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Home My WebLink About217-047Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/02/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251002 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 11A 50133205210100 224123 9/23/2025 YELLOWJACKET PERF T40937 BCU 13 50133205250000 203138 8/18/2025 YELLOWJACKET GPT-PERF T40938 BCU 13 50133205250000 203138 8/26/2025 YELLOWJACKET GPT-PERF T49038 BCU 13 50133205250000 203138 8/21/2025 YELLOWJACKET GPT-PLUG T40938 BCU 23 50133206350000 214093 9/10/2025 YELLOWJACKET PERF T40939 BCU 24 50133206390000 214112 9/16/2025 YELLOWJACKET PLUG-PERF T40940 BRU 212-35T 50283200970000 198161 9/18/2025 AK E-LINE Perf T40941 BRU 224-34T 50283202050000 225044 7/29/2025 AK E-LINE CBP/Punch T40942 BRU 224-34T 50133207170000 225044 9/19/2025 AK E-LINE GPT/Perf T40942 END 1-05 50029216050000 186106 9/25/2025 YELLOWJACKET IPROF T40943 END 2-08 50029217710000 188004 8/11/2025 YELLOWJACKET PERF T40944 END 4-50 50029219400000 189044 9/8/2025 YELLOWJACKET P-PROF T40945 KBU 11-08Z 50133206290000 214044 9/15/2025 AK E-LINE Perf T40946 KU 33-08 50133207180000 224008 7/1/2025 YELLOWJACKET PERF T40947 KU 41-08 50133207170000 224005 8/28/2025 YELLOWJACKET PERF T40948 KU 41-08 50883201990100 224005 9/16/2025 AK E-LINE Perf T40948 MPU R-108 50029238210000 225062 8/14/2025 YELLOWJACKET SCBL T40949 MRU K-06RD2 50733200880200 216131 9/12/2025 AK E-LINE CBL T40950 MRU M-01 50733203880000 187046 9/20/2025 AK E-LINE Perf T40951 MRU M-25 50733203910000 187086 9/21/2025 AK E-LINE Perf T40952 NCIU A-21A 50883201990100 225075 8/21/2025 AK E-LINE CBL T40953 NFU 14-25 50231200350000 210111 9/3/2025 YELLOWJACKET PERF T40954 PBU PTM P1-08A 50029223840100 202199 9/13/2025 YELLOWJACKET SCBL T40955 PBU W-35A 50029217990200 225076 9/17/2025 YELLOWJACKET SCBL T40956 SRU 241-33 50133206630000 217047 9/17/2025 AK E-LINE Perf T40957 SRU 32A-33 50133101640100 191014 9/23/2025 AK E-LINE Perf T40958 SRU 32A-33 50133101640100 191014 9/21/2025 AK E-LINE Perf T40958 Please include current contact information if different from above. SRU 241-33 50133206630000 217047 9/17/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.03 09:00:56 -08'00' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________SWANSON RIV UNIT 241-33 JBR 10/31/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 Test with 1-3/4" Coil. Accumulator bottle precharge Avg. 1200 psi. Had issues with the digital and graph bouncing around 30psi high and 15 psi low. Had to switch to crystal gauge for the test. They will be figuring it all out with their software and wires. Looked to be how things were talking to each other in the software. Test Results TEST DATA Rig Rep:Eli WilsonOperator:Hilcorp Alaska, LLC Operator Rep:Jeremy Hart Rig Owner/Rig No.:Fox 1 PTD#:2170470 DATE:9/11/2025 Type Operation:WRKOV Annular: Type Test:INIT Valves: 250/2500 Rams: 250/2500 Test Pressures:Inspection No:bopKPS250911231852 Inspector Kam StJohn Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 3.5 MASP: 1722 Sundry No: 325-282 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 0 NA Lower Kelly 0 NA Ball Type 0 NA Inside BOP 0 NA FSV Misc 0 NA 5 PNo. Valves 2 PManual Chokes 0 NAHydraulic Chokes 0 NACH Misc Stripper 1 1-3/4"P Annular Preventer 0 NA #1 Rams 1 Blind/Shears P #2 Rams 1 1-3/4" Pipe Sl P #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 2 2"P HCR Valves 0 NA Kill Line Valves 2 2"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3028 Pressure After Closure P2600 200 PSI Attained P4 Full Pressure Attained P54 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)NA0 ACC Misc NA0 NA NATrip Tank NA NAPit Level Indicators NA NAFlow Indicator NA NAMeth Gas Detector NA NAH2S Gas Detector NA NAMS Misc Inside Reel Valves 1 P Annular Preventer NA0 #1 Rams P12 #2 Rams P12 #3 Rams NA0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke NA0 HCR Kill NA0       Rig Inspection Report attached 2025-0911_Rig_Fox_CTU1_SRU_241-33_ksj Page 1 of 4 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: 09/11/2025 P. I. Supervisor FROM: Kam StJohn SUBJECT: Service CTU Inspection – Fox CTU1 Petroleum Inspector SRU 241-33 Hilcorp Alaska LLC PTD 2170470; Sundry 325-282 09/11/2025: Traveled to Swanson River Unit 241-33 to witness a BOPE test and inspect the new service coil tubing unit Fox Energy CTU #1. The weather was terrible, but the unit looked in good working order. Everything was rigged up properly, and as organized as a CTU can be. Visually inspected all aspects of the CTU; it is very similar to Fox CTU #10 other than the operations cab is more updated and all digital. The accumulator meets regulation – 4 accumulator bottles with a current pre-charge average pressure of 1200 psi and the correct volume of fluid for the system. The only issue during the BOP test was their wellhead cable or software for such display was very erratic. It would bounce 30 psi on a high test and 15 psi on a low test. Due to this they had to line up a crystal digital gauge to do the BOP test. It was only on the well head display that we had this chatter on the digital graph, and they will trouble shoot to figure out if it is software or the cable thru the unit connecting this together. The Fox CTU #1 is a good looking unit. Attachments: Photos (6)      2025-0911_Rig_Fox_CTU1_SRU_241-33_ksj Page 2 of 4 Fox CTU #1 – New Service Coil Tubing Unit Photos by AOGCC Inspector K. StJohn 9/11/2025 Fox CTU #1 Over SRU 241-33 Fox CTU #1 2025-0911_Rig_Fox_CTU1_SRU_241-33_ksj Page 3 of 4 Fox CTU #1 Operator Cab and Coil Reel Fox CTU #1 Injector Head 2025-0911_Rig_Fox_CTU1_SRU_241-33_ksj Page 4 of 4 Fox CTU #1 Pump Unit Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 08/26/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250826 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 24 50133206390000 214112 7/15/2025 AK E-LINE PPROF T40803 BR 11-86 50733207370000 225057 7/30/2025 AK E-LINE Hoist T40804 BR 11-86 50733207370000 225057 8/4/2025 AK E-LINE Perf T40804 BR 11-86 50733207370000 225057 8/9/2025 AK E-LINE Perf T40804 BRU 212-35T 50283200970000 198161 8/4/2025 AK E-LINE Perf T40805 BRU 212-35T 50283200970000 198161 6/28/2025 AK E-LINE Perf T40805 BRU 224-34T 50283202050000 225044 8/2/2025 AK E-LINE CBL T40806 BRU 224-34T 50283202050000 225044 8/5/2025 AK E-LINE CBL T40806 BRU 224-34T 50283202050000 225044 7/27/2025 AK E-LINE CBL T40806 BRU 224-34T 50283202050000 225044 8/2/2025 AK E-LINE Punch T40806 KTU 43-6XRD2 50133203280200 205117 7/26/2025 AK E-LINE Perf T40807 MPL-13A 50029223350100 223017 8/10/2025 READ CaliperSurvey T40808 NCIU A-21 50883201990000 224086 1/14/2025 AK E-LINE Plug/Perf T40809 ODSN-16 50703206200000 210053 8/10/2025 READ CaliperSurvey T40810 PBU 01-30A 50029216060100 225050 8/7/2025 HALLIBURTON RBT-COILFLAG T40811 PBU 06-11A 50029204280100 225042 7/13/2025 HALLIBURTON RBT-COILFLAG T40812 PBU 11-37A 50029227160100 219062 7/27/2025 HALLIBURTON RBT T40813 PBU 14-43A 50029222960100 225041 7/31/2025 HALLIBURTON RBT-COILFLAG T40814 PBU F-06B 50029200970200 225054 8/5/2025 HALLIBURTON RBT-COILFLAG T40815 PBU L1-10A 50029213400100 225032 8/1/2025 HALLIBURTON RBT-COILFLAG T40816 PCU 02A 50283200220100 224110 7/27/2025 AK E-LINE Perf T40817 SRU 241-33 50133206630000 217047 7/28/2025 AK E-LINE Perf T40818 WhiskeyGulch 1 50231200790000 221046 6/18/2025 AK E-LINE Packer T40819 Please include current contact information if different from above. T40818SRU 241-33 50133206630000 217047 7/28/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.27 08:12:23 -08'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 8,630'N/A Casing Collapse Structural Conductor Surface 5,410 psi Intermediate Production 7,500 psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng ryan.lemay@hilcorp.com 661-487-0871 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Ryan LeMay, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028399 / FEDA028406 217-047 50-133-20663-00-00 Hilcorp Alaska, LLC Proposed Pools: 6.4# / L-80 TVD Burst 2538' 8,430 psi 1,986' Size 120' 2,005' MD See Attached Schematic 7,240 psi 120'120' 2,005' May 19, 2025 2-7/8" 8,625' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Swanson River Unit (SRU) 241-33CO 716A Same 7,672'4-1/2" ~1722psi 8,625' See Schematic Length D&L, Halliburton, Tri-Pt Pkrs & N/A 2,493'; 6,660'; 8,565' MD / 2,414'; 5,493'; 7,613' TVD & N/A 7,677'5,915'5,073' Swanson River Beluga Gas 16" 7" See Attached Schematic m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.05.06 16:19:24 - 08'00' Noel Nocas (4361) 325-282 By Grace Christianson at 8:47 am, May 07, 2025 DSR-5/8/25A.Dewhurst 13MAY25 10-404 BJM 5/13/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.15 10:43:40 -08'00'05/15/25 RBDMS JSB 051625 Well Prognosis Well: SRU 241-33 Well Name: SRU 241-33 API Number: 50-133-20663-00-00 Current Status: Producing Gas Well Permit to Drill Number: 217-047 Regulatory Contact: Donna Ambruz (907) 777-8305 First Call Engineer: Ryan LeMay (661)487-0871 (M) Second Call Engineer: Scott Warner (907) 830-8863 (M) (907) 564-4506 (O) Maximum Expected BHP: 2228 psi @ 5062’ TVD Based on 0.44 psi/ft Max. Potential Surface Pressure: 1722 psi Based on 0.1 psi/ft gas gradient to surface Applicable Frac Gradient: 0.65 psi/ft using 12.5 ppg EMW FIT at the 7” casing shoe Shallowest Allowable Perf TVD: MPSP/(0.65-0.1) = 1722 psi / 0.55 = 3131‘ TVD Top of Applicable Gas Pool / PA 5345’ MD / 4621’ TVD (Beluga) Well Status: Online Gas Producer flowing at 521 mcfd, 0 bwpd, 634 psi FTP (As of 5/1/25) Brief Well Summary In August 2022, open perforations in sands LB 51-3 – Bel_UB_52-9 were isolated and perforations were added to LB_51-0 zone with an initial gas production rate of ~2 mmcfd. From August 2022 to August 2024, the well produced from the LB_51-0 sand with gradual decline. In August 2024 additional perforations were added in the LB_51-2 – LB_51-1 sands with an initial production of ~1 mmcfd. As of 5/1/2025, production has declined to 521 mcfd / 634 FTP. The purpose of this Sundry is to add additional perforations in the MB_49-5 – LB_51-1 sands. Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low / 2,500 psi high 3. RIH and perforate MB_49-5 – LB_51-1 from bottom up. Below are proposed targeted sands in order of testing (bottom/up), but additional sand may be added depending on results of these perfs, between the proposed top and bottom perfs Well Sand MD top MD Bottom TVD TVD Interval SRU_241-33 MB_49-5 +5,348’ +5,358’ +4,624’ +4,632’ +10’ SRU_241-33 LB_50-7 +5,518’ +5,528’ +4,753’ +4,761’ +10’ SRU_241-33 LB_50-7 +5,551’ +5,557’ +4,779’ +4,783’ +6’ SRU_241-33 LB_50-9 +5,615’ +5,625’ +4,829’ +4,839’ +10’ SRU_241-33 LB_50-9 +5,718’ +5,727’ +4,911’ +4,918’ +9’ SRU_241-33 LB_51-1 +5,816’ +5,822’ +4,992’ +4,996’ +6’ a. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation b. Use Gamma/CCL to correlate Well Prognosis Well: SRU 241-33 c. Record Tubing pressures before and after each perforating run at 5 min, 10 min, and 15 min intervals post perf shot (if using switched guns, wait 10 min between shots) d. Pending well production, all perf intervals may not be completed e. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations i. Note: A CIBP may be used instead of WRP if it is determined that no cement is needed for operational purposes. 35ft will not be placed on each plug as these zones are close together. If possible, the CIBP will be set 50’ above of the top of the last perforated sand unless zones are too close together in which case the plug will be set within 50’. f. If necessary, use high pressure pad gas or N2 to pressure up well during perforating or to depress water prior to setting a plug above perforations. 4. RDMO Contingency Procedure: Coiled Tubing Cleanout 1. If throughout the job any current or proposed zones produce sand and / or water that cannot be depressed and pushed away with nitrogen or high-pressure pad gas, a coil tubing unit may be rigged up to clean out fill or fluid blown down as necessary. a. MIRU Fox CTU, PT BOPE to 250 psi low / 2500 psi high i. Provide AOGCC 24hrs notice of BOP test. b. Cleanout wellbore fill and / or blowdown well with nitrogen if necessary. Attachments: 1. Current Schematic 2. Proposed Schematic 3. Standard Well Procedure – N2 Operations 4. Coil Tubing BOP Diagram Updated by RPL 05-02-25 SCHEMATIC Well SRU #241-33 PTD: 217-047 API: 50-133-20663-00-00 PBTD = 5,915’ MD / 5,073’ TVD TD = 8,630’ MD / 7,677’ TVD RKB to GL = 11’ 1 2 3 14 13 12 11 10 9 8 5 6 7 4 3a OPEN HOLE / CEMENT DETAIL 7"8-1/2” hole: Pumped 88bbls 12.0ppg Type I/II lead cement followed by 22bbls 15.4ppg class G tail cement. – 23 BBLs Cement to Surface 4-1/2” 6-1/8” hole: Pumped 166 bbls 12.8ppg Type I/II lead cement followed by 27bbls 15.3ppg class G tail cement – 13bbls back to surface. 8/3/17 CBL showed ToC at 1440’ MD after 4 days of cement cure. 10/22/20 CBL confirms ToC at surface. 16” 7” 4-1/2” CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120' 7"Surf Csg 26 L-80 BTC/M 6.875”Surf 2,005’ 4-1/2"Prod Csg 12.6 L-80 TXP 3.958”Surf 8,625‘ TUBING DETAIL 2-7/8”Production 6.4 L-80 FJ3 2.375”Surf 2,538’ RA @ 6,006’ RA @ 8,415’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Pool Date Status LB_51-1 5,852’5,858’5,020’5,025’6 Beluga 8/23/24 Open LB_51-1 5,868’5,873’5,034’5,038’5 Beluga 8/23/24 Open LB_51-2 5,887’5,891’5,050’5,053’4 Beluga 8/23/24 Open LB 51-0 5,898’5,902’5,059’5,062’4 Beluga 8/28/22 Open LB 51-3 5,936’5,939’5,090’5,092’3’Beluga 6/13/22 Isolated 8/28/22 LB 51-3 5,965’5,968’5,115’5,118’3’Beluga 6/13/22 Isolated 8/28/22 LB 51-7 6,114’6,121’5,244’5,250’7’Beluga 9/28/21 Isolated 8/28/22 LB 51-7 6,123’6,126’5,252’5,254’3’Beluga 6/13/22 Isolated 8/28/22 LB 52-9 Middle 6,171’6,175’5,294’5,298’4’Beluga 9/28/21 Isolated 8/28/22 LB 52-9 6,185’6,188’5,306’5,308’3'Beluga 6/13/22 Isolated 8/28/22 BEL_UB_52-9 6,195’6,205’5,315’5,325’10’Beluga 8/15/20 Isolated 8/28/22 56-9 6,658'6,678'5,541'5,560'20’Tyonek 12/22/17 Isolated 6,684'6,696'5,765'5,777'12’Tyonek 12/22/17 Isolated 6,715’6,730’5,795’5,809’15’Tyonek 12/18/17 Isolated 65-5 7,527’7,547’6,585’6,605’20’Tyonek 12/10/17 Isolated 7,528’7,533’6,586’6,591’5’Tyonek 11/30/17 Isolated 68-0 68-0 68-3 68-3 7,770’7,775’6,826'6,830’5’Tyonek 11/29/17 Isolated 7,770’7,775’6,826'6,830’5’Tyonek 11/11/17 Isolated 7,812’7,817’6,867'6,872’5’Tyonek 10/28/17 Isolated 7,845’7,860’6,900’6,914’15’Tyonek 10/16/17 Isolated 73-5 8,355’8,375’7,404’7,424’20’Tyonek 9/28/17 Isolated 75-7 8,538’8,558’7,586’7,606’20’Tyonek 9/19/17 Isolated 77-3 8,585’8,595'7,632’7,642’10’Tyonek 9/18/17 Isolated JEWELRY DETAIL No.Depth ID OD Item 1 2,493’4-1/2” x 2-7/8” Dual Bore Perm Pkr (D&L) (7/27/20) 2 2,506’2-7/8” X-Nipple (7/27/20) 3 2,539’2-7/8” WLEG (7/27/20) 3a 5,930’4-1/2” CIBP w/ 15’ cement; ToC @ 5,915’ (8/28/22) 4 6,271’4-1/2” CIBP w/ 44’ of cement- TOC 6,227’ (8/4/20) 5 6,600’2.33”3.79”4-1/2” Halliburton TWR Perma Series Packer 6 6,610’2.313”2-7/8” X-Nipple 7 6,620’2.441”2-7/8” WLEG 8 6,710’CIBP (12/22/17) 9 7,520’CIBP w/ 35’ of cement: ToC at 7485’ (12/21/17) 10 7,760’CIBP w/ 36’ fill & 35’ cement: ToC at 7589’ (11/30/17) 11 7,795’CIBP w / 15’ cement: ToC at 7780’ (11/02/17) 12 7,838’CIBP w/ 21’ cement: ToC at 7817’ (10/28/17) 13 8,168’CIBP w/ 35’ of cmt; 55’ total: ToC at 8113’ (10/26/17) 14 8,565’1.875”3,75”Tri-Pt Model D Isolation Pkr 08/28/17 X X Fish: 6,334’ – 24.5’ E-Line toolstring + 21’ slickline toolstring 7/25/20 RA @ 2817’ RA @ 3800’ Updated by RPL 05-02-25 PROPOSED Well SRU #241-33 PTD: 217-047 API: 50-133-20663-00-00 PBTD = 5,915’ MD / 5,073’ TVD TD = 8,630’ MD / 7,677’ TVD RKB to GL = 11’ 1 2 3 14 13 12 11 10 9 8 5 6 7 4 3a OPEN HOLE / CEMENT DETAIL 7"8-1/2” hole: Pumped 88bbls 12.0ppg Type I/II lead cement followed by 22bbls 15.4ppg class G tail cement. – 23 BBLs Cement to Surface 4-1/2” 6-1/8” hole: Pumped 166 bbls 12.8ppg Type I/II lead cement followed by 27bbls 15.3ppg class G tail cement – 13bbls back to surface. 8/3/17 CBL showed ToC at 1440’ MD after 4 days of cement cure. 10/22/20 CBL confirms ToC at surface. 16” 7” 4-1/2” CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120' 7"Surf Csg 26 L-80 BTC/M 6.875”Surf 2,005’ 4-1/2"Prod Csg 12.6 L-80 TXP 3.958”Surf 8,625‘ TUBING DETAIL 2-7/8”Production 6.4 L-80 FJ3 2.375”Surf 2,538’ RA @ 6,006’ RA @ 8,415’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Pool Date Status MB_49-5 5,348’5,358’4,624’4,632’10’Beluga Proposed LB_50-7 5,518’5,528’4,753’4,761’10’Beluga Proposed LB_50-7 5,551’5,557’4,779’4,783’6’Beluga Proposed LB_50-9 5,615’5,625’4,829’4,839’10’Beluga Proposed LB_50-9 5,718’5,727’4,911’4,918’9’Beluga Proposed LB_51-1 5,816’5,822’4,992’4,996’6’Beluga Proposed LB_51-1 5,852’5,858’5,020’5,025’6’Beluga 8/23/24 Open LB_51-1 5,868’5,873’5,034’5,038’5’Beluga 8/23/24 Open LB_51-2 5,887’5,891’5,050’5,053’4’Beluga 8/23/24 Open LB 51-0 5,898’5,902’5,059’5,062’4’Beluga 8/28/22 Open LB 51-3 5,936’5,939’5,090’5,092’3’Beluga 6/13/22 Isolated 8/28/22 LB 51-3 5,965’5,968’5,115’5,118’3’Beluga 6/13/22 Isolated 8/28/22 LB 51-7 6,114’6,121’5,244’5,250’7’Beluga 9/28/21 Isolated 8/28/22 LB 51-7 6,123’6,126’5,252’5,254’3’Beluga 6/13/22 Isolated 8/28/22 LB 52-9 Middle 6,171’6,175’5,294’5,298’4’Beluga 9/28/21 Isolated 8/28/22 LB 52-9 6,185’6,188’5,306’5,308’3'Beluga 6/13/22 Isolated 8/28/22 BEL_UB_52-9 6,195’6,205’5,315’5,325’10’Beluga 8/15/20 Isolated 8/28/22 56-9 6,658'6,678'5,541'5,560'20’Tyonek 12/22/17 Isolated 6,684'6,696'5,765'5,777'12’Tyonek 12/22/17 Isolated 6,715’6,730’5,795’5,809’15’Tyonek 12/18/17 Isolated 65-5 7,527’7,547’6,585’6,605’20’Tyonek 12/10/17 Isolated 7,528’7,533’6,586’6,591’5’Tyonek 11/30/17 Isolated 68-0 68-0 68-3 68-3 7,770’7,775’6,826'6,830’5’Tyonek 11/29/17 Isolated 7,770’7,775’6,826'6,830’5’Tyonek 11/11/17 Isolated 7,812’7,817’6,867'6,872’5’Tyonek 10/28/17 Isolated 7,845’7,860’6,900’6,914’15’Tyonek 10/16/17 Isolated 73-5 8,355’8,375’7,404’7,424’20’Tyonek 9/28/17 Isolated 75-7 8,538’8,558’7,586’7,606’20’Tyonek 9/19/17 Isolated 77-3 8,585’8,595'7,632’7,642’10’Tyonek 9/18/17 Isolated JEWELRY DETAIL No.Depth ID OD Item 1 2,493’4-1/2” x 2-7/8” Dual Bore Perm Pkr (D&L) (7/27/20) 2 2,506’2-7/8” X-Nipple (7/27/20) 3 2,539’2-7/8” WLEG (7/27/20) 3a 5,930’4-1/2” CIBP w/ 15’ cement; ToC @ 5,915’ (8/28/22) 4 6,271’4-1/2” CIBP w/ 44’ of cement- TOC 6,227’ (8/4/20) 5 6,600’2.33”3.79”4-1/2” Halliburton TWR Perma Series Packer 6 6,610’2.313”2-7/8” X-Nipple 7 6,620’2.441”2-7/8” WLEG 8 6,710’CIBP (12/22/17) 9 7,520’CIBP w/ 35’ of cement: ToC at 7485’ (12/21/17) 10 7,760’CIBP w/ 36’ fill & 35’ cement: ToC at 7589’ (11/30/17) 11 7,795’CIBP w / 15’ cement: ToC at 7780’ (11/02/17) 12 7,838’CIBP w/ 21’ cement: ToC at 7817’ (10/28/17) 13 8,168’CIBP w/ 35’ of cmt; 55’ total: ToC at 8113’ (10/26/17) 14 8,565’1.875”3,75”Tri-Pt Model D Isolation Pkr 08/28/17 X X Fish: 6,334’ – 24.5’ E-Line toolstring + 21’ slickline toolstring 7/25/20 RA @ 2817’ RA @ 3800’ STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 12/05/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241217 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 12A 50133205300100 214070 8/17/2024 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 9/26/2024 YELLOWJACKET PERF-GPT BCU 24 50133206390000 214112 8/19/2024 YELLOWJACKET PERF BCU 25 50133206440000 214132 9/27/2024 YELLOWJACKET PLUG-PERF BLOSSOM 1 50133206480000 215015 9/30/2024 YELLOWJACKET GPT-PLUG-PERF HV B-17 50231200490000 215189 9/23/2024 YELLOWJACKET GPT KU 24-7 50133203520100 205099 10/3/2024 YELLOWJACKET PERF KU 13-06A 50133207160000 223112 12/5/2024 AK E-LINE Plug Setting KU 22-6X 50133205800000 208135 12/8/2024 AK E-LINE Perf KU 23-07A 50133207300000 224126 12/7/2024 AK E-LINE CBL MPU L-17 50029225390000 194169 10/5/2024 YELLOWJACKET PERF MPU R-103 50029237990000 224114 10/14/2024 YELLOWJACKET CBL MPU C-23 50029226430000 196016 11/29/2024 AK E-LINE Plug/cement MPU D-01 50029206640000 181144 11/26/2024 AK E-LINE Perf PBU 13-24B 50029207390200 224087 9/26/2024 YELLOWJACKET CBL PBU 06-07A 50029202990100 224043 9/29/2024 BAKER MRPM PBU 06-18B 50029207670200 223071 10/1/2024 BAKER MRPM PBU 07-32B 50029225250200 204128 10/28/2024 BAKER SPN PBU 14-32B 50029209990200 224073 10/12/2024 BAKER MRPM PBU H-13A 50029205590100 209044 10/23/2024 BAKER SPN PBU L2-20 50029213760000 185134 10/7/2024 BAKER SPN PBU L3-22A 50029216630100 219051 10/9/2024 BAKER PEARL 10 50133207110000 223028 9/25/2024 YELLOWJACKET GPT-PERF PEARL 11 50133207120000 223032 8/29/2024 YELLOWJACKET GPT-PLUG-PERF SRU 241-33 50133206630000 217047 8/23/2024 YELLOWJACKET PERF Please include current contact information if different from above. T39863 T39864 T39865 T39868 T39869 T39870 T39871 T39872 T39873 T39875 T39874 T39867 T39866 T39876 T39877 T39880 T39878 T39879 T39881 T39882 T39883 T39884 T39885 T39886 T39887SRU 241-33 50133206630000 217047 8/23/2024 YELLOWJACKET PERF Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.18 08:35:44 -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 8,630 feet See Schematic feet true vertical 7,677 feet N/A feet 2,493; Effective Depth measured 5,915 feet 6,600; 8,565 feet true vertical 5,073 feet 2,414; 5,483; feet 7613 Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 2-7/8" 6.4# / L-80 2,538' MD 2,451' TVD 2,493' MD; 6,600; 2,414'; 5,493'; Packers and SSSV (type, measured and true vertical depth) N/A 8,565' MD 7,613' 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: Scott Warner, Operations Engineer 324-204 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 372 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A scott.warner@hilcorp.com 907-564-4506 D&L, Halliburton, Tri-Pt Pkrs; measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 0 Size 120' 0 0828 0 1610 652 measured TVD 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 217-047 50-133-20663-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA028399; FEDA028406 Swanson River / Sterling-Up Beluga Gas and Tyonek Gas Swanson River Unit (SRU) 241-33 Plugs Junk measured Length Production Liner 8,625' Casing Structural 7,672'8,625' 120'Conductor Surface Intermediate 16" 7" 120' 2,005' 7,500 psi 7,240 psi 8,430 psi 2,005' 1,986' Burst Collapse 5,410 psi p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 10:38 am, Nov 19, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.11.18 14:13:14 - 09'00' Noel Nocas (4361) Well Name: SRF SRU 241-33 API #:50-133-20663-00-00 Field:Swanson River Start Date:8/23/2024 Permit #:217-047 Sundry #:324-204 End Date: 8/23/2024 9/20/2024 10/20/2024 Well Operations Summary Production monitoring complete- additional perfs will not be completed at this time. PJSM, Crew travel to location, Spot in & rig up, Pick up lube & run #1, Pressure test 250/2500-good, Run in hole with run #1, Correlate, Perf LB 51-2 (5887-5891), Pull up & perf LB 51-1 (5868-5873), Pull up & perf LB 51-1 (5852-5858), Pull out of hole, Rig down for the night. Monitoring production and evaluating additional perfs in sundry. Daily Operations: Page 1 of 1 Updated by DMA 11-07-24 SCHEMATIC Well SRU #241-33 PTD: 217-047 API: 50-133-20663-00-00 PBTD = 5,915 MD / 5,073 TVD TD = 8,630 MD / 7,677 TVD RKB to GL = 11 1 2 3 14 13 12 11 10 9 8 5 6 7 4 3a OPEN HOLE / CEMENT DETAIL 7"8-1/2 hole: Pumped 88bbls 12.0ppg Type I/II lead cement followed by 22bbls 15.4ppg class G tail cement. 23 BBLs Cement to Surface 4-1/2 6-1/8 hole: Pumped 166 bbls 12.8ppg Type I/II lead cement followed by 27bbls 15.3ppg class G tail cement 13bbls back to surface. 8/3/17 CBL showed ToC at 1440 MD after 4 days of cement cure. 10/22/20 CBL confirms ToC at surface. 16 7 4-1/2 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16Conductor Driven to Set Depth 84 X-56 Weld 15.01Surf 120' 7"Surf Csg 26 L-80 BTC/M 6.875Surf 2,005 4-1/2"Prod Csg 12.6 L-80 TXP 3.958Surf 8,625 TUBING DETAIL 2-7/8Production 6.4 L-80 FJ3 2.375Surf 2,538 RA @ 6,006 RA @ 8,415 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Pool Date Status LB_51-1 5,852 5,858 5,020 5,0256 Beluga 8/23/24 Open LB_51-1 5,868 5,873 5,034 5,0385 Beluga 8/23/24 Open LB_51-2 5,887 5,891 5,050 5,0534 Beluga 8/23/24 Open LB 51-0 5,898 5,902 5,059 5,0624 Beluga 8/28/22 Open LB 51-3 5,936 5,939 5,090 5,092 3Beluga 6/13/22 Isolated 8/28/22 LB 51-3 5,965 5,968 5,115 5,118 3Beluga 6/13/22 Isolated 8/28/22 LB 51-7 6,114 6,121 5,244 5,250 7Beluga 9/28/21 Isolated 8/28/22 LB 51-7 6,123 6,126 5,252 5,254 3Beluga 6/13/22 Isolated 8/28/22 LB 52-9 Middle 6,171 6,175 5,294 5,298 4Beluga 9/28/21 Isolated 8/28/22 LB 52-9 6,185 6,188 5,306 5,3083' Beluga 6/13/22 Isolated 8/28/22 BEL_UB_52-9 6,195 6,205 5,315 5,325 10Beluga 8/15/20 Isolated 8/28/22 56-9 6,658'6,678'5,541'5,560'20Tyonek 12/22/17 Isolated 6,684'6,696'5,765'5,777'12Tyonek 12/22/17 Isolated 6,7156,7305,7955,80915Tyonek 12/18/17 Isolated 65-5 7,5277,5476,5856,60520Tyonek 12/10/17 Isolated 7,5287,5336,5866,5915Tyonek 11/30/17 Isolated 68-0 68-0 68-3 68-3 7,7707,7756,826'6,8305Tyonek 11/29/17 Isolated 7,7707,7756,826'6,8305Tyonek 11/11/17 Isolated 7,8127,8176,867'6,8725Tyonek 10/28/17 Isolated 7,8457,8606,9006,91415Tyonek 10/16/17 Isolated 73-5 8,3558,3757,4047,42420Tyonek 9/28/17 Isolated 75-7 8,5388,5587,5867,60620Tyonek 9/19/17 Isolated 77-3 8,5858,595'7,6327,64210Tyonek 9/18/17 Isolated B E L U G A JEWELRY DETAIL No. Depth ID OD Item 1 2,493 4-1/2 x 2-7/8 Dual Bore Perm Pkr (D&L) (7/27/20) 2 2,506 2-7/8 X-Nipple (7/27/20) 3 2,539 2-7/8 WLEG (7/27/20) 3a 5,930 4-1/2 CIBP w/ 15 cement; ToC @ 5,915 (8/28/22) 4 6,271 4-1/2 CIBP w/ 44 of cement- TOC 6,227 (8/4/20) 5 6,6002.333.794-1/2 Halliburton TWR Perma Series Packer 6 6,6102.3132-7/8 X-Nipple 7 6,6202.4412-7/8 WLEG 8 6,710CIBP (12/22/17) 9 7,520CIBP w/ 35 of cement: ToC at 7485 (12/21/17) 10 7,760CIBP w/ 36 fill & 35 cement: ToC at 7589 (11/30/17) 11 7,795CIBP w / 15 cement: ToC at 7780 (11/02/17) 12 7,838CIBP w/ 21 cement: ToC at 7817 (10/28/17) 13 8,168CIBP w/ 35 of cmt; 55 total: ToC at 8113 (10/26/17) 14 8,5651.8753,75Tri-Pt Model D Isolation Pkr 08/28/17 X X Fish: 6,334 24.5 E-Line toolstring + 21 slickline toolstring 7/25/20 RA @ 2817 RA @ 3800 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: N2 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 8,630'N/A Casing Collapse Structural Conductor Surface 5,410 psi Intermediate Production 7,500 psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng jake.flora@hilcorp.com 907-777-8442 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Jake Flora, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028399 / FEDA028406 217-047 50-133-20663-00-00 Hilcorp Alaska, LLC Proposed Pools: 6.4# / L-80 TVD Burst 2538' 8,430 psi 1,986' Size 120' 2,005' MD See Attached Schematic 7,240 psi 120'120' 2,005' April 18, 2024 2-7/8" 8,625' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Swanson River Unit (SRU) 241-33CO 716A Same 7,672'4-1/2" ~1771psi 8,625' See Schematic Length D&L, Halliburton, Tri-Pt Pkrs & N/A 2,493'; 6,660'; 8,565' MD / 2,414'; 5,493'; 7,613' TVD & N/A 7,677'5,915'5,073' Swanson River Sterling-Up Beluga & Tyonek Gas 16" 7" See Attached Schematic m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 8:22 am, Apr 09, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.04.08 17:39:30 - 08'00' Noel Nocas (4361) 10-404 SFD 4/9/2024 CT BOP test to 2500 psi if CT is used. BJM 4/11/24 X DSR-4/12/24JLC 4/12/2024 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.04.12 15:37:02 -08'00'04/12/24 RBDMS JSB 041624 Well Name:SRU 241-33 API Number:50-133-20663-00-00 Current Status:Offline Gas Producer Permit to Drill Number:217-047 First Call Engineer:Jake Flora (720) 988-5375 (c) Second Call Engineer:Chad Helgeson (907) 229-4824 (c) Max. Expected BHP: ~ 2,276 psi @ 5,059’ TVD (0.45psi/ft to deepest open perfs) Max. Potential Surface Pressure: ~ 1,771 psi (0.1psi/ft to surface) Current Status: Producing Gas Well 350 MCFD @ 150 psi, 0 BWPD Brief Well Summary Swanson River 241-33 is a 2017 new drill completed in the Beluga Pool. During the completion phase, the well did not pass an MIT-IA to 2,500 psi (the pressure bled to 750 psi and held solid). It is suspected that the MITIA failed through a micro annulus and below the surface casing shoe. As such a tubing and packer were run to provide a monitorable annulus as required per 20 AAC 25.200 (d). The well was then completed as a Beluga producer and to date multiple plug backs have occurred with the well currently producing from the LB-51 sand at diminishing rates. A recent flowing PT survey found the FBHP at 190 psi with no fluid. The purpose of this work is to add additional perfs staying within the Beluga Pool/PA. Notes Regarding Wellbore Condition Current Gross Perf Interval: 5898 – 5902’ MD (5059-5062’ TVD) 09/26/23 1.75 DDB to 5906’, full of sand 03/30/24 1.75” DDB to 5897’, log Flowing PT survey Procedure 1. RU E-line, PT lubricator to 2000 psi 2. Perforate from the bottom up within the below intervals: Well Sand MD top MD btm TVD TVD H Top of Beluga Pool 5044’ 4401’ SRU_241-33 LB_49-5 5348 5358 4624 4632 10 SRU_241-33 LB_50-7 5518 5528 4753 4761 10 SRU_241-33 LB_50-7 5551 5555 4779 4782 4 SRU_241-33 LB_50-9 5616 5624 4830 4836 8 SRU_241-33 LB_50-9 5719 5726 4912 4917 7 SRU_241-33 LB_51-1 5817 5822 4992 4996 5 SRU_241-33 LB_51-1 5854 5858 5022 5025 4 SRU_241-33 LB_51-1 5868 5873 5034 5038 5 SRU_241-33 LB_51-2 5887 5891 5050 5053 4 5044’ Top of Beluga Pool a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. Contingency Coil Tubing Fill Cleanout (if fill is encountered during testing) 1. Provide 24hrs notice of BOP test 2. MIRU coil tubing unit 3. BOP test to 2500 psi 4. Perform fill cleanout 5. Set CIBP over open perfs if isolation is needed 6. Jet well dry with nitrogen 7. Proceed with perforation program Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Nitrogen SOP 4. Coil Tubing BOP Diagram Updated by DMA 09-13-22 SCHEMATIC Well SRU #241-33 PTD: 217-047 API: 50-133-20663-00-00 PBTD = 5,915’ MD / 5,073’ TVD TD = 8,630’ MD / 7,677’ TVD RKBtoGL= 11’ 1 2 3 14 13 12 11 10 9 8 5 6 7 4 3a OPEN HOLE / CEMENT DETAIL 7"8-1/2” hole: Pumped 88bbls 12.0ppg Type I/II lead cement followed by 22bbls 15.4ppg class G tail cement. – 23 BBLs Cement to Surface 4-1/2” 6-1/8” hole: Pumped 166 bbls 12.8ppg Type I/II lead cement followed by 27bbls 15.3ppg class G tail cement – 13bbls back to surface. 8/3/17 CBL showed ToC at 1440’ MD after 4 days of cement cure. 10/22/20 CBL confirms ToC at surface. 16” 7” 4-1/2” CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 84 X-56 Weld 15.01”Surf 120' 7"Surf Csg 26 L-80 BTC/M 6.875”Surf 2,005’ 4-1/2"Prod Csg 12.6 L-80 TXP 3.958”Surf 8,625‘ TUBING DETAIL 2-7/8”Production 6.4 L-80 FJ3 2.375”Surf 2,538’ RA @ 6,006’ RA @ 8,415’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Pool Date Status LB 51-0 5,898’5,902’5,059’5,062’4 Beluga 8/28/22 Open LB 51-3 5,936’5,939’5,090’5,092’3’Beluga 6/13/22 Isolated 8/28/22 LB 51-3 5,965’5,968’5,115’5,118’3’Beluga 6/13/22 Isolated 8/28/22 LB 51-7 6,114’6,121’5,244’5,250’7’Beluga 9/28/21 Isolated 8/28/22 LB 51-7 6,123’6,126’5,252’5,254’3’Beluga 6/13/22 Isolated 8/28/22 LB 52-9 Middle 6,171’6,175’5,294’5,298’4’Beluga 9/28/21 Isolated 8/28/22 LB 52-9 6,185’6,188’5,306’5,308’3'Beluga 6/13/22 Isolated 8/28/22 BEL_UB_52-9 6,195’6,205’5,315’5,325’10’Beluga 8/15/20 Isolated 8/28/22 56-9 6,658'6,678'5,541'5,560'20’Tyonek 12/22/17 Isolated 6,684'6,696'5,765'5,777'12’Tyonek 12/22/17 Isolated 6,715’6,730’5,795’5,809’15’Tyonek 12/18/17 Isolated 65-5 7,527’7,547’6,585’6,605’20’Tyonek 12/10/17 Isolated 7,528’7,533’6,586’6,591’5’Tyonek 11/30/17 Isolated 68-0 68-0 68-3 68-3 7,770’7,775’6,826'6,830’5’Tyonek 11/29/17 Isolated 7,770’7,775’6,826'6,830’5’Tyonek 11/11/17 Isolated 7,812’7,817’6,867'6,872’5’Tyonek 10/28/17 Isolated 7,845’7,860’6,900’6,914’15’Tyonek 10/16/17 Isolated 73-5 8,355’8,375’7,404’7,424’20’Tyonek 9/28/17 Isolated 75-7 8,538’8,558’7,586’7,606’20’Tyonek 9/19/17 Isolated 77-3 8,585’8,595'7,632’7,642’10’Tyonek 9/18/17 Isolated B E L U G A JEWELRY DETAIL No.Depth ID OD Item 1 2,493’4-1/2” x 2-7/8” Dual Bore Perm Pkr (D&L) (7/27/20) 2 2,506’2-7/8” X-Nipple (7/27/20) 3 2,539’2-7/8” WLEG (7/27/20) 3a 5930 4-1/2” CIBP w/ 15’ cement; ToC @ 5,915’ (8/28/22) 4 6,271’4-1/2” CIBP w/ 44’ of cement- TOC 6,227’ (8/4/20) 5 6,600’2.33”3.79”4-1/2” Halliburton TWR Perma Series Packer 6 6,610’2.313”2-7/8” X-Nipple 7 6,620’2.441”2-7/8” WLEG 8 6,710’CIBP (12/22/17) 9 7,520’CIBP w/ 35’ of cement: ToC at 7485’ (12/21/17) 10 7,760’CIBP w/ 36’ fill & 35’ cement: ToC at 7589’ (11/30/17) 11 7,795’CIBP w / 15’ cement: ToC at 7780’ (11/02/17) 12 7,838’CIBP w/ 21’ cement: ToC at 7817’ (10/28/17) 13 8,168’CIBP w/ 35’ of cmt; 55’ total: ToC at 8113’ (10/26/17) 14 8,565’1.875”3,75”Tri-Pt Model D Isolation Pkr 08/28/17 X X Fish: 6,334’ – 24.5’ E-Line toolstring + 21’ slickline toolstring 7/25/20 RA @ 2817’ RA @ 3800’ Updated by JMF 4-04-24 PROPOSED Well SRU #241-33 PTD: 217-047 API: 50-133-20663-00-00 PBTD = 5,915’MD / 5,073’TVD TD = 8,630’ MD / 7,677’ TVD RKB to GL = 11’ 1 2 3 14 13 12 11 10 9 8 5 6 7 4 3a OPEN HOLE / CEMENT DETAIL 7" 8-1/2” hole: Pumped 88bbls 12.0ppg Type I/II lead cement followed by 22bbls 15.4ppg class G tail cement. – 23 BBLs Cement to Surface 4-1/2” 6-1/8” hole: Pumped 166 bbls 12.8ppg Type I/II lead cement followed by 27bbls 15.3ppg class G tail cement – 13bbls back to surface. 8/3/17 CBL showed ToC at 1440’ MD after 4 days of cement cure. 10/22/20 CBL confirms ToC at surface. 16” 7” 4-1/2” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor –Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7"Surf Csg 26 L-80 BTC/M 6.875”Surf 2,005’ 4-1/2"Prod Csg 12.6 L-80 TXP 3.958”Surf 8,625‘ TUBING DETAIL 2-7/8”Production 6.4 L-80 FJ3 2.375”Surf 2,538’ RA @ 6,006’ RA @ 8,415’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Pool Date Status LB_49-5 5348 5358 4624 4632 10 Beluga TBD proposed LB_50-7 5518 5528 4753 4761 10 Beluga TBD proposed LB_50-7 5551 5555 4779 4782 4 Beluga TBD proposed LB_50-9 5616 5624 4830 4836 8 Beluga TBD proposed LB_50-9 5719 5726 4912 4917 7 Beluga TBD proposed LB_51-1 5817 5822 4992 4996 5 Beluga TBD proposed LB_51-1 5854 5858 5022 5025 4 Beluga TBD proposed LB_51-1 5868 5873 5034 5038 5 Beluga TBD proposed LB_51-2 5887 5891 5050 5053 4 Beluga TBD proposed LB 51-0 5,898’ 5,902’ 5,059’ 5,062’ 4 Beluga 8/28/22 Open LB 51-3 5,936’ 5,939’ 5,090’ 5,092’ 3’ Beluga 6/13/22 Isolated 8/28/22 LB 51-3 5,965’ 5,968’ 5,115’ 5,118’ 3’ Beluga 6/13/22 Isolated 8/28/22 LB 51-7 6,114’ 6,121’ 5,244’ 5,250’ 7’ Beluga 9/28/21 Isolated 8/28/22 LB 51-7 6,123’ 6,126’ 5,252’ 5,254’ 3’ Beluga 6/13/22 Isolated 8/28/22 LB 52-9 Middle 6,171’ 6,175’ 5,294’ 5,298’ 4’ Beluga 9/28/21 Isolated 8/28/22 LB 52-9 6,185’ 6,188’ 5,306’ 5,308’ 3' Beluga 6/13/22 Isolated 8/28/22 BEL_UB_52-9 6,195’ 6,205’ 5,315’ 5,325’ 10’ Beluga 8/15/20 Isolated 8/28/22 56-9 6,658' 6,678' 5,541' 5,560' 20’ Tyonek 12/22/17 Isolated 6,684' 6,696' 5,765' 5,777' 12’ Tyonek 12/22/17 Isolated 6,715’ 6,730’ 5,795’ 5,809’ 15’ Tyonek 12/18/17 Isolated 65-5 7,527’ 7,547’ 6,585’ 6,605’ 20’ Tyonek 12/10/17 Isolated 7,528’ 7,533’ 6,586’ 6,591’ 5’ Tyonek 11/30/17 Isolated 68-0 68-0 68-3 68-3 7,770’ 7,775’ 6,826' 6,830’ 5’ Tyonek 11/29/17 Isolated 7,770’ 7,775’ 6,826' 6,830’ 5’ Tyonek 11/11/17 Isolated 7,812’ 7,817’ 6,867' 6,872’ 5’ Tyonek 10/28/17 Isolated 7,845’ 7,860’ 6,900’ 6,914’ 15’ Tyonek 10/16/17 Isolated 73-5 8,355’ 8,375’ 7,404’ 7,424’ 20’ Tyonek 9/28/17 Isolated 75-7 8,538’ 8,558’ 7,586’ 7,606’ 20’ Tyonek 9/19/17 Isolated 77-3 8,585’ 8,595' 7,632’ 7,642’ 10’ Tyonek 9/18/17 Isolated B E L U G A JEWELRY DETAIL No. Depth ID OD Item 1 2,493’ 4-1/2” x 2-7/8” Dual Bore Perm Pkr (D&L) (7/27/20) 2 2,506’ 2-7/8” X-Nipple (7/27/20) 3 2,539’ 2-7/8” WLEG (7/27/20) 3a 5930 4-1/2” CIBP w/ 15’ cement; ToC @ 5,915’ (8/28/22) 4 6,271’ 4-1/2” CIBP w/ 44’ of cement- TOC 6,227’ (8/4/20) 5 6,600’ 2.33” 3.79” 4-1/2” Halliburton TWR Perma Series Packer 6 6,610’ 2.313” 2-7/8” X-Nipple 7 6,620’ 2.441” 2-7/8” WLEG 8 6,710’ CIBP (12/22/17) 9 7,520’ CIBP w/ 35’ of cement: ToC at 7485’ (12/21/17) 10 7,760’ CIBP w/ 36’ fill & 35’ cement: ToC at 7589’ (11/30/17) 11 7,795’ CIBP w / 15’ cement: ToC at 7780’ (11/02/17) 12 7,838’ CIBP w/ 21’ cement: ToC at 7817’ (10/28/17) 13 8,168’ CIBP w/ 35’ of cmt; 55’ total: ToC at 8113’ (10/26/17) 14 8,565’ 1.875” 3,75” Tri-Pt Model D Isolation Pkr 08/28/17 X X Fish: 6,334’ – 24.5’ E-Line toolstring + 21’ slickline toolstring 7/25/20 RA @ 2817’ RA @ 3800’ STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Kyle Wiseman Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/21/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20221121 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# CLU 05RD2 50133204740200 222092 10/18/2022 AK E-Line Perf_GPT MGS S MGS Unit 11 50733201040000 168032 10/11/2022 AK E-Line LDL SRU 241-33 50133206630000 217047 8/29/2022 AK E-Line TTBP_Perf SRU 32A-33 50133101640100 191014 9/23/2022 AK E-Line GPT SCU 344-33 50133202930100 218054 9/11/2022 AK E-Line Punch BCU 18RD 50133205840100 222033 9/10/2022 AK E-Line GPT BCU 18RD 50133205840100 222033 9/18/2022 AK E-Line Stim BRU 233-23 50283201360100 222050 11/1/2022 AK E-Line Perf BRU 233-23 50283201360100 222050 9/12/2022 AK E-Line CIBP Please include current contact information if different from above. T37280 T37281 T37282 T37283 T37284 T37285 T37285 T37286 T37286 By Meredith Guhl at 2:54 pm, Nov 21, 2022 SRU 241-33 50133206630000 217047 8/29/2022 AK E-Line TTBP_Perf Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.11.21 14:55:38 -09'00' By Anne Prysunka at 10:20 am, Sep 13, 2022 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________SWANSON RIV UNIT 241-33 JBR 09/06/2022 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 Location looked good, coil unit in good shape. Had an issue getting test on pipe/slips, they rebuilt the blocks and changed all seals. Found out that the valve alignment was incorrect and that was the problem and Pipe/slips tested good. Coil crew worked thru these issues and was taken care of in a timely manner. All parts were on location. Accumulator System 4/1400 psi. Test Results TEST DATA Rig Rep:Terrance/LandryOperator:Hilcorp Alaska, LLC Operator Rep:Karson Kozub Rig Owner/Rig No.:Fox 8 PTD#:2170470 DATE:8/24/2022 Type Operation:WRKOV Annular: N/AType Test:INIT Valves: 250/2500 Rams: 250/2500 Test Pressures:Inspection No:bopKPS220825121955 Inspector Kam StJohn Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 5.5 MASP: 1864 Sundry No: 322-457 CLOSURE TIME (sec) Time/Pressure P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.NA Test Fluid W Misc NA Upper Kelly 0 NA Lower Kelly 0 NA Ball Type 0 NA Inside BOP 0 NA FSV Misc 0 NA 5 PNo. Valves 2 PManual Chokes 0 NAHydraulic Chokes 0 NACH Misc Stripper 1 1.75"P Annular Preventer 0 NA #1 Rams 1 1.75" Blind/S P #2 Rams 1 1.75" Pipe/Sli P #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 2 2" Plug P HCR Valves 0 NA Kill Line Valves 2 2" plug P Check Valve 0 NA BOP Misc 0 NA System Pressure P2950 Pressure After Closure P2400 200 PSI Attained P3 Full Pressure Attained P10 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)NA0 ACC Misc NA0 NA NATrip Tank NA NAPit Level Indicators NA NAFlow Indicator NA NAMeth Gas Detector NA NAH2S Gas Detector NA NAMS Misc Inside Reel Valves 1 P Annular Preventer NA0 #1 Rams P15 #2 Rams P11 #3 Rams NA0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke NA0 HCR Kill NA0 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 coil unit in good shape.issue getting test on pipe/slips, valve alignment was incorrect 7\SHRI5HTXHVW$EDQGRQ 3OXJ3HUIRUDWLRQV )UDFWXUH6WLPXODWH 5HSDLU:HOO 2SHUDWLRQVVKXWGRZQ 6XVSHQG 3HUIRUDWH 2WKHU6WLPXODWH 3XOO7XELQJ &KDQJH$SSURYHG3URJUDP 3OXJIRU5HGULOO 3HUIRUDWH1HZ3RRO 5HHQWHU6XVS:HOO $OWHU&DVLQJ 2SHUDWRU1DPH&XUUHQW:HOO&ODVV 3HUPLWWR'ULOO1XPEHU ([SORUDWRU\ 'HYHORSPHQW $GGUHVV6WUDWLJUDSKLF 6HUYLFH $3,1XPEHU 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ϲ͘Zh'>ŽƌŶŝƚƌŽŐĞŶĂŶĚĂƉƉůǇt,WĨŽƌƐŚŽŽƚŝŶŐƉĞƌK;ŝĨŶĞĞĚĞĚͿ ϳ͘Z/,ĂŶĚƉĞƌĨŽƌĂƚĞƐĂŶĚƐĨƌŽŵцϱ͕ϱϵϮ͛ʹцϲ͕ϬϬϬ͛D;цϰ͕ϴϭϭ͛ʹцϱ͕ϭϰϲ͛dsͿŝŶƚŚĞĞůƵŐĂWŽŽůͬWƉĞƌ Zͬ'ĞŽ;ĂůůĚĞƉƚŚƐĂŶĚůĞŶŐƚŚƐĂƌĞнͬͲͿ ϴ͘ZDK> ŽŶƚŝŶŐĞŶĐǇ>WůƵŐ ϭ͘D/ZhͲůŝŶĞĂŶĚƉƌĞƐƐƵƌĞĐŽŶƚƌŽůĞƋƵŝƉŵĞŶƚ Ϯ͘WdůƵďƌŝĐĂƚŽƌƚŽϮϱϬƉƐŝůŽǁͬϮϬϬϬƉƐŝŚŝŐŚ ϯ͘ZhŐĂƐůŝĨƚŽƌEŝƚƌŽŐĞŶĂŶĚƉƵƐŚǁĂƚĞƌďĂĐŬŝŶƚŽĨŽƌŵĂƚŝŽŶ ϰ͘ŽŶĨŝƌŵǁĂƚĞƌůĞǀĞůŝƐďĞůŽǁŝŶƚĞƌǀĂůƚŽŝƐŽůĂƚĞ͕ĂŶĚƐĞƚϰͲϭͬϮ͟ĞǆƉĂŶĚĂďůĞďƌŝĚŐĞƉůƵŐ ϱ͘ƵŵƉďĂŝůϯϱ͛ĐĞŵĞŶƚŽŶƚŽƉŽĨƉůƵŐ /ĨƐĞƚƚŝŶŐĂďƌŝĚŐĞƉůƵŐ͕ŝƚŵƵƐƚďĞƐĞƚϱϬ͛ĂďŽǀĞƉĞƌĨ͕ĂŶĚŚĂǀĞϯϱ͛ĐĞŵĞŶƚĚƵŵƉďĂŝůĞĚƵŶůĞƐƐĂ>DǀĂƌŝĂŶĐĞŝƐ ŽďƚĂŝŶĞĚŝŶĂĚǀĂŶĐĞ ϲ͘ZDK tĞůů͗^ZhϮϰϭͲϯϯ &KͬWůƵŐͬWĞƌĨ ĂƚĞ͗ϴͬϭϬͬϮϬϮϮ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ƵƌƌĞŶƚtĞůů^ĐŚĞŵĂƚŝĐ Ϯ͘WƌŽƉŽƐĞĚtĞůů^ĐŚĞŵĂƚŝĐ ϯ͘&ŽǆdKWƐĐŚĞŵĂƚŝĐ ϰ͘^ƚĂŶĚĂƌĚtĞůůƉƌŽĐĞĚƵƌĞʹEϮKƉĞƌĂƚŝŽŶƐ hƉĚĂƚĞĚďǇZZϴͲϮͲϮϮ ^,Dd/ tĞůů^ZhηϮϰϭͲϯϯ Wd͗ϮϭϳͲϬϰϳ W/͗ϱϬͲϭϯϯͲϮϬϲϲϯͲϬϬͲϬϬ Wdсϲ͕ϮϮϳ͛ͬWdsсϱ͕ϯϰϰ͛ dсϴ͕ϲϯϬ͛ͬdsсϳ͕ϲϳϳ͛ Z<ƚŽ'>сϭϭ͛ ϭ Ϯ ϯ ϭϰ ϭϯ ϭϮ ϭϭ ϭϬ ϵ ϴ ϱ ϲ ϳ ϰ KWE,K>ͬDEdd/> ϳΗϴͲϭͬϮ͟ŚŽůĞ͗WƵŵƉĞĚϴϴďďůƐϭϮ͘ϬƉƉŐdǇƉĞ/ͬ//ůĞĂĚĐĞŵĞŶƚĨŽůůŽǁĞĚďǇϮϮďďůƐϭϱ͘ϰƉƉŐĐůĂƐƐ' ƚĂŝůĐĞŵĞŶƚ͘ʹϮϯ>ƐĞŵĞŶƚƚŽ^ƵƌĨĂĐĞ ϰͲϭͬϮ͟ ϲͲϭͬϴ͟ŚŽůĞ͗WƵŵƉĞĚϭϲϲďďůƐϭϮ͘ϴƉƉŐdǇƉĞ/ͬ//ůĞĂĚĐĞŵĞŶƚĨŽůůŽǁĞĚďǇϮϳďďůƐϭϱ͘ϯƉƉŐĐůĂƐƐ 'ƚĂŝůĐĞŵĞŶƚʹϭϯďďůƐďĂĐŬƚŽƐƵƌĨĂĐĞ͘ϴͬϯͬϭϳ>ƐŚŽǁĞĚdŽĂƚϭϰϰϬ͛DĂĨƚĞƌϰĚĂǇƐŽĨ ĐĞŵĞŶƚĐƵƌĞ͘ϭϬͬϮϮͬϮϬ>ĐŽŶĨŝƌŵƐdŽĂƚƐƵƌĨĂĐĞ͘ ϭϲ͟ ϳ͟ ϰͲϭͬϮ͟ ^/E'd/> ^ŝǌĞdǇƉĞtƚ'ƌĂĚĞŽŶŶ͘/dŽƉƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌʹƌŝǀĞŶ ƚŽ^ĞƚĞƉƚŚϴϰyͲϱϲtĞůĚ ϭϱ͘Ϭϭ͟^ƵƌĨϭϮϬΖ ϳΗ^ƵƌĨƐŐϮϲ>ͲϴϬdͬDϲ͘ϴϳϱ͟^ƵƌĨϮ͕ϬϬϱ͛ ϰͲϭͬϮΗWƌŽĚƐŐϭϮ͘ϲ>ͲϴϬdyWϯ͘ϵϱϴ͟^ƵƌĨϴ͕ϲϮϱ͚ dh/E'd/> ϮͲϳͬϴ͟WƌŽĚƵĐƚŝŽŶϲ͘ϰ>ͲϴϬ&:ϯϮ͘ϯϳϱ͟^ƵƌĨϮ͕ϱϯϴ͛ ZΛϲ͕ϬϬϲ͛ ZΛϴ͕ϰϭϱ͛ WZ&KZd/KEd/> ^ĂŶĚƐdŽƉ ;DͿ ƚŵ ;DͿ dŽƉ ;dsͿ ƚŵ ;dsͿ&dWŽŽů ĂƚĞ ^ƚĂƚƵƐ >ϱϭͲϯϱ͕ϵϯϲ͛ϱ͕ϵϯϵ͛ϱ͕ϬϵϬ͛ϱ͕ϬϵϮ͛ϯ͛ĞůƵŐĂϲͬϭϯͬϮϮKƉĞŶ >ϱϭͲϯϱ͕ϵϲϱ͛ϱ͕ϵϲϴ͛ϱ͕ϭϭϱ͛ϱ͕ϭϭϴ͛ϯ͛ĞůƵŐĂϲͬϭϯͬϮϮKƉĞŶ >ϱϭͲϳϲ͕ϭϭϰ͛ϲ͕ϭϮϭ͛ϱ͕Ϯϰϰ͛ϱ͕ϮϱϬ͛ϳ͛ĞůƵŐĂϵͬϮϴͬϮϭKƉĞŶ >ϱϭͲϳϲ͕ϭϮϯ͛ϲ͕ϭϮϲ͛ϱ͕ϮϱϮ͛ϱ͕Ϯϱϰ͛ϯ͛ĞůƵŐĂϲͬϭϯͬϮϮKƉĞŶ >ϱϮͲϵDŝĚĚůĞϲ͕ϭϳϭ͛ϲ͕ϭϳϱ͛ϱ͕Ϯϵϰ͛ϱ͕Ϯϵϴ͛ϰ͛ĞůƵŐĂϵͬϮϴͬϮϭKƉĞŶ >ϱϮͲϵϲ͕ϭϴϱ͛ϲ͕ϭϴϴ͛ϱ͕ϯϬϲ͛ϱ͕ϯϬϴ͛ϯΖĞůƵŐĂϲͬϭϯͬϮϮKƉĞŶ >ͺhͺϱϮͲϵϲ͕ϭϵϱ͛ϲ͕ϮϬϱ͛ϱ͕ϯϭϱ͛ϱ͕ϯϮϱ͛ϭϬ͛ĞůƵŐĂϴͬϭϱͬϮϬKƉĞŶ ϱϲͲϵ ϲ͕ϲϱϴΖϲ͕ϲϳϴΖϱ͕ϱϰϭΖϱ͕ϱϲϬΖϮϬ͛dǇŽŶĞŬϭϮͬϮϮͬϭϳ/ƐŽůĂƚĞĚ ϲ͕ϲϴϰΖϲ͕ϲϵϲΖϱ͕ϳϲϱΖϱ͕ϳϳϳΖϭϮ͛dǇŽŶĞŬϭϮͬϮϮͬϭϳ/ƐŽůĂƚĞĚ ϲ͕ϳϭϱ͛ϲ͕ϳϯϬ͛ϱ͕ϳϵϱ͛ϱ͕ϴϬϵ͛ϭϱ͛dǇŽŶĞŬϭϮͬϭϴͬϭϳ/ƐŽůĂƚĞĚ ϲϱͲϱϳ͕ϱϮϳ͛ϳ͕ϱϰϳ͛ϲ͕ϱϴϱ͛ϲ͕ϲϬϱ͛ϮϬ͛dǇŽŶĞŬϭϮͬϭϬͬϭϳ/ƐŽůĂƚĞĚ ϳ͕ϱϮϴ͛ϳ͕ϱϯϯ͛ϲ͕ϱϴϲ͛ϲ͕ϱϵϭ͛ϱ͛dǇŽŶĞŬϭϭͬϯϬͬϭϳ/ƐŽůĂƚĞĚ ϲϴͲϬ ϲϴͲϬ ϲϴͲϯ ϲϴͲϯ ϳ͕ϳϳϬ͛ϳ͕ϳϳϱ͛ϲ͕ϴϮϲΖϲ͕ϴϯϬ͛ϱ͛dǇŽŶĞŬϭϭͬϮϵͬϭϳ/ƐŽůĂƚĞĚ ϳ͕ϳϳϬ͛ϳ͕ϳϳϱ͛ϲ͕ϴϮϲΖϲ͕ϴϯϬ͛ϱ͛dǇŽŶĞŬϭϭͬϭϭͬϭϳ/ƐŽůĂƚĞĚ ϳ͕ϴϭϮ͛ϳ͕ϴϭϳ͛ϲ͕ϴϲϳΖϲ͕ϴϳϮ͛ϱ͛dǇŽŶĞŬϭϬͬϮϴͬϭϳ/ƐŽůĂƚĞĚ ϳ͕ϴϰϱ͛ϳ͕ϴϲϬ͛ϲ͕ϵϬϬ͛ϲ͕ϵϭϰ͛ϭϱ͛dǇŽŶĞŬϭϬͬϭϲͬϭϳ/ƐŽůĂƚĞĚ ϳϯͲϱϴ͕ϯϱϱ͛ϴ͕ϯϳϱ͛ϳ͕ϰϬϰ͛ϳ͕ϰϮϰ͛ϮϬ͛dǇŽŶĞŬϵͬϮϴͬϭϳ/ƐŽůĂƚĞĚ ϳϱͲϳϴ͕ϱϯϴ͛ϴ͕ϱϱϴ͛ϳ͕ϱϴϲ͛ϳ͕ϲϬϲ͛ϮϬ͛dǇŽŶĞŬϵͬϭϵͬϭϳ/ƐŽůĂƚĞĚ ϳϳͲϯϴ͕ϱϴϱ͛ϴ͕ϱϵϱΖϳ͕ϲϯϮ͛ϳ͕ϲϰϮ͛ϭϬ͛dǇŽŶĞŬϵͬϭϴͬϭϳ/ƐŽůĂƚĞĚ :t>Zzd/> EŽ͘ĞƉƚŚ/K/ƚĞŵ ϭϮ͕ϰϵϯ͛ϰͲϭͬϮ͟ǆϮͲϳͬϴ͟ƵĂůŽƌĞWĞƌŵWŬƌ;Θ>Ϳ;ϳͬϮϳͬϮϬͿ ϮϮ͕ϱϬϲ͛ϮͲϳͬϴ͟yͲEŝƉƉůĞ;ϳͬϮϳͬϮϬͿ ϯϮ͕ϱϯϵ͛ϮͲϳͬϴ͟t>';ϳͬϮϳͬϮϬͿ ϰϲ͕Ϯϳϭ͛ϰͲϭͬϮ͟/Wǁͬϰϰ͛ŽĨĐĞŵĞŶƚͲdKϲ͕ϮϮϳ͛;ϴͬϰͬϮϬͿ ϱϲ͕ϲϬϬ͛Ϯ͘ϯϯ͟ϯ͘ϳϵ͟ϰͲϭͬϮ͟,ĂůůŝďƵƌƚŽŶdtZWĞƌŵĂ^ĞƌŝĞƐWĂĐŬĞƌ ϲϲ͕ϲϭϬ͛Ϯ͘ϯϭϯ͟ϮͲϳͬϴ͟yͲEŝƉƉůĞ ϳϲ͕ϲϮϬ͛Ϯ͘ϰϰϭ͟ϮͲϳͬϴ͟t>' ϴϲ͕ϳϭϬ͛/W;ϭϮͬϮϮͬϭϳͿ ϵϳ͕ϱϮϬ͛/Wǁͬϯϱ͛ŽĨĐĞŵĞŶƚ͗dŽĂƚϳϰϴϱ͛;ϭϮͬϮϭͬϭϳͿ ϭϬϳ͕ϳϲϬ͛/Wǁͬϯϲ͛ĨŝůůΘϯϱ͛ĐĞŵĞŶƚ͗dŽĂƚϳϱϴϵ͛;ϭϭͬϯϬͬϭϳͿ ϭϭϳ͕ϳϵϱ͛/Wǁͬϭϱ͛ĐĞŵĞŶƚ͗dŽĂƚϳϳϴϬ͛;ϭϭͬϬϮͬϭϳͿ ϭϮϳ͕ϴϯϴ͛/WǁͬϮϭ͛ĐĞŵĞŶƚ͗dŽĂƚϳϴϭϳ͛;ϭϬͬϮϴͬϭϳͿ ϭϯϴ͕ϭϲϴ͛/Wǁͬϯϱ͛ŽĨĐŵƚ͖ϱϱ͛ƚŽƚĂů͗dŽĂƚϴϭϭϯ͛;ϭϬͬϮϲͬϭϳͿ ϭϰϴ͕ϱϲϱ͛ϭ͘ϴϳϱ͟ϯ͕ϳϱ͟dƌŝͲWƚDŽĚĞů/ƐŽůĂƚŝŽŶWŬƌϬϴͬϮϴͬϭϳ y >ͺhͺϱϮͲϵ y &ŝƐŚ͗ ϲ͕ϯϯϰ͛ʹϮϰ͘ϱ͛Ͳ>ŝŶĞƚŽŽůƐƚƌŝŶŐнϮϭ͛ƐůŝĐŬůŝŶĞƚŽŽůƐƚƌŝŶŐϳͬϮϱͬϮϬ >ϱϭ >ϱϭͲϳ >ϱϮͲϵ ZΛϮϴϭϳ͛ ZΛϯϴϬϬ͛ hƉĚĂƚĞĚďǇDϬϴͲϭϭͲϮϮ WZKWK^ tĞůů^ZhηϮϰϭͲϯϯ Wd͗ϮϭϳͲϬϰϳ W/͗ϱϬͲϭϯϯͲϮϬϲϲϯͲϬϬͲϬϬ Wdсϲ͕ϮϮϳ͛ͬWdsсϱ͕ϯϰϰ͛ dсϴ͕ϲϯϬ͛ͬdsсϳ͕ϲϳϳ͛ Z<ƚŽ'>сϭϭ͛ ϭ Ϯ ϯ ϭϰ ϭϯ ϭϮ ϭϭ ϭϬ ϵ ϴ ϱ ϲ ϳ ϰ ϯĂ KWE,K>ͬDEdd/> ϳΗϴͲϭͬϮ͟ŚŽůĞ͗WƵŵƉĞĚϴϴďďůƐϭϮ͘ϬƉƉŐdǇƉĞ/ͬ//ůĞĂĚĐĞŵĞŶƚĨŽůůŽǁĞĚďǇϮϮďďůƐϭϱ͘ϰƉƉŐĐůĂƐƐ' ƚĂŝůĐĞŵĞŶƚ͘ʹϮϯ>ƐĞŵĞŶƚƚŽ^ƵƌĨĂĐĞ ϰͲϭͬϮ͟ ϲͲϭͬϴ͟ŚŽůĞ͗WƵŵƉĞĚϭϲϲďďůƐϭϮ͘ϴƉƉŐdǇƉĞ/ͬ//ůĞĂĚĐĞŵĞŶƚĨŽůůŽǁĞĚďǇϮϳďďůƐϭϱ͘ϯƉƉŐĐůĂƐƐ 'ƚĂŝůĐĞŵĞŶƚʹϭϯďďůƐďĂĐŬƚŽƐƵƌĨĂĐĞ͘ϴͬϯͬϭϳ>ƐŚŽǁĞĚdŽĂƚϭϰϰϬ͛DĂĨƚĞƌϰĚĂǇƐŽĨ ĐĞŵĞŶƚĐƵƌĞ͘ϭϬͬϮϮͬϮϬ>ĐŽŶĨŝƌŵƐdŽĂƚƐƵƌĨĂĐĞ͘ ϭϲ͟ ϳ͟ ϰͲϭͬϮ͟ ^/E'd/> ^ŝǌĞdǇƉĞtƚ'ƌĂĚĞŽŶŶ͘/dŽƉƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌʹƌŝǀĞŶ ƚŽ^ĞƚĞƉƚŚϴϰyͲϱϲtĞůĚ ϭϱ͘Ϭϭ͟^ƵƌĨϭϮϬΖ ϳΗ^ƵƌĨƐŐϮϲ>ͲϴϬdͬDϲ͘ϴϳϱ͟^ƵƌĨϮ͕ϬϬϱ͛ ϰͲϭͬϮΗWƌŽĚƐŐϭϮ͘ϲ>ͲϴϬdyWϯ͘ϵϱϴ͟^ƵƌĨϴ͕ϲϮϱ͚ dh/E'd/> ϮͲϳͬϴ͟WƌŽĚƵĐƚŝŽŶϲ͘ϰ>ͲϴϬ&:ϯϮ͘ϯϳϱ͟^ƵƌĨϮ͕ϱϯϴ͛ ZΛϲ͕ϬϬϲ͛ ZΛϴ͕ϰϭϱ͛ WZ&KZd/KEd/> ^ĂŶĚƐdŽƉ ;DͿ ƚŵ ;DͿ dŽƉ ;dsͿ ƚŵ ;dsͿ&dWŽŽů ĂƚĞ ^ƚĂƚƵƐ >ϱϭͲϬцϱ͕ϲϴϭ͛цϲ͕ϬϬϬ͛цϰ͕ϴϭϭ͛цϱ͕ϭϰϲ͛цϰϳϵ͛ĞůƵŐĂWƌŽƉŽƐĞĚd >ϱϭͲϯϱ͕ϵϯϲ͛ϱ͕ϵϯϵ͛ϱ͕ϬϵϬ͛ϱ͕ϬϵϮ͛ϯ͛ĞůƵŐĂϲͬϭϯͬϮϮKƉĞŶ >ϱϭͲϯϱ͕ϵϲϱ͛ϱ͕ϵϲϴ͛ϱ͕ϭϭϱ͛ϱ͕ϭϭϴ͛ϯ͛ĞůƵŐĂϲͬϭϯͬϮϮKƉĞŶ >ϱϭͲϳϲ͕ϭϭϰ͛ϲ͕ϭϮϭ͛ϱ͕Ϯϰϰ͛ϱ͕ϮϱϬ͛ϳ͛ĞůƵŐĂϵͬϮϴͬϮϭKƉĞŶ >ϱϭͲϳϲ͕ϭϮϯ͛ϲ͕ϭϮϲ͛ϱ͕ϮϱϮ͛ϱ͕Ϯϱϰ͛ϯ͛ĞůƵŐĂϲͬϭϯͬϮϮKƉĞŶ >ϱϮͲϵDŝĚĚůĞϲ͕ϭϳϭ͛ϲ͕ϭϳϱ͛ϱ͕Ϯϵϰ͛ϱ͕Ϯϵϴ͛ϰ͛ĞůƵŐĂϵͬϮϴͬϮϭKƉĞŶ >ϱϮͲϵϲ͕ϭϴϱ͛ϲ͕ϭϴϴ͛ϱ͕ϯϬϲ͛ϱ͕ϯϬϴ͛ϯΖĞůƵŐĂϲͬϭϯͬϮϮKƉĞŶ >ͺhͺϱϮͲϵϲ͕ϭϵϱ͛ϲ͕ϮϬϱ͛ϱ͕ϯϭϱ͛ϱ͕ϯϮϱ͛ϭϬ͛ĞůƵŐĂϴͬϭϱͬϮϬKƉĞŶ ϱϲͲϵ ϲ͕ϲϱϴΖϲ͕ϲϳϴΖϱ͕ϱϰϭΖϱ͕ϱϲϬΖϮϬ͛dǇŽŶĞŬϭϮͬϮϮͬϭϳ/ƐŽůĂƚĞĚ ϲ͕ϲϴϰΖϲ͕ϲϵϲΖϱ͕ϳϲϱΖϱ͕ϳϳϳΖϭϮ͛dǇŽŶĞŬϭϮͬϮϮͬϭϳ/ƐŽůĂƚĞĚ ϲ͕ϳϭϱ͛ϲ͕ϳϯϬ͛ϱ͕ϳϵϱ͛ϱ͕ϴϬϵ͛ϭϱ͛dǇŽŶĞŬϭϮͬϭϴͬϭϳ/ƐŽůĂƚĞĚ ϲϱͲϱϳ͕ϱϮϳ͛ϳ͕ϱϰϳ͛ϲ͕ϱϴϱ͛ϲ͕ϲϬϱ͛ϮϬ͛dǇŽŶĞŬϭϮͬϭϬͬϭϳ/ƐŽůĂƚĞĚ ϳ͕ϱϮϴ͛ϳ͕ϱϯϯ͛ϲ͕ϱϴϲ͛ϲ͕ϱϵϭ͛ϱ͛dǇŽŶĞŬϭϭͬϯϬͬϭϳ/ƐŽůĂƚĞĚ ϲϴͲϬ ϲϴͲϬ ϲϴͲϯ ϲϴͲϯ ϳ͕ϳϳϬ͛ϳ͕ϳϳϱ͛ϲ͕ϴϮϲΖϲ͕ϴϯϬ͛ϱ͛dǇŽŶĞŬϭϭͬϮϵͬϭϳ/ƐŽůĂƚĞĚ ϳ͕ϳϳϬ͛ϳ͕ϳϳϱ͛ϲ͕ϴϮϲΖϲ͕ϴϯϬ͛ϱ͛dǇŽŶĞŬϭϭͬϭϭͬϭϳ/ƐŽůĂƚĞĚ ϳ͕ϴϭϮ͛ϳ͕ϴϭϳ͛ϲ͕ϴϲϳΖϲ͕ϴϳϮ͛ϱ͛dǇŽŶĞŬϭϬͬϮϴͬϭϳ/ƐŽůĂƚĞĚ ϳ͕ϴϰϱ͛ϳ͕ϴϲϬ͛ϲ͕ϵϬϬ͛ϲ͕ϵϭϰ͛ϭϱ͛dǇŽŶĞŬϭϬͬϭϲͬϭϳ/ƐŽůĂƚĞĚ ϳϯͲϱϴ͕ϯϱϱ͛ϴ͕ϯϳϱ͛ϳ͕ϰϬϰ͛ϳ͕ϰϮϰ͛ϮϬ͛dǇŽŶĞŬϵͬϮϴͬϭϳ/ƐŽůĂƚĞĚ ϳϱͲϳϴ͕ϱϯϴ͛ϴ͕ϱϱϴ͛ϳ͕ϱϴϲ͛ϳ͕ϲϬϲ͛ϮϬ͛dǇŽŶĞŬϵͬϭϵͬϭϳ/ƐŽůĂƚĞĚ ϳϳͲϯϴ͕ϱϴϱ͛ϴ͕ϱϵϱΖϳ͕ϲϯϮ͛ϳ͕ϲϰϮ͛ϭϬ͛dǇŽŶĞŬϵͬϭϴͬϭϳ/ƐŽůĂƚĞĚ > h ' :t>Zzd/> EŽ͘ĞƉƚŚ/K/ƚĞŵ ϭϮ͕ϰϵϯ͛ϰͲϭͬϮ͟ǆϮͲϳͬϴ͟ƵĂůŽƌĞWĞƌŵWŬƌ;Θ>Ϳ;ϳͬϮϳͬϮϬͿ ϮϮ͕ϱϬϲ͛ϮͲϳͬϴ͟yͲEŝƉƉůĞ;ϳͬϮϳͬϮϬͿ ϯϮ͕ϱϯϵ͛ϮͲϳͬϴ͟t>';ϳͬϮϳͬϮϬͿ ϯĂцϲ͕Ϭϲϰ͛ϰͲϭͬϮ͟/Wǁͬϯϱ͛ĐĞŵĞŶƚ͖dŽΛцϲ͕ϬϮϵ͛ ϰϲ͕Ϯϳϭ͛ϰͲϭͬϮ͟/Wǁͬϰϰ͛ŽĨĐĞŵĞŶƚͲdKϲ͕ϮϮϳ͛;ϴͬϰͬϮϬͿ ϱϲ͕ϲϬϬ͛Ϯ͘ϯϯ͟ϯ͘ϳϵ͟ϰͲϭͬϮ͟,ĂůůŝďƵƌƚŽŶdtZWĞƌŵĂ^ĞƌŝĞƐWĂĐŬĞƌ ϲϲ͕ϲϭϬ͛Ϯ͘ϯϭϯ͟ϮͲϳͬϴ͟yͲEŝƉƉůĞ ϳϲ͕ϲϮϬ͛Ϯ͘ϰϰϭ͟ϮͲϳͬϴ͟t>' ϴϲ͕ϳϭϬ͛/W;ϭϮͬϮϮͬϭϳͿ ϵϳ͕ϱϮϬ͛/Wǁͬϯϱ͛ŽĨĐĞŵĞŶƚ͗dŽĂƚϳϰϴϱ͛;ϭϮͬϮϭͬϭϳͿ ϭϬϳ͕ϳϲϬ͛/Wǁͬϯϲ͛ĨŝůůΘϯϱ͛ĐĞŵĞŶƚ͗dŽĂƚϳϱϴϵ͛;ϭϭͬϯϬͬϭϳͿ ϭϭϳ͕ϳϵϱ͛/Wǁͬϭϱ͛ĐĞŵĞŶƚ͗dŽĂƚϳϳϴϬ͛;ϭϭͬϬϮͬϭϳͿ ϭϮϳ͕ϴϯϴ͛/WǁͬϮϭ͛ĐĞŵĞŶƚ͗dŽĂƚϳϴϭϳ͛;ϭϬͬϮϴͬϭϳͿ ϭϯϴ͕ϭϲϴ͛/Wǁͬϯϱ͛ŽĨĐŵƚ͖ϱϱ͛ƚŽƚĂů͗dŽĂƚϴϭϭϯ͛;ϭϬͬϮϲͬϭϳͿ ϭϰϴ͕ϱϲϱ͛ϭ͘ϴϳϱ͟ϯ͕ϳϱ͟dƌŝͲWƚDŽĚĞů/ƐŽůĂƚŝŽŶWŬƌϬϴͬϮϴͬϭϳ y y &ŝƐŚ͗ ϲ͕ϯϯϰ͛ʹϮϰ͘ϱ͛Ͳ>ŝŶĞƚŽŽůƐƚƌŝŶŐнϮϭ͛ƐůŝĐŬůŝŶĞƚŽŽůƐƚƌŝŶŐϳͬϮϱͬϮϬ ZΛϮϴϭϳ͛ ZΛϯϴϬϬ͛ ^dEZt>>WZKhZ E/dZK'EKWZd/KE^ ϭϮͬϬϴͬϮϬϭϱ &/E>ǀϭ WĂŐĞϭŽĨϭ ϭ͘Ϳ D/ZhEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚĂŶĚ>ŝƋƵŝĚEŝƚƌŽŐĞŶdƌĂŶƐƉŽƌƚ͘ Ϯ͘Ϳ EŽƚŝĨǇWĂĚKƉĞƌĂƚŽƌŽĨƵƉĐŽŵŝŶŐEŝƚƌŽŐĞŶŽƉĞƌĂƚŝŽŶƐ͘ ϯ͘Ϳ WĞƌĨŽƌŵWƌĞͲ:Žď^ĂĨĞƚǇDĞĞƚŝŶŐ͘ZĞǀŝĞǁEŝƚƌŽŐĞŶǀĞŶĚŽƌƐƚĂŶĚĂƌĚŽƉĞƌĂƚŝŶŐƉƌŽĐĞĚƵƌĞƐĂŶĚ ĂƉƉƌŽƉƌŝĂƚĞ^ĂĨĞƚǇĂƚĂ^ŚĞĞƚƐ;ĨŽƌŵĞƌůǇD^^Ϳ͘ ϰ͘Ϳ ŽĐƵŵĞŶƚ ŚĂǌĂƌĚƐ ĂŶĚ ŵŝƚŝŐĂƚŝŽŶ ŵĞĂƐƵƌĞƐ ĂŶĚ ĐŽŶĨŝƌŵ ĨůŽǁ ƉĂƚŚƐ͘ /ŶĐůƵĚĞ ƌĞǀŝĞǁ ŽŶ ĂƐƉŚǇǆŝĂƚŝŽŶĐĂƵƐĞĚ ďǇ ŶŝƚƌŽŐĞŶĚŝƐƉůĂĐŝŶŐŽǆǇŐĞŶ͘DŝƚŝŐĂƚŝŽŶŵĞĂƐƵƌĞƐŝŶĐůƵĚĞĂƉƉƌŽƉƌŝĂƚĞ ƌŽƵƚŝŶŐŽĨĨůŽǁůŝŶĞƐ͕ĂĚĞƋƵĂƚĞǀĞŶƚŝŶŐĂŶĚĂƚŵŽƐƉŚĞƌŝĐŵŽŶŝƚŽƌŝŶŐ͘ ϱ͘Ϳ ^ƉŽƚWƵŵƉŝŶŐhŶŝƚĂŶĚdƌĂŶƐƉŽƌƚ͘ŽŶĨŝƌŵůŝƋƵŝĚEϮǀŽůƵŵĞƐŝŶƚƌĂŶƐƉŽƌƚ͘ ϲ͘Ϳ ZŝŐƵƉůŝŶĞƐĨƌŽŵƚŚĞEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚƚŽƚŚĞǁĞůůĂŶĚƌĞƚƵƌŶƐƚĂŶŬ͘^ĞĐƵƌĞůŝŶĞƐǁŝƚŚǁŚŝƉ ĐŚĞĐŬƐ͘ ϳ͘Ϳ WůĂĐĞ ƐŝŐŶƐ ĂŶĚ ƉůĂĐĂƌĚƐ ǁĂƌŶŝŶŐ ŽĨ ŚŝŐŚ ƉƌĞƐƐƵƌĞ ĂŶĚ ŶŝƚƌŽŐĞŶ ŽƉĞƌĂƚŝŽŶƐ Ăƚ ĂƌĞĂƐ ǁŚĞƌĞ EŝƚƌŽŐĞŶŵĂǇĂĐĐƵŵƵůĂƚĞŽƌďĞƌĞůĞĂƐĞĚ͘ ϴ͘Ϳ WůĂĐĞƉƌĞƐƐƵƌĞŐĂƵŐĞƐĚŽǁŶƐƚƌĞĂŵŽĨůŝƋƵŝĚĂŶĚŶŝƚƌŽŐĞŶƉƵŵƉƐƚŽĂĚĞƋƵĂƚĞůǇŵĞĂƐƵƌĞƚƵďŝŶŐ ĂŶĚĐĂƐŝŶŐƉƌĞƐƐƵƌĞƐ͘ ϵ͘Ϳ WůĂĐĞƉƌĞƐƐƵƌĞŐĂƵŐĞƐƵƉƐƚƌĞĂŵĂŶĚĚŽǁŶƐƚƌĞĂŵŽĨĂŶǇĐŚĞĐŬǀĂůǀĞƐ͘ ϭϬ͘Ϳ tĞůůƐŝƚĞDĂŶĂŐĞƌƐŚĂůůǁĂůŬĚŽǁŶǀĂůǀĞĂůŝŐŶŵĞŶƚƐĂŶĚĞŶƐƵƌĞǀĂůǀĞƉŽƐŝƚŝŽŶŝƐĐŽƌƌĞĐƚ͘ ϭϭ͘Ϳ ŶƐƵƌĞƉŽƌƚĂďůĞϰͲŐĂƐĚĞƚĞĐƚŝŽŶĞƋƵŝƉŵĞŶƚŝƐŽŶƐŝƚĞ͕ĐĂůŝďƌĂƚĞĚ͕ĂŶĚďƵŵƉƚĞƐƚĞĚƉƌŽƉĞƌůǇƚŽ ĚĞƚĞĐƚ>>ͬ,Ϯ^ͬKϮͬKϮůĞǀĞůƐ͘ŶƐƵƌĞEŝƚƌŽŐĞŶǀĞŶĚŽƌŚĂƐĂǁŽƌŬŝŶŐĂŶĚĐĂůŝďƌĂƚĞĚĚĞƚĞĐƚŽƌĂƐ ǁĞůůƚŚĂƚŵĞĂƐƵƌĞƐKϮůĞǀĞůƐ͘ ϭϮ͘Ϳ WƌĞƐƐƵƌĞƚĞƐƚůŝŶĞƐƵƉƐƚƌĞĂŵŽĨǁĞůůƚŽĂƉƉƌŽǀĞĚƐƵŶĚƌǇƉƌĞƐƐƵƌĞŽƌDW^W;DĂǆŝŵƵŵWŽƚĞŶƚŝĂů ^ƵƌĨĂĐĞWƌĞƐƐƵƌĞͿ͕ǁŚŝĐŚĞǀĞƌŝƐŚŝŐŚĞƌ͘dĞƐƚůŝŶĞƐĚŽǁŶƐƚƌĞĂŵŽĨǁĞůů;ĨƌŽŵǁĞůůƚŽƌĞƚƵƌŶƐƚĂŶŬͿ ƚŽϭ͕ϱϬϬƉƐŝ͘WĞƌĨŽƌŵǀŝƐƵĂůŝŶƐƉĞĐƚŝŽŶĨŽƌĂŶǇůĞĂŬƐ͘ ϭϯ͘Ϳ ůĞĞĚŽĨĨƚĞƐƚƉƌĞƐƐƵƌĞĂŶĚƉƌĞƉĂƌĞĨŽƌƉƵŵƉŝŶŐŶŝƚƌŽŐĞŶ͘ ϭϰ͘Ϳ WƵŵƉŶŝƚƌŽŐĞŶĂƚĚĞƐŝƌĞĚƌĂƚĞ͕ŵŽŶŝƚŽƌŝŶŐƌĂƚĞ;^&DͿĂŶĚƉƌĞƐƐƵƌĞ;W^/Ϳ͘ůůŶŝƚƌŽŐĞŶƌĞƚƵƌŶƐ ĂƌĞƚŽďĞƌŽƵƚĞĚƚŽƚŚĞƌĞƚƵƌŶƐƚĂŶŬ͘ ϭϱ͘Ϳ tŚĞŶĨŝŶĂůŶŝƚƌŽŐĞŶǀŽůƵŵĞŚĂƐďĞĞŶĂĐŚŝĞǀĞĚ͕ŝƐŽůĂƚĞǁĞůůĨƌŽŵEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚĂŶĚ ďůĞĞĚĚŽǁŶůŝŶĞƐďĞƚǁĞĞŶǁĞůůĂŶĚEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚ͘ ϭϲ͘Ϳ KŶĐĞǇŽƵŚĂǀĞĐŽŶĨŝƌŵĞĚůŝŶĞƐĂƌĞďůĞĚĚŽǁŶ͕ŶŽƚƌĂƉƉĞĚƉƌĞƐƐƵƌĞĞǆŝƐƚƐ͕ĂŶĚŶŽŶŝƚƌŽŐĞŶŚĂƐ ĂĐĐƵŵƵůĂƚĞĚďĞŐŝŶƌŝŐĚŽǁŶŽĨůŝŶĞƐĨƌŽŵƚŚĞEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚ͘ ϭϳ͘Ϳ &ŝŶĂůŝǌĞũŽďůŽŐĂŶĚĚŝƐĐƵƐƐŽƉĞƌĂƚŝŽŶƐǁŝƚŚtĞůůƐŝƚĞDĂŶĂŐĞƌ͘ŽĐƵŵĞŶƚĂŶǇůĞƐƐŽŶƐůĞĂƌŶĞĚ ĂŶĚĐŽŶĨŝƌŵĨŝŶĂůƌĂƚĞƐͬƉƌĞƐƐƵƌĞͬǀŽůƵŵĞƐŽĨƚŚĞũŽďĂŶĚƌĞŵĂŝŶŝŶŐŶŝƚƌŽŐĞŶŝŶƚŚĞƚƌĂŶƐƉŽƌƚ͘ ϭϴ͘Ϳ ZDKEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚĂŶĚ>ŝƋƵŝĚEŝƚƌŽŐĞŶdƌĂŶƐƉŽƌƚ͘ Kaitlyn Barcelona Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: Date: 07/11/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL Well API # PTD # Log Date Log Company Log Type Notes BCU 18RD 50133205840100 222033 6/11/2022 Yellowjacket GPT-PERF + Report BCU 18RD 50133205840100 222033 6/18/2022 Yellowjacket GPT-PERF + Report BCU 18RD 50133205840100 222033 6/7/2022 Yellowjacket GPT-PLUG + Report BCU 24 50133206390000 214112 6/16/2022 Halliburton PPROF BCU 24 50133206390000 214112 5/23/2022 Yellowjacket GPT-PERF + Report BCU 24 50133206390000 214112 5/26/2022 Yellowjacket GPT-PERF + Report BCU 7A 50133202840100 214060 6/21/2022 Yellowjacket CBL BCU 7A 50133202840100 214060 6/15/2022 Yellowjacket GAMMA RAY + Report BRU 232-26 50283200770000 184138 5/25/2022 Yellowjacket CBL CLU 01RD 50133203230100 203129 5/19/2022 Yellowjacket PERF + Report CLU 01RD 50133203230100 203129 5/24/2022 Yellowjacket PERF + Report CLU 09 50133205440000 204161 5/27/2022 Yellowjacket PERF + Report CLU-1RD 50133203230100 203129 5/28/2022 Halliburton PPROF + Report END 1-17A 50029221000100 196199 5/26/2022 Halliburton LDL END 1-45 50029219910000 189124 5/23/2022 Halliburton LDL + Report END 3-17F 50029219460600 203216 6/15/2022 AK E-Line PLUG CUT FALLS CREEK 3 50133205240000 203102 6/4/2022 Yellowjacket PERF + Report HVB B-16 50231200400000 212133 6/14/2022 AK E-Line CIBP KALOTSA 1 50133206570000 216132 7/7/2022 Yellowjacket PERF + Report KBU 11-07 50133205560000 205165 6/16/2022 Yellowjacket GPT-PERF + Report KBU 11-07 50133205560000 205165 6/20/2022 Yellowjacket GPT-PERF + Report KBU 33-06X 50133205290000 203183 6/22/2022 Yellowjacket CBL MPU B-28 50029235660000 216027 5/27/2022 Halliburton LDL MPU B-28 50029235660000 216027 5/27/2022 Halliburton MFC + Report MPU B-30 50029235710000 216153 5/18/2022 Halliburton PERF MPU E-06 50029221540000 191048 5/28/2022 Halliburton MFC + Report Kaitlyn Barcelona Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: MPU E-35 50029236150000 218152 6/15/2022 Halliburton MFC + Report MPU L-50 50029235550000 215132 6/24/2022 Read COIL FLAG PAXTON 10 50133206910000 220064 5/27/2022 Halliburton PPROF + Report PBU C-24B 50029208160200 212063 5/28/2022 Halliburton PPROF + Report PBU C-24B 50029208160200 212063 5/28/2022 Halliburton RBT PBU GNI-03 50029228200000 197189 6/25/2022 Read CALIPER PBU GNI-03 50029228200000 197189 6/25/2022 Read TEMP-PRESS PBU K-01 50029209980000 183121 6/21/2022 Halliburton PPROF + Report PBU M-13A 50029205220100 201165 5/27/2022 Halliburton TMD3D-WFL + Report PBU NGI-05 50029201960000 176014 6/7/2022 Halliburton CAST PBU W-01A 50029218660100 203176 6/8/2022 Halliburton RBT SRU 241-33 50133206630000 217047 6/13/2022 Yellowjacket PERF SRU 241-33B 50133206960000 221053 5/25/2022 Halliburton TEMP-PRESS SRU 32A-33 50133101640100 191014 6/11/2022 AK E-Line PPROF Please include current contact information if different from above. BCU 18RD PTD:222-033 T36747 BCU 24 PTD:214-112 T36748 BCU 7A PTD:214-060 T36749 BRU 232-26 PTD:184-138 T36750 CLU 01RD PTD:203-129 T36751 CLU 09 PTD: 204-161 T36752 CLU1RD PTD:203-129 T36751 END 1-17A PTD:196-199 T36753 END 1-45 PTD:189-124 T36754 END 3-17F PTD:203-216 T36755 Falls Creek 3 PTD:203-102 T36756 HVB B-16 PTD:212-133 T36757 Kalosta 1 PTD:216-132 T36758 KBU 11-7 PTD:205-165 T36759 KBU 33-06X PTD:203-183 T36760 MPU B-28 PTD:216-027 T36761 MPU B-30 PTD:216-153 T36762 MPU E-06 PTD: 191-048 T36763 MPU E-35 PTD:218-152 T36764 MPU L-50 PTD:215-132 T36765 Paxton 10 PTD:220-064 T36766 PBU C-24B PTD:212-063 T36767 PBU GNI-03 PTD:197-189 T36768 PBU K-01 PTD:183-121 T36769 PBU M-13A PTD:201-165 T36770 PBU NGI-05 PTD:176-014 T36771 PBU W-01A PTD:203-176 T36772 SRU 241-33 PTD:217-047 T36773 SRU 241-33B PTD:221-053 T36774 SRU 32A-33 PTD: 191-014 T36775 Kayla Junke Digitally signed by Kayla Junke Date: 2022.07.12 12:56:51 -08'00' 7\SHRI5HTXHVW $EDQGRQ 3OXJ3HUIRUDWLRQV )UDFWXUH6WLPXODWH 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dсϴ͕ϲϯϬ͛ͬdsсϳ͕ϲϳϳ͛ Z<ƚŽ'>сϭϭ͛ ϭ Ϯ ϯ ϭϰ ϭϯ ϭϮ ϭϭ ϭϬ ϵ ϴ ϱ ϲ ϳ ϰ ϳ͟ KWE,K>ͬDEdd/> ϳΗ ϴͲϭͬϮ͟ŚŽůĞ͗WƵŵƉĞĚϴϴďďůƐϭϮ͘ϬƉƉŐdǇƉĞ/ͬ//ůĞĂĚĐĞŵĞŶƚĨŽůůŽǁĞĚďǇϮϮďďůƐϭϱ͘ϰƉƉŐĐůĂƐƐ' ƚĂŝůĐĞŵĞŶƚ͘ʹϮϯ>ƐĞŵĞŶƚƚŽ^ƵƌĨĂĐĞ ϰͲϭͬϮ͟ ϲͲϭͬϴ͟ŚŽůĞ͗WƵŵƉĞĚϭϲϲďďůƐϭϮ͘ϴƉƉŐdǇƉĞ/ͬ//ůĞĂĚĐĞŵĞŶƚĨŽůůŽǁĞĚďǇϮϳďďůƐϭϱ͘ϯƉƉŐĐůĂƐƐ 'ƚĂŝůĐĞŵĞŶƚʹϭϯďďůƐďĂĐŬƚŽƐƵƌĨĂĐĞ͘ϭϬͬϮϮͬϮϬ>ƐŚŽǁĞĚdŽĂƚϭϰϰϬ͛DĂĨƚĞƌϰĚĂǇƐŽĨ ĐĞŵĞŶƚĐƵƌĞ͘ϴͬϯͬϭϳ>ĐŽŶĨŝƌŵƐdŽĂƚƐƵƌĨĂĐĞ͘ ϭϲ͟ ϰͲϭͬϮ͟ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘ / dŽƉ ƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌʹƌŝǀĞŶ ƚŽ^ĞƚĞƉƚŚ ϴϰ yͲϱϲ tĞůĚ ϭϱ͘Ϭϭ͟ ^ƵƌĨ ϭϮϬΖ ϳΗ ^ƵƌĨƐŐ Ϯϲ >ͲϴϬ dͬD ϲ͘ϴϳϱ͟ ^ƵƌĨ Ϯ͕ϬϬϱ͛ ϰͲϭͬϮΗ WƌŽĚƐŐ ϭϮ͘ϲ >ͲϴϬ dyW ϯ͘ϵϱϴ͟ ^ƵƌĨ ϴ͕ϲϮϱ͚ dh/E'd/> ϮͲϳͬϴ͟ WƌŽĚƵĐƚŝŽŶ ϲ͘ϰ >ͲϴϬ &:ϯ Ϯ͘ϰϰϭ͟ ^ƵƌĨ Ϯ͕ϱϯϴ͛ ZΛϮ͕ϴϭϳ͛ ZΛϯ͕ϴϬϬ͛ ZΛϲ͕ϬϬϲ͛ ZΛϴ͕ϰϭϱ͛ WZ&KZd/KEd/> ^ĂŶĚƐ dŽƉ ;DͿ ƚŵ ;DͿ dŽƉ ;dsͿ ƚŵ ;dsͿ &d WŽŽů ĂƚĞ ^ƚĂƚƵƐ >ϱϭͲϳ ϲ͕ϭϭϰ͛ ϲ͕ϭϮϭ͛ ϱ͕Ϯϰϰ͛ ϱ͕ϮϱϬ͛ ϳ͛ ĞůƵŐĂ ϵͬϮϴͬϮϭ KƉĞŶ >ϱϮͲϵDŝĚĚůĞ ϲ͕ϭϳϭ͛ ϲ͕ϭϳϱ͛ ϱ͕Ϯϵϰ͛ ϱ͕Ϯϵϴ͛ ϰ͛ ĞůƵŐĂ ϵͬϮϴͬϮϭ KƉĞŶ >ͺhͺϱϮͲϵ ϲ͕ϭϵϱ͛ ϲ͕ϮϬϱ͛ ϱ͕ϯϭϱ͛ ϱ͕ϯϮϱ͛ ϭϬ͛ ĞůƵŐĂ ϴͬϭϱͬϮϬ KƉĞŶ ϱϲͲϵ ϲ͕ϲϱϴΖ ϲ͕ϲϳϴΖ ϱ͕ϱϰϭΖ ϱ͕ϱϲϬΖ ϮϬ͛dǇŽŶĞŬ ϭϮͬϮϮͬϭϳ /ƐŽůĂƚĞĚ ϲ͕ϲϴϰΖ ϲ͕ϲϵϲΖ ϱ͕ϳϲϱΖ ϱ͕ϳϳϳΖ ϭϮ͛dǇŽŶĞŬ ϭϮͬϮϮͬϭϳ /ƐŽůĂƚĞĚ ϲ͕ϳϭϱ͛ϲ͕ϳϯϬ͛ϱ͕ϳϵϱ͛ϱ͕ϴϬϵ͛ϭϱ͛dǇŽŶĞŬ ϭϮͬϭϴͬϭϳ /ƐŽůĂƚĞĚ ϲϱͲϱ ϳ͕ϱϮϳ͛ϳ͕ϱϰϳ͛ϲ͕ϱϴϱ͛ϲ͕ϲϬϱ͛ϮϬ͛dǇŽŶĞŬ ϭϮͬϭϬͬϭϳ /ƐŽůĂƚĞĚ ϳ͕ϱϮϴ͛ϳ͕ϱϯϯ͛ϲ͕ϱϴϲ͛ϲ͕ϱϵϭ͛ϱ͛dǇŽŶĞŬ ϭϭͬϯϬͬϭϳ /ƐŽůĂƚĞĚ ϲϴͲϬ ϲϴͲϬ ϲϴͲϯ ϲϴͲϯ ϳ͕ϳϳϬ͛ϳ͕ϳϳϱ͛ϲ͕ϴϮϲΖ ϲ͕ϴϯϬ͛ϱ͛dǇŽŶĞŬ ϭϭͬϮϵͬϭϳ /ƐŽůĂƚĞĚ ϳ͕ϳϳϬ͛ϳ͕ϳϳϱ͛ϲ͕ϴϮϲΖ ϲ͕ϴϯϬ͛ϱ͛dǇŽŶĞŬ ϭϭͬϭϭͬϭϳ /ƐŽůĂƚĞĚ ϳ͕ϴϭϮ͛ϳ͕ϴϭϳ͛ϲ͕ϴϲϳΖ ϲ͕ϴϳϮ͛ϱ͛dǇŽŶĞŬ ϭϬͬϮϴͬϭϳ /ƐŽůĂƚĞĚ ϳ͕ϴϰϱ͛ϳ͕ϴϲϬ͛ϲ͕ϵϬϬ͛ϲ͕ϵϭϰ͛ϭϱ͛dǇŽŶĞŬ ϭϬͬϭϲͬϭϳ /ƐŽůĂƚĞĚ ϳϯͲϱ ϴ͕ϯϱϱ͛ϴ͕ϯϳϱ͛ϳ͕ϰϬϰ͛ϳ͕ϰϮϰ͛ϮϬ͛dǇŽŶĞŬ ϵͬϮϴͬϭϳ /ƐŽůĂƚĞĚ ϳϱͲϳ ϴ͕ϱϯϴ͛ϴ͕ϱϱϴ͛ϳ͕ϱϴϲ͛ϳ͕ϲϬϲ͛ϮϬ͛dǇŽŶĞŬ ϵͬϭϵͬϭϳ /ƐŽůĂƚĞĚ ϳϳͲϯ ϴ͕ϱϴϱ͛ϴ͕ϱϵϱΖ ϳ͕ϲϯϮ͛ϳ͕ϲϰϮ͛ϭϬ͛dǇŽŶĞŬ ϵͬϭϴͬϭϳ /ƐŽůĂƚĞĚ ϲϱͲϱ ϲϴͲϬ ϲϴͲϯ ϳϯͲϱ ϳϱͲϳ ϳϳͲϯ EŽ͘ ĞƉƚŚ / /ƚĞŵ ϭ Ϯ͕ϰϵϯ͛ Ϯ͘ϯϵϬ͟ ϰͲϭͬϮ͟ǆϮͲϳͬϴ͟ ƵĂůŽƌĞWĞƌŵWŬƌ;Θ>ͿϳͬϮϳͬϮϬ Ϯ Ϯ͕ϱϬϲ͛ Ϯ͘ϯϭϯ͟ ϮͲϳͬϴ͟yͲEŝƉƉůĞϳͬϮϳͬϮϬ ϯ Ϯ͕ϱϯϵ͛ Ϯ͘ϰϰϭ͟ ϮͲϳͬϴ͟t>'ϳͬϮϳͬϮϬ ϰ ϲ͕Ϯϳϭ͛ ϰͲϭͬϮ͟/Wǁͬϰϰ͛ŽĨĐĞŵĞŶƚ͕dKϲ͕ϮϮϳ͛ ϴͬϰͬϮϬ ϱ ϲ͕ϲϬϬ͛Ϯ͘ϯϯ͟ϰͲϭͬϮ͟,ĂůůŝďƵƌƚŽŶdtZWĞƌŵĂ^ĞƌŝĞƐWĂĐŬĞƌ ϲ ϲ͕ϲϭϬ͛Ϯ͘ϯϭϯ͟ϮͲϳͬϴ͟yͲEŝƉƉůĞ ϳ ϲ͕ϲϮϬ͛Ϯ͘ϰϰϭ͟ϮͲϳͬϴ͟t>' ϴ ϲ͕ϳϭϬ͛/WϭϮͬϮϮͬϭϳ ϵ ϳ͕ϱϮϬ͛/Wǁͬϯϱ͛ŽĨĐĞŵĞŶƚϭϮͬϮϭͬϭϳ ϭϬ 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&ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ϱϭͲϭ цϱ͕ϴϭϴ͛ цϱ͕ϴϮϭ͛ цϰ͕ϵϵϮ͛ цϰ͕ϵϵϱ͛ цϯ͛ ĞůƵŐĂ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ϱϭͲϭ цϱ͕ϴϱϰ͛ цϱ͕ϴϱϴ͛ цϱ͕ϬϮϮ͛ цϱ͕ϬϮϱ͛ цϰ͛ ĞůƵŐĂ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ϱϭͲϭ цϱ͕ϴϲϴ͛ цϱ͕ϴϳϭ͛ цϱ͕Ϭϯϰ͛ цϱ͕Ϭϯϳ͛ цϯ͛ ĞůƵŐĂ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ϱϭͲϮ цϱ͕ϴϴϳ͛ цϱ͕ϴϵϬ͛ цϱ͕Ϭϰϵ͛ цϱ͕ϬϱϮ͛ цϯ͛ ĞůƵŐĂ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ϱϭͲϮ цϱ͕ϴϵϴ͛ цϱ͕ϵϬϭ͛ цϱ͕Ϭϱϵ͛ цϱ͕ϬϲϮ͛ цϯ͛ ĞůƵŐĂ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ϱϭͲϯ цϱ͕ϵϯϲ͛ цϱ͕ϵϯϵ͛ цϱ͕ϬϵϬ͛ цϱ͕ϬϵϮ͛ цϯ͛ ĞůƵŐĂ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ϱϭͲϯ цϱ͕ϵϰϲ͛ цϱ͕ϵϱϯ͛ цϱ͕Ϭϵϵ͛ цϱ͕ϭϬϱ͛ цϳ͛ ĞůƵŐĂ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ϱϭͲϯ цϱ͕ϵϲϱ͛ цϱ͕ϵϲϴ͛ цϱ͕ϭϭϱ͛ цϱ͕ϭϭϴ͛ цϯ͛ ĞůƵŐĂ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ϱϭͲϳ ϲ͕ϭϭϰ͛ ϲ͕ϭϮϭ͛ ϱ͕Ϯϰϰ͛ ϱ͕ϮϱϬ͛ ϳ͛ ĞůƵŐĂ ϵͬϮϴͬϮϭ KƉĞŶ >ϱϭͲϳ цϲ͕ϭϮϯ͛ цϲ͕ϭϮϲ͛ цϱ͕ϮϱϮ͛ цϱ͕Ϯϱϰ͛ цϯ͛ ĞůƵŐĂ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ϱϮͲϵDŝĚĚůĞ ϲ͕ϭϳϭ͛ ϲ͕ϭϳϱ͛ ϱ͕Ϯϵϰ͛ ϱ͕Ϯϵϴ͛ ϰ͛ ĞůƵŐĂ ϵͬϮϴͬϮϭ KƉĞŶ >ϱϮͲϵ цϲ͕ϭϴϱ͛ цϲ͕ϭϴϵ͛ цϱ͕ϯϬϲ͛ цϱ͕ϯϬϵ͛ цϰΖ ĞůƵŐĂ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ >ͺhͺϱϮͲϵ ϲ͕ϭϵϱ͛ ϲ͕ϮϬϱ͛ ϱ͕ϯϭϱ͛ ϱ͕ϯϮϱ͛ ϭϬ͛ ĞůƵŐĂ ϴͬϭϱͬϮϬ KƉĞŶ ϱϲͲϵ ϲ͕ϲϱϴΖ ϲ͕ϲϳϴΖ ϱ͕ϱϰϭΖ ϱ͕ϱϲϬΖ ϮϬ͛dǇŽŶĞŬ ϭϮͬϮϮͬϭϳ /ƐŽůĂƚĞĚ ϲ͕ϲϴϰΖ ϲ͕ϲϵϲΖ ϱ͕ϳϲϱΖ ϱ͕ϳϳϳΖ ϭϮ͛dǇŽŶĞŬ ϭϮͬϮϮͬϭϳ /ƐŽůĂƚĞĚ ϲ͕ϳϭϱ͛ϲ͕ϳϯϬ͛ϱ͕ϳϵϱ͛ϱ͕ϴϬϵ͛ϭϱ͛dǇŽŶĞŬ ϭϮͬϭϴͬϭϳ 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ϭϰϴ͕ϱϲϱ͛ϭ͘ϴϳϱ͟ϯ͕ϳϱ͟dƌŝͲWƚDŽĚĞů/ƐŽůĂƚŝŽŶWŬƌϬϴͬϮϴͬϭϳ y dKϴ͕ϭϭϯ͛ dKϳ͕ϴϭϳ͛ dKϳ͕ϳϴϬ͛ ϱϲͲϵ dKϳ͕ϰϴϱ͛ dKϳ͕ϱϴϵ͛ >ͺhͺϱϮͲϵ y &ŝƐŚ͗ ϲ͕ϯϯϰ͛ʹϮϰ͘ϱ͛Ͳ>ŝŶĞƚŽŽůƐƚƌŝŶŐнϮϭ͛ƐůŝĐŬůŝŶĞƚŽŽůƐƚƌŝŶŐϳͬϮϱͬϮϬ dK&ϲ͕ϯϯϰ͛ ϳͬϮϱͬϮϬ >ϱϭͲϳ >ϱϮͲϵ >ϱϭͲϳϲ͕ϭϭϰ͛ϲ͕ϭϮϭ͛ϱ͕Ϯϰϰ͛ϱ͕ϮϱϬ͛ϳ͛ϵͬϮϴͬϮϭKƉĞŶ >ϱϮͲϵDŝĚĚůĞϲ͕ϭϳϭ͛ϲ͕ϭϳϱ͛ϱ͕Ϯϵϰ͛ϱ͕Ϯϵϴ͛ϰ͛ϵͬϮϴͬϮϭKƉĞŶ Ɖ Ɖ 6,120' SFD Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/25/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL SRU 241-33 (PTD 217-047) Perforation Record 09/28/2021 Please include current contact information if different from above. 10/26/2021 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: Install Upper Completion, N2 2. Operator Name:4. Current Well Class:5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? W ill planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): Swanson River - Sterling/U Beluga, Beluga, and Tyonek Gas Pools 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 8,630'N/A Casing Collapse Structural Conductor Surface 5,410 psi Intermediate Production 7,500 psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: 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 Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: September 6, 2021 2-7/8" 8,625' Perforation Depth MD (ft): See Attached Schematic 8,625'7,672'4-1/2" 16" 7" 120' 2,005'7,240 psi 120' 1,986' 120' 2,005' L-80 TVD Burst 2538' 8,430 psi MDLengthSize CO 716 Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 A028399; A028406 217-047 50-133-20663-00-00 Swanson River Unit (SRU) 241-33 COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic jake.flora@hilcorp.com 7,677'7,760'6,816'~ 1,864 psi See Attached Schematic Model D PKR, Packer w/ Snap Latch Assy; Perm Dual Bore PKR 8,565' MD & 7,612' TVD, 6,600' MD & 5,483'TVD; 2493' MD, 2350' TVD Perforation Depth TVD (ft):Tubing Size: m n s 2 6 5 6 meeentntntntntnntntntnnnnnnn c Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 1:31 pm, Aug 23, 2021 321-416 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.08.23 13:09:52 -08'00' Taylor Wellman (2143) CO 716.001 and SFD 8/24/2021 DSR-8/23/21SFD 8/24/2021BJM 9/1/21 bjm 10-404 dts 9/1/2021 JLC 9/2/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.09.02 10:22:45 -08'00' RBDMS HEW 9/3/2021 Well Prognosis Well: SRU 241-33 Date: 08/23/2020 Well Name: SRU 241-33 API Number: 50-133-20663-00-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: 09/06/2021 Rig: E-Line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 217-047 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: ~2,400 psi @ 5299’ TVD (Overburden gradient to base of new perfs) Max. Potential Surface Pressure: ~1,870 psi (Max expected BHP + gas to surface) Well Status: Online (878 MCFD / 0% WC / 773#) Brief Well Summary: SRU 241-33 was drilled and completed in July 2017 as a grass roots development well targeting gas sands in the Sterling and Tyonek formation. Multiple zones and sands were perforated in September, October, November and December 2017 when the Tyonek 56-9 was shot and commercial rates came online. This zone was prolific, cum’ing 2.5+ BCF in just over two years. Once the 56-9 tank depleted, it was plugged back and the 52-9 was shot. It, too, came on very strong – 2.4MMCFD – and has produced nicely since August 2020. The LB 52-9 has been on a steady, although not unusual, decline and has now reached a sufficiently low rate that it is time to commingle it with a few up-hole sands. Objective: The purpose of this work/sundry is to add rate by perforating multiple Beluga sands while flowing. Notes Regarding Wellbore Condition: 7/23/2021 Drifted w/ 1.75” GR to 6229’, POOH E-line Procedure 1. MIRU E-Line Unit and pressure control equipment. PT lubricator to 250 psi Low / 3,000 psi High. 2. RU perf guns. 3. RIH and perforate the below intervals bottom up while flowing: Sand TOP MD BOT MD Total TOP TVD BOT TVD Pool Order to Shoot Est Pressure LB 51-2_Mid 5886 5892 6 5049 5054 Beluga 6 2282 LB 51-2_Lwr 5896 5903 7 5057 5063 Beluga 5 2286 LB 51-3_Mid_1 5935 5940 5 5090 5094 Beluga 4 2301 LB 51-3_Mid_2 5943 5953 10 5097 5105 Beluga 3 2304 LB 51-7 6112 6121 9 5242 5250 Beluga 2 2369 LB 52-9 Middle 6169 6176 7 5293 5299 Beluga 1 2392 Beluga LB 52-9 Middle Beluga add rate by perforating multiple Beluga sands while flowing. Well Prognosis Well: SRU 241-33 Date: 08/23/2020 a. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. b. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. c. Use Gamma/CCL to correlate. d. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. e. All perforations in the table above are located in the Beluga-Tyonek Gas Pool based on Conservation Order 701C. E-Line Procedure (Contingency) 1.If any zone produces sand and/or water and needs to be isolated: 2. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 3,000 psi High. 3. RIH and set 2-7/8” Casing Patch or set 2-7/8” CIBP above the zone and dump 25’ of cement on top of the plug. Attachments 1. Current Well Schematic 2. Proposed Well Schematic Updated By DMA 08-31-20 SCHEMATIC Swanson River Unit Well SRU #241-33 PTD: 217-047 API: 50-133-20663-00-00 PBTD = 6,227’ / PBTVD = 5,344’ TD = 8,630’ / TVD = 7,677’ RKB to GL = 11’ 1 2 3 14 13 12 11 10 9 8 5 6 7 4 16” 7” 4-1/2” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7" Surf Csg 26 L-80 BTC/M 6.875” Surf 2,005’ 4-1/2" Prod Csg 12.6 L-80 TXP 3.958” Surf 8,625‘ TUBING DETAIL 2-7/8” Production 6.4 L-80 FJ3 2.375” Surf 2,538’ RA @ 2,817’ RA @ 3,800’ RA @ 6,006’ RA @ 8,415’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status BEL_UB_52-9 6,195’ 6,205’ 5,315’ 5,325’ 10’ 8/15/20 Open 56-9 6,658' 6,678' 5,541' 5,560' 20’ 12/22/17 Isolated 6,684' 6,696' 5,765' 5,777' 12’ 12/22/17 Isolated 6,715’ 6,730’ 5,795’ 5,809’ 15’ 12/18/17 Isolated 65-5 7,527’ 7,547’ 6,585’ 6,605’ 20’ 12/10/17 Isolated 7,528’ 7,533’ 6,586’ 6,591’ 5’ 11/30/17 Isolated 68-0 68-0 68-3 68-3 7,770’ 7,775’ 6,826' 6,830’ 5’ 11/29/17 Isolated 7,770’ 7,775’ 6,826' 6,830’ 5’ 11/11/17 Isolated 7,812’ 7,817’ 6,867' 6,872’ 5’ 10/28/17 Isolated 7,845’ 7,860’ 6,900’ 6,914’ 15’ 10/16/17 Isolated 73-5 8,355’ 8,375’ 7,404’ 7,424’ 20’ 9/28/17 Isolated 75-7 8,538’ 8,558’ 7,586’ 7,606’ 20’ 9/19/17 Isolated 77-3 8,585’ 8,595' 7,632’ 7,642’ 10’ 9/18/17 Isolated 65-5 68-0 68-3 73-5 75-7 77-3 JEWELRY DETAIL No. Depth ID OD Item 1 2,493’ 4-1/2” x 2-7/8” Dual Bore Perm Pkr (D&L) 7/27/20 2 2,506’ 2-7/8” X-Nipple 7/27/20 3 2,539’ 2-7/8” WLEG 7/27/20 4 6,271’ 4-1/2” CIBP w/ 44’ of cement, TOC 6,227’ 8/4/20 5 6,600’ 2.33” 3.79” 4-1/2” Halliburton TWR Perma Series Packer 6 6,610’ 2.313” 2-7/8” X-Nipple 7 6,620’ 2.441” 2-7/8” WLEG 8 6,710’ CIBP 12/22/17 9 7,520’ CIBP w/ 35’ of cement 12/21/17 10 7,760’ CIBP w/ 36’ fill & 35’ cement 11/30/17 11 7,795’ CIBP w / 15’ cement 11/02/17 12 7,838’ CIBP w/ 21’ cement 10/28/17 13 8,168’ CIBP w/ 35’ of cement; 55’ total 10/26/17 14 8,565’ 1.875” 3,75” Tri-Pt Model D Isolation Pkr 08/28/17 X TOC 8,113’ TOC 7,817’ TOC 7,780’ 56-9 TOC 7,485’ TOC 7,589’ BEL_UB_52-9 X Fish: 6,334’ – 24.5’ E-Line toolstring + 21’ slickline toolstring 7/25/20 TOF 6,334’ 7/25/20 Updated By JMF 08-05-21 PROPOSED SCHEMATIC Swanson River Unit Well SRU #241-33 PTD: 217-047 API: 50-133-20663-00-00 PBTD = 6,227’ / PBTVD = 5,344’ TD = 8,630’ / TVD = 7,677’ RKB to GL = 11’ 1 2 3 14 13 12 11 10 9 8 5 6 7 4 16” 7” 4-1/2” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7" Surf Csg 26 L-80 BTC/M 6.875” Surf 2,005’ 4-1/2" Prod Csg 12.6 L-80 TXP 3.958” Surf 8,625‘ TUBING DETAIL 2-7/8” Production 6.4 L-80 FJ3 2.375” Surf 2,538’ RA @ 2,817’ RA @ 3,800’ RA @ 6,006’ RA @ 8,415’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status LB 51-2 Middle 5886 5892 5049 5054 6 PROP 08/21 PROP LB 51-2 Lower 5896 5903 5057 5063 7 PROP 08/21 PROP LB 51-3 Middle 1 5935 5940 5090 5094 5 PROP 08/21 PROP LB 51-3 Middle 2 5943 5953 5097 5105 10 PROP 08/21 PROP LB 51-7 6112 6121 5242 5250 9 PROP 08/21 PROP LB 52-9 Middle 6169 6176 5293 5299 7 PROP 08/21 PROP BEL_UB_52-9 6,195’ 6,205’ 5,315’ 5,325’ 10’ 8/15/20 Open 56-9 6,658' 6,678' 5,541' 5,560' 20’ 12/22/17 Isolated 6,684' 6,696' 5,765' 5,777' 12’ 12/22/17 Isolated 6,715’ 6,730’ 5,795’ 5,809’ 15’ 12/18/17 Isolated 65-5 7,527’ 7,547’ 6,585’ 6,605’ 20’ 12/10/17 Isolated 7,528’ 7,533’ 6,586’ 6,591’ 5’ 11/30/17 Isolated 68-0 68-0 68-3 68-3 7,770’ 7,775’ 6,826' 6,830’ 5’ 11/29/17 Isolated 7,770’ 7,775’ 6,826' 6,830’ 5’ 11/11/17 Isolated 7,812’ 7,817’ 6,867' 6,872’ 5’ 10/28/17 Isolated 7,845’ 7,860’ 6,900’ 6,914’ 15’ 10/16/17 Isolated 73-5 8,355’ 8,375’ 7,404’ 7,424’ 20’ 9/28/17 Isolated 75-7 8,538’ 8,558’ 7,586’ 7,606’ 20’ 9/19/17 Isolated 77-3 8,585’ 8,595' 7,632’ 7,642’ 10’ 9/18/17 Isolated 65-5 68-0 68-3 73-5 75-7 77-3 JEWELRY DETAIL No. Depth ID OD Item 1 2,493’ 4-1/2” x 2-7/8” Dual Bore Perm Pkr (D&L) 7/27/20 2 2,506’ 2-7/8” X-Nipple 7/27/20 3 2,539’ 2-7/8” WLEG 7/27/20 4 6,271’ 4-1/2” CIBP w/ 44’ of cement, TOC 6,227’ 8/4/20 5 6,600’ 2.33” 3.79” 4-1/2” Halliburton TWR Perma Series Packer 6 6,610’ 2.313” 2-7/8” X-Nipple 7 6,620’ 2.441” 2-7/8” WLEG 8 6,710’ CIBP 12/22/17 9 7,520’ CIBP w/ 35’ of cement 12/21/17 10 7,760’ CIBP w/ 36’ fill & 35’ cement 11/30/17 11 7,795’ CIBP w / 15’ cement 11/02/17 12 7,838’ CIBP w/ 21’ cement 10/28/17 13 8,168’ CIBP w/ 35’ of cement; 55’ total 10/26/17 14 8,565’ 1.875” 3,75” Tri-Pt Model D Isolation Pkr 08/28/17 X TOC 8,113’ TOC 7,817’ TOC 7,780’ 56-9 TOC 7,485’ TOC 7,589’ BEL_UB_52-9 X Fish: 6,334’ – 24.5’ E-Line toolstring + 21’ slickline toolstring 7/25/20 TOF 6,334’ 7/25/20 LB 51-1 LB 51-3 LB 51-7 LB 52-9 1. 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: Install Upper Completion, N2 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: 6,271; 6,710; 7,520; 7,760; 7,795; Total Depth measured 8,630 feet 7,838 8,168 feet true vertical 7,677 feet N/A feet 2,493; Effective Depth measured 6,227 feet 6,600; 8,565 feet true vertical 5,344 feet 2,414; 5,483; feet 7613 Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)2-7/8" 6.4# / L-80 2,538' MD 2,451' TVD 2,493' MD; 6,600; 2,414'; 5,493'; Packers and SSSV (type, measured and true vertical depth)N/A 8,565' MD 7,613' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 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:Mike Quick Authorized Title:Operations Manager Contact Email: Contact Phone:777-8442 0 Water-Bbl MD 120' 2,006' Oil-Bbl measured true vertical Packer 4-1/2"8,625' measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 Swanson River Unit - Sterling/U Beluga, Beluga, and Tyonek Gas PoolsN/A measured TVD Tubing Pressure 100 Swanson River Unit (SRU) 241-33A028399; A028406 Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 217-047 50-133-20663-00-00 4. Well Class Before Work:5. Permit to Drill Number:2. Operator Name:Hilcorp Alaska, LLC 3. Address: mquick@hilcorp.com 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-261 1861 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 0 WINJ WAG 0 Casing Pressure Liner 3161 Gas-Mcf 4000 Representative Daily Average Production or Injection Data Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: Length 7,500 psi 120' 2,006' 8,625' Size 7,672' 7,240 psi Casing Structural 16" 7" Collapse 5,410 psi Senior Engineer:Senior Res. Engineer: Burst D&L, Halliburton, Tri-Pt Pkrs; 8,430 psi 120' 1,986' t Fra O O 6. A G L PG , R 2 Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 3:18 pm, Sep 11, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.09.11 14:14:23 -08'00' Taylor Wellman DSR-9/15/2020 gls 10/22/20 Perforate New Pool RBDMS HEW 9/14/2020 Pull Tubing SFD 9/25/2020 Note: Only perfed UB 52-9 zone 3161 Perforate Install Upper Completion, gls 10/22/20 Rig Start Date End Date 401 7/20/20 8/16/20 Daily Operations: Hilcorp Alaska, LLC. Well Operations Summary API Number Well Permit NumberWell Name SRU 241-33 50-133-20663-00-00 217-047 ARRIVE @ SR OFFICE, SIGN-IN/PERMIT/JSA/TALK W/PRODUCTION ABOUT DAYS OPERATIONS. SPOT EQUIPMENT, RU SLICKLINE USING .160" WIRE. RIH W/2.30" SCRATCHER TO 6,334KB. POOH. RIH W/2.35" G-RING TO 3,334KB, SET DOWN, W/T, GET STUCK, CANNOT PASS, POOH W/METAL GOUGES ON SIDE OF G-RING. RIH W/ 2.30" G-RING TO 6,334'KB, TAG TOP OF TOOLSTRING, POOH. RIH W/2.5" RB W/SPIT SKIRT W/BRASS PIN TO 6,334'KB, W/T SLIPS OFF 3 TIMES, LATCH AND PULL 2,200#, RE-LATCH AND SEE SECOND SET OF SPANGS, PULL UP TO 2,800#, PIN SHEARS, POOH. RIH W/SAME W/STEEL PIN, LATCH FISH, PULL 2,000# JAR LICK, 2,200# JAR LICK, IN SHEARS, POOH RIH W/SAME W/STEEL PIN, LATCH FISH, PULL 2,000# JAR LICK, 2,200# JAR LICK, PIN SHEARS, POOH. RIH W/ 2.5" JUC W/STEEL PIN TO SAME, LATCH AND GIVE MULTIPLE SPANG LICKS, ONE 1500# JAR LICK AND TOOL HOLDS, PULL UP TO 2.800# AND FISH COMES FREE, POOH TO 6,164'KB AND FISH GETS STUCK, GIVE 2 SPANG LICKS AND PULL UP TO 2,200, PIN SHEARS AND FISH FALLS TO 6,226K'B, POOH. RIH W/SAME TO 6,334'KB, CANNOT LATCH, TALK W/ PRODUCTION AND DECIDE TO LEAVE FISH IN HOLE. PLUG WILL BE SET AND CEMENTED ABOVE. OOH, RD SLICKLINE. 07/24/2020 - Friday Fill tbg W/ Produced water, pressure to 1,000psi, hold toolstring, no movement, whip wire, no movement. Arm Kinley cutter, drop cutter Wire cut, POOH W/wire. Fish Cutter, RIH withLIB, clean rope socket, POOH, RIH with Blind box, beat toolstring down to 6,334' POOH. RDMO, lay down for night, depart location. 07/20/2020 - Monday Sign in. Mobe to location. PTW and JSA. Spot equipment and rig up lubricator. PT to 250 psi low and 3,000 psi high. TP - 0. RIH w/ 2" x 10' bailer with casing cleaner in it and tag at 5,840'. Tried to go past this depth but cound not. Dump bailer here. POOH. RIH w/ 1-11/16" CCL/GR tool, 1-11/16" x 7 wt. bar, 2" x 5' wt. bar, 1-11/16" xr' wt. bar, 2-1/8" x 5' wwt. bar and rope socket and tag obstruction at 5,840'. Work tools approx 5 times and broke thru. Went down 20' and back 3 times. RIH without any problem to 6,400'. Started out of hole and tools hung up at 6,184'. Shouldn't be anything there to hand us up. Could not go down or up. Call town and discussed. Filled tubing up to see if that would help. Didn't help so we pressured up to 1,500 psi and tried, no good. Bleed well pressure off. Started working out line tension up by 100 lbs. Worked it up and down. Got to 3,400 lb and pulled out of rope socket. POOH and it showed that the tattle tail on line showed that it pulled out of rope socket. Got slickline lined up to come out in the morning and fish tools out. Rig down lubricator and secure the well. 07/25/2020 - Saturday leave fish in 2 7/8" tubing above packer @6600 ft RIH without any problem to 6,400' D FISH COMES FREE, POOH TO 6,164'KB AND FISH GETS STUCK, GIVE 2 SPANG LICKS AND PULL UP TO 2,200, PIN SHEARS AND FISH FALLS TO 6,226K'B, POOH. RIH W/SAME TO 6,334'KB, CANNOT LATCH, TALK W/ PRODUCTION AND DECIDE TO LEAVE FISH IN HOLE. PLUG WILL BE SET AND CEMENTED ABOVE. OOH, RD SLICKLINE. fish tools. Rig Start Date End Date 401 7/20/20 8/16/20 Daily Operations: Hilcorp Alaska, LLC. Well Operations Summary API Number Well Permit NumberWell Name SRU 241-33 50-133-20663-00-00 217-047 07/31/2020 - Friday Hold PTSM & review JSA'S with personnel. Bleed off 500 psi of gas from IA, Fill IA with 19 bbls of 6% kcl fluid. Open tbg, well static. set bpv & N/D production tree. N/U 11' X 7-1/16" DSA, mud cross, double gated bop, hydril, choke & kill lines. Hook up Koomey lines, pressure up Koomey system & function test same. R/U rig floor, hand rails, & stairs. P/U & land 2-7/8" test joint. P/U bails & 2-7/8" elevators. Perform bope pre-test. Test hydril to 250/2,500, tested blind, vbr, choke & kill line, choke manifold, hcr, & stand pipe manifold to 250/3,000. #1 valve on choke leaking. rebuild valve & retest. Test good. Clean location & prepare to test bope with possible state witness. 08/01/2020 - Saturday Test hydril to 250/2,500, tested blind, vbr, choke & kill line, choke manifold, hcr, & stand pipe manifold to 250/3,000.Test conducted with 2-7/8" tbg. Conduct draw down test. All test good. Back out hold down pins, P/U tbg off hanger & set 45k in slips (5k over string wt). Spot & R/U AK e-line. P/U lubricator, & M/U tools. RIH with 1-1/16" weight bar, ccl, gamma, & 2.063" jet cutter. Tag same @ 5,969'. Unable to work past. POOH to surface, L/D gun assembly. R/U Pollard slick line & wait on 2.25" bailer assembly. M/U 2.25" flat bottom flapper bailer assembly, RIH to 5,925' SLM & tag same. stroke bailer 3 times & fell thru. Continue RIH to 6,232' & tag solid. Work bailer not able to make hole. POOH same. Recovered 1 gallon of mud. Had indication on flat bailer surface we were on CIBP. R/D Pollard slick line & R/U AK E- LINE. RIH with 2.063" jet cutter assembly. Tie into RA tag marker @ 6,006'. Continue RIH & tag CIBP @ 6,281'. P/U to 6,274' Cut tbg same. Good indication of tbg cut. POOH to surface & L/D spent guns. P/U on tbg, tbg free. Secure well & rest crew. 07/30/2020 - Thursday Load rig 401 carrier, fluid pump, & fluid tank at CLU pad. Transport 13 trailer loads of rig equipment to SRU 241-33. Lay out felt & herculiner on SRU 241-33. Spot base beam, rig carriage, choke house, fluid tank, fluid pump, accumulator, air tank, generator, & transformer. Perform pre-lift inspection, lift & fully scope derrick. Secure guy lines. R/U pump lines, electrical lines, lay out Koomey lines, hook up gas detection system& pvt monitoring system. Haul in 300 bbls of fresh water, mix & blend to 6% kcl, build containment, get rig into compliance. 07/28/2020 - Tuesday STOP AT OFFICE FOR PERMIT AND MEETING WITH OPS LEAD. MISU, INSPECT LOC, PJSM, REVIEW EXPLOSIVE JSA. "BEGIN R/U, TAKE CONTROL OF 1/4"" CABLE, 1-7/16"" CABLEHEAD(5X2), 5' 1-11/16"" WEIGHT BAR, SPARTEK GR/CCL. STAB ON AND PT PCE 250LP-3,000HP(GOOD)" "RIH AT 120 FPM LOGGING GAMMA, TIE INTO RA MARKER @ 6,006' RKB. TAG BOTTOM @ 6,304' RKB. PULL UP TO PLANNED CCL STOP DEPTH OF 6,279'.2' RKB. FLAG WIRE FOR SECONDARY DEPTH. "RECONFIGURE TOOLS, SWAP TO 5' 1-11/16"" WEIGHT BAR, 1-11/16"" CCL, 1-11/16"" LONG STROKE, WLAK, 2.10"" CIBP. RIH W/ TOOLS AND DROP PASSED FLAG AND TAG BOTTOM, LOG UP PASSED FLAG AND OVERLAY. COLLARS TO PREVIOUS GAMMA/CCL RUN. DROP DOWN, PULL UP TO CCL STOP. DEPTH=6,279.2' RKB, CCL OFFSET=8.2', ME SET DEPTH=6,287.4', GOOD INDICATION OF SHOCK AND CURRENT. STACK WEIGHT AND WEIGHT 5 MINS. FINISH UP PASS AND POOH." "AT SURFACE WITH TOOLS, POP AND DROP AND UNSTAB FROM WELL. HAND WELL TO PRODUCTION FOR MIT-T. HELP PRODUCTION MIT-T PLUG, PLUG APPEARS TO BE HOLDING. BEGIN R/D. CLEAN UP WORK AREA AND DOWN STACK PCE. 2 7/8" plug at 6287 ft bar, ccl, gamma, & 2.063" jet cutter. Continue RIH & tag CIBP @ 6,281'. P/U to 6,274' Cut tbg same. Good indication of tbg cut. POO DEPTH=6,287.4', Test hydril to 250/2,500, tested blind, vbr, choke & kill line, choke manifold, hcr, & stand pipe manifold to 250/3,000. #1 cut tubing at 6274 ft Test hydril to 250/2,500, tested blind, vbr, choke & kill line, choke manifold, hcr, & stand pipe manifold to 250/3,000.Test conducted with 2-7/8" tbg. & N/D production tree. N/U 11' X 7-1/16" DSA, mud c Rig Start Date End Date 401 7/20/20 8/16/20 Daily Operations: Hilcorp Alaska, LLC. Well Operations Summary API Number Well Permit NumberWell Name SRU 241-33 50-133-20663-00-00 217-047 08/02/2020 - Sunday Hold PTSM & review JSA'S with personnel. Open well, well static. Reverse circulate 90 bbls of clean 6% kcl. R/D Kelly hose. & prepare to POOH. POOH laying down 2-7/8" slim hole production tubing. Total of 103 joints of Hydril 511, (1) hydril 511 pup jt, 98 JTS of FJ3 with a 15 ' cut jt. Secure well same & rest crew. 08/03/2020 - Monday Spot & R/U AK E-line. N/U 11" X 7" Otis flange. P/U lubricator & test to 1,500 psi, RIH with 3.75" GR/JB to 6,275' & tag same. POOH & L/D GR/JB. P/U CIBP for 4.5" casing. RIH & tie into RA tag marker @ 6,006'. Continue in hole & tag @ 6,275', P/U & set CIBP @ 6,271' with 200 lb of weight loss. P/U 60' then lower down tagging top of plug @ 6,271'. POOH & L/D setting assembly. P/U 3" X 30' of cement bailer, load with cement & RIH to 6,271' tagging top of cibp, dump cement & POOH to reload bailer, total of 3 cement bailer runs made leaving cement top @ 6,236'. Secure well & allow cement to cure for state witness hard tag in the morning. 08/04/2020 - Tuesday R/U AK E-line, P/U & RIH with 3.55" GR, gamma ray, & ccl. Tie into RA tag marker @ 6,006', lower tool string & tag top of cement @ 6,227'. POOH & L/D tools. Pressure test 4.5" casing & cement top to 2,225 psi on chart for 30 minutes. Held same. Tag & test was witnessed by AOGCC representative Bryan Bixby. P/U & RIH WITH Tripoint model D wireline set packer. Tie in to RA tag marker @ 2,817'. P/U & set packer @ 2,500'. Had 400 lb weight loss. P/U 40' then lowering down lightly tagging packer top. POOH & R/D AK E-line. Spot pipe wrangler & load racks with 2-7/8" 6.5# fj3 tbg. SLM tubing & prepare to tih. P/U & TIH drifting 2-7/8" fj3 production tbg to 2,470'. P/U WT = 8K, S/O WT = 8K. Tag & latch onto packer @ 2,496'. P/U 15K over string weight then lowering 2k over string weight. Release from packer, space out & install tbg hanger. Attempt to land out & latch packer. unable to obtain latch. Measure space out & found that space out was 4" too short to latch packer. Unable to space out with pup jts on location. POOH & shuffle pipe, Install 1.01' longer jt inside string. Attempt to land out tbg, tbg stacking out with hanger 3" above tbg spool. Measure remaining jts on location & obtain jt within 6" of space out due to lack of string wt & shallow packer setting for compression. Secure well & rest crew. 08/05/2020 - Wednesday Test packer seals to 1,000 psi, to insure no seal damage. Seals held. Release from packer. L/d hanger, POOH racking 1 stand in derrick, L/D 29.13' joint & replace with 28.64' joint. RIH same, P/U TBG hanger & land out same. Tubing string wt = 8k. Run in hold down pins. Pressure test IA to 3,000 psi on chart for 30 minutes. Held same. Top of packer @ 2,492.80', WLEG @ 2,538.86', PBTD @ 6,227', R/D foster tongs, clear handling tools from rig floor, remove stair ways & hand rails, R/D & remove rig floor. Bleed down & disconnect koomey lines, N/D hydril, double ram bop, kill & choke lines, & mud cross with dsa. N/U 7" x 4" production tree. Test void to 250/5,000, held same. Pull bpv, close all valves on tree & install night cap. Haul off 90 bbls of fluid using production vac truck, hold perform derrick inspection for lowering. scope in & lay down derrick onto carriage. R/D electrical, pvt & gas monitoring system. R/D pump lines, prep rig & equipment for load out. set 4.5" CIBP at 6271 ft. P/U & set CIBP @ 6,271' with POOH laying down 2-7/8" slim hole production tubing. Pressure test IA to 3,000 psi on chart for 30 minutes. to lack of string wt & shallow packer setting for compression. Secure well & rest crew. 08/05/2 Space out landing joint/ packer with new tubing joint Tie into RA tag marker @ 6,006', lower tool string & tag top of cement @ 6,227'. POOH & L/D tools. Pressure test 4.5" casing & cement top to 2,225 psi on chart for 30 minutes. Tag & latch onto packer @ 2,496'. P/U 15K over string weight then lowering 2k over string weight. P/U & set packer @ 2,500' Rig Start Date End Date 401 7/20/20 8/16/20 Daily Operations: Hilcorp Alaska, LLC. Well Operations Summary API Number Well Permit NumberWell Name SRU 241-33 50-133-20663-00-00 217-047 08/15/2020 - Saturday PTW, JSA. Pick injector head and 10' lubricator. Make up slim BHA. 1.75" OD coil connector, 1.75" MBT, 1.75" Ball drop nozzle. Stab on well. PT stack 250/4,000 psi. Open well. 0 psi WHP. (cased hole) Transfer N2 from Air Liquid and cool down pump and triplex. PT N2 lines 250/4,000 psi. Online down 1.75" coil x 2 7/8" tubing annulus taking returns up CT to return tank. 1,000 scf/min. Fluid returns seen at surface. Tag PBTD 6,237' CTMD. Unload wellbore. WHP broke over 2,420 psi. 74 bbls returned from well. POOH from 6,237'. Close in choke and start pressuring up well. Tagged up at surface. Shut lower, upper master , and swab valve. SITP 2160 psi. Total fluid returned 74 bbls 3% KCL. Total N2 pumped 187,555 scf or 2014 gal. SITP: 2,160 psi. Rig down SLB CTU 13. Crew will mobilize one item to CLU-14. Location secure. SDFN. 08/16/2020 - Sunday Sign in. Mobe to location. Spot equipment and RIg up lubrication. PT Lubricator to 250 psi for low and 3,500 psi for high. TP - was 20,000. RIH W 2-7/8" x 10' Razor HC, 6 spf, 60 deg phase gun and tie into the OHL. Bled well to 1,900 psi while going to hole. Ran correlation log and send to town. Town said we were good to go. Spotted and shot from 6,195' to 6,205' with 1,900 psi on tubing. After 5 min - 1,950 psi, after 10 and 15 min it was 2,000 psi. POOH. All shots fired and gun was dry. Rig down equipment out of the way and turn well over to field. 08/14/2020 - Friday PTW, JSA. MIRU SLB CTU 13 wtih 1.75" coil. 24 Hr BOPE test witness notification sent 8/13/2020 @ 12:53 hrs. Witness waived by Jim Regg via email 8/13/2020 @ 14:16 hrs. Start BOPE test. Accumulator draw down. Pressure test all rams and valves 250/4,000 psi. Good test. Dress coil and make up 1.75" OD roll on connector. Pull test 25k. Location walk around complete. SDFN. E line MIRU SLB CTU 13 wtih 1.75" coil. 24 Spotted and shot from 6,195' to 6,205' with 1,900 psi on tubing. CTU Fluid returns seen at surface. Tag PBTD 6,237' CTMD. Unload wellbore. WHP broke over 2,420 psi. 74 bbls returned from well. POOH from 6,237'. Close in choke and start pressuring Updated By DMA 08-31-20 SCHEMATIC Swanson River Unit Well SRU #241-33 PTD: 217-047 API: 50-133-20663-00-00 PBTD = 6,227’ / PBTVD = 5,344’ TD = 8,630’ / TVD = 7,677’ RKB to GL = 11’ 1 2 3 14 13 12 11 10 9 8 5 6 7 4 16” 7” 4-1/2” CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120' 7" Surf Csg 26 L-80 BTC/M 6.875” Surf 2,005’ 4-1/2" Prod Csg 12.6 L-80 TXP 3.958” Surf 8,625‘ TUBING DETAIL 2-7/8” Production 6.4 L-80 FJ3 2.375” Surf 2,538’ RA @ 2,817’ RA @ 3,800’ RA @ 6,006’ RA @ 8,415’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status BEL_UB_52-9 6,195’ 6,205’ 5,315’ 5,325’ 10’ 8/15/20 Open 56-9 6,658' 6,678' 5,541' 5,560' 20’ 12/22/17 Isolated 6,684' 6,696' 5,765' 5,777' 12’ 12/22/17 Isolated 6,715’ 6,730’ 5,795’ 5,809’ 15’ 12/18/17 Isolated 65-5 7,527’ 7,547’ 6,585’ 6,605’ 20’ 12/10/17 Isolated 7,528’ 7,533’ 6,586’ 6,591’ 5’ 11/30/17 Isolated 68-0 68-0 68-3 68-3 7,770’ 7,775’ 6,826' 6,830’ 5’ 11/29/17 Isolated 7,770’ 7,775’ 6,826' 6,830’ 5’ 11/11/17 Isolated 7,812’ 7,817’ 6,867' 6,872’ 5’ 10/28/17 Isolated 7,845’ 7,860’ 6,900’ 6,914’ 15’ 10/16/17 Isolated 73-5 8,355’ 8,375’ 7,404’ 7,424’ 20’ 9/28/17 Isolated 75-7 8,538’ 8,558’ 7,586’ 7,606’ 20’ 9/19/17 Isolated 77-3 8,585’ 8,595' 7,632’ 7,642’ 10’ 9/18/17 Isolated 65-5 68-0 68-3 73-5 75-7 77-3 JEWELRY DETAIL No. Depth ID OD Item 1 2,493’ 4-1/2” x 2-7/8” Dual Bore Perm Pkr (D&L) 7/27/20 2 2,506’ 2-7/8” X-Nipple 7/27/20 3 2,539’ 2-7/8” WLEG 7/27/20 4 6,271’ 4-1/2” CIBP w/ 44’ of cement, TOC 6,227’ 8/4/20 5 6,600’ 2.33” 3.79” 4-1/2” Halliburton TWR Perma Series Packer 6 6,610’ 2.313” 2-7/8” X-Nipple 7 6,620’ 2.441” 2-7/8” WLEG 8 6,710’ CIBP 12/22/17 9 7,520’ CIBP w/ 35’ of cement 12/21/17 10 7,760’ CIBP w/ 36’ fill & 35’ cement 11/30/17 11 7,795’ CIBP w / 15’ cement 11/02/17 12 7,838’ CIBP w/ 21’ cement 10/28/17 13 8,168’ CIBP w/ 35’ of cement; 55’ total 10/26/17 14 8,565’ 1.875” 3,75” Tri-Pt Model D Isolation Pkr 08/28/17 X TOC 8,113’ TOC 7,817’ TOC 7,780’ 56-9 TOC 7,485’ TOC 7,589’ BEL_UB_52-9 X Fish: 6,334’ – 24.5’ E-Line toolstring + 21’ slickline toolstring 7/25/20 TOF 6,334’ 7/25/20 Open 8/15/2010’5,325’5,315’6,205’BEL UB 52-9 6,195’ BEL_UB_52-9 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg P.I. Supervisor�� FROM: Brian Bixby Petroleum Inspector Section: 33 Township: Drilling Rig: N/A Rig Elevation: Operator Rep: Bobby Harrington Csg Cut@ Casing/Tubing Data (depths are MD): Conductor: 16" O.D. Shoe@ Surface: 7" 0. D. Shoe@ Intermediate: 0. D. Shoe@ Production: 4.5" 0. D. Shoe@ Liner: 0. D. Shoe@ Tubing: 2 7/8" 0. D. Tail@ Plugging Data: Test Data: DATE: August 4, 2020 SUBJECT: Well Bore Plug & Abandonment SRU 241-33 Hilcorp Alaska PTD 2170470; Sundry 320-261 8N Range: 9W N/A Total Depth: 8,630 ft MD Suspend: 120 Feet 2005 Feet Feet 8625 Feet Feet 6620 Feet Meridian: Seward Lease No.: A028399 P&A: Casing Removal: Csg Cut@ Feet Csg Cut@ Feet Csg Cut@ Feet Csg Cut@ Feet Csg Cut@ Feet Tbg Cut@ Feet Type Plug Founded on Depth Btm) Depth To MW Above Verified Fullbore Bridge plug 1 6,271 ft MD " 6,227 ft MD- 8.6 KCL Wireline tag 10 10 Initial 15 min 30 min 45 min Result Tubing 2225 2200 - 2200 - IA 2225 2200 2200- P OA 10 10 10 Tubing IA OA Initial 15 min 30 min 45 min Result Remarks: Plug back to reperf in the Beluga. Tubing pulled and set a couple CIBP's and cement plugs. This plug verification is the 2nd cement plug above the tubing cut and on top of 2nd CIBP. Tag top of cement @ —6300 ft MD; set 300lbs down on plug. Pressure test to 2000psi for 30 minutes. ' Attachments: none , rev. 11-28-18 2020-0804_Plug_Verification_SRU_241-33_bb h— hatuound is aed Sw 241,33 swunel Worm ane slm.e. Schee the .1e dame up Ina, wa mry be e.nng we newt and hit«mg anomer Be, Six, Ixacwp...g l-s--prre,l mase ah,a log he no Imemrernmn as to wilyere bell we are in the em" seluga sand in mese Thinned pe,mrnion. Evan though 9en,lmemreuno, does not uppose my p ounin to m/ lass discussion wrtn "'oho, Nuaory whin Toger m6 MrM. If—, ,is—Ude a Iooxal dens log below and pkssP In uskeow ado, dolde,ends you marl:.In van S of the ppRanre of sundry s]0]631arzad l.1nnhill veru des, 1. ue.. we need,. do 1. .,a me pont one and swath th CO g.vttns. .1. as sbme.11.well,wenm not downtime anyml ng ed,. are cmrenlh bhang wvn slihxbne on whim fill he we an get dttp enougen to se, a plug. We wo plan on.—., pg des 1.th.-11 as marry as We]nesdaV of n ed way smwe is ohn. dismiss.. The feel Is to get dap enough to she a plug In the noting ® ]ms wlll and us a second barite,. We.Tyne. male the if . we and MI NOing and the tubing X4.)/1- won& annulus and pull the ].1/9 .ung M INS Thus Mkpp will mn a4 V2 CIBP and set It above The submit sub. 35of cement will be pla ew on Imp of the bl/]-Clap. AT mi, pint mer—.it-.- phaw thdme oulWme of we whodunit disclmon.11 union mmoere,, Is ed sell to seep m.eirg l.rwaM.Iandpose tat we maga notified— to hil here fw a.1td.ed T, In Fe„ure toss of the plug. In the meantime. aresol uti on of the Geon,cel,k a sen lake plain. %eaused me once iI thin meets.,In the RObUs so .,al. smithe/. 1. .ram¢, .. CpPanms Engear hacons N.Y. LLC ORia-90].)77.. Cell -9 I,O-we form: BM1Yn'vn Sib .: Fndry, lids, 3],]OID led 1 AM Ud .Cutin TwOgW]- fClsphlderision, MerMstn RichNs o0eredym. BlcaMsgthllwrO mane On Ted Namtt «kra.tldawlprpmmy $ubje[f: BE SIV 241-33 Intends (eYRpYga] Aa hisW in IM1c gt'113d I Lt nehl Than hd afore Reluga,hull is U(Ti II is o—W..l owl mer- lase mlxM1nl my --Winn Who ',:Moder,.Ind. the "I up Iweek "The, Them -11, is nm muff ewm 6r hbls hifiew clone me Iq, l'ymek Coal. iifilly high berylwn of,he waymiing aoolam will. Them l mink had fle—anduchwol erin helm, in IM1e 9eluga On, pol nut who Tycrmk On, pwl, as mnlirc in C)]16 Rale 5 Pwl deRwnbe IIJ1nwmed. wasidd ng IXe AllaloJ Am and sewhe dw hilmal, defined We- wnsiwle me nand Pn Thum. De Swlirel- im MW oa l4nl. xiewll indWu.11 imenvle lint--I.xm tle iTuns'ei?,J)f Rp MD w 4,609 Itfl W in To Shelf Cweh Uhill 411 all b. The W., Gs PW, ne it11 inelWn all inurvala ,hu c.—I. xi h IM what 1M1W said MD w S,N51 had MD in the wildon a Creek 11.1141) xell. e. TM of o k Cut Poul, phich ircluent all iMen'tle final eurtcRw wish 1k mu l 5.30e! MD To 10,0115 few MD in Tiny Snldnlne, Creek Uwe 41.4 - TUFA sR_3r nn � iV Yf SFTS SRr 55d SRT 5S5 SFLNsia. The lkju N SRM -474 5R m 506 SR m 501 M. l.k (i-IVl - K— M v Tmm InI.—ASI-711M. cell—.--vosazvowfis nem: rn.�nlne r� - �q LM: TIw W ay, July 16. 3020 25fi PM MMIM oaf lull IIIII �j Sj IIIII l�ul,Wow!1111 M. l.k (i-IVl - K— M v Tmm InI.—ASI-711M. cell—.--vosazvowfis nem: rn.�nlne r� - �q LM: TIw W ay, July 16. 3020 25fi PM Ta: Sai 3lks <M1vi4erandm >I MdM51M1 GAeN,isann M1 snih, Q: iM KRmere4r S6fM:30.V ia1331nMml gscRpan[i¢si %II[ bµs like Steve DMps atM C dnssrees Men tMInhryas as bstM In the SAU M 133 spntlry. MaOiMtwrHpren[p. Thaintm'Ss are app ibut xa prehkin Nto Rvi s.'sski.1"ket[epan[y M¢ es, or the Mhm. Chrigh a Twegood operatla aEnonee Cend..learn, alkeep Neeka fail 9D77arpdmt 8443 M.,MAdagp, AY X503 C) 9% W 37& [I �W)3i3 wwm•—erovnm,mnyan memmn,--�ias,wmwamui:Mwewwmnwpiv e_. _ han, nn nneynwyvawe y:nwnumsmmmpinmmryvmwwrmwapxxyammuam,ausm�mn.v�mna rAMmemvm,ryuwmmmp emswmgnmeanurymmnxivseaummnneeawma vnvmum uwiweaxsuxnunw+ngpuwvm.mmq.om}eamreep eaq-a—uens eenmM1and Ismumersu.w—s ay a ewMpw mmavvxw xpm From: Chnstina Tw0000d - (C) To: Loepp. Victoria T (CEDI; Schwartz, Guy L (ED) Cc: Ted Kramer: Donna Ambruz Subject: RE: [EXTERNAL] SRU 241-33 RWO (PT) 217-047, Sundry 320-261) Date: Thursday, July 16, 2020 2:40:39 PM Victoria, As per your request, I have handed this request off to Ted. Christina Twogood Operations Engineer Kenai Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 99503 (w)907-777-8443 (c) 907-378-7323 From: Loepp, Victoria T (CED) [mailto:victoria.loepp@alaska.gov] Sent: Thursday, July 16, 2020 1:05 PM To: Christina Twogood - (C) <ctwogood@hilcorp.com> Subject: [EXTERNAL] SRU 241-33 RWO (PTD 217-047, Sundry 320-261) Christina, Is it correct that the Sterling/Tyonek pool is totally abandoned and you are opening perfs in a new pool(Beluga)? Would like to see the results of an MIT -T and MIT -IA before setting the CIBP? The fill was bailed to 6710' on 4/25/20. So in 3 months fill to 6327'. Was the well still producing? Thanx, Victoria From: Loepp, Victoria T (CED) Sent: Thursday, July 16, 2020 11:50 AM To: Christina Twogood - (C) <ctwogood(alhilcorD.com> Subject: RE: SRU 241-33 RWO (PTD 217-047, Sundry 320-261) Christina, Please send schematic. When is last MIT -IA, MIT -T? Thanx, Victoria From: Christina Twogood - (C) <ctwogoodtahilcolp.com> Sent: Thursday, July 16, 2020 10:44 AM To: Loepp, Victoria T (CED) <victoria loepp(@alaska.gov>; Schwartz, Guy L (CED) <guy.schwartz(@ a I aska. gov> Cc: Ted Kramer <tkramer(@hilcorn com>; Donna Ambruz <dambruz(CDhilcorp com> Subject: SRU 241-33 RWO (PTD 217-047, Sundry 320-261) Victoria, Hilcorp requests to modify the approved sundry on SRU 241-33 due to tagging at approx. 6,327' which is approx. 331' above the top of the top perf we intend to permanently isolate. After tagging high, we attempted to perform a clean out by bailing on Slickline but were unable to make any significant progress. In order to effectively isolate from the open perfs during this workover, Hilcorp would like to set a plug in the tubing, load/circulate the well, cut/pull the tubing, and set a plug w/ cement above the tubing stub. The changes to the approved procedure are detailed below. E -Line Procedure 1. MIRU E -Line and pressure control equipment. PT lubricator to 250 psi Low / 3,000 psi High. 2. Rill with 4 1,9" expandable plag and set at approx. 6,650' Otist above the 56 9 open perf) and dump betill 25' of cement on tOF (TOG estimated to be 6,625'). 3. RIH with 2-7/8" CIBP and set at approx. 6,320' (just above fill). PT plug to ensure effective isolation. If PT fails, dump bail minimum of 10' of cement on top of plug. 4. RU pump truck and return tank. 5. Load well with approx. 8.4 ppg brine (tubing volume approx. 100 bbls, annulus filled with fluid). 6. PT plug to 3,000 psi. 7. RU tubing punches. 8. RIH and punch 2-7/8" tubing at approx. 6,550'. 9. Circulate fluid. 10. POOH & RD E -Line. Additionally, due to this delay the rig will likely be ready to move onto the well once we set the plug such that we may be loading and circulating the well with the rig pumps as opposed to the pump truck as indicated. 1Zg Procedure 1. MIRU workover rig 401. 2. Notify AOGCC 24 hours in advance of test to extend the opportunity to witness. 3. Set back pressure valve. 4. ND wellhead, NU 13-5/8" BOP and test to 250 psi Low / 3,500 psi High, annular to 250 psi Low / 3,500 psi High. Record accumulator pre -charge pressures and chart tests. a. Perform Test. b. Test VBR rams 2-7/8" test joint. c. Submit completed form 10-424 to AOGCC within 5 days of BOPE test. 5. Unseat the T-dbing Ox. 23 6. • 7. PU ftnd FUll 2 W82' Tubing ttndRa*h" „ 8. MIRU E -Line and pressure control equipment. PT lubricator to 250 psi Low / 3,000 psi High. 9. RIH with tubing cutter and cut 2-7/8" tubing at approx. 6,300'. 10. POOH and stand back E -Line. 11. Unseat Tubing Hanger and PU on 2-7/8" Tubing. 12. POOH and laydown. 13. RU E -Line and pressure control equipment. PT 250 psi Low / 3,000 psi High. 14. PU and RIH with 4-1/2" CIBP and set at approx. 6,290' (above tubing stub). Dump bail 35' of cement on top of plug. Tag cement. 15. POOH and RD E -Line. 16. PU & RIH with 2-7/8" tubing tail w/ completion jewelry, 4-1/2" packer and 2-7/8" tubing back to surface to approx. 2,500' MD. Hang off in tubing hanger. a. Proposed equipment configuration also shown on the proposed schematic in red font. 17. Drop ball & rod. 18. Set packer with approx. 3,500 psi tubing pressure. 19. Chart pressure test on backside to 3,000 psi. 20. ND BOP/ NU wellhead and test. 21. Move off rig 401. is this plan acceptable to the state? Respectfully, Christina Twogood Operations Engineer Kenai Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 99503 (w)907-777-8443 (c) 907-378-7323 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. 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By Samantha Carlisle at 3:16 pm, Jun 15, 2020 320-261 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.06.15 15:06:37 -08'00' Taylor Wellman DSR-6/15/2020 RWO 10-404 SFD 6/15/2020 SFD 6/16/2020 Sterling/U Beluga, Beluga, and Tyonek Gas Pools SFD 6/16/2020 O 401 716 gls 6/16/20 *3000 psi BOPE test *2500 psi annular test 6/16/2020 dts 6/16/2020 JLC 6/16/2020 RBDMS HEW 6/18/2020 (test plug to 2500 psi min. gls) set expandable plug/ load well and test to 2000 psi (pre - rig) pull tubing RIH with tubing 3000 psi (test IA to 2000 psi ) 2500 psi BOPE test 3500 psi (1900 psi SIWHP) (Test CT BOPE to 4000 psi ) N2 DISPLACE SFD 6/15/2020CO 716 Beluga Gas Pool Sterling/U Beluga Gas Pool Tyonek Gas Pool SFD 6/15/2020 (expandable plug and cement for isolating each zone ) (after first set of perfs) pull or cut tubing isolatedplug/cmt Old packer and tailpipe isoall perfs isolated iso STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION GAS WELL OPEN FLOW POTENTIAL TEST RFPnRT Ia. Test: U� Initial Lj Annual 0 Special 1b. Type Test:Stabilized U Non Stabilized Multipoint ❑ Constant Time [I Isochronal Q✓ Other: Nodal 2. Operator Name: Hecorp Alaska, LLC 5. Date Completed: 5/24/2018 11. Permit to Drill Number: 217-047 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 6. Date TD Reached: July 2, 2017 12. API Number: 50- 133-20663-00-00 4a. Location of Well (Governmental Section): Surface: 513' FNL, 2145' FWL, Sec 33, T8N, R9W, SM, AK Top of Productive Horizon: 835' FNL, 49' FEL, Sec 33, T8N, R9W, SM, AK Total Depth: 853' FNL, 66' FWL, Sec 34, T8N, R9W, SM, AK 7. KB Elevation above MSL (feet): 205.1 13. Weil Name and Number: SRU 241-33 8. Plug Back Depth(MD+TVD): 7,760' MD / 6,816 TVD 14. Field/Pool(s): Swanson River Field / Tyonek Gas Pool 9. Total Depth (MD + TVD): 8,630' MD / 7,677' TVD 41b. Location of Well (Slate Base Plane Coordinates NAD 27): Surface: x- 344550 y-2465962 `Lone- 4 TPI: x- 347632 y- 2465607 Zone- 4 Total Depth: x- 347746 y- 2465587 Zone- 4 10. land Use Permit: NIA 15. Property Designation: (SHL/iPH) A028389 / (BHL) A028406 16. Type of Completion (Describe): 4-1/2" Production String, Perforated 17. Casing Size Weight per foot, Ib. I.D. in inches Set at ft. 4-1/2" 12.6# 3.958 8,625 19. Perforations: From To 6,658-6,676 7,528-7,533 8,355-8,375 6,684-6,696 7,770-7,775 8,538-8,558 6,715-8,730 7,812-7,817 8,585-8,595 7,527.7,547 7,845-7,860 18. Tubing Size Weight per foot, Ib. I.D. in inches Set at ft. 2.7/8" 6.4# 2.375 6.620 20. Packer set at ft: 6660 21. GOR cf/bbl: 0 22. API Liquid Hydrocardbons: 50 23. Specific Gravity Flowing Fluid (G): 0.56 24a. Producing through: F] Tubing D Casing 24b. Reservoir Temp: 117 F° 24c. Reservoir Pressure: 2375 psia Q Datum 5527 TVDSS 24d. Barometric Pressure (Pa): psta 25. Length of Flow Channel (L): Vertical Depth (H): Gg: 0.06 % CO2: 0 % N2: 0 % H2S: Prover: Meter Run: Taps: 26. FLOW DATA TUBING DATA CASING DATA No. Prover Choke Pressure Diff. Temp. Line X Orifice sl Hw Size (in.) Size (In.) P 9 F. Pressure Temp. Psig F° Pressure psig Temp. F° Duration of Flow Hr. 1. x 2. x 3. i x 4. x 5. x No. Basic Coefficient Flow Temp. Pressure Gravity Factor (24 -Hour) -hPm Flo or Fp Pm Ft Fg Super Comp. Factor Fpv Rate of Flow O, Mcfd 1. 2. 3. 4. 5. Temperature No. Pr T Tr z for Separator Gas Gg for Flowing Fluid G 1. 2. 3. Critical Pressure 4. Critical Temperature 5. Form 10-421 Rev. 7/2009 CONTINUED ON REVERSE SIDE Submit in Duplicate RBDMSJE-v OCT 3 0 2019 Pc Pc? Pf Pe No. Pt Piz PCZ -Pt, PW Pwz Pc?-Pv2 Ps Pse P - sz 1. 2. 3. 4. 5. 25. AOF (Mcfd) 31.5 n Remarks: Awesomewell!II : I hereby certify that the foregoing is,tf46, .. and correct to the best of my knowledge. Signed ..,.....:.. - _y_„Y=—"'..' •-��'"� Title Reservoir Engineer Date 0924119 DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing were reduced to zero psia Fb Basic orifice factor Mcfd/ Ph iJ m Fp Basic critical flow prover or positive choke factor Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= tFZ—dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensionless GOR Gas -oil ratio, cu, ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back -pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia Pt Flowing wellhead pressure, psia PW Static column wellhead pressure corresponding to Pt; psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 7/2009 Side 2 I 0 0 1 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Reviewed By: /�//I� P.I.Suprv,� pi BOPE Test Report for: SWANSON RIV UNIT 241-33 Comm Contractor/Rig No.: Moncla 401 PTD#: 2170470 " DATE: 5/21/2018 - Inspector Lou Laubenstein ' Insp Source Operator: HILCORP ALASKA LLC Operator Rep: Gamaliel Salas Rig Rep: Cole BartlewskiInspector E Type Operation: WRKOV Sundry No: Test Pressures: Inspection No: bopLOL180523071156 Rams: Annular: Valves: MASP: Type Test: INIT - 317-424 250/4500 250/4500 ' 250/4500' 4172Insp ' 'Related No: j TEST DATA MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: P/F Visual Alarm Time/Pressure P/F Location Gen.: P - Trip Tank P - NA System Pressure 3100 - P - Housekeeping: P • Pit Level Indicators NA NA Pressure After Closure 2450 - P ' PTD On Location P - Flow Indicator NA NA 200 PSI Attained 26 - P Standing Order Posted P - Meth Gas Detector P - P - Full Pressure Attained 83 - P ' Well Sign P - H2S Gas Detector P - P Blind Switch Covers: yes - P : Drl. Rig P - MS Misc NA NA Nitgn.Bottles(avg): 6 na 2300 ' P' Hazard Sec. P " ACC Misc 0 NA Misc NA FLOOR SAFTY VALVES: BOP STACK: CHOKE MANIFOLD: Quantity P/F Quantity Size P/F Quantity P/F p, Upper Kelly 0 NA Stripper 0 NA No.Valves 8 - P Lower Kelly 0 NA Annular Preventer 1 -7 1/16 _ P - Manual Chokes 2 - P - Ball Type 1 = P " #1 Rams 1 -2 3/8 x 3 1/2- P - Hydraulic Chokes 0 NA Inside BOP 1 ; P #2 Rams 1 - Blind rams - P CH Misc 0 NA FSV Misc 0 NA ' #3 Rams 0 NA #4 Rams 0 #5 Rams 0 NA INSIDE REEL VALVES: #6 Rams 0 NA (Valid for Coil Rigs Only) Choke Ln.Valves 1 _ 2 1/16 _ P - Quantity P/F HCR Valves 1 2 1/16 p - Inside Reel Valves 0 NA Kill Line Valves 2- 2 1/16 ' _ P Check Valve 0 NA BOP Misc 0 NA_ 1 Number of Failures: 0 Test Results Test Time Remarks: Test was completed with a single 2 7/8 test joint,there are is no PVT system in the pits.Visual readings of tank levels only. ✓ SCANNED JUN 962018 �� • • • Schwartz, Guy L (DOA) From: Ted Kramer <tkramer@hilcorp.com> Sent: Friday, May 18, 2018 2:13 PM To: Schwartz, Guy L(DOA) Cc: Donna Ambruz Subject: RE: SCU 31-08 PTD# 181-099, 21C-04 PTD#214-169, SRU 241-33 PTD#217-047 Guy, No,That Sundry is still open however. 317-572 was written to add perforations to three Sand intervals in the 55-4 sand. Two of those three were shot. The Third one was not. This work will be completed under W424(also still open). This Sundry contains the work to set the packer on E—line (done on 1-15-18 report). The next operation will p be to run the tubing with seals, stab into the packer, space out, hang off and pressure test. We will then rig up coil, blow the tubing dry, pressure up to balance above and below the X plug, and pull the plug. The well is ready to flow at that point. We will then close out both Sundries, 317-572 and 317-424 with a 10-404. From:Schwartz,Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent: Friday, May 18, 2018 1:29 PM To:Ted Kramer<tkramer@hilcorp.com> Cc: Donna Ambruz<dambruz@hilcorp.com> Subject: RE: SCU 31-08 PTD# 181-099, 21C-04 PTD#214-169,SRU 241-33 PTD#217-047 Is SRU 241-33 still under 317-572? Guy Schwartz Sr. Petroleum Engineer AOGCC MAY 2'1 2018 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 Conservatioh 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@alaska.gov). From:Schwartz, Guy L(DOA) Sent: Friday, May 18, 2018 1:22 PM To: 'Ted Kramer'<tkramer@hilcorp.com> Cc: Donna Ambruz<dambruz@hilcorp.com> Subject: RE:SCU 31-08 PTD# 181-099, 21C-04 PTD#214-169, SRU 241-33 PTD#217-047 Ted, I can not find the sundry for SRU 241-33 ... 1 • • 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 Ito you,contact Guy Schwartz at(907-793-1226) or(Guv.schwartz@alaska.gov). From:Ted Kramer [mailto:tkramer@hilcorp.com] Sent: Friday, May 18, 2018 9:53 AM To:Schwartz,Guy L(DOA)<guy.schwartz@alaska.gov> Cc: Donna Ambruz<dambruz@hilcorp.com> Subject:SCU 31-08 PTD#181-099,21C-04 PTD#214-169, SRU 241-33 PTD#217-047 Guy, As a follow up to our phone conversation, the wells involved and their permit to drill numbers are listed above. The order of the work is below and a brief history on each well. SCU 31-08—Currently rigging down The Moncla 401 was on this well with the purpose to pull tubing, remove a stuck rod pump and re-run the tubing and rods in the well to return the well to production. The tubing was pulled and the rod pump retrieved and we were starting to run the tubing back in the well. At 42 joints in the well the driller got out of rythmn and opened the slips before the next joint of pipe was screwed in the tubing string—dropping the 42 joints,tubing hanger and a cavins sand separator into the well bore. Slickline tagged the fish t 3,980' and we ran in with an overshot and recovered 19 joints of the 42 joints dropped. The top of the fish was then located at 4,713' slm and the LIB showed a smashed flat tubing end looking up. Long story short, Hilcorp needs a 6.75' concave mill which our vendor does not have in the State of Alaska. Therefore, Hilcorp has decided to rig down off of the well temporarily and perform work on two other welkls in the 3 well package while these mills are shipped up fro the lower 48. SRU 241-33 This well was drilled last year but the well would not pass a casing test. The solution was to run an e-line set packer with a plug in it in the well bore where good cement is known to exist behind casing. The 401 rig is moving here next to run Tubing in the well to stab into the packer and the well will be placed on line. SCU 21C-04 The Sundry for this well was submitted on 5-16-18 to pull tubing in order to set a CIBP over the Hemlock Bench 5 to sh t off water. H9ilcorp requests some help in getting this Sundry expedited because with the rig coming off of SCU 31-08 early,this well will move up in the schedule most= likely Thursday of next week. The back story on this well is that the Hemlock Bench 5 was perforated around the beginning of 2018 thinking that oil would be added. Instead,the zone was wet,water came in and 50 bopd of oil was lost in the process. Hilcorp made 4 separate attempts to set through tubing plugs in this well (2 umbrella and 2 spiral) and all failed to set. Therefore the 2 next step is while the rig crew ilAlaska,to pull the tubing and set a CIBP 105'of cement with e-line and re-run the 2- 7/8" portion of the production string. SCU 31-08— Return to this well with the correct fishing tools and remove the fish and run tubing. Please call me with any further questions. Sincerely, Ted Kramer Sr.Operations Engineer Hilcorp Alaska, LLC. 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O I '...—k F Z I ' Q I C7 pi 1 os C1 i D ce J y a u) UJ0 LIJ V E• Q Z ICC w.o J 0.N m G. lc CO0 ON ol E co0 V• N U d o JE Q` M E 0el N V I el 0. 11 H r I • N lu� 1111 CO CO m Z C / CO f s G a N o I N Q C n G Zd o EA co N Z r r- , • rN N N_ 1I CO CO 0) O) et- CD ti I'm nt > 1 0 1 a 13 N d N N *- > — co1 ,` 0 O M C fa O W 0 CC O (0 o 0 'a. Cco U .�. t N .O' d 11.. U E co ' E E 0 • 0 a. a o 0 00 • • Davies, Stephen F (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Tuesday,January 30, 2018 3:56 PM To: Davies, Stephen F (DOA) Subject: RE: SRU 241-33 (PTD#217-047) -Well Location Good morning Steve, Yes I can expand on that. For BLM properties we will,submit a PTD to them with an "As-Staked"survey of the well location.After we receive an approved PTD from the BLM we will then drive a conductor. Once the conductor is in place,we will re-survey to get an "As-built"survey. When we receive this survey we will incorporate it into the PTD for the AOGCC, and then submit this package to the AOGCC for approval.This should mitigate the issues with the SHL's being different. As far as the permitting goes for AOGCC only properties. We will continue doing what we have been doing. Set the conductor,get an "As-Built"survey for the conductor and plan off of that. Please let me know if you would like further clarification of this. Thank you! Monty M Myers Drilling Engineer Hilcorp Alaska Office:907.777.8431 Cell: 907.538.1168 From: Davies,Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Friday,January 26, 2018 4:47 PM To: Monty Myers<mmyers@hilcorp.com> Subject: RE:SRU 241-33 (PTD#217-047)-Well Location Monty, 20 AAC 25.015 requires a new Permit to Drill application if the proposed surface location is changed by any amount. Could you please provide a brief summary of the process that Hilcorp now has in place to prevent this from happening again? Thanks for your help, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. 1 • • Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Friday,January 26,2018 4:47 PM To: 'Monty Myers' Subject: RE: SRU 241-33 (PTD#217-047) -Well Location Monty, 20 AAC 25.015 requires a new Permit to Drill application if the proposed surface location is changed by any amount. Could you please provide a brief summary of the process that Hilcorp now has in place to prevent this from happening again? Thanks for your help, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Monty Myers [mailto:mmyers@hilcorp.com] Sent:Tuesday,January 16, 2018 11:11 AM To: Davies,Stephen F (DOA)<steve.davies@alaska.gov> Cc:Cody Dinger<cdinger@hilcorp.com> Subject: RE:SRU 241-33 (PTD#217-047)-Well Location Good morning Steve, Attached is the correct surface location for the SRU 241-33. When we permit a well to drill in Swanson we have to get a PTD from the BLM to install a conductor,so both permits were submitted with as staked locations. The staked location is—11' North and 2'West, of the As-built.This was a necessary change to make to accommodate the rig layout on such a small pad, since the BLM does not like us to do any pad expansions. We did obtain this new As-built survey prior to spudding the well, however I failed to submit it to the AOGCC when I received it, as well as submitting a revised PTD.We have a process in place to keep this from happening, however this one slipped through the cracks. Please except my apology for missing this and let me know how you would like to proceed. Monty M Myers Drilling Engineer Hilcorp Alaska Office:907.777.8431 Cell:907.538.1168 From: Davies,Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Friday,January 12, 2018 3:49 PM To:Cody Dinger<cdinger@hilcorp.com> Subject:SRU 241-33 (PTD#217-047)-Well Location 1 • • Davies, Stephen F (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Tuesday,January 16, 2018 11:11 AM To: Davies, Stephen F (DOA) Cc: Cody Dinger Subject: RE: SRU 241-33 (PTD#217-047) -Well Location Attachments: 177012 HILCORP SRU 241-33 AS BUILT SLD NAD 27.pdf Good morning Steve, Attached is the correct surface location for the SRU 241-33. When we permit a well to drill in Swanson we have to get a PTD from the BLM to install a conductor,so both permits were submitted with as staked locations. The staked location is^'11' North and 2'West,of the As-built.This was a necessary change to make to accommodate the rig layout on such a small pad,since the BLM does not like us to do any pad expansions. We did obtain this new As-built survey prior to spudding the well, however I failed to submit it to the AOGCC when I received it,as well as submitting a revised PTD. We have a process in place to keep this from happening, however this one slipped through the cracks. Please except my apology for missing this and let me know how you would like to proceed. Monty M Myers Drilling Engineer Hilcorp Alaska Office:907.777.8431 Cell:907.538.1168 From: Davies,Stephen F(DOA) [mailto:steve.davies@alaska.gov] Sent: Friday,January 12, 2018 3:49 PM To:Cody Dinger<cdinger@hilcorp.com> Subject:SRU 241-33 (PTD#217-047)-Well Location Cody, While reviewing the Completion Report for SRU 241-33,we noticed that the surface location of the well on the Permit to Drill does not match the surface location reported on the Completion Report. Which location is correct? If the surface location was changed from that presented on the Permit to Drill and the As-Staked surveyor's plat,what necessitated the change? Under 20 AAC 25.015(a)(1),a new Permit to Drill application is required if the proposed surface location of a well is changed. Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. 1 • • --29 28 _—_-----_—_ SECTION LINE 32 33 - - - - - - - SECTION COR(COMPUTED) I N:2466504.335 E:342411.787 513'FNL SEC 33 T8N R9W w -J Q Ci) FOOF OFPAO 0 I— I SRU 21-33 PAD �SSROP= Of — - PGG '�`�., Z 2145 FWL(NTS) W Z J z SRU 241-33 0 0 AS BUILT SURFACE LOCATION Lu NAD 27 ASP ZONE 4 co N: 2465962.803' ' E: 344550.676' LAT: 60°44'48.8950" N LON: 150°52' 07.8618"W 513' FNL - 2145' FWL TOP OF GRATE EL: 187.51' NAVD88 TOP CONDUCTOR EL: 184.65' NAVD88 GROUND EL: 187.15' NAVD88 `N�‘‘.\\11'` 9 A� 6 • /P- • f ,1SI C 1� ,i / • * .49TH /\ * i ow i NOTES , /�i,�•'> /2ss- 00 1. BASIS OF HORIZONTAL;NAD83 US FEET POSITION(EPOCH 2010) __ 00 M. SCOTT McLANE. AND VERTICAL CONTROL(NAVD88)IS AN OPUS SOLUTION FROM �, 4928—S NGS STATIONS TBON,TSEA AND ANC2 TO ESTABLISH CP-2. THE �� _ fi •. 6128/201.7... ALASKA STATE PLANE COORDINATES NAD 83 ZONE 4 IN FEET ARE: �� E=1483669.444 a 'II I 1' ' xxx�```` ELEV.=212.690(NAVD88) 11111111111111111,n1iIIIIIIIIII UpI"` 2.SECTION LINES SHOWN WERE ESTABLISHED FROM SURVEY TIES TO ORIGINAL GLO MONUMENTATION(1987) SCALE 3. DATUM TRANSFORMATIONS(NAD83 ASPZ4 TO NAD27 ASPZ4) 0 200 400 WERE DONE USING CORPSCON SOFTWARE VERSION 6.0.1. / l 1 FEIET I. PROJECT HILCORP ALASKA, LLC REVISION: - Consultiny Inc SWANSON RIVER FIELD DATE: 6/28/17 WELL SRU 241-33 DRAWN BY: ICB/BGB SCALE: 1"=200' M`L°`NE AS BUILT SURFACE LOCATION NAD 27 PROJECT NO. 177012 ENGINEERING I MAPPING/BURVEVING/TESTING BOOK NO. 16-03/12-31 P.O.BOX 468 SOLDOTNA,AK.99669 LOCATION VOICE:(907)283-4218 FAX:(907)283-3265 SECTION 33 TO8N RO9W SHEET EMAIL:SAMCLANE@MCLANECG.COM Hilcorp Alaska,LLC SEWARD MERIDIAN, ALASKA °F 1 • • Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Friday,January 12, 2018 3:49 PM To: Cody Dinger- (C) (cdinger@hilcorp.com) Subject: SRU 241-33 (PTD#217-047) -Well Location Cody, While reviewing the Completion Report for SRU 241-33, we noticed that the surface location of the well on the Permit to Drill does not match the surface location reported on the Completion Report. Which location is correct? If the surface location was,changed from that presented on the Permit to Drill and the As-Staked surveyor's plat,what necessitated the change? Under 20 AAC 25.015(a)(1),a new Permit to Drill application is required if the proposed surface location of a well is changed. Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. 1 • STATE OF ALASKA • RECEIVED ALASKA OIL AND GAS CONSERVATION COMMISSION DEC 6 WELL COMPLETION OR RECOMPLETION REPORT AND Lba7 la.Well Status: Oil ❑ Gas Q ' SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ lb.Well Clas C" 20AAC 25.105 20MC 25.110 Development Q . Exploratory ❑ GINJ ❑ WINJ ❑ WAGE WDSPL❑ No.of Completions: _1 Service ❑ Stratigraphic Test ❑ 2.Operator Name: 6.Date Comp.,Susp.,or 14.Permit to Drill Number/ Sundry: Hilcorp Alaska, LLC Aband.: 9/18/2017 217-047 /31 7-354' 3.Address: 7.Date Spudded: 15.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 July 2,2017 . 50-133-20663-00-00 4a. Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: Surface: 513'FNL,2145'FWL,Sec 33,T8N, R9W,SM,AK - July 17,2017 SRU 241-33 Top of Productive Interval: 9. Ref Elevations: KB: 205.1' 17. Field/Pool(s):Swanson River Field 835'FNL,49'FEL,Sec 33,T8N, R9W,SM,AK GL: 187.1'BF: 186.1' Tyonek Gas Pool Total Depth: 10.Plug Back Depth MD/TVD: 18. Property Designation: 853'FNL,66'FWL,Sec 34,T8N, R9W,SM,AK • 7,760'MD/6,816'TVD • (SHL/TPH)A028399/(BHL)A028406 4b. Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- 344550 • y- 2465962• Zone- 4 • 8,630'MD/7,677'TVD • N/A TPI: x- 347632 y- 2465607 Zone- 4 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 347746 y- 2465587 Zone- 4 N/A N/A 5.Directional or Inclination Survey: Yes 12_1 (attached) No ❑ 13.Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) N/A 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 CBL-VDL-GR-CCL, PNX-PBMS,CASTM +' FORMATION LOG 2"/5"MD/TVD, LWD COMBO LOG 2"MD/TVD,GAS RATIO LOG 2"MD/TVD DRILLING DYNAMICS LOG 2"MD/TVD, FINAL WELL REPORT ROP-DGR-ADR-EWR-CTN-ALD 2"/5"MD, DGR-ADR-EWR-CTN-ALD 2"/5"TVD PERFORATION RECORD, PLUG SETTING RECORD(11-2-2017), PLUG SETTING RECORD(10-26-2017) GASSAT3D ANALYSIS 23. CASING, LINER AND CEMENTING RECORD WT.PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD FT PULLED 16" 84# X-56 Surface 120' Surface 120' Driven Driven 7" 26# L-80 Surface 2,005' Surface 1,986' 8-1/2" L-203 sx/T-100 sx 23 bbls 4-1/2" 12.6# L-80 Surface 8,625' Surface 7,672' 6-1/8" L-490 sx/T-230 sx 24.Open to production or injection? Yes Q No ❑ 25.TUBING RECORD If Yes, list each interval open(MD/TVD of Top and Bottom; Perforation SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Size and Number; Date Perfd): TBD TBD TBD /...." **See attached Schematic for Detail** 4✓ • 1 � i op- (f c. 1 i 1 26.ACID,FRACTURE,CEMENT SQUEEZE,ETC. 0 Was hydraulic fracturing used during completion? Yes❑ No Q Per 20 AAC 25.283 i 2 attach electronic and printed information �'l8)/t� OO DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED l,- 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): TBD TBD Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: Test Period — Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 24-Hour Rate -4 Form 10-407 Revised 5/2017 CONTINUED ON PAGE 2 „ ,� Su mit ORIGINIAL one • • YesNo � Sidewall Cores: Yes No J 28.CORE DATA Conventional Core(s): ❑ ❑ ❑ ❑ 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 ❑✓ Permafrost-Top If yes, list intervals and formations tested,briefly summarizing test results. Permafrost-Base N/A N/A Attach separate pages to this form, if needed,and submit detailed test Top of Productive Interval TBD TBD information, including reports, per 20 AAC 25.071. Upper Beluga 3,681' 3,399' Tyonek 6,223' 5,340' TY 55-5 6,487' 5,581' TY 65-5 7,430' 6,490' TY 71-8 8,148' 7,199' TY 73-5 8,277' 7,327' Formation at total depth: Tyonek 77-3 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. I hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Paul Mazzolini Contact Name: Cody Dinger Authorized Title: Drilling Man;gerContact Email: Cdingef(C�hIICOrp.00171 Authorized / Contact Phone: 777.8389 Signature: f ?CV �, , ,G4ZZtXr�ltbate: /2/L f Zo/7 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 1 b: 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 • • Swanson River Unit 14 SCHEMATIC Well SRU #241-33 PTD: 217-047 API: 50-133-20663-00 Flilcarp Alaska,LLC RKB to GL=18.5' 4): 0 CASING DETAIL 16" .i .� 4*f Size Type Wt Grade Conn. ID Top Btm p, mConductor-Driven 16" 84 X-56 Weld 15.01" Surf 120' to Set Depth 44 0. ° "i A,,- 7" Surf Csg 26 L-80 BTC/M 6.875" Surf 2,005' V.?I 1 4-1/2" Prod Csg 12.6 L-80 TXP 3.958" Surf 8,625' 4 0 JEWELRY 7,, No. Depth ID OD Item 4 • .. ♦* A+ 1 7,760' CIBP 11/30/17 RA @ 2,817' ' * ' - 2 7,795' CIBP w/15'cement 11/02/17 q N 3 7,838' CIBP w/21'cement 10/28/17 RA @ 3,800' .'_*• " 4 8,168' CIBP w/35'of cement;55'total 10/26/17 �_ ' I ' 5 8,565' 1.875" 3,75" Tri-Pt Model D Isolation Pkr 08/28/17 I - RA @ 6,006' �� ' _ , �- ] )/pA E44 (.44441/ Ile* /`44, , �L t NBft `1 7Z_ hit...4, . -'' PERFORATION DETAIL Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status ,� r`04t, 65-8 7,528' 7,533' 6,586' 6,591' 5 11/30/17 Open 65-8 7,527' 7,547' 6,586' 6,605' 20 12/10/17 Open 4.,,,,..;.4.: 4-, 68-0 7,770' 7,775' 6,826' 6,830' 5 11/29/17 Isolated r. t , 68-0 7,770' 7,775' 6,826' 6,830' 5 11/11/17 Isolated 65-8 68-0 7,812' 7,817' 6,867' 6,872' _ 5 10/28/17 Isolated 68-0 7,845' 7,860' 6,900' 6,914' 15 10/16/17 Isolated TOC 7,780' - ' 3 73-5 8,355' 8,375' 7,404' 7,424' 20 9/28/17 Isolated 75-7 8,538' 8,558' 7,586' 7,606' 20 9/19/17 Isolated a 77-3 8,585' 8,595' 7,632' 7,642' 10 918 L TOC 7,817' 6440, `'s� � 68-0 / /17 Isolated i' yam: TOC 8,113' t' _41 #za r 73-5 RA @ 8,415' .,* li 4, , .41.°0`704.4r" 75-7 '. OPEN HOLE/CEMENT DETAIL t.,,:iy� . . ( 7„ 8-1/2"hole.88 BBL(203 sx)of 12 ppg Type I/II Cement and 22 BBLs(100 sx)15.4 ��?,t .� , ppg of Class G tail. 100%returns throughout,23 bbls to surface. VI ',..r.'..7.' 77-3 44/2" 6-1/8"hole.166 BBL(490 sx)of 12.8 Type I-II Cement and 27 BBLs(120 sx)15.3 ppg ,'1ri,`4 .4 _ WI(; of Class G tail.99%returns throughout,0 bbls to surface. 4-1/2" arc' r ' PBTD=7,760'/PBTVD=6,816' TD=8,630'/TVD=7,677' Updated By CJD 12-18-17 • • Hilcorp Energy Company Composite Report Well Name: SRF SRU 241-33 Field: Swanson River County/State: ,Alaska i(LAT/LONG): evation(RKB): 18 API#: Spud Date: 7/3/2017 Job Name: 1711425D SRU 241-33 Drilling Contractor SLR 169 AFE#: AFE$: 1.XONKOWNIMEINVIIMINIENIEMOHNIMINIMENAR04401,1•1111!IIIIIMOOMMENEEMERNMEMEMEMMEM.M.i.MON 6/27/2017 Remove wind walls from mud tanks,rig down mud pumps,rig down mud tanks,hand railings,interconnects,lower roof tops on pit modules.Remove Koomey unit lines from sub;base.Prepare derrick to be scoped down,and laid over.Pick up all handiberm and place in connex.Rinse out cellar,and vacuum clean.Empty boiler water.;Complete scoping down derrick.Un-spool drilling line,prepare derrick to be laid down and transported. Secure all hoses,steam lines,interconnects for road transport.Load trailers.:Preoare to lower doe house. 6/28/2017 Prep to lower doghouse,Peak on location at 8:00.Held PJSM with rig team and drivers.Hooked up and transported 4 trailers from Kalotsa pad to Swanson River,;transported pump 2 skid and doghouse/water tank,spotted 3 trailers on 241-33 pad,tore out backyard at Kalotsa and staged on pad.RU transformer and gen set on 241-33 and powered up Co Rep trailer,;spotted Pushers sewer tank,shuffled items on 241-33 to access rig mats(have to move rig mats to spot comm tower.;Transported catwalk,pit 3,boiler skid,gen 1-2 skid,and pump 1 to Swanson River.Night crew policed Kalotsa pad then mob'd to Swanson River.;Spot Pusher shack.Rig crew and Peak support laid out felt and herculite for foot print of rig.All crews housed in Swanson housing.5 Star catering serving meals_:Place ria mats on herculite will containment. 6/29/2017 Set up comm tower on location and finished laying backyard matting.Plugged in Push shack and break shack and powered up same. Started transport of cranes, pony walls,derrick,carrier and sub-base;09:00.RU comm's.Spotted cranes and pony walls over SRU 241-33.Brought in and set sub-base and carrier. Transported pit 2-3,gen 3 and upright water tank. Set test pump and HPU under sub.;Bring in and set derrick.Place extra wind walls in connex.Set Generator 1 &2 module.Reset TP sewer tank.Set rig water/Dog house module.Raise Dog House.SIMOPS:Peak hauling 5 loaded flatbeds fr/;Kalotsa to SRU.Set top drive HPU module.Set mud pit#1,and pump#1 modules.Lower walk ways,attach hand rails,connect all interconnects,hook up koomey lines,power lines,and air lines.;Start up Generator#1,and provide lights to rig.Change out air boots in out board flanges on Pit#1. 6/30/2017 Set boiler,set pump 2,set pits 2 and 3,raise roof tops on pits 2 and 3,hook up cords and equalizer lines,lay felt and liner for catwalk,set centrifuge,set gen 3, set catwalk and beaver slide.;Held PJSM and raised mast,set mud lab and Canrig shack.Received bits,centralizers and"B"section of well head.Day and night rig crews,Drilling Foremen and Peak roustabout attended Swanson River.;general orientation and wildlife interaction avoidance training at main office,given by HSE Rep John Coston.Also met with BLM Rep Amanda Eagle and the two new BLM inspectors.;Set Directional shack.Scope derrick to full height.Secure all turn buckles on torque tube.Finish rigging up pumps.Lay over and secure rain flaps on roof of pit modules.Check all hammer unions.;Remove dunnage and extra felt and liner from location.Stage shaker connex,Peak connex,and spill connex on edge of pad.Pick up and rig up top drive.Dress rebuilt floor tongs.Install remaining.;grounding rods.Install poor boy degasser with first inside pins.Stage riser near cellar on rig mats.Haul off all un-needed materials to storage pad.Run Pason lines to all 3rd party buildings.;Test Gens,mud pump motors.lnstall 70 mesh screens on both shakers.Hang Kelly hose,adjust.Stand up degasser and Din in oleca 7/1/2017 Installed service loop and wrap,installed saver sub,hung rig tongs,RU centrifuge,staged drill subs on rig floor,hung bails and elevators,charged topdrive compensators,changed oil in topdrive;swivel,installed discharge line from poor boy degasser to shakers,Canrig Rep and MWD Reps RU their shacks,took on rig fuel,installed Handy Berm,Total Safety RU gas detection equipment and;calibrated/tested same,Peak removed items not needed on location,strung new drill line through crown and blocks.;Spool up new drill line on draw works,function test all mix pumps,mud pumps.Pressure test lines,mud pumps.Receive MWD/DD tools,off load and stage on Tyler pad.Receive 7"26#L-80 DWC/C surface;casing,stage on Tyler pad.Roll up and palletize old drilling line for haul off to metal dumpster.Round up all felt and herculite scraps.Remove cellar box grating and angle iron cross members.;Pick up and install surface riser,nipple up. RE-install angle iron,grating.Attach clips to grating to secure.Install flow line.Replace leaking 4"butterfly valve from mix pump into pit 4.;Bring on 250 bbls water into pits 2.3 and 4.Test all lines and transfer valves.Roll the pits.Test run centrifuge.;Chain riser off in cellar.Work on rig acceptance checklist. 7/2/2017 Staged Sperry tools,strapped and upload those,brought in 4'W'DP.Built containment for wet dock(drum products),offloaded drum products,RU hurricane vac system,installed wear ring,racked and;tallied DP,PU racked back 70 jnts DP.PU and racked back 9 jnts HWDP and jars.BLM Reps stopped by and waived witnessing our initial BOP test.Mix gel for spud mud.Drift casing on Tyler Pad.;Pick up and make up a stand with Jars and 1 HWDP,rack back.Stage Directional n 0 C, BHA on catwalk while tallying Pason.Building spud mud.;Make up BHA#1.8W HDBS milltooth QHC1 GRC bit,7"MM set on 1.5°,float sub,stab,2 NM flex\' ' collars,HWDP stand.;Trip in the hole.tag @ 125'.circulate @ 130 Gpm.Circulate water out of the conductor,condition spud mud.Mix 10 more sacks of y Gel.;Conduct Pre-Spud meeting in Dog House.with all service hands,Peak crew and Drilling crew.Discuss everyone has stop the job authority,the small location,watch out for each other.Good meeting.;Spud well:Drill 8W surface hole from 125'to 280',415 gpm,450 psi,2-5 k wob,60 rpm,4k fUlbs trq,PU 35 k, SO wt 35 k,ROT wt 35 k.Maintain 200 to 250 viscosity.8.8 ppg MW.50'/hr.;Circulate bottoms up.Clay and gravel on shakers.;Back ream out to the flex collars. 415 gpm,450 psi,50 rpm.;Stand back flex collars.Pick up MWD tool.DM collar.43.90'.;0 bbls solids to G&I,0 bbls cum. 0 bbls class II fluid to G&l,0 bbls cum 0 bbls cement to G&I,0 bbls cum 0 bbls mud loss down hole,0 bbls cum OP7/3/2017 MU DM and ADR collars,MU ALD aTN collars.Upload and shallow test MWD(ok).Load RA so es.RIH w/NM flex DC's,XO's,HWDP and jars to 280'.;Resume drilling 8 1/2"surface hole from 280'to 991'.Rotating wob 8 to 11K,460 gpm-1318 psi,65 rpm-5200 ft/lbs on bott torque,150 ft/hr ROP,MW 8.9 ppg/vis 150.At 363'we are getting dirty;surveys,by 384'they are getting worse with bad mag data.DD put a 40'slide in at 109 magnetic toolface,in an attempt to nudge the well away from the source of interference,which we assume is an;abandon vertical well on the pad.That slide brought the Inc up to 3 degrees and survey quality started getting better.The survey at 517'had a good Bt,but the dip was still out of spec.;Surveys continued to become cleaner,and we got our first good clean survey at 764',showing an Inc of 3.14 degrees,and Azi of 121.19 degrees. Had another clean survey at 828'.;At 991'pumped a hi-vis nutplug condet sweep around at 475 gpm-1465 psi,65 rpm-4500 ft/lbs off bott torque.Sweep came back 40%early by hole volume.Indicating under gauge hole.;Back ream to HWDP stand with jars.8 stands DP,and 4 stands of HWDP.495 Gpm,1432 PP,60 Rpm.Copious quantities of clay balls and paddies came over shakers.;Service rig.Grease blocks,top drive,crown,iron roughneck,draw works.Level rig.Change screens on shakers from 100's to 120's.;Trip in the hole. Ream last stand to bottom.No fill.good displacement.;Resume drilling 8 1/2"surface hole from 991'to 1400'.Rotating wob 8 to 11K,525 gpm-1630 psi,65 rpm- 5200 ft/lbs on bott torque,120 ft/hr ROP,MW 9.2 ppg/vis 100.clean surveys.KOP @ 1200'.;Pump sweep @ 991'MD.50%increase in cuttings.Came back on time.Complete casing tally.Complete casing check list.;Wellbore position:47'from plan.46'high,4 feet right. Nudged well to 3°early to avoid unknown vertical cased hole.;151 bbls solids to G&I=151 bbls total 119 bbls Class II junk fluid to G&I=119 bbls total 0 bbls cement to G&I=0 bbls total 0 bbls mud lost down hole=0 bbls total 7/4/2017 Cont drilling 8 1/2"surface from 1400'to 1490',,Rot wob 10K,524 gpm-1678 psi,65 rpm-5100 ft/lbs on bott torque,150 to 180 ft/hr ROP,MW 9.3/vis 90,ECD's at 9.9 ppg.;At 1490'pumped a 20 bbl hi-vis nutplug sweep around at 527 gpm-1581 psi,60 rpm-4300 ft/lbs off bott torque,did second bott up.Sweep back on time with 50%increase in cuttings.Obtained SPR's.;Pulled up hole on elevators from 1490'to jars at 278'with no issues.;Serviced rig and topdrive.;TIH from 278' to 1490'with no issues.;Continue drilling 8-1/2"hole from 1490'to 2014',sliding as needed;MAD pass all slides. Sliding parameters:ROP 200-250 fph,WOB 10-20K,525 1 R , psi, , 's 8 9.1 ppg mud;Circugpm/late720 sweeppsiwith surface68psi todiff surface.Camepressure.;Rotating back on time.parameters:No increaseOP180 Infph cuttingsWOB seen3-10Kon 525 shakers.gpm/1650 Monitor well.80 Dropped rpms/5500 2"inff-lbs10 mins.EDFill9.3trip with u)\,4tank.;POOH on elevators from 2014 to 314.No issues.Calculated hole fill 10 bbls.Actual fill 17 bbls.Monitor well on trip tank.Establish loss rate©1.2 BPH.;Trip in hole.From 314'to 2014'.Wash&ream last stand down.No fill.Calculate fill 13,actual 11 bbls.;Circulate sweep surface to surface plus one more BU strokes. 20%increase in cuttings.Sweep returned on time. Monitor well.Dropping 2"in 10 mins.Line up on trip tank.;Trip out of the hole to BHA.No issues.Calculated fill 13 bbls,actual 19 bbls.;Prejob meeting.Retrieve sources.Down load.Lay down BHA.SIMOPS:Clean out cuttings tank,pill pit.Stage casing equipment on location.;Clean and clear rig floor.Pull wear bushing.Lay down XO's,bit,bit breaker.;98 bbls solids to G&I=249 bbls total 152 bbls Class II junk fluid to G&I=271 bbls total 0 bbls cement to G&I=0 bbls total 0 bbls mud lost down hole=0 bbls total;Wellbore position:25'to plan.24'high,3'right. 7/5/2017 Continue rigging up;dummy run hanger,install long bails,rig up casing tongs,slips. Bring centralizers on rig floor.;Make up shoe track,check floats-good. RIH with 7"BTC casino as per tallK. Make up landing joint and land hanger at 2004'.;Rig down casing crew,rig up cement head,manifold and bails.;Establish ni circulation and stage pumps up to 6 bpm 268 psi,reciprocating pipe.Continue to rig up Halliburton cementers.;HES loaded lines with 5 bbls water and checked I for leaks.HES pressure tested lines at 1100 low 4000 high,good tests.HES pumped 30 bbls 10.2 ppg Clean Spacer III at 5 bpm,140 psi. HES dropped;bottom t:� plug and pumped 88 bbls(203 sx)12.0 ppg type I/II lead cement at 6 bpm,198 psi,followed by 22 bbls(100 sx)15.4 ppq Class G tail cement at 5 born.150. HES dropped top plug,then;displaced with 73.1 bbls 9.1 ppg Spud Mud at 4 bpm,420 psi.Slowed to 3 bpm with 10 bbl to go.Bumped the plug and held 1200 / psi(FCP of 500 psi)for 5 minutes,bled off and floats held.;Bled back 1.5 bbls to truck.Had 30 bbls Clean Spacer III return to surface and 23 bbls of 12 ppq lead vRcement to surface.Well life was added to both lead and tail cement at 0.5 ppb.Mix;water temp at 83 deg.Pumped 116%excess on lead and 66%excess on tail. C- Reciprocate be string throughout most of the job,landed the hanger 20 bbls into displacement with mud push back;due to hole getting sticky.Had no losses.Up wt 70K,dwn wt 60K at time of landing hanger.CIP at 17:26 hrs,7/5/2017. RD cleaned up and released Halliburton.;Rig down Halliburton cementers.Wash up cement lines to the cuttings tank.Lay out chicksens and swivels from rig floor.rig down hard line and manifold on rig floor.Monitor well through cement head.;Rig down cement head,lay down,back out LJ,Pull out and pick up pack off. RIH with pack off and set.Verify in place by pulling one gland nut.Good.Run in all lock downs.Lay down LJ.;Nipple down surface riser,install wellhead,nipple up.Test void,500 psi low 5 mins,5k psi high 15 mins.,test packoff,500 psi low,5k psi high,5 mins each. SIMOPS:Hauling cement returns to G&I;Lift BOPE stack from carrier with 100 ton crane.Take possession with rig bridge crane,nipple up spacer spool,set BOPE nipple up.SIMOPS:Testing next MWD string. Position drill pipe to be picked up;lnstall flow box,flow line,Kill hose,choke HCR,choke hose.;28 bbls solids to G&I=277 bbls total 409 bbls Class II junk fluid to G&I=680 bbls total 23 bbls cement to G&I=23 bbls total 25 bbls mud lost down hole=63 bbls total 7/6/2017 Double check and tighten all BOP bolts. Install catch can,flowline. Re-install cellar grating. Install flow nipple,chain off stack. Hook up accumulator lines,install fill up line;Lay down casing elevators and bails. Pick up short bails and elevators. Rig up floor,install wear bushing.;Strap,tally,drift and pick up 80 joints of drill pipe in batches of 20 jnts.;Rig up test equipment.Set test plug.Fill stack,choke manifold with water.Shell test to 2500.Held for 30 mins.good.;AOGCC Inspector Guy Cook on location.Test BOPE to BLM initial test criteria.Test#1.UPR,CM 1,3,4,5,7,Mezzanine 4",dart valve,HYD I BOP in TD.Fail/leaking flange between choke side HCR and;manual.Hammer up.restart test#1.Fail.Leak in choke house,#7,function and grease.Pass#1.Tests held for 10 mins each,500 psi low, 3500 psi high.Inspector request we move horn for gas alarms;closer to living quarters for CoMan.Done. All tests held for 10 mins each,500 psi low,and 3500 psi high.Annular also tested to 3500 psi high.Test all pit level alarms,and flow sensor.;Test#2:UPR,CM 2,4,5,6,8,Kill HCR,TIW,Lower I BOP.Good.Test#3 UPR's,Inside manual kill,TIW,CM 7,9,11,13.Fail.Inside manual kill.Grease and function.Re-test#3.Fail.Drain stack,pull;test plug,decide to rebuild inside kill.(Found broken guide.)BLM Engineer Amanda Eagle waived witness of this test.(7-2-17,12:00 HRS).Total safety calibrated,tested all gas alarms,and lights.;Rebuild manual inside kill valve.Set test plug.Fill stack with water.;0 bbls solids to G&I=277 bbls total 70 bbls Class II junk fluid to G&I=750 bbls total 0 bbls cement to G&I=23 bbls total 0 bbls mud lost down hole=63 bbls total 7/7/2017 Continue testina BOPE250/3500 psi. AOGCC Guy Cook witnessed test. BLM Amanda Eagle waived witness. F/P on annular purge air and retested-Pass. / F/P on blinds and inside choke line valve;Grease choke and retest-F,function blinds and inside choke attempt to bleed air-F. Closed HCR choke to trouble (/ shoot and appears to hold better. Pull test plug to drain stack.;pull ported bullnose(ported for a gauge)from annulus valve-appears to be plugged-test plug tl ` rubber good,set plug and attempt low pressure,test plug leaking. Redress test plug.;Test still not holding. Rebuild inside manual choke valve. Rig up and test blinds/manual choke-pass. Test electric choke and manual choke-pass. Accumulator draw down:;starting pressure 3125,final 1450. First 200 psi recharge 1 ffffffllJllJ"'''' 19 sec,full recharge 96 sec;4 N2 bottles at 2787 average.;Clean and clear rig floor,cellar area.Rig down test equipment.Put away tools.(All crew members, service hands given UA test at Production Office.);Pull test plug,set 9.063"ID wear bushing.Run in two lock downs.;Test casing.Flood kill line and casing.Close blinds,pump in kill line with test pump.45 gallons water,pressure up to 3600 psi on chart.Chart for 30 mins,bleed back 44 gallons.Good test.;Rig down test equipment.blow down choke line,manifold.Line up for hard shut in.;Pick up 20 joints 4.5"CDS 40 DP,stand back in derrick.;Pick up 80 joints 4.5"CDS 40 DP, stand back in derrick.;Clean and clear rig floor.Bring BHA components to rig floor.;Tally drill pipe,measure BOPE elevations.;0 bbls solids to G&I=277 bbls total 0 bbls Class II junk fluid to G&I=750 bbls total 0 bbls cement to G&I=23 bbls total 0 bbls mud lost down hole=63 bbls total 7/8/2017 Pick up BHA:6-11°'HDBS55D-5 bla8✓3d PDC bit. SperryDrill mud motor with 1.5°bend,1 rev/gal, collar. measure RFO MWD-MTR=1.87/4.81=139.95°. SP4 collar,ALD,CTN,PWD,TM collar;upload MWD,shallow pulse test,load sources. M/U(2)NM flex collars,(2)HWDP,Jars,and(7)HWDP.;Single in the hole with 36 joints of 4.5"DP to 1537'. Continue RIH with stands from derrick to 1850'. Wash down and tag cement/cement stringer at 1894'. Tag up on plugs at 1918'(on depth);Drill out shoe track 253 gpm/1541 psi with 200 psi diff,30 rpms 4650 ft-lbs,WOB 5-12K. Tag float collar at 1919',shoe at 2004-on depth. Continue drilling to 2034'(20'new hole);Circulate 2 x annular volume at 250gpm/1430 psi,displace to 9.0 ppg 6%KCL PHPA mud.;Clean possum belly,trough, t pit 4 and under shakers.;Circulate even mud around 250gpm/1400 psi 2 x hole volume;Rig up test equipment for LOT.Flood pipe and annulus.Perform FIT to of 12.5 ppg.MW=9 ppg.achieved 360 psi @ 1985 ND.Pumped 8 gallons,bled back 5 gallons.;Rig down.record SPR's.Drill ahead in 6.125"hole.From 2034'to 2229'.Slide 25 feet top of each std, WP#8.250 GPM,1200 PP,5500 TQ on,4500 TQ off,65 RPM,10.39 EMW,9.0 MW.54 up/50 do/52 rot;Drill ahead in 6.125"hole.From 2229'to 2563'.Slide 18 feet top of each stand,WP#8.250 GPM,1235 PP,5900 TQ on,4600 TQ off,65 RPM,10.50 EMW,9.0 MW.Pumped HI-Vis sweep @ 2409.No increase.;58k up,50k Dn,55k Rot.120'/hr.;34 bbls solids to G&I=311 bbls total 311 bbls Class II junk fluid to G&I=1061 bbls total 0 bbls cement to G&I=23 bbls total 0 bbls mud lost down hole=63 bbls total;Wellbore position:5'from plan.5'high,.5'left 7/9/2017 Continue drilling 6-1/8"from 2563'to 2779',sliding as needed to maintain WP08,MAD pass all slides. ROP 120-130 fph;sliding parameters:WOB 1-3K,250 gpm/1280 psi with 60psi diff;Rotating parameters:WOB 1-3K,250 gpm/1282 psi,80 rpmsl6300 ft-lbs ECD's 10.57 ppg with 9.0 ppg mud.;Pump high viscosity sweep(15%increase,on time)and circulate hole clean 250 gpm!1280 psi,40 rpms/4980 ft-lbs. Flow check-static,SPR's.;Wiper trip:PUW 70K,SOW 59K. POOH from 2779'to 1972'with no issues. Hole fill 0.9 bbls over calculated.;Service rig,grease crown,blocks,drawworks top drive.;RIH from 1972'to 2779', washing last stand to bottom with no issues,calculated hole fill.;Continue drilling 6-1/8"hole from 2779'to 3181'. Pump high viscosity sweep sweep once back on bottom(10%increase,on time). Slide as needed to maintain WP08.ROP 120-130fph Sliding parameters:;WOB 4-6K,240gpm/1307gpm with 150 psi diff. Rotating parameters:WOB2-4K 240gpm/1316psi,80rpms/7300 ft-lbs.ECD's 10.8ppg with 9.0ppg mud. Flow rate limited by shakers.;Drill from 3181'to 3523'. 245 GPM,1315 PP,6900 TQ on,5500 TQ off,80 RPM,10.55 EMW,9.0 MW.78 up/60 do/70 rot,Pump low vis sweep,came back 10%late.20%increase in cuttings.;Ream stand slow,CBU.Monitor well.Static.Dropped 5 inches in 10 mins.;POOH on elevators.From 3523'to 2658'.No issues.Rack back 12 stands, pull#13 high.Calc fill=5.2 bbls,Actual fill 7.73 bbls.;TIH to bottom.No fill.No issues.Good displacement.Air out mud pumps after cleaning suction screens. Plugged with polymers.;Drill from 3523'to 3774'. 245 GPM,1315 PP,6900 TQ on,5500 TO off,80 RPM,10.55 EMW,9.05 MW.78 up/60 do/70 rot,Pump Hi vis sweep,came back on time.20%increase in cuttings.;Up wt 76k,Dn wt 58k,Rot wt 66k.Running 20 bph water.;79 bbls solids to G&I=390 bbls total 261 bbls Class II junk fluid to G&I=1322 bbls total 0 bbls cement to G&I=23 bbls total 0 bbls mud lost down hole=63 bbls total;Wellbore position:4'to plan.4'high,1 foot left. 7/10/2017 Continue drilling 6-1/8"hole from 3774'to 4140',sliding as needed to maintain WP08,MAD pass all slide.ROP 90-120fph.Sliding parameters:WOB 8—15K, 242gpm/1629psi with 200 psi diff;Rotating parameters:WOB 8-10K,242gpm/1700 psi,80 rpms/7400 ft-lbs ECD's 10.93ppg with 9.0 ppg mud. M-I representative onsite to attempt and get centrifuge cut drier;Continue drilling 6-1/8"hole from 4140'to 4458'maintaining WP08,no slides. ROP 20-120fph WOB 10-15K,242gpm/1800psi,80 rpms/7300 ft-lbs,ECD 11.25 ppg with 9.0 ppg mud;Directional drilling 6-1/8"hole fr 4458'to 4517'maintaining WP08,no slides. ROP 20-120fph WOB 10-15K,250gpm/1800psi,80 rpms/7300 ft-lbs,ECD 11.65 ppg with 9.0 ppg mud;Short trip depth.Pump low vis sweep surface to surface, 20%increase in cuttings.1620 PP,245 GPM,9 ppg MW.11.65 ECD.Monitor well.Dropped 6 inches in 10 mins.;Pump out with one pump in idle.135 GPM, 825 PP.Pull 4 stands.Bottom of stand#5 pulled tight and tried to pack off.Dropped down and began back reaming.;Back ream out to last short trip depth.3460' MD.Shakers carried a lot of cuttings during the trip.250 GPM,1550 PP,5 to 7k TQ.;Monitor well.Static.Empty trip tank.Turn around elevators.;Trip in hole on elevators.No issues.No fill.Good displacement.Calc 6.8,actual 6.5 bbls.;Continue drilling 6-1/8"hole from 4517'to 4769'maintaining WP08.ROP 20-120fph 10% ed after short trip.80 r ms/8k ft-lbs 2100 on bottom with 500psi differential. increase in cuttings swee � um WOB 10-15K,250gpml1600psI off bottom, g p,p P P P on,5.5k off, ECD 11.09 ppg with 9.05 ppg mud.;38 bbls solids to G&I=428 bbls total 162 bbls Class II junk fluid to G&I=1484 bbls total 0 bbls cement to G&I=23 bbls total 0 bbls mud lost down hole=63 bbls total;Wellbore Position:8'to plan.3'low,7'right. 7/11/2017 Continue drilling 6-1/8"hole from 4769'to 4972'sliding as needed to maintain WP08. Sliding parameters 20-60 fph,254gpm/1867psi with 182psi diff. Increase flow rate to 290gpm/2324psi as;shakers allow. Rotating parameters:ROP 20-100fph,290gpm/2167psi,80 rpms 8400ft-lbs. ECD's 11.75ppg with 9.0ppg mud;Continue drilling 6-1/8"hole from 4972'to 5132'as per WP08. Pump sweep at 5040'with 20%increase in cuttings and on time.Sliding parameters 10-30 fph,292 gpm/2164psi with 40psi diff;Rotating parameters:WOB 4-14K,10-100fph 290gpm/2300psi,80rpms/8500ft-lbs,ECD's 11.75ppg with 9.0ppg mud. Attempt to vary parameters to increase ROP,pump low viscosity nut plug sweep;for bit balling at 5073',and 5133'.;Cont.drilling 6-1/8"hole from 5132'to 5515'. 280 gpm,2200 psi,PU 110 wt K,SO wt 70 k,ROT wt 82 k,80 rpm,7.5-8 k ft/lbs trq,ECD 12.23 ppg with 9.1 ppg mud wt.;Pump sweep&circ hole clean for wiper trip.265 gpm,2100 psi,50 rpm,7.5 k ft/lbs trq.25%increase in cuttings with sweep.;68 bbls solids to G&I=496 bbls total 272 bbls Class II junk fluid to G&I=1756 bbls total 0 bbls cement to G&I=23 bbls total 30 bbls mud lost down hole=93 bbls total;Distance to Plan:9.46'(1.96 low/9.26'right) 7/12/2017 Continue circulating hole clean 290gpm/1789 50rpms/7618ft-lbs. SPR,flow check,slight drop.;POOH from 5515 to 1970'. Consistent 5-15K drag to 3600'. Tight at 4576'(30K),4498(30K),4349'(35K),4170'(35K),4051'(40K),3942'(40K),and 3460'(40K). Wipe tight spots 1-2 times until clean.;Service rig; grease/inspect blocks,top drive,draw works,brakes. Monitor well on trip tank 1.2 bph static loss rate.;RIH from 1970'to 4450'with no issues,fill pipe every 20 stands,observe 225U of gas while filling pipe.;Circulate surface to surface 225gpm/1550psi,30rpms/6800 ft-lbs max gas 2144U;RIH from 4450 to 5455',wash and ream down to 5515';tight at 5455'with 20K down;Pump low vis/nut plug sweep and circulate it out of the hole at 290gpm/2350psi, 80rpm/8500 ft-lbs. Sweep on time,with no increase in cuttings.;Continue drilling 6-1/8"hole from 5515'to 5616'sliding as needed to maintain WP08. Sliding parameter:ROP 10- 50 fph,WOB 10-15K,290gpm/2600 psi with 254psi diff.;Rotating parameters:ROP 15-120fph,WOB 14-20K,290gpm/2520psi,80rpms/8200 ft-lbs. ECD's 12.04 ppg with 9.15 ppg mud.;Cont.drilling 6-1/8"hole from 5616'to 6078'.275 gpm,2678 psi,PU 112 wt K,SO wt 74 k,ROT wt 86 k,80 rpm,7-8.5 k ft/lbs trq,ECD 12.85 ppg with 9.15 ppg mud wt.;Pump low vis sweep&circ hole clean to reduce ECD's;Distance to Plan:5.97'(5.96 low/.41'right);25 bbls solids to G&I=521 bbls total 135 bbls Class II junk fluid to G&I=1891 bbls total 0 bbls cement to G&I=23 bbls total 4n hi-4Q mi irl Inco rinwn hnla=194 hhle ental 7/13/2017 Continue to circulate low vis sweep out of the hole,20%increase in cuttings.;Continue drilling 6-1/8"hole from 6078'to 6514'as per WP08,MAD Pass all slides. ROP 20-100 fph,80 rpms/9500ft-lbs,282gpm/2678 psi,12.4-12.5 ppg ECD's;Slow pump rate in stages to minimize ECD's down to 210 gpm/1950psi with 11.5- 11.6 ppg ECD's,little to no noticeable decrease in ROP. PUW 150,SOW 92,ROTW 114;Pump tandem low vis/high vis sweep(on time 20%increase)210 gpm/1645psi,80rpms/9200 ft-lbs and circulate hole clean. SPR and flow check.;POOH wiper trip from 6514'to 5496'with no issues.;Circ B/U while service rig.;RIH from 5496'to 6514';Cont.drilling 6-1/8"hole from 6514'to 6734'.210 gpm,2000 psi,PU 132 wt K,SO wt 82 k,ROT wt 100 k,80 rpm,10 k ft/lbs trq, ECD 11.6 ppg with 9.2 ppg mud wt.;Distance to Plan:2.41'(1.21 low/.41'right);59 bbls solids to G&I=580 bbls total 281 bbls Class II junk fluid to G&I=2172 bbls total 0 bbls cement to G&I=23 bbls total 30 bbls mud lost down hole=153 bbls total 7/14/2017 Cont.drilling 6-1/8"hole from 6734 to69'sliding as needed to maintain WP08. Sliding ROP 25- ,WOB 10-14K,225gpm/2329psi with 233psi diff;Rotating parameters:WOB 10-15K ROP:10-20fph up to 70-120fph at 6774',80rpms/11400ft-lbs,210 gpms increasing to 225gpm/2200psi for MWD detection. ECD's 11.65ppg with 9.15ppg mud;Cont.drilling 6-1/8"hole from 6869'to 7046 sliding as needed. Sliding ROP 10-40fph,WOB 5-10K, 225gpm/2125psi with 130psi diff.;Rotating parameters:WOB 6-14K,50-120fph,225gpm/2100psi,80rpms/11800psi,ECD's 11.65ppg with 9.15ppg mud.;Cont. drilling 6-1/8"hole from 7046'to 7450'.210 gpm,2000 psi,PU 162 wt K,SO wt 90 k,ROT wt 110 k,80 rpm,10.5-12 k ft/lbs trq,ECD 11.8 ppg with 9.2 ppg mud wt.;Distance to Plan:4.92'(.57'low/ 4.89'right);55 bbls solids to G&I=635 bbls total 335 bbls Class II junk fluid to G&I=2507 bbls total 0 bbls cement to G&I=23 bbls total 30 hhls mud lost down hole=189 hhls total 7/15/2017 Continue drilling from 7450'to 7512'. ROP 40-100 fph,8orpms/11620ft-lbs,214gpm/2282psi,ECD's 11.9ppg with 9.2ppg mud. Shut pumps down x2 to collect surveys,on bottom and top of stand.;Circulate hole clean 212gpm/1900psi,80 rpms/11100 ft-lbs. At bottoms up from shutting pumps down observe gas spike 2227u and 1726u,circulate out. Flow check,CBU with 2193u of gas. Weigh mud;system up to 9.45ppg. Shut down pumps for 4 min and circulate towhile continuing to weigh mud up to 9.6ppg.30u of gas observed at bottoms up(15u back ground gas). SPR's and flow check,static;POOH to 6450'with no issues, hole fill 3 bbls over calculated;Service rig,grease/inspect blocks,top drive,draw works,brake Iinkage;RlH from 6450'to 7512',tight at 7315'25K over,wipe through. Wash last stand to bottom,10'of fill. Displacement 2 bbls shy from calculated. Wiper gas 1962u.;Continue drilling from 7512'to 7560'. ROP 15- 85fph,204gpm/2121 psi,8orpms/10500 ft-lbs,ECD's 11.9-12.0ppg with 9.6ppg mud.;Cont.drilling 6-1/8"hole from 7560'to 7761'.210 gpm,2000 psi,PU 170 wt K,SO wt 90 k,ROT wt 110 k,80 rpm,10.5-12 k ft/lbs trq,ECD 11.9 ppg with 9.6 ppg mud wt.;While attempting to back ream stand prior to making connection experienced tight hole&not able to work past 7620'.It appeared BHA was hanging up on coal seams.;BROOH 2 stands to 7575'working coal seams @ 7690'&7658'.Pumped sweep&circ hole clean.30%increase in cuttings,lots of fine coal pieces.;W&R back in hole from 7575'to 7761'.;Cont.drilling 6-1/8" hole from 7761'to 7857'.200 gpm,2050 psi,PU 170 wt K,SO wt 90 k,ROT wt 110 k,80 rpm,10.5-12 k ft/lbs trq,ECD 12 ppg with 9.6 ppg mud wt.;Distance to Plan:6.5'(5.86'low I 2.8'right);52 bbls solids to G&I=687 bbls total 208 bbls Class II junk fluid to G&I=2715 bbls total 0 bbls cement to G&I=23 bbls total 35 bbls mud lost down hole=218 bbls total 7/16/2017 Continue drilling from 7857'to 8101'. ROP 50-100fph diminishing to 10-20fph at 7911'. Vary WOB and pump rate in attempt to increase ROP. Pump low viscosity nut plug sweep at 7980',pick up just;off bottom while sweep exits the bit. Continue drilling ahead with 50-70fph with 12-14K on bit to 8057',where ROP diminished down to 10-15fph,vary parameters. Pump low vis nut plug sweep at 8081';with no increase in ROP. Pumping 212 gpm/2344psi,8orpms/10700ft- Ibs,ECD's 12.2ppg with 9.7ppg mud.;Cont.drilling 6-1/8"hole from 8101'to 8511'.210 gpm,2250 psi,PU 180 wt K,SO wt 90 k,ROT wt 110 k,80 rpm,11.5- 12.5 k ft/lbs trq,ECD 12.4 ppg with 9.7 ppg mud wt.;Changed out liners in mud pump#1 to 5"to aid in pump performance.Pumping lube sweeps to aid in weight transfer to bit.;Distance to Plan:21.42'(21.04'low/ 3.98'right);23 bbls solids to G&I=710 bbls total 212 bbls Class II junk fluid to G&I=2927 bbls total 0 bbls cement to G&I=23 bbls total 30 bbls mud lost down hole=248 bbls total 7/17/2017 Continue drilling 6-1/8"hole from 8511'to 8605';ROP 60-90fph,210gpm/2610psi,80rpms/11692 ft-lbs,ECD's 12.6ppg.;Observe consistent 1500-2800u of gas. Circulate out gas at 8605'. Gas consistently maintains at 1500u to 2600u after bottoms up. Continue circulating raising flow rate to 222gpm/2320 psi with ECD's;12.6-12.7 ppg. Observe gas fall with higher ECD's. One gas spike at 1374u after bottoms up when ECD's fell to 12.45-12.5ppg. Gas consistent under Start weighing mud system up by 0.2ppg at a time.;100u with steady 10.6ppg ECD's. Start weighing mud system up by 0.2ppg at a time. Discuss options with town.;Drill ahead to 8630'(same stand)for casing point(TD 70%claystone). Shoot survey with 10.45ppg mud in the hole,bottoms up gas 1892u with flow out increasing from 26%to 40%.;Distance to Plan:38.42'(37.32'Low/9.09'Right);Continue weighing mud up from 10.45ppg to 11.0 ppg,while adding additional background LCM. Shut pumps down with 11.Oppg mud for 4 minutes and circulate bottoms up.;Max gas 1785 units,Continue weighing up to a 11.2 ppg mud weight going in.;Wt up to 11.3 ppg,shut down pumps&circ B/U max gas 900 units.Wt up to 11.5 ppg,shut down pumps&circ B/U max gas 570 units.Wt up to 11.7 ppg,shut down pumps&circ B/U max gas 483 units.;Wt up to 11.9 ppg,shut down pumps&circ B/U max gas 151 units.Wt up to 12.1 ppg,shut down pumps&cont.to circulate.;Start weighting up towards 12.3ppg,113 gpm,1300 psi,ECD's 13.55ppg,seepage losses 5-10 bbls/hr;28 bbls solids to G&I=738 bbls total 137 bbls Class II junk fluid to G&I=3064 bbls total 0 bbls cement to G&I=23 bbls total 120 bbls mud lost down hole=368 bbls total 7/18/2017 Continue to weigh up to 12.3 ppg while circulating bottoms up after shutting pumps down with 12.1 ppg mud. Bottoms up gas 65U. ECD's ranging 13.8-13.9 ppg at 113 gpm,seepage loss rate 3.5 bph.;With 12.3 around Shut down and check bottoms up gas=21 units. Circulate 12.4 ppg mud all the way around. Obtain SPR's.Flow check=static.;Pulled up hole from 8630'to 8257'on elevators(5 stands)with no issues.Up wt 215K,dwn wt 90K.Calculated hole fill=2 bbls,actual hole fill 2.6 bbls.;TIH on elevators with no issue,MU last stand and filled pipe as we slowly washed to bottom.;Cont to circ bottoms up with pump at idle,116 gpm-1300 psi,50 rpm-11,500 ft/lbs off bottom torque.Had a max of 681 units at bottoms up.Gas climbed,peaked then dropped to 46 units over 12 minutes.;Added 1 drum of Drill-n-Slide to suction pit during circ,and spotted same outside drill string.Pulled 30'off bottom and down pump.Monitored well 15 minutes.Fluid dropped 3"over 15 minutes.;Pulled OOH on elevators from 8630'to 7850'with no issues.At 7850'pulling tight(50K over).MU topdrive and backreamed slowly from 7850'to 7760'with pump at idle,.30 rpm.Cont to pull on;elevators from 7760'to 6885'then pulling tight.Back reamed from 6885'to 6825'.Cont pulling on elevators from 6825'to 6325'.Had 8 tight spots we worked on elevators and able to clean up.;Cont POOH on elevators from 6325'to 5450', back reaming various tight spots;BROOH due to tight hole from 5450'to 4460',110 gpm,1000-1200 psi,30 rom,10-11 k trq;Cont.POOH on elevators from 4460'to 1970',no issues;Service rig and monitor well on trip tank.Lost 0.5 bbls in 30 min;Cont.POOH on elevators from 1970'to 110'(rack back flex collars, HWDP&jars);7 bbls solids to G&I=745 bbls total 63 bbls Class II junk fluid to G&I=3127 bbls total 0 bbls cement to G&I=23 bbls total 75 bbls mud lost down hole=443 bbls total 7/19/2017 Cont LD directional BHA,held PJSM and removed RA sources,plug in and upload MWD data,cont LD BHA.Bit graded at 2-1 and was in gauge.Hole taking 1 bph static loss.;Clean and clear rig floor,drain BOP stack,PU test jot and pull wear ring.Set test plug and RU test equipment.Flood surface lines and stack then purged air.Shell test stack(OK).;Test all BOPE at 250 low,3500 high(250/2500 on annular)with 3 BLM Reps as witness.Witness waived by AOGCC Rep Jim Regg on 7-18-17.Had one fail/pass on inside manual kill valve.;Blow down,re-align valves,RD test equipment.Pulled test plug,set wear ring.;MU 6 1/8" cleanout BHA(roller cone,bit sub and NM flex DC's),HWDP,jars and HWDP to 375.5'. Cont TIH on 4 1/2"DP from 375'to 1992';Fill pipe&circ B/U,117 gpm, 200 psi,max gas 28 units;Slip&cut 122'drill line.;Cont.to RIH with clean out BHA from 1992'to 3793',(no issues);Fill pipe&circ&cond mud to 12.4 ppg In/Out,117 gpm,440 psi,549 max gas units,Lightest mud wt observed 12.2 ppg;Cont.to RIH with clean out BHA from 3793'to 5723'(no issues);Fill pipe&circ &cond mud to 12.4 ppg In/Out,117 gpm,564 psi,1626 max gas units,Lightest mud wt observed 12.2 ppg;Cont.to RIH with clean out BHA from 5723'to 7531' (no issues up to 6526,then few minor tight spots,picked up&work thru once with no problem)Disp Calc=52 bbls/Act=48 bbls;Fill pipe&circ&cond mud to 12.4 ppg In/Out,117 gpm,1000 psi;0 bbls solids to G&I=745 bbls total 0 bbls Class II junk fluid to G&I=3127 bbls total 0 bbls cement to G&I=23 bbls total 30bbls mud lost down hole=473 bbls total 7/20/2017 Cont circulating at 7531'.117 gpm-8 Si,50 rpm-8319 ft/lbs off bott torque.Had a max of 1567 un at bottoms up.Did one full circ to get good 12.4 ppg all the way around.;Cont TIH on elevators from 7531'to 8589'with no issue.MU topdrive.;Filled pipe,started rotation and washed down from 8589'to bottom at 8630'. Had+1-17'of fill.Circ at 113 gpm-906 psi,50 rpm-10,500 ft/lbs off bott torque.Had a max of 1090 units gas at bottoms;up.After bottoms up pumped a 20 bbl hi- vis nutplug sweep around with no increase in cuttings.Also added 1 drum Drill-n-Slide to suction pit and spotted that outside drill string.Obtained SPR's.;Pulled up hole slowly,6 stands with no problem.Up wt 185K.Hole fill looks good.Flow check=fluid dropped 3'in 5 minutes.Pulled and racked back 5 more stands with no problem to 7966'.;Cont to POOH LD 4 1/2"DP from 7966'to 4450'.Hole fill thus far:calculated 26 bbls,actual 34 bbls.;Cont POOH LD 41/2"DP from 4450' to 1977';F/C(fluid level dropping).Clean&clear floor.Prep for for E-Line;R/U E-Line&Gyro Data tools.RIH with Gyro to 1000'.POOH collecting surveys every 100'.RID E-Line&Gyro Data.;Cont.to POOH&UD drill pipe from 1977'to 375';RIH remaining 20 stands in derrick from 375'to 1619;POOH&UD drill pipe from 1619'to 375'.UD HWDP,Jars&clean out BHA.;9 bbls solids to G&I=754 bbls total 81 bbls Class II junk fluid to G&I=3208 bbls total 0 bbls cement to G&I=23 bbls total 21 bbls mud lost down hole=494 bbls total 7/21/2017 Cont to POOH LD remaining BHA,bit sub and bit.Bit grade=1-1;Clean and clear rig floor,drained stack and retrieved wear ring,dummy ran 4 1/2"x 10 3/4" casing hanger/landing jnt,C/O to long bails,hung casing elevators and tongs,RU fill up line.;Staged centralizers,staged Peak trailer with casing and load pipe �/` rack,stage circ swedges.Replaced pipe skate cable while RU for casing run.;Held PJSM with rig team and Weatherford casing crews.;MU shoe track assembly (single jnt shoe track),fill pipe and check float equipment(ok),cont PU and single in hole with 4 1/2 12.6#L-80 TXP casino to 2000'(7e jnts).MU circ swedge ,`V and topdrive.;Perform one full circ at 113 gpm-150 psi and had a max of 556 units gas at bottoms up.Shut down and remove topdrive/circ swedge.;Cont to PU single in hole from 2000'to 2980'and had to work through tight spot(coal seam and just starting through a slide section).MU circ swedge and topdrive.;Circ at i, 113 gpm-232 psi,replace 1/2"bolt on topdrive dogbone pin bracket.Had a max of 579 units gas at bottoms up.Shut down pump and removed topdrive and circ (/ U swedge.;Cont to PU single in hole from 2980'to 4332'.MU topdrive and circ swedge.Calculated displacement=21 bbls,actual displacement=17.5 bbls (3.5 bbls lost);Circ at 113 gpm-350 psi.Had a max of 922 units gas at bottoms up.Shut down pump and removed topdrive and circ swedge.Replaced grabber dies on --- 've.;Cont to run 4 1/2"TXP from 4332'to 6458';Circ at 113 gpm-607 psi.Had a max of 1100 units gas at bottoms up;Cont to run 4 1/2"TXP from 6 0'7288'4 swell packer&attempt to RIH.started taking wt once swell packer entered 7"casing top.POOH&double check od of swell packer.OD=6.43.UD swell packer ont to run 41/2"TXP from 7288'&land on hanger©8625.34'(Disp Calc=42.4 bbls/Act=38.1 bbls)No issues running casing;Circ&cond •r cement j...113 gpm-650 psi.Had a max of 975 units gas at bottoms up.HES on location @ 430 hrs.Spot truck into position&start riggin�up for cement job.,;• .• solids to G&I=790 bbls total 0 4 bbls Class II junk fluid to G&I=3212 bbls total / 0 bbls cement to G&I=23 bbls total ,, "` GSL 28 bbls mud lost down hole=522 bbls total PGL 7/22/2017 Cont circulating 4%"casing with hanger 2'off seat,while RU and staging cementing equipment.113 gpm-620 psi.Up wt 105K,dwn wt 45K.BGG at 29 units. ,` Loaded plugs in plug launcher,shut down pump;and attempt to slack off 2'to land hanger.String would not move.Worked pipe a dozen times at 180K up,12K t,}v down while pumping and string came free.Slacked off and landed hanger,shut down pump.;Removed topdrive and circ swedge.MU plug launcher and k,,` A hardlines.Halliburton pumped 10 bbls to cuttings box,then 5 bbls down casing to purge air and flood lines for testing.;Halliburton pressure tested lines at 300 low *%\v 5000 high,good tests.Halliburton pumped 28 bbls of 12.9 ppg Clean Spacer Ill at 3 bpm,860 psi and shut down.Halliburton dropped bottom plug and- A. pumped;166 bbls(490 sx)12.8 ppq Type I-II cement at 3 bpm,670 psi,followed with 27 bbls(120 sx)of 15.3 ppq Class G Tail cement at 3 bpm.650 psi. Halliburton dropped top plug,then displaced with 10;bbls fresh water,followed by 120 bbls 3%KCL at 3 bpm,1050 to 3700 psi.Slowed to 2.5 bpm with 10 bbls to go.Started seeing spacer returns 90 bbls into displacement,and cement 117.5 bbls into;displacement.Diverted returns to cellar box through annulus valve at first sign of spacer.Bumped the plug(calc=130.44 bbls,actual=130 bbls)and held 4200 psi(FCP 3700 psi at 2.5 bpm)for 3;minutes,bled off and floats held. Bled back 2 bbls to truck.Had 13 bbls of 12.8 ppg cement to surface.WellLife 1094 was added at 1/2 ppb,to both lead and tail.Mix water temp=69 deg. Pumped 50%;excess on both lead and tail.Could not reciprocate the string due to differential sticking.Lost 19 bbls throughout the job.Up wt 105K,dwn wt 45K prior to landing hanger.TOC at surface,top of;tail at+/-7084'. CIP at 10:32 am,7-22-17. Wait on cement 25 hrs on lead,21 hours on tail prior to testing casing. RD and released mudloggers.;RD hardlines and cement manifold.Flush out stack and hanger.Back out landing joint and MU packoff assembly.Land packoff and RILD's.Test packoff at 500 and 5000 psi 5 min each,good tests.;LD landing joint.RD casing elevators and long bails.Flush mud pumps,surface lines and Kelly hose with soap water.Blow down surface lines and hoses,remove all subs and rig tongs from rig floor.;RD Kelly hose,saver sub, IBOP,service loop.RD and LD topdrive.Haul off 450 bbls mud to Tyler Pad for workover rig.Haul mud to G&I.Clean pits.Shipped Weatherford casing equipment.;Cont.W.O.C.Clean derrick,roughneck,&rig.R/D top drive HPU.Remove swabs,liners&valve seats from mud pumps.;Cont.W.O.C.R/D floor equipment,stand pipe&iron roughneck.Clean cat walk.R/D mud loggers shack.R/D gen 3.RID misc ground tools&equipment;39 bbls solids to G&I=829 bbls total 528 bbls Class II junk fluid to G&I=3740 bbls total 13 bbls cement to G&I=36 bbls total 31 bbls mud lost down hole=553 bbls total 7/23/2017 Cont to clean pits,suction lines and rig while waiting on cement for casing test.RU chart recorder and test hoses.;Fill kill line with water and purge air from ram cavities.Close blinds,pressure up and test 4 1/2"casing at 3500 psi for 30 minutes on chart.Good test.Bled off and RD test equipment.Set BPV.;ND flow line, ‘ �� flow riser and drip pan.Remove kill and choke lines.Open doors and remove ram bodies.Pressure wash ram cavities and close up.Remove stack from wellhead and trolly to end of sub.;Set dry hole tree in cellar,NU same.Pull BPV and install 2 way check.RU and test hanger void at 250-5000 psi for 10 minutes each,then uk IA l tested tree at 250-5000 psi for 10 minutes each.Good tests.;Pull two way check and secure tree/well.;Cont cleaning under rig floor around rotary beams,cont prep vaccum degasser for removal. Rig Released at 18:00 hrs on 7-23-17:R/D gas buster.Clean out Rotary table.Clean sub base&cellar.Cont.to clean around rig.Prep 3rd party shacks for move.Slip&cut 35'drill line.;Prep derrick&scope down.Unspool drill line.RID pits&pumps.Prep derrick to lay over. Cont.cleaning rig&pad.;8 bbls solids to G&I=837 bbls total 152 bbls Class II junk fluid to G&I=3892 bbls total 0 bbls cement to G&I=36 bbls total 0 bbls mud lost down hole=553 bbls total 7/24/2017 Cont cleaning under sub base,RD koomey lines,disconnect shaker#2 electrical for change out,disconnect pit module#2 roof electrical for removal,pull bladders from;pulsation dampeners,spool up various cords and hoses,ship mud products back to Nikiski,Total Safety RD all gas detection equipment.Received verbal approval to prep and;move to Pad 12-27 at 12:40.Removed valve seats from pump#1 (took some doing).HSE Rep John Coston stopped by for a visit.No issues.;Cont.to remove bladders from pulsation dampeners on pumps.Remove shakers from pits.R/D centrifuge.R/D boilers.R/D pason lines&electrical lines. Prep modules for trucks.:Cont.to clean ria&preppina for ria move&cold stack. 7/25/2017 Lay felt and liner on SRU 12-27 to receive SLR 169 for cold stack.Lay out rig mats.Cont to clean rig,rig down electrical lines to carrier.Lower dog house. Remove light off of pit;modules,pump modules,dog house,and choke house.Moly mist pump seats,disconnect power lines to choke house.Pressure wash and clean crown section of derrick.RD derrick board.;Pressure wash and clean cellar box.Haul rig matts to next location.Shipped 400 bbl upright tank,excess casing,hurricane vac's,Canrig shack and Sperry shack.Weatherproof electric cord ends.;No activity on rig. All crews working Daylight tour. 7/26/2017 RD Handy Berm,held PJSM with Pea rivers and rig team.Spotted crane and picked BOP stack fr cellar trolly's and set in cradle.Shipped out catwalk, picked centrifuge,picked iron roughneck,;Transported doghouse,mud pits 1,2&3,pump#2.Rig down comm tower.Transported#1 mud pump,HPU skid and boiler skid.Loaded exposed rig mats.Spotted cranes and removed derrick house;Fold down derrick wind walls,picked derrick off carrier,picked carrier off of sub, picked sub off of pony walls.Transported pony walls to 12-27 pad.Relocated cranes to 12-27 Pad.Set rig mats,;pony walls,spotted cranes and set sub on pony walls,set carrier on sub,sets pits 1 and 3,set doghouse and raised same,set gen 3,set gen 1-2 skid,set HPU,set pump skids,set boiler,set SLR CO;shack,set BOP cradle,set catwalk,installed Handy Berm around entire footprint.Cleaned liner on 241-33.;No activity,all crews on daylight tour. • S n. Hilcorp Energy Company Composite Report , Well Name: SRF SRU 241-33 � ir" Field: Swanson River �D County/State: ,Alaska p)`.. (LAT/LONG): :vation(RKB): �►�� API#: 50-133-20663-00 Spud Date: p �! rck Job Name: 1711425C SRU 241-33 Completion j' Contractor ti. 6 G, AFE#: AFE$: . .... ... .... ..... . 8/2/2017 Meet SLB at office.PTW and J.S.A.Mobe to location.Spot equipment.SLB goes over tool with Hilcorp intern.Rig up lubricator.PT to 250 psi low and 4500 psi high,RIH with SLB PNX logging tool and tie into LWD log.Tag bottom at 8568'.Start logging up at 200'per hour(Approx logging time 24 hrs). 8/3/2017 Continue to run PNX log.Run a repeat log from 6150'to 6350 and 8030'to 8050'at 200'per hour.POOH.,RIH with SLB CBL and log from 8570'to surface, Looks like good cement to—surface.,Riq down lubricator and turn well over to field. 8/9/2017 ARRIVE @ SWANSON RIVER,JSA,PERMITS,JOB SCOPE RIG UP TO TUBING,FILL TUBING,PRESSURE TO DESIRED PR`FISSURE,NO COMM.W/IA BLEED OFF 84 RIG UP TO IA.PRESSURE UP/BLEED OFF SEVERAL TIMES jf REALEASED FROM WELL. 8/16/2017 Mobe to location. PTW and JSA.Spot equipment. Rig up lubricator.PT to 250 psi low and 4500 psi high.,RIH w/Halliburton CAST Log and tied into SLB CBL to 3052'.Logged from 3052'to surface with 350 psi on well.Good data.,Rig down lubricator and turn well over to field. 9/6/2017 Mobe to location.PTW and JSA.Rig up lubricator,PT to 250 psi low and 2500 psi high.TP-0 psi,RIH w/HLB RMT3D/Press/Temp tool to 8556'.Log from 8556'to 3500'at 15'per min.POOH.Good data.,Riq down lubricator and turn well over to field. 9/13/2017 Obtain PTW. Hold safety meeting. Spot in equipment. Start rigging up SLB CTU 13 with 1.75"CT. Rain for rent tanks on location. Build pit liner and berm.,Start BOPE test. BOPE system: Combi rams dressed with 1.75"Blind/Shear rams top set.Bottom set 1.75"pipe/slip rams. Test BOPE equipment and choke valves to 250/4500 psi. 24 hr BOPE test witness notification sent 9/12/17 @ 13:28 hrs. Given permission to test as scheduled. If State rep isn't on location during time of test witness is waived. BOPE test complete.,Weatherford tool hand arrives from the slope to Kenai. At shop checking out tools. Location walk around completed by company Rep. Wellhead secure. Crews off location. 9/14/2017 Arrive at office. Obtain PTW. Hold safety meeting and discuss job procedure. Travel to 241-33 pad. Fire equipment. Pick injector head. Stab 20' lubricator. Trim 15'of CT.,Make up Weatherford Thru Tubing Motor and mill assembly. 2.875"x2.5'MHA,(7/8"disconnect ball)(3/4"circ sub ball). 2.875"x12' CTD motor, 3.65"5 blade convex button mill. (MHA was pull tested to 25k and pressure tested 250/3500 psi),Stab on well. Correct to RKB. Pressure test stack to 250/4500 psi for 5 minutes.Good test. Open master and swab 23.5 turns. RIH without pumping. Dry tag TOC @ 8575'. 28 bbls returned for pipe displacement. Confirmed well was full.,Online down CT with water at 1.5 bbls/min. Free spin 3108 psi. Start seeing motor work at 8575' Mill to 8583.5'. Lost ROP. Stack 10k not able to stall motor or get motor work to increase over 200 psi. Float collar with cement wiper plugs start at 8582' as per tubing tally. Work CT mill.,Pick up and RIH at 80 ft/min trying to stab and chunk up wiper plugs. With this method we saw better motor work. Either no cement is holding wiper plugs in place or we broke them free and they are spinning. Attempt to stack on wiper plugs while pumping and spinning motor and mill 1.5 bbls/min shut down pump and relax pressure.,with weight stacked ramp up pressure to 3800 psi in attempt to destroy wiper plugs. Orange rubber chunks seen in return tank. Looks like we made it through the plug. Start seeing weight stack with motor work and both break back together. ROP.3 ft/min. Back milling cement. Milled to 8610.9' Pump bottoms up.,Drop 3/4"ball to open circ sub. ball on seat. sheared circ pins at 2934 psi. N2 cooled down. PT lines 250/4500 psi.,Online down CT with N2 at 1500 scf/min. 1892 psi circ pressure. Returns at surface. N2 at surface. returned 133 bbls of 3%KCL from wellbore. Blowing dry at tank. Start POOH to surface. Close in choke. Line up N2 down backside coil isolated. Pressure up wellbore to 3200 psi.,Continue to POOH. Tagged up at surface. Master swab closed 23.5 turns. 3278 psi SITP. Start rigging down CTU. Location rigged down. SLB CTU equipment will stay on location. Will have peak vac truck dispose of remaining fluid in return tanks. 377 bbls total. 9/18/2017 Sign in.Mobe to location.PTW and JSA.Rig up Lub,PT to 250 psi low and 4500 psi high.TP-3156 psi.,RIH w2-7/8"x20'Razor HC,6 spf,60 deg phase and tie into OHL.Tag TOC at 8604'.Run correlation log and send to town.Get ok to perf from 8585'to 8595'.Spotted and fired gun with 3156 psi on tubing.Did not see any in pressure.POOH.All shots fired and gun was had some mud in bull plug.,RIH w/Gama/CCL tie into OHL and tag TOC at 8604'and log to 8400'. Send to town.POOH,RIH w/GPT tool,tie into OHL and tag at 8604'.Found fluid level at 7988'with 3184 psi on tubing.,Rig down lubricator and secure well. Will perforate again in the AM. 9/19/2017 Sign in.Mobe to location.PTW and JSA.Rig up Lub,PT to 250 psi low and 4500 psi high.TP-3368 psi.,RIH w/GPT tool and find fluid level at 8002'.Bled pressure from 3368 psi to 3000 psi while checking for cooling effect.Shut well in for 37 min and pressure built to 3057 psi.Made a few runs across perfs. Found fluid level at 7988'with 3069 psi on well.Send log to town.POOH.,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 perf from 8538'to 8558'.Spotted and fired gun with 3226 psi on tubing.After 5 min tubing pressure was 3229 psi.POOH.All shots fired,Riq down lubricator and turn well over to field. 9/22/2017 Sign in.Mobe to location.PTW and JSA.Rig up Lub,PT to 250 psi low and 4500 psi high.,RIH w/GPT tool,tie into OHL and tag fill at 8600'.Well flowing —280K at 1650 psi.Found fluid level at 7720'.Send log to town and POOH.,Rig down lubricator and turn well over to field.Move to SRU 14-15. 9/28/2017 Sign in.Mobe to location.PTW and JSA.Spot and rig up equipment.Wait on wellhead cross over to come from town.PT to 250 psi low and 4500 psi high.,RIH w/GPT tool and tie into OHL.Tag at 8581'.Run correlation log and send to town.Found Fluid Level at 7783'w/TP at 3047 psi.Get ok to use this log to set packer with.POOH,RIH w/CCL-GR,and Tri-Point 4-1/2"Model D packer assy(15.15'long)with 2 burst disks in dual isolation sub(5000 psi each)and tie into GPT log.Tag at 8585.6'. Run correlation log.Set packer top at 8565'and set packer with 3090 psi on tubing.Lost 150 lbs line tension when packer set.Pick up 30'and go back down and tag packer.POOH.,RIH w/2-7/8"x20'HC Razor,6 spf,60 deg phase and tie into GPT log.Run correlation log and send to town. Get ok to perforate from 8355'to 8375'.Bled tubing pressure from 3092 psi to 2615 psi.Spotted gun and fired gun.After 5 min pressure was 2625 psi,after 10 min was 2631 psi and after 15 min was 2635 psi.All shots fired.,Rig down lubricator and turn well over to production. 9/30/2017 Sign in.Mobe to location.PTW and JSA.Spot and rig up SL and N2 equipment.PT to 250 psi low and 4500 psi high.,RIH w/GPT tool to 7800'.Log up to 7500'.Find fluid level at 7596'KB.Make passes from 8450'to 8300'static.,Bring well on and make pass thru perfs.Shut well in and POOH and find fluid level at 7530'KB,POOH,Riq down lubricator and turn well over to production. • • 10/8/2017 Sign in.Mobe to location.PTW and JSA.Spot and rig up SL and N2 equipment.PT to 250 psi low and 4500 psi high.,RIH w/1-114"x17'wt bar(as a spear)and set down at 8535 KB.Attempted several times to run deeper.Pressured up tubing from 1400 psi to 3500 psi while running in hole.POOH.Wt.bar had sand on the in of it.,RIH w/2-1/2"x8'DD bailer and tag fill at 8530'KB.Bailed to 8537 KB and POOH.Bailer was 1/3 full of gray moist sand. Called town and decision was made to bail sand out.Made another run with bailer to 8539'KB while calling town and got same result.TP-3400 psi.,RIH w/10'3"DD Bailer SID @ 8540'KB.Drive bailer to 8547'KB. POOH bailer full of same sand.,Pressure well up from 3316 psi to 3700 psi w/N2.Rig N2 off well.Will call them back out when we need them.They are leaving pump trk on location.RIH w/3"x10'DD bailer and bail to 8541'.Looks like sand fell off wall of tubing.Bail to 8550'.POOH.Bailer full of gray moist sand.,Rig lubricator off well and clean up.Will be back to bail more 7 am in the morning. 10/9/2017 Sign in.Mobe to location.PTW and JSA.Spot and rig up SL and N2 equipment.PT to 250 psi low and 4500 psi high. TP-3545 psi,RIH w/3"x 10'DD bailer. Tag Fill @ 8541'KB Drive bailer to 8547'KB. POOH Bailer full of sand and fluid,RIH w/3"x 10'DD bailer. Tag Fill @ 8544'KB Drive bailer to 8550'KB. POOH Bailer full of sand RIH w/3"x 10'DD Bailer. Tag Fill @ 8549'KB. Bail to 8557'JKB,Gear box on unit malfunctions. Troubleshoot.Gear broke or stripped. Cut wire and spool on other drum. OOH w/tools,Riq down lubricator and turn well over to field.Pollard will be out in AM.TP 3530 psi 10/10/2017 ARRIVE S.R.TGSM JSA PERMITTP-3530 psi ARRIVE ON PAD RIG UP SLICKLINE P/T LUB TO 4500PSI FAIL C/O GASKET ON 15-02 RIH W/3 1/2"FLUID BAILER TO 7540'KB TAG FLUID CONT.TO 8551'KB TAG FILL POOH TOOLS DRAGGING HEAVY-OOH BAILER FULL FLUID,RIH W/SAME TO 7570'KB TAG FLUID CONT.TO 7620'SIT 1 MIN.POOH STILL DRAGGING HEAVY RIH W/SAME TO 7600'KB TAG FLUID CONT.TO 7650'SIT 1 MIN.POOH FULL RIH W/SAME TO 7630'KB TAG FLUID CONT.TO 7685'SIT 1 MIN.POOH FULL,RIH W/SAME TO 7650'KB TAG FLUID CONT.TO 7700'SIT 1 MIN.POOH EMPTY BOTTOM FAILED RE-DRESS BOTTOM RIH W/SAME TO 7650'KB TAG FLUID CONT.TO 7700'SIT 1 MIN.POOH FULL,RIH W/SAME TO 7670'KB TAG FLUID CONT.TO 7720'SIT 1 MIN.POOH EMPTY BOTTOM FAILED C/O BOTTOM RIH W/3.76"BLIND BOX 7660'KB TAG FLUID POOH LAY DOWN LUB SECURE WELL FOR NIGHT TP-3450 psi 10/11/2017 ARRIVE S.R.PERMIT JSATGSM START EQUIP.CHECK TOOL STRING P/U STAB ON WELL RIH w/3.75 BLIND BOX TO 7650 KB TAG FLIUD-POOH,RIH W/3.50 FLUID BAILER(30'}TO 7650 KB CONTINUE TO 7700 SIT 1 MIN-POOH PULLING TP-3500 psi HEAVEY 1400 POUNDS.00H BAILER FULL RIH W/SAME TO 7630'KB CONT.TO 7700'SIT 1 MIN.POOH FULL RIH W/SAME TO 7660'KB CONT.TO 7700'SIT 1 MIN.POOH FULL,RIH W/SAME TO 7665'KB CONT.TO 7710'SIT 1 MIN.POOH FULL RIH W/SAME TO 7665KB CONT.TO 7710'SIT 1 MIN.POOH FULL RIH W/SAME TO 7670'KB CONT.TO 7730'SIT 1 MIN.POOH FULL RIH W/SAME TO 7670'KB CONT.TO 7730'SIT 1 MIN.POOH FULL,RIH W/2.75"G-RING TO 8549'KB TAG POOHTP-3500 psi RIG DOWN SLICKLINE SECURE WELL FOR PRODUCTION-FUEL EQUIP.&PARK SIGN OUT DEPART FIELD 10/12/2017 ARRIVE S.R.TGSM JSA PERMIT START EQUIPMENT DRIVE TO LOCATION RIG UP SLICKLINE P/T LUB TO 4500PSI GOOD RIH W/3.5"X30'FLUID BAILER TO 7685'CONTINUE TO 7750'SIT 1 MIN.POOH FULL FLUID,RIH W/SAME TO 7705'KB CONT.TO 7750'SIT 1 MIN. POOH-OOH WHILE SHEARING BAILER BOTTOM NOTICED SPANGS STUCK OPEN.BREAK OFF BAILER TO SPANGS NOTICED ELECTRICAL TAPE IN SPANGS.REMOVE-BUILD BAILER-BAILER FULL RIH W/SAME TO 7710'KB CONT.TO 7780'SIT 1 MIN.POOH FULL,RIH W/SAME TO 7725'KB CONT.TO 7780'SIT 1 MIN.POOH FULL RIH W/SAME TO 7730'KB CONT.TO 7800'SIT 1 MIN.POOH FULL RIH W/SAME TO 7740'KB CONT.TO 7810'SIT 1 MIN.POOH FULL RIH W/SAME TO 7750'KB CONT.TO 7820'SIT 1 MIN.POOH FULL,00H BREAK OFF BAILER LAY DOWN LUB SECURE WELL FOR NIGHT SING OUT TURN IN PERMIT DEPART FIELD APPROX.1.5 BBLS.FLUID BAILED 10/13/2017 ARRIVE SWANSON R.TGSM JSA PERMIT START EQUIP.Pill LUB BUILD BAILER STAB ON P/T 4500PSI GOOD RIH W/3.5"X30'FLUID BAILER TO 7760'KB CONTINUE TO 7830'SIT 1 MIN.POOH FULL FLUID RIH W/SAME TO 7770'KB TAG FLUID CONT.TO 7830'SIT 1 MIN.POOH FULL,RIH W/SAME TO 7785'KB TAG FLUID CONT.TO 7830'SIT 1 MIN.POOH FULL RIH W/SAME TO 7790'KB TAG FLUID CONT.TO 7830'SIT 1 MIN.POOH FULL RIH W/SAME TO 7805'KB TAG FLUID CONT.TO 7900'SIT 1 MIN.POOH FULL RIH W/SAME TO 7815'KB TAG FLUID CONT.TO 7900'SIT 1 MIN.POOH FULL,RIH W/SAME TO 7830.KB TAG FLUID CONT.TO 7900'SIT 1 MIN.POOH FULL RIH W/SAME TO 7850'KB TAG FLUID CONT.TO 7920'SIT 1 MIN.POOH FULL RIH W/SAME TO 7860'KB TAG FLUID CONT.TO 7930'SIT 1 MIN.POOH FULL RIH W/SAME TO 7875'KB TAG FLUID CONT.TO 7930'SIT 1 MIN.POOH FULL,RIH W/SAME TO 7890'KB TAG FLUID CONT.TO 7950'SIT 1 MIN.POOH REMOVE BAILER RIH W/3.76"BLIND BOX TO 7910'KB TAG FLUID POOH OOH LAY DOWN LUB SECURE WELL FOR NIGHT SIGN OUT TURN IN PERMIT DEPART FIELD 10/15/2017 Arrive at PWL shop Pickup crew and TOOLS Arrive at Swanson river do Permit and JSA talk to Kevin about well work for the day Rig up Slickline on SRU 241-33 P/T Lub and WLV GOOD 4500 PSI,RIH/w 3.25"Blind Box to 7910'KB tag Fluid Level continue to 8550'KB tag btm w/t cant pass POOH OOH rig down Slickline and 4 1/2"lub and Prep to Move to SCU 22B-04 Off well and Moving • 10/16/2017 Sign in.Mobe to location.PTW and JSA.Spot and rig up lubricator.PT to 250 psi low and 4500 psi high.,RIH w/GPT tool and tie into OHL.Found fluid level at 7892'and tagged at 8550'.Send log to town. POOH,Wait on perf gun.RIH w2-718"x15'Razor HC,6 spf,60 deg phase and tie into OHL.Run correlation log and send to town.Get ok to perf from 7845'to 7860'.Spotted gun,bled well down from 3800 psi to 2009 psi.Fired gun and pressure started climbing immediately. After 1 min and 20 seconds pressure was 2100 psi,2 min-2126 psi,3 min-2176 psi,4 min-2220 psi,5 min-2257 psi,6 min-2292 psi,7 min• 2323 psi„8 min-2349 psi.9 min-2372 psi,10 min-2392 psi. After 15 min-2460 psi. Out of hole.All shots fired and bull plug was packed with sand but not the gun. Gun looked pretty dry.TP-2532 psi.when swab was shut.,Rig down lubricator and turn well over to production. 10/22/2017 Sign in at office.HLB has 2 new people on job.Send them to Swanson Orientation.Mobe to location.PTW and JSA.PT lub to 250 psi low and 4500 psi high. TP-2650 psi.,MU and RIH w/2.5"x50'cement dump bailer and tie into OHL.Bailer sat down at 8130'.Worked tools several times and could go deeper.POOH. Call town and discuss.Dump cement into buckets.Break bailer partially down.,RIH w12.75"GR/JB and tie into OHL.Sat down at same place 8130'. Hit obstruction with GR/JB at 60 fpm,100 fpm and 170 fpm.The most weight over pull was 100 lbs.It wasn't very sticky.Didn't make any hole.Call town and discussed.POOH.Will have HLB slickline out in morning.Will rig up beside HLB E-line truck and use same lubricator.GR had fine gray sand on the inside of it.,Riq down lubricator and secure well. 10/23/2017 Arrive @Office. PJSM and review JSATP-2650 psi Inspect location and rig up.125. P/T 4500psi RIH w/3"x 10'DD bailer. Tag Fill @ 8130'KB Drive bailer to 8140'KB. POOH OOH w tools. Bailer full of moist and soupy sand.C/O bailers. Bailers threads damaged.,RIH w/3"x 10'DD bailer. Tag Fill @ 8141'KB Drive bailer to 8148'KB. POOH OOH w tools. Bailer full of drier sand RIH w/3"x 10'DD bailer. Tag Fill @ 8149'KB Drive bailer to 8155'KB. POOH OOH w/tools.Bailer full of sand,RIH w/3"x 10'DD bailer. Tag Fill @ 8155'KB Drive bailer to 8162'KB. POOH OOH w/tools.Bailer full of sand RIH w/3.85 gauge ring. S/D in perfs @ 7860'KB. POOH TP-2760 psi,RIH WI 3 1/2"x 10' Tag Fill @ 8162'KB. Drive bailer to 8166'KB POOH bailer 1/3 full of moist sand.,Ria lubricator off well and secure well.Will be back in AM. 10/24/2017 Arrive @Office. PJSM and review JSA Inspect location and rig up.125. P/T 4500psi RIH w/3"x 10'DD bailer. Tag Fill 8169'KB @ Drive bailer to 8171'KB. P/U sit down @ 8165' Drive bailer again to 8171'KB. POOHBailer 1/2 full moist sand,1/2 sloppy wet sand,RIH w/3"x 10'DD bailer. Tag Fill @ 8171'KB. Drive bailer to 8174' KB. Bailer same as above. RIH w/3"x 10'DD Bailer. Tag Fill @ 8174'KB. Bail to 8175'KB Difficult to make hole.POOH3'wet sand,7'mostly fluid.Add wt bar,RIH w/3"x 10'DD Bailer.Tag fill @ 8170'KB Bail to 8177'KB. 3'sand/fluid RIH w/10'2.5"DD Bailer. Tag fill @ 8179'KB.Bail to 8188'KB.POOH and bailer full of moist sand.,RIH w/2.5"x 20'DD bailer.Tag fill @ 8184'KB, Bail to 8196'KB Bailer had 12'of moist sand and rest soupy sand slurry. Lay down and re-pack stuffing box.,Rig down off well and secure.Get E-line truck and equipment ready to move to SCU 24A-09 in the morning.Detonators are in Kenai at FedEx.HLB will pick up in the morning.They have two 10'strip guns ready now.Will have the other 2 ready before we need them.Will be moving to 24A-09 at 0700 hrs in the mornina. 10/26/2017 HLB sign at office.Mobe to location.Spot equipment.PTW and JSA.Rig up lubricator and check tools. PT to 250 psi low and 4500 psi high.MU and arm 3- 1/2"OD CIBP.,RIH w13-1/2"CIBP and tie into HLB dump bailer log dated 10-22-17.Tag fill at 8170'.Run correlation log and send to town.Shifted log up 2'and get ok to set plug at 8168'.Spot plug and set plug with 2950 psi on tubing.Lost 200 lb of line tension when plug set.Pick up 30'and go back down and tag plug.POOH.Setting tool looked ok.Good set.,MU and RIH w/GPT tool and tie into Plug correlation log.Tag top of plug at 8168. Find fluid level at 7122'. Send log to town.POOH,Rig down lubricator and secure well.Will be back in am to dump bail the cement on top of plug. 10/27/2017 HLB sign at office.Mobe to location.PTW and JSA.Rig up lubricator and check tools. PT to 250 psi low and 4500 psi high.TP-3000 psi.,RIH w/3-1/2"X40' cement dump bailer,tied into plug log and tag fill 20'high at 8148'.Dump bail 11.5 gals(17.5')of 17#Neo super slurry cement on top of fill at 8148'. Lost 100 lbs of line tension wt.when dumped.POOH.Good dump.RIH with same bailer amount and dumped on top of cement at 8130.5'.Lost 100#line tension when bailer dumped.POOH.Good dump.Est TOC at 8113'(35'of cement).CIP at 1400 hrs.,Rig down lubricator,cleaned bailer and loaded up equipment.Move to SCU 24A-09 10/28/2017 Pollard E-line sign at office.Mobe to location.PTW,JSA and SIMOPS.Rig up lubricator and check tools.MU 3-1/2"CIBP and GPT tool.,Rig up SLB N2 to Pollard Lubricator.Transfer N2 from tanker to pump truck PT hard lines and lubricator to 250 psi low and 4500 psi high.,RIH w/3-1/2"CIBP and GPT tool and tie into CBL.Find fluid level at 7082'.Started pumping N2 at 1500 scf/m and pressure broke over at 3670 psi and pumped 805 gals of N2.Fluid level was 7854'.Ran correlation log and got ok to set plug at 7838'(collar was at 7840').Set plug with 3076 psi on tubing.Lost 250 lb line tension when plug set.Pick up 30'and went back and tagged plug..POOH.Good set.,RIH w/2-7/8"x5'Razar HC,6 spf,60 deg phase and tie into plug correlation log.Send log to town and get ok to perf from 7812 to 7817'.Bled well down to 2174 psi,spotted gun and fired gun.After 5 min-2182 psi,10 min-2187 psi and 15 min-2191 psi. POOH all shots fired and gun was wet.TP-2203 psi.,Rig down lubricator and turn well over to field. 10/31/2017 HLB sign at office.Mobe to location.PTW and JSA.Spot equipment.Rig up lubricator and check tools. PT to 250 psi low and 4500 psi high.Send new hand to orientation.,RIH w/GPT tool and tie into Pollard Plug log dated 10-28-17.Tag plug at 7838'.Found fluid level 638'with 846 psi on tubing.Send log to town and POOH.,MU 3-112"x40'dump bailer.Fill with 10 gals(21')of Neo Super Slurry cement(17 Ib).Had to re-wire dump bailer.Nicked wire putting sections together.RIH w13-1/2"x40'dump bailer and tagged plug at 7838'.Pick up 20'and dump cement on top of plug.Cement in place at 1600 hrs and est TOC at 7817'.POOH.Good dump.TP-800 psi.,Rig down lubricator and secure well.Should have a SLB N2 pump truck and crew Thursday. 11/2/2017 HLB sign at office.Mobe to location.PTW and JSA.Spot equipment.Rig up lubricator and check tools.PTW,JSA and SIMOPS with SLB N2. PT hard lines and Lubricator to 250 psi low and 5000 psi high. TP-1280 psi.,RIH with GPT tool and 3-1/2"CIBP.Find fluid level at 500'.Start pressuring up tubing with N2 from 1280 psi to 4500 psi at 1000 scf/min.Check fluid level and found it at 590'.Call town and get ok to pressure tubing up to 5000 psi.Checked fluid level and it was still at 590 psi.Bleed tubing to 3500 psi and fluid level moved up to 570'. Run down hole,tie into HLB tag log and tag at 7816'.Send log to town,and get ok to set plug at 7795'.Spot plug and set plug with 3500 psi on tubing.Lost 200 lbs of line tension when plug set.Pick up 30'and go back and tag plug. POOH.Good set.Used 1800 scf of N2(300 gals).Have approx.2200 gals left.,Rig down lubricator and hard lines.Turn well back over to field. 11/9/2017 SLB CTU crew arrive at Swanson river field. PTW, safety meeting.,Spot in and berm Johnson tank. Ru CTRU 13 with 1.75" coil.,24 hr BOPE test witness notification sent 11/8/17 @ 11:38 am. Witness waived by Jim Regg via email on 11/8/17 @ 16:17. Test all rams and valves 250 low and 4500 psi high.,BOPE test completed. Stab pipe in injector head. Make up roll on connector. Crews finished for the night. Location secure. N2 will arrive at 2300 hrs. • 11/10/2017 Obtain PTW. Hold safety meeting and discuss job procedure. SLB genset down. Mechanic on location.,Gen set fixed. Pick injector head. Stab 10' lubricator. Make up 2x 1.75"OD x 5 straight joints. 1.75"OD x 2'DFCV, 2.125"OD x 6"jet swirl nozzle. Stab on well. PT lubricator to 250/3500 psi. (1700 gallons of N2 was added to N2 pump). Total N2 on board 3300 gallons. Cooling down N2 pump.,Bleed PT pressure down to 1500 psi. Open master swab 23.5 turns. Initial WHP 1834 psi. Bleed down WHP. RIH. 500'CTMD online with n2 700 scf/min. increase CT speed to 100'/min. Fluid returns at surface CTMD 2400'. Continue IH. Increase rate 1000 scf/min. Tagged CIBP @ 7791.5 CTMD. 73 bbls returned upon tag. Pick up and re tag to confirm depth. Stay parked at 7791.5'.,Continue unloading well. 113 bbls returned to surface. Tank blowing dry. Pump for additional 15 minutes to dry up tubing walls. Total fluid recovered from wellbore 113.5 bbls.,POOH to surface. 140/min. Close choke. Increase N2 rate to 2000 scf//min to build WHP to 2100 psi. Tagged up at surface. Shut down N2 pump. Close master and swab 23.5 turns. FINAL SITP 2150 psi. N2 rigged down and moved to SRU 14-15.,BIeed down CT reel and wellhead stack. Pop off tree. Bread down tools. Rig down SLB CTU 13. Peak vac truck on location to empty Johnson tank.. 142,000 scf or 1524 gallons of N2 to unload wellbore 73,000 scf or 783 gallons to pressure up well to 2150 psi Total N2 pumped for job 215,000 or 2308 gallons 113.5 bbls returned from wellbore. 992 gallons left for SRU 14-15 E-line job. SLB rigged down location secure. 11/11/2017 Mobe to location.PTW and JSA.Rig up lubricator,PT to 250 psi low and 4500 psi high.TP-2100 psi,RIH with GPT tool,tie into plug set log and tagged at 7795'.Ran correlation log and send to town.Found fluid level at 7365'with 2041 psi on tubing..POOH,RIH w/2-7/8"x10'(loaded with 5'of charges)Razer HC, 6 spf,60 deg phase.Ran correlation log and send to town.Get ok to perf from 7770'to 7775'.Spotted and fired gun with 2018 psi on tubing.Pressure dropped to 2016 psi when shot,5 min-2020 psi,10 min-2022 psi and 15 min-2023 psi.POOH.All shots fired.,Rig down lubricator and turn well over to field. 11/16/2017 ON LOCATION-TGSM-JSA-PERMIT START EQUIPMENT AT BULL RAIL ALLOW TO WARM RIG UP W/L-PT LUB TO 4500 PSI-GOOD,RIH W/3.54"SWEDGE-TO 2650'KB SLOW DOWN-(DOES NOT LOOK LIKE FLUID-POSSIBLY E-LINE GREASE OR DEVIATION)CONTINUE IN HOLE TO 7795'KB TAG-POOH-OOH W/SWEDGE COVERED IN GREASE-SURVEY REPORT WILL HAVE FLUID LEVEL INDICATION,RIH W/TANDEM TRI GAUGES @ 120'/MIN TO 7772'KB MAKE 10 MIN STOP-POOH MAKING GRADIENT STOPS ON THE WAY OOH OOH W/GAUGES-DOWNLOAD DATA-GOOD RIG DOWN W/L-CLEAN AREA-RETURN WELL TO PRODUCTION,CLOSE OUT PERMIT-FUEL EQUIPMENT AND STAGE AT BULL RAIL LEAVE FIELD-RETURN TO PWL SHOP 11/27/2017 Mobe to location.PTW and JSA.Rig up lubricator,PT to 250 psi low and 4500 psi high.TP-1400 psi MU 2-1/2"x30'bailer and mix cement.,RIH w/3-1/2"x30' dump bailer loaded with 17#Neo Super Slurry cement and tie into OHL.Tag at 7795'.Dump 15'of cement on top of plug at 7795'.Tubing pressure was 1500 psi.POOH.Good dump.,PTW,JSA and SIMOPS w/N2 crew and Pollard.Rig up hard lines and pressure test lines and lubricator to 5000 psi.RIH w/GPT tool and 3-1/2"CIBP and find fluid level at 2200'at 1620 psi.Started pressuring up with N2 slowly until it reached 4200 psi.Shut N2 down and fluid level was at 2250'.Brought N2 back on line at 3800 psi.Brought pressure back up to 4600 psi and waited 30 min.Checked fluid level-2254'.,Called town and discussed. Pressured tubing back up to 4600 psi and wait an hour.Checked fluid level and it was 2264'.Pressured back up to 4600 psi and went down to 7740'(Bottom of tool was at 7760'.Perfs were 7770'to 7775').Pressured tubing back up to 4600 psi and BHP was 6895 psi at 7740'.Pulled out of hole and found fluid level at 2558'(about 300'lower than before)with tubing pressure at 4146 psi.It looks,like perfs are taking fluid slowly. POOH.Pressure tubing up to 4600 psi and close masters and swab.Will check fluid level in the morning.We used 559 gals of N2.,Rig down lubricator and N2 hard line off well and secure well. 11/28/2017 HLB and SLB sign at office.Mobe to location.PTW,JSA and SIMOPS.Spot equipment.Rig up lubricator and check tools. PT hard lines and Lubricator to 250 psi low and 5000 psi high. TP-3000 psi.,RIH w/GPT tool and find fluid level at 3732'.Start pressuring N2 up at 400 to 500 scf until we reached 4600 psi. Fluid level was being pushed away about 12'per minute.We would pressure up to 4600 psi and shut down until it bleed couple hundred psi and then pressure back up.Called town and discussed.Decided to bring pressure up to 4800 psi to try and maintain the 12'per min. At 1515 hrs we are at-6300 with fluid,level. We are averaging between 8.5'and 11'per min.When FL got to 6700'formation started getting tighter around 1700 hrs.We started making between 4'to 6' per min by pressuring up to 4800 psi. and letting it bleed about 150 psi off.Called town and discussed.Decision was made to order more N2(2000 gal- minimum charge)for in the morning,put 4800 psi on tubing and shut well in.,We will check FL in the morning and make a decision rather to reperf the old zone or not.FL is 6715'fight now.We need to get below perfs from 7528'to 7533'.We have pumped/used a total of approx.1950 gals and got about 500 gals of N2 left.,Rig down lubricator and pressure well back up to 4800 psi and close swab and mastersw. 1 112 9/2 01 7 HLB and SLB sign at office.Mobe to location.PTW,JSA and SIMOPS.Spot equipment.Rig up lubricator and check tools. PT hard lines and Lubricator to 250 psi low and 5000 psi high. TP-4300 psi.,RIH w/Sondex GPT tool,tied into OHL and found Fluid Level at 7196'.Pressure tubing up to 4800 psi.Fluid level started being pushed away at 5'per min by pressuring up to 4800 psi when pressure dropped 75 psi.It got down to 2.7'per min and I called town and discussed.Decision was made to re-pert the zone and see if that helped.POOH.FL-7310',RIH w/2-1/2"x5'HC Millineum,6 spf,60 deg pert gun,tied into OHL and tagged TOC at 7776'.Ran correlation log and send to town.Get ok to re-pert from 7770'to 7775'.Pressure tubing up to 4800 psi,spot and fire gun. Saw no change on pressure.POOH.All shots fired.,RIH w/GPT tool and 3-1/2"OD plug.Found fluid level at 7480'at 1430 hrs.Pumped tubing pressure up to 4800 psi whenever it dropped below 4700 psi. It finally got to 0.6'per min with FL at 7530'.It takes about 20 min to lose 50 psi on TP.I waited 1 hour and checked FL and it was at 7555'.That's 25'in an hour.Called town and decision was made to POOH,pressure tubing up to 4800 psi and shut masters and swab.,I turned SLB N2 crew loose to meet their min charge after pressuring tubing up to 4800 psi.Rig down SLB N2 crew and HLB lubricator.Will leave pressure on well overnight and Halliburton will be back in the morning to check fluid level,set plug and perforate. Pumped at total of 650 gals of N2 11/30/2017 Mobe to location.PTW and JSA.Rig up lubricator,PT to 250 psi low and 4500 psi high.TP-3150 psi. MU 3-1/2"OD CIBP w/GPT tool.,RIH w/3-1/2"OD CIBP.GPT tool and tie into OHL.Went down to 7760'w/plug and 7745'with PT tool.Fluid level was below 7745'.Ran correlation log and send to town.Get ok Gt (to set plug at 7760'.Set plug and lost 50 lb line tension.Pick up 30'and went back down and tagged plug.Good set.TP was 3150 psi when plug was set. POOH.Looks good.,RIH w/2-7/8"x5'Razor HC,6 spf,60 degree phase and tie into OHL.Run correlation log and send to town.Bleed well down to 2000 psi. -71(00 Down shifted log 1.5'and get gun on depth from 7528'to 7533'.Fired gun with 2044.5 psi,after 5 min-2045 psi,10 min-2048.3 psi and 15 min-2047 psi. Pressure was 2045 psi when HLB closed swab.All shots fired and gun was dry.,Rig down lubricator and turn well over to field. 12/10/2017 Mobe to location.PTW and JSA.Rig up lubricator,PT to 250 psi low and 4500 psi high. TP-703 psi(Scada),RIH w/3-318"x20'(Loaded w/3-1/8"charges) Connex HC,6 spf,60 deg phase and tie into the OHL.Ran correlation log and send to town.Get ok to perforate from 7527'to 7547'.Spotted and shot gun with 703 psi on tubing.Pressure rose slowly from 703 psi to 709 psi after 15 min.POOH.All shots fired and gun was dry.TP-716 psi on Scada.,Rig down lubricator and turn well over to field. • • Hilcorp Alaska, LLC Swanson River Unit SRU 21-33 SRU 241-33 50-133-20663-00-00 Sperry Drilling Definitive Survey Report 24 July, 2017 az yx# y HALLIBURTON Sperry Drilling 1 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC - Local Co-ordinate Reference: Well SRU 241-33 Project: Swanson River Unit TVD Reference: .: SRU 241-33 WP08 As-Built @ 205.15usft Site: SRU 21-33 :' MD Reference: ', l'-'":;,7`.°-..?„,'-!„-"i:•1`,.,.. SRU 241-33 WP08 As-Built @ 205.15usft Well: SRU 241-33 y North Reference: True Wellbore: SRU 241-33 Survey Calculation Method: Minimum Curvature Design: SRU 241-33 ( Database: Sperry EDM-NORTH US+CANADA Project Swanson River 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 I Well SRU 241-33 `:... Well Position +N/-S 0.00 usft Northing: 2,465,962.80 usft . Latitude: 60°44'48.895 N +EI-W 0.00 usft Easting: 344550.68 usft . Longitude: 150°52'7.862 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 187.15 usft Wellbore r.,.. 4-410 al' Magnetics i04 , Model Name Sample Date a.« Declination Dip Angle. Field Strength 0_ , 'S . & r) , () Via. (nT) BGGM2017 6/29/2017 16.08 73.73 55,435 Design SRU 241-33 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 18.00 Vertical Section: Depth From(TVD) +NI-S +EI-W ,'llDirection ° (usft) (usft) (usft) l _.Wwu.l. (°) ,. ;s1,,,,,,,';:,,,,-', 18.00 0.00 0.00 95.81 4. Survey Program Date 7/24/2017 r. .( From To ,-..::?!,,, ,4,1,,,,,,:-',..e-,:t (usft) (usft) Survey(Wellbore) Tool Name Description ''''1!::'t Survey Date 100.00 1,000.00 SRG-SS(SRU 241-33) SRG-SS Surface readout gyro single shot 07/21/2017 1,014.52 1,975.27 MWD+SC+sag(SRU 241-33) MWD+SC+sag Fixed:v2:standard dec&axial correction+sag 07/03/2017 2,060.76 8,591.78 MWD+SC+sag(2)(SRU 241-33) MWD+SC+sag Fixed:v2:standard dec&axial correction+sag 07/10/2017 Survey Map Map Vertical MD Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft)} (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 18.00 0.00 0.00 18.00 -187.15 0.00 0.00 2,465,962.80 344,550.68 0.00 0.00 UNDEFINED 100.00 0.15 56.68 100.00 -105.15 0.06 0.09 2,465,962.86 344,550.77 0.18 0.08 SRG-SS(1) 200.00 0.24 133.55 200.00 -5.15 -0.01 0.35 2,465,962.78 344,551.03 0.25 0.35 SRG-SS(1) 300.00 0.31 109.31 300.00 94.85 -0.25 0.76 2,465,962.55 344,551.43 0.13 0.78 SRG-SS(1) 400.00 1.57 108.17 399.98 194.83 -0.76 2.31 2,465,962.01 344,552.98 1.26 2.38 SRG-SS(1) 500.00 2.71 116.05 499.91 294.76 -2.23 5.74 2,465,960.50 344,556.39 1.17 5.94 SRG-SS(1) 600.00 2.90 118.42 599.79 394.64 -4.47 10.09 2,465,958.20 344,560.70 0.22 10.49 SRG-SS(1) 700.00 2.96 121.33 699.66 494.51 -7.02 14.52 2,465,955.59 344,565.10 0.16 15.16 SRG-SS(1) 800.00 3.42 121.04 799.51 594.36 -9.90 19.28 2,465,952.65 344,569.82 0.46 20.18 SRG-SS(1) 900.00 2.91 118.99 899.35 694.20 -12.67 24.06 2,465,949.82 344,574.56 0.52 25.22 SRG-SS(1) 1,000.00 3.52 108.10 999.20 794.05 -14.85 29.19 2,465,947.57 344,579.67 0.86 30.55 SRG-SS(1) 1,014.52 3.56 106.48 1,013.69 808.54 -15.12 30.05 2,465,947.29 344,580.52 0.74 31.43 MWD+SC+sag(2) 7/24/2017 7.52::51 PM Page 2 COMPASS 5000.1 Build 81D • 0 Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well SRU 241-33 Project: Swanson River Unit TVD Reference: SRU 241-33 WP08 As-Built @ 205.15usft P Site: SRU 21-33 MD Reference: ,, SRU 241-33 WP08 As-Built @ 205.15usft Well: SRU 241-33 North Reference: True Wellbore: SRU 241-33 Survey Calculation Method: Minimum Curvature Design: SRU 241-33 Database: ; Sperry EDM-NORTH US+CANADA Survey Map Map Vertical` MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 1,076.11 3.59 106.52 1,075.16 870.01 -16.21 33.73 2,465,946.15 344,584.19 0.05 35.20 MWD+SC+sag(2) 1,140.42 3.62 107.70 1,139.34 934.19 -17.40 37.60 2,465,944.91 344,588.04 0.12 39.17 MWD+SC+sag(2) 1,201.91 3.61 108.48 1,200.71 995.56 -18.60 41.28 2,465,943.66 344,591.71 0.08 42.95 MWD+SC+sag(2) 1,265.19 3.65 108.58 1,263.86 1,058.71 -19.87 45.08 2,465,942.34 344,595.49 0.06 46.86 MWD+SC+sag(2) 1,327.01 4.48 112.33 1,325.53 1,120.38 -21.42 49.18 2,465,940.74 344,599.57 1.41 51.10 MWD+SC+sag(2) 1,389.96 4.89 110.78 1,388.27 1,183.12 -23.30 53.96 2,465,938.79 344,604.32 0.68 56.04 MWD+SC+sag(2) 1,451.94 5.32 116.53 1,450.00 1,244.85 -25.53 59.00 2,465,936.50 344,609.33 1.08 61.28 MWD+SC+sag(2) 1,512.67 6.10 113.33 1,510.43 1,305.28 -28.06 64.49 2,465,933.89 344,614.78 1.39 66.99 MWD+SC+sag(2) 1,574.60 8.19 110.03 1,571.87 1,366.72 -30.88 71.65 2,465,930.98 344,621.91 3.44 74.41 MWD+SC+sag(2) 1,637.64 10.45 107.77 1,634.28 1,429.13 -34.17 81.35 2,465,927.56 344,631.56 3.62 84.39 MWD+SC+sag(2) 1,700.56 12.63 107.94 1,695.72 1,490.57 -38.02 93.29 2,465,923.56 344,643.45 3.48 96.66 MWD+SC+sag(2) 1,763.39 15.16 106.91 1,756.71 1,551.56 -42.52 107.69 2,465,918.86 344,657.78 4.05 111.44 MWD+SC+sag(2) 1,825.29 16.75 106.67 1,816.22 1,611.07 -47.44 123.98 2,465,913.73 344,674.00 2.57 128.14 MWD+SC+sag(2) 1,888.46 18.76 107.13 1,876.38 1,671.23 -53.04 142.41 2,465,907.89 344,692.36 3.19 147.04 MWD+SC+sag(2) 1,975.27 21.21 107.22 1,957.96 1,752.81 -61.80 170.75 2,465,898.75 344,720.58 2.82 176.13 MWD+SC+sag(2) 2,060.76 22.31 106.54 2,037.36 1,832.21 -71.00 201.08 2,465,889.15 344,750.78 1.32 207.23 MWD+SC+sag(3) 2,121.87 24.67 108.41 2,093.40 1,888.25 -78.33 224.30 2,465,881.52 344,773.90 4.05 231.08 MWD+SC+sag(3) 2,185.45 26.70 107.94 2,150.69 1,945.54 -86.92 250.48 2,465,872.58 344,799.97 3.21 257.99 MWD+SC+sag(3) 2,247.94 28.77 108.53 2,206.00 2,000.85 -96.03 278.10 2,465,863.11 344,827.46 3.34 286.39 MWD+SC+sag(3) 2,309.48 30.66 108.77 2,259.45 2,054.30 -105.78 307.00 2,465,852.98 344,856.23 3.08 316.13 MWD+SC+sag(3) 2,371.30 32.60 109.36 2,312.08 2,106.93 -116.38 337.64 2,465,841.98 344,886.72 3.18 347.69 MWD+SC+sag(3) 2,433.20 33.58 109.22 2,363.94 2,158.79 -127.54 369.54 2,465,830.39 344,918.47 1.59 380.55 MWD+SC+sag(3) 2,494.97 34.06 109.21 2,415.26 2,210.11 -138.86 402.00 2,465,818.65 344,950.78 0.78 413.99 MWD+SC+sag(3) 2,557.92 34.44 109.18 2,467.29 2,262.14 -150.50 435.46 2,465,806.56 344,984.08 0.60 448.46 MWD+SC+sag(3) 2,620.64 34.13 106.79 2,519.12 2,313.97 -161.41 469.06 2,465,795.21 345,017.52 2.20 482.99 MWD+SC+sag(3) 2,682.40 33.46 103.04 2,570.45 2,365.30 -170.26 502.24 2,465,785.93 345,050.58 3.55 516.89 MWD+SC+sag(3) 2,743.88 33.17 99.79 2,621.83 2,416.68 -176.95 535.32 2,465,778.80 345,083.57 2.94 550.49 MWD+SC+sag(3) 2,805.97 33.00 96.77 2,673.85 2,468.70 -181.83 568.86 2,465,773.48 345,117.04 2.67 584.34 MWD+SC+sag(3) 2,868.92 33.43 94.01 2,726.52 2,521.37 -185.06 603.18 2,465,769.79 345,151.31 2.50 618.81 MWD+SC+sag(3) 2,931.14 32.69 92.84 2,778.67 2,573.52 -187.09 637.06 2,465,767.31 345,185.16 1.57 652.72 MWD+SC+sag(3) 2,992.36 33.35 92.85 2,830.00 2,624.85 -188.75 670.38 2,465,765.22 345,218.45 1.08 686.04 MWD+SC+sag(3) 3,054.39 33.75 92.94 2,881.70 2,676.55 -190.48 704.62 2,465,763.03 345,252.66 0.65 720.28 MWD+SC+sag(3) 3,116.71 33.41 92.35 2,933.62 2,728.47 -192.07 739.05 2,465,760.99 345,287.06 0.76 754.69 MWD+SC+sag(3) 3,177.58 33.90 92.63 2,984.28 2,779.13 -193.54 772.75 2,465,759.07 345,320.74 0.84 788.37 MWD+SC+sag(3) 3,239.71 32.67 91.88 3,036.22 2,831.07 -194.88 806.82 2,465,757.28 345,354.79 2.09 822.40 MWD+SC+sag(3) 3,302.37 33.26 91.42 3,088.79 2,883.64 -195.86 840.90 2,465,755.85 345,388.85 1.02 856.41 MWD+SC+sag(3) 3,364.24 33.76 91.68 3,140.38 2,935.23 -196.79 875.04 2,465,754.47 345,422.98 0.84 890.47 MWD+SC+sag(3) 3,425.95 34.40 91.25 3,191.49 2,986.34 -197.67 909.61 2,465,753.13 345,457.53 1.11 924.95 MWD+SC+sag(3) 3,488.03 34.75 91.71 3,242.61 3,037.46 -198.58 944.83 2,465,751.75 345,492.73 0.70 960.08 MWD+SC+sag(3) 3,550.77 35.45 91.60 3,293.94 3,088.79 -199.62 980.89 2,465,750.24 345,528.77 1.12 996.06 MWD+SC+sag(3) 7/24/2017 7:52:51PM Page 3 COMPASS 5000.1 Build 81D • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well SRU 241-33 Project: Swanson River Unit TVD Reference: SRU 241-33 WP08 As-Built @ 205.15usft • Site: SRU 21-33 MD Reference: SRU 241-33 WP08 As-Built @ 205.15usft Well: SRU 241-33 North Reference: True Wellbore: SRU 241-33 Survey Calculation Method: Minimum Curvature Design: SRU 241-33 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +14)-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 3,612.73 36.26 92.53 3,344.15 3,139.00 -200.93 1,017.16 2,465,748.45 345,565.01 1.58 1,032.27 MWD+SC+sag(3) 3,674.70 37.65 93.07 3,393.67 3,188.52 -202.76 1,054.37 2,465,746.13 345,602.19 2.30 1,069.47 MWD+SC+sag(3) 3,736.98 38.56 93.44 3,442.68 3,237.53 -204.94 1,092.74 2,465,743.44 345,640.53 1.51 1,107.87 MWD+SC+sag(3) 3,799.03 39.87 93.42 3,490.75 3,285.60 -207.29 1,131.90 2,465,740.58 345,679.65 2.11 1,147.06 MWD+SC+sag(3) 3,861.35 40.94 93.97 3,538.21 3,333.06 -209.89 1,172.21 2,465,737.44 345,719.92 1.81 1,187.43 MWD+SC+sag(3) 3,923.25 41.07 93.81 3,584.92 3,379.77 -212.65 1,212.73 2,465,734.15 345,760.39 0.27 1,228.02 MWD+SC+sag(3) 3,985.38 41.14 93.14 3,631.74 3,426.59 -215.12 1,253.50 2,465,731.13 345,801.13 0.72 1,268.83 MWD+SC+sag(3) 4,048.05 43.11 94.43 3,678.22 3,473.07 -217.91 1,295.44 2,465,727.79 345,843.02 3.43 1,310.84 MWD+SC+sag(3) 4,110.91 43.25 94.38 3,724.06 3,518.91 -221.21 1,338.32 2,465,723.92 345,885.86 0.23 1,353.84 MWD+SC+sag(3) 4,172.59 43.43 94.52 3,768.92 3,563.77 -224.49 1,380.53 2,465,720.08 345,928.01 0.33 1,396.16 MWD+SC+sag(3) 4,234.65 43.58 94.61 3,813.93 3,608.78 -227.89 1,423.12 2,465,716.12 345,970.55 0.26 1,438.88 MWD+SC+sag(3) 4,296.98 43.92 94.80 3,858.95 3,653.80 -231.43 1,466.07 2,465,712.01 346,013.45 0.58 1,481.97 MWD+SC+sag(3) 4,358.86 43.42 94.97 3,903.71 3,698.56 -235.07 1,508.65 2,465,707.81 346,055.97 0.83 1,524.69 MWD+SC+sag(3) 4,420.84 42.96 95.07 3,948.90 3,743.75 -238.78 1,550.90 2,465,703.54 346,098.17 0.75 1,567.11 MWD+SC+sag(3) 4,480.97 42.54 94.56 3,993.06 3,787.91 -242.21 1,591.58 2,465,699.58 346,138.79 0.91 1,607.92 MWD+SC+sag(3) 4,544.84 42.08 94.69 4,040.29 3,835.14 -245.67 1,634.43 2,465,695.55 346,181.59 0.73 1,650.90 MWD+SC+sag(3) 4,607.19 42.43 95.90 4,086.44 3,881.29 -249.54 1,676.17 2,465,691.12 346,223.28 1.42 1,692.83 MWD+SC+sag(3) 4,669.32 43.79 96.24 4,131.80 3,926.65 -254.04 1,718.40 2,465,686.07 346,265.44 2.22 1,735.28 MWD+SC+sag(3) 4,732.09 43.14 96.96 4,177.35 3,972.20 -259.00 1,761.29 2,465,680.55 346,308.26 1.30 1,778.46 MWD+SC+sag(3) 4,794.64 44.46 95.83 4,222.50 4,017.35 -263.81 1,804.31 2,465,675.16 346,351.21 2.45 1,821.75 MWD+SC+sag(3) 4,857.38 44.40 96.13 4,267.30 4,062.15 -268.39 1,847.99 2,465,670.01 346,394.82 0.35 1,865.67 MWD+SC+sag(3) 4,919.79 45.01 95.11 4,311.66 4,106.51 -272.69 1,891.68 2,465,665.13 346,438.45 1.51 1,909.57 MWD+SC+sag(3) 4,978.46 43.60 92.90 4,353.65 4,148.50 -275.56 1,932.56 2,465,661.72 346,479.28 3.56 1,950.52 MWD+SC+sag(3) 5,041.16 43.41 93.31 4,399.12 4,193.97 -277.90 1,975.66 2,465,658.81 346,522.34 0.54 1,993.64 MWD+SC+sag(3) 5,107.13 43.25 91.62 4,447.11 4,241.96 -279.84 2,020.88 2,465,656.27 346,567.53 1.77 2,038.83 MWD+SC+sag(3) 5,168.99 42.97 91.67 4,492.27 4,287.12 -281.06 2,063.14 2,465,654.50 346,609.76 0.46 2,080.99 MWD+SC+sag(3) 5,230.68 42.40 92.20 4,537.62 4,332.47 -282.47 2,104.94 2,465,652.53 346,651.54 1.09 2,122.72 MWD+SC+sag(3) 5,292.65 42.33 91.96 4,583.41 4,378.26 -283.98 2,146.67 2,465,650.47 346,693.24 0.28 2,164.39 MWD+SC+sag(3) 5,356.72 42.44 92.05 4,630.73 4,425.58 -285.49 2,189.83 2,465,648.38 346,736.38 0.20 2,207.48 MWD+SC+sag(3) 5,417.32 40.97 90.55 4,675.98 4,470.83 -286.42 2,230.13 2,465,646.93 346,776.66 2.93 2,247.67 MWD+SC+sag(3) 5,479.00 39.97 89.95 4,722.90 4,517.75 -286.59 2,270.17 2,465,646.22 346,816.69 1.74 2,287.52 MWD+SC+sag(3) 5,540.30 38.99 89.46 4,770.21 4,565.06 -286.39 2,309.14 2,465,645.91 346,855.66 1.68 2,326.27 MWD+SC+sag(3) 5,605.12 37.65 90.98 4,821.07 4,615.92 -286.54 2,349.33 2,465,645.23 346,895.84 2.53 2,366.27 MWD+SC+sag(3) 5,668.40 37.01 92.66 4,871.39 4,666.24 -287.76 2,387.68 2,465,643.51 346,934.17 1.90 2,404.54 MWD+SC+sag(3) 5,728.98 36.60 93.12 4,919.89 4,714.74 -289.58 2,423.93 2,465,641.20 346,970.38 0.82 2,440.79 MWD+SC+sag(3) 5,792.13 35.01 90.64 4,971.11 4,765.96 -290.81 2,460.84 2,465,639.48 347,007.28 3.41 2,477.64 MWD+SC+sag(3) 5,854.71 33.96 90.76 5,022.69 4,817.54 -291.24 2,496.27 2,465,638.58 347,042.69 1.68 2,512.93 MWD+SC+sag(3) 5,916.58 32.34 92.15 5,074.49 4,869.34 -292.09 2,530.09 2,465,637.28 347,076.50 2.89 2,546.66 MWD+SC+sag(3) 5,980.53 32.11 92.74 5,128.59 4,923.44 -293.55 2,564.16 2,465,635.38 347,110.54 0.61 2,580.70 MWD+SC+sag(3) 6,041.48 30.21 91.68 5,180.74 4,975.59 -294.77 2,595.67 2,465,633.74 347,142.03 3.24 2,612.18 MWD+SC+sag(3) 7/24/2017 7:52:51PM Page 4 COMPASS 5000.1 Build 81D • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well SRU 241-33 Project: Swanson River Unit TVD Reference . SRU 241-33 WP08 As-Built @ 205.15usft Site: SRU 21-33 ' MD Reference: - SRU 241-33 WP08 As-Built @ 205.15usft :> Well: SRU 241-33 North Reference: ?x True Wellbore: SRU 241-33 Survey Calculation Method: Minimum Curvature r Design: SRU 241-33 Database: Sperry EDM NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 6,103.82 28.83 91.82 5,234.99 5,029.84 -295.71 2,626.37 2,465,632.39 347,172.72 2.22 2,642.81 MWD+SC+sag(3) 6,165.85 27.95 92.16 5,289.56 5,084.41 -296.73 2,655.85 2,465,630.98 347,202.17 1.44 2,672.24 MWD+SC+sag(3) 6,228.14 26.44 92.90 5,344.96 5,139.81 -297.98 2,684.29 2,465,629.35 347,230.59 2.48 2,700.66 MWD+SC+sag(3) 6,290.29 25.70 93.63 5,400.79 5,195.64 -299.54 2,711.55 2,465,627.44 347,257.83 1.30 2,727.95 MWD+SC+sag(3) 6,353.25 23.61 91.54 5,458.01 5,252.86 -300.74 2,737.78 2,465,625.89 347,284.04 3.60 2,754.17 MWD+SC+sag(3) 6,416.12 23.52 91.66 5,515.63 5,310.48 -301.44 2,762.91 2,465,624.86 347,309.16 0.16 2,779.23 MWD+SC+sag(3) 6,477.68 21.88 90.98 5,572.42 5,367.27 -301.99 2,786.66 2,465,623.99 347,332.89 2.70 2,802.91 MWD+SC+sag(3) 6,540.12 21.51 91.18 5,630.44 5,425.29 -302.43 2,809.74 2,465,623.25 347,355.96 0.60 2,825.92 MWD+SC+sag(3) 6,602.71 21.04 91.14 5,688.76 5,483.61 -302.89 2,832.44 2,465,622.49 347,378.66 0.75 2,848.55 MWD+SC+sag(3) 6,665.12 18.90 89.73 5,747.42 5,542.27 -303.06 2,853.75 2,465,622.03 347,399.96 3.51 2,869.77 MWD+SC+sag(3) 6,727.86 18.94 89.36 5,806.77 5,601.62 -302.90 2,874.10 2,465,621.92 347,420.30 0.20 2,889.99 MWD+SC+sag(3) 6,790.69 17.69 90.18 5,866.41 5,661.26 -302.82 2,893.84 2,465,621.75 347,440.05 2.03 2,909.63 MWD+SC+sag(3) 6,853.76 16.46 90.66 5,926.70 5,721.55 -302.95 2,912.36 2,465,621.37 347,458.56 1.96 2,928.06 MWD+SC+sag(3) 6,914.69 15.91 92.47 5,985.22 5,780.07 -303.41 2,929.33 2,465,620.69 347,475.53 1.22 2,945.00 MWD+SC+sag(3) 6,974.52 15.60 91.07 6,042.80 5,837.65 -303.92 2,945.57 2,465,619.97 347,491.75 0.82 2,961.20 MWD+SC+sag(3) 7,040.08 14.12 92.23 6,106.17 5,901.02 -304.39 2,962.37 2,465,619.27 347,508.55 2.30 2,977.97 MWD+SC+sag(3) 7,102.25 12.70 92.51 6,166.64 5,961.49 -304.99 2,976.78 2,465,618.48 347,522.94 2.29 2,992.36 MWD+SC+sag(3) 7,163.43 10.97 90.51 6,226.52 6,021.37 -305.33 2,989.32 2,465,617.97 347,535.48 2.91 3,004.87 MWD+SC+sag(3) 7,225.03 8.64 94.96 6,287.21 6,082.06 -305.78 2,999.79 2,465,617.38 347,545.94 3.97 3,015.34 MWD+SC+sag(3) 7,287.82 8.43 93.31 6,349.31 6,144.16 -306.46 3,009.09 2,465,616.59 347,555.23 0.51 3,024.65 MWD+SC+sag(3) 7,350.07 8.12 91.68 6,410.91 6,205.76 -306.85 3,018.04 2,465,616.07 347,564.17 0.62 3,033.59 MWD+SC+sag(3) 7,412.82 9.66 95.41 6,472.91 6,267.76 -307.48 3,027.71 2,465,615.32 347,573.83 2.62 3,043.28 MWD+SC+sag(3) 7,473.50 9.40 96.24 6,532.75 6,327.60 -308.49 3,037.70 2,465,614.17 347,583.81 0.48 3,053.33 MWD+SC+sag(3) 7,537.18 9.31 97.27 6,595.58 6,390.43 -309.71 3,047.98 2,465,612.82 347,594.07 0.30 3,063.68 MWD+SC+sag(3) 7,600.10 9.14 97.90 6,657.69 6,452.54 -311.04 3,057.98 2,465,611.35 347,604.05 0.31 3,073.76 MWD+SC+sag(3) 7,661.81 8.74 97.42 6,718.65 6,513.50 -312.32 3,067.48 2,465,609.95 347,613.54 0.66 3,083.34 MWD+SC+sag(3) 7,723.60 8.55 97.45 6,779.74 6,574.59 -313.52 3,076.69 2,465,608.63 347,622.73 0.31 3,092.63 MWD+SC+sag(3) 7,785.75 8.93 97.47 6,841.16 6,636.01 -314.75 3,086.06 2,465,607.28 347,632.07 0.61 3,102.07 MWD+SC+sag(3) 7,849.28 9.06 97.50 6,903.91 6,698.76 -316.04 3,095.90 2,465,605.85 347,641.90 0.20 3,111.99 MWD+SC+sag(3) 7,911.73 8.84 97.56 6,965.60 6,760.45 -317.32 3,105.54 2,465,604.45 347,651.52 0.35 3,121.71 MWD+SC+sag(3) 7,973.80 8.63 97.86 7,026.95 6,821.80 -318.58 3,114.88 2,465,603.06 347,660.84 0.35 3,131.13 MWD+SC+sag(3) 8,036.66 8.33 98.83 7,089.13 6,883.98 -319.93 3,124.05 2,465,601.60 347,669.99 0.53 3,140.39 MWD+SC+sag(3) 8,098.52 8.60 98.78 7,150.31 6,945.16 -321.32 3,133.05 2,465,600.09 347,678.97 0.44 3,149.48 MWD+SC+sag(3) 8,160.36 8.81 97.54 7,211.44 7,006.29 -322.65 3,142.31 2,465,598.64 347,688.22 0.46 3,158.83 MWD+SC+sag(3) 8,223.13 8.39 99.80 7,273.50 7,068.35 -324.06 3,151.59 2,465,597.10 347,697.47 0.86 3,168.20 MWD+SC+sag(3) 8,285.87 7.98 99.15 7,335.60 7,130.45 -325.53 3,160.40 2,465,595.52 347,706.26 0.67 3,177.12 MWD+SC+sag(3) 8,347.90 7.74 99.49 7,397.05 7,191.90 -326.90 3,168.77 2,465,594.03 347,714.61 0.39 3,185.58 MWD+SC+sag(3) 8,410.32 7.11 101.79 7,458.95 7,253.80 -328.38 3,176.70 2,465,592.45 347,722.52 1.12 3,193.62 MWD+SC+sag(3) 8,471.98 6.55 100.01 7,520.17 7,315.02 -329.77 3,183.90 2,465,590.96 347,729.70 0.97 3,200.92 MWD+SC+sag(3) 8,535.60 6.16 100.54 7,583.40 7,378.25 -331.03 3,190.83 2,465,589.61 347,736.61 0.62 3,207.94 MWD+SC+sag(3) 7/24/2017 7.52.51PM Page 5 COMPASS 5000.1 Build 81D • i Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: :, Well SRU 241-33 Project: Swanson River Unit TVD Reference: SRU 241-33 WP08 As-Built @ 205.15usft Site: SRU 21-33 MD Reference: SRU 241-33 WP08 As-Built @ 205.15usft Well: SRU 241-33 North Reference: True Wellbore: SRU 241-33 Survey Calculation Method: Minimum Curvature Design: SRU 241-33 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (a) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 8,591.78 6.12 101.04 7,639.26 7,434.11 -332.15 3,196.73 2,465,588.41 347,742.50 0.12 3,213.93 MWD+SC+sag(3) 8,630.00 6.12 101.04 7,677.26 7,472.11 -332.94 3,200.73 2,465,587.58 347,746.49 0.00 3,217.99 PROJECTED to TD mitchell.laird@halliburtoncom M` ", ""�';',°,"""` Checked By: 2017.072416:54:15-05'00' Approved By: Michael Calkins o ,a« .—.-. Date: 7/24/2017 7/24/2017 7:52:51PM Page 6 COMPASS 5000.1 Build 81D • Hilcorp Energy Company • CASING&CEMENTING REPORT Lease&Well No. SRF SRU 241-33 Date Run 5-Jul-17 County Kenai State Alaska Supv. C Montague /R Wall CASING RECORD Surface V. TD 2,014.50 Shoe Depth: 2,004.50 PBTD: 1,919.40 No.Jts.Delivered 50 No.Jts.Run 47 No.Jts.Returned 3 Ftg.Delivered 2,109.00 Ftg.Run 1,983.00 Ftg.Returned 126.00 Length Measurements W/O Threads Ftg.Cut Jt. Ftg.Balance RKB 18.00 RKB to BHF 20.35 RKB to CHF RKB to THF Casing(Or Liner)Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top lull nose float sho 7 5/8 26.0 L-80 DWC/C Weatherford 1.59 2,004.52 2,002.93 2 Casing 7 26.0 L-80 DWC/C Atlas Bradford 82.25 2,002.93 1,920.68 Float collar 7 5/8 26.0 L-80 DWC/C Weatherford 1.28 1,920.68 1,919.40 44 Casing 7 26.0 L-80 BTC-M Atlas Bradford 1,832.32 1,919.40 87.08 1 Pup jt"E" 7 26.0 L-80 BTC-M Atlas Bradford 19.81 87.08 67.27 1 Casing 7 26.0 L-80 BTC-M Atlas Bradford 41.69 67.27 25.58 Hanger w/pup 13 5/8 55.0 L-80 BTC-M Cactus 4.35 25.58 21.23 Csg Wt.On Hook: 70,000 Type Float Collar: Weatherford Mod 404 No.Hrs to Run: 3.5 Csg Wt.On Slips: 70,000 Type of Shoe: Weatherford Mod 303B Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg X Yes No 20 Ft.Min. 9.1 PPG Fluid Description: water based spud mud Liner hanger Info(Make/Model): Liner top Packer?: _Yes No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: Two on the shoe joint.One on joint#2&3.Then starting with#5 ran one every other joint to#41.23 in the hole.Solid body Hydroforms.8.25".All free floating except on shoe joint,trapped with two stop rings each 10 feet from top and bottom.Joint #3 trapped in the middle with two stop rings.6 rings in the hole. CEMENTING REPORT Shoe @ 2004.52 FC @ 1,919.40 Top of Liner #N/A Preflush(Spacer) Type: Clean Spacer Density(ppg) 10.2 Volume pumped(BBLs) 30 Lead Slurry Type: Type I/II Sacks: 203 Yield: 2.43 Density(ppg) 12 Volume pumped(BBLs) 88 Mixing/Pumping Rate(bpm): 6 Tail Slurry m Type: Class G Sacks: 100 Yield: 1.23 Density(ppg) 15.4 Volume pumped(BBLs) 22 Mixing/Pumping Rate(bpm): 5 y Post Flush(Spacer) F re Type:Water Density(ppg) 8.34 Rate(bpm): 4 Volume: 10 LL Displacement: Type: Spud Mud Density(ppg) 9.1 Rate(bpm): 6 Volume(actual/calculated): 63.1/63.4 FCP(psi): 500 Pump used for disp: Halliburton Bump Plug? X Yes No Bump press 1200 Casing Rotated? Yes X No Reciprocated? X Yes No %Returns during job 100 Cement returns to surface? X Yes _No Spacer returns? X Yes No Vol to Surf: Cement In Place At: 17:24 Date: 7/5/2017 Estimated TOC: Ai-- 6 ' Method Used To Determine TOC: Returns Post Job Calculations: Calculated Cmt Vol @ 0%excess: 66.3 Total Volume cmt Pumped: 110 Cmt returned to surface: 23 Calc ed cement left in we .ore: 87 OH volume Calculated: AZICIP OH volume actual: 63.25 Actual%Washou: 48 _ WELLHEAD Make Cameron Type Serial No. 113017414004 Size 4.06 W.P. 5000 Test head to PSIG MIN OK Remarks: www.wellez.net WellEz Information Management LLC ver_102716bf . Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. SRF SRU 241-33 Date Run 21-Jul-17 County Kenai State Alaska Supv. R Pederson /A.Dorr CASING RECORD Production V' TD 8,630.00 Shoe Depth: 8,625.34 PBTD: 8,581.00 No.Jts.Delivered No.Jts.Run 211 No.Jts.Returned Ftg.Delivered Ftg.Run 8,606.16 Ftg.Returned Length Measurements W/O Threads Ftg.Cut Jt. Ftg.Balance RKB 18.00 RKB to BHF 20.35 RKB to CHF RKB to THF Casing(Or Liner)Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top Shoe 5 TXP Antelope 1.40 8,625.34 8,623.94 1 Casing 41/2 12.6 L-80 TXP Tenaris 41.53 8,623.94 8,582.41 Float Collar 5 TXP Antelope 1.30 8,582.41 8,581.22 210 Casing 41/2 12.6 L-80 TXP Tenaris 8,558.95 8,581.22 22.27 Hanger Pup 41/2 12.6 L-80 TXP Tenaris 2.09 22.27 20.18 Casing Hanger 10 3/4 1.00 20.18 19.18 Csg Wt.On Hook: 77 Type Float Collar: Antelope No.Hrs to Run: 15 Csg Wt.On Slips: Type of Shoe: Antelope Bullnose Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg _Yes X No Ft.Min. 12.4 PPG Fluid Description: 6%KCL PHPA Liner hanger Info(Make/Model): Liner top Packer?: _Yes X No Liner hanger test pressure: Floats Held X Yes_ No Centralizer Placement: 155 total centralizers(153 Hydroforms 6"OD Centralizers/2 Aluminum Straight Blade 6"OD Centralizers) CEMENTING REPORT Shoe @ 8625 FC @ 8,581.00 Top of Liner Preflush(Spacer) Type: Clean Spacer III Density(ppg) 12.9 Volume pumped(BBLs) 28 Lead Slurry Type: I-II Sacks: 490 Yield: 1.86 Density(ppg) 12.8 Volume pumped(BBLs) 166 Mixing/Pumping Rate(bpm): 3 Tail Slurry w Type: Class G Sacks: 120 Yield: 1.25 .4 Density(ppg) 15.3 Volume pumped(BBLs) 27 Mixing/Pumping Rate(bpm): 3 w Post Flush(Spacer) 1— en Type: Density(ppg) Rate(bpm): Volume: a Displacement: Type: 3%KCL Density(ppg) 8.4 Rate(bpm): 3 Volume(actual/calculated): 130/130.44 FCP(psi): 3700 Pump used for disp: Halliburton Bump Plug? X Yes No Bump press 4200 Casing Rotated? Yes X No Reciprocated? Yes X No %Returns during job 99 Cement returns to surface? X Yes _No Spacer returns? X Yes No Vol to Surf: 0 Cement In Place At: 10:32 Date: 7/22/2017 Estimated TOC: 21 Method Used To Determine TOC: Cement Returns 1 n-y G_c,,,,,"„�.�- r '/1 K 7" 4 nil-L.-L-1— ellt -C(L (AS 1 1—,_--d-_5 r u..4". C' .�t-- L ,...6---4- Z-.•c C Post Job Calculations: lA w,ti hs.:r �'''mss':{^�- Calculated Cmt Vol @ 0%excess: 149.3 Total Volume cmt Pumped: 193 Cmt returned to surface: 13 Calculated cement left in wellbore: 180 OH volume Calculated: 111.3 OH volume actual: Actual%Washout: WELLHEAD I `f-c _/zr, Make Cameron Type Serial No. 113017414004 Size 4.06 W.P. 5000 Test head to PSIG MIN OK Remarks: www.wellez.net WellEz Information Management LLC ver_102716bf i •11 2 � � Seth Nolan Hilcorp Alaska, LLC 0 GeoTech 3800 Centerpoint Drive, Suite 100 RECEIVEAnch , AK Tele:orage907 777-830899503 11ilrs,rp:tl:exlca.1,l.t: Fax: 907 777-8510 DEC 15 2017 E-mail: snolan@hilcorp.com DATA LOGGED \ /A/201' A (�; K.BENDER DATE 12/06/2017 " '®GC" To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL SRU 241-33 Prints: PERFORATION RECORD PLUG SETTING RECORD (11-2-2017) PLUG SETTING RECORD (10-26-2017) GASSAT3D ANALYSIS CD: 1 Completion logs PERF_11NOV17 11/15/2017 3:05 PM File folder PLUG 02NOV17 11/15/2017 3:01 PM File folder PLUG_260CT17 11/15/2017 2:58 PM File folder CD: 2 GASSAT3D FIELD DATA 11/1512017 2:22 PM File folder 2 8 8 7 2 FRS PROCESSED 11/1512017 2:24 PM File folder Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received Byp/) (.../ Date: • ti OF 74,6. THE STATE Alaska Oil and Gas 4w "l�i�"-9� of LAsKA Conservation Commission 333 West Seventh Avenue ro- GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 o Main: 907.279.1433 ALAS'" Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manger Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Tyonek Gas Pool, SRU 241-33 Permit to Drill Number: 217-047 Sundry Number: 317-572 Dear Mr. Helgeson: Enclosed is the approved application for 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, Hollis S. French Chair DATED this � day of December, 2017. RBDNIS L'E`'(.: f, 2617 • RECEIVED STATE OF ALASKA DEC 0 7 ?017 ALASKA OIL AND GAS CONSERVATION COMMISSION 015 ( (3//7 APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate 0 ` Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well El Alter Casing El Other: CT N2 Lift+Run Tubing❑✓ • 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory ❑ Development Q• 217-047• 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic El Service ❑ 6.API Number: Anchorage Alaska 99503 50-133-20663-00 . 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O.716.001 Swanson River Unit(SRU)241-33 ' Will planned perforations require a spacing exception? Yes El No No 0 9.Property Designation(Lease Number): 10. Field/Pool(s): A028399;A028406 • Swanson River-Tyonek Gas Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD):7,760'; Junk(MD): 8,630' 7,677' 7,760' 6,816' -2,277 psi 7,795';7,838';8,168' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 2,005' 7" 2,005' 1,986' 7,240psi 5,410psi Intermediate Production 8,625' 4-1/2" 8,625' 7,672' 8,430psi 7,500psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A;N/A N/A;N/A 12.Attachments: Proposal Summary Q Wellbore schematic Q 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory El Stratigraphic El Development❑2 ' Service ❑ 14.Estimated Date for 15.Well Status after proposed work: December 20,2017 CommencingOperations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑✓ • WAG El GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned 0 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: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer@hilcorp.com Contact Phone: 777-8420 Authorized Signature: 117 -�., Date: a1Z.ob 7 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 11- 572 Plug Integrity ❑ BOP Test p Mechanical Integrity Test ❑ Location Clearance ❑ Other: RES ( k-- C i ! 2017 !t Post Initial Injection MIT Req'd? Yes No ��+ 3 ` 7— '12-'1Spacing Exception Required? Yes El No Subsequent Form Required: I l7—��G _. �" i/ APPROVED BY � Approved by:/ AIDT-..\____, plication is valid for 12 monthc)oRhi del viol. .27,i).ttachments in Duplicate • • Well Prognosis Well: SRU 241-33 Hilcorp Alaska,Lb Date: 12/06/2017 Well Name: SRU 241-33 API Number: 50-133-20663-00 Current Status: New Grassroots Well Leg: N/A Estimated Start Date: December 20, 2017 Rig: E-line/Coil Tubing/ Nitrogen Unit Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 217 0 First Call Engineer: Ted Kramer (907) 777-8420(0) (985) 867-0665 C) Second Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (C) AFE Number: 1711425C Maximum Expected BHP: —2,530 psi @ 5,786' TVD (Based on .437 psi/ft gradient to the deepest perforation. Max. Potential Surface Pressure: —2,277 psi @ 5,786' TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary SRU 241-33 is a grass roots development well targeting gas sands in the Sterling and Tyonek formation. This new well reached TD on 7/18/17 and completed 7/23/17. During the completion phase,the well did not pass an MIT-IA to 2,500 psi (the pressure bled to 750 psi and held solid). Because the well does not have a monitorable annulus or tubing casing annulus as required per 20 AAC 25.200 (d). Hilcorp is requesting a waiver from this monitorable annulus requirement for no more than ten days per zone in order to perforate, test, and plug back any non-productive intervals prior to running the final completion which will isolate the tubing casing annulus from fluids being produced. This testing with access to the full bore of the well is necessary in order to set plugs for plug backs and patches to isolate non-productive zones that make water. Once production is established,a packer and production tubing V will be ran ( Sundry # 317-424) with the Packer being set @ 6,550' (+/-) where good cement is shown to exist from a CBL. The purpose of this work/sundry is to Perforate and test additional sand intervals in the well bore prior to running the completion. Notes Regarding Wellbore Condition • Well did not pass an MIT-IA due to a micro channel. Well held 750 psi, but bled off to that amount when subjected to higher pressures. Hilcorp will run a packer and tubing after initial testing shows that the well is commercially viable. Safety Concerns / • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. • Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job). • Ensure all crews are aware of their stop job authority. • • Well Prognosis Well: SRU 241-33 IIileorp Alaska,LL Date: 12/06/2017 E-Line Procedure 1. MIRU e-line and pressure control equipment. PT lubricator to 3,000 psi Hi 250 Low. 2. PU Bailer. RIH and Dump Bail 35' of cement on the CIBP @ 7,760' (TOC @ 7,725' (+/-)). 3. Pressure up with Nitrogen and push any water higher than 6,700' into the 65-8 sand perforations. 4. PU, RIH W/4-1/2" CIBP to 7,510'. Set same. 5. PU Bailer. Load with Cement and RIH dumping 35' of cement on top of the 4-1/2" CIBP (TOC @ 7,475'). 6. Adjust Nitrogen charge on well to achieve a 20% underbalance on the formation to be perforated. 7. Perforate and test the following sands one at a time with 2-7/8" 6 SPF 60 deg phased perf guns (up to 12 SPF with 2 perf runs) starting with the deepest perf interval. Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt SR-55-4 ±6,650' ±6,695' ±5,528' ±5,570' 45 SR-55-4 ±6,704' ±6,734 ±5,579' ±5,607 30 v"- SR-55-4 SR-55-4 ±6,904 ±6,920' ±5,769' ±5,786' 16 a. Proposed perfs also shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. d. Use Gamma/CCL to correlate. e. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. f. Conservation Order 716.001 defines the Tyonek Gas Pool as all intervals that correlate with the interval 5,304 feet MD to 10,085 feet MD in the Soldotna Creek Unit 41-4 well. All of the perforations in table above fall within the defined SRU Tyonek Gas Pool, as currently defined. d.(4rri-' 8. POOH. 9. RD e-line. 10. Turn well over to production. Test each zone for 5-7 days. If the zone is productive, SI after 7 days of testing. Complete SVS testing per 20 AAC25.265 within 5 days of stable production. E-line Procedure (Contingency): • If any zone produces sand and/or water or needs isolated • MIRU E-line, PT lubricator to 4,500 psi Hi 250 Low. • RIH and set 4-1/2" CIBP at depth above zone. Or • RIH and set 4-1/2" Casing Patch across the zone. • Jet dry with Coil Tubing and nitrogen if needed. Once production is established from testing work and the well is deemed commercial, the completion will be ran starting with Step#15 in Sundry#317-424. The new packer setting depth will be adjusted for the new perforations, currently estimated to be 6,550'. r p � tOi • • Well Prognosis Well: SRU 241-33 Ililcorp Alaska,LU Date: 12/06/2017 Attachments: 1. Actual and Proposed Well Schematics 2. Coil BOPE Schematic 3. CT Flow Diagrams(Forward and Reverse Jetting) 4. Wellhead Diagram 5. Workover Rig BOP Schematic 6. Rig 401 Flow Diagram. 7. Blank RWO Change Form 8. Standard Well Procedure—N2 Operations • • , Swanson River Unit SCHEMATIC WeII SRU #241-33 PTD: 217-047 API: 50-133-20663-00 Hi[carp Alaska,LLC RKB to GL=20' CASING DETAIL Size Type Wt Grade Conn. ID Top Btm s et is: Conductor-Driven 16" to Set Depth 84 X-56 Weld 15.01" Surf 120' vs' 7" Surf Csg 26 L-80 BTC/M 6.875" Surf 2,005' rk4 Iii eObf 4-1/2" Prod Csg 12.6 L-80 TXP 3.958" Surf 8,625' eyvd i* %).. JEWELRY DETAIL 7" "" No. Depth ID OD Item ' a 1 7,760' CIBP 11/30/17 RA @ 2,817' •iry 2 7,795' CIBP w/15'cement 11/02/17 , 3 7,838' CIBP w/21'cement 10/28/17 RA @ 3,800' 1":" ,6 r 4 8,168' CIBP w/35'of cement;55'total 10/26/17 5 8,565' 1.875" 3,75" Tri-Pt Model D Isolation Pkr 08/28/17 y p, RA @ 6,006' trik y ' ' ': PERFORATION DETAIL ,�a# 1 ,, Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status .. 65-8 7,528' 7,533' 6,586' 6,591' 5 11/30/17 Open r} eS".f , f 68-0 ±7,745' ±7,755' ±6,801' ±6,811' 10 Proposed TBD , a 68-0 7,770' 7,775' 6,826' 6,830' 5 11/29/17 Isolated A - 65-8 68-0 7,770' 7,775' 6,826' 6,830' 5 11/11/17 Isolated OtAkt Y t : ,<: 68-0 7,812' 7,817' 6,867' 6,872' 5 10/28/17 Isolated 68-0 7,845' 7,860' 6,900' 6,914' 15 10/16/17 Isolated TOC 7,780' ., ,Slit 3 73-5 8,355' 8,375' 7,404' 7,424' 20 9/28/17 Isolated 20,11....,L. ..%�"I. 75-7 8,538' 8,558' 7,586' 7,606' 20 9/19/17 Isolated > 4 TOC 7,817' . .�. 68-0 77-3 8,585' 8,595' 7,632' 7,642' 10 9/18/17 Isolated . :-a TOC 8,113' t +A , f ficii ' `. 73-5 RA@8,415' „ '�1f A 4 ■17: ,am 75-7 4 . OPEN HOLE/CEMENT DETAIL sem' " ' ' 8-1/2"hole.88 BBL(203 sx)of 12 ppg Type I/II Cement and 22 BBLs(100 sx)15.4 ,,r 'hNc� * ,F 7 7 ppg of Class G tail. 100%returns throughout,23 bbls to surface. .' 6-1/8"hole.166 BBL(490 sx)of 12.8 Type I-II Cement and 27 BBLs(120 sx)15.3 ppg 77-3 4-1/2" ,, . . of Class G tail.99%returns throughout,0 bbls to surface. 4-1/2" 'kat. . A.11W12!r: PBTD=7,760'/PBTVD=6,816' TD=8,630'/ND=7,677' Updated By DMA 12-06-17 • • Swanson River Unit 14 PROPOSED SCHEMATIC Well SRU #241-33 PTD: 217-047 API: 50-133-20663-00 I lilcarp Alaska,LLC RKB to GL=20' CASING DETAIL 41,1,, 16" ' ' h,.0,1 aj ->' Size Type Wt Grade Conn. ID Top Btm ' :it Conductor-Driven t . to Set Depth :M: 16" 84 X-56 Weld 15.01" Surf 120' a 14 7" Surf Csg 26 L-80 BTC/M 6.875" Surf 2,005' P xa; - 4-1/2" Prod Csg 12.6 L-80 TXP 3.958" Surf 8,625' y, TUBING DETAIL E0 44 ,cri Hrdr511/ * , ' 2-7/8" Production 6.4 L-80 EZGO FJ-3 2.441" Surf ±6,550' lit LP 1 es . 4 . JEWELRY DETAIL " ' No. Depth ID OD Item r 1 ±6,550' 2.33" 3.79" Packer w/snap latch assembly RA @ 2,817' 'z �r 2 ±6,560' 2.313" X-Nipple ,, 3 7,760' CIBP 11/30/17 RA @ 3,800' 4 7,795' CIBP w/15'cement 11/02/17 !� 5 7,838' CIBP w/21'cement 10/28/17 6 8,168' CIBP w/35'of cement;55'total 10/26/17 RA @ 6,006' . . ,tt' ,r ' 1.4 ... 7 8,565' 1.875" 3,75" Tri-Pt Model D Isolation Pkr 08/28/17 piiki +moi , 1 r :2 ,_..„,.., tar t PERFORATION DETAIL flit-' 55-4 Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status u 4 w/1181.aa< 55-4 ±6,650' ±6,695' ±5,528' ±5,570' 45 Proposed TBD ; 55-4 ±6,704' ±6,734 ±5,579' ±5,607 30 Proposed TBD 55-4 ±6,904 ±6,920' ±5,769' ±5,786' 16 Proposed TBD %"" 65-8 ±7,527' ±7,547' ±6,585' ±6,605' 20 Proposed TBD " sar"E 65-8 !.it+a� �� Ell 65-8 7,528' 7,533' 6,586' 6,591' 5 11/30/17 Open . _ ,�1 ei' 68-0 ±7,745' ±7,755' ±6,801' ±6,811' 10 Proposed TBD * ..e..%''..1-1%'y� 3 68-0 7,770' 7,775' 6,826' 6,830' 5 11/29/17 Isolated TOC 7,780' v � '+45. ,4 li.fi 68-0 7,770' 7,775' 6,826' 6,830' 5 11/11/17 Isolated 4 `k 4 68-0 7,812' 7,817' 6,867' 6,872' 5 10/28/17 Isolated TOC 7,817' ., p"'" '" 68-0 68-0 7,845' 7,860' 6,900' 6,914' 15' 10/16/17 Isolated '-+ - 73-5 8,355' 8,375' 7,404' 7,424' 20 9/28/17 Isolated _._ 5 75-7 8,538' 8,558' 7,586' 7,606' 20 9/19/17 Isolated y+(i,' $;= 77-3 8,585' 8,595' 7,632' 7,642' 10 9/18/17 Isolated TOC 8,113' T1 . rt' ' r a r It 6 ,./ �e iA ,r,rR t��a. 73-5 RA @ 8,415' ,,"(r, .: , OPEN HOLE/CEMENT DETAIL „,-, 4 -',-.40. .,I-MVIS, 75-7 z"+4. 8-1/2"hole.88 BBL(203 sx)of 12 ppg Type I/II Cement and 22 BBLs(100 sx)15.4 ''' ,t �Ih.dl'� ,'l': 7 7 ppg of Class G tail. 100%returns throughout,23 bbls to surface. `` r" ,-m 77-3 6-1/8"hole.166 BBL(490 sx)of 12.8 Type I-II Cement and 27 BBLs(120 sx)15.3 ppg �' 4 1/2 of Class G tail.99%returns throughout,0 bbls to surface. 1,1' ,, yy,., 4-1/2" t"'''.. -'"''''''‘• r-. PBTD=7,760'/PBTVD=6,816' TD=8,630'/TVD=7,677' Updated By DMA 12-06-17 • HILCORP ALASKA 7-1/16" 5M BOPE ( 7-1/16" 5M HYDRIL GK ANNULAR 32" TALL, FLANGE TO FLANGE f I'M RI rTh rTh / \ 7-1/16" 5M LWS DBL GATE BOP DRESSED W/VARIABLE RAMS IN TOP DRESSED W/BLIND RAMS IN BOTTOM • 26-3/4"TALL, FLANGE TO FLANGE 7-1/16" 5M DRILLING SPOOL W/2-1/16" SM OUTLETS "�"ff 18" TALL, FLANGE TO FLANGE —77" TOTAL STACK HEIGHT ANNULAR STYLE BOP SPECS: - 3.30 gallon open chamber volume -3.86 gallon close chamber volume GATE STYLE BOP SPECS: - 1.45 gallons to close per gate - 1.18 gallons to open per gate -5.45:1 closing ratio - 1.93:1 opening ratio • 83 : t D v Q = y ' , U z Q m o 8 , ) 9ZY I Cl) F E OU w W N V Z = -+--, s :5 a a N ! o X o st% CP § 8 g W, E e a ci) 4444--- N g Z -0 f L._ ii ,-)c(i__ 0 , i 0 U C > O c_ F-O Pith •mi a = IMI* 0 11I1!11.111I. IFIL Ii ' liii taiMgIn ii I II o g U -. Z _c C F0 - a 0 I c g nm1 O • 1 � O t i II I :.k ti 8 '-e-= Ht C / 0 C � O� 7 C c _ _ o oa - U N - o o Z m° w o p i • i . 8] g F '3 0 I C a '3 I— z" ° ' mo l .3 —0P- -u-2 '� !i O O CD Ii N ^ � Z s €611e C V g t1/2g k -1-, vliN I I, c,, ._ t _._,N Z a. ° C •z N 0_ F-o 0 II IIIII • _ b I-1III0 IIIII.'I.h'.II�$I.'� 4 y I 311MIIIIi " w a 3 c c i2 n 1 E• 1 A tio • 6 V • 1 I D ., O g 00 IA I8 t1 al c n o c = O a v U N O Z O p° 3 uI0 i N 3 i Swanson River Unit • • II WELLHEAD DRAWING SRU 241-33 07/28/2017 llilr•orp Va.l,a.LL(. Casing hanger,CW,11x4% DWC/C box btm x 6.125"RH stub acme box top,w/7 5/8 od neck,4"type H BPV profile,DD-NL material BHTA,Otis,4 1/16 5M FE x 6.5 Otis quick union top o a I 116111•1 1.1111.1.10.1 1•J1�1 Iii lel Valve,Swab,WKM-Mf:),14%Valve,S M FE,HWO, EE trim J r r . Valve,Wing,WKM- Valve,Wing,SSV,WKM-M, 31/85M FE,HWO, 31/S SM FE,w/15"Hydraulic 111I�1_I�IIYI E/ lir operator 0 'Hi -17. 111 . i i 6. '_ ri i 1 ii .11.1-1.11.1 Valve,Upper master, F > O WKM-M, I y-- Ci. 4 1/16 5M FE,HWO,EE trim • MIN Valve,Master,WKM-M, O -'- 4 1/16 5M O41/165M FE,HWO, -- EE trim © • 11_1111_1n 1/1 „a Tubing head,Cactus C-29L- _■.I ,INIIIINI . IIIIII , :■_ aw HPS,135/85M x115M,w/ — - 2-2 1/16 5M SSO Mr :c _I : I 4,, . 1 - iiii : so:k ). ; Im d= 1 I - ANNE 1 MN 111117 1 Starting head,Cactus C-29L, .ilii...0 A1Mon Ii■- 135/85M x16 SOW,w/2-2 — r- 1/16 5M SSO 1 11171 /•.I C Z 1, - i e III MI I I i • : II 16" 7 5/8" 4'f." • i II Swanson River Unit SRU 241-33 07/28/2017 illi At IsAa.1.1.r: sus. t t. C __ ____� IiiIII MMliii=moi M Illi`1q t1 , Coiled Tubing HR580 Injector Head&Gooseneck 111. i i Y1 Weight=12,850 lbs ��. u '.;I.I1 • 4 4-1/16"10K Conventional Stripper ow .ii WI NI 4 51( C062x Lubricator xlLearc WH PSI 2"1502 x 2-1/16 10K Flanged Valve 5K C062 4-1/16"10K Flan ge (Manual) 2-1/16 10K x2-1/16 IM 4-1/16"10K Combi BOP 10K Flanged Valve .�.0 — —. i Top Set:Blind/Shear (ManiJ) it . . Second Set:Pipe/Slip ;nub . ° . Mnn it 4-1/16"10K Flow Cross Manual 2x2 Valve 1:2"1502 x 2-1/16"10K Flange 010110[01 liri ID§01! 4 Manual 2x2 Valve 2:2-1/16"10K x2-1/16"10K Flange Manual 2x2 Valve 3:2-1/16"10K x2-1/16"10K Flange Manual 2x2 Valve 4:2"1502 x 2-1/16"10K Flange I 4-1/16"10K x Wellhead Adapter Flange 1111011E14111011.1 ; ` 4 Wellhead • • r UW :.:„.,..,,..,., , ,,J , m,_,_z__:..: C ori aw o 'jy = 7.1 F, V wig. , IiNIIII1 •�I!II t -.,11 i mN 01V Er.:1111111111111111111111111111111111111111111111111F (' i f 22.. z a F- 0 5 LL CI c O G 2 O o ce a v Q r g 0 0 F g 0 1 z W 0 0 ❑ Uw 2 5z a oa0-' L.L. 7 j 2a • 0 § k # 2S � kJ2 o Q — as a > § / E 0o■ co \2 k §/ «� E E 0o c 73 o c t 2 \ ( X a1-2 ff< \ \ \ _0 � �03 § \ f2� \ ,_ Q. E2 § .\ n ■ 2 } O W $ � 2 k k Oct2 �...._--- (1) Co ZJ CO 0 Q 9 4- 0 k / > 0 0 \ O / al L. n e = CD * 73— CD % / Z & ° Oco CO / « 4 = 0 2 E §/ > _ = e 0 2 / '\ • I- _ \ / 16 \ \ a. E a) .� =2 -o 2\ cc a E 2 $ p w CD \ % 2> \ g o. § �o k5 L « m / 0 0. / k E = Q a) x / a e ƒ 0 7 2 2 ./ e ) 0 L-- 0 (1) # (/) 7 © / 2it 0 .. \ g \ 4) -0 E 0 2 \ I / CO a. \ 23 0 / • 11 STANDARD WELL PROCEDURE IliicorpAIa ka.H.4, NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher.Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 i T S III 21 7047 II Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 Meng]Al;rska.LU. RECEIVED ID Fax: 907 777-85010 E-mail: snolan@hilcorp.com SEP 19 2017 �OG^C DATA LOGGED DATE 09/19/2017 (�✓� 28 6 2 7 M. BENDER K.BENDER To: Alaska Oil & Gas Conservation Commission 2 8 6 2 8 Makana Bender 2 8 6 2 9 Natural Resource Technician 2 8 6 333 W 7th Ave Ste 100 Anchorage, AK 2 6 3 99501 DATA TRANSMITTAL SRU 241-33 Prints: GAS RATIO LOG 2" MD/TVD CBL-VDL-GR-CCL DRILLING DYNAMICS LOG 2"MD/TVD PNX-PBMS FINAL WELL REPORT CASTM ROP-DGR-ADR-EWR-CTN-ALD 2"15"MD FORMATION LOG 2"/5" MD/TVD DGR-ADR-EWR-CTN-ALD 2"/5"TVD LWD COMBO LOG 2" MD/TVD CD: 1 Electric logs Hilcorp_SRU241-33 SCMT-CBL 03AUG17 8/9/2017 7:36 AM File folder CD: 2 Electric logs DLIS Data 8/10/2017 8:45 AM File folder LAS Data 8/10/2017 8:45 AM File folder Log 8/10/2017 8:45 AM File folder CD: 3 Electric logs en SRU 241-33 CAST_16AUG2017.pdf 8/16/2017 3:34 PM PDF Document 3,272 KB ,$- SRU 241-33 CAST_16AUG2017 img.tiff 8/16/2017 3:34 PM TIFF File 10,157 KB u SRU241-33 CAST_16AUG2017 Main.las 8/16/2017 3:49 PM LAS File 3,181 KB SRU 241-33 CAST_16AUG2017 Repeat.las 8/16/2017 3:50 PM LAS File 278 KB CD: 4 Electric logs Daily Reports 8/21/2017 11:18 AM File folder DML Data 8/21/2017 11:18 AM File folder Final Well Report 8/21/2017 11:18 AM File folder LAS Data 8/21/2017 11:18 AM File folder Log PDFs 8/21/2017 11:20 AM File folder Log I lits 8/21/2017 11:20 AM File folder CD: 5 Electric logs Please acknowledge receipt by signing and returnin6g one copy of this transmittal or FAX to 907 777.8337 Received By: Date: • ! • • Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8308 trlrs,rp:tlnraa-1.1A. Fax: 907 777-8510 E-mail: snolan@hilcorp.com Log Viewers 9/8/2017 2:15 PM File folder CGM 7/29/2017 4:04 PM File folder Definitive Survey 7/29/2017 4:04 PM File folder EMF 9/8/2017 2:16 PM File folder LAS 7/29/2017 4:04 PM File folder PDF 7/29/2017 4:04 PM File folder TIFF 9/8/2017 2:17 PM File folder Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: 142,AL,420....7#) o_elkt,ekeet • • a °444-- Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive Co I Anchorage, AK 99503 Tele: 907 777-8308 Mirror')Alaska.t.t.t. Fax: 907 777-8510 E-mail: snolan@hilcorp.com DATE 09/19/2017 RECEIVED To: Alaska Oil & Gas Conservation Commission SEP Meredith Guhl 9 2017 Petroleum Geology Assistant 333 W 7th Ave Ste 100 AOGCC Anchorage, AK 99501 DATA TRANSMITTAL SRU 241-33 WELL SAMPLE INTERVAL SRU 241-33 2014—2940 SRU 241-33 2940—4210 SRU 241-33 4210—5740 SRU 241-33 5740—7060 SRU 241-33 7060—8630 Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received : • Date: OF T7j O \ Iy�,&?. THE STATE Alaska Oil and Gas �,-s-�A of LAsKA Conservation Commission 333 West Seventh Avenue C' GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 OF wa Main: 907.279.1433 ALAS Q. Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Tyonek Gas Pool, SRU 241-33 Permit to Drill Number: 217-047 Sundry Number: 317-424 Dear Mr. Helgeson: Enclosed is the approved application for 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, 671e-er/v Cathy . Foerster Commissioner DATED this-(p day of September, 2017. RBDMS (,L SEP - 7 2017 • • • • RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION SEP 01 20 APPLICATION FOR SUNDRY APPROVALS Ac--5 If CI' 7 20 AAC 25.280 AOG`✓"' 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate 0 Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑r • Other Stimulate 0 Pull Tubing 0 Change Approved Program 0 Plug for Redrill 0 Perforate New Pool ❑ Re-enter Susp Well 0 Alter Casing ❑ Other: CT N2 Lift ❑r 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number:. i2wK.-64../o:03. Hilcorp Alaska, LLC Exploratory ❑ Development Q 217-047 • 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage Alaska 99503 50-133-20663-00 - 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O.716.001 Swanson River Unit(SRU)241-33 ` Will planned perforations require a spacing exception? Yes ❑ No ❑✓ 9.Property Designation(Lease Number): 10.Field/Pool(s): A028399;A028406 Swanson River-Tyonek Gas 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): 8,630' 7,677' 8,581' 7,628' —4,172 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 2,005' 7" 2,005' 1,986' 7,240psi 5,410psi Intermediate Production 8,625' 4-1/2" 8,625' 7,672' 8,430psi 7,500psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A;N/A N/A; N/A 12.Attachments: Proposal Summary ❑✓ Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑r Exploratory El Stratigraphic 0 Development 2 • Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: September 13,2017 OIL 0 WINJ El WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑r WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 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: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer@hilcorp.com Contact Phone: 777-8420 Authorized Signature: Date: trA� /7 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: �� S ' 31-7-`f Z. Plug Integrity 0 BOP Test E Mechanical Integrity Test ❑ Location Clearance ❑ Other: if 11500ta 5 L 4di(9 5 4— (2,s—4 es e4v., n 4.. -1,„--.) Post Initial Injection MIT Req'd? Yes ❑ No 2/ Spacing Exception Required? Yes ❑ No Subsequent Form Required: `0-- Lio' RBDMS I ' SEP - 7 2017 APPROVED BY l/` Approved by: /1 /93...c.,.../4„, COMMISSIONER THE COMMISSION Date: 9_.56:e.....4/i. 7 (J(�/ /`� (//(�J mi and Form 10-403 Revised 4/2017RAF6et NiAnhi ,valickf2 months* from the date of approval. Attachments in Duplicate • Well Prognosis Well: SRU 241-33 Ililcorp Alaska,LL Date:8/30/2017 Well Name: SRU 241-33 API Number: 50-133-20663-00 Current Status: New Grassroots Well Leg: N/A Estimated Start Date: September 13, 2017 Rig: Coil Unit/Moncla 401 Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) Second Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (C) AFE Number: 1711425C Maximum Expected BHP: —4,934 psi @ 7,652 TVD (Based 12.4 ppg mud weight to kill the well and the lowest perf to be shot at 8,571' MD. Max. Potential Surface Pressure: —4,172 psi @ 7,652' TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary SRU 241-33 is a grass roots development well targeting gas sands in the Sterling and Tyonek formation. This new well reached TD on 7/18/17 and completed 7/23/17. During the completion phase, the well did not pass an MIT-IA to 2,500 psi (the pressure bled to 750 psi and ' held solid). Because the well does not have a monitorable annulus or tubing casing annulus as required per 20 AAC 25.200 (d). /0 eia Hilcorp is requesting a waiver from this monitorable annulus requirement for no more than t ee s per <--- * zone in order.to perforate, test, and plug_back any non-productive intervals prior to running the final completion which will isolate the tubing casing annulus from fluids being produced. ,1 � This testing with access to the full bore of the well is necessary in order to set plugs for plug backs an4atches to isolate non-productive zones that make water. Once production is established, a packer and production tubing will be ran with the Packer being set below 7,250' where good cement is known to exist from a cement . bond log. The purpose of this work/sundry is to drill out the casing shoe to the proper depth, blow dry with nitrogen, perforate and test zones until production is established, and then run a completion packer and tubing. Notes Regarding Wellbore Condition • Well is full with 6% KCI. • CBL has been run,AOGCC has a copy on file. • Well did not pass an MIT-IA due to a micro channel. Well held 750 psi, but bled off to that amount when subjected to higher pressures. Will run packer and tubing after initial testing. AA; /74,1e--w A- 4-1.6 /7 Safety Concerns t;�n; �'z`'� : `'` . 7" • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. • Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job). • Ensure all crews are aware of their stop job authority. • • Well Prognosis Well: SRU 241-33 IIilcorp Alaska,LL Date:8/30/2017 Pre—Rig Work Coiled Tubing Procedure (start of Sundry work) 1. MIRU Coiled Tubing, PT BOPE to 4,500 psi Hi 250 Low. Notify AOGCC 24 hrs in advance of BOP test. 2. MU Mill and Motor BHA. 3. RIH and mill cement and cleanout to 8,610' MD. t.- ;.ti" 4. Circulate hole clean with 2 bottoms up, ensure any rubber or cement is free from the hole. it f 5. RU N2 pumping unit. 1v 6. Drop ball and come online with N2 and jelte_IlLyIr . 7. Once well is dry,verify desired surface pressure to leave on well with Operations Engineer. 8. POOH w/coil. LD BHA. 9. RD Coiled Tubing. E-Line Procedure 10. MIRU e-line and pressure control equipment. PT lubricator to 4,500 psi Hi 250 Low. Note that the well is pressurized with nitrogen. • If necessary, bleed pressure down as requested by the RE to establish a drawdown on the formation. 11. Perforate the following Tyonek sands with 2-7/8" 6 SPF 60 deg phased perf guns (up to 12 SPF with 2 perf runs) starting with the deepest perf interval. Zone Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Tyonek 65-8 ±7,522' ±7,547' ±6,580' ±6,605' 25 Tyonek 68-0 ±7,734' ±7,872' ±6,790' ±6,926' 138 Tyonek 69-4 ±7,947' ±7,955' ±7,000' ±7,008' 8 • Tyonek 73-5 ±8,351' ±8,378' ±7,400' ±7,426' 27 Tyonek 75-7 ±8,525' ±8,558' ±7,572' ±7,605' 33 Tyonek 77-3 ±8,571' ±8,605' ±7,618' ±7,652' 34 a. Proposed perfs also shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. d. Use Gamma/CCL to correlate. e. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. f. Conservation Order 716.001 defines the Tyonek Gas Pool as all intervals that correlate with the interval 5,304 feet MD to 10,085 feet MD in the Soldotna Creek Unit 41-4 well.All of the perforations in table above fall within the defined SRU Tyonek Gas Pool, as currently defined. 12. POOH. 13. RD e-line. 14. Turn well over to production. Test zone for 5-7 days. If the zone is productive, SI after 7 days of c testing. t Jr A..ty : An SSV will be installed and function tested. However, Hilcorp w testing the SSV during the testing period as it will be removed for the rig workover to install the tubing. • 11 Well Prognosis Well: SRU 241-33 I3ilcurp Alaska,LU Date:8/30/2017 E-line Procedure (Contingency): • If any zone produces sand and/or water or needs isolated • MIRU E-line, PT lubricator to 4,500 psi Hi 250 Low. • RIH and set 4-1/2" CIBP at depth above zone. Or • RIH and set 4-1/2" Casing Patch across the zone. • Jet dry with nitrogen if needed. Once production is established from testing work and the well is deemed commercial: 15. MIRU E-line unit. Pressure test lubricator to 4,500 psi Hi 250 Low. P- - 16. PU Packer and tail pipe assembly with a plug installed. RIH with same and log on depth at or below 7,250'. Set same. POOH W/E-line. 17. Perform a negative test on the plug by bleeding off pressure above the packer to ensure plug is set. 18. Fill well with produced water(8.4 PPG). Pressure test packer to 2,500 psi on chart for 30 min. Moncla 401 19. MIRU Moncla Rig 401. -1C-©U Z '`' 20. NU 11" BOPE. Test to 250 psi Low/.4;66'0 psi High, annular to 250 psi Low/,..170 psi High (hold each valve and test for 10-min). Record accumulator pre-charge pressures and chart tests. • Notify AOGCC 24 hrs in advance of BOP test. • Test VBR rams on test joint of the smallest diameter pipe used in the well. 21. Pressure test packer and casing to 2,500 psi for 30 min. on chart, 22. PU Ratch Latch assembly on production tubing string. Note: Drift all tubing and tools as they are picked up to be ran into well. 23. RIH W/Production tubing to just above the Production packer. Circ packer fluid down the back side to the packer at or below 7,250'. u . ,�� -7cfS cc^' ... 24. Space out and latch into Production Packer. "� f,� 3 t .2S x 25. Hang off tubing. ND BOP, NU wellhead and test. Z-S"az.)10 s 26. RDMO Workover Rig. Coil Tubing Unit(If necessary based on well performance.) i'4'/T 27. MIRU Coiled Tubing, PT BOPE to 0 psi Hi 250 Low(Notify AOGCC 24 hrs. in advance of BOP test). 28. RIH and blow tubing dry with Nitrogen. Remove plug from tailpipe. kr 29. Turn well over to production to bleed down and place on production. 30. Test SS_V2..../ilhjii.5 days ofaiiiilk production on well. -Notify AOGCC 24 hours prior to testing to give them the opportunity to witness. 0*:- P 2 , •z (e )«) • i Well Prognosis Well: SRU 241-33 llilcorp Alaska.LL Date: 8/30/2017 Attachments: 1. Actual and Proposed Well Schematics 2. Coil BOPE Schematic 3. CT Flow Diagrams (Forward and Reverse Jetting) 4. Wellhead Diagram 5. Workover Rig BOP Schematic 6. Rig 401 Flow Diagram. 7. Blank RWO Change Form 8. Standard Well Procedure—N2 Operations • • Swanson River Unit SCHEMATIC well SRU #241-33 PTD: 217-047 API: 50-133-20663-00 Hacurp Alaska,LLC RKB to GL=20' „v CASING DETAIL 16" 't i~r ' i ► Size Type Wt Grade Conn. ID Top Btm r,,,,##� Conductor—Driven I� ,1 ,..„,t-'4 16" to Set Depth 84 X-56 Weld 15.01" Surf 120' 0404,00* 7" Surf Csg 26 L-80 BTC/M 6.875" Surf 2,005' u ¢ 'A i. *' 4-1/2" Prod Csg 12.6 L-80 TXP 3.958" Surf 8,625' i e t W4, O� � � L k . ,,', .! e. RA @ 2,817' 'y., lli RA @ 3,800' t x f 4 itt 1, RA @ 6,006' Ys , d, r` 4% pir rt 4 r. V rill k?4� tragi t*14: t.,-, ;l RA @ 8,415' 1 . "` " -- k OPEN HOLE/CEMENT DETAIL 4,4 4 7„ 8-1/2"hole.88 BBL(203 sx)of 12 ppg Type I/II Cement and 22 BBLs(100 sx)15.4 '§ . ppg of Class G tail. 100%returns throughout,23 bbls to surface. �. .11 4 1/2" 6-1/8"hole.166 BBL(490 sx)of 12.8 Type I-II Cement and 27 BBLs(120 sx)15.3 ppg 44,4/'''sHill"La". "�a of Class G tail.99%returns throughout,0 bbls to surface. , -� 4:4_1/2„ 10,. - -. PBTD=8,581'/PBTVD=7,628' TD=8,630'/TVD=7,677' Updated By DMA 07-28-17 • • Swanson River Unit 11 PROPOSED SCHEMATIC Well SRU #024133 API: 50-133-20663-00 Hflemp Slaskn.LLC RKB to GL=20' ,-- CASING DETAIL 16" �Y' C. Size Type Wt Grade Conn. ID Top Btm ',. 1 Conductor-Driven I # 16" 84 X-56 Weld 15.01" Surf 120' .. to Set Depth 4) A7" Surf Csg 26 L-80 BTC/M 6.875" Surf 2,005' ' 9 (l .. J 4-1/2" Prod Csg 12.6 L-80 TXP 3.958" Surf 8,625' . ' TUBING DETAIL .i----•:-. 2-7/8" Production 6.4 L-80 Hrdr511/ 2.441" Surf ±7,250' y EZGO FJ-3 ", z .'m - r.1" 1 y,i7 JEWELRY DETAIL 7" -.' , •,Aa' No. Depth ID OD Item - o, t, ti- 1 ±7,250' 2.33" 3.79" Packer w/snap latch assembly 2 ±7,260' 2.313" X-Nipple RA @ 2,817' 'y PERFORATION DETAIL RA @ 3,800 ,7, .A l. ,,,; N--*` Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status `,,� & ,:%**. 65-8 ±7,522 ±7,547' ±6,581' ±6,605' 15 TBD Proposed ' as - 68-0 ±7,734' ±7,872' ±6,790' ±6,926' 138 TBD Propose RA @ 6,006' '' TBD Proposed �_. ti' 4* 69-4 ±7,947' ±7,955' ±7,0uL, ±7,008' 8 p t ` % :-.E.a.:":1'7, * %1 73-5 ±8,351' ±8,37P' ±7,4nr' ±7,427' 27 TBD Proposed IMII � 2 TBDPro osed ,, 75-7 ±8,525' ±8,558' ±7,573 ±7,606' 33 p ±8,571' ±7,619' ±7,652' 34 TBD Proposed i 65-8 77-3 ±8,605' 4 '` 68-0 orittIN--,,,, 1 i 69-4 t ;034;77 404 ' 73-5 r _; , RA@8,415' *4i a.:41 : OPEN HOLE/CEMENT DETAIL 8-1/2"hole.88 BBL(203 sx)of 12 ppg Type I/II Cement and 22 BBLS(100 sx)15.4 r �= . 7'4 , 7„ l'eppg of Class G tail. 100%returns throughout,23 bbls to surface. ,� 4-1/2" 6 1/8"hole.166 BBL(490 sx)of 12.8 Type I-II Cement and 27 BBLS(120 sx)15.3 ppg# 77 3of Class G tail.99%returns throughout,0 bbls to surface. )A . 4-1/2" 'f.sv ; I .'•: .� r. PBTD=- /PBTVD=±7,657' TD=8,630'/TVD=7,677' Updated By DMA 08-31-17 • • II Swanson River Unit SRU 241-33 07/28/2017 Iliiaur„�.Etc: k K• 1: -';'.'.. ia—, Iilryildi I Ilii:=_ice M 1111111•11111 Coiled Tubing HR580 Injector Head&Gooseneck II. •:L�i 1ii Weight=12,850 lbs -- fir.> — ilM ,- ice" ,1 Ic • 4 4-1/16"10K Conventional Stripper mill 5K C062 Lubricator Kill.Pad 41 WH PSI 6 2"1502 x 2-1/16 10K A Flanged Valve 4 5K C062 x 4-1/16"10K Flange (Manual) 2-1/1610Kx2-1/15I 4-1/16"10K Combi BOP 10K Flanged Valve ,, Top Set:Blind/Shear (Manual) M •'"�C. 111&111'. -44 Second Set:Pipe/Slip nn■C. . ■.w:I 4-1/16"10K Flow Cross Manual 2x2 Valve 1:2"1502 x 2-1/16"10K Flange 4.01`1[ONE-4011'1E0V • Manual 2x2 Valve 2:2-1/16"10K x2-1/16"10K Flange Manual 2x2 Valve 3:2-1/16"10Kx2-1/16"10K Flange Manual 2x2 Valve 4:2"1502 x2-1/16"10K Flange III 4-1/16"10K x Wellhead Adapter Flange 1II01=IOil 41I1■ 1 4 Wellhead `, 1 0- • i 83 e ,3 gr () D r Q f ,1 U F t I 3 I- g ? Q = i 7 CD b' i . 3 Et Q moi ,i (n F w E U W D Ali 0104 A (..) g M9 CD V • Z ya II::, Y 1ii = N • Z L i 0 U- o E U O d F-O 1111 mu nil nil ii. I—"II,Ii 0 111.11uhh' 1111. I !ij h S Iuil�imu lc _ g 0 o g Z Y C I- 0 a 0 F- _ V a €i ` = R wm . O 0 8 .. = g I , a = 13 oEi .., V N 0 '0 = 0 i g i • 0 83 . 'I L, 9 F i ti E Z N ! m o 1y , ] H C 1 ] Q) 41 Z g F C 0 o Q N -,baa . o gg€4 • U 1 111. EU D Z 4 g ►0/ ggg E U 0 II 0404 N Z N (no C L U ^` nnV\/ll L crt LL 1111 �_ ii m iuii liii N F i—I'IuII 0 1IIUII•I1'. '��it: l no un muni s w fi 1111 0 0 If 0 I-- , n 0 I C o_ 6 1 • O ¢6�k AV • A a i I II lio , \„........_....} , II 8 10A j • it E c a c 12 0 ?- U N oto Z ii 0 d C M E K • • • Swanson River SRU 241-33-proposed 08/31/2017 Hilrorp 11.1,4u-IIA Swanson River Tubing hanger,Cactus-EN-CL, SRU 241-33 7 x 2 7/8 EUE 8rd lift and 16x 7x4Y:x27/8 susp,w/2 t4 type H BPV profile,1-Y.npt control line port BHT,Otis,4 1/16 5M FE x 6.5 Otis quick union top r""W="1 :7 ., ........ ..._..... Valve,Swab,CIW-FLS ' • 4 1/16 5M FE,HWO, . .•. Valve,Wing,CIW-FC, Valve,Wing,SSV,WKM-M, EE trim • 3 1/8 SM FE,HWO, 3 1/8 5M FE,w/15"Hydraulic 110 EE trim operator tl i � . t :-!1I C i Itail ) Valve,Upper master, CIW-FLS, 41/16 5M FE,HWO,EE trim Valve,Master,CIW-FLS, 4 1/16 5M FE,HWO, ( 1 EE trim Spool,2 9/16 5M FE x 4 1/16 5M stdd ., Adapter,Cactus-EN,7 1/16 5M Stdd x 2 9/16 5M --- prepped for 5''extended neck hanger ' 11111 Tubing head,Cactus C-HPS, 115Mx71/165M,w/2- IP, - 6'L 21/165M SSO , WA ta? -igi.I r Casing hanger,CW,11x4'/: -- ` DWC/C box btm x 6.125"RH - stub acme box top,w/7 5/8 -• Its ! = od neck,4"type H BPV ft Tubing head,Cactus C-29L- ..._ HPS,13 5/8 5M x 11 5M,w/ el -I — * profile,DD-NL material 2-21/165MSSO " , ! lir titi' LI-11111 00.: I Starting head,Cactus C-29L, 135/85M x 16 SOW,w/2-2 1/16 5M SSO I 4 4 - a I16'' 7" 4%" 2 7/8" • • HILCORP ALASKA 11" 5M BOPE 11" 5M HYDRIL GK ANNULAR 47-7/8"TALL, FLANGE TO FLANGE 11" 5M CAMERON TYPE U DOUBLE GATE BOP DRESSED W/VARIABLE RAMS IN TOP DRESSED W/BLIND RAMS IN BOTTOM fa.I .'.u�'. 54-1/2"TALL, FLANGE TO FLANGE 11" 5M DRILLING SPOOL ® ® W/2-1/16" &4-1/16" 5M OUTLETS rft;RI ft All- 24"TALL, FLANGE TO FLANGE —127"TOTAL STACK HEIGHT ANNULAR STYLE BOP SPECS: -8.08 gallon open chamber volume -9.81 gallon close chamber volume GATE STYLE BOP SPECS: -3.4 gallons to open per gate -3.5 gallons to close per gate -7.3:1 closing ratio -2.5:1 opening ratio 0 i C w O 2 = L ....Au 2 u U W a �— t aJ • <w zo= u fL � tx a U111116---- 717 ..T U) gi5 a O �� a O 0 ftlki O I ° LL i 0 - 0 0 a oCI 2 u..._ o Er. cc aZ Kt 0 °` 3 z v o ° Z< � Q = aDz 3 J V1 J V) LIni 2- R. 0 0 - 0 / / Wf 2 a 07c > § \F Dow / / 2kCL ° § /< a E ® E e Sc 2 \ \ 1 cfa oE fE /\/ _0 � �- aro F. f / a.{ a = § .\n ■ e 2 ° qa2 k k % % 2 �>- co zJ $ o 0 � h. k \ > CD Ct _o / O / 03 M / _ & (-o ± VD — Z ° St 0 & 0 \ / 2 / _ < _ 1_ E § \ m = e O 2\ o '\ 2 - / / 0 a / / / § .� m / la 2 : Cl)Ct w0 cU)c LU t \ 0 C Q 2 § - % g k \ kG i < e 'o 0 ■ a. .x x 0 E % 3 a � Q � x R e ƒ 0 7 x / .7 e C o g e # u) 7 0 / mc CI 2 E 0 UU F \ m E CD E O & § CO O ■ a . U U) / < < C) U) • • IISTANDARD WELL PROCEDURE Hilcorp Alaska,LLC NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher.Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Monday, April 10, 2017 11:39 AM To: Monty Myers (mmyers@hilcorp.com) Subject: SRU 241-33 (PTD 217-047) - Request and Questions Monty, Since proposed well SRU 241-33 is a deviated well, please ensure that directional survey data are recorded in accordance with the requirements of 20 AAC 25.050. Will SRU 241-33 penetrate any gas storage reservoirs within the Swanson River Unit? If so, what are the current pressures of those reservoirs? The Planned Wellbore Schematic on page 6 of the Drilling Procedure indicates that cement will be placed across the entire production interval, from TD to surface casing shoe. Page 36 specifies that a cement bond log will be run across the production hole interval. In the event that cement does not cover the entire production interval to the surface casing shoe, what remedial actions will Hilcorp take to ensure that migration of fluids and/or gas does not occur from any reservoir? Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. Davies, Stephen F (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Monday, April 10, 2017 2:13 PM To: Davies, Stephen F (DOA) Subject: RE: SRU 241-33 (PTD 217-047) - Request and Questions Thanks for the questions Steve. Please see responses in red below Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell: 907.538.1168 From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Monday, April 10, 2017 11:39 AM To: Monty Myers <mmyers@hilcorp.com> Subject: SRU 241-33 (PTD 217-047) - Request and Questions Monty, The well will penetrate the 64-5 reservoir and the current pressure gradient is 8.89ppg. Since proposed well SRU 241-33 is a deviated well, please ensure that directional survey data are recorded in accordance with the requirements of 20 AAC 25.050. We will be sure to comply with the regulation and have surveys a minimum of every 100' in accordance with 20 AAC 25.050 (c)(1) Will SRU 241-33 penetrate any gas storage reservoirs within the Swanson River Unit? Yes, we will penetrate the Tyonek 64-5 reservoir at depth 7432' TMD If so, what are the current pressures of those reservoirs? The current pressure is at 8.89 ppg EMW The Planned Wellbore Schematic on page 6 of the Drilling Procedure indicates that cement will be placed across the entire production interval, from TD to surface casing shoe. Page 36 specifies that a cement bond log will be run across the production hole interval. In the event that cement does not cover the entire production interval to the surface casing shoe, what remedial actions will Hilcorp take to ensure that migration of fluids and/or gas does not occur from any reservoir? In the event that bond log shows little or no cement, Hilcorp will perforate and squeeze the interval in question to isolate any migration of fluids. A water activated swell packer will also be placed in the casing string and reside inside the surface shoe at approximately 1500' to isolate the annulus from formation fluids. Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.eov. OF Tk 4'1.*\�y/'� THE STATE Alaska Oil and Gas ofAT ASKA Conservation Commission OM =__ 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 O1"4,LAe*P' Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Tyonek Gas Pool, SRU 241-33 Permit to Drill Number: 217-047 Sundry Number: 317-356 Dear Mr. Helgeson: Enclosed is the approved application for 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, Hollis S. French Chair DATED this 22-day of August, 2017. RBDMS w As'' 2 3 2017 • sscQ „ RECEIVED csL9. STATE OF ALASKA c69AUG 01 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS ' GCC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate 0 Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑✓ ' Other Stimulate 0 Pull Tubing 0 Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool 0 Re-enter Susp Well 0 Alter Casing 0 Other: CT N2 Lift ❑✓ • 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory El Development ❑✓ • 217-047 ' 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic 0 Service 0 6.API Number: Anchorage Alaska 99503 50-133-20663-00 • 7.If perforating: do-7/4, 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O.716.001 ,>?,, Swanson River Unit(SRU)241-33 • Will planned perforations require a spacing exception? Yes ❑ No 11 1-4,t7 9.Property Designation(Lease Number): 10. Field/Pool(s): A028399;A028406 Swanson River-Tyonek Gas 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): 8,630' 7,677' 8,581' 7,628' -4,172 psi N/A N/A Casing Length Size MD TVD Burst Collapse - Structural Conductor 120' 16" 120' 120' Surface 2,005' 7" 2,005' 1,986' 7,240psi 5,410psi Intermediate Production 8,625' 4-1/2" 8,625' 7,672' 8,430psi 7,500psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A;N/A N/A;N/A 12.Attachments: Proposal Summary ❑✓ Wellbore schematic Q 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ❑✓ Exploratory ❑ Stratigraphic ❑ Development 0 • Service 0 14.Estimated Date for 15.Well Status after proposed work: Operations: August 14,2017 CommencingOILWINJWDSPL El 0 0 Suspended ❑ 16.Verbal Approval: Date: GAS ❑✓ • WAG 0 GSTOR 0 SPLUG ❑ Commission Representative: GINJ 0 Op Shutdown ❑ Abandoned 0 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: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer@hilcorp.com Contact Phone: 777-8420 Authorized Signature: eDate: 7/31I/p COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 7 3 C3 6 C.- Plug Integrity 0 BOP f Test Mechanical Integrity Test El Location Clearance 0 Other: j- 4t( ) r s z.: t1 p • f (Cr) Post Initial Injection MIT Req'd? Yes ❑ No ❑ R�DM.S ✓ h } Spacing Exception Required? Yes ❑ No LJ j Subsequent Form Required: ! C�•-L(!� ( A J C lU�^U 7 APPROVED BY Approved by: WQS;--- COMMISSIONER THE COMMISSION Date: o 1'1" I t l- yZ d `r ! l L Suents ibmint Form aatend Form 10-403 Revised 4/2017 Approved appl' ati is v id fpr 12 months from th o aoIl A AttachmDour uplic • • Well Prognosis Well: SRU 241-33 IIilcurp Alaska,LLQ Date:7/28/2017 Well Name: SRU 241-33 API Number: 50-133-20663-00 Current Status: New Grassroots Well Leg: N/A Estimated Start Date: August 14th, 2017 Rig: Coil Unit Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 217-028 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) Second Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (C) AFE Number: 1711425C Maximum Expected BHP: —4,934 psi @ 7,652 TVD (Based 12.4 ppg mud weight to kill the well and the lowest perf to be shot at 8,571' MD. Max. Potential Surface Pressure: —4,172 psi @ 7,652' TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary SRU 241-33 is a grass roots development well targeting gas sands in the Sterling and Tyonek formation. This new well reached TD on 7/18/17 and completed 7/23/17. The purpose of this work/sundry is to jet the well dry with coil tubing, and perforate. Notes Regarding Wellbore Condition • Well is full with 6% KCI. • Slickline tag and make gauge ring run prior to starting work. • E-line will complete CBL prior to starting sundry work. Electronic copy of CBL to be sent to AOGCC when completed. ;f • An MIT-IA(7-5/8" x 4-1/2") will be performed to 2,500 psig for 30 minutes prior to beginning the coil tubing work. P 4i l�IavP� Safety Concerns • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. • Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) • Ensure all crews are aware of their stop job authority Coiled Tubing Procedure (start of Sundry work) 1. MIRU Coiled Tubing, PT BOPE to 4,500 psi Hi 250 Low. Notify AOGCC 24 hrs. in advance of BOP test. If slickline or eline tags cement shallower than 8,610'. Follow steps 2-6&9-11. 2. MU Mill and Motor BHA. 3. RIH and mill cement and cleanout to 8,610' MD. 4. Circulate hole clean with 2 bottoms up, ensure any rubber or cement is free from the hole. 5. RU N2 pumping unit. 6. Drop ball and come online with N2 and jet well dry. • Estimated volume of displaced 6% KCI is 131 bbls. If slickline or eline tags cement deeper than 8,610'. Proceed with steps 7-11. • • Well Prognosis Well: SRU 241-33 Hilcorp Alaska,LL' Date: 7/28/2017 7. RIH w/coiled tubing and jet nozzle BHA and tag PBTD. 8. PU 5ft and displace well fluids with Nitrogen. • Estimated volume of displaced 6% KCI is 131 bbl. 9. Once well is dry,verify desired surface pressure to leave on well with Operations Engineer. 10. POOH w/coil. LD BHA. 11. RD Coiled Tubing. E-Line Procedure 12. MIRU e-line and pressure control equipment. PT lubricator to 4,500 psi Hi 250 Low. Note that the well is pressurized with nitrogen. • If necessary, bleed pressure down as requested by the RE to establish a drawdown on the formation. 13. Perforate the following Tyonek sands with 2-7/8" 6 SPF 60 deg phased perf guns (up to 12 SPF with 2 perf runs) Zone Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Tyonek 65-8 ±7,522' ±7,547' ±6,580' ±6,605' 25 Tyonek 68-0 ±7,734' ±7,872' ±6,790' ±6,926' 138 Tyonek 69-4 ±7,947' ±7,955' ±7,000' ±7,008' 8 Tyonek 73-5 ±8,351' ±8,37 ' ±7,400' ±7,426' 27 Tyonek 75-7 ±8,525' ±8,558' ±7,572' ±7,605' 33 Tyonek 77-3 ±8,571' ±8,605' ±7,618' ±7,652' 34 a. Proposed perfs also shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. d. Use Gamma/CCL to correlate. e. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. f. Conservation Order 716.001 defines the Tyonek Gas Pool as all intervals that correlate with the interval 5,304 reet MD to 10,085 reet MD in the Soldotna Creek Unit 41-4 well.All of the perforations in table above fall within the defined SRU Tyonek Gas Pool, as currently defined. 14. POOH. 15. RD e-line. 16. Turn well over to production. (Test SSV with-in 5 days of stable production on well—notify AOGCC 24hrs before testing) E-line Procedure (Contingency): 1. If any zone produces sand and/or water or needs isolated 2. MIRU E-line, PT lubricator to 3,500 psi Hi 250 Low. 3. RIH and set 4-1/2" CIBP at depth above zone. Or 4. RIH and set 4-1/2" Casing Patch across the zone. Attachments: • • Well Prognosis Well: SRU 241-33 Ilileorp Alaska,LLQ Date: 7/28/2017 1. Actual and Proposed Well Schematics 2. Coil BOPE Schematic coil (Combi BOPs) 3. CT Flow Diagrams (Forward and Reverse Jetting) 4. Wellhead Diagram 5. Blank RWO Change Form 6. Standard Well Procedure—N2 Operations 0 9 Swanson River Unit • CURRENT SCHEMATIC Well SRU #241-33 PTD: 217-047 API: 50-133-20663-00 Hi!carp Alaska,LLC RKB to GL=20' CASING DETAIL 16" 4 4i *1* Size Type Wt Grade Conn. ID Top Btm c Conductor—Driven �'�. , f4t.1 16" 84 X-56 Weld 15.01" Surf 120' T -- ; r ¢ to Set Depth Am , {+ 7" Surf Csg 26 L-80 BTC/M 6.875" Surf 2,005' k ,•'r, r ' 4-1/2" Prod Csg 12.6 L-80 TXP 3.958" Surf 8,625' r[" " " N' , G /en `' / °r`51 .err-1,,,. j� ..'r r 1 1Ob ( ft A/Lb 7" 2005 s�`°�P�.•fi- P.t17 .LL RA@2,817' - A. fi:r. fi RA @ 3,800' ,e -4*,g `y ts:} �a RA @ 6,006' .)- 11‘ ,,111'V41 '7 V..:' 1.1; , A k ,s * t (1 0 ' trIrVi ..s'it 4 a v � A .s.,?a 4 . ' t.' i "e 1" '° RA @ 8,415' q �4 '—414 - OPEN HOLE/CEMENT DETAIL " ;.. 8-1/2"hole.88 BBL(203 sx)of 12 ppg Type I/II Ce BLs(100 sx)15.4 7„ ppg of Class G tail. 100%returns througho ,23 bbls to surface., ` � 4 1'2„ 6-1/8"hole.166 BBL(490 sx)of 12.8 Type I-II Ls(120 sx)15.3 ppg trt . s.0 q ig` y of Class G tail.99%returns throughout,0 bbls to surface. + Fr 1,4,t... 4 w . e r 4-1/2" 'lin'Aibl, t� .r« PBTD=8,581'/PBTVD=7,628' TD=8,630'/TVD=7,677' Updated By DMA 07-28-17 , • • • Swanson River Unit • PROPOSED SCHEMATIC Well SRU #241-33 PTD: 217-047 API: 50-133-20663-00 Hilrarp Alaska,LLC RKBto GL=20' CASING DETAIL 16" 4` ;`ie.- f. ; . r i Size Type Wt Grade Conn. ID Top Btm Conductor-Driven ., '' 16 to Set Depth 84 X-56 Weld 15.01" Surf 120' 7" SurfCsg26 L-80 BTC/M 6.875" Surf 2,005' �. �' } ' 4-1 /2" Prod Csg 12.6 L-80 TXP 3.958" Surf 8,625' r p.1 ,4..., 4,4:111:::: t I fr 7 711 r RA @ 2,817' rvL :,;',1--,,,!--1: ... . -i.::::4. . .. *"" PERFORATION DETAIL RA @ 3,800' ii ,y.<", Sands Top(MD) Btm(MD) Top(TVD) Btm FT Date Status it. ive. (TVD) . t s - 65-8 ±7,522' ±7,547' ±6,581' ±6,605' 15 TBD Proposed RA @ 6,006' :..1:,,4„; 68-0 ±7,734' ±7,872' ±6,790' ±6,926' 138 TBD Proposed , i 69-4 ±7,947' ±7,955' ±7,000' ±7,008' 8 TBD Proposed 3 73-5 ±8,351' ±8,378' ±7,400' ±7,427' 27 TBD Proposed "!. '.":. • 75-7 ±8,525' ±8,558' ±7,573' ±7,606' 33 TBD Proposed TBD Pro 65 8 77-3 ±8,571' ±8,605' ±7,619' ±7,652' 34 p tt 1..0 M. 68-0 .410 firoi �c 69 4 �a *14 t.f,t , .,,, ,,,..., y;1/4,.. . tv a 'h , 73-5 RA @ 8,415' N`nir♦ 5fi rr r4I„...) 75-7 OPEN HOLE/CEMENT DETAIL k 4i`w' 7„ 8-1/2"hole.88 BBL(203 sx)of 12 ppg Type I/II Cement and 22 BBLs(100 sx)15.4 r,' ..--1; 77-3 ppg of Class G tail. 100%returns throughout,23 bbls to surface. "` • r . 4-1/2" 6-1/8"hole.166 BBL(490 sx)of 12.8 Type I-II Cement and 27 BBLs(120 sx)15.3 ppg e7,, . `1. ' of Class G tail.99%returns throughout,0 bbls to surface. 6 4-1/2" 'kta;; ,d _p. ' a« , PBTD=8,581'/PBTVD=7,628' TD=8,630'/TVD=7,677' Updated By DMA 07-28-17 • • • II Swanson River Unit SRU 241-33 07/28/2017 ililnup tlm.l.a.I.I.t. 4111"111 .04 ,414\ t G f� ,: N N M!we-._ua�-�,iamr �M , Coiled Tubing HR580 Injector Head&Gooseneck �_��- -40 ti•70�1Ail U Weight=12,850 lbs i.....0 0 ilriliei E _ yii1- 7 IIIIMMAINIZi • 1 4-1/16"10K Conventional Stripper nil'I 161 MI 4 5K C062 Lubricator Kill Pnrt WH PSI 16 T1502 x 2-1/16 10K Flanged Valve O 41 5K C062 x 4-1/16"10K Flange (Manual) A 2-1/1610Kx2-1/16 ,Ott,-, - 4-1/16"10K Combi BOP 10K flared l)Valve .®..Z. �°'• Top Set:Blind/Shear ._. '•"� Second Set:Pipe/Slip :gym. 40 . .FM'ui i1 4-1/16"10K Flow Cross Manual 2x2 Valve 1:2"1502 x 2-1/16"10K Flange IllO IKONW ONICNIP4111 Manual 2x2 Valve 2:2-1/16"10K x2-1/16"10K Flange Manual 2x2 Valve 3:2-1/16"10K x 2-1/16"10K Flange Manual 2x2 Valve 4:2"1502 x 2-1/16"10K Flange NM I 4-1/16"10K x Wellhead Adapter Flange III 01111111 f,�l1611■ Viliw. 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Y c 0 I-- 1 1 n 0 - I c • O p A V •A O 11 a a It c Il En c rn 12 c '8. 0 E U c1 0411 Z 11 o A t q a i • • Swanson River Unit 41-33 WELLHEAD DRAWING SRU 07/288/201/201 7 /Glmrp Alaska.I.U: Casing hanger,CW,11 x 4% DWC/C box btm x 6.125"RH stub acme box top,w/7 5/8 od neck,4"type H BPV profile,DD-NL material BHTA,Otis,4 1/16 5M FE x 6.5 Otis quick union top I`J4T141711--R47 ( . re t Y .. Alt Valve,Swab,WKM-M is 41/165M FE,HWO, /^^ i :p EE trim ' V . Valve,Wing,WKM-M, 31/SSM FE,HWO, Valve,Wing,SSV,WKM-M, unsay. EE trim 31/85M FE,w/15"Hydraulic operator .15-F.' 3`I lid+) `, ,11 r,� c �: T` Lii - - Valve,Upper master, kiiG WKM-M, 4 1/16 5M FE,HWO,EE trim "U - 17777 urn Valve,Master,WKM-M, - 4 1/16 5M FE,HWO, ,�/ EE trim v 7771 r-srn I. 1 -,. Tubing head,Cactus C-29L- :■��®1 Pia"-•= HPS,135/8 SM x115M,w/ • - 2-2 1/16 5M SSO 3, i. =r_ Starting head,Cactus C-291, _rill! �„� '�' nib. 135/85M x 16 SOW,w/2-2 — - 1/16 5M SSO 1 1 i . _i • I.,,,1 , 5 1 16" L 7 5/8" 4'/_" r i CCD � a) > c v 0 ow V Hca ro � NoQ U U C Q Q.a EO Q E Oo 'f' d N Q 0 m'r _- a) = Q C T Q - L •- C L N Y M -0 _0 Q fC >+.f6 a) = d m O N n E L ._ I.L. .i Q 5 Q. a- CZ L o O• N ..:t LZ O co c O (0 d a>.' CDL Z 0 C U of O L Tr U _c ___ L O 3 a N ° o o o _a L ✓ a o � o > � 2 a M OL M Q r N (13a RS0 � o 0 01 ci �° � Q U a ai U O G1 0 • 'O c d L 0 0 y O — a i 3U asCa) a) a i co cc C 7 CX -a (i) O C W U - da > 0 N G> O > rI cc O a O a 0_ 45Q i .4 4 L Q ca o 0 a 4 `- o c(0 o E 0 X O "x Q ai X F- R m r d +.+ X O 1.13 N L o 0 U o Q it ii v O o To. -6 URO m > a r— a) E Vo oUco v0Qa 23 C.) cu Q i • STANDARD WELL PROCEDURE !Wog) 1ki ka.H.c NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher.Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 • • Hilcorp Alaska, LLC 148curp M.i.ka,LL( Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SRU 241-33 Saxon 169 SLR 169 217-047 6/28/2017 Future 7/22/17-Saturday Cont circulating 4'/:"casing with hanger 2'off seat,while RU and staging cementing equipment.113 gpm-620 psi.Up wt 105K,dwn wt 45K.BGG at 29 units.Loaded plugs in plug launcher,shut down pump and attempt to slack off 2'to land hanger.String would not move.Worked pipe a dozen times at 180K up,12K down while pumping and string came free.Slacked off and landed hanger,shut down pump.Removed topdrive and circ swedge.MU plug launcher and hardlines.Halliburton pumped 10 bbls to cuttings box,then 5 bbls down casing to purge air and flood lines for testing.Halliburton pressure tested lines at 300 low 5000 high,good tests.Halliburton pumped 28 bbls of 12.9 ppg Clean Spacer III at 3 bpm,860 psi and shut down.Halliburton dropped bottom plug and pumped 166 bbls(490 sx)12.8 ppg Type I-II cement at 3 bpm,670 psi,followed with 27 bbls(120 sx)of 15.3 ppg Class G Tail cement at 3 bpm,650 psi. Halliburton dropped top plug,then displaced with 10 bbls fresh water,followed by 120 bbls 3%KCL at 3 bpm,1050 to 3700 psi. Slowed to 2.5 bpm with 10 bbls to go.Started seeing spacer returns 90 bbls into displacement,and cement 117.5 bbls into displacement.Diverted returns to cellar box through annulus valve at first sign of spacer.Bumped the plug(calc=130.44 bbls,actual=130 bbls)and held 4200 psi(FCP 3700 psi at 2.5 bpm)for 3 minutes,bled off and floats held.Bled back 2 bbls to truck.Had 13 bbls of 12.8 ppg cement to surface.WellLife 1094 was added at 1/2 ppb,to both lead and tail.Mix water temp=69 deg.Pumped 50%excess on both lead and tail.Could not reciprocate the string due to differential sticking.Lost 19 bbls throughout the job.Up wt 105K,dwn wt 45K prior to landing hanger.TOC at surface,top of tail at+1-7084'. CIP at 10:32 am,7-22-17. Wait on cement 25 hrs on lead,21 hours on tail prior to testing casing. RD and released mudloggers.RD hardlines and cement manifold.Flush out stack and hanger.Back out landing joint and MU packoff assembly.Land packoff and RILD's.Test packoff at 500 and 5000 psi 5 min each,good tests.LD landing joint.RD casing elevators and long bails.Flush mud pumps,surface lines and Kelly hose with soap water.Blow down surface lines and hoses,remove all subs and rig tongs from rig floor.RD Kelly hose,saver sub,IBOP,service loop.RD and LD topdrive.Haul off 450 bbls mud to Tyler Pad for workover rig. Haul mud to G&I.Clean pits.Shipped Weatherford casing equipment.Cont.W.O.C.Clean derrick,roughneck,&rig. R/D top drive HPU.Remove swabs, liners&valve seats from mud pumps.Cont.W.O.C.R/D floor equipment,stand pipe&iron roughneck.Clean cat walk.R/D mud loggers shack.R/D gen 3. R/D misc ground tools&equipment. 7/23/17-Sunday Cont to clean pits,suction lines and rig while waiting on cement for casing test.RU chart recorder and test hoses.Fill kill line with water and puree air from ram cavities.Close blinds,pressure up and test 4 1/2"casing at 3500 psi for 30 minutes on chart.Good test.Bled off and RD test equipment.Set BPV.ND flow line,flow riser and drip pan.Remove kill and choke lines.Open doors and remove ram bodies.Pressure wash ram cavities and close up.Remove stack from wellhead and trolly to end of sub.Set dry hole tree in cellar,NU same.Pull BPV and install 2 way check.RU and test hanger void at 250-5000 psi for 10 minutes each,then tested tree at 250-5000 psi for 10 minutes each.Good tests.Pull two way check and secure tree/well.Cont cleaning under rig floor around rotary beams,cont prep vaccum degasser for removal. Rig Released at 18:00 hrs on 7-23-17 R/D gas buster.Clean out Rotary table.Clean sub base&cellar.Cont.to clean around rig.Prep 3rd party shacks for move.Slip&cut 35'drill line.Prep derrick&scope down.Unspool drill line.R/D pits& pumps.Prep derrick to lay over.Cont.cleaning rig&pad. 7/24/17- Monday Cont cleaning under sub base,RD koomey lines,disconnect shaker#2 electrical for change out,disconnect pit module#2 roof electrical for removal,pull bladders from pulsation dampeners,spool up various cords and hoses,ship mud products back to Nikiski,Total Safety RD all gas detection equipment. Received verbal approval to prep and move to Pad 12-27 at 12:40.Removed valve seats from pump#1(took some doing).HSE Rep John Coston stopped by for a visit.No issues.Cont.to remove bladders from pulsation dampeners on pumps.Remove shakers from pits.R/D centrifuge.R/D boilers.R/D pason lines&electrical lines.Prep modules for trucks.Cont.to clean rig&prepping for rig move&cold stack. 7/25/17-Tuesday Lay felt and liner on SRU 12-27 to receive SLR 169 for cold stack.Lay out rig mats.Cont to clean rig,rig down electrical lines to carrier.Lower dog house. Remove light off of pit modules,pump modules,dog house,and choke house.Moly mist pump seats,disconnect power lines to choke house.Pressure wash and clean crown section of derrick.RD derrick board.Pressure wash and clean cellar box.Haul rig matts to next location.Shipped 400 bbl upright tank,excess casing,hurricane vac's,Canrig shack and Sperry shack.Weatherproof electric cord ends.No activity on rig. All crews working Daylight tour. • • Hilcorp Alaska, LLC i,ilourpAlaska,1.IA: Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SRU 241-33 Saxon 169 SLR 169 217-047 6/28/2017 Future Daily Operations: 7/19/17-Wednesday Cont LD directional BHA,held PJSM and removed RA sources,plug in and upload MWD data,cont LD BHA.Bit graded at 2-1 and was in gauge.Hole taking 1 bph static loss.Clean and clear rig floor,drain BOP stack,PU test jnt and pull wear ring.Set test plug and RU test equipment.Flood surface lines and stack then purged air.Shell test stack(OK).Test all BOPE at 250 low,3500 high(250/2500 on annular)with 3 BLM Reps as witness.Witness waived by AOGCC Rep Jim Regg on 7-18-17.Had one fail/pass on inside manual kill valve.Blow down,re-align valves,RD test equipment.Pulled test plug,set wear ring.MU 6 1/8"cleanout BHA(roller cone,bit sub and NM flex DC's),HWDP,jars and HWDP to 375.5'. Cont TIH on 4 1/2"DP from 375'to 1992'Fill pipe&circ B/U, 117 gpm,200 psi,max gas 28 units Slip&cut 122'drill line.Cont.to RIH with clean out BHA from 1992'to 3793',(no issues)Fill pipe&circ&cond mud to 12.4 ppg In/Out,117 gpm,440 psi,549 max gas units,Lightest mud wt observed 12.2 ppg Cont.to RIH with clean out BHA from 3793'to 5723'(no issues) Fill pipe&circ&cond mud to 12.4 ppg In/Out,117 gpm,564 psi,1626 max gas units,Lightest mud wt observed 12.2 ppg Cont.to RIH with clean out BHA from 5723'to 7531'(no issues up to 6526,then few minor tight spots,picked up&work thru once with no problem)Disp Calc=52 bbls/Act=48 bbls Fill pipe&circ&cond mud to 12.4 ppg In/Out,117 gpm,1000 psi. 7/20/17-Thursday Cont circulating at 7531'.117 gpm-865 psi,50 rpm-8319 ft/lbs off bott torque.Had a max of 1567 units at bottoms up.Did one full circ to get good 12.4 ppg all the way around.Cont TIH on elevators from 7531'to 8589'with no issue.MU topdrive.Filled pipe,started rotation and washed down from 8589' to bottom at 8630'.Had+/-17'of fill.Circ at 113 gpm-906 psi,50 rpm-10,500 ft/lbs off bott torque.Had a max of 1090 units gas at bottoms up.After bottoms up pumped a 20 bbl hi-vis nutplug sweep around with no increase in cuttings.Also added 1 drum Drill-n-Slide to suction pit and spotted that outside drill string.Obtained SPR's.Pulled up hole slowly,6 stands with no problem.Up wt 185K.Hole fill looks good.Flow check=fluid dropped 3'in 5 minutes.Pulled and racked back 5 more stands with no problem to 7966'.Cont to POOH LD 4 1/2"DP from 7966'to 4450'.Hole fill thus far:calculated 26 bbls,actual 34 bbls.Cont POOH LD 4 1/2"DP from 4450'to 1977'F/C(fluid level dropping).Clean&clear floor.Prep for for E-Line R/U E-Line&Gyro Data tools.RIH with Gyro to 1000'.POOH collecting surveys every 100'.R/D E-Line&Gyro Data.Cont.to POOH&L/D drill pipe from 1977'to 375'RIH remaining 20 stands in derrick from 375'to 1619'POOH&L/D drill pipe from 1619'to 375'.L/D HWDP,Jars&clean out BHA. 7/21/17-Friday Cont to POOH LD remaining BHA,bit sub and bit.Bit grade=1-1 Clean and clear rig floor,drained stack and retrieved wear ring,dummy ran 4 1/2"x 10 3/4"casing hanger/landing jnt,C/O to long bails,hung casing elevators and tongs,RU fill up line.Staged centralizers,staged Peak trailer with casing and load pipe rack,stage circ swedges.Replaced pipe skate cable while RU for casing run.Held PJSM with rig team and Weatherford casing crews.MU shoe track assembly(single jnt shoe track),fill pipe and check float equipment(ok),cont PU and single in hole with 4 1/2"12.6#L-80 TXP casing to 2000'(79 jnts).MU circ swedge and topdrive.Perform one full circ at 113 gpm-150 psi and had a max of 556 units gas at bottoms up.Shut down and remove topdrive/circ swedge.Cont to PU single in hole from 2000'to 2980'and had to work through tight spot(coal seam and just starting through a slide section).MU circ swedge and topdrive.Circ at 113 gpm-232 psi,replace 1/2"bolt on topdrive dogbone pin bracket.Had a max of 579 units gas at bottoms up.Shut down pump and removed topdrive and circ swedge.Cont to PU single in hole from 2980'to 4332'.MU topdrive and circ swedge.Calculated displacement=21 bbls,actual displacement=17.5 bbls (3.5 bbls lost)Circ at 113 gpm-350 psi.Had a max of 922 units gas at bottoms up.Shut down pump and removed topdrive and circ swedge.Replaced grabber dies on topdrive.Cont to run 4 1/2"TXP from 4332'to 6458'Circ at 113 gpm-607 psi.Had a max of 1100 units gas at bottoms up Cont to run 4 1/2"TXP from 6458'to 7288'.M/U swell packer&attempt to RIH,started taking wt once swell packer entered 7"casing top.POOH&double check od of swell packer.OD=6.43".L/D swell packer Cont to run 4 1/2"TXP from 7288'&land on hanger @ 8625.34'(Disp Calc=42.4 bbls/Act=38.1 bbls)No issues running casing Circ&cond mud for cement job.113 gpm-650 psi.Had a max of 975 units gas at bottoms up.HES on location @ 430 hrs.Spot truck into position&start rigging up for cement job. • • Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Tuesday,August 22,2017 10:56 AM To: Donna Ambruz Cc: Ted Kramer;Chad Helgeson Subject: RE:Sundry Cancellation/Withdraw- SRU 241-33 completion sundry 317-356(PTD 217-047) Donna, AOGCC will withdraw sundry 317-356 as requested. MIT-IA failed so major change to the scope of work was needed. 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.gov). From: Donna Ambruz[mailto:dambruz@hilcorp.com] Sent:Tuesday,August 22,2017 10:22 AM To:Schwartz,Guy L(DOA)<guy.schwartz@alaska.gov> Cc:Ted Kramer<tkramer@hilcorp.com>; Chad Helgeson<chelgeson@hilcorp.com> Subject:Sundry Cancellation/Withdraw-SRU 241-33 completion sundry 317-356(PTD 217-047) Guy, Please withdraw the above mentioned sundry(submitted 10-403 sundry on 08/01/17 to AOGCC; however,they did not approve sundry 317-356). Thank you. `.Datura amfo cvz Operations/Regulatory Tech Kenai Asset Team Hilcorp Alaska, LLC 3800 Centerpoint Drive,Suite 1400 Anchorage,AK 99503 907.777.8305-Direct 907.777.8310-Fax dambruz(a7hilcorp.com From:Ted Kramer Sent:Tuesday,August 22,2017 9:58 AM 1 i To: Donna Ambruz<dambruz@hilcorp.com> Subject: FW:SRU 241-33 completion sundry status.(PTD 217-047) Donna, We will want to withdraw this Sundry. From:Schwartz,Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent:Tuesday,August 22,2017 8:34 AM To:Ted Kramer<tkramer@hilcorp.com> Cc:Chad Helgeson<chelgeson@hilcorp.com> Subject:SRU 241-33 completion sundry status.(PTD 217-047) Ted, Have you come up with a new completion plan for well as the IA will not pressure test? You may want to withdraw the current sundry(317-356). 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.gov). 2 i i Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Wednesday,August 09, 2017 9:21 AM To: Chad Helgeson Subject: RE:SRU 241-33 Sounds good. / vt Guy Schwartz JA-.J. 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.gov). From:Chad Helgeson [mailto:chelgeson@hilcorp.com] Sent:Tuesday,August 08,2017 4:25 PM To:Schwartz,Guy L(DOA)<guy.schwartz@alaska.gov> Subject:SRU 241-33 Our team got a little behind on other work in Swanson today and can't get to the MIT until tonight on the annulus for 2136-15. I should hopefully have that MIT for you tomorrow and then we can discuss tomorrow. Chad 1 OFT • • , y0"�� lyy�... THE STATE Alaska Oil and Gas F ;,-s a 14 4AT /\ SKA. Conservation Commission ..iti 333 West Seventh Avenue Ill..- - Anchorage, Alaska 99501-3572 ^M GOVERNOR BILL WALKER g O Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Monty Myers Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Sterling/Upper Beluga Gas and Tyonek Gas Pools, SRU 241-33 Hilcorp Alaska, LLC Permit to Drill Number: 217-047 Surface Location: 502' FNL, 2147' FWL, SEC. 33, T8N, R9W, SM, AK Bottomhole Location: 858' FNL, 184' FWL, SEC. 34, T8N, R9W, SM, AK Dear Mr. Myers: Enclosed is the approved application for permit to drill the above referenced development 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, aiet Cathy P. oerster Chair dix— DATED this // day of April, 2017. RECEIVED STATE OF ALASKA APR0 " 2017 AL OIL AND GAS CONSERVATION COMM ON PERMIT TO DRILL A OGCC 20 AAC 25.005 la.Type of Work: 1 b.Proposed Well Class: Exploratory-Gas ❑ Service- WAG ❑ Service-Disp ❑ 1 c.Specify if well is proposed for: Drill 2 • Lateral ❑ Stratigraphic Test ❑ Development-Oil 0 Service- Winj 0 Single Zone 0 Coalbed Gas 0 Gas Hydrates 0 Redrill 0 Reentry 0 Exploratory-Oil 0 Development-Gas 0• Service-Supply 0 Multiple Zone El - _Geothermal 0 Shale Gas 0 2.Operator Name: 5. Bond: Blanket Q - Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC Bond No. 022035244 - SRU 241-33- 3.Address: 6.Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 MD: 9,100' • TVD: 8,115' ' Swanson River Field 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Sterling/Upper Beluga Gas Pool Surface: 502'FNL,2147'FWL,Sec 33,T8N, R9W,SM,AK(proposed) (SHL,TPH)A028399(BHL)A028406 ' Tyonek Gas Pool Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 821'FNL,308'FEL,Sec 33,T8N,R9W,SM,AK N/A 5/5/2017 Total Depth: 9.Acres in Property: • 14.Distance to Nearest Property: 858'FNL, 184'FWL,Sec 34,T8N,R9W,SM,AK A028399-1760,A028406-2400 3651'to nearest unit boundary • 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL(ft): 205.3 ' 15.Distance to Nearest Well Open Surface: x-344552• y- 2465973. Zone-4 GL Elevation above MSL(ft): 187.3 • to Same Pool: 2342'to SRU 34-28 • 16.Deviated wells: Kickoff depth: ISE '" feett, 717.Maximum Potential Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: v3 degrees Downhole: 3652 Surface: 2840' 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) Cond 16" 84# X-52 Weld 120' Surface Surface 120' 120' Driven(proposed) 8-1/2" 7" 26# L-80 DWC/C 2,000' Surface Surface 2,000' 1,976' 583 ft3 6-1/8" 4-1/2" 12.6# L-80 DWC/C 9,100' Surface Surface 9,100' 8,115' 1063.5 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): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): 20. Attachments: Property Plat Q BOP Sketch Q Drilling Program Q Time v.Depth Plot Q Shallow Hazard Analysis Diverter Sketch Q Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050 requirements Q 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Monty Myers Email mmyerse,hilcorp.com Printed Name Monty Myers Title Drilling Engineer Signature ` Phone 777-8431 1 Date 7 . 6 . ' Commission Use Only Permit to Drill API Number: Permit Approval /II See cover letter for other Number: 2/7-"�V 7 50- /53-2.-06Z3-6C-)s-c2Y'y Date: 1 I I?'11 requirements. Conditions of approval: If box is checked,,�well may-ynn'oott be used to explore for,test,or produce coalbed methane gas hydrates,or gas contained in shales: [ Other: }�• 3 5 c.) ,CISc.. f 5C3i /e�t Samples req'd: Yes 0 No Dr, Mud log req'd:Yes 0 No Z� O H25 measures: Yes 0 No Lid Directional svy req'd:Yes[r No❑ L Spacing exception req'd: Yes 0 No L✓ Inclination-only svy req'd:Yes 0 No[1/ 11 /T ti- (,) ,, e,Sl 2-0(AA L �, c: 3S C ice,Jl f z-\ Post initial injection MIT req'd:Yes 0 No❑ h/i J 47 APPROVED BY Approved by:64eCOMMISSIONER THE COMMISSION Date: I. -1 `?—/7 106-17- Submit Form and Form 10-401 (Revised 11/2015) ,it Ii fo 24 months rom the date of approval(20 AAC 25.005(g)) Att c m nts in guklicate • • Hilcorp Alaska, LLC P.O. Box 244027 Monty Myers Anchorage,AK 99524-4027 Drilling Engineer Tel 907 777 8431 Email mmyers@hilcorp.com Hilcorp Energy Company 4/6/2017 ECEIVEDCommissioner Alaska Oil &Gas Conservation Commission APR 0 7 2017 333 W. 7th Avenue Anchorage, Alaska 99501 lC C Re: SRU 241-33 Dear Commissioner, Attached is the application for permit to drill of SRU 241-33. SRU 241-33 is an S-shaped directional grassroots development well to be drilled off of the SRU 21-33 pad. Subsurface modeling and seismic interpretation, along with production data, indicates that there is remaining gas reserves stranded in the Sterling and Tyonek sands. This well will be targeting PUD reserves in the Sterling sands. These existing reserves are not recoverable in existing wellbores due to - lack of take points or mechanical condition of other existing wellbores. Drilling operations are expected to commence approximately May 5th, 2017. The Saxon Rig# 169 will be used to drill the wellbore then run casing and cement. 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 1 S Hilcorp Alaska, LLC SRU 241-33 Drilling Program Swanson River Field --gip rte ' d by: l ' r My Version 0 April 4t'', 2017 • • SRU 241-33 Drilling Procedure Hilcorp Energy Company Contents 1.0 Well Summary 2 2.0 Management of Change Information 3 3.0 Tubular Program: 4 4.0 Drill Pipe Information: 4 5.0 Internal Reporting Requirements 5 6.0 Planned Wellbore Schematic 6 7.0 Drilling/Completion Summary 7 8.0 Mandatory Regulatory Compliance/Notifications 8 9.0 R/U and Preparatory Work 11. 10.0 N/U 16" Conductor Riser 12 11.0 Drill 8-1/2"Hole Section 13 12.0 Run 7" Surface Casing 18 13.0 Cement 7" Surface Casing 20 14.0 BOP N/U and Test 24 15.0 Drill 6-1/8"Hole Section 25 16.0 Run 4-1/2"Production Casing 30 17.0 Cement 4-1/2"Production Casing 33 18.0 RDMO 36 19.0 BOP Schematic 37 20.0 Wellhead Schematic 38 21.0 Days Vs Depth 39 22.0 Geo-Prog 40 23.0 Anticipated Drilling Hazards 41 24.0 Saxon Rig 169 Layout 43 25.0 FIT Procedure 44 26.0 Choke Manifold Schematic 45 27.0 Casing Design Information 46 28.0 6-1/8"Hole Section MASP 47 29.0 Spider Plot(NAD 27) (Governmental Sections) 48 30.0 Surface Plat(As Staked) (NAD 27) 49 31.0 Surface Plat(As Staked) (NAD 83) 50 S SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 1.0 Well Summary Well SRU 241-33 Pad&Old Well Designation SRU 241-33 is a grass roots well on SRU Pad 21-33 Planned Completion Type 4-1/2"Production tubing Target Reservoir(s) Tyonek/Sterling ' Planned Well TD,MD/TVD 9,100 MD/8,115' TVD PBTD,MD/TVD 9,000' MD/8,017' TVD Surface Location(Governmental) 502' FNL,2147' FWL, Sec 33,T8N,R9W, SM,AK Surface Location(NAD 27)• X=344552.451,Y=2465973.085 Surface Location(NAD 83) X=1484575.382,Y=2465734.46 Top of Productive Horizon (Governmental) 821' FNL, 308' FEL, Sec 33, T8N,R9W, SM,AK TPH Location(NAD 27) X=347373.530,Y=2465624.6 TPH Location(NAD 83) X=1487396.531,Y=2465385.885 BHL(Governmental) 858' FNL, 184' FWL, Sec 34, T8N,R9W, SM,AK BHL(NAD 27) X=347864.31,Y=2465581.08 BHL(NAD 83) X=1487887.324,Y=2465342.35 AFE Number 1711425D AFE Drilling Days 4 MOB, 16 DRLG AFE Completion Days AFE Drilling Amount $2,397,840 AFE Completion Amount Maximum Anticipated Pressure (Surface) 2840 psi (Drilling) Maximum Anticipated Pressure ✓ (Downhole/Reservoir) 3652 psi • Work String 4-1/2" 16.6# S-135 CDS-40(Saxon Owned String) RKB—GL 205.33' • Ground Elevation 187.33' ' BOP Equipment 11" 5M Townsend Annular BOP 11" 5M Townsend Double Ram 11" 5M Townsend Single Ram Page 2 Version 0 April, 2017 • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 2.0 Management of Change Information g Hilcorp Alaska, LLC FARE,CilatiaSi Hilcorp Changes to Approved Permit to Drill Date: 4-4-2017 Subject: Changes to Approved Permit to Drill for SRU 241-33 File#: SRU 241-33 Drilling Program Any modifications to SRU 241-33 Drilling Program will be documented and approved below. Changes to an approved APD will be approved in advance by the AOGCC and BLM. Sec Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Version 0 April, 2017 s • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 3.0 Tubular Program: Hole OD (in) ID (in) Drift Conn Wt Grade Conn Burst Collapse Tension ection 0- /ft) sw (ssi) (k-lbs) Cond 16" 15" - - 84 X-52 Weld 8-1/2" 7" 6.276" 6.151" 7.875" 26 L-80 DWC/C 7240 5410 604 6-1/8" 4-1/2" 3.958" 3.833" 5.0" 12.6 L-80 DWC/C 8430'' 7500 288 4.0 Drill Pipe Information: e. OD (in) ID (in) TJ ID TJ OD Wt Grade Conn Burst Co.. '"Tension Section (in) (in) (#/ft) (psi) (psi) (k-lbs) All 4-1/2" 3.826 2.6875" 5.25" 16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Version 0 April,2017 • • SRU 241-33 Drilling Procedure Rev Hilcorp Energy Company 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • 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. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a username to login with. 5.4 EHS Incident Reporting • 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: 0: (907)777-6726 C: (907)227-3189 b. Matt Hogge: 0: (907) 777-8418 C: (907)227-9829 2. Spills: Keegan Fleming: 0:907-777-8477 C:907-350-9439 • Notify Drlg Manager 1. Paul Mazzolini: 0: 907-777-8369 C: 907-317-1275 • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final"As-Run"Casing tally to mmyers@hilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cmt report • Send casing and cement report for each string of casing to mmyers@hilcorp.com and cdinger@hilcorp.com Page 5 Version 0 April, 2017 • • SRU 241-33 , n Drilling Procedure Rev 0 Hilcorp Energy Company 6.0 Planned Wellbore Schematic Swanson River Unit PROPOSED WeII SRU#241-33 PTD: 000-000 API: 50-000-00000-00 CASING r r DETAIL 16" ,. Size Type Wt Grade Conn. ID Top Btm Mud Weight Conductor } 16" —Driven 84 X52 Weld 14" Surf 120' to Set Depth _ 7" Surf Csg 26 L-80 DWC/C 6.276" Surf 2,000'. 8.8 ppg ' *` 4-1/2" Prod Csg 12.6 L-80 DHT/C 3.958" Surf 9,100' 9.0 ppg x, 1 ' u.:L1 ,2:4 i✓ Drilling Info l Hole Section Casing MW Workstring / �' 8-1/2" 7" 8.8 ppg 4-1/2" •.i. ✓ IC, 6-1/ 8" 4-1/2" 9.0-10.0 ppg 4-1/2" 1_ :;. .r; 1.10 JEWELRY DETAIL No. Depth ID OD Item 1 1,500' 3.958" 6.875" Baker Swell Packer s 6-1/8" •�`;,* ..". Hole ^ � � C,6('' rel V .,-.,,,: 24, +t 4-1 2" -� PBTD=9.000'I PBTV'D=8,017' TD=9,100'/TVD=8,115' Page 6 Version 0 April, 2017 • • 14SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 7.0 Drilling / Completion Summary SRU 241-33 is an S-shaped directional grassroots development well to be drilled off of the SRU 21-33 pad. - Subsurface modeling and seismic interpretation, along with production data,indicates that there is remaining gas reserves stranded in the Sterling and Tyonek sands. This well will be targeting PUD reserves in the Sterling sands. These existing reserves are not recoverable in existing wellbores due to lack of take points or mechanical condition of other existing wellbores. Drilling operations are expected to commence approximately May 5th, 2017. • The Saxon Rig# 169 will be used to drill the wellbore then run casing and cement. • cit-4Surface casing will be run to 2,000 MD / 1,977' TVD and cemented to surface to ensure protection of any shallow freshwater resources. No freshwater aquifers appear below 1700' in the Swanson River Unit as per - pe -''40 CFR 147.102(b) (1) (i). Cement returns to surface will confirm TOC at surface:/If cmt returns to surface 4i. are not observed,a Temp log will be run between 6— 18 hrs after CIP to determine TOC. Necessary remedial 1 ft, k,„ action will then be discussed with AOGCC and BLM authorities. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal/beneficial reuse depending on test results. General sequence of operations: 1. MOB Saxon Rig# 169 to well site ✓ 2. N/U conductor riser. (No diverter, diverter waiver requested) 3. Drill 8-1/2"hole to 2000' MD. Run and cmt 7" surface casing. 4. ND conductor riser,N/U &test 11"x 5M Townsend BOP. 5. Drill 6-1/8"hole section to 9,100' MD. Perform Wiper trip. • 6. POOH laying down drill pipe. 7. Run and cmt 4-1/2"production casing. 8. N/D BOP,N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: 1. Surface hole: GR+Res. • 2. Production Hole: GR+Res. • 3. Mud loggers from surface casing point to TD. • Page 7 Version 0 April, 2017 • • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 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 SRU 241-33. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. BLM requires 48 hrs notice prior to testing. • The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 10/10 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 approved drilling permit and BLM sundry are posted on the rig floor and in Co Man office. Regulation Variance Requests: • Diverter waiver requested due to the recent drilling of SRU 213-15 and SRU 213B-15 on a nearby pad. No issues were experienced while drilling the surface hole. Surface casing for SRU 213-15 was set at 2250' TVD. Surface casing is requested to be set at 1,977' TVD on SRU 241-33. No shallow hydrocarbon zones will be penetrated. 0 h- • Onshore Oil and Gas Order No. 1, Section III. D. 3. C. stn o Hilcorp requests approval to install a 3-1/8" 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. Page 8 Version 0 April,2017 • • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 8-1/2" • No diverter utilized n/a • 11"x 5M Townsend Annular BOP • 11"x 5M Townsend Double Ram Initial Test:250/3500 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross 6-3/4" • 11"x 5M Townsend Energy Single Ram • 3-1/8"5M Choke Line Subsequent Tests: • 2-1/16"x 5M Kill line 250/3500 • 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 11 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 cmt 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 and Sundry. Page 9 Version 0 April,2017 int • • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email:jim.regg@alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-301-4533 /Email: guy.schwartz@alaska.gov Victoria Loepp/Petroleum Engineer/(0): 907-793-1247/Email: victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone: 907-793-1236 (During normal Business Hours) Notification/Emergency Phone: 907-659-2714 (Outside normal Business Hours) 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@b1m.gov Use the below email address for BOP notifications to the BLM: BLM AK AKSO_EnergySection Notifications(aiblm.gov Page 10 Version 0 April, 2017 • • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 9.0 R/U and Preparatory Work 9.1 Set 16" conductor at+/-120' below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install Seaboard slip-on 16-3/4" 3M"A" section. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 51-12 161 9.6 R/U Saxon Rig# 169, spot service company shacks, spot&R/U company man & toolpusher offices. 9.7 Mud loggers not required on surface hole section. . 9.8 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.9 Mix mud for 8-1/2"hole section. 9.10 Install 5-1/2" liners in mud pumps. • HHF 1000 mud pumps are rated at 3036 psi (85%) /339 gpm (100%) with 5-1/2"liners. Page 11 Version 0 April, 2017 I • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 10.0 N/U 16" Conductor Riser 10.1 N/U 16" Conductor Riser • Ensure line does not direct flow from trip tank straight down the flowline. Fill up line and flowline should be oriented 90 degrees to each other at approx. the same height. • Ensure flowline outlet installed so that enough slope exists to carry cuttings to the shakers. • Consider adding additional drainage points at the bottom of the conductor riser if deemed necessary. • R/U fill up line to conductor riser. 10.2 Set wearbushing in wellhead. Diver (� '` )2"1"4-' (l)(z) Page 12 Version 0 April,2017 • S SRU 241-33 H Drilling Procedure Rev 0 Hilcorp Energy Company 10.3 Rig Orientation on SRU 21-33 pad: 61611 . $ 4 1 . 4:.‹.***:°..:4 kelc.: 4:4444‘4a7 ' .ir 41: iittZ.,...11...4, 0. lf 1, ., . .. . . ..".....,,, lir:1k. . - .14? ..,:t...40: ...t - - A-,.., Ai 411k f' • Nip�4 ...... i„ .. „ .. .• . .`r♦ ! I t i ,. , . _.,,,,-:,- -, , ..„-...... ....,_ ..„ , -.:Ve."tr! l'tom. r,, _ ,,,,,,vie.„4::,:t.fr" *4 uct4on Fac+ii y .a � x � te., . 1 pt,. .. . ' • w +. , : it 4r.,,, - -.it . 40^ a .. .v b ii .••: I. April, 2017 Page 13 Version 0 • SRU 241-33 ut Drilling Procedure Rev 0 Hilcorp Energy Company 11.0 Drill 8-1/2" Hole Section 11.1 P/U 8-1/2" directional drilling assy: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 4.5" 16.6# S-135 CDS40 11.2 8-1/2" BHA (GR and Res LWD are included in below BHA): ' COMPONENT DATA Item OD ID Gauge Weight Top Length Cumulative Description Serial Number ti (In) (In) (in) ithPf) Connection (It) Length tit) 1111 8.5'PDC V513GH 5.900 3.000 8.500 69.08 P 4-112"REG 0.81 0.81 ® 7"SperryDril Lobe 718-7.5 stg 7.00011323111111111 ELM L 31.53 32.34 © Float Sub 6.750 2.500 105.23 B 4-112"IF 2/5 35.09 Ell 6 314'DM(Directional) 6.750 ®... 103.40 In= 9.20 ® 6 314"DGR(Gamma) . 6.750 1.920 97.80 B 4-112"IF 6A0 50.69 0 6 314"EWR-P4(Resisliwity) . 6.750 2.000 ® 104.30 IMMO 12.10 62.79 © 6 314"HCIM(Processor) 6.750 1.920 101.70 B 4-1/2"IF 6.80 69.59 1011 6 314"TM(Telemetry) ® 6.900 3.250 ® 103.60 10.00 MEM 0 6-314"Fiex Collar 6.750 2.875 99.83 B 4-112"IF 30.00 109.59 10 6-3/4"Flex Collar - 6.750 am_Ea B 4-112"IF 30.00 MUM ® 6-314"Flex Collar 6150 2.875 99.83 B 4-112"IF 30.00 169.59 ® 1111111111 ® 30.00 6-314"flex Cellar 6.750 MEM ® 4-112"IF P x CDS-40 Box 6.350 2.625 89.48 B 4.5"CDS40 2.75 202.34 • 2)ts 4-112"CDS-4O HWWDP ® 4.500 2.813 36.86 60.00 262.34 El CDS-40 P x 4-117'IF Box 6.550 2.685 95.54 6 4-112"IF 2.75 265.09 Sal 625"Weatherford Jar mininiai2.250 NEE 90.57 32.00 297.09 wa 4-1/2"IF P x CDS-40 Box 6.190 2.685 63.26 B 4.5"CDS40 2.75 299.84 Km 15)ts 4-112"COS-44 HWDP ® 4.500 2.813 36.86 111111111 450.00 749.84 Total. 749.84 Page 14 Version 0 April, 2017 • •• SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 11.3 Primary Bit: ` 8 1/2" (215.9mm)-.i —=.. ' Assembly: A09879 V711 PDG1�� voyager ,..r. iPRODUCT SPECIFICATIONS \\� N 41:• • , Cutter Size: 11 mm Cutter Back Up: 11 mm PDC&Diamond Shock Studs Total Cutter Count: 103 • rr"rt 3 0 .,,� Face Cutter Count: 75 ‘, t, Connection: 4 1/2" API Regular ,; Nozzle 1 Qty/Type: 8-Series 55 " Nozzle 2 Qty/Type: - Junk Slot Area: 13.2in2(85.2cm2) Gage Pad Length: 0 3/4"FG+O 3/4"UG(19mmFG+l9mmUG) • • Make Up Length: 9.1" (231.6mm) ' Shank Diameter: 5.9"(149.9mm) 4.•sp„,., i' OPERATING PARAMETERS` • 4• �Ns� 1Rotary Speed: For all rotary and motor applications '44 {., ,3 31 Flowrate Min-Max: 250-750GPM(0.95-2.84m3/min) Max Weight On Bit: 450001bs(20017daN) Makeup Torque: 12000-16000Ft-Lbs.(16270-21693Nm) -Operating parameters once are typcas tar the bit type specAAec For recommendations on your spectc apphoatroncontact et” :'o'ei International representa'wo Voyager Series Bits-Voyager series bits utilize Varel's proprietary design.modeling,and programming software coupled with specialized manufacturing techniques to create the optimal drill bit for your fit-for-purpose applications. Engineered though Varel Simulator Suite for specific directional applications.Voyager bits incorporate the latest design features to maximize cuttings removal.enhance ROP potential,improve directional response.and create a more durable bit frame to aid in accomplishing your aggressive directional drilling objectives. Bit Features P__-PowerCutterst" provide extra cutter density on the shoulder reducing excessive wear or cutting structure damage when drilling interbedded formations. _D_-Drop in cutter in gage pad. _pi_-Premium Stepped Gage pad set with TSP.Designed for use with conventional rotary,PDM.or RSS drilling assemblies.The gage pad design is both Full gage and Undercut and is specifically engineered for the application. _H_-Increased number of nozzles for improved bit cleaning. _R_-Diamond shock studs limit drill bit vibration and increase stability allowing smooth cutting action. This increases cutter life and overall bit performance. U -PDC cutters strategically placed to help reduce hole problems when up drilling or back reaming. VAR EL www.varelintl.com n v'1 L.'a NA l' u N n l_ Page 15 Version 0 April, 2017 i • • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 11.4 41/- 2 Workstring rkstrin &HWDP will come from Saxon. Jars will come from Weatherford. 11.5 Begin drilling out from 16" conductor at reduced flow rates to avoid broaching the conductor. 11.6 Drill 8-1/2"hole section to 2,000' MD/ 1,977' TVD. Confirm this setting depth with the geologist and drilling engineer while drilling the well. • • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be - provided by Hilcorp Geo team. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. • Take MWD surveys every stand drilled (60' intervals). • 11.7 8-1/2"hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on / location to weight up the active system (1)ppg above highest anticipated MW. We will start with a simple gel+FW spud mud at 8.8 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 8.8—9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud ✓/ Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-2000' ' 8.8—9.5 M 85-150 20-40 25-45 <10 8.5-9.0 Page 16 Version 0 April,2017 S SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company System Formulation: Aquagel + FW spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 12-15 ppb caustic soda 0.1 ppb (9 pH) BARAZAN D+ as needed BAROID 41 as required for weight PAC-L/DEXTRID LT if required for<12 FL ALDACIDE G 0.1 ppb X-TEND II 0.02 ppb 11.8 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16" conductor shoe. 11.9 TOH with the drilling assy, handle BHA as appropriate. 11.10 No open hole logs are planned for the 8-1/2"hole section. Page 17 Version 0 April, 2017 SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 12.0 Run 7" Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 7" casing running equipment. • Ensure 7" BTC x CDS 40 XO on rig floor and M/U to FOSV. • R/U fill-up line to fill casing while running. • Ensure all casing has been drifted on the location prior to running. • Be sure to count the total # of joints on the location 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. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U&thread locking shoe track assy consisting of: • (1) Shoe joint w/float shoe bucked on (thread locked). • (1) Joint with coupling thread locked. • (1) Joint with float collar bucked on pin end &thread locked. • Ensure proper operation of float equipment. 12.5 Continue running 7" surface casing • Fill casing while running using fill up line on rig floor. • Use "API Modified"thread compound. Dope pin end only w/paint brush. • Install (1) solid body centralizer(hydroform) every other joint to 300'. Do not run any centralizers above 300' in the event a top out job is needed. • Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 18 Version 0 April, 2017 • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company Technical Specifications Connection Type: Size(O.D.): Weight(Wall): Grade: DWC/C Casing 7 in 26.00 lb/ft (0.362 in) L-80 2012 API SPEC 5CT COUPLING O.D. Material L-80 Grade �� 80.000 Minimum Yield Strength (psi.) 95.000 Minimum Ultimate Strength (psi.) SA Pipe Dimensions vAM USA 7.000 Nominal Pipe Body O.D. (in.) 4424 VV.Sam Houston Pkwy.Suite 150 Houston.Tx 770416.276 Nominal PipeBody I.D. (in.) Phone:713-479-3200 0.362 Nominal Wall Thickness (in.) Fax 713-479-3234 26.00 Nominal Weight (lbs./ft.) E-mail,VAMUSAsalesvam-usa.com 25.69 Plain End Weight (lbs./ft.) 7.549 Nominal Pipe Body Area (sq. in.) Pipe Body Performance Properties 604.000 Minimum Pipe Body Yield Strength (lbs.) 5.410 Minimum Collapse Pressure (psi.) 7.240 Minimum Internal Yield Pressure (psi.) 6.600 Hydrostatic Test Pressure (psi.) Connection Dimensions 7.875 Connection O.D. (in.) 6.276 Connection I.D. (in.) 6.151 Connection Drift Diameter(in.) 4.50 Make-up Loss (in.) 7.549 Critical Area (sq. in.) 100.0 Joint Efficiency (%) -- Connection Performance Properties 604.000 Joint Strength (lbs.) 16.590 Reference String Length (ft) 1.4 Design Factor 641,000 API Joint Strength (lbs.) 302.000 Compression Rating (lbs.) 5.410 API Collapse Pressure Rating (psi.) 7,240 API Internal Pressure Resistance (psi.) 26.2 Maximum Uniaxial Bend Rating [degrees/100 ft] Approximated Field End Torque Values 18,300 Minimum Final Torque (ft.-lbs.) 21,100 Maximum Final Torque (ft.-lbs.) ' 23.800 Connection Yield Torque (ft.-lbs.) Page 19 Version 0 April, 2017 I SRU 241-33 intDrilling Procedure Rev 0 Hilcorp Energy Company 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at(1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. 13.0 Cement 7" Surface Casing 13.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud&water can be delivered to the cmt unit at acceptable rates. • Pump 20 bbls of freshwater through all of Schlumberger's equipment, taking returns to cuttings bin, prior to pumping any fluid downhole • How to handle cmt returns at surface. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls 10 ppg spacer. Test surface cmt lines. 13.5 Pump remaining 30 bbls of 10 ppg spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. Page 20 Version 0 April, 2017 • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 13.7 Cement volume based on annular volume + 50% open hole excess. Job will consist of lead & tail, TOC brought to surface. Estimated Total Cement Volume: Section: Calculation: Vol Vol (ft3) (BBLS) 12.0 ppg LEAD: 120' x .17126 bpf= 20.5 113 16" Conductor x 7"casing annulus: 12.0 ppg LEAD: (2000' — 120')x .02259 bpf x 1.5 = 63.7 358 8-1/2" OH x 7" Casing annulus: Total LEAD: 84.2 471 ft3 111 15.4 ppg TAIL: (2000'- 1500')x .02259 bpf x 1.5 = 16.9 95 8-1/2" OH x 7" Casing annulus: 15.4 ppg TAIL: 80 x .03828 bpf = 3.1 17 7" Shoe track: Total TAIL: 20 bbl 112 ft3 "1 sx Cement Slurry Design: Lead Slurry (1500' MD to surface) Tail Slurry (1500' to 2000' MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Code Description Concentration Code Description Concentration G Cement 94#/sk A Cement 94#/sk D110 Retarder 0.15 gal/sk BWOC D046 Anti Foam 0.2% BWOC Additives D046 Anti Foam 0.2 % BWOC D065 Dispersant 0.4% BWOC D079 Extender 2.0% BWOC S002 CaCl2 0.35%BWOC D020 Extender 3.0% BWOC D177 CaCl2 0.1% BWOC Page 21 Version 0 April,2017 • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Displacement calculation: ,` 2000'- 80' = 1920' x .003828 bpf= 74 bbls v 13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. Page 22 Version 0 April, 2017 • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 13.13 Do not overdisplace by more than V2 shoe track volume. Total volume in shoe track is 3.1 bbls. • Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12— 18 hours after CIP. • Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require us to run steel pipe through the hanger flutes. The ID of the flutes is 1.5". 13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.15 R/D cement equipment. Flush out wellhead with FW. 13.16 Back out and L/D landing joint. Flush out wellhead with FW. 13.17 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.18 Lay down landing joint and pack-off running tool. Ensure to report the following on wellez: • 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 during job, 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 Send final "As-Run" casing tally & casing and cement report to cdingerhilcorp.com and mmyers@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 23 Version 0 April,2017 11111 SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 14.0 BOP N/U and Test 14.1 N/U Seaboard multi-bowl wellhead assy. Install 7"packoff P-seals. Test to 3000 psi. 14.2 N/U 11" x 5M Townsend BOP as follows: • BOP configuration from Top down: 11" x 5M Townsend annular BOP/11" x 5M Townsend double ram/11" x 5M mud cross/11"x 5M Townsend single ram • Double ram should be dressed with 2-7/8 x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should be dressed with 2-7/8 x 5" VBRs • N/U bell nipple, install flowline. • Install (2) manual valves & a check valve on kill side of mud cross. • Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.3 Run 4-1/2" BOP test assy, land out test plug (if not installed previously). Vey • Test BOP to 250/3500 psi for 10/10 min. Test annular to 250/2500 psi for 10/10 min. � • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.4 R/D BOP test assy. 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 8.8 ppg 6% KCL PHPA mud system. 14.7 R/U mud loggers for production hole section. 14.8 Rack back as much 4-1/2" DP in derrick as possible to be used while drilling the hole section. Page 24 Version 0 April, 2017 ! ! SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 15.0 Drill 6-1/8" Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.5 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. 15.6 Workstring will be 4.5" 16.6# S-135 CDS40. Ensure to have enough 4-1/2"DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. Page 25 Version 0 April, 2017 H • S SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 15.7 6-1/8"BHA: COMPONENT DATA f Description Serial Nu OD ID Gauge Weight Top Length Cumulative (in) (in) (in) (Ibpf) Connection (ft) Length {11) Ell 6-1'8'PDC 5.000 1.500 6.125 60.89 P 3-12"REG 0.80 0.80 © 4 3.4'SperryDnll Lobe 5 6-8.3 stg 4.750 2.794 _cm B 3-1 2'IF 26.70 27.50 © 4-3 4'Float Sub 4.680 2.250 45.07 B 3-12"IF 3 00 30.50 a 4 3'4'DM Collar(Directional) 4.740 2.610 47.00 B 3-1'2"IF 9.20 39.70 - DM Sonde 1.750 ___-- 39.70 © 4 3.4'SP4(Gamma&Res:s:v ty; •- 4 750 1.250 48.20 B 3-12'IF 22.00 61.70 - DDS Insert 61.70 - Slim P4 Insert -____-- 61.70 Mill DGR Insert -____-- 61.70 Q 4 34'PWD(Pressurel - 4.730 1.250 47.90 B 3-12'IF 9.20 70.90 a 4 3 4"TM Col'ar(Te'emetry) 4 700 2.812 46.10 B 3-1 2'IF 11.60 82.50 0 4.3'4'NM Flex Co'lar 4.640 2.250 44.08 B 3-1'2'IF 30.00 112.50 • 4-3.4'NM Flex Co+ar 4 770 2.250 47.35 B 3-12"IF 30.00 142.50 10 X-Over 3 12'IF Pin s CDS-40 Box 5.25011:111 54.44 B 4.5' 1.58 144.08 CDS-40 ® 2lts 4.1'2"HWDP CDS-40 4.500 2.813 36.86 63.00 207.08 ® X-Over CDS-40 Pin x HT-38 Box 5.260 2.125 61.97 B 4'HT 38 2.00 209.08 ® 4-3'4"Weatherford Jar 4.890 1.875 54.59 29.00 238.08 ® X-Over HT-38 Pin x CDS-40 Box 5.260 2.000 63.35 B 4.5" 2.00 240.08 CDS-40 ® 13 Its 4-1 2"HWDP CDS-40 4.500 2.813 36.86 409.50 649.58 r*'''t' 649.58 Page 26 Version 0 April, 2017 i • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 15.8 Primary Bit: 1/ 6 8" (155.6mm) . r 5 3av - voyager."'� ="A09537 �'� IADC Code: ' M323 SCRIE5 PRODUCT SPECIFICATIONS Cutter Size: 13 mm Cutter Back Up: Matrix Shock Studs Total Cutter Count: 37 Face Cutter Count: 26 Connection: 31/2" ►; Nozzle 1 Qty/Type: 5-Series 55 Nozzle 2 Qty/Type: Junk Slot Area: 6.1 in'(39.4cm2) Gage Pad Length: 3"(76mm) Make Up Length: 9.6"(243.8mm) #.i► Shank Diameter: 4.9"(124.5mm) OPERATING PARAMETERS* k,• _. Rotary Speed: For all rotary and motor applications �` Flowrate Min-Max: 150-350GPM(0.57-1.32m3/min) Ii. Max Weight On Bit: 24,000Ibs(10676daN) Makeup Torque: 7000-9000Ft-Lbs.(9491 -12202Nm) voyager Series Blts-Voyager series bits utilize Varel's proprietary design,modeling.and programming software coupled with specialized manufacturing techniques to create the optimal drill bit for your fit-for-purpose applications. Engineered through Varel Simulator Suite for specific directional applications,Voyager bits incorporate the latest design features to maximize cuttings removal.enhance ROP potential,improve directional response.and create a more durable bit frame to aid in accomplishing your aggressive directional drilling objectives. Bit Features O -Drop in cutter in gage pad. U -PDC cutters strategically placed to help reduce hole problems when up drilling or back reaming. X -Shock studs limit drill bit vibration and increase stability allowing smooth cutting action increasing cutter life and overall bit performance. V A R EL www.varelinti.com h Page 27 Version 0 April, 2017 SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 15.9 6-1/8"hole section mud program summary: Weighting material to be used for the hole section will be salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system(1)ppg above highest ./ anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.0 ppg 6%KCL PHPA fresh water based drilling fluid. Properties: Mud: Plastic MD Viscosity Yield Point pH HPHT Weight Viscosity 2000'-9,100' 8.8—10.0 : 40-53 15-25 15-25 8.5-9.5 <11.0 - System Formulation: 6% KCL EZ Mud DP Product Concentration Water 0.905 bbl KC1 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) EZ MUD DP 0.75 ppb(initially 0.25 ppb) DEXTRID LT 1-2 ppb PAC-L 1 ppb BARACARB 5/25/50 15-20 ppb(5 ppb of each) BAROID 41 as required for a 8.8—10.0 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 ppb (maintain per dilution rate) 15.10 TIH w/6-1/8" directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 15.11 R/U and test casing to 3500 psi/30 min. Ensure to record volume/pressure and plot on FIT lL,'�( graph. AOGCC requirement is 50% of burst. 1 15.12 Drill out shoe track and 20' of new formation. 15.13 CBU and condition mud for FIT. Page 28 Version 0 April,2017 • • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 15.14 Conduct FIT/LOT to 11.5 ppg EMW. Note: Offset field test data predicts fracFadient at the 7-5/8"shoe to be between 11 - 13 ppg EMW An 11.5 ppg FIT results in a.2 S ppg kick margin while drilling with the planned MW of 9.5 ppg. 2 a x s) 15.15 Drill 6-1/8"hole section to 9,100' MD. VoP ,2 3 x L• = •'-16 1. jc- • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. ~`` ` • Pump at 225 - 300 gpm. Ensure shaker screens are set up to handle this flowrate. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. • Take MWD surveys every other stand drld. Surveys can be taken more frequently if deemed � _._ - C z6".c)SD necessary. °—�... ��:��-�, _.�� 2�-%-4�f • Take (3) sets of formation samples every 20'. /°1%/4). /7 15.16 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7" shoe. 15.17 Trip to bottom, pump sweep, CBU and condition mud for casing run. 15.18 POOH LDDP and BHA 15.19 Install 4-1/2"pipe rams in BOP stack and RU and test. Page 29 Version 0 April,2017 • • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 16.0 Run 4-1/2" Production Casing 16.1. R/U Weatherford 4-1/2" casing running equipment. ,/ • Ensure 4-1/2"DWC/C HT x 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 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. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U &thread locking shoe track assy consisting of: • (1) Shoe joint w/ shoe bucked on&threadlocked(coupling also thread locked). • (1) Joint with float collar bucked on pin end &threadlocked (coupling also thread locked). • Solid body centralizers will be pre-installed on shoe joint an FC joint. • Leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe and float collar. • Utilize a collar clamp until weight is sufficient to keep slips set properly 16.4. Continue running 4-1/2"production casing • 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 joint across zones of interest, TBD after LWD. • Install solid body centralizers on every other joint to 7-5/8" shoe. Leave the centralizers free floating. • Pick up swell packer and place in string at approximately 1500'. 16.5. Continue running 4-1/2"production casing 4-1/2" DWC/C HT M/U torques Casing OD Minimum Maximum Yield Torque 4-1/2" 5,800 ft-lbs 6,500 ft-lbs 7,200 ft-lbs Page 30 Version 0 April, 2017 1111 SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company Technical Specifications Connection Type: Size(O.D.): Weight(Wall): Grade: DWC/C Tubing 4-112 in 12.60 Ib/ft(0.271 in) L-80 standard Material L-80 Grade 80,000 Minimum Yield Strength (psi) 1111111111111111111111FU SA 95,000 Minimum Ultimate Strength (psi) VAM USA 4424 W.Sam Houston Pkwy.Suite 150 Pipe Dimensions Houston,TX 7 041 00 4.500 Nominal Pipe Body O.D. (in) Fax 71a-479-3234 3.958 Nominal Pipe Body I.D.(in) E-rrail:VAMUSAsatesQvam-usa.00m 0.271 Nominal Wall Thickness (in) 12.60 Nominal Weight(lbslft) 12.25 Plain End Weight(Ibsift) 3.600 Nominal Pipe Body Area (sq in) 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) 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(%) Connection Performance Properties 288,000 Joint Strength (lbs) 14,290 Reference String Length (ft) 1.6 Design Factor 314,000 API Joint Strength (lbs) 288,000 Compression Rating (lbs) 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-lbs) 6,500 Maximum Final Torque (ft-lbs) 7,200 Connection Yield Torque (ft-lbs) Page 31 Version 0 April,2017 • • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 16.6. Run in hole w/4-1/2" casing to the 7" casing shoe. 16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 16.10. Continue to RIH w/casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.11. Set casing slowly in and out of slips. 16.12. PU 4-1/2"X 6-1/8" swell packer to be placed at approximately 1500'. Swell packer should have 10' handling pups installed on both ends with bow spring centralizers on pups. 16.13. Swedge up and wash last 2 joints to bottom. P/U 5' off bottom. Note slack-off and pick-up weights. 16.14. Stage pump rates up slowly to circulating rate. Circ and condition mud with casing on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16.15. Reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 32 Version 0 April, 2017 • • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 17.0 Cement 4-1/2" Production Casing 17.1. Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud& water can be delivered to the cmt unit at acceptable rates. • Pump 20 bbls of freshwater through all of Schlumberger's equipment, taking returns to cuttings bin, prior to pumping any fluid downhole • How to handle cmt returns at surface,regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 17.2. Attempt to reciprocate the casing during cmt operations until hole gets sticky • 17.3. Pump 5 bbls of 12.5 ppg Mud Push spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining 30 bbls 10.5 ppg Mud Push spacer. 17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 50% OH excess. • Section: Calculation: BLS) Vol (ft3) (B7"x 4-1/2" Csg Overlap: 500' x 0.01859= 9.3 52 6-1/8" OH x 4-1/2" Casing: (9,100—2,000)x 0.01677 x 1.5 = 178.6 1003 Shoe Track: 80' x 0.019= 1.5 8.5 Total Volume : 189.4 1063.5 ;r • Page 33 Version 0 April, 2017 • S SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company EASYBLOK (9100' to 1500') System Conventional Density 15.3 lb/gal Yield 1.36 ft3/sk Mixed Water 5.93 gal/sk Mixed Fluid 5.93 gal/sk Code Description Concentration Class G Cement 94#/sk D046 Foam Preventer 0.2% BWOC D202 Dispersant 1.5% BWOC Additives D400 EASYBLOK 0.8% BWOC D154 Extender 8.0% BWOC D174 Expanding Additive 1.5% BWOC D198 Retarder 0.3% BWOC 17.7. Drop wiper plug and displace with 3% KC1. 17.8. If hole conditions allow—continue reciprocating casing throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.9. If elevated displacement pressures are encountered,position casing at setting depth and cease reciprocation. Monitor returns &pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 17.10. Bump the plug and pressure up to 500 psi over final lift pressure. Hold pressure for 3 minutes. 17.11. Do not overdisplace by more than %2 shoe track. Shoe track volume is 1.5 bbls. 17.12. Bleed pressure to zero to check float equipment. Watch for flow.Note amount of fluid returned after bumping plug and releasing pressure. 17.13. RD cementers and flush equipment. �1 .5 17.14. WOC minimum of 12 hours, test casing to 3500 psi and chart for 30 minutes. Page 34 Version 0 April,2017 • • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 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 during job, 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 Send final "As-Run" casing tally & casing and cement report to mmyers@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 35 Version 0 April, 2017 • • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 18.0 RDMO 18.1. Install BPV in wellhead 18.2. N/D BOPE 18.3. N/U temp abandonment cap 18.4. RDMO Saxon Rig#169 1885._ Post rig work: Perform CBL andMlT-IA to 2500 psi for 30 minutes. 18.6. A separate sundry will be required to perforate and produce. Page 36 Version 0 April, 2017 • • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 19.0 BOP Schematic —7"-- j it el at all 0 riliVr i i , 3. Model 6011i 11"-Salo ali at art rtll ftThi— / .--d I M • 3.G7' --.. [a.1__ N 0T-3 Energy r 41 Model'r 082 a ..r+ 1. It 11"-5001) 111.1110 N '.--ty I 0.E111- III ■- " — 1-U-1 a c ✓" r L :. :: 111 tit.tit lit lit 2 1/16 5M Kill Side t1 1J8 SM Choke Side 1.:11 o M ,. :� � Model 71182 ..®. -`'- p 11"-5000 iiiie ®' - 1e1 1811111 181 181 Grade lit fill 1!11!1 1111 Loh . r— a limnjr 1 _ mai ul-_. II 1 i3. • r. 120': ' S/8" r Page 37 Version 0 April,2017 • s SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 20.0 Wellhead Schematic BUM,Otis,4 1/15 5M II a 6..5 Ota quick urian tap IIIIIIIIIIIIII 1 Valve,Swab.OW EL •T•t �'% 41/16 SM FE,HUM, ;i. EE him r, • VS WC,Wigg,cm-FC, Valve,SSW,Barber,3 1/5 5M '! !' /' 31/55M FE,MVO, FE,w/Barer,-Hydraulic self �•, 1r EE Mir centalnedoperate( niiillill Cross,god,41116 SM X :• ' H: N-41; i *3L$5M • li s. .ate., -is Valve,upper Master, k " OW FC,41/16 SM FE,HWO, •. \..• EE trim 111�ijk • 1141111 NMIligi 111.11111. r��at rs,.,, i Valve,Matte',pW-FC, r�y • 81/36 SM FE,trim I IWO, -. `fir �• EE trim • i,, r+ MEM '- Tub rig hrnd,[ictus C 29L _Bill .' t�, UPS,131/B3Me115M,w/ •.pm=ts `..: ` mato_ 1111.1 2-21/16 SM&SO `a W _ _ l= MI . ;11'i 4 Oil Ill m. xa1-Se head,Cactus C-291, I. ki {I��1 ':; , ; I n 1- fir 4 S. Page 38 Version 0 April, 2017 • S SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 21.0 Days Vs Depth Days Vs Depth 0 I —SRU 241-33 Plan 1000 ---_-__ I 2000 3000 — 4000 s 0. •0 5000 II CV 6000 7000 8000 9000 10000 -- 0 2 4 6 8 10 12 14 16 18 20 Days Page 39 Version 0 April, 2017 • • II SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 22.0 Geo-Prog 4/5/2017 8:55 GEOLOGICAL PROGNOSIS WELL NAME SRU 241-33 1 FIELD: Swanson River Field SURFACE LOCATION • X=344,552.45 BHL: X=347864.31 AFE: I(PROPOSED): • Y=2,465,973.08 Y=2465581.08 PAD: 21-33(Rio Pad) PROPOSED TD: 9,100'MD 8,112'TVD • EST.KB: 205.33 API: TBD Rig RKB: 18 Saxon 169 EST.GL: 187.33 Objective: Drill a 9100 MD grass roots well at Kenai Field that will target booked reserves in Tyonek 56-9 and Sterling B-2,3,and 5 sands.Secondary targets include the Tyonek 73-5 and 75-7 sands. I ANTICIPATED FORMATION TOPS&GEOHAZARDS EXPECTED FLUID MD TVD(FT) SUBSEA DEPTH Est.Pressure EMW Gradient Abandoned WD Sand(A8) gas 1 2080 2,061 (1856) 927 87 • 045, Sterling 8-2 gas 2873 2,709 (2504) 1210 8.7 0.45 Sterling B-3 gas 3030{ 2,814 (2609) 1266 8.7 0.45 Sterling 8-5 gas 3318 3,008 (2803) 1354 8.7 0.45 yonek 56-9 gas = 0, , 6734 5,675 (5470) 2554 8.7 0 45 Tyonek 64-5(Gas Storage) as ; 7432 6,372 (6167) 2867 8.7 ` 0.45' Tyonek 73-5 8354 7,294 (7089) • ', ,.° 8.7 0.45; =Reservoir Objectives =Possible Geo Hazards DATA COLLECTION REQUIREMENTS: `Mud Logging: I Surface Csg.To TD,samples collected at20'intervals • LWD Data GR/RES Other Log Data: COMPLETION TYPE Chance of Success&Anticipated Rate •^5°/0 ARTIFICIAL LIFT EQUIPMENT OD 16" , 100' PROBED PIPE SET DEPTHS 7" .,-...,-,.....,._--,__, ' 000, " 000' 4-1/2" , TD TUBING SIZE i ."This well is to be driled from the 21-33(Rio)pad and will initially be drilled to the east ease'prowae Fi Tn and yself with the final surface location when the best location has been identified and staked.The two primarytargets i F` fj OTHER COMMENTS g well are the Tyonek and Sterling,and it is imperitive that we get cement across the entire production string intetval.a /✓ ..=______________________ �__ NO INFORMATION CONCERNING THIS WELL IS TO BE RELEASED TO ANYONE EXCEPT THE EMPLOYEES OF HILCORP OR THEIR PARTNERS. Page 40 Version 0 April, 2017 • i SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 23.0 Anticipated Drilling Hazards 8-1/2" Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP btwn 25 —45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of—50 - —60 lbs/100ft2 to combat this issue. Maintain low flow rates for the intial 200' of drilling to reduce the likelihood of washing out the conductor shoe. To help insure good cement to surface after running the casing, condition the mud to a YP of 25 —30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 41 Version 0 April, 2017 • i SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 6-1/8" Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/viscosifier as necessary. Sweep hole w/20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP btwn 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6%KC1 in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. • 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. H2S: / H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 42 Version 0 April, 2017 SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 24.0 Saxon Rig 169 Layout q . r , — Ij a raw 1MI r�®r r 1 r f I 011111... M k j ,� ��,� , IV SI I. ��II I I. ' I roll � . nwoommo skII :fmi Ill I IIII ' ■■I^IA �i 1_ = 1111111 � ..I 1 1r -..I 1:1 I IMF t4 III �Illl' .iI ;:li.i:ii I E1 EYrig ts Ij I . l_ I�� I [ p 1 .. :c-_. , IIIIIIII ,,,, �,,I" I1 ISII:'' �t ' I 11 N_v(Ie I'I I IIII„ ,„ I .�ij IIIIIII, 1 III i - 1 :� . I ? ,.ww.1 ...4 1 1 i 1 " I i ... 1 I Mill=—_ I Page 43 Version 0 April, 2017 • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 25.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer(ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure.Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 44 Version 0 April,2017 in" I SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 26.0 Choke Manifold Schematic I Pe nb °30, s_ /0111 . . —-1 -: "94r.= ''''' rt _ C4 •.‘ rieuill1111 n 4P4 i i1"' _ ,,, I p = 1111111111111111 7 i a 4!' ` : .. el fr. �' t r— _ r ti P J - �- ' a C. c -_ C. C. eelo eK`iltiV � a L _ , � ggN 1,,,, � c y i Illi t , f. " , k. igq o m 'A 4401t 111111111 1 Ilit 7..* t li r s ,t�fi�' 4 Zt Ii P N 'Le i4 1111111111111111 €� I� ,...,_.k._ N x111 C sill.,'(gil l i 11., Page 45 Version 0 April, 2017 SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 27.0 Casing Design Information Calculation & Casing Design Factors Swanson River Unit DATE:4/5/2017 WELL: SRU 241-33 FIELD:Swanson River DESIGN BY: Monty M Myers Design Criteria: Hole Size 8-1/2" Mud Density: 8.8 ppg Hole Size 6-1/8" Mud Density: 9.5 ppg Hole Size Mud Density: Drilling Mode MASP: 1087 psi (see attached MASP determination& calculation) MASP: Production Mode MASP: 2840 psi (see attached MASP determination&calculation) Collapse Calculation: 111111111111111111111111111111111111111111111111111111111111111111M Section Calculation 1 Normal gradient extemal stress (0.45 psi/ft)and the casing evacuated for the internal stress I � ' Casing Section Calculation/Specification 1 2 3 4 Casing OD 7" 4-1/2" Top(MD) 0 0 Top(TVD) 0 0 Bottom (MD) 2,000 9,100 Bottom (TVD) 1,977 8,115 Length 2,000 9,100 Weight(pp0 26 12.6 Grade L-80 j L-80 Connection DWC/C DWC/C HT Weight w/o Bouyancy Factor(lbs) 52,000 114,660 Tension at Top of Section (lbs) 52,000 114,660 Min strength Tension(1000 lbs) 604 288 Worst Case Safety Factor(Tension) 11.62 . 2.51 Collapse Pressure at bottom (Psi) 900 3,530 Collapse Resistance w/o tension (Psi) 5,410 7,480 Worst Case Safety Factor(Collapse) 6.01 • 2.12 MASP (psi) 692 1 2,840 Minimum Yield (psi) 7,240 8,430 Worst case safety factor(Burst) 10.46, 2.97 Page 46 Version 0 April, 2017 • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 28.0 6-1/8" Hole Section MASP Maximum Anticipated Surface Pressure Calculation Hilcorp 6-1/8"Hole Section SRU 241-33 Swanson River Unit MD ND Planned Top: 0 0 Planned TD: 9100 8115 Anticipated Formations and Pressures: Formation ND Est Pressure Oil/Gas/Wet PPG Grad Abandoned WD Sand(A8) 2061 927.45 Gas 8.7 0.450 Sterling B-2 _ 2709 1219.05 Gas 8.7 0.450 Sterling B-3 2814 1266.3 Gas 8.7 0.450 Sterling B-5 3008 1353.6 Gas 8.7 0.450 Tyonek 56-9 _ 5675 2553.75 Gas 8.7 0.450 Tyonek 64-5(Gas Storage) _ 6372 2867.4 Gas 8.7 0.450 Tyonek 73-5 7294 3282.3 Gas 8.7 0.450 Offset Well Mud Densities Well MW range Top(ND) Bottom(ND) Date SCU 21-4 12 ppg 0 10,965 1961 SCU44-33 11.3-12.5ppg 9,216 10,747 2013 SCU 41A-4 11.2 ppg 9,300 10,807 2013 Assumptions: 1. Fracture gradient at shoe is estimated at 0.65 psi/ft based on field test data. 2. Maximum planned mud density for the 6-1/8"hole section is 9.5 ppg. 3. Calculations assume"Unknown"reservoir contains 100%gas(worst case). 4. Calculations assume worst case event is 100%evacuation of well bore to gas. Fracture Pressure at r shoe considering a full column of gas from shoe to surface: ND Frac Grad 1977 ft X 0.650 psi/ft 1285 psi 1285(psi)-[0.1(psi/ft)*1977(ft)]= 1087 psi MASP from pore pressure during production mode(Complete evacuation to gas) 8115 ft X0.450 psi/ft 3652 psi Downhole 3652(psi)-[0.1(psi/ft)*8115(ft)]= 2840 psi Surface Summary: 1. MASP while drilling 6-1/8"production hole is governed by frac pressure at 7"shoe Page 47 Version 0 April,2017 Hs SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 29.0 Spider Plot (NAD 27) (Governmental Sections) // 12-27 Pad / \ KGSF 7 BHL• i \ i ! KGSF 3 BHL•/j \` // KGSF 2 Bell• \ \ \ f 'fiea----------------.......-_ / \ SRU43-28 / \ SRU 428 Pad 3-28 KGSF 7A ) SRU 13-27 BML• / / / // SRU31427P2 8H / SRU314-27 BHL 1`--, / 1 SR11 28.Patl / SRU31427P1 BHLIIII 3 PAP / OU 146-:7 snip X'� J ' A028406 - A028399 • r/0- ,,,‘ / /' // SRL 241-33 SHL / / snu 2l a;Pad/ // / !SRL'241-33TPII SRU21.33t•Vb BHL ubWpo SRU41-33 BFil•/ // S008N009W QDp000000000e000000000000000o I` SRL',-t1-:;_13111. I ~� SWANSON RIVER FIELD r 31-s' SRU21A34BHL•- ._` Y-- -- SRUI2-34 8HLIII SRU 32-33 Pad 580 t 2.34 Pad SRU32-33 BHL €9 SRU32A3313HL• 0 ✓ ECU 43A-33 Beg, SCU343-33 BHI> / I/ 4' SRU23-33 BHL•..... I ' Legend SRU 23-33 Fad /` 4 u 33 33 SRU 241-33_SHL • Other Surface Well Locations SRU 241-33 TPH • Other Bottom Hole Locations �r SCU33.33 BHL• -•_ SRU 241-33 BHL __ - Well Paths SR�1a4.s3BHL Q Oil and Gas Unit Boundary •SRU14-33 BHL / 1 SCU 14-34-Pad -`-' III 0 1,000 2.000 Swanson River Unit Feet SRU241-33 Alaska State Plane Zone 4,NAD27 A IIih-orp,%a+ka.l.l.0 Map Date:3/29/2017 Page 48 Version 0 April, 2017 Hi SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 30.0 Surface Plat (As Staked) (NAD 27) I 1 29'28 33 — SECTION LINE SECTION COR(COMPUTED) N.2466504.335 E 342411 787 502 FNL . SEC 33 T8N R9W w J or °'N„ o ~ RU 21.33 PADOA D H ACCESS Q -\' 2147 FWL(NISI - w- Z \--*---"'-''.----- Ill Z_ J Z O SRU 241-33 U AS STAKED SURFACE LOCATION a) NAD 27 ASP ZONE 4 N:2465973.085' E:344552.451' LAT:60°44'48.99650"N LON:150`52'07.82883"W 502'FNL 2147'FWL ' EL: 187.33 NAVD88 • NOTES 1. BASIS OF HORIZONTAL,NAD83 US FEET POSITION(EPOCH 2010) ``�..1j AND VERTICAL CONTROL(NAVD88)IS AN OPUS SOLUTION FROM _N ".. OF I i t t NGS STATIONS TBON.TSEA AND ANC2 TO ESTABLISH CP-2. THE4 _y�p'�F'--""' ,:Q p9it/ ALASKA STATE PLANE COORDINATES NAD 83 ZONE 4 IN FEET ARE. Z. N=2458384.578 *14 9181 T•*/ E=1483669 444 r�r►:�— i X'.411154714.. ELEV =212.690(NAV088) �'''''' / •,STAN A YdAkE 2.SECTION LINES SHOWN WERE ESTABLISHED FROM SURVEY TIES TO ORIGINAL GLO MONUMENTATION(1987) SCALE it `... /l'/I`:: — 3 DATUM TRANSFORMATIONS(NA083 ASPZ4 TO NAD27 ASPZ4) <' 203 OCA ttt.11""``�---• WERE DONE USING CORPSCON SOFTWARE VERSION 6.0.1. , II FEET J ,R-E�HILCORP ALASKA,LLC • Can�ulting Inc SWANSON RIVER FIELD W+iirMiw� WELL SRU 241-33 AS STAKED SURFACE LOCATION +EErwra7L.PFIWo•aum>;»arTESTms NAD 27 A O Mt w8 n-T-NOT'YA NC%NO t6(:ATKrN ytrAcr .,4. .W8 . nm,T.-a SECTION 33 TO8N RO9W VAN, SAITI:u ENTATANECCCON Ililrurp:Ila.la,1,IC 1'` 1 SEWARD MERIDIAN.ALASKA Page 49 Version 0 April, 2017 • SRU 241-33 Drilling Procedure Rev 0 Hilcorp Energy Company 31.0 Surface Plat (As Staked) (NAD 83) - . 29 28 _—_—_—_ SECTION LINE 3 33 - —-- - - -- --——-------. SECTION COR(COMPUTED) N.2466265.728 E-1482434.646 f.4.,`N` SEC 33 T8N R9W W -J Q w 4Aro •O FSRU 21-33 PAD ACCESS R� ``h O --A. 214TFWL(NTS) Allo Z W Z -' SCU 241-33 O_ AS STAKED SURFACE LOCATION t' NAD 83 ASP ZONE 4 w N:2465734.460' cn E: 1484575.382 LAT:60°44'46.97000"N LON: 150°52'15.82000"W 502'FNL 2147'FWL ELEV: 187.33 NAVD88 1 NOTES 1. BASIS OF HORIZONTAL,NAD83 US FEET POSITION(EPOCH 2010) %%‘1 AND VERTICAL CONTROL(NAVD88)IS AN OPUS SOLUTION FROM �.' OF A t ti NGS STATIONS TBON.TSEA AND ANC2 TO ESTABLISH CP-2. THE4. QV •••-•-'•Lqs tt� r ALASKA STATE PLANE COORDINATES NAD 83 ZONE 4 IN FEET ARE: r��'' y �� *i IL+ '*i N=2458384.578 `4�9 E=1483669.444 ,,— ! N�:rf�11a.r...., ELEV.=212 690(NAVD88) :ST �C Stu1 p .... ur SCALE 66.1.1 7-SS - it .. 2.SECTION LINES SHOWN WERE ESTABLISHED FROM SURVEY t `........ TIES TO ORIGINAL GLO MONUMENTATION(1987) o 200 `L'• t t t 1 j""``% / �� FEET `__- PRo.ecT HILCORP ALASKA,LLC Consulting Inc SWANSON RIVER FIELD '' 1""'° 11�c1.�1. WELL SRU 241-33 AS STAKED SURFACE LOCATION CRA'NN sr me '"`E ,"" PROJECT NO ,Brox (•.f:1,EE kNG:EtVfor:.SW'.E'NG:TESTNG NAD 83 SOCK AO 1641 PO EQ.ti8Y.h.D�,VA AA.!.:4? 1:11tQGigN .�,rE ,.�z „1n rAr , ,,�.,.., SECTION 33 TO8N RO9W g11(r7 ft.. SUCuNCI.{,,:1.KECGCC' IIiI,•urp,tI:I-La.Ilk 1 oP I SEWARD MERIDIAN,ALASKA Page 50 Version 0 April,2017 • • Hilcorp Alaska, LLC Swanson River Unit SRU 21-33 Plan: SRU 241-33 SRU 241-33 Plan: SRU 241-33 WPO7a Standard Proposal Report 05 April, 2017 ,44 II III 11 HALLIBURTON Sperry Drilling Services HALLIBURTONHilcorpAlaska,LLC REFERENCE INFORMATION HALLIBURTON . HilCorp Calculation Method: Minimum Curvature Co-ordinate(N/E)Reference: Well Plan:SRU 241-33,True North Sperry Drilling Error System: ISCWSA Vertical(ND)Reference: Initial @ 205.33usft(Saxon 169) Scan Method: Closest Approach 3D Measured Depth Reference: Initial @ 205.33usft(Saxon 169) Error Surface: Elliptical Conic Warning Method: Error Ratio Calculation Method: Minimum Curvature Project: Swanson River Unit SECTION DETAILS Site: SRU 21-33 Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Well: Plan:SRU 241-33 1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00 2 1200.00 0.00 0.00 1200.00 0.00 0.00 0.00 0.00 0.00 I Wellbore: SRU 241-33 3 2296.91 32.91 110.22 2237.59 -105.91 287.55 3.00 110.22 297.03 Design: SRU 241-33 WPO7a 4 2585.29 32.91 110.22 2479.70 -160.06 434.57 0.00 0.00 448.90 5 2902.94 34.00 93.00 2745.33 -194.61 604.62 3.00 -90.68 621.63 SRU 241-33 wp06 Tgt1 6 2913.12 34.17 92.54 2753.76 -194.89 610.32 3.00 -57.09 627.33 _ 7 3593.96 34.17 92.54 3317.09 -211.86 992.30 0.00 0.00 1009.00 8 3721.73 38.00 92.54 3420.33 -215.19 1067.47 3.00 -0.03 1084.10 SRU 241-33 wp06 Tgt3 9 3896.58 43.20 93.60 3553.04 -221.34 1181.04 3.00 7.96 1197.70 DDI = 5.631 10 5396.58 43.20 93.60 4646.49 -285.81 2205.84 0.00 0.00 2223.62 11 6000.00 31.19 91.58 5126.30 -303.17 2569.51 2.00 -175.00 2587.12 12 6509.67 21.00 92.00 5583.42 -310.02 2793.30 2.00 179.16 2810.40 13 6639.91 21.00 92.00 5705.00 -311.65 2839.94 0.00 0.00 2856.96 SRU 241-33 wp06 Tgt4 14 7191.18 10.00 95.00 6235.42 -319.29 2986.80 2.00 177.28 3003.81 15 9100.00 10.00 95.00 8115.24 -348.18 3317.00 0.00 0.00 3335.23 -1500- CASING DETAILS WELL DETAILS: Plan:SRU 241-33 - Ground Level: 187.33 - TVD TVDSS MD Size +N1-5 +E/-W Northing Easting Latittude Longitude - 1976.81 1771.48 2000.00 7"x 8 3/4" 0.00 0.00 2465973.08 344552.45 60°44'48.996 N 150°52 7.829 W -750- 8115.24 7909.91 9100.00 4 1/2"x 6 1/8" -1 SURVEY PROGRAM A Date:2016-10-26T00:00:00 Validated:Yes Version: 0- Depth From Depth To Survey/Plan Tool _ 18.00 1500.00 SRU 241-33 WP07a MWD+SC+sag _ 1500.00 9100.00 SRU 24133 WP07a MWD+SC+sag - 500 - Start Dir 3°/100':1200'MD,1200'TVD 750- FORMATION TOP DETAILS 1009- TVDPath TVDssPath MDPath Formation 2061.33 1856.00 2093.58 Abandoned WD Sand(A8) - 2709.33 2504.00 2859.59 Sterling B-2 End Dir :2296.91'MD,2237.59'TVD 1500- 1500 2814.33 2609.00 2986.33 Sterling B-3 3008.33 2803.00 3220.79 Sterling B-5 _ 7"x 8 3/4" 5675.33 5470.00 6608.13 Tyonek 56-9 Abandoned WD Sand(A8) ` p0o Start Dir 3°/100':2585.29'MD,2479.7'TVD 6372.33 6167.00 7330.21 Tyonek 64-5(Gas Storage) 7294.33 7089.00 8266.43 Tyonek 73-5 2250- - y00 -_- End Dir _2913.12'MD,2753.76'TVD Sterling B-2 .- - -. .. _ SRU 241-33 wp06 T., pfl_=Start Dir 3°/100':3593.96'MD,3317.09'TVD 3000- - - -g- - - - - - - - - - - - Start Dir 3°/100':3593.96'MD,3317.09'TVD ts)o Sterling B-5 SRU 241-33 wp06 Tg ,5g�---- o �O End Dir :3896.58'MD,3553.04'TVD al _ tP 3750- SRU 241-33 wp06 Tgt ao a - ah Q - o� Start Dir 2°/100':5396 .58'MD,4646.50'TVD - 4P m - • 4500- Pp4" End Dir :6509.67'MD,5583.41'TVD • _ co 5250- Start Dir 2°/100':6639.91'MD,5705'TVD _- Tyonek 56-9 SRU 241-33 wp06 Tg 'g50ti _----- 6000-Tyonek 64-5(Gas Storage) -7000 End Dir :7191.18'MD,6235.42'TVD '= - - - - - - - 7500 6750- =Tyonek 73-5 a000 7500- 8500 Total Depth:9100'MD 8115.24'TVD 4 1/2"x 6 1/8" "9100 8250- - SRU 241-33 WPO7a 9000- 9750- I , F I 1 F I I I F I I I F , I I I I F , , l •. i iI I I I , I I I I I I I I I F I I I I I I I p I -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 Vertical Section at 95.99° (1500 usft/in) • • HALLIBURTON Project: Swanson River Unit WELL DETAILS:rag SRU 241-33 Site: SRU 21-33 Ground Level: 197.33 Sperry Orating Well: Plan:SRU 241-33 ON/-S +E�-W Northing EosSog Latim,aa Longitude Wellbore: SRU 241-33 0.00 0.00 2465973.08 344552.45 60° 2' 44'48.996 N 150°57.829W Plan: SRU 241-33 WP07a REFERENCE INFORMATION liti I h l e e()ri CoaNlnafa(N/E)Reference:Well Plan:SRU 241-33,True North Vertical(TVD)Reference.Initial 0 205.33usf(Saxon 169) Measured Depth Reference:Initial 0 205.330SR(Saxon 189) Calculation MoMod:Minimum Curvature 1333— CASING DETAILS TVD TVDSS MD Name 1976.81 1771.48 2000.00 7"0 8 3/4" 8115.24 7909.91 9100.00 412"0 61/8" 1000- 667- 0 �1 9 - .1.1-63.4'9 .4°:'ryrye,159T,- ryp19Ta 116A^b'49 'S'5\1 �,,o • 333— et0 1969` S:(10 `118'° v8'`A1' 3311°�a O ,a°aS6�9 ,S`14 3' - D`` :1 1t�..1;5% .19 t'.5, '3590' tom' ,SpN0 $�• �A 51p5 �,O o - I `p°a / 0�3 �OS 'f lx� 35g3 355 3965 p,�'1`" atm �`" '^.' 15�` 9S., Itdy. 5g� t�:5 SO. X399 6135 Nti g ,'S� 9S� .3496 c11 14.0' td5 0— ��°S' S�yy amt 5,4" 6561 '$1 1t9tt6� - g FA 1. Ss- ' Q�� Total DeptR:9100'MD 8115.24'TVD ro 4imi Aft 8 R a _ 7"x83/4" � m ^ .� `„L$6R�gc_ tiVI7 W ,S_RU 241-33 WPo7a -333— SRU241-33 wp06 Tg11 -- SRU 241-33 wp06 Tgt3 - SRU 241-33 ssp06 Tgt2 - 412"x61/8" SRU 241-33 331706 Tg14 -667— -1000- -1333— -1667— IIII1I1IIII1IIIIII1IIIiIIIIIIIIIIIIIiil1l , iilllillllll11Iilll , -333 0 333 667 1000 1333 1667 2000 2333 2667 3000 3333 3667 40110 4i$3 • West(-)/East(+)(500 usft/in) 0 0 Halliburton HALLIBURTONJ Standard Proposal Report Database:,;;t1;;': Sperry EDM-NORTH US+CANADA `Local Co-ordinate Reference: ";.Well Plan:SRU 241-33 Company: Hilcorp Alaska,LLC TVD Reference: Initial @ 205.33usft(Saxon 169) ' r.;';....,,;01.;:;;. . Project: Swanson River Unit MD Reference: Initial @ 205.33usft(Saxon 169) Site:a� SRU 21-33 North Reference: 411,4 True • Well: Plan:SRU 241-33 Survey Calculation Method: Minimum Curvature • Wellbore (,. ; SRU 241-33 Design: ,. SRU 241-33 WP07a :- Project I Swanson River 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 it SRU 21-33 Ait, Site Position: Northing: 2,465,923.33 usft Latitude: 60°44'48.502 N From: Map Easting: 344,517.50 usft Longitude: 150°52'8.519 W Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -0.76° Well Plan:SRU 241-33 ,a...._. ... ............. -. Well Position +N/-S 0.00 usft Northing: 2,465,973.08 usft • Latitude: 60°44'48.996 N +EI-W 0.00 usft Easting: 344,552.45 usft . Longitude: 150°52'7.829 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: • 187.33 usft Wellbore: SRU 241-33 Magnetics Model Name Sample Date Declinations Field Strength n E , ,r nT BGGM2016 10/26/2016 16.29 73.75 55,498 Design ,, SRU 241-33 WPO7a Audit Notes: Version: Phase: PLAN Tie On Depth: 18.00 Vertical Section: Depth From(TVD) _"+N/-S +E/-W I Direction ;: ,, .,. '_(usft) >: (usft) (usft) rqfP . ' (°) 18.00 0.00 0.00 95.99 Plan Sections Measured Vertical TVD 47' Dogleg Build Turn Depth Inclination Azimuth Depth System +N/-S 10 - +El-W Rate Rate Rate Tool Face • (usft) (°) (°) (usft) usft (usft) (usft) (°/100usft) (°/100usft) (°l100usft) () ,t;; 18.00 0.00 0.00 18.00 -187.33 0.00 0.00 0.00 0.00 0.00 0.00 1,200.00 0.00 0.00 1,200.00 994.67 0.00 0.00 0.00 0.00 0.00 0.00 2,296.91 32.91 110.22 2,237.59 2,032.26 -105.91 287.55 3.00 3.00 0.00 110.22 2,585.29 32.91 110.22 2,479.70 2,274.37 -160.06 434.57 0.00 0.00 0.00 0.00 2,902.94 34.00 93.00 2,745.33 2,540.00 -194.61 604.62 3.00 0.34 -5.42 -90.68 2,913.12 34.17 92.54 2,753.76 2,548.43 -194.89 610.32 3.00 1.64 -4.48 -57.09 3,593.96 34.17 92.54 3,317.09 3,111.76 -211.86 992.30 0.00 0.00 0.00 0.00 3,721.73 38.00 92.54 3,420.33 3,215.00 -215.19 1,067.47 3.00 3.00 0.00 -0.03 3,896.58 43.20 93.60 3,553.04 3,347.71 -221.34 1,181.04 3.00 2.97 0.61 7.96 5,396.58 43.20 93.60 4,646.49 4,441.16 -285.81 2,205.84 0.00 0.00 0.00 0.00 6,000.00 31.19 91.58 5,126.30 4,920.97 -303.17 2,569.51 2.00 -1.99 -0.33 -175.00 6,509.67 21.00 92.00 5,583.42 5,378.09 -310.02 2,793.30 2.00 -2.00 0.08 179.16 6,639.91 21.00 92.00 5,705.00 5,499.67 -311.65 2,839.94 0.00 0.00 0.00 0.00 7,191.18 10.00 95.00 6,235.42 6,030.09 -319.29 2,986.80 2.00 -2.00 0.54 177.28 9,100.00 10.00 95.00 8,115.24 7,909.91 -348.18 3,317.00 0.00 0.00 0.00 0.00 4/5/2017 6:58:20PM Page 2 COMPASS 5000.1 Build 81 4111 • Halliburton HALLIBURTON Standard Proposal Report Database:` Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: r Well Plan:SRU 241-33 Company: . Hilcorp Alaska,LLC TVD Reference: Initial @ 205.33usft(Saxon 169) • • Project: .Swanson River Unit MD Reference: . Initial @ 205.33usft(Saxon 169) Site: SRU 21-33 North Reference: True i Well: Plan:SRU 241-33 Survey Calculation Method: Minimum Curvature • -• Wellbore: SRU 241-33 ' '' 1 Design: SRU 241-33 WP07a � Planned Survey ,, ' Measured vertical t1 4."+" Map Map .- " Depth Inclination Azimuth Depth TVDss +N/-S +E/-W : Northing , Easting ; e Vert Section (usft) (°) (°) (usft) usft ., (usft) ',:, (usft) (usft) '''''., (usft) 18.00 0.00 0.00 18.00 -187.33 0.00 0.00 2,465,973.08 344,552.45 0.00 0.00 100.00 0.00 0.00 100.00 -105.33 0.00 0.00 2,465,973.08 344,552.45 0.00 0.00 200.00 0.00 0.00 200.00 -5.33 0.00 0.00 2,465,973.08 344,552.45 0.00 0.00 300.00 0.00 0.00 300.00 94.67 0.00 0.00 2,465,973.08 344,552.45 0.00 0.00 400.00 0.00 0.00 400.00 194.67 0.00 0.00 2,465,973.08 344,552.45 0.00 0.00 500.00 0.00 0.00 500.00 294.67 0.00 0.00 2,465,973.08 344,552.45 0.00 0.00 600.00 0.00 0.00 600.00 394.67 0.00 0.00 2465,973.08 344,552.45 0.00 0.00 700.00 0.00 0.00 700.00 494.67 0.00 0.00 2,465,973.08 344,552.45 0.00 0.00 800.00 0.00 0.00 800.00 594.67 0.00 0.00 2,465,973.08 344,552.45 0.00 0.00 900.00 0.00 0.00 900.00 694.67 0.00 0.00 2,465,973.08 344,552.45 0.00 0.00 1,000.00 0.00 0.00 1,000.00 794.67 0.00 0.00 2,465,973.08 344,552.45 0.00 0.00 1,100.00 0.00 0.00 1,100.00 894.67 0.00 0.00 2,465,973.08 344,552.45 0.00 0.00 1,200.00 " 0.00 0.00 1,200.00 994.67 0.00 0.00 2,465,973.08 344,552.45 0.00 0.00 Start Dir 3°/100':1200'MD,1200'TVD 1,300.00 3.00 110.22 1,299.95 1,094.62 -0.90 2.46 2,465,972.14 344,554.89 3.00 2.54 1,400.00 6.00 110.22 1,399.63 1,194.30 -3.62 9.82 2,465,969.33 344,562.22 3.00 10.14 1,500.00 9.00 110.22 1,498.77 1,293.44 -8.13 22.06 2,465,964.66 344,574.40 3.00 22.79 1,600.00 12.00 110.22 1,597.08 1,391.75 -14.42 39.16 2,465,958.14 344,591.42 3.00 40.45 1,700.00 15.00 110.22 1,694.31 1,488.98 -22.49 61.07 2,465,949.78 344,613.21 3.00 63.08 1,800.00 18.00 110.22 1,790.18 1,584.85 -32.31 87.71 2,465,939.62 344,639.72 3.00 90.61 1,900.00 21.00 110.22 1,884.43 1,679.10 -43.84 119.03 2,465,927.67 344,670.89 3.00 122.96 2,000.00 24.00 110.22 1,976.81 1,771.48 -57.07 154.94 2,465,913.97 344,706.61 3.00 160.05 7"x 8 3/4" 2,093.58 26.81 110.22 2,061.33 1,856.00 -70.94 192.61 2,465,899.60 344,744.09 3.00 198.96 Abandoned WD Sand(A8) 2,100.00 27.00 110.22 2,067.06 1,861.73 -71.95 195.33 2,465,898.56 344,746.80 3.00 201.78 2,200.00 30.00 110.22 2,154.93 1,949.60 -88.44 240.10 2,465,881.48 344,791.35 3.00 248.02 2,296.91 32.91 110.22 2,237.59 2,032.26 -105.91 287.55 2,465,863.38 344,838.55 3.00 297.03 End Dir :2296.9V MD,2237.59'TVD 2,300.00 32.91 110.22 2,240.19 2,034.86 -106,49 289.13 2,465,862.78 344,840.12 0.00 298.66 2,400.00 32.91 110.22 2,324.14 2,118.81 -125.27 340.11 2,465,843.33 344,890.84 0.00 351.33 2,500.00 32.91 110.22 2,408.10 2,202.77 -144.05 391.09 2,465,823.88 344,941.57 0.00 403.99 2,585.29 32.91 110.22 2,479.70 2,274.37 -160.06 434.57 2,465,807.29 344,984.83 0.00 448.90 Start Dir 3°/100':2585.29'MD,2479.7'TVD 2,600.00 32.90 109.41 2,492.05 2,286.72 -162.77 442.08 2,465,804.49 344,992.31 3.00 456.66 2,700.00 33.03 103.90 2,575.97 2,370.64 -178.34 494.17 2,465,788.23 345,044.18 3.00 510.09 2,800.00 33.39 98.46 2,659.66 2,454.33 -188.94 547.85 2,465,776.92 345,097.71 3.00 564.58 2,859.59 33.71 95.28 2,709.33 2,504.00 -192.87 580.54 2,465,772.56 345,130.34 3.00 597.50 Sterling B-2 2,900.00 33.98 93.15 2,742.89 2,537.56 -194.52 602.98 2,465,770.61 345,152.76 3.00 619.99 2,902.94 34.00 93.00 2,745.33 2,540.00 -194.61 604.62 2,465,770.50 345,154.40 3.00 621.63 End Dir :2913.12'MD,2753.76'TVD 2,913.12 34.17 92.54 2,753.76 2,548.43 -194.89 610.32 2,465,770.15 345,160.09 3.00 627.33 Start Dir 3°/100':3593.96'MD,3317.09'TVD 4/5/2017 6:58:20PM Page 3 COMPASS 5000.1 Build 81 • • Halliburton HALLIBURTON Standard Proposal Report Database Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: 1. Well Plan:SRU 241-33 :? Company: Hilcorp Alaska,LLC TVD Reference: Initial @ 205.33usft(Saxon 169) Project: Swanson River Unit MD Reference: r' Initial @ 205.33usft(Saxon 169) Site: SRU 21-33 North Reference: ,,,..,.. True I Well: Plan:SRU 241-33 :!Survey Calculation Method: `. :Minimum Curvature Wellbore: SRU 241-33 . Design: SRU 241-33 WPO7a x ' Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +11/-S " +E/-W Northing Easting !` DLS Vert Section jj (usft) (°) (°) (usft) usft (usft) I,.„:(usft) (usft) (usft) 2,609.00 2,986.33 34.17 92.54 2,814.33 2,609.00 -196.71 651.39 2,465,767.78 345,201.13 0.00 668.37 Sterling B-3 3,000.00 34.17 92.54 2,825.64 2,620.31 -197.05 659.06 2,465,767.34 345,208.80 0.00 676.03 3,100.00 34.17 92.54 2,908.38 2,703.05 -199.55 715.17 2,465,764.11 345,264.86 0.00 732.09 3,200.00 34.17 92.54 2,991.12 2,785.79 -202.04 771.27 2,465,760.87 345,320.93 0.00 788.15 3,220.79 34.17 92.54 3,008.33 2,803.00 -202.56 782.94 2,465,760.20 345,332.58 0.00 799.81 Sterling B-5 3,300.00 34.17 92.54 3,073.87 2,868.54 -204.53 827.38 2,465,757.64 345,376.99 0.00 844.21 I 3,400.00 34.17 92.54 3,156.61 2,951.28 -207.02 883.48 2,465,754.40 345,433.05 0.00 900.27 3,500.00 34.17 92.54 3,239.35 3,034.02 -209.51 939.59 2,465,751.17 345,489.12 0.00 956.33 3,593.96 34.17 92.54 3,317.09 3,111.76 -211.86 992.30 2,465,748.13 345,541.79 0.00 1,009.00 Start Dir 3°/100':3593.96'MD,3317.09'TVD 3,600.00 34.35 92.54 3,322.08 3,116.75 -212.01 995.70 2,465,747.93 345,545.19 3.00 1,012.39 3,700.00 37.35 92.54 3,403.13 3,197.80 -214.60 1,054.20 2,465,744.56 345,603.64 3.00 1,070.84 3,721.73 38.00 92.54 3,420.33 3,215.00 -215.19 1,067.47 2,465,743.80 345,616.90 3.00 1,084.10 3,800.00 40.33 93.04 3,481.01 3,275.68 -217.60 1,116.83 2,465,740.74 345,666.23 3.00 1,133.45 3,896.58 43.20 93.60 3,553.04 3,347.71 -221.34 1,181.05 2,465,736.15 345,730.38 3.00 1,197.70 End Dir :3896.58'MD,3553.04'TVD 3,900.00 43.20 93.60 3,555.54 3,350.21 -221.49 1,183.38 2,465,735.97 345,732.71 0.00 1,200.04 4,000.00 43.20 93.60 3,628.43 3,423.10 -225.79 1,251.70 2,465,730.77 345,800.97 0.00 1,268.43 4,100.00 43.20 93.60 3,701.33 3,496.00 -230.08 1,320.02 2,465,725.57 345,869.22 0.00 1,336.83 4,200.00 43.20 93.60 3,774.23 3,568.90 -234.38 1,388.34 2,465,720.37 345,937.47 0.00 1,405.22 4,300.00 43.20 93.60 3,847.12 3,641.79 -238.68 1,456.66 2,465,715.17 346,005.72 0.00 1,473.62 4,400.00 43.20 93.60 3,920.02 3,714.69 -242.98 1,524.98 2,465,709.97 346,073.97 0.00 1,542.01 4,500.00 43.20 93.60 3,992.92 3,787.59 -247.28 1,593.30 2,465,704.76 346,142.22 0.00 1,610.41 4,600.00 43.20 93.60 4,065.81 3,860.48 -251.57 1,661.62 2,465,699.56 346,210.48 0.00 1,678.80 4,700.00 43.20 93.60 4,138.71 3,933.38 -255.87 1,729.94 2,465,694.36 346,278.73 0.00 1,747.20 4,800.00 43.20 93.60 4,211.61 4,006.28 -260.17 1,798.26 2,465,689.16 346,346.98 0.00 1,815.59 4,900.00 43.20 93.60 4,284.51 4,079.18 -264.47 1,866.58 2,465,683.96 346,415.23 0.00 1,883.99 5,000.00 43.20 93.60 4,357.40 4,152.07 -268.77 1,934.90 2,465,678.76 346,483.48 0.00 1,952.38 5,100.00 43.20 93.60 4,430.30 4,224.97 -273.07 2,003.22 2,465,673.56 346,551.74 0.00 2,020.78 5,200.00 43.20 93.60 4,503.20 4,297.87 -277.36 2,071.54 2,465,668.35 346,619.99 0.00 2,089.17 5,300.00 43.20 93.60 4,576.09 4,370.76 -281.66 2,139.86 2,465,663.15 346,688.24 0.00 2,157.57 5,396.58 43.20 93.60 4,646.50 4,441.17 -285.81 2,205.84 2,465,658.13 346,754.16 0.00 2,223.63 Start Dir 2°/100':5396.58'MD,4646.50'TVD 5,400.00 43.13 93.59 4,648.99 4,443.66 -285.96 2,208.18 2,465,657.95 346,756.49 2.00 2,225.96 5,500.00 41.14 93.33 4,723.14 4,517.81 -290.01 2,275.14 2,465,653.02 346,823.39 2.00 2,292.98 5,600.00 39.15 93.04 4,799.58 4,594.25 -293.59 2,339.51 2,465,648.58 346,887.70 2.00 2,357.37 5,700.00 37.16 92.73 4,878.21 4,672.88 -296.70 2,401.20 2,465,644.66 346,949.34 2.00 2,419.06 5,800.00 35.17 92.38 4,958.95 4,753.62 -299.34 2,460.15 2,465,641.24 347,008.24 2.00 2,477.95 5,900.00 33.18 92.00 5,041.67 4,836.34 -301.49 2,516.27 2,465,638.35 347,064.33 2.00 2,534.00 6,000.00 31.19 91.58 5,126.30 4,920.97 -303.17 2,569.51 2,465,635.97 347,117.54 2.00 2,587.12 6,100.00 29.19 91.64 5,212.73 5,007.40 -304.58 2,619.78 2,465,633.89 347,167.78 2.00 2,637.26 6,200.00 27.19 91.71 5,300.87 5,095.54 -305.96 2,667.00 2,465,631.88 347,214.97 2.00 2,684.37 6,300.00 25.19 91.79 5,390.59 5,185.26 -307.31 2,711.11 2,465,629.95 347,259.07 2.00 2,728.38 4/5/2017 6:58:20PM Page 4 COMPASS 5000.1 Build 81 o • Halliburton I 1.1ALLI B V •• "TON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:SRU 241-33 Company: Hilcorp Alaska,LLC TVD Reference: Initial @ 205.33usft(Saxon 169) Project: Swanson River Unit MD Reference: " -' Initial @ 205.33usft(Saxon 169) Site: SRU 21-33 North Reference: True Well: Plan:SRU 241-33 Survey Calculation Method: Minimum Curvature Wellbore: SRU 241-33 ? ` SRU 241-33 WPO7a Design: - ffi Planned Survey � �� _ F• Measured Vertical Map Map Depth Inclination Azimuth Depth TVDssF +N/-S +E/-W ':,:e' Northing Easting DLS Vert Section , (usft) (°) (°) (usft) usft (usft) (usft) (usft) -- .t,; (usft) 5,27648 6,400.00 23.19 91.88 5,481.81 5,276.48 -308.62 2,752.07 2,465,628.10 347,300.00 2.00 2,769.25 6,500.00 21.19 91.99 5,574.39 5,369.06 -309.90 2,789.82 2,465,626.32 347,337.73 2.00 2,806.93 6,509.67 21.00 92.00 5,583.41 5,378.08 -310.02 2,793.30 2,465,626.16 347,341.20 2.00 2,810.40 End Dir :6509.67'MD,5583.4V TVD 6,600.00 21.00 92.00 5,667.74 5,462.41 -311.15 2,825.65 2,465,624.60 347,373.53 0.00 2,842.69 6,608.13 21.00 92.00 5,675.33 5,470.00 -311.25 2,828.56 2,465,624.46 347,376.44 0.00 2,845.60 Tyonek 56-9 6,639.91 21.00 92.00 5,705.00 5,499.67 -311.65 2,839.95 2,465,623.91 347,387.82 0.00 2,856.96 Start Dir 2°1100':6639.91'MD,5705'TVD 6,700.00 19.80 92.17 5,761.32 5,555.99 -312.41 2,860.88 2,465,622.87 347,408.74 2.00 2,877.86 6,800.00 17.80 92.50 5,855.98 5,650.65 -313.71 2,893.08 2,465,621.14 347,440.91 2.00 2,910.02 6,900.00 15.81 92.91 5,951.71 5,746.38 -315.07 2,921.95 2,465,619.40 347,469.77 2.00 2,938.88 7,000.00 13.81 93.43 6,048.38 5,843.05 -316.48 2,947.47 2,465,617.66 347,495.26 2.00 2,964.41 7,100.00 11.82 94.13 6,145.89 5,940.56 -317.93 2,969.60 2,465,615.92 347,517.37 2.00 2,986.56 7,191.18 10.00 95.00 6,235.42 6,030.09 -319.29 2,986.80 2,465,614.33 347,534.55 2.00 3,003.81 End Dir :7191.18'MD,6235.42'TVD 7,200.00 10.00 95.00 6,244.10 6,038.77 -319.42 2,988.33 2,465,614.17 347,536.07 0.00 3,005.34 7,300.00 10.00 95.00 6,342.58 6,137.25 -320.94 3,005.62 2,465,612.43 347,553.35 0.00 3,022.71 7,330.21 10.00 95.00 6,372.33 6,167.00 -321.39 3,010.85 2,465,611.91 347,558.57 0.00 3,027.95 Tyonek 64-5(Gas Storage) 7,400.00 10.00 95.00 6,441.06 6,235.73 -322.45 3,022.92 2,465,610.69 347,570.62 0.00 3,040.07 7,500.00 10.00 95.00 6,539.54 6,334.21 -323.96 3,040.22 2,465,608.95 347,587.90 0.00 3,057.43 7,600.00 10.00 95.00 6,638.03 6,432.70 -325.48 3,057.52 2,465,607.21 347,605.18 0.00 3,074.79 7,700.00 10.00 95.00 6,736.51 6,531.18 -326.99 3,074.82 2,465,605.46 347,622.45 0.00 3,092.15 7,800.00 10.00 95.00 6,834.99 6,629.66 -328.50 3,092.12 2,465,603.72 347,639.73 0.00 3,109.52 7,900.00 10.00 95.00 6,933.47 6,728.14 -330.02 3,109.42 2,465,601.98 347,657.00 0.00 3,126.88 8,000.00 10.00 95.00 7,031.95 6,826.62 -331.53 3,126.72 2,465,600.24 347,674.28 0.00 3,144.24 8,100.00 10.00 95.00 7,130.43 6,925.10 -333.04 3,144.01 2,465,598.50 347,691.55 0.00 3,161.60 8,200.00 10.00 95.00 7,228.91 7,023.58 -334.56 3,161.31 2,465,596.75 347,708.83 0.00 3,178.97 8,266.43 10.00 95.00 7,294.33 7,089.00 -335.56 3,172.80 2,465,595.60 347,720.31 0.00 3,190.50 Tyonek 73-5 8,300.00 10.00 95.00 7,327.39 7,122.06 -336.07 3,178.61 2,465,595.01 347,726.11 0.00 3,196.33 8,400.00 10.00 95.00 7,425.87 7,220.54 -337.58 3,195.91 2,465,593.27 347,743.38 0.00 3,213.69 8,500.00 10.00 95.00 7,524.35 7,319.02 -339.10 3,213.21 2,465,591.53 347,760.66 0.00 3,231.05 8,600.00 10.00 95.00 7,622.83 7,417.50 -340.61 3,230.51 2,465,589.79 347,777.93 0.00 3,248.41 8,700.00 10.00 95.00 7,721.31 7,515.98 -342.12 3,247.81 2,465,588.04 347,795.21 0.00 3,265.78 8,800.00 10.00 95.00 7,819.79 7,614.46 -343.64 3,265.11 2,465,586.30 347,812.49 0.00 3,283.14 8,900.00 10.00 95.00 7,918.28 7,712.95 -345.15 3,282.40 2,465,584.56 347,829.76 0.00 3,300.50 9,000.00 10.00 95.00 8,016.76 7,811.43 -346.66 3,299.70 2,465,582.82 347,847.04 0.00 3,317.86 9,100.00 • 10.00 95.00 8,115.24• 7,909.91 -348.18 3,317.00 2,465,581.08 , 347,864.31 • 0.00 3,335.23 Total Depth:9100'MD 8115.24'TVD-4 1/2"x 6 1/8" 4/5/2017 6:58:20PM Page 5 COMPASS 5000.1 Build 81 • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co ordinate Reference: - Well Plan:SRU 241-33 Company: Hilcorp Alaska,LLC TVD Reference: '--34-44 Initial @ 205.33usft(Saxon 169) Project: Swanson River Unit MD Reference: Initial @ 205.33usft(Saxon 169) Site: SRU 21-33 North Reference: True Well: Plan:SRU 241-33 Survey Calculation Method: ; -Minimum Curvature Wellbore: SRU 241-33 Design: SRU 241-33 WP07a "; :, Targets Target Name . , -1, . �, , -hit/miss target Dip Angle Dip Dir. TVDC. Northing -Shape (°) (o) ., (usft) (usft) ): SRU 241-33 wp06 Tgt4 0.00 0.00 5,705.00 -300.41 2,850.98 2,465,635.00 347,399.00 -plan misses target center by 15.28usft at 6643.61 usft MD(5708.46 TVD,-311.69 N,2841.27 E) -Circle(radius 150.00) SRU 241-33 wp06 Tgt3 0.00 0.00 3,420.33 -215.19 1,067.47 2,465,743.80 345,616.90 -plan hits target center -Circle(radius 100.00) SRU 241-33 wp06 Tgt2 0.00 0.00 3,050.33 -218.13 845.17 2,465,743.80 345,394.60 -plan misses target center by 31.17usft at 3290.85usft MD(3066.29 TVD,-204.30 N,822.24 E) -Circle(radius 100.00) SRU 241-33 wp06 Tgt1 0.00 0.00 2,745.33 -194.61 604.62 2,465,770.50 345,154.40 -plan hits target center -Circle(radius 100.00) Casing Points Measured -Nii4Ift:-.2441:- Vertical :., '' ' Casing t Hole Depth Depth -. Diameter :" , Diameter (usft) ,i' I , (usft) , , e. O .. .. :(„) 2,000.00 1,976.81 7 x 8 3/4" 7 8-3/4 9,100.00 8,115.24 41/2"x61/8" 4-1/2 6-1/8 Formations 1,44.1 Measured Vertical Vertical 4 Dip Depth Depth Depth SSI ® Direction , 1 ::.- (usft) (usft) Name : (°) 3,220.79 3,008.33 Sterling B-5 0.00 2,093.58 2,061.33 Abandoned WD Sand(A8) 0.00 2,859.59 2,709.33 Sterling B-2 0.00 8,266.43 7,294.33 Tyonek 73-5 0.00 2,986.33 2,814.33 Sterling B-3 0.00 7,330.21 6,372.33 Tyonek 64-5(Gas Storage) 0.00 6,608.13 5,675.33 Tyonek 56-9 0.00 Plan Annotations ' Measured Vertical Local Coordinates r Ir: ' 'Depth Depth +N/-S +Ei-W (usft) (usft) (usft) (usft) Comment 1,200.00 1,200.00 0.00 0.00 Start Dir 3°/100':1200'MD,1200'TVD 2,296.91 2,237.59 -105.91 287.55 End Dir :2296.91'MD,2237.59'TVD 2,585.29 2,479.70 -160.06 434.57 Start Dir 3°/100':2585.29'MD,2479.7'TVD 2,902.94 2,745.33 -194.61 604.62 End Dir :2913.12'MD,2753.76'TVD 2,913.12 2,753.76 -194.89 610.32 Start Dir 3°/100':3593.96'MD,3317.09'TVD 3,593.96 3,317.09 -211.86 992.30 Start Dir 3°/100':3593.96'MD,3317.09'TVD 3,896.58 3,553.04 -221.34 1,181.05 End Dir :3896.58'MD,3553.04'TVD 5,396.58 4,646.50 -285.81 2,205.84 Start Dir 2°/100':5396.58'MD,4646.50'TVD 6,509.67 5,583.41 -310.02 2,793.30 End Dir :6509.67'MD,5583.41'TVD 6,639.91 5,705.00 -311.65 2,839.95 Start Dir 2°/100':6639.91'MD,5705'TVD 7,191.18 6,235.42 -319.29 2,986.80 End Dir :7191.18'MD,6235.42'TVD 9,100.00 8,115.24 -348.18 3,317.00 Total Depth:9100'MD 8115.24'TVD 4/5/2017 6:58:20PM Page 6 COMPASS 5000.1 Build 81 410 • Hilcorp Alaska, LLC Swanson River Unit SRU 21-33 Plan: SRU 241-33 SRU 241-33 SRU 241-33 WPO7a Sperry Drilling Services Clearance Summary Anticollision Report 24 March,2017 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: SRU 21-33-Plan:SRU 241-33-SRU 241-33-SRU 241-33 WPO7a Well Coordinates: 2,465,973.08 N,344,552.45 E(60"44'49.00"N,150'52'07.83"W) Datum Height: Initial @ 205.33usft(Saxon 169) Scan Range:0.00 to 9,100.00 usft.Measured Depth. Scan Radius is Unlimited.Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Geodetic Scale Factor Applied version: 5600.1 Build: 61 **Global Filter Was Applied(Some wells were missed w/o manual selection) Scan Type: NO GLOBAL FILTER:Using user defined selection&Merin•criteria Scan Type: 25.00 r HALLIBURTON Ai Sperry Drilling Services • • i I Hilcorp Alaska,LLC HALLI B U RTO ISI Swanson River Unit Anticollision Report for Plan: SRU 241-33-SRU 241-33 WPO7a Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design:SRU 21-33-Plan:SRU 241-33-SRU 241-33-SRU 241-33 WPO7a Scan Range:0.00 to 9,100.00 usft.Measured Depth. Scan Radius is Unlimited.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is 1,000.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft SRU 12-34 SRU 12-34-SRU 12-34-SRU 12-34 MEM 1,4111 11111.11.111 IF -496.34 8,065.14 0.754 Clearance Factor SRU 21-15 SRU 21-33 Swanson Riv Unit 211-33-SRU 211-33-SRU 211-33 203.82 52.68 203.82 51.35 204.99 39.375 Centre Distance Pass- Swanson Riv Unit 211-33-SRU 211-33-SRU 211-33 250.00 52.78 250.00 51.23 250.90 34.138 Ellipse Separation Pass- Swanson Riv Unit 211-33-SRU 211-33-SRU 211-33 500.00 68.13 500.00 65.34 493.53 24.392 Clearance Factor Pass- SWANSON RIV UNIT 21-33WD-SRU 21-33WD(aka 2 - - - IIIIII'_min i=m - SWANSONRIVUNIT 21-33WD-SRU 21-33WD(aka 2 MIMI ® Mil 1111111111= - SWANSONRIVUNIT 21-33WD-SRU 21-33WD(aka 2 ® Ir -1,263.38 ' ' 3,33111 - MEIMMII SRU 21-34 SRU 21-34-SRU 21-34-SRU 21-34 - - - - Ilird3,063.91 0.329 Clearance Factor 411. SRU 21-34-SRU 21A-34-SRU 21A-34e 11 MEM 1111111.11 MINN NOME �pce Factor -79 - IK- SRU 32-33 SRU 32-33WD-SRU 32-33WD-SRU 32-33WD - SRU 32-33WD-SRU 32-33WD-SRU 32-33WD MI - _ - I -- SRU 32-33WD-SRU 32-33WD-SRU 32-33WD SRU 34-28 SRU 34-28-SRU 34-28-SRU 34-28 4,422.96 1,478.92 4,422.96 299.09 3,915.46 1.254 Centre Distance Pass- SRU 34-28-SRU 34-28-SRU 34-28 4,500.00 1,480.14 4,500.00 298.99 3,982.10 1.253 Clearance Factor Pass- SRU 41-33 SRU 31-33(Need SHL verified)-SRU 31-33WD-SRU 3 - - 1- SRU 31-33(Need SHL verified)-SRU 31-33WD-SRU 3 MM. - - - 24 March,2017-17:09 Page 2 015 COMPASS • . Hilcorp Alaska,LLC HALL I B U RTO N Swanson River Unit Anticollision Report for Plan: SRU 241-33-SRU 241-33 WPO7a Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design:SRU 21-33-Plan:SRU 241-33-SRU 241-33-SRU 241-33 WP07 Scan Range: 0.00 to 9,100.00 usft.Measured Depth. Scan Radius is Unlimited.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is 1,000.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (ash) (usft) (usft) usft SRU 31-33(Need SHL verified)-SRU 31-33WD-SRU 3 5 54* 5: 1,121.31 - 1.111466.22 2,461.00 0.808 Centre Distance .,i FAIL- SRU 41-33WD-SRU 41-33WD-SRU 41-33WD 5459 5 904.13 - 5 95.62 3,000.00 0.452 Ellipse S,pgArgfigPAIL- SRU 41-33WD-SRU 41-33WD-SRU 41-33WD SS594 5 871.09 5 77.41 3,000.00 0.447 Clea, FAIL- SRU 41-33WD-SRU 41-33WD-SRU 41-33WD 5 116s - IIIIIhwu mmmaANUM _ 0. 1... - Swanson Riv Unit 13-27-SRU 13-27-SRU 13-27 5,530.59 479.55 5,530.59 418.50 4,609.53 7.855 Centre Distance Pass- .--� Swanson Riv Unit 13-27-SRU 13-27-SRU 13-27 5,575.00 480.49 5,575.00 418.00 4,644.46 7.690 Ellipse Separation Pass- Swanson Riv Unit 13-27-SRU 13-27-SRU 13-27 5,700.00 492.47 5,700.00 426.78 4,744.61 7.497 Clearance Factor Pass- Swanson Riv Unit 14B-27-SRU 14B-27-SRU 14B-27 5,974.33 113.73 5,974.33 41.38 5,077.00 1.572 Clearance Factor Pass- Swanson River Unit 41-33-SRU 41-33-SRU 41-33 55 MI= IM - Fr 0.041 Cent Swanson River Unit 41-33-SRU 41-33-SRU 41-33 - - - ,254.18 0.041 Clearance Factor FAIL Swanson River Unit 41-33-SRU 41-33-SRU 41-33 5 - 0.259 Ellipse Separation FAIL+i Survey tool program From To Survey/Plan Survey Tool (usft) (usft) 18.00 1,500.00 SRU 241-33 WPO7a MWD+SC+sag 1,500.00 9,100.00 SRU 241-33 WPO7a MWD+SC+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. 24 March,2017- 17:09 Page 3 of 5 COMPASS • • REFERENCE INFORMATION WELL DETAILS:Plan:SRU241-33 NAD 1927(NADCONCONUS) Alaska Zone 04 NALLIBURTON Project: Swanson River Unit Site: SRU 21-33 Ca-ordinate(WE)Reference:Well Plan:SRU 241-33,True North Ground Level: 187.33 _ Well: Plan:SRU 241-33 Venial(TVD)Reference:InOal @ 205.33usf(Saxon 189) +NGS +E/-W Northing Fasting Latioodo Longitude Sperry Oriiiing Measured Death Reference:InitialE 205.33uan(Saxon 169) 0.00 0.00 2465973.08 344552.45 60°44'48.996N 150°52'7.829W Wellbore: SRU 241-33 Calculation Method:Minimum Curvatura Plan: SRU 241-33 WPO7a SURVEY PROGRAM NO GLOBAL FILTER:Using user defined selection&filtering criteria Itil liiieOri) 18.00 To 9100.00 Date:2016-10-28T00:00:00 Validated:Yes Version: Depth From Depth To Survey/Plan Tool CASING DETAILS Ladder/S.F. Plots 18.00 1500.00 SRU 241-33WPO7a MWD+SC+gag - -- 1500.00 9100.00 SRU 241-33 WP07a MWD+SC+sag TVD TVDSS MD Size Name 1976.81 1771.48 2000.00 7 7"x 8 3/4" -__----- 8115.24 7909.91 9100.00 4-1/2 4 12"x 6 1B" 150.00 -__ .. �, I i (4 IRU 41-33.1 r I I -1 �_ I I1 II N _ { I I 111 I 11 .120.00 V I �Ilil I ! I III' -. . 1 1 I II I _. i I.� - - - I -----J -90.00 1 I SRU 1 60.00 SRU 21 33WD 'I 1i 11•1•1 1 1� I1 'i �I ,'II r i I _ _ _ _ m 1 1111.1 II I �JJ1� I I .I 1 ,) 1 l E 30.00l III�IIII'hI lip'. .. - . . _ 11. 1 ! Et..) f ilil+l U - �' l All, 111 - I 0.00 'r I I..I. , , , , I I I A , , , , V I I I 1 1 1 1 1 1 1 1 111 r 1 I 1 I j , 1 1 1 1 1 1 1 1 1 1 1 1 I I I 1 1 I I I 1 I 1 I I r 0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 Measured Depth(1200 usft/in) 4.50 IIIIIIIIIMINIIIIIIIIII I i i u_ Collision Risk Procedures R=q. c m - --- ' / If - ___ ! .... `m1 n. co 1.50 - - Collision Avoidance Req�,,,...,.` -�- _'. _ No-Go Zone-Stop Drilling I 0.00 1iii IIIII , IIIIII , IIIIIIiIIITIIII , i 1 , 1-'i 1111111111 : IIII : II II , I II , I , ii , iili , I : : : iI , I 0 650 1300 1950 2600 3250 3900 4550 5200 5850 6500 7150 7800 8450 9100 9750 10400 11050 Measured Depth(1200 usft/in) 041, tN as Y II Q1 ks U O so Lu g N F 3to WIJHI 1 t7. 2Qg8Et0 Of C NIN O IlljlCC 0 0 U) I- .%•N M n ds c1N to N O N V O M 010 Qca i N Nlr __ „ {� 0 0 41 r•NO 'ThO 5.'.� r•-• �r'7jI�;i NIM IL � ° DT . , _. .....,, l\ WI--i `�. �s�?{, (0 _._ Mc _. y 1. �.d. I N� M tv) . N. ..N. CI (.9- 1111:70 N do,' -Ag Ilk 1 x- C4 1.- •cr•• D YO -M ... MN 7 I V 4.< .. c H IN.- �► i M°o u H CO CC 0 CC 10 • OANh CO t0 LO D 11 � O Mq1.:N ! M M' O � 0 0 _._..=._____14- _ ICI tee05— N N t M 1 M Mit! i co CI �' 1 0 o h i o Min co 0 u? • / 0 co 0009- ;�OD ID ,106.11,... ' a) _ ..•• CO M ' y6 M M OOSS ....r -1/ VNIS O O 1 CC 19 '0 M \ Illi `- co I- M To in a — aN 1 co n �o W M . " 17 .. M �Mo 0 �� M O i M I— i-i m L � � �N �u)i I— U) � ,f C�c NI° to r O O N Op +r � M CeI- dl • • • • Schwartz, Guy L (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Tuesday,April 18, 2017 3:33 PM To: Schwartz, Guy L(DOA) Subject: SRU 241-33 AC concerns Attachments: RE: SRU 241-33 WPO7a Offset Well Review and Plan Forward - MOC Forms Ready for Approval; MOC_302514332.pdf; MOC 409081046.pdf;SRU_MOC_SupportingDocs.zip Guy, Attached is the supporting documentation from Halliburton that we put together covering all the offset wells. It is probably way more info than you need but there is no good way to break it out. Let me know if you need something different. Thank you! Monty M Myers Drilling Engineer Hilcorp Alaska Office:907.777.8431 Cell:907.538.1168 1 • • •S . N Y co N i I Q a y 8 ' �, 3 Z S o' p w J O n I o NC 3 3CO = NF 4y4y■aK LL Q O S N nLL 44±•11# h 0- a . ...AO cr) ill NIN O W p N ~ 00 M ^ dS � NOJ • N O • o � Ip ` O N• cc ap p" to 1 NIi • - p O O I▪ 0 M OS e-N° NM LLi u.p D 03 [0 \ LL '! MO M op = op �\ p I Q M co 0 0 .IT O �r �� O p� ��I i Y 0.._.— �pj!' I op 04 r?co Ce 16 U �� p estr _N ,III fn ;1- M�ti e U CO to 'Cr%`' _ G ! v�c„ ,_ 7p7 MMS R . I 7(O p O M c� I U p; I co H _/ .LINO i �N Ip is in CO I DH L1.. N0 U) e co `° 1 U MIND .. c. rn �, 1 0 o LY : p rn N to " 1 I p 1 p 'Min c Du? - U p M i M M co I- i co UIF" !p� MN ice' i -J a. 00 O 19 A s' ` � ,),,10./.... 1' i E i 6 M M Doss-... - NIS O i 01 Ili nQS Q COO LOM ? ..,i a r S r. F-coo W .rM COCO,c,co ..• 'Carr Ma ptt3 N eco LY D n /� C y -0 NM ~ z C p W 1 O M W0 `c v) Lh 3 cn • • • • Davies, Stephen F (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Monday, April 10, 2017 2:13 PM To: Davies, Stephen F (DOA) Subject: RE: SRU 241-33 (PTD 217-047) - Request and Questions Thanks for the questions Steve. Please see responses in red below. Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell: 907.538.1168 From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Monday, April 10, 2017 11:39 AM To: Monty Myers<mmyers@hilcorp.com> Subject: SRU 241-33 (PTD 217-047) - Request and Questions Monty,The well will penetrate the 64-5 reservoir and the current pressure gradient is 8.89ppg. Since proposed well SRU 241-33 is a deviated well, please ensure that directional survey data are recorded in accordance with the requirements of 20 AAC 25.050. We will be sure to comply with the regulation and have surveys a minimum of every 100' in accordance with 20 AAC 25.050(c)(1) Will SRU 241-33 penetrate any gas storage reservoirs within the Swanson River Unit? Yes,we will penetrate the Tyonek 64-5 reservoir at depth 7432'TMD If so, what are the current pressures of those reservoirs? The current pressure is at 8.89 ppg EMW The Planned Wellbore Schematic on page 6 of the Drilling Procedure indicates that cement will be placed across the entire production interval,from TD to surface casing shoe. Page 36 specifies that a cement bond log will be run across the production hole interval. In the event that cement does not cover the entire production interval to the surface casing shoe, what remedial actions will Hilcorp take to ensure that migration of fluids and/or gas does not occur from any reservoir? in the event that bond log shows little or no cement, Hilcorp will perforate and squeeze the interval in question to isolate any migration of fluids. A water activated swell packer will also be placed in the casing string and reside inside the surface shoe at approximately 1500'to isolate the annulus from formation fluids. Thanks, 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.gov. 1 • • • • SRU 241-33 (PTD 217-047) LANDOWNERSHIP (BIM ACRES WEBSITE) Or: /C 25/ 28 27 2-40 00 --59C% i-^-4 o.co 1-160.00 33 34 .24,..,2747/ r oke • S . Case Abstract for: AKA 028399 LEASE STATUS CURRENT AS OF 02/11/2013 LEASE RTI: HILCORP: 100% ENTIRE LEASE GEOGRAPHIC NAMES SWANSON RIVER UNIT LAND DESCRIPTION Mr Twp Rng Sec Aliquot Survey ID Tr Blk Lot IDi Bor NR LS Acres View MTP 28 008 N 009 W 028 -- 1 04 122 07 Al 360.0000 MTP TWPLAT HI TWPALL Doc ID: 08-Aug-195& 28 008 N 009 W 028 -- -- 1-- 2 04 122 07 Al 280.0000 MTP TWPLAT HI TWPALL Doc ID: 08-Aug-1956 28 008 N 009 W 029 -- 04 122 07 1AI 1 19.9600 M71)TWPLAT HI TWPALL Doc ID: 01-Sep-1956 28 008 N 009 W 029 -- 1041 122 07 Al 620.0400 MTP TWPLAT HI TWPALL Doc ID: 08-Aug-1956 28 008 N 009 W 033 -- 1-- -- 04 122 07 1AI 1 9.4100 MTP TWPLAT HI TWPALL Doc ID: 08-Aug-1956 28 008 N 009 W 033 -- -- 1-- 1 04 122 07 Al 1 150.5900 MTP TWPLAT HI TWPALL Doc ID: 08-Aug-1956 28 008 N 009 W 033 -- -- 1-- 1 04 122 07 1AI I 80.0000 MTP TWPLAT HI TWPALL Doc ID: 08-Aug-1956 28 1008 N 009 W 033 -- 1 104 1 122 07 Al 160.0000 MTP TWPLAT HI TWPALL Doc ID: 08-Aug-1956 28 008 N 009 W 033 -- 1 04 122 07 Al 40.0000 MTP TWPLAT HI TWPALL Doc ID: 08-Aug-1956 28 008 N 009 W 033 -- -- 2 1041 122 07 Al 40.0000 MTP TWPLAT HI TWPALL Doc ID: 08-Aug-1956 Total Case Acres: 1,760.0000 CASE ACRES ANALYSIS Adjudicated: 1,760.0000 Total: 1,760.0000 ---- __ Authorization Issued: 1760.0000 Total: 1760.0000 • • • • Case Abstract for:AKA 028406 LEASE STATUS CURRENT AS OF 02/11/2013 LEASE RTI: HILCORP: 100%ENTIRE LEASE GEOGRAPHIC NAMES SWANSON RIVER UNIT LAND DESCRIPTION Mr Twp Rng Sec Aliquot Survey ID Tr Bik Lot Di Bor NR LS Acres View MTP 28 008 N 009 W 015 W2 1041 122 07 Al 320.0000 MTP TWPLAT HI TWPALL Doc ID: 08-Aug-1956 28 008 N 009 W 022 -- -- 1 04 122 07 AI 40,0000 MTP TWPLAT HI TWPALL Doc ID: 08-Aug-1956 28 008 N 009 W 022 -- H-- 2 041 122 07 AI 600.0000 MTP TWPLAT HI TWPALL Doc ID: 08-Aug-1956 28 1 008 N 009 W 026 -- -- 1-- -- 04 122 07 Al 8.9300 MTP TWPLAT HI TWPALL Doc ID: 08-Auq-1956 28 008 N 009 W 026 N2 -- -- 04 122 07 AI 311.0700 MTP TWPLAT HI TWPALL Doc ID: 08-Aug-1956 28 008 N 009 W 026 SW -- 04 122 07 AI 160,0000 MTP TWPLAT HI TWPALL Doc ID: 08-Aug-1956 28 008 N 009 W 027 -- -- 1-- 1-- 1 04 122 07 AI 560.0000 MTP TWPLAT HI TWPALL Doc ID: 08-Aug-1956 28 1008 N 1 009 W 027 -- -- -- -- 2 04 122 07 AI 80.0000 MTP TWPLAT HII TWPALL Doc ID: 08-Aug-1956 28 008 N 009 W 034 -- -- -- -- 1 04 122 07 AI 80.0000 MTP TWPLAT NI TWPALL Doc ID: 08-Auq-1956 28 008 N 009 W 034 -- -- -- -- 2 1041 122 07 AI 240.0000 MTP TWPLAT HI TWPALL Doc ID: 08-Auq-1956 Total Case Acres: 2,400.0000 CASE ACRES ANALYSIS Adjudicated: 2,400.0000 Total: 2,400.0000 � I Authorization Issued: 2400.0000 Total: 2400.0000 • • • • TRANSMITTAL LETTER CHECKLIST WELL NAME: /��t- -S C r r PTD: 2/7- -) 67.7 1.//Development _Service _Exploratory _ Z�' P Strati a hic Test Non-Conventional FIELD: . ,„5.1,„t ac's/ 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(dX2)(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 • • • • I 0) 0 o CD 0) p y fp N OG a) N c a) O-0 c O o w. 0. . , . , , , , I d-0tt CL 0 al O L 14 O wm 3 , a ar 0, 3 (55' o d 0 o. > y, o. o Q ami _ '0' O' y f0 U co-'- , o -o c rn w, 4 0, a c c �, y, a, 0 F- E U T.E p c > o. -, o es, d c d 3. . . . a ' cm o b -o w 0 o pNa .o U _, , N a) 0 c< 0 0 o ° ° , V, m. t v 0 o 0 co , 0. E Cu a, U, U, . (n0. .N 3. . •f6. - . . . . d U' C) a) 0. a) a) o) c = p. p, d c c 0. > 2, m, ,, '3 �', �, E, . �. 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N 7 E QJ Nc O O O c o L an o a 0 WDEIa O J Q S a Q Q u") w Q 0 0 Q C/) SRU 241-33 50-133-20663-00-00 Swanson River Unit Kenai Peninsula Borough, Alaska July 2, 2017 – July 17, 2017 Provided by: Approved by: Jacob Dunston Compiled by: Marquel Mosebay Britten Adams Eric Andrews Distribution Date: Aug 14, 2017 SRU 241-33 2 TABLE OF CONTENTS 1 MUDLOGGING EQUIPMENT & CREW ................................................................................................ 3 1.1 Equipment Summary ...................................................................................................................... 3 1.2 Crew................................................................................................................................................ 3 2 GENERAL WELL DETAILS ................................................................................................................... 4 2.1 Well Objectives ............................................................................................................................... 4 2.2 Hole Data ........................................................................................................................................ 5 2.3 Daily Activity Summary ................................................................................................................... 5 3 GEOLOGICAL DATA ............................................................................................................................. 7 3.1 Lithostratigraphy ............................................................................................................................. 7 3.2 Lithology Details ............................................................................................................................. 8 3.3 Sampling Program ........................................................................................................................ 19 4 DRILLING DATA .................................................................................................................................. 20 4.1 Surveys ......................................................................................................................................... 20 4.2 Bit Record ..................................................................................................................................... 24 4.3 Mud Record .................................................................................................................................. 25 4.4. Drilling Progress ........................................................................................................................... 26 5 SHOW REPORTS ............................................................................................................................... 27 6 DAILY REPORTS ................................................................................................................................ 28 Enclosures 2” / 100’ Formation Log (MD/TVD) 5” / 100’ Formation Log (MD/TVD) 2” / 100’ LWD Combo Log (MD/TVD) 2” / 100’ Drilling Dynamics Log (MD/TVD) 2” / 100’ Gas Ratio Log (MD/TVD) Final Data CD SRU 241-33 3 1 MUDLOGGING EQUIPMENT & CREW 1.1 Equipment Summary Parameter Equipment Type /Position Total Downtime Comments Computers – Surface Logging (3) Rigwatch Server, Rigwatch Remote DML, LWD WITS, Rigwatch Remote 0 Ditch gas QGM gas trap; Flame ionization total gas & chromatography. Hook Load / Weight on bit WITS from Pason Mud Flow In Calculated value derived from Strokes/Minute and Pump Output 0 Mud Flow Out WITS from Pason “ Pit Volumes, Pit Gain/Loss WITS from Pason “ Pump Pressure WITS from Pason “ Pump Stroke Counters (2) WITS from Pason “ Rate of Penetration Calculated from Pason “ RPM WITS from Pason “ Torque WITS from Pason “ WITS To/ From Pason Rigwatch Remote (HP Compaq) 1.2 Crew Mud Logging Unit Type: Arctic Mud Logging Unit Number: ML038 Logging Geologists Years1 Days2 Sample Catchers/Loggers Years Days2 Marquel Mosebay 18 13 Leigh Ann Rasher 6 11 Britten Adams 5 22 Jacob Robertson 4 6 Eric Andrews 5 20 *1 Years’ experience as Mudlogger *2 Days at wellsite between rig up and rig down of logging unit. SRU 241-33 4 2 GENERAL WELL DETAILS 2.1 Well Objectives SRU 241-33 is an S-shaped directional grassroots development well to be drilled off of the SRU 21-33 pad. Subsurface modeling and seismic interpretation, along with production data, indicates that there is remaining gas reserves stranded in the Sterling and Tyonek sands. This well will be targeting PUD reserves in the Sterling sands. These existing reserves are not recoverable in existing wellbores due to lack of take points or mechanical condition of other exiting wellbores. Drill a 9100’ MD grass roots well at Swanson River Field that will target booked reserves in Tyonek 56-9 and Sterling B-2, 3, and 5 sands. Secondary targets include the Tyonek 73-5 and 75-7 sands. The base plan is a directional wellbore with a kickoff point at 383’ MD. Maximum hole angle will be 43.20°. TD of the well will be 9100’ MD/ 8115.24’ TVD, ending at 10° inclination. The vertical section will be 3335.23’. Operator: HILCORP ALASKA, LLC Well Name: SRU 241-33 Field: Swanson River Unit County: Kenai Peninsula Borough State: Alaska Company Representatives: Rance Pederson, Robert Wall , Clint Montague, Adam Dorr Location: Surface Coordinates 502’ FNL, 2147’ FWL, Sec 33, T8N, R9W, SM, AK Ground ( Pad ) Elevation 187.3’ AMSL Rotary Table Elevation 18’ RKB – 205.3’ AMSL Classification: Development – Gas API #: 50-133-20663-00-00 Permit #: 217-047 Rig Name/Type: Saxon 169 / Land / Double Spud Date July 3, 2017 Total Depth Date: July 17, 2017 Total Depth 8630’ MD Primary Targets Tyonek 56-9 6734’MD/ 5675’TVD, Sterling B-2 2873’MD/ 2709’TVD, Sterling B-3 3030’MD/ 2814’TVD, Sterling B-5 3318’MD/ 3008’TVD. Total Depth Formation: Tyonek Completion Status: 4 1/2” Casing LWD-MWD Services. Halliburton / Sperry Drilling Services Directional Drilling Halliburton / Sperry Drilling Services Drilling Fluids Service Halliburton / Baroid Wireline Logging Service Schlumberger SRU 241-33 5 2.2 Hole Data 2.3 Daily Activity Summary July 2, 2017: Rig up mudlogging unit, prepare pits, catwalk, rig floor, drawworks, top drive, function text equipment, calibrate Canrig equipment for Canrig, continue to Rig up and prepare for drilling ahead new footage, P/U Jars, rack back in derrick, Stage directional BHA on catwalk while tallying in pason, building spud mud, stag BHA in hole, Strapping pipe, building spud mud, P/U DP & HWDP, PJSM with crew and 3rd party personnel on spudding in hole, Prepare to drill ahead at report time. July 3, 2017: Circulate water out hole & condition spud mud, Drill ahead from 125’ to 280’, Wash and Ream from 280’, Rack back flex collars in derrick, pulled out of the hole, pick up smart tools. Ran back into the hole to 280’ and drilled ahead to 370’, Drill ahead from 370 to 890’, SPR, Drill ahead to 991’. Pump HI-VIS sweep & circulate out, 100% increase in cuttings, Wash and Ream from 991’ to 312', Service Rig, Level Derrick, change shaker screens, R.I.H from 312' to 991', Washed last stand (No fill), pump HI-VIS sweep, Drill ahead from 991'. July 4, 2017: Circulate at 991’, Pump HI-VIS sweep with 80% increase in cuttings @ 991’, Drill ahead from 991’ to 1400’, Drill to 1485’, pump sweep and circulate hole clean, increase in cutting, POOH from 1490’ to 278’, Service Rig, Trip in Hole to 1490’, Wash last stand down, Drill ahead to 2014’ 7” Csg TD, Circulate sweep, monitor well, well static dropped 2 inches in 10 minutes, POOH from 2014’ to 314’(No issues), RIH from 314’ to 2014’, Circulate, pump sweep, Max wiper gas 10u, Circulate out with 20% increase in cuttings, sweep on time, POOH for 7” Casing. July 5, 2017: Continue to POOH, L/D BHA, Lay down directional BHA, PJSM on radio active source, remove source, down load LWD Data, Service Rig and bushing, Run dummy hanger joint, Rig up Casing crew, Run Casing, Rig down casing crew, Rig up cement crew, Cement 7” Casing string, Rig down Halliburton cementers, Nipple down conductor, Install well head, Test Void. July 6, 2017: Continue to nipple down conductor, Install BOPE, Hook up gas buster line to catwalk, clean mud tanks, Build KCL mud system, Nipple up Stack, Continue to nipple up Rig, and prepare Rig for drilling 6 1/8” Hole, Install wear bushing, Pick up drill pipe, POOH and rack back DP in derrick, TEST BOPE. July 7, 2017: Continue to TEST BOPE, Retest when needed, Blow down choke manifold, Complete BOPE testing, Pick up and rack back DP in Derrick. July 8, 2017: Pick up and rack back DP in Derrick, Continue to pick up DP, P/U smart tools, Scribe motor, P/U HWDP, P/U Drill pipe, Drill cement, tag float collar @ 1918', Tag shoe @ 2004', Drill ahead to 2034', Circulate clean, Displace spud mud with 6%KCL mud, Clean possum belly, Continue to circulate 3 bottoms up on new mud, FIT Test to 12.5 EMW @ 360psi, Drill ahead from 2034' at report time. July 9, 2017: Continue to drill ahead to 2779’, Circulate sweep 15% increase in cuttings, wipe hole to 1972’, flow check, static, NO issues coming out of hole, Service Rig, Trip back in hole with NO issues, Max wiper gas 10u, Drill ahead from 2279’ to 3184’, pump sweep @ 2792’ 10% cuttings, Continue to drill ahead to 3523’, Circulate sweep, wipe hole from 3523’ at report time. Hole Section Max Depth TD Formation MW ppg Dev oinc Csg Dia Shoe Depth LOT ppg MD (ft) TVD (ft) MD (ft) TVD (ft) 8 1/2” 2014’ 1994.3’ Sterling 9.10 21.21 7 “ 2004’ 1984.9’ 12.4 6 1/8” 8630’ 7677’ Tyonek 9.8 3.58 4 ½” 8630’ 7776’ NA SRU 241-33 6 July 10, 2017: Wipe hole to 2658', R.I.H to 3523', NO issues, Max wiper gas 8u, Drill ahead from 3523', Continue to drill ahead to 4217', pump sweep and circulate out with 20% increase in cuttings, monitor will, Wipe hole from 4517', to 4250' pulled 20K over, Wash & ream from 4250' to 3460', R.I.H. at report time July 11, 2017: Continue to run in the hole from Wiper Trip at 4517’, wash lost stand down, Max wiper gas 7u, Drill ahead from 4517’, Continue to drill ahead at report time. July 12, 2017: Drill ahead from 5351' to 5516', pump sweep and circulate. Pull out of the hole on elevators from 5516’ to 1970’ for wiper trip. Service rig, run back into the hole from 1970’ to 5516’ and pump sweep. Drill ahead from 5516’ to 5824’. July 13, 2017: Continued drilling from 5824' to 6514', pumped a high viscosity sweep and circulated hole clean before pulling for a wiper trip. Pulled out of hole from 6514’ to 5496’, serviced rig, circulated bottoms up, and started running back in hole from 5496’ to 6514’. Continued drilling ahead from 6514’ to 6589’. July 14, 2017: Continued drilling ahead from 6589' to 7227’. July 15, 2017: Continued drilling from 7227' to 7512', pumped a sweep, took a survey, and circulated hole. Max gas from circulating bottoms up rose to 2228 units; performed flow check. Circulated mud and weighted up active system from 9.2ppg to 9.4 ppg and then to 9.6ppg; when flow check max gas was 30 units of gas. Pulled out of the hole from 7512’ to 6450’, for wiper trip. Serviced rig, and ran back into the hole from 6450’ to 7512’. Circulated a bottoms up with 1964 units. Continued drilling ahead from 7512’ to 7737’. July 16, 2017: Continued drilling ahead from 7737' to 8247’. Note: After connections we are seeing coal caving and correlating gas peaks. Max gas 2349u. July 17, 2017: Continued drilling ahead from 8247' to 8605’, picked up and circulated due to high has. Weighted up mud while trying to maintain ECD. Drilled ahead from 8605' to 8630, and called TD. Continued circulating and weighting up mud from 9.8 ppg to 11.7 ppg. July 18, 2017: Continued circulating and weighting up mud from 11.7 ppg to 12.4 ppg. Wiped hole from 8630’ to 8257’; with no issues, and run back into the hole from 8257’ to 8630’. Performed a flow check and then began pulling out of the hole from 8630’ to 4274’. July 19, 2017: Continued pulling out of the hole from 4274' to BHA, laid down directional BHA, removed active sources, and downloaded data. Prepared for and performed BOP test. Rigged up and ran in hole with clean out BHA from 65' to 1980', slip and cut drill line, and continued running in hole from 1980' to 3734'. July 20, 2017: Proceeded running into the hole from 3734’ to 8630’, circulated, conditioned mud, and began pulling out of the hole. Pulled out of the hole from 8630’ to 7966’, and laid down drill pipe from 7966’ to 1977’. Rigged up Wire line and ran into the hole with Gyro tool to take surveys. July 21, 2017: Rigged down wireline, laid down drill pipe from 1977' to 375', and ran in hole out of the derrick from 375' to 1619’. Laid down drill pipe from 1619' to 375' and proceeded to lay down heavy weight drill pipe from 375' to BHA. Laid down BHA, rigged up for casing, and began running casing from shoe to 7121’. SRU 241-33 7 3 GEOLOGICAL DATA 3.1 Lithostratigraphy Tops picked by Hilcorp Geo, Jacob Dunston FORMATION PROGNOSED ACTUAL MD (ft) TVD (ft) SSTVD (ft) MD (ft) TVD (ft) SSTVD (ft) Primary Sterling B-2 2873 2709 -2504 2,901 2,753 -2,548 Sterling B-3 3030 2814 -2609 3,014 2,848 -2,643 Sterling B-5 3318 3008 -2803 3,265 3,057 -2,852 T 56-9 6734 5675 -5470 6,657 5,740 -5,535 Secondary T 73-5 8354 7294 -7089 8,278 7,328 -7,123 SRU 241-33 8 3.2 Lithology Details As per Hilcorp direction, a Canrig/NDS-provided full service mudlogging program, with lithology descriptions of interval-collected rock cuttings samples in the Sterling and Tyonek Formations, was initiated at the 6 1/8” production interval at 2000’. The Kenai Group formations of Alaska’s Cook Inlet Basin, which include the Sterling, Beluga and Tyonek were deposited in a variable-energy fluvial system within a large closed fore-arc basin. The stratigraphic column consists of very dominant thin to massive sections of sandstone and claystone-siltstone, which are interrupted by extensively-distributed thinner zones of coal and carbonaceous rocks, locally to generally abundant thin layers of original and re-deposited volcanic ash, and minor beds of basal or modal conglomerate. Gradational upward-fining sequences and bi-modal zones are abundant within the sandstones. Stratovolcanoes, perpetually forming along the fore-arc’s margins; produced abundant widely-distributed deposits of vitric air fall volcanic ash; which became a major directly-derived source, and/or a consistent lithogenic influence, for all Tertiary soft-sediment rocks in the Cook Inlet Basin. Note that the special modifying term “tuffaceous” in Canrig/NDS Lithology Descriptions was created to address the diversity of volcanic-origin rocks in the Cook Inlet basin, and its use may include everything from discernible micro-shard concentrations of disaggregated volcanic glass to rare layers of vitric ignimbrite. Sand (2014' - 2075') = medium dark gray siliciclastic material; light gray feldspars with clear quartz grains common soft pinkish volcanic debris; sand grains are individual grains range from clear to translucent quartz grains grayish, clear, orangish, green, to dark gray dominantly lower fine to upper fine floating sand grains; subrounded to angular grains; moderately sorted with moderate to high sphericity; submature with visible impact abrasion features; overall non calcareous. Tuffaceous Claystone (2075' - 2100') = medium dark gray; faint olive hue; crumbly to very soft; trace carbonaceous shale fragments from thin beds; becoming massive; dull earthy luster; smooth clayey texture; non calcareous. Tuffaceous Siltstone (2100' - 2150') = uniform olive gray with brownish hue; crunchy; irregular fragments; gritty to silty texture; massive subblocky interval; dull earthy luster; no visible structure; com dark black streaks insitu cuttings; increase in mushy clays; no visible sample fluorescence. Sand (2165' - 2205') = variable sediment medium dark gray to light gray, clear, black; abundant light gray feldspars etched clear quartz grains; scattered reddish volcanic debris; individual sand subround to subangular; loose unconsolidated lithics; upper fine to lower medium; well sorted; noncalcareous lithic sands. Sand (2205' - 2280') = medium light gray clear; opaque; greenish gray; black, red to pinkish volcanics; loose unconsolidated sands interbed in very mushy clay ric h sandy material; gummy sticky clayey; adhesive to sticky; appears as clumpy c lay with interstitial sands; dominantly lower very fine to upper very fine grains floating in mushy clay material; disseminated sands, very well sorted; well rounded; clays commonly light gray; noncalcareous. Sand (2280' - 2330') = light gray, off white; clear to opaque; peppered black; greenish glauconitic clast and trace volcanics; commonly appears as loose unconsolidated sands; upper fine to lower medium; subrounded clast with etched surfaces; evident lithic sand sediments; noncalcaeous; no sample fluorescence; interbeded dark brownish black carbonaceous shale at 2320'; firm to indurated mudstone; visible clayey texture with wedgelike to tabular features along fresh breaks. SRU 241-33 9 Tuffaceous Claystone (2350' - 2380') = medium dark gray to light gray; repeat lithology; mushy to soft; adhesive clayey material; crumbly; Dull earthy luster; massive habit; smooth clayey texture; occasional grading to siltstone with very fine silty size particles suspended in mushy hydrated clay; no visible structure laminae; no petro odor or sample fluorescence. Sand (2380' - 2460') = medium to light gray, opaque, clear; peppered black to dark gray; orange, green; loose unconsolidated sands; lower to upper fine grains; felsic with quartz framework; mod to well sorted; mod sphericity; common etched surfaces; glauconite mineral clast; occasional mushy clays intercalated through sand interval; overall noncalcareous. Limestone (2485') = very thin layer of dense, moderate yellowish brown carbonate; irregular fragments; tabular frosted, sucrosic texture; flaky to bladed breaks; pinpoint reaction to HCL. Generally small fragments within predominate sand interval. Lignite Coal (2530' - 2575') = dusky yellowish brown to grayish brown colors; crunchy to brittle with occasional dense; hackly to splintery fracture; wedgelike to tabular with bladed edges cutting habits; matte to sucrosic texture; thin layer bedding structure; No fluorescence color; weak HCL reaction in bulk sample; no hydrocarbon indictors. Sand (2585' - 2650') = translucent to cloudy white dominate with grayish blue green hues, light green hues, light gray hues, light bluish gray hues, moderate reddish pink hues colors; quartz and feldspar dominate with occasional micas, orthoclase, and lithics framework; fine to medium grain size; fair sorting; Sub-angular to angular angularity; low to very low sphericity; impact to grind mechanical abrasion; unconsolidated sands; massive to bedding structure; no fluorescence color in sample; no Hydrocarbon indicators in full sample. Tuff (2660' - 2670') = creamy white to grayish yellow colors; adhesive clay properties; pasty to mushy consistency; malleable tenacity; earthy to irregular fracture; nodular cutting habits; waxy to earthy luster; smooth to slight silty texture; thin to soft sediment deformation bedding structure; light yellowish green color under fluorescence light on tuff; hydrocarbon indictors; no HCL reaction on tuff, but moderate HCL in bulk sample. Siltstone (2725' - 2775') = yellowish gray to pale yellowish brown with occasional slight olive gray and creamy white hues colors; crumbly to sectile tenacity; earthy to blocky fracture; wedgelike to platy cutting habits; waxy when wet luster; silty to colloidal texture; thick bedding structure with interbedded coal thin layers; weak HCL reaction in bulk sample; no color fluorescence in bulk sample. Tuffaceous Claystone (2785' - 2830') = white to slight pale yellowish white colors; clotted to pasty consistency; pulverulent to malleable tenacity; irregular fracture; nodular to round cutting habits; dull to earthy luster; clayey to smooth texture; soft sediment deformation bedding structure; no HCL reaction; no fluorescence color; no hydrocarbon indictors. Sand (2840' - 2910') = translucent to clear with occasional cloudy light gray hues, light pale yellow hues, and light to dark bluish green hue colors; unconsolidated sands quartz and feldspar dominated with occasional lithics, mica, tuff, and calcareous minerals; upper fine to lower coarse grain sizes; poor sorting; subangular to angular; low sphericity; thick bedding structure; weak HCL reaction in bulk sample; no fluorescence color or residual fluorescence cut color no hydrocarbon indictors. Tuffaceous Claystone (2920' - 2980') = white to light grayish white with occasional pale brownish yellow hues; expansive clay properties; clotted to mushy consistency; malleable tenacit y; nodular cutting habits; irregular fractures; clayey texture; large to massive bedding structure; moderate HCL reaction bulk sample; no fluorescence cut colors or residual cut color and no residual white light color; no hydrocarbon indictors. SRU 241-33 10 Sand (2990' - 3070') = clear to translucent with occasional white to creamy hues, pale bluish green hues, reddish pink hues, and grayish yellow hues colors; quartz to feldspar dominated with lithics and calcareous minerals framework; low fine to upper medium grain size; fair to poor sorting; subrounded to subangular angularity; low to moderate sphericity; unconsolidated sands; moderate HCL reaction in bulk sample; no oil odor, no fluorescence color; no fluorescence cut color; no residual color in white light; no residual fluorescence cut colors; no hydrocarbon indictors in bulk samples. Tuffaceous Claystone (3080' - 3140') = white to milky white with slight pale grayish hues colors; cohesive clay properties; lumpy to mushy consistency; malleable tenacity; irregular fractures; massive nodular cutting habits; dull to waxy luster; clayey to smooth texture; thick to soft sediment deformation bedding structure; no oil odor; no fluorescence colors; no fluorescence cut colors; no residual white light colors; no residual fluorescence colors; no hydrocarbon indictors in sample. Sand (3140' - 3200') = clear to translucent with occasional white to creamy hues, pale bluish green hues, reddish pink hues, and grayish yellow hues colors; quartz to feldspar dominated with lithics and calcareous minerals framework; low fine to upper medium grain size; fair to poor sorting; subrounded to subangular angularity; no visible sample or cut fluorescence. Tuffaceous Claystone (3200' - 3260') = dark greenish gray to olive gray; crumbly, soft, sectile; subblocky; massive interval; dull earthy luster; nodules overall intact with common very fine smooth clayey texture; low density; moderate to easily soluble; noncalcareous; common volcanic clast suspended in claystone cuttings. Sand/ Tuffaceous Sandstone (3200' - 3335') = off white to medium light gray loose unconsolidated sands dominantly light to dark gray; opaque; clear quartz grains; trace peppered black lithic sediments and orangish volcanic debris; felsic framework; upper fine to lower medium fine grains; subround to sub angular; moderate sphericity; common abrasive etched surfaces; at 3300' - 3320' increase in clay rich friable sandstone; clay matrix; with variable siliciclastic fragments suspended in epimatrix; no petroleum odor; no sample fluorescence, no fluorescent cut, visible cut, or C-5 heavy hydrocarbon indicators. Sand (3235' - 3380') = medium dark gray to light gray, clear, off white, opaque dark gray; peppered black lithic sediments; commonly appears as loose unconsolidated sands; felsic framework upper fine to lower medium fine grains; individual sand clast reworked with subtle etched surfaces; subrounded; moderate sphericity; sands commonly fused with amorphous clays; tuffaceous sandstone with clay matrix; very soluble matrix; no oil indicators present. Tuffaceous Sandstone (3410' - 3470') = overall medium gray; variable colors felsic framework; lower medium coarse sand grains; subround to subangular moderate sphericity; scattered tuffaceous sandstone with clay matrix; soft to friable sandstone; clumpy appearance trace yellowish orange volcanic clast floating in matrix; loose reddish orange volcanic clast floating throughout sample at depth. Sand (3470' - 3520') = medium dark gray to light gray; clear, translucent to transparent; black; greenish gray; common pale yellow crunchy, firm tuffaceous ash; predominate sands loose unconsolidated; upper medium coarse sands; subround to subangular. Moderate sorting; moderate to low sphericity; no sample fluorescence, no petroleum or odor or any other oil indicators present. Tuffaceous Sandstone (3520' - 3580') = predominate medium light gray to light gray; felsic framework with scattered clear quartz grains; dominantly opaque light gray feldspar grain clast; trace pink orthoclase clast; reddish orange volcanic debris; silic sand sample appearance continues as a loose unconsolidated range of sediments; commonly loose sands and clay; variable colors and composed of igneous derived sediments; individual grains subround to subangular; mod sphericity; common clay material from remnant matrix; no visible sample fluorescence, no cut fluorescence or residual cut. SRU 241-33 11 Siltstone (3610' - 3638') = brownish black to dark olive gray; crumbly to soft; irregular cuttings with rounded edges; massive habit; dull earthy luster gritty with silty clayey texture; thin micro bedding planes; no oil present. Tuffaceous Claystone (3640' - 3700') = olive gray to dark brownish black with increased silty composition; firm to crumbly with abundant amorphous clayey m aterial; easily soluble; reduced loose sands with depth; overall dull earthy luster; smooth clayey texture; grading to silts with slight greenish hue when clayey; no visible structure; no sample fluorescence or any other oil indicators. Tuffaceous Sandstone (3720' - 3760') = white to cream milk white with clear to translucent mineral colors; quartz to feldspar dominated with occasional lithics framework; coarse to medium grain size; fair to poor sorting; subrounded angularity; moderate to low sphericity; consolidated sand with soft to easy friable hardness; silica to tuff cement grain support; floating fabric; thick bedding structure; very weak HCL reaction in bulk sample; no hydrocarbon indicators in bulk sample. Tuffaceous Claystone (3805' - 3870') = grayish white to slight yellowish gray with occasional pale bluish white hue colors; expansive to cohesive clay properties; clotted to lumpy consistency; malleable to pulverulent tenacity; irregular fracture; nodular to cutting habits; waxy when wet and earthy to dull when dry luster; smooth to clayey texture; thick bedding structure; no oil odor in bulk samples; no fluorescence colors; no fluorescence cut colors; no residual colors; no indictors of hydrocarbon in sample. Coal (3890' - 3910') = dusky brown to grayish black with occasional olive brown hues colors; tough to brittle tenacity; splintery to hackly; tabular to wedgelike cutting habits; frosted when wet luster; abrasive to matte texture; thin to slight fissile bedding structure; no oil indictors. Sandstone (3925' -3995') = clear to translucent with bluish green hues, and light grayish hues colors; quartz dominate with lithics and calcite minerals framework; very fine to upper medium grain size; poor to fair sorting; subrounded to angular angularity; low to moderate sphericity; consolidated sand with firm friable to hard hardness; grain enlargement and calcareous cement; occasional suture fabric; large bedding structure; no oil odor; no fluorescence colors; no fluorescence cut colors; no residual color or cut; no hydrocarbon indictors. Tuffaceous Claystone (4005' - 4065') = creamy milk white to white with pale grayish white hues colors; expansive to cohesive clay properties; lumpy to clotted and pasty consistency; malleable tenacity; irregular fracture; massive to nodular cutting habits; waxy to earthy luster; smooth to clayey texture; thick soft sediment deformation bedding structure; no fluorescence cut colors; no fluorescence colors; no residual cut colors; no hydrocarbon indictors in bulk sample. Tuffaceous Claystone (4075' - 4140') = grayish white to slight yellowish gray with occasional pale yellow gray hue colors; expansive to cohesive clay properties; clotted to mushy consistency; malleable to pulverulent tenacity; irregular fracture; nodular to cutting habits; waxy when wet and earthy to dull when dry luster; smooth to clayey texture; thick bedding structure; no oil odor in bulk samples; no fluorescence colors; no fluorescence cut color; no residual colors; no indictors of hydrocarbon in sample. Sand (4150' - 4215') = translucent to clear with smokey gray hues, cloudy white hues, and pale yellowish hues colors; quartz and feldspar dominated with black lithic and calcareous mineral framework; upper fine to medium grain size; fair to poor sorting, subangular to angular angularity; low sphericity; unconsolidated sands; thin layers of bedding; moderate HCL reaction in bulk sample; no fluorescence colors or cut colors in bulk sample; no oil odor in bulk sample; no hydrocarbon indictors in bulk sample. Tuffaceous Siltstone (4225 - 4280') = pale green to light bluish green color; malleable to sectile tenacity; earthy fracture; elongated to wedgelike cutting habits; frosted to waxy luster when wet; matte to silty with SRU 241-33 12 slight gritty texture; thin bedding structure; no fluorescence colors; no fluorescence cut colors; no oil odor; no residual cut color in white light; no fluorescence residual cut colors; no oil indictors in bulk sample. Coal/Carbonaceous Shale (4290' - 4345') = dark brown to black brown and with occasional light olive brown hues color; tough to crunchy tenacity; splintery to hackly; bladed edges with wedgelike cutting habits; frosted greasy when wet luster; matte to abrasive texture; thin laminae bedding structure; no fluorescence in bulk sample; no fluorescence cut color; no streamers; no oil odor; no residual colors; no oil indictors in full sample. Sand (4355' - 4410') = clear to cloudy white with light gray hues, bluish hues; greenish blue hues, and pale yellowish gray hues colors; unconsolidated sands with quartz/feldspar dominate and lithics; fine to medium grain size; poor sorting; subangular angularity; low sphericity; thick to thin bedding structure; no fluorescence colors; no fluorescence cut colors; no hydrocarbon odor in bulk sample; no hydrocarbon indictors in bulk sample. Tuffaceous Claystone/Siltstone (4410' - 4450') = light gray to very light gray with slight yellowish gray hues; soft amorphous, shapeless globular cuttings; hydrated soft mushy material; hydrophilic; slight to moderate expansive; poor cohesion; fair adhesive properties; dull earthy luster; smooth clayey texture; no oil indicators. Sand (4450' - 4515') = light gray to slightly medium dark gray; individual sands grains opaque to clear; common felsic framework; scattered loose unconsolidated quartz and other lithic sand grains; increase in conglomeritic clast; poor sorting; subround to angular shards; non calcareous; no visible off gases, no sample fluorescence or residual cut present. Sandstone (4540' - 4580') = greenish gray very hard, tight; fused felsic framework very fine grained packed cuttings; trace individual conglomeratic clast; possible interbed section of matrix supported and beds of tight grain supported sandstone poorly sorted; abrasive texture; angular shards of dark gray feldspars; and silic quartz clast; common remnant grain packed lithics; no oil indicators. Sandstone (4580' - 4650') = light gray to off white; grain packed sandstone; very hard; common large angular clast suspended in silic matrix; felsic with shards of quartz, frosted conglomeratic clast; disaggregated to well consolidated; very hard; scattered soluble tuffaceous clays; complex intergranular mix from original fluvial deposit; no oil indicators present. Tuffaceous Sandstone (4650' - 4740') = dark greenish gray to light green; dark gray; felsic framework with mushy clayey matrix; dominantly opaque light gray feldspar grain clast; trace volcanic clast; loose angular shards; loose conglomeratic sand grains; brittle upon contact; friable with soft clumpy soluble clays; remnant trace yellowish orange volcanic clast floating in matrix; no sample fluorescence; no petroleum odor or any other oil indicators present. Tuffaceous Claystone (4740' - 4805') = light bluish gray to light grayish colors; cohesive to clay properties; malleable tenacity; irregular fracture; massive to nodular cutting habits; waxy when wet and earthy when dry luster; clayey to smooth texture; thick to soft sediment deformation bedding structure; no HCL reaction in bulk sample; no fluorescence colors; no fluorescence cut colors; no oil odor; no residual in white light; no fluorescence residual cut colors; no hydrocarbon indictors in bulk sample. Conglomerate Sand (4815' -4880') = light gray to smokey clear with occasional dark grayish to black hues, and pale green hues colors; quartz and lithic dominated unconsolidated sands framework; granule to very coarse grain size; very poor sorting; subangular to subrounded angularity; low sphericity; low to slight moderated HCL reaction in bulk sample; no fluorescence colors, no fluorescence cut colors; no residual cut colors; no residual fluorescence cut colors; no hydrocarbon indictor in bulk sample. SRU 241-33 13 Coal (4890' - 4930') = light brown to light olive brown with dusky brown hues color; lignite coal with crunchy to dense tenacity; hackly to splintery fracture; tabular wedgelike with bladed edged cutting habits; frosted luster; matte to abrasive texture; thin bedding structure; no oil indicators in bulk sample. Tuffaceous Claystone (4940' - 5005') = pale bluish gray to light grayish colors; cohesive clay properties; malleable tenacity; irregular fracture; massive to nodular cutting habits; waxy when wet and earthy when dry luster; clayey to smooth texture; thick and soft sediment deformation bedding structure; no HCL reaction in bulk sample; no fluorescence colors; no fluorescence cut colors; no oil odor; no residual in white light; no fluorescence residual cut colors; no hydrocarbon indictors in bulk sample. Tuffaceous Siltstone (5015' - 5065') = light grayish brown to pale yellowish gray brown colors; sectile tenacity; earthy to blocky fracture; tabular cutting habits; dull to earthy luster; silty to matte texture; thin bedding structure; no fluorescence colors; no fluorescence cut colors; no residual cut color; no residual white light colors; no oil odor; no hydrocarbon indictors in bulk sample. Sand (5075' - 5105') = smokey grayish white to translucent with occasional pale greenish gray hue colors; quartz and feldspar dominate with lithic and calcareous minerals; moderate to low sphericity; low to slight moderate HCL reaction in bulk sample; no oil fluorescence colors, no fluorescence cut colors; no residual cut colors; no residual fluorescence cut colors; no hydrocarbon indicator in bulk sample. Tuffaceous Claystone (5105' - 5165') = uniform olive gray; crumbly, soft with common amorphous appearance; massive clayey interval; dull earthy luster; clumpy material with trace loose sands; smooth clayey texture; easily soluble; noncalcareous; no oil indicators. Sandstone (5165' - 5230') = dark gray to medium dark gray; speckled with dark gray and white; frosted; very hard; brittle; fused silic cemented sandstone large dark gray conglomerate clast felsic; common loose siliciclastic sand clear quartz; dark gray feldspars, pure white plagioclase feldspars; grain packed sandstone, frosted luster; abrasive texture; noncalcareous; no sample fluorescence or petroleum odor; trace random pinpoint bright white mineral fluorescence. Tuffaceous Claystone (5230' - 5300') = uniform olive gray; repeat lithology; common easily hydrated, amorphous; soft to crumbly; dull earthy luster; very smooth clayey surfaces; overall crumbly, soluble; good adhesion; mushy to sticky; silt size particles suspended in clumpy claystone material; no visible structure; non calcareous; no sample fluorescence; no free or residual cut. Tuffaceous Claystone (5300' - 5360') = light olive gray with light grayish to green hues; cohesive to clay properties; malleable tenacity; irregular fracture; massive to nodular cutting habits; waxy when wet and earthy when dry luster; clayey to smooth texture; thick to soft sediment deformation bedding structure; no HCL reaction in bulk sample; no fluorescence cut or petroleum odor; no residual cut fluorescence or residual ring; at 5347' black subbituminous fragments from coal bed. Sandstone (5390' - 5425') = medium dark gray to light gray; grain packed clast; very hard; common large angular clast suspended in silic matrix; felsic with shards of quartz, frosted conglomeratic clast; disaggregated clast; loose unconsolidated bit generated grains from sandstone matrix; individual sand grains subround to subangular; no petroleum odor, no sample fluorescence or any other fluorescent indicators. Siltstone (5425' - 5440') = dark olive gray with brownish hue; crumbly to soft; insitu black streaks, incipient micro bedding laminae; very fine; subblocky; nodular habit; dull earth y luster; silty rich discontinues bedding laminae no oil present. Sand (5505' - 5560') = translucent to clear with smokey white hues, and slight pale yellowish brown hues colors; quartz dominate with lithics, and calcite framework; upper fine to very coarse grain sizes; poor sorting; rounded to subangular angularity; moderated sphericity; unconsolidated sand; moderate to weak SRU 241-33 14 HCL reaction in bulk sample; no fluorescence colors; no fluorescence cut colors; no oil odor; no hydrocarbon indictors in bulk sample. Tuffaceous Siltstone (5570' - 5630') = olive gray to brownish gray with medium dark gray secondary hues; pasty to stiff consistency; brittle to crumbly tenacity; earthy fracture; tabular to wedgelike cuttings habit; dull, earthy luster; silty to slightly gritty texture; trace microthin carbonaceous laminae; trace carbonaceous fragments; moderate reaction to 10% HCL in sample; no oil present. Coal (5640' - 5660') = black to slightly brownish black; brittle to crunchy; blocky fracture; wedgelike, elongated, and bladed cuttings habit; resinous luster; smooth to abrasive and matte textures observed; thin structure; no outgassing observed. Tuffaceous Claystone (5660' - 5730') = light olive gray to olive gray and brownish gray; pasty consistency; malleable to sectile tenacity; earthy fracture; globular to shapeless cuttings habit; dull, earthy luster; silty to slightly gritty texture; common suspended carbonaceous fragments; thin coals common throughout interval; moderate outgassing observed; no oil in sample. Tuffaceous Sandstone (5730'-5780') = light olive gray to olive gray to brownish gray; quartz and feldspar dominant; fine to very fine grains moderately sorted; subangular to subround; moderate to high sphericity; easily friable; silica cement; tuffaceous matrix; trace thin coals throughout interval; no outgassing observed; no oil in sample. Sand (5780'-5870') = medium gray to medium dark gray with olive gray and brownish gray secondary hues; dominantly clear to translucent and frosted quartz and feldspar framework; upper very fine to upper medium grains; poor to moderately sorted; subangular to subrounded; moderate to high sphericity; unconsolidated; trace yellow, pink, dark green, gray, and white lithics; common thin coals throughout interval; weak reaction to 10% HCL in sample; no fluorescence; no cut fluorescence; no oil in sample. Tuffaceous Claystone (5870'-5930') = light olive gray to olive gray and brownish gray; adhesive and cohesive clay properties; expansive; mushy and pasty consistency; sectile tenacity; earthy fracture; globular to shapeless cuttings habit; dull, earthy luster; clayey to slightly gritty texture; thick bedding structure; common black suspended carbonaceous fragments; no reaction to 10% HCL in sample; no fluorescence; no other oil indicators present. Tuffaceous Siltstone (5940'-5990') = olive gray to brownish gray with medium gray secondary hues; expansive; dominantly stiff, trace mushy consistency; PDC disaggregated cuttings; brittle to crumbly tenacity; earthy fracture; tabular to wedgelike cuttings habit; dull earthy luster; smooth and silty to slightly gritty texture; thin structure; microthin carbonaceous laminae; trace suspended coal in sample; weak to moderate reaction to 10% HCL in sample; no fluorescence; no other oil indicators present. Coal (6010'-6040') = black to brownish black; hard; crunchy to brittle; blocky to splintery fracture; PDC bit disaggregated; fine, wedgelike to flaky cuttings; dull luster; abrasive texture, trace matte texture; thin structure; no outgassing observed. Tuffaceous Claystone (6060' -6115') = light olive gray to brownish gray colors; cohesive clay properties; mushy to pasty consistency; malleable tenacity; earthy to irregular fracture; massive to nodular cutting habits; waxy to when wet luster; smooth to clayey texture; massive to soft sediment deformation bedding structure; weak HCL reaction in bulk sample; no fluorescence colors; no oil odor; no hydrocarbon indictors in bulk sample. Coal (6125' - 6175') = brownish black to grayish black with occasional olive gray hues color; dense to crunchy tenacity; splintery to hackly fracture; wedgelike to tabular and flaky cutting habits; greasy to frosted luster; matte to abrasive texture; no fluorescence colors; no fluorescence cut colors; no oil odors in bulk sample; no residual colors; no hydrocarbon indictors in bulk sample. SRU 241-33 15 Sand (6185' - 6255') = clear to translucent with cloudy white hues, pale bluish green hues, light gray hues, and pale yellowish brown hue colors; quartz dominate with feldspars, lithics, and calcite framework; very fine to lower medium grain size; moderate to poor sorting; angular to subangular angularity; low sphericity; impact mechanical abrasion; unconsolidated sand; no fluorescence colors; no fluorescence cut colors; no residual cut colors; no residual white light colors; no oil odor; weak HCL reaction in bulk sample; no oil indictors in bulk sample. Tuffaceous Claystone (6265' - 6330') = light olive gray to yellowish gray colors; mushy to pasty consistency; malleable tenacity; irregular to earthy fracture; nodular cutting habits; earthy to dull with like waxy luster; smooth to clayey texture; massive and thick bedding thin layer of coal interbedded; no fluorescence colors; no fluorescence cut; no hydrocarbon odors bulk sample; no residual fluorescence cut colors; no hydrocarbon indictor in bulk sample. Sand (6330' - 6395') = clear to translucent with smokey white hues, pale bluish green hues, pale gray hues, and pale yellowish brown hue colors; quartz and feldspars dominated with lithics, calcite framework; fine to lower coarse grain size; moderate to poor sorting; angular to subrounded angularity; low sphericity; impact mechanical abrasion; unconsolidated sand; no fluorescence colors; no fluorescence no hydrocarbon odor in bulk sample; no residual cut or white light colors; weak to moderate HCL reaction in bulk sample. Tuffaceous Sandstone (6405'- 6450') = light olive gray to olive gray to brownish gray; quartz and feldspar dominant; lower medium to upper medium grains; subangular to subrounded; fair sorting; low to moderate sphericity; easily friable; tuffaceous matrix with slight calcite cement floating fabrics; thin to small layering bedding structure; no fluorescence cut colors; no fluorescence colors; no hydrocarbon indictors; no residual colors; no residue fluorescence colors; no oil indictors in bulk sample. Tuffaceous Claystone (6450'- 6550') = olive gray to brownish gray with medium dark gray and dark gray secondary hues; poorly adhesive, moderately cohesive clay properties; hydrophilic; mushy to pasty consistency; sectile to pulverulent tenacity; earthy fracture; globular to shapeless cuttings habit; dull, earthy luster; smooth and silty to slightly gritty texture; common suspended carbonaceous fragments; no reaction to 10% HCL in sample; no sample fluorescence; no sample cut fluorescence; no other oil indicators observed. Coal (6600'-6640') = black; hard to very hard; brittle to crunchy tenacity; irregular to blocky fracture; wedgelike, elongated, bladed, and curved cuttings habit; resinous luster; abrasive to matte texture with smooth faces where broken; thin structure; no outgassing observed. Sand (6645'-6715') = medium gray to medium dark gray with olive gray secondary hues; dominantly a clear to translucent quartz and feldspar framework; lower fine to lower medium sand grains; moderate to well sorted; subrounded to subangular; moderate to high sphericity; unconsolidated sand grains; trace carbonaceous fragments; trace pink, yellow, green, brown, white lithics; no fluorescence colors; no fluorescence cut colors; no oil odor; no residual colors; no residual cut colors; weak HCL reaction in bulk sample; no hydrocarbon indictors in bulk sample. Sand (6725' - 6795') = translucent to clear with smokey gray hues, cloudy white hues, yellowish gray hue, and occasional very pale greenish blue hues colors; quartz and feldspar dominate with calcareous minerals, lithic, and disseminate mica framework; very fine to coarse grain size; rounded to sub- angular angularity; poorly sorted; high sphericity; majority unconsolidated sand with sandstone firm friable; weak to moderate HCL reaction in bulk sample; no fluorescence colors; no fluorescence cut colors; no hydrocarbon odors; no oil indictors in bulk sample. Tuffaceous Claystone (6805' - 6865') = olive gray to brownish gray with medium dark gray and yellowish gray hues; poor adhesive with moderately cohesive clay properties; hydrophilic mushy to pasty SRU 241-33 16 consistency; pulverulent tenacity nodular to shapeless cuttings habit; earthy luster; smooth and silty to slightly gritty texture; weak to slight moderate HCL reaction in bulk sample; no fluorescence colors; no fluorescence cut colors; no residual cut colors; no hydrocarbon indictors in bulk sample. Sandstone (6875' - 6945') = translucent white to cloudy gray white with occasional light yellowish gray and medium gray secondary hue colors; quartz and feldspars framework; fine to medium grain size; poorly sorting; angular to subangular angularity; low sphericity; friable to hard; grain enlargement and tuffaceous cement; grain and cement matrix; floating fabric; thick bedding structure; weak HCL reaction in bulk sample; no fluorescence colors; no fluorescence cut colors; no residual colors; no oil odor; no hydrocarbon indictors in bulk sample. Tuffaceous claystone (6955' - 7010') = light olive gray to light brownish gray colors; lumpy to mushy consistency; malleable tenacity; cohesive clay properties; irregular to earthy fracture; nodular to rounded cutting habits; dull earthy luster; silty to slightly gritty; thick bedding structure; very weak reaction to 10% HCL in sample; no sample fluorescence; no residual colors; no oil odor; no other hydro- carbon indicators in sample. Coal (7030'-7060') = black, trace brownish black; moderately hard to hard; brittle to crunchy; irregular to blocky fracture; wedgelike to flaky and scaly cuttings habit; resinous luster; abrasive to matte texture, larger pieces have smooth surfaces; thin structure; weak to moderate outgassing. Tuffaceous Sandstone/Sand (7060'-7130') = medium light gray to medium gray to medium dark gray; dominant quartz and feldspar framework; lower very fine to upper fine grains; moderate to well sorted; subangular to subround; moderate to high sphericity; PDC disaggregated; soft to easily friable, trace firm friable; calcite cement; tuffaceous matrix; floating and point contact fabric; thin bedding; common carbonaceous fragments; strong reaction to 10% HCL; unconsolidated sand; strong salt and pepper appearance; quartz and feldspar framework; lower fine to lower medium grains; subangular to subrounded; high sphericity; thin coals common throughout interval; no outgassing; no sample fluorescence; no residual colors; no oil odor; no other hydrocarbon indicators. Coal (7130'-7240') = black to trace brownish black; moderately hard to hard; brittle to crunchy; blocky to irregular fracture; tabular, wedgelike, platy, flaky, and trace bladed cuttings habit; resinous luster; smooth to matte texture, common abrasive surfaces; thin structure; thin to moderately thick coals common throughout interval; weak to moderate outgassing observed. Tuffaceous siltstone (7240'-7300') = light olive gray to olive gray and brownish gray; brittle to crumbly tenacity; earthy fracture; tabular to wedgelike cuttings habit; dull, earthy luster; silty to gritty texture; thin bedding; bedded with claystone and sand; weak reaction to 10% HCL; no sample fluorescence; no residual colors; no oil odor; no other hydrocarbon indicators. Sand (7300'-7360') = brownish gray to brownish black and olive gray with medium dark gray secondary hues; clear to translucent quartz and feldspar framework with a strong salt and pepper appearance; lower fine to lower medium, occasionally lower coarse grains; moderately sorted; subangular; moderate to high sphericity; unconsolidated sand grains; trace green, yellow, orange, purple lithics; common gray and black carbonaceous material; moderate to strong reaction to 10% HCL in sample; no sample fluorescence; no residual colors; no oil odor; no other hydrocarbon indicators. Tuffaceous Siltstone (7390'-7455') = brownish gray to brownish black with olive gray secondary hues; argillaceous; hydrophilic; pasty to slightly stiff; malleable to crumbly; earthy fracture; tabular to shapeless cuttings habit; earthy luster; silty texture; no reaction to 10% HCL in sample; no sample fluorescence; no residual colors; no fluorescence cut colors; no hydrocarbon oil odor; no residual colors; no residual cut colors; no other hydrocarbon indictors in bulk sample. SRU 241-33 17 Tuffaceous Sandstone/Sand (7450'-7580') = light gray to medium gray and medium dark gray; lower very fine to upper fine grains; clear to translucent quartz and feldspar framework; lower very fine to upper fine grains; moderate to well sorted; subangular to subrounded, trace rounded; moderate to high sphericity, rarely low sphericity; PDC disaggregated; ranging from soft to firm friable; clay mineral cement; tuffaceous matrix; floating and point contact fabric; trace black carbonaceous fragments suspended; trace mica; non calcareous; unconsolidated sand; lower fine to lower coarse grains; moderate to well sorted; subangular to subrounded; high sphericity; no sample fluorescence; no residual colors; no residual cuts; no other hydrocarbon indicators in sample. Tuffaceous Siltstone (7600'-7650') = olive gray to brownish gray to brownish black; sectile tenacity; earthy fracture; tabular to wedgelike cuttings; habit; dull, earthy luster; clayey to silty and slightly gritty texture; very weak reaction to 10% HCL in sample; no sample fluorescence; no residual color; no residual cut; no oil odor; no other hydrocarbon indicators present. Sand (7650'-7720') = brownish gray to brownish black with olive gray secondary hues; strong salt and pepper appearance; dominantly clear and translucent quartz and feldspar; upper very fine to lower medium grains, occasionally lower to upper coarse grains; moderately sorted; subangular to subround; moderate to high sphericity; unconsolidated; common carbonaceous fragments throughout sample; trace yellow, orange, green, grayish purple, amber, and white lithics; no sample fluorescence; no residual colors; no residual cuts; no oil odor; no other hydrocarbon indicators. Sand/Tuffaceous Sandstone (7720'-7855') = medium light gray to medium gray and medium dark gray with light brownish gray secondary hues; strong salt and pepper appearance; clear and translucent quartz and feldspar framework; lower fine to lower medium grains, occasionally lower, very angular coarse grains; moderately sorted; subangular to subrounded; moderate to high sphericity; easily friable to soft hardness sandstone; unconsolidated sands; tuffaceous cement and grain support; floating and long contract fabric; thin to soft sediment deformation bedding structure; massive sand bedding structure; no fluorescence colors; no oil odor; no fluorescence cut color; no oil indication in bulk sample. Tuffaceous Claystone (7865' - 7930') = light olive gray to light brown with occasional grayish white hue colors; expansive clay properties; lumpy and mushy consistency; pulverulent to malleable tenacity; irregular to earthy fracture; nodular to shapeless cutting habits; waxy luster when wet; clayey to smooth texture; thick bedding structure; no fluorescence colors; no fluorescence cut colors; no oil odor; no residual cut colors; no residual white light colors; no oil indictor in bulk sample; weak to moderate HCL reaction in sample. Coal (7955' - 8010') = black to olive black colors; dense to tough tenacity; hackly to splintery fracture; tabular and flaky wedgelike cutting habits; greasy to sparkling when wet luster; matte to abrasive texture; thin and laminae bedding structure; slight gas bubble on surface; no HCL reaction; no fluorescence colors; no fluorescence cut color; no oil odor; no residual colors; no residual cut colors; no hydrocarbon indictors. Tuffaceous Claystone (8020' - 8080') = light olive gray to pale yellowish brown color; cohesive to colloidal clay properties; clotted to mushy consistency; malleable tenacity; irregular fracture; nodular to irregular cutting habits; waxy luster; colloidal to clayey texture; soft sediment deformation bedding structure; no fluorescence colors; no fluorescence cut colors; moderate HCL reaction in bulk sample; no residual fluorescence colors; no oil odor; no hydrocarbon indictors. Tuffaceous Sandstone/Sand (8080'- 8180') = ranging from very light gray to medium dark gray; lower very fine to upper fine grains; well to moderately sorted; subangular to subrounded; moderate to high sphericity; PDC disaggregated; soft to firm friable; calcite cement; tuffaceous matrix; floating and point contact fabric observed; common suspended black carbonaceous fragments; unconsolidated sand; strong salt and pepper appearance; upper very fine to lower medium grains; moderately sorted; SRU 241-33 18 subangular to subrounded; trace orange, green, amber, grayish purple, yellow, and white lithics; weak reaction to 10% HCL in sample; no visual fluorescence; no cut fluorescence; no oil odor; no other hydrocarbon indicators. Tuffaceous Siltstone (8200'- 8230') = medium gray to medium dark gray with olive gray secondary hues; often very argillaceous; ranging from mushy to firm; crumbly to pulverulent; earthy fracture; tabular to wedgelike and often shapeless cuttings; habit; dull, earthy luster; clayey to silty and often slightly silty; trace microthin carbonaceous laminae; thin coals throughout interval; no reaction to 10% HCL in sample; no sample fluorescence; no cut fluorescence; no oil odor; no other Coal (8240-8300') = black; hard; brittle to crunchy; blocky, irregular fracture; wedgelike, bladed, elongated, scaly, and trace massive cuttings habit; resinous luster; smooth to matte and often abrasive textures; moderately thick structures; strong outgassing. Sand (8320'-8380') = very light gray to medium gray with light olive gray secondary hues; moderate salt and pepper appearance; dominantly clear to translucent quartz and feldspar framework; upper very fine to lower coarse grains; moderately sorted; dominantly subangular to angular, common subrounded; moderate to high sphericity; unconsolidated sand; common black carbonaceous fragments; trace green, white, amber, yellow, reddish pink, grayish purple lithics; no reaction to 10% HCL in sample; no visual fluorescence; no cut fluorescence; no oil odor; no other hydrocarbon indicators. Tuffaceous Siltstone (8410'-8440') = light olive gray to olive gray to brownish gray; pasty to stiff consistency; crumbly tenacity; earthy fracture; tabular cuttings habit; greasy to waxy luster; smooth to silty texture; no reaction to 10% HCL in sample; no visual fluorescence; no cut fluorescence; no oil odor; no other hydrocarbon indicators. Conglomerate Sand (8470' - 8500') = smokey white to light grayish translucent with pale blue grayish secondary hues colors; quartz and feldspar dominate with lithic and calcareous minerals framework; upper fine to coarse grain size; poorly sorting; round to subrounded angularity; moderate to high sphericity; unconsolidated sands; thin bedding structure; moderate HCL reaction in bulk sample; no fluorescence colors; no fluorescence cut colors; no hydrocarbon indictors in bulk sample. Sand (8540' - 8595') = clear to translucent with grayish white hues, light gray hues, grayish yellow hues, and light green hues colors; quartz dominate with calcite and lithics framework; fine to upper medium grain size; poor sorting; subangular to rounded angularity; high to moderate sphericity; unconsolidated sands mixed with consolidated sandstones; no fluorescence colors; no fluorescence cut; no oil odor; no oil indictors in full sample. SRU 241-33 19 3.3 Sampling Program Set Type and Purpose Interval Frequency Distribution A Washed and Dried Reference 2014’ – 3520’ 3520’ – 8630’ 20’ 30’ Jacob Dunston Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 B Washed and Dried Reference 2014’ – 3520’ 3520’– 8630’ 20’ 30’ Jacob Dunston Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 C Washed and Dried Reference 2014’ – 3520’ 3520’ – 8630’ 20’ 30’ Jacob Dunston Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 SRU 241-33 20 4 DRILLING DATA 4.1 Surveys Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 18 0 0 18 0 0 0 0 143.66 0.33 111.93 143.6593 -0.1352 0.3357 -0.1352 0.2626 268.7 0.31 79.64 268.6975 -0.2088 1.0025 -0.2088 0.1432 330.49 0.31 55.48 330.4866 -0.084 1.3046 -0.084 0.21 391.37 1.19 111.9 391.3613 -0.2265 2.0269 -0.2265 1.726 454.66 3.08 115.91 454.6045 -1.2147 4.1663 -1.2147 2.9937 517.48 2.98 116.2 517.3367 -2.673 7.1494 -2.673 0.161 578.44 2.92 114.04 578.2159 -4.0052 9.9892 -4.0052 0.2072 641.84 2.97 115.28 641.5322 -5.3644 12.9492 -5.3644 0.1277 702.95 3.03 118.09 702.5585 -6.801 15.8056 -6.801 0.2599 764.13 3.14 121.19 763.6498 -8.4301 18.6655 -8.4301 0.3266 828.18 3.16 121.07 827.6031 -10.2496 21.6782 -10.2496 0.0329 890.66 3.21 119.68 889.9866 -12.0046 24.673 -12.0046 0.1472 952.27 3.42 110.24 951.4939 -13.4944 27.8959 -13.4944 0.948 1014.52 3.56 106.48 1013.6285 -14.685 31.4913 -14.685 0.4309 1076.11 3.59 106.52 1075.0987 -15.7758 35.1736 -15.7758 0.0489 1140.42 3.62 107.7 1139.2814 -16.9656 39.038 -16.9656 0.1244 1201.91 3.61 108.48 1200.6491 -18.1694 42.7234 -18.1694 0.0816 1265.19 3.65 108.58 1263.8021 -19.4426 46.5221 -19.4426 0.064 1327.01 4.48 112.33 1325.4662 -20.987 50.6207 -20.987 1.4091 1389.96 4.89 110.78 1388.2057 -22.873 55.4034 -22.873 0.6816 1451.94 5.32 116.53 1449.9401 -25.0937 60.4441 -25.0937 1.0775 1512.67 6.1 113.33 1510.3685 -27.6291 65.926 -27.6291 1.3868 1574.6 8.19 110.03 1571.8144 -30.4434 73.0926 -30.4434 3.4379 1637.84 10.45 107.77 1634.2158 -33.737 82.7875 -33.737 3.6196 1700.56 12.63 107.94 1695.6642 -37.5856 94.7291 -37.5856 3.4762 1763.39 15.16 106.91 1756.6508 -42.0917 109.1268 -42.0917 4.0458 1825.29 16.75 106.67 1816.1643 -47.005 125.4166 -47.005 2.5709 1975.27 21.21 107.22 1957.8987 -61.3704 172.1897 -61.3704 2.8225 2060.76 22.31 106.54 2037.29 -70.98 203.03 209.17 1.32 2121.87 24.67 108.41 2093.33 -78.31 226.25 233.02 4.05 2185.45 26.7 107.94 2150.62 -86.9 252.43 259.93 3.21 2247.94 28.77 108.53 2205.93 -96 280.05 288.33 3.33 2309.48 30.66 108.77 2259.38 -105.76 308.95 318.07 3.09 2371.3 32.6 109.36 2312.01 -116.35 339.59 349.63 3.17 SRU 241-33 21 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 2433.2 33.58 109.22 2363.87 -127.52 371.49 382.49 1.58 2494.97 34.06 109.21 2415.19 -138.83 403.96 415.94 0.78 2557.92 34.44 109.18 2467.22 -150.48 437.41 450.4 0.6 2620.64 34.13 106.79 2519.05 -161.39 471.01 484.93 2.2 2682.4 33.46 103.04 2570.38 -170.24 504.19 518.83 3.55 2743.88 33.17 99.79 2621.76 -176.92 537.27 552.42 2.94 2805.97 33 96.77 2673.78 -181.8 570.81 586.28 2.67 2868.92 33.43 94.01 2726.45 -185.04 605.14 620.76 2.49 2931.14 32.69 92.84 2778.59 -187.07 639.02 654.67 1.57 2992.36 33.35 92.85 2829.92 -188.73 672.34 687.99 1.07 3054.39 33.75 92.94 2881.62 -190.46 706.58 722.23 0.65 3116.71 33.41 92.35 2933.54 -192.05 741.01 756.64 0.76 3177.58 33.9 92.63 2984.21 -193.51 774.71 790.32 0.86 3239.71 32.67 91.88 3036.14 -194.86 808.78 824.35 2.09 3302.37 33.26 91.42 3088.71 -195.84 842.86 858.36 1.02 3364.24 33.76 91.68 3140.3 -196.76 877.01 892.43 0.84 3425.95 34.4 91.25 3191.41 -197.64 911.58 926.91 1.1 3488.03 34.75 91.71 3242.53 -198.55 946.8 962.03 0.71 3550.77 35.45 91.6 3293.85 -199.6 982.85 998.01 1.12 3612.73 36.26 92.53 3344.08 -200.91 1019.12 1034.23 1.57 3674.7 37.65 93.07 3393.6 -202.73 1056.33 1071.43 2.31 3736.98 38.56 93.44 3442.6 -204.92 1094.7 1109.82 1.5 3799.03 39.87 93.42 3490.68 -207.26 1133.86 1149.02 2.12 3861.35 40.94 93.97 3538.14 -209.87 1174.17 1189.38 1.8 3923.25 41.07 93.81 3584.85 -212.62 1214.69 1229.98 0.27 3985.38 41.14 93.14 3631.66 -215.1 1255.46 1270.78 0.72 4048.05 43.11 94.43 3678.14 -217.88 1297.4 1312.79 3.42 4110.91 43.25 94.38 3723.98 -221.19 1340.29 1355.79 0.24 4172.59 43.43 94.52 3768.84 -224.47 1382.49 1398.11 0.33 4234.65 43.58 94.61 3813.85 -227.87 1425.08 1440.82 0.27 4296.98 43.92 94.8 3858.88 -231.41 1468.04 1483.92 0.58 4358.86 43.42 94.97 3903.64 -235.05 1510.61 1526.64 0.83 4420.84 42.96 95.07 3948.82 -238.76 1552.87 1569.06 0.75 4480.97 42.54 94.56 3992.98 -242.18 1593.54 1609.87 0.9 4544.84 42.08 94.69 4040.21 -245.65 1636.4 1652.86 0.74 4607.19 42.43 95.9 4086.36 -249.52 1678.14 1694.78 1.42 4669.32 43.79 96.24 4131.71 -254.02 1720.37 1737.24 2.22 4732.09 43.14 96.96 4177.27 -258.98 1763.26 1780.42 1.3 4794.64 44.46 95.83 4222.42 -263.79 1806.29 1823.71 2.44 SRU 241-33 22 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 4857.38 44.4 96.13 4267.22 -268.37 1849.97 1867.63 0.35 4919.79 45.01 95.11 4311.57 -272.67 1893.66 1911.53 1.51 4978.46 43.6 92.9 4353.55 -275.54 1934.53 1952.49 3.56 5041.16 43.41 93.31 4399.03 -277.88 1977.63 1995.6 0.54 5107.13 43.25 91.62 4447.03 -279.83 2022.86 2040.79 1.77 5168.99 42.97 91.67 4492.18 -281.05 2065.11 2082.95 0.45 5230.68 42.4 92.2 4537.53 -282.46 2106.91 2124.68 1.09 5292.65 42.33 91.96 4583.32 -283.97 2148.64 2166.35 0.29 5356.72 42.44 92.05 4630.64 -285.48 2191.8 2209.44 0.19 5417.32 40.97 90.55 4675.89 -286.41 2232.1 2249.63 2.93 5479 39.97 89.95 4722.82 -286.58 2272.14 2289.48 1.74 5540.3 38.99 89.46 4770.13 -286.38 2311.11 2328.22 1.68 5605.12 37.65 90.98 4820.99 -286.52 2351.29 2368.22 2.53 5668.4 37.01 92.66 4871.31 -287.74 2389.64 2406.49 1.9 5728.98 36.6 93.12 4919.82 -289.56 2425.89 2442.74 0.83 5792.13 35.01 90.64 4971.03 -290.79 2462.8 2479.58 3.41 5854.71 33.96 90.76 5022.62 -291.22 2498.23 2514.88 1.68 5916.58 32.34 92.15 5074.42 -292.07 2532.05 2548.61 2.88 5980.53 32.11 92.74 5128.52 -293.53 2566.12 2582.65 0.62 6041.48 30.21 91.68 5180.67 -294.75 2597.62 2614.12 3.24 6103.82 28.83 91.82 5234.92 -295.69 2628.33 2644.76 2.22 6165.85 27.95 92.16 5289.49 -296.71 2657.8 2674.19 1.43 6228.14 26.44 92.9 5344.88 -297.96 2686.24 2702.6 2.5 6290.29 25.7 93.63 5400.72 -299.52 2713.51 2729.89 1.3 6353.25 23.61 91.54 5457.94 -300.72 2739.74 2756.11 3.59 6416.12 23.52 91.66 5515.56 -301.42 2764.86 2781.17 0.16 6477.68 21.88 90.98 5572.35 -301.98 2788.62 2804.86 2.7 6540.12 21.51 91.18 5630.37 -302.41 2811.69 2827.86 0.61 6602.71 21.04 91.14 5688.69 -302.87 2834.4 2850.5 0.74 6665.12 18.9 89.73 5747.35 -303.04 2855.71 2871.72 3.52 6727.86 18.94 89.36 5806.7 -302.88 2876.05 2891.94 0.21 6790.69 17.69 90.18 5866.34 -302.8 2895.8 2911.57 2.03 6853.76 16.46 90.66 5926.63 -302.93 2914.32 2930.01 1.96 6914.69 15.91 92.47 5985.15 -303.39 2931.3 2946.95 1.23 6974.52 15.6 91.07 6042.73 -303.89 2947.53 2963.15 0.82 7040.08 14.12 92.23 6106.09 -304.37 2964.33 2979.92 2.3 7102.25 12.7 92.51 6166.57 -304.96 2978.74 2994.31 2.28 7163.43 10.97 90.51 6226.44 -305.31 2991.28 3006.82 2.91 7225.03 8.64 94.96 6287.14 -305.76 3001.75 3017.28 3.98 SRU 241-33 23 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 7287.82 8.43 93.31 6349.23 -306.43 3011.04 3026.59 0.51 7350.07 8.12 91.68 6410.83 -306.83 3019.99 3035.54 0.62 7412.82 9.66 95.41 6472.83 -307.45 3029.66 3045.22 2.61 7473.5 9.4 96.24 6532.68 -308.47 3039.65 3055.27 0.48 7537.18 9.31 97.27 6595.51 -309.69 3049.93 3065.61 0.3 7600.1 9.14 97.9 6657.61 -311.02 3059.92 3075.69 0.31 7661.81 8.74 97.42 6718.58 -312.3 3069.42 3085.27 0.66 7723.6 8.55 97.45 6779.67 -313.5 3078.63 3094.55 0.3 7785.75 8.93 97.47 6841.09 -314.73 3087.99 3103.99 0.6 7849.28 9.06 97.5 6903.84 -316.02 3097.84 3113.92 0.21 7911.73 8.84 97.56 6965.53 -317.29 3107.47 3123.63 0.36 7973.8 8.63 97.86 7026.89 -318.56 3116.81 3133.05 0.34 8036.66 8.33 98.83 7089.05 -319.9 3125.98 3142.31 0.53 8098.52 8.6 98.78 7150.24 -321.29 3134.98 3151.4 0.44 8160.36 8.81 97.54 7211.36 -322.62 3144.25 3160.76 0.46 8223.13 8.39 99.8 7273.43 -324.03 3153.53 3170.13 0.87 8285.87 7.98 99.15 7335.53 -325.5 3162.34 3179.04 0.67 8347.9 7.74 99.49 7396.98 -326.87 3170.71 3187.51 0.4 8410.32 7.11 101.79 7458.88 -328.36 3178.63 3195.55 1.11 8471.98 6.55 100.01 7520.1 -329.75 3185.83 3202.85 0.98 8535.6 6.16 100.54 7583.32 -331 3192.76 3209.86 0.61 8591.78 6.12 101.04 7639.18 -332.13 3198.66 3215.85 0.12 *8630.00 6.12 101.04 7677.19 -332.91 3202.66 3219.91 0 *Projected SRU 241-33 24 4.2 Bit Record BIT NO. SIZE TYPE S/N JETS/ TFA IN OUT Feet Drilled HRS AVE ROP (Ft/H R) CONDITION 1 8 ½” QHC1GRC 12899891 4x16 125’ 2014’ 1889’ 16.32 253 2-1-WT-A-E-1/16-NO-TD 2 6.125” MM55D 12671049 5x12 2014’ 8630’ 6616’ 107.95 87.1 2-1-BT-N-X-I-PN-TD SRU 241-33 25 4.3 Mud Record Contractor: HALLIBURTON: Baroid Date Depth MW (ppg) VIS (s/qt) PV YP Gels FL (cc) FC Sols (%) O/W Ratio Sd (%) MBT pH Cl (mg/l) Ca (mg/l) MD (ft) TVD (ft) Spud Mud 7/2/17 120 125 8.8 250 22 44 39/74/87 11.2 2/0 3.5 0/96.2 - 25.0 9.6 700 120 7/3/17 991 990 9.1 90 24 35 18/61/77 10.3 2/0 5.8 0/94.0 0.30 25.0 8.4 550 60 7/4/17 2014 1994 9.1 62 22 20 7/30/48 10.0 2/0 5.8 0/94.0 0.30 25.0 8.4 550 40 7/5/17 2014 1994 9.15 45 16 7 2/3/4 9.8 2/0 6.2 0/93.6 0.30 20.0 8.0 550 40 6% KCl Polymer 7/6/17 2014 1994 9.20 53 8 19 7/11/12 7.6 1/0 3.5 0/93.6 - - 10.5 35000 240 7/7/17 2014 1994 9.0 55 8 19 7/11/12 7.2 1/0 1.9 0/95.0 - - 9.9 37000 240 7/8/17 2158 2189 9.0 50 8 19 8/10/12 6.6 1/2 1.8 0/95.0 0.25 - 10.0 38000 100 7/9/17 3523 3273 9.05 53 11 20 7/10/12 5.8 1/2 2.4 0/94.7 0.25 1.0 9.8 35000 80 7/10/17 4518 4021 9.08 49 11 18 6/8/9 5.5 1/2 2.6 0/94.5 0.20 1.8 10.1 35000 60 7/11/17 5330 4626 9.12 53 14 20 6/7/9 5.0 1/2 2.9 0/94.2 0.25 2.3 10.4 36000 - 7/12/17 5765 4765 9.2 54 16 20 5/8/11 4.5 1/2 3.3 0/93.6 0.10 3.0 10.3 38000 40 7/13/17 6585 5673 9.2 52 15 17 5/7/10 4.5 1/2 3.3 0/93.6 0.10 3.8 10.2 38000 40 7/14/17 7203 6264 9.2 55 15 19 5/6/9 3.8 1/2 3.3 0/93.6 0.10 3.8 9.9 38000 40 7/15/17 7689 6745 9.6 57 18 19 5/7/10 3.2 1/2 5.7 1.0/91.2 0.10 4.5 10.5 26500 40 7/16/17 8226 7227 9.78 58 19 17 4/7/9 3.3 1/2 5.9 0.8/90.3 0.10 4.8 10.4 39000 40 7/17/17 8630 7677 11.65 57 27 20 5/11/17 2.6 1/2 13.2 0.5/83.5 0.10 5.8 10.3 38000 40 7/18/17 8630 7677 12.4 55 26 22 5/11/17 2.9 1/2 16.7 0.5/80.5 0.10 6.0 10.9 34000 40 7/19/17 8630 7677 12.4 51 21 18 5/8/14 2.8 1/2 16.6 0.5/80.5 0.10 6.0 8.7 33500 40 7/20/17 8630 7677 12.45 50 20 18 5/13/18 3.8 1/2 17.2 0.5/80.5 0.10 6.5 10.0 33500 40 7/21/17 8630 7677 12.42 49 18 17 4/12/18 3.8 1/2 17.5 0.4/80.0 0.10 6.3 11.0 30500 40 7/22/17 1/2 Abbreviations: MW = Mud Weight VIS = Funnel Viscosity PV = Plastic Viscosity YP = Yield Point Gels = Gel Strength FL = Water or Filtrate Loss FC = Filter Cake O/W = Oil to Water ratio Sols = Solids Sd = Sand content MBT = Methylene Blue Alk, Pm = Alkalinity, Mud pH = Acidity Cl = Chlorides Ca = Hardness Calcium nr = Not Recorded SRU 241-33 26 4.4. Drilling Progress 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 7/2/177/3/177/4/177/5/177/6/177/7/177/8/177/9/177/10/177/11/177/12/177/13/177/14/177/15/177/16/177/17/177/18/177/19/177/20/177/21/177/22/177/23/178 1/2" 6 3/4" SRU 241-33 28 6 DAILY REPORTS DATE: DEPTH: 125' TIME: 23:59:59 YESTERDAY: 125' ' 4 1/2" @ xxxx' DEPTH INCLINATION N/A 0.00° 0.00° CONDITION REASON NO SIZE TYPE S/N JETS IN OUT FOOTAGE T/B/C PULLED #VALUE! HIGH LOW 0 @ 0 0 @ 0 FT/HR 0 @ 0 0 @ 0 FT/LBS 0 @ 0 0 @ 0 KLBS 0 @ 0 0 @ 0 RPM 0 @ 0 0 @ 0 PSI S-Mud N/A °F MW VIS PV YP FL CL- FC SOL SD MBT Ca+ OIL 0.0 / TOOL: HIGH LOW UNITS 0 @ 0 0 @ 0 0 SURVEY 0 @ 0 0 @ 0 0 0 @ 0 0 @ 0 0 AVG 0 @ 0 0 @ 0 0 CURRENT 0 @ 0 0 @ 0 0 0 @ 0 0 @ 0 0 AVG 0 INTERVAL LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY 2 SRU 241-33 0 DAILY WELLSITE REPORTSwanson River Field Hilcorp Alaska, LLc 16" @ 120' 7" @ xxxx' DRILLING PARAMETERS SURFACE TORQUE AZIMUTH VERTICAL DEPTH AVERAGE CURRENT AVG 0 0 RATE OF PENETRATION 0 0 0 METHANE(C-1) ETHANE(C-2) Gels pH CHROMATOGRAPHY(ppm) DITCH GAS GAS SUMMARY (UNITS) TO CONNECTION GAS HIGH TRIP GAS July 02, 2017 0.00'SURVEY DATA TOP DRIVE RPM PUMP PRESSURE WEIGHT ON BIT 0 0 DRILLING MUD REPORT: DEPTH 125' 0 0 FLOWLINE TEMPERATURE: REPORT FOR: Rance Pederson, Robert Wall PRESENT OPERATION: 24 HOUR FOOTAGE CASING INFORMATION Prepare to spud well BIT INFORMATION INTERVAL HOURS MWD SUMMARY AVERAGE INTERVAL CURRENT BACKGROUND/ HYDROCARBON SHOWS BUTANE(C-4) PENTANE(C-5) GAS DESCRIPTION LITHOLOGY LITHOLOGY/REMARKS WIPER GAS PRESENT LITHOLOGY Rig Canrig equipment, prepare pits, catwalk, rig floor, drawworks, top drive, function text equipment, calibrate Canrig equipment for Canrig, continue to Rig up and prepare for drilling ahead new footage, P/U Jars, rack back in derrick, Stage directional BHA on catwalk while tallying in pason, building spud mud, PJSM with crew and 3rd party personnel on spudding in hole, Prepare to drill ahead at report time. CANRIG PERSONNEL ON BOARD DAILY COST $2,129 REPORT BY Marquel Mosebay PROPANE(C-3) DATE: DEPTH: 1002' TIME: 23:59:59 YESTERDAY: 125' 877' 4 1/2" @ xxxx' DEPTH INCLINATION 952.27' 3.42° 110.24° CONDITION REASON NO SIZE TYPE S/N JETS IN OUT FOOTAGE T/B/C PULLED NB #1 8.5"QHC1GRC 12899891 4x16 125' #VALUE! HIGH LOW 225 @ 747 1.2 @ 312 FT/HR 5727 @ 283 0 @ 950 FT/LBS 12 @ 670 0 @ 127 KLBS 62 @ 616 31 @ 127 RPM 1633 @ 911 198 @ 128 PSI 83 °F MW 9.1 VIS 90 PV 24 YP 35 FL 10.3 CL- 550 Cake 2/0 SOL 5.8 SD 0.30 OIL 0.0/94.0 MBT 25.0 8.4 Ca+ 60 TOOL: HIGH LOW UNITS 31 @ 968 0 @ 0 10 6 SURVEY 6838 @ 969 164 @ 384 2031 0 @ 980 0 @ 980 0 AVG 0 @ 980 0 @ 980 0 CURRENT 0 @ 980 0 @ 980 0 0 @ 980 0 @ 980 0 AVG 3 INTERVAL LITHOLOGY: PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY 2 Soft clay, mushy to crumbly, massive irregular clumpy material. Circulate water out hole & condition spud mud, Drill ahead from 125’ to 280’, Wash and Ream from 280’, Rack back flex collars in derrick, pulled out of the hole, pick up smart tools. Ran back into the hole to 280’ and drilled ahead to 370’, Drill ahead from 370 to 890’, SPR, Drill ahead to 991’. Pump HI-VIS sweep & circulate out, W ash and Ream from 991’ to 312', Service Rig, Level Derrick, change shaker screens, R.I.H from 312' to 991', Washed last stand (No fill), pump HI-Vis sweep, Drill ahead from 991'. CANRIG PERSONNEL ON BOARD DAILY COST $1,825 REPORT BY Marquel Mosebay GAS DESCRIPTION Soft mushy hydrated clays @ 890' LITHOLOGY/REMARKS CURRENT BACKGROUND/ HYDROCARBON SHOWS BUTANE(C-4) PENTANE(C-5) WIPER GAS @ 991' PROPANE(C-3) CONNECTION GAS HIGH HOURS MWD SUMMARY AVERAGE BIT INFORMATION INTERVAL SURVEY DATA REPORT FOR: Rance Pederson, Robert Wall PRESENT OPERATION: DEPTH 991' 1470 54 4490 4726 FLOWLINE TEMP: TRIP GAS 1100 18/61/77 TOP DRIVE RPM PUMP PRESSURE WEIGHT ON BIT DRILLING MUD REPORT: DRILLING PARAMETERS SURFACE TORQUE METHANE(C-1) ETHANE(C-2) Gels pH CHROMATOGRAPHY(ppm) DITCH GAS GAS SUMMARY (UNITS) TOINTERVAL AVERAGE CURRENT AVG 163 4 951.50' DAILY WELLSITE REPORTSwanson River Field Hilcorp Alaska, LLc 16" @ 120' 7" @ xxxx' 24 HOUR FOOTAGE CASING INFORMATION DRILLING SRU 241-33 60 7 138 AZIMUTH VERTICAL DEPTH July 03, 2017 RATE OF PENETRATION DATE: DEPTH: 2014' TIME: YESTERDAY: 1002' 1012' 4 1/2" @ xxxx' DEPTH INCLINATION 1,975.27' 21.21° 107.22° CONDITION REASON NO SIZE TYPE S/N JETS IN OUT FOOTAGE T/B/C PULLED 1 8.5"QHC1GRC 12899891 4x16 125' 2014' 1889' CSG HIGH LOW 280.3 @ 1560 18.9 @ 1183 FT/HR 5784 @ 1762 0 @ 2001 FT/LBS 17 @ 1891 0.5 @ 1417 KLBS 63 @ 1802 1 @ 1620 RPM 1878 @ 1183 1313 @ 1010 PSI TYPE: SPUD MUD MW 9.1 VIS 62 PV 22 YP 20 FL 10 CL- 550 Cake 2/0 SOL 5.8 SD 0.30 OIL 0.0/94.0 MBT 25.0 8.4 Ca+ 40 TOOL: HIGH LOW UNITS 36 @ 1392 1 @ 1 11.1 5 10 8027 @ 1394 264 @ 1464 2273 0 @ 2014 0 @ 2014 0 AVG 0 @ 2014 0 @ 2014 0 CURRENT 0 @ 2014 0 @ 2014 0 0 @ 2014 0 @ 2014 0 AVG 1 INTERVAL LITHOLOGY: PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY 2 23:59:59 PM DEPTH: 2014' FLOWLINE TEMP: SRU 241-33 0 7 158 AZIMUTH VERTICAL DEPTH July 4, 2017 RATE OF PENETRATION DAILY WELLSITE REPORTSwanson River Field Hilcorp Alaska, LLc 16" @ 120' 7" @ xxxx' 24 HOUR FOOTAGE CASING INFORMATION POOH AVERAGE CURRENT AVG 253 12 1,957.89' METHANE(C-1) ETHANE(C-2) Gels pH CHROMATOGRAPHY(ppm) DITCH GAS GAS SUMMARY (UNITS) TOINTERVAL DRILLING PARAMETERS SURFACE TORQUE TRIP GAS 1579 7/30./48 TOP DRIVE RPM PUMP PRESSURE WEIGHT ON BIT DRILLING MUD REPORT: 1678 41 3378 0 REPORT FOR: Clint Montague, Robert Wall PRESENT OPERATION: BIT INFORMATION INTERVAL SURVEY DATA HOURS 16.32 MWD SUMMARY AVERAGE MWD, LWD Smart Tool CURRENT BACKGROUND/ HYDROCARBON SHOWS BUTANE(C-4) PENTANE(C-5) WIPER GAS @ 1490' PROPANE(C-3) CONNECTION GAS HIGH Siliciclastic sands with scattered volcanic debris @ bottoms up LITHOLOGY/REMARKS WIPER GAS @ 2014' Immature lithic sands with floating mica sheets, and volcanic debris Circulate at 991’, Pump HI-VIS sweep with 80% increase in cuttings @ 991’, Drill ahead from 991’ to 1400’, Drill to 1485’, pump sweep and circulate hole clean, increase in cutting, POOH from 1490’ to 278’, Service Rig, Trip in Hole to 1490’, Wash last stand down,Wiper Gas 5u, Drill ahead to 2014’ 7” Csg TD, Circulate sweep, monitor well, well static dropped 2 inches in 10 minutes, POOH from 2014’ to 314’(No issues), RIH from 314’ to 2014’, Circulate, pump sweep, Max wiper gas 10u, Circulate out with 20% increase in cuttings, sweep on time, POOH for 7” Casing. CANRIG PERSONNEL ON BOARD DAILY COST $1,825 REPORT BY Marquel Mosebay GAS DESCRIPTION DATE: DEPTH: 2014' TIME: YESTERDAY: 2014' ' 4 1/2" @ xxxx' DEPTH INCLINATION 1,975.27' 21.21° 107.22° CONDITION REASON NO SIZE TYPE S/N JETS IN OUT FOOTAGE T/B/C PULLED 1 8.5"QHC1GRC 12899891 4x16 125' 2014' 1889'2-1-WT-A-E-1/16-NO-TD CSG 2 6.125" HIGH LOW 0 @ 0 @ FT/HR 0 @ 0 @ FT/LBS 0.0 @ 0.0 @ KLBS 0 @ 0 @ RPM 0 @ 0 @ PSI TYPE: SPUD MUD MW 9.1 VIS 62 PV 22 YP 20 FL 10 CL- 550 Cake 2/0 SOL 5.8 SD 0.30 OIL 0.0/94.0 MBT 25.0 8.4 Ca+ 40 TOOL: HIGH LOW UNITS @ @ @ @ 0 @ 0 @ 0 AVG 0 @ 0 @ 0 CURRENT 0 @ 0 @ 0 0 @ 0 @ 0 AVG INTERVAL LITHOLOGY: PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY 2 SRU 241-33 0 0.0 0 AZIMUTH VERTICAL DEPTH July 5, 2017 RATE OF PENETRATION CURRENT AVG DAILY WELLSITE REPORTSwanson River Field Hilcorp Alaska, LLC 16" @ 120' 7" @ 2004' 24 HOUR FOOTAGE 23:59:59 PM CASING INFORMATION 1,957.89' Gels 7/30./48 pH CHROMATOGRAPHY(ppm) DITCH GAS DEPTH: 2014' GAS SUMMARY (UNITS)AVERAGE MWD, LWD Smart Tool FLOWLINE TEMP: F TRIP GAS 0 TO WEIGHT ON BIT DRILLING MUD REPORT: 0 0SURFACE TORQUE 0 0 0.0 REPORT FOR: Clint Montague, Robert Wall PRESENT OPERATION: BOPE SURVEY DATA 0 DRILLING PARAMETERS AVERAGE HOURS 16.32 TOP DRIVE RPM PUMP PRESSURE MWD SUMMARY BIT INFORMATION INTERVAL CURRENT BACKGROUND/ INTERVAL METHANE(C-1) ETHANE(C-2) HYDROCARBON SHOWS BUTANE(C-4) PENTANE(C-5) WIPER GAS PROPANE(C-3) CONNECTION GAS HIGH SURVEY LITHOLOGY/REMARKS GAS DESCRIPTION Continue to POOH for 7" Casing String, L/D BHA, Lay down directional BHA, PJSM on radio active source, remove source, down load LWD Data, Service Rig and bushing, Run dummy hanger joint, Rig up Casing crew, Run Casing, Rig down casing crew, Rig up cement crew, Cement 7” Casing string, Rig down Halliburton cementers, Nipple down conductor, Install well head, Test Void. Install BOPE CANRIG PERSONNEL ON BOARD DAILY COST $1,825 REPORT BY Marquel Mosebay DATE: DEPTH: 2014' TIME: YESTERDAY: 2014' ' 4 1/2" @ xxxx' DEPTH INCLINATION 1,975.27' 21.21° 107.22° CONDITION REASON NO SIZE TYPE S/N JETS IN OUT FOOTAGE T/B/C PULLED 1 8.5"QHC1GRC 12899891 4x16 125' 2014' 1889'2-1-WT-A-E-1/16-NO-TD CSG 2 6.125" HIGH LOW 0 @ 0 @ FT/HR 0 @ 0 @ FT/LBS 0.0 @ 0.0 @ KLBS 0 @ 0 @ RPM 0 @ 0 @ PSI TYPE: MW 9.1 VIS 62 PV 22 YP 20 FL 10 CL- 550 Cake 2/0 SOL 5.8 SD 0.30 OIL 0.0/94.0 MBT 25.0 8.4 Ca+ 40 TOOL: HIGH LOW UNITS @ @ 0 @ 0 @ 0 0 @ 0 @ 0 AVG 0 @ 0 @ 0 CURRENT 0 @ 0 @ 0 0 @ 0 @ 0 AVG INTERVAL LITHOLOGY: PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY 2 SRU 241-33 0 0.0 0 AZIMUTH VERTICAL DEPTH July 6, 2017 RATE OF PENETRATION CURRENT AVG DAILY WELLSITE REPORTSwanson River Field Hilcorp Alaska, LLC 16" @ 120' 7" @ 2004' 24 HOUR FOOTAGE 23:59:59 PM CASING INFORMATION 1,957.89' Gels 7/30./48 pH CHROMATOGRAPHY(ppm) DITCH GAS DEPTH: ' GAS SUMMARY (UNITS)AVERAGE FLOWLINE TEMP: F TRIP GAS 0 TO WEIGHT ON BIT DRILLING MUD REPORT: 0 0SURFACE TORQUE 0 0 0.0 REPORT FOR: Clint Montague, Robert Wall PRESENT OPERATION: TEST BOPE SURVEY DATA 0 DRILLING PARAMETERS AVERAGE HOURS 16.32 TOP DRIVE RPM PUMP PRESSURE MWD SUMMARY BIT INFORMATION INTERVAL CURRENT BACKGROUND/ INTERVAL METHANE(C-1) ETHANE(C-2) HYDROCARBON SHOWS BUTANE(C-4) PENTANE(C-5) WIPER GAS PROPANE(C-3) CONNECTION GAS HIGH SURVEY LITHOLOGY/REMARKS GAS DESCRIPTION Continue to nipple down conductor, Install BOPE, Hook up gas buster line to catwalk, clean mud tanks, Build KCL mud system, Nipple up Stack, Continue to nipple up Rig, and prepare Rig for drilling 6 1/8” Hole, Install wear bushing, Pick up drill pipe, POOH and rack back DP in derrick, TEST BOPE. CANRIG PERSONNEL ON BOARD DAILY COST $1,825 REPORT BY Marquel Mosebay DATE: DEPTH: 2014' TIME: YESTERDAY: 2014' ' 4 1/2" @ xxxx' DEPTH INCLINATION 1,975.27' 21.21° 107.22° CONDITION REASON NO SIZE TYPE S/N JETS IN OUT FOOTAGE T/B/C PULLED 1 8.5"QHC1GRC 12899891 4x16 125' 2014' 1889'2-1-WT-A-E-1/16-NO-TD CSG 2 6.125" HIGH LOW 0 @ 0 @ FT/HR 0 @ 0 @ FT/LBS 0.0 @ 0.0 @ KLBS 0 @ 0 @ RPM 0 @ 0 @ PSI TYPE: 6% KCL/PHPA MW 9.0 VIS 55 PV 8 YP 19 FL 7.2 CL- 37000 Cake 1/0 SOL 1.9 SD - OIL 0.0/95 MBT - 9.9 Ca+ 240 TOOL: HIGH LOW UNITS @ @ 0 @ 0 @ 0 0 @ 0 @ 0 AVG 0 @ 0 @ 0 CURRENT 0 @ 0 @ 0 0 @ 0 @ 0 AVG INTERVAL LITHOLOGY: PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY 4 DESCRIPTION Continue to TEST BOPE, Retest BOPE when needed, Blow down choke manifold, Pick up and rack back DP in Derrick. CANRIG PERSONNEL ON BOARD DAILY COST $2,585 REPORT BY Marquel Mosebay PROPANE(C-3) CONNECTION GAS HIGH SURVEY LITHOLOGY/REMARKS GAS CURRENT BACKGROUND/ INTERVAL METHANE(C-1) ETHANE(C-2) HYDROCARBON SHOWS BUTANE(C-4) PENTANE(C-5) WIPER GAS MWD SUMMARY BIT INFORMATION INTERVAL 0 DRILLING PARAMETERS AVERAGE HOURS 16.32 TOP DRIVE RPM PUMP PRESSURE REPORT FOR: Clint Montague, Robert Wall PRESENT OPERATION: P/U DRILL PIPE SURVEY DATA WEIGHT ON BIT DRILLING MUD REPORT: 0 0SURFACE TORQUE 0 0 0.0 TRIP GAS 0 TO FLOWLINE TEMP: - F pH CHROMATOGRAPHY(ppm) DITCH GAS DEPTH: 2014' GAS SUMMARY (UNITS)AVERAGE 1,957.89' Gels 7/11/12. DAILY WELLSITE REPORTSwanson River Field Hilcorp Alaska, LLC 16" @ 120' 7" @ 2004' 24 HOUR FOOTAGE 23:59:59 PM CASING INFORMATION SRU 241-33 0 0.0 0 AZIMUTH VERTICAL DEPTH July 7, 2017 RATE OF PENETRATION CURRENT AVG DATE: DEPTH: 2234' TIME: YESTERDAY: 2014' 220' 4 1/2" @ xxxx' DEPTH INCLINATION 2,185.45' 26.70° 107.94° CONDITION REASON NO SIZE TYPE S/N JETS IN OUT FOOTAGE T/B/C PULLED 1 8.5"QHC1GRC 12899891 4x16 125' 2014' 1889'2-1-WT-A-E-1/16-NO-TD CSG 2 6.125" MM55D 12671049 5x12 2014' HIGH LOW 654.3 @ 2031 34.5 @ 2108 FT/HR 5916 @ 2179 0 @ 2044 FT/LBS 11.0 @ 2014 0.4 @ 2181 KLBS 78 @ 2218 28 @ 2061 RPM 1678 @ 2014 1078 @ 2096 PSI TYPE: 6% KCL/PHPA MW 9.0 VIS 55 PV 8 YP 19 FL 7.2 CL- 37000 Cake 1/0 SOL 1.9 SD - OIL 0.0/95 MBT - 9.9 Ca+ 240 TOOL: HIGH LOW UNITS 33 @ 2038 2 @ 2 9.6 9491 @ 2044 532 @ 2019 2546 0 @ 0 @ 0 AVG 96 @ 2044 31 @ 2052 4.1 CURRENT 0 @ 0 @ 0 0 @ 0 @ 0 AVG 11 INTERVAL LITHOLOGY: PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY 4 BIT#2 Make:HDBS SRU 241-33 79 1.9 159 AZIMUTH VERTICAL DEPTH July 8, 2017 RATE OF PENETRATION DAILY WELLSITE REPORTSwanson River Field Hilcorp Alaska, LLC 16" @ 120' 7" @ 2004' 24 HOUR FOOTAGE 23:59:59 PM CASING INFORMATION 2,150.62' Gels 7/11/12. CURRENT AVG pH CHROMATOGRAPHY(ppm) DITCH GAS DEPTH: 2014' GAS SUMMARY (UNITS)AVERAGE FLOWLINE TEMP: - F TRIP GAS 32 TO WEIGHT ON BIT DRILLING MUD REPORT: 1178 3038SURFACE TORQUE 5610 132 1.1 REPORT FOR: Clint Montague, Robert Wall PRESENT OPERATION: DRILLING SURVEY DATA 1191 DRILLING PARAMETERS AVERAGE HOURS 16.32 TOP DRIVE RPM PUMP PRESSURE MWD SUMMARY BIT INFORMATION INTERVAL CURRENT BACKGROUND/ INTERVAL METHANE(C-1) ETHANE(C-2) HYDROCARBON SHOWS BUTANE(C-4) PENTANE(C-5) WIPER GAS PROPANE(C-3) CONNECTION GAS HIGH SURVEY Sterling Formation LITHOLOGY/REMARKS GAS DESCRIPTION Loose unconsolidated sands, subround to subangular, well sorted, common lithic sand fragments and volcanic debris. Pick up and rack back DP in Derrick, Continue to pick up DP, P/U smart tools, Scribe motor, P/U HWDP, P/U Drill pipe, Drill cement, tag float collar @ 1918', Tag shoe @ 2004', Drill ahead to 2034', Circulate clean, Displace spud mud with 6%KCL mud, Clean possum belly, Continue to circulate 3 bottoms up on new mud, FIT Test to 12.4 @ 360psi, Drill ahead from 2034'. CANRIG PERSONNEL ON BOARD DAILY COST $2,675 REPORT BY Marquel Mosebay DATE: DEPTH: 3523' TIME: YESTERDAY: 2234' 1289' 4 1/2" @ xxxx' DEPTH INCLINATION 2,185.45' 26.70° 107.94° CONDITION REASON NO SIZE TYPE S/N JETS IN OUT FOOTAGE T/B/C PULLED 1 8.5"QHC1GRC 12899891 4x16 125' 2014' 1889'2-1-WT-A-E-1/16-NO-TD CSG 2 6.125" MM55D 12671049 5x12 2014' HIGH LOW 217.4 @ 2424 7 @ 2854 FT/HR 6831 @ 3468 0 @ 2599 FT/LBS 5.0 @ 3202 0.3 @ 2601 KLBS 82 @ 2796 2 @ 3097 RPM 1534 @ 2811 1091 @ 2365 PSI TYPE: 6% KCL/PHPA MW 9.0 VIS 50 PV 8 YP 19 FL 7.2 CL- 38000 Cake 1/2 SOL 1.8 SD 0.25 OIL 0.0/95 MBT - 10.0 Ca+ 100 TOOL:2014' HIGH LOW UNITS 126 @ 2892 2 @ 2 17.2 10 39713 @ 2893 576 @ 2284 5148 0 @ 0 @ 0 AVG 0 @ 0 @ 0 CURRENT 0 @ 0 @ 0 0 @ 0 @ 0 AVG 14 INTERVAL LITHOLOGY: PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY 4 DESCRIPTION Tuffaceous sandstone fused in clay matrix with suspended volcanic clast, and abundant loose unconsolidated upper medium coarse sands. Continue to drill ahead to 2779', Circulate sweep 15% increase in cuttings, wipe hole to 1972' Flow check static, NO issues coming out of hole, Service Rig, Trip back in hole with NO issues, Max Wiper Gas 10u, Drill ahead from 2279' to 3184', pump sweep @ 2792' 10% cuttings, Continue to drill ahead to 3523', Circulate sweep, wipe hole from 3523' at report time. CANRIG PERSONNEL ON BOARD DAILY COST $2,675 REPORT BY Marquel Mosebay PROPANE(C-3) CONNECTION GAS HIGH SURVEY No oil Indicators present Lower Sterling Formation LITHOLOGY/REMARKS GAS CURRENT BACKGROUND/ INTERVAL METHANE(C-1) ETHANE(C-2) HYDROCARBON SHOWS BUTANE(C-4) PENTANE(C-5) WIPER GAS @ 2779' BIT INFORMATION INTERVAL 2.5 1287 DRILLING PARAMETERS AVERAGE DRILLING MUD REPORT: 1310 HOURS 16.32 TOP DRIVE RPM PUMP PRESSURE REPORT FOR: Clint Montague, Robert Wall PRESENT OPERATION: WIPE HOLE at 3523' SURVEY DATA WEIGHT ON BIT 5374SURFACE TORQUE 6697 126 TRIP GAS 68 TO FLOWLINE TEMP: 83 F pH CHROMATOGRAPHY(ppm) DITCH GAS DEPTH: 2228' GAS SUMMARY (UNITS)AVERAGE LWD TRIPLE COMBO HALLIBURTON: MWD/LWD SUMMARY TD 2,150.62' Gels 8/10/12. CURRENT AVG DAILY WELLSITE REPORTSwanson River Field Hilcorp Alaska, LLC 16" @ 120' 7" @ 2004' 24 HOUR FOOTAGE 23:59:59 PM CASING INFORMATION BIT#2 Make:HDBS SRU 241-33 77 1.7 123 AZIMUTH VERTICAL DEPTH July 9, 2017 RATE OF PENETRATION DATE: DEPTH: 4517' TIME: YESTERDAY: 3523' 994' 4 1/2" @ xxxx' DEPTH INCLINATION 4,480.97' 42.54° 94.56° CONDITION REASON NO SIZE TYPE S/N JETS IN OUT FOOTAGE T/B/C PULLED 1 8.5"QHC1GRC 12899891 4x16 125' 2014' 1889'2-1-WT-A-E-1/16-NO-TD CSG 2 6.125" MM55D 12671049 5x12 2014' HIGH LOW 207.8 @ 3725 6.1 @ 3649 FT/HR 8613 @ 4516 0 @ 3777 FT/LBS 14.0 @ 4024 0.2 @ 3525 KLBS 81 @ 4453 0 @ 3778 RPM 2306 @ 4484 1275 @ 3587 PSI TYPE: 6% KCL/PHPA MW 9.08 VIS 49 PV 8 YP 18 FL 5.5 CL- 35000 Cake 1/2 SOL 2.6 SD 0.20 OIL 0.0/94.5 MBT 1.8 10.1 Ca+60 TOOL:2014' HIGH LOW UNITS 196 @ 3932 1 @ 3526 23.5 8 61565 @ 3934 267 @ 3526 7111 0 @ 0 @ 0 AVG 0 @ 0 @ 0 CURRENT 0 @ 0 @ 0 0 @ 0 @ 0 AVG 18 INTERVAL LITHOLOGY: PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY 4 DESCRIPTION Tuffaceous Claystone / Siltstone, Light gray, amorphous hydrated clumpy clays with interstitial sands. Continue to wipe hole to 2658', R.I.H to 3523, NO issues, Max wiper gas 8u, Drill ahead from 3523', Continue to drill ahead to 4217', pump sweep and circulate out with 20% increase in cuttings, monitor well. Wipe hole from 4517' to 4250' pulled 20K over, wash & ream from 4250' to 3460', R.I.H at report time. CANRIG PERSONNEL ON BOARD DAILY COST $2,675 REPORT BY Marquel Mosebay PROPANE(C-3) CONNECTION GAS HIGH SURVEY No oil Indicators present Beluga Formation LITHOLOGY/REMARKS GAS CURRENT BACKGROUND/ INTERVAL METHANE(C-1) ETHANE(C-2) HYDROCARBON SHOWS BUTANE(C-4) PENTANE(C-5) WIPER GAS @ 3523' BIT INFORMATION INTERVAL 11.5 1702 DRILLING PARAMETERS AVERAGE DRILLING MUD REPORT: 2252 HOURS 16.32 TOP DRIVE RPM PUMP PRESSURE REPORT FOR: Clint Montague, Robert Wall PRESENT OPERATION: Wiper Trip SURVEY DATA WEIGHT ON BIT 6505SURFACE TORQUE 8613 110 TRIP GAS 71 TO FLOWLINE TEMP: 84 F pH CHROMATOGRAPHY(ppm) DITCH GAS DEPTH: 4517' GAS SUMMARY (UNITS)AVERAGE LWD TRIPLE COMBO HALLIBURTON: MWD/LWD SUMMARY TD 3,992.98' Gels 6/8/9. CURRENT AVG DAILY WELLSITE REPORTSwanson River Field Hilcorp Alaska, LLC 16" @ 120' 7" @ 2004' 24 HOUR FOOTAGE 23:59:59 PM CASING INFORMATION BIT#2 Make:HDBS SRU 241-33 79 7.9 102 AZIMUTH VERTICAL DEPTH July 10, 2017 RATE OF PENETRATION DATE: DEPTH: 5351' TIME: YESTERDAY: 4517' 834' 4 1/2" @ xxxx' DEPTH INCLINATION 5,292.65' 42.33° 91.96° CONDITION REASON NO SIZE TYPE S/N JETS IN OUT FOOTAGE T/B/C PULLED 1 8.5"QHC1GRC 12899891 4x16 125' 2014' 1889'2-1-WT-A-E-1/16-NO-TD CSG 2 6.125" MM55D 12671049 5x12 2014' HIGH LOW 173.9 @ 4816 6.3 @ 5132 FT/HR 9522 @ 4980 0 @ 4647 FT/LBS 21.0 @ 4904 0.6 @ 4519 KLBS 81 @ 4668 2 @ 4582 RPM 2693 @ 4989 1352 @ 4519 PSI TYPE: 6% KCL/PHPA MW 9.08 VIS 49 PV 8 YP 18 FL 5.5 CL- 35000 Cake 1/2 SOL 2.6 SD 0.20 OIL 0.0/94.5 MBT 1.8 10.1 Ca+60 TOOL:2014' HIGH LOW UNITS 27 @ 5351 1 @ 4897 8.7 7 7367 @ 5351 237 @ 5199 2362 0 @ 0 @ 0 AVG 0 @ 0 @ 0 CURRENT 0 @ 0 @ 0 0 @ 0 @ 0 AVG 9 INTERVAL LITHOLOGY: PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY 4 DESCRIPTION Tuffaceous Claystone, Olive gray, soluble and easily hydrated, dull earthy luster with good adhesive properties and varied silty particles intercalated within current cuttings. Continue to run in the hole from Wiper Trip at 4517’, wash last stand down, Max wiper gas 7u, Drill ahead from 4517', Continue to drill ahead at report time CANRIG PERSONNEL ON BOARD DAILY COST $2,675 REPORT BY Marquel Mosebay PROPANE(C-3) CONNECTION GAS HIGH SURVEY No oil Indicators present Beluga Formation LITHOLOGY/REMARKS GAS CURRENT BACKGROUND/ INTERVAL METHANE(C-1) ETHANE(C-2) HYDROCARBON SHOWS BUTANE(C-4) PENTANE(C-5) WIPER GAS @ 4517' BIT INFORMATION INTERVAL 9.1 2172 DRILLING PARAMETERS AVERAGE DRILLING MUD REPORT: 2409 HOURS 16.32 TOP DRIVE RPM PUMP PRESSURE REPORT FOR: Clint Montague, Robert Wall PRESENT OPERATION: DRILLING SURVEY DATA WEIGHT ON BIT 7263SURFACE TORQUE 8007 74 TRIP GAS 69 TO FLOWLINE TEMP: 84 F pH CHROMATOGRAPHY(ppm) DITCH GAS DEPTH: 4517' GAS SUMMARY (UNITS)AVERAGE LWD TRIPLE COMBO HALLIBURTON: MWD/LWD SUMMARY TD 4,583.32' Gels 6/8/9. CURRENT AVG DAILY WELLSITE REPORTSwanson River Field Hilcorp Alaska, LLC 16" @ 120' 7" @ 2004' 24 HOUR FOOTAGE 23:59:59 PM CASING INFORMATION SRU 241-33 80 11.2 75 AZIMUTH VERTICAL DEPTH July 11, 2017 RATE OF PENETRATION Hilcorp Alaska, LLC Swanson River Field DAILY WELLSITE REPORT SRU 241-33 REPORT FOR Clint Montague, Adam Dorr DATE Jul 12, 2017 DEPTH 5824' PRESENT OPERATION Drilling Ahead TIME 23:59:59 YESTERDAY 5351' 24 HOUR FOOTAGE 473' CASING INFORMATION 16" @ 120' 7" @ 2004' 4 1/2" @ XXXX' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 5792.13 35.01 90.64 4971.03 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6.125" MM55D 12671049 5x12 2014 3810' 50:21 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 124.2 @ 5595' 3.6 @ 5578' 64.3 87.02 FT/HR SURFACE TORQUE 8959 @ 5411' 0 @ 5589' 6862.2 7969.54199 AMPS WEIGHT ON BIT 23 @ 5738' 2 @ 5427' 14.7 19.23409 KLBS ROTARY RPM 81 @ 5648' 4 @ 5581' 67.8 79.35 RPM PUMP PRESSURE 2934 @ 5809' 2222 @ 5451' 2559.8 2848.21997 PSI DRILLING MUD REPORT DEPTH 5823' MW 9.2 VIS 54 PV 16 YP 20 FL 4.5 Gels 5/8/11 CL- 38000 FC 1/2 SOL 3.3 SD 0.10 OIL 0.0/93.6 MBL 3.0 pH 10.3 Ca+ 40 CCI 1.30 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 54 @ 5619' 3 @ 5579' 12.3 TRIP GAS 0 CUTTING GAS 0 @ 5824' 0 @ 5824' 0.0 WIPER GAS 2141u CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 16735 @ 5620' 539 @ 5757' 3498.4 CONNECTION GAS HIGH 4u ETHANE (C-2) 0 @ 5824' 0 @ 5824' 0.0 AVG 2u PROPANE (C-3) 0 @ 5824' 0 @ 5824' 0.0 CURRENT 0 BUTANE (C-4) 0 @ 5824' 0 @ 5824' 0.0 CURRENT BACKGROUND/AVG 28u/12u PENTANE (C-5) 0 @ 5824' 0 @ 5824' 0.0 HYDROCARBON SHOWS No oil indicators present INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Beluga Formation PRESENT LITHOLOGY Tuffaceos Claystone, Tuffaceos Siltstone, Sand, Coal DAILY ACTIVITY SUMMARY Drill ahead from 5351' to 5516', pump sweep and circulate. Pull out of the hole on elevators from 5516’ to 1970’ for wiper trip. Service rig, run back into the hole from 1970’ to 5516’ and pump sweep. Drill ahead from 5516’ to 5824’. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2,675.00 REPORT BY Eric Andrews Hilcorp Alaska, LLC Swanson River Field DAILY WELLSITE REPORT SRU 241-33 REPORT FOR Clint Montague, Adam Dorr DATE Jul 13, 2017 DEPTH 6589' PRESENT OPERATION Drilling Ahead TIME 23:59:59 YESTERDAY 5824' 24 HOUR FOOTAGE 765' CASING INFORMATION 16" @ 120' 7" @ 2004' 4 1/2" @ XXXX' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 6540.12' 91.18 21.51 5630.37' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6.125" MM55D 12671049 5x12 2014 4585' 61:46 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 121.6 @ 6022' 1.7 @ 5966' 78.8 23.180 FT/HR SURFACE TORQUE 9716 @ 6515' 0 @ 6086' 7558.1 8271.33008 AMPS WEIGHT ON BIT 29 @ 6586' 0 @ 6327' 16.1 24.38005 KLBS ROTARY RPM 81 @ 6027' 2 @ 6458' 69.0 79.50 RPM PUMP PRESSURE 2933 @ 6056' 1771 @ 6391' 2323.6 2250.67993 PSI DRILLING MUD REPORT DEPTH 6585' MW 9.2 VIS 52 PV 15 YP 17 FL 4.5 Gels 5/7/10 CL- 38000 FC 1/2 SOL 3.3 SD 0.10 OIL 0.0/93.6 MBL 3.8 pH 10.2 Ca+ 40 CCI 1.0 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 150 @ 6235' 3 @ 5825' 34.2 TRIP GAS 0 CUTTING GAS 0 @ 6589' 0 @ 6589' 0.0 WIPER GAS 1920u CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 46675 @ 6236' 557 @ 6447' 9946.3 CONNECTION GAS HIGH 27u ETHANE (C-2) 0 @ 6589' 0 @ 6589' 0.0 AVG 15u PROPANE (C-3) 0 @ 6589' 0 @ 6589' 0.0 CURRENT 10u BUTANE (C-4) 0 @ 6589' 0 @ 6589' 0.0 CURRENT BACKGROUND/AVG 7u/9u PENTANE (C-5) 0 @ 6589' 0 @ 6589' 0.0 HYDROCARBON SHOWS No oil indicators present INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Beluga Formation PRESENT LITHOLOGY Tuffaceous Claystone, Tuffaceous Siltstone, Sand DAILY ACTIVITY SUMMARY Continued drilling from 5824' to 6514', pumped a high viscosity sweep and circulated hole clean before pulling for a wiper trip. Pulled out of hole from 6514’ to 5496’, serviced rig, circulated bottoms up, and started running back in hole from 5496’ to 6514’. Continued drilling ahead from 6514’ to 6589’. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2,675.00 REPORT BY Eric Andrews Hilcorp Alaska, LLC Swanson River Field DAILY WELLSITE REPORT SRU 241-33 REPORT FOR Clint Montague, Adam Dorr DATE Jul 14, 2017 DEPTH 7227' PRESENT OPERATION Drilling Ahead TIME 23:59:59 YESTERDAY 6589' 24 HOUR FOOTAGE 638' CASING INFORMATION 16" @ 120' 7" @ 2004' 4 1/2" @ XXXX' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 7163.43' 10.97 90.51 6226.44' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6.125" MM55D 12671049 5x12 2014' 5213' 74:45 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 184.6 @ 6783' 1.3 @ 6601' 73.5 121.04 FT/HR SURFACE TORQUE 12158 @ 6975' 0 @ 6833' 8558.1 11547.46289 AMPS WEIGHT ON BIT 25 @ 6593' 0 @ 6952' 11.7 6.05052 KLBS ROTARY RPM 80 @ 6702' 5 @ 7015' 65.0 73.87 RPM PUMP PRESSURE 2833 @ 7155' 1469 @ 7214' 2227.1 2085.6001 PSI DRILLING MUD REPORT DEPTH 7203' MW 9.2 VIS 55 PV 15 YP 19 FL 3.8 Gels 5/6/9 CL- 38000 FC 1/2 SOL 3.3 SD 0.10 OIL 0.0/93.6 MBL 3.8 pH 9.9 Ca+ 40 CCI 0.70 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 229 @ 6665' 4 @ 6956' 32.5 TRIP GAS 0 CUTTING GAS 0 @ 7227' 0 @ 7227' 0.0 WIPER GAS 1920u CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 71323 @ 6667' 427 @ 6703' 9365.4 CONNECTION GAS HIGH 0 ETHANE (C-2) 0 @ 7227' 0 @ 7227' 0.0 AVG 0 PROPANE (C-3) 0 @ 7227' 0 @ 7227' 0.0 CURRENT 0 BUTANE (C-4) 0 @ 7227' 0 @ 7227' 0.0 CURRENT BACKGROUND/AVG 11u/10u PENTANE (C-5) 0 @ 7227' 0 @ 7227' 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tyonek Formation PRESENT LITHOLOGY Tuffaceous Sandstone, Sand, Tuffaceous Claystone, Tuffaceous Siltstone, Coal DAILY ACTIVITY SUMMARY Continued drilling ahead from 6589' to 7227’. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2,675.00 REPORT BY Eric Andrews Hilcorp Alaska, LLC Swanson River Field DAILY WELLSITE REPORT SRU 241-33 REPORT FOR Clint Montague, Adam Dorr DATE Jul 15, 2017 DEPTH 7737' PRESENT OPERATION Drilling Ahead TIME 23:59:59 YESTERDAY 7227' 24 HOUR FOOTAGE 510' CASING INFORMATION 16" @ 120' 7" @ 2004' 4 1/2" @ XXXX' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 7661.81' 8.74 97.42 6718.58 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6.125" MM55D 12671049 5x12 2014' 5723' 85:21 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 121.8 @ 7231' 5.7 @ 7572' 61.8 29.04 FT/HR SURFACE TORQUE 11547 @ 7227' 0 @ 7403' 10149.5 10102.66113 AMPS WEIGHT ON BIT 24 @ 7598' 1 @ 7453' 15.4 19.91265 KLBS ROTARY RPM 79 @ 7417' 73 @ 7230' 74.4 78.47 RPM PUMP PRESSURE 2394 @ 7371' 1896 @ 7525' 2211.2 2356.69995 PSI DRILLING MUD REPORT DEPTH 7689' MW 9.6 VIS 57 PV 18 YP 19 FL 3.2 Gels 5/7/10 CL- 26500 FC 1/2 SOL 5.7 SD 0.10 OIL 1.0/91.2 MBL 4.5 pH 10.5 Ca+ 40 CCI 0.65 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 196 @ 7232' 5 @ 7448' 41.7 TRIP GAS 0 CUTTING GAS 0 @ 7737' 0 @ 7737' 0.0 WIPER GAS 1964u CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 59572 @ 7233' 1417 @ 7449' 12460.2 CONNECTION GAS HIGH 0 ETHANE (C-2) 0 @ 7737' 0 @ 7737' 0.0 AVG 0 PROPANE (C-3) 0 @ 7737' 0 @ 7737' 0.0 CURRENT 11u BUTANE (C-4) 0 @ 7737' 0 @ 7737' 0.0 CURRENT BACKGROUND/AVG 7u/10u PENTANE (C-5) 0 @ 7737' 0 @ 7737' 0.0 HYDROCARBON SHOWS No Hydrocarbon Indicators INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tyonek Formation PRESENT LITHOLOGY Tuffaceous Sandstone, Sand, Tuffaceous Siltstone, Coal DAILY ACTIVITY SUMMARY Continued drilling from 7227' to 7512', pumped a sweep, took a survey, and circulated hole. Max gas from circulating bottoms up rose to 2228 units; performed flow check. Circulated mud and weighted up active system from 9.2ppg to 9.4 ppg and then to 9.6ppg; when flow check max gas was 30 units of gas. Pulled out of the hole from 7512’ to 6450’, for wiper trip. Serviced rig, and ran back into the hole from 6450’ to 7512’. Circulated a bottoms up with 1964 units. Continued drilling ahead from 7512’ to 7737’. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2,675.00 REPORT BY Eric Andrews Hilcorp Alaska, LLC Swanson River Field DAILY WELLSITE REPORT SRU 241-33 REPORT FOR Clint Montague, Adam Dorr DATE Jul 16, 2017 DEPTH 8247' PRESENT OPERATION Drilling Ahead TIME 23:59:59 YESTERDAY 7737' 24 HOUR FOOTAGE 510' CASING INFORMATION 16" @ 120' 7" @ 2004' 4 1/2" @ XXXX' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 8223.13' 8.39 99.80 7273.43' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6.125" MM55D 12671049 5x12 2014' 6233' 101:07 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 119.7 @ 7845' 7.1 @ 7851' 48.6 58.54 FT/HR SURFACE TORQUE 13403 @ 8186' 9228 @ 8116' 10952.8 11663.61523 AMPS WEIGHT ON BIT 25 @ 7947' 4 @ 7763' 15.0 16.24862 KLBS ROTARY RPM 78 @ 7741' 50 @ 8111' 77.3 77.22 RPM PUMP PRESSURE 2793 @ 8219' 1926 @ 8087' 2273.0 2605.33008 PSI DRILLING MUD REPORT DEPTH 8226' MW 9.78 VIS 58 PV 19 YP 17 FL 3.3 Gels 4/7/9 CL- 39000 FC 1/2 SOL 5.9 SD 0.10 OIL 0.8/90.3 MBL 4.8 pH 10.4 Ca+ 40 CCI 0.70 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 635 @ 8163' 7 @ 7979' 41.4 TRIP GAS 0 CUTTING GAS 0 @ 8247' 0 @ 8247' 0.0 WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 176250 @ 8163' 2188 @ 7757' 11477.6 CONNECTION GAS HIGH 12u ETHANE (C-2) 0 @ 8247' 0 @ 8247' 0.0 AVG 0u PROPANE (C-3) 0 @ 8247' 0 @ 8247' 0.0 CURRENT 0 BUTANE (C-4) 0 @ 8247' 0 @ 8247' 0.0 CURRENT BACKGROUND/AVG 17u/20u PENTANE (C-5) 0 @ 8247' 0 @ 8247' 0.0 HYDROCARBON SHOWS No Hydrocarbon Indicators INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tyonek Formation PRESENT LITHOLOGY Tuffaceous Sandstone, Sand, Tuffaceous Siltstone, Tuffaceous Claystone, Coal DAILY ACTIVITY SUMMARY Continued drilling ahead from 7737' to 8247’. Note: After connections we are seeing coal caving and correlating gas peaks. Max gas 2349u. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2,675.00 REPORT BY Eric Andrews Hilcorp Alaska, LLC Swanson River Field DAILY WELLSITE REPORT SRU 241-33 REPORT FOR Clint Montague, Adam Dorr DATE Jul 17, 2017 DEPTH 8630' PRESENT OPERATION Circulating/Weighting up mud TIME 23:59:59 YESTERDAY 8247' 24 HOUR FOOTAGE 383' CASING INFORMATION 16" @ 120' 7" @ 2004' 4 1/2" @ xxxx' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 84.71.98' 6.55 100.01 7520.1 8535.6' 6.16 100.54 7583.32 8591.78' 6.12 101.4 7639.18 8630' 6.12 101.04 7677.19' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6.125" MM55D 12671049 5x12 2014' 6616' 107:13 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 175.1 @ 8604' 7.7 @ 8629' 67.4 46.49 FT/HR SURFACE TORQUE 13598 @ 8515' 10248 @ 8353' 11620.1 11842.89844 AMPS WEIGHT ON BIT 23 @ 8376' 3 @ 8260' 17.5 16.70701 KLBS ROTARY RPM 78 @ 8318' 74 @ 8563' 77.0 76.65 RPM PUMP PRESSURE 2956 @ 8365' 2272 @ 8260' 2612.0 2549.87988 PSI DRILLING MUD REPORT DEPTH 8630' MW 11.65 VIS 57 PV 27 YP 20 FL 2.6 Gels 5/11/17 CL-38000 FC 1/2 SOL 13.2 SD 0.10 OIL 0.5/83.5 MBL 5.8 pH 10.3 Ca+ 40 CCI 0.60 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 2959 @ 8602' 16 @ 8607' 280.9 TRIP GAS 0 CUTTING GAS 0 @ 8630' 0 @ 8630' 0.0 WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 533629 @ 8605' 4602 @ 8606' 71761.7 CONNECTION GAS HIGH 0 ETHANE (C-2) 0 @ 8630' 0 @ 8630' 0.0 AVG 0 PROPANE (C-3) 335 @ 8512' 29 @ 8553' 18.0 CURRENT 0 BUTANE (C-4) 85 @ 8512' 19 @ 8558' 1.0 CURRENT BACKGROUND/AVG 9u/9u PENTANE (C-5) 23 @ 8512' 20 @ 8513' 0.2 HYDROCARBON SHOWS No Hydrocarbon Indicators INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tyonek Formation PRESENT LITHOLOGY Tuffaceous Siltstone, Tuffaceous Claystone, Sand DAILY ACTIVITY SUMMARY Continued drilling ahead from 8247' to 8605’, picked up and circulated due to high has. Weighted up mud while trying to maintain ECD. Drilled ahead from 8605' to 8630, and called TD. Continued circulating and weighting up mud from 9.8 ppg to 11.7 ppg. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2,675.00 REPORT BY Eric Andrews Hilcorp Alaska, LLC Swanson River FIield DAILY WELLSITE REPORT SRU 241-33 REPORT FOR Clint Montague, Adam Dorr DATE Jul 18, 2017 DEPTH 8630' PRESENT OPERATION Tripping out of the hole TIME 23:59:59 YESTERDAY 8630' 24 HOUR FOOTAGE 0' CASING INFORMATION 16" @ 120' 7" @ 2004' 4 1/2" @ xxxx' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6.125" MM55D 12671049 5x12 2014 8630 6616' 107:13 TD DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 8630' MW 12.4 VIS 55 PV 26 YP 22 FL 2.9 Gels 5/11/17 CL- 34000 FC 1/2 SOL 16.7 SD 0.10 OIL 0.5/80.5 MBL 6.0 pH 10.9 Ca+ 40 CCI 0.80 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 105u CUTTING GAS @ @ WIPER GAS 681u CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) @ @ CONNECTION GAS HIGH 0 ETHANE (C-2) @ @ AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continued circulating and weighting up mud from 11.7 ppg to 12.4 ppg. Wiped hole from 8630’ to 8257’; with no issues, and run back into the hole from 8257’ to 8630’. Performed a flow check and then began pulling out of the hole from 8630’ to 4274’. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2,675.00 REPORT BY Eric Andrews Hilcorp Alaska, LLC Swanson River Fiedd DAILY WELLSITE REPORT SRU 241-33 REPORT FOR Rance Pederson, Adam Dorr DATE Jul 19, 2017 DEPTH 8630' PRESENT OPERATION RIH: Clean Out Run TIME 13:06:18 YESTERDAY 8630' 24 HOUR FOOTAGE 0' CASING INFORMATION 16" @ 120' 7" @ 2004' 4 1/2" @ xxxx' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6.125" MM55D 12671049 5x12 2014' 8630' 6616' 107:13 2-1-BT-N-X-I-PN-TD TD DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 8630' MW 12.4 VIS 51 PV 21 YP 18 FL 2.8 Gels 5/8/14 CL- 33500 FC 1/2 SOL 16.6 SD 0.10 OIL 0.5/80.5 MBL 6.0 pH 8.7 Ca+ 40 CCI 0.10 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 549u CUTTING GAS @ @ WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) @ @ CONNECTION GAS HIGH 0 ETHANE (C-2) @ @ AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 50u/50u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continued pulling out of the hole from 4274' to BHA, laid down directional BHA, removed active sources, and downloaded data. Prepared for and performed BOP test. Rigged up and ran in hole with clean out BHA from 65' to 1980', slip and cut drill line, and continued running in hole from 1980' to 3734'. CANRIG PERSONNEL ON BOARD 2 DAILY COST $1,870.00 REPORT BY Eric Andrews Hilcorp Alaska, LLC Swanson River Field DAILY WELLSITE REPORT SRU 241-33 REPORT FOR Rance Pederson, Adam Dorr DATE Jul 20, 2017 DEPTH 8630' PRESENT OPERATION Surveys TIME 23:59:59 YESTERDAY 8630' 24 HOUR FOOTAGE 0' CASING INFORMATION 16" @ 120' 7" @ 2004' 4 1/2" @ xxxx' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 8630' MW 12.45 VIS 50 PV 20 YP 18 FL 3.8 Gels 5/13/18 CL-33500 FC 1/2 SOL 17.2 SD 0.10 OIL 0.5/80.0 MBL 6.3 pH 10.0 Ca+ 40 CCI 0.55 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 1626u CUTTING GAS @ @ WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) @ @ CONNECTION GAS HIGH 0 ETHANE (C-2) @ @ AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Proceeded running into the hole from 3734’ to 8630’, circulated, conditioned mud, and began pulling out of the hole. Pulled out of the hole from 8630’ to 7966’, and laid down drill pipe from 7966’ to 1977’. Rigged up Wire line and ran into the hole with Gyro tool to take surveys. CANRIG PERSONNEL ON BOARD 2 DAILY COST $1,870.00 REPORT BY Eric Andrews Hilcorp Alaska, LLC Swanson River Field DAILY WELLSITE REPORT SRU 241-33 REPORT FOR Rance Pederson, Adam Dorr DATE Jul 21, 2017 DEPTH 8630' PRESENT OPERATION Running Casing TIME 23:59:59 YESTERDAY 8630' 24 HOUR FOOTAGE 0' CASING INFORMATION 16" @ 120' 7" @ 2004' 4 1/2" @ xxxx' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 8630' MW 12.42 VIS 49 PV 18 YP 17 FL 3.8 Gels 4/12/18 CL-30500 FC 1/2 SOL 17.5 SD 0.10 OIL 0.4/80.0 MBL 6.3 pH 11 Ca+ 40 CCI 1.20 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 1100u CUTTING GAS @ @ WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) @ @ CONNECTION GAS HIGH 0 ETHANE (C-2) @ @ AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Rigged down wireline, laid down drill pipe from 1977' to 375', and ran in hole out of the derrick from 375' to 1619’. Laid down drill pipe from 1619' to 375' and proceeded to lay down heavy weight drill pipe from 375' to BHA. Laid down BHA, rigged up for casing, and began running casing from shoe to 7121’. CANRIG PERSONNEL ON BOARD 2 DAILY COST $1,870.00 REPORT BY Eric Andrews