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Home My WebLink About215-0771. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: CTCO Development Exploratory 3. Address: Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 10,200 feet 10,055 feet true vertical 5,577 feet N/A feet Effective Depth measured 10,055 feet 7,239 feet true vertical 5,433 feet 2,792 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6# / L-80 7,287' MD 2,821' TVD WL SCSSV 259' MD 259' TVD Packers and SSSV (type, measured and true vertical depth)7,239' MD 2,792' TVD 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: Jake Flora, Operations Engineer 322-266 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 jake.flora@hilcorp.com 907-777-8442 N/A 2,959' 4-1/2" 10,198' 5,575' 8,430psi Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 0 Size 120' 0 00 0 00 0 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-077 50-133-20651-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL 389737 Ninilchik - Beluga/Tyonek Gas Grassim Oskolkoff (GO) #8 16" 10-3/4" 120' 3,492' measured TVD 7-5/8" 7-5/8" Plugs Junk measured Length measured true vertical Packer Burst Collapse 2,470psi Intermediate Production 1,778' 5,687' Casing Structural 1,450' 2,943' 1,779' 7,466' 120'Conductor Surface Intermediate 7,500psiLiner Baker ZXP Liner Top Pkr 4,790psi 5,340psi 5,210psi 6,890psi 9,470psi 3,492' 1,844' p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 8:15 am, Jul 28, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.07.26 16:37:23 - 08'00' Noel Nocas (4361) Rig Start Date End Date 6/3/22 7/13/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name GO-08 50-133-20651-00 215-077 06/03/2022- Friday 06/04/2022 - Saturday Fox Energy CTU arrive on location. Conduct JSA and approve PTW. Well is shut in. MIRU and Spot Coil tubing unit and related equip. on location. Transport Tanks, Tri Plex test pump and water from the Pearl 2A pad to the GO 8 pad. Spot return tank and complete Iron and manifold rig up. Test all BOP's and related valves to 250-psi Low, 2500-psi high test for 5-minutes each. All test good. SDFN 06/08/2022 - Wednesday Fox Energy Crew arrives at facility and obtains permit, PJSM. Spot in coil unit and make hard line back up. Stab 1.75" coil reel loaded with 5/16" eline through injector. Make up roll-on CTC. AKEL crew arrives and spots eline unit. Make up depth encoder spliced cable to CT digital counter. Troubleshoot same and determine that both eline and CT units are supplying encoder with power. Disconnect eline power and system checks out ok. Make up CT logging head and tie 7x3 weakpoint (4200# breaking strength). Terminate electrical connection at logging head bulkhead and test same. Good to go. SDFN. Fox Energy CTU arrive on location. Conduct JSA and approve PTW. SITP 600-psi. Pick up Injector and lubricator, complete rig up and fill reel, test Breaks to 250-psi low and 3000-psi high. RIH with 1-3/4" coil tubing with 6 port wash nozzle @ 70' per minute. Tag fill @ 8686' Note: Bottom T6A perf is @ 8690'. Establish circ. @ 1.75 BPM @ 180-psi with 143'/minute annular velocity. Back in N2 and rig up and test. Pick up weight 25K. Established circ rate @ 1.75 bpm in and out @ 180-psi back pressure. Begin washing down at 10'/minute with sand washing in front of us. Note fluid returns real dirty water. @ 0945 hrs slowed pump rate down to 1.5 bpm @ 160-psi back pressure with 123'/minute annular velocity. @ 9217' lost return couple minutes, just gas then intermittent returns and leveled back off barrel in barrel out with influx of gas mixed. Increased rate of penetration to 35-40'/minute. Tagged solid second bridge @ 9469' That is between the T13B interval and T17A interval. Went back down didn't tag, washing in front of Coil tubing. Washed down to 10,085' CTM (10,055' TD). Pumped 50 bbls @ 1.5 bpm @ 180-psi back pressure while bringing N2 on-line. Bring N2 online at 1100 CF/Min @ 1450-psi displacing fluid out the hole. At 70 bbls returned POOH @ 130' per min while continuing to displace fluid out the hole and slowly bring up Back pressure to 800-900-psi while losing hydrostatic head from fluid displacement. At 4000' with coil, slowed N2 rate down to 500 CF/Min @ 1100-psi maintaining 800-900-psi back pressure. At 300' shut down N2 and shut-in choke. Bumped up Coil Shut in Well Head with 940-psi SITP. Note Pumped 140 bbls total of clean fluid and recovered 285 bbls total. Recovered 145 bbls additional fluid and tubing capacity is 152 bbls. Rig down Coil tubing to the top of the BOP's and secure Well and turn over to production. 06/05/2022 - Sunday Coil tubing unit standing by while production unloads the well. Rig Start Date End Date 6/3/22 7/13/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name GO-08 50-133-20651-00 215-077 06/11/2022 - Saturday Fox Energy crew arrives at facility and obtains permit, PJSM. Crew swapped from e-coil string to work string prior to arrival. Spot Yellowjacket fluid pump, HAK batch mixer and CT unit. Stab coil through injector. Line up to perform BOP test on stack loaded for 1.75" coil. Jim Regg waived witness on 6/9/22 at 16:20. Fluid pump will not fire up. Unable to troubleshoot, call out mechanic. Road to CLU 3 pad and retrieve KGF field triplex. Function test BOPE circuits. Test all rams and valves to 250 psi low / 2500 psi high. Good BOPE test. Install night cap and secure well. Mechanic repairs fluid pump starter. SDFN. 06/12/2022 - Sunday 06/09/2022 - Thursday Fox Energy and AKEL crews arrive at facility and obtain permit, PJSM. Stand by one hour for lightning storm to pass. Rig up injector and make up eline plug setting tool BHA with 4.5" CIBP (3.71" Running OD). RIH and tag up hard at 3050', stacked 10k down. Unable to move tools up or down. Mobilize fluid pump to location and cool down N2 pump. Come online with N2 at 800 scf/min down CT taking returns to open top tank. No fluid returns. Gently work pipe up and down with no movement. Rig up hot oil truck and circulate 75 bbls of water at 1 bpm with N2 at 500 scf/min. Returns look pretty clean at 1:1. Cut N2 to zero and circulate 75 bbls water at 1:1. Work pipe up and down with no movement. Pressure up on well to 3500 psi and pressure is holding. Surge well down through choke while working tools with no luck. Decision made to set plug in place to get free. Plug set at 3065'. POOH and blow down coil. RDMO CT and eline. Fox Energy crew arrives at facility and obtains permit, PJSM. Fire up CT equipment spread, pick up injector and lubricator. Make up connector and pull test to 25,000#. Make up milling BHA: checks, bi-directional jars, disconnect, circ sub, 2-7/8" Tomahawk motor and 3.74" 5 blade concave junk mill. Function test motor. Pressure test lubricator to 250 psi low / 2500 psi high. RIH and dry tag at 3069.3'. Pick up, begin pumping and establish milling parameters: 2.5 BPM @ 3600 psi, 210 fpm AV. Begin milling on plug with 100-300 psi of motor work. Continue milling until first stall-out at 3070.5'. Stall again at 3071.0' and push through plug. Observe motor work down to 4800' before mill is free spinning. Continue to RIH pumping at 2.5 BPM until tag at 8719'. Attempt to mill through but unable to gain circ pressure and make hole. POOH still pumping 2.5 BPM. Hang up and have to work through several pieces of debris along 75 deg sail section at ~3800'. Make it to surface and break down tools. Lay down lubricator and injector, secure well and SDFN. 06/13/2022 - Monday Fox Energy crew arrives at facility and obtains permit, PJSM. Fire up CT spread. Pick up injector. Make up BHA: checks, bi- directional jars, circ sub, and 2-7/8" venturi junk basket with 5' extension. RIH to 1500' and kick pump on. Establish circulation rate of 2.2 BPM at 5000 psi. RIH to 4000' and pump shuts down. Troubleshoot pump. Come back online and continue to suck up debris down to 7250'. Cut pump and dry drift down to 8600'. POOH, smooth trip out. Break off injector and inspect tools. Recovered approximately 1 gallon of metal shaving enriched sand and 1/2 cup of large metal chunks. Make up Plug setting BHA: checks, bi-directional jars, circ sub, and hydraulic setting tool loaded with 4.5" CBP (3.57" running OD). RIH to 6700' and hit weight bobble. Tag up hard at 6905', work tools conservatively and unable to pass. POOH, break off injector and lay down tools. Rig down, secure well and SDFN. Rig Start Date End Date 6/3/22 7/13/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name GO-08 50-133-20651-00 215-077 06/14/2022 - Tuesday Fox Energy crew arrives at facility and obtains permit, PJSM. Fire up CT spread. Pick up injector. Make up drift BHA: checks, bi-directional jars, disconnect, circ sub, and 3.72" DJN. RIH to 6000'. Kick on pump down coil with choke closed. Pressure up well to 900 psi and see slight breakover to 850 psi WHP. Injection rate levels off at 2.2 BPM at 1270 psi WHP. RIH to 7500' bullheading with DJN. POOH to 6000' and dry drift down to 8600' with no bobbles. POOH and break off injector. Make up Plug setting BHA: checks, bi-directional jars, disconnect, circ sub, and hydraulic setting tool loaded with 4.5" CBP (3.67" running OD). RIH to 8520' and drop ball. Cool down N2 pump. Circulate ball to seat and pressure up to 4600 psi to set plug. Good indication of set. Tag plug and pressure test tubing to 2000 psi, good test. Come online with N2 and evacuate 125 bbls from CT string and well. Pumped 171 mcf N2. POOH and break off injector. Lay down tools and secure well. RDMO CT spread. 07/12/2023 - Wednesday AK E-line and Altus tractor crew arrived on GO pad, obtained PTW and held PJSM identifying hazards and discussing scope of work. Complete RU and MU 2-1/8" tractor. Function test on W/L and hot check Gun Gamma Ray/CCL. Arm and MU 2-1/2" x 20' HSC perf gun (6spf/60D) loaded w/ 15gm charges. CCL to top shot - 8.5' Move lube and tool string to well head and PT 250L/2500H. Pass. 965 SITP (N2). Open swab and RIH. Ran tools to 1900' and stopped due to high deviation (78 deg.). Power up tractor and RIH @ 48fpm. thru sail angle to 7280'. Power down tractor and continue RIH unassisted. Tag PBTD at 8483' (ELM), run correlation pass and send log to GEO/RE. Approved on depth. Position gun at 8291.5' (CCL depth) and shoot Tyonek T2 interval at 8300'-8320'. POOH. No pressure change. OOH. LD lube and tools. All shots fired. gun bull plug wet. Function test tractor hot check gamma ray/CCL. MU Gun #2 - 2-1/2" x 20' perf gun. (9.7' CCL-T.S.) PU and stab on well head. 922 SITP Open swab and RIH. Free fall to 2060'. Power up tractor and walk tools to 7300'. Power down tractor and free fall to 8350'. Log correlation pass, confirm on depth, position gun at 8161.3' (CCL) and shoot gun at 8171' - 8191'. POOH. No change in pressure. OOH. LD lube and tools. All shots fired, gun bull plug wet. Secure well with night cap and SDFN. Plan forward to perf Bel 120 and flow test well. 06/15/2022 - Wednesday AK Eline arrive on location. PTW and PJSM. Rig up on well. Standby for AKEL mechanic for EL unit tractor. MU 2' and 4' 2- 7/8" guns with 3 sets of roller bogies (OAL 26' 4"). Pressure test to 250 psi / 2500 psi. RIH. Very slow progress RIH. POOH. Add additional weight bar (OAL - 33'4"). RIH while pumping in diesel with field triplex. Making much faster progress. Trouble spot at 6650'. Pumped total of 2 bbls of diesel between PT and this last run. Unable to make it any deeper. POOH. RDMO. Rig Start Date End Date 6/3/22 7/13/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name GO-08 50-133-20651-00 215-077 07/13/2023 - Thursday Obtain PTW and hold PJSM. Fire up equipment MU and function test tractor. Add and hot check Gun Gamma Ray/CCL. MU and arm Gun #3 (2.50" x 20' gun). CCL to top shot - 8.5'. SITP - 918 psi Open swab and RIH to 1918'. Power up tractor and walk tools to 7180'. Power down tractor and RIH to 8350'. Log correlation pass up to 7850'. Send log to Geo/RE confirm on depth. Position gun at 7945.5' (CCL depth). Shoot gun in the Beluga 120 interval 7954'-7974'. Initial: 886 psi - no change in pressure while POOH. OOH. All shots fired. Gun plug wet. Secure well and RD E-line. Turn well over to production. RU Echometer and shoot fluid level - 6934'. RU portable flowback tank and bleed N2 in well down to atmospheric pressure. No LEL's detected. SI, allow well to build and monitor pressure. SITP - 82 psi leaving location. ___________________________________________________________________________________ Updated by DMA 07-18-23 SCHEMATIC Ninilchik Unit Well: Grassim Oskolkoff #8 PTD: 215-077 API: 50-133-20651-00-00 PBTD = 10,055 MD / 5,433 TVD TD = 10,200 MD / 5,577 TVD Max Deviation: 79 deg @ 2,421 78 deg sail angle from 2100-6700 MD RKB 18CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16 Conductor 84 X-56 Weld 15.010 Surf 120 10-3/4" Surf. Csg 45.5 L-80 BTC 9.950 Surf 3,492 7-5/8" Int. Csg 29.7 L-80 BTC 6.875 Surf 1,779 7-5/8 Int. Csg 29.7 P-110 BTC 6.875 1,779 7,466 4-1/2" Prod Liner 12.6 L-80 DWC/C- HT 3.958" 7,239 10,198 TUBING DETAIL 4-1/2 Tubing 12.6 L-80 BTC-mod 3.958 Surf 7,287 16 10-3/4 4-1/2 7-5/8 1 2 4 5 3 RA tag 8,211' JEWELRY DETAIL No. Depth ID OD Item 1 184.00-Tubing Hanger, 4-1/2 BT Mod 2 2693.8135.505-1/2 Hydraulic Nipple for WL Retrievable SCSSV 3 3353.855.754-1/2 Chemical Injection Mandrel 4 7,239 3.958 6.875 Baker ZXP Liner Top Packer/ HRD-E Profile (10 tie- back extension) 5 7,272 3.833 4.74 Seal Bore Extension GBH-22 Locating seal assembly (16.37) 6 8,520NA 3.67CIBP set on coil w hydraulic setting tool (6/14/22) 7 10,0553.958CIBP set on coil w hydraulic setting tool (8/26/15) PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Status Date Bel 120 7,954 7,974 3,352 3,371Open 07/13/2023 Bel 135 8,171 8,191 3,562 3,582Open 07/12/2023 T2 8,300 8,320 3,689 3,709Open 07/12/2023 T6A 8,622 8,631 4,009 4,018Isolated 6/14/22 04/10/2020 8,664 8,690 4,0514,077 Isolated 6/14/22 04/09/2020 T9 8,818 8,825 4,204 4,211Isolated 6/14/22 04/09/2020 8,852 8,856 4,238 4,242Isolated 6/14/22 04/04/2020 8,871 8,891 4,257 4,276Isolated 6/14/22 04/04/2020 T12 9,166 9,220 4,550 4,604Isolated 6/14/22 03/02/2017 9,220 9,260 4,604 4,643Isolated 6/14/22 03/01/2017 T13B 9,412 9,424 4,794 4,806Isolated 6/14/22 03/01/2017 T17A 9,800 9,877 5,180 5,256Isolated 6/14/22 02/03/2017 9,828 9,851 5,208 5,230Isolated 6/14/22 08/28/2015 9,837 9,877 5,216 5,256Isolated 6/14/22 02/02/2017 RA tag 8,502' RA tag 8,790' RA Mkr Jt 9,905 T17A T12 T13B 7 T9 T6A OPEN HOLE / CEMENT DETAIL 10-3/4383 bbls 12ppg lead + 76 bbls 15.2ppg tail of cement in 13-1/2 hole. 208 bbls cement back to surface 7-5/8235 bbls of 12.5ppg Class G lead cmt, and 70 bbls of 15.3ppg GasBlok tail cement in 9-7/8 hole. No losses during job. ~15bbls contaminated cement returns back to surface. 4-1/2 109 bbls of 15.3ppg Class G EasyBlok lead cmt. Losses during displacement after dart latched up. No cement nor spacer back to surface.8/24/15 CBL shows top good cement at 8550 MD and highest ToC at 8200 MD. Fill tagged at 1420, suspect bridge 6 Bel 120 Bel 135 T2 Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 07/25/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230725 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 222-34 50283201860000 222039 6/29/2023 AK E-LINE Perf-ProductionProfile BRU 223-34 50283201880000 223041 7/14/2023 AK E-LINE CBL/Perf BRU 223-34 50283201880000 223041 7/16/2023 AK E-LINE Perf BRU 244-27 50283201850000 222038 6/30/2023 AK E-LINE Perf END 1-01 50029218010000 188037 7/9/2023 AK E-LINE Plug/Cement END DIU 1-01 50029218010000 188037 7/7/2023 AK E-LINE Cross-Flow-Detect GO 8 50133206510000 215077 7/13/2023 AK E-LINE Perf KBU 33-06X 50133205290000 203183 7/18/2023 AK E-LINE GPT/Patch PBU F-29B 50029216270200 211147 7/8/2023 AK E-LINE CIBP Please include current contact information if different from above. T37872 T37873 T37873 T37874 T37875 T37875 T37876 T37877 T37878 GO 8 50133206510000 215077 7/13/2023 AK E-LINE Perf Kayla Junke Digitally signed by Kayla Junke Date: 2023.07.25 12:04:00 -08'00' 5HJJ-DPHV%2*& )URP%URRNV3KRHEH/2*& 6HQW:HGQHVGD\-XQH30 7R7RGG6LGRWL& &F5HJJ-DPHV%2*& 6XEMHFW):%23(7HVWUHSRUW+LOFRUS*2ZHOO $WWDFKPHQWV)R[5HYLVHG[OV[ )ROORZ8S)ODJ)ROORZXS )ODJ6WDWXV&RPSOHWHG dŽĚĚ͕ ƚƚĂĐŚĞĚŝƐĂƌĞǀŝƐĞĚƌĞƉŽƌƚĐŚĂŶŐŝŶŐƚŚĞƚĞƐƚƚǇƉĞƚŽtĞĞŬůǇ;ĂƐƚŚĞϲͬϱͬϮϮǁĂƐůŝƐƚĞĚĂƐ/ŶŝƚŝĂůͿ͘ tŽƵůĚǇŽƵďĞĂďůĞƚŽƐĞŶĚƚŚĞǆĐĞůǀĞƌƐŝŽŶŽĨƚŚĞϲͬϱͬϮϮƌĞƉŽƌƚĂƐǁĞůů;ǁĞŚĂǀĞŶŽƚƌĞĐĞŝǀĞĚĂƌĞƐƉŽŶƐĞĂŶĚǁĞ ĐĂŶŶŽƚŝŵƉŽƌƚĂƉĚĨͿ͍ dŚĂŶŬǇŽƵ͕ WŚŽĞďĞ WŚŽĞďĞƌŽŽŬƐ ZĞƐĞĂƌĐŚŶĂůǇƐƚ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ WŚŽŶĞ͗ϵϬϳͲϳϵϯͲϭϮϰϮ 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. &ƌŽŵ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх ^ĞŶƚ͗dŚƵƌƐĚĂǇ͕:ƵŶĞϵ͕ϮϬϮϮϯ͗ϰϰWD dŽ͗WĂƚŽƵĚƌĞĂƵǆфƐƉĂŶŬǇďŽƵĚƌĞĂƵǆΛǇĂŚŽŽ͘ĐŽŵх Đ͗ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗Z͗KWdĞƐƚƌĞƉŽƌƚ,ŝůĐŽƌƉ'KϴǁĞůů ^ĞŶĚǆĐĞůǀĞƌƐŝŽŶŽĨƚŚĞƚĞƐƚƌĞƉŽƌƚ :ŝŵZĞŐŐ ^ƵƉĞƌǀŝƐŽƌ͕/ŶƐƉĞĐƚŝŽŶƐ K' ϯϯϯt͘ϳƚŚǀĞ͕^ƵŝƚĞϭϬϬ ŶĐŚŽƌĂŐĞ͕<ϵϵϱϬϭ ϵϬϳͲϳϵϯͲϭϮϯϲ &ƌŽŵ͗WĂƚŽƵĚƌĞĂƵǆфƐƉĂŶŬǇďŽƵĚƌĞĂƵǆΛǇĂŚŽŽ͘ĐŽŵх ^ĞŶƚ͗^ƵŶĚĂǇ͕:ƵŶĞϱ͕ϮϬϮϮϵ͗ϰϰD 1LQLOFKLN8QLW*2 37' ƌĞǀŝƐĞĚƌĞƉŽƌƚĐŚĂŶŐŝŶŐƚŚĞƚĞƐƚƚǇƉĞƚŽtĞĞŬůǇ dŽ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх͖KK'WƌƵĚŚŽĞĂǇфĚŽĂ͘ĂŽŐĐĐ͘ƉƌƵĚŚŽĞ͘ďĂǇΛĂůĂƐŬĂ͘ŐŽǀх͖ ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗KWdĞƐƚƌĞƉŽƌƚ,ŝůĐŽƌƉ'KϴǁĞůů 3OHDVHVHHDWWDFKHG 3DW6SDQN\%RXGUHDX[ &HOO VSDQN\ERXGUHDX[#\DKRRFRP &$87,217KLVHPDLORULJLQDWHGIURPRXWVLGHWKH6WDWHRI$ODVNDPDLOV\VWHP'RQRWFOLFNOLQNVRURSHQ DWWDFKPHQWVXQOHVV\RXUHFRJQL]HWKHVHQGHUDQGNQRZWKHFRQWHQWLVVDIH STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSu b m i tt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:8 DATE: 6/11/22 Rig Rep.: Rig Phone: (907)887-1766 Operator: Op. Phone:(907)632-4113 Rep.: E-Mail Well Name: PTD #2150770 Sundry #322-266 Operation: Drilling: Workover: x Explor.: Test: Initial: Weekly: x Bi-Weekly: Other: Rams:250/2500 Annular:NA Valves:250/2500 MASP:1871 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig P Lower Kelly 0NA PTD On Location P Hazard Sec.P Ball Type 0NA Standing Order Posted NA Misc.NA Inside BOP 0NA FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75"P Trip Tank NA NA Annular Preventer 0 N/A NA Pit Level Indicators NA NA #1 Rams 1 1.75" BS P Flow Indicator NA NA #2 Rams 1 1.75" PS P Meth Gas Detector NA NA #3 Rams 0 N/A NA H2S Gas Detector NA NA #4 Rams 0 N/A NA MS Misc 0NA #5 Rams 0 N/A NA #6 Rams 0 N/A NA Quantity Test Result Choke Ln. Valves 2 2"P Inside Reel valves 1P HCR Valves 0 N/A NA Kill Line Valves 2 2"P Check Valve 0 N/A NA ACCUMULATOR SYSTEM: BOP Misc 0 N/A NA Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)2450 P Quantity Test Result 200 psi Attained (sec)5 P No. Valves 5P Full Pressure Attained (sec)14 P Manual Chokes 2P Blind Switch Covers: All stations Yes Hydraulic Chokes 0NA Nitgn. Bottles # & psi (Avg.): N/A NA CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:4.5 Hours Repair or replacement of equipment will be made within N/A days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 6/9/22 14:56 Waived By Test Start Date/Time:6/11/2022 11:00 (date) (time)Witness Test Finish Date/Time:6/11/2022 15:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Fox Terence Rais Hilcorp Alaska Todd Sidoti Ninilchik Unit GO-08 Test Pressure (psi): todd.sidoti@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0611_BOP_Fox8_Ninilchik_GO-8 5(9,6(' 9 9 9 9 9 9 9 9 9 9 9 MEU -5HJJ Weekly:x 5HJJ-DPHV%2*& )URP7RGG6LGRWL&7RGG6LGRWL#KLOFRUSFRP! 6HQW:HGQHVGD\-XQH30 7R%URRNV3KRHEH/2*& &F5HJJ-DPHV%2*& 6XEMHFW5(>(;7(51$/@):%23(7HVWUHSRUW+LOFRUS*2ZHOO $WWDFKPHQWV*2)R[&7%23(7HVW[OV[ )ROORZ8S)ODJ)ROORZXS )ODJ6WDWXV&RPSOHWHG ,ŝWŚŽĞďĞ͕ ^ĞĞĂƚƚĂĐŚĞĚƌĞƉŽƌƚƉĞƌĨŽƌŵĞĚŽŶϲͬϯͬϮϮŝŶĞǆĐĞůĨŽƌŵĂƚ͘/ďĞůŝĞǀĞƚŚĂƚƚŚŝƐŝƐƚŚĞƌĞƉŽƌƚƌĞƋƵĞƐƚĞĚ͘WůĞĂƐĞůĞƚŵĞŬŶŽǁ ŝĨǇŽƵƌĞƋƵŝƌĞĂŶǇĂĚĚŝƚŝŽŶĂůŝŶĨŽƌŵĂƚŝŽŶ͘ dŚĂŶŬǇŽƵ͕ dŽĚĚ &ƌŽŵ͗ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх ^ĞŶƚ͗tĞĚŶĞƐĚĂǇ͕:ƵŶĞϭϱ͕ϮϬϮϮϭ͗ϱϱWD dŽ͗dŽĚĚ^ŝĚŽƚŝͲ;ͿфdŽĚĚ͘^ŝĚŽƚŝΛŚŝůĐŽƌƉ͘ĐŽŵх Đ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗΀ydZE>΁&t͗KWdĞƐƚƌĞƉŽƌƚ,ŝůĐŽƌƉ'KϴǁĞůů dŽĚĚ͕ ƚƚĂĐŚĞĚŝƐĂƌĞǀŝƐĞĚƌĞƉŽƌƚĐŚĂŶŐŝŶŐƚŚĞƚĞƐƚƚǇƉĞƚŽtĞĞŬůǇ;ĂƐƚŚĞϲͬϱͬϮϮǁĂƐůŝƐƚĞĚĂƐ/ŶŝƚŝĂůͿ͘ tŽƵůĚǇŽƵďĞĂďůĞƚŽƐĞŶĚƚŚĞǆĐĞůǀĞƌƐŝŽŶŽĨƚŚĞϲͬϱͬϮϮƌĞƉŽƌƚĂƐǁĞůů;ǁĞŚĂǀĞŶŽƚƌĞĐĞŝǀĞĚĂƌĞƐƉŽŶƐĞĂŶĚǁĞ ĐĂŶŶŽƚŝŵƉŽƌƚĂƉĚĨͿ͍ dŚĂŶŬǇŽƵ͕ WŚŽĞďĞ WŚŽĞďĞƌŽŽŬƐ ZĞƐĞĂƌĐŚŶĂůǇƐƚ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ WŚŽŶĞ͗ϵϬϳͲϳϵϯͲϭϮϰϮ 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. &ƌŽŵ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх ^ĞŶƚ͗dŚƵƌƐĚĂǇ͕:ƵŶĞϵ͕ϮϬϮϮϯ͗ϰϰWD dŽ͗WĂƚŽƵĚƌĞĂƵǆфƐƉĂŶŬǇďŽƵĚƌĞĂƵǆΛǇĂŚŽŽ͘ĐŽŵх 1LQLOFKLN8QLW*2 37' ĞĂƚƚĂĐŚĞĚƌĞƉŽƌƚƉĞƌĨŽƌŵĞĚŽŶϲͬϯͬϮϮ Đ͗ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗Z͗KWdĞƐƚƌĞƉŽƌƚ,ŝůĐŽƌƉ'KϴǁĞůů ^ĞŶĚǆĐĞůǀĞƌƐŝŽŶŽĨƚŚĞƚĞƐƚƌĞƉŽƌƚ :ŝŵZĞŐŐ ^ƵƉĞƌǀŝƐŽƌ͕/ŶƐƉĞĐƚŝŽŶƐ K' ϯϯϯt͘ϳƚŚǀĞ͕^ƵŝƚĞϭϬϬ ŶĐŚŽƌĂŐĞ͕<ϵϵϱϬϭ ϵϬϳͲϳϵϯͲϭϮϯϲ &ƌŽŵ͗WĂƚŽƵĚƌĞĂƵǆфƐƉĂŶŬǇďŽƵĚƌĞĂƵǆΛǇĂŚŽŽ͘ĐŽŵх ^ĞŶƚ͗^ƵŶĚĂǇ͕:ƵŶĞϱ͕ϮϬϮϮϵ͗ϰϰD dŽ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх͖KK'WƌƵĚŚŽĞĂǇфĚŽĂ͘ĂŽŐĐĐ͘ƉƌƵĚŚŽĞ͘ďĂǇΛĂůĂƐŬĂ͘ŐŽǀх͖ ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗KWdĞƐƚƌĞƉŽƌƚ,ŝůĐŽƌƉ'KϴǁĞůů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ll BOPE reports are due to the agency within 5 days of testing* SSu b m i t t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:8 DATE: 6/3/22 Rig Rep.: Rig Phone: (907)887-1766 Operator: Op. Phone:(907)632-4113 Rep.: E-Mail Well Name: PTD #2150770 Sundry #322-266 Operation: Drilling: Workover: x Explor.: Test: Initial: x Weekly: Bi-Weekly: Other: Rams:250/2500 Annular:N/A Valves:250/2500 MASP:1871 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig P Lower Kelly 0NA PTD On Location P Hazard Sec.P Ball Type 0NA Standing Order Posted NA Misc.NA Inside BOP 0NA FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75"P Trip Tank NA NA Annular Preventer 0 N/A NA Pit Level Indicators NA NA #1 Rams 1 1.75" BS P Flow Indicator NA NA #2 Rams 1 1.75" PS P Meth Gas Detector NA NA #3 Rams 0 N/A NA H2S Gas Detector NA NA #4 Rams 0 N/A NA MS Misc 0NA #5 Rams 0 N/A NA #6 Rams 0 N/A NA Quantity Test Result Choke Ln. Valves 2 2"P Inside Reel valves 1P HCR Valves 0 N/A NA Kill Line Valves 2 2"P Check Valve 0 N/A NA ACCUMULATOR SYSTEM: BOP Misc 0 N/A NA Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)2450 P Quantity Test Result 200 psi Attained (sec)4 P No. Valves 5P Full Pressure Attained (sec)14 P Manual Chokes 2P Blind Switch Covers: All stations Yes Hydraulic Chokes 0NA Nitgn. Bottles # & psi (Avg.): N/A NA CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:6.0 Hours Repair or replacement of equipment will be made within N/A days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time Waived By Test Start Date/Time:6/3/2022 8:00 (date) (time)Witness Test Finish Date/Time:6/3/2022 14:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Fox Accumulator precharge pressure 1400 psi Terence Rais Hilcorp Alaska Pat "Spanky" Boudreaux Ninilchik Unit GO-08 Test Pressure (psi): spankyboudreaux@yahoo.com Form 10-424 (Revised 02/2022) 2022-0603_BOP_Fox8_Ninilchik_GO-8 9 9 9 9999 9 9 9 9 MEU -5HJJ 5HJJ-DPHV%2*& )URP7RGG6LGRWL&7RGG6LGRWL#KLOFRUSFRP! 6HQW0RQGD\-XQH30 7R5HJJ-DPHV%2*&'2$$2*&&3UXGKRH%D\%URRNV3KRHEH/2*& 6XEMHFW1,18*237' $WWDFKPHQWV)R[[OV[ ,ĞůůŽ͕ WůĞĂƐĞƐĞĞĂƚƚĂĐŚĞĚKWƚĞƐƚƌĞƉŽƌƚĨŽƌƚŚĞdǁŽƌŬŽŶ'KϬϴƐƚĂƌƚŝŶŐŽŶϬϲͬϭϭ͘ ZĞŐĂƌĚƐ͕ dŽĚĚ dŽĚĚ^ŝĚŽƚŝͮ<ĞŶĂŝ&ŝĞůĚŶŐŝŶĞĞƌͮ,ŝůĐŽƌƉůĂƐŬĂͮϵϬϳͲϲϯϮͲϰϭϭϯ 7KHLQIRUPDWLRQFRQWDLQHGLQWKLVHPDLOPHVVDJHLVFRQILGHQWLDODQGPD\EHOHJDOO\SULYLOHJHGDQGLVLQWHQGHGRQO\IRUWKHXVHRIWKHLQGLYLGXDORUHQWLW\QDPHG DERYH,I\RXDUHQRWDQLQWHQGHGUHFLSLHQWRULI\RXKDYHUHFHLYHGWKLVPHVVDJHLQHUURU\RXDUHKHUHE\QRWLILHGWKDWDQ\GLVVHPLQDWLRQGLVWULEXWLRQRUFRS\RIWKLV HPDLOLVVWULFWO\SURKLELWHG,I\RXKDYHUHFHLYHGWKLVHPDLOLQHUURUSOHDVHLPPHGLDWHO\QRWLI\XVE\UHWXUQHPDLORUWHOHSKRQHLIWKHVHQGHU VSKRQHQXPEHULVOLVWHG DERYHWKHQSURPSWO\DQGSHUPDQHQWO\GHOHWHWKLVPHVVDJH :KLOHDOOUHDVRQDEOHFDUHKDVEHHQWDNHQWRDYRLGWKHWUDQVPLVVLRQRIYLUXVHVLWLVWKHUHVSRQVLELOLW\RIWKHUHFLSLHQWWRHQVXUHWKDWWKHRQZDUGWUDQVPLVVLRQ RSHQLQJRUXVHRIWKLVPHVVDJHDQGDQ\DWWDFKPHQWVZLOOQRWDGYHUVHO\DIIHFWLWVV\VWHPVRUGDWD1RUHVSRQVLELOLW\LVDFFHSWHGE\WKHFRPSDQ\LQWKLVUHJDUGDQG WKHUHFLSLHQWVKRXOGFDUU\RXWVXFKYLUXVDQGRWKHUFKHFNVDVLWFRQVLGHUVDSSURSULDWH &$87,217KLVHPDLORULJLQDWHGIURPRXWVLGHWKH6WDWHRI$ODVNDPDLOV\VWHP'RQRWFOLFNOLQNVRURSHQ DWWDFKPHQWVXQOHVV\RXUHFRJQL]HWKHVHQGHUDQGNQRZWKHFRQWHQWLVVDIH 1LQLOFKLN8QLW*2 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSu b m i t t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:8 DATE: 6/11/22 Rig Rep.: Rig Phone: (907)887-1766 Operator: Op. Phone:(907)632-4113 Rep.: E-Mail Well Name: PTD #2150770 Sundry #322-266 Operation: Drilling: Workover: x Explor.: Test: Initial: x Weekly: Bi-Weekly: Other: Rams:250/2500 Annular:N/A Valves:250/2500 MASP:1871 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig P Lower Kelly 0NA PTD On Location P Hazard Sec.P Ball Type 0NA Standing Order Posted NA Misc.NA Inside BOP 0NA FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75"P Trip Tank NA NA Annular Preventer 0 N/A NA Pit Level Indicators NA NA #1 Rams 1 1.75" BS P Flow Indicator NA NA #2 Rams 1 1.75" PS P Meth Gas Detector NA NA #3 Rams 0 N/A NA H2S Gas Detector NA NA #4 Rams 0 N/A NA MS Misc 0NA #5 Rams 0 N/A NA #6 Rams 0 N/A NA Quantity Test Result Choke Ln. Valves 2 2"P Inside Reel valves 1P HCR Valves 0 N/A NA Kill Line Valves 2 2"P Check Valve 0 N/A NA ACCUMULATOR SYSTEM: BOP Misc 0 N/A NA Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)2450 P Quantity Test Result 200 psi Attained (sec)5 P No. Valves 5P Full Pressure Attained (sec)14 P Manual Chokes 2P Blind Switch Covers: All stations Yes Hydraulic Chokes 0NA Nitgn. Bottles # & psi (Avg.): N/A NA CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:4.5 Hours Repair or replacement of equipment will be made within N/A days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 6/9/22 14:56 Waived By Test Start Date/Time:6/11/2022 11:00 (date) (time)Witness Test Finish Date/Time:6/11/2022 15:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Fox Terence Rais Hilcorp Alaska Todd Sidoti Ninilchik Unit GO-08 Test Pressure (psi): todd.sidoti@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0611_BOP_Fox8_Ninilchik_GO-8 9 9 9 9 9 99 9 9 9 9 MEU -5HJJ 7\SHRI5HTXHVW $EDQGRQ 3OXJ3HUIRUDWLRQV )UDFWXUH6WLPXODWH 5HSDLU:HOO 2SHUDWLRQVVKXWGRZQ 6XVSHQG 3HUIRUDWH 2WKHU6WLPXODWH 3XOO7XELQJ &KDQJH$SSURYHG3URJUDP 3OXJIRU5HGULOO 3HUIRUDWH1HZ3RRO 5HHQWHU6XVS:HOO $OWHU&DVLQJ 2SHUDWRU1DPH &XUUHQW:HOO&ODVV 3HUPLWWR'ULOO1XPEHU ([SORUDWRU\ 'HYHORSPHQW $GGUHVV6WUDWLJUDSKLF 6HUYLFH $3,1XPEHU ,ISHUIRUDWLQJ:HOO1DPHDQG1XPEHU :KDW5HJXODWLRQRU&RQVHUYDWLRQ2UGHUJRYHUQVZHOOVSDFLQJLQWKLVSRRO" :LOOSODQQHGSHUIRUDWLRQVUHTXLUHDVSDFLQJH[FHSWLRQ" <HV 1R 3URSHUW\'HVLJQDWLRQ/HDVH1XPEHU 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ϰ͕ϲϬϰ͛ ϱϰ ϮͲϳͬϴ͟ ϬϯͬϬϮͬϮϬϭϳ ϵ͕ϮϮϬ͛ ϵ͕ϮϲϬ͛ ϰ͕ϲϬϰ͛ ϰ͕ϲϰϯ͛ ϰϬ ϮͲϳͬϴ͟ ϬϯͬϬϭͬϮϬϭϳ dϭϯ ϵ͕ϰϭϮ͛ ϵ͕ϰϮϰ͛ ϰ͕ϳϵϰ͛ ϰ͕ϴϬϲ͛ ϭϮ ϮͲϳͬϴ͟ ϬϯͬϬϭͬϮϬϭϳ dϭϳ ϵ͕ϴϬϬ͛ ϵ͕ϴϳϳ͛ ϱ͕ϭϴϬ͛ ϱ͕Ϯϱϲ͛ ϳϳ ϮͲϳͬϴ͟ ϬϮͬϬϯͬϮϬϭϳ ϵ͕ϴϮϴ͛ ϵ͕ϴϱϭ͛ ϱ͕ϮϬϴ͛ ϱ͕ϮϯϬ͛ Ϯϯ ϮͲϳͬϴ͟ ϬϴͬϮϴͬϮϬϭϱ ϵ͕ϴϯϳ͛ ϵ͕ϴϳϳ͛ ϱ͕Ϯϭϲ͛ ϱ͕Ϯϱϲ͛ Ϯϯ ϮͲϳͬϴ͟ ϬϮͬϬϮͬϮϬϭϳ 5$0NU-W 5$0NU-W 5$0NU-W ¶ 7$ 7 7% 7 7$ %HO KWE,K>ͬDEdd/> ϭϬͲϯͬϰ͟ ϯϴϯďďůƐϭϮƉƉŐůĞĂĚнϳϲďďůƐϭϱ͘ϮƉƉŐƚĂŝůŽĨĐĞŵĞŶƚŝŶ ϭϯͲϭͬϮ͟ŚŽůĞ͘ϮϬϴďďůƐĐĞŵĞŶƚďĂĐŬƚŽƐƵƌĨĂĐĞ ϳͲϱͬϴ͟ϮϯϱďďůƐŽĨϭϮ͘ϱƉƉŐůĂƐƐ'ůĞĂĚĐŵƚ͕ĂŶĚϳϬďďůƐŽĨϭϱ͘ϯƉƉŐ'ĂƐůŽŬƚĂŝůĐĞŵĞŶƚŝŶϵͲϳͬϴ͟ŚŽůĞ͘EŽ ůŽƐƐĞƐĚƵƌŝŶŐũŽď͘ΕϭϱďďůƐĐŽŶƚĂŵŝŶĂƚĞĚĐĞŵĞŶƚƌĞƚƵƌŶƐďĂĐŬƚŽƐƵƌĨĂĐĞ͘ ϰͲϭͬϮ͟ ϭϬϵďďůƐŽĨϭϱ͘ϯƉƉŐůĂƐƐ'ĂƐǇůŽŬůĞĂĚĐŵƚ͘>ŽƐƐĞƐĚƵƌŝŶŐĚŝƐƉůĂĐĞŵĞŶƚĂĨƚĞƌĚĂƌƚůĂƚĐŚĞĚƵƉ͘EŽ ĐĞŵĞŶƚŶŽƌƐƉĂĐĞƌďĂĐŬƚŽƐƵƌĨĂĐĞ͘ϴͬϮϰͬϭϱ>ƐŚŽǁƐƚŽƉŐŽŽĚĐĞŵĞŶƚĂƚϴϱϱϬ͛DĂŶĚŚŝŐŚĞƐƚdŽ ĂƚϴϮϬϬ͛D͘ ϯ й < > %HO 7 7 7 7 7 7% CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Jacob Flora Cc:Juanita Lovett Subject:RE: 10-403 Grassim Oskolkoff 8 PTD 215-077 - Sundry_322-266_Approved_051822 Date:Thursday, May 19, 2022 4:34:00 PM Jake, Approval is granted to use Nitrogen as needed for the cleanout. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Thursday, May 19, 2022 8:53 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: 10-403 Grassim Oskolkoff 8 PTD 215-077 - Sundry_322-266_Approved_051822 Good Morning Bryan, We appreciate the recently approved sundries. While looking through the GO-08 coil sundry I realized we will need nitrogen during the fill cleanout to lift fluids off of the open perfs. I’ve attached the nitrogen SOP. Please advise if this is acceptable. Thanks, Jake From: Juanita Lovett <jlovett@hilcorp.com> Sent: Wednesday, May 18, 2022 2:19 PM To: Jacob Flora <Jake.Flora@hilcorp.com> Subject: 10-403 Grassim Oskolkoff 8 - Sundry Approval Jake, For distribution when needed. \\hilcorp.com\share\Alaska\Fields\Ninilchik\G Oskolkoff\Wells\GO-08\Regulatory\Agency Filings\AOGCC\10-403\10-403 Grassim Oskolkoff 8 PTD 215-077 - Sundry_322- 266_Approved_051822.pdf Thanks, Juanita The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: _N2/Patch/Cap string____ 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 10,200'N/A Casing Collapse Structural Conductor Surface 2,470 psi Intermediate 4,790 psi Intermediate 5,340 psi Liner 7,500 psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng ryan.rupert@hilcorp.com 5,577'10,055'5,433'~1,850psi 10,055' Baker ZXP Liner Top Packer ; none 7,239' MD / 2,792' TVD Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: 8,430 psi Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 389737 215-077 50-133-20651-00-00 Grassim Oskolkoff (GO) #8 Ninilchik Field - Beluga/Tyonek Gas Pool Length Size CO 701C Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 12.6# / L-80 TVD Burst 7,287' 9,470 psi MD 6,890 psi 5,210 psi 120' 1,844' 1,450' 120' 3,492' 2,943'7-5/8" 16" 10-3/4" 120' 7-5/8"1,779' 3,492' 7,466' Perforation Depth MD (ft): 1,779 See Attached Schematic 5,687' 4-1/2" Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: June 12, 2021 10,198'2,959' 4-1/2" 5,575' Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.05.27 16:35:47 -08'00' Taylor Wellman (2143) 10-404 BJM 6/8/21 Separate Sundry required for capstring installation. DLB 05/28/2021 DSR-5/28/21 X dts 6/9/2021 JLC 6/9/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.06.09 12:19:53 -08'00' RBDMS HEW 6/10/2021 Well Prognosis Well: GO-08 Date: 5/27/2021 Well Name:GO-08 API Number:50-113-20651-00-00 Current Status:Gas Producer Leg:N/A Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:215-077 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907)301-1736 (C) Second Call Engineer:Ted Kramer (907) 777-8420 (O)(985) 867-0665 (C) Maximum Expected BHP:~ 2376 psi @ 5256’ TVD Assuming 0.452psi/ft to deepest perf Max. Potential Surface Pressure:~ 1850 psi Using Max BHP minus 0.1 psi/ft. gas gradient to surface Well Summary After being offline for ~1yr due to loading up, additional sands were perf’d in the Upper Tyonek in April 2020. The sands were successful in returning the well to production at ~1 MMCFD at 77psi. However, through a combination of water and fill, the well loaded up in October 2020. There are additional sands to perforate in the Upper Tyonek, as well as some Lower Beluga sands. Despite the high deviation, E-line has been successful in the past in reaching the perf depths. If unsuccessful, coil may be require to run a fill cleanout and access the perforation depths, and would be the subject of a different sundry. The cement quality across the proposed perforations ranges from good down deep, to poor as we continue upward. Despite this, given the well is dead currently, and all proposed sands are within the same pool, the perforations are still worth pursuing. The goal of this project is to perforate the remaining accessible Upper Tyonek and Lower Beluga sands. Notes Regarding Wellbore Condition Min ID = 3.813” at 259’ (4-1/2” SSSV nipple) Inclination: o Goes >70 degrees at 1825’ MD o Max = 80 degrees at 2421’ MD o 78 deg sail angle from 2100 – 6700’ MD o Rolls over to <20 deg through proposed perf intervals Drifts o 5/21/20: SL pulled SSSV (covered in mud) and couldn’t brush down past 1800’. SL made it down to 8827’ with a 3” x 4’ drive down bailer (came back full of sand). o 4/11/20: EL made it down with final perf gun run to 8632’ MD with a 9’ x 2-7/8” perf gun and logging assembly. Used roller boogies as well. Note says:When tools are hard to get down, ensure at least 550# hanging weight, and pump 10-15 gal of diesel to help get down. o 4/4/20: EL made it down to 8891’ with a 435# 2-7/8” x 20’ perf gun + logging sub. (no tag) o 4/3/20: SL pulled WLSSSV from 259’ MD. Drifted to PBTD and tagged at 9616’ MD with a 3.74” gauge ring. coil may be require to run a fill cleanout and would be the subject of a different sundry. Well Prognosis Well: GO-08 Date: 5/27/2021 Nitrogen Risk Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) Ensure all crews are aware of stop work authority E-Line Perf 1. MIRU E-line and pressure control equipment. Ensure a few bbls of diesel are on hand to help tools get downhole, if needed. 2. PT lubricator to 250psi low / 3,500 psi High. 3. If no prior SL drift, consider an EL drift run with a junk basket. 4. RIH W/ GPT tool to find fluid level and obtain a light tag of PBTD 5. Consult with OE to determine if Nitrogen is needed to push away fluid 6. RU Nitrogen Truck a) Push water back into formation to top open perf b) Use GPT tool to confirm water level c) Consult OE for pressure to leave on well for perforating 7. Rig up perf gun (Likely 2-7/8” 4-6 spf) 8. RIH and perforate the sand listed in the table below, per Geo/RE. Sand Perforation Top (MD) Perforation Bottom (MD) Perforation Top (TVD) Perforation Bottom (TVD) Total Footage (MD) BEL_120 ±7,948’±7,976’±3,347’±3,373’28‘ BEL_135u ±8,159’±8,165’±3,551’±3,556’6‘ BEL_135L ±8,171’±8,191’±3,563’±3,582’20‘ T-2u ±8,230’±8,243’±3,620’±3,633’13‘ T-2L ±8,300'±8,322'±3,690'±8,322'22‘ T-3u ±8,348’±8,362’±3,737’±3,750’12‘ T-3L ±8,370’±8,374’±3,759’±3,763’4‘ T-5 ±8,450’±8,452’±3,838’±3,840’2‘ T-6 ±8,571’±8,583’±3,959’±3,970 12‘ T-7 ±8,735’±8,753’±4,121’±4,139’18‘ T-15 ±9,513’±9,527’±4,894’±4,908’14‘ T-17B ±9,930’±9,936’±5,309’±5,315’6‘ Consult with OE for what WHP to use. Some intervals may be shot while flowing Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a.Use Gamma/CCL to correlate. b. Record initial and 5/10/15 minute tubing pressures after firing c. Consult with RE/Geo between each perf interval: i. Anthony McConkey: RE - 529-6199 ii. Matthew Petrowsky: Geo – 814-421-6753 9.RD E-Line Unit and turn well over to production. Well Prognosis Well: GO-08 Date: 5/27/2021 SL set SSSV A SSSV will need to be run if sustained flow is achieved from GO-08 and if a cap string is not RIH. Must be set within 14 days of well’s return to service, and tested no later than 5 days after installation. 1. MIRU SL 2. Set WLSSSV in profile at 259’ MD 3. Confirm set, and RDMO SL 4. Ensure SSSV is state-tested with 5 days of setting. Contingency EL Plug or Patch 1. MIRU E-line, PT lubricator to 250 psi low / 3,500 psi high 2. RIH W/ GPT tool and find fluid level 3. RU Nitrogen Truck a. Push water back into formation b. Use GPT tool to confirm water level is below interval to perf c. Consult OE for pressure to leave on well for perforating 4. Once fluid level is below interval to isolate, MU 4-1/2” patch or plug 5. RIH and set plug or patch per OE. 6. RD E-Line Unit and turn well over to production. Contingency Capstring Procedure: 1. MIRU Cap String Truck, PT lubricator to 2,500 psi Hi 250 Low. 2. Install wellhead packoff. 3. PU 3/8” capillary string. RIH and set @ ±8,600’ MD (or as deep as practical) 4. Set spool of remaining line near well. 5. Rig down Cap String Truck. 6. Turn well over to production. Attachments: 1. Current schematic 2. Proposed Schematic 3. Standard Well procedure – N2 Operations Separate sundry require for capstring installation. ___________________________________________________________________________________ Updated by CRR 05-27-21 SCHEMATIC Ninilchik Unit Well: Grassim Oskolkoff #8 PTD: 215-077 API: 50-133-20651-00-00 PBTD = 10,055’ MD / 5,433’ TVD TD = 10,200’ MD / 5,577’ TVD Max Deviation: 79 deg @ 2,421’ 78 deg sail angle from 2100-6700’ MD RKB 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor 84 X-56 Weld 15.010” Surf 120’ 10-3/4" Surf. Csg 45.5 L-80 BTC 9.950” Surf 3,492’ 7-5/8" Int. Csg 29.7 L-80 BTC 6.875” Surf 1,779’ 7-5/8” Int. Csg 29.7 P-110 BTC 6.875” 1,779’ 7,466’ 4-1/2" Prod Liner 12.6 L-80 DWC/C- HT 3.958" 7,239’ 10,198’ TUBING DETAIL 4-1/2” Tubing 12.6 L-80 BTC-mod 3.958” Surf 7,287’ 16” 10-3/4” 4-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 18’4.00”-Tubing Hanger,4-1/2”BT Mod 2 259’3.813”5.50”4-1/2”Hydraulic Nipple for WL Retrievable SCSSV 3 335’3.85”5.75”4-1/2”Chemical Injection Mandrel 4 7,239’ 3.958” 6.875” Baker ZXP Liner Top Packer/ HRD-E Profile (10’ tie-back extension) 5 7,272’ 3.900” 4.74” Seal Bore Extension “GBH-22” Locating seal assembly (16.37’) 6 10,055’3.958”CIBP 7-5/8” 1 2 4 5 3 RA Mkr Jt 8,211' PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) ft Size Date T6A 8,622’ 8,631’ 4,009’ 4,018’ 9 2-7/8” 04/10/2020 8,664’ 8,690’ 4,051’ 4,077 26 2-7/8” 04/09/2020 T9 8,818’ 8,825’ 4,204’ 4,211’ 7 2-7/8” 04/09/2020 8,852’ 8,856’ 4,238’ 4,242’ 4 2-7/8” 04/04/2020 8,871’ 8,891’ 4,257’ 4,276’ 20 2-7/8” 04/04/2020 T12 9,166’ 9,220’ 4,550’ 4,604’ 54 2-7/8” 03/02/2017 9,220’ 9,260’ 4,604’ 4,643’ 40 2-7/8” 03/01/2017 T13B 9,412’ 9,424’ 4,794’ 4,806’ 12 2-7/8” 03/01/2017 T17A 9,800’ 9,877’ 5,180’ 5,256’ 77 2-7/8” 02/03/2017 9,828’ 9,851’ 5,208’ 5,230’ 23 2-7/8” 08/28/2015 9,837’ 9,877’ 5,216’ 5,256’ 23 2-7/8” 02/02/2017 RA Mkr Jt 8,502' RA Mkr Jt 8,790' RA Mkr Jt 9,905’ T17A T12 T13B 6 T9 T6A OPEN HOLE / CEMENT DETAIL 10-3/4” 383 bbls 12ppg lead + 76 bbls 15.2ppg tail of cement in 13-1/2” hole. 208 bbls cement back to surface 7-5/8”235 bbls of 12.5ppg Class G lead cmt, and 70 bbls of 15.3ppg GasBlok tail cement in 9-7/8” hole. No losses during job. ~15bbls contaminated cement returns back to surface. 4-1/2” 109 bbls of 15.3ppg Class G EasyBlok lead cmt. Losses during displacement after dart latched up. No cement nor spacer back to surface. 8/24/15 CBL shows top good cement at 8550’ MD and highestToC at 8200’ MD. 3 % K C L ___________________________________________________________________________________ Updated by CRR 05-27-21 PROPOSED SCHEMATIC Ninilchik Unit Well: Grassim Oskolkoff #8 PTD: 215-077 API: 50-133-20651-00-00 PBTD = 10,055’ MD / 5,433’ TVD TD = 10,200’ MD / 5,577’ TVD Max Deviation: 79 deg @ 2,421’ 78 deg sail angle from 2100-6700’ MD RKB 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor 84 X-56 Weld 15.010” Surf 120’ 10-3/4" Surf. Csg 45.5 L-80 BTC 9.950” Surf 3,492’ 7-5/8" Int. Csg 29.7 L-80 BTC 6.875” Surf 1,779’ 7-5/8” Int. Csg 29.7 P-110 BTC 6.875” 1,779’ 7,466’ 4-1/2" Prod Liner 12.6 L-80 DWC/C- HT 3.958" 7,239’ 10,198’ TUBING DETAIL 4-1/2” Tubing 12.6 L-80 BTC-mod 3.958” Surf 7,287’ 16” 10-3/4” 4-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 18’4.00”-Tubing Hanger,4-1/2”BT Mod 2 259’3.813”5.50”4-1/2”Hydraulic Nipple for WL Retrievable SCSSV 3 335’3.85”5.75”4-1/2”Chemical Injection Mandrel 4 7,239’ 3.958” 6.875” Baker ZXP Liner Top Packer/ HRD-E Profile (10’ tie-back extension) 5 7,272’ 3.900” 4.74” Seal Bore Extension “GBH-22” Locating seal assembly (16.37’) 6 10,055’3.958”CIBP 7-5/8” 1 2 4 5 3 RA Mkr Jt 8,211' PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) ft Size Date Adperfs per sundry T6A 8,622’ 8,631’ 4,009’ 4,018’ 9 2-7/8” 04/10/2020 8,664’ 8,690’ 4,051’ 4,077 26 2-7/8” 04/09/2020 T9 8,818’ 8,825’ 4,204’ 4,211’ 7 2-7/8” 04/09/2020 8,852’ 8,856’ 4,238’ 4,242’ 4 2-7/8” 04/04/2020 8,871’ 8,891’ 4,257’ 4,276’ 20 2-7/8” 04/04/2020 T12 9,166’ 9,220’ 4,550’ 4,604’ 54 2-7/8” 03/02/2017 9,220’ 9,260’ 4,604’ 4,643’ 40 2-7/8” 03/01/2017 T13B 9,412’ 9,424’ 4,794’ 4,806’ 12 2-7/8” 03/01/2017 T17A 9,800’ 9,877’ 5,180’ 5,256’ 77 2-7/8” 02/03/2017 9,828’ 9,851’ 5,208’ 5,230’ 23 2-7/8” 08/28/2015 9,837’ 9,877’ 5,216’ 5,256’ 23 2-7/8” 02/02/2017 RA Mkr Jt 8,502' RA Mkr Jt 8,790' RA Mkr Jt 9,905’ T17A T12 T13B 6 T9 T6A OPEN HOLE / CEMENT DETAIL 10-3/4” 383 bbls 12ppg lead + 76 bbls 15.2ppg tail of cement in 13-1/2” hole. 208 bbls cement back to surface 7-5/8”235 bbls of 12.5ppg Class G lead cmt, and 70 bbls of 15.3ppg GasBlok tail cement in 9-7/8” hole. No losses during job. ~15bbls contaminated cement returns back to surface. 4-1/2” 109 bbls of 15.3ppg Class G EasyBlok lead cmt. Losses during displacement after dart latched up. No cement nor spacer back to surface. 8/24/15 CBL shows top good cement at 8550’ MD and highestToC at 8200’ MD. 3 % K C L STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Install Cap String 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 10,200 feet 10,055 feet true vertical 5,577 feet N/A feet Effective Depth measured 10,055 feet 7,239 feet true vertical 5,433 feet 2,792 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 7,287' MD 2,821' TVD WL SCSSV 259' MD 259' TVD Packers and SSSV (type, measured and true vertical depth)7,239' MD 2,792' TVD 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: 8,430psi Burst Intermediate 5,687'7-5/8"7,466' 120' 1,844' 1,450'6,890psi 5,210psi 2,943'9,470psi Collapse 2,470psi 4,790psi 7,500psi 5,340psi Casing Structural 16" 10-3/4" 7-5/8" Length 120' 3,492' 1,778' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 28 Casing Pressure Liner 2,959' 299 5,575' 0 Representative Daily Average Production or Injection Data 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A 73 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 34 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-077 50-133-20651-00=00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 8414 Grassim Oskolkoff (GO) #8 N/A ADL 389737 1,779' Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Ninilchik - Beluga/Tyonek Gas PoolN/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 4-1/2" Baker ZXP Liner Top Pkr WINJ WAG 626 Water-Bbl MD 120' 3,492' 10,198' 1 t Fra O 6. A G L PG , R g Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 2:52 pm, Jun 24, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.06.24 13:57:18 -08'00' Taylor Wellman DSR-6/24/2020 RBDMS HEW 6/24/2020 Install Cap Stringg gls 6/25/20 Rig Start Date End Date Cap String 5/25/20 5/25/20 05/25/2020 - Thursday Install cap string to 5,910' MD w/ Pollard Slickline. Pollard ($2487), Cap string coil 10,000 (est $15K), labor $1500. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name GO-08 50-133-20651-00 215-077 ___________________________________________________________________________________ Updated by DMA 06-05-20 SCHEMATIC Ninilchik Unit Well: Grassim Oskolkoff #8 PTD: 215-077 API: 50-133-20651-00-00 PBTD = 10,055’ MD / 5,433’ TVD TD = 10,200’ MD / 5,577’ TVD Max Deviation: 79 deg @ 2,421’ Max Dogleg: 6.2 deg/100 @ 1,496’ RKB 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor 84 X-56 Weld 15.010” Surf 120’ 10-3/4" Surf. Csg 45.5 L-80 BTC 9.950” Surf 3,492’ 7-5/8" Int. Csg 29.7 L-80 BTC 6.875” Surf 1,779’ 7-5/8” Int. Csg 29.7 P-110 BTC 6.875” 1,779’ 7,466’ 4-1/2" Prod Liner 12.6 L-80 DWC/C- HT 3.958" 7,239’ 10,198’ TUBING DETAIL 4-1/2” Tubing 12.6 L-80 BTC-mod 3.958” Surf 7,287’ 16” 10-3/4” 4-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.00” - Tubing Hanger, 4-1/2” BT Mod 2 269’ 3.813” 5.50” 5-1/2” Hydraulic Nipple for WL Retrievable SCSSV 3 335’ 3.85” 5.75” 4-1/2” Chemical Injection Mandrel 4 7,239’ 3.958” 6.875” Baker ZXP Liner Top Packer/ HRD-E Profile (10’ tie-back extension) 5 7,272’ 3.833” 4.74” Seal Bore Extension “GBH-22” Locating seal assembly (16.37’) 6 10,055’ 3.958” CIBP 7-5/8” 6-3/4” hole Shoe @ 10,198’ TOC @ ~2,000’ 1 2 4 5 3 RA Mkr Jt 8,211' PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) ft Size Date T6A 8,622’ 8,631’ 4,009’ 4,018’ 9 2-7/8” 04/10/2020 T9 8,818’ 8,825’ 4,204’ 4,211’ 7 2-7/8” 04/09/2020 8,664’ 8,690’ 4,051’ 4,077 26 2-7/8” 040/9/2020 8,852’ 8,856’ 4,238’ 4,242’ 4 2-7/8” 04/04/2020 8,871’ 8,891’ 4,257’ 4,276’ 20 2-7/8” 04/04/2020 T12 9,166’ 9,220’ 4,550’ 4,604’ 54 2-7/8” 03/02/2017 9,220’ 9,260’ 4,604’ 4,643’ 40 2-7/8” 03/01/2017 T13B 9,412’ 9,424’ 4,794’ 4,806’ 12 2-7/8” 03/01/2017 T17A 9,800’ 9,877’ 5,180’ 5,256’ 77 2-7/8” 02/03/2017 9,828’ 9,851’ 5,208’ 5,230’ 23 2-7/8” 08/28/2015 9,837’ 9,877’ 5,216’ 5,256’ 23 2-7/8” 02/02/2017 RA Mkr Jt 8,502' RA Mkr Jt 8,790' RA Mkr Jt 9,905’ T17A T12 T13B 6 T9 T6A Capillary String Installed 05/25/20 3/8” 2205 Stainless Steel (11,500’ spool) Top Bottom MD 0’ 5,910’ TVD 0’ 2,401’ Capillary String Installed 05/25/20 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: CTCO, Perf N2 Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 10,200 feet 10,055 feet true vertical 5,577 feet N/A feet Effective Depth measured 10,055 feet 7,239 feet true vertical 5,433 feet 2,792 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 7,287' MD 2,821' TVD WL SCSSV 259' MD 259' TVD Packers and SSSV (type, measured and true vertical depth)7,239' MD 2,792' TVD 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 WINJ WAG 0 Water-Bbl MD 120' 3,492' 10,198' 14 Oil-Bbl measured true vertical Packer 4-1/2" Baker ZXP Liner Top Pkr measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Ninilchik - Beluga/Tyonek Gas PoolN/A measured TVD Tubing Pressure 870 Grassim Oskolkoff (GO) #8 N/A ADL 389737 1,779' Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-077 50-133-20651-00=00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-096 84 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 22 Authorized Signature with date: Authorized Name: 34 Casing Pressure Liner 2,959' 626 5,575' 0 Representative Daily Average Production or Injection Data 1,778' Conductor Surface Intermediate Production Casing Structural 16" 10-3/4" 7-5/8" Length 120' 3,492' Collapse 2,470psi 4,790psi 7,500psi 5,340psi 120' 1,844' 1,450'6,890psi 5,210psi 2,943'9,470psi tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: 8,430psi Burst Intermediate 5,687'7-5/8"7,466' t Fra O 6. A G L PG , R 2 Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 9:04 am, May 26, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.05.22 17:09:07 -08'00' Taylor Wellman Perforate gls 5/26/20 RBDMS HEW 5/26/2020 DSR-5/26/2020 CTCO, Perf N22 Rig Start Date End Date E-Line 4/3/20 5/7/20 Daily Operations: Hilcorp Alaska, LLC Weekly Operations Summary API Number Well Permit NumberWell Name GO-08 50-133-20651-00 215-077 04/04/2020 - Saturday Sign in. PTW, JSA and SIMOPS with SLB N2 and AKE-line. Rig up lubricator. Had O-ring leak in lubricator. Changed out Oring. PT lubricator to 250 psi low and 3,000 psi high. Rig up SLB N2 hard lines and PT to 250 psi low and 4,000 psi high, RIH w/roller bogies, 2-7/8" x 20' HC Razor, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town (Tool string weighed ~435 lbs). Get ok to perf from 8871' to 8,891'. Pressure up tubing with N2 from 65 psi to 1,521 psi. Spotted and fired gun with 1,521 psi on tubing. After 5 min - 1,508.1 psi, 10 min - 1,503.1 psi and 15 min - 1,498.3 psi. POOH. All shots fired and gun was dry. Takes longer time to go in hole due to about a 4,000' which is 77 to 80 deg angle. RIH w/roller bogies, 2-7/8" x 4' HC Razor, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town (Tool string weighed ~390 lbs). Get ok to perf from 8,852' to 8,856'. Spotted and fired gun with 1290.3 psi on tubing. After 5 min - 1,288.3 psi, 10 min - 1,286.5 psi and 15 min - 1,284.3 psi. POOH. All shots fired and gun was dry Rig down lubricator. Secure well. Be back Monday. 04/03/2020 - Friday ARRIVE AT PWL - GATHER TOOLS AND EQUIPMENT - STANDBY FOR REST OF CREW. DEPART SHOP - MOB TO FIELD. ON LOCATION - TGSM - JSA - PERMIT. RIG UP W/L - PT LUB - GOOD RIH W/ 4-1/2 PRS TO 2,67'KB LATCH SSSV - WT - HAND SPANG - COME FREE - POOH - OOH W/ SSSV IN GOOD CONDITION - SOME DAMAGED PACKING. RIH W/ 3.74" GAUGE RING TO 9,616'KB TAG BOTTOM - POOH - OOH W/ FOAM AND LIGHT GREASE ON TOOLS RIG DOWN W/L - SECURE WELL - CLEAN AREA - DEPART FIELD FOR PWL SHOP. ARRIVE AT PWL SHOP - FUEL EQUIPMENT - SPOT ON BULL RAIL. 04/09/2020 - Thursday PTW, JSA and rig up lubricator. PT to 250 psi low and 3,000 psi high. RIH w/roller bogies, 2-7/8" x 7' HC Razor, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perf from 8818' to 8825' (T9 Upper). Spotted and fired gun with 1,604.9 psi on tubing. After 5 min - 1,607.5 psi, 10 min - 1,608.2 psi and 15 min - 1,609.3 psi. POOH. All shots fired and gun was dry. Pumped 20 gals of diesel in lubricator before we opened up. RIH w/roller bogies, 2-7/8" x 26' HC Razor, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Told to add 2' to correlation log, Added 2 ', spotted and fired gun from 8,664' to 8,690' with 1,621.7 psi. After 5 min - 1,623.9 psi, 10 min - 1,622.9 psi and 15 min - 1,622.5. POOH. All shots fired and gun was dry. Rig down lubricator and secure well. Will be back at 0700 hrs and finish the perf job. TP - 1,621.7 psi. Get ok to perf from 8871' to 8,891' 8,852' to 8,856' 80 deg angle. k to perf from 8818' to 8825' gun from 8,664' to 8,690' Rig up SLB N2 hard lines and PT to 250 psi low and 4,000 psi Note: high angle well... 80 deg Rig Start Date End Date E-Line 4/3/20 5/7/20 Daily Operations: Hilcorp Alaska, LLC Weekly Operations Summary API Number Well Permit NumberWell Name GO-08 50-133-20651-00 215-077 04/10/2020 - Friday PTW, JSA and rig up lubricator. PT to 250 psi low and 3,000 psi high. TP - 1,620.1 psi Pumped 10 gals of diesel in lubricator before we opened up. RIH w/roller bogies, 2-7/8" x 9' HC Razor, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perf from 8,622' to 8,631'. Spotted and fired gun with 1,633.2 psi. After 5 min - 1,633.0 psi, 10 min - 1,632.8 psi and 15 min - 1,631.7 psi. POOH. All shots fired and gun was dry. Rig down equipment and turn well back over to field. TP - 1,638.6 psi. Will be mobe to Beaver Creek to set plug on BCU-19 this afternoon and dump cement in morning while coil is spotting around us. Just need 2 runs of cement, NOTE: ON IS WELL WE NEED TO HAVE APPROX 550 LBS HANGING TOOL WEIGHT ON LIJNE AND DUMP 10 TO 15 GALS OF DIESEL TO CUT WIRELINE GREASE WHEN TOOLS ARE HARD TO GET DOWN. 05/07/2020 - Thursday Met with Reservoir Engineer. Decided to hold off on adding any more perforations at this time. o perf from 8,622' to 8,631'. S ___________________________________________________________________________________ Updated by DMA 05-14-20 SCHEMATIC Ninilchik Unit Well: Grassim Oskolkoff #8 PTD: 215-077 API: 50-133-20651-00-00 PBTD = 10,055’ MD / 5,433’ TVD TD = 10,200’ MD / 5,577’ TVD Max Deviation: 79 deg @ 2,421’ Max Dogleg: 6.2 deg/100 @ 1,496’ RKB 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor 84 X-56 Weld 15.010” Surf 120’ 10-3/4" Surf. Csg 45.5 L-80 BTC 9.950” Surf 3,492’ 7-5/8" Int. Csg 29.7 L-80 BTC 6.875” Surf 1,779’ 7-5/8” Int. Csg 29.7 P-110 BTC 6.875” 1,779’ 7,466’ 4-1/2" Prod Liner 12.6 L-80 DWC/C- HT 3.958" 7,239’ 10,198’ TUBING DETAIL 4-1/2” Tubing 12.6 L-80 BTC-mod 3.958” Surf 7,287’ 16” 10-3/4” 4-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.00” - Tubing Hanger, 4-1/2” BT Mod 2 269’ 3.813” 5.50” 5-1/2” Hydraulic Nipple for WL Retrievable SCSSV 3 335’ 3.85” 5.75” 4-1/2” Chemical Injection Mandrel 4 7,239’ 3.958” 6.875” Baker ZXP Liner Top Packer/ HRD-E Profile (10’ tie-back extension) 5 7,272’ 3.833” 4.74” Seal Bore Extension “GBH-22” Locating seal assembly (16.37’) 6 10,055’ 3.958” CIBP 7-5/8” 6-3/4” hole Shoe @ 10,198’ TOC @ ~2,000’ 1 2 4 5 3 RA Mkr Jt 8,211' PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) ft Size Date T6A 8,622’ 8,631’ 4,009’ 4,018’ 9 2-7/8” 04/10/2020 T9 8,818’ 8,825’ 4,204’ 4,211’ 7 2-7/8” 04/09/2020 8,664’ 8,690’ 4,051’ 4,077 26 2-7/8” 040/9/2020 8,852’ 8,856’ 4,238’ 4,242’ 4 2-7/8” 04/04/2020 8,871’ 8,891’ 4,257’ 4,276’ 20 2-7/8” 04/04/2020 T12 9,166’ 9,220’ 4,550’ 4,604’ 54 2-7/8” 03/02/2017 9,220’ 9,260’ 4,604’ 4,643’ 40 2-7/8” 03/01/2017 T13B 9,412’ 9,424’ 4,794’ 4,806’ 12 2-7/8” 03/01/2017 T17A 9,800’ 9,877’ 5,180’ 5,256’ 77 2-7/8” 02/03/2017 9,828’ 9,851’ 5,208’ 5,230’ 23 2-7/8” 08/28/2015 9,837’ 9,877’ 5,216’ 5,256’ 23 2-7/8” 02/02/2017 RA Mkr Jt 8,502' RA Mkr Jt 8,790' RA Mkr Jt 9,905’ T17A T12 T13B 6 T9 T6A ,,,,/// 1 T9 T6A 8,622’8,631’4,009’4,018’9 2-7/8”04/10/2020 8,818’8,825’4,204’4,211’7 2-7/8”04/09/2020 8,664’8,690’4,051’4,077 26 2-7/8”040/9/2020T9 8,852’8,856’4,238’4,242’4 2-7/8”04/04/2020 8,871’8,891’4,257’4,276’20 2-7/8”04/04/2020 ’’’’/”// 8,871 8,891 4,257 4,276 20 27/8 04/04/2020 new perfs T6A THE STATE °fALASKA. GOVERNOR MIKE DUNLEAVY Taylor Wellman Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga/Tyonek Gas Pool, GO 8 Permit to Drill Number: 215-077 Sundry Number: 320-096 Dear Mr. Wellman: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.alaskci.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, WJ e y rice Chair DATED this -I day of March, 2020. RBDM&L4 MAR 0 5 2020 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS gn AAr 9l; ?nn RECEIVE® MAR 2 2020 p�S 3/4J 20 AOGCC 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well p ❑ Operations shutdown ❑ Suspend ❑ Perforate I] ' Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Coiled Tubing CO/Pert, N2 ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development 0 Stratigraphic ❑ Service ❑ 215-077 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 t 50-133-20651-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 701 ' Will planned perforations require a spacing exception? Yes ❑ No El Grassim Oskolkoff (GO) #8 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL 389737 Ninilchik Field - Beluga/Tyonek Gas Pool Y 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): 10,200' 5,577' 10,055' 5,4331 -2,800psi 10,055' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 3,492' 10-3/4" 3,492' 1,844' 5,210 psi 2,470 psi Intermediate 1,779' 7-5/8" 1,779 1,450' 6,890 psi 4,790 psi Intermediate 5,687' 7-58" 7,466' 21943' 9,470 psi 5,340P si Production Liner 2,959' 4-1/2" 10,198' 5,575' 8,430 psi 7,500P si Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 4-1/2" 12.6# / L-80 1 7,287' Packers and SSSV Type: Baker ZXP Liner Top Packer Packers and SSSV MD (ft) and TVD (ft): 7,239' MD / 2,792' TVD WL SCSSV 269' MD / 269' TVD 12. Attachments: Proposal Summary .i Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Strati ra hic g p ❑ Development Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: March 16th, 2020 Commencing Operations: OIL E]WINJ F]WDSPL ❑ Suspended El GAS Q WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Taylor Wellman 777-8449 Contact Name: Christina Twogood Authorized Title: Operations Manager Contact Email: CtwO OOd hJ1cor .COM Contact Phone: 777-8443 Authorized Signature: Date: COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 -a Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: RBDMS b54MAR 0 5 2020 Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes ❑ No Subsequent Form Required: / o " 1 y o t -r APPROVED BY/� ll. 3 Approved by: COMMISSIONER THE COMMISSION Date: p(lf 3;-� -�V Submit Form and e /2 1 Form 1 ws7 vApprovetl applicati s�yi f� rr�n�Ag the date of approval. Attachments in Du licate 1[ 1-1'l� IV Li � Z tR g1'z)za .�i�/3�n�n H f ilwm Alaska, Lb Well Prognosis Well: GO -8 Date:02/14/2020 Well Name: GO -8 API Number: 50-133-20493-00-00 Current Status: Shut -In Gas Well Leg: N/A Estimated Start Date: 03/16/2020 Rig: E -Line Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-077 First Call Engineer: Christina Twogood (907) 777-8443 (0) (907) 378-7323 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) AFE Number: Max. Expected BHP: Max. Potential Surface Pressure: Brief Well Summary — 1,926 psi @ 4,281' TVD - 1,498 psi (Based on 0.45 psi/ft gradient) (Based on expected BHP and gas gradient to surface (0.10 psi/ft)) GO -8 was drilled and completed in September 2015. The Tyonek T -17A sand was initially perforated. In February 2016 a capillary string was installed. In February 2017 the Tyonek T -17A sand was re -perforated. In March 2017 the Tyonek T -13B and T-12 sands were perforated. In May 2017 a CIBP was set over the T -13B and T -17A sands. In September 2018 the CIBP was pulled. • The purpose of this work/sundry is to perforate the Tyonek T9, T7 and T6A and Beluga BEL 135 and BEL 120 sands. Notes Regarding Wellbore Condition • Coil Clean Out to 9,852' on 9/21/2018 • Coil Tag at 10,060' PBTD (coiled tubing measurement) on 9/21/2018 • Last drift with 1.85" GR to 2,500' (carried to 9,838' with 65 gal of pumped fluid) on 10/24/2018 Safety Concern Discuss Nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. Considertank placement based on wind direction and current weather forecast (venting Nitrogen during this job). 0 Ensure all crews are aware of stop job authority. n Weary Alaska, M E -line Procedure Well Prognosis Well: GO -8 Date:02/14/2020 1. MIRU E -Line Unit and pressure control equipment. PT lubricator to 250 psi Low/ 3,000 psi High. 2. Perform dummy drift run(s) prior to RIH with GPT and perf guns. a. If needed, discuss using Coiled Tubing to Clean Out well with the Operations Engineer. 3. RIH with GPTtool and find fluid level. If fluid is over the depth of the new perfs, discuss using Nitrogen with the Operations Engineer. 4. If needed, RU Nitrogen Truck, pressure up on well and push water back into formation. Use GPTtool to confirm water level is below interval to perf. 5. RU perf guns. 6. RIH and perforate the below intervals: Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Beluga BEL 120 ±7,943' ±7,980' ±3,342' ±3,377' 37 Beluga BEL 135 +8,168' +8,197' +3,559' +3,588' 29 Tyonek T6A ±8,593' ±8,696' ±3,980' ±4,083' 103 Tyonek T7 ±8,736' ±8,766' ±4,122' ±4,152' 30 Tyonek T9 ±8,812' ±8,896' ±4,198' ±4,281' 84 a. Pressure up well to 1,500 psi before perforating. b. Proposed perfs also shown on the proposed schematic in red font. c. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. d. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. e. Use Gamma/CCL to correlate. f. Spacing allowance is based on Conservation Order 7010. Proposed perforation intervals are in the Beluga/Tyonek Gas Pool. g. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. h. Record 5, 10 and 15 minute pressures after firing guns. Coiled Tubing Clean Out Procedure (Contingency) 1. MIRU Coiled Tubing Unit and BOP equipment. 2. RU Coiled Tubing Stripper and Lubricator. 3. PT BOPE, Stripper and Lubricator to 250 psi Low / 4,000 psi High. 4. PU and RIH with 1.75" coil with nozzle BHA. 5. Clean out to +9,100' using N2, brine and/or gel sweeps as needed. 6. Blow well dry with N2 and POOH with coiled tubing. 7. Stand back coiled tubing and rig up E -Line to perform dummy drift run(s). a. If successful, RDMO coiled tubing and proceed with perforating on E -Line. b. If unsuccessful, discuss proceeding with perforating on coiled tubing with the Operations Engineer. Well Prognosis Well: GO -8 Hilcnru Alaska, LL' Date: 02/14/2020 Coiled Tubing Perforating Procedure (Contingency) 1. RU E -Line Data Acquisition Unit. 2. RU perf guns. 3. RIH and perforate the following intervals: a. Pressure up well to 1,500 psi before perforating. b. Proposed perfs also shown on the proposed schematic in red font. c. Final perfs tie-in sheet will be provided in the field for exact pert intervals. d. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer and the Geologist. e. Use Gamma/CCL to correlate. f. Spacing allowance is based on Conservation Order 701C. Proposed perforation intervals are in the Beluga/Tyonek Gas Pool. g. Record tubing pressure before and after each perforating run. h. Record 5, 10 and 15 minute pressures after firing guns. 4. POOH. 5. RD E -Line Unit and Coiled Tubing Unit. 5. Turn well over to production. E -Line Procedure (Contingency) 1. if any zone produces sand and/or water and needs to be isolated: 2. MIRU E -Line and pressure control equipment. PT lubricator to 250 psi Low/ 3,000 psi High. 3. RIH and set 4-1/2" Casing Patch or set 4-1/2" CIBP above the zone and dump 25' of cement on top of the plug. Attachments 1. Current Well Schematic 2. Proposed Well Schematic 3. Coiled Tubing BOPE Schematic 4. Wellhead Diagram S. Standard Well Procedure — Nitrogen Operations 6. CT Flow Schematic (Forward) 1 K Hil-.F Abrs ., 1,J,C RKB 1S' 13 , TO -2,000 ' SCHEMATIC Ninilchik Unit Well: GrassimOsl<olkoff#8 PTD: 215-077 API: 50-133-20651-00-00 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16" Conductor 84 X-56 Weld 15.010" Surf 120' 10-3/4" Surf. Csg 45.5 L-80 BTC 9.950" Surf 3,492' 7-5/8" Int. Csg 29.7 L-80 BTC 6.875" Surf 1,779' 7-5/8" Int. Csg 29.7 P-110 BTC 6.875" 1,779' 7,466' 4-1/2" Prod Liner 12.6 L-80 D HT/C 3.958" 7,239' 10,198' TUBING DETAIL 4-1/2" Tubing 12.6 L-80 BTC -mod 3.958" Surf 7,287 IPXA/FI RV rWTAII No. Depth ID OD Item 1 18' 4.00" - Tubing Hanger, 4-1/2" BT Mod 2 269' 3.813" 5.50" 5-1/2" Hydraulic Nipple for WL Retrievable SCSSV 3 335' 3.85" 5.75" 4-1/2" Chemical Injection Mandrel 4 7,239' 3.958" 6.875" Baker ZXP Liner Top Packer/HRD-E Profile (10' tie -back extension) 5 7,272' 3.833" 4.74" Seal Bore Extension "GBH -22" Locating seal assembly 6 10,055' 3.958" CIBP Updated by DMA 10-16-18 5 4 7-$/8" RA Mkr Jt ' ` PERFORATION DETAIL 8,211 Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) ft Size Date '{ T12 9,166' 9,220' 4,550' 4,604' S4 2-7/8" 03/02/2017 9,220' 9,260' 4,604' 4,643' 40 2-7/8" 03/01/2017 RA Mkr Jt w T13B 9,412' 9,424' 4,794' 4,806' 12 2-7/8" 03/01/2017 8,502' w/ 9,800' 9,877' 5,180' 5,256' 77 2-7/8" 02/03/2017 T17A 9,828' 9,851' 5,208' 5,230' 23 2-7/8" 08/28/2015 9,837' 9,877' 5,216' 5,256' 23 2-7/8" 02/02/2017 RA Mkr Jt 8,790' T12 13B RA RA Mkr It T17A 9,905' " ,4 .1 6 6-3/4" hole Shoe @ 10,198' 4-1/2"` PBTD =10,055' MD / 5,433' TVD TD =10,200' MD/ 5,577' TVD Max Deviation: 79 deg @ 2,421' Max Dogleg: 6.2 deg/100 @ 1,496' Updated by DMA 10-16-18 H Hileor„ Alneka, 1AX 16"94. ' 6"9i.. 2 3 I 5 4 7-5/8" RKB 18' RA Mkr Jt Size '- 8,211' Grade ;.. ID Top Btm 16" Conductor 84 RA Mkr Jtk Weld 15.010" 8,502' 12U •,`' Surf. Csg 45.5 yl , RA Mkr Jt 9.950" Surf 3,492' 8,790' ; Int. Csg RA Mkr Jt 9,905' 6 4-1/2" 1 TOC @ -2,000' BEL 120 BEL 135 T6A T7 T9 T12 T13B T17A PROPOSED SCHEMATIC Ninilchik Unit Well: Grassim Oskolkoff #8 PTD: 215-077 API: 50-133-20651-00-00 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16" Conductor 84 X-56 Weld 15.010" Surf 12U 10-3/4" Surf. Csg 45.5 L-80 BTC 9.950" Surf 3,492' 7-5/8" Int. Csg 29.7 L-80 BTC 6.875" Surf 1,779' 7-5/8" Int. Csg 29.7 P-110 BTC 6.875" 1,779' 7,466' 4-1/2" Prod Liner 12.6 L-80 DHT/C 3.958" 7,239' 10,198' TUBING DETAIL 4-1/2" Tubing 12.6 1 L-80 1 BTC -mod 3.958" 1 Surf 1 7,287' IPM/Fol RV r1FTAU No. Depth ID OD Item 1 18'4.00" Date - Tubing Hanger, 4-1/2" BT Mod 2 269' 3.813" 5.50" 5-1/2" Hydraulic Nipple for WL Retrievable SCSSV 3 335' 3.85" 5.75" 4-1/2" Chemical Injection Mandrel 4 7,239' 3.958" 6.875" Ba ker ZXP Liner Top Packer/ HRD-E Profile (10' tie -back. extension) 5 7,272' 3.833" 4,74" Seal Bore Extension "GBH -22" Locating seal assembly (16.37') 6 10,055' T7 3.958" CIBP PERFORATRnN nFTAU Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) ft Size Date BEL 120 +7,943' +7,980' -+-S, -197' +3,342' +3,377' 37 TBD Proposed BEL 135 +8,168' +3,559' +3,588' 29 TBD Proposed TEA +8,593' +8,696' +3,980' +4,083' 103 TED Proposed T7 +8,736' +8,766' +4,122' +4,152' 30 TBD Proposed T9 +8,812' +8,896' +4,198' +4,281' 84 TBD Proposed T12 9,166' 9,220' 4,550' 4,604' 54 2-7/8" 03/02/2017 9,220' 9,260' 4,604' 4,643' 40 2-7/8" 03/01/2017 T13B 9,412' 9,424' 4,794' 4,806' 12 2-7/8" 03/01/2017 9,800' 9,877' 5,180' 5,256' 77 2-7/8" 02/03/2017 T17A 1 9,828' 9,851' 5,208' 5,230' 23 2-7/8" 08/28/2015 9,837 9,877' 5,216' 1 5,256' 1 23 2-7/8" 02/02/2017 w; 6-3/4" hole Shoe @ 10,198' PBTD =10,055' M D / 5,433' TVD TD = 10,200' MD / 5,577' TVD Max Deviation: 79 deg @ 2,421' Max Dogleg: 6.2 deg/100 @ 1,496' Updated by CMT 2-25-2020 Kill P, WH P. 2" 1502 x2-1) Flanged V (Manual 2-1/16 1 OK 10K Rargc (Mans Coiled Tubing HR580 Injector Head 8 Gooseneck Weight = 12,850 lbs 4-1116" 10K Convenbonai Stripper SK C062 Lubricator 6K C062 x 4.1116" 10K Flange 4-1116"' 10K Combi BOP Tcp Set. &ealsrear SecmdSet R e/Sir 4-1116" 1 O Flow cross ManValve 1. 2' 1502 x 2-1116'10K Merge Mena) 2x2 Vele 2: 21116" tOK x2-1/18" 10K Range Merin 2x2 Valve 3:2-1118" 10K x2-1/16" IOK Mange ManVale 4'. 2' 1502 x 21/18- 109 Range 4-1116" 1 O x Wellhead Adapter Flange Wellhead Ninilchik Unit Go #8 16 X 10% X 75/8 X 41/2 BHTA, Otis, 4 1/16 5M FE X 6.5" Otis Quick Union Valve, Swab, WKM-M, 41/16 5M FE, HWO, DD trim Valve, Upper Master WKM-M, 41/16 5M FE, HWO, DD trim Valve, Master, WKM-M, 41/16 SM FE, HWO, DD trim Multibowl Wellhead, SMB -22, 115M X16%3M, w/ 4- 2 1/16 5M SSO Starting head, Seaboard, 16 Y. 3M X16"SOW, w/ 2- 2 1/16 5M EFO GO# 8ik Unit O#8 08/11/2015 Tubing hanger, SME -CL, 11 X 4 EUE lift and4 % EUE susp, w/ 4" Type H BPV profile, 2-3/8 CCL, . ,m og100" < JGd` 0<dJKsc Ja\je SFE NJJ e .`ood1� 1�a�c6 Jy\J el ` 31�ay� oQ litULIVLU STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION FEB 2 6 2018 • REPORT OF SUNDRY WELL OPERATIONS AOGCC 1.Operations Abandon U Plug Perforations U Fracture Stimulate Li Pull Tubing U Operations shutdown U Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ srforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: Set RBP ❑✓ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development Q Exploratory ❑ 215-077 3.Address: 3800 Centerpoint Dr,Suite 1400 Anchorage, Stratigraphic❑ Service ❑ 6.API Number: AK 99503 50-13-20651-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 389737 Grassim Oskolkoff(GO)#8 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Ninilchik Field-Beluga/Tyonek Gas Pool 11.Present Well Condition Summary: Total Depth measured 10,200 feet Plugs measured 9,310&10,055 feet true vertical 5,577 feet Junk measured N/A feet Effective Depth measured 9,310 feet Packer measured 7,239 feet true vertical 4,693 feet true vertical 2,792 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 3,492 10-3/4" 3,492' 1,844' 5,210 psi 2,470 psi Intermediate 1,779' 7-5/8" 1,779' 1,450' 6,890 psi 4,790 psi 1 Intermediate 5,687' 7-5/8" 7,466' 2,943' 9,470 psi 5,340 psi Production Liner 2,959' 4-1/2" 10,198' 5,575' 8,430 psi 7,500 psi Perforation depth Measured depth See Attached Schematic /`j�� t 4" Y ''' True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80 _ 7,287'MD 2,821'TVD Baker ZXP Packers and SSSV(type,measured and true vertical depth) Liner Top Pkr 7,239'MD 2,792'TVD 12.Stimulation or cement squeeze summary: N/A 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: 0 1334 1 62 185 Subsequent to operation: 0 1012 2 0 108 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations C1 Exploratory Development❑✓ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas Q WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ p 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: N/A Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Contact Email: tkramer@hilcorp.com Authorized Signature: / /14#/fl‘ Date: Z-/Z4 I ( g Contact Phone: 777-8420 Form 10-404 Revised 4/2017 /� ,� ` p Submit Original Only l 14f� REDMS 1. t�., C1t1 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date GO-08 E-Line 50-133-20651-00 215-077 5/13/17 5/27/17 Daily 001, ibfj ,,tr7V2E, 05/13/2017-Saturday PTW and JSA. Rig up lubricator. PT lub to 250 psi low and 3,000 psi high. Had 130 psi on well. NOTE: 112 zone is 9,166' to 9,260'. T13B zone is 9,412'to 9,424'. RIH w/3.85" GR and tag WL retrievable SSSV @ 268' KB. Had 2 roller boggies on tool string with wt bars had tools weighing about 320 lbs.Tight spot @ 151' KB. Work through no problems. Shut well in with 130 psi on tubing. RIH w/4-1/2" slim hole GS pulling tool with 68" prong. Latch and pull WL retrievable SSSV from well at 268'. Halliburton is going to re-dress SSSV. MU CCL/GR memory tool, added another weight and roller boggie and start timer at 1033 hrs.Tools was stop and go every once in a while from 2,200' to 5,000' due to angle. Ran ok after that but tools sat down at 9,841' KB (CIBP set at 10,055'on schematic). Called town and discussed. Flagged line. Started logging from 9,764'to 8,644'WLM. Stop for 5 min and POOH with no problems. Correlate log, put Halliburton EVO w/DPU and WRP on line . Timer set for 1633 hrs to start set the plug . Did not have any trouble going in hole. Had to add 29'feet to Halliburton slick line depth for correlation.Set plug at 9,310'. We waited 30 mins past timer because it was hard to see set in this deviated hole. Picked up and sat back down on plug lightly twice. It looked good. POOH. Had 1,023.1 psi when plug set. Setting tool looked good. Rig down lubricator and turn well back over to field. 05/24/2017 Wednesday PTW and JSA. Rig up lubricator. PT lub to 250 psi low and 3,000 psi high. TP-820 psi. RIH w/ Press/Temp gauges down to 9,150' KB. Waited 30 min and pulled out of hole.TP-816 psi. RIH w/equalizing prong and 3.25" centralizer and roller bogies to 2,530'.Took several tries to get past this depth.Also trouble at 5,520' but got by after several attempts. Found plug at 9,312' WLM and tried numerous times to equalize plug. Had 816 psi on tubing (Plug was set with 1,023.1 psi on tubing).Saw no pressure change. POOH. RIH w/3.80" barbell. Unable to make it past 2,529'. POOH. RIH w/3.65" barbell. S/D @ 2,537'. POOH. RIH w/3.65" Cent and equalizing prong. Unable to pass 2,537'. RIH w/2.50" Cent and equalizing prong. Run past 2,537'to 9,312' WLM. Equalize plug. POOH. Did not lose or gain any psi. TP-808 psi. RIH w/dogless pulling tool to see if plug was equalized. Pin was sheared which should be if plug is equalized. RIH w/ Evo pulling tool and attempted to pull plug. Latched on plug after numerous tries but could not pull. Sheared pin and POOH.Tool had gritty sandy mud on and around dogs. Rig down lubricator. Will be back in AM with bailers.TP-809.3 psi. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date GO-08 E-Line 50-133-20651-00 215-077 5/13/17 5/27/17 Darcy Operations :. °' . 05/25/2017-Thursday PTW and JSA. Rig up lubricator. cut 100' of line off and re-head line. PT lub to 250 psi low and 3,000 psi high. TP- 819.3 psi. RIH w/2" x 10' Pump bailer. Tag plug @ 9,312'. Work pump bailer and POOH. 2.5' of returns 2" bailer. Gray colored fine sand and mud mixed. No problem going in hole. RIH w/2"x 10' pump bailer.Sat down @ 3,778'. Work tools. Unable to pass. POOH. Bailer empty. Ran same set up as first run but would not go thru.Add 5' rollerstem and knuckle. RIH w/2" x 10' pump bailer. Bail @ 9,312'. POOH 2' of the same sand mud mix. RIH w/2"x 10' pump bailer. S/D @ 9,312'. Work tools bail 3" of sand,fluid. Possible metal to metal contact. RIH w/3" x 10' drive down bailer S/D @ 5,531' Unable to pass.Tools had grease mixed with sand on tools. Dump 5 gals methanol. RIH w/2.5" X 10' drive down bailer S/D @ 2,550'. Worked tools but would not go. POOH. RIH w/2.0" x 10' drive down bailer S/D 2,550'. Worked tools but would not go. POOH. Pumped 15 gals diesel in well. RIH w/2.0" x 10' drive down bailer S/D 2,550'. RIH w/2.50" Cent and 1.75" 3' bailer S/D @ 9,312'. Drive bailer. POOH. Sample catcher full of sandy mud. RIH w/2" x 10' pump bailer. S/D @ 9,312' Work tools bail 3" of sand,fluid. Rig down lubricator. Be back in the morning with some different tools.TP-786 psi. 05/26/2017 Friday PTW and JSA. Rig up lubricator. Cut 100' of line off and re-head line. PT lub to 250 psi low and 3,000 psi high. TP- 790.4 psi. Pressure tested with diesel and let fall down hole. RIH with 2.5" x 10' drive down bailer with roller boogies with just one knuckle joint at rope socket (stiff).Tried to get E-line perf job (2-7/8" x 20' perf gun).Tools stopped at 2,550'. Worked tools but could not get thru. POOH. Add Knuckles. RIH w. 2.25" x 10' DD bailer. S/D 9,312'. Bail to 9,313' POOH. Bailer full of soupy sand. RIH w/2" x 5' DD bailer. Made it to 5,538' and sat down. POOH.Tubing pressure 760 psi. Hook up jumper to pressure up lub to 740 (all we could get) before opening swab on runs from here down. RIH w/ 1.75" x 3' DD bailer w/2.25" Centralizer. Tag @ 9,312' . Work tools and POOH. Bailer full of hard sand. Add 6' of roller stem. RIH w/2.25" x 10' DD Bailer . S/D @ 2,530' work tools could not run any deeper. POOH. RIH w/ 2.25" x 5' DD Bailer. S/D @ 5,783'. Work tools but could not run deeper. POOH. RIH w/2"x 5' DD bailer.Tag @ 9,312'. Bail. POOH 2' of sand. RIH w/2.5" x 5' DD Bailer. S/D @ 3,767'. Could not run below this depth. POOH. RIH w/2." x 5' DD Bailer and set down at 5,570'. Worked tools but wouldn't go down. POOH. Rig down lubricator. Will flow well tonight and come back in morning to see if it did any good. 05/27/2017-Saturday Shut in well. Flowed well over night at 1 million scf with 108.5 psi. PTW and JSA. Rig up lubricator. Cut 100' of line off and re-head line. PT lub to 250 psi low and 3,000 psi high. Pressure up lub to 740 psi w/field gas. RIH with 2.5" x 10' drive down bailer with roller boogies to 9,300' (had approx. 10' of sand come in after flowing well). Worked bailer and POOH. Had about 4' of moist sand in bailer.TP-752 psi. Pressure up lub with gas. RIH w/2.5" x 10' drive down bailer and set down at 5,538'.Tried numerous times to get thru but could not. POOH. Bailer empty. Pressure up lub with gas. RIH w/2" x 10' Drive down bailer and set down at 2,550'.Tried numerous times to get thru but could not. POOH. Bailer empty. Called town and will set SSSV. RIH with brush and brush nipple at 268'. Set SSSV valve in nipple at 268' and tested good. Rig down lubricator and turn well over to field. Ninilchik Unit Well: Grassim Oskolkoff#8 SCHEMATIC PTD: 215-077 API: 50-133-20651-00-00 Hilcorp Alaska,LLC RKB 18' CASING DETAIL 16"4 } Is Size Type Wt Grade Conn. ID Top Btm 4 IIII 16" Conductor 84 X-56 Weld 15.010" Surf 120' r 2 i III t 10-3/4" Surf.Csg 45.5 L-80 BTC 9.950" Surf 3,492' 'r*' , 3 7-5/8" Int.Csg 29.7 L-80 BTC 6.875 Surf 1,779' s i. 10-3/4 <� ` ' 7-5/8" Int.Csg 29.7 P-110 BTC 6.875" 1,779' 7,466' I TOC @DWC/C- 2,000' 4-1/2" Prod Liner 12.6 L-80 HT 3.958" 7,239' 10,198' TUBING DETAIL 4-1/2" Tubing 12.6 L-80 BTC-mod 3.958" Surf 7,287' ir 4 IFId '' JEWELRY DETAIL i. No. Depth ID OD Item 1 18' 4.00" - Tubing Hanger,4-1/2"BT Mod 2 269' 3.813" 5.50" 5-1/2"Hydraulic Nipple for WL Retrievable SCSSV P' l 3 335' 3.85" 5.75" 4-1/2"Chemical Injection Mandrel Baker ZXP Liner Top Packer/HRD-E Profile(10'tie-back 4 7,239' 3.958" 6.875" extension) #, S 7,272' 3.833" 4.74" Seal Bore Extension"GBH-22"Locating seal assembly t" �_ ) (16.37') P 11 *9,310' 4.5" Halliburton Evo-Trieve RBP 5/14/17-*Temporary PBTD 5 7 10,055' 3.958" CIBP 4 ` a 7-5/8" I •o :'.A RA Mkr Jt .'rte,; PERFORATION DETAIL 8,211' ''' 4 Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) ft Size Date -11 `T12 9.166' 9,220' 4,550' 4,604' 54 2-7/8" 03/02/2017 . 9,220' 9,260' 4,604' 4,643' 40 2-7/8" 03/01/2017 RA Mkr Jt 4 E+; T13B 9,412' 9,424' 4,794' 4,806' 12 2-7/8" 03/01/2017 8,502' ° 441, + 9,800' 9,877' 5,180' 5,256' 77 2-7/8" 02/03/2017 . 0i, T17A 9,828' 9,851' 5,208' 5,230' 23 2-7/8" 08/28/2015 * }" +�}�`µ 9,837' 9,877' 5,216' 5,256' 23 2-7/8" 02/02/2017 RA Mkr Jt .‘,..,0,, ,,i 1._410 8,790' . Grp ,a { l 6 " % i. t T12 T13B T17A RA RA Mkr Jt 9,905 if 94 '4. i. 7 .....;4 IV I'',. , 6-3/4" hole "' 1'' 'jt' Shoe @ 10,198' 4-1/2" t;. , . .a" " *PBTD=9,310'MD/4,693'ND TD=10,200'MD/5,577'ND Max Deviation:79 deg @ 2,421' Max Dogleg:6.2 deg/100 @ 1,496' Updated by DMA 02-09-18 • • 215077 Seth Nolan Hilcorp Alaska, LLC p GeoTechh 3800 Centerpoint Drive 2 8 3 6 7 RECEIVED Anchorage, ag , AK 83083 Tele:Hilenrp A10)440.11: Fax: 907 777-8510 JUL 0 7 2017 E-mail: snolan@hilcorp.com DATE 07/07/2017 p//"�� //^^++//'�'�� DATA LOcc", I►'1iJGVV 7i1BE Drt? M.K.BENDER To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL GO 8 SCANNED AUG 0 8 2017 Prints: GR/CCL Correlation Log CD1: GO-8CoRRELATIoN_13MAY17.las 6120/2017 2:96 PM LAS File 1,399 KB To GO-8CORRELAATION_13MAY17.pdf 6/20/2017 2:46 PM PDF Document 1,139 KB GO-8 CORRELATION_13MAY17 img.tiff 6/20/2017 2:96 PM TIFF File 1,672 KB Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: , Date: • ir1A t - Regg, James B (DOA) From: Regg,James B (DOA) Sent: Tuesday, May 23, 2017 12:09 PM 2' y I 2;51(7 To: Ted Kramer Cc: Schwartz, Guy L (DOA) Subject: RE:Waiver Request for GO # 8 From 20 AAC 25.265 (d) (2)(F), PTD 215-077 Request denied unless the well will pass a no flow test. Sent from my Samsung Galaxy smartphone. SCANNED ..+�_�t 1 4n17, Original message From: Ted Kramer<tkramer@hilcorp.com> Date: 05/23/2017 7:47 AM (GMT-09:00) To: "Regg,James B (DOA)" <jim.regg@alaska.gov> Cc:Taylor Nasse<tnasse@hilcorp.com>, Donna Ambruz<dambruz@hilcorp.com> Subject: Waiver Request for GO#8 From 20 AAC 25.265 (d) (2)(F), PTD 215-077 Jim, Hilcorp requests a waiver from 20 AAC 25.265 (d) (2)(F)—installing a SSSV for the GO#8 Well for the following reasons: GO#8 Meets all conditions of the regulation except item (F)—660 feet of the coast line measured at mean high water level from which it falls only a few feet inside of the 660 feet mark (See attached map). GO#8 is a gas well and makes no appreciable water. Therefore,the risk of any fluid from the well reaching the water is infinitesimally small at worst (for water) and non-existent (for Gas). Hilcorp believes that the intent of this regulation was to prevent oil from an oil well from leaking into the Cook Inlet and a differentiation for a gas well was never fully contemplated. Therefore, Hilcorp respectfully asks for a waiver under 20 AAC 25.265 (o) (2). Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. O 907-777-8420 C 985-867-0665 1 • From: Michael Anderson Sent: Monday, May 22, 2017 1:49 PM To:Taylor Nasse<tnasse@hilcorp.com> Cc:Ted Kramer<tkramer@hilcorp.com> Subject: RE: Ninilchik GO-8 map [Work Item: 15217] It appears that you are within 660 feet of the MHW mark. I don't see any houses for at least 2400'from the SHL of GO-8 and the Sterling Hwy is about 2350' away from the SHL. Let me know if you need anything else. Thanks, Michael From:Taylor Nasse Sent: Monday, May 22, 2017 1:07 PM To: Michael Anderson <mianderson@hilcorp.com> Cc:Ted Kramer<tkramer@hilcorp.com> Subject: Ninilchik GO-8 map [Work Item: 15217] Hi Michael- When you have a moment could you put together a quick sketch of the GO-8 well that shows it's distance relative to the MHWL, houses, and the Sterling Highway? Looking to see if we are outside of the 660'setback requirement for AOGCC, and if we aren't then what the distance is to each of these. If you have any questions, please feel free to contact me. Thanks for your help! Taylor W. Nasse, PE Operations Engineer Kenai Asset Team Hilcorp Alaska, LLC (907)777-8354 office (907) 903-0341 cell 2 151'2540'W 151° 151'19'20"W 151`29'10"W ''° Legend' Le d Ninilchik Unit , 1 er v ° Overview Surface Well Location Area 1 of Detail k.. " - 4. LR' House of Interest 1 11 + N Fi A Existing Gas Pipelines MHW(NOAA-CUSP) �! KPB Parcels $ ';.• , 7" M.1 Cook Inlet Oil and Gas Units , /1 1 „.'` • - f GO-8 660 ft buffer radius It i '''' .-''..'''' 4ii 'tt. p ,S, '4 At\1/4 ,, ; • �yentiii‘rts` k Er . . : o : 01lokt1 •Vit' k c f �. �i v MKENAI i _ *, l ..v PENINSULA f' ,I jJf/ �„ ;s.`' !'°., •aOROUG44 V. may. :. ;. ` / . r I UNIT 1NOW `+ .''`. ti c F i i: 7 t T $ {�� -1 �\ 1 E 07 .....4.,.., . , ....,....,_.,..,... , 4 -: it'!" 3,.*N.4,1 t.It.%r '. t:. lititii•‘ ;f, a ,- ' ,r, , %:7 • -1st -.., ,,:-.../1„N.,zr,s- -16 - ; 15 '‘'t bi, 1/41,40 s ' ' C b , • OSKOLKOFF ` ± 4 r,A 1 ,fq �' v. MARION ET I" iy U. �'l ' '�t y 114, 33}} t.$ �Y " «' • y . °t. 1 "C t M t � l Y N Ninilchik Unit GRASSIM OSKOLKOFF Pad 1 inch=200 feet A 4 1 (GO Pad) Feet Map oa1e.5/22/2017 Well 0 120 240 360 480 STATE OF ALASKA ALL OIL AND GAS CONSERVATION COMOISION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon U Plug Perforations U Fracture Stimulate Lf Pull Tubing Li Operations shutdown U Performed: Suspend ❑ Perforate El Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ srforate New Pool ❑ Repair Well ❑ Re-enter Susp Well Cl Other: Re-perforate ❑., 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory Li 215-077 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic El Service ❑ 6.API Number: Anchorage,AK 99503 50-13-20651-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 389737 Grassim Oskolkoff(GO)#8 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Ninilchik Field-Beluga/Tyonek Gas Pool 11.Present Well Condition Summary: Total Depth measured 10,200 feet Plugs measured 10,055 RECEIVED true vertical 5,577 feet Junk measured N/A feet s G MAR 2 8 2017 Effective Depth measured 10,055 feet Packer measured 7,239 feet true vertical 5,433 feet true vertical 2,792 feet 4,1 AOGCC Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 3,492 10-3/4" 3,492' 1,844' 5,210 psi 2,470 psi Intermediate 1,779' 7-5/8" 1,779' 1,450' 6,890 psi 4,790 psi Intermediate 5,687' 7-5/8" 7,466' 2,943' 9,470 psi 5,340 psi Production Liner 2,959' 4-1/2" 10,198' 5,575' 8,430 psi 7,500 psi Perforation depth Measured depth See Attached SchematicP p i;'7 A SCANNED , ,5 1 2�.., , True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80 7,287'MD 2,821'TVD Baker ZXP Packers and SSSV(type,measured and true vertical depth) Liner Top Pkr 7,239'MD 2,792'TVD 12.Stimulation or cement squeeze summary: N/A 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: 0 74 0 60 101 Subsequent to operation: 0 1791 2 68 333 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations ❑ Exploratory ID Development Q Service ❑ Stratigraphic [] Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas Q WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ Li 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: 317-041 ,"0/1, Contact Ted Kramer-777-8420 Email tkramer anhilcorp.com Printed Name Chad Helgeson Title Operations Manager 004/0, Signature C" 7 Phone 907-777-8405 Date yz...5117 Form 10-404 Revised 5/2015 -�� Submit Original Only A*7 +-( (4icaS 1i,AFR - 32017 • ' Hilcorp Alaska, LLC .w Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date GO-08 E-Line 50-133-20651-00 215-077 2/2/17 3/5/17 Daily Operations: 02/02/2017 -Thursday PTW and JSA. Shut well in. Spot equipment and rig up lubricator. Pressure test to 250 psi low and 2,000 psi high. RIH w/roller boogies, 2-7/8" x 20' Connex HC, 6 spf, 60 deg phase perf gun, tie into Halliburton ROP-EWR-ALD-CNT log dated 18-Aug-15 and tag at 10,040'. Run correlation log and send to town. Get ok to perf from 9,857'to 9,877'. Spotted gun and fired with 367 psi on tubing. Pressure jumped to 368 psi and back to 367 psi. After 5 min tubing pressure was 364.44 psi. POOH. All shots fired and gun was wet.TP -361 psi. RIH w/roller boogies, 2-7/8" x 20' Connex HC, 6 spf, 60 deg phase perf gun, tie into Halliburton ROP-EWR-ALD-CNT log dated 18-Aug-15. Started having trouble going in hole at 5,000'. Worked tools down to 5,850'. Finally pumped approx. 50 gals diesel. After diesel got to tools they went down hole good. Spot gun from 9,837' to 9,857', sent log to town. Fired gun with 353.4 psi. Saw a little bump when gun went off but back 353.0 psi. After 5 min pressure was 352.9 psi. POOH. All shots fired and gun was wet. NOTE:. We lost bottom roller boggie in hole. Rig down lubricator and SDFN. Going to check and service roller boogie, if need be. 02/03/2017 - Friday PTW and JSA. PT to 250 psi low and 2000 psi high.TP- 329 psi. RIH w/1-9/16" O/S with 3.58" guide and tie into Pollard correlation log#1. Pumped 15 gals diesel at 5,000' and went down and tagged at 10,040. Hit down a couple times and spang tools free. POOH and had roller boogie fish in overshot. Shot blast had stripped eline threads out of bull plug. RIH w/roller boogies, 2-7/8"x20' Connex HC, 6 spf, 60 deg phase perf gun, tie into Halliburton ROP-EWR-ALD-CNT log dated 18-Aug-15. Started having trouble going in hole at 5000'. Pumped approx. 20 gals diesel. After diesel got to tools they went down hole good. run correlation log. Spot gun from 9,817' to 9,837'. Sent log to town. Fired gun with 326.7 psi. Saw a little bump when gun went off but back to 326 psi. After 5 mi pressure was at 324.2 psi. POOH. All shots fired and gun was wet. Re-build roller boogie. RIH w/roller boogies, 2-7/8"x17' Connex HC, 6 spf, 60 deg phase perf gun, tie into Halliburton ROP-EWR-ALD-CNT log dated 18-Aug-15. Run correlation log and send to town. Spot shot from 9,800' to 9,817'. Fired shot with 321.4 psi. Saw little bump when fired and went back to 321.4 psi. After 5 min pressure was 321.5 psi. POOH. All shots fired. Gun was wet. Pumped approx. 15 gal diesel. Rig down lubricator and turn well over to field. 03/01/2017 -Wednesday Sign in. PTW and JSA. Spot equipment and rig up lubricator. PT to 250 low and 2,000 high. RIH w/2-7/8" x 12' Razor HC, 6 spf, 60 deg phase and tie into GO-08 ROP-DGR-EWR-ALD-CNT dated 18 Aug 2015. Run correlation log and send to town. Get ok to perf from 9,412' to 9,424'. Spot and fired gun with 700.4 psi on tubing. Pressure went to 702 and back to 700.8 psi. After 5 min TP was 700.5 psi. POOH. Gun was wet. RIH w/2-7/8" x 20' Razor HC, 6 spf, 60 deg phase and tie into GO-08 ROP-DGR-EWR-ALD-CNT dated 18 Aug 2015. Run correlation log and send to town. Get ok to perf from 9,240' to 9,260'. Spot and fired gun with 681 psi on tubing. Pressure started building and after 5 min TP was 697 psi psi. POOH. Gun was wet. RIH w/2-7/8" x 20' Razor HC, 6 spf, 60 deg phase and tie into GO-08 ROP-DGR-EWR-ALD- CNT dated 18 Aug 2015. Run correlation log and send to town. Get ok to perf from 9,220'to 9,240'. Spot and fired gun with 772.8 psi on tubing. Pressure started building and after 5 min TP was 778 psi psi. POOH. Rig down lubricator and secure well. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date GO-08 E-Line 50-133-20651-00 215-077 2/2/17 3/5/17 Daily Operations: 03/02/2017-Thursday Sign in. PTW and JSA. Spot equipment and rig up lubricator. PT to 250 low and 2,000 high. RIH w/2-7/8" x 20' Razor HC, 6 spf, 60 deg phase and tie into GO-08 ROP-DGR-EWR-ALD-CNT dated 18 Aug 2015. Run correlation log and send to town. Get ok to perf from 9,200' to 9,220'. Spot and fired gun with 103.4 psi on tubing. After 5 min TP was 104.1 psi. POOH. Gun was wet. RIH w/2-7/8" x 20' Razor HC, 6 spf, 60 deg phase and tie into GO-08 ROP-DGR-EWR-ALD-CNT dated 18 Aug 2015. Run correlation log and send to town. Get ok to perf from 9,180' to 9,200'. Spot and fired gun with 1,027 psi on tubing. After 5 min TP was 1,033 psi. POOH. Gun was wet. RIH w/2-7/8" x 14' Razor HC, 6 spf, 60 deg phase and tie into GO-08 ROP-DGR-EWR-ALD-CNT dated 18 Aug 2015. Run correlation log and send to town. Get ok to perf from 9,166' to 9,180'. Spot and fired gun with 1,365 psi on tubing. After 5 min TP was 1,370 psi. POOH. Gun was wet. RIH w/GPT tool and find fluid level at 8,040'. Rig down lubricator and turn well over to field. 03/05/2017 -Sunday PTW and JSA. Rig up lubricator. PT lub to 250 psi low and 2,000 psi high. Well flowing 1.310 million at 759.6 psi. RIH with roller boggier and GPT tool and tie into GO-08 ROP-DGR-EWR-ALD-CNT dated 18 Aug 2015. Log from 9,050' down to 10,025' where we tagged. It was real sticky on bottom. Log up at 35' per min to 9,150' and back down to 9,975'. Did 5 min stops at 9,800', 9,390' and 9,150'. Found fluid level at 9,198'. Well was flowing between 1.310 million at 759.6 psi and 1.279 million at 757.4 psi. POOH. Rig down lubricator and turn well back over to field. Sent field copy to Ops Engr and Res Engr. Ninil: Gr Unit Well: Grassim Oskolkoff#8 • n • SCHEMATIC PTD:215-077 API: 50-133-20651-00-00 Hilcorp Alaska,LLC RKB 18' CASING DETAIL .• 1 •1 16" 4 t . Size Type Wt Grade Conn. ID Top Btm • ? 16" Conductor 84 X-56 Weld 15.010" Surf 120' 2 11. >t.. 10-3/4" Surf.Csg 45.5 L-80 BTC 9.950" Surf 3,492' i iii 3 7-5/8" Int.Csg 29.7 L-80 BTC 6.875" Surf 1,779' 7-5/8" Int.Csg 29.7 P-110 BTC 6.875" 1,779' 7,466' 14yTOC @ 4-1/2" Prod Liner 12.6 L-80 D HT C 3.958" 7,239' 10,198' ;' 2,000 g at 1 TUBING DETAIL 4. A. 4-1/2" Tubing 12.6 L-80 BTC-mod 3.958" Surf 7,287' •Y 4 ' Z)" 'Y JEWELRY DETAIL 024 " ' No. Depth ID OD Item 2' 1 18' 4.00" - Tubing Hanger,4-1/2"BT Mod 2 269' 3.813" 5.50" 5-1/2"Hydraulic Nipple for WL Retrievable SCSSV 3 335' 3.85" 5.75" 4-1/2"Chemical Injection Mandrel 14!c Baker ZXP Liner Top Packer/HRD-E Profile(10'tie-back 4 7,239' 3.958" 6.875" extension) .I' i Seal Bore Extension"GBH-22"Locating seal assembly k A 5 7,272' 3.833" 4.74" (16.37') `'' 6 10,055' 3.958" CIBP 4* 5 'I'' "" i4 s{f 7-5/8" 4 •w.'• r O r#r RA Mkr Jt PERFORATION DETAIL 8,211' ', ° .‘v.' . ' Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) ft Size Date Iv: ` w 9,166' 9,220' 4,550' 4,604' 54 2-7/8" 03/02/2017 n r, T12 9,220' 9,260' 4,604' 4,643' 40 2-7/8" 03/01/2017 RA Mkr Jt VCI T13B 9,412' 9,424' 4,794' 4,806' 12 2-7/8" 03/01/2017 8,502' 'r t-, w, 9,800' 9,877' 5,180' 5,256' 77 2-7/8" 02/03/2017 a T17A 9,828' 9,851' 5,208' 5,230' 23 2-7/8" 08/28/2015 `ate, 9,837' 9,877' 5,216' 5,256' 23 2-7/8" 02/02/2017 RAMkrJt r t,y; x1 8,790' i'.. 1 rix ) Tu," nr. , T12 + � T13B ..ter.. RA Mkr Jt ast" y•- • T17A 9,905' 1 t 41 6 I . s 1144 1 6-3/4"hole t, "' " -� Shoe @ 10,198' 4-1/2" PBTD=10,068' MD/5,445'TVD TD=10,200' MD/5,577'TVD Max Deviation:79 deg @ 2,421' Max Dogleg:6.2 deg/100 @ 1,496' Updated by DMA 03-28-17 • • Carlisle, Samantha J (DOA) From: Schwartz, Guy L (DOA) Sent: Wednesday, February 22, 2017 9:13 AM To: Donna Ambruz Cc: Chad Helgeson;Taylor Nasse;Carlisle, Samantha J (DOA) Subject: RE: Sundry Cancellation - Sundry#315-715 GO-08 (PTD 215-077) Donna, Sundry#315-715 will be withdrawn as requested. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guv.schwartz@alaska.gov). From: Donna Ambruz [mailto:dambruz@hilcorp.com] Sent:Tuesday, February 21, 2017 3:11 PM To:Schwartz,Guy L(DOA)<guy.schwartz@alaska.gov> Cc:Chad Helgeson<chelgeson@hilcorp.com>;Taylor Nasse<tnasse@hilcorp.com> Subject:Sundry Cancellation-Sundry#315-715 GO-08 (PTD 215-077) Guy, Please withdraw the above mentioned sundry. Thank you. Donna amivavz Operations/Regulatory Tech Kenai Asset Team Hilcorp Alaska, LLC SCANNED MAR 142017 3800 Centerpoint Drive,Suite 1400 Anchorage,AK 99503 907.777.8305- Direct 907.777.8310-Fax dambruzPhilcorp.com 1 RBDISS201 • 1,OF Ty 0,1. �V7�.'. THE STATE Alaska Oil and Gas ti�• �, of Conservation Commission - LAS�:A Sr � z �� 333 West Seventh Avenue rti GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 O Q. Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager SCANNED MAR 82E? Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage,AK 99503 Re: Ninilchik Field, Beluga/Tyonek Gas Pool, GO 8 Permit to Drill Number: 215-077 Sundry Number: 317-041 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 41)191-- Daniel T. Seamount, Jr. Commissioner DATED this vd day of January,2017. RBDIViS C,( --F7:3 - 3 2017 STATE OF ALASKA • RECEIVED ALASKA OIL AND GAS CONSERVATION COMMISSION JAN 2 4 2017 APPLICATION FOR SUNDRY APPROVALS �� 20 AAC 25.280 CC 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑� • Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Re-perforate ❑� 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory ❑ Development Q • 215-077 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 50-133-20651-00 • 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O.701 Will planned perforations require a spacing exception? Yes ❑ No ❑✓ Grassim Oskolkoff(GO)#8 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 389737' Ninilchik Field-Beluga/Tyonek Gas Pool - 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi):Current: 1021 psi Plugs(MD): Junk(MD): 10,200' . 5,577' ' 10,055' 5,433' Post T13B: 1679 psi 10,055' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 3,492' 10-3/4" 3,492' 1,844' 5,210 psi 2,470 psi Intermediate 1,779' 7-5/8" 1,779 1,450' 6,890 psi 4,790 psi Intermediate e ediate 5,687' 7-58" 7,466' 2,943' 9,470 psi 5,340 psi Production Liner 2,959' 4-1/2" 10,198' 5,575' 8,430 psi 7,500 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 4-1/2" 12.6#/L-80 7,287' Packers and SSSV Type: Baker ZXP Liner Top Packer Packers and SSSV MD(ft)and TVD(ft): 7,239'MD/2,792'ND WL SCSSV 259'MD/259'ND 12.Attachments: Proposal Summary E Wellbore schematic E 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development D Service ❑ 14.Estimated Date for 15.Well Status after proposed work: February 7,2017 Commencing Operations: OIL ❑ 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. Contact Taylor Wellman-777-8449 Email twellman a hilcorp.com Printed Name Chad Helgeson Title 9 Operations Manager Signature //47,/,,,":-.7/ Phone 907-777-8405 Date /lZ"ii‘7 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ i-4-)f- 1 1'341 Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes 0 No Subsequent Form Required: l RS®Eil5 L\---FL.,) - 3 2017 1C)1----- 47 / > 7 Approved by: COMMISSIONER APPROVED BY 1 THE COMMISSION Date: (/ 3#/L O Ri6a1NtiAtElid Subs in Form and Form 10-403 Revised 11/2015 for 12 month?-from the date of approval. Attachments in Duplicate 1—.:17—/7 �.©7 __,.sb (. 2.4— 17 Perforate • Well: GO#8 Hilcorp Alaska,Lb Date:01/23/2017 Well Name: GO#8 API Number: 50-133-20651-00 Current Status: Gas Well Leg: N/A Estimated Start Date: 02/07/17 Rig: EL Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-077 First Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (M) AFE Number: WeIIEZ Entry Required: Yes Current Surface Pressure: 100 psi (flowing) Maximum Expected BHP (Current): 1832 psi @ 5,256' TVD Max. Potential Surface Pressure(Current): 1021 psi (SI pressure on 2/10/16) Maximum Expected BHP (Post add T13): 2158 psi @ 4,794' TVD Max. Potential Surface Pressure (Post add T13): 1679 psi (0.1 psi/ft to surface) Brief Well Summary GO#8 was a grass roots development well drilled in July 2015 targeting gas sands in the Beluga and Tyonek formations. The well had seen declining production so a cap string was installed in 2015. The cap string pumped surfactants and soap but had minimal impact to helping to keep the well unloaded. The cap string was pulled in May 2016. Over the past few months the well's production has declined and the well has died. v Objective: - Re-perforate and add perforations to the T17A sand ' - Perforate the T13 sand Slickline Procedure: 1. MIRU Slickline Unit. Pressure test to 250psi low/2000psi high. 2. Pull 4-1/2" SSSV at 269' KB. 3. MU roller drift toolstring and drift to bottom of well. 4. RD Slickline unit. E-Line Procedure: 5. MIRU E-Line unit. Pressure test to 250psi low/2000psi high. 6. RU tractor and perforating toolstring. 7. MU 2-7/8"—3-3/8", 6spf perf guns and perforate the following interval: Zone Sand Top Shot(md) Bottom Shot(md) Ft Tyonek T17A 9,800' 9,877' 77' Total 77' a. The well reaches 75deg at 1993' KB. Slickline is able to drift the well with a very specific configuration of weight bars and rollers. Tractoring may be required in different intervals to reach depth. b. Correlation Log: GO#8 ROP-DGR-EWR-ALD-CNT dated 18-Aug-2015. ' c. Confirm with RE or Geologist final correlation log prior to perforating. d. Record pre/post perforating tubing pressures in the daily report. 8. RD E-Line unit. 9. Turn well over to production. • • Perforate Well: GO#8 Hilcorp Alaska,LL, Date:01/23/2017 Operations: 10. Flow well and obtain stable well test. E-Line Procedure: 11. MIRU E-Line unit. Pressure test to 250psi low/2000psi high. 12. RU tractor and perforating toolstring. 13. MU 2-7/8"—3-3/8", 6spf perf guns and perforate the following intervals in this order testing between perforating (top of chart down): Zone Sand Top Shot(md) Bottom Shot (md) Ft Tyonek T13B 9,412' 9,424' 12 Tyonek T12 9,166' 9,260' 94 Total 106' a. The well reaches 75deg at 1993' KB. Slickline is able to drift the well with a very specific configuration of weight bars and rollers. Tractoring may be required in different intervals to reach depth. b. Correlation Log: GO#8 ROP-DGR-EWR-ALD-CNT dated 18-Aug-2015. c. Confirm with RE or Geologist final correlation log prior to perforating. d. Record pre/post perforating tubing pressures in the daily report. 14. RD E-Line unit. 15. Turn well over to production. E-line Procedure(Contingency): 1. If any zone produces sand and/or water. 2. MIRU E-line, PT lubricator to 2,000 psi Hi 250 Low. 3. RIH and set 4.5"Plug at 25'above zone to be isolated. Or 4. RIH and set 4.5"Casing Patch across the zone. Slickline Procedure: (within 14 days of stable production) 16. MIRU Slickline Unit. Pressure test to 250psi low/2000psi high. 17. RIH w/brush toolstring and brush the SSSV nipple at 269' KB if needed (up to discretion of the field crew). 18. Set 4-1/2" SSSV at 269' KB. a. Confirm drawdown on SSSV. 19. RD Slickline unit. - ti 0 • Ninilchik Unit Well: Grassim Oskolkoff#8 SCHEMATIC PTD:215 077 • API: 50-133-20651-00-00 Hilc"rp Alaska,ld.0 RKB 18' CASING DETAIL 1 e rI, Size Type Wt Grade Conn. ID Top Btm 16" 2 ( 1— og 16" Conductor 84 X-56 Weld 15.010" Surf 120' ( , 10-3/4" Surf.Csg 45.5 L-80 BTC 9.950" Surf 3,492' 3 ) r 7-5/8" Int.Csg 29.7 L-80 BTC 6.875" Surf 1,779' 10-3/4"4 ' TOC @ 7-5/8" Int. Csg 29.7 P-110 BTC 6.875" 1,779' 7,466' ^'2,000' 4-1/2" Prod Liner 12.6 L-80 D HT C 3.958" 7,239' 10,198' TUBING DETAIL 4-1/2" Tubing 12.6 L-80 C- B d 3.958" Surf 7,297' i Yilr JEWELRY DETAIL �. No. Depth ID OD Item 1 18' 4.00" - Tubing Hanger,4-1/2" BT Mod 2 269' 3.813" 5.50" 5-1/2" Hydraulic Nipple for WL Retrievable �1 SCSSV A 3 335' 3.85" 5.75" 4-1/2"Chemical Injection Mandrel r. 5 4 7,239' 3.958" 6.875" Baker ZXP Liner Top Packer/HRD-E Profile(10' 4 tie-back extension) 7-5/8" 7 y, ! , 5 7,272' 3.833" 4.74" Seal Bore Extension "GBH-22" Locating seal .., + assembly(16.37') 6 10,055' 3.958" CIBP = 'tri RA Mkr Jt 411I V. r. 8,211' 44, z 44,"^" ri �' :' 4 P t� '"`. i PERFORATION DETAIL RA MkrJt 8 502' Sands Top(MD) Btm(MD) Top(ND) Btm(TVD) ft Size Date lam, ty, T17A 9,828' 9,851' 5,208' 5,231' 23 2-7/8" 8/28/2015 RA Mkr Jt +, . : 4' 8,790' y , 1i1 T17A RA Mkr Jt y ! 9,905' 1t6 ` 11q 6-3/4"hole b " a `' Shoe 10,198' 4-1/2" ' �� PBTD=10,068' MD/5,445'TVD TD=10,200' MD/5,577'TVD Max Deviation:79 deg @ 2,421' Max Dogleg:6.2 deg/100 @ 1,496' Updated by TTW 01-17-17 0 Ninilchik Unit Well: Grassim Oskolkoff#8 , . H 4110 PROPOSED SCHEMATIC 215-077 APID..50433-20651-00-00 Ililcorp Alaska,1,I.0 RKB 18' CASING DETAIL e Size Type Wt Grade Conn. ID Top Btm 16"d 2 ( 16" Conductor 84 X-56 Weld 15.010" Surf 120' 10-3/4" Surf.Csg 45.5 L-80 BTC 9.950" Surf 3,492' 3 7-5/8" Int.Csg 29.7 L-80 BTC 6.875" Surf 1,779' 10-3/4"G s'd ' '.TOC @ 7-5/8" Int.Csg 29.7 P-110 BTC 6.875" 1,779' 7,466' 2,000' 4-1/2" Prod Liner 12.6 L-80 D HT C 3.958" 7,239' 10,198' TUBING DETAIL 4-1/2" Tubing 12.6 L-80 C- B d 3.958" Surf 7,297' s JEWELRY DETAIL 1 No. Depth ID OD Item 1 18' 4.00" - Tubing Hanger,4-1/2" BT Mod 2 269' 3.813" 5.50" 5-1/2" Hydraulic Nipple for WL Retrievable SCSSV 3 335' 3.85" 5.75" 4-1/2"Chemical Injection Mandrel • 5 4 7,239' 3.958" 6.875" Baker ZXP Liner Top Packer/HRD-E Profile(10' `. tie-back extension) „ Seal Bore Extension "GBH-22" Locating seal 7-5/8" 4 5 7,272 3.833 4.74" assembly(16.37) 6 10,055' 3.958" CIBP RA Mkr Jt �; 8,211' isi PERFORATION DETAIL Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) ft Size Date RA Mkr JtW r T12 9,166' 9,260' 4,550' 4,643' 94 2-7/8" Future - 8,502' T13B 9,412' 9,424' 4,794' 4,806' 12 2-7/8" Future T17A 9,828' 9,851' 5,208' 5,231' 23 2-7/8" 8/28/2015 - {*. T17A 9,800' 9,877' 5,233' 5,256' 23 2-7/8" Future RA MkrJt is,," 17 8,790 `.: i `a + T1313 T17A RA Mkr Jt 9,905' ( 6 h * -- -t. ...- 6-3/4"hole Shoe @ 10,198' 4-1/2" PBTD=10,068' MD/5,445'ND TD=10,200' MD/5,577'TVD Max Deviation:79 deg @ 2,421' Max Dogleg:6.2 deg/100 @ 1,496' Updated by CAH 01-23-17 STATE OF ALASKA ALL OIL AND GAS CONSERVATION COM SION • REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon _I Plug Perforations U Fracture Stimulate U Pull TubingM Operations shutdown A Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing Cl Change Approved Program ❑ Plug for Redrill ❑ srforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: Cap String Install 2 2.Operator 4.Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development 2 Exploratory ❑ 215-077 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic Li Service ❑ 6.API Number: Anchorage,AK 99503 50-13-20651-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 389737 Grassim Oskolkoff(GO)#8 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Ninilchik Field-Beluga/Tyonek Gas Pool 11. Present Well Condition Summary: e Total Depth measured 10,200 feet Plugs measured 10,055 fee C E e r`' E true vertical 5,577 feet Junk measured N/A feet ).PR 13 2016 Effective Depth measured 10,055 feet Packer measured 7,239 feet true vertical 5,433 feet true vertical 2,792 feet AOGCC Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 3,492 10-3/4" 3,492' 1,844' 5,210 psi 2,470 psi Intermediate 1,779' 7-5/8" 1,779' 1,450' 6,890 psi 4,790 psi Intermediate 5,687' 7-5/8" 7,466' 2,943' 9,470 psi 5,340 psi Production Liner 2,959' 4-1/2" 10,198' 5,575' 8,430 psi 7,500 psi Perforation depth Measured depth See Attached Schematic L�16 True Vertical depth See Attached Schematic `4►4NE® APR 2 9 IU Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80 7,287'MD 2,821'TVD Baker ZXP Packers and SSSV(type,measured and true vertical depth) Liner Top Pkr 7,239'MD 2,792'TVD 12.Stimulation or cement squeeze summary: N/A 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: 0 2150 1 85 207 Subsequent to operation: 0 2060 1 85 166 14.Attachments(required per 20 AAC 25.070.25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations ❑ Exploratory❑ Development El Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil Li Gas ❑✓ WDSPL Li Printed and Electronic Fracture Stimulation Data ❑ 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: 315-731 Contact Taylor Nasse-777-8354 Email tnasse@hilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature .1" (�! Phone 907-777-8405 Date ' / /IGj GGG Form 10-404 Revised 5/2015 E�I-24. Submit Original Only 4,/„--4 RBDMS 'kA-- plt 1 4 2016 • Ninilc 4111 Well: GrassimhikUnit Oskolkoff#8 11 SCHEMATIC PTD: 215-077 API: 50-133-20651-00-00 Hilcorp Alaska,LLC RKB 18' CASING DETAIL 16"J t a Size Type Wt Grade Conn. ID Top Btm 2 I 16" Conductor 84 X-56 Weld 15.010" Surf 120' L 10-3/4" Surf. Csg 45.5 L-80 BTC 9.950" Surf 3,492' 3 L 7-5/8" Int.Csg 29.7 L-80 BTC 6.875" Surf 1,779' 10-3/4" TOC @ 7-5/8" Int.Csg 29.7 P-110 BTC 6.875" 1,779' 7,466' ° -—2,000' 4-1/2" Prod Liner 12.6 L-80 D HT C 3.958" 7,239' 10,198' •1 TUBING DETAIL 1 4-1/2" Tubing 12.6 L-80 BTC- mod 3.958" Surf 7,297' 3/8" SS Tubing 0.049" 2205 Surf 9,800' JEWELRY DETAIL No. Depth ID OD Item ' 1 18' 4.00" - Tubing Hanger,4-1/2" BT Mod •* 2 269' 3.813" 5.50" 5-1/2" Hydraulic Nipple for WL Retrievable 1 SCSSV(SCSSV removed for 3/8"capillary string) • . 3 335' 3.85" 5.75" 4-1/2" Chemical Injection Mandrel 5 "'.< 4 7,239' 3.958" 6.875" Baker ZXP Liner Top Packer/HRD-E Profile(10' • tie-back extension) '" °a 5 7272' 3833" 4.74" Seal Bore Extension "GBH-22" Locating seal 7-5/8" d 4 , . assembly(16.37 ) ,,, �, 6 10,055' 3.958" CIBP RA Mkr Jt I . 8,211' +( A. PERFORATION DETAIL RA Mkr Jt 4, 8,502' ,, Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) ft Size Date is T18 9,828' 9,851' 5,208' 5,231' 23 2-7/8" 8/28/2015 RA Mkr Jt ^,* s' '' 8,790' , • 1 �' ,. Cap String Info: FCV set at 1,700 psi, Max tool OD 2.08" (centralizer with rollers), 200' at surface, 1,911#calculated weight of tubing. 1 )('----- -1-r RA Mkr Jt - 9,905' 6 • .,, ``, 6-3/4" hole Shoe @ 10,198' 4-1/2" PBTD=10,068' MD/5,445'TVD TD=10,200' MD/5,577'TVD Max Deviation: 79 deg @ 2,421' Max Dogleg:6.2 deg/100 @ 1,496' Updated by TWN 4-03-16 • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date GO-08 NA 50-133-20651-00 215-077 2/11/16 2/11/16 Daily Operations: 02/11/2016-Thursday JSA and tail gate safety meeting. Inspect and secure area, mitigate unsafe conditions, roll out tarps, spot truck,ground unit to WH. Deploy and inspect BJDC crane and deck equipment, customer supplied man-lift, install counter, release weight indicator travel bolts and zero the weight indicator. Connect centralizer with rollers to FCV. Verify FCV set pressure @ 1,700 psi. Ops dumping friction reducer into well head. Shut swab valve and bleed off tree-cap. Pull tree- cap. Replace OTIS blanking plug with WHA (note 0-ring). MU fitting. PU BJDC injector with crane. Install tubing through counter into injector chains and adjust the tubing straightener. Run cap string through injector. Run cap string through WPA. Insert WPA support pin. Attach FCV. Pull test FCV to 500 pounds to ensure the ferrule is secure. Remove WPA support pin. Lift injector over WH, lower and thread WPA into WHA. Lower injector carefully onto the WPA while "walking"the injector chains down the tubing. Set the counter reading to KB depth. Install snubbing guides. Connect the WPA control line. Connect the WH pressure test manifold to the WPA, ensure positive closure on both quick-couplers and attach whip-checks. Open methanol tank feed. Pressure the WPA hydraulic seal to 3,000 psi. Pressure test 1.5x SIWHP. Open swab valve. RIH to setting depth. RIH 10 feet past target set depth. POOH back to the target depth and record the pull force. Set slips. Set Rattigans. Release pressure on upper hydraulic seal. Install slip retainer pins. Place 3,000 psi on WPA hydraulic seals, close needed valve on WPA, bleed off hose and remove. Insert hydraulic plug. RD/MO. Secure area. Leave location. • • - - - so o 0 C N o O M co• CO N I • LL W s ID _ • -o • y w LL o c Z c rn n E aEi a nN s.et CO 1 c; U ml ao > Z > > > O 0 Co • D > @ 2 H �' a� 2 F- 2 H 2 H O O � b in I T 0 �0 I—00 F- j � J F- F- H F- F- F- O O •- W C CD m ui CO CO Q Q CO ao w CO 00 00 ai m '8 z z E 4t .E • z z a* * 4t 4# 1# It O 0 E o 3 ET. CO O O t LL LL 0 0 0 O O O F_- I' CO x J CD 00a Q CO 7 it n - . 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C U w '� J '� a) .Q l0 U a z o a a m w E a p E E 2 o 2 E o m E E Q E 0 2 o a 0 D. 0 0 0 s, OF rit • • G;w\ //7„ s THE STATE Alaska Oil and Gas e�►; �� ofAT A1 Conservation Commission *h. == 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 \Th'.� Main: 907.279.1433 477110,, AL �P- Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager Hilcorp Alaska, LLC f 5_. 0 77 3800 Centerpoint Drive, Suite 1400 Anchorage,AK 99503 Re: Ninlchik Field, Beluga/Tyonek Gas Pool, GO#8 Sundry Number: 315-731 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 11 Cathy P. Foerster Chair DATED this !St of December, 2015 Encl. - AV103 1015 • • RECEIVEr STATE OF ALASKA 201 DEC 0 4 ALASKA OIL AND GAS CONSERVATION COMMISSION is/ Off, t244 PS APPLICATION FOR SUNDRY APPROVALS r,r,e-‘ 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other:Cap String Install 2.Operator Name: Hilcorp Alaska, LLC 4.Current Well Class: 5.Permit to Drill Number: , v r> Exploratory ❑ Development 0• 215-077 • •f 1- 3.Address. 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 50-133-20651-00 7. If perforating: 8,Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O.701 ❑ Grassim Oskolkoff(GO)#8 Will planned perforations require a spacing exception? Yes ❑ No 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 389737 ' Ninilchik Field-Beluga/Tyonek Gas Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 10,200' • 5,577' - 10,055' 5,433' 985psi 10,055' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 3,492' 10-3/4" 3,492' 1,844' 5,210 psi 2,470 psi Intermediate 1,779' 7-5/8" 1,779 1,450' 6,890 psi 4,790 psi Intermediate 5,687' 7-58" 7,466' 2,943' 9,470 psi 5,340 psi Production Liner 2,959' 4-1/2" 10,198' 5,575' 8,430 psi 7,500 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 4-1/2" 12.6#/L-80 7,287' Packers and SSSV Type: Baker ZXP Liner Top Packer Packers and SSSV MD(ft)and TVD(ft): 7,239'MD/2,792'TVD WL SCSSV 259'MD/259'TVD 12.Attachments: Proposal Summary 0 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: December 18,2015 Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS E . 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. Contact Taylor Nasse-777-8354 Email tnasseahiIcorD.com Printed Name Chad Helgeson Title Operations Manager Signature 7://1 "7/7- 7/ Phone 907-777-8405 Date !? /j // COMMISSION USE ONLY / Conditions of approval: Notify Commission so that a representative may witness Sundry Number. 315- 73l Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: A. 5'a SS 1/ v�;v if-c"- Zb AA" C-- 2 S. z G r CA) (.M 11 w Post Initial Injection MIT Req'd? Yes ElNo ❑ c,� 1-°Spacing Exception Required? Yes ❑ NoJ' Subsequent Form Required: /.0 — / 0`( �� .. aAPPROVED BY _ Approved by: �� THE COMMISSION Date:/2 —!mrmaForm 10-403 Revised 11/2015 oleGpiliUbd&ffdJSSIONER for 12 months from the date of approval. Attachments in Duplicate 'Al' 2•• /e.4_ • • Well Prognosis Well: GO#8 Hilcoru Alaska,LL Date: 12/03/2015 Well Name: GO#8 API Number: 50-133-20651-00 Current Status: Producing Leg: N/A Estimated Start Date: 12/18/15 Rig: Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-077 First Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (M) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907) 229-4824(M) AFE Number: 1511166C Current Surface Pressure: -572 psi Maximum Expected BHP: - 1,887 psi @ 5,379' TVD (PBU survey 11/14/15) Max. Potential Surface Pressure: -985 psi (PBU survey 11/14/15) Brief Well Summary GO #8 was a grass roots development well drilled in July 2015 targeting gas sands in the Beluga and Tyonek formations. A 72 hr. pressure build-up and pressure-temperature survey was recently conducted on this well, which showed a fluid level at around 8,075' MD. The purpose of this work/sundry is to install a capillary string to help keep the well unloaded. Variance: Hilcorp Alaska respectfully requests a variance from 20 AAC 25.265 for requiring a SSSV when a w capillary string is run within the tubing string. o� : p-'-- 44-c, z.s: us' C d)0) Notes Regarding Wellbore Condition • Prior to performing work, remove wireline-retrievable SCSSSV and install blanking sleeve. • Current fluid level is 8,075' MD. • Well currently producing 1.3 MMSCFD at 572 psig. (Previous Rate of 2.4 MMSCFD on 10/29/15) Procedure: 1. RU Dyna Coil Unit. 2. Stab 3/8" capillary line into wellhead pack-off assembly. Make up BHA components. Install pack-off and pressure test against swab valve 250 psi low/3,000 psi high. 3. RIH with 3/8" capillary string to ±9,800' MD. 4. Install slips and connect tubing to chemical injection pump. 5. RD Dyna Coil Unit. 6. Turn well over to production. Nom Attachments: 5�/ p-h. "1-'1 1. Current Schematic ' 2. Proposed Schematic /v. Iy- cS . . Ninilchik Unit Well: Grassim Oskolkoff#8 SCHEMATIC :215-077 APD 50-133-20651-00-00 Hileorp Alaska,LLC RKB 18' _ CASING DETAIL 16" .,*� Size Type Wt Grade Conn. ID Top Btm �� 16" Conductor 84 X-56 Weld 15.010" Surf 120' 2 I SSSV ip 10-3/4" Surf.Csg 45.5 L-80 BTC 9.950" Surf 3,492' 3 1 /4, *' J- 7-5/8" Int. Csg 29.7 L-80 BTC 6.875" Surf 1,779' 10-3 ".TOC @ 7-5/8" Int. Csg 29.7 P-110 BTC 6.875" 1,779' 7,466' —2,000' . r,4 -1/2" Prod Liner 12.6 L-80 DHT/C 3.958" 7,239' 10,198' TUBING DETAIL 4-1/2" Tubing 12.6 L-80 BTC- ; d 3.958" Surf 7,297' a' JEWELRY DETAIL r No. Depth ID OD Item 'i 1 18' 4.00" - Tubing Hanger,4-1/2" BT Mod r 2 269, 3.813" 5.50" 5-1/2" Hydraulic Nipple with WL Retrievable 2.125" SCSSV—Wireline Valve(ID-2.125") } 11. 3 335' 3.85" 5.75" 4-1/2"Chemical Injection Mandrel � 1 Baker ZXP Liner Top Packer/HRD-E Profile(10' 5 4 7,239' 3.958" 6.875" fo tie-back extension) 7_5/8» d ."• 5 7,272' 3.833" 4.74" Seal Bore Extension "GBH 22" Locating seal assembly(16.37') , 6 10,055' 3.958" CIBP •*! :, 82111 I �' ,e1l PE PERFORATION DETAIL RA MkrJt 8,502' 'k El' Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) ft Size Date T18 9,828' 9,851' 5,208' 5,231' 23 2-7/8" 8/28/2015 ori RA Mkr Jt k,• ,.4 �;4' 8,790' , , 4 n 6131 'r' T18 RA Mkr Jt I 9,905' 4 A I 6 6-3/4"hole 4-1/2 „ gal $ .,t, i.40" Shoe @ 10,198' PBTD=10,068' MD/5,445'ND TD=10,200' MD/5,577'TVD Max Deviation:79 deg @ 2,421' Max Dogleg:6.2 deg/100 @ 1,496' Updated by GD 09-23-15 14 0 • Ninilchik Unit • Well: Grassim Oskolkoff#8 qp PROPOSED SCHEMATIC D 501303206510000 Hilcorp Alaska,LLC 0 Ci it RKB 18' 2 CASING DETAIL 16"d I L Size Type Wt Grade Conn. ID Top Btm 2 l 16" Conductor 84 X-56 Weld 15.010" Surf 120' LI10-3/4" Surf.Csg 45.5 L-80 BTC 9.950" Surf 3,492' 3 7-5/8" Int.Csg 29.7 L-80 BTC 6.875" Surf 1,779' 10-3/4"G TOC @ i ' 2,000' 7-5/8" Int.Csg 29.7 P-110 BTC 6.875" 1,779' 7,466' 4-1/2" Prod Liner 12.6 L-80 D HT C 3.958" 7,239' 10,198' TUBING DETAIL 4-1/2" Tubing 12.6 L-80 BC- ' d 3.958" Surf 7,297' rAk 3/8" SS Tubing Surf 9,800' 1 '_ JEWELRY DETAIL r No. Depth ID OD Item ,., ' ' 1 18' 4.00" - Tubing Hanger,4-1/2" BT Mod • `' 5-1/2" Hydraulic Nipple for WL Retrievable 2 269' 3.813" 5.50" , 1 " ; SCSSV(SCSSV removed for 3/8"capillary string) ill 3 335' 3.85" 5.75" 4-1/2"Chemical Injection Mandrel 44* • ' „ „ Baker ZXP Liner Top Packer/HRD-E Profile(10' ,, 4 7,239' 3.958 6.875 tie-back extension) 4 « Seal Bore Extension "GBH-22” Locating seal 7-5/8" � F'` 5 7,27Z 3.833" 4.74" s4, , ►' assembly(16.37) ,r' 6 10,055' 3.958" CIBP ii RA Mkr Jt 8,211 *,„"; i, ; ,if � 1,44 ' .� PERFORATION DETAIL RA Mkr Jt ' 8,502' V. S► Sands Top(MD) Btm(MD) Top(ND) Btm(TVD) ft Size Date � ; T18 9,828' 9,851' 5,208' 5,231' 23 2-7/8" 8/28/2015 RAMkrJt 0I. ;L* 8,790' w ,tl, t,) ;.,,+ '+_ ,I' "i .( T18 RA Mkr Jt y,. T 9,905' jji 6 ?,, 11. 1- 4. 6-3/4"hole f w4x* Shoe @ 10,198' 4-1/2" 4 PBTD=10,068' MD/5,445'ND TD= 10,200' MD/5,577'TVD Max Deviation:79 deg @ 2,421' Max Dogleg:6.2 deg/100 @ 1,496' Updated byTWN 12-03-15 • ti of TFJ� • w�� y/� sA THE • STATE Alaska Oil and Gas ba —s� of Conservation Commission ` ' • z _ 333 West Seventh Avenue e, Alaska 99501-3572 Anchorage,GOVERNOR BILL WALKER "•° Main: 907.279.1433 °FALASYQ' Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager I �- - j� Hilcorp Alaska, LLC 0/ 7 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga/Tyonek Gas Pool, Grassim Oskolkoff(GO) #8 Sundry Number: 315-715 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy '. Foerster Chair DATED this day of November, 2015 Encl. RBDMS SEC 0k 2015 ` � RECEIVED STATE OF ALASKA \\� NOV 2 0 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS A Or`(`: 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: N2 lift El 2.Operator Name: 4.Current Well Class: 5. Permit to Dnll Number: Hilcorp Alaska,LLC , Exploratory ❑ Development E" 215-077 " 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic LiService ❑ 6.API Number: Anchorage,Alaska 99503 50-133-20651-00 - 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O.701 J ❑ Grassim Oskolkoff(GO)* Will planned perforations require a spacing exception? Yes El No 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 389737 ' Ninilchik Field-Beluga/Tyonek Gas Pool • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 10,200' 5,577' ,. 10,055' 5,433' 985psi 10,055' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 3,492' 10-3/4" 3,492' 1,844' 5,210 psi 2,470 psi Intermediate 1,779' 7-5/8" 1,779 1,450' 6,890 psi 4,790 psi Intermediate 5,687' 7-58" 7,466' 2,943' 9,470 psi 5,340 psi Production Liner 2,959' 4-1/2" 10,198' 5,575' 8,430 psi 7,500 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic' See Attached Schematic 4-1/2" 12.6#/L-80 7,287' Packers and SSSV Type: Baker ZXP Liner Top Packer Packers and SSSV MD(ft)and TVD(ft): 7,239'MD/2,792'TVD WL SCSSV ' 259'MD/259'TVD 12.Attachments: Proposal Summary 0 Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Q Exploratory ❑ Stratigraphic ❑ Development ❑✓ Service ❑ 14. Estimated Date for 15.Well Status after proposed work: CommencingOperations: December ,2015 OIL WIND WDSPL P ❑ ❑ ❑ 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. Contact Taylor Nasse-777-8354 Email tnasse@hilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature (j ^ �� '. Phone 907-777-8405 Date rI c f i J�. COMMISSION USE ONLY / Conditions of approval: Notify Commission so that a representative may witness Sundry Number. <.-.7 316- — 7I Plug Integrity ❑ BOP Test Z Mechanical Integrity Test ❑ Location Clearance ❑ Other: A a=(J 06 f'y J 3• c;4..' < ...„-r- t ` r_. **1A1 •,�10 1 C 0 4 2015 Post Initial Injection MIT Req'd? Yes ❑ No ill MS�: Spacing Exception Required? Yes ❑ No d Subsequent Form Required: /0 4/6`i APPROVED BY �..- Approved by: p� COMMISSIONER THE COMMISSION Date:/� 2.1--/3 ��''•�� //�� Submit Form and Form 10-40 eviseti-.2%.1s- 11/Z015i 0 FfPGet Nic, o� valid for 12 months f,[or�l thdat q pprova. ! J/Attachments in Duplicate j / /� 2 • Well Prognosis • Well: GO#8 ilik oip Alaska,LL Date: 11/19/2015 Well Name: GO#8 API Number: 50-133-20651-00 Current Status: Producing Leg: N/A Estimated Start Date: 12/4/15 Rig: CTU Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-077 First Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824(M) AFE Number: 1511166C Current Surface Pressure: —572 psi Maximum Expected BHP: — 1,887 psi @ 5,379' TVD (PBU survey 11/14/15) Max. Predicted Surface Pressure: — 985 psi (PBU survey 11/14/15) Brief Well Summary GO #8 was a grass roots development well drilled in July 2015 targeting gas sands in the Beluga and Tyonek formations. A 72 hr. pressure build-up and pressure-temperature survey was recently conducted on this well, which showed a fluid level at around 8,075' MD. The purpose of this work/sundry is to jet the well with N2 using coiled tubing to unload the water from the wellbore. Notes Regarding Wellbore Condition • Prior to performing work, remove wireline-retrievable SCSSSV. • Current fluid level is 8,075' MD. • Well currently producing 1.3 MMSCFD at 572 psig. (Previous Rate of 2.4 MMSCFD on 10/29/15) Safety Concerns • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. • Consider tank placement based on wind direction and current weather forecast (venting methane and Nitrogen during this job) • Ensure all crews are aware of stop job authority Coiled Tubing Procedure: 1. Submit 24 hr. witness notification to AOGCC via web base notification. 2. MIRU Coiled Tubing, PT BOPE to 250/4500 psi. 3. Confirm SCSSSV has been removed prior to coil Intervention. SI well. 4. Isolate production flow line. Route well production to open top diffuser 400 bbl tank. 5. Pressure test N2 lines to 4,500 psi, prior starting job. 6. RIH w/ 1.75" coil w/2-1/4"jet nozzle BHA. a. Start pumping N2 at 800scf at 8,000ft b. Increase N2 rate as necessary while RIH to 10,026' MD and tag PBTD. Once N2 has reached return tank start pinching in choke (Maintain approximately 400-500 psi). 7. PU slowly to 8,000ft monitoring tank for fluid. Cycle between 8,000ft and 10,000ft one more time pumping N2 to lift well. Strap return tank until estimated volume of fluid recovered. If fluid rate is substantial continue to cycle between intervals. Use LEL monitor to sniff for gas on Return tank. • Well Prognosis Well: GO#8 Ililcon)Alaska,LL Date: 11/19/2015 a. Estimated volume of fluid is 30 bbl. 8. POOH w/coil. LD 2-1/4"jet nozzle BHA. 9. Bleed N2 off well and put well into production. 10. If well does not flow as predicted, SI overnight and repeat. 11. If well rates are acceptable RD Coiled Tubing. 12. Turn well over to production. 13. Within 10-days of stable production on well, RIH on slickline and set SCSSSV. Notify AOGCC to witness testing of SCSSSV. Attachments: 1. Current Schematic 2. Coil BOPE Schematic 3. Wellhead Diagram 4. CT Flow Schematic(Forward) . il • • Ninilchik Unit Well: Grassim Oskolkoff#8 • SCHEMATIC :215-077 APID:: 50-133-20651-00-00 Hilrnrp Alaska,LLC RKB 18' CASING DETAIL 1 b. Size Type Wt Grade Conn. ID Top Btm 16" ' ''" ill 2 16" Conductor 84 X-56 Weld 15.010" Surf 120' re ,� i10-3/4" Surf.Csg 45.5 L-80 BTC 9.950" Surf 3,492' 1 3 de"� 7-5/8" Int.Csg 29.7 L-80 BTC 6.875" Surf 1,779' 10-3/4 , . TOC @ 7.5/8" Int.Csg 29.7 P-110 BTC 6.875" 1,779' 7,466' '* —2,000' • 4-1/2" Prod Liner 12.6 L-80 DHT/C 3.958" 7,239' 10,198' l• i TUBING DETAIL #ii 1 4-1/2" Tubing 12.6 L-80 BTd 3.958" Surf 7,287' 01 i414 .0151e-6A---/fir JEWELRY DETAIL F s No. Depth ID OD Item 1 1 18' 4.00" - Tubing Hanger,4-1/2" BT Mod { 3.813" 5-1/2" Hydraulic Nipple with WL Retrievable 51 2 259' 2 125" 5.50" SCSSV—Wireline Valve(ID-2.125") N * 3 325' 3.85" 5.75" 4-1/2"Chemical Injection Mandrel t ;t 5 4 7,239' 3.958" 6.875" Baker ZXP Liner Top Packer/HRD E Profile(10' `'` tie-back extension) 4 Seal Bore Extension "GBH-22" Locating seal 7-5/8" ,' 5 7,272' 3.833" 4.74" a. , i �ftassembly(16.37) bopof,G, 6 10,055' 3.958" CIBP ,gym ) . S RA Mkr Jt Ir '` I 8,211' '+ ., .. �; RA Mkr Jt P.' 't PERFORATION DETAIL 8,502' 'A ri Sands Top(MD) Btm(MD) Top(ND) Btm(ND) ft Size Date '''' T18 9,828' 9,851' 5,208' 5,231' 23 2-7/8" 8/28/2015 RA Mkr Jt V. 4.�� 8,790' r "'" T18 RA Mkr Jt 4.t 9,905' 1 Al A *, `a t , 6-3/4"hole L ' I' ti a1 4 a% Shoe @ 10,198' 4-1/2" PBTD=10,068' MD/5,445'ND TD=10,200' MD/5,577'TVD Max Deviation:79 deg @ 2,421' Max Dogleg:6.2 deg/100 @ 1,496' Updated by DMA 11-17-15 ® •• , llNinilchik Unit G. Oskolkoff#8 11/19/2015 i1d,,,l1, ‘1-1,....1.1 I. GO#8 16X10%X75/8X4% Coil Tubing BOP Lubricator to injection head 1.75"Tandem Stripper I 1 t r ',I, Blind/Shear=' 1/16 10 =`Blind/Shear .l,'• Illj ll�`\\ MIMi 0110Blind/Shear i111111 =-Blind/Shear I,I.'• 13= 2. - —__ Slip —.1.12 Slip 01��.(�■ MIME � 011111 i „ _9�Pipe Pipe Mud Cross !P. m-mi M �• 4 1/16 10M X 4 1/16 10M Outlet — w/2-2 1/16 10M full opening FMC valves m m i : 111111[ 1111 0 ) mom I[ c I l[ 11111 ISI iii .. . Manual Manual Manual Manual 2 1/16 10M 2 1/16 10M ow 2 1/16 10M 2 1/16 10M Crossover spool °' \\ 41/1610MX41/165M 0( 00\� O' �\\c 0' .1c,-,,,,e Valve,Swab,WKM-M, �� a\Je04.\\n�0 � .rl�•t`�',y5 4 1/16 5M FE, HWO,DD trim 3 1555 .�'2,` , ..atop u. 31'$5 0� N / of I .? t, _%i il Valve, Upper Master "' ” WKM-M,4 1/16 SM FE, `A.' cti HWO,DD trim �,V' on ma_mm MR Valve, Lower Master,WKM-M, ihisx,•, 4 1/16 5M FE, HWO,DD trim . .cam u` q,.1 1x11._. ai Grade Level • • Ninilchik Unit GO #8 08/11/2015 Ninilchik Unit Tubing hanger,SME-CL,11 X 4% GO#8 EUE lift and susp,w/4"Type H 16 X 10%X 7 5/8 X 4 1/2 BPV profile,2-3/8 CCL,Alloy material BHTA,Otis,4 1/16 5M FE X 6.5"Otis Quick Union m i..w_®iue 0(--5-- 0-‘4\ 'O''�t‘'C� .0, J�G �p� O ��, ata ��..�e.�`T� ��o� 15�� Valve,Swab,WKM-M, Ja 4 1/16 5M FE, HWO,DD trim ►f� ' 1\9' NI?' ., FE.etati°t v:.. 3 31'q,5V oP me riTIEZ Ma 7 / • = a , - Valve,Upper Master WKM-M,4 1/16 5M FE, HWO, DD trim , 5-F rrrrr: iffo Valve,Lower Master,WKM-M, i" '1-4". . <a 4 1/16 5M FE,HWO,DD trim Qi , A - ■ — -r'0T o= _ o Grade Level nii el Multibowl Wellhead,SMB-22, AI.:lip € '= ' s- 11 5M X 16%3M,w/ .;o : ci . : a• 4- 4-21/165M550 '-�— e' en Ji _ : 46. !11'C. Starting head,Seaboard, Pii 16%3MX16"SOW,w/ 2-2 1/16 5M EFO ; 3 3 -.j,. 4 ' - .�, :4h} a 16" 10%" 7 5/8" 4%Z' S z8] D a ! ,1 D U 7 C Q D _ 1 e] U Z 0 t .] w z p 0, C liz • • -= • e OVI N N i z i1004 0 s_ 0 E, C • V A 0 d O H - i ��1 1't1111111 7 —'I Ii 0 111•11.JI' I®II.'II..l mi un un in, _ _ y a0 I 6J f a _ ' V 3 . c O I- 0. 0 r t _ 0 n11 • o A V • A . I ml' D , .O r � I 3 k i e It c rn IA c a oI O Z O X 0 • • Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive ' � Anchorage, AK 99503 Tele: 907 777-8308 H�Irnrp alurkc,.LI.t Fax: 907 777-8510 E-mail: snolan@hilcorp.com ECEIVED DATE 10/13/2015 NOV 0 4 2015 To: Alaska Oil & Gas Conservation Commission AOGCC Meredith Guhl Petroleum Geology Assistant 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL GO 8 eo,c 2- 5 5 boxes: Dry Cuttings Transmitted herewith are cuttings from GO 8 WELL SAMPLE INTERVAL GO 8 3500—5000 GO 8 5000—6000 GO 8 6000—8300 GO 8 8300—9400 GO 8 9400—10200 Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Rec- . : # 24A—J2 Date: `( ( /J s- • • 115077 II Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive Anchorage, AK 99503 Tele: 907 777-8308 DATA LOGGED eriIcI„-p �ia4 i.[.i I Fax: 907 777-8510 kO/1i/2015 E-mail: snolan@hilcorp.com M.K.BENDER DATE 10/02/15 To: Alaska Oil & Gas Conservation Commission � C CEI M G i`j C Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 OCT 12 2015 Anchorage, AK n^ 99501 AOGCC DATA TRANSMITTAL GO 8 GO 8 Elog and Mudlog prints and digital data Prints: 5" Formation Log MD/TVD 2" Drilling Dynamics Log MD/TVD 2" Formation Log MD/TVD 2"/5" ROP-DGR-EWR-ALD-CTN MD 2" LWD Combo Log MD/TVD 2"/5" DGR-EWR-ALD-CTN TVD 2" Gas Ratio Log MD/TVD 3 x END OF WELL REPORT CD1: digital Elog Data 2 64 3 CGM 8/18/2015 3:56 PM File folder Definitive Survey 8/18/2015 3:56 PM File feller DLIS+LAS 8/18/2015 3:56 PM File folder EMF 8/18/2015 3:56 PM File folder PDF 8/18/2015 3:56 PM File folder TIFF 8/18/2015 3:56 PM File folder CD2: digital Mudlog Data 2 6 3 4 4 Daily Reports 8/18/2015 8:22 AM File folder DML Data 8/18/2015 8:22 AM File folder ,;. Final Well Report 8/18/2015 8:22 AM File folder Ai LAS Data 8/18/2015 8:22 AM File folder LOG PDFs 8/18/2015 8:22 AM File folder Ai LOG TIFF; 8/18/2015 8:22 AM File folder I Show Reports 8/18/2015 8:22 AM File folder Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received y6...eat Date: • • RECEIVED SEP 2 5 2015 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION [fro"° WELL COMPLETION OR RECOMPLETION REPORT AND G la.Well Status: Oil ❑ Gas L SPLUG E Other ] Abandoned ❑ Suspended 1b.Well Class: 20PAC 25.105 20AAC 25.110 Development El ' Exploratory [] GINJ❑ WINJ ❑ WAGE WDSPL❑ No.of Completions: _1 Service ❑ Stratigraphic Test ❑ 2.Operator Name: 6. Date Comp., Susp., or 0' 14. Permit to Drill Number/ Sundry: Hilcorp Alaska, LLC Aband.: • 8/2/2015 215-077 3.Address: 7. Date Spudded: 15.API Number: 3800 Centerpoint Drive, Suite 1400 Anchorage,AK 99503 ' 7/23/2015 '' 50-133-20651-00-00 4a. Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: Surface: 3374'FSL,2726'FEL, Sec 23,TIN, R13W,SM,AK - 8/1/2015 -t8Z,B rAG . Grassim Oskolkoff#8 Top of Productive Interval: 9. KB(ft above MSL): 1.83.0 17. Field/Pool(s): • 2001'FNL, 1742'FEL, Sec 15,Ti N, R13W,SM,AK GL(ft above MSL): 164.8. Ninilchik/Beluga/Tyonek Gas Pool - Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: • 1967'FNL, 1763'FEL, Sec 15,Ti N, R13W,SM,AK -10,068'MD/5,445'TVD -, •ADL 389737; Unit Tract 3 4b. Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. Land Use Permit: Surface: x- 229297.68 - y- 2255334 - Zone- 4 10,200'MD/5,577'TVD N/A ' TPI: x- 225103.24 y- 2260601.95 Zone- 4 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 225082.88 y- 2260636.56 Zone- 4 259'MD /259'TVD N/A 5. Directional or Inclination Survey: Yes attached) No ❑ 13.Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension,or abandonment,whichever occurs first.Types of logs to be listed include, but are not limited to: mud log,spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance,dipmeter,formation tester,temperature, cement evaluation, casing collar locator,jewelry,and perforation record. Acronyms may be used.Attach a separate page if necessary ROP-DGR-EWR-ALD-CTN 2"/5"MD, DGR-EWR-ALD-CTN 2"/5"TVD, 5"FORMATION LOG MD/TVD,2"FORMATION LOG MD/TVD, LWD COMBO LOG MD/TVD, GAS RATIO LOG MD/TVD, DRILLING DYNAMICS LOG MD/TVD 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD FT PULLED 16" 84# X-56 0 120' 0 120' Driven Driven Conductor 10-3/4" 45.5# L-80 0 3,492' 0 1,843' 13-1/2" L-383 bbl 12#/T-76.7 bbl 15.2# 208 bbls 7-5/8" 29.7# L-80 0 3,240' 0 1,779 9-7/8" L-235 bbls 12.5# 7-5/8" 29.7# P-110 3,240' 7,466' 1,779' 2,842' 9-7/8" T-70 bbls 15.3# 15 bbls 4-1/2" 12.6# L-80 7,239' 10,198' 2,791' 5,575' 6-3/4" 109 bbls 15.3# 24. Open to production or injection? Yes ❑✓ No ❑ 25.TUBING RECORD If Yes, list each interval open(MD/TVD of Top and Bottom; Perforation Size SIZE DEPTH SET(MD) PACKER SET(MD/TVD) and Number): 4-1/2" 7,287' Tieback Assy. •9,828'-9,851'MD/5,208'/5,231 TVD(2-7/8",6 SPF) 26.ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes ❑ No 0 Per 20 AAC 25.283(i)(2)attach electronic and printed information DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 8/28/2015 Flowing Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 9/12/2015 24 Test Period —0 2887 0 N/A N/A Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 839 N/A 24-Hour Rate —0. 0 2887 0 N/A 34tta. 1" r Vii/r6 RBD SEP 3 0 2015 Form 10-407 Revised 5/2015 CONTINUED ON PAGE 2 Submit ORIGINIAL onl 28.CORE DATA Conventional`(s): Yes ❑ No ' . Sidewall Core es ❑ No ❑ If Yes, list formations and intervals cored(MD/TVD, From/To),and summarize lithology and presence of oil,gas or water(submit separate pages with this form, if needed). Submit detailed descriptions,core chips,photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑✓ Permafrost-Top N/A If yes, list intervals and formations tested, briefly summarizing test results. Permafrost-Base N/A Attach separate pages to this form, if needed, and submit detailed test BLG-50 4,644' 2,115' information, including reports, per 20 AAC 25.071. BLG-90 7,280' 2,817' BLG-135 8,133' 3,525' Tyonek 8,232' 3,622' T1 8,299' 3,689' T2 8,405' 3,794' T6 8,660' 4,047' T7 8,776' 4,162' T8 8,995' 4,380' T12 9,167' 4,551' T13 9,355' 4,738' T18 9,804' 5,184' T20 10,021' 5,400' Formation at total depth:T20 31. List of Attachments: Wellbore Schematic, Daily Drilling and Completion Reports, Definitive Directional Surveys, Days vs Depth and MW vs Graphs, Casing&Cementing Reports Information to be attached includes, but is not limited to:summary of daily operations,wellbore schematic,directional or inclination survey, core analysis, paleontological report, production or well test results,per 20 AAC 25.070. 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Monty Myers Email: mmyers@hilcorp.com Printed Name: Monty Myers Title: Drilling Engineer Signature: Phone: 907-777-8431 Date: rf• a 5-- Z0 15— INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed.All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item la: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class-Service wells: Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits(ex: 50-029-20123-00-00). Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing,Gas Lift, Rod Pump, Hydraulic Pump,Submersible,Water Injection,Gas Injection, Shut-in, or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071,submit detailed descriptions,core chips, photographs,and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability,fluid saturation,fluid composition,fluid fluorescence,vitrinite reflectance,geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070,attach to this form:well schematic diagram,summary of daily well operations,directional or inclination survey,and other tests as required including, but not limited to: core analysis,paleontological report, production or well test results. Form 10-407 Revised 5/2015 Submit ORIGINAL Only Ninilchik Unit H . • Well: Grassim Oskolkoff#8 SCHEMATIC 0 API: 50-133-20651-00-00 Hilcorp Alaska,LLC RKB 18' CASING DETAIL 16"1 1 .,k Size Type Wt Grade Conn. ID Top Btm 2 SSS 3 16" Conductor 84 X-56 Weld 15.010" Surf 120' 10-3/4" Surf.Csg 45.5 L-80 BTC 9.950" Surf 3,492' 7-5/8" Int.Csg 29.7 L-80 BTC 6.875" Surf 1,779' 10-3/4" TOC @ 7-5/8" Int.Csg 29.7 P-110 BTC 6.875" 1,779' 7,466' —2,000' 4-1/2" Prod Liner 12.6 L-80 DHT/C 3.958" 7,239' 10,198' TUBING DETAIL BTC- 4-1/2" Tubing 12.6 L-80 mod 3.958" Surf 7,297' r :x .-r 4i JEWELRY DETAIL No. Depth ID OD Item .1 1 18' 4.00" - Tubing Hanger,4-1/2" BT Mod 1 3.813" 5-1/2" Hydraulic Nipple with WL Retrievable 2 269' 5.50" 2.125" SCSSV—Wireline Valve(ID-2.125") . 7 3 335' 3.85" 5.75" 4-1/2" Chemical Injection Mandrel 5 ,,,° 4 7,239' 3.958" 6.875" Baker ZXP Liner Top Packer/HRD-E Profile(10' A tie-back extension) 4 iv "" -. Seal Bore Extension "GBH-22" Locating seal 7-5/8" , , . 5 7272' 3833" 474" . ,.* '; , . . assembly(16.37) 6 10,055' 3.958" CIBP ,.1'1'III 'am .. RAMkrJt [�', 8,211" ", . . ;; +t"/ aha 3, PERFORATION DETAIL RA Mkr Jt 8,502' 1 t ,:10, Sands Top(MD) Btm(MD) Top(ND) Btm(TVD) ft Size Date __, ..,:. i. T18 9,828' 9,851' 5,208' 5,231' 23 2-7/8" 8/28/2015 " k7, A f•. RA Mkr Jt " „' 8,790" ; r 64 Pt , T18 RA Mkr Jt :;.41 mii9,905' 4.; '" 6 4'14t ' '' 6-3/4"hole 4-1/2" 1641,` ," Shoe @ 10,198' PBTD=10,068' MD/5,445'ND TD=10,200' MD/5,577'ND Max Deviation:79 deg @ 2,421' Max Dogleg:6.2 deg/100 @ 1,496' Updated by OD 09-23-15 • • GO #8 Days vs Depth 0 500 GO#8 Actual 1I 1000 GO#8 Plan _ - 1500 2000 2500 3000 3500 4000 4500 r 5000 -o 5500 m 6000 - a 6500 7000 7500 8000 8500 l 9000 -_ _ ------- 9500 10000 10500 11000 -__ -- 0 5 10 15 20 25 30 35 Days • • GO #8 MW vs Depth 0 GO 1000 GO#8#8 Actual 2000 — — 3000 4000 5000 . . .. F L 4- v 6000 O of L 0 R a) 7000 .... 8000 9000 10000 t 11000 12000 8.0 9.0 10.0 11.0 12.0 13.0 14.0 Mud Density(ppg) • Hilcorp Energy Company Ninilchik Unit Grassim Oskolkoff G0 8 50-133-20651-00-00 50-133-20651-00-00 Sperry Drilling Definitive Survey Report 13 August, 2015 Immommimmo HALLIBURTON apia'ry i..�rtilany • • Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well Grassim Oskolkoff#8 Project: Ninilchik Unit TVD Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) ' Site: Grassim Oskolkoff MD Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) Well: Grassim Oskolkoff#8 North Reference: True Wellbore: GO 8 Survey Calculation Method: Minimum Curvature • Design: GO 8 Database: Sperry EDM-NORTH US+CANADA Project Ninilchik Unit Map System: US State Plane 1927(Exact solution) - System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) ' Using Well Reference Point Map Zone: Alaska Zone 04 , Using geodetic scale factor Well Grassim Oskolkoff#8 Well Position +NIS 0.00 usft Northing: 2,255,334.02 usft • Latitude: 60°9'54.553 N +E/-W 0.00 usft Easting: 229,297.68 usft . Longitude: 151°29'10.558 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: • 164.80 usft Wellbore GO 8 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (`) (°) (nT) BGGM2015 6/26/2015 16.28 73.18 55,226 Design GO 8 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 18.00 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 18.00 0.00 0.00 320.23 Survey Program Date 8/13/2015 From To (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 18.00 3,459.97 GO 8 Rig Surveys(GO 8) MWD+SC+sag Fixed:v2:standard dec&axial correction+sag 07/16/2015 3,541.42 7,386.90 GO 8 Rig Surveys(2)(GO 8) MWD+SC+sag Fixed:v2:standard dec&axial correction+sag 07/31/2015 7,435.13 10,158.91 GO 8 Rig Surveys(3)(GO 8) MWD+SC+sag Fixed:v2:standard dec&axial correction+sag 08/10/2015 Survey Map Map Vertical MD Inc Azi ND TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (0) (°) (usft) (usft) (usft) (usft) (ft) (ft) (0/100') (ft) Survey Tool Name 18.00 0.00 0.00 18.00 -164.80 0.00 0.00 2,255,334.02 229,297.68 0.00 0.00 UNDEFINED 196.92 0.07 28.29 196.92 14.12 0.10 0.05 2,255,334.12 229,297.73 0.04 0.04 MWD+SC+sag(1) 260.19 2.33 326.82 260.17 77.37 1.21 -0.63 2,255,335.24 229,297.07 3.63 1.33 MWD+SC+sag(1) 323.10 3.65 327.29 323.00 140.20 3.96 -2.42 2,255,338.04 229,295.35 2.10 4.59 MWD+SC+sag(1) 384.53 5.69 326.18 384.22 201.42 8.14 -5.17 2,255,342.27 229,292.70 3.32 9.56 MWD+SC+sag(1) 445.89 6.80 325.04 445.21 262.41 13.64 -8.94 2,255,347.86 229,289.05 1.82 16.21 MWD+SC+sag(1) 507.35 8.80 319.37 506.10 323.30 20.19 -14.09 2,255,354.53 229,284.05 3.48 24.53 MWD+SC+sag(1) 569.35 10.25 319.29 567.25 384.45 27.97 -20.78 2,255,362.46 229,277.54 2.34 34.79 MWD+SC+sag(1) 631.75 13.03 318.97 628.36 445.56 37.49 -29.02 2,255,372.15 229,269.52 4.46 47.38 MWD+SC+sag(1) 691.86 15.85 321.49 686.56 503.76 49.03 -38.58 2,255,383.90 229,260.22 4.81 62.36 MWD+SC+sag(1) 754.28 19.21 320.94 746.07 563.27 63.68 -50.36 2,255,398.81 229,248.77 5.39 81.16 MWD+SC+sag(1) 816.43 22.55 321.86 804.14 621.34 80.99 -64.17 2,255,416.44 229,235.35 5.40 103.30 MWD+SC+sag(1) 8/13/2015 2:16:45PM Page 2 COMPASS 5000.1 Build 73 i 0 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well Grassim Oskolkoff#8 Project: Ninilchik Unit TVD Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) Site: Grassim Oskolkoff MD Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) Well: Grassim Oskolkoff#8 North Reference: True Wellbore: GO 8 Survey Calculation Method: Minimum Curvature Design: GO 8 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +El-W Northing Easting DLS Section (usft) (0) (0) (usft) (usft) (usft) (usft) (ft) (ft) 0100 (ft) Survey Tool Name 878.44 26.09 321.17 860.63 677.83 100.97 -80.06 2,255,436.77 229,219.91 5.73 128.83 MWD+SC+sag(1) 940.19 29.66 319.59 915.21 732.41 123.19 -98.49 2,255,459.40 229,201.99 5.90 157.69 MWD+SC+sag(1) 1,004.69 33.63 320.08 970.11 787.31 149.05 -120.30 2,255,485.74 229,180.76 6.17 191.52 MWD+SC+sag(1) 1,064.29 36.43 318.60 1,018.91 836.11 174.99 -142.60 2,255,512.17 229,159.05 4.91 225.72 MWD+SC+sag(1) 1,127.13 40.32 318.72 1,068.16 885.36 204.28 -168.36 2,255,542.03 229,133.96 6.19 264.71 MWD+SC+sag(1) 1,187.83 40.85 319.23 1,114.26 931.46 234.07 -194.28 2,255,572.40 229,108.72 1.03 304.19 MWD+SC+sag(1) 1,249.92 42.85 319.02 1,160.51 977.71 265.39 -221.39 2,255,604.32 229,082.32 3.23 345.61 MWD+SC+sag(1) 1,312.48 46.13 318.89 1,205.13 1,022.33 298.45 -250.18 2,255,638.02 229,054.29 5.24 389.43 MWD+SC+sag(1) 1,373.48 49.34 320.27 1,246.15 1,063.35 332.82 -279.43 2,255,673.04 229,025.81 5.52 434.57 MWD+SC+sag(1) 1,435.21 52.84 320.46 1,284.92 1,102.12 369.81 -310.07 2,255,710.70 228,996.02 5.67 482.59 MWD+SC+sag(1) 1,496.03 56.61 320.06 1,320.04 1,137.24 407.98 -341.81 2,255,749.58 228,965.15 6.22 532.24 MWD+SC+sag(1) 1,558.91 58.81 320.31 1,353.63 1,170.83 448.81 -375.84 2,255,791.16 228,932.04 3.51 585.39 MWD+SC+sag(1) 1,621.98 61.70 319.51 1,384.92 1,202.12 490.69 -411.11 2,255,833.83 228,897.73 4.71 640.14 MWD+SC+sag(1) 1,682.33 65.22 320.50 1,411.88 1,229.08 532.05 -445.79 2,255,875.96 228,863.98 6.01 694.12 MWD+SC+sag(1) 1,744.64 66.38 320.82 1,437.42 1,254.62 576.00 -481.82 2,255,920.71 228,828.95 1.92 750.95 MWD+SC+sag(1) 1,807.39 68.97 321.45 1,461.25 1,278.45 621.20 -518.24 2,255,966.71 228,793.56 4.23 808.99 MWD+SC+sag(1) 1,868.59 72.41 321.25 1,481.49 1,298.69 666.30 -554.31 2,256,012.61 228,758.52 5.63 866.72 MWD+SC+sag(1) 1,931.14 74.38 322.51 1,499.36 1,316.56 713.45 -591.31 2,256,060.59 228,722.59 3.69 926.64 MWD+SC+sag(1) 1,993.20 75.14 322.59 1,515.68 1,332.88 760.99 -627.71 2,256,108.93 228,687.26 1.23 986.46 MWD+SC+sag(1) 2,054.75 75.00 321.67 1,531.54 1,348.74 807.94 -664.22 2,256,156.69 228,651.82 1.46 1,045.90 MWD+SC+sag(1) 2,117.67 77.15 322.41 1,546.68 1,363.88 856.09 -701.78 2,256,205.67 228,615.35 3.60 1,106.94 MWD+SC+sag(1) 2,178.76 78.41 321.87 1,559.61 1,376.81 903.22 -738.43 2,256,253.62 228,579.78 2.24 1,166.61 MWD+SC+sag(1) 2,242.89 79.24 319.68 1,572.04 1,389.24 951.96 -778.21 2,256,303.23 228,541.10 3.59 1,229.52 MWD+SC+sag(1) 2,303.49 78.59 317.91 1,583.69 1,400.89 996.70 -817.38 2,256,348.84 228,502.95 3.06 1,288.97 MWD+SC+sag(1) 2,365.55 78.83 319.02 1,595.84 1,413.04 1,042.25 -857.74 2,256,395.29 228,463.63 1.80 1,349.79 MWD+SC+sag(1) 2,421.88 79.42 317.74 1,606.47 1,423.67 1,083.60 -894.48 2,256,437.46 228,427.83 2.47 1,405.08 MWD+SC+sag(1) 2,486.01 78.98 318.32 1,618.48 1,435.68 1,130.44 -936.60 2,256,485.23 228,386.77 1.12 1,468.03 MWD+SC+sag(1) 2,549.41 77.23 317.27 1,631.55 1,448.75 1,176.39 -978.28 2,256,532.11 228,346.14 3.20 1,530.01 MWD+SC+sag(1) 2,611.48 77.40 318.28 1,645.18 1,462.38 1,221.23 -1,018.97 2,256,577.85 228,306.46 1.61 1,590.51 MWD+SC+sag(1) 2,671.50 77.84 318.14 1,658.05 1,475.25 1,264.94 -1,058.04 2,256,622.43 228,268.39 0.77 1,649.10 MWD+SC+sag(1) 2,735.29 77.70 318.21 1,671.56 1,488.76 1,311.40 -1,099.61 2,256,669.81 228,227.87 0.24 1,711.40 MWD+SC+sag(1) 2,796.70 78.09 318.52 1,684.44 1,501.64 1,356.28 -1,139.51 2,256,715.57 228,189.00 0.80 1,771.41 MWD+SC+sag(1) 2,859.22 78.93 318.94 1,696.89 1,514.09 1,402.33 -1,179.92 2,256,762.52 228,149.64 1.50 1,832.66 MWD+SC+sag(1) 2,920.71 79.40 319.42 1,708.45 1,525.65 1,448.03 -1,219.40 2,256,809.10 228,111.20 1.08 1,893.04 MWD+SC+sag(1) 2,982.56 78.28 319.48 1,720.42 1,537.62 1,494.14 -1,258.84 2,256,856.08 228,072.80 1.81 1,953.71 MWD+SC+sag(1) 3,045.27 77.96 320.37 1,733.33 1,550.53 1,541.09 -1,298.35 2,256,903.91 228,034.36 1.48 2,015.08 MWD+SC+sag(1) 3,107.39 76.31 320.66 1,747.17 1,564.37 1,587.83 -1,336.86 2,256,951.51 227,996.91 2.69 2,075.64 MWD+SC+sag(1) 3,169.71 75.97 320.42 1,762.09 1,579.29 1,634.55 -1,375.31 2,256,999.07 227,959.52 0.66 2,136.14 MWD+SC+sag(1) 3,231.56 75.59 320.74 1,777.29 1,594.49 1,680.86 -1,413.38 2,257,046.23 227,922.50 0.79 2,196.09 MWD+SC+sag(1) 3,294.26 75.82 321.28 1,792.77 1,609.97 1,728.09 -1,451.61 2,257,094.31 227,885.35 0.91 2,256.85 MWD+SC+sag(1) 8/13/2015 2:16:45PM Page 3 COMPASS 5000.1 Build 73 • • Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well Grassim Oskolkoff#8 Project: Ninilchik Unit TVD Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) Site: Grassim Oskolkoff MD Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) Well: Grassim Oskolkoff#8 North Reference: True Wellbore: GO 8 Survey Calculation Method: Minimum Curvature Design: GO 8 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi ND TVDSS +N1-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 3,354.91 75.08 320.91 1,808.01 1,625.21 1,773.77 -1,488.48 2,257,140.81 227,849.52 1.36 2,315.54 MWD+SC+sag(1) 3,415.55 74.86 320.54 1,823.73 1,640.93 1,819.11 -1,525.55 2,257,186.96 227,813.47 0.69 2,374.11 MWD+SC+sag(1) 3,459.97 75.26 321.29 1,835.18 1,652.38 1,852.42 -1,552.61 2,257,220.88 227,787.17 1.86 2,417.02 MWD+SC+sag(1) 3,541.42 74.39 322.56 1,856.50 1,673.70 1,914.30 -1,601.09 2,257,283.83 227,740.10 1.85 2,495.60 MWD+SC+sag(2) . 3,602.60 76.11 322.92 1,872.08 1,689.28 1,961.39 -1,636.91 2,257,331.71 227,705.35 2.87 2,554.70 MWD+SC+sag(2) 3,665.91 77.95 323.14 1,886.29 1,703.49 2,010.68 -1,674.01 2,257,381.82 227,669.37 2.93 2,616.32 MWD+SC+sag(2) 3,726.30 79.02 323.05 1,898.34 1,715.54 2,057.99 -1,709.54 2,257,429.93 227,634.91 1.78 2,675.42 MWD+SC+sag(2) 3,788.02 77.44 322.60 1,910.93 1,728.13 2,106.13 . -1,746.05 2,257,478.88 227,599.49 2.66 2,735.78 MWD+SC+sag(2) 3,850.80 77.82 322.61 1,924.38 1,741.58 2,154.85 -1,783.29 2,257,528.42 227,563.36 0.61 2,797.05 MWD+SC+sag(2) 3,912.58 77.19 321.09 1,937.75 1,754.95 2,202.29 -1,820.55 2,257,576.68 227,527.18 2.61 2,857.34 MWD+SC+sag(2) 3,974.60 76.10 319.46 1,952.08 1,769.28 2,248.70 -1,859.11 2,257,623.94 227,489.67 3.10 2,917.68 MWD+SC+sag(2) 4,035.72 76.56 319.60 1,966.52 1,783.72 2,293.87 -1,897.66 2,257,669.98 227,452.15 0.78 2,977.06 MWD+SC+sag(2) 4,098.95 76.74 319.34 1,981.12 1,798.32 2,340.63 -1,937.64 2,257,717.62 227,413.24 0.49 3,038.58 MWD+SC+sag(2) 4,161.12 77.00 319.10 1,995.24 1,812.44 2,386.48 -1,977.18 2,257,764.35 227,374.73 0.56 3,099.11 MWD+SC+sag(2) 4,222.97 74.77 318.68 2,010.33 1,827.53 2,431.67 -2,016.62 2,257,810.41 227,336.32 3.67 3,159.07 MWD+SC+sag(2) 4,285.24 74.58 318.39 2,026.78 1,843.98 2,476.68 -2,056.38 2,257,856.30 227,297.58 0.54 3,219.10 MWD+SC+sag(2) 4,347.61 74.89 318.68 2,043.20 1,860.40 2,521.76 -2,096.23 2,257,902.27 227,258.77 0.67 3,279.25 MWD+SC+sag(2) 4,409.23 75.34 318.68 2,059.03 1,876.23 2,566.49 -2,135.55 2,257,947.87 227,220.46 0.73 3,338.78 MWD+SC+sag(2) 4,470.77 75.84 318,16 2,074.35 1,891.55 2,611.07 -2,175.10 2,257,993.34 227,181.92 1.15 3,398.35 MWD+SC+sag(2) 4,532.74 76.30 318.29 2,089.27 1,906.47 2,655.93 -2,215.17 2,258,039.08 227,142.87 0.77 3,458.46 MWD+SC+sag(2) 4,593.66 76.69 318.08 2,103.49 1,920.69 2,700.08 -2,254.67 2,258,084.11 227,104.38 0.72 3,517.66 MWD+SC+sag(2) 4,655.72 77.12 317.92 2,117.55 1,934.75 2,745.00. -2,295.11 2,258,129.92 227,064.95 0.74 3,578.06 MWD+SC+sag(2) 4,718.39 76.37 318.86 2,131.92 1,949.12 2,790.61 -2,335.62 2,258,176.43 227,025.48 1.89 3,639.03 MWD+SC+sag(2) 4,779.29 76.74 318.82 2,146.08 1,963.28 2,835.20 -2,374.60 2,258,221.89 226,987.51 0.61 3,698.24 MWD+SC+sag(2) 4,842.50 77.57 318.33 2,160.14 1,977.34 2,881.41 -2,415.38 2,258,269.00 226,947.79 1.52 3,759.84 MWD+SC+sag(2) 4,904.47 78.50 318.61 2,172.98 1,990.18 2,926.79 -2,455.57 2,258,315.28 226,908.63 1.56 3,820.44 MWD+SC+sag(2) 4,966.00 77.75 319.91 2,185.64 2,002.84 2,972.41 -2,494.87 2,258,361.77 226,870.37 2.40 3,880.64 MWD+SC+sag(2) 5,028.87 75.73 321.49 2,200.07 2,017.27 3,019.76 -2,533.63 2,258,409.98 226,832.69 4.04 3,941.82 MWD+SC+sag(2) 5,090.53 75.09 321.62 2,215.60 2,032.80 3,066.50 -2,570.73 2,258,457.54 226,796.65 1.06 4,001.48 MWD+SC+sag(2) 5,152.28 75.21 321.60 2,231.42 2,048.62 3,113.28 -2,607.80 2,258,505.14 226,760.64 0.20 4,061.15 MWD+SC+sag(2) 5,214.48 75.85 321.62 2,246.97 2,064.17 3,160.48 -2,645.20 2,258,553.17 226,724.31 1.03 4,121.36 MWD+SC+sag(2) 5,276.28 76.68 320.99 2,261.64 2,078.84 3,207.34 -2,682.73 2,258,600.86 226,687.85 1.67 4,181.38 MWD+SC+sag(2) 5,338.65 77.25 321.11 2,275.71 2,092.91 3,254.59 -2,720.93 2,258,648.96 226,650.72 0.93 4,242.14 MWD+SC+sag(2) 5,400.16 77.50 320.90 2,289.15 2,106.35 3,301.24 -2,758.70 2,258,696.45 226,614.01 0.53 4,302.15 MWD+SC+sag(2) 5,461.90 77.88 320.86 2,302.31 2,119.51 3,348.04 -2,796.76 2,258,744.09 226,577.02 0.62 4,362.47 MWD+SC+sag(2) 5,523.73 76.17 320.54 2,316.19 2,133.39 3,394.66 -2,834.92 2,258,791.56 226,539.92 2.81 4,422.72 MWD+SC+sag(2) 5,585.62 76.74 320.47 2,330.69 2,147.89 3,441.09 -2,873.18 2,258,838.84 226,502.70 0.93 4,482.89 MWD+SC+sag(2) 5,648.05 77.44 320.70 2,344.64 2,161.84 3,488.11 -2,911.82 2,258,886.71 226,465.14 1.18 4,543.74 MWD+SC+sag(2) 5,708.86 78.14 320.36 2,357.50 2,174.70 3,533.99 -2,949.60 2,258,933.43 226,428.40 1.27 4,603.17 MWD+SC+sag(2) 5,773.41 77.19 320.26 2,371.29 2,188.49 3,582.51 -2,989.87 2,258,982.84 226,389.23 1.48 4,666.23 MWD+SC+sag(2) 8/13/2015 2:16:45PM Page 4 COMPASS 5000.1 Build 73 • • Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well Grassim Oskolkoff#8 Project: Ninilchik Unit TVD Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) Site: Grassim Oskolkoff MD Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) Well: Grassim Oskolkoff#8 North Reference: True Wellbore: GO 8 Survey Calculation Method: Minimum Curvature Design: GO 8 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 5,834.75 77.82 319.80 2,384.56 2,201.76 3,628.41 -3,028.34 2,259,029.59 226,351.80 1.26 4,726.11 MWD+SC+sag(2) 5,896.09 77.57 319.76 2,397.63 2,214.83 3,674.17 -3,067.04 2,259,076.21 226,314.14 0.41 4,786.04 MWD+SC+sag(2) 5,957.65 77.06 319.38 2,411.15 2,228.35 3,719.88 -3,105.99 2,259,122.79 226,276.23 1.02 4,846.10 MWD+SC+sag(2) 6,020.60 76.43 319.50 2,425.58 2,242.78 3,766.43 -3,145.83 2,259,170.23 226,237.45 1.02 4,907.36 MWD+SC+sag(2) 6,082.15 76.31 319.64 2,440.09 2,257.29 3,811.97 -3,184.62 2,259,216.62 226,199.69 0.29 4,967.18 MWD+SC+sag(2) 6,144.38 76.93 319.31 2,454.49 2,271.69 3,857.99 -3,223.96 2,259,263.51 226,161.40 1.12 5,027.71 MWD+SC+sag(2) 6,206.46 77.38 319.30 2,468.29 2,285.49 3,903.88 -3,263.43 2,259,310.28 226,122.98 0.73 5,088.23 MWD+SC+sag(2) 6,269.04 77.63 319.27 2,481.83 2,299.03 3,950.19 -3,303.28 2,259,357.47 226,084.18 0.40 5,149.32 MWD+SC+sag(2) 6,330.89 77.13 319.65 2,495.34 2,312.54 3,996.05 -3,342.51 2,259,404.21 226,045.99 1.01 5,209.67 MWD+SC+sag(2) 6,391.81 76.86 319.91 2,509.05 2,326.25 4,041.38 -3,380.84 2,259,450.38 226,008.69 0.61 5,269.02 MWD+SC+sag(2) 6,454.49 76.87 319.77 2,523.30 2,340.50 4,088.03 -3,420.21 2,259,497.90 225,970.39 0.22 5,330.06 MWD+SC+sag(2) 6,516.51 77.11 319.89 2,537.26 2,354.46 4,134.20 -3,459.18 2,259,544.94 225,932.46 0.43 5,390.49 MWD+SC+sag(2) 6,577.61 78.14 319.81 2,550.35 2,367.55 4,179.82 -3,497.67 2,259,591.41 225,895.01 1.69 5,450.17 MWD+SC+sag(2) 6,637.83 78.12 319.58 2,562.74 2,379.94 4,224.76 -3,535.79 2,259,637.20 225,857.91 0.38 5,509.10 MWD+SC+sag(2) 6,702.23 77.25 320.01 2,576.47 2,393.67 4,272.81 -3,576.40 2,259,686.16 225,818.39 1.50 5,572.01 MWD+SC+sag(2) 6,764.69 75.55 320.22 2,591.16 2,408.36 4,319.39 -3,615.33 2,259,733.60 225,780.52 2.74 5,632.72 MWD+SC+sag(2) 6,826.98 72.79 320.63 2,608.15 2,425.35 4,365.58 -3,653.51 2,259,780.63 225,743.39 4.48 5,692.64 MWD+SC+sag(2) 6,889.43 70.11 320.55 2,628.02 2,445.22 4,411.32 -3,691.09 2,259,827.21 225,706.85 4.29 5,751.84 MWD+SC+sag(2) 6,951.28 67.46 320.38 2,650.40 2,467.60 4,455.78 -3,727.79 2,259,872.49 225,671.16 4.29 5,809.49 MWD+SC+sag(2) 7,013.34 64.26 320.01 2,675.77 2,492.97 4,499.29 -3,764.04 2,259,916.79 225,635.90 5.18 5,866.12 MWD+SC+sag(2) 7,075.57 61.54 319.50 2,704.12 2,521.32 4,541.57 -3,799.82 2,259,959.87 225,601.08 4.43 5,921.51 MWD+SC+sag(2) 7,138.33 58.78 319.87 2,735.34 2,552.54 4,583.07 -3,835.04 2,260,002.15 225,566.80 4.43 . 5,975.94 MWD+SC+sag(2) 7,199.79 55.31 319.71 2,768.77 2,585.97 4,622.45 -3,868.33 2,260,042.27 225,534.41 5.65 6,027.50 MWD+SC+sag(2) 7,261.02 52.40 320.37 2,804.88 2,622.08 4,660.34 -3,900.09 2,260,080.87 225,503.51 4.83 6,076.94 MWD+SC+sag(2) 7,324.96 49.24 321.60 2,845.27 2,662.47 4,698.84 -3,931.29 2,260,120.05 225,473.18 5.16 6,126.49 MWD+SC+sag(2) 7,386.90 46.85 322.11 2,886.68 2,703.88 4,735.06 -3,959.74 2,260,156.91 225,445.55 3.91 6,172.53 MWD+SC+sag(2) 7,435.13 44.51 322.13 2,920.38 2,737.58 4,762.29 -3,980.93 2,260,184.61 225,424.99 4.85 6,207.02 MWD+SC+sag(3) 7,509.52 42.41 322.71 2,974.37 2,791.57 4,802.84 -4,012.14 2,280,225.85 225,394.70 2.87 6,258.15 MWD+SC+sag(3) 7,572.40 39.89 320.20 3,021.72 2,838.92 4,835.21 -4,037.90 2,260,258.79 225,369.68 4.79 6,299.50 MWD+SC+sag(3) 7,634.37 36.56 319.62 3,070.39 2,887.59 4,864.54 -4,062.58 2,260,288.67 225,345.66 5.40 6,337.84 MWD+SC+sag(3) 7,696.93 32.79 319.58 3,121.83 2,939.03 4,891.64 -4,085.64 2,260,316.28 225,323.21 6.03 6,373.42 MWD+SC+sag(3) 7,758.30 29.62 321.88 3,174.32 2,991.52- 4,916.23 -4,105.79 2,260,341.32 225,303.63 5.52 6,405.21 MWD+SC+sag(3) 7,819.88 2643 323.95 3,228.72 3,045.92 4,939.21 -4,123.19 2,260,364.68 225,286.74 5.72 6,434.01 MWD+SC+sag(3) 7,881.77 23.10 321.16 3,284.96 3,102.16 4,959.74 -4,138.86 2,260,385.55 225,271.54 5.39 6,459.80 MWD+SC+sag(3) 7,943.98 19.68 320.11 3,342.88 3,160.08 4,977.28 -4,153.24 2,260,403.42 225,257.56 5.53 6,482.49 MWD+SC+sag(3) 8,005.57 16.89 321.43 3,401.35 3,218.55 4,992.24 -4,165.47 2,260,418.64 225,245.67 4.58 6,501.81 MWD+SC+sag(3) 8,067.40 14.13 319.92 3,460.92 3,278.12 5,005.04 -4,175.93 2,260,431.67 225,235.50 4.51 6,518.34 MWD+SC+sag(3) 8,129.26 11.93 315.07 3,521.19 3,338.39 5,015.34 -4,185.31 2,260,442.19 225,226.36 3.97 6,532.26 MWD+SC+sag(3) 8,191.79 10.06 308.68 3,582.57 3,399.77 5,023.33 -4,194.14 2,260,450.37 225,217.71 3.57 6,544.05 MWD+SC+sag(3) 8,253.63 8.90 318.80 3,643.57 3,460.77 5,030.31 -4,201.51 2,260,457.51 225,210.50 3.28 6,554.12 MWD+SC+sag(3) 8/13/2015 2:16:45PM Page 5 COMPASS 5000.1 Build 73 lip 410 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well Grassim Oskolkoff#8 Project: Ninilchik Unit TVD Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) Site: Grassim Oskolkoff MD Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) Well: Grassim Oskolkoff#8 North Reference: True Wellbore: GO 8 Survey Calculation Method: Minimum Curvature Design: GO 8 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,315.22 7.25 318.61 3,704.55 3,521.75 5,036.81 -4,207.21 2,260,464.14 225,204.94 2.68 6,562.77 MWD+SC+sag(3) 8,377.22 7.60 319.42 3,766.03 3,583.23 5,042.86 -4,212.47 2,260,470.31 225,199.82 0.59 6,570.78 MWD+SC+sag(3) 8,439.01 6.80 318.87 3,827.33 3,644.53 5,048.72 -4,217.53 2,260,476.28 225,194.89 1.30 6,578.52 MWD+SC+sag(3) 8,501.19 6.78 322.55 3,889.07 3,706.27 5,054.40 -4,222.18 2,260,482.07 225,190.37 0.70 6,585.87 MWD+SC+sag(3) 8,565.08 7.19 324.86 3,952.49 3,769.69 5,060.67 -4,226.78 2,260,488.43 225,185.92 0.78 6,593.62 MWD+SC+sag(3) 8,626.12 5.97 320.01 4,013.13 3,830.33 5,066.22 -4,231.02 2,260,494.08 225,181.80 2.19 6,600.61 MWD+SC+sag(3) 8,688.09 5.86 317.67 4,074.77 3,891.97 5,071.03 -4,235.22 2,260,498.98 225,177.71 0.43 6,606.99 MWD+SC+sag(3) 8,751.36 6.16 317.86 4,137.69 3,954.89 5,075.94 -4,239.67 2,260,503.99 225,173.37 0.48 6,613.61 MWD+SC+sag(3) 8,812.13 6.45 316.91 4,198.09 4,015.29 5,080.85 -4,244.19 2,260,509.00 225,168.96 0.51 6,620.27 MWD+SC+sag(3) 8,874.04 6.45 320.43 4,259.61 4,076.81 5,086.07 -4,248.78 2,260,514.32 225,164.49 0.64 6,627.22 MWD+SC+sag(3) 8,936.06 6.49 323.01 4,321.23 4,138.43 5,091.55 -4,253.11 2,260,519.90 225,160.29 0.47 6,634.21 MWD+SC+sag(3) 8,998.30 5.98 323.48 4,383.11 4,200.31 5,096.97 -4,257.16 2,260,525.41 225,156.36 0.82 6,640.96 MWD+SC+sag(3) 9,060.88 5.73 322.13 4,445.36 4,262.56 5,102.05 -4,261.01 2,260,530.58 225,152.62 0.46 6,647.33 MWD+SC+sag(3) 9,122.26 5.52 322.62 4,506.44 4,323.64 5,106.82 -4,264.69 2,260,535.42 225,149.06 0.35 6,653.35 MWD+SC+sag(3) 9,184.17 6.56 323.34 4,568.01 4,385.21 5,112.02 3,268.61 2,260,540.71 225,145.26 1.68 6,659.85 MWD+SC+sag(3) 9,246.55 6.99 324.60 4,629.95 4,447.15 5,117.97 -4,272.93 2,260,546.76 225,141.07 0.73 6,667.20 MWD+SC+sag(3) 9,308.12 6.91 325.18 4,691.07 4,508.27 5,124.07 -4,277.22 2,260,552.95 225,136.92 0.17 6,674.62 MWD+SC+sag(3) 9,370.53 6.84 324.21 4,753.03 4,570.23 5,130.16 -4,281.53 2,260,559.14 225,132.74 0.22 6,682.07 MWD+SC+sag(3) 9,453.48 6.66 321.97 4,835.41 4,652.61 5,137.96 -4,287.39 2,260,567.07 225,127.06 0.38 6,691.80 MWD+SC+sag(3) 9,515.57 6.62 321.69 4,897.08 4,714.28 5,143.60 -4,291.82 2,260,572.81 225,122.76 0.08 6,698.98 MWD+SC+sag(3) 9,576.89 6.67 323.30 4,957.99 4,775.19 5,149.23 -4,296.14 2,260,578.54 225,118.56 0.31 6,706.07 MWD+SC+sag(3) 9,638.77 6.63 324.07 5,019.45 4,836.65 5,155.01 -4,300.39 2,260,584.40 225,114.45 0.16 6,713.22 MWD+SC+sag(3) 9,701.14 6.39 325.82 5,081.42 4,898.62 5,160.79 -4,304.45 2,260,590.28 225,110.52 0.50 6,720.27 MWD+SC+sag(3) 9,762.98 6.41 326.80 5,142.88 4,960.08 5,166.53 -4,308.27 2,260,596.10 225,106.83 0.18 6,727.12 MWD+SC+sag(3) 9,825.51 6.19 327.66 5,205.03 5,022.23 5,172.30 -4,311.99 2,260,601.95 225,103.24 0.38 6,733.93 MWD+SC+sag(3) 9,887.33 6.39 327.38 5,266.48 5,083.68 5,178.01 -4,315.63 2,260,607.74 225,099.73 0.33 6,740.65 MWD+SC+sag(3) 9,949.35 6.47 328.07 5,328.11 5,145.31 5,183.88 -4,319.33 2,260,613.70 225,096.16 0.18 6,747.54 MWD+SC+sag(3) 10,011.92 6.07 328.41 5,390.30 5,207.50 5,189.69 -4,322.93 2,260,619.59 225,092.69 0.64 6,754.31 MWD+SC+sag(3) 10,073.63 6.08 329.31 5,451.66 5,268.86 5,195.28 -4,326.31 2,260,625.25 225,089.44 0.16 6,760.76 MWD+SC+sag(3) 10,135.51 5.99 328.97 5,513.20 5,330.40 5,200.87 -4,329.65 2,260,630.91 225,086.23 0.16 6,767.19 MWD+SC+sag(3) 10,158.91 5.82 327.78 5,536.48 5,353.68 5,202.92 -4,330.91 2,260,632.99 225,085.02 0.90 6,769.57 MWD+SC+sag(3) - 10,200.00 5.82 327.78 5,577.36 • 5,394.56 5,206.44 -4,333.13 2,260,636.56 225,082.88 0.00 6,773.70 PROJECTED to TD Checked By: °i4n A1i"O1`O"' o..m..n,,,u.u.. Approved By: cary.taylor@halliburton.com te,a=;.;,,:: Date: 8/13/2015 2:16:45PM Page 6 COMPASS 5000.1 Build 73 S • Hilcorp Energy Company Composite Report Well Name: NINU GO 08 Field: Ninilchik County/State: ,Alaska (LAT/LONG): =vation(RKB): 18 API#: 50-133-20651-00-00 Spud Date: 7/23/2015 Job Name: 1511166D GO 08 Drilling Contractor AFE#: 1511166D AFE$: Activity Date Ops Summary 7/18/2015 No activity.;Rig down mud pumps.Pressure wash derrick.Clean cellar area and mud tanks.Remove bales and saver sub.Break down rotary tongs for inspection. R/D electric lines.;Remove Kelly hose,service loop and torque bushing.Lay down TDS.Rig down gas buster,pump module and pits.Prepare and scope derrick down. 7/19/2015 Cont to spool up cords and hoses on rig modules,RD Handy Berm.Total Safety on location at 07:30 and RD gas detection equipment.Peak on location at 08:00 to tear out rig.Held PJSM with rig crew;and Peak crew.Load out connex',gen 3.Move HPU skid,move pump skids and pit modules.Load out exposed mats and poor boy degasser.Spot crane and pick centrifuge.;Spot crane and pick centrifuge.Move gen 1-2 skid,spool off drill line,lay over beaver slide,lay derrick over and un-pin hydraulic rams.Dis-connect brake linkage and scope down doghouse.Prep;derrick to LD board windwalls and pick derrick off carrier.Prep water tank/doghouse for load out.Move water tank,spot cranes.Pick BOP stack from cellar,RU on board windwalls and LD.;Pick iron roughneck off floor.Cont sending various loads to GO Pad.RU to pick derrick off carrier.;Load out carrier combo,subs,pony subs,rig mats.Clean up location.Rig is 100%rigged down.;Lay down felt,containment Herculite.Spot matting boards on new location.Set pony subs,IR HPU,test pump and kill hose.Prepare all modules for transport.Continue clean up of Blossom location. 7/20/2015 Cont to clean up felt and liner on Blossom#1.Peak on loc at 06:30.Held PJSM and transported sub base at 07:15.Load and transported pit modules,cranes, derrick,pump and gen skids.Spot cranes at;Go Pad and set sub base on pony walls,set carrier,set derrick,raised derrick board windwalls,set iron roughneck,set water tank/doghouse,set HPU skid,set gen 1-2 skid,set both pump skids,set;all three pit modules and lay felt for catwalk liner.Also set well house over GO#1 (live)and Go#4(dead)with crane and Production Operators on location.;Prepare and raise derrick.Connect brake linkage.Raise pit roof sections. Set centrifuge and gas buster.Begin tieing in pits and pumps suction and discharge lines.;Spool up drill line.Prepare derrick to scope up.Install torque tube.Scope up derrick. Spot contrator conex's.Continue hooking up utilities(electric,water,etc.)throughout rig package. 7/21/2015 Continue rigging up. Scope derrick. Change oil and filters in TDS hydraulic system. Purge same. Hook up svc loop and begin hooking up kelly hose. Demob camp/offices from blossom and mob to GO#8.;Set and R/U camp/offices,change shack. Hook up svc lines and establish coms. Power up 3rd party shacks and R/U associated equipment. Nipple up 21 1/4"annular,Diverter"T"and koomey Iines.;Attempt to fill pits with water well onsite. Unable to obtain reasonable flow rate. Diagnose,determined water pump to be undersized. Kraxberger will replace pump. Haul water from state pad.;Total safety installed and tested H2S 10/20, LEL 20/40 alarms. Handy berm installed containment. Site assessment by Dave Kerkvliet(Lead Field Operator)for camp layout(good).;Dress both pumps w/5 1/2"liners. Demob remaining equipment from Blossom. Cleanup remaing containment. Install original cellar grating;State notification sent @ 21:15 via web form. Confirmation letter recieved for 21:20 7/22 diverter test.;Torque bolts on diverter flanges.Function test mix pumps.Install trip tank pump.Function test ESD's. Install T-bar on torque tube. Install ball valve,saver sub and clamps on TDS.;R/U Pason and remote lines for catwalk/choke house.Connect IR hydraulics.Finish N/U diverter system. Install bales.R/U rotary tongs.Pressure test surface lines at 3300 psi.;Rig is 90%rigged up 7/22/2015 4 pt annular in cellar. Hook up koomey lines to annular and knife valve. Function test diverter system. Build spud mud. Hook up mudloggers svc power and air. Finish pre rig acceptance checklist.;Rig accepted @ 12:00 hrs.;Continue build spud mud. Load and tally drill pipe. Set 15.375"wear bushing(RILDS). RIH and tag bottom of conductor @ 133'MD.;Cut and slip 108'/ drilling line. Inspect line and anchors. Reset COM.;Load strap and tally pipe. P/U 4 1/2",16.6#,S 135 drill pipe. Drift all pipe w/2.56"drift.Stand back in denick.;Repair hydraulic leak on TDS service loop hose.;Continue load,strap and tally pipe. P/U 4 1/2",16.6#,S 135 drill pipe. Drift all pipe w/2.56"drift.Stand back in derrick.;Pick up 16 joints HWDP. Stand back in derrick.;Function tested diverter with 4 1/2"joint DP and 950 psi on annular.Knife valve open time=23 seconds,annular closure time=44 seconds.Perform Koomey draw down test.Witness waived by Jim Regg.;P/U up directional tools(bit-motor-dm collar-tm collar-bottle neck xo)tagged bottom @ 133'.;Hauled 0 bbls cuttings to G&I Total cuttings hauled=0 bbls Hauled 0 bbls Class II fluid to G&I Total Class II fluid hauled=0 bbls 7/23/2015 Flood conductor and check for leaks(no leaks).;Spud well. Drtg F/133'-T/299'MD. 500 gpm,1510 psi on,40 diff,53%flow,35 rpm,4k tq on,2k tq off,32k up 31k dn. Drilled out of conductor shoe at reduced rate to minimize washout.;TOH F/299'(3)stands and pick up jars. TIH and tag up @ 296'(3'fill).;Continue drig ahead F/299'-T/919'MD. 3-12k WOB,500 gpm,1810 psi off,85 diff,40 rpm,4.4k tq on,2k tq off. 56k up,49k dn. 2 units BGG. 78 ft/hr avg ROP.;Continue drig ahead F/919'-T/1167"MD. 3-12k WOB,580 gpm,1880 psi off,100 diff,50 rpm,4.4k tq on,2k tq off. 60k up,49k dn. 3 units BGG. 71 ft/hr avg ROP. Pump 20 bbl Hi-vis sweep on;last stand with 25%increase in cuttings and sweep coming back on time.Monitor well(static).;POOH 1167'to 270'.10K overpull at 972'. No swabbing.;Level derrick(slips difficult to set).Service rig.;RIH 270'to 970'on elevators.Set down 15K..Kelly up and wash through 970'to 975'without issue.RIH on elevators 975'to 1107'.Safety ream 1107'to 1167'.No fill noted.;Continue ddg ahead F/1167'-T/1475'MD. 3-12k WOB,580 gpm,1880 psi off, 100 diff,50 rpm,6.4k tq on,2k tq off. 60k up,49k dn. 3 units BGG. 56 ft/hr avg ROP.;Hauled 540 bbls cuttings to G&I Total cuttings hauled=540 bbls Hauled 0 bbls Class II fluid to G&I Total Class II fluid hauled=0 bbls Distance to the plan:14.63'High,1.34 Left 7/24/2015 Continue drig ahead F/1475'-T/1787'MD. 10-20k WOB,565 gpm,1880 psi off,100 diff,50 rpm,6k tq offn,8.9k tq on. 60k up,50k dn,53k rot. 3 units BGG. 52 ft/hr avg ROP.;Pump 20 bbl hi vis sweep @ 1612'MD. Est 25%increase in cuttings. Sweep came back on time.;Continue drig ahead F/1787'-T/2096'MD. 10-25k WOB,550 gpm,2000 psi on,200 diff,48%flow,60 rpm,9k tq on,6.5k tq off. 60k up,50k dn. 3 units BGG. 52 ft/hr avg ROP.;Pump 20 bbl hi vis sweep @ 1903'MD. Est 50%increase in cuttings. Sweep came back 400 stks eariy.;Continue drig ahead F/2096'-T/2407'MD. 10-25k WOB,550 gpm,2000 psi on, 200 diff,48%flow,60 rpm,9k tq on,6.5k tq off. 60k up,50k dn. 3 units BGG. 48 ft/hr avg ROP.;Pump 20 bbl Hi-Vis Wallnut sweeps at 1903',2184',2314'and 2357'with 50%-100%increase in cuttings(clay)and 400-500 strokes early.;Attempt to survey before short trip.Bell nipple and flow line plugged off with clay. Clear same twice and circulate at 500 GPM/2000 psi until hole is clean.Survey.Monitor weII.;POOH from 2407'to 1102'.Had to back ream 2330'-2275',2175'- 2151'and 2084'-2045'due to 30K overpulls.When able to pull on elevators encountered no swabbing.;Monitor well while servicing rig.;Hauled 306 bbls cuttings to G&I Total cuttings hauled=846 bbls Hauled 584 bbls Class II fluid to G&I Total Class II fluid hauled=584 bbls Distance to the plan:1.89 Low,9.54 Right • • 7/25/2015 RIH on elevators 1102'to 2092'MD. Tripped clean.;TIH F/2092'-T/2407'MD.Pick up 10 jts HWDP (push pipe)due to insufficient hook load for sliding. Drift (2.56")pipe. Fill pipe and wash down last stand. No fill note.Hole took proper disp.;CBU @ 2407'rot&reciprocating pipe. Pump @ 273 gpm,711 psi,29%flow, 27 rpm,6.3k tq off,3 units bgg. Pump hi vis/nut plug sweep and C/O charge pump#2 MP(leaking mech seal).;Drig F/2407'-T/ 2838. 10-25k WOB,550 gpm, 2350 psi on,150 diff,48%flow,60 rpm,9k tq on,6.5k tq off. 60k up,50k dn. 3 units BGG. 43.1 ft/hr avg ROP.;Drlg F/2838'-T/ 3265'. 10-25k WOB,550 gpm, 2350 psi on,150 diff,48%flow,60 rpm,9k tq on,6.5k tq off. 60k up,50k dn. 3 units BGG. 35.6 ft/hr avg ROP.;2,588'and pumped tandem Lo-Vis/Lo-weight followed by Hi-Vis weighted sweeps-10%increase in cuttings(came back 340 strokes early).;Drilling through mostly clay all day long-packed off possum belly a few times. Pumped 20 bbl Hi-Vis/WALLNUT/DRILL-N-SLIDE sweep @ 2,899'-50%increase in cuttings(clay balls,500 stks early);Pumped 20 bbl Hi- Vis/WALLNUT/CON-DET sweep @ 2,988'-10%increase in cuttings,came back 800 strokes early.;Hauled 194 bbls cuttings to G&I Total cuttings hauled=1040 bbls Hauled 506 bbls Class II fluid to G&I Total Class II fluid hauled=1090 bbls Distance to the plan:16.84 High,8.55 Left 7/26/2015 Dig F/3265'-T/ 3500'MD/1845'TVD(TD). 10-25k WOB,550 gpm,2350 psi on,150 diff,48%flow,60 rpm,9k tq on,6.5k tq off. 60k up,50k dn. 3 units BGG. 47 ft/hr avg ROP.;Continue dealing with significant amount of clay at surface. Plugged off flowline and possum belly.;Circulate and condition hole @ 3500'MD. Pump @ 550 gpm,2260 psi,45%flow,35 rpm,7k tq off,3 units bgg.;TOH F/3500'-T/3385'MD. Overpull 30k @ 3385',unable to work past on elevators. Backream out F/3385'-T/2400'MD. Pump @ 500 gpm,30 rpm,7k.;TOH on elevators F/2400'-T/735'MD. Pulled clean w/hole taking proper displacement.;CBU @ 735'rot&reciprocating pipe. Pump @ 530 gpm,1550 psi. Clean and clear rig floor.;Rig service. Drawworks,Top drive and blocks.;TIH F/ 735'-T/3500'MD. Hole took calculated displacement.;Circulate hole clean at 540 GPM/2100 psi. Circulate Hi-Vis wallnut sweep around bringing back 10% excess and 42 bbls early.Monitor well.Static.;POOH 3500'to BHA(733.61')without issue.No significant over pulls and no swabbing.P/U 62K,SIO 45K. Hole fill good.;Lay down BHA.Bit and stabilizer balled up with clay.Grade bit. Photos in o-drive.;Clear/clean rig floor.Pull wear bushing.Had to flush profile with'Johnny Whacker'due to clay/cuttings build up.;Hauled 140 bbls cuttings to G&I Total cuttings hauled=1180 bbls Hauled 500 bbls Class II fluid to G&I Total Class II fluid hauled=1590 bbls Distance to plan:9.24 High,4.58 Left at 3500'MD/1845 7/27/2015 Pull wear bushing. Clean and clear rig floor.;PJSM, R/U Weatherford. C/O bails,elevators,spiders,slips and R/U power tongs. Load pipe on racks.;PJSM, M/U 10 3/4"shoe track(Bakertok). Check floats(tested good).Run 10 3/4",45.5#,L-80,BTC casing as per detail F/0'-T/2017'MD(btm of build). No issues. Good returns during trip.;Circulate and condition mud @ 2017'MD. Reciprocate pipe,stage pumps up to 6 BPM,75 psi,23%flow with no losses. Pumped a total of 1x casing volume.;Continue run 10 3/4",45.5#,L-80,BTC casing as per detail F/2017'-T/3492'MD. No issues. Good returns during trip. 9 bbl loss over calculated for total trip.;M/U landing jt w/hgr, SIO and landout on depth as per Cameron rep @ 3492'MD w/32k string wt on hanger. 172k up. Pick up and clear wellhead profile with fluted hanger.;Circulate and condition mud @ 3492'MD. Stage pumps up to 6 BPM,119 psi,23%flow. Finish racking in SLB cmtrs and bring cmt tools to rig floor. Circulated a total of 235 bbls.;Shut down pumping. R/D circulating swedge and M/U SLB 3K dual drop plug head. R/U hardlines F/SLB and tie in with rig. SLB pump 10 bbls water to clear lines. Turn over to rig.;Rig continue circulating and conditioning mud. Pump @ 6 BPM,130 psi,23%flow. Circulated a total of 350 bbls. Hold PJSM for cementing.;Schlumberger pump 5 bbls H2O.Test lines at 1000/3000 psi.Rig pump 45 bbls MudPush II at 150 GPM/70 psi.Drop bottom plug.Schlumberger pump 383 bbls 12 ppg lead cement at 5 BPM/140 psi.;Pump 76.7 bbls 15.2 ppg tail cement at 5 BPM/400 psi.Drop top plug.Chase with 332 bbls 9.4 ppg mud.Did not bump plug.500 psi final circulating pressure.Hold for 5 minutes.;Bteed back.75 bbls.Floats holding.CIP at 2400 hrs.Had 100%returns throughout job.Reciprocated pipe 7'until lead cement was pumped,then landed in hanger.P/U 140K,S/O 54K.;Dumped 208 bbls cement to cellar through 4"valves. Used retarder and removed with vac trucks as fast as possible.Cement did fill up to+-1'from top of cellar during process.;Rig down cement head and cement lines.Finish vacuuming cement out of cellar and cleaning cellar box.Noticed that 4"lines were plugged.;Remove landing joint.Cement caked on running tool.Riser would not drain.;Rig down diverter to be able to clear/clean casing hanger and profile to be able to install packoff.;Hauled 0 bbls cuttings to G&I Total cuttings hauled=1180 bbls Hauled 520 bbls Class II fluid to G&I Total Class II fluid hauled=1907 bbls Distance to plan:9.24 High,4.58 Left at 3500'MD/1845 7/28/2015 Nippling down diverter"T". Clean pits. Continue hauling cement returns to G&I.;Clean residual cement from top of hanger and well head profile for packoff. M/U packoff to landing jt dress seals and set as per Cameron rep.RILDS.;Remove excess cement from btm of cellar and from around piping in cellar(est 2 cu/yds).;Nipple up 16 3/4"3M x 11"5M Seaboard multi bowl wellhead. Test 16 3/4"3M connection&void to 3K(test good)w/15 min hold. Test witnessed-Shane Barber[Cleaning mud pitsj.;lnstall 2'spacer spool,11"5M T3 Energy BOP equipment. M/U choke line,kill line,bell nipple,pollution pan,stack turn buckles, accumulator lines,flowline and fill up Iines.;Lower LDS=18.85', Upper LDS=17.9';Flow nipple was to long so it was removed so it could be cut off while testing. Function test BOPs and Rig up gas buster while rigging up to test.;Start testing BOPs on 4 1/2.;Hauled 0 bbls cuttings to G&I Total cuttings hauled=1180 bbls Hauled 1090 bbls Class II fluid to G&I Total Class II fluid hauled=2997 bbls Distance to plan:9.24 High,4.58 Left at 3500'MD/1845 7/29/2015 Finish shell test. Test 11"5M T3 Energy BOP equipment. Test#1-Annular(250/2500). #2-Upr pipe,CM valves 1,3,4,5,7,Mez kill,Hyd IBOP. Test#3-Upr pipe,CM 2,4,5,6,8;kill HCR,Dart,Iwr IBOP. Test#4-Manual choke and Electric choke. Test#5-upr pipe,CM 7,9,11,13,inside kill,TIW valve. Test#6-Upr pipe,dart,inside kill and choke HCR.;Test#7-Upr pipe,dart,inside choke and inside kill. Test#8-Lwr pipe and dart.;Test#9-Drawdown: 3100 psi start,1600 psi drawdown,18 sec/200 psi increase,86 sec full charge. 2750 psi (4)bottle avg. Test#10-blinds,CM 7,10,12 and inside kill.;R/D test equipment. All BOP equipment tested 250 low(5min)/4000 high(10 min)except annular as noted above. Jim Regg waived witness via email. See"0"drive.;Install flow nipple. Bring tools to rig floor. Set 10"ID(26"long)wear bushing. RILDS.;M/U BHA#2-C/O slick sleeve to 9.625"4 bld mtr stab and tq. P/U 9 7/8"Varel 516. Tq 18k. M/U MWD tools and shallow pulse test 406 gpm,720 spp(test good). PJSM,Install sources.;TIH F/140'-T/424'MD out of derrick w/HWDP and jars.;RIH w/4 extra stds of HWDP and POH laying dn same.;RIH picking up 4 1/2 DP.Fill pipe at 2744'.;Continue RIH picking up DP.Started taking wt at 3316'.;MU topdrive and was down to 3333'where we tagged good cmt.Circ out contaminated thick mud at a slow rate of 48 spm and 450 psi.Cleaned up after 1 1/2 bottomsup;Test csg to 2600 psi for 30 min on a chart.Lost 100 psi in first 10 min then held sotid.;Drill cmt and rubber plugs f/3333't/float at 3409'.20 RPM,9.5 tq,5k bit wt,150 spm, 450 GPM,1500 psi.;Drill float f/3409't/3410'.Clean out firm cmt to shoe at 3491'.Drill shoe,clean out rat hole and drill 20'of new hole to 3520'. Increased flow rate to 500 GPM to get throught float and shoe.;Circ and condition mud for FIT.;Hauled 0 bbls cuttings to G&I Total cuttings hauled=1180 bbls Hauled 95 bbls Class II fluid to G&I Total Class II fluid hauled=3092 bbls Distance to plan:9.24 High,4.58 Left at 3500'MD/1845 • 7/30/2015 Circulate and condition 9.3 mud In/Out prior to FIT.;POOH F/3520'-T/3456'MD. Attempt 12 EMW FIT(Test inconclusive). R/D test equipment.TIH to 3520' MD. Discuss with drilling engineer.;Drill ahead F/3520'-T/3530'MD,1853'ND. 505 gpm,1398 psi,21 diff,2-3k wob,23 rpm,8k tq. Displace w/9.3 ppg 6% KCL mud while drilling ahead.;POOH F/3530-T/3456'MD. R/U test equipment and perform FIT. Psi up to 260 psi and shut in. Psi drop to 220 psi over 16 min then levels off. 11.6 EMW.;Discuss with drilling engineer. Decision made to drill ahead.;Drill ahead F/3530'-T/3855'MD. 5k wob,544 gpm,1720 psi off,40 psi diff,40%flow,85 rpm,7k tq off,9k tq on,5 units bgg.;Rotary Drill 9 7/8 hole f/3855'U 3890'.Slide Drill f/3890'U 3915'.Rotary Drill f/3915'U 3953'.[WOB=5k, RPM=85,TQ=10300,GPM=544,Pump press=1800,Diff=110.];Saver sub broke in wrong place at connection.Remove clamp,re-torque sub,and install clamp back on.;Slide Drill f/3953'U 3978'.Rotary Drill f/3978'U 4076'.[WOB-5,RPM=85,TQ=10300,GPM=544,Pump press=1800,Diff=110.];Rotary Drill f/4076 U 4201'.Pumped 20 bbl low vis followed by 20 bbl high vis high wt sweep while rotating dn.Slide drill f/4201't/4221',Rotary Drill f/4221'U 4331'. W0B=5,RPM=85, TQ=9800,;GPM=544,SPP=1800,Diff=110.Sliding hrs=2.10 Rotating hrs=8.14;Hauled 57 bbls cuttings to G&I Total cuttings hauled=1237 bbls Hauled 543 bbls Class II fluid to G&I Total Class II fluid hauled=3635 bbls Distance to plan:9.40 High,11.93 Right at 4161'MD/1995 7/31/2015 Drill ahead F/4331'-T/4819'MD,2157'ND. 7K wob,88 rpm,9k tq off,10k tq on,550 gpm,1770 psi off,80 psi diff,44%Flow,39 units bgg. 4.14 rot hrs,.52 sld hrs.;Circulate and condition hole @ 4819'MD. Reciprocate and rotate while circulating. Pump @ 550 gpm,1770 psi,44%flow. Circulated a total of 640 bbls.;Pump tandem sweeps-20 bbls 9.0#with 37 vis/20 bbl 11.3#with 250 vis. Came back on time w/est 50%increase in cuttings. Shut down and monitor well (static).;TOH F/4819'-T/3690'MD. Tight spots 4355'and 3786'. Work past tight spots with no pump or rotary. Hole took 2 bbls over calculated displacement.;Pulled tight @ 3690'MD.Backream F/3690'-T/3492'(10 3/4"shoe)at 518 gpm,1590 psi,42%flow,60 rpm,8k tq.;Service rig.Change out saver sub w/proper size so clamp wont slip.Change oil in TD gear box.;RIH picking up 20 jts of 4 1/2 DP.Continue RIH out of derrick to 4345'where we sat dn on a tight spot at 4345'.MU TD and wash through a couple times and it cleared up.;Continue RIH to 4761'w/no more tight spots.MU TD and wash to bottom at 4819'w/no fill.;Rotary drill f/4819 U 4943'.Slide f/4943'U 4968'.Rotary drill f/4968 U 5005', WOB=5,RPM=90,TQ=10,200.GPM=550,SPP=2050,DIFF=80,BGG=13.;Slide f/5005'U 5033'.Rotary drill f/5033'U 5108'.;PU and change out a swab on#2 mud pump.Continue reciprocate pipe and circ w/#1 pump.;Rotary drill f/5108 U 5300'. WOB=5,RPM=90,TQ=10,250,GPM=550,SPP=2055,DIFF=80,BGG=13.;Hauled 87 bbls cuttings to G&I Total cuttings hauled=1324 bbls Hauled 188 bbls Class II fluid to G&I Total Class II fluid hauled=3823 bbls Distance to plan:2.76 High,9.33'left at 4842.5'/MD 2060.14;Drilling hrs last 24 hrs=12.26 Sliding hrs last 24 hrs=1.69 Rotating hrs last 24 hrs=10.57 8/1/2015 Drill ahead F/5300'-T/5874'MD,2393'TVD. 7K wob,90 rpm,9.3k tq off,10.5k tq on,550 gpm,1850 psi off,140 psi diff,46%Flow,22 units bgg,10.2 ECD. Centrifuge went down.;Circulate and condition mud(full drilling rate) @ 5874'due to inability to manage mud wt while drilling ahead. Mud wt increased to 9.6 heavy and centrifuge still inoperable.;Troubleshoot Centrifuge. Found conveyor speed pressure switch had failed.;Monitor well(6 BPH static loss rate). Changed shaker screens to 200s to assist in cutting mud wt while short tripping.Circ active over shakers.;Short trip f/5874'U4577'.Had to work through tight spots f/5360'U 5330' and 4846'U 4790'.Worked through tight spots by pulling 40k over and breaking back. Up wt=98 and dn wt=38.;Service rig and got centrifuge back on line at 2100 hrs.Mud wt in active back to 9.5 ppg.;RIH U 5815'moving HWDP back on top of the string for push pipe.No tight spots encountered.;Wash last std dn f/5815'U 5874'with no fill.Changed shaker screens back to 3-140s and 1-175 on each shaker so we can bring the flow rate up.;Rotary drill f/5874 U 5924'.447 GPM,1500 Psi,80 RPM,134 Mtr RPM,11k Tq on,9.5k TO off,ECD 10 ppg,BGG 15 units,Avg ROP 33.3'/hr,40%flow. Centrifuge went dn again at 23:30.;Rotary drill f/5924'U 6018'.500 GPM,1740 Psi,90 RPM,150 Mtr RPM,11k TQ on,9.8k TQ off,ECD 10.06,BGG 16 units,Avg ROP 31'/hr,42%flow.;Rotary drill f/6018'U 6124'.450 GPM,1425 Psi,90 RPM,130 Mtr RPM,11 k TQ on,10k TQ off,ECD 10,BGG 34 units,Avg ROP 35'/hr, 37%flow. Finally got centrifuge running at 0500 hrs.Mud wt 9.5;Hauled 88 bbls cuttings to G&I Total cuttings hauled=1412 bbls Hauled 722 bbls Class II fluid to G&I Total Class II fluid hauled=4545 bbls Distance to plan:4.12 High,.62'left at 5798' MD 2357';Last 24 hrs Drilling hrs=13.72 Sliding hrs=.87 Rotating hrs=12.85 8/2/2015 Drlg F/6124'-T/6410'.450 GPM,1425 Psi,90 RPM,11k TO on,10 TQ off.ECD 10.2,BGG 25 units,Avg ROP 48'/hr,37%flow.;Rotary drill f/6410'U 6680.450 GPM.1582 Psi,81 diff press,90 RPM,11700 TQ,10500 off bot TQ,ECD 10.02, BGG 30 units,Avg ROP 49'/hr,37%flow.;Pump tanden sweeps,20 bbls low and 20 bbls high.Circ sweep out w/20%increase in cuttings.;Monitor well.Well static.Change out shaker screens to 200s.Circ active over one shaker and trip tank over other.;POH f/6680'U 5620.Had to work through tight spots at 6265,6236,6157,6105,&5760.hole took 11 bbls over displacement.;Service rig.Pulled active system down to 500 bbls and treated it with 1%lube.;RIH to 6621'and fill pipe while changing all shaker screens to 140s.Had several spots where it started to take wt but fell through.Wash to bottom with no fill.;Slide drill f/6680'U 6701'.550 GPM,2230 Psi,110 Diff,5k WOB,BGG 8 units,Avg ROP 10.5'/hr.[Took a while to get going but got up to 45'/hr] maintaining 1%lube.;Rotary drill f/6701'U 6732'.Slide drill f/6732'U 6737'.GPM 553,2180 psi,Diff 70,RPm 85,TQ 11500,BGG 17,Avg ROP 36'/hr,Flow 47.;Slide drill f/6737',U 6755',Rotary drill f/6755'U6786',Slide drill f/6786'U 6820',Rotary drill f/6820'U6919'.Avg ROP 30'/hr 5 WOB,90 RPM,11,300 TO, 555 GPM,2170 Psi,50 Diff.;Hauled 78 bbls cuttings to G&I Total cuttings hauled=1490 bbls Hauled 824 bbls Class II fluid to G&I Total Class II fluid hauled=5369 bbls Distance to plan:8.84 High,.6.1'left at 6702' MD 2357';Last 24 hrs Drilling hrs=14.88 Sliding hrs=3.03 Rotating hrs=11.85 • • 8/3/2015 Dig F/6919'-T/6928'MD/2642'TVD.550 GPM,2155 psi on,55 psi diff,90 RPM,11.4k TQ on,10 TQ off.ECD 9.9,BGG 15 units,47%flow. Hyd IBOP leaking.;Std back 1 std. R/U head pin to maintain circulation. Move pipe every 15 min max. CIO Hydraulic IBOP. Function test(test good). R/D head pin. Wash down last std.;Load lead cmt silo#5-579 sxs, Load tail cmt silo#4 292 sxs as per Robert Wardrup w/SLB cementers;Drig F/6928'-T/7055'MD/2695'ND. 550 GPM,2110 psi on,50 psi diff,90 RPM,12k TQ on,10.5 TQ off.ECD 9.9,BGG 15 units,47%flow. Drilling drop section since 6800'. 75%slide time.;Drlg F/ 7055'-T/7321'MD/2838'ND.555 GPM,2330 psi on,165 psi diff,90 RPM,12.5k TQ on,11.2 TQ off.ECD 10.1,BGG 25 units,47%flow.;Drilling ahead looking for tight formation to set csg shoe f/7321'V 7465'.Started getting into harder formation.Rotate drill f/7465'U 7474'.;5 WOB,552 GPM,2300 Psi,100 Psi diff, 90 RPM,11.4 TQ,ECD 10.1,BGG 27, 48%flow,Avg ROP 61'/hr.;Circ bottoms up.Cutting samples show we are in siltstone.;Take survey and pump 20 bbl low vis sweep and 20 bbls high vis high wt sweep.20%increase in cutting w/sweep.Monitor well,static. Tight spots 6951',6527',5578',5430',5340'.;POH f/7474'to csg shoe at 3492'.Didnt have any issues in the coals but did have to work through the clays and siltstone.;Service rig.;Hauled 70 bbls cuttings to G&I Total cuttings hauled=1560 bbls Hauled 470 bbls Class II fluid to G&I Total Class II fluid hauled=5837 bbls Distance to plan:4.24 low,.3.22'left at 7435' MD 2357';Last 24 hrs Drilling hrs=9 Sliding hrs=6.78 Rotating hrs=2.22 8/4/2015 Check C.O.M. TIH F/3492'-T/7474'.No tight spots and no fill on bottom.;Fill pipe and pump high vis sweep.Had a good 50%increase in sand and Gay to surface just prior to bottoms up.Cont to circulate until clean at shakers.Checked for flow,fluid dropping slowly.;POOH on elevators from 7474'to 3415'(just inside casing) with no issues during trip.At this point hole has taken 9.5 bbls over calculated hole fill.Flow check at shoe=static,cont POOH from;3415'inside casing,to top of BHA at 424'.LD excess HWDP,jars and NMDC.Removed RA sources.Hole has taken 16 bbls over calculated for entire trip thus far.;Plug in and upload MWD tool.LD remaining BHA.Bit graded at 1-2-CT-G-X-1-No-TD.;Clean and clear floor of tools.Pull wear bushing.Change upper rams to 7 5/8'.;Rig up 7 5/8 test jt and assorted test equip.Test plug rubber failed.Pull test jt and replace rubber.Set test jt and test 7 5/8 rams to 250&4000 psi on a chart.;RD test equip and RU to run 7 5/8 csg.Hold PJSM with everyone involved.;MU shoe track.Baker loc connections,check floats.RIH w/7 5/8 csg installing centralizers and TQ connections as per well plan.Run to 850'.;Hauled 0 bbls cuttings to G&I Total cuttings hauled=1560 bbls Hauled 180 bbls Class II fluid to G&I Total Class II fluid hauled=6017 bbls Distance to plan:4.24 low,.3.22'left at 7435' MD 2357' 8/5/2015 Cont PU and single in hole with 7 5/8",29.7#,P-110 casing from 850'to 3490'(just above surface shoe).;MU circ swedge and topdrive,broke circ at 210 gpm-164 psi.Changed to long bails while circulating.Up wt=90K,dwn wt 22K.;Cont PU and single in hole with 7 5/8"casing from 3490'to 5540'.At joint 105 we switched from P-110 to L-80 casing.RIH was slow due to floating of casing string in high angle section of hole.;MU circ swedge and topdrive,break circ at 5 bpm-295 psi. While pumping,up wt 92K,dwn wt 22K.;Cont PU and single in hole with 7 5/8"casing from 5540'to 7440'.MU hanger/landing joint.Up wt 130K,dwn wt 40K,land same and PU off seat.;Circ at 5 BPM,400 psi.Circ and condition mud while getting schlumberger cementers rigged up.Hold PJSM.;Had hanger setting about 8"off seat and at that point we attempted to PU on the pipe and it wouldnt move at 180k up so we landed the hanger and rigged up the cmt head.;SLB pumped 10 bbls water to flush lines,then 5 bbls water to fill hardline,tested lines at 1000 psi low and 5000 psi high. Good Test.;Rig pumped 30 bbls 11 ppg MUDPUSH II at 4 bpm- 310 psi.Shut down and dropped bottom plug.Lined up SLB pump truck to well.;SLB mixed and pumped on the fly 235 bbls(579sx)12.5 ppg Class"G"lead cement at 6 bpm,500 to 300 psi,followed with 70 bbls(291 sx)15.3 ppg GasBlok tail cement at 4 to 5 bpm,150 to 85 psi.;Shut down and dropped top plug.SLB displaced with 20 bbls water&317 bbls 9.6 ppg,6%KCL at 7 to 5 bpm.With 10 bbls to go we landed the hanger(was 8"off seat).;Bumped plug 337 bbls into displacement (calculated at 339 bbls).Held 1250 psi(FCP 750 psi)for 3 minutes,bled off 1.5 bbls to pump truck and floats held.;Had MudPush 260 bbls into displacement,with increase in PH and mud weight.Had 15 bbls contaminated cement to surface.Mix water temp 70 degrees.Lost 0 bbls throughout job,;did not reciprocate string. CIP at 1:55 on 8-6-15.Estimated TOC at surface.;RD schlumberger equip and release cementers.;Pull landing jt.Flush stack out.Install packoff and test to 5000 psi for 15 min.good test.Change bails back to short bails.;Change upper rams back to VBRs. 8/6/2015 Cont to change upper rams back to 2 7/8"x 5"variables.Removed service loop hoses from topdrive and drained same.;RU test equipment(test joint,TIW,chart recorder),flood stack,test upper rams at 250 low for 5 minutes,4000 high for 10 minutes.RD test equipment.Install 9 1/16"ID wear bushing.;Load pipe racks with 80 joints 4 1/2"DP and BHA items,strap same.Install new service loop hoses and purge air from system by function testing topdrive.;Service drawworks,crown, blocks and topdrive.;PU and MU 6 3/4"Varel V513PDHRU PDC bit,5"-6.0 stg mud motor,float sub,azimuthal gamma prototype tool,DM collar,SP4 collar,ALD collar,CTN collar and PWD tool.Downloaded MWD tool.;Shallow tested MWD tool(OK),loaded RA sources,cont TIH with NMDC's,HWDP and jars for a total BHA length of 609.64'.;PU and single in hole with 4 1/2"CDS-40 drill pipe from 609'to 1917'.;Cont to PU single in hole from 1917'to 3217'.;Fill pipe and RIH out of derrick to 6190'.Fill pipe and continue RIH picking up HWDP on top for push pipe to 7367'.;Circ to clear pipe while getting everything ready to test csg.;Position string where we could close the rams on the pipe for the test and also cut drilling line at same time.Pressure up to 2700 psi with rig pump and bring it up to 3500 psi w/test pump.;Hold pressure on csg for 30 min on a chart.Good test.Also cut&slipped 105'of drilling line while we were testing.;PU a couple more jts of HWDP and tag cmt stringers at 7373'.Clean out to top of float collar at 7378'.Tagged 5'high.Drilled float collar,hard cmt,and shoe at 7460'.Again 5'high.;Drill rathole and 20'of new hole to 7494'.ND 2964'.;Circ hole clean for FIT with a good mud wt of 9.5 all around.PU to 7422';MU headpin and RU test pump.perform FIT to 12.5 PPG.Pressured up to 462 psi w/no bleed off for 10 min.Good test.RD test equip.;Drill 6 3/4"hole f/7494'V 7505'.;Hauled 0 bbls cuttings to G&I Total cuttings hauled=1560 bbls Hauled 415 bbls Class II fluid to G&I Total Class II fluid hauled=6522 bbls Hauled 15 bbls cmt Total cmt hauled 238 bbls.;Distance to plan=4.24 low&3.22 left. 8/7/2015 Cont directional drilling 6 3/4"hole from 7505'to 7964'.Sliding:wob 5 to 10K,341 gpm-2465 psi,60 to 150 psi diff,30 to 60 ft/hr ROP.Rotating:wob 3K,341 gpm- 2387 psi,90 rpm-14,800 ft/lbs on;bott torque,MW 9.5 ppg/vis 54,ECD's at 11.4 ppg,BGG 10 to 20 units,conn gas+/-80 units.;Cont directional drilling 6 3/4"hole f/7964'V 8231'.WOB 5 to 8k,88 RPM 15,500 TQ,341 GPM,2400 psi,100 psi Diff.Sliding WOB 4 to 8k,GPM 338,2415 psi,90 Psi Diff,BGG 30 units,Max gas 90.;Avg ROP 44.5 ft/hr.ECD 11.6 ppg.Mud wt 9.4 ppg,Vis 52.;Cont directional drilling 6 3/4"hole f/8231'V 8481'.Rotating WOB 4 to 8k,345 GPM,2600 Psi,141 Psi Diff,BGG 75 units,Max gas 189 units,90 RPM,16,400 TQ.Sliding WOB 2 to 9k, 344 GPM,;2600 psi,100 Psi Diff, BGG 70 units,ECD 11.3,MW 9.5,Vis 54. Avg ROP 41.6 ft/hr.;Hauled 33 bbls cuttings to G&I Total cuttings hauled=1593 bbls Hauled 142 bbls Class II fluid to G&I Total Class II fluid hauled=6664 bbls Hauled 5 bbls cmt Total cmt hauled 243 bbls.;Distance from plan at 8129',17.13 high and.61'left Sliding hrs=7.54 Rotating hrs=5.69 . • 8/8/2015 Cont directional drilling 6 3/4"hole from 8481'to 8541'.Rotating:3K wob,343 gpm-2575 psi,90 rpm-16,500 ft/lbs on bolt torque,70 ft/hr ROP,MW 9.5 ppg/vis 52, ECD's at 11.5 ppg,BGG 34 units.;Pumped tandem lo-wt lo-vis/hi-wt hi-vis sweep just prior to stand drilled down.;Cont to circ sweep around at 342 gpm-2510 psi,90 rpm-17,000 ft/lbs off bolt torque.Had a 40%increase in cuttings to surface and cont to circ until clean at shakers.Obtained SPR's and survey.;Flow check(static), POOH on elevators from 8541'to 7466'(casing shoe)with no issues in open hole.Cont to pull up hole and rack back 5 stands HWDP used for push pipe.Up wt 180K on bottom.;Serviced rig and topdrive,greased crown and inspected Eaton brake.;PU and singled in hole 10 joints 4 1/2"DP to 7431',then cont to TIH from derrick on elevators to 8540'.Washed last stand to bottom with no indication of fill.Hole in excellent shape.Dwn wt 44K.;Cont to fill pipe while rotating and reciprocating,checking off bottom torque now that we have no HVVDP in upper section of hole,and MWD re-booting their computer.;Cont directional drilling 6 3/4" hole from 8541'to 8854'.Rotating:3K wob,348 gpm-2636 psi,90 rpm-17,300 ft/lbs on bolt torque,100 ft/hr ROP,MW 9.4 ppg/vis 52,ECD's at 11.6 ppg,BGG 13 to 229.;Cont directional drilling 6 3/4"hole f/8854't/9180'.Rotating,3 to 8k WOB,346 GPM,2815 Psi,160 Psi Diff,RPM 82,Torque 17,700,Avg ROP 54 ft/hr, MW 9.4,Vis 53,ECD 11.7,BGG 22 to 249 units.;Cont directional drilling 6 3/4"hole f/9180't/9474',Rotating,3 to 6k WOB,345 GPM,2880 Psi,271 psi Diff,RPM 81,Torque 18,600,Avg ROP 74 ft/hr,MW 9.4,Vis 52,ECD 11.6.BGG 60 to 360 units;Pump 20 bbl low vis low wt and 20 bbl high vis high wt sweeps.Circ hole clean.Had+/-5%increase in cuttings to surface.Flow check=static.;Short trip f/9475't16800',currently at 8927',up wt pulling off bottom was 220K with no pump or rotation.Pulling on elevators and no issues with hole conditions thus far.;Distance from plan at 8129',7.92 high and 1.81 Right Sliding hrs=1.27 Rotating hrs=12.44;;Hauled 43 bbls cuttings to G&I Total cuttings hauled=1636 bbls Hauled 232 bbls Class II fluid to G&I Total Class II fluid hauled=6896 bbls Hauled 0 bbls cmt Total cmt hauled 243 bbls. 8/9/2015 Cont pulling wiper trip up hole,from 8927'to 6801', no issue pulling BHA into casing shoe.Worked through 3 slightly tight spots at 8799',8693'and 8373'on elevators one time each.3 bbl over.;Serviced rig and topdrive.;TIH from 6801'adding spiro-torque subs every second stand to 9432'.At 9432'MU topdrive and washed last stand to bottom at 9475'with no fill,no hole issues during trip.Down wt 45K on bott.;While filling pipe rotated and reciprocated string.Off bottom torque reduced to 15 to 16K on down stroke,static rotating or up stroke still at 18 to 19K.Had 180 units trip gas at bolt up.;Cont drilling 6 3/4"hole from 9475'to 9799'. Rotating wob 3 to 5K,350 gpm-2859 psi,60 rpm-18,000 to 19,200 ft/lbs on bolt torque,50 to 95 ft/hr ROP,MW 9.5 ppg/vis 54,ECD's at 11.3 ppg.;Cont drilling 6 3/4"hole from 9799'to 10200'MD/5577'ND'. 5-7 wob,50-60 rpm,18.4k tq on,20.7k tq off,348 gpm,3150 psi on,208 psi diff,37%flow,11.48 ECD's,60u bgg, r/ 58 ft/hr avg rop.;Circ and condtion hole @ 10,200'MD.Pump @ 347 gpm,2900 psi,85 rpm,17.8k tq. Pump 20/20 bbls tandem sweep 9.3 ppg/37 vis, 11.3 ppg/300 vis. Sweep 15%increase in cuttings and on time.;11.48 ECD before cleanup cycle,11.35 ECD post cleanup cycle.;Monitor well(static). TOH on elevators F/10,200'-T/7450'MD. Pulled cleaned to 7450'MD. 5 bbls over calc displacement.;Extrapolated to bit @ 10,200'MD. 1.1'high and 10.4 right of plan.;Hauled 42 bbls cuttings to G&I Total cuttings hauled=1678 bbls Hauled 228 bbls Class II fluid to G&I Total Class II fluid hauled=7124 bbls Hauled 0 bbls cmt Total cmt hauled 243 bbls. 8/10/2015 Monitor well for flow at 7449'(inside casing shoe)while crews change out.Well static.;TIH on elevators,from 7449'to 10,200'.Had no problems tripping in open hole and no fill on bottom.Up wt 240K,dwn wt 50K.;Pumped tandem sweeps around at 347 gpm-2895 psi.Had a max of 233 units gas at bottoms up and an increase of 10%in cuttings with sweeps to surface.;Pulled up hole 5 stands from 10,200'to 9785'.Flow check was static.Pumped dry job then dropped a 2 3/8" hollow drift with wire.;Cont to POOH from 9785'to 6800',inside the 7 5/8"casing,up wt 220K on bottom,laying down alt 20 spiro-torque subs in the process.Cont to POOH inside casing from 6800'to 3024'.;Cont POOH from 3024'and lay down 78 joints 4 1/2"CDS-40 DP.;PJSM,UD directional tools,remove sources and secure. Download MWD. L/D remaining BHA,Drain mtr and B/O bit. Bit grade-1,2,CT,G,X,1,PN,TD.;CIean and clear rig floor. Prep for upcoming BOP test.;Pull wear bushing. Set test plug and R/U test equipment. Test BOPE 250 low/4000 high(annular 2500 high)w/5 min low and 10 min high as per Saxon. Chart and record same.;Test#1-Annular,Test#2-Upper pipes,Outside kill,Dart,CM-1,3,4,5,7. Test#3-Hyd kill,Hyd TD IBOP,FOSV,CM 2,4,5,6,8. Test#4Remote choke.Test#5-Manual choke;Test#6-Inside kill,Upper pipe,FOSV,TD manual IBOP,CM 7,9,11,13. Test#7-Upper pipe,FOSV,Inside choke,Inside kill. Test#8-Lower pipe,FOSV.;Test#9-Drawdown. Initial psi 3050,drawdown psi=1425,200 psi increase=18 secs,full charge=98 secs,annular closure time 20 secs. 4 bottle avg=2650 psi;BOPE test witnessed by Lou Grimaldi. 8/11/2015 Tested lower piperams and blind rams at 250/4000 psi to complete bi-weekly BOP test,witnessed by AOGCC Rep Lou Grimaldi.Total test time 5 1/2 hours.;RD test equipment,pull test plug,set wear ring,re-align all valves for drilling/well control,close annulus valve.;RU Weatherford casing run equipment and held PJSM with rig crew,Weatherford and Baker Reps.;MU 4 1/2"shoe track and Baker Lok same,verify floats operational,cont PU RIH with a total of 66 joints 4 1/2"12.6#,L- 80 DWC/C-HT liner filling pipe on the fly,to 2898'.PU SBE and MU same,;PU Baker HRD-E ZXPN Flex-Lock liner hanger assembly.RD Weatherford casing run equipment and released same.MU tail pipe extension and Type 1 Liner Wiper Plug.MU assembly on SBE.;Mixed and poured pal-mix.RIH on one stand 4'A"DP and circ one liner volume at 135 gpm-238 psi.Up wt 40K,dwn wt 31 K.;Cont to TIH with liner assembly on 4 1/2"DP from derrick,at 1 to 1 1/2 minutes per stand, from 2966'to 7426'(just above casing shoe at 7466').Filled pipe on the fly then completely filled every;10 stands.MU topdrive and broke circ.;Adjust max drilling tq on top drive to 10k ft/lbs. Circulate one full liner and drill pipe volume at 87 spm-254 gpm-647 psi.Up wt=78k,down wt=34k.;Rotating parameters as follows:10 rpm=8200 ft/Ibs,Unable to obtain tq values @ 20,30 rpm due to stalling issues.;Cont to TIH with liner assembly on 4 1/2"DP from derrick,at 1 to 1 1/2 minutes per stand,from 7426'to 10200'MD. Tagged up 20k dn @ 10174'and washed down from there to TD.5 bpm,880 psi.;P/U rotating cement head and M/U same. Circulate and condition 135 gpm,620 psi,17%flow. 165k up,55k dn w/no pumps or rotary. Tagged 10,200'w/6k dn.;Pick up and break over @ 165k,2 ft then park @ 10,198'MD(4 1/2"liner shoe depth). Bring SLB lines,manifold and equipment to floor.;SLB pumped 5 bbls water to flush lines,then 5 bbls to fill lines.Shut in cement head and PT lines at 1000 and 5000 psi.Rig pumped 20 bbls 12.5 ppg Mud Push II at 5 bpm-870 psi;lined up cement head to SLB.SLB pumped 109 bbls(455 sx)15.3 ppg Class"G"Easy Blok cement at 4 bpm,700 to 425 psi with full retums and shut down.;Baker released dart,then SLB displaced with 9.5 ppg 6%KCL mud at 4.5 bpm-140 psi ICP.Slowed to 2.5 bpm with 90 bbls displaced and saw dart latch wiper plug 100 bbls into displacement.;lncreased pump rate to 4.5 bpm-1450 psi and started losing returns.With 10 bbls to go,reduced rate to 2 bpm-1100 psi and bumped plug/landing collar at 134.5 bbls into displacement calculated at 139;FCP 1100 psi.SLB increased to and held 3000 psi(2900 over fcp)for 3 minutes.Bled back 2.5 bbls to truck and floats held.;Slacked off on blocks from 84K to 15K giving us a good indication hanger was set.SLB increased to 4500 psi then bled off as per Baker Rep.Pumped a total of 131 bbls with a total of 131 bbls retumed;Lost 75 bbls during displacement.CIP at 04:30 on 8-12-15.RD hardline and layed down cement head. PU 5'to clear dogs from hanger top and had good indication we released liner string.;SO 70K to set packer with no indication of shear.PU,rotated at 20 rpm,9000 ftAbs torque,SO and set down 70K to set packer,with good indication of shear.;Top of liner hanger at 7239',top of landing collar at 10,068'.Closed annular,lined up on kill line,pressured up on annulus to 1800 psi and held for 10 minutes,with a loss of 100 psi.;Shut in 4"on pump and pressure holding at 1700 psi,had good indication HRD-E ZXPN liner top packer set.Bled off psi to 0 psi,opened bag,then pressured up to 1000 psi on drill string and PU 34';Once psi dropped rig started pumping and did one full circ at 265 gpm- 639 psi.181 bbls into circ started dumping returns due to high PH.Dumped 35 bbls and started taking returns to pits. • • ElHilcorp Energy Company Composite Report Well Name: NINU GO 08 Field:Ninilchik County/State: ,Alaska 1(LAT/LONG): evation(RKB): 18 API#: 50-133-20651-00-00 Spud Date: 7/23/2015 Job Name: 1511166C GO 08 Completion Contractor AFE#: 1511166C AFE$: Activity Date Ops Summary 8/12/2015 Cont to circulate any cement out of hole at 5 bpm-584 psi.Shut down pump.,Close upper pipe rams,pump down drill pipe 2.2 bbls and pressure up on annulus to 1,700 psi.Pressure bled off 60 psi to 1,640 psi and held after 10 minutes,for liner lap test.Bled off opened rams.,LD one single joint plus pup joint,dropped wiper ball,MU topdrive and circulated surface to surface at 298 gpm-671 psi.Reciprocated pipe while circ.,POOH racking back in derrick.Break down and LD liner hanger run tool.Good indication dog sub sheared.PU Baker cement head and break off pup joints,LD same.,PU and MU Baker"TBR"dress and polish mill. Overall length 64.66'.Bottom mill OD=4.61",top mill OD=6.50". TIH to top of liner lap @ 7,239'MD.,34K dn,98K up. Slowly engage top of liner lap w/milling assy. Continue to slack off and tag up on depth @ 7,290'w/5k dn,no rot or pump.,Worlc milling assy F/7,290'-7,270'MD. 13 rpm,8K tq,134 gpm,451 psi,17% flow. Work mills 4 times as per BOT rep. P/U from 7,290'to 7,125'disengaging mills from liner lap w/pumps on.,CBU @ 7,125'MD. 284 gpm,907 psi,29% flow.,TOH w/milling assy F/7,125'-T/surface. B/O and laydown milling assy same.,Pull wear bushing. Set test plug. R/U and test lower,upper rams and annular w/2-7/8"test jt. Chart and record same. 8/13/2015 Test annular,upper and lower pipe rams with 2-7/8"test joint at 250 tow,4,000 high.Annular at 250 tow,2,500 high.RD test equipment and set wear ring.,RU Weatherford tongs and elevators,held PJSM.,PU and MU first multi-back combo tool(Swaco scraper)for 4-1/2"liner,followed with 92 joints 2-7/8"workstring,XO and 2nd multi-back combo tool for 7-5/8"casing,to 2,851'.RD Weatherford equipment.,Cont TIH with 4-1/2"CDS-40 DP from 2,851'to 7,235'MD.,CBU @ 7,235' MD. 283 gpm,2,720 psi,35%flow.,R/U and test casing to 3,500 psi w/30 min hold(test good). Chart and record same. R/D test equipment.,Continue TIH F/ 7,235'-T/10,068'MD. Engaged top of liner w/no issue. Tagged landing collar on depth(10,068')w/4K.,CBU @ 10,068'then displace 9.5 ppg KCUpolymer mud w/20 bbl hi vis fresh water spacer followed by fresh water. 180 gpm,1,820 psi,20%flow. 124k up,44K dn(mud),150k up,52K dn(water).,TOH F/10,068'-T/ 6,868'MD. UD 9 stds HWDP and 1 std dp during trip. Continue trip out standing back in derrick. Trip out to top scraper. 8/14/2015 POOH with tapered cleanout string,from 6,868'to 6,500'at the upper multi-back combo tool(Swaco scraper).,Cut and slip 124'of drill line,calibrate block height, check crown saver.,TIH from 6,500'to 10,068'with no issue entering liner top at 7,239'.Tagged up on landing collar on depth at 10,068'.PU and parked 5'off bottom.,Held PJSM with rig crew and Peak drivers,pumped second fresh water displacement followed with 25 bbl caustic wash,25 bbl baraclean pill,25 bbl hi-vis sweep then displaced well to 3%filtered KCL brine.Had 98 NTU's at shut down.Took pill train to cuttings box and treated same with citric acid.,POOH UD 4-1/2" CDS-40 drill pipe from 10,068'to 6,500',UD upper scraper,cont POOH from 6,500'to 2,885'MD. UD second scraper and XO.,C/O grabber heads on iron roughneck to 2-7/8". C/O closing ram and adjust hydraulic psi to 2K for 2-7/8"connections.,POOH UD 2-7/8"workstring F/2,885'-T/surface. B/O and laydown 4.5"scraper. Estimated 3 lbs fine metal shavings on string magnets,est 1/2 lb fine metal on shaker magnets.,Clean and clear rig floor.,Hauled 0 bbls cuttings to KGF G&I cummulative 1,681 bbls. Hauled 910 bbls class II fluid to KGF G&I cummulative 8,641 bbls. Hauled 0 bbls cement to KGF to G&I cummulative 243 bbls. 8/15/2015 Remove wear ring,remove all excess subs and equipment from rig floor.CO heads and ram on iron roughneck.,RU Weatherford power tongs,elevators and slips, held PJSM with rig crew and Weatherford Rep's.,PU"GBH-22"locating seal assembly with locator sub followed with 220 joints 4-1/2"12.6#L-80 IBT completion tubing.MU and test chem inject mandrel and test to 3,000 psi.RIH to jt#222 and MU SSSV.Test valve and line to 5,000 psi for 10 min,good test.,RIH to jt#230 and set down on liner top at 7,251'.Work 3/4 of a turn into the tbg and finally went in.Run in and tag no/go locator in liner hanger at 7,260'with WLG at 7,299',PU 2' and mark pipe for spaceout.Test back side to 500 to ensure seals were in.Pressure held. POOH and lay dn 2 jts.Measure pipe and figure space out.,MU subs to top of tbg so we can reverse circ corrosion inhibitor.,Pump 189 bbls 3%KCL w/corrosion inhibitor down and taking returns from tbg.235 GPM at 245 psi.,Space out,MU hanger and landing jt.String chem lines through hanger and land hanger w/WLG at 7,297'and no-go at 7,258'.[Installed 17 SS bands].,Check to make sure hanger was landed and RILDS.,RU and test csg to 2,500 psi for 30 min on a chart.Had to swap out hoses due to cmt plug.Did get a good test.,RU to pump down tbg and pressure up to 2,500 psi with the rig pump.Attempt to bring up pressure to 5,000 psi with air operated test pump.Got to 4,300 psi and had to shut down to work on the pump.,Hauled 0 bbls cuttings to KGF G&I cumulative 1,681 bbls. Hauled 320 bbls Class II junk fluid w/a cumulative of 8,961 bbls. 8/16/2015 ,RU Pollard pump and test 4-%"tubing and liner at 5,000 psi.Lost 300 psi over 30 minutes with no psi gain on annulus.Purge all hoses,add isolation valve on pump in sub and bring psi back up from 0 to 5,000 psi.Lost 300 psi over 30 minutes again.Discussed with Drilling Engineer and decision made to ND BOP,NU dry hole tree and make another attempt at 5,000 psi test with dry hole tree on.,Released Pollard pump truck.Bleed off,and RD test equipment,XO's,Weatherford broke out landing joint,LD same,RD Weatherford equipment.,Remove flowline and drip pan and flow riser.Installed trolly beams.Installed 2-way check valve.ND BOP stack.,NU dry hole tree(lower master valve).RU to test hanger void.,Had to pressure up on void and go around tightening the lockdowns to get a test on the void. Finally got it tested to 250 tow and 5,000 psi high.,Pull BPV and set TWC.RU and test single valve tree.Had leak on bottom of valve flange.Tighten flange and retest to 250 low and 5,000 high.Good test.,Pull TWC and test tbg to 5,000 psi.First attempt sheared pop off disk in test pump at 5,000 psi and pressure fell back. Second attempt we shut in at 5,000 psi and pressure bled back to 4,650 psi in 30 min on a chart.,RD test equip and secure well.Rig released from Grassim Oskoloff 08 to KBU 31-06X at midnight on 8-16-2015.,No activity on this well during this time. 8/23/2015 Obtain PTW. Hold safety meeting and discuss job procedure. Review SLB JSA.,Rig up SLB CTU 12 with 1.75in CT.,Start BOP test. Test all valves and Rams to 250 low and 4,500 psi for 5 minutes. Witness waived by Jim Regg,AOGCC. Record pressure test. Fill out state BOPE test form.,Replace stripper rubbers on injector head. Walk location and secure for the evening. • 8/24/2015 Obtain PTW. Hold safety meeting and review JSA and job procedure.,Online down 4.5in tubing with 3%KCL. Pressure test tubing to 5,000 psi for 30 minutes. 0753 hrs. WHP 5,019 psi. At end of 30 minute test 4,615 psi. Visually checked for flow at SSSV control line and chemical injection line. No indication of communication. Visually cracked 4-1/2"x 7-5/8"annulus and no pressure or fluid. No communication but at the time couldn't confirm annulus was fluid packed.,Called town to discuss plan forward. Decision made to bleed down to 3,000 psi and then pressure back up to 4,500 psi. Down on pump and isloate fluid lines at surface 4,503 psi on 4.5in tubing. Monitor pressure. Pressure bleed down to 4,351 with in 20 minutes. Pressure graphs sent to town. Pressure bleed shows a consistent line throughout test pressures.,Decided to bleed down and continue with SL and CT logging.,Pick up slick line. Stabbed on well pressure test SL to 250/4,000 psi. Bleed down to tank. Open well and RIH,tagged at 250 ft. Confirmed latched into SSSV sleeve. Hand spang. Confirmed tool pulled. POOH. RDMO SL. Pollard off location.,Pick CT injector head and stab 40 ft of lubricator. Noticed ding on pipe. Cut 55ft of CT. Make up CT coil connector. Pull test good. Install check valves and disconnect. Make up 30 ft CBL tools with SLB memory. Stab on well. Clint Chantey on location to pressure test hanger seal. 5,000 psi for 30 minutes. Good test.,Low pressure test stack 250 psi. 4,500 high. 5 minute tests good. Bleed down to tank. RIH with memory tools slowing down for restriction at 250 ft. Confirm memory tools acquisition software is reading and calibrated.,Stop at 1,000 ft to confirm memory counter calibration. Looks good, continue to RIH with CBL logging tools. Pressure test IA(4-1/2"x 7-5/8"to 2,000 psi)2,001 psi start and end at 1,994 psi after 30 minutes.,Stopped CT at 10,000 ft. Mechanical counter reading 10,000 ft. Memory happy with logging depth. Start logging with CBL OOH at 30 ft/min from 10,000 ft to 7,350 ft.,Parked at 7,350'. Logging interval completed. Headed back to 8,000 ft to log back up to pick up TOC.At 7,350 ft with second log run. Memory hand happy with pass. POOH to surface.,OOH. Breaking down memory tools. Filling up tubing to pressure test 4.5in overnight.,Stacking down injector head. Filling tubing with KCL. Memory downloading data. Good data confirmed. Location secure. 8/25/2015 Discuss pressure test procedure with town. Obtain PTW.,Open well. WHP at 1100 hrs was 700 psi,. Online with KCL to pressure up 4.5in tubing.,IA pressure from previous day still 2016 psi. Tubing pressure 3017 psi,. Start 30 minute test. 2752 psi after 30 minute test. 295 psi bleed off. la pressure built from 2207 psi from tubing ballooning effect.,SEnt graph to town. Called to discuss plan forward. Directions given to bleed of IA pressure to zero and perform 30 minute pressure test on tubing to 3000 psi. 3001 psi start pressure. end of 30 minute test tubing pressure was at 2760 psi.241 psi leak off. la pressure showing 50 psi due to ballooning of tubing while applying 3000 psi.,Locationg CIBP and setting tools. Tools aquired. Will be on location 0800 hrs following day. 8/26/2015 Obtain PTW. Hold safety meeting and discuss job procedures. Review SLB JSA.,Pick injector head. Stab 40 ft of lubricator. Make up MHA and pull test to 25K. Fluid pack coil tubing. Pressure test MHA(coil connector,check valves,disconnect)to 250/3,500 psi. Good pressure test. Bleed down to tank. Make up 4-1/2 in CIBP and Baker series 10 J setting tool loaded with 1/2in ball seat. CIBP with OD of 3.75in. 9.3 ft Iong.,Zero at bottom of lubricator. Distance from tubing hanger to zero is 12 ft. RKB measurement is 18 ft. Input corrected depth at CT zero of 6 ft. Stabbed on well with CIBP. Pressure test lubricator on back side to 250/4,500 psi.5 minute pressure test good. Bleed down to open top tank. Shut in choke. Open master and swab. RIH with CT. Slow down for SSSV restriction. Small weight bobble(g;250 ft.,RIH performing weight checks every 2,500 ft. Clean weights. Review tubing tally to ensure CIBP will not be set in collar. Estimated PBTD with tubing tally 10,068 ft. Tagged PBTD with CT at 10,067.7 ft RKB.,Pick up off bottom from 10,067.7 ft. Determined by weight break we have 6 ft of CT stretch. Pick up to 10,055 ft. Load 1/2 in ball in CT. High gear stall against block valve. Launched ball. Confirmed moving in coil. Ball over gooseneck at 1 bbl/min. Reel volume 25 bbls. Slow down pump rate to.5 bbls/min after 20 bbls away. 500 psi CT pressure while pumping.5 bbls. Ball on seat pressure up to 1,800 psi.,Increase pressure to 2,300 psi. Wait a minute. Increase pressure to 2,700 psi. Increase pressure to 3,000 psi. Pick up to set CIBP 21.500 lbs seen on weight gauge when pressure dropped. Normal CT up weight 19k. 2,500 lbs of over pull at 3,000 psi to set CIBP. Pick up 50 ft off plug. Weight 19K clean. RIH to tag top of plug. Stacked 2k down on CIBP at 10,058 ft.,Fish in hole is CIBP at 10,055 at 1 ft Iong.,PIck up to 9,900 ft and park CT. Break circulation to surface at 1 bbl/min.Good returns.Close choke. Pressure up tubing to 3,000 psi. IA pressure 30 psi. Start 30 minute test on tubing. 3,100 psi. After 30 minutes pressure dropped to 2,829 psi. 271 psi loss. Steady drop in pressure. Pressure line never leveled off.,N2 primed up. Pressure test N2 lines to 250/4,500 psi. Good test. CT parked at 10,058 ft on CIBP. Online with N2©1,800 scf/min. Starting strap of return tank 86 bbls. Blowing well dry. 222 bbls in return tank start.POOH while pumping N2. 235 bbls in returns. No fluid at tank. Swap N2 down back side of CT to pressure up well. CT(g;5000 ft. Continue to POOH,choke closed.,POOH. At surface. Down on N2. 1,300 psi on wellhead. Close in master and swab. Bleed down BOPE. Pop off well and break down tools. Cap BOPS. Open master and swab. Continue buliheading N2 to build to 3,000 psi. Crews stacking down lubricator and injector head. N2 at 3,200 scf/min. WHP building consistently.,Injector set down on back deck. Continue bullhead N2. WHP 3,100 psi. Annulus pressure 80 psi.,Start 30 minute test. 3,279 psi start. Finish pressure 3,237 psi. Good test.42 psi loss over 30 minutes. No increase in IA pressure. 85 psi. Sent pressure test chart into town. Shut in well with 3,233 psi. Bleed down CT BOPs to tank. Shut down CTU 12 equipment and secure location. Total N2 pumped 2,300 gallons or 215,000 scf. Tanks strap calculation=235 bbls-84 bbls=151 bbls.,151 out of 153 bbls returned from wellbore. SITP 3,233 psi. IA pressure 86 psi. Crews off location. Plan to rig down following day depending on well pressures. 8/27/2015 Obtain PTW. Hold safety meeting and discuss job procedure with new crew. Review SLB JSA.,Rig down CTU 12. Check tubing pressure and IA pressure. Tubing at 3,270 psi. IA pressure 38 psi. Rigging down CTU 12. Vac truck disposing of fluid. Crews rigged down and off location at 1200 hrs. SLB agreed to charge add hours for 4 hrs. Instead of a complete unit charge day. 8/28/2015 PTW and JSA.Rig up lubricator and put tractor on line.Test tractor.Pressure test lubricator to 250 psi low and 3,000 psi high.,RIH with Weltec tractor,2-7/8"x 23' HC Connex,6 spf,60 deg phase and tie into SLB CBL dated 24 Aug 2015(CBL is off 4'from Open Hole log).Turn tractor on at 2,103'and tum off tractor at 6,900'. < Run correlation log 1A and send to town.Get ok to perforate from 9,828'to 9,851'.Bleed well to 1,302 psi.Fired gun.After 5 min-1,332 psi and 10 min-1,370 psi. POOH.All shots fired.Gun dry.,Rig down lubricator and get equipment ready to move to Blossom 1.TP was 1,540 psi when swab was shut. ! i Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. GO#8 Date 28-Jul-15 County Kenai Peninsula Borough State Alaska Supv. Shane Barber CASING RECORD TD 3500.00 Shoe Depth: 3492.42 PBTD: 3408.44 Casing(Or Liner)Detail Setting Depths No.of Jts. Size Wt. Grade THD Make Length Bottom Top Shoe 103/4 BTC WFD 1.90 3,492.42 3,490.52 2 Jnts 10 3/4 ' 45.5 L-80 BTC 80.57 3,490.52 3,409.95 Fit Cir 10 3/4 BTC WFD 1.51 3,409.95 3,408.44 84 10 3/4 45.5 L-80 BTC 3,384.64 3,408.44 23.80 Hgr w/pup 10 3/4 45.5 L-80 BTC Seaboard 2.80 23.80 21.00 Landing jnt 103/4" BTC 21.00 21.00 0.00 Totals Csg Wt.On Hook: 54,000 Type Float Collar: Model 402 No.Hrs to Run: 12 Csg Wt.On Slips: 36,000 Type of Shoe: Bull Nose/303 Casing Crew: WFD Fluid Description: 9.35 ppg Spud Mud,PV 19,YP 21 Liner hanger Info(Make/Model): Liner top Packer?: _Yes X No Liner hanger test pressure: 0 Centralizer Placement: 2 bowspring on shoe jnt,1 centralizer middle bakerlok jnt, 39 centralizers every otherjnt(42 total) CEMENTING REPORT Preflush(Spacer) Type: Mud Push II Density(ppg) 10 Volume pumped(BBLs) 45 Lead Slurry Type: Extended Density(ppg) 12 Volume pumped(BBLs) 383 Mixing/Pumping Rate(bpm): 5.5 Tall Slurry Type: Conventional Density(ppg) 15.2 Volume pumped(BBLs) 76.7 Mixing/Pumping Rate(bpm): 5.5 N Post Flush(Spacer) N Type: Density(ppg) Rate(bpm): Volume: ix LL Displacement: Type: Spud Mud Density(ppg) 9.5 Rate(bpm): 5 Volume(actual/calculated): 332/328 FCP(psi): 500 Pump used for disp: SLB Plug Bumped? Yes X No Bump press N/A Casing Rotated? Yes X No Reciprocated? _Yes X No %Returns during job 100 Cement returns to surface? x Yes No Spacer returns? X Yes No Vol to Surf: 208 bbls cement Cement In Place At 23:59 Date: 7/27/2015 Estimated TOC: 0 Method Used To Determine TOC: Visual confirmation and samples. PSIG/PH samples Preflush(Spacer) Type: Density(ppg) Volume pumped(BBLs) Lead Slurry Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tail Slurry w Type: a Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): y Post Flush(Spacer) 0 o Type: Density(ppg) Rate(bpm): Volume: w Displacement: or Type: Density(ppg) Rate(bpm): Volume(actual/calculated): FCP(psi): Pump used for disp: Plug Bumped? Yes No Bump press Casing Rotated? Yes _No Reciprocated? _Yes_No %Returns during job Cement returns to surface? Yes_No Spacer returns? Yes_No Vol to Surf: Cement In Place At Date: Estimated TOC: Method Used To Determine TOC: WELLHEAD Make Seaboard Type 16 SOWx 16 3/4"3M Serial No. H439495 Size 16 3/4" W.P. 3000 Test Head To 3000 PSIG 15 MIN Tested good OK Remarks: Report for 10 3/4"surface casing. 0 410 Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. Ninilchik,GO-08 Date 6-Jul-15 County Kenai PB State Alaska Supv. R.Pederson/M Rogers CASING RECORD TD 7474.00 Shoe Depth: 7466.00 PBTD: Casing(Or Liner)Detail Setting Depths _ No.of Jts. Size Wt. Grade THD Make Length Bottom Top Shoe 7 5/8 29.7 BTC Weatherford 1.62 7,466.00 7,464.38 2 7 5/8 29.7 P110 BTC 80.70 7,464.38 7,384.39 float 7 5/8 29.7 BTC Weatherford 1.38 7,384.39 7,383.01 103 75/8 29.7 P110 BTC 4,142.74 7,383.01 3,240.27 81 7 5/8 29.7 L-80 BTC 3,217.87 59.85 22.40 pup 7 5/8 29.7 1-80 BTC 2.00 22.40 21.80 hanger 7 5/8 Seaboard 0.60 21.80 19.80 RKB 19.80 19.80 0.00 Totals 186 Csg Wt.On Hook: 40 dn,150 up Type Float Collar: WOC float No.Hrs to Run: 17 Csg\M.On Slips: 20 Type of Shoe: WOC float Casing Crew: Weatherford Fluid Description: 6%KCL Polymer Liner hanger Info(Make/Model): Liner top Packer?: _Yes x No Liner hanger test pressure: Centralizer Placement: Ran 67 centrilizers.1 on first 34 jts,then every other one up to jt#98 CEMENTING REPORT Preflush(Spacer) Type: mudpush Density(ppg) 11 Volume pumped(BBLs) 30 Lead Slurry . Type: Class G Density(ppg) 12.5 Volume pumped(BBLs) 235 Mixing/Pumping Rate(bpm): 6 Tail Slurry Type: Gas Bloc Density(ppg) 15.3 Volume pumped(BBLs) 70 Mixing/Pumping Rate(bpm): 5 N Post Flush(Spacer) N Type: Density(ppg) Rate(bpm): Volume: v: ii Displacement: Type: Drilling mud Density(ppg) 9.3 Rate(bpm): 7 to 4 Volume(actual/calculated): 337-339 FCP(psi): 700 Pump used for disp: SLB Plug Bumped? X Yes No Bump press 1250 Casing Rotated? Yes X No Reciprocated? Yes X No 100%Retums during job yes Cement retums to surface? X Yes No Spacer retums? X Yes No Vol to Surf: 15 bbls cmt Cement In Place At: 1:55 Date: 7/6/2015 Estimated TOC: surface Method Used To Determine TOC: Got 15 bbls cmt back Preflush(Spacer) Type: Density(ppg) Volume pumped(BBLs) Lead Slurry Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tail Slurry w Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): 1— (t) Post Flush(Spacer) 0 o Type: Density(ppg) Rate(bpm): Volume: wDisplacement: Type: Density(ppg) Rate(bpm): Volume(actual/calculated): FCP(psi): Pump used for disp: Plug Bumped? Yes No Bump press Casing Rotated? Yes No Reciprocated? Yes No %Returns during job Cement returns to surface? Yes No Spacer returns? Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: WELLHEAD Make Sea board Type Multi bowl Serial No. Size 16 3/4 x 11 W.P. 3M X 5M Test Head To 5000 PSIG 15 MIN test OK Remarks: plug bumped and the floats held. • • Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. Ninilchik,GO#8 Date 12-Aug-15 County Kenai PB State Alaska Supv. Rance Pederson/Shane Barber CASING RECORD TO 10200.00 Shoe Depth: 10198.00 PBTD: 10068.69 Casing(Or Liner)Detail Setting Depths No.of Jts. Size Wt. Grade THD Make Length Bottom Top Shoe 5 x 4 1/2 DWC/C Weatherford 1.62 10,198.00 10,196.38 2 Joints 41/2 12.6 _ L-80 DWC/C USS 83.40 10,196.38 10,112.98 Float collar _ 5 x 4 1/2 _ DWC/C• Weatherford 1.32 10,112.98 10,111.66 1 Joint 41/2 12.6 _ L-80 DWC/C USS 41.96 10,111.66 10,069.70 Landing Collar 5 x 4 1/2 _ DWC/C J Hobbs 1.01 10,069.70 10,068.69 63 jnts(4 RA Jilts) 41/2 12.6 L-80 _ DWC/C USS 2,769.53 10,068.69 7,299.16 Liner Hanger 51/2x75/8 DWC/C Baker 59.91 7,299.16 7,239.25 Totals Csg Wt.On Hook: 52,280 Type Float Collar: Weatherford#303E No.Hrs to Run: 13.5 hrs Csg Wt.On Slips: Type of Shoe: Weatherford Bullnose Casing Crew: Weatherford Fluid Description: 9.6 ppg 6%KCL Drilling mud PV 12,YP 18 Liner hanger Info(Make/Model): Baker/HRD-E ZXP RS Flex-Lock Liner top Packer?: X Yes_No Liner hanger test pressure: 1700 psi Centralizer Placement: 40'spacing,Ran 70 Hollow Vane Spiral Centralizers CEMENTING REPORT Preflush(Spacer) Type: Mud Push II Density(ppg) 12.5 Volume pumped(BBLs) 20 Lead Slurry Type: Class"G"Easy Blok Density(ppg) 15.3 Volume pumped(BBLs) 109 Mixing/Pumping Rate(bpm): 4 Tail Slurry Type: N/A Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): N Post Flush(Spacer) y Type: Density(ppg) Rate(bpm): Volume: cc LL Displacement: Type: 6%KCL Mud Density(ppg) 9.5 Rate(bpm): 4.5 Volume(actual/calculated): 134.5/139 FCP(psi): 1100 Pump used for disp: SLB Plug Bumped? X Yes No Bump press 3000 Casing Rotated? Yes X No Reciprocated?_ Yes X No %Retums during job 50 Cement returns to surface? Yes X No Spacer returns? Yes X No Vol to Surf: 0 Cement In Place At: 4:30 Date: 8/12/2015 Estimated TOC: 7,239 Method Used To Determine TOC: Lost no returns during cement pumping,once dart latched wiper plug returns tapered off Preflush(Spacer) Type: Density(ppg) Volume pumped(BBLs) Lead Slurry Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tall Slurry w Type: a Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): y Post Flush(Spacer) 0 o Type: Density(ppg) Rate(bpm): Volume: yDisplacement: Type: Density(ppg) Rate(bpm): Volume(actual/calculated): FCP(psi): Pump used for disp: Plug Bumped? Yes No Bump press Casing Rotated? Yes _No Reciprocated? Yes No %Returns during job Cement returns to surface? Yes_No Spacer returns? Yes_No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: WELLHEAD Make Sea board Type Multi bowl Serial No. Size 16 3/4 x 11 W.P. 3M X 5M Test Head To 5000 PSIG 15 MIN test OK • Remarks: Possibly 1/2 lb per bbl cemnet restricted flow around liner hanger causing,loss of returns during displacement 2 s-- 0-7 7 Davies, Stephen F (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Monday, March 21, 2016 1:59 PM To: Davies, Stephen F (DOA) Cc: Guhl, Meredith D (DOA) Subject: RE: Grassim Oskolkoff No. 8 - Question Good afternoon Steve, Sorry it took me so long to get back to you. The correct KB elevation is 182.8'above MSL. That is 164.8' (from McLane survey) plus 18' (KB height for Saxon). = 182.8' Great catch! Thank you! /'GO NC.8 WELL NS-EULT CT1 d N2255334.021LOAI E:222297.661 ..✓r LATITUDE 9"09'54 553"N LONGITUDE 151'2E00 5STW NAD27 ASP ZONE 4 FEL=7728' ! PSL=3374' PLev 164 B'(N0vD291 SECTION 23 ft TOWNSHIP IN 10 RANGE 13W,SQA Ax ,00 Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell: 907.538.1168 From: Davies, Stephen F (DOA) [mailto:steve.davies@ alaska.gov] Sent: Friday, March 18, 2016 4:53 PM To: Monty Myers Cc: Guhl, Meredith D (DOA) Subject: Grassim Oskolkoff No. 8 - Question Monty, I'm reviewing the Well Completion Report for Grassim Oskolkoff No. 8,and I have a question. On the Report form,the KB elevation is listed as 183.4' above mean sea level, but on the Definitive Survey Report from Halliburton,the MD and TVD References are listed as 182.2' above mean sea level. The ground elevations agree between the form and the report. I know it's a small difference, but which KB elevation value is correct? Thanks, Steve Davies I Senior Petroleum Geologist gist 1 • Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. 2 ` • • ` OF 71.1. 7 Alaska Oil and Gas �w\��js� THE STATE of/� L /� ( Conservation Commission - -= 1�1 I1�7 x 333 West Seventh Avenue ier - STM_ GOVERNOR BILL WALKERAnchorage, Alaska 99501-3572 O Main: 907.279.1433 AL � A9Fax: 907.276.7542 www.aogcc.alaska.gov Taylor Nasse Operations Engineer , �i717 Hilcorp Alaska, LLC r 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga/Tyonek Gas Pool, Grassim Oskolkoff(GO) #8 Sundry Number: 315-492 Dear Mr. Nasse: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy . Foerster Chair DATED this/ ay of August, 2015 Encl. 0 • RECEIVED STATE OF ALASKA AUG 11 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION Cri--G ISlIS APPLICATION FOR SUNDRY APPROVALS !A 20 AAC 25,280 1.Type of Request: Abandon❑ Plug Perforations ❑ Fracture Stimulate ❑ Pull Tubing ❑ Operations shutdown ❑ Suspend❑ (Initial)Perforate • Other Stimulate ❑ Alter Casing ❑ Change Appr ved Program ❑ Plug for Redrill❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other. 4v �o."./4iL 7 L141 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC Exploratory ❑ Development ❑ - 215-077 ' 14'. 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic E Service ❑ 6.API Number. Anchorage,AK 99503 50-133-20651-00 - 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O.701 Grassim Oskolkoff(GO)#8 Will planned perforations require a spacing exception? Yes ❑ No ❑✓ 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 389737• Ninilchik Field-Beluga/Tyonek Gas Pool 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): 10,200 5,577 -10,026 -5,404 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 3,492' 10-3/4" 3,492' 1,844' 5,210 psi 2,470 psi Intermediate Production 7,466' 7-5/8" 7,466' 2,943' 6,890 psi 4,790 psi Liner -2,927' 4-1/2" -10,198' -5,575' 8,430 psi 7,500 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 4-1/2" 12.6#/L-80 -7,271 Packers and SSSV Type: Baker ZXP Liner Top Packer Packers and SSSV MD(ft)and TVD(ft): 7,239'MD/2,792'TVD WL SCSSV -250'MD/-250'TVD 12.Attachments: Description Summary of Proposal ❑✓ 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: 08/25/15 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS E . WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Taylor Nasse Email tnasse@.hilcorp.com Printed Name Taylor Nasse Title Operations Engineer Signature g//-//774:- */ ,A...(--- Phone 907-777-8354 Date 2,7f/I/I S COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 315- `-192 Plug Integrity ❑ BOP Test V Mechanical Integrity Test ❑ Location Clearance ❑ Other: , ifooe p..,..:, fix,r /-f- ( /1,1A- P = / g '1° /'s` Spacing Exception Required? Yes ❑ No El Subsequent Form Required: i(ry y 7 (.. ....:‘,.."j(y APPROVED BY Approved by: Pw -_(/ COMMISSIONER THE COMMISSION Date: 8 •��/'S Rite Submn Form and Form 10-403 Revised 5/20150 valid for 12 months from the date of approval. �� Attach nts in Duplicate RBDMS . P"'' 1 4 2015,.(0��15---.�::r" ,/s • • Well Prognosis Well: GO#8 Hilcorp Alaska,Ida Date:8/11/2015 Well Name: GO#8 API Number: 50-133-20651-00 Current Status: New Grassroots Well Leg: N/A Estimated Start Date: TD of well was 8/10/15 Rig: Saxon#169 Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-077 First Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (M) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907) 229-4824(M) AFE Number: 1511166C Maximum Expected BHP: —2,398 psi @ 5,577' TVD (Assumed 0.43 psi/ft gradient) Max. Allowable Surface Pressure: — 1,840 psi (0.10 psi/ft gas gradient) Brief Well Summary GO #1 is a grass roots development well targeting gas sands in the Beluga and Tyonek formations. This new - well reached TD on 8/10/15. The purpose of this work/sundry is to run the 4.5" completion tubing, jet the well dry with coil, and perforate the well. No spacing exception is required; CO 701 granted unlimited spacing for the combined Beluga/Tyonek Gas pool within1,SOOft of the unit boundary. Y' Notes Regarding Wellbore Condition • Below procedure to be completed post 4.5"liner cleanout noted in PTD step#21.5. (Do not LDDP on the way out). LD 2-7/8"work string on the way out of the hole. • Well will be filled with filtered 6% KCI. Drilling Rig Completion Procedure: 1. MU PBR polish mills. 2. RIH w/4-1/2" DP and tag up on liner top.Work polish mills inside tie-back receptacle. 3. Circulate btms up. POOH. Lay down 4-1/2" DP and polish mills. 4. MU completion w/seal assembly, chemical injection sub, and SSSV nipple. a. Use conventional bands to secure'A" control line to tubing(2 bands per joint). Pk. 5. RIH w/4-1/2" tubing to liner top. a. Circulate corrosion inhibitor into annulus. r/f" b. Land seals in tie-back receptacle. (Space out 24" above locator seal assembly) V 6. Land 4-1/2" tubing hanger. (op7. Test casing (4-1/2" x 7-5/8") to 2,500 psi for 30 min and chart. 8. Test tubing (4-1/2" tubing and 4-1/2" liner)to 5,000 psi for 30 min and chart. 9. Lay down landing joint. Set BPV. ND BOPE. NU 4-1/2" 5000#tree. Pull BPV. 10. Set TWC.Test tubing hanger to 250/5,000 psi.Test tree to 250/5,000 psi. Pull TWC. ( 11. RD Saxon#169 Drilling Rig. 12. Install IA x OA pressure gauges (7-5/8" x 10-3/4"). ,13. Turn well over to production. 'i l • Well Prognosis Well: GO#8 Ililcorp Alaska,LI: Date:8/11/2015 Coiled Tubing Procedure: 14. MIRU Coiled Tubing, PT BOPE to 4,500 psi Hi 250 Low. 15. RIH w/1.5" coil w/CBL tool and run bond log from 9,950' to +/-7,400'. 16. Make CBL logging run with free pipe record and confirmation pass. 17. RIH w/2-1/4"jet nozzle BHA to 10,026' MD and tag PBTD. 18. PU 10ft and displace well fluids with Nitrogen. a. Estimated volume of displaced 6% KCI is 153 bbl. 19. Leave well with+/- 1,600 psi Nitrogen SITP. 20. POOH w/coil. LD 2-1/4"jet nozzle BHA. 21. RD Coiled Tubing. E-Line Procedure 1. MIRU e-line and pressure control equipment. PT lubricator to 250 psi low/3,000 psi high. Note that the well is pressurized with nitrogen. a. If necessary, bleed nitrogen pressure down as requested by the RE to establish a drawdown on the formation. 2. Perforate the Tyonek sands with 2-7/8" 6 SPF 60 deg phased perf guns, RIH with tractors. All intervals are planned for 12 SPF so each zone may be shot twice. Depths are from the Halliburton LWD Combo log dated August 11th, 2015. Send the correlation pass to Taylor Nasse and David Buthman for confirmation. Gross Proposed Perforated Intervals Sands Top (MD) Btm (MD) FT Tyonek T1 ±8,291 ±8,326 ±35 Tyonek T6 ±8,539 ±8,638 ±99 Tyonek T7 ±8,843 ±8,885 ±42 Tyonek T12 ±9,185 ±9,253 ±68 Tyonek T18 ±9,805 ±9,875 ±70 3. POOH. 4. Individually flow each zone through test separator and record water and gas rates. 5. If any of the Tyonek sands are not commercial or wet,the zone will be permanently plugged back. 6. RD e-line. 7. Turn well over to production. 8. Within 10-days of stable production on well, RIH on slickline and set SCSSSV. Notify AOGCC to witness testing of SCSSSV. Attachments: 1. Proposed Schematic 2. Rig BOPE and Choke Schematic 3. Coil BOPE Schematic 4. Wellhead Diagram , 411 • Ninilchik Unit Well: Grassim Oskolkoff#8 PROPOSED SCHEMATIC PTD: 21 1077 API: 20651 00 00 Hilcorp Alaska,LLC CASING DETAIL 1 �a' Size Type Wt Grade Conn. ID Top Btm 16" ' 2 ' 3 ;0'4141+ " 16" Conductor 84 X-56 Weld 15.010" Surf 120' 4 10-3/4" Surf.Csg 45.5 L-80 BTC 9.950" Surf 3,492' F � 4 1'a . ? TOC @ 7-5/8" Prod.Csg 29.7 L-80 BTC 6.875" Surf 7,466' 10-3/4 ',, ^2,000' t$34 ' 4-1/2" Prod Liner 12.6 L-80 DHT/C 3.958" -7,271' 10,198' litr;; 'y. TUBING DETAIL IBT 4-1/2" Tubing 12.6 L-80 3.958" Surf "7,271' f° mod il JEWELRY DETAIL No. Depth ID OD Item ry 1 18' 4.00" - Tubing Hanger,4-1/2"8RD 2 22' 3.958" Pup Joint, IBT x 8RD XO 3.813" 4-1/2" Hydraulic Nipple with WL Retrievable 3 250 2 125" 5.9" SCSSV-Wireline Valve(ID-2.125") 4 -300' 3.85" 5.85" 4-1/2"Chemical Injection Sub A: Baker ZXP Liner Top Packer/HRD-E Profile(10' 911' 5 7,239' tie-back extension) L. 6 -7,272' 3.833" 4.74" Seal Bore Extension"GBH-22" Locating seal , assembly(16.37') , 6 5 `1 ." re' of •' Shoe @ 7,466' 7-5/8" , 4, ♦q RA Mkr Jtkii. w.fi,, 8,211' e' , PERFORATION DETAIL ,. t', Sands Top(MD) Btm(MD) Top(ND) Btm(ND) ft Size Date RA Mkr Jt ,t,.s 8,502' L , ,. T1 ±8,291 ±8,326 ±3,681 ±3,715 35 2-7/8" Proposed ,/ 4{ ,. +r T6 ±8,539 ±8,638 ±3,927 ±4,025 99 2-7/8" Proposed 4; T7 ±8,843 ±8,885 ±4,229 ±4,270 42 2-7/8" Proposed RA Mkr Jt ' .,1 T12 ±9,185 ±9,253 ±4,569 ±4,636 68 2-7/8" Proposed 8,790' *1/04; T18 ±9,805 ±9,875 ±5,185 ±5,254 70 2-7/8" Proposed Ile RAMkr Jt y�, Co WI,'; 9,905' il Xr wq T <iv, lig r:,A. 4' 4,4 6-3/4"hole 4-1/2" ; % -� 1 ,s4;',, • . 1 , Shoe @ 10,198' PBTD=10,026' MD/5,404'ND TD=10,200' MD/5,577'TVD Max Deviation:79 deg @ 2,421' Max Dogleg:6.2 deg/100 @ 1,496' Updated by CAH 8/11/15 ' • • GO #8 14 Completion Procedure Rev. 0 Ililcarp Alaska,in: BOPE Schematic a 111111 III iii di iii fib rii rte, Model b011i ...„11"-saga ,, • tit nil Iii IC Nit �� Model ----" owIf 7. 0 1 3 thew mro- •R- _-4 11" WOO ''� H 1 1" Blind .. — w. ta 2.00' J IItIIj 14 ect - ' 40 'i lit 2 1/15 SM Kill Side 3 1/8 5M Choke Slde 13En-= 1.A1' i Ai ti. Model 1fid2 "Mr: a ...:. ii 4-1/2" Pipe Ram ill iv 191191 1!I IC Grade 2.00' Il 1 Oil Iii iii lin iii .1211ti ... .r_i •: . 4..5. . 7.6 -"TN= s it pi=I al taisaiti� IF II 54-As rs INCiL /6 i� ® Revision 0 June, 2015 • • GO #8 II Completion Procedure Rev. 0 Ililrorp Alaska,1,1,11: Choke Manifold Schematic tip %' / C- . r 417.24 43.62 4362 ul,• i y +a43 t4u U,i'9 a r 0 OWy4 An �j c -'\ 14.62 1143—. -a-4,- _a. C •- 0.311 ��A �� 0.19 0.111 t © ` et ` 01 •.nw�I�.� �>•. � •4.1 Cfiu,.•, r �� N. 619 � 0.19 rl�� ,......,.!....,-.v.I ill/4 •:-.- i ''4,' ,4,,Ire 11 1 , :1:,;-.:',14411 _ I►r%1410. —"I,°°' 9.60 1�:9,�• i` _ g.. -• • • It 7-61 6.19 It y�j -a,t.. 0.19 0 —a Q79-J I \� i '364 0ON 7.44 I ^0.19 __ W © al las 'mule 1 I 1 IIIMMII1 0.19 1.11 J ■ ru___y fir36.w M� -^,. r,.....? 0.N .1 1.62 L,�,`/: • f ' j6." 1.62 38.03 14T;74 CI Ow )j: r 0.19 &A ,/SOl .h• ear- 6 �. AIL I s s '� al9 1�sL. .. 0.19J 40 CI 10 50 MI Azy X11: �� k® p v�.._ =11,=, 44• 1 i 1 —tib/ 1.11.1 161111! \-,19 C3', r 0 -- - - \_42 CHOKE NA9OAL vn/� 1� an —419 OPERATIONJ PA/". -8.31_ t 482----- -----14.52_. —14.62 1..62 631— !7 -_-_- -_ 45 c2.__.__._.._ 4162 /'a tVeVi 67.24 __ C+4"C..KC- CADrr•il`i41.;_._zz s� �� . ._. 1.LAYOUT 1111 R OAS= - I01111 WI NW X. x..-44 la Y i �Tak'✓ .-. 0 11.AO WPC t 1,11''',':',I1710. 7.3.7.7. FI 01201, N I e 3-1 woa..c4 .r. v nm.a ss--39 Revision 0 June, 2015 . 11 • • Ninilchik Unit COIL BOPF. GO #8 08/11/2015 nh,,.,, U13.1,n.!.r(. GO#8 16X10'/4X75/8X4'A Coil Tubing BOP Lubricator to injection head o i rilI I 1.75"Tandem Stripper � 411/16 1 I —// t1/ieio III.—.',I, Blind/Shear _ .....Blind/Shear :4 I1iuIiI Blind/Shear'= III;Blind/Shear'—_ :I mom .. nomi- - �• ;_ ,/ C _-—_ Slip Slip •I,' 011111 Pipe - _• Pipe l �_ Mud Cross - �G 1 4 1/16 10M X 4 1/16 1OM _ Outlet w/2-2 1/16 10M full opening FMC valves 11111- 11111 III illi 0 l! M i[ !liii Ill in nM is Manual Manual Manual Manual 2 1/16 10M 2 1/16 10M riall 'V 2 1/16 10M 2 1/16 10M Crossover spool �, 41/1610M X41/165Mfrl i �� O�t\� 0, .)\‘c Valve,Swab,WKM-M, Ja\Jei do, Je��I15 4 1/16 5M FE, HWO,DD trim (o 1'g5� Jai ,e�a�°� g 31'$c�° op 11111 Imm Valve, Upper Master "'`i�"' WKM-M,4 1/16 5M FE, (4,,..(,--c:; "' : HWO,DD trim ..Ai.. imimmi Valve, Lower Master,WKM-M, 4 1/16 5M FE,HWO,DD trim °� c e 1.11.1.1 Iffi� Grade Level . II • . Ninilchik Unit GO #8 08/11/2015 HiIcorp tia.k...1.11. Ninilchik Unit Tubing hanger,SME-CL,11 X 4'/2 GO#8 EUE lift and susp,w/4"Type H 16 X 10''4 X 7 5/8 X 4 1/2 BPV profile,2-3/8 CCL,Alloy material BHTA,Otis,4 1/16 5M FE X 6.5"Otis Quick Union Valve,Swab,WKM-M, ... \va��e�F.�� 304'1 \r' 1`3�y 4 1/16 5M FE, HWO,DD trim ( ,r).--„-;,;.,, 11y'�� a��ei ��'�aco� v�� ,, 11s�� oQe fa If in F-- :ie.` . 00 Valve,Upper Master MI;WWI WKM-M,4 1/16 5M FE, "''' `1 HWO, DD trim I�o C:% JJ N11�,■i t11. 111.111111 . .. Valve,Lower Master,WKM-M, "0,,N -. 4 1/16 5M FE,HWO, DD trim Pr:--0-- - li,'i' 1. , % a. l_ ' Grade Level Multibowl Wellhead,SMB-22, 2 11 5M X 16%3M w �� : n1 0k'%. 014 4-2 1/16 5M SSO Z• 111 Hip. Starting head,Seaboard, re 16' 3M X16"SOW,w/ ��~�� °. 2-2 1/16 5M EFO • .� 11 ; _ 6) li 16" 10%„ 7 5/8" 4%" • • ! Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Thursday, August 13, 2015 9:40 AM To: 'Taylor Nasse' Cc: Chad Helgeson Subject: RE: GO#8 Rig Completion (PTD 215-077) Taylor, Verbal approval granted to proceed with completion (run tubing with Saxon 169)as outlined in the sundry application. GO#8 may not be perforated until sundry is approved. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). From: Taylor Nasse [mailto:tnasseOhilcorp.com] Sent: Thursday, August 13, 2015 9:13 AM To: Schwartz, Guy L(DOA) Cc: Chad Helgeson Subject: GO #8 Rig Completion (PTD 215-077) Guy- Due to timing and schedule constraints, Hilcorp Alaska would like to respectfully request approval to land the tubing in GO#8 with the Saxon#169 drilling rig in the next day or two, per steps 1-13 in the 10-403 sundry which was submitted on 8/11/15 (see attached for reference). If you have any questions, please feel free to contact me. Thanks, Taylor W. Nasse, PE Operations Engineer Kenai Asset Team Hilcorp Alaska, LLC (907) 777-8354 office (907)903-0341 cell 1 Ati OF Tit % \�\Is, THE STATE Alaska Oil and Gas �,,;- oft.11 LASKA Conservation Commission ` __= 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 Off'4LAS1e*Q` Fax: 907.276.7542 www.aogcc.alaska.gov Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga/Tyonek Gas Pool, Grassim Oskolkoff#8 Hilcorp Alaska, LLC Permit No: 215-077 Surface Location: 3374' FSL, 2726' FEL, SEC. 23, T1N, R13W, SM, AK Bottomhole Location: 1989' FNL, 1759' FEL, SEC. 15, T1N, R13W, SM, AK Dear Mr. Keller: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, 4 Daniel T. Seamount, Jr. Commissioner DATED this /5 day of June, 2015. RECEIVE[ STATE OF ALASKA AlPA OIL AND GAS CONSERVATION COMMI•N MAY 2 7 2015 �\ \c 2 PERMIT TO DRILL .;C�� 20 AAC 25.005 r-t r,,,r,t la.Type of Work: 1 b. Proposed Well Class: Development-Oil ❑ Service- Winj ❑ Single Zone ❑✓ - lc.Specify if well is,proposed for: Drill - ❑ Lateral ❑ Stratigraphic Test ❑ Development-Gay M' Service-Supply ❑ Multiple Zone ❑ Coalbed Gas ❑ Gas Hydrates ❑ Redrill❑ Reentry ❑ Exploratory ❑ Service- WAG ❑ Service-Disp ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blan<et 0 Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC Bond No. 22035244 Grassim Oskolkoff(GO)#8 " 3.Address: 6.Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive,Suite 1400,Anchorage AK 99503 MD: 10,039 - TVD: 5,409' - Ninilchik Field 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Beluga/Tyonek Gas Pool Surface: 3374'FSL,2726'FEL,Sec 23,T1 N,R13W,SM,AK • ADL 389737; Unit Tract 3 Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 1161'FSL, 14'FWL,Sec 14,T1 N, R13W,SM,AK N/A 6/13/2015 ' Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 1989'FNL, 1759'FEL,Sec 15,TIN,R13W,SM,AK 3096 3249'from unit boundry 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL: 183.4 feet . 15. Distance to Nearest Well Open Surface: x-229297.68 - y- 2255334.02 . Zone-4 GL Elevation above MSL: 164.8 feet . to Same Pool: 1,813' (GO#1) 16. Deviated wells: Kickoff depth: 450 feet 17.Maximum Anticipated Pressures in psig(see 20 AAC 2,5„.035)„.„ Maximum Hole Angle: 77 degrees Downhole:1.:',3Z.&X85 psi • Surface:/77,' $66 psi Al G".e-9-/� r 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 13-1/2" 10-3/4" 45.5 L-80 BTC 3,500' 0 0 3,500' • 1,850' . Lead-2179 ft3/Tail-414 ft3 9-7/8" 7-5/8" 29.7 L-80 BTC 7,400' 0 07,400' 2,884' • Lead 1643 ft3/Tail-399 ft3 6-3/4" 4-1/2" 12.6 L-80 DWC/CHT 2,839' 7,200' 2,761' 10,039'. 5,409' - 624 ft3 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth TVD(ft): Plugs(measured): Effect. Depth MD(ft): Effect.Depth TVD(ft): Junk(measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): 20. Attachments: Property Plat n BOP SketcY El Drilling Program 0 Time v. Depth Plot 0 Shallow Hazard Analyss❑ Diverter SketcY ❑✓ Seabed Report ❑ Drilling Fluid Program ❑✓ 20 AAC 25.050 requiremens❑ 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. Luke Keller Contact Ikeller(@..hilcorp.com Email Printed Name Lu e Ke rTitle Drilling Engineer Signature Phone 777-8395 Date 5/27/2015 Commission Use Only Permit to Drill API Number: . Permit Approval See cover letter for other Number: 416- ti 7 • 50-13S-2,04W-00-GCs Date: (.4,..‘6-Z.b t. requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained in sh: Other: -X- LIU 00 pS:, 30(' T Samples req'd: Yes❑ M)® Mud log req'd:Yes❑ No[y]"' H2S measures: Ye;[i NV jj Directional svy req'd:YEs©` Non )- 5,, !t,J ('e.1 \ `!j /rt.- Spacing exception req'd: ye❑ Nh[w]Z Inclination-only svy req'd:Ys❑ No r Co 1„,,fees...—/Pe 4^ 4.--4-;6"' (----11.1e-C 4.4-.41" V APPROVED BY Approved by: A , COMMISSIONER THE COMMISSION Date: 6/i /!�� C.' /. ( - -2-�',/c-- (T)IiRet6 hnths Submit Form and Form 10-401(Revise 0/2012) Ia from the date of approval(20 AAC 25.005(g)) Attachments in Duplic to �6� rr----- Luke Keller • Hilcorp Alaska, LLC Drilling Engineer 3800 Centerpoint Drive Suite 1400 Anchorage,AK 99503 Tel 907 777 8395 Hilcorp Alaska,111,C Email Ikeller@hilcorp.com 5/27/2015 RECEIVED Commissioner MAY 2 7 2015 Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue /► Anchorage, Alaska 99501 AOGCC Re: Permit to Drill GO (Grassim Oskolkoff)#8 Dear Commissioner, GO #8 is a development Tyonek and Beluga well. Primary objectives are Upper Beluga through Tyonek T90 reservoir sandstones. While drilling, we will establish the top of the Tyonek structure in order to determine whether or not to drill the well to its planned TD. The base plan is an"S-Turn"wellbore reaching a maximum inclination of 77 deg and a 6,754'vertical separation. Drilling operations are expected to commence approximately June 13th, 2015. The Saxon Rig # 169 will be used to drill and complete the wellbore. After the rig has departed, the well will be perforated rigless. If you have any questions, please don't hesitate to contact myself at 777-8395 or Paul Mazzolini at 777-8369. Sincerely, Luke Keller Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 • RECEIVED MAY 292015 AOGCC Hilcorp Alaska , LLC Grassim Oskolkoff#8 Drilling Program Ninilchik Field Revision 2 May 28th 2015 • ! RECEIVED GO#8 MAY 2 9 2015 Drilling Procedure rtilrorp Ala ka,I.LC AOGCC Contents 1.0 Well Summary 2 2.0 Management of Change Information 3 3.0 Tubular Program. 4 4.0 Drill Pipe Information: 4 5.0 Internal Reporting Requirements 5 6.0 Planned Wellbore Schematic 6 7.0 Drilling/Completion Summary 7 8.0 Mandatory Regulatory Compliance/Notifications 9 9.0 R/U and Preparatory Work 11 10.0 N/U 21-1/4"2M Diverter 12 11.0 Drill 13-1/2"Hole Section 14 12.0 Run 10-3/4"Surface Casing 18 13.0 Cement 10-3/4"Surface Casing 21 14.0 BOP N/U and Test 24 15.0 Drill 9-7/8"Hole Section 25 16.0 Run 7-5/8"Production Casing 29 17.0 Cement 7-5/8"Cement Procedure 31 18.0 Drill 6-3/4"Hole Section 34 19.0 Run 4-1/2"Production Liner 39 20.0 Cement 4-1/2"Production Liner 42 21.0 Wellbore Clean Up&Displacement 46 22.0 Production Tubing Installation and Perf. 47 23.0 BOP Schematic 48 24.0 Wellhead Schematic 49 25.0 Days Vs Depth 50 26.0 Formation Tops 51 27.0 Anticipated Drilling Hazards 52 28.0 Saxon Rig 169 Layout 55 29.0 FIT Procedure 56 30.0 Choke Manifold Schematic 57 31.0 Casing Design Information 58 32.0 9-7/8"Hole Section MASP 59 33.0 6-3/4"Hole Section MASP 60 34.0 Spider Plot(NAD 27)(Governmental Sections) 61 35.0 Surface Plat(As Built)(NAD 27) 62 36.0 Salinity Calculation 63 37.0 Offset MW vs TVD Chart 64 38.0 Drill Pipe Information 65 • RECEIVED • 11 MAY 2 9 2015 AOGCC Go#s Drilling Procedure Hihorp.alaNka,HA' 1.0 Well Summary Well Grassim Oskolkoff#8 Pad&Old Well Designation GO#8 is a grass roots well on the GO Pad Planned Completion Type 4-1/2"tie back production tubing Target Reservoir(s) Beluga&Tyonek formations Planned Well TD,MD/TVD 10,039' MD/5,409' TVD PBTD,MD/TVD 9,900' MD 5270' TVD Surface Location(Governmental) 3374' FSL, 2726' FEL, Sec 23, T1N, R13W, AK Surface Location(NAD 27) X=229297.681,Y=2255334.021 Surface Location(NAD 83) Top of Productive Horizon (Governmental) 1161'FSL, 14'FWL, Sec 14, T1N,R13W, SM,AK TPH Location(NAD 27) X=226812.81,Y=2258443.94 TPH Location(NAD 83) BHL (Governmental) 1989'FNL, 1759'FEL, Sec 15,T1N,R13W, SM,AK BHL(NAD 27) X=225086.4,Y=2260614.5 BHL (NAD 83) AFE Number 1511166D AFE Drilling Days 33 Days AFE Completion Days AFE Drilling Amount $5,092,700 AFE Completion Amount $600,000 Maximum Anticipated Pressure (Surface) 1784 psig Maximum Anticipated Pressure (Downhole/Reservoir) 2325 psig Work String 4-1/2" 16.6#S-135 CDS-40 (Saxon Owned String) KB Elevation above MSL: 183.4' GL Elevation above MSL: 164.8' (NGVD29) BOP Equipment 11" 5M T3-Energy Annular BOP 11" 5M T3-Energy Double Ram 11" 5M T3-Energy Single Ram Page 2 Revision 2 May, 2015 • • IINF HilcorpAlas LLC Grassim Oskolkoff#8 Drilling Program Ni ilchik Field 14 N/ o Revision 1 May 21st, 2015 i ! GO#8 Drilling Procedure ii t OI1, Ia ka.i,i.c Contents 1.0 Well Summary 2 2.0 Management of Change Information 3 3.0 Tubular Program- 4 4.0 Drill Pipe Information: 4 5.0 Internal Reporting Requirements 5 6.0 Planned Wellbore Schematic 6 7.0 Drilling/Completion Summary 7 8.0 Mandatory Regulatory Compliance/Notifications 9 9.0 R/U and Preparatory Work 11 10.0 N/U 21-1/4"2M Diverter 12 11.0 Drill 13-1/2"Hole Section 14 12.0 Run 10-3/4"Surface Casing 18 13.0 Cement 10-3/4"Surface Casing 21 14.0 BOP N/U and Test 24 15.0 Drill 9-7/8"Hole Section 25 16.0 Run 7-5/8"Production Casing ( 29 17.0 Cement 7-5/8"Cement Procedure ; 31 18.0 Drill 6-3/4"Hole Section r 34 19.0 Run 4-1/2"Production Liner 39 20.0 Cement 4-1/2"Production Liner (, ., 42 • 21.0 Wellbore Clean Up&Displacement Y 46 22.0 Production Tubing Installation and Perf 47 23.0 BOP Schematic 48 24.0 Wellhead Schematic \"'. 49 25.0 Days Vs Depth 50 26.0 Formation Tops 1 51 27.0 Anticipated Drilling Hazards 51 28.0 Saxon Rig 169 Layout (((// 55 29.0 FIT Procedure 56 30.0 Choke Manifold Schematic 57 31.0 Casing Design Information 58 32.0 9-7/8"Hole Section MASP 59 33.0 6-3/4"Hole Section MASP 60 34.0 Spider Plot(NAD 27)(Governmental Sections) 61 35.0 Surface Plat(As Built)(NAD 27) 62 36.0 Offset MW vs TVD Chart 63 37.0 Drill Pipe Information 65 • • GO#8 Drilling Procedure ni:,,h:,.1,1 c 1.0 Well Summary Well Grassim Oskolkoff#8 Pad&Old Well Designation GO#8 is a grass roots well on the GO Pad • Planned Completion Type 4-1/2"tie back production tubing Target Reservoir(s) Beluga&Tyonek formations • Planned Well TD,MD/TVD 10,039' MD/5,409' TVD • PBTD,MD/TVD 9,900' MD 5270'TVD Surface Location(Governmental) 3374' FSL,2726' FEL,Sec,23, T1N,R13W,AK • Surface Location(NAD 27) X=229297.681,Y=2255334.021 • Surface Location(NAD 83) Top of Productive Horizon (Governmental) 1161'FSL, 14'FWL, Sec 14, TIN,R13W, SM,AK TPH Location(NAD 27) X=2268 2.81, Y/2258443.94 TPH Location(NAD 83) BHL(Governmental) 1989' , 159'FEL, Sec 15, T1N,R13W, SM,AK BHL(NAD 27) X=2 084, Y=2260614.5 BHL(NAD 83) AFE Number )8/$411,6.6 AFE Drilling Days Iays� AFE Completion Days AFE Drilling Amount y5,092,700 • AFE Completion Amount ')'$600,000 $600,000 Maximum Anticipated Pressure (Surface) 2866 psig Maximum Anticipated Pressure (Downhole/Reservoir) 3735 psig • Work String 4-1/2" 16.6#S-135 CDS-40(Saxon Owned String) KB Elevation above MSL: 183.4' GL Elevation above MSL: 164.8' (NGVD29) BOP Equipment 11" 5M T3-Energy Annular BOP 11" 5M T3-Energy Double Ram 11" 5M T3-Energy Single Ram Page 2 Revision 0 April, 2015 • • GO#8 Drilling Procedure IIiIc orp AlaAka,LLC 2.0 Management of Change Information Hilcorp Alaska, LLC Hilcorp Cam,Company Changes to Approved Permit to Drill Date: 4-22-2015 Subject Changes to Approved Permit to Drill for Grassim Oskolkoff#8 File#: Grassim Oskolkoff#8 Drilling Program Any modifications to Grassim Oskolkoff#8 Drilling Program will be documented and approved below. Changes to an approved APD will be approved in advance by the AOGCC_ Sec Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Revision 0 April, 2015 • • GO#8 Drilling Procedure Hi14orio iln..la.LLC 3.0 Tubular Program: Hole OD(in) ID(in) Drift Conn Wt Grade Conn Burst Collapse Tension Section (in) OD(in) (#/ft) (psi) (psi) (k-lbs) Cond 16" 15" - - 109 X-56 Weld 13-1/2" 10-3/4" 9.95" 9.875" 11.75" 45.5 L-80 BTC 5210 2470 1040 9-7/8" 7-5/8" 6.875" 6.75" 8.5" 29.7 L-80 BTC 6890 4790 683 6-3/4" 4-1/2" 3.918" 3.833" 5.0" 12.6 L-80 DWC/C 8430 7500 288 HT 4.0 Drill Pipe Information: Hole OD(in) ID(in) TJ ID TJ OD Wt Grade Conn Burst Collapse Tension Section (in) (in) (#/ft) (psi) (psi) (k-lbs) All 4.5" 3.826 2.6875" 5.25" 16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100%mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Revision 0 April, 2015 • • GO#8 Drilling Procedure II li,)rp:th,La,ii is 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area—this will not save the data entered, and will navigate to another data entry tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com; mmyers@hilcorp.com, lkeller@hilcorp.com, &cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a username to login with. 5.4 EHS Incident Reporting • Notify EHS field coordinator. 1. Matt Hogge:0: 777-8418 C:907-227-9829 2. Spills:Julieanna Orczewska: 0:907-777-8444 • Notify Drlg Manager&Drlg Engineer: 1. Paul Mazzolini:0: 907-777-8369 C:907-317-1275 2. Monty M Myers: 0:907-777-8431 C: 907-538-1168 • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final"As-Run"Casing tally to mmyers@hilcorp.com&cdinger@hilcorp.com 5.6 Casing and Cmt report • Send casing and cement report for each string of casing to mmyers@hilcorp.com& cdinger@hilcorp.com Page 5 Revision 0 April,2015 • • GO#8 Drilling Procedure Iliirorp 6.0 Planned Wellbore Schematic • Ninttchik Unit We Grassi7C#skolkoffit8 Planned SCHEMATIC I 20651-x-00 CASING DETAIL 1-1 f ft Size Type Wt Grade Conn. ID Top Btm I SSSV 16" Conductor 84 X-56 Weld 15.010" Surf 120'• 10-3/4" Surf.Csg 45.5 L-80 BTC 9.950" Surf 3,500'• TOC a 7-5/8" Prod.Csg 29.7 L-80 BTC 6.875" Surf 7.400'- 10-3;4 2000' • j-k 4-1/2" Prod Liner 12.6 L-80 DHT/C 3.958" 7,200' 10,039', TUBING DETAIL 4.1/2" Tubing 12.6 L-80 m 3.958" Surf 7,200' JEWELRY DETAIL Depth ID OD Item 1 18' 4.00" - Tubing Hanger,4-1/2" 19' - Pup Joint 3 -170' 4-1/2"SSSV 4 7,140' 4-1/2"Chemical Injection Mandrel 4 T ' 5 ^7,200' 7-5/8"x 4-1/2"Retrievable Production Packer 6 ^7,250' 4-1/2"X-Nipple •` ' ° 7 -7,300' 4-1/2"Tailpipe **Jewelry set depths will be finalized after reviewing the open hole logs** 6 X Tie Back Receptacle Liner Hanger Packer 4)7,200' c;8 Qthi Shoe 4)7,400' - r2.s Gtr- 6-3/4"hole 4-11" .- d Shoe @ 10,024' • PBTD=9,900'MD/5,171'TVD TD=10,039'MD/5,409'TVD Max Deviation:77 plgg Max Dogleg:Islam de2J1 m Page 6 Revision 0 April,2015 • • GO#8 Drilling Procedure u.� 7.0 Drilling / Completion Summary GO#8 is a development Tyonek and Beluga well. Primary objectives are Upper Beluga through Tyonek T90 reservoir sandstones. While drilling,we will establish the top of the Tyonek structure in order to determine whether or not to drill the well to its planned TD. • The base plan is an"S-Turn"wellbore reaching a maximum inclination of 77 deg and a 6,754' vertical separation. Drilling operations are expected to commence approximately June 13th,2015. • The Saxon Rig # 169 will be used to drill and complete the wellbore. After the rig has departed, the well will be perforated rigless. All known freshwater zones in existing water wells (see map) exist above 68 feet in the immediate vicinity of the proposed GO #8 well. The Falls Creek #2 well, drilled in 1966, has the shallowest wireline log information in the area, and salinity calculations indicate: a) the sandstone reservoir at 380' depth has salinities between 2500 and 3300 ppm chlorides, and b) the sandstone reservoir at 955' has salinities between 6000 and 8500 ppm chlorides. The total gas curve from the Falls Creek #2 mudlog first starts recording very shallow gas at 380'. _— 0 ` lALt CAFE 1 ' 1 s tLMy.i.:ryl1l ••• rows cam f•$y .r- yi"1.4 1 �n. ,. '• � Y d lq ML y« h, W. ;_ 1a es .�..�.. • TSR '_' .. _._....._... � lALLi•CJ f�i R $S$1'SS"'' Coa[A CRM • k1q« # ?OUAt 1N11A. G0.0, 1. 001$.1 ` • R • '50411•141. • • 00$$011l GO 8 surface location •. 1 LCHIK ' +-�.-. NNKtMMU 11i # A. A Water Wells (blue triangles) and their Falls Ck#2 well surface location depths in the vicinity of the GO #8 Shallowest logs in vicinity Used to calculate salinities W211. Page 7 Revision 0 April, 2015 • • GO#8 Drilling Procedure IIilrnrp:1la+Ao.LI C Surface casing will be run to 3500' MD and cemented to surface to ensure protection of these resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6 — 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. - All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal/beneficial reuse depending on test results. General sequence of operations: 1. MOB Saxon Rig# 169 to well site 2. N/U 21-1/4"x 2M diverter. 3. Drill 13-1/2"hole to 3500' MD. Run and cmt 10-3/4" surface casing. • 4. N/D diverter,N/U &test 11" x 5M T3-Energy BOP. 5. Drill 9-7/8"hole section to 7,400' MD. Run and cmt 7-5/8" intermediate casing. - 6. Drill 6-3/4"production hole section to well TD. Run and cmt 4-1/2"production liner. 7. TIH w/clean out assy, clean out to landing collar. Displace mud to filtered completion fluid. 8. TOH, LDDP, RIH w/production tubing. 9. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: 1. Surface section: Mud logging only 2. Intermediate section: GR+Res+Den/Neu LWD+mud logging 3. Production section: GR+Res+Den/Neu LWD+mud logging Page 8 Revision 0 April,2015 • • GO#8 Drilling Procedure IIilrorp Ala. a, 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2)week intervals during the drilling and completion of GO #8. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/4000 psi& subsequent tests of the BOP equipment will be to 250/4000 psi for 5/5 min(annular to 50%rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • No waivers requested Page 9 Revision 0 April,2015 • • GO#8 Drilling Procedure Ilileiorik Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 13-1/2" • 21-1/4"x 2M Hydril MSP diverter Function Test Only • 11"x 5M T3-Energy(Model 7082)Annular BOP • 11"x 5M T3-Energy Double Ram Initial Test:250/4000 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross 9-7/8"&6-3/4" • 11"x 5M T-3 Energy Single Ram • 3-1/8"5M Choke Line Subsequent Tests: • 2-1/16"x 5M Kill line 250/4000 • 3-1/8"x 2-1/16"5M Choke manifold (Annular 2500 psi) • Standpipe,floor valves,etc • Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon(12 x 11 gal bottles). • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: • Well control event(BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running&cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email:jim.regg@alaska.gov Guy Schwartz/Petroleum Engineer/(0):907-793-1226/(C): 907-301-4533 /Email: guy.schwartz(c�alaska.gov Victoria Loepp/Petroleum Engineer/(0):907-793-1247/Email: Victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone:907-793-1236(During normal Business Hours) Notification/Emergency Phone:907-659-2714(Outside normal Business Hours) Page 10 Revision 0 April, 2015 • • GO#8 Drilling Procedure IIilrarp ala ka,LI I 9.0 R/U and Preparatory Work 9.1 Set 16" conductor at 120' below ground level. 9.2 Dig out and set cellar. Ensure to level area around cellar so drilling sub structure is level. 9.3 Install Seaboard slip-on 16-3/4" 3M"A" section. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Saxon Rig# 169, spot service company shacks, spot&R/U company man &toolpusher offices. 9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.8 Mix spud mud for 13-1/2"hole section. 9.9 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.10 Install 5-1/2" liners in mud pumps. • TSM 1000 mud pumps are rated at 3633 psi(85%) /333 gpm(100%) with 5-1/2" liners. Page 11 Revision 0 April,2015 • • GO#8 Drilling Procedure Hilcorp 11a4a, a,LLC 10.0 N/U 21-1/4" 2M Diverter 10.1 N/U 21-1/4"Hydril MSP 2M diverter System. • N/U 16-3/4" 3M x 21-1/4"2M DSA(Hilcorp)on 16-3/4" 3M wellhead. • N/U 21-1/4"diverter"T". • Knife gate, 16"diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). 10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking. • A prohibition on ignition sources or running equipment. • A prohibition on staged equipment or materials. • Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set 15.375"ID wearbushing in wellhead. Page 12 Revision 0 April,2015 • i GO#8 Drilling Procedure H iIcorp:1la.ka,LI( 10.5 Diverter Schematic Divertes Srhesn�7ti;. For 13-'7'2 Hole Section t � on II i 7l at ri 44\in-1. Annular Preventer 1111111V -u`y 21-'4"2M I1 Iii Kn.fc Gate Il1IIIt1III lel --u 16" Diverter line Diverter Tee, 21-W x 21-%'x 2M w!16"ANSI 150 outlet _` n_ III 111111 III ItI 16-W 3M x 21-W 2M DSA 11111111111111111111111111. I i 1714 Vet Seaboard 16-W 3M t Casing head Assy 16' Page 13 Revision 0 April, 2015 II • II GO#8 Drilling Procedure nilrurp:11a-6a.LLC 11.0 Drill 13-1/2" Hole Section 11.1 P/U 13-1/2"directional drilling assy: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics • calculations and recommended TFA is attached below. • Workstring will be 4.5" 16.6# S-135 CDS40. • Ensure motor setting can achieve 5 deg/100' DLS in surface hole. Minimum of 1.5 deg AKO is recommended. / 11.2 13-1/2" BHA(No LWD in surface hole BHA): !COMPONENT DATA tem Desurpt rias Numbrr Ymehr tep (in) (° (in( (84111Connac` Ott) Length (ft) 11111 HOBS OHCIGRC MiIItooth " 8.000 3.378 13.500 140.76 P 6-518"REG 100 1.00 © 8'SperryDritt Lobe 4,5-5.3 stg 8.000 5.000 121 08 B 7'H 40 3200 33.00 - Stabilizer -__ 13.250 _--- © 8'MWD DM HOC 8000 1.920 165 44 5 6-518'REG 8.75 41.75 © 8'Inline Stabilizer fiLS) 8.000 1.625 12.125 164.24 B 6-5:8'REG 3.80 45.55 ® 8"MWD TM HOC 8.510 1.920 166 18 B 6-5:8'REG 9.50 55.05 68"Non Mag Flex Drill Collar 8.000 2.813 150.13 B 6-58'REG 29.50 84.55 © 8'Non May Flex Doll Collar 8.000 2.813 150 13 8 6-518-REG 30.00 114 55 8'NM Bottle Neck XO Sub 8.000 2.875 149.18 8 4-112"IF 2.25 116.80 9 6-314"Non May Flex Drill Collar 6.750 2.810 100.82 B 4-112"IF 30.00 146 80 ® 6-314'Non Mag Flex Drill Collar 6.750 2.810 100.82 B 4-112'IF 30.00 176 80 ® X-O 4 1.2'IF P x 4 117 COS 40 8 6.500 2.750 92.85 B 4.5"COS 40 2.75 179 55 ® 4 its 4 112"CDS40 HWOP 4.500 2.813 36.80 122 03 301_55 ® :c-0 4 112'CDS 40 P x 4 112"IF 8 6.500 2.750 92.85 B 4-112"IF 2.75 304 30 ® Weatherford Hyd.Jar 6.480 2.750 92 15 B 4-1/2"IF 32.00 336 30 ® X-04112'IFPx41/2"COS 408 Rig 6.500 2.188 1=1028 84.5"COS 40 2.75 1 -11'S 16 15 its 4 1/7 CDS40 HW DP 4.500 2.813 36.80 460.00 799 05 Totals" 799 05 BIT DATA Bit Number Nozzles :3x16,1x14 Bit Size (in) : 13.500 TFA (int) :0.7394 Manufacturer : HOBS Dull Grade In . Model : OHC1GRC Dull Grade Out Serial Number Page 14 Revision 0 April,2015 • GO#8 Drilling Procedure II lrnrlr Ala..kn, 11.3 Primary bit will be the Security 13-1/2"QHC1GRC Milled Tooth Bit. These are available from Halliburton. 13-1/2" (343mm) QHCI GRC PRODUCT SPECIFICATIONS IADC Code 117W Total Tooth Count 64 q Cage Row Tooth Count 36 Journal Angk 33' Offset(h'l6") 6 Jet Nozzle Types Standard 83244 Extended 311306 Center Jet (lf Center Jetted)501813 Ti.Connection 6-S,'8"(API Reg.( " Recommended Make-tip Torque' 2$000'32000 Et'Iba, Bit weight(Boxed I 260 Lbs.(118 Kg.) Bit Beaker(Mat.W'iLegacya) 183777"64498 Oh 14 PRODUCT FEATURES 411110 • New patented Dian andto Claw*tooth bit design. ,e • I•niprietary Demount I I-(H2000ry full tooth th hanlfacing on cutting structure and gage. • Tungsten carbide'surf inserts in gage teeth for added gage W ` protection • • Premium bearing and seal configuration suitable for both rotaryand " motor applications. ilk • Innovative mechanical pressure compensating system protides reliable pressure,equalization and relief fur maxhnum bearing and seal hfe. • Raised tungsten carbide inserts and proprietary hardfac provides!MINIMUM atm protection in abrasive and directional applications while minimizing drill string torque. • QuadPack-il Plus Series incorporates its successful'longevity" features and patented engineered hydraulics system for optimal cleaning efficiency. • Caner fat feature to prevent bit balling probknts Material#540030 •Calcutatiucn baud on n cummenautioa•(rum API amt tout-iuml menufurtunrs. C 2014 Halliburton.All rights reserved.Saks of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the salt. Page 15 Revision 0 April,2015 • • GO#8 Drilling Procedure Ililrorp Alaska.Ll.f. 11.4 4-1/2" Workstring &HWDP will come from Saxon. Jars will come from Weatherford. 11.5 No LWD tools will be run on the 13-1/2"hole section. 11.6 Begin drilling out from 16"conductor at reduced flow rates to avoid broaching the conductor. 11.7 Drill 13-1/2" hole section to 3500' MD/ 1850' TVD. Plan is to set the surface casing shoe through the base of the build section along the tangent at 78 deg. • Pump viscous sweeps as often as necessary and maintain mud rheology to ensure effective hole cleaning. • Pump at 550 gpm. This gives us an annular velocity of 83 fpm, which is borderline for effective hole cleaning. Ensure shaker screens are set up to handle this flowrate. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. • TD the hole section in a good shale btwn 3450' & 3550' MD. • Take MWD surveys every stand drilled(60' intervals) Page 16 Revision 0 April,2015 • GO#8 Drilling Procedure IIhop.ti .. ,.11.4' 11.8 13-1/2"hole mud program summary: No weighting material will be required in the surface hole section. However, enough barite should be available on location to weight up the active system(1) ppg above highest anticipated MW. We will start with a simple gel+ FW spud mud at 8.8 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 8.8—9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: MD Mudht Viscosity PV YP API FL LGS Weig 120'-3,500' 8.8—9.5 . 250- 85 40 -20 75 -25 <10 <15% System Formulation: AQUAGEL/freshwater Spud Mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 -20 ppb caustic soda 0.1 ppb(8.5—9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8—9.5 ppg PAC-L/DEXTRID LT if required for<10 FL ALDACIDE G 0.1 ppb 11.9 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16" conductor shoe. 11.10 TOH with the drilling assy, handle BHA as appropriate. Page 17 Revision 0 April,2015 • GO#8 Drilling Procedure IIik orp.11a.ka,LLC 12.0 Run 10-3/4" Surface Casing 12.1 R/U and pull 15.375"wearbushing. 12.2 R/U Weatherford 10-3/4"casing running equipment. • Ensure 10-3/4" BTC x CDS 40 XO on rig floor and M/U to FOSV. • R/U fill-up line to fill casing while running. • Ensure all casing has been drifted on the location prior to running. • Be sure to count the total# of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U &thread locking shoe track assy consisting of: • (1) Shoe joint w/float shoe bucked on(thread locked). • (1) Joint with coupling thread locked. • (1) Joint with float collar bucked on pin end &thread locked. • Install(2) centralizers on shoe joint over a stop collar. 10' from each end. • Install(1) centralizer, mid tube on thread locked joint and on FC joint. • Ensure proper operation of float equipment. 12.5 Continue running 10-3/4" surface casing • Fill casing while running using fill up line on rig floor. • Use "API Modified"thread compound. Dope pin end only w/paint brush. • M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values required to achieve this position. Estimated torque to reach base of triangle: 10,750 ft-lbs. • After making up several connections, use the torque required to M/U to base of triangle as the M/U torque and continue running string. • Install(1) centralizer every other joint to 300'. Do not run any centralizers above 300' in the event a top out job is needed. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 10-3/4"BTC Estimated M/U Torque Casing OD Est Torque to Reach Triangle Base 10-3/4" 10,750 ft-lbs Page 18 Revision 0 April, 2015 • GO#8 Drilling Procedure HiIcor!)Ala,ka,Lt( oloo - Tenaris Casing and Tubing Performance Data Choose pipe size,wall thickness and steel grade to view API connection options and performance data. Size r"Jail • Grade Connection • Unit • Pipe Body Data GEOMETRYA Nominal OD 10.750 in Wall Thickness 0.400 in API Drill Diameter 9.794 in 'Nominal ":eight 45.50 Ibs41 Nominal ID 9.950 in Alternate Drill Diameter 9.875 in Plain End*eight 44.26 Ibs4t Nominal Cross Section 13.006 sq in PERFORMANCE Steel Grade 180 Minimum Yield 80.000 psi Minimum Ultimate 95,000 psi Body Yield Strength 1,040,000 lbs Internal Yield Pressure 5.210 psi Collapse Pressure 2,470 psi ISI f _(��. Connection Data GEOMETRY !Regular 00 11.750 in Threads Per Inch 5 Make-Up Thread Turns 1 PERFORMANCE Steel Grade L80 Minimum Yield 80,000 psi Minimum Ultimate 95,000 psi 'Joint Strength 1.063,000 lbs Internal Pressure 5.210 psi Resistance TenarisHAril Premium Connections Print Contact Us ver 8.8 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe 5-10' from TD if possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Page 19 Revision 0 April,2015 • • GO#8 Drilling Procedure H ih orp:ua.aa,ia.c 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. Page 20 Revision 0 April,2015 • • GO#8 Drilling Procedure II I orp;11a..ka.I.I,C 13.0 Cement 10-3/4" Surface Casing 13.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud &water can be delivered to the cmt unit at acceptable rates. • Flush cement lines with 10 bbls water before pumping any fluid downhole. • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • Schlumberger pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 13.2 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.3 Pump 5 bbls 10 ppg spacer. Test surface cmt lines. Pump remaining 35 bbls 10 ppg spacer. 13.4 Drop bottom plug. Mix and pump cmt per below recipe. 13.5 Cement volume based on annular volume+ 100%open hole excess. Job will consist of lead & tail, TOC brought to surface. Estimated Total Cement Volume: Section: Calculation: Vol(BBLS) Vol(ft3) LEAD: 80' x.106 bpf= 8.5 48 16"Conductor x 10-3/4" casing annulus: LEAD: (3000' —80')x .065 bpf x 2= 379.6 2131 13-1/2"OH x 10-3/4" Casing annulus: Total LEAD: 388.1 2179 , 5 TAIL: (3500'-3000')x .065 bpf x 2 = 65 365 13-1/2" OH x 10-3/4" Casing annulus: TAIL: 90 x .096 bpf = 9 49 10-3/4" Shoe track: Total TAIL: 74 414 5 Z3 .,r Page 21 Revision 0 April,2015 • • GO#8 Drilling Procedure Hileorp Aleka.LLf. Cement Slurry Design: Lead Slurry (3000' MD to surface) Tail Slurry (3500' to 3000' MD) System Blend Conventional Density 12 lb/gal 15.2 lb/gal Yield 2.44ft3/sk / 1.26 ft3/sk ✓` Mix Fluid 14.437 gal/sk 5.76 gal/sk Base Fluid 14.417 gal/sk 5.76 gal/sk Expected 5 HR 3 HR Thickening Code Description Concentration Code Description Concentration D901 Cement 94 lb/sk D901 Cement 94 lb/sk D046 Antifoam 0.2%BWOC D046 Antifoam 0.2%BWOC D020 Extender 2.6%BWOC D065 Dispersant 0.4%BWOC Additives D079 Extender 2%BWOC D167 Fluid Loss 0.2%BWOC D110 Retarder 0.02 gal/sk cmt S002 Accelerator 0.25%BWOC 13.7 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets"sticky", land the hanger on seat and continue with the cement job. 13.8 After pumping cement, drop top plug and displace cement with 9.2 ppg 6% KCl/PHPA drilling fluid (mud to be used on next hole section). 13.9 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.10 Displacement calculation: 3420' x.0962 bpf= 329 bbls 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sugar available to retard setting of cement(1 ppb). 13.12 Do not overdisplace by more than '/2 shoe track volume. Total volume in shoe track is 8.7 bbls. 13.13 Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log btwn 6— 18 hours after CIP. Page 22 Revision 0 April,2015 • • GO#8 Drilling Procedure nile,orio:tla.ka,IA t 13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.15 R/D cement equipment. Flush out wellhead with FW. 13.16 Back out and L/D landing joint. Flush out wellhead with FW. 13.17 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.18 Lay down landing joint and pack-off running tool. Ensure to report the following on wellez: • Pre flush type,volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing,bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement,actual displacement volume, whether plug bumped&bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface&volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Send final `As-Run"casing tally&casing and cement report to mmyers@hilcorp.com & cdinger@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 23 Revision 0 April,2015 • GO#8 Drilling Procedure orp ala�ka,IA 14.0 BOP N/U and Test 10-(1 ,- I 14.1 N/D the diverter. 14.2 N/U Seaboard multibowl wellhead assy. Install packoff 10-3/4"P-seals. Test to 3000 psi. 14.3 N/U 11"x 5M T3-Energy BOP as follows: • BOP configuration from Top down: 11"x 5M T3-Energy annular BOP/11"x 5M T3-Energy Model 6011i double ram/11"x 5M mud cross/11"x 5M T3-Energy Model 6011 i single ram • Double ram should be dressed with 2-7/8 x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should be dressed with 2-7/8 x 5"VBRs • N/U bell nipple, install flowline. • Install(2) manual valves& a check valve on kill side of mud cross. • Install(1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Run 4-1/2"BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/4000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 R/D BOP test assy. 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 9.2 ppg 6%KC1/PHPA drilling fluid for 9-7/8"hole section. 14.8 Set 10" ID wearbushing in wellhead. 14.9 Rack back as much 4-1/2"DP in derrick as possible to be used while drilling the hole section. 14.10 Install 5" liners in mud pumps. • TSM 1000 mud pumps are rated at 4250 psi(85%) /275 gpm(100%) with 5" liners. Page 24 Revision 0 April, 2015 • ED • RECEIV MAY 2 9 2015 Go #a Drilling Procedure Hilrorp Ala.l.a,II t' OGCC 15.0 Drill 9-7/8" Hole Section 15.1 Prior to P/U 9-7/8" directional assy, test casing against blind rams to 2600 psi/ 30 min. 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 Bit TFA should be -0.75 -0.80 in2. We need to pump at-450 - 500 gpm to clean the hole effectively. Have the directional driller run hydraulics calculations to confirm optimum TFA. 15.5 P/U the below 9-7/8" directional drilling assy (GR + RES +Den/Neu LWD) included in below BHA): COMPONENT DATA 1 ftem Description Serial Number OD ID Gauge Wei R Length Cumulatirrl * on) (n) (in) tlbpt) Conn . `' (ft) Length (ftl 1 HOBS MId65 PDC 7.000 2 500 9.875 114.43 P 4-112"REG 0.90 0.90 2 7"Sperr,'Drili Lobe 718-6.0 stg 7.000 4.952 93.13 B 4-1J2"IF 26.40 27.30 Stabilizer 9.625 3 6-314"NM Stabilizer 6.7 50 3.063 8.750 96.84 B 4-1:2"IF 7.00 34.30 4 6-3.4"Float Sub 6.750 2.813 100.78 B 4-1;2"IF 2.20 36.50 5 6-314"DM Collar(Directiona 1 6.750 3.125 103.40 B 4-1;2"IF 9 20 45 70 6 6 3:4"DGR Collar(Gamma; 6.750 1.920 97.80 B NC 50 4.55 50.25 7 6 3.+4"EWR-P4 Collar i Resistivity? 6.750 2.000 104.30 B NC 50 12.10 62.36 8 6 14"PWD(Pressure? 6.750 1.905 96.30 8 4-1,2"IF 4.44 66.79 9 6 3:4"HCIM Collar;Processor} 6.750 1.920 10'.70 B NC 50 4.97 71.76 10 6 3:4"ALD Collar;Density; 6.750 1.920 8.250 104.30 B 4-112"IF 14.54 86.30 Stabilizer 8.250 11 6 34"CTN Collar(porosity; 6.750 1.905 102.30 B 4-1±2"IF 1' 84 98.15 12 6-3.:4"TM.Collar(Telemetry i 6 750 3.250 103.60 B 4-1,2"IF 10.00 108.15 13 6-34"Non Mag Flex Collar 6750 2.813 10078 B 4-1:2"IF 30.00 138 15 14 6-3:4"Non Mag Flex Collar 6.750 2.813 100.78 B 4-1:2"IF 30.00 168.15 15 6-34"Well Commander Sob 6.750 3.000 97.86 B 4-1:2"IF 13.00 181.15 16 X:0 4.5"IF P x 4.5"CDS 4013 6.500 2.750 92.85 B 4.S CDS 2.75 183.90 17 4 x jts 4.5"HWDP 4.500 2.813 33.02 120 00 303.90 18 K:0 4.5"CDS 40 P x 4.5"IF B 6.500 2750 92.85 B 4-1,'2"IF 2.50 306.40 19 6-1:4"Weathertor0 Jar 6.250 2.313 90.24 B 4-112"IF 30.00 336.40 20 X10 4.5"IF P x 4.5"COS 4013 6.500 2.188 100.27 B 4.40CDS 3.00 339.40 21 15 x jts 4.5"HWDP 4.500 2.813 33.02 450 00 789.40 ,:i=411 789.4 Page 25 Revision 2 May, 2015 0 s GO#8 Drilling Procedure nil, np u-k.,.IJ( 15.0 Drill 9-7/8" Hole Section 15.1 Prior to P/U 9-7/8"directional assy, test casing against blind rams to 2600 psi/30 min. 15.2 Ensure BHA components have been inspected previously. //' 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 Bit TFA should be -0.75 -0.80 in2. We need to pump at -450 - 500 gpm to clean the hole effectively. Have the directional driller run hydraulics calculations to confirm optimum TFA. / 15.5 P/U the below 9-7/8" directional drilling assy(GR+ RES + Den/Neu LWD) included in below BHA): 1 COMPONENT DATA ' -m OD ID Stiff ID Gauge Weight Top Length Total ti. Description # enr en) (in) (In) (IbPR Connection of ot am) ) 1 HDBS MM65 PDC 7 s 0' , .500 1 / 9.875 114 P 4-1/2"REG 0 90 2 7"SperryDrill Lobe 7+8-6.0 stg 7.000 4.952/�iA.4.952 93.13 B 4-112"IF 26.40 27.30 .+r 3 6-3;4"Float Sub ( 6.7 i 2. 3 t/ 2.813 100.78 B 4-1;2"IF 2 20 29-50 4 6-3:4'DM Collar(Directional) 6 50 3. 3.155 103.40 B 4-1;2"IF 9 20 38.70 5 6-14"DGR Collar(Gamma) •_75(1,620 4.430 97.80 B NC 50 4 55 43.25 6 6-3:4'EWR-P4 Collar(Resistivity) ''.• , 6.750\21000 3.978 104.30 B NC 50 12.10 55.36 7 6-3+4"HCIM Collar[Processor) 6 750 1 920 3 667 101.70 B NC 50 4 97 60 33 8 6-3:4"TM Collar(Telemetry) 6.750 3.250 3 551 103.60 B 4-112"IF 10.00 70.33 9 6-3:4'Non Mag Flex Collar 6.750 2 813 100 78 B 4-112"IF 30 00 100.33 10 6-3:4"Non Mag Flex Collar 6.750 2.813 100.78 B 4-112"IF 30.00 130.33 11 6-314'Well Commander Sub 6 750 3-000 3 000 97 86 B 4-1;2"IF 13.00 143 33 12 X+O 4.5"IF P x 4.5"CDS 40 B ' 6.500 2.750 2 750 92.85 B 4.50 DS 2.75 146.08 13 4 x jts 4.5"HWDP 4.500 2.813 3302 120.00 266.08 14 X+O 4.5"CDS 40 P x 4.5'IVB 6 500 2.750 2 750 92.85 B 4-1;2"IF 2.50 268.58 15 6-1:4'Weatherford Jar / 6 250 2.313 2 313 90 24 B 4-1;2"IF 30.00 298.58 16 X+O 4.5'IF P x 4.5"CDS 40 8 6.500 2.188 2 '88 100.27 B 4'5"C 0 D5 3.00 301.58 17 15 x its 4.5'HWDP 4.500 2.813 33.02 450.00 751.58 ,w ,a 751.58 Page 25 Revision 0 April, 2015 ! • 11 GO#8 Drilling Procedure IliIvorp Ala...ka,II.( 15.6 Primary bit will be the Security 9-7/8" MM65. 9-718" (251mm) MM65 PRODUCT SPECIFICATIONS Cutter Type SelectCutter Itt IADC Code M323 ar• Body Type MATRIX e 9 at Total Cutter Count 46 } 4 Cutter Distribution j jplt4 J�pti # # Face ti 2$ g Fes' Gauge 12 0 ett �` Up Drill 6 0 g r Number of Large Nozzles 6 Nutrtbct of Medium Nozzles 0 ,,Number of Small Nozzles 0 ar, Number of Micro Nozzles 0 • r R• Number or Plats(Sire) 0 + Number of Replaceable Ports lSizcl dt Junk Slot Arca l sq in) 16.71 0 ..‘,1" ! Normalised Face Volume 45.49% API Connection 4-112 REG.PIN Recommended Make-Up Torque' 12,461-17.766 Ft•tbs. Nominal Dimensions** Make-Up Face to Nose 10.81 in-275 mm Gauge Length 2.5 in•64 atm Sleeve Length 0 in-0 men Slunk Diameter 6 in-152 men Break Out Plate 1Mat iflegneyal IIfi954144P10 Approximate Shipping Weight 250Lbs.-113Kg. SPECIAL FEATURES Up-Lein Cutters on Hage Pads,U 16"Relieved Gage Material#771827 'Bit specific recommended make•up torque is a Iunciian of tbe bit I.D.and acnol bit sub O.D.utilised as'Twilled in API RPTG Sorban A.n.2. **Demon damcn,ens nen nominal and teas vary sliyhsty on nwnul,sctuml ImIxioa.tlaltihwuin Drill Hits and$emcee models are eontinunualy n niessed and relined Product sped ficatium may change without notice. C,2013 Halliburton.All rights reserved_Saks of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the sale. Page 26 Revision 0 April, 2015 • GO#8 Drilling Procedure Ililrnrp alnska,I,LC 15.7 9-7/8" hole section mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system(1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.2—9.8 ppg 6%KCUPHPA fresh water based drilling fluid. Properties: MD Mud Viscosity Plastic Yield Point pH HPHT Weight Viscosity 3,500'-7,400' 9.2—9.8 40-53 15-25 15-25 8.5-9.5 < 11.0 System Formulation: 6% KCL/EZ MUDBDF-499 Product Concentration Water 0.905 bbl KC1 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) BDF-499 4 ppb EZ MUD DP 0.75 ppb(initially 0.25 ppb) DEXTRID LT 1-2 ppb PAC-L 1 ppb BARACARB 5/25/50 5—10 ppb(3.3 ppb of each) BAROTROL PLUS 2—4 ppb SOLTEX 2—4 ppb BAROID 41 as required for a 9.2—9.8 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 ppb (maintain per dilution rate) 15.8 TIH, conduct shallow hole test of MWD and confirm LWD functioning properly. 15.9 Continue in hole and tag TOC. Note depth tagged on AM report. 15.10 Drill out plugs and shoe track. Clean out rat hole and drill an additional 20' of new formation. 15.11 CBU and condition mud for FIT. 15.12 Conduct FIT to 12 ppg EMW. 15.13 Drill 9-7/8"hole section to 7,400' MD/2,884' TVD. Page 27 Revision 0 April,2015 i GO#8 Drilling Procedure 11111111 l:ua+ka.1,1.c • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 500- 510 gpm. Ensure shaker screens are set up to handle this flowrate. • Utilize inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team,try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. If tight hole is encountered, screw in and begin backreaming connections until hole conditions improve. Shales in the Beluga formations are notorious for swelling and causing tight hole. Most of the time, backreaming them on a short trip is the only solution. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 8. • Take MWD surveys every stand drld. Surveys can be taken more frequently if deemed necessary. • Mud Loggers: 30 ft samples with 20' samples in zones of interest, two sets of cuttings, chromatograph, pixler plots. 15.14 Casing point will be determined by hole conditions while drilling from 7300' MD to 7500' MD. 15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 10-3/4" shoe. 15.16 TOH with the drilling assy, handle BHA as appropriate. Page 28 Revision 0 April, 2015 • • GO#8 Drilling Procedure Ililr0111.11aK6a,LI,4 16.0 Run 7-5/8" Production Casing 16.1 R/U and pull 10" ID wear bushing. Install and test 7-5/8"casing ram in top ram cavity. Test to 250/4000 psi. 16.2 Make a dummy run with casing hanger. Mark landing joint at land out for later reference. 16.3 R/U Weatherford 7-5/8"casing running equipment. • Ensure 7-5/8" BTC x CDS-40 XO on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total# of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. 16.4 P/U 7-5/8" 29.7# L-80 BTC shoe joint, visually verify no debris inside joint. 16.5 Continue M/U &thread locking the shoe track assy consisting of: • (1) Float shoe joint w/float shoe bucked on. Install(2)bow spring centralizers at 10' from each end over a stop collar. • (1) Baker locked joint. Install(1) centralizer mid tube over a stop collar. • (1) Float collar joint w/float collar bucked on pin end. Install(1) centralizer mid tube over a stop collar. • Ensure proper operation of float shoe and float collar. 16.6 Run 7-5/8" 29.7#L-80 BTC casing. • Fill casing while running using fill up line on rig floor. • Use "API Modified"thread compound. Dope pin end only w/paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install centralizers over couplings on every joint to 6,000' MD. • Install centralizers over couplings on every other joint to 3,400' MD. 16.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.8 Slow in and out of slips. 16.9 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe approx 10—20' above TD with hanger landed out. Page 29 Revision 0 April,2015 • • GO#8 Drilling Procedure Ill orp..Ia.ka, Casing and Tubing Performance Data PIPE BODY DATA GEOMETRY Outside Diameter 7.625 in Wall Thickness 0.375 in API Drift Diameter 6.750 in Nominal Weight 29.70 lbs/ft Nominal ID 6.875 in Alternative Drift Diameter n.a. Plain End Weight 29.06 lbs/ft Nominal cross section 8.541 in PERFORMANCE Steel Grade 180 Minimum Yield 80,000 psi Minimum Ultimate 95,000 psi Tension Yield 683,000 in Internal Pressure Yield 6,890 Psi Collapse Pressure 4,790 psi Available Seamless Yes Available Welded No CONNECTION DATA TYPE:BTC GEOMETRY Coupling Reg OD 8.500 in Threads per in 5 Thread turns make up 1 PERFORMANCE Steel Grade 180 Coupling Min Yield 80,000 psi Coupling Mm Ultimate 95,000 psi Joint Strength 721,000 lbs Internal Pressure Resistance 6,890 psi 7-5/8" BTC Estimated M/U Torque Casing OD Est Torque to Reach Triangle Base 7-5/8" 7,630 ft-lbs 16.10 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 16.11 R/U circulating equipment and circulate the greater of 1 x casing capacity and 1 x OH volume. Elevate the hanger offseat (slightly) to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 16.12 Continue circulating until required properties achieved for cmt operations. 16.13 After circulating, lower string and land hanger in wellhead again. Page 30 Revision 0 April,2015 GO#8 Drilling Procedure II ihorp 11:o.ka.LTA' 17.0 Cement 7-5/8" Cement Procedure 17.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. • Flush cement lines with 10 bbls of water before any fluid goes downhole. • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • Schlumberger will be utilized for displacement, discuss how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 17.2 R/U cmt head(if not already done so). Ensure top&bottom plugs are loaded correctly. 17.3 Pump 5 bbls 10 ppg spacer. Close low torque on plug dropping head, test surface cmt lines to 4000 psi. 17.4 Pump remaining 35 bbls 10 ppg spacer. 17.5 Mix and pump slurry per below calculations: Section: Calculation: Vol(BBLS) Vol(ft3) LEAD: (6400'- 2'000')x .038 bpfx 1.75 = 293 1643 9-7/8" OH x 7-5/8"csg: Total Lead: 293 bbls 1643 ft3 103`t s- TAIL: 1000' x .038 bpf x 1.75 = 67 373 9-7/8" OH x 7-5/8"csg: TAIL: 7-5/8" Shoe Track: 90' x.046 bpf= 4 23 Total Tail: 71 bbls 399 ft3 49,1 Y Si Page 31 Revision 0 April, 2015 I GO#8 Drilling Procedure Ilileorp Slurry Information Stage Lead Tail System Conventional Conventional Density 12.4 lb/gal 15.3 lb/gal Yield 1.58 ft3/sk 1.35 ft3/sk ' Mixed Water 8.09 gal/sk 5.912 gal/sk Mixed Fluid 8.09 gal/sk 5.962 gal/sk Expected Thickening 5:30 HR:MIN 4:00 HR:MIN Expected ISO/API Fluid Loss 13 mL in 30 min Code Description Concentration Code Description Concentration G Cement 94 lb/sk WBWOB G Cement 94 lb/sk WBWOB D110 Retarder 0.05 gal/sk D110 Retarder 0.05 gal/sk VBWOC VBWOC Additives D046 Anti Foam 0.2%BWOB D046 Anti Foam 0.2%BWOB D020 Extender 4.0%BWOB D202 Dispersant 1.5%BWOB D065 Dispersant 0.3%BWOB D400 Gas Control Agent 0.8%BWOB D800 Retarder 0.2%BWOB D154 Extender 8.0%BWOB D174 Expanding Agent 1.5%BWOB 17.7 After pumping cement, drop flexible shut-off plug and displace cement with mud. Use the cement unit to displace with as volumes can be tracked much more accurately. Displacement calcs: • 7,320' x .0459 bpf= 336 bbls. • Displace with 9.2 ppg 6%KC1/PHPA drilling fluid out of mud pits. 17.8 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 17.9 Do not overdisplace by more than V2 shoe track volume. Total volume in shoe track is 4.1 bbls. 17.10 There should be no cmt returns to surface. TOC is planned to be at 2,000' MD. 17.11 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. • If this is the case, monitor the pressure on the casing and do not let it exceed 500 psi over the final pump pressure. Page 32 Revision 0 April,2015 • • GO#8 Drilling Procedure r 1,4,91:u,wa. Ensure to report the following on wellez: • Pre flush type, volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing,bpm,note any shutdown during mixing operations with a duration • Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement,actual displacement volume, whether plug bumped&bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface&volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Send final "As-Run"casing tally&casing and cement report to mmyers@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 17.1 R/D cement equipment. Flush out wellhead with FW. 17.2 Back out and L/D landing joint, flush out wellhead with FW. 17.3 M/U pack-off running tool and pack-off to bottom of landing joint. Set casing hanger pack-off Run in lock downs and inject plastic packing element. Test void to 250/3000 psi for 10 min. 17.4 Lay down landing joint and pack-off running tool. Page 33 Revision 0 April, 2015 I I GO#8 Drilling Procedure Ililrorp.11�*Aa. 1,1 I 18.0 Drill 6-3/4" Hole Section 18.1 Remove 7-5/8"casing rams from BOP. Install 2-7/8" x 5"VBRs in top cavity. BOP configuration should be (from top down): Annular/VBR/Blind/Mud crossNBR. 18.2 Test BOPs on 4-1/2"test joint, 18.3 Pull test plug, run and set wear bushing. 18.4 Ensure BHA Components have been inspected previously. 18.5 Ensure to have enough 4-1/2" DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 18.6 Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 18.7 Ensure TF offset is measured accurately and entered correctly into the MWD software. 18.8 Confirm that the bit is dressed with a TFA of 0.46 sqin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 270 gpm. 18.9 Triple combo LWD will be run in 6-3/4" hole section: • Gamma Ray (DGR: Combined Gamma Ray) • Resistivity(E WR: Shallow/Med/Deep) • Density(DEN: Bulk Density) • Neutron(NEU: Thermal neutron porosity) • Density Image, dip picks, and additional engineer for same. Page 34 Revision 0 April, 2015 • 0 II GO#8 Drilling Procedure Hileorp Alaska,III: 18.10 P/U below 6-3/4"directional drilling assy: NENT DIt I m OD ID Stiff ID Gauge Weight Tap Length Total Location Description (in) (in) (in) (in) (140Connection (ft) (It) (ft) 0 HOBS EM165D PDC 4.500 2.250 6.750 40.65 P 3-1/2"REG 0.80 ©5"SperryDrill Lobe 6/7-6.0 stg 5.000 3.120 3.120 48.00 B 3-112"IF 23.20 24.00 E.4-314"Float Sub 4.750 2.250 1.000 46.84 OM 2.20 26 20 0 4-314'DM Collar(Directional) 4750 2.610 2.638 47.00 9.20 35.40 im 4-3i4"SP4 Collar(Gamma&Res t.:ty , 4.750 1.250 3.280 48.20 8 3-112"IF 24 57 59.97 0 4-3/4"ALD Collar(Density) - 4.750 1.250 2.696 6 000 45.50 B 3-1;2"IF 14 35 74 32 67 31 -Stabilizer __ 0 030 67.31 ©4-314"CTN Collar..Porosity) - 4.750 1.250 1 853 50.50 B 3-112"IF 11.14 85 46 0 4-314"TM Collar(Telemetry) - 4.750 2.812 3 039 46.10 MEM 11.00 96.46 MIS 9 4-314"Non Mag Flex Collar 4.750 2.250 46.84 InGEI 30.00 126.46 1111111 10 4-314'Non Mag Flex Collar 4.750 2.250 46.84 B 3-112"IF 30.00 156.46 ®3.5'IF P x 4.5'CDS 40 B 5 300 2.250 2 250 61.64 6 CDS 402" 2 50 158.96 11111 ®2 xjts 4.5"HWDP 4.500 2.750 41.00 6000 218.96 ®4.5'CDS 40 P x 3.5"IF 8 5.300 2.200 2.250 62 23 8 3-112"IF 2.50 221.46 igi 4.75"Weatherford Jar 4.800 2.250 2.250 48.12 8 3-112"IF 30.00 251.46 112 3.5"IF P x 4.5"CDS 40 8 5.250 2.250 2250 60.22 B 4.5"4 1.2" 2.50 253.96 CDS 40 16 17 x jts 4.5"HWDP 4.500 2.750 4100 510 00 763.96 <, 763.96 Page 35 Revision 0 April, 2015 • • GO#8 Drilling Procedure !Menet)leorp:Ua-ka.l I.c 18.11 Primary bit will be the Security EM65D: 6-3/4" (171mm) EM65D PRODUCT SPECIFICATIONS Cutter Type X3-Extreme Drilling "" IARC Cody M323 � ' Body Type MATRIX ,+Al Total Cutter Count 33 Cutter Distribution jj1p� If= " 4 Face .f 1; i Gauge 11 l 1!. Up Drill 3 0 ; * Number of Large Nozzles 0 Number of Medium Nozzles 0 Number of Nozzles 6 " Number of Micro Nozzles 0 Number of Puns!Biota 0 Number of Replaceable Ports I Size) 0 11'' f' :11111: re'''' Junk Slot Area 1sq in) 8.68 l` i Nnrmalried Face,aalumc 34.6'Yl. sr API Connection 3-I12 KEG.PIN k'� *ae Recommended Make-Up Torque* 5.173—7,665 FNlbs. iTM, t ' Nominal Dimensions** Make-Lep Face to Nose 9.42 in-239 mm Gauge Length 2 in-51 mm Sleeve Length 0 in-0 town Shank Diameter 4.5in-114min Bre*k Out Plate IMat.a egacyk) 181953.440341 Approximate Shipping Weight 90Lbs.-41 Kg. SPECIAL.FEATURES Up-Drill Cutters on Gage Pads,1:16"Steppe!Gage,.Optimized Dual Row-"D"Feature Material#761302 'Bit specific aecutnmended make-up torque is a Punt-ton ut the hit I,D.and actual hit sub O.D.utilized as specified in API Rl'G Section AA..? **Desagn dimensions.•re nominal and lazy vary slightly on ntuasefacmred product.Hallihunon Drill Airs and Servicre models are conrinuaunly reviewed and refused. Product epecifacanens away chattier without notice. ✓C 2013 Halliburton.All rights reserved.Saks of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the sale. www.haliibutton.com Page 36 Revision 0 April, 2015 • • GO#8 Drilling Procedure Ililrorp 11:4.1a,LLC 18.12 TIH to TOC. Shallow test MWD on trip in. Note depth TOC tagged at on AM report. 18.13 Conduct casing test to 3500 psi/30 min. 18.14 Drill out shoe track and additional 20' new formation. CBU and prep for FIT. 18.15 Conduct FIT to 12.5 ppg EMW. 18.16 9-7/8"hole section mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system(1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.2 ppg 6%KC1/EZ MUD/BDF-499 fresh water based drilling fluid. Properties: MD Mud Viscosity Plastic Yield Point pH HPHT Weight Viscosity 7,400'- 10,039' 9.5— 10.5. 40-53 15-25 15-25 8.5-9.5 < 10.0 System Formulation: 6% KCL/EZ MUDBDF-499 Product Concentration Water 0.905 bbl KC1 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) BDF-499 4 ppb EZ MUD DP 0.75 ppb DEXTRID LT 1-2 ppb PAC-L 1 ppb BARACARB 5/25/50 15-20 ppb(5 ppb of each) BAROID 41 as required for a 9.2—9.6 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 ppb (maintain per dilution rate) 18.17 Drill 6-3/4" hole to 10,039' MD/5,409' TVD using above motor assembly. Page 37 Revision 0 April,2015 • • GO#8 Drilling Procedure • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • See attached mud program for hole cleaning and LCM strategies. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. • Ensure mud engineer set up to perform HTHP fluid loss. • Maintain HTHP fluid loss <6. • Take MWD surveys every stand drilled. • Mud Loggers: 30 ft samples with 20' samples in zones of interest,two sets of cuttings, chromatograph, pixler plots. 18.18 Hilcorp Geologists will follow LWD log closely to determine exact TD. 18.19 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8" shoe. 18.20 TOH with drilling assy, handle BHA as appropriate. Drop drift on trip out. Page 38 Revision 0 April,2015 • GO#8 Drilling Procedure orp ( 19.0 Run 4-1/2" Production Liner 19.1 M/U and rack cement stand in derrick. • Ensure to drift components prior to M/U. Ensure dart will pass through components. • Confirm largest OD of packer assy will pass through wear bushing. 19.2 R/U Weatherford 4-1/2" casing running equipment. • Ensure 4-1/2"DWC/C HT x CDS 40 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total# of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor &model info. 19.3 P/U shoe joint, visually verify no debris inside joint. 19.4 Continue M/U &thread locking shoe track assy consisting of: • (1) Shoe joint w/shoe bucked on&threadlocked(coupling also thread locked). • (1) Joint with float collar bucked on pin end &threadlocked (coupling also thread locked). • (1) Joint with landing collar bucked on. • Solid body centralizers will be pre-installed on shoe joint&FC joint. • Install a solid body centralizer on landing collar joint. Leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe. 19.5 Continue running 4-1/2" prod liner • Fill casing while running using fill up line on rig floor. • Use"API Modified"thread compound. Dope pin end only w/paint brush. • Install solid body centralizers on every joint to 7,400' MD. Leave the centralizers free floating. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 4-1/2"DWC/C HT M/U torques Casing OD Minimum Maximum Yield Torque 4-1/2" 5,800 ft-lbs 6,500 ft-lbs 7,200 ft-lbs Page 39 Revision 0 April,2015 • • GO#8 Drilling Procedure Hiker!).Alaska,LLC Technical Specifications Connection Type: Size(O.D.): Weight(Wall): Grade: DWC+C Tubing 4-1/2 in 12.60 lblft(0.271 in) L-80 standard WigL-80 Grade 80.000 Minimum Yield Strength (psi) 111111111111111111.11111111111U BA 95.000 Minimum Ultimate Strength (psi) VAM USA 4424 W.Sam Houston Pkwy.Suite 150 Pipe Dimensions Houston.TX 77041 Phone:713-479-3200 4.500 Nominal Pipe Body O.D. (in) Fax:713-479-3234 3.958 Nominal Pipe Body I.D.(in) E-mail:VAMUSAsatest vam-usa.com 0.271 Nominal Wall Thickness(in) 12.60 Nominal Weight(lbsift) 12.25 Plain End Weight(lbs t) 3.600 Nominal Pipe Body Area(sq in) Pipe Body Performance Properties 288.000 Minimum Pipe Body Yield Strength(lbs) 7.500 Minimum Collapse Pressure(psi) 8.430 Minimum Internal Yield Pressure(psi) 7.700 Hydrostatic Test Pressure (psi) Connection Dimensions 5.000 Connection O.D. (in) 3.958 Connection I.D. (in) 3.833 Connection Drift Diameter(in) 3.94 Make-up Loss(in) 3.600 Critical Area(sq in) 100.0 Joint Efficiency(%) Connection Performance Properties 288.000 Joint Strength(lbs) 14.290 Reference String Length(ft) 1.6 Design Factor 314.000 API Joint Strength(lbs) 288.000 Compression Rating (lbs) 7.500 API Collapse Pressure Rating (psi) 8.430 API Internal Pressure Resistance(psi) 81.5 Maximum Uniaxial Bend Rating[degrees/100 ft] Appoximated Field End Torque Values 5.800 Minimum Final Torque(ft-lbs) 6.500 Maximum Final Torque(ft-lbs) 7.200 Connection Yield Torque(ft-lbs) Page 40 Revision 0 April, 2015 • • GO#8 Drilling Procedure 19.7 Ensure to run enough liner to provide for approx 200' overlap inside 7-5/8" casing. Ensure hanger/pkr will not be set in a 7-5/8"connection. 19.8 Before picking up Baker ZXP liner hanger/packer assy, count the#of joints on the pipe deck to make sure it coincides with the pipe tally. 19.9 M/U Baker ZXP liner top packer. Fill liner tieback sleeve with"Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 19.10 RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 19.11 RIH w/ liner on DP no faster than 1-1/2 min/stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 19.12 M/U top drive and fill pipe while lowering string every 10 stands. 19.13 Slow in and out of slips. 19.14 Circulate 1-1/2 drill pipe and liner volume at 7-5/8" shoe prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. Nominal liner hanger setting pressure is 2500 psi. 60% of this value is 1500 psi 19.15 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 19.16 Continue to fill the DP every stand down using fill up line on rig floor. Do not stop to fill casing. 19.17 P/U the cmt stand and tag bottom with the liner shoe. P/U 2' off bottom. Note slack-off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 19.18 Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure (1500 psi). Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 19.19 Reciprocate&rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 41 Revision 0 April, 2015 • • GO#8 Drilling Procedure Ililrnrp.1la4.6a. 20.0 Cement 4-1/2" Production Liner 20.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 20.2 Attempt to rotate & reciprocate the liner during cmt operations. This is the most effective method to ensure effective mud and wall cake removal and a good quality cmt bond. 20.3 Pump 5 bbls 10 ppg MUDPUSH II spacer. 20.4 Test surface cmt lines to 4500 psi. 20.5 Pump remaining 15 bbls 12 ppg MUDPUSH II spacer. 20.6 Mix and pump 15.3 ppg class"G"cmt per below recipe. Ensure cmt is pumped at designed weight. Job is designed to pump 50%OH excess. Section: Calculation: Vol(BBLS) Vol(ft3) 7-5/8"x 4-1/2 DP" 200' x 0.026 = 5.2 29 Overlap: 7-5/8"x 4-1/2"Liner 200' x 0.026 = 5.2 29 Overlap: 6-3/4" OH x 4-1/2" Liner: (10,039—7,400')x 0.025 x 1.5 = 99 556 Shoe Track: 90' x 0.019= 1.7 9.5 Total Volume: 111 bbls 624 ft3 Li& Page 42 Revision 0 April,2015 • • GO#8 Drilling Procedure Ililrorp: la.i a.L1.E Tail Slurry System Easy BLOK Density 15.3 lb/gal Yield 1.34 ft3/sk Mix Fluid 5.879 gal/sk Base Fluid 5.879 gal/sk Expected 70 Bc at 5:00 hrs Thickening Code Description Concentration G Cement 941b/sk 0046 Antifoam 0.2%BWOC D202 Dispersant 1.5%BWOC Additives D400 Gas Control 0.8%BWOC D154 Extender 8.0%BWOC 20.7 Drop DP dart and displace with 9.2 ppg drilling fluid. 20.8 Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point. 20.9 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns&pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 20.10 Bump the plug and pressure up as required by Baker procedure to set the liner hanger(20% above nominal setting pressure. 2500 psi is nominal setting pressure. Pressure up to 3000 psi to confirm hanger setting. 20.11 Slack off total liner weight plus 20k to confirm hanger set. 20.12 Do not overdisplace by more than V2 shoe track. Shoe track volume is 1.7 bbls. 20.13 Pressure up to 4200 psi to release the running tool(HRD-E) from the liner. 20.14 Bleed pressure to zero to check float equipment. Page 43 Revision 0 April, 2015 • GO#8 Drilling Procedure n a,0,11.t ha.A.a.IA l 20.15 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve. 20.16 Rotate slowly and slack off 50k downhole to set the ZXPN liner top packer. 20.17 P/U to P/U weight plus 1 ft. 20.18 Close annular and test 4-1/2" DP x 7-5/8"annulus to 1500 psi/ 10 min to test liner top packer. 20.19 Bleed off pressure, open up annular. 20.20 Pressure up to 500 psi down DP and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req'd to maintain 500 psi DP pressure while moving pipe until the pressure drops off rapidly, indicating pack-off is above the sealing area(ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 20.21 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 20.22 Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. 20.23 Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 20.24 POOH, verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 20.25 If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise)torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 20.26 NOTE: Some hole conditions may require movement of the drillpipe to "work"the torque down to the setting tool. 20.27 After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point,the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Page 44 Revision 0 April, 2015 • • GO#8 Drilling Procedure Hileorp Ala An,LLC Ensure to report the following on wellez: • Pre flush type,volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing,bpm,note any shutdown during mixing operations with a duration • Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement,actual displacement volume, whether plug bumped&bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job.Final circulating pressure • Note if pre flush or cement returns at surface&volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Send final "As-Run"casing tally&casing and cement report to mmyers@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 45 Revision 0 April,2015 • • GO#8 Drilling Procedure IIil orp;ila.ka.IAA' 21.0 Wellbore Clean Up & Displacement 21.1 M/U casing clean out assy complete with casing scraper assys for each size casing in the hole. • 3.75"bit or mill. • Casing scraper for 4-1/2" 12.6# casing. • +/- 2800' 2-7/8"workstring. • Crossover(No PBR Polish Mills). • Casing scraper for 7-5/8" 29.7# casing. • 4-1/2"DP to surface. 21.2 TIH &clean out well to landing collar(+/- 9,919' MD). • Circulate as needed on trip in if string begins to take weight. • Circulate hi-vis sweeps as necessary to carry debris out of wellbore. • Ensure 3-3/4"bit is worked down to the landing collar. • Space out the cleanout BHA so that the 4"bit reaches the 5" landing collar when crossover is +/- 30' above the 5" liner top. • The primary objective of the clean out run is to ensure the TCP assy will reach intended depth. 21.3 After wellbore has been cleaned out satisfactorily using mud, test casing to 3500 psi/30 min. 21.4 Displace drilling fluid in wellbore with a hi-vis pill followed by fresh water. • Consider catching drilling fluid in rain-for-rent tanks for use on a future well if feasible. • Circulate fresh water into wellbore until clean-up is satisfactory. Do not recirculate fluid, • After a couple circulations using FW, short trip the assy to bring the upper 7-5/8" scraper to surface. • RIH again&tag landing collar w/4"bit. Continue circulation as necessary until fluid cleans up. Make another short trip if necessary. • Pump a chemical train followed by 6%filtered KC1(or alternative fluid specified by Ops team). 21.5 TOH w/clean out assy. LDDP on the trip out. Note any abnormal wear on the clean out assy. Page 46 Revision 0 April,2015 • • GO#8 Drilling Procedure Hileorp AIxuka,l i f 22.0 Production Tubing Installation and Perf. 22.1 A separate Sundry will be submitted to the AOGCC that will cover the post well logging program/production tubing installation/perforation procedure. Page 47 Revision 0 April,2015 0 • GO#8 Drilling Procedure IIiI.orll aiaAa.I,I.E 23.0 BOP Schematic e-) l c___------- k) I. III 141141 i1 • Saxon Rig 169 11"SM T-3 Energy BOP Iii ifs 111 i+lil - III'I .ria-ea ■i - " e t 4 ° ' iii'''.1"..,±t2. }/I;t:,. !1 ^��C{4 ��1 A1 _H1�I!IIN. ice ^ , El 131=31 MI Iii I!1 ifl Ito Sparser spans � 11 5MX 11 5M i;; lir It; lei ii -.ipmemi ,!, I .- Seaboard-MBS system ' ° ' 18%3MX115M .-. :•� le 1 . 11-io. tee .ri. fin .,,. - -.G■ if 111 Ii•— iI101 •II+.Al a 1. 1I I. Page 48 Revision 0 April, 2015 • • GO#8 Drilling Procedure Hileorp Ala.ka,1,1,C 24.0 Wellhead Schematic 6-1/111011 I /-ADAPTER. EN ! 11 911 It 66-1/6 ECMf 8.6 - CST •.. •- •.- 1 '1111111 16f __. 11 X41 CASING HANGFR ii, 51A9-22 Pa1TED 11 x 5-1/2 17# YAN DM1::l4 t!1All ...�..u- 11 2..1/16 9Y CSG BOX STA x 5.a7-�•i_--:ICi' 111'. 17.2 ACHE-2C-LN BOX TCI EST K./PRIMARY SEAL i � :,.. J I I " .T.yt_ t , i NItill 11ir �� n 50.1 1 --- .L.:7.---7. CASING' HAMAR, '!145-22 Ill .' `,Z i 1 ti X 7--Sf'A--= '71 73.7 W/SEAL AS'a4!!LY• i (( R i EST J 24,3 �f rOfs"..�1 I 't '. EST 1 mss/ 1 r i i 1C-3/+1 SINGLE IPS---MI - - 111 2-1/10 fjA1 www. s_ www4 2 16.3/4 3N MI 1!1 CASING4.At, sus-22 1a-2/-�/4 x ,0-3/4 ST 21.8 W/PRIMARY SERI �'- �_ ~ �-, S 1 o 5 ; - a I ! isv 1.! i 2 '.16 'N 16 CA51N, -" ...p 1..]-'lit CASNG 7-5/8 CASP.G------.r „• 2-7/8"Prod Tubing ---....., ' NI 6 GAS 10000 P M[W4EAD ASSE48LY tiCIL. 16 x10-3/4 x 7-5/8 1 5-1/2 (WYiSUMS 94101 O4 11115 1)1A11.4.WE ESIMAES MAY ANS CAA VARY 90,1FSiMIfLY '.RESTRx;TED CGNr0ENTIAL DOCUUENT DEK:04G CMI RAM W.TIRYL£)422 6. sr ,C5 NO OW MISE CT SIAD4UP 41xa,I IS IIIPZ41}. _.pl-10—P40/13114 " DAMS DAMSONS 540101 9�aL3 6E ONSIO iED • � LAY ��RErr R6015E5(Y4 Y. N.:.SL"i.� '" 1 Ip'— 20339 Page 49 Revision 0 April,2015 • • GO#8 Drilling Procedure Hileorp Alaska, 25.0 Days Vs Depth Days Vs Depth NI _.m.._GD#8 SRU 22-22 Frances#1 2767 —Susan Dianne#8 4000 6DO D 2 N N 8000 10000 \\\ 12000 14000 0 10 20 30 40 50 60 70 80 Days Page 50 Revision 0 April, 2015 • • GO#8 Drilling Procedure Hilrarp Alaska,tic 26.0 Formation Tops GEOLOGICAL PROGNOSIS WELL NAME: G08 • FIELD: Ninilchik Unit,GO Unit SURFACE: X= 229297.681 • STATE: Alaska Y= 2255334.021 • BOTTOMHOLE X= 2250864 TVD REF DATUM KB Y= 3,^,31'i TVD REF ELEV 183 COORD REF. SYSTEM NAD27 • GROUND ELEV PROPOSED TD: 10039 . MD Objective: Drill a 10039'MD Tyonek and Beluga gas development well. • Geo Summary/ Justification: Subsurface data indicates the northeast quarter of section 15 is an untapped and in a crestal postion for Lower Beluga and • Tyonek gas development. ANTICIPATED FORMATION TOPS&GEOHAZARDS EXPECTED Intersection Points TOP TOP NAME FLUID MD(FT) TVD(FT) TVDSS(FT) Est.Pressure X Beluga 50 Pos Gas 4609 . 2,104 • -1,921 905 I I Tyonek GAS 8198 3,582 -3,399 1540 225232 2260432 100' ✓ I T6 Tight Gas 8609 3,989 -3,806 1715 ✓ I T20 Tight Gas 9727 5,099 -4,916 2193 Total Depth 10039 5,409 r -5,226 / 2326 r 225086.4r 2260614.5 200 =Primary Objective =Secondary Objective TARGET RADIUS 100 FT DATA COLLECTION REQUIREMENTS: Mud Logging: Surface casing to total depth,30 ft samples with 20'samples in nines of interest,two sets of cuttings,chromatograph,show reports,Oder plots. • LWD Data: *LWD GR/Res for correlation and drilling • E-Line Log Data: COMPLETION TYPE Monobore ANTICIPATED RATES 3 MMCFGD ARTIFICIAL LIFT EQUIPMENT OD TUBING SIZE Page 51 Revision 0 April,2015 • • GO#8 Drilling Procedure Ililrorp Alaska,LLC 27.0 Anticipated Drilling Hazards 13-1/2" Hole Section: Lost Circulation: Ensure adequate amounts of LCM are available. Safe-carb 10, 20, 40, 250, &750. Ensure G-seal, Pecan nut plug, and Mix II are also available for more severe lost returns incidents. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of Safe-carb 10 &20 to the active system at 1 —2 ppb. Hole Cleaning: Maintain rheology w/gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP btwn 25 —45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of-50 - —60 lbs/100ft2 to combat this issue. Maintain low flow rates for the intial 200' of drilling to reduce the likelihood of washing out the conductor shoe. To help insure good cement to surface after running the casing, condition the mud to a YP of 25 —30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. 9-7/8" Hole Section: Lost Circulation: Ensure adequate amounts of LCM are available. Safe-carb 10, 20, 40, 250, &750. Ensure G-seal, Pecan nut plug, and Mix II are also available for more severe lost returns incidents. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of Safe-carb 10 &20 to the active system at 1 —2 ppb. Hole Cleaning: Maintain rheology w/flowzan. Sweep hole w/20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP btwn 20 - 30 to optimize hole cleaning and control ECD. Page 52 Revision 0 April, 2015 • • GO#8 Drilling Procedure IIiP.orp I .ka.I.11 Wellbore stability: Maintain 1ppb total of PolyPac Supreme UL to maintain a thin/strong wall cake and keep HTHP filtrate below 9 ml/30 min. Maintain MW as necessary using additions of Barite. Maintain 6 ppb EMI-2009 for shale/clay inhibition. Maintain 4 ppb Asphasol Supreme & 3 ppb Sack Black for Shale/Coal stabilizer. Maintain 6% KC1 in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt-type additives to further stabilize coal seams (Asphasol Supreme, Sack Black). • Increase fluid density as required to control a"running coal". • Emphasize good hole cleaning through hydraulics, ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb Asphasol Supreme pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. 6-3/4" Hole Section: Lost Circulation: Ensure adequate amounts of LCM are available. Safe-carb 10, 20, 40, 250, & 750. Ensure G-seal, Pecan nut plug, and Mix II are also available for more severe lost returns incidents. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of Safe-carb 10 &20 to the active system at 1 —2 ppb. Hole Cleaning: Maintain rheology w/flowzan. Sweep hole w/20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP btwn 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain 1ppb total of PolyPac Supreme UL to maintain a thin/strong wall cake and keep HTHP filtrate below 6 ml/30 min. Maintain MW as necessary using additions of Barite. Maintain 6 ppb EMI-2009 for shale/clay inhibition. Maintain 6% KCl in system for shale inhibition. Page 53 Revision 0 April, 2015 • • GO#8 Drilling Procedure IIilrorp,11a.6a,LAA Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Do not use"black products"to stabilize coal sections. • Increase fluid density as required to control a"running coal". • Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 54 Revision 0 April,2015 • • HGO#8 Drilling Procedure Hilcorp.11:14:1,I.1 I' 28.0 Saxon Rig 169 Layout . r j__4, I! • 51 151, / i1I 7'. 1 111=1-r F I r 1 ft I Iii; I� I-4;1111 . Sin. 1 1 itllllhIH J 1 . •I_ . 1 Y I1n liIi'I !,i - � 43 I."ilicuII� 'lur��, I 1 ' I 1li'.cuIEl m ■IIIiiE'' m _ °I Iii a'-'!' Ila� �� 11 r ��lirr!!� �lil r—+ �I': � ?Ili_ Itc ] _^[11...1 lit! Ii'! ■ill■11.: i�.-1 ep: i ,.rll IgIII xl - I'�r�iI III I ' (Will h. il nlu _ MIN.. 1 � (VIII' w! La 1 u� = - p II ,71,,,,..„ Ii� iII -!11 IiiS Il 1111'111, N 1 ,I1IIII_ '�- ' 1 .„ , 1 , - r:, , . , , ill 1 111 1111„ ;II. .., i..iru, h�ri. li iI I I=1 ,-,--=-.1 I=1 I= 1 Page 55 Revision 0 April, 2015 • • GO#8 Drilling Procedure IIiI.orp 11a4a.LI.I 29.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20'of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer(ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 56 Revision 0 April,2015 • • GO #8 Drilling Procedure wk.", ‘I:,,L0..II 1' 30.0 Choke Manifold Schematic ,!;/6-- %I v 4,24 43$2 43 62 N NMI es 0 `` p.;o OD61110.1. 1 ^8 43 14.42cmiO.. •.�n3 16.43 `�Y`! 0.19 --O.ia ..:• -:,} 4i$1.-- - iir .' r0.t4 0.19-1,,,,,,..„,,,,i...... 0.19iC� I .t. i 1 r, F -11nG� ° C I I 9po ■ , • 11:71'AreMt 1 7 ' AlkrA ; • i ." I"! - 0. J -- � I 019 I S- 0.19 J 0.19 10 I_N'�1... JJJ ).M Co / YJ- i 9.64 0. 1111 7.64 0.19 r -mild' .I. 1N1..1 I __ 1 I _� - 0.19.130.43 �1~~ Ni l 0.1YJ L' 10 14.62 > oe ^ 14.62 3" ��!A 0y = 1662 '.A x-0.19 .: 1 • _Y�.."" i 1 I Ow 0 a u, [419 019, 1011150 N \ a .., r+ '0.'A it .iI ll.r4-4„,e,,,,..-01144.,„:3-4.1k7,"....1.„'!......,25..,Y� 11'1. 1.� . i F -0.19 111 191,•1 191', 1 '\-1,12 C110..6 M2 GN0.KE -0.19 -009 0.19 - MANUAL ACIb61m 4 ... 0.19-- -_0.19 Gi'8R8Tl ER690M -031 -14.42 -14.62 -14.62-. 14.62--631 43.62 4162 6).24 11 v0)f- t....ATOP''MSF Si GAS%E15 [ �C�i. .. `"S4-, -/ 0 `G� Page 57 Revision 0 April, 2015 S GO #8 Drilling Procedure Hilrorp Ala.ka,LLC 31.0 Casing Design Information Calculation & Casing Design Factors Ninilchik Unit DATE: 5-26-2015 WELL:Grassim Oskolkoff#8 FIELD: Ninilchik DESIGN BY: Monty Myers Design Criteria: Hole Size 9-7/8" Mud Density: 10.0 ppg Hole Size 6-3/4" Mud Density: 10.0 ppg Hole Size Mud Density: Drilling Mode MASP(sec 2): 1,784 psi (see attached MASP determination&calculation) MASP(sec 3): 952 psi(see attached MASP determination&calculation) Production Mode MASP: 1,784 psi(see attached MASP determination&calculation) Collapse Calculation: Section Calculation 1,2, 3 Normal gradient external stress (0.494 psi/ft)and the casing evacuated for the internal stress Casing Section Calculation/Specification 1 2 3 Casing OD 10-3/4" 7-5/8" 4-1/2" Top(MD) 0 0 7,200 Top(1VD) 0 0 2,761 Bottom(MD) 3,500 7,400 10,039 Bottom (TVD) 1,850 2,884 5,409 Length 3,500 7,400 2,839 Weight(ppf) 45.5 29.7 12.6 Grade L-80 L-80 L-80 Connection BTC BTC DWC/C HT Weight w/o Bouyancy Factor(lbs) 159,250 219,780 35,771 Tension at Top of Section(lbs) 159,250 219,780 35,771 Min strength Tension(1000 lbs) 1040 683 288 Worst Case Safety Factor(Tension) 6.53 • 3.11 8.05 Collapse Pressure at bottom(Psi) 962 1,500 2,813 Collapse Resistance w/o tension (Psi) 2,470 4,790 7,500 Worst Case Safety Factor(Collapse) 2.57 . 3.19 - 2.67 MASP(psi) 1,316 2,733 2,733 Minimum Yield(psi) 5,210 6,890 8,430 Worst case safety factor(Burst) 3.96 2.52 3.08 Page 58 Revision 0 April,2015 # ! GO#8 Drilling Procedure Hilrnrp Ala.ka,LLC 32.0 9-7/8" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 9-7/8"Hole Section Hilcorp nar,y Grassi m Oskol koff#8 Ninilchik Unit MD ND Planned Top: 3500 1850 Planned TD: 7400 2884 Anticipated Formations and Pressures: Formation ND Est Pressure Oil/Gas/Wet PPG Grad Upper Beluga 2,104 906 Gas 8.3 0.431 Offset Well Mud Densities Well MW range Top(MD) Bottom(MD) Date Falls Creek 1 10.5-13.1 2,500 11,000 1960 Corea Creek 1 9.4-10.4 2,500 6,664 1996 Falls Creek 1 RD 8.7-9.3 3,000 8,332 2001 Falls Creek#5 9.2-9.7 1,758 9,715 2014 Frances#1 9.3-9.8 2,638 10,703 2014 Falls Creek#6 9.0-9.4 2,424 9,060 2014 Assumptions: 1. Fracture gradient at 3,500'MD/1,850'ND is estimated at 0.936 psi/ft based on field test data. 2. Maximum planned mud density for the 9-7/8"hole section is 9.6 ppg. 3. Calculations assume"Unknown"reservoir contains 100%gas(worst case). Fracture Pressure at 10-3/4"shoe considering a full column of gas from shoe to surface: 1850(ft)x 0.936(psi/ft)= 1732 psi 1732(psi)-[0.1(psi/ft)*1850(ft)]= 1547 psi MASP from pore pressure(unknown gas sand at TD,at 8.3 ppg) 2884(ft)x 0.43(psi/ft)= 1240 psi 1240(psi)-[0.1(psi/ft)*2884(ft)]= 952 psi Summary: 1. MASP while drilling 9-7/8"intermediate hole is governed by fracture gradient at the 10-3/4"casing shoe Page 59 Revision 0 April,2015 • • GO#8 Drilling Procedure Hileorp AIa*la,Lt.( 33.0 6-3/4" Hole Section MASP Maximum Anticipated Surface Pressure Calculation Hilcorp 6-3/4"Hole Section Grassim Oskolkoff#8 Cook Inlet,Alaska MD TVD Planned Top: 7200 2761 Planned TD: 10039 5409 Anticipated Formations and Pressures: Formation ND Est Pressure Oil/Gas/Wet PPG Grad UpperTyonek Target 3,517 1540 Oil/Gas/Wet 8.4 0.438 Offset Well Mud Densities Well MW range Top(MD) Bottom(MD) Date Falls Creek 1 12.2-12.3 11,000 13,500 1960 Corea Creek 1 9.4-10.4 2,500 6,664 1996 Falls Creek 1 RD 8.7-9.3 3,000 8,332 2001 Falls Creek#5 9.2-9.7 1,758 9,715 2014 Frances#1 9.5-9.7 10,700 12,814 2014 Falls Creek#6 9.0-9.4 2,424 9,060 2014 Assumptions: 1. Fracture gradient at 10,039'MD/5,409'ND is estimated at 0.936 psi/ft based on field test data. 2. Maximum planned mud density for the 9-7/8"hole section is 9.6 ppg. 3_ Calculations assume"Unknown"reservoir contains 100%gas(worst case). Fracture Pressure at 7-5/8"shoe considering a full column of gas from shoe to surface: 5,409(ft)x 0.936(psi/ft)= 5063 psi 5,063(psi)-[0.1(psi/ft)*5,409(ft)]= 4522 psi dc- +7 MASP MASP from pore pressure(entire wellbore evacuated to gas from TD) 5,409(ft)x 0.43(psi/ft)= 2,325 psi 2,325(psi)-[0.1(psi/ft)*5,409(ft)1= 1,784 psi Summary: 1. MASP while drilling 6-3/4"production hole is governed by SIBHP minus gas gradient(0.1 psi/ft)to surface after entire wellbore is evacuated to gas. Page 60 Revision 0 April, 2015 O O GO#8 Drilling Procedure Hileorp Aler.ka,LIC 34.0 Spider Plot (NAD 27) (Governmental Sections) 0 Legend • G08 SHL X GO 8 TPH + G0 8 BHL • Other Surface Hobe Local: • Other Baemm Hole Locator: ---Weil Paths tits I3Hl_!: GO 8 ale/ �taland Gas LMtBoundary � ¢3 L 384306 (�{ ADL 389737 say+ oa v.5 6l-L •` GO 1 BH_ % • % % ! , o t o GO4B1J ° (II)* 7PII a O ti r ` . t �,. •GG6BHL \• •, ea t • NINILCHIkUNIt'•. SO 01N013W_ fd`f ___. FALLSCRfiEK2BHL `` \\„ •o t` 1 NINIICHIK 1(TX)BK.\` ` 0 a`t •` • AKA 024399 GO2BHL \ -:vbo•' too:s SEIi_ --,--...s.- -- -- --__1..„------------------ Vie: La38'9180 ADL 384305 - "� - - _ - AKA 024399 Private CIRI= HG t5D0 3v0� Ninilchik Unit Feet Ilil..xp 04$4w.III GO 8 Alaska State Ptane Zone 4 NAD27 Map Date:5:1x2015 Page 61 Revision 0 April, 2015 • • II GO#8 Drilling Procedure Ilill orp Ala..ka,1,1.0 35.0 Surface Plat (As Built) (NAD 27) C 21 KENAI PENINSULA BOROUGH / GONO.SWELL N=:255369 317 m T01N R13WS23 HM SW-64 NEI; /F N 2255334.021 LOCATION l\=229298.836 / _z LEV=163.97/ -. N. /0" E:229297.681 / - arc iQH /1� LATITUDE:60'09'54 553'N N. / u \f�`Rr r I / LONGITUDE:1W2910 558"W O Y / NA027 ASP ZONE 4 / a I �'�F + / FEL=2726' / ��\ FSE=3374' / '"'��'- ',..,,\06."'"1.,,,,,0„.. LOT 111M 2007-17 �N ..." , 'f SECTIO164.6' Z3 I,NGVD29} ..... "\C-;X ��lAN Ft TOWNSHIP IN 2726'FEL ' A\P•j '_ ••,f-. 1/RANGE I3W,SM AK /Q / / 0 i , . , .. , i / , i ,.. ... .,:N.1'vELL . 0• / j, N. ....„.O. / 2 (r ,� M. SCOTT MtXANE = I};'r WELL o / / FLEV=1855• �+ ,{ / I,s 4926-5 / ' / r /, •q•�•,1, 72,299'.1*_ `~ / ,U,3 WELL ./ // �, •`' FSS IOWA' `7b / ,166 4' ., 111111111 / 00, ''1��%� / .44 1 / .- -_,WATER / I / / / SWELL®' / RM2 PAT 1979 / 0 No.4 WELL .i, •// '�. _ / N=2255179 16 / ELEV.=1€6 4' .1:'' 4• / E=228974.16 `A. zz,./ II ELEV=183.08' / y/ ® /'1 / / ®/ ,r'" / TROL Q� �y // / / ( { NG r v...�OF / EL 00 1E6 2- ,a '/ .. / I 7 .. 9 C7 CORNER IR>5, `it / / - Ch E T r„„9,7jM0 ® _- � SECiKNJlI NE 1�15t r 21 E �. / f8'RE 2t n +(/ .a No 8 WELL 1 :+. t / O L / N.2254986.17 NOTES ELEV=165.5' E=229175.04 RM1 PAT 1979 / N=2254965,6 ELEV=180.5' 1.BASIS OF GEODETIC CONTROL AND NAD83 POSITION E.228817.63 lk � / (EPOCH 2003)1S AN OPUS SOLUTION FROM NGS STATIONS ELEV=182 81' '•. GO No.7 WELL 'KENS CORS ARP','ZAN1 CORS ARP'.AND"TSEA ARP TO I l/ ...I ELEV.•185.8' r ESTABLISH THE POSITION OF NGS CONTROL STATION PAT II _tea/ GOVT LOT 2 1979 RM 1.THE GEODETIC POSITION OF PAT 1979 RM 1 WAS ?c9'' SECTION 23 DETERMINED TO HAVE A LATITUDE OF 60'09'48.70932•N AND I' 4/ TIN.R13W,S.M.-AK A LONGITUDE OF 151`23'27.84397'W.THE ALASKA STATE PLANE COORDINATES(ASP)ZONE 4 NAD 83 FEET ARE: J N•2,254,126.735 F 4. S E=1,368,837.058 ` ELEV.162.47(NGVD29I / O "CAUTION" 2.THE BASIS OF BEARING FOR THIS PROJECT WAS I/ 110 HIGH PRESSURE DETERMINED BY A HIGH PRECISION GPS SURVEY UTILIZING 1/ .....................—_,A L UNDERGROUND TRIMBLE R8 MODEL 3 GNSS RECEIVERS.DIFFERENTIALLY Y LATERAL GAS CORRECTED AND PROCESSED WITH TRH4BLE TSC3 / I N O, PIPELINE TO K.K,P,L CONTROLLER AND ACCESS FIELD SOFTWARE. / I — r—=�'�' J 3.PROJECT BASIS OF BEARING IS ASP NADE3 ZONE4 US FT +^^^'� GRID BEARING. 1, Ipi '.J m 4.DATA TRANSFORMATIONS(NAD83 TO NA02T ASPZ4)WERE I IIIj 1 DONE USING CORPSCON VERSION 8.0.1 S I GO PAD WELL NO. 8 AS-BUILT SURFACE LOCATION (NAD27) • lir GRASSIM OSKOLKOFF PAD LOCATION:SECTION 23, TOWNSHIP 1 NORTH, ENGINEERING-TESTING /f ', SURVEYING•MAPPING P.Q.BOX 468 RANGE 13 WEST,SEWARD MERIDIAN,ALASKA flavor,*Alaska.111:SOLDOTAK 99669 JOB NO. 157006 VOICE:(907901)283.4218 FAX(907)283.3265 DWG- Comm Inc WWW.MCLANECG.COM 157006 Date:5/22/2015 FIGURE: 1 Page 62 Revision 0 April, 2015 0 • II GO#8 Drilling Procedure Hileor!Alaska,LGA. 36.0 Salinity Calculation METHOD#1 Rmf iC 70 degrees F 2.8 Depth 380 • Temp(F) 49 K= 69.21 Rmf @ 45 degrees 3.87 i Rmfe 3.29 SP -16 sp deflection from shale baseline `> Rmfe/Rwe 1.70 Rwe 1.93 Rw 2.28 .x Salirsty ppm 3300 3 METHOD#2 S RESD 33 POR est 0.3 , SW est 1 .555°" RW talc 2.97 Salinity ppm 2500 • .. „ :z, METHDDIf1 Rmf i 70 degrees F 2.8 Depth 955 Temp(F) 54 K= 69.92 Rmf.r`cJ 45 degrees 3.52 ., Rmfe 2.99 SP -30 sp deflection from shale baseline Rmfe/Rwe 2.69 Rwe 1.11 Rw 1.31as Salinity ppm 6000 t., s METHOD 82 ^• ,.i RESD 10 POR est 0.3 ',! SW est 1 r RW talc 0.90 c Salinity ppm 8500 a if, k c 1q, ,:- Page 63 Revision 0 April, 2015 • • II GO#8 Drilling Procedure Hileorp Ala%ka,LIC' 37.0 Offset MW vs TVD Chart MW vs TVD Offsets 0 I , 1 00 1 —Corea Creek#1(1996) 10 —Fans Creek#5(20141 Or, I —GO#1(2000) 2000I NM. I —GO#2(2001) — \b, III-11. (4,0 8 r '' 1 kir rr ' 3000 (<- 4000 Ilk 5000 il a lki 6000 - 1 I7000 1 saoo i 9000 1\ 10000 11000 8 9 10 11 12 13 14 15 Mud Weight(PPG) Page 64 Revision 0 April,2015 0 • II GO#8 Drilling Procedure Hilrorp Alaska,EEC 38.0 Drill Pipe Information SIZE: 4 1/2" igs COMMAND WEIGHT: 16.6 LBS/FT GRADE: 5135 IMIA6Y 3INYICIS RANGE: 11(31.59 DRILL PIPE SPECS CONNECTION: CDS40 TUBE NEW PREMIUM IN MM IN MM OD 4.500 114,3 4,365 1 10.9 WALL THICKNESS 0.337 8.6 0.270 6.8 ID 3.826 97.2 3.826 97.2 FT-LBS N.M FT-LBS N.M TORSIONAL STRENGTH 55.453 75200 43,451 58.900 80%TORSIONAL STRENGTH 44.362 60.200 34,761 47.100 LBS DAN LBS DAN TENSILE STRENGTH 595.004 265.300 468,297 208.800 PSI KPA PSI KPA INTERNAL PRESSURE CAPACITY 17,693 121.985 16,176 111.530 COLLAPSE CAPACITY 16,769 115.615 10.959 75.561 IN2 MM2 iNs MM2 CROSS SECTIONAL AREA BODY 4.407 2844 3.469 2238 CROSS SECTIONAL AREA OD 15.904 10261 14.966 9655 CROSS SECTIONAL AREA ID 11.497 74 17 11.497 741 7 IN* MM* IN* MM* SECTION MODULUS4.271 69995 3.347 54845 Pot AR SECTION MODUt.u_�l 8.543 139989 6.694 109690 TooL JOINT I NEw PREMIUM 1 PSI KPA PSI KPA YIELD STRENGTH 130.000 896.318 130,000 896,318 IN MM IN MM OD 5.2500 133.4 5.1 198 130.0 ID 2.6875 68.3 2.6875 68-3 PIN LENGTH 11.0 279 4 11.0 279.4 BOX LENGTH 14,0 355 6 14.0 355 6 FTiaS N44 FT-Les NM TORSIONAL STRENGTH 35.400 48.000 34,700 47.100 MAX MAKE-UP TORQUE 22.500 30.500 21,400 29.000 RECOMMENDED MAKEUP TORQUE 21,200 28.800 20.800 28.200 MIN MAKEUP TORQUE 19.600 26.600 19.300 26.200 LBS DAN LBS DAN TENSILE STRENGTH 824,400 367.600 804,900 358,900 TOOL JOINT/DRILL PIPE TORSIONAL RATIO 0.64 0.80 DRILL PIPE ASSEMBLY WITH CO_NNE_CTION LBS/FT KG/M ADJUSTED WEIGHT 17.87 26.64 FT M APPROXIMATE LENGTH 31.50 9 60 GAL/FT Ms/M FLUID DISPLACEMENT 0.273 0.003394 FLUID CAPACITY 0.577 0.007169 IN MM DRIFT SIZE 2.5625 65 Page 65 Revision 0 April, 2015 0 • ...._ GO#8 Drilling Procedure iilleorp Alaraka,111: COMBINED LOAD CURVE FOR 4 1/2"S-135 16,6 LBS/FT DRILL PIPE WITH CDS4O CONNECTIONS wo,act) SO,31:0 10.X0 1,1:•:).;)co com 0,00 tv, _11 51CO3OCO gib 4116 lit Oki 0 ... A' 411106 17, E 41::,.:,1:0 . - a 11116 •* glib * * * 4.4. • * 411.6 XO 0 141 0 tilb * :co,a cu • lko 111. a \ • • • * • lii 11 I I o 0 mow 20,000 30.0013 40,000 50,000 61."'.(•,ni: Applied Torquellt4bs) an aim NEve TUBE COMBINED LOAD ••••PREMIUM TUBE COMBINED LOAD •••• ••MAKE-UP TORQUE ••••••••••SHOULDER SEPERA11ON --.•PIN YIELD •••••••••Box YIELD Page 66 Revision 0 April, 2015 Hilcorp Energy Company Ninilchik Unit Grassim Oskolkoff Grassim Oskolkoff#8 G0 8 Plan: GO-8 WP3 Standard Proposal Report 26 May, 2015 HALLIBURTON Sperry Drilling Services i ! Project: Ninilchik Unit WELL DETAILS: Grassim Oskolkoff#8 NAD 1927(NADCONCONUS) Alaska Zone 04 HALLIBURTOIV Site: Grassim Oskolkoff Ground Level: 164.80 Well: Grassim Oskolkoff#8 +NI-S +E/-W Northing Easting Latittude Longitude Slot Sperry orating Wellbore: GO 8 0.00 0.00 2255334.02 229297.68 60°9'54.553 N 151°29'10.558 W Plan: GO-8 WP3 REFERENCE INFORMATION - Co-ordinate(N/E)Reference:Well Grassim Oskolkoff#8,True North - Vertical(TVD)Reference:GO#8©182.80us8(Saxon169(164.8GO-18KB)) - Measured Depth Reference:GO#8 @182.80usft(Saxon169(164.8GL+18KB)) - Calculation Method:Minimum Curvature -1500- SECTION DETAILS _ Sec MD Inc Azi TVD TVDSS +N/-S +E/-W DLeg TFace VSec Target -1000- 1 18.00 0.00 0.00 18.00 -164.80 0.00 0.00 0.00 0.00 0.00 - 2 250.00 0.00 0.00 250.00 67.20 0.00 0.00 0.00 0.00 0.00 - 3 450.00 4.00 320.24 449.84 267.04 5.36 -4.46 2.00 320.24 6.98 4 1905.56 76.78 320.14 1485.44 1302.64 681.68 -569.08 5.00 -0.11 888.00 -500- 5 6802.57 76.78 320.14 2605.52 2422.72 4340,85 -3624.68 0.00 0.00 5655.19 - 6 8198.53 6.98 320.14 3581.80 3399.00 5012.73 -4185.72 5.00 180.00 6530.51 - R,911, 7 10039.55 6.98 320.14 5409.18 5226.38 5184.46 -4329.11 0.00 0.00 6754.24 GO 8 T2 TD 0- Start Dir 2°/100'W 250'MD,250'ND CASING DETAILS - Cont Dir 5°/100 @ 450'MD,450'TVD TVD TVDSS MD Size Name ____--- 1850.13 1667.33 3500.00 10-3/4 10 3/4" 2884.26 2701.46 7400.00 7-5/8 7 5/8" 500- 500 End Dir @ 1906'MD,1485'TVD 5409.18 5226.38 10039.55 4-1/2 4 1/2" 1000 FORMATION TOP DETAILS 1000- p TVDPath TVDssPath MDPath Formation _ ^42 00 - 2103.80 1921.00 4609.05 Beluga 50 o0 3581.80 3399.00 8198.53 Tyonek b 0 3988.80 3806.00 8608.57 T6 1500- N M o0 5098.80 4916.00 9726.86 T20 o M 0 O _ v h o Cont Dir 5°/100'@ 6803'MD,2606'TVD 0 /` Ni- o 0 2000- _Beluga 50- uo o ' 10 3/4" rho / 0 2500- ^/ oo 0 3000- Lo 7 5/8" _ = 8000 End Dir @ 8199'MD,3582'ND L 3500- Tyonek - -- - - a 138500 4000- T6- - 9000 a) 4500- m H - 9500 5000- T20 - TD @ 10040'MD,5409'TVD 5500- GO 8 T2 TD • 0040 _ 4 1/2" 6000- GO-8 Wp3 6500- 7000- 7500- 8000- 8500- 9000- 1 I I I I I 1 1 1 1 1 1 1 1 1 1 1 1 1 1 I I I I 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 I 1 i I I I 1 1 1 1 1 1 1 1 1 i i I 1 1 1 1 I r 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 i l l 1 1 1 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 Vertical Section at 320.23° (1250 usft/in) laI!ilw►rl► i • HALLIBURTON Project: Ninilchik Unit WELL DETAILS: Grassim Oskolkoff Sperry DrillingSite: Grassim Oskolkoff Ground Level: 164.80 Well: Grassim Oskolkoff#8 +NI-S +E/-W Northing Easting Latittude Longitude Slot Wellbore: GO 8 0.00 0.00 2255334.02 229297.68 60°9'54.553 N 151°29'10.558 W Plan: GO-8 WP3 REFERENCE INFORMATION Coordinate(N/E)Reference:Well Grassim Oskolkoff#8,True North Vertical(TVD)Reference:0088(ft?182.80usft(Saxon169(184.8GL+18KB)) Measured Depth Reference:0088(dJ 182.80usft(Saxon189(164.8GL+1813)) Calculation Method:Minimum Curvature 5750 - / CASING DETAILS TD @ 10040,MD 5409,TVD • TVD TVDSS MD Size Name 5500— h End Dir @@ 8199'MD,3582'TVD 1850.13 1667.33 3500.00 10-3/4 10 3/4" yr{' 2884.26 2701.46 7400.00 7-5/8 75/8" i� • 5409.18 5226.38 10039.55 4-1/2 412" CP 5250— ° 41/2"-- SC3c3• � • 5000— I GO8T2TDI / Cont Dir 5°/100'Q 6803'MD,2606'TVD 4750— 7 5/8"• �3 4500- I GO-8 Tl Tyoneki • 4250— ' 4000— ti 3750- 3500- 3250—_ - 3000— o - rn 2750— +� 0 2500- 2250-7- 2000-: 500- 2250- 2000— •� 1750- 10 3/4" 1500- 1250— _ End Dir @ 1906'MD,1485'TVD 1000- 750 : 000- 750So 500- 250— 0- T M Azimuths to True North - Magnetic North:16.45° --- -250— Magnetic Field Cont Dir 5°/100(4)450'MD,450'TVD • Strength:55192.8snT Dip Angle:73.17° Start Dir 2°/100'W 250'MD,250'TVD Date:5/8/2015 500— Model:BGGM2014 IIII I II II I 1111111111111 II 11111111111111111111111111111111111111111111111111111 1111111 II IIII IIII 1111111111 -4750 -4500 -4250 -4000 -3750 -3500 -3250 -3000 -2750 -2500 -2250 -2000 -1750 -1500 -1250 -1000 -750 -500 -250 0 250 500 West(-)/Fast(+)(750 usft/in) f t iilcorp I • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Grassim Oskolkoff#8 Company: Hilcorp Energy Company TVD Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) - Project: Ninilchik Unit MD Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) Site: Grassim Oskolkoff North Reference: True Well: Grassim Oskolkoff#8 Survey Calculation Method: Minimum Curvature - Wellbore: GO 8 Design: GO-8 WP3 Project Ninilchik Unit Map System: US State Plane 1927(Exact solution) • System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) • Using Well Reference Point Map Zone: Alaska Zone 04 • Using geodetic scale factor Site Grassim Oskolkoff Site Position: Northing: 2,255,349.00 usft Latitude: 60°9'54.704 N From: Map Easting: 229,313.00 usft Longitude: 151°29'10.262 W Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -1.29 ° Well Grassim Oskolkoff#8 Well Position +N/-S 0.00 usft Northing: 2,255,334.02 usft • Latitude: 60°9'54.553 N +E1-W 0.00 usft Easting: 229,297.68 usft • Longitude: 151°29'10.558 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: • 164.80 usft Wellbore GO 8 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2014 5/8/2015 16.45 73.17 55,193 Design GO-8 WP3 Audit Notes: Version: Phase: PLAN Tie On Depth: 18.00 Vertical Section: Depth From(ND) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 22.20 0.00 0.00 320.23 Plan Sections Measured Vertical ND Dogleg Build Turn Depth Inclination Azimuth Depth System +NI-S +E1-W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (°1l00usft) (°/100usft) (1100usft) (°) 18.00 0.00 0.00 18.00 -164.80 0.00 0.00 0.00 0.00 0.00 0.00 250.00 0.00 0.00 250.00 67.20 0.00 0.00 0.00 0.00 0.00 0.00 450.00 4.00 320.24 449.84 267.04 5.36 -4.46 2.00 2.00 0.00 320.24 1,905.56 76.78 320.14 1,485.44 1,302.64 681.68 -569.08 5.00 5.00 -0.01 -0.11 6,802.57 76.78 320.14 2,605.52 2,422.72 4,340.85 -3,624.68 0.00 0.00 0.00 0.00 8,198.53 6.98 320.14 3,581.80 3,399.00 5,012.73 -4,185.72 5.00 -5.00 0.00 180.00 10,039.55 6.98 320.14 5,409.18 5,226.38 5,184.46 -4,329.11 0.00 0.00 0.00 0.00 5/26/2015 5:05:41PM Page 2 COMPASS 5000.1 Build 73 I • Halliburton HALLIBIJRTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Grassim Oskolkoff#8 Company: Hilcorp Energy Company TVD Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) Project: Ninilchik Unit MD Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) Site: Grassim Oskolkoff North Reference: True Well: Grassim Oskolkoff#8 Survey Calculation Method: Minimum Curvature Wellbore: GO 8 Design: GO-8 WP3 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -164.80 18.00 0.00 0.00 18.00 -164.80 0.00 0.00 2,255,334.02 229,297.68 0.00 0.00 100.00 0.00 0.00 100.00 -82.80 0.00 0.00 2,255,334.02 229,297.68 0.00 0.00 200.00 0.00 0.00 200.00 17.20 0.00 0.00 2,255,334.02 229,297.68 0.00 0.00 250.00 • 0.00 0.00 250.00 67.20 0.00 0.00 2,255,334.02 229,297.68 0.00 0.00 Start Dir 2°/100'W 250'MD,250'TVD 300.00 1.00 320.24 300.00 117.20 0.34 -0.28 2,255,334.36 229,297.41 2.00 0.44 400.00 3.00 320.24 399.93 217.13 3.02 -2.51 2,255,337.09 229,295.24 2.00 3.93 450.00 4.00 320.24 449.84 267.04 5.36 -4.46 2,255,339.48 229,293.34 2.00 6.98 Cont Dir 5°/100 @ 450'MD,450'ND • 500.00 6.50 320.20 499.62 316.82 8.88 -7.39 2,255,343.06 229,290.49 5.00 11.55 600.00 11.50 320.17 598.36 415.56 20.89 -17.40 2,255,355.30 229,280.75 5.00 27.19 700.00 16.50 320.16 695.36 512.56 39.46 -32.90 2,255,374.21 229,265.68 5.00 51.38 800.00 21.50 320.15 789.88 607.08 64.45 -53.75 2,255,399.66 229,245.40 5.00 83.92 900.00 26.50 320.15 881.21 698.41 95.67 -79.80 2,255,431.46 229,220.05 5.00 124.58 1,000.00 31.50 320.15 968.64 785.84 132.88 -110.86 2,255,469.35 229,189.84 5.00 173.05 1,100.00 36.50 320.14 1,051.52 868.72 175.79 -146.68 2,255,513.06 229,154.99 5.00 228.95 1,200.00 41.50 320.14 1,129.21 946.41 224.08 -187.00 2,255,562.25 229,115.77 5.00 291.86 1,300.00 46.50 320.14 1,201.12 1,018.32 277.39 -231.51 2,255,616.55 229,072.48 5.00 361.31 1,400.00 51.50 320.14 1,266.71 1,083.91 335.31 -279.86 2,255,675.53 229,025.44 5.00 436.75 1,500.00 56.50 320.14 1,325.47 1,142.67 397.39 -331.70 2,255,738.77 228,975.02 5.00 517.63 1,600.00 61.50 320.14 1,376.95 1,194.15 463.16 -386.62 2,255,805.76 228,921.59 5.00 603.32 1,700.00 66.50 320.14 1,420.78 1,237.98 532.13 -444.21 2,255,876.01 228,865.57 5.00 693.17 1,800.00 71.50 320.14 1,456.60 1,273.80 603.77 -504.02 2,255,948.97 228,807.38 5.00 786.50 1,900.00 76.50 320.14 1,484.16 1,301.36 677.53 -565.62 2,256,024.10 228,747.46 5.00 882.59 1,905.56 76.78 320.14 1,485.44 1,302.64 681.68 -569.08 2,256,028.33 228,744.09 5.00 888.00 End Dir @ 1906'MD,1485'TVD 2,000.00 76.78 320.14 1,507.04 1,324.24 752.25 -628.01 2,256,100.20 228,686.76 0.00 979.94 2,100.00 76.78 320.14 1,529.91 1,347.11 826.97 -690.41 2,256,176.31 228,626.07 0.00 1,077.29 2,200.00 76.78 320.14 1,552.79 1,369.99 901.70 -752.81 2,256,252.41 228,565.37 0.00 1,174.64 2,300.00 76.78 320.14 1,575.66 1,392.86 976.42 -815.20 2,256,328.52 228,504.67 0.00 1,271.99 2,400.00 76.78 320.14 1,598.53 1,415.73 1,051.14 -877.60 2,256,404.63 228,443.97 0.00 1,369.33 2,500.00 76.78 320.14 1,621.41 1,438.61 1,125.86 -940.00 2,256,480.73 228,383.27 0.00 1,466.68 2,600.00 76.78 320.14 1,644.28 1,461.48 1,200.59 -1,002.40 2,256,556.84 228,322.57 0.00 1,564.03 2,700.00 76.78 320.14 1,667.15 1,484.35 1,275.31 -1,064.79 2,256,632.95 228,261.87 0.00 1,661.38 2,800.00 76.78 320.14 1,690.02 1,507.22 1,350.03 -1,127.19 2,256,709.05 228,201.17 0.00 1,758.73 2,900.00 76.78 320.14 1,712.90 1,530.10 1,424.75 -1,189.59 2,256,785.16 228,140.48 0.00 1,856.08 3,000.00 76.78 320.14 1,735.77 1,552.97 1,499.48 -1,251.98 2,256,861.26 228,079.78 0.00 1,953.43 3,100.00 76.78 320.14 1,758.64 1,575.84 1,574.20 -1,314.38 2,256,937.37 228,019.08 0.00 2,050.78 3,200.00 76.78 320.14 1,781.51 1,598.71 1,648.92 -1,376.78 2,257,013.48 227,958.38 0.00 2,148.13 3,300.00 76.78 320.14 1,804.39 1,621.59 1,723.64 -1,439.17 2,257,089.58 227,897.68 0.00 2,245.48 3,400.00 76.78 320.14 1,827.26 1,644.46 1,798.37 -1,501.57 2,257,165.69 227,836.98 0.00 2,342.82 3,500.00 76.78 320.14 1,850.13 • 1,667.33 1,873.09 -1,563.97 2,257,241.80 227,776.28 0.00 2,440.17 10 3/4" • 3,600.00 76.78 320.14 1,873.00 1,690.20 1,947.81 -1,626.37 2,257,317.90 227,715.58 0.00 2,537.52 3,700.00 76.78 320.14 1,895.88 1,713.08 2,022.53 -1,688.76 2,257,394.01 227,654.88 0.00 2,634.87 5/26/2015 5:05:41PM Page 3 COMPASS 5000.1 Build 73 • S Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Coordinate Reference: Well Grassim Oskolkoff#8 Company: Hilcorp Energy Company TVD Reference: GO#8 @ 182.8ousft(Saxon169(164.8GL+18KB)) Project: Ninilchik Unit MD Reference: GO#8 @ 182.8ousft(Saxon169(164.8GL+18KB)) Site: Grassim Oskolkoff North Reference: True Well: Grassim Oskolkoff#8 Survey Calculation Method: Minimum Curvature Wellbore: GO 8 Design: GO-8 WP3 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-5 +E/-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 1,735.95 3,800.00 76.78 320.14 1,918.75 1,735.95 2,097.26 -1,751.16 2,257,470.12 227,594.19 0.00 2,732.22 3,900.00 76.78 320.14 1,941.62 1,758.82 2,171.98 -1,813.56 2,257,546.22 227,533.49 0.00 2,829.57 4,000.00 76.78 320.14 1,964.49 1,781.69 2,246.70 -1,875.95 2,257,622.33 227,472.79 0.00 2,926.92 4,100.00 76.78 320.14 1,987.37 1,804.57 2,321.42 -1,938.35 2,257,698.43 227,412.09 0.00 3,024.27 4,200.00 76.78 320.14 2,010.24 1,827.44 2,396.15 -2,000.75 2,257,774.54 227,351.39 0.00 3,121.62 4,300.00 76.78 320.14 2,033.11 1,850.31 2,470.87 -2,063.14 2,257,850.65 227,290.69 0.00 3,218.96 4,400.00 76.78 320.14 2,055.99 1,873.19 2,545.59 -2,125.54 2,257,926.75 227,229.99 0.00 3,316.31 4,500.00 76.78 320.14 2,078.86 1,896.06 2,620.31 -2,187.94 2,258,002.86 227,169.29 0.00 3,413.66 4,600.00 76.78 320.14 2,101.73 1,918.93 2,695.04 -2,250.34 2,258,078.97 227,108.60 0.00 3,511.01 4,609.05 76.78 320.14 2,103.80 1,921.00 2,701.80 -2,255.98 2,258,085.85 227,103.10 0.00 3,519.82 Beluga 50 4,700.00 76.78 320.14 2,124.60 1,941.80 2,769.76 -2,312.73 2,258,155.07 227,047.90 0.00 3,608.36 4,800.00 76.78 320.14 2,147.48 1,964.68 2,844.48 -2,375.13 2,258,231.18 226,987.20 0.00 3,705.71 4,900.00 76.78 320.14 2,170.35 1,987.55 2,919.20 -2,437.53 2,258,307.29 226,926.50 0.00 3,803.06 5,000.00 76.78 320.14 2,193.22 2,010.42 2,993.93 -2,499.92 2,258,383.39 226,865.80 0.00 3,900.41 5,100.00 76.78 320.14 2,216.09 2,033.29 3,068.65 -2,562.32 2,258,459.50 226,805.10 0.00 3,997.76 5,200.00 76.78 320.14 2,238.97 2,056.17 3,143.37 -2,624.72 2,258,535.60 226,744.40 0.00 4,095.11 5,300.00 76.78 320.14 2,261.84 2,079.04 3,218.09 -2,687.12 2,258,611.71 226,683.70 0.00 4,192.45 5,400.00 76.78 320.14 2,284.71 2,101.91 3,292.82 -2,749.51 2,258,687.82 226,623.00 0.00 4,289.80 5,500.00 76.78 320.14 2,307.58 2,124.78 3,367.54 -2,811.91 2,258,763.92 226,562.31 0.00 4,387.15 5,600.00 76.78 320.14 2,330.46 2,147.66 3,442.26 -2,874.31 2,258,840.03 226,501.61 0.00 4,484.50 5,700.00 76.78 320.14 2,353.33 2,170.53 3,516.98 -2,936.70 2,258,916.14 226,440.91 0.00 4,581.85 5,800.00 76.78 320.14 2,376.20 2,193.40 3,591.71 -2,999.10 2,258,992.24 226,380.21 0.00 4,679.20 5,900.00 76.78 320.14 2,399.07 2,216.27 3,666.43 -3,061.50 2,259,068.35 226,319.51 0.00 4,776.55 6,000.00 76.78 320.14 2,421.95 2,239.15 3,741.15 -3,123.89 2,259,144.46 226,258.81 0.00 4,873.90 6,100.00 76.78 320.14 2,444.82 2,262.02 3,815.87 -3,186.29 2,259,220.56 226,198.11 0.00 4,971.25 6,200.00 76.78 320.14 2,467.69 2,284.89 3,890.60 -3,248.69 2,259,296.67 226,137.41 0.00 5,068.59 6,300.00 76.78 320.14 2,490.57 2,307.77 3,965.32 -3,311.09 2,259,372.77 226,076.72 0.00 5,165.94 6,400.00 76.78 320.14 2,513.44 2,330.64 4,040.04 -3,373.48 2,259,448.88 226,016.02 0.00 5,263.29 6,500.00 76.78 320.14 2,536.31 2,353.51 4,114.76 -3,435.88 2,259,524.99 225,955.32 0.00 5,360.64 6,600.00 76.78 320.14 2,559.18 2,376.38 4,189.49 -3,498.28 2,259,601.09 225,894.62 0.00 5,457.99 6,700.00 76.78 320.14 2,582.06 2,399.26 4,264.21 -3,560.67 2,259,677.20 225,833.92 0.00 5,555.34 6,800.00 76.78 320.14 2,604.93 2,422.13 4,338.93 -3,623.07 2,259,753.31 225,773.22 0.00 5,652.69 6,802.57 76.78 320.14 2,605.52 2,422.72 4,340.85 -3,624.67 2,259,755.26 225,771.66 0.00 5,655.19 Cont Dir 5°/100'@ 6803'MD,2606'ND 6,900.00 71.91 320.14 2,631.80 2,449.00 4,412.84 -3,684.79 2,259,828.58 225,713.18 5.00 5,748.98 7,000.00 66.91 320.14 2,666.97 2,484.17 4,484.67 -3,744.77 2,259,901.74 225,654.83 5.00 5,842.56 7,100.00 61.91 320.14 2,710.15 2,527.35 4,553.87 -3,802.56 2,259,972.23 225,598.62 5.00 5,932.72 7,200.00 56.91 320.14 2,761.03 2,578.23 4,619.92 -3,857.71 2,260,039.50 225,544.96 5.00 6,018.77 7,300.00 51.91 320.14 2,819.21 2,636.41 4,682.32 -3,909.82 2,260,103.06 225,494.28 5.00 6,100.06 7,400.00 46.91 320.14 2,884.26 . 2,701.46 4,740.59 -3,958.47 2,260,162.40 225,446.95 5.00 6,175.97 7 5/8" - 7,500.00 41.91 320.14 2,955.68 2,772.88 4,794.28 -4,003.31 2,260,217.09 225,403.33 5.00 6,245.92 7,600.00 36.91 320.14 3,032.92 2,850.12 4,842.99 -4,043.99 2,260,266.71 225,363.76 5.00 6,309.38 7,700.00 31.91 320.14 3,115.40 2,932.60 4,886.35 -4,080.19 2,260,310.87 225,328.54 5.00 6,365.87 5/26/2015 5:05:41PM Page 4 COMPASS 5000.1 Build 73 0 Halliburton H A LL I B U R TO N Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Grassim Oskolkoff#8 Company: Hilcorp Energy Company TVD Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) Project: Ninilchik Unit MD Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) Site: Grassim Oskolkoff North Reference: True Well: Grassim Oskolkoff#8 Survey Calculation Method: Minimum Curvature Wellbore: GO 8 Design: GO-8 WP3 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +El-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,019.69 7,800.00 26.91 320.14 3,202.49 3,019.69 4,924.03 -4,111.65 2,260,349.24 225,297.94 5.00 6,414.96 7,900.00 21.91 320.14 3,293.52 3,110.72 4,955.74 -4,138.13 2,260,381.54 225,272.18 5.00 6,456.26 8,000.00 16.91 320.14 3,387.81 3,205.01 4,981.23 -4,159.42 2,260,407.50 225,251.47 5.00 6,489.48 8,100.00 11.91 320.14 3,484.64 3,301.84 5,000.32 -4,175.36 2,260,426.95 225,235.96 5.00 6,514.35 8,132.70 10.27 320.14 3,516.72 3,333.92 5,005.15 -4,179.39 2,260,431.87 225,232.04 5.00 6,520.64 GO-8 T1 Tyonek 8,198.53 6.98 320.14 3,581.80 3,399.00 5,012.73 -4,185.72 2,260,439.58 225,225.89 5.00 6,530.51 End Dir @ 8199'MD,3582'TVD-Tyonek 8,200.00 6.98 320.14 3,583.26 3,400.46 5,012.87 -4,185.83 2,260,439.72 225,225.78 0.00 6,530.69 8,300.00 6.98 320.14 3,682.52 3,499.72 5,022.19 -4,193.62 2,260,449.23 225,218.20 0.00 6,542.84 8,400.00 6.98 320.14 3,781.78 3,598.98 5,031.52 -4,201.41 2,260,458.73 225,210.62 0.00 6,555.00 8,500.00 6.98 320.14 3,881.04 3,698.24 5,040.85 -4,209.20 2,260,468.23 225,203.05 0.00 6,567.15 8,600.00 6.98 320.14 3,980.29 3,797.49 5,050.18 -4,216.99 2,260,477.73 225,195.47 0.00 6,579.30 8,608.57 6.98 320.14 3,988.80 3,806.00 5,050.98 -4,217.66 2,260,478.54 225,194.82 0.00 6,580.34 T6 8,700.00 6.98 320.14 4,079.55 3,896.75 5,059.51 -4,224.78 2,260,487.23 225,187.89 0.00 6,591.45 8,800.00 6.98 320.14 4,178.81 3,996.01 5,068.84 -4,232.57 2,260,496.73 225,180.32 0.00 6,603.61 8,900.00 6.98 320.14 4,278.07 4,095.27 5,078.16 -4,240.35 2,260,506.23 225,172.74 0.00 6,615.76 9,000.00 6.98 320.14 4,377.33 4,194.53 5,087.49 -4,248.14 2,260,515.73 225,165.16 0.00 6,627.91 9,100.00 6.98 320.14 4,476.59 4,293.79 5,096.82 -4,255.93 2,260,525.23 225,157.59 0.00 6,640.06 9,200.00 6.98 320.14 4,575.85 4,393.05 5,106.15 -4,263.72 2,260,534.73 225,150.01 0.00 6,652.21 9,300.00 6.98 320.14 4,675.11 4,492.31 5,115.48 -4,271.51 2,260,544.23 225,142.43 0.00 6,664.37 9,400.00 6.98 320.14 4,774.37 4,591.57 5,124.81 -4,279.30 2,260,553.74 225,134.86 0.00 6,676.52 9,500.00 6.98 320.14 4,873.62 4,690.82 5,134.13 -4,287.09 2,260,563.24 225,127.28 0.00 6,688.67 9,600.00 6.98 320.14 4,972.88 4,790.08 5,143.46 -4,294.87 2,260,572.74 225,119.70 0.00 6,700.82 9,700.00 6.98 320.14 5,072.14 4,889.34 5,152.79 -4,302.66 2,260,582.24 225,112.13 0.00 6,712.98 9,726.86 6.98 320.14 5,098.80 4,916.00 5,155.30 -4,304.75 2,260,584.79 225,110.09 0.00 6,716.24 ' T20 9,800.00 6.98 320.14 5,171.40 4,988.60 5,162.12 -4,310.45 2,260,591.74 225,104.55 0.00 6,725.13 9,900.00 6.98 320.14 5,270.66 5,087.86 5,171.45 -4,318.24 2,260,601.24 225,096.97 0.00 6,737.28 10,000.00 6.98 320.14 5,369.92 5,187.12 5,180.78 -4,326.03 2,260,610.74 225,089.40 0.00 6,749.43 10,039.55 • 6.98 320.14 5,409.18 • 5,226.38 5,184.46 -4,329.11 2,260,614.50 225,086.40 0.00 6,754.24 TD @ 10040'MD,5409'TVD-4 1/2"-GO 8 T2 TD-GO 8 TD tgt 5/26/2015 5:05:41PM Page 5 COMPASS 5000.1 Build 73 0 • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Grassim Oskolkoff#8 Company: Hilcorp Energy Company ND Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) Project: Ninilchik Unit MD Reference: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) Site: Grassim Oskolkoff North Reference: True Well: Grassim Oskolkoff#8 Survey Calculation Method: Minimum Curvature Wellbore: GO 8 Design: GO-8 WP3 Targets Target Name -hit/miss target Dip Angle Dip Dir. TVD +NI-S +E/-W Northing Easting -Shape (°) (°) (usft) (usft) (usft) (usft) (usft) GO 8 T2 TD 0.00 0.00 5,409.18 5,184.46 -4,329.11 2,260,614.50 225,086.40 -plan hits target center -Circle(radius 100.00) GO-8 T1 Tyonek 0.00 0.00 3,581.80 4,704.85 -3,928.61 2,260,126.00 225,476.00 -plan misses target center by 396.57usft at 8121.31 usft MD(3505.53 TVD,5003.55 N,-4178.06 E) -Circle(radius 100.00) GO 8 TD tgt 0.00 0.00 8,685.80 5,184.46 -4,329.11 2,260,614.50 225,086.40 -plan misses target center by 3276.62usft at 10039.55usft MD(5409.18 TVD,5184.46 N,-4329.11 E) -Circle(radius 100.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name ('•) (1 7,400.00 2,884.26 7 5/8" 7-5/8 9-7/8 10,039.55 5,409.18 4 1/2" 4-1/2 6-3/4 3,500.00 1,850.13 10 3/4" 10-3/4 13-1/2 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology (1 (1 8,198.53 3,581.80 Tyonek 0.00 4,609.05 2,103.80 Beluga 50 0.00 9,726.86 5,098.80 T20 0.00 8,608.57 3,988.80 T6 0.00 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 250.00 250.00 0.00 0.00 Start Dir 2°/100'W 250'MD,250'TVD 450.00 449.84 5.36 -4.46 Cont Dir 5°/100 @ 450'MD,450'TVD 1,905.56 1,485.44 681.68 -569.08 End Dir @ 1906'MD,1485'TVD 6,802.57 2,605.52 4,340.85 -3,624.67 Cont Dir 5°/100'@ 6803'MD,2606'TVD 8,198.53 3,581.80 5,012.73 -4,185.72 End Dir @ 8199'MD,3582'TVD 10,039.55 5,409.18 5,184.46 -4,329.11 TD @ 10040'MD,5409'TVD 5/26/2015 5:05:41PM Page 6 COMPASS 5000.1 Build 73 • • • Hilcorp Energy Company Ninilchik Unit Grassim Oskolkoff Grassim Oskolkoff#8 GO 8 GO-8 WP3 Sperry Drilling Services Clearance Summary Anticollision Report 26 May,2015 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: Grassim Oskolkoff-Grassier Oskolkoff#8-GO 8-GO-8 WP3 Well Coordinates: 2,255,334.02 N,229,297.68 E(60°09'54.55"N,151°29'10.56"W) Datum Height: GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)) Scan Range:0.00 to 10,039.55 usft.Measured Depth. Scan Radius is 1,202.16 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build: 73 Scan Type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services • • Hilcorp Energy Company HALLIBURTON Ninilchik Unit Anticollision Report for Grassim Oskolkoff#8-GO-8 WP3 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: Grassim Oskolkoff-Grassim Oskolkoff#8-GO 8-GO-8 WP3 Scan Range:0.00 to 10,039.55 usft.Measured Depth. Scan Radius is 1,202.16 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft Grassim Oskolkoff Grassim Oskolkoff#1-GO 1-GO 1 204.92 98.55 204.92 97.05 208.13 65.470 Centre Distance Pass- Grassim Oskolkoff#1-GO 1-GO 1 225.00 98.62 225.00 97.03 227.55 61.881 Ellipse Separation Pass- Grassim Oskolkoff#1-GO 1-GO 1 4,375.00 1,201.35 4,375.00 1,056.50 4,219.00 8.294 Clearance Factor Pass- Grassim Oskolkoff#2-GO 2-GO 2 247.72 56.41 247.72 54.53 251.94 30.060 Centre Distance Pass- Grassim Oskolkoff#2-GO 2-GO 2 250.00 56.41 250.00 54.52 254.19 29.897 Ellipse Separation Pass- Grassim Oskolkoff#2-GO 2-GO 2 500.00 69.51 500.00 66.46 500.00 22.789 Clearance Factor Pass- Grassim Oskolkoff#4-GO 4-GO 4 619.24 183.18 619.24 177.31 641.25 31.205 Centre Distance Pass- Grassim Oskolkoff#4-GO 4-GO 4 625.00 183.20 625.00 177.26 645.69 30.848 Ellipse Separation Pass- Grassim Oskolkoff#4-GO 4-GO 4 4,425.00 1,199.24 4,425.00 1,014.25 4,277.33 6.483 Clearance Factor Pass- Grassim Oskolkoff#5-GO 5-GO 5 515.39 245.36 515.39 242.47 527.31 84.848 Centre Distance Pass- Grassim Oskolkoff#5-GO 5-GO 5 525.00 245.38 525.00 242.44 536.56 83.474 Ellipse Separation Pass- Grassim Oskolkoff#5-GO 5-GO 5 4,125.00 1,192.37 4,125.00 1,086.07 4,238.35 11.217 Clearance Factor Pass- Survey fool program From To Survey/Plan Survey Tool (usft) (usft) 18.00 3,500,00 GO-8 WP3 MWD*SC*sag 3,500,00 7,400.00 GO-8 WP3 MWD*SC*sag 7,400.00 10,039.55 GO-8 WP3 MWD*SC*sag 26 May,2015- 17:13 Page2of5 COMPASS • • Hilcorp Energy Company HALLIBURTON Ninilchik Unit Anticollision Report for Grassim Oskolkoff#8-GO-8 WP3 Ellipse error terms are correlated across survey tool tie-on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor=Distance Between Profiles/(Distance Between Profiles-Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 26 May,2015-17:13 Page 3 of 5 COMPASS • . Hilcorp Energy Company HA LLI B U RTO N Ninilchik Unit Anticollision Report for Grassim Oskolkoff#8-GO-8 WP3 Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to GO#8 @ 182.80usft(Saxon169(164.8GL+18KB)). Northing and Easting are relative to Grassim Oskolkoff#8. Coordinate System is US State Plane 1927(Exact solution),Alaska Zone 04. Central Meridian is-150.00',Grid Convergence at Surface is:-1.29°. Ladder Plot C I M N101 I TIPer' 0 0 �� ,Ij C q = /- LEGEND ca 711 �� ca " Q I ►i ♦— GrassimOskolkofr#1,GO1,GO1V0 N 6 n ' '$ GrassimOntvtfvf#2,GO2,GO2VO $...,. GrassimOskolko6#4,G04,G04V0 `1 ' —ler Grassim Oskolkof#5,GO5,GO5V0 U :� $ GO-8 WP3 0) 35' ' O • • Hilcorp Energy Company H ALL I B U RTO N Ninilchik Unit Anticollision Report for Grassim Oskolkoff#8-GO-8 WP3 Clearance Factor Plot: Measured Depth versus Separation(Clearance)Factor 10.00 • 8.75— C 7.50— 6.25---- LEGEND i LL -}- Grassim Oslmlkoff#1,GO1,GO1 VO o s.00- - — $Grassim Oskolkoff#2,GO2,GO2V0 $ Grassim Oskolkoff#4,GO4,GO4V0 0 $ Grassim Oskolloff#S,GOS,GOSV0 Cl) 3.75 $ GO$1/l1F'3 2.50—- — --- Collision Avoidance Req —��`Zone-Stop Drilling 1.25— 0.00- 1 1 1 1 1111 1 1 1 1 1 1 1 1 1 1 1 1 1111 1111 1111 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 Measued Depth(750 usff/in) 26 May,2015- 17:13 Page 5 of 5 COMPASS • • Davies, Stephen F (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Friday, May 29, 2015 9:58 AM To: Davies, Stephen F (DOA) Subject: RE: GO 8 (PTD # 215-077) Permit to Drill Application: Additional Questions Attachments: AOGCC copy.xlsx You're welcome Steve! That's it,there is no additional notes on the summary.See attached excel file that the pdf was made from. Thanks! Monty M Myers Drilling Engineer Hilcorp Alaska Office:907.777.8431 Cell:907.538.1168 From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Friday, May 29, 2015 9:51 AM To: Monty Myers Subject: RE: GO 8 (PTD # 215-077) Permit to Drill Application: Additional Questions Thanks Monty, Now about that summary note on page 59: Could you please send me the rest of the summary sentence that was cut- off at the bottom of the page? Thanks for your help, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Monty Myers [mailto:mmyers@hilcorp.com] Sent: Thursday, May 28, 2015 4:37 PM To: Davies, Stephen F (DOA) Subject: RE: GO 8 (PTD # 215-077) Permit to Drill Application: Additional Questions Steve, I was out yesterday when the Drilling Program was submitted and had Luke sign it for me. Here are the corrections for the PTD.Thanks for getting on it so quick. Include, new cover page showing revision 2, new 9-7/8BHA, new well summary page with corrected MASP and Reservoir pressure, new TOC 1 . • I'm working through the revised Permit to Drill application for GO No.8. Nicely done! I have a couple of quick questions: Quick question on the LWD program: the text in Step 15. of Hilcorp's program indicates the 9-7/8" directional assembly will contain GR, resistivity,and density/neutron tools, but I don't see the density/neutron tools listed in the Component Data table on page 25. Are they contained in the HCIM collar?Or am I missing something? No,that was our original design BHA,and we have since added Neu/Dens to most wells. Correction attached. On page 59 (9-7/8" Hole Section MASP),the last portion of the sentence in Item 1 in the "Summary" section at the bottom of the page is missing. Are there other items in this summary section, or just one? Please email me a copy of the corrected page.Just the one summary note In Box 17, Maximum Anticipated Pressures,on the Permit to Drill application form, how are the values of 3735 psi (downhole)and 2866 psi (at surface) derived? I don't see them listed in the calculations presented on pages 59 and 60. believe those values may have been leftover from the originally submitted permit when the PTD was submitted on May 1st and didn't get updated yesterday on the 10-401. Should be 2325 downhole, and 1784 Surface and match the MASP calcs on pg 60 -----. To help with future applications, I noticed that Section 36.0,Salinity Calculation, isn't included in the Table of Contents (TOC)on page 1,and the sections that follow it are incorrectly numbered in the TOC. Forgot to update TOC after adding new field (see attached) Thank you! Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell: 907.538.1168 From: Luke Keller Sent: Thursday, May 28, 2015 3:41 PM To: Monty Myers Subject: FW: GO 8 (PTD # 215-077) Permit to Drill Application: Additional Questions From: Davies,Stephen F (DOA) Sent: 5/28/2015 2:32 PM To: Luke Keller Cc: Schwartz, Guy L(DOA) Subject: FW: GO 8 (PTD# 215-077) Permit to Drill Application: Additional Questions Luke, I'm working through the revised Permit to Drill application for GO No.8. Nicely done! I have a couple of quick questions: Quick question on the LWD program: the text in Step 15.5 of Hilcorp's program indicates the 9-7/8" directional assembly will contain GR, resistivity,and density/neutron tools, but I don't see the density/neutron tools listed in the Component Data table on page 25. Are they contained in the HCIM collar?Or am I missing something? 2 • • On page 59 (9-7/8" Hole Section MASP),the last portion of the sentence in Item 1 in the "Summary" section at the bottom of the page is missing. Are there other items in this summary section,or just one? Please email me a copy of the corrected page. In Box 17, Maximum Anticipated Pressures, on the Permit to Drill application form, how are the values of 3735 psi (downhole) and 2866 psi (at surface) derived? I don't see them listed in the calculations presented on pages 59 and 60. To help with future applications, I noticed that Section 36.0,Salinity Calculation, isn't included in the Table of Contents (TOC) on page 1, and the sections that follow it are incorrectly numbered in the TOC. Thanks for your help, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Monty Myers [mailto:mmyers@hilcorp.com] Sent: Tuesday, May 05, 2015 9:35 AM To: Davies, Stephen F (DOA) Cc: Schwartz, Guy L (DOA) Subject: RE: GO 8 (PTD # 215-077) Permit to Drill Application: Questions Good morning Steve, • The surveyor's plat is the correct version.All of this is just a plan until the conductor is driven.Once the conductor is driven,we will get an "as-built" surveyor's plat and correct the directional plan,and the drilling program to the surveyor's"as-built".We will then re-submit these items to the AOGCC for review.This is how it is done for almost every well we submit. • The Northing's and Eastings on Halliburton's directional plan will be corrected to the "as-built"after conductor is driven • The formation tops listed on page 49 is the geologists best guess for the MD of the well along that path.The TVD is more important to look at and they are spot on with the geoprog from page 49. Halliburton uses a more precise directional planning tool than our geologists do.Attached is the updated geoprog with corrected MD's. • The water well drilled on the blossom pad did not have any salinity analysis done to my knowledge and the same standardized text is included because the pad is less than a mile away to the south of the Blossom Pad. The issue was in fact resolved with the comments from Dave Buthman,our geologist for the calculations and the information you needed to back up the calculations., in an email dated March 24th 2015. "Hi Steve, Attached are 1)the salinity calculations for the Falls Creek#1 well (the nearest well with the shallowest SP run, and located 13,652 feet to the northeast of the Blossom well), and 2) McGee's 1976 cross section showing Cook Inlet Water Salinities. On McGee's cross section,the Blossom 1 would lie at approximately the Mobil 1-Ninilchik well posting, and indicates 250' depth to the base of the freshwater surface. The Falls Creek 1 ran SP below 250', so salinity calculations reported could not have been made using this well (calculations for this well are herein attached). Gas shows in the Falls Creek 1 increase from 9 units at 250'to 25 units at 660', and increase below that.We anticipate eventual gas production from very shallow intervals such as this at wells more optimally located on the structure. 3 • • If you need further clarification, please don't hesitate to call or email. Regards, David B. Buthman Sr. Geologist 3800 Centerpoint Drive Suite 100 Anchorage,AK 99503" Please let me know what other questions arise. Thank you! Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell:907.538.1168 From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Monday, May 04, 2015 4:50 PM To: Monty Myers Cc: Schwartz, Guy L (DOA) Subject: FW: GO 8 (PTD # 215-077) Permit to Drill Application: Questions Monty, Please provide information to support Hilcorp's statement on page 7 of the application: All known potential fresh water zones exist above 200'. This information is based off salinity calculations of neighboring water wells. Chlorides are 1100 ppm at the 171 -194'sand, 1800 ppm at the 505—535'sand, and 6000 ppm at the 1040' sand. Furthermore, the TGAS (total gas) curve from offset mud logs begins registering shallow gas at depths just below the sandstone bed at 200'. Hilcorp included this same standardized text in the Permit to Drill application for Blossom 1, but as I recall no one at Hilcorp knows where it came from. Please information regarding the depth to the base of freshwater at the GO Pad that utilizes recent logs/mudlogs so that I may verify Hilcorp's conclusions. Regards, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue,Suite 100 Anchorage,AK 99501 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 4 • • you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or From: Davies, Stephen F (DOA) Sent: Monday, May 04, 2015 3:49 PM To: Monty Myers (mmyers@hilcorp.com) Subject: GO 8 (PTD # 215-077) Permit to Drill Application: Questions Monty, The footage coordinates listed for the surface location for the proposed GO 8 well on the Permit to Drill application form are slightly different (-12')than those presented on the accompanying surveyor's plat. Which coordinates are correct? Please submit a revised surveyor's plat if necessary. The northing and easting State Base Plane coordinates for the surface location on the Permit to Drill application form are about 30' different from those presented on Halliburton's proposed directional survey. Which coordinates are correct? Please submit a revised proposed directional survey if necessary. The formation tops list on page 49 presents the total depth of the well as being 12067' MD. On the Permit to Drill application form, the total depth of the well is listed as 13100' MD. I'm suspect that the measured depths for the other formation tops in this list are also incorrect. Could Hilcorp please submit a revised formation top list? I've just started my review of this application, so other questions may follow under separate cover. Regards, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue,Suite 100 Anchorage,AK 99501 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you,contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. 5 410 • 2./S 6' 37 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION NOTICE OF APPLICATION DEFICIENCY �__, (H The attached application is being returned due to the deficiency or deficiencies listed below. Please submit a new application and all required supporting information. insufficient information to confirm that the casing and cementing program will protect freshwater aquifers insufficient information to demonstrate that the proposed perforations will be in compliance with applicable spacing provisions _ insufficient information to demonstrate that adequate barriers to flow will be maintained failure to calculate (or to calculate accurately) anticipated pressures _insufficient information to confirm quality of cement and TOC, relative to proposed perforations insufficient or contradictory well location information or coordinates4-A'Lc2t17 aly ce,e,/-7 r "L. Ci-f tILtC1-.rvfLves.1 insufficient or contradictory geologic prognosis information ',4 014-— • other — �'4 c �et/ �, / /� GC.l f�-•� � L /�/ ULeye�(� e--( Lt.v-i J4( e-W 7�'it'tC��G �s�X 4' 'r 11-e-4--- other, t /-4---other, other other STATE OF ALASKA ALI,OIL AND GAS CONSERVATION COMMI _ ON MAY 0 1 2015 PERMIT TO DRILL 20 AAC 25.005 AQGr'' 1a.Type of Work: lb.Proposed Well Class: Development-Oil E] Service- Winj EI Single Zone • 1c.Specify if well is proposed for: Drill • ❑ Lateral ❑ Stratigraphic Test ❑ Development-Gas 0 • Service-Supply ❑ Multiple Zone ❑ Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory ❑ Service- WAG ❑ Service-Disp ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: . Blanket ❑✓ Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC Bond No. 22035244 • Grassim Oskolkoff(GO)#8 3.Address: 6.Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Drive,Suite 1400,Anchorage AK 99503 MD: 13,100' TVD: 8,690' Ninilchik Field 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Beluga/Tyonek Gas Pool . Surface: 1889'FNL,2550'FWL,Sec 23,TIN,R13W,SM,AK • ADL 389737;Unit Tract 3 • Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 1161'FSL, 14'FWL,Sec 14,T1 N,R13W,SM,AK N/A 6/13/2015 Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 1989'FNL, 1759'FEL,Sec 15,TIN,R13W,SM,AK 3096 • 3249'from unit boundry 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL: 183 feet 15.Distance to Nearest Well Open Surface: x-229280.84 . y- 2255338 • Zone-4 GL Elevation above MSL: 165.4 feet to Same Pool: 1,813' (GO#1) 16.Deviated wells: Kickoff depth: 400 feet 17.Maximum Anticipated Pr s in psig(see 20 AAC 25.035) Maximum Hole Angle: 78 degrees , Downhole: 37 Surface: 2866 psi 18.Casing Program: Specifications Top - Settin - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 13-1/2" 10-3/4" 45.5 L-80 BTC 3,500' 0 ) 3,500' . 2,023' • Lead-1913 ft3/Tail-371 ft3 9-7/8" 7-5/8" 29.7 L-80 BTC 10,500' 0 10,500' • 6,125' • Lead-1202 ft3/Tail-1090 ft3 6-3/4" 4-1/2" 12.6 L-80 DWC/CHT 2,800' 10,301 , 6' 13,1o9i 8,690' 618 ft3 19. PRESENT WELL CONDITION SUMMARY(To be• . ed fpt; drill and - ntry Operations) Total Depth MD(ft): Total Depth TVD(ft): Plugs measured . ct.Depth F t Effect. Depth TVD(ft): Junk(measured): Casing Length Size Cement V Iume MD TVD Conductor/Structural Surface �` Intermediate Z °V Production Liner ` Perforation Depth MD(ft): \! Perfor i n epth TVD(ft): 1 20. Attachments: Property Plat ❑ BOP Q, Dr i • .: am LI Time v.Depth Plot ❑ Shallow Hazard Analysis Diverter ,�} Se.',' 'ep.rt [1] Drilling Fluid Program ❑ 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: ``1�� Date 22. I hereby certify that the foregoing is true and correct. Monty Myers Contact mmyers(a�hilcorp.com Email Printed Name Monty Myers ' Title Drilling Engineer JJ SignaturePhone 777-8431 Date 5/1/2015 -'- Commission Use Only Permit to Drill //;,., API Nugi'6er: „ _ Permit Approval See cover letter for other Number: Zai" c--' �7 / 50-/35-/6,(,-,s -/ ��-tC- Date: requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained in shales:[y Other: Samples req'd: Yes❑ No 0 , Mud log req'd:Yes[1] No❑v• H2S measures: Yes Li No re Directional svy req'd:Yes ` No[1] Spacing exception req'd: Yes❑ No❑' Inclination-only svy req'd:Yes❑ NoL APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Submit Form and OiRr[GvilNrArtths Form 10-401(Revised 10/2012) from the date of approval(20 AAC 25.005(g)) Attachments in Duplicate • Monty Myers . Hilcorp Alaska, LLC Drilling Engineer 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Tel 907 777 8431 rico p Alakn,1.Lt: Email mmyers@hilcorp.com 5/1/2015 Commissioner Alaska Oil & Gas Conservation Commission RECEIVED 333 W. 7th Avenue / Anchorage, Alaska 99501 / MAY 0 1 2015 Re: Permit to Drill GO (Grassim Oskolkoff)#8 AOGCC Dear Commissioner, Enclosed for review and approval is the application for the Permit to Drill the GO#8 Development gas well. GO #8 is a development Tyonek and Beluga well. Pri ary objectives are Upper Beluga through Tyonek T90 reservoir sandstones. While drilling, we will establish the p of the Tyonek structure in order to determine whether or not to drill the well to its planned TD. Drilling operations are expected to commence approximately June 13th, 2015. - The Saxon Rig# 169 will be used to drill and complete the wellbore. A separate 10-403 sundry will be submitted prior to completion operations. The 10-401 PTD covers all operations up to running and cementing the 4-1/2" liner. If you have any questions, please don't hesitate to contact myself at 777-8431 or Paul Mazzolini at 777-8369. Sincerely, Monty Myers Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 • • Hilcorp Alask1 LLC Grassim Osko off#8 Drilli g Program Nin' chik Field Revision 0 April 22"d, 2015 • • GO#8 Drilling Procedure IIileorp Ala,ka,ITC ( Contents 1.0 Well Summary / 2 2.0 Management of Change Information ,l 3 3.0 Tubular Program: / 4 4.0 Drill Pipe Information: / 4 5.0 Internal Reporting Requirements / 5 / 6.0 Planned Wellbore Schematic 6 7.0 Drilling/Completion Summary / 7 8.0 Mandatory Regulatory Compliance/Notifications % 8 9.0 R/U and Preparatory Work �l/ 10 10.0 N/U 21-1/4"2M Diverter / 11 11.0 Drill 13-1/2"Hole Section ./ 13 12.0 Run 10-3/4"Surface Casing / 17 13.0 Cement 10-3/4"Surface Casing ,l 20 14.0 BOP N/U and Test / 23 15.0 Drill 9-7/8"Hole Section / 24 16.0 Run 7-5/8"Production Casing / 28 17.0 Cement 7-5/8"Cement Procedure / 30 18.0 Drill 6-3/4"Hole Section 33 19.0 Run 4-1/2"Production Liner o' 38 20.0 Cement 4-1/2"Production Liner ,' 41 21.0 Wellbore Clean Up&Displacement 45 22.0 Production Tubing Installation and Perf 45 23.0 BOP Schematic 46 24.0 Wellhead Schematic 47 25.0 Days Vs Depth 48 26.0 Formation Tops 49 27.0 Anticipated Drilling Hazards 49 28.0 Saxon Rig 169 Layout 53 29.0 FIT Procedure 54 30.0 Choke Manifold Schematic 55 31.0 Casing Design Information... 56 32.0 9-7/8"Hole Section MASP. 57 33.0 6-3/4"Hole Section MAS: 58 34.0 Spider Plot(NAD 27)(governmental Sections) 59 35.0 Surface Plat(As Built (NAD 27) 60 36.0 Offset MW vs TVD 'hart 61 37.0 Drill Pipe Informa on 62 • • GO#8 Drilling Procedure IIilrnrp Alaeka,i iA 1.0 Well Summary Well Grassim Oskolkoff#8 Pad&Old Well Designation GO#8 is a grass roots well on the GO Pad Planned Completion Type 4-1/2"tie back production tubing Target Reservoir(s) Beluga&Tyonek formations Planned Well TD, MD/TVD 13,084' MD/8,690' TVD PBTD, MD/TVD 12,964' MD/ 8,571' TVD Surface Location(Governmental) 3379' FSL, 2743' FEL, Sec 23, T1N, R13W,AK Surface Location(NAD 27) X=229280.84, Y=2255338 Surface Location(NAD 83) Top of Productive Horizon (Governmental) 1161' FSL, 14'FWL, Sec 14, T1N, R13W, SM, AK TPH Location(NAD 27) X=226812.81, Y=2258443.94 TPH Location(NAD 83) BHL (Governmental) 1989'FNL, 1759' FEL, Sec 15, T1N, R13W, SM, AK BHL(NAD 27) X=225086.4,Y=2260614.5 BHL(NAD 83) AFE Number 1511166D AFE Drilling Days 33 Days AFE Completion Days AFE Drilling Amount $4,507,600 AFE Completion Amount $1,034,000 Maximum Anticipated Pressure (Surface) 2866 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1� 3735 psig Work String / 4-1/2" 16.6# S-135 CDS-40 (Saxon Owned String) KB Elevation above MSLy� 183' GL Elevation above MS 165.4' (NGVD29) BOP Equipment 11" 5M T3-Energy Annular BOP 11" 5M T3-Energy Double Ram 11" 5M T3-Energy Single Ram Page 2 Revision 0 April, 2015 • GO#8 Drilling Pro,edure niko,p.a�,K�� tx,I: 2.0 Management of Change Information Hileorp Alaska, LLC H lcorp Cromomy Changes to Approved Permit to Drill Date: 4-22-2015 Subject: Changes to Approved Permit to Drill for Grassim Oskolkoff#8 File#: Grassim Oskolkoff#8 Drilling Program Any modifications to Grassim Oskolkoff#8 Drilling Program will be documented and approved below. Changes to an approved APD will be tromthe BLM and AOGCC. 04 ( �r �C S 4. 1 Sec Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Revision 0 April, 2015 • • GO #8 Drilling Procedure HtIem 1.) 11:o.ka.ill: 3.0 Tubular Program: Hole 7, foil(in) "'ill h(in) Drift Conn i, W,4 ,Grade, '',1C41.1-1:-.7''r.,Burst Colla a k" siu : Section ''°'"I ',�' = a; Wit,,OD*(in) '`'(#/ft).; " ``(moi):S';"'i (Psi) s) Cond 16" 15" - - 109 X-56 Weld 13-1/2" 10-3/4" 9.95" 9.875" 11.75" 45.5 L-80 BIC 5210 2470 1040 9-7/8" 7-5/8" 6.875" 6.75" 8.5" 29.7 L-80 BTC 6890 4790 683 6-3/4" 4-1/2" 3.918" 3.833" 5.0" 12.6 L-80 DWUC 8430 7500 288 HT 4.0 Drill Pipe Information: - Hole OD (in) ID (in) TJ ID TJ OD Wt Grade Conn Burst Collapse Tension Section _ ,, (in) (in) (#/ft) (psi) (psi) (k-lbs) All 4.5" 3.826 2.6875" 5.25" 16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100%mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Revision 0 April, 2015 • S GO #8 Drilling Procedure Hilrorp 1,1a48,1,1 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area—this will not save the data entered, and will navigate to another data entry tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com; mmyers@hilcorp.com, lkeller@hilcorp.com, &cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a username to login with. 5.4 EHS Incident Reporting • Notify EHS field coordinator. 1. Matt Hogge: 0: 777-8418 C: 907-227-9829 2. Spills: Julieanna Orczewska: 0:907-777-8444 • Notify Drlg Manager& Drlg Engineer: 1. Paul Mazzolini: 0: 90-777-8369 C: 907-317-1275 2. Monty M Myers: 0; 907-777-8431 C: 907-538-1168 • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final"As-Run"Cawing tally to mmyers@hilcorp.com&cdinger@hilcorp.com 5.6 Casing and Cmt report • Send casing and cement report for each string of casing to mmyers !hilcorp.com & cdin_er hilcor•.co Page 5 Revision 0 April, 2015 • 0 GO#8 Drilling Procedure Illikorp 41:04,a.HA: 6.0 Planned Wellbore Schematic NI,ilctukUnIt ti Ell cir.A..7).-5ial.Dag.i.i.,,aff#S PIC),XX X-XXX Planned SCHEMATIC CASING A ETAIL -' 1 : i, .i.-1 Size Tvpe W..1 Gra e Corm. ID Top atm 1.64' , 3 16" Conductor 84 X-56 Weld 15.020" Surf 78' '331? ,"--' 10-3/4" Surf.Csg 45.5 L-80 BTC 9.950" Surf 3,500' TOC @ 7-5/2" Prod.Csg 29.7 L-S0 BTC 6.875' Surf 10,500" 10-3,4': : ,..3.-' 2,000' DWCIC- 4-1/2" Prod Liner 12.6 L-80 HT' 3.958" 10,303 13,100' TUBING DETAIL 4-1/2" Tubing 12.5 L-80 BTG 3.958" Surf 10,30' /JEWELRY DETAIL Na. Depth ID / OD Item , 1 3.8" 4.00" / - Tubing Hanger,4-1/2" 2 29' - PupJoint 3 -170' / 4-1/2"SSW - 0 4 -10,140' / 4-1/2'Chemical Injection Mandrel , I K 1 4 . 5 -10,200' / 7-5I5"x4-1/2"Retrievable Production Packer 14 m s: / MI .,.,. 6 -:3,250' , / 4-1/2"X-Nipple 7 -10,300' / 4-1/2"Tailpipe t'l i a ,, --Jewelry set depths will be finalized after reviewing the open hole logs .• i ' Tis Back Re ceptxle // ei t Liner Hanger Pecker tp. 10,300' I rice 1 ri.e. e„,4 7-'1'''8" A k"'"' (4k', Shoe Ai0,,,,.• , 1 $' .4.4 . . X. v. ,-.. . " 6-3,4' hole . ' .... V. SIT @ 13,100' PBTD=12,980'MD/8,587'TVD TD= 13,100' MD/8,706'ND - Max Deviation:.78 deg Max Dogleg:5..gua0Q, Page 6 Revision 0 April, 2015 0 • II GO #8 Drilling Procedure tiilcorp Ala4a,1,1 1 7.0 Drilling / Completion Summary GO#8 is a development Tyonek and Beluga well. Primary objectives are Upper Beluga through Tyonek • T90 reservoir sandstones. While drilling, we will establish the top of the Tyonek structure in order to determine whether or not to drill the well to its planned TD. The base plan is an"S- Turn"wellbore reaching a maximum inclination of 78 deg and a 6,752' vertical separation. Drilling operations are expected to commence approximately June 13th, 2015. The Saxon Rig # 169 will be used to drill and complete the wellbore. After the rig has departed, the well will be perforated rigless. All known potential fresh water zones exist above 200'. This information is based off salinity calculations of neighboring water wells. Chlorides are 1100 ppm at the 171 — 194' sand, 1800 ppm at the 505 — 535' sand, and 6000 ppm at the 1040' sand. Furthermore, the TGAS (total gas) curve from offset mud logs begins registering shallow gas at depths just below the sandstone bed at 200'. 3 Ste' liv; Surface casing will be run to 3000' MD and cemented to surface to ensure protection of these resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6 — 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and,Completion operations will be hauled to the Kenai Gas Field G&I facility for disposal/beneficial reuse depending on test results. General sequence of operations: / /i 1. MOB Saxon Rig# 169 to well site 2. N/U 21-1/4"x 2M diverter. / 3. Drill 13-1/2" hole to 3500' MD� Run and cmt 10-3/4" surface casing. - 4. N/D diverter,N/U &test 11" 5M T3-Energy BOP. 5. Drill 9-7/8" hole section to 19,500' MD. Run and cmt 7-5/8" intermediate casing. 6. Drill 6-3/4"production hole,�ection to well TD. Run and cmt 4-1/2" production liner. 7. TIH w/clean out assy, clea out to landing collar. Displace mud to filtered completion fluid. 8. TOH, LDDP, RIH w/prod ction tubing. 9. N/D BOP, N/U temp aba donment cap, RDMO. Reservoir Evaluation Plan: • 1. Surface section: Mud ogging only 2. Intermediate section: R+Res +Den/Neu LWD +mud logging - 3. Production section: GR+ Res +Den/Neu LWD + mud logging - Page 7 Revision 0 April, 2015 • • GO#8 Drilling Procedure mi., :1Iaska,l.LC 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of GO #8. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/4000 psi &subsequent tests of the BOP equipment will be to 250/4000 psi for 5/5 min (annular to 50%rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.Q35 "Secondary well control for primary drilling and completion: blowout prevention equipmentAnd diverter requirements". • Ensure AOGCC approved drilling permiVis posted on the rig floor and in Co Man office. AOGCC Regulation Variance Reques•s: • No waivers requested Page 8 Revision 0 April, 2015 • 0 GO #8 Drilling Procedure IHilcom•p Ala4ka.I iA Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 13-1/2" • 21-1/4"x 2M Hydril MSP diverter Function Test Only • 11"x 5M T3-Energy(Model 7082)Annular BOP • 11"x 5M T3-Energy Double Ram Initial -st:250/4000 o Blind ram in btm cavity (' $ ular 2500 psi) • Mud cross 9-7/8"&6-3/4" • 11"x 5M T-3 Energy Single Ram • 3-1/8"5M Choke Line Subsequent Tests: • 2-1/16"x 5M Kill line 250/4000 • 3-1/8"x 2-1/16"5M Choke manifold (Annular 2500 psi) • Standpipe,floor valves,etc • Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). • Primary closing hydraulic pressure is provided by an e ctrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: • Well control event(BOPs utilized to shut in t - well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running cement operations. • Any other notifications required in AP P. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-7' -1236/Email: jim.regg@alaska.gov Guy Schwartz/Petroleum Engineer/(0)• '07-793-1226/(C): 907-301-4533 /Email: guy.schwartz@alaska.gov Victoria Loepp/Petroleum Engineer/(g): 907-793-1247/Email: Victoria.loepp@alaska.gov Primary Contact for Opportunity to wi P ess: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardi ation format: http://doa.alaska.gov/ogc/forms/TestWitnessNoti£html Notification/Emergency Phone: 90 -793-1236 (During normal Business Hours) Notification/Emergency Phone: 9 i 7-659-2714 (Outside normal Business Hours) Page 9 Revision 0 April, 2015 • S GO#8 Drilling Procedure Ha,.it Alaal.a, 9.0 R/U and Preparatory Work 9.1 Set 16" conductor at 100' below ground level. 9.2 Dig out and set cellar. Ensure to level area around cellar so drilling sub structure is level. 9.3 Install Seaboard slip-on 16-3/4" 3M "A" section. Ensure to orient weliead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of ri 9.6 R/U Saxon Rig# 169, spot service company shacks, of & R/U company man&toolpusher offices. 9.7 After rig equipment has been spotted, R/U han berm containment system around footprint of rig. 9.8 Mix spud mud for 13-1/2" hole section. 9.9 Set test plug in wellhead prior to N/U/diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.10 Install 5-1/2" liners in mud pum 5s. • TSM 1000 mud pumps ars rated at 3633 psi (85%)/ 333 gpm (100%) with 5-1/2" liners. Page 10 Revision 0 April, 2015 • • 111 GO#8 Drilling Procedure Fiilrnrl4lasha,LIf: 10.0 N/U 21-1/4" 2M Diverter 10.1 N/U 21-1/4" Hydril MSP 2M diverter System. • N/U 16-3/4" 3M x 21-1/4" 2M DSA (Hilcorp) on 16-3/4" 3M wellhead. • N/U 21-1/4" diverter"T". / • Knife gate, 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C `` 10.2 Function test diverter. Ensure that the knife gate and annular are o erated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked "warning zone" is establed on each side and ahead of the vent line tip. "Warning Zone"must include: • A prohibition on vehicle parking. i • A prohibition on ignition sources or running epment. • A prohibition on staged equipment or maters s. • Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set 15.375" ID wearbushing in wellhead. , Page 11 Revision 0 April, 2015 • GO#8 Drilling Procedure mi.!) kla.ka, 10.5 Diverter Schematic Diverter Schematic For 13-W Hole Section • ifi II Ill 111 111 II Al 1I1 Annular Preventer Knife Gate I 11 III '101 16"Diverter line mot 1 Er Diverter Tee, 2144"x 21-'4" x 2M WI 16"ANSI 150 outlet a ems ilia ill lit lit lit 16-W 3M x 21-W 2M OSA —ammosa — Ian loom 41a...goiii : P N . Seaboard 16-W 3M 111 1111",i1 4 t ; Casing head Assy 161' Page 12 Revision 0 April, 2015 • S GO#8 Drilling Procedure Hiking"Alaska.U.C: 11.0 Drill 13-1/2" Hole Section 11.1 P/U 13-1/2" directional drilling assy: • Ensure BHA components have been inspected previously. • • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the WD software. • Have DD run hydraulics calculations on site to ensure optimum no a sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 4.5" 16.6# S-135 CDS40. / • Ensure motor setting can achieve 5 deg/100' DLS in surface hole. Minimum of 1.5 deg AKO is recommended. 11.2 13-1/2"BHA (No LWD in surface hole BHA): COMPONENT DATA Item OD 1D Gauge Weight Top Length Cumulative Description Serial Number in innril fibpitiCcnrP'ttsn tfll Lentit) 1 HOBO OHC 1 GRC Milltooth 8.000 3 '8 13.500 140.76 P 6-5/8"REG 1.00 1.00 2 8"SperryDrill Lobe 4/5-5,3 stg 8.000 � .000 121.08 B 7"H90 32.00 33.00 Stabilizer 13.250 .................... . 3 8'MWD DM HOC 8.000 1.920 161.44 B 6-518-REG 8.75 41.75 4 8"Inline Stabilizer(ILS) 8/00 1.625 12.125 164 24 B 6-578"REG 3.80 45 55 5 8"MWD TM HOC .110 1.920 166 18 B 6-5'8"REG 9.50 55.05 6 8"Non Mag Flex Drill Collar /8.000 2.813 150.13 B 6-518"REG 29.50 84.55 7 8"Non Mag Flex Drill Collar 8.000 2.813 150.13 B 6-518'REG 30.00 114 55 8 8"NM Bottle Neck XO Sub 8.000 2.875 149.18 B 4-112"IF 2.25 116.80 9 6-314"Non Mag Flex Drill Collar 6.750 2.810 100.82 B 4-112"IF 30.00 146 80 10 6414'Non Mag Flex Drill Collar 6.750 2.810 100.82 B 4-1/2"IF 30.00 176 80 11 X-14 1/2"IF P r 4 1r2"CDS 40 B 6.500 2.750 82.85 B 4.5"CDS 40 2.75 179.55 12 4 its 4 1/2"CDS40 HWDP 4.500 2.813 36.80 122.00 301.55 13 X-O 4 112"CDS 40 P x 4 1/2"IF B 6.500 2.750 42.85 B 4-112"IF 2.75 304.30 14 Weatherford Hyd.Jar 6.480 2.750 ' 92.15 B 4-1/2"IF 32.00 336.30 15 X-0 4 1/2"IF P r 4 112"CDS 40 B! Rig 6.500 2.188 100 28 B 4.5"CDS 40 2.75 339 05 16 15 jts 4 1/2"CDS40 HWDP 7/ 4. 500 4.500 2.813 36.80 460.00 799.05 I c 799.05 BIT DATA Bit Number Nozzles : 3x16,1x14 Bit Size {in) : 13 500 TFA (int) 0.7394 Manufacturer : HOBS Dull Grade In Model : OHC1GRC Dull Grade Out • Serial Number . Page 13 Revision 0 April, 2015 • GO #8 fl Drilling Procedure IIiIriu r Alaska,1.11: 11.3 Primary bit will be the Security 13-1/2" QHC1GRC Milled Tooth Bit. These are available from Halliburton. 13-1/2** (143mm) QHC GRC PRODU(7r SPECIFICATIONS IAD('Cadc 117W +1,7 Total Tooth Count 64. caw Row Tooth Count 36 Journal Angle 33# Offset(1716") ft Jet Nwrrk Types Standard 83244 311317/6, Center Jet (If Center kited)501813 4,40; T.1.Connection 6- v(API Reg.), Recommended Slake-17p Torque* 210101837,000 Bit Weight 1Bosedi 260 Lbs,0 18 4.1 Bit Breaker (Mar Aqi.egaeyn) 114377164498 PraI IFEATURES Dititriondl" tooth bi• t design . .48 • Novi letary lYiaantaxirrenzixxol ma Moth liardfacing 4141 mining siructute and gage. i#774- • Tungsten carbide'surf inserts in gage teeth for added gage protection • Premium bearing and seal configuration suitable for both rotary and motor applications. was • Innovative meehanical pressure ionmermating system provides reliable pleasure equalization and relief for maximum bearing and life. • Raised tungsten carbide inserts and primrietary bardfacing provides maximum arm proteciant in abrasive and direetional applicanons while minimizing drill string torque, • QuailPack*Plot Series incorporates its successful"longevity" features and patented engineered hydraulics system for optimal eleaauta • Gaiter Jit feature to prevent bit balling problem Material#540030 .valculatio**t***t maartmciakeicass from API and Issahaila P1411 AVII.trat, i 2014 Halliburton.All rights reserred.Sales of Halliburte roams and services mlI be in accord solely with the terms and conditions contained in the continet between I button and the cus met that is appl liable to Ihe sale. www.BaBiburton.com Page 14 Revision 0 April, 2015 • • GO #8 Drilling Procedure F�ilrnrp a,LL(:: 11.4 4-1/2" Workstring& HWDP will come from Saxon. Jars will come from Weatherford. i 11.5 No LWD tools will be run on the 13-1/2"hole section. . / 11.6 Begin drilling out from 16" conductor at reduced flow rates to avoid broaching t -conductor. 11.7 Drill 13-1/2" hole section to 3500' MD/2023' TVD. Plan is to set the surface casing shoe through the base of the build section along the tangent at 78 deg. • Pump viscous sweeps as often as necessary and maintain mud rheology to ensure effective hole cleaning. • Pump at 550 gpm. This gives us an annular velocity of 83 fpm, which is borderline for effective hole cleaning. Ensure shaker screens are set up to/handle this flowrate. • Utilize Inlet experience to drill through coal seams efficie1itly. Coal seam log will be ' provided by Hilcorp Geo team. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. • TD the hole section in a good shale btwn 3450' & 3550' MD. . • Take MWD surveys every stand drilled (60' intervals) Page 15 Revision 0 April, 2015 • • GO#8 Drilling Procedure nilrarp Alaska I,I : 11.8 13-1/2" hole mud program summary: No weighting material will be required in the surface hole section. However, o gh barite should be available on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. • Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Tc(olpusher office, and mud loggers office. System Type: 8.8—9.5 ppg Pre-Hydrated Aquagel/freshwater spucimud Properties: MD Mud Viscosity PV YP API FL LGS Weight 78'-3,500' 8.8—9.5 . 250- 85 40 - 20 75 -25 <10 <15% System Formulation: AQUAGEL/freshwater Spud Mud Product cncentration Fresh Water 0.905 bbl soda Ash /0.5 ppb AQUAGEL / 15 - 20 ppb caustic soda 0.1 ppb(8.5 —9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8—9.5 ppg PAC-L/DEXTRID LT if required for<10 FL ALDACIDE G 0.1 ppb 11.9 At TD; pump sweeps, CB and pull a wiper trip back to the 16" conductor shoe. 11.10 TOH with the drilling a..sy, handle BHA as appropriate. Page 16 Revision 0 April, 2015 • 0 GO#8 Drilling Procedure rrrirot p.,111A.H,1,1,c 12.0 Run 10-3/4" Surface Casing 12.1 R/U and pull 15.375"wearbushing. 12.2 R/U Weatherford 10-3/4" casing running equipment. • Ensure 10-3/4" BTC x CDS 40 XO on rig floor and M/U to FOS . • R/U fill-up line to fill casing while running. • Ensure all casing has been drifted on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor& model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U &thread locking shoe track assy consisting of: • (1) Shoe joint w/float shoe bucked on (thread locked). • (1) Joint with coupling thread locked. • (1) Joint with float collar bucked on pin end &thread locked. • Install (2) centralizers on shoe joint over a stop collar. 10' from each end. • Install (1) centralizer, mid tube on thread locked joint and on FC joint. • Ensure proper operation of float equipment. 12.5 Continue running 10-3/4" surface casing • Fill casing while running using fill up line on rig floor. • Use "API Modified"thread4ompound. Dope pin end only w/paint brush. • M/U connections to the baie of the triangle stamped on the pin end. Note M/U torque values required to achieve this position. Estimated torque to reach base of triangle: 10,750 ft-lbs. • After making up severak connections, use the torque required to M/U to base of triangle as the M/U torque and cghtinue running string. • Install (1) centralizer/every other joint to 300'. Do not run any centralizers above 300' in the event a top out job ' needed. • Utilize a collar cl p until weight is sufficient to keep slips set properly. 10- /4" BTC Estimated M/U Torque Ca ng OD Est Torque to Reach Triangle Base 10-3/4" 10,750 ft-lbs Page 17 Revision 0 April, 2015 • I:11r GO #8 Drilling Procedure Iliicorp Ala%ka.1,1,f' =MN fta ienaris Casing and Tubing Perform ce Data Choose pipe size,wall thickness and steel grade to view API connection options and performance data. Size • Wall • Grade - Connection V Unit Pipe Body Data '!'''');i40• 13/ Nominal OD 10.750 in Wall Thickness 0.400 in API On •iameter 9.794 in Nominal Weight 45.5011)&11 Nominal ID 9.950 in Alter :te Drift Diameter 9,875 in Plain End Weight 44.26 lbstft Nominal Cross Section 13.006 sq in PERFORMANCE Steel Grade 180 Minimum Yield 80,000 psi 'idinimum Ultimate 95,000 psi Body Yield Strength 1,040,000 lbs Internal Yield Pressure 5,210 psi / Collapse Pressure 2,470 psi 113 Connection Data Regular OD 11.750 in Threads Per Inch 5 Make-Up Thread Turns I PE4:41‘0,04110:P7L,14;1::;'f'f7.C.5r1;:i4,4:)4'1; Steel Grade L80 Minimum Yield .0,000 psi Minimum Ultimate 95,000 psi Joint Strength 1,063,000 lbs Internal Pressure , 5,210 psi Resistance eriarts4 II Pre turn Conner.tioris Print I Contact Us 1 Ver 8.6 12.6 Watch displacement carefully a I avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint an. /U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe 5-10' from TD if possible. Strap the landing joint while it is on the deck an. mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the well ead profile. Page 18 Revision 0 April, 2015 S GO #8 Drilling Procedure Ililrorlr 4Insk%,I,I:. 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. Page 19 Revision 0 April, 2015 i • GO#8 Drilling Procedure H it eor h A 1.14..4,LLC 13.0 Cement 10-3/4" Surface Casing 13.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room'n pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates/ • How to handle cmt returns at surface, regardless of how unlik y it is that this should occur. • Which pump will be utilized for displacement, and how thud will be fed to displacement pump. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 13.2 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.3 Pump 5 bbls 10 ppg spacer. Test surface cmt line Pump remaining 35 bbls 10 ppg spacer. 13.4 Drop bottom plug. Mix and pump cmt per beh3w recipe. 13.5 Cement volume based on annular volume/75% open hole excess. Job will consist of lead & tail, TOC brought to surface. ,/ Estimated Total Cement Volume: Section: Calculation: Vol ($BLS) Vol(1t3) LEAD: ,, 80' x .106 bpf= 8.5 48 16" Conductor x 10-3/4" casing annulus: LEAD: /3000' — 80') x .065 bpf x 332.2 1865 13-1/2" OH x 10-3/4" 1.75 = Casing annulus: Total LEAD: / 340.7 1913 TAIL: (3500'-3000') x .065 bpf x 57 319 13-1/2" OH x 10-3/4" 1.75 = Casing annulu : TA : 90 x .096 bpf = 9 49 10-3/4" Shoe tr ck: Total AIL: 66 371 Page 20 Revision 0 April, 2015 • • GO #8 Drilling Procedure rrfr.p a13=4.a,El t Cement Slurry Design: Lead Slurry (3000' MD to surface) Tail Slurry (3500' to 3000' MD) System Blend Conventional Density 12 lb/gal 15.2 lb/gal Yield 2.44ft3/sk 1.26 ft3/s Mix Fluid 14.437 gal/sk 5.76 g sk Base Fluid 14.417 gal/sk 5.76 gal/sk Expected 5 HR ;' 3 HR Thickening r' Code Description Concentration Code ,description Concentration D901 Cement 94 lb/sk D901 // Cement 94 lb/sk D046 Antifoam 0.2%BWOC D046 / Antifoam 0.2%BWOC D020 Extender 2.6% BWOC D065 Dispersant 0.4% BWOC Additives D079 Extender 2% BWOC D167 Fluid Loss 0.2% BWOC D110 Retarder 0.02 gal/sk cmt SOW Accelerator 0.25% BWOC r s' 13.7 Attempt to reciprocate casing during cement pimping if hole conditions allow. Keep the hanger elevated above the wellhead while working.4f the hole gets "sticky", land the hanger on seat and continue with the cement job. /r 13.8 After pumping cement, drop top plug acid displace cement with 9.2 ppg 6% KC1/PHPA drilling fluid (mud to be used on next hole sec/tion). 13.9 Ensure cement unit is used to displfce cmt so that volume tracking is more accurate. 13.10 Displacement calculation: / 3420' x .0962 b f= 329 bbls 13.11 Monitor returns closely whi displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wel, ead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cella/. Have some sugar available to retard setting of cement (1 ppb). fir' 13.12 Do not overdisplace by/more than V2 shoe track volume. Total volume in shoe track is 8.7 bbls. / 13.13 Be prepared for ce ent returns to surface. If cmt returns are not observed to surface, be prepared to run a mp log btwn 6— 18 hours after CIP. Page 21 Revision 0 April, 2015 • • GO#8 Drilling Procedure n1lf011 LTA' C 13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure a d confirm floats are holding. If floats do not hold, pressure up string to final circulating pre ure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi ove final circulating pressure if pressure must be held. 13.15 R/D cement equipment. Flush out wellhead with FW. 13.16 Back out and L/D landing joint. Flush out wellhead with FW 13.17 M/U pack-off running tool and pack-off to bottom of Lang ing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.18 Lay down landing joint and pack-off running tool. Ensure to report the following on wellez: • Pre flush type, volume(bbls)&weight(ppg) y. • Cement slurry type, lead or tail, volume&weight • Pump rate while mixing,bpm, note any shudown during mixing operations with a duration • Pump rate while displacing,note whether„displacement by pump truck or mud pumps, weight&type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped&bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement retuFbs at surface &volume • Note time cement in place • Note calculated top of cement/ , • Add any comments which Iould describe the success or problems during the cement job • Send final "As-Run" casing tally casing and cement report to mmyers a hilcorp.corn & cdinger(d�hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 22 Revision 0 April, 2015 • • IIGO #8 Drilling Procedure Flilrorp Alaaa.a,1,1 C 14.0 BOP N/U and Test 14.1 N/D the diverter. 14.2 N/U Seaboard multibowl wellhead assy. Install packoff 10-3/4" P-seals est to 3000 psi. 14.3 N/U 11" x 5M T3-Energy BOP as follows: • BOP configuration from Top down: 11" x 5M T3-Energy awl lar BOP/11" x 5M T3-Energy Model 6011i double ram/11" x 5M mud cross/11" x 5M T'-Energy Model 6011i single ram • Double ram should be dressed with 2-7/8 x 5" VBRs in,top cavity, blind ram in btm cavity. • Single ram should be dressed with 2-7/8 x 5" VBRs • N/U bell nipple, install flowline. • Install (2) manual valves & a check valve on kill ide of mud cross. • Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Run 4-1/2" BOP test assy, land out test plug(if not installed previously). • Test BOP to 250/4000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave "B" section side outl t valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 R/D BOP test assy. 14.6 Dump and clean mud pits, send ud mud to G&I pad for injection. 14.7 Mix 9.2 ppg 6% KC1/PHPA illing fluid for 9-7/8" hole section. 14.8 Set 10" ID wearbushing i ellhead. 14.9 Rack back as much 4-1/ " DP in derrick as possible to be used while drilling the hole section. 14.10 Install 5" liners in m d pumps. i • TSM 1000 mud mps are rated at 4250 psi (85%) /275 gpm (100%) with 5" liners. Page 23 Revision 0 April, 2015 • • 11 GO #8 Drilling Procedure HiIvor'Alaska,III 15.0 Drill 9-7/8" Hole Section 15.1 Prior to P/U 9-7/8" directional assy, test casing against blind rams to 2.10 psi / 30 min. 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verif, no debris inside components that cannot be drifted. i 15.4 Bit TFA should be-0.75 -0.80 in2. We need to pum.at-450 - 500 gpm to clean the hole effectively. Have the directional driller run hydraulics calculations to confirm optimum TFA. 15.5 P/U the below 9-7/8" directional drilling assy Fa R+RES +Den/Neu LWD) included in below BHA): / COMPONENT DATA iterttOP ID Stiff ID Gauge Weight 'fop Length Total Location De iu,€ 'ptnl (in) (in) tli f3 '72.-'r e,e�ai0a, lffl (ft) 1f} 1 HOBS MM65 PDC 7.000 2.500 9.875 114.43 P 4-112"REG 0.90 2 7"SperryDriil Lobe 7/8-6.0 stg 7.000 4.952 4.952 93.13 B 4-1/2"IF 26.40 27.30 3 6-314" Float Sub 6.750 2.813 2.813 100 78 B 4-1/2"IF 2.20 29.50 4 6-314"DM Collar(Directional) • 6.750 3.125 3.155 103.40 B 4-1/2"IF 9.20 38.70 5 6-3/4"'DGR Collar(Gamma) 6.750 1.920 4.430 97.80 B NC 50 4.55 43.25 6 6-314"EWR-P4 Collar(Resistivity) - 6150 2.000 3.978 104.30 B NC 50 12.10 55.36 7 6-314"HCIM Collar(Processor) 6150 1.920 3.667 _ . . 101.70 B NC 50 4.97 60.33 8 6-314"TM Collar(Telemetry) a 6.750 3.250 3.551 103.60 B 4-1/2"IF 10.00 70.33 9 6-314'Non Mag Flex Collar 6.750 2.813 100.78 B 4-1/2"IF 30.00 100.33 10 6-314'Non Mag Flex Collar / 6.750 2.813 100.78 B 4-112"IF 30.00 130.33 11 6-314'Well Commander Su 6.750 3.000 3.000 97.86 B 4-1/2"IF 13.00 143.33 12 X`0 4.5'IF P x 4.5"CDS B 6.500 2.750 2.750 92.85 B 4 40 CDB 2.75 146.08 13 4 x its 4.5"HWDP 4.508 2.813 33.02 120.00 266.08 14 X10 4.5'CDS 40 P x .5'IF B 6.500 2.750 2.750 92.85 B 4-1/2"IF 2.50 268.58 15 6-1/4")Nearherford Jar 6.250 2.313 2.313 90.24 B 4-112"IF 30.00 298.58 16 X10 4.5"IF P x 4.5"CDS 40 B 6.500 2.188 2.188 100.27 B 4.54"OCDS 3.00 301.58 17 15 x jts 4.5' HWDP 4.500 2.813 33.02 450.00 751.58 751.58 Page 24 Revision 0 April, 2015 . • GO #8 Drilling Procedure Ili!Pori)Alaska,1,11,t: 15.6 Primary bit will be the Security 9-7/8" MM65. 9-7/8" (251 mm) MM65 . , . . PRODUCT SPECIFICATIONS // Cutter Type Seleeteuttet lifliS ' -1- I ADC Code M323 lls:II Body Type MATRIX IF',..11*? , ' • Too('tit ter Cuont .114V Cutter Distribution ) Up Mill 6 0 Number of Large Nozzles6 / ,:„:„„..... :.,.. Nurobv of Medium Northes 0 / / sr' Number of Smell Nozzles 0 / ta. , Number of Micro Nozzles 0 / Nontbet of Ports(Sire.) 0 / Number of Replaceable Ports(Size) 0 Junk Slot Area(sq itil tilt 71 / Normalized Volum .45,4v. / e Face ,,„ ..,'• ,:i1,.. ,,,,,, :.:47,1,, .„, API Connection 4-1.7 REC.PIN ' Reimnimended Make-Up Torque* 11,461-17,766 Ft*Ibci,„ Nominal Dimensions** -1, , , , Make-Up face to Nose 10.81 in-275 nun/ . ,.„.... . (loop Length Sleeve Length 0 an-0 .: Shank Diameter6 in-15yrnan Break Out Plate i'Matirlegar5.41i IIII054., I Approximate Shipping Weight 250Lbs./I I 3Kg. SPECIAL FEATURES /' / , Up-Drill Curio's on Gage Pads.Iii6-Relieved Gage / , Material#771827 *nit specific recommended makeup mimic is it ittroti s i a the bit ID.and actual hit sub O.D.isiirized,its sperr.ford. in m....A,derl RF' 7G Se roi.e.nctianA&2.unuov.,jvv ..,14,,,i rtfi.m "net111 dit11011$44111.1: nssrainat i y vary slight. cin timinsfaellirad pessimis Hallibusson Doll Dim and Si"leVA Product%Nei Ds-oboists may change without nolicc. C 2013 lialliburton.All rights reserved_Sal of itallibliften products and services will be in accord solely with the terms and conditions omained in the contract between Flallibur n and the customer than is applicable to the saic. arivw.halliburton.com Page 25 Revision 0 April, 2015 • • GO #8 Drilling Procedure Miro'p Alawka,1,1.0 15.7 9-7/8"hole section mud program summary: Weighting material to be used for the hole section will be barite. Additiorja 1 barite will be on location to weight up the active system (1)ppg above highest anticipatecrMW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, loolpusher office, and mud loggers office. System Type: 9.2—9.8 ppg 6% KCl/PHPA fresh water based drilling fluid. Properties: MudPlastic MD Viscosity Yield Point pH HPHT t Weight Viscosity _2,500 9.2—9.8 40-53 15-25 15-25 8.5-9.5 < 11.0 ,,!/ 10,500' System Formulation: 6% KCL/EZ MUD/BDF-499 Product Concentration Water 0.905 bbl KCI 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) BDF-499 4 ppb EZ MUD DP 0.75 ppb(initially 0.25 ppb) DEXTRID LT / 1-2 ppb PAC-L 1 ppb BARACARB 5/25/50 5—10 ppb(3.3 ppb of each) BAROTROL PLUS 2—4 ppb SOLTEX 2—4 ppb BAROID 41 as required for a 9.2—9.8 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 ppb (maintain per dilution rate) 15.8 TIH, conduct shallow hole test of MWD and confirm LWD functioning properly. 15.9 Continue in hole and tag TOC. Note depth tagged on AM report. 15.10 Drill out plu0 and shoe track. Clean out rat hole and drill an additional 20' of new formation. 15.11 CBU an/ondition mud for FIT. 15.12 Conduct FIT to 12 ppg EMW. Page 26 Revision 0 April, 2015 • • GO #8 Drilling Procedure Ililcorp Ala.ka,1,LC 15.13 Drill 9-7/8"hole section to 10,500' MD /6,125' TVD. • • Pump sweeps and maintain mud rheology to ensure effective hole c -aning. • Pump at 500 - 510 gpm. Ensure shaker screens are set up to hail, e this flowrate. • Utilize inlet experience to drill through coal seams efficiently. oal seam log will be provided by Hilcorp Geo team, try to avoid sliding through •sal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days un •ss hole conditions dictate otherwise. If tight hole is encountered, screw in and begin bac earning connections until hole conditions improve. Shales in the Beluga format'•ns are notorious for swelling and causing tight hole. Most of the time, backreaming the on a short trip is the only solution. • Ensure shale shakers are functioning properl . Check for holes in screens on connections. • Adjust MW as necessary to maintain hole ability. Keep HTHP fluid loss < 8. • Take MWD surveys every stand drld. S eys can be taken more frequently if deemed necessary. • Mud Loggers: 30 ft samples with 20' amples in zones of interest, two sets of cuttings, chromatograph, pixler plots. 15.14 Casing point will be determined by ,ole conditions while drilling from 10300' MD to 10500' . MD. 15.15 At TD; pump sweeps, CBU, anpull a wiper trip back to the 10-3/4" shoe. 15.16 TOH with the drilling assy, 'andle BHA as appropriate. Page 27 Revision 0 April, 2015 • . GO#8 Drilling Procedure II dm p alaeka.LLC 16.0 Run 7-5/8" Production Casing 16.1 R/U and pull 10" ID wear bushing. Install and test 7-5/8" casing ram i top ram cavity. Test to 250/4000 psi. 16.2 Make a dummy run with casing hanger. Mark landing joint at la d out for later reference. 16.3 R/U Weatherford 7-5/8" casing running equipment. • Ensure 7-5/8" BTC x CDS-40 XO on rig floor and M to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor & model info. 16.4 P/U 7-5/8" 29.7# L-80 BTC shoe joint, visual verify no debris inside joint. 16.5 Continue M/U &thread locking the shoe trick assy consisting of: • (1) Float shoe joint w/float shoe bucged on. Install (2) bow spring centralizers at 10' from each end over a stop collar. / • (1) Baker locked joint. Install (1)/entralizer mid tube over a stop collar. • (1) Float collar joint w/float colltir bucked on pin end. Install (1) centralizer mid tube over / a stop collar. • Ensure proper operation of flat shoe and float collar. 16.6 Run 7-5/8" 29.7# L-80 BTC casing. • Fill casing while running Ising fill up line on rig floor. • Use "API Modified"thred compound. Dope pin end only w/paint brush. • Utilize a collar clamp uttil weight is sufficient to keep slips set properly. • Install centralizersov couplings on every joint to 6,500' MD. • Install centralizers ov r couplings on every other joint to 3,400' MD. 16.7 Watch displacement c efully and avoid surging the hole. Slow down running speed if necessary. 16.8 Slow in and out of lips. 16.9 P/U casing hang r joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint al ady M/U. Position the shoe approx 10—20' above TD with hanger landed out. / Page 28 Revision 0 April, 2015 • • GO #8 Drilling Procedure IIllnorh Ala*ka,HA: Casing and Tubing Performance Data PIPE BODY DATA GEOMETRY Outside Diameter 7.625 in Wall Thickness 0.375 in API Drift Diameter 6.750 in Nominal Weight 29.70 lbs/ft Nominal ID 6.875 in Alternative Drift Diameter n.a. Plain End Weight 29.06 lbs/ft Nominal cross section 8.541 in PERFORMANCE Steel Grade L80 Minimum Yield 80,000 psi Minimum Ultimate 95,000 psi Tension Yield 683,000 in Internal Pressure Yield 6,890 psi Collapse Pressure 4,790 psi Available Seamless Yes Available Welded No CONNECTION DATA TYPE:BTC GEOMETRY Coupling Reg OD 8.500 in Threads per in 5 Thread turns ake up 1 PERFORMANCE Steel Grade L80 Coupling Min Yield 80,000 psi Couplin• in Ultimate 95,000 psi Joint Strength 721,000 lbs Inter .I Pressure Resistance 6,890 psi 7-5/8" BTC Estimated M/U Torque Casing OD / Est Torque to Reach Triangle Base 7-5/8" 7,630 ft-lbs 16.10 Lower string and land out in wel ead. Confirm measurements indicate the hanger has correctly landed out in the wellhead prof e. 16.11 R/U circulating equipment a d circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat lightly) to avoid plugging the flutes. Stage up pump slowly and monitor losses closely wh. e circulating. 16.12 Continue circulating un 1 required properties achieved for cmt operations. 16.13 After circulating, low r string and land hanger in wellhead again. Page 29 Revision 0 April, 2015 • • GO#8 Drilling Procedure k�ilrorp Alaaka.LLC 17.0 Cement 7-5/8" Cement Procedure 17.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid Will be fed to displacement pump. • Positions and expectations of personnel involved with t}re cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 17.2 R/U cmt head (if not already done so). Ensure top &bottom plugs are loaded correctly. 17.3 Pump 5 bbls 10 ppg spacer. Close low torque on, lug dropping head, test surface cmt lines to 4000 psi. 17.4 Pump remaining 35 bbls 10 ppg spacer. 17.5 Mix and pump slurry per below calculax ons: Section: Calculation: Vol (BBLS) Vol (ft3) LEAD: 9-7/8" OH x 7-5/8" csg: (6,500'- 2 100') x .038 bpf x 1.25 = 214 1202 Total Lead: 214 bbls 1202 ft3 TAIL: 4000' x .038 bpf x 1.25 = 190 1067 9-7/8" OH x 7-5/8" csg: TAIL: 7-5/8" Shoe Track: 90' x .046 bpf= 4.1 23 Total Tail: 194.1 bbls 1090 ft3 Page 30 Revision 0 April, 2015 • • GO#8 Drilling Procedure nilcorp Aln.+kn.LLC Slurry Information tna ai; � �„t®� ip �'�;iNi�� ` r 3�'�e k�� l v,day 7�a �� -4 �r a��`��tl iP�i�,ti �' ,ter Edi ��;„ � _ _ n ' ��riu �r � � P��k��nN„ q��,k�� System Conventional Conventional Density 12.4 lb/gal 15.3 lb/gal Yield 1.58 ft3/sk 1.35 ft3/sk Mixed Water 8.09 gal/sk 5.912 gal/sk Mixed Fluid 8.09 gal/sk 5.962 gal/sk Expected Thickening 5:30 HR:MIN 4:00 HR:M Expected ISO/API 13 mL in 0 min Fluid Loss Code Description Concentration Code Descripri 'on Concentration G Cement 94 lb/sk WBWOB G dement 94 lb/sk WBWOB D110 Retarder 0.05 gal/sk D110 //Retarder 0.05 gal/sk VBWOC / VBWOC Additives D046 Anti Foam 0.2%BWOB D046 / Anti Foam 0.2%BWOB / D020 Extender 4.0%BWOB D202 / Dispersant 1.5%BWOB D065 Dispersant 0.3%BWOB D40(/ Gas Control Agent 0.8%BWOB D800 Retarder 0.2%BWOB D 514 Extender 8.0%BWOB pi 74 Expanding Agent 1.5%BWOB 17.7 After pumping cement, drop flexible shut-off plug and displace cement with mud. Use the cement unit to displace with as volumes can Xe tracked much more accurately. Displacement calcs: • 10,500' x .0459 bpf= 344 bbls. • Displace with 9.2 ppg 6% KC1/PI-PA drilling fluid out of mud pits. 17.8 Monitor returns closely while displ4ting cement. Adjust pump rate if necessary. 17.9 Do not overdisplace by more thayl V2 shoe track volume. Total volume in shoe track is 4.1 bbls. 17.10 There should be no cmt return/to surface. TOC is planned to be at 2,000' MD. 17.11 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do n�t hold, pressure up string to final circulating pressure and hold until cement is set. • If this is the case, nitor the pressure on the casing and do not let it exceed 500 psi over the final pump pre sure. Bleed off pressure occasionally as necessary to ensure stage tool isn't opened pre turely. Page 31 Revision 0 April, 2015 GO #8 Drilling Procedure Harm9 Alaska,I iA Ensure to report the following on wellez: • Pre flush type,volume (bbls) &weight(ppg) • Cement slurry type, lead or tail, volume&weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing,note whether displacement by pump truck or mud pumps'', weight&type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether p1'ug bumped &bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pum ing of job. Final circulating pressure • Note if pre flush or cement returns at surface &volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Send final "As-Run" casing tally & casing and cement report to mmyers@hilcorp.corn. This will be included with the EOW documentation that goes to the AOGCC. 17.1 R/D cement equipment. Flush out wellhead with FW. 17.2 Back out and L/D landing joint, flush out wellhead with FW. 17.3 M/U pack-off running tool and pack-off to bottom of landing joint. Set casing hanger pack-off. Run in lock downs and inject plastic packing element. Test void to 250/3000 psi for 10 min. 17.4 Lay down landing joint and pack-off running tool. Page 32 Revision 0 April, 2015 i S GO #8 Drilling Procedure FLilrorp410.1.a, ( 18.0 Drill 6-3/4" Hole Section 18.1 Remove 7-5/8" casing rams from BOP. Install 2-7/8" x 5" VBRs in top cavity. BOP configuration should be (from top down): Annular/VBRIBIind/Mud cross/VBR. 18.2 Test BOPs on 4-1/2"test joint, 18.3 Pull test plug, run and set wear bushing. 18.4 Ensure BHA Components have been inspected previously. 18.5 Ensure to have enough 4-1/2" DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 18.6 Drift& caliper all components before M/U. Visually ve fy no debris inside components that cannot be drifted. 18.7 Ensure TF offset is measured accurately and enter correctly into the MWD software. 18.8 Confirm that the bit is dressed with a TFA of 0,6 sqin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 270 gpm. 18.9 Triple combo LWD will be run in 6-3/4"hole section: • Gamma Ray (DGR: Combined Ga nma Ray) • Resistivity (EWR: Shallow/Med/t eep) • Density (DEN: Bulk Density) ,/ • Neutron (NEU: Thermal neuron porosity) • Density Image, dip picks, tficl additional engineer for same. Page 33 Revision 0 April, 2015 I • 0 II GO#8 Drilling Procedure Ifilrol p 11a..1,;L LI 1 18.10 P/U below 6-3/4" directional drilling assy: COMPONENT DATA Item OD ID Stiff ID Gauge Weight Tip Length Total Locatio Ditscripti.ort (In) On) On) (n) (Ibpf) Connection im ft) 1 HOBS Efii165D PDC 4.500 2.250 6.750 40.65 P 3-1/2"REfie 0.80 2 5"SperryDrill Lobe 617-6.0 stg 5.000 3.120 3 120 48.00 B 3-112"IF 23.20 24.00 3 4-34" Float Sub 4.750 2.250 1.000 46.84 B 3-112"IF 2.20 26.20 4 4-14'DM Collar(Directional) , 4.750 2.610 2.638 47.00 B 3-112"IF 9.20 35.40 _ - , - 5 4-14" SP4 Collar(Garnma& Resistivity) 4.750 1.250 3 280 48.20 B 3-112"IF 24.57 59.97 6 4-14'ALD Collar(Density) 4.750 1.250 2.696 6 000 45.50 B 3-112"IF 14,35 74.32 67.31 Stabilizer 6.000 67.31 7 4-14"CTN Collar(Porosity i - 4.750 1_250 1 853 50.50 B 3-1i2"IF 11.14 85 46 - , 8 4-3/4'TM Collar(Telemetry) . 4.750 2.812 3.039 /_ 46.10 B 3-112"IF 11.00 96.46 9 4-3i4' Non Mag Flex Collar 4.750 2.250 / 46.84 B 3-112"IF 30.00 126.46 10 4-14*Non Mag Flex Collar 4.750 2.250 46.84 B 3-112"IF 30.00 156.46 11 3.5*IF P x 4.5"CDS 40 B 5.300 2.250 2 250 61 64 B 4.5'4 1 f2i12.50 158.96 CDS 40 12 2 x jts 4.5"HWDP 4.500 2.750 41,00 60.00 218.96 13 4.5"CDS 40 P x 3.5" IFS 5.300 2.200 2 250 62.23 B 3-112"IF 2.50 221.46 14 4.75"Weatherford Jar 4.800 , B 4.54 112"2.250 2.250 48.12 B 3-112"IF 30.00 251.46 " 15 3.5"IF P x 4.5" CDS 40 8 5.250 2.250 2.250 60.22 2.50 253.96 CDS 40 , 16 17 x its 4.5'HWDP 4.500 2/50 41.00 510.00 763.96 / ,z14:100; 763.96 Page 34 Revision 0 April, 2015 • • GO #8 Drilling Procedure Wirral)Alnyka.1,11: 18.11 Primary bit will be the Security EM65D: 6-3/4" (171mm) EM65D '' , PRODUCE SPECIFICATIONS ,' ' Cutter Type X3-Extreme Dt Ming IA DC Cole M323 arailk, . Body Type MATRIX Total Cutter(Mint i„„' 'i,..= Cutter Distribution 1iik Eace 11" 111111 ,,,-:ii,,,,.. Illik..,-.'i,„,,, ,..L.,'''' 4 13 Cane II 0 Up Drill S 0 / Number of Large NO721CS il Number of Medium Nozzles 0 Number a Small Nozzles ..,,, Numbo . ..... orm „ 0 Number of Porm(Sine) ft Number of Replaceable Ports(SiP.'ze) ft Junk Slut Area f sq in) - - Normalized Face Volume 34.69% API Connection 3-Ib2 REG.PIN / Reeattiritended Make-Up Tu t 5,173—7,665 Et*Itss. Nominal Dimensions** , , Make-Up Face to Nose 9.42 m-239 mm / Gauge Length 2 In Sleeve Length Pin-(I Shank Diametet 4_5 int-I,It rent Break Out Plate(MaLOVUegitcY0 D11953;, 110 Approximate Shipping Weight %Lbs.- I Kg. SPECIAL FEATURES lip-Drill Cutters on Gage Pads,1/16"SteppoM Gage,Optimi Row-"D"Feature Material#761302 'Bit inert&arca ended rrisky-up torque is a Pandit of A bit E.Q.and,14'1,141 bit alb art.bitilircyl as sprvilkid in API IIPTG Scalia!'A.S2. "Dcsagn dimeriaain .iioniinil and nray an%lightly . ntancrayiured priadam.Ilalliharban Drill flirt and Sarvier,v models arc rani/annual*rovvircd.ancil refirral Product v.pccirioillaca may ottotitix without umww, 2013 Halliburlon,AU rights reserved Sates o Ilalliburton products and services will be in accord solely with the terms and conditions contaiiwd in the contract between Halliburto and the customer that is applicable to the 5010. www.halliburton corn Page 35 Revision 0 April, 2015 I • • GO #8 Drilling Procedure U korp Ala.la,Ltd; 18.12 TIH to TOC. Shallow test MWD on trip in. Note depth TOC tagged at on AM report. 18.13 Conduct casing test to 3500 psi / 30 min. 18.14 Drill out shoe track and additional 20' new formation. CBU and prep for FIT. 18.15 Conduct FIT to 12.5 ppg EMW. 18.16 9-7/8" hole section mud program summary: Weighting material to be used for the hole section will be bari . Additional barite will be on location to weight up the active system (1) ppg above highest/anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.2 ppg 6%KC1/EZ MUD/BDF-499 fresh water based drilling fluid. Properties: MD Mud Viscosity Yield yield Point pH HPHT Weight scosity - 8.5-9.5 < 10.0 10 500 9.5 — 10 5 40 53 15-25 15-25 13,100' System Formulation: 6% KCL/1Z MUD/BDF-499 Product / Concentration Water 0.905 bbl KCI 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) BDF-499 4 ppb EZ MUD DP 0.75 ppb DEXTRID LT 1-2 ppb PAC-L I ppb BARACA' : 5/25/50 15-20 ppb(5 ppb of each) BAROID 1 as required for a 9.2—9.6 ppg ALDAC G 0.1 ppb BARA'OR 700 1 ppb BA' •SCAV D 0.5 ppb (maintain per dilution rate) Page 36 Revision 0 April, 2015 • GO#8 Drilling Procedure Alarm AIa..ka,LLL: 18.17 Drill 6-3/4" hole to 13,100' MD/ 8,690' TVD MD using above motor assembly. ,,a'� • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. / • Utilize Inlet experience to drill through coal seams efficiently. Coal seam to will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. rk through coal seams once drilled. • Keep swab and surge pressures low when tripping. • See attached mud program for hole cleaning and LCM strategies. f'' • Ensure solids control equipment functioning properly and utilizyd to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. • Ensure mud engineer set up to perform HTHP fluid loss./ • Maintain HTHP fluid loss <6. • Take MWD surveys every stand drilled. • Mud Loggers: 30 ft samples with 20' samples in z nes of interest, two sets of cuttings, chromatograph,pixler plots. 18.18 Hilcorp Geologists will follow LWD log closet to determine exact TD. 18.19 At TD; pump sweeps, CBU, and pull a wipq'r trip back to the 7-5/8" shoe. 18.20 TOH with drilling assy, handle BHA as,appropriate. Drop drift on trip out. Page 37 Revision 0 April, 2015 • • GO#8 Drilling Procedure FTilrvirp Alaska,1,1,( 19.0 Run 4-1/2" Production Liner 19.1 M/U and rack cement stand in derrick. • Ensure to drift components prior to M/U. Ensure dart will pass through ctn'ponents. • Confirm largest OD of packer assy will pass through wear bushing./ 19.2 R/U Weatherford 4-1/2" casing running equipment. • Ensure 4-1/2"DWC/C HT x CDS 40 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor & model info. 19.3 P/U shoe joint, visually verify no debris inside joint. 19.4 Continue M/U & thread locking shoe track assy consisting of: • (1) Shoe joint w/ shoe bucked on &threadlocked (coupling also thread locked). • (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). • (1) Joint with landing collar bucked on. • Solid body centralizers will be pre-installed on shoe joint& FC joint. • Install a solid body centralizer on landing collar joint. Leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe. 19.5 Continue running 4-1/2" prod liner • Fill casing while running/using fill up line on rig floor. • Use "API Modified"thvead compound. Dope pin end only w/paint brush. • Install solid body centralizers on every joint to 10,500' MD. Leave the centralizers free floating. ' • Utilize a collar clamp until weight is sufficient to keep slips set properly. 4-1/2" DWC/C HT M/U t rques Casing OD Minimum Maximum Yield Torque 4-1/2" 5,800 ft-lbs 6,500 ft-lbs 7,200 ft-lbs Page 38 Revision 0 April, 2015 �� •_� GO #8 DdU|ngProcedure xo"=,m"okk° /�c I Technical Specifications , Connection Type: Size(O.D.): Weight(Wall): Grade: 0WC/CTubimg 4-1/2 in 12.SQlb/ft(J.271 in) L-80 standard Material �— ^� — L-80 Grade Gmde 80.000 Minimum Yield Strength (psi) , USA 95,000 Minimum Ultimate Strength (psi) v*MuoA 4424vvSam Houston Pkwy.Suite 150 Pipe Dimensions Houston,rxnow1 Phone:713-479-3200 4.500 Nominal Pipe Body Oft (in) Fax:713-479-323* 3.058 Noni inal Pipe Body ID.(in) E-mail:v^MuaAoawa�vm-um:.uom 0.271 Nominal Wall Thickness (in) 1 12.60 Nominal Weight(lbsfft) 12.25 Plain End Weight(Ibsift) ee 3.600 Nominal Pipe Body Area (sq im) we eve Pipe Body Performance Properties 288,000 Minimum Pipe Body Yield Strength (Ibs) 7.508 Minimum Collapse Pressure (psi) 0.430 Minimum Internal Yield Pressure(psi) 7.700 Hydrostatic Test Pressure (psi) Connection Dimensions 5.000 Connection().D. (in) 3`958 Connection iD. (im) 3_833 Connection Drift Diameter (in) 3.94 Make-up Loss(in) 3.800 Critical A 100.8 Joint Effi Connec±imn/PwrhormanceProperties 288.000 Joint Strength (Ibs) 14,200 Reference String Length (ft) 1.6 Design Factor 314.000 API Joint Strength (lbs) 288^000 Compression Rating (Ibs) 7.500 API Collapse Pressure Rating (psi)Internal 8,438 API Pressure Resistance(psi) 81.5 Maximum Uniaxial Bd Rating [dogn*ee/1O0fO wVa|ume ~� • • GO #8 Drilling Procedure nileorp AIa.kx IIA 19.7 Ensure to run enough liner to provide for approx 200' overlap inside 7-5/8" casing. Ensure hanger/pkr will not be set in a 7-5/8" connection. 19.8 Before picking up Baker ZXP liner hanger/packer assy, count the # of j ints on the pipe deck to make sure it coincides with the pipe tally. 19.9 M/U Baker ZXP liner top packer. Fill liner tieback sleeve with" al mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff.Wait 30 min for mixture to set up. 19.10 RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 19.11 RIH w/liner on DP no faster than 1-1/2 min/ stands'Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 19.12 M/U top drive and fill pipe while lowering/sing every 10 stands. 19.13 Slow in and out of slips. 19.14 Circulate 1-1/2 drill pipe and liner volume at 7-5/8" shoe prior to going into open hole. Stage pumps up slowly and monitor for}fosses. Do not exceed 60% of the nominal liner hanger setting pressure. Nominal liner hanger Vetting pressure is 2500 psi. 60% of this value is 1500 psi J, 19.15 Obtain up and down weights f the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 19.16 Continue to fill the DP ery stand down using fill up line on rig floor. Do not stop to fill casing. 19.17 P/U the cmt stand a4tag bottom with the liner shoe. P/U 2' off bottom. Note slack-off and pick-up weights. lord rotating torque values at 10, 20, & 30 rpm. 19.18 Stage pump rate/up slowly to circulating rate without exceeding 60% of the liner hanger setting pressu/e (1500 psi). Circ and condition mud with the liner on bottom. Reduce the low end rheologyrbf the drilling fluid by adding water and thinners. 19.19 Reciproca t& rotate string if hole conditions allow. Circ until hole and mud is in good conditio for cementing. Page 40 Revision 0 April, 2015 • GO #8 Drilling Procedure Harm.p 11.1,4,8,i,i,A: 20.0 Cement 4-1/2" Production Liner 20.1 Hold a pre job safety meeting over the upcoming cmt operations. Make oom in pits for volume gained during cement job. Ensure adequate cement displacement vo e available as well. • How to handle cmt returns at surface, regardless of how unli y it is that this should occur. • Which pump will be utilized for displacement, and how fl 'd will be fed to displacement pump. • Positions and expectations of personnel involved wit the cmt operation. • Document efficiency of all possible displacement/pumps prior to cement job. i 20.2 Attempt to rotate & reciprocate the liner duringc operations. This is the most effective method to ensure effective mud and wall cake r noval and a good quality cmt bond. i 20.3 Pump 5 bbls 10 ppg MUDPUSH II spacer. 20.4 Test surface cmt lines to 4500 psi. 20.5 Pump remaining 15 bbls 12 ppg MU PUSH II spacer. 20.6 Mix and pump 15.3 ppg class "G' cmt per below recipe. Ensure cmt is pumped at designed weight. Job is designed to pump 50% OH excess. Section: / Calculation: Vol(BBLS) Vol (ft3) 7-5/8" x 4-1/2 DP" 200' x 0.026 = 5.2 29 Overlap: 7-5/8" x 4-1/2" Liner 200' x 0.026 = 5.2 29 Overlap: 6-3/4" OH x 4-1/2" Liner: (13,100— 10,500') x 0.025 x 1.5 = 98 550 Shoe Trac,: 90' x0.019 = 1.7 9.5 Total Volu - e: 110 bbls 618 ft3 Page 41 Revision 0 April, 2015 i GO#8 Drilling Procedure me.p Ala ,a,11,(. Tail Slurry System Easy BLOK Density 15.3 lb/gal Yield 1.34 ft3/sk Mix Fluid 5.879 gal/sk Base Fluid 5.879 gal/sk Expected Thickening 70 Bc at 5:00 hrs Code Description Concentration G Cement 94 lb/sk D046 Antifoarn 0.2%BWOC D202 Dispersant 1.5% BWOC Additives r D400 Gas Control 0.8% BWOC D154 Extender 8.0% BWOC 20.7 Drop DP dart and displace wh 9.2 ppg drilling fluid. 20.8 Reduce pump rate to 3 bpn prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point. 20.9 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns &pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 20.10 Bump the plug tnd pressure up as required by Baker procedure to set the liner hanger(20% above nominal/setting pressure. 2500 psi is nominal setting pressure. Pressure up to 3000 psi to confirm hanger setting. 20.11 Slack off t al liner weight plus 20k to confirm hanger set. 20.12 Do not o erdisplace by more than '/2 shoe track. Shoe track volume is 1.7 bbls. 20.13 Pressu e up to 4200 psi to release the running tool (HRD-E) from the liner. 20.14 Bleed pressure to zero to check float equipment. Page 42 Revision 0 April, 2015 0 M GO #8 Drilling Procedure Hilrorp a ka.LLC 20.15 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve. 20.16 Rotate slowly and slack off 50k downhole to set the ZXPN liner to. sacker. 20.17 P/U to P/U weight plus 1 ft. 20.18 Close annular and test 4-1/2" DP x 7-5/8" annulus to 1 10 psi / 10 min to test liner top packer. 20.19 Bleed off pressure, open up annular. 20.20 Pressure up to 500 psi down DP and pick up, o remove the RS packoff bushing from the RS nipple. Bump up pressure as req'd to maintain 500 psi DP pressure while moving pipe until the pressure drops off rapidly, indicating paeI -off is above the sealing area(ensure that 500 psi will be enough to overcome hydrostatic di%erential at liner top). J 20.21 Immediately with the loss of presire and before DP reaches zero, initiate circulation while picking up to position the botton'i of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until thyi sleeve area is thoroughly cleaned. /// 20.22 Pick up to the high-rate ci `ulation point above the tieback extension, mark the pipe for reciprocation, do not rethe liner top, and circulate the well clean. 20.23 Watch for cement rens and record the estimated volume. Rotate & circulate to clear cmt from DP. / 20.24 POOH, verify tle liner top packer received the required setting force by inspecting the rotating dog sub. / Backup release frin liner hanger: 20.25 If the HR$-E tool still does not release hydraulically, left-hand (counterclockwise)torque will have to e applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and en ure that the tool is in the neutral position. Apply left-hand torque as required to shear screw . 20.26 N E: Some hole conditions may require movement of the drillpipe to "work"the torque down to he setting tool. 20.27 /After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Page 43 Revision 0 April, 2015 GO #8 Drilling Procedure El'Ivor!,Alaska,I.GC Ensure to report the following on wellez: • Pre flush type,volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing,bpm,note any shutdown during mixing o•erations with a duration • Pump rate while displacing,note whether displacement by pu . truck or mud pumps,weight&type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displaceme, volume,whether plug bumped&bump pressure, do floats hold • Percent mud returns during job, if intermittent not;timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface volume • Note time cement in place • Note calculated top of cement • Add any comments which would descr +e the success or problems during the cement job Send final "As-Run" casing tally & casing nd cement report to mmyers@hilcorp.com. This will be included with the EOW documentation th• goes to the AOGCC. Page 44 Revision 0 April, 2015 re0 HGO #8 Drilling Procedure I{ileorp.4la.ka,II,f:; 21.0 Wellbore Clean Up & Displacement 21.1 M/U casing clean out assy complete with casing scraper assys for each size casi in the hole. • 3.75" bit or mill. /,, • Casing scraper for 4-1/2" 12.6# casing. / , • +/- 2800' 2-7/8" workstring. .`, • Crossover (No PBR Polish Mills). • Casing scraper for 7-5/8" 29.7# casing. • 4-1/2" DP to surface. 21.2 TIH & clean out well to landing collar (+/- 12,980' MD). • Circulate as needed on trip in if string begins to takyi weight. • Circulate hi-vis sweeps as necessary to carry debout of wellbore. • Ensure 3-3/4" bit is worked down to the landing/collar. • Space out the cleanout BHA so that the 4" biyieaches the 5"landing collar when crossover is +/- 30' above the 5" liner top. • The primary objective of the clean out run,is to ensure the TCP assy will reach intended depth. 21.3 After wellbore has been cleaned out safactorily using mud, test casing to 3500 psi/ 30 min. r 21.4 Displace drilling fluid in wellbore with a hi-vis pill followed by fresh water. • Consider catching drilling fluicl`in rain-for-rent tanks for use on a future well if feasible. • Circulate fresh water into wellbore until clean-up is satisfactory. Do not recirculate fluid, • After a couple circulations1sing FW, short trip the assy to bring the upper 7-5/8" scraper to surface. , s • RIH again &tag landin collar w/4" bit. Continue circulation as necessary until fluid cleans up. Make another sho trip if necessary. • Pump a chemical tram followed by 6% filtered KC1 (or alternative fluid specified by Ops team). ! 3 21.5 TOH w/clean out a0y. LDDP on the trip out. Note any abnormal wear on the clean out assy. , 22.0 Production/Tubing Installation and Perf. 23.1 A separate S ndry will be submitted to the AOGCC that will cover the post well logging program/ oduction tubing installation/perforation procedure. Page 45 Revision 0 April, 2015 • GO #8 Drilling Procedure I1de rti Ala4a,1.1,C 23.0 BOP Schematic 129 fII Ifl s! 151 T3-Energy Saxon Rig 147 11"5M T-3 Energy BOP Ist 1!1 U I II I1t1 13-Energy Modet 60111 • Mir 11%5000 Menai Manual al.iai it-.l,Er fR Valve Valve Valve Iil tit tat tit Kill FA' /'yy�' 5 1 4h.kr Line wf wl ' M+! i L �l■■l .440- ''lei ISI I1I1llilc.. rr` 13-nes9y Model 60111 - Grade Lev 131 1 1 o311!1 141 Sp. r spoof 1.95' 11561X115M Iii. it! 1!1I In 141 U �.- > bexard-NtBs sy i � i' '� ; tacr 16'Y,361 X 11 5181 - limmi_ j'I; IaI 11' s la.1. Molorisi =1soh [Il I I - 1 11. - L..'' 5„ Page 46 Revision 0 April, 2015 00 GO #8 Drilling Procedure rHiIvor!.Alaska.!It 24.0 Wellhead Schematic 5_1„s I 4'> - 11 9441X '5-1/6 MO 110 EST ...,_ 3 7 a 1 4.4 311 I .... . 0. .0 11 SW EASING MANGER, -Ii b Fj i-” EM/3-22 PORTED 11 K 5-1,/2 17! vp.W D r/C Ill i rYr-� 2-IPE WA CSG Kix 1274.1 X 6.076-4 0 ■ I a 17.7 ACNE-20-LN f T IP' E5r w t/IART SEAL i • , - @ - i 1.. • a ; s .... iii I f 4 „ ► 1I ------ CASING NAMUR, 945-22 11111 .11 11 k 7-5/8-^'— r 737 rYi L L A i�t4Jtf3tr - 3- /11' \ l� '-i , Tt EST 26,3 I _ lite. '�E+��'i ! 1S-3/4 1114.: 1PS 'a1 am2-1/1iM 1.1' --- a ■, 1 D 16-3/4 MS . -ii eii ! .= - Ia1111 I.1, GASLNC MANGER,X 10--2'7 21.6 W IwJ tv 5E44 -- 41 8574 bhyy� 2 1116 F 16 CASING 19-3/4 CA5NG 2-6/6 CAS4 r 2-7/8”Prod Tubing — — ,, ■ 04181 0445 12.000 11,41 V1E1124E60 AMOY •t' 16 z 10-3/4 X 7-5/8 X 5-1/2 ' -.S SKIM Ott 1145 84.416/42.MHE 6442 A4rD CAN WRY 9OVCANILY RISTRICTED CONFIDENTIAL DOCUMENT 14.1<, 011 RAM MATERIAL.SEHHU?R5i. Ito 1;W4 lU3 or STA t4UJ I Is 1» ..*4 �," � r.` ".� t-.s. ,or LMIDAS MS SHORN SKALD EE lY1 SE:EWE q,.�wa.c w+.�■tx` tea "'k' LAI' `0.0.,‘t6. / r Rti 4t'ELkf P+APOS'ES 014.f. g '`�5"Ir. t�'I;u i,-...E..a7'4°'.. w" `44,1144 F',,,,,,,,20339 Page 47 Revision 0 April, 2015 GO #8 Drilling Procedure 25.0 Days Vs Depth Days Vs Depth 0 - -..\- --v\ 2000 —GO#8. -----SRU Z ,.�—,„°Frats#1 usan Dionne#3/Z77' r \Ili ir 2i \ ,. t i 'a 7 an m amoo 1 \--\\* , 10000 12000 1 , 0 10 20 30 40 50 60 70 80 Days Page 48 Revision 0 April, 2015 • GO#8 Drilling Procedure naroi h 4l��ka,I,r.r: 26.0 Formation Tops GEOLOGICAL PROGN WELL NAME: GO8 FIELD: Ninilchik Unit,GO Unit SURFACE X= 229313 STATE Alaska Y= 2255349 BORWHOLE X= 225:;86.4 TVD REF DATUM KB Y= 22U0614.5 TVD REF ELEV 187 COORD REF SYSTEM NAD27 GROUND ELEV PROPOSED TD:= 12067 MD Objective.* Drill a 12067'MD Tyonek and Beluga gas development well. Geo Summary/ Justification: Subsurface data indicates the northeast quarter of section 15 is an untapped and in a crestal postion for Lower Beluga and Tyonek gas development. ANTICIPATEDFORMATION TOPS&GEOHAZARDS �� EXPECTED Intersection Points TOP TOP NAME FLUID MD(F7) TVD(F7) TVDSS(F7) Est.Pressure X Y +/- Beluga 50 Pos Gas 3898 2,108 • -1,921 906 Tyonek GAS 7465 3,586 • -3,399 1542 225476 2260126 100' r r T6 Tight Gas 7958 3,993 -3,806 1717 ✓ r T20 Tight Gas 9112 5,103 . -4,916 2194 ✓ r T60 GAS 10112 6,103 -5,916 2624 ✓ r T65 GAS 10273 6,263 6,076 2693 r T90 GAS 10712 6,702 -6,515 2882 ✓ ° r 225086.4 r 2260614.5 200 Total Depth 12067 � 8,690 -8,503 3737 =Primary TARGET RADIUS 100 FT DATA COLLECTION REQUIREMENTS: Mud Logging: Surface casing to total depth 30 ft samples with 20'samples in zones of interest,two sets of cuttings,chromatograph,show reports,puder plots. LWD Data *LWD GR/Res for correlation and drilling E-Line Log Data: Thru bit Quad Combo through production hole COMPLETION TYPE Monobore7 ANTICIPATED ED RATES 3 MMCF D ARTIFICIAL LIFT EQUIPMENT OD TUBING SIZE Page 49 Revision 0 April, 2015 • GO #8 Drilling Procedure nihvn I)Al ask a.I,I,C 27.0 Anticipated Drilling Hazards 13-1/2" Hole Section: Lost Circulation: Ensure adequate amounts of LCM are available. Safe-carb 10, 20, 40, 250, & 750. Ensure G-seal, Pecan nut plug, and Mix II are also available for more severe lost returns incidents. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of Safe-carb 10 & 20 to the active system at 1 —2 ppb. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP btwn 25 —45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of—50 - —60 lbs/100ft2 to combat this issue. Maintain low flow rates for the intial 200' of drilling to reduce the likelihood of washing out the conductor shoe. To help insure good cement to surface after running the casing, condition the mud to a YP of 25 —30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco F, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this ole section. No abnormal pressures/Or temperatures are present in this hole section. 9-7/8" Hole Sect'on: Lost Circulation: Ensure adequate mounts of LCM are available. Safe-carb 10, 20, 40, 250, & 750. Ensure G-seal, Pecan nut plug and Mix II are also available for more severe lost returns incidents. Monitor fluid volumes to d ect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of afe-carb 10 & 20 to the active system at 1 —2 ppb. Hole C1 aning: Mainta'n rheology w/flowzan. Sweep hole w/20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP btwn 20 - 30 to optimize hole cleaning and control ECD. Page 50 Revision 0 April, 2015 • • GO #8 Drilling Procedure Ilileorp AiaNkn,LLC Wellbore stability: Maintain 1ppb total of PolyPac Supreme UL to maintain a thin/strong wall cake an. eep HTHP filtrate below 9 ml/30 min. Maintain MW as necessary using additions of Barite. Maint. n 6 ppb EMI-2009 for shale/clay inhibition. Maintain 4 ppb Asphasol Supreme & 3 ppb Sack Bl.' for Shale/Coal stabilizer. Maintain 6%KC1 in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience dri ng coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized •: a key component for success. • Keep the drill pipe in tension to prevent a whippin. -ffect which can disturb coal sections. • Use asphalt-type additives to further stabilize co. seams (Asphasol Supreme, Sack Black). • Increase fluid density as required to control a nning coal". • Emphasize good hole cleaning through hydra lies, ROP and system rheology. In the event that sloughing coal is encountered, c 2 nsider spotting a 30 ppb Asphasol Supreme pill across the coal seam. The pill can be safely "squ,ezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure oss. H2S: � H2S is not present in this hole section. No abnormal pressures or temperatures .re present in this hole section. 6-3/4" Hole Section: Lost Circulation: Ensure adequate amounts of LC►i are available. Safe-carb 10, 20, 40, 250, & 750. Ensure G-seal, Pecan nut plug, and Mix II are .lso available for more severe lost returns incidents. Monitor fluid volumes to detect any early s'.ns of lost circulation. For minor seepage losses, consider adding small amounts of Safe-carb 10 & 0 to the active system at 1 —2 ppb. Hole Cleaning: Maintain rheology w/ .wzan. Sweep hole w/20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintai density and minimize sand content. Maintain YP btwn 20 - 30 to optimize hole cleaning and control CD. Wellbore stabili•;: Maintain 1ppb t.tal of PolyPac Supreme UL to maintain a thin/strong wall cake and keep HTHP filtrate below 6 ml/30 , in. Maintain MW as necessary using additions of Barite. Maintain 6 ppb EMI-2009 for shale/clay inhibition. Maintain 6%KC1 in system for shale inhibition. Page 51 Revision 0 April, 2015 • • GO #8 Drilling Procedure Fiilroi :tI J C Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which ca •isturb coal sections. • Do not use "black products"to stabilize coal sections. / • Increase fluid density as required to control a"running coal". • Emphasize good hole cleaning through hydraulics, ROP an. system rheology. H2S: � H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 52 Revision 0 April, 2015 • • GO #8 Drilling Procedure HiIcor!)Alaska,Lr;C 28.0 Saxon Rig 169 Layout � � s = a ., a' ii • :Y Lail N!i I gg i 9 e l P 1 MIIIIIIIIIB i q �; ,_ ..,.:,I- 1 i•-,a 711-174r, • , " : � . _ a 9 It- ' piing* eltliali u _ ligni ■1 rE111 A 1 rel, (.;. �r� 1114 li'l li Y li �In '1�!! E ::■: iI , IIr11 .!MIMI DB li A �IGI® �—. •111_ .]I IH -.1 i.' 1 II a III! 'I�LralTar� �� '-'t.4.1 -ritzi-.45 Ilie -"::'—'1-11 ,. rill , G, i r rye . S i P 2 -1 o v I t 1 ,1,.111,1; ills 11111,1 r i„„„„.4 — — 11.��.. j��11111i111t 11111�11i1111111111111 Ell 'ill I ;! I. ! VIII, !,1 I r C III l li Ili 1l lli ili 1 •— MN 1IIIIIIII1�I 'IIIIPII1111 IJII111111 III .........,.. I� l (r 0 �l I i I I • ''''. I . r a 1. t 11 11111_ ; Page 53 Revision 0 April, 2015 • GO #8 Drilling Procedure 11 ieo p t!n kxi,I,LC 29.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does no nclude rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throug ut the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown,plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure j,s achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute irxtervals. 7. Bleed the pressure off and record the fluid volun e recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures ate required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. ' Page 54 Revision 0 April, 2015 I • GO #8 Drilling Procedure I tarot iv t In.la,111: 30.0 Choke Manifold Schematic 7 le71C, /47 : ,I" „,'.7.. ./7.- 4,,,,,,,,- .,4 2. 97-24 4342 4342 / "1 el 0111111V"""43' .7 a ;Or ,0 i;ii• ,-0...A. 14.43 1462 _jpat ., 14.42 la 43- ' 0.19 0.19 14 Iii, -0 79 67/i - ;Rill 461Prit 81111014 43D ' a,a.MIMI lii iii tai (4,011.111111 ma oh ...N.- 0 , A . 1.,, __ c .3 , vil - 4 tiksipt 2 2 I rp- 'WV, - —,lboi--- - 41/4 -I t AtilrftNi3i;40i ". i I t 04,-'22*4t11401! tik..„..* 1 I, i "'takt, g Do glitmoi,1* , i s. a I, *tittikiso I cP1 A - 1 , i 2 1 _9 i -1111 9 i I t Mn MP OP MP (3-5 C.' '119 I eh UV Olt i 11111144 * 7 84 7 84 773) ...' 70 C)-- i 2.24 1•1 IMAM till MN MIMI 11* • 7" 111111111.1 111111111 MIMI 11111111 I 1 111111111111.11 111111111111111. I ' *ft D I F.,71.0i,f0.0, 111111111” 11111111111111.1814 XIIII4C g 38 03SIR 1,0•19 • V.e4 7 - V!' .4 '' P-, INT4 , _ 1411,k. ".• ttf 74.6.1 r'19 ...2,..aira 6-6, 4...-41(1 mom 711114Imit- OA 9• .1111110111.11 0,,,j l CP '7841171111X i 10 50 hi'- AEI , 41,N, 10.5D ,Z. III i 2 MI V 411104k 911 ., irlii in gr 11A; 111•1141 a e ' 1.,,i, :1 r.: 4.4'40, ll 0 ' • .,,, AirWil r,a-weviNAI:Mit I t 4kW.' .-1.1It addr4,46411 ih" 11.4.11,„VN4 I Aut 12.... .„..v. t t lir .,. ItaiNmil - No Iiitw•io ,.., . 7„„_ :: ,Ert AnsiSMIli gm. U , - I 1 1 iota lanai -0,I5 \c) VIP .... 1 10 \-:/4470CHr 279 019 - 0 i 0 .. -,...0.10 OPERAION '4.4.831-4-1 4 44....... 14.6.2 1+1,62 14624444.—831 t. ., 43_62 4162 i6 tve..„-=, 87.24 FF4 1CAD ler: =wit or 107474;t8.76.01•ArIO10111114 Z..=1111('''' talge. C .Kt I.LAYOUT 76TH It 03.5C275 I.S.. 2L.L.....=.'.... L.WA.211,11001,;" 1"::._ • ...._' ' ''' ' '') "....,"." reir.VrT ''.1- ''lijj 0 ke irc. r.va 0 .r— rum 7 Ape OA MI 11.4 .., ........ ... ..... 117.1,27112 .44 ........_ Page 55 Revision 0 April, 2015 • GO#8 Drilling Procedure Hilivwh Alaska,Lt!' 31.0 Casing Design Information Calculation & Casing Design Factors Ninilchik Unit DATE:4-29-2015 WELL:Grassim Oskolkoff#8 FIELD: Ninilchik DESIGN BY: Monty Myers Design Criteria: Hole Size 9-7/8" Mud Density: '(.d.0 ppg Hole Size 6-3/4" Mud Density: 10.0 ppg Hole Size Mud Density: Drilling Mode MASP(sec 2): 2,064 psi(see attached MASP determinati*& calculation) MASP(sec 3): 2,866 psi (see attached MASP determin ion&calculation) Production Mode MASP: 2,866 psi(see attached MASP dermination& calculation) Collapse Calculation: Section Calculation 1, 2, 3 Normal gradient external stress (0.4941;si/ft)and the casing evacuated for the internal stress Casing Section Calculation/Specificati..._... ................__.....................__..._._............_............._...1 ?.._..............._.................._3............._.._.. ................................... Casing OD 10-3/4" 7-5/8" 4-1/2" Top(MD) 0 0 7,300 Top(1VD) 0 0 3,950 Bottom (MD) 3,500 10,500 11,915 Bottom (TVD 2,023 6,125 8,283 Length 3,500 10,500 4,615 Weight( f) 45.5 29.7 12.6 Gra L-80 L-80 L-80 Conn: tion BTC BTC DWC/C HT Weight w/o Bou;"ancy Factor(lbs) 159,250 311,850 58,149 Tension at T.. of Section (lbs) 159,250 311,850 58,149 Min strengt ension (1000 lbs) 1040 683 288 Worst Case -afety Factor(Tension) 6.53 2.19 4.95 Collapse Pr-ssure at bottom (Psi) 1,052 3,185 4,307 Collapse Re.istance w/o tension(Psi) 2,470 4,790 7,500 Worst Ca Safety Factor(Collapse) 2.35 1.50 1.74 MASP (psi) 1,316 2,733 2,733 __._____......_.__...__..._...___......._.._......_____.._._._._........._. �__.__._.____._......_._..__..............._.._..._._....__...._.....__._...____ Minimum Yield(psi) 5,210 6,890 8,430 Worst case safety factor(Burst) 3.96 2.52 3.08 Page 56 Revision 0 April, 2015 • • GO #8 Drilling Procedure tri„orp 32.0 9-7/8” Hole Section MASP Maximum Anticipated Surface Pressure Calculation Hilcorp 9-7/8" Hole Section ° Grassim Oskolkoff#8 Ninilchik Unit MD TVD Planned Top: 3500 1891 Planned TD: 10500 6253 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Upper Beluga 2,108 906 Gas 8.3 0.430 Offset Well Mud Densities Well MW range Top(MD) Bottom (MD) Date Falls Creek 1 10.5-13.1 2,500 11,000 1960 Corea Creek 1 9.4- 10.4 2,500 6,664 1996 Falls Creek 1 RD 8.7-9.3 3,000 8,332 2001 Falls Creek#5 9.2-9.7 1,758 9,715 2014 Frances#1 9.3-9.8 2,638 10,703 2014 Falls Creek#6 9.0-9.4 2,424 9,060 2014 Assumptions: 1. Fracture gradient at 2,500' MD/1,574'TVD is estimated at 0.936 psi/ft based on field test data. 2. Maximum planned mud density for the 9-7/8" hole section is 9.6 ppg. 3. Calculations assume "Unknown" reservoir contains 100%gas(worst case). Fracture Pressure at 10-3/4" shoe considering a full column of gas from shoe to surface: 1891(ft)x 0.936(psi/ft)= 1770 psi 1770(psi)- [0.1(psi/ft)*2108(ft)]= 1560 psi MASP from pore pressure(unknown gas sand at TD,at 8.3 ppg) 6253(ft) x 0.43(psi/ft)= 2689 psi 2689(psi)- [0.1(psi/ft)*6253(ft)]= 2064 psi Summary: 1. MASP while drilling 9-7/8" intermediate hole is governed by fracture gradient at the 10-3/4" casing shoe Page 57 Revision 0 April, 2015 • • GO #8 Drilling Procedure Hilcor')Ala k".Id,C 33.0 6-3/4" Hole Section MASP Maximum Anticipated Surface Pressure Calculation Hilcorp 6-3/4" Hole Section Grassim Oskolkoff#8 Cook Inlet,Alaska MD TVD Planned Top: 10500 6253 Planned TD: 12952 8686 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad LowerTyonekTarget 6,702 2882 Oil/Gas/Wet 8.3 0.430 Offset Well Mud Densities Well MW range Top(MD)/"Bottom(MD) Date Falls Creek 1 12.2- 12.3 11,000 13,500 1960 Corea Creek 1 9.4- 10.4 2,500 6,664 1996 Falls Creek 1 RD 8.7-9.3 3,000 8,332 2001 Falls Creek#5 9.2-9.7 1,758 9,715 2014 Frances#1 9.5-9.7 10,700 12,814 2014 Falls Creek#6 9.0-9.4 2,424 9,060 2014 Assumptions: 1. Fracture gradient at 10,500'MD/6,253'TVD' estimated at 0.936 psi/ft based on field test data. 2. Maximum planned mud density for the 9- /8" hole section is 9.6 ppg. 3. Calculations assume "Unknown" reservoir contains 100%gas(worst case). Fracture Pressure at 7-5/8"shoe considering a full column of gas from shoe to surface: 6,253(ft)x 0.936(psi/ft)= 5852 psi 5,852(psi)- [0.1(psi/ft)*6,253(ft)]= 5226 psi MASP MASP from pore pressure(entire wellbore evacuated to gas from TD) 8,686(ft)x 0.43(psi/ft)= 3,735 psi 3,735(psi) - [0.1(psi/ft)*8,686(ft)]= 2,866 psi Summary: 1. MASP while drilling 6-3/4" production hole is governed by SIBHP minus gas gradient(0.1 psi/ft)to surface after entire wellbore is evacuated to gas. Page 58 Revision 0 April, 2015 • • GO #8 Drilling Procedure nilrot p 4la.1:a,LL(: 34.0 Spider Plot (NAD 27) (Governmental Sections) 0 t 47 .�f �.$ Legend • GO 8 SNL X GO 8 TPH -'}- GO 8 BNL • Otter Surface 14ole Location • Otter B,cttom Hale Location ./ ———Wetl P hs >(JO �3 E�C_GO 8 ":.j Ort and Gas Una Boundary L 384306 ADL 389737 to N % GO 5 BHL 0 . GO 1 BHI l.4 ,t Cd• 0 } t a e,OaRNa /100rt�� • t •i 1 D b GO 6 SRL N. Y � •,..., o 6 `` ' NINILefilkJNI '-< ` b ,Y 6yS001NO3W_, ti _ Y . ti • ~ ._. FA CFI.REK 2 BHL , Y o 5t e t �NINICHIK T(TX)BH `',�,, e Y�YY �� `. W, .4 Y Y AKA 024399 4 n `i ,. +. til 4f} GO2BHL Cit) til[1.! _ti L 389180 ADL 384305 '" i \ r� AKA 024399 i a- t 4 -J`4/ w r -_..--- Private "- / //,<A\ i , 1 CIRI fit 13 1.600 3.000 Ninilchik Unit Feet llIc.rp.hla4 GO 8 Alaska State Plane Zone 4.NAD27 Map Date 5/1F2015 Page 59 Revision 0 April, 2015 • 0 II GO#8 Drilling Procedure Ili!coy Ala4a,11A: 35.0 Surface Plat (As Staked) (NAD 27) / / KENAI PENINSULA BOROUGH / GO NO.8 WELL AS-STAKED LOCATION / # TOIN Rt3WS23 HM SW 1/4 NE1i 7, •••„,,, N2255338.004 .r. E229280 "842 / ..'/A'5 LAITTUDE:6009'54WIN LONGITUDE:151'2Vio 892W / N / N i w cc 0• / NAD27 ASP ZONE 4 / CL 1 ., / FEL=2743 / ' ESL=3379' I / ji'''''---- ••.. 1 LOT 2007.17 TOWNSHIP 1N N...,6NNIA•%%1 ELEV=165.4'INGVD20) /, N IS, SECTION 23 / -/ Ur 274T FEL • ...., 'SN.-ef•''''''''''''''' if, ,P ' /' A , : - OP RANGE 13W,SM AK (2 gi' / / ..17 ./ riel ND 2 /WEt' / . ..., I a ,. Ft \ or , . i _ n / --r-A-4s"Ilt....._ .. i ,,,,N I'NI I. / ,.,".15)0 i / 0/ I / , ELEV.",'-I. i / ----"---.., 1 '7 /IP° ••• / * 1k -0,4. SCOTT 144cLANE; ... / /zz i I °- •• , / 0....,•., 4928-5 ..."." _77 / / q , ,, •.,...bir"AL 20! ...' .„-.77 —, / -.. No,WEI I ' r". ' ..-':.;, .,/, 1 f 1 i P4'01,' ‘''oc... .11:* .I. ESS0114- /4k, /„..., 7 " X ,,; ,',,,, '''';I:% .>'''''- WATER / ,//////// -47. 1 I 1,• I%%V6•NNN,e, li-' '4',;,fil / , 0 ../ , --- 41 '„ / / /2,, 10k •41// A' NW PAT 1979 / . / / N \ '4', ,/';/../ / 00 14.)4 WtLL / •/7 `..._ 't, I N.2255179 16 / f.-t ..,-165 4' I' " = t'l. 4,1.1 / E•228974.16 / Co / 410;14,// / ELEV.163 064 / / Irt / / / '4QN / \ / ..---------" 7— TROL .4,-• q / / eu11131NG ...socr cP 'c) 0 Go WI 5 WE --E..Ev=i.— ' .,., tt, /I/ I:L c, , N...., /! \-1, 4/ ..„41. ,1 / i , „:,,- _, • ...... , 4.- ( 4 - . 1,- (/) CCAMII,NMI c:.0 CO LL msza 0 .4.. ) , :") / - , .,111.REBAR __ SECITONLIKE,INTS 3 I. e, GO NOE,WELL \ e, , / - - i N.2254096,17 NOTES , RMI PAT 1979 // / E.22917504 N.2254065.8 , / / ELEV=18/1.5* 1.BASIS OF GEODETIC CONTROL AND NADU POSITION E.228817 63 11 / (EPOCH 2003)IS AN OPUS SOLUTION FROM NW STATIONS i ELEV.162 81' 1 ,/ ,..-9-/GO No 7 13,3'LL , j.. ' k . 8' GOV'T LOT 2 "KEN5 CORS ARP' 'Z , AN I CORS ARP-,AND-TSEA ARP'TO 1 / ETV 16` ESTABLISH THE POSITION OF NGS CONTROL STATION PAT .2 1979 RM 1,mE GEODETIC POSITION OF PAT 1979 R8.4 1 WAS 1 I AfiK TIN R134V S IA SECTION 23 . ADETERMINED TO HAVE A LATITUDE OF 600948,70932'N AND A LONGITUDE OF 1512927.64397-W THE ALASKA STATE 11 '41 , PLANE COORDINATES(ASP)ZONE 4 NAD 83 FEET ARE *42754726735 f lit, E=1,368,837.068 44 ./ u. --4F _,....‘ /.1 _ / ...___Aii, (., . •CAUTION• ,.., Hicol PRESSURE DE TERELEV 162.40'(NGVD201 2 THE BASIS Of BEARING FOR THIS PROJECT WAS NONED BY A HIGH PRECISION GPS SURVEY UTILIZING .... .=` ,.' g UNDERGROUND TRIMBLE R8 MODEL 3 GNSS RECEIVERS,DIFFERENTIALLY • •••,,auni, is t• . LATERAL GAS CORRECTED AND PROCESSED WITH TRIMBLE TSC3 / 1 0 'W"' PIPELINE TO K K P L CONTROLLER AND ACCESS FIELD SOFTWARE. / .......41,For.... 3 PROJECT BASIS OF BEARING IS ASP NA083 ZONE4 US FT -../. .- GRID BEARING /I , IN, 4 DATA TRANSFORMATIONS(NADU TO NAD27 ASPZ4)WERE I I 'DONE USING coApscoN vERsIoN 60 1 SC \I c2 • PAD WELL NO. 8 S-STAKED SURFACE LOCATION (NAD27) RASSIM OSKOLKOFF PAD LOCATION:SECTION 23. TOWNSHIP 1 NORTH, ETESTINGNGINEERING• , RANGE 13 WEST,SEWARD MERIDIAN.ALASKA ,,..• \ SURVEYING•MAPPING ii aro,.p t 1.4.a.IJA: 1 P.O.BOX 4 68 \ r6 SOLDOTINtA,AK,99.569 JOB No, 157006 \iiimpippi VOICE,(907)283-4216 Page ( FAX (097)263-3265 DWG. Consultiv Inc www mcLANEGG.com 157006 Date:4/2812015 FIGURE: 1 • 0 / 11 GO #8 Drilling Procedure CIilnorp rtla.;ka,LIA: 36.0 Offset MW vs TVD Chart MW vs TVD Offsets 0 , Corea Cr= #1(1996) 1000 1 Fans'reek#5(2014) l' NA i I (2000) i 2000 -•--•--1I GO#2(2001) 3000 1 3 1 i 4000 1 I i 5000 C c3 j I lk* 60 1 I I i 1 7000 - I : I 1 I i � I 1/4\' cl '''''*.A. I 0 I I 1 1 9000 11 \ 1 i 1 10000 I 1 I g 1 1 11000 ' ' E 8 9 10 11 12 13 14 15 Mid Weight fes) Page 61 Revision 0 April, 2015 ,f, • GO#8 Drilling Procedure no.ii, t ki-la.Li c 37.0 Drill Pipe Information z I immsv own LUI E: - SIZE. 4 1/2" WEIGHT: 16.6 LBSiLBS/fl" / GRAD5-135 / RANGE: II(3 1.6 /7 ') DRILL PIPE SPECS CONNECTION: CDS4O TUBE / t NEw PREMIUM 1 IN Mfoi IN AIM OD 4,500 114 3 4,365 110 9 WALL THIC NESS 0.337 86 0,270 68 ID: 3.826 97.2 3,826 97.2 FT-LBS N•fi FT-LBS N-M TORSIONAL STRENOTHI 55.453 75.200 / 43.451 58,900 L 80%TORSIONAL STRENGTHt 44,362 60.200 / 34,761 47.100 LBS DAN / LBS DAN TENSILE STRENGTH! 595,004 265,?D0 468,297 208 800 1 PSI KPA' PSI KPA INTERNAL PRESSURE CAPACITY17,693 1/1.985 16,176 111.530 COLLAPSE CAPACITY 16.769 115 615 I 10,959 75,561 1N2 / MM2 IN2 MM2 CROSS SECTIONAL AREA BODY 4,407 ' 2844 3.469 2238 CROSS SECTIoNAL AREA OD 15.904/ 10261 14.966 9655 CROSS SECTIONAL AREA ID I 1.49 7417 11.497 7417 IMM3 IN SECTION MODULUS N* ,271 69995 IbR 3.347 54845 POLAR SECTION MODULUSL 8.543 139989 6.694 109690 T. L JOINT NEW II PREMIUM PSI KPA PSI KPA YIELD STREN 130,000 896.318 130,000 896,318 IN MM IN NIM a D 5.2500 133 41 5.1198 130.0 ID 2.6875 6.8.3 2.6875 68.3 PIN NGTH 11,0 279 41 11.0 279 4 BO, LENGTH 14,0 355.61 14.0 355.6 FTLBS N-M Ft-LISS N-M TORSION- STRENGTH 35.400 48.000 34.700 47.100 MAX MA E.UP TORQUE 22.500 30.500 21.400 29.000 RECOMMENDED .KE4J1P TORQUE 21,200 28,800' 20.800 28.200 MIN AKE-LLIF To RLDLTE 19,600 26,600 19.300 26.200 LBS DAN LBS DAN , TENSILE STRENGTH 824,400 367,600 808.900 358,900 TOOL JOINT/DRILL ;IRE TORSIONAL RATIO 0.64 0,80 / DRILL PIPE ASSEMBLY WITH CONNECTION / WS/FT KG/M ADJUSTED WEIGHT 17.87 26.64 FT M APPROXIMATE LENGTH 31,50 9 60 GAL/FT m2/p4 FLUID DISPLACEMENT 0 273 0,003394 FLUID CAPAC iry 0,577 0.007169 IN MM DRIFT SIZE 2.5625 65 Page 62 Revision 0 April, 2015 • • GO#8 Drilling Procedure II Riled.'1,alae&,1.1,4 COMBINED LOAD CURVE FOR 4 1/2"S 135 16.6 LBS/FT QRII L PIPE WITH CDS4f7 CONNECTIONS , ` scav oao �ua.fl700,01141y, 6CX7,060 i SCd,00::) €acs oa 300,000 1 al 200,flC,7 I m _ W kim.41$tit m, 0 10 000 20,000 36,000 40,000 50000 ':c'i r .plied11 Tnrque�k-ihs� ar rr NEW TUBE COMBINER 11. LOAD ••>-0 PRI MiLI.'TUBE COMBINED LOAD MAKE-UP TORQUE - -- HOULDER SEPERATUON -PIN'YIEUD -""'"'BOX YIELD / / Page 63 Revision 0 April, 2015 • 011 a k Hilcorp Energy Company 4 - Ninilchik Unit Grassim Oskolkoff r, Grassim Oskolkoff #8 G08 13' Plan: GO 8 WPI Standard Proposal Report 14 November, 2014 ;2•`• ; „ . ij - `1,• , ,•••, 7.1 • HALLISURTON Sperry Drilling Services 4110 —- DETAILS: Grassim Oskolkoff Ground Level: 168.50 +N/-S +F/-W Northing Fasting Latittude Longitude Slot 0.00 0.00 2255349.00 229313.00 60.16519559 -151.48618376 _ GO8 WP1 GO 8 TD tgt E-HALLIUR N 4500 GO 8 Tyonek tgt Sperry Drilling Services Q a 0 0 3000— Project: Ninilchik Unit : Grassim Oskolkoff Wellll: Grassim Oskolkoff#8 Wellbore: GO 8 Plan: GO 8 WP1 0 1500— v) 1,4 0 .. I -7500 -6000 -4500 -3000 -1500 0 1500 3000 West(-)fEast(+) (1500 usft/in) REFERENCE INFORMATION Co-ordinate(N/E)Reference: Well Grassim Oskolkoff#8,True North Vertical(TVD)Reference: Preliminary(g 187.00usft Measured Depth Reference: Preliminary t 187.00usft Calculation Method: Minimum Curvature 0— Start Dir•°/100':400'MD,400TVD 1000— End Dir :2372.56'MD,1805.61'TVD 2000— - Beluga 50 - -- c - Start Dir 5°/100':6503.55'MD,2600.76'TVD co 3000- 7 o - GO 8 Tyonek tgt o —- Tyonek- --- ---- 0 CV 4000— T6 _.... a _ End Dir :7942'MD,3586'TVD a) o - t 5000— T20....... ......... .. 'C - a) - 6000—___T60 - M Azimuths to True North T65- Magnetic North:16.58° - T90- Magnetic Field Strength:55233.9snT 7000— Dip Angle:73.18° Date: 11/7/2014 Model:BGGM2013 8000— GO 8 WP1 GO 8 TD tgt -- Total Depth: 13084.11'MD,8690'TVD 9000— ° -3000 -2000 -1000 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 Vertical Section at 319.96° (2000 usft/in) I I by0 Project: Ninilchik Unit • ^5 J� Site: Grassim Oskolkoff 13� 4875-- Well: Grassim Oskolkoff#8 - ,sem Wellbore: GO 8 GO RTI Ne Plan: GO 8 WP1 �• 4500— ,Sod GO i HAL LIENUsaTON �qa. Sperry Orating Sorvilaw .... o,. SO 4125 Kil $ - T M Azimuths to True North - Magnetic North:16.58° x" 4°°° 3750-- Magnetic Field ,^ $ - Strength:55233.9onT lcti ycA - Dip Angle:73.18° / .ti Date:11/7/2014 e350° _ Model:0GGM2013 3375-- `.? S ry _ 11 7 •7 tO4--f1�44Cr) s c 3000— a = 5 5 300 in S' 12625— + A S ,' O • 2250--_ 424 s - 5 - 1 1875..... WF,I]..DETAIIS,001.41111 Oskolkoff 88 - ,y25°° Ground ound Level: 168.50 -"+ +NAS +F./-W Northing Faring letittude lengimde Slot 0.00 0.00 225534900 229313.00 6016519559 •15148618376 1500— .. ............... ......... _ .................. ......... _.. 8 ti' 1125— REFERENCE INFORMATION. Co-ordinate(NIE)Reference:Well Gracsim Oakolkoa#B.True North - Vertical(TVD)Reference:Preliminary®1e7.00ush measured Depth Reference'.Preliminary Pal 1e7.00usa Calculation Method:Minimum Curvature s°750— ycFF 375..... <K/2 0 0— . o$ g _ $ 8\ it I- . , , rllil ' ll " ' I ' ' lllil1 , ' rillr „ Ilii r1 , ll 1 ' ' ' 1 " ' ' i , llll _ ' , illi - 111 -7125 -6750 -6375 -6000 -5625 -5250 -4875 -4500 125 -3750 -3375 -3000 -2625 -2250 -1875 -1500 -1125 -750 -375 0 West(-)/East(+)(750 usft/in) I I Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Grassim Oskolkoff#8 • Company: Hilcorp Energy Company TVD Reference: Preliminary @ 187.00usft - Project: Ninilchik Unit MD Reference: Preliminary @ 187.00usft Site: Grassim Oskolkoff North Reference: True Well: Grassim Oskolkoff#8 Survey Calculation Method: Minimum Curvature` Wellbore: GO 8 Design: GO 8 WP1 Project Ninilchik Unit Map System: US State Plane 1927(Exact solution) - System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) . Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Grassim Oskolkoff f Site Position: Northing: 2,255,349.00 usft Latitude:// 60.16519559 From: Map Easting: 229,313.00usft Longit�: -151.48618376 Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid p'onvergence: -1.29 ° Well Grassim Oskolkoff#8 Well Position +N/-S 0.00 usft Northing: 2,255,349.0 usft Latitude: 60.16519559 +E/-W 0.00 usft Easting: 229,313 0 usft • Longitude: -151.48618376 Position Uncertainty 0.00 usft Wellhead Elevation: .00 usft Ground Level: . 168.50 usft Wellbore GO 8 Magnetics Model Name Sample Date Declin ion Dip Angle Field Strength (° (0) (nT) BGGM2013 11/7/2014 16.58 73.18 55,234 Design GO 8 WP1 Audit Notes: f0 Version: Phase: P • Tie On Depth: 20.88 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 20.88 0.00 0.00 319.96 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth Syste, +N/-S +E/-W Rate Rate Rate Tool Face (usft) (°) (0) (usft) us' (usft) (usft) (°/100usft) (°/100usft) (°/100usft) (0) 20.88 0.00 0.00 20.88 - 66.12 0.00 0.00 0.00 0.00 0.00 0.00 400.00 0.00 0.00 400.00 213.00 0.00 0.00 0.00 0.00 0.00 0.00 2,372.56 78.90 319.94 1,805.61 1,618.61 885.23 -744.50 4.00 4.00 0.00 319.94 6,503.55 78.90 319.94 2,600.76 2,413.76 3,987.62 -3,353.72 0.00 0.00 0.00 0.00 7,942.00 6.98 320.14 3,586.00 3,399.00 4,689.53 -3,943.58 5.00 -5.00 0.01 179.97 13,084.11 6.98 320.14 8,690.00 8,503.00 5,169.15 -4,344.08 0.00 0.00 0.00 0.00 11/14/2014 1:29:10PM Page 2 COMPASS 5000.1 Build 70 0 I Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Grassim Oskolkoff#8 Company: Hilcorp Energy Company TVD Reference: Preliminary @ 187.00usft Project: Ninilchik Unit MD Reference: Preliminary @ 187.00usft Site: Grassim Oskolkoff North Reference: True Well: Grassim Oskolkoff#8 Survey Calculation Method: Minimum Curvature Wellbore: GO 8 Design: GO 8 WP1 Planned Survey Measured Vertical Map Ma Depth Inclination Azimuth Depth TVDss` +N/-S +E/-W Northing E ing DLS Vert Section (usft) (°) (0) (usft) usft (usft) (usft) ' (usft) usft) -166.12 20.88 0.00 0.00 20.88 -166.12 0.00 0.00 2,255,349.00 229,313.00 0.00 0.00 100.00 0.00 0.00 100.00 -87.00 0.00 0.00 2,255,349.0 229,313.00 0.00 0.00 200.00 0.00 0.00 200.00 13.00 0.00 0.00 2,255,349 0 229,313.00 0.00 0.00 300.00 0.00 0.00 300.00 113.00 0.00 0.00 2,255,3 9.00 229,313.00 0.00 0.00 400.00 0.00 • 0.00 400.00 213.00 0.00 0.00 2,25 ,349.00 229,313.00 0.00 0.00 Start Dir 4°1100':400'MD,400'TVD 500.00 4.00 319.94 499.92 312.92 2.67 -2.25 ,255,351.72 229,310.81 4.00 3.49 600.00 8.00 319.94 599.35 412.35 10.67 -8.97 2,255,359.87 229,304.27 4.00 13.94 700.00 12.00 319.94 697.81 510.81 23.96 -20.15 2,255,373.40 229,293.40 4.00 31.30 800.00 16.00 319.94 794.82 607.82 42.47 -35.7 2,255,392.26 229,278.25 4.00 55.49 900.00 20.00 319.94 889.91 702.91 66.11 -5 .60 2,255,416.34 229,258.90 4.00 86.38 1,000.00 24.00 319.94 982.61 795.61 94.77 - 9.71 2,255,445.54 229,235.45 4.00 123.84 1,100.00 28.00 319.94 1,072.47 885.47 128.32 107.92 2,255,479.71 229,208.00 4.00 167.67 1,200.00 32.00 319.94 1,159.05 972.05 166.57 -140.09 2,255,518.68 229,176.69 4.00 217.66 1,300.00 36.00 319.94 1,241.94 1,054.94 209.36 -176.08 2,255,562.27 229,141.68 4.00 273.56 1,400.00 40.00 319.94 1,320.73 1,133.73 256.4 -215.70 2,255,610.25 229,103.13 4.00 335.12 1,500.00 44.00 319.94 1,395.02 1,208.02 307 .7 -258.76 2,255,662.41 229,061.23 4.00 402.02 1,600.00 48.00 319.94 1,464.48 1,277.48 3; .71 -305.05 2,255,718.48 229,016.19 4.00 473.94 1,700.00 52.00 319.94 1,528.74 1,341.74 .21.33 -354.35 2,255,778.18 228,968.23 4.00 550.52 1,800.00 56.00 319.94 1,587.51 1,400.51 483.23 -406.41 2,255,841.24 228,917.57 4.00 631.41 1,900.00 60.00 319.94 1,640.49 1,453.49 548.12 -460.98 2,255,907.34 228,864.47 4.00 716.20 2,000.00 64.00 319.94 1,687.43 1,500.4 615.68 -517.80 2,255,976.16 228,809.19 4.00 804.47 2,100.00 68.00 319.94 1,728.09 1,541.e• 685.58 -576.59 2,256,047.37 228,751.99 4.00 895.81 2,200.00 72.00 319.94 1,762.29 1,57 .29 757.48 -637.06 2,256,120.61 228,693.15 4.00 989.76 2,300.00 76.00 319.94 1,789.85 1,6'2.85 831.03 -698.92 2,256,195.53 228,632.96 4.00 1,085.87 2,372.56 78.90 319.94 1,805.61 1 .18.61 885.23 -744.51 2,256,250.74 228,588.61 4.00 1,156.69 End Dir :2372.56'MD,1805.61'TVD 2,400.00 78.90 319.94 1,810.89 1,623.89 905.84 -761.84 2,256,271.74 228,571.75 0.00 1,183.61 2,500.00 78.90 319.94 1,830.14 1,643.14 980.94 -825.00 2,256,348.24 228,510.29 0.00 1,281.74 10 3/4" 2,600.00 78.90 319.94 1,849 9 1,662.39 1,056.04 -888.16 2,256,424.74 228,448.84 0.00 1,379.87 2,700.00 78.90 319.94 1,864.64 1,681.64 1,131.14 -951.32 2,256,501.24 228,387.38 0.00 1,478.00 2,800.00 78.90 319.94 1,::7.89 1,700.89 1,206.24 -1,014.49 2,256,577.74 228,325.93 0.00 1,576.13 2,900.00 78.90 319.94 1 '07.13 1,720.13 1,281.34 -1,077.65 2,256,654.24 228,264.47 0.00 1,674.26 3,000.00 78.90 319.94 ,926.38 1,739.38 1,356.44 -1,140.81 2,256,730.74 228,203.02 0.00 1,772.39 3,100.00 78.90 319.94 1,945.63 1,758.63 1,431.54 -1,203.97 2,256,807.24 228,141.56 0.00 1,870.52 3,200.00 78.90 319.9, 1,964.88 1,777.88 1,506.64 -1,267.13 2,256,883.75 228,080.11 0.00 1,968.65 3,300.00 78.90 319.•4 1,984.13 1,797.13 1,581.74 -1,330.30 2,256,960.25 228,018.65 0.00 2,066.78 3,400.00 78.90 31*.94 2,003.38 1,816.38 1,656.84 -1,393.46 2,257,036.75 227,957.20 0.00 2,164.91 3,500.00 78.90 3 9.94 2,022.62 1,835.62 1,731.94 -1,456.62 2,257,113.25 227,895.74 0.00 2,263.04 3,600.00 78.90 .19.94 2,041.87 1,854.87 1,807.04 -1,519.78 2,257,189.75 227,834.29 0.00 2,361.17 3,700.00 78.90 319.94 2,061.12 1,874.12 1,882.14 -1,582.94 2,257,266.25 227,772.83 0.00 2,459.30 3,800.00 78.90 319.94 2,080.37 1,893.37 1,957.24 -1,646.10 2,257,342.75 227,711.38 0.00 2,557.43 3,900.00 78.90 319.94 2,099.62 1,912.62 2,032.34 -1,709.27 2,257,419.26 227,649.92 0.00 2,655.56 11/14/2014 1:29:10PM Page 3 COMPASS 5000.1 Build 70 0 III Halliburton HALLIBURTON Standard Proposal Report , _ = _ , . . mss.. Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Grassim Oskolkoff#8 Company: Hilcorp Energy Company TVD Reference: Preliminary @ 187.00usft Project: Ninilchik Unit MD Reference: Preliminary @ 187.00usft Site: Grassim Oskolkoff North Reference: True Well: Grassim Oskolkoff#8 Survey Calculation Method: Minimum Curvature Wellbore: GO 8 / Design: GO 8 WP1 /y�/ Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NI-S +EI-W Northing Easting DLS Vert Section (usft) (0) (0) (usft) usft (usft) (usft) (usft) (usft) 1,921.00 3,943.55 78.90 319.94 2,108.00 1,921.00 2,065.05 -1,736.77 2,257,452.57 227,623.16 0.00 2,698.30 Beluga 50 4,000.00 78.90 319.94 2,118.87 1,931.87 2,107.44 -1,772.43 2,257,495. • 227,588.47 0.00 2,753.69 4,100.00 78.90 319.94 2,138.11 1,951.11 2,182.55 -1,835.59 2,257,57 .26 227,527.01 0.00 2,851.82 4,200.00 78.90 319.94 2,157.36 1,970.36 2,257.65 -1,898.75 2,257 :48.76 227,465.56 0.00 2,949.95 4,300.00 78.90 319.94 2,176.61 1,989.61 2,332.75 -1,961.91 2,2 ,725.26 227,404.10 0.00 3,048.08 4,400.00 78.90 319.94 2,195.86 2,008.86 2,407.85 -2,025.08 57,801.76 227,342.65 0.00 3,146.21 4,500.00 78.90 319.94 2,215.11 2,028.11 2,482.95 -2,088.24 2,257,878.26 227,281.19 0.00 3,244.34 4,600.00 78.90 319.94 2,234.36 2,047.36 2,558.05 -2,151.40 2,257,954.77 227,219.74 0.00 3,342.47 4,700.00 78.90 319.94 2,253.60 2,066.60 2,633.15 -2,214.54 2,258,031.27 227,158.28 0.00 3,440.60 4,800.00 78.90 319.94 2,272.85 2,085.85 2,708.25 -2,277 2 2,258,107.77 227,096.83 0.00 3,538.73 4,900.00 78.90 319.94 2,292.10 2,105.10 2,783.35 -2,3'4.88 2,258,184.27 227,035.37 0.00 3,636.86 5,000.00 78.90 319.94 2,311.35 2,124.35 2,858.45 -2 '04.05 2,258,260.77 226,973.92 0.00 3,734.99 5,100.00 78.90 319.94 2,330.60 2,143.60 2,933.55 ,467.21 2,258,337.27 226,912.46 0.00 3,833.12 5,200.00 78.90 319.94 2,349.85 2,162.85 3,008.65 -2,530.37 2,258,413.77 226,851.01 0.00 3,931.25 5,300.00 78.90 319.94 2,369.10 2,182.10 3,083.7, -2,593.53 2,258,490.27 226,789.55 0.00 4,029.38 5,400.00 78.90 319.94 2,388.34 2,201.34 3,158 s5 -2,656.69 2,258,566.78 226,728.10 0.00 4,127.51 5,500.00 78.90 319.94 2,407.59 2,220.59 3,2 4.95 -2,719.86 2,258,643.28 226,666.64 0.00 4,225.64 5,600.00 78.90 319.94 2,426.84 2,239.84 3 .09.05 -2,783.02 2,258,719.78 226,605.19 0.00 4,323.77 5,700.00 78.90 319.94 2,446.09 2,259.09 .,384.15 -2,846.18 2,258,796.28 226,543.73 0.00 4,421.90 5,800.00 78.90 319.94 2,465.34 2,278.34 3,459.25 -2,909.34 2,258,872.78 226,482.28 0.00 4,520.03 5,900.00 78.90 319.94 2,484.59 2,297.59 3,534.35 -2,972.50 2,258,949.28 226,420.82 0.00 4,618.16 6,000.00 78.90 319.94 2,503.83 2,316.: 3,609.45 -3,035.67 2,259,025.78 226,359.37 0.00 4,716.29 6,100.00 78.90 319.94 2,523.08 2,33•.08 3,684.55 -3,098.83 2,259,102.29 226,297.91 0.00 4,814.42 6,200.00 78.90 319.94 2,542.33 2,3-5.33 3,759.65 -3,161.99 2,259,178.79 226,236.46 0.00 4,912.55 6,300.00 78.90 319.94 2,561.58 2 74.58 3,834.76 -3,225.15 2,259,255.29 226,175.00 0.00 5,010.68 6,400.00 78.90 319.94 2,580.83 ,393.83 3,909.86 -3,288.31 2,259,331.79 226,113.55 0.00 5,108.81 6,500.00 78.90 319.94 2,600.08 2,413.08 3,984.96 -3,351.47 2,259,408.29 226,052.09 0.00 5,206.94 6,503.55 78.90 319.94 2,600.76 2,413.76 3,987.62 -3,353.72 2,259,411.01 226,049.91 0.00 5,210.43 Start Dir 5°I100':6503.55'MD,2600.761 VD 6,600.00 74.08 319.94 2,623 8 2,436.28 4,059.37 -3,414.06 2,259,484.10 225,991.20 5.00 5,304.18 6,700.00 69.08 319.94 2,6 '.87 2,467.87 4,131.97 -3,475.10 2,259,558.04 225,931.80 5.00 5,399.03 6,800.00 64.08 319.94 2,•44.61 2,507.61 4,202.18 -3,534.14 2,259,629.56 225,874.36 5.00 5,490.76 6,900.00 59.08 319.95 42.19 2,555.19 4,269.47 -3,590.72 2,259,698.11 225,819.31 5.00 5,578.68 7,000.00 54.08 319.95 ',797.25 2,610.25 4,333.34 -3,644.41 2,259,763.17 225,767.07 5.00 5,662.12 7,100.00 49.08 319.95 2,859.37 2,672.37 4,393.29 -3,694.81 2,259,824.24 225,718.04 5.00 5,740.44 7,200.00 44.08 319.9• 2,928.08 2,741.08 4,448.88 -3,741.53 2,259,880.87 225,672.58 5.00 5,813.05 7,300.00 39.08 319.•• 3,002.86 2,815.86 4,499.67 -3,784.21 2,259,932.60 225,631.06 5.00 5,879.39 7,400.00 34.08 319 •7 3,083.14 2,896.14 4,545.28 -3,822.53 2,259,979.07 225,593.77 5.00 5,938.97 7,500.00 29.08 314.98 3,168.30 2,981.30 4,585.37 -3,856.20 2,260,019.90 225,561.01 5.00 5,991.32 7,600.00 24.08 9.99 3,257.71 3,070.71 4,619.63 -3,884.97 2,260,054.79 225,533.02 5.00 6,036.05 7,700.00 19.08 :20.00 3,350.67 3,163.67 4,647.79 -3,908.60 2,260,083.48 225,510.03 5.00 6,072.82 7,800.00 14.08 320.03 3,446.48 3,259.48 4,669.65 -3,926.93 2,260,105.75 225,492.19 5.00 6,101.35 7,900.00 9.08 320.09 3,544.41 3,357.41 4,685.03 -3,939.82 2,260,121.42 225,479.66 5.00 6,121.41 11/14/2014 1:29:10PM Page 4 COMPASS 5000.1 Build 70 • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Grassim Oskolkoff#8 Company: Hilcorp Energy Company TVD Reference: Preliminary @ 187.00usft Project: Ninilchik Unit MD Reference: Preliminary @ 187.00usft Site: Grassim Oskolkoff North Reference: True Well: Grassim Oskolkoff#8 Survey Calculation Method: Minimum Curvature Wellbore: GO 8 Design: GO 8 WP1 Planned Survey / Measured' Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (usft) (°} (°) (usft) usft (usft) (usft) (usft) (usft 3,399.00 7,942.00 6.98 320.14 3,586.00 3,399.00 4,689.53 -3,943.58 2,260,126.00 2$,476.00 5.00 6,127.28 End Dir :7942'MD,3586'TVD-Tyonek 8,000.00 6.98 320.14 3,643.57 3,456.57 4,694.94 -3,948.10 2,260,131.51 225,471.61 0.00 6,134.33 8,100.00 6.98 320.14 3,742.83 3,555.83 4,704.27 -3,955.89 2,260,141.01 225,464.03 0.00 6,146.48 8,200.00 6.98 320.14 3,842.09 3,655.09 4,713.60 -3,963.68 2,260,150. 225,456.45 0.00 6,158.63 8,300.00 6.98 320.14 3,941.35 3,754.35 4,722.92 -3,971.46 2,260,164.01 225,448.88 0.00 6,170.78 8,352.04 6.98 320.14 3,993.00 3,806.00 4,727.78 -3,975.52 2,260, .4.95 225,444.93 0.00 6,177.10 T6 8,400.00 6.98 320.14 4,040.60 3,853.60 4,732.25 -3,979.25 2, .0,169.51 225,441.30 0.00 6,182.93 8,500.00 6.98 320.14 4,139.86 3,952.86 4,741.58 -3,987.04 ,260,179.01 225,433.72 0.00 6,195.08 8,600.00 6.98 320.14 4,239.12 4,052.12 4,750.91 -3,994.83 2,260,188.51 225,426,15 0.00 6,207.24 8,700.00 6.98 320.14 4,338.38 4,151.38 4,760.23 -4,002.62;' 2,260,198.01 225,418.57 0.00 6,219.39 8,800.00 6.98 320.14 4,437.64 4,250.64 4,769.56 -4,010.,, 2,260,207.51 225,410.99 0.00 6,231.54 8,900.00 6.98 320.14 4,536.90 4,349.90 4,778.89 -4,01:.20 2,260,217.01 225,403.42 0.00 6,243.69 9,000.00 6.98 320.14 4,636.16 4,449.16 4,788.21 -4,0 5.98 2,260,226.51 225,395.84 0.00 6,255.84 9,100.00 6.98 320.14 4,735.42 4,548.42 4,797.54 433.77 2,260,236.01 225,388.26 0.00 6,267.99 9,200.00 6.98 320.14 4,834.68 4,647.68 4,806.87 4,041.56 2,260,245.51 225,380.69 0.00 6,280.14 9,300.00 6.98 320.14 4,933.93 4,746.93 4,816.20 -4,049.35 2,260,255.01 225,373.11 0.00 6,292.30 9,400.00 6.98 320.14 5,033.19 4,846.19 4,825.5 -4,057.14 2,260,264.51 225,365.53 0.00 6,304.45 9,470.33 6.98 320.14 5,103.00 4,916.00 4,832 48 -4,062.62 2,260,271.19 225,360.20 0.00 6,312.99 T20 9,500.00 6.98 320.14 5,132.45 4,945.45 4,7 4.85 -4,064.93 2,260,274.01 225,357.96 0.00 6,316.60 9,600.00 6.98 320.14 5,231.71 5,044.71 ,844.18 -4,072.72 2,260,283.51 225,350.38 0.00 6,328.75 9,700.00 6.98 320.14 5,330.97 5,143.97 4,853.51 -4,080.51 2,260,293.01 225,342.80 0.00 6,340.90 9,800.00 6.98 320.14 5,430.23 5,243.23 4,862.83 -4,088.29 2,260,302.51 225,335.23 0.00 6,353.05 9,900.00 6.98 320.14 5,529.49 5,342.4 4,872.16 -4,096.08 2,260,312.01 225,327.65 0.00 6,365.20 10,000.00 6.98 320.14 5,628.75 5,441 5 4,881.49 -4,103.87 2,260,321.51 225,320.07 0.00 6,377.36 10,100.00 6.98 320.14 5,728.01 5,5, .01 4,890.81 -4,111.66 2,260,331.01 225,312.50 0.00 6,389.51 10,200.00 6.98 320.14 5,827.27 5,440.27 4,900.14 -4,119.45 2,260,340.51 225,304.92 0.00 6,401.66 10,300.00 6.98 320.14 5,926.52 ',739.52 4,909.47 -4,127.24 2,260,350.01 225,297.34 0.00 6,413.81 10,400.00 6.98 320.14 6,025.78 5,838.78 4,918.80 -4,135.03 2,260,359.51 225,289.77 0.00 6,425.96 10,477.79 6.98 320.14 6,103.00 5,916.00 4,926.05 -4,141.08 2,260,366.90 225,283.87 0.00 6,435.42 T60 10,500.00 6.98 320.14 6,125 64 5,938.04 4,928.12 -4,142.81 2,260,369.01 225,282.19 0.00 6,438.11 10,600.00 6.98 320.14 6,22 .30 6,037.30 4,937.45 -4,150.60 2,260,378.51 225,274.61 0.00 6,450.27 10,638.99 6.98 320.14 6, 3.00 6,076.00 4,941.09 -4,153.64 2,260,382.21 225,271.66 0.00 6,455.00 T65 10,700.00 6.98 320.14 ,323.56 6,136.56 4,946.78 -4,158.39 2,260,388.01 225,267.04 0.00 6,462.42 10,800.00 6.98 320.14 6,422.82 6,235.82 4,956.11 -4,166.18 2,260,397.51 225,259.46 0.00 6,474.57 10,900.00 6.98 320.14 6,522.08 6,335.08 4,965.43 -4,173.97 2,260,407.01 225,251.88 0.00 6,486.72 11,000.00 6.98 320.1 6,621.34 6,434.34 4,974.76 -4,181.76 2,260,416.51 225,244.31 0.00 6,498.87 11,081.27 6.98 320. 4 6,702.00 6,515.00 4,982.34 -4,188.09 2,260,424.23 225,238.15 0.00 6,508.75 T90 11,100.00 6.98 3 .14 6,720.60 6,533.60 4,984.09 -4,189.55 2,260,426.01 225,236.73 0.00 6,511.02 11,200.00 6.98 0.14 6,819.85 6,632.85 4,993.41 -4,197.33 2,260,435.51 225,229.15 0.00 6,523.17 11/14/2014 1:29:10PM Page 5 COMPASS 5000.1 Build 70 • 0 Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Grassim Oskolkoff#8 Company: Hilcorp Energy Company TVD Reference: Preliminary @ 187.0ousft / Project: Ninilchik Unit MD Reference: Preliminary @ 187.00usft Site: Grassim Oskolkoff North Reference: True Well: Grassim Oskolkoff#8 Survey Calculation Method: Minimum Curvature Wellbore: GO 8 Design: GO 8 WP1 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Eastin: DLS Vert Section (usft) (0) (0) (usft) usft " (usft) (usft) (usft) (us 6,732.11 11,300.00 6.98 320.14 6,919.11 6,732.11 5,002.74 -4,205.12 2,260,445.01 5,221.58 0.00 6,535.33 11,400.00 6.98 320.14 7,018.37 6,831.37 5,012.07 -4,212.91 2,260,454.51 225,214.00 0.00 6,547.48 11,500.00 6.98 320.14 7,117.63 6,930.63 5,021.40 -4,220.70 2,260,464.01 225,206.42 0.00 6,559.63 11,600.00 6.98 320.14 7,216.89 7,029.89 5,030.72 -4,228.49 2,260,473.5 225,198.85 0.00 6,571.78 11,700.00 6.98 320.14 7,316.15 7,129.15 5,040.05 -4,236.28 2,260,48 .01 225,191.27 0.00 6,583.93 11,800.00 6.98 320.14 7,415.41 7,228.41 5,049.38 -4,244.07 2,260,-•2.51 225,183.69 0.00 6,596.08 11,900.00 6.98 320.14 7,514.67 7,327.67 5,058.71 -4,251.86 2,26$,502.01 225,176.12 0.00 6,608.24 12,000.00 6.98 320.14 7,613.93 7,426.93 5,068.03 -4,259.64 2, 60,511.51 225,168.54 0.00 6,620.39 12,100.00 6.98 320.14 7,713.19 7,526.19 5,077.36 -4,267.43 ',260,521.01 225,160.96 0.00 6,632.54 12,200.00 6.98 320.14 7,812.44 7,625.44 5,086.69 -4,275.22 2,260,530.51 225,153.39 0.00 6,644.69 12,300.00 6.98 320.14 7,911.70 7,724.70 5,096.01 -4,283.01 2,260,540.01 225,145.81 0.00 6,656.84 12,400.00 6.98 320.14 8,010.96 7,823.96 5,105.34 -4,290.:$ 2,260,549.51 225,138.23 0.00 6,668.99 12,500.00 6.98 320.14 8,110.22 7,923.22 5,114.67 -4,29:.59 2,260,559.01 225,130.66 0.00 6,681.14 12,600.00 6.98 320.14 8,209.48 8,022.48 5,124.00 -4, .6.38 2,260,568.51 225,123.08 0.00 6,693.30 12,700.00 6.98 320.14 8,308.74 8,121.74 5,133.32 -,314.16 2,260,578.01 225,115.50 0.00 6,705.45 12,800.00 6.98 320.14 8,408.00 8,221.00 5,142.65 -4,321.95 2,260,587.51 225,107.93 0.00 6,717.60 12,900.00 6.98 320.14 8,507.26 8,320.26 5,151.9: -4,329.74 2,260,597.01 225,100.35 0.00 6,729.75 13,000.00 6.98 320.14 8,606.52 8,419.52 5,161. -4,337.53 2,260,606.51 225,092.77 0.00 6,741.90 13,084.10 6.98 320.14 8,689.99 8,502.99 5,16•.15 -4,344.08 2,260,614.50 225,086.40 0.00 6,752.12 Total Depth: 13084.11'MD,8690'TVD - 13,084.11 6.98 320.14 8,690.00 8,503.00 5 69.15 -4,344.08 2,260,614.50 225,086.40 0.00 6,752.12 Targets Target Name -hit/miss target Dip Angl Dip Dir. TVD +NI-S +El-W Northing Easting -Shape (0) (°) (usft) (usft) (usft) (usft) (usft) GO 8 Tyonek tqt 0.00 0.00 3,586.00 4,689.53 -3,943.58 2,260,126.00 225,476.00 -plan hits target center -Circle(radius 100.00) GO 8 TD tqt 0.00 0.00 8,690.00 5,169.15 -4,344.08 2,260,614.50 225,086.40 -plan hits target center -Circle(radius 100.00) Casing Points Measured Vertica Casing Hole Depth Dept Diameter Diameter (usft) (us•) Name (•) C') 13,084.11 8.90.00 7 5/8" 7-5/8 9-7/8 2,500.00 ,830.14 10 3/4" 10-3/4 12-1/4 11/14/2014 1:29:10PM Page 6 COMPASS 5000.1 Build 70 • • Halliburton HALLIBURTON Standard Proposal Report _ „ Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Grassim Oskolkoff#8 Company: Hilcorp Energy Company TVD Reference: Preliminary @ 187.00usft Project: Ninilchik Unit MD Reference: Preliminary @ 187.00usft Site: Grassim Oskolkoff North Reference: True Well: Grassim Oskolkoff#8 Survey Calculation Method: Minimum Curvature Wellbore: GO 8 Design: GO 8 WP1 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology (°) (°) 9,470.33 5,103.00 T20 8,352.04 3,993.00 T6 10,477,79 6,103.00 T60 10,638.99 6,263.00 T65 11,081.27 6,702.00 T90 3,943.55 2,108.00 Beluga 50 7,942.00 3,586.00 Tyonek Plan Annotations Measured Vertical Local Coordinates ,` Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 400.00 400.00 0.00 0.00 Start Dir 4°/100':400'MD,400'TVD 2,372.56 1,805.61 885.23 -744.51 End Dir :2372.56'MD, 1805.61'TVD 6,503.55 2,600.76 3,987.62 -3,353.72 Start Dir 5°/100':6503.55'MD,2600.76'TVD 7,942.00 3,586.00 4,689.53 -3,943.58 End Dir :7942'MD,3586'TVD 13,084.10 8,689.99 5,169.15 -4,344.08 Total Depth: 13084.11'MD,8690'TVD 11/14/2014 1.29:10PM i Page 7 COMPASS 5000.1 Build 70 I • r Hilco p Energy Company p Y fid; Ninilchik Unit Grassim Oskolkoff Grassim Oskolkoff#8 G0 8 GO 8 WP1 4 il Sperry Drilling Services Clearance Summary Anticollision Report 14 November, 2014 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Ref ence) Reference Design: Grassim Oskolkoff-Grassim Oskolkoff#8-GO 8-GO:WP1 Well Coordinates: 2255,349.00 N,229,313.00 E (60°09'54.70"N,151°2' 10.26"W) Datum Height: Preliminary©187.00usft Scan Range: 0.00 to 13,084.11 usft.Measured Depth. Scan Radius is 1,506.32 usft. Clearance Factor cutoff is Unlimited Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build: 70 Scan Type: GLOBAL FILTER APPLIED All welipaths within 20.+100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services • • Hilcorp Energy Company HALLIBURTON Ninilchik Unit Anticollision Report for Grassim Oskolkoff#8 -GO 8 WP1 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: Grassim Oskolkoff-Grassim Oskolkoff#8-GO 8-GO 8 WP1 Scan Range: 0.00 to 13,084.11 usft.Measured Depth. Scan Radius is 1,506.32 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft Grassim Oskolkoff Grassim Oskolkoff#1-GO 1-GO 1 212.59 117.91 212.59 116.44 211.59 79.941 Centre Di nce Pass- Grassim Oskolkoff#1-GO 1-GO 1 225.00 117.94 225.00 116.41 223.57 77.101 Ellipse -paration Pass- Grassim Oskolkoff#1-GO 1-GO 1 2,525.00 428.65 2,525.00 342.09 2,457.31 4.952 Clearance Factor Pass- Grassim Oskolkoff#2-GO 2-GO 2 239.85 77.14 239.85 75.37 239.86 43.438 C= tre Distance Pass- Grassim Oskolkoff#2-GO 2-GO 2 250.00 77.16 250.00 75.33 249.84 42.353 'Ilipse Separation Pass- Grassim Oskolkoff#2-GO 2-GO 2 3,150.00 1,502.12 3,150.00 1,428.10 2,623.73 20.29. Clearance Factor Pass- Grassim Oskolkoff#4-GO 4-GO 4 610.62 206.71 610.62 201.11 629.79 3•.:78 Ellipse Separation Pass- Grassim Oskolkoff#4-GO 4-GO 4 5,575.00 1,428.89 5,575.00 1,185.49 5,204,44 5.870 Clearance Factor Pass- Grassim Oskolkoff#5-GO 5-GO 5 1,982.37 239.74 1,982.37 227.48 2,216.56 19.563 Centre Distance Pass- Grassim Oskolkoff#5-GO 5-GO 5 2,000.00 239.94 2,000.00 227.25 2,232.82 18.912 Ellipse Separation Pass- Grassim Oskolkoff#5-GO 5-GO 5 4,175.00 1,035.72 4,175.00 919,34 4,206.7 8.899 Clearance Factor Pass- Survey tool proaram From To Survey/Plan Survey Tool (usft) (usft) 20.88 13,084.11 GOB WP1 MWD+SC+sag Ellipse error terms are correlated across survey tool tie-on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor=Distance Between Profiles/(Distance Between Profiles-Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 14 November,2014- 13:28 Page 2 of 4 COMPASS • • Hilcorp Energy Company HALLIBURTON Ninilchik Unit Anticollision Report for Grassim Oskolkoff#8 - GO 8 WP1 Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to Preliminary©187,00usft. Northing and Easing are relative to Grassim Oskolkoff#8. Coordinate System is US State Plane 1927(Exact solution),Alaska Zone 04. Central Meridian is-150.00°,Grid Convergence at Surface is' -1.29°. Ladder Plot / n 1350 / p LEGEND ca _ .. ; >a. , , , $ GrassimOskolkott#1,GO1,G01V0 N 1n • 4E- GrassimOskolkoff#2,GO 2,GO2V0 $ Grassim Oskolkoff#4,GO4,G04VO N I ` I -9- Grassim Oskolkoff#5,GO 5,GO 5 VO d / $ GO8VvP1 U450— . 0 ; C • .), _. •� I V I 1 J / f 0 0 1000 2000 3000 4000 5000 Measured Depth(1000 usft/in) 14 November,2014- 13:28 / Page 3 of 4 COMPASS , / . a I • • Hilcorp Energy Company HALLIE3URTON Ninilchik Unit Anticollision Report for Grassim Oskolkoff#8 - GO 8 WP1 Clearance Factor Plot: Measured Depth versus Separation(Clearance)Factor _... 1.. 1 ... , 10.00— \ I 8.75— ', 7.50—-. . Si_...... 6.25— LEGEND ___:_ tL $ Grassim OskAlkofr#1,G01,G01V0 O• 5.00— -X- Grassim Oskolkfr#2,GO2,GO2VO @ -A- Grassim Oskolkoff#4,GO4,GO4VO 3.75— $ Grassim OskoIkoff#5,GO5,GO5VO $ GO8WP1 2.50— . ........ _ Collision Avoidance Reg No-Go Zone•Stop Drilling—» 1.25— ..._..... ....... ......_. :... 0.00 , ; , , i , , , , i , , , , L , , , i , , , , i , , , i , , , , i , , L , , i i , , i , , , , L , , , i , 0 475 950 1425 1900 2375 2850 3325 3800 4 5 4750 5225 5700 Meastred Depth(950 usf fn) 14 November,2014- 13:28 Page 4 of 4 COMPASS • • Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Monday, May 11, 2015 10:20 AM To: 'Monty Myers' Cc: Paul Mazzolini; Foerster, Catherine P (DOA); Schwartz, Guy L (DOA) Subject: RE: Meeting request for Friday 5.15.15 Monty, A meeting at this point would be premature. The GO No. 8 Permit to Drill application is deficient; it will be returned to Hilcorp accompanied by a list of deficiencies for Hilcorp to address. Regards, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue,Suite 100 Anchorage,AK 99501 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you,contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Monty Myers [mailto:mmyers@hilcorp.com] Sent: Monday, May 11, 2015 9:55 AM To: Foerster, Catherine P (DOA); Davies, Stephen F (DOA); Schwartz, Guy L(DOA) Cc: Paul Mazzolini Subject: Meeting request for Friday 5.15.15 Good morning, I was hoping to meet with everyone in regards to the recent concerns with the PTD that was submitted for GO#8. If Friday May 15th 2015 at 10 am will work for you, please let me know and I will schedule it. If a different time works better please let me know. Thank you! Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell: 907.538.1168 1 • �� ~� Davies, Stephen F (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Tuesday, May 05, 2015 9:35 AM To: Davies, Stephen F (DOA) Cc: Schwartz, Guy L (DOA) Subject: RE: GO 8 (PTD#215-077) Permit to Drill Application: Questions Attachments: RevisedGO8_NU_pnognosis_O5O51S.pdf Good morning Steve, • The surveyor's plat is the correct version. All of this is just a plan until the conductor is driven. Once the conductorisdriven' wexvi||getan ''a*bui|t'' surveyor'ap|atandcor/ectthedirectiona| p|an, andthed/i||ing program to the surveyor's "as-built". We will then re-submit these items to the AOGCC for review. This is how it is done for almost every well we submit. • The Northing's and Eastings on Halliburton's directional plan will be corrected to the "as-built" after conductor is driven • The formation tops listed on page 49 is the geologists best guess for the MD of the well along that path.The TVD is more important to look at and they are spot on with the geoprog from page 49. Halliburton uses a more precise directional planning tool than our geologists do. Attached is the updated geoprog with corrected MD's. • The water well drilled on the blossom pad did not have any salinity analysis done to my knowledge and the same standardized text is included because the pad is less than a mile away to the south of the Blossom Pad.The issue was in fact resolved with the comments from Dave Buthman, our geologist for the calculations and the information you needed to back up the calculations., in an email dated March 24th 2015. "Hi Steve, Attached are 1) the salinity calculations for the Falls Creek#1 well (the nearest well with the shallowest SP run, and located 13,652 feet to the northeast of the Blossom well), and 2) McGee's 1976 cross section showing Cook Inlet Water Salinities. On McGee's cross section, the Blossom 1 would lie at apprnxima1e|ytheMobi| 1'Nini|chikweUposting, andindicotes25U' depthtothehaseofthefreshwater surface. The Falls Creek 1 ran SP below 250', so salinity calculations reported could not have been made using this well (calculations for this well are herein attached). Gas shows in the Falls Creek 1 increase from 9 units at 250' to 25 units at 660', and increase below that. We anticipate eventual gas production from very shallow intervals such as this at wells more optimally located on the structure. If you need further clarification, please don't hesitate to call or email. Regards, David B. Buthman Sr. Geologist 3800 Centerpoint Drive Suite 100 Anchorage, AK 99503" Please let me know what other questions arise. Thank you! Monty M Myers 1 • • Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell: 907.538.1168 From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Monday, May 04, 2015 4:50 PM To: Monty Myers Cc: Schwartz, Guy L (DOA) Subject: FW: GO 8 (PTD # 215-077) Permit to Drill Application: Questions Monty, Please provide information to support Hilcorp's statement on page 7 of the application: All known potential fresh water zones exist above 200'. This information is based off salinity calculations of neighboring water wells. Chlorides are 1100 ppm at the 171 -194'sand, 1800 ppm at the 505—535'sand, and 6000 ppm at the 1040' sand. Furthermore, the TGAS (total gas) curve from offset mud logs begins registering shallow gas at depths just below the sandstone bed at 200'. Hilcorp included this same standardized text in the Permit to Drill application for Blossom 1, but as I recall no one at Hilcorp knows where it came from. Please information regarding the depth to the base of freshwater at the GO Pad that utilizes recent logs/mudlogs so that I may verify Hilcorp's conclusions. Regards, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue,Suite 100 Anchorage,AK 99501 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or From: Davies, Stephen F (DOA) Sent: Monday, May 04, 2015 3:49 PM To: Monty Myers (mmyers@hilcorp.com) Subject: GO 8 (PTD # 215-077) Permit to Drill Application: Questions Monty, The footage coordinates listed for the surface location for the proposed GO 8 well on the Permit to Drill application form are slightly different(-12') than those presented on the accompanying surveyor's plat. Which coordinates are correct? Please submit a revised surveyor's plat if necessary. 2 IP • The northing and easting State Base Plane coordinates for the surface location on the Permit to Drill application form are about 30' different from those presented on Halliburton's proposed directional survey. Which coordinates are correct? Please submit a revised proposed directional survey if necessary. The formation tops list on page 49 presents the total depth of the well as being 12067' MD. On the Permit to Drill application form, the total depth of the well is listed as 13100' MD. I'm suspect that the measured depths for the other formation tops in this list are also incorrect. Could Hilcorp please submit a revised formation top list? I've just started my review of this application, so other questions may follow under separate cover. Regards, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue,Suite 100 Anchorage,AK 99501 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. 3 • • Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Monday, May 04, 2015 4:50 PM To: Monty Myers (mmyers@hilcorp.com) Cc: Schwartz, Guy L (DOA) Subject: FW: GO 8 (PTD # 215-077) Permit to Drill Application: Questions Monty, Please provide information to support Hilcorp's statement on page 7 of the application: All known potential fresh water zones exist above 200'. This information is based off salinity calculations of neighboring water wells. Chlorides are 1100 ppm at the 171 -194'sand, 1800 ppm at the 505—535'sand, and 6000 ppm at the 1040' sand. Furthermore, the TGAS (total gas) curve from offset mud logs begins registering shallow gas at depths just below the sandstone bed at 200'. Hilcorp included this same standardized text in the Permit to Drill application for Blossom 1, but as I recall no one at Hilcorp knows where it came from. Please information regarding the depth to the base of freshwater at the GO Pad that utilizes recent logs/mudlogs so that I may verify Hilcorp's conclusions. Regards, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue,Suite 100 Anchorage,AK 99501 CONFIDENTIALITY NOTICE: This e-mail message,including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you,contact Steve Davies at 907-793-1224 or From: Davies, Stephen F (DOA) Sent: Monday, May 04, 2015 3:49 PM To: Monty Myers (mmyers@hilcorp.com) Subject: GO 8 (PTD # 215-077) Permit to Drill Application: Questions Monty, The footage coordinates listed for the surface location for the proposed GO 8 well on the Permit to Drill application form are slightly different("'12')than those presented on the accompanying surveyor's plat. Which coordinates are correct? Please submit a revised surveyor's plat if necessary. 1 • The northing and easting State Base�Plane coordinates for the surface location on the Permit to Drill application form are about 30' different from those presented on Halliburton's proposed directional survey. Which coordinates are correct? Please submit a revised proposed directional survey if necessary. The formation tops list on page 49 presents the total depth of the well as being 12067' MD. On the Permit to Drill application form, the total depth of the well is listed as 13100' MD. I'm suspect that the measured depths for the other formation tops in this list are also incorrect. Could Hilcorp please submit a revised formation top list? I've just started my review of this application, so other questions may follow under separate cover. Regards, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue,Suite 100 Anchorage,AK 99501 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. 2 • OVERSIZED DOCUMENT INSERT This file contains one or more oversized documents. These materials may be found in the original hard file or check the parent • folder to view it in digital format. • • TRANSMITTAL LETTER CHECKLIST WELL NAME: -67,-455iyi(. L-1-5A-c4--P6 PTD: Z / C:.j 7 /Development Service Exploratory Stratigraphic Test Non-Conventional FIELD: ,�/ i Odil i/C% 1lG_. POOL: /C✓%�1 Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10'sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non-Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a)authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application,the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion,suspension or abandonment of this well. Revised 2/2015 . . 0 a m > E �0 aa)) y- , , , m U) I m C C O C °, 0 E, a y m Z o, q ca) 0 _ O . r• . E. �, , to y, a), a 3 2-) n, a a) g, aYi L W 0 • "'� Oi y 't -O N as 0 w8. 3 , , , , 3, o, E' as, o m v p a. °. a°), . . , . . . , g. o, p, O CO N c Q. ' y, �, E y' .c�, -o ° u_ n E O c. a3 o m ,�� y, a co" 0, �� C w w N , gQotn a , Q M �, o) io f0 v ' m o O 7+ y Q , f6, - M, O. N, �, @ U LL Z, , '0� ,. 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Q -' : _ g a>), a a, E, € c -' 3a),' a c, c, '°t. 1-; F- F-' 'w. a "D, a 6', c' a. a. o, o. a cL), €. w, .N, m. c. m m, af°i. c. 0' 0' 0' 7, v d d a, 0, 0 a) - 1 o o, 7, 2, 5, a) v, f6 v, v -, O, O, .c, a) a) o a), a), o, o a J � �; 3, 3; cii '--; oO; a a, 0 ; a; o: U, co' U, U, U', U. Q, -, Q, -, o, m, m, U , o' ' a; o' co' W °' O N M tO c0 n a0 °f O '. N M V to c0 `c:", 00 °) O N M to CO - CO 0) I E .- N M er to co t` a0 °) N N N N N N N N N N M M M M CM M M M M ✓ o I- U to to to •• ca m ca CD 0 m'- ci co OW. tO C c0 to aoi E N y a) co 0 E 4. ••C a. Q C Q O a o 0 A' a E a LL c) d J O d tL a ¢ Q w Q O Q U) 1110 Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. 1 Grassim Oskolkoff #8 Ninilchik Unit Kenai Peninsula Borough, Alaska July 23, 2015 – August 10, 2015 Provided by: Approved by: Dave Buthman Compiled by: Craig Silva, Ralph Winkelman Tollef Winslow Distribution Date: August 18, 2015 2 TABLE OF CONTENTS 1 MUDLOGGING EQUIPMENT & CREW ............................................................................................... 3 1.1 Equipment Summary.................................................................................................................... 3 1.2 Crew .......................................................................................................................................... 3 2 GENERAL WELL DETAILS ................................................................................................................ 4 2.1 Well Objectives ........................................................................................................................... 4 2.2 Hole Data ................................................................................................................................... 4 2.3 Daily Activity Summary ................................................................................................................ 5 3 GEOLOGICAL DATA ......................................................................................................................... 9 3.1 Lithostratigraphy ......................................................................................................................... 9 3.2 Lithology Details .......................................................................................................................... 9 3.3 Sampling Program ..................................................................................................................... 21 4 DRILLING DATA .............................................................................................................................. 22 4.1 Surveys .................................................................................................................................... 22 4.2 Bit Record ................................................................................................................................ 27 4.3 Mud Record .............................................................................................................................. 28 5 SHOW REPORTS............................................................................................................................ 29 6 DAILY REPORTS ............................................................................................................................ 30 Enclosures 2” / 100’ Formation Log (MD/TVD) 5” / 100’ Formation Log (MD/TVD) 2” / 100’ LWD Combo Log (MD/TVD) 2” / 100’ Drilling Dynamics Log (MD/TVD) 2” / 100’ Gas Ratio Log (MD/TVD) Final Data CD 3 1 MUDLOGGING EQUIPMENT & CREW 1.1 Equipment Summary Parameter Equipment Type /Position Total Downtime Comments Computers – Surface Logging (3) Rigwatch Server, Rigwatch Remote DML, LWD WITS, Rigwatch Remote 0 Ditch gas QGM gas trap; Flame ionization total gas & chromatography. 0 Hook Load / Weight on bit WITS from Pason 0 Mud Flow In Derived from Strokes/Minute and Pump Output 0 Mud Flow Out WITS from Pason 0 Pit Volumes, Pit Gain/Loss WITS from Pason 0 Pump Pressure WITS from Pason 0 Pump Stroke Counters (2) WITS from Pason 0 Rate of Penetration Calculated from Pason 0 RPM WITS from Pason 0 Torque WITS from Pason 0 WITS To/ From Pason Rigwatch Remote (HP Compaq) 0 1.2 Crew Mud Logging Unit Type: Arctic Mud Logging Unit Number: ML030 Logging Geologists Years1 Days2 Sample Catchers Years Days2 Craig Silva 30 11 Doug Merkert 6 13 Ralph Winkelman 24 22 Karen Austin 4 13 Tollef Winslow 7 10 Frank Thrailkill 3 3 *1 Years experience as Mudlogger *2 Days at wellsite between rig up and rig down of logging unit. 4 2 GENERAL WELL DETAILS 2.1 Well Objectives GO #8 is a development Tyonek and Beluga well. Primary objectives are Upper Beluga through Tyonek T20 reservoir sandstones. While drilling, we will establish the top of the Tyonek structure in order to determine whether or not to drill the well to its planned TD. Operator: HILCORP ALASKA, LLC Well Name: Grassim Oskolkoff #8 Field: Ninilchik Unit County: Kenai Peninsula Borough State: Alaska Company Representatives: Shane Barber, Rick Brumley, Marvin Rogers, Rance Pederson Location: Surface Coordinates 3374’ FSL, 2726’ FEL, Sec 23, T1N, R13W, SM, AK Ground ( Pad ) Elevation 162.40’ AMSL Rotary Table Elevation 180.40’ AMSL Classification: Development - Gas API #: 50-133-20651-00-00 Permit #: 215-077 Rig Name/Type: Saxon 169 / Land / Double Spud Date July 23, 2015 Total Depth Date: August 10, 2015 Total Depth 10200’ MD / 5577’ TVD / -5394’ TVDSS Primary Targets Beluga 50, Tyonek, T6, T20 Primary Target Depths Beluga 50: 4609’ MD / 2104‘ TVD, Tyonek: 8198’ MD / 3582’ TVD T6: 8609’ MD / 3989’ TVD, T20 9727’ MD / 5099’ TVD Total Depth Formation: Tyonek Completion Status: 4.5” Liner LWD-MWD Services. Halliburton/ Sperry Drilling Services Directional Drilling Halliburton/ Sperry Drilling Services Wireline Logging Services None Drilling Fluids Service Halliburton/ Baroid 2.2 Hole Data Hole Section Max Depth TD Formation MW ppg Dev oinc Csg Dia Shoe Depth FIT ppg MD (ft) TVD (ft) MD (ft) TVD (ft) 13 ½” 3500’ 1845’ Beluga 9.4 75.26 10 ¾” 3492’ 1843’ 11.6 9 7/8” 7474’ 2950’ Beluga 9.5 44.51 7 5/8” 7466’ 2942’ 12.5 6 ¾” 10200’ 5577’ Tyonek 9.5 5.82 4 ½” 10198’ 5577’ NA 5 2.3 Daily Activity Summary 7/22/2015: Winkelman and Silva arrive on location and rig up. 7/23/2015: Continue picking up drill pipe and racking back in derrick. Replace hose on service loop. Splice hose. Continue picking up drill pipe and racking back in derrick. Function test diverter (23 sec for knife valve to open, 44 sec for bag to close). Perform accumulator drawdown test. Pick up/prep combo jars and lay down. Hold PJSM with crew procedures for picking up and making up BHA. Pick up and make up motor, bit, stabilizer, DM/TM collars, flex collars and subs. Drill out conductor and Spud Well. Drill from 133’ to 300’ (picking up and making up HWDP while drilling ahead). Circulate out. POOH 3 stands of HWDP. Pick up and make up two (2) 6 ¾” monels, jars and HWDP single. Drill ahead, rotating and sliding from 300’ to 1167’. Pump and circulate around Hi -Vis sweep (and observe 25% increase in cuttings). Pull out of hole from 1167’ to 272’ on Wiper Trip. Service drawworks. Level subbase. Run back in hole from 272’ to 1105’. Wash and ream through tight spot at 970’ on way in. 7/24/2015: Wash and ream last stand back to bottom from 1105’ to 1167’. Record 9 units of Wiper Gas. Drill ahead, rotating and sliding, from 1167’ to 2360’. 7/25/2015: Drill ahead, rotating and sliding, from 2360’ to 2407’. Note constant maintenance keeping possum belly clean and free of clay. Pump 20 bbl Hi -Vis/Nut Plug sweep at 2363’, and record 100% increase in cuttings with significant very large clay balls. At 2407’ observe large solid mass of clay filling flowline, possum belly and conductor annulus to bell nipple when circulating bottoms up. Slowly circulate and clear clay mass, and then circulate additional bottoms up to clean up hole. Perform wiper trip from 2407’ to 1102’. Backreaming required in many spots on way out. Service rig. Run back in hole from 1102’ to 2092’. No tight spots on way in. Pick up, make up, drift and run in 10 joints (5 stands) of HWDP off catwalk for push pipe. Wash down last joint to bottom from 2381’ to 2407’ with no fill. Drill ahead, rotating and sliding, from 2407’ to 3020’. Continue frequent maintenance keeping possum belly free of clay, and pumping occasional sweeps to clean hole. 7/26/2015: Drill ahead, sliding and rotating, from 3020’ to 3113’. Continue drilling ahead, rotating only, from 3113’ to surface casing point at 3500’. Begin circulating around H-Vis sweep while circulating bottoms up. Clean hole for wiper trip. POOH with elevators from 3500’ to 3385’. Pull out of hole, backreaming, from 3385’ to 2400’. Continue pulling out of hole with elevators (and no tight spots) from 2400’ to 735’. Circulate 18 minutes at 530 gpm. Service drawworks, topdrive, and blocks. Run back in hole from 735’ to bottom at 3500’. Circulate bottoms up three times and clean hole. Pump around Hi -Vis sweep and observe 10% increase in returns 600 strokes early. POOH from 3500’ to 2185’. 7/27/2015: Continue POOH from 2185’ to 173’. Rack back flex collars in derrick. Break and lay down TM and DM collars, stabilizer, motor and bit. Clean and organize rig floor. Pick up johnny -wacker and jet out clay around wear bushing. Pull wear bushi ng. Clear and clean rig floor. Rig up Weatherford 10-3/4” casing running equipment. Change elevators and elevator links. Rig up power tongs and spider. Rig up fill-up line. Prep rig floor for running casing. Load racks with casing. Follow all casing running procedures as per Hilcorp Plan. Pick up and make up shoe track. Test floats. Pick up, make up and run 10 ¾” casing in hole, filling on way in, to 2017’. Circulate casing volume. Continue running 10 ¾” casing in hole, filling on way in, to 3468’. Make up landing joint and complete running casing to 3492’. Make up circulating swage and circulate hole volume while rigging up Schlumberger cementers. Rig up cementing head with top and bottom plugs correctly loaded. Hold pre-job meeting with all hands on safety and operating procedures for cement job. Finish circulating. Follow all cementing procedures as per Hilcorp Plan. Pump 5 bbls of water and pressure test lines to 3000psi. Pump 45 bbls of 10.0ppg mud push with the rig pumps at 3.2 bpm and then switch over lines to Schlumberger pumping unit. Pump 387.9 bbls of 12.0ppg lead cement, and follow with 72.5 bbls of 15.2ppg tail cement. Drop top plug and displace cement with 328 bbls of 9.5ppg spud mud. Plug did not bump. Hold column with 440 psi pressure. Check floats and floats held. Prep to rig down cementing head and cement lines. 6 7-28-2015: Rig down cementing head and Schlumberger cement lines. Begin cleaning cement out of cellar box. Remove landing joint. Begin cleaning pits. Nipple down diverter tee. Clean cement from wellhead profile. Install pack-off. Continue cleaning pits. Continue cleaning cement out of cellar area. Nipple up multi-bowl wellhead and then pressure test to 3000psi for 15 minutes. Finish cleaning pits and then load on stored KCL/Polymer mud from Atigun tanks to be centrifuged. Hang BOP stack off of stack-handler. Install hydraulic fittings on BOPs. Prep 2’ spacer spool for installation and then install. Stack and align BOPs on spacer spool. Install choke hose to BOPE and to catwalk. Torque bolts on BOP flanges. Install kill line. 7-29-2015: Install flow box, flow nipple, and flow line. Chain stack. Spot and raise gas buster. Rig up test equipment. Flood stack and choke manifold with water. Perform shell test of BOPs. Test all BOPE (Tests 1-10). Test annular to 250psi Low / 2500psi High. Test all other BOPE to 250psi Low / 4000psi High. (1: annular, inside kill, inside choke; 2: CMVs 1-3-4-5-7, mezzanine kill, upper IBOP; 3: CMVs 2-4-5-6-8, kill, HCR, dart, lower IBOP; 4: electric choke, manual choke, inside kill, TIW; 5: CMVs 7-9-11-13, inside kill, TIW; 6: dart, inside kill, HCR; 7: dart, inside kill, inside choke; 8: lower pipe rams, dart; 9: accumulator drawdown performance; 10: blind rams, CMVs 7-10-12, inside kill). Rig down test equipment. Install wear bushing with 10” ID. Pick up, make up and run in BHA #2. Function test MWD-LWD tool electronics. Pulse test MWD tool. Load radioactive sources in CTN collar. Continue making up and running in BHA to 424’. Make up additional stands of HWDP running in, and then lay down 9 joints. Single in hole with 94 joints of 4 ½” drill pipe from 424’ to cement stringer tag-up at 3316’. Begin and continue circulating thick mud out of hole. 7-30-2015: Finish circulating out thick (cement -contaminated) mud. Prep for casing test. Test casing to 2600psi for 30 minutes. Wash down from 3316’ and tag first rubber at 3333’. Drill out cement, float debris and shoe track from 3333’ to 3500’. (Note float collar at 3409’, casing shoe at 3491’, 8’ of rathole to 3500’). Drill 20’ of new 9 7/8” hole from 3500’ to 3520’. Circulate bottoms up and clean hole for FIT. Attempt to test to 12.0ppg EMW, but failed to hold pressure. Bleed-off was continuous. Checked all equipment for leakage and could not find issue. Re- tested but pressure still would not hold. Discussed options with town. Decision made to drill deeper and re-test. Drill 10’ of hole from 3520’ to 3530’ while displacing spud mud with 9.2ppg KCL mud. Circulate bot toms up and clean hole for FIT. Perform FIT test (with 9,2ppg MW). Successfully pressure up and hold on FIT to 11.6ppg EMW. Drill ahead, rotating and sliding, from 3530’ to 3953’. Re-torque thread saver sub and backup clamp. Drill ahead, rotating and sliding, from 3953’ to 4076’. 7-31-2015: Drill ahead, rotating and sliding, from 4076’ to 4819’. Circulate bottoms up. Pump around tandem 20 bbl sweeps (Lo-Vis/Hi -Vis). Circulate hole clean. POOH from 4819’ to 3453’. Note 30K overpull at 4355’, 3786’, 3690’ on way out. Kelly up topdrive at 3690’ and backream from 3690’ to 3490’ (with 1.8 bbls over calculated fill). Service rig. Check topdrive end play and backlash with rig mechanic. Change oil in drawworks. Grease crown, drawworks, wash pipe and blocks. Change out saver sub. Adjust topdrive drilling torque up to 16500 lbs. Single in hole 20 joints of 4 ½” drill pipe from 3450’ to 4070’. Continue to run back in hole with stands out of derrick from 4070’ to 4757’. (Observe tight spot at 4345’ on way in). Note that 5 stands of HWDP “push pipe” were moved and repositioned up the drill string. Wash down last stand to bottom from 4757’ to 4819’ with no fill. Drill ahead, rotating and sliding, from 4819’ to 5005’. 8-01-2015: Drill ahead, rotat ing and sliding, from 5005’ to 5108’. Change swab on pump #2. Drill ahead, rotating and sliding, from 5108’ to 5874’. Pump around tandem 20 bbl sweeps (Lo-Vis/Hi -Vis). Observe no increase in cuttings volume. Centrifuge packing off. Flow check well and note mud loss at rate of 6 bph. Change shaker screens (to 200s) and line up to pump mud across shakers and condition mud while tripping. Pull out of hole on wiper trip from 5874’ to 4577’. Note tight zones at 5360’-5330’ and 4846’-4790’ (with swabbing ) on way out. Record 4.5 bbls over calculated displacement for trip. Service topdrive, blocks and drawworks. Run back in hole from 4577’ to 5812’. Kelly up and wash down last stand to bottom from 5812’ to 5874’ with no fill. Drill, rotating and sliding, from 5874’ to 5924’. 8-02-2015: Drill ahead, rotating and sliding from 5924’ to 6680’. Pump tandem sweeps of 20 BBLS each: low/l and high / h. Circulate hole clean for a wiper trip. Check hole for flow: static. Pull out of hole from 6680’ to 5620 with tight spots at 6265’, 6238’, 6157’, 6105, and 5760’. The hole over displaced by 11 BBLS. Service the crown, draw woks and wash pipe. Trip in hole from 5620’ to 6680’, wash down the last stand, no fill. Change the shaker screens from 200’s to 140’s. Drill ahead from 6680’ to 6737’ 7 8-03-2015: Drill ahead, rotating and sliding from 6767’ to 6928’. Ibop began to leak. Ibop replaced. Drill ahead, rotating and sliding from 6928’ to 7474’. Circulate bottoms up to confirm formation lithology. Pump tandem sweep. Circulate sweep out of hole. Check for well flowing. No flow. Prepare to pull out of hole on elevators. 8-04-2015: Pull out of hole from 7474’ to 3470’ (10 ¾” casing shoe) with tight spots at 6951’, 6527’, 5578’ and 5340’. The hole was displaced over 9 barrels (calculated). Service the top drive, blocks, crown and draw works. Trip in hole from 3470’ to 7474’ filling the pipe every 20 stands; no tight spots were encountered. A high viscosity sweep was pumped and the hole was circul ated clean with 56 units of wiper gas at bottoms up. The well was flow checked and found static. The string was pulled out of the hole from 7474’ to 424’ on elevators with no tight spots or other issues encountered. The hole was displaced over 16 barrels (calculated). The bottom hole assembly (BHA) was laid down, nuclear source was removed, logging while drilling tools were downloaded and then the rest of the bottom hole assembly was laid down. The rig floor was organized and cleaned. The wear ring was pulled. Change out upper pipe rams for 7 5/8”. Install BOP test plug. Begin testing 7 5/8” upper pipe ram. 8-05-2015: Tripping in hole with 7 5/8" casing from 6850' to 7440', pick up landing joint and land at 7466'. Circulate casing at 5 bbl/min and begin rigging up cementing equipment. Flush 10 bbls water to cuttings box and pump 5 bbls down hole with cement truck. Test lines to 1,000 / 5,000 psi and pump 25 bbls 11 ppg mud with rig pump, drop bottom plug. SLB pump 235 bbls 12.5 ppg lead and then 70 bbls 15.3 ppg tail. Drop top plug. Displacement pump 20 bbls of water and 321 bbls mud and bump plug 500 psi over final circulating pressure. Bleed back and check floats. Rig down cement equipment. 8-06-2015: Finish changing uppers from 7 5/8 to 4.5 VBRS and rig up test equipment. Test upper at 250 psi for 5 minutes and 4000 psi for 10 minutes. Rig down test equipment and pull test plug. Install wear bushing (9 1/16 ID). Stage BHA, strap 80 joints of drill pipe to single in. Perform rig service. Make up bit and BHA, download pulse test and load sources. Single in hole from 609' to 2160'. Continue running in hole while occasionally filling pipe to 7,366'. Pressure up to 3500 psi for 30 minutes for casing pressure test while slip and cut drill string 8-07-2015: Good casing test of 3500 psi for 30 minutes. Cut and slip 105’ of drill line during casing test. Tagged cement @ 7373’. Drilled cement from 7373’ to 7373’. The float collar was found at 7378’. Shoe depth was 7460’. Drill 20’ of new formation from 7474’ to 7494’. Circulate bottoms up. Perform FIT test: target = 462 psi for a 12.5 ppg EMW, test good to 12.5 ppg EMW. Drill ahead: rotating and sliding from 7494’ to 8222’ 8-08-2015: Drill ahead: rotating and sliding from 8222’ to 8541’. Pump sw eep and prepare for wiper trip. Pull out of hole on elevators from 8541’ to 7122’, no difficulties encountered. The hole over displaced by 1.6 barrels. Service the draw works, check the brake and the Eaton brake, grease the crown, top drive and blocks. Trip in hole from 7122’ to 8541’, no issues, 49 units of wiper gas. Drill ahead, rotating and sliding from 8541’ to 9188’. 8-09-2015: Drill ahead, rotating and sliding from 9188’ to 9475’. A tandem sweep was pumped to circulate hole clean. Performed f low check to confirm the well was static. Pull out of hole on elevators from 9475’ to 6800’; tight spot at 8799’ and 8373’, the hole took 3 additional barrel of fluid over theoretical volume during the trip. The rig was serviced including greasing the draw works, blocks, crown and checking the brakes. Trip in hole while installing turbulizers every other stand from 6800’ to 9475’. Turbulizers installed to reduce torque. 180 units of wiper trip gas upon circulating bottoms up. Drill ahead, rotating and sliding from 9474’ to 10117’. 8-10-2015: Drill ahead, rotating from 10117’ to 10200’. 10200’ MD is the total depth of the well. Circulate bottoms up then pump two tandem sweeps to clean the hole. The well was flow checked and it was static. Pull out of hole from 10200’ to 7450’ on elevators with no tight spots. The well over displaced by five barrels. Trip in hole from 7450’ to 10140’ on elevators with no tight spots. The hole displacement was 0.5 barrels under displacement. The hole was circulated clean and 250 units of wiper gas were observed with a 10% increase in cuttings. Pulled out of the hole from 10200’ to 9875’ and the checked the well for flow. The well was static. A dry job was pumped. Pulled out of the hole on elevators from 9875’ to 3024’, laying down the turbuliezers. Flow checked at the shoe, the well was static. Continued to pull out of the hole from 3024’ to 609’ laying down the drill pipe. Lay down directional tools and logging while drilling tools including removing the nuclear source and downloading the memory data. Performed general housekeeping. Removed the wear ring. Installed the test plug. Prepared to test BOP. 8 8-11-2015: Test Choke manifold. Test BOP's. Remove test plug and rig down test equipment. Rig up Weatherford power tongs and spider elevators. Make up shoe track. Test float. Run in hole with 4.5” liner to 2898’. Rig down Weatherford power tongs and spider elevators. Make up hanger packer running tool assembly. Run in hole with 4.5” liner from 300’ to 7400’, filling every 10 stands. Circulate at shoe. Continue running in the hole from 7400’ to 10174’. Fill found at 10174’. Wash down from 10174’ to 10200’. Tag bottom at 10200’. Circulate bottoms up. 267 units of wiper gas observed. 9 3 GEOLOGICAL DATA 3.1 Lithostratigraphy Tops provided by Hilcorp Geologist. FORMATION PROGNOSED ACTUAL MD (ft) TVD (ft) SSTVD (ft) MD (ft) TVD (ft) SSTVD (ft) Beluga 50 4609’ 2104’ -1921’ 4644’ 2115’ -1932’ Tyonek 8198’ 3582’ -3399’ 8232’ 3622’ -3439’ T6 8609’ 3989’ -3806’ 8660’ 4047’ -3864’ T20 9727’ 5099’ -4916’ 10021’ 5399’ -5216’ TD 10039’ 5406’ -5226 10200’ 5577’ -5394’ 3.2 Lithology Details Full service mudlogging began at 3500’ MD/ 1845’ TVD. All the sample lithology descriptions provided by Canrig began after the surface casing point . The well includes Beluga and Tyonek formations. The basic building blocks in this depositional area ha ve a unique lithology of thick structured formations of tuffaceous sediments. These fluvial deposits are of tuffaceous claystone, tuffaceous siltstone, tuffaceous sandstone s, and lose disaggregated, unconsolidated sands. The ash and tuff are revealed along with devitrified volcanic glasses as loosely (friable) to heavily indurated clasts of volcanic origin. The basal structure to almost all local fluvial deposit s, coals, and carbonaceous shales, are included as minor thinly bedded lithologies. Sand (3500' - 3590') = medium to medium light gray with individual grains dominantly clear to translucent quartz, medium gray, greenish gray; fine lower to medium lower; angular to subangular; moderately well sorted; unconsolidated; trace thin coal beds; continued cement contamination. Tuffaceous Claystone/ Tuffaceous Siltstone (3590' - 3650') = medium gray with medium light gray secondary hues; soft; fragile; crumbly to pulverulent; irregular shaped cuttings; silty to clayey texture; dull luster; poor adhesiveness; poor to fair cohesiveness; moderately to very soluble; slight to moderately expansive; non calcareous; trace thin coals. Sand (3650' - 3700') = medium gray with a salt and pepper appearance, individual grains dominantly clear to translucent quartz and volcanic glass, medium gray; black and light greenish gray; fine lower to medium upper; angular to subangular; moderately well sorted; unconsolidated; non calcareous; trace thin coal beds. Tuffaceous Claystone/ Tuffaceous Siltstone (3700' - 3750') = medium to medium light gray; soft; pulverulent; irregular shaped; silty to clayey texture; dull luster; poor adhesiveness and cohesiveness; soluble and slightly expansive; hydrophilic; non calcareous; trace black microthin carbonaceous laminations and inclusions; continued trace cement contamination. 10 Sand (3750' - 3810') = medium to medium dark gray with a moderate to strong salt and pepper appearance, ind ividual grains dominantly medium to dark gray, black, clear to translucent quartz and volcanic glass, trace greenish gray; very fine upper to trace very coarse upper, dominantly medium; angular to subangular; poor to fair sorting; unconsolidated; non calcareous. Tuffaceous Claystone/ Tuffaceous Siltstone (3810' - 3870') = medium to medium light gray with trace light yellowish gray secondary hues; soft; fragile; irregular; silty to clayey text ure; dull luster; poor adhesiveness and cohesiveness; soluble and slightly expansive; hydrophilic; non calcareous; trace black microthin carbonaceous laminations and inclusions. Sand (3870' -3910') = medium gray with a salt and pepper appearance, individual grains dominantly clear to translucent quartz and volcanic glass, medium gray; dark gray, black, greenish gray; very fine upper to medium lower, dominantly fine; angular to subangular; moderately well sorted; unconsolidated; non calcareous. Sand (3910' - 3950') = medium gray with salt and pepper appearance, dominantly clear to translucent quartz, medium to dark gray, greenish gray; fine lower to medium lower; angular to subangular; moderately well sorted; unconsolidated; non calcareous. Claystone (3960'-4100') = light medium gray to medium gray; strong grayish brown secondary hues; locally higher lightness values when increase in ash (microshard) content; soft to very slightly firm or brittle; hydrophilic; minor expansion and increased separation points as hydration progresses; irregular to subblocky cuttings habit; moderate to poor cohesiveness and adhesiveness; clayey to "ashy" to soft matte to local slightly silty texture; dense earthy luster , with microsparkly highlights as microshard content of ash-derived claystones increases; significant percentage of claystones display spot ty to locally abundant black microthin laminations and floating particles of coal and other carbonaceous material; generally non-calcareous, but weathered, slightly more porous looking rocks have slight effervescence. Tuffaceous Claystone/ Carbonaceous Tuffaceous Claystone/ Carbonaceous Shale/ Coal (4100'-4300') = though rocks are not diverse overall, there are abundant complex variations in texture; and especially significant transitioning from non-carbonaceous group rocks to essentially the same rocks with moderate to abundant carbonaceous content; drilling closer to bedding plane "breaks out" and mixes very thin successive beds of rocks that have different characteristics; dominantly medium gray to medium dark gray tuffaceous claystone with very strong (and locally dominant) brownish gray to brownish black colorization derived from fine carbonaceous and coaly detritus floating in the clay; some zones are clearly the reverse, with interbedded carbonaceous shale and coal that is interrupted by clay/ash sediments; mostly soft and hydrophilic; clays have moderate to good adhesiveness that binds to floating loose sediment and grains; most of the claystones have well-distributed floating sand grains and spotty larger floating coal fragments; coal is: black to grayish black to brownish black; brittle and more often fragile than tough; smooth to dense matte textures; dull to moderately greasy luster; very strong micro-thin planar fracture; many coal fragment will separate into thin flat "greasy" pieces with very little pressure from probe. Sand (4100'-4400') = medium gray to dark medium gray; generally homogeneous color when not influenced by adjacent carbonaceous zones; range very fine upper to medium lower, but mostly moderately well sorted at fine lower to fine upper close to (medium boundary); generally equant dimensions, subrounded - subangular, subspherical shape; pale gray translucent quartz, contrasted with black (and trace colored) mafic minerals and dark gray to black metalithic rock fragments; often "dirty, grayish" salt and pepper; overall appearance is dull bulk grayish non-descript coloration; major occurrence as floating sand grains in claystone. Coal/ Carbonaceous Shale (4200'-4500') = black to brownish black to locally grayish black; smooth to very dense matte texture; dull to resinous or vitreous luster; note one variation of thin laminar coal with greasy luster; brittle and fragile to minor brittle and tough; dominant irregular very thin planar fracture to slight subconchoidal fracture; lignite to minor subbituminous interbedded with, and also grading to carbonaceous shale; note higher grade coal has discreet banding or zoning; no cleating is evident. 11 Tuffaceous Claystone/ Tuffaceous Siltstone (4450' - 4520') = medium to medium light gray with trace very light brownish gray secondary hues; very soft; sticky at times; fragile to pulverulent; irregular, shapeless cuttings with trace pdc bit action shaped; silty to clayey; dull, earthy luster; hydrophilic; moderate to very soluble slight to moderately expansive; poor to fair cohesiveness fair adhesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions. Sand (4520' - 4580') = medium to medium light gray with a moderate to strong salt and pepper appearance, individual grains dominantly medium to dark gray, black, clear to translucent quartz and volcanic glass, trace medium greenish gray; very fine upper to medium upper, dominantly fine upper to medium lower; angular to subangular; moderately well sorted; unconsolidated; non calcareous. Tuffaceous Claystone/ Tuffaceous Siltstone ( 4580' - 4640') = medium light to light gray with trace medium dark gray secondary hues; soft; sticky; fragile to pulverulent at times; irregular to shapeless cuttings; silty to clayey texture; dull to earthy luster; hydrophilic; poor to fair adhesiveness and cohesiveness; non calcareous; trace black microthin carbonaceous laminations and inclusions. Sand (4640' - 4690') = medium light gray overall with moderate salt and pepper appearance, individual grains dominantly medium to dark gray, black, light gray, clear to translucent quartz and volcanic glass; very fine upper to medium lower, dominantly fine; angular to subangular; moderately well to well sorted; unconsolidated; non calcareous. Tuffaceous Claystone/ Tuffaceous Siltstone (4690' - 4760') = medium to medium light gray with trace very light brownish gray secondary hues; very soft; sticky at times; fragile to pulverulent; irregular, shapeless cuttings with trace pdc bit action shaped; silty to clayey; dull, earthy luster; hydrophilic; moderate to very soluble slight to moderately expansive; poor to fair cohe siveness fair adhesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions. Sand (4760' - 4810') = medium to medium light gray with a moderate to strong salt and pepper appearance, individual grains dominantly medium to dark gray, black, clear to translucent quartz and volcanic glass, trace medium greenish gray; very fine upper to medium upper, dominantly fine upper to medium lower; angular to subangular; moderately well sorted; unconsolidated; non calcareous; note 4820' sample contaminated from sweep. Sand (4810'-4980') = medium gray to dark gray with faint olive black to dark brownish gray secondary hues; range very fine upper to medium upper, but overall moderately well sorted at fine lower to medium lower; largest fraction is just below fine -medium boundary; grain dimensions dominantly equant to slightly prismoidal; major subangular to angular, minor subrounded, spotty rounded; dominantly discoidal to subdiscoidal to lesser subspherical, largest grains commonly discoidal; lithic grains generally more rounded than quartz; nearly all cuttings sand is loose and disaggregated; note many subtle examples of very soft hydrated soluble tuffaceous clay matrix support; very dominant compositional graywacke with 30-70% lithics and mafic minerals, 30-50% quartz and clear amorphous silica (volcanic ash derived glass), 15-25% chalcedony, chert, other cryptosilica, various non-differentiated silica, 5-10% feldspar: lithics fraction dominated by phyllite/ argillite meta rock fragments, other non-differentiated dark grayish brown to black vitreous grains. Coal (4800'-5100') = grade of coal is improving overall; lower grade lignite grading to carbonaceous shale almost absent; black to only spotty brownish black or grayish black; smooth to very dense matte texture; dull to increasing vitreous and resinous lusters; becoming tougher and harder overall; dominantly brittle and tough to marginally hard; fracture is more splintery than platy and irregular, and also increasingly blocky and subconchoidal; note trace of birdeye fracture; higher grade lignite to higher grade subbituminous; note common coal with discreet banding or zoning of different grades; trace of coal with micro-thin discontinuous laminations of silica; no significant cleating is evident. 12 Sand (4980'-5300') = medium gray to dark gray with faint olive black to dark brownish gray secondary hues; overall very homogenous appearance; range from very fine lower to medium upper; very fine grains mostly larger shards winnowed from reworked volcanic ash; overall moderately well sorted at fine lower to medium lower; largest fraction is fine upper just below the fine -medium boundary; grain dimensions dominantly equant to very slightly prismoidal; trace medium feldspar grains are long and prismoidal; ang ular to subangular, minor subrounded, trace rounded; dominantly discoidal to subdiscoidal to lesser subspherical, largest grains commonly discoidal and angular; fine lithic grains often more rounded and equant than quartz and feldspar; almost entirely disaggregated sand grains; spotty tiny blebs of very soft hydrated matrix supported sandstone; also localized traces of very fragile silica-cemented sandstone very fine sandstone; very dominant compositional graywacke (>30% lithics), with 35-70% lithics and mafic minerals, 25-50% quartz and clear amorphous silica (volcanic ash derived glass), 15-25% chalcedony, chert, other cryptosilica, various non- differentiated silica, 5-15% feldspar; lithics fraction dominated by medium grade metamorphic medium to dark gray to grayish black phyllite and argillite rock fragments, and smaller but still abundant fraction of other non- differentiated dark grayish brown to black vitreous grains; note trace greenstone rock fragments impart faint overall olive coloration. Sand (5320' - 5380') = medium gray with a weak salt and pepper appearance, individual grains dominantly light to dark gray, greenish gray, black, clear to translucent quartz and volcanic glass; fine lower to trace coarse upper, dominantly fine upper to medium lower; angular to subangular; moderately well sorted to very well sorted; unconsolidated; non calcareous. Sand (5380' - 5420') = medium to medium dark gray with weak salt and pepper appearance, individual grains are medium to dark gray, black, clear to translucent quartz and volcanic glass; very fine upper to very coarse lower, dominantly fine upper to medium upper; angular to subangular; poor to fair sorting; unconsolidated; non calcareous. Tuffaceous Claystone/ Tuffaceous Siltstone (5420' - 5480') = medium light to light gray with trace light olive gray secondary hues; very soft; fragile; irregular shaped; silty to clayey texture; dull to slightly waxy luster; moderate to very soluble; slight to moderately expansive; hydrophilic; poor adhesiveness and cohesiveness; non calcareous; trace dark brown to black microthin carbonaceous lamina tions and inclusions; trace thin coal beds. Sand (5480' - 5540') = medium to medium dark gray with strong salt and pepper appearance, individual grains medium to dark gray, black, clear to translucent quartz and volcanic glass; very fine upper to very coarse lower, dominantly fine upper to medium upper; angular to subangular; poor to fair sorting; unconsolidated; non calcareous; trace thin coal beds. Tuffaceous Claystone/ Tuffaceous Siltstone (5540' - 5610') = medium light gray to light gray with very light gray and light olive gray secondary hues; very soft; fragile; irregular to shapeless, amorphous cuttings; silty to clayey; dull to greasy luster; hydrophilic; very soluble; moderately expansive; poor cohesiveness and adhesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions. Sand (5610' - 5670') = medium to medium light gray with individual grains dominantly clear to translucent quartz and volcanic glass, medium to dark gray and black: very fine lower to medium lower, dominantly fine; angular to subangular; moderately well sorted; dominantly unconsolidated with trace sandstone; dark gray to dark greenish gray; very fine to fine; hard to brittle; slight to moderately calcareous. Tuffaceous Claystone/ Tuffaceous Siltstone (5670' - 5730') = medium light to light gray with trace light olive gray secondary hues; very soft; fragile; irregular shaped; silty to clayey texture; dull to slightly waxy luster; moderate to very soluble; slight to moderately exp ansive; hydrophilic; poor adhesiveness and cohesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions. 13 Sand (5730' - 5860') = medium to medium light gray with salt and pepper appearance, dominantly clear to translucent quartz and volcanic glass, light to dark gray, black; very fine upper to trace coarse upper, dominantly fine upper to medium lower; angular to subangular; fair to good sorting; unconsolidated; non calcareous; note 20% baracarb (crushed marble) present in samples. Tuffaceous Claystone/ Tuffaceous Siltstone (5790’ - 5860') = medium light gray with light gray and light olive gray secondary hues; soft; fragile; sticky at times; irregular to shapeless, amorphous cuttings; silty to clayey texture; dull to greasy luster; hydrophilic moderate to very soluble and expansive; poor to fair cohesiveness; fair adhesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions. Sand/ Sandstone (5860'-6000') = medium dark gray to dark gray with very faint olive gray to brownish gray secondary hues; appears very homogenous; overall moderately well to well sorted at fine upper; range very fine upper to medium lower; very fine fraction has abundant shards winnowed from volcanic ash; equant to very slightly elongated grain dimensions; diverse range of angular to rounded, and discoidal to spherical; dominant subangular to subrounded, subdiscoidal to subspherical; abundant disaggregated sand, but local fractions of fine consolidated grain supported sandstone with mixed calcite and silica cementation that ranges from friable and crunchy to marginally hard; also note trace blebs of very soft hydrated soluble tuffaceous clay matrix supported sandstone that is apparent source of post-washing loose sand; continued compositional graywacke (>30% lithics); 30-65% lithics and mafic minerals,30-50% quartz and volcanic-derived amorphous silica, 10- 25% chalcedony, chert, other cryptosilica, non-differentiated silica, 5-15% feldspar; abundant lithics dominated by medium grade metamorphic dark gray to grayish black phyllite (>65% of total rock fragme nts), argillite (15%) and significant fraction of non-differentiated dark grayish brown to black vitreous grains (15%); note greenstone rock fragments impart faint overall olive coloration. Coal (5800'-6100') = consistently fine coal fragments; only spotty lower grade coal grading to lignite; black to minor brownish black or grayish black; smooth to very dense matte texture; dull to shiny vitreous and resinous luster; brittle and fragile to brittle and tough to marginally hard; dominantly splintery slightly irregular fracture, lesser blocky-conchoidal or subconchoidal fracture, platy fracture and various irregular; note trace of birdeye fracture; higher grade lignite to higher grade subbituminous; note common coal with discreet banding or zoning of different grades; trace of coal with micro-thin discontinuous laminations of silica; no significant cleating is evident. Tuffaceous Claystone/ Tuffaceous Siltstone (6170' - 6240') = medium light to light gray with light brownish gray secondary hues; very soft; fragile; sticky at times; irregular to shapeless with trace pdc bit action shaped cuttings; silty to clayey texture; dull, earthy to slightly waxy luster; hydrophilic; very soluble; slight to moderately expansive; poor to fair cohesiveness and adhesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; trace thin coal beds Sand (6240' - 6290') = medium gray, individual grains dominantly clear to translucent quartz and volcanic glass, light to dark gray, black; very fine upper to medium lower, dominantly fine; angular to subangular; moderately well to very well sorted; unconsolidated; non calcareous. Tuffaceous Claystone/ Tuffaceous Siltstone (6290' - 6360') = medium light gray with light gray and light olive gray secondary hues; soft; fragile; sticky at times; irregular to shapeless, amorphous cuttings; silty to clayey texture; dull to greasy luster; hydrophilic; moderate to very soluble and expansive; poor to fair cohesiveness; fair adhesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; trace thin coal beds Coal (6310' - 6440') = black with brownish black secondary hues; finely ground, platy to flaky and elongated; very firm to hard and brittle; planar fracture dominant; slightly earthy to resinous luster; smooth to slightly gritty texture; subbituminous and grading to a less developed carbonaceous shale; trace outgassing bubbles from larger fragments. 14 Tuffaceous Claystone/ Tuffaceous Siltstone (6400' - 6480') = medium light to light gray with light olive gray secondary hues; very soft; fragile; sticky at times; irregular to shapeless with trace pdc bit action shaped cuttings; silty to clayey texture; dull, earthy to slightly waxy luster; hydrophilic; very soluble; slight to moderately expansive; poor to fair cohesiveness and adhesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; trace thin coal beds throughout interval. Sand (6480' - 6540') = medium to medium light gray with salt and pepper appearance, dominantly clear to translucent quartz and volcanic glass, light to dark gray, black; very fine up per to medium upper, dominantly fine; angular to subangular; fair to good sorting; dominantly unconsolidated with trace sandstone; dark gray with strong salt and pepper appearance; fine to medium; hard to brittle; slight to moderately calcareous. Tuffaceous Claystone/ Tuffaceous Siltstone (6540' - 6600') = medium light to light gray; soft; sticky; irregular with pdc bit action shaped cuttings; silty to clayey texture; dull, earthy to waxy luster; hydrophilic; moderate to very soluble and expansive; poor to fair cohesiveness; fair to good adhesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; continued thin coal beds. Sand (6600' - 6680') = medium gray with a weak salt and pepper appearance, individual grains dominantly light to dark gray, greenish gray, black, clear to translucent quartz and volcanic glass; fine lower to medium upper, dominantly fine upper to medium lower; angular to subangular; moderately well sorted to very well sorted; dominantly unconsolidated; non calcareous; continued thin coal beds throughout. Sand (6680' - 6710') = medium light gray to light gray; upper fine to lower fine, occasional upper very fine or lower medium; sub prismoidal to sub discoidal; angular to sub angular; well sorted; unconsolidated; texturally immature; compositionally mature; quartz, translucent or transparent; 90%; coal, black, moderately hard, splintery fracture, massive cuttings habit, laminae structure; porosity and permeability visually good. Tuffaceous Siltstone (6710' - 6740') = medium light gray to medium gray; friable to firm friable; moderately indurated; brittle to crumbly tenacity; irregular to blocky fracture; sub tabular to wedgelike cuttings habit; earthy luster; silty to clayey texture; massive to laminae structure; sand, quartz, fine, sub prismoidal, angular, well sorted, unconsolidated. Sand (6740' - 6860') = medium gray to medium light gray; lower fine to upper fine with occasional upper medium and lower coarse; spherical to sub discoidal; angular to sub angular; well to moderately well sorted; unconsolidated; texturally immature; compositionally mature; quartz, translucent to transparent; tuffaceous siltstone, coal; porosity and permeability visually good. Sand (6860' - 6920') = medium light gray to medium gray; upper fine to lower fine with occasional lower coarse; spherical to sub discoidal; angular to sub angular; well to moderately well sorted; unconsolidated; texturally immature; compositionally mature; quartz, translucent to transparent; tuffaceous siltstone, coal; porosity and permeability visually good. Tuffaceous Claystone/ Tuffaceous Siltstone (6920' - 6980') = medium light to light gray with trace light olive gray secondary hues; soft; fragile to pulverulent; irregular, finely ground up cuttings; sticky at times; silty to clayey texture; dull to slightly greasy and waxy luster; hydrophilic; moderately soluble and expansive; non calcareous ; trace dark brown to black microthin carbonaceous laminations and inclusions. Coal (6980' - 7030') = black with brownish black secondary hues; finely ground, platy to flaky and elongated; very firm to hard and brittle; planar fracture dominant; slightly earthy to resinous luster; smooth to slightly gritty texture; subbituminous and grading to a less developed carbonaceous shale; present as thin beds in dominantly a sand formation throughout interval. 15 Sand (7030' - 7080') = medium light to light gray overall with individual grain dominantly clear to translucent quartz and volcanic glass, light to dark gray, black and trace light greenish gray; very fine upper to fine upper; angular to subangular; very well sorted; unconsolidated; non calcareous. Sand (7080' - 7110') = medium light gray individual grains dominantly clear to translucent quartz and volcanic glass, light to dark gray, black, greenish gray very fine upper to fine upper; angular to subangular; moderately well to very well sorted; unconsolidated; non calcareous. Coal (7110' - 7170) = black with brownish black secondary hues; moderately hard to brittle; finely ground cuttings, flaky to platy; planar fracture dominant with trace conchoidal; vitreous to resinous luster; smooth to matte texture; subbituminous to bituminous; trace prolonged visible outgassing bubbles from larger fragments. Sand (7170' - 7230') = medium light gray to light gray with a weak salt and pepper appearance, individual grains dominantly clear to translucent quartz and volcanic glass, light to dark gray, black and trace light greenish gray; very fine upper to medium lower, dominantly fine; angular to subangular; moderately well to very well sorted; unconsolidated; non calcareous. Tuffaceous Claystone/ Tuffaceous Siltstone (7230' - 7290') = medium light to light gray with trace light olive gray secondary hues; soft; fragile to pulverulent; irregular, finely ground up cutting s; sticky at times; silty to clayey texture; dull to slightly greasy and waxy luster; hydrophilic; moderately soluble and expansive; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; trace thin coal beds throughout interval that is dominantly unconsolidated sand. Sand (7290' - 7340') = medium light to light gray overall with individual grain dominantly clear to translucent quartz and volcanic glass, light to dark gray, black and trace light greenish gray; very fine upper to fine upper; angular to subangular; very well sorted; unconsolidated; non calcareous. Sand (7340' - 7380') = medium light to light gray overall with individual grain dominantly clear to translucent quartz and volcanic glass, light to dark gray, black and trace light greenish gray; very fine upper to fine upper; angular to subangular; very well sorted; unconsolidated; non calcareous. Sand (7380' - 7460') = medium gray to medium light gray; upper fine to lower fine; spherical to sub discoidal; angular to sub angular; well to moderately well sorted; unconsolidated; texturally immature; compositionally mature; quartz, translucent to transparent; tuffaceous siltstone, coal; porosity and permeability visually good. Tuffaceous Siltstone (7460' - 7474') = medium gray to medium dark gray; easily friable; poor induration; crumbly tenacity; earthy fracture; massive cuttings habit; silty texture. Tuffaceous Siltstone (7474' - 7540') = medium gray to dark greenish gray; soft to easily friable with occasional firmly friable; very poor to slightly moderate induration; pulverulent to crumbly; massive cuttings habit; silty to slightly clayey texture; earthy luster moderate hcl reactions Sand (7540' - 7620') = medium dark gray to dark gray with scattered dark greenish gray; upper fine to lower coarse grading towards lower fine to lower medium; moderate to high sphericity; subrounded to subangular; moderately sorted grading into well sorted; unconsolidated; texturally immature and compositionally mature; quartz dominated; moderate to strong hcl reaction; tuffaceous siltstone and coal present early and grades out gradually. Coal (7620' - 7670') = black with grayish black and brownish black secondary hues; hard; brittle; platy to flaky to massive; planar fracture dominant with conchoidal and birdeye common; earthy to resinous luster; smooth to matte texture; bituminous to lignitic; prolonged outgassing bubbles observed from larger fragments. 16 Tuffaceous Siltstone/ Tuffaceous Claystone (7670' - 7740') = light gray with very light gray and light brownish gray secondary hues; slightly firm to fragile and pulverulent; finely ground to irregular and sub tabular; silty to clayey texture; dull to slightly waxy and occasionally sparkling luster; slight to moderately soluble; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions. Sand (7740' - 7790') = medium to medium dark gray, individual grains dominantly medium to dark gray to grayish black and clear to translucent quartz and volcanic glass; very fine upper to coarse low er, dominantly fine upper to medium lower; angular to subangular; poorly sorted; disaggregated; trace light yellowish gray tuff; fragile to pulverulent; waxy; non calcareous. Tuffaceous Claystone/ Tuffaceous Siltstone (7790' - 7850') = medium light to light gray with trace light olive gray secondary hues; soft to slightly firm; irregular, finely ground up cuttings; silty to clayey texture; dull to slightly waxy luster; hydrophilic; moderately soluble and expansive; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; trace thin coal beds throughout interval. Sand (7850' - 7900') = medium to medium dark gray, individual grains dominantly medium to dark gray to grayish black and clear to translucent quartz and volcanic glass; very fine upper to coarse lower, dominantly fine upper to medium lower; angular to subangular; poorly sorted; disaggregated. Tuffaceous Siltstone/ Tuffaceous Claystone (7900' - 7940') = light gray with very light gray and light brownish gray secondary hues; slightly firm to fragile and pulverulent; finely ground to irregular and sub tabular; silty to clayey texture; dull to slightly waxy and occasionally sparkling luster; slight to moderately soluble; non calcareous. Sand/ Tuffaceous Sandstone (7940' - 8000') = note transition zone from medium to medium dark gray Beluga sands to light to very light gray Tyonek sands; dominantly clear to translucent quartz, light to medium gray; very fine lower to fine upper; angular to subangular; well sorted; disaggregated to very fragile ash supported grains; very fragile; non to slightly calcareous. Sand (8000' - 8030') = formation showing more Beluga characteristics; medium gray with individual grains dominantly medium to dark gray, black, clear to translucent quartz and volcanic glass; very fine upper to medium upper, dominantly fine; angular to subangular; unconsolidated; fair to good sorting; non calcareous. Sand (8030' - 8090') = medium dark gray to dark gray; lower fine to upper very fine; spherical to sub prismoidal; angular to sub angular; well to moderately well sorted; unconsolidated; texturally immature; compositionally sub mature; quartz, translucent to transparent ; carbonaceous material, tuffaceous siltstone/ claystone; porosity and permeability visually good. Sand (8090' - 8135') = dark gray to medium dark gray; upper fine to lower fine; spherical to sub discoidal; angular to sub angular; well to moderately well sorted; texturally immature; compositionally sub mature; quartz, translucent to transparent; pale yellowish orange volcanics, black carbonaceous material; porosity and permeability visually good. Tuffaceous Siltstone / Claystone (8135' - 8180') = medium gray; friable to soft; poor induration; crumbly tenacity. Sand (8175' - 8195') = medium light gray to medium gray; up per fine to lower fine occasional lower medium or upper very fine; spherical to sub discoidal; angular to sub angular; moderate to well sorted; unconsolidated; texturally immature; compositionally sub mature; quartz, translucent to transparent; muscovite, carbonaceous material, pale yellow volcanics; porosity and permeability visually good. Tuffaceous Siltstone / Claystone (8195' - 8240') = medium gray; friable to soft. 17 Sand (8240' - 8330)' = medium gray to medium light gray; lower fine to upper fine with some upper very fine; spherical to sub discoidal; angular to sub angular; well to moderately well sorted; unconsolidated; texturally immature; compositionally sub mature; quartz, transparent or translucent; black carbonaceous material, muscovite, pale yellowish orange volcanic; tuffaceous siltstone / claystone; porosity and permeability visually good. Tuffaceous Sandstone (8330' - 8360') = medium gray to medium dark gray; lower fine to upper very fine; spherical to sub discoidal; angular to sub angular; well to moderately well sorted; very friable to unconsolidated; tuffaceous matrix; texturally immature; quartz, translucent to transparent; carbonaceous lithics, pale yellow volcanics. Sand (8360' - 8450') = medium light gray to medium gray; lower fine to upper fine with some upper very fine; spherical to sub discoidal; angular to sub angular; well to moderately well sorted; unconsolidated; texturally immature; compositionally sub mature; quartz, translucent to transparent; black carbonaceous lithics, green lithics, pale yellow volcanic lithics; coal, brownish black; porosity and permeability visually fair to good. Tuffaceous Sandstone (8450' - 8540') = medium light gray to medium gray; lower fine to upper fine, occasional medium or upper very fine; spherical to sub discoidal; angular to sub angular; well to moderately well sorted; friable to unconsolidated; tuffaceous matrix; texturally immature; compositionally sub mature; matrix supported; quartz, transparent or translucent; carbonaceous lithics, pale yellow volcanics; coal, sub bit uminous, black; porosity and permeability visually fair. Coal (8520' - 8565') = black; hard; brittle; planar fracture dominant with conchoidal and birdeye present; platy to flaky, massive at times; vitreous to resinous luster; smooth texture; well developed; bituminous; vigorous, prolonged outgassing bubbles observed. Sand/ Tuffaceous Sandstone (8565' - 8610') = light to very light gray, dominantly clear to translucent quartz and volcanic glass; very fine lower to fine upper; angular to subangular; well sorted; disaggregated to very loosely supported in ash matrix; very fragile to pulverulent; very light grayish white with darker secondary hues; non calcareous. Tuffaceous Claystone/ Tuffaceous Siltstone (8610' - 8670') = light to very light gray with light brownish gray and light olive gray secondary hues; irregular to sub tabular; soft to fragile and pulverulent; silty to clayey texture; dull, earthy luster; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions. Tuffaceous Sandstone/ Sand (8670' - 8730') = light to very light gray overall with light yellowish gray and light greenish gray secondary hues from ashy matrix, individual grains dominantly clear to translucent quartz and volcanic glass, trace darker liths; very fine upper to fine upper; angular to subangular; moderately well to very well sorted; very fragile ashy supporting matrix for loose grains; non calcareous. Sand/ Tuffaceous Sandstone (8730' - 8800') = light to very light gray, dominantly clear to translucent quartz and volcanic glass; very fine lower to trace coarse upper, dominantly fine upper to medium; angular to subangular; fair sorting; disaggregated to very loosely supported in ash matrix; very fragile to pulverulent; very light grayish white with darker secondary hues; non calcareous. Tuffaceous Claystone/ Tuffaceous Siltstone (8800' - 8850') = light to very light gray with light brownish gray and light olive gray secondary hues; irregular to sub tabular; soft to fragile and pulverulent; silty to clayey texture; dull, earthy luster; moderate to very soluble; poor adhesiveness and fair cohesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions. 18 Sand/ Tuffaceous Sandstone (8850' - 8920') = very light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, light to medium gray and trace amounts of pale rose, pale green to greenish gray, orange and yellowish gray; very fine upper to very coarse upper, dominantly fine upper to medium lower; angular to subangular; poorly sorted; disaggregated to very loosely supported in ash matrix; very fragile to pulverulent; non calcareous. Tuffaceous Siltstone/ Tuffaceous Claystone (8920' - 8990') = light to very light gray with light olive gray secondary hues; irregular shaped with trace PDC bit action shaped cuttings; soft to fragile; silty to clayey texture; dull to slightly sparkling luster; moderately soluble; non calcareous; trace to common dark brown to black microthin carbonaceous laminations and inclusions; trace thin coal beds. Tuffaceous Sandstone (8990' - 9040') = medium gray to medium light gray, slight light olive gray sub hue; lower fine to upper very fine; spherical to sub discoidal, rare sub prismoidal; angular to sub angular; friable to unconsolidated; tuffaceous matrix; matrix supported; texturally immature; compositionally sub mature; quartz, transparent or translucent; black carbonaceous material, biotite; porosity and permeability visually fair. Tuffaceous Sandstone (9040' - 9100') = medium light gray to medium gray with slight olive gray sub hue; lower fine to upper very fine; spherical to sub discoidal, rare sub prismoidal; angular to sub angular; friable to unconsolidated; tuffaceous matrix; matrix supported; texturally immature; compositionally sub mature; quartz, transparent or translucent; black carbonaceous material, biotite; porosity and permeability visually fair. Sand (9100' - 9130') = medium light gray to light gray; upper fine to lower fine, some upper very fine and lower medium; spherical to sub discoidal; sub angular to angular; well sorted; unconsolidated; texturally immature; compositionally sub mature; quartz, transparent or translucent; pale yellow volcanics; black carbonaceous material; porosity and permeability visually good. Tuffaceous Siltstone / Claystone (9130' - 9180') = medium dark gray; friable; poor induration; crumbly tenacity; sub tabular cuttings habit; earthy luster; silty texture; laminar or massive structure. Sand (9180' - 9280') = medium gray to medium light gray; lower medium to upper medium with some upper fine; spherical to sub discoidal; angular to sub angular; well to moderately well sorted; unconsolidated; texturally immature compositionally sub mature; quartz, transparent to translucent; pale yellow volcanics, light green lithics, black carbonaceous material; porosity and permeability visually good. Tuffaceous Siltstone / Claystone (9280' - 9350') = medium dark gray to medium gray with slight light olive gray sub hue; friable to soft; poorly indurated; crumbly to crunchy tenacity; earthy fracture; massive or sub tabular cutting habit; earthy to dull luster; silty to gritty texture; massive or laminae structure; sand, lower fine to upper very fine, spherical, angular, well sorted, unconsolidated, quartz, porosity and permeability visually fair; coal, sub bituminous, black, hard, brittle dense tenacity, irregular or conchoidal fracture, massive cuttings habit, dull luster, matte texture, massive structure. Tuffaceous Sandstone (9350' - 9420') = medium dark gray to dark gray; upper fine to lower fine; spherical to sub discoidal; sub angular to sub rounded; well sorted; friable or unconsolidated; tuffaceous matrix; matrix supported; texturally immature; compositionally sub mature; quartz, transparent to translucent; pale yellow volcanics; porosity and permeability visually poor. Tuffaceous Sandstone (9420' - 9470') = medium dark gray to dark gray; upper fine to lower fine; spherical to sub discoidal; \angular to sub angular; well sorted; friable or unconsolidated; tuffaceous matrix; matrix supported; texturally immature; compositionally sub mature; quartz, transparent to translucent; pale yellow volcanics; 19 Sand/ Tuffaceous Sandstone (9470'-9560')= medium light to light gray with individual grains dominantly clear to translucent quartz and volcanic glass, trace light green to light greenish gray, pale rose, dusky red and dark gray to black; very fine lower to medium upper, dominantly fine; angular to subangular; fair to good sorting; disaggregated with common ash supporting matrix; very fragile; white to bluish white with many darker secondary hues; trace sandstone; light gray with salt and pepper appearance; fine to medium; grain supported; moderately hard to brittle; non calcareous. Tuffaceous Siltstone/ Tuffaceous Claystone (9560' - 9630') = light gray to light olive gray with light yellowish gray secondary hues; soft to slightly firm; irregular, finely ground up cuttings; silty to clayey to slightly sandy texture; dull to earthy to slightly waxy luster; moderately soluble; non calcareous; trace black microthin carbonaceous laminations and inclusions; trace thin coal beds throughout interval. Coal (9500' - 9680') = black; hard; brittle; planar fracture dominant with conchoidal and birdeye present; platy to flaky, massive at times; vitreous to resinous luster; smooth texture; well developed; bituminous; trace outgassing observed from larger fragments. Sand/ Tuffaceous Sandstone (9680' - 9740') = medium light to light gray with individual grains dominantly clear to translucent quartz and volcanic glass, trace light green to light greenish gray, black very fine lower to medium upper, dominantly fine; angular to subangular; fair to good sorting; disaggregated with common ash supporting matrix; very fragile; white to bluish white with many darker secondary hues; trace sandstone; light gray with salt and pepper appearance; fine to medium; grain supported; moderately hard to brittle; non calcareous. Sand/ Tuffaceous Sandstone (9740' - 9800') = light to very light gray with individual grains dominantly clear to translucent quartz and volcanic glass, trace light to medium gray; very fine upper to fine upper; angular to subangular; very well sorted; dominantly unconsolidated to very loosely supported from ashy matrix; very light gray to bluish white; very fragile to pulverulent; non calcareous. Sand/ Tuffaceous Sandstone/ Conglomeratic Sand (9800' - 9860') = very light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass with trace amounts of pale rose, light green to light greenish gray black and dusky red; very fine lower to very coarse lower, dominantly fine upper to medium upper; angular to subangular; poorly sorted; dominantly disaggregated with ashy supporting matrix common; very fragile; non calcareous. Sand / Tuffaceous Sandstone (9860' - 9920') = medium light gray to light gray; upper fine to lower fine; spherical to sub discoidal; well sorted; unconsolidated or friable; tuffaceous matrix; matrix supported; texturally immature; compositionally sub mature; quartz, translucent to transparent; pale yellowish orange volcanics, black carbonaceous material; porosity and permeability visually fair. Tuffaceous Sandstone / Sand (9920' - 9960') = medium gray to medium light gray with slight light olive gray sub hue; upper fine to lower fine; spherical to sub discoidal; well to moderately well sorted; friable or unconsolidated; tuffaceous matrix; matrix supported; texturally immature; compositionally sub mature; quartz, translucent or transparent; pale yellowish orange volcanics; black carbonaceous material; porosity and permeability visually fair. Carbonaceous Tuffaceous Siltstone (9960' - 10040') = dark gray to greenish black; easily friable to soft; poorly indurated; crumbly to crunchy tenacity; earthy fracture; sub tabular to sub wedgelike cuttings habit; earthy to dull luster; silty to gritty texture; laminae to thin structure; carbonaceous laminations visible; coal, sub bituminous. Sand / Tuffaceous Sandstone (10040' - 100100') = medium gray to medium light gray; upper fine to lower fine; spherical to sub discoidal; well to moderately well sorted; friable or unconsolidated; tuffaceous matrix; matrix supported; texturally immature; compositionally sub mature; quartz, translucent or transparent; pale yellowish orange volcanics; black carbonaceous material; porosity and permeability visually fair. 20 Carbonaceous Siltstone (10100' - 10140') = dark gray to greenish black; easily friable to soft; poorly indurated; crumbly to crunchy tenacity; earth fracture; sub tabular cuttings habit; earthy luster; silty texture; laminae structure; coal, sub bituminous black to brownish black, conchoidal or irregular fracture. Carbonaceous Siltstone (10140' - 10200') = dark gray to greenish black; easily friable to soft; poorly indurated; crumbly to crunchy tenacity; earth fracture; sub tabular cuttings habit; earthy luster; silty texture; laminae structure; coal, sub bituminous black to brownish black, conchoidal or irregular fracture. 21 3.3 Sampling Program The sampling program, specified by the Hilcorp Geologist called for the collection of two sets of Washed and Dried Reference Samples beginning at 3500’ MD. The resulting set, interval, and distribution are shown below. Set Type and Purpose Interval Frequency Distribution A Washed and Dried Reference Samples 30’ 20’ 30’ 20’ 3500’ – 8180’ 8180’ – 8600’ 8600’– 9020’ 9020’ –10200’ David Buthman Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 B Washed and Dried Reference Samples 30’ 20’ 30’ 20’ 3500’ – 8180’ 8180’ – 8600’ 8600’– 9020’ 9020’ –10200’ David Buthman Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 22 4 DRILLING DATA 4.1 Surveys Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 196.92 0.07 28.29 196.92 0.09 0.05 0.04 0.04 260.19 2.33 326.82 260.18 1.21 -0.64 1.33 3.64 323.10 3.65 327.29 323.00 3.96 -2.42 4.59 2.09 384.53 5.69 326.18 384.22 8.14 -5.17 9.56 3.32 445.89 6.80 325.04 445.21 13.64 -8.95 16.21 1.82 507.35 8.80 319.37 506.10 20.19 -14.09 24.53 3.48 569.35 10.25 319.29 567.25 27.97 -20.78 34.79 2.34 631.75 13.03 318.97 628.36 37.48 -29.02 47.37 4.46 691.86 15.85 321.49 686.57 49.02 -38.58 62.36 4.81 754.28 19.21 320.94 746.07 63.67 -50.36 81.15 5.39 816.43 22.55 321.86 804.14 80.99 -64.17 103.30 5.40 878.44 26.09 321.17 860.63 100.97 -80.07 128.83 5.72 940.19 29.66 319.59 915.21 123.19 -98.49 157.69 5.91 1004.69 33.63 320.08 970.11 149.05 -120.31 191.52 6.17 1064.29 36.43 318.60 1018.91 174.98 -142.61 225.72 4.90 1127.13 40.32 318.72 1068.16 204.27 -168.37 264.71 6.19 1187.83 40.85 319.23 1114.27 234.06 -194.29 304.19 1.03 1249.92 42.85 319.02 1160.52 265.38 -221.40 345.61 3.23 1312.48 46.13 318.89 1205.14 298.43 -250.18 389.42 5.24 1373.48 49.34 320.27 1246.17 332.80 -279.44 434.55 5.52 1435.21 52.84 320.46 1284.93 369.78 -310.07 482.58 5.69 1496.03 56.61 320.06 1320.05 407.96 -341.81 532.23 6.22 1558.91 58.81 320.31 1353.63 448.79 -375.85 585.38 3.51 1621.98 61.70 319.51 1384.92 490.68 -411.11 640.13 4.71 1682.33 65.22 320.50 1411.89 532.04 -445.80 694.11 6.01 1744.64 66.38 320.82 1437.43 575.99 -481.83 750.94 1.93 1807.39 68.97 321.45 1461.26 621.18 -518.24 808.97 4.22 1868.59 72.41 321.25 1481.50 666.28 -554.31 866.71 5.63 1931.14 74.38 322.51 1499.38 713.43 -591.31 926.63 3.70 1993.20 75.14 322.59 1515.69 760.96 -627.72 986.45 1.24 2054.75 75.00 321.67 1531.54 807.91 -664.23 1045.89 1.47 2117.67 77.15 322.41 1546.69 856.06 -701.80 1106.93 3.60 2178.76 78.41 321.87 1559.62 903.19 -738.44 1166.60 2.23 2242.89 79.24 319.68 1572.05 951.93 -778.23 1229.51 3.59 23 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 2303.49 78.59 317.91 1583.70 996.67 -817.40 1288.95 3.06 2365.55 78.83 319.02 1595.85 1042.22 -857.75 1349.78 1.79 2421.88 79.42 317.74 1606.48 1083.58 -894.50 1405.07 2.47 2486.01 78.98 318.32 1618.50 1130.41 -936.63 1468.02 1.12 2549.41 77.23 317.27 1631.56 1176.36 -978.30 1530.00 3.21 2611.48 77.40 318.28 1645.20 1221.20 -1018.99 1590.49 1.60 2671.50 77.84 318.14 1658.06 1264.90 -1058.06 1649.08 0.78 2735.29 77.70 318.21 1671.58 1311.36 -1099.64 1711.39 0.26 2796.70 78.09 318.52 1684.46 1356.24 -1139.53 1771.40 0.81 2859.22 78.93 318.94 1696.91 1402.29 -1179.94 1832.64 1.49 2920.71 79.40 319.42 1708.47 1447.99 -1219.42 1893.03 1.09 2982.56 78.28 319.48 1720.45 1494.10 -1258.87 1953.70 1.81 3045.27 77.96 320.37 1733.36 1541.06 -1298.37 2015.06 1.47 3107.39 76.31 320.66 1747.19 1587.80 -1336.88 2075.62 2.68 3169.71 75.97 320.42 1762.11 1634.51 -1375.33 2136.12 0.66 3231.56 75.59 320.74 1777.30 1680.83 -1413.41 2196.08 0.80 3294.26 75.82 321.28 1792.78 1728.05 -1451.64 2256.83 0.91 3354.91 75.08 320.91 1808.02 1773.74 -1488.50 2315.53 1.35 3415.55 74.86 320.54 1823.74 1819.07 -1525.57 2374.09 0.70 3459.97 75.26 321.29 1835.20 1852.39 -1552.63 2417.01 1.86 3541.42 74.39 322.56 1856.52 1914.27 -1601.11 2495.58 1.85 3602.60 76.11 322.92 1872.09 1961.35 -1636.93 2554.69 2.87 3665.91 77.95 323.14 1886.30 2010.64 -1674.03 2616.31 2.93 3726.30 79.02 323.05 1898.35 2057.96 -1709.57 2675.41 1.77 3788.02 77.44 322.60 1910.95 2106.10 -1746.08 2735.76 2.66 3850.80 77.82 322.61 1924.40 2154.82 -1783.32 2797.04 0.61 3912.58 77.19 321.09 1937.76 2202.25 -1820.57 2857.32 2.60 3974.60 76.10 319.46 1952.09 2248.66 -1859.13 2917.66 3.11 4035.72 76.56 319.60 1966.54 2293.84 -1897.68 2977.05 0.79 4098.95 76.74 319.34 1981.14 2340.60 -1937.66 3038.56 0.49 4161.12 77.00 319.10 1995.26 2386.45 -1977.20 3099.10 0.56 4222.97 74.77 318.68 2010.34 2431.64 -2016.64 3159.06 3.67 4285.24 74.58 318.39 2026.79 2476.64 -2056.41 3219.09 0.54 4347.61 74.89 318.68 2043.21 2521.73 -2096.25 3279.24 0.68 4409.23 75.34 318.68 2059.04 2566.45 -2135.57 3338.76 0.73 4470.77 75.84 318.16 2074.35 2611.04 -2175.13 3398.34 1.14 4532.74 76.30 318.29 2089.27 2655.90 -2215.20 3458.46 0.77 4593.66 76.69 318.08 2103.50 2700.05 -2254.69 3517.65 0.72 4655.72 77.12 317.92 2117.56 2744.97 -2295.13 3578.05 0.73 4718.39 76.37 318.86 2131.93 2790.57 -2335.64 3639.01 1.88 24 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 4779.29 76.74 318.82 2146.09 2835.17 -2374.62 3698.23 0.62 4842.50 77.57 318.33 2160.15 2881.38 -2415.39 3759.83 1.50 4904.47 78.50 318.61 2173.00 2926.77 -2455.59 3820.43 1.57 4966.00 77.75 319.91 2185.66 2972.39 -2494.88 3880.62 2.40 5028.87 75.73 321.49 2200.08 3019.74 -2533.64 3941.82 4.03 5090.53 75.09 321.62 2215.62 3066.47 -2570.74 4001.47 1.06 5152.28 75.21 321.60 2231.44 3113.26 -2607.81 4061.14 0.21 5214.48 75.85 321.62 2246.98 3160.46 -2645.21 4121.35 1.03 5276.28 76.68 320.99 2261.65 3207.32 -2682.74 4181.37 1.66 5338.65 77.25 321.11 2275.72 3254.57 -2720.93 4242.13 0.93 5400.16 77.50 320.90 2289.17 3301.22 -2758.70 4302.14 0.53 5461.90 77.88 320.86 2302.33 3348.02 -2796.77 4362.46 0.62 5523.73 76.17 320.54 2316.22 3394.64 -2834.93 4422.71 2.81 5585.62 76.74 320.47 2330.71 3441.07 -2873.20 4482.88 0.94 5648.05 77.44 320.70 2344.66 3488.08 -2911.84 4543.72 1.16 5708.86 78.14 320.36 2357.52 3533.96 -2949.62 4603.16 1.27 5773.41 77.19 320.26 2371.31 3582.48 -2989.89 4666.22 1.47 5834.75 77.82 319.80 2384.58 3628.38 -3028.36 4726.10 1.26 5896.09 77.57 319.76 2397.66 3674.14 -3067.06 4786.03 0.41 5957.65 77.06 319.38 2411.18 3719.85 -3106.01 4846.08 1.02 6020.60 76.43 319.50 2425.61 3766.41 -3145.85 4907.35 1.03 6082.15 76.31 319.64 2440.12 3811.93 -3184.64 4967.16 0.29 6144.38 76.93 319.31 2454.52 3857.96 -3223.98 5027.70 1.13 6206.46 77.38 319.30 2468.32 3903.84 -3263.44 5088.21 0.72 6269.04 77.63 319.27 2481.87 3950.15 -3303.30 5149.30 0.40 6330.89 77.13 319.65 2495.38 3996.02 -3342.53 5209.66 1.01 6391.81 76.86 319.91 2509.09 4041.34 -3380.85 5269.01 0.61 6454.49 76.87 319.77 2523.33 4088.00 -3420.22 5330.05 0.22 6516.51 77.11 319.89 2537.29 4134.17 -3459.20 5390.48 0.43 6577.61 78.14 319.81 2550.39 4179.79 -3497.68 5450.16 1.68 6637.83 78.12 319.58 2562.77 4224.73 -3535.80 5509.08 0.38 6702.23 77.25 320.01 2576.51 4272.78 -3576.42 5572.00 1.51 6764.69 75.55 320.22 2591.20 4319.36 -3615.34 5632.70 2.75 6826.98 72.79 320.63 2608.19 4365.54 -3653.52 5692.62 4.47 6889.43 70.11 320.55 2628.05 4411.28 -3691.11 5751.82 4.29 6951.28 67.46 320.38 2650.43 4455.75 -3727.81 5809.48 4.28 7013.34 64.26 320.01 2675.81 4499.25 -3764.05 5866.10 5.20 7075.57 61.54 319.50 2704.16 4541.54 -3799.84 5921.49 4.43 7138.33 58.78 319.87 2735.39 4583.04 -3835.06 5975.92 4.43 7199.79 55.31 319.71 2768.81 4622.42 -3868.34 6027.48 5.64 25 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 7261.02 52.40 320.37 2804.92 4660.31 -3900.10 6076.92 4.83 7324.96 49.24 321.60 2845.31 4698.81 -3931.30 6126.48 5.17 7386.90 46.85 322.11 2886.73 4735.03 -3959.75 6172.52 3.91 7435.13 44.51 322.13 2920.42 4762.26 -3980.94 6206.99 4.85 7509.52 42.41 322.71 2974.41 4802.80 -4012.15 6258.12 2.87 7572.40 39.89 320.20 3021.76 4835.17 -4037.90 6299.48 4.79 7634.37 36.56 319.62 3070.44 4864.51 -4062.58 6337.82 5.40 7696.93 32.79 319.58 3121.88 4891.61 -4085.64 6373.40 6.03 7758.30 29.62 321.88 3174.37 4916.20 -4105.79 6405.18 5.51 7819.88 26.23 323.95 3228.77 4939.18 -4123.20 6433.99 5.73 7881.77 23.10 321.16 3285.01 4959.70 -4138.86 6459.78 5.40 7943.98 19.68 320.11 3342.93 4977.25 -4153.24 6482.46 5.52 8005.57 16.89 321.43 3401.40 4992.20 -4165.47 6501.78 4.59 8067.40 14.13 319.92 3460.97 5005.00 -4175.93 6518.31 4.51 8129.26 11.93 315.07 3521.24 5015.31 -4185.31 6532.23 3.96 8191.79 10.06 308.68 3582.62 5023.30 -4194.14 6544.02 3.57 8253.63 8.90 318.80 3643.61 5030.27 -4201.51 6554.10 3.28 8315.22 7.25 318.61 3704.60 5036.77 -4207.22 6562.75 2.66 8377.22 7.60 319.42 3766.08 5042.83 -4212.47 6570.76 0.58 8439.01 6.80 318.87 3827.38 5048.68 -4217.53 6578.50 1.30 8501.19 6.78 322.55 3889.12 5054.37 -4222.19 6585.84 0.70 8565.08 7.19 324.86 3952.54 5060.63 -4226.78 6593.60 0.78 8626.12 5.97 320.01 4013.17 5066.18 -4231.02 6600.58 2.20 8688.09 5.86 317.67 4074.82 5070.99 -4235.22 6606.96 0.43 8751.36 6.16 317.86 4137.74 5075.90 -4239.67 6613.58 0.48 8812.13 6.45 316.91 4198.14 5080.80 -4244.19 6620.24 0.50 8874.04 6.45 320.43 4259.66 5086.02 -4248.78 6627.19 0.64 8936.06 6.49 323.01 4321.28 5091.51 -4253.11 6634.17 0.47 8998.30 5.98 323.48 4383.15 5096.92 -4257.15 6640.92 0.82 9060.88 5.73 322.13 4445.41 5102.01 -4261.01 6647.30 0.45 9122.26 5.52 322.62 4506.49 5106.77 -4264.68 6653.31 0.36 9184.17 6.56 323.34 4568.06 5111.97 -4268.60 6659.81 1.68 9246.55 6.99 324.60 4630.00 5117.92 -4272.92 6667.15 0.74 9308.12 6.91 325.18 4691.12 5124.02 -4277.21 6674.58 0.17 9370.53 6.84 324.21 4753.08 5130.12 -4281.53 6682.03 0.22 9453.48 6.66 321.97 4835.45 5137.91 -4287.38 6691.76 0.38 9515.57 6.62 321.69 4897.13 5143.56 -4291.82 6698.94 0.08 9576.89 6.67 323.30 4958.04 5149.19 -4296.14 6706.04 0.31 26 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 9638.77 6.63 324.07 5019.50 5154.97 -4300.38 6713.19 0.16 9701.14 6.39 325.82 5081.47 5160.75 -4304.44 6720.23 0.50 9762.98 6.41 326.80 5142.92 5166.48 -4308.27 6727.09 0.18 9825.51 6.19 327.66 5205.07 5172.25 -4311.98 6733.90 0.39 9887.33 6.39 327.38 5266.53 5177.97 -4315.62 6740.61 0.33 9949.35 6.47 328.07 5328.16 5183.84 -4319.33 6747.50 0.18 10011.92 6.07 328.41 5390.35 5189.65 -4322.92 6754.26 0.63 10073.63 6.08 329.31 5451.71 5195.24 -4326.30 6760.72 0.15 10135.51 5.99 328.97 5513.25 5200.82 -4329.64 6767.15 0.15 10158.91 5.82 327.78 5536.53 5202.87 -4330.90 6769.53 0.89 27 4.2 Bit Record BIT NO. SIZE TYPE S/N JETS/ TFA IN OUT FT HRS AVE ROP Ft/HR CONDITION 1 13 ½” Varel DT1GJMRS 1462249 3x16, 14cj 133’ 3500’ 3367’ 45.89 73.4 2-2-ER-A-E-3-CT -TD 2 9 7/8” Varel V516P2DU 4008489 4x14, 1x15 3500’ 7474’ 3974’ 60.2 66.2 1-2-CT -G-X-1-NO-TD 3 6 3/4” Varel V513PDHRU 4007828 3x10, 4x9 7474’ 10200’ 2726’ 37.45 74.7 1-2-CT -G-X-1-PN-TD 28 4.3 Mud Record Contractor: M.I. Swaco Date Depth MW (ppg) VIS (s/qt) PV YP Gels FL (cc) FC Sols (%) O/W Ratio Sd (%) MBT pH Cl (ml/l) Ca (ml/l) MD (ft) TVD (ft) Spud Mud 7/23/2015 1167 1098 8.9 171 13 46 34/65/71 12.1 2 4.2 0/95.5 1.00 20.0 9.4 500 20 7/24/2015 2357 1594 9.25 155 40 50 20/34/46 7.5 2 6.9 0/92.9 0.50 25.0 8.8 300 10 7/25/2015 3021 1725 9.38 115 41 42 20/34/40 6.8 2 7.8 0/92.0 0.50 25.0 8.3 300 20 7/26/2015 3500 1845 9.40 72 26 34 14/23/30 8.5 2 8.0 0/91.8 0.10 22.5 8.2 300 10 7/27/2015 3500 1845 9.50 45 17 13 5/8/10 8.0 2 8.8 0/91.0 0.10 20.0 7.9 300 10 Kla-Shield 7/28/2015 3500 1845 9.45 46 8 16 4/5/7 4.8 2 6.0 0/92.0 0.0 3.5 9.4 25000 480 7/29/2015 3500 1845 9.30 48 8 18 4/5/7 4.9 1 5.0 0/92.7 0.0 3.5 9.2 29000 480 7/30/2015 4015 1962 9.30 52 12 21 7/10/14 4.2 2 4.7 0/93.0 0.50 3.0 9.5 28500 160 7/31/2015 4948 2182 9.50 48 11 19 5/10/15 4.8 2 6.1 0/91.6 0.15 3.5 9.5 28500 160 8/1/2015 5930 2405 9.60 55 15 22 5/9/14 4.1 2 7.3 0/90.5 0.10 3.5 9.1 28500 160 8/2/2015 6681 2572 9.50 61 14 20 6/11/16 4.2 1/2 6.4 1/90.1 0.15 3.0 9.2 32000 140 8/3/2015 7474 2950 9.50 60 15 20 7/13/20 4.6 1/2 6.5 0.8/90.4 0.15 3.3 9.6 29500 160 8/4/2015 7474 2950 9.45 58 12 20 6/12/18 4.3 1/2 5.9 0.8/90.8 0.15 3.5 10 32000 120 8/5/2015 7474 2950 9.45 53 11 17 5/8/12 4.4 1/2 5.4 0.6/91.4 0.15 3.5 10.1 32500 120 8/6/2015 7474 2950 9.60 53 12 19 6/11/16 5.1 1/2 6.5 0.6/90.4 0.15 3.5 10.1 32000 140 8/7/2015 8136 3258 9.50 52 13 20 5/9/14 4.2 1/2 6.3 1.2/90.0 0.10 3.5 9.9 32000 240 8/8/2015 9164 4514 9.50 51 14 19 5/9/14 3.8 1/2 6.3 1.5/89.7 0.10 3.5 9.6 32000 320 8/9/2015 10051 5431 9.55 57 14 20 5/10/14 3.7 1/2 6.7 1.5/89.2 0.10 4.0 9.0 33000 200 8/10/2015 10200 5577 9.50 51 13 18 5/9/14 3.8 1/2 6.5 1.5/89.6 0.10 4.0 10.0 30500 180 8/11/2015 10200 5577 9.65 55 14 19 6/10/14 3.3 1/2 6.9 1.5/89.2 0.10 4.0 10.0 31000 200 Abbreviations: MW = Mud Weight VIS = Funnel Viscosity PV = Plastic Viscosity YP = Yield Point Gels = Gel Strength FL = Water or Filtrate Loss FC = Filter Cake O/W = Oil to Water ratio Sols = Solids Sd = Sand content MBT = Methylene Blue Alk, Pm = Alkalinity, Mud pH = Acidity Cl = Chlorides Ca = Hardness Calcium nr = Not Recorded 29 5 SHOW REPORTS Hydrocarbon Show Report # 1 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 7948 MD 7961 MD Country: 3346 TVD 3358 TVD Averages Before During After Maximum ROP (fph) 100 125 45 185 WOB 3.5 2.5 9.0 13.0 RPM 83 83 SLIDE 86 Mud Weight 9.50 9.50 9.50 9.50 Chloride 32,000 32,000 32,000 32,000 Total Gas 25 170 40 190 C1 (ppm) 4,948 34,692 7,898 38,681 C2 (ppm) C3 (ppm) C4 (ppm) - - - - C5 (ppm) - - - - Lithology Cuttings Analysis Odor Fluorescence Cut Fluorescence Residual Cut Stain Amount Type Amount Amount Distribution Intensity Color Color Intensity Color Residual Fluorescence Cut Color Intesity Color Color Show Rating Free Oil in Mud Comments Report by: 8/7/2015 Hilcorp Alaska, LLC. 50-133-20651-00-00 Grassim Oskolkoff #8 Ninilchik Unit 17:42 SAND/ TUFFACEOUS SANDSTONE = LIGHT TO VERY LIGHT GRAY, DOMINANTLY CLEAR TO TRANSLUCENT QUARTZ AND VOLCANIC GLASS, TRACE MEDIUM TO DARK GRAY LITHS; VERY FINE LOWER TO FINE UPPER; ANGULAR TO SUBANGULAR; WELL SORTED; DISAGGREGATED WITH COMMON VERY FRAGILE ASH SUPPORTING MATRIX; SLIGHT TO MODERATELY CALCAREOUS. NOTE: ROTATING AND SLIDING THRU TRANSITION ZONE FROM BELUGA TO TYONEK. Kenai Peninsula Borough Alaska United States of America Saxon 169 Ralph Winkelman Gas show, no oil indicators present. Pixler Plot 1 10 100 1000 10000 1 2 3 4 pp m DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 2 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 8175'MD 8195'MD Country: 20 3567'TVD 3587'TVD Averages Before During After Maximum ROP (fph) 85 ft/hr 99 ft/hr 82 ft/hr 115 ft/hr WOB 4 klbs 3 klbs 3 klbs 5 klbs RPM 17 rpm 83 rpm 66 rpm 85 rpm PP 2359 psi 2398 psi 2394 psi 2480 psi Mud Weight 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal Chloride 32,000 32,000 32,000 32,000 Total Gas 42 73 30 116 C1 (ppm) 8,413 14,563 5,975 23,115 C2 (ppm) - - - - C3 (ppm) - - - - C4 (ppm) - - - - C5 (ppm) - - - - Lithology Odor Amount Type Amount Amount Distribution Intensity Color Color Intensity Color Color Intesity Color Color Comments Report by: Residual Fluorescence Cuttings Analysis Tollef Winslow Gas show, no oil parameters GAS SHOW Oil Show Rating Cut Free Oil in Mud Kenai Peninsula Borough Alaska United States of America Fluorescence Cut Fluorescence Stain Hilcorp Alaska, LLC. 50-133-20651-00-00 Grassim Oskolkoff #8 Ninilchik Unit Saxon 169 8/7/2015 11:40 PM Residual Cut SAND = MEDIUM LIGHT GRAY TO MEDIUM GRAY; UPPER FINE TO LOWER FINE OCCASIONAL LOWER MEDIUM OR UPPER VERY FINE; SPERICAL TO SUB DISOIDAL; ANGULAR TO SUB ANGULAR; MODERATE TO WELL SORTED; UNCONSOLIDATED; TEXTURALLY IMMATURE; COMPOSITIONALLY SUB MATURE; QUARTZ, TRANSLUCEN TO TRANSPARENT; MUSCOVITE, CARBONACEOUS MATERIAL, PALE YELLOW VOLCANICS; POROSITY AND PERMEABILTY VISUALLY GOOD. Pixler Plot 1 10 100 1000 10000 1 2 3 4 pp m DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 3 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 8350'MD 8390'MD Country: 20 3740'TVD 3779'TVD Averages Before During After Maximum ROP (fph) 85 ft/hr 97 ft/hr 86 ft/hr 113 ft/hr WOB 4 klbs 4 klbs 5 klbs 5 klbs RPM 83 rpm 82 rpm 82 rpm 85 rpm PP 2414 psi 2545 psi 2608 psi 2662 psi Mud Weight 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal Chloride 32,000 32,000 32,000 32,000 Total Gas 57 86 62 109 C1 (ppm) 11,329 16,606 12,072 21,441 C2 (ppm) 44 52 6 79 C3 (ppm) - - - - C4 (ppm) - - - - C5 (ppm) 0 3 0 7 Lithology Odor Amount Type Amount Amount Distribution Intensity Color Color Intensity Color Color Intesity Color Color Comments Report by: Residual Cut TUFFACEOUS SANDSTONE = MEDIUM GRAY TO MEDIUM DARK GRAY; LOWER FINE TO UPPER VERY FINE; SPHERICAL TO SUB DISCOIDAL; ANGULAR TO SUB ANGULAR; WELL TO MODERATELY WELL SORTED; VERY FRIABLE TO UNCONSOLIDATED; TUFFACEOUS MATRIX; TEXTURALLY IMMATURE; QUARTZ, TRANSLUCENT TO TRANSPARENT; CARBONACEOUS LITHICS, PALE YELLOW VOLCANICS. Stain 50-133-20651-00-00 Grassim Oskolkoff #8 Ninilchik Unit Saxon 169 8/8/2015 3:20 AM Cut Free Oil in Mud Kenai Peninsula Borough Alaska United States of America Fluorescence Cut Fluorescence Residual Fluorescence Cuttings Analysis Tollef Winslow Gas show, no oil parameters GAS SHOW Oil Show Rating Pixler Plot 1 10 100 1000 10000 1 2 3 4 pp m DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 4 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 8570'MD 8595'MD Country: 20 3958'TVD 3983'TVD Averages Before During After Maximum ROP (fph) 80 ft/hr 81 ft/hr 67 ft/hr 92 ft/hr WOB 4 klbs 3 klbs 6 klbs 4 klbs RPM 82 rpm 81 rpm 50 rpm 83 rpm PP 2637 psi 2612 psi 2578 psi 2644 psi Mud Weight 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal Chloride 32,000 32,000 32,000 32,000 Total Gas 60 112 59 154 C1 (ppm) 11,758 23,134 11,589 32,051 C2 (ppm) - - - - C3 (ppm) - - - - C4 (ppm) - - - - C5 (ppm) - - - - Lithology Odor Amount Type Amount Amount Distribution Intensity Color Color Intensity Color Color Intesity Color Color Comments Report by: Residual Cut SAND/TUFFACEOUS SANDSTONE = LIGHT TO VERY LIGHT GRAY, DOMINANTLY CLEAR TO TRANSLUCENT QUARTZ AND VOLCANIC GLASS; VERY FINE LOWER TO FINE UPPER; ANGULAR TO SUBANGULAR; WELL SORTED; DISAGGREGATED TO VERY LOOSELY SUPPORTED IN ASH MATRIX; VERY FRAGILE TO PULVERULENT; VERY LIGHT GRAYISH WHITE WITH DARKER SECONDARY HUES; NON CALCAREOUS. Stain Hilcorp Alaska, LLC. 50-133-20651-00-00 Grassim Oskolkoff #8 Ninilchik Unit Saxon 169 8/8/2015 1:40 PM Cut Free Oil in Mud Kenai Peninsula Borough Alaska United States of America Fluorescence Cut Fluorescence Residual Fluorescence Cuttings Analysis Tollef Winslow / Ralph Winkleman Gas show, no oil parameters GAS SHOW Oil Show Rating Pixler Plot 1 10 100 1000 10000 1 2 3 4 pp m DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 5 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 8615'MD 8645'MD Country: 20 4003'TVD 4032'TVD Averages Before During After Maximum ROP (fph) 70 ft/hr 82 ft/hr 95 ft/hr 141 ft/hr WOB 5 klbs 3 klbs 3 klbs 5 klbs RPM 53 rpm 55 rpm 81 rpm 84 rpm PP 2583 psi 2618 psi 2661 psi 2817 psi Mud Weight 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal Chloride 32,000 32,000 32,000 32,000 Total Gas 55 142 74 229 C1 (ppm) 10,919 28,029 14,309 45,172 C2 (ppm) - 20 26 54 C3 (ppm) - - - - C4 (ppm) - - - - C5 (ppm) - - - - Lithology Odor Amount Type Amount Amount Distribution Intensity Color Color Intensity Color Color Intesity Color Color Comments Report by: Residual Cut TUFFACEOUS CLAYSTONE/ TUFFACEOUS SILTSTONE = LIGHT TO VERY LIGHT GRAY WITH LIGHT BROWNISH GRAY AND LIGHT OLIVE GRAY SECONDARY HUES; IRREGULAR TO SUB TABULAR; SOFT TO FRAGILE AND PULVERULENT; SILTY TO CLAYEY TEXTURE; DULL, EARTHY LUSTER; NON CALCAREOUS; TRACE DARK BROWN TO BLACK MICROTHIN CARBONACEOUS LAMINATIONS AND INCLUSIONS. Stain Hilcorp Alaska, LLC. 50-133-20651-00-00 Grassim Oskolkoff #8 Ninilchik Unit Saxon 169 8/8/2015 2:40 PM Cut Free Oil in Mud Kenai Peninsula Borough Alaska United States of America Fluorescence Cut Fluorescence Residual Fluorescence Cuttings Analysis Tollef Winslow / Ralph Winkleman Gas show, no oil parameters GAS SHOW Oil Show Rating Pixler Plot 1 10 100 1000 10000 1 2 3 4 pp m DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 6 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 8660'MD 8690'MD Country: 20 4047'TVD 4077'TVD Averages Before During After Maximum ROP (fph) 97 ft/hr 93 ft/hr 90 ft/hr 126 ft/hr WOB 2 klbs 2 klbs 3 klbs 3 klbs RPM 81 rpm 81 rpm 81 rpm 83 rpm PP 2660 psi 2610 psi 2621 psi 2669 psi Mud Weight 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal Chloride 32,000 32,000 32,000 32,000 Total Gas 80 170 165 230 C1 (ppm) 15,688 34,055 33,041 48,042 C2 (ppm) 32 7 - 31 C3 (ppm) - - - - C4 (ppm) - - - - C5 (ppm) - - - - Lithology Odor Amount Type Amount Amount Distribution Intensity Color Color Intensity Color Color Intesity Color Color Comments Report by: Residual Fluorescence Cuttings Analysis Tollef Winslow / Ralph Winkleman Gas show, no oil parameters GAS SHOW Oil Show Rating Cut Free Oil in Mud Kenai Peninsula Borough Alaska United States of America Fluorescence Cut Fluorescence Stain Hilcorp Alaska, LLC. 50-133-20651-00-00 Grassim Oskolkoff #8 Ninilchik Unit Saxon 169 8/8/2015 2:40 PM Residual Cut TUFFACEOUS SANDSTONE/SAND = LIGHT TO VERY LIGHT GRAY OVERALL WITH LIGHT YELLOWISH GRAY AND LIGHT GREENISH GRAY SECONDARY HUES FROM ASHY MATRIX, INDIVIDUAL GRAINS DOMINANTLY CLEAR TO TRANSLUCENT QUARTZ AND VOLCANIC GLASS, TRACE DARKER LITHS; VERY FINE UPPER TO FINE UPPER; ANGULAR TO SUBANGULAR; MODERATELY WELL TO VERY WELL SORTED; VERY FRAGILE ASHY SUPPORTING MATRIX FOR LOOSE GRAINS; NON CALCAREOUS. Pixler Plot 1 10 100 1000 10000 1 2 3 4 pp m DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 7 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 8845'MD 8890'MD Country: 20 4231'TVD 4276'TVD Averages Before During After Maximum ROP (fph) 93 ft/hr 90 ft/hr 84 ft/hr 126 ft/hr WOB 4 klbs 3 klbs 4 klbs 5 klbs RPM 81 rpm 81 rpm 80 rpm 83 rpm PP 2650 psi 2676 psi 2693 psi 2753 psi Mud Weight 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal Chloride 32,000 32,000 32,000 32,000 Total Gas 57 124 53 249 C1 (ppm) 11,268 24,548 10,513 48,265 C2 (ppm) - 7 30 30 C3 (ppm) - - - - C4 (ppm) - - - - C5 (ppm) - - - - Lithology Odor Amount Type Amount Amount Distribution Intensity Color Color Intensity Color Color Intesity Color Color Comments Report by: Residual Cut SAND/TUFFACEOUS SANDSTONE = VERY LIGHT GRAY OVERALL WITH IDIVIDUAL GRAINS DOMINANTLY CLEAR TO TRANSLUCENT QUARTZ AND VOLCANIC GLASS, LIGHT TO MEDIUM GRAY AND TRACE AMOUNTS OF PALE ROSE, PALE GREEN TO GREENISH GRAY, ORANGE AND YELLOWISH GRAY; VERY FINE UPPER TO VERY COARSE UPPER, DOMINANTLY FINE UPPER TO MEDIUM LOWER; ANGULAR TO SUBANGULAR; POORLY SORTED; DISAGGREGATED TO VERY LOOSELY SUPPORTED IN ASH MATRIX; VERY FRAGILE TO PULVERULENT; NON CALCAREOUS. Stain Hilcorp Alaska, LLC. 50-133-20651-00-00 Grassim Oskolkoff #8 Ninilchik Unit Saxon 169 8/8/2015 6:20 PM Cut Free Oil in Mud Kenai Peninsula Borough Alaska United States of America Fluorescence Cut Fluorescence Residual Fluorescence Cuttings Analysis Tollef Winslow / Ralph Winkleman Gas show, no oil parameters GAS SHOW Oil Show Rating Pixler Plot 1 10 100 1000 10000 1 2 3 4 pp m DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 8 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 9105'MD 9130'MD Country: 20 4490'TVD 4515'TVD Averages Before During After Maximum ROP (fph) 86 ft/hr 107 ft/hr 110 ft/hr 141 ft/hr WOB 5 klbs 5 klbs 6 klbs 7 klbs RPM 80 rpm 80 rpm 80 rpm 82 rpm PP 2758 psi 2787 psi 2810 psi 2860 psi Mud Weight 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal Chloride 32,000 32,000 32,000 32,000 Total Gas 85 176 87 299 C1 (ppm) 17,006 35,165 17,438 60,218 C2 (ppm) 12 65 53 115 C3 (ppm) 1 - - - C4 (ppm) - - - - C5 (ppm) - - - - Lithology Odor Amount Type Amount Amount Distribution Intensity Color Color Intensity Color Color Intesity Color Color Comments Report by: Residual Cut SAND = MEDIUM LIGHT GRAY TO LIGHT GRAY; UPPER FINE TO LOWER FINE, SOME UPPER VERY FINE AND LOWER MEDIUM; SPERICAL TO SUB DISCOIDAL; SUB ANGULAR TO ANGULAR; WELL SORTED; UNCONSOLIDATED; TEXTURALLY IMMATURE; COMPOSITIONALLY SUB MATURE; QUARTZ, TRANPARENT OR TRANSLUCENT; PALE YELLOW VOLCANICS; BLACK CARBONACEOUS MATERIAL; POROSITY AND PERMEABILITY VISUALLY GOOD. Stain Hilcorp Alaska, LLC. 50-133-20651-00-00 Grassim Oskolkoff #8 Ninilchik Unit Saxon 169 8/8/2015 10:40 PM Cut Free Oil in Mud Kenai Peninsula Borough Alaska United States of America Fluorescence Cut Fluorescence Residual Fluorescence Cuttings Analysis Tollef Winslow Gas show, no oil parameters GAS SHOW Oil Show Rating Pixler Plot 1 10 100 1000 10000 1 2 3 4 pp m DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 9 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 9185'MD 9270'MD Country: 20 4569'TVD 4654'TVD Averages Before During After Maximum ROP (fph) 50 ft/hr 100 ft/hr 93 ft/hr 221 ft/hr WOB 3 klbs 3 klbs 3 klbs 6 klbs RPM 8 rpm 80 rpm 78 rpm 83 rpm PP 2664 psi 2743 psi 2787 psi 2855 psi Mud Weight 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal Chloride 32,000 32,000 32,000 32,000 Total Gas 82 207 110 363 C1 (ppm) 15,840 40,767 21,473 71,552 C2 (ppm) 5 182 90 285 C3 (ppm) - 1 4 3 C4 (ppm) 0 1 - 8 C5 (ppm) - - - - Lithology Odor Amount Type Amount Amount Distribution Intensity Color Color Intensity Color Color Intesity Color Color Comments Report by: Residual Fluorescence Cuttings Analysis Tollef Winslow Gas show, no oil parameters GAS SHOW Oil Show Rating Cut Free Oil in Mud Kenai Peninsula Borough Alaska United States of America Fluorescence Cut Fluorescence Stain Hilcorp Alaska, LLC 50-133-20651-00-00 Grassim Oskolkoff #8 Ninilchik Unit Saxon 169 8/9/2015 1:35 AM Residual Cut SAND = MEDIUM GRAY TO MEDIUM LIGHT GRAY; LOWER MEDIUM TO UPPER MEDIUM WITH SOME UPPER FINE; SPHERICAL TO SUB DISCOIDAL; ANGULAR TO SUB ANGULAR; WELL TO MODERATELY WELL SORTED; UNCONSOLIDATED; TEXTURALLY IMMATURE COMPOSITIONALLY SUB MATURE; QUARTZ, TRANSPARENT TO TRANSLUCENT; PALE YELLOW VOLCANICS, LIGHT GREEN LITHICS, BLACK CARBONACEOUS MATERIAL; POROSITY AND PERMEABILITY VISUALLY GOOD. Pixler Plot 1 10 100 1000 10000 1 2 3 4 pp m DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 10 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 9405'MD 9430'MD Country: 20 4788'TVD 4813'TVD Averages Before During After Maximum ROP (fph) 122 ft/hr 114 ft/hr 116 ft/hr 156 ft/hr WOB 3 klbs 1 klbs 2 klbs 4 klbs RPM 79 rpm 79 rpm 79 rpm 80 rpm PP 2848 psi 2831 psi 2874 psi 2890 psi Mud Weight 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal Chloride 32,000 32,000 32,000 32,000 Total Gas 73 157 63 275 C1 (ppm) 14,609 31,117 12,478 54,413 C2 (ppm) 64 137 34 232 C3 (ppm) - - - - C4 (ppm) - - - - C5 (ppm) - - - - Lithology Odor Amount Type Amount Amount Distribution Intensity Color Color Intensity Color Color Intesity Color Color Comments Report by: Residual Fluorescence Cuttings Analysis Tollef Winslow Gas show, no oil parameters GAS SHOW Oil Show Rating Cut Free Oil in Mud Kenai Peninsula Borough Alaska United States of America Fluorescence Cut Fluorescence Stain Hilcorp Alaska, LLC 50-133-20651-00-00 Grassim Oskolkoff #8 Ninilchik Unit Saxon 169 8/9/2015 3:40 AM Residual Cut SAND = MEDIUM GRAY TO MEDIUM LIGHT GRAY; LOWER MEDIUM TO UPPER MEDIUM WITH SOME UPPER FINE; SPHERICAL TO SUB DISCOIDAL; ANGULAR TO SUB ANGULAR; WELL TO MODERATELY WELL SORTED; UNCONSOLIDATED; TEXTURALLY IMMATURE COMPOSITIONALLY SUB MATURE; QUARTZ, TRANSPARENT TO TRANSLUCENT; PALE YELLOW VOLCANICS, LIGHT GREEN LITHICS, BLACK CARBONACEOUS MATERIAL; POROSITY AND PERMEABILITY VISUALLY GOOD. Pixler Plot 1 10 100 1000 10000 1 2 3 4 pp m DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 11 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 9811'MD 9880'MD Country: 20 4788'TVD 4813'TVD Averages Before During After Maximum ROP (fph) 122 ft/hr 114 ft/hr 116 ft/hr 156 ft/hr WOB 3 klbs 1 klbs 2 klbs 4 klbs RPM 79 rpm 79 rpm 79 rpm 80 rpm PP 2848 psi 2831 psi 2874 psi 2890 psi Mud Weight 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal 9.5 lbs/gal Chloride 32,000 32,000 32,000 32,000 Total Gas 73 157 63 275 C1 (ppm) 14,609 31,117 12,478 54,413 C2 (ppm) 64 137 34 232 C3 (ppm) - - - - C4 (ppm) - - - - C5 (ppm) - - - - Lithology Odor Amount Type Amount Amount Distribution Intensity Color Color Intensity Color Color Intesity Color Color Comments Report by: Residual Fluorescence Cuttings Analysis Tollef Winslow / Ralph Winkleman Gas show, no oil parameters GAS SHOW Oil Show Rating Cut Free Oil in Mud Kenai Peninsula Borough Alaska United States of America Fluorescence Cut Fluorescence Stain Hilcorp Alaska, LLC 50-133-20651-00-00 Grassim Oskolkoff #8 Ninilchik Unit Saxon 169 8/9/2015 6:15 PM Residual Cut SAND/ TUFFACEOUS SANDSTONE/CONGLOMERATIC SAND = VERY LIGHT GRAY OVERALL WITH INDIVIDUAL GRAINS DOMINANTLY CLEAR TO TRANSLUCENT QUARTZ AND VOLCANIC GLASS WITH TRACE AMOUNTS OF PALE ROSE, LIGHT GREEN TO LIGHT GREENISH GRAY BLACK AND DUSKY RED; VERY FINE LOWER TO VERY COARSE LOWER, DOMINANTLY FINE UPPER TO MEDIUM UPPER; ANGULAR TO SUBANGULAR; POORLY SORTED; DOMINANTLY DISAGGREGATED WITH ASHY SUPPORTING MATRIX COMMON; VERY FRAGILE; NON CALCAREOUS. Pixler Plot 1 10 100 1000 10000 1 2 3 4 pp m DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 12 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 9925'MD 9960'MD Country: 20 5304'TVD 5339'TVD Averages Before During After Maximum ROP (fph) 56 ft/hr 85 ft/hr 87 ft/hr 115 ft/hr WOB 5 klbs 5 klbs 6 klbs 7 klbs RPM 48 rpm 51 rpm 51 rpm 53 rpm PP 2864 psi 2992 psi 3030 psi 3100 psi Mud Weight 9.6 lbs/gal 9.6 lbs/gal 9.6 lbs/gal 9.6 lbs/gal Chloride 33,000 33,000 33,000 33,000 Total Gas 67 140 118 189 C1 (ppm) 11,695 27,383 23,484 37,146 C2 (ppm) 41 112 77 145 C3 (ppm) - 3 9 13 C4 (ppm) - 0 13 7 C5 (ppm) - - - - Lithology Odor Amount Type Amount Amount Distribution Intensity Color Color Intensity Color Color Intesity Color Color Comments Report by: Residual Fluorescence Cuttings Analysis Tollef Winslow Gas show, no oil parameters GAS SHOW Oil Show Rating Cut Free Oil in Mud Kenai Peninsula Borough Alaska United States of America Fluorescence Cut Fluorescence Stain Hilcorp Alaska, LLC 50-133-20651-00-00 Grassim Oskolkoff #8 Ninilchik Unit Saxon 169 8/9/2015 9:05 PM Residual Cut TUFFACEOUS SANDSTONE / SAND = MEDIUM GRAY TO MEDIUM LIGHT GRAY WITH SLIGHT LIGHT OLIVE GRAY SUB HUE; UPPER FINE TO LOWER FINE; SPHERICAL TO SUB DISCOIDAL; WELL TO MODERATELY WELL SORTED; FRIABLE OR UNCONSOLIDATED; TUFFACEOUS MATRIX; MATRIX SUPPORTED; TEXTURALLY IMMATURE; COMPOSITIONALLY SUB MATURE; QUARTZ, TRANSLUCENT OR TRANSPARENT; PALE YELLOWISH ORANGE VOLCANICS; BLACK CARBONACEOUS MATERIAL; POROSITY AND PERMABILITY VISUALLY FAIR. Pixler Plot 1 10 100 1000 10000 1 2 3 4 pp m DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 13 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 10060'MD 10085'MD Country: 20 5439'TVD 5463'TVD Averages Before During After Maximum ROP (fph) 97 ft/hr 91 ft/hr 93 ft/hr 139 ft/hr WOB 4 klbs 6 klbs 6 klbs 7 klbs RPM 51 rpm 51 rpm 50 rpm 51 rpm PP 2872 psi 2896 psi 2876 psi 2981 psi Mud Weight 9.6 lbs/gal 9.6 lbs/gal 9.6 lbs/gal 9.6 lbs/gal Chloride 33,000 33,000 33,000 33,000 Total Gas 67 89 58 150 C1 (ppm) 13,404 17,688 11,607 29,825 C2 (ppm) 43 64 41 113 C3 (ppm) - - - - C4 (ppm) - - - - C5 (ppm) - - - - Lithology Odor Amount Type Amount Amount Distribution Intensity Color Color Intensity Color Color Intesity Color Color Comments Report by: Residual Fluorescence Cuttings Analysis Tollef Winslow Gas show, no oil parameters GAS SHOW Oil Show Rating Cut Free Oil in Mud Kenai Peninsula Borough Alaska United States of America Fluorescence Cut Fluorescence Stain Hilcorp Alaska, LLC 50-133-20651-00-00 Grassim Oskolkoff #8 Ninilchik Unit Saxon 169 8/9/2015 11:20 PM Residual Cut SAND / TUFFACEOUS SANDSTONE = MEDIUM GRAY TO MEDIUM LIGHT GRAY; UPPER FINE TO LOWER FINE; SPHERICAL TO SUB DISCOIDAL; WELL TO MODERATELY WELL SORTED; FRIABLE OR UNCONSOLIDATED; TUFFACEOUS MATRIX; MATRIX SUPPORTED; TEXTURALLY IMMATURE; COMPOSITIONALLY SUB MATURE; QUARTZ, TRANSLUCENT OR TRANSPARENT; PALE YELLOWISH ORANGE VOLCANICS; BLACK CARBONACEOUS MATERIAL; POROSITY AND PERMABILITY VISUALLY FAIR Pixler Plot 1 10 100 1000 10000 1 2 3 4 pp m DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 30 6 DAILY REPORTS Hilcorp Alaska LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Shane Barber Rick Brumle;y DATE July 23, 2015 DEPTH 1167 PRESENT OPERATION Runnning back in hole on Wiper Trip TIME 24:00 YESTERDAY 133 24 HOUR FOOTAGE 1034 CASING INFORMATION 16" Conductor at 138' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 196.92 0.07 028.29 196.92 445.89 6.80 325.04 445.21 691.86 15.85 321.49 686.57 940.19 29.66 319.59 915.21 1127.13 40.32 318.72 1068.16 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1 13.50 Varel DT1GJMRS 1462249 3x16, 1x14cj 133 1033 10.35 In Hole DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 441.1 @ 547 2.1 @ 731 147.5 90.2 FT/HR SURFACE TORQUE 7006 @ 1069 953 @ 348 2012.5 5375.0 AMPS WEIGHT ON BIT 21 @ 1027 1 @ 746 10.9 7.4 KLBS ROTARY RPM 45 @ 684 3 @ 348 14.9 34.0 RPM PUMP PRESSURE 1986 @ 570 1053 @ 176 1729.4 1812.9 PSI DRILLING MUD REPORT DEPTH 1167 / 1098TVD MW 8.9 VIS 171 PV 13 YP 46 FL 12.1 Gels 34/65/71 CL- 500 FC 2 SOL 4.2 SD 1.00 OIL 0.0/95.5 MBT 20.0 pH 9.4 Ca+ 20 Alk 0.15 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 29 @ 1081 0 @ 981 1.4 TRIP GAS CUTTING GAS @ @ WIPER GAS 9 CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 5882 @ 1081 15 @ 981 282.3 CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 3 / 7 PENTANE (C-5) @ @ HYDROCARBON SHOWS NONE INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue picking up drill pipe and racking back in derrick. Replace hose on service loop. Splice hose. Continue picking up drill pipe and racking back in derrick. Function test diverter (23 sec for knife valve to open, 44 sec for bag to close). Perform accumulator drawdown test. Pick up/prep combo jars and lay down. Hold PJSM with crew procedures for picking up and making up BHA. Pick up and make up motor, bit, stabilizer, DM/TM collars, flex collars and subs. Drill out conductor and Spud Well. Drill from 133’ to 300’ (picking up and making up HWDP while drilling ahead). Circulate out. POOH 3 stands of HWDP. Pick up and make up two (2) 6 ¾” monels, jars and HWDP single. Drill ahead, rotating and sliding from 300’ to 1167’. Pump and circulate around Hi-Vis sweep (and observe 25% increase in cuttings). Pull out of hole from 1167’ to 272’ on Wiper Trip. Service drawworks. Level subbase. Run back in hole from 272’ to 1105’. Wash and ream through tight spot at 970’ on way in. CANRIG PERSONNEL ON BOARD 2 DAILY COST 2115 REPORT BY Craig Silva Hilcorp Alaska LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Shane Barber Rick Brumley DATE Jul 24, 2015 DEPTH 2360 PRESENT OPERATION Drilling ahead TIME 24:00 YESTERDAY 1167 24 HOUR FOOTAGE 1193 CASING INFORMATION 16" Conductor at 138' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 1127.13 40.32 318.72 1068.16 1435.2 52.84 320.46 1284.93 1744.64 66.38 320.82 1437.743 2054.75 75.00 321.67 1531.54 2365.55 78.83 319.02 1595.85 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1 13.50 Varel DT1GJMRS 1462249 3x16, 1x14cj 133 2227 26.07 In Hole DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 845.4 @ 2205 2.4 @ 2237 93.5 65.6 FT/HR SURFACE TORQUE 10659 @ 2246 0 @ Sliding 9352.6 9404.6 AMPS WEIGHT ON BIT 49 @ 1841 1 @ 1884 23.5 35.0 KLBS ROTARY RPM 61 @ 2346 0 @ Sliding 30.8 57.8 RPM PUMP PRESSURE 2357 @ 2316 1786 @ 1167 2032.1 2211.1 PSI DRILLING MUD REPORT DEPTH 2357 / 1594 TVD MW 9.25 VIS 155 PV 40 YP 50 FL 7.5 Gels 20/34/46 CL- 300 FC 2 SOL 6.9 SD 0.50 OIL 0.0/92.9 MBT 25.0 pH 8.8 Ca+ 10 Alk 0.10 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 14 @ 2282 0 @ 2185 4.7 TRIP GAS CUTTING GAS @ @ WIPER GAS 9 CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 2870 @ 2282 65 @ 2185 935.3 CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 1 / 3 PENTANE (C-5) @ @ HYDROCARBON SHOWS NONE INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Major Clay, Sand and Coal PRESENT LITHOLOGY Major Clay DAILY ACTIVITY SUMMARY Wash and ream last stand back to bottom from 1105’ to 1167’. Record 9 units of Wiper Gas. Drill ahead, rotating and sliding, from 1167’ to 2360’. CANRIG PERSONNEL ON BOARD 2 DAILY COST 2115 REPORT BY Craig Silva Hilcorp Alaska LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Shane Barber Rick Brumley DATE Jul 25, 2015 DEPTH 3020 PRESENT OPERATION Drilling Ahead TIME 24:00 YESTERDAY 2360 24 HOUR FOOTAGE 660 CASING INFORMATION 16" Conductor at 138' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 2365.55 78.83 319.02 1595.85 2549.41 77.23 317.27 1631.56 2671.50 77.84 318.14 1658.06 2859.22 78.93 318.94 1696.91 2982.56 78.28 319.48 1720.45 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1 13.50 Varel DT1GJMRS 1462249 3x16, 1x14cj 133 2887 38.02 In Hole DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 236.1 @ 2511 0.9 @ 2465 72.0 59.0 FT/HR SURFACE TORQUE 11746 @ 2497 0 @ Sliding 9276.4 8763.6 AMPS WEIGHT ON BIT 46 @ 2538 8 @ 2651 29.0 28.1 KLBS ROTARY RPM 72 @ 2462 0 @ Sliding 50.6 62.2 RPM PUMP PRESSURE 2661 @ 2791 2046 @ 2409 2364.5 2313.2 PSI DRILLING MUD REPORT DEPTH 3021 / 1725 TVD MW 9.38 VIS 115 PV 41 YP 42 FL 6.8 Gels 20/34/40 CL- 300 FC 2 SOL 7.8 SD 0.50 OIL 0.0/92.0 MBT 25.0 pH 8.3 Ca+ 20 Alk 0.05 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 45 @ 2692 0 @ 2492 2.5 TRIP GAS CUTTING GAS @ @ WIPER GAS 25 CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 8319 @ 2692 51 @ 2492 482.2 CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 1 / 3 PENTANE (C-5) @ @ HYDROCARBON SHOWS NONE INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Major Clay/Silt, Sand and Coal PRESENT LITHOLOGY Clay still dominant, but increased (Beluga) silt and sand. Appears generally less coaly. DAILY ACTIVITY SUMMARY Drill ahead, rotating and sliding, from 2360’ to 2407’. Note constant maintenance keeping possum belly clean and free of clay. Pump 20 bbl Hi- Vis/Nut Plug sweep at 2363’, and record 100% increase in cuttings with significant very large clay balls. At 2407’ observe large solid mass of clay filling flowline, possum belly and conductor annulus to bell nipple when circulating bottoms up. Slowly circulate and clear clay mass, and then circulate additional bottoms up to clean up hole. Perform wiper trip from 2407’ to 1102’. Backreaming required in many spots on way out. Service rig. Run back in hole from 1102’ to 2092’. No tight spots on way in. Pick up, make up, drift and run in 10 joints (5 stands) of HWDP off catwalk for push pipe. Wash down last joint to bottom from 2381’ to 2407’ with no fill. Drill ahead, rotating and sliding, from 2407’ to 3020’. Continue frequent maintenance keeping possum belly free of clay, and pumping occasional sweeps to clean hole. CANRIG PERSONNEL ON BOARD 2 DAILY COST 2115 REPORT BY Craig Silva Hilcorp Alaska LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Shane Barber Rick Brumley DATE Jul 26, 2015 DEPTH 3500 PRESENT OPERATION Pulling out of hole after Wiper Trip TIME 24:00 YESTERDAY 3020 24 HOUR FOOTAGE 480 CASING INFORMATION 16" Conductor at 138' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 2982.56 78.28 319.48 1720.45 3107.39 76.31 320.66 1747.19 3231.56 75.59 320.74 1777.30 3354.91 75.08 320.91 1808.02 3459.97 75.26 321.29 1835.20 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1 13.50 Varel DT1GJMRS 1462249 3x16, 1x14cj 133 3500 3367 45.89 In Hole DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 196.0 @ 3210 2.9 @ 3392 74.1 62.0 FT/HR SURFACE TORQUE 11294 @ 3382 0 @ Sliding 9609.2 7553.2 AMPS WEIGHT ON BIT 45 @ 3099 18 @ 3334 34.4 27.7 KLBS ROTARY RPM 65 @ 3162 0 @ Sliding 52.6 54.9 RPM PUMP PRESSURE 2759 @ 3215 2168 @ 3330 2418.4 2375.5 PSI DRILLING MUD REPORT DEPTH 3500 / 1845 TVD MW 9.40 VIS 72 PV 26 YP 34 FL 6.5 Gels 14/23/30 CL- 300 FC 2 SOL 8.0 SD 0.10 OIL 0.0/91.8 MBT 22.5 pH 8.2 Ca+ 10 Alk 0.01 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 47 @ 3356 0 @ 3398 3.1 TRIP GAS CUTTING GAS @ @ WIPER GAS 8 CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 9556 @ 3356 47 @ 3398 609.2 CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 1 / 3 PENTANE (C-5) @ @ HYDROCARBON SHOWS NONE INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Major Clay/Silt, Sand and Coal PRESENT LITHOLOGY Sand and Clay at 3500' casing point DAILY ACTIVITY SUMMARY Drill ahead, sliding and rotating, from 3020’ to 3113’. Continue drilling ahead, rotating only, from 3113’ to surface casing point at 3500’. Begin circulating around H-Vis sweep while circulating bottoms up. Clean hole for wiper trip. POOH with elevators from 3500’ to 3385’. Pull out of hole, backreaming, from 3385’ to 2400’. Continue pulling out of hole with elevators (and no tight spots) from 2400’ to 735’. Circulate 18 minutes at 530 gpm. Service drawworks, topdrive, and blocks. Run back in hole from 735’ to bottom at 3500’. Circulate bottoms up three times and clean hole. Pump around Hi-Vis sweep and observe 10% increase in returns 600 strokes early. POOH from 3500’ to 2185’. CANRIG PERSONNEL ON BOARD 2 DAILY COST 2115 REPORT BY Craig Silva Hilcorp Alaska LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Shane Barber Rick Brumley DATE Jul 27, 2015 DEPTH 3500 PRESENT OPERATION Rigging down cementing lines TIME 24:00 YESTERDAY 3500 24 HOUR FOOTAGE 0 CASING INFORMATION 10 3/4" at 3492' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 3500 (Projection) 75.26 319.48 1845.25 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1 13.50 Varel DT1GJMRS 1462249 3x16, 1x14cj 133 3500 3367 45.89 2-2-ER-A-E-3-CT-TD Surface casing point DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 3500 / 1845 TVD MW 9.50 VIS 45 PV 17 YP 13 FL 8.0 Gels 5/8/10 CL- 300 FC 2 SOL 8.8 SD 0.10 OIL 0.0/91.0 MBT 20.0 pH 7.9 Ca+ 10 Alk 0.01 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 3 @ 3500 0 @ 1 TRIP GAS 3 CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG N/A PENTANE (C-5) @ @ HYDROCARBON SHOWS N/A INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY N/A PRESENT LITHOLOGY N/A DAILY ACTIVITY SUMMARY Continue POOH from 2185’ to 173’. Rack back flex collars in derrick. Break and lay down TM and DM collars, stabilizer, motor and bit. Clean and organize rig floor. Pick up johnny-wacker and jet out clay around wear bushing. Pull wear bushing. Clear and clean rig floor. Rig up Weatherford 10 -3/4” casing running equipment. Change elevators and elevator links. Rig up power tongs and spider. Rig up fill-up line. Prep rig floor for running casing. Load racks with casing. Follow all casing running procedures as per Hilcorp Plan. Pick up and make up shoe track. Test floats. Pick up, make up and run 10 ¾” casing in hole, filling on way in, to 2017’. Circulate casing volume. Continue running 10 ¾” casing in hole, filling on way in, to 3468’. Make up landing joint and complete running casing to 3492’. Make up circulating swage and circulate hole volume while rigging up Schlumberger cementers. Rig up cementing head with top and bottom plugs correctly loaded. Hold pre-job meeting with all hands on safety and operating procedures for cement job. Finish circulating. Follow all cementing procedures as per Hilcorp Plan. Pump 5 bbls of water and pressure test lines to 3000psi. Pump 45 bbls of 10.0ppg mud push with the rig pumps at 3.2 bpm and then switch over lines to Schlumberger pumping unit. Pump 387.9 bbls of 12.0ppg lead cement, and follow with 72.5 bbls of 15.2ppg tail cement. Drop top plug and displace cement with 328 bbls of 9.5ppg spud mud. Plug did not bump. Hold column with 440 psi pressure. Check floats and floats held. Prep to rig down cementing head and cement lines. CANRIG PERSONNEL ON BOARD 2 DAILY COST 2115 REPORT BY Craig Silva Hilcorp Alaska LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Shane Barber Marvin Rogers DATE Jul 28, 2015 DEPTH 3500 PRESENT OPERATION Installing lines to BOPE TIME 24:00 YESTERDAY 3500 24 HOUR FOOTAGE 0 CASING INFORMATION 10 3/4" at 3492' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 3500 (Projection) 75.26 319.48 1845.25 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 3500 / 1845 TVD MW 9.45 VIS 46 PV 8 YP 16 FL 4.8 Gels 4/5/7 CL- 25000 FC 2 SOL 6.0 SD 0.0 OIL 0.0/92.0 MBT 3.5 pH 9.4 Ca+ 480 Alk 0.20 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG N/A PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Rig down cementing head and Schlumberger cement lines. Begin cleaning cement out of cellar box. Remove landing joint. Begin cleaning pits. Nipple down diverter tee. Clean cement from wellhead profile. Install pack-off. Continue cleaning pits. Continue cleaning cement out of cellar area. Nipple up multi-bowl wellhead and then pressure test to 3000psi for 15 minutes. Finish cleaning pits and then load on stored KCL/Polymer mud from Atigun tanks to be centrifuged. Hang BOP stack off of stack-handler. Install hydraulic fittings on BOPs. Prep 2’ spacer spool for installation and then install. Stack and align BOPs on spacer spool. Install choke hose to BOPE and to catwalk. Torque bolts on BOP flanges. Install kill line. CANRIG PERSONNEL ON BOARD 2 DAILY COST 2115 REPORT BY Craig Silva Hilcorp Alaska LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Shane Barber Marvin Rogers DATE Jul 29, 2015 DEPTH 3500 PRESENT OPERATION Circulating out thick mud after tagging cement TIME 24:00 YESTERDAY 3500 24 HOUR FOOTAGE 0 CASING INFORMATION 10 3/4" at 3492' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 9.875" Varel V516P2DU 4008489 4x14, 1x15 3500 In Hole DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 3500 / 1845 TVD MW 9.30 VIS 48 PV 8 YP 18 FL 4.9 Gels 4/5/7 CL- 29000 FC 1 SOL 5.0 SD 0.0 OIL 0.0/92.7 MBT 3.5 pH 9.2 Ca+ 480 Alk 0.20 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG N/A PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Install flow box, flow nipple, and flow line. Chain stack. Spot and raise gas buster. Rig up test equipment. Flood stack and choke manifold with water. Perform shell test of BOPs. Test all BOPE (Tests 1-10). Test annular to 250psi Low / 2500psi High. Test all other BOPE to 250psi Low / 4000psi High. (1: annular, inside kill, inside choke; 2: CMVs 1-3-4-5-7, mezzanine kill, upper IBOP; 3: CMVs 2-4-5-6-8, kill, HCR, dart, lower IBOP; 4: electric choke, manual choke, inside kill, TIW; 5: CMVs 7-9-11-13, inside kill, TIW; 6: dart, inside kill, HCR; 7: dart, inside kill, inside choke; 8: lower pipe rams, dart; 9: accumulator drawdown performance; 10: blind rams, CMVs 7-10-12, inside kill). Rig down test equipment. Install wear bushing with 10” ID. Pick up, make up and run in BHA #2. Function test MWD-LWD tool electronics. Pulse test MWD tool. Load radioactive sources in CTN collar. Continue making up and running in BHA to 424’. Make up additional stands of HWDP running in, and then lay down 9 joints. Single in hole with 94 joints of 4 ½” drill pipe from 424’ to cement stringer tag-up at 3316’. Begin and continue circulating thick mud out of hole. CANRIG PERSONNEL ON BOARD 4 DAILY COST 3065 REPORT BY Craig Silva Hilcorp Alaska LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Shane Barber Marvin Rogers DATE Jul 30, 2015 DEPTH 4076 PRESENT OPERATION Drilling ahead TIME 24:00 YESTERDAY 3500 24 HOUR FOOTAGE 576 CASING INFORMATION 10 3/4" at 3492' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 3459.97 75.26 321.29 1835.20 3602.60 76.11 322.92 1872.09 3788.02 77.44 322.60 1910.95 3974.60 76.10 319.46 1952.09 4098.95 76.74 319.34 1981.14 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 9.875 Varel V516P2DU 4008489 4x14, 1x15 3500 576 7.79 In Hole DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 213.1 @ 3647 4.4 @ 3966 92.0 56.8 FT/HR SURFACE TORQUE 10634 @ 3795 0 @ Sliding 8449.5 8755.1 AMPS WEIGHT ON BIT 63 @ 3769 0.4 @ 3915 10.8 9.6 KLBS ROTARY RPM 91 @ 3927 0 @ Sliding 58.3 82.9 RPM PUMP PRESSURE 1854 @ 3512 1353 @ 3530 1702.0 1679.7 PSI DRILLING MUD REPORT DEPTH 4015 / 1962 TVD MW 9.30 VIS 52 PV 12 YP 21 FL 4.2 Gels 7/10/14 CL- 28500 FC 2 SOL 4.7 SD 0.50 OIL 0.0/93.0 MBT 3.0 pH 9.5 Ca+ 160 Alk 0.30 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 22 @ 3561 0 @ 3522 6.9 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 4449 @ 3561.00000 67 @ 3522.00000 1343.9 CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 3 / 7 PENTANE (C-5) @ @ HYDROCARBON SHOWS NONE INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Major Sand and Tuffaceous Claystone Minor Coal, Tuffaceous Siltstone PRESENT LITHOLOGY Dominant Tuffaceous Claystone with local increase in Sand DAILY ACTIVITY SUMMARY Finish circulating out thick (cement-contaminated) mud. Prep for casing test. Test casing to 2600psi for 30 minutes. Wash down from 3316’ and tag first rubber at 3333’. Drill out cement, float debris and shoe track from 3333’ to 3500’. (Note float collar at 3409’, casing shoe at 3491’, 8’ of rathole to 3500’). Drill 20’ of new 9 7/8” hole from 3500’ to 3520’. Circulate bottoms up and clean hole for FIT. Attempt to test to 12.0ppg EMW, but failed to hold pressure. Bleed-off was continuous. Checked all equipment for leakage and could not find issue. Re-tested but pressure still would not hold. Discussed options with town. Decision made to drill deeper and re-test. Drill 10’ of hole from 3520’ to 3530’ while displacing spud mud with 9.2ppg KCL mud. Circulate bottoms up and clean hole for FIT. Perform FIT test (with 9,2ppg MW). Successfully pressure up and hold on FIT to 11.6ppg EMW. Drill ahead, rotating and sliding, from 3530’ to 3953’. Re-torque thread saver sub and backup clamp. Drill ahead, rotating and sliding, from 3953’ to 4076’. CANRIG PERSONNEL ON BOARD 4 DAILY COST 3065 REPORT BY Craig Silva Hilcorp Alaska LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Shane Barber Marvin Rogers DATE Jul 31, 2015 DEPTH 5005 PRESENT OPERATION Drilling ahead TIME 24:00 YESTERDAY 4076 24 HOUR FOOTAGE 929 CASING INFORMATION 10 3/4" at 3492' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 4098.95 76.74 319.34 1981.14 4347.61 74.89 318.68 2043.21 4532.74 76.30 318.29 2089.27 4779.29 76.74 318.82 2146.09 4966.00 77.75 319.91 2165.66 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 9.875 Varel V516P2DU 4008489 4x14, 1x15 3500 1505 20.48 In Hole DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 219.0 @ 4885 1.7 @ 4513 86.0 51.3 FT/HR SURFACE TORQUE 11243 @ 4752 0 @ Sliding 9088.7 9789.3 AMPS WEIGHT ON BIT 43 @ 4713 0.9 @ 4821 13.1 1.7 KLBS ROTARY RPM 90 @ 4986 0 @ Sliding 79.0 86.8 RPM PUMP PRESSURE 2115 @ 4885 1253 @ 4089 1827.0 2032.9 PSI DRILLING MUD REPORT DEPTH 4948 / 2182 TVD MW 9.5 VIS 48 PV 11 YP 19 FL 4.8 Gels 5/10/15 CL- 28500 FC 2 SOL 6.1 SD 0.15 OIL 0.0/91.6 MBT 3.5 pH 9.5 Ca+ 160 Alk 0.30 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 126 @ 4804 2 @ 4079 26.7 TRIP GAS CUTTING GAS @ @ WIPER GAS 60 CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 24424 @ 4804 591 @ 4079 5294.4 CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 7 / 18 PENTANE (C-5) @ @ HYDROCARBON SHOWS NONE INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Major Sand, Tuffaceous Claystone, Coal, Minor Tuffaceous Siltstone PRESENT LITHOLOGY Presently in dominant Tuffaceous Claystone after thick section of Sand DAILY ACTIVITY SUMMARY Drill ahead, rotating and sliding, from 4076’ to 4819’. Circulate bottoms up. Pump around tandem 20 bbl sweeps (Lo-Vis/Hi-Vis). Circulate hole clean. POOH from 4819’ to 3453’. Note 30K overpull at 4355’, 3786’, 3690’ on way out. Kelly up topdrive at 3690’ and backream from 3690’ to 3490’ (with 1.8 bbls over calculated fill). Service rig. Check topdrive end play and backlash with rig mechanic. Change oil in drawworks. Grease crown, drawworks, wash pipe and blocks. Change out saver sub. Adjust topdrive drilling torque up to 16500 lbs. Single in hole 20 joints of 4 ½” drill pipe from 3450’ to 4070’. Continue to run back in hole with stands out of derrick from 4070’ to 4757’. (Observe tight spot at 4345’ on way in). Note that 5 stands of HWDP “push pipe” were moved and repositioned up the drill string. Wash down last stand to bottom from 4757’ to 4819’ with no fill. Drill ahead, rotating and sliding, from 4819’ to 5005’. CANRIG PERSONNEL ON BOARD 4 DAILY COST 3065 REPORT BY Craig Silva Hilcorp Alaska LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Shane Barber Marvin Rogers DATE Aug 01, 2015 DEPTH 5924 PRESENT OPERATION Drilling ahead TIME 24:00 YESTERDAY 5005 24 HOUR FOOTAGE 919 CASING INFORMATION 10 3/4" at 3492' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 4966.00 77.75 319.91 2165.66 5214.48 75.85 321.62 2246.98 5461.90 77.88 320.86 2302.33 5708.86 78.14 320.36 2371.31 5957.65 77.06 319.38 2411.18 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 9.875 Varel V516P2DU 4008489 4x14, 1x15 3500 2424 33.00 In Hole DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 317.7 @ 5222 6.6 @ 5765 88.3 30.6 FT/HR SURFACE TORQUE 12388 @ 5838 0 @ Sliding 9881.9 9835.5 AMPS WEIGHT ON BIT 40 @ 5007 0.9 @ 5513 9.8 11.0 KLBS ROTARY RPM 91 @ 5273 0 @ Sliding 80.1 61.4 RPM PUMP PRESSURE 2163 @ 5693 1473 @ 5893 1976.4 1562.5 PSI DRILLING MUD REPORT DEPTH 5930 / 2405 TVD MW 9.60 VIS 55 PV 15 YP 22 FL 4.1 Gels 5/9/14 CL- 28500 FC 2 SOL 7.3 SD 0.10 OIL 0.0/90.5 MBT 3.5 pH 9.1 Ca+ 160 Alk 0.20 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 54 @ 5085 7 @ 5756 22.7 TRIP GAS CUTTING GAS @ @ WIPER GAS 21 CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 10968 @ 5085 1419 @ 5756 4563.1 CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 9 / 16 PENTANE (C-5) @ @ HYDROCARBON SHOWS NONE INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Major Sand, Tuffaceous Claystone. Minor Coal, Sandstone, Tuffaceous Siltstone PRESENT LITHOLOGY Very Dominant disaggregated Sand with spotty consolidated Sandstone fragments and local coal. DAILY ACTIVITY SUMMARY Drill ahead, rotating and sliding, from 5005’ to 5108’. Change swab on pump #2. Drill ahead, rotating and sliding, from 5108’ to 5874’. Pump around tandem 20 bbl sweeps (Lo-Vis/Hi-Vis). Observe no increase in cuttings volume. Centrifuge packing off. Flow check well and note mud loss at rate of 6 bph. Change shaker screens (to 200s) and line up to pump mud across shakers and condition mud while tripping. Pull out of hole on wiper trip from 5874’ to 4577’. Note tight zones at 5360’-5330’ and 4846’-4790’ (with swabbing) on way out. Record 4.5 bbls over calculated displacement for trip. Service topdrive, blocks and drawworks. Run back in hole from 4577’ to 5812’. Kelly up and wash down last stand to bottom from 5812’ to 5874’ with no fill. Drill, rotating and sliding, from 5874’ to 5924’. CANRIG PERSONNEL ON BOARD 4 DAILY COST 3065 REPORT BY Craig Silva Hilcorp Alaska, LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Shane Barber / Marvin Rogers DATE Aug 02, 2015 DEPTH 6737' PRESENT OPERATION Drilling Ahead TIME 24:00 YESTERDAY 5924' 24 HOUR FOOTAGE 813' CASING INFORMATION 10 3/4" at 3492' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 6454.49' 76.81 319.77 2523.33' 6516.51' 77.11 319.89 2537.29' 6577.61' 78.14 319.81 2550.39' 6637.83' 78.12 319.58 2562.77' 6702.23' 77.25 320.01 2576.51' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 9.875 Varel V516P2DU 4008489 4x14, 1x15 3500 3237' 48:20 In Hole DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 132.4 @ 6580' 0.8 @ 6683' 64.7 7.53 FT/HR SURFACE TORQUE 12720 @ 6634' 2413 @ 6685' 10731.9 2990.28 AMPS WEIGHT ON BIT 19 @ 6105' 2 @ 5941' 8.0 5.50 KLBS ROTARY RPM 90 @ 6156' 1 @ 6702' 79.8 15.840 RPM PUMP PRESSURE 2230 @ 6707' 1361 @ 6039' 1629.7 1911.33 PSI DRILLING MUD REPORT DEPTH 6681' MD / 2572' TVD MW 9.50 VIS 61 PV 14 YP 20 FL 4.2 Gels 6/11/16 CL- 32000 FC 1/2 SOL 6.4 SD 0.15 OIL 1.0/90.1 MBT 3.0 pH 9.2 Ca+ 140 Alk 0.20 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 64 @ 6658' 6 @ 6682' 26.4 TRIP GAS NA CUTTING GAS @ @ WIPER GAS 28 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 13176 @ 6658' 1252 @ 6682' 5308.6 CONNECTION GAS HIGH 0 ETHANE (C-2) 58 @ 6083' 0 @ 6737' 5.9 AVG 0 PROPANE (C-3) 12 @ 6083' 0 @ 6054' 0.4 CURRENT 17 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 12 / 10 PENTANE (C-5) @ @ HYDROCARBON SHOWS None INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Major Sand, Tuffaceous Claystone / Siltstone. Minor Coal, Sandstone, Tuffaceous Siltstone PRESENT LITHOLOGY Quart Sand with coal and tuffaceous siltstone. DAILY ACTIVITY SUMMARY Drill ahead, rotating and sliding from 5924’ to 6680’. Pump tandem sweeps of 20 BBLS each: low/l and high / h. Ciruclate hole clean for a wiper trip. Check hole for flow: static. Pull out of hole from 6680’ to 5620 with tight spots at 6265’, 6238’, 6157’, 6105, and 5760’. The hole over displaced by 11 BBLS. Service the crown, draw woks and wash pipe. Trip in hole from 5620’ to 6680’, wash down the last stand, no fill. Change the shaker screens from 200’s to 140’s. Drill ahead from 6680’ to 6737’ CANRIG PERSONNEL ON BOARD 4 DAILY COST 3065 REPORT BY Tollef Winslow Hilcorp Alaska, LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Shane Barber / Marvin Rogers DATE Aug 03, 2015 DEPTH 7474' PRESENT OPERATION Pulling out of hole on elevators TIME 24:00:00 YESTERDAY 6767' 24 HOUR FOOTAGE 707' CASING INFORMATION 10 3/4" at 3492' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 7199.79' 55.31 319.71 2768.81' 7261.02' 52.40 320.37 2804.92' 7324.96' 49.24 321.60 2845.31' 7386.90' 46.85 322.11 2886.73' 7435.13' 44.51 322.13 2920.42' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 9.875 Varel V516P2DU 4008489 4x14, 1x15 3500' 3974' 60:01 In Hole DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 225.6 @ 7206' 2.5 @ 7457' 80.3 113.30 FT/HR SURFACE TORQUE 14707 @ 7079' 2412 @ 7196' 4577.5 12507.06 AMPS WEIGHT ON BIT 19 @ 7079' 0 @ 7333' 5.1 5.02 KLBS ROTARY RPM 90 @ 6948' 1 @ 6792' 32.3 82.89 RPM PUMP PRESSURE 2393 @ 7350' 2012 @ 7056' 2232.5 2361.77 PSI DRILLING MUD REPORT DEPTH 7474' MD / 2590' TVD MW 9.50 VIS 60 PV 15 YP 20 FL 4.6 Gels 7/13/20 CL- 120 FC 1/2 SOL 6.5 SD 0.15 OIL 0.8/90.4 MBT 3.3 pH 9.6 Ca+ 120 Alk MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 71 @ 7130' 7 @ 7094' 22.4 TRIP GAS NA CUTTING GAS @ @ WIPER GAS NA CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 13064 @ 7134' 1309 @ 7056' 4272.0 CONNECTION GAS HIGH 0 ETHANE (C-2) 41 @ 6815' @ 2.0 AVG 0 PROPANE (C-3) 9 @ 6767' @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 0 /22 PENTANE (C-5) @ @ HYDROCARBON SHOWS None INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Major Sand, Tuffaceous Claystone / Siltstone. Minor Coal, Sandstone, Tuffaceous Siltstone PRESENT LITHOLOGY Tuffaceous Siltstone DAILY ACTIVITY SUMMARY Drill ahead, rotating and sliding from 6767’ to 6928’. Ibop began to leak. Ibop replaced. Drill ahead, rotating and sliding from 6928’ to 7474’. Circulate bottoms up to confirm formation lithology. Pump tandem sweep. Circulate sweep out of hole. Check for well flowing. No flow. Prepare to pull out of hole on elevators. CANRIG PERSONNEL ON BOARD 4 DAILY COST 3065 REPORT BY Tollef WInslow Hilcorp Alaska, LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Rance Pederson / Marvin Rogers DATE Aug 04, 2015 DEPTH 7474' PRESENT OPERATION Testing 7 5/8 BOP RAMS TIME 24:00:00 YESTERDAY 7474' 24 HOUR FOOTAGE 0' CASING INFORMATION 10 3/4" at 3492' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 9.875 Varel V516P2DU 4008489 4x14, 1x15 3500' 7474' 3974' 60.1 1-2-CT-G-X-1-NO-TD TD DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 7474' MD / 2950' TVD MW 9.45 VIS 58 PV 12 YP 20 FL 4.3 Gels 6/12/18 CL- 32000 FC 1/2 SOL 5.9 SD 0.15 OIL 0.8/90.8 MBT 3.5 pH 10.0 Ca+ 120 Alk MWD SUMMARY INTERVAL TO TOOLS No tools in the hole GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS NA CUTTING GAS @ @ WIPER GAS 56 CHROMATOGRAPHY (ppm) SURVEY NA METHANE (C-1) @ @ CONNECTION GAS HIGH NA ETHANE (C-2) @ @ AVG NA PROPANE (C-3) @ @ CURRENT NA BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 0 / 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS No new footage INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY No new lithology PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Pull out of hole from 7474’ to 3470’ (10 ¾” casing shoe) with tight spots at 6951’, 6527’, 5578’ and 5340’. The hole was displaced over 9 barrels (calculated). Service the top drive, blocks, crown and draw works. Trip in hole from 3470’ to 7474’ filling the pipe every 20 stands; no tight spots were encountered. A high viscosity sweep was pumped and the hole was circulated clean with 56 units of wiper gas at bottoms up. The well was flow checked and found static. The string was pulled out of the hole from 7474’ to 424’ on elevators with no tight spots or other issues encountered. The hole was displaced over 16 barrels (calculated). The bottom hole assembly (BHA) was laid down, nuclear source was removed, logging while drilling tools were downloaded and then the rest of the bottom hole assembly was laid down. The rig floor was organized and cleaned. The wear ring was pulled. Change out upper pipe rams for 7 5/8”. Install BOP test plug. Begin testing 7 5/8” upper pipe ram. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3065 REPORT BY Tollef Winslow Hilcorp Alaska, LLC Ninilchik DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR DATE Aug 05, 2015 DEPTH 7474' PRESENT OPERATION Rigging down cement equipment TIME 24:00:00 YESTERDAY 7474' 24 HOUR FOOTAGE 0' CASING INFORMATION 10 3/4" at 3492' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 9.875 Varel V516P2DU 4008489 4x14, 1x15 3500' 7474' 3974' 60.1 1-2-CT-G-X-1-NO-TD TD DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 7474/2950 MW 9.45 VIS 53 PV 11 YP 17 FL 4.4 Gels 5/8/12 CL- 32500 FC 1/2 SOL 5.4 SD 0.15 OIL 0.6/91.4 MBT 3.5 pH 10.1 Ca+ 120 Alk MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 47 CUTTING GAS @ @ WIPER GAS NA CHROMATOGRAPHY (ppm) SURVEY NA METHANE (C-1) @ @ CONNECTION GAS HIGH NA ETHANE (C-2) @ @ AVG NA PROPANE (C-3) @ @ CURRENT NA BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 1 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY No new lithology PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Tripping in hole with 7 5/8" casing from 6850' to 7440', pick up landing joint and land at 7466'. Circulate casing at 5 bbl/min and begin rigging up cementing equipment. Flush 10 bbls water to cuttings box and pump 5 bbls down hole with cement truck. Test lines to 1,000 / 5,000 psi and pump 25 bbls 11 ppg mud with rig pump, drop bottom plug. SLB pump 235 bbls 12.5 ppg lead and then 70 bbls 15.3 ppg tail. Drop top plug. Displacement pump 20 bbls of water and 321 bbls mud and bump plug 500 psi over final circulating pressure. Bleed back and check floats. Rig down cement equipment. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3065 REPORT BY Trey Thrailkill Hilcorp Alaska, LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Rance Pederson/ Marvin Rogers DATE Aug 06, 2015 DEPTH 7474' PRESENT OPERATION Casing test TIME 24:00:00 YESTERDAY 7474' 24 HOUR FOOTAGE 0' CASING INFORMATION 7.625" @ 7.465' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3 6.75 Varel V513PDHRU 4007828 3x10, 4x9 7474 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 7,474'/2,950' MW 9.6 VIS 53 PV 12 YP 19 FL 5.1 Gels 6/11/16 CL- 32,000 FC 1/2 SOL 6.5 SD 0.15 OIL 0.6/90.4 MBT 3.5 pH 10.1 Ca+ 140 Alk MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS NA CUTTING GAS @ @ WIPER GAS NA CHROMATOGRAPHY (ppm) SURVEY NA METHANE (C-1) @ @ CONNECTION GAS HIGH NA ETHANE (C-2) @ @ AVG NA PROPANE (C-3) @ @ CURRENT NA BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 1 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY No New Lithology PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Finish changing uppers from 7 5/8 to 4.5 VBRS and rig up test equipment. Test upper at 250 psi for 5 minutes and 4000 psi for 10 minutes. Rig down test equipment and pull test plug. Install wear bushing (9 1/16 ID). Stage BHA, strap 80 joints of drill pipe to single in. Perform rig service. Make up bit and BHA, download pulse test and load sources. Single in hole from 609' to 2160'. Continue running in hole while occasionally filling pipe to 7,366'. Pressure up to 3500 psi for 30 minutes for casing pressure test while slip and cut drill string CANRIG PERSONNEL ON BOARD 4 DAILY COST $3065.00 REPORT BY Trey Thrailkill Hilcorp Alaska, LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Rance Pederson/ Marvin Rogers DATE Aug 07, 2015 DEPTH 8222' PRESENT OPERATION DRILLING AHEAD TIME 24:00:00 YESTERDAY 7474' 24 HOUR FOOTAGE 748' CASING INFORMATION 10 3/4" at 3492' 7 5/8" @ 7465' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 7943.98' 19.68 320.11 3342.93' 8005.57' 16.89 321.43 3401.40' 8067.40' 14.13 319.92 3460.97' 8129.26' 11.93 315.07 3521.24' 8191.79' 10.06 308.68 3585.62' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3 6 3/4" Varel V513PDHRU Varel V513PDHRU 3x10, 4x9 7474' 748' 11:00 IN HOLE DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 293.6 @ 7478' 1.5 @ 7487' 75.7 60.10 FT/HR SURFACE TORQUE 15718 @ 8193' 902 @ 8151' 9097.0 0.00 AMPS WEIGHT ON BIT 13 @ 7819' 0 @ 8189' 3.4 1.22 KLBS ROTARY RPM 86 @ 7923' 1 @ 8096' 43.1 0.00 RPM PUMP PRESSURE 2565 @ 7524' 1910 @ 7487' 2291.8 2279.18 PSI DRILLING MUD REPORT DEPTH 8136' MD / 3258' TVD MW 9.50 VIS 52 PV 13 YP 20 FL 4.2 Gels 5/9/14 CL- 32000 FC 1/2 SOL 6.3 SD 0.10 OIL 1.2/90.0 MBT 3.5 pH 9.9 Ca+ 2400 Alk 0.9 MWD SUMMARY INTERVAL 7474 TO 8222 TOOLS GAMMA, RESISTIVITY, NEUTRON POROSITY, BULK DENSITY GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 190 @ 7954' 2 @ 8176' 30.4 TRIP GAS NA CUTTING GAS @ @ WIPER GAS NA CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 38681 @ 7954' 566 @ 8176' 5878.3 CONNECTION GAS HIGH 0 ETHANE (C-2) 17 @ 8222' 1 @ 8104' 0.4 AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 45 / 30 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION 7948-7961 8175-8195 SAND / TUFFACEOUS SAND SAND 190 UNITS 116 UNITS GAS TYONEK GAS LITHOLOGY SAND / TUFFACEOUS SILTSTONE / TUFFACEOUS CLAYSTONE PRESENT LITHOLOGY SAND DAILY ACTIVITY SUMMARY Good casing test of 3500 psi for 30 minutes. Cut and slip 105’ of drill line during casing test. Tagged cement @ 7373’. Drilled cement from 7373’ to 7373’. The float collar was found at 7378’. Soe depth was 7460’. Drill 20’ of new formation from 7474’ to 7494’. Circulate bottoms up. Perform FIT test: target = 462 psi for a 12.5 ppg EMW, test good to 12.5 ppg EMW. Drill ahead: rotating and sliding from 7494’ to 8222’ CANRIG PERSONNEL ON BOARD 4 DAILY COST $3065 REPORT BY Tollef Winslow Hilcorp Alaska, LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Rance Pederson/ Marvin Rogers DATE Aug 08, 2015 DEPTH 9188' PRESENT OPERATION Drilling Ahead TIME 24:00:00 YESTERDAY 8222' 24 HOUR FOOTAGE 966' CASING INFORMATION 10 3/4" at 3492' 7 5/8" at 7465' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 8936.06 6.49 323.01 4321.28 8998.30 5.98 323.48 4383.15 9060.88 5.73 322.13 4445.41 9122.26 5.52 322.62 4506.49 9184.17 6.56 323.34 4568.06 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3 6 3/4" Varel V513PDHRU 4007828 3x10, 4x9 7474' 1714' 23:27 In Hole DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 144.3 @ 8260' 4.7 @ 8311' 85.7 58.71 FT/HR SURFACE TORQUE 18116 @ 9185' 1964 @ 8314' 15386.7 17834.08 AMPS WEIGHT ON BIT 38 @ 8607' 0 @ 8315' 3.4 5.88 KLBS ROTARY RPM 86 @ 8323' 1 @ 8314' 74.4 82.97 RPM PUMP PRESSURE 2859 @ 9119' 2158 @ 8301' 2628.8 2854.67 PSI DRILLING MUD REPORT DEPTH MW 9.5 VIS 51 PV 14 YP 19 FL 3.8 Gels 5/9/14 CL- 32000 FC 1/2 SOL 6.3 SD 0.10 OIL 1.5/89.7 MBT 3.5 pH 9.6 Ca+ 320 Alk 1.00 MWD SUMMARY INTERVAL 7474' TO 8222' TOOLS GAMMA, RESISTIVITY, NEUTRON POROSITY, BULK DENSITY GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 299 @ 9120' 10 @ 8483' 81.0 TRIP GAS NA CUTTING GAS @ @ WIPER GAS 49 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 60217 @ 9120' 1882 @ 8483' 16002.5 CONNECTION GAS HIGH 0 ETHANE (C-2) 137 @ 8318' 0 @ 8396' 21.3 AVG 0 PROPANE (C-3) 11 @ 9071' 0 @ 9094' 0.1 CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 45 / 150 PENTANE (C-5) @ @ HYDROCARBON SHOWS See Show Reports #3 to #8 INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone / Sand / Tuffaceous Claystone / Tuffaceous Siltstone PRESENT LITHOLOGY Tuffaceous Sandstone DAILY ACTIVITY SUMMARY Drill ahead: rotating and sliding from 8222’ to 8541’. Pump sweep and prepare for wiper trip. Pull out of hole on elevators from 8541’ to 7122’, no difficulties encountered. The hole over displaced by 1.6 barrels. Service the draw works, check the brake and the eaton brake, grease the crown, top drive and blocks. Trip in hole from 7122’ to 8541’, no issues, 49 units of wiper gas. Drill ahead, rotating and sliding from 8541’ to 9188’. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3065 REPORT BY Tollef Winslow Hilcorp Alaska, LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Rance Pederson / Shane Barber DATE Aug 09, 2015 DEPTH 10117' PRESENT OPERATION Drilling to TD TIME 24:00:00 YESTERDAY 9188' 24 HOUR FOOTAGE 929' CASING INFORMATION 10 3/4" at 3492' 7 5/8" at 7465' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9825.51' 6.19 327.66 5205.07' 9887.33' 6.39 327.38 5266.53' 9949.35' 6.47 328.07 5328.16' 10011.92 6.07 328.41 5390.35' 10073.63' 6.08 329.31 5451.71' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3 6 3/4" Varel V513PDHRU 4007828 3x10, 4x9 7474' 2643' 35:38 In Hole DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 220.8 @ 9233' 1.7 @ 9617' 89.4 133.88 FT/HR SURFACE TORQUE 19841 @ 9547' 17093 @ 9474' 18493.8 19533.84 AMPS WEIGHT ON BIT 30 @ 10067' 0 @ 9235' 7.6 0.00 KLBS ROTARY RPM 82 @ 9188' 34 @ 9919' 64.1 50.36 RPM PUMP PRESSURE 3111 @ 10117' 2428 @ 9491' 2787.9 3111.96 PSI DRILLING MUD REPORT DEPTH 10051' MD / 5431' TVD MW 9.55 VIS 57 PV 14 YP 20 FL 3.7 Gels 5/10/14 CL- 33000 FC 1/2 SOL 6.7 SD 0.10 OIL 1.5/89.2 MBT 4.0 pH 0.90 Ca+ 200 Alk 0.90 MWD SUMMARY INTERVAL 7474' TO 9188' TOOLS GAMMA, RESISTIVITY, NEUTRON POROSITY, BULK DENSITY GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 363 @ 9191' 7 @ 9459' 101.6 TRIP GAS 0 CUTTING GAS @ @ WIPER GAS 180 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 71551 @ 9191' 1538 @ 9459' 20153.4 CONNECTION GAS HIGH 0 ETHANE (C-2) 284 @ 9192' 4 @ 9459' 77.7 AVG 0 PROPANE (C-3) 17 @ 9963' @ 1.1 CURRENT 0 BUTANE (C-4) 25 @ 9963' @ CURRENT BACKGROUND/AVG 42 / 75 PENTANE (C-5) @ @ HYDROCARBON SHOWS See Show Reports #9 to #13 INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone / Tuffaceous Claystone / Sand PRESENT LITHOLOGY Tuffaceous Sandstone / Tuffaceous Claystone / Sand DAILY ACTIVITY SUMMARY Drill ahead, rotating and sliding from 9188’ to 9475’. A tandem sweep was pumped to circulate hole clean. Performed flow check to confirm the well was static. Pull out of hole on elevators from 9475’ to 6800’; tight spot at 8799’ and 8373’, the hole took 3 additional barrel of fluid over theoretical volume during the trip. The rig was serviced including greasing the draw works, blocks, crown and checking the brakes. Trip in hole while installing turbulizers every other stand from 6800’ to 9475’. Turbulizers installed to reduce torque. 180 units of wiper trip gas upon circulating bottoms up. Drill ahead, rotating and sliding from 9474’ to 10117’. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3065 REPORT BY Tollef Winslow Hilcorp Alaska, LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Rance Pederson / Shane Barber DATE Aug10, 2015 DEPTH 10200' PRESENT OPERATION Preparing to test BOPS TIME 24:00:00 YESTERDAY 10117' 24 HOUR FOOTAGE 83' CASING INFORMATION 10 3/4" at 3492' 7 5/8" at 7465' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 10135.51' 5.99 328.97 5513.25' 10158.91' 5.82 327.78 5536.53' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3 6 3/4" Varel V513PDHRU 4007828 3x10, 4x9 7474' 10200' 2726' 37.45 1-2-CT-G-X-1-PN-TD TD DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 148.5 @ 10118' 23.4 @ 10147' 88.6 FT/HR SURFACE TORQUE 20484 @ 10122' 17921 @ 10169' 18611.9 AMPS WEIGHT ON BIT 7 @ 10121' 1 @ 10181' 4.5 KLBS ROTARY RPM 81 @ 10122' 41 @ 10126' 45.6 RPM PUMP PRESSURE 3177 @ 10197' 2955 @ 10181' 3087.9 PSI DRILLING MUD REPORT DEPTH 10200' MD / 5577' TVD MW 9.50 VIS 51 PV 13 YP 18 FL 3.6 Gels 5/9/14 CL- 30500 FC 1/2 SOL 6.5 SD 4.0 OIL 1.5/89.6 MBT 4.0 pH 10.0 Ca+ 180 Alk MWD SUMMARY INTERVAL TO TOOLS No tools in the hole GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 252 @ 10134' 32 @ 10177' 77.7 TRIP GAS NA CUTTING GAS @ @ WIPER GAS 250 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 49290 @ 10134' 6397 @ 10177' 15217.4 CONNECTION GAS HIGH 0 ETHANE (C-2) 210 @ 10134' 30 @ 10177' 66.3 AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 0/0 PENTANE (C-5) @ @ HYDROCARBON SHOWS None in the last 24 hours INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Siltstone / Carbonaceous Siltstone / Tuffaceous Sandstone PRESENT LITHOLOGY Carbonaceous Siltstone DAILY ACTIVITY SUMMARY Drill ahead, rotating from 10117’ to 10200’. 10200’ MD is the total depth of the well. Circulate bottoms up then pump two tandem sweeps to clean the hole. The well was flow checked and it was static. Pull out of hole from 10200’ to 7450’ on elevators with no tight spots. The well over displaced by five barrels. Trip in hole from 7450’ to 10140’ on elevators with no tight spots. The hole displacement was 0.5 barrels under displacement. The hole was circulated clean and 250 units of wiper gas were observed with a 10% increase in cuttings. Pulled out of the hole from 10200’ to 9875’ and the checked the well for flow. The well was static. A dry job was pumped. Pulled out of the hole on elevators from 9875’ to 3024’, laying down the turbuliezers. Flow checked at the shoe, the well was static. Continued to pull out of the hole from 3024’ to 609’ laying down the drill pipe. Lay down directional tools and logging while drilling tools including removing the nuclear source and downloading the memory data. Performed general housekeeping. Removed the wear ring. Installed the test plug. Prepared to test BOP. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3065 REPORT BY Tollef Winslow Hilcorp Alaska, LLC Ninilchik Unit DAILY WELLSITE REPORT Grassim Oskolkoff #8 REPORT FOR Rance Pederson / Shane Barber DATE Aug11, 2015 DEPTH 10200' PRESENT OPERATION Preparing to cement 4.5" liner. TIME 24:00:00 YESTERDAY 10200' 24 HOUR FOOTAGE 0' CASING INFORMATION 10 3/4" at 3492' 7 5/8" at 7465' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 10200' MD / 5577' TVD MW 9.65 VIS 55 PV 14 YP 19 FL 636 Gels 6/10/14 CL- 31000 FC 1/2 SOL 6.9 SD 0.10 OIL 1.5/89.2 MBT 4.0 pH 10.0 Ca+ 200 Alk MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 267 CUTTING GAS @ @ WIPER GAS NA CHROMATOGRAPHY (ppm) SURVEY NA METHANE (C-1) @ @ CONNECTION GAS HIGH NA ETHANE (C-2) @ @ AVG NA PROPANE (C-3) @ @ CURRENT NA BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 50 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY No new lithology PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Test Choke manifold. Test BOP's. Remove test plug and rig down test equipment. Rig up Weatherford power tongs and spider elevators. Make up shoe track. Test float. Run in hole with 4.5” liner to 2898’. Rig down weatherford power tongs and spider elevators. Make up hanger packer running tool assembly. Run in hole with 4.5” liner from 300’ to 7400’, filling every 10 stands. Circulate at shoe. Continue running in the hole from 7400’ to 10174’. Fill found at 10174’. Wash down from 10174’ to 10200’. Tag bottom at 10200’. Circualate bottoms up. 267 units of wiper gas observed. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2115 REPORT BY Tollef Winslow