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Home My WebLink About167-046Nolan 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: 5/9/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240509 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# END 3-07A 50029219110100 198147 4/17/2024 HALLIBURTON MFC END 3-25B 50029221250200 203021 3/31/2024 HALLIBURTON PPROF MPU J-16 50029226150000 195169 3/28/2024 HALLIBURTON WFL-TMD3D NCIU A-18 50883201890000 223033 5/1/2024 READ Multiple Array PProf PBU B-05D 50029202760400 213069 4/24/2024 HALLIBURTON RBT PBU C-16C 50029204380300 213191 4/26/2024 HALLIBURTON RBT PBU D-18B 50029206940200 215001 4/21/2024 HALLIBURTON RBT TBF A-07 50733200360000 167046 4/17/2024 HALLIBURTON RBT TBF A-18 50733201430000 168076 4/16/2024 HALLIBURTON RBT Please include current contact information if different from above. T38771 T38772 T38773 T38774 T38775 T38776 T38777 T38778 T38779 TBF A-07 50733200360000 167046 4/17/2024 HALLIBURTON RBT Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.05.13 12:46:46 -08'00' 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 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 6,407 feet See schematic feet true vertical 6,390 feet N/A feet Effective Depth measured 6,341 feet 370 feet true vertical 6,325 feet 370 feet Perforation depth Measured depth 2,050 - 6,330 feet True Vertical depth 2,050 - 6,314 feet 2-7/8" 6.4 / L-80 5,755 (MD) 5,746 (TVD) Tubing (size, grade, measured and true vertical depth) 2-3/8" 4.6 / L-80 4,715 (MD) 4,711 (TVD) 370 (MD) 340 (MD) Packers and SSSV (type, measured and true vertical depth) D&L Hyd II Dual Pkr 370 (TVD) TRSV 340 (TVD) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 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: 2,570psi 3,090psi 3,950psi 1,067 1,067 Burst Collapse 1,540psi measured TVD Production Liner 4,810 1,651 Casing Structural 4,806 7" 4,810 6,397 6,380 ~264 1,067 ~264Conductor Surface Intermediate 20" 13-3/8" 7,240psi 9-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 167-046 50-733-20036-00-00 3. Address: Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0018731 Trading Bay / Hemlock Oil, Middle Kenai B,C,D & E Oil Trading Bay St A-07 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 246 Gas-Mcf MD N/A 70 Size ~264 252 70165 0 2840 108 N/A Sr Pet Eng: 5,410psi Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Ryan Rupert Ryan.Rupert@hilcorp.com 907 777-8503Operations Manager N/A Hemlock Oil, Middle Kenai B,C,D & E Oil pp kkk ttt SPL Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Samantha Carlisle at 11:33 am, Feb 10, 2023 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2023.02.10 10:22:05 -09'00' Dan Marlowe (1267) Updated by: CRR 01/20/23 SCHEMATIC Trading Bay Unit Well # A-07 API# 50-733-20036-00 PTD: 167-046 Last Completed: 03/06/2019 KB to MSL = 101, MSL to Mudline 66 PBTD = 6,341 TD = 6,407 ANGLE thru INTERVAL = 3.2 RKB to TBG Hngr = 38.23 1 2 3 6 C, CZN C, CZN DZN EZN 5 TOC @ 1,530 D DV Collar @ 2,977 Tbg Punch 4,147 4,153 MD 01/13/23 HEM E 4 Top Annular fill @ 4310 MD (1/12/23 Log) A BZN X C B XN RN R Tubing Punchs ~5,219 5,226 KB 12/16/20 ~5,469 - 5,476 KB 11/26/20 ~5,738 - 5,746 MD 10/21/20 CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 20 Conductor Pile Surface ~264 13-3/8 61 J-55 Butt 12.515 Surface 1,067 9-5/840 J-55 Butt 8.835 Surface 4,810 7 26 J-55 Butt 6.276 4,746 6,397 TUBING DETAIL 2-7/8 Long 6.4 L-80 IBT SCC 2.441 Surf 5,755 2-3/8 Short 4.6 L-80 IBT 1.995 Surf 4,715 PERFORATION DATA Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Date Status BZN 2,050 2,120 2,050 2,120 70 5 06/24/18 Open BZN 2,244 2,334 2,244 2,334 90 5 06/24/18 Open 2,782 2,817 2,584 2,616 35 03/03/19 Open 31-8 BZN 2,874' 2,906' 2,873' 2,906' 32' 5 03/03/19 Open 2,875' 2,907' 2,874' 2,906' 22' 4 9/7/1988 Open 2,882' 2,896' 2,881' 2,895' 14' 4 8/17/1970 Open 2,920' 2,947' 2,919' 2,946' 27' 5 03/03/19 Open 2,923' 2,947' 2,922' 2,946' 24' 4 9/8/1988 Open 2,928' 2,944' 2,927' 2,943' 16' 4 8/17/1970 Open 33-6 BZN 2,997' 3,076' 2,996' 3,075' 79' 4 9/9/1988 Open 2,999' 3,077' 2,998' 3,076' 78' 5 03/03/19 Open 3,044' 3,076' 3,043' 3,075' 32' 4 8/17/1970 Open 41-3 BZN 3,193' 3,242' 3,192' 3,241' 49' 5 03/03/19 Open 3,196' 3,208' 3,195' 3,207' 12' 4 8/17/1970 Open 3,196' 3,240' 3,195' 3,239' 44' 4 9/10/1988 Open 3,214' 3,240' 3,231' 3,239' 26' 4 8/17/1970 Open 3,282' 3,433' 3,281' 3,432' 151' 5 03/03/19 Open 3,283' 3,435' 3,282' 3,434' 52' 4 9/11/1988 Open 3,290' 3,434' 3,289' 3,433' 144' 4 8/17/1970 Open 3,300' 3,320' 3,299' 3,319' 20' 4 9/10/1970 Cmt Szqd 44-7 BZN 3,795' 3,960' 3,793' 3,958' 65' 4 9/12/1988 Open 3,803' 3,959' 3,801' 3,957' 156' 5 03/03/19 Open 3,808' 3,850' 3,807' 3,848' 42' 4 8/17/1970 Open 3,820' 3,840' 3,818' 3,838' 20' 4 9/10/1967 Cmt Szqd 3,858' 3,956' 3,856' 3,954' 98' 4 8/17/1970 Open C-2 4,037' 4,097' 4,035' 4,095' 60' 5 03/03/19 Open C-3 4,127' 4,224' 4,125' 4,221' 97' 5 03/03/19 Open 44-7 BZN 4,125' 4,225' 4,123' 4,222' 100' 4 9/15/1967 Cmt Szqd 4,140' 4,160' 4,138' 4,157' 20' 4 9/10/1967 Cmt Szqd CZNS6 4,267' 4,335' 4,264' 4,332' 68' 5 03/03/19 Open C4 4,344' 4,371' 4,341' 4,368' 27' 5 03/03/19 Open C5 4,429' 4,479' 4,426' 4,476' 50' 5 03/03/19 Open C-6 4,600' 4,639' 4,595' 4,635' 39' 5 03/03/19 Open 44-7 BZN 4,605' 4,625' 4,601' 4,621' 20' 4 9/10/1967 Cmt Szqd CZNS7 4,670' 4,700' 4,666' 4,696' 30' 5 03/03/19 Open 4,720' 4,740' 4,716' 4,736' 20' 5 03/03/19 Open C7 4,760' 4,781' 4,756' 4,777' 21' 5 03/03/19 Open 49-4 CZN 4,807' 4,829' 4,803' 4,825' 22' 5 03/03/19 Open 50-0 CZN 4,869' 4,879' 4,865' 4,875' 10' 5 03/03/19 Open 50-3 CZN 4,897' 4,927' 4,893' 4,923' 30' 5 03/03/19 Open CZNS2 4,952' 4,957' 4,989' 4,953' 5' 5 03/03/19 Open 50-6 CZN 4,992' 5,021' 4,988' 5,017' 29' 5 03/03/19 Open CZNS9 5,102' 5,122' 5,097' 5,117' 20' 5 03/03/19 Open 51-6 CZN 5,122' 5,156' 5,117' 5,151' 34' 5 03/03/19 Open 51-9 CZN 5,170' 5,195' 5,165' 5,190' 28' 5 03/03/19 Open 53-0 DZN 5,260' 5,288' 5,254' 5,282' 28' 5 5/11/2013 Open DZNS2 5,328' 5,335' 5,322' 5,329' 7' 5 5/11/2013 Open 53-8 DZN 5,360' 5,393' 5,354' 5,387' 33' 5 5/11/2013 Open 54-5 DZN 5,424' 5,458' 5,417' 5,451' 34' 5 5/11/2013 Open 54-9 DZN 5,492' 5,509' 5,485' 5,502' 17' 5 5/11/2013 Open 55-7 DZN 5,542' 5,560' 5,534' 5,552' 18' 5 5/11/2013 Open 56-1 DZN 5,587' 5,670' 5,579' 5,661' 83' 5 5/11/2013 Open 57-2 DZN 5,700' 5,744' 5,691' 5,735' 44' 5 5/11/2013 Open 58-1 EZN 5,798' 5,817' 5,788' 5,807' 19' 5 5/11/2013 Open 5,823' 5,837' 5,813' 5,827' 14' 5 5/11/2013 Open 58-7 EZN 5,860' 5,875' 5,850' 5,864' 15' 5 5/11/2013 Open 5,882' 5,948' 5,871' 5,937' 66' 5 05/11/2013 Open 60-0 EZN 5,982' 6,019' 5,970' 6,007' 37' 5 05/11/2013 Open Hemlock 6,157 6,328 6,143 6,312 171 5 06/24/2018 Open Hemlock 6,225 6,330 6,210 6,314 105 5 06/24/2018 Open GAS LIFT MANDRELS Long String STA MD TVD ID TYPE PORT VALVE Psc Date 1 2,180 2,1802.347" 2-7/8 MANA SPMO-1.0F-LT (side string mandrel) 16 DOME 1007 01/14/2023 2 3,338 3,3372.347" 2-7/8 MANA SPMO-1.0F-LT (side string mandrel) 16 DOME 975 01/15/2023 3 4,092 4,0902.347" 2-7/8 MANA SPMO-1.0F-LT (side string mandrel) 20 ORIFICE 01/15/2023 4 4,698 4,6942.347" 2-7/8 MANA SPMO-1.0F-LT (side string mandrel) Dummy 01/04/2023 JEWELRY DETAIL Long String NO DEPTH (MD) DEPTH (TVD) ID OD ITEM 1 340' 340' 2.313" 4.900" TRSSV - Halliburton NE:Locked out January-23. WL-SSSV installed Jan-2023 Total length of WLRSV is: 5 3-1/2 w/lock expanded. (see e-file for WL-SSSV spaceout) 2 370' 370' 2.992" 8.500" Packer - D&L Oil Tools Hydroset II (xxK Shear) w/Weatherford WFT Vent Valve 3 426' 426' 2.313" 2.875" X Nipple 4 5,191 5,186 - - Packoff Plug(5,1915,193)Set 1/5/23 5 5,751' 5,742' 2.205" 2.875" XN Nipple 6 5,755' 5,746' 2.343" 3.250" WLEG Short String NO DEPTH (MD) DEPTH (TVD) ID OD ITEM A 370' 370' 1.940" 8.500" Packer - D&L Oil Tools Hydroset II (xxK Shear) w/Weatherford WFT Vent Valve B 420' 420' 1.710" 2.375" R Nipple C 4,114 4,112 -- CIBP (1/13/23) D 4,712 4,708 1.560 2.375 RN Nipple - Plug installed upon initial completion (2019) E 4,715 4,711 1.995 2.375 WLEG D&L Oil Tools 2-3/8" Telescoping Unions w/24"stroke used to make up short string jewelry (ID 1.750") Rig Start Date End Date ELine 1/5/23 1/27/23 01/12/2023 - Thursday Fly to Monopod Platform. Orientation. Open PTW & PJSM w/ ops. Skid rig and Eline unit over A-07. Begin rig up. Pick up CBL tools and stab on lubricator to the long string. PT to 250/2500 psi, pass. RIH w/ weight bar, centralizer, CBL, centralizer, GR/CCL, centralizer (31' x 1.69" toolstring). Find FL @ 115'. Tag plug @ 5182'. Perform repeat CBL pass from TD to 4800' @ 60 fpm. Log CBL from TD to surface @ 60 fpm. OOH. Lay down CBL toolstring and grease head. Secure well for the night w/ night cap. 01/05/2023 - Thursday Production left GL pressure on short string overnight. Now at 555psi on short string and 220psi on long string. DGLV's are holding. Rig up slickline P/t 2500 PSI on Long String - Pass. RIH/w 2 1/2" GS /w 2 7/8" Packoff Plug to 5211' SLM (5193' RKB C/F -18 based off mandrels ) w/t set on top of AD-2 Stop POOH. Pressure lub to 500 PSI then Open Swab RIH/w 2 1/2" GS /w 2 7/8" AA stop to 5209' SLM ( 5191' RKB) w/t set w/t shear POOH. Felt FL at 2350' MD. OOH Night cap Riser standby for Production P/T long String. Applied 575psi to long string via GL. Looks good, and short string stayed at 120psi. RD from Long String. Move from Long String, standby for Production to Swap 8 Round connections then Stab on P/T 2500 PSI- PASS RIH on short string /w 1.65" Gauge ring Clean drift to 4725' SLM (4712' RKB Neg 13' C/F) tag Plug POOH OOH rig off and Prep for Rig Skid. Felt FL at 2450' MD. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Trading Bay St A-07 50-733-20036-00 167-046 Rig Start Date End Date ELine 1/5/23 1/27/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Trading Bay St A-07 50-733-20036-00 167-046 01/15/2023 - Sunday 01/13/2023 - Friday Open PTW & PJSM. Stab off long string and stab onto short string. Pick up CIBP BHA, Stab on grease head. RIH w/ 12' x 1.5" Weight Bar, 1.5" shorty setting tool, 1.5" Magna range CIBP (OAL 20.5', max OD 1.5"). 6.3' CCL to mid element. Pull correlation pass, on depth. Set CIBP @ 4114' mid element (4107.7' CCL stop depth). Pick up and set down on plug @ set depth. POOH. Bump up and fluid pack short string w/ water. Lay down BHA. Move lubricator from short string to long string. Re-tie cable head. Perform MIT-T on the short string, starting pressure = 2758 psi, 15 min loss 44 psi, 2nd 15 min 26 psi, 3rd 15 min 23 psi, pass. RIH w/ Weight Bar, CCL, magnet, 6' x 1.56" tubing punch, magnet (24.5' OAL, max OD 1.75"). 4.3' CCL to top shot. Pull correlation pass, on depth. Pressure up long string to ~838 psi w/ water. Shoot tubing punch from 4147' - 4153', CCL stop depth = 4142.7'. Starting pressures: LS = 838, SS = 440, IA = 126 5 min: LS = 0, SS = 438, IA = 132 10 min: LS = 0, SS = 423, IA = 134 15 min: LS = 0, SS = 412, IA = 137 Scada tags: MPP_Tubing_PIT_PV = LS, MPP_WH_PIT_A78 = IA, MPP_Casing_PIT_PV = SS POOH. Begin to rig down Eline. Lay down tubing punch BHA. Perform MIT-T on the short string. Starting pressure = 2780 psi, 15 min loss 35 psi, 2nd 15 min loss 16 psi, pass. 30 min final pressure = 2729 psi. Lay down lubricator and secure well. Finish Eline rig down and secure equipment on deck. Fly back to OSK. Install live GLV's Rig Start Date End Date ELine 1/5/23 1/27/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name Trading Bay St A-07 50-733-20036-00 167-046 01/26/2023 - Thursday Chopper to Monopod. PJSM. Permits. Orientation. Review lock out tool procedure with PW operator. Spot equipment & rig up slick line. Attempt pressure test. Cut O-ring. Repaired leak. Pressure test to 2500 PSI. Test good. SI well / flowline. Run in hole with 2.00" drive down bailer w/ mule shoe bottom. Tag fill at 5195' RKB. Jar down for sample. POOH. Recovered black oily fluid but no solids. Run in hole with 2.33" gauge ring to orient depths. Sat down and tagged top polish bore (2.313" ID) of Halliburton NE TRSV flapper valve at 342' RKB. POOH. Run in hole with 2-1/2" braided line brush. Brushed Halliburton NE TRSV for 20 minutes. POOH. Brush is clean. Run in hole with 2.313" Halliburton lock out tool. Lower packing stopped at upper polish bore at 342'. Tapped tools through. Sat down solid at 346'. Jarred down several times to set. Perform pull test. LOT is set. Line up pump. Start injecting water down tubing to pressure up against TRSV. (SI tubing PSI at 200). Pressure rose to 950 on pump. Saw a small spike and then pressure dropped back off indicating LOT has shifted. Jarred down by hand 100 licks to complete lock out of sleeve. Jar LOT free and POOH. LOT is sheared out as supposed to be. A lot of new paraffin build up around X-keys on LOT. Reran braided line brush. Work NE-TRSV 15 minutes. Bled off control line from 4500 PSI to 0. Drifted past flapper and back up above SV without problem confirming flapper is locked out. POOH.Out of hole. Braided line brush has heavy paraffin on it. Discussed w/ Lead Op & Engineer that well may have cooled off from earlier runs in the day & is building paraffin while we are working it. Decision made to flow well overnight to warm back up & re-run braided line brush in morning before running communicator tool. Night cap lubricator. Secure equipment. SDFN. 01/27/2023 - Friday Morning meeting. PJSM. Permits. Shut in well. Run in hole with 2-1/2" braided line brush. Brush NE-TRSV 340 - 350' several times. POOH. Brush was clean. Run in hole with HES Communication tool. With 4500 PSI on C/L, engaged NE-TRSV at 346'. Jarred down to actuate Communication tool. Tool successfully opened C/L pressure and it dropped from 4500 to 250 PSI (Well PSI). POOH. Pinned and assembled 2.313" HES-DKX ball valve / 29-3/4" extension / 2.313" X-lock. Run in hole with WLRSV assembly to NE-TRSV. While tapping lower packing through upper polish bore, SV assembly dropped through and prematurely sheared bottom pin of running tool. POOH. Repinned running tool with steel pins. Reran WLRSV assembly to NE-TRSV at 342'. Locate & set. Pressure C/L to 4500 PSI. Sheared off running tool. POOH. Able to pressure up C/L to 4500 but having difficulty with vee packing not energizing and allowing us to bleed off C/L below tubing pressure. Cycle open & closed WLRSV several times with bleed off improving each time. Flow well 1/2 hour. SI well. Cycle WLRSV. Vee packing seated & working correctly. Achieved 2 solid tests back to back on C/L and DP against ball & seat of 340 to 70 PSI. Notified engineers of successful lock out of NE-TRSV and installation of tested DKX-WLRSV. Lead Op requested AOGCC inspector for 1/30/23. Rig down wireline. Return to beach. Kyle Wiseman Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 02/06/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230206 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPU C-07 50029212660000 185002 1/20/2023 AK E-LINE Perf Paxton 6 50133207070000 222054 1/24/2023 AK E-LINE Perf TBF A-07 50733200360000 167046 1/13/2023 AK E-LINE CBL TBF A-18 50733201430000 168076 1/22/2023 AK E-LINE Tubing Punch TBU D-09RD 50733201310100 181080 1/18/2023 AK E-LINE LDL Please include current contact information if different from above. By Meredith Guhl at 11:24 am, Feb 06, 2023 T37486 T37487 T37488 T37489 T37490 TBF A-07 50733200360000 167046 1/13/2023 AK E-LINE CBL Meredith Guhl Digitally signed by Meredith Guhl Date: 2023.02.06 11:33:21 -09'00' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS RECEIVED APR 0 3 2019 A r% e% J1 r� 1. Operations Abandon LJ Plug Perforations LJ Fracture Stimulate LJ Pull Tubing Ld M"Nai Performed: Suspend ❑ Perforate Other Stimulate[—] Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well❑ Re-enter Susp Well ❑ Other. Dual G/L Completion Q 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development Q Exploratory ❑ Stratigraphic ❑ Service ❑ 167-046 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-733-20036-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0018731 Trading Bay St A-07 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Trading Bay Field / Hemlock Oil, Middle Kenai B,C,D & E Oil Pools 11. Present Well Condition Summary: Total Depth measured 6,407 feet Plugs measured N/A feet true vertical 6,389 feet Junk measured N/A feet Effective Depth measured 6,341 feet Packer measured 370 feet true vertical 6,325 feet true vertical 370 feet Casing Length Size MD TVD Burst Collapse Structural Conductor —264' 20" —264' —264' Surface 1,067' 13-3/8" 1,067' 1,067' 3,090 psi 1,540 psi Intermediate Production 4,810' 9-5/8" 4,810' 4,806' 3,950 psi 2,570 psi Liner 1,651' 7" 6,397' 6,380' 7,240 psi 5,410 psi Perforation depth Measured depth 2,050 - 6,330 feet True Vertical depth 2,050 - 6,314 feet 2-7/8" 6.5 / L-80 5,755 (MD) 5,746 (TVD) Tubing (size, grade, measured and true vertical depth) 2-3/8" 4.7 / L-80 4,715 (MD) 4,711 (TVD) 370 (MD) 340 (MD) Packers and SSSV (type, measured and true vertical depth) D&L Hyd II Dual Pkr 370 (TVD) Halliburton TRSV 340 (TVD) 12. Stimulation or cement squeeze summary: Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation:1 0 175 0 98 82 Subsequent to operation:1 254 230 264 79 83 14. Attachments (required Per 20 AAc 25.070, 25.071, & 25.283) 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 Q Gas ❑ WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 318494 Authorized Name: Stan W. Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: dmadowe(a)hilcem.com Authorized Signature: Li 6& Date: z Z 19 Contact Phone: (907) 283-1329 RBDMSd0t,/APR 0 4 2019 Form 10-404 Revised 4/2017 Submit Original Only Trading Bay Unit SCHEMATIC Well # A-07 API# 50-733-20036-00 PTD: 167-046 Last Completed: 03/06/2019 O I Esu Rngr= 38.27 CASING DETAIL KB to MSL = 101'. MSL to Mudline 66' SIZE I 'W I GRADE I CONN to I TOP IBTM. , BZN C 11 C, CZN L= >5 6a 1 E Zone Top IMD) Stm(MD) C, CZN Btm D) Amt N DZN SGtus Qt1 EZN wo 'Dept' HEM PBTD = 6,341' 00 TD = 6,407' MoD) ANGLE thru INTERVAL = 3.20 Zone Top IMD) Stm(MD) Top MO) Btm D) Amt Sp, Date SGtus 1rxeW Detrol 2,050' wo 'Dept' DWth w 00 ft MoD) (M) ID OD Item Wn S do. 90' S Mn4/19 ESh. 9Mng 2,702' ;817' 2594' 1 34PU34V232-.313" 03/03/19 Open. 2,874' 719%' 2,873' 1906' TBSV-HallibuRonNE 2 370'2.992" Open 2,875' 2,90]' 370 3]OP 1,9W &507" Packer D&LOil Tools Horowt 11 oPKShear)w/ WeaNerford WETVentValve Open 426'2.313" 2'883 2A%' 21881' 2895' east 420' 1.]82" 23]5" Nip les- Wn Sida X Short SideR 2,920' ,1D2'2.Ur 2,919' 2,946' 27, 14.�4,�W 2174' 3,337' 21]4' 3,336' ].901° 1,Or 4750" 4.750" OLMgl-2-3/8"&2-71W MANA SPMO-1.0FLT)dtle sttln mandrel) GLM92-2-3/B"&2-]/8" MANNSPMOl.OFLT(sdealringmandm14.2'2.34]" GLM N3-2-3/8°&2-7/8'MAMASPMOLO6LTsMe.34]" 43,338'2,347 4"V 4,089' 19D3' 4.759' 24' 4 9/wl. Open 2,928' 8 4,694' Lwl" 4.750' '.,GLMp4-2-3/W&2-7/8"MANASPMO 1.OFLT)slde5 8/17/1970 5,751'.791° 2,997 3,076' 2%6' 4,71r CM8' 1.640' 2.375" Nipples -b Side%N, Shod 9tle RN w/ lu inshlle6 33-68ZN 5,755'2.343° 3p]]' ;9%' 3p76' ]B' 4,735 4,711' 3.995 2375" .07.665 DSL OU Tee623/r Ttleuepi Dnims w/ 2P stroke uvd W make up snort pan wN )ID 1]50'1 3,075' Zone Top IMD) Stm(MD) Top MO) Btm D) Amt Sp, Date SGtus UN 2,050' 2tN 21059 2,120 70 5 06/24/18 Open BZN 2,244' 21334' ;2M' ;33V 90' S Mn4/19 Open 2,702' ;817' 2594' 2616' 3.5' 03/03/19 Open. 2,874' 719%' 2,873' 1906' 5 03/03/19 Open 2,875' 2,90]' 2874' 2,076' ]Y 4 9/7/1988 Open 2'883 2A%' 21881' 2895' 14' 4 8/1]/19]0 Open 31-8BZN 2,920' Z94T 2,919' 2,946' 27, 5 03/03/19 Open 2,923 2,947' 2,922' 2,946' 24' 4 9/wl. Open 2,928' 2944' 2927' 2943' 16' 4 8/17/1970 Open 2,997 3,076' 2%6' 3,075' 79' 4 9/9/1988 Open 33-68ZN 2,999' 3p]]' ;9%' 3p76' ]B' S (X3/03/19 Open 3,W ",,' 3,d . 3,075' 32' 4 8/1]/19]0 Open 3,193' 1242' 3,192' 1 3,241' 11 49' 5 03AO119 open 3,196' 3,208' 3,195' 3,207 II' 4 B/1]/19]n Open 3,196' 3,249 3}95' 3139' 44' 4 9/10/1908 Open 3,214' 3,240 3,231' 3)% 26' 4 8/17/1970 Open 41-3 UN 3,282' 1433' 3,281' %e33' 151' S 03/03/19 Open 3.283' 3,435' 3,2H2' 3134' 52' 4 9/11/1980 Open 3290' 3134' 3.289' 3133' 148 4 W17/1970 O en 3,300 3,320' 3,299' %,Ow 2V 4 9/10/1970 Ont Sod 3,795' 3,907' 3,]93' 3958' 65' 4 9/u/19% Open 3,M3' 3,959' 31071' 3,957' 356' 5 03/03/19 Open N9 RN 31807' 3,850' 3,077' 3,848' 42' 4 9/17/1970 Open 3,820' 3,Wtl Se1B' 3,M8' 211' 4 9/10/1%7 Cmt Szpd 3,858' 3,958 3,856' 3,954' w 4 8/1]/19]0 Open 0.2 4,037' 4,091 4135' 4p95' id 5 03/03/19 Open L3 4,127' 4,224' "in. 4,221' 1. 5 03A)3/19 Open 4,125' 4,225' CUT 4,222' lW' 4 9/15/1967 Cmt5z46 00.7 UN 4,140' 4,10' 4,33&' 4,157' 2tl 0/1967 Ont S,,d UNS6 4,26T 4,135' 4,264' 4,332' 69' /03/19 Open C4 4,340' 4,371' 4,341' g36B' 27' /03/19 Open CS 4,429' 4p]9' 4126' 41]6' S0' M3/]9 Open L6 4,607 4,639' 4,595' O,fi35' 39' 3/19 Open 40.7 BZN 4,6M' 4,625' 6,CA1' 4,621' 1 0/196] Ont Sz4d 4,6]0' 4,M 4,666' 4,6%' 30 03/19 #503/03A� Open C2W7 4,]ID' 4,740 4,716' 4,]35 20 /03/19 Open C] 4,707' 4,781' 4,756' 4,27]' 21' 0349 Open 49.K2N 4,WT' 4,829' 4,83 4,825' 22' o3/19 On 50.0CZN 4,869' 4.8]9' 4,%5' 4,8]5' 10' 03/19 Oppn 563 CZN 4,89T 4,927 4,893' 4,923' 30 M/19 Open Uhtt2 4,957 4,%7' 4,989' 4,953' S' 03/19 Open 504 CZN 4%2' Sp21' 4,980' 5,01]' 29' 03/19 Open UM9 5102' 5,122' 5,097' 5,117' 1. 5 03/03/19 Open 516 CZN 5122' 5,nw 5,11]' 5,131' 34' 5 M/03/39 Open 51m9 CZN 51170' 5,195' 5165' 5,190 2B' s W03/19 Open 53 0 DZN 5,260' 5,288' 1,P14 50M w 5 5/11/2013 Open DZN52 5,328' 51335' 5,322' 5,329' 7' 5 511WO13 Open 53-e DZN 5.307' 5,393' 5,354' 5,387' 33' S 5/11/2013 Open 54 5 DZN 5124' 515B' 5417' 5151' 34' 5 5/11/2013 Open 50.9 DZN 519P 5,W9' 51e85' 5,502' 1' 5 5/11/2013 Open 557 DZN 5S4T 51507' 5,53kV 5,552' o. S 5/iv/m' Open 561 DZN 5,587 5,6m' 5,57A SA61 83 5 5/1V2013 Ocen 57-2 WN 5,7W 5,704' 51691' 5,735' 1. 5 5/11/2013 Open 5,798' S,B1]'1 5788' 5 Po 19' 5 5/13/2013 Open 58-1 E2N BY 513]' 5,013' 5AD' 14' S 5/11/2013 Open 5,860' S8]S' 5,BW' 5X4' 15'5 5/11/2013 Open 5&7EZN SA82' 5,948' 5,871' 5,937' 66' 5 05/11/2013 Open 600 E2N 5982' 6.019' 5,wor P. 31 5 05/11/2013 Open Hemlock 6,151 6,328' 1k103' 8312' 171' 5 %/24/2018 Open Hemlock I 6,225' ",t Y I 62W 1 6,314' 1M' S 06/24/2018 Open Updated by: JLL03/20/19 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Rig 56 50-733-20036-00 1 167-046 2/14/19 1 3/6/19 Daily Operations: 02/14/2019 - Thursday Held kick-off meeting with AAO, Peak and all contractors at AAO office. All American Oilfield and contractors arrive on platform. Orientation with crews. Clean debris from rig floor sumps. Clean debris from trip tank and cellar box. String power cord from rig floor to derrick board for mules. Drain pits to production. Uncover shakers and begin housekeeping around pits. Assist crane crew with stowing mud product below deck. Continue with housekeeping and organization. Rig orientation with new crew and permit training. Inventory pump parts. Install suction manifolds. Fire up Hotsy and beginning on rig floor. 02/15/2019 - Friday Orient crew with rig and platform. Put suction manifold together. Clean pits. Work on pump parts inventory. General housekeeping. Clean rig floor, pipe deck and pit area. Begin dressing out mud pumps. Install SRL's in cellar. Check oils and inspect equipment. Organize tools and parts. Add weight to tong counter weights. Continue dressing mud pumps. Perform derrick inspection. Install SRL's in derrick and inspect remaining SRL's. Replace derrick assist cables. Drain drawworks contaminated gear oil. Wire in jet heater. Check all pit agitator oil levels. Finish derrick assist cable install, but needs new master link on tie -off chain. Begin filling drawworks with gear oil. Relocate derrick mules to pump room. Assist with rig up of hose to take water onto platform from boat. Finish drawworks oil change. Clean drains in cellar and drill deck. Continue dressing mud pumps. Rig up heater trunks to rig and fire jet heater. Hook up steam to rig floor. Prepare flanges and locate clean studs for mud line to rig. 02/16/2019 -Saturday Finish drawworks oil change. Dress out Mud Pump #1. R/U HP mud hoses to rig. Function accumulator pumps. Function mud pumps, blowers and rod wash pumps. Install deluge line to rig. Pressure test PRV's. Rig up circulating hoses to tree. Orientation with fluid moving systems (pits, hoppers, suctions, discharge, and FIW lines). Move fluid through system to verify functions. Finish MP #1. Continued crew training on pit fluid line-up, valve locations and positions. Determined 100 lbs of extra weight needed for counter weights for rotary tongs. Measured length of cable needed for Kelly pull-back (67'). Secured ODS tong weight bucket pin. DS weight bucket still not freed on the pin (will continue working on it). Mixing LCM pills. Continue building salt pills. Remove flange on choke line. Begin installing bridge cranes. Continue freeing up DS tong weight bucket. R/U water to rig. Service choke manifold. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Rig 56 50-733-20036-00 1 167-046 2/14/19 1 3/6/19 Daily Operations: 02/17/2019-Sunday Finish rigging up bridge cranes. Housekeeping in pump room. Prime pump to pressure test lines. Clean suction manifold. PJSM on pumping pills. Pressure test lines to 2500 psi. Pump 20 bbls saturated salt pill followed with 45 bbls sized salt pill, plus 10 bbls SS pill and chase with 10 bbls FIW. Shut in well and allow to fall. Troubleshoot and adjust super choke stroke counter. Troubleshoot and repair stroke counter for MP #2. Begin replacing defective butterfly valves at pill pit. Assist with snow removal on decks and heliport. Continue working on tong counter weight issues. Install drawworks and rotary table blower hoses. Gather equipment needed for testing choke manifold. Continue changing out bad butterfly valves on pill pit and hopper. Finish tong counter weight task. Install cardboard carpet in camp and traffic areas. Finish replacing butterfly valves on pill pits and hopper system. Run Kelly spinner control lines to driller console. Rig up to pressure test choke manifold. Rig up hoses to pump down annulus, Pump 30 bbls FIW down annulus at 2 BPM. Starting pressure at 220 psi which built up to 260 psi. Final pressure 220 psi. Tubing remained at 210 psi. Monitor tubing and annulus every 30 minutes. Rig up 16" heater trunks from Jet heater. Rig up and test choke hose. 02/18/2019 - Monday R/U and pressure choke lines to 5000 psi on chart for 10 minutes. R/u to pump down tubing. Bleed off annulus to flare tank. Install splash guard on cable tray behind drawworks. Mount well control board behind driller console. Begin installing flow lines. Circulate 345 bbls FIW down tubing at 5 BPM/210 psi with no returns. Shut down. Annulus on vacuum after 30 minutes. Finish installing flow lines. Begin mixing pills in upper and lower mix rooms. Obtained measurements for additional weight configuration on tong weight buckets. Continue mixing salt pills. Install rat hole pull back brace in derrick. Set two boxes of accumulator on rig floor to thaw. Hang harness rack behind drawworks. Housekeeping in all areas. Begin sorting and staging accumulator hoses in cellar. Finish mixing salt pills. Line up and pump 35 bbls saturated salt, 184 bbls sized salt, 10 bbls saturated salt and chase with 25 bbls FIW. Pumped at 5 BPM with high pressure of 400 psi. Beginning: 130 psi on tubing and annulus. Continue staging accumulator hoses in cellar. Housekeeping in pump room and pill pits. Fluid Losses Total: FIW 575 Sized Salt: 229 Saturated Salt: 75 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Rig 56 50-733-20036-00 1 167-046 2/14/19 3/6/19 Daily Operations: 02/19/2019-Tuesday Inventory ring gaskets. R/D circulating hose from tree and reroute through correct portal on well room wall. Continue sorting and connecting accumulator hoses. Housekeeping around mud pumps and pill pit area. Begin mixing salt pills. Continue with general rig prep and housekeeping. Obtain measurements for stabbing board placement. Clear floor of mud boxes and bring up mud cross valves and components to thaw out. Finish mixing salt pills. Pump 18 bbls saturated salt, 43 bbls sized salt 17 bbls saturated salt and chase with 25 bbls FIW. High pressure of 600 psi while pumping down tubing. No returns to surface. Monitor annulus (static). Continue preparing bolts and equipment for nipple up. Assist with off loading helicopter. Begin mixing salt pills. Continue prepping equipment for nipple up. General housekeeping throughout rig package. Line up on annulus with tubing shut in. Load annulus with 84 bbls of FIW using charge pump at 45 psi. Monitor well. Continue with rig acceptance projects. Tubing and annulus equalized at 40 psi. Begin bleeding off through production header at report time. Fluid Losses Daily: FIW: 25 Sized Salt: 43 Saturated Salt: 35. Fluid Losses Total: FIW: 600 Sized Salt: 272 Saturated Salt: 110 02/20/2019- Wednesday Rig up annulus to production and bleed off gas. Rig up circulating hose to annulus. p 60 bbls FIW and pumped a total of 180 bbls and still on vacuum. Begin mixing salt pills. Dress out shakers. Install suction screen on MP #2. Using charge pump load annulus with 96 bbls sized salt pill followed with 10 bbls FIW. Annulus on vacuum. Continue preparing BODE for nipple up. Grease crown. Mix sized salt pill and ship up to Pit #1. Fill Pit #2 with 90 bbls FIW. Mix 35 bbls saturated salt pill. Check flow path. Send down annulus 20 bbl saturated salt and 20 bbl sized salt pill using charge pump. Using MP #2 pump 70 bbls sized salt and 15 bbls saturated salt and chase with 20 bbls FIW at 2 BPM. Final pressure with tubing shut in: 500 psi on tubing and 400 psi on annulus. Monitor well. Continue general rig prep on BOP components. General housekeeping in mixing area. Begin mixing salt pills. Jet heater and hydraulic unit and broke down. Continue mixing salt pills. Work on charge pump coupling. Charging battery on Jet heater. Prepping BOPE for nipple up. Checked well at 0300 hrs/well is static. Line up on tubing taking returns to production. Pump FIW at 3.5 BPM/200 psi. Caught pressure at 50 bbls pumped and crude oil returns at 70 bbls pumped with 700 psi. Shut down and shut in while initiating NPFT. Monitor pressures. Continue mixing salt pills. Fluid Losses Daily: FIW: 497 Sized Salt: 96 Saturated Salt: 0. Fluid Losses Total: FIW: 1097 Sized Salt: 452 Saturated Salt: 190 02/21/2019 - Thursday Cont. work on activation list while monitoring well. Circulate well @ 5 BPM, 800 PSI, get returns @ 50 bbls. Cont. circulate until clean. Slowed rate t/ 3.5 BPM pumped 470 bbls total. Monitor well, one hour, check fluid loss 28 BPH. Set BPV, N/D tree, prep wellhead, check lift threads, install blanking sub. Unload boat, N/U BOPE. PJSM/JSA with OPS. Make up DSA to Riser and install on Well Head, Set Single Gate BOP and Mud Cross in place. Conduct platform orientation with new crew. Continue with N/U of BOPE. Attach Kill and Choke line valves to Mud Cross. Attach DSA's for Kill and Choke lines. Set Double Gate BOP'S and Annular in place.Fluid Losses Daily: FIW: 86 Sized Salt: 90 Saturated Salt: 0. Fluid Losses Total: FIW: 1045 Saturated Salt: 130 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Rig 56 50-733-20036-00 1 167-046 2/14/19 1 3/6/19 Daily Operations: 02/22/2019 - Friday N/U BOPE. Torque all bolts on BOP Stack. Iristall riser Boot Adapter on top of Annular and bottom of Flow Box. Begin making up Choke and Kill lines. N/U BOPE. Continue with final torque of all BOP bolts. Sort and connect Koomey lines. Trim and install Flow nipple. Install centering binds on Stack. Stage X/0's and floor valves on rig floor. Get RKB measurements: RKB to Wellhead = 40.53', RKB to Annular = 14.50', RKB to Upper Pipe Rams = 17.02', RKB to Blind Rams = 18.62', RKB to Single Gate BOP (no rams) = 22.61. N/U BOPE. Install Choke and Kill line target tees and install Choke and Kill lines. Pressure up Koomey, function test rams to verify no leaks on control lines. N/U BOPE. Install Blind Rams (bottom cavity) and 5" X 2-7/8" VBR'S (top cavity) into Double Gate BOP. R/U rig floor tongs. Rig up 2-7/8" test joint . Function test rams and annular preventer. Flood BOPE and choke manifold with FIW. R/U PT equipment to test BOPE. Shell test BOPE and Choke Manifold, 250 psi low / 2500 psi high. Tighten kill line flange and function CM valve #16. Repair leaks as required. Fluid Losses Daily: FIW: 0 Sized Salt: 0 Saturated Salt: 0. Fluid Losses Total: FIW: 1045 Sized Salt: 458 Saturated Salt: 130 02/23/2019 - Saturday Cont. Shell testing BOPE 250/2500, repairing leaks as needed. Cont. shell testing BOPE had leak on doublegate from weep plug on upper rams, contact Axom for direction. Open door & check seal while waiting on call back, close door & function rams as per Axom. Retest good. Cont. checking surface eq. testing @ 250/2500 repairing visual leaks on mud cross & choke manifold. Function Annular multiple times to break in new element and achieve good test. Test BOPE as per procedure with AOGCC Inspector Adam Earl present to witness. Tested annular, pipe rams, choke and kill line valves and choke manifold to 250 psi low and 2,500 psi high. Performed draw down test on annular. Initial pressures: ACC= 3000 psi, MAN = 1600 psi, ANN =1550 PSI After function: ACC= 1450 psi, MAN = 1500 psi, ANN = 1400 PSI Final psi :3000 psi (+200 psi = 30 sec., 3000 psi = 158 sec.) Pull test joint and rig up to test Blind Rams. Attempted low pressure test on Blinds Failed. Cycled rams several times without a successful test. Isolate choke manifold and verify leak in stack. Suspected leak at blanking plug as no fluid was observed leaking past Blind Rams during test attempts. Pull blanking plug and immediately had seepage of gas through BPV. Closed Blind Rams and observed gas leaking past Blind Rams. Opened choke and lined up through gas buster and leakage at Blinds ceased. Closed hydraulic choke and saw leakage at Blind Rams with —50 psi showing on choke. Rigged up and circulated FIW through kill line and out choke slowly closing choke (initial bull heading psi= 175 psi, Final psi=33 psi) Bull headed 30 bbl FIW and hole went on vacuum. Open Blind Rams and observed BPV still leaking. Closed Blind Rams and bull headed another 37 bbl FIW down tubing. Opened Blind Rams and observed well was static. Reset BPV monitor well and install blanking plug. Run test joint in hole and test blanking plug against Pipe Rams (250 low/ 3800 high) 5 min each. Blow down BODE and Choke Manifold. Pull test joint. Open Blind Ram doors and pull ram blocks for inspection. Fluid Losses Daily: FIW: 67 Sized Salt: 0 Saturated Salt: 0. Fluid Losses Total: FIW: 1112 Sized Salt: 458 Saturated Salt: 130 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Rig 56 50-733-20036-00 1 167-046 2/14/19 1 3/6/19 Daily Operations: 02/24/2019-Sunday Cont. troubleshoot Blind ram issues, check Hyd path & inner seals good, open doors, check carriers, swap rams to alternate cavities test same. Blind rams tested in upper ram cavities, Pipe rams would not hold water in lower cavities. Open doors on both upper and lower ram cavities. Function rams to close position and measure piston lengths. (TOP= 0.875 and 0.83 , BTM = 0.81 and 0.80) Decision made to N/D and change out Double Gate BOP's. Button up doors and N/D BOPS. Remove Flow Riser, Annular and Double Gate BOPS from cellar. Tie onto M/C, Single Gate BOP, Riser and DSA with lifting beam. Break bottom 11" DSA connection and pick up assembly off of well head and secure. Tie into vent valve control line, pressure up and block vent valve in open position (Observed Ann. psi increase from 0 psi stabilizing at 210 psi) Nipple up M/C, Single Gate BOP, Riser and DSA to wellhead. Nipple up Weatherford Double Gate BOP, Annular and Flow Riser. Install 5" X 2-7/8" VBR rams in top cavity of Double Gate BOPS. Function test rams. Change out hydraulic control hose on close side of blind rams. Fluid Losses Daily: FIW: 0 Sized Salt: 0 Saturated Salt: 0. Fluid Losses Total: FIW: 1112 Sized Salt: 458 Saturated Salt: 130 02/25/2019 - Monday TROUBLE SHOOT KOOMEY HOSES AND FUNCTION TEST ALL RAMS TO ENSURE EVERYTHING IS FUNCTIONING PROPERLY. TEST VBR RAMS WITH 250 PSI / 2500 PSI ON 2-7/8" PIPE. TEST BLIND RAMS 250 PSI / 2500 PSI. TEST VBR RAMS AND ANN. WITH 250 PSI / 2500 PSI ON 3-1/2" PIPE. PERFORM KOOMY DRAWDOWN TEST WITH 3.5" TEST JT. START: ACC=3000PS1, MAN=1500PSI, ANN=1050PSI. AFTER FUNCTION: ACC=1500PSI, MAN=1500PSI, ANN=1200PSI. +200PSI=30 SECS. FINAL=177 SECS 3000PSI. 6 BOTTLE BACK-UP AVG.=2400PSI. BREAK DOWN TEST JOINT AND LAY DOWN SAME. PUMP 47 BBLS. OF FIW DOWN TBG. (TBG. ON VAC) PULLED BPV. PUMP DOWN ANNULUS (20 BBLS SAT. SALT, 90 BBLS SIZED SALT, 20 BBLS SAT. SALT, 20 BBLS FIW) SHUT IN & MONITOR WELL 1 HOUR. PUMP DOWN TBG. (PUMPED 7BBLS BEFORE CATCHING PRESSURE, @ 51BBL5 PUMPED DETECTED 100 PSI PESSURE DROP) OBSERVED RETURNS @ 175BBLS PUMPED. STOPPED PUMPING @ 460BBLS FINAL CIRCULATINE RATE 1320 PSI @ 4 BPM. MONITOR WELL FOR 10 MIN. PUMP TO DETERMINE FLUID LOSS. TBG. PRESSURE OBSERVED @ 7BBLS PUMPED, OBSERVED RETURNS ON ANN @ 20 BBL PUMPED. ( FLUID LOSS TO HOLECALCULATED @ 66 BPH. CLOSE WELL IN AND MONITOR. MONITOR WELL. P/U TBG. HANDLING EQUIP. P/U AND M/U 2 7/8" LANDING JT. STAGE. PREP. POWER TONGS FOR USE. FILL PITS WITH FIW. PJSM ON RIG FLOOR FOR PULLING COMPLETIONS. PUMP DOWN TBG. TO FILL HOLE. (OBSERVED PRESSURE AT 51 BBL PUMPED, RETURNS OUT ANN WITH 144 BBL PUMPED.) TOTAL PUMPED =200 BBL. FINAL CIRCULATING RATE 720 PSI @ 4 BPM. SCREW LANDING JT. INTO HANGER, BACK OUT LOCK DOWN SCREWS AND PULL HANGER TO RIG FLOOR. (OFF SEAT HANGER W/ 45K UP, RELEASE PACKER W/70K, STRING PICK UP WEIGHT =55K) BREAK OFF HANGER AND LAY DOWN SAME (SSSV AND PKR VENT VALVE BOTH BLOCKED OPEN) ESTIMATE FLUID LOSS TO HOLE @ — 80 BPH. PERFORM WELL CONTROL AND CABLE CUTTING DRILL WITH CREWS. PULL TUBING. RIG UP ESP CABLE SHEAVE AT V-DOOR AND STRING CABLE THROUGH TO SPOOLING UNIT. Fluid Losses Daily: FIW: 599, Sized Salt: 90, Saturated Salt: 40. Fluid Losses Total: FIW: 1711, Sized Salt: 548, Saturated Salt: 170 Hilcorp Alaska, LLC Q Well Operations Summary�� Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Rig 56 50-733-20036-00 167-046 2/14/19 3/6/19 Daily Operations: 02/26/2019 -Tuesday Finish RU to pull ESP and PCH to SSSV spooling cable and control line. LD SSSV at 300' and packer at 413'. Hole taking 80 BPH. Continue PCH to about 2,000'. Hole still taking 80 BPH. Pipe started coming out covered with oil. Work on getting steam jenny working. Had to get production electrician to get it heating up and working properly. Continue POH w/ ESP 1100'. Well still taking 80 BPH. Continue POOH W/ ESP to 653' w/calculated fluid losses of —54 BPH. Began observing Scale/Sand behind clamps at 1100' (3523' hole depth) Summit Flat cable spooler locked up. Disconnect drive and continue POOH rolling spool by hand. Continue POOH to XN Nipple @207'. Scale/Salt on clamps starting at 240' (4382' hole depth). Continue POOH, L/D XN Nipple and ESP assembly to 78' (fluid losses continue @ 54 BPH) Continue L/D ESP assembly. R/D and clear ESP equipment from floor. Clean Rig Floor Rig Up Pollard Wireline and RIH W/ 8.15" junk basket for gage ring to top of 7" liner @ 4746'. L/D 8.15" junk basket. P/U 5.95" gage rig and RIH to 5327' (unable to work past obstruction at 5327') PCH and R/D Pollard Wireline. Fluid losses 0000 - 0600 hr. @ 54 BPH, Canon Cross Collar Clamps Recovered = 78, Splice Clamps Recovered = 2, Motor Clamps Recovered = 5, Seal Clamps Recovered = 4, Pump Clamps Recovered = 23, Bands Recovered = 19. Fluid Losses Daily: FIW: 1284, Sized Salt: 0, Saturated Salt: 0. Fluid Losses Total: FIW: 2995, Sized Salt: 548, Saturated Salt: 170. 02/27/2019- Wednesday Finish clearing floor of wireline tools. Loss rate to well is 54 BPH. Rig Up ST -80 on rig floor and test same. Finish rigging up to PU clean out assem. Get BHA strapped and drifted. PU clean out BHA. 6" Bit w/ no jets, Bit Sub, six 4 3/4 DCs. =185.43'. Continue RIH, strapping, drifting, & PU 3 1/2 DP to 1018'. Continue RIH PU 3 1/2 DP to 1712' and blew an hyd hose on the ST - 80. Hose on ST -80 may have been strung incorrectly because it wore through from rubbing on the frame. String new hose through a diff path and re- string another hose that was starting to wear. Both hoses were to the make and break cylinder. Hose was 5'6" overall length. Losses to well are 42 BPH. Continue RIH PU 3 1/2 DP to 3043'. Held BOP drill while tripping. Good response from crew. Continue RIH PU 3 1/2 DP to 4693'. Install TIW valve and monitor well (Fluid losses at 48 BPH). L/D elevators and bails. Clear floor and stage Kelly swivel, spinner, valves and subs on floor. Screw Kelly swivel assembly into Kelly and lay down Kelly shuck. Install Kelly bushings on Kelly, pick up and torque lower Kelly cock and saver sub to Kelly. Make up Kelly to string and RIH. Torque upper Left Handed connections from Kelly to Swivel. (Mixed 42 bbl high vis sweep while picking up Kelly). Rig up turnbuckles from swivel to spinner, make up spinner and Kelly hoses. Pull out of hole and break off Kelly. Rig up and test lower and upper Kelly cocks on chart with 250 psi low / 2500 psi high. (Good Tests) Fluid losses to hole = 43 BPH. Rig down test equipment and blow down Kelly. Fluid Losses Daily: FIW: 1224, Sized Salt: 0, Saturated Salt: 0. Fluid Losses Total: FIW: 4219, Sized Salt: 548, Saturated Salt: 170. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Rig 56 50-733-20036-00 167-046 2/14/19 3/6/19 Daily Operations: 02/28/2019 -Thursday RU pull back line to stand back Kelly. Had to pull mouse hole back and secure it at the bottom to get Kelly back out of the way. Put bails and elevators back on swivel. Clean floor and service rig while waiting on chopper and crane crew change out. RIH PU 3 1/2 DP f/ 4693' t/ 5323' where we tagged fill. Kelly up and break circ. Bring circ rate up to 6 BPM and had a 1003 union on the standpipe leaking. Drain and blow do lines. Loss rate 45 BPH. Circ across well. Break union and standpipe clamps. PU stand pipe and replace O-ring in union. MU union and test mudline and standpipe to 2000 psi and it held good! Retighten all the standpipe clamps and secure 1" Kelly spinner lines to Kelly hose while doing that. Clean out fill (/5323 t/ 5700'. Ream down 1 st single then just wash do to 5487' where we started taking wt again. Ream from there to 5700'. Running 60 rpm, 8BPM, 1150 psi, Up and Dn wt 85k. Loss rate has been hanging in there at 45 BPH. Cuttings at shakers has been sand and we are catching samples. Ream from 5700' to 5836',Circulate 43 bbl. Hi -Vis sweep around - No visible change in cuttings observed with sweep back at surface. Ream from 5836' to 6342' (tagged solid) RPM=60, TQ=2k, SPM=80, PSI= 1050, PUW= 98k, SOW= 96k, ROT=97k. Cuttings at shakers have been sand (catching samples) Fluid losses to hole at rate of 40 BPH, Circulate 43 bbl. Hi -Vis sweep around. No visible changes in cuttings observed with sweep back at surface. Shakers unable to handle last sweep and blinded off filling cuttings tank. Shut down circulating and changed out cuttings tank. Complete circulation of sweep to surface. RIH dry and tag bottom (no fill),Stand back Kelly. POOH f/ 6342'. Overpull at 5815' (55k over, slacked off and came back through with no overpull), @ 5775' (15k overpull, clean on 2nd pass through), @ 5630' (pull up to 25k over with no movement several times, free down),Pick up Kelly and break circulation. Wash up through 5630' with no overpull. Took 5-8k on initial pass down through it but nothing up or down after. Worked through dry several times with no issues. Stand back Kelly to resume trip out of hole. Fluid Losses Daily: FIW: 1056, Sized Salt: 0, Saturated Salt: 0. Fluid Losses Total: FIW: 5275, Sized Salt: 548, Saturated Salt: 170. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Rig 56 50-733-20036-00 167-046 2/14/19 3/6/19 Daily Operations: 03/01/2019 - Friday Continue to POH to TOL at 4746' with no issues. PU Kelly and break circ. Pump 40 bbl high vis sweep and circ it out of the hole. Got back about 3 bbls of sand back. Blow down and stand back Kelly. POH leaving BHA and 9 1/3 stds of DP in the hole for 20k wt below the storm packer. Loss to well 44 BPH. MU storm packer. RIH and set packer at 287'. [Up and Dn wt 34k] Test packer to 2500 psi. Good test. Release from pkr and POH. Drain stack and prep to remove BOPS for tbg spool swap. Pull master bushings, Clean out drip pan. Pull flow nipple. Pull bottom off drip pan, Remove flow nipple boot off annular. MU BOP picking beam on annular, Work on breaking bolts loose on tbg spool. Break and remove bolts under sng gate and finish breaking bolts loose in wellhead room. PU stack and trolley it off to the side. Put lifting eye on riser. Hold PJSM with production. Pull riser with tbg spool off wellhead and pull up to rig floor. Clean up wellhead and prep new spool. Lower tbg spool into wellhead room. Set tbg spool pack -off seals on 9-5/8" stub looking up. Lower riser with blocks from rig floor and press tubing spool pack off seals down over 9-5/8" stub. Tighten 13-5/8" 3000 flange bolts on bottom of tbg spool. Pressure 13-5/8" X 3000 void to 1800 psi (seals holding on inside but observed leak on flange). Bleed off pressure. Proceed to N/U Riser. Trolley BOP Stack back over riser, lower and install bolts to riser. Torque up flange bolts on wellhead, riser and BOPS (Having to use hammer wrench on wellhead flanges - blew seal in one torque head and sheared pin in the other) Re -connect hyd. control lines to Choke and Kill line HCR valves. N/U flow nipple boot, flow nipple and install bottom of drip pan. Continue torqueing flange bolts. Re -test 13-5/8 3M flange void to 2500 psi and hold for 5 minutes (Good test witnessed by Northern Oil and DSM) N/U flow nipple boot, flow nipple and install bottom of drip pan. Install hyd. control lines to single gate BOP. Install Dual ram VBR blocks in single gate BOP. Gather up X/0's and pups to rig floor for dual string test joint. Pick up half of dual string hanger and make dummy run to check orientation of alignment pin. Fluid Losses Daily: FIW: 528, Sized Salt: 0, Saturated Salt: 0. Fluid Losses Total: FIW: 5803, Sized Salt: 548, Saturated Salt: 170. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Rig 56 50-733-20036-00 1 167-046 2/14/19 1 3/6/19 Daily Operations: 03/02/2019-Saturday MU dual string test it w/ 2 7/8 and 2 3/8. Land testjt, fill and purge stack. Test lower pipe rams w/ dual rams to 250 low and 2500 psi high. At 8:40 we had not heard back from the AOGCC yet so I called Jim Regg and he waived the witness of the test. RD dual string test it. MU 3 1/2 test jt and land in wellhead. Test all BOP equip to 250 and 2500 psi. Perform choke tests. Run testjt back in and perform accumulator test. Pull test plug. When testjt was pulled to the rig floor it had been partially crushed. This had happened when the dual VBRs were closed Inadvertently during the Accumulator test. LD testjt and discuss options. [Blow down test equip],MU dual string test plug and test assem. Re-test 2 3/8 X 3 1/2 Dual VBR rams 250 low and 2500 psi high for 5 min each (Good Test). RD dual string test assembly. M/U TriPoint storm packer stinger and RIH to top of Packer @ 287'. Attempt to screw into tool without success. POOH and inspect tool. (Threads covered with debris). Clean tool and run back in hole to top of storm packer. R/U and circulate at top of tool. Attempt to stab in and rotate W/O success. Tag top of packer and pick weight up off of tool. Circulate 40 bbl FIW @ 6 bpm and 275 psi to clean threads. Set down 1000 Ib. on packer and rotate into tool 11 turns to right. Storm valve opened and drill pipe went on a vacuum. Closed annular and picked up (35k) on packer to open bypass (well on vacuum) Open annular and began filling hole through kill line with DP open. At 40 bbl pumped began seeing gas venting out of DP. Close in DP safety valve and Annular. Line up to circulate down DP and out through choke manifold. Pump total of 230 bbl of FIW before seeing returns at gas buster. Circulate another 60 bbl. and shut down pumping. (Final circ. rate was 450 psi @ 5 bpm) Verified all pressures were zero and opened Annular. Rig up to fill hole with charge pump through kill line and rig down circulating head from drill pipe. Initial fluid losses after filling the hole estimated at 50 BPH. POOH with Storm Packer. Lay down Packer. POOH standing back 9 std. 3-1/2" DP. Lay down lea. 3-1/2" DP and 6ea. 4-3/4" DC. Clear and clean up floor. Fluid loss to hole = 34 BPH. Rig up to run Tripoint TCP guns. Make up safety joint and secure in V-door. Hold PJSM with crew on running procedure. Place 1st basket in V-door. P/U and run TCP guns as per Tripoint procedure. Fluid Losses Daily: FIW: 130, Sized Salt: 0, Saturated Salt: 0. Fluid Losses Total: FIW: 5933, Sized Salt: 548, Saturated Salt: 170. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Rig 56 50-733-20036-00 1 167-046 1 2/14/19 1 3/6/19 Daily Operations: 03/03/2019 -Sunday RIH PU 4 1/2" pert guns. Run 112 guns. MU firing head, ported sub, 3 tbg pups, XO, 3 jts 3 1/2 DP, and RA sub. RIH w/ 28 stds of 3 1/2 DP out of derrick. PU 5' pup and slack off down to table 5203'. PU and set pipe on the upstroke at 5198'. Break off pup. RU E -line and run correlation log. Send logs to town and they confirmed we should PU 1'. POH and RD E -line. PU on the pipe 1', RU perf, circ, assem. Test lines to 1500 psi. Hold PJSM. Close annular and line up on choke. Drop bar and guns fired at 17:07. [shook the whole rig] Check tbg and it was on a vac. Pump at 4BPM. Got fluid back at choke manifold at 43 bbls away. Started seeing some oil at 120 bbls away & at 130 bbls away we were getting about 10% oil, with about 40 BPH loss rate. Continue circulating through choke manifold @ 40 SPM w/ 350 psi. Catching samples every 50 bbl. Showing >1% oil in sample taken at 250 bbl with trace amount in subsequent samples. Fluid loss to hole calculated at 50 BPH at 350 bbl pumped decreasing to 40 BPH at 500 bbl pumped. Shut in and monitor well. Open Annular and observe well. Circulate one bottoms up down pipe and out flow line @ 47 SPM w/370 psi. Shut down pumps and monitor well. Fluid losses to hole 38.5 BPH. RD circulating lines and POOH w/ 25 std 3-1/2" DP filling hole through kill line. Monitor well. Stand back remaining 4 std. of 3- 1/2" DP. Fluid losses to hole 38.5 BPH. RU and lav down TCP guns as per Tripoint procedure. Fluid loses to hole 38 BPH. Fluid Losses Daily: FIW: 803, Sized Salt: 0, Saturated Salt: 0. Fluid Losses Total: FIW: 6736, Sized Salt: 548, Saturated Salt: 170. 03/04/2019 - Monday Clear floor of Tripoint perf tools. Clean floor and service rig. Have production getting A-31 ready so we can fill wth kill fluid. Rigging up stabbing board. Working on mixing up kill fluid for A-31. Started unloading boat with completion equip. Finish rigging up stabbing board w/ safety cables and retractable safety line for stabber. Mixing fluid for A-31. Strap 2 3/8 and 2 7/8 tbg as it is unloaded. Continue unloading boat w/ tbg and completion equip. Strapping tbg as it comes off boat. Finish w/tbg at 1600 hrs but still unloading boat. Work on preparing tallies for both strings. While rigging up Weatherford dual string equip. Cont. rigging up Weatherford dual string equip. Hold PJSM on running dual completion. (2-7/8" to be drifted to, 2-3/8" to be drifted to 1.901" ) Fluid losses to hole 28 BPH. PU Indexing MS Guide, 2-7/8" EUE Coupling, X/O Pup 2-7/8 (IBT pin X EUE pin), IBT Coupling, 2-7/8" IBT X/N Nipple and 2-7/8" IBT Coupling. PU and drift 33 jt. 2-7/8" 4.7# L-80 IBT tubing to 1039'. P/U 2- 7/8" GLM #1 (side string mandrel)/2-3/8" L-80 IBT 1/2 Mule Shoe, 2-3/8" RN Landing Nipple, 2-3/8" L-80 IBT Coupling, 2-3/8" 4.6# L-80 Pup, 2-3/8" IBT GLM w/ Injector Tube and 2-3/8" 4.6# L-80 Pup. PU and drift 18 jt. each of 2-7/8" 4.7# L-80 IBT tubing and 2-3/8" 4.6# L-80 IBT tubing to 1636'. PU GLM assembly #2 (2-7/8" side string mandrel / 2-3/8" w/ Injector tube and telescoping Union. Unable to MU 2-3/8" (unable to spread pipe far enough apart to get threads to start as mandrels are attached together 12' above pin end connection.) Brake band tab on Weatherford tongs broke while attempting to MU 2-3/8" connection. Break out 2-7/8" connection & pick up mandrel assembly. PU 10' pups to make on bottoms of 2-7/8", Change out 2-3/8" power tongs. Back up 2-3/8" tongs not biting. 2-7/8" tongs slipping on pipe. Get welder up to repair 2-3/8" tong brake tab. Work on 2-7/8" tongs to get them to bite. (Found 2-3/8" dies in with 2-7/8"). Continue RIH w/ 2 7/8 X 2 3/8 dual completion t/ 1700'. Fluid Losses Daily: FIW: 672, Sized Salt: 0. Saturated Salt: 0. Fluid Losses Total: FIW: 7408, Sized Salt: 548, Saturated Salt: 170. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Rig 56 50-733-20036-00 1 167-046 2/14/19 1 3/6/19 Daily Operations: 03/05/2019-Tuesday Continue RIH PU 2 7/8 X 2 3/8 dual string completion f/ 1700't/ 3577'. Hole is taking 30 BPH. Continue RIH PU 2 7/8 X 2 3/8 Dual string completion. PU last of 4 GLM. RIH to just below packer. MU X nipple on LS and R nipple in SS. Fill short string w/ FIW. Hole taking 32 BPH. Pick up and make packer assembly and vent valve and verify operation. Make up SSSV and check for operation. RIH with P/U dual string to 5710'. Makeup landing joints and set in v-door. Makeup tubing hangers to landing joints. Makeup long string tubing hanger to dual string. Finished making up dual tubing hangers and dressed with control lines. Land tubing with 62K down. Verify tubing hangers properly in profile. Run in lock down screws. Hole was taking 32 BPH before landing out. Rig up Pollard slick line on long string with pump-in sub. RIH with plug to above XN nipple. Fluid pack long string and annulus before setting plug. Fluid Losses Total: Daily FIW: 732, Total FIW: 8140, Sized Salt: 548, Saturated Salt: 170. 03/06/2019- Wednesday Pump do arm until we got fluid up the LS. Finish setting standing valve with Pollard. Stay latched onto valve. Pressure up do LS to 3800 psi to set packer. Pressure bled back to 3600 psi and we held it for 30 min. Swap over to ann and pressure up to 1500+ psi and chart it for 30 min. Swap back to SS and pressure up to 1650 psi for 30 min on a chart. Lost 100 psi in 35 min. Bleed off tbg. POH with slickline recovering the standing valve. RD slickline. Clear floor of dual string tools and testing equip. Prep for nipple dn. Nipple do BOPS. Hot bolt bottom of single gate, pull flow nipple, pull drip pan bottom plate remove flow nipple boot off annular, RU BOP picking beam on top of annular. Hook chain falls up to BOP picker and PU BOPs. Trolly BOPS over to the side and secure them out of the way. MU picking plate on riser. Pull riser with DSA to rig floor. Remove riser and set out on drill deck. Lower tree valves and safety valve down to well head room. Bring well head to rig floor. Install bolts and nuts in flange. Lower same into well bay. Torque bolts as per well head rep. Void test at 500 psi for 5 minutes and 5000 psi for 15 minutes. Assist with tree nipple up. Install actuator valve. Set two way checks and test tree at 250 L/5000 H. Assist production with remainder of tree nipple up. This will be the final report on this AFE. Fluid Losses Total: Daily FIW: 96, Total FIW: 8236, Sized Salt: 548, Saturated Salt: 170. Stan Golis THE srniP "'ALASKA GOVERNOR BILL WALKER Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 *w CM,'C f . 174 Conservation Commission scove Not) 2 (t Z01� 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Trading Bay Field, Middle Kenai B, C, D, and E and Hemlock Oil Pools, Trading Bay St A-07 Permit to Drill Number: 167-046 Sundry Number: 318-494 Dear Mr. Golis: Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French Chair DATED this day of November, 2018. RBDMSL NOVl 6 2018 9 0 RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 NOV 0 5 2018 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ ALY Perforate 0 • Other Stimulate ❑ Pull Tubing Q Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: GL Completion ❑✓ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: V V16 Hilcorp Alaska, LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 167-046 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-733-20036-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 93B ' Will planned perforations require a spacing exception? Yes❑ No ❑Q _ Trading Bay St A-07 ' 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0018731 Trading Bay Field / Hemlock Oil, Middle Kenai B,C,D & E Oil Pools - 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): 6,407 6,389 6,089 6,076 394 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor —264' 20" —264' —264' Surface 1,067' 13-3/8" 1,067 1,067' 3,090 psi 1,540 psi Intermediate Production 4,810' 9-5/8" 4,810' 4,806' 3,950 psi 2,570 psi Liner 1,651' 7" 6,397' 6,380' 7,240 psi 5,410 psi Perforation Depth MD (ft): Perforation Depth ND (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 2,050 - 6,330 2,050 - 6,314 2-7/8" 6.5# / L-80 4,425 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): DLH Hydroset II Pkr & Halliburton TRSV 413 (MD) / 413 (TVD) & 300 (MD) / 300 (TVD) 12. Attachments: Proposal Summary [2] Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑✓ Exploratory ❑ Stratigraphic ❑ Development Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 12/1/2018 OIL ❑� ` WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Stan W. Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: dmarlOw2 hilCOr .CO LL , ` t Contact Phone: (907) 283-1329 Authorized Signature: � Date: COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Cl Plug Integrity ❑ BOP Test W/ Mechanical Integrity Test ❑ Location Clearance ❑ Other: c;2 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: �_P , , \fo \\"\13Form 10-403 Revised 4/2017 II�l-{ -i -6 `) ^ 1 NAIMOUIVISU, NOV 16 2018 Approved applic ntis`r i 2 r s the date of approval. _/ //�� Submit Form and lents in Duplicate • 11 0 Hileorp Alaska, LLC Well Work Prognosis Well Name: Monopod A-07 API Number: 50-733-20036-00 Current Status: Oil Producer Leg: N/A Estimated Start Date: December 01, 2018 Rig: Monopod Platform Rig # 56 Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 167-046 First Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) Second Call Engineer: Mike Quick (907) 777-8442 (0) (907) 317-2969 (M) Current Bottom Hole Pressure: 681 psi @ 2,873' TVD 0.237 psi/ft (4.56 ppg) 2013 ESP Gauge Maximum Expected BHP: 681 psi @ 2,873' TVD 0.237 psi/ft (4.56 ppg) 2013 ESP Gauge Maximum Potential Surface Pressure: 394 psi Using 0.1 psi/ft gradient per 20AAC 25.280(b)(4) Brief Well Summary: The A-07 is currently completed in the B, C, D, E, and Hemlock sands. This workover will re -perforate to remediate suspected skin damage and install a side -string gas -lift completion to improve operational reliability. Last Casing Test: 07/11/2013 2,836' 1,500 psig for 30 minutes on chart Cr Procedure: 1. MIRU Monopod Platform Rig # 56.`L C c rc B 2. Circulate hydrocarbon off of well.-- Lsr,J-r � 3. Workover fluid to be FIW with LCM as needed to balance wel ,BOPrvill be closed as needed to circulate the well. ;? 4. ND Wellhead, NU BOP and test to 250psi low/2,500psi high. (Note: Notify AOGCC 24 hours in advance of test to allow them to witness test). 5. Monitor well to ensure it is static. 6. POOH with completion. 7. Cleanout as needed. �. 5 8. PU TCP guns, RIH, Correlate, perforate per program. Circulate out any gun gas, ensure well is static, POOH. 9. PU and RIH with duals -completion assembly consisting of Side -String Gas Lift Mandrels, High -set Packex w/ Vent Valve, & SSSV. Le-�✓ % S� / �J^�' �-t r- ^f� cyr'1 10. Set Packer at ±400'. Pressure test to 1,500 psig and chart for 30 minutes. 11. ND BOP, NU wellhead and test. 12. Turn well over to production. 13. Conduct SVS testing per AOGCC regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Current 4. Wellhead Schematic Proposed 5. BOP Drawing 6. Fluid Flow Diagrams 7. RWO Sundry Revision Change Form • SCHEMATIC Btm (MD) Top (TVD) Trading Bay Unit Well # A-07 CONN ID TOP BTM. Status API# 50-733-20036-00 2,050' 2,120' 2,050' 2,120' PTD: 167-046 5 06/24/18 Open BZN Last Completed: 06/26/2018 RKB to TBG Hngr= 38.23 2,244' 2,334' CASING DETAIL S KB to MSL = 101', MSL to Mudline 66' Open 2,874' 2,906' 2,873' 2,906' 32' 5 5/11/2013 Open 1 2,875' 2,907' 2,874' 2,906' 22' 3 2 DV C.11a, @zWT It ti. Tubing P -h- BZN @ 4,3fi0' SLM 4 :x 4• 5 JC, CZN C, CZN DZN EZN HEM PBTD = 6,089' (original 6,350') TD = 6,407' ANGLE thru INTERVAL = 3.21 SIZE Btm (MD) Top (TVD) GRADE CONN ID TOP BTM. Status BZN 2,050' 2,120' 2,050' 2,120' 70' 5 06/24/18 Open BZN 2,244' 534' 2,244' 2,334' 90' S 06/24/18 Open 2,874' 2,906' 2,873' C, CZN DZN EZN HEM PBTD = 6,089' (original 6,350') TD = 6,407' ANGLE thru INTERVAL = 3.21 Wi 20" Conductor Pile Surface ^264' 13-3/8" 61 1-55 Butt 12.515 Surface 1,067' 40Butt 8.835 Surface 4,810' 7" 26 J-55 Butt 6.276 4,746' 6,397' TUBING DETAIL 2-7/8" 6.5 L-80 8 round EUE 2.441 Surf 1,917' 6.5 L-80 8 round EUE Mod 2.441 L. 1,917' 4,425 Tubing Punches at 4,360' SLM -19 RTG 1562-453 charges .40 entry hole JEWELRY DETAIL No Depth Depth (MD) (TVD) ID OD Item 38.23 38.23' Seaboard -ESP -EN, 11"x3-1/2" EUE lift & susp w/3" Type H BPV profile 1 300' 300' 2.313 4.650 Halliburton TRSV SSSV 2 413' 413' 2.920 8.500 Packer- DLH Hydroset 11 twinsealw/ Weatherford WFT vent valve (35K shear) 3 1,953' 1,953' 2.441 4.625 GLM #1-SFO-1w/dummy valve 4 4,389' 4,386' 2.313 3.670 XN Nipple w/ Brio -tech standing valve & Kobe knock out plug 4,425' 4,422' N/A 3.050 Discharge, Bolt -On 4,426' 4,423' N/A 4.500 Zenith Discharge Pressure sub 4,426' 4,423' N/A 4.000 Pumps- 100 Stage Veretek 5 4,533' 4,529' N/A 4.000 Intake Pump -9 Stage Veretek 4,546' 4,542' N/A 4.000 Seals- Tandem Summit BPBSL 4,563' 4,559' N/A 4.560 Motor -Summit FMS2, 240HP/3040V/56A 4,595' 4,591' N/A 4.560 Gauge(Zenith)/Anode/Centralizer 1DCDLrI0ATif)K1 (IATA Zone SIZE Btm (MD) Top (TVD) GRADE CONN ID TOP BTM. Status BZN 2,050' 2,120' 2,050' 2,120' 70' 5 06/24/18 Open BZN 2,244' 534' 2,244' 2,334' 90' S 06/24/18 Open 2,874' 2,906' 2,873' 2,906' 32' 5 5/11/2013 Open 2,875' 2,907' 2,874' 2,906' 22' 4 9/7/1988 Open 31-8 BZN 2'882 2,896' 2,881' 2,895' 14' 4 8/17/1970 Open 2,920' 2,947' 2,919' 2,946' 27' 5 5/11/2013 Open 2,923' 2,947' 2,922' 2,946' 24' 4 1 9/8/1988 Open 2,928' 2,944' 2,927' 2,943' 16' 4 8/17/1970 Open 2,997' 3,076' 2,996' 3,075' 79' 4 9/9/1988 Open 33-6 BZN 2,999' 3,077' 2,998' 3,076' 78' 5 5/11/2013 Open 3,044' 3,076' 3,043' 3,075' 32' 4 8/17/1970 Open 3,193' 3,242' 3,192' 3,241' 49' 5 5/11/2013 Open 3,196' 3,208' 3,195' 3,207' 12' 4 8/17/1970 Open 3,196' 3,240' 3,195' 3,239' 44' 4 9/10/1988 Open 41-3 BZN 3,214' 3,240' 3,231' 3,239' 26' 4 8/17/1970 Open 3,282' 3,433' 3,281' 3,432' 151' 5 5/11/2013 Open 3,283' 3,435' 3,282' 3,434' 52' 4 9/11/1988 Open 3,290' 1DCDLrI0ATif)K1 (IATA Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Date Status BZN 2,050' 2,120' 2,050' 2,120' 70' 5 06/24/18 Open BZN 2,244' 534' 2,244' 2,334' 90' S 06/24/18 Open 2,874' 2,906' 2,873' 2,906' 32' 5 5/11/2013 Open 2,875' 2,907' 2,874' 2,906' 22' 4 9/7/1988 Open 31-8 BZN 2'882 2,896' 2,881' 2,895' 14' 4 8/17/1970 Open 2,920' 2,947' 2,919' 2,946' 27' 5 5/11/2013 Open 2,923' 2,947' 2,922' 2,946' 24' 4 1 9/8/1988 Open 2,928' 2,944' 2,927' 2,943' 16' 4 8/17/1970 Open 2,997' 3,076' 2,996' 3,075' 79' 4 9/9/1988 Open 33-6 BZN 2,999' 3,077' 2,998' 3,076' 78' 5 5/11/2013 Open 3,044' 3,076' 3,043' 3,075' 32' 4 8/17/1970 Open 3,193' 3,242' 3,192' 3,241' 49' 5 5/11/2013 Open 3,196' 3,208' 3,195' 3,207' 12' 4 8/17/1970 Open 3,196' 3,240' 3,195' 3,239' 44' 4 9/10/1988 Open 41-3 BZN 3,214' 3,240' 3,231' 3,239' 26' 4 8/17/1970 Open 3,282' 3,433' 3,281' 3,432' 151' 5 5/11/2013 Open 3,283' 3,435' 3,282' 3,434' 52' 4 9/11/1988 Open 3,290' 3,434' 3,289' 3,433' 144' 4 8/17/1970 Open 3,300' 3,320' 3,299' 3,319' 20' 4 9/10/1970 Cmt Szqd 3,795' 3,960' 3,793' 3,958' 65' 4 9/12/1988 Open 3,803' 3,959' 3,801' 3,957' 156' 5 5/11/2013 Open 44-7 BZN 3,808' 3,850' 3,807' 3,848' 42' 4 8/17/1970 Open 3,820' 3,840' 3,818' 3,838' 20' 4 9/10/1967 Cmt Szqd 3,858' 3,956' 3,856' 3,954' 1 98' 4 8/17/1970 1 Open C-2 4,037' 4,097' 4,035' 4,095' 60' 5 5/11/2013 1 Open C-3 4,127' 4,224' 4,125' 4,221' 97' 5 5/11/2013 I Open 44-7 BZN 4,125' 4,225' 4,123' 4,222' 100' 4 9/15/1967 Cmt Szqd 4,140' 4,160 4,138' 4,157' 20' 4 9/10/1967 Cmt Szqd CZNS6 4,267' 4,335' 1 4,264' 4,332' 68' 5 5/11/2013 Open C4 4,344' 4,371' 1 4,341' 4,368' 27' 5 5/11/2013 Open C5 4,429' 4,479' 4,426' 4,476' 50' 5 5/11/2013 Open C-6 4,600' 4,639' 4,595' 4,635' 39' 5 5/11/2013 Open 44-7 BZN 4,605' 4,625' 4,601'1 4,621' 20' 4 9/10/1967 Cmt Szqd CZNS7 4'670 4,700' 4,666' 1 4,696' 30' S 5/11/2013 Open 4,720' 4,740' 4,716' 4,736' 20' 5 5/11/2013 Open C7 4,760' 4,781' 4,756' 4,777' 21' 5 5/11/2013 Open 49-4 CZN 4,807' 4,829' 4,803' 4,825' 22' 5 5/11/2013 Open 50-0 CZN 4,869' 4,879' 4,865' 4,875' 10' 5 5/11/2013 Open 50-3 CZN 4,897' 4,927' 4,893' 4,923' 30' 5 5/11/2013 Open CZNS2 4,952' 4,957' 4,989' 4,953' 5' 5 5/11/2013 Open 50-6 CZN 4,992' 5,021' 4,988' 5,017' 29' 5 5/11/2013 1 Open CZNS9 5,102' 5,122' 5,097' 5,117' 20' 5 5/11/2013 Open 51-6 CZN 5,122' 5,156' 5,117' 5,151' 34' 5 5/11/2013 Open 51-9 CZN 5,170' 5,198' 5,165' 5,193' 28' 5 5/11/2013 Open 53-0 DZN 5,260' 5,288' 5,254' 5,282' 28' 5 5/11/2013 Open DZNS2 5,328' 5,335' 5,322' 5,329' 7' 5 5/11/2013 Open 53-8 DZN 5,360' 5,393' 5,354' 5,387' 33' 5 5/11/2013 Open 54-5 DZN 5,424' 5,458' 5,417' 5,451' 34' S 1 5/11/2013 Open 54-9 DZN 5,492' 5,509' 5,485' 5,502' 17' 5 5/11/2013 Open 55-7 DZN 5,542' 5,560' 5,534' 5,552' 18' 5 5/11/2013 Open 56-1 DZN 5,587' 5,670' 5,579' 5,661' 83' 5 5/11/2013 Open 57-2 DZN 5,700' 5,744' 5,691' 5,735' 74' S 5/11/2013 Open 58-1 EZN 5'788 5,817' 5,788' 5,807' 19' S 5/11/2013 Open 5,823' 5,837' 5,813' 5,827' 14' 5 5/11/2013 Open 58-7 EZN 5,860' 5,875' 5,850' 5,864' 15' 5 5/11/2013 Open 5,882' 5,948' 5,871' 5,937' 66' 5 5/11/2013 Open 60-0EZN 5,982' 6,019' 5,970' 6,007' 37' 5 5/11/2013 Open Hemlock 6,157' 6,328' 6,143' 6,312' 171' 5 06/24/18 Open Hemlock 6,225' 6,330' 6,210' 6,314' 105' S 06/24/18 Open Updated by: JILL 07/16/18 0Trading Bay Unit • PROPOSED Well #A-07 API# 50-733-20036-00 PTD: 167-046 KKB Last Completed: FUTURE o ngr = CASING DETAIL KB to MSL = 101', MSL to Mudline 66' SUE WT GRADE CONN ID TOP BTM. 20" Conductor Pile Surface -264' 77 4 13-3/8" 61 J-55 Butt 12.515 Surface 1,067' ''I 9-5/8" 40 1-55 Butt 8.835 Surface 4,810' 1 a 7" 26 1-55 Butt 6.276 4,746' 6,397' A TUBING DETAIL 2-7/8" 6.5 L-80 IBT SCC 2.441 Surf x4,700' 2-3/8" 4.7 L-80 IBT SCC 1.995 x4,700 16,113' 2 2-3/8" 4.7 L-80 IBTSCC 1.995 Surf Y 35,500 Y: PBTD = 6,341' TD = 6,407' ANGLE thru INTERVAL = 3.21 Updated by: JLL 10/31/18 Zone Top (MD) Bt. (MD) Top (TVD) Bt. (TVD) Amt SPF Jewelry Detail No (MDJ (TVD) Depth Depthf62C ID 2,120 Depth o (MD) Depth (TVD) b OD ;.'': Item Long String RZN 2,244' ort String 2,244' 2,334' 90 5 1 x350' x350' 2.313" 12,782' x2,817' x2,584' 335' TRSV 2 x400' 3400' 3.000" 32,906' A x400' 3400' 2.50D" 8.500" Packer -D&L Oil Tools Hydroset 11(uK Shear)w/ Weatherford WFT Vent Valve 3 3430' 3430' 2.313"B 2,874' 2,906' 3430' x430' 2.313" Open X Nipples 2'882 x1,950' 31,950 2.347" 2,895' 14' x1,950' 31,950 1.995" 6.625" GLM #1-2-7/8" MANA SPMO-I.OF-LT (side string mandrel) 4 x3,101' 33,300 2.347" x27' S 33,101' x3,100 1.995" 6.625" GLM #2 -2-7/8" MANA SPMO-LOF-LT (side string mandrel) 2,922' 33,902' x3,900' 2.347" 4 9/8/1988 33,902' 33,900 1.995" 6.625" GLM #3-2-7/8"MANA SPMO-I.OF-LT(side string mandrel) 2,943' x4,503' 34,500 2.347" 8/17/1970 34,503' x4,500 1.995" 6.625" ':'.'GLM#4-2-7/8"MANA SPMO-S.OF-LT(side string mandrel) 5 x4,700 x4,696' 1.995" Open 33-6 8ZN x2,999' x3,077' x2,998' ±3,076' Crossover 6 x5,004' x5000 1.901" 3,044' 35,004' x5,000 1.995" 6.625" GLM #5 -2-3/8" MANA SPMO-LOF-LT (side string mandrel) 8/17/1970 35,457' x5,450 1.901" x3,193' x3,242' x5,457' 35,450 1.995" 6.625" GLM #6-2-3/8"MANA SPMO-1.OF-LT(side string mandrel) 7 36,103' x6,090' 1.791" 3,208' D x5,487' x5,480 1.791" 8/17/1970 XN Nipples w/ PXN plug installed on short string side E x6,113' 36,100' 1 3,240' 3,195' E 35,500' 35,493' 9/10/1988 Open WLEGs D&L Oil Tools 2-3/8" Telewoping Unions w/ 24" stroke used to make up short string jewelry 3,240' Zone Top (MD) Bt. (MD) Top (TVD) Bt. (TVD) Amt SPF Date Status BZN 2,050 2,120 2,050 2,120 70 5 06/24/18 Open RZN 2,244' 2,334' 2,244' 2,334' 90 5 06/24/18 Open 12,782' x2,817' x2,584' x2,616' 335' Future New x2,874' 32,906' x2,873' x2,906' x32' S 5/11/2013 Re -pert 2,875' 2,907' 2,874' 2,906' 22' 4 9/7/1988 Open 31-8 8ZN 2'882 2'896' 2,881' 2,895' 14' 4 8/17/1970 Open 32,920' x2,947' x2,919' 32,946' x27' S 5/11/2013 Re-perf 2,923' 2,947' 2,922' 2,946' 24' 4 9/8/1988 Open 2,928' 2,944' 2,927' 2,943' 16' 4 8/17/1970 Open 2,997' 3,076' 2,996' 3,075' 79' 4 9/9/1988 Open 33-6 8ZN x2,999' x3,077' x2,998' ±3,076' x78' S 5/11/2013 Re -pert 3,044' 3,076' 3,043' 3,075' 32' 4 8/17/1970 Open x3,193' x3,242' x3,192' x3,241' x49' S 5/11/2013 Re -pert 3,196' 3,208' 3,195' 3,207' 12' 4 8/17/1970 Open 3,196' 3,240' 3,195' 3,239' 44' 4 9/10/1988 Open 41-3 8ZN 3,214' 3,240' 3,231' 3,239' 26' 4 8/17/1970 Open x3,282' x3,433' x3,281' x3,432' x151' S 5/11/2013 Re- erf 3,283' 3,435' 3,282' 3,434' S2' 4 9/11/1988 Open 3,290' 3,434' 3,289' 3,433' 144' 4 8/17/1970 Open 3,300' 3,320' 3,299' 3,319' 20' 4 9/10/1970 Cmt Szgd 3,795' 3,960' 3,793' 3,958' 65' 4 9/12/1988 Open 13,803' x3,959' x3,801' x3,957' x156' S 5/11/2013 Re -pert 44-7 RZN 3,808' 3,850' 3,807' 3,848' 42' 4 8/17/1970 Open 3,820' 3,840' 3,818' 31838' 20' 4 9/10/1967 Cmt Szgd 3,858' 3,956' 3,856' 3,954' 98' 4 8/17/1970 Open C-2 34,037' 34,097' x4,035' 0,095' x60' S 5/11/2013 Ro-perf C-3 x4,127' x4,224' x4,125' 34,221' x97' S 5/11/2013 Re-perf 44-7 BZN 4,125' 4,225' 4,123' 4,222' 100' 4 9/15/1967 Cmt Szgd 4,140' 4,160' 4,138' 4,157' 20' 4 9/10/1967 Cmt Szgd CZN56 x4,267' x4,335' x4,264' x4,332' x68' S 5/11/2013 Re -pert C4 x4,344' x4,371' x4,341' x4,368' x27' S 5/11/2013 Re -pert CS 34,429' x4,479' x4,426' x4,476' x50' S 5/11/2013 Re -pert C-6 ±4,600' x4,639' x4,595' x4,635' 139' S 5/11/2013 Re-perf 44-7 BZN 4,605' 4,625' 4,601' 1 4,621' 20' 4 9/10/1967 Cmt Szgd CZNS7 ±4.670 x4,700 x4,666' x4,696' x30' S 5/11/2013 Re-perf ±4,720' 34,740 x4,716' x4,736' x20' S 5/11/2013 Re-perf C7 14,760' 14,781' x4,756' x4,777' x21' S 5/11/2013 Re -pert 49-4 CZN ±4,807' x4,829' x4,803' x4,825' x22' S 5/11/2013 Re -pert 50-0 CZN x4,869' x4,879' 0,865' ±4,875' x10' S 5/11/2013 Re -pert 503 CZN x4,897' x4,927' 14,893' x4,923' x30' S 5/11/2013 Re-perf CZNS2 x4,952' x4,957' 34,989' x4,953' 35' S 5/11/2013 Re-perf 50-6 CZN x4,992' 15,021' x4,988' 15,017' x29' S 5/11/2013 Re -pert CZN59 ±5,102' x5,122' 15,097' x5,117' x20' S 5/11/2013 Re-Derf 51-6 CZN x5,122' x5,156' x5,117 15,151' ±34' S 5/11/2013 Re -pert 51-9 CZN x5,170' x5,198' x5,165' 15,193' x28' S 5/11/2013 Re -pert 53-0 DZN x5,260' x5,288' x5,254' x5,282' x28' S 5/11/2013 Re -pert DZNS2 x51328' x5,335' x5,322' 15,329' x7' S 5/11/2013 Re -pert 53-8 DZN x5,360' 15,393' x5,354 15,387' ±33' S 5/11/2013 Re-Perf 545 DZN 15,424 x5,458' i5r4171 x5,451 334' S 5/11/2013 Re-Perf 549 DZN x5,492 x5,509' x5,485 ±5,5021 x17' S 5/11/2013 Re -Pert 55-7 DZN x5,542' x5,560 x5,534' x5,552' ±18' S 5/11/2013 1 Re -Pert 56-1 DZN x5,587' x5,670' x5,579' x5,661' 1 x83' S 5/11/2013 Re-Perf 57-2 DZN x5,700' x5,744' x5,691' ±5,735' 04' S 5/11/2013 Re-Perf 58-1 EZN ±5,798' x5,817' 35,788' 35,807' x19' S 5/11/2013 Re-Perf 15,823' 35,837' x5,813' ±5,827' x14' S 5/11/2013 Re-Perf 58-7 EZN x5,860' 1:5,875' x5,850 ±5,864' x15' S 5/11/2013 Re -Pert ±5,882' x5,948' x5,871' x5,937' x66' S 05/12/2013 Re-Perf 60-0 EZN x5,982' 16,019' x5,970' ±6,007' ±37' S 05/11/2013 Re -Pert Hemlock x6,157' x6,328' x6,143' x6,312' x171' S 06/24/2018 Re-PerfHemlock 6,225' 6,330 6,210 6,314' 105' S 06/24/2018 Open t Monopod Platform A-7 Current Hilrairp :11a�ka, LLC 05/28/2018 Monopod Platform A-7 133/8X95/8X27/8 Valve, Swat 31/85M FE, F Valve, Wing, WKM-M, 2 1/D 5M FE, HWO, DD trim Valve, Mastei 31/85M FE, H' Valve, Mas 3 1/8 SM FE, Tubing head, S-8, 13 5/8 3M x 115M, w/ 2- 2 1/16 SM SSO, w/ BG bottom w/ 1- 2 1/16 SM WKM-M valves Casing head, Shaffer -KD, 135/83MX 13 3/8 SOW, w/ 2- 2" LPO, BHTA, Bowen, 3 1/8 SM X 2.5 Bowen quick union Tubing hanger, Seaboard - ESP -EN, 11 X 3 1/2 EUE lift and Susp w/ 3" Type H BPV profile, 4- Y/ CCL, Prepped for BIW penetrator WKM-M, 3 1/8 r/ 15" OMNI )r, DD trim ,W/ :CL, tor Monopod Platform A-7 Proposed 10/25/2018 Hilmrp Ala%ka, LIA', Monopod Platform A-7 133/8X95/8X27/8x23/8 Dual tree asst', CIW-F, 11 5M FE bottom x 3 1/8 5M x 3 1/8 5M, double master and swab, 3 1/8 5M API 5 bolt top, 3 1/8 SM SSO outlets, 5 3/64" centers, 3" nominal CIW seal pockets Control line X2 Short string Tubing head, FMC -TC -60, 13 5/8 3M x 11 5M, w/ 2- 2 1/16 5M SSO, BG bottom prep Casing head, Shaffer -KD, 135/83MX 13 3/8 SOW, w/ 2- 2" LPO, 2 7/8" Tubing hanger, dual, FMC- TC-60-2CCL, 11 x 3 % EUE 8rd lift and susp, w/ 3" type H BPV, 5 3/64" centers, 4- Y." CCL ports, SS material Adapter, Dual, 11 5M Rotating flange bottom X 115M stdd top prepped for CM 3" nom seal pockets on 5 3/64 centers Monopod Platform 2018 BOP Stack Hilairp Abkwko, Lik • 0 1 sig a ��o��■tea �o Mud PUMP 4 IMPQ Pit • • 0 • Monopod Rig # 56 BOP Test Procedure Hilcorp Alaska, LLC Attachment #1 Attachment #1 Hilcorp Alaska LLC. BOP Test Procedure: Monopod Rig # 56 WO Program — Oil Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with FIW to kill well. • Note: Fluid level will fall to a depth that balances with reservoir pressure. 3) Circulate down tubing taking returns to production off of the annulus and sweep gas and oil to production until returns are clean. 4) Confirm that well is static shooting fluid levels if necessary right before ND/NU. Initial Test (i.e. Tubing Hanger is in the Wellhead) If BPV profile is good 1) Set BPV. ND Tree. NU BOP. 2) MU landing joint. Pull BPV. Set 2 -way check in hanger. 3) Space out test joint so end of tubing (EOT) is just above the blind rams. 4) Set slips, mark same. Test per standard Monopod Rig #56 BOPE test procedure. If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on. Profile and/or landing threads must be prepped while tree is off. Worst Case: BPV profile and landing threads are bad. 1) Attempt to set BPV through tree. If unsuccessful, establish static fluid level, shoot fluid level with an echometer gun or tag with slick line to establish static fluid level if necessary. 2) Once the fluid level is established to be static, notify Hilcorp Anchorage Operations Engineer. 3) Proceed as follows: a) ND tree with no BPV b) Inspect and prepare BPV profile to accept a 2 -way valve, or prepare lift -threads to accept landing joint to hold pressure. If well is a producer and the culprit is scale, attempt to clean profile with Muriatic acid and a wire brush or wheel. c) Set 2 -way check valve by hand, or MU landing (test) joint to lift -threads d) Plug penetrations in hanger. For ESP wells - Ensure that cap is on cable penetrator e) NU BOP. Test BOPE per standard procedure. 4) If both set of threads appear to be bad and unable to hold a pressure test and / or a penetrator leaks, notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC - guy.schwartz@alaska.gov ) and Mr. Jim Regg (AOGCC-jim.regg@alaska.gov ) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. As outlined and approved in the sundry, proceed as follows: a) Nipple Up BOPE • • Monopod Rig # 56 BOP Test Procedure HileorpAlaska, LLC Attachment #1 b) With stack out of the test path, test choke manifold per standard procedure c) Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) d) Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e) Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 5) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 6) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re -land hanger (or test plug) in tubing head. Test BOPE per standard procedure. Note: BOPE high test pressures will be determined upon Approved Sundry. Test joint sizes will be determined upon well work. Subsequent Tests (i.e. Test Plug can be set in the Tubing -head) 1) Remove Wear bushing. a) Use inverted test plug to pull wear busing. MU to 1 jt. of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same, and RIH on 1 joint of tubing. Install a closed TIW or lower Kelly valve in top of test joint. 3) Break joint off test plug and pull up to space the bottom of tool joint above blind rams. 4) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE (after 2 -way check or test plug is set) 1) Fill stack with rig pump and install chart recorder on the stack side of the pump manifold. 2) Note: When testing, pressure up with pump to desired pressure, close valve on pump manifold to trap pressure and read same with chart recorder. 3) Referencing the attached schematics test rams and valves as follows. a) Close C-2 (inside gate valve on choke side of mud cross) and close the annular preventer. Pressure test to 200 psi for 5 minutes and 1,500 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open annular. b) Close Pipe Rams. Test to 200 psi for 5 minutes and 3,000 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open pipe rams. c) Test Dual Rams. If the well has dual tubing, and dual rams are installed in the stack, test the dual rams by picking up two test joints with dual elevators and lowering them into stack and position Monopod Rig # 56 BOP Test Procedure Hilcorp Alaska, LLC Attachment #1 them properly in the dual rams. Close rams. Test to 200 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open rams. d) Open C-2. Flow through the choke manifold and purge air. Test the choke manifold starting with the outer most valves, to 250 psi low and 3,000 psi high, for 5 minutes each, as follows: (Valve numbers are in reference to Diagram B) i) Valves 1, 2, 10. After test, open same. ii) Valves, 3, 4, 9. After test, open valves 3 & 4. Leave 9 closed. iii) Valves 5, 6, 9. After test, open valves 5 & 6, leave 9 closed. iv) Valves, 7, 8, 9. After test, open all valves. e) Close C-3. This is the HCR (the hydraulic controlled remote) valve just outside C-1 on choke side of mud cross. Test to 250 psi low and 3,000 psi high. After test, open HCR, close C-1. f) Blind Rams. Make sure test joint is above the blind rams. Close blind rams. Test to 200 psi Low for 5 minutes and 3,000 psi High for 5 minutes. Bleed down pressure. g) Bleed off all pressure. Line up pumps to pump down tubing. h) Test C-1, C-2, and C-4 on the kill (pump -in) side by pressuring up on tubing. Test to 200 psi Low for 5 minutes and 3,000 psi High for 5 minutes. i) Test floor valves TIW (or Lower Kelly Valve) and IBOP. STANDARD TEST PROCEDURE OF CLOSING UNIT (ACCUMULATOR) 1) This is a test of stored energy. Shut off all power to electric and pneumatic pumps. 2) Record "Accumulator Pressure". It should be +/- 3,000 psi. 3) Close Annular Preventer, the Pipe Rams, and HCR. Close 2"d set of pipe rams if installed (e.g. dual pipe rams). Open the lower pipe rams to simulate the closing volume on the blinds. 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (i.e. Report might read "10 bottles at 2,150 psi"). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre -charge pressure of 1,000 psi). 7) Turn on the pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually +/- 30 seconds. 8) Once 200 psi pressure build is reached, turn on the pneumatic pumps and record the time it takes for the pumps to automatically shut-off after the pressure to builds back to original pressure (+/- 3,000 psi). Note: Make sure the electric pump is turned to "Auto", not "Manual' so the pumps will kick-off automatically. 9) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 10) Fill out AOGCC report. FINAL STEP, FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves, for correct operating position Monopod Rig # 56 BOP Test Procedure Hilcorp Alaska, LLC Attachment #1 3) Fill out the AOGCC BOPE Test Form (10-424) in Excel Format and e-mail to AOGCC and Juanita Lovett. Document both the rolling test and the follow up tests. Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well A-07 (PTD 167-046) Sundry #: XXX -XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first call' engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By Initials HAK Approved By Initials AOGCC Written Approval Received (Person and Date) Approval: Prepared: Asset Team Operations Manager Date First Call Operations Engineer Date r� .7 Schwartz, Guy L (DOA) n From: Schwartz, Guy L (DOA) Sent: Wednesday, November 14, 2018 10:35 AM To: 'Dan Marlowe' Subject: RE: [EXTERNAL] A-07 Gas lift string (dual string ) PTD 167-046 Dan, Thanks for the clarification... in the future make sure you include any procedure steps that have to do with the wellbore or completion integrity. I can't assume these steps are being done if not stated in the procedure. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226) or (Guy.schwartz@alaska.aov). From: Dan Marlowe <dmarlowe@hilcorp.com> Sent: Wednesday, November 14, 201810:27 AM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Subject: RE: [EXTERNAL] A-07 Gas lift string (dual string) PTD 167-046 Procedure 1. With plugs set in both strings at lowest nipple, Pressure up on long string to 3500 psi for 30 minutes to set packer, and jug test production tubing at >1500 psi and chart for 30 minutes 2. Bleed off long string to <1000 psi 3. Pressure up on short string to 1500 psi with long string blocked in to bundle test both short and long side together charting for 30 minutes. (fluid transfers through live valves in this step) 4. Bleed off both tubing strings 5. Pressure up on IA to 1500 psi charting for 30 minutes From: Schwartz, Guy L (DOA)[mailto:guy.schwartz@alaska.gov] Sent: Wednesday, November 14,2018 10:19 AM To: Dan Marlowe <dmarlowe@hilcorp.com> Subject: RE: [EXTERNAL] A-07 Gas lift string (dual string) PTD 167-046 Please send me a procedure outline on how that is done. Not sure how GL side is tested if Checks are in place. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, in'Ctuding any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226) or (Guv.schwartz@alaska.gov). From: Dan Marlowe <dmarlowe@hilcorp.com> Sent: Wednesday, November 14, 2018 9:50 AM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Subject: RE: [EXTERNAL] A-07 Gas lift string (dual string) PTD 167-046 Easily done by using the lowest most nipples to set the hydraulic packer which is around a 3500 psi set pressure From: Schwartz, Guy L (DOA)[mailto:guy.schwartz@alaska.gov] Sent: Wednesday, November 14, 2018 9:42 AM To: Dan Marlowe <dmarlowe@hilcorp.com> Subject: [EXTERNAL] A-07 Gas lift string (dual string) PTD 167-046 Dan, How are you verifying that the gaslift and production string is competent before startup? . There is nothing in the procedure about testing the two strings as a system. Assume this would apply to A-31 also. 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). STATE OF ALASKA *SKA OIL AND GAS CONSERVATION C09ISSION REPORT OF SUNDRY WELL OPERATIONS F2- - t.. ... a 2� 1. Operations Abandon H Plug Perforations H Frarxture Stimulate Li Pull TubingLi rirpss own Performed: Suspend 11 Perforate [:1 % 'Other Stimulate Q Alter Casing El Gari .. Pdgram ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development 0 Exploratory ❑ Stratigraphic ❑ Service ❑ 167-046 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-733-20036-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0018731 Trading Bay St A-07 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Trading Bay Field / Hemlock Oil, Middle Kenai B,C,D & E Oil Pools 11. Present Well Condition Summary: Total Depth measured 6,407 feet Plugs measured N/A feet true vertical 6,389 feet Junk measured N/A feet Effective Depth measured 6,089 feet Packer measured 413 feet true vertical 6,076 feet true vertical 413 feet Casing Length Size MD TVD Burst Collapse Structural Conductor -264' 20" -264' -264' Surface 1,067' 13-3/8" 1,067' 1,067' 3,090 psi 1,540 psi Intermediate Production 4,810' 9-5/8" 4,810' 4,806' 3,950 psi 2,570 psi Liner 1,651' 7" 6,397' 6,380' 7,240 psi 5,410 psi Perforation depth Measured depth 2,050 - 6,330 feet True Vertical depth 2,050 6,314 feet CA�NEflt, tu�u - Tubing (size, grade, measured and true vertical depth) 2-7/8" 6.5# / L-80 4,425 (MD) 4,422 (TVD) 413 (MD) 300 (MD) Packers and SSSV (type, measured and true vertical depth) DLH Hydroset II 413 (TVD) Halliburton TRSV 300 (TVD) 12. Stimulation or cement squeeze summary: Intervals treated (measured): 2,050 - 6,330 Treatment descriptions including volumes used and final pressure: Pump 220 bbls FIW down tubing taking returns up IA to production @ 1.7 bpm 550#. Pump 8,800 gallons of OilSafe AR down tubing taking returns up IA to production at 1.4 bpm. Displace with 30 bbls FIW. Final Treatment Pressure 250# @ 1.5 bpm. 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 60 115 124 554 76 Subsequent to operation: 178 421 81 74 75 14. Attachments (required Per 20 AAc 25.070, 25.071, &25.283) 15. Well Class after work: Daily Report of Well Operations 0 Exploratory ❑ Development Q Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Gas ❑ WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 1318-332 Authorized Name: Stan W. Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: dmarloweCcilhilcom.com Authorized Signature: C4, Date: 9 1-2!5 S Contact Phone: (907) 283-1329 Form 10-404 Revised 4/2017Submit Original Only RBDMS�. Ste 18 Z018 � 11 '!/� Trading Bay Unit SCHEMATIC Well #A-07 API# 50-733-20036-00 PTD: 167-046 Last Completed: 06/26/2018 RKB to TBG Hngr= 38.23' CASING DETAIL KB to MSL = 101', MSL to Mudline 66' BZN C, CZN C, CZN DZN IJ- HEM � EZN HEM PBTD = 6,089' (original 6,350') TD = 6,407' ANGLE thru INTERVAL = 3.2° PFRFnRATinN nATA Zone SIZE Wi GRADE CONN TOP BTM. Date 20" BZN Conductor Pile 2,120' Surface -264' 70' 13-3/8" 61 1-55 Butt a12.515 Surface 1,067' 2,244' 9-5/8' 40 1-55 Butt Surface 4,510' 2,874' 7" 26 J-55 Butt 4,746' 6,397' Open 2,875' TUBING DETAIL 2,874' 2,906' 22' 2-7/8" 6.5 L-80 8 round EUE 2.441 Surf 2,851' 1,917' 14' 2-7/8" 6.5 L-80 S round EUE Mod 2.441 1,917' 2,919' 4,425 27' 5 5/11/2013 Open 2,923' 2,947' 2,922' 2,946' 24' 4 9/8/1988 JEWELRY DETAIL 2,928' No Depth (MD) Depth (TVD) ID OD Item 4 8/17/1970 Open 38.23 35.23' Seaboard -ESP -EN, 11"x3-1/2" EUE lift & susp w/3" Type H BPV profile 1 300' 300' 2.313 4.650 Halliburton TRSV SSSV 9/9/1988 Open 2 413' 413' 2.920 8.500 Packer-DLH Hydroset II twinseal w/ Weatherford WET vent valve (35K shear) 3 1,953' 1,953' 2.441 4.625 GLM#1-SFO-1w/dummy valve 3,044' 4 4,389' 4,386' 2.313 3.670 XN Nipple w/ Brio -tech standing valve & Kobe knock out plug 4 8/17/1970 4,425' 4,422' N/A 3.050 Discharge, Bolt -On 3,242' 3,192' 3,241' 4,426' 4,423' N/A 4.500 Zenith Discharge Pressure sub Open 3,196' 4,426' 4,423' N/A 4.000 Pumps- 100 Stage Veretek 12' 4 5 4,533' 4,529' N/A 4.000 Intake Pump -9 Stage Veretek 3,240' 3,195' 3,239' 4,546' 4,542' N/A 4.000 Seals- Tandem Summit BPBSL Open 41-3 BZN 3,214' 4,563' 4,559' N/A 4.560 Motor- Summit FMS2,240HP/3040V/56A 26' 4 4,595' 4,591' N/A 4.560 Gauge(Zenith)/Anode/Centralizer 3,282' 3,433' PFRFnRATinN nATA Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Date Status BZN 2,050' 2,120' 2,050' 2,120' 70' 5 06/24/18 Open BZN 2,244' 2,334' 2,244' 2,334' 90' 5 06/24/18 Open 2,874' 2,906' 2,873' 2,906' 32' 5 5/11/2013 Open 2,875' 2,907' 2,874' 2,906' 22' 4 9/7/1988 Open 31-8 BZN 2'882 2,896' 2,851' 2,895' 14' 4 8/17/1970 Open 2,920' 2,947' 2,919' 2,946' 27' 5 5/11/2013 Open 2,923' 2,947' 2,922' 2,946' 24' 4 9/8/1988 Open 2,928' 2,944' 2,927' 2,943' 16' 4 8/17/1970 Open 2,997' 3,076' 2,996' 3,075' 79' 4 9/9/1988 Open 33-6 BZN 2,999' 3,077' 2,998' 3,076' 78' 5 5/11/2013 Open 3,044' 3,076' 3,043' 3,075' 32' 4 8/17/1970 Open 3,193' 3,242' 3,192' 3,241' 49' 5 5/11/2013 Open 3,196' 3,208' 3,195' 3,207' 12' 4 8/17/1970 Open 3,196' 3,240' 3,195' 3,239' 44' 4 9/10/1988 Open 41-3 BZN 3,214' 3,240' 3,231' 3,239' 26' 4 8/17/1970 Open 3,282' 3,433' 3,281' 3,432' 151' 5 5/11/2013 Open 3,283' 3,435' 3,282' 3,434' 52' 4 9/11/1988 Open 3,290' 3,434' 3,259' 3,433' 144' 4 8/17/1970 Open 3,300' 3,320' 3,299' 3,319' 20' 4 9/10/1970 Cmt Szqd 3,795' 3,960' 3,793' 3,958' 65' 4 9/12/1988 Open 3,803' 3,959' 3,801' 3,957' 156' 5 5/11/2013 Open 44-7 BZN 3,808' 3,850' 3,807' 3,848' 42' 4 8/17/1970 Open 3,520' 1 3,840' 3,818' 3,838' 20' 4 9/10/1967 Cmt Szqd 3,858' 1 3,956' 3,856' 3,954' 98' 4 1 8/17/1970 Open C-2 4,037' 4,097' 4,035' 4,095' 60' 5 5/11/2013 Open C-3 4,127' 4,224' 4,125' 4,221' 97' 5 5/11/2013 Open 44-7 BZN4,125' 4,225' 4,123' 4,222' 100' 4 9/15/1967 Cmt Szqd 4,140' 4,160' 4,138' 4,157' 20' 4 9/10/1967 Cmt Szqd CZNS6 4,267' 4,335' 4,264' 4,332' 68' 5 5/11/2013 Open C4 4,344' 4,371' 4,341' 4,368' 27' 5 5/11/2013 Open CS 4,429' 4,479' 4,426' 4,476' 50' 5 5/11/2013 Open C-6 4,600' 1 4,639' 4,595' 4,635' 39' 5 5/11/2013 Open 44-7 BZN 4,605' 4,625' 4,601' 4,621' 20' 4 9/10/1967 Cmt Szqd CZNS7 4,670' 4,700' 4,666' 4,696' 30' 5 5/11/2013 Open 4,720' 4,740' 4,716' 4,736' 20' 5 5/11/2013 Open C7 4,760' 4,781' 4,756' 4,777' 21' 5 5/11/2013 Open 49-4 CZN 4,807' 4,829' 4,803' 4,825' 22' 5 5/11/2013 Open 50-0 CZN 4,869' 4,879' 4,865' 4,875' 1 10' 5 5/11/2013 Open 50-3 CZN 4,897' 4,927' 4,893' 4,923' 30' 5 5/11/2013 Open CZNS2 4,952' 4,957' 4,959' 4,953' 5' 5 5/11/2013 Open 50-6 CZN 4,992' 5,021' 4,988' 5,017' 29' 5 5/11/2013 Open CZN59 5,102' 5,122' 5,097' 5,117' 20' 5 5/11/2013 Open 51-6 CZN 5,122' 5,156' 5,117' 5,151' 34' 5 5/11/2013 Open 51-9 CZN 5,170' 5,198' 5,165' 5,193' 28' 5 5/11/2013 Open 53-0 DZN 5,260' 5,288' 5,254' 5,282' 28' 5 5/11/2013 Open DZNS2 5,328' 5,335' 5,322' 5,329' 7' 5 5/11/2013 Open 53-8 DZN 5,360' 5,393' 5,354' 5,387' 33' 5 5/11/2013 Open 54-5 DZN 5,424' 5,458' 5,417' 5,451' 34' 5 5/11/2013 Open 54-9 DZN 5,492' 5,509' 5,485' 5,502' 17' 5 5/11/2013 Open 55-7 DZN 5,542' 5,560' 5,534' 5,552' 18' S 1 5/11/2013 Open 56-1 DZN 5,557' 5,670' 5,579' 5,661' 83' 5 5/11/2013 Open 57-2 DZN 1 5,700' 5,744' 5,691' 5,735' 74' 5 5/11/2013 Open 58-1 EZN 5,798' 5,817' 5,785' 5,807' 19' 5 5/11/2013 Open 5,823' 51837' 51,813' 5,827' 1 14' 5 5/11/2013 Open 58-7 EZN 5,560' 5,875' 5,550' 5,864' 1 15' 5 5/11/2013 Open 5,882' 5,948' 5,871'5,937' 66' 5 5/11/2013 Open 60-0 EZN 5,982' 6,019' 5,970' 6,007' 37' 5 5/11/2013 Open HemlockK 6,157' 6,328' 6,143' 6,312' 171'S 06/24/18 Open Hemlock 6,225' 6,330' 6,210' 6,314' 105' 5 06/24/18 Open Updated by: JU.07/16/18 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Pumping Unit 50-733-20036-00 1 167-046 8/31/18 1 8/31/18 Daily Operations: 08/31/2018 - Friday Rig up treatment equipment. Pressure test @ 100/250/500/2000. Pump 220 bbls FIW down tubing taking returns up IA to production @ 1.7 bpm 550#. Pump 8,800 gallons of OilSafe AR down tubing taking returns up IA to production at 1.4 bpm. Displace with 30 bbls FIW. Final Treatment Pressure 250# @ 1.5 bpm. Shut-in well to soak >48 hours. Secure well and rig down treatment equipment. NF SiATf 'ALASKA GOVERNOR BILL WALKER • Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Stan W. Golis SCAWKID A U U 155 2018 Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Trading Bay Field, Hemlock Oil & Middle Kenai B, C, D, & E Oil Pools, Trading Bay St. A-07 Permit to Drill Number: 167-046 Sundry Number: 318-332 Dear Mr. Golis: Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. DATED this day of August, 2018. Sincerely, Hollis S. French Chair RBDMS4(-)\AU6 0 9 2018 :7 • RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate El • Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other. ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number- Hilcorp Alaska, LLC Exploratory ❑ Development Stratigraphic ❑ Service ❑ 167-046 ' 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number. Anchorage, AK 99503 50-733-20036-00-00 ' 7. If perforating: 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes ❑ No I] Trading Bay St A-07 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0018731 Trading Bay Field / Hemlock Oil, Middle Kenai B,C,D & E Oil Pools 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): 6,407 • 6,389 6,089 6,076 2,000 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor —264' 20" —264' —264' Surface 1,067' 13-3/8" 1,067' 1,067' 3,090 psi 1,540 psi Intermediate Production 4,810' 9-5/8" 4,810' 4,806' 3,950 psi 2,570 psi Liner 1,651' 7" 6,397' 6,380' 7,240 psi 5,410 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 2,050 - 6,330 2,050 - 6,314 2-7/8" 6.5# / L-80 4,425 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): DLH Hydroset II Pkr & Halliburton TRSV 413 (MD) / 413 (TVD) & 300 (MD) / 300 (TVD) 12. Attachments: Proposal Summary 0 Wellbore schematic 0 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: 8/27/2018 OIL Q WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ElGSTOR ❑ SPLUG ElCommission 16. Verbal Approval: Date: Representative: GINJ ElOp Shutdown ❑ Abandoned El 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Stan W. Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: dmiarlOW hilco .com rr \ Contact Phone: 907 283-1329 w (O ($ Authorized Signature: 'k-�1 Date: COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. 31? -3-32 Plug Integrity ElBOP Test ❑ Mechanical Integrity Test El Location Clearance Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Subsequent Form Required: 4-10 �( APPROVED BY 7 Approved by: COMMISSIONER THE COMMISSION Date: G� ''b ORIGINAL BDMS_q"UG 0 9 201un S ubm t Form and Q, Form 10-403 Revised 4/2017 Approved application is valid for 12 months from the date of approval. - mac men Duplicate • • Hil�rp Alaska, LL(: Well Work Prognosis Well Name: Monopod A-07 API Number: 50-733-20036-00 Current Status: Oil Producer Leg: N/A Estimated Start Date: August 27, 2018 Rig: N/A Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 167-046 First Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) Second Call Engineer: Mike Quick (907) 777-8442 (0) (907) 317-2969 (M) Current Bottom Hole Pressure: 681 psi @ 2,873' TVD 0.237 psi/ft (4.56 ppg) 2013 ESP Gauge Maximum Expected BHP: 681 psi @ 2,873' TVD 0.237 psi/ft (4.56 ppg) 2013 ESP Gauge Maximum Potential Surface Pressure: 2,000 psi Treatment pump pressure limit Brief Well Summary: ZI The A-07 is currently completed in the B, C, D, E, and Hemlock sands. The last workover in June 2018 did not result in the expected productivity leading us to believe we have skin damage from the LCM used during the workover. This stimulation will attempt to restore expected productivity. _ Last Casing Test: 07/11/2013 2,836' 1,500 psig for 30 minutes on chart Procedure: 1. MIRU pumping equipment. 2. Shutdown ESP. 3. Pressure test surface lines to 1800-2,000 psi (treatment pump relief valve limit). 4. Mix chemicals and pump in the following sequence: a. Open back side, pump FIW down tubing taking returns up the annulus. b. Pump ±180 bbls Oilsafe AR (synthetic acid) c. Pump ±26 bbls FIW 5. Shut down pump and let for >_48 hours. 6. Rig down pumping equipment 7. Turn over to production Attachments: 1. Well Schematic Current 2. Fluid Flow Diagrams 3. Oilsafe AR —Technical Data Sheet Trading Bay Unit • SCHEMATIC • well # A-07 API# 50-733-20036-00 PTD: 167-046 Last Completed: 06/26/2018 RKB to TBG Hngr= 38.23' CASING DETAIL KB to MSL = 101', MSL to Mudline 66' TO @ 1,530' BZN C, CZN C, CZN DZN EZN HEM PBTD = 6,089' (original 6,350') TD = 6,407' ANGLE thru INTERVAL = 3.2° SIZE WT GRADE CONN ID TOP BTM. 20" Depth (TVD) Conductor Pile OD Item Surface -264' 13-3/8" 61 J-55 Butt 12.515 Surface 1,067' 9-5/8' 40 1-55 Butt 8.835 Surface 4,810' 7" 26 J-55 Butt 6.276 4,746' 6,397' GLM #1-SFO-1w/dummy valve 4 TUBING DETAIL 4,386' 2.313 3.670 2-7/8" 6.5 L-80 8 round EUE 2.441 Surf 1,917' 2-7/8" 6.5 L-80 8 round EUE Mod 1 2.441 1,917' 1 4,425 PERFORATION DATA Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) JEWELRY DETAIL No Depth (MD) Depth (TVD) ID OD Item 2,050' 38.23 38.23' 5 06/24/18 Seaboard -ESP -EN, 11"x3-1/2" EUE lift & susp w/3" Type H BPV profile 1 300' 300' 2.313 4.650 Halliburton TRSV SSSV 2 413' 413' 2.920 8.500 Packer- DLH Hydroset 11 twinseal w/ Weatherford WFT vent valve (35K shear) 3 1,953' 1,953' 2.441 4.625 GLM #1-SFO-1w/dummy valve 4 4,389' 4,386' 2.313 3.670 XN Nipple w/ Brio -tech standing valve & Kobe knock out plug 4 4,425' 4,422' 1 N/A 3.050 Discharge, Bolt -On 2,881' 4,426' 4,423' N/A 4.500 Zenith Discharge Pressure sub 31-8 BZN 4,426' 4,423' N/A 4.000 Pumps- 100 Stage Veretek 5 4,533' 4,529' N/A 4.000 Intake Pump -9 Stage Veretek 2,922' 4,546' 4,542' N/A 4.000 Seals- Tandem Summit BPBSL 4,563' 4,559' N/A 4.560 Motor -Summit FMS2, 240HP/3040V/56A 1 4 4,595' 4,591' N/A 4.560 Gauge(Zenith)/Anode/Centralizer PERFORATION DATA Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Date Status BZN 2,050' 2,120' 2,050' 2,120' 70' 5 06/24/18 Open BZN 2,244' 2,334' 2,244' 2,334' 90' 5 06/24/18 Open 2,874' 2,906' 2,873' 2,906' 32' 5 5/11/2013 Open 2,875' 2,907' 2,874' 2,906' 22' 4 9/7/1988 Open 2,882' 2,896' 2,881' 2,895' 14' 4 8/17/1970 Open 31-8 BZN 2,920' 2,947' 2,919' 2,946' 27' 5 5/11/2013 Open 2,923' 2,947' 2,922' 2,946' 24' 4 9/8/1988 Open 2,928' 2,944' 1 2,927' 2,943' 16' 1 4 8/17/1970 Open 2,997' 3,076' 2,996' 3,075' 79' 4 9/9/1988 Open 33-6 BZN 2,999' 3,077' 2,998' 3,076' 78' 5 5/11/2013 Open 3,044' 3,076' 3,043' 3,075' 32' 4 8/17/1970 Open 3,193' 3,242' 3,192' 3,241' 49' 5 5/11/2013 Open 3,196' 3,208' 3,195' 3,207' 12' 4 8/17/1970 Open 3,196' 3,240' 3,195' 3,239' 44' 4 9/10/1988 Open 3,214' 3,240' 3,231' 3,239' 26' 4 8/17/1970 Open 41-3 BZN 3,282' 3,433' 3,281' 3,432' 151' 5 5/11/2013 Open 3,283' 3,435' 3,282' 3,434' 52' 4 9/11/1988 Open 3,290' 3,434' 3,289' 3,433' 144' 4 8/17/1970 Open 3,300' 3,320' 3,299' 3,319' 20' 4 9/10/1970 Cmt Szqd 3,795' 3,960' 3,793' 3,958' 65' 4 9/12/1988 Open 3,803' 3,959' 3,801' 3,957' 156' 5 5/11/2013 Open 44-7 BZN 3,808' 3,850' 3,807' 3,848' 42' 4 8/17/1970 Open 3,820' 3,840' 3,818' 3,838' 20' 4 9/10/1967 Cmt Szqd 3,858' 3,956' 3,856' 3,954' 98' 4 8/17/1970 Open C-2 4,037' 4,097' 4,035' 4,095' 60' 5 5/11/2013 Open C-3 4,127' 4,224' 4,125' 4,221' 97' 5 5/11/2013 Open 4,125' 4,225' 4,123' 4,222' 100' 4 9/15/1967 Cmt Szqd 44-7 BZN 4,140' 4,160' 4,138' 4,157' 20' 4 9/10/1967 Cmt Szqd CZNS6 4,267' 4,335' 4,264' 4,332' 68' 5 5/11/2013 Open C4 4,344' 4,371' 4,341' 4,368' 27' 5 5/11/2013 Open CS 4,429' 4,479' 4,426' 4,476' S0' 5 5/11/2013 Open C-6 4,600' 4,639' 4,595' 4,635' 39' 5 5/11/2013 Open 44-7 BZN 4,605' 4,625' 4,601' 4,621' 20' 4 9/10/1967 Cmt Szqd 4670' 4,700' 4,666' 4,696' 30' 5 5/11/2013 Open CZN57 4,720' 4,740' 4,716' 4,736' 20' 5 5/11/2013 Open C7 4,760' 4,781' 4,756' 4,777' 21' 5 5/11/2013 Open 49-4 CZN 4,807' 4,829' 4,803' 4,825' 22' 5 5/11/2013 Open 50-0 CZN 4,869' 4,879' 4,865' 4,875' 10' 5 5/11/2013 Open 50-3 CZN 4,897' 4,927' 1 4,893' 4,923' 30' 5 5/11/2013 Open CZNS2 4,952' 4,957' 4,989' 4,953' 5' 5 5/11/2013 Open 50-6 CZN 4,992' 5,021' 4,988' 5,017' 29' 5 5/11/2013 Open CZNS9 5,102' 5,122' 5,097' 5,117' 20' S 1 5/11/2013 Open 51-6 CZN 5,122' 5,156' 5,117' 5,151' 34' S 1 5/11/2013 Open 51-9 CZN 5,170' 5,198' 5,165' 5,193' 28' 5 5/11/2013 Open 53-0 DZN 5,260' 5,288' 5,254' 5,282' 28' 5 5/11/2013 Open DZNS2 5,328' 5,335' 5,322' 5,329' 7' 5 5/11/2013 Open 53-8 DZN 5,360' 5,393' 1 5,354' 5,387' 33' 5 5/11/2013 Open 54-5 DZN 5,424' 5,458' 5,417' 5,451' 34' 5 5/11/2013 Open 54-9 DZN 5,492' 5,509' 5,485' 5,502' 17' 5 5/11/2013 Open 55-7 DZN 5,542' 5,560' 5,534' 5,552' 18' 5 5/11/2013 Open 56-1 DZN 5,587' 5,670' 5,579' 5,661' 83' 5 5/11/2013 Open 57-2 DZN 5,700' 5,744' 5,691' 5,735' 74' 5 5/11/2013 Open 5,798' 5,817' 5,788' 5,807' 19' 5 5/11/2013 Open 58-1 EZN 5,823' 1 5,837' 5,813' 5,827' 14' 5 5/11/2013 Open 5,860' 5,875' 5,850' 5,864' 15' 5 5/11/2013 Open 58-7 EZN 5,882' 5,948' 5,871' 5,937' 66' 5 5/11/2013 Open 60-0 EZN 5,982' 6,019' 5,970' 6,007' 37' 5 5/11/2013 Open HemlockK 6,157' 6,328' 6,143' 6,312' 171' S 06/24/18 Open Hemlock 6,225' 6,330' 6,210' 6,314' 105' S t 06/24/18 Open Updated by: JUL 07/16/18 BATCH TANK TRIPLEX PUMP i Dn. NUMBER 917 REFERENCE DRAWINGS n REVISED V ..wa....o ...�,o. COOK INLET OFFSHORE COOK INLET ALASKA PIPING AND INSTRUMENT DIAGRAM w� PORTABLE WELL WORK PUMP H MLCMAid>gAiI.0 Oil Safe ARO is a safe yet functional replacement for traditional hydrochloric acid treatments and other commonly used oilfield acid treatments. It is non-regulated by US DOT, Canadian TDG and carries a triple zero hazardous materials information system score. Oil Safe ARO biodegrades in10 days or less and is approved by the US EPA as a Designed for the Environment product. Our standard Oil Safe AR® formula includes iron control agents, de-mulsifiers and requires no organic acid additions or corrosion inhibitors under most conditions. FEATURES AND BENEFITS: • An excellent choice for fracs, spearhead treatments, injection wells and dis- posal wells and annular soaks • Requires no organic acid additions to help retard reaction rates • Standard formula includes surfactant and de-mulsifier system • Requires no iron control agent addition for most applications • EPA DfE formula; biodegradable in 10 days or less; approved for direct dis- charge; made with Cleangredients and DfE ingredients approved by the EPA • Safe on most metals, piping and pumping equipment • Non toxic; non fuming; non mutagenic; no VOC's • No secondary containment required as per Chapter 62-761 F.A.C. • Eliminates foulants • An excellent choice for work -over projects, bullhead treatments and cement remediation • Requires no additional corrosion inhibitor step for most applications • 100% biodegradable, acid free and naturally inhibited DISSOLVING PROPERTIES ACID TYPE % CaCO' Oil Safe ARO 100% Solution 100.00% Oil Safe ARO 50% Solution 96.76% Oil Safe AR@ 30% Solution 54.00 7 V. HCI 46.48% 15% HCI 87.39% 7'/2 HCI + 100 gpt of 85% Acetic Acid 75.08% 15% HCI + 100 gpt of 85% Acetic Acid 97.87% 10% Acetic Acid 21.00% 15% Acetic Acid 63.09% Each test above was conducted with 1 cubic inch of material placed in 50 ml of solution and allowed to soak for 8 his at 100T. TYPICAL PHYSICAL PROPERTIES: Appearance and Color Colorless to slight yellow liquid Initial Freeze Point -24.88°F (-31.6°C) Odor Odorless to mild soapy odor Solubility in water 100% Flashpoint None Specific Gravity 1.152+0.04 DIRECTIONS FOR USE: Recommended Dilution Rates: 30-100% with H2O based on the severity of the build-up and the reaction rate required for the project. Note: Oil Safe ARO concentrate contains iron control agents and de-mulsifiers. No organic acid or corrosion inhibitors are required due to the power of our patented Syntech®. A typical ratio for an acid frac is one part Oil Safe AR@ and one part H2O. Blending ratios may vary based on specific applications and recommendations from your consultants at Heartland Energy Group, Ltd. STORAGE AND HANDLING: Oil Safe ARO has a storage life of better than one year. Keep container closed when not in use. As with all chemical products and materials, take care as to where you store them. Safety glasses are suggested for use when handling this product. No special gloves or protective equipment are required when handling this product. When pumping this product, it is strongly recommended to use manufacturer approved hose couplings or fittings. DO NOT USE ALUMINUM FITTINGS. 316 Stainless Steel, polypropylene, po yethylene are recommended. PACKAGING: Oil Safe AR® is shipped in bulk tanker trucks from the manufacturing facility. Smaller packaging quantities are available upon request. Recommendations given in this data sheet are based on tests believed to be reliable. However, the use of the information is beyond the control of Heartland Energy Group, Ltd., and no guarantee, ex- pressed or implied is made to the results obtained ifnot used in accordance with directions or established safe practice. The buyermust assume all responsibility, including injury or damage from the misuse of the product as such, or in combination with other materials. This bulletin isnot to be taken as a license to operate under or recommendation to infringe anypatent. STATE OF ALASKA ACA OIL AND GAS CONSERVATION COMSION REPORT OF SUNDRY WELL OPERATIONS RECOVED JUL 17 2013 1. Operations Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Pull Tubing ❑i ElPerformed: Suspend El Perforate [21 Other Stimulate El Alter Casing ElChange App ov r ❑ Plug for Redri]l ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: ESP/GL Completion 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development Exploratory ❑ Stratigraphic ❑ Service ❑ 167-046 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-733-20036-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0018731 Trading Bay St A-07 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Trading Bay Field / Hemlock Oil, Middle Kenai B,C,D & E Oil Pools 11. Present Well Condition Summary: Total Depth measured 6,407 feet Plugs measured N/A feet true vertical 6,389 feet Junk measured N/A feet Effective Depth measured 6,089 feet Packer measured 413 feet true vertical 6,076 feet true vertical 413 feet Casing Length Size MD TVD Burst Collapse Structural Conductor —264' 20" —264' —264' Surface 1,067' 13-3/8" 1,067' 1,067' 3,090 psi 1,540 psi Intermediate Production 4,810' 9-5/8" 4,810' 4,806' 3,950 psi 2,570 psi Liner 1,651' 7" 6,397' 6,380' 7,240 psi 5,410 psi Perforation depth Measured depth 2,050 - 6,330 feet SCMSES' 2 4 2018 True Vertical depth 2,050 - 6,314 feet Tubing (size, grade, measured and true vertical depth) 2-7/8" 6.5# / L-80 4,425 (MD) 4,422 (TVD) 413 (MD) 300 (MD) Packers and SSSV (type, measured and true vertical depth) DLH Hydroset II 413 (TVD) Halliburton TRSV 300 (TVD) 12. Stimulation or cement squeeze summary: Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 118 357 119 519 81 Subsequent to operation: 285 462 308 128 133 14. Attachments (required per 20 AAC 25.070, 25.071, &25.283) 15. Well Class after work: Daily Report of Well Operations 221 Exploratory ❑ Developments Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ IGSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 1318-158 Authorized Name: Stan W. Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: dmarloweC_hilcorp.com Authorized Si nature: L") 6 rc Date: k $ Contact Phone: (907) 283-1329 I TL q/)4/l?, 4 Form 10-404 Revised 4/2017 ABDMS/��L 181018 Submit Original Only Trading Bay Unit SCHEMATIC • Well # A-07 API# 50-733-20036-00 PTD: 167-046 Last Completed: 06/26/2018 RKB to TBG Hngr = 38.23' CASING DETAIL KB to MSL = 101', MSL to Mudline 66' 4 BZN C, CZN ....I T C, CZN DZN EZN HEM PBTD = 6,089' (original 6,350') TD = 6,407' ANGLE thru INTERVAL = 3.2° SIZE WT GRADE CONN ID TOP BTM. 20" Depth TVD Conductor Pile OD Item Surface "264' 13-3/8" 61 1-55 Butt 12.515 Surface 1,067' 9-5/8" 40 J-55 Butt 8.835 Surface 4,810' 7" 26 1-55 Butt 6.276 4,746' 6,397' GLM #1-SFO-1w/dummy valve 4 TUBING DETAIL 4,386' 2.313 3.670 2-7/8" 6.5 L-80 8 round EUE 1 2.441 Surf 1,917' 2-7/8" 1 6.5 L-80 8 round EUE Mod 1 2.441 1,917' 4,425 PERFORATION DATA Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) JEWELRY DETAIL No Depth (MD Depth TVD ID OD Item 2,050' 38.23 38.23' 5 06/24/18 Seaboard -ESP -EN, 11"x3-1/2" EUE lift & susp w/3" Type H BPV profile 1 300' 300' 2.313 4.650 Halliburton TRSV SSSV 2 413' 413' 2.920 8.500 Packer- DLH Hydroset II twinseal w/ Weatherford WFT vent valve (35K shear) 3 1,953' 1,953' 2.441 4.625 GLM #1-SFO-1w/dummy valve 4 4,389' 4,386' 2.313 3.670 XN Nipple w/ Brio -tech standing valve & Kobe knock out plug 4 4,425' 4,422' N/A 3.050 Discharge, Bolt -On 2,881' 4,426 4,423' N/A 4.500 Zenith Discharge Pressure sub 31-8 BZN 4,426' 4,423' N/A 4.000 Pumps- 100 Stage Veretek 5 4,533' 4,529' N/A 4.000 Intake Pump -9 Stage Veretek 2,922' 4,546' 4,542' N/A 4.000 Seals -Tandem Summit BPBSL 4,563' 4,559' N/A 4.560 Motor -Summit FMS2, 240HP/3040V/56A 4 4,595' 4,591' N/A 4.560 Gauge(Zenith)/Anode/Centralizer PERFORATION DATA Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Date Status BZN 2,050' 2,120' 2,050' 2,120' 70' 5 06/24/18 Open BZN 2,244' 2,334' 2,244' 2,334' 90' 5 06/24/18 Open 2,874' 2,906' 2,873' 2,906' 32' 5 5/11/2013 Open 2,875' 2,907' 2,874' 2,906' 22' 4 9/7/1988 Open 2'882 2,896' 2,881' 2,895' 14' 4 8/17/1970 Open 31-8 BZN 2,920' 2,947' 2,919' 2,946' 27' 5 5/11/2013 Open 2,923' 2,947' 2,922' 2,946' 24' 4 9/8/1988 Open 2,928' 2,944' 2,927' 2,943' 16' 4 8/17/1970 Open 2,997' 3,076' 2,996' 3,075' 1 79' 4 9/9/1988 Open 33-6 BZN 2,999' 3,077' 2,998' 3,076' 78' S 1 5/11/2013 Open 3,044' 3,076' 3,043' 3,075' 32' 4 8/17/1970 Open 3,193' 3,242' 3,192' 3,241' 49' 5 5/11/2013 Open 3,196' 3,208' 3,195' 3,207' 12' 4 8/17/1970 Open 3,196' 3,240' 3,195' 3,239' 44' 4 9/10/1988 Open 3,214' 3,240' 3,231' 3,239' 26' 4 8/17/1970 Open 41-3 BZN 3,282' 3,433' 3,281' 3,432' 151' 5 5/11/2013 Open 3,283' 3,435' 3,282' 3,434' 52' 4 9/11/1988 Open 3,290' 3,434' 3,289' 3,433' 144' 4 1 8/17/1970 Open 3,300' 3,320' 3,299' 3,319' 20' 4 9/10/1970 Cmt Szqd 3,795' 3,960' 3,793' 3,958' 65' 4 9/12/1988 Open 3,803' 3,959' 3,801' 3,957' 156' 5 5/11/2013 Open 44-7 BZN 3,808' 3,850' 3,807' 3,848' 42' 4 8/17/1970 Open 3,820 3,840' 3,818' 3,838' 20' 4 9/10/1967 Cmt Szqd 3,858' 3,956' 3,856' 3,954' 98' 4 8/17/1970 Open C-2 4,037' 4,097' 4,035' 4,095' 60' S 5/11/2013 Open C-3 4,127' 4,224' 4,125' 4,221' 97' S 1 5/11/2013 Open 4,125' 4,225' 4,123' 4,222' 100' 4 9/15/1967 Cmt Szqd 44-7 BZN 4,140' 4,160' 4,138' 4,157' 20' 4 9/10/1967 Cmt Szqd CZNS6 4,267' 4,335' 4,264' 4,332' 68' 5 5/11/2013 Open C4 4,344' 4,371' 4,341' 4,368' 27' 5 5/11/2013 Open C5 4,429' 4,479' 4,426' 4,476' 50' 5 5/11/2013 Open C-6 4,600' 1 4,639' 4,595' 4,635' 39' 5 5/11/2013 Open 44-7 BZN 4,605' 4,625' 4,601' 4,621' 20' 4 9/10/1967 Cmt Szqd 4,670' 4,700' 4,666' 4,696' 30' 5 5/11/2013 Open CZNS7 4,720' 4,740' 4,716' 4,736' 20' 5 5/11/2013 Open C7 4,760' 4,781' 4,756' 4,777' 21' 5 5/11/2013 Open 49-4 CZN 4,807' 4,829' 4,803' 4,825' 22' 5 5/11/2013 Open 50-0 CZN 4,869' 4,879' 4,865' 4,875' 10' 5 5/11/2013 Open 50-3 CZN 4,897' 4,927' 4,893' 4,923' 30' 5 5/11/2013 Open CZNS2 4,952' 1 4,957' 4,989' 4,953' 5' 5 5/11/2013 Open 50-6 CZN 4,992' 1 5,021' 4,988' 5,017' 29' 5 5/11/2013 Open CZNS9 5,102' 5,122' 5,097' 5,117' 20' 5 5/11/2013 Open 51-6 CZN 5,122' 5,156' 5,117' 5,151' 34' 1 5 5/11/2013 Open 51-9 CZN 5,170' 5,198' 5,165' 5,193' 28' 1 5 5/11/2013 Open 53-0 DZN 5,260' 5,288' 5,254' 5,282' 28' 5 5/11/2013 Open DZNS2 5,328' 5,335' 5,322' 5,329' 7' 5 5/11/2013 Open 53-8 DZN 5,360' 5,393' 5,354' 5,387' 33' 5 5/11/2013 Open 54-5 DZN 5,424' 5,458' 5,417' 5,451' 34' 5 5/11/2013 Open 54-9 DZN 5,492' 5,509' 5,485' 5,502' 17' 5 5/11/2013 Open 55-7 DZN 5,542' 5,560' 5,534' 5,552' 18' 5 5/11/2013 Open 56-1 DZN 5,587' 5,670' 5,579' 5,661' 83' 5 5/11/2013 Open 57-2 DZN 5,700' 5,744' 5,691' 5,735' 74' 5 5/11/2013 Open 5,798' 5,817' 5,788' 5,807' 19' 5 5/11/2013 Open 58-1 EZN 5,823' 5,837' 5,813' 5,827' 14' 5 5/11/2013 Open 5,860' 5,875' 5,850' 5,864' 15' 5 5/11/2013 Open 58-7 EZN 5,882' 5,948' 5,871' 5,937' 66' 5 5/11/2013 Open 60-0 EZN 5,982' 6,019' 5,970' 6,007' 37 5 5/11/2013 Open HemlockK 6,157' 6,328' 6,143' 6,312' 171' S 06/24/18 Open Hemlock 1 6,225' 6,330' 6,210' 6,314' 105' 5 06/24/18 Open Updated by: JILL 07/16/18 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Monopod Rig 56 50-733-20036-00 1 167-046 1 6/13/18 1 6/26/18 � Daily Operations: 06/13/2018 - Wednesday R/U Pollard S/L while securing storm clamps on skid sections. M/U Run #1 rope socket, 2- 5' 11/2" stem w/ oil and spang jars plus 2 1/4" gauge. Prod personnel prep tree for well work. M/U lubricator to well head w/ tool string inside- tested to 1500 psi. Bled pressure off and opened well. 300 psi on tb and casing. TIH w/ Run #1 to 201'- could not get deeper- POOH - evidence of paraffin. B/O gauge and M/U scratcher. Production pumped 10 bbls of diesel down hole- 0310 hrs TIH w/ Run #2 to 1,200' with no trouble- POOH and B/O scratcher- M/U kick -over tool and TIH to 2,656' and latched valve -jarred valve from pocket and POOH. R/D S/L. Lined up to kill/flush well w/ FIW sending returns to prod well clean tank. 06/14/2018 - Thursday Continued R/U to kill well sending returns to prod well clean tank. Held PJSM w/ prod and rig crew- pumped 400 bbls FIW @ 3 bpm 0 psi- no returns. Prepared NW -50 pill. Pumped 44.5 bbls (#1) 9.5# NW -50 pill staging in at 5 min intervals. Shut well in and mixed another batch of NW -50 pill. R/D circ equipment from tree/annulus- R/U pump to well clean tank and pumped 115 bbls 9.5# away (contents of active system)- R/U to A-07 tree and annulus. Mixed another 84 bbls NW -50 pill. Pumped 42 bbl NW -50 pill down tb at 3 bpm 0 psi followed by second 42 bbl pill (#2) at same rate- no returns. Monitored well while building 35 bbl NW -50 pill. Pumped (#3) pill down tb at 3 bpm 0 psi- no returns. Monitored well while building 35 bbls (higher visc) NW -50 pill- pumped (#4) pill down tb at 3 bpm 0 psi- chased w/ 20 bbls FIW- no returns. Monitored well while building 40 bbl NW -50 pill. Decision was made to skid rig over for slickline work on A-31. Moved cylinders around, removed storm clamps, flow lines, stair way, vac unit- raised cable tray, cleared V -door, greased skids, moved rear walkway. Skidded rig 7' West- setup stairways and handrails as needed only. Bled down 80 psi on IA (thru flare) prior to attempting circulation. Began pumping FIW LW at 3 bpm 0 psi- pumped 400 bbls w/ no indication of fluid rise in annulus (slightest blow on casing). Pumped 40 bbls of NW -50 pill (#5) @ 3 bpm 0 psi- chased with 20 bbls FIW- no returns. Mixed 80 bbl sized salt pill. Pumped 42 bbls of the sized salt pill then chased w/ 16 bbls FIW- no returns. Monitored well- 0 psi on casing. Mixed another 40 bbl sized salt pill while allowing 1st ssp to soak. C • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Monopod Rig 56 50-733-20036-00 167-046 6/13/18 6/26/18 Daily Operations:an4 ,�... 06/15/2018 - Friday Finished mixing 80 bbl sized salt pill. Pumped 80 bbl pill @ 3 bpm- pump pressure 0, shut down monitor went on vac. Mixed another 80 bbl sized salt pill while allowing last pill to soak. Performed housekeeping/maintenance: greased choke manifold, sweep decks, assisted crane crew R/U 3" hose for diesel transfer, clean suction screen on MP #2. Finished building 80 bbl pill. Cleaned & organized mud pump room, gathered pallets and sacks. Pumped 80 bbl pill @ 3 bpm- pump pressure 0, shut down monitor went on vac. Monitored well while building another 80 bbl sized salt pill. Pumped 80 bbl pill @ 3 bpm- pump pressure 0, shut down monitor went on vac. Unload product from boat, Mixed 200 bbl calcium chloride pill- 2100 hrs worked M/V receiving needed Baracarb ingredients for pill and diesel ISO- worked on hanging rig tongs on floor. Agitated pill f/ 30 mins. Began pumping 200 bbl 9.5# CC pill at 3 bpm 0 psi- gradual increase on pump and casing pressures. 160 bbls away 500 psi on pump and 225 psi on casing- decreased pump rate to 1 bpm. 180 bbls away pump pressure 600 psi, casing 400 psi. Shutdown f/ 30 mins to monitor pressures 375 psi on tb- 275 psi on casing). Tb pressure at 150 psi, casing pressure at 185 psi- began pumping again at 1 bpm. Pumped remaining 20 bbls pill and 10 bbls FIW with ending pressures at 700 psi on casing & tb- (static pressure 560 psi tb, 530 psi casing). Began prepping to skid rig back over A-07. Pressures at 0430 are 330 psi on tb & casing. 0500 pressures 200 psi on casing & tb. 0530 pressures 180 psi on both. 0600 pressures are 100 on tb 130 on casing. 06/16/2018` -Saturday Skid rig over well center & secure, install landings, hand rails & flow line. Clean and organize drill deck- service rig and adjust brakes. Flushed well pumping down tb, taking returns to well clean tank at 3 bpm- caught pressure at 6 bbls away, returns at 29 bbls away- treated returns w/ bleach- increased rate to 4 bpm 800 psi- returns cleaned up at 300 bbls pumped. Shut down pump. Monitored well- no flow, well is on vacuum- rig down hoses from tree and AI valve. NOS installed BPV and tested hanger void- good. N/D tree- cleaned threads in hanger and M/U blanked test sub. Lowered 13 5/8" 5M riser w/ 11" adapter spool- M/U to tb head. Added mud cross w/ manual & hyd valves, double gate w/ blinds & 2 7/8" x 5" VBR and annular. Bolted on air boots and installed flow risor- installed mouse hole. M/U 3 1/2" test jt w/ ported LHR sub on btm, pump in, SV, IBOP on top- M/U to test sub in hanger- setup test pump and manifold- filled system w/ FIW. Shelled tested to 2500 psi. P/U Kelly and M/U 3 1/2" IF lower Kelly valve- filled Kelly and tested upper & lower Kelly valves- set back Kelly. Lined test pump back on test jt- continued pretesting BOPE until AOGCC witness arrives. Continue cleaning and organizing cellar and mud pump areas. • 0 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Monopod Rig 56 50-733-20036-00 1 167-046 6/13/18 6/26/18 . Daily Operations: . x 06/17/2018 - Sunday Continued working thru BOPE pretest while awaiting arrival of AOGCC witness. Continued with housekeeping of upper deck, cellar and mud room. Tested all BOPE to 250 psi low 2500 psi high, as per Sundry, in accordance with Hilcorp and AOGCC requirements- tested with 2 7/8" & 3 1/2" tb. Performed successful koomey draw down test. All tests witnessed by Mr. Bob Nobles/AOGCC. B/D test equipment- pulled BPV- M/U landing jt and screwed into hanger. P/U on string and hanger moved off seat at 20k- pkr released at 70k. Lined up to circ LW- returns after 110 bbls pumping 5 bpm 800 psi- circ 2- btms up - losses running — 24 bph. Shutdown pump- well on slight vac. Pulled hanger to surface (weighing 30k)- NOS worked and laid down hanger. Pulled 1- stand and setup control line spooler on pipe deck. POOH standing back 2 7/8" 6.5# L-80 completion tb, spooling up SSSV and chem inj control line. Laid down SSSV, 2- SPM, CIM and 9 5/8" hyd set pkr w/ pups & WLEG- S/B 28 - stands of 2 7/8" + L/D 2- singles- (full recovery). Cleared and cleaned floor- prepped to M/U WFT BHA #1. Changed out tongs- loaded floor w/ needed DH tools. M/U WFT BHA #1: 6 1/8" Varel rock bit, 2- 5" x 11/2" boot baskets, 4 3/4" x 11/2" bit sub, 4 3/4" x 2 1/4" Tripoint magnet, 4 3/4" x 2 1/4" bumper & oil jars, 6- 4 3/4" x 2 1/4" DCs, 4 3/4" x 2 1/4" Acc jar = 234.64'. Losses — 30 bph. TIH running BHA on 3 1/2" IF 13.30# S-135 DP- had to set back Gill tongs- used spinner hawk and BJs to make connections. R/I 27 stands of DP = 2,573' EOT. R/U circulate at 5 bpm 500 psi at 2,805'. TIH p/u singles from 2,805' to 2,998' 06/18/2018 - Monday Cont. tih p/u 3 1/2" wk string w/BHA #1 t/ 3837' tagged up. Attempt to wk through, no luck, Kelly up, wash & ream past spot, drift through clean. Cont. TIH p/u 3 1/2" wk string t/ 4706' tag up. P/U Kelly (PUW 80k)- broke circ at 5 bpm 500 psi- washed/rotated down from 4,706' to 4,780' at 60 RPMs. Serviced rig- greased draw works, Kelly, blocks & crown- checked oil in Kelly swivel. Washed/rotated from 4,780' to 4,895' 5 bpm 500 psi, 10-15k WOB- broke thru at 4,895'- nothing to 4,970'. M/U #149 on Kelly and washed down to 5,002' w/o rotating- circulated hole clean at 6 bpm 600 psi w/ loss rate at 15 bph. RIH Dry t/ 5,093'. Set back Kelly. Cont. in hole t/ 5,210'. Tag up, P/U Kelly. Washed & ream from 5,210' to 5,444' Circulated btms up 7 bpm 850 psi- losses — 21 bph. Continued washing/rotating from 5,444' to 5,452'- ROP slowed- now running 10k WOB, 5 bpm 500 psi, 60 RPM. Washed/rotated from 5,452' to 5,696' (#171 + Kelly) w/ intermittent ROP breaks that don't correspond to perf intervals- losses — 16 bph. Added 4 gals of oil to swivel. M/U #172 and continued from 5,696' at report time. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Monopod Rig 56 50-733-20036-00 1 167-046 6/13/18 1 6/26/18 Daily Operations: 06/19/2018 -Tuesday Cont. Wash & ream f/5,696', t/ 6087' EZ Drill Cmt retainer, Up/Dn/rot wt 95k 80 RPM, 2k tq off, circ 7 BPM 1050psi. Drill up Cmt retainer 10-15k WOB, Up/Dn/rot wt 95k 80 RPM, 2k tq off, circ 7 BPM 1050psi. Cont. down to top of Packer 6097' pipe measurement, CBU clean c/o handling eq. POOH standing back 3 1/2" wk string in derrick. B/D WFT BHA #1- recovered 40.75#s of metal from inline magnet and boot baskets- pics in '0' drive. M/U WFT BHA #2: 6 1/8" x 5 1/8" pkr type shoe, 5 3/4" x 4 5/16" XO bushing, 5 3/4" x 4 3/16" overshot bowl, 5 3/4" x 2 7/8" top sub, 4 3/4" x 11/2" DP sub, 2- 5" x 11/2" boot baskets, 4 3/4" x 11/2" bit sub, 4 3/4" x 2 1/4" Tripoint magnet, 4 3/4" x 2 1/4" B&O jars, 6- 4 3/4" x 2 1/4" spiral DCs, 4 3/4" x 2 1/4" Acc jar = 245.94'. TIH w/ BHA #2 on 3 1/2" 13.30# S-135 IF DP to 6,080' (61 stands + single). P/U Kelly and began circ 5 bpm 550 psi- tagged 2' in @ 6,084' (13' high)- P/U B/O single #184- M/U Kelly to string and began circ again at 5 bpm 550 psi 50 RPMs 0 Torq PU/SO 95k- eased down and tagged something at 6,084' again. Began washing/rotating at 6,084'. Washed/rotated from 6,084' to 6,090' (Kelly down). B/O Kelly and M/U #184- continued washing/rotating to 6,097'- 0245 hrs began milling on pkr- 6,099' at report time. Losses — 12 bph. 06/20/2018 - Wednesday Continued milling on pkr/junk at 6,099' at 4 bpm 430 psi, 80 RPMs 1-6k FPT, 5k WOB, PU/SO 95k- losses running 11 bph. No hole made last couple of hrs- decision made to circ & POOH. CBU at 8 bpm 1415 psi. Serviced rotary table and high drum clutch. S/B Kelly and R/U spinner hawk. Had 15k overpull when pulling off btm- P/U Kelly again and attempted to work free - unable to pull free w/o pump- pumped OOH laying down singles to liner top. S/B Kelly and finished ooh R/B pipe (47 stands). B/D BHA #2- B/0 shoe, 100% wear on face of shoe (no indications of milling over pkr inside shoe)- emptied boot baskets and cleaned magnet- 41.5#s of metal recovered, f/ a total of 82.25#s in 2 runs. Installed wear ring- M/U boot baskets on magnet/jar assy. Waited on concave mill. Finished M/U WFT BHA #3: 6 1/16" x 11/2" Concave mill, 2- 5" x 11/2" boot baskets, 4 3/4" x 11/2" bit sub, 4 3/4" x 2 1/4" Tripoint magnet, 4 3/4" x 2 1/4" B&O jars, 6- 4 3/4" x 2 1/4" spiral DCs, 4 3/4" x 2 1/4" Acc jar = 235.88'. TIH w/ WFT BHA #3 to 4,708' (47 stands in)- 0030 hrs P/U Kelly and flushed thru liner top (@ 4,746') several times- S/B Kelly. CIH P/U singles to 6,072' (61 stands + single)- P/U Kelly and break circ at 5 bpm 550 psi, PU/SO 95k- tagged at 6,097' (had 1 1/2' of fill on top). Milled w/ 3-5k WOB 300-500 FPT. t/6097.5. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Monopod Rig 56 1 50-733-20036-00 167-046 6/13/18 6/26/18 Daily Operations:, 06/21/2018 - Thursday Cont. Mill t/6098', ro 40-80 RPM, tq 2.5k, circ 3-8 BPM varying parameters hunting Tq. CBU, had gas breaking out, CBU @ 8 BPM 1250 psi, shut down monitor well. CBU @ 8 BPM 1250 psi, gas breaking out @ BU, mix & spot weighted pill, monitor hole, static. Stand back Kelly, POOH t/ liner top @4746'. CBU, monitor hole, good, pump slug. Cont. POOH t/ BHA. B/D WFT BHA #3 20% wear on concave mill- recovered 43#s of metal from 2- boot baskets and magnet, for a total recovery of 125.25#s of metal (3 runs). Discussed plan forward w/ Eng & WFT. M/U WFT BHA #4: 6 1/8" x 4 3/16" pkr type shoe, 5 3/4" x 4 5/16" XO bushing, 5 3/4" x 4 3/16" overshot bowl, 5 3/4" x 2 7/8" top sub, 4 3/4" x 2 1/4" Tripoint magnet, 4 3/4" x 2 1/4" B&O jars, 6- 4 3/4" x 2 1/4" spiral DCs, 4 3/4" x 2 1/4" Acc jar = 235.74'. TIH to 4,768'- B/O single and R/U circ hose- P/U and flushed thru TOL several times- R/D hose and CIH to tag @ 6,094'. P/U 2' and R/U hose to rev out down flow line bypassing stand pipe & manifold- closed bag and circ btms up at 5 bpm 530 psi- no solids in returns. Washed down to 6,097' and tagged solid- reversed btms up- sand, traces of oil and some pill in returns. P/U Kelly and M/U to string- estb circ at 5 bpm 540 psi- eased down seeing torque at 6,096.5'. Milled down to 6097.6' lost weight w/ 2k WOB, 1000 FPT, 80 RPMs. Fluid losses — 18 bph. Increased rate to 8 bpm 960 psi- circ btms up. No gas to surface, losses still — 18 bph. 0330 hrs washed & reamed chasing down t/6,245'- worked to 6,290' stopped making headway. 06/22/2018 - Friday CBU @ 8 BPM 1250psi. Monitor well, good. POOH standing back wk string, up do wt 98k. L/D BHA, shoe was 75% worn on face & outside leading edge, inside green, had 4 locator pins sheared ( 17"). Prep & M/U BHA #5 - Overshot assy, string magnet, bumper sub, oil jar, 6-4 3/4" DC, acc jar= 229.06'. TIH to 6,256'. P/U Kelly and tagged pkr @ 6290'- went thru the motions to latch same. S/B Kelly and attempted to POOH but had tight spot at 6,230'- P/U Kelly again- pulled L/O 4- singles- S/B Kelly- pumped dry job. POOH. B/D BHA #5- recovered milled over pkr assy in overshot (flapper assy in btm of recovery). Cleaned 16.6#s of metal off magnet for a total of 141.85#s recovered. M/U BHA #6: 6 1/8" bladed junk mill, 2- 5" x 11/211 boot baskets, 4 3/4" x 11/2" bit sub, 4 3/4" x 2 1/4" Tripoint magnet, 4 3/4" x 2 1/4" B&O jars, 6- 4 3/4" x 2 1/4" spiral DCs, 4 3/4" x 2 1/4" Acc jar = 236.11'. TIH w/ BHA #6 to 6,136' (62 stands)- P/U 4- singles to 6,263'. P/U Kelly and broke circ at 5 bpm 620 psi, 80 RPMs at 1000 FPT, RotW 97k, P/U S/0 98k. Losses running — 16 bph- wash & ream f/ 6,291' to 6,341' tag up solid decision made to call TD. 06/23/2018 - Saturday TD called at 6,341'. P/U to 6,336' and CBU x 2 @ 8 bpm 1650 psi- losses — 14 bph. Monitored well- good. S/B Kelly- Utubing- pumped 10 bbl pill- attempted to pull but hung- P/U Kelly and circ 3- singles out (minimual trouble). S/B Kelly- pulled to liner top and R/U circ hose- flushed thru liner top several times. POOH to BHA. B/D WFT BHA #6 completely- L/O all tools - recovered 39.3 lbs of metal from 2- boot baskets and magnet. Total of 181.15 lbs of metal recovered during C/O. Serviced rig- M/U test plug on btm of 3 1/2" tb- landed test plug and M/U pumpin, SV, IBOP on top. Shell tested BOPE to 2500 psi, working thru leaks. Tested all BOPE to 250 psi low 2500 psi high, as per Sundry, in accordance with Hilcorp and AOGCC requirements- tested with 2 7/8" & 3 1/2" tb. Performed successful koomey draw down test- witnessed waived by Jim Regg/AOGCC by email 1:19 PM today. B/D all test equipment and cleared same from floor. Moved all Tripoint TCP equipment needed to floor- held PJSM w/ involved personnel. M/U 171' of 4 1/2" EHC Idd 5 SPF 60* phase w/ SDP charges - total BHA to RA tag = 313.37'. TIH w/ TCP assy on 3 1/2" IF DP- t/ 2,223'. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Trading Bay St A-07 Monopod Rig 56 1 50-733-20036-00 1 167-046 6/13/18 1 6/26/18 Daiiy:Operations: 3;.., .. 06/24/2018 - Sunday Cont. TIH w/ 4 1/2" TCP assembly to 6331' on 3 1/2" DP, drifting from derrick. R/U e -line. RIH w/ GR/CCL, t/6125', log up, send correlation log to Engineers. POOH & r/d e -line. P/U string 17' as Directed by engineering to put guns on depth, top shot @ 6157', btm shot @ 6328', Drop firing bar, Had good indication guns fired @ 12:06PM, hole took 7 bbls to fill. Perforated f/6157' t/6328' w/ 4 1/2" EHC Idd 5 SPF 60* phase w/ SDP charges, CBU x2, 7 bpm, 1300 psi. Had some gun gas at first btms up with a skim of oil. POOH R/B 20 stands 3 1/2" IF DP- laid down remaining workstring. B/D L/O 1st Tripoint TCP assy- all shots fired. M/U 2nd Tripoint TCP assy: 284' of 4 1/2" EHC Idd 5 SPF 60* phase w/ SDP charges (btm up- 90' Idd- 124' blank- 70' Idd), 15.97' of blank gun, firing head, pup jt, 3- 2 7/8" pups, ported sub, x -over, 3- jts 3 1/2" IF DP, RA sub = 432.69'. TIH w/ 2nd TCP assy to 2,363' (20 stands & 1- single). R/U Pollard ELine in block- RIH w/ GR/CCL and pulled correlation strip from 2,012' to 1,776'- emailed files to Ops Eng- POOH R/D ELine. Directions from Engs were to P/U 26.69'. P/U string, dropped bar and fired guns (perfing 2,050-2,120' & 2,244 - 2,334')- circ 2 btms up thru open choke, taking 10 bbls to get returns at 6 bpm 650 psi- losses — 24 bph- minimual gun gas seen. Slacked down and B/O circ hose- POOH laying down workstring. 40 jts laid down = 1,102' at report time. 06/25/2018 - Monday Cont. POOH I/d 3 1/2" wk string t/ TCP assy @ 432', monitor hole, good. Drill p/u safety valve good. POOH I/d 4 1/2" TCP assy, all guns fired. Clean & clear floor. Secured well and mustered for gas alarm. Prepped rig floor to run ESP assy- setup spools on pipe deck- static losses — 26 bph. M/U Summit 4.56" 240 HP motor w/ gauge & anode, upper & lower tandem, 6 - pump sections w/ intake on 1st, ported pressure sub, discharge and handling jt = 200.90'. Serviced assy and placed clamps as needed. TIH w/ Summit ESP assy on used 2 7/8" 6.5# L-80 8rd tb drifting and torqueing to 2200 FPT (tb previously pulled from this well)- placing clamps as needed- checking cable every 1000'. M/U SPM at 2,638'- CIH to 4,183' and M/U Tripoint hyd set/retrievable pkr (@ 35k shear). M/U packer penetrations. 06/26/2018 - Tuesday Finished w/ pkr penetrator M/U- electrical checked good. M/U and tested pkr vent valve (opened at 3200 psi- tested to 3500 psi). M/U chem inj lines- tested to 2000 psi. RIH w/ 3 jts completion tb and M/U SSSV- function tested same. RIH w/ final 8 jts of completion tb to 4,554'. NOS rep M/U hanger w/ landing jt then plumbed control lines thru same. Summit terminated power cable thru hanger and checked same- good. SOW 50k- landed hanger w/ EOT @ 4,598.70'- ran in LD screws- R/U pump hose on tb and pressured up to 3800 psi setting pkr at 412.87' - held pressure on chart f/ 30 mins. Tied into IA and filled same- pressured up to 1500 psi and held on chart f/ 30 mins- good test on both. Released pressure and B/O landing jt- set BPV. N/D BOP stack breaking each section apart to be moved out and cleaned prior to return to Weatherford. Worked M/V backloading during N/D. Prepped tb head, hanger and control lines to receive tree. Lowered tree to well bay onto tb head- assisted production N/U tree. Bolted on SSV and all hookups- NOS tested hanger void to 500 psi 5 mins 5000 psi 15 mins. M/U lubricator and bled 300 psi off tree- pulled BPV- shell tested tree 5000 psi. Turned well over to production at 0430 hrs. • • STATE OF ALASKA Reviewed B OIL AND GAS CONSERVATION COMMISSION P.I.Supry-1 6/1(06 BOPE Test Report for: TRADING BAY ST A-07 ✓ Comm Contractor/Rig No.: All American Oil 56 ' PTD#: 1670460 - DATE: 6/17/2018 Inspector Bob Noble - Insp Source Operator: HILCORP ALASKA LLC Operator Rep: Harold Soule Rig Rep: Kevin McDowell Inspector Test Pressures: {{ Type Operation: WRKOV Sundry No: l Inspection No: bopRCN180618164419 1 Rams: Annular: Valves: MASP: f Type Test: INIT 318-158 250/2500 250/2500' 250/2500' 394 Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: P/F Visual Alarm Time/Pressure P/F Location Gen.: P• Trip Tank P _ P " System Pressure 3000 - P Housekeeping: P Pit Level Indicators P - P ,Pressure After Closure 1350 " P - PTD On Location P Flow Indicator P " P - 200 PSI Attained 31 P Standing Order Posted P Meth Gas Detector _ P _ P - Full Pressure Attained 205 - P Well Sign P - H2S Gas Detector P - __.P ' Blind Switch Covers: All Stations- P Drl.Rig P ' MS Misc NA NA Nitgn.Bottles(avg): 6 @ 2450 - P_ Hazard Sec. P " ACC Misc 0 NA Misc NA i FLOOR SAFTY VALVES: BOP STACK: CHOKE MANIFOLD: Quantity P/F Quantity Size P/F Quantity P/F , Upper Kelly 1 • P - Stripper 0 none NA No.Valves 16 - P- 3 Lower Kelly 1 P - Annular Preventer 1 - 13 5/8" - P - Manual Chokes 2 P . ', Ball Type 1 - P . #1 Rams 1 2 7/8" x5" VB P Hydraulic Chokes 1 - P I Inside BOP 1 P " #2 Rams 1 - Blinds - P CH Misc 0 NA FSV Misc 0 NA #3 Rams 0 none NA #4 Rams 0 none NA #5 Rams 0 none NA INSIDE REEL VALVES: #6 Rams 0 none NA (Valid for Coil Rigs Only) Choke Ln.Valves 1 - 2 1/16" - P • Quantity P/F HCR Valves 2 - 2 1/16" _p Inside Reel Valves 0 NA Kill Line Valves 2 " 4 dem,2 1/16 P Check Valve 0 none NA BOP Misc 0 none NA Number of Failures: 0 '� Test Results Test Time 6 Remarks: Good test, 2 7/8"and 3 1/2"test joints were tested. SCANNED JUN 2 2 • V OF T7y� �1 !/ 0)P.'� THE STATE s �\I/� Alaska Oil and Gas h�:.'l�►�� OfALASKA Conservation C®llCommission'-s _�� 333 West Seventh Avenue - jg GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 OF Q. Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Stan Golis Operations Manager SC Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Trading Bay Field, Middle Kenai B, C, D, and E Oil Pool, Trading Bay St A-07 Permit to Drill Number: 167-046 Sundry Number: 318-158 Dear Mr. Golis: 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 by4:30 PM the on23rd day following the date of this letter, or the next working day if the 23rd day falls a is on a holiday or weekend. Sincerely, Hollis S. French Chair DATED this R day of April, 2018. RECEIVED STATE OF ALASKA APR 10 20 ALASKA OIL AND GAS CONSERVATION COMMISSION ai'S 4/4/16 1 APPLICATION FOR SUNDRY APPROVALS AOGCC 20 MC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown Suspend ❑ Perforate 0 Other Stimulate ❑ Pull Tubing 0 Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other. ESP/GL Completion 2 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC ' Exploratory ❑ Development 0• 167-046 ' 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic EDService ❑ 6.API Number. Anchorage,AK 99503 50-733-20036-00-00 • 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 93B ' Will planned perforations require a spacing exception? Yes ❑ No 0 / Trading Bay ST A-07 ' 9.Property Designation(Lease Number): 10.Field/Pool(s): E 14 ADL0018731 ' Trading Bay Field/Hemlock Oil,Middle Kenai B,C,Dieil Pools • 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): ' 6,407 . 6,389 . 6,089 $ 6,076 394 psi 6,089 N/A Casing Length Size MD TVD Burst Collapse Structural Conductor , Surface 1,067' 13-3/8" 1,067' 1,067' 3,090 psi 1,540 psi Intermediate Production 4,810' 9-5/8" 4,810' 4,806' 3,950 psi 2,570 psi Liner 1,651' 7" 6,397' 6,380' 7,240 psi 5,410 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 2,874-6,019 • 2,873-6,007 2-7/8" 6.5#/N-80 2,861 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): DLH Packer&Baker SSSV 2,836'(MD)2,835'(TVD)&305'(MD)305'(TVD) 12.Attachments: Proposal Summary 0 Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ Stratigraphic❑ Development 0• Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 5/1/2018 OIL 0 ' WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ 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: Stan W.Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: dmarlowe a@hilcorp.com Contact Phone: (907)283-1329 Authorized Signature: t—.3 L1 Date: e>ii. f 4 c=4 (E. COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. 313� 15,3 Plug Integrity ❑ BOP Test /,Mechanical Integrity CI Test Location Clearance Other: 'k. (2 33-0E) /,o 5;, 46)f (—F:5--f- Post S"� RBDMS APR 1 �� Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ Nod Subsequent Form Required: /6 'j©`1 APPROVED BY Approved by: Lr2aACOMMISSIONER THE COMMISSION Date: il 11 11e, � tc ` / ORIGINAL� Submit Form and �,I' Form 10-403 Revised 4/2017 Approved application is valid for 12 months from the date of approval. Attachments in Duplicate Well Work Prognosis Hilcorp Alaska,LLC Well Name: Monopod A-07 API Number: 50-733-20036-00 Current Status: Oil Producer Leg: N/A Estimated Start Date: May 01, 2018 Rig: Monopod Platform Rig#56 Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 167-046 First Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904(M) Second Call Engineer: Mike Quick (907) 777-8442 (0) (907) 317-2969 (M) Current Bottom Hole Pressure: 681 psi @ 2,873'TVD 0.237 psi/ft(4.56 ppg)2013 ESP Gauge Maximum Expected BHP: 681 psi @ 2,873'TVD 0.237 psi/ft(4.56 ppg)2013 ESP Gauge Maximum Potential Surface Pressure:394 psi Using 0.1 psi/ft gradient per 20AAC 25.280(b)(4) Brief Well Summary: The A-07 is currently completed in the B,C, D,&E sands.The purpose of this work over is to clean-out the well back to original PBTD restoring access to the Hemlock sands.We will then install an ESP to improve drawdown with a backup option of gas-lift. Last Casing Test: 07/11/2013 2,836' 1,500 psig for 30 minutes on chart Procedure: 1. MIRU Monopod Platform Rig#56. 2. Pull Gas Lift valve and circulate hydrocarbon off of well through open pocket. 3. Workover fluid to be FIW with LCM as needed to balance well, BOP's will be closed as needed to circulate the well. 4. ND Wellhead, NU BOP and test to 250psi low/2,500psi high. (Note: Notify AOGCC 24 hours in advance of test to allow them to witness test). 5. Monitor well to ensure it is static. 6. POOH with completion. 7. Cleanout the well to original PBTD of±6,350'.Circulate clean. POOH. 8. PU TCP guns, RIH,Correlate, perforate per program.Circulate out any gun gas, ensure well is static, POOH. 9. PU and RIH with new completion assembly consisting of the ESP, Gas Lift Mandrels, High-set Packer w/Vent Valve,&SSSV. 10. Set Packer at±300'. Pressure test to 1,500 psig and chart for 30 minutes. 11. ND BOP, NU wellhead and test. 12. Turn well over to production. 13. Conduct SVS testing per AOGCC regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Current 4. Wellhead Schematic Proposed 5. BOP Drawing 6. Fluid Flow Diagrams 7. RWO Sundry Revision Change Form Trading Bay Unit 11 SCHEMATIC Monopod Well#A-07 API#50-733-20036-00 PTD: 167-046 Last Completed:07/11/2013 RKB to TBG Hngr=38.23' CASING DETAIL KB to MSL=101', MSL to Mudline 66' SIZE WT I GRADE 1 CONN ID TOP BTM. 20" Conductor Pile Surface '-264' 1 13-3/8" 61 J-55 Butt 12.515 Surface 1,067' .... 2 9-5/8" 40 1-55 Butt 8.835 Surface 4,810' 7" 26 J-55 Butt 6.276 4,746' 6,397' TUBING DETAIL 2-7/8" I 6.5 I N-80 j 8 round EUE I 2.441 I Surf I 2,861' A 1 JEWELRY DETAIL No Depth Depth ID OD Item (MD) (TVD) TOC @ 1 41.00' 41.00' 2-7/8"Hanger Assy. 1,530' 2 305' 305' 2.313 4.970 Baker SSSV' 3 2,101' 2,101' 2.441 4.750 GLV h' 4 2,656' 2,655' 2.441 4.750 GLV 5 2,826' 2,825' 2.441 4..480 Chemical Injection Mandrel 6 2,836' 2,835' 4.000 8.250 DIM Hydraulic set Packer(40k Shear) 7 2,856' 2,855' 2.313 3.680 X-Nipple 8 2,861' 2,860' 2.441 3.690 WLEG DV col 9 6,089' 6,076' EZ Drill Cement Retainer IA 4 2.977 10 6,099' 6,086' Baker 5-2 Packer with DR Packer Plug -) 3 PERFORATION DATA Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt SPF Date Status 2,874' 2,906' 2,873' 2,906' 32' 5 5/11/2013 Open 2,875' 2,907' 2,874' 2,906' 22' 4 9/7/1988 Open 31-5 BZN 2,882' 2,896' 2,581' 2,895' 14' 4 8/17/1970 Open 2,920' 2947' 2,919' 2946' 27' 5 5/11/2013 Open 2923' 2,947' 2922' 2,946' 24' 4 9/8/1988 Open 2,928' 2,944' 2,927' 2,943' 16' 4 8/17/1970 Open 4 2,997' 3,076' 2,996' 3,075' 79' 4 9/9/1988 Open 5 33-6 BZN 2,999' 3,077' 2,998' 3,076' 78' 5 5/11/2013 Open 3,044' 3,076' 3,043' 3,075' 32' 4 8/17/1970 Open 6 - 3,193' 3,242' 3,192' 3,241' 49' 5 5/11/2013 Open f 7 3,196' 3,208' 3,195' 3,207' 12' 4 8/17/1970 Open _ 3,196' 3,240' 3,195' 3,239' 44' 4 9/10/1988 Open 8 = 3,214' 3,240' 3,231' 3,239' 26' 4 8/17/1970 Open 41-3 BZN 3,282' 3,433' 3,281' 3,432' 151' 5 5/11/2013 Open 3,283' 3,435' 3,282' 3,434' 52' 4 9/11/1988 Open BZN 3,290' 3,434' 3,289' 3,433' 144' 4 8/17/1970 Open _ 3,300' 3,320' 3,299' 3,319' 20' 4 9/10/1970 Cmt Szqd 3,795' 3,960' 3,793' 3,958' 65' 4 9/12/1988 Open 3,803' 3,959' 3,801' 3,957' 156' 5 5/11/2013 Open 44-7 BZN 3,808' 3,850' 3,807' 3,848' 42' 4 8/17/1970 Open 3,820' 3,840' 3,818' 3,838' 20' 4 9/10/1967 Cmt Szqd 3,858' 3,956' 3,856' 3,954' 98' 4 8/17/1970 Open C-2 4,037' 4,097' 4,035' 4,095' 60' 5 5/11/2013 Open C-3 4,127' 4,224' 4,125' 4,221' 97' 5 5/11/2013 Open 44-7 BZN 4,125' 4,225' 4,123' 4,222' 100' 4 9/15/1967 Cmt Szqd 4,140' 4,160' 4,138' 4,157' 20' 4 9/10/1967 Cmt Szqd C,CZN CZNS6 4,267' 4,335' 4,264' 4,332' 68' 5 5/11/2013 Open C4 4,344' 4,371' 4,341' 4,368' 27' 5 5/11/2013 Open ,if = C5 4,429' 4,479' 4,426' 4,476' 50' 5 5/11/2013 Open C-6 4,600' 4,639' 4,595' 4,635' 39' 5 5/11/2013 Open 44-7 BZN 4,605' 4,625' 4,601' 4,621' 20' 4 9/10/1967 Cmt Szqd 41 - CZNS7 4,670' 4,700' 4,666' 4,696' 30' 5 5/11/2013 Open 4,720' 4,740' 4,716' 4,736' 20' 5 5/11/2013 Open C7 4,760' 4,781' 4,756' 4,777' 21' 5 5/11/2013 Open c. 49-4 CZN 4,807' 4,829' 4,803' 4,825' 22' 5 5/11/2013 Open 50-0 CZN 4,869' 4,879' 4,865' 4,875' 10' 5 5/11/2013 Open 50-3 CZN 4,897' 4,927' 4,893' 4,923' 30' 5 5/11/2013 Open F•, C,CZN CZNS2 4,952' 4,957' 4,989' 4,953' 5' 5 5/11/2013 Open 50-6CZN 4,992' 5,021' 4,988' 5,017' 29' 5 5/11/2013 Open $* 1==11- CZNS9 5,102' 5,122' 5,097' 5,117' 20' 5 5/11/2013 Open =1-DZN 51-6 CZN 5,122' 5,156' 5,117' 5,151' 34' 5 5/11/2013 Open TI. 51-9 CZN 5,170' 5,198' 5,165' 5,193' 28' 5 5/11/2013 Open w. 53-0 DZN 5,260' 5,288' 5,254' 5,282' 28' 5 5/11/2013 Open ' DZNS2 5,328' 5,335' 5,322' 5,329' 7' 5 5/11/2013 Open 4,. 5' _ EZN 53-8 DZN 5,360' 5,393' 5,354' 5,387' 33' 5 5/11/2013 Open ; 9 = 54-5 DZN 5,424' 5,458' 5,417' 5,451' 34' 5 5/11/2013 Open P** -,. - �.w.......... 54-9 DZN 5,492' 5,509' 5,485' 5,502' 17' 5 5/11/2013 Open 30 55-7 DZN 5,542' 5,560' 5,534' 5,552' 18' 5 5/11/2013 Open 56-1 DZN 5,587' 5,670' 5,579' 5,661' 83' 5 5/11/2013 Open 57-2 DZN 5,700' 5,744' 5,691' 5,735' 74' 5 5/11/2013 Open PBTD=6,089'(original 6,350') 58-1EZN 5,798' 5,817' 5,788' 5,807' 19' 5 5/11/2013 Open TD=6,407' 5,823' 5,837' 5,813' 5,827' 14' 5 5/11/2013 Open 58-7 EZN 5,860' 5,875' 5,850' 5,864' 15' 5 5/11/2013 Open ANGLE thru INTERVAL=3.2° 5,882' 5,948' 5,871' 5,937' 66' 5 5/11/2013 Open 60-0 EZN 5,982' 6,019' 5,970' 6,007' 37' 5 5/11/2013 Open Hemlock 6,160' 6,205' 6,146' 6,191' 45' 8 10/02&05/1967 Isolated Hemlock 6,225' 6,330' 6,210' 6,314' 105' 8 10/02&05/1967 Isolated Updated by: JLL 08/12/13 Trading Bay Unit PROPOSED Well#A-07 API#50-733-20036-00 PTD: 167-046 Last Completed: FUTURE RKB to TBG Hngr=38.23' KB to MSL=101', MSL to Mudline 66' CASING DETAIL tr SIZE WT GRADE I CONN ID TOP BTM. t 20" Conductor Pile Surface `,2067' 64' 13-3/S" 61 _ 1-55 Butt 12.515 Surface 1 9-5/8" 40 1-55 Butt 8.835 Surface 4,810' 7" 26 1-55 Butt 6.276 4,746' 6,397' L ; TUBING DETAIL 2-7/8" I 6.5 I N-80 I 8 round EUE I 2.441 I Surf I ±4,465' JEWELRY DETAIL , , Depth Depth No (MD) (TVD) ID OD Item TOC @ isso 41.00' 41.00' 2-7/8"Hanger Assy. 1 ±300' ±300' SSSV 2 ±415' ±415' ESP Packer w/Vent Valve '; - 3 ±1,950' ±1,950' GLM d'51 3 4 ±4,435' ±4,432' X Nipple ±4,465' ±4,462' Discharge,Bolt-On 0 Pump 5 Intake DV Collar Seals 1 @ 2,977' : Motor ±4,590' ±4,586' Gauge/Anode/Centralizer PERFORATION DATA Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt SPF Date Status „ BZN ±2,050' ±2,120' ±2,050' ±2,120' ±70' 5 FUTURE PROPOSED • BZN ±2,244' ±2,334' ±2,244' ±2,334' ±90' S FUTURE PROPOSED • 2,874' 2,906' 2,873' 2,906' 32' 5 5/11/2013 Open i 2,875' 2,907' 2,874' 2,906' 22' 4 9/7/1988 Open 31-8 BZN 2,882' 2,896' 2,881' 2,895' 14' 4 8/17/1970 Open 2,920' 2,947' 2,919' 2,946' 27' 5 5/11/2013 Open 2,923' 2,947' 2,922' 2,946' 24' 4 9/8/1988 Open 2,928' 2,944' 2,927' 2,943' 16' 4 8/17/1970 Open } 2,997' 3,076' 2,996' 3,075' 79' 4 9/9/1988 Open ;; = 33-6 BZN 2,999' 3,077' 2,998' 3,076' 78' 5 5/11/2013 Open 3,044' 3,076' 3,043' 3,075' 32' 4 8/17/1970 Open 3,193' 3,242' 3,192' 3,241' 49' S 5/11/2013 Open BZN 3,196' 3,208' 3,195' 3,207' 12' 4 8/17/1970 Open 3,196' 3,240' 3,195' 3,239' 44' 4 9/10/1988 Open - 3,214' 3,240' 3,231' 3,239' 26' 4 8/17/1970 Open 41-3 BZN 4 .1.74- 3,282' 3,433' 3,281' 3,432' 151' 5 5/11/2013 Open 3,283' 3,435' 3,282' 3,434' 52' 4 9/11/1988 Open 3,290' 3,434' 3,289' 3,433' 144' 4 8/17/1970 Open -- - 3,300' 3,320' 3,299' 3,319' 20' 4 9/10/1970 Cmt Szqd 3,795' 3,960' 3,793' 3,958' 65' 4 9/12/1988 Open 3,803' 3,959' 3,801' 3,957' 156' 5 5/11/2013 Open 44-7 BZN 3,808' 3,850' 3,807' 3,848' 42' 4 8/17/1970 Open . 3,820' 3,840' 3,818' 3,838' 20' 4 9/10/1967 Cmt Szqd - fl 3,858' 3,956' 3,856' 3,954' 98' 4 8/17/1970 Open 1/ I:=1 5 _ C,CZN C-2 4,037' 4,097' 4,035' 4,095' 60' 5 5/11/2013 Open C-3 4,127' 4,224' 4,125' 4,221' 97' 5 5/11/2013 Open 44-7 BZN 4,125' 4,225' 4,123' 4,222' 100' 4 9/15/1967 Cmt Szqd ,E 4,140' 4,160' 4,138' 4,157' 20' 4 9/10/1967 Cmt Szqd C2N56 4,267' 4,335' 4,264' 4,332' 68' S 5/11/2013 Open diE 7.-2E7 C4 4,344' 4,371' 4,341' 4,368' 27' 5 5/11/2013 Open CS 4,429' 4,479' 4,426' 4,476' 50' S 5/11/2013 Open C-6 4,600' 4,639' 4,595' 4,635' 39' S 5/11/2013 Open 44-7 BZN 4,605' 4,625' 4,601' 4,621' 20' 4 9/10/1967 Cmt Szqd ® CZNS7 4,670' 4,700' 4,666' 4,696' 30' 5 5/11/2013 Open 4,720' 4,740' 4,716' 4,736' 20' 5 5/11/2013 Open C,CZN C7 4,760' 4,781' 4,756' 4,777' 21' S 5/11/2013 Open 49-4 CZN 4,807' 4,829' 4,803' 4,825' 22' 5 5/11/2013 Open 50-0 CZN 4,869' 4,879' 4,865' 4,875' 10' 5 5/11/2013 Open i": _1-DZN 50-3 CZN 4,897' 4,927' 4,893' 4,923' 30' S 5/11/2013 Open _ CZNS2 4,952' 4,957' 4,989' 4,953' 5' 5 5/11/2013 Open 50-6CZN 4,992' 5,021' 4,988' 5,017' 29' 5 5/11/2013 Open 4; CZNS9 5,102' 5,122' 5,097' 5,117' 20' 5 5/11/2013 Open yEZN 51-6CZN 5,122' 5,156' 5,117' 5,151' 34' 5 5/11/2013 Open # = 51-9 CZN 5,170' 5,198' 5,165' 5,193' 28' 5 5/11/2013 Open V" 53-0 DZN 5,260' 5,288' 5,254' 5,282' 28' 5 5/11/2013 Open 1 HEM DZNS2 5,328' 5,335' 5,322' 5,329' 7' 5 5/11/2013 Open 53-8 DZN 5,360' 5,393' 5,354' 5,387' 33' S 5/11/2013 Open 54-5 DZN 5,424' 5,458' 5,417' 5,451' 34' 5 5/11/2013 Open PBTD=6,089' (original 6,350') 54-9 DZN 5,492' 5,509' 5,485' 5,502' 17' 5 5/11/2013 Open TD=6,407' 55-7DZN 5,542' 5,560' 5,534' 5,552' 18' 5 5/11/2013 Open 56-1 DZN 5,587' 5,670' 5,579' 5,661' 83' 5 5/11/2013 Open ANGLE thru INTERVAL=3.2° 57-2DZN 5,700' 5,744' 5,691' 5,735' 74' 5 5/11/2013 Open 58-1 EZN 5,798' 5,817' 5,788' 5,807' 19' 5 5/11/2013 Open 5,823' 5,837' 5,813' 5,827' 14' 5 5/11/2013 Open 58-7 EZN 5,860' 5,875' 5,850' 5,864' 15' 5 5/11/2013 Open 5,882' 5,948' 5,871' 5,937' 66' S 5/11/2013 Open 60-0 EZN 5,982' 6,019' 5,970' 6,007' 37' 5 5/11/2013 Open HEMLOCK ±6,157' ±6,328' ±6,143' ±6,312' ±171' 5 FUTURE PROPOSED • Hemlock 6,160' 6,205' 6,146' 6,191' 45' 8 10/02&05/1967 Open Hemlock 6,225' 6,330' 6,210' 6,314' 105' 8 10/02&05/1967 Open Updated by: ILL 04/09/18 Monopod Platform A-07 Current 08/06/2013 Hikurp,1}xi1ka,LU Monopod Platform Tubing hanger,SME-CL,11 X A-7 3 Y EUE lift and susp,w/3" 13 3/8 X 9 5/8 X 2 7/8 Type H BPV profile,2-3/8 CCL,Alloy material BHTA,Bowen,3 1/8 5M X 2.5 Bowen quick union mit ni n n Valve,Swab,WKM-M, 3 1/8 5M FE,HWO,DD trim :00. mer, ® Valve,Wing,WKM-M,3 1/8 5M FE,w/15"OMNI Valve,Wing,WKM-M,2 1/16 aft 11 '" operator,DD trim 5M FE,HWO,DD trim - ‘; 0 }111 11 II QOr Valve,Master,WKM-M, rO 3 1/8 5M FE,HWO,DD trim o 0 1:".5/0 `' uI 10 u, Iii Valve,Master,WKM-M, 3 1/8 5M FE,HWO,DD trim C , IllNW I., 4 'u _I�ice' ``II_Ili._ Tubing head,S-8,13 5/8 3M �I x 11 5M,w/2-2 1/16 5M SSO,w/BG bottom 11011 - w/1-21/165M WKM-M L valves irlt yog 11111 :I: Casing head, Shaffer KD, I 1m1 13 5/8 3M X 13 3/8 SOW,w/2-2" wll �1Mr al 10-1- LPO r II Monopod Platform A-7 Proposed 04/05/2018 I Hilrnrp Aturka,LU. Monopod Platform Tubing hanger,Seaboard- A-7 ESP-EN,11 X 2 7/8 EUE lift 133/8X95/8X27/8 and Susp w/2%Type H BPV profile,4-'A CCL,Prepped for BIW penetrator BHTA,Bowen,3 1/8 5M X 2.5 Bowen quick union m V ,u I. Valve,Swab,WKM-M, "` ", 3 1/8 5M FE,HWO,DD trim Valve,Wing,WKM-M,3 1/8 Valve,Wing,WKM-M,2 1/16 5M FE,w/15"OMNI .8. ni 5M FE,HWO,DD trim operator,DD trim n \ - - o - , - 111111114111 OrP Valve,Master,WKM-M, '. 1 3 1/8 5M FE,HWO,DD trim ui1n, DSA,3 1/8 5M X 2 9/16 5M L I. III mu Adapter,Seaboard-ESP, 11 5M rotating flange x 2 9/16 5M rotating flange, w/411/16 pocket,w/4-'''A CCL,ported for BIW lel — is_ penetrator Tubing head,5-8,13 5/8 3M a l si 4I ii1u!�- x115M,w/2-21/165M SSO,w/BG bottom 1 i ' w/1-2 1/16 5M WKM-M • F.valves =1 © f', litm � i o � I 1 - O _ 1®1 I. Casing head, 1 Shaffer-KD, • 1--1 . ) 1 1 135/83MX 9 13 3/8 SOW,w/2-2" Irk NM[ 1 1 ISI LPO, Monopod Platform 11 2018 BOP Stack 11.1..91 kla4...i.1.1A Bottom of air boot flange Rig Floor I 5'below rig Floor 16" Pipe III lit f lIII!din III 4.54' • Hydril GK 13 5/8-5000 Ill Ell III Ill Ill III III III III III 26.25' �L CIW U 27/8x Svariable rams 4.67' EOM =— 135/85M - - =lied LIP Ili III til Iii fit 2 1/16 5M manual and 2 1/16 SM manual and 2 26 "CR HCR 'r kill side Ir, 1 I 1 :'1i I 11 111 r, Ir 1141114" III tit , III III III I11 III Dell deck y Riser 135/85M FE 13 5/8 5M FE 14.20' LUNY Spacer spool 135/85M FE 41' 11 5M Ifr fel,rai n Monopod Rig#56 BOP Test Procedure Hilcorp Alaska,LLC Attachment#1 Attachment #1 Hilcorp Alaska LLC. BOP Test Procedure: Monopod Rig# 56 WO Program — Oil Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with FIW to kill well. • Note: Fluid level will fall to a depth that balances with reservoir pressure. 3) Circulate down tubing taking returns to production off of the annulus and sweep gas and oil to production until returns are clean. 4) Confirm that well is static shooting fluid levels if necessary right before ND/NU. Initial Test(i.e.Tubing Hanger is in the Wellhead) If BPV profile is good 1) Set BPV. ND Tree. NU BOP. 2) MU landing joint. Pull BPV. Set 2-way check in hanger. 3) Space out test joint so end of tubing (EOT) is just above the blind rams. 4) Set slips, mark same. Test per standard Monopod Rig#56 BOPE test procedure. If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on. Profile and/or landing threads must be prepped while tree is off.Worst Case: BPV profile and landing threads are bad. 1) Attempt to set BPV through tree. If unsuccessful, establish static fluid level, shoot fluid level with an echometer gun or tag with slick line to establish static fluid level if necessary. 2) Once the fluid level is established to be static, notify Hilcorp Anchorage Operations Engineer. 3) Proceed as follows: a) ND tree with no BPV b) Inspect and prepare BPV profile to accept a 2-way valve, or prepare lift-threads to accept landing joint to hold pressure. If well is a producer and the culprit is scale, attempt to clean profile with Muriatic acid and a wire brush or wheel. c) Set 2-way check valve by hand, or MU landing(test)joint to lift-threads d) Plug penetrations in hanger. For ESP wells- Ensure that cap is on cable penetrator e) NU BOP. Test BOPE per standard procedure. 4) If both set of threads appear to be bad and unable to hold a pressure test and/or a penetrator leaks, notify Operations Engineer(Hilcorp), Mr. Guy Schwartz(AOGCC-guy.schwartz@alaska.gov) and Mr. Jim Regg(AOGCC-jim.regg@alaska.gov)via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness.As outlined and approved in the sundry, proceed as follows: a) Nipple Up BOPE Monopod Rig#56 BOP Test Procedure Hilcorp Alaska,LLC Attachment#1 b) With stack out of the test path, test choke manifold per standard procedure c) Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d) Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e) Once the BOP ram and annular tests are completed,test the remainder of the system following the normal test procedure (floor valves,gas detection, etc.) f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile /penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 5) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 6) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re-land hanger(or test plug) in tubing head. Test BOPE per standard procedure. Note: BOPE high test pressures will be determined upon Approved Sundry.Test joint sizes will be determined upon well work. Subsequent Tests(i.e.Test Plug can be set in the Tubing-head) 1) Remove Wear bushing. a) Use inverted test plug to pull wear busing. MU to 1 jt.of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same, and RIH on 1 joint of tubing. Install a closed TIW or lower Kelly valve in top of test joint. 3) Break joint off test plug and pull up to space the bottom of tool joint above blind rams. 4) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE(after 2-way check or test plug is set) 1) Fill stack with rig pump and install chart recorder on the stack side of the pump manifold. 2) Note: When testing, pressure up with pump to desired pressure,close valve on pump manifold to trap pressure and read same with chart recorder. 3) Referencing the attached schematics test rams and valves as follows. a) Close C-2 (inside gate valve on choke side of mud cross) and close the annular preventer. Pressure test to 200 psi for 5 minutes and 1,500 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open annular. b) Close Pipe Rams. Test to 200 psi for 5 minutes and 3,000 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open pipe rams. c) Test Dual Rams. If the well has dual tubing, and dual rams are installed in the stack, test the dual rams by picking up two test joints with dual elevators and lowering them into stack and position 11 Monopod Rig#56 BOP Test Procedure Hilcurp Alaska,LLC Attachment#1 them properly in the dual rams. Close rams. Test to 200 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open rams. d) Open C-2. Flow through the choke manifold and purge air. Test the choke manifold starting with the outer most valves,to 250 psi low and 3,000 psi high,for 5 minutes each, as follows: (Valve numbers are in reference to Diagram B) i) Valves 1, 2, 10. After test, open same. ii) Valves, 3,4, 9. After test, open valves 3 &4. Leave 9 closed. iii) Valves 5, 6, 9. After test,open valves 5&6, leave 9 closed. iv) Valves, 7, 8, 9. After test, open all valves. e) Close C-3. This is the HCR (the hydraulic controlled remote)valve just outside C-1 on choke side of mud cross. Test to 250 psi low and 3,000 psi high. After test, open HCR, close C-1. f) Blind Rams. Make sure test joint is above the blind rams. Close blind rams. Test to 200 psi Low for 5 minutes and 3,000 psi High for 5 minutes. Bleed down pressure. g) Bleed off all pressure. Line up pumps to pump down tubing. h) Test C-1, C-2, and C-4 on the kill (pump-in)side by pressuring up on tubing.Test to 200 psi Low for 5 minutes and 3,000 psi High for 5 minutes. i) Test floor valves TIW (or Lower Kelly Valve) and IBOP. STANDARD TEST PROCEDURE OF CLOSING UNIT(ACCUMULATOR) 1) This is a test of stored energy. Shut off all power to electric and pneumatic pumps. 2) Record "Accumulator Pressure". It should be+/-3,000 psi. 3) Close Annular Preventer,the Pipe Rams, and HCR. Close 2nd set of pipe rams if installed (e.g. dual pipe rams). Open the lower pipe rams to simulate the closing volume on the blinds. 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (i.e. Report might read "10 bottles at 2,150 psi"). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre-charge pressure of 1,000 psi). 7) Turn on the pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually+/-30 seconds. 8) Once 200 psi pressure build is reached,turn on the pneumatic pumps and record the time it takes for the pumps to automatically shut-off after the pressure to builds back to original pressure (+/-3,000 psi). Note: Make sure the electric pump is turned to "Auto", not "Manual" so the pumps will kick-off automatically. 9) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 10) Fill out AOGCC report. FINAL STEP, FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves,for correct operating position II Monopod Rig#56 BOP Test Procedure Hilcorp Alaska,LLCAttachment#1 3) Fill out the AOGCC BOPE Test Form (10-424) in Excel Format and e-mail to AOGCC and Juanita Lovett. Document both the rolling test and the follow up tests. a . 35 V 44— ► °w I < I D. 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STATE OF ALASKA ALA.OIL AND GAS CONSERVATION COMMI ION AUG 1 2 2013 REPORT OF SUNDRY WELL OPERATIONS , , 1.Operations Abandon ❑ Repair Well ❑ Plug Perforations ❑ Perforate❑ Other O Gas Lift Completion Performed: Alter Casing ❑ Pull Tubing El Stimulate-Frac ❑ Waiver❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development. 12 Exploratory❑ 167-046 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service❑ 6.API Number: Anchorage,AK 99503 50-733-20036-00 • 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0018731 Trading Bay ST A-07 • 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): Trading Bay Field/Hemlock Oil,Middle Kenai B Oil,Middle Kenai C Oil,Middle Kenai D,Oil 11.Present Well Condition Summary: Total Depth measured 6,407 feet Plugs measured 6,069(cement Ret) feet true vertical 6,389 feet Junk measured N/A feet Effective Depth measured 6,089 feet Packer measured 2,836' feet true vertical 6,076 feet true vertical 2,835' feet Casing Length Size MD ND Burst Collapse Structural Conductor Surface 1,067' 13-3/8" 1,067' 1,067' 3,090 psi 1,540 psi Intermediate Production 4,810' 9-5/8" 4,810' 4,806' 3,950 psi 2,570 psi Liner 1,651' 7" 6,397' 6,380' 7,240 psi 5,410 psi Perforation depth Measured depth See Schematic feet swat) LI". 'I . L.t '" True Vertical depth See Schematic feet ��lIMM�� Tubing(size,grade,measured and true vertical depth) 2-7/8" 6.5#/N-80 2,861'(MD) 2,860'(ND) Packers and SSSV(type,measured and true vertical depth) DLH Packer 2,836'(MD)2,835'(TVD) Baker SSSV 305'(MD) 305'(ND) 12.Stimulation or cement squeeze summary: Intervals treated(measured): Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 423 101 6 610 100 Subsequent to operation: 1085 639 21 888 110 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run Exploratory❑ Development El • Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil El. Gas ❑ WDSPL❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 313-335 ° Contact Ted Kramer Email tkramer(c�hilcorp.com Printed Name Ted Kramer Title Sr.Operations Engineer Signature ,ate Phone (907)777-8420 Date 8/12/2013 t' y2/•i3 FiBrM AU620Z0f5,% Form 10-404 Revised 10/2012 /9;� 7K Submit Original Only • • • Trading Bay Unit SCHEMATIC Monopod Well #A-7 API# 50-733-20036-00 Completed 07/11/13 RKB to TBG Hngr=38.23' CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. i 1 --. 1 13-3/8" 61 K-55 Butt 12.515 Surf. 1067' 2 9-5/8" 40.0 K-55 Butt 8.835 Surf 4810' 7" 26 N-80 Butt 6.276 4746' 6397' Tubing: 2-7/8" 6.56 N-80 2.441 Surf 2861' JEWELRY DETAIL No Depth Item 1 41' 2-7/8"Hanger Assy. 2 305' Baker SSSV 3 2,101' GLV 4 2,656' GLV 5 2,826' Chemical Injection Mandrel 6 2,836' DLH Packer 7 2,856' X-Nipple 8 2,861' WLEG ■ 9 6,089' EZ Drill Cement Retainer 7 3 PERFORATION DATA Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt SPF Date Status 2,874' 2,906' 2,873' 2,906' 32' 5 5/11/2013 Open 2,875' 2,907' 2,874' 2,906' 22' 4 9/7/1988 Open 31-8 BZN 2,882' 2,896' 2,881' 2,895' 14' 4 8/17/1970 Open 2,920' 2,947' 2,919' 2,946' 27' 5 5/11/2013 Open / 2,923' 2,947' 2,922' 2,946' 24' 4 9/8/1988 Open .... 4 '/ 2,928' 2,944' 2,927' 2,943' 16' 4 8/17/1970 Open 2,997' 3,076' 2,996' 3,075' 79' 4 9/9/1988 Open 5 33-6 BZN 2,999' 3,077' 2,998' 3,076' 78' 5 5/11/2013 Open -11 3,044' 3,076' 3,043' 3,075' 32' 4 8/17/1970 Open 6 3,193' 3,242' 3,192' 3,241' 49' S 5/11/2013 Open X 7 3,196' 3,208' 3,195' 3,207' 12' 4 8/17/1970 Open -=.--- 3,196' 3,240' 3,195' 3,239' 44' 4 9/10/1988 Open 8 3,214' 3,240' 3,231' 3,239' 26' 4 8/17/1970 Open 41-3 BZN 3,282' 3,433' 3,281' 3,432' 151' 5 5/11/2013 Open 3,283' 3,435' 3,282' 3,434' 52' 4 9/11/1988 Open = BZN 3,290' 3,434' 3,289' 3,433' 144' 4 8/17/1970 Open = 3,300' 3,320' 3,299' 3,319' 20' 4 9/10/1970 Cmt Szqd = 3,795' 3,960' 3,793' 3,958' 65' 4 9/12/1988 Open = 3,803' 3,959' 3,801' 3,957' 156' 5 5/11/2013 Open 44-7 BZN 3,808' 3,850' 3,807' 3,848' 42' 4 8/17/1970 Open 3,820' 3,840' 3,818' 3,838' 20' 4 9/10/1967 Cmt Szqd 3,858' 3,956' 3,856' 3,954' 98' 4 8/17/1970 Open C-2 4,037' 4,097' 4,035' 4,095' 60' 5 5/11/2013 Open C-3 4,127' 4,224' 4,125' 4,221' 97' 5 5/11/2013 Open 44-7 BZN 4,125' 4,225' 4,123' 4,222' 100' 4 9/15/1967 Cmt Szqd 4,140' 4,160' 4,138' 4,157' 20' 4 9/10/1967 Cmt Szqd CZNS6 4,267' 4,335' 4,264' 4,332' 68' 5 5/11/2013 Open -- C,CZN C4 4,344' 4,371' 4,341' 4,368' 27' 5 5/11/2013 Open C5 4,429' 4,479' 4,426' 4,476' 50' 5 5/11/2013 Open C-6 4,600' 4,639' 4,595' 4,635' 39' 5 5/11/2013 Open 7 C _ 44-7 BZN 4,605' 4,625' 4,601' 4,621' 20' 4 9/10/1967 Cmt Szqd �.k?t = CZNS7 4,670' 4,700' 4,666' 4,696' 30' 5 5/11/2013 Open ik 4,720' 4,740' 4,716' 4,736' 20' 5 5/11/2013 Open C7 4,760' 4,781' 4,756' 4,777' 21' 5 5/11/2013 Open 49-4CZN 4,807' 4,829' 4,803' 4,825' 22' 5 5/11/2013 Open n 50-0 CZN 4,869' 4,879' 4,865' 4,875' 10' 5 5/11/2013 Open Zy 50-3 CZN 4,897' 4,927' 4,893' 4,923' 30' 5 5/11/2013 Open Q [� CZNS2 4,952' 4,957' 4,989' 4,953' 5' 5 5/11/2013 Open C,CZN 50-6CZN 4,992' 5,021' 4,988' 5,017' 29' 5 5/11/2013 Open C2NS9 5,102' 5,122' 5,097' 5,117' 20' 5 5/11/2013 Open 51-6CZN 5,122' 5,156' 5,117' 5,151' 34' 5 5/11/2013 Open _1-DZN 51-9 CZN 5,170' 5,198' 5,165' 5,193' 28' 5 5/11/2013 Open 53-0 DZN 5,260' 5,288' 5,254' 5,282' 28' 5 5/11/2013 Open DZNS2 5,328' 5,335' 5,322' 5,329' 7' 5 5/11/2013 Open 53-8 DZN 5,360' 5,393' 5,354' 5,387' 33' 5 5/11/2013 Open EZN 54-5 DZN 5,424' 5,458' 5,417' 5,451' 34' S 5/11/2013 Open 9 - 54-9 DZN 5,492' 5,509' 5,485' 5,502' 17' 5 5/11/2013 Open -...„.... ..- 55-7 DZN 5,542' 5,560' 5,534' 5,552' 18' 5 5/11/2013 Open _.......• mi... 56-1 DZN 5,587' 5,670' 5,579' 5,661' 83' 5 5/11/2013 Open ■ 57-2 DZN 5,700' 5,744' 5,691' 5,735' 74' 5 5/11/2013 S 5/11/2013 Open 58-1 EZN 5,798' 5,817' 5,788' 5,807' 19' Open KB ELEV=101' 5,823' 5,837' 5,813' 5,827' 14' 5 5/11/2013 Open PBTD=6,089' TD=6,407' 58-7 EZN 5,860' 5,875' 5,850' 5,864' 15' 5 5/11/2013 Open 5,882' 5,948' 5,871' 5,937' 66' 5 5/11/2013 Open ANGLE thru INTERVAL=3.2° 60-0 EZN 5,982' 6,019' 5,970' 6,007' 37' 5 5/11/2013 Open Updated by: 111 08/12/13 • • Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date A-07 50-733-20036-00 167-046 7/5/13 7/11/13 Daily Operations: 7/5/2013 - Friday Rig up Pollard slickline unit, Pollard hands arrived on platform at 1040 hrs. Rig up lubricator on tree,Test lubricator to 1,500psi,[TBG & ann 1100] Run#1-Run 2.22 BO Shifting Tool. Couldnt get past 306' which is the X profile at the SSSV. POH and tool was covered with paraffin. Run #2 -Run 2.27 J Latch to 68'. POH covered with paraffin. Run#3 - Run 2.23 rin to 35'. Press on ann 1,100 psi,tbg 500 psi. Rig up to pump diesel down the tbg. Pump 10 bbls do tbg at a final gauge ring p g p g p p p pressure of 1,200psi and let it set 1 hr. Mixing 3& KCL. Run#4- Run brush, couldnt get past 70'. POH. Run#5-PU another sinker bar and a 1.84 gauge ring and RIH to 306'. Set down solid. POH-GR sat down solid at 306' and flared edges of GR. Run#5, 2" LIB-sat down at 306'. POOH. LIB had impression of flapper. RU hyd hand pump to CL. Pressure CL to 4,800psi at 2,000psi a pres flicker is noticed. Dump CL press several times to open vlv. Run#6 with 1-1/2" slick TS-still set down solid at 306'. RU to pump gas down tbg to equalize press across SV, max press with GL—900psi. Run#7 1-1/2" slick TS set tool wt on flapper at 306'. SV not open. RU and pump WF down tbg to equalize press. At^'1,750psi started loosing tbg press down to 850 psi. 50 psi increase in CL to 5,050psi. Production flow chart shows sharp increase in flow. Run#8 same slick TS-sat down at 306'. RU to flow well -open well monitor flow to stabilize-after 2 hrs FTP at 200 gas cut fluid at sample port. Run#9 same slick TS able to go past SS at 306'. Continue in hole sliding sleeve at 3,760'. Run# 10 with 1 latch shifting tool. Work tool at 3,771' kinda spongy. No pressure change in tbg 1,000psi or annuls 989psi, no good indication of shifting. Was able to run thru SS sevearal times without setting down indicating sleeve shifted. POOH. J latch packed with paraffin not allowing tool to work. MU wireline brush, stab on to well. Bleed tbg down to see if any drop on tbg. Lost 50psi on tbg to 1,000psi. 40 psi on annulus to 860psi. Run# 11-with wireline brush while pumping diesel. Work thru SSSV at 306'. Work thru tight spots at 2,394' and 2,833' make several brush runs thru SS at 3,760' until free. POOH brush tight areas and SSSV. Pumped 57 bbls diesel. LD wireline brush. Pick up 142 BO shifting tool. Run# 12 - No problem RIH. Locate and work SS. Start tbg 875psi-annulus 900psi. Tool indication sleeve opened. 10psi inc on tbg- 0 inc on annulus. Run thru sleeve several times no latch up. POOH. 75psi inc on tbg-40 psi loss on annulus in 30 mins. Final tbg 950 psi, annulus 860 psi. Total 3% KCL mixed 360 bbls. 7/6/2013-Saturday Accept rig to A-07. Rig up. Prep to kill well A-07. • • 7/7/2013 -Sunday PJSM with everone involved in Killing A-7. Tbg press 250 psi, csg press 650 psi. Bring pump on holding annulus press at 650psi until tbg press stablized at 1,200psi. Maintain tbg pressure taking returns to production through choke. Returns were all gas. After pumping hole vol of 206 bbls we still had gas returns with annulus presure at 120 psi. Pump 250 bbls with tbg press at 1,270 psi and annulus press at 110psi. Shut pump down. Tbg press bled back to 0 psi and went on vac and annulus bled to 100psi. Monitor well for 15 min and pressure stayed the same. Change 3" flange on top of tree f/2" 1502 t/3-1/2" Bowen connection. Rig up Pollard. RIH and retrieve plug from Y-Block at 2,762'. POH with plug. Rig down Pollard. Change top tree flange to circ flange. Prepare to pump dn well, tbg press 90psi, annulus press 180psi. Start pumping dn tbg at 3 BPM,tbg press fell to Opsi and annulus stayed at 180psi. Pumped 75 bbls with no tbg press and 180psi on annulus. Bleeding annulus to production. All we were getting back was gas. Pumped 42 bbls size salt pill and chased it with 8 bbls 3% KCL. Shut down and shut well in. Total bbls pumped so far 375 bbls with only gas returns. Monitor well and let size salt pill find the loss zone. Prepare to pump dn tbg. Tbg press Opsi, annulus press 82psi. Start pumping dn tbg at 1.5 BPM for the first 35 bbls. 0 psi on tbg, 50psi on annulus. Increase pump rate to 6BPM and tbg press went to 200 psi, annulus 50 psi. After another 75 bbls pumped tbg press worked up to 400psi, annulus 50psi. Returns still gas. Slow pump dn to 5 BPM and tbg press went back dn to 200psi. Pump another 145 bbls and pressure climbed to 400 psi on the tbg with 50 psi on the annulus. Still getting gas returns. Shut down and tbg press bled to 0 psi in about 30 sec. Annulus press still at 50psi. Total bbls pumped from start of kill 630 bbls. Pump 45 bbls sized salt pill- displace with 8 bbls KCL,gas to surface,tbg 0 psi/annulus 20 psi. T/0-A/20 on line with pump, stage pumps up to 5 bpm/20 psi-pres increasing-oil cap to surface at 85 bbls oil turning to dirty water. Pump total 250 bbls-FCP 700. On line staging pumps to 4 bpm 40psi gas then water to surface in 11 bbls. Pump at 5 bpm/25psi and rising. Gas to oil then water. Pump total 210 bbls-FCP 765. On line with pump stage up to 5 bpm/50psi at 3 bbls away, pump total 27 bbls/425psi. SD pumps. 27 bph fluid loss. Pump 41 bbls sized salt pill with 8 bbls brine displaced water to surface. Wait on sized salt pill to settle, building 40 bbl SSP. On line with pump stage up to 5 bpm/830 psi. Water to surface at 40 bbls, annulus at 230psi. Water last 25 bbls,total 100 bbls pumped. Monitor well and let sized salt pill soak. On line with pump- stage up to 5 bpm/625 psi, water to surface at 13 bbls, annulus 120psi. Water pumped total 30 bbls, pump 40 bbls sized salt pill at 3 bpm/400psi/annulus 120psi. Displace with 8 bbls brine. SD pump. RD pumping iron to A-07. Stage hose to monitor annulus production RD well head monitoring equip. 7/8/2013- Monday Set BPV. Nipple down tree. Remove flow lines, Break wellhead bolts and remove tree from wellhead room. Keeping annulus full with line from trip tank. Hole taking 18 BPH. PU Riser and lower down to wellhead room, Install riser on wellhead and MU flange. PU stack and stab onto riser. MU bolts to specs. Install flow nipple and turn buckles. Set mouse hole and covers around stack. Hole taking f/20 t/22 BPH. MU test equip.The witnessing of the test was waived by AOGCC Jim Reggs. Perform Accumulator test as per State Benchmark Test, Hole taking 24 BPH. Test BOPE and related valves as per HAK-Kuukpik-AOGCC procedures 250psi low/2,500psi high. LD test tool. Pump 40 bbls sized salt pill, oil cap to surface, shut in 9-5/8" annulus. Finish testing BOPE and related valves as per HAK-Kuukpik-AOGCC procedures 250psi low/2,500psi high. LD test jt, pull BPV, set TWC,test blind rams/CMV 250psi low/2,500psi high. Pull TWC. RU and circulate 38 bbls for oil to surface. Pump 13 bbls oil cap off well to production. RD circulating equip. Back out LDS. RU tubing tongs, stage cable sheays on floor, pull hanger to floor with 34k puw. Disconnect ESP cable-control line. LD hgr, hang control line and ESP sheaves. POOH standing 2-7/8"tbg in derrick. Spooling ESP cable and control line. Fluid loss today-3% KCL 383 bbls- Total loss 910 bbls - Sized Salt Pill 124bbls-Total loss 208 bbls loss rate 23 bph. • • 7/9/2013-Tuesday Continue POH with ESP, Cleaning and spooling cable and control lines. Lay dn Y-Tool string. Cut and spool up cable and control line. Lay down pump and rig dn ESP equip. Recovered all Canon Clamps and SS bands. Rig dn Weatherford, clear tools from floor and clean same, set wear ring. MU BHA#1-8-1/2" bit, bit sub, XO, (12)4-3/4" DCs, X0=375.90. Move 15 stds of 4 to the drillers station pipe rack. RIH with 5 DP. Tag top of liner with no fill, Circ bottoms up, no sand, max gas 25 units. POH laying dn 5" DP, lay dn 30 jts. Monitor well hole taking 30 BPH. POH t/2,555'. Spot 20 bbl sized salt pill to slow fluid loss 35 bph. POOH to BHA. LD 12 ea 6-1/2" DC-8-1/2" bit and XO's. MU 6-1/8" bit, XO's, 7 ea 4-3/4" DC, 13 std 4" DP. 18 bph after pump SSP. RIH with 5" DP to 4,700'. Fill pipe. Continue RIH, slow thru TOL at 4,746'. 20 bph loss. Tag fill at 5,991' (91'from PBTD at 6,082'). Pick up kelly, wash down 8 bpm 590psi to 5,970'. CBU with —2 bbls sand across shakers. Reaming/washing from 5,991' to 6,082' hard bottom attempt to clean out with no progress. POOH. Fluid loss today-3% KCL 494 bbls- Total loss 1404 bbls - Sized Salt Pill 20 bbls-Total loss 228 bbls. 7/10/2013 -Wednesday Rig up and circ 1 1/2 bottoms up getting back about 1/4 bbl of sand. POOH lay dn 5" DP to liner top at 4746'. Circ 1 1/2 bottoms up to ensure liner top is clean. POOH laying down 5" DP. Stand the 4" pipe and the 4 3/4 DCs back in the derrick. Pull wear ring- monitor well 15 min -23 bph loss. R/U power tongs, control and chemical inj lines. M/U pkr-x nip-civ-xo- pups- hang control line sheave-test CL to 5000 psi. RIH with 2 7/8_tbg and jewelry. Install canon clamps every other jt and 10 SS bands where needed. M/U SSSV-test vlv/line to 5000 psi 15 min -bleed off psi-function test SSSV can feel and hear it open/close. Finish RIH with tbg. M/U hgr. Install CL/pressure to 5000 psi and lock in psi. - 29k puw 29k sow- land hgr with 29k wt. Ran total 43 Canon Clamps and 10 SS bands. Move tbg running equip out of way. Set wireline unit in place. M/U lubricator- hang sheave. RIH with 2.20 GR to 2860'SLM - POOH. MU/ RIH with 2.29 PX plug- locate X nip at 2864'SLM - plug acting spongy. Pass thru X-nip- unable to pull back thru X-nip. Work spang jars 30-40 times- hit with 25 oil jar licks-tools came free. POOH. Left tool body and 1 dog slip in well. Make up 2 7/8"GS pulling tool. RIH with 2 7/8" GS- locate PX body- latch and PU -set back down gently won't go past X-nip. POOH slow- recovered PX plug body-1 dog slip-ordered another PX plug and running tool. Fluid loss today- 3% KCL 531 bbls- Total loss 1935 bbls - Sized Salt Pill 0 bbls-Total loss 228 bbls loss rate 22 bph 7/11/2013 -Thursday MU brush on slickline tools and RIH brushing down through X-Nipple at 2856' while waiting on new PX Plug. MU tools and RIH w/ PX Plug. Set plug in X-nipple, POOH. P/U prong and RIH.Attempt to set prong in PX plug. POOH and still had prong. Re-run and get prong set on 2nd try. Rig dn Pollard. Rig up to pressure up down tbg. Pressure up to 3250 psi and hold it for 5 Min. [The pkr set when pressure hit 2100 to 2200 psi]. Bled press off tbg and rig up to pump dn ann. Pressure upon ann and pkr to 1500 psi.and Chart it for 30 min. No pressure loss. Rig dn test equip. Rig up Pollard and RIH. Retrieve Prong and POOH. Rig dn slickline. Set BPV and Nipple dn BOPs. PU and trolly BOPs to the side. Unbolt and remove riser. Clean up wellhead and nipple up the tree-test pack off 5000 psi/15 mins-test tree 5000 psi 15 mins-good test- pressure under TWC. R/U CIW lubricator pull TWC-T/125 psi-A/40 psi. R/U Pollard -test lub 2500 psi. Pump open SSSV- T/135 psi. RIH with Run# 1 pull DV at 2663' slm -tbg pressure increased to 250 psi after pulling DV. Run #2 Pull DV at 2106' slm. Run#3 pull/recover DV#2 at 2106' slm. Run #4 set GLV at 2106 'slm. Run#5 set GLV at 2663' slm. Run#6 pull PX body at 2864' slm-tbg 150 psi. L/D Pollard wireline-clean/clear rig floor. Prep to skid.Skid rig from A-07. Release rig at 0600 hrs 7/12/13. Fluid loss today-3% KCL 247 bbls-Total loss 2182 bbls-Sized Salt Pill 0 bbls-Total loss 228 bbls loss rate 20.5 bph THE STATE FOR IWE VILkISA GOVERNOR SEAN PARNELL SCA�H�D Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 tA014 Q 4201I 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 Re: Trading Bay Field, Hemlock Oil, Middle Kenai B Oil, Middle Kenai C Oil, and Middle Kenai D Oil Pools, Trading Bay ST A-07 Sundry Number: 313-335 Dear Mr. Kramer: 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 Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this Z7day of June, 2013. Encl. N STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS •]A A Ar 7G noA 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pod ❑ Repair Well ❑ Change Approved Program r Suspend ❑ Plug Perforations El Perforate ❑ Pull Tubing [� �t&•r3 Time Extension ❑ Operations Shutdown ❑ Re-enter Susp. Well ❑ Stimulate ❑ Auer Casing ❑ Other. 2. Operator Name: 4. Current Well Class: 5. Penn it to Drill Number. Hilcorp Alaska, LLC Exploratory ❑ Development Q. Stratigraphic ❑ Service ❑ 167-M 3. Address: 3800 Centerpoint Drive, Suite 100 6. API Number. Anchorage, AK 99503 50-733-20036-00 - 7. If perforating: 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes ❑ No ❑ Trading Bay ST A-07 . 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0018731 I Trading Bay Field / Hemlock Oil, Middle Kenai B Oil, Middle Kenai C Oil, Middle Kenai D Oil 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth ND (ft): Effective Depth MD (ft): Effective Depth ND (ft): Plugs (measured): Junk (measured): . 6,407 1 6,389 • 6,089 ' 6,076 6,089 (Cement Ret) N/A Casing Length Size MD ND Burst Collapse Structural Conductor Surface 1,067' 13-3/8" 1,067' 1,067' 3,090 psi 1,540 psi Intermediate Production 4,810' 9-5/8" 4,810' 4,806' 3,950 psi 2,570 psi Liner 1,651' 7" 6,397' 6,380' 7,240 psi 5,410 psi Perforation Depth MD (ft): Perforation Depth ND (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 2-7/8" 6.4# / N-80 12,811- ,811'Packers Packersand SSSV Type: Packers and SSSV MD (ft) and ND (ft): N/A N/A 12. Attachments: Description Summary of Proposal 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Q Exploratory ❑ Stratigraphic ❑ Development El • Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 7/5/2013 Oil El . Gas ❑ WDSPL ❑ Suspended ❑ WINJ ❑ GINJ ElWAG F1Abandoned ❑ 16. Verbal Approval: Date: Commission Representative: GSTOR ElSPLUG El 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Ted Kramer Email tkramer@lillcorg.com Printed Name Ted Kramer Title Sr. Operations Engineer Signature Phone 907 777-8420 Date 6/25/2013 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 313-'3,76 Plug Integrity ❑ BOP Test Wf/ Mechanical Integrity Test ❑ Location Clearance ❑ Other: 'A 2 SOOL s RBDM,JUL e tIIJ�' Spacing Exception Required? Yes ❑ No Eif/ Subsequent Form Required: d n , qo q APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: �� ,U 6-Z-4-/-3Form 10-403 (Revised 10/2012) Applfo R ji&j 144L months from the date of approval. Submit Fo and �� Attachments in Duplicate \�� i • Hilcorp Alaska, LLC June 25, 2013 Guy Schwartz Alaska Oil and Gas Conservation Commission 333 W. 7t' Avenue, Suite 100 Anchorage, Alaska 99501 Re: Sundry # 313-272 —Amendment Dear Mr. Schwartz: Attached to this letter, please find an amendment to the above Sundry. Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 100 Anchorage, AK 99503 Phone: 907/777-8300 Fax: 907/777.-8301 The ESP currently in the A-7 well will not run despite several attempts to start it and get it running. The unit is pulling almost twice the normal current which causes the motor to heat up and shuts the unit down on high temperature. Hilcorp has made a decision to simplify the proposed completion by dropping the y tool and ESP out and running a straight gas lift completion in this well. This will give us time to tear down the equipment currently in the well and determine what went wrong. Corrections can then be made to the ESP pump design for a future installation. Therefore, Hilcorp is submitting this amendment which changes the completion for this well to remove the ESP and run a gas lifted completion including a packer and surface r controlled subsurface safety valve. S� S 51" r The amendment includes: 1. Revised Procedure 2. Revised Proposed Well Schematic Please accept this amendment so that Hilcorp can move to this well and complete it after the current well. Respectfully, HILCORP ALASKA, LLC <� <--� Ted E. Kramer Senior Operations Engineer TEK/JLL Hilcorp Alaska, LL, Well Prognosis Well: A-7 Date:06/25/2013 Well Name: Monopod A-7 API Number: 50-733-20036-00 Current Status: Oil producer (ESP Lifted) Leg: N/A Estimated Start Date: July 5, 2013 Rig: Monopod Rig #56 Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: 1147 Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: -046 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) Second Call Engineer: Trudi Hallett (907) 777-8323 (0) AFE Number: Current Bottom Hole Pressure: 680 psi @ 2,805' (2,804' TVD) From Phoenix Pressure Gauge Maximum Expected BHP: 820 psi @ 2805' MD (2,804' TVD) Static From Phoenix Pressure Gauge (6/13/13 — two day shut in) Max. Anticipated Surface Pressure: —175 psi Measured. Brief Well Summary The A-7 is currently completed as an ESP lifted oil well. A recent re -completion opened some new intervals and the well began flowing. The current re -completion plan involves pulling the existing completion and installing a SSSV, GLMs, and a packer. This will allow the well to flow on its own up the tubing, and when it no longer will flow on its own, the well can be placed on gas lift. Brief Procedure: 1. MIRU Monopod Platform Rig # 56. 2. Circulate three percent KCL to kill well and circulate Hydrocarbon off of the well. 3. ND Wellhead, NU BOP and test to 250psi low/2,500psi high. (Note: Notify AOGCC 24 hours in advance of test to allow them to witness test). 4. RU Schlumberger artificial lift. Unseat tubing hanger, POOH with ESP and cable. 5. RU E -line. RIH and set Model D permanent packer at 2,810' (+/-). RD E -line. 6. PU new completion consisting of Seal Assembly, GLMs, and SSSV spaced out on 2-7/8" production tubing string and hang off same /I ( PSv 7. ND BOP, NU wellhead and test. I f i"� 8. Turn well over to production. Attachments: 1. As -built Well Schematic 2. Proposed Well Schematic 3. BOP Drawing n0 SCHEMATIC • Trading Bay Unit Monopod Well # A-7 API# 50-733-20036-00 Completed 05/14/13 RKB to TBG Hngr = 38.23' BZN C, CZN C, CZN DZN EZN KB ELEV =101' PBTD = 6,089' TD = 6,407' ANGLE thru INTERVAL = 3.2° CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 13-3/8" 61 K-55 Butt 12.515 Surf. 1067' 9-5/8" 40.0 K-55 Butt 8.835 Surf 4810' 7" 26 N-80 Butt 6.276 4746' 6397' Tubing: Motor Base Plug 9 2,811' WLEG 10 6,089' 2-7/8" 6.4 N-80 Seal Lock 2.441 Surf 2811' See Next Page for Perforation Data Updated by: JLL 05/29/13 JEWELRY DETAIL No Depth Item 1 41' 2-7/8" Hanger Assy. 2 2,761' Y Block 3 2,773' Head Bolt On Discharge 4 2,774' Pump DN1750, CR -CT, 46 DTG 400/400 60 CS VTHD 5 2,790 Intake 6 2,792' Protector 7 2,800' Motor Maximus, RA -S 30 HP463V 42,3A 8 2,810' Motor Base Plug 9 2,811' WLEG 10 6,089' EZ Drill Cement Retainer See Next Page for Perforation Data Updated by: JLL 05/29/13 n0 SCHEMATIC • Trading Bay Unit Monopod Well # A-7 API# 50-733-20036-00 Completed 05/14/13 PERFORATION DATA Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Date Status 2,874' 2,906' 2,873' 2,906' 32' 5 5/11/2013 Oen 2,875' 2,907' 2,874' 2,906' 22' 4 9/7/1988 Open 2,882 2,896' 2,881' 2,895' 14' 4 8/17/1970 Open 31-8 BZN 2,920' 2,947' 2,919' 2,946' 27' 5 5/11/2013 Open 2,923' 2,947' 2,922' 2,946' 24' 4 9/8/1988 Open 2,928' 1 2,944' 2,927' 2,943' 16' 4 8/17/1970 Open 2,997' 3,076' 2,996' 3,075' 79' 4 9/9/1988 Open 33-6 BZN 2,999' 3,077' 2,998' 3,076' 78' 5 5/11/2013 Open 3,044' 3,076' 3,043' 3,075' 32' 4 8/17/1970 Open 3,193' 3,242' 3,192' 3,241' 49' 5 5/11/2013 Open 3,196' 3,208' 3,195' 3,207' 12' 4 8/17/1970 Open 3,196' 3,240' 3,195' 3,239' 44' 4 9/10/1988 Open 3,214' 3,240' 3,231' 3,239' 26' 4 8/17/1970 Open 41-3 BZN 3,282' 3,433' 3,281' 3,432' 151' S 5/11/2013 Open 3,283' 3,435' 3,282' 3,434' 52' 4 9/11/1988 Open 3,290' 3,434' 3,289' 3,433' 144' 4 8/17/1970 Open 3,300' 3,320' 3,299' 3,319' 20' 4 9/10/1970 Cmt Szqd 3,795' 3,960' 3,793' 3,958' 65' 4 9/12/1988 Open 3,803' 3,959' 3,801' 3,957' 156' S 5/11/2013 Open 44-7 BZN 3,808' 3,850' 3,807' 3,848' 42' 4 8/17/1970 Open 3,820' 3,840' 3,818' 3,838' 20' 4 9/10/1967 Cmt Szqd 3,858' 3,956' 3,856' 3,954' 98' 4 8/17/1970 Open C-2 4,037' 4,097' 4,035' 4,095' W. S 5/11/2013 Open C-3 4,127' 4,224' 4,125' 4,221' 97' S 1 5/11/2013 Open 4,125' 4,225' 4,123' 4,222' 100' 4 1 9/15/1967 Cmt Szqd 44-7 BZN 4,140' 4,160' 4,138' 4,157' 20' 4 1 9/10/1967 Cmt Szqd CZNS6 4,267' 4,335' 4,264' 4,332' 68' 5 5/11/2013 Open C4 4,344' 4,371' 4,341' 4,368' 27' 5 5/11/2013 Open C5 4,429' 4,479' 4,426' 4,476' SO' 5 5/11/2013 Open C-6 4,600' 4,639' 4,595' 4,635' 39' S 5/11/2013 Open 44-7 BZN 4,605' 4,625' 4,601' 4,621' 20' 4 9/10/1967 Cmt Szqd 4,670' 4,700' 4,666' 4,696' 30' 5 5/11/2013 Open CZN57 4,720' 4,740' 4,716' 4,736' 20' S 1 5/11/2013 Open C7 4,760' 4,781' 4,756' 4,777' 21'S 5/11/2013 Open 49-4 CZN 4,807' 4,829' 4,803' 4,825' 22' 5 5/11/2013 Open 50-0 CZN 4,869' 4,879' 4,865' 4,875' 10' 5 5/11/2013 Open 50-3 CZN 4,897' 4,927' 4,893' 4,923' 30' S 5/11/2013 Open CZNS2 4,952' 4,957' 4,989' 4,953' 5' 5 5/11/2013 Open 50-6 CZN 4,992' 5,021' 4,988' 5,017' 29' 5 5/11/2013 Open CZN59 S,102' 5,122' 5,097' 5,117' 20' 5 5/11/2013 Open 51-6 CZN 5,122' 5,156' 5,117' 5,151' 34' S 5/11/2013 Open 51-9 CZN 5,170' 5,198' 5,16S' 5,193' 28' 5 5/11/2013 Open 53-0 DZN 5,260' 5,288' 5,254' 5,282' 28' 5 5/11/2013 Open DZNS2 5,328' 5,335' 5,322' 5,329' 7' S 5/11/2013 Open 53-8 DZN 5,360' 5,393' 5,354' 5,387' 33' 5 5/11/2013 Open 54-5 DZN 5,424' 5,458' 5,417' 5,451' 34' 5 5/11/2013 Open 54-9 DZN 5,492' 5,509' 5,485' 5,502' 17' S 5/11/2013 Open 55-7 DZN 5,542' 5,560' 5,534' 5,552' 18' 5 5/11/2013 Open 56-1 DZN 5,587' 5,670' 5,579' 5,661' 83' 5 5/11/2013 Open 57-2 DZN 5,700' 5,744' 5,691' 5,735' 74' 5 5/11/2013 Open 5,798' 5,817' 5,788' 5,807' 19' 5 5/11/2013 Open 58-1 EZN 5,823' 5,837' 5,813' 5,827' 14' 5 5/11/2013 Open 5,860' 5,875' 5,850' 5,864' 15' 5 5/11/2013 Open 58-7 EZN 5,882' 5,948' 5,871' 5,937' 1 66' 5 5/11/2013 Open 60-0 EZN 5,982' 6,019' 1 5,970' 1 6,007' 1 37' 5 5/11/2013 Open Updated by: JLL 05/29/13 . • Trading Bay Unit PROPOSED Monopod Well # A-7 API# 50-733-20036-00 Completed 05/14/13 RKB to TBG Hngr = 38.23' BZN C, CZN C, CZN DZN EZN KB ELEV = 101' PBTD = 6,089' TD = 6,407' ANGLE thru INTERVAL = 3.2* CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 13-3/8" 61 K-55 Butt 12.515 Surf. 1067' 9-5/8" 40.0 K-55 Butt 8.835 Surf 4810' 7" 26 N-80 Butt 6.276 4746' 6397' Tubing: EZ Drill Cement Retainer 2,881' 2,895' 14' 4 8/17/1970 2-7/8" 6.4 N-80 Seal Lock 2.441 Surf 2811' PERFORATION DATA Zone Top (MD) JEWELRY DETAIL No Depth Item 1 41' 2-7/8" Hanger Assy. 2 ±300' Baker SSSV 3 ±2,100' GLV 4 ±2,640' GLV 5 ±2,824' Packer 6 ±2,855 X -Nipple 7±2,856' 9/7/1988 WLEG 8 6,089' EZ Drill Cement Retainer PERFORATION DATA Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Date Status 2,874' 2,906' 2,873' 2,906' 32' 5 5/11/2013 Open 2,875' 2,907' 2874' 2,906' 22' 4 9/7/1988 Open 2.882' 2,896' 2,881' 2,895' 14' 4 8/17/1970 Open 31-8 BZN 2,920' 2,947' 2,919' 2,946' 27' 5 5/11/2013 Open 2,923' 2,947' 2922' 2,946' 24' 4 9/8/1988 Open 2,928' 2,944' 2,927' 2,943' 16' 4 8/17/1970 Open 2,997' 3,076' 2,996' 3,075' 79' 4 9/9/1988 Open 33-6 BZN 2,999' 3,077' 2,998' 3,076' 78' 5 5/11/2013 Open 3,044' 3,076' 3,043' 3,075' 32' 4 8/17/1970 Open 3,193' 3,242' 3,192' 3,241' 49' 5 5/11/2013 Open 3,196' 3,208' 3,195' 3,207' 12' 4 8/17/1970 Open 3,196' 3,240' 3,195' 3,239' 44' 4 9/10/1988 Open 3,214' 3,240' 3,231' 3,239' 26' 4 8/17/1970 Open 41-3 BZN 3,282' 3,433' 3,281' 3,432' 151' 5 5/11/2013 Open 3,283' 3,435' 3,282' 3,434' 52' 4 9/11/1988 Open 3,290' 3,434' 3,289' 3,433' 144' 4 8/17/1970 Open 3,300' 3,320' 3,299' 3,319' 20' 4 1 9/10/1970 Cmt Szqd 3,795' 3,960' 3,793' 3,958' 65' 4 9/12/1988 Open 3,803' 3,959' 3,801' 3,957' 156' 5 5/11/2013 Open 44-7 BZN 3,808' 3,850' 3,807' 3,848' 42' 4 8/17/1970 Open 3,820' 3,840' 3,818' 3,838' 20' 4 9/10/1967 Cmt Szqd 3,858' 3,956' 3,856' 3,954' 98' 4 8/17/1970 Open C-2 4,037' 4,097' 4,035' 1 4,095' 60' 5 5/11/2013 Open C-3 4,127' 4,224' 1 4125' 4,221' 97' 5 5/11/2013 Open 4,125' 4,225' 4,123' 4,222' 100' 4 9/15/1967 Cmt Szqd 44-7 BZN 4,140' 4,160' 4,138' 4,157' 20' 4 9/10/1967 Cmt Szqd CZNS6 4,267' 4,335' 4,264' 4,332' 68' 5 5/11/2013 Open C4 4,344' 4,371' 4,341' 4,368' 27' 5 5/11/2013 Open CS 4,429' 4,479' 4,426' 4,476' So' 5 5/11/2013 Open C-6 4,600' 4,639' 4,595' 4,635' 39' 5 5/11/2013 Open 44-7 BZN 4,605' 4,625' 4,601' 4,621' 20' 4 9/10/1967 Cmt Szqd 41670' 4,700' 4,666' 4,696' 30' S 5/11/2013 Open CZN57 4,720' 4,740' 4,716' 4,736' 20' 5 5/11/2013 Open C7 4,760' 4,781' 4,756' 4,777' 21' 5 5/11/2013 Open 49-0 CZN 4,807' 4,803' 4,825' 22' 5 5/11/2013 Open 50-0 CZN 4,869' 4,865' 4,875' 10' 5 5/11/2013 Open 50-3 CZN 4,897' 4,893' 4,923' 30' 5 5/11/2013 Open CZNS2 4,952' M5,122' 4,989' 4,953' 5' 5 5/11/2013 Open 50-6 CZN 4,992' 4,988' 5,017' 29' 5 5/11/2013 Open CZNS9 5,102' 5,097' 5,117' 20' S 5/11/2013 Oen 51-6 CZN 5,122' 5,117' 5151' 34' S 5/11/2013 Open 51-9 CZN 5170' 5198 5,165' 5,193' 28' 5 5/11/2013 Open 53-0 DZN 5,260' 5,288' 5,254' 5,282' 28' 5 5/11/2013 1 Open DZNS2 5,328' S,335' 5,322' 5,329' 7' 5 5/11/2013 Open 53-8 DZN 5,360' 5,393' 1 5,354' 5,387' 33' 5 5/11/2013 Open 54-5 DZN 5,424' 5,458' 5,417' 5,451' 34' 5 5/11/2013 Oen 54-9 DZN 5,492' 5,509' 5,485' 5,502' 17' 5 5/11/2013 Open 55-7 DZN 5,542' 5,560' 5,534' 5,552' 18' 5 5/11/2013 Open 56-1 DZN 5 587' 5,670' 5,579' 5,661' 83' 5 5/11/2013 Open 57-2 DZN 5,700' 5,744' 5,691' 5,735' 74' 5 5/11/2013 Open 5,798' 5,817' 5,788' 5,807' 19' 5 5/11/2013 Open 58-1 EZN 5,823' 5,837' 5,813' 5,827' 14' 5 5/11/2013 1Open 5,860' 5,875' 5,850' 5,864' 15' 5 5/11/2013 Open 58.7 EZN 5,882' 5,948'5,871' 5,937' 66' 5 5/11/2013 1 Open 60-0 EZN 5,982' 6,019' 5,970' 6,007' 37' 5 5/11/2013 1 Open Updated by: JLL 06/25/13 Monopod Platform 2013 BOP Stack 03/12/2013 Hilrnrp Ahioku. LIS', Wellhead @ 15.00' I deck Schwartz, Guy L (DOA) (D10 LI (Ob From: Ted Kramer <tkramer @hilcorp.com> Sent: Wednesday,June 26, 2013 1:49 PM To: Schwartz, Guy L(DOA) Cc: Juanita Lovett Subject: RE:TBU A-07 (PTD 167-046) Guy, Hilcorp would like to withdraw Sundry#313-272 for the Monopod A-7 well PTD 167-046. A replacement Sundry application has been submitted in its place. Respectfully, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. SCANNED FEB 2 0 2014 0 907-777-8420 C 985-867-0665 From: Schwartz, Guy L(DOA) [mailto:guuy.schtitiartz aIaska_gov] Sent: Wednesday,June 26, 2013 1:44 PM To: Ted Kramer Subject: TBU A-07 (PTD 167-046) Ted, It will be cleaner to just withdraw sundry 313-272 ... please request with email reply. Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office Schwartz, Guy L (DOA) From: Ted Kramer <tkramer@hilcorp.com> Sent: Friday, June 21, 2013 11:08 AM To: Schwartz, Guy L (DOA); Ferguson, Victoria L (DOA) Subject: Monopod Well A-7 - Udate # 1 Guy and Victoria, (Q u 1(, -7- o'f(I The A-7 well has been on line for one week now and here is the first update flowing the well up the tubing. Flow Line Ultrasonic Testing A base line UT scan was conducted on Friday June 14, 2013 of the surface flow line and piping prior to initiating flow up the tubing. No signs of erosive service was found in the flow line at that time. This UT scan was repeated 7 days later (today). The final report has not been issued but the inspector reported that he found no new signs of erosive service. ESP Start Attempt Hilcorp attempted to start the ESP in the well this week and although we did manage to get the ESP running, it was pulling almost twice the rated Amps of the motor indicating that there was a significant amount of solids in the pump binding the impellors. The unit was pulling so high of current that it would cause the motor to overheat after running 12 to 15 minutes. The motor was started and ran 4 times with the same result so a decision was made to leave the pump down until pulled. Well Test A well test was also conducted overnight and the well is flowing 678 bbls. of fluid with a 1% water cut. Rig Availibility Work on the A-13 continues and the current operation is fishing the last remaining packer out of the well. From there we will: 1.) Fish the last remaining packer out of well. 2.) Make a bit and scraper run. 3.) Run Casing Inspection Log and evaluate. 4.) Repair casing (Expandable liner patch or scab liner) 5.) Perforate the well. 6.) Run completion. 7.) Move Rig to A-7. Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. O 907-777-8420 C 985-867-0665 Schwartz, Guy L (DOA) From: Ted Kramer <tkramer @hilcorp.com> Sent: Thursday,June 13, 2013 8:07 AM To: Schwartz, Guy L(DOA); Ferguson,Victoria L(DOA) Cc: Regg,James B (DOA) Subject: RE: Monopod Well A-7 Request to Continue to Flow the Well / ,7—o Guy, Hilcorp asks that we be allowed to flow test the A-7 well up the tubing. Recent flow tests in our attempts to start the ESP demonstrated that flowing through the ESP was possible,just at a reduced rate. It is important to Hilcorp to keep this well on line to be able to continue to gather data and information which will affect the subsequent completion. To answer the Commission's concern of sand and solids production, It is not uncommon for wells on the Monopod to produce some sand. This is managed by periodically performing UT inspections to determine if erosion is occurring and if it is, what is the rate of the erosion. That is how the equalizing line erosion was found, was by performing an x-ray and UT inspection for a base line and a followup inspection 7 days later. Flowing the A-7 up the tubing will further reduce the risk of erosion due to two factors: 1. Rate will be reduced by flowing through the ESP pump. 2. The flow line is a straighter run than the equalizing line (fewer 90 degree elbows). We will also continue to monitor the flow line by performing periodic UT inspections to monitor if any erosion is taking place so that corrective action can occur. As an added precaution, we still have the water injection line connected to the casing annulus so that waterflood injection water can be placed down the backside should a need to kill the well occur. Hilcorp asks that based on the need to collect further data and under these conditions, that we be allowed to flow A-7 up the tubing until the rig is available to change the completion. Respectfully, FEB 2 0 2014 SCOW Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. O 907-777-8420 C 985-867-0665 1 From: Schwartz, Guy L(DOA) [mailto:guy.schwartz @alaska.gov] Sent: Wednesday, June 12, 2013 3:17 PM To: Ted Kramer; Ferguson, Victoria L(DOA) Cc: Regg,James B (DOA) Subject: RE: Monopod Well A-7 Request to Continue to Flow the Well Ted, The Commission will not authorize any more flow testing using the annulus. With the production of sand even with targeted "T" the risk is too high since the there is no SVS in the event of a breach in the production line. We can discuss further flow testing using the tubing side if that is still an option (ie possible tubing punches above the ESP pump? ) or some other way to bypass the sanded up pump. I'm not sure how much sand is being produced but other issues may come up if flowing continues regarding retrieving the ESP pump due to fill on top of it etc.Again this would have to be discussed before more testing is allowed. Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office From: Schwartz, Guy L(DOA) Sent: Wednesday, June 12, 2013 8:27 AM To: 'Ted Kramer'; Ferguson, Victoria L(DOA) Subject: RE: Monopod Well A-7 Request to Continue to Flow the Well Ted, Need to discuss with Commissioners today. I will get back to you later today with answer. Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office From: Ted Kramer[maiitotkram r a hiicorp_com] Sent: Wednesday, June 12, 2013 6:33 AM To: Schwartz, Guy L(DOA); Ferguson, Victoria L (DOA) Subject: FW: Monopod Well A-7 Request to Continue to Flow the Well Guy and Victoria, Just a heads up that since I did not hear back from you yesterday concerning the extension for A-7, we shut the well in at Midnight last night. I am not sure at this point if this was an oversight or not. I will be calling early this AM to find out. Respectfully, 2 Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 From:Ted Kramer Sent: Tuesday, June 11, 2013 1:51 PM To: Schwartz, Guy L(DOA) (guy schwartz@aiaska.gov); Ferguson, Victoria L (DOA) Cc: Juanita Lovett Subject: FW: Monopod Well A-7 Request to Continue to Flow the Well Guy and Victoria, Hilcorp asks that we be given an extension to continue flowing well A-7 on the Monopod Platform in order to continue efforts to produce the well towards a stabilized flow rate. Current Well Status: The A-7 well continues to flow up the backside intermittently. The well is scheduled to go back into test tonight to measure the flow cycles and the watercut . I will forward those as soon as I receive them from the field. Efforts over the Last Seven Days: During the last seven days we continued to gather data on the well to better understand the flow regime the well is in. We attempted to start the ESP without success. During the start attempt, the motor current rapidly increased until it hit the high shutdown limit which in turn shut down the drive. This suggests that the impellers of the ESP are stuck most likely due to sand falling back on top of the pump. Although unsuccessful in starting the ESP, information was gathered suggesting that a diverter valve is needed to prevent sand from falling back into the ESP on shutdown. We are also considering trying to start the pump without the shutdown safeties in place to see if the pump can be "rocked "free . Although this is not something normally done it is a risk worth considering in this case since we know we are returning to this well following the completion of the A-13. Also this week we verified that the well is making sand. Both in from the ESP having the locked pump and through performing a second UT on the equalizing line connecting the casing to the tubing on the surface. ( This line is the flow path for the production coming up the casing to get to the production vessel.) The two UT's were taken 1 week apart and resulted in observing significant metal loss due to erosion in the 90 degree elbows of the line. A new line was fabricated and the well was shut in for 4 hours to allow for the changing of the line. Targeted tees were used in the replacement line instead of 90 degree elbows to prevent the erosion. The 4 hour shut-in also allowed us to get a shut in pressure reading on the casing. The casing pressure increased to 480 psi. which is down from the 700+ psi the casing pressure was at initially. Plan Forward for the Next 7 Days Hilcorp plans to accomplish the following in the next seven days of flowing the well: 3 1. Place the well in test and observe what the cycle time is for the well heading. This cycle time will then be compared to the previously measured cycle time to see if adjusting the choke setting will bring the well into stabilized flow. 2. Discuss the merits of eliminating the shutdown limits in the ESP to see if we can reverse the rotations to "rock" the ESP to see if we can get it started. 3. Continue to gather well data to determine what the optimum completion is going forward for these wells. Hilcorp asks the commission for an extension to allow us to continue flowing the A-7 so that additional data can be gathered and a stabilized flow achieved. Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 From: Ted Kramer Sent: Tuesday, June 04, 2013 11:11 AM To: Schwartz, Guy L (DOA) (cuy.schwartzti)alaska.gov); Ferguson, Victoria L(DOA) Cc: Juanita Lovett Subject: Monopod Well A-7 Request to Continue to Flow the Well Guy, Hilcorp asks that we be given an extension to continue flowing well A-7 on the Monopod platform in order to continue efforts to produce the well towards a stabilized flow rate. Current Well Status: The A-7 well is still flowing up the back side and is exhibiting cycles of heading followed by cycles of low to no flow. Pressure cycles are from a high of 150 psi. during the heading portion of the cycle which then drops to 70 psi (which is essentially system pressure). The well has also began making some water (currently 5%water cut)which we believe will lead to the well not being able to continue flowing on its own. Efforts over the Last Seven Days: During the last seven days, attempts were made to adjust back pressure on the casing to help get the well to stabilize. While we were unsuccessful in getting the well to flow at a consistent rate, we were able to move the heading cycle into a pattern of 17 minutes of heading followed by 23 minutes of low to no flow. In order to aid in flow stabilization we attempted to start the ESP on Friday of last week. We feel that starting this ESP is the next step in getting the well to stabilized production. The ESP startup was unsuccessful do to the drive tripping out on current overload. Yesterday afternoon a meeting was held with our ESP vendor, our drive vendor, and Hilcorp to 4 discuss the issues surrounding the Br not starting. The outcome of that meeting was that the flow coming up the tubing was causing the impellors of the pump to spin. The drive of the ESP was not set up to catch the load in motion (although it does have that capability) and was causing the ESP to go down on current overload (this is not the typical way to start an ESP). Hilcorp submitted the Sundry to recomplete the A-7 with a packer and SSSV in the well in the event we are unsuccessful in getting the well to pass a no flow test. That Sundry was approved and returned by the AOGCC. Plan Forward for the Next 7 Days Hilcorp has a plan in place to again start the ESP on Thursday of this week. What we plan to do differently is: 1. Set the drive to be able to catch the load in motion with the ESP impellers spinning. 2. Shut in the tubing of the well to stop the impellers from spinning. 3. Start the ESP and allow it to pump against the closed tubing valve momentarily and then open the valve. Produce the well with the ESP running in order to get the production moving up the tubing. Hilcorp asks for an extension to continue to produce the well into a stabilized flow that will pass the no flow condition. Respectfully, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 From:Ted Kramer Sent:Tuesday, May 28, 2013 11:23 AM To: Ferguson, Victoria L(DOA) Cc: Schwartz, Guy L (DOA) (g_uy.schwartz©aaiaska.gov); Juanita Lovett; Jonathan Liebenthal Subject: FW: Monopod Well A-7 Request to Continue to Flow the Well to get it to Stabilize Victoria, Hilcorp asks that we be given permission to continue to flow the A-7 well on the Monopod Platform for another 7 days. Permission to flow the A-7 well for 7 days was granted by the commission (See Guy Schwartz's email below) to see if the well would die on its own or if the flow would stabilize. The well overall has continued to weaken and currently the backside pressure has decreased to 60 psi. The flow rate on the well at times goes to zero and then heads up to a rate of 2,000 bpd. Hilcorp's plan for this week is to see if we can start the ESP in the well in order to lower the bottom hole pressure to the point where stabilized flow can be achieved. Once stabilized flow is achieved, a no flow test will be conducted. As a contingency, Hilcorp is making plans to rig back up on the well as soon as the rig is finished with the A-13 workover. The Sundry for a completion with a packer is currently being prepared. 5 Hilcorp believes that allowing this weii to flow/ be produced for another 7 days will help us determine which completion is necessary. Please let me know if continuing to produce this well is agreeable to the commission. Respectfully, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 From: Ted Kramer Sent: Friday, May 24, 2013 2:07 PM To: Ferguson, Victoria L(DOA) Cc: Schwartz, Guy L(DOA) (g_uy.schwu�t74alaska.gov);jim.reggualaska.gov; Juanita Lovett Subject: FW: Monopod Well A-7 Request to Continue to Flow the Well to get it to Stabilize Victoria, I realize this is early (current extension expires on Tuesday of next week) but Mr. Schwartz asked me to submit a forward plan and I wanted to get this plan to you today because Monday is a holiday. The A-7 well is still flowing up the casing and still heading due to unstabilized flow. Overall, the casing pressure trend seems to be downward. Low casing pressures are now reaching 70 psi which is 40 to 50 psi lower than when we first brought the well on. The immediate forward plan is to continue to flow A-7 through the weekend to see if the casing pressure will continue the downward trend. If it dies, we then would turn the ESP on to see if the well will reach a more stabilized flow. As a safety measure we have piped high pressure injection water to the 9-5/8" X 2-7/8" tubing annulus. If there is an issue, we can open a valve and pump injection water down the annulus to kill the well. Longer term plan forward for A-7 is that Hilcorp is preparing a new completion for the A-7 well similar to the revised A- 13 completion that you and I discussed earlier today. This is a contingency plan in the event the well does not die on its own and /or will not pass a no flow test.. The plan is to move back on A-7 as soon as the rig is finished with the A-13 workover. We believe by that time we will know how the well will respond and have the necessary jewelry procured and here to change the completion. Please let me know if you have any questions or concerns. Respectively, Ted Kramer 6 Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 From: Schwartz, Guy L(DOA) [maito_quy schwartzci alaska.gnv] Sent: Tuesday, May 21, 2013 8:39 AM To: Ted Kramer Cc: Ferguson, Victoria L(DOA); Juanita Lovett; Regg, James B (DOA) Subject: Re: Monopod Well A-7 Request to Continue to Flow the Well to get it to Stabilize Ted, You have approval to flow well via tubing x casing annulus for short term testing and analysis of the well flow characteristics. After this initial 7 day flow period check in with Commission with an update and your plan forward for well ... Guy schwartz AOGCC Sent from my iPhone On May 20, 2013,at 3:01 PM, "Ted Kramer" <tkraoier(hilcorp_com>wrote: Guy and Victoria, The Monopod Well A-7 was brought on line on 5-16-13 at approximately 1 PM. We started the ESP and ran it for 15 minutes when we noticed a communication scaling issue with the drive not reflecting what we observed in our PLC Scada system. We shut the ESP down and the well began to flow up the tubing. The casing was opened to prevent the well from spinning the ESP backwards and the well continued to flow up the casing. The well has been flowing up the casing since Saturday although the rate has not stabilized. The oil rate has varied from 650 BOPD to 2,500 BOPD depending on the gas heading which has varied from 240 mcf up to 1.6MMscf(gas chart attached). The gas is showing some signs of weakening today peaking at 1.3 MMscf rate. Hilcorp requests an extension on flowing this well to see if the well will stabilize or quit flowing on its own. The concern is that until the well stabilizes, it will not be known which type of completion is needed. It may be that the current completion is adequate if the well dies on its own in a short period of time.There is also a concern that unnecessarily killing this well in order to rig back up on it may damage the formation so that it will not behave the same after the re-completion. Hilcorp asks for a 7 day extension to begin after the usual 5 days allowed in the regulation which will end tomorrow (Tuesday 5/21/13). At the end of the 7 days the well's status will be reviewed and an extension requested at that time if needed. 7 As a mitigation measure, Hilcorp will install piping from the Monopod's waterflood system so that in the event the need arises, high pressure waterflood water can be injected down the back side of the well in order to kill it. Please let me know if this is acceptable to the commission or if further information is needed to make the determination. Respectfully, Ted Kramer Sr.Operations Engineer Hilcorp Alaska, LLC. O 907-777-8420 C 985-867-0665 <hot sheet0002.jpg> 8 • ®F � • • %% s THE STATE Al 011 and Gas ofA GOVERNOR SEAN PARNELL 333 West Seventh Avenue ®FALaS��' Anchorage, Alaska 99501 -3572 Main: 907.279.1433 2.013 Fax: 907.276.7542 SCANNED J\ JN fi 7 Ted Kramer Sr. Operations Engineer 127 -01-11 r , Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: Trading Bay Field, Hemlock, Middle Kenai B, C, and D Oil Pools, Trading Bay ST A -07 Sundry Number: 313 -272 Dear Mr. Kramer: 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 Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this 3 day of June, 2013. Encl. `e , .. 0 • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION �w "° (* "� APPLICATION FOR SUNDRY APPROVALS ,�"� s 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations El Perforate ❑ Pub Tubing El - lime Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other. e� - 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. ESP Hilcorp Alaska, LLC Exploratory ❑ Development p • 167-046 � 3. Address: 3800 Centerpoint Drive, Suite 100 Stratigraphic ❑ Service ❑ 6. API Number. 3l `i Anchorage, AK 99503 50- 733 - 20036 -00 • 7. If perforating: 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes ❑ No El Trading Bay ST A -07 9. Property Designation (Lease Number): 10. Field /Pool(s): ADL0018731 ' Trading Bay Field / Hemlock Oil, Middle Kenai B Oil, Middle Kenai C Oil, Middle Kenai D Oil ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): • 6,407 - 6,389 • 6,089 6,076 6,089 (Cement Ret) N/A Casing Length Size MD TVD Burst Collapse Structural Conductor Surface 1,067' 13 -3/8" 1,067' 1,067' 3,090 psi 1,540 psi Intermediate Production 4,810' 9 -5/8" 4,810' 4,806' 3,950 psi 2,570 psi Liner 1,651' 7" 6,397' 6,380' 7,240 psi 5,410 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic • See Schematic 2 -7/8" 6.4# / N -80 2,811' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A N/A 12. Attachments: Description Summary of Proposal In • 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 • Exploratory ❑ Stratigraphit ❑ Development IN - Service ❑ 14. Estimated Date for 15. Well Status after proposed work: 6/12/2013 • Commencing Operations: Oil O ' Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Ted Kramer Email tkramer@hilcorp.com Printed Name Ted Kramer Title Sr. Operations Engineer Signature 1 ' " �— Phone 907 777 -8420 Date 5/30/2013 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 2 1 5 _ 1 . 7 I Plug Integrity ❑ BOP Test Mechanical Integrity Test El Location Clearance ❑ Other: Q Z RBDMS JUN - 5 2016\ Spacing Exception Required? Yes ❑ No Yr Subsequent Form Required: 10` / ay 1 AHERO BY /3 Approved by: COMMISSIONER THE COMMMM ON Date: ,ril'I3 . ,p a' ■/�� n NalAoL2 Submit Form and A 1 ,4 - Form 10-403 (Revised 10/2012) Ap �e fpi;a4� ol months from the date of a prove!. Attachments in Duplicate 1'2V. • • Well Prognosis Well: A -7 Hilcorp Alaska, LL Date: 05/30/2013 Well Name: Monopod A -7 API Number: 50- 733 - 20036 -00 Current Status: Oil producer (ESP Lifted) Leg: N/A Estimated Start Date: June 12, 2013 Rig: Monopod Rig #56 Reg. Approval Req'd? 10 -403 Date Reg. Approval Rec'vd: Regulatory Contact: Juanita Lovett 777 -8332 Permit to Drill Number: 168 -046 First Call Engineer: Ted Kramer (907) 777 -8420 (0) (985) 867 -0665 (M) Second Call Engineer: Trudi Hallett (907) 777 -8323 (0) AFE Number: Current Bottom Hole Pressure: 450 psi @ 2,805' (2,804' TVD) From Phoenix Pressure Gauge Maximum Expected BHP: 1,187 psi @ 2805' MD (2,804' TVD) Static From Phoenix Pressure Gauge Max. Anticipated Surface Pressure: —175 psi Measured. Brief Well Summary The A -7 is currently completed as an ESP lifted oil well. A recent re- completion opened some new intervals and the well began flowing. The current re- completion plan involves pulling the existing completion and installing a SSSV, GLMs, an ESP on a Y -tool, and a sliding sleeve above a packer. This will allow the well to flow on its own, and when it no longer will flow on its own, the sliding sleeve can be opened and the ESP started. Brief Procedure: 1. MIRU Monopod Platform Rig # 56. 2. Circulate three percent KCL to kill well and circulate Hydrocarbon off of the well. 3. ND Wellhead, NU BOP and test to 250psi low /2,500psi high. (Note: Notify AOGCC 24 hours in advance of test to allow them to witness test). 4. RU Schlumberger artificial lift. Unseat tubing hanger, POOH with ESP and cable. 5. RU E -line. RIH and set Model D permanent packer at 2,810' ( + / -). RD E -line. 6. PU new completion consisting of Seal Assembly, Sliding Sleeve, ESP mounted on Y -Tool, GLMs, and SSSV spaced out on 2 -7/8" production tubing string and hang off same. 7. ND BOP, NU wellhead and test. J f - 1 �" y5"- 8. Turn well over to production. chk/ e) 5 31. /3 Attachments: 1. As -built Well Schematic 2. Proposed Well Schematic 3. BOP Drawing , , • • Trading Bay Unit SCHEMATIC Monopod Well # A -7 API# 50- 733 - 20036 -00 Completed 05/14/13 RKB to TBG Hngr = 38.23' i I 1 CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 1 3 3/8" 61 K -55 Butt 12.515 Surf. 1067' 9 -5/8" 40.0 K -55 Butt 8.835 Surf 4810' 7" 26 N -80 Butt 6.276 4746' 6397' Tubing: 2 -7/8" 6.4 N -80 Seal Lock 2.441 Surf 2811' IN L 2 JEWELRY DETAIL No Depth Item 3 1 41' 2 -7/8" Hanger Assy. 4 2 2,761' Y Block s 3 2,773' Head Bolt On Discharge I e 4 2,774' Pump DN1750, CR -CT, 46 DTG 400/400 60 CS VTHD 5 2,790 Intake `'" 7 6 2,792' Protector 7 2,800' Motor Maximus, RA -S 30 HP463V 42,3A 8 8 2,810' Motor Base Plug 9 2,811' WLEG 9 10 6,089' EZ Drill Cement Retainer 8ZN —J See Next Page for Perforation Data C, CZN ■ C, CZN �} DZN 10 = EZN KB ELEV = 101' PBTD = 6,089' TD = 6,407' ANGLE thru INTERVAL = 3.2° Updated by: JLL 05/29/13 .. • • Trading Bay Unit ... SCHEMATIC M onopod W ell # A -7 API# 50- 733 - 20036 -00 Completed 05/14/13 PERFORATION DATA Zone Top (MD) Btm (MD) Top (ND) Btm (ND) Amt SPF Date Status 2,874' 2,906' 2,873' 2,906' 32' 5 5/11/2013 Open 2,875' 2,907' 2,874' 2,906' 22' 4 9/7/1988 Open 31 -8 BZN 2,882' 2,896' 2,881' 2,895' 14' 4 8/17/1970 Open 2,920' 2,947' 2,919' 2,946' 27' 5 5/11/2013 Open 2,923' 2,947' 2,922' 2,946' 24' 4 9/8/1988 Open 2,928' 2,944' 2,927' 2,943' 16' 4 8/17/1970 Open 2,997' 3,076' 2,996' 3,075' 79' 4 9/9/1988 Open 33 -6 BZN 2,999' 3,077' 2,998' 3,076' 78' 5 5/11/2013 Open 3,044' 3,076' 3,043' 3,075' 32' 4 8/17/1970 Open 3,193' 3,242' 3,192' 3,241' 49' 5 5/11/2013 Open 3,196' 3,208' 3,195' 3,207' 12' 4 8/17/1970 Open 3,196' 3,240' 3,195' 3,239' 44' 4 9/10/1988 Open 41 -3 BZN 3,214' 3,240' 3,231' 3,239' 26' 4 8/17/1970 Open 3,282' 3,433' 3,281' 3,432' 151' 5 5/11/2013 Open 3,283' 3,435' 3,282' 3,434' 52' 4 9/11/1988 Open 3,290' 3,434' 3,289' 3,433' 144' 4 8/17/1970 Open 3,300' 3,320' 3,299' 3,319' 20' 4 9/10/1970 Cmt Szqd 3,795' 3,960' 3,793' 3,958' 65' 4 9/12/1988 Open 3,803' 3,959' 3,801' 3,957' 156' 5 5/11/2013 Open 44 -7 BZN 3,808' 3,850' 3,807' 3,848' 42' 4 8/17/1970 Open 3,820' 3,840' 3,818' 3,838' 20' 4 9/10/1967 Cmt Szqd 3,858' 3,956' 3,856' 3,954' 98' 4 8/17/1970 Open C -2 4,037' 4,097' 4,035' 4,095' 60' 5 5/11/2013 Open C -3 4,127' 4,224' 4,125' 4,221' 97' 5 5/11/2013 Open 44 -7 BZN 4,125' 4,225' 4,123' 4,222' 100' 4 9/15/1967 Cmt Szqd 4,140' 4,160' 4,138' 4,157' 20' 4 9/10/1967 Cmt Szqd CZN56 4,267' 4,335' 4,264' 4,332' 68' 5 5/11/2013 Open C4 4,344' 4,371' 4,341' 4,368' 27' 5 5/11/2013 Open C5 4,429' 4,479' 4,426' 4,476' 50' 5 5/11/2013 Open C -6 4,600' 4,639' 4,595' 4,635' 39' 5 5/11/2013 Open 44 -7 BZN 4,605' 4,625' 4,601' 4,621' 20' 4 9/10/1967 Cmt Szqd CZN57 4,670' 4,700' 4,666' 4,696' 30' 5 5/11/2013 Open 4,720' 4,740' 4,716' 4,736' 20' 5 5/11/2013 Open C7 4,760' 4,781' 4,756' 4,777' 21' 5 5/11/2013 Open 49-4 CZN 4,807' 4,829' 4,803' 4,825' 22' 5 5/11/2013 Open 50 -0 CZN 4,869' 4,879' 4,865' 4,875' 10' 5 5/11/2013 Open 50 -3 CZN 4,897' 4,927' 4,893' 4,923' 30' 5 5/11/2013 Open CZN52 4,952' 4,957' 4,989' 4,953' 5' 5 5/11/2013 Open 50 -6 CZN 4,992' 5,021' 4,988' 5,017' 29' 5 5/11/2013 Open CZN59 5,102' 5,122' 5,097' 5,117' 20' 5 5/11/2013 Open 51 -6 CZN 5,122' 5,156' 5,117' 5,151' 34' 5 5/11/2013 Open 51 -9 CZN 5,170' 5,198' 5,165' 5,193' 28' 5 5/11/2013 Open 53 -0 DZN 5,260' 5,288' 5,254' _ 5,282' 28' 5 5/11/2013 Open DZ■52 5,328' 5,335' 5,322' 5,329' 7' 5 5/11/2013 Open 53 -8 DZN 5,360' 5,393' 5,354' 5,387' 33' 5 5/11/2013 Open 54 -5 DZN 5,424' 5,458' 5,417' 5,451' 34' 5 5/11/2013 Open 54 -9 DZN 5,492' 5,509' 5,485' 5,502' 17' 5 5/11/2013 Open 55 -7 DZN 5,542' 5,560' 5,534' 5,552' 18' 5 5/11/2013 Open 56 -1 DZN 5,587' 5,670' 5,579' 5,661' 83' 5 5/11/2013 Open 57 -2 DZN 5,700' 5,744' 5,691' 5,735' 74' 5 5/11/2013 Open 58 -1 EZN 5,798' 5,817' 5,788' 5,807' 19' 5 5/11/2013 Open 5,823' 5,837' 5,813' 5,827' 14' 5 5/11/2013 Open 58 -7 EZN 5,860' 5,875' 5,850' 5,864' 15' 5 5/11/2013 Open 5,882' 5,948' 5,871' 5,937' 66' 5 5/11/2013 Open 60 -0 EZN 5,982' 6,019' 5,970' 6,007' 37' 5 5/11/2013 Open Updated by: JLL 05/29/13 II • • Trading Bay Unit PROPOSED Monopod Well # A -7 API# 50- 733 - 20036 -00 Completed 05/14/13 RKB to TBG Hngr = 38.23' J. z L CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 1 3 3/8" 61 K -55 Butt 12.515 Surf. 1067' 9 -5/8" 40.0 K -55 Butt 8.835 Surf 4810' 7" 26 N -80 Butt 6.276 4746' 6397' Tubing: 2 -7/8" 6.4 N -80 Seal Lock 2.441 Surf 2811' ■ • 3k JEWELRY DETAIL No Depth Item A 4 1 41' 2 -7/8" Hanger Assy. 5 2 ±300' Baker SSSV 3 ±2,675' Y Block 7 4 ±2,687' Head Bolt On Discharge Slat 18 5 ±2,688' Pump DN1750, CR -CT, 46 DTG 400/400 60 CS VTHD Sl�c = 9 6 ±2,704' Intake Li I 7 ±2,706' Protector 10 8 ±2,714' Motor Maximus, RA -S 30 HP463V 42,3A = 9 ±2,724' Motor Base Plug ii = 10 ±2,824' Packer 11 ±2,855' WLEG BZN 12 6,089' EZ Drill Cement Retainer See Next Page for Perforation Data C, CZN If g IL C, CZN =} DZN 12 - EZN KB ELEV = 101' PBTD = 6,089' TD = 6,407' ANGLE thru INTERVAL = 3.2° Updated by: JLL 05/29/13 • II • • Trading Bay Unit ... PROPOSED Monopod Well # A -7 API# 50- 733 - 20036 -00 Completed 05/14/13 PERFORATION DATA Zone Top (MD) Btm (MD) Top (ND) Btm (ND) Amt SPF Date Status 2,874' 2,906' 2,873' 2,906' 32' 5 5/11/2013 Open 2,875' 2,907' 2,874' 2,906' 22' 4 9/7/1988 Open 31 -8 BZN 2,882' 2,896' 2,881' 2,895' 14' 4 8/17/1970 Open 2,920' 2,947' 2,919' 2,946' 27' 5 5/11/2013 Open 2,923' 2,947' 2,922' 2,946' 24' 4 9/8/1988 Open 2,928' 2,944' 2,927' 2,943' 16' 4 8/17/1970 Open 2,997' 3,076' 2,996' 3,075' 79' 4 9/9/1988 Open 33 -6 BZN 2,999' 3,077' 2,998' 3,076' 78' 5 5/11/2013 Open 3,044' 3,076' 3,043' 3,075' 32' 4 8/17/1970 Open 3,193' 3,242' 3,192' 3,241' 49' 5 5/11/2013 Open 3,196' 3,208' 3,195' 3,207' 12' 4 8/17/1970 Open 3,196' 3,240' 3,195' 3,239' 44' 4 9/10/1988 Open 41 -3 BZN 3,214' 3,240' 3,231' 3,239' 26' 4 8/17/1970 Open 3,282' 3,433' 3,281' 3,432' 151' 5 5/11/2013 Open 3,283' 3,435' 3,282' 3,434' 52' 4 9/11/1988 Open 3,290' 3,434' 3,289' 3,433' 144' 4 8/17/1970 Open 3,300' 3,320' 3,299' 3,319' 20' 4 9/10/1970 Cmt Szqd 3,795' 3,960' 3,793' 3,958' 65' 4 9/12/1988 Open 3,803' 3,959' 3,801' 3,957' 156' 5 5/11/2013 Open 44 -7 BZN 3,808' 3,850' 3,807' 3,848' 42' 4 8/17/1970 Open 3,820' 3,840' 3,818' 3,838' 20' 4 9/10/1967 Cmt Szqd 3,858' 3,956' 3,856' 3,954' 98' 4 8/17/1970 Open C -2 4,037' 4,097' 4,035' 4,095' 60' 5 5/11/2013 Open C -3 4,127' 4,224' 4,125' 4,221' 97' 5 5/11/2013 Open 44 7 BZN 4,125' 4,225' 4,123' 4,222' 100' 4 9/15/1967 Cmt Szqd 4,140' 4,160' 4,138' 4,157' 20' 4 9/10/1967 Cmt Szqd CZNS6 4,267' 4,335' 4,264' 4,332' 68' 5 5/11/2013 Open C4 4,344' 4,371' 4,341' 4,368' 27' 5 5/11/2013 Open C5 4,429' 4,479' 4,426' 4,476' 50' 5 5/11/2013 Open C -6 4,600' 4,639' 4,595' 4,635' 39' 5 5/11/2013 Open 44 -7 BZN 4,605' 4,625' 4,601' 4,621' 20' 4 9/10/1967 Cmt Szqd CZNS7 4,670' 4,700' 4,666' 4,696' 30' 5 5/11/2013 Open 4,720' 4,740' 4,716' 4,736' 20' 5 5/11/2013 Open C7 4,760' 4,781' 4,756' 4,777' 21' 5 5/11/2013 Open 49 -4 CZN 4,807' 4,829' 4,803' 4,825' 22' 5 5/11/2013 Open 50 -0 CZN 4,869' 4,879' 4,865' 4,875' 10' 5 5/11/2013 Open 50 -3 CZN 4,897' 4,927' 4,893' 4,923' 30' 5 5/11/2013 Open CZNS2 4,952' 4,957' 4,989' 4,953' 5' 5 5/11/2013 Open 50 -6 CZN 4,992' 5,021' 4,988' 5,017' 29' 5 5/11/2013 Open CZNS9 5,102' 5,122' 5,097' 5,117' 20' 5 5/11/2013 Open 51 -6 CZN 5,122' 5,156' 5,117' 5,151' 34' 5 5/11/2013 Open 51 -9 CZN 5,170' 5,198' 5,165' 5,193' 28' 5 5/11/2013 Open 53 -0 DZN 5,260' 5,288' 5,254' 5,282' 28' 5 5/11/2013 Open DZNS2 5,328' 5,335' 5,322' 5,329' 7' 5 5/11/2013 Open 53 -8 DZN 5,360' 5,393' 5,354' 5,387' 33' 5 5/11/2013 Open 54 -5 DZN 5,424' 5,458' 5,417' 5,451' 34' 5 5/11/2013 Open 54 -9 DZN 5,492' 5,509' 5,485' 5,502' 17' 5 5/11/2013 Open 55 -7 DZN 5,542' 5,560' 5,534' 5,552' 18' 5 5/11/2013 Open 56 -1 DZN 5,587' 5,670' 5,579' 5,661' 83' 5 5/11/2013 Open 57 -2 DZN 5,700' 5,744' 5,691' 5,735' 74' 5 5/11/2013 Open 58 -1 EZN 5,798' 5,817' 5,788' 5,807' 19' 5 5/11/2013 Open 5,823' 5,837' 5,813' 5,827' 14' 5 5/11/2013 Open 58 -7 EZN 5,860' 5,875' 5,850' 5,864' 15' 5 5/11/2013 Open 5,882' 5,948' 5,871' 5,937' 66' 5 5/11/2013 Open 60 -0 EZN 5,982' 6,019' 5,970' 6,007' 37' 5 5/11/2013 Open Updated by: JLL 05/29/13 • • Monopod Platform 2013 BOP Stack 03/12/2013 liilrn : '1/4I.ink:,. Rig Floor Bottom of air boot flange • 5' below rig floor 16" 14.72' 9.50' Pipe 11 III 111II1fii • • III Illilll I I I %I IN 3.74' Shaffer 13585M 111 111 11I Ill al 26.25' Shaffer LXT - - -- © p il 27/8 -5 Variables _ 230' 135/85M IIIM)=-1 Blind 1.76 N 11101 ` 0 I Mud Cross %1 : ' Iii1111 1111 n1 135 /85MFEX FE w/ 31/85M EFO w/ 2 1/16 5M Choke and Kill valves w/ Unbolt end connections for lines III 1111II 2.83' Dual Cameron Flex rams Itl III 11l ft 111 70' III II: III III III • Drill deck Riser 14.20' 135/85M FE X 135/85M FE i! III. III 1,11 tl I. Spacer spool 1.5' 135 /85M FEX113M III 11 l il'. III Wellhead @ 15.00' STATE OF ALASKA � ALA. OIL AND GAS CONSERVATION COMMISSION 1;1 z REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon ❑ Repair Well El Plug Perforations ❑ Perforate IS r Other M : Install ESP Performed: Alter Casing ❑ Pull Tubing 0 . Stimulate - Frac ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat. Shutdown❑ Stimulate - Other ❑ Re -enter Suspended WeII❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC 4 Development el • Exploratory ❑ 167-046 • 3. Address: 3800 Centerpoint Drive, Suite 100 Stratigraphic❑ Service ❑ 6. API Number: Anchorage, AK 99503 50- 733 - 20036 -00 • 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0018731 Trading Bay ST A -07, 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): Trading Bay Field / Hemlock Oil, Middle Kenai B Oil, Middle Kenai C Oil, Middle Kenai D, Oil • 11. Present Well Condition Summary: Total Depth measured 6,407 feet Plugs measured 6,089 (cement Ret) feet true vertical 6,389 feet Junk measured N/A feet Effective Depth measured 6,089 feet * Packer measured N/A feet true vertical 6,076 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor Surface 1,067' 13 -3/8" 1,067' 1,067' 3,090 psi 1,540 psi Intermediate Production 4,810' 9 -5/8" 4,810' 4,806' 3,950 psi 2,570 psi Liner 1,651' 7" 6,397' 6,380' 7,240 psi 5,410 psi 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# / N -80 2,811' (MD) 2,810' (TVD) Packers and SSSV (type, measured and true vertical depth) Packer: N/A SSSV: N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): CA,I�CCt JU 0 3 2,0 Treatment descriptions including volumes used and final pressure: R�1� Gtr 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 12 0 20 250 120 Subsequent to operation: 2120 510 100 150 100 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory❑ Development El • Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: Oil E1 . Gas ❑ WDSPL❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 313 -065 Contact Ted Kramer Email tkramerahilcorp.com Printed Name Ted Kramer Title Sr. Operations Engineer Signature , / d (. "' " Phone (907) 777 -8420 Date 5/30/2013 1/1/r J f RBDMS MAY 312 Form 10-404 Revised 10/2012 Submit Original Onl y J 7g 1 l J ,1 T/0 • • Trading Monopod Bay Unit 1 n SCHEMATIC Well # A -7 API# 50- 733 - 20036 -00 Completed 05/14/13 RKB to TBG Hngr = 38.23' 1 CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 1 3 3/8" 61 K -55 B utt 12.515 Surf. 1067' 9 -5/8" 40.0 K -55 Butt 8.835 Surf 4810' 7" 26 N -80 Butt 6.276 4746' 6397' Tubing: 2 -7/8" 6.4 N -80 Seal Lock 2.441 Surf 2811' ■ ■ Z JEWELRY DETAIL No Depth Item 1 41' 2 -7/8" HangerAssy. 4 2 2,761' Y Block WI ' 5 3 2,773' Head Bolt On Discharge ■ I,- 6 4 2,774' Pump DN1750, CR -CT, 46 DTG 400/400 60 CS VTHD 5 2,790 Intake 7 6 2,792' Protector IR 7 2,800' Motor Maximus, RA -S 30 HP463V 42,3A 8 8 2,810' Motor Base Plug 9 2,811' WLEG 9 = 10 6,089' EZ Drill Cement Retainer BZN See Next Page for Perforation Data C, CZN z x C, CZN = 1.- DZN 10 = EZN -e..... J KB ELEV = 101' PBTD = 6,089' TD = 6,407' ANGLE thru INTERVAL = 3.2° Updated by: JLL 05/29/13 II • • Trading Bay Unit SCHEMATIC Monopod Well # A -7 API# 50- 733 - 20036 -00 Completed 05/14/13 PERFORATION DATA Zone Top (MD) Btm (MD) Top (TVD) Btm (ND) Amt SPF Date Status 2,874' 2,906' 2,873' 2,906' 32' 5 5/11/2013 Open 2,875' 2,907' 2,874' 2,906' 22' 4 9/7/1988 Open 31 -8 BZN 2,882' 2,896' 2,881' 2,895' 14' 4 8/17/1970 Open 2,920' 2,947' 2,919' 2,946' 27' 5 5/11/2013 Open 2,923' 2,947' 2,922' 2,946' 24' 4 9/8/1988 Open 2,928' 2,944' 2,927' 2,943' 16' 4 8/17/1970 Open 2,997' 3,076' 2,996' 3,075' 79' 4 9/9/1988 Open 33 -6 BZN 2,999' 3,077' 2,998' 3,076' 78' 5 5/11/2013 Open 3,044' 3,076' 3,043' 3,075' 32' 4 8/17/1970 Open 3,193' 3,242' 3,192' 3,241' 49' 5 5/11/2013 Open 3,196' 3,208' 3,195' 3,207' 12' 4 8/17/1970 Open 3,196' 3,240' 3,195' 3,239' 44' 4 9/10/1988 Open 41 -3 BZN 3, 3,240' 3,231' 3,239' 26' 4 8/17/1970 Open 3,282' 3,433' 3,281' 3,432' 151' 5 5/11/2013 Open 3,283' 3,435' 3,282' 3,434' 52' 4 9/11/1988 Open 3,290' 3,434' 3,289' 3,433' 144' 4 8/17/1970 Open 3,300' 3,320' 3,299' 3,319' 20' 4 9/10/1970 Cmt Szqd 3,795' 3,960' 3,793' 3,958' 65' 4 9/12/1988 Open 3,803' 3,959' 3,801' 3,957' 156' 5 5/11/2013 Open 44 -7 BZN 3,808' 3,850' 3,807' 3,848' 42' 4 8/17/1970 Open 3,820' 3,840' 3,818' 3,838' 20' 4 9/10/1967 Cmt Szqd 3,858' 3,956' 3,856' 3,954' 98' 4 8/17/1970 Open C -2 4,037' 4,097' 4,035' 4,095' 60' 5 5/11/2013 Open C -3 4,127' 4,224' 4,125' 4,221' 97' 5 5/11/2013 Open 44 -7 BZN 4,125' 4,225' 4,123' 4,222' 100' 4 9/15/1967 Cmt Szqd 4,140' 4,160' 4,138' 4,157' 20' 4 9/10/1967 Cmt Szqd CZNS6 4,267' 4,335' 4,264' 4,332' 68' 5 5/11/2013 Open C4 4,344' 4,371' 4,341' 4,368' 27' 5 5/11/2013 Open C5 4,429' 4,479' 4,426' 4,476' 50' 5 5/11/2013 Open C -6 4,600' 4,639' 4,595' 4,635' 39' 5 5/11/2013 Open 44 -7 BZN 4,605' 4,625' 4,601' 4,621' 20' 4 9/10/1967 Cmt Szqd CZNS7 4,670' 4,700' 4,666' 4,696' 30' 5 5/11/2013 Open 4,720' 4,740' 4,716' 4,736' 20' 5 5/11/2013 Open C7 4,760' 4,781' 4,756' 4,777' 21' 5 5/11/2013 Open 49 -4 CZN 4,807' 4,829' _ 4,803' 4,825' 22' 5 5/11/2013 Open 50 -0 CZN 4,869' 4,879' 4,865' 4,875' 10' 5 5/11/2013 Open 50 -3 CZN 4,897' 4,927' 4,893' 4,923' 30' 5 5/11/2013 Open CZNS2 4,952' 4,957' 4,989' 4,953' 5' 5 5/11/2013 Open 50 -6 CZN 4,992' 5,021' 4,988' 5,017' 29' 5 5/11/2013 Open CZNS9 5,102' 5,122' 5,097' 5,117' 20' 5 5/11/2013 Open 51 -6 CZN 5,122' 5,156' 5,117' 5,151' 34' 5 5/11/2013 Open 51 -9 CZN 5,170' 5,198' 5,165' 5,193' 28' 5 5/11/2013 Open 53 -0 DZN 5,260' 5,288' 5,254' 5,282' 28' 5 5/11/2013 Open DZNS2 5,328' 5,335' 5,322' 5,329' 7' 5 5/11/2013 Open 53 -8 DZN 5,360' 5,393' 5,354' 5,387' 33' 5 5/11/2013 Open 54 -5 DZN 5,424' 5,458' 5,417' 5,451' 34' 5 5/11/2013 Open 54 -9 DZN 5,492' 5,509' 5,485' 5,502' 17' 5 5/11/2013 Open 55 -7 DZN 5,542' 5,560' 5,534' 5,552' 18' 5 5/11/2013 Open 56 -1 DZN 5,587' 5,670' 5,579' 5,661' 83' 5 5/11/2013 Open 57 -2 DZN 5,700' 5,744' 5,691' 5,735' 74' 5 5/11/2013 Open 58 -1 EZN 5,798' 5,817' 5,788' 5,807' 19' 5 5/11/2013 Open 5,823' 5,837' 5,813' _ 5,827' 14' 5 5/11/2013 Open 58 -7 EZN 5,860' 5,875' 5,850' 5,864' 15' 5 5/11/2013 Open 5,882' 5,948' 5,871' 5,937' 66' 5 5/11/2013 Open 60 -0 EZN 5,982' 6,019' 5,970' 6,007' 37' 5 5/11/2013 Open Updated by: JLL 05/29/13 • • Hilcorp Alaska, LLC • Hiieorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date A -07 50- 733 - 20036 -00 167 -046 4/24/2013 5/15/2013 '#t° 64/24f Rigging up. 0' -T ursday Skid rig south and center over well A -07. Secure rig and install seismic clamps. Modify walkways and handrails. Move drilling conex and drill line spool. Install flow lines and walkway to welding shop. Install cross over spool on 13 -5/8" riser. Remove production plumbing from tree. Change out tree cap flange. Remove tree flow line and rig up circulating lines to 9 -5/8" annulus. * *Studs had to be cut to remove piping from tree. Tubing = 200 psi, 9 -5/8" = 45 psi, 13 -3/8" = 110 psi. Rig up 2 -7/8" riser to rig floor from tree cap. Rig up PESI. RIH with tubing punch (1- 11/16 ", 13 shots x 3/8 "). Not able to get past GLM #3 @ 2,755'. Collar locator failed. POOH and check (thick tar on tools). RIH to GLM #2 @ 2,593' and collar locator failed again. POOH and rehead CCL (thick tar on tools). RIH and tag top of GLM #3. Punch holes 2,735' - 2,739'. Tubing pressure 260 psi /annulus 40 psi. Pressures did not change upon detonation. POOH. All shots fired. Rig down PESI. 64/26/13 - Fria R /up to pump dn tbg. Pump FIW w/ 3% KCL dn tbg. Bring pump on line @ 3 bpm @ 85 psi, and staged rate t/ 8 Bpm @ 1030 psi attempting to get returns on 9 -5/8" annulus. Pumped total of 200 bbls w/ no returns but did record 90 psi increase in pressure on 9- 5/8" / Dn pump strong vac / shut in. While Building 70 bbl sized salt pill, installed ground wire on flow lines. Service rig. Install cellar stairs & landing / shorten air intake ducting for rigs traction motors. Work on hand rail safety chains. Service drlg line anchor load cell. House clean rig. Tbg = 80 psi / 9 -5/8" = zero / 13 -3/8" = 150 psi. Bull head 70 bbl sized pill @ 3 bpm @ 75 psi / slow pump @ 30 bbls away t/ 1.5 bpm @ 55 psi / slow pump @ 55 bbls away t/ 1 bpm @ 40 psi, chased pill w/ 16 bbl FIW w/ 3% KCL @ 1 bpm @ 42 psi & falling t/ 25 psi / Dn pump TBG = strong vacuum 9 -5/8" = zero / 13 -3/8" = 100 psi. While building the last 35 bbl of sized salt on board, cut penetration in drill deck for mouse hole. House clean. Wait on boat for Mud products. House clean. Adjust accumulator hoses in hose tray. Service choke manifold. Work on plumbing deluge line. Off load work boat. Build 35 bbl sized salt pill. Continue with housekeeping detail. Tubing psi = 180psi / Annulus psi =0 psi. Line up and pump 75 bbl sized salt pill down tubing and chase with 16 bbls 3% KCL. Pumped at 3 BPM /90 psi. Pressure did not change on tubing, annulus increased to 80 psi. Tubing on strong vacuum. Monitor pressures on tubing and annulus while building third 70 bbl sized salt pill. Daily FIW w/ 3% KCL losses = 286 bbls. Total FIW w/ 3% KCL losses = 286 bbls - Total Sized salt pill Pumped = 70 bbls 9 -5/8" X 13 -3/8" = 150 psi / 13 -3/8 X 20" = 0. 04/27/13 SatUj' Continue build 3rd sized salt pill @ +/- 70 bbls / R /up to pump dn 9 -5/8 ", Tbg = strong vacuum, 9 -5/8" = 120 gas, 13 -3/8" 10 psi. Test line 1000 psi (ok). Pump FIW w/ 3% KCL dn 9 -5/8" @ 5 bpm @ 240 psi @ 80 bbl away (Rig lost power) shut in well. Fire up # 3 cat trouble shoot SCR ( #3 cat went dn & tripped off SCR ). Resume Pumping dn 9 -5/8" @ 5 bpm & t/ 1000 psi w/ total 160 bbls. Tbg 400 psi Gas ( appears pills starting to take) 9 -5/8" = 850 psi gas 13 -3/8" zero. Bleed gas cap off 9 -5/8" t/ production (fluid packed 9- 5/8 "). Line up on Tbg, bull head 14.5 bbls FIW w/ 3% KCL dn tbg ® 3 bpm @ 200 psi (Tbg clear & building psi). Bull head 33 bbls sized salt pill @ 3 bpm w/ squeeze psi of 790 psi / displace w/ 17 bbls of FIW w/ 3% KCL @ 1.5 bpm final displacement psi 658 psi / dn pump & monitor bleed dn to zero in 10 min. Pump FIW w/ 3% KCL dn tbg taking returns to production & sweep annulus w/ 260 bbls w/ clean returns / dn pump & monitor bleed dn 493 psi t/ zero in 11 min. Wait (1) hr to get estimated lost rate (2.7 bbls to fill pipe & get fluid returns = est. 2.7 bph loss rate). Install BPV. Nipple down tree. Verify lift threads to be 2 -7/8" EUE 8 round. Cut out 4 remaining studs on tubing spool flange with Sawzall. Set ESP spool and adapter spool in well head room. Set riser. Nipple up BOPE. Function test BOPE. Make up test joint. Fill stack. Test BOPE as per sundry, 250L/2500H. Daily FIW w/ 3% KCL losses = 316 bbls. Total FIW w/ 3% KCL losses = 602 bbls - Total Sized salt pill Pumped = 178 bbls. 9 -5/8" X 13 -3/8" = 80 psi. 9,4/28/13`'- Sunda} Continue test BOPE as per sundry 250L / 2500H (good test no failures). Witness of test waived by Lou Grimaldi, AOGCC. R /dn test equipment. R /up 5" landingjt to pump & pull. Pump FIW w/ 3% KCL dn tbg @ 2 bpm took 128 bbls to get returns (no oil cap ) wait 15 min & refill w/ 19 bbls est 76 bph loss rate. B.O.L.D.S while circ. Continue Juice up 38 bbl sized salt pill t/ 70+ bbls. R /up return line from 9 -5/8" t/ choke manifold. Fluid pack 9 -5/8" w/ 74 bbls. Pump #4 sized salt pill @ 3 bpm @ 15 bbls away. Shut in 9 -5/8" & bull head @ 40 bbls away slow rate t/ 2 bpm / total pill pumped 73 bbls / displace pill w/ 10 bbls @ 1 bpm w/ 60 -80 psi increase in pressure (260 psi t/ vacuum in one min). Wait one hr / start building SS pill #5. Refill well & establish loss rate @ 11 bph. Pull hanger loose & work pipe t/ 72k over. Bring pump on line & continue work pipe t/ 72k over & released pkr ( hanging weight 18k heavy) & pull pkr up hole +/- 8'. Circ btm /up & remove pkr gas @ 5 Bpm @ 680 psi. Monitor static well on trip tank ( Loss rate @ 3.4 BPH). POOH I /dn gas lift completion. Daily FIW w/ 3% KCL losses = 302bbIs. Total FIW w/ 3% KCL losses = 904 bbls - Total Sized salt pill Pumped = 253 bbls. 9 -5/8" X 13 -3/8" = 80 psi. • • Hilcorp Alaska, LLC . Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date A -07 50- 733 - 20036 -00 167 -046 4/24/2013 5/15/2013 in 4. t4/29.3- Monday �.. 3 „ < ... Continue POOH I /dn gas lift completion (had to pump out & circ out gas last 27 jts to keep from unloading tbg) full recovery. Monitor well on trip tank 1.2 BPH loss rate while clear & clean floor & install wear ring. M /up Bha #1 8-1/2" bit (open) + (2) 7" junk bsk + 9 -5/8" csg scrapper + bit sub w/ float + 6 -1/2" bumper sub + 6 -1/4" oil jar + pump out sub + (9) 6 -1/2" dc's + Xo = 316.80'. RIH to 3,601'. Tagged hard fill. Lay down 13 joints drill pipe. RIH 4 stands to 3,600'. Pick up Kelly. Wash and ream sand fill 3,601' - 3,775'. P/U 110K, S/O 110K, Rt Wt 110K @ 20 RPM /2000 ft /Ibs. 8 BPM /220 psi. Wash and ream with 10 - 15K weight on bit. Pump sweep @ 8 BPM /220 psi. Recovered +/ -8 bbls of sand. POOH laying down 16 joints to be able to wash and ream with Kelly. POOH to remove casing scraper and add boot baskets. Static loss rate = 4.8 BPH., Daily FIW w/ 3% KCL losses = 44.7 bbls. Total FIW w/ 3% KCL losses = 948 bbls - Total Sized salt pill Pumped = 253 bbls. 9 -5/8" X 13 -3/8" = 0 psi. 04/30/13 - ` 4 ' .: Work BHA L /dn Chk & clean BHA #1 (Recovered 1 -1/2" Gal scale, sand & iron in junk bsk's). P /up BHA # 2. P /up Kelly & chg /out Kelly spinner & set back same [Hole taking 8.5 BPH by the time the Kelly was set back]. RIH t/ 3,764', filling pipe at 2,200'. [Hole got up to taking 12.5 BPH while RIH]. Kelly up & clean out fill f/ 3,774' t/ 3,901', Pumping 9.4 BPM, 350 psi, 60 RPM, Pumped 20 bbl high vis sweep and circ it out. Had to slow pump down to 1 BPM to keep from going over shakers. Recovered about 10 bbls sand. Clean out fill f/ 3,901' t/4,540'. Pump sweeps as necessary. Recovered approximately 40 bbls of sand total. Parameters: 117K P/U wt, 115K S/O wt, 116 Rt wt /40 RPM and 3500 ft/Ibs. 9 BPM /350 psi. Drill on CIBP @ 4,540' - 4,541'. 15K - 25K WOB. 20 - 60 RPM. Establish loss rate = 2.5 BPH. POOH for bit inspection and to clean out boot baskets. Daily FIW w/ 3% KCL losses = 167 bbls. Total FIW w/ 3% KCL losses = 1115 bbls - Total Sized salt pill Pumped = 253 bbls. 9 -5/8" X 13 -3/8" = 0 psi. 000/0- Wednesday . k. While sitting still monitoring loss rate at 4,520' pipe became hung up. M/U head pin and break circ. Pull pipe free with a 30k over pull. Circ and work pipe 1 -1/2 bottoms up. Got back approx 1 bbl of sand. POOH to above top perfs at 2,882'. Monitor well, 9+ BPH loss rate. Pump and spot a 40 bbl size salt pill. POOH. Break and clean boot baskets. Recovered 20 Ibs metal and 10 gal sand. Bit came out in good shape. [Hole taking 8 BPH]. Make up boot baskets [Hole taking 6 BPH]. P/U Kelly and run it in hole. Pull air motor and found broken gear, fish out broken pieces. Replace motor and set Kelly back. Break bit, M/U mill and RIH 4,491'. Fill pipe and wash down to 4,536' where we tagged fill. Clean out fill f/ 4,536' t/4,565'. Broke through CIBP. Circulate gas out of hole. Took three bottoms up @ 9 BPM /450 psi. Highest gas was 600 units but 'burping' over bell nipple. Wash and ream 4,565' to 4,707'. Gas went to 500 units. Pick up off bottom and circulate out gas @ 5 - 9 BPM /450 psi. Again gas was 'burping' over bell nipple. 700 units was highest gas units. Mill 4,705' - 4,707' (very hard) and wash and ream 4,707' - 4,743'. Gas units rose to 700 units then tapered off to less than 150 units. Mill 4,743' - 4,747'. Milled very rough and fast so have doubts about this being a CIBP. Seemed more like junk and remnants of the CIBP from 4,540'. Circulate sweep @ 9 BPM /500 psi. Establish static loss rate @ 3.2 BPH. POOH to 2,800'. (Laid down 4 joints). Establish static loss rate @ 4.0 BPH. Continue POOH to BHA. Change out BHA. P/U BHA #4. (6 -1/8 bit, bit sub, 1 ea. 4 3/4 drill collar, XO, 5 ea. boot baskets, bit sub, bumper sub /oil jars, pump out sub, XO 9 ea. 61/2 drill collars, XO = 355.81). Daily FIW w/ 3% KCL losses = 108 bbls. Total FIW w/ 3% KCL losses = 1222 bbls - Total Sized salt pill Pumped = 293 bbls. 9 -5/8" X 13 -3/8" = 0 psi. x , 05/Q2/3 - Thursday s. KK .xs< x ��*Ai Finish picking up BHA #4. [Recovered 163 Ibs metal & 3 gal of sand from boot baskets]. RIH to 4,712', Hole taking 3.6 BPH. Wash down to top of liner or BP at 4,747'. Drill on BP or junk f/ 4,747' t/ 4,755'. Chase f/ 4,755' t/ 4,780' where we tagged the top of the liner with 7" boot basket. Pumping 8 to 10 BPM, at 500 to 700 psi. Getting gas back most the time with the highest units of 623. Circulate at 5 BPM /200 psi to allow gas to migrate from 7" liner. Then circulate @ 10 BPM /500 psi to attempt to get gas units below 200. Gas units down to 220 while circulating @ 10 BPM. Recovered 55 Ibs of metal from shaker magnets. Establish static loss rate @ 4 BPH. POOH to 2,800'. Establish loss rate @ 4.0 BPH. POOH to BHA. Work BHA. Clean boot baskets. Recovered 76.5 Ibs of metal. Mill tooth bit in excellent shape for rerun. Pick up BHA #5. (6" bit, 5 ea. 4 3/4" boot baskets, bit sub with float, bumper sub /oil jars, 12 ea. 4 3/4" DC's, 33 jts 3 1/2" DP, XO = 1431.98). Static loss rate = 2.0 BPH., Daily FIW w/ 3% KCL losses = 87 bbls. Total FIW w/ 3% KCL losses = 1309 bbls - Total Sized salt pill Pumped = 293 bbls. 9 -5/8" X 13 -3/8" = 0 psi. • Hilcorp Alaska, LLC • Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date A -07 50- 733 - 20036 -00 167 -046 4/24/2013 5/15/2013 •13- FridaH , Finish P/U BHA #5 to 3 -1/2 DP. PU Kelly and change out Kelly spinner. Test spinner and set Kelly back. Finish P/U 3 -1/2 DP and RIH t/ 4,745', just above liner top. Circ to check for gas. Had 700 units of gas on bottoms up. RIH to 5,760' where we tagged junk and fill. Wash and ream f/ 5,760' t/ 5,804'. Had increase in flow due to gas bubble and we had to P/U and slow the pumps down for about 10 min. Had a high of 650 units of gas. Wash and ream f/ 5,804' t/ 6,098'. Did not see any indication of CIBP until 6,098'. Drilled at this depth for 30 minutes with little progress. 10K -15K WOB, 40 RPM /4 - 8K torque. 9.5 BPM /1200 psi. Circulate high vis sweep @ 9.5 BPM /1200psi. Marginal amount of sand with sweep. Establish static loss rate @ 3.5 BPH while setting Kelly back. POOH with BHA #5 to 2,800'. Check static loss rate = 2.0 BPH. Continue POOH. Daily FIW w/ 3% KCL losses = 118 bbls. Total FIW w/ 3% KCL losses = 1472 bbls - Total Sized salt pill Pumped = 293 bbls. 9 -5/8" X 13 -3/8" = 100 psi. Recovered 68 Ibs of metal off ditch magnets. Recovered total of 123 Ibs from ditch magnets. Saturday _ Continue POOH. Break dn boot baskets and clean same. Recovered 81 Ibs of metal. Make up BHA #6 - Bit, 2 boot baskets, 7" csg scraper, bit sub [float], bumper sub, oil jars, 12 DCs, 33 jts 3 -1/2 DP, Dbl pin sub, 9 -5/8 csg scraper, 2 7" boot baskets, bit sub = 1437.46. RIH t/ 6,075'. Fill pipe and break circ. Work dn and tag fill at 6,090'. Work junk baskets and clean out to 6,098'. Had to drill down last 2', acted like junk. Also packed off where we had to shut the pump down and get it to free up by rotating. Pump 11 bbl high vis sweep and circ hole clean. Got back a trace of sand over shakers. Work pipe while circ. Monitor well. Fluid loss of 0 BPH. Blow down Kelly and set back same. Went to POOH and pipe was hung up, Pull up to 75k over with no movement. Set pipe in slips and break free with rotation. Rig up headpin and cmt hose and pump out f/ 6,075' t/ 6,012'. Ended up laying dn 3 singles. Continue POOH with spots that pulled 20k over up to 5,910'. POOH to 1,532' - monitor well -1 bph loss. Continue POOH. L/D C/O BHA junk baskets / scrapers - recover 38 Ibs metal from junk baskets - looks like BP metal and pieces of slick line wire. R/U Pollard eline. RIH with GR / CCL tag at 6,101' ELM (un corrected). Log up from 6,101' with GR / CCL. Daily FIW w/ 3% KCL losses = 56 bbls. Total FIW w/ 3% KCL losses = 1528 bbls - Total Sized salt pill Pumped = 293 bbls. 9 -5/8" X 13 -3/8" = 20 psi. Recovered 41 Ibs of metal off ditch magnets. Recovered total of 164 Ibs from ditch magnets. 05/05/13 - Sunday '. Rig dn Pollard a -line. Hole is taking 3.4 BPH. Pull wear ring, flush stack and drain same. Rig up to test BOPs. Test all BOP equip to 250 psi low and 2500 psi high, Test bag and upper rams on 2 -7/8" and 5 ". Test was witnessed by Bob Noble, No failures! Hole taking 3.4 BPH. Clear floor of test equip and extra tools - grease blocks- crown -draw works - Kelly. Cut 60' drilling line. PU / MU HES - RTTS -9ea 6.5 DC -xo -9 5/8 RTTS- xo -l2ea 4.75 DC -33 ea 3.5 DP- 1681.35'. RIH with RTTS and set at 2,723' with CE at 2,730'. Prep and test csg - purge choke and lines - test 9 -5/8 csg to 1600 psi - 30 mins on chart. POOH to the RTTS stand back DP / DC. PU / MU storm valve to RTTS. RIH set RTTS / Storm Valve at "'90' release and std back DC. Pressure test RTTS / SV to 1450 psi 10 mins good test. ND BOPE and riser to change out DSA and tbg adpt spool. Daily FIW w/ 3% KCL losses = 68 bbls. Total FIW w/ 3% KCL losses = 1596 bbls - Total Sized salt pill Pumped = 293 bbls. 9 -5/8" X 13 -3/8" = 40 psi. Recovered 0 lbs of metal off ditch magnets. Recovered total of 164 lbs from ditch magnets. X15/06/13 '- Mond .._. 4 -,, Break wellhead bolts loose by using a jack to push them dn through the flange. Raise stack and install new ESP spool on wellhead. Tighten spool and test to 2,500 psi, Good test. Set in spacer spool. Set stack back down and nipple up same - install bell nipple - secure stack - function BOPE - clean / organize work area. Test csg spools to 1500 psi 10 mins - no leaks. Set test plug - purge choke and lines - shell test stack to 250psi 5 mins good / 2,500psi 5 mins good on chart - pull test plug install wear ring. PU / MU HES RTTS /Storm packer retrieving tool. RIH 1 std engage and release RTTS. Monitor well - well took 37 bbls fluid after releasing RTTS. LD RTTS and retrieving tools - stand back DC. MU / BHA #8, Bit, 5 boot baskets, bit sub [float], bumper sub, oil jars, 12 DCs, 33 jts 3 1/2 DP, xo = 1431.98'. RIH with clean out BHA. Daily FIW w/ 3% KCL losses = 31 bbls -1.3 bph - Total FIW w/ 3% KCL losses = 1626 bbls - Total Sized salt pill Pumped = 293 bbls. 9 -5/8" X 13 -3/8" = 20 psi. Recovered 0 Ibs of metal off ditch magnets. Recovered total of 164 Ibs from ditch magnets. Hilcorp Alaska, LLC Hilcorp Alaska, LLC Well Operations Summary Well Name API Number lWell Permit Number Start Date End Date A-07 50-733-20036-00 167-046 4/24/2013 5/15/2013 �:• .; -,u`es ,y ' RIH with boot basket assembly. Tag fill or junk at 6,090'. Work junk baskets and clean to 6,098'. Circ hole clean. Put 2 drums [110 gals] of bleach in system and circ around system and hole 2 circulations. Short trip 10 stds to check for fill. Had 5' of fill when we got back in the hole. Clean out fill and circ while production repaired their shipping pump. Pump to production with #2 pump at 4.5 BPM until we had 120 bbls away. Then start pumping new 3% KCL down hole w/ #1 pump at 4.5 BPM. Maintain rate on both pumps until new KCL reached top of the 7" liner. Then raise the rate on #1 pump to 6 BPM. Pump 438 bbls and returns were clean. Continue pumping w/ #2 pump to production until we started to suck air. Shipped 667 bbls to Trading Bay. Monitor well for losses. Well taking 0 BPH. POOH with clean out BHA - rack back Kelly - cleaning pits - work boat - change out elevators to 3-1/2", LD BHA - stand back DC - break off bit - recover 99 lbs metal from junk baskets same type metal we have been seeing. Hole taking 3.8 BPH. RU Pollard eline with HES - TMD-3D pulse neutron tool - rehead rope socket - swap tool components and chip module around before tools were able to communicate. Fluid loss -4 bph. RIH wit HES TMD 3D logging tool. Daily FIW w/ 3% KCL losses = 31 bbls-1.3 bph - Total FIW w/ 3% KCL losses =1626 bbls - Total Sized salt pill Pumped = 293 bbls. 9-5/8" X 13-3/8" = 0 psi. Recovered 0 lbs of metal off ditch magnets. Recovered total of 164 lbs from ditch magnets. 05/08/13 - Wednesday` Run TMD-31) Pulse Neutron Log. Finished running log at 1300 hrs. Let tool cool down and rig down E-Line. Hole taking 3.5 BPH. RIH with 4-3/4"" DCs and 3-1/2" DP out of derrick. POOH laying everything down. R/U Pollard eline and HES EZ Drill. RIH with EZ Drill tag bottom at 6.093'. P/U 1' and set EZ Drill with btm at 6,092'. CE at 6,091' - top at 6,089'. Check set to verify plug in place. POOH. R/D Pollard/HES. Prep floor to pick up 2-7/8" tbg. R/U WOT to run 2-7/8 tbg. P/U & M/U 2-7/8" tbg a single at a time and RIH. Service rig. POOH standing back 2-7/8" tbg in derrick. Hole taking 6 BPH. Daily FIW w/ 3% KCL losses = 92 bbls-3.8 bph - Total FIW w/ 3% KCL losses =1802 bbls - Total Sized salt pill Pumped = 293 bbls. 9-5/8"" X 13-3/8"" = 0 psi. Recovered 0 lbs of metal off ditch magnets today and 164 lbs total. Recovered 477.5 lbs metal total." 05/09/13x- Thursday n`h Finish POOH w/ 2-7/8" completion tbg and standing it back on off drillers side. Hole taking 5.6 BPH. Ship wash water to pill pit. Ship wash water to pipeline with #2 mud pump, keeping water going to pill pit with diaphragm pump. Flush pit, lines, and pump with FIW. Ended up shipping 81 bbls to Trading Bay. Hole taking 6.5 BPH. Blow down and rig down transfer and circ lines. Finish cleaning solids out of the pits and building 3% KCl. Hole taking 7 BPH. Perform rig maintenance while waiting on third party tools (TCP guns). Put new head on #3 Cat. Change oil and test run. Shorten hopper discharge line in #1 pill pit. Pull drwks guards, inspect and adjust brakes. Re-wire shut downs on #4 motor. Hole taking 6 BPH. Continue with rig maintenance while waiting on third party tools (TCP guns). M/U connections for test jt. R/U and FCO test pump for BOPE test. Finish cleaning debris from #1 pill pit. Transfer fluid from reserve pit to # 1,3,4. Building pit volume of new 3% KCL. PT spare 2" valves, grease choke manifold. Clean/ organize rig floor. Remove lift subs from floor. Clean / organize cellar. Remove and re-install 2" 1502 connections on hi pressure hoses -7.5 bph fluid loss since 1800 hr. Continue with rig maintenance while waiting on third party tools (TCP guns). Building pit volume total 160 bbls. Clean / organize deck - prep deck for pert guns. Rig down jet heaters and heat trunks on rig floor - fluid loss to well since 2400 hrs between 7.5 bph to 9.0 bph - current at 9 bph. Daily FIW w/ 3% KCL losses = 168 bbls-7.0 bph - Total FIW w/ 3% KCL losses = 1970 bbls - Total Sized salt pill Pumped = 293 bbls. 9-5/8"" X 13-3/8"" = 0 psi. Recovered 0 lbs of metal off ditch magnets today and 164 lbs total. Recovered 477.5 lbs metal total. 05/10/1= friday, ;t Perform rig maintenance while waiting on tools. Hole taking 9+ BPH. RIH with 5" DP to 2,873', circ bottoms up. Pump and spot 26 bbl size salt pill on top of perfs. POOH. Flush stackout and pull wear ring. Rig up line from trip tank to annulus valve. Hole taking 5 BPH. P/U 2-7/8" test jt and rig up to test BOPs. Couldn't get test plug to hold. Pull test plug and inspect o-ring seals. Seals looked ok. Dope up good and run back in. M/U Dart-TIW-PI Sub-test pump to manifold- fluid loss to well 7 bph. Test BOPE 2-7/8" and 5" rams 250 psi low / 2500 psi high as per HAK - Kuukpik - AOGCC procedures - no failures. Witness of test waived by Jim Regg, AOGCC. L/D test jts and install wear bushing. R/D all test equip - clean floor - prep to run TCP guns. Fluid loss 3.0 bph. RIH with HES TCP guns dressed as 4- 5/8" 5 spf-39 g millennium charge-60 deg phase - to perf intervals - 2,860-2,892/2,909-2,936/2,987-3,065/3,184-3,233/3,273- 3,424/3,793-3,949/4,028-4,088/4,118-4,215/4,257-4,325/4,334-4,361/4,417-4,467/4,590-4,629/4,664-4,694/4,712-4,732/4,753- 4,774/4,803-4,825/4,884-4,874/4,892-4,922/4,943-4,948/4,985-5,014/5,097-5,151/5,162-5,180/5,258-5,286/5,325-5,332/5,356- 5,389/, 5,422-5,456/5,492-5,509/5,542-5,560/5,583-5,666/5,700-5,774/5,798-5,817/5,823-5,837/5,860-5,875/5,882-5,948/5,982- 6,019. Fluid loss 3 bph. Daily FIW w/ 3% KCL losses =127 bbls- 5.3 bph - Total FIW w/ 3% KCL losses = 2097 bbls - Total Sized salt pill Pumped= 319 bbls. 9-5/8"" X 13-3/8"" = 0 psi. Recovered 0 lbs of metal off ditch magnets today and 164 lbs total. Recovered 477.5 lbs metal total. • . Hilcorp Alaska, LLC Hilcorp Alaska, LLG Well Operations Summary Well Name API Number Well Permit Number Start Date End Date A -07 50- 733 - 20036 -00 167 -046 4/24/2013 5/15/2013 • /13 - Y. ay RIH picking up Halliburton perf guns with crane. Have approx 70% of the guns picked up. Hole taking 3 BPH. P/U xo to perf guns and secure well. Shut down rig power [CATS] to allow production to have more water pressure to bring everything back on line. RIH picking up Halliburton perf guns with crane. Run 143 guns, P/U firing head, 1 jt 2 -7/8" tbg, ported fill disk sub, 1 jt 2 -7/8" tbg, RA marker, and 2 XOs. Total= 3304.03. Hole taking 3 BPH. RIH w/ 5" DP to 6,029'. R/U Pollard eline - RIH correlate perf depth with GR /CCL tie in log dated 5/5/13, space guns out with DP pup jts. M/U bar drop and circulating subs. PJSM; Kuukpik- HES -HAK - roles and responsibilities for dropping bar to fire guns - drop bar at 2010 hrs and fire guns on depth as per perf design - good surface indication guns fired. Close annular, open HCR choke. Monitor fluid level with Echometer dropped 195 in 1 min- 320' in 5 mins- 400' in 10 mins. On line - circ at 8 bpm 550 psi thru open choke -35 bbls to load tbg and total 210 bbl pumped. S/D pump. Perf gun gas at surface - no well bore gas units at surface. CBU at 5 bpm -150 psi - total 142 bbls - monitor well 30 mins - 20 bph loss and gun gas slowing down - no well bore gas units at surface. CBU at 7 bpm - 300 psi - total 160 bbls - monitor well 30 mins 18 bph loss - no gun gas at surface - no well bore gas units at surface. Pump 20 bbl sized salt pill -7 bpm -350 psi - spot at 2,752'. Monitor well - fluid loss at 14 bph. Break off bar drop -circ subs- fluid loss at 12.6 bph. POOH with DP. Fluid loss at 11 bph. L/D - xo- 2 -7/8" tbg- firing head - retrieved drop bar. M/U safety jt for guns 2 -7/8" tbg - fluid loss at 9 bph. POOH. L/D TCP guns with crane - allowing guns to drain of fluid - fluid loss 8.5 bph. 15 guns L/D at report time. Daily FIW w/ 3% KCL losses =193 bbls- 8bph - Total FIW w/ 3% KCL losses = 2290 bbls - Total Sized salt pill Pumped = 339 bbls. 9 -5/8 " X 13 -3/8 "" = 0 psi. Recovered 0 Ibs of metal off ditch magnets today and 164 Ibs total. Recovered 477.5 Ibs metal total. ©�" 12/13-Sunday .: Lay down shot Halliburton pert guns. [Fluid loss at 0700 hrs 9 BPH] All shots fired. Top shot was at 2,860' and bottom shot was at 6,019'. The last 300' of guns had heavy oil on them. [Fluid loss at 1500 hrs 8 BPH]. Clear rig floor of pert tools. Prep loads for the boat and clean up oil residue from guns. Load out 8 Halliburton gun baskets and Halliburton tools on boat. Bring on board all the Schlumberger ESP equip. and spot in position. Unload mud products, and put transfers and backloads on boat. [Pull wear bushing]. Test SLB Y tool 500 psi 5 min ok. PU / MU ESP assy- motor - protector- intake -adv. gas handler -pump- discharge. M/U Y tool. Fluid loss 8.6 bph. Continue M/U ESP assy. Hang flat pack and ESP sheaves. M/U Shroud. Purge flat pack lines. Install lines /cable on pump meg test /calibrate sensor. Install pump into shroud. Fluid loss 6.8 bph. M/U Y tool by -pass tbg. Fluid loss 6.5 bph. Daily FIW w/ 3% KCL losses = 222 bbls- 9.2 bph - Total FIW w/ 3% KCL losses = 2290 bbls - Total Sized salt pills Pumped = 339 bbls. 9 -5/8 "" X 13 -3/8 "" = 0 psi. Recovered 0 Ibs of metal off ditch magnets today and 164 Ibs total. Recovered 477.5 Ibs metal total. r/1 - Monday. .w. Continue making up Y -Tool on ESP. Hole taking 8 BPH. Run ESP in the hole on 2 - 7/8" tbg out of derrick installing clamps as per procedure. RIH 8 stds, [821']. Test pressure lines and the top pressure line or the pump discharge pressure wasn't increasing with the depth. Decided to POOH and check line. Everything checked out ok. Hole taking 8 BPH. RIH with ESP. Had issues with the air tool that we put the cannon clamps on with. This cost us at least 1 hr running time. Run 281/3 stds of 2 -7/8" tbg [2762.94] and PU tbg hanger. Hole taking 8 BPH. [Up wt 34k Dn wt 34k]. Cut and splice electric cable to hgr. M/U flat pack lines to hgr. Drain stack. R/D cable and flat pack sheaves. Meg test motor. Land hgr w/ BPV installed. PUW 33k / SOW 34k / Blocks 15k - LD 2 singles 2 -7/8" tbg to the deck. Ran 45 Cannon clamps -12 steel bands - tbg tail at 2,811'. ND BOPE. Clean out mud box. ND bell nip. LD mouse hole on deck. RU BOPE crane - un bolt and move stack. RU / PU slings. ND riser and spacer spools. Remove pitcher nip - flow line - gas buster flow line. H/U P/U slings to riser - break studs on well head -pull riser thru rotary table and LD on deck. Remove spacer spools from well head room. NU wellhead and tree and torque to specs. Get tree valves in wellhead room and install on tree. Prep to skid rig. Pull rig floor landing - remove hand rails - hurricane clamps from top /btm sections of sub base. Pump out trip tank and flush with water. Remove draw works traction motor intake trunk. Pull handrails. Tested tbg head adapter, neck and hgr seals, ESP penetration -chem inj line to 5000 psi /15 mins. Release rig from A -07 at 0600 5/14/13. Daily FIW w/ 3% KCL losses =125 bbls- 8.1 bph - Total FIW w/ 3% KCL losses = 2637 bbls - Total Sized salt pills Pumped = 339 bbls. 9 -5/8 " X 13 -3/8 "" = 0 psi. Recovered 0 Ibs of metal off ditch magnets today and 164 Ibs total. Recovered 477.5 Ibs metal total. Previously unreported: Re- orient tree on A -07 for tree valves to line up with flow line riser as per production. i 1 fl Hilcorp Alaska, LLC 11Heorp Alaska, LLC W e 11 O p e rations Su m ma ry Well Name API Number Well Permit Number Start Date End Date A -07 50- 733 - 20036 -00 167 -046 4/24/2013 5/15/2013 Dail O p era t i ons: .` r� v Y �. 05/15/13 - Wednesday Attempt pull BPV out of A -07 (470 psi gas) on back side. Bleed down same. Unable to remove BPV from A -07 due to pressure. Call for other BPV & work on getting pressure lubricator out. Secure flow line & repair DWK air intake air trunk. Install gas loop on A -07, N/U BOP (set riser, Trolly stack over & set same) & R/U pressure lubrictor on A -07. Remove BPV & install TWC. P/T A -07 tree 250 L / 5000 psi H - 15 min. Remove TWC - torque up bolts on BOPE. • • � w \�� , THE STATE Alaska Oil and Gas 7 �l 1 1J1 1 � F - '"�'� ° Conservation Commission „ t GOVERNOR SEAN PARNELL � * . �. 333 West Seventh Avenue OF+�+mn - Q. Anchorage, Alaska 99501 -3572 ALA Main: 907.279.1 433 Y h Fax: 907.276.7542 Ted Kramer Q Sr. Operations Engineer Hilcorp Alaska, LLC SCANNED MAR 1 3 2013 3800 Centerpoint Drive Anchorage, AK 99503 Re: Trading Bay Field, Hemlock, Middle Kenai B, C, and D Oil Pool, Trading Bay St A -07 Sundry Number: 313 -065 Dear Mr. Kramer: 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 Commission grants for good cause shown, a person affected by it may file with the Commission 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. Sincere Or � W I . orman o .• • ssioner DATED this day of March, 2013. Encl. c .W it 1110 C-D �tt3 • ta �1 RECEIVED STATE OF ALASKA FEB 0 7 2013 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 MC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pod ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate p Pull Tubing GI Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other. Install ESP El 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. Hilcorp Alaska, LLC Exploratory ❑ Development 12 • 167-046. 3. Address: 3800 Centerpoint Drive, Suite 100 Stratigraphic ❑ Service ❑ 6. API Number. Anchorage, AK 99503 50- 733 - 20036 -00 7. If perforating: 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 93 Will planned perforations require a spacing exception? Yes ❑ No I9 TradingBay ST A -07 - 9. Property Designation (Lease Number): 10. Field /Pool(s): 1' — ADL0018731 Trading Bay Field / Hemlock Oil, Middle Kenai B Oil, Middle Kenai C Oil , IA iu) ,II&_ 4.44042 0.l '!a 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): ■ 6,407 6,389 • 4,550 4,546 6,052' Bridge Plug / 4,550' Bridge Plug N/A Casing Length Size MD TVD Burst Collapse Structural Conductor Surface 1,067' 13 -3/8" 1,067' 1,067' 3,090 psi 1,540 psi Intermediate Production 4,810' 9 -5/8" 4,810' 4,806' 3,950 psi 2,570 psi Liner 1,651 7" 6,397' 6,380' 7,240 psi 5,410 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 2 -7/8" 6.4# / N -80 2,837' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Packer - HES Model "RH" / SSSV - 2 -7/8" Otis Packer 2,795' (MD) 2,794' (TVD) and SSSV 292' (MD) 292' (TVD) 12. Attachments: Description Summary of Proposal El • 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch GI. Exploratory ❑ Stratigraphic ❑ Development 0 ` Service ❑ 14. Estimated Date for 15. Well Status after proposed work: 3/13/2013 Commencing Operations: Oil E y Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Ted Kramer Email tkramere..hilcorp.com Printed Name Ted Kramer Title Sr. Operations Engineer Signature 'd Phone 907 777 -8420 Date 2/7/2013 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Numbe 3-00O5- Plug Integrity ❑ BOP Test i Mechanical Integrity Test ❑ Location Clearance ❑ Other: jG 2 SCE ips 5'6 (' 7y t (,mss kJ �- /Scc i ,o .� re. ® RBDMS MAR 0 7 I [ v o ! occl /-G ,T'- t1. p�Lr s� d-Lt�i7 (dZ1. Spacing Exception Required? Yes ❑ No gi7 ,b. /i ent Form Required: it) — Li 0 APPROVED BY 7 . Approved by: , COMMISSIONER THE COMMISSION Date: ,k. ORIG1N4 1 tion i r 12 , Sub it Form and ' t Approved app licas valid fo m onths from the date of approval. Attac in Duplicate ')A t , , • • Well Prognosis Well: A -7 Hilcorp Alaska, LL Date: 1/25/2013 Well Name: Monopod A -7 API Number: 50- 733 - 20036 -00 Current Status: Oil producer (Gas Lifted) Leg: N/A Estimated Start Date: March 13, 2013 Rig: Monopod Rig #56 Reg. Approval Req'd? 10 -403 Date Reg. Approval Rec'vd: Regulatory Contact: Juanita Lovett 777 -8332 Permit to Drill Number: 168 -046 First Call Engineer: Ted Kramer (907) 777 -8420 (0) (985) 867 -0665 (M) Second CaII Engineer: Trudi Hallett (907) 777 -8323 (0) AFE Number: Current Bottom Hole Pressure: 903 psi @ 3,303' (3,303' TVD) From 6/5/09 Fluid Level Shot =0.273 psi /ft grad. (Maximum Expected BHP: — 2,627 psi @ 6,019' MD (6,006 TVD) Using a .437 psi /foot Gradient Max. Allowable Surface Pressure: —363 psi (Based on 2,627psi @ 6,006 TVD using a worst case .377 psi /ft. fluid gradient (All oil fluid column of 31 API gravity oil). Brief Well Summary / The A -7 is currently completed as a single string B -Zone producer on gas lift. The latest well test on this A -7 was 17 bopd, and 18 bwpd. The current re- completion plan involves removing the current gas lift completion, cleaning out the well to +/- 6,100 ft. MD + / -. A cast Iron bridge plug will be installed to give a new hard bottom. The well will then be perforated according to the approved perf add sheet. An ESP will then be installed and the well returned to production. Brief Procedure: 1. RU Slickline and pull centerset GLV's. RD SL. 2. MIRU Monopod Platform Rig # 56. 3. Circulate Hydrocarbon off of well. 4. ND Wellhead, NU BOP and test to 250psi low /2,500psi high. (Note: Notify AOGCC 24 hours in advance of test to allow them to witness test). 5. Pick up on tubing to 24K over string weight to shear and release retrievable packer at 2,795'. If --- -successful in releasing packer, go to step 9. If not, go to step #6. 6. E -line. RIH and cut tubing at 2,770' ( +/ -). RD E -line. / 7. POOH RU with 2 -7/8" tubing string and lay down the same 8. PU Work string, Mill and wash pipe and RIH to 2,795. Burn over HES RH packer. RIH with Spear assembly, engage packer and POOH with same. 9. PU and RIH with Work string and C/ 0 assembly cleaning out 9 -5/8" casing and milling up CIBP @ 4,550' and remove same. Continue cleaning out to the top of the 7" liner @4,746'. POOH with 9- 5/8" Clean out Assembly. 10. PU 7" milling and clean out assembly and RIH to Top of 7" liner at 4,746'. Clean out 7" liner and CIBP at 4,743' and continue cleaning out to 6,100'. POOH with C/O assembly. 11. PU and RIH with 7" CIBP and set at 6,100'. • • Well Prognosis Well: A -7 Hilcorp Alaska, Lb, Date: 1/25/2013 12. PU Test packer and RIH to 2,850 ( + / -). Set plug and pressure test casing to-1 Chart same. POOH with Test Packer. /S 3aµ"+iC�l�r 13. PU TCP perf guns and run into hole. RU E -line. Use a -line to place Perf guns on depth and perforate well according to the approved Perf Request Form. ros ' 14. Pick up TCP guns above perforations, monitor well by shooting fluid levels allowing the well to stabilize. POOH with TCP guns. 15. RU Schlumberger. PU ESP building into the well. RIH with ESP and set 50' ( + / -) above top perforation. 16. ND BOP, NU wellhead and test. 17. Turn well over to production. y� k , t t= /04. Tf �� .✓ Attachments: X 57_ SVS r L� 1. As -built Well Schematic 2. Proposed Well Schematic 3. BOP Drawing • U S Trading Bay Unit SCHEMATIC Monopod Well # A -7 API# 50- 733 - 20036 -00 Completed 08/19/70 RKB to TBG Hngr = 38.23' CASING AND TUBING DETAIL Tree connection: ?? SIZE WT GRADE CONN ID TOP BTM. J 13 -3/8" 61 K -55 Butt 12.515 Surf. 1067' o _ 1 9 -5/8" 40.0 K -55 Butt 8.835 Surf 4810' --xi 3150 pi- 7" 26 N -80 Butt 6.276 4746' 6397' d .- Tubing: � 2 -7/8" 6.4 N -80 Seal Lock 2.441 Surf 2837' 1 12 .w .. 2 JEWELRY DETAIL NO. Depth ID Item 37.86' 10" Cameron DC -B 2 -7/8" EUE 8rd Tubing hanger, 1 292 2.313 2 -7/8" Otis, SSSV Nipple, 2 1783' GLV #1 Otis CX GLM iiiii 3 3 2593' GLV #2 Otis CX GLM 4 2755' GLV #3 Otis CX GLM • 5 2795' HES Model "RH" Retrievable Pkr. (Shear release set at 24,000 #) 6 2805' 2.313 Otis "X" Profile Nipple, 2.313 7 2836' WLEG btm 2837' WM 4 t \ c� -.rJ i�'1 5 }7`� Wireline Summary - � 12/6/90 Fill tagged w/ GLS gauges @ 4155' 7 8 PERFORATION DATA =31 -8 Accum. Date =33 6 Zone Top Btm Amt. SPF Last Opr. Present Condition 31-8 2,882 2,896' 14' 4 8/17/1970 Open f/ Production =41 - 31-8 2,928' 2,944' '6' 4 8/17/1970 Open f/ Production 33-6 3,044' 3,076' 32' 4 8/17/1970 Open f/ Production =41 - 41-3 3,196' 3,208' 12' 4 8/17/1970 Openf /Production _ 41-3 3,214' 3,240' 26' 4 8/17/V70 Open /Production l =41 - 41 3,290' 3,434' 144' 4 8/17/1970 Open f/ Production ' 3,300' 3,320' 20' 4 9/10/1967 Cmt Sqzd. Tested to 500 psi sio■ P 44 3,808' 3,850' _ 42 4 8/17/1970 Open f/ Production V 3,820 3,840' 20' 4 9/13/1967 Cmt Sqzd. Tested to 500 psi k∎ g � 74L 44-7 3,858' 3,956' 98' 4 8/17/1970 Openf /Production 4,125' 4,225' 100' 4 9/15/1967 Cmt Sqzd. y tl o 4,140' 4,160' 20' 4 9/13/'667 Cmt Sqzd. Tested to 500 psi 4,605' 4,625' 20' 4 9/10/'667 Cmt Sqzd. 31-8 2,875' 2,90? 22 4 9/7/1988 Open f/ Production 31-8 2,923' 2,947' 24' 4 9 /8/1988 Open f/ Production 33-6 2.997' 3,076' 79' 4 9/9/988 Open f/ Production \ 7 ' 9/13/ 41-3 3,196' 3240' 44 ' 4 1)88 f/ Production 41-8 3,283' 3,435' 52 4 9/1N1988 Openf /Production KB ELEV = 101' 44-7 3,795' 3,960' 65' 4 9/12/'388 Open f/ Production PBTD = 4,550' TD = 6,387' ANGLE thru INTERVAL = 3.2° A -7 Schematic 02 -07 -13 REVISED: 10/16/00 DRAWN BY: SLT . • • Trading Bay Unit II PROPOSED Monopod Well # A -7 API# 50- 733 - 20036 -00 Completed Future RKB to TBG Hngr = 38.23' 1 i CASING AND TUBING DETAIL L SIZE WT GRADE CONN ID TOP BTM. 1 3 -3/8" 61 K -55 Butt 12.515 Surf. 1067' 9 -5/8" 40.0 K -55 Butt 8.835 Surf 4810' 7" 26 N -80 Butt 6.276 4746' 6397' Tubing: 2 -7/8" 6.4 N -80 Seal Lock 2.441 Surf 2837' ■ ■ JEWELRY DETAIL [ j No Depth Item 1 ±41' 2 -7/8" Hanger Assy. ull 2 ±2,000' Bottom of ESP it 3 ±6,100' CIBP i I I 9 L e 2 See Next Page for Perforation Data BZN C, CZN z X • C, CZN _} DZN _T EZN 3 KB ELEV = 101' PBTD = 6,100' TD = 6,387' ANGLE thru INTERVAL = 3.2° Updated by: JLL 02/07/13 • II • • Trading Bay Unit PROPOSED Monopod Well # A -7 API# 50- 733 - 20036 -00 Completed Future PERFORATION DATA Zone Top (MD) Top (ND) Btm (MD) _ Btm (ND) Amt SPF Date Status 24 -6 BZN ±2,052' ±2,052' ±2,123' ±2,123' 71' 6 Future 26 -7 BZN ±2,225' ±2,225' ±2,332' ±2,332' 107' 6 Future 28 -6 BZN ±2,419' ±2,419' ±2,445' ±2,445' 26' 6 Future BZNS5 ±2,516' ±2,515' ±2,524' ±2,523' _ 8' 6 Future BZNS1 ±2,716' ±2,715' ±2,724' ±2,723' 8' 6 Future ±2,784' ±2,783' ±2,858' ±2,857' 74' 6 Future ±2,874' ±2,873' ±2,906' ±2,906' 32' 6 Future 2,875' 2,874' 2,907' 2,906' 22' 4 9/7/1988 Open 31 -8 BZN 2,882' 2,881' 2,896' 2,895' 14' 4 8/17/1970 Open ±2,920' ±2,919' ±2,947' ±2,946' 27' 6 Future 2,923' 2,922' 2,947' 2,946' 24' 4 9/8/1988 Open 2,928' 2,927' 2,944' _ 2,943' 16' 4 8/17/1970 Open 2,997' 2,996' 3,076' 3,075' 79' 4 9/9/1988 Open 33 -6 BZN ±2,999' ±2,998' ±3,077' ±3,076' 78' 6 Future 3,044' 3,043' 3,076' 3,075' 32' 4 8/17/1970 Open ±3,193' ±3,192' ±3,242' ±3,241' 49' 6 Future 3,196' 3,195' 3,208' 3,207' 12' 4 8/17/1970 Open 3,196' 3,195' 3,240' 3,239' 44' 4 9/10/1988 Open 41 -3 BZN 3,214' 3,231' 3,240' 3,239' 26' 4 8/17/1970 Open ±3,282' ±3,281' ±3,433' ±3,432' 151' 6 Future 3,283' 3,282' 3,435' 3,434' 52' 4 9/11/1988 Open 3,290' 3,289' 3,434' 3,433' 144' 4 8/17/1970 Open 3,300' 3,299' 3,320' 3,319' 20' 4 9/10/1970 Cmt Szqd 3,795' 3,793' 3,960' 3,958' 65' 4 9/12/1988 Open ±3,803' ±3,801' ±3,959' ±3,957' 156' 6 Future 44 -7 BZN 3,808' 3,807' 3,850' 3,848' 42' 4 8/17/1970 Open 3,820' 3,818' 3,840' 3,838' 20' 4 9/10/1967 Cmt Szqd 3,858' 3,856' 3,956' 3,954' _ 98' 4 8/17/1970 Open C -2 ±4,037' ±4,035' ±4,097' ±4,095' 60' 6 Future C -3 ±4,127' ±4,125' ±4,224' ±4,221' 97' 6 Future 44 -7 BZN 4,125' 4,123' 4,225' 4,222' 100' 4 9/15/1967 Cmt Szqd 4,140' 4,138' 4,160' - 4,157' 20' 4 9/10/1967 Cmt Szqd CZNS6 ±4,267' ±4,264' ±4,335' ±4,332' _ 68' 6 Future C4 ±4,344' ±4,341' ±4,371' ±4,368' 27' 6 Future C5 ±4,429' ±4,426' ±4,479' ±4,476' 50' 6 Future C -6 ±4,600' ±4,595' ±4,639' ±4,635' 39' 6 Future 44 -7 BZN 4,605' 4,601' 4,625' 4,621' 20' 4 9/10/1967 Cmt Szqd ±4,670' ±4,666' ±4,700' ±4,696' 30' 6 Future CZNS7 ±4,720' ±4,716' ±4,740' ±4,736' 20' 6 Future C7 ±4,760' ±4,756' ±4,781' ±4,777' _ 21' 6 Future 49 -4 CZN ±4,807' ±4,803' ±4,829' ±4,825' 22' 6 Future 50 -0 CZN ±4,869' ±4,865' ±4,879' ±4,875' 10' 6 Future 50 -3 CZN ±4,897' ±4,893' ±4,927' ±4,923' 30' 6 Future CZNS2 ±4,952' ±4,989' ±4,957' ±4,953' 5' 6 Future 50 -6 CZN ±4,992' ±4,988' ±5,021' ±5,017' 29' 6 Future CZNS9 ±5,102' ±5,097' ±5,122' ±5,117' 20' 6 Future 51 -6 CZN ±5,122' ±5,117' ±5,156' ±5,151' 34' 6 Future 51 -9 CZN ±5,170' ±5,165' ±5,198' ±5,193' 28' 6 Future 53 -0 DZN ±5,260' ±5,254' ±5,288' ±5,282' 28' 6 Future DZNS2 ±5,328' ±5,322' ±5,335' ±5,329' 7' 6 Future 53 -8 DZN ±5,360' ±5,354' ±5,393' ±5,387' 33' 6 Future 54 -5 DZN ±5,424' ±5,417' ±5,458' ±5,451' 34' 6 Future 54 -9 DZN ±5,492' ±5,485' ±5,509' ±5,502' 17' 6 Future 55 -7 DZN ±5,542' ±5,534' ±5,560' ±5,552' 18' 6 Future 56 -1 DZN ±5,587' ±5,579' ±5,670' ±5,661' 83' 6 Future 57 -2 DZN ±5,700' ±5,691' ±5,744' ±5,735' 74' 6 Future ±5,798' ±5,788' ±5,817' ±5,807' 19' 6 Future 58 -1 EZN ±5,823' ±5,813' ±5,837' ±5,827' 14' 6 Future ±5,860' ±5,850' ±5,875' ±5,864' 15' 6 Future 58 -7 EZN ±5,882' ±5,871' ±5,948' ±5,937' 66' 6 Future 60 -0 EZN ±5,982' ±5,970' ±6,019' ±6,007' 37' 6 Future Updated by: JLL 02/07/13 • • Monopod Platform 2013 BOP Stack 01/10/2013 Hilrnrp :thaska. LI.(. Annular Preventer Shaffer Spherical 13 5/8 5M FE X 13 5/8 5M stdd top Shaffer 3.74' 3 5/8 5M 111 Itl 111111 111 Double gate Shaffer SL Sh r SL • --- 13 5/8 5M stdd X stdd ' 2.83' 10" operators o'.,_ Mud Cross 135 /85MFEXFE `r 111 111' 1 1.11 111 � . w/ 3 118 5M EF0 ii! 4 1 w/ 21/16 5M Choke and Killfl' l v ��" 2.00' valves wl Unibolt end 111 111 111 111 111 connections for lines Shaffer SL Single gate = 1.44' Shaffer SL ° \ 13 5/8 5M stdd X stdd 111 111 Riser 13 5/8 5M Flange X 13 5/8 5M Flange 14.20' 111 111 Crossover spool I 11 1.50' 13 5/8 5M X 11 5M 11 11 RECEIVED 1 �(, MAR 0 4 1f113 2 1 -A -0 1 1 AOGCC I T9N -R13W TBS 01A 4 A -01 RD I r A -16RD 1 I A-32 • 1 4 1 1 1 1 A-02-_. 1 A -11 4,__ 1 - -A-07 A -09RD 104 01 I I B ZONE 1 1 ( ( Active Completion A -10 I I Shut -in Completion • Abandoned Completion 1 l' Proposed Completion 1 �0 �® " 0 1 t I 1 `o. HILCORP ALASKA, LLC II TRADING BAY I B ZONE COMPLETIONS I I A -23 500 FEET A -17RD PFTRA 311 /9∎111 , 'Id '),:l PM ■ I mi.r 2 I A -01 I �© T9N-R13W - TBS -01A A -01 RD 1 4 1 L 1- A 6 I I A -32 • ik I I I I 3 1 A -02-/ 1 I A -11 I _ —A0 A 09RD A'�_ A04 ti f - -- j E1-i C ZONE 1 1 Active Completion A -1d .1 I I Shut-in Completion I • 11 1 1 Abandoned Completion I I MN Proposed Completion f 1 1 CI HILCORP ALASKA, LLC 1 TRADING BAY C ZONE COMPLETIONS I A-23 o 500 • A -17RD FEET PPrPA '1 /1001, 1, - 25'55 PM 1 MI r, — vv — A -01 2 I 1 1 -a- TBS -01A T9N -R13W 4 A -01 R D I r L 1 A -16RD i I 401P• A -32 I tile, 1 1 1 A -02– 3 1 in A - • 0- A -07 I A 09RD1 r _ jb4 _ _ - - - -- D ZONE Active Completion A -1d == _. „ %' ( 1 Shut -in Completion • 1 I I Abandoned Completion I MN Proposed Completion I I I 1 1 fl HILCORP ALASKA, LLC 1 TRADING BAY 1 D ZONE COMPLETIONS I I — A -23 o 500 �A -17RD – FEET ■ PP7RC1/1/nf1111, "17 SA PM M. I w r1 2 1 A01 1 1 T9N -R13W TBS 01A 4 A -01 R D I I a A -16RD � • /, ,, '4 • A -32 • 1 i I 1 I 3 I A -02 - -0 t I 1 A -11 1 A -07 I A -09RD A -04 11 I I I E ZONE 1 1 1 I Active Completion A-10 Shut -in Completion • I I ( Abandoned Completion I ( I Proposed Completion I I I I 1 fi HILCORP ALASKA, LLC I TRADING BAY I E ZONE COMPLETIONS I � \ 0 500 A -23 � �. FEET A -17RD PFTPC 1/1 nf11g 1' YO - fI7 PM ..... A-07 H is t orica l p pl B-Zone Only Producer i ;, -----: . " : . — „ . • •••. mmmmmmmmm .1••......•••••••.. ••••U•••.•. mmmmmm •••• •••••• c cu u rn m0 , , • G., ,,.2;;;Bbb mc • ,, • c.r.Wat 365,915 bbl . ',- \ 1 '.: • , • , ' . :■ " i • ,, ' ■ l . . ' . . ' : I I " ''',,i i A li • 1 A :: . .. „ . . . , . . . .: . , . . . 109 , .. • .. . ' I . i ' ' . ' 111111011.111111 ill fill7, , Air: . . f; ,,, ) .." i: . ■'i MIIII■IM all .::.. :`. i : : ,,; ; :: , ,t: , mut if •saracitimi[ sus MIL • .1111:11111111111111 Milingiiii.illinV RI gralp Orli ; IriSliii rant ill . 111111111117/11,17001 Itili IlitIW.Tiii.a II 1 111111111111111= 1 i ! Limamicarin Mani i idol i Id 1 ! IP 1 ._., .. _ Oil Production .601) Daily --, Gas Production Oncf, Daily . '' ' II i; t i. i T '`: ! rsr • 1 • + II iii j — Water Production (bbl) Daily c & D Zone plugged back i: 4 ,, ;,:„: vii it .:... , ' , ‘: all ; tti :' .f L il il , ii "1. " ., . .„ ., . . , :.::;:, :,..: :: , L J J!.,. MI B Zone Completed , i . 1 'T ' 1 • ? f , 1 1! 7 il 1 1 . ,..: ,:, ,,,, , ,,,I, i, , ,,,, . .,.; $, $ :,:, ..$ ;; :,:: $ , :.:, , .„--- C & D Zone i iIIIIINNI.....simor■Nramsxmakin■••=motimitammia Romminamimmistimammomi NI im, it - Completed 11,... ii il I I : it — - ' . 1 1 I 1 1 . ' .. • , t , , . 1987 1972 1977 1982 1987 1592 1997 2002 2007 2012 2017 0 0 II Monopod Platform A -7 Proposed 03/05/2013 HiIrnrp r114trkr, LIA. Monopod Platform Tubing hanger, Seaboard - A -7 ESP -EN, 11 X 2 7/8 EUE lift 13 3/8 X 9 5/8 X 2 7/8 and Susp w/ 2 Type H BPV profile, 2- Y2 CCL, Prepped for BIW penetrator BHTA, Bowen, 2 9/16 5M X 2.5 Bowen quick union 1 u1 u1 amiwir Valve, Swab, WKM -M, MI 2 9/16 5M FE, HWO, DD trim O '' Valve, Wing, WKM -M, 2 1/16 v ill - Vale, Wing, WKM M, 2 9/16 �•� 5M FE, w/ MA -15 operator, 5M FE, HWO, DD trim - p r._ 9.11 _ � � DD trim i c, .„),„ 1 • 111 Valve, Master, WKM -M, ® 0 2 9/16 5M FE, HWO, DD trim 0 O \ 1 i pr_ LL I Li Adapter, Seaboard -ESP, 11 5M rotating flange x 2 9/16 5M rotating flange, w/ 4 11/16 pocket, w/ 2- _ CCL, ported for BIW Ili "' 1� penetrator Tubing head, S -8, 13 5/8 3M x 11 5M, w/ 2- 2 1/16 5M rip . _ SSO, w/ BG bottom =�,i� ��' . , w/ 2- 2 1/16 5M WKM -M valves 1 j � _ V I 1 0, 74 1 L2F --. 1 0 1 1 ial Casing head, 11111` rt Shaffer KD, lol r 1111 135/83MX 13 3/8 SOW, w/ 2- 2" - LPO, 111 01114 IllI - k PP • • • ALASKA OIL AND GAS CONSERVATION COMMISSION March 3, 2013 10:00 a.m. Trading Bay Field NAME — AFFILIATION TELEPHONE (PLEASE PRINT) NW/d Dc. / )1elcuvv, 4107 -3-17--ew Le 6ve-6 , s et frt_ 9 -- 7 7 7 - eR3 - /7.17 T" FO-4-4/ PoZT Fa2 ?27 — 6 ' 3 . 7 6 v E DP ?'oz--•A; - X 231 6-c (yob -, ? - /23y ,' • • Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Friday, March 01, 2013 10:26 AM To: 'Ted Kramer; 'David Duffy' Subject: FW: Application for Sundry Approval: Trading Bay ST A -07 Good morning Ted and David, A review of the Monopod wells shows four development wells with BHLs within the SE1 /4 Sec. 4, Township 9 North, Range 13 West, S.M. Those wells are: A -02, production pools Hemlock and Mid Kenai D and E A -11, production pools Middle Kenai C and D A -32, production pools Hemlock and Middle Kenai C A -07, production pools Kenai B, C, and D, and Hemlock. Of these wells, A -02, A -32 and A -04 are producing. In addition, a portion of A -01RD wellbore lies within the SE1/4 Sec. 4. This well is also producing. As Hilcorp plans to add new perforations for the A -07 well from 4670' to 5970' MD which will be below the current perforation intervals, I would appreciate receiving a map showing the wellbore traces and perforation intervals of the wells completed in the Hemlock, and Middle Kenai B, C, D, and E Oil Pools within 660 feet, true measured distance, to the Trading Bay St A -07 well. Please include the perforation intervals and proposed perforation intervals for the Trading Bay St A -07 well on the maps, and color code the perforations to reference the various pools. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793 -1238 From: Bettis, Patricia K (DOA) Sent: Tuesday, February 12, 2013 11:47 AM To: 'tkramer @hilcorp.com' Subject: Application for Sundry Approval: Trading Bay ST A -07 Good morning Ted, I started to review Hilcorp's sundry application for the Trading Bay St A -07 well this morning. I would appreciate receiving maps for the Middle Kenai B, C, D and E Oil Pools that shows the wellbore trace and perforation intervals of wells completed in these pools within 660 feet, true measured distance, to the Trading Bay St A -07 well. Please include 1 • S the perforation intervals for the Trading Bay St A -07 well on the maps, and color code the perforation to reference the various pools. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793 -1238 2 • • Bettis, Patricia K (DOA) From: David Duffy [dduffy ©hilcorp.com] Sent: Friday, March 01, 2013 8:59 AM To: Bettis, Patricia K (DOA) Cc: Matt Frankforter; Larry Greenstein Subject: Trading Bay St. A -07 Hi Patricia — In regards to your question below about A -07, no spacing exception is required because: 1) A -07 will be the second active completion within the applicable quarter section (CO 93, Rule 4); and 2) there are no other active completions within 660' of the proposed intervals (CO 93, Rule 5). Because no spacing exception is required, we did not prepare a map to prove the negative. However, we'd be pleased to answer any additional questions you may have. Regards, David Duffy, Landman Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, Alaska 99503 Office: 907 777 -8300 Direct: 907 777 -8414 Fax: 907 777 -8580 Cell: 907 301 - 2629 Email: dduffy @hilcorp.com This email may contain confidential and /or privileged information and is intended for the recipient(s) only. In the event you receive this message in error, please notify me and delete the message. From: Bettis, Patricia K (DOA) [ mailto :patricia.bettis(Walaska.gov] Sent: Thursday, February 28, 2013 1:13 PM To: David Duffy Subject: RE: 10 -403 Monopod - A -18 - Amended 02- 22- 13.pdf David, Thank you. Will a similar map be provided for the Trading Bay St A -07 sundry application? Have a great afternoon. Patricia 1 • • • Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Tuesday, February 12, 2013 11:47 AM To: 'tkramer @hilcorp.com' Subject: Application for Sundry Approval: Trading Bay ST A -07 Good morning Ted, I started to review Hilcorp's sundry application for the Trading Bay St A -07 well this morning. I would appreciate 1 receiving maps for the Middle Kenai B, C, D and E Oil Pools that shows the welibore trace and perforation intervals of wells completed in these pools within 660 feet, true measured distance, to the Trading Bay St A -07 well. Please include the perforation intervals for the Trading Bay St A -07 well on the maps, and color code the perforation to reference the various pools. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793 -1238 1 ~ ~ ~~~[Æ~£ ~} [Æ~[Æ~~~[Æ AI,A.SIiA. OILAlVD GAS CONS~RVATI ON COMMISSION í / í f ! ¡ í ¡ ¡ ¡ FRANK H. MURKOWSKI, GOVERNOR 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE. ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 May 18,2004 Dwight Johnson Field Superintendent Unocal PO Box 19624? Anchorage, Alaska 99519 RE: No-Flow Verifications Trading Bay State A-O?, PTD 167-046 Dear Mr. Johnson: On May 14, 2004, AOGCC Petroleum Inspector Lou Grimaldi witnessed a "no flow test" at Unocal's Monopod platform, Trading Bay State Well A-O? The well was opened to atmosphere through flow measurement equipment with suitable range and accuracy and monitored for several hours. The well demonstrated a stabilized gas rate of 600 standard cubic feet per hour (SCF /hr) at 1 psi during the test, which is less than the allowable rate (900 SCF/hr); no liquid was produced to the surface. The subsurface safety valves may be removed from service in Well A-O? based on this no-flow test result. Fail-safe automatic surface safety valve systems capable of preventing uncontrolled flow must be maintained in proper working condition in this well as required in 20 AAC 25.265. The subsurface safety valve must be returned to service if the well demonstrates an ability to flow unassisted to surface. Please retain a copy of this letter on the Monopod platform. Sincerely, ~. ,-¡~ "-J(M/ ~ 1S '. Jame~. Re ~ Petroleum Inspection Supervisor cc: Bob Fleckenstein TO: (' State of Alaska Alaska Oil and Gas Conservation Commission Jim Regg, ~f/t¡ 0J \110+ DATE: May 16, 2004 P. I. Supervisor ( I (, MEMORANDUM THRU: FROM: Lou Grimaldi, Petroleum Inspector SUBJECT: No-Flow Test Unocal, Monopod platform TBU A-7 Trading Bay Field PTD 167-0460 NON-CONFIDENTIAL Friday, May 14, 2004: I witnessed a No-Flow verification on the Monopod platform in the Trading Bay Field, well #A-7 Following is a timeline and well status during test. 1600 Arrive location, tubing/casing open to atmosphere with gas flow evident. 570 scf @ 1 psi 1620 Shut-in well @ 2 psi. 1640 Well shut-in @ 28.5 psi, 1650 Well shut-in @ 31.5 psi. Open well to atmosphere and blowdown to 2 psi. 1700 Well bleeding 750 scf @ 2 psi. 1705 Well Bleeding 400 scf @ .5 psi. 1740 Well Bleeding stabilized @ 600 scf @ 1 psi. Shut-in well. 1810 Shut-in @ 28 psi. Blowdown well to atmosphere. 1820 Well bleeding 700 scf @ 1.5 psi 1830 Well bleeding 600 scf @ 1 psi 1845 Well bleeding 600 scf @ 1 psi Conclude test. SUMMARY: I witnessed No-Flow verification on UNOCAL's Trading Bay Field well #A-7 on the Monopod Platform. NON-CONFIDENTIAL CC: Dwight Johnson (UNOCAL) No-Flow TBF A-7 05-14-04 LG.doc MEMORANDUM TO: Julia Heusser, Commissioner THRU:Tom Maunder,/3'~ P. !. Supervisor State of Alaska Alaska Oil and Gas Conservation Commission DATE: April 5, 2001 FROM: Jeff JOnes, SUBJECT: Petroleum Inspector Safety Valve Tests Monopod Platform Trading Bay Field Thum. di~.y, Aoril 5, 200! :1 traveled to UNOCAL's Monopod Platform and witnessed the semi annual safety valve system testing. Lead operator Gary Smith conducted the testing today; he did a thorough job and was a pleasure to work with. As the AOGCC Safety Valve System test report indicates lWitnessed the testing of 18 wells and 53 components, with four failures;~ The pilot on well A-02 tripped at 26 psi and was repaired and passed a retest. This well has had the SSSV removed for repair since 2/24/00 and has not been re-installed. Well A-11 has had the SSSV removed for repair since 11/7/99 and has not been re-installed. /indicated to Mr. Smith that these SSSV's must be repaired and. re-installed and successfully tested in a timely manner or the two wells shut in. Well A-06 SSSV failed to close and will require maintenance. Wells A-13 and A-21 have been certified as "no flow" status and do not have SSSV's installed. While on location ! inspected the platform and found it very clean and it appeared to be in excellent condition. Summa.ry.: I witnessed the semi annual Safety Valve System testing at Unocal's Monopod Platform in the Trading Bay Field. Monopod Platform, 18 wells, 53 components. 4 failures, 7.5% failure rate. :.Platform inspection conducted. Attachme.nt.: svs TBF Monopod Platform 4/5101 JJ NON-CONFIDENT.I.A...L. SVS TBF Monopod Platform 4-5-01 JJ Operator: UNOCAL' Operator Rep: Gary Smith AOGCC Rep: Jeff Jones Submitted By: Jeff Jones Date: Field/U~ad: Trading Bay Field Monopo,d Separator psi: LPS 65 HPS 4/5/01 Well Permit Separ Set L/P Test Test Test Date Oil, WAG, GIN J, Number Number PSI PSI Trip Code Code Code Passed GAS or CYCLE A-01RD 1901470 "651 ' 45 42 P P ' P ' ' OIL A~2 1660490 "65 45 26 3 P "43 4/5/01 OIL A-03RD3' 1971300 65 45 42 e P P OIL A-04 1670020 A-06 1670250 65 45 45 P P '43 OIL · .~.~.~7~t~'~-~. 1670460 65 45 42 P P P OIL A-09RD 1810360 A-10 1670760 ' A,41 1700240 65 ~5 '43 P P '~[3 OIL , , , A-13 1680020 65! 45 41 P P OIL ,, A-14 1680270 A-15' '1680330 65' 45 '45 P "P P OiL A-16RD 188038'0 " 65 45 4i/42 P 1~ 'P ...... OIL A-I'TRD 1810670 65 45 43 P P P 'OIL A-18 1680760 6~ 45 ' 47 P P P '" OIL A'21 1700470 65 45 46 P P .... OiL A-22 17003'i0 ' 65 45 44 P P" P ' OIL ,, A-23 1700590 , A-23DPN 1720200 A.24RD 18i0400 65 45 4'1 P 'P P ' oIL lA-27RD1 1970630 6'5 45 43' 'P P' P oiL A-28RD 1890920 65 45' 451 P P P OIL 'A-30 1730140 A-32 1770180 65 45 44 P P P OIL Wells: 18 Components: 53 FaRures: "4 Failure Rate: 7.5% I-'Ioo var Remarks: A-13 & A-21.reported as No-Flow wells. SSSV's removed for repair: A-02 out since 2/24/00, A-11 out since 11/7/99. A.-02 pilot repaired and retested "OK". A-06 SSSV failed to close. A-16 RD is a dual completion. 4/9/01 Page 1 of 1 SVS TBF Monopod Platform 4-5-01 JJ Unocal North Amerk Oil & Gas Division Unocal Corporation P.O. Box 190247 Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 UNOCAL Alaska Region April 16, 1990 Alaska Oil & Gas Conservation Commission 3001 Porcupine Dr. Anchorage, AK 99504 Attn: Ms. Elaine Johnson Dear Ms. Johnson: I have attached surface survey locations of the "Legs" and conductors for the four platforms in the Trading Bay Unit as well as the Union Oil-operated Monopod and Granite Point Platforms. I was unable to locate any plats from a registered surveyor but I hope this will meet your needs. YourS very truly, u Regional Drilling Manager GSB/lew CONDUCTOR 1 2 3 4 5 6 7 8 9' l0 ll 12 13 14 15 16 17 18 19 20, 21 22 · ~..~_._ 24 25 26 27 28 29 30 31 32 MONOPOD CENTER FROM SOUTHEAST CORNER, SECTION 4, TgN, 'R13W "Y 2,523 126 LAT. 60°53' ": , 48.65 X'' = 218,87l LONG. :- 151034 43.51 "Y" COORD. 2,523,134.3 2,523,130.2 2,523,125.7 2,523,121.7 2,523,118.2 2,523,114.4 2,523,113.2 2,523,1.13.2 2,523,114.8 2,523,117.7 2,523,121.8 2,523,126.4 2,523,130.3 2,523,133.8 2,523,137.6 2,523,138.8 2,523,138.8 2,523,137'.2 2,523,132.8 2,523,129.4 2,523,132.0 2,523,128.4 · ..?, 52.3,3.2_.,a. 8 2,523,133.9 2,523,120.9 2,523,131.4 2,523,118.1 2,523,127.2 2,523,123.6 2,523,120.0 2,523,122.6 2,523,119.2 "X" COORD. FEL 218,880.9 218,883.2 218,883.9 218,883.2 218,881.3 218,576.8 218,873.0 218,869.0 218,864.6 218,861.1 218,858.8 218,858.1 218,858.8 218,860.7 218,865.2 218,869.0 218,873.0 218,877.4 218,875.7 218,878.6 218,870.8 218,873.9 .. 21R. R7F;. q ~.. 218,867.0 218,878.1 218,863.9 .218,875.0 218,865.1 218,868.1 218,871.1 218,863.4 218,866.3 WELL # FSL A-28 1621 A-25 1617 A-3O 1612 1608 A-27 1605 A-23 1601 A-21 and RD 1600 A-22 1600 A-14 1601 A-13 1604 A-17 1608 A-8 1612 A-15 1616 A-24 and RD 1620 A-29 1624 A-9 and RD 1625 A-19 1625 A-18 1624 A-11 1619 A-3 1616 ,. A-1 1618 A-7 1615 A-4 1611 A-6 1600 A-32 1607 A-12 and RD 1617 A-20 1604 A-2 1613 A-16 1610 A-26 1606 A-10 1609 A-5 and RD 1605 1 &2 554 551 551 551 '553 557 561 565 570 573 576 577 577 574 570 566 562 558 559 556 564 561 558 · : 568 556 571 559 570 566 563 571 568 ,"-'~ STATE OF ALASKA '-' AL~,..,~ OIL AND GAS CONSERVATION COMMIS,~aN REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown __ StimUlate __ Plugging __ Pedorate ~ Pull tubing __ Alter casing ~ Repair well ~ Pull tubing ~ Other 2. Name of Operator i 5. Type of Well: Union 0±1 Company of' Calif,ornia (UNOCAL) Development.~ · ! Exploratory __ 3. Address |. Stratigraphic P.0. BOX 15;0247, Anch, Ak. ' 99519-0:~47 Service 6. Datum elevation (DF or KB) KB 101 feet 7. Unit or Property name Trading Bay 4. Location of well at surface 1615N' 561'W of, SE corner Sec. 4, T9N, R13W, SM At top of productive interval ll'S, 50' E of surf`ace At effective depth 36'N 126'E At total depth 1826'N 514'W of, SE Corn. Sec. 4 TS;N. R13W. SM 12. Present well condition summary Total depth: measured 6,155;7 ' feet Plugs (measured) true vertical 6,381 feet Effective depth: measured 4,550 feet Junk (measured) true vertical 4,546 feet 6052' 4550' 8. Well number A-7 ~. Permit number/approval number '"~-- & 6 ~ 67-46 10. APl number 50-- 733-20036 11. Field/Pool TV.O~ B bridge plug bridge plug Casing Length Structural Conductor 1067 ' 4810 ' Surface Intermediate Production 1651 ' Liner Perforation depth: measured true vertical Tubing (size, grade, and measured depth) Size Cemented 13 3/8", 61# 1067' 5; 5/8", 40# 4810' 7" 26# 6397-4746 Packers and SSSV (type and measured depth) 13. Stimulation or cement squeeze summary Intervals treated (measured) Treatment description including volumes used and final pressure See attached Top perf, 2882 MB. 2881 TVD Btm perf 3956 MD, 3952 TVD See attached See attached Measureddepth ~ueverticaldepth 1067' 1067' 4810' 4810' 6397-4746' 4741-6381 RECEIVED Alas~.~il & Gas Cons. Commission · ,~i~ ~ch0rage ' 14. Prior to well operation Subsequent to operation · 15. Attachments Copies of Logs and Surveys run Daily Report of Well Operations _ ~presentetiveDmlyAverageProdu~ionorlnjeCtionData OiI-Bbl Gas-Md Water-Bbl CasingPressure ~bingPressure 33 138 22 240 70 58 228 36 270 67 16. Status ofweli classification as: Oil __ Gas __ Suspended __ Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. ~--2(~, r~ --_..~'/-dc>~ -Sig~ed 7~"~ ~.¢~ Roy D. Roberts Title Environmental Engineer DateO1/20/89 Form 10-404 Rev 06/15/88 SUBMIT IN DUPLICATE MONOPOD PLATFORM Well A-7 9-7-88 The following intervals were perforated with Atlas 2 1/8" Silver Oet charges at OO phasing: 2875' - 2907' 2923' - 2947' 2997' - 3076' 3196' - 3240' 3283' - 3435' 3795' - 3960' 0019n/65 .111 1'8 :3'6 44.-7 IG L:~ 2 G L:~ 4 -- VII VIII j , · WELL TBS A-7 1 CASING & ABANDONMENT DETAIL I.) Rotary Table Measurement at 0.00' II.) Tubing Hanger at 37.B6' II1.) 13 3/8', 61-, J-~5 Casing at 1067' IV.) Bridge Plug at 4550' V.) Top 7', 26~', N-80 Liner at 4746' VI.) 9 5/8', 40,~, J-55 Casing at 4810' VII.) Bridge Plug at 6052' VIII.) 7', 26+, N-80 Liner at 6397' TUBING DETAIL 2 7/8", 6.4-~, N-80 TUBING 1.) Ball Valve at 291.55' 2.) Otis 'CX' Gas Lift Mandrel at 1782.70' 3.) Otis 'CX' Gas Lift Mandrel at 2593.38' 4.) Otis 'CX' Gas Lift Mandrel at 2755.23' 5.) ~ 5/8' x 2 7/8"Model 'RH-I' Packer at 2794.55' 6.) "X' Landing Nipple at 2804.84' 7.) Bottom of Tubing at 2836.60' PERFORAT DATE INTERVAL 9/10/67 3300'-3320' 3820'-3840' 4140'-4160' 4605'-4625° 9/15/67 4125'-4225' 8/17/70 2882'-2896' 2928'-2944' 3044'-3076' 3196'-3208' 3214'-3240' 3290'-3434' 3808'-3850° 3858'-3956' ION RECORD CONDITION Squeezed Squeezed Squeezed Squeezed Squeezed Open 31-8 Sd. Prdduction Open 31-8 Sd. Production Open 33-6 Sd. Production Open 41-3 Sd. Production Open 4.1-3 Sd. Production Open 41-8 Sd. Production Open 44-7 Sd. Procuction Open 44-7 Sd. Production NOTE: 10° OF CEMENT ON TOP OF BP AT 4550' AND ON SAND AT 6052', FOR PERFS IN MIDDLE KENAI "C°, 'D'. & HEMLOCK ZONES SEE ORIGINAL WELL HISTORY WELL TBS A 7 ,_ . ~'~ ;CAt.[ NONE WELL SCHEMATIC ,,, j UNION OiL COMPANY OF CALiFOrNIA A-7 PERFORATING PROCEDURE MONOPOD PLATFORM ® e Retrieve ball valve with slickline. Pressure test lubricator to 1500 psi. Reperforate from 2875'-2907'; 2923-2947'; 2997-3076'; 3196-3240'; 328~'-~435'; 3795'-3960' with 2-1/8" through-tubing perforating guns. Rig down & return well to production. Note: Static bottom hole pressure is estimated as 500 psi. Well will be flowing by means of gas lift during perforating. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon ~ Suspend E3 Operation Shutdown "3 Re-enter suspended well ~ Alter casing [] Time extension--L_: Change·approved program [] Plugging O Stimulate ~ Pull tubing ~ Amend order [] Perforate.~ Other 2. Name of Operator Unlon 011 Company of California (UNOCAL) 3. Address P.O. Box 190247, Anch, Ak., 99519-0247 4. Location of well at surface 1615N' 561'W of SE corner Sec. 4, T9N, R13W, SM At top of produCtive interval ll'S, 50' E of surface At effective depth 36'N 126'E At total depth 1826'N 514'W of SE Corn. Sec. 4 T9N~ R13W~ SM 11. Present well condition summary Total depth: 5. Datum elevation (DF or KB) KB 101 feet 6. Unit or Property name Trading Ba: 7. Well number A-7 8. Permit number 67-46 B. APl number '§0-- 733-20036 10. Pool measured 6,397' feet true vertical 6,381 feet Tyonek B Plugs (measured¢;052' bridge plug 4550 ' bridge plug Effective depth: measured ~,550 feet Junk (measured) 546 feet true vertical Casing Length Size Cemented Measured depth True Vertical depth Structural , , Conductor 1~0~ 1393~,641~# 48~10 ' ' ._ '. Surface Intermediate Production 1651' 7" 26# 6397-4746 6397-4746' 4741-638; Liner Perforation depth: measured See attached R[CEIVED true vertical T~op perf 2882 MD. 2881 TVD ~r.m perf 3956 MD, 3952 TVD Tubing (size, grade and measured depth) See attached Alaska 0il & Oas Cons. Anchorage Packers and SSSV (type and measured depth) See attached 12.Attachments Description summary of proposal ~ Detailed operations program Well diaqram 13. Estimated date for commencing operation Farl y 14. If proposal was verbally approved BOP sketch - Name of approver Date approved hereby certify that the foregoing is true and correct to the best of my knowledge ed/~¢_.¢6,., ~ ~¢.//~Roy D, Roberts Title Environmental Enqlneer Commission Use Only Date 08/29/88 Conditions of approval Approved by Form 10-403 Rev 12-1-85 Notify commission so representative may witness ,"q Plug integrity [] BOP Test [] Location clearance Approved Copy Return~ ORIGINAL SIGNED BY LONNIE C. SMITH ' Commissioner Subsequent JApprovat No. ~?,. ~.~:~ the commission Date Submit in triplicate/~ I i1__ '!11 ,,, 31'8 33'6 41'3 41'8 44."7 V ¥11 VIII -,e=e WELL TBS A-7WO 1 CASING& ABANDONMENT DETAIL II.) !11.) iv.) v.) vi.) vii.) VIII.) I.) Rotary Table Measurement at 0.00' Tubing Hanger at 37.86' 13 3/8', 619, J-55 Casing at 1067' Bridge Plug at 4550' Top 7', 269, N-80 Liner at 4746' 9 5/8', 409, J-55 Casing at 4810' Bridge Plug at 6052' 7', 269, N-80 Liner at 6397' TUBING DETAIL 2 7/8'; 6.4#, N-80 TUBING 1.) Ball Valve at 291.55' 2.) Otis 'CX° Gas Lift Mandrel at 1782.70' 3.) Otis 'CX' Gas Lift Mandrel at 2593.38' 4.) Otis 'CX' Gas Lift Mandrel at 2755.23' 5.) 9 5/8' x 2 7/8°'Model 'RH-I' Packer at 2794155' 6.) 'X' Landing Nipple at 2804.84' 7.) Bottom of Tubing at 2836.60' PERFORATION RECORD DA TE INTERVAL CONDITION 9/10/67 3300'-3320' Squeezed 3820'-3840' Squeezed 4140'-4160' Squeezed 4605'-4625' Squeezed 9/15/67 4125'-4225' Squeezed 8/17/70 2882'-2896' Open 31-8 Sd. Production 2928'-2944' Open 31-8 Sd. Production 3044'-3076' Open 33-6 Sd. Production 3196'-3208' Open 41-3 Sd. Production 3214'-3240' Open 41-3 Sd. Production 3290'-3434' Open 41;8 Sd. Production 3808'-3850' Open 44-7 Sd. Production 3858'-3956' Open 44-7 Sd. Production NOTE: 10' OF CEMENT ON TOP OF BP AT 4550' AND ON SAND AT 6052', FOR PERFS IN MIDDLE KENAI .... C , D , & HEMLOCK ZONES SEE ORIGINAL WELL HISTORY WELL TBS A-7 WO ¢ WELL SCHEMATIC UNION OIL. COMPANY OF CALIFORNIA APP'D. .~C,~ LE NONE ~.'r?. 2/J,7.,2/.. 65 , . REV.Form 9~0.6~P~3 ~'~h Submit "Intentions'' in Triplicate ' & "$ub~e~uent l~eports" ~n Duplicate - STAYE OF ALASKA OIL AND GAS CONSERVATION; COMMI~EE ' J 3-E'MG'-"~ ........................... (DO not use this fora for proposals ~ drill or to deepen or plug ~ck to a diffMren~, r~. Un~on O&~ Company o~ Ca~&forn&a ~rad&n8 Bay State A~sS O~ oP~A~o~ ......... pl,¢~$bSd.; OT O;L A;.;D GAS ~ A~CHO~AG~ 507 W. Northern Lights Blvd., Anchorage, Ak. 99503 A-7 ........ - C~N~. LOCATZON. O~ W~L ......... m. F~ ~ ~OO~, Om w~CA~ A~¢a~e 1615'N & 561'W from SE corner Section 4, T9N, Trading Bay-Middle Ken;,~l~'' -. R13W, SM u: smc., ~.. ~., ~., (m~ ~o~ ..... ' , O~IVE) · Sec. 4, TgN, R13W, SM. , ,~ ,, ,, 1~. ~LEv~oNs' (Show Whether DF, R~, GR, etc. i2. P~T ~O. 101' R.T. above MSL I 67-46 , ,,, , , , , , ~ , , , , , , ,, ,, Check Appropriate Box To I,n~ I~ture of N~Otice, lte,~'t, or Other ,Data NOTICE OF INTENTION TO: TEST WATER SHUT-OFF FRACTURE TREAT SHOOT OR ACIDIZE REPAIR WELL PULL OR ALTER CASING MULTIPLE COMPLETE CHANOE PLANS 6UBS~QUENT REPORT OF: FRACTURE TREATMENT t--I ALTERII~O CA6INO SHOOTING OR ACIDIZING b_.wj ABANDONMENT* (Other) Recomp iet ion ,. (NOTE: Report results of multiple completion on Well (Other) Com~letion or Recompletion Report and Log form.) 15. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertineut details, and give pertinent dates, including estimated date of starting an;r proposed work. Trading Bay State A-7 was producing 200 BOPD from a dual completion in the Middle Kenai "C" and Middle Kenai "D" zones, with a high gas-oil ratio approaching the 2000 ft3/bbl allowable. It was proposed to isolate the "C" and "D" Zones with bridge plugs and recomplete as a single oil well in the Middle Kenai "'B" interval. This work was completed as follows: 1. Moved rig over A-7 @ 6:00 pm 8/13/70. Killed well w/76#/ft3 Invermul. 2. Removed Christmas tree, installed and tested BOE. 3. Pulled dual strings of tbg, and CO to sand fill @ 6052'. Pumped 10' cmt on top of sand (isolating Hemlock Zone). 4. Isolated Middle Kenai "D" zone with CIBP @ 4743' - dumped 10' cmt top of plug. 5. Isolated Middle Kenai "C" zone with CIBP @ 4550' - dumped 10' cmt top of plug. 6. Ran CBL 4500'-1500' Bond good between "C" & "B" zone and above "B" zone. 7 Perfd Middle Kenai ~B" zone two 1/2" hpf for production 2882' to 2896' 2928' . , to 2944', 3044' to 3076', and 3196' to 3208', 3214' to 32'40', 3290' to 3434', 3808' to 3850', and 3858' to 3956'. 8. Ran single string 2-7/8" tbg (89 jts) w/singleGuiberSon AH-1 pkr @ 2794' & g.1. valves in place. Form ,sTATE OF ALASKA Submit "Intentions'' in Triplicate & "SubzeqUent Reports" in Duplicate OIL AND GAS CONSERVATION; COMMITTEE SUNDRY NOTICES AND REPORTS ON W~LS (Do not use this form for proposals to drill or to deepen or plug back to a diffierent reservoir, Use "APPLICATION FOR PEH1ViIT~" for such proposals.) ?~. 2 AP1 NUME~OAL CODE 6. LEASE DESIGNATION AND SERIAL NO. 7. IF /NDIA.N, ALLOTTEE OR TRIBE NAM. E 0IL ~. GAS WELL WELL [~ OTHER 2. NAME OF OPERATOR 8. UNIT, F~ OR LEASE NAME Union Oil Company of California 3. ADDRESS OF OPERATOR 9. WELL NO. TBS A-7 4. LOCATION. O,F WELL 10. FIELD ~ I~OOL, OR WILDCAT At surface 13. ELEVATIONS (Show whether DF, RT, GR, etc. Ch~ck Appropriate B~x To I~ndi~te I~ature of N~oti'ce' Re 11. SEC,, T., R., M., (BiYITOM HOLE OBJECTIVE) 12. PERMIT NO, NOTICE OF INTENTION TO: TEST WATER SHUT-OFF ~-~ PULL OR ALTER CASING FRACTURE TREAT j__ j MULTIPLE COMPLETE SHOOT OR ACIDIZE ]~ ABANDONs REPAIR WELL CHANGE PLANS (Other) ~IUBSEQUENT REPORT OF: FRACTURE TREATMENT ALTERING CASINO SHOOTING OR ACIDIZING ABANDONMEI~T* (Other) NOTE: Report results of multiple completion on Well ompletion or Recompletion Report and Log form.) 15. DESCRIBE PROPOSED OR COMPLETED OPERA~IONS (Clearly state all pertinent details, and give pertinent dates, including estimated date of starting any proposed work. . . 10. 11. Nippled down BOE, installed single 10" 3000# Christmas tree. Displaced system w/diesel and set pkr. Tested OK. Placed well on test via gas lift. RIG RELEASED @ 9:00 pm 8/19/.70, well started flowing. Well flowing from Middle Kenai "B" Zone. ! 16. I hereby certify SIGNED ~ae_ = (This space for state ofl~ce use)// APPROVED BY CONDITIONS OF APPROVAL, ANY and correct TITLE Dist, Drlg. Supt. DATE ..... 8/24/70 TITLE DATE See lnstrucfions On Reverse Side Approved Copy Returned Form 'P~3 REV. 9-30-67 STATE OF ALASKA Subrrflt "Intentions" in Triplicate & "Sul~equent Reports" in Duplicate OIL AND GAS CONSERVATIONi COMMITTEE SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen or plug back to a diffierent reservoLr. Use "APPLICATION FOR PER1VIIT~" for such pro.posals.) OIL OAS [] WELL WELL OTHER 2. NAME OF OPERATOR Union Oil Company of California 3. ADDRESS OF OPI~RATOR 507 W. Northern Lights Blvd. ~. Anchora~;e~ Alaska 99503 4. LOCATION. O.F WELL Atsurface 1615'N & 561'W from SE corner Sec. 4, T9N, R13W, SM. 13. ELEVATIONS (Show whether DF, RT, GR, etc. 101' R,T, above M$~ 14. Check Appropriate Box To In.cate Nlat'ure o~ N~ti'ce, Re 8. UNIT, FAR2VI OR LEASE NAME Trading Bay State 9. WELL NO. A-7 ' 10. FIELD A~gD POOL, OR WILDCAT Middle Kenai "C" & 11. SEC., T., R.7'B/I., (I~OTT6M YI6I.~] - - OBJECTIVE) Sec. 4, T9N, R13W, SM. 12. PER1VIIT NO. 67-46 ~ort, or Other 'Data NOTICE OF INTENTION TO: FRACTURE TREAT MULTIPLE COMPLETE SHOOT OR ACIDIZE ABANDONs REPAIR WELL CHANGE PLANS (Other) Recomp lete SUBSEQUENT REPORT OF: FRACTURE TREATMENT ALTERING CASING SHOOTING OR ACIDIZING ABANDONMEI~T* (Other) (NOTE: Report results of multiple completion on Well Completion or Recompletion Report and Log form.) 15. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent details, and give pertinent dates, including estimated date of starting an~' proposed work. Trading Bay State A-7 is currently producing 200 BOPD from a dual completion in the Middle Kenai "C" & Middle Kenai "D" Zones. The well is producing with a high gas-oil ratio:which is approaching the 2000 GOR allowable. It is proposed to isolate the "C" and "D" Zones with bridge plugs and recomplete as a Single oil well in the Middle Kenai "B" Interval. Estimated St.art~ng Dat~: 3/20/70 P. roposed Procedure: 1. Move over well· Kill well w/70#/ft3 invert emulsion fluid· 2. Remove xmas tree & install BOE. Pull dual tbg strings· 3. Clean out to PBTD @ 6099'. 4. Isolate Middle Kenai "D" Zone w/CIBP @ 4745'· Dump cmt on top of plug· 5. Isolate Middle Kenai "C" Zone w/CIBP @ 4550'· Dump cmt on top of plug· 6 Sqz for zone segregation @ 4480' 3960' & 2200' 7. CO w/bit & scraper to 4550'. 8. Perf Middle Xenai "B" Interval' as follows: 2882-2896, 2928-2944, 3040-3076, 3196-3206, 3214-3242, 3290-3418 3426-3432, 3808L38~0, 3858-3956. 9. Run single hydraulic pkr & g.1. valves in place. Hang pkr.@ 2150'*-. Instl BPV. ND BOE & NU'xmas tree, displace w/diesel, set pkr, & release rig. Place on production a.~ sin~]m, zona Middlm Kenai "B" nroducer. 16.1 hereby eert~/~.~t t~rffotng ts true and correct ' CONDITION8 I~ : OF' APPROVAN, ANY Approved Copy' Returned See '[nstrucfions On Reverse Side ~ _ DIVISiC'N CF OIL AND GAS ANCHORAGE Form P--7 OIL AND GAS CONSERVATION I Il I._ [ .I .[. il i WELL COMPLETION OR REC?MPLETION 'la. TYPE OF 'WELL: OIL [~ CAs ' [~] ~ i [--] %%'ELL ~ WELL ~ '~DRY I'I b. TYPE OF COMPLETION: NE,W [] WORK _ %VELL EN 2. NAME OF OPERATOR STATE OF ALAS A '.-' ~--. ~: ...~ ( See other ~- ' st ructions on · 1~.'~ ~*~.9'. :~ ,-- - , - . 6. API NIIMERICAL CODE $. I~F_~E DI!I~IGNATION A-ND S~ NO. l~% '~ADL 18751 8. U~,F~ OR ~SE N~E Trading Bay State ~ i' J U--'~ ~'~ 9. WELL NO, Union Oil.Company of California :' ~- :~ :~.. 3. ADDRESS 6~ OPERA~OR ~ ' .... ' ~-'~ · ~ ~-- .'~ = A-7 4, LOCA-TION OF WELL.Report loc~tt~n clearly and'~in accordance witK ady{~a~r&~u~ments)* [ ~.~4~. i'""~'~-1615'. N ~ 5613. W f~om.SE co~ner Se,~; T~,~R18W, SN A{toP pr0d. inte~l revorted"below (6!60) I78' N ~ 6~]~ ~f sub, ace locatio0 At total dep~ (407) 211' Nfl 47' E o~ suria~'i0c[t~n.~ . Sec. 4, TPN~ R15~, SM _ ~ · :_ ._~ ~: ~-: ~. ..... 67-46 8.27-67 · I 9-28-67 : I 10-12-67. ~ ~ ¥~R2T. 101' above ~S[ 18. T~ D~, ~ & TVD~9. r~U~, ~ 'MD & ~.~. ~ ~L~~~ ..... Im. ';S~,a~*~S ' ' ' [ ~ '- I ~W ~Y*~ ~. ~ '.--. I aO~X~ TOOLS " ' I " c,a~e TOOLS ..... 54o~ ~D, 53S9 vp~ 5SSO ~', 5SSS VD~i Sin~!~ 7 > '~ ~':1 , 5407 ~. PRODUCING ~V~(S), OF:~iS ~IO~, ~M, ~ :~ ~a~) ' [ ~. W~ DI~E~ON~ ' ': · - ..... ' C, .... ~ t~ ~--~ ~ t SURV~ MADE 6160 MD, 6145 VD to 6205 '~, 6~90 VD ' ~ ....,o =- "'~-:.~ 0225 MD, 0210:VD to 6330 ~,,-0~13 YD ~He~l(e[~' /-. ::~':" 4924-0307 -- " - .~ . : m~ 'i> L'' ~ ' ,J ' SOnic CDM, G ,:. '~ ~ :::" " IES, , · -R CST -:: o :', .,~ ~ '"' ~.' .... -~ - CA~G ~ (Re~ all str~s set ~ w~l) , 9 s/8 l,: 40 '" ,l'-,J::ss:-'i 4810 : ~ta'.~/~ ]'~oe 800 sacks DV 2974- ,.. ': ! ' i~ - I : ~ = ' q.-~ 760 s~cks ' '. . ' L ' ' ~ · ('3 (,q ~ C' . ' .~ i- ~ ~- , .,. l-.. .... f-.!. . :,'. ",:-;l ...... 2~. "LINER ~CO~ : ' - ::: C[~- : ~ [ 27.. TUB~G 8~~, 't ToP (5{D,I o,,~-, l~,~ ~~ ! I D~ g~ (~, r CCI(ER SET ,D) 7', ' [4746 [. 779~,. ,[ 460 : ]'J~"~f.{ I~' 28. PE~O~TIONS OP~ ~ PRO~O~. ~Inte~al, s~e and numar) . 29. A~, SHOT, F~'U~, C~ENT SQU~ZE, ~C. 4 jet holes/foot. D]~PTL~_IIq~IRVAL(1VID) 6160-6205 ~'~300-3320 '1 -6 s-6 3o ' i8 _o- s4o "I ' ~412'5-4140 I : ' '~160-4225 J DATE FI~ST.P~ODUC~O~ ~O~UCTIOH METHOD (Flowing, g~' lift, pump~size and type of 8ee ~$4.' DATE OF TEST, [HO~S T~ ' [~OXE SIZE [PROD'N FOR OI~BBL, ~o " ~ ' . 1 W, ~BI G ~AS~G P~S~ [C~~~ OI~BBL. O~~. ~' -' > ~ 31' ' ' ' A3ViOUHT ;~!D ~ND O~ M~TE~AL US~,D Test ~ S~zd 200 sx. cement Test ~ Sqzd 100 sx. cement Test & Sqzd 75 sx. cement Test ~ Sqzd 75 sx. ~ement WELL STATUS (Producing or ~"~'~%hut In jw~-~. TEST WITNESSED Bt ',IST O~' ATTACHMENTS certify that the foregoing and a~tached information is complete and correct as determined from all:available records ' TITLE Dis~ Drilling $,uperintendentoxT~. Dec. 28, 1967 D ~ McMahan ~:., *(See Instructions and Spoce, tot Additionol Dato on Reverse Side) INSTRUCTIONS .,C-ener,al: This form is designed for- su~mitting_.a complete ancl correct well coml~!~etion report end tog on ~"~11 tY..~es of lands and leases'in Alaska. "' ' ~ :Item:-16: Indicate which eJevation is:'Osed as reference (where not otherwise shown) for depth measure- (,,'"%. ..ments.giv.e.n in ether spaces on this form and in,tony attachments. .. i.item~Z20, and 22:: If this well is c~mpfeted fo(,separatc production from mo~e than one interval zone ,, '(multiPle completion), so state in .item.20, and. in item 2? show the p,c. Juci~hg interval, or intervals, 'top(s}~~ bottom(s) and name (s) (if any)'fbr only the inte. r~vaJ reported in item 3Q. Submit a separate repc~rt(.i......%' ;mx ... i(page): on -~his form, adequately identified, for each addi~io,~,al inte, va! to be seperatety produced, s~9~ ~' _i"0~ ._ :ing ~Ee ,:/dkJitionaE"data perfinent to such-inter~al. '~:? · . : .--- ,. O~, ~:,?"'-' '.ltem2j: "Sacks cement": Attached suppi~men~·~l records for this well should show the details of :any mul- ~;fiple.:~tage..ce'm. enti~g and the location.of, the cementi~'g' 'tool. '- 'ftem '~$: Submit a.'~eparate completion' re'port on this form for each interval to be separately p?oduced. .:_(.See i,~struction for items 20 and 22 a..bo~e). .. 'r"6F IPORM^TION TE~"I'S "I'~ t'LU I)I N (; I N"i'Eli. V^ L, ~'Er). PH~URE DATA ~ ~OVEttI~'~F OIb....'t3AS. - ..... : ' 35. G~GIC ' .' WA~ AND MUD st: 6160-6205 [ ~62'25-6530 Set packer-at 6036' with tail of N*~ ~,~.s. 6'~m mu~vm..6~, ~t 6155'. ~Orf6'~ated.~in diesel Oith 4~'~holes per'~f6ot. Well, ' " ...... ~. Re-perforated 616056190 [ 6225-6530~ ~ell ~oul. d not floW, Top(Hemlock 6123 6109 11 for ten hburs. Avei~age rate of 138 B/D, 1.5~ ;cut', 24°-25°.API :: -': 2620 on gas lift. Installed blanking plug in permanent packer at ~ · orm P-7 dated OctOber 18, 1967' for subsequent completion. ' ~..: . . ~ .'-: .. .~ : · . · ,. . . ..... ~ .. .... : .... . . .... : ~, . ,. · .. f ' :., .,, . , ,,,,,,,, , ,,, %XTA, Aq'I'ACt{ BR1E~''DESCRIPI'I'I'O'NS OF LITltOLOGY. POROSITY. FIIAC'~RES, APP~NT DIPS ".' :-. :~ND I)E'I'I;X;TEI)..SHOWS ;O,F Oli~, GAS OR WAT~. . , ,, ,, ~ . ~, ,~',, , _ ,,,,, ,~ , ,,, , ,,,, ~ .. . : .. .. . ? ...:~ · .,.. ; ~ : · ~: -: ..., ...... I ' ' '; ~ ) '~' . . . . ~-,.~ .. ., . ~ ' , .... , ..~. ,,,. .. 2 ~ ., .... ....... . Union Oil Compam, f'"!California ~ 507 W. Northern Lights Blvd., Anchorage, Alaska 99503 ~. Telephone (907) 277-1401 ~,,~ union December 15, 1967 Mr. Thomas R. Marshall, Jr. Petroleum Supervisor Division of Mines fi Minerals 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Marshall: SUBJECT: Trading Bay State A-7 Correction fi Addition to Form P-7 filed October 18, 1967 Ran packer on 2 7/8" tubing. Set packer at 6036' with tail to 6135. Lane Wells perforated 4 holes per foot from 6160-6205 and 6225-6330. Well perforated with casing and tubing full of diesel. Unloaded tubing with gas lift from S986'. Well would not flow. Re-perforated with 4 holes per foot from 6160-6190 and 6225-6330'. Well wo~ld not flow. Gas lifted well for 10 hours. Hemlock Zone produced an average rate of 138 B/D, 1.5% cut, 24°-25~ API Gravity GOR 2620 on gas lift. The Zones are packer separated. The H~mlock Zone is open to the tubing but the well is not wet nor will it produce without gas lift. Yours very H. D. McMahan ~istrict Drilling Superintendent ANCHO~GE ,, Form No. P--4 STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE Effective: July 1, 1964 LAND {~VFI~E LEA~E NU~B£~ LEASE EIR UNIT NAME LESSEE'S MONTHLY REPORT OF OPERATIONS T1~e followinff is a correot repor~ of operatior~s and production (ineludinff drillir~ff and produoinff wells) for th,e month, of ...... _O___c__t__o__b__e_x. ...................... 19__~__7_ ............................................................................. .,1~enffs address ___$_O_7___~,___N_oX_t_h_e__r__n____L__i_g_h_~_s___.B_.l__v__d__: ........ Company U~_i__gn Oil C o.m. p_ _a_ ~ny_ /Lo_ .f Cali£ornia Dist. Drlg. Su erintendent V~one ........ ~ZZ_-_~_4__0_~ ........................................................... ~en~'s uae ................................ 9_! .................... SEC. AND BARRELS OF OIL (~RAVITY (~ASOLINE WATER (If (If drilling, depth; if shut down, oauze; ~ OF ~ TWP. RANGE WELL DAYS CU. FT. OF GAS (]ALLON$ OF BARRELS OF RE~ViARKS NO. Pnov~c~. (In' thousands) RECOVERED none~ so state) date and result of t~t for gasoline oontan~ of ga~) · TRA[~ING BAY 5TAT',~ A-7 5407~ TD, ¢i350' ED packer set @ 6099~. Perfor;ited ~ith 4 3/8" holesi'£oot 61~ 0-6205' ~md 6225-6330', ;700-4600' at intexYals. J ~ig released 10/11/67. ~/ell on pr,,duction I .. ~ k~~ NOTE.~There were ............. NO ..............................runs or sales of oil; ......... NO ................................. M cu. ft.,b~gas sold; ............................. NO ......................... runs or sales of gasoline during the month. (Write "no" where applicable.~ NOTE.--Report on this form is required for each calendar month, regardless of the status of operatlons,"and ~ust' be fried in duplicate with the Division of Mines directed. FORM 369 4-63 UNION OIL COMPANy OF CALIFORNIA Document ansmittal N0._ TRANSMITTING THE FOLLOWING: / . ~_.,:,..-.~x~ ~.~. 4 ~.~_",.x~ ;' ' %,'i .~. . ..:, ~. ~ ,._:x..- .,.--.- .',x,._x, ~_4 / --,,.._.,-, · II ' ~. '/. ,'-" ' : '""""~¥"D t, 1- 2 1967 MINES & MINI~i,~I,,~ Form P~7 ':i'; ~'~" SUBMIT IN DUPLi -~ ~:~ " ~ ~TATE OF ALASKA ---'~ ~ structions on ~.: ... ~%: ~ ~. reverse side) 2.~.~M~ OF O~pa ~ ~ ' ~ ~'pni~ 0 Corn ny f California ¢}.07 $. ~the~n Ls~ht~ Blva. · Xtsu~aee t61.5'N~[~ 5~['W~ro~,SE corner, Sec. 6, TgN, R13W, SM · ~port~-ibelow (45~' ~) 38 ' N & 129' [ of Surface Locatio: ~ ~ ~ [ ~ (!~ ~'I ~t total de~ '--~'(57J0 ~) i~'N~ 92'E of Surface:?_Location ~ ' ' 67-46 ~ 8/22/67 Effective: July 1, 1964 ~....~ 5. LEASE DESIGNATION AND SERIAL NO. ADL 18731 /~ , 6. IF INoIAN, ALLOTTEE OR TRIBE NAM~ J'~ 7. UNIT AGREEMENT NAME .: 8. FARM OR- LEASE NAME Trading Bay State 9..'WELL NO. A.7 10. FIELD AND POOL, OR WILDCAT Trading Bay 'HemloCk · 11. SEC., T., R., M., OR BLOCK AND SURVEx OR. AREA · Sec. ~4., T9N, R13W, SM ~ ; . 1:2. BOROUGH ]. 18. S,TATE~ :enai i Pentn. Alaska ..... ~, ........' .... 2V:-.._ :' ": . ?'. { 19, ELEV. CA~rINGHEAD 15.fDATE SPUDDED. ~-F i6. D~TE T.L~ REACHEDm [(17. DATE COMPL. (Re~g tO ~27767 ;-'~; :~{~ 91-~81~ - I';:~ 10112167 ~T lOl' above ~SL 20. ~AL~H~ ~-& ~ . 9 21..tLUO, B~ T~Da MD & ~ 22. IF MULTIPL~.COMPL. 23. INT~RVAL~ ROTAR~ ~OOLS CABL~ WOOLS 6407' -'~ 63~ 60 ' J608 D Dual ..... ' " 25. WAS DIRECTIONAL 24f;RODU~ING "~ + . INTEK~AL(S), OF TJX. IS COMPLETIO~NTOP, BOTTOM, NAME (MD A~D TVD)* .,~90~' -.57~0'},.0 i6~.rfal"~ 4895'~- 57~'~ 26._TYPE-ELECTRI~ AND O~ER LOGS~UN2 ;~ Son~, c ~' ~aZ, CST '~ES ~:~ ..._ , -' CtSI~ SIZe: ") -.. -: Di~TH SET (MC) -~0~ S!ZE~. CEMENTING RECORD ~ ~.~9:'/8''~.~ ~, ,,_f ,t~~ :,''~: ', 4'~'~ [ 2,.. 4810' ' d;l~i!/~' .Sh°e' 800 sks.DV02974-760sk' SURVEY MADE , 6~40i 4924 27. WAS WELL C0~ yes -' AMOUNT PULLED · None ': None ~29.c~' <, ~ '~'% c: C c: /i :: LI~ERoKECORD ~' L ~/' - '"' 30. TUBING RECORD ~ "'"'"' :.! - - - [3300-3320 [Test & Sqzd. 200 sx.'cmt' 5005 5020, ~0 5120, 51 5 , , 5260-5290, 5360-5390,'5435=5460;5495-5505,'[~ 'Test a S Zd. ~00 Bx. cm~. 88.* PRODUCTION' PRODUCTION METHOD (.FlOwing, g~s lift, pU~pi~g--SiZe a~d. type of p~mp) WELL STATUS (Prog~ci~g or 10/11/67 ........ Flowing" DATE FIRST PRODUCTION Frouuclng . · DATE OF TEST !~]i HOURS TESTED [ CHOKE SIZE ] PROD'N, FOR .OiL------B~I~_ G~fL.--~.MCF. . ~. W~ '-' AT~:- ~" ':~A7S~8~64'[-T'ST"p~alO~ I,A}:S'Z/~ ' I Al5 - 141 I AI~ ~i~:~67 A7L- 6, :(!~TL~J~di~:.!:, ':.~ :~.;~ ':(>:~' ']ATL~17 I A7L- 1081 A7L- i IA7L- 500 A7S - 125 I ' i 2i-.ooa RZ~m IA/E - /~Z AtP -"el? I OtP - . A7L - 270 I 390 [ ' > IA7L - 868 I A7L - 434 I aTL - ~ I A7L - 31.3 Used for fuel and vented TEST WITNESSED BY B. G. Spradlin OF ATTACHMENTS /~ :7 ~tif for~_go2tdg an.d~.t~h~ed information is complete and correct as determined from all available records *(See [nstruCflons una Spaces[0i~Aaaifi0hu[ Dui. on Reverse Siae) 0Ci 19 OI¥1SION OF MINES & MINEItAI~ INSTRUCTIONS Genera: This form is des~gned:tor submitting a'complete and correct well completion report and log:.~n all types of lands and leases to either a Federal agency o; or both,, pursuant to appli~)le Federal and/or'Sl~ate'laws and regulations. Any neces,qary special instructions concerning the use of this fbrm and the number ,submitted, particularly with regard to local, area; or regional procedures and practices, either are shown below or will be':issued 6y., or may(be obtaine~ from, ':and/o'~State office. See instructions on items 22 and 24, and 33; below regarding separate reports for separate completions.. ' ~ --. If not.fi)ed prior to:the time this summary record is bubmitted, copies of all currently available logs (drillers, geologists, sample and. core analysis, all types electric, tion and pressure tests, and directional surveys, should'be att, ached hereto, to the extent required bY applicable Federal and/or State laWS and regulations. -should:be listed on this form, see item 35. -. I'l'em 4:,, If there are no .applicable State requirements, locations on Federal or Indian land should be described in accordance with Federal requireme/~ts. or Federal office for specific instructions. · :Dcm ]..~ Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any att:: Dems 22 ~d 14: If this well is compI~ted for 'separdte production from more than'5'ne interval zone (multiple completion ) ;..so state in item 22, and"in it?.m 24 ahoy, interval, or intervals, top(s), .bottom(s) and name(s)- (if any) for.only the interval reported in item 33. Submit a separate report (page) on thi~ form, adeq, ~ for each additional, interval to .be. separately I~odu~, :showing-'the 'additional data pertinent to such interval. I$~m 29: "Sacks Cement": Att:ached supplemehtai reCOrds for this Well should show the details of any multiple stage cementing and the location of the C~mentim' Dcm :]3: Submi~ a separate completion report on this form for each interval to be separately produced. (See instruction for items.22 and 24 above.) , . 37. SUMMARY OF POROUS" ZONES : SHO'~,' ALI, IMPORTANT ZONES OF I'ORO~ITY AND CONTENT~ THEREOF; CORED INTERVAI,S'~ AND ALL DRILL-~TEM TESTS, INCI,UDIN(] · DEPTI1 INTERVAL TESTED, CUStIION USED, TIM'E TOOL OPEN, FI,OWING AND SItUT-INt'RESSURES,AND RECOVERIES FOR M ATIO N .. Middle Kenai II Hemlock Core 1 2 3 4 5 6 DST #1 2 TOP 1065 3820 5796 6123 3837 '4057 .-4069 4835 4853 6373 4605 4140 38.20 33OO ... .. 4125 4810 '5600 5635 BO~T9~'' 3437 5730 6020 6330 _ 3854. 4069 4082 48 3' 487.3 6387 462'5 41.60 . 3840'· .. 3320 4225 4873 56~0 5645 DESCRIPTION, CONTENTS, ETC. Possible oil (not tested) Oil (tested or produced at int~:rvals) Possible Oil (not tested) .Oil (production tested) Recvd. 17' Recvd. 8.5 ' Recvd .. "i 3 ' Recvd. 9 ' Recvd. 20' Recvd. 13 ' '.500# dUshion, 12-3/4 hrs'. FF.~ ~FP li35-86 '"0.5%, "25.3 o : gas cushion, 7 hrs. :~r,:!r~r~67-8o, z ~h0ie fluid with scum of Oil !500# gas cushion ,:12, hrs. i2 ~n~ FFi.7 FFP~ 4 '.0..,~25%, 23.7° ............. '500# gas cushion, 14-1/2'hfs ,rr, rFP 377 7~2-%, 22.~: 1 o ': '~.500# gas eushion,8hrs, FF, 'FFP/'i60-'77, ISI 500# gas cushion,20 hrs...FF, FFP 405-1150 0- 1.7%, 31.3° 500# gas cushion,8..,.hrs. FF, FFP 603-637.·i . 38, GEOLOGIC MARKERS Top Hemlock , .. , ISIP 2033, FSi .. IP 18117',"'~ FSIP 5! , . i8-908) ISI~ 168z 963, ISIP 1484)i 1817, FsIP 13~, ISIP 2065·, FSit TO MEAS. DEPTH 6123' -' P 1,518, Re~ 2,"Rec. 1- , SZP FS~P 1370, R~e. 22[ bl SIP 2494, FSIP' 141~, Rec. , , :7 7' gas cush±on, 8' hrs.'FF,'FFP 72.4-2085, ISTP 2243, FSIp 218!, Rec, ' ,."5122 6* 32 3° 51.4.4 .... .:500# gas cut oily mud £;EASE__Trading Bay State Trading Bay O,'.L GO. O [':' WlZLL P~ ~(CO N D WELL N'O._ A-7~.q_Oj~l LOCATIOx'~ Conductor (/22 1615'N & 561'W from SE corner Sec ,__4.= ~9N, .R13_W, S._~ Kenai Borough, Alaska' .~ ¢ 67-46 P,.,{~..IT NO .... SERIAL NO ADL 18731 PA O r~ lq O. St UD I) 11 ~ . CO NTIIA CTO D.__WOD'ECO . TYPE UNIT Oilwell 860 DRILL P1P~ Dz,,qCkIl i IO~ ELEVATIONS: WATER 1,LP'I H I1. T. TO OCIgAN FI.GOB COMP. DATE 8/19/70 BIG. NO 56 5 r r--x-:'~ o--1-~--i-9 ;"5 f! · 62~ 174' T.D. 6387' I.V.D. 6350' B.T. TO MLL\V~ 112' m __ 22.07' p~'xr~'.m~'~-~ ...... · R;T. TO D!~Ii,L DECK . . ., COMPANY ENGINEER Boykin, Shell ' .. R.T. TO PROI)U~/ON~,~~ - ' ',, '- · CAS,;IG 8e TUBING ~ECOtlD [ _il _ ' . I._ ~.1 _ I I -~ [ ~~~~3X-~X Z ~s.f¢~T-C ........... :- _ ~~ . &3-3/8;;.--~~~J~ _ _.~6~ F~~ t I . -,,. -' f". ''2st~" szs0 '6sw ~~='top ~-4~s' ~ . ...... 2 .... ~~_ . - ....... . _ 1.3,__&.~. _-_ .. ........... · . '' ' PERi, ORATING tECOnD . ~ ~ ] ~~] ] ~¢~-] -Zq- ~ ~'~~-- :9/~0/67 3300-3320 . ~7~9 _ . _ DSZ ~ _. ¢~z~ ~/200 sx co 2000¢( zoI 41402¢~ ' ~ ~ -7 ~ ~-' ~q~za ~¢~ ~ ~o 2000// 'Z0 "' 46DS'Z4625 -" ' DsT~-' s~z~ ~/Z¢0"sx co 2000t/ c6N~R: ':"-]! . ~ ; ~ _ .i DST ¢5 sqza wi/75 sx ~ ~0-~ (FOR PR ¢8/17/70 Il 4t25-4225 )DUCTION PERFS IN MIDDLE KENA[ "C","D",' &"~iEMLOCK ZON-~S,~'SEE ORIGINAL WELL HISTO~I1 6099' 4743' 45.50' 2882-2896 BP - isolati BP - isolati BP is°Iati 455O " 2928-2944 " " 3044-3076 " II II 3196-3208 3214-3240 ,, -. 3290=3434 3808-3850 3858~3956 .... II I! ~g Hemlock Zo Yg bliddle K~n 5g Mfddle Ken production ¥~,, II :' ' II ' ' le ti iii)ii-Zone ti ::C:: Zone ,open f~r P'rodud"fion'lim'Middle Kefiai ::Ii:: £nf'e'rVai INITIAL PRODUCTIOn[ · , . 2 SS ~ ' ~ ............... 3956' I 819 [ ' I ' 0 .~ Z 3ll'l-Ol; ..1030 330..j. 22_/~}4''._ 88~.... Z 07[ 9 f'i'Ow[[II_~; J ll Middle Kenai "]" · _ ! A.P.Io CODE'50'133-20036 Re]ease Date 11-12-69 ~ ,_. ., ._ ~, ,,,, State of Alaska Oepartment of Natural Resources DIVISION OF MINES AND MINERALS Pet roleum Branch INDIVIDUAL WELL RECORD Sec. 4- T. 9N R.. 13W S Meridian Permit No. 67-46 Issued 8-22-67 Operator_ Union Oil Co. of Calif. Lease No. ADL 18731 or Owner .... T_r_a__ding_pay_. S_t~ate Wel ! No, A-7 Area Location (Surface) 1615' FSL & 561' FEL, Sec. 4 Straight. h, ole Spud Date 8-27-67 Loc. (Bottom) Drilling Ceased PBTD 6099' Total Depth 6407' Suspended Abandoned S 742 Completed (F-,G,/../-~._ .... 10-12-67 IP_~_868 ....... B/D, S 141 48 -- GasL 108 MCF/D, Be~n 36. /64 CP 3~0 psi -- -- - _ ~,~ ,_ a_, .... ~ Elevation 25.9° Grav ~! _'~° APl Cut 123 TP 270 .... -.__ ps i 101' RT Casing: Size L3_3_/8/__'_:_ i_ lO67' DY 2974 9,. 4746 ) = 2 7/8" tbs. ~.~/~'~: tbs. GEOLOGI C FORMATIONS Surface L~st Tested - ._: ........ SxCmt 3820 ' -3840 '; 3300 ' -3320 '; 120. 0 . Te~s_t.~_cl~___the._n__s_q~_e.~e'_z_ed_ _eac_b: 760 interval to 2000 psi ~OO- 6t60'-6205 ' ~ 6225 '-6330' " - a-~i=Eer~iisTM4~-0b'-~7~-~ '-¥' ' _ 4_60 Perf: 4605 ' -4625 ' ;4125 '-4225 ~;!ugs _ 4514' Pckr,4508' 5A97' Pclr~~. ' - J l~ , ,,~,_,__ __ ,,_, . i i_l i , _ mi ,_ PRODUCTIVE HORIZONS Name Depth Con ten ts .-, , _L__,'L - ~---' - '--' - - ' - --' · '- · ' ' WELL STATUS Year Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec Perf. 4600'-40';4670'-4700';4720-35'; (Upper) _ _,,_ , ~, .... u,_._' '_-_~- _. - ......... ' ' -: __., ,, .... -' ':- -' :- - ' ......: :--- --- ~ - I I CI ! I 9 I I I ! 1 4900-20 ;500~ -20 ;509.0-~0 ;5~22 -42, ;5170'-90' ;5260l'-90' ;5360'-90,_. ; (Lower_). ....543.5" -'---60-'- -; b495' "--5o05-"'- --' ;5~40:-~ '- "-5550' -'~ ,5600;" ;'10-~'-;;'3630--~5- ;5 700-~-30 ~ -" ' '; ' (6160'-6205'; 6225'-6330' not producing) . ' ' _ __- .¥ :_ __ _ ~ _ _ -:.... :-__._ _ ._- _ ._. ........ -:-. _. · . _ _; __ · ._..,:. _ , ..... _,_, _ _,, . , ,_ ,_ .... _: _-_ Remarks: Contractor: Caldri!, Inc. ' UNIO OIL.CO. Of CalifOrNia " ' WELL RECORD SHEET C PAGE: NO,, i , I LEASE TRADING -BAY STATE %VELL ND.A-7 FIELD ,~RADIMC BAY CA ~ING & TUBING'RECO,R, D "'SIZE ' WEIGHT,, THREAD . I GRADE: DEPTH ~" REMA'RKS ...... , . , · 13-3/8 61# Buttress 'J-55 1067i~ Cemented w~th 170~ ~nc~s Class "c" ~om~nt ' 9-5/8 40# ' Buttress' J'55 .i: 4810' Cemented with 1560 sacks Class "G" cement blended - " . with CFR-2 (Two Stage) 7".Line:: 26# .. Buttress ; J-55 ' 6397' Cemented with.460 sacks.Class "G" plus CFR-2 .-2-7/8 6.4# Seal-Lock· N-80 ' 5497' Long String: F-1 Pkr @ 4832'; A-V Pkr @ 4508' 2-7/8 6,4# ' seal-Lock 'N-80 ' .4508' Short string , Baker S-2 Pkr w/dR plU~ set @ 6099' PERFORATING RECORD " REASON' ' ~'~-SE NT CONDITION DATE :" INTERVAL E.T.D. ~- .... -.10'1-67 '16160-6205' 6350' DST'' Perfs isolated by S-2 Pkr w/DR plu~ @ 6099' ' . i '~ Il WI II It II 6225-6330' 6350 ' " " 10-6-·67 '5600-5610' 6099' · ". Open.for present production 5630-5645' ' .6099' " "~ " " ,, ' 4600-4640 · '" production " " '" · · . 4670-4700 " " " 4720-4735 " " " , '' ' ' 4900-4920 ' " ' ,,., . · ' 5005-5020 " " " . I 5100-5120 " ' " " · 5260_5~90. " ~. ~ ,.. 5360-5390' " I 5435-5460 " ' ~ " " · 5495-5505 " " " , 5540-5550 " " ' 5700-5730 "· ' " "~ 10-7-67 5~ 22-5147.~ " DST " " , , INITIAL PRODUCTION ' I IDATE INTERVAL NET OIL CUT GRAV. C.P. T.P. iCHOX~ ~ ~O~ REMARKS 10-11-67 4832-6099 868 0.5 31.1 390 290 36/64 43~ 500 Long string prod 10-11-6'~ 4600-4735 742 0.7' 25..9 125 390 48/64 376, 505 'Short; string' prod · .. · . , · · , , · , · , · · , , · · -. , ,, · . · II ' 11 ~ Ii , ' ' WELL HEAD ASSEb~BLY TYPE: Shaffer Model KD, 12" 'Series 900 up w/2-2" LP screWed CASING HEAD: Shaffer Model KD', 12" Series 900 up w/2'2" LP scre~.-ed side outlets. Bottom to SOW 13-3/8" casing CASING HANGER: Shaffer 12" Nominal 9-5/8'' Model K.D.K.S. CASING SPOOL:, TUBING HEAD: 12" Series 900 x %0" Series 900 DCB w/2" 1500# stu~dded outlets TUBING HANGER: "R" Seal , TUBING HEAD TOP: .... Dual String, solid block w/master valve and swab valve w/o win~ valve MASTER VALVES:. 2-9/16" Bore UNION OIL CO. OF CALIFORNIA DRILLING RECORD SHEET D PAGE NO. LEASE. Trading Bay State WELL NO. A.-7 I FIELD Trading Bay DATE E.T.D. DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 3/20/69 23 Checked pressure in 9-5/8" x 13-3/8" annulus. Shut in pressure 500 psi, bled to 0 psi. 12 hr build up to. 475 'si. 9-5/8" x 13-3/8" annulus, 500 psi. 9-5/8" x tubing, 900 psi', bled 9-5/8" x 13-3/8; annulus to 0 psi. Connected Ilalliburton unit to well & pumped 8-1/2 ft of wtr into annulus w/pressure increasing to 2850#. Released pressure & recovered 7-1/2 £t3 wtr. Mixed 5 sx BJ Gyp-Seal & pumped 3-1/2 sx into annulus w/pressure increasing to 2900#. Washed out lines & displaced another 1/2 ft3. CIP @ 2:45 PM. 9-5/8" x tubing annulus remained constant 900# throughout squeeze job. No communication between 1'3-3/8" & 9-5/8" casing. RECEIVED APR 9 1969 DIVISION OF OIL AND GAS · LEASE Trading Bay State DATE f13/70 14 15 16 17 18 19 E. T. D. 6099' 6099' 6099' 6052' sand fill.' 4550' BP 4055' 4055' UNION OIL CO. OF CALIFORNIA DRiLLiNG RECORD SHEET D PagE NO. 3 V~ELL NO.. A-7WOf/1 FIELD Trading Bay DETAILS OF OPEiqATIONS, DESCRIPTIONS & RESULTS Started moving rig to Conductor #22 (A-7) at 6:00 pm 8/13/70. Trouble w/hyd pump for jacks. Used power from Koomey to complete. Completed move. RU wireline. RI to open sleeves in LS @ 4460 & 4798'~ after , pulling ball valves. Pumped down LS, out SS. Press increased in annulus. Disp out annulus w/76#/ft~ Invermul. When annulus full, checked sleeve @ 4798'. Unable to circ. RI w/wireline. Checked sleeve. It still appeared to be open, but'still unable ~o circ. RI to remove g.1. valves in SS. Unable to reach because of wax. Tried disp through g.1. valves into SS. Discontinued because of pressure increase. RI LS w/positive tool. Opened all sleevds in LS, still could not circ. Second try circ thru g.1. valves & successful. Amt of disp indicated entry thru,'valve @ 4437. RI w/wireline & ,closed sleeves in LS to the one @ 4460'. Circ thru this sleeve to kill annulus & LS, then thru SS. Killed well w/76#/ft3 Invermul. RI w/wireline. Closed all sleeves in LS. Placed ball valve dummies in both strings. Installed BPV in both strings. Removed Christmas tree. NU BOE. Tstd w/1500# OK. Pulled SS free w/10,O00#. Worked LS 1 hr & finally pulled free w/90,O00# & 1000# press under pkrs. POH w/tbg. CO to top of liner @ 4746'. Picked up 6" bit & 7" csg scrpr & CO to sand at 6052'. Circ & conditioned mud. RU wireline & pumped 10' cmt on top of sand @ 6052' to isolate Hemlock Interval. Set 9-5/8" Howco EZ drill BP at 4743' and dumped 10' cmt on top to isolate Middle Kenai "D" interval. Set 9-5/8" Howco EZ drill BP @ 4550~ and dumped 10' cmt on top to isolate Middle Kenai "C" interval. Ran CBL from 4500' to 1500' to evaluate cmt bonding above and below ~roduction interval. Bond excellent above & below "B" zone. Perfd Middle Kenai "B" Zone for production as follows: 2882'-2896' 2928'-2944' 3044'-3076' 3196'-3208' 3214'-3240' 3290'-3434' 3808'-3850' 3858'-3956' RU & ran 89 jts 2-7/8" 6.4# N-80 seal-lock tbg w/RH-1 pkr, top @ 2794'. Landed tbg in Cameron DC-B head. ND BOE & NU single 2-7/8" 3000# xmas tree. Tstd w/3000# OK. Disp system w/diesel. Set X plug in X nipple @ 2804'. Unable to press up on tbg to set pkr. Pulled X plug free & reset in "CX" at 2760'. Tested tbg to 1500# w/no communication on annulus. Attempted to seal off "CX" w/g.1, valve. Reset X plug in X nipple. Pressd tbg to 2800# & csg equalized. Held for 20 min indicating pkr set. Pulled valve &"'X" plug Pumped into formation @ 20 ft3/min., rate w/2000#. Formation bled to i500# w/pumps off. Attempted to test Csg by setting "blank plug" across "CX" @ 2760'. Tubing and csg equalized w/lO00#. Pulled blank valve out of CX. Opened CX mandrel @ 2755'. Installed g.1. valve & put well on test via gas lift from Middle Kenai "B" interval. RU to do rig repair while waiting on test results. Replaced rotary. Removed transmission. Sent both to beach to be repaired. RELEASED RIG TO A-19 W0 '@ 9:00 PM 8/19/70. Middle Kenai "B" Zone flowing. UNICa! OIL CO. OF CALIFO' qlA· DRILLING RECORD SHEET A PAGE NO. LEASE TRADING BAY STATE VCELL NO. A-7 FIELD . Trading Bay LOC:A,.T. ION ~ Conductor No.22 1615 N and 561i'w from SE corner Section 4~ TgN, R13W, Kenai Borou~.h, Alaska PERMIT NO.'. 67-46 ! SERIAL'NO. ~%DL-18731 T,D. 6387' T.V.D. 6350' DEVIATION (B.H.L.) SPUD DATE 8-27-67 COMP. DATE 10-11-67 CONTRACTOR Caldrill Alaska, Inc. RIG NO. TYPE_~NIT Oilwe!l 860 DRILLPIPE DESCRIPTION 5"- 19.5!! Hughes X-Hole ELEVATIONS: WATER DEPTH ~z' 1{ T. TO OCEAN FLOOR 174' '. R.T. TO MLLW ·112; R.T. TO DRILL DECK 22.07 ' COMPANY ENGINEER ~-0 "En.abror.~nn ' R.T. TO PRODUCTION DECK ,40.82 ' · · ~' - APPROVED: Ifil , I I r i r Il I I I . ,,. BIT RECORD MUD VEL. DEPTH & DEVIATION BlT JET DEPTH VERTICAL ', DATE DEPTH NO. SIZE MAKE TYPE SIZE OUT FEET HOURS 'ANN. JET DIRECTIONAL 8.27-67 0 Q 1 '12-1/4 Reed . YT3J .3/].4 1100' ll00 10 See Directional Plat 28 0 ~':~1.1~0 17-1/2 Smith 6 Point - 1075 1075 6 29' 1100 Ra'~n 13.3/8". CasinF. WOC ~,nd NiD~led u~ . 'I'30,, , 1100 2 12-1/4 Reed YT3J 3/14'1692 592 9 T-2 B, 2 31 I 1692 3 12-1/4. HTC .. X3.AJ 3/12 2510 818 1021/4 T-3 B-1 ~- 1. 2510 4 12-1/4 Reed.. 'ST3AJ. ~,/~/ ;//'~ 3085 575 11-1/4 T-3 B.-3 .... · ' ,....... ~'/, 3451 366 9-3/4 T-3 B-1 2 3085 5 12-1/4 Reed ST1AG.~ "~ - . 34.51 . 6 12-1/4-~ Reed ST1AG ~>*.///~- 3661 210 6 T-2 3661 7 12-1/4 HTC X1GJ x~4-//~_ 3837. 176 3 T-2 B-1 3 3837 i7--5/8 Chr. i~ Dia~' -,.- 3854 ,1'7 1-3/4 ' Core Head Cronved , , 3854 6 R~.12-1/4 Keed ST3A.:T. ~'/~/ >~z 4057 203 14-1/2. %-4 4057 7-5/8' Chri~ Dia --- " 4069' 12 ..3 Core Bbl Jammed 4' 4069 : 7~!8 Ch~'~ bia --- 40R9_ .13 ~-122_2. '. 4082 a 12-1/4 HTC ' XlO3 a/'~ "//~ 4233 151 6-112 125 ~10 T-~ 13-I 'I5 . 4233 9 12--1/4 [iTC X1GJ ,z,//, ,j)~. 4364 131 3-1/2 125 510 T-2 B-1 4364 10 12-1/4 HTC X1GJ m/// ,/;-~ 4496 132 8-1/4 .125 ~,10 T-2 B-1 I I ' " 6 ' 4496 11 12-1/.4 HTC X1GJ :/~, ,,&- 4778 282 6-3/4 125 510 1'-3 B-1 ... 4778 7 R~.12-1/4 HTC X1GJ ~,'~' 5~' 4822 44 !-1/2 125 510. Cond for Logs. T-2 B-l. 7 482,2. Lo:ged, Concitionec hole.~.nd ran 9-5/B' casir~z 8 . 48.22 Rat Casing, Cemented and r,ipoled uo 9 4759 12 8-5/8 Reed ST1AG Open CO C~..mentec FC onc Ran Bond Log ... 9/10-9/15 4759 Pez~fprated ~.nd Ran DST~ 9116-9/!7 4759 12RF Cementec Perfs ~and Dri.lled O~.t cem~..nt plt.g$ .~O /~822' 18 48?2 12RF '8-5/8 Reed ~TIAG Open 4824 2 1-1/2 155. 460 T-2 B-4 Junk in h0]o lq 4824 13 8-5/8 HTC . X1GJ 3/10. 4835 11 3 155 460 T-1 B-1 CO Junk , &835 7-5/8 C~hr~ Die --- 4873 38, 8-3/4 125 - 20 4873 R~rnin~ DST.~ and c~an~n~ hole b~.ck to ~ud ?! 4R7.~ · la 8-5/$. HTC X1C-J 3/10 4923 50 1-~/?_ 163 4gg T-1 B-1 _ ~ hq?1 ! 5 g-5 I8 Roed .qT I. AC 3/24 500'I 78 7-I/2 - . Dyna-Dr~ 11 72 q0~Ol .16 8-qt8 Reed gTIA(". 3/10 5299 298 10-1/2 205 52CI T-3 B-l. - 21 5299 17 ~-5/8 Reed 8T1AG 3/10 5455 156 9 205 520 T-4 B.-1 _ q&~ 18 8-5!8 R~d .ST1AC 3110 5561, 106 6 175 435 T-4 B-1 .. · --- ,5561 lq 8-518 Ra~d ST1AC 3/10 5659 98 4 175 435 T-4 B-1 ?4 - . 5659 20 8-5/8 Smith SV2HJ 311.1 5729 70 4 1.75 435 T-4 B-2 ' I I 5729 21. 8-5/8 Smith SV2H.I. 31-1.1 5779 50 4-112 175 435 T-.3 B-1 ~ . 5779 2,?, 8-.5/8 HTC X1CJ 3/10 5865 86 4-3/4 175 435 T-4 B-1 25 5865 .23 8-5/8. HTC XIG3 3/10 5908 ~ 43 3-1/4 175 435 T-4 B-1 -- i 5q08 24 8-5/8. R~ort .STIAC 3/9 601.8. il0 5-1/2 l&5 5'00 T-3 B-]_ 76 6018 ] 25 8-518 lqtC X1C.! 319 61Y, g 128 7-112 145 500 T-3 B-1 · 6146 26 8-5/8 HTC X1G.I 3/9 6197 51 2-1/2 149 5lq T-4 B-2 1/2" ... I. 61.07 27 8-5/8 [ITC Xl)7 3/9 6263 66 3-3/4 149 519 T-4 B-1 1/4" OG 27 67f~3 28 8-518 ~{tC ¥1C..T 3/0 631 5' 52 2-1 12 1 Ag 51 q T-4 R-2 1" _ I 6415 29 8-51R IqtC XIC, J 319 6373. 5'8 ql . 149 510 t-4 B-2 '6373 .7-5/8 Chr~q ir)~ -- 6387 14' 6 130 - } 28 6387 30 8-5/8 HTC iXlGJ ' 3/9 " 6407 20 3/4 149 519 r-1 B-1 · 29 6407 LOgged, ran 7" lit er WOC _ 30 . 6350 31 6-i/8 HTC OSCIG. Reg. CO cement to' 6350' , LO/1-10/116350 Logged, perforated, tested and ~completed · · , · .- I _ . _ ., UNION OIL.' CO. OF CaLIFORNia DRILLING RECORD .. .. - SHEET D PAGE NO. ,~ LEASE. Trading Bay State VMELL NO. A-7 .FIELD Trading Bay DATE 8~-27-67 28 29 3O 31 9-1-67 E. T. D. 524 1100 1100 1692 2581 3395 3837 4069 DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS Hoved rig over conductor 22# and spudded @ 3:30 p.m. Drilled and surveyed 12 1/4" hole from 0 to 524'. Drilled and surveyed 12 1/4" hole from 524' to 1100'. Opened 12 1/4" hole to 17 1/2" from 0 to 1075'. Ran 24 its. 13 3/8" 61# J-SS new buttress casing (1063.27t Centralizers @ 1042' 983' 943' 904' 863' fi 819'. Shaffer fin joint @ 39'. 13 3/8" casing Detail From To . 1067,00' 1064.90' 2.10' 1064.90' 1030.95' 33.95' 1030.95' 1029.32' 1.63' 1029,32' 48.90' 980.42' 48.90' 38.90' 10.00' 38.90' 0.00 38.90' Totals 10~7.00' 13 3/8" Baker Flexiflow cement shoe 1 it. 13 3/8" 61# J-SS Buttress, new smls. casing 13 3/8" Baker flexiflow float collar 23 its. 13 3/8" 61# J-SS Buttress, new smls. casing Shaffer 13 3/8" fin joint Landed below rotary table (zero) 24 its. + 1 landing jt 13 3/8" 61# (38.90') Cemented 13 3/8'' casing with 1200 sacks regular Class "G" cement mixed with Inlet water. }lad good cement returns to surface. Bumped plug with 1200 psi. Released press, and floats held OK. CIP @ 1:00 a.m. Installed Shaffer KD casing head and tested :to 3000 psi, pK% Installed riser and BOPE. Tested blind rams to 1000 psi for 15 mins, OK. RIIt with DA and tested pipe rams and Hydrill to 1200 psi for 15 minutes = OK. Tagged top of cement @ 1026'. Drilled float collar and shoe and cleaned out to 1100'. Bit ran rough and torqued up'. POI-[ and found some broken teeth on bit. Also found metal scars on shanks. Rill, but unable to get bit to drill. POH and picked up Globe junk basket with clusterite shoe. Ran basket to 1127' and cut 3' core. POH and recovered 3' of coal and shale, but no iron· FL~ran basket to 1130' and cut 3' core.. POH and recovered 3' coal and shale. Top of core contained 3 pieces of iron. Picked up bit and RIH and reamed 6' core hole. Drille~ and surveyed 12 1/4" hole from 1133' to 1692'. POH @ 1692' for bit change. Drilled and surveyed 12 1/4" hole from 1692' to 2581' with bit change at.2S10'. Had to ream @ 2350' going back in hole. While reaming well "kicked" with gas pocket unloading mud, clay, and coal to ditch. Circulated and raised mud weight to clean up hole and control gas. Drilled and surveyed 12 1/4'" ~ole from 2581' to 3395'. Drilled and surveyed 12 1/4" hole from 3395' to 3837'. POH to pick up.core barrel. Picked up core barrel-and RIH. Cut core .No. 1 (7 5/8" X 4") from 3837' to 3854'. Broke off core and POt{ when pressure indicated barrel' jammed. Laid down and recovered 17' of oil-sand core. Picked up bit, RIH, reamed behind core and drilled 12 1/4" hole from 3854' to 4057'. Circulated sample dnd POH to pick up core'barrel. RII! with barrell and cut core No. 2 [7 S/8', X 4") from 4057' to 4069'. Started out of hole after breaking 'off core. · · LEASE UNION OIL CO. OF CALIFORNIA DRILLING RECORD . · · SHEET D PAGE NO. Trading Bay~State WELL NO. A-7 FIELD Tradin~ 'Bay DATE E.T.D. DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 9-4-67 - 4564 4496 4822 4822 Finished POtt, laid down core No. 2 and recovered 8 1/2" Oil-sand with. good P ~ P. Ran back in hole with core barrel. Cut core No. S (7 5/8" X 4") from 4069' to 40.82'. POH, laid down core with recovery of 13' of oil-sand with good P ~ P. Laid down core barrel, picked up bit, Rill, reamed behind core, and drilled and surveyed 12 1/4" hole from 4082' to 4364'. Circulated samples @ 4564',' made short trip, and POll. Rigged up Schlumberger. Ran IES Log and Sonic Log with caliper. Found depth too shallow for anticipated next core point and casing setting depth. Rigged down lSchlumberger. Rill with bit and drilled and surveyed 12 hole from 4364' to 4496'. POH, changed bits, RIH, drilled and' surveyed 12 1/4" hole from 4496 to 4822', Circulated samples, POtt, and rigged up Schlumberger. Ran IES Log, Sonic Log with caliper, and Continuous Dipmeter. Started running Gamma- Ray - Density Log. Finished running Gamma R~y - DenSity Log and obtained side wail samples. Rigged down Schlumberger. RIH with bit to circulate to condition hole for casing. POH, changed to 9 5/8" casing rams, and rigged up to run casing. Ran S6 its casing when well "kicked". Closed rams and installed cementing head on casing. Circulated to pit through choke to work gas out of mud (Est. approx. 75 bbls. mud lost when well kicked) After killing well, continued running 9 5/8" casing. Ran total of 112 jts. 9 S/8" 40# J-SS Buttress casing with Baker Model "G" shoe @ 4815', and Baker Model "G" float collar @ 4772'. Halliburton DV collar located @ 2977'. Mixed and pumped 800 sacks Class "G" cement with CFR-2 using Inlet water. Displaced cement with 2050 ft mud using #2 rig pump. Bumped plug with 1000#. Dropped DV opening bomb and waited 1S minutes for same to reach DV collar. Opened DV with 2100# and circulated 1240 cubic feet mud obtaining 192 cubic feet cement in returns. Mixed and pumped 760 sacks Class "G" cement with CFR-2 using Inlet water. Displaced cement with 1268 cubic feet mud using rig pump. Lo, returns after pumping 1S minutes. Continued pumping additional S minutes without returns, and bumped plug with 1800 psi. Released pressure and floats held OK. {Note: Last 100 sacks cement in 1st stage contained 2% CaC12) CIP @ 9:00 a.m. 9-8-67. Picked up and installed slips. Cut off casing and installed casing landing spool. Re-installed riser assembly and BOPE. TeSted blind rams to 1SO0 psi. Rill with bit to drill out DV collar. 9 S/8" Casing Detail 9 5/8" Baker Model "G" ~loat Shoe 'I jr. 9 S/8" 40# J-SS Buttress Casing 9.5/8".Baker Model "G" Float Collar 42 j~ 9 S/8" 40# J-SS Buttress Casing - i 9 S/8', HOWCO DV Collar 68 its .9 S/8~' 40# J-SS Buttress_Casing Landed Below Zero 111 jts. ' '2.56 4815.35-4812.79 $8.99 4812.79-4773.80 1.90 4775.80-4771.90 1792.96 4771.90-2978.9'4 2.15 2978.94-2976.79 2939.81 2976.79- 36.98 36.98 36.98- 0.00 4815.35 . UNION Oil CO. OF CALIFORNIA SHEET D ' ' DRILLING RECORD PAGE NO. ,,3., , LEAS~ Trading Bay 'State llrELL NO. ,%-7 FIELD tr~{~,g R~y DATE 9-9-67 10 11 12 13 E.T.D. 4759 4759 4759 3892 PB . 3367 PB DETAILS OF OPERATIONS, .DESCRIPTIONS & RESULTS Drilled'out DV Collar @ 2977' and ran on to bottom. Tagged bottom @ 4759'. 'Displaced mud in hole with Inlet water weighted to 68.S# cubic feet. Circulated hole clean and POH. Picked up casing scraper. Ran same. to bottom. Circulated hole clean, POll, and rigged up Lane Wells. After considerable difficulty with tool failures, ran Cement Bond Log. Cement bond indicated to be generally good. Top of cement found @ 1530'. POH with CBL. Started running Gamma Ray - Correlation Log. Completed running GR Log. Perforated following intervals with 4SPFusing ~CF II charges on 4" carrier guns' 4605' - 4625'; 4140 - 4160'; 3820'- 3840'; $300' - 3320'. Rigged down Lane Wells and made up Halliburton test tools.- Ran same in hole. Set. packer @ 4587' with tail pipe to 4605' to test perforation interval 4605'- 4625. Press. drill pipe to S00 psi with gas from A-2. Opened tool against SO0 psi for 10 minutes with no sign of pressure-increase. Closed-tool for 1 1/2'. Reopened tool and gradually bled pressure from 500 psi to 50 psi during a 45' period. Well continued to flow gas @ constant blow throughodt remainder of 8' open period, but pressure declined from S0 to SS psi during last 2 1/2' of open period.' No fluid to surface during flow period. Closed tool in to obtain FCIP. While tool was closed reversed drill pipe with no recovery indicated from test. Completed taking 3 1/2' FCIP. Pulled tool loose and started out of hole. Finished POH and found test had been run one stand too low, thus was below perforations and open only to blank pipe. Gas blow during test apparently due to leak in wellhead room manifold system. Dressed packer and RIH to re-run DST #1. Set packer and pressured drill pipe as before. Opened tool and pressure increased 75 psi in 3". Closed tool 1 1/2'. Reopened tool for final flow. Bled off gas cushion and had oil to surface in 30 mins. Flowed well to clean tank then turned well to test trap for measurement of oil and'gas rates. Closed tool after 12-3/4 hr flow period. During 3-1/2 hr FCIP reversed drill pipe and recovered 99 BO. Recovered total of 491 BO during test. Finished POH w/ DST #1. Pressure as follows: IHP 2185 psi; IFP - NM; ICIP 2054 psi; FFP 1158-872 psi; FCIP 1516 psi; FHP 2185 psi. BHT measured @ l12"F. Dressed packer, picked up Baker retrievable bridge plug, and RIH. Set Bridge Plug @ 4175', pulled up and set packer @ 4087' w/ tail pipe to 4105' for DST .#2. Pressured drill pipe to 510 psi w/gas cushion. Opened tool with no noticable increase in pressure. Left tool open 10 min then obtained 1-1/2 hr ICIP. Opened tool for final flow and bled off gas cushion. After bleed-off had initial strong, blow which.diminished to very weak in 3-1/2 hrs and remained weak to end of 7 hr flow period. Closed tool for 3-1/2 hr FCIP. R~versed drill pipe and recovered 1-1/2 bbls GOCW (99% water). Released packer went down and latched onto BP @ 4175'. Pulled ~up hole and reset BP @ 3892'. POH w/ DST assembly and broke down tools. DST #2 pressures as follows: IHP i940 psi; IFP - NM; ICIP 1842 psi; FFP 66-82 psi; FCIP 573 psi; FHP 1940 psi, Dressed packer and started RIH for DST #3. Finished RIH w/ DST #3. Set HOWCO packer @ 3775'. Pressured drill pipe to 500 psi. Opened tool and in 3 min pressure increased to 512 psi. Closed tool for 1-1/2 hrs, Reopened tool w/ strong blow. Oil surfaced in 3-1/2 hrs. Tool remained open 12-1/4 hrs. Closed tool for FCIP and reversed drill pipe. Total fluid recovered during test was 131 BO (21.4" API). After 3-1/2 hrs FCIP released packer and POH. Latched'onto BP @,3892' and reset same @ ~367.' prior to POH. DST #3 pressures as follows: LEASE DATE 9-14 -67 15 16 UNION OIL CO. OF CALIFORNIA DRILLING RECORD SHEET D PAGE NO, A Trading Bay State A-7 Trading Bay VFELL NO. FIELD DETAILS OF OPERATIONS, DEscRIPTIONS & RESULTS E. T. D. 4759 ' 4759' 4759' IHP 1809 psi; IFP - ~M; ICIP 1712 psi; FFP 492-979 psi; FCIP 1663 psi; FHP 1809 psi. Dressed HOWCO packer and RIH for DST #4. Set packer @ 3273' w/ tail pipe to 3291'. Pressured drill pipe to 505 psi and opened test tool. Pressure increased to 525 psi in 3 mins. Closed tool for ICIP. After 1-1/2 hrs ICIP opened tool for final flow period. Flowed oil to surface in 2 hr 42 mins. Turne6.well to well clean tank then to test trap. Would not flow against trap pressure. Well flowed 152.55 BO during 14-1/2 hfs final flow period. Closed tool to obtain FCI? of 3 hr. Reversed drill pipe and recovered 36.1 BO with no water. After final shut in released packer. Went down to retrieve BP @ 3367', but found 6' sand fill-up over retrieving stinger. POH w/ DST tool. RIH w/ BP retrieving head and circulated down over stinger. Released BP and POR. Rigged up Lane Wells ana perforated 4125-4140' and 4160-4225' w/ 4 shots per foot using NCF II 4" carrier g~ns. Picked up HOWCO test tool and Baker bridge Plug. RIH w/ .same for' DST #5. Set BP @ 4269'. Pulled up and set packer @ 4086'. Pressured drill pipe to 500 psi. Opened tool with 6 psi increase in 10 mins. Closed tool for 1-1/2 hrs. Opened tool for final flow. After gas cushion bled off well continued with strong blow. Blow steadily decreased to weak at end of 8 hr flow period. Shut tool in for 3 hrs FCIP. While shut in, reversed drill pipe and recovered 22.5 BO plus 2.25 OC water (74.6% water,19.2% oil, 4.8% emulsion, 1.4% sand and solids). Released packer, retrieved bridge plug and POH. Laid down test tools. Picked up RTTS packer and started RIH for squeeze jobs. DST #5 p~essures as follows: IHP 1956 psi; IFP 589' psi; ICIP 1826 psi; FFP 66-82 psi; FCIP 148 psi; FhP 1956 psi. Set packer @ 4507'. Closed circulating parts and pumped into perfs 4605-4625' with 23 cuft @ 15 cfm and 1400 psi. No evidence of communi- cation. Spotted 100 sx Class "G" cement mixed with Inlet water at tool and closed tool. Pumped 76 sx cement into formation @ 1500 psi then staged 8 sx from 1500 psi to 2000 psi. Iield 2000 psi OK for 10 mins. then released pressure and flowed back 7 cu ft. Released packer and reversed Circulation with no 'cement returns. POH, picked up 216' tail pipe below RTTS packer and ran in hole. Positioned packer @ 4039' w/ tail pipe @ 4255'. Equalized 75 sx Class "G" cement, mixed w/ Inlet water, around bottom of tail pipe over perfs 4125-4225'. Pulled 2 stands and set packer @ 3852' with tail pipe @ 4068'. Squeezed. formation with 2000 psi injecting 17 cuft into formation. Held 2000 psi OK for 10 mins, released pressure, released packer and pulled out of hole. Cement in place @ 10:'45 AM. Laid down tail pipe and ran in hole with RTTS packer. Set packer @ 3663' and pumped into perfs 3820-3840' @ 7 cuft per min with 1600 psi. Spotted 100 sx Class "G" cement mixed with Inlet water at tool and closed tool. Cleaned tool and stage squeeZed formation to final pressure of 2000 psi which held OK for 10 mins (47.5 sx pumped into form.) Bled off pressure, released packer, and reversed circulation with no cement returns. Cement in place @-5:50 PM. Pulled up hole and reset packer @ 3100'. Pumped into perfs 3300-3320' @ 20 cfm w/ 1500 psi. Spotted 200 sx class "G" cement, mixed with Inlet water, at tool. While spotting cement 42 sx cement U-tubed.to backside before tool was closed. After clearing tool, released packer and reversed cement.above packer. Reset packer and squeezed formation to final pressure of 2000 psi whict~ held OK for 10 mins (115 sx pumped into formation) UNION OiL CO. OF CALiFOrNiA SHEET D DRILLING RECORD PAGE NO. 5 · . . . LEAsE~' 'Trading Bay State' ' VvqZLL NO. A-7 FIELD Trading Bay · DATE 9-17-67 18 19 2O 21 22-26 27 28 E. T.D. . . 4759 · 4826 4872 4872 5001 6273 6387 6407 TD DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS Completed final squeeze on perforations 3300-3320'. Cement in place @ 12:30 AM. Released packer and pulled out of hole. Picked up 8-5/8"bit with casing scraper and ran in hole. Tagged cement plug @ 3160'. Drld out of cement @ 3310'. Pressureltested perforations 3300-3320' OK for 10 mins w/500 psi. Tagged top of 2nd cement plug @ 3728' and drilled out plug @ 3838'. Pressure tested perforations 3820-3840' to 500 psi, OK for 10 mins. Found top.of'third cement plug'@ 4100'. Drilled out of plug @ 4276' then tested perforations 4125-4225' w/500 psi, OK. Found top of fourth piug@ 4560'. Drilled out of plug @ 4638'. Tested perforations 4605-4625' OK w/ 500 psi for 10 mins. Tagged top of float collar @ 4768'. Began changing s~lt wtr in hole to Hi-Vis Ceilex before drilling out float collar and shoe. Completed changing over to Hi-Vis Cellex drilling fluid. Drilled cement and float shoe. Went through shoe and tagged old hole @ 4822'. Drilled 8-5/8" hole to 4824' and began running on junk. Pulled out.of hole and picked up junk sub. Ran in hole and began drilling to .clean up junk before cutting core. Drilled on junk and cleaned up hole fromm4826-4835'. Pulled out of hole, picked up core barrel and ran in hole. Cut Core #4 from 4835-4853'. Pulled out of hole and laid down cdre. Cut i8' core, recovered 9' core: siltstone, claystone, and coal'. Ran in hole and cut Core #5 from 4853- 4873'. Cut 20' core, pulled out of hole and recovered 20'. Core: 1' coal 6' mudstone and siltstone; 12-1/2' oil sand; 1/2' siltstone. Prep to run in hole with test tools. Ran in hole with Halliburton test tool for DST #6. Set packer @ 4776' with tail pipe to 4794' (test interval: 4815-4872' open hole). Pressured drill pipe to 500 psi with gas cushion. Opened tool with 30 psi pressure increase in 5 mins. Closed tool for i-1/2 hrs. Reopened tool and bled off gas cushion. Well continued with strong blow (25 psi TP) throughout 8 hrs open flbw period, but no fluid to surface. Shut tool in and reversed drill pipe. Recovered 40 BO (31.3°API, 0.02-1.48% sand, 0.2-0.0% wtr). After reversing continued to obtain 3-1/2 FCIP. Released packer, pulled out of hole and laid down test tools. DST #6 pressure as follows: IHP 2315 psi; IFP 748 psi; ICIP 2086 psi; FFP 426-1174 psi; FCIP 1827 psi; FHP 2283 psi. Ran in hole with bit and began changing hole over to mud. After changing to. mud, reamed core hole from 4835-4872'. Drilled and surveyed 8-5/8" hole from 4872' to 4923'. Pulled out of hole to pick up Dyna-Drill. Ran in hole with same and dynadrilled 8-5/8" hole from 4923' to 5001'. Pulled out of hole to lay down Dyna-Drill. Drilled and .surveyed 8-5/8"'h~le. Drilled and surveyed hole to 6373' Pulled out of hole to pick up core barrel. RIH and cut Core #6 from.'6373-6387'. Cut 14' core, recovered 13'. Core: 6373'6379-1/2 - sand siltstone; 6379-1/2 to 6387' oil sand to oil. stained conglomerate and sand. RIH w/ bit. Drilled 8-5/8" ho1~e from 6387-6407'. Conditioned hole and pulled out to run logs. Rigged'up Schlumberger. Ran IES, Sonic Log w/ caliPer, GR- Density log, and CDM. Obtained sidewall samples. Conditioned hole to run 7" liner. UNION OIL CO. Of CaliFOrNiA DRILLING RECORD · LEASE Trading Bay State V~ELL NO.A-7 . FIELD -. SHEET D PAGE NO. Trading Bay DATE 9-29-67 3O 10-1-67 E. T. D. 6350 6350 6350 6099 6099 6099 DETAILS 'OF OPERATIONS, D'ESCRIPTIONS & RESULTS Ran 38 Jts (1650.66') of 7" 26# buttress thread casing with turned down collar plus 7" TIW liner hanger . Landed 7" liner w/ Baker Model "G" shoe @ 6397' and Baker Model "G" float collar @ 6350'. Top of liner hanger @ 4746'. Mixed and pumped 460 sx Class "G" cement.with 1% CFR-2 using Inlet water. DiSplaced cement with 829 cuft mud. Bumped plug with 2000 psi. Cement in place @ 12:10 PM 9/29/67. Reversed out · approximately 86 sx-cement. POH, waited on cement and began to RIH with tubing and bit. 6397.00-6394.60 2.40 6394.60-6352.90 41.70 6352.90-6351.17 1.73 6351.17-6350.27 0.90 6350.27-4763.64 1586.63 4763.64-4762.54 1.10 4762.54-4746.34 16.20 7" LINER DETAIL 7" Baker Model "G" Float Shoe 1 JT 7" 26# J-55 Buttress Casing 7" Baker-Model "G" Float Collar Liner Hanger Landing Nipple 37 Jts 7" 26# J-55 Buttress Casing X-Over Sub TIW Liner Hanger Ran in hole with tubing and bit. Tagged cement top @6302'. Drilled cement from 6302-6350' (top of float collar). Circulated and displaced mud from hole with Inlet water. Pressure tested casing, OK to 500 psi for 15 mins. Displaced Inlet wtr with diesel. POH w/ tubing and bit. Rigged up and ran Lane Wells CBL, GR-Correlation log from 6350-4700'. Cement bond over 7" liner generally good to excellent. Rigged down Lane Wells, removed casing landing spool, installed tubing landing spool and re-installed riser assembly Ran in hole with 2-7/8" tubing and Baker Model S-2 packer. Ran 195 Jts 2-7/8" Armco Seal Lock tubing an'd positioned packer @ 6099' with tail pipe to 6135'. Installed Cameron X-mas tree and tested same to 3000 psi. Removed du~y from ball valve mandrel with wireline unit. Attempted to set packer but kept getting circulation. Ran wireline and found CX mandrels open. Closed same then set packer with 2100 psi. Opened CX mandrels @ 6000' and depressed tubing FL to 4200' with 1500 psi tubing pressure. Attempted but failed to run perforating gun holding tubing pressure. Bled off tubing pressure. Perforated through tubing using "Slim Jim" guns intervals 6160-6205' and 6225-6330'. After perforating turned well to producing into well clean tank @ 12:30 AM. Wireline measurement indicated fluid rise to 1400' from surface by 6:00 ~-[. No gas to surface. Ran BHP bomb for 2-3/4 hr buildup. BHP measured @ 1850 psi. Attempted to inject diesel into formation but found communi- cation in tubing string. Ran wireline tools to check for open mandrels. Checked for communication with wireline tools. Attempted to remove X-mas tree but' well began flowing back diesel. Reinstalled head and began displacing diesel in hole with Inlet water. Completed displacing diesel in hole with water. Diesel returns towards end of job mixed with undeterminable amount of crude. After killing well removed X-mas tree and installed BOPE. POH with tubing and packer seal assembly. RIH with RTTS packer on tubing and Baker seal assembly and stinger below packer. Stung through packer @ 6099' w/ Halliburton RTTS LEASE DATE UNION OIL CO. OF CALIFORNIA DRILLING RECORD SHEET D PAGE NO. · 7 A-7 Trading Bay Trading Bay State V~-ELL NO. FIELD E. T. D. 6099 / 6099 6099 6099 6099 DETAILS OF OPERATIONS, DEscRIPTIONS & RESULTS packer set @ 6026'. Bottom of stinger @ 6135'. Filled tubing w/ diesel while attempting to break down formation, found communication thrpugh tubing with annulus. Rigged up Lane Wells and reperforated intervals' 6160-6190' and 6225-6330' through tubing with 4 shots per foot. Finished perforating with Lane Wells. Ran tubing blanking plug below RTTS packer. Pressure tested tubing after setting plug and'closing sleeves', Pressure .to 3500 psi, OK. Pulled blanking plug from tubing and unloaded diesel from tubing and annulus. Turned well to production for test. " Continued testing well, total 10 hrs. Well produced average rate of 138 BPD with 1.5% cut and GOR of 2620 using gas lift. Gravity was 29.5°API. Opened bottom sleeves and circulated Inlet water to kill well. Unseated ' RTTS packer and pulled out of hole with tubing. Picked up Baker Locator Type DR packer plug, ran and set same on tubing in Baker Model S-2 packer @ 6099'. Pulled up one joint and changed' hole over to Hi-Vis solution. POH with tubing. Laid 5 sack sand plug on top of packer.using dump bailer. Perforated intervals 5600-5610' and 5630-5645' using Lane Wells NCF II 4" carrier guns. RIH with DST assembly and positioned packer @ 5568' with tail pipe to 5583'. Pressured tubing with 500 psi gas cushion. Opened test tool and obtained 25 psi pressure increase in 3 mins. Shut tool in for 1-1/2 hrs. Opened tool to bleed off gas cushion. Obtained 8-hr open flow with no fluid to surface. Closed tool and reversed. Rec. 4 bbls crude. Obtained 3-1/2 hr FCIP. Released packer and started .pulling tubing. Well began to flow. Circulated and raised salt water weight to 70#/cu ft. POH with tubing and DST assembly. DST #7 pressures as follows: IHP 2624 psi; IFP 625 psi; ICIP 2493 psi; FFP 625-639 psi; FlIP 2714 psi; FCIP 2140 psi. Perforated interval 5122-5142' with 4 NCF II 'shots per foot. Picked up DST assembly with retrievable bridge plug and started RIH. Finished RIH. Set .bridge plug @ 5465'. Pulled up and set packer @ 5077' with tail pipe to 5092'. Pressured tubing to 500 psi with gas cushion. Opened tool and left open 10 mins with no pressure increase. Closed tool 1-1/2 hrs. Reopened tool and bled off gas cushion. Well continued to blow moderately steady. Continued to flow well for 8 hfs, no fluid to surface. Closed tool and reversed, recovering 24 bbls highly 'gas cut oil foam and emulsion. Unable to get accurate cut but no free water present. Obtained 3-1/2 hfs FCIP, pulled tool loose and POH. DST #8 pressures as follows: IHP 2463 psi; IFP - Not measured; ICIP 2243 psi; FFP 726 -2096 psi; FCIP 2184 psi; FHP 2463 psi. Began perforating with Lane Wells NCF II 4" carrier guns using 4 shots/ft Perforated following intervals: 4600-4640~ 4670-4700'; 4720-4735~ 4900-4920'; 5005-5020; 5100-5120'; 5170-5190'; 5260-5290'; 5360-5390'; 5435,5460'; 5495-5505'; 5540-5550'; and 5700-5730'. Attempted to use selective firing device, but device failed resulting in upper section being fired first instead of lower section. Cdnsequently, interval 5090-5100' was also perforate~. Discontinued attempts to use selective firing.device. Rigged down'Lane Wells and rigged up to run tubing. Picked up and ran 173 its 2-7/8" 6.4# N-80 Azmco Seal Lock tubing with Baker 7" F-R single packer and Baker 9-5/8" A-V dual packer for long string. Also ran 142 jts 2-7/8" ditto tubing for short string. With tubing approximately 300' abOve landing point stabbed short string into dual packer and began to run strings in tandem with 7" packer @ approximately 4768' (inside liner -UNION OIL. CO. Of CALIFORNIA DRILLING RECORD SHEET D Page NO. 8 LEASE Trading Bay State WELL NO. A-7 FIELD Trading Bay · . 10 11 DATE E. T. D. . 6099 6099 I DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS assembly) could not lower tubing in hole. Worked tubing but still could not go do%m. Picked up and began pulling short string. After pulling short string attempted to move long string down hole but still could not get tubing below 4768'. POH with long string and found dual packer OK but 7".packer slips had extended prematurely and 2 slips missing. With new 7" packer picked up and ran A-V dual packer on 174 joints 2-7/8" 6.4# N-80 tubing. Landed tubing with donut in landing spool. F-1 packer @ 4832' and A-V packer @ 4508'. Ran 143 jts 2-7/8" 6.4# N-80 Seal Lock Tubing for short string. Stabbed Baker packer seal assembly into A-V dual packer and landed tubing with donut in landing spool. Removed BOPE and installed dual X-mas tree. Tested same, OK to 3000 psi. Began displacing salt Water in hole with diesel oil. :ompleted displacing salt water with diesel. Dropped balls and set 7" single packer and 9-5/8" dual 'packer. Checked for communication. Found none. Turned well to production and RELEASED RIG @ 7:00 AM 10/11/67. 2-7/8" TUBING DETAIL (Long_ St.ring). 5499.03-5498.58' 0.45' 2-7/8" 8rd Collar 5498.58-5497.24' 1.34' Baker Packer Trip Sub 5497.24-5496.14' 1.10' Otis No-go Nipple 5496.14-5246.47' 249.67' 8 Jts 2-7/8" 6.4# N-80 Armco Seal Lock Tubing 5246.47-5243.25' 3.22' Otis X-Sleeve 5243.25-4838.56' 404.69' 13 Jts 2-7/8" 6.4# N-80 Armco Seal Lock Tubing 4838.56-4831.81' 6~75' 7" Baker bIodel F-1 Packer 4831.81-4828.66' 3.15' 2-7/8" 8rd x 2-7/8" Seal Lock Tubing Pup 4828.66-4798.27' 30.39' 1 Jt 2-7/8" 6.4# Armco Seal Lock Tubing, N-80 4798.27-4795.05' 3.22' Otis X-Sleeve 4795.05-4515.12' 279.93' 9 Jts 2-7/8" 6.4# N-80 Armco Seal Lock Tubing 4515.12-4501.37' 13.75' 9-5/8" Baker Model A-V Dual Packer 4501.37-4497.12' 4.25 2-7/8" 8rd x 2-7/8" Seal Lock Tubing Pup 4497.12-4466.1'7' 30.95' 1 Jt 2-7/8" 6.4# N-80 Armco Seal Lock Tubing 4466.17-4460.67' 5.50' Otis CX Mandrel 4460.67-3283.97' 1176.70' 38 Jts 2-7/8" 6.4# N-80 Se~l Lock Tubing 3283.97-3278.43' 5.54' Otis CX Mandrel 3278.43-2007.74' 1270.69' 41 Jts 2-7/8" 6.4# N-80 Seal Lock Tubing 2007.74-2002.20 5.54' Otis CX Mandrel 2002.20- 296.76' 1705.44' 55 Jts 2-7/8" 6.4# N-80 Seal Lock Tubing 296.76- 293.91' 2.85' Otis Ball Valve Mandrel 293.91-290.95' 2.96' ~ Flo-Coupling 290.95- 287.83' 3',12' 2-7/8" 8rd x 2-7/8" Seal Lock Tubing Pup 287.83- 40.60' 247.23' 8 Jts 2-7/8" 6.4# N-80 Seal Lock Tubing 40.60- 38.00.' -2.60' 2-7/8" 8rd x 2-7/8" Seal Lock Tubing Pup 38.00- 37.00 1.00 Cameron Split Tubing Hanger 37.00- 00.00 ~ 37.00 Zero (RT) to Tubing Hanger 5499.03'174 Jts UNION OIL CO. OF CALIFORNIA DRILLING RECORD SHEET D PAGE NO. 9 LEASE Trading Bay State V~ELL NO. A-7 FIELD Trading Bay . DATE E. T. D. DETAILS' OF OPERATIONS, DESCRIPTIONS & RESULTS 2~7/8" TUBING DETAIL' 4512.18-4505.68 6,50 Baker Mo~el A-V Dual Packer Seal Assembly 4505.68-4442.65' 63.03' 2 Jts 2-7/8" 6.4# N-80 Seal lock Tubing 4442.65-4437.11' 5.54' Otis CX Mandrel 4437.11-3260.19 1176.92' 38 Jts 2-7/8" 6.4# N-80 Seal Lock Tubing 3260.19-3254.65' 5.54 Otis CX Mandrel 3254.65-1952.98' 1301.67' 42 Jts 2-7/8" 6.4# N-80 Seal Lock Tubing 1952.98-194.7.44' 5.54' Otis CX ~iandrel 1947.44- 303.125 1644.19 53 Jts 2-7/8" 6.4# N-80 Seal Lock Tubing 303.25- 297.00 6.25' 2-7/8" 6.4# N-80 Seal Lock Tubing Pup .. 297.00- 265.90' 31.10' i Jt 2-7/8" 6.4# N-80 Seal Lock Tubing 265.90-263.05 ' 2.85' Otis Ball.Valve Mandrel 263.05-260.09 ' 2.96' Flo-Coupling 260.09-256.97 ' 3.12 2-7/8" 8rd x 2-7/8" Seal Lock Tubing'Pup 256.97- 40.60 ' 216.37' 7 Jts 2-7/8" 6.4# N-80 Seal Lock Tubing 40.60- 38.00' 2.60 2-7/8" 9rd x 2-7/8" Seal Lock Tubing Pup 38.00- 37.00' 1.00' Cameron'Split Tubing Hanger 37.00- 00.00 37.00' Zero (RT) to Tubing Hanger 4512.18 143 Note: 8rd Collar, Shear Sub, and-No-Go Nipple on 4' Stinger below packer set @ 4508'. Seal Assembly stabbed in @ 4508'. ?ASE_ ~Trading Bay State ,yp~ Invermul ., UNION OIL CO. OF CALIFORNIA .-/~,, _ MUD RECORD · . ' 'V CELL.NO[Al-7 WO ~/-1 FIELD Trading Ba~ i. DISTRIBUTOR_ Baroid · . SHEET B PAgE NO. 2 .D_E~I:~T.~.~ WEIGHT . . iVt,. ~,.. PH SALT.i OIL SA~D SOLIDS ,, 6097' 77~'! 75 ~ kSi~ed well . '- 7(~__80 ..... '% ' ............ circ & conditioned -- i7 '~1 76¢/ 58 30 i ~I ' . ..... Ii3 ' 7 ~ -r ,,~6~t s~, .. :. , ............... . ...................... , .- .... .I, ' . , , ....... . .......... .. . - . ..... . ~ - ....... , ................... ........... .... . ..... , .................. ..... ............... ....... ,,, ~ ..'. .......... ........ ...... ...... . ........... . ....... , ~ . .... . . ...... . ................. . ............. ..... . . .................. ~ ......... ..... ,. . ........ . ...... . .... , , . . , _ ,, ..... ...... ... ..... . , , .... .. ~ , , .. - ~ · . , * ....... .. . , · . .. ......... ...... ..... . ...... . ...... ........ . . .... . ....... .......~ ...... . ....... UNiC OIL CO. OF CALIFO qlA SHEET B MUD RECORD PAGE: NO LEASE TRADING BAY STATE WELL NO. TYPE... Fr~h Wmr~r - T,ignn~,,1F~nm. to A-7 FIELD TRAD I NC, BAY BAY DISTRIBUTOR Ba ro id 3-27-67 ' 566 77,0 34 10.4 . 10.0 6400 - 4' J ' ~ 8 ~ 9 I ,28 . 1!00 74.0 ,41. 6.8 9.5 5260 4 [-1/2 12 ,- ,, 30 1650 · 75,5 41 4,7 9.5 '6060 6 L,-3/41 14 , 31' ,2612 78.0' 49' 5 ' i0' '9.0 9900 3 ~--1/4! 17 Increased MW after ':k{.ck'" w/75.5~,-'m 7- 1-67 3370 78.5 43 '5,0 91,5 11200 2 ~_-1/21 17 Gas Cut. ,, : .... .,, ..2 - 3837 77.5 47 ..4,0 9,,5 ' 9600 ,6 2 14 ' 3. 4069 78.5 43 ' 4,4 9,0 9.270 6 2 16" ' 4' 4365 77.0 48 4.4 '9.5 10400 8 2. 16 .5 4496 78.0 43 4.6 9.0 9250 8 1 14 6 4822 78.0, 42 4.6 9..,0 10400 6 l-1/2 16 , 7 4822 78.0 '46 4.0 9.0 10400 6 I-1/2 16 Running 9-5/8" casing 7-8/9-1; Perfor~,ting, ']'es'tin: and S~ueez 18 4822' 68.0 36 7.2 11.0 83000 .... Hi-Vis fluid for co~ing and testin .19 4873 68.5 35 4.8 11.0 .17000 - - 4 Coring 20 ~873 68.5 .35 4.8 11.0 " - - 4 Running DST 21 4923 74.0 49 5.6 10,,0 31000 - 1-1/2 - Displaced Hi-Vis fluid w/Res.Mud· 5035 75.0 40 4,8 9.5 31400 3 1 13 22 5440 75,0. 43 3.6 9,.5 31400 8 1 13 2q 5659 76.0 40. 4.0 - 9.0! 198·00 5 . ' 1 .. 14 2& 5865 75,0 '46 4.6' .9,5 13.5.50 4. 1 11 25 6055 74.5 43 4.6 "'9,0j 10900 4 · 1 10 · 26 62~¢) 75.0 45 4.0 9,5 10550 .4 1-1/4 10 _ 27 6387 75,0 43 4.8 9.3! 10000 4 1 10 28 6407 7.5,0 41 4.6 9.2 13000 4 1-1/4 10 Ran Logs and Casing 10-6 60qq 68..5 33 6.8 9,0: 86000 - - - .Completion Fluid - Iii Vis for peri and run,ning DST. Disp. complete ' I [ system w/diesel on final well comp ,, · .. · · , , · , · _. · · ,, ,. · · ,, · -- , · , - , · · · . . _ ,. , , · . , -- . · · . ,,, - , · DATE F '- DRILLER SIZE & TYPE FF, Ohl TO J NO. J BARREL · ~2--~0N OiL '"'"'""'*~""'Y OF CALl . ' CORE RECOR D '. ... . . , i ., _ _ , . JTOTAL OiL GRAY JAPP' 'j ~ ~.,~-,o,~ o~ ~o~ / ~'~' I.o~ I TOTAL' OIL GRAY - DATE ·SIZE:.& TYPE' FROM TO REC'RY SHALE SAND SAND SHELL ' I~ARREL ..V-tELt. DESCRIPTION OF CORE jE L EV/;'FI O; ! K1..4. ! 0.... tL,,'- i4.-, .; .>) / .', d'. , ¢., ~:: Z,¢,,/,,'/¢/.) cz.:.:/ .. ;~ ,- -,;..j:.-L.'_.&. ............. . ,¥ · - -,.- '., --F'-~,,,->/¢ · ~.,-.J~,-, -c.i~l V<. / I ./::/,.,,-,..'). /~' ,, .... . . · .c.:.-/,~..,..,o ,,,. ) .:£ ./.- :: ./,,- ,.;,. ,.,., ,,-!/.,' ,,¢. ' . . ,- 'il ~ /'*).- d ,~. ,, ( / ' -/" '->" ,I ,' :, ~- : r ? - c... . " '~ ':" ' · ,o :.''' I / ~' ';' '" c-",- ~ I L.. "' '"' t;,, ,u.,* F "~"""/ '"' ;' '' ~ ./,...-,':'.0 '-/¢ ,,,'¢ . /¢,...,../:: ~,: i ~ ._]~>,/.¢ :' 'i' ~ ,r.:¢..'. .~:.',"oc · . .. ~ · .- '.o,-, z,. ? */', ..'/ o .~',-- ,,,. -'-; ~/t- -":". ":"*- '-'i:, . .:, ¢: ,,.. 1,.,./-.,,....':..,.,/...:,..,., ,: :,: ..,>:..1 · .. ,-., '*' 4)?,..;.~:.'~ k /',, ..: -.'. ~'. ~.., r' ¢ I,.¢ ' ' . .. ,- ', .....<,t,~. :,.~, · ... '. .. .. · o .::;./.-"-'-: ¢%,:-..-' . .,~*,~.-'.'~ ,? ,."¢ ; v. " ~. -.. .'. '*'1 ' ~ /t " · .. ,...4..' · . '. ' ..¢.. ¢ - · · ,' " ~ r':.'~ ' C ~.. · 1"7' , ~ ' o , ~ :.~ ~ ..... /,--.,.'~.. ,, .F'.~. :',-' t;,.,:~. ,~ ,".~' ~.'.-:,:' ~-, x,..,,--,.--~.. 2:,.-,,?/./:': %'. ~..-.' . , ~ . -~ ,. ~ .. ,/-.-/ ,.:,,,-.'.,;. / ¢.,'/,'-- .D':%"'~' 't~ , ¢.:,'",. ,}~,* Il . ~/,~*" -,'..--,. L.* ,.,- ¢',:, ¢,/.'.; ~;,,~., :, ,.,, .:/,,,/.. ~,, .."~ -", ,""' / ,"'~ . .,...d -/ .... ;:" I / / ' ¢..:x.O~;.>. .... : .... ~ ~' . / "' · I ""t.:"'"' > ~''' ,' ~ .... . . ,..":.'.,/'/.', ~.. ! ,~.:' ~ ~':~ ," '"":"'~!-':~ ~ /: ' I .C' - ~ .4 -'"- .,~,'~' .'" '~/' ,', · / .: .. ,~'.~j,\ ALACAL DIRECTIONAL DRILLING CORP. Main ~',~~" 888 No. Street Santa Ana, California 92701 ..A _ ~ UNION'0IL C@,~ANY OF CALIFOR~A STA~ A-7 COUNTY _~N. AI BOROUO~ WELL ..... LOCATION___ TRADING BAY COUrSE NO. SHEET NO. 2/3 N0~m~,NBER 1967 STATE - ALASKA TOTA[- DEPTH JLINGT.;I ANGLE ' COURSE TOTAL DEVIATION DEVIATION ----N-~"I~'~'~.'I-" 'l-'-~U~tt --'~S~-- :[ -- ~'T NORTH --: ...... SOUTH i[ [AS~-- '? 3837 j , 2j30r ~ jj 383&~97 9i72,N, 52 ~EjJ i ~ ~ :j ~ ~ J lJ 7j39:~. ~ Ii 91t&O J ~AS: ~ J ~360~0 25 ~2~N 60 )E ~ ~ ~ 32~37 : .... ..... 122 66 . o'' '' ~' ................ :'" *'- JO ' ............. : ' :~ ......... .... ~-- '~ ~ ~ 73~L .......j{ 5_~ .......... jj062188 6:~ N' W .......... : ........... : ......... ' ..... ~__, 6~ !.~ !~ ~5 ~' 5190'26 !2~32 N ~5 ~W ~ . ~ . '; 72:93: , ':~ 13~74L E , , 5381 ~, 11 m A ',' : ,~ ' ' ~ ................ ~'- .... 5389 ~[ 6 ' ' ' " 0'IN" 0 J;~' " [, , ; 8 , ~2i, ' ,, 120,00j, ,' J " ~N) ~,r' i l, ' ' lO& 56 ~ ~ 107) 37 .., ..... .,j J, ,, ,j, ,, , .~ , , ' ,' ' , 111 78,~ 101l 73 5865 J 8 15,J ~, 5853 166' 19152,,N) 33 IW I :' :i I ~) t JJ l&0 ~37lj !- :, 81156' TYPE OF SURVEY: CALCULATED BY CHECKED BY I COMPANY ALACAL DIRECTIONAL DRILLIN~ CORP. 888 No. Main Street · Santa Ana, California 92701 UNION 0IL C0~,fPA~ OF CALIFORNZA ADDRESS ....... JOB NO ...... <__ SHEET NO 1/3 NOVF. A~ K"R 1967 WELL- STATE A-7 LOCATION .... TR..~,DING BAY COUNTY_ KEN.AZ BROUGH ---STATE ALASKA 97]- i iio 1692 :0 30; : ~ 1691 96:1:90 1977 1 D0 ;~ 1976 87 7 ~7 213/* 2281 3O 970 9~_ 1099 96 ' ,, ', ...... i' _ ...... ~ ........... ii 1 ;93 '~ :j 8 57 il 2/+ E ~j , , j ~: t: G E6,, ~ Il 10 ...... 19 05. > .... , 2133 ,t78 5 :~8 S 50 ',E~ , ' 2 28~ 23 25' 2280 6A~ 6 L1 55 ~Er, ' ~ > ~ [: 5 i96i' 28 50:i '! 2510 I! :; 2 267/,t ~; ~j 2 :! : 2832 :i .: 2 3271 ii I2 t' ' :, i ' i73 2509 41i: 9 t98ilS 2673 25;i 7i151;~ 75 !E ...... --[ 111/,911 65 TYPE OF SURVEY' · CALCULATED BY. CHECKED BY . ,,,:,'.~,, ~.~ ALACAL DIRECTIONAL DRILLING CORP. ~ ~ '"" ', 888 No. Main Street · Santa Ana, California 92701 ¢OMi~ANV_--__t~_ION 0IL C0:~,,~ANY OF CALIFORNIA, JOB NO. s.., .o ' NOVEMBER 1967 WELL STATE A-? .... LOCATION TRADING BAY .COUNTY. K'ENAI BOROUGH --STATE_- COURSE ~' '~ COURSE ~j TOTAL t [j DEVIATION , .... ~;~-H ': "~-~--~ '--~5; ........ ;i .... ~-~;';--',~ NORTh: ..... SOUTH --j{-- ~' :' 8 " i 6101'75 19;0L N, 30 ~, ,, 172 ~, ~ 62g0 ~ ;: 8~30~ , ~J 622g;~9~ 18j 33,,N~ 28 ~ , ,{ i ~ ' ~ ' ~ 1~9, Ogl j ;~ 53i O~ j ~ ~ ' ~ ~L0~E: ~N.;: 12°;~ 02' E; : 210.76.' : j ii ........................... ~ ........... l , .............. , ~ ...... ......., ...................... ~ ...... ................ , J ti ; ', '~ , , , j I 11 ~ ........ i ......................... ? .... f .... i ............. : ............ ............ ~ ........... I; ........ ,, ......... ~ ...... , ~ X ........ !/ TYPE OF SURVEY: CALCULATED BY CHECKED BY, , UNION OIL COMPANY OF CALIFORNIA TRADING BAY- STATE '~ A-7 TRADING BAY, ALASKA BOX i10~ ~ DALLAS, 'l'~Xi$ 75221 TCompeny i Dote .. /'~ .... . :...,...:.] ',.. ~ . / ..':,,, 'fState t © New Completion I Co. or Perish CASING LINER si~:;:f ~_.~/,~ il' Weight I'-I 0,o e Size I'Weight j Grade 'i:l~r:ad , Depth Depth TYPE OF TUBING FOR STRING NO. j Size . J Weight J Grade J Thread j Depth .... ~ .....1 7: '~- I . 2 ' ( . I ...... l ....................~~ ................. - .............. .~:~:~ < ..... :.- :.:. :-..',: :-:.:-.-:.' :.: :.; :+: .-:v...: .-:.: :.:-.-: :-: ..'-. :.:-:.. :.x-: :.. :-'-.,: :-:-: >:.:.: :-: :-:-::.: .' -:.: .-'. >: .-: .... :. · :.: ............................... : ....... '. -:.:.:-...:.:-:.:.:-:.:-:, .:.:.:.,:.x. -... · .' :-. -'..:.: · '.:+: >;.'.:.:-: :.. :.:..j' :.:.:-'..<: :.: >. :.% .', · .'..'.: ........... ...: :.:.-.: ·.....:.:,;., :.' '.'.'. :. ,. <4..:.:.:.:.', 1 ,h' ', ........ ~ -" . ',~ V.', .~ /f~.Z ~ · ~ ~I ~l . . ~ 4::)9 ~:~ ~.,:~ lt.~, >~/~v ~,~ ~- ~u; - ~ ~ .... r.~-- . . .. , ~,~'. ~ ~ %._ z ~.. . ' ~ , .- :5 .L/,0. "-/ ";L, __ · --' ._/ ,:,;; ? ._C s,S ".~..> ~:. ,9 , ..>.."5 ~ ,,, ,.., ..,, 2. 3' - , .2 7Ld,. 7 ~q j..:- /,:...,'_, ~ ' ~ "' I .' ; 'v c' 7 ./ ,'""' 2 757. 6 ;< ].: / :'~.:, .,..., :> / '/'~ o :~., /-:.,-: ::: ,' ,:: :z ,-.2 c , /:1, G6' Dt'v'i'~tON OF DR~G,.~ER.tNOUSTRIES, INC. P. O~ Dox liO$ Dallas, Texas 7§22! Prepared For MR. LINER TUBING . Si ze jWell Ne. i4:-2' jWeight FIRST STRING jWeight SECOND STRING . THIRD STRING PART NUMBER Size iSize Size lCompany ...?/j_:"_,: ..-~ I i Ca. or Parish ,~'..:.:--/;../.~ / Grade I~hread ,,,;,/ :',..'j j Dote :,.,~ j :?"'." ":... State j [-'-'IL__j New Comp;et,on · /l ! "1 ,° '~ .'; Lc2! ¥;orkover .,z., >. ,/:; .~ (~/: J re-; jThreod JThread JT hre ad Weight IGrode tWeight j Grade DF_.SCRIPTION Depth Depth Depth Depth E STi:,',A'.': £z. .' -- -- ' ' Form No. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Effective: July 1, 1964 LAND DF'FICE LEASE NUMBER LEASE nR UNIT NAME LESSEE'S MONTHLY REPORT OF OPERATIONS TAe followir~ is a eorreot report of operatior~s arid prod,zetior, (ir~el~dir~ drillir~ and produoir~ff wells) for tAe rnor~t], of ...... .S_.e_~_t_~_m__b___e_V_ .................. 19_._6._7__, _ ........................................................................... .4~en ff s address ..... 5_9_?___~,___~_o_r__t_h_e_r_n____L__i_g_h__t;_s___~_l__v__d__: ...... Corr~pany ___U_B!o_q._ Oil Co. O_f__~alif. ............................................................................................. ....... ::::::::::::::::::::::::::::::: Pl~o~e ............ _2._7_7__-_%~_0_~_ ...................................................... .4~e~t' s title __DJ.s_t ..... D_r_lg .... Sup.t; ................... ~EC. AND ~ OF ~,~ BARRELS OF OIL Ti Cu. Fr. o~' (in' thousands) Drille, Ran el, 40# J-~ cement interv, 3820' all iht Drilled logs. 6397' Pressu from 6 four 3 GALLONS OF OASOLINE RECOVERED 12-1/4" ctric lo i5 casing Perfor ,ls: 460 , 3840', ervals t 8-5/8" Ran 7" 2 nd cemen e tested 60' to 6 8" holes BARRELS OF WirER (If none, so state) hole fr( S · Ran at 4810 ated and 5 ' -4625 ' ~nd 3300 > 2000ps: .~ole to ~# J-55 :ed with lap. P~ >.05 ' and ~ft. No~ REMARKS (I! dr~Jng, depth; if shut down, oause; date and result of te~t for gasoline content of ga~) )m 2060' to 4822'. and cemented 9-5/8" with 800 sacks tested the'following 4125' - 4225', - 3320'. Squeezed , after testing. ,407'. Ran electric .iner from 4746' to 460 sacks cement. ~rforated 7" liner 6225' - 6330' with testing. NOTE.--There were ................ nO .......................... runs or sales of oil; ............... ..n..O.. ........................... M cu. ft. of gas sold; ............................... · .....~..O.. .................... runs or sales of gasoline during the month. (Write "no" where applicable.) NOTE.--Report on this form is required for each calendar month, regardless of the status of operations, and must be filed in duplicate with the Division of Mines & Minerals by the 6th of the succeeding rnonjl~, ~]~l~sld~t]ileer~ial~ m,~ directed. gi:L- t U OCT 6 369 4-63 UNION OIL COMPANY OF CALIFORNIA Document Transmittal October 4, 1967 TO State of Alaska AT _M)OI Porcupine. ~)rive FROM Onion 011 Company AT_ Anchorage TRANSMITTING THE FOLLOWING: , . UNION TRAOING BAY STATE A-4: 2 Directional Surveys, RSJit~ 6390-10505 1 Core Description (Cores 5&4) 1 i IES, Final log (Runs i-5), ~lue line 1 " '~ ~' (" 1-5), :~et:,ia ..... 1 b~g Core Chip, C&re #3, 10605' 1 b~.g " " Core #3~ 10604' 1 b~.g " " Core #4~ 10606 1 bag '~ " Core #4~ 10607' 1 bag " " Core #4, 10608' UN ION TILAI) I NG BAY STATE A- 7: 2 be,xes Core chips, 38S7-4081' and 48515-6385' I ! , I ~ Bey Union Ol.], Co. Very tmJ,Ly yours, Form P 3 ST. OF ALASKA SU]~MZT IN TR ~TE* (Other lnstructl~ .On re- OIL AND GAS CO'NSERVATION COMMISSION verse side) SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen or plug back to a different reservoir. Use "APPLICATION FOR PERMITN' for such proposals.) OIL [~ OAS [=-] WELL WELL OTHER NAME OF OPERATOR Union Oil Company ADDRESS OF OPERATOR 507 I/. Northern Lights Blvd.; lnehoz~ase, Alaska 99503 4. LOCATION OF WELL (Report location clearly and in accordance with any State requirements.* See also space 17 below.) At surfece Tradin$ Bay Nonopod, 1615' g & 56' I/ of SE corner Sec. 4, TgN, R131/, SN 14. PERMIT NO. 67-46 15. E'.~-VA?IONS (Show whether DF, RT, RT I01' above NSL Effective: July 1, 1964 LEASE DESIGNATION AND SERIAL NO, ADL 18731 6. IF INDIANt ALLOTTEE OR TRIBE-NAME 7. UNIT AGREEMENT N~ME 8. FARM 'OR LEASE NAME 9. WELL NO, A-7 10, FIELD AND i~OOL, OR WILDCAT' r,d i' hv 11, SEC., T.~-B., M.[oRBLE, AND - 8UiVB~ oB /l~i Sec. 4, TgN, R13T/~ SN 12. BOROUGH ,. 'j 1'8, STATE 16. Check Appropriate Box T° Indicate Nature o~ Notice, Report, or Other Data NOTICE OF INTENTION TO: SHOOT OR ACIDIZE ABANDONs REPAIR WELL CHANGE PLANS (Other) T~t SUBSEQUENT REPOR'~' OF ': WATER SHUT-OFF ~ REPAIRING 'WELL SHOOTING OR ACIDIZINO [ ] ABANDONMENT* [ 1 (Other) (NOTE: Report results of multiple completion on Well' Completion or Reeompletion Report and Logform.) DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent details, and give pertinent dates, including estimated date of starting any proposed work. If well is dlreotionally drilled, sire subsurface locations and measured and true vertieal depths fo~_ all markers and zones perti- nent to this work,) * Presen~ Status of ~ell: 13-3/8" casing cemented at 1067'. 9-5/8" casing cemented at: 4810 with 800 sacks cement through shoe and 760 sacks cement throl~gh "DV" collar at 2974'. Top of cement at 1530' by Bond LoS. Proposad: 2~ Shoot four 1/2" :let holes 4605' - 4625', 4140' - 4160', 3820' 3840' and a contingent test 3300' - 3320'. Intervals will be Casted individually to evaluate the C-5 sand, C-2' sand, 44-7 sand and the contingent test in the 41-8 sand. 3. All intervals will be squeezed before drilling ahead and after teats are evaluated. 18. I hereby certify .that_the foregoing is tr~ and correct u. ~. He~han TITLE Dist. Drlg. Supt. Sept. 12-, 1967 (This space for Federal or State o~ee use) CONDITIONS OF APPROVAL, IF ANY: TITLE *See In~ruction. on Reverse Side RECE'IV O SEP ! 1967 DIVISION OF MINES & MINERALS Form No. ? 4 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Effective: July 1, 1964 LAND 13FFICE LEASE NUMBER LEASE OR UNIT NAME LESSEE'S MONTHLY REPORT OF OPERATIONS Tt~e followin~ is a oorreot report of operatior~s and'production (incl~dir~ drillin~ and produein~ wells) for t]*e month of ........ _A_ ~ g _u_ _s_ _t:_ _ ..................... , 19(:2_?___, ............................................................................ ,/l~enffs address _5_0_7___10[ ...._Nar. r~harn__Lights__BlYd ............ Company __L!n, i0n__0il_.Cor0,pan.y_4~f .................. ____c_~!_t_Lo_~_._~ ....................................................................... s~ ........ Jd:~_~_~__~_~_~~___-, .......... Phone ........ _2_7_7___-_~_0__~ ........................................................... ,/l~ent' s title ___.D_.i__~_t__,___D__F_J~g .... Or. FT. OZ (}AS GALLONS OF BARRELS oz REMARKS SEC. AND r~wP. RANGE WELL D&rs. BARRELS OF OIL GRAVITY GASOLINE WATER (If (If drilling, depth; if shu$ down, oause; ~ Or ~ NO. Pnov~rc~D (In'thousands) RECOVERED none, so state)d~te and result of test for gasoline content of · , . · TRAD] NC BAY S'~ATE A-7 Spudded ~,ell 8-27-67. Drilled ],7 1/2" h )le to 1~.00'. Cemented 13 3/8" ~asing at 1067 wil:h 1200 sacks cement. Now drilling 12 './4" hole at 2060 ' . · NOTE.--There were ................. ~.O..i ........................ runs or sales of oil; ........................... 0.. .................. M cu. ft. of gas sold; ..................... ~.O.. .... ............................. runs or sales of gasoline during the month. (Write "no" where applicable.) NOTE.--Report on this form is required for each calendar month, regardless of the status of operations, and must be filed in duplicate with the Division o£Mines & Minerals by the 6th of the succeeding directed. KI: L_ I::/VI:: V 1967 DI¥1$1ON OF MINES & MINERAL~ sum &-) (.4.~.4) August 22, 1957 Trad/ng Bay State A-7 (43.4) gncl~ are the a~p~oved cheek in the a~ount o£ $50.00 Form P 1 STATE OF ALASKA O1£ AND GAS CONSERVATION COMMITTEE SUBMIT IN TRIP .TE* (Other tnstructton~ on reverse side) APPLICATION-FOR-PERMIT TO 'DRILE~ DEEPEN, OR PLUG BACK 1R. TYPE OF WORK DRILLJJ]g ' DEEPEN [] ,..PLUG BACK J--I b. TYPE OF WELL NAMe/ OF ~0PERATOR Union 0il 'Comply 2805 Denali LOCATZON Or~zEL~.(~Repor~!oeat~9=nelearly§~d .lla..~c~da~ee with any S_tate requirements.* ) At sUrfac~' Tl~ad~ng ~ay ~~,' 1615 N, ~ :- $61'"#. o~.. SE corner SeC, 4,.T9N, RIM, SM rs ght hole 14. DISTANCE IN MILE8 AND DIRECTION FROM NEAREST TOWN OR POST OFFICEs Approximately 27.air miles .N~ 0£ F~nai, Alaska APl ~50-133- 20036 Effective: July 1, 1954 5. LEASE DESIGNATION AND SERIAL NO ADL IF INDIAN, ALLOTTEE OR TRIBE NAME 7, UNIT AGREEMENT NAME 8. FARM OR LEASE NAME Tradin~ Ba7 State 9. WELL , ,,,~-7 ~adt~ Bay, Hemlock 11. SEC., T., R., M., OR BLK. AND SURVEY OR AREA Sec. 4, TgN, R13W, SM 12. B.OROUGH SHJ 13. STATE Kenat Penin,J Alaska ~.o. DISTANCE ,ROM PROPOSED' 3665' LOCATION TO NEAREST PROPERTY OR LEASE LINE, FT. S61' (Also to nearest drlg. unit line, if any) is. DISTANCE FROM PROPOSED LOCATION' 1500' TO NEAREST WELL, DRILLING, COMPLETED, GE ,,P,.,~ ,GE. o~ ,HIS ,.-*~E. ,,. 16. NO. OF ACRES IN LEASE 3840 19. PROPOSED DEPTH 7100' MD $ VD 17.NO. OF ACRES ASSIONED TO THIS WELL 8O 20. ROTARY OR CABI,E TOOLS Rotax~ 21. ELEVATIONS (Show whether DF, RT, GR, etc.) 22. APPROX. DATE WORK WILL STARTs RT 10I' above ~SL lu~mt 28, 1967 23. PROPOSED CASING AND CEMENTING PROGRAM SIZE OF HOLE WEIGHT PER FOOT QUANTITY OF CEMEN'~ SIZE OF CASING 61# 40-4:S.S# SETTING DEPTH 6800 1,000 sacks 1,7S0 " l¸j 2, $. Drill 17~" hole to 1100'. Run.end cement 1080* 13-$/8" casing to .surhce. InStall ~ test i2' 3000# :d~bhydraulic gate ~ "GK" Hydril Drill 12~' ~hole to 4200'. ~ electric logs' Run and cement 9-5/8" casing. Dri!l 8'$/8" hole to $700', ~ elect~c:~logs, Run and cement 7" casing, Drill 6-1/8" ~le to 7100~. Rum elect~e logs. Hang $" liner. Complete ~ell. IN ABOVE SPACE DESCRIBE PROPOSED PROGRAM: If proposal is to deepen or plug back, give data on present productive zone and proposed new productive zone. If proposal is to drill or deepen directionally, give pertinent data on subsurface locations and measured and true vertical depths. Give blowout preventer program, if any. (This space for Federal or State office use) APPROVED BY CONDITIONS OF APPROVAL, IF ANY: AP1 #50-133-20036 TITLE *See Instructions On Reverse Side RECEIVED 1967 rD|VISION OF MINES & MINERALS 17 !8 · · ~ ,~ ! ' ! i ! ~ . . · · , . · . · . UNION - ~A RAT,'dON J6 IG i JO 15 R 13 W IJ 14 rU~IlO~t - MAF~AT HON AOL 17 E, 9 6 RECEiVE D-- AUG 2., i 1967 DIVISION OF MINES & MINERAL8 'ANCHOgAGE U PJ l 0 N CALl ~''~ TRADING BAY STATE A-7