen 135 bbls to vac trk, Monitoring bbl/in and bbl/out. Before going to mud pump and taking returns to pits. continue circ thru choke until 8.8 ppg was seen coming out wl 58 bbis interface (capture same and dust back up to 9.Oppg obm,open annular and work pipe an confirm prk is released close TIW and blow do line and r/dn same,Close Pipe rams and use MP preform csg test and pressure up one time w/ test pump V 2500 psi w/ 15.6 bbis pumped on chart for 30 min test #6 bleed w/ 12.5 bbis back,Brk/out I/dn 5' pup, Pump in sub and TIW valve along w/ 15' space out pup,Chk flow ok Pooh racking back 11060' V 9496' rotating breaks coming out,Continue pooh Ildn dp f/ 9496' V 8535',Hole fill cal =16.8 bbl, Measured = 14.3 bbls Diff. = 2.5 bbl under preform flow chk 10 min flow check =2.5 bbis Gain, flow rate of 8.4 bph shut in well @ 15:06 firs monitor pressures Stabilized SIDPP = 366 psi, SICP = 450 psi,Held PJSM, circ out kick w/ first step of drillers method @ 17:09 his, staged pumps to 4 bpm, while holding SICP constant at 400 psi, swap and hold SIDPP constant @ 600 psi through circ.,Cont. holding SIDPP constant @ 600 psi, while circ. out kick, max gas at BU was 109 units, lowest mud weight seen was 8.8+, w/ no change in color/water of mud at BU.,Shut down pumps, shut in well & monitored pressure, SIDPP built to 377 psi, SICP built to 412 psi, in one hours time. Called town and decision was made to TIH to top of 4.5" liner and circulate to even out MW to 9.0 ppg,Bleed off casing pressure through choke, both casing & DP pressures bleed to 0 psi, opened rams, Broke & UD 15' pup and TIW, initial volume bled off was 2.3 bbls, flow on back side slowed to from 7 bbis per/hr to .32 bbls per/hr after watching it for 10 min.,TIH F/8,535' - T/11,199', screwing into each std to prevent flowing out of top of DP, went through 7" liner top @ 10,991' w/ no issues. P/U-145K S1O-140K, pipe displacement was 13.3 bbls under calculate @ 11,199',Crew change, held PJSM, cont. TIH Fit 1,199'-T/14,946. calculated hole fill was 36.8 bbis under, flow check, well flowing @ 1.2 bbis/hr.,Stab TIW & 15' pup , shut in and monitored well for pressure build on choke. SIDPP=92 psi SICP=163 psi, -Hauled 0 bbls fluid to KGF G&I Cumulative: 8118 bbls -Hauled 0 bbls solids to KGF G&I Cumulative: 2683 bible -Daily downhole losses: 0 bbis Cumulative: 48 bbis -Daily metal: 0 lbs Cumulative: 1186.5 lbs Conductor arm pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 6/2/2019 Continue monitor well pressures SIDPP = 210 psi and SICP = 279 psi, PJSM Circ out influx using first step of the drillers method hold Csg psi @279 psi while starting pumps once @ Kill Rate Speed @ 4 bpm swap to Drill pipe @ 675 psi hold this constant through out Lowest MW seen was 8.7+, ES =400 -1200, Retort = 21 % water Max gas 1303 units at trim /up w/ 7.5 bbl gain,Continue circ through choke @ 4 bpm @ 675 psi monitoring gas f/ 1303 units V 395-430 units 9.0 PPG in w/ 8.9+ppg out,Shut do and shut in monitor pressures, Stabilized pressure was SIDPP=440 psi SICP=443 psi while weighting up active system V 9.5 ppg„Performed second step of drillers method, staged pump up to 4 bpm, holding SICP constant SICP=540, once 9.5 ppg was at the bit. ICP=1002 w/100 psi safety factor, FCP=615 W/73 psi safety factor, max gas 461 units.,Finished second step, had 9.5 ppg all the way around, shut in & monitored well pressure, shut in gas was 146 units, pressure built & stabilized @ SIDPP=126 SICP=82, weighted up active system to 9.9+ ppg., Performed second step of drillers method, staged pump up to 4 bpm, holding SICP constant SICP=200, w/116 psi safety factor once, 9.9+ ppg was at the bit, ICF -740 w/100 psi safety factor, FCP=451 W/113 psi safety factor, max gas 137 units. Had 82 units of gas prior to shutting down the pump.,Shut down & shut in well, pressure stabilized @ 0 psi, watched for pressure build for 30 min, SIDPP=O psi SICP--O psi„Opened up well, flow check for 15 min, well was static, blew down choke manifold & vac out gas buster, filled trip tank & prep to POOH. pumped 20 bbis dry job 2 lbs over MW.,Started TOOH F/14,944' to current depth of 12,288', w/ correct calculated hole fill., -Hauled 0 bbls fluid to KGF G&I Cumulative: 8118 bbis -Hauled 0 bbis solids to KGF G&I Cumulative: 2683 bbls -Daily downhole losses: 0 bbis Cumulative: 48 bbls -Daily metal: O lbs Cumulative: 1186.5 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 6/3/2019 Continue pooh on single f/ 12,288 V 9,494' 1.4 bbls over calculated,Circ surface to surface to clear dry job chk mud weights @ 10.0 ppg in and out w/ back ground gas @ 66- 46 units,Flow chk well out of balance flowing out dip slightly stab and shut TIW and monitor on trip tank and Hang Blocks,PJSM slip cut 109' drill line tested COM (good) re -cal hook load and height, Brk circ and warm mud and attempt to balance string to prevent u -tube from stump and pump dry job,Pooh I/dn singles f/ 9494' U 5463' vacuuming foot balls thru pipe and cleaning od AAO running 3 hands short due to company UA, Covered positions for remaining tour with service personnel, three hands were escorted off location by AAO Safety,POOH standing back stands in derrick f/ 5463' U 26,L/D BHA Clear floor,Pull wear ring Set test plug fill lines and stack with water,Test BOP Components used in well control, VBR, Choke HCR, TIW V 250/4000 psi f/ 5 min low 10 min high, Test super choke V 1500 psi verify holds pressure and restricts flow,Blow down lines pull test pull R/D test Equipment set wear ring,M/U 9 5/8” Test Packer BHA #19 RIH,RIH f/ 27' V 2501' fluid running over pipe,Fill pipe, break circulation 3 bpm 120 psi 850 stks DP Volume,Continue RIH screwing into every stand f/ 2501' V 4,930', -Hauled 90 bbis fluid to KGF G&I Cumulative: 8208 bbls -Hauled 10 bbls solids to KGF G&I Cumulative: 2693 bbis -Daily downhole losses: 0 bbls Cumulative: 48 bbls -Daily metal: O lbs Cumulative: 1186.5 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 6/412019 Kelly up and pump pipe volume and warm mud at 4998', 168 gpm-170 psi, pumped total 71 bbls.,Continue RIH screwing into every stand f/4998' V 5300' Continue RIH on elevators slow and able to keep it from flowing over f/ 5300' V 7500'. Up wt 107K, dwn wt 109K.,Kelly up and pump pipe volume and warm mud at 7509, 168 gpm-225 psi, pumped total 107 bbls.,Continue RIH slow from 7500' to 10,368' (7” finer top at 10,991'). Calc pipe displacement = 78.6 bbis, actual pipe displacement = 75.7 bbis. Up wt 138K, dwn wt 140K., MU 5' pup jnt, pump in sub and TIW on stump, MU topdrive. Set Tri -Point test packer as per Tri -Point Rep: 4 turns to right, pressured up to 1000 psi with rig pump, bled off to +/- 300 psi, PU 3' to open by-pass, saw fluid movement in wellbore and then pressure drop to 0 psi on drill string.,Circ at 168 gpm-325 psi while holding PJSM with rig team and Peak drivers on pumping diesel down DP. Down pump #1.,Lined up two vac trucks of diesel on pump #2, pumped 146 bbis diesel (3128 strokes) down drill string at 128 gpm. Final circ pressure = 1935 psi against 10.1 ppg OBM on backside.,S/O on drill string from 138K to 110K and closed bypass on test packer. Seeing 1856 psi on stand pipe. Closed TIW, upper rams and choke HCR. Bled off pressure on mud line via pump bleeder. Closed 4" standpipe valve. Lined up rig pump to 9 5/8" annulus, rolled pump #1 and pressured up to 550 psi on backside.,Down pump #1, opened 4" stand pipe valve, rolled pump #1 and pressured up on top of TIW to 1630 psi to equalize above/below, to allow opening of TIW. Opened TIW valve, seeing 1935 psi on standpipe gauge, 500 on backside. Attempted to bleed off drill string. Appears well flowing at 13 to 15 bph. Bled off a,total 5.7 bbls then shut in drill string to monitor pressure build. Called out Pollard a -line and Halliburton TMD3D tool Rep.,Pressure built to 1650 psi over 2.5 hours. Spotted Pollard unit at 16:30 hrs, closed TIW valve on stump and bled off surface equipment, broke off pump in sub, 5' pup and topdrive. Staged lubricator sections and sheaves on catwalk.,RU Pollard equipment (XO's, pump in sub, lubricator, sheave), MU Halliburton tool string, RU 2" HP hose to choke manifold from pump in sub, test all connections and lubricator to 2500 psi with rig test pump, bleed down to 1650 open TIW equalize pressure 1675 psi,RIH w/ Eline V 10680' SIDDP increased V 1792 psi open well begin to flow bleed off until static pressure of 680 psi begin logging while well flowing make pass across liner top V 11150' detect leak @ 11020' +1- make correlation pass verify depth of leak, take static logs in 10' increments f/ 11 050' U 10890' Shut in well AVG flow rate It well 29.6 bph,RIH w/ Eline V 16180'tag upon unable to get deeper suspect fill, POOH V 15050' SIDDP 1219 psi open well begin to flow log 4.5" Liner top no indication of leak, POOH w/ Eline Close TIW bleed off 1092 psi R/D Eline lubricator and side entry sub, M/U side entry sub to pup and TIW M/U surface lines V perform injectivity test.,Equalize drill string, 1100 psi pressure upon drill string w/ test pump .25 bpm t/2650 psi pumped 4.25 bbls pumped, monitor pressure f/ bleed off lost 150 psi in 20 min, Bleed off and R/D test equipment,R/U to displace diesel out of drill string, bleed off 600 psi off back side, PIU and open bypass Line up to U -Tube diesel through choke, Circulate and condition mud until MW balanced 10.1 ppg in and out, - Hauled 0 bbis fluid to KGF G&I Cumulative: 8208 bbls -Hauled 0 bbis solids to KGF G&I Cumulative: 2693 bbis -Daily downhole losses: 0 bbis Cumulative: 48 bbis -Daily metal: 0 IN Cumulative: 1186.5 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 6/5/2019 Cont to reverse circ out any water/gas with end of drill string parked at 10,638', 140 gpm-415 psi, taking returns through full open choke and poorboy degasser, max gas 1786 units. Dumped 55 bbis trash fluid, kept 80 bbls for treatment and re -use. Shut down, bled off and flow check = static.,Opened annular, released Tri -Point test packer as per packer Rep. TIH from 10,638' to 11,012' where we tagged No -Go sub on 7" liner top. MU topdrive, applied 500 psi down drill string to confirm we had seals properly set in SBR. Good test., Bled off, broke off topdrive, MU TIW, pump in sub w2" hose to choke manifold, and 5' pup jnt to stump, MU topdrive. PU 11' to clear seals from SBR. Closed annular and reversed out remaining water/gas, taking returns through full open choke and poorboy degasser. Had a max of 1903 units with water to surface. Dumped 28 bbls water contaminated fluid., Held PJSM with rig team on filling drill string with diesel. Lined up vac trucks to pump #2 and pumped 151 bbls diesel down drill string, 130 gpm, final circ pressure 1790 psi against 10.1 ppg OBM on backside. Shut down pump, cracked bleeder and SIO landing seal assembly in SBR -Lined up rig pump on 9 5/8" annulus, closed upper rams and pressured up to 2650 for 30 min on chart. Pressure dropped to 2500 psi over 30 min. Bumped pressure back up to 2650 psi and held another 30 min. Pressure dropped to 2600 over 30 min. Rebuilt 4" valve on pump #1 while monitoring pressure build on drill string (1595 psi to 1658 psi).,Closed in annulus with psi gauge to monitor any pressure change, RU test pump to pump in sub on drill string. Could not use rig pump due to 1650 psi already on drill string. Pumped down drill string with lest pump to see if we could achieve any kind of injectivity. At 3646 psi on drillstring, decision made to call out,Halliburton cementers for use of their pump truck rather than rig test pump. At this time test pump failed to pump.,Bled drill string back to 1650 psi, tore down test pump. Found broken valve assembly. Continue monitoring annulus pressure (has dropped to 2550 psi) and cleaning rig floor. Halliburton pump truck on location at 18:00 hm.,Spot pump truck, load diesel on vac truck from tank farm and staged truck at pump unit. RU hardline to rig floor and tied into pump in sub on drill string, pressure up on back side f/ 2500 psi to 2650 psi, Halliburton attempt to PT lines found bad valve on pump truck replace,PT lines U 5000 psi, perform injectivity test staging pump pressure V 1800 t/ 4750 psi staging up in 500 psi increments took 1.5 bbls to increase 500 psi every time, hold 4750 psi on DP f/ 1 hr lost 250 psi in hr, bleed down U 600 psi 10.5 bbis bled back, shut in well.,Bleed off 2650psi on back side, blow down and RID Halliburton, Hook up lines U choke to U -Tube diesel through gas buster , R/U U-tube Lines in cellar, P/U and unsting from seals, U-tube Diesel through choke U gas buster, Circulate 141 gpm 390 psi to balance out MW 10.1 ppg in and out treat mud while circulating, Flow check well blow down choke lines suck out gas buster, Pump Dry job,POOH f/ 10980't/ 8000', -Hauled 68 bbls fluid to KGF G&I Cumulative: 8276 bbis -Hauled 7 bbls solids to KGF G&I Cumulative: 2700 bbls -Daily downhole losses: 0 bbis Cumulative: 48 bbls -Daily metal: 0lbs Cumulative: 1186.5 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 6/6/2019 Cont POOH from 8000'to surface with Tri -Point test packer and Baker seal assembly. Calculated hole fill = 82 bbls, actual hole fill = 82.9 bbis. Both seals and packer in good shape.,Closed blind rams. Cleaned and cleared rig floor. Cleaned BOP stack for ND of MPD head and orbit valves. Blew down topdrive to mud pumps to remove any fluids. Vac'd out poorboy degasser Iine.,Remove MPD hardlines from orbit valves, removed trip nipple and drip pan, removed 6" flowline, removed MPD sensor from mud line and installed 1502 bull plug, removed 4" and 6" orbit valves, removed MPD head from top of BOP stack, removed 2" hardware from annulus valve, removed MPD hardware from poorboy degasser line. Pressure washed all items for shipping. Mechanic working on glycol sensor and drive Iine.,Make up riser and drip pan, install flow lines and hole fill line, clean and clear cellar, Load and strap 2 718" work string.,R/U Weatherford, Break crossovers off scrapem.,M/U Clean Out BHA RI PIU 50 its of 2 7/8" SLH90 work string t/ 1522', M/U cross over RIH on 4.5" Dip U 7100', -Hauled 75 bbls fluid to KGF G&I Cumulative: 8351 bbis -Hauled 10 bbls solids to KGF G&I Cumulative: 2710 bbis -Daily downhole losses: 0 bbis Cumulative: 48 bbis -Daily metal: 0lbs Cumulative: 1186.5 lbs Conductor ann pressure- 0 psi 3-3/8 X 9-5/8 ann Pressure - 0 ps' 6/7/2019 With bit at 7100' MU topdrive and circ at 185 gpm-825 psi while holding PJSM on PU singles.,Single in hole 130 jnts 4 1/2" DP from 7100' to 11,056'.,Cont TIH from derrick, from 11,056' to 14,891'.,At 14,891' and just above 4 1/2" liner, MU topdrive and CBU one time. 200 gpm-1143 psi. Had a max of 171 units at bottoms up. BGG 56 unks.,Cont TIH from 14,891' to 15,890' on elevators, saw nothing entering 4 1/2" liner top. At 15,142' obtained parameters as follows: Up wt 184K, dwn wt 176K, 30 rpm = 3165 flAbs, 40 rpm = 3140 fUlbs, 50 rpm = 3280 fUlbs,Washed and reamed down from 15,890' to top of wiper plugs at 16,470'. 178 gpm-1449 psi, 40 rpm -3360 ft/lbs torque (topdrive torque set at 5000 ft/lbs).,Ddlled up wiper plugs and landing collar from 16,470' to 16,473', 199 gpm-1932 psi, 50 rpm -3900 to 4300 fl/fibs, on bott torque. Seeing no wt on bit, drill cement t/ 16512',Circulate bottoms up while conditioning mud 210 gpm 1900 psi 50 rpm 3500 tq, flow check well static, Pump dry job,POOH f/ 16508' U 11864', -Hauled 0 bbis fluid to KGF G&I Cumulative: 8351 bbis -Hauled 0 bbls solids to KGF G&I Cumulative: 2710 bbls -Daily downhole losses: 0 bbis Cumulative: 48 bbis -Daily metal: 0 lbs Cumulative: 1186.5 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 6/8/2019 Cont POOH with tapered cleanout string from 11,864' to 11,053' racking back in demck.,POOH UD 130 jnts 4 1/2" DP from 11,053' to 7022'.,Cut and slip 90' drill line, adjust kick back rollers on draw works, checked crown saver, calibrate block height and hook load, grease blocks, topdrive, crown and blocks, inspect driveline -Cont POOH from 7022' to the 2 7/8" workstring at 1556', racking back in derrick., RU Weatherford tongs, elevators and slips for UD of workstring.,Cont POOH UD 2 7/8" SLH-90 workstring from 1556'to surface. Broke off XO and bit sub. The re -run 3.75" bit in decent shape, has a couple small chips in carbide blades.,RD Weatherford equipment, closed blinds.,Clean and clear rig floor, clean cellar and walk ways, EAM's and maintenance,Continue Cleaning and maintenance, EAM's and work orders, change out 3" PTO line., -Hauled 52 bbls fluid to KGF G&I Cumulative: 8403 bbls -Hauled 3 bbls solids to KGF G&I Cumulative: 2713 bible -Daily downhole losses: 0 bbls Cumulative: 48 bbls -Daily metal: 0 lbs Cumulative: 1186.5 lbs Conductor arm pressure- 0 psi 13-318 X 9-5/8 arm pressure - 0 psi 6/9/2019 Continued working on PM's until Pollard's arrival at 07:00. Cut 5' mule shoe from an old jnt 2 7/8", racked and tallied 10 jnts 2 7/8" 8 rnd tubing.,Spotted a -line unit and RU. RIH with composite bridge plug and using collar locator set bridge plug 84' below leaking pup jnt at 11,094' (11,105' on 7" run tally). PU with a loss of 100 lbs up weight, SO and tagged bridge plug, POOH RD and released Pollard e-llne.,RU 2 7/8" handling equipment., PU RIH with 10 jnts 2 718" EUE 8 rnd tubing and mule shoe, MU XO, C/O elevators to 4 1/2", PU Tripoint packer with 4 1/2" pup on top and MU on stump, LD pup jnt and MU XO. Total BHA length = 336.60', Total tubing tail below packer = 323'.,Cont TIH from 336' on 4 1/2" DP from derrick to 11,110' Tag Composite bridge plug, Space out M/U Circulating equipment.,Circulate and condition mud while waiting for Halliburton pump truck 210 gpm-510 psi. Held PJSM on RU and run hoses to feed pump truck. RU to rig floor to pump in sub and TIW.,R/U Halliburton pump truck and lines, spot in diesel truck and chemical totes.,Pump 5 bbls diesel to fill lines, PT Lines at 1000 low, 3000 high, Pump remaining 25 bola diesel w/ Halliburton, dropped nert ball, Mixed and batch up Well Lock epoxy and pumped 10 bbls, dropped nert ball, pumped 7.5 bbls diesel, then spotted Well lock epoxy w/ 145 bbls OBM from pump truck.,Shut down pump truck, broke off topdrive and circ head, POOH slowly racking back 7 stands in demck t/ 1067T.,M/U Circ head, set packer as per Tri -Point Rep, then pressured up on DP 11700 psi. Pressure bled to 600 psi over 5 minutes. Bumped pressure up to 700 psi, pressure dropped to 634 psi over 20 minutes., -Hauled 0 bbls fluid to KGF G&I Cumulative: 8403 bbls n -Hauled 0 bbls solids to KGF G&I Cumulative: 2713 bols -Daily downhole losses: 0 bbls Cumulative: 48 bbls -Daily metal: 0 lbs k v,-, Cumulative: 1186.5lbs � ,o 0 Conductor arm pressure- 0 psi 1 1 13-3/8 X 9-5/8 arm pressure - 0 psi 6/10/2019 Cont holding squeeze pressure of 634 psi on drill string against Tri -Point packer (pressure initially dropped from 700 to 600 over 5 min, bumped up to 700 and dropped to 634 over 20 min). Pressure slowly increased from 634 to a max of 663 over 3.5 hours., Had Halliburton pump truck prep their 8 bbls of solvent on the pump truck. Bled off drill string and had no flow. Straight pulled on packer to release/open by-pass and seeing 4K over our original 120K up wt. Tried to slack off to verify packer released but string stacked out immediately. Cont pulling up hole to the point,We had to LD top single, could not slack off. Tri -Point Rep had Driller rotate right one round and attempt to pull/slack off with no change. Made numerous attempts to pull up hole rotating left, rotate left in neutral and with weight on packer. No change. Lined up on rig pump and we are able to circ through by-pass with no problem.,Pulled solvent off pump truck with Peak vac truck, tied vac truck in to pump 92 suction, pumped 8 bbls solvent down OP then swapped to OBM and cont circ surface to surface at 3 bpm -174 psi initial. After 35 min pump pressure dropped to 60 psi. Up to 172 at bottoms up. Did not attempt to work string or packer,while circulating (chance of closing by-pass). Halliburton cleaned up pump truck and left location at 13:00 hrs. Received 10,000 gals wellbore diesel into tank farm on pad 3. Final circ pressure at surface to surface 174 psi. Shut down and flow check = static,Pulled one stand and racked back. Put two rounds to right in packer and straight pulled to release, would not release. Pulled 5 more stands and attempt to release, would not release. Pumped dryjob and resumed POOH from 10,256'. Up wt 125K, made another attempt to slack off once insude 47# casing with no luck, UD Test Packer and tubing.,Clean and clear rig floor, P/U BHA components, Bit and bit sub,M/U Bit and bit sub, RIH on 4.5" DP U 9300', -Hauled 95 bbls fluid to KGF G&I Cumulative: 8498 bols -Hauled 5 bbls solids to KGF G&I Cumulative: 2718 bible -Daily downhole losses: 0 bbls Cumulative: 48 bbls -Daily metal: 0 lbs Cumulative: 1186.5 lbs Conductor arm pressure- 0 psi 13-3/8 X 9-5/8 arm pressure - 0 psi 6/1112019 Cont TIH with 6" roller cone bit for epoxy plug drill out, from 9300' to 10,859'. Top of plug calculated to beat 10,911'. Calculated displacement= 80 bbis, actual displacement = 78 bbls.,MU topdrive at 10,859' and broke circ to fill up pipe and warm up mud. With pump at idle, no rotation, ease down and tagged top of epoxy plug at 10,928' with 10K twice. Up wt 132K, dwn wt 133K.,PU, increased pump rate to 180 gpm-275 psi, 45 rpm-1780 ft/lbs, eased down and began drilling plug with 500 to 1000K wob to establish bit pattern. Increased to 50-2000 fUlbs and 60-2180 ft/lbs rpm and 5K wob, 187 gpm-335 psi. Making 18 ft/hr ROP. Drilled from 10,928' to 11,010' then had a pump pressure spike. Driller PU off bottom and string stalled at 6500 ft/lbs.,At initial bottoms up we saw thin strips of epoxy on shakers, like stringers peeled off casing wall, then cuttings turned into very small particles much like sawdust.,lncreased topdrive torque to 10K, still able to circulate, worked string from 120K to 170K a dozen times then parked at 133K. Made attempt to rotate a couple times and string came free.,At 204 gpm-529 to 762 psi, 110 rpm-2000 it/lbs torque started inching our way back up hole, able to get a foot at a time, able to increase to 400 gpm-1809 psi. worked up to 10,987' and held there for a bottoms up. Saw no increase in cuttings at bottoms up, if anything tapered off. Racked back one stand and cont, backreaming slowly up hole. At 10,953' hole packed off again, pressure spiked and string stalled. Worked string loose with 110 rpm rotary, no pump, and able to pull up above top of plug parking at 10,925'. Resumed pumping and rotating.,At 10,925' 380 gpm-1404 psi, 110 rpm-1590 ft/lbs torque, circulated a bit above epoxy plug, things looking good. Washed/reamed down slowly to 10,958' and started seeing pressure spike. Pulled back up hole to 10,925', gave it a few minutes then washed reamed slowly back down to 10,953' where pump pressure started,to increase and torque started to increase. Downed pumps while pulling back up hole, string stalled at 10,938' and then overpulled to 170K (normal up wt 133K). Eased into pump and able to circulate no problem, worked string a dozen times from 100K to 220K, made numerous attempts to rotate. String finally,came free and we pulled last 10' up out of plug and began rotating 110 rpm-pumping 389 gpm,Pumped 38 bbl hi-vis sweep around at 10,925', 390 gpm-1419 psi, 110 rpm-1700 Nlbs. Had some good sized chunks of epoxy, like gravel on shakers, as well as long thin skin material. Could be knocking some stuff off the casing walls and it's falling in on top of us. So no increase in material with sweep to surface.,Resumed washing/reaming down from 10,925' slowly. Go too fast and pressure starts climbing with some occasional torque increase. Flow pretty stable but pump pressure up and down. 390 gpm-1778 psi, 110 rpm-2950 ft/Ibs torque. Wash down U 10,939' observed pack off and torque spike, P/U Hung up and stalled out, over pulling 100k work string free, Establish circ and rotary, pull up U 10,897%Circulate bottoms up, Pump dry job, POOH U 10,740',Top drive Leak observed Electric over hydraulic valve leaking change out, Extend ram hose leaking replace hose„POOH f/ 10,740't/ 4300',- Hauled 95 bbls fluid to KGF G&I Cumulative: 8593 bbis -Hauled 5 bbis solids to KGF G&I Cumulative: 2723 bbis -Daily downhole losses: 0 bbis Cumulative: 48 bbis -Daily metal: 0 lbs Cumulative: 1186.5 lbs Conductor ann pressure- 0 psi 13-318 X 9-5/8 ann pressure - 0 psi 611212019 Cont POOH with 6” bit from 4300' to surface. BR in good shape, no sign of epoxy balling. Broke off bit.,Clean and clear rig floor. PU 41/2" test jnt, drained stack and pulled wear ring., set test plug, RU to test SOPE.,Flooded surface lines and stack, purged air and obtained shell test.,Tested all BOPE at 250 low, 4000 high for 5 min each on chart. 250/2500 on annular. Tested with both 4 1/2" and 2 718" test joints. Performed drawdown test. Witness was waived by both BLM and AOGCC on 6-11-19. Total Safety calibrated and tested gas alarm equipmenl.,R/D Test equipment, Blow down lines, Pull Test plug, set wear ring,WU 8.375" Bit, Bit Sub and Cross over RIH,Trip in the hole t/3868',Break circulation 134 gpm 155 psi, fill pipe, change roughneck dies,Continue RIH f/ 3868't/ 5943',-Hauled 0 bbls fluid to KGF G&I Cumulative: 8593 bbls -Hauled 0 bbis solids to KGF G&I Cumulative: 2723 bbls -Daily downhole losses: 0 bbis Cumulative: 48 bbls -Daily metal: 0 lbs Cumulative: 1186.5 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann Pressure - 0 ps' 6/13/2019 RIH to 5943' and Eaton brake would not release. Parked string there and troubleshot Eaton brake issue with the help of Rig Super and Rig Foreman. Found Rexroth brand dump valve (sneezer) under Drillers console was leaking air through diaphragm, pressuring up on backside of diaphragm and not allowing Eaton brake release. Resolved issue-Cont TI from 5943' to 10,887' with no further Eaton brake issue. MU topdrive and filled pipe at 8446' and 10,88T.,Circ at 386 gpm-1578 psi, 60 rpm-2000 fUlbs off bott torque. Up wt 136K, dwn wt 140K, rot wt 138K. Eased down and saw first sign of epoxy material at 10,888' with slight increase in torque spikes. Cant washing/reaming down slowly from 10,888', with a max of 2K wob, 1700 to 4000 ft/lbs torque. 7000 strokes into circulating started seeing,l-2 inch by 112 inch thick broken up pieces of epoxy material. At bottoms up still getting the bigger pieces but with considerable more fine material. Washed/reamed down to 10991" (top of 7" liner) at +1- 15 ft/hr.,Circulate Bottoms up at 386gpm-1530 psi, 60 rpm-1400 ft/lbs torque to clean up hole. Flow check well Static, pumped dry job., POOH f/ 10988' U 8192%Service rig draworks, driveline and brake linkage, crown sheaves and iron roughneck, POOH f/ 8192' U 3950', hole took correct fill,Slip and cut drilling Iine,Continue POOH f/ 3950' U Surface, UD BHA, Clean and clear rig floor,M/U BHA RIH w/ 6" Drilling Assy. @ 744',-Hauled 18 bbls fluid to KGF G&I Cumulative: 8611 bbis -Hauled 2 bbis solids to KGF G&I Cumulative: 27251bbls -Daily downhole losses: 0 bbis Cumulative: 48 bbis -Daily metal: 0 lbs Cumulative: 1186.5 lbs Conductor ann pressure- 0 psi 6/14/2019 Cont TIH with 6" bit from 744' to 10,928'.,MU topdrive, filled pipe, obtained pumping/rotating parameters at 30 rpm. Up wt 146K, dwn wt 149K, rot wt 144K. 379 gpm-1362 psi, 30 rpm -1580 ft/lbs torque. Eased down into 7" liner at 30 rpm then increased to 40 rpm -1460 ft/lbs, saw first increase in torque and wt on bit at 10,998', increased to 60 rpm -1650 ft/lbs.,cont to wash/ream down slowly with no issue to 11,019, then resumed drilling out epoxy, from 11,010' to 11,050', web 2-51K, 383 gpm-1433 psi, 60 rpm -2250 to 2492 fl/Ibs.,Pumped 30 bbl hi -vis sweep around at 383 gpm-1250 psi, 30 rpm -1236 fillies torque. As sweep left bit we pulled up hole and out of T' liner slowly and parked at 10,990'. Had no increase in epoxy cuttings with sweep to surface. Performed flow check (static), pumped dry job.,POOH from 10,990' to surface, LD 6" bit and bit sub.,Clean and clear rig floor, strap BHA P/U components to rig floor,M/U BHA 2 7/8" Mule shoe, 6 jts 2 7/8" tubing Cross over and test packer 210.33',RIH w/ Test Packer f/ 210't/ 6050', -Hauled 0 bbls fluid to KGF G&I Cumulative: 8611 bbls -Hauled 0 bbls solids to KGF G&I Cumulative: 2725bbls -Daily downhole losses: 0 bbls Cumulative: 48 bbls -Daily metal: 0lbs Cumulative: 1186.5 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 6/15/2019 Cont TIH from 6050' to 11,010' muleshoe depth, test packer at 10,802'. No issue entering 7" liner with 2 7/8" mule shoe.,MU circ assembly on stump consisting of TIW, pump in sub and 5' pup jnt, MU topdrive, installed low torque valves and 2" bleeder hose to flow line. Set test packer as per Tri -Point Rep, 4 turns to right and SIO 18K, packer set. Lined up pump #1, pressured up on drill string to 623 psi, no flow on backside, bled to 300 psi,Pulled up hole 4' on drill string until we saw fluid move in wellbore and psi drop to zero, verifying bypass on packer is open.,With pump #1 circulated long way at 2.7 bem-67 psi and held PJSM with rig team on displacing drill string to diesel. Shut down pump 91, lined up diesel vac trucks on pump #2, pumped 155 bbls diesel down string, shut down pump. Initial circ psi = 86 psi, final circ psi = 1906 psi.,S/O and closed bypass on packer, from 142K to 118K, closed TIW on stump, closed upper rams and choke HCR. Peak then took excess diesel and pre -loaded poorboy degasser vessel with 14 bbls. With pump #1 lined up on kill line (stand pipe valve closed) and pressured up on annulus to 475 psi and closed kill HCR. Have gauge on annulus to monitor backside.,Opened standpipe valve, pressured up on top of TIW to equalize pressure above/below, opened TIW. Closed ISOP. Opened low torque valve on pump in sub and bled off 3 bbls to trip tank from drill string, then flow dropped to a trickle. Flow cont to taper off to little or nothing over 2 hours. Gained .8 bols over 2 hours. Notified Drilling Manager.,Bled off annulus to zero, removed bleeder hose on pump in sub, installed 2" HP hose from pump in sub to choke manifold valve 911. RU 3" camlock hose from pit #9 to annulus valve to u -tube 10.1 ppg OBM into annulus. PU on drill string 6" to open bypass. Opened auto choke and started u -tube diesel out of drill string through choke and poorboy degasser until 0 psi., PU on drillstring 4' and unseated packer. S/O and packer was released. Closed annular and reverse circulated any remaining diesel out of drillstring at 94 gpm-175 psi taking diesel returns into pits 1-2 when we saw 7.2 ppg at surface. Had choke wide open. With good 10.1 ppg irdout shut down and flow check -Blew down circ lines and topdrive, Peak vac'd out choke manifold, poorboy degasser and pits 1-2 for transport to OBM tank farm. All displaced diesel was routed into clean cuttings box for transport to diesel tank farm. LD circ assembly from stump.,Pumped dry job and LD top single jnt to alternate breaks while POOH. POOH from 11,006' V 210' 60k over pull @ 4308' appeared to be resin no other issues coming out, UD BHA Packer and tubing, Packer was damaged slip got wedged out with resin and bent in half, pictures in the O: Drive (Missing Pieces of packer approximately 1 1/2" x 3/4" x 1l4" steel and 3/4 strap Approx 2" long 1/16 thick sleel),Clean and clear rig floor, P/U BHA components,WU BHA 6" Bit, 5 3/4" Boot Baskets, and bit sub,RIH w/ 6" Drilling Assy w/ boot baskets V 4609, -Hauled 0 bbls fluid to KGF G&I Cumulative: 8611 bbls -Hauled 0 bbls solids to KGF G&I Cumulative: 2725bbis -Daily downhole losses: 0 bbls Cumulative: 48 bbls -Daily metal: 416s Cumulative: 1191 his Conductor ann pressure- 0 psi 13-318 X 9-5/8 ann pressure - 0 psi 6/16/2019 Cont TIH with 6" bit and two junk baskets from 4600' to 5479' running stands in hole., PU single in hole 130 jnts CDS-40 DP from 5479' to 9538' -,Cont TIH with stands from 9538'to 10,970'. Up wt 145K, dwn wt 146K.,At 10,970' MU topdrive and attempt to circ with pump #1, could get no pressure. Switch to pump #2 while troubleshoot #1. With pump at idle, 20 rpm, wash down to top of 7" liner and held there for a couple minutes, then washed down into 7" liner to 11,049.5' (stopped drilling epoxy at 11,050' previously.,Sat 6" off bottom for a minute then shut down pump. Gave it a minute, PU 10', then with pump on and off, rotating at 10-20-30 rpm, worked string a dozen times stopping just short of bottom, to try and recover packer metal in junk baskets. Once pump #1 back on line (had camlock hose gasket in discharge valve)„eased down and tagged bottom at 11,050'to resume drilling epoxy plug. Had no torque spikes, no indication of metal pieces under the bit., Drilled epoxy plug from 11,050' to top of composite bridge plug at 11,109'. 380 gpm-1476 psi, 60 and 70 rpm -1000 to 2200 ft/lbs torque, i - 3K web. Drilled on plug from 11,109' to 11,111' then plug went away. Had one torque spike of 4400 R/Ibs. Had 3 pieces of epoxy, 2-3 ft long across flowline we had to maneuver down flowline. Washed down to 11, 180',CBU at 11,180', 380 gpm-1418 psi and worked string at 60 rpm -1381 ft/lbs. Pulled rotary bushing and removed two long strips of epoxy from wellbore, each 10' long, while circ. Had good show of composite material, aluminum and rubber on shakers at bottoms up. Circ until clean. Centrifuging active system to drop mud weight from 10.1 to 9.7 ppg.,Cont TIH on elevators from 11,180' to 14909,, Break Circulation wash down V 4.5” liner top/plug @ 14962', P/U Rotary to 60 rpm Wash and ream down V 14964' 3-4k tq 370 gpmm 2200 psi, Tq spiked V 5-6k P/U, Pump high vis sweep circulate around 380 gem 2300 psi no increase in cuttings on return, turn on centrifuge cul MW back V 9.7 ppg, Flow Check well Static, perform top drive maintenance electrician fixed SOP Iight,Pump dry Job, POOH f/ 14961' V 8925', -Hauled 75 bbls fluid to KGF G&I Cumulative: 8686 bbls -Hauled 5 bbls solids to KGF G&I Cumulative: 2730 bbls -Daily downhole losses: 0 bola Cumulative: 48 bbls -Daily metal: 61bs Cumulative: 1197 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 6/17/2019 Cont POOH with 6" bit and junk baskets from 8925'to 7295' LD singles.,At 7295' had to shut down and replace a leaking hydraulic fitting on topdrive. Monitored well on trip tank, well static.,Cont POOH LD singles from 7295' to 5537'.,Cont POOH racking back in derrick, LD 6" bit and junk baskets. Recovered the two metal pieces from test packer, plus a good amount of broken up composite bridge plug slip segments, approximately 5lbs total.,Cleaned and cleared rig floor, removed a good amount of epoxy strips from flowline elbow at shakers, strapped 50 jnls 2 7/8" SLH-90 workstring, started cleaning pits 9-10, RU Weatherford tongs, slips elevators for 2 7/8" pipe, held PJSM with rig crew and Weatherford Reps.,MU 3.75" tri-cone with no jets, MU bit sub and XO, PU singled in hole 50 jnts 2 7/8" SLH-90, MU SLH-90 x CDS-40 XO, RD released Weatherford. BHA length = 1556.73'. RIH 2 stands CDS-40 DP.,Hung topdrive and blocks, cut and slipped 110 H drill line, calibrated block height, hook load, serviced rig, topdrive and crown.,Cont TIH out of derrick F/1556'-T/7025' w/ 4.5" DP from DS mast,,Started P/U singles F/7025'-T/11,053', no sign of drag F/10,928'-T/11,110', or any bobble entering 7" liner top. P/U-122K S/0-124K,Cont. TIH out of derrick F/11,053-to current depth of 12,730'. Getting calculated pipe displacement.,-Hauled 143 bbls fluid to KGF G&I Cumulative: 8829 bbls -Hauled 17 bbis solids to KGF G&I Cumulative: 2747 bbls -Daily downhole losses: 0 tools Cumulative: 48 bbis -Daily metal: 0 lbs Cumulative: 1197 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 6/1812019 Cont. RIH out of derrick F/l2,730' U 14,889' w/ calculated pipe displacement,Fill pipe and brk circ and establish Parameters. GPM = 300, SPP = 2900 psi , RPM = 30 w/ 2830 free torque Up/dn/rot = 160/1501156k,Continue rih out of derrick F/ 14,889' U 5k set on @ 14,958',Wash ream f/ 14,958' tl 14,975' and took 8k WOS W/ 250 gpm, @ 40 rpm w/ max tq @ 5200 ft/lbs drill junk f/ 14,975't/ 14,975.7' varying parameters and running centrifuge cutting mud weight,Wash ream and chase junk in hole f/ 14, 976' U 14,991', attempted to RIH on elevators T/15,122' (no luck), cont. to wash & ream F/l 5,122'-T/16,31 9' while continuing to cut mud weight MW out 9.6 ppg and MW in 9.5 ppg,Cont. to wash & ream Bridge plug to bottom of 4.5" liner F/16,319'-T/16,512', tagged bottom, set 4K down, P/U 5', CBU while cont. to cutting mud weight back, worked on cleaning around rig & filling pit w/ diesel and building Barascrub/diesel pill for displacement. GPM-250 SSP-2560 psi,Shut down pumps, R/U to reverse circ. OBM, staged up pumps to 250 GPM, keeping close eye on pressure, backing off pumps as needed to keep pressure below 2600 psi.,Cont. to reverse circ. cutting MW down wl centrifuge from 9.2 ppg to 9.0 ppg. GPM-250 SPP- 2500 Psi,Cont. to reverse circ, finished cutting MW down to 9.0 ppg all the way around, mixed 50 bbl Hi-Vis spacer, shut down pumps, flow check (static), noticed chunk of floating resin in stack, lined up & circ. conventionally, fished out 4' chunk of resin, shut down pumps, drained stack looking for additional chunks„Noticed chunk of floating resin in stack, lined up & circ. conventionally, fished out 4' chunk of resin, shut down pumps, drained stack looking for additional chunks, no chunks in stack. Called town to discuss options regarding resin chunks, decision was made to displace well over to diesel.,-Hauled 25 blots fluid to KGF G&I Cumulative: 8854 bbls -Hauled 20 bbls solids to KGF G&I Cumulative: 2767 bbis -Daily downhole losses: 0 bbls Cumulative: 48 blols -Daily metal: 0lbs Cumulative: 1197 lbs Conductor ann pressure- 0 psi 13-318 X 9-5/8 arm oressu 6/19/2019 PJSM w/ drill crew and peak on displacement procedure,Pump 19.5 bbls Barascrub pill followed by 43.3 bbis high vis spacer and chg over w/ 886 bbis of 6.7 ppg diesel keeping rate at max while not allowing pressure to exceed 2600 psi and dumped 53 bbis of interface,Monitor well on trip tank while cleaning pits & prep to gdn dip well out balance,Circ do cip and pumped string volume tag btm @ 16,512.5' lark out I/dn TIW valve, pump in sub and hose & flow chk (ok),Pooh Udn dp f/ 16,512'-T/ 14,217', whipping OD & vacuuming foot ball thru ID and cleaning and re-doping threads, started cleaning pit of tank bottom/OBM & flushing lines. PIU-198K S/0-179K,Cont. POOH UD 4.5” DP F/14,217'-T/12,792', whipping OD & vacuuming foot ball thru ID and cleaning and re-doping threads, P/U-175K SIO-160K,Shut down & performed rig service, greased/inspected-crown, blocks, TD, DW, brake linkage, drive line bolts, pins/keepers 8 checked fluid Ievels.,Cont. POOH UD 4.5" DP F/12.792'-T/8,606', whipping OD & vacuuming foot ball thru ID and cleaning and re-doping threads, PIU-150K S/0-140K,Crew change, held PJSM, cont. POOH UD 4.5" DP F/8,606'-T/3,800', whipping OD & vacuuming foot ball thru ID and cleaning and re-doping threads, gave Weatherford 3 hr notice for UD 2-7/8" work string, 3.5 bbls over calculated hole fill for trip up to this point.,Found 18 bad jts of DP pipe during TOOH up to this point, due to scaring on the side of face on the box end, set aside jts to be sent to Tuboscope to be inspected. Had 1/2 gallon spill in containment of hydraulic fluid from iron roughneck HPU.,-Hauled 60 table fluid to KGF G&I Cumulative: 8914 bbls -Hauled 58 bbls solids to KGF G&I Cumulative: 2825 bbls -Daily downhole losses: 0 bbls Cumulative: 48 bbls -Daily metal: 0lbs Cumulative: 1197 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 6/20/2019 Continue POOH UD 4.5" DP F/3800' -T/1556', wiping OD & vacuuming football thru ID and cleaning and re -doping threads w/ total 32 jts bad most w/ double bit marks from iron rough neck misalignment hot topic for discussion at PTSM w/ crews continue clean pits w/ total 3.5 over Cal hole fIl,Monkor static well on trip tank (ok) Move dip off walk onto trailers clean prep rig floor r/up weatherford tongs and 2-7/8" handling equipment, PJSM on I/dn of 2-7/8" and Continue clean pits,Pooh I/dn 2-7/8" dp wiping OD and vacuuming ID f/ 1556' t/ Bha 3.75" bit missing two cone and some of the shanks (see photos in file) w/ cal hole fill =116.3 bbls, measured @ 113.9 bbls diff = 2.4 bbls for complete trip continue clean pits and Iines,R/up and pull wear ring continue clean pits and flush lines and choke manifold w/ diesell baraclean pill and blow do same and prep to P/up gas lift competition, R/U Weatherford to run 3.5" completion, M/U TIW to XO.,Held PJSM on running 3.5" completion w/ Weatherford, rig crew, Peak. Tri -point, and all other personal involved.,Started RIH w/ 3.5" completion string, P/U & MIU Bullet seal assy. (minus the seals), XO to single joint, X -landing nipple w/ 2.813" profile, single joint, pup, XO to 7" Tri -point permanent packer to 5" seal bore tie back sleeve to 5" Tri -point anchor latch w/ seals, XO to 3.5" 9.3# P-110 EUE 8 Round T11085', TO connections to 4230,Cont. RIH w/ 3.5" 9.3# P-110 EUE 8 round tubing F/1085' -T/3360', P/U 3 GLM, P/U-38K SIO -36K, TO connections to 4230,Performed rig service, greased/inspected- crown, blocks, TD, DW, brake linkage, drive line & checked drive line bolts, and inspected Kelley hose.,Cont. RIH w/ 3.5" 9.3# P-110 EUE 8 round tubing F/3360' -T/6050', PIU GLM #'s 4-6, PIU -SOK S/0 -48K, TO connections to 4230,Crew change, held PJSM, cont. RIH w/ 3.5" 9.3# P-110 EUE 8 round tubing F/6050' -T/7,479, PIU GLM #'s 7 & 8, P/U-54K SIO -52K, TO connections to 4230,Held PJSM w/ Pollard, brought over canon clamps & nails, staged on rig floor in piles of ten, R/U 1/4" stainless steel chemical line through shive and hung off derrick board, oriented chemical line, checked clearance on power tongs, pressure tested chemical line fitting to 500 psi.,Cont. RIH w/ 3.5" 9.3# P-110 EUE 8 round tubing F/7475' -T/8,585', P/U GLM #'s 9 & 10, P/U-58K S/0 -55K, TO connections to 4230, while maintaining 3500 psi on chemical line, w/ calculated pipe displacement., -Hauled 45 bbls fluid to KGF G&I Cumulative: 8959 bbls -Hauled 5 bbls solids to KGF G&I Cumulative: 2830 bbls -Daily downhole losses: 0 bbls Cumulative: 48 bbls -Daily metal: O lbs Cumulative: 1197 lbs Conductor ann pressure -0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 6/21/2019 Cont. RIH w/ 3.5" 9.3# P-110 EUE 8 round tubing F/8585' -T/10,288', PIU GLM #'s 9 & 10, PIU-68KS/0-64K, TO connections to 4230, while maintaining 3500 psi on chemical line, w/ calculated pipe displacement.,5et slips on chemical line p/up to collar and splice same and test to 5000 psi for 15 min (ok) and place clamp over splice and collar @ 10,272',Cont. RIH w/ 3.5" 9.3# P-110 EUE 8 round tubing F/10,288' -T/11,189', P/U GLM #'s 11, P/U-78K S/O-79K, TQ connections to 4230, while maintaining 3500 psi on chemical line, w/ calculated pipe displacement, cont, to clean pit system, rigged down centrifuge & vacuumed out line and installed load blocks, rigged down hurricane vac & moved off location. Loaded 11 ISO w/ OBM & sent GPP.,Cont. RIH w/ 3.5" 9.3# P- 110 EUE 8 round tubing, had no issues @TOL but been working up to 3 Times 8-10k set dn's every 32-33' before falling through F/ 11,189' T/13,474', P/U GLM # 12. P/U-94K S/0 -93K, while maintaining 3500 psi on chemical line, w/ calculated pipe displacement. worked through several tight spots every 30-33', w/ 8-10 K set down, working up to 3-4 times before falling through.,Cont. RIH w/ 3.5" 9.3# P-110 EUE 8 round tubing F/13,474' -T/14,946', P/U-94K S/0 - 92K, TQ connections to 4230, while maintaining 2800 psi on chemical line, worked through several tight spots every 30.33', w/ 10-12 K set down, working up to 3-4 times before falling through. Pipe displacement calculated= 49.4 bbls, measured=48.8 bbls, difference=.6 bbls,Verify pipe count (Good), PIU 2 single jts to tag 4.5" liner top @14,980' w/ 4K set down on nogo, set down 20K to verify, P/U & calculated space out of 20.65', , UD jts 450-451, R/D air slips, rig bails & elevators, R/U long bails & elevators, verify RKB=18'., P/U 2 10' pups Its, M/U hanger & landing jt in mousehole, M/U to string, R/D chemical control line & sheave, cut chemical line, wrapped line around tubing below hanger & banded twice, run chemical line though hanger & plugged extra ports, R/D power tongs, MIU XO, TIW, head pin, chickson, & 50' 1502 hose to top of landing it., Eased in the hole w/ hanger, stopped 2 off seat, P/U 5', lined up & started pumping @ 2.2 bbls/min & established flow, eased back down 4' and stabbed naked seals into 4.5" liner top, saw pressure increase to 187 psi, shut down pumps, drained stack, landed hanger & run in lock downs. R/D XO, TIW, head pin, swing, & 50'1502 hose.,Held PJSM w/ Pollard slickline crew, R/U slickline sheaves, RIH wl rod & ball on slickline, latched into X -nipple @ 14,936' w/ rod & ball.,R/U 2 low torque valves, & a 1502 hose to Pollards side entry sub on landing jt, started pressuring up to 4K psi down string to set Tri -point packer., -Hauled 87 bbls fluid to KGF G&I Cumulative: 9046 bbls -Hauled 12 bbls solids to KGF G&I Cumulative: 2842 bbls -Daily downhole losses: 0 bbls Cumulative: 48 bbls -Daily metal: O lbs Cumulative: 1197 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 6/22/2019 Continue Pressure upon tbg, to 3975 psi w/ 7.3 bbls total and hold for 10 min as per tri point hand and set prk @ 14, 888' , lost 45 psi over 10 min, bled off pressure, removed low torque & hose off Pollards side entry sub., POOH w/ rod & ball from X -nipple w/ slickline @ 14,936', R/U 2" 1502 hose from stand pipe to annulus w/ an inline low torque valve, tied into tee on annulus w/ test pump, broke slickline lubricator. R/U slickline to RIH to pull plug body,with Tbg open Pressured up on annulus to lest packer and csg w/ MP part way, brought up w/ test pump the rest of the way to 2200 psi, had to bump up pressure twice w/ test pump, held on chart for 30 min @ 2100 psi (Good test),RIH run #2 w/ slickline to pull plug from X -nipple, RID testing equipment & MP lines from annulus.,POOH wl slickline after latching onto plug, swapped out slickline assembly, P/U 20' of 2.5" spent dummy guns & RIH, Run #3 set an numerus times and oil jar licks to free tools once wiped area was clean starting @ 14, 972' U 16, 550' SLM RKB ( Seams deep) flushed MP through bleeder wl Barascrub, RID gen #3 skid. Pooh Chk counter re zero w/ negative 38' so Tag was 16,512' SUM. R/dn slick Iine,Back out landing jt, and install BPV and r/ do long bails pump barscrub pill thru TDS flow lines and blow back mud lines R/up crane and start r/dn wind walls Prep for nip/dn and clean rig and equipment as needed in prep for move,Held PJSM, N/D flow line, flow box, hole fill line, installed BOP trolly beams, N/D choke/kill lines, tie onto stack, break bolts, lift stack & trolly out, cont. cleaning rig in prep for move.,Nipple down -Remove gas buster return line & kill line from mez. kill, upper annulus outer flange & low torque valve, install blank flange, clean well head, prep for tree installation, clean & install covering on all accumulator lines/ fittings/choke/kill lines, staged tree in cellar.,N/U tree w/ well head Rep James Craycraft, torqued bolts, pressure tested void to 500 psi /S min Low, 5000 psi/1 Smin High (ok) hanger neck seals 500 psi/5min Low, 5000 psUSmin High (ok) , tested tree 5000 psi, visual inspection folk). Removed BPV and secured well.,Cleaned rig floor equip., UD sub rack, misc. XO subs, DP slips, & rig tongs, installed shipping beams in cellar, UD gas buster, removed saver sub from top drive, removed wash pipe from TD, installed new & rebuilt old one, cleaned out MP bear traps & suction lines to MP, scrubbed derrick from board down to wind walls & on roof top, cleaned pill pit, 7 & 3.,Continued to scrub derrick, iron roughneck, hang TD in shipping cradle, clean pits 1 & 2, Removed stairs to pits by gas buster. Rig released @ 06:OO,Removed wind walls & stored in conex container, removed centrifuge, LVT vertical tank, Genset, mud loggers shack, & directional shack off location, sent three remaining ISO tanks out to GPP for a total of 1,315 bbls of OBM shipped off., -Hauled 48 bbls fluid to KGF G&I Cumulative: 9094 bbls -Hauled 12 bbls solids to KGF G&I Cumulative: 2854 bbls -Daily downhole losses: 0 bbls Cumulative: 48 bbls -Daily metal: 0lbs Cumulative: 1197 lbs Conductor ann pressure- 0 psi 13-3/8 X 9-5/8 ann pressure - 0 psi 6/28/2019 ARRIVE AT BEAVER CREEK - TGSM -JSA- PERMIT STANDBY FOR CONSTRUCTION CREW RIG UP W/L - PT LU B - FAIL - C/O ORINGS - PT LUB 4000 PSI - GOOD RIH W/ 3" GS W/ 3 1/2 AD -2 STOP TO 13325'KB SET STOP - SHEAR OFF POOH FL - SeNIce,RIH W/ 3 1/2 DANIELS KOT W/ 1 1/4 JDS TO 11692'KB SIT DOWN WIT POOH W/ DUMMY VALVE RIH W/ SAME PULL UP LOCATE SIT DOWN AT 13231'KB WIT POOH W/ DUMMY VALVE RIH W/ SAME PULL UP LOCATE SIT DOWN AT 12430'KB WIT POOH WI DUMMY VALVE RIH W/ SAME PULL UP LOCATE SIT DOWN AT 10985'KB W/T POCH WI DUMMY VALVE,RIH W/ SAME PULL UP LOCATE SIT DOWN AT 10311'KB WIT POOH W/ DUMMY VALVE RIH W/ 3 1/2 DANIELS KOT W/ 1 114 JDC LOCATE SIT DOWN AT 9638'KB WIT POOH W/ DUMMY VALVE RIH W/ SAME LOCATE SIT DOWN AT 8966'KB WIT POOH W/ DUMMY VALVE RIH W/ SAME LOCATE SIT DOWN AT 8166KB WIT POOH W/ DUMMY VALVE RIH W/ SAME SIT DOWN AT 2440'KB WIT POOH W/ DUMMY VALVE,RIH WI SAME LOCATE SIT DOWN AT 7526'KS WIT POOH W/ DUMMY VALVE RIH W/ SAME LOCATE SIT DOWN AT 7189KB WIT POOH W/ DUMMY VALVE RIH WI SAME LOCATE SIT DOWN AT 5951'KB WIT POOH W/ DUMMY VALVE RIH W/ SAME LOCATE SIT DOWN AT 393'KB WIT POO W/ DUMMY VALVE 6/29J2019 RIH W/ 3 112 DANIELS KOT W/ JK R.T. W/ STATION 91 GLV LOCATE SITE DOWN 2440'KB WIT POOH VALVE SET RIH W/ SAME W/ STATION #2 GLV LOCATE SIT DOWN AT 4393'KB WIT POOH - VALVE SET RIH W/ SAME W/ STATION #3 GLV LOCATE SET DOW N AT 5951'KB WT POOH - VALVE NOT SET RIH W/ SAME TO 5951 WT - POOH - OOH VALVE NO SET - PACKING SHOWS FULLY IN POCKET,RIH W/ SAME TO 5951'KB LOCATE SIT DOWN - WT- POOH - VALVE SET RIH W/ SAMW W/ GLV # 4 TO 7180 LOCATE SIT DOWN WT - POOH - OOH VALVE NO SET RIH W/ SAME TO 7180'KB LOCATE SIT DOWN WT- POOH - OOH VALVE NO SET ADD KJ ABOVE KOT - RIH W/ SAME 7180'KB WT - POOH - NOT SET RIH W/ OK -1 KOT W/ JKRT W/ GLV # 4 TO 7180'KB LOCATE - CAN NOT SET DOWN POOH - NOT SET,RIH W/ OK -5 KOT W/ JKRT W/ GLV 94 TO 7189KB WT SET VALVE POOH - OOH VALVE SET RIH W/ DANIELS KOT W/ CHEM INJ TO 7509KB WT SET VALVE POOH - VALVE ST RIH W/ DANIELS W/ GLV #5 TO 8146'KB WT TO SET VALVE POOH - VALVE SET RIH W/ SAME W/ GLV # 6 TO 8946'KB WT SET VALVE POOH - OOH VALVE SET RIH W/ SAME W/ GLV # 7 TO 9618'KB WT SET VALVE POOH - OOH VALE SET,RIH W/ SAME W/ GLV # 8 TO 10,291'KS WT SET VALVE POOH - OOH VALVE SET RIH W/ SAME W/ GLV # 9 TO 7160'KB SET DOWN - WT FALL TO 10965'KB WT SET VALVE POOH SLIP CUT 25' W IRE - REHEAD - CHECK TOOL STRING RIH W/ DANIELS KOT W/ JKRT W/ GLV #10 TO 11692'KB WIT POOH - VALVE SET, ARM RELEASE HALF SHEARD OFF ON KOT LEFT IN HOLE,RIH W/ OK -5 WI JK R.T. W/ GLV #11 TO 12430'KB WIT POOH - VALVE SET - REPIN KOT RIH W/ SAME W/ ORIFICE VALVE TO 13235'KB WIT POOH - VALVE SET RIH W/ 3" GS TO 13345'KB WIT COMES FREE POOH, HANG UP IN 7526'KB SPANG THROUGH, HANG UP AT 7172'KB W/T,IN HOLE W/ 3" GS LATCHED ONTO AD -2 STOP HUNG UPAT 7592'KB WIT 7588'KB, JAR LICK 40 TIMES, SHEAR OFF, POOH, CUT 30' WIRE, RETIE ROPE SOCKET, ADD 5' STEM RIH W/ T' GS TO 7176'KB WIT COMES FREE PULLS HEAVYAND JAR LICKING IN MULTIBLE SPOTS PULL UP TO 5943'KB HANGS UP DO 50 JAR LICKS SHEAR OFF POOH, REHEAD, CUT WIRE 6/30/2019 REBUILD TOOLSTRING - 15' 2.125" STEM RIH W/ 3"G8 TO 5943'KB WT 40 OIL JAR LICKS -DOES NOT COME FREE -SHEAR OFF - POOH SLIP CUT 50' WIRE - RETIE ROPE SOCKET RIH W/ SAME TO 5943'KB WT 40 OIL JAR LICKS - 30 MINS SPANG LICKS - SHEAR OFF - POOH SLIP CUT 50' W IRE - RETIE ROPE SOCKET - ADD LONG STROKE OIL JARS,RIH W/ 3" PR TO 5942'KB WT - 30 OIL JAR LIICKS - SHEAR OFF POOH RIG DOWN BARNEY - RIG UP .160 SKUNK TRUCK,RIH W/ 3" PR TO 5942'KB WT - 20 3500 LBS OIL JAR LICKS - COME FREE - POOH - HANG UP AT EVERY COLLAR AND JAR LICK THROUGH TO 4373'KB - HANG UP - 5 X 3500 LBS JAR LICKS - COME FREE - POOH -OOH W/ DAMAGED AD-2 STOP- MISSING 2 WHOLE SLIPS, UPPER HALF OF ONE SLIP, BAND, SLIP RETAINING SECTIONS OF THE HOUSING/BODY RIG DOWN SKUNK TRUCK - RIG UP .125" WIRE ON BARNEY,RIH W/ 2.70" GAUGE RING TO 4627'KB TAG - DO NOT WORK TOOLS - POOH RIH W/ 2.75" LIB 4667'KB WT - POOH - OOH W/ IMPRESSION OF POSSIBLE SLIP TURNED SIDEWAYS CREW C/O, GO OVER PLAN FORWARD W/ CHAD J. RIH W/ 2.60" MAGNET TO 4658'KB SIT DOWN 3 TIMES POOH - METAL SHAVINGS,RIH W/ SAME TO 4631'KB SIT DOWN TAP DOWN ONCE SIT DOWN 4662'KB TAP DOWN, SIT AT 4728'KB TAP DOWN FALL THROUGH POOH - METAL SHAVINGS RIH W/ SAME SIT DOWN AT 4385'KB W/T PICK UP TO 4381'KB GET SLIGHT OVERPULL REPEAT WITH SAME RESULT POSSIBLE METAL IN STATION 2 POOH - METAL SHAVINGS,RIH W/ ALLIGATOR GRAB SIT DOWN AT 4386KB W/T FALLS THROUGH POOH - HAVE UPPER HALF OF BROKEN SLIPHOURS 12.160/ 12.125-$7370.00 RIH W/ 2.60" MAGNET SIT DOWN 7470'KB POOH - METAL SHAVINGS,RIH W/ 2.75 G-RING TO 11692'KB SITS DOWN CAN NOT PASS POOH - METAL MARKS ON BOTTOM RIH W/ ALLIGATOR GRAB TO 11698'KB W/T POOH - NO RETURN RIH W/ 2.75" LIB TO 7480'KB TAP DOWN POOH - LIGHT MARKS ON BOTTOM AND SIDES 7/1/2019 RHW/2.5"X6'PUMP BAILER TO 7496'KB WT (PUMP ONLY) FALL TO 11698'KB WT (PUMP ONLY)\ FALL TO 12,430'KB WT CAN NOT PASS POOH - OOH W/ EMPTY BAILER - METAL MARKS ON BTM RIH W/ DECENTRALIZER (TO INDICATE LOW SIDE) W/2.75" LIB TO 12,428'KB WT- POOH - OOH W/ IMPRESSION OF SLIP BEVELED DOWN,RIH W/ DECENTRALIZER W/ 3 PRONG WIRE GRAB TO 7506'KB (CHEM INJ) PICK UP- FALL TO 12,430'KB WT FALL TO 12,782'KB WT FALL TO 12,956'KB WT FALL TO 13,211'KB WT FALL TO 13956'KB WT FALL TO 13990'KB WT FALL TO 16,546'KB TAG BTM - POOH RIH W/ 2.5" X 20' SPENT PERF GUNS W/ 2.9" BRAIDED LINE BRUSH ON BTM TO 16,529'KB - POOH OOH W/GUNS,RIG DOWN W/L- SECURE WELL MOB EQUIPMENT TO PWL SHOP PUSH ALL PIECES LEFT IN HOLE TO BOTTOM - DRIFT W/ 2.5" X 20 SPENT PERF GUNS 7/2/2019 PTW and JSA (4:30 am). Spot equipment and rig up lubricator. PT to 250 psi low and 2500 psi high. TP - 0 psi,RiH w/2-7/8"x26' HC Razor 6 spf, 60 deg phase and tie into OHL. Run correlation and Trudi (Res Engr on location) ok the log. Tagged at 16,503'. Spotted gun from 16,448' to 16,474' with 0 psi on tubing. Fired gun and POOH. Got out of hole and bottom 6' of shots did not go off. Decision was made to run a 20' gun and shoot bottom 6' and overlap the other 14'. Well would pressure up to 50 to 100 psi due to line displacement,and we would bleed it to zero. The 6' gun was tandem with a 20' gun and 20' went off but 6' didn't. Either wet out or blasting booster didn't go off good. 20' was on top. Fired gun at 1035 his .Look like diesel in guns,RIH w/2-7/8"x20' HC Razor 6 spf, 60 deg phase and tie into OHL. Run correlation log and Trudi (Res Engr on location) ok the log. Spotted and fired gun with 10 psi on tubing from 16,454' 16,474' (overlap 14') lost 10 psi right away. POOH. All shots fired. Fired gun at 1445 his. Look like diesel in guns,RIH w/2-7/8"x20' HC Razor 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town (Trudi left). Get ok to pert from 16,428' to 16,448' withl 10 psi on well. Spotted and fired gun. Lost 10 psi when fired. POOH. All shots fired. Fired gun at 1806 hrs. Look like diesel in guns,RIH w/2-7/8"x20' HC Razor 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to pert from 16,408' to 16,428' with 150 psi on well. Spotted and fired gun. Lost 50 psi when fired. POOH. All shots fired. Fired gun at 2130 his. Look like diesel in guns.,Rig down lubricator and turn well over to field. Clean up work area. 7/6/2019 ARRIVE BEAVER CREEK MEET W/ PROD. TGSM JSA PERMIT RIG UP SLICKLI NE P/T LU B. TO 1500PSI GOOD RIH W/ 2.5" DD BAILER TO 16,547'KB TAG W/ TOOL POOH RIH W/ TRI-GAUGES TO 16,537'KB 10' FROM BOTTOM TAG SEE STOP SHEET,OOH - DOWNLOAD DATA& SEND TO JERRY BUTTLER RIH W/ 2 1/2" X 20' DUMMY GUNS 400FPM TO 14,000' SLOW TO 150FPM TO 16,546'KB TAG POOH RIG DOWN SLICKLI NE CLEAN AREA SECURE WELL FOR PRODUCTION DEPART FOR PWL SHOP 7/8/2019 Sign in (5:30 AM). PTW and JSA w/AKE-Line. Mobs to location. Tail gate meeting. PT to 250 psi low and 2500 psi high. TP - 500 psi,RIH w/2"x16.5' (counting bushings between stim tubes. 5 explosive tubes) and tie into correlation pert log (CCL only) and tag at 16,508., Run correlation log and send to town. Got ok to fire stim tubes from 16,472' to 16,455.5' (2' higher than bottom pert) with 500 psi (lub gauge) on tubing. Spotted and fired gun at 1028 his. Had good indication of gun firing. Didn't really see any pressure change. POOH. The tools were,not on line. They pulled out of the rope socket. They had to put a light pull out on rope socket due to depth we were shoots at. The gun probably jump up a few feet and when they came down is when it pulled out of the rope socket. Call town and discussed. Slickline is coming out today and fish tools out. If line was blown up hole very far it would have kinked the line and I didn't see any kinks.,Rig down lubricator and tools. Cut 200' of line off due to loose strands.,PTW and JSA. Put new rope socket on. Spot and rig up Pollard SL lubricator. PT to 250 psi low and 2500 psi high.,RIH w/JDC with 2.70" bell guide down to 16,511' SLM and latch E-Line tools. Pickup and had approx. 150 Ibs over weight. POOH with no trouble and had the whole E-Line fish. E-Line tools looked in good shape.,Rig down slick line off well and turn back over to field. Finish rigging down lubricator and tools. 7/10/2019 PTW and JSA w AKE-Line.. Mobe to location. Spot equipment. Decision made to fill well with oil before we perforate., Pumped 90 bbis crude and 5.5 bbls 1 diesel. That should have fill well bore to surface with Fluid. Put 1000 psi of gas on well. 7/11/2019 PTW and JSA. Rig up lubricator. Find bad spot in line. Cut off another 200' of line and re -head line. Had o -ring leak on lubricator. Changed it out. PT to 250 psi low and 2500 psi high. TP - 1000 psi,RIH w/2.6'x20' Razar HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Got ok to perf from 15,933'to 15,913' with 1200 psi on tubing. Spot and fired gun. Good indication of gun fired. Gained 3 psi. Fired gun at 1520 hrs. POOH and all shots fired.,RIH w/25N13' Razar HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to pert from 15,913' to 15,900' with 1100 psi on well. Spotted and fired gun. Didn't get a good indication that gun went off. Attempted to fire gun 3 more times. POOH and gun had not fired. Called town and discussed. Decision was made to trouble shoot problem and SDFN. Checked everything out but did not find the,problem. Tomorrow they will put new rope socket on line and change out weight and shooting CCIJGama Ray and put new firing head and detonator on. AKE-Line operator will go over everything he did with his supervisor. Plan is to be back at 7 am in the morning. Rig off well and secure well. 7/12/2019 PTW and JSA WAKE -Line. Change out tool string and re -head line. PT to 250 psi and 2500 psi high. TP - 1100 psi,RlH w/2.5"x13' Razar HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Told to shift log up 2' and pert from 15,900' to 15,913'.. Shifted log up 2' and spotted gun. Fired gun with 1082 psi on scada at 1100 hrs. Showed good indication gun fired. Didn't see any pressure increase except for gun gas. POOH and all shots fired.,Rig down lubricator and turn well over to field. Will leave AKE-Line equipment out here for the next operation in a couple days. (No charge). 7/16/2019 PTW and JSA. Rig up lubricator and MU Interwell W RP. PT to 250 psi low and 2500 psi high. TP - 0 psi, RIH w/Interwell 2.70" WRP and tie into AKE-Line CCL log. Get on depth at 15,810' and start pumping crude in well. Pumped approx. 112 to 115 bbls of crude and tubing pressured up to 200 psi. Quit pumping and start setting plug. Plug set at 15,810'. Pick up 30' and went back down and tagged plug. POOH. Setting tool showed good set. Graph that showed the setting of the tool looked good. Pressure tested,plug to 1000 psi and held. Rig down AKE-Line. Will be out in the am to pert. SLB pump truck and N2 tanker will be here around 8:30 am. Plan on running guns to depth and then pressuring up with N2. Release Interwell plug man. 7/17/2019 PTW and JSA. Rig up lubricator. Have a SIMOPS meeting with SLB N2 crew. N2 crew spotting up and transferring N2 from tanker. PT Iub to 250 psi low and 3500 psi high.,RIH w/2.50"x18' HC Razar, 6 spf, 60 deg phase and tie into OHL. Run correlation log and Res Eng on location to correlate log. PT N2 lines to 4500 psi. Pressured up tubing to 2200 psi. Spotted gun from 15216'to 15,234' and fired gun. Good indication gun fired. Started to build pressure and at 2800 psi started bleeding N2 off at a low rate to keep it under 3000 psi. POOH. All shots fired and TP - 2930 psi.,Rig lubricator off well and field started bleeding N2 off tubing. Pumped 448 gals of N2 total. Using the pump in sub to bleed off N2. Rigged down lubricator and equipment while bleeding well down. We have 2200 cals N2 left in SLB Pump truck. Hilcorp Alaska, LLC Beaver Creek Unit Beaver Creek Unit BCU 4RD BCU 4RD 501332023901 Sperry Drilling Definitive Survey Report 17 May, 2019 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well Beaver CK Unit 4 Protect: Beaver Creek Unit TVD Reference: RCU Planned IRKS @ 166.20usft Site: Beaver Creek Unit MD Reference: BCU Planned RKB @ 166.20usft Well: Beaver CK Unit 4 North Reference: True Wellbore: BCU 4RD Survey Calculation Method: Minimum Curvature Design: BCU 4RD Database: NORTH US+CANADA noted Beaver Creek Unit Beaver CK Unit 4 dap Svstem: US State Plane 1927 (Exact solution) Svstem Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Usino Well Reference Point dap Zone: Alaska Zone 04 Usino geodetic scale factor Survey Program Well Beaver CK Unit 4 Well Position +NIS 0.00 usft Northing: 2,433,577.41 usft Latitude: 60° 39'25+8089 N +E/ -W 0.00 usft Easting: 315,181.61 usft Longitude: 151" 1'48.4891 W Position Uncertainty Survey Date 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 148.20 usft 2 -CB -Film -GMS A022Ga: Film camera gyro multi -shot 11/27/1972 3,187.20 Wellbore BCU 4RD A024Ma: Film camera magnetic multi -shot 11/27/1972 Magnetics Model Name Sample Date Declination Dip Angle Field Strength 11/27/1972 11,356.00 P) (9 (l H003M6: Interpolated azimuth +sag correction BGGM2018 4/10/2019 15.52 73.60 55,277.56833047 Design BCU 4RD 04/18/2019 15,228.41 Audit Notes: 2_MWD+IFRI+MS+Sag A010Mb: IFR dec & multi -station analysis +sag 05/01/2019 Version: 1.0 Phase: ACTUAL Tie On Depth: 11,291.20 Vertical Section: 0.00 Depth From (TVD) +N/ -S +FJ -W Direction 0.00 0.00 UNDEFINED (usft) (usft) (usft) (•) itill 202.20 18.00 0.00 0.00 131.21 0.00 2,433,577.41 315,181.61 Survey Program Date 5/16/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 202.20 2,802.20 BCU-04PB1 GMS (BCU 04PB1) 2 -CB -Film -GMS A022Ga: Film camera gyro multi -shot 11/27/1972 3,187.20 8,587.20 BCU-04PB1 CB -MMS (BCU 04PB1) 2_CB-Film-MMS A024Ma: Film camera magnetic multi -shot 11/27/1972 8,767.20 11,291.20 BCU-04PB2 CB -MSS (BCU 04PB2) 2_CB-Film-MSS H057Ma: Film camera magnetic single shot 11/27/1972 11,356.00 11,667.40 BCU 4RD MWD Interp+Azi+Saq (BCU 4R 2_MWD_Interp Azi+Sag H003M6: Interpolated azimuth +sag correction 04/12/2019 11,729.87 15,142.56 BCU 4RD MWD+IFRI +MS+Saq (1) (BCU 2_MWD+IFRI+MS+Sag A010Mb: IFR dec & multi -station analysis+sag 04/18/2019 15,228.41 16,603.96 BCU4RDMWD+IFRI+MS+Saa(2)(BCU 2_MWD+IFRI+MS+Sag A010Mb: IFR dec & multi -station analysis +sag 05/01/2019 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/.S +E/ -W Northing Easting DIS Section (usft) (1 (1) (usft) (usft) (usft) (usft) 1ft1 (ft1 (9100') (it1 Survey Tool Name 18.00 0.00 0.00 18.00 148.20 0.00 0.00 2,433,577.41 315,181.61 0.00 0.00 UNDEFINED 202.20 0.00 itill 202.20 -36.00 0.00 0.00 2,433,577.41 315,181.61 0.00 0.00 2_CB-Film-GMS(1) 402.20 0.50 244.00 402.20 -236.00 -0.38 -0.]8 2,433,57].04 315,180.82 0.25 4.34 2_CB-Film-GMS(1) 602.20 0.25 280.00 602.19 4W.99 -0.69 -2.00 2,433,5]6.]5 315,179.61 0.17 -1.05 2_CB-Film-GMS(1) 802.20 0.25 256.00 802.19 -635.99 -0.72 -2.85 2,433,576.74 315,178.75 0.05 -1.67 2_CB-Film-GMS(1) 1,002.20 0.33 348.00 1,002.19 -835.99 -0.26 -3.39 2,433,5]].20 315,178.22 0.21 -2.38 2 CB-FiInl(1) 1,202.20 0.33 325.00 1,202.19 -1,035.99 0.77 a.84 2,433,578.25 315,1]7.78 0.07 -3.40 2_CB-FIIm-GMS(1) 1,402.20 0.50 250.00 1,402.18 -1,235.98 0.95 -5.00 2,433,578.44 315,176.63 0.26 4.38 2_CB-Fi1m-GMS(1) 1,602.20 0.00 180.00 1,602.18 -1,435.98 0.65 -5.82 2,433,578.15 315,175.81 0.25 4.80 2_CB-Film-GMS(1) 1,802.20 0.25 130.00 1,802.18 -1,635.98 0.37 -5.48 2,433,5]7.8] 315,176.14 0.12 4.37 2_CB-Film-GMS(1) 5/172019 1:51:48PM Pace 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Companv: Protect: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Beaver Creek Unit Beaver Creek Unit Beaver CK Unit 4 BCU 4RD BCU 4RD Local Co-ordinate Reference: Well Beaver CK Unit 4 TVD Reference: BCU Planned RKB @ 166.20usft MD Reference: BCU Planned IRKS @ 166.20usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +Nl-S +Ef-W Northing Easting DLS Section (usft) 0 (•) (usft) (usft) (usft) (usft) Ifin int rilooi IRI Survey Tool Name 2,002.20 0.17 15.00 2,002.18 -1,835.98 0.37 5.07 2,433,577.87 315,176.55 0.18 -4.06 2_CB-Film-GMS(1) 2,202.20 0.25 100.00 2,202.18 -2,035.98 0.59 4.56 2,433,578.07 315,177.06 0.14 -3.82 2_CB-Film-GMS(1) 2,402.20 0.17 20.00 2,402.18 -2,235.98 0.79 4+03 2,433,578.26 315,177.59 0.14 3.55 2_CB-Film-GMS(1) 2,602.20 0.08 240.00 2,602.18 -2,435.98 1.00 4.05 2,433,578.47 315,177.58 0.12 -3.71 2 -CB -Film -GMS (1) 2,802.20 0.50 179.00 2,802.17 -2,635.97 0.05 4.16 2,433,577.53 315,177.46 0.23 -3.16 2_CB-Film-GMS(1) 3,187.20 0.25 296.00 3,187,17 5,020.97 -1.26 4.88 2,433,57623 315,176,71 0.17 -2.85 2_CS-FIImMMS(2) 3.367.20 0.00 0.00 3,367.17 5,200.97 -1,08 -524 2,433,576.41 315,176,36 0.14 -3.22 2_08-Film-MMS(2) 3,547.20 0.25 35.00 3,547.17 -3,380.97 -0.76 -5.01 2,433,576.73 315,176.59 0.14 5.27 2_CB-Film-MMS(2) 3,727.20 0.25 100.00 3,727.17 -3,560.97 6.51 4.40 2,433,576.97 315,1T.21 0.15 -2.97 2_CB-Film-MMS(2) 3,907.20 0.00 180.00 3,907.17 -3,740.97 -0.58 4.01 2,433,576.90 315,177.59 0.14 -2.64 2 -CB -Film -MMS (2) 4,087.20 0.25 90,00 4,087.16 -3,920.96 -0.58 -3.62 2,433,576.89 315,177,99 0.14 -2.34 2_CB-Fi1mMMS(2) 4,267.20 0.50 210.00 4,267.16 4.100.96 -1.26 -3.62 2,433,576.21 315,177.98 0.37 -1.89 2_CB-Film-MMS(2) 4,447.20 0.50 230.00 4,447.16 4,280.96 -2,44 4.61 2,433,575.04 315,176.96 0.10 -1.86 2_CB-Film-MMS (2) 4,627.20 0.25 209.00 4,627.15 4,460.95 -3.29 -5.41 2,433,574.21 315,176.16 0.16 -1.90 2_CB-Film-MMS (2) 4,807.20 0.50 265.00 4,807.15 4,640.95 -3.70 -6.38 2,433,573.81 315,175.18 0.23 -2.36 2_CB-Film-MMS(2) 4,987.20 0.25 299.00 4,987.14 4,820.94 -358 -7.50 2,433,573.95 315,174.06 0.18 -3.29 2_CB-Film-MMS(2) 5,158.20 0.25 303,00 5,158,14 4,991.94 -3.20 -8.14 2,433,574.34 315,173.42 0.01 4.02 2-CB-Film-MMS(2) 5,347.20 0.25 245.00 5,347.14 -5,180.94 -3.15 446 2,433,574.41 315,172.70 0.13 4.59 2_CB-Film-MMS(2) 5,527.20 0.00 180.00 5,527.14 -5,360.94 5.31 -9.22 2,433,574.24 315,172.35 0.14 4.75 2_CB-Film-MMS (2) 5,707.20 0.25 325.00 5,707.14 -5,540.94 -2.99 -9.44 2,433,574.57 315,172.12 0.14 -5.13 2_CB-Film-MMS(2) 5,887.20 0.25 340.00 5,887,14 -5,720.94 -2.30 -9.80 2,433,575.27 315,171,78 0.04 -5.86 2_CB-Film-MMS(2) 6,067.20 0.25 340.00 6,067.14 5,900.94 -1.56 -10.07 2,433,576.01 315,171.52 0.00 -6.55 2_CS-Film-MMS(2) 6,247.20 0.25 26.00 6,247.14 6,080.94 -0,84 -10.03 2,433,576.73 315,171.57 0.11 -7.00 2_CB-Film-MMS (2) 6,427.20 0.75 329.00 6,427.13 .6,260.93 0.52 -10.47 2,433,578.10 315,171.16 0.36 -8.22 2_CB-Film-MMS (2) 6,607.20 1.25 312.00 6,607.10 -6,440.90 2.85 -12.53 2,433,580.45 315,169.13 0.32 -11.31 2_CB-Film-MMS (2) 6,787,20 1.25 305.00 6,787.06 -6,620.86 5.29 -15.60 2,433,582.94 315,166.10 0.08 -15.22 2_CB-Film-MMS(2) 6,967,20 1,00 304.00 6,967.02 -6,800.82 7.29 -18.51 2,433,584,99 315,163.22 0.14 -18.73 2_CB-Film-MMS(2) 7,147.20 1.25 289.00 7,146.99 -6,980.79 8.81 -21.67 2,433,586.56 315,160.08 0.21 -22.11 2_CB-Film-MMS(2) 7,327.20 1.50 291.00 7,325.94 -7,160.74 10.29 -25.73 2,433,588.10 315,156.05 0.14 -26.13 2_CB-Film-MMS.(2) 7,507.20 1.50 306.00 7,506.88 -7,340A6 12.52 -29.83 2,433,590.40 315,151.98 0.22 -30.69 2_CB-Film-MMS(2) 7,687.20 1.50 31000 7,686.81 -7,52061 15.42 -33.54 2,433,593.35 315,148.32 0.06 -35.39 2_CB-Film-MMS(2) 7,867.20 1.50 305.00 7,866.75 -7,700.55 18.29 -37.28 2,433,596.28 315,144,63 0.07 40.09 2_CB-Film-MMS(2) 8,047.20 1.25 310.00 8,046.70 -7,880.50 20.90 40.71 2,433,598.94 315,141.24 0.15 -04.40 2_CB-Film-MMS(2) 8,227.20 1.50 310.00 8,226.65 -8,060.45 23.68 44.02 2,433,601.77 315,137.97 0.14 -48]1 2_CB-Film4MS (2) 8,407.20 1.50 315.00 8,406.59 -8,240.39 26.86 47.49 2,433,605.01 315,134.55 0,07 -53.42 2_CB-Film-MMS (2) 8,587.20 1.50 321.00 8,586.53 -8,420.33 30.35 -50.64 2,433,608.55 315,131.46 0.09 -58.09 2_CB-Film-MMS (2) 8,767.20 2.00 324.00 8,766.44 -8,600.24 34.72 -53.97 2,433,612.98 315,128.20 0.28 -63.48 2_CB-FIIm-MSS(3) 8,79820 3.50 355.00 8,797.41 6,631.21 36.10 -5437 2,433,614.36 315,127.82 6.65 64.69 2_CB-Film-MSS(3) 8,830.20 3.50 344.00 8,829,35 -8,663.15 38,02 54.72 2,433,616.28 315,127.50 2.10 66.21 2_CB-Film-MSS(3) 8,860.20 4.75 20.00 8,859.27 4.693.07 40.06 -54.55 2,433,618.32 315,127.70 9.37 -67.43 2_CB-Film-MSS(3) 5/172019 1:51:48PM Pace 3 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Companv: protect: Site: Well: Wellbore: Design: Hiicorp Alaska, LLC Beaver Creek Unit Beaver Creek Unit Beaver CK Unit BCU 4RD BCU4RD Local Co-ordinate Reference: Well Beaver CK Unit 4 TVD Reference: BCU Planned RKB @ 166.20usft MD Reference: BCU Planned RKB @ 166.20usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US+CANADA Survey Map Map vertical MD Inc Azl TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) /ftl rftl ('/1007 /ftl Survey Tool Name 8,906.20 5.25 27.00 8,905.10 -8,738.90 43.73 -52.94 2,433,621.96 315,129.37 1.71 -68.64 2 -CB -Film -MSS (3) 8,984.20 6.00 27.00 8,982.72 -8,816.52 50.54 49.47 2,433,628.72 315,132.94 0.96 -70.52 2 -CB -Film -MSS (3) 9,187.20 7.75 35.00 9,184.26 -9,018.06 71.21 -36.80 2,433,649.18 315,145.93 0.98 -74.60 2_CB-Film-MSS(3) 9,362.20 9.25 4000 9,357.33 -9,191.13 91.65 -20.99 2,433,669.37 315,162.06 0.95 -76.18 2_CB-Film-MSS(3) 9,524.20 9.25 44.00 9,517.23 41,351.03 110.99 x.58 2,433,688.44 315,179.77 0.40 -75.82 2_CB-Film-MSS (3) 9,638.20 9.75 46.00 9,629.67 -9,463.47 124.29 9.73 2,433,70152 315,193.29 0.53 -74.56 2_CB-Fi1m-MSS(3) 9,780.20 10.75 50.00 9,769.40 -9.603.20 141.15 28.52 2,433,718.09 315,212.34 0.86 -71.54 2_CB-Film-MSS(3) 9,904.20 11.50 52.00 9,891.07 -9,724.87 156.20 47.12 2,433.732.84 315,231.18 0.68 -67.46 2 -CB -Film -MSS (3) 10,112.20 11.50 56.00 10,094.90 -9,928.70 180.56 80.65 2,433,756.67 315,265.08 0.38 58.28 2_CB-Film-MSS (3) 10,323.20 14.00 58.00 10,300.68 -10,134.48 205.85 119.74 2,433,781.34 315,304.56 1.20 45.54 2_CB-Film-MSS (3) 10,448.20 14.75 60.00 10,421.77 -10,255.57 221.82 146.34 2,433,796.89 315,331.41 0.72 -36.04 2_CB-Film-MSS (3) 10,545.20 14.50 62.00 10,515.62 -10,349.42 233.69 167.76 2,433,808.43 315,353.01 0.58 -27.76 2_CB-Film-MSS (3) 10,666.20 14.50 62.00 10,632.77 -10,466.57 247.91 194.51 2,433,822.23 315,379.97 0.00 -17.00 -2 CB -Film -MSS (3) 10,784.20 15.50 66.00 10,746.75 -10,580.55 261.26 221.96 2,433,835.15 315,407.63 1.22 -5.15 2_CB-Film-MSS(3) 10,830.20 15.50 66.00 10,791.08 -10,624.88 266.26 233.19 2,433,839.97 315.418.93 0.00 0.01 2_CB-Film-MSS (3) 10,934.20 1525 68.00 10,891.36 -10,725.16 277,4 258.57 2,433,850.35 315,444.47 0.56 12.0 2_CB-Film-MSS(3) 11,041.20 15.25 70.00 10,994.59 -10,828.39 287.12 284.84 2,433,860.02 315,470.90 0.49 25.12 2_CB-Film-MSS (3) 11,200.20 15.25 72.00 11,147.99 -10,981.79 300.74 324.37 2433,873.01 315,510.64 0.33 45.89 2_CB-Film-MSS(3) 11,291.20 15.75 74.00 11,235.68 -11,069.48 307.84 347.63 2,433,879.75 315,534.00 0.80 58.71 2 -CB -Film -MSS (3) 11,356.00 15.75 74.91 11,298.05 -11,131.85 312.55 36457 2,433,884.20 315,551.02 0.38 68.35 2_MWD_Interp Azi+Sag(4) 11,418.03 17.03 79.24 11,357.56 -11,191.36 316.44 381.63 2,433,887.82 315,568.13 2.85 78.62 2_ MWD_Interp Azl+Sag(4) 11,478.83 16.76 83.10 11,415.74 -11,249.54 319.16 399.08 2,433,890.26 315,585.62 1.90 89.96 2_MWD _Intem Ali+Sag(4) 11,541.46 17.48 86.97 11,475.59 -11,309.39 320.74 417.44 2,433,891.55 315,604.00 2.15 102.73 2_ p Azi MWD_Inter+Sag(4) 11,604.60 18.25 90.56 11,535.69 -11,369.49 321.14 436.79 2,433,891.65 315,623+36 2.13 117.02 2_MWD_Interp Azi+Sag(4) 11,667.40 19.37 93.83 11,595.14 -11,428.94 320.35 457.02 2,433,890.54 315,643.57 2.45 132.76 2_MWD_lnterp Azi+Sag(4) 11,729.87 20.09 9619 11,653.94 -11,487.74 318.39 478.01 2,433.888.25 315,664.62 1.97 149.84 2_MWD+IFR1+MS+Sag(5) 11,791.85 20.75 97.20 11,712.03 -11,545.83 315.76 49947 2,433,885.28 315,685.94 1.09 167.73 2_MWD+IFR1+MS+Sag(5) 11,854.81 20.83 102.78 11,770.89 -11,604.69 311.88 521.46 2,433,881.07 315,707.86 3.15 186.82 2_MWD+IFRI+MS+Ssg(5) 11,916.71 21.67 109.73 11,828.59 -11.662.39 305.59 542.95 2,433,874.44 315,729.25 4.29 207.13 2_MWD+IFR1+MS+Sag(5) 11,979.34 22.91 114.09 11,886.54 -11,720.34 29611 564.97 2,433,86521 315,751.13 330 229.55 2_MWD+IFR1+MS+Sag(5) 12,042.82 24.01 117.67 11,944.78 -11,778.58 285.67 587.69 2,433,853.82 315,773.67 2.84 253.91 2_MWD+IFRI+MS+Sag(5) 12,10296 25.71 121.06 11,999.35 -11,833.15 273.25 6D9.70 2433,841.06 315,795.48 3.69 27865 2_MWD+IFR1+MS+Sag(5) 12,166.38 27.34 124.87 12,056.09 -11,889.89 257.83 633.44 2,433,825.27 315,816.97 3.71 306.67 2_MWD+IFRI+MS+Sag(5) 12,228.44 28.48 129.08 12,110.94 -11,944.74 240.35 656.62 2,433,807.43 315,841.88 3.67 335.63 2_MWD+IFRI+MS+Sag(5) 12,291.13 30.45 131.24 12,165.52 -11,999.32 220.45 68D.17 2,433,787.16 315,865.11 3.57 366.45 2_MWD+IFRI+MS+Sag(5) 12,353.43 32.40 132.98 12,218.68 -12,052.48 198.66 704.25 2,433,765.00 315,888.85 3.45 398.92 2_MWD+IFR1+MS+Sag(5) 12,414.94 34.35 134.90 12,270.05 -12,103.65 175.18 728.60 2,433,741.14 315,912.83 3.61 432.72 2_MWD+IFRI+MS+Sag(5) 12,476.86 35.58 136.74 12,320.79 -12,154.59 149.73 753.32 2,433,71531 315,937.15 2.62 468.08 2_MWD+IFR1+MS+Sag(5) 12,539.31 35.57 135.78 12,371.58 -12,205.38 123.48 778.44 2,433,688.67 315,961.85 0.89 504.27 2_MWD+IFR1+MS+Sag(5) 12,600.30 35.52 134.70 12,421.21 -12,255.01 98.30 803.41 2,433,663.11 315.986.41 1.03 539.64 2_MWD+IFRI+MS+Sag(5) 5/172019 1:51:48PM Paas 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Coordinate Reference: Well Beaver CK Unit 4 Proiect: Beaver Creek Unit TVD Reference: BCU Planned RKB @ 166.20usft Site: Beaver Creek Unit MD Reference: BCU Planned RKB @ 166.20usft Well: Beaver CK Unit 4 North Reference: True Wellbore: BCU 4RD Survev Calculation Method: Minimum Curvature Design: BCU4RD Database: NORTH US+CANADA Survey MD Inc Aid TVD TVDSS (usft) V) (1) (usft) (usft) 12,663.02 34.70 134.48 12,472.52 -12,306.32 12,723.38 34.72 134.92 12,522.14 -12,355.94 12,786.09 36.05 137.54 12,573.26 -12,407.06 12,846.99 36.87 140.13 12,622.25 -12,456.05 12,907.68 37.47 141.21 12,670.61 -12,504.41 12,968.69 37.93 142.39 12,718.88 -12,552.68 13,030.98 38.24 142.40 12,767.91 -12,601.71 13,092.33 37.42 141.65 12,816.37 -12,650.17 13,152.23 37.04 143.11 12,864.06 -12,69].86 13,217.63 36.99 143.90 12,916.28 -12,750.08 13,278.78 3790 145.01 12,964.63 -12,798.63 13,340.39 38.76 144.82 13,013.16 -12,846.96 13,401.56 39.94 146.21 13,060.46 -12,894.26 13,464.37 40.47 147.66 13,108.43 -12,942.23 13,526.19 41.62 14TEM. 13,155.06 -12,988.86 13,589.05 43.00 146.43 13,201.54 -13,035.34 13,649.96 44.26 145.67 13,245.64 -13,079.44 13,71157 4 Aii 144.62 13,289.49 -13,123.29 13,774.30 44.45 143.98 13,334.07 -13,167.87 13,834.71 44.24 143.13 13,377.28 -13,211.08 13,898.31 44.35 142.52 13,422.80 -13,256.60 13,959.19 44.01 141.92 13,466.46 -13,300.26 14,022.20 43.50 140.98 13,511.97 -13,345.77 14,085.41 43.16 140.15 13,557.95 -13,391.75 14,147.14 42.64 139.81 13,603.17 -13,436.97 Map Map +N/S +El -W Northing Fasting DLS (usft) (usft) Iffl (f11 (-/ion.) 72.98 829.10 2,433,637.38 316,011.70 1.32 48.80 853.53 2,433,612.83 316,035.75 0.42 22.58 878.63 2,433,586.21 316,060.44 3.22 4.67 90244 2,433,558.60 316,083.82 2.86 -33.03 925.68 2,433,529.88 316,106.61 1.46 -62.35 948.75 2,433,500.20 316,129.21 1.40 -92.79 972.20 2,433,469.40 316,152.18 0.50 -122.45 995.35 2,433,439.38 316,174.86 1.53 -151.15 1,017.47 2,433,410.34 316,196.53 1.61 -182.81 1040.88 2,433,378.33 316,219.44 0.73 -213.06 1,062.49 2,433;34].74 316,240.57 1.85 -244.32 1,084.46 2,433,316.14 316,262.04 1.41 -276.29 1,106.41 2,433,283.83 316,283.49 2.41 -310.27 1,128.53 2,433,249.51 316,305.07 1.71 -344.45 1,150.43 2,433,215.00 316,326.43 1.97 -379.83 1,173.64 2,433,179.26 316,349.09 2.29 414.70 1,197.12 2,433,144.03 316,372.02 2.24 450.19 1,221.84 2,433,108.16 316,396.18 1.65 486.03 1,247.59 2,433,071.92 316,421.36 1.08 -519.99 1,272.67 2,433,037.57 316,445.91 1.04 -555.36 588.92 -623.00 -656.50 -688.68 14,210.83 42.34 141.17 13,650.14 -13,483.94 -721.86 14,272.07 41.91 141.64 13,695.56 -13,529.36 -753.97 14,334.49 41.22 141.22 13,742.26 -13,576.06 -786.35 14,396.14 40.80 140.00 13,788.78 -13,622.58 -817.61 14,457.23 41.11 141.02 13,834.92 -13,668.72 -848.51 14,519.19 41.48 141.98 13,881.47 -03,715.27 -880.51 14,582.57 41.70 14225 13,92887 -13,762.67 -913.72 14,645.60 41.66 141.44 13,975.95 -13,809.75 -946.68 14,707.25 41.29 141.13 14,022.14 -13,855.94 -978.54 14,767.65 40.53 140.58 14,067.79 -13,901.59 -1,009.21 14,831.13 39.85 140.71 14,116.28 -13,950.08 -1,040.89 14,893.49 39.28 139.83 14,164.35 -13,998.15 -1071.44 14,955.29 38.77 139.66 14,212.36 -14046.16 -1,101.13 15,018.38 37.90 139.67 14,261.85 -14,095.65 -1,130.96 15,080.94 37.47 138.73 14,311.36 -14,145.16 -1,159.91 1,299.51 2,433,001.77 1,325.50 2,432,967.83 1,352.66 2,432,933.33 1,380.21 2,432,899.41 1,407.23 2,432,866.81 1,434.60 2,432,833.20 1,460.22 2,432,800.70 1,486.04 2,432,767.92 1,51111 2,432,736.26 1,537.18 2,432,704.96 1,562.63 2,432,672.57 1,58846 2,432,638.97 1,614.36 2,432,605.61 1,639.89 2,432,573.36 1,664.86 2,432,542.29 1,690.84 2,432,510.22 1,716.23 2,432,479.28 1,741.37 2,432,449.19 1,766.70 2,432,418.97 1,791.69 2,432,389.63 316,472.18 316,497.65 316,524.26 316,551.28 316,577.79 316,604.64 316,629.75 316,655.06 316,680.24 316,705.21 316,730.16 316,755.47 316,780.84 316,805.87 316,830.35 316,855.83 316,880.73 316,905.41 316,930.26 316,954.79 0.69 0.89 1.31 1.05 0.92 vertical Section Iftl Survey Tool Name 575.65 2_MWD+IFRI+MS+Sag(5) 609.96 2_MWD+IFRI+MS+Sag(5) 646.12 2_MWD+IFRI+MS+Sag(5) 681.98 2_MWD+IFRI+MS+Sag(5) 718.15 2_MWD+IFRI+MS+Sag(5) 754.82 2_MWD+IFRI+MS+Sag(5) 792.51 2_MWD+IFRI+MS+Sag (5) 829.47 2_MWD+IFRI+MS+Sag(5) 865.02 2_MWD+IFRI+MS+Sag(5) 903.49 2_MWD+IFRI+MS+Sag(5) 939.68 2_MWD+IFRI+MS+Sag(5) 976.80 2_MWD+IFRI+MS+Sag(5) 1,014.38 2_MWD+IFRI+MS+Sag(5) 1,053.41 2_MWD+IFRI+MS+Sag (5) 1,092.40 2_MWD+IFRI+MS+Sag(51 1,133.17 2_MWD+IFRI+MS+Sag(5) 1,173.81 2_MWD+IFRI+MS+Sag (5) 1,215.79 2_MWD+IFRI+MS+Sag(5) 1,258]7 2_MWD+IFRI+MS+Sag(5)M 1,300.02 2_WD+IFRI+MS+Sag(5) 1,343.52 2_MWD+IFRI+MS+Sag(5) 1,385.17 2_MWD+IFRI+MS+Sag(5) 1,428.05 2_MWD+IFRI+MS+Sag(5) 1,470.84 2_MWD+IFRI+MS+Sag(5) 1,512.37 2_MWD+IFRI+MS+Sag(5) 1.52 1,554.83 2 MWD+IFRI+MS+Sag(5) 0.87 1,595.26 2_MWD+IFRI+MS+Sag(5) 1.19 1,636.01 2_MWD+IFRI+MS+8ag (5) 1.47 1,675.92 2_MWD+IFRI+MS+Sag(5) 121 171544 2_MWD+IFRI+M3+Sag(5) 1.18 1,755.67 2_MWD+IFRI+MS+Sag(5) 0.45 1,796.98 2 MWD+IFRI+MS+Sag(5) 0.86 1,838.17 2_MWD+IFRI+MS+Sag(5) 0.69 1,878.37 2_MWD+IFRI+MS+Sag(5) 1.39 1,917.37 2_MWD+IFRI+MS+Sag(5) 1.08 1,957.78 2_MWD+IFRI+MS+Sag(5) 1.28 1,997.00 2_MWD+IFRI+MS+Sag(5) 0.84 2,035.48 2_MWD+IFRI+MS+Sag(5) 1.38 2,074.19 2_MWD+IFRI+MS+Sag(5) 1.15 2,112.06 2_MWD+IFRI+MS+Sag(5) 5/172019 1:51:48PM Pam 5 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Beaver Creek Unit Site: Beaver Creek Unit Well: Beaver CK Unit 4 Wellbore: BCU 4RD Design: BCU 4RD Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Referenw: Survev Calculation Method: Database: Well Beaver CK Unit 4 BCU Planned RKB @ 166.20usft BCU Planned RKB @ 166.20usft True Minimum Curvature NORTH US + CANADA Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) lft1 Ift1 (°/100') Ikl Survey Tool Name 15,142.56 36.75 137.82 14,360.50 -14,194.30 -1,187.66 1,816.43 2,432,361.50 316,979.10 1.47 2,148.96 2_MWD+IFRI+MS+Sag(5) M 15,228.41 37.04 138.74 14,429.16 -14,262.96 -1,226.13 1,850.73 2,432,322.50 317,012.78 0.73 2,200.10 2_WD+IFRI+MS+Sag(6) 15,290.84 36.86 139.67 14,479.05 -14,312.85 -1,254.54 1,875.24 2,432,293.71 317,036.85 0.94 2,237.26 2_MWD+IFR1+MS+Sag(6) 15,353.66 35.65 139.81 14,529.71 -14,363.51 -1,282.89 1,899.25 2,432,264.99 317,060.41 1.93 2,274 M00 2_WD+IFRI+MS+Sag(6) 15,414.97 35.21 141.27 14,579.67 -14,413.47 -1,310.33 1,921.84 2,432,237.21 317,082.57 1.56 2,309.07 2_MWD+IFRI+MS+Sag(6) 15477.74 34.61 141.61 14,631.14 -14,464.94 -1,338.42 1,944.23 2,432,208.77 317,104.52 1.00 2,344.42 2_MWD+IFRI+MS+Sag(6)M 15,538.87 32.73 141.72 14,682.01 -14,515.81 -1,365.00 1,965.26 2,432,181.86 317,125.12 3.08 2,377.75 2_WD+IFR1+MS+Sag(6) 15,60074 33.02 142.86 14,733.97 -14,567.77 -1,391.57 1,985.80 2,432,154.98 317,145.24 1.10 2,410.71 2_MWD+IFR1+MS+Sag(6) 15,661.88 33.74 143.06 14,785.03 -14,618.83 -1,418.42 2,006.06 2,432,127.82 317,165.07 1.19 2,443.64 M 2_WD+IFRI+MS+Sag(6) 15,723.41 33.74 143.19 14,836.20 -14,670.00 -1,445.76 2,026.57 2,432,100.16 317,185.15 0.12 2,477.08 2_MWD+IFRI+MS+Sag(6) 15,786.03 33.15 143.47 14,888.45 -14,722.25 -1,473.44 2,047.18 2,432,072.16 317,205.32 0.97 2,510.82 2_MWD+IFR1+MS+Sag(6) 15,848.61 32.23 143.00 14,941.11 -14,774.91 -1,500.51 2,067.40 2,432,044.77 317,225.12 1.53 2,543.88 2_MWD+IFRI+MS+Sag(6) 15,910.58 31.67 143.44 14,993.70 -14,827.50 -1,526.78 2,087.04 2,432,018.21 317,244.34 0.98 2,575.95 2_MWD+IFR1+MS+Sag(6) 15,971.29 31.37 143.75 15,045.45 -14,879.25 -1,552.32 2,105.68 2,431,992.37 317,262.78 0.56 2,606.95 2_MWD+IFRI+MS+Sag (6) 16,034.44 29.68 143.29 15,099.79 -14,933.59 -1,578.19 2,125.00 2,431,966.21 317,281.49 2.39 2,638.38 2_MWD+IFR1+MS+Sag(6) 16,096.63 28.90 142.73 15,153.97 -14,987.77 -1,602.57 2,143.36 2,431,941.55 317,299.47 1.64 2,668.26 2_MWD+IFR1+MS+Sag(6) 16,158.69 28.64 142.55 15,208.37 -15,042.17 -1,626.31 2,161.49 2,431,917.53 317,317.21 0.44 2,697.53 2_MWD+IFRI+MS+Sag(6) 16,218.80 29.15 142.03 15,261.00 -15,094.80 -1,649.29 2,179.25 2,431,894.27 317,334.62 0.95 2,726.04 2_MWD+IFRI+MS+Sag(6) 16,280.97 28.86 140.40 15,315.37 -15,149.17 -1,672.79 2,198.13 2,431,870.49 317,353.13 1.35 2,755.72 2_MWD+IFRI+MS+Sag(6) 16,342.95 26.49 137.55 15,370.26 -15,204.06 -1,694.51 2,217.00 2,431,848.46 317,371.65 4.38 2,784.23 2_MWD+IFRI+MS+Sag(6) 16,406.02 21.93 134.54 15,427.77 -15,261.57 -1,713.16 2,234.90 2,431,829.54 317,389.25 7.49 2,809.98 2_MWD+IFR1+MS+Sag(6) 16,469.82 19.54 134.92 15,487.43 -15,321.23 -1,729.06 2,250.95 2,431,813.40 317,405.05 3.75 2,832.53 2_MWD+IFRI+MS+Sag(6) 16,531.34 17.54 132.54 15,545.76 -15,379.56 -1,742.59 2,265.06 2,431,799.64 317,418.95 3.48 2,852.06 2_MWD+IFRI+MS+Sag(6) 16,591.98 15.89 129.13 15,603.84 -15,437.64 -1,754.01 2,278.24 2,431,788.02 317,431.94 3.16 2,869.50 2_MWD+IFRI+MS+Sag(6) 16,603.96 15.31 128.41 15,615.37 -15,449.17 -1,756.03 2,280.75 2,431,785.96 317,434.42 5.10 2,872.71 2_MWD+IFRI+MS+Sag(6) 16,642.00 15.31 128.41 15,652.06 -15,485.86 -1,762.27 2,288.62 2,431,779.60 317,442.19 0.00 2,882.75 PROJECTEDWTD Checked By: Mitch Laird - = Approved By: Benjamin Hand=" Date: 5.17.19 511712019 1:51:48PM Pepe 6 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Beaver Creek Unit Beaver Creek Unit BCU 4RDPB1 BCU4RDPB1 501332023972 Sperry Drilling Definitive Survey Report 23 May, 2019 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcam Alaska, LLC Local Corordinate Reference: Well Beaver CK Unit 4 Protect: Beaver Creek Unit TVD Reference: BCU Planned RKB @ 166.20usft Site: Beaver Creek Unit MO Reference: BCU Planned RKB @ 166.20usft Well: Beaver CK Unit 4 North Reference: True Wellbore: BCU4RDPB1 Survey Calculation Method: Minimum Curvature Design: BCU 4RDPB1 Database: NORTH US+CANADA Project Beaver Creek Unit Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well Beaver CK Unit 4 Magnetics Model Name Sample Data Declination Well Position +N/ -S 0.00 usft Northing: 2,433,577.41 usft Latitude: 60" 39'25.8089 N 15.54 +EI -W 0.00 usft Eastinq: 315,181.61 usft Longitude: 151' V48.4891 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 148.20 usft Wellbore BCU 4RDPB1 Magnetics Model Name Sample Data Declination Dip Angle Field Strength W) BGGM2018 3/10/2019 15.54 73.60 55,282.79141995 Design BCU 4RDP81 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 12,017.20 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) M 18.00 0.00 0.00 147.58 Survey Program Date 4/25/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 202.20 2,802.20 BCU-04PB1 GMS (BCU 04PB1) 2_CB-Film-GMS A022Ga: Film camera gyro multi -shot 11/27/1972 3,187.20 8,587.20 BCU-04PBI CS -MMS (BCU 04PBlI 2_CB-Film-MMS A024Ma: Film camera magnetic multi -shot 11/27/1972 8,767.20 12,017.20 BCU-04PB2 CS -MSS (BCU 04PB21 2_CB-Film-MSS H057Ma: Film camera magnetic single shot 11/27/1972 12,030.00 12,280.66 BCU 4RDPB1 Intep Azi(BCU 4RDP81) 2_MWD_Interp Azi+Sag H003Mb: Interpolated azimuth +sag correction 03/17/2019 12,340.77 14,202.98 BCU 4RDPB1 MWD+IFRI+MS+Saq(BCU 2_MWD+IFRI+MS+Sag A010Mb: IFR dec&multi-station analysis+sag 03/25/2019 Survey Map Map vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting OLS Section (usft) (°) V) (usft) (usft) (usft) (usft) Ift) !ft1 (°1100•) rel Survey Tool Name 18.00 0.00 0.00 18.00 -148.20 0.00 090 2,433,577.41 315,181.61 0.00 0.00 UNDEFINED 202.20 0.00 180.00 202.20 36.00 0.00 0.00 2,433,577.41 315,181.61 0.00 0.00 2_CB-Film-GMS(1) 402.20 0.50 244.00 402.20 236.00 -038 41.78 2,433,577.04 315,180.82 0.25 -0.10 2_CB-Film-GMS(1) 602.20 0.25 280.00 602.19 435.99 -0.69 -2.00 2,433,576.75 315,179.61 0.17 -0.49 2-CS-Film-GMS(1) 802.20 0.25 256.00 802.19 635.99 -0.72 -2.85 2,433,576.74 315,178.75 0.05 -0.92 2_CB-FIIm-GMS(1) 1,002.20 0.33 348.00 1,002.19 83599 -0.26 -3.39 2,433,577.20 315,178.22 0.21 -1.60 2_CB-Film-GMS(1) 1,202.20 033 325.00 1,202.19 1,035.99 0.77 -3.84 2,433,578.25 315,177.78 0.07 -2.71 2_CB-Film-GMS(1) 1,402.20 0.50 250.00 1,402.18 1,235.98 0.95 -5.00 2,433,578.44 315,176.63 0.26 -3.48 2_C&Film-GMS(1) 1,602.20 0.00 180.00 1,602.18 1,43598 0.65 -5.82 2,433,578.15 315,175.81 0.25 -3.67 2_CB-FI1mGMS(1) 1,802.20 0.25 130.00 1,802.18 1,635.98 0.37 -5.48 2,433,577.87 315,176.14 0.12 -3.25 2_CB-Film-GMS(1) 523/2019 1:47:09PM Pace 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well Beaver CK Unit 4 Project: Beaver Creek Unit TVD Reference: BCU Planned RKB @ 166.20usft Site: Beaver Creek Unit MD Reference: BCU Planned RK13 @ 166.20usft Well: Beaver CK Unit 4 North Reference: True Wellbore: BCU 4ROP81 Survev Calculation Method: Minimum Curvature Design: BCU 4RDPB7 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting OLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) IRl Ift) (°/1001 Ift1 Survey Tool Name 2,00220 0.17 15.00 2,002.18 1,835.98 0.37 -5.07 2,433,577.87 315,176.55 0.18 -303 2_CB-Film-GMS(1) 2,202.20 0.25 100.00 2,202.18 2,035.98 0.59 4.56 2,433,578.07 315,177.06 0.14 -2.94 2_CB-FilmGMS(1) 2,402.20 0.17 20.00 2,402.18 2,235.98 0.79 4.03 2,433,578.26 315,177.59 0.14 -2.83 2_CB-Film-GMS(1) 2,602.20 0.08 240.00 2,602.18 2,43598 100 4.06 2,433,578.47 315,177.58 0.12 -3.01 2 -CB-Film-GMS (1) 2,802.20 0.50 179.00 2,802.17 2,635.97 0.05 4.16 2,433,577.63 315,177.46 0.23 -2.28 2 CB -Film -GMS (1) 3,187.20 0.25 296.00 3,187.17 3,020.97 -1.26 4.88 2,433,576.23 315,176.71 0.17 -1.56 2_CB-Film-MMS(2) 3,367.20 0.00 0.00 3,367.17 3,200.97 -1.08 -5.24 2,433,576.41 315,176.36 0.14 -1.89 2_CB-Film-MMS(2) 3,547.20 0.25 35.00 3,547.17 3,380.97 -0.76 5.01 2,433,576.73 315,176.59 0.14 -2.04 2_CB-Film-MMS (2) 3,727.20 0.25 100.00 3,727.17 3,560.97 -0.51 4.40 2,433,576.97 315,177.21 0.15 -1.93 2-CB-Film-MMS(2) 3,907.20 0.00 180.00 3,907.17 3,740.97 -0.58 4.01 2,433,576.90 315,177.59 0.14 -1.66 2_CB-Fi1m-MMS(2) 4,087.20 0.25 90.00 4,087.16 3,920.96 -0.58 -3.62 2,433,576.89 315,177.99 0.14 -1.45 2_CB-Film-MMS (2) 4,267.20 0.50 210.00 4,267.16 4,100.96 -1.26 -3.62 2,433,576.21 315,177.98 0.37 -0.88 2_CB-Film-MMS(2) 4,447.20 0.50 2WA0 4,447.16 4,280.96 -2.44 4.61 2,433,575.04 315,176.96 0.10 -0.41 2_CB-Film-MMS(2) 4,627.20 0.25 209.00 4,627.15 4,460.95 -3.29 -5.41 2,433,574.21 315,176.16 0.16 -0.12 2-CB-Film-MMS(2) 4,807.20 0.50 265.00 4,807.15 4,640.95 -3.70 0.38 2,433,573.81 315,175.18 0.23 -0.29 2_CB-Film-MMS (2) 4,987.20 0.25 299.00 4,987.14 4,820.94 -3.58 -7.50 2,433,573.95 315,174.06 0.18 -1.00 2 -CB -Film -MMS (2) 5,158.20 0.25 303.00 5,158.14 4,991.94 -3.20 -8.14 2,433,574.34 315,173.42 0.01 -1.67 2_CB-Film-MMS(2) 5,347,20 0.25 245.00 5,347.14 5,180.94 -3.15 -8.86 2,433,574.41 315,172.70 0.13 -2.10 2_CB-Film-MMS(2) 5,527.20 0.00 180.00 5,527.14 5,360.94 -3.31 -9.22 2,433,574.24 315,172.35 0.14 -2.15 2_CB-Film-MMS (2) 5,707.20 0.25 325.00 5,707.14 5,540.94 -2.99 -9.44 2,433,574.57 315,172.12 0.14 -2.54 2_CB-Film-MMS(2) 5,887.20 0.25 340.00 5,887.14 5,720.94 -2.30 -9.80 2,433,575.27 315,171.78 0.04 5.31 2_CB-FIlm-MMS(2) 6,067.20 0.25 340.00 6,067.14 5,900.94 -1.56 -10.07 2,433,576.01 315,171.52 0.00 4.08 2_CB-Film-MMS (2) 6,247.20 0.25 26.00 6,247.14 6,080.94 -0.84 -10.03 2,433,576.73 315,171.57 0.11 4.67 2_CB-Film-MMS(2) 6,427.20 0.75 329.00 6,427.13 6,260.93 0.62 -10.47 2,433,578.10 315,171.16 0.36 -6.05 2_CB-Film-MMS(2) 6,607.20 1.25 312.00 6,607.10 6,440.90 2.85 -12.53 2,433,580.45 315,169.13 0.32 -9.12 2 -CB -Film -MMS (2) 6,787.20 1.25 305.00 6,787.06 6,620.86 5.29 -15.60 2,433,582.94 315,166.10 0.08 -12.83 2_CB-Film-MMS (2) 6,967.20 1.00 304.00 6,967.02 6,800.82 7.29 -18.51 2,433,584.99 315,163.22 0.14 -16.08 2 -CB -Film -MMS (2) 7,147.20 1.25 289.00 7,146.99 6,980.79 8.81 -21.67 2,433,586.56 315,160.08 0.21 -19.05 2_CB-Film-MMS(2) 7,327.20 1.50 291.00 7,326.94 7,160.74 10.29 -25.73 2,433,588.10 315,156.05 0.14 -22.48 2_CB-Film-MMS(2) 7,507.20 1.50 306.00 7,506.88 7,340.68 12.52 -29.83 2,433,590.40 315,151.98 0.22 -26.56 2_CB-Film-MMS(2) 7,687.20 1.50 310.00 7,686.81 7,520.61 15.42 -33.54 2,433,593.35 315,148.32 006 -31.00 2_CB-Film-MMS(2) 7,867.20 1.50 305.00 7,866.75 7,700.55 18.29 -37.28 2,433,596.28 315,144.63 0.07 -35.42 2_CB-Film-MMS(2) 8,047.20 1.25 310.00 8,046.70 7,880.50 20.90 40.71 2,433,598.94 315,141.24 0.15 -39.47 2 -CB -Film -MMS (2) 8,227.20 1.50 310.00 8,226.65 8,060.45 23.68 44.02 2,433,601.77 315,137.97 0.14 43.59 2_CB-Film-MMS (2) 8,407.20 1.50 315.00 8,406.59 8,240.39 26.86 47.49 2,433,605.01 315,134.55 0.07 -48.13 2_CB-Film-MMS(2) 8,587.20 1.50 321.00 8,586.53 8,420.33 30.35 -50.64 2,433,60855 315,131.46 0.09 -5217 2_CB-Film-MMS(2) 8,767.20 2.00 324.00 8,766.44 8,600.24 34.72 -53.97 2,433,612.98 315,128.20 0.28 -58.25 2_CB-Film-MSS(3) 8,798.20 3.50 355.00 8,797.41 8,631.21 36.10 -54.37 2,433,614.36 315,127.82 6.65 -59.63 2_CB-Film-MSS (3) 8,830.20 3.50 344.00 8,829.35 8,663.15 38.02 54.72 2,433,616.28 315,127.50 2.10 -61.43 2_CB-Film-MSS(3) 8,860.20 4.75 2000 8,859.27 8,693.07 40.06 -54.55 2,433,618.32 315,127.70 9.37 -63.07 2_CB-Film-MSS(3) 51232019 1:47:09PM Page 3 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Comoanv: Protect: Site: Well: Wellbore: Deslon: Hilcorp Alaska, LLC Beaver Creek Unit Beaver Creek Unit Beaver CK Unit 4 BCU 4RDPB1 BCU 4RDPB1 Local Coordinate Reference: Well Beaver CK Unit 4 TVD Reference: BCU Planned RKB @ 166.20usfi MD Reference: BCU Planned RKB @ 166.20usft North Reference: True Survev Calculation Method: Minimum Curvature Database: NORTH US+CANADA Survey Map Map vertical MD Inc Azi TVD NDSS +N/ -S +FJ -W Northing Easting DLS Section (usft) (I (°) (usft) (usft) (usft) (usft) Ift1 Ifn (°/100') Iftl Survey Tool Name 8,906.20 5.25 27.00 8,905.10 8,738.90 43.73 52.94 2,433,621.96 315,129.37 1.71 -65.30 2 -CB -Film -MSS (3) 8,984.20 6.00 27.00 8,982.72 0.816.52 50.54 49.47 2,433,628.72 315,132.94 0.96 -69.19 2_CB-Film-MSS(3) 9,187.20 7.75 35.00 9.184.26 9,018.06 71.21 -36.80 2,433,649.18 315,145.93 0.98 -79.84 2_CB-Film-MSS(3) 9.362.20 9.25 40.00 9,357.33 9,191.13 91.65 -20.99 2,433,669.37 315,162.06 0.95 -88.62 2_CB-Film-MSS(3) 9,524.20 9.25 44.00 9,517.23 9,351.03 110.99 -3.58 2,433,688.44 315,179.77 0.40 -95.61 2 -CB -Film -MSS (3) 9,63820 9.75 4600 9,629.67 9,463.47 124.29 9.73 2,433,701.52 315,193.29 0.53 -99.70 2_GB-Film-MSS(3) 9,780.20 10.75 50.00 9,769.40 9,603.20 141.15 28.52 2,433,718.09 315,212.34 0.86 -103.86 2_CB-Film-MSS(3) 9,904.20 11.50 52.00 9,891.07 9,72487 156.20 47.12 2,433,732.84 315,231.18 0.68 -106.59 2_CB-Film-MSS(3) 10,112.20 11.50 56.00 10,094.90 9,928.70 180.56 80.65 2,433,756.67 315,265.08 0.38 -109.18 2 CB-Film-MSS(3) 10,323.20 14.00 58.00 10,300.68 10,134.48 205.85 11974 2,433,781.34 315,304.56 1.20 -109.57 2_CB-Film-MSS(3) 10,440.20 14.75 60.00 10,421.77 10,255.57 221.82 146.34 2,433,796.89 315,331.41 0.72 -108.79 2_CB-Film-MSS(3) 10,545.20 14.50 62.00 10,515.62 10,349.42 233.69 167.76 2,433,808.43 315,353.01 0.58 -107.33 2_C13 -Film -MSS (3) 10,666.20 14.50 62.00 10,632.77 10,466.57 247.91 194.51 2,433,822.23 315,379.97 0.00 -104.99 2_CB-Film-MSS (3) 10,784.20 15.50 66.00 10,746.75 10,580.55 261.26 221.96 2,433,835.15 315,407.63 1.22 -101.55 2 -CB -Film -MSS (3) 10,830.20 15.50 66.00 10,791.08 10,624.88 266.26 233.19 2,433,839.97 315,418.93 0.00 -99.75 2_CB-FIm-MSS(3) 10,934.20 15.25 68.00 10,891.36 10,725.16 277.04 258.57 2,433,850.35 315,444.47 0.56 -95.24 2_CB-FIImMSS (3) 11,041.20 15.25 70.00 10,994.59 10,828.39 2717.12 284.84 2,433,860.02 315,470.90 0.49 -89.67 2_CB-Film-MSS (3) 11,200.20 15.25 7200 11,147.99 10,981.79 30034 32437 4433,873.01 315,510.64 0.33 -79.96 2 -CB -Film -MSS (3) 11,291.20 15.75 74.00 11,235.68 11,069.48 307.84 347.63 2,433,879.75 315,534.00 0.80 -73.49 2_CB-Film-MSS (3) 11,439.20 15.75 76.00 11,378.13 11,211.93 318.24 386.43 2,433,889.53 315,572.96 0.37 -61.46 2_CB-Film-MSS (3) 11,564.20 15.25 78.00 11,498.58 11,332.38 325.76 418.97 2,433,896.55 315,605.61 0.59 -50.37 2_CB-Film-MSS (3) 11,668.20 15.25 80.00 11,598.92 11,432.72 330.98 445.82 2,433,901.34 315,632.54 0.51 40.38 2_GB-Film-MSS (3) 11,763.20 15.25 80.00 11,690.57 11,524.37 335.32 470.43 2,433,906.29 315,657.21 0.00 -30.85 2_CB-Film-MSS (3) 11,837.20 15.00 82.00 11,762.01 11,595.81 338.34 489.49 2,433,906.02 315,676.32 0.78 -23.18 2_CB-FIm-MSS(3) 11,931.20 14.75 85.00 11,852.86 11,686.66 341.08 513.46 2,433,910.38 315,700.33 0.86 -12.64 2_CB-Film-MSS (3) 12,017.20 14.75 86.00 11,936.03 11,769.83 342.79 535.29 2,433,911.75 315,722.18 0.30 -2.39 2 -CB -Film -MSS (3) 12,030.00 14.70 86.29 11,948.41 11,782.21 343.01 538.53 2,433,911.92 315,725.43 0.70 -0.83 2_MWD_Interp Azi+Sag(4) 12,094.01 14.35 94.58 12,01038 11,844.18 342.90 554.55 2,433,911.56 315,741.43 3.29 7.85 2_MWD_Interp Azi+Sag(4) 12,153.10 15.41 102.05 12,067.49 11,901.29 340.68 569.53 2,433,909.10 315,756.37 3.71 17.75 2_ MWD_Interp Azi+Sag(4) 12,216.72 17.02 109.13 12,128.58 11,962.38 335.86 586.59 2,433,904.02 315,773.36 4.00 30.97 2_ MWD_Interp Azi+Sag(4) 12,280.66 18.50 115.32 12,189.48 12,023.28 328.46 604.61 2,433,896.33 315791.26 3.75 46.88 2_MWD_Inteip Azi+Sag(4) 12,340.77 18.66 120.64 12,246.46 12,080.26 31948 621.50 2,433,887.09 315,808.01 2.83 63.52 2_MWD+IFRI+MS+Sag(5) 12,402.46 19.78 117.39 12,304.71 12,138.51 309+65 63926 2,433,876.98 315,825.61 2.51 81.34 2_MWD+IFRI+MS+Sag(5) 12,465.07 21.14 116.82 12,363.37 12,197.17 299.68 658.74 2,433,866.71 315,844.93 2.20 100.20 2_MWD+IFRI+MS+Sag(5) 12,526.88 21.93 120.39 12,420.87 12,254.67 288.81 678.65 2,433,855.53 315,864.66 2.48 120.04 2_MW0+IFR1+MS+Sag(5) 12,588.32 22.58 124.73 12,477.74 12,311.54 276.28 698.24 2,433,842.70 315,884.06 2.88 141.12 2_MWD+IFRI+MS+Sag(5) 12,650.84 22.75 130.11 12,535.44 12,369.24 261.66 717.35 2,433,827.78 315,902.94 3.33 163.71 2_MWD+IFR1+MS+Sag(5) 12,710.84 23.55 135.43 12,590.61 12,424.41 245,64 734.64 2,433,811.49 315,919.97 3.73 186.50 2_MWD+IFR1+MS+Sag(5) 12,772.95 24.34 139.06 12,647.38 12,481.18 227.13 751.74 2,433,792.72 315,936.77 2.69 211.29 2_MWD+IFR1+MS+Sag(5) 12,837.18 2683 141.45 12,705.31 12,539.11 205.79 769.45 2,433,771.11 315,954.14 4.20 238.80 2_MWD+IFR1+MS+Seg(5) 5/23/2019 1:47:09PM Paae 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Companv: Project: Site: Well: Wellbore: Desipn: Hilcorp Alaska, LLC Beaver Creek Unit Beaver Creek Unit Beaver CK Unit 4 BCU 4RDPB1 BCU 4RDPB1 Local Coordinate Reference: TVD Reference: MD Reference: North Reference: Survev Calculation Method: Database: Well Beaver CK Unit 4 BCU Planned RKB @ 166.20usfi BCU Planned RKB @ 166.20us0 True Minimum Curvature NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N4S +E/.W Northing Easting DLS Section (usft) (') (1) (usft) (usft) (usft) (usft) 1111 1111 (°1100) (111 Survey Tool Name 12,898.83 28.54 140.88 12,759.90 12,593.70 183.48 787.41 2,433,746.52 315,971.75 2.81 267.26 2_MWD+IFR1+MS+Sag(5) 12,960.77 30.95 141.75 12,813.67 12,647.47 159.49 806.61 2,433,724.23 315,990.57 3.95 297.81 2_MWD+IFRI+MS+Sag(5) 13,022.48 31.45 144.55 12,866.46 12,700.26 133.92 825.77 2,433,698.36 316,009.33 2.49 329.67 2_MWD+IFRI+MS+Sag(5) 13,094.45 32.56 147.86 12,919.01 12,752.81 106.62 84402 2,433,67039 316,027.15 3.35 36249 2_MWD+IFRI+MS+Sag(5) 13,147.37 34.57 150.14 12,971.44 12,805.24 76.80 861.92 2,433,640.69 316,044.58 3.77 39726 2_MWD+IFR1+MS+Seg(5) 13,209.95 36.10 151.16 13,022.49 12,856.29 4525 879.65 2,433,608.87 316,061.81 2.62 433.40 2_MWD+IFR1+MS+Sag(5) 13,271.75 38.37 151.97 13,071.69 12,905.49 12.37 897.45 2,433,575.71 316,079.09 3.76 470.70 2_MWD+IFR1+MS+Sag(5) 13,334.11 41.10 152.52 13,119.64 12,953.44 -22.91 916.01 2,433,540.15 316,097.09 4.41 51043 2_MWD+IFRI+MS+Sag(5) 13,393.46 43.28 153.28 13,163.61 12,997.41 -58.39 934.16 2,433,504.39 316,114.69 3.77 550.11 2_MWD+IFRI+MS+Sag(5) 13,457.08 45.31 154.33 13,209.15 13,042.95 -98.26 953.76 2,433,464.23 316,133.66 3.39 594.27 2_MWD+IFR1+MS+Sag(5) 13,518.36 47.57 154.48 13,251.37 13,085.17 -138.30 972.94 2,433,423.89 316,152.21 3.69 638.36 2_MWD+IFR1+MS+Sag(5) 13,581.26 49.16 155.40 13,293.16 13,126.96 -180.89 992.85 2,433,381.00 316.171.45 2.75 684.98 2_MWD+IFR1+MS+Sag(5) 13,642.56 50.76 157.16 13,332.60 13,166.40 -223.85 1,011.72 2,433,337.74 316,189.64 3.41 731.37 2_MWD+IFRI+MS+Sag(5) 13,704.04 52.30 157.91 13,370.85 13,204.65 -268.33 1,030.11 2,433,292.98 316,207.33 2.68 778.78 2_MWD+IFR1+MS+Sag(5) 13,766.05 55.01 158.97 13,40].59 13,241.39 X14.78 1,048.45 2,433,246.25 316,224.94 4.58 827.82 2_MWD+IFR1+MS+Sag(5) 13,827.78 57.01 159.91 13,442.10 13,275.90 -362.71 1,066.42 2,433,198.06 316,242.16 3.48 877.91 2_MWD+IFRI+MS+Sag (5) 13,891.92 59.06 160.36 13,476.06 13,309.86 413.88 1,084.91 2,433,146.61 316,259.84 3.25 931.02 2_MWD+IFRI+MS+Sag(5) 13,956.54 60.66 160.47 13.508.50 13,342.30 466.53 1,103.64 2,433,093.67 316,277.74 2.48 985.50 2_MWD+IFR1+MS+Sag(5) 14,016.66 60.63 160.30 13,537.97 13,371.77 -515.89 1,121.23 2,433,044.05 316,294.56 0.25 1,036.60 2_MWD+IFRI+MS+Ssg(5) 14,078.59 60.72 159.86 13,568.30 13,402.10 -566.65 1,139.63 2,432,993.00 316,312.15 0.64 1,089.31 2_MWD+IFR1+MS+Sa9(5) 14,141.05 60.52 160.18 13,598.95 13,432.75 -617.80 1,158.23 2,432,941.57 316,329.94 0.55 1,142.46 2 MWD+IFRI+MS+Sag(5) 14,202.98 60.51 160.21 13,629.43 13,463.23 -668.52 1,176.49 2,432,890.57 316,347.41 0.05 1,195.07 2_MWD+1FR1+MS+Sag(5) 14,234.00 60.51 16021 13,644.70 13,478.50 -693.93 1,185.63 2,432,865.03 316,356.15 0.00 1,221.42 PROJECTEDIo TD Checked By: Mitch Laird -- Approved By: Benjamin Hand .....,..__ --- Date: 5.23.2019 5232019 1:47:09PM Pam 5 COMPASS 5000.15 Build 91 Lease & Well No. County Hilcorp Energy Company CASING & CEMENTING REPORT BCU-04RD Kenai State Alaska Supv. Date Run 4 -May -19 S Hauck/J Richardson CASING RECORD Intermediate,k2 � TO 15,193.00 Shoe Depth: 15,193.00 PBTD: No. Jts. Delivered 101 No..Itc Rin 91 Nn no P fi,roan to Csg Wt. On Hook: 21,000 Type Float Collar: Antelope Csg Wt. On Slips: Type of Shoe: Reamer _ Rotate Csg Yes X No Recip Csg _ Yes X No Fluid Description: 6% KCUPHPA Liner hanger Info (Make/Model): Baker Flex-LockV liner hanger, HRDE ZXHD liner t Liner hanger test pressure: 2500 Centralizer Placement: Ran fiberglass centralizers on every joint . CEMENTING REPORT Shoe @ 15193 FC @ 15,148.00 ush (Spacer) Clean spacer III Density (ppg) 13 1 Slurry Class "G' cement Density (ppg) 15.3 Volume pumped (BBLs) Tail Slurry 88 No. Him to Run: 60 Casing Crew: Weatherford 30 Ft. Min. 12.5 PPG Liner top Packer?: X Yes _ No Floats Held X Yes No Top of Liner 10991 Volume pumped (BBLs) Sacks: 400 Yield: 1.24 Mixing / Pumping Rate (bpm): 5 Class "G' cement Sacks: 215 Yield: 1.61 ity (ppg) 15.3 Volume pumped (BBLs) 61 Mixing / Pumping Rate (bpm): 5 Flush (Spacer) Density (ppg) Rate (bpm): Volume: : 6% KCUPHOA Density (ppg) 12.5 Rate (bpm): 5 Volume (actual / calculated): (psi): 1093 Pump used for disp: Cement Truck Bump Plug? _ Yes X No Casing (Or Liner) Detail Ig Rotated? _Yes X No Reciprocated? _Yes Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top Reamer Shoe 73/4 TXP BTC Reamer 2.59 15,193.00 15,190.41 1 7" liner 7 29.0 P -110 -IC TXP BTC 40.58 15,190.41 15,149.83 Float collar 73/4 TXP BTC Antelope 1.30 15,149.83 15,148.53 2 7" liner 7 29.0 P -110 -IC TXP BTC 40.58 15,148.53 15,107.95 Pup Joint 7 29.0 P -110 -IC TXP BTC 3.89 15,107.95 15,104.06 Landing Collar 7 TXP BTC J -Hobbs 3.33 15,104.06 15,100.73 Pup Joint 7 29.0 P -110 -IC TXP BTC 21.82 15,100.73 15,078.91 Swell Packer 73/4 TXP BTC Baker 11.90 15,078.91 15,067.01 Pup Joint 7 29.0 P -110 -IC TXP BTC 16.64 15,067.01 15,050.37 87 7" liner 7 29.0 P -110 -IC TXP BTC 3,893.83 15,050.37 11,156.54 Pup Joint 7 29.0 P -110 -IC TXP BTC 16.65 11,156.54 11,139.89 Swell Packer 73/4 TXP BTC 11.89 11,139.89 11,128.00 Pup Joint 7 29.0 P -110 -IC TXP BTC 17.45 11,128.00 11,110.55 2 7" liner 7 29.0 P -110 -IC TXP BTC 89.65 11,110.55 11,020.90 Pup Joint 7 29.0 P -110 -IC TXP BTC 2.83 11,020.90 11,018.07 Liner Hanger 85/8.1 Baker 26.94 11,018.07 1 10,991.13 Csg Wt. On Hook: 21,000 Type Float Collar: Antelope Csg Wt. On Slips: Type of Shoe: Reamer _ Rotate Csg Yes X No Recip Csg _ Yes X No Fluid Description: 6% KCUPHPA Liner hanger Info (Make/Model): Baker Flex-LockV liner hanger, HRDE ZXHD liner t Liner hanger test pressure: 2500 Centralizer Placement: Ran fiberglass centralizers on every joint . CEMENTING REPORT Shoe @ 15193 FC @ 15,148.00 ush (Spacer) Clean spacer III Density (ppg) 13 1 Slurry Class "G' cement Density (ppg) 15.3 Volume pumped (BBLs) Tail Slurry 88 No. Him to Run: 60 Casing Crew: Weatherford 30 Ft. Min. 12.5 PPG Liner top Packer?: X Yes _ No Floats Held X Yes No Top of Liner 10991 Volume pumped (BBLs) Sacks: 400 Yield: 1.24 Mixing / Pumping Rate (bpm): 5 Class "G' cement Sacks: 215 Yield: 1.61 ity (ppg) 15.3 Volume pumped (BBLs) 61 Mixing / Pumping Rate (bpm): 5 Flush (Spacer) Density (ppg) Rate (bpm): Volume: : 6% KCUPHOA Density (ppg) 12.5 Rate (bpm): 5 Volume (actual / calculated): (psi): 1093 Pump used for disp: Cement Truck Bump Plug? _ Yes X No Bump press Ig Rotated? _Yes X No Reciprocated? _Yes X No % Returns during job _ 100 ant returns to surface? _Yes X No Spacer returns? _Yes X No Vol to Surf: 0 ant In Place At: 15:35 Date: 5/4/2019 Estimated TOC: 12,758 A Used To Determine TOC: Calc Post Job Calculations: Calculated Cmt Vol @ 0% excess: 90 Total Volume cmt Pumped: 149 Cart returned to surface: 0 Calculated cement left in wellbore: 149 OH volume Calculated: 78 OH volume actual: 168 Actual % Washout: 116 www.weliez.net WellEz Information Management LLC ver 04818br Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No. BCU-04RD Date Run 19 -May -19 County Kenai State Alaska Supv. R Pederson /J Riley CASING RECORD Liner � TD 16,642.00 Shoe Depth: 16,607.00 PBTD: No. Jts. Delivered 53 No. Jts. Run 39 No. Jts. Returned 14 Csg Wt. On Hook: 16,810 Type Float Collar: Antelope Csg Wt. On Slips: Type of Shoe: Reamer SHoe Rotate Csg X Yes No Recip Csg X Yes _ No Fluid Description: OBM Liner hanger Info (Make/Model): Baker HRDE ZXPN Liner Top Hanger Packer Liner hanger test pressure: Centralizer Placement: 1 every it after shoe track f/ total of 36 centralizers CEMENTING REPORT Shoe @ 16606.04 FC @ 14,460.56 lush (Spacer) Lead Slurry 3.5 Volume (actual / calculated): Casing (Or Liner) Detail (psi): 1500 Pump used for disp: ialiburton cement pum Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top Type: Reamer Shoe 55/8 15,100 od Used To Determine TOC: DWC 2.30 16,607.04 16,604.74 2 4.5" Liner Jt 41/2 12.6 L-80 DWC 78.92 16,604.74 16,525.82 Float Collar 5 DWC 1.37 16,525.82 16,524.45 3 4.5"Liner A 41/2 12.6 L-80 DWC 38.72 16,524.45 16,485.73 Landing Collar 5 DWC 1.09 16,485.73 16,484.64 36 4.5" Liner Jt 41/2 12.6 L-80 DWC 1,476.13 16,484.64 15,008.51 x Lock Liner Han 65/8 DWC 34.78 15,008.51 1 14,973.73 Csg Wt. On Hook: 16,810 Type Float Collar: Antelope Csg Wt. On Slips: Type of Shoe: Reamer SHoe Rotate Csg X Yes No Recip Csg X Yes _ No Fluid Description: OBM Liner hanger Info (Make/Model): Baker HRDE ZXPN Liner Top Hanger Packer Liner hanger test pressure: Centralizer Placement: 1 every it after shoe track f/ total of 36 centralizers CEMENTING REPORT Shoe @ 16606.04 FC @ 14,460.56 lush (Spacer) No. Hrs to Run: Casing Crew: 20 Ft. Min. Liner top PackeR: Floats Held Top of Liner 14973.73 Density (ppg) 13 Volume pumped (BBLs) Sacks: 165 Yield: Volume pumped (BBLs) 35 Mixing / Pumping Rate (bpm): Volume pumped (BBLs) Sacks: Yield: Mixing / Pumping Rate (bpm): Density (ppg) Rate (bpm): 48 Weatherford 12.3 PPG Volume: X Yes No X Yes No 30 4 OBM Density (ppg) Lead Slurry 3.5 Volume (actual / calculated): Type: Class G (psi): 1500 Pump used for disp: ialiburton cement pum Density (ppg) 15 Bump press 2360 Tail Slurry w Type: 100 Density (ppg) v, Post Flush (Spacer) Lr Type: w _No Estimated TOC: No. Hrs to Run: Casing Crew: 20 Ft. Min. Liner top PackeR: Floats Held Top of Liner 14973.73 Density (ppg) 13 Volume pumped (BBLs) Sacks: 165 Yield: Volume pumped (BBLs) 35 Mixing / Pumping Rate (bpm): Volume pumped (BBLs) Sacks: Yield: Mixing / Pumping Rate (bpm): Density (ppg) Rate (bpm): 48 Weatherford 12.3 PPG Volume: X Yes No X Yes No 30 4 OBM Density (ppg) 12.3 Rate (bpm): 3.5 Volume (actual / calculated): 225/235 (psi): 1500 Pump used for disp: ialiburton cement pum Bump Plug? X Yes No Bump press 2360 ig Rotated? X Yes _No Reciprocated? X Yes _No % Returns during job 100 ant returns to surface? _Yes X No Spacer returns? X Yes Vol to Surf: 0 ant In Place At: 13:30 Date: 5/19/2019 _No Estimated TOC: 15,100 od Used To Determine TOC: Calculation Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: 35 Cmt returned to surface: 0 Calculated cement left in wellbore: 35 www.wellez.net WelIEZ Information Management LLC ver 04818br Winston, Hugh E (CED) From: Cody Dinger <cdinger@hilcorp.com> Sent: Wednesday, August 21, 2019 10:51 AM To: Winston, Hugh E (CED) Subject: RE: [EXTERNAL] BCU -04 and BCU-04RD Well Completion Reports Huey, See responses below. I will resubmit the 10-407s today with corrections. Thanks! Cody From: Winston, Hugh E (CED) [mailto:hugh.winston@alaska.gov] Sent: Wednesday, August 21, 2019 9:29 AM To: Cody Dinger <cdinger@hilcorp.com> Subject: [EXTERNAL] BCU -04 and BCU-04RD Well Completion Reports Hi Cody, I am entering the data from the well completion reports for BCU -04 and BCU-04RD and there are a couple questions and issues: BCU -04 • The top productive interval information is missing from box 4a and 4b. Can you tell me why this was omitted? Since the well is abandoned, the well no longer has open perfs or any productive intervals, I've marked them N/A. • The total depth location coordinates in box 4b seems to be a little off. Our database takes both sets of coordinates and calculates to make sure they match, but the reported state plane coordinates are off by about 50 ft each from the reported governmental coordinates in box 4a. Can you verify these numbers please? — I updated this, what we had on record from the original wellbore was way off, the new coordinates/measurements are correct. • Both "Oil" and "Abandoned" are checked in box 1. Please only check "Abandoned". - fixed BCU-04RD • The completion date reported in box 6 is after the reported start of production in box 27. Can you verify these dates please? Corrected to date completion tubing was run. • The API number is slightly off. It should be 50-133-20239-03-00 - fixed • The formation at total depth is missing from box 29. - fixed • The x-coordinate in box 4b appears to be incorrect. Please verify this number as well. - fixed If you would please correct these errors and send an updated signed copy of both reports, just the 2 page 10-407 is fine. Thanks Huev Winston Statistical Technician Alaska Oil and Gas Conservation Commission hu¢h.winston@alaska.aov 907-793-1241 DATE 8/08/2019 219011 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 3 1 0 0 1 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMI AL BCU 04RD PTD CD 1 :HALLIBURTON FINAL LWD DATA BCU 04RD & BCU 04RD PB1 Log Viewers CGM Definitive Survey EMF LAS PDF TIFF CD 2: NABORS FINAL MUDLOG DATA Final Well Report LAS Data Log PDFs Log Tiffs Sample Photography Show Reports BCU04RD-PB1 Daily Reports DML Data CD 3: POLLARD CBL/GR ]1 BC4RD CBL 6 -MAY -2019 i BC 4RD CBL 6 -MAY -2019 a1'7-ticl 8/8/20192:08 PM Filefolder 8,/8/20192:09 PM Filefolder 8/8/20192,09 PM Filefolder 8/8/2019209 PM Filefolder 8,18/20192:09 PM Filefolder 8/8/20192:09 PM Filefolder 8/8/20192:09 PM Filefolder 8/8/20192:18 PM Filefolder 8/8120192:18 PM Filefolder 6/320194:27 PM Filefolder 8/820192:18 PM Filefolder 6/8/20192:20 PM Filefolder 8/8/20192:21 PM Filefolder 8/8/20192--21 PM Filefolder 8;CJ2D192:21 PM Filefolder 8/8/20192:21 PM Filefolder 516/20196:05 AM LAS File 5/6/20196:03 AM PDF Document Please include current contact information if different from above. RECEIVED AUG 0 8 2019 A0GCC 1,613 KB 4,045 KB Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 By: .N._I Y-) t, I I I Date: 219011 Debra Oudean Hilcorp Alaska, LLC 3 1 0 8 2 GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Hilrngr %14,4.. UA. Fax: 907 777-8510 E-mail: doudean@hilcorp.com DATE 8/08/2019 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 7th Ave Ste Anchorage, RECE�� Anchooraage, AK 9950101 VV G ..AUG 0 2019 ., O a ICI- a c p OGGG CD 1 :HALLIBURTON FINAL LWD DATA BCU 04RD & BCU 04RD PB1 _Log Viewers 8/8120192:08Pfd Filefolder CGM $!8/20192:09 P1v1 Filefolder Definitive Survey 818120192:09 PM Filefolder EMF 818./20192A9PM Filefolder LAS 8(8/20192:09 PAI Filefolder PDF 8,13/20192:09 PM Filefolder TIFF &B/20191.09 PM Filefolder CD 2: NABORS FINAL MUDLOG DATA Final Well Report 81812D192:18 PM Filefolder LAS Data 8/8,20192:18 PM Filefolder Log PDFs 6/32D194:21 PM File folder Log TIFFS 8/8/2019 2:18 PtA File folder Sample Photography 8!820192:20 PM Filefolder Show Reports 8/820192:21 Pfd Filefolder BCU04RD-PB1 818/20192:21 PM Filefolder Daily Reports 8,1$20192:21 PM Filefolder DML Data 818,120192:21 PM Filefolder CD 3: POLLARD CBL/GR J BC4RD CBL 6 -MAY -2019 5/6/20196: D5 AM LAS File 1,613 KB BC 4RD CBL 6 -MAY -2019 S.+612019 E:D3 AM PDF Document 4,045 K8 Please include current contact information if different from above. Please acknowledge receipt by sjqning and returning one copy of this transmittal or FAX to 907 777.8337 BY: IT I Y -)I 1I I Date: r 2190101 Debra Oudean 8Alaska, LLC 3 108 3 300 C GeoTech 3800 enterpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Rennrp aI:,A..IdA. Fax: 907 777-8510 E-mail: doudean@hilcorp.com DATE 8/08/2019 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 7th Ave Ste Anchorage, RECE1\JED Anchooraage, AK 9950101 G AUG 8 2019 A®GCG CD 1 :HALLIBURTON FINAL LWD DATA BCU 04RD & BCU 04RD PBI _Log Viewers 84120192.08PM Filefolder CGM $/8/20192:09 PM Filefolder Definitive Survey 8/8/20192:09 PM Filefolder EMF 818/20192:0 PM Filefolder LAS 8./8,20192:09 PM Filefolder PDF M.120192:09 PM Filefclder TIFF 918/20192:09 PM Filefolder CD 2: NABORS FINAL MUDLOG DATA Final Well Report E/212D192:18 PM Filefolder LAS Data 8.18/20192:18 PM Filefclder Log PDFs 6/3/20194:27 PM File folder Log TIFFS e/8/2019 2:18 Pti File folder Sample Photography /2:9/20192:20 PM Filefolder Show Reports 8"Z"'015 121 PM File fclder BCU04RD-Pill 8,rar20192:21 PKI File folder Daily Reports E/W0192:21 PM Filefolder DML Data 8:.."2D192:21 PM Filefolder CD 3: POLLARD CBL/GR . i BC4RD CBL 6 -MAY -2019 5{62019 6:05 AM LAS File 1,613 KB �. BC 4RD CBL 6 -MAY -2019 =.16/2()196:03 AM PDF Document 4,045 KB Please include current contact information if different from above. Please acknowledge receipt by s ning and returning one copy of this transmittal or FAX to 907 777.8337 Received8y: 22 44 190 a 4 11 3 Debra Oudean Hilcorp Alaska, LLC 1 0 8 GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 14 Tele: 907 777-8337 Iris.•nep Al;,.L.. M.I. Fax: 907 777-8510 E-mail: doudean@hilcorp.com DATE 8/08/2019 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician Anchorage, o 7th Ave Ste 01 RE,V E /EI) Anchorage, AK 99501 C VV G X • . AUG 0 B 2019 � -15w a rq— v c t ASG GC CD 1 :HALLIBURTON FINAL LWD DATA BCU 04RD & BCU 04RD PB1 Log Viewers 8/8.20152:0813M Filefclder CGM 88120192:09 PM Filefolder Definitive Survey 8,18/20192:09 PM Filefolder EMF 8/8/20192:09PM Filefolder LAS &8/20192:09 PKI Filefclder PDF 8,'8120192:09 PM Filefclder TIFF 8.18/20192:09 PM Filefolder CD 2: NABORS FINAL MUDLOG DATA Final Well Report -... 20192:19 PtA Filefclder LAS Data 618^019 LIS PF,7 Filefclder Log PDFs 613/20194:27 PM Filefclder Log TIFFS 816?2")192:16 PM Filefolder Sample Photography 819126192:20 PM Filefolder Show Reports 8'820192:21 PM Filefolder 13CI104P,D-Pill 818IMS 2:21 PfA Filefclder Daily Reports 8`820192:21 PM Filefclder DML Data 8%e: 0192:21 PFA File Wear CD 3: POLLARD CBL/GR BC4RD CBL 6 -MAY -2019 5/15'2019 6:D5 AM LAS File 1,613 KB BC 4RD CBL 6 -MAY -2019 5:+1.12019 6:63 AM PDF Document 4,u:5 KB Please include current contact information if different from above. Please acknowledge receipt by s,[qning and returning one copy of this transmittal or FAX to 907 777.8337 CUTTINGS FROM BCU-04RD WELL SAMPLEINTERVAL BCU atq-bl/ 11340'-12818' BCU 04RD 12810'-14190' Debra Oudean Hilcorp Alaska, LLC / qZd 14190'-15193' GeoTech 3800 Centerpoint Drive, Suite 1400 04RD 15193'-15960' Anchorage, AK 99503 7 Z _ P6 I— 04RD 15960'-16640' Tele: 907 777-8337 BCU n:!.:,�p U:F.t.,,. Lu ' Fax: 907 777-8510 E-mail: doudean@hilcorp.com BCU 04RD 12030'-13320' RECEIVED DATE 08/08//2019 04RD 13320'-14234' To: AOGCC AUb 0 8 2019 I1 Meredit,V Guhl 333 W. 7th Ave. Ste#100 AOGCC Anchorage, AK 99501 J M I ;?11 tart CUTTINGS FROM BCU-04RD WELL SAMPLEINTERVAL BCU 04RD 11340'-12818' BCU 04RD 12810'-14190' BCU 04RD 14190'-15193' BCU 04RD 15193'-15960' BCU 04RD 15960'-16640' BCU 04RD ' BCU 04RD 12030'-13320' BCU 04RD 13320'-14234' '2 -0f --Z Please include current contact information if different from above. �bNt" /Vo6�DXrhC psi Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Date: '6 [ Q Schwartz, Guy L (CED) From: Schwartz, Guy L (CED) Sent: Saturday, June 8, 2019 1:06 PM To: Monty Myers Subject: Re: PTD 219-011 (BCU 04RD thread leak) Monty, Have approval to perform resin sqz on the 7" liner top. Update MOC and keep informed on results. Guy Schwartz AOGCC 907/301-4533 Sent from my iPhone On Jun 8, 2019, at 11:57 AM, Monty Myers <mmyers@hilcorp.com> wrote: Guy, I wasn't sure if you were aware or not, but when we negative tested the liners on BCU04RD we had a leak somewhere that had flow with it. Upon investigation we discovered a leak in the pup joint threads directly below the 7" liner hanger at 11,020' TMD. We are going to attempt to squeeze the threads with Halliburton's Well Lock resin to seal the leak. Attached is the procedure and schematic with a leak log. Please let me know if you have any questions. Thank you! Monty M Myers Drilling Manager 907.538.1168 (c) 907.777.8431 (o) The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. <BCU 04RD Well Lock Squeeze.pdf> U mi,"'], kk'kn. IJ.c Well Work Prognosis Well: BCU-04RD Date: 06/08/2019 Well Name: Beaver Creek 04RD API Number: 50-133-20239-01 Current Status: Lined and cemented Leg: Estimated Start Date: June 9, 2019 Rig: Rig 169 Reg. Approval Req'd? FYI Only Date Reg. Approval Rec'vd: Regulatory Contact: Cody Dinger (8389) Permit to Drill Number: 219-011 First Call Engineer: Monty M Myers (907) 777-8431 (0) (907) 538-1168 (M) Second Call Engineer: Paul Mazzolini (907) 777-8369 (0) (907) 317-1275 (M) Current Bottom Hole Pressure: 0 psi @ X,XXX' ND 0.000 Ibs/ft (8.2 ppg) based on 6/2013 SIBHP Maximum Expected BHP: 0 psi @ X,XXX' ND 0.000 Ibs/ft (8.2 ppg) based on 6/2013 SIBHP Maximum Potential surface Pressure: 2,772 psi Brief Well Summary After the cleanout and during the negative testing of BCU-04RD, using Diesel (6.7 ppg EMW), we noticed a flow in the well. The well was shut in @ 15:41 hrs on 5/26/2019 and monitored for pressure build up: 1 hr = 748 psi, 2 hrs = 1053 psi, 3 hrs = 1322 psi, 4 hrs = 1435 psi, 5 hrs = 1487 psi, were it seemed to stabilize. MW was increased to 10.1 to kill well and arrangements were made to get an acoustic log from the slope down to the rig to diagnose the well. The ACX log was run and a leak was detected in the pup joint below the 9-5/8 X 7 liner hanger at 11,020' TMD. Several option have been considered for repairing the leak. The first attempt will be to squeeze Halliburton's Well Lock resin into the threads to try and seal the leak. Last Casing Test: 6/6/2019 4750 psi on 7" and 4-1/2" liner with 250psi bleed off over 1 hr. Procedure: 1. RU Pollard and set composite bride plug at 11,105' TMD 2. POOH and RD Pollard E -line 3. PU 300' of 2-7/8" tubing with mule shoe 4. Crossover to 9-5/8" RTTS test packer 5. Crossover to 4-1/2" CDS-40 DP 6. RIH and tag composite bridge plug with tubing tail 7. PUlftoffofBP 8. RU Halliburton cementers and pressure test lines 9. Line up and pump down hole the following: a. 30 bbls of diesel (6.7 ppg) b. Nerf ball c. 10 bbls of well lock resin (9.3 ppg) d. Nerf ball 10. Displace work string with —150 bbls of 10.1 ppg OBM 11. POOH 7 stands 12. Set 9-5/8" test packer 13. Apply 700 psi of pressure on drill string Well Work Prognosis Well: BCU-04RD ,❑dn,,., k, ,kz,„, Date: 06/08/2019 14. Monitor pressure for 1 hr. a. If pressure falls to 200 psi, bump pressure up to 500 psi b. Monitor well for another hour 15. This process will be repeated for approximately 4 hours 16. After 4 hours, bleed off pressure, release test packer and circulate a bottoms up 17. On second circulation, pump 330 gallons of Halliburton's well lock solvent 18. Circulate bottoms up and monitor well for flow 19. POOH and wait on well lock for 24 hours. 20. While waiting, PU 6" clean out assembly and RIH to 10,900' TMD and circulate hole to an even 10.1 ppg mud in/out. 21. After waiting 24 hours and with even MW in/out, drill out resin to composite bridge plug. 22. POOH and PU 9-5/8" test packer 23. RIH and perform negative test across threads. Attachments: 1. Current Well Schematic 2. Leak detectlog K mrn Alaska. LIX KB Elei.:16&2'/ BF/GL Elev.:148.7 PROPOSED SCHEMATIC TD=16,642' (ND) / TD=15,652' (TVD) PBTD=±16,486' (ND) / PBfD=±15,427' (TVD) Beaver Creek Unit Well: BCU 04RD Completed: Future PTD: 219-011 API: 50-133-20239-01-00 Revised By: CID 05-28-19 JEWELRY DETAIL CASING DETAIL Depth ID OD Item 12 Size Type Wt Grade Conn. Drift ID Top Btm 20" Conductor 94 H-40 N/A Surface 288' 13-3/8" Surface 72 N-80 12.415 Surface 2,989' 9-5/8" Production 47& 53.5 N -80,S-95, P-110 8.681 Surface 12,521' 7" Liner 29 P-110 IC/TXP BTC 6.059 10,991' 15,193' 4-1/2" Liner 12.6 L-80 DWC/C 3.833 14,974' 16,607' TUBING DETAIL TBD Revised By: CID 05-28-19 JEWELRY DETAIL No. Depth ID OD Item 12 10'991'7" Liner Top Packer 16 11,128' Water Swell Packer 19 14,974' 4.5" Liner Top Packer 21 15,067' Water Swell Packer Revised By: CID 05-28-19 FLOWING LOG UP PASS '..tTH 30 Bbls/HR HALLIBURTON 5"=100' Database File bcu 04rd two.db Dataset Pathname BCU_04RD TWQIrun1/pass2 Presentation Format ACA559-1 Dataset Creation Tue Jun 04 20:46:45 2019 Charted by Depth in Feet scaled 1:240 0 GR (GAPI) 75 LTEN 0 TEMP (degF) 220 Acoustic Amp 0 Spectrum (khz) 50 1 Radial Location (in) 4 CCL (lb) Pressure 0 (Pa) 300 °a ' LSPD (2500 4500 (psi) 5800 0 (ft/min) 50 0 QP#2 (psi) 10 '----- ----------- "I ......... CCL#2 (QPC) DTMP (degF) -2 2 CWH (cps) " (4 -- �rzD Regg, James B (CED) From: Shane Hauck <shauck@hilcorp.com> Sent: Sunday, June 2, 20194:35 AM To: Regg, James B (CED) Cc: Monty Myers; Paul Mazzolini; Ted Kramer; Jesse Richardson - (C); Tool Pusher (toolpusher@allamericanoilfield.com) Subject: Notice of BOPE used for well control In compliance w/ guidance bulletin 10-003 Date and time = 6-01-19 @ 15:06 hrs Well/location/PTD number= BCU-04rd (219-011) Rig Name= Hilcorp #169 Operator Contact = Shane R Hauck 907-776-6776 shauck@ hilcorp.com Operations summary, including events leading up to BOPE use = We were Pooh w/ seals for top of 4-1/2" liner and 7" test prk w/ bypass (We have been Hole hunting ) @ 8553' trip sheet started getting off t/ max of 2.5 bbls stop and flow chk well flowing @ 8.4 bph and took other 2.5 bbl gain while monitoring for total of 5.0 bbls. Shut in on 4-1/2" dp w/ upper VBR and monitored Pressure for 2 hrs to get stable Pressure SIDPP= 366 psi and SICP = 450 psi Bope Used = Upper VBR ram shut in on 4-1/2" dp + TIW floor Valve, Choke her and Manual valve Choke manifold and used elect choke Reason for use = Action taken/to be taken (including the date used BOPE was tested) Well was flowing and was 5.0 bbls off on trip sheet. shut in to check for pressure build up. circ out influx using the first step of drillers method w/ only 109 units max gas at btm/up and lightest mud weight of 8.8+ bled off pressure w/ 2.3 bbl flow on back side slowed f/ 7 bph t/ .32 bph staging in hole at present time. Plan to circ up Influx (water) right above top of 4-1/2" liner @ 14,973' Last BOP test date was 5-29-19 Thanks Shane R. Hauck Hilcorp DSM Rig 907-776-6776 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 'le Cruet- 4)06 prrb ZROl(G' Regg, James B (CED) From: Shane Hauck <shauck@hilcorp.com Sent: Tuesday, May 28, 2019 11:45 AM I c T3I To: Regg, James B (CED) Subject: RE: [EXTERNAL] RE: Hilcorp BCU-#4rd rig #169 notice of bop use for well control Sorry Yes sir Mr. Regg We did stage back to btm and chg well back t/9 ppg OBM and monitored well static Currently Pooh we have done better than I thought on time we at @ 2600' w/ correct hole fill still have to lay do our 2-7/8" est test start time of bope test 20:00 hrs this PM Date and time = 5-25-19 @ 15:41 hrs Well/location/PTD number - B U-04rd (219-011) Rig Name = Hilcorp #169 Operator Contact = Shane R Hauck 907-776-6776 shauck@ hilcorp.com Operations summary, including events leading up to BOPE use = rih t/ tag of PBTD @ 16,482' w/ 4 scrapers assy to cover complete well tubulars and change well over from 9.0 ppg obm to diesel and well was flow chk stable Pooh and trip sheet started getting off t/ max of 10.5 bbls and 5.2 bph flow was observed stabbed TIW valve and shut in on upper VBR w/ 4-1/2" dp and monitored Pressure for 5.0 hrs to get stable Pressure of 1487 psi Bope Used = Upper VBR ram shut in on 4-1/2" dp +TIW floor Valve, Choke her and Manual valve Choke manifold & use ✓ both Hyd choke and Manual choke for personal training with crew on well kill operations and equipment use Reason for use = Action taken/to be taken (including the date used BOPE was tested) Well was flowing and was 10.5 bbls off on trip sheet shut in to check for pressure build up. Stage back in hole circ out influx using the driller method and chg well back over to 9.0 ppg OBM flow chk and Pooh I/dn bha #17 and preform complete bope test to re- set clock run dp and wire line tools in a under balance condition to find leak Path to water zone Last BOP test date was 5-21-19 witness by Mr. Jeff Jones Thanks Shane R. Hauck Hilcorp DSM Rig 907-776-6776 From: Regg, James B (CED) [mailto:jim.regg@alaska.gov] Sent: Tuesday, May 28, 2019 9:34 AM To: Shane Hauck <shauck@hilcorp.com> Subject: [EXTERNAL] RE: Hilcorp BCU-#4rd rig #169 notice of bop use for well control For future reference, report of BOPE Use is to include all information listed in the guidance bulletin 10-003, including BOPE used and well PTD. Thank you. Jim Regg Supervisor, Inspections AOGCC 333 W.7'h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail messages, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.reze@alaska.zov. From: Shane Hauck <shauck@hilcorp.com> Sent: Sunday, May 26, 2019 8:15 AM To: Regg, James B (CED) <iim.reeg@alaska.eov> Cc: Monty Myers <mmvers@hilcorp.com>; Ted Kramer <tkramer@hilcorp.com>; Jesse Richardson - (C) <iesrichardson@hilcorp.com>; Tool Pusher (toolpusher@allamericanoilfield.com) <toolpusher@allamericanoilfield.com>; Joe Engel <jeneel@hilcorp.com>; Paul Mazzolini <pmazzolini@hilcorp.com> Subject: Hilcorp BCU-#4rd rig #169 notice of bop use for well control Mr. Regg After displacing well to diesel and starting pooh laying down drill pipe we starting getting improper hole fill and observed well flowing and shut in well @ 15:41 hrs on 5-25-19 Once we are back on the bank we will test our bope as per regulations Thanks Hilcorp DSM Shane Hauck Rig 907-776-6776 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC. 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Beaver Creek Field, Beaver Creek Oil Pool, BCU 04 -RD Permit to Drill Number: 219-011 Sundry Number: 319-099 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 wvvw.a ogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this Z/ day of May, 2019. RBDMS �{ MAY 2 12019 nVFE STATE OF ALASKA MAR 0 1 2019 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AL GCCo 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate Q 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: Hilcorp Alaska, LLC Exploratory ❑ Development Q. Stratigraphic ❑ Service ❑ 219-011 - 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-13320239-01-00 - 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 2378 Will planned perforations require a spacing exception? Yes ❑ No � ❑ Beaver Creek 04RD 9. Property Designation (Lease Number):10. Field/Pool(s): FEDA028083 . Beaver Creek Field / Beaver Creek Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (R): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 17,434' 15,452' 17,434' 15,452' -968 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 288' 20" 288' 288' Surface 2,989' 13-3/8" 2,989' 2,878' 5,380psi 2,670psi Intermediate Production 12,521' 9-5/8" 12,521' 12,425' 6,870psi 4,760psi Liner 3,250' 7" 15,150' 14,950' 11,220psi 8,530psi Liner -2384 4-1 /2" 17,434' 17,174' 8,430psi 7,500psi Perforation Depth MD (R): Perforation Depth T V (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 3-1/2" 9.39 / P-110 15,050' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (R): 12. Attachments: Proposal Summary Q Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Q Exploratory ❑ Stratigraphic ❑ Development Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: Apri115,2019 OIL Q WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: So York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer hi1cor .Com Contact Phone: 777-8420 1 Authorized Signatur . Date: 1 �°✓ (= 0 �� COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test r Mechanical Integrity Test ❑ Location Clearance ❑ Other: P 'T 7S r ' a o o PS. RBDMSMAY 2 12019 Post Initial Injection MIT Req'd? Yes ❑ No ❑ . ` Spacing Exception Required? Yes ❑ No y� Subsequent Form Required: ©-- y -7 //' �jl I D O �,4�(l,,.n�/ ) C b-vn.�.�+' b f: X11 APPROVED 1' SI Approved by: COMMISSIONER THE COMMISSION Date: 5-12 4-d - d 11 l -Approved o fJ D I�tI A I A V { /� Submit Form and For ised 01 Approved afiplication is li 1 o td� of approval. � /•(S7�/ Attachments in kuplicate s-• 17 i3 U aJeorp Alaska, LLI Well Prognosis Well: BCU-04RD Date: 2/28/19 Well Name: BCU-04RD API Number: 50-133-20239-01 Current Status: New Sidetrack Leg: N/A Estimated Start Date: April 15th, 2019 Rig: 169 Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 172-013 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) Second Call Engineer: Bo York (907) 777-8345 (0) (907) 727-9247 (M) AFE Number: Maximum Expected BHP: —6,742 psi @ 15,416' TVD (.437 psi/ft. gradient to the WF) Max. Potential Surface Pressure: —968 psi (0.374 psi/ft diesel gradient) Brief Well Summary The BCU 4RD is being sidetracked out of the BCU 4 well bore. This well is being drilled to an anticipated depth of 17,434' MD. The purpose of this work/sundry is to complete this well and place the well on production. Notes Regarding Wellbore Condition Well has been cleaned out and changed over to diesel as the completion fluid. Saxon #169 Procedure 1. MIRU Saxon #169 Rig. 2. Depending on where the Rig is in the BOP Testing cycle, consider testing BOPE to 250 psi Low/ 4,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 10 -min). Record accumulator pre -charge pressures and chart tests. a. Confirm test pressures per the Sundry Contitions of Approval b. Perform Test. c. Notify AOGCC 24 hrs in advance of BOP test. d. Test VBR rams on 3-1/2" test joint. e. Email completed 10-424 form to all AOGCC addresses listed on the form within 5 days of BOPE test. 3. L/D BOP test equipment. 4. PU Seals on 3.5" 9.3 # 8 RD EUE production tubing along with GLMs and chemical injection mandrel and RIH to top of ZXP liner top packer @ +/- 15,050'. 5. Stab seals into packer and space out. 6. Pressure test back side annulus to 2,000 psi on chart for 30 min. 7. Hang off well and ND BOP, NU Well head and test. 8. RU Slickline and run GR to bottom of the West Foreland's (depth to be determined by logs). POOH and Rig down Slickline. 9. RDMO Rig 169. 10. MIRU E -line unit. PU RIH With Perf Guns to Perforate well as determined by well logs. RDMO E - line unit. 11. Turn Well overto production for Testing. H Ili] coru Alueku, LL, Attachments 1. Proposed Schematic 2. BOPE Schematic 3. Current Wellhead Schematic 4. Blank RWO Procedure Change Form Well Prognosis Well: BCU-04RD Date: 2/28/19 20' 13-3/8' ( Beaver Creek Unit Well: BCU 04RD PROPOSED SCHEMATIC Completed -011 PTD: 2199 -011Future t111,v,ru Almka. LLC API: 50-133-20239-01-00 KB Bev.: 166.2'1 BF/GL 13ev--148.2' t 9 518' ECU14 t' 4-1/2' 2 3 4 6 6 7 e 9 1a n 12 13 14 15 P 16 Tl II is 19 PERFORATIONS Zone Top(MD) Btm(MD) CASING DETAIL No. Depth ID Size Type Wt Grade Conn. Dlpk Top Btm 20" Conductor 94 H-40 N/A Surface 288' 13-3/8" Surface 72 N-80 12.415 Surface 2,989' 9-5/8" Production 47& 53.5 N -80,S-95, P-110 8.681 Surface 12,521' 7" Liner 29 P-110 ICMP BTC 6.059 ±11,900' ±15,150' 4-1/2" Liner 12.6 L-80 DWC/C 3.833 ±15,050' ±17,434' 9 ±9,609' 2.920" TUBING DETAIL 3-- r)-1 Mandrel 8RD 10 ±10,276' 3-1/2" ±16,002' 9.3 P-110 I 8RD EUE ±10,944' Surf ±15,050' PERFORATIONS Zone Top(MD) Btm(MD) JEWELRY DETAIL No. Depth ID OD Item 1 20' 2.998" - Tubing Hanger 2 ±2,400' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 3 ±4,350' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 4 ±5,900' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 5 ±7,150' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 6 ±7,500' 2.920" 5.375" 3-1 'D 7 ±8,151' 2.920" 5.375" 3-1: n: 218RD 8 ±8,952' 2.920" 5.375" 3-1:. 0-1 Mandrel 8RD 9 ±9,609' 2.920" 5.375" 3-- r)-1 Mandrel 8RD 10 ±10,276' 2.9- ±16,002' 0-1 Mandrel 8RD 11 ±10,944' 2.9c, 6 0-1 Mandrel 8RD 12 10,991' Hemlock 2B :,018 7" Liner Top Packer 13 ±11,669' 2.920" 5.375" 3-1/1-0-1 Mandrel 8RD 14 ±12,397' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD 15 ±13,192' 2.920" 5.375" 3-1/2" FO -1 Mandrel 8RD- Orll-; 1 6 11,128' TBD Proposed Water Swell Packer 17 M1916 ±15,OSO' 4.5" Liner Top Packer 18 ±15,050' 4.276" 5.750" Packer Tie Back Bullet Seals 15,067' Water Swell Packer PERFORATIONS Zone Top(MD) Btm(MD) Top(ND) BTm(ND) Amt Size SPF Phase Status Date Tyonek G18 234' ±14,419' ±14,433' ±18' 2-1/2" 6 60 TBD Proposed Tyonek G2A "",629' ±14,725' ±14,757 ±39' 2-1/2" 6 60 TBD Proposed Tyonek G2A ,,662' 115,706' ±14,785' ±14,882' ±44' 2-1/2" 660 TBD Proposed Hemlock 90(y ±15,933' ±14,984' ±15,013' ±33' 2-1/2" 6 60 TBD Proposed Hemlock 2A :1,994 ±16,002' ±15,065' ±15,073' ±8' 2-1/2" 6 60 TBD Proposed Hemlock 2B :,018 ±16,040 ±15,085' ±15,015' ±22 2-1/2" 6 60 TBD Proposed West Foreland :16,408' 1 ±16,474' ±15,430' ±15,491' ±66' 2-1/2" 1 6 60 TBD Proposed TD =16,647 (MD) /TD = 15,652' (1VD) PBTD=111,4W'(MD)/PBTD = '(TVD) Revised By: DMA 05-17-19 Beaver Creek Unit Well: BCU PROPOSED SCHEMATIC Completed::Future Hilwro Alaska LLC PTD: TBD I® Flew 1662'/ BF/GL Bei.: 14&2' TD=17,434' (MD) / TD= 35,452M) Pero=±17,400' (MD) / PBfD=±15,427'(M) PERFORATIONS Top D) Btm(MD) Top(TVD) Btm(TVD) Amt Gun SPF Phase Status Date Size 150' 75' 25' GENERAL WELL INFO API: TBD Initial Completion - 1/13/1973 Revised By: DMA 02-01-19 JEWELRY D AIL CASING DETAIL Depth ID OD Item Size Type Wt Grade Conn. Drift to Top Btm 20" Conductor 94 H-40 N/A Surface ±288' 13-3/8" Surface 72 N-80 12.415/Surface 3-1/2" SFO -1 Mandrel 8RD 12 port ±2,989' 9-5/8" Production 47 & 53.5 N -80,S-95, P-110 8,6 Surface ±12,521' 7" Liner 29 P-110 IC/T%P BTC .059 ±11,900' ±15,150' 4-1/2" Liner 12.6 L-80 DWC/C 3.833 ±15,050' ±17,434' 2.44" 4.750" 3-1/2" SFO -1 Mandrel 8RD 12 port 12 TUBING DETAIL 2.44" 4.750" 3-1/2" SFO -1 Mandrel 8RD 12 port 13 3-1/2" 9.3 1 P-110 I 8RD WE ISurf x15,O5tl TD=17,434' (MD) / TD= 35,452M) Pero=±17,400' (MD) / PBfD=±15,427'(M) PERFORATIONS Top D) Btm(MD) Top(TVD) Btm(TVD) Amt Gun SPF Phase Status Date Size 150' 75' 25' GENERAL WELL INFO API: TBD Initial Completion - 1/13/1973 Revised By: DMA 02-01-19 JEWELRY D AIL No. Depth ID OD Item 1 ±20' 2.44" - ubing Hanger 2 ±2,800 2.44" 4.750" 3-1/2" SFO -1 Mandrel 8RD 12 port 3 ±6,900 2.44" 4.75 " 3-1/2" SFO -1 Mandrel SRO 12 port 4 ±7,900 2.44" 4. 0" 3-1/2" SFO -1 Mandrel 8RD 12 port 5 ±8,900 2.44" .750" 3-1/2" SFO -1 Mandrel 8RD 12 port 6 ±9,900 2.44" 4.750" 3-1/2" SFO -1 Mandrel 8RD 12 port 7 ±10,900 2.44" 4.750" 3-1/2" SFO -1 Mandrel 8RD 12 port 8 111,900 2. 4.750" 3-1/2" SFO -1 Mandrel 8RD 12 port 9 x12,371' Liner Top Packer 10 ±12,500 .44" 4.750" 3-1/2" SFO -1 Mandrel 8RD 12 port 11 ±13,500 2.44" 4.750" 3-1/2" SFO -1 Mandrel 8RD 12 port 12 2.44" 4.750" 3-1/2" SFO -1 Mandrel 8RD 12 port 13 Water Swell Packer 14 /±14,8 Water Swell Packer Liner Top Packer 16 Backer Tie Back Bullet Seals TD=17,434' (MD) / TD= 35,452M) Pero=±17,400' (MD) / PBfD=±15,427'(M) PERFORATIONS Top D) Btm(MD) Top(TVD) Btm(TVD) Amt Gun SPF Phase Status Date Size 150' 75' 25' GENERAL WELL INFO API: TBD Initial Completion - 1/13/1973 Revised By: DMA 02-01-19 Beaver Creek Field BC #4RD—Redrill 02/13/2019 Beaver Creek BC#4RD Sidetrack H ilit.o.p .af..ka. LIA: Beaver Creek BC N4RD 20 x 133/8 x 95/8 x 3'h BHTA, Otis, 31/8 SM FE x 6.5" Otis quick union top Valve, Swab, CIW-FLS, 3 1/8 SM FE, HWO, EE trim Valve, Master, CI W -FLS, 31/85M FE, HWO, EE trim Valve, Master, CI W -FLS, 31/8 SM FE, HWO, EE trim Tubing head, FMC -TC -BG, 135/85M x115M, w/2- 2 1/16 SM SSO Casing spool, OCT- C -22 -BP - 00, 21 W'2M x 13 5/8 5M, W/ 2- 2 1/16 5M SSO'V Starting head, OCT -C22, 21 1/4" 2M x 20" SOW, w/ 2- 21/16 SM EFO Beaver Creek Field BC #4RD 11/20/2018 Tubing hanger, FMC -TC -EN - CCL, 11 x 3 A EUE 8rd lift and susp, w/ 3" type H-BPV profile, 2-'/.npt control line port, 6 Y. EN Ja\'e' c1 40Et m �a\"�� j O 'i' 13 3/8" 95/811 Y'11 Adapter, FMC -ASP -CCL, 31 SM stdd x 3 1/8 SM, w/ 2- 1" npt control line exits HHilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well BCU 4RD (PTD 219-011) Sundry #: XXX -XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first call' engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By Initials HAK Approved By Initials AOGCC Written Approval Received (Person and Date) Approval: Prepared: Asset Team Operations Manager Date First Call Operations Engineer Date THE STATE OIALASKA GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Beaver Creek Field, Beaver Creek Oil Pool, BCU-04RD Hilcorp Alaska, LLC Permit to Drill Number: 219-011 revised Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .aogcc.aloska.gov Surface Location: 1641' FNL, 631' FEL, SEC. 33, T7N, RI OW, SM, AK Bottomhole Location: 1418' FSL, 1757' FWL, SEC. 34, T7N, R10W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to re -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, �f Jessie L. Chmielowski Commissioner DATED this 10 day of April, 2019. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL REVISED 20 AAC 25 005 APR 0 4 2015 1 a. Type of Work: 11b. Proposed Well Class: Exploratory - Gas ❑ Service- WAG ❑ Service - Disp ❑ ic. SpecifyA9% �v(III� F-1Drill ❑ Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑� • Service - Winj El Single Zone ❑� Coalbed G s dr s Redrill Q • Reentry ❑ Exploratory -Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q • Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 • BCU-04RD 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 16,729' TVD: 15,454' Beaver Creek Field Beaver Creek Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 1641' FNL, 631' FEL, Sec 33, T7N, R10W, SM, AK FEDA028083 8. DNR Approval Number: 13. Approximate Spud Date: Top of Productive Horizon: 2050' FSL, 1318' FWL, Sec 34, T7N, R10W, SM, AK N/A 4/8/2019 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 1418' FSL, 1757' FWL, Sec 34, T7N, R10W, SM, AK 2560 3278' to nearest unit boundary - 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 166.2' 15. Distance to Nearest Well Open Surface: x-315181 y- 2433577 Zane -4 GL / BF Elevation above MSL (ft): 148.2'. to Same Pool: 4,864' to BCU-05RD2 - 16. Deviated wells: Kickoff depth: 11,500 feet - 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 43 degrees - Downhole: 8318 • Surface: 2772 . 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade I Coupling Length MD TVD MD TVD (including stage data) 8-3/8" 7" 29# P110 -IC TXP BTC 3,630' 11,350' 11,290' 14,980' 14,174'- 448 ft3 6" 4-1/2" 12.6# L-80 DWC/C 1,899' 14,830' 14,075 16,729' 15,454' 309 ft3 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): 14,234' 13,334' N/A 14,234' (if fish retrieved) ✓ 13,334' N/A Casing Length Size Cement Volume MD TVD Conductor/Structural 288' 20" Driven 288' 288' Surface 2,989' 13-3/8" 2000 sx 2,989' 2,989' Intermediate 12,521' 9-5/8" 2868 sx 12,521' 12,425' Production 3,704' 7" 1400 sx 15,921' 15,699' Liner 1 326' 1 5" 1 N/A 14,813' 14,623' Perforation Depth MD (ft): Various Through Tyonek/Hemlock Pertoration Depth TVD (ft): Various Through Tyonek/Hemlock 14,535' - 15,461' 14,355'- 15,252' Hydraulic Fracture planned? Yes ❑ No ❑4 20. Attachments: Property Plat O BOP Sketch Drilling Program Time v. Depth Plot 2 Shallow Hazard Analysis Time Diverter Sketch e Seabed Report e Fluid Program e 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Dale 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Monty Myers Authorized Name: Monty Myers Contact Email: mm er5 hllcor .Com Authorized Title: Drilling Manager Contact Phone: 777-8431 Authorized Signature: Date: Commission Use Only Permit to Drill ��/yl /umber: -7 /�, C} l —06 Permit Approval ' See cover letter for other Number. / f I �/` 50- f:,+3 -- ✓ 2� /'•-0 Date: requirements. 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: ,�,/ YesPi/No Other: . B� �% T S ,� / •G Samples req'd: Yes O No a Mud log req'd: L2 [ HzS measures: Yes NoLFa// Directional svy req'd: Yes No [_1Spacing F V exception req'd: Yes El No Inclination -only svy req'd: Yes ❑ No Post initial injection MIT req'd: Yes ❑ No ❑ II�IGA�./ APPROVED BY L pr 1. Approved by: 10 h El THE COMMISSION Date: � ' MALI auomrt rmni enu Form 1 0, Revised 512017� This permit is vali s IrMALIapproval per 20 AAC 25.005(8) Attachments in Duplbate�/ HProposed Schematic Rev 1 HD-om Aloka- I.I.0 KB Bev.: 165.2/ BF/GL Elm.: 148Y 20' 13-3i8' vB W4RD PBI TD @ 14,234' MD / 13,334' ND ) i e i r I 2&3 CASING DETAIL Beaver Creek Unit Well: BCU 04RD Completed: Future PTD: TBD Size Type Wt/Grade/Conn Drift ID I Top Btm 20" Conductor 94/H-40 N A Surface 288' 13-3/8" Surface 72/N-80 12.415 Surface 2,989' 9-5/8" Production 47 & 535 / N-80, 5-95, P130 8.681 Surface 12,521' 7" Liner 29/P-110IC/TXP BTC 6.059 11,350' 14,980' 4-1/2" Liner 12.6/L-80/DWC/C 3.833 14,830' 16,729' JEWELRY DETAIL No Depth Item 1 11,350' Liner TDP Packer 2 ±14,800' WaterSwell Packer(Straddle HP Water Zone) 3 ±14,952' WaterSwell Packer(Straddle HP Water Zone) 4 14,830' Liner Top Packer 5 ±11,560' Cement Retainer it tiTr: �— A)s4„ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Bt, (TVD) FT Size Date Status TBD GENERAL WELL INFO API: TBD Initial Completion - 1/13/1973 4-1/2' TD =16,729' (MD) ITD=1.5,454'(TVD) PBTD=116,650' (MD) I PI ID=115,400'(TVD) Revised By: CID 4/4/2019 R Hil.m Alaska. LL Well Prognosis Well: BCU-04RD Date:4/4/19 Well Name: BCU-04RD API Number: 50-133-20239-01-00 Current Status: Oil Producer Leg: N/A Estimated Start Date: 4/4/19 Rig: 169 Reg. Approval Req'd? 401 Date Reg. Approval Rec'vd: DP Regulatory Contact: Cody Dinger 777-8389 Permit to Drill Number: 219-011 First Call Engineer: Monty Myers (907) 777-8431 (0) (907) 531-1168 (M) Second Call Engineer: Joe Engel (907) 777-8395 (0) (805) 235-6265 (M) AFE Number: 2.625 12507.06 Brief Well Summary While cleaning out the well after a short trip at 14,234' our drillstring became detained. We were able to eventually pull the BHA free but we broke our tool while working pipe. The decision was made to POOH and LD the rotary steerable and drill to intermediate TO with a motor. We continued having issues with coal sloughing in on us while trying to POOH. When we finally got to the window, we have been unable to pull through the window with our BHA. We cut the DP as per our prior discussion and email, cleaned up the window and attempted to fish the BHA out of the hole with no success. The plan forward would be as follows: Notes Regarding Wellbore Condition Well is currently static and full of 10.5 ppg WBM The directional BHA is stuck across the window with the top of the fish at 11,561' Top of window is 12,030' TMD Bottom of window is 12,047' TMD BHA in hole consists of: TMD Length Item OD ID 11561 Top of Fish 12014.56 453.56 DP 4.5 2.813 12473.5 458.94 HWDPX15 4.5 2.813 12476.05 2.55 Cross Over 6.25 2.625 12507.06 31.01 Weatherford Jars 6.25 2.313 12509.57 2.51 Cross Over 6.25 2.68 12632.17 122.6 HWDPx4 4.5 2.813 12634.53 2.36 Cross Over 6.25 2.625 12637.47 2.94 Float Sub 6.688 2.875 12698.52 61.05 Flex Collar x 2 6.62 2.75 12701.53 3.01 Float Sub 6.75 2.88 12711.45 9.92 TM Collar 6.9 3.25 12718.29 6.84 HCIM Collar 6.75 1.92 12722.72 4.43 PWD Collar 6.75 1.905 12734.82 12.1 EWR-P4 Collar 6.75 2 12739.37 4.55 DGR Collar 6.75 1.92 12745.07 5.7 In line Stabilizer 6.8 1.9 K ea�rP uaak.. u 12754.27 19.2 DM Collar 6.75 3.125 12754.27 0 Ref Housing Stabilizer 8.312 0 12777.51 23.24 Geo -Pilot 7.625 1.49 12778.5 0.99 Kymera Bit 8.375 1.75 Saxon #169 Procedure 1. RIH w/ 8-1/8" fishing assembly and engage fish 2. POOH with fish 3. RU eline and set retainer at 12,020' 4. RIH with cement stinger and sting into retainer 5. Pump —35 bbls of abandonment cement 6. POOH with stinger S /� 7. RU eline and set CIBP at 11,500' 8. PU new whipstock assembly and RIH to 11,500' and mill window 9. POOH and RU directional drilling assembly 10. RIH to window 11. Drill as per new directional plan Attachments 1. Proposed Schematic 2. Updated directional plan—WP07A 3. Revised PTD (10-401) Well Prognosis Well: BCU-04RD Date:4/4/19 Hilcorp Alaska, LLC Beaver Creek Unit Beaver Creek Unit Beaver CK Unit 4 BCU 4RD Plan: BCU 4RD WP07a Standard Proposal Report 03 April, 2019 HALLIBURTON Sperry Grilling Services HALLIBURTON Inc Ew Sperry Drilling +NIS Vertical (TVD) Reference: BCU Planned RKB @ 166.20us8 Hit., Alaska, LLC Calculation Method: Minimum Curvature Inc ordinate (NE) Reference: Well Beaver CK Unit 4, True North Error System: ISCWSA +NIS Vertical (TVD) Reference: BCU Planned RKB @ 166.20us8 Scan Method: Closest Approach 3D TF.. Measured Depth Reference: BCU Planned RKB @ 166.20us8 Enor Surface: Pedal Curve 1 11500.00 Calculation Method: Minimum Curvature Warning Method: Error Ratio 11436.68 322.07 SECTION DETAILS Sac MD Inc Ad ND +NIS +EI -W ' Dleg TF.. VSec1 Target Annotation 1 11500.00 15.50 76.96 11436.68 322.07 402.35 0.00 0.00 75.99 KOP: Start Dir 12.7561100': 11500' MD, 11436.68'TVD: 45 -RT TF 2 11513.33 16.75 81.13 11449.48 322.77 405.98 12.75 45.00 78.18 End Dir : 11513.33' MD, 11449.48' We 3 11533.33 16.75 81.13 11468.64 323.65 411.68 0.00 0.00 81.75 Stert DI, 3°1100': 11533.33' MD, 11468.64'ND 4 12804.96 43.00 145.16 12584.00 -18.64 857.04 3.00 83.00 639.70 End Dir : 12804.96' MD, 12584' TVO 5 16579.20 43.00 145.16 15344.30 -2129.14 2327.73 0.00 0.00 3154.53 BCU 4RD tgt3 wp04 6 16729.20 43.00 145.16 15454.00 -2213.10 2386.18 0.00 0.00 3254.48 Total Depth: 16729.2' MD, 15454' NO 9 5/8" TOW KOP: Start Dir 12.750/100' : 11500' MD, 11436.68'ND : 450 RT TF Start Dir 3°/100' :11533.33' MD, 11468.64'ND 11600- 20'0 End Dir : 11513.33' MD, 11449.48' ND _nL Ex T. z 12000 End Dir : 12804.96' MD, 12584' ND - 000 12400 arirlmx cn 2 -' 00 w ,a 12800 !time cn p0 = - - Obs- - 13200 E_ 3600 p 14000 m C a m 0 14400 U 15200 15600 16000 em�sEra - - _ _ 500. _ _ 7" x 8 3/8" _ - _ - _ _ - O 00 spm o _ - _ - - - - _ - _ - _ _ - TVDPam TVDssPath Moped, rvoxotTs_x 11307.98 11539.12 11518.55 0 11585A9 a_rrauaL�s 11490.08 11730.01 11959.87 11793.67 12055.40 ttr-_-.,a- - - _ - _ -_ - BCU 4RD tgtt wp04 Tx=rvwEtiTEx- _- 12324.94 000 i M nisi -_BCD 4RDPB7= '.54000._ 13185.60 12971.48 _ - 13334.77 v rvor¢x.Tse 12886.77 13446.20 13299.26 -- "..- RM ...- _ . . 00 em�sEra - - _ _ 500. _ _ 7" x 8 3/8" _ - _ - _ _ - O 00 spm o _ - _ - - - - _ - _ - _ _ - TVDPam TVDssPath Moped, 11474.18 11307.98 11539.12 11518.55 14352.35 11585A9 11666.28 11490.08 11730.01 11959.87 11793.67 12055.40 12228.97 12062.77 12359.30 12491.14 12324.94 12681.29 12862.38 12696.18 13185.60 12971.48 1280528 13334.77 13052.97 12886.77 13446.20 13299.26 13133.06 13782.96 13311&M13219.44 13901.07 13449.35i3283.15 13988.18 13489.10 13322.90 14042.53 13548.03 13381.83 14123.11 13590.39 13424.19 14181.03 13630.28 13464.08 14235.57 13652.99 13486.79 14266.62 13710.5913541.39 Name 14345.38 13766.03 13599.83 14421.18 13816.87 13650.67 14490.70 13866.29 13700.09 14558.27 13937.31 13771.11 14655.38 13996.24 13830.04 14735.96 14040.23 13874.03 14796.11 14091 J6 13925.56 14866.56 14126.51 13960.31 14914.08 14143.57 13977.37 14937.41 14153.69 13987.49 14951.24 14295.33 14129.13 15144.91 14337.50 14171.30 15202.57 14358.02 14191.82 15230.63 14411.44 14245.24 15303.67 14505.5914339.39 15432.40 14574.59 14408.39 15526.75 14620.5814454.38 15589.63 14752.57 14588.37 15770.11 14816.66 14650.46 15857.74 14833.07 14666.87 15880.18 14892.57 14726.37 15961.53 14948.50 14782.30 16038.01 15002.85 14836 65 16112.32 15059.24 14893.04 16189.43 15100.23 14934.03 16245.47 15134.70 14968.50 16292.60 15217.53 15051.33 16405.86 +N/-S _ _ _ __ _ _- Project. Beaver Creek Unit ao_pLA Site: Beaver Creek Unit saoo Well: Beaver CK Unit 4 >c.."BCU -- Wellbore: BCU 4RD 472 D tgt2 wp04 Design: BCU 4RD WP07a 17200 K.xL-_ - _ Mtl W ..-_- -.�... - _.- - _ _ - _ _ - _ BCU 4RD tgt3 wp04 !C x5 -- "s 15500 .ter 500 O Total Depth :16729.2' MD, 15454' ND - _ -' eea,r°EeAxo 15630 BCU 4RD WP07a CASING DETAILS 15940 41/2"x6" TVD NDSS MD Size Name BCU 04P82 11436.68 11270.48 11500.00 9-518 9518°TOW 14174.72 14008.52 14980.00 7 7'x8318' 15454 00 15287.80 16729.20 4-1Y2 4112'x6- 112°x6" 16400- +N/S FI -W 0.00 0.00 Project. Beaver Creek Unit Site: Beaver Creek Unit saoo Well: Beaver CK Unit 4 Wellbore: BCU 4RD Design: BCU 4RD WP07a 17200 WELL DETAILS: Beaver CK Unit Ground Level: 148.20 Northing Easfing Latidude Longitude 2433577.41 315181.61 60° 39' 25.8089 N 151° 1' 48.4891 W SURVEY PROGRAM Date: W1943-29TH:00:00 Veldsled: Yes Version: Depth From Depth To SurveylPlan Tool 202.20 280230 BCU-(4PB1 GMS (BCU 04P81) 2_CB-FIIm4SMS 3107.20 8587.20 BCU -0 PBI CB -MMB (DCU 041`131) 2 CB -Film -MMS 8767.20 11500.00 BCUMPB2 CB -MSS (BCU 04PB2) 2_CB-Film-MSS ii500.00 11800.00 BCU 4RD WP07a(BCU 4RD) 2MWD Inter, Ali+Sag 900.00 16729.20 BCU 4RD WP07a(BCU 4RD) 2_MWD+IM1+MS+Sag -400 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 Vertical Section at 132.84' (800 usfUin) HALLIBUFTON i Bpeeev OrlNnp IBM KDP:SWX Dir 12]s°/IW':IISOV ].m.114)6fiH'fVi]:IS°0.TTF Fid Du :11511 II'MD, IIdd9.J8'TVD $wldr]"/IW:IIS]J.J]'M0, 114N.W'Np OW 9 $ II J9' �� •IA..pI .9 ___. BClla fl "'--- EW Dir J2W496'MD. L'SN'TW _ y9 ecu oral Ile 350 -]00 V nW'OI QM1O F a -1050 Ile ]'x81r8' , 01M1 }^ 4400 -1750— -T- 15 a[D 4nD WI v50Jl-- --- Ile ,,,9 -2100 Project: Beaver Creek Unit ! -- Tuul nwn 176729 -MD, Isdsd•TVD Site: Beaver Creek Unit Well: Beaver CK Unit -. Wellbore: BCU 4RD ecu4xnryx�H9a 41n''a' -z4sa Plan: BCU 4RD WP07a REFERENCE INFORWTION -2800 CueWub lNrel flelerenre: Ylel� CKwJ. Tnn wm e54(h➢I MOrerce'. flKB0 �B63Werr Mus um9w Remrew'. omen muomafl�0lzzmnn envmn Msuof'. PCV JRDIy]yW�� JI50 G9ING DETAILS TVD MSS MD Siu Namc 11436.68 113]0.48 11500.00 9-5]8 95M"TOW 14174.7_ 14008.52 14980.00 7 ]°x8L8' -3500 15454.00 IS]8].HO 1672930 4 -IR dlf]"z6' M£Il DFTAIIS: 9seur CK Uni�4 GmunG lettl: IJe ]o -3850 ,NI -5 °F/ -W' WMug 518ir6 IanWtle 151- 4e O:W 000 24)l5]1.11 31518161 64°lYE5.8089N 151°1'KAH91. r I 3100 -1750 -1400 -1050 -01 350 0 350 700 1050 1400 1950 2100 2450 2800 L50 3500 w�q-uBsst(*) (700 uAVin) HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Beaver Creek Unit Site: Beaver Creek Unit Well: Beaver CK Unit 4 Wellbore: BCU 4RD Design: BCU 4RD WP07a Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Beaver CK Unit 4 BCU Planned RKB @ 166.20usft BCU Planned RKB @ 166.20usft True Minimum Curvature Project Beaver Creek Unit Dogleg Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Gee, Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Beaver Creek Unit Site Position: Northing: 2,430,086.36usft Latitude: 60° 38'51.3158 N From: Map Easting: 314,428.19usft Longitude: 151°2'2.5023W Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -0.90 ° Well Beaver CK Unit 4 Well Position +N/S 0.00 usft Northing: 2,433,577.41 can Latitude: 60° 39' 25.8089 N +E/ -W 0.00 usft Easting: 315,181.61 usft Longitude: 151° 1'48.4891 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 148.20 usft Wellbore BCU 4RD Magnetics Model Name Sample Date Declination Dip Angle Field Strength 1°) C) (nT) BGGM2018 3/29/2019 15.53 73.60 55,279.59006291 fDesign BCU 4RD WP07a - - _- Audit Notes: Version: Phase: PLAN Tie On Depth: 11,500.00 Vertical Section: Depth From (TVD) +NIS +EI -W Direction (usft) (usft) (usft) (') 18.00 0.00 0.00 132.84 4/32019 11:50:15AM Page 2 COMPASS 5000.15 Build 91 Dogleg Build Turn Plan Sections +N/S +E/ -W Rate Rate Measured Tool Face (usft) Vertical TVD Depth Inclination Azimuth Depth System (usft) (1 (1) (usft) usft 11,500.00 15.50 76.96 11,436.68 11,270.48 11,513.33 16.75 81.13 11,449.48 11,283.28 11,533.33 16.75 81.13 11,468.64 11,302.44 12,804.96 43.00 145.16 12,584.00 12,417.80 16,579.20 43.00 145.16 15,344.30 15,178.10 16,729.20 43.00 145.16 15,454.00 15,287.80 4/32019 11:50:15AM Page 2 COMPASS 5000.15 Build 91 Dogleg Build Turn +N/S +E/ -W Rate Rate Rate Tool Face (usft) (usft) (°/100usft) ("1100usft) ("1100usft) (') 322.07 402.35 0.00 0.00 0.00 0.00 322.77 405.98 12.75 9.33 31.31 45.00 323.65 411.68 0.00 0.00 0.00 0.00 -16.64 857.04 3.00 2.06 5.03 83.00 -2,129.14 2,327.73 0.00 0.00 0.00 0.00 -2,213.10 2,386.18 0.00 0.00 0.00 0.00 4/32019 11:50:15AM Page 2 COMPASS 5000.15 Build 91 HALLIBURTON Database: Company: Project: Site: Well: Wellbore: Design: Planned Survey Measured Depth (usft) 18.00 202.20 402.20 602.20 802.20 1,002.20 1,202.20 1,402.20 1,602.20 1,802.20 2,002.20 2,20220 2,402.20 2,602.20 2,802.20 2,991.20 13 3/8" 3,187.20 3,367.20 3,547.20 3,727.20 3,907.20 4,087.20 4,267.20 4,447.20 4,627.20 4,807.20 4,987.20 5,158.20 5,347.20 5,527.20 5,707.20 5,887.20 6,067.20 6,247.20 6,427.20 6,607.20 6,787.20 6,967.20 7,147.20 7,327.20 7,507.20 7,687.20 7,867.20 8,047.20 NORTH US + CANADA Hilcorp Alaska, LLC Beaver Creek Unit Beaver Creek Unit Beaver CK Unit 4 BCU 4RD BCU 4RD WP07a Halliburton Standard Proposal Report Local Coordinate Reference: Well Beaver CK Unit 4 TVD Reference: BCU Planned RKB @ 166.20usft MD Reference: BCU Planned RKB @ 166.20usft North Reference: True Survey Calculation Method: Minimum Curvature 4WO19 11:50:15AM Page 3 COMPASS 5000.15 Build 91 Vertical Map Map Inclination Azimuth Depth TVDss +NIS +E/ -W Northing Easting DLS Vert Section (^) (1) (usft) usft (usft) (usft) (usft) (usft) 148.20 0.00 0.00 18.00 148.20 0.00 0.00 2,433,577.41 315,181.61 0.00 0.00 0.00 180.00 202.20 -36.00 0.00 0.00 2,433,577.41 315,181.61 0.00 0.00 0.50 244.00 402.20 -236.00 -0.38 -0.78 2,433,577.04 315,180.82 0.25 -0.31 0.25 280.00 602.19 435.99 -0.69 -2.00 2,433,576.75 315,179.61 0.17 -1.00 0.25 256.00 802.19 -635.99 -0.72 -2.85 2,433,576.74 315,178.75 0.05 -1.60 0.33 348.00 1,002.19 -835.99 -0.26 -3.39 2,433,577.20 315,178.22 0.21 -2.31 0.33 325.00 1,202.19 -1,035.99 0.77 3.84 2,433,578.25 315,177.78 0.07 -3.35 0.50 250.00 1,402.18 -1,235.98 0.95 -5.00 2,433,578.44 315,176.63 0.26 -4.31 0.00 180.00 1,602.18 -1,435.98 0.65 -5.82 2,433,578.15 315,175.81 0.25 -4.70 0.25 130.00 1,802.18 -1,635.98 0.37 -5.48 2,433,577.87 315,176.14 0.12 -4.27 0.17 15.00 2,002.18 -1,835.98 0.37 -5.07 2,433,577.87 315,176.55 0.18 -3.97 0.25 100.00 2,202.18 -2,035.98 0.59 -4.56 2,433,578.07 315,177.06 0.14 -3.74 0.17 20.00 2,402.18 -2,235.98 0.79 4.03 2,433,578.26 315,177.59 0.14 -3.49 0.08 240.00 2,602.18 -2,435.98 1.00 -4.05 2,433,578.47 315,177.58 0.12 -3.65 0.50 179.00 2,802.17 -2,635.97 0.05 4.16 2,433,577.53 315,177.46 0.23 -3.09 0.23 207.81 2,991.17 -2,824.97 -1.10 -4.32 2,433,576.38 315,177.28 0.17 -2.42 0.25 296.00 3,187.17 -3,020.97 -1.26 -4.88 2,433,576.23 315,176.71 0.17 -2.73 0.00 0.00 3,367.17 -3,200.97 -1.08 -5.24 2,433,576.41 315,176.36 0.14 -3.10 0.25 35.00 3,547.17 -3,380.97 -0.76 5.01 2,433,576.73 315,176.59 0.14 -3.16 0.25 100.00 3,727.17 -3,560.97 -0.51 -4.40 2,433,576.97 315,177.21 0.15 -2.88 0.00 180.00 3,907.17 -3,740.97 -0.58 -4.01 2,433,576.90 315,177.59 0.14 -2.55 0.25 90.00 4,087.16 -3,920.96 -0.58 3.62 2,433,576.89 315,177.99 0.14 -2.26 0.50 210.00 4,267.16 -4,100.96 -1.26 -3.62 2,433,576.21 315,177.98 0.37 -1.80 0.50 230.00 4,447.16 4,280.96 -2.44 4.61 2,433,575.04 315,176.96 0.10 -1.72 0.25 209.00 4,627.15 -0,460.95 -3.29 5.41 2,433,574.21 315,176.16 0.16 -1.73 0.50 265.00 4,807.15 4,640.95 -3.70 -6.38 2,433,573.81 315,175.18 0.23 -2.16 0.25 299.00 4,987.14 -4,820.94 -3.58 -7.50 2,433,573.95 315,174.06 0.18 -3.07 0.25 303.00 5,158.14 -4,991.94 -3.20 -8.14 2,433,574.34 315,173.42 0.01 -3.80 0.25 245.00 5,347.14 -5,180.94 3.15 -8.86 2,433,574.41 315,172.70 0.13 -4.36 0.00 180.00 5,527.14 -5,360.94 -3.31 -9.22 2,433,574.24 315,172.35 0.14 -0.51 0.25 325.00 5,707.14 -5,540.94 -2.99 -9.44 2,433,574.57 315,172.12 0.14 ASS 0.25 340.00 5,887.14 -5,720.94 -2.30 -9.80 2,433,575.27 315,171.78 0.04 -5.62 0.25 340.00 6,067.14 -5,900.94 -1.56 -10.07 2,433,576.01 315,171.52 0.00 -6.32 0.25 26.00 6,247.14 -6,080.94 -0.84 -10.03 2,433,576.73 315,171.57 0.11 -6.79 0.75 329.00 6,427.13 -6,260.93 0.52 -10.47 2,433,578.10 315,171.16 0.36 -8.03 1.25 312.00 6,607.10 -6,440.90 2.85 -12.53 2,433,580.45 315,169.13 0.32 -11.13 1.25 305.00 6,787.06 -6,620.86 5.29 -15.60 2,433,582.94 315,166.10 0.08 -15.03 1.00 304.00 6,967.02 -6,800.82 7.29 -18.51 2,433,584.99 315,163.22 0.14 -18.53 1.25 289.00 7,146.99 -6,980.79 8.81 -21.67 2,433,586.56 315,160.08 0.21 -21.88 1.50 291.00 7,326.94 -7,160.74 10.29 -25.73 2,433,588.10 315,156.05 0.14 -25.86 1.50 306.00 7,506.88 -7,340.68 12.52 -29.83 2,433,590.40 315,151.98 0.22 -30.39 1.50 310.00 7,686.81 -7,520.61 15.42 -33.54 2,433,593.35 315,148.32 0.06 -35.08 1.50 305.00 7,866.75 -7,700.55 18.29 -37.28 2,433,596.28 315,144.63 0.07 -39.77 1.25 310.00 8,046.70 -7,880.50 20.90 -40.71 2,433,598.94 315,141.24 0.15 -44.06 4WO19 11:50:15AM Page 3 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Beaver Creek Unit Site: Beaver Creek Unit Well: Beaver CK Unit Wellbore: BCU 4RD Design: BCU 4RD WP07a Planned Survey Measured Vertical Depth Inclination Azimuth Depth (usft) (1) (1 (usft) Halliburton Standard Proposal Report Local Coordinate Reference: Well Beaver CK Unit 4 TVD Reference: BCU Planned RKB @ 166.20usft MD Reference: BCU Planned IRKS @ 166.20usft North Reference: True Survey Calculation Method: Minimum Curvature TVDss +NIS usft (usft) +E/.W (usft) -44.02 -47.49 -50.64 -53.97 -54.37 -54.72 -54.55 -52.94 -49.47 -36.80 -20.99 -3.58 9.73 28.52 47.12 80.65 119.74 146.34 167.76 194.51 221.96 233.19 258.57 284.84 324.37 347.63 386.43 402.35 8,227.20 1.50 310.00 8,226.65 -8,060.45 23.68 8,407.20 '1.50 315.00 8,406.59 -8,240.39 26.86 8,587.20 1.50 321.00 8,586.53 -8,420.33 30.35 8,767.20 2.00 324.00 8,766.44 -8,600.24 34.72 8,798.20 3.50 355.00 8,797.41 -8,631.21 36.10 8,830.20 3.50 344.00 8,829.35 -8,663.15 38.02 8,860.20 4.75 20.00 8,859.27 -8,693.07 40.06 8,906.20 5.25 27.00 8,905.10 -8,738.90 43.73 8,984.20 6.00 27.00 8,982.72 -8,816.52 50.54 9,187.20 7.75 35.00 9,184.26 -9,018.06 71.21 9,362.20 9.25 40.00 9,357.33 -9,191.13 91.65 9,52420 9.25 44.00 9,517.23 -9,351.03 110.99 9,638.20 9.75 46.00 9,629.67 -9,463.47 124.29 9,780.20 10.75 50.00 9,769.40 -9,603.20 141.15 9,904.20 11.50 52.00 9,891.07 -9,724.87 156.20 10,112.20 11.50 56.00 10,094.90 -9,928.70 180.56 10,323.20 14.00 58.00 10,300.68 -10,134.48 205.85 10,448.20 14.75 60.00 10,421.77 -10,255.57 221.82 10,545.20 14.50 62.00 10,515.62 -10,349.42 233.69 10,666.20 14.50 62.00 10,632.77 -10,466.57 247.91 10,784.20 15.50 66.00 10,746.75 -10,580.55 261.26 10,830.20 15.50 66.00 10,791.08 -10,624.88 266.26 10,934.20 15.25 68.00 10,891.36 -10,725.16 277.04 11,041.20 15.25 70.00 10,994.59 -10,828.39 287.12 11,200.20 15.25 72.00 11,147.99 -10,981.79 300.74 11,291.20 15.75 74.00 11,235.68 -11,069.48 307.84 11,439.20 15.75 76.00 11,378.13 -11,211.93 318.24 11,500.00 15.50 76.96 11,436.68 -11,270.48 322.07 KOP: Start Dir 12.75°/700' : 11500' MD, 11436.68TVD : 45° RT TF - 9 518" TOW 11,513.33 16.75 81.13 11,449.48 -11,283.28 322.77 End Dir : 11513.33' MD, 11449.48' TVD 11,533.33 16.75 81.13 11,468.64 -11,302.44 323.65 Start Dir 3°1100' : 11533.33' MD, 11468.64TVD 11,539.72 16.77 81.73 11,474.18 -11,307.98 323.90 TK TY0NEK_T4 1 11,585.49 17.01 86.45 11,518.55 -11,352.35 325.29 TK TYONEK_T4_2 11,600.00 17.10 87.89 11,532.42 -11,366.22 325.50 11,700.00 18.03 97.36 11,627.78 -11,461.58 324.05 11,730.01 18.40 99.99 11,656.28 -11,490.08 322.64 TK TYONEK_T4_3 11,800.00 19.37 105.74 11,722.51 -11,556.31 317.57 11,900.00 21.05 112.96 11,816.37 -11,650.17 306.06 12,000.00 22.98 119.09 11,909.08 -11,742.88 289.57 405.98 411.68 413.33 426.72 430.97 461.02 470.29 492.35 524.85 558.46 Map Map Northing Easting DLS Vert Section (usft) (usft) -8,060.45 2,433,601.77 315,137.97 0.14 -48.38 2,433,605.01 315,134.55 0.07 -53.08 2,433,608.55 315,131.46 0.09 -57.77 2,433,612.98 315,128.20 0.28 -63.18 2,433,614.36 315,127.82 6.65 -64.41 2,433,616.28 315,127.50 2.10 -65.97 2,433,618.32 315,127.70 9.37 -67.24 2,433,621.96 315,129.37 1.71 -68.56 2,433,628.72 315,132.94 0.96 -70.64 2,433,649.18 315,145.93 0.98 -75.41 2,433,669.37 315,162.06 0.95 -77.72 2,433,688.44 315,179.77 0.40 -78.10 2,433,701.52 315,193.29 0.53 -77.38 2,433,716.09 315,212.34 0.86 -75.07 2,433,732.84 315,231.18 0.68 -71.67 2,433,756.67 315,265.08 0.38 -63.65 2,433,781.34 315,304.56 1.20 -52.19 2,433,796.89 315,331.41 0.72 33.54 2,433,808.43 315,353.01 0.58 -35.91 2,433,822.23 315,379.97 0.00 -25.97 2,433,835.15 315,407.63 1.22 -14.92 2,433,839.97 315,418.93 0.00 -10.09 2,433,850.35 315,444.47 0.56 1.19 2,433,860.02 315,470.90 0.49 13.59 2,433,873.01 315,510.64 0.33 33.32 2,433,879.75 315,534.00 0.80 45.54 2,433,889.53 315,572.96 0.37 66.92 2,433,893.11 315,588.94 0.59 75.99 2,433,893.76 315,592.58 12.75 78.18 2,433,894.55 315,598.29 0.00 81.75 2,433,894.78 315,599.94 3.00 82.79 2,433,895.95 315,613.35 3.00 91.67 2,433,896.09 315,617.61 3.00 94.64 2,433,894.18 315,647.63 3.00 117.66 2,433,892.62 315,656.88 3.00 125.42 2,433,887.21 315,678.85 3.00 145.03 2,433,875.20 315,711.17 3.00 176.69 2,433,858.17 315,744.51 3.00 212.55 4/3/2019 11:50:15AM Page 4 COMPASS 5000.15 Build 91 Halliburton HALL I B U R TO N Standard Proposal Report Database: NORTH US + CANADA Company: Hilwrp Alaska, LLC Project: Beaver Creek Unit Site: Beaver Creek Unit Well: Beaver CK Unit Wellbore: BCU 4RD Design: BCU 4RD WP07a Local Co-ordinate Reference: Well Beaver CK Unit 4 TVD Reference: BCU Planned RKB @ 166.20usft MD Reference: BCU Planned RKB @ 166.20usft North Reference: True Survey Calculation Method: Minimum Curvature Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NIS +E -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -11,793.67 12,055.40 24.14 122.06 11,959.87 -11,793.67 278.30 577.51 2,433,846.61 315,763.38 3.00 234.18 TK_TVONEK_T4 4 12,100.00 25.11 124.27 12,000.41 -11,834.21 268.13 593.06 2,433,836.19 315,778.77 3.00 252.50 12,200.00 27.40 128.66 12,090.09 -11,923.89 241.80 628.57 2,433,809.31 315,813.86 3.00 296.44 12,300.00 29.80 132.42 12,177.89 -12,011.69 210.65 664.89 2,433,777.60 315,849.69 3.00 344.25 12,359.30 31.27 134.39 12,228.97 -12,062.77 189.94 686.78 2,433,756.55 315,871.24 3.00 374.38 SR_TYNK_CT7 12,400.00 32.30 135.65 12,263.56 -12,097.36 174.78 701.93 2,433,741.15 315,886.15 3.00 395.80 12,500.00 34.87 138.46 12,346.87 -12,180.67 134.27 739.57 2,433,700.07 315,923.15 3.00 450.94 12,600.00 37.49 140.92 12,427.59 -12,261.39 89.24 777.72 2,433,654.45 315,960.58 3.00 509.53 12,681.29 39.66 142.72 12,491.14 -12,324.94 49.39 809.03 2,433,614.12 315,991.27 3.00 559.59 L_E_TNK 12,700.00 40.16 143.11 12,505.49 -12,339.29 39.82 816.26 2,433,604.43 315,998.35 3.00 571.40 12,804.96 43.00 145.16 12,584.00 -12,417.80 -16.64 857.04 2,433,547.34 316,038.24 3.00 639.70 End Dir :12804.96- MD, 12584' TVD 12,900.00 43.00 145.16 12,653.51 -12,487.31 -69.83 894.08 2,433,493.58 316,074.43 0.00 703.02 13,000.00 43.00 145.16 12,726.64 -12,560.44 -125.80 933.04 2,433,437.01 316,112.51 0.00 769.65 13,100.00 43.00 145.16 12,799.78 -12,633.58 -181.78 972.01 2,433,380.44 316,150.59 0.00 836.28 13,185.60 43.00 145.16 12,862.38 -12,696.18 -229.69 1,005.36 2,433,332.01 316,183.19 0.00 893.32 SR_TYNK_CT4 13,200.00 43.00 145.16 12,872.91 -12,706.71 -237.75 1,010.97 2,433,323.86 316,188.68 0.00 902.92 13,300.00 43.00 145.16 12,946.05 -12,779.85 -293.72 1,049.94 2,433,267.29 316,226.76 0.00 969.55 13,334.77 43.00 145.16 12,971.48 -12,805.28 -313.18 1,063.49 2,433,247.62 316,240.00 0.00 992.72 TK_TYONEK_T4_5 13,400.00 43.00 145.16 13,019.18 -12,852.98 -349.69 1,088.91 2,433,210.72 316,264.84 0.00 1,036.18 13,446.20 43.00 145.16 13,052.97 -12,886.77 -375.55 1,106.91 2,433,184.58 316,282.43 0.00 1,066.96 SR_E10MKT 13,500.00 43.00 145.16 13,092.32 -12,926.12 -405.66 1,127.87 2,433,154.15 316,302.92 0.00 1,102.81 13,600.00 43.00 145.16 13,165.45 -12,999.25 -461.63 1,166.84 2,433,097.58 316,341.00 0.00 1,169.44 13,700.00 43.00 145.16 13,238.59 -13,072.39 -517.61 1,205.81 2,433,041.00 316,379.09 0.00 1,236.07 13,782.96 43.00 145.16 13,299.26 -13,133.06 -564.04 1,238.13 2,432,994.07 316,410.68 0.00 1,291.35 TK TYONEK_TS_X 13,800.00 43.00 145.16 13,311.72 -13,145.52 -573.58 1,244.77 2,432,984.43 316,417.17 0.00 1,302.71 13,900.00 43.00 145.16 13,384.86 -13,218.66 -629.55 1,283.74 2,432,927.86 316,455.25 0.00 1,369.34 13,901.07 43.00 145.16 13,385.64 -13,219.44 -630.15 1,284.15 2,432,927.26 316,455.66 0.00 1,370.05 TK_TYONEK_T5_X1 13,988.18 43.00 145.16 13,449.35 -13,283.15 -678.91 1,318.10 2,432,877.97 316,488.83 0.00 1,428.09 TK_TYONEK_T5_X2 14,000.00 43.00 145.16 13,458.00 -13,291.80 -685.52 1,322.71 2,432,871.29 316,493.33 0.00 1,435.97 14,042.53 43.00 145.16 13,489.10 -13,322.90 -709.33 1,339.28 2,432,847.23 316,509.53 0.00 1,464.31 TK_TYONEK T5 14,100.00 43.00 145.16 13,531.13 -13,364.93 -741.49 1,361.67 2,432,814.71 316,531.42 0.00 1,502.60 14,123.11 43.00 145.16 13,548.03 -13,381.83 -754.43 1,370.68 2,432,801.64 316,540.21 0.00 1,518.00 TK_TYONEK_TS_1 14,181.03 43.00 145.16 13,590.39 -13,424.19 -786.85 1,393.25 2,432,768.88 316,562.27 0.00 1,556.59 TK TYONEK TS -2 4WO19 11:50:15AM Page 5 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Beaver Creek Unit Site: Beaver Creek Unit Well: Beaver CK Unit 4 Wellbore: BCU 4RD Design: BCU 4RD WP07a Local Co-ordinate Reference: Well Beaver CK Unit 4 TVD Reference: BCU Planned RKB @ 166.20usft MD Reference: BCU Planned RKe @ 166.20usft North Reference: True Survey Calculation Method: Minimum Curvature Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -13,438.07 14,200.00 43.00 145.16 13,604.27 -13,438.07 -797.47 1,400.64 2,432,758.14 316,569.50 0.00 1,569.23 14,235.57 43.00 145.16 13,630.28 -13,464.08 -817.37 1,414.50 2,432,738.02 316,583.04 0.00 1,592.93 TK_TYONEK_TS_3 14,266.62 43.00 145.16 13,652.99 -13,486.79 -834.75 1,426.60 2,432,720.45 316,594.87 0.00 1,613.62 TK_TYONEK_T5_4 14,300.00 43.00 145.16 13,677.40 -13,511.20 -853.44 1,439.61 2,432,701.57 316,607.58 0.00 1,635.87 14,345.38 43.00 145.16 13,710.59 -13,544.39 -878.84 1,457.29 2,432,675.90 316,624.86 0.00 1,666.10 TK TYONEK T5_5 14,400.00 43.00 145.16 13,750.54 -13,584.34 -909.41 1,478.57 2,432,645.00 316,645.66 0.00 1,702.50 14,421.18 43.00 145.16 13,766.03 -13,599.83 -921.27 1,486.83 2,432,633.01 316,653.73 0.00 1,716.61 TK_TYONEK_T5_6 14,490.70 43.00 145.16 13,816.87 -13,650.67 -960.17 1,513.91 2,432,593.69 316,680.20 0.00 1,762.93 TK_TVONEK_T5_7 14,500.00 43.00 145.16 13,823.67 -13,657.47 -965.38 1,517.54 2,432,588.43 316,683.74 0.00 1,769.13 14,558.27 43.00 145.16 13,866.29 -13,700.09 -998.00 1,540.24 2,432,555.46 316,705.93 0.00 1,807.96 TK TYONEK T5_8 t� 1D //CCJJ 14,600.00 43.00 145.16 13,896.81 -13,730.61 -1,021.35 1,556.50 2,432,531.85 316,721.83 0.00 1,835.76 1 10 I //4 14,655.38 43.00 145.16 13,937.31 -13,771.11 -1,052.35 1,578.08 2,432,500.52 316,742.92 0.00 1,872.66 0, PTK_TYONEK_TS_9 V,9' 14 ,700.00 43.00 145.16 13,969.94 -13,803.74 -1,077.32 1,595.47 2,432,475.28 316,759.91 0.00 1,902.39 14,735.96 43.00 145.16 13,996.24 -13,830.04 -1,097.45 1,609.48 2,432,454.94 316,773.60 0.00 1,926.35 W� TYONEK_T5 -10 14,7,7 96.11 43.0.0 0 145.16 14,040.23 -73,874.03 -1,131.12 1,632.92 2,432,420.91 316,796.51 0.00 1,966.43 TK TYONEK_TS_11 14,800.00 43.00 145.16 14,043.08 -13,876.88 -1,133.30 1,634.44 2,432,418.71 316,797.99 0.00 1,969.02 14,866.56 43.00 145.16 14,091.76 -13,925.56 -1,170.55 1,660.37 2,432,381.05 316,823.34 0.00 2,013.38 TK_TYONEK_T5_12 14,900.00 43.00 145.16 14,116.21 -13,950.01 -1,189.27 1,673.40 2,432,362.14 316,836.07 0.00 2,035.66 14,914.08 43.00 145.16 14,126.51 -13,960.31 -1,197.15 1,678.89 2,432,354.17 316,841.43 0.00 2,045.04 TK TYONEK T5_13 14,937.41 43.00 145.16 14,143.57 -13,977.37 -1,210.20 1,687.98 2,432,340.98 316,850.32 0.00 2,060.58 TOP _TYONEK_G 14,951.24 43.00 145.16 14,153.69 -13,987.49 -1,217.95 1,693.37 2,432,333.15 316,855.59 0.00 2,069.80 HP -H20 -SAND 14,980.00 43.00 145.16 14,174.72 -14,008.52 -1,234.04 1,704.58 2,432,316.88 316,866.54 0.00 2,088.96 7" x 8 3/8" 15,000.00 43.00 145.16 14,189.35 -14,023.15 -1,245.24 1,712.37 2,432,305.57 316,874.15 0.00 2,102.29 15,100.00 43.00 145.16 14,262.48 -14,096.28 -1,301.21 1,751.34 2,432,248.99 316,912.24 0.00 2,168.92 15,144.91 43.00 145.16 14,295.33 -14,129.13 -1,326.35 1,768.84 2,432,223.59 316,929.34 0.00 2,198.84 BC_G1_A 15,200.00 43.00 145.16 14,335.62 -14,169.42 -1,357.18 1,790.30 2,432,192.42 316,950.32 0.00 2,235.55 15,202.57 43.00 145.16 14,337.50 -14,171.30 -1,358.62 1,791.30 2,432,190.97 316,951.30 0.00 2,237.26 BC_G1_B 15,230.63 43.00 145.16 14,358.02 -14,191.82 -1,374.33 1,802.24 2,432,175.09 316,961.98 0.00 2,255.96 BC_Gi_C 15,300.00 43.00 145.16 14,408.76 -14,242.56 -1,413.15 1,829.27 2,432,135.85 316,988.40 0.00 2,302.18 4/3/2019 11:50:15AM Page 6 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLG Project: Beaver Creek Unit Site: Beaver Creek Unit Well: Beaver CK Unit Wellbore: BCU 4RD Design: BCU 4RD WP07a Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Planned Survey Map Northing Easting OLS Measured (usft) (usft) Vertical 2,432,133.77 316,989.80 Depth Inclination 2,304.63 Azimuth Depth TVDss -N/-S +E/ -W (usft) (1) (°) (usft) milt (usft) (usft) 15,303.67 43.00 145.16 14,411.44 -14,245.24 -1,415.21 1,830.70 BC_G1_D 2,431,966.13 317,102.65 0.00 2,502.08 2,431,909.56 317,140.73 15,400.00 43.00 145.16 14,481.89 .14,315.69 -1,469.13 1,868.24 15,432.40 43.00 145.16 14,505.59 -14,339.39 -1,487.26 1,880.86 BC_G1_E 317,209.34 0.00 2,688.77 2,431,796.42 317,216.89 0.00 15,500.00 43.00 145.16 14,555.03 -14,388.83 -1,525.10 1,907.20 15,526.75 43.00 145.16 14,574.59 -14,408.39 -1,540.07 1,917.63 SC -GIF 0.00 2,835.24 2,431,676.30 317,297.75 0.00 2,843.45 15,589.63 43.00 145.16 14,620.58 -14,454.38 -1,575.27 1,942.13 BC_G2_A 2,431,600.98 317,348.46 0.00 2,932.17 2,431,574.31 317,366.40 15,600.00 43.00 145.16 14,628.16 -14,461.96 -1,581.07 1,946.17 15,700.00 43.00 145.16 14,701.30 -14,535.10 -1,637.04 1,985.14 15,770.11 43.00 145.16 14,752.57 -14,586.37 -1,676.28 2,012.45 BC G2_B 2,431,400.41 317,483.47 0.00 3,168.40 2,431,393.82 317,487.91 15,800.00 43.00 145.16 14,774.43 -14,608.23 -1,693.01 2,024.10 15,857.74 43.00 145.16 14,816.66 -14,650.46 -1,725.33 2,046.60 BC_G2_C 15,880.18 43.00 145.16 14,833.07 -14,666.87 -1,737.89 2,055.34 BC_G2_D 15,900.00 43.00 145.16 14,847.57 -14,681.37 -1,748.98 2,063.07 15,961.53 43.00 145.16 14,892.57 -14,726.37 -1,783.43 2,087.05 HEMLOCK 16,000.00 43.00 145.16 14,920.70 -14,754.50 -1,804.96 2,102.03 16,038.01 43.00 145.16 14,948.50 -14,782.30 -1,826.23 2,116.84 BC H1 16,100.00 43.00 145.16 14,993.84 -14,827.64 -1,860.93 2,141.00 16,112.32 43.00 145.16 15,002.85 -14,836.65 -1,867.83 2,145.80 BC H2 16,189.43 43.00 145.16 15,059.24 -14,893.04 -1,910.98 2,175.85 BC -H3 16,200.00 43.00 145.16 15,066.97 -14,900.77 -1,916.90 2,179.97 16,245.47 43.00 145.16 15,100.23 -14,934.03 -1,942.35 2,197.69 BC H4 16,292.60 43.00 145.16 15,134.70 -14,968.50 -1,968.73 2,216.05 BC_H5 16,300.00 43.00 145.16 15,140.11 -14,973.91 -1,972.87 2,218.93 16,400.00 43.00 145.16 15,213.24 -15,047.04 -2,028.84 2,257.90 16,405.86 43.00 145.16 15,217.53 -15,051.33 -2,032.12 2,260.18 BC_H6 16,500.00 43.00 145.16 15,286.38 -15,120.18 -2,084.82 2,296.87 16,579.20 43.00 145.16 15,344.30 -15,178.10 -2,129.14 2,327.73 16,600.00 43.00 145.16 15,359.51 -15,193.31 -2,140.79 2,335.83 16,611.66 43.00 145.16 15,368.04 -15,201.84 -2,147.31 2,340.38 WEST FORELAND 16,700. 00 43.00 145.16 15,432.65 -15,266.45 -2,196.76 2,374.80 Halliburton Standard Proposal Report Well Beaver CK Unit 4 BCU Planned RKB @ 166.20usft BCU Planned RKB @ 166.20usft True Minimum Curvature Map Map Northing Easting OLS Vert Section (usft) (usft) -14,245.24 2,432,133.77 316,989.80 0.00 2,304.63 2,432,079.28 317,026.48 0.00 2,368.81 2,432,060.95 317,038.82 0.00 2,390.41 2,432,022.71 317,064.56 0.00 2,435.45 2,432,007.57 317,074.75 0.00 2,453.27 2,431,972.00 317,098.70 0.00 2,495.17 2,431,966.13 317,102.65 0.00 2,502.08 2,431,909.56 317,140.73 0.00 2,568.71 2,431,869.90 317,167.43 0.00 2,615.42 2,431,852.99 317,178.81 0.00 2,635.34 2,431,820.32 317,200.80 0.00 2,673.81 2,431,807.63 317,209.34 0.00 2,688.77 2,431,796.42 317,216.89 0.00 2,701.97 2,431,761.61 317,240.33 0.00 2,742.97 2,431,739.84 317,254.97 0.00 2,768.61 2,431,718.34 317,269.45 0.00 2,793.93 2,431,683.27 317,293.06 0.00 2,835.24 2,431,676.30 317,297.75 0.00 2,843.45 2,431,632.68 317,327.11 0.00 2,894.82 2,431,626.70 317,331.14 0.00 2,901.87 2,431,600.98 317,348.46 0.00 2,932.17 2,431,574.31 317,366.40 0.00 2,963.57 2,431,570.13 317,369.22 0.00 2,968.50 2,431,513.56 317,407.30 0.00 3,035.13 2,431,510.24 317,409.53 0.00 3,039.04 2,431,456.98 317,445.39 0.00 3,101.76 2,431,412.18 317,475.54 0.00 3,154.53 2,431,400.41 317,483.47 0.00 3,168.40 2,431,393.82 317,487.91 0.00 3,176.16 2,431,343.84 317,521.55 0.00 3,235.03 41312019 11:50:15AM Page 7 COMPASS 5000.15 Build 91 Halliburton H A L L I B U R TO N Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Beaver CK Unit 4 Company: Hilcorp Alaska, LLC TVD Reference: BCU Planned RKB @ 166.20usft Project: Beaver Creek Unit MD Reference: BCU Planned RKB @ 166.20usft Site: Beaver Creek Unit North Reference: True Well: Beaver CK Unit 4 survey Calculation Method: Minimum Curvature Wellbore: BCU 4RD Design: BCU 4RD WP07a Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (1) Cl (usft) usft (usft) (usft) (usft) (usft) -15,287.80 16,729.20 43.00 145.16 15,454.00 -15,287.80 -2,213.10 2,386.18 2,431,327.32 317,532.67 0.00 3,254.48 Total Depth : 16729.2' MD, 15454' TVD .4 1/2" x 6' Targets Target Name -hitlmiss target Dip Angle Dip Dir. TVD +NIS +El -W Northing Easting -Shape (') (1) (usft) (usft) (usft) (usft) (usft) BCU 4RD Igt1 wp04 0.00 0.00 14,138.20 -1,765.41 1,424.42 2,431,790.00 316,57810 - plan misses target center by 579.73usft at 15141.54usft MD (14292.86 TVD, -1324.46 N, 1767.52 E) - Circle (radius 500.00) BCU 4RD tgt3 wp04 0.00 0.00 15,344.30 -3,074.81 1,982.01 2,430,472.11 317,115.07 - plan misses target center by 958.08usft at 16729.20usft MD (15454.00 TVD, -2213.10 N. 2386.18 E) - Circle (radius 150.00) BCU 4RD tgt2 wp04 0.00 0.00 14,617.20 -2,311.80 1,725.23 2,431,239.00 316,870.30 - plan misses target center by 695.51 usft at 15914.90usft MD (14858.46 TVD, -1757.32 N, 2068.87 E) - Circle (radius 150.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 14,980.00 14,174.72 7" x 8 3/8" 7 8-3/8 16,729.20 15,454.00 4 1/2" x 6" 4-112 6 11,500.00 11,436.68 95/8"TOW 9518 12-1/4 41312019 11:50:15AM Page 8 COMPASS 5000.15 Build 91 HALLIBURTON Database: Company: Project: Site: Well: Wellbore: Design: Formations NORTH US + CANADA Hilcorp Alaska, LLC Beaver Creek Unit Beaver Creek Unit Beaver CK Unit 4 BCU 4RD BCU 4RD WP07a Measured Vertical Depth Depth (usft) (usft) 14,042.53 13,489.10 15,526.75 14,574.59 13,446.20 13,052.97 13,988.18 13,449.35 14,937.41 14,143.57 11,539.12 11,474.18 15,880.18 14,833.07 16,245.47 15,100.23 16,292.60 15,134.70 14,866.56 14,091.76 16,112.32 15,002.85 14,266.62 13,652.99 14,655.38 13,937.31 16,038.01 14,948.50 15,303.67 14,411.44 15,144.91 14,295.33 14,558.27 13,866.29 15,432.40 14,505.59 13,782.96 13,299.26 15,857.74 14,816.66 14,181.03 13,590.39 14,123.11 13,548.03 12,681.29 12,491.14 14,490.70 13,816.87 14,235.57 13,630.28 14,735.96 13,996.24 15,770.11 14,752.57 11,585.49 11,518.55 12,055.40 11,959.87 14,951.24 14,153.69 16,189.43 15,059.24 13,334.77 12,971.48 15,961.53 14,892.57 14,421.18 13,766.03 14,345.38 13,710.59 14,914.08 14,126.51 13,185.60 12,862.38 15,202.57 14,337.50 13,901.07 13,385.64 16,405.86 15,217.53 16,611.66 15,368.04 15,589.63 14,620.58 12,359.30 12,228.97 15,230.63 14,358.02 14,796.11 14,040.23 11,730.01 11,656.28 Vertical Depth SS Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Beaver CK Unit 4 TVD Reference: BCU Planned RKB @ 166.20usft MD Reference: BCU Planned RKB @ 166.20usft North Reference: True Survey Calculation Method: Minimum Curvature Name TK_TYONEK_T5 BC_G1_F SR_E10MKT TK_TYONEK_T5_X2 TOP_TYONEK G TK_TYONEK_T4_1 BC_G2_D BC H4 BC H5 TK_TVONEK_T5_12 BC H2 TK_TYONEK_T5_4 TK_TYONEK_T5_9 BC H1 BC_G1_D BC_G1_A TK_TYONEK_T5_8 BC_G1_E TK_TYONEK_T5_X BC_G2_C TK_TYONEK_T5_2 TK_TYONEK_T5_1 L_E_TNK TK_TYONEK_T5_7 TK_TYONEK_T5_3 TK_TYONEK_T5_10 BC_G2_B TK_TYONEK_T4_2 TK_TYONEK_T4_4 HP -H20 SAND BC—H3 TK_TYONEK_T4_5 HEMLOCK TK_TYONEK_TS_6 TK_TYONEK_T5_5 TK_TYONEK_T5_13 SR_TYNK CT4 BC_G1_B TK_TYONEK_T5_X1 BC H6 WEST FORELAND BC_G2_A SR_TYNK_CT7 BC_G1_C TK_TYONEK_T5_11 TK TYONEK T4 3 Dip Dip Direction Lithology (°) (I 4!32019 11:50:15AM Page 9 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Beaver Creek Unit Site: Beaver Creek Unit Well: Beaver CK Unit 4 Wellbore: BCU 4RD Design: BCU 4RD WP07a Plan Annotations Measured Depth (usft) 11,500.00 11,513.33 11,533.33 12,804.96 16,729.20 Vertical Depth (usft) 11,436.68 11,449.48 11,468.64 12,584.00 15,454.00 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Local Coordinates +N/ -S +E/ -W (usft) (usft) 322.07 402.35 322.77 405.98 323.65 411.68 -16.64 857.04 -2,213.10 2,386.18 Halliburton Standard Proposal Report Well Beaver CK Unit 4 BCU Planned RKB @ 166.20usft BCU Planned RKB @ 166.20usft True Minimum Curvature Comment KOP: Start Dir 12.75°/100' : 11500' MD, 11436.68'TVD : 45° RT TF End Dir : 11513.33' MD, 11449.48' TVD StartDir 3°/100' : 11533.33' MD, 11468.64'TVD End Dir : 12804.96' MD, 12584' TVD Total Depth : 16729.2' MD, 15454' TVD 4/32019 11:50:15AM Page 10 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Beaver Creek Unit Beaver Creek Unit Beaver CK Unit 4 BCU 4RD 50133202390100 BCU 4RD WP07a Sperry Drilling Services Clearance Summary Anticollision Report 03 April, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: Beaver Creek Unit - Beaver CN Unit 4 - BCU 4RD - BCU 4RD WP07a Wall C—diremo: 2p33,577A1 N, 315,181.61 E pi 39 25.51" N,151. 0t' 4049" WI Datum Height: BCU Planned RKB @ 166.20usf1 Scan Range: 11,50000 to 16,72930 ui Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited Max Ellipse Separation is 10,00(1 usft Cruder. Scale Facmr Ali Verson: 5000.15 Build. 91 Scan Type: GLOBAL FILTER APPLIED'. AIL wellpaths within 200'- 100/1000 of reference Scan Type: 2500 HALLIGURTON Sperry Orilling Services HALLIBURTON Anticollision Report for Beaver CK Unit 4 - BCU 4RD WP07a Closest Approach 30 Proximity Seen on Current Survey Data (Highside Reference) Fmm To Survey/Plan Survey Tool (usft) (usft) Reference Design: Beaverereek Unit- BimVer CK Unit4- BCU 4RD-Bell 4RDWP117a 2_CB-Film-GMS 3,187.20 8,537.20 2 CB-F11—MMS 8,767.20 11,500.00 Seen Range: 11,500.00 to 16,Y19.20 ..ft. Measured Depth. 11,500.00 11,900.0 BCU 4RD "07a 2 MI) lntetp Ad+Sag 11,900.00 16]29.20 BCU 4RD WP07a 2 MWDaIFR1+MSaSa9 Ellipse error temp are correlated across surrey not tie -on points. Scan Radius is Unlimited. Clearance Factorculoa Is indented. Max Ellipse Separation is 10,000.00 usft Calculated ellipses Incomooda surface errors. Separalicn is the actual distance bereach ellipsoids. Measured Minimum ligkteaaured Ellipse @Measured Clearance Summary Based on Sale Name Depth Distance Depth separation Depth Factor Minimum Comparison Wali Name- Wellbore Name - Design (usft) (usft) (usft) (usft) usft Beaver Creek Unit Beaver CK Unit 4 -BCU 04 -BCU O4 11,800.00 23.23 11,800.0 18.88 11,796.75 5.331 Clearance Factor Beaver CK Unit 4 -BCU NP81-BCU Well 11,500D0 1,766.14 111500.00 1,745.85 91754.00 87.50 Clearance Factor Beaver CK Unit 4 -BCU 04PB2-BCU GIPB2 11,8011.011 2323 11,800.00 18.88 11,796]5 5.331 Clearance Factor Beaver CK Unit 4 -BCU 4RDPB1-BCU 4RDP81 11,800.00 23.23 11,800.00 to." 11,798.95 5.285 Clearance Factor Survey tool Dwaraln Fmm To Survey/Plan Survey Tool (usft) (usft) 202.20 2,80220 2_CB-Film-GMS 3,187.20 8,537.20 2 CB-F11—MMS 8,767.20 11,500.00 2 CB -Film -MSS 11,500.00 11,900.0 BCU 4RD "07a 2 MI) lntetp Ad+Sag 11,900.00 16]29.20 BCU 4RD WP07a 2 MWDaIFR1+MSaSa9 Ellipse error temp are correlated across surrey not tie -on points. Calculated ellipses Incomooda surface errors. Separalicn is the actual distance bereach ellipsoids. Distance Belvreaa centras Is the straight line distance batween wellbore centres. Clearance Factor= Distance Between Profiles I (Distance Belwaen ProOles - Ellipse Separation). All slation ceordinates were calculated using the Minimum Curvature method. Hilcorp Alaska, LLC Beaver Creek Unit Separation Warning Pass- Pass- Pass- Pass - 03 Aprg, 2019 - 12x01 Page 2 of4 COMPASS HALLIBURTON REFEPENCE NFORMPPON 1' Project: : Beaver Gres NAIM_]hAIXYI\CONVSI ALvyalpieW Site: Beaver Creek Unit °^^^*^a¢1wE1 x1earce: swcup ., cR uen b.rm. xnm Vn14a111VBl Rela— a R.1 Gowx heel; I<8.30 RI(B®IM.x0un Ads -C/-W NMltin9 F"slv�g LamuM laipwk Well: Beaver CK Unit 4 'AvaveCm..1. PelNrenx NZ Fipemry ONlling tacuMmN fell=CU 4RD am a nimum CwaW2 N.N O.W 113357741 05181,1 60°J435 NNP I51°1'i8.18V10.' Plan: BCU 4RD WP07a GLOBAL FILTER APPLIED: AN weNpMhs wWhn 20W, 100110W of W,e ,t ® s11RVEV PPGGRAM 115p0.W To 1672910 Date:201903:9T00M-00 wfidaNC:Y veypn: GASDIG DETMU Depth Fmm 0'. To 9urvryRlan Tool TVD TVD55 MD Bize Nam 20220 280230 BCU4WPB1 GMs IBCU 04Petl 2C6FImGMs 318720 858].20 BCU WPBI LB-MM9(BCU MPB1l 2_CA-FNm IVS 11436.6a 1@]OA. 1ti00W 9V8 95/8"TOW 87:)20 1IWOM BCu.aE LBM991000 C4PB2l 2CB-OH,M99 Idl)4 ]2 1400tl.52 1498000 ] 7"x82R° Ladder/S.F. Plots 11500.00 11900.00 BCU 4ROWPWa(BCU4RDl 2MWP;,MSPvraa9 1545iW 1528].AO 1697N.0 41tl 91Q"x6" 1190000 1672830 BCU dRBWPo7a (B CU 4RD) 2_MWDAFR1aMWsea 200.00 w BOU 04PB2 BCU RDPB1 0160.00 — �--�— _—_— '120ACI120 — i� -- - 0 v w 00.00 —t--- — O U m I Ti U O.W 11700 12025 12350 12675 13000 13325 13650 13975 14300 16625 14950 15275 15600 15925 16250 16575 16900 17225 17550 Measured Depth (650 usftrin) 4.00 I 1 o i ma.W 0 D Collision Risk Procedures Req. m 2.00 - OL Collision Avoidance Req. m - 1 I W 1 0 No Go Zane -Stop Dnlfirq I NOERRORS o.ao 12300 12600 12900 13200 13500 13800 14100 14400 14700 15000 15300 15600 15900 16200 16500 16800 17100 17400 17700 Measured Depth (600 ustUn) Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Friday, April 5, 2019 11:46 AM To: 'Monty Myers' Cc: Rixse, Melvin G (DOA); Davies, Stephen F (DOA) (steve.davies@alaska.gov) Subject: RE: PTD 219-011 (BCU04RD-Plug Back) Monty, Per our phone call this morning we will work the revised PTD for BCU 4A. Top of window at 11530 ft (vs 11500 ft) will allow the new drilling plan without a revision for KOP. ( <500 ft change) The P & A plan for the lost hole section looks good as proposed in the new PTD application. Lost hole section will need - 70 suffix and be labeled BCU -04RD P61. Will still need the revised PTD due to change in BHL for new wellpath. In other words you can start kickoff as proposed in the revised PTD with only change being the slightly lower window depth. Also, if you do leave BHA in wellbore please verify there are no RA sources. Otherwise NRC will need to get involved. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226) or (Guv.schwartz@alasko.aov). From: Monty Myers <mmyers@hilcorp.com> Sent: Friday, March 29, 2019 2:38 PM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Cc: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov> Subject: PTD 219-011 (BCU04RD-Plug Back) Guy, While cleaning out the well after a short trip at 14,234' our drillstring became detained. We were able to eventually pull the BHA free but we broke our tool while working pipe. The decision was made to POOH and LD the rotary steerable and drill to intermediate TO with a motor. We continued having issues with coal sloughing in on us while trying to POOH. When we finally got to the window, we have been unable to pull through the window with our BHA. The plan forward would be as follows: #NOTES# New well plan is outside the 500' radius New KOP is more than 500' above old KOP New fluid will be MOBM RIH and set BHA on bottom RIH with chemical cutter orjet cutter and cut drill pipe outside window at -12,080-12,100' POOH with DP PU window mill assembly and RIH Dress off whipstock and window POOH and PU overshot RIH and Fish BHA RU eline and set retainer at -12,020' RIH with cement stinger and sting into retainer Pump -150 bbls of abandonment cement POOH with stinger RU eline and set CIBP at -11,500' PU new whipstock assembly and RIH to 11,500' and mill window POOH and RU rotary steerable RIH to window Swap well to OBM Drill as per new well plan Please call me to discuss. We will be ready to cut pipe tonight The abandonment will not happen for a few days. The sidetracking is at least a week out. Thank you! Monty M Myers Drilling Manager 907.538.1168 (c) 907.777.8431 (o) TRANSMITTAL LETTER CHECKLIST WELL NAME: BW - N 9 b PTD: Development _ Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: 6&4*ey' LG F POOL: &Wer Cme F-, 0 I Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50 - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 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 Pilot Hole name ( PH) and API number (50--- ___) from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. 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 (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements 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 da s after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool BEAVER CREEK, BEAVER CREEK OIL - 80100 PTD#:2190110 Company HILCORP ALASKA LLC Initial Class/Type Well Name: BEAV Ul1LL0943D __Program DEV Well bore seg ❑ DEV/1-OIL _GeoArea 820 Unit 50212 On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached _ ...... _ ......... NA Commissioner: Date Commissioner Date PRESSURE water sands is now 14,678' MD (13,954' TVD). MPD will be needed. SFD 2 Lease number appropriate. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ Entire well in FED A028063, _ _ _ _ 3 Unique well name and number . . . . ...... . .. . .. . . . ....... . . . . . . Yes _ _ BEAVER. CREEK, BEAVER CREEK OIL - 80100 r governed by CO 2376 issued May 6, 2016 _ .. 4 Well located in a_defiined pool _ _ _ _ _ _ _ _ _ _ _ ___ _ _ _ _ __ _ _____ _ Yes _ Rule 3(b): Well spacing in the Beaver Creek Oil Pool shall be 40 acres. No wellbore may be opened nearer. . 5 Well located proper distance from drilling unit boundary_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ than 660 feet from the nearest open wellbore in the same pool. No wellbore may, b0 opened. nearer than 6 Well located proper distance from other wells. _ _ _ _ _ _ Yes _ 500 feet from the exterior boundary of the Beaver Creek Unit where owners and landowners_ 7 Sufficient acreage available in drilling unit Yes _ _ As planned, this well will. conform to sparing requirements, 8 if deviated, is wellbore plat included _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 9 Operator only affected party ............. . Yes .............................. ............. 10 Operator has appropriate bond in force ... . ... ... .. . .. . . ....... Yes 11 Permit can be issued without conservation order.. _ _ _ _ . .......... . . Yes ..... _ Appr Date 12 Permit can be issued without administrative. approval _ _ _ Yes _ 13 Can permit be approved before 15 -day wait ........................... Yes SFD 4/5/2019 14 Well located within area and strata authorized by Injection Order # (put 10# in. comments)(For NA. _ 15 All wells. within 1/4 mile area of review identified (For service well only) _ _ _ _ _ _ _ _ _ _ _ NA_ 16 Pre -produced injector; duration of Drs production less than 3 months _(For service welt only) NA 17 Nonconven, gas.confonns to AS31,05O30(L 1.A),02.A-0) .......................NA ................ 18 Conductor string provided _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ _ _ _ _ _ _ _ Sidetracking_ existing well BCU -04_ Engineering 19 Surface casing. protects all known USDWs _ _ _ _ _ _ _ _ _ _ _ NA _ _ _ Surface casing set and cemented._ 20 CMT vol adequate, to circulateon conductor & surf.csg . . .. . ... . . . . . . . . ........ NA - _ _ - - window.in 9 5/8" casing planned at 11530 ft. MD.. (2nd.window) .. 21 CMT vol adequate to tie-in long string to surf csg........ . ................... NA........ New BHL more than 500 ft from PTD. 22 CMT will cover all known productive horizons_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ ... 23 Casing designs adequate for C, T, B &_ permafrost _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - _ - _ - _ BTO caJcs supplied..Running 7" and 4,5" liner sections....... 24 Adequate tankage or reserve pit _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ Rig has steel pits .., All waste will be transported to KGF G &.I 25 If a_ re -drill, has_a 10-403 for abandonment been approved _ ..... _ _ . Yes Sundry 319.013 26 Adequate wellbore separation proposed. _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 27 If diverter required, does it meet regulations_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA _ _ BOPE will be used..._ wellhead is, in place_.. _ ..... _ ....... . Appr Date 28 Drilling fluid program schematic .& equip list adequate ......................... Yes Using MPD to manage Tyonek Water flow zone, GLS 4/5/2019 29 BOPEs,.do they meet regulation _ . . . . . ........ . . ............ Yes _ _ Rig 169 has 11".5000 psi DOPE.... .. _ .. 30 BOPS press rating appropriate; test to (put psig in comments)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ MASP 2700psi ...(1/3 gas column) Testing BOPE to 4000 psi 31 Choke_ manifold compliesw/API RP-53(May 84) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 32 Work will occur without operation shutdown.. _ _ _ _ Yes _ _ Sundry to Pert and _rurt. tubing is required,....... 33 Is presence of H2S gas. probable . . . . .......... . . . . ........ . . . . . . Yes _ _ H2S not expected but rig will use H2S monitoring system.. 34 Mechanicatconditlon of wells within AOR verified (For service well only) . .. . .......... NA .............. _ _ _ .. _ _ _ _ 35 Permit can be issued w/o hydrogen sulfide measures _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ H2S not recorded in nearby wells. Geology 36 Data presented on potential overpressure zones _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ High-pressure water sands will be encountered at. about 14,676' MI) (113,954' TVD) in this wellbore. _ Appr Date 37 Seismic analysis of shallow ges zones. ..... _ NA Anticipated pressureis. 8,318 psi, or about 11.5 ppg EMW. Planned mud weight for drilling ranges _ SFD 4/5/2019 38 Seabed .condition survey (if off -shore) _ _ NA _ from 9.5 to. 1.1.5 ppg..Operator plans to use Managed Pressure_ Drilling Technique. to control. flow 39 .Contact name/phone for weekly.progress reports. [exploratory only] .... . .............NA........ from those.water sands._ _ _ _ _ _ _ _ _ ...... Geologic Engineering Public Using MPD to drill Tyonek High pressure water zones. GIs. REVISED APPLICATION: Anticipated depth of those HIGH- Cois�sio�n�e'r: Date: Commissioner: Date Commissioner Date PRESSURE water sands is now 14,678' MD (13,954' TVD). MPD will be needed. SFD CFF `O 1 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v .00gcc.olaska.gov Re: Beaver Creek Field, Beaver Creek Oil Pool, BCU-04RD Hilcorp Alaska, LLC Permit to Drill Number: 219-011 Surface Location: 1641' FILL, 631' FEL, SEC. 33, T7N, R10W, SM, AK Bottomhole Location: 458' FSL, 1384' FWL, SEC. 34, T7N, R10W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to re -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, Daniel T. Seamount, Jr. Commissioner / v DATED this J day of February, 2019. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 RECEIVE® JAN 2 5 2019 1a. Type of Work: {.� /✓ l'�Y/' I A Proposed Well Class: Exploratory - Gas ❑ Service - WAG Service - Disp ❑ ic. Specify if well is proposed r: Drill ❑ Lateral ❑ 11b. Stratigraphic Test 1-1Development-Oil ❑� Service- Win! ❑ Single Zone ❑Q Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑� Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 a BCU-04RD 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 17,434' TVD: 15,452' Beaver Creek Field ' Beaver Creek Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 1641' FNL, 631' FEL, Sec 33, T7N, R10W, SM, AK FEDA028083 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 1809' FSL, 932' FWL, Sec 34, T7N, R10W, SM, AK N/A 2/15/2019 Total Depth: 9. Acres_in Property: 14. Distance to Nearest Property: 458' FSL, 1384' FWL, Sec 34, T7N, R10W, SM, AK 2560 3457' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 166.2' 15. Distance to Nearest Well Open Surface: x-315181 y- 2433577 Zone -4 GL / BF Elevation above MSL (ft): 148.2' - to Same Pool: 4,864' to BCU-05RD2 16. Deviated wells: Kickoff depth: 12,100 feet 17. Maximum Potential Pressures� in��i (see 20 AAC 25.035) Maximum Hole Angle: 60 degrees' Downhole: 8318 « EQ Zo�Surtace: 2772 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 8-3/8" 7" 29# P110 -IC TXP BTC 3,250' 11,900' 11,820' 15,150' 14,098' 480 ft3 6" 4-1/2" 12.6# L-80 DWC/C 2,384' 15,050' 14,048' 17,434' 15,452' 309 ft3 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): 15,940' 15,717' N/A 15,212' 15,010' 15,212' Casing Length Size Cement Volume MD TVD Conductor/Structural 288' 20" Driven 288' 288' Surface 2,989' 13-3/8" 2000 sx 2,989' 2,989' Intermediate 12,521' 9-5/8" 2868 sx 12,521' 12,425' Production 3,704' 7" 1400 sx 15,921' 15,699' Liner 326' 5" N/A 14,813' 14,623' Perforation Depth MD (ft): Various Through Tyonek/Hemlock Perforation Depth TVD (ft): Various Through Tyonek/Hemlock 14,535'- 15,461' 14,355' - 15,252' Hydraulic Fracture planned? Yes ❑ No P1 20. Attachments: Property Plat O BOP Sketch u Drilling Program Time v. Depth Plot v Shallow Hazard Analysis Diverter Sketch e Seabed Report e Drilling Fluid Program B 20 AAC 25.050 requirements 8✓ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Monty Myers Authorized Name: Monty Myers Contact Email: mmyers(Whilcoro.com Authorized Title: Drilling Manager Contact Phone: 777-8431 Authorized Signature: Dale: 9 . ( - commission use Only Permit to Drill Number:Permit Approval See cover letter for other Number: —011 So- 33-a. -�Q _ Q Date: requirements. Conditions of approval : If box is c cke/d'J, well may not beusedto explore for, test, or produce coalbed methane, as hydrates, or gas contained in shales: ry Other: + L..��[�j oSZ �rE 51 Samples req'd: Yes ❑ No [V Mud log req'd: Yes,❑] Nolte / HzS measures: Yes ❑ No,Fe, Directional svy mq'd: Yes Ly Nor❑] `.,,,, o i4 11,10 CAW, r gi^D�L "' ��pacmgexceptionreq'd: Yes❑ No L�" Inclination -only svy req'd: Yes❑ Nou �/�` M CAW, C)Cy ` !A\ Post initial injection MIT req'd: Yes ❑ No ❑ w 7]Ir -ODS- (C)C14) APPROVED BY ^O (T / p G�JMISSIONER nproved by: COMTHE COMMISSION Date: / Submit Form and 10-401 Reviser 5/2017 This permit is valid for"hl h t proval per 20 AAC 25.0050�i Attachments in Duplicate �� V R-5 f, "o r7?,? �-C.B. n Hilcorp 1/24/2019 Monty Myers Drilling Engineer Commissioner Alaska Oil & Gas Conservation Commission 333 W. 71" Avenue Anchorage, Alaska 99501 Re: BCU-04RD Dear Commissioner, Hilcorp Alaska, LLL P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8431 Email mmyers@hilcorp.com BCU 04RD is an oil producer planned to be re -drilled in a South-easterly direction from the existing BCU04 utilizing the existing casing program down to 12100' MD / 12016' TVD. At 12,100' MD the parent wellbore will be sidetracked and new wellbore drilled penetrating several Tyonek sands, including the HP Tyonek Water Sand. A 3250'X 8-3/8" hole section is planned and a 7" liner will be run to isolate the HP Water sand. The production hole will be drilled penetrating several Hemlock targets. A 2484'x 6" open hole section is planned. A 4-1/2" 12.6# L-80 DWC/C prod liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with 3-1/2" production tubing string. Drilling operations are expected to commence approximately February 151^, 2019 If you have any questions, please don't hesitate to contact myself at 777-8431 or Paul Mazzolini at 777-8369. Sincerely, Monty Myers Drilling Engineer Hilcorp Alaska, LLC Page 1 of i Hilcorp Alaska, LLC BCU-04RD Drilling Program Beaver Creek ro d by: M tMy s Revision 1 January 18, 2019 ff MIN -1, klk.. LLC BCU 04RD Drilling Procedure Rev I 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 Summary ........................................................................................................................................... 7 8.0 Mandatory Regulatory Compliance / Notifications ..................................................................................... 9 9.0 R/U and Preparatory Work ......................................................................................................................... 12 10.0 BOP N/U and Test ........................................................................................................................................ 13 11.0 Mud Program and Density Selection Criteria ........................................................................................... 14 12.0 Whipstock Running Procedure ................................................................................................................... 15 13.0 Whipstock Setting Procedure ...................................................................................................................... 17 14.0 Drill 8-3/8" Hole Section .............................................................................................................................. 19 15.0 Run 7" Drilling Liner ................................................................................................................................... 21 16.0 Cement 71' Drilling Liner ............................................................................................................................. 24 17.0 Drill 6" Hole Section ..................................................................................................................................... 28 18.0 Run 4-1/2" Production Liner ....................................................................................................................... 31 19.0 Cement 4-1/2" Production Casing ............................................................................................................... 34 20.0 Wellbore Clean Up & Displacement ........................................................................................................... 38 21.0 Run Completion Assembly .......................................................................................................................... 39 22.0 RDMO ........................................................................................................................................................... 39 23.0 BOP Schematic ............................................................................................................................................. 40 24.0 Wellhead Schematic ..................................................................................................................................... 41 25.0 Days vs Depth ................................................................................................................................................ 42 26.0 Geo-Prog ....................................................................................................................................................... 43 27.0 Anticipated Drilling Hazards ...................................................................................................................... 45 28.0 Rig Layout ..................................................................................................................................................... 46 29.0 FIT Procedure ............................................................................................................................................... 47 30.0 Choke Manifold Schematic .......................................................................................................................... 48 31.0 Casing Design Information .......................................................................................................................... 49 32.0 8-3/8" Hole Section MASP ........................................................................................................................... 50 33.0 6" Hole Section MASP ................................................................................................................................. 51 34.0 Spider Plot (Governmental Sections) .......................................................................................................... 52 35.0 Surface Plat (As -Built) ................................................................................................................................. 53 36.0 Directional Program (WP05b) .................................................................................................................... 54 ff nilmrp Alaska, UA: 1.0 Well Summary BCU 04RD Drilling Procedure Rev 1 Well BCU 04RD Pad & Old Well Designation Sidetrack of existing well BCU 04RD (PTD#172-013 Planned Completion Type 3-1/2" Gaslift Completion Target Reservoirs Hemlock Hl through H5 Planned Well TD, MD / TVD 17434' MD / 15452' TVD PBTD MD / TVD 17300' MD / 15428' TVD Surface Location Governmental 1641' FNL, 631' FEL, Sec 33, T7N, RIOW, SM, AK Surface Location (NAD 27) X=315181.614, Y=2433577.412 Surface Location AD 83 X=1455202.718, Y=2433338.409 Top of Productive Horizon Govemmental 1809' FSL, 932' FWL, Sec 34, T7N, R10W, SM, AK TPH Location AD 27 X=316713.6, Y=2431730.9 TPH Location AD 83 X=1456734.7, Y=2431491.7 BHL Governmental 458' FSL, 1384' FWL, Sec 34, T7N, R10W, SM, AK BHL (NAD 27) X=317146.7, Y=2430372.9 BHL AD 83 X=1457167.8, Y=2430133.7 AFE Number 1910116D AFE Drilling Das 30 AFE Drilling Amount $905K DeCom,$7.3 MM Dril, $2.1MM Com, $276K Fac Work String 4-1/2" 16.6# S-135 CDS-40 RKB — AMSL 18' KB — 148.2' AMSL Ground Elevation 166.2' AMSL BOP Equipment 11" 5M Townsend Type 90 Annular BOP 11" 5M Townsend Type 82 Double Ram 11" 5M Townsend Type 82 Single Ram Page 2 Revision 0 January 2019 H mi,,,.N Al,k.. rr.c 2.0 Management of Change Information BCU 04RD Drilling Procedure Rev 1 H Hilcorp Alaska, LLC Hilootp Hil crp Changes to Approved Permit to Drill Date: January 18, 2019 Subject: Changes to Approved Permit to Drill for BCU 04RD File #: BCU 04RD Drilling Program Any modifications to BCU 04RD Drilling Program will be documented and approved below. Changes to an approved APD will be communicated and approved by the AOGCC prior to continuing forward with work. Approval: Monty M Myers Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Revision 0 January 2019 U 3.0 Tubular Program Hole 3/8" 7' 29 7.75" 6.184" 6.059 6" 4-1/2" 12.6 5.0 3.918 3.833 4.0 Drill Pipe Information BCU 04RD Drilling Procedure Rev 1 P-110 IC I TXP BTC I 1 Hole OD (ink' ID TJ OD Wt Section in #/ft(k-lbs) 8-3/S" 4-1/2" 3.826" 2-11/16" 5-1/4" 16.65-135 CDS-40 17693 16769 595k & 6" • All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Revision 0 January 2019 H 11H.,p A1.4 , LLC 5.0 Internal Reporting Requirements BCU 04RD Drilling Procedure Rev 1 21.1 Fill out daily drilling report and cost report on Wellez. L Report covers operations from 6am to 6am ii. 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. iii. Ensure time entry adds up to 24 hours total. iv. Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 21.2 Afternoon Updates i. Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcoM.com and Win ger(a�hilcorp.com 21.3 Intranet Home Page Morning Update i. Submit a short operations update each morning by lam 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. 21.4 EHS Incident Reporting L 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: 0:907-777-8477 C:907-350-9439 ii. Notify Drlg Manager 1. Monty M Myers: O: 907-777-8431 C: 907-538-1168 iii. Submit Hilcorp Incident report to contacts above within 24 hrs 21.5 Casing Tally i. Send final "As -Run" Casing tally to mmyers@hilcorp.com and Winger 21.6 Casing and Cart report i. Send casing and cement report for each string of casing to mmyers nghilcomcom and cdinger@hilcorp.com Page 5 Revision 0 January 2019 H Ilik,orp Alaeka, LLL' BCU 04RD Drilling Procedure Rev 0 6.0 Planned Wellbore Schematic Beaver Creek Unit Well: BCU 04RD SCHEMATIC Completed: Future PTD: TBD 103 Eley: IWZ/ BF/a Ow.: 14BZ Cj-1 g46 �: �•� IL,lo7r ISO BCM4 FITS 13 Sf" f 11190 Iz•s PPS f CASING DETAIL Size Type Wt/Grade/Cann Drift ID Top Btm 20' C ncivaar 94 tH0 A Surface 288' 4 1 Surfau 7211L80 12415 Sur/au 2,989' _13-3/B^ 9-5(8" Pro4u n 4] &535 rFW, 995, PIM JIM Surfau 12 521' 7- liner ?9 P-13010/TXP BTC 6.059 11,900' L5150' 4I U. I 12.6 L -0O C 3.833 15054 11434 JEWELRY DETAIL No Depth lum 1 liner Top Patloer 2 34,800' Water Swea Packs 3 1 15000' I Water Swed Pa4or 4 1 15050' I li T Packer 1 �9 � j2i5 =J 283 58ntlsTop(MD) TBD ) v s,6 . TD -17,434' (MDI /TD=15,452'(TFO) PBID=S7,4DD (ME4 I PBID.15A27(TA) PERFORATION DETAIL GENERAL WELL INFO AP.: TBD Initial Com letian -113 1973 Revised By: CID 1/18/2019 Page 6 Revision 0 January 2019 6.0 Planned Wellbore Schematic BCU 04RD Drilling Procedure Rev 1 NI Elev: 166Z/ BF/GL Eb.: 14&Z Beaver Creek Unit Well: BCU 04RD SCHEMATIC Completed: Future CASING DETAIL PTD: TBD NI Elev: 166Z/ BF/GL Eb.: 14&Z GENERAL WELL INFO API: TBD InItiN Cwn - 33 19TJ TD -17,434' (MD) /TDs 15,45Z(7W) PBrD-!17AW (MLI /PBTD-15,427(%0) Re Is day CIO 1/]8/2019 Page 6 Revision 0 January 2019 CASING DETAIL JEWELRY DETAIL Size Type W:/Gr dC /Conn Drih lD Top Bim 2D` C4r..or 9 N40 A Surtece 288' 13-31V Surfaw 72 /N -BO 12415 Surface 2,WT 9-5/8" Pro4urtlon 47&S3.5/N-W,S-95, P310 8.661 Surface 12,521' T' Oner 29/ P-110 IC / TXP BTC 6.059 11,904 35158 412" liner =6 Ld0 OWCC 3.833 SS 05 1]434' GENERAL WELL INFO API: TBD InItiN Cwn - 33 19TJ TD -17,434' (MD) /TDs 15,45Z(7W) PBrD-!17AW (MLI /PBTD-15,427(%0) Re Is day CIO 1/]8/2019 Page 6 Revision 0 January 2019 JEWELRY DETAIL No Depth 11em 95/& 1 .2372- Dner Tap Pe r 2 14800' Water S.11 Pe 3 15000' Water S.11 Pe / 4 15050' U—r Top Porker � 283 I CIF PERFORATION DETAIL San& Top [MD) Dtm(MD) Top rrVDI JIM VVD) FT Size Det. SM.t TBD GENERAL WELL INFO API: TBD InItiN Cwn - 33 19TJ TD -17,434' (MD) /TDs 15,45Z(7W) PBrD-!17AW (MLI /PBTD-15,427(%0) Re Is day CIO 1/]8/2019 Page 6 Revision 0 January 2019 H l ilrorn Alaxke. LLC X028083 164' (19' AGL) 1/26/1972 Tree cxn: 6412" Oes Directional Data Maximum Hole Angie- 18 (71113,780' MD Angie Through'G': 14 Angle Through Hemlock: 14 BC -04 Pad 4 1,700' FNL, 660' FEL, Sec. 33, T7N, R10W, S.M. Jewel ry Depth 9-518" 1. Otis X Nipple (2.613 ID) 14,482' BTC 2. 3-112" ha0cut Muleshoe 14482 jag 3. 3-112" Baker seal assembly -8040 PBR (17.91' (53.5ppf ends 12,521') 12,217' length) Baker PBR (4.00" ID) w/concentric Bottom MD coulping 14 00" ID) and Baker SBE (18 74' length) 14,464' ND 4. Baker FAB -1 pkr, sue 83FA47(400"ID) 6. Baker FAB -1 pkr, size 83FA47 (4.00" ID) 14,484' 14,813' L 1 �GS 6. Cement retainer 15,361' - PROPOSED SCHEMATIC Conductor 10 R Bottom J\ MD 0' 288' ND 0' 288' Cmt w\ 60 sks Class G Surface Casino 13-318" N-80 (72ppf ends 1,942') l 8RD J-55 (68ppf ends 2,989) 231 TOP Bottom 3 MD 0' 2,989 ND 0' 2,989' Cmt w12,000 sks Class G w14% gel; r followed by 300 sks Class G 7ti8v Intermediate Casing T' 9-518" N-80 (47.Oppf ends 7,421') BTC S-95 (47.Oppf ends 9,938') jag P-110 (53.5ppf ends 12,521') 12,217' Top Bottom MD 0' 12,521' ND 0' 12,425' Liner T' P-110 (29ppf ends 12,552') BTC P-110 (32ppf ends 15,921') State/Prov: jag Bottom MD 12,217' 15,921' ND 12,130' 15,699' Chit w\1,400 sks Glass G .F� �J SlicklIne gll tag 41 15,212' RKB (iTI27/14) Hemixk J.-JR5 6 TD I PBTD 15,940' MD 15,315' MD 15,717' ND 15,110' ND Well Name & Number. Beaver Creek Unit #4 Lease: A .028083 Isolation Liner Kenai Peninsula Borough State/Prov: Alaska I Count USA S. N-80 (18ppf) p> Top of Cement -14,215 " �M op of Liner Hanger Tubing MD i2a Bottom 14,487' 14,813' L 1 �GS 7CIBP -14,250 Revised By: @12,21]' 3-1/2" L-80 9.3ppf ND 14,309' 14,623' 1/14/2019 8RD-MOD Top Bottom 3.5" Tubing Cut -14,300' Shoe @ 12,521' MD 0' 14,482' ND 0 14,304' Top of Cement -14,360' - Tyonek Paris; - -PpL. 3 7,0;) 2: 1 MD TVD Net Ft Zone t4F 2 14$35'-14,565' 14,355'-14,384' 30'Sgzd FppeCG' 4 1r73 3 4 14,731'-14,743' 14,544'-14,556' 12' Sqzd Upper'G' 4 8128/88 �GSr 15,063'-15,123' 14,865'-14,923' 60' Lower'G' 6 04/75113 /l 15,040'-15,100' 14,843'-44,901' 60' Lower'G' 8 12/11186 15108'-15,128' 14,909'-14,928' 20' Lower'G' 8 12/11188 ?s'k 15,132'-15,146' 14,932-14,946' 14' Lower'G' 8 12110/88 15,149'-15,165' 14,946'-14,962' 16' Lower'G' 6 01/15114 .(girt ,r!t°•' 15,155'-15,175' 14,954'-14,974' 20' Lower'G' 8 12/10188 - r 15,185'-15,210' 14,984'45,008' 25' Lower 'G' 8 12/10'88 _ ., FL ,;:�, -,-G- 15,361'-15,376' 15,154'-75,169' 15' Hemlock 4 72/12172 •- 15,382'-15,397' 15,176-15,189' 15' Hemlock 4 12/12/72 15,416-15,431' 15.206-15,222' 15' Hembck 4 12/12/72 15,446-15,461' 15,237-15,252' 15' Hemlock 4 12/12172 „- Last 4 parts zone Is Hemlock DST Perforations and is iso4aled by cmlretainer, but never .F� �J SlicklIne gll tag 41 15,212' RKB (iTI27/14) Hemixk J.-JR5 6 TD I PBTD 15,940' MD 15,315' MD 15,717' ND 15,110' ND Well Name & Number. Beaver Creek Unit #4 Lease: A .028083 County or Parish: Kenai Peninsula Borough State/Prov: Alaska I Count USA Angle @KOP and Depth: 2.0° @ 8,765' Arlgle/Perfs: 1 13015° Maximum Deviation: 18° IR 13,780' Date Completed: 01113/73 Ground Level (above MSL): 144.8' 1 RKB (above GL): 19.2' Revised By: Joe Kaiser Downhole Revision Date: 12127120141 Schematic Revision Date: 1/14/2019 n 11ticorp Alaska, L1,C 172-013 A-028083 164' (19' AGL) Tree czo. 6.1/2' Otis Directional Data Maximum Hole Angle. 18 @ 13,780' MD Angle Through'G': 14 Angle Through Hemlock. 14 BC -04 Pad 4 1,700' FNL, 660' FEL, Sec. 33, T7N, R10W, S.M. Jevvel Depth 1. Otis XXO profile for SSSV (2.613' ID) 250' 2. Otis X Nipple (2.813 ID) 14,482' 3.3-1/2"haffcut Muleshoe 14,482' 4. 3-112" Baker seal assembly -8040 PBR (17.91' 2,989' length) Baker PBR (4 00" ID) w/concentric Mandrel cculping (4 00" ID) and Baker SBE (18.74' length). 14,464' 5. Baker FAB -1 pkr, size 83FA47 (4.00" ID) 14,464' 6. Baker FAB -1 pkr, size 83FA47 (4 00" ID) 14813' 7. Cement retainer 15,361' Gas Lift Data 95/8" N-80 13-3/8" N-80 (72ppf ends 1,942') 8RD J-55 Size for all: 3.5" ID for all, 2.867' Brnom MD 0' 2,989' Depth Mandrel Valve Tvss Latch FQJ3 2,737' Flopetrol SPM -2 1.5" GLV 1.51R RK 16/64 4,74T Flopetrel SPM -2 1.5" GLV 1.5R RK 16/64 6,132' Flopetrol SPM -2 1.5" GLV 1.5R RK 16/64 7,200' Flopetrol SPM -2 1.5" GLV 1.5R RK 16/64 8,079' Flopelrol SPM -2 1.5" GLV 1.5R RK 16/64 8,862' Flopetrol SPM -2 1.5'* GLV I.SR RK 20/64 9,596' Flopetrol SPM -2 1.5" GLV 1.5R RK 20/64 10,215' Flopetrel SPM -2 1.5" GLV 1,SR RK 20/64 10,837' Flopetrol SPM -2 1.5" GLV 1.5R RK 20/64 11,463' Flopetrol SPM -2 1.5" GLV 1.5R RK 20/64 12,085' Flopetrol SPM -2 1.5" GLV I.SR RK 20/64 12,708' GLMA BST 1" GLV 1.OR BK -2 20/64 13,206' GLMA BST 1" GLV 1.OR BK -2 20/64 13,730' GLMA BST 11" GLV 1.OR BK -2 20/64 14,259' GLMA BST 1" GLV I.OR BK -2 3/8 2 4 ACTUAL SCHEMATIC _Conductor 20" H-40 94ppf Z02 Bottom MD 0' 288' TVD a 268' Dint w160 sks Class G Surface Caslna 95/8" N-80 13-3/8" N-80 (72ppf ends 1,942') 8RD J-55 (68ppf ends 2,989') LB Brnom MD 0' 2,989' TVD 0' 2,989' Chit w12,000 sks Class G w/4% gel; followed by 300 sks Class G Intermediate Casino 95/8" N-80 (47.Oppf ends 7,421') BTC S-95 (47.Oppf ends 9,938') P-110 (53.Sppf ends 12,521') Lop Bottom MD 0' 12,521' TVD 0' 12,425' Tubina 7" P-110 3-1/2" L-80 9.3ppf 8RD-MOD 148 Bottom MD 0' 14,482' TVD 0' 14,304' Top of Liner Hanger @ 12,217' Shoe is, 12,521' Liner 7" P-110 (29ppf ends 12,552') BTC P-110 (32ppf ends 15,921') TVD 14,309 122 Bottom MD 12,217' 15,921' TVD 12,130' 15,699' Cmt x41,400 sks Glass G Isolation Liner 5" N-80 (18pp0 TOR Bottom MD 14,487' 14,813' TVD 14,309 14,623' Hemlock 7 TD PBTD 15,940-10D 15,315' MD 15,717 -TVD 15,110, TVD 4 per's zone is Hemlock DST Perforations and is isolated by cmlretainer, but never Sllckline fill tag 0 15,212' RKB (12127/14) Well Name 8, Number: �'.f D TVO Net Ft Zone SPFQ3ite Kenai Peninsula BFu h 3 14,535'-14,565 14,355'-14,384' 30' Sqzd Upper'G' 4 1173 -5 '14,731'-14,743' 14,544'-14,556' 12'Sgzd Uppar'G' 4 8128188 19.2' -15,063'-15,123' 14866-14,923' 60' lower'G' 6 04115!13 15,040'-15,100' 14,843'-14,901' 60' Lower'G' 8 12!11!68 6 15,108'-15,126' 14,909-14,928' 20' Lower'G' 8 12/11188 15,137-15,146' 14,932'-14,946' 14' Lower'G' 8 12110188 15,149-15,165' 14,946-14,962' 19 Lower'G' 6 01/15/14 15,156-15,175' 14954'44,974' 20' Lower'G' 8 12!10188 15,185'-15,210' 14,984'-15,008' 25' Lower'G' 8 12/10186 15,361'-15,376' 15,154'-15,169' 15' Hemlock 4 12/12/72 15,382'-15,397' 15,175'45,189' 15' Hemlock 4 12/12/72 15,416'-15,431' 15,206'-15,222' 15' Hemlock 4 1202172 15,446'-15,461' 15.237'-15,252' 15' Hemlock 4 12)12172 Hemlock 7 TD PBTD 15,940-10D 15,315' MD 15,717 -TVD 15,110, TVD 4 per's zone is Hemlock DST Perforations and is isolated by cmlretainer, but never Sllckline fill tag 0 15,212' RKB (12127/14) Well Name 8, Number: Beaver Creek Unit N4 Lease: A - 028083 County mParish: Kenai Peninsula BFu h State/Prov: Alaska Country: USA Angle @KOP and De 2.0° 8,765' Angle/Peds: 13°-,15° Maximum Deviation: 18° 13,780' Date Completed: 01/13/73 Ground Level (above MSL): 144.8' 1 RKB (above GL):1 19.2' Revised By: Stan Porhola Downhole Revision Dale: 12127120141 Schematic Revision Date:1 12129/2014 U ua.rorp AWka, u.c 7.0 Drilling Summary BCU 04RD Drilling Procedure Rev 1 BCU 04RD is an oil producer planned to be re -drilled in a South-easterly direction from the existing BCU04 utilizing the existing casing program down to 12100' MD / 12016' TVD. At 12,100' MD the parent wellbore will be sidetracked and new wellbore drilled penetrating several Tyonek sands, including the HP Tyonek Water Sand. A 3250'X 8-3/8" hole section is planned and a 7" liner will be run to isolate the HP Water sand. The production hole will be drilled penetrating several Hemlock targets. A 2484' x 6" open hole section is planned. A 4-1/2" 12.6# L-80 DWC/C prod liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with 3-1/2" production tubing string. Drilling operations are expected to commence approximately February 15', 2019. 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. A separate sundry notice will be submitted to cover P&A and wellbore preparation for the sidetrack and for running the completion assembly General sequence of operations pertaining to this approved drilling procedure: 1. Rig #169 will be rigged up on BCU 04 for decompletion operations. 2. Set 9-5/8" Storm packer at 500' 3. RD BOPE, Remove attachment spool and original tubing head. 4. Install new tubing head which will put the top of the wellhead at ground level 5. RIG up full drilling BOPE w/ MPD and test. 6. Pull test packer 7. RU E -line to set CIBP. RIH w/ CIBP and set at 12,100' (5' above a collar) 8. RD E -line and test casing/CIBP t 2500 si " 9. PU 8.375" window milling assembly and DP and cleanout to CIBP S 10. POOH standing back, PU whipstock, and mills and TIH to CIBP 11. Orient whipstock and set at 45 deg right of high side. 12. Displace well to 9.5 ppg WBM 14. Perform FIT to 12.5 ppg 15. Drill 8-3/8" production hole from 12100' to 15150' MD. 16. Perform short trip and condition mud. POOH /ice,✓ 17. LD Directional Tools. RIH w 7" liner. Set liner and cement. Circ wellbore clean. 18. POOH, standing back DP " 19. PU 6-1/8" bit and drilling BHA and TIE to float collar 20. Test casing and liner lap to 2500 psi 21. Drill float equipment and 20' of new formation Page 7 Revision 0 January 2019 BCU 04RD Drilling ProcedurH I e Rev 7 nm,,.p nl.,.m., ua: 22. Perform FIT to 13.5 ppg 23. Drill 6-1/8" prod hole from 15150' to 17434' MD 24. Perform short trip and condition mud. POOH 25. LD Directional Tools. RIH w 4-1/2" liner. Set liner and cement. Circ wellbore clean. 26. POOH, standing back DP 27. PU 4-1/2" casing scraper assembly and TIH to landing collar. 28. Circ casing clean. POOH laying down DP. ay. xun s-112 upper compienon. La 30. ND BOPE, NU tree and test void 31. RDMO Page 8 Revision 0 January 2019 BCU 04RD Drilling Procedure Rev 1 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. • BOPs shall be tested at (2) week intervals during the drilling of BCU 04RD. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/4000 psi & subsequent tests of the BOP equipment will be to 250/4000 psi for 10/5 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. • 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. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system" • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements" • Ensure both AOGCC and BLM approved drilling permit is posted on the rig floor and in Co Man office. Variance Requests: • Onshore Oil and Gas Order No. 1, Section III. D. 3. C. o Hilcorp requests approval to install a 2-1/16" 5M HCR valve on kill line in lieu of a check valve. Operator suspects a freeze plug risk associated with installation of a check valve in the kill line. o Hilcorp requests approval to utilize flexible choke and kill lines in lieu of hard piping. ''.The calculated MASP for this wellbore when completely evacuated to gas is 8318 psi. However, ..for Beaver Creek (HP Tyonek), we assume that the well can never flow 100% gas, due to the 4}pwater in the reservoir. We reduce this MASP calculation to 2772 psi which assumes that only 1/3 of the wellbore is evacuated to gas and 2/3 water. Revision 0 January 2019 H BCU 04RD Drilling Procedure Rev 1 Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) • 11"x 5M Townsend Annular BOP • 11" x 5M Townsend Double Ram Initial Test: 250/4000 o Blind ram in burn cavity (Annular 2500 psi) • Mud cross 8-3/8" & 6" 11"x 5M Townsend Single Ram • 3-1/8" 5M Choke Line Subsequent Tests: • 2-1/16' x 5M Kill line 250/4000 • 3-1/8" x 2.1/16' 5M Choke manifold (Annular 2500 psi) Standpipe, floor valves, etc • Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 1 l gal bottles). • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Required BLM Notifications: • 48 hours before spud. Follow up with actual spud date and time. • 48 hours before casing running and cult operations • 48 hours before BOPE tests • 48 hours before logging, coring, & testing • Any other notifications required in APD. Additional requirements may be stipulated on APD. Page 10 Revision 0 January 2019 Regulatory Contact Information: BCU 04RD Drilling Procedure Rev 1 AOGCC Jim Regg / AOGCC Inspector/ (0): 907-793-1236 / Email: iim.regg@a alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartzna alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / Email: melvinAxse@alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@ja askagov Test/Inspection notification standardization format: http://doa alaska gov/OM/forms/TestWitnessNotifhtml Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) BLM Amanda Eagle / BLM Petroleum Engineer / (0): 907-271-3266 (C): 907-538-2300 Email: aeagle&blm.gov Mutasim Elganzoory / BLM Petroleum Engineer / (0): 907-271-4224 Email: melganzoory&blm.gov Use the below email address for BOP notifications to the BLM: BLM AK AKSO EnergySection Notifications@blm.gov Page 11 Revision 0 January 2019 H IGirorp 1layka, LIA: BCU 04RD Drilling Procedure Rev 1 9.0 R/U and Preparatory Work 9t oer-) 13 Sil-° 9.1 A separate sundry will be submitted that will include the following: • P&A lower perfs with a cement plug • Pull tubing 9.2 Mix water based mud for 8-3/8" hole section. 9.3 Check wellhead for pressure 9.4 Load well with 8.4 ppg KWF 9.5 Set storm packer at 500' 9.6 Nipple down BOPE �¢� � t4 9.7 Remove attachment spool and original tubing head. •� 9.8 Install new tubing head which will put the top of the wellhead back at ground level 9.9 Set test Plug in wellhead prior to N/U BOP to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.10 Rig up BOPE including MPD s= in drilling configuration (RCD, Annular, Double gate, mud cross, single gate) 9.11 Verify 5" liners installed in mud pumps. • HHF-1000 Pumps are rated at 3457 psi (80%) with 5" liners and can deliver 306 gpm at 120 spm. This will allow us to drill the 5-7/8" hole section with (1) mud pump. Page 12 Revision 0 January 2019 H ❑O..rrp kh4z, LU. 10.0 BOP N/U and Test BCU 04RD Drilling Procedure Rev 1 10.1 * BOPE was NU and tested on prior decompletion sundry. We will test BOPE on 7 day cycle until the window is milled, at that point we will switch to the 14 day test cycle. Continue on to step 11. 10.2 NIU 11"x 5M BOP as follows: • BOP configuration from Top down: RCD for MPD/11" x 5M annular BOP/I1" x 5M double ram/l1" x 5M mud cross/11" x 5M single ram. • Double ram should be dressed with 4-1/2" solid ram in top cavity, blind ram in btm cavity. • Single ram should be dressed with 4-1/2" solid ram. • N/U bell nipple, install flowline. 10.3 Run BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/4000 psi for 10/5 min. Test annular to 250/2500 psi for 10/5 min. • Ensure to leave "A" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Confirm the correct valves are opened!!! • Test rams on a 4-1/2" test joint. • Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 10.4 R/D BOP test assy. 10.5 Continue mixing mud for 8-3/8" hole section. 10.6 Set wearbushing in wellhead. Ensure ID of wearbushing > 8.375". Page 13 Revision 0 January 2019 0 HH.,p Alaeko UX 11.0 Mud Program and Density Selection Criteria 11.1 8-3/8" Intermediate hole mud program summary: BCU 04RD Drilling Procedure Rev 1 Primary weighting material to be used for the hole section will be Calcium Carbonate to minimize solids. We will have barite on location to weight up the active system Ippg above highest anticipated MW in the event of a well control situation. 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: 9.5 — 11.5 ppg 6% KCl/PUPA fresh water based drilling fluid. Properties: MDeigh Viscosity Plastic yield Point pH HPHT Caustic 0.2 ppb (9 pH) Viscosity 1.25 ppb (as required 18 YP) BDF-499 4 ppb 12,100'- 15,150' 9.5 — 11.5 40-53 1 15-25 1 15-25 1 8.5-9.5 < 11.0 System Formulation: 67. KCL/PHPA --Product Concentration Water 0.905 bbl KC] 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) BDF-499 4 ppb EZ MUD DP 0.75 ppb (initially 0.25 ppb) DEXTRID LT 1-2 ppb PAC -L 1 ppb BARACARB 5/25/50 5 — 10 ppb (3.3 ppb of each) BAROTROL PLUS 2 — 4 ppb SOLTEX 2 — 4 ppb BAROID 41 as required for a 9.0 — 9.5 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAVD 0.5 ppb maintain per dilution rate 11.2 Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated BHP's from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. 11.3 A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead. Page 14 Revision 0 January 2019 H Ililroop kl.rka, LIA: BCU 04RD Drilling Procedure Rev 1 12.0 Whipstock Running Procedure 12.1 M/U window milling assembly and TIH to CIBP. • Use an 8-3/8" taper mill and a 8-3/8" string mill above to ensure whipstock assy will pass freely. • Ensure BHA components have been inspected previously. • Caliper and drift all BHA components before running them in the hole. • Drift DP prior to RIH. • Lightly wash and ream any tight spots noted. 12.2 TIH to CIBP (12,100' MD). Note that this was a wireline measurement so actual depth tagged may vary slightly. Keep up with the # of joints picked up so we know where we are. 12.3 Pressure test casing to 2500 psi / 30 min. Chart record casing test & keep track of the amount of y fluid pumped. Stage up to 2500 psi in 500 psi increments. v 12.4 CBU & circ at least (1) hi -vis sweep to remove any debris created by the clean out run. Anything left in the wellbore could affect the setting of the whipstock. 12.5 TOH. 12.6 Makeup mills on a joint of HWDP. 12.7 RIH & set in slips. 12.8 Make up float sub, install float. 12.9 Make up UBHO sub. 12.10 Orient UBHO to starter mill. 12.11 Leave assembly hanging in the elevators, and stand back on floor. 12.12 Bring whipstock to rig floor on the pipe skate. Do not slam into bottom of whipstock with pipe skate. 12.13 Pick up whipstock per Baker rep using the Baker whipstock handling system using air hoist. Allow assy to hang while Baker Rep inspects and removes shear screws as needed and any safety screws. Note: Anchor should be pinned with 6 shear screws initially. Shear screws are rated for 6,630 lbs each. REMOVE 3 screws for a set down shear of 6,630 x 3 =19,890 lbs. Note: Attach mills to Whipstock with(]) 35k mill shear bolt. Page 15 Revision 0 January 2019 H IIIL.., U.A.,UX 12.14 If needed, open BOP Blinds. BCU 04RD Drilling Procedure Rev 1 12.15 Run the whipstock in the hole, install safety clamp as per Baker Rep, and install hole cover wrap. 12.16 Release pick up system at this point, make up mills. 12.17 With the top drive, pick the assembly and position the starting mill to align with the hole in the slide. The Baker Rep will instruct the driller when the slot is lined up, the shear bolt then can be made up by the Baker Rep. 12.18 The assembly can now be picked up to ensure that the shear bolt is tight. 12.19 Remove the handling system. 12.20 Slowly run in the hole as per Baker Rep. Run extremely slow through the BOP & wear bushing. 12.21 Run in hole at 1 %z to 2 minutes per stand. 12.22 Fill every 30 stands or as needed, do not rotate or work the string unnecessarily. 12.23 Call for Baker Rep. 15 — 10 stands before getting to bottom. 12.24 Orient at least 30' — 45' above the CTBP. Page 16 Revision 0 January 2019 N Flileorp Alaska, l.l.r. 13.0 Whipstock Setting Procedure BCU 04RD Drilling Procedure Rev 1 13.1 With the bottom of the Whipstock 30 — 45' above the CIBP, measure and record P/U and S/O weights. We will orient Whipstock face using highside MWD. 13.2 Orient Whipstock to desired direction by turning DP in %4 round increments. P/U and S/O on DP to work all torque out (Being careful not to set BTA). Whipstock Orientation Diagram: u AZI 60 AZI Desired orientation of the Whipstock face is in 25 to 60 degrees azimuth. Hole Angle at window interval (12100' MD) is — 14 deg. The wellbore trajectory is also planned to kick off at 88 degrees azimuth and turn to 161 degrees. Highside of the casing at 12100' is 88 degrees azimuth. 133 Once Whipstock is in desired orientation, slack off and tag CIBP to set Bottom Trip Anchor. a3.4 Set down 12-15K on anchor to trip, P/U 5-7K maximum overpull to verify anchor is set. The \4. tJ window mill can then be sheared off by slacking off weight on the Whipstock shear bolt. (25k shear value). r13.5 P/U 5-10' above top of Whipstock. 13.6 Displace to 9.5 ppg 6% KCL PHPA water based mud. 13.7 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window. Utilize 4 ditch magnets on the surface to catch metal cuttings. 13.8 Install catch trays in shaker underflow chute to help catch iron. 13.9 Keep iron in separate bbls. Record weight of iron recovered on ditch magnets. 13.10 Estimated metal cuttings volume from cutting window: Page 17 Revision 0 January 2019 N mikl—k:,. u.c BCU 04RD Drilling Procedure Rev 1 Wieght of Cuttings For Milled Casing Exit O.D. Of Casing (in) 9.625 LD_ Of Casing (in) 8.535 Whipstock Face Length (Ft) 16.00 Percent of Casing Removed (%) ' 38 Milled Area (InAl2) 5.908 Volume of Cuttings (inA3) 1134.272 Density of Casing (lb.tinA3) " 0.283 Weight of Cutting Generated (Ibs) 321.0 ' Calculated Average of Casing Removed Based on Drill Mills (38%) **Density of Steel = .283 DLT 311101 BAKER HUGHES Baker Oil Tools 13.11 Drill approx. 20' rat hole to accommodate the drilling assembly. Ream window as needed to assure there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through window checking for drag. 13.12 Circulate Bottoms Up until MW in = MW out. C� 13.13 Conduct FIT to 12.5 ppg EMW. • (12.5 — 9.5) * 0.052 * 12016' tvd = 1875 psi 13.14 Kick Tolerance 0 (12.5 -9.5) * (12016/14098) = 2.55 Note: Offset field test data predicts frac gradients at the window to be between 12 ppg and 15 ppg. A 12.5 ppg FIT results in a 2.55 ppg kick tolerance while drilling the interval with a 9.5 ppg fluid density. 13.15 Slug pipe and POOH. Gauge Mills for wear. Page 18 Revision 0 January 2019 n Illl- , kI.A., IAA: 8CU 04RD Drilling Procedure Rev 1 14.0 Drill 8-3/8" Hole Section 14.1 Ensure that the managed pressure drilling (MPD) system is rigged up and functional prior to drilling through the high pressure Tyonek water sands in this area. We expect to encounter the sand at approximately 14,860' TMD (13,954' TVD). 14.2 P/U 8-3/8" directional drilling assy. 14.3 Ensure BHA Components have been inspected previously. 14.4 Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 14.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 14.6 Have DD run hydraulics models to ensure optimum TFA. We want to pump at 350-500 gpm. 14.7 Intermediate section will be drilled with Geopilot 7600. Must keep up with 3 deg/100 DLS in the drop section of the wellbore. 14.8 Primary bit will be the Baker Hughes Kymera. Ensure to have a back up PDC bit available on location. 14.9 TIH to window. Shallow test MWD on trip in. 14.10 TIH through window, ensure Halliburton MWD service rep on rig floor during this operation. • Do not rotate string while bit is across face of Whipstock. Page 19 Revision 0 January 2019 N mimrp Al"ka, uL BCU 04RD Drilling Procedure Rev 1 14.11 Drill 8-3/8" hole to 15,150' MD using rotary steerable assembly. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Utilize ECD while pumping to minimize waterflow from Tyonek sands • Utilize MPD to minimize Tyonek water flow • On trips spot weighted pills inside window and hi vis pills at TD to control waterflow • Try to keep waterflow below 10 bph while tripping • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • See attached mud program for hole cleaning and LCM strategies. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. • Ensure mud engineer set up to perform HTHP fluid loss. • Maintain API fluid loss < 6. • Take MWD surveys every stand drilled. • Minimize backreaming when working tight hole 14.12 Hilcorp Geologists will follow mud log closely to determine exact TD. 14.13 At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU, and pull a wiper trip back to the window. 14.14 TOH with drilling assembly, handle BHA as appropriate. 14.15 Change out one set of pipe rams to 7" casing rams and test as per AOGCC regulations. (250 psi low/3000 psi high) Page 20 Revision 0 January 2019 H liil o p Alalia, LLC 15.0 Run 7" Drilling Liner BCU 04RD Drilling Procedure Rev 1 15.1 R/U Weatherford 7" casing running equipment. • Ensure 7" TXP BTC x 4-1/2" CDS-40 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted and tally verified prior to running. • Be sure to count the total # of joints before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 15.2 P/U shoe joint, visually verify no debris inside joint. 15.3 Continue M/U & thread locking shoe track assy consisting of: • (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). • (1) Baker locked joint. • (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). • (1) Joint with landing collar bucked up. • Fiberglass 7" X 8-1/8" injection molded solid body centralizers will be pre-installed on shoe joint, FC joint, and LC joint. • Install 7" X 8-1/8" fiberglass injection molded solid body centralizers, one per joint, and leave centralizers free floating so that they can slide up and down the joint. These are available at Mike Leslie's warehouse. • Ensure proper operation of float shoe & FC. 15.4 Continue running 7" drilling liner to TD • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. • Install solid body centralizers on every other joint to window. Leave the centralizers free floating. Utilize a collar clamp until weight is sufficient to keep slips set properly. 7" 29# TXP BTC NM torques Casing OD Minimum Maximum Yield Torque 7" 15880 ft -lbs 19400 ft -lbs 32000 ft -lbs Page 21 Revision 0 January 2019 H Ilila,rp 1lnaka, LLC BCU O4RD Drilling Procedure Rev 1 TXP® BTC 11130/2018 outside Diameter 7.1100 in. Min. Wall 97.5% Thickness rl Grade PI to. IC Wall Thickness 0.408 in. Connection OD REGULAR COUPLING PIPE BODY Option Body: White 1st Band: while Drat APISWIdara Grade P110JC- list Band: - 2nd Band. Pate 2nd Bar: - Green Type Casing 3rd Bar. - 3rd Band. - 41h Band: - PIPE BODY DATA GEOMETRY Nominal OD 7.000 In. Nominal Weigh, 19lbs.ri Drift 6.0590, Nominal to 6.181:,. Wall Thickness 0A08 in. Wain End Weight 28.75 teM OD Tolerance AN PERFORMANCE Body Yield StrengT 929 x1000 Obs Intemal Yield 11220 ov SMYS 110000 psi Collapse 9580 psi CONNECTION DATA GEOMETRY Connection OD 7.750n. Coupling Length 10.20 N. Comecon ID Bd72 u. Make-up Loss 4.579 m. Threads per in 5 Conregion 00 Option REGULAR PERFORMANCE Tension Efrcienry 1000% hint Yield strength 020.00 x1000 Internal PressureCapacity" 11220.00 µ3i Its, Compression Efficienry, 100% Compression strength 929.00 xlVA Max. N4owabte Bending 7211100 ft lbs External Pressure Capacity 9580.00 psi MAKE-UP TORQUES klmimom 15880 ft -lbs Optimum 17640 ft4bs Maximum 19{00 ft8rs OPERATION LIMIT TORQUES 0,ana,Inc Torque 2720 ft -Ib r*M Torque 52000 ft -me Notes This connection is fully interchangeable With: TXP(b8TC-7 in.- 23126132 / 35138 Ibsft (t] Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API 5C3 / ISO 10400 - 2007. Datasheet is also valid for Special Bevel option When applicable - except for Coupling Face Load, which will be reduced. Please contact a local Tenans technical sales representative. H nflco.p Alk., LIA: BCU 04RD Drilling Procedure Rev 1 15.5 Ensure to run enough liner to provide at least 100' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a connection. 15.6 Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 15.7 M/U Baker ZXP liner top packer. Fill liner tieback sleeve with "XANPLEX", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 15.8 RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 15.9 RIH w/ liner on DP no faster than I min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 15.10 M/U top drive and fill pipe while lowering string every 10 stands. 15.11 Set slowly in and pull slowly out of slips. 15.12 Circulate 1-1/2 drill pipe and liner volume at 9-5/8" window prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 15.13 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 15.14 Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 15.15 P/U the cmt stand and tag bottom with the liner shoe. P/U 2' off bottom. Note slack -off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 15.16 Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 15.17 Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 23 Revision 0 January 2019 N mirv.p AI.Ak , u.c 16.0 Cement 7" Drilling Liner BCU 04RD Drilling Procedure Rev 1 • Cement will be mixed using batch mixer to ensure consistent density 16.1 Hold a pre job safety meeting over the upcoming cmt operations. 16.2 Attempt to reciprocate the casing during curt operations until hole gets sticky. 16.3 Pump 15 bbls 12.5 ppg spacer. 16.4 Test surface cmt lines to 4500 psi. 16.5 Pump remaining 10 bbls 12.5 ppg spacer. 16.6 Mix and pump 40 bbls of 15.3 ppg class "G" cmt per below recipe with 2 lbs/bbl of loss circulation fiber. Ensure cmt is pumped at designed weight. Job is designed to pump 50% OH excess but if fluid caliper dictates otherwise we may increase excess volumes. Cement volume is designed to bring cement to 12,500' TMD in annulus between 7" casing and 8-3/8" hole. 16.7 Displacement fluid will be drilling mud. —164 bbls of displacement fluid in drill pipe and 117 bbls in liner. (.01378 * 11900 = 164), (03715 * 3160 = 117), Total 282 Cement Calculations 8-3/8" OH x 7" Liner: (15150'— 12500') x 0.02054 x 1.5 = 82 bbls Shoe Track: 90' x 0.03715 = 3.4 bbls Total Volume (bbls): 82 + 3.4 = 85.4 bbls Total volume (113): 85.4 bbls x 5.615 ft31bbl = 480 ft3 Total Volume (sx): 480 ft3 / 1.34 ft3/sk = 358 sx Page 24 Revision 0 January 2019 U Ilik.. , ki„k,. LII; Slurry Information: BCU 04RD Drilling Procedure Rev 1 System VariCEM Density 15.3 ]b/gal Yield 1.34 ft3/sk Mixed Water 5.879 gal/sk Mixed Fluid 5.879 gal/sk Expected Thickening 70 Be at 05:00 hr:mn API Fluid Loss <25 mL in 30.0 min at 155degF / 1000 psi Additives Code Description Concentration G D046 D202 D400 D154 Cement Anti Foam Dispersant Gas Control Agent Extender 94 lb/sk 0.2%BWOC 1.5%BWOC 0.8% BWOC 8.0%BWOC 16.8 Drop DP dart and displace with 11.5 ppg WBM drilling mud. 16.9 Pump cement at max rate of 5 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running too] and resume pumping at full displacement rate. Displacement volume can be re -zeroed at this point 16.10 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 16.11 Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (15% above nominal setting pressure. Hold pressure for 3-5 minutes. 16.12 Slack off total liner weight plus 30k to confirm hanger is set. 16.13 Do not overdisplace by more than % shoe track (-1 bbls). Shoe track volume is 1.8 bbls. 16.14 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner Page 25 Revision 0 January 2019 H Ilik.q Almke, WA: 16.15 Bleed pressure to zero to check float equipment. BCU 04RD Drilling Procedure Rev 1 16.16 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve 16.17 Rotate slowly and slack off 50k downhole to set ZXPN. 16.18 Pressure up drill pipe to 500 psi and pickup to remove the RS packoff bushing from the RS nipple. Bump up pressure as req'd to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack -off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 16.19 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 16.20 Pick up to the high -rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re -tag the liner top, and circulate the well clean. 16.21 Watch for cement returns and record the estimated volume. Rotate & circulate to clear curt from DP. 16.22 POOH, LDDP. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 16.23 If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 16.24 NOTE: Some hole conditions may require movement of the drillpipe to "work" the torque down to the setting tool. 16.25 After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set -down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Page 26 Revision 0 January 2019 H Ilil.,p M.A., LIA: BCU 04RD Drilling Procedure Rev 7 Ensure to report the following on Wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the jab • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns duringjob, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the successor problems during the cement job Note: Send Csg & cmt report + "As Run" liner tally to mmvers(a)hilcorp.com Page 27 Revision 0 January 2019 17.0 Drill 6" Hole Section 17.1 P/U 6" directional drilling assy. 17.2 Ensure BHA Components have been inspected previously. BCU 04RD Drilling Procedure Rev 1 17.3 Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 17.4 Ensure TF offset is measured accurately and entered correctly into the MWD software. 17.5 Have DD run hydraulics models to ensure optimum TFA. We want to pump at 200 - 450 gpm. 17.6 Production section will be drilled with Geopilot 5200. Must keep up with 3 deg/100 DLS in the drop section of the wellbore. 17.7 Primary bit will be the Baker Hughes Kymera 6" KMX323T. Ensure to have a back up PDC bit available on location. 17.8 TIH to liner hanger. Shallow test MWD on trip in. 17.9 TIH through liner hanger ensure Halliburton MWD service rep on rig floor during this operation. Page 28 Revision 0 January 2019 H Ilil.q .Alaska, LLC BCU 04RD Drilling Procedure Rev 1 17.10 Displace well to 9.5 ppg MOBM2 • S - I R )-50D r 5 t. 17.11 Test casing t 3�si and chart for 10 minutes 17.12 Drill approx. 20' rat hole to accommodate the drilling assembly. Ream shoe as needed to assure there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through shoe checking for drag. 17.13 Circulate Bottoms Up until MW in = MW out. 17.14 Conduct FIT to 12.5 ppg EMW. i f U a (12.5 — 9.5) * 0.052 * 14098' tvd = 2199 psi 17.15 Kick Tolerance (12.5 -9.5) * (14098/15452) = 2.73 Note: Offset field test data predicts frac gradients at the window to be between 12 ppg and 15 ppg. A 12.5 ppg FIT results in a 2.73 ppg kick tolerance while drilling the interval with a 9.5 ppg fluid density. 17.16 System Type: 9.5 ppg 90/10 Enviromul mineral oil based drilling fluid. Properties: b1D 1 baud Weight Viscosity PV VP HTRP WPS ES EZ MUL NT (Ppg) GELTONE V 6-10 ppb Lime 7 ppb DURATONE HT 2 ppb 15,150-17,434' 95-10.5 50-80 _i 20-30 15-22 G 250-270K >580 System Formulation: 90/10 Enviromul MOBM Product. Concentration _ LVT 0.662 bbl Water .172 bbl INVERMUL NT 4 ppb EZ MUL NT 4 ppb GELTONE V 6-10 ppb Lime 7 ppb DURATONE HT 2 ppb Calcimn Chloride 21 ppb BAROID 41 9.5 ppg (as needed) BARACARB 5 3-5 ppb BARABLOK 2 ppb BAROTROLPLUS 1 4 PPb Page 29 Revision 0 January 2019 N Who, Al—ka, LIA: BCU 04RD Drilling Procedure Rev 1 17.17 Drill 6" hole to 17,434' MD using rotary steerable assembly. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • See attached mud program for hole cleaning and LCM strategies. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. • Ensure mud engineer set up to perform HTHP fluid loss. • Maintain API fluid loss < 6. • Take MWD surveys every stand drilled. • Minimize backreaming when working tight hole 17.18 Hilcorp Geologists will follow mud log closely to determine exact TD. 17.19 At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU, and pull a wiper trip back to the window. 17.20 TOH with drilling assembly, handle BHA as appropriate. Page 30 Revision 0 January 2019 H nil,-, A1.4., LLO 18.0 Run 4-1/2" Production Liner BCU 04RD Drilling Procedure Rev 1 18.1 R/U Weatherford 4-1/2" casing running equipment. • Ensure 4-1/2" DWC/C x 4-1/2" CDS-40 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted and tally verified prior to running. • Be sure to count the total # of joints before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 18.2 P/U shoe joint, visually verify no debris inside joint. 18.3 Continue M/U & thread locking shoe track assy consisting of • (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). • (1) Baker locked joint. • (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). • (1) Joint with landing collar bucked up. • Fiberglass 4-1/2" X 5-5/8" Solid body centralizers will be pre-installed on shoe joint, FC joint, and LC joint. • Install 4-1/2" X 5-5/8" fiberglass injection molded solid body centralizers, one per joint, and leave centralizers free floating so that they can slide up and down the joint. These are available at Mike Leslie's warehouse. • Ensure proper operation of float shoe & FC. 18.4 Continue running 4-1/2" production liner to TD • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paintbrush. • Install solid body centralizers on every other joint to window. Leave the centralizers free floating. Utilize a collar clamp until weight is sufficient to keep slips set properly. 4-1/2" DWC/C NM torques Casin OD Minimum Maximum Yield Torque 4-1/2" 1 5800 ft -lbs 6500 ft -lbs 7200 ft -lbs Page 31 Revision 0 January 2019 Connection Type: DWC/C Tubing standard Technical Specifications Size(O.D.): Weight (Wall): 4-1/2 in 12.60 Ib/ft (0.271 in) Material L-80 Grade 80,000 Minimum Yield Strength (psi) 95,000 Minimum Ultimate Strength (psi) Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft-Ibs) 6,500 Maximum Final Torque (ft-Ibs) 7,200 Connection Yield Torque (ft-Ibs) BCU 04RD Drilling Procedure Rev 1 Grade: L-80 "low -USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston. TX 77041 Phone: 713-4793200 Fax: 713479-3234 E-mail: VAMUSAsales®vam�.com Page 32 Revision 0 January 2019 Pipe Dimensions 4.500 Nominal Pipe Body O.D. (in) 3.958 Nominal Pipe Body I.D.(in) 0.271 Nominal Wall Thickness (in) 12.60 Nominal Weight (lbs/ft) 12.25 Plain End Weight (lbs/ft) 3.600 Nominal Pipe Body Area (sq in) Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft-Ibs) 6,500 Maximum Final Torque (ft-Ibs) 7,200 Connection Yield Torque (ft-Ibs) BCU 04RD Drilling Procedure Rev 1 Grade: L-80 "low -USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston. TX 77041 Phone: 713-4793200 Fax: 713479-3234 E-mail: VAMUSAsales®vam�.com Page 32 Revision 0 January 2019 Pipe Body Performance Properties 288,000 Minimum Pipe Body Yield Strength (lbs) 7,500 Minimum Collapse Pressure (psi) 8,430 Minimum Internal Yield Pressure (psi) 7,700 Hydrostatic Test Pressure (psi) Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft-Ibs) 6,500 Maximum Final Torque (ft-Ibs) 7,200 Connection Yield Torque (ft-Ibs) BCU 04RD Drilling Procedure Rev 1 Grade: L-80 "low -USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston. TX 77041 Phone: 713-4793200 Fax: 713479-3234 E-mail: VAMUSAsales®vam�.com Page 32 Revision 0 January 2019 Connection Dimensions 5.000 Connection O.D. (in) 3.958 Connection I.D. (in) 3.833 Connection Drift Diameter (in) 3.94 Make-up Loss (in) 3.600 Critical Area (sq in) 100.0 Joint Efficiency (%) Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft-Ibs) 6,500 Maximum Final Torque (ft-Ibs) 7,200 Connection Yield Torque (ft-Ibs) BCU 04RD Drilling Procedure Rev 1 Grade: L-80 "low -USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston. TX 77041 Phone: 713-4793200 Fax: 713479-3234 E-mail: VAMUSAsales®vam�.com Page 32 Revision 0 January 2019 Connection Performance Properties 288,000 Joint Strength (Ibs) 14,290 Reference String Length (ft) 1.6 Design Factor 314,000 API Joint Strength (Ibs) 288,000 Compression Rating (Ibs) 7,500 API Collapse Pressure Rating (psi) 8,430 API Internal Pressure Resistance (psi) 81.5 Maximum Uniaxial Bend Rating [degrees/100 ft] Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft-Ibs) 6,500 Maximum Final Torque (ft-Ibs) 7,200 Connection Yield Torque (ft-Ibs) BCU 04RD Drilling Procedure Rev 1 Grade: L-80 "low -USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston. TX 77041 Phone: 713-4793200 Fax: 713479-3234 E-mail: VAMUSAsales®vam�.com Page 32 Revision 0 January 2019 H Ililmrp Alm ka, LU: BCU 04RD Drilling Procedure Rev 1 18.5 Ensure to run enough liner to provide at least 100' overlap inside 7" casing. Ensure hanger/pkr will not be set in a 7" connection. 18.6 Before picking up Baker ZXP liner hanger / packer assy, count the # ofjoints on the pipe deck to make sure it coincides with the pipe tally. 18.7 M/U Baker ZXP liner top packer. Fill liner tieback sleeve with "XANPLEX", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 18.8 RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 18.9 RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 18.10 M/U top drive and fill pipe while lowering string every 10 stands. 18.11 Set slowly in and pull slowly out of slips. 18.12 Circulate 1-1/2 drill pipe and liner volume at 9-5/8" window prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 18.13 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 18.14 Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 18.15 P/U the cmt stand and tag bottom with the liner shoe. P/U 2' off bottom. Note slack -off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 18.16 Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 18.17 Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 33 Revision 0 January 2019 19.0 Cement 4-1/2" Production Casing BCU 04RD Drilling Procedure Rev 1 • Cement will be mixed using batch mixer to ensure consistent density 19.1 . Hold a pre job safety meeting over the upcoming cmt operations. 19.2 Attempt to reciprocate the casing during curt operations until hole gets sticky. 19.3 Pump 15 bbls 12.5 ppg spacer. 19.4 Test surface cmt lines to 4500 psi. 19.5 Pump remaining 10 bbls 12.5 ppg spacer. 19.6 Mix and pump 53 bbls of 15.3 ppg class "G" cmt per below recipe with 2 lbs/bbl of loss circulation fiber. Ensure cmt is pumped at designed weight. Job is designed to pump 50% OH excess but if fluid caliper dictates otherwise we may increase excess volumes. Cement volume is designed to bring cement to 15,150' TMD in annulus between 4-1/2" casing and 6" hole. 19.7 Displacement fluid will be drilling mud. --207 bbls of displacement fluid in drill pipe and 35 bbls in liner. (.01378 * 15050 = 207), (.01522 * 2294 = 35), Total 242 Cement Calculations 6" OH x 7" Liner: (17434' — 15150') x 0.01530 x 1.5 = 53 bbls Shoe Track: 90' x 0.01522 = 1.5 bbls Total Volume (bbls): 38.5 + 1.5 = 55 bbls Total Volume (ft3): 55 bbls x 5.615 ft3/bbl = 309 ft3 Total Volume (sx): 309 113 / 1.34 ft3/sk = 231 sx Page 34 Revision 0 January 2019 U llilmrp Alaska, LIA: Slurry Information: BCU 04RD Drilling Procedure Rev 1 System VariCEM Density 15.3 lb/gal Yield 1.34 ft3/sk Mixed Water 5.879 gal/sk Mixed Fluid 5.879 gal/sk Expected Thickening 70 Be at 05:00 hr:mn API Fluid Loss <25 mL in 30.0 min at 155degF / 1000 psi Additives Code Description Concentration G D046 D202 D400 D154 Cement Anti Foam Dispersant Gas Control Agent Extender 94 lb/sk 0.2% BWOC 1.5% BWOC 0.8% BWOC 8.0% BWOC 19.8 Drop DP dart and displace with 9.5 ppg OBM drilling mud. 19.9 Pump cement at max rate of 5 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re -zeroed at this point 19.10 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 19.11 Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (15% above nominal setting pressure. Hold pressure for 3-5 minutes. 19.12 Slack off total liner weight plus 30k to confirm hanger is set. 19.13 Do not overdisplace by more than %z shoe track (—1 bbls). Shoe track volume is 1.8 bbls. 19.14 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner Page 35 Revision 0 January 2019 H Ofhv,p A1.4, 1AX 19.15 Bleed pressure to zero to check float equipment. BCU 04RD Drilling Procedure Rev 1 19.16 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve 19.17 Rotate slowly and slack off 50k downhole to set ZXPN. 19.18 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req'd to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack -off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 19.19 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 19.20 Pick up to the high -rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re -tag the liner top, and circulate the well clean. 19.21 Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 19.22 POOH, LDDP. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 19.23 If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 19.24 NOTE: Some hole conditions may require movement of the drillpipe to "work" the torque down to the setting tool. 19.25 After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set -down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Page 36 Revision 0 January 2019 H uIa.La. LLC BCU 04RD Drilling Procedure Rev 1 Ensure to report the following on Wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns duringjob, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Note: Send Csg & curt report + "As -Run " liner tally to mmvers(&hilcorn.com Page 37 Revision 0 January 2019 20.0 Wellbore Clean Up & Displacement BCU 04RD Drilling Procedure Rev 1 20.1 M/U casing clean out assy complete with casing scraper assys for each size casing in the hole. • 3-3/4" bit or mill • Casing scraper & brush for 4-1/2" 12.6# casing (MI Swaco - Multiback) +/- 2300' 2-3/8" workstring. • Casing scraper & brush for 7" 29# casing (MI Swaco - Multiback) • (2000') 4-1/2" DP • Casing scraper & brush for 7" 29# casing (MI Swaco - Multiback) • 4-1/2" DP to surface. 20.2 TIH & clean out well to landing collar (+/- 17,344' MD). • Circulate as needed on trip in if string begins to take weight. • Circulate hi -vis sweeps as necessary to carry debris out of wellbore. • Ensure 3-3/4" bit is worked down to the landing collar. • Space out the cleanout BHA so that the 3-3/4" bit reaches the 4-1/2" landing collar when crossover is +/- 30' above the 4-1/2" liner top. • The primary objective of the clean out run is to ensure the TCP assy will reach intended depth. a SDv 20.3 After wellbore has been cleaned out satisfactorily using mud, test casing toj�psi / 30 min. Ensure to chart record casing test. / 20.4 Displace drilling fluid in wellbore with a hi -vis pill followed by fresh water. • Catch drilling fluid in rain -for -rent tanks for use on a future well. • Circulate fresh water into wellbore until clean up is satisfactory. Do not recirculate fluid, • After a couple circulations using FW, short trip the assy to bring the upper 7" multi -back assy to surface. • RIH again & tag landing collar w/ 3-3/4" bit. Continue circulation as necessary until fluid cleans up. Make another short trip if necessary. • Pump a chemical train followed by diesel completion fluid. 20.5 TOH w/ clean out assy. LDDP on the trip out. L/D the 4-1/2" work string. Page 38 Revision 0 January 2019 H Mk o, w..Ga, LIX 21.0 Run Completion Assembly 21.1 Perforate required intervals as per separate sundry 21.2 Run 3-1/2" tubing as per separate Approved Completion Sundry 22.0 RDMO 22.1 Install BPV in wellhead. RILDs. 22.2 ND BOPE, NU tree, test void 22.3 RDMO BCU 04RD Drilling Procedure Rev 1 Page 39 Revision 0 January 2019 0 Hil.rp Aru.ku, LIA 23.0 BOP Schematic BCU 04RD Drilling Procedure Rev 1 Page 40 Revision 0 January 2019 H Ilili ,.rp Ala,ka, LI f. 24.0 Wellhead Schematic Beaver Creek BC 04AD 2O x 133/8 x 95/9 x 3% BHTA. Otis, 31/8 5M FE x 6.5" Ons quid union top Valve, Master, OW -FIS, 31/85M FE, HWO, EE trim Tubing head, FMC -TC -BG, 13 5/85M x 215M, w/ 2- 2 This 5M 550 Casing spool, OCT- C -22 -BP - 00,21%"2M x 135/85M, W/ 2- 2 1/16 5M 550/ Starting head, OCT -U2, 211/4" 2M x 20" SOW, w/ 2-21/165M EFO BCU 04RD Drilling Procedure Rev 1 Tubing hanger, FMC -TC EN - CCL 11 x 3 %EUE erd lift and su1p, w/ 3" type H -BIN profile, 2. Xnpt control line port, 6 %EN Adapter, FMC.ASP-CC4 115M stdd x 31/O SM, w/ 2 1" npt control line exits Page 41 Revision 0 January 2019 H ❑if—, Xi.,ka,LIA: BCU 04RD Drilling Procedure Rev 7 25.0 Days vs Depth Days Vs Depth 0 BC 04RD 2000 4000 6000 8000 rL 8 s g 10000 12000 —BCU 04RD —BCU OSRD2 14000 16000 18000 0 5 10 15 20 25 30 35 40 Days Page 42 Revision 0 January 2019 26.0 Geo -Frog I at 12100'M, drill -2800'M using WBM and get pipe set r HP H2O Sands. Once completed, kick out with OBM and -2600 targeting Tyonek G sands and seconardy targets in upper Hemlock formation. This sidetrack will provide us i proof of structure (moving up dip into white space), and 1 confirming reservoir continuity of sands. �... LITHOLOGY......�....::, Gradient EMIN TK TYONEK T4 3 : Water 12,1 S_T_Y_N_ K- CT7 ................................... Water ....... .12.4 . L E TNK Water 12,1 St TYNK CT4Water :............................. ...................... 13,1 ..--------- TK_TYONEK_T4_5 Water_ 13,: Sf, EIOMKT ....................... .._.Water ..13,4 TK- TYONEK T5_X t -- -........................................... Water 13.1 TK TYONEK T5 XI:Water .................. .'--..... ...................... 13,f ........... TK TYONEK TS X21Water _„ - - -............................................................. 0:45 13 TK TYONEK T5 - - . ............................. Water ....... . 13c TK-TYONEK-TS-1 t ._. :.............................. Water ........_..__._.. 14,( TK TYONEK TS 2 i _-_..._._._-._-............................... Water ................................. 14,( TK TYONEK T5 3 i _-_............................................... Water 14;1 TK-TYONEK T5 4 ? Water 14,1 Water . 14,<' TK TYONEK T5_-5 - - . :.......................................... TK_TYONEK_T5_6 Water 14,: Water 14,: TK TYONEK TS 7 -- - - -.............................................................. TK__TYONEK_T5_8 Water 14,4 Water 14,f TK TYONEK T5 9 _ _...................................._........................ TK-TYONEK _T5_10: Water 1 14,E Water 14,E TK-TYONEK-T5-11: I ............................................................... TK-TYONEK-T-5-12: Water 14,1 Water 14,7 TK TYONEK T5 13: 1 BCU 04RD Drilling Procedure Rev 1 Beaver C KB 166221 18.0 Fst Gradient EMIN Pressure ............................. 5273.08 1.0.45 8.7 5393.08 : ............... .,. OAS 8.7 __ 5505.21 i ............................... 0.45 8.7 5676.58OAS .............................. . _ 8.7 ' ............. ;..._._____ 5759.91 i .............................. 0.458.7 __. 587521 i ...........-... ,,,...__OAS 8.7 - 5911.61 ................ 0:45 8.7 - 5944.66:.OAS ............... 8.7 -- 596426_ i .OAS 8.7 5991.97 : ............................... 0.45 8.7 6012.89 _ _ 0.45 8.7 _..---- OA5 8.7 8042.32 OAS _ 8.7 8.7 6088.21 i .OAS ................. 6094.86 OAS _ 8.7 8.7 6119.03 i 0.45 6141.87 i OAS 8.7 8.7 _ ------------- 6174.18 0.45 ............................... 6201.88 i OAS 8.7 8.7 _. 6222.94 0:45 -........._I._._._.__ 6246.69 i 0.45 8.7 Page 43 Revision 0 January 2019 K Hila.... kl.-La. LLC BCU 04RD Drilling Procedure Rev 7 OTHER COMMENTSThis well Is to be drilled from the Beaver Creek Pad 4. Please provide drilling and myself with the final surface location when the location has been identified and staked. Page 44 Revision 0 January 2019 8.7 13.5 8.7 8.7 8.7 8.7 8.7 8.7 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 n 27.0 Anticipated Drilling Hazards BCU 04RD Drilling Procedure Rev 1 Water Flow: The Tyonek water sands will be open. Ensure to treat the initial flow as gas. After we are confident we are only dealing with water from the sands we will utilize managed pressure drilling to control the flow of water while drilling. During trips we will use heavy pills and viscous pills to control the flow and trip in and out of the well. Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual -composition carbon -based 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/ viscofier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain programmed mud specs. 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. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt -type additives to further stabilize coal seams. • Increase fluid density as required to control running coals. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. • Minimize swab and surge pressures • Minimize back reaming through coals when possible H2S: H2S is not present in this hole section. No abnormal temperatures or pressures are present in this hole section. Page 45 Revision 0 January 2019 H Hil"' , ei:"K.. u.c 28.0 Rig Layout BCU 04RD Drilling Procedure Rev 1 Page 46 Revision 0 January 2019 29.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: BCU 04RD Drilling Procedure Rev 1 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 I -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. Page 47 Revision 0 January 2019 30.0 Choke Manifold Schematic Pi A9 BCU 04RD Drilling Procedure Rev 1 1. N1W, aM R G9Eli Page 48 Revision 0 January 2019 K Ilitmrp Ala ka, LIA] 31.0 Casing Design Information BCU 04RD Drilling Procedure I Rev 1 Calculation & Casing Design Factors Hole Size 8-1/2" Hole Size 6" Hole Size Drilling Mode MASP: Beaver Creek Unit DATE: 21512019 WELL: BCU-04RD FIELD: Beaver Creek Unit DESIGN BY: Monty M Myers Criteria: Mud Density: 11.5 2pq Mud Density: 9.5 ppg Mud Density:_ Production Mode MASP: 6335 psi (See attached MASP determination & calculation) Collapse Calculation: Section Calculation 1,2 Normal gradient external stress (0.44 psi/ft) and the casing evacuated for the Internal stress . . ....... . ... -6a'i�-ui"- -,n"/-S,-p--e-c-1fi-c—afi-o—n-- Cas. ng Section ------- 3 4 Casing CID 7' 4-112" To (MID) 11,900 15,050 11,820 14,048 Bottom (MD) 15,150 17,434 Bottom (TVD) 14,098 15,452 Length 3,250 2,384 Weight (pA 29 126 Grade P-110 L-80 Connection T)p BTC; I DWC/C Weight w/o Bouyancy Factor Obs) 291,790 279,868 I T Tension at TWqSectj2EI ItLs) 291,790 279,868 T Min strength Tension (1000 lbs) 929 288 Worst Case Safety Factor (Tension) 3.18 1.03 Collapse Pressure at bottom (Psi) 8,430 7,070 Collapse Resistance w/o tension (Psi) 9,580 7,500 Worst Case Safe ty Factor (Collapse) 1.14 1.06 MASP (psi) 2,772 2,-6-78 Minimum Yield (psi) 1 11,220 8.430 Worst casesa&LTactor Burst) 4.05 3.I-5 Page 49 Revision 0 January 2019 BCU 04RD Drilling Procedure Rev 1 32.0 8-3/8" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 11 8-3/8" Hole Section Hilcorp BCU 04RD2 Kenai, Alaska MD TVD Planned Top: 11900 11820 Planned TD: 15150 14098 Antirinated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad TK_TYONEK_T4_4 11,884 5,273 Water 8.5 0.44 SR TYNK CT7 12,151 5,393 Oil/Water 8.5 0.44 TK_TVON EK_T4_5 12,890 5,726 Oil/Water 8.5 0.44 TK_TYONEK_T5_X 13,222 5,875 oil/Water 8.5 0.44 TK_TYONEK_T5 13,420 5,964 Oil/Water 8.5 0.44 TOP_TYONEK_G 13,928 6,276 Oil/Water 0.45 HP-H20_SAND 13,953 9,782 Water 13.5 0.70 TD 14,098 6,260 Oil/Water 8.5 0.44 Offset Well Mud Densities Well MW ranee Top (TVD) Bottom (TVD) Date BCU 05 1 11-13pp9 12,500 16,250 2014 Beaver Creekl4A 9.0-9.4ppg 5,000 9,450 2014 Beaver Creek 7A 1 9.0-9.3 1 2,400 8,929 2014 Assumptions: 1. Maximum planned mud density for the 8-3/8" hole section is 11.5 ppg. 2. Calculations assume reservoirs contain 100% gas (worst case). 3. Calculations assume worst case event is complete evacuation of wellbore to gas. 4. Anticipated fracture gradient at 14098'TVD = 13.5 ppg EMW Fracture Pressure at 8-3/8" window considering a full column of gas from window to surface: 14098 (ft) x 0.71(psi/ft)= 10010 psi 10010(psi)-(0.1(psi/ft)*14098(ft)]= 8600 psi MASP from pore pressure; entire wellbore evacuated to gas from TD 14098 (ft) x 0.69(psi/ft)= 9728 psi 9728(psi)-[0.1(psi/ft)*14098(ft)]= 8318 psi 9728(psi)-[(1/3)*0.1(psi/ft)*14098(ft)]+[(2/3)*0.69(psi/ft)*14098(ft)]= 2772 psi Alternate Drilling MASP Summary: 1. MASP while drilling 8-3/8" intermediate hole Is governed by SIBHP minus 1/3 wellbore evacuated to gas from TD. Page 50 Revision 0 January 2019 �Al(L ! Le✓� U I Id,", %IaA a. 1.1.1: 33.0 611 Hole Section MASP BCU 04RD Drilling Procedure Rev 1 Maximum Anticipated Surface Pressure Calculation 14 6" Hole Section Eaml BCU 04RD Kenai, Alaska MD ND Planned Top: 15150 14098 Planned TD: 17434 15452 Anticipated Formations and Pressures: Formation ND Est Pressure Oil/Gas/Wet PPG Grad BC G3 A 14,283 6352 Water 8.6 0.44 BC G2 A 14,601 7506 Oil 9.9 0.51 BC G2_B 14,726 7571 Oil 9.9 0.51 BC_G2_C 14,791 7605 Oil 9.9 0.51 BC_G2_D 14,806 7613 011 9.9 0.51 HEMLOCK 14,862 7662 Oil 9.9 0.51 BC H1 14,918 7671 Oil 9.9 0.51 BC H2 14,972 7699 Oil 9.9 0.51 BC H3 15,026 7727 Oil 9.9 0.51 BC H4 15,067gW781O011 9.9 0.51 BC_HS 15,102 9.9 0.51 BC_H6 15,186 9.9 0.51 15,341 9.9 0.51 15,452 er &1 0.42 Offset Well Mud Densities Well MW ran a To (ND Bottom ND Date BCU 05 Il-13ppg 12,500 16,250 2014 Beaver Creekl4A 9.0-9.4ppg 5,000 9,450 2014 Beaver Creek 779 1 9.0-9.3 2,400 8,929 2014 Assumptions: 1. Maximum planned mud density for the 6"hole section is 10.5 ppg. 2. Calculations assume reservoirs contain 100% gas (worst ase). 3. Calculations assume worst ase event is complete evacuation of wellbore to gas. 4. Anticipated fracture gradient at 140M TVD =12.5 ppg EMW Fracture Pressure at 6" shoe considering a full column of gas from window to surface: 14M (ft) x 0.65(psl/ft)= 9164ps1 9164(psi)-[0.1(psi/ft)-14098(ft)]= I 7754 sl MASP from pore pressure; entire wellbore evacuated to gas from TD 15452 (ft)x0.51(psi/ft)= 7881 sl 7881(psi)-[0.1(psl/ft)-15452(it)]= 6335 ps1 6335(psi)-[(2/3)•0.3(psl/ft)•15452(ft)]i[(1/3)•0.51(psl/ft)•15452(ft)]= 2678 si Alternate Drilling MASP Summary: 1. MASP while drilling 6" production hole is governed by SIBHP minus 2/3 wellbore evacuated to gas from TD. 2. MASP during production mode is governed by SIBHP minus entire wellbore evacuated to gas from TD. Page 51 Revision 0 January 2019 34.0 Spider Plot (Governmental Sections) BCU ® A028083 BLV 11 BEAVER CREI 'CU 04RD Drilling Procedure Rev 1 ecu o, e °e'BCU 4RD_BNL Legend S006NOlOW 4 28118 • BCU 4RD_SHL o Other Surface Well Locations X BCU 4RD_TPH a Other Bottom Hole Locations + BCU 4RD_BHL ---- Well Paths OOil and Gas Unit Boundary 0 500 1.OW 1$00 Beaver Creek Unit Feet 11 BCU-04RD Alaska State Plane Zone 4, NAD27 A lain -e Al,.kn. 1.111 wp_05b Map Date: 1/7812019 Page 52 Revision 0 January 2019 35.0 Surface Plat (As -Built) BCU 04RD Drilling Procedure Rev 1 SECTION20 T7N RIM SECTION33 T N RIM N 24352W 07 E 91583564 OLA .4 111 • •'.9 moi: AS -BUILT WELL �......... ..... �./............/ BCU4 ffiLL 3 3 i N:2433577.412 0 E .. 10 STA �� E:315181.614 ¢' / i STAN A. McLANE :' � z 37-5 :� LAT: 60° 39' 25.8088'N z ; /� '•.1 9/201 Q:• 44" LONG: -151°01'48.489M 4 „ q.,1}4� ♦ ASP ZONE 4 NAD27 z �fIll ss1om,,t 0 z 0 FNL=1641' FEL =631' w w ELEV = 148.2' (NAVD88) SECTION 33, T7N. R10W. SM. AK NOTES 531 I) BASIS OF GEODETIC CONTROL AND NAD83 FEL POSITION (EPOCH 2003) IS AN OPUS SOLUTION FROM NGS COORDINATES STATIO 1 COR$ ARP,TLKA TALKEETNA CORS ARP, AND•POT3 f POTATO BCU POINT 3 ARP TO ESTABLISH THE POSITION OF Pap Na. 4 MCI BCI. THE GEODETIC POSITION OF SCI WAS DETERMINED HAVE OF (LATITUDE 60-38'50 ANDA LONGITUDE D 151'02TOF 3031 THE ALASKA STATE PLANE E COORDINATES (ASP) ZONE 4 ARE COORDINATES N=2429933.534 ELEV 183.065 ELEV. 131.31' (NAVD88) 2) BASIS OF VERTICAL CONTROL IS NGS SM V80 PID TT0508 LOCATED WITHIN THE KENAI SPUR HIGHWAY RIGHT OF WAY AT MILE POST 3,75 NORTH HAVING AN ELEVATION OF 164.55 FEET NAVO 88 ACCORDING TO NGS PUBLISHED DATA 3) COORDINATES CONVERTED TO NAD27 USING 4'A 6m CORPSCON6 CONVERSION SOFTWARE SATE BCU #4 WELL AS -BUILT SURFACE LOCATION (NAD27) BEAVER CREEK UNIT PAD 4 ENGINEERING - TESTING LOCATION: SECTION 33, TOWNSHIP 7 NORTH, SURVEYING -MAPPING RANGE 10 WEST, SEWARD MERIDIAN ALASKA Ililalr Alu.ku. LLC P.O. BOX 468 P JOB NO. 197002 [ SOLDOTNA,AK-99669 VOICE (907)2a34219 FAX: 1907) 2833265 DRAWN BY CesaLHp 1W WWW.MCLANECG.COM BGB 1/9119 FIGURE:1 Page 53 Revision 0 January 2019 H 1101 p M.A.. W A: 36.0 Directional Program (WP05b) BCU 04RD Drilling Procedure Rev 1 Page 54 Revision 0 January 2019 Hilcorp Alaska, LLC Beaver Creek Unit Beaver Creek Unit Beaver CK Unit 4 Plan: BCU 4RD Plan: BCU 4RD wp05b Standard Proposal Report 16 January, 2019 HALLIBURTON Sperry Orilling Services HALLIBURTON Sp©r-ry Drilling HlI.M Alaska, LLC Cell Method: Minimum Curvature _ ___ _ TK_TVONEK-TS _I- Co-ordinate (NE) Reference: Well Beaver CK Unit 4, True North Error System: 1St, A K T53_.__ NE - _ _ _ _ TYONEK TS -- - Vertical (ND) Reference: BCU Planned RKB @ 166.20us8 Scan Methotl: Closes[Approach 3D SECTION Measured Depth Reference: BCU Planned RKB @ 16620.11 Error Surface: Pedal Curve -. TKttONEK T5_ _ - - Calculation Method: Minimum Curvature Warning Method: Enor Ratio Azi ND ND NDSS MD Size Name 12016.17 11849.97 12100.01 9-5/8 9 518' TOW 14097.98 13931.78 15150.00 7 7' x 8 3/8" 15452.20 15286.00 17434.29 4-1/2 4 7/2' x 6' 111500 71600 I KOP :Start Dir 12.75°/100' : 121 00'MD, 12016.16'ND : 45' RT TF 9 5/8" TOW 12000' 12000 f _ _ _End Dir :12113.33' MD, 12029.03' ND SR ttNK LT) - - -- - -" Start Dir 3-1100': 12133.33' MD, 12048.29'ND SR TVNK CT4 12800- TK TYONEK T4 S - - -1'3 V SR EIOMKT- w TYONEK_TS_x 13200 TK WONEK T5_ End Dir : 13995.02' MD, 13525.09' ND `M_TVONEK TS --x'3509 - O- _ ___ _ TK_TVONEK-TS _I- U BL G1_B. BC G1 L K T53_.__ NE - _ _ _ _ TYONEK TS -- - p0 12122.37 SECTION DETAILS _ c Gpelc a -. TKttONEK T5_ _ - - Sec MO Inc Azi ND +N/ -S -E/-W Dleg TFace VSect Target Annotatbn 1 12100.00 14.42 87.93 12016.16 343.9D 556.11 0.00 0.00 7.80 13146.76 KOP: Stars Dir 12.75°/ID9: 12100'MD, 12016.16'ND: 45' RT TF 2 12113.33 15.67 92.39 12029.03 34389 559.56 12.75 45.00 9.66 13459.27 End Dir : 1211333' MD, 12029.03' TVD 3 12133.33 15.67 92.39 12048.29 34386 564.96 0.00 0.00 12.75 14170.84 TK_TYONEK T5_7 Start Dir 3°1100': 12133.33' MD, 12048.29' 13 4 13995.02 60.26 161.46 13525.09 -501 AS 1117.64 3.00 78.52 1022A3 13643.28 End Dir : 13995.0210D.13525.09 -TVI) 5 15986.22 60.26 161.46 14512.75 -2140:30 1667.52 0.00 000 2700.69 13953.74 Start Dir 3°/100': 15986.22'MD, 14512.75'ND 6 15995.15 60.00 161.40 14517.20 -2147.64 1669.99 3.00 -169.63 2708.21 15255.78 BC__G1_C End Dir : 15995.15' MD, 14517.2' ND 7 16195.15 60.00 161.40 14617.20 -2311.80 1725.23 0.00 0.00 2876.40 BCU 4RD tgt2 wp04 Start Dir Y/100': 16195.15' MD, 14617.2'ND 8 16728.48 44.00 161.40 14944.49 -2708.83 1858.85 3.00 180.00 3283.19 14660.21 End Dir : 16728.48' MD, 14944.49' ND 9 17284.29 44-00 161.40 15344.30 4074.76 1982.00 0.00 0.00 3658.12 BCU 4RD igt3 MP04 14907.93 10 17434.29 44.00 161.40 15452.20 4173.51 2015.23 OGD 0.00 3759.30 15090.97 Total Depth : 17434.29' MD, 15452.2' TVD ND NDSS MD Size Name 12016.17 11849.97 12100.01 9-5/8 9 518' TOW 14097.98 13931.78 15150.00 7 7' x 8 3/8" 15452.20 15286.00 17434.29 4-1/2 4 7/2' x 6' 111500 71600 I KOP :Start Dir 12.75°/100' : 121 00'MD, 12016.16'ND : 45' RT TF 9 5/8" TOW 12000' 12000 f _ _ _End Dir :12113.33' MD, 12029.03' ND SR ttNK LT) - - -- - -" Start Dir 3-1100': 12133.33' MD, 12048.29'ND SR TVNK CT4 12800- TK TYONEK T4 S - - -1'3 V SR EIOMKT- w TYONEK_TS_x 13200 TK WONEK T5_ End Dir : 13995.02' MD, 13525.09' ND `M_TVONEK TS --x'3509 - O- _ ___ _ TK_TVONEK-TS _I- U BL G1_B. BC G1 L K T53_.__ NE - _ _ _ _ TYONEK TS -- - p0 12122.37 _M _ _- _ , -- - _ by _ _ c Gpelc a -. TKttONEK T5_ _ - - - 7•' x 8 3/8' K TK TYONEK TS ] 12866.07 SR _TYNK CT4 _TSs eTK K WONET5 B H4 - '- -- 12897.56 75-f0-_- _ _ J WEST_FOREl t TRTVDNE tLiSN TK TYONEK TS 1 TOP 14400 TYDNEK. G _ _ - HP4120 SAND ��- U BL G1_B. BC G1 L r @C G1 E BC G1_D- 12122.37 BC G2_A BC G1 F 0 14800 _ c Gpelc a F - 12729.18 BC HiHEMLOCK 12866.07 SR _TYNK CT4 BC_ 15200--1SBC H4 - '- -- 12897.56 =,BL_He ... -155( J WEST_FOREl 15630 15600 16000 16400 BCU 4RD tgtl wp04 _ - _- 6005 NDPath TVOssPath MDPath Formation 11857.06 1169086 11935.54 TK_TYONEK_T4_4 12122.37 11956.17 12210.38 SR_TYNK_CP 12363.87 12197.67 12464.33 L_ETNK 12729.18 12562.96 12866.07 SR _TYNK CT4 12827.05 12660,85 1297989 TN TVONEK T4_5 12897.56 12731.36 13064.20 SRE10MKT 13138.89 12972.69 13372.91 TK_TYONEK TS X 13208.39 13042.19 13469.64 TK_TYONEK_TS_X1 13273.98 13107.78 13565.37 TK_TYONEK TS_X2 13312.96 13146.76 13624.70 TK TYONEK TS 13365.41 13199.21 13707.92 TK TYONEK TS 1 13406.91 13240.71 13777.00 TK_TYONEK_T5_2 13438.71 13272.51 13832.23 TK_TYONEK_TS_3 13459.27 13293.07 13869.13 TK TYONEK TS 4 13508.18 13341.98 13961.40 TK TYONEK TS 5 13567.91 13401.71 14081.33 TK_TYONEK_T56 13612.30 44 136.10 14170.84 TK_TYONEK T5_7 13653.24 13467.04 14253.36 TKTYONEK TS 8 13723.30 13557.10 14394.61 TKTYONEK_TS 9 13766.94 13600.74 14482.60 TK_TYONEK_T5_10 13809.48 13643.28 1456636 TK TYONEK_T5_11 13851.98 13685.78 14654.04 TK TYONEK TS 12 13901.97 13735.77 14754.84 TK_TYONEK_T5_13 13928.07 13761.87 14807.45 TOPTYONEK 13953.74 13787.54 14859.21 HP-I_20 14094.30 13928.10 _SAND 15142.58 BC G1 A 14129.20 13963.00 15212.94 BCG1_B 14150.45 13984.25 15255.78 BC__G1_C 14206.61 14040.41 15369.00 BC G1 D 14293.6314127.43 15544.45 8C_G1_E 14353.63 14187.43 15665.41 BC G1 F 14396.11 14229.91 15751.06 SC; 14534.17 14367.97 _G2_A 16029.09 BC_G2_S 14610.99 14444.79 16182.73 BC_G2_C 14623.56 14457.36 16207.81 BC G2 D 14660.21 14494.01 16278.07 HEMLOCK 14729.48 14563.28 16400.93 SC_H1 14798.72 14632.52 16513.75 BC H2 14848.13 14681.93 16589.53 BC HIS 14907.93 14741.73 16676.98 BC H4 14941.36 14775.16 16724.13 BC 5 15058.87 14892.67 16887.49 BC-1-1He 15257.17 15090.97 17163.16 WEST FORELAND Start Dir 3°/100' 15986.22' MD, 14512.75'ND End Dir : 15995.15' MD, 14517.2' NU `BCU 4RD 4g@ 15000 Start Dir 3°/100: 16195.15' MD, 14617.2'ND D 16728 48 D 1 944 49 ND --- - ---006-End ir: 'M 4 ' BCU 04PB2 15940 BCU 04 - - _ - - - BCU 4RD t9t3 wp(; BCU 4RD wpO5b Total Depth: 17434.29' MD, 15452.2' ND 4 1/2" x 6" Vertical Section at 147.58° (800 usRfin) WELL DETAILS: Beaver CK Unit 4 Ground Level: 148.20 ,NI -S +E/ -W 0.00 0.00 Northing Easting 2433577.41 315181.61 Latittude Longitude 60' 39'25.809 N 151' V 48.489 W Project., Site: Beaver Creek Unit Beaver Creek Unit SURVEY PROGRAM Date:2019-12-14T00:00:00 validated: Yea Veraien: yyep: Beaver CK Unit 4 Depth ep 3@20 oz8az.zu BCUG PBI GMS (BCU OOPBI) 2Flan �ol C8 -Film -GMS -I Wellbore: Design: Plan: BCU 4RD BCU 4RD wp05b 3107.20 050720 0767.20 12100.00 12100M 2500.00 1515040 RCU-04PR1 CB -MMS (RCU "PSI) 2 CR -Film -MMS RCU44PB2 CB -MSS (BCU Ol 2 CB -Firm -MSS BCU 4RD "Cra,(PIan: BCU 4RD( 2 MWD+IFRIPMS+S, - �1 -400 0 400 800 1200 1600 2000 2400 2800 3200 3600 r -rr- 4000 4400 4800 5200 5600 Vertical Section at 147.58° (800 usRfin) c ,o _m -S 4 r • t ) ; oa ! } ! {) ®) \ )\ ` /`� \ c ,o _m -S 4 ! } ! {) ®) )\ ` ; { § {) ®) )\ ` HALLIBURTON Database: NORTH US+CANADA Company: Hiloorp Alaska, LLC Project: Beaver Creek Unit Site: Beaver Creek Unit Well: Beaver CK Unit 4 Wellbore: Plan: BCU 4RD Design: BCU 4RD wp05b Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Beaver CK Unit 4 TVD Reference: BCU Planned IRKS @ 166.20usft MD Reference: BCU Planned IRKS @ 166.20usft North Reference: True Survey Calculation Method: Minimum Curvature 'reject Beaver Creek Unit Aap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Aap Zone: Alaska Zane 04 Using geodetic scale factor nPa„P� rrcak i iia Site Position From: Map Position Uncertainty: 0.00 usft Well Beaver CK Unit 4 Well Position +N/ -S 0.00 usft +E/ -W 0.00 usft Position Uncertainty 0.00 usfl Wellbore Plan: BCU 4RD Magnetics Design Audit Notes: Version: Vertical Section: Model Name BGGM2018 BCU 4RD wp05b Northing: 2,430,086.36usft Latitude: Easting: 314,428.19usft Longitude: Slat Radius: 13-3/16" Grid Convergence: Northing: 2,433,577.41 usfl Easting: 315,181.61 usfl Wellhead Elevation: 0.00 usft Sample Date Declination (°) 12/14/2018 15.61 Phase: PLAN Depth From (TVD) +NI -S (usfl) (usft) 18.00 0.00 Plan Sections Dogleg Build Turn +N1 -s +E/ -W Measured Rate Rate Tool Face (usft) Vertical TVD ("1100usft) Depth Inclination Azimuth 343.90 Depth System 0.00 (usfl) (°) 343.89 (°) 12.75 (usft) usft 45.00 12,100.00 14.42 0.00 87.93 0.00 12,016.16 11,849.96 1,117.64 12,113.33 15.67 3.71 92.39 -2,140.30 12,029.03 11,862.83 0.00 12,133.33 15.67 -2,147.64 92.39 3.00 12,048.29 11,882.09 -169.63 13,995.02 60.26 0.00 161.46 0.00 13,525.09 13,358.89 1,858.85 15,986.22 60.26 0.00 161.46 -3,074.76 14,512.75 14,346.55 0.00 15,995.15 60.00 -3,173.51 161.40 0.00 14,517.20 14,351.00 0.00 16,195.15 60.00 161.40 14,617.20 14,451.00 16,728.48 44.00 161.40 14,944.49 14,778.29 17,284.29 44.00 161.40 15,344.30 15,178.10 17,434.29 44.00 161.40 15,452.20 15,286.00 60°38'51.316N 151 ° 2'2.502 W -0.90 ° Latitude: 60° 39'25.809 N Longitude: 151° 1'48.489 W Ground Level: 148.20 usft Dip Angle Field Strength l°) (nT) 73.61 55, 297.31498804 Tie On Depth: 12,100.00 +E/ -W Direction (usft) (I 0.00 147.58 1/182019 4:09:38PM Page 2 COMPASS 5000.15 Build 91 Dogleg Build Turn +N1 -s +E/ -W Rate Rate Rate Tool Face (usft) (usfl) (°1100usft) ("1100usft) (°1100usft) (°) 343.90 556.11 0.00 0.00 0.00 0.00 343.89 559.56 12.75 9.35 33.41 45.00 343.66 564.96 0.00 0.00 0.00 0.00 -501.08 1,117.64 3.00 2.40 3.71 78.52 -2,140.30 1,667.52 0.00 0.00 0.00 0.00 -2,147.64 1,669.99 3.00 -2.95 -0.62 -169.63 -2,311.80 1,725.23 0.00 0.00 0.00 0.00 -2,708.83 1,858.85 3.00 -3.00 0.00 180.00 -3,074.76 1,982.00 0.00 0.00 0.00 0.00 -3,173.51 2,015.23 0.00 0.00 0.00 0.00 1/182019 4:09:38PM Page 2 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Beaver Creek Unit Site: Beaver Creek Unit Well: Beaver CK Unit 4 Wellbore: Plan: BCU 4RD Design: BCU 4RD wp05b Planned Survey Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Beaver CK Unit 4 BCU Planned RKB @ 166.20usft BCU Planned RKB @ 166.20usft True Minimum Curvature Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NIS +E/ -W Northing Easting DLS Vert Section (usft) (') (1) (usft) usft (usft) (usft) (usft) (usft) -148.20 18.00 0.00 0.00 18.00 -148.20 0.00 0.00 2,433,577.41 315,181.61 0.00 0.00 202.20 0.00 180.00 202.20 36.00 0.00 0.00 2,433,577.41 315,181.61 0.00 0.00 402.20 0.50 244.00 402.20 236.00 -0.38 -0.78 2,433,577.04 315,180.82 0.25 -0.10 602.20 0.25 280.00 602.19 435.99 -0.69 -2.00 2,433,576.75 315,179.61 0.17 -0.49 802.20 0.25 256.00 802.19 635.99 -0.72 -2.85 2,433,576.74 315,178.75 0.05 -0.92 1,002.20 0.33 348.00 1,002.19 835.99 -0.26 -3.39 2,433,577.20 315,178.22 0.21 -1.60 1,202.20 0.33 325.00 1,202.19 1,035.99 0.77 -3.84 2,433,578.25 315,177.78 0.07 -2.71 1,402.20 0.50 250.00 1,402.18 1,235.98 0.95 -5.00 2,433,578.44 315,176.63 0.26 -3.48 1,602.20 0.00 180.00 1,602.18 1,435.98 0.65 -5.82 2,433,578.15 315,175.81 0.25 -3.66 1,802.20 0.25 130.00 1,802.18 1,635.98 0.37 -5.48 2,433,577.87 315,176.14 0.12 -3.25 2,002.20 0.17 15.00 2,002.18 1,835.98 0.37 -5.07 2,433,577.87 315,176.55 0.18 -3.03 2,202.20 0.25 100.00 2,202.18 2,035.98 0.59 -4.56 2,433,578.07 315,177.06 0.14 -2.94 2,402.20 0.17 20.00 2,402.18 2,235.98 0.79 -4.03 2,433,578.26 315,177.59 0.14 -2.83 2,602.20 0.08 240.00 2,602.18 2,435.98 1.00 -4.05 2,433,578.47 315,177.58 0.12 -3.01 2,802.20 0.50 179.00 2,802.17 2,635.97 0.05 -4.16 2,433,577.53 315,177.46 0.23 -2.27 2,991.20 0.23 207.81 2,991.17 2,824.97 -1.10 -4.32 2,433,576.38 315,177.28 0.17 -1.39 13 318" 3,187.20 0.25 296.00 3,187.17 3,020.97 -1.26 -4.88 2,433,576.23 315,176.71 0.17 -1.56 3,367.20 0.00 0.00 3,367.17 3,200.97 -1.08 -5.24 2,433,576.41 315,176.36 0.14 -1.89 3,547.20 0.25 35.00 3,547.17 3,380.97 -0.76 -5.01 2,433,576.73 315,176.59 0.14 -2.04 3,727.20 0.25 100.00 3,727.17 3,560.97 -0.51 4.40 2,433,576.97 315,177.21 0.15 -1.93 3,907.20 0.00 180.00 3,907.17 3,740.97 -0.58 -4.01 2,433,576.90 315,177.59 0.14 -1.66 4,087.20 0.25 90.00 4,087.16 3,920.96 -0.58 -3.62 2,433,576.89 315,177.99 0.14 -1.45 4,267.20 0.50 210.00 4,267.16 4,100.96 -1.26 -3.62 2,433,576.21 315,177.98 0.37 -0.88 4,447.20 0.50 230.00 4,447.16 4,280.96 -2.44 4.61 2,433,575.04 315,176.96 0.10 -0.41 4,627.20 0.25 209.00 4,627.15 4,460.95 -3.29 -5.41 2,433,574.21 315,176.16 0.16 -0.12 4,807.20 0.50 265.00 4,807.15 4,640.95 -3.70 -6.38 2,433,573.81 315,175.18 0.23 -0.29 4,987.20 0.25 299.00 4,987.14 4,820.94 -3.58 -7.50 2,433,573.95 315,174.06 0.18 -1.00 5,158.20 0.25 303.00 5,158.14 4,991.94 -3.20 -8.14 2,433,574.34 315,173.42 0.01 -1.67 5,347.20 0.25 245.00 5,347.14 5,180.94 -3.15 -8.86 2,433,574.41 315,172.70 0.13 -2.09 5,527.20 0.00 180.00 5,527.14 5,360.94 -3.31 -9.22 2,433,574.24 315,172.35 0.14 -2.15 5,707.20 0.25 325.00 5,707.14 5,540.94 -2.99 -9.44 2,433,574.57 315,172.12 0.14 -2.54 5,887.20 0.25 340.00 5,887.14 5,720.94 -2.30 -9.80 2,433,575.27 315,171.78 0.04 -3.31 6,067.20 0.25 340.00 6,067.14 5,900.94 -1.56 -10.07 2,433,576.01 315,171.52 0.00 -4.08 6,247.20 0.25 26.00 6,247.14 6,080.94 -0.84 -10.03 2,433,576.73 315,171.57 0.11 -4.67 6,427.20 0.75 329.00 6,427.13 6,260.93 0.52 -10.47 2,433,578.10 315,171.16 0.36 -6.05 6,607.20 1.25 312.00 6,607.10 6,440.90 2.85 -12.53 2,433,580.45 315,169.13 0.32 -9.12 6,787.20 1.25 305.00 6,787.06 6,620.86 5.29 -15.60 2,433,582.94 315,166.10 0.08 -12.83 6,967.20 1.00 304.00 6,967.02 6,800.82 7.29 -18.51 2,433,584.99 315,163.22 0.14 -16.08 7,147.20 1.25 289.00 7,146.99 6,980.79 8.81 -21.67 2,433,586.56 315,160.08 0.21 -19.05 7,327.20 1.50 291.00 7,326.94 7,160.74 10.29 -25.73 2,433,588.10 315,156.05 0.14 -22.48 7,507.20 1.50 306.00 7,506.88 7,340.68 12.52 -29.83 2,433,590.40 315,151.98 0.22 -26.56 7,687.20 1.50 310.00 7,686.81 7,520.61 15.42 -33.54 2,433,593.35 315,148.32 0.06 -31.00 7,867.20 1.50 305.00 7,866.75 7,700.55 18.29 -37.28 2,433,596.28 315,144.63 0.07 -35.42 8,047.20 1.25 310.00 8,046.70 7,880.50 20.90 -40.71 2,433,598.94 315,141.24 0.15 -39.47 1/162019 4,09:38PM Page 3 COMPASS 5000.15 Build 91 Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Beaver CK Unit 4 Company: Hilcorp Alaska, LLC TVD Reference: BCU Planned IRKS @ 166.20usft Project: Beaver Creek Unit MD Reference: BCU Planned IRKS @ 166.20usft Site: Beaver Creek Unit North Reference: True Well: Beaver CK Unit 4 Survey Calculation Method: Minimum Curvature Wellbore: Plan: BCU 4RD Vertical Design: BCU 4RD wp05b Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (^) (^) (usft) usft (usft) (usft) (usft) (usft) 8,060.45 8,227.20 1.50 310.00 8,226.65 8,060.45 23.68 -44.02 2,433,601.77 315,137.97 0.14 -43.58 8,407.20 1.50 315.00 8,406.59 8,240.39 26.86 -47.49 2,433,605.01 315,134.55 0.07 -48.13 8,587.20 1.50 321.00 8,586.53 8,420.33 30.35 -50.64 2,433,608.55 315,131.46 0.09 -52.77 8,767.20 2.00 324.00 8,766.44 8,600.24 34.72 -53.97 2,433,612.98 315,128.20 0.28 -58.24 8,798.20 3.50 355.00 8,797.41 8,631.21 36.10 54.37 2,433,614.36 315,127.82 6.65 -59.62 8,830.20 3.50 344.00 8,829.35 8,663.15 38.02 -54.72 2,433,616.28 315,127.50 2.10 -61.43 8,860.20 4.75 20.00 8,859.27 8,693.07 40.06 -54.55 2,433,618.32 315,127.70 9.37 -63.06 8,906.20 5.25 27.00 8,905.10 8,738.90 43.73 -52.94 2,433,621.96 315,129.37 1.71 -65.30 8,984.20 6.00 27.00 8,982.72 8,816.52 50.54 -49.47 2,433,628.72 315,132.94 0.96 -69.19 9,187.20 7.75 35.00 9,184.26 9,018.06 71.21 -36.80 2,433,649.18 315,145.93 0.98 -79.84 9,362.20 9.25 40.00 9,357.33 9,191.13 91.65 -20.99 2,433,669.37 315,162.06 0.95 -88.62 9,524.20 9.25 44.00 9,517.23 9,351.03 110.99 -3.58 2,433,688.44 315,179.77 0.40 -95.61 9,638.20 9.75 46.00 9,629.67 9,463.47 124.29 9.73 2,433,701.52 315,193.29 0.53 -99.71 9,780.20 10.75 50.00 9,769.40 9,603.20 141.15 28.52 2,433,718.09 315,212.34 0.86 -103.87 9,904.20 11.50 52.00 9,891.07 9,724.87 156.20 47.12 2,433,732.84 315,231.18 0.68 -106.60 10,112.20 11.50 56.00 10,094.90 9,928.70 180.56 80.65 2,433,756.67 315,265.08 0.38 -109.19 10,323.20 14.00 58.00 10,300.68 10,134.48 205.85 119.74 2,433,781.34 315,304.56 1.20 -109.58 10,448.20 14.75 60.00 10,421.77 10,255.57 221.82 146.34 2,433,796.89 315,331.41 0.72 -108.80 10,545.20 14.50 62.00 10,515.62 10,349.42 233.69 167.76 2,433,808.43 315,353.01 0.58 -107.35 10,666.20 14.50 62.00 10,632.77 10,466.57 247.91 194.51 2,433,822.23 315,379.97 0.00 -105.01 10,784.20 15.50 66.00 10,746.75 10,580.55 261.26 221.96 2,433,835.15 315,407.63 1.22 -101.57 10,830.20 15.50 66.00 10,791.08 10,624.88 266.26 233.19 2,433,839.97 315,418.93 0.00 -99.77 10,934.20 15.25 68.00 10,891.36 10,725.16 277.04 258.57 2,433,850.35 315,444.47 0.56 -95.26 11,041.20 15.25 70.00 10,994.59 10,828.39 287.12 284.84 2,433,860.02 315,470.90 0.49 -89.69 11,200.20 15.25 72.00 11,147.99 10,981.79 300.74 324.37 2,433,873.01 315,510.64 0.33 -79.99 11,291.20 15.75 74.00 11,235.68 11,069.48 307.84 347.63 2,433,879.75 315,534.00 0.80 -73.52 11,439.20 15.75 76.00 11,378.13 11,211.93 318.24 386.43 2,433,889.53 315,572.96 0.37 -61.50 11,564.20 15.25 78.00 11,498.58 11,332.38 325.76 418.97 2,433,896.55 315,605.61 0.59 -50.40 11,668.20 15.25 80.00 11,598.92 11,432.72 330.98 445.82 2,433,901.34 315,632.54 0.51 -40.42 11,763.20 15.25 80.00 11,690.57 11,524.37 335.32 470.43 2,433,905.29 315,657.21 0.00 -30.89 11,837.20 15.00 82.00 11,762.01 11,595.81 338.34 489.49 2,433,908.02 315,676.32 0.78 -23.22 11,931.20 14.75 85.00 11,852.86 11,686.66 341.08 513.46 2,433,910.38 315,700.33 0.86 -12.68 11,935.54 14.75 85.05 11,857.06 11,690.86 341.17 514.56 2,433,910.46 315,701.43 0.30 -12.17 TK_TVONEK_T4_4 12,017.20 14.75 86.00 11,936.03 11,769.83 342.79 535.29 2,433,911.75 315,722.18 0.30 -2.43 12,100.00 14.42 87.93 12,016.16 11,849.96 343.90 556.11 2,433,912.53 315,743.01 0.71 7.80 KOP : Start Dir 112.7511100': 12100' MD, 12016.16'TVD : 450 RT TP 12,100.01 14.42 87.93 12,016.17 11,849.97 343.90 556.11 2,433,912.53 315,743.01 0.00 7.80 ,V (N DOu! 9 5/8" TOW 12,113.33 15.67 92.39 12,029.03 11,862.83 343.89 559.56 2,433,912.47 315,746.46 12.76 9.66 End Dir : 12113.33' MD, 12029.03' TVD 12,133.33 15.67 92.39 12,048.29 11,882.09 343.66 564.96 2,433,912.16 315,751.86 0.00 12.75 Start Dir 30/100' : 12133.33' MD, 12048.29TVD 12,200.00 16.18 99.44 12,112.41 11,946.21 341.76 583.12 2,433,909.97 315,769.98 3.00 24.08 1/162019 4:09:38PM Page 4 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Beaver CK Unit 4 Company: Hilcorp Alaska, LLC TVD Reference: BCU Planned RKB @ 166.20usft Project: Beaver Creek Unit MD Reference: BCU Planned RKB @ 166.20usft Site: Beaver Creek Unit North Reference: True Well: Beaver CK Unit 4 Survey Calculation Method: Minimum Curvature Wellbore: Plan- BCU 4RD Design: BCU 4RD wp05b Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +Nl-S +EI -W Northing Basting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 11,956.17 12,210.38 16.28 100.49 12,122.37 11,956.17 341.26 585.98 2,433,909.43 315,772.83 3.00 26.04 SR_TYNK_CT7 12,300.00 17.35 109.03 12,208.17 12,041.97 334.61 610.97 2,433,902.39 315,797.71 3.00 45.04 12,400.00 18.92 117.27 12,303.22 12,137.02 322.32 639.48 2,433,889.65 315,826.02 3.00 70.70 12,464.33 20.09 121.86 12,363.87 12,197.67 311.71 658.13 2,433,878.75 315,844.51 3.00 89.66 L_E_TNK 12,500.00 20.79 124.18 12,397.29 12,231.09 304.92 668.57 2,433,871.80 315,854.84 3.00 100.99 12,600.00 22.89 129.94 12,490.12 12,323.92 282.46 698.17 2,433,848.88 315,884.08 3.00 135.82 12,700.00 25.17 134.74 12,581.45 12,415.25 255.00 728.19 2,433,820.96 315,913.67 3.00 175.09 12,800.00 27.58 138.78 12,671.05 12,504.85 222.62 758.56 2,433,788.10 315,943.52 3.00 218.71 12,866.07 29.22 141.10 12,729.16 12,562.96 198.56 778.76 2,433,763.73 315,963.35 3.00 249.85 SR_TYNK_CT4 12,900.00 30.08 142.20 12,758.65 12,592.45 185.40 789.18 2,433,750.41 315,973.55 3.00 266.54 12,979.89 32.14 144.58 12,827.05 12,660.85 152.26 813.77 2,433,716.89 315,997.62 3.00 307.70 TK_TYONEK_T4_5 13,000.00 32.67 145.13 12,844.03 12,677.83 143.44 819.97 2,433,707.98 316,003.69 3.00 318.47 13,064.20 34.36 146.81 12,897.56 12,731.36 114.07 839.80 2,433,678.30 316,023.05 3.00 353.90 SR_E10MKT 13,100.00 35.31 147.68 12,926.94 12,760.74 96.87 850.86 2,433,660.93 316,033.84 3.00 374.34 13,200.00 38.00 149.91 13,007.17 12,840.97 45.81 881.75 2,433,609.39 316,063.92 3.00 434.01 13,300.00 40.72 151.88 13,084.48 12,918.28 -9.61 912.56 2,433,553.50 316,093.86 3.00 497.30 13,372.91 42.73 153.19 13,138.89 12,972.69 -52.67 934.93 2,433,510.10 316,115.55 3.00 545.64 TK_TYONEK_T5_X 13,400.00 43.48 153.65 13,158.67 12,992.47 -69.22 943.21 2,433,493.42 316,123.57 3.00 564.06 13,469.64 45.41 154.78 13,208.39 13,042.19 -113.13 964.41 2,433,449.19 316,144.08 3.00 612.49 TK_TYONEK_TS_X1 13,500.00 46.26 155.25 13,229.54 13,063.34 -132.87 973.61 2,433,429.31 316,152.96 3.00 634.09 13,565.37 48.09 156.21 13,273.98 13,107.78 -176.57 993.31 2,433,385.30 316,171.97 3.00 681.54 TK_TYONEK_T5_X2 13,600.00 49.06 156.70 13,296.89 13,130.69 -200.38 1,003.68 2,433,361.34 316,181.97 3.00 707.20 13,624.70 49.75 157.04 13,312.96 13,146.76 -217.63 1,011.05 2,433,343.98 316,189.06 3.00 725.70 TK_TYONEK_TS 13,700.00 51.88 158.04 13,360.54 13,194.34 -271.57 1,033.34 2,433,289.70 316,210.50 3.00 783.19 13,707.92 52.10 158.14 13,365.41 13,199.21 -277.36 1,035.66 2,433,283.88 316,212.74 3.00 789.32 TK_TYONEK_T5_1 13,777.00 54.06 159.00 13,406.91 13,240.71 -328.76 1,055.84 2,433,232.16 316,232.10 3.00 843.53 TK_TYONEK_T5_2 13,800.00 54.71 159.27 13,420.30 13,254.10 -346.24 1,062.50 2,433,214.59 316,238.49 3.00 861.85 13,832.23 55.62 159.65 13,438.71 13,272.51 -371.01 1,071.77 2,433,189.68 316,247.38 3.00 887.74 TK_TYONEK_T5_3 13,869.13 56.67 160.08 13,459.27 13,293.07 -399.78 1,082.32 2,433,160.74 316,257.47 3.00 917.68 TK_TYONEK_T5_4 13,900.00 57.55 160.43 13,476.03 13,309.83 -424.18 1,091.08 2,433,136.21 316,265.85 3.00 942.97 13,961.40 59.30 161.10 13,508.18 13,341.98 -473.57 1,108.31 2,433,086.56 316,282.30 3.00 993.90 TK_TYONEK_T5_5 1/162019 4:09:38PM Page 5 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Beaver CK Unit 4 Company: Hilcorp Alaska, LLC TVD Reference: BCU Planned RKB @ 166.20usft Project: Beaver Creek Unit MD Reference: BCU Planned RKB @ 166.20usft Site: Beaver Creek Unit North Reference: True Well:. Beaver CK Unit 4 Survey Calculation Method: Minimum Curvature Wellbore: Plan: BCU 4RD Design: BCU 4RD wp05b Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +EI -W Northing Easting DLS Vert Section (usft) (1) (1) (usft) usft (usft) (usft) (usft) (usft) 13,358.90 13,995.02 60.26 161.46 13,525.10 13,358.90 -501.08 1,117.64 2,433,058.91 316,291.19 3.00 1,022.13 End Dir : 13995.02' MD, 13525.09' TVD 14,000.00 60.26 161.46 13,527.57 13,361.37 -505.18 1,119.01 2,433,054.79 316,292.50 0.00 1,026.33 14,081.33 60.26 161.46 13,567.91 13,401.71 -572.14 1,141.47 2,432,987.49 316,313.91 0.00 1,094.89 TK_TYONEK_T5_6 14,100.00 60.26 161.46 13,577.17 13,410.97 -587.51 1,146.63 2,432,972.04 316,318.82 0.00 1,110.63 14,170.84 60.26 161.46 13,612.30 13,446.10 £45.82 1,166.19 2,432,913.43 316,337.47 0.00 1,170.35 TK_TYONEK_TS_7 14,200.00 60.26 161.46 13,626.77 13,460.57 -669.83 1,174.24 2,432,889.30 316,345.14 0.00 1,194.93 14,253.36 60.26 161.46 13,653.24 13,487.04 -713.76 1,188.98 2,432,845.15 316,359.19 0.00 1,239.91 TK_TYONEK_T5_8 14,300.00 60.26 161.46 13,676.37 13,510.17 -752.15 1,201.86 2,432,806.56 316,371.47 0.00 1,279.23 14,394.61 60.26 161.46 13,723.30 13,557.10 -830.04 1,227.99 2,432,728.28 316,396.37 0.00 1,358.98 TK_TYONEK_T5_9 14,400.00 60.26 161.46 13,725.97 13,559.77 -834.48 1,229.48 2,432,723.82 316,397.79 0.00 1,363.52 14,482.60 60.26 161.46 13,766.94 13,600.74 -902.48 1,252.29 2,432,655.47 316,419.53 0.00 1,433.16 TK_TYONEK_T5_10 14,500.00 60.26 161.46 13,775.57 13,609.37 -916.80 1,257.09 2,432,641.08 316,424.11 0.00 1,447.82 14,568.36 60.26 161.46 13,809.48 13,643.28 -973.07 1,275.97 2,432,584.52 316,442.10 0.00 1,505.45 TK_TYONEK_T5_11 14,600.00 60.26 161.46 13,825.17 13,658.97 -999.12 1,284.71 2,432,558.34 316,450.43 0.00 1,532.12 14,654.04 60.26 161.46 13,851.98 13,685.78 -1,043.61 1,299.63 2,432,513.63 316,464.65 0.00 1,577.68 TK_TYONEK_T5_12 14,700.00 60.26 161.46 13,874.77 13,708.57 -1,081.44 1,312.32 2,432,475.60 316,476.75 0.00 1,616.42 14,754.84 60.26 161.46 13,901.97 13,735.77 -1,126.59 1,327.47 2,432,430.23 316,491.18 0.00 1,662.65 TK_TYONEK_T5_13 14,800.00 60.26 161.46 13,924.37 13,758.17 -1,163.77 1,339.94 2,432,392.86 316,503.07 0.00 1,700.72 14,807.45 60.26 161.46 13,928.07 13,761.87 -1,169.91 1,342.00 2,432,386.69 316,505.03 0.00 1,707.00 TOP _TYONEK_G 14,859.21 60.26 161.46 13,953.74 13,787.54 -1,212.51 1,356.29 2,432,343.87 316,518.65 0.00 1,750.63 HP -H20 -SAND 14,900.00 60.26 161.46 13,973.98 13,807.78 -1,246.09 1,367.55 2,432,310.12 316,529.39 0.00 1,785.02 15,000.00 60.26 161.46 14,023.58 13,857.38 -1,328.41 1,395.17 2,432,227.38 316,555.71 0.00 1,869.32 15,100.00 60.26 161.46 14,073.18 13,906.98 -1,410.74 1,422.79 2,432,144.64 316,582.03 0.00 1,953.62 15,142.58 60.26 161.46 14,094.30 13,928.10 -1,445.79 1,434.54 2,432,109.41 316,593.24 0.00 1,989.51 BC G1_A 15,150.00 60.26 161.46 14,097.98 13,931.78 -1,451.90 1,436.59 2,432,103.27 316,595.19 0.00 1,995.77 7" x 8 3/8" 15,200.00 60.26 161.46 14,122.78 13,956.58 -1,493.06 1,450.40 2,432,061.90 316,608.35 0.00 2,037.92 15,212.94 60.26 161.46 14,129.20 13,963.00 -1,503.71 1,453.98 2,432,051.19 316,611.76 0.00 2,048.83 BC_G1_B 15,255.78 60.26 161.46 14,150.45 13,984.25 -1,538.98 1,465.81 2,432,015.74 316,623.03 0.00 2,084.94 BC_G1_C 15,300.00 60.26 161.46 14,172.38 14,006.18 -1,575.38 1,478.02 2,431,979.15 316,634.67 0.00 2,122.22 15,369.00 60.26 161.46 14,206.61 14,040.41 -1,632.19 1,497.07 2,431,922.06 316,652.83 0.00 2,180.38 1/1612019 4:09:38PM Page 6 COMPASS 5000.15 Build 91 Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Beaver CK Unit 4 Company: Hilcorp Alaska, LLC TVD Reference: BCU Planned RKB @ 166.20usft Project: Beaver Creek Unit MD Reference: BCU Planned RKB @ 166.20usft Site: Beaver Creek Unit North Reference: True Well: Beaver CK Unit 4 Survey Calculation Method: Minimum Curvature Wellbore: Pian: BCU 4RD Vert Section (usft) Design: BCU 4RD wp05b (usft) Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (1) (1) (usft) usft (usft) (usft) (usft) (usft) 14,055.78 15,400.00 60.26 161.46 14,221.98 14,055.78 -1,657.71 1,505.63 2,431,896.41 316,660.99 0.00 2,206.51 15,500.00 60.26 161.46 14,271.58 14,105.38 -1,740.03 1,533.25 2,431,813.67 316,687.31 0.00 2,290.81 15,544.45 60.26 161.46 14,293.63 14,127.43 -1,776.63 1,545.52 2,431,776.89 316,699.01 0.00 2,328.29 BC_G1_E 15,600.00 60.26 161.46 14,321.18 14,154.98 -1,822.35 1,560.86 2,431,730.93 316,713.63 0.00 2,375.11 15,665.41 60.26 161.46 14,353.63 14,187.43 -1,876.20 1,578.93 2,431,676.81 316,730.85 0.00 2,430.25 BC_G1_F 15,700.00 60.26 161.46 14,370.78 14,204.58 -1,904.68 1,588.48 2,431,648.19 316,739.95 0.00 2,459.41 15,751.06 60.26 161.46 14,396.11 14,229.91 -1,946.71 1,602.58 2,431,605.94 316,753.39 0.00 2,502.46 BC_G2_A 15,800.00 60.26 161.46 14,420.39 14,254.19 -1,987.00 1,616.10 2,431,565.45 316,766.27 0.00 2,543.71 15,900.00 60.26 161.46 14,469.99 14,303.79 -2,069.32 1,643.71 2,431,482.71 316,792.59 0.00 2,628.01 15,986.22 60.26 161.46 14,512.75 14,346.55 -2,140.30 1,667.52 2,431,411.37 316,815.29 0.00 2,700.69 Start Dir 3°1100' : 15986.22' MD, 14512.75'TVD 15,995.15 60.00 161.40 14,517.20 14,351.00 -2,147.64 1,669.99 2,431,403.99 316,817.64 3.00 2,708.21 End Dir : 15995.15' MD, 14517.2' ND 16,000.00 60.00 161.40 14,519.63 14,353.43 -2,151.62 1,671.33 2,431,399.99 316,818.91 0.00 2,712.29 16,029.09 60.00 161.40 14,534.17 14,367.97 -2,175.50 1,679.36 2,431,375.99 316,826.58 0.00 2,736.76 BC_G2_B 16,100.00 60.00 161.40 14,569.63 14,403.43 -2,233.70 1,698.95 2,431,317.50 316,845.25 0.00 2,796.39 16,182.73 60.00 161.40 14,610.99 14,444.79 -2,301.61 1,721.80 2,431,249.25 316,867.03 0.00 2,865.96 BC_G2_C 16,195.15 60.00 161.40 14,617.20 14,451.00 -2,311.80 1,725.23 2,431,239.00 316,870.30 0.00 2,876.41 Start Dir 3°/100' : 16195.15' MD, 14617.2'TVD 16,200.00 59.85 161.40 14,619.63 14,453.43 -2,315.78 1,726.57 2,431,235.00 316,871.58 3.00 2,880.48 16,207.81 59.62 161.40 14,623.56 14,457.36 -2,322.17 1,728.72 2,431,228.58 316,873.63 3.00 2,887.03 BC_G2_D 16,278.07 57.51 161.40 14,660.21 14,494.01 -2,378.99 1,747.84 2,431,171.47 316,891.85 3.00 2,945.24 HEMLOCK 16,300.00 56.85 161.40 14,672.09 14,505.89 -2,396.45 1,753.72 2,431,153.92 316,897.46 3.00 2,963.14 16,400.00 53.85 161.40 14,728.93 14,562.73 -2,474.42 1,779.96 2,431,075.56 316,922.47 3.00 3,043.02 16,400.93 53.83 161.40 14,729.48 14,563.28 -2,475.13 1,780.20 2,431,074.84 316,922.70 3.00 3,043.75 BC H1 16,500.00 50.85 161.40 14,790.00 14,623.80 -2,549.45 1,805.21 2,431,000.14 316,946.54 3.00 3,119.90 16,513.75 50.44 161.40 14,798.72 14,632.52 -2,559.53 1,808.60 2,430,990.01 316,949.77 3.00 3,130.22 BC H2 16,589.53 48.17 161.40 14,848.13 14,681.93 -2,613.98 1,826.93 2,430,935.28 316,967.24 3.00 3,186.01 BC H3 16,600.00 47.85 161.40 14,855.13 14,688.93 -2,621.36 1,829.41 2,430,927.87 316,969.61 3.00 3,193.57 16,676.98 45.55 161.40 14,907.93 14,741.73 -2,674.45 1,847.28 2,430,874.50 316,986.64 3.00 3,247.97 BC H4 16,700.00 44.85 161.40 14,924.15 14,757.95 -2,689.93 1,852.49 2,430,858.94 316,991.61 3.00 3,263.83 16,724.13 44.13 161.40 14,941.36 14,775.16 -2,705.96 1,857.88 2,430,842.83 316,996.75 3.00 3,280.25 BC HIS 16,728.48 44.00 161.40 14,944.49 14,778.29 -2,708.83 1,858.85 2,430,839.95 316,997.67 3.00 3,283.19 End Dir : 16728.48' MD, 14944.49' TVD 1/1612019 4:09:38PM Page 7 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Beaver Creek Unit Site: Beaver Creek Unit Well: Beaver CK Unit Wellbore: Plan: BCU 4RD Design: BCU 4RD wp05b Planned Survey Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Measured Map Map Vertical Measured +EI -W Depth Inclination Azimuth Depth TVDss +N/ -S (usft) V) (^) (usft) usft (usft) 16,800.00 44.00 161.40 14,995.93 14,829.73 -2,755.91 16,887.49 44.00 161.40 15,058.87 14,892.67 -2,813.52 BC H6 1,919.01 2,430,660.28 317,055.01 0.00 3,466.35 16,900.00 44.00 161.40 15,067.87 14,901.67 -2,821.75 17,000.00 44.00 161.40 15,139.80 14,973.60 -2,887.59 17,100.00 44.00 161.40 15,211.73 15,045.53 -2,953.43 17,163.16 44.00 161.40 15,257.17 15,090.97 -2,995.01 WEST -FORELAND 2,007.63 2,430,395.59 317,139.50 0.00 3,736.17 17,200.00 44.00 161.40 15,283.67 15,117.47 -3,019.26 17,284.29 44.00 161.40 15,344.30 15,178.10 -3,074.76 17,300.00 44.00 161.40 15,355.60 15,189.40 -3,085.10 17,400.00 44.00 161.40 15,427.54 15,261.34 -3,150.94 17,434.29 44.00 161.40 15,452.20 15,286.00 -3,173.51 Total Depth : 17434.29' MD, 15452.2' TVD Targets Target Name - hitimiss target Shape Halliburton Standard Proposal Report Well Beaver CK Unit 4 BCU Planned RKB @ 166.20usft BCU Planned RKB @ 166.20usft True Minimum Curvature Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing (1) C) (usft) (usft) (usft) (usft) BCU 4RD tgtl wp04 0.00 0.00 14,138.20 -1,765.41 1,424.42 - plan misses target renter by 156.87usft at 15424.68usft MD (14234.22 TVD, -1678.03 N, 1512.45 E) - Circle (radius 500.00) BCU 4RD tgt3 wp04 0.00 0.00 15,344.30 -3,074.81 1,982.01 - plan misses target center by 0.04usft at 17284.32usft MD (15344.33 TVD, -3074.78 N, 1982.00 E) - Circle (radius 150.00) BCU 4RD tgt2 wp04 0.00 0.00 14,617.20 -2,311.80 1,725.23 - plan hits target center - Circle (radius 150.00) 2,431,790.00 2,430,472.11 2,431,239.00 Easting (usft) 316,578.10 Casing Points Map Map Measured +EI -W Northing Easting OLS Vert Section (usft) (usft) (usft) 14,829.73 (") 1,874.69 2,430,792.63 317,012.77 0.00 3,331.44 1,894.08 2,430,734.73 317,031.25 0.00 3,390.46 1,896.85 2,430,726.45 317,033.89 0.00 3,398.89 1,919.01 2,430,660.28 317,055.01 0.00 3,466.35 1,941.16 2,430,594.11 317,076.14 0.00 3,533.80 1,955.16 2,430,552.31 317,089.48 0.00 3,576.41 1,963.32 2,430,527.94 317,097.26 0.00 3,601.26 1,982.00 2,430,472.16 317,115.06 0.00 3,658.12 1,985.48 2,430,461.76 317,118.38 0.00 3,668.72 2,007.63 2,430,395.59 317,139.50 0.00 3,736.17 2,015.23 2,430,372.90 317,146.74 0.00 3,759.30 Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing (1) C) (usft) (usft) (usft) (usft) BCU 4RD tgtl wp04 0.00 0.00 14,138.20 -1,765.41 1,424.42 - plan misses target renter by 156.87usft at 15424.68usft MD (14234.22 TVD, -1678.03 N, 1512.45 E) - Circle (radius 500.00) BCU 4RD tgt3 wp04 0.00 0.00 15,344.30 -3,074.81 1,982.01 - plan misses target center by 0.04usft at 17284.32usft MD (15344.33 TVD, -3074.78 N, 1982.00 E) - Circle (radius 150.00) BCU 4RD tgt2 wp04 0.00 0.00 14,617.20 -2,311.80 1,725.23 - plan hits target center - Circle (radius 150.00) 2,431,790.00 2,430,472.11 2,431,239.00 Easting (usft) 316,578.10 Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 15,150.00 14,097.98 7" x 113/8" 7 8-3/8 17,434.29 15,452.20 41/2"x6" 4-1/2 6 12,100.01 12,016.17 95/8"TOW 9-5/8 12-1/4 317,115.07 316,870.30 1/162019 4:09:38PM Page 8 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Coordinate Reference: Well Beaver CK Unit 4 Company: Hilcorp Alaska, LLC TVD Reference: BCU Planned IRKS @ 166.20usft Project: Beaver Creek Unit MD Reference: BCU Planned RKB @ 166.20usft Site: Beaver Creek Unit North Reference: True Well: Beaver CK Unit 4 Survey Calculation Method: Minimum Curvature Wellbore: Plan: BCU 4RD Design: BCU 4RD wp05b Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology (1) (1) 14,482.60 13,948.15 TK_TVONEK_T5_10 6.71 301.99 14,394.61 13,886.61 TK_TYONEK_T5_9 6.29 302.48 16,724.13 15,102.29 BC -H5 3.17 297.81 14,859.21 14,139.93 HP -H20 -SAND 5.86 307.47 16,676.98 15,067.33 BC -H4 3.15 298.38 13,469.64 13,303.12 TK_TYONEK_T5_X1 6.84 312.27 15,142.58 14,282.78 BC_G7_A 5.33 307.94 15,369.00 14,399.87 BC_G1_D 5.09 305.90 14,170.84 13,764.05 TK_TYONEK_T5_7 6.52 304.11 17,163.16 15,340.76 WEST -FORELAND 1.46 303.35 13,565.37 13,376.56 TK_TYONEK_T5_X2 6.77 311.15 12,866.07 12,780.83 SR_TYNK_CT4 6.46 311.10 16,589.53 15,025.59 BC_113 3.45 302.42 14,807.45 14,112.55 TOP_TYONEK_G 5.92 308.92 13,869.13 13,593.58 TK_TYONEK_T5_4 6.89 305.83 13,832.23 13,569.57 TK_TYONEK_T5_3 6.89 306.38 16,513.75 14,972.00 BC -H2 3.61 295.96 16,278.07 14,862.01 HEMLOCK 4.29 299.38 16,207.81 14,806.35 BC_G2_D 4.01 297.58 14,253.36 13,814.80 TK_TYONEK_T5_8 6.65 303.15 13,707.92 13,481.69 TK_TYONEK_T5_1 6.79 309.37 15,544.45 14,490.86 BC_G1_E 4.92 305.63 14,568.36 13,994.95 TK_TYONEK_T5_11 6.63 301.26 12,979.89 12,889.57 TK_TYONEK_T4_5 6.89 310.72 13,961.40 13,651.10 TK_TYONEK_T5_5 6.92 305.43 14,654.04 14,047.74 TK_TYONEK_T5_12 6.75 301.66 16,182.73 14,791.47 BC_G2_C 4.02 296.51 13,372.91 13,222.23 TK_TYONEK_T5_X 6.39 310.60 13,624.70 13,420.10 TK_TYONEK_T5 6.61 308.77 16,400.93 14,918.40 BC -HI 3.95 298.09 16,029.09 14,726.14 BC_G2_B 4.30 300.61 14,754.84 14,100.88 TK_TYONEK_T5_13 6.63 299.70 11,935.54 11,884.15 TK_TYONEK_T4_4 7.67 307.44 15,255.78 14,344.66 BC -GI -C 5.29 307.12 16,887.49 15,185.83 BC -H6 2.41 298.85 15,751.06 14,600.75 BC_G2_A 4.85 303.57 14,081.33 13,710.33 TK_TYONEK_T5_6 6.43 304.83 15,212.94 14,323.64 BC_G1_B 5.35 309.01 13,064.20 12,966.01 SR_E10MKT 6.58 307.82 12,210.38 12,150.82 SR_TYNK_CT7 7.58 311.41 15,665.41 14,556.85 BC -GI -F 4.89 305.54 13,777.00 13,528.18 TK_TYONEK_T5_2 6.66 307.38 12,464.33 12,400.00 L_E_TNK 7.34 312.00 1/16/2019 4.*09:38PM Page 9 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Beaver Creek Unit Site: Beaver Creek Unit Well: Beaver CK Unit 4 Wellbore: Plan: BCU 4RD Design: BCU 4RD wp05b Plan Annotations Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) 12,100.00 12,016.16 343.90 556.11 12,113.33 12,029.03 343.89 559.56 12,133.33 12,048.29 343.66 564.96 13,995.02 13,525.10 -501.08 1,117.64 15,986.22 14,512.75 -2,140.30 1,667.52 15,995.15 14,517.20 -2,147.64 1,669.99 16,195.15 14,617.20 -2,311.80 1,725.23 16,728.48 14,944.49 -2,708.83 1,858.85 17,434.29 15,452.20 -3,173.51 2,015.23 Halliburton Standard Proposal Report Well Beaver CK Unit 4 BCU Planned IRKS @ 166.20usft BCU Planned IRKS @ 166.20usft True Minimum Curvature Comment KOP : Start Dir 12.75'/100'. 12100' MD, 12016.16'TVD : 45° RT TF End Dir : 12113.33' MD, 12029.03' TVD Start Dir 3°/100' : 12133.33' MD, 12048.29'TVD End Dir : 13995.02' MD, 13525.09' TVD Start Dir 3-/100': 15986.22' MD, 14512.75'TVD End Dir : 15995.15' MD, 14517.2' TVD Start Dir 3-1100': 16195.15' MD, 14617.2'TVD End Dir : 16728.48' MD, 14944.49' TVD Total Depth: 17434.29' MD, 15452.2' TVD 1/16/2019 4:09:38PM Page 10 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Beaver Creek Unit Beaver Creek Unit Beaver CK Unit 4 Plan: BCU 4RD 501332023900 BCU 4RD wp05b Sperry Drilling Services Clearance Summary Anticollision Report 16 January, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: Beaver Creek Unit - Beaver CK Unit 4 - Plan: BCU 4RD - BCU 4RD wp65b Well Coordinates: 2,433,577.41 N, 315,181.61 E (60° 39' 25.81"N, 151° 01' 48.49" W) Datum Height: BCU Planned RKB @ 166.20usft Scan Range: 12,100.00 to 17,434.29 usft. Measured Depth. Scan Radius Is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 2,500.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Beaver CK Unit 4 - BCU 4RD wp05b Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: Beaver Creek Unit - Beaver CK Unit 4 - Plan: BCU 4RD - BCU 4RD wp05b Scan Range: 12,100.00 to 17,434.29 usft. Measured Depth. Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 2,500.00 usft Site Name Comparison Well Name -Wellbore Name -Design Beaver Creek Unit Beaver CK Unit 4 - BCU 04 - BCU 04 Beaver CK Unit 4 - BCU 04PB2 - BCU 04PB2 Ew-me, . .. Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Depth Distance Depth Separation Depth Factor Minimum (usft) (usft) (usft) (usft) usft 12,400.00 24.40 12,400.00 20.38 12,396.45 6.070 Clearance Factor 12,400.00 24.40 12,400.00 20.38 12,396.45 6.070 Clearance Factor From To (usft) (usft) 202.20 2,802.20 3,187.20 8,587.20 8,767.20 12,100.00 12,100.00 12,500.00 BCU 4RD wp05b 12,500.00 15,150.00 BCU 4RD wp05b 15,150.00 17,434.29 BCU 4RD wp05b Survey/Plan Survey Tool 2_CB-Film-GMS 2 CB -Film -MMS 2 CB -Film -MSS 2_MWD Interp Azi+Sag 2_MWD+IFRI+MS+Sag 2_MWD+IFRI+MS+Sag Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Hilcorp Alaska, LLC Beaver Creek Unit Separation Warning Pass - Pass - 16 January, 2019 - 16:06 Page 2 of 4 COMPASS HALLIBURTON REFERENCE INFORMATION Project: Beaver Creek Unit WELL DETAILS: Beaver CK Unit 4 NAD 1927(NADCON CONUS) Alaska Zonis 04 CaaNinele(WE) Reference: We119eaver CN Unit ue 14, RNotlh Site: Beaver Creek Unit Gmund Lsvel: 148.20 Bpemy DHIIIn, Verlinel nVl Rerererce: BCU Planned RKB 16620wK Well: Beaver CK Unit Measured Cul Reaal BCU PIanretl RKB®166.20wK +N1 -S +Fl -W Nodhing lasting Lslituode Longitudc Wellbore: Plan: BCU 4RD Calculaticn Wa l Minimum Curvature 0.00 0.00 243397.41 315181.61 60°39'25.809N 151°1'48.489W Plan: BCU 4RD Wp056 GLOBAL FILTER APPLIED: Al wellpaths within 200'+ 100/1000 of reference FTM SURVEY PROGRAM 12100.00 To 17434.29 Date: 2018-02-14700:00:00 Valitlatetl: Yes Version: CASING DETAILS Depth Foam Depth To Sulvey/Plan Tool TVD TVOSS MD Sizc Name 202.20 2802.20 BCU -04P!31 GMS (BCU 04PB1) 2_CB-Film-GMS 12016.17 11849.97 12100.01 9-5/8 9 98" TOW 3187.20 8587.20 BCU-04PB1 CB -MMS (BCU 04PB7) 2_CB-Film-MMS 14097.98 13931.78 15150.00 7 7" x 8 3/8" 8767.20 12100.00 BCU-04PB2 CS -MSS (BCU 04PB2) 2_CB-FIlm-M5S Ladder/S.F. Plots 2100.00 1250000 BCU 4RD wp05b(Plan: BCU 4RD) 2_MWD _Inlerp Av+Sag 15452.20 15286.00 17434.29 4-1/2 41/2"x 6" 12500.00 15150.00 BCU 4RD wp05b(Plan BCU 4RD) 2_MWD+IFRI+MS+Seg 15150.00 17434.29 BCU 4RD wp05b(PIan: BCU 4RD) 2_MWD+IFRI+MS+Sag 200.00 ____ _ ..._._ .._ - ___-, 0C,160.00--- PB2 w C BCU 04 azo.00 m N 80.00 c U 40.00 - -- -- -------------- ----- -------a - m 1 U 0.00 12300 12600 12900 13200 13500 13600 14100 14400 14700 15000 15300 15600 15900 16200 16500 16800 17100 17400 17700 Measured Depth (600 usfUln) 5 0 3.00 O 2 2.00 o. Collision Risk Procedures Req. rn Collision Avoidance Req. 1.00 No -Go Zone - Stop Drilling 0.00- 12300 1260D 12900 13200 13500 13800 14100 14400 14700 15000 15300 15600 15900 16200 16500 16800 17100 17400 17700 Measured Depth (600 usft/in) HALLIBURTON Anticollision Report for Beaver CK Unit 4 - BCU 4RD wp05b Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to BCU Planned RKB @ 166.20usft. Northing and Easting are relative to Beaver CK Unit 4. Coordinate System is US State Plane 1927 (Exact solution), Alaska Zone 04. Central Meridian is -150.00°, Grid Convergence at Surface is: -0.90 °. rn 1350 - CD LO a C: 0 Y 900- a) J. Ladder Plot I I I I I I I I I I 1 I I I I I I I I I I I I I I I I I I _1 _1 _J_J _ J _J I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I 3000 6000 9000 12000 15000 Measured Depth (3000 usfVin) Hilcorp Alaska, LLC Beaver Creek Unit LEGEND $ BeaverCK Unit12,BCU-12, BCU 12VO $ BeavarCKUnit12,BCL-12A,BCLL12AV0 —} BeaverCK Unit4,BCU04,BCU04V0 —*- BeaverCK Unft4,B0004PB1,BCU04PB1 V0 $ BeaverCK Unft4,B0004PB2,BCU04PB2V0 $ BCU4RDwp05b 16 January, 2019 - 16:06 Page 3 of 4 COMPASS Transform Points Source coordinate system State Plane 1927 -Alaska Zone 4 Datum: NAD 1927 - North Amenca Datum of 1927 (Mean) 0 Target coordinate system Albers Equal Area 1-159) Datum: NAD 1927 - North America Datum of 1927 [Mean) L7>t pj Easting Nortt L! ""i 1 -56124.5 . 1186239.5 4 12 � BGS-D�f-RD Type values into the spreadsheet or copy and paste columns of data from a spreadsheet using the keyboard shortcuts Ctd+C to copy and Ctd+V to paste. Then click on the appropnate amow button to transform the points to the desired coordinate system. < Back Finish Cancel Help From: Cody Dinaer To: Boyer, David L (DOA); Davies. Stephen F (DOA) Cc: Monty Myers Subject: BCU-04RD and MPU M-11 Directional Plans Date: Friday, January 25, 2019 7:20:24 AM Attachments: BCU 4RD wo05b GIS.txt BCU 4RD wo05b.bt M-11 wo08 GIS.txt M-11 w008.txt Gentlemen, Attached are the directional plans for BCU-04RD(permit to drill submitted yesterday) and MPU M-11 (anticipated submittal of this early afternoon). Let Monty or I know if you need any additional information. Thanks! Cody Dinger Hilcorp Alaska, LLC Drilling Technician cdin2er(@hilcoriD.com Direct: 907-777-8389 Schwartz, Guy L (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Tuesday, February 5, 2019 7:33 AM To: Schwartz, Guy L (DOA) Subject: RE: BCU 04RD (PTD 219-011) Attachments: BCU 04RD Drilling Program (rev 1).pdf Good morning Guy, Thank you for the email. Please see responses below and the attached updated drilling program Monty M Myers Drilling Manager 907.538.1168 (c) 907.777.8431 (a) From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.gov] Sent: Monday, February 4, 2019 3:22 PM To: Monty Myers <mmyers@hilcorp.com> Subject: [EXTERNAL] BCU 04RD (PTD 219-011) Monty, Some issues with the PTD came up: 1. Decided on 4000psi BOPE test pressure. I did allow the 1/3 gas cap for calc. -Will update the drilling program to show this 2. The 7" casing rams can be tested t 3000 psi -Will update this also 3. There is no mention of changing rams to 7" and testing in the procedure. -Added a bullet point in 14.15 4. There is not FIT in the procedure for the 7" shoe drillout. - Added this in as section 17.12-17.15 S. You are proposing at 3500 psi casing test once the 4.5 "liner is cemented on age 37 (20.3) This will also put 9 5/8" casing at same pressure . Are you Ok with that? �$° - Good observation, would like to lower this value to 2000 psi, due to the age of the 9-5/8" 6. Are the tension safety factors for the 7" and 4.5" liner correct? Page 48 - No I had the weight of the 7" as 26#. Updated it to 29# Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended TRANSMITTAL LETTER CHECKLIST WELL NAME: B G U- — D 4- RD PTD: a — O (/Development _ Service Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: 6 e,aLAE / G Ile�e POOL: f3 p_,�5tVe,(— Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- (If last two digits _- Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(1), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50-_ from records, data and logs acquired for well name on peimit . The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. 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 ✓ (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements 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. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool BEAVER CREEK, BEAVER CREEK OIL - 80100 PTD#:2190110 Company HILCORP ALASKA LLC Initial Class/Type Well Name: BEAVER CK UbJ1104-RD - _ _ Program DEV Well bore seg ❑ DEV/PEND GeoArea 820 Unit 50212 On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached - - - - - - --- - - - - - - - - - - --- - - - - - -- - - - - - - -- NA. 2 Lease numberappropriate --------------------------------------Yes. .....-------------------------------......----...---....----------- 3 Unique well. name and number _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ Yes ---------------------------------------- 4 Well located in a-defined pool . . ..... . . . . . . ....... . . . . . ... . . . . . .... Yes - ------------------ ---- - 5 Well located proper distance from drilling unit boundary- -- - - - - - - - --- - - - - - - - - Yes 6 Well located proper distance from other wells _ _ _ _ _ _ . _ _ _ _ _ . - _ _ Yes 7 Sufficient acreage available in drilling unit_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 8 If deviated, is wellbore plat included _ _ _ ... _ _ _ _ _ _ _ _ _ Yes - 9 Operator only affected party.. - - _ - - _ .. _ - _ _ - ..... - _ _ - - Yes 10 Operator has appropriate bond in force _ .. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .... _ _ _ Yes 11 Permit can be issued without conservafien order_ - _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes Appr Date 12 Permit. can be issued without administrativeapproval. - _ - _ - _ ... _ _ _ - Yes _ DLB 1/28/2019 13 Can permit be approved before 15-day wait _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 14 Well located within area and. strata authorized by Injection Order # (put 10# in.comments). (For NA 15 All wellswithin1/4. mile area of review identified (For service well only)- .. _ NA - - - 16 Pre-produced injector: duration of pre-production Iess than 3 months (For service well only) _ NA 17 Nonconven,gas.conforms to AS31,05,030(L 1.A),(j2.A-D) _ ...... _ _ - - - _ _ . NA 18 Conductor stdng_provided _ _ _ _ ______ _ _ _ _ _ _ _ _ ___ _ _ _ _ _ .. _ _ - NA_ - - _ ... Sidetraoking.existing well BCU -04_ Engineering 19 Surface casingprotects all known USDWs _ _ ..NA - Surface casing set and cemented._ 20 CMT vol adequate to circulate on conductor & surfcsg _ _ _ _ _ _ _ ______ _ _ _ _ _ _ _ _ _ _ _ NA .. - - windowin 9 5/8" rasing planned at 12100 ft. MD. 21 CMT vol adequate to tie-in long string to surf csg_ _ _ _ _ _ _ _ _ _ _ _ _ ______ _ _ _ _ _ NA 22 CMT. will coverall known productive horizons. . . . . . . .. . .... . . . . .. . . . . .... Yes- 23 Casing designs adequate for C.T B &_permafrost ... . . . . ..... . . _ ... _ _ _ Yes _ - BTC calos supplied.. Running 7" and 4,5" liner sections_ 24 Adequate tankage or reserve pit - - _ ....... _ _ _ _ _ _ Yes _ Rig has steel pits — All waste will be transported to. KGF G & 1. . 25 If a-re-drill, has 10403 for abandonment been approved _ _ _ _ _ _ _ _ _ _ Yes _ _ Sundry 319-013 _ _ _ 26 Adequate wellbore separation proposed. _ _ _ _ _ _ _ _ _ _ _ .... _ _ . Yes 27 If diverter required, does it meet regulations _ _ _ .... _ _ _ _ _ ... _ _ _ _ _ _ .. NA_ - _ - . _ - BOPE will be used..._wellhead is in place. Appr Date 28 Drilling fluidprogramschematic & equip list adequate_ _ _ _ _ _ _ _ _ _ _ ..... _ _ _ Yes _ _ _ _ Using MPD to manage Tyonek Water flow zone, GLS 2/5/2019 29 BOPEs, do they meet regulation - - _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ Rig 169 has 11"5000 psi SOPE.. 30 BOPE press rating appropriate; fest to (put psig in comments). . . . . .. . ... . . . . Yes _ _ MASP 2700 psi... (1/3 gas column) Testing BOPE to 4000 psi 31 Chokemanifoldcomplies w/API RP-53 (May 84).... _ . _ _ _ _ - - - - - _ _ Yes 32 Work will occur without operation shutdown_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes Sundryto Perf and run. tubing is required... 33 Is presence of H2S gas probable _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 1-12S not expected but dg will use 1-12S monitoring system.. 34 Mechanical condition of wells within AOR verified (For service well only) _ _ - - - - - _ _ _ .. NA 35 Permit can be issued w/o hydrogen sulfide measures . . . .... . . . . . ..... . . . . . .. Yes _ 1-12S not recorded in nearby-wells. Geology 36 Datapresentedon. potential overpressure zones . ........ . . . . . - - - - _ .... _ Yes _ _ _ _ - - - 1-12S not recorded mud. logs from nearby wells, - Appr Date 37 Seismic analysis_of shallow gas zones _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ ____ _ _ _ _ _ _ _ - - NA.... _ - High-pressure water sands will be encountered below KOP for this. wellbore. Anticipated pressure is DLB 1/28/2019 38 Seabed condition survey (if off-shore) _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ ____ _ NA _ ... _ _ _ 8318 psi.. 39 Contact name/phone for weekly_ progress reports (exploratory only) ___ _ _ _ _ _ _ _ _ _ _ _ NA.. Geologic Engineering Public Using MPD to drill Tyonek High pressure water zones. GIs. Commissioner: Date: /C/o issioner, Q DateCommissioner Date