Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation
Commission
HOME
EVENTS
DATA
Data List
Drilling
Production
Orders
Data Miner
Document Search
REPORTS
Reports and Charts
Pool Statistics
FORMS
LINKS
Links
Test Notification
Data Requests
Regulations
Industry Guidance Bulletins
How to Apply
ABOUT US
History
Staff
HELP
Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
216-010
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: 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 11,755 feet N/A feet true vertical 10,737 feet N/A feet Effective Depth measured 11,628 feet 10,948 feet true vertical 10,653 feet 10,183 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 2-7/8" 6.5# / L-80 6,310' MD 6,309' TVD Tubing (size, grade, measured and true vertical depth)2-3/8" 4.7# / L-80 10,973' MD 10,201' TVD Tri-Pt Hyd Pkr 10,948' MD 10,183' TVD Packers and SSSV (type, measured and true vertical depth)N/A N/A N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Todd Sidoti Authorized Title:Operations Manager Contact Email: Contact Phone:777-8443 todd.sidoti@hilcorp.com Senior Engineer:Senior Res. Engineer: 17,693psi Burst 28' 3,000' 8,160psi 3,730psi Collapse 1,130psi 7,020psi 16,769psi Casing Structural 22" 13-3/8" 7" Length 28' 3,000' 6,514' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 0 Casing Pressure Liner 5,438' 1 10,736' 3 Representative Daily Average Production or Injection Data 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-348 170 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 1 Gas-Mcf 0 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 216-010 50-133-10099-02-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 180343 Soldotna Creek Unit (SCU) 31B-04 N/A A028997 6,514' Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Swanson River Field / Hemlock Oil PoolN/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 4-1/2" 6,513' WINJ WAG 1 Water-Bbl MD 28' 3,000' 11,753' 344 t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Meredith Guhl at 2:01 pm, Sep 13, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.09.13 13:23:26 -08'00' Dan Marlowe (1267) DSR-9/13/21 SFD 9/20/2021 RBDMS HEW 9/13/2021 BJM 11/2/21 Updated by DMA 06-22-18 Soldotna Creek Unit Well SCU 31B-04 PTD: 216-010 API: 50-133-10099-02-00 SCHEMATIC TD @ 11,755’ MD / 10,737’ TVD PBTD @ 11,628’ MD / 10,653’ TVD MAX HOLE ANGLE = 48.21° @ 11,755’ MD CASING AND TUBING DETAIL Size WT Grade Conn ID Top Btm 22” - - - Surface 28’ 13-3/8” 54.5 - - 10.050” Surface 3,000’ 7” 29 P-110 - 6.059” Surface 6,514’ 4-1/2” 12.6 L-80 DWC/C-HT 3.833” 6,315’ 11,753’ 2-7/8” 6.5 L-80 8RD EUE 2.441” Surface 6,310’ 2-3/8” 4.7 L-80 8RD EUE 1.995” 6,310’ 10,973’ JEWELRY DETAIL No Depth ID OD Item 1 19’ 2.441” - Tubing Hanger, 2-7/8” 8RD 2 2,541’ 2.441” 4.500” 2-7/8” SFO-1 GLM #9 (Live Valve) 3 4,581’ 2.441” 4.500” 2-7/8” SFO-1 GLM #8 (Live Valve) 4 6,174’ 2.441” 4.500” 2-7/8” SFO-1 GLM #7 (Live Valve) 5 6,310’ 1.995” 3.670” XO, 2-7/8” 8RD x 2-3/8” 8RD 6 7,361’ 1.990” 3.350” 2-3/8” GLMAX-1 GLM #6 (T-1 latch) (Live Valve) 7 8,264’ 1.990” 3.350” 2-3/8” GLMAX-1 GLM #5 (T-1 latch) (Live Valve) 8 8,947’ 1.990” 3.350” 2-3/8” GLMAX-1 GLM #4 (T-1 latch) (Live Valve) 9 9,535’ 1.990” 3.350” 2-3/8” GLMAX-1 GLM #3 (T-1 latch) (Live Valve) 10 10,185’ 1.990” 3.350” 2-3/8” GLMAX-1 GLM #2 (T-1 latch) (Live Valve) 11 10,900’ 1.990” 3.350” 2-3/8” GLMAX-1 GLM #1 (T-1 latch) (Live Valve) 12 10,948’ 2.680” 3.750” 4-1/2” x 2-3/8” Hydraulic Packer 13 10,963’ 1.875” 3.050” X-Nipple 14 10,973’ 1.995” 3.050” WL Entry Guide 7” Window Detail TOW @ 6,514’ BOW @ 6,527’ A 6,315’ 4.190” - 7” X 4-1/2” ZXP liner hanger 22” 13-3/8” 7” 4-1/2” shoe @ 11,753’ 1 X 2 3 4 A 6 7 8 9 11 12 5 10 13 14 PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size SPF Status Date G-2 10,981’ 11,011’ 10,206’ 10,228’ 30' 1-11/16” 6 Open 05/23/18 H-1 11,122’ 11,145’ 10,306’ 10,322’ 23' 1-11/16” 6 Open 02/11/17 H-2 11,186’ 11,212’ 10,350’ 10,374’ 26’ 1-11/16” 6 Open 02/10/17 H-2 11,210’ 11,220’ 10,367’ 10,374’ 10' 1-11/16” 6 Open 02/11/17 H3/H3L 11,242’ 11,329’ 10,389’ 10,448’ 87' 1-9/16" 6 Open 07/08/16 H3/H3L 11,242’ 11,329’ 10,389’ 10,448’ 87' 1-9/16" 6 Open 03/31/16 H-3L 11,330’ 11,347’ 10,450’ 10,461’ 17’ 1-11/16” 6 Open 02/10/17 H-5 11,340’ 11,355’ 10,457’ 10,467’ 15’ 1-11/16” 6 Open 04/04/18 H3/H3L H3L H3L RA Tag 11,044’ RA Tag 11,112’ RA Tag 11,182’ RA Tag 11,252’ H-1 H-2 H5 G-2 SFD 9/20/2021 No new perforations added: unable to get gun assembly down to approved depth. Rig Start Date End Date 8/4/21 8/17/21 E-line crew arrives at location, Spot trucks, Rig up. PT 250/3,000 psi. MU 1.6875" rope socket, 1.6875" CCL, 1.56" jars, 1.6875" FH, 1.6875"x 8' strip gun. RIH to 1,0763.2' sat down. Work tools at different speeds from 60 FPM to 218 FPM, No luck. POOH. OOH, tools look good. Rig down equipment. Secure well. Turn over to production. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name SCU 31B-04 50-133-10099-02-00 216-010 08/17/2021 - Tuesday 08/04/2021 - Wednesday Crew arrives at facility. Discuss job with involved personnel. Rig up E-Line. PT 250 low/ 3,000 high. RIH with 1-11/16" x 19' Strip gun (60 deg, 6SPF), GGR, Impact selector jars to 10,274'. Tagged several times W/ good clean pick up each time. can not pass. POOH. OOH W/ ~4' of carrier caked W/Asphaltine. E-Line rigs down and stages Equipment. Slickline Moves over from another well. Rig up slickline p/t lub. 500 To 2,000psi good test. Rih w/ 1.75'' g-ring @ 10,241'-10,275'- 10,290' bobble thru make several passes cont. to 11,323'slm Tag. POOH. Send E-line crew home. Rih w/ 1.75'' x 15' stem w/ 2-3/8'' scratcher to 9,421'slm w/ tool fell to 9,594' bobbled thru to 10,276' w/tool 20 min. fell to 10,763' w/ tool 20 min, would not fall POOH. RIH w/ 2-3/8'' scratcher flared out so its tight on tubing walls. Bobble through continue to 10,835' SLM bobble thru continue to 10,917' SLM. Bobble thru, RIH to 11,000' SLM. Locate tail at 10,973' SLM pickup slow hang at mandrel 10,960' SLM w/t PU to 10,700' SLM go back down slow. SD at 10,773' SLM work tools thru 5 passes same issue, work 10,835' slm, 10,900' slm (Mandrel #1), then work 10,773' 5 passes each. RIH/w 5' stem /w 1.75'' 9' DD Bailer to 10,763' SLM SD w/t fall through to 10,795' SLM SD w/t fall to 10,811' SLM SD w/t fall thru to 11,300' SLM stop at depth. PU to 10,700' SLM. Work with Different speeds to fall thru tight spots. Slowest we could fall thru on tools own weight was 110-130' per min. All set downs prior was at less then 100' a min did not see more then 50 lbs of overpull thru all 3 tight spots on PU. POOH. OOH. Lay down equipment. Secure well. Turn well over to production, turn in permit. SL crew leaves location. 08/05/2021 - Thursday Crew arrives at location. Permit, JSA. Rig up. PT 250 low/ 3,000 high. RIH with 1-11/16" GGR , 1-11/16" Impact selector jars, 1-11/16" SS, 1-11/16" X 19' STP gun to 10,022' working through spot, tag 10,273'. Try speeds from ~30 FPM-200 FPM stop making progress. POOH. OOH. Replacing GGR in tool string with 1-11/16" CCL shorten overall tool string length. Inspecting STP gun, gun is coated in very light paraffin and thick oil. RIH with 1-11/16" CCL, 1-11/16" Impact selector jars, 1-11/16" SS, 1-11/16" X 19' STP gun to 10,531'. Work through tight spot, fall to 10,756', work but can not make it past 10,756'. POOH. Rig down, secure well. turn well over to production. David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-5245 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt and return one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 08/26/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: SCU 31B-04 Jet Cut (PTD 216-010) FTP Folder Contents: Log Print Files and LAS Data Files: Please include current contact information if different from above. 37' (6HW Received By: 08/30/2021 By Abby Bell at 2:46 pm, Aug 26, 2021 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 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): 11,755'N/A Casing Collapse Structural Conductor Surface 1,130psi Intermediate 7,020psi Production Liner 6,350psi 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: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: July 24, 2021 11,753'5,438' 2-7/8" ; 2-3/8" 10,736' Perforation Depth MD (ft): 6,514' See Attached Schematic 4-1/2" 22" 13-3/8" 18' 7"6,514' 3,000'3,730psi 28' 3,000' 6,513' 28' 3,000' 6.5# L-80 ; 4.7# L-80 TVD Burst 10,973' MD 8,160psi Length Size CO 123A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 AO28997 216-010 50-133-10099-02-00 Soldotna Creek Unit (SCU) 31B-04 Swanson River Field / Hemlock Oil Pool COMMISSION USE ONLY Authorized Name: 7,780psi Tubing Grade: Tubing MD (ft): See Attached Schematic todd.sidoti@hilcorp.com 10,737'11,628'10,653'2,165 N/A 4-1/2" x 2-3/8" Hydraulic Packer ; N/A 10,948' MD / 10,183" TVD ; N/A Perforation Depth TVD (ft): Tubing Size: Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:21 am, Jul 13, 2021 321-348 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.07.12 23:02:12 -08'00' Taylor Wellman (2143) 10-404 DSR-7/13/21 X BJM 7/22/21 DLB 07/13/2021 dts 7/22/2021 JLC 7/22/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.07.22 16:35:32 -08'00' RBDMS HEW 7/26/2021 Well Prognosis Well: SCU 31B-04 Date: 7/12/2021 Well Name: SCU 31B-04 API Number: 50-133-10099-02-00 Current Status: Gas Lifted Oil Well Leg: N/A Estimated Start Date: 7/24/21 Rig: 401 Reg. Approval Req’d? 10-403 Sundry Number: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 216-010 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) Maximum Expected BHP: ~3230 psi @ 10,653’ TVD Based on Hemlock 0.303 psi/ft gradient. Max. Potential Surface Pressure: ~2165 psi Gas gradient to surface @ 0.1 psi/ft Brief Well Summary February 2016: Drilled through H-9; PBTD @ 11,628’ MD. March 2016: Completed in H-4; 87’ of on-rig perfs. IP = 200 BOPD / 26 BWPD. July 2016: H-4 re-perf’d after production totally crashed (<10 BOPD). IP = 80 BOPD / 40 BWPD. October 2016: Pumped xylene and hot asphaltene treatment (“PA072” chemical). Scraped tubing while soaking. Found paraffin during flowback; thickness did not change throughout treatment flowback. Pumped more and well went on vac; left to soak. No production change pre/post-treatment. February 2017: Xylene treatment. No WSR details. Effect unclear since also shot perfs at this time. Shot H-1 (23’), H-3 (34’), and H-5 (17’). IP = 60 BOPD (+10 BOPD) / 135 BWPD (+80 BWPD). Back to pre-perf rates by April 2017 with stable decline for the following year. April 2018: Shot H-5 (15’). Stemmed decline, increased water. IP = 20 BOPD (+5 BOPD) / 150 BWPD (+110 BWPD). May 2018: Shot G-2 (30’). Production initially fell from 22 BOPD to 14 BOPD with no change in water rate, but picked back up to 34 BOPD in early August. Water production up to ~275 BWPD (+125 BWPD). August 2019: Long period of stable flow ends. For the next year, online in fits and spurts < 5 BOPD / > 150 BPWD. October 2020: BOL after being SI for low rate since July 2020. IP = 10 BOPD / 390 BWPD. April 2021: SL tagged obstruction ~11,329’ MD (4/24/21). June 2021: Stable decline with steady GFR. Most recent test @ 5 BOPD / 324 BWPD. The purpose of this work is to improve oil production at low-rate Hemlock and G-Zone well with an additional ~73’ of G-2 perforations. In addition to a net oil increase, this project will provide useful information about current G-2 performance in this area as instances of stand-alone G-2 production are rare. Objectives x Perforate G2 sand as proposed below Well Condition x Slickline tagged fill at 11,329’ in April 2021. x Minimum restriction is 2-3/8” X nipple at 10,963’ (1.875”). E-line Procedure 1. MIRU E-line. Pressure test lubricator to 250 psi low / 3,000 psi high. 2. Perforate the following interval with 1-11/16” Shogun Spiral guns loaded at 6 SPF 60 degree phasing: Sand MD Top MD Bottom TVD Top TVD Bottom Total Footage G2 11,025’ 11,098’ 10,239’ 10,291’ 73’ a. Perforate with the well shut in, we will need to kick the well off with gas lift after perforating. Well Prognosis Well: SCU 31B-04 Date: 7/12/2021 b. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to Geologist (Jeff Nelson) and Reservoir Engineer (Meredyth Richards) for confirmation. c. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record a tubing Surface pressure before each run and after each gun firing of 5, 10, 15 min reading intervals. d. The G2 Tyonek Sand is part of the Hemlock Oil PA governed by Conservation Order 123A. 3. POOH. RDMO e-line. 4. Turn well over to production. Attachments 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic Updated by DMA 06-22-18 Soldotna Creek Unit Well SCU 31B-04 PTD: 216-010 API: 50-133-10099-02-00 SCHEMATIC TD @ 11,755’ MD / 10,737’ TVD PBTD @ 11,628’ MD / 10,653’ TVD MAX HOLE ANGLE = 48.21° @ 11,755’ MD CASING AND TUBING DETAIL Size WT Grade Conn ID Top Btm 22” - - - Surface 28’ 13-3/8” 54.5 - - 10.050” Surface 3,000’ 7” 29 P-110 - 6.059” Surface 6,514’ 4-1/2” 12.6 L-80 DWC/C-HT 3.833” 6,315’ 11,753’ 2-7/8” 6.5 L-80 8RD EUE 2.441” Surface 6,310’ 2-3/8” 4.7 L-80 8RD EUE 1.995” 6,310’ 10,973’ JEWELRY DETAIL No Depth ID OD Item 1 19’ 2.441” - Tubing Hanger, 2-7/8” 8RD 2 2,541’ 2.441” 4.500” 2-7/8” SFO-1 GLM #9 (Live Valve) 3 4,581’ 2.441” 4.500” 2-7/8” SFO-1 GLM #8 (Live Valve) 4 6,174’ 2.441” 4.500” 2-7/8” SFO-1 GLM #7 (Live Valve) 5 6,310’ 1.995” 3.670” XO, 2-7/8” 8RD x 2-3/8” 8RD 6 7,361’ 1.990” 3.350” 2-3/8” GLMAX-1 GLM #6 (T-1 latch) (Live Valve) 7 8,264’ 1.990” 3.350” 2-3/8” GLMAX-1 GLM #5 (T-1 latch) (Live Valve) 8 8,947’ 1.990” 3.350” 2-3/8” GLMAX-1 GLM #4 (T-1 latch) (Live Valve) 9 9,535’ 1.990” 3.350” 2-3/8” GLMAX-1 GLM #3 (T-1 latch) (Live Valve) 10 10,185’ 1.990” 3.350” 2-3/8” GLMAX-1 GLM #2 (T-1 latch) (Live Valve) 11 10,900’ 1.990” 3.350” 2-3/8” GLMAX-1 GLM #1 (T-1 latch) (Live Valve) 12 10,948’ 2.680” 3.750” 4-1/2” x 2-3/8” Hydraulic Packer 13 10,963’ 1.875” 3.050” X-Nipple 14 10,973’ 1.995” 3.050” WL Entry Guide 7” Window Detail TOW @ 6,514’ BOW @ 6,527’ A 6,315’ 4.190” - 7” X 4-1/2” ZXP liner hanger 22” 13-3/8” 7” 4-1/2” shoe @ 11,753’ 1 X 2 3 4 A 6 7 8 9 11 12 5 10 13 14 PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size SPF Status Date G-2 10,981’ 11,011’ 10,206’ 10,228’ 30' 1-11/16” 6 Open 05/23/18 H-1 11,122’ 11,145’ 10,306’ 10,322’ 23' 1-11/16” 6 Open 02/11/17 H-2 11,186’ 11,212’ 10,350’ 10,374’ 26’ 1-11/16” 6 Open 02/10/17 H-2 11,210’ 11,220’ 10,367’ 10,374’ 10' 1-11/16” 6 Open 02/11/17 H3/H3L 11,242’ 11,329’ 10,389’ 10,448’ 87' 1-9/16" 6 Open 07/08/16 H3/H3L 11,242’ 11,329’ 10,389’ 10,448’ 87' 1-9/16" 6 Open 03/31/16 H-3L 11,330’ 11,347’ 10,450’ 10,461’ 17’ 1-11/16” 6 Open 02/10/17 H-5 11,340’ 11,355’ 10,457’ 10,467’ 15’ 1-11/16” 6 Open 04/04/18 H3/H3L H3L H3L RA Tag 11,044’ RA Tag 11,112’ RA Tag 11,182’ RA Tag 11,252’ H-1 H-2 H5 G-2 Updated by MKR 07-08-21 Soldotna Creek Unit Well SCU 31B-04 PTD: 216-010 API: 50-133-10099-02-00 PROPOSED SCHEMATIC TD @ 11,755’ MD / 10,737’ TVD PBTD @ 11,628’ MD / 10,653’ TVD MAX HOLE ANGLE = 48.21° @ 11,755’ MD CASING AND TUBING DETAIL Size WT Grade Conn ID Top Btm 22” - - - Surface 28’ 13-3/8” 54.5 - - 10.050” Surface 3,000’ 7” 29 P-110 - 6.059” Surface 6,514’ 4-1/2” 12.6 L-80 DWC/C-HT 3.833” 6,315’ 11,753’ 2-7/8” 6.5 L-80 8RD EUE 2.441” Surface 6,310’ 2-3/8” 4.7 L-80 8RD EUE 1.995” 6,310’ 10,973’ JEWELRY DETAIL No Depth ID OD Item 1 19’ 2.441” - Tubing Hanger, 2-7/8” 8RD 2 2,541’ 2.441” 4.500” 2-7/8” SFO-1 GLM #9 (Live Valve) 3 4,581’ 2.441” 4.500” 2-7/8” SFO-1 GLM #8 (Live Valve) 4 6,174’ 2.441” 4.500” 2-7/8” SFO-1 GLM #7 (Live Valve) 5 6,310’ 1.995” 3.670” XO, 2-7/8” 8RD x 2-3/8” 8RD 6 7,361’ 1.990” 3.350” 2-3/8” GLMAX-1 GLM #6 (T-1 latch) (Live Valve) 7 8,264’ 1.990” 3.350” 2-3/8” GLMAX-1 GLM #5 (T-1 latch) (Live Valve) 8 8,947’ 1.990” 3.350” 2-3/8” GLMAX-1 GLM #4 (T-1 latch) (Live Valve) 9 9,535’ 1.990” 3.350” 2-3/8” GLMAX-1 GLM #3 (T-1 latch) (Live Valve) 10 10,185’1.990” 3.350” 2-3/8” GLMAX-1 GLM #2 (T-1 latch) (Live Valve) 11 10,900’1.990” 3.350” 2-3/8” GLMAX-1 GLM #1 (T-1 latch) (Live Valve) 12 10,948’2.680” 3.750” 4-1/2” x 2-3/8” Hydraulic Packer 13 10,963’1.875” 3.050” X-Nipple 14 10,973’1.995” 3.050” WL Entry Guide 7” Window Detail TOW @ 6,514’ BOW @ 6,527’ A 6,315’ 4.190” - 7” X 4-1/2” ZXP liner hanger 22” 13-3/8” 7” 4-1/2” shoe @ 11,753’ 1 X 2 3 4 A 6 7 8 9 11 12 5 10 13 14 PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size SPF Status Date G-2 10,981’ 11,011’ 10,206’ 10,228’ 30' 1-11/16” 6 Open 05/23/18 G-2 11,025 11,098 10,239 10,291 73’ TBD TBD Prop. Prop. H-1 11,122’ 11,145’ 10,306’ 10,322’ 23' 1-11/16” 6 Open 02/11/17 H-2 11,186’ 11,212’ 10,350’ 10,374’ 26’ 1-11/16” 6 Open 02/10/17 H-2 11,210’ 11,220’ 10,367’ 10,374’ 10' 1-11/16” 6 Open 02/11/17 H3/H3L 11,242’ 11,329’ 10,389’ 10,448’ 87' 1-9/16" 6 Open 07/08/16 H3/H3L 11,242’ 11,329’ 10,389’ 10,448’ 87' 1-9/16" 6 Open 03/31/16 H-3L 11,330’ 11,347’ 10,450’ 10,461’ 17’ 1-11/16” 6 Open 02/10/17 H-5 11,340’ 11,355’ 10,457’ 10,467’ 15’ 1-11/16” 6 Open 04/04/18 H3/H3L H3L H3L RA Tag 11,044’ RA Tag 11,112’ RA Tag 11,182’ RA Tag 11,252’ H-1 H-2 H5 G-2 G-2 ]CLC '3/9-0+ Pm z4fonloo Regg, James B (CED) From: Taylor Wellman <twellman@hilcorp.com> Sent: Thursday, June 18, 2020 3:17 PM To: Regg, James B (CED) Cc: Wallace, Chris D (CED) Subject: RE: [EXTERNAL] Swanson River SVS Tests - High Annular Pressures Attachments: SRU 42-05X TIO Plot.xlsx; FW: SCU 42-05X MIT Jim, Please find the responses to the wells in question. - 31B-04 (PTD 2160100) 1860 psi Your assumptions are correct on this. This well is currently on fulltime gaslift and this is the source of annular pressure. - 42-05X PTD 2060740) 1700 psi Please see the attached TIO plot for reference. The increased IA pressure is due to the well restarting injection into storage. The pressure trend on the IA follows the injection rates and are indicative of being thermally induced. Also over this timeframe there is a pressure differential between the Tbg and IA that ranged from 400psi—1,000psi. The TxIA differential also increases over time as we are refilling the storage tank the injection/tbg pressure increases. There does not appear to be an integrity issue with TxIA communication at this time but we will continue to monitor for any signs of impaired integrity and make immediate notification to you and Chris if there is in the future. With respect to the 2016 possible TxIA communication I've attached an email with a summary of the diagnostics conducted to ensure the integrity and that the suspected TAA looked to be more of an anomaly than confirmed TxIA communication. If you would like additional information on these wells please let me know. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC — Kenai Ops Manager Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Regg, James B (CED) [mailto:jim.regg@alaska.gov] Sent: Thursday, June 18, 2020 1:10 PM To: Taylor Wellman <twellman@hilcorp.com> Subject: RE: [EXTERNAL] Swanson River SVS Tests - High Annular Pressures I apologize — correct report is attached. Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 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 Jim Regg at 907- 793-1236 or im.re¢¢@alaska.eov. From: Taylor Wellman <twellman@hilcorp,com> Sent: Thursday, June 18, 2020 12:59 PM To: Regg, James B (CED) <iim.regg@alaska.gov> Cc: Wallace, Chris D (CED) <chris.wallace@alaska.gov> Subject: RE: [EXTERNAL] Swanson River SVS Tests - High Annular Pressures Jim, I will dig into this and provide you a response. Can you re -send a copy of the inspection report? The previous one sent is for Kuparuk and ConocoPhillips. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC — Kenai Ops Manager Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Regg, James B (CED) [mailto:iim.regg@alaska.gov] Sent: Thursday, June 18, 2020 12:36 PM To: Taylor Wellman <twellman@hilcorp.com> Cc: Wallace, Chris D (CED) <chris.wallacec"alaska.gov> Subject: [EXTERNAL] Swanson River SVS Tests - High Annular Pressures Attached is our Inspection report for Swanson River SCU wells performed 5/25/2020. The following wells were observed with elevated IA pressures: - 31B-04 (PTD 2160100) 1860 psi - 42-05X (PTD 2060740) 1700 psi Inspector did not indicate 31131-04 as being on gas lift but the most recent well schematic in our well files from a 2018 workover (add perfs) shows live gas lift valves. Please confirm the source of pressure in the IA. Regarding 42-05X, what diagnostics have been done to confirm continued integrity? There were several email exchanges in 2016 regarding possible TxIA communication; the well was allowed to continue in service following diagnostics and some mitigations implemented. Jim Regg Supervisor, Inspections AOGCC 333 W.7'h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 OF TtJ4, • • \177,��� THE STATE Alaska Oil and Gas 0 f T 1 f 1C� Conservation Commission -fiA 333 West Seventh Avenue 1 --11-11111;1*- Anchorage, Alaska 99501-3572* GOVERNOR BILL WALKER g Main: 907.279.1433 ALASts. Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage,AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 31B-04 Permit to Drill Number: 216-010 Sundry Number: 318-192 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French Chair DATED this t 4 day of May,2018. RBDM _ 141 1131 • • RECEIVED. STATE OF ALASKA MAY 0 7 2018 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS GC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations 0 Fracture Stimulate ❑ Repair Well 0 Operations shutdown❑ Suspend ❑ Perforate ❑✓ • Other Stimulate El Pull Tubing ❑ Change Approved Prog am❑ Plug for Redrill El Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: 0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory ❑ Development 2• 216-010 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic 0 Service 0 6.API Number: Anchorage Alaska 99503 50-133-10099-02-TLCj 7.If perforating: 8.Well Name and Number: 4,1',l What Regulation or Conservation Order governs well spacing in this pool? CO 123A- Soldotna Creek Unit(SCU)31 B-04 • Will planned perforations require a spacing exception? Yes ❑ No ❑✓ 9.Property Designation(Lease Number): 10. Field/Pool(s): A028997 • Swanson River Field/Hemlock Oil Pool • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 11,755' • 10,737' 11,628' 10,653' 605 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 18' 22" 28' 28' Surface 3,000' 13-3/8" 3,000' 3,000' 3,730psi 1,130psi Intermediate 6,514' 7" 6,514' 6,513' 8,160psi 7,020psi Production Liner 5,438' 4-1/2" 11,753' 10,736' 17,693psi 16,769psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: 2-7/8" Tubing Grade: 6.5#/L-80 Tubing MD(ft): 6,310' See Attached Schematic See Attached Schematic 2-3/8" 4.7#/L-80 10,973' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Tri-Point Hydraulic Packer; N/A 10,948'MD/10,183'TVD;N/A 12.Attachments: Proposal Summary Q 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: 5/24/2018 Commencing Operations: OIL ❑r • WINJ ❑ WDSPL 0 Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG 0 Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned 0 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramerahitcorp.com Contact Phone: 777-8420 Authorized Signature: O Date:SII/i? COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ^ - ^t 1 18 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ JL ICI Other: Post Initial Injection MIT Req'd? Yes 0 No aRBDMS)NkilAY Spacing Exception Required? Yes ❑ No Subsequent Form Required: (0 .-L(Uil APPROVED BY Approved by:roved COMMISSIONER THE COMMISSION Date: lis it hk C 5 -/(% -I 4 Submit Form and V Form 10-403 Revised 4/201 7 Approved applica O i v i rmittthe date of approval. ttachments ih Duplicate • • Well Prognosis Well: SCU 31B-04 Hilcorp Alaska,Lb Date:5/7/2018 Well Name: SCU 31B-04 API Number: 50-133-10099-02-00 Current Status: Producing Oil Well Leg: N/A Estimated Start Date: May 24th, 2018 Rig: E-line Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 216-010 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: Maximum Expected BHP: — 1,600 psi @ 10,231' TVD (Based on Offset Well 34-04 Buildup 4/30/13) Max. Potential Surface Pressure: — 577 psi (Based on 0.1 psi/ft to surface) Brief Well Summary SCU 31B-04 is a gas lifted oil well that was drilled as a sidetrack to SCU 12A-03 in March 2016. In July 2016 the H3L sands were re-perforated due to a 70% decline in production. Additionally, asphaltene treatments were performed to sustain oil production. The H-1 and H-2 intervals were added in February 2017 and the H-5 was added in April of 2018. Objective:The purpose of this sundry is to perforate the Tyonek G-2 formation. Notes Regarding Wellbore Condition • Slickline will drift and tag prior to E-line procedure below. E-line Procedure: 1. MIRU E-line, PT lubricator to 2,500 psi Hi and 250 psi Low. 2. PU wireline guns. 3. RIH and perforate the following intervals and test the zones individually: Zone Sands Top (MD) Btm (MD) FT Tyonek G2 ±10,981' ±11,015' 34 a. Proposed perfs shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Correlation Log. d. Use Gamma/CCL/to correlate. e. Install Crystal gauges on well before perforating. Record tubing pressures before and after each perforating run. f. All perforations in table above are located in the Tyonek Pool based on Conservation Order No. 123A. 4. RD E-line. 5. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic Soldotna Creek Unit H 0 SCHEMATIC • WelPTDISCU: 2 60 004 API: 50-133-10099-02-00 liilrnrn Moat,LLC CASING AND TUBING DETAIL -I 1 1Y L 22" Size WT Grade Conn ID Top Btm 22" - - - Surface 28' 13-3/8" 54.5 - - 10.050" Surface 3,000' 7" 29 P-110 - _ 6.059" Surface 6,514' 4-1/2" 12.6 L-80 DWC/C-HT 3.833" 6,315' 11,753' 2-7/8" 6.5 L-80 8RD EUE 2.441" Surface 6,310' 2-3/8" 4.7 L-80 8RD EUE 1.995" 6,310' 10,973' 13-3/8" 2 JEWELRY DETAIL K. No Depth ID OD Item 1 19' 2.441" - Tubing Hanger,2-7/8"8RD 2 2,541' 2.441" 4.500" 2-7/8"SFO-1 GLM#9(Live Valve) 3 4,581' 2.441" 4.500" 2-7/8"SF0-1 GLM#8(Live Valve) 4 6,174' 2.441" 4.500" 2-7/8"SF0-1 GLM#7(Live Valve) L 5 6,310' 1.995" 3.670" X0,2-7/8"8RD x 2-3/8"8RD 6 7,361' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#6(T-1 latch)(Live Valve) 7 8,264' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#5(T-1 latch)(Live Valve) 8 _ 8,947' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#4(T-1 latch)(Live Valve) 9 9,535' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#3(T-1 latch)(Live Valve) 10 10,185' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#2(T-1 latch)(Live Valve) 4 I ill 11 10,900' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#1(T-1 latch)(Live Valve) i 12 10,948' 2.680" 3.750" 4-1/2"x 2-3/8"Hydraulic Packer � / 13 10,963' 1.875" 3.050" X-Nipple A X 7 14 10,973' 1.995" 3.050" WL Entry Guide : � ll 7"Window Detail TOW @ 6,514'BOW @ 6,527' C,'a 6 I I `"'7" A 6,315' 4.190" - 7"X 4-1/2"ZXP liner hanger 7 I -' 81 61 4 91 6 a PERFORATIONS II)I h ' Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size SPF Status Date H-1 11,122' 11,145' 10,306' 10,322' 23' 1-11/16" 6 Open 02/11/17 k �' 11 i 4 H-2 11,186' 11,212' 10,350' 10,374' 26' 1-11/16" 6 Open 02/10/17 ' a H-2 11,210' 11,220' 10,367' 10,374' 10' 1-11/16" 6 Open 02/11/17 H3/H3L 11,242' 11,329' 10,389' 10,448' 87' 1-9/16" 6 Open 07/08/16 •yw .._11— or H3/H3L 11,242' • 11,329' 10,389' 10,448' 87' 1-9/16" 6 Open 03,31/16 , 12 I' H-3L 11,330' 11,347' 10,450' 10,461' 17' 1-11/16" 6 Open 02/10/17 + 13 .s H-5 11,340' 11,355' 10,457' 10,467' 15' 1-11/16" 6 Open 04/04/18 RA Tag 11,044' ''14. 111 AI RA Tag 11,112' 0, H-1 RA Tag 11,182' _ 11 H-2 H3/H3L RA Tag 11,252' H3L ' H3L iH5 • Ask '• ' \ ' 4-1/2"shoe @ 11,753' TD @ 11,755'MD/10,737'TVD PBTD @ 11,628'MD/10,653'TVD MAX HOLE ANGLE=48.21°@ 11,755'MD Updated by DMA 04-18-18 Soldotna Creek Unit tiOPOSED SCHEMATO WelPDI.S2 U 60 004 API: 50-133-10099-02-00 ilii,o,o:11111,k".11.1 CASING AND TUBING DETAIL J 1 I, 7 I 22" Size WT Grade Conn ID Top Btm 22" - - - Surface 18' 13-3/8" 54.5 - - 10.050" Surface 3,000' 7" 29 P-110 - 6.059" Surface 6,514' 4-1/2" 12.6 L-80 DWC/C-HT 3.833" 6,315' 11,753' 2-7/8" 6.5 L-80 8RD EUE 2.441" Surface 6,310' 2-3/8" 4.7 L-80 8RD EUE 1.995" 6,310' 10,973' 13-3/8" I JEWELRY DETAIL No Depth ID OD Item 1 19' 2.441" - Tubing Hanger,2-7/8"8RD 2 2,541' 2.441" 4.500" 2-7/8"SF0-1 GLM#9(Live Valve) 3 4,581' 2.441" 4.500" 2-7/8"SFO-1 GLM#8(Live Valve) 4 6,174' 2.441" 4.500" 2-7/8"SFO-1 GLM#7(Live Valve) I hi 5 6,310' 1.995" 3.670" X0,2-7/8"8RD x 2-3/8"8RD 6 7,361' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#6(T-1 latch)(Live Valve) 7 8,264' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#5(T-1 latch)(Live Valve) 8 8,947' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#4(T-1 latch)(Live Valve) 9 9,535' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#3(T-1 latch)(Live Valve) 10 10,185' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#2(T-1 latch)(Live Valve) 4 11 10,900' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#1(T-1 latch)(Live Valve) 11) 12 10,948' 2.680" 3.750" 4-1/2"x 2-3/8"Hydraulic Packer 13 10,963' 1.875" 3.050" X-Nipple A 14 10,973' 1.995" 3.050" WL Entry Guide 7"Window Detail TOW @ 6,514'BOW @ 6,527' /1,.10 (LE i 7" A 6,315' 4.190" - 7"X 4-1/2"ZXP liner hanger A. V• -.,=1', 7 t. ii_t M 80 ,TA '` PERFORATIONS *W I() fl Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size SPF Status Date 4' G-2 ±10,981' ±11,015' ±10,206' ±10,231' ±34' 6 TBD Proposed t7 11 7 ' H-1 11,122' ' 11,145'' • 10,306' 10,322' 23' 1-11/16" 6 Open 02/11/17 A H-2 11,186' , 11,212' • 10,350' 10,374' 26' 1-11/16" 6 Open 02/10/17 - I < ,;_t H-2 11,210' • 11,220' • 10,367' 10,374' 10' 1-11/16" 6 Open 02/11/17 z :. H3/H3L 11,242' • 11,329' • 10,389' 10,448' 87' 1-9/16" 6 Open 07/08/16 120 H3/H3L 11,242' • 11,329' • 10,389' 10,448' 87' 1-9/16" 6 Open 03/31/16 II H-3L 11,330' . 11,347' ' 10,450' 10,461' 17' 1-11/16" 6 Open 02/10/17 13 H-5 11,340'. 11,355' ' 10,457' 10,467' 15' 1-11/16" 6 Open 04/04/18 RA Tag 11,044' G 14 RATag11,112' 6-2 H-1 RA Tag 11,182' H-2 H3/H3L RA Tag 11,252' ' y H3L I H3L H5 1 i• ,d►.` 4.1/2"shoe @ 11,753' TD @ 11,755'MD/10,737'TVD PBTD @ 11,628'MD/10,653'TVD MAX HOLE ANGLE=48.21°@ 11,755'MD Updated by DMA 05-07-18 STATE OF ALASKA � � � '�M ,� &KA OIL AND GAS CONSERVATION CONfNlISSION REPORT OF SUNDRY WELL OPERATIONS APR 2 6 2018 1.Operations Abandon U Plug Perforations U Fracture Stimulate U Pull Tubing LI AeGtown U Performed: Suspend ❑ Perforate ❑✓ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill El =rforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: ❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development Q Exploratory ❑ 216-010 3.Address: 3800 Centerpoint Dr,Suite 1400 Anchorage, Stratigraphic El Service ❑ 6.API Number: AK 99503 50-133-10099-02 7.Property Designation(Lease Number): 8.Well Name and Number: A028997 Soldotna Creek Unit(SCU)31 B-04 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Swanson River Field/Hemlock Oil Pool 11.Present Well Condition Summary: Total Depth measured 11,755 feet Plugs measured N/A feet true vertical 10,737 feet Junk measured N/A feet Effective Depth measured 11,628 feet Packer measured 10,948 feet true vertical 10,653 feet true vertical 10,183 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 18' 22" 28' 28' Surface 3,000' 13-3/8" 3,000' 3,000' 3,730psi 1,130psi Intermediate 6,514' 7" 6,514' 6,513' 8,160psi 7,020psi Production Liner 5,438' 4-1/2" 11,753' 10,736' 17,693psi 16,769psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 2-7/8" 6.5#/L-80 6,310'MD 6,309'TVD Tubing(size,grade,measured and true vertical depth) 2-3/8" 4.7#/L-80 10,973'MD 10,201'TVD Tri-Pt Hyd Pkr 10,948'MD 10,183'TVD Packers and SSSV(type,measured and true vertical depth) N/A N/A N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 4 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 19 26 46 1020 200 Subsequent to operation: 21 2 185 1050 200 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations LI Exploratory❑ Development Q Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil Q Gas El WDSPL❑ 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: 318-103 Chad Helgeson 777-8405 Authorized Name: 9 Ted Kramer Contact Name: Authorized Title: Operations00:e‘.. Manager ,/ ,7 Contact Email: tkramer(c ihilcoro.com Authorized Signature: � Date: //ZS//[! Contact Phone: 777-8420 �BDMS�.�., APR 3 0 2018 22 Form 10-404 Revised 4/2017 5'�'�g Submit Original Only • • Hilcorp Alaska, LLC Well Operations SumMary Well Name Rig API Number Well Permit Number Start Date End Date SCU 31B-04 Completion E-Line 50-133-10099-02 216-010 4/4/18 4/4/18 Daily Operations: 04/04/2018-Wednesday Mobe to location. PTW and JSA. Rig up lubricator. Pressure test to 250 psi low and 2,500 psi high. TP - 1,350 psi. RIH w/ 1-11/16" x 15' ShoGun Spiral strip gun, 6 spf, 60 deg phase and tie into OHL.Tools set down at 11,355'. Called town and discussed. Ran correlation log and send to town. Got ok to perf from 11,340' to 11,355'. Spotted and fired gun with 1,350 psi on well. Saw no pressure increase after 15 min. POOH. All shots fired. Rig down lubricator and equipment. Turn well over to field. • 0 Soldotna Creek Unit Wel11 • SCHEMATIC PTD: 216-01CU -04 PTD: 216-010 API: 50-133-10099-02-00 11ilearn Alaska.LLC L CASING AND TUBING DETAIL 1 1 L 22" Size WT Grade Conn ID Top Btm 22" - - - Surface 28' 13-3/8" 54.5 - - 10.050" Surface 3,000' 7" 29 P-110 - 6.059" Surface 6,514' 4-1/2" 12.6 L-80 DWC/C-HT 3.833" 6,315' 11,753' 2-7/8" 6.5 L-80 8RD EUE 2.441" Surface 6,310' 2-3/8" 4.7 L-80 8RD EUE 1.995" 6,310' 10,973' 13-3/8" 2 JEWELRY DETAIL _ No Depth ID OD Item 1 19' 2.441" - Tubing Hanger,2-7/8"8RD 2 2,541' 2.441" 4.500" 2-7/8"SF0-1 GLM#9(Live Valve) 3 4,581' 2.441" 4.500" 2-7/8"SFO-1 GLM#8(Live Valve) 4 6,174' 2.441" 4.500" 2-7/8"SFO-1 GLM#7(Live Valve) 3 i1 5 —_ 6,310' 1.995" 3.670" X0,2-7/8"8RD x 2-3/8"8RD 6 7,361' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#6(T-1 latch)(Live Valve) 7 8,264' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#5(T-1 latch)(Live Valve) 8 8,947' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#4(T-1 latch)(Live Valve) 9 9,535' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#3(T-1 latch)(Live Valve) 10 10,185' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#2(T-1 latch)(Live Valve) 4 I 1 11 10,900' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#1(T-1 latch)(Live Valve) 12 10,948' 2.680" 3.750" 4-1/2"x 2-3/8"Hydraulic Packer 5 is 13 10,963' 1.875" 3.050" X-Nipple A =' = 14 10,973' 1.995" 3.050" WL Entry Guide 7"Window Detail TOW @ 6,514'BOW @ 6,527' 6 7" A 6,315' 4.190" 7"X 4-1/2"ZXP liner hanger 4. :.l 7 r . t C .# 8 i 'Ir l'� r''aae. J* _ e >; PERFORATIONS 1;7,10 ` Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size SPF Status Date H-1 11,122' 11,145' 10,306' 10,322' 23' 1-11/16" 6 Open 02/11/17 �s 11 7 H-2 11,186' 11,212' 10,350' 10,374' 26' 1-11/16" 6 Open 02/10/17 a H-2 11,210' 11,220' 10,367' 10,374' 10' 1-11/16" 6 Open 02/11/17 I ,tom I H3/H3L 11,242' 11,329' 10,389' 10,448' 87' 1-9/16" 6 Open 07/08/16 , T H3/H3L 11,242' 11,329' 10,389' 10,448' 87' 1-9/16" 6 Open 03/31/16 L , 12r' H-3L 11,330' 11,347' 10,450' 10,461' 17' 1-11/16" 6 Open 02/10/17 13 H-5 I/ 11,340' 11,355' 10,457' 10,467' 15' 1-11/16" 6 Open 04/04/18 r4 i '14 7: RA Tag 11,044 'J le rt RA Tag 11,112' 9r'�...: i H-1 ti,1 LA RA Tag 11,182 i , '" : H-2 el H3/H3L RA Tag 11,252' _' 1 H3L 2 '" H3L '.w H5 ara +,„ 1,:: „1 kl�. 'Y .1-' k k _�4-1/2"shoe @ 11,753' TD @ 11,755'MD/10,737'TVD PBTD @ 11,628'MD/10,653'TVD MAX HOLE ANGLE=48.21°@ 11,755'MD Updated by DMA 04-18-18 OF 7751., • y/, • THE STATE Alaska Oil and Gas of TT ®® S KA Conservation Commission 333 West Seventh Avenue C GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 0,ift ;.�� Main: 907.279.1433 S Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson S`A144� Operations Manager Hilcorp Alaska,LLC 3800 Centerpoint Drive, Suite 1400 Anchorage,AK 99503 Re: Swanson River Field,Hemlock Oil Pool, SCU 31B-04 Permit to Drill Number: 216-010 Sundry Number: 318-103 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French Chair DATED this 2-c) day of March,2018. RECEIVED • • STATE OF ALASKA MAR 1 2 2013 ALASKA OIL AND GAS CONSERVATION COMMISSION 0 312-0 / 1 le APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑✓ Other Stimulate 0 Pull Tubing ❑ Change Approved Program❑ Plug for Redrill 0 Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing 0 Other: ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory ❑ Development 0, 216-010 - 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage Alaska 99503 50-133-10099-02 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 123B,Rule 5 ❑ Soldotna Creek Unit(SCU)31 B-04 s Will planned perforations require a spacing exception? Yes ID No 9. Property Designation(Lease Number): 10.Field/Pool(s): A028997 Swanson River Field/Hemlock Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 11,755' . 10,737' 11,628' 10,653' 605 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 18' 22" 28' 28' Surface 3,000' 13-3/8" 3,000' 3,000' 3,730psi 1,130psi Intermediate 6,514' 7" 6,514' 6,513' 8,160psi 7,020psi Production Liner 5,438' 4-1/2" 11,753' 10,736' 17,693psi 16,769psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: 2-7/8" Tubing Grade: 6.5#/L-80 Tubing MD(ft): 6,310' See Attached Schematic ' See Attached Schematic 2-3/8" 4.7#/L-80 10,973' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Tri-Point Hydraulic Packer;N/A - 10,948'MD/10,183'TVD;N/A 12.Attachments: Proposal Summary ❑✓ Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development Q r Service 0 14.Estimated Date for 15.Well Status after proposed work: 3/26/2018 ❑• ❑ WDSPL ❑ Suspended 0 Commencing Operations: OIL WINJ 16.Verbal Approval: Date: GAS 0 WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ 0 Op Shutdown ❑ Abandoned 0 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson 777-8405 Contact Name: Taylor Nasse Authorized Title: Operations Manager Contact Email: tnasseahilcorp.com J Contact Phone: 777-8354 Authorized Signature: , `/� Date: j/ie./1$ COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31"6- 1 03 Plug Integrity 0 BOP Test El Mechanical Integrity Test 0 Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes 0 No 0 © MAR 2 2 2018 Spacing Exception Required? Yes No Er No Er Subsequent Form Required: RBDMS octoco1/4........________" APPROVED BY Date: `,3 J I`t Approved by: COMMISSIONER THE COMMISSION CtoW3 // ~ r burin Form and VC(�) Form 10-403 Revised 4/2017 APProved application i I rL N Lto of approval. Attachments in Duplicate *); • • Well Prognosis Well: SCU 31B-04 Hilcorp Alaska,LU Date:3/12/2018 Well Name: SCU 31B-04 API Number: 50-133-10099-02-00 Current Status: Producing Oil Well Leg: N/A Estimated Start Date: Mar. 26th, 2018 Rig: E-line Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 216-010 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: Maximum Expected BHP: — 1,647 psi @ 10,412' TVD (Based on PBU 6/10/2016) Max. Potential Surface Pressure: —605 psi (Based on 0.1 psi/ft to surface) Brief Well Summary SCU 31B-04 is a gas lifted oil well that was drilled as a sidetrack to SCU 12A-03 in March 2016. In July 2016 the H3L sands were reperforated due to a 70% decline in production. Additionally, asphaltene treatments were performed to sustain oil production.The H-1 and H-2 intervals were added in February 2017. Objective:The purpose of this sundry is to perforate the Hemlock formation in the H5 Sand to bring into conformance with current gas flooding at Swanson River. �--- SCA- 3 L Z - C`-( Notes Regarding Wellbore Condition • Slickline will drift and tag prior to E-line procedure below. Slickline Procedure: 1. MIRU E-line, PT lubricator to 2,500 psi Hi and 250 psi Low. 2. RU HC wireline guns. 3. RIH and perforate the following intervals and test the zones individually: Zone Sands Top (MD) Btm (MD) FT Hemlock H5 ±11,332' ±11,402' 70 a. Proposed perfs shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Correlation Log. d. Use Gamma/CCL/to correlate. e. Install Crystal gauges on well before perforating. Record tubing pressures before and after each perforating run. f. All perforations in table above are located in the Hemlock Pool based on Conservation Order No. 123B Rule 5. 4. RD E-line. 5. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic Soldotna Creek Unit S ctE M AT I C • Well SCU 31B-04 PTD: 216-010 API: 50-133-10099-02-00 Aileen)Alaska.LLC CASING AND TUBING DETAIL J 1 \ 1 L 22 Size WT Grade Conn ID Top Btm 22" - Surface 28' 13-3/8" 54.5 - - 10.050" Surface 3,000' 7" 29 P-110 - 6.059" Surface 6,514' 4-1/2" 12.6 L-80 DWC/C-HT 3.833" 6,315' 11,753' 2-7/8" 6.5 L-80 8RD EUE 2.441" Surface 6,310' 2-3/8" 4.7 L-80 8RD EUE 1.995" 6,310' 10,973' '13-3/8" JEWELRY DETAIL No Depth ID OD Item 1 19' 2.441" - Tubing Hanger,2-7/8"8RD 2 2,541' 2.441" 4.500" 2-7/8"SFO-1 GLM#9(Live Valve) 3 4,581' 2.441" 4.500" 2-7/8"SF0-1 GLM#8(Live Valve) 4 6,174' 2.441" 4.500" 2-7/8"SF0-1 GLM#7(Live Valve) I Yl 5 6,310' 1.995" 3.670" X0,2-7/8"8RD x 2-3/8"8RD 6 7,361' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#6(T-1 latch)(Live Valve) 7 8,264' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#5(T-1 latch)(Live Valve) 8 8,947' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#4(T-1 latch)(Live Valve) 9 9,535' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#3(T-1 latch)(Live Valve) 10 10,185' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#2(T-1 latch)(Live Valve) 4 k III 11 10,900' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#1(T-1 latch)(Live Valve) --- 12 10,948' 2.680" 3.750" 4-1/2"x 2-3/8"Hydraulic Packer 13 10,963' 1.875" 3.050" X-Nipple A X Z. 14 10,973' 1.995" 3.050" WL Entry Guide 6 0 % 7"Window Detail TOW @ 6,514'BOW @ 6,527' Z4 7 A 6,315' 4.190" - 7"X 4-1/2"ZXP liner hanger -' 7( 8 9 1 tix PERFORATIONS r 10 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size SPF Status Date H-1 11,122' 11,145' 10,306' 10,322' 23' 1-11/16" 6 Open 02/11/17 0..Y 11 —1 -' H-2 11,186' 11,212' 10,350' 10,374' 26' 1-11/16" 6 Open 02/10/17 I" a * H-2 11,210' 11,220' 10,367' 10,374' 10' 1-11/16" 6 Open 02/11/17 1 .1 H3/H3L 11,242' 11,329' 10,389' 10,448' 8T 1-9/16" 6 Open 07/08/16 1,' ......4 H3/H3L 11,242' 11,329' 10,389' 10,448' 87' 1-9/16" 6 Open 03/31/16 L. 12 H-3L 11,330' 11,347' 10,450' 10,461' 17' 1-11/16" 6 Open 02/10/17 4I 131 `a f. ' i ' ', RA Tag 11,044' `n 14 RA Tag 11,112' t " %, `- H-1 a RA Tag 11,182' 4,51 1 }tc. a H-2 ,,''' H3/H3L RA Tag 11,252' H3L r.'*i. H3L / &k•\- 4-1/2"shoe @ 11,753' TD @ 11,755'MD/10,737'TVD PBTD @ 11,628'MD/10,653'TVD MAX HOLE ANGLE=48.21°@ 11,755'MD Updated by JEK 02-17-17 0 PROPOSED WellSnaCreekUnit • Well CU 316-04 PTD: 216-010 . HSCHEMATIC API: 50-133-10099-02-00 !Worn Alaska.LLC CASING AND TUBING DETAIL , J 1 \ iv 1 22" Size WT Grade Conn ID Top Btm 22" - - - Surface 28' 13-3/8" 54.5 - - 10.050" Surface 3,000' 7" 29 P-110 - 6.059" Surface 6,514' 4-1/2" 12.6 L-80 DWC/C-HT 3.833" 6,315' 11,753' 2-7/8" 6.5 L-80 8RD EUE 2.441" Surface 6,310' 2-3/8" 4.7 L-80 8RD EUE 1.995" 6,310' 10,973' '13-3/8" 2 f' JEWELRY DETAIL No Depth ID OD Item 1 19' 2.441" - Tubing Hanger,2-7/8"8RD 2 2,541' 2.441" 4.500" 2-7/8"SFO-1 GLM#9(Live Valve) 3 4,581' 2.441" 4.500" 2-7/8"SFO-1 GLM#8(Live Valve) 4 6,174' 2.441" 4.500" 2-7/8"SFO-1 GLM#7(Live Valve) 1 ill 5 6,310' 1.995" 3.670" X0,2-7/8"8RD x 2-3/8"8RD 6 7,361' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#6(T-1 latch)(Live Valve) 7 8,264' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#5(T-1 latch)(Live Valve) 8 8,947' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#4(T-1 latch)(Live Valve) 9 9,535' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#3(T-1 latch)(Live Valve) 10 10,185' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#2(T-1 latch)(Live Valve) 4 6 iV 11 10,900' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#1(T-1 latch)(Live Valve) 12 10,948' 2.680" 3.750" 4-1/2"x 2-3/8"Hydraulic Packer \ / 13 10,963' 1.875" 3.050" X-Nipple A X Z. 14 10,973' 1.995" 3.050" WL Entry Guide /���6 i 7"Window Detail TOW @ 6,514'BOW @ 6,527' 4` + `"- 7 A 6,315' 4.190" 7"X 4-1/2"ZXP liner hanger IP 7 t 4 8 i r 4 ''''' 1 .' PERFORATIONS t 10 i' * Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size SPF Status Date 11 H-1 11,122' 11,145' 10,306' 10,322' 23' 1-11/16" 6 Open 02/11/17 11 { ' H-2 11,186' 11,212' 10,350' 10,374' 26' 1-11/16" 6 Open 02/10/17 H-2 11,210' 11,220' 10,367' 10,374' 10' 1-11/16" 6 Open 02/11/17 - ., i l ,• H3/H3L 11,242' 11,329' 10,389' 10,448' 87' 1-9/16" 6 Open 07/08/16 44" `- a. H3/H3L 11,242' 11,329' 10,389' 10,448' 87' 1-9/16" 6 Open 03/31/16 / 12 H-3L 11,330' 11,347' 10,450' 10,461' 17' 1-11/16" 6 Open 02/10/17 ` 13 t+. H-5 11,332' 11,402' 10,451' 10,499' 70' TBD tv RA Tag 11,044' ••14 RA Tag 11,112' t• H-1 RA Tag 11,182' I" t H 2 H3/H3L RA Tag 11,252' ...0;) li H3Lt_/ r,,, 32 =C — a l , -,,. , H3L r 3 I. H5 < w. 614 s fiat. -I •tr-vk 9 Gi,t "dlir.--16T tx a..' ,.-- ►▪ ?",4-1/2"shoe @ 11,753' TD @ 11,755'MD/10,737'TVD PBTD @ 11,628'MD/10,653'TVD MAX HOLE ANGLE=48.21°@ 11,755'MD Updated by TWN 03-12-18 • 21 00 10 Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 2 8 0 4 8 RECEIVED Anchorage, AK 99503 Tele: 907 777-8308 fflrnrp:u:emka_t.ts. Fax: 907 777-8510 MAR 09 2017 E-mail: snolan@hilcorp.com DATE 03/08/17 AOGCC DATA t3%O11 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 SCU 31B-04 SCANNED APR 0 7 2017. Prints: Perforation record CD1: Elog digital data SCU_318-04_PERF_10FEB17.pdf 3/1120179:15 AM PDF Document 910 KB SCU_31B-04 PERF_10FEB 17_CorrelationPas... 3/1/2017 10:02 AM LAS File 97 KB SCU_31B-04 PERF_10FEB17_img.tiff 3/1/20179:15 AM TIFF File 2,754KB SCU_31B-04 PERF_10FEB17 Perf 11177-1... 3/1/2017 9:33 AM LAS File 63 KB SCU_31B-04_PERF_10FEB17 Perf 11186-1... 3/1/2017 10:02 AM LAS File 54 KB SCU_318-04 PERF_10FEB17_Perf 11203-1... 3/1/201710:02 AM LAS File 56 KB SCU_318-04 PERF_10FE817 Perf 11210-1... 3/1/2017 10:02 AM LAS File 103 KB SCU_31B-04 PERF_10FEB17 Perf 11330-1... 3/1/2017 10:02 AM LAS File 58 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 B(1.2val2424Z4L,417) : � Date: _el-% ' STATE OF ALASKA AL&OIL AND GAS CONSERVATION COMNI!6SION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon ❑ Plug Perforations H Fracture Stimulate ❑ Pull Tubing H Operations shutdown ❑ Performed: Suspend ❑ Perforate ❑., Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ 8rforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: Asphaltene Treatment ❑., 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development ❑✓ Exploratory ❑ 216-010 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic Service ❑ 6.API Number: Anchorage,AK 99503 50-133-10099-02 7.Property Designation(Lease Number): 8.Well Name and Number: A028997 Soldotna Creek Unit(SCU)31B-04 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Swanson River Field/Hemlock Oil Pool 11.Present Well Condition Summary: Total Depth measured 11,755 feet Plugs measured N/A RECEIVED true vertical 10,737 feet Junk measured N/A Effective Depth measured 11,628 feet Packer measured 10,948 feet FEB 21 2017 true vertical 10,653 feet true vertical 10,183 feet C' AOGC Casing Length Size MD ND Burst Collapse Structural Conductor 18' 22" 28' 28' Surface 3,000' 13-3/8" 3,000' 3,000' 3,730psi 1,130psi Intermediate 6,514' 7" 6,514' 6,513' 8,160psi 7,020psi Production Liner 5,438' 4-1/2" 11,753' 10,736' 17,693psi 16,769psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 2-7/8" 6.5#/L-80 6,310'MD 6,309'ND Tubing(size,grade,measured and true vertical depth) 2-3/8" 4.7#/L-80 10,973'MD 10,201'ND Tri-Pt Hyd Pkr 10,948'MD 10,183'ND Packers and SSSV(type,measured and true vertical depth) N/A N/A N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A SCANNED �+ MAY - 91. [ 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: 58 11 48 920 205 Subsequent to operation: 93 293 218 770 200 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory❑ Development❑✓ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil H Gas ❑ WDSPL 0 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: 317-015 • Contact Joe Kaiser-777-8393 Email jkaiser@hilcorp.com Printed Name Chad HelgesonlgsoTitle Operations Manager Signature ( �/ Phone 907-777-8405 Date ?/21 f(7 2 .z z-./7 Form 10-404 Revised 5/2015B��S �� ,-, 2017 Submit Original Only • • Hilcorp Alaska, LLC Well Operations SumMary Well Name Rig API Number Well Permit Number Start Date End Date SCU 31B-04 Completion E-Line 50-133-10099-02 216-010 2/10/17 2/11/17 Daily Operations: 02/10/2017- Friday Sign in. PTW and JSA. Rig up lubricator, pressure test to 250 psi low and 2,500 psi high. Bleed TP down from 1,400 psi to 150 psi. RIH w/ 1-11/16" x 17', 6 spf,45 deg phase strip gun and tie into Halliburton RMTI log dated 16 Mar 16. Run correlation log and send to town. Get ok to perf from 11,3301-11,347'. Bled tubing down to 157 psi. Spotted shot and fired with 177 tubing pressure. Lost 2 psi and gained it right back. After 45 min TP was 259 psi. POOH. RIH w/ 1-11/16" x 17', 6 spf,45 deg phase strip gun and tie into Halliburton RMTI log dated 16 Mar 16. Run correlation log and send to town. Get ok to perf from 11,203'-11,220'. Spotted shot and fired gun with 286 psi on tubing. Got 1 psi bump and went back to 286 psi. After 5 min pressure was same. POOH. Top 9' shot and the bottom 8' did not fire. Called town and discussed. (11,212' to 11,220' did not shoot). Will come back and shoot that 8' interval later after building gun. RIH w/ 1-11/16" x 17', 6 spf, 45 deg phase strip gun and tie into Halliburton RMTI log dated 16 Mar 16. Run correlation log and send to town. Get ok to perf from 11,186'-11,203'.Spotted shot and fired gun with 288 psi on tubing. Did not see pressure change. POOH. All shots fired. Rig down lubricator and secure well. 02/11/2017 -Saturday Sign in. Mobe to location. PTW and JSA. Rig lub back up. PT to 250 psi low and 2,500 psi high. RIH w/ 1-11/16" x 10', 6 spf, 45 deg phase strip gun and tie into Halliburton RMTI log dated 16 Mar 16. Run correlation log and send to town. Get ok to perf from 11,210'-11,220'.Spotted shot and fired gun with 298 psi on tubing. Did not see pressure change. POOH.All shots fired. RIH w/ 1-11/16" x 23', 6 spf,45 deg phase strip gun and tie into Halliburton RMTI log dated 16 Mar 16. Run correlation log and send to town. Get ok to perf from 11,122'-11,145'. Spotted shot and fired gun with 296 psi on tubing. Did not see pressure change. POOH. All shots fired. Rig down e-line and turn well over to field. Soldotna Creek Unit II SEMATIC 0PTD!2 601004 API: 50433-10099-02-00 Hilcora Alaska.LL(: CASING AND TUBING DETAIL Ji L 22" Size WT Grade Conn _ ID Top Btm 22" - - - Surface 28' 13-3/8" 54.5 10.050" Surface 3,000' 7" 29 P-110 6.059" Surface 6,514' 4-1/2" 12.6 L-80 DWC/C-HT 8RD EUE 3.833" 6,315' 11,753' 2-7/8" 6.5 L-80 2.441" Surface 6,310' 2-3/8" 4.7 L-80 8RD EUE 1.995" 6,310' 10,973' 13-3/8" 2 JEWELRY DETAIL iillir i' I No Depth ID OD Item 1 2 19' 2.441" - Tubing Hanger,2-7/8"8RD 2,541' 2.441" 4.500" 2-7/8"SF0-1 GLM#9(Live Valve) 3 4,581' 2.441" 4.500" 2-7/8"SF0-1 GLM#8(Live Valve) 4 6,174' 2.441" 4.500" 2-7/8"SFO-1 GLM#7(Live Valve) 3 1/1 i 5 6,310' 1.995" 3.670" X0,2-7/8"8RD x 2-3/8"8RD I 6 7,361' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#6(T-1 latch)(Live Valve) 7 8,264' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#5(T-1 latch)(Live Valve) 8 8,947' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#4(T-1 latch)(Live Valve) 9 9,535' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#3(T-1 latch)(Live Valve) 10 10,185' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#2(T-1 latch)(Live Valve) 4 i' 11 10,900' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#1(T-1 latch)(Live Valve) m 12 10,948' 2.680" 3.750" 4-1/2"x 2-3/8"Hydraulic Packer 5 sir 13 10,963' 1.875" 3.050" X-Nipple A ,/ W 14 10,973' 1.995" 3.050" WL Entry Guide CS 7"Window Detail TOW @ 6,514'BOW @ 6,527' A 6 . 7" A 6,315' 4.190" - 7"X 4-1/2"ZXP liner hanger y 7 P te V.` 8 1 14 i PERFORATIONS • 10 a Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size SPF Status Date IH-1 11,122' 11,145' 10,306' 10,322' 23' 1-11/16" 6 Open 02/11/17 '. 11 H-2 11,186' 11,212' 10,350' 10,374' 26' 1-11/16" 6 Open 02/10/17 f a i" H-2 11,210' 11,220' 10,367' 10,374' 10' 1-11/16" _ 6 Open 02/11/17 I III I 4 H3/H3L 11,242' 11,329' 10,389' 10,448' 87' 1-9/16" 6 Open 07/08/16 - _ H3/H3L 11,242' 11,329' 10,389' 10,448' 87' 1-9/16" 6 Open 03/31/16 k 12 e H-3L 11,330' 11,347' 10,450' 10,461' 17' 1-11/16" 6 Open 02/10/17 13 El ,o, is 4,I 14 ',• '* RA Tag 11,044' as S 1i. RA Tag 11,112' , J '.:.rti .. H-1 i. rRa I NO RA Tag 11,182' '.i '- H-2 r.. H3/H3L RA Tag 11,252' 'i "'' H3L r 'Lim H3L 41 AJ R ,. a 12,,k„' s. S 1 ► r,,4-1/2"shoe @ 11,753' TD @ 11,755'MD/10,737'TVD PBTD @ 11,628'MD/10,653'TVD MAX HOLE ANGLE=48.21°@ 11,755'MD Updated by JEK 02-17-17 • • �,OF Tji *.e ���y/�� THE STATE Alaska Oil and Gas fALASI�:A o: � te, Conservation Commission 333 West Seventh Avenue Anchora rh„ e, Alaska 99501-3572 GOVERNOR BILL WALKER g Main: 907.279.1433 OF ALAS� Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager MSR ' Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 31B-04 Permit to Drill Number: 216-010 Sundry Number: 317-015 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 P Foerster Chair DATED this i 3 day of January, 2017. RBDMS LLA .a 2 5 2017 • • RECEIVED • STATE OF ALASKA JAN 1 2011 ALASKA OIL AND GAS CONSERVATION COMMISSION Q I j 3 V/7 APPLICATION FOR SUNDRY APPROVALS AO C 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate 2 • Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number: Exploratory ❑ Development 0 - 216-010 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 50-133-10099-02 . 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 123B,Rule 5 - Will planned perforations require a spacing exception? Yes ❑ No 2Soldotna Creek Unit(SCU)316-04 9.Property Designation(Lease Number): 10.Field/Pool(s): A028997' Swanson River Field/Hemlock Oil Pool - 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 11,755' ' 10,737' ' 11,628' 10,653' 605 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 18' 22" 28' 28' Surface 3,000' 13-3/8" 3,000' 3,000' 3,730psi 1,130psi Intermediate 6,514' 7" 6,514' 6,513' 8,160psi 7,020psi Production Liner 5,438' 4-1/2" 11,753' 10,736' 17,693psi 16,769psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: 2-7/8" Tubing Grade: 6.5#/L-80 Tubing MD(ft): 6,310' See Attached Schematic See Attached Schematic 2-3/8" 4.7#/L-80 10,973' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Tri-Point Hydraulic Packer;N/A 10,948'MD/10,183'ND;N/A 12.Attachments: Proposal Summary 2 Wellbore schematic D 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development 2 Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: January 26,2017 OIL 0 • WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Joe Kaiser-777-8393 Email jkaiser@hilcorp.com Printed Name Chad Helgeson Title 9 Operations Manager Signature �i� `'../✓ Phone 907-777-8405 Date 01//7 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31I— o iG Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ Nod Subsequent Form Required: 0 —L04-1RSDNIS L L JAN2 5 2017 APPROVED BY Approved by: r AL OMMISSIONER THE COMMISSION Date: /-/3 l7 . 1_1. _, 7 F&n 10-403 Revised 1 015 Rr vAd� Ilc�lid for 12 months from the date of approval. Submit Form and Attachmentsin Duplicate (4/, � /,/ . /7 • • Well Prognosis • Hilcoru Alaska,LL Well: SCU 31B-04 Date: 1/11/2017 Well Name: SCU 31B-04 API Number: 50-133-10099-02-00 Current Status: Producing Oil Well Leg: N/A Estimated Start Date: Jan. 27th, 2017 Rig: E-line Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 216-010 First Call Engineer: Joe Kaiser (907) 777-8393 (0) (907) 952-8897(M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824(M) AFE Number: Maximum Expected BHP: — 1,647 psi @ 10,412' ND (Based on PBU 6/10/2016) Max. Potential Surface Pressure: - 605 psi (Based on 0.1 psi/ft to surface) Brief Well Summary SCU 31B-04 is a gas lifted oil well that was drilled as a sidetrack to SCU 12A-03 in March 2016. In July 2016 the H3L sands were reperforated due to a 70% decline in production. Additionally, asphaultene treatments were performed to sustain oil production. Objective:The purpose of this sundry is to perforate the Hemlock formation in the H1, H2, and H3/H3L Sands. Notes Regarding Wellbore Condition • Slickline will drift and tag prior to E-line procedure below. Slickline Procedure: 1. MIRU E-line, PT lubricator to 2,500 psi Hi and 250 psi Low. 2. RU HC wireline guns. 3. RIH and perforate the following intervals and test the zones individually: Zone Sands Top (MD) Btm (MD) FT Hemlock H1 ±11,114' ±11,166' 52 Hemlock H2 ±11,180' ±11,227' 47 Hemlock H3/H3L ±11,240' ±11,385' 145 a. Proposed perfs shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Correlation Log. d. Use Gamma/CCL/to correlate. e. Install Crystal gauges on well before perforating. Record tubing pressures before and after each perforating run. f. All perforations in table above are located in the Hemlock Pool based on Conservation Order No. 1236 Rule 5. 4. RD E-line. 5. Turn well over to production. Attachments: • • Well Prognosis Well: SCU 31B-04 Hilcorp Alaska,LL Date: 1/11/2017 1. Acutal Schematic 2. Proposed Schematic Soldotna Creek Unit 11 • SCHEMATIC 111 Well PTD: 16-010 CU 04 API: 50-133-10099-02-00 Hilcora Alaska.LL(: r CASING AND TUBING DETAIL —J 1 \ " L 22" Size WT Grade Conn ID Top Btm 22" - - - Surface 28' 13-3/8" 54.5 - - 10.050" Surface 3,000' 7" 29 P-110 - 6.059" Surface 6,514' 4-1/2" 12.6 L-80 DWC/C-HT 3.833" 6,315' 11,753' 2-7/8" 6.5 L-80 8RD EUE 2.441" Surface 6,310' 2-3/8" 4.7 L-80 8RD EUE 1.995" 6,310' 10,973' '13-3/8" 2 ( JEWELRY DETAIL No Depth ID OD Item 1 19' 2.441" - Tubing Hanger,2-7/8"8RD 2 2,541' 2.441" 4.500" 2-7/8"SF0-1 GLM#9(Live Valve) 3 4,581' 2.441" 4.500" 2-7/8"SFO-1 GLM#8(Live Valve) 4 6,174' 2.441" 4.500" 2-7/8"SFO-1 GLM#7(Live Valve) 3 ( ill 5 6,310' 1.995" 3.670" X0,2-7/8"8RD x 2-3/8"8RD 6 7,361' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#6(T-1 latch)(Live Valve) 7 8,264' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#5(T-1 latch)(Live Valve) 8 8,947' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#4(T-1 latch)(Live Valve) 9 9,535' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#3(T-1 latch)(Live Valve) 10 10,185' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#2(T-1 latch)(Live Valve) 41 IV 11 10,900' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#1(T-1 latch)(Live Valve) 12 10,948' 2.680" 3.750" 4-1/2"x 2-3/8"Hydraulic Packer 13 10,963' 1.875" 3.050" X-Nipple A Irl \''' 14 10,973' 1.995" 3.050" WL Entry Guide 7"Window Detail TOW @ 6,514'BOW @ 6,527' Z 6 '',7" A 6,315' 4.190" - 7"X 4-1/2"ZXP liner hanger 7 i 8 aw 9 II i • PERFORATIONS 10 P Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size ' SPF Status Date H3/H3L 11,242' 11,329' 10,389' 10,448' 87' 1-9/16" 6 Open 07/08/16 11 r ;i H3/H3L 11,242' 11,329' 10,389' 10,448' 87' 1-9/16" 6 Open 03/31/16 liLmtvic ,, 12Ot' .x 13 x ' 14 1 RA Tag 11,044' 4 RA Tag 11,112' j, x•7 RA Tag 11,182' . ' II 6 H3/H3L RA Tag 11,252' ' H3L I H3L --1.7. •'1 4-1/2"shoe @ 11,753' TD @ 11,755'MD/10,737'TVD PBTD @ 11,628'MD/10,653'TVD MAX HOLE ANGLE=48.21°@ 11,755'MD Updated by DMA 07/14/16 Soldotna Creek Unit II PFl°,1POSED SCHEMATIC • Well PTD!516010CU 04 API: 50-133-10099-02-00 Hikoru Alaska.LLC CASING AND TUBING DETAIL J 1 1 L 22" Size WT Grade Conn _ ID Top Btm 22" - - - Surface 28' 13-3/8" 54.5 - 10.050" Surface 3,000' 7" 29 P-110 - 6.059" Surface 6,514' 4-1/2" 12.6 L-80 DWC/C-HT 3.833" 6,315' 11,753' 2-7/8" 6.5 L-80 8RD EUE 2.441" Surface 6,310' 2-3/8" 4.7 L-80 8RD EUE 1.995" 6,310' 10,973' 13-3/8" 2 JEWELRY DETAIL No Depth ID OD Item 1 19' 2.441" - Tubing Hanger,2-7/8"8RD 2 2,541' 2.441" 4.500" 2-7/8"SF0-1 GLM#9(Live Valve) 3 4,581' 2.441" 4.500" 2-7/8"SF0-1 GLM#8(Live Valve) 4 6,174' 2.441" 4.500" 2-7/8"SFO-1 GLM#7(Live Valve) 3 5 6,310' 1.995" 3.670" X0,2-7/8"8RD x 2-3/8"8RD 6 7,361' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#6(T-1 latch)(Live Valve) 7 8,264' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#5(T-1 latch)(Live Valve) 8 8,947' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#4(Ti- latch)(Live Valve) 9 9,535' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#3(T-1 latch)(Live Valve) 10 10,185' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#2(T-1 latch)(Live Valve) 4 11 1Q900' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#1(Ti- latch)(Live Valve) rr 12 10,948' 2.680" 3.750" 4-1/2"x 2-3/8"Hydraulic Packer 5 s 13 10,963' 1.875" 3.050" X-Nipple A a 14 10,973' 1.995" 3.050" WL Entry Guide , ,x 6 �. ig 7 7 "Window Detail TOW @ 6,514'BOW @ 6,527' A 6,315' 4.190" 7"X 4-1/2"ZXP liner hanger . 7 44.1 '` M. 1r4 PERFORATIONS i1x 111 10 i it Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size SPF Status Date H-1 ±11,114' ±11,166' ±10,156' ±10,192' 52' Proposed 11 t H-2 ±11,180' ±11,227' ±10,202' ±10,234' 47' Proposed e F H-3L ±11,240' ±11,385' ±10,243' ±10,344' 145' Proposed # i1#:i ll H3/H3L 11,242' 11,329' 10,389' 10,448' 87' 1-9/16" 6 Open 07/08/16 - >.d H3/H3L 11,242' 11,329' 10,389' 1Q448' 87' 1-9/16" 6 Open 03/31/16 e, 12I r 13 ri . , 01 x"':14 �„ RA Tag 11,044' '* Jr RA Tag 11,112' , 1. , ,,d H-1 RA Tag 11,182' A, • % 4 '' H-2 ' H3/H3L RA Tag 11,252' :';., H3L sF+ H3L •a. .N, „,,,,, , ....c,,,,,,„„, y; 1° . -► 4-1/2”shoe @ 11,753' TD @ 11,755'MD/10,737'TVD PBTD @ 11,628'MD/10,653'TVD MAX HOLE ANGLE=48.21°@ 11,755'MD Updated by JEK 1-10-17 DATA SUBMITTAL COMPLIANCE REPORT 12/15/2016 Permit to Drill 2160100 Well Name/No. SOLDOTNA CK UNIT 3113-04 Operator HILCORP ALASKA LLC API No. 50-133-10099-02-00 MD 11755 TVD 10737 Completion Date 3/30/2016 Completion Status 1 -OIL Current Status 1 -OIL UIC No REQUIRED INFORMATION Mud Log A5 ` Samples N6 \ Directional Survey Yes✓ DATA INFORMATION w1d Types Electric or Other Logs Run: 2"/5"ROP-DGR-EWR-ALD-CTN MD/TVD, 2"/5"Formation Log MD/TV (data taken from Logs Portion of Master Well Data Maint) Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH / Type Med/Frmt Number Name Scale Media No Start Stop CH Received Comments ED C 27026 Digital Data 6490 11755 4/8/2016 Electronic Data Set, Filename: SCU 3113- 04_final.las ED C 27026 Digital Data 4/8/2016 Electronic File: SCU 31B-04 TC MD.cgm ED C 27026 Digital Data 4/8/2016 Electronic File: SCU 31B-04 TC TVD.cgm ' ED C 27026 Digital Data 4/8/2016 Electronic File: SCU 31B-04 - Definitive. Survey.pdf ED C 27026 Digital Data 4/8/2016 Electronic File: SCU 318-04.txt ED C 27026 Digital Data 4/8/2016 Electronic File: SCU 3113-04 final.dlis , ED C 27026 Digital Data 4/8/2016 Electronic File: SCU 316-04 final.ver i ED C 27026 Digital Data 4/8/2016 Electronic File: SCU 31B-04 TC MD.emf ED C 27026 Digital Data 4/8/2016 Electronic File: SCU 31B-04 TC TVD.emf ED C 27026 Digital Data P 4/8/2016 Electronic File: SCU 31 B-04 TC MD.pdf ED C 27026 Digital Data 4/8/2016 Electronic File: SCU 31B-04 TC TVD.pdf ' ED C 27026 Digital Data 4/8/2016 Electronic File: SCU 31B-04 TC MD.tif - ED C 27026 Digital Data 4/8/2016 Electronic File: SCU 31 B-04 TC TVD.tif ' Log C 27026 Log Header Scans 0 0 2160100 SOLDOTNA CK UNIT 31 B-04 LOG HEADERS Log C 27027 Log Header Scans 0 0 2160100 SOLDOTNA CK UNIT 3113-04 LOG HEADERS ED C 27027 Digital Data 6400 11900 4/8/2016 Electronic Data Set, Filename: SCU 3113-04.1as ED C 27027 Digital Data 4/8/2016 Electronic File: SCU31B-04.dbf , ED C 27027 Digital Data 4/8/2016 Electronic File: SCU31B-04.mdx AOGCC Page I of 6 Thursday, December 15, 2016 DATA SUBMITTAL COMPLIANCE REPORT 12115/2016 Permit to Drill 2160100 Well Name/No. SOLDOTNA CK UNIT 3113-04 Operator HILCORP ALASKA LLC API No. 50-133-10099-02-00 MD 11755 TVD 10737 Completion Date 3/30/2016 Completion Status 1-0I1- Current Status 1-0I1- UIC No ED C 27027 Digital Data 4/8/2016 Electronic File: SCU31B-04 SCL.DBF , ED C 27027 Digital Data 4/8/2016 Electronic File: SCU316-04_SCL.MDX • ED C 27027 Digital Data 4/8/2016 Electronic File: SCU3113-04 tvd.dbf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU316-04 tvd.mdx ED C 27027 Digital Data 4/8/2016 Electronic File: scu3lb-04.hdr ' ED C 27027 Digital Data 4/8/2016 Electronic File: scu3lb-04r.dbf' ED C 27027 Digital Data 4/8/2016 Electronic File: scu3lb-04r.mdx' ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 3113-04 Canrig Daily Report #1 17 Feb 2016.pdf I ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Canrig Daily Report #10 26 Feb 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 316-04 Canrig Daily Report #11 27 Feb 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Canrig Daily Report #12 28 Feb 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 316-04 Canrig Daily Report #13 29 Feb 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 3113-04 Canrig Daily Report #14 1 Mar 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Canrig Daily Report #15 2 Mar 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Canrig Daily Report #16 3 Mar 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Canrig Daily Report #17 4 Mar 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Canrig Daily Report #18 5 Mar 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Canrig Daily Report #19 6 Mar 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Canrig Daily Report #2 18 Feb 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Canrig Daily Report #20 7 Mar 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Canrig Daily Report #21 8 Mar 2016.pdf AOGCC Page 2 of 6 Thursday, December 15, 2016 DATA SUBMITTAL COMPLIANCE REPORT 12/15/2016 Permit to Drill 2160100 Well Name/No. SOLDOTNA CK UNIT 3113-04 Operator HILCORP ALASKA LLC API No. 50-133-10099-02-00 MD 11755 TVD 10737 Completion Date 3/30/2016 Completion Status 1 -OIL Current Status 1 -OIL UIC No ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 318-04 Canrig Daily Report #22 9 Mar 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Canrig Daily Report #23 10 Mar 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Canrig Daily Report #24 11 Mar 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Canrig Daily Report #3 19 Feb 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 316-04 Canrig Daily Report #4 20 Feb 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Canrig Daily Report #5 21 Feb 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Canrig Daily Report #6 22 Feb 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Canrig Daily Report #7 23 Feb 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31 B-04 Canrig Daily Report #8 24 Feb 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Canrig Daily Report #9 25 Feb 2016.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 Final Well Report.docx ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 316-04 Final Well - Report.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU31 B-04 - 5in Formation Log - MD.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU31 B-04 - 5in Formation Log' TVD.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU31 B-04 -Drilling Dynamics P Log MD.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU31 B-04 -Drilling Dynamics e Log TVD.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU31 B-04 - Formation Log , P MD.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU31 B-04 - Formation Log 19 TVD.pdf AOGCC Page 3 of 6 Thursday, December 15, 2016 DATA SUBMITTAL COMPLIANCE REPORT 12/15/2016 Permit to Drill 2160100 Well Name/No. SOLDOTNA CK UNIT 3113-04 Operator HILCORP ALASKA LLC API No. 50-133-10099-02-00 MD 11755 TVD 10737 Completion Date 3/30/2016 Completion Status 1 -OIL Current Status 1 -OIL UIC No ED C 27027 Digital Data 4/8/2016 Electronic File: SCU31 B-04 - Gas Ratio Log . Q MD.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU31 B-04 - Gas Ratio Log If TVD.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU31 B-04 - LWD Combo Log" 1 MD.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCI -13113-04 - LWD Combo Log .i TVD.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31 B-04 - 5in Formation Log MD.tif ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31 B-04 - 5in Formation Log ' TVD.tif ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31 B-04 - Drilling Dynamics Log MD.tif ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31 B-04 - Drilling Dynamics ' Log TVD.tif ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31 B-04 - Formation Log 1 MD.tif ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 3113-04 - Formation Log TVD.tif ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 316-04 - Gas Ratio Log MD.tif ' ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31 B-04 - Gas Ratio Log . TVD.tif ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04 - LWD Combo Log - MD.tif ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31B-04- LWD Combo Log ' TVD.tif ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31 B-04 Show Report #1 11117 - 11164.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 3113-04 Show Report #1 11117 - 11164.xls ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 316-04 Show Report #2 11186 - 11222.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31 B-04 Show Report #2 . 11186 - 11222.x1s AOGCC' Page 4 of 6 Thursday, December 15, 2016 DATA SUBMITTAL COMPLIANCE REPORT 12/15/2016 Permit to Drill 2160100 Well Name/No. SOLDOTNA CK UNIT 3113-04 Operator HILCORP ALASKA LLC API No. 50-133-10099-02-00 MD 11755 TVD 10737 Completion Date 3/30/2016 Completion Status 1 -OIL Current Status 1-0I1- UIC No ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 31 B-04 Show Report #3 11261 - 11373.pdf ED C 27027 Digital Data 4/8/2016 Electronic File: SCU 3113-04 Show Report #3 - 11261 - 11373.xis Log C 27027 Mud Log 6515 11755 4/8/2016 Formation Log 5" MD & TVD Formation Log 2" MD & TVD LWD Combo Log 2" MD & TVD Gas Ratio Log 2" MD & TVD ED C 27198 Digital Data 11640 6097 5/20/2016 Electronic Data Set, Filename: SCU_3113- 04 RCBL 16MAR16.las ED C 27198 Digital Data 11640 6097 5/20/2016 Electronic Data Set, Filename: SCU_3113- 04 RMTI_16MAR16.las ED C 27198 Digital Data 5/20/2016 Electronic File: SCU l _31B-04 RCBL_16MAR16.pdf ED C 27198 Digital Data 5/20/2016 Electronic File: SCU 31 B-04 , RCBL_ 16MAR16_img.tif ED C 27198 Digital Data 5/20/2016 Electronic File: SCU_3113-04 RMTI_16MAR16_img.tif ED C 27198 Digital Data 5/20/2016 Electronic File: SCU-04_CBL_16MAR16.pdf ED C 27198 Digital Data 5/20/2016 Electronic File: SCU 31 B- 04_CBL_16MAR16_img.tif , ED C 27198 Digital Data 5/20/2016 Electronic File: SCU _31B- 04 RMTI 16MAR16.pdf Log C 27198 Log Header Scans 0 0 2160100 SOLDOTNA CK UNIT 31 B-04 LOG HEADERS ED C 27609 Digital Data 10/3/2016 Electronic File: SCU 316- 04 PERF 08JUL16.pdf ED C 27609 Digital Data 10/3/2016 Electronic File: SCU_3113- 04_PERF_08JUL16_LAS.zip ED C 27609 Digital Data 10/3/2016 Electronic File: SCU_316- 04_PERF_08JUL16_img.tif Log C 27609 Log Header Scans 0 0 2160100 SOLDOTNA CK UNIT 31 B-04 LOG HEADERS Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments AOGCC Page 5 of 6 Thursday, December 15, 2016 DATA SUBMITTAL COMPLIANCE REPORT 12/15/2016 Permit to Drill 2160100 Well Name/No. SOLDOTNA CK UNIT 31B-04 Operator HILCORP ALASKA LLC MD 11755 TVD 10737 Cuttings INFORMATION RECEIVED Completion Report Y� Production Test Information Of NA Geologic Markers/Tops v COMPLIANCE HISTORY Completion Date: 3/30/2016 Release Date: 1/28/2016 Description Comments: Compliance Reviewed By: Completion Date 3/30/2016 Completion Status 1-0I1- Current Status 1-011- 6514 -OIL6514 11755 3/30/2016 1579 Directional / Inclination Data Mud Logs, Image Files, Digital Data Q NA Mechanical Integrity Test Information Y /19 Composite Logs, Image, Data Files Daily Operations Summary C Cuttings Samples 0/ NA Date Comments API No. 50-133-10099-02-00 UIC No Core Chips Y / Core Photographs Y / Laboratory Analyses Y / A Date: l l f /1,6 AOGCC Page 6 of 6 Thursday, December 15, 2016 21 6010 Seth Nolan Hilcorp Alaska, LLC 27 60 9 GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8308 DATA LOGGED 1111",ri, i:«a:j. LII Fax: 907 777-8510 %oit{i201(o E-mail: snolan@hilcorp.com M. K. BENDED DATE 09/30/16 RECEIVED To: Alaska Oil & Gas Conservation Commission OCT 0 3 2016 Makana Bender G�+ Natural Resource Technician II 40l�+� 333 W 7th Ave Ste 100 Anchorage, AK 99501 Elog and Mudlog prints and digital data Prints: Perforation Record 5" MD CD1: Elog digital data SCU_31B-04_PERF_08JUL16_L.AS.zip 8,15.:2016 8.56 AM yip Archive 92 KB SCU_316-04_PERF_08JUL16.pdf 8,'15,•'25116 8,52 AM PDF Dccument 1,088 KB + SCU 31B-0 PERF_08JUL16_img.tif 8r15r2016 8,52 AM TIF File 3530 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:, A„ 14 , vj „1 Date: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RECEIVED �PP 292016 WELL COMPLETION OR RECOMPLETION REPORT AND LOG - 1 a. Well Status: Oil Q • Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended ❑ 20AAC 25.105 20AAC 25.11U GINJ ❑ WINJ ❑ WAG ❑ WDSPL ❑ No. of Completions: 1b. Well Class: Development Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC Date Comps., Susp., or Aband.: 3/30/2016 • 14. Permit to Drill Number/ Sundry: '216-010/316-158,316-168 yrs 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: February 18, 2016 15. API Number: 50-133-10099-02-00 4a. Location of Well (Governmental Section): Surface: 2032' FNL, 359' FWL, Sec 3, T7N, R9W, SM, AK • Top of Productive Interval: 1057' FNL, 2076' FEL, Sec 4, T7N, R9W, SM, AK Total Depth: 834' FNL, 2396' FEL, Sec 4, T7N, R9W, SM, AK 8. Date TD Reached: February 27, 2016 - 16. Well Name and Number: SCU 31 B-04 9. Ref Elevations: KB: 164' GL: 144' BF: 17. Field / Pool(s): Swanson River Field Hemlock Oil Pool - 10. Plug Back Depth MD/TVD: 11,628' MD / 10,653' TVD 18. Property Designation: A028997 - 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 347966. y- 2459121 • Zone- 4 TPI: x- 345540 y- 2460132 Zone- 4 Total Depth: x- 345223 y- 2460359 Zone- 4 11. Total Depth MD/TVD: • 11,755' MD / 10,737' TVD. 19. Land Use Permit: N/A 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MDfTVD: N/A 5. Directional or Inclination Survey: Yes [2](attached) No ❑ Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: •TOW @ 6,514' MD / 6,513' TVD 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary 2"/5" ROP-DGR-EWR-ALD-CTN MD, 2"/5" DGR-EWR-ALD-CTN TVD, 2" FORMATION LOG MD/TVD, 5" FORMATION LOG MD/TVD, 2" DRILLING DYNAMICS MD/TVD, 2" GAS RATIO MD/TVD, 2" LWD COMBO MD/TVD, FINAL WELL REPORT, CBL 5" MD, RCBL 5" MD, RMTI 5" MD C: .Qi! ��la 1 A'�'� 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH TVD WT. PER GRADE SETTING DEPTH MD HOLE SIZE CASING FT TOP BOTTOM TOP BOTTOM CEMENTING RECORD AMOUNT PULLED 4-1/2" 12.6 L-80 6,315 11,753' 6,314' 10,736' 6" L - 200 bbls 13.1 ppg T - 47 bbls of 15.5 ppg 24. Open to production or injection? Yes ❑ No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number): 11,242' - 11,329' MD / 10,389' - 10,448' TVD 87' Total / 522 holes total Gun Size 1-9/16" 6 SPF COMPLETION DATEI 3l �o l j VERIFIED L_1__ 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 2-7/8" x 2-3/8" 10,973' 10,948' MD / 10,183' TVD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes ❑ No ❑✓ Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: 3/27/2016 Method of Operation (Flowing, gas lift, etc.): Gas Lift Date of Test: 4/21/2016 Hours Tested: 24 Production for Test Period --0.209 Oil -Bbl: Gas -MCF: 102 Water -Bbl: N/A Choke Size: N/A Gas -Oil Ratio: 487 scf/bbl Flow Tubing Press. 290 Casing Press: 895 Calculated 24 -Hour Rate --lo. Oil -Bbl: 209 Gas -MCF: 102 Water -Bbl: N/A Oil Gravity - API (corr): 33 Form 10-407 Revised 11/2015 '� CONTINUED ON PAGE 2 Submit ORIGINIAL o ,�1���� �z r[ RBDMS ��- MAY 0 2 2016 %�� r`z 28. CORE DATA Conventional Co,c(s): Yes ❑ No Q Sidewall Cores: fes ❑ 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 0 N/A If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top N/A Permafrost - Base N/A N/A Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 11,242' 10,389' information, including reports, per 20 AAC 25.071. Tyonek G 10,948' 10,183' Tyonek G2 10,965' 10,195' Hemlock 1 11,118' 10,303' Hemlock 2 11,185' 10,349' H3 11,233' 10,383' H3L 11,250' 10,394' H4 11,375' 10,481' H5 11,425' 10,515' H7 11,624' 10,650' Formation at total depth: Hemlock 31. List of Attachments: Wellbore Schematic, Daily Drilling and Completion Reports, Days vs Depth, MW vs Depth, Casing and Cement Report, Definitive Directional Surveys. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Monty Myers Email: rpm ers hl1cor .com Printed Name: Monty Myers Title: Drilling Engineer Signatur Phone: 777-8431 Date: 4/29/2016 INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 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 11/2015 Submit ORIGINAL Only Soldotna Creek Unit 3113-04 TD: 216--010010 SCHEMATIC PSCU PTD: API: 50-133-10099-02-00 Hilmrn Alaska. LLC, 1 2 I 4 i A h 7 94z F7= 12 13 14 RA Tag 11,044' �. RA Tag 11,112' RA Tag 11,182' RA Tag 11,252' 22" �in2t` 13-3/8" CASING AND TUBING DETAIL Size WT Grade Conn ID Top Btm 22" - Tubing Hanger, 2-7/8" 8RD 2 2,541' Surface 28' 13-3/8" 54.5 4,581' 2.441" 10.050" Surface 3,000' 7" 29 P-110 2-7/8" SFO -1 GLM #7 (Live Valve) 6.059" Surface 6,514' 4-1/2" 12.6 L-80 DWC/C-HT 3.833" 6,315' 11,753' 2-7/8" 6.5 L-80 8RD EUE 2.441" Surface 6,310' 2-3/8" 4.7 L-80 8RD EUE 1.995" 6,310' 1 10,973' JEWELRY DETAIL No Depth ID OD Item 1 19' 2.441" Tubing Hanger, 2-7/8" 8RD 2 2,541' 2.441" 4.500" 2-7/8" SFO -1 GLM #9 (Live Valve) 3 4,581' 2.441" 4.500" 2-7/8" SFO -1 GLM #8 (Live Valve) 4 6,174' 2.441" 4.500" 2-7/8" SFO -1 GLM #7 (Live Valve) 5 6,310' 1.995" 3.670" XO, 2-7/8" 8RD x 2-3/8" 8RD 6 7,361' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #6 (T-1 latch) (Live Valve) 7 8,264' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #5 (T-1 latch) (Live Valve) 8 8,947' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #4 (T-1 latch) (Live Valve) 9 9,535' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #3 (T-1 latch) (Live Valve) 10 10,185' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #2 (T-1 latch) (Live Valve) 11 10,900' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #1(T-1 latch) (Live Valve) 12 10,948' 2.680" 3.750" 4-1/2" x 2-3/8" Hydraulic Packer 13 10,963' 1.875" 3.050" X -Nipple 14 10,973' 1.995" 3.050" WL Entry Guide 7" Window Detail TOW @ 6,514' BOW @ 6,527' A 1 6,315' 4.190" 7" X 4-1/2" ZXP liner hanger PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size SPF Status Date H3/H3L 11,242' 11,329' 10,389' 10,448' 87' 1-9/16" 6 Open 3/31/16 to),'� H3/H3L HR HR 4-1/2" shoe @ 11,753' TD @ 11,755' MD / 10,737' TVD PBTD @ 11,628' MD / 10,653' TVD MAX HOLE ANGLE = 48.21° @ 11,755' MD Updated by CJD 04-27-16 Hilcorp Energy Company Composite Report Well Name: SRF SCU 31B-04 (SCU 12A-03 ST) Field: Swanson River Field County/State: , Alaska i (LAT/LONG): evation (RKB): API #: 50-133-10099-02-00 Spud Date: Job Name: 1610111P SCU 31B-04 (SCU 12A-03 ST) PreDrill Contractor AFE#: 1610111P AFE $: $682,300 Activity Date I Ops Summary 2/2/2016 Mobe Moncla 401 from Kenai to SCU 12A-03 and associated eouioment.,Laid containment and seals, spotted beam, WOR heaters, generator and light plants. Prepped WOR to pull rods. SDFN. 2/3/2016 Held PJSM.,Prep to pull rods. Latched polish rod and BO/LD rod BOP's and stuffing boxes. String weight 28K PU and unseated pump 1 K over string weight. MU stripper head and LD pony and 2 1" rods.,MIRU hot oil unit and tested lines to 1 K - test ok. Pumped 32 bbls of 180deg PW down tbg, stopped pumping due to O burner going out on Unit. RDMU hot oil unit.,TOOH w/ rod string and pump LD same. No sign of visiable damage to string or pump.,RD stripper head and rig floor. LD derrick and secured well head. SDFN. 2/4/2016 Held PJSA, RDMO MONCLA 401 and associated eguigment to SCU 33-33„MIRU Peak 120 ton crane and removed beam and the A frame section of the Lufkin Unit, hauled section to P&S for temporary storage. SDFN. 2/5/2016 Moved out Lukin Pumping Unit,MIRU SL, Tested Lubricator and RIH w/2.35 GR and Tagged hard at 7,899'. POOH metal marking on bottom of GR. PU/MU 2.25 LIB and RIH tag and dropped thru @ 7,933', 8,598', 8,661', 8,756'. Continued RIH and tagged Hard at 9,549' no-go. (POOH LIB showed that the tbg has sections of being rod cut.) RDMO SL. Secured well 2/7/2016 R/D mud pumps, TDS, change house, Pason lines to camp buildings. Change oil in TDS and swivel. Remove torque bushing and install TDS in shipping frame. Remove TDS from rig floor. Rebuild kill HCR and mezzanine kill line valve.,Change out scoping lines on derrick. Rig down mud lines in pits and pumps. R/D electric cables. Spot and rig up office and quarters on 12-3 pad. Begin mud pump maintenance. Prepare and scope down derrick. Prepare derrick for lowering. 11 -ower errick. Lay out felt/liner and set mats on SCU 12-3 pad. 2/8/2016 Rig move. Load out doghouse, combo building and catwalk. Crane BOP, iron roughneck, derrick carrier, sub base. Load out pony subs and sub base equipment., Mobilize cranes to SCU 12-3. Set pony subs, sub base equipment, carrier, derrick. Set HPU combo building. Removed BOP from cradle and hung off �o p� in sub base with hydraulic chain hoist. Spot doghouse and combo building. Install iron roughneck on rig floor.,Set remaining rig mats. Set pits #1 and #2. Set MP `7 #1 and MP #2. Rig up pits and pumps suction and discharge lines. Miscellaneous ground rig up.,Rig up electric, hydraulic and water lines. Prepare to raise �V derrick. Perform derrick inspection. Raise derrick.,Spool drill line. Install torque tube. Scope derrick up. Continue with miscellaneous utilities rig up.,Vacated pad is 50% cleaned up. 2/9/2016 Continue R/up, Install turn buckles on torque tube, Spotted gen #3 and Both boilers. continue hook up elect, water and Mud lines. Continue to bring in Misc. from 322C-04 and staging pads as per permits and organize pad. Set crane and set centrifuge work on welding projects install new section of HP mud line in pump house.,Spot pipe skate and raised ramp. install rig floor wind walls. install rig floor mud manifold Hook up and run Pason lines. Spot pit #3 level camp trailers and p/up TDS install roof on Camps transformer. Had false LEL alarm rig floor 22% all hands mustered Driller suited up SCBA and swep area w/ hand held w/ 0% and disabled alarm gave all clear (Good drill) Continue to bring in Misc. from 322C-04 and staging pads as per permits and organize pad,Finish rigging up TD and function test same. RU rig floor equip. RU gas degasser. Finish hooking up accumulator lines to sub. Set, stand up, and RU gas buster. Build containment for Weatherford hyd equip and other equip that contain hydrocarbons. Haul Weatherford equip, parts conex, and test jt rack to rig. Straighten up and organize trailers on storage pad.,Haul all the rest of the parts connexs from the storage pad and spot in place. Load containment dock w/ Weatherford equip. RU mud line from pumps to sub. RU line from choke manifold. Trim liner and felt around rig and dispose of small sections. Continue hauling assorted equip from old pad and storage pads. Rig is 100% set & 90% rigged up. 2/10/2016 Continue R/up and continue to bring misc. from SCU 322C-04 and both staging pads Continue hooking up Pason wires, replace bad steam lines finish hooking up centrifuge lines, filled up liner wash and functioned test both water pumps for rig finish install of ground rods and wires. Tested new section of HP mud line t/ 5000 psi re -tighten and chg rubber re -test good. test all surfaced hp mud lines t/ 3350 psi (good),Tested rig ESD's good, fill rig water tank fill pits w/ lease water Total safety chk gas system found two bad heads replace same and calibrated and test system. held refresher w/ crew on gas system and SCBA training. set Cmt silo. chg out camp gen-set. chg out crack set of forks on Saxon fork lift continue work on rig acceptance Iist.,R/up and test lines to production tree to pump do tbg taking returns on annulus thru wide open choke and gas buster. well had slight vacuum on both sides crew change finish r/up fill wet leg of gas buster PJSM.,Pump 128 bbls PW at 3 BPM with no pressure and no returns. Shut down and put another 102 bbls PW in the pits. Pump again at 5 BPM and we started to see pressure after pumping 9 bbls. Slow do to 4 BPM and pump another 20 bbls and we got returns. [157 bbls total] Continue pumping and dump 35 bbls oil to cuttings tank. Dump another 4.5 bbls oily water and take returns back to pits.,Pump another 61 bbls with no Iosses.,Shut do and monitor well. Well did not go on a vac or build any pressure. Put the dbl studded adaptor and the spacer spools together while circ and monitoring well.,Start pumping again at 2.7 BPM and caught press and returns right away. Returns were dirty oily water so we continued circ dumping another 54 bbls until it cleaned up. Circ another 12 bbls to establish a loss rate. Well didn't take any fluid.,Shut down and monitor well and it was static. Set BPV, and blow down Iines.,Nipple down tree and remove from cellar. Clean up hanger and wellhead. Hanger neck sticks up 4 1/2” above flange. MU left handed blanking sub in hanger.,Nipple up dbl studded adaptor with spacer spools. Nipple up BOP stack. Nipple up choke line valves and choke line. MU kill line shock hose. Install flow nipple and flowline.,Rig accepted at 0600 hrs on 2/11/2016. 2/11/2016 finish n/up bopes install koomey line instau tarp on cellar door. re-chk all bolts. Pressure up accumula— function test bopes (ok) M/up 2-7/8" test jt fill stack and choke w/ water and Preform shell test 250-3500 os! TIW and safety valve failed. BLM inspector Amanda Eagle on location site orientation and safety meeting,Pull testjt and chk out valves and while testing gas system (ok). Preform 2nd shell test failed and confirmed hanger seals leaking, Isolated stack and test choke manifold and dart valve to 250 psi L and 3500psi H 10/10. While testing discuss rolling test option w/ BLM Amanda Eagle & town. Recived verbal approval from AOGCC to conduct a rolling test on bope w/conditions. Crew change and PJSM on rolling test.,Perform rolling test on Annular to 250 low and 2500 psi hi h. Perform rolling test on upper rams, lower rams, manual kill and choke line valves, and HCR kill and choke line valves to 250 low and 3500 psi high.,Lay do test jt and break off subs. RU to test floor valve and TD valves. Tesco dual TD valved and floor valve failed. RD test equip.,Made the decision to RU and circ well while changing out the TD valves. Blow do TD. MU head pin on landing jt. Pull BPV. MU landing it and RU to circ do tbg taking return off ann valve to choke t2 manifold -Got ready to circ and Pason locked up so we changed out the TD valve while trouble shooting Pason. Contacted Pason tech and they repaired _6c,3 it.,Attempt to test Hyd upper TD valve. No test.,Start to circ down tbg at 2.7 BPM 300 psi. Pumped 1 1/2 bbls and caught pressure. Pumped 2 more bbls and got returns. Dumped 29 bbls of oily water and then it cleaned up. Started taking water back to pits. Raised pump rate to 4 BPM at 600 psi and cir a total of 230 bbls. Tested lower TD valve and floor valve to 250 low and 2500 high for 10 & 10 while circ.,Shut down pump and monitor well to let oil migrate up. Re test upper hyd TD valve. Tested good.,Circ well at 4.2 BPM 632 psi. Dump 86 bbls until it cleaned up good. Keep cir another 29 bbls taking returns back to pits. No losses to well.,Blow down lines. Perform accumulator draw down tests. RU to pull hanger and see is anchor is free. Back out LDS. 2/12/2016 Screw into top of landing it w/ TD. Pull 48k and hanger came off seat. Should have weighed 77k with tbg and block wt. PU 2' and check well for flow or loss. Well static. Continue PU bringing hanger to floor with no wt increase. LD landing jt.,RU Weatherford power tongs and equip.,Lay do tbg hanger with 6' pup. POH laying do 2 7/8 tbg. Cleaning pipe and looking for holes or bad pipe. Layed down 216 its. Should put top of fish at approx. 6424'. Bottom jt had a split collar that looked like it had been rubbed into by a sucker rod. Problem was it was rubbed on the outside of the it. Pictures in o -drive. Hole took 2 bbls over displacement.,Rig down Weatherford equipment and clear floor -Ria up to test BOPs. Fill system w/ water and purge air from system.,Test BOPs on 4 1/2". Test annular to 250 psi low and 2500 psi high for 10 min on each. Test all other BOP equip except blind rams to 250 low and 3500 high for 10 min ea. Perform accumulator draw down test. Had to Grease choke HCR and re -test. Also had to bump the pressure up once on the annular high pressure test.,Pull 4 1/2 test jt and test blind rams to 250 psi low and 3500 psi high for 10 min each. Had issues getting air out of system and had to change out a blown sensor in choke house. Perform choke tests. MU 2 7/8 to it. Fill and purge air from system. Testing upper pipe rams. 2/13/2016 Test BOPS on 2 7/8". Finish test on upper rams and test lower rams. Tested to 250 low and 3500 psi high for 10 min ea. Test annular to 250 low and 2500 psi high for 10 min ea. Had issues w/ air and getting test plug to seat.,RD and blow do test equip and set 6 7/16" wear ring.,Service rig,PU fishing BHA #1= 5 3/4 Bowen overshot. dressed w/ 3.09" arapple w] stop and olain contro, Bumper sub, oil jars, XO, 14 HWDP = 453.66,Check torque on TD, Tongs, and Iron Roughneck. All torques matched. Shimmed TD to center over well.,Continue RIH picking up 4 1/2 DP to 6400'.,Continue RIH picking up pipe slow looking for the top of the fish. Tag top of fish at 6882' Set do 12k on fish. PU and pull 30k over bleeding off jars on way up. MU TD and break circ. Pump 112 GPM, 218 psi. Work pipe down to neutral wt and PU 30k over. Increase pump rate to 225 GPM, 805 psi in the attempt to help free fish. Work pipe several times picking up to 45k over up wt. Slow pump back down so we wouldn't wash out top of fish.,Continue working pipe pulling up to 45k over several times. Cock jars and fire them at 30k over then PU to 50k over. Fire jars 2 more times at 40k over and PU to 50k over. Still no movement. Call town and discuss getting a -line out to cut tbg with chem cutter. Get E - line headed this way.,Continue circ and dump 30 bbls oily water on bottoms up. Looks like we are circ at top of fish. Continue circ while waiting on E-Iine.,RU e - line to run a tbg punch. Test lubricator. Test failed. Rebuild head. Re -test lubricator. 2/14/2016 Continue chg pollard E -line Packing head to Grease head & test lubricator 250-2500 psi (ok) monitor well w/ little to no Iosses,Rih w/ 1=11/16" tbg punch gun w/ 3' loaded w/ 13 shots @ 0 deg phased w/ 3/8" exit hole and de -centralized w/ no problem entering TOF Rih logging and seen anchor and set do an fill @ 10012' wlm (23' below anchor in a 31' jt) logged anchor and tied in and tbg punch f/ 9967' U 9970' wLnnod indication of fire and log punches Good . Pooh I/dn tbg punch all shots fired,M/up and arm 1.875" RTC rih w/ no problem log and tie in to Anchor and tbg punches and sever tbg @ 9970'( right below tbg punches ) leaving 16' stub of 31' jt on top of anchor w/ good indication of fire Pooh log few collars w/ 2' of movement Pooh inspect cutter w/ no sign of blow back. R/dn E-Iine,M/up TDS and p/up and verified tbg free and w/ 14k of extra weight circ surface to surface @ 1990 psi and 387 gpm w/ no chg in fluid monitor static well w/ no Iosses,Pooh f/ 6876' and rack back DP and HWDP. Lay do fishing tools.,Lay do Baker grapple w/jt in tool and break out on catwalk. Tot of the it had a groove cut in it about 2' down that matched the jt we pulled out above it. Break out a couple jts w/ pipe wrenches. Both its had worn spot on one side of the collar like they had been drug across something or something had been drug across them.,Service rig, Grease TD, Drwks, Crown, and Iron Roughneck. Check bolts on drive line, and inspect drwks brakes.,RU Weatherford tongs and equip.,POH laying do 2 7/8 tbg. Cleaning, inspecting, and sucking nerf balls through the tubes. Started getting bent jts after pulling 26 its. continued getting bent jts but they started getting cork screwed on jt # 63. All the rest of the its were bent and cork screwed. Pictures in 0 -drive. Layed do 97 jts and a 15.25 cut off with 13 holes punched in it.,RD Weatherford and clear floor of tools. RU Pollard E -line. PU 7" lubricator, MU 6" GR junk basket, Set bottom of lubricatorjust below bag, Close bag and pull lubricator up against bag. Chain down and test.,RIH w/ 6" GR. Set down at 6786' WLM. Tool hung up. Work 850 over several times to get free. Attempt to pass through but kept setting dn. POH with GR and RD E -line. 2/15/2016 RD a -line. Gage ring had 3/4 to 1" groove cut in the side about 1/2" long. Junk basket was empty.,MU BHA #2 = Silverback window mill, Lower string mill, Flex it, Upper string mill, Bumper sub, Oil jars, XO, !4 jts HWDP = 469.00',RIH to 6795' and start taking wt.,Attempt to ream through tight spot easy. Could tell we were on metal or bad csg due to increase in torque. Decision was made not to damage the csg any worse than it already was.,RU to test csg. Pressure up to 1500 psi. Presure started bleeding dn. Call town and discuss options. Press bled f/ 1500 psi to 1325 in 50 min on a chart.,POH and lay do fishing tools. Mill had 2 spots where the inserts had broken loose on the gage of the mill.,RU to PU 2 7/8 tbg cmt stinger BHA = 2 7/8 mule shoe cut off, 19 jts 2 7/8 tbg, XO, XO = 614.84,RIH with 4 1/2 DP out of the derrick to 7038'.,Continue RIH picking up 4 1/2 DP to 7721'. 2/16/2016 Continue RIH picking up 4 1/2 DP. Ease down last joint from 9916' to 9957' and tagged up twice. Up wt 150K, dwn wt 158K.,LD single, MU 10' and 15' pups, MU topdrive. CBU one time, then cont circ through choke to allow practice on holding 400 psi back pressure with manual choke on choke manifold. Shut down pump.,MU 5' pup, closed TIW and pump in sub on stump (installed wiper ball above TIW valve), RU Schlumberger hardline and manifold. Held PJSM with rig team and SLB cementers.,Prime SLB pump, flush hardline to cuttings box with 5 bbls water. SLB pumped 10 bbls water down DP, SLB PT lines at 1750 and 3000 psi (good tests), Installed wiper ball in pump in sub, SLB mixed and pumped 10 bbls (48 sx) 15.8 ppg cement at 2.6 bpm -500 psi while we held 420 psi Gbackpressure on casing (with manual choke). Shut down SLB pump and closed choke. SLB flushed lines to cuttings box, then pumped 2 bbls fresh water,to clear any cement from hardline and manifold. Rig opened TIW to launch second wiper ball and displaced cement with 125.85 bbls produce water. Initial rate of 2.7 bpm, up to 4 bpm -551 psi, again while holding 412 psi back pressure with manual choke. With 200 strokes to go we eased open manual choke holding 200 psi back pressure, and at pump shut down opened manual choke fully. At shut down we had 80 psi on drillstring.,Bled off psi to zero with 5 bbls back to trip tank. FCP was 2.7 bpm -494 psi. 10 bbls cement = 269.25' of coverage. TOC should be +/- 9686'..Blew down hardline to SLB pump truck and RD same. Broke off TIW/pump in sub/5' pup and LD same. Pulled 10 stands from 9957' to 9300' slowly (1 minute per stand). Pipe pulling dry.,At 9300', installed 6" wiper ball in drill string, MU topdrive and performed one full circ at 391 gpm-1464 psi and had no cement to surface.,Shut down rig pump, blew down topdrive and choke lines, drained poorboy degasser. Cont POOH from 9300' to 2 7/8" tubing at 614'. Lay do XOs. PU pups off walk and break them dn.,Clear floor and RU to LD 2 7/8 tbg. Lay do 19 jts 2 7/8 tbg and mule shoe cut off. RD tbg equip. [Tbg stinger had slight cmt ring on collars but the rest was clean],RU Pollard slick line. Had to steam there real to get there brakes to release. Held PJSM. PU lubricator and get set in table, RU sheaves. Wt indicator line must of had water in it because it was froze or plugged. Thawed there line out. Finished rigging up. Test lubricator to 1000 psi. RIH w/ 4.48 GR. 5,500' at report time,Hauled 70 bbls class 11 junk fluid to G&I I 2/17/2016 Cont RIH w/ 4.48" GR on slickline and tag cmt at 9671' WLM. POOH, RD and released slickline.,RU ,.,tet equipment tied in to annulus valve on wellhead. Closed blind rams and attempt to test casing at 2500 psi for 30 minutes. PSI bled off 300 psi over 30 minutes. Bad test. Called out Tri Point for RTTS. RD test equipmen ., ig crew cut and slipped o riline and service rig while waiting on RTTS and plan forward from town. Decision made to set CIBP. Released Tri Point. Called out Pollard a -line crew and Baker Rep.,Spot Pollard unit, held PJSM, RU sheaves and lubricator. Tested lubricator at 500 psi.,RIH with CIBP on e - line to 6570' with no issues. Obtained casing collar log from 6570' up to 6170' (to be used during liner hanger setting later). Set CIBP at 6542' (5' above casing collar at 6547'). POOH RD Pollard.,RU test equipment tied in to annulus valve on wellhead. Closed blind rams and tested casing at 2500 psi for 30 minutes on chart. Good test. Pumped a total of 87.5 gallons to achieve 2500 psi, bled back 87 gallons. RD test equipment. RD remainder of Pollard equipment.,Staged Baker whipstock tools for PU. PU 6" window mill assembly as follows: 6" starter mill, 5 15/16" lower mill, 6' flex joint, 6.059" upper mill.,Orientate UBHO sub. PU, inspect, and lower whipstock into stack. Install hanging clamps and set do on table. Install anchor bolt to silverback window mill.,RIH slow and smooth with whipstock t/ 6522'. MU topdrive and PU to 6515'.,Hold PJSM and get everything lined up to displace, Displace pumping 10.5 ppg KUL Polymer mud duW11 MTaT,—ng_9_.5ppg produced fluid back to cuttings tank. Displaced at 246 GPM, starting pressure of 347 psi and a final pressure of 1068 psi. Mud came back on planned stks w/ very little interface.,Circ on short system at 112 GPM & 422 psi. Finish hauling produced water to snake pit and haul 45 bbls mud contaminated fluid to G&l. Rinse out pits and build mud. Haul 6% KCL from storage pad and build mud.,Class II fluid hauled to G&1=0 bbls Total class II fluid hauled=70 bbls 2/18/2016 Cont building 10.5 ppg 6% KCL mud while waiting on AOGCC approval to move forward with milling ops. Notified by Drillina Engineer we were approved to set whipstock and mill window at 9:45am. Had Pollard and Gyro Data on location at 09:00 hrs and a -line re -headed for gyro tool.,Shut down rig pump, broke off topdrive. PU single, eased down and tagged CIBP with whipstock at 6532' DPM. Down wt 114K. LD single, PU 15' pup jnt and parked whipstock 5' above CIBP. Held PJSM with Pollard, Gyro Data and rig crew. Hung sheave in derrick, RIH with gyro tool on a -line. Stung into UBHO sub 5 times with an orientation of 240 deg. Turned drill string 1/8 turn to the right and worked it one time.,Re-seated gyro tool twice with a 281 deg orientation. POOH RD Gyro Data and Pollard e- Iine.,Slacked off on drill string from 114K to 102K as per Baker Rep and tripped anchor. PU and verified anchor set. SO to 86K and sheared bolt. PU and verified whipstock set, up wt 110K. LD 15' pup jnt and adjusted topdrive drilling torque to 15,000 ft/lbs.,Mill 6" window from 6514' (top of ramp) to 6518', wob .SK, 197 gpn 822 psi, 65 rpm -4900 ft/lbs on bolt torque, 1-2 ft/hr ROP, MW 10.5 ppg/vis 48. At 6518' topdrive started stalling out with little to no on bottom torque. Rack stand back.,Troubleshoot topdrive rotating/torque issue. Will rollover to "Drilling" phase of wellez as of 18:00 hrs.,No activity on pre -drill after 1800 hrs. Hilcorp Energy Company Composite Report Well Name: SRF SCU 31 B-04 (SCU 12A-03 ST) Field: Swanson River Field County/State: , Alaska i (LAT/LONG): evation (RKB): API #: 50-133-10099-02-00 Spud Date: 2/19/2016 Job Name: 1610111 D SCU 31 B-04 (SCU 12A-03 ST) Drilling Contractor AFE#: 1610111D AFE $: $3,131,960 Is e1- �_c i Activity Date Ops Summary 2/18/2016 No operations took place on this AFE until 1800 hrs where we swapped from the pre -drill to the Drill AFE.;Working on hyd issue w/ TD. Found hyd shuttle valve that had com apart on topdrive hyd manifold. Rebuilt shuttle valve and re -installed. Test run and everything looked good. PU stand and test TD.;Establish parameters, Up wt 110, Dn wt 112, Rt wt 105, 195 GPM, 735 psi. Go back to milling window at 6518' U 6527'.;Milling at 84 RPM, 5800 Tq, 154 GPM, 660 Psi, 0-6 WOB, with no losses to the well.;Continue milling open hole f/ 6527't/6542'. Getting cmt and sandstone at shakers. Changing parameters to try to get mill to make hole. ROP 2 to 5 FPH.;Found best ROP at 112 GPM, 895 psi, 100 RPM, 6.5 to 7.5k Tq., 12k WOB.;Class II fluid hauled to G&1=73 bbls Total class II fluid hauled= 143 bbls Cuttings hauled to G&1=0 bbls Total cuttings hauled to G&I=Obbls 2/19/2016 Cont milling 6" hole from 6542' to 6547' (TD for 20' new formation), in Claystone. WOB 11K, 112 to 197 gpm-642 to 800 psi, 100 rpm -6100 fU1bs on bott torque, 1.5 to 3 fUhr ROP.;Circulate hole clean at 265 gpm-1850 psi. Work mills in/out window with no rotary. Nice and smooth. Rack back stand placing mill at 6503'. Blow down topdrive and mudline.;RU test equipment on drill string and annulus. Purged air from all lines and filled drill pipe. Performed FIT to a 12.9+ EMW using 10.5 ppg mud at 840 psi. Pumped 20 gallons;to achieve 860 psi which bled back to 840 psi over the first 3 minutes, then held solid remaining 10 minutes. Bled off nearly 20 gallons. RD and blew down test Iines.;POOH with mill assembly from 6503'. LD Baker milling assembly. Starter mill 1/2" under gauge, lower mill 1/4" under gauge, upper mill was in gauge. New hole should be in gauge to 6531'.;Clean rig floor, PU testjoint and retrieve wear ring. PU 1 jnt HWDP and MU on bottom of test plug, set test plug. Load choke manifold and lines w/water.; Filling everything w/ water and working the air out #1 valve on the choke manifold started leaking from the stem. Installed new stem packing and finished purging system.;Test BOP equip to 250 and 3500 psi for 10 min on both high and low. Test annular to 250 and 2500 psi for 10 min on both high and low. Test both manual and power chokes.;Perform accumulator test. Only failure we had was the #1 choke manifold valve stem packing on the pre-test and that was repaired.; Witness of test was waived by Jim Regg @ 2:55 PM on Wed 2/17/16. Witness of test was waived by BLM Amanda Eagle @ 2:19 PM on Wed 2/17/16.;Blow do and RD test equip. Break out jt of HWDP off bottom of test plug. Set wear ring. Clear floor and prep to PU BHA.;Hold PJSM. and PU directional drilling assem BHA. Scribe tools and measure TF offset. PU tools to TM collar. MU TD and circ 10 min to warm up tools.;Plug into tools and down load. Took 50 min. Pump on tool again to check tools. Good signal. Shut down and load nukes.;Class II fluid hauled to G&1=0 bbls Total class II fluid hauled=143 bbls Cuttings hauled to G&1=0 bbls Total cuttings hauled to G&I=Obbls 2/20/2016 MU UBHO sub and orient to toolface, TIH with HWDP from derrick, MU jars and single in hole with 12 jnts HWDP to 975'. Cont TIH on 4 1/2" DP from derrick to 4105'. Turn elevators and PU single in hole;with 50 joints 4 1/2" DP to 6467'. TIH from derrick to 6503'. Pollard a -line crew and Gyro Data crew on Iocation.;Held PJSM with rig crew, Pollard and Gyro Data. Hang sheave in derrick. PU gyro tool and RIH 200'. MU XO's and side entry sub in middle of stand 89.;RIH with gyro tool on a -line and seat into UBHO sub. TF reading 160 for 3 check shots. Tighten do packing nut and install clamp on side entry sub. Pump 243 GPM and packing held.;Turn pipe 1/4 turn to the right and work the pipe. TF reading 280. Work do through whipstock. TOW=6514', BOW 6517', Bring on pumps and wash do to 6542'. PU and make connection.; Continue sliding do through out of gauge hole to Bottom at 6547' Holding 265 degrees. Pumping 246 GPM, 2072 psi.;Drill new hole using Gyro f/ 6547' to 6571' holding TF at 290. Pumping at 250 GPM, 2200 Psi, 80 to 250 Diff, 2 to 4 WOB.;PU and take check shot survey to see if we crossed over to gravity. Survey was good. Pull up to side entry sub. Remove clamp and back off wireline packing nut. POH with Gyro and RD e-Iine.;PU std and go back to bottom. Directional drill 6" hole f/ 6571' to 6597'. 251 GPM, 2141 psi, 235 Diff, 45 RPM, 5343 TQ, 2k WOB, Avg ROP 98 FPH, High gas 156 units coal gas.;PU in window and service rig. Shut well in and grind welds off iron roughneck ram. Install new rams and hook up hyd lines. Grease up drwks and check drive line bolts.;MU stand and wash to bottom. Mad Pass last 23'. Had 320 units of gas.; Directional drill 6" hole f/6597' U6659'. 251 GPM, 2064 psi, 115 Diff, 2 to 5 WOB. Rotate 43 RPM, 5400 Tq.;Class II fluid hauled to G&1=0 bbls Total class II fluid hauled=143 bbls Cuttings hauled to G&1=0 bbls Total cuttings hauled to G&I=Obbls 2/21/2016 Cont directional drilling 6" hole from 6659' to 7228', Sliding wob 5 to 10K, 247 gpm-2426 psi, 200 to 300 psi diff, 49 to 70 ft1hr ROP. Rotating wob 6K, 248 gpm- 2521 psi, 60 rpm -5500 fUlbs on bott;torque, 74 to 120 ft/hr ROP. MW 10.5/vis 51, ECD's at 12.5 ppg, BGG 100 units, connection gas 300 to 500 units. Pumped a sweep at 7046' with a 75% increase in cuttings to surface, of fine coal/clay.;At 7228', up wt 116K, dwn wt 11 OK, rot wt 112K. Obtained SPR's.;Cont drilling 6" hole f/ 7228'V7588'. Sperry's ECD is reading f/ 12.3 U 13.1. Calculated ECD is 12.1 ppg. 248 GPM, 2588 Psi, 375 Diff, 60 Rpm, 5700 Tq, 50 to 117 ROP, High gas 803 units.; Background gas is hanging between 200 and 350 units and climbs to 800 units on bottoms up. Also get a 4% increase in flow on bottoms up.;At 7250' we pumped a 20 bbl high vis sweep and had a 50% increase in cuttings.;Take survey, and get slow pump rates. Pump high vis sweep and had 25 % increase in cuttings. Pump at a reduced rate and spot as a balanced 20 bbl plug of 12.6 ppg mud on bottom.;Blow do TD and short trip to window. Had several spots we had to pull 20k over. 7477', 7342', 6943', 6848', 6811', 6702. At 6838' we had work up to 60k over to get through. [.5 bbls under];Service rig, Check drive line bolts, Grease TD, Blocks, Crown, and drwks.;RIH to7588'. Had to work through tight spot at 6835'. Had 13' of fill on bottom. Hole fill was .5 over on trip in.;Class II fluid hauled to G&1=168 bbls Total class II fluid hauled=311 bbls Cuttings hauled to G&1=72 bbls Total cuttings hauled to G&1=72bbls;Rotating hrs=7.89 Sliding hrs=4.55 Distance to plan=7.67 4.23' high & 6.40' right ,i 2/22/2016 Cont circulating hi-wt pill out of hole at —0 gpm-2259 psi. Hole unloaded pretty good. Circulated until —n at shakers.; Resumed drilling from 7588' to 8085', Rotating wob 7K, 241 gpm-2383 psi, 45 rpm-6000 ft/lbs on bott torque, 83 rpm-6800 ft/lbs on bott torque, 9 to 100 fUhr ROP, MW 10.5/vis 50, BGG 100 units.;Pumped a 20 bbl weighted hi-vis sweep while drilling stand down to 8085' (captured from weighted pill spotted before wiper trip).;Cont circulating sweep around at 240 gpm-2400 psi, 45 rpm-5500 ft/lbs off bott torque, had a good 25% increase in cuttings to surface and recovered 20 bbls 10.9 ppg mud back in pill pit).;Cont drilling from 8085' to 8184', wob 6 to 11 K, 239 gpm-2348 psi, 80 rpm-6800 fUlbs on bott torque, 9 to 24 fUhr ROP. BGG 165 units, MW 10.5 ppg/ vis 49. Slow drilling through tuffaceous ashy sand.;Cont drilling directional 6" hole f/ 8184't/8520'. 6 to 13 WOB, 242 GPM, 2600 psi, 340 Diff, 48 RPM, 7200 Tq, BGG 170 units, max gas 600 units. Avg ROP 56 FPH.;Drill directional 6" hole f/ 8520' U 8616'. Sliding, 10 to 16 WOB, 242 GPM, 2737 psi, 280 Diff. Rotating, 8 to 12 WOB, 242 GPM, 2944 Psi, 461 Diff, 46 RPM, 7127 Tq, BGG 150, Max gas 580.;Pump High vis 10.8 ppg sweep and circ hole clean. Had a 25% increase in cuttings. Monitor well, Well flowing 5 BPH, Looks like we got into the water flow. Blow do TD;Short trip to above last trip at 7588'. Had a couple spots we pulled 5 to 10 over but nothing we stopped for. Hole took 2.9 bbls under cal fill.;Run back in the hole to 8560'. Set down twice. PU and MU TD. Wash through with no issues to 8581'. Got back 4.7 bbls over cai fill.;Class II fluid hauled to G&1=112 bbls Total class II fluid hauled=423 bbls Cuttings hauled to G&1=48 bbls Total cuttings hauled to G&1=1 20bbls; Rotating hrs=12.73 Sliding hrs=1.35 Distance to plan= 10.90 .10' high & 10.90' right 2/23/2016 MU last stand and prep to wash single to bottom. Pump on idle and psi climbed significantly trying to packoff, attempted to rotate and string stalled. Down pump and work string. Able to stage pump up;get rotating. Circ at 165 gpm1400 psi, 80 rpm-7600 fUlbs off bott torque and get hole cleaned up. Hole unloaded pea size coal chips at bott up. Had a max of 643 units gas at bott up and MW water cut;from 10.5 to 10.1 ppg. Water probably deteriorated bottom coal. Cont circ until good 10.5 in/out. Gas down to 200 units. Washed down to bottom at 8616'. Racked/drifted 4 1/2" Iiner.;Resumed drilling 6" hole from 8616' to 9019'. Rotating wob 10K, 241 gpm-2800 psi, 80 rpm-7800 fUlbs on bott torque, 50 to 100 fUhr ROP, MW 10.5/vis 46, BGG 180 units, ECD's 12.4 ppg. Adding lube at;8800' due to stick/slip of BHA, to 1 % in system. Cont to see +/- 5 bph flow during connections. Appears to be no gain while drilling/pumping. Did no sliding. Offloaded lead cement into silo.;Pumped a 20 bbl hi-vis sweep at 9019' in anticipation of upcoming slide. 242 gpm-2540 psi, 80 rpm-7200 fUlbs off bott torque. Had a 10% increase in cuttings to surface, but sweep was 25 bbls late!;Cont drilling from 9019' to 9034'. Sliding wob 15K, 240 gpm-2600 psi, 283 psi diff, 5 ft/hr ROP. Rotating wob 9K, 245 gpm-3000 psi, 45 rpm-7000 fUlbs on bott torque, 60 to 120 fUhr ROP.;Cont drilling from 9034' to 9317'. Flow check on conn at 9201'= 7 BPH. Rotating WOB 9K, 245 gpm-3000 psi, 45 rpm-7000 fUlbs on bott torque, 60 to 120 ft1hr ROP.;Flow rate increased from 27% to 32% with 5 bbl gain.;Circulate gas out at 245 GPM/2800 psi while working pipe. Had max gas of 914 units and gas cut mud at 9.8 ppg. (10.5 ppg in/out after circulating gas out.);Cont drilling from 9317' to 9638'. Sliding WOB 15K, 245 gpm-2700 psi, 283 psi diff, 65 fUhr ROP. Rotating WOB 13K, 245 gpm-3000 psi, 45 rpm-7000 fUlbs on bolt torque, 60 to 120 fUhr ROP.;Well flowing at 5 - 6% on connections. Not able to get accurate flow rate. Gaining +-10 BPH while drilling. Weighting system up to 10.6 ppg while drilling.; Circulating sweep around before short trip to 8600'.;Class II fluid hauled to G&1=180 bbls Total class II fluid hauled=603 bbls Cuttings hauled to G&1= 60 bbls Total cuttings hauled to G&1=180 bbls;Rotating hrs=12.7 Sliding hrs= .75 Distance to plan= 3.55 2.06' High & 2.89 Left 2/24/2016 Cont circ sweep around at 9638'. 235 gpm-2069 psi, 50 rpm-7200 fUlbs off bolt torque. Sweep was 25 bbis late to surface, little to no increase in cuttings, still gaining 20-25 bph while pumping.;Drill 6" hole from 9638' to 9700', rot wob 5K, 248 gpm-2471 psi, 50 rpm-7400 ft/lbs on bott torque, increase MW from 10.6 to 10.8 ppg. BGG 300 to 400 units, ECD's at 11.9 to 12.0 ppg.;Cont to rotate/reciprocate string at 9700', pump 247 gpm-2190 psi, 50 rpm-7000 fUlbs torque to get weight up to 10.8 ppg. With good 10.8 in/out, perform 15 minute flow check. Flow at 36 bph-;Drill 6" hole from 9700' to 9825'. Dumped 21 bbls 8.6 ppg water (influx from previous flow check) at bottoms up. Cont wt up from 10.8 to 11.1 ppg while drilling. Rot wob 7K, 247 gpm-2525 psi, 50 rpm-;7100 fUlbs on bott torque, 40 to 100 fUhr ROP, BGG 200 units with 11.1 ppg, ECD's at 12.7 ppg, seeing no gain while drilling. At 9825' obtained survey and SPR's, flow check at 36 bph.;Cont drilling from 9825' to 10,064'. Sliding wob 5K, 233 gpm-2126 psi, 113 psi diff, 70 ft/hr ROP. Rotating wob 7K, 247 gpm-2450 psi, 50 rpm-8100 fUlbs on bott torque, BGG 230 units, ECD's 12.5 ppg.;Cont drilling from 10,064' to 10,322'. Sliding wob 5K, 240 gpm-2260 psi, 121 psi diff, 58 ft/hr ROP. Rotating WOB 7K, 247 gpm-2500 psi, 50 rpm-8100 fUlbs on bott torque, BGG 310 units, ECD's 12.5 ppg;Maintaining MW at 11.1 ppg. Influx at 12 -13 BPH while drilling.;Circulate STS at 240 GPM/2180 psi. Flow check at 45 BPH. (With pump shut down gas increased from 320 units to 662 units with 2% flow.) Obtain SPR's at 10,322'.;Cont drilling from 10,322' to 10,522'. Sliding WOB 5K, 240 gpm-2260 psi, 121 psi diff, 58 fUhr ROP. Rotating WOB 7K, 247 gpm-2500 psi, 50 rpm-8100 fUlbs on bott torque, BGG 310 units, ECD's 12.5 ppg;Class II fluid hauled to G&I =530 bbls Total class II fluid hauled =1133 bbls Cuttings hauled to G&I = 35 bbls Total cuttings hauled to G&I =215 bbls;Rotating hrs =12.2 Sliding hrs = 1.729 Distance to plan = 7.8 7.0' High & 4' Right 2/25/2016 Cont drilling 6" hole from 10 522' to 10 570'. Rot wob 10K, 242 gpm-2467 psi, 50 rpm- 8500 ft/lbs on bott torque, 25 to 80 ft/hr ROP, MW 11.1/vis 46, ECD's 12.6 ppg, BGG 150 units,; seeing 10+ bph gain while drilling.; Circulated surf to surf at 242 gpm-2161 psi, 50 rpm-7800 fUlbs off bott torque, BGG up to 250 units. Performed flow check. 39 bph.;Cont drilling 6" hole from 10,570' to 10,831', sliding wob 10K, 241 gpm-2180 psi, 60 to 200 psi diff, 20 to 70 fUhr ROP. Rotating wob 10K, 241 gpm-2536 psi, 50 rpm-9000 ft/lbs on bolt torque,;MW 11.1/vis 48, ECD's 12.5+, BGG 234 units. At 10,700' were informed to maintain 45 deg Inc and turn right from 290 to 305 deg azimuth, as per Geologist. Flow check at 10,760'= 47 bph.;Seeing 7 to 8 bph gain while drilling. Received shoe track and liner hanger.;Cont drilling 6" hole from 10,831' to 11,009'. Sliding WOB 10K, 241 gpm-2200 psi, 60 to 230 psi diff, 20 to 70 ft/hr ROP. Rotating wob 10K, 241 gpm-2550 psi, 50 rpm-9000 ft/lbs on bott torque,; Circulated surf to surf at 242 gpm-2161 psi, 50 rpm-8200 ftflbs off bott torque, BGG up to 280 units. Performed flow check. 50 BPH. Obtain SPR's.;Cont drilling 6" hole from 11,009' to 11,143'. Sliding WOB 6 K, 241 gpm-2350 psi, 60 to 240 psi diff, 20 to 40 fUhr ROP. Rotating wob 10K, 241 gpm-2536 psi, 50 rpm-9000 ft/lbs on bott torque;,*No significant change in water influx upon drilling into Hemlock formation.; Class II fluid hauled to G&I =136 bbls Total class II fluid hauled =1269 bbls Cuttings hauled to G&I = 24 bbis Total cuttings hauled to G&I =239 bbls;Rotating hrs = 8.39 Sliding hrs = 5.94 Distance to plan = 12.15 2.36 Low and 11.62 Left 2/26/2016 Cont attempt to slide drill for direction twin 11,143'. Stalled motor 3 times as string hangs then slips. N._.., computer for Pason system locked up.;Racked back one stand to stay off bottom while trouble shoot Pason computer. Rotate/reciprocate string, pump at 240 gpm-2100 psi. Pason on and off. TIH one stand and slide to 11,151', rack back stand;again. Cont work and circ string. Pason up and running. 2.5 hrs code 8 on tour sheet for rig repair.; Cont drilling from 11,151' to 11,475'. Rot wob 2 to 9K, 240 gpm-2627 psi, 80 rpm-10,500 ft/lbs on bott torque, 40 to 100 ft/hr ROP, MW 11.1 ppg/vis 46, ECD's 12.5 to 12.6 ppg,. Cutback on bit weight;and sped up rotary to help reduce left hand walk (close approach concerns) in rotation. Flow check at 11,382' was 61 bph. Hauling excess mud from rig to frac tank on storage pad, in case we Iose;all returns in Hemlock formation. Also obtained SPR's at 11,380'.;Cont drilling 6" hole from 11,475' to 11,497'. At 18:45 MW computer lost network. Driller PU off bottom and we lost all returns.;Cut pump to idle, rotate 60 rpm and pull up hole from 11,497' to 10,949' (top of Hemlock at 11,117') idling pump and rotating to break free. Rot at 50 rpm while backreaming up hole. Filling backside;with trip tank. Up wt 190K. At 11,256' and 19 bbls away we got returns at 6% on flow show. Saw SPP with 4 bbis away down DP. At 10,949' flow show up to 10%.;Pump at 122 gpm-647 psi, 30 rpm-8800 fUlbs off bott torque reducing surface volume from 11.1 ppg to 10.8 ppg. Getting pretty much full returns. Max gas of 647 units at bott up.;Circulate 10.8 ppg around at 5 BPM/1500 psi but not able to obtain returns lower than 10.4+ ppg. Flow check at 71 BPH. Max gas 519 units-;Consult with engineer. Weight system back up to 10.9+ ppg. 5 BPM/1500 psi. Continue rotating/reciprocating string 10,944'- 11,004'. Circulate system two times and only able to obtain;10.5 ppg in returns. Flow check at 43 BPH influx. Max gas during circulation 1000 units. Avg gas 320 units.,Wash and ream 11,004' to 11,440'. 30 RPM, 5 BPM/1450 psi. No hole issues with full returns.; Circulate STS with 10.9+ ppg at 5 BPM/1450 psi. Losing +-10 BPH while circulating. Only able to obtain 10.5+ ppg mud returns. High gas 885 units. Flow check 43 BPH influx.;Make connection. Cont drilling from 11,497' to 11,508'. Rot wob 2 to 9K, 240 gpm-2627 psi, 50 rpm-9500 ft/lbs on bott torque, 25 to 40 ft/hr ROP, MW 10.9 ppg/vis 46, ECD's 11.5.;Class II fluid hauled to G&I = 302 bbls Total class II fluid hauled =1571 bbis Cuttings hauled to G&I = 18 bbls Total cuttings hauled to G&I =257 bbls;Rotating hrs = 7.24 Sliding hrs = .75 Distance to plan = 15.01 10.5 High and 10.8 Left 2/27/2016 Cont drilling slowIV from 11 508' to TD at 11,755'. Rot WOB 2 to 9K, 204 gpm-1600 psi, 50 to 80 rpm-9100 to 10,862 ft/lbs on bott torque, 8 to 40 fUhr ROP.;MW 10.9 ppg/vis 46, ECD's 11.5 to 11.8 ppg, BGG 230 units. (TD 11,755' md/10,737' tvd). Had little to no stick slip issues.; Circulate hole clean at 204 gpm-1623 psi, rotating 80 rpm-10,250 fl/lbs off bott torque, BGG 243 units.;Pull up hole from 11,755' to 11,097'. Idled pump and rotated free, but gaining fluid at +/- 60 bph with pump at idle. Increased pump rate to 204 gpm and lost slight fluid while pulling. Up wt 174k.;At 11,190' we could pull free with no pump or rotation, but flow show at 4% and steady gain while pulling. Had to cont pumping at 204 gpm.;Circulated gas and water out at 11,097', 204 gpm-1616 psi, had a max of 1156 units past bottoms up. Watered back mud cut surface volume to a 10.6 ppg. Cont condition mud to 10.9 ppg.;Flow check 63 BPH influx.;Short trip on elevators without issue 11,097 - 10,504'. This 10 stand trip was to insure that we would be able to pull without pumping in order to leave the Hi-vis LCM pill in place.; Circulate and condition mud to 10.9+ ppg in and 10.7 ppg out. 1186 units high gas. Spot 23 bbl Hi-Vis LCM pill out of bit. Flow check 47 BPH.;POOH on elevators 11,097'to 10,063' without issue. Flow check 43 BPH.;Circulate and condition mud to lessen influx at 5 BPM/1380 psi. High gas 1122 units. Flow check 43 BPH.;POOH on elevators 10,063' to 9035' without issue.;Circulate and condition mud to lessen influx at 5 BPM/1450 psi. High gas 1158 units. Flow check 43 BPH.;POOH on elevators 9035' to 8523' without issue.;Class II fluid hauled to G&I = 60 bbis Total class II fluid hauled = 1631 bbls Cuttings hauled to G&I = 10 bbls Total cuttings hauled to G&I =267 bbls;Rotating hrs = 7.75 Sliding hrs = .00 Distance to plan 49.06 47.5 High and 12.25 Left f r1 2/28/2016 POOH on elevators from 8579' to 7460' without issue. Up wt 145K.;MU topdrive, CBU at 204 gpm-1565 psi, rotate 20 rpm-4990 fl/lbs off bott torque. Had a max of 845 units gas at bott up. Spot 20 bbis hi-vis 15 ppg pill. Flow check 31 bph.;Cont pull up hole from 7460' and into casing parking bit at 6348'. No issue pulling BHA through window at 6527';Cut and slip 95' drill line. Service rig and build 90 bbls hi-vis hi-wt pill.;CBU at 204 gpm-1454 psi, 20 rpm-4396 ft/lbs off bott torque. Had a max of 865 units at bott up. Spotted 40 bbis hi-vis 15 ppg pill. Flow check at 8 to 10 bph.;Cont POOH from 6348' to 3413', racking back in derrick. Flow check at 40 bph.;MU topdrive and CBU 204 gpm-648 psi. Spot remainder of hi-vis 15 ppg pill. Flow check at 55 bph. Hauling excess volume to frac tank and G&I.;Cont POOH LD 4 1/2" DP, excess HWDP and BHA. Removed RA sources, but uploaded Slim Phase 4 collar on the ground, to cut time sitting in slips. Well flow up and down 0 to 80 bph. Pretty much all water.;Bit graded: 2-2-CT-S-X-IN-ER-TD. Photos are in o-drive.;Shut well in while rigging up to run liner. Pressure built up to 625 psi in 15 minutes. Bleed down same to 0 psi. Shut back in. Pressure built back up to 415 psi in 1 1/2 hours;while preparing to run liner. Hold PJSM. Bleed off pressure and open blind rams.;Pick up shoe track and check floats. RIH picking up 4 1/2" 12.6# L-80 DWC/C-HT liner to 1665'. Well flowing water at average of 85 BPH. Gas units fluctuating 150 - 550 units.; Encountered obstruction at 1665'. Lay down joint of 4 1/2" liner. Screw in with top drive. Break circulation at 2.5 BPM/210 psi. Rotate pipe at 25 RPM and work string up/down 6'. Well;unloading sand, clay and coal. Gas 100 - 750 units. Return flow is sporadic. Continue working string and allowing well to unload.;Class II fluid hauled to G&I = 320 bbis Total class II fluid hauled = 1951 bbls Cuttings hauled to G&I = 0 bbis Total cuttings hauled to G&I =267 bbls 2/29/2016 Cont to rotate/reciprocate liner at 1665', pumping at 193 gpm-145 psi, 30 rpm-3500 fUlbs torque. Circ until shakers cleaned up. Flow check at that time 85 bph.;Single in hole with 10 jnts 4 1/2" liner from 1665' to 2044' with no obstructions.; Perform another full circ at 200 gpm-179 psi until good mud to surface.;Single in hole with 4 1/2" liner from 2044' to 2833' with no obstructions. MU topdrive and pump pipe volume to fill pipe. Single in hole to 3791'.;MU topdrive and circ at 243 gpm-343 psi, 27 rpm-3644 ft/lbs torque, very little sand or barite at shakers. BGG 274 units and gaining 20 bph while circulating. Hauled off excess trash fluid to G&I.;Transported good mud from frac tank to rig to make room for trash fluid. Flow check at 65 bph.;Single in hole remainder of 4'W liner from 3791' to 5413', PU and MU Baker "HRDE" ZXPN, Flex-Lock liner top packer and hanger assembly, mix and pour PalMix, RD Weatherford and released same.;RU drift to drop in derrick, MU XO and TIH one stand HWDP to 5476'. MU topdrive and circulate, staging pump rate to 248 gpm-560 psi, until good mud at surface.;TIH with HWDP and DP from derrick, dropping drift down stands in derrick. Stopped with shoe just above window at 6508'.;MU topdrive, circ at 207 gpm-590 psi until good mud to surface. After circ, up wt 85K, dwn wt 88K, torque at following RPMs, 10=3560, 20=4100 and 30=4300 ft/lbs. MU Baker cement head to single joint.;RIH with liner assembly on drill pipe from 6508' to 7048' drifting stands in derrick.;Engage tight spot at 7048'. Packing off and unable to rotate. Pull up to 155K to free pipe. Had to pull back up hole to 6842' before being able to rotate and circulate. Work pipe while;circulating at staged rates up to 5 BPM/710 psi. Rotating at 15 RPM/5150 ft/lbs torque. Hole unloaded with 1 1/2" cuttings (clay, sand, coal) over shakers at bottoms up with;high gas of 812 units. Circulate until shakers cleared up.;Wash and ream in hole with liner assembly from 6842' to 7785'. 4.5 BPM1700 - 950 psi, 25 RPM/5500 ft/lbs torque. Pump rate appears to be keeping influx in check and staying below hanger setting psi.;Mud weights 10.9 ppg in /10.8 ppg out. Water influx area possibly partially bridged off.;Class II fluid hauled to G&I = 1170 bbls Total class II fluid hauled = 3121 bbis Cuttings hauled to G&I = 0 bbls Total cuttings hauled to G&I =267 bbis 3/1/2016 Cont wash and ream in hole with liner a. sembly from 7785'to 8324', 150 gpm-669 psi, 30 rpm-4900 fti .,. torque. Getting a constant supply of barite, sand and coal chips on shakers.;Flow check at 7887' was 27 bph during connection. Did wash down two stands with no rotation but made things worse trying to pack- off.;At 8324', CBU one time to clean up hole and possible cuttings buildup under liner hanger. 152 gpm-725 psi, 30 rpm-4700 ft/lbs torque. SPP down 100 psi and flow up 2% at bott up.;Cont wash and ream in hole with liner assembly from 8324' to 8826'. Had rough time getting through coals at 8560' and 8725'. Increased rpm to 40-5900 ft/lbs torque which helped.; Continue wash and ream in hole with liner assembly from 8826' to 9738'.;Continue wash and ream in hole with liner assembly from 9738' to 10,350'. Rough getting through coals at 961 0'and 9850' and siltstone ledge at 10,218. Mud weight 10.8+ in/10.5 out.;P/U142 k/ S/O 125 K. Fine, sandy cuttings coming over shakers. Attempted to work down without rotating at 10,220' but started packing off. Continue W/R.;Class II fluid hauled to G&I = 850 bbls Total class 11 fluid hauled = 3971 bbis Cuttings hauled to G&I = 50 bbls Total cuttings hauled to G&I =317 bbis 3/2/2016 Continue wash and ream in hole with liner assembly from 10,350' to 10,626'. 182 gpm-629 psi, 18 to 19% flow, 40 to 50 rpm-6450 fUlbs torque, MW 10.9/vis 38,;BGG 200 to 600 units. Quite hard getting through two coal seams at 10,400' to 10,420'. Pumped a 15 bbl hi-vis pill followed with a 15 bbl lube pill and drilled to 10,606';pretty quick. At 10,606' we were into claystone and forward progress dropped significantly. Pumped a second lube pill and drilling took off again to 10,627' (bott of claystone);Built 30 bbls of lube pill in pill pit (1 drum each NXS and Torque Trim).;Continue wash and ream in hole with liner assembly from 10,626' to 10,636'. Pumped two 10 bbl lube pills with no effect. Attempted to work through without rotation or pump and 50K set down.;4.3 BPM/630 psi, 18 to 19% flow, 40 to 50 rpm-6450 ft/lbs torque, MW 10.8/vis 44. BGG 225 units. High gas 640 units. Water influx +-18 BPH. Static flow check 34 BPH.;Class II fluid hauled to G&I = 145 bbis Total class II fluid hauled = 4116 bbls Cuttings hauled to G&I = 5 bbis Total cuttings hauled to G&I =322 bbis 3/3/2016 Rack back one stand pulling reamer shoe from 10,636' to 10,598'. Cont circ at low rate and service rig and topdrive.;Cont circulating with no rotation while waiting on plan forward from Drilling team. Pull two stands up hole with no issues, TIH back to tight spot at 10,636'. Decision made to POOH LD 4 1/2" Iiner.;POOH from 10,636' racking 4 1/2" DP in derrick. Pumping while pulling to reduce water influx. Pump rate at 153 gpm-304 psi. Pulled to 8750' with no problem. Hole in good shape and no issue with;centralizers pulling into window. Gaining +/- 27 bph while pulling/pumping. Performed flow checks every 5 stands. These varied from 55 to 80 bph. At 8821' flow check was 80 bph and pipe pulling dry.;Fluid appears to be "U" tubing. Pulled to 8750' and parked string for circulation.; Circulated at 256 gpm-448 psi to clear wellbore of water. Staged casing tongs on rig floor. Dumped a total of 170 bbis water and light mud. Sent 90 bbls to G&I, kept 80 bbls in frac tank.;Had a max of 649 units gas at bottoms up. Flow check back to 55 bph at shut down. Up wt 115K, dwn wt 115K. Built 25 bbl hi-vis pill in pill pit for spotting at 7,000'.;Cont pull up hole pumping, from 8750' to 7014', again with no issues in open hole or centralizers pulling into window. Cont flow checks every 5 stands that varied from 39 to 55 bph.;Circulate at 208 gpm-654 psi while building 90 bbls of 17 ppg pill for spotting inside 7" casing. Had a max of 643 units gas at bottoms up, which dropped to 58 units. Dumped no water this circ.;Spot 20 bbl/500 vis pill at 6990'. Flow check at 35 BPH. Gas 130 units.;POOH from 7010' to 6324' with slow pump rate for two stands to place pill.;Spot 17 ppg/40 bbl pill at 6324'. Flow check at 8 BPH. Break down cement head. High gas 648 units.;POOH 6324' to 5454' and lay down liner hanger assembly. No noticeable damage to hanger assembly.;Rig up Weatherford casing tongs. Hold PJSM.;POOH laying down 4 1/2" liner form 5454' to 5226'.;Spot 17 ppg/50 bbl pill at 5226'. Flow check before pumping 8 BPH. Gas down to 30 units.;POOH laying down 4 1/2" liner from 5226' to 2090'. Flow check at 4186'= 0.3 BPH. Flow check at 3802'= 1.2 BPH. BGG 30 units.;Class II fluid hauled to G&I = 350 bbis Total class II fluid hauled = 4466 bbis Cuttings hauled to G&I = 5 bbis Total cuttings hauled to G&I =322 bbls 3/4/2016 POOH laying down 4 1/2" liner from 2090' to shoe track. Closed bag, sniffed rotary, welder heated couplers with torch. Weatherford broke/LD shoe track assembly with no issues. Lost two of three;aluminum standoff bands on shoe track. Reamer shoe in good shape. At 1400' flow check was 5 bph. With liner out of hole flow check was 20 bph. Closed blinds and lined up to monitor pressure.; RD and released Weatherford casing crew.;Cleaned and cleared rig floor. psi built to 468 over 45 minutes. Bled off and psi built to 509 over 30 minutes. Staged HWDP joint and wash tool, PU and flushed stack. Staged Halliburton RTTS.;TIH with wash tool, 19 joints HWDP and one stand DP. MU RTTS and XO's. Flow at 55 bph. TIH 2 stands DP and set packer at 123'. Backed out stinger, pulled up hole racking back. Upper sleeve backed out.;MU sleeve on stinger, RIH and engage packer, screw sleeve into packer, attempt to back out stinger, backed out upper sleeve again. Pulled up hole and removed stinger, MU upper sleeve, RIH engaged RTTS;Screw upper back onto RTTS, closed annular, MU TIW to top of DP, MU topdrive, pressured up to 500 psi on top of packer to release same. Bled off wellbore pressure through choke and poorboy degasser.;flow rate at 55 bph, open kill line to bleeder then opened annular. PU 2' and ensured packer released.Turned 1/4 turn to left and SO. Set string in slips, remove topdrive and open/remove TIW. Pulled;up hole to RTTS. Torqued up lower (18 rnd) connection on upper sleeve. TIH to 123' and re-set RTTS. POOH. Closed blinds and test to top of packer at 1330 psi, good test.;MU retrieval tool and pull wear bushing. MU joint HWDP on bottom of test plug, MU testjoint and set test plug. Flood and purge air from surface lines and valves. Called AOGCC Rep Jeff Jones and was; informed he would be out at 06:30 am to witness testing. Total Safety Rep will have to return in the morning for gas detection equipment testing as per AOGCC Rep.;Test BOPE as per sundry without AOGCC witness. Housekeeping in all areas.;Finish testing BOPS. Perform accumulator draw down test. Blow down test equipment, choke manifold and kill Iine.;Stage drill pipe and clean out BHA. Strap same. Service drawworks motor and transmission. Await arrival of AOGCC inspector.; Class II fluid hauled to G&I = 490 bbls Total class 11 fluid hauled = 4956 bbis f Cuttings hauled to G&I = 0 bbis ` Total cuttings hauled to G&I =322 bbls S 1 3/5/2016 Flood surface lines and choke manifold with water, obtain shell test. AOGCC Rep Jeff Jones on location at 06:15. Start BOPE test at 06:44. Tested all BOPE components at 250 low f/5 min, 3500 high f/10;min, tested annular at 250 low/2500 high at 5 and 10 min. Had no failures. Total test time 6 hrs. Blow down surface lines, RD test equip, pull test plug and set wear ring.;MU Halliburton stinger and XO on stand DP. TIH two stands, MU TIW, idle pump to flood surface lines. SO and engage storm packer at 123'. Screw stinger into RTTS 13 of 21 rounds and bound up.;Back off stinger and CBU washing top of RTTS of any debris. Down pump and SO, screw stinger into RTTS 16 of 21 rounds. Eased TIW open to monitor psi on DP, which climbed quickly to 1696 psi.;Closed annular and lined up on kill line with bleeder. Bled DP psi into annulus, below bag and above RTTS to equalize and release RTTS. With psi equal, PU 1' and RTTS is free. Lined up on choke and;start bleed off through choke/poorboy degasser. Bled down to 1251 psi and started getting fluid at shakers. 8.4 ppg returns. Casing bled to 0 psi with 83 bbis bled off, then had no fluid at shakers.;Still 261 psi on DP and climbing to 557 psi. Attempted to circ down DP, but climbed to 1500 psi with 3 bbis pumped. Down pump and DP dropped to 1076 psi. No returns, possibly packed off under;RTTS. Closed standpipe and choke, lined up pump on kill line and pumped 2 bbis into annulus, to 800 psi. Down pump, psi built to 1215, start bleed off through choke/degasser. Getting fluid at;shakers. May have moved packoff debris down allowing fluid to get around RTTS again. Casing bled to 0 with continuous flow of 55 to 100 bph, DP down to 91 psi. Reduced annular psi and made 1/4 turn;to left of RTTS with topdrive. PU 5' then SO to ensure RTTS fully released. Lined up on topdrive and roll pump to circ down DP. Built to 800 psi then broke over. Circulated surf to surf, FCP 379 psi;On DP. Down pump and DP bled to 0 psi, 0 psi on backside, flow at 127 opm. Work pipe 10' up and down, flow erratic at 0 to 15% on flow show. Closed TIW and broke off topdrive. Eased open TIW, no;flow. Pull 2 stands, RTTS to floor and broke XO's, LD RTES, MU TIW and topdrive.;Close annular and circulated through choke, fair amount of fine sand on shakers. Circulate at 2.7 BPM/80 psi. Open annular and pump an additional STS. High gas 637 units.;POOH. Well flowing out of drill pipe. Circulate out HWDP stands and last joint of DP with stack washer.;Shut blinds and flow through gas buster while M/U bit and bit sub. Well flowing at 85 BPH. High gas 652 units.;RIH with clean out BHA to 1026'. Circulate STS at 4.2 BPM/200 psi with high gas 720 units. Fine sand coming over shakers. RIH filling pipe at 2024' and 3013'.; Circulate STS at 4.2 BPM/210 psi. Fine sand over shakers with high gas of 648 units. Flow check 78 BPH.;RIH picking up drill pipe from 3013' to 5280'. CBU at 4026' and 5027'. High gas of 638 units. Flow check 73 BPH. No obstructions encountered.; Class II fluid hauled to G&I = 840 bbls Total class 11 fluid hauled = 5796 bbis Cuttings hauled to G&I = 0 bbis Total cuttings hauled to G&I =322 bbis 6S 3/6/2016 RIH picking up drill pipe from 5280' to - 9', then cont TIH from derrick to 6464', just above window', i ,,,, .g pipe every 1 000'with water from wellbore.;MU topdrive and circulate wellwater at 500 gpm-2446 psi. 20 bph gain while pumping, fair amount of fine sand on shakers.;Cut and slip 60' drill line while circ and waiting for trucks to return from G&I. Serviced rig andiron roughneck.; Held PJSM with rig team on well displacement. Lineup and displace well to 11.1 ppg mud at 437 gpm- 1688 psi ICP. FCP at 500 gpm-3144 psi. Flow check at 45 bph.;Ease down from 6464' and wash through window with no rotation at 400 gpm-2115 psi. Once clear of window rotate at 30 rpm-4800 ft/lbs torque. Wash and ream from 6536' to 6691';with shakers full of barite, fine sand and coal chips. Had to work coal seam at 6665'a couple times. At 6691' we started seeing anomalies in pump psi and flow rates. Pull back into window at 6527'.;Swap pumps but still having pressure spikes and flow erratic. Go to one pump and clean suction/discharge screens. Screens pretty much packed off in both pumps. Cont circ above window;one pump at a time and while cleaning the other. Run individual pits over shakers via gun lines to clear of coal chips. One or two jets in bit likely plugged as well. Getting decent flow rates again.;Change grabber dies on topdrive, then wash back through window with no rotation. TIH one stand clean, then wash next two down rotating at 30 rpm with no problem. Resume wash/reaming from;6691' to 6955'. Pump psi dropping slightly every connection and flow rate increasing. Appears bit jets cleared up at 6710. Wash and ream at 275 gpm-1800 psi, 60 rpm-5300 ft/lbs torque.;Rotate and reciprocate pipe 6890' to 6955while circulating at 4.5 BPM/1170 psi. 60 RPM/5500 torque. Well unloaded with 2" cuttings over shakers (coal, clay, sand. 641 units gas.;Wash and ream 6955to 7080'. Hole began unloading again.;Rotate and reciprocate pipe while circulating at 5 BPM/1415 psi. 60 RPM/5500 torque. Well unloaded with 2" cuttings over shakers (coal, clay, sand). 650 units gas.;Wash and ream 7080' to 7300' (coal at 7320').;Pipe temporarily stuck at 7300' with full circulation. Jar free with 4 licks at 180K. P/U 110, SIO 104, Rot 104 K/6400 ft lbs torque. Wash down stand to 7328'.;Rotate and reciprocate pipe while circulating at 5 BPM/1415 psi. 60 RPM/6200 torque. Well unloaded with 2" cuttings over shakers (coal, clay, sand). 528 units gas.;Wash and ream 7328' to 7515'. 5.8 BPM/2000 psi. 60 RPM/5450 torque. Pump pressure began to rise and well started unloading again.;Rotate and reciprocate pipe while circulating at 5 BPM/1415 psi. 60 RPM/5500 torque. Well unloading with 2" cuttings over shakers (coal, clay, sand). 528 units gas.;4.8 BPM/1886 psi.;Class II fluid hauled to G&I = 1300 bbls Total class II fluid hauled = 7096 bbls Cuttings hauled to G&I = 80 bbls Total cuttings hauled to G&I =402 bbls 3/7/2016 Rotate and reciprocate pipe while circulating at 5 BPM/1415 psi. 60 RPM/5500 torque. Well unloading with 2" cuttings over shakers (coal, clay, sand). 528 units gas.;Resumed washing and reaming 6" hole from 7515to 7763'. 200 gpm-1964 psi, 60 rpm-5300 ft/lbs torque. MW 11.2 in-out/vis 46, gaining 20 bph while pumping. At 7763' ,;(into the tangent section, below build section) performed a cleanup cycle pumping a 20 bbl hi-vis sweep around. Hole unloaded thick paste of barite, sand and coal chips for an hour.;Resumed washing and reaming 6" hole from 7763' to 7926'. At 7885' in a coal/shale, we pressured up, packed off and stalled topdrive. Down pump, jarred twice and resumed circ/rotation.;At 7926' bit tried to sidetrack in a 3 deg dogleg. Torque smoothed out and with 10K on bit appeared to be drilling new formation. Notified Drilling Engineer, tried numerous parameters;low pump-hi pump, rotation-no rotation, no pump, set down and jet wash etc. As a last resort, increased pump rate to 381 gpm- 2453 psi, set down 25K and at 20 rpm it wound up and broke free,;regained string weight and could slide down hole to 7930'. Broke off ledge or rolled out of sidetrack pocket. Notified Drilling Engineer and moved forward.; Resumed washing and reaming 6" hole from 7930' to 8200' at 270 gpm-1500 psi, 60 rpm-5700 ft/lbs torque, with no further issues other than when tapping into coal seams, they try to packoff and grab.;At 8200' pumped 20 bbl hi-vis sweep prior to planned wiper trip to window. 300 gpm-1875 psi, 80 rpm-6300 ft/lbs torque. Hole unloaded again. Circ until clean at shakers. BGG 645 units.;Pulled up hole on elevators from 8200' to just below previous sidetrack issue. Wash and ream through 7930' to 7920' three times. Continue POOH on elevators to 6510' without issue.;Service rig while circulating at 2.7 BPM/550 psi. Flow check 20 BPH.;RIH on elevators 6510' to 7008'. Set down 30K and not able to pass. Wash and ream through tight spots at 7008',7500', 7580', 7600', 7645' and continue to W/R from 7698' to 8200'.;Did not see any issue at area of 7920' to 7930'. High gas 701 units.;Wash and ream 8200' to 8545'. Pumped hi-vis sweep at 8450'. Reaming parameters: 60 RPM/7200 torque, 5.6 BPM/1550 psi. 120 k P/U, 110 S/O, 115 K Rt wt.;Sweep came back 40 bbls late with 80% increase in cuttings. Flow check 21 BPH.;Work stuck pipe at 8545'. Took 3 jars licks at 210K and rotation to break free. Bring pump back up to speed slowly while working string back up to 8520'. Parameters as before.;Wash and ream 8545' to 8570'. Work through dogleg to prevent side tracking (2.06 to .68 in 61'). Continue washing and reaming 8570' to 8726'.;Work stuck pipe at 8726'. Took 2 jars licks at 210K and rotation to break free. Bring pump back up to speed slowly while working string back up to 8690'. Parameters as before.; Continue washing and reaming 8726' to 8758'. Pump 20 bbl viscous sweep at 8726'. P/U 120 K, S/O 110 K, Rt 117 K at 7350 ft/lbs. High gas 693, BGG 218 units.;Class II fluid hauled to G&I = 550 bbls Total class II fluid hauled = 7646 bbls Cuttings hauled to G&I = 60 bbls Total cuttings hauled to G&I =462 bbls 3/8/2016 Cnn ince washing and reaming 8758' to 8820'. Pump 20 bbl viscous sweep at 8726'. P/U 120 K, S/O 110 K, Rt 117 Kat 7350 fUlbs. 6.2 BPM/2250 psi. BGG 240 units.;Wash & Ream f/ 8820't/ 9195', 120 GPM, 1613 Psi, 60 RPM, 72k TQ, 21 % flow, 234 Units BGG.; Pump 20 BBL Hi-Vis Sweep, Circ and work pipe f/ 9150 U 9190', 311 GPM, 2251 Psi, 80 RPM, 92k Tq. BGG 250 units, Gas high 650 units, Had a 20% increase of fine cuttings f/ sweep.;Wash & Ream f/ 9195' U 9685', Started adding black products at 9200'. Work through coals at 9239', 9575', 9605. 260 GPM, 1531 Psi, BGG 245, Flow 21%, 68 RPM, 80k Tq. MW 11.2 in and out.;Starting to have torque & pack-off issues. Pump 20 bbl high vis sweep w/ nut plug. Rotate and reciprocate. 80 GPM, 1925 Psi, 8 RPM, 10,500 TQ, Getting back fine sand and coal during full circ.;Got sweep with nut plug back 483 bbls late w/ a 40% increase in cuttings.;Wash & Ream f/ 9686V 9828'. 260 GPM, 1530 Psi, 21 % Flow, 70 RPM, 7 to 11 k TQ, Have 4 PPB black product in system. Put carbide in pipe on connection.;Work and free stuck pipe at 9828'. 10 jar licks at 240K. Finally able to free pipe with rotation and bringing pump on slowly and working pipe up hole to 9820'.;Wash & Ream 9828' to 10123'. 260 GPM, 1500 Psi, 21 % Flow, 70 RPM, 7 to 11 k TO, Pumped carbide at 9873' which came back 504 bbls Iate.;Wash and ream 10,123' to 10,620'. P/U 150, S/O 120, Rt 140/9100 ft lbs at 78 RPM. 6.2 BPM/1460 psi. Pumped tandem lo-weight/lo-vis followed by hi-vis weighted sweep;at 10,040'. Sweep came back 530 bbls late. High gas 701 units. BGG 219 units. Flow check 35 BPH.;Work through very tight area at 10,598'. Work stand 10,557' to 10,620' until area cleaned up. Coal at 10,570'- 10,580'. Dogleg at 10,598' of 3.29 degrees.;Wash and ream 10,620' to 10640'. 10,630' to 10,640' very sticky. Packing off and stalling issues but able to work through. High gas 710 units. BGG 205 units.;Class II fluid hauled to G&I = 430 bbls Total class II fluid hauled = 8076 bbls Cuttings hauled to G&I = 55 bbls Total cuttings hauled to G&I = 517 bbls 3/9/2016 Wash and ream f/ 10653't/ 10661'. Started taking wt like it was side tracking. Slowed RPM and attempted to work back into well bore. Got hung up at 10661'. Work pipe and break free.;lncrease pump rate to 278 GPM & slowed RPM U 20. Work back into hole at 10661't/ 10680' and continue to work pipe until it cleaned up.;Wash & ream f/ 10680't/10755'. 107 GPM, 2000 Psi, 75 RPM, 11 k TQ, 22 % Flow, MW in and out 11.2. Pumped high vis nut plug sweep at 10736' because bit & BHA seemed balled up.;As soon as the sweep started to clear the bit the pump pressure started dn. Press came down f/ 2000 to 1750 psi and we started making hole.;At 10755' we started to side track when the assem started taking wt and torque leveled off. Attempted using a high flow rate and low RPMs but we were in a sandstone and it kept drilling off.;Finally got back in the original hole at 10764'. Picked up the RPM to 75 and worked the pipe to clean the hole. [Nut Plug Sweep we pumped came back 459 BBLS late].;Wash & ream f/ 10764' U 10966'. Pumped high vis nut plug sweep and it came back 421 bbls late w/ a 50% increase in cuttings. Well flowing 65 BPH on connections. Worked to get through coals at; 1 0909'and 10950'. Also had issues w/ it trying to side track after getting through coals.;Wash & ream U 10,966't/11,421'. 5 BPM/1850 Psi, 75 RPM, 11 k TQ, 22 % Flow. MW in /out 11.2. Pumped high vis nut plug sweep at 11,184'. Came back 508 bbls Iate.;Work through sidetracking issues 11,360'to 11,380'. High gas 576 units. BGG 215 units. Flow check 32 BPH on connection. Pumped carbide at 11,560'. Flow check 35 BPH.;Wash and ream 11,421' to 11,755'. Same parameters as before. High gas 575 units. Appeared to be fill the last 130' before TD. Carbide came back 530 bbls late.; Pump high viscosity nut plug sweep while rotating and reciprocating pipe. Build viscous LCM to spot across Hemlock.;Class II fluid hauled to G&I = 75 bbls Total class II fluid hauled = 8151 bbls Cuttings hauled to G&I = 10 bbls Total cuttings hauled to G&I = 527 bbls 3/10/2016 Circ out high vis nut plug sweep. Sweep ame back 500 bbls late w/ a 10% increase in cuttings.; Pump -o.5 bbl,11.4 ppg high vis LCM pill and spot as a balanced plug covering the Hemlock. Top of pill should beat 10910'.;POH on elevators f/ 11755' U 10904'. Had a couple spots on 1st 90' that we pulled 40k over up wt and after that we had a couple 10, 15, & 20 k overpulls. Well flowing 39 BPH.;Rotate and reciprocate pipe while weighting up F/ 11.2 t/ 11.6 ppg. [Went to a short circ system so we could save on bar],Shut do to check flow. After 3 min DP press still had 345 psi. Bled DP to 0 psi. Started checking flow. 5 min = 25 BPH, 7 min = 21, 10 min = 19 BPH. DP press built up to 237 psi.,Rotate and reciprocate pipe while weighting up f/ 11.6 t/ 12 ppg. Pumping 250 GPM on upstroke and 200 on do stroke to keep surge pressure dn.;Shutdown and check flow. Standpipe wouldn't bleed down again so we bled it off. After 8 min well was still flowing 25 BPH, SPP 125 psi. 15 min 12 BPH, & SPP 67 psi., 27 min 7 BPH & SPP 53 psi.;At 35 min it was still 7 BPH and SPP was 48 psi. Call town and decided to wt up to 12.2 PPG.;Rotate and reciprocate pipe while weighting up f/ 12 U 12.2 ppg.;With 12.2 ppg around flow check was <1 BPH. BGG 27 units. POOH on elevators 10,901' to 10,528'. Appears to be swabbing. Pump out of hole 10,528' to 9450' without issue.;Continue POOH with pump 9450' to 6494'. Had to rotate to get past 6748' (25K over pull) due to obstruction and had slight drag to +-6698'. 12.2 ppg in/12.1+ out.;Took 31.4 bbls fill. 27 bbls fill calculated. Flow check 1.5 BPH. BGG 22 units. High gas 216 units.;Service rig. Pump dry job.;POOH laying down drill pipe.;Class II fluid hauled to G&I = 210 bbls Total class II fluid hauled = 8361 bbls Cuttings hauled to G&I = 20 bbls Total cuttings hauled to G&I = 547 bbls 3/11/2016 POOH laying down 87 jt of DP to 3776'. Well giving us 5.5 BPH.;Continue POH standing DP & HWDP back in the derrick. LD jars, break bit and bit sub. Bit is 1/8 out of gage. Well is flowing 4 BPH;RU Weatherford liner running equip.;Hold PJSM w/ everybody involved. MU shoe track, Check floats, RIH picking up 4 1/2 DWC liner. Flow check at 1913' was 8 BPH. Ran 140 jts 4 1/2 liner to 5395.;PU and MU Baker ZXP liner top packer. Fill tieback sleeve w/ Pal Mix and wait for it to set up. RIH 1 std of HWDP. Well flowing 6 BPH.;Circ bottoms up @ 5501' MD. 191 GPM, 930 psi, 13% flow, 42k up, 44k dn.;RIH out of derrick w/ DP from 5501'- T/ 6370' MD just above TOW (6514' ).;Circulate hole volume @ 6370' MD. 192 gpm, 1080 psi, 14% flow, 25 bbl loss while circulating. UD power tongs. P/U and M/U cmt swivel head and UD on catwalk. Reduce pump rate to minimum 112 gpm-;600 psi. Saw flow out increase to 16% then slowly taper off to 6% over 15 min w/ 13 bbl return from charged formation.; Rig service prior to going into open hole. Adjust tq on TDS to 6200 ft/lbs.;RIH F/ 6370'- T/ 10748' MD. Work past obstructions @ 6672', 6701', 6751' MD w/ slight to moderate effort needed. No pumps. Fill pipe every 10 stds.;Tag up @ 10748' MD. Wash and ream F/ 10748' - T/ 10760' MD. Pump @ 212 gpm, 1355 psi, 20% flow, 22 rpm, 6k tq, 1-3k wob. Coal logged 10740-10760'.; Saw 733 units max gas @ btms up. Mud wt cut to 11.8. Spot and rig up cementers.;Class II fluid hauled to G&I = 80 bbls Total class II fluid hauled = 8441 bbls Cuttings hauled to G&I = 0 bbls Total cuttings hauled to G&I = 547 bbls 3/12/2016 Broke through tight spot at 10760' and washed liner do to 11014'. Reamed through tight spot t/ 11017'. Washed f/ 11017 to 11600' where we tagged fill. [Mixing mud push];Wash and ream fill f/ 11600' U11731'. PU cmt head with sng on the bottom and wash to bottom at 11755'.; Continue rotating and circ while we rigged up cmt manifold and lines on the rig floor.;Hold PJSM for cementing liner and setting hanger. Shut put shoe on depth at 11753' and shut do pump and rotation. Rig up lines to cmt head.;Flush Schlumberger lines to slop tank w/ water. Pump 2 bbls water downhole. Test lines to 1000 and 5500 psi. Pump 24.2 bbIs 12.5 ppg mud ush w/ ria. Swap back to cmt unit and pump 98 bbls 13 lead cmt Pump 102 bbis 13.2 ppg 2nd lead cmt & 47 bbls 15.5 tail cmt. [Ran cement in all the slurrys.] Pump water through cmt lines to slop tank. Drop dart and displace w/ 12 ppg mud. Saw dart Iatch;Wiper plug at 79 bbls and bumped plug at 159 bbls. Plug bumped 5 bbls early. Pressure up to 4200 psi and hold press for 3 min. Bled back 1 bbl, floats held. CIP 15:05. Slack off blocks f/ 122k to 35k;giving us good indication hanger was set. Pressure up again to 4500 psi. Bled press off. Had full returns during cmt iob. Top of hanger at 6,315' and landing collar at 11,628'. Pu 6' to expose dogs;after release. Slack off 25k and saw packer shear. PU and rotate at 20 RPM and tq at 3900. Slack off 50k while rotating. Close annular and test back side to 1500 psi for 5 min. Bleed press off and;open annular. Press up do DP to 650 psi, pull out of hanger and press fell off. Kick on mud pump and circ bottoms up. Didn't get back any mud push or cmt. 4 bpm avg pump rate forjob.;Lay do cmt head. Put 2 wiper balls in the pipe and circ all the way around.;Rack back 2 stds and PU cmt head, Break cmt head down and lay do same.;Slip and cut 300' of drilling line. Also adjusted the brakes. Recalibrate rig smart & set COM.;Service rig. Adjust compensator.; Pump dry job. Blowdown TDS. POOH F/ 6200'- T/ 3433' laying down drill pipe.;Continue POOH F/ 3433' - T/ surface.;Advance clocks forward for daylight savings 1 hr.;B/O slick stick from liner running tool UD same. P/U and B/O sng jt from rot cmt head. Clean and UD same.;M/U stack flusher and flush stack. Drain stack, pull wear bushing, set test plug and changeout btm rams to 2-3/8" fixed body. R/U for testing BOP equipment.; Clean pits and prep for scraper run/ displacement. Release mudloggers 3/12/16. R/D same.;Class 11 fluid hauled to G&I =420 bbls Total class II fluid hauled = 8861 bbls Cuttings hauled to G&I = 0 bbls Total cuttings hauled to G&I = 547 bbls CV -f Hilc%,. p Energy Company Composit,, Report Well Name: SRF SCU 31 B-04 (SCU 12A-03 ST) Field: Swanson River Field County/State: , Alaska i (LAT/LONG): evation (RKB): 18 API #: 50-133-10099-02-00 Spud Date: Job Name: 1610111C SCU 3113-04 (SCU 12A-03 So Completion AFE#: 1610111C AFE $: $374,000 Activity Date I Ops Summary 3/13/2016 MU 2 3/8 test it. Change rams and look into came cavity to ensure rams will be closing on 2 3/8 jt. Button up ram doors.,Flood stack and purge air out of the test manifold, stack and test joint. Shell test 2500 (good).,Test lower rams on 2 3/8 to 250 and 3500 psi. Test annular on 2 3/8 to 250 and 2500 psi. Had 2 fail passes. Lower ram door seal leaked. Re -tighten door and it passed. Annular was leaking by. Functioned annular and it passed.Change out 2 3/8 test jt for 2 7/8 test jt. Test upper rams w/ 2 7/8 to 250 and 3500 psi.,RD and blow do test equip. Install wear ring.,RU to run 2 7/8 DP. Change out heads and rams on the iron roughneck.,PU 4 1/2 mill and scrapper assem. RIH PU 2 7/8 DP T/ 5343' MD. Drift= 1.80".,C/0 heads and tq ram on iron roughneck for 4-1/2" dp connections. C/O handling equipment. Bring scraper assy to rig floor and M/U same. TIH out of derrick F/ 5343'- T/ 6280' MD.,CBU @ 6280' MD. 156 gpm, 1882 psi, 13% flow. 75K up, 75K do w/ pumps off, 70k up, 70k do w/ pumps on.,M/U single then M/U second 7" scraper assy. Continue TIH F/63211, - T/ 10,592' MD. No issues entering liner top @ 6315' MD., Hauled 0 bbls cuttings to KGF G&I for total= 547 bbls Hauled 860 bbls Class II junk fluid to KGF G&I for total = 9721 bbls Daily losses downhole 0 bbls for total = 731 bbls 3/14/2016 RIH and tap landing collar at 11628'. Attempt to circ but pressure was to high. Pressure up to 4200 psi and stalled the mud pump. Up wt 175k, Dn wt 125K.,Decision was made to RU bleeder choke on standpipe so we could bleed some of the pressure and keep the pump rate up so motors wouldn't stall. Also cut mud wt in pits back f/ 12 ppg to 10.9 ppg.,Start circ keeping pressure below 3500 psi by bleeding at standpipe choke. Circ at 198 GPM, 3500 psi. After we got the 10.9 ppg back we could circ with a closed choke at 185 GPM, 2849 Psi.,Flush both pumps and kill line w/ water. Pump 22.5 bbl spacer sweep. Swap to fresh water and displace well. Still had to use standpipe choke until water started up back side. Had a final press after water was all the way around and choke was closed of 240 GPM and 3100 psi.,RU to test csg pumping do tbg and ann. Test csg to 2500 Psi for 30 min on a chart. Good test. RD test equip.,Pump through choke manifold with freshwater. Blow do choke and TD.,POH F/ 11,628' MD - T/ 6250' MD ( top scraper). Inspect scraper (good). UD single to alternate breaks on trip. Had multiple tight connections (break with tongs) during trip out.,TIH w/ scraper assy F/ 6250'- T/ 11,625' MD. Entered top of liner with no issues (6315' MD) w/ clean trip to btm.,CBU @ 11,625' MD. PJSM, Pump chem train as follows - 20 bbl caustic pill, 20 bbl barakleen pill, 25 bbl hi vis pill then displace out of hole w/ 8.6 ppg 6% KCL brine. Pump disp @ 5 bpm, 2010 psi, 15% flow.,Build and pump dry job. B/D TDS. Fill pill pit and trip tank w/ brine treated w/ baracor 100 (corrosion inhibitor). POOH laying down drill pipe F/ 11,628'- T/ 6900' MD.,Hauled 0 bbls cuttings to KGF G&I for total = 547 bbls Hauled 655 bbls Class II junk fluid for total = 10376 bbls 3/15/2016 Continue POH laying do 4 1/2 DP f/6800' to lower 7" csg scraper at 5340'. While LD scraper, floorhand injured left index finger.,Made notifications to appropriate personnel. Held safety stand down with rig crew.,LD remaining XO's, changed iron roughneck die blocks to accommodate 2 7/8" workstring. C/O handling equipment.,Cont POOH LD 2 7/8" workstring, from 5340' to 4 1/2" casing scraper and bit. Clean and UD same. Safety clamp and lift nubbins used 100% for trip V due to minimal upset on 2-7/8" drill pipe.,R/U and test 7" x 4.5" casing to 3500 psi w/ 30 min hold. 4 bbls bleed back. (test good). Chart and record same. R/D and blow down lines. Start psi 3525 / end psi 3450 (75 psi over 30 min hold = 2%).,PJSM, Rack in and R/U Halliburton Loggers. RIH w/ 3.13" OD string. CBURMTI/GR RIH to Landing Collar and begin logging up. @ 9500'+/- computer froze and lost data (4 hr NPT). Restart from btm and re -log CBL. Log @ 14- 15 ft/min. Current depth at 9700'., Hauled 0 bbls cuttings to KGF G&I for total = 547 bbls Hauled 1020 bbls Class II junk fluid to KGF G&I for total = 11396 bbls 3/16/2016 Cont performing CBL of 4 1/2" liner (Halliburton) from 9700' to 6315' (top of liner). Cont hauling trash fluid from frac tank to G&I and loading unused dry mud product on trailers for return. POOH with a -line and RD released Halliburton.,Service rig and topdrive, inspect brakes and linkage. Pulled wear ring.,RU Weatherford tongs and handling equipment. Staged packer assembly and GLM's. Held PJSM with Tri -Point, Weatherford and rig crew.,MU Tri -Point 4 1/2" x 2 3/8" hydraulic packer assembly with WLEG and X nipple, cont PU single in hole with 143 jnts 2 3/8" 4.7# L-80 EUE 8 and tubing to 4660'. MU 2 3/8" x 2 7/8" XO, CO handling equipment, cont PU single in hole with 54 jnts 2 7/8" tubing to 6365' WLEG depth (packer at XO on bottom of liner hanger) and set down solid. Work string numerous times with half rounds etc.,Notify Completion Engineer, Tri -Point Supervisor and Baker Rep. Made numerous attempts to pass through liner hanger assembly by pulling clear of assembly, making half rounds and continue to set down at 6365' WLEG depth (packer bottom 15' up the string at 6342', which is at the 5" Vam x 4 1/2" DWC crossover bushing on the bottom of liner hanger assembly. Max set down of 15K, string pulls clean off set down point.,Decision made to POOH. Cannot rack back 2 3/8" in derrick, prep to LD tubing.,POOH LD 54 jnts 2 7/8" tubing from 6365' to 4660'. CO handling equipment from 2 7/8" to 2 3/8". Prep to LD 2 3/8" tubing.,Hauled 0 bbls cuttings to G&I, Total cuttings hauled = 547 bbls. Hauled 435 bbls Class II junk fluid to G&I, Total Class II fluid hauled = 11,831 bbls. 3/17/2016 Cont POOH LD 54 jnts 2 7/8" tubing from 6365to 4660', CO handling equipment to 2 3/8", cont POOH LD 143 jnts 2 3/8" tubing and 6 GLM's. Pull Tri -Point FH packer to table and inspect. Packer partial set and missing one of three rubber elements (3.6" OD).,Notify appropriate personnel on packer status, decision made to call out a second FH packer. Service rig and topdrive. Replace 6 jnts 2 3/8" tubing due to thread damage, CO ram on iron roughneck (not used on tubing). Shipped two frac tanks to G&I for cleaning and return to vendor.,MU new WLEG (mule shoe type) and new 2 3/8" x 4 1/2" FH packer assembly. Discussed with completion engineer and area ops manager on possibly running gauge ring on slickline due to missing rubber element. Decision made to run packer.,Cont PU single in hole with 143 jnts 2 3/8" 4.7# L-80 EUE tubing (+ 6 GLM's) to 4660', MU 2 3/8" x 2 7/8" XO, CO handling equipment to 2 7/8", cont PU and single in hole with 54 jnts 2 7/8" 6.5# L-80 EUE tubing. On joint 54 of 2 7/8", entered top of liner hanger at 6315'. With WLEG at 6342' (crossover bushing) set down 1 K. PU 5' and feathered down with no issue, allowing WLEG to enter 4 1/2" Iiner.,With packer at 6342' (crossover bushing) set down 1 K. PU 5' and feathered down with no issue, allowing packer to enter 4 1/2" liner. Cont to PU and single in hole with 2 7/8" tubing to 6458' at 06:00. Up wt 34K, dwn wt 34K.,Hauled 0 bbls cuttings to G&I, Total cuttings hauled = 547 bbls. Hauled 150 bbls Class 11 junk fluid to G&I, Total Class 11 fluid hauled = 11,981 bbls. 3/18/2016 Cont PU single in hole with 2 7/8" tubing From 6458' to 10,797' (4.5 joints from bottom) and string set r'nwn approximately 6K, mid joint. Up wt 60K, dwn wt 56K. At 10,797' pulled up to 80K as per Tri -Poi p indicating packer set. SO and string took weight agair ),797'. PU to 90K and had every indication packer sheared. Notified Completion Engineer, a. ea Ops Manager and Drilling Engineer. Decision made to i ., the,last 4 joints, hanger and landing joint, drop the ball/rod, pressure up on tubing to 3000 psi for 30 min, pull the rod with slickline, then attempt to pressure test down tubing and below the packer, to see if packer set. (note: running speed at time of packer set was 50 seconds per joint, any faster and fluid would surge out the top of completion string),Worked 2 of the last 4 joints down (string continued to take weight a couple times). MU hanger and landing joint, drained the stack and landed hanger in wellhead 19.75' RKB. Dropped ball/rod, RILD's and RU to test down the tubing with test pump. Rod had a good 30 minutes to drop.,Attempted to pressure up on tubing with test pump, annulus open. All we did was circulate water into the cellar box. Obtained no pressure. Lined up rig pump on tubing, pumped 10.5 bbls at 80 spm -4.5 bpm, up to 3000 psi with no decrease in flow at annulus valve. Pressure bled to zero when pump shut down. Tri -Point Supervisor thinks there is a bypass port in the packer that probably opened when packer sheared., Notified Completion Engineer. Decision made to retrieve ball/rod with slickline (already on location) and POOH for a -line run packer assembly. RD tubing test equipment.,RU Pollard slickline, RIH with retrieval tool and engaged ball/rod at 10,952'. POOH with no problems, RD Pollard slickline and released same. Notified AOGCC and BLM of BOP test when OOH.,BOLD's, pull hanger to rig floor, up wt 60K, RU Weatherford tongs, rack 3 stands 4 1/2" DP in derrick and string rope to act as belly board for tubing racked back in derrick, on off drillers side. Both AOGCC and BLM waived witness of BOP test.,POOH from 10,862' racking 2 7/8" tubing in derrick, to 4660'. Rack 3 stands 4 1/2" DP in derrick on drillers side, weave rope to act as belly board for tubing. CO handling equipment, cont POOH from 4660' to 3042', racking 2 3/8" tubing in derrick. 3/19/2016 Cont POOH racking back 2 3/8" tubing in derrick. Tri -Point FH packer looked good, all three elements in place, shear ring was sheared. LD packer assembly. RD Weatherford tongs.,Held PJSM with Pollard a -line and rig crew, RU sheaves, MU tail pipe and new D model packer assembly to setting tool. 3.75" OD on packer. RIH on a -line. At 10,850' string lost weight. PU 15' and SO with no movement of tools. Pull up hole and at 10,760' tools hung up. Pulled 150 lbs over and tool string came free. Notified Completion Engineer. POOH LD packer assembly.,Tested choke manifold valves while running a -line, Total Safety calibrated and tested gas detection equipment.,MU 3.75" gauge ring/junk basket assembly on a -line, RIH with no issues to 11,586', pulled back up hole with no issues at 10,850' or 10,760'. Cont POOH LD gauge ring/junk basket, no debris in basket.,RIH with D model packer and tailpipe assembly on a -line. Saw a slight drop in string weight at 10,850' (previous hung up depth) but passed through no problem. RIH to top RA marker joint at 10,995'. Pulled up hole to 10,921.5' (CCL depth, packer at 10,932.5'). Set packer at 10,932.5' WLM. Good indication packer set/setting tool released. Pulled up hole, SO and tagged top of packer on depth.,P00H with e - line from 10,932', RD release same.,Install test plug, RU test equipment.,Test BOPE at 250/3500 psi, 250/2500 on annular. Tested with 2 3/8" and 2 7/8" test joints. No failures. Choke manifold tested during a -line work, gas detection equipment tested during a -line work. Test time 6.5 hours. Both AOGCC and BLM waived witness of testing on 3-18-16.,RD test equipment, blew down surface Iines.,RU Weatherford tongs and handling equipment. 3/20/2016 MU Tri -Point seal assembly with snap latch and locator (6.20' long, OD 2.660", ID 1.995") and pup joint to first single jnt 2 3/8" tubing, cont TIH with 2 3/8" tubing from derrick to 4660', MU 2 3/8" x 2 7/8" XO. Up wt 26K, dwn wt 29K. Ran a total of 143 joints tubing.,CO handling equipment to 2 7/8", cont TIH with 2 7/8" tubing from derrick to 10,914'. No issue passing through liner hanger at 6315'. MU XO and topdrive. Up wt 60K, dwn wt 56K. Heat 25 bbls water in pill pit to 110 degrees.,Pump hot water pill long way around at 3 bpm -925 psi to clean tubing of pipe dope and any paraffin. Shut down pump, break off topdrive.,PU two singles and with test pump lined up on string via topdrive, wash down 32' and saw psi increase as seals entered packer top. Shut down test pump and open bleeder. Calculate space out pups at 14'. LD two singles, pull third single and MU 10' and 6' pups on bottom. Make that up on stump, SO and MU hanger, pup and landing joint. Drain BOP stack, up wt 60K, dwn wt 56K. SO 19' and string taking weight. PU to 64K,to ensure snap latch is latched in packer (OK). SO and land hanger at 19.75' RKB.,RD Weatherford tongs, RILD's, PJSM and RU Pollard slickline to run RHCP plug.,RIH with RHCP plug on slickline to 10,941', set same. POOH and standby Pollard.,Drop rod/ball. RU test pump on tubing and start pressure up. Rod made it to seat without needing to pump on it. Increase pressure to 3100 psi. Start 30 min recording on chart recorder. Good test.,Slickline RIH to recover ball and rod. Rod recovered. RHCP plug body recovered. RD Pollard and release same.,RU on tubing and pressure test below packer to 2500 psi for 30 minutes. Good test. Bleed off and RD test equipment from tubing.,RU test pump on annulus, performed jug test pumping down annulus to 2500 psi, seeing communication through live GLM valves into tubing to 2500 psi. Good test. Pump 45 gallons diesel down annulus to freeze protect 50'. RD test pump.,Pull landing joint and install BPV. 3/21/2016 Load Weatherford equipment and ship same, L/D 6 stnds 4 1/2" DP from derrick, ship out 5 star smoke shack, CO lower rams back to variables, load and ship 2 jet heat units and tri -point basket, load bbl warm shack and test joint rack and stage for shipping, crane on location at 11:00 am, spot crane and remove centrifuge and feed pump. Load and ship centrifuge, feed pump and 4 UR light plants, LD degasser, load Hilcorp rig,mats and degasser and stage for shipping, remove pit windwalls and stage in Connex, ND BOP stack and spacer spools, NU tree, test hanger void at 250/5000 psi, test tree at 250/5000 psi. Good tests. Remove windwalls from pits and rig floor. Total Safety RD gas detection equipment, Handy Berm RD berming, lower pit roof tops and stage all three sections on SCU 23- 03 pad. Clear rig floor of subs and tongs, disconnect shock,on catwalk, shut down boiler and shut in, check end play and backlash on topdrive, RD pump skids for move. (Note: pulled TWC from hanger, no BPV installed, pulled fluid from tree and hanger and topped off with diesel for freeze protect.) RIG RELEASED at 18:00 hrs on 3-21-16,Spot crane and cont windwall removal from rig floor. Change oil in swivel and gear box on topdrive, remove bails, IBOP and saver sub, change swivel packing, cont prep pump skids for move, RD boiler #1, disconnect electric cords on pump skids. RD topdrive, RU bridle lines, install beams in sub, RD torque tube, scope derrick down, clean sub and cellar box, lay plywood across south bridge, lay over beaver slide.,Peak on location at 05:30 to haul 3 pit modules and boiler to D&D yard. Road in good shape (was graded overnight). 3/22/2016 Load 2 pit modules, boiler and pump #2, transport to D&D yard, tear out pump #1, tear out catwalk, tear out HPU skid, cradle BOP stack, unspool drill line and secure in derrick, un -pin and lay over derrick, transport pit mod, pump and catwalk to D&D, 2nd crane on location at 10:00. lower doghouse and transport same, transport gen 1-2 skid, remove iron roughneck, lower derrick board windwalls, pick derrick and transport„pick carrier and transport, pick sub off pony walls, transport sub and pony walls. Transport both cranes and bed truck to D&D yard at 16:00 hrs. Stack and stage rig mats. Transport Handy Berm and Drilling connex's to Gas Field.,Cont stack and stage rig mats at SCU 31 B-04. Clean up liner and felt on location. Rig crew traveled to D&D to lay felt and liner for rig stack, then broke tour at 02:00.,Peak hands loaded trailer on 31 B-04 with equipment to be sent to Tuboscope for inspection, and pressure washed Hilcorp test pump for storage. 3/26/2016 Meet at office. Mobe to location. Rig up lubgricator and pressure test to 250 psi low and 2500 psi high. TP - 780,RIH w/1 -9/16"x31' and tie into Halliburton RMTI tool dated 16 mar 16. Found fluid level at 10,714'.Run correlation log and send to town. Get ok to perf from 11,298' to 11,329'. Spot gun across interval and fired with 780 psi on tubing. Pressure went to 760 psi and right back up to 780 psi. POOH.,RIH w/1 -9/16"x25' and tie into Halliburton RMTI tool dated 16 mar 16. Found fluid level at 10,690'.Run correlation log and send to town. Get ok to pert from 11,273' to 11,298'. Spot gun across interval and fired with 760 psi on tubing. Pressure stayed the same. POOH.,Pressure was 740 when we closed swab valve, Rig down lubricator and turn well over to field. The other perf charges will be in Monda . We will perforate 31' more feet Wednesday. 3/30/2016 Meet at office. Mobe to location. Rig up lubgricator and pressure test to 250 psi low and 2500 psi high. TP - 680 psi,RIH w/1 -9/16"x31' and tie into Halliburton RMTI tool dated 16 mar 16..Run correlation log and send to town. Get ok to perf from 11,242' to 11,273'. Spot gun across interval and fired with 701 psi on tubing. Pressure stayed the same after 5 min. POOH.,Rig down lubricator and tum well over to field. SCU 316-04 FINAL Days vs Depth i 0 ! 500 1000 1500 —SCU 31B-04 Actual SCU 31B-04 Plan 2000 2500 3000 3500 4000 4500 5000 i $ 5500 r +� 6000 0 j v 6500 m W 7000 7500 — i 8000 I 8500 ! 9000 9500 10000 I 10500 11000 11500 12000 12500 1 6 11 16 21 26 31 36 Days 4/29/201610:33 AM t - s Y C. v 0 v L LA LA w i SCU 316-04 MW vs Depth 0 SCU 3113-04 Plan 1000 SCU 31B-04 Actual 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 8.0 9.0 10.0 11.0 12.0 13.0 14.0 Mud Density (ppg) Hilcorp Energy Company Soldotna CK Unit Soldotna CK Unit SCU 31B-04 50-133-10099-02-00 50-133-10099-02-00 perry Drilling Definitive Survey Report 22 April, 2016 HAL.L.IBURTON Sperry Drilling a�a� Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well Soldotna CK Unit 12-3 Project: Soldotna CK Unit TVD Reference: SCU 3113-04 @ 162.45usft (Saxon 169) Site: Soldotna CK Unit MD Reference: SCU 31 B-04 @ 162.45usft (Saxon 169) Well: Soldotna CK Unit 12-3 North Reference: True Wellbore: SCU 31 B-04 Survey Calculation Method: Minimum Curvature Design: SCU 31 B-04 Database: Sperry EDM - NORTH US + CANADA Project Soldotna CK Unit, Swanson River Field 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 Well Soldotna CK Unit 12-3 Well Position +N/ -S 0.00 usft Northing: 2,459,121.98 usft Latitude: 60° 43 41.971 N Map +E/ -W 0.00 usft Easting: 347,966.38 usft Longitude: 150° 50'57.362 W Position Uncertainty 0.00 usft Wellhead Elevation: 144.45 usft Ground Level: 144.45 usft Survey Program Date 4/21/2016 From To Map Map Wellbore SCU 31 B-04 Tool Name Description Survey Date Magnetics Model Name Sample Date Declination Dip Angle Field Strength 6,514.00 6,622.45 MWD_Interp Azi+sag (SCU 31 B-04) MWD_Interp Azi+sag Fixed:v2:std dec with interpolated azimuth + sag (nT) 6,684.60 BGGM2015 2/13/2016 MWD+SC+sag 16.41 73.69 55,504 Design SCU 31 B-04 (ft) Survey Tool Name 18.00 0.00 Audit Notes: 18.00 -144.45 0.00 0.00 Version: 1.0 Phase: ACTUAL Tie On Depth: 6,498.45 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction -0.07 (usft) (usft) (usft) (°) 198.45 18.00 0.00 0.00 293.46 0.64 -0.49 Survey Program Date 4/21/2016 From To Map Map (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 98.45 6,498.45 SCU12-3 (SCU 12-3) SR -Gyro -SS Fixed:v2:surface readout gyro single shot 01/06/2014 6,514.00 6,622.45 MWD_Interp Azi+sag (SCU 31 B-04) MWD_Interp Azi+sag Fixed:v2:std dec with interpolated azimuth + sag 02/16/2016 6,684.60 11,718.25 MWD+SC+sag (SCU 31 B-04) MWD+SC+sag Fixed:v2:standard dec & axial correction + sag 02/16/2016 4/22/2016 6 57 32PM Page 2 COMPASS 5000.1 Build 73 Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 18.00 0.00 0.00 18.00 -144.45 0.00 0.00 2,459,121.98 347,966.38 0.00 0.00 UNDEFINED 98.45 0.25 338.00 98.45 -64.00 0.16 -0.07 2,459,122.14 347,966.32 0.31 0.13 SR -Gyro -SS (1) 198.45 0.50 309.00 198.45 36.00 0.64 -0.49 2,459,122.63 347,965.90 0.31 0.70 SR -Gyro -SS (1) 298.45 0.33 276.00 298.45 136.00 0.94 -1.11 2,459,122.94 347,965.28 0.29 1.40 SR -Gyro -SS (1) 398.45 0.25 295.00 398.44 235.99 1.07 -1.60 2,459,123.07 347,964.80 0.12 1.89 SR-Gyro-SS(1) 498.45 0.25 356.00 498.44 335.99 1.38 -1.81 2,459,123.38 347,964.59 0.25 2.21 SR -Gyro -SS (1) 598.45 0.00 356.00 598.44 435.99 1.59 -1.82 2,459,123.60 347,964.58 0.25 2.31 SR -Gyro -SS (1) 698.45 0.50 215.00 698.44 535.99 1.24 -2.07 2,459,123.24 347,964.32 0.50 2.40 SR -Gyro -SS (1) 798.45 0.50 251.00 798.44 635.99 0.74 -2.74 2,459,122.75 347,963.65 0.31 2.80 SR -Gyro -SS (1) 898.45 0.50 314.00 898.43 735.98 0.90 -3.46 2,459,122.92 347,962.93 0.52 3.54 SR -Gyro -SS (1) 998.45 0.25 348.00 998.43 835.98 1.41 -3.82 2,459,123.44 347,962.58 0.32 4.07 SR -Gyro -SS (1) 1,098.45 0.00 348.00 1,098.43 935.98 1.63 -3.87 2,459,123.66 347,962.53 0.25 4.20 SR -Gyro -SS (1) 4/22/2016 6 57 32PM Page 2 COMPASS 5000.1 Build 73 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well Soldotna CK Unit 12-3 Project: Soldotna CK Unit TVD Reference: SCU 31 B-04 @ 162.45usft (Saxon 169) Site: Soldotna CK Unit MD Reference: SCU 31B-04 @ 162.45usft (Saxon 169) Well: Soldotna CK Unit 12-3 North Reference: True Wellbore: SCU 31B-04 Survey Calculation Method: Minimum Curvature Design: SCU 31 B-04 Database: Sperry EDM - NORTH US + CANADA Survey 412212016 6:57:32PM Page 3 COMPASS 5000.1 Build 73 Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 1,198.45 0.25 99.00 1,198.43 1,035.98 1.59 -3.65 2,459,123.62 347,962.75 0.25 3.99 SR -Gyro -SS (1) 1,298.45 0.50 244.00 1,298.43 1,135.98 1.37 -3.83 2,459,123.40 347,962.57 0.72 4.06 SR -Gyro -SS (1) 1,398.45 0.33 196.00 1,398.43 1,235.98 0.90 -4.30 2,459,122.94 347,962.09 0.37 4.30 SR -Gyro -SS (1) 1,498.45 0.33 319.00 1,498.43 1,335.98 0.84 -4.57 2,459,122.88 347,961.82 0.58 4.53 SR-Gyro-SS(1) 1,598.45 0.33 20.00 1,598.43 1,435.98 1.33 -4.66 2,459,123.37 347,961.74 0.33 4.80 SR -Gyro -SS (1) 1,698.45 0.25 40.00 1,698.43 1,535.98 1.77 -4.42 2,459,123.80 347,961.98 0.13 4.76 SR -Gyro -SS (1) 1,798.45 0.25 137.00 1,798.42 1,635.97 1.77 -4.13 2,459,123.81 347,962.27 0.37 4.50 SR -Gyro -SS (1) 1,898.45 0.50 16.00 1,898.42 1,735.97 2.03 -3.86 2,459,124.06 347,962.54 0.66 4.35 SR -Gyro -SS (1) 1,998.45 0.50 35.00 1,998.42 1,835.97 2.81 -3.49 2,459,124.84 347,962.93 0.17 4.32 SR -Gyro -SS (1) 2,098.45 0.25 55.00 2,098.42 1,935.97 3.29 -3.06 2,459,125.31 347,963.36 0.28 4.12 SR -Gyro -SS (1) 2,198.45 0.50 46.00 2,198.42 2,035.97 3.72 -2.57 2,459,125.73 347,963.86 0.26 3.84 SR-Gyro-SS(1) 2,298.45 0.25 85.00 2,298.41 2,135.96 4.04 -2.04 2,459,126.05 347,964.39 0.34 3.48 SR -Gyro -SS (1) 2,398.45 0.00 85.00 2,398.41 2,235.96 4.06 -1.82 2,459,126.07 347,964.61 0.25 3.29 SR -Gyro -SS (1) 2,498.45 0.25 150.00 2,498.41 2,335.96 3.87 -1.71 2,459,125.88 347,964.72 0.25 3.11 SR -Gyro -SS (1) 2,598.45 0.00 150.00 2,598.41 2,435.96 3.69 -1.60 2,459,125.69 347,964.82 0.25 2.94 SR -Gyro -SS (1) 2,698.45 0.00 150.00 2,698.41 2,535.96 3.69 -1.60 2,459,125.69 347,964.82 0.00 2.94 SR -Gyro -SS (1) 2,798.45 0.50 129.00 2,798.41 2,635.96 3.41 -1.27 2,459,125.41 347,965.16 0.50 2.52 SR -Gyro -SS (1) 2,898.45 0.50 122.00 2,898.41 2,735.96 2.90 -0.56 2,459,124.89 347,965.86 0.06 1.67 SR -Gyro -SS (1) 2,998.45 0.42 75.00 2,998.40 2,835.95 2.77 0.17 2,459,124.75 347,966.58 0.37 0.95 SR -Gyro -SS (1) 3,098.45 0.50 79.00 3,098.40 2,935.95 2.95 0.95 2,459,124.91 347,967.37 0.09 0.30 SR-Gyro-SS(1) 3,198.45 0.00 79.00 3,198.40 3,035.95 3.03 1.38 2,459,124.99 347,967.80 0.50 -0.06 SR-Gyro-SS(1) 3,298.45 0.17 160.00 3,298.40 3,135.95 2.89 1.43 2,459,124.85 347,967.85 0.17 -0.16 SR -Gyro -SS (1) 3,398.45 0.50 341.00 3,398.40 3,235.95 3.16 1.34 2,459,125.13 347,967.76 0.67 0.03 SR -Gyro -SS (1) 3,498.45 0.58 345.00 3,498.39 3,335.94 4.06 1.06 2,459,126.03 347,967.50 0.09 0.64 SR -Gyro -SS (1) 3,598.45 0.58 312.00 3,598.39 3,435.94 4.89 0.56 2,459,126.86 347,967.00 0.33 1.44 SR -Gyro -SS (1) 3,698.45 0.83 310.00 3,698.38 3,535.93 5.70 -0.37 2,459,127.68 347,966.08 0.25 2.61 SR -Gyro -SS (1) 3,798.45 0.83 334.00 3,798.37 3,635.92 6.81 -1.25 2,459,128.81 347,965.22 0.35 3.85 SR -Gyro -SS (1) 3,898.45 0.50 355.00 3,898.36 3,735.91 7.90 -1.60 2,459,129.90 347,964.88 0.41 4.61 SR -Gyro -SS (1) 3,998.45 1.00 339.00 3,998.36 3,835.91 9.15 -1.95 2,459,131.15 347,964.55 0.54 5.43 SR -Gyro -SS (1) 4,098.45 0.75 333.00 4,098.34 3,935.89 10.55 -2.56 2,459,132.56 347,963.96 0.27 6.55 SR -Gyro -SS (1) 4,198.45 1.00 329.00 4,198.33 4,035.88 11.88 -3.31 2,459,133.90 347,963.23 0.26 7.76 SR -Gyro -SS (1) 4,298.45 0.92 326.00 4,298.32 4,135.87 13.29 -4.21 2,459,135.32 347,962.35 0.09 9.15 SR -Gyro -SS (1) 4,398.45 0.83 315.00 4,398.31 4,235.86 14.47 -5.17 2,459,136.51 347,961.40 0.19 10.50 SR -Gyro -SS (1) 4,498.45 0.75 345.00 4,498.30 4,335.85 15.61 -5.85 2,459,137.67 347,960.73 0.42 11.58 SR -Gyro -SS (1) 4,598.45 0.58 324.00 4,598.29 4,435.84 16.65 -6.32 2,459,138.71 347,960.28 0.29 12.42 SR -Gyro -SS (1) 4,698.45 0.92 329.00 4,698.28 4,535.83 17.75 -7.03 2,459,139.82 347,959.58 0.35 13.51 SR -Gyro -SS (1) 4,798.45 0.50 359.00 4,798.27 4,635.82 18.88 -7.45 2,459,140.95 347,959.18 0.55 14.35 SR -Gyro -SS (1) 4,898.45 0.50 10.00 4,898.27 4,735.82 19.74 -7.38 2,459,141.82 347,959.26 0.10 14.63 SR -Gyro -SS (1) 4,998.45 1.17 340.00 4,998.26 4,835.81 21.13 -7.65 2,459,143.21 347,959.00 0.78 15.43 SR -Gyro -SS (1) 5,098.45 0.50 352.00 5,098.25 4,935.80 22.52 -8.06 2,459,144.61 347,958.61 0.69 16.36 SR -Gyro -SS (1) 412212016 6:57:32PM Page 3 COMPASS 5000.1 Build 73 Company: Hilcorp Energy Company Project: Soldotna CK Unit Site: Soldotna CK Unit Well: Soldotna CK Unit 12-3 Wellbore: SCU 31B-04 Design: SCU 31B-04 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well Soldotna CK Unit 12-3 SCU 31 B-04 @ 162.45usft (Saxon 169) SCU 31B-04 @ 162.45usft (Saxon 169) True Minimum Curvature Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting OLS Section (usft) (°) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 5,198.45 1.67 346.00 5,198.23 5,035.78 24.37 -8.48 2,459,146.46 347,958.22 1.17 17.48 SR -Gyro -SS (1) 5,298.45 1.83 333.00 5,298.18 5,135.73 27.21 -9.55 2,459,149.31 347,957.18 0.43 19.59 SR -Gyro -SS (1) 5,398.45 2.00 335.00 5,398.13 5,235.68 30.21 -11.02 2,459,152.33 347,955.76 0.18 22.13 SR -Gyro -SS (1) 5,498.45 2.50 344.00 5,498.05 5,335.60 33.89 -12.35 2,459,156.02 347,954.47 0.61 24.82 SR-Gyro-SS(1) 5,598.45 2.25 318.00 5,597.97 5,435.52 37.44 -14.27 2,459,159.60 347,952.60 1.10 28.00 SR -Gyro -SS (1) 5,698.45 2.50 330.00 5,697.88 5,535.43 40.79 -16.67 2,459,162.98 347,950.24 0.56 31.53 SR -Gyro -SS (1) 5,798.45 2.58 355.00 5,797.79 5,635.34 44.92 -17.96 2,459,167.13 347,949.00 1.10 34.36 SR -Gyro -SS (1) 5,898.45 2.25 315.00 5,897.70 5,735.25 48.55 -19.54 2,459,170.78 347,947.47 1.68 37.26 SR -Gyro -SS (1) 5,998.45 2.92 335.00 5,997.60 5,835.15 52.25 -22.01 2,459,174.51 347,945.05 1.11 40.99 SR-Gyro-SS(1) 6,098.45 1.67 331.00 6,097.52 5,935.07 55.83 -23.79 2,459,178.11 347,943.31 1.26 44.05 SR -Gyro -SS (1) 6,198.45 1.58 309.00 6,197.48 6,035.03 57.97 -25.57 2,459,180.28 347,941.56 0.63 46.54 SR -Gyro -SS (1) 6,298.45 2.25 348.00 6,297.43 6,134.98 60.76 -27.05 2,459,183.09 347,940.12 1.43 49.00 SR -Gyro -SS (1) 6,398.45 1.08 312.00 6,397.39 6,234.94 63.31 -28.16 2,459,185.65 347,939.04 1.52 51.04 SR -Gyro -SS (1) 6,498.45 2.25 325.00 6,497.35 6,334.90 65.55 -29.98 2,459,187.91 347,937.25 1.22 53.60 SR-Gyro-SS(1) 6,514.00 2.25 321.68 6,512.88 6,350.43 66.04 -30.35 2,459,188.41 347,936.89 0.84 54.13 MWD _InterpAzi+sag (2) 6,561.08 6.22 307.41 6,559.83 6,397.38 68.32 -32.95 2,459,190.72 347,934.32 8.66 D 57.42 MW_InterpAzi+sag(2) 6,622.45 8.53 302.34 6,620.69 6,458.24 72.77 -39.44 2,459,195.26 347,927.89 3.91 65.15 MWD _InterpAzi+sag(2) 6,684.60 10.24 299.21 6,682.00 6,519.55 77.93 -48.15 2,459,200.53 347,919.24 2.87 W 75.20 MD+SC+sag (3) 6,746.40 11.27 292.16 6,742.72 6,580.27 82.89 -58.54 2,459,205.62 347,908.92 2.70 86.70 MWD+SC+sag (3) 6,808.46 11.76 287.09 6,803.53 6,641.08 87.04 -70.20 2,459,209.92 347,897.31 1.81 99.05 MWD+SC+sag (3) 6,870.59 12.81 287.71 6,864.24 6,701.79 90.99 -82.82 2,459,214.04 347,884.75 1.70 112.20 MWD+SC+sag (3) 6,932.77 15.13 288.00 6,924.57 6,762.12 95.60 -97.10 2,459,218.83 347,870.52 3.73 127.13 MWD+SC+sag (3) 6,994.61 16.81 289.61 6,984.02 6,821.57 101.09 -113.20 2,459,224.53 347,854.50 2.81 144.09 MWD+SC+sag (3) 7,056.77 18.50 287.47 7,043.26 6,880.81 107.07 -131.08 2,459,230.74 347,836.70 2.91 162.87 MWD+SC+sag (3) 7,118.79 20.03 286.85 7,101.80 6,939.35 113.11 -150.63 2,459,237.02 347,817.23 2.49 183.21 MWD+SC+sag (3) 7,181.08 22.05 287.47 7,159.93 6,997.48 119.71 -171.99 2,459,243.90 347,795.95 3.26 205.43 MWD+SC+sag (3) 7,243.01 24.10 288.59 7,216.91 7,054.46 127.23 -195.07 2,459,251.72 347,772.97 3.39 229.60 MWD+SC+sag (3) 7,304.67 26.33 290.39 7,272.69 7,110.24 136.01 -219.82 2,459,260.82 347,748.33 3.82 255.80 MWD+SC+sag (3) 7,367.97 28.54 291.63 7,328.87 7,166.42 146.48 -247.04 2,459,271.64 347,721.25 3.61 284.93 MWD+SC+sag (3) 7,430.34 29.79 291.44 7,383.33 7,220.88 157.63 -275.31 2,459,283.16 347,693.13 2.01 315.31 MWD+SC+sag (3) 7,491.35 31.78 292.57 7,435.74 7,273.29 169.34 -304.26 2,459,295.24 347,664.34 3.40 346.52 MWD+SC+sag (3) 7,553.69 34.36 291.64 7,487.98 7,325.53 182.13 -335.78 2,459,308.43 347,632.99 4.22 380.53 MWD+SC+sag (3) 7,616.02 33.92 291.08 7,539.57 7,377.12 194.87 -368.35 2,459,321.60 347,600.58 0.87 415.48 MWD+SC+sag (3) 7,677.75 36.60 291.89 7,589.97 7,427.52 207.93 -401.51 2,459,335.08 347,567.60 4.41 451.10 MWD+SC+sag (3) 7,739.80 36.49 292.00 7,639.82 7,477.37 221.74 -435.78 2,459,349.33 347,533.51 0.21 488.03 MWD+SC+sag (3) 7,802.29 36.12 292.12 7,690.18 7,527.73 235.63 -470.07 2,459,363.67 347,499.40 0.60 525.02 MWD+SC+sag (3) 7,865.27 35.75 292.29 7,741.17 7,578.72 249.60 -504.29 2,459,378.08 347,465.36 0.61 561.97 MWD+SC+sag (3) 7,927.42 36.65 289.64 7,791.32 7,628.87 262.72 -538.56 2,459,391.64 347,431.26 2.90 598.63 MWD+SC+sag (3) 7,989.92 35.93 289.10 7,841.70 7,679.25 274.99 -573.46 - 2,459,404.36 347,396.53 1.26 635.53 MWD+SC+sag (3) 8,051.69 35.37 289.81 7,891.90 7,729.45 286.98 -607.40 2,459,416.79 347,362.74 1.13 671.44 MWD+SC+sag (3) 422/2016 6:57.,32PM Page 4 COMPASS 5000.1 Build 73 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well Soldotna CK Unit 12-3 Project: Soldotna CK Unit TVD Reference: SCU 31 B-04 @ 162.45usft (Saxon 169) Site: Soldotna CK Unit MD Reference: SCU 31 B-04 @ 162.45usft (Saxon 169) Well: Soldotna CK Unit 12-3 North Reference: True Wellbore: SCU 31B-04 Survey Calculation Method: Minimum Curvature Design: SCU 31 B-04 Database: Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +El -W Northing Easting DLS Section (usft) (1) 0 (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,114.22 36.61 288.78 7,942.49 7,780.04 299.12 -642.08 2,459,429.38 347,328.22 2.21 708.09 MWD+SC+sag (3) 8,174.60 36.48 288.99 7,991.00 7,828.55 310.76 -676.10 2,459,441.45 347,294.35 0.30 743.93 MWD+SC+sag (3) 8,238.05 36.02 288.38 8,042.17 7,879.72 322.78 -711.64 2,459,453.93 347,258.97 0.92 781.32 MWD+SC+sag (3) 8,299.76 35.35 288.69 8,092.29 7,929.84 334.22 -745.77 2,459,465.81 347,224.99 1.12 817.18 MWD+SC+sag (3) 8,362.29 37.20 289.02 8,142.70 7,980.25 346.18 -780.78 2,459,478.22 347,190.14 2.98 854.06 MWD+SC+sag (3) 8,424.79 36.80 289.13 8,192.61 8,030.16 358.47 -816.33 2,459,490.97 347,154.75 0.65 891.56 MWD+SC+sag (3) 8,486.23 36.63 288.89 8,241.86 8,079.41 370.43 -851.06 2,459,503.39 347,120.18 0.36 928.18 MWD+SC+sag (3) 8,548.23 37.83 288.14 8,291.23 8,128.78 382.34 -886.63 2,459,515.75 347,084.77 2.07 965.55 MWD+SC+sag (3) 8,609.79 37.81 287.45 8,339.86 8,177.41 393.88 -922.57 2,459,527.75 347,048.98 0.69 1,003.11 MWD+SC+sag (3) 8,671.96 37.59 287.45 8,389.05 8,226.60 405.28 -958.84 2,459,539.62 347,012.87 0.35 1,040.92 MWD+SC+sag (3) 8,734.90 36.90 287.85 8,439.15 8,276.70 416.83 -995.14 2,459,551.64 346,976.72 1.16 1,078.82 MWD+SC+sag (3) 8,797.01 36.84 288.02 8,488.84 8,326.39 428.30 -1,030.59 2,459,563.57 346,941.41 0.19 1,115.91 MWD+SC+sag (3) 8,859.76 36.58 287.87 8,539.14 8,376.69 439.86 -1,066.28 2,459,575.59 346,905.88 0.44 1,153.25 MWD+SC+sag (3) 8,921.72 35.84 288.03 8,589.14 8,426.69 451.14 -1,101.10 2,459,587.32 346,871.21 1.20 1,189.68 MWD+SC+sag (3) 8,984.00 35.49 288.31 8,639.74 8,477.29 462.46 -1,135.60 2,459,599.09 346,836.86 0.62 1,225.84 MWD+SC+sag (3) 9,044.59 36.84 288.62 8,688.65 8,526.20 473.79 -1,169.51 2,459,610.85 346,803.09 2.25 1,261.46 MWD+SC+sag (3) 9,107.92 36.56 288.01 8,739.43 8,576.98 485.68 -1,205.44 2,459,623.21 346,767.32 0.73 1,299.15 MWD+SC+sag (3) 9,169.42 36.44 288.14 8,788.86 8,626.41 497.03 -1,240.22 2,459,635.01 346,732.69 0.23 1,335.57 MWD+SC+sag (3) 9,231.95 36.16 288.02 8,839.26 8,676.81 508.52 -1,275.41 2,459,646.95 346,697.66 0.46 1,372.43 MWD+SC+sag (3) 9,293.77 35.34 287.23 8,889.43 8,726.98 519.46 -1,309.83 2,459,658.33 346,663.38 1.52 1,408.36 MWD+SC+sag (3) 9,355.15 36.28 288.74 8,939.21 8,776.76 530.55 -1,343.98 2,459,669.86 346,629.37 2.10 1,444.10 MWD+SC+sag (3) 9,417.52 36.07 288.72 8,989.55 8,827.10 542.37 -1,378.85 2,459,682.14 346,594.66 0.34 1,480.79 MWD+SC+sag (3) 9,478.99 37.37 290.69 9,038.83 8,876.38 554.77 -1,413.44 2,459,694.98 346,560.23 2.85 1,517.46 MWD+SC+sag (3) 9,541.66 37.14 290.44 9,088.71 8,926.26 568.10 -1,448.96 2,459,708.77 346,524.89 0.44 1,555.35 MWD+SC+sag (3) 9,602.63 36.61 289.83 9,137.48 8,975.03 580.69 -1,483.31 2,459,721.80 346,490.70 1.06 1,591.88 MWD+SC+sag (3) 9,666.30 36.31 289.57 9,188.69 9,026.24 593.45 -1,518.93 2,459,735.02 346,455.25 0.53 1,629.63 MWD+SC+sag (3) 9,727.85 35.98 289.76 9,238.39 9,075.94 605.67 -1,553.12 2,459,747.68 346,421.22 0.57 1,665.86 MWD+SC+sag (3) 9,790.05 35.11 289.64 9,289.00 9,126.55 617.86 -1,587.16 2,459,760.31 346,387.34 1.40 1,701.94 MWD+SC+sag (3) 9,851.65 36.37 289.71 9,339.00 9,176.55 629.97 -1,621.04 2,459,772.86 346,353.62 2.05 1,737.84 MWD+SC+sag (3) 9,914.23 36.23 290.44 9,389.44 9,226.99 642.69 -1,655.84 2,459,786.02 346,318.99 0.73 1,774.82 MWD+SC+sag (3) 9,975.88 37.37 289.80 9,438.80 9,276.35 655.39 -1,690.51 2,459,799.17 346,284.48 1.95 1,811.69 MWD+SC+sag (3) 10,037.88 36.99 290.14 9,488.20 9,325.75 668.18 -1,725.73 2,459,812.42 346,249.44 0.70 1,849.09 MWD+SC+sag (3) 10,099.65 36.56 290.80 9,537.67 9,375.22 681.11 -1,760.37 2,459,825.80 346,214.96 0.95 1,886.02 MWD+SC+sag (3) 10,162.50 36.20 291.19 9,588.28 9,425.83 694.47 -1,795.18 2,459,839.60 346,180.33 0.68 1,923.26 MWD+SC+sag (3) 10,225.78 36.24 291.76 9,639.33 9,476.88 708.16 -1,829.97 2,459,853.74 346,145.72 0.54 1,960.63 MWD+SC+sag(3) 10,287.35 37.48 290.31 9,688.59 9,526.14 721.41 -1,864.45 2,459,867.43 346,111.42 2.46 1,997.53 MWD+SC+sag (3) 10,350.04 37.57 289.75 9,738.31 9,575.86 734.49 -1,900.32 2,459,880.98 346,075.72 0.56 2,035.64 MWD+SC+sag (3) 10,412.90 37.43 289.60 9,788.18 9,625.73 747.37 -1,936.35 2,459,894.32 346,039.85 0.27 2,073.82 MWD+SC+sag (3) 10,475.46 38.78 289.58 9,837.40 9,674.95 760.31 -1,972.72 2,459,907.74 346,003.65 2.16 2,112.34 MWD+SC+sag(3) 10,536.13 40.70 289.41 9,884.05 9,721.60 773.26 -2,009.28 2,459,921.15 345,967.26 3.17 2,151.03 MWD+SC+sag (3) 4/22/2016 6:57:32PM Page 5 COMPASS 5000.1 Build 73 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well Soldotna CK Unit 12-3 Project: Soldotna CK Unit TVD Reference: SCU 31 B-04 @ 162.45usft (Saxon 169) Site: Soldotna CK Unit MD Reference: SCU 31B-04 @ 162.45usft (Saxon 169) Well: Soldotna CK Unit 12-3 North Reference: True Wellbore: SCU 31 B-04 Survey Calculation Method: Minimum Curvature Design: SCU 31 B-04 Database: Sperry EDM - NORTH US + CANADA Survey brlan.wheeler@halliburtow...a.�....� Checked By: ApprOVed By: cary.taylor@haliiburton.com �� u s� Date: n.com 4/22/2016 6:57:32PM Page 6 COMPASS 5000.1 Build 73 Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (1) (1) (usft) (usft) (usft)' (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 10,598.69 42.75 289.12 9,930.74 9,768.29 786.99 -2,048.59 2,459,935.39 345,928.14 3.29 2,192.56 MWD+SC+sag (3) 10,662.51 43.90 287.63 9,977.17 9,814.72 800.79 -2,090.14 2,459,949.73 345,886.77 2.41 2,236.17 MWD+SC+sag (3) 10,726.49 44.20 287.67 10,023.16 9,860.71 814.28 -2,132.53 2,459,963.76 345,844.55 0.47 2,280.43 MWD+SC+sag (3) 10,788.56 43.49 289.08 10,067.92 9,905.47 827.83 -2,173.34 2,459,977.84 345,803.93 1.95 2,323.25 MWD+SC+sag (3) 10,851.34 43.60 291.93 10,113.43 9,950.98 842.97 -2,213.84 2,459,993.51 345,763.63 3.13 2,366.43 MWD+SC+sag (3) 10,913.26 44.33 295.94 10,158.01 9,995.56 860.41 -2,253.11 2,460,011.46 345,724.59 4.65 2,409.40 MWD+SC+sag (3) 10,974.93 44.28 299.74 10,202.15 10,039.70 880.52 -2,291.18 2,460,032.05 345,686.77 4.30 2,452.33 MWD+SC+sag (3) 11,037.82 45.27 302.07 10,246.80 10,084.35 903.28 -2,329.18 2,460,055.30 345,649.08 3.05 2,496.25 MWD+SC+sag (3) 11,100.00 46.00 304.95 10,290.28 10,127.83 927.82 -2,366.23 2,460,080.32 345,612.34 3.51 2,540.01 MWD+SC+sag (3) 11,160.96 45.99 305.61 10,332.63 10,170.18 953.14 -2,402.03 2,460,106.10 345,576.88 0.78 2,582.92 MWD+SC+sag (3) 11,223.25 46.04 305.44 10,375.89 10,213.44 979.19 -2,438.50 2,460,132.61 345,540.74 0.21 2,626.75 MWD+SC+sag (3) 11,285.01 46.20 305.29 10,418.70 10,256.25 1,004.95 -2,474.80 2,460,158.85 345,504.78 0.31 2,670.31 MWD+SC+sag (3) 11,346.40 46.61 305.18 10,461.03 10,298.58 1,030.60 -2,511.12 2,460,184.96 345,468.80 0.68 2,713.84 MWD+SC+sag (3) 11,409.40 46.73 304.95 10,504.26 10,341.81 1,056.93 -2,548.63 2,460,211.78 345,431.63 0.33 2,758.73 MWD+SC+sag (3) 11,472.81 47.01 304.72 10,547.61 10,385.16 1,083.36 -2,586.61 2,460,238.70 345,393.99 0.51 2,804.10 MWD+SC+sag (3) 11,535.59 47.31 304.38 10,590.30 10,427.85 1,109.47 -2,624.53 2,460,265.29 345,356.42 0.62 2,849.27 MWD+SC+sag (3) 11,598.54 47.78 304.44 10,632.79 10,470.34 1,135.72 -2,662.85 2,460,292.03 345,318.44 0.75 2,894.87 MWD+SC+sag (3) 11,660.12 48.04 304.78 10,674.07 10,511.62 1,161.67 -2,700.46 2,460,318.47 345,281.17 0.59 2,939.70 MWD+SC+sag (3) 11,718.25 48.21 305.01 10,712.87 10,550.42 1,186.43 -2,735.96 2,460,343.69 345,245.99 0.42 2,982.13 MWD+SC+sag (3) 11,755.00 . 48.21 305.01 10,737.36 . 10,574.91 1,202.15 -2,758.40 2,460,359.70 345,223.76 0.00 3,008.97 PROJECTED to TD brlan.wheeler@halliburtow...a.�....� Checked By: ApprOVed By: cary.taylor@haliiburton.com �� u s� Date: n.com 4/22/2016 6:57:32PM Page 6 COMPASS 5000.1 Build 73 Lease & Well No. County TD 11.755.00 Hilcorp Energy Company CASING & CEMENTING REPORT SRF SCU 31 B-04 (SCU 12A-03 Sl State CASING RECORD Liner 7 Shoe Deoth: 11 753 00 Alaska Date Run 12 -Mar -16 Supv. M Rogers/ R Brumley/S Barber PRTn Csg Wt. On Hook: 45 Type Float Collar: WOT No. Hrs to Run: 12 Csg Wt. On Slips: Type of Shoe: Reamer shoe Casing Crew: WOT Rotate Csg Yes X No Recip Csg Yes X No Ft. Min. 12.1 PPG Fluid Description: PHPA polymer Liner hanger Info (Make/Model): Baker HRDE ZXPN Liner top Packer?: X Yes _ No Liner hanger test pressure: 4500 Floats Held X Yes _ No Centralizer Placement: Ran 17 cents starting w/ jt # 5 through 21. Just ran enough to cover the Hemlock. CEMENTING REPORT Shoe @ 11753 FC @ 11,669.00 Top of Liner 6315.64 Preflush (Spacer) Type: Mudpush II Density (ppg) Lead Slurry 3 Type: Class "G" Sx = 570 / Yield = 1.33 ft3/sk 12.5 Volume pumped (BBLs) 24.2 Casing (Or Liner) Detail Density (ppg) 13.1 Volume pumped (BBLs) 200 Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top 1 Shoe 53/4 12.6 L-80 DWC/C-HT Weatherford / Reamer 2.25 11,753.00 11,750.75 2 4.5 Liner 41/2 12.6 L-80 DWC/C-HT Vallourec Star 80.38 11,750.75 11,670.37 1 Float Collar 5 12.6 L-80 DWC/C-HT Weatherford 1.39 11,670.37 11,668.98 1 4 1/2 Liner 41/2 12.6 L-80 DWC/C-HT Vallourec Star 39.89 11,668.98 11,629.09 1 Landing collar 5 12.6 L-80 DWC/C-HT JHobbs 1.10 11,629.09 11,627.90 137 4 1/2 Liner 41/2 12.6 L-80 DWC/C-HT Vallourec Star 5,270.06 11,627.90 6,357.39 1 Pup Jt 41/2 12.6 L-80 DWC/C-HT 13.88 6,357.39 6,343.51 1 HRDE ZXPN liner hgr 7 5" Vann Top BOT 27.87 6,343.51 6,315.64 Csg Wt. On Hook: 45 Type Float Collar: WOT No. Hrs to Run: 12 Csg Wt. On Slips: Type of Shoe: Reamer shoe Casing Crew: WOT Rotate Csg Yes X No Recip Csg Yes X No Ft. Min. 12.1 PPG Fluid Description: PHPA polymer Liner hanger Info (Make/Model): Baker HRDE ZXPN Liner top Packer?: X Yes _ No Liner hanger test pressure: 4500 Floats Held X Yes _ No Centralizer Placement: Ran 17 cents starting w/ jt # 5 through 21. Just ran enough to cover the Hemlock. CEMENTING REPORT Shoe @ 11753 FC @ 11,669.00 Top of Liner 6315.64 www.wellez.net WellEz Information Management LLC ver 041416bf Preflush (Spacer) Type: Mudpush II Density (ppg) Lead Slurry 3 Type: Class "G" Sx = 570 / Yield = 1.33 ft3/sk 12.5 Volume pumped (BBLs) 24.2 Density (ppg) 13.1 Volume pumped (BBLs) 200 Mixing / Pumping Rate (bpm): 4 Tail Slurry Lu Type: Easy Blok Sx = 202 / Yield = 1.97 ft3/sk Density (ppg) 15.5 Volume pumped (BBLs) 47 Mixing / Pumping Rate (bpm): 4 U) Post Flush (Spacer) w Type: Density (ppg) Rate (bpm): Volume: LL Displacement: Type: 6% KCL / Polymer Density (ppg) 12 Rate (bpm): 5 Volume (actual / calculated): 159/164 FCP (psi): 1450 Pump used for disp: Rig Bump Plug? X Yes No Bump press 4200 Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job 100 Cement returns to surface? Yes X No Spacer returns? Yes X No Vol to Surf: Cement In Place At: 15:05 Date: 3/13/2016 Estimated TOC: 7,720' Method Used To Determine TOC: CBL - Monty Myers www.wellez.net WellEz Information Management LLC ver 041416bf STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon LJ Plug Perforations Ll Fracture Stimulate Pull Tubing 11 Operations shutdown Performed: Suspend ❑ Perforate ❑✓ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ arforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: Asphaltene Treatment ❑✓ 2. Operator Hilcorp Alaska, LLC 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development p ❑ Stratigraphic ❑ Ex Exploratory ry ❑ Service ❑ 216-010 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-133-10099-02 7. Property Designation (Lease Number): 8. Well Name and Number: A028997 Soldotna Creek Unit (SCU) 31 B-04 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Swanson River Field / Hemlock Oil Pool 11. Present Well Condition Summary: Total Depth measured 11,755 feet Plugs measured N/A feet true vertical 10,737 feet Junk measured N/A feet i JL 19 2016 Effective Depth measured 11,628 feet Packer measured 10,948 feet ; GC;C true vertical 10,653 feet true vertical 10,183 feet v Casing Length Size MD TVD Burst Collapse Structural Conductor 18, 22" 28' 28' Surface 3,000' 13-3/8" 3,000' 3,000' 3,730psi 1,130psi Intermediate 6,514' 7" 6,514' 6,513' 8,160psi 7,020psi Production Liner 5,438' 4-1/2" 11,753' 10,736' 17,693psi 16,769psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 2-7/8" 6.5# / L-80 6,310' MD 6,309' TVD Tubing (size, grade, measured and true vertical depth) 2-3/8" 4.7# / L-80 10,973' MD 10,201' TVD Tri -Pt Hyd Pkr 10,948' MD 10,183' TVD Packers and SSSV (type, measured and true vertical depth) N/A N/A N/A 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: 29 17 3 680 150 Subsequent to operation: 49 5 26 705 181 14. Attachments (required per 20 AAC 25.070, 25.071, a 25.283) 15. Well Class after work: Daily Report of Well Operations ❑✓ Exploratory[] Development[2] Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil ✓ Gas WDSPL Printed and Electronic Fracture Stimulation Data ❑ IGSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 316-339 Contact Joe Kaiser - 777-8393 Email ikaiser(a,hilcorp. com Printed Name Chad Helgeson Title Operations Manager Signature r� Phone 907-777-8405 Date ? h r ! a Form 10-404 Revised 5/2015 RBDMS W JUL 2 2 2016 = Submit Original Only #� Hilcorp Alaska, LLC v Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SCU 3113-04 Completion E -Line 50-133-10099-02 1 216-010 6/28/16 7/8/16 Daily Operations: 06/28/2016 -Tuesday Mobe to location. PTW and JSA. Rig up lubricator P/T Lub 2,500 psi fail change 0 -ring re -test (good). RIH w/ 1.75'G - ring to 11,546' KB. Tag fill. POOH. No problems. RIH w/ 10' OF 1-11/16" dummy guns to 11,536' KB. Clear. POOH. No problem. Rig down lubricator and turn well back to field. TP 420 psi. 06/29/2016 - Wednesday Meet at office. Mobe to location. PTW and JSA. Spot equipment, pressure test lubricator to 250 psi low and 2,500 psi high. Arm gun. RIH w/ 1-11/16" x 22.6' Maxforce strip gun, 6 spf. Triphase and tie into Halliburton RMTI log dated 16 Mar 16. Strip gun, set down at top of X -nipple at 10,963'. Tried different things but could not get past X -nipple. POOH. Tools and strip gun was packed with paraffin. Called town and decision was made to brush and flush tubing tomorrow and perf on Friday. Rigged down lubricator and moved some of Halliburton equipment out of the way for Pollard tomorrow. 07/05/2016 - Tuesday Arrive at Swanson River. Permit, JSA,TGSM and MOBE to location. Rig up lubricator, PT to 250 psi low and 2,500 psi high, shut in. RIH w/ 2.1" cutter to 33' KB, fall slow to 60' KB. RIH to 1,300' KB, slight build up to 1,500' KB, cont. RIH to 2,500' KB. POOH, paraffin on cutter, pump 15bbl of hot oil, RIH w/ 2.30" G -ring to 1,100' KB, pump oil to 1,200' KB, fall free to 2,500' KB, pull back to surface, run back in hole to 6,178' KB, tag top of x -over for 2- 3/8". POOH, standby for hot oil to pump remaining oil down flow line. RIH w/ 1.75" DD bailer to 11,556' KB. POOH, bleed down lubricator, RD slickline. 07/06/2016 - Wednesday Meet at office. Mobe to location. PTW and JSA. Rig up lubricator, PT to 250 psi low and 2,500 psi high. Arm gun. RIH w/ 1-11/16" x 22.6' Maxforce strip gun, 6 spf Triphase and tie into Halliburton RMTI log dated 16 Mar 16. Run correlation log and send to town. Get ok to perf from 11,306.4' to 11,329'. Fired gun with 231 psi TP. After 5 min TP - 236 psi. POOH and gun did not fire. Looked like a low order fire. Arm gun. RIH w/ 1-11/16" x 22.6' Maxforce strip gun, 6 spf Triphase and tie into Halliburton RMTI log dated 16 Mar 16. Gun set down at 8,260'. POOH and gun had 4 to 5 big chunks of paraffin/asphaltene. Called town and discussed. Will change from strip gun to hollow carrier guns and come back Friday to perf. Slickline will be here tomorrow. Rig unit for standby. TP - 245 psi. 07/07/2016 - Thursday Swanson Hilcorp office, permit inspect location, lay tarps, spot equipment, PJSM, JSA, rig up .125" slickline, PT lubricator 500/2,500psi, pass. RIH w/1.75" gauge ring, S/D and work through areas @ 450', 6,175', 8,266'& 10,965' KB. Work areas until tools fall freely, tag T/D @ 11,569' KB. POOH. RIH w/ 2.343" paraffin knife while pumping xylene, see very little paraffin, tools fall freely. S/D and fall through @ 6,175' KB work area @ GLM# 7, tools fall freely, tag XO @ 6,310' KB. POOH. Overpull 200# @ 3,060' KB, work area, tools fall freely. POOH. RIH w/ 1.6875" x 20' dummy gun drift, drift to 11,350' KB. POOH to surface, no restrictions. Rig down lubricator and turn well over to field. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SCU 31B-04 Completion E-Line 1 50-133-10099-02 1 216-010 6/28/16 1 7/8/16 Daily Operations: 07/08/2016 - Friday Meet at office. Mobe to location. PTW and JSA. Rig up lubricator, PT to 250 psi low and 2,500 psi high. RIH w/ 1-9/16" x 20' Razor HC, 6 spf, 60 deg phase and tied into Halliburton RMTI log dated 16 Mar 16. Run correlation log and send to town. Get ok to perf from 11,309' to 11,329'. Fired gun with 219 psi on well and saw no pressure change. POOH. All shots fired. RIH w/ 1-9/16" x 20' Razor HC, 6 spf, 60 deg phase and tied into Halliburton RMTI log dated 16 Mar 16. Gama ray tool quit working when we tried to run correlation log. Tried different things but no good. POOH. Change gamma ray tool out and tested. RIH w/ 1-9/16" x 20' Razor HC, 6 spf, 60 deg phase and tied into Halliburton RMTI log dated 16 Mar 16. Run correlation log and send to town. Get ok to perf from 11,289' to 11,309. Fired shot with 212 psi on tubing. No change in pressure. POOH. All shots fired. RIH w/ 1-9/16" x 20' Razor HC, 6 spf, 60 deg phase and tied into Halliburton RMTI log dated 16 Mar 16. Run correlation log and send to town. Get ok to perf from-, ,26 'aa... 11,289'. Fired shot with 209 psi on tubing. POOH. All shots fired. RIH w/ 1-9/16" x 20' Razor HC, 6 spf, 60 deg phase and tied into Halliburton RMTI log dated 16 Mar 16. Run correlation log and correlate log myself. Spot gun from 11,249' to 11,269'. Fired shot with 205 psi on tubing and saw no pressure change. POOH. All shots fired (Sent correlation log to town). RIH w/ 1-9/16" x 7' Razor HC, 6 spf, 60 deg phase and tied into Halliburton RMTI log dated 16 Mar 16. Run correlation log and correlate log myself. Spot gun from 11,242' to 11,249'. Fired shot with 202 psi on tubing and saw no pressure change. POOH. All shots fired (Sent correlation log to town). Rig down lubricator and turn well back to field. Halliburton will get with Joe Kaiser about the pricing. Soldotna Creek Unit CU 3113-04 SCHEMATIC Well 216-001010 PTD: 21 API: 50-133-10099-02-00 Hilcoco Alaska. LLC 11,753' TD @ 11,755' MD / 10,737' TVD PBTD @ 11,628' MD / 10,653' TVD MAX HOLE ANGLE = 48.21° @ 11,755' MD CASING AND TUBING DETAIL Size WT Grade Conn ID Top Btm 22" - Tubing Hanger, 2-7/8" 8RD 2 2,541' Surface 28' 13-3/8" 54.5 4,581' 2.441" 10.050" Surface 3,000' 7" 29 P-110 2-7/8" SFO -1 GLM #7 (Live Valve) 6.059" Surface 6,514' 4-1/2" 12.6 L-80 DWC/C-HT 3.833" 6,315' 11,753' 2-7/8" 6.5 L-80 8RD EUE 2.441" Surface 6,310' 2-3/8" 4.7 L-80 8RD EUE 1.995" 6,310' 10,973' JEWELRY DETAIL No Depth ID OD Item 1 19' 2.441" - Tubing Hanger, 2-7/8" 8RD 2 2,541' 2.441" 4.500" 2-7/8" SFO -1 GLM #9 (Live Valve) 3 4,581' 2.441" 4.500" 2-7/8" SFO -1 GLM #8 (Live Valve) 4 6,174' 2.441" 4.500" 2-7/8" SFO -1 GLM #7 (Live Valve) 5 6,310' 1.995" 3.670" XO, 2-7/8" 8RD x 2-3/8" 8RD 6 7,361' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #6 (T-1 latch) (Live Valve) 7 8,264' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #5 (T-1 latch) (Live Valve) 8 8,947' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #4 (T-1 latch) (Live Valve) 9 9,535' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #3 (T-1 latch) (Live Valve) 10 10,185' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #2 (T-1 latch) (Live Valve) 11 10,900' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #1 (T-1 latch) (Live Valve) 12 10,948' 2.680" 3.750" 4-1/2" x 2-3/8" Hydraulic Packer 13 10,963' 1.875" 3.050" X -Nipple 14 10,973' 1.995" 3.050" WL Entry Guide 7" Window Detail TOW @ 6,514' BOW @ 6,527' A 6,315' 4.190" 7" X4-1/2" ZXP liner hanger -- PERFORATIONS fop(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size SPF Status Date 11,242' 11,329' 10,389' 10,448' 87' 1-9/16" 6 Open 07/08/16 11,242' 11,329' 10,389' 10,448' 87' 1-9/16" 6 Open 03/31/16 Updated by DMA 07/14/16 THE STATE °fALAS -KA GOVERNOR BILL WALKER Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 31B-04 Permit to Drill Number: 2_ \ Lk Sundry Number: 316-339 Dear Mr. Helgeson: Alaska Oil and Cas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov 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 ZZ day of June, 2016. RBDMS �V JUN 2 4 2016 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVED JUN 17 2016 A068 ; 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate E Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Asphaltene Treatment Q 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development ❑✓ Stratigraphic ❑ Service ❑ 216-010 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, Alaska 99503 50-133-10099-02 7. If perforating: 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 123B. Rule 5 Will planned perforations require a spacing exception? Yes ❑ No ❑� Soldotna Creek Unit (SCU) 31 B-04 ° 9. Property Designation (Lease Number): 10. Field/Pool(s): A028997 Swanson River yield / Hemlock Oil Pod 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): 11,755' ' 10,737' • 11,628' 10,653' 1,647psi WA N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 18' 22" 28' 28' Surface 3,000' 13-3/8" 3,000' 3,000' 3,730psi 1,130psi Intermediate 6,514' 7" 6,514' 6,513' 8,160psi 7,020psi Production Liner 5,438' 4-1/2" 11,753' 10,736' 17,693psi 16,769psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: 2-7/8" Tubing Grade: 6.5# / L-80 Tubing MD (ft): 6,310' See Attached Schematic See Attached Schematic 2-3/8" 4.7# / L-80 10,973' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Tri -Point Hydraulic Packer; N/A 10,948' MD/ 10,183' TVD; WA 12. Attachments: Proposal Summary Q Wellbore schematic ❑,/ 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigrapnic ❑ Development [2] Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: July 1, 2016 OIL Q - WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG D 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. Contact Joe Kaiser - 777-8393 Email kaiser hilcor .com Printed Name Chad Helgeson Title Operations Manager Signature Phone 907-777-8405 Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. -3 -33� Plug Integrity ❑ BOP Test ' Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ RBDMS 1, - JUN 2 4 2016 Spacing Exception Required? Yes ❑ No ❑° Subsequent Form Required: - Y� APPROVED BY / Approved by: COMMISSIONER THE COMMISSION Date: (p -23 - on OPR+64441rldSubmit Form and Form 10-403 Revised 11/2015 for 12 ths from the date of ap:4� Attachmen s in Duplicate - C.Zu%4," Hilcorp Alaska, LLC Well Prognosis Well: SCU 31B-04 Date: 6/17/2016 Well Name: SCU 316-04 API Number: 50-133-10099-02-00 Current Status: Active Gas lifted Oil Well Leg: N/A Estimated Start Date: July 15`, 2016 Rig: E -line Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 216-010 First Call Engineer: Joe Kaiser (907) 777-8393 (0) (907) 952-8897 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (M) AFE Number: Maximum Expected BHP MPSP for Reperforation: MPSP During Treatment: Brief Well Summary 1,647 psi @ 10,429' TVD (Based on 24hr PBU 6/10/2016) 604 psi (Based on gas gradient 0.1 psi/ft) 1,400 psi (Gas lift supply pressure) SCU 3113-04 is a gas lifted oil well that was drilled as a sidetrack to SCU 12A-03 in March 2016. Since initial completion, this well has declined 70%. - RWO Objective: The purpose of this sundry is to reperforate the H3L Sands and perform an asphaltene treatment. Notes Regarding Wellbore Condition • Well fluid analysis are: 5.36% asphaltenes and 8.32% Asphaltic Resins. • Slickline will remove any parafin build up on tubing prior to E -line work. Eline Procedure: 1. MIRU E -line, PT lubricator to 2,500 psi Hi and 250 psi Low. 2. Shut in well and bleed gas lift down to system pressure (-150psi). 3. RU wireline guns. 4. RIH and reperforate the following intervals: Zone Sands Top (MD) Btm (MD) FT Hemlock H3L ±11,242' ±11,329' 87 a. Proposed perfs shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Correlation Log provided by Reservior Engineer d. Use Gamma/CCL/ to correlate. e. Install Crystal gauges on well before perforating. Record tubing pressures before and after each perforating run. f. All perforations in table above are located in the Hemlock Pool based on Conservation ` Order No. 1238 Rule S. 5. RD E -line. 6. Turn well over to production. 7. Test Well. Well Prognosis Well: SCU 316-04 llilcorp Alaska. LLC Date: 6/17/2016 Contingency if reperforation doesn't improve performance Asphaltene Treatment Procedure: 8. Shut in well, pressure up tubing with gas lift supply pressure with chart recorder or cystal gauge. Pressure should break over at—1,300psig. Push fluid into formation with gas until pressure breaks over and shut in well. Note breakover pressure on chart. 9. RU Hot oil truck/pump truck. Pressure test lines and hoses to 2,000 psig. 10. Pump 3 bbls of neet Kvrl�ne 11. Mix 1,800 gallons of treatment in Vac Truck. (A mixture of Baker PAO 72 chemical may be used in a ratio up to 2:1 xylene/PA072). Pump into hot oil tank and pump at lbpm into well. Tubing pressure will decrease to zero and possibly go on a vaccum. (Calc notes: 0.63 gal/ft in 4.5" tubing; .378 psi/ft xylene gradient) 12. Pump 3 bbls of neet xylene in well. 13. Slowly pressure up on well with gas lift supply. Inject gas down tubing until tubing pressure reads —75 psi below breakover pressure in step 8. Do NOT over pressure to the break over point and continue to add gas. Keep treament partially in tubing. Monitor casing pressure during pumping operations. 14. Soak for 4hrs with well shut-in. 5. Bleed down tubing pressure to approximately 500psig. Let stand for 30min. 16. Repeat steps 13-15, 2 more times. On 3rd soak, shut in well with tubing pressure at 75 ps below breakover pressure overnight. 17. After overnight soak, bleed down to system pressure (-150 psi). 18. Bring well back online. 19. Turn over to production. 20. Test Well. Attachments: 1. Proposed Schematic 2. MSDS Xylene 3. MSDS PA072 Soldotna Creek Unit Well SCU 3113-04 PhJPOSED SCHEMATIC PTD: 216-010 API: 50-133-10099-02-00 Hilcoro Alaska. LLC 11,753' TD @ 11,755' MD / 10,737' TVD PBTD @ 11,628' MD / 10,653' TVD MAX HOLE ANGLE = 48.21° @ 11,755' MD CASING AND TUBING DETAIL Size WT Grade Conn ID Top Btm 22" - Tubing Hanger, 2-7/8" 8RD 2 2,541' Surface 28' 13-3/8" 54.5 4,581' 2.441" 10.050" Surface 3,000' 7" 29 P-110 2-7/8" SFO -1 GLM #7 (Live Valve) 6.059" Surface 6,514' 4-1/2" 12.6 L-80 DWC/C-HT 3.833" 6,315' 11,753' 2-7/8" 6.5 L-80 8RD EUE 2.441" Surface 6,310' 2-3/8" 4.7 L-80 8RD EUE 1.995" 6,310' 10,973' IEWELRY DETAIL No Depth ID OD Item 1 19' 2.441" - Tubing Hanger, 2-7/8" 8RD 2 2,541' 2.441" 4.500" 2-7/8" SFO -1 GLM #9 (Live Valve) 3 4,581' 2.441" 4.500" 2-7/8" SFO -1 GLM #8 (Live Valve) 4 6,174' 2.441" 4.500" 2-7/8" SFO -1 GLM #7 (Live Valve) 5 6,310' 1.995" 3.670" XO, 2-7/8" 8RD x 2-3/8" 8RD 6 7,361' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #6 (T-1 latch) (Live Valve) 7 8,264' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #5 (T-1 latch) (Live Valve) 8 8,947' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #4 (T-1 latch) (Live Valve) 9 9,535' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #3 (T-1 latch) (Live Valve) 10 10,185' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #2 (T-1 latch) (Live Valve) 11 10,900' 1.990" 3.350" 2-3/8" GLMAX-1 GLM #1 (T-1 latch) (Live Valve) 12 10,948' 2.680" 3.750" 4-1/2" x 2-3/8" Hydraulic Packer 13 10,963' 1.875" 3.050" X -Nipple 14 10,973' 1.995" 3.050" WL Entry Guide 7" Window Detail TOW @ 6,514' BOW @ 6,527' A 1 6,315' 1 4.190" 7" X4-1/2" ZXP liner hanger PERFORATIONS Updated by JEK 6/17/2016 Science Lah aim Chemicals & Laboratory Equipment Material Safety Data Sheet Xylenes MSDS Section 1: Chemical Product and Companv Identification Product Name: Xylenes Catalog Codes: SLX1075, SLX1129, SLX1042, SLX1096 CAS#: 1330-20-7 RTECS: ZE2100000 TSCA: TSCA 8(b) inventory: Xylenes CI#: Not available. Synonym: Xylenes; Dimethylbenzene; xylol; methyltoluene Chemical Name: Xylenes (o-, m-, p- isomers) Chemical Formula: C6H4(CH3)2 Contact Information: Sciencelab.com, Inc. 14025 Smith Rd. Houston, Texas 77396 US Sales: 1-800-901-7247 International Sales: 1-281441-4400 Order Online: Sciencel-ab.com CHEMTREC (24HR Emergency Telephone), call: 1-800-424-9300 International CHEMTREC, call: 1-703-527-3887 For non -emergency assistance, call: 1-281-441-4400 I Section 2: Composition and Information on Ingredients Composition: Name Xylenes CAS # 1330-20-7 % by Weight 100 Toxicological Data on Ingredients: Xylenes: ORAL (LD50): Acute: 4300 mg/kg [Rat]. 2119 mg/kg [Mouse]. DERMAL (LD50): Acute: >1700 mg/kg [Rabbit]. Section 3: Hazards Identification Potential Acute Health Effects: Hazardous in case of skin contact (irritant, permeator), of eye contact (irritant), of ingestion, of inhalation. Potential Chronic Health Effects: CARCINOGENIC EFFECTS: 3 (Not classifiable for human.) by IARC. MUTAGENIC EFFECTS: Not available. TERATOGENIC EFFECTS: Not available. DEVELOPMENTAL TOXICITY: Not available. The substance may be toxic to blood, kidneys, liver, mucous membranes, bone marrow, central nervous system (CNS). Repeated or prolonged exposure to the substance can produce target organs damage. Section 4: First Aid Measures Eye Contact: Check for and remove any contact lenses. In case of contact, immediately flush eyes with plenty of water for at least 15 minutes. Get medical attention. Skin Contact: In case of contact, immediately flush skin with plenty of water. Cover the irritated skin with an emollient. Remove contaminated clothing and shoes. Wash clothing before reuse. Thoroughly clean shoes before reuse. Get medical attention. Serious Skin Contact: Wash with a disinfectant soap and cover the contaminated skin with an anti -bacterial cream. Seek immediate medical attention. Inhalation: If inhaled, remove to fresh air. If not breathing, give artificial respiration. If breathing is difficult, give oxygen. Get medical attention if symptoms appear. Serious Inhalation: Evacuate the victim to a safe area as soon as possible. Loosen tight clothing such as a collar, tie, belt or waistband. If breathing is difficult, administer oxygen. If the victim is not breathing, perform mouth-to-mouth resuscitation. Seek medical attention. Ingestion: Do NOT induce vomiting unless directed to do so by medical personnel. Never give anything by mouth to an unconscious person. Loosen tight clothing such as a collar, tie, belt or waistband. Get medical attention if symptoms appear. Serious Ingestion: Not available. I Section 5: Fire and Explosion Data I Flammability of the Product: Flammable. Auto -Ignition Temperature: 464°C (867.2°F) Flash Points: CLOSED CUP: 24°C (75.2°F). (Tagliabue.) OPEN CUP: 37.8°C (100°F). Flammable Limits: LOWER: 1% UPPER: 7% Products of Combustion: These products are carbon oxides (CO, CO2). Fire Hazards in Presence of Various Substances: Highly flammable in presence of open flames and sparks, of heat. Non-flammable in presence of shocks. Explosion Hazards in Presence of Various Substances: Risks of explosion of the product in presence of mechanical impact: Not available. Slightly explosive in presence of open flames and sparks, of heat. Fire Fighting Media and Instructions: Flammable liquid, soluble or dispersed in water. SMALL FIRE: Use DRY chemical powder. LARGE FIRE: Use alcohol foam, water spray or fog. Cool containing vessels with water jet in order to prevent pressure build-up, autoignition or explosion. Special Remarks on Fire Hazards: Vapors may travel to source of ignition and flash back. Special Remarks on Explosion Hazards: Vapors may form explosive mixtures with air. Containers may explode when heated. May polymerize explosively when heated. An attempt to chlorinate xylene with 1,3-Dichloro-5,5-dimethyl-2,4-imidazolidindione (dichlorohydrantoin) caused a violent explosion Section 6: Accidental Release Measures Small Spill: Absorb with an inert material and put the spilled material in an appropriate waste disposal. Large Spill: Flammable liquid. Keep away from heat. Keep away from sources of ignition. Stop leak if without risk. Absorb with DRY earth, sand or other non-combustible material. Do not touch spilled material. Prevent entry into sewers, basements or confined p. 2 areas; dike if needed. Be careful that the product is not present at a concentration level above TLV. Check TLV on the MSDS and with local authorities. Section 7: Handling and Precautions: Keep away from heat. Keep away from sources of ignition. Ground all equipment containing material. Do not ingest. Do not breathe gas/fumes/ vapor/spray. Wear suitable protective clothing. In case of insufficient ventilation, wear suitable respiratory equipment. If ingested, seek medical advice immediately and show the container or the label. Avoid contact with skin and eyes. Keep away from incompatibles such as oxidizing agents, acids. Storage: Store in a segregated and approved area. Keep container in a cool, well -ventilated area. Keep container tightly closed and sealed until ready for use. Avoid all possible sources of ignition (spark or flame). I Section 8: Exposure Controls/Personal Protection I Engineering Controls: Provide exhaust ventilation or other engineering controls to keep the airborne concentrations of vapors below their respective threshold limit value. Ensure that eyewash stations and safety showers are proximal to the work -station location. Personal Protection: Splash goggles. Lab coat. Vapor respirator. Be sure to use an approved/certified respirator or equivalent. Gloves. Personal Protection in Case of a Large Spill: Splash goggles. Full suit. Vapor respirator. Boots. Gloves. A self contained breathing apparatus should be used to avoid inhalation of the product. Suggested protective clothing might not be sufficient; consult a specialist BEFORE handling this product. Exposure Limits: TWA: 100 (ppm) [Canada] TWA: 435 (mg/m3) [Canada] TWA: 434 STEL: 651 (mg/m3) from ACGIH (TLV) [United States] TWA: 100 STEL: 150 (ppm) from ACGIH (TLV) [United States] Consult local authorities for acceptable exposure limits. I-- Section 9: Physical and Chemical Properties Physical state and appearance: Liquid. Odor: Sweetish. Taste: Not available. Molecular Weight: 106.17 g/mole Color: Colorless. Clear pH (1% soln/water): Not available. Boiling Point: 138.5°C (281.3°F) Melting Point: -47.4°C (-53.3°F) Critical Temperature: Not available. Specific Gravity: 0.864 (Water = 1) Vapor Pressure: 0.9 kPa (@ 20°C) Vapor Density: 3.7 (Air = 1) Volatility: Not available. Odor Threshold: 1 ppm p. 3 Water/Oil Dist. Coeff.: The product is more soluble in oil; log(oil/water) = 3.1 lonicity (in Water): Not available. Dispersion Properties: Not available. Solubility: Insoluble in cold water, hot water. Miscible with absolute alcohol, ether, and many other organic liquids. Section 10: Stability and Reactivity Data Stability: The product is stable. Instability Temperature: Not available. Conditions of Instability: Heat, ignition sources, incompatibles Incompatibility with various substances: Reactive with oxidizing agents, acids. Corrosivity: Non -corrosive in presence of glass. Special Remarks on Reactivity: Store away from acetic acid, nitric acid, chlorine, bromine, and fluorine. Special Remarks on Corrosivity: Not available. Polymerization: Will not occur. Section 11: Toxicoloaical Information Routes of Entry: Absorbed through skin. Dermal contact. Eye contact. Inhalation Toxicity to Animals: WARNING: THE LC50 VALUES HEREUNDER ARE ESTIMATED ON THE BASIS OF A 4 -HOUR EXPOSURE. Acute oral toxicity (LD50): 2119 mg/kg [Mouse]. Acute dermal toxicity (LD50): >1700 mg/kg [Rabbit]. Acute toxicity of the vapor (LC50): 5000 4 hours [Rat]. Chronic Effects on Humans: CARCINOGENIC EFFECTS: 3 (Not classifiable for human.) by IARC. May cause damage to the following organs: blood, kidneys, liver, mucous membranes, bone marrow, central nervous system (CNS). Other Toxic Effects on Humans: Hazardous in case of skin contact (irritant, permeator), of ingestion, of inhalation. Special Remarks on Toxicity to Animals: Lowest Lethal Dose: LDL [Human] - Route: Oral; Dose: 50 mg/kg LCL [Man] - Route: Oral; Dose: 10000 ppm/6H Special Remarks on Chronic Effects on Humans: Detected in maternal milk in human. Passes through the placental barrier in animal. Embryotoxic and/or foetotoxic in animal. May cause adverse reproductive effects (male and femael fertility (spontaneous abortion and fetotoxicity)) and birth defects based animal data. Special Remarks on other Toxic Effects on Humans: Acute Potential Health Effects: Skin: Causes skin irritation. Can be absorbed through skin. Eyes: Causes eye irritation. Inhalation: Vapor causes respiratory tract and mucous membrane irritation. May affect central nervous system and behavior (General anesthetic/CNS depressant with effects including headache, weakness, memory loss, irritability, dizziness, giddiness, loss of coordination and judgement, respiratory depression/arrest or difficulty breathing, loss of appetite, nausea, vomiting, shivering, and possible coma and death). May also affects blood, sense organs, liver, and peripheral nerves. Ingestion: May cause gastrointestinal irritation including abdominal pain, vomiting, and nausea. May also affect liver and urinary system/ kidneys. May cause effects similar to those of acute inhalation. Chronic Potential Health Effects: Chronic inhalation may affect the urinary system (kidneys) blood (anemia), bone marrow (hyperplasia of bone marrow) brain/behavior/Central Nervous system. Chronic inhalation may alsocause mucosal bleeding. Chronic ingestion may affect the liver and metabolism (loss of appetite) and may affect urinary system (kidney damage) p. 4 I Section 12: Ecological Information I Ecotoxicity: Not available. BOD5 and COD: Not available. Products of Biodegradation: Possibly hazardous short term degradation products are not likely. However, long term degradation products may arise. Toxicity of the Products of Biodegradation: The products of degradation are less toxic than the product itself. Special Remarks on the Products of Biodegradation: Not available. Section 13: Disposal Considerations Waste Disposal: Waste must be disposed of in accordance with federal, state and local environmental control regulations. Section 14: Transport Information DOT Classification: CLASS 3: Flammable liquid. Identification:: Xylenes UNNA: 1307 PG: III Special Provisions for Transport: Not available. I Section 15: Other Regulatory Information I Federal and State Regulations: Connecticut hazardous material survey.: Xylenes Illinois chemical safety act: Xylenes New York acutely hazardous substances: Xylenes Rhode Island RTK hazardous substances: Xylenes Pennsylvania RTK: Xylenes Minnesota: Xylenes Michigan critical material: Xylenes Massachusetts RTK: Xylenes Massachusetts spill list: Xylenes New Jersey: Xylenes New Jersey spill list: Xylenes Louisiana spill reporting: Xylenes California Director's List of Hazardous Substances: Xylenes TSCA 8(b) inventory: Xylenes SARA 302/304/311/312 hazardous chemicals: Xylenes SARA 313 toxic chemical notification and release reporting: Xylenes CERCLA: Hazardous substances.: Xylenes: 100 lbs. (45.36 kg) Other Regulations: OSHA: Hazardous by definition of Hazard Communication Standard (29 CFR 1910.1200). EINECS: This product is on the European Inventory of Existing Commercial Chemical Substances. Other Classifications: WHMIS (Canada): CLASS 13-2: Flammable liquid with a flash point lower than 37.8°C (100°F). CLASS D -2A: Material causing other toxic effects (VERY TOXIC). DSCL (EEC): R10- Flammable. R21- Harmful in contact with skin. R36/38- Irritating to eyes and skin. S2- Keep out of the reach of children. S36/37- Wear suitable protective clothing and gloves. S46- If swallowed, seek medical advice immediately and show this container or label. HMIS (U.S.A.): Health Hazard: 2 Fire Hazard: 3 Reactivity: 0 Personal Protection: h p. 5 National Fire Protection Association (U.S.A.): Health: 2 Flammability: 3 Reactivity: 0 Specific hazard: Protective Equipment: Gloves. Lab coat. Vapor respirator. Be sure to use an approved/certified respirator or equivalent. Wear appropriate respirator when ventilation is inadequate. Splash goggles. I Section 16: Other Information I References: Not available. Other Special Considerations: Not available Created: 10/11/2005 12:54 PM Last Updated: 05/21/2013 12:00 PM The information above is believed to be accurate and represents the best information currently available to us. However, we make no warranty of merchantability or any other warranty, express or implied, with respect to such information, and we assume no liability resulting from its use. Users should make their own investigations to determine the suitability of the information for their particular purposes. In no event shall ScienceLab. com be liable for any claims, losses, or damages of any third party or for lost profits or any special, indirect, incidental, consequential or exemplary damages, howsoever arising, even if ScienceLab. com has been advised of the possibility of such damages. viae SAFETY DATA SHEET BAKER HUGHES Section 1. Identification Product name Product code PAO72 ASPHALTENE DISPERSANT PAO72 Relevant identified uses of the substance or mixture and uses advised against Identified uses : Asphaltene dispersant. Print date 11/6/2014. Validation date 11/6/2014. Version 1 Supplier's details Baker Petrolite A Baker Hughes Company 12645 W. Airport Blvd. Sugar Land, TX 77478 For Product Information/MSDSs Call: 800-231-3606 (8:00 a.m. - 5:00 p.m. cst, Monday- Friday) 281-276-5400 Emergency telephone CHEMTREC: 800-424-9300 (U.S. 24 hour) number (with hours of Baker Petrolite: 800-231-3606 operation) (001)281-276-5400 CANUTEC: 613-996-6666 (Canada 24 hours) CHEMTREC Int'I 01-703-527-3887 (International 24 hour) Section 2. Hazards identification OSHA/HCS status This material is considered hazardous by the OSHA Hazard Communication Standard (29 CFR 1910.1200). Classification of the FLAMMABLE LIQUIDS - Category 3 substance or mixture SKIN CORROSION/IRRITATION - Category 1 SERIOUS EYE DAMAGE/ EYE IRRITATION - Category 1 CARCINOGENICITY - Category 1 SPECIFIC TARGET ORGAN TOXICITY (SINGLE EXPOSURE) [Respiratory tract irritation and Narcotic effects] - Category 3 AQUATIC HAZARD (LONG-TERM) - Category 2 GHS label elements Hazard pictograms 1> < > Signal word Danger Hazard statements Flammable liquid and vapor. Causes severe skin burns and eye damage. May cause cancer. May cause respiratory irritation. May cause drowsiness and dizziness. Toxic to aquatic life with long lasting effects. Precautionary statements 11/6/2014. PAO72 1/11 PA072 ASPHALTENE DISPERSANT Section 2. Hazards identification Prevention Obtain special instructions before use. Do not handle until all safety precautions have been read and understood. Use personal protective equipment as required. Wear protective gloves. Wear eye or face protection. Wear protective clothing. Keep away from heat, sparks, open flames and hot surfaces. - No smoking. Use explosion -proof electrical, ventilating, lighting and all material -handling equipment. Use only non - sparking tools. Take precautionary measures against static discharge. Keep container tightly closed. Use only outdoors or in a well -ventilated area. Avoid release to the environment. Avoid breathing vapor. Wash hands thoroughly after handling. Response Collect spillage. IF exposed or concerned: Get medical attention. IF INHALED: Remove victim to fresh air and keep at rest in a position comfortable for breathing. Immediately call a POISON CENTER or physician. IF SWALLOWED: Immediately call a POISON CENTER or physician. Rinse mouth. Do NOT induce vomiting. IF ON SKIN (or hair): Take off immediately all contaminated clothing. Rinse skin with water or shower. Wash contaminated clothing before reuse. Immediately call a POISON CENTER or physician. IF IN EYES: Rinse cautiously with water for several minutes. Remove contact lenses, if present and easy to do. Continue rinsing. Immediately call a POISON CENTER or physician. Storage Store locked up. Store in a well -ventilated place. Keep cool. Disposal Dispose of contents and container in accordance with all local, regional, national and international regulations. Hazards not otherwise None known. classified Section 3. Composition/information on ingredients Substance/mixture : Mixture Ingredient name % CAS number Light aromatic naphtha 30-40 64742-95-6 1,2,4 -Trim ethyl benzene 20-30 95-63-6 Alkyl benzenesulfonic acid 20-30 68584-22-5 1,3,5-Trimethylbenzene 5-10 108-67-8 1,2,3 -Trim ethyl benzene 1 - 5 526-73-8 Xylene 1 -5 1330-20-7 Cumene 0.1 -1 98-82-8 Sulfuric acid 0.1 -1 7664-93-9 Section 4. First aid measures Description of necessary first aid measures Eye contact Get medical attention immediately. Call a poison center or physician. Immediately flush the eye(s) continuously with lukewarm, gently flowing water for at least 20-60 minutes while holding the eyelid(s) open. Check for and remove any contact lenses. Chemical burns must be treated promptly by a physician. Inhalation Get medical attention immediately. Call a poison center or physician. Remove victim to fresh air and keep at rest in a position comfortable for breathing. If it is suspected that fumes are still present, the rescuer should wear an appropriate mask or self-contained breathing apparatus. If not breathing, if breathing is irregular or if respiratory arrest occurs, provide artificial respiration or oxygen by trained personnel. It may be dangerous to the person providing aid to give mouth-to-mouth resuscitation. If unconscious, place in recovery position and get medical attention immediately. Maintain an open airway. Loosen tight clothing such as a collar, tie, belt or waistband. 11/6/2014. PA072 2/11 PA072 ASPHALTENE DISPERSANT Section 4. First aid measures Skin contact Get medical attention immediately. Call a poison center or physician. Wash affected area with soap and mild detergent for at least 20 - 60 minutes. Wash contaminated skin with soap and water. Remove contaminated clothing and shoes. Wash contaminated clothing thoroughly with water before removing it, or wear gloves. Chemical burns must be treated promptly by a physician. Wash clothing before reuse. Clean shoes thoroughly before reuse. Ingestion Get medical attention immediately. Call a poison center or physician. Wash out mouth with water. Remove dentures if any. Remove victim to fresh air and keep at rest in a position comfortable for breathing. If material has been swallowed and the exposed person is conscious, give small quantities of water to drink. Stop if the exposed person feels sick as vomiting may be dangerous. Do not induce vomiting unless directed to do so by medical personnel. If vomiting occurs, the head should be kept low so that vomit does not enter the lungs. Chemical burns must be treated promptly by a physician. Never give anything by mouth to an unconscious person. If unconscious, place in recovery position and get medical attention immediately. Maintain an open airway. Loosen tight clothing such as a collar, tie, belt or waistband. Most important symptoms/effects, acute and delayed Potential acute health effects Eye contact Causes serious eye damage. Inhalation Can cause central nervous system (CNS) depression. May cause drowsiness and dizziness. May cause respiratory irritation. Skin contact Causes severe burns. Ingestion Can cause central nervous system (CNS) depression. May cause burns to mouth, throat and stomach. Over-exaosure signs/symptoms Eye contact pain,watering,redness Inhalation respiratory tract irritation, coughing, nausea or vomiting,headache,drowsiness/fatigue, dizziness/vertigo, unconsciousness Skin contact pain or irritation, redness, bl isteri ng may occur Ingestion stomach pains Indication of immediate medical attention and special treatment needed, if necessary Notes to physician Treat symptomatically. Contact poison treatment specialist immediately if large quantities have been ingested or inhaled. Specific treatments No specific treatment. Protection of first -aiders No action shall be taken involving any personal risk or without suitable training. If it is suspected that fumes are still present, the rescuer should wear an appropriate mask or self-contained breathing apparatus. It may be dangerous to the person providing aid to give mouth-to-mouth resuscitation. Wash contaminated clothing thoroughly with water before removing it, or wear gloves. See toxicological information (Section 11) Section 5. Fire -fighting measures Extinauishina media Suitable extinguishing media Unsuitable extinguishing media Use dry chemical, COz water spray (fog) or foam. : Do not use water jet. 11/6/2014. PA072 3111 PA072 ASPHALTENE DISPERSANT Section 5. Fire -fighting measures Specific hazards arising Flammable liquid and vapor. In a fire or if heated, a pressure increase will occur and from the chemical the container may burst, with the risk of a subsequent explosion. The vapor/gas is heavier than air and will spread along the ground. Vapors may accumulate in low or confined areas or travel a considerable distance to a source of ignition and flash back. Runoff to sewer may create fire or explosion hazard. This material is toxic to aquatic life with long lasting effects. Fire water contaminated with this material must be contained and prevented from being discharged to any waterway, sewer or drain. Hazardous thermal : carbon dioxide,carbon monoxide,sulfur oxides decomposition products Special protective actions Promptly isolate the scene by removing all persons from the vicinity of the incident if for fire-fighters there is a fire. No action shall be taken involving any personal risk or without suitable training. Move containers from fire area if this can be done without risk. Use water spray to keep fire -exposed containers cool. Special protective Fire-fighters should wear appropriate protective equipment and self-contained breathing equipment for fire-fighters apparatus (SCBA) with a full face -piece operated in positive pressure mode. Section 6. Accidental release measures Personal precautions, protective equipment and emergency procedures For non -emergency No action shall be taken involving any personal risk or without suitable training. personnel Evacuate surrounding areas. Keep unnecessary and unprotected personnel from entering. Do not touch or walk through spilled material. Shut off all ignition sources. No flares, smoking or flames in hazard area. Do not breathe vapor or mist. Provide adequate ventilation. Wear appropriate respirator when ventilation is inadequate. Put on appropriate personal protective equipment. For emergency responders If specialised clothing is required to deal with the spillage, take note of any information in Section 8 on suitable and unsuitable materials. See also the information in "For non- emergency personnel'. Environmental precautions Avoid dispersal of spilled material and runoff and contact with soil, waterways, drains and sewers. Inform the relevant authorities if the product has caused environmental pollution (sewers, waterways, soil or air). Water polluting material. May be harmful to the environment if released in large quantities. Collect spillage. Methods and materials for containment and cleanina u Small spill Stop leak if without risk. Move containers from spill area. Use spark -proof tools and explosion -proof equipment. Dilute with water and mop up if water-soluble. Alternatively, or if water -insoluble, absorb with an inert dry material and place in an appropriate waste disposal container. Dispose of via a licensed waste disposal contractor. Large spill Stop leak if without risk. Move containers from spill area. Use spark -proof tools and explosion -proof equipment. Approach release from upwind. Dike spill area and do not allow product to reach sewage system or surface or ground water. Notify any reportable spill to authorities. (See section 12 for environmental risks and 13 for disposal information.) Wash spillages into an effluent treatment plant or proceed as follows. Contain and collect spillage with non-combustible, absorbent material e.g. sand, earth, vermiculite or diatomaceous earth and place in container for disposal according to local regulations (see Section 13). The spilled material may be neutralized with sodium carbonate, sodium bicarbonate or sodium hydroxide. Dispose of via a licensed waste disposal contractor. Contaminated absorbent material may pose the same hazard as the spilled product. Note: see Section 1 for emergency contact information and Section 13 for waste disposal. If RQ (Reportable Quantity) is exceeded, report to National Spill Response Office at 1-800-424-8802. 11/6/2014. PA072 4111 PA072 ASPHALTENE DISPERSANT Section 7. Handling and storage Precautions for safe handling Ingredients: Protective measures Put on appropriate personal protective equipment (see Section 8). Avoid exposure - lother ppm obtain special instructions before use. Do not handle until all safety precautions have Other ppm been read and understood. Do not get in eyes or on skin or clothing. Do not breathe Other Notations vapor or mist. Do not ingest. Avoid release to the environment. Use only with US ACGIH 25 adequate ventilation. Wear appropriate respirator when ventilation is inadequate. Do not enter storage areas and confined spaces unless adequately ventilated. Keep in the original container or an approved alternative made from a compatible material, kept tightly closed when not in use. Store and use away from heat, sparks, open flame or OSHA PEL 1989 25 any other ignition source. Use explosion -proof electrical (ventilating, lighting and material handling) equipment. Use only non -sparking tools. Take precautionary measures against electrostatic discharges. Keep away from alkalis. Empty containers retain product residue and can be hazardous. Do not reuse container. Advice on general Eating, drinking and smoking should be prohibited in areas where this material is occupational hygiene handled, stored and processed. Workers should wash hands and face before eating, drinking and smoking. Remove contaminated clothing and protective equipment before entering eating areas. See also Section 8 for additional information on hygiene OSHA PEL 1989 25 measures. Conditions for safe storage, : Store in accordance with local regulations. Store in a segregated and approved area. including any Store in original container protected from direct sunlight in a dry, cool and well -ventilated incompatibilities area, away from incompatible materials (see Section 10) and food and drink. Store locked up. Eliminate all ignition sources. Separate from alkalis. Separate from oxidizing materials. Keep container tightly closed and sealed until ready for use. Containers that have been opened must be carefully resealed and kept upright to prevent leakage. Do not store in unlabeled containers. Use appropriate containment to avoid environmental contamination. Section 8. Exposure controls/personal protection Control parameters Occupational exposure limits TWA (s hours) STEL (15 mins) ceiling Ingredients: List name ppm mg/m' lother ppm g/m' Other ppm mg/m' Other Notations 1,2,4-Trimethylbenzene US ACGIH 25 123 - OSHA PEL 1989 25 125 1,3,5-Trimethylbenzene US ACGIH 25 123 OSHA PEL 1989 25 125 1,2,3-Trimethylbenzene US ACGIH 25 123 OSHA PEL 1989 25 125 - Xylene US ACGIH 100 434 150 651 OSHA PEL 100 435 - - OSHA PEL 1989 100 435 150 655 Cumene US ACGIH 50 - - - OSHA PEL 50 245 [1] OSHA PEL 1989 50 245 Sulfuric acid US ACGIH - 0.2 - (a] OSHA PEL - 1 OSHA PEL 1989 - 1 [1]Absorbed through skin. Form: [a]Thoracic fraction Consult local authorities for acceptable exposure limits. Only components of this product with established exposure limits appear in the box above. If OSHA permissible exposure levels are shown above they are the OSHA 1989 levels or are from subsequent OSHA regulatory actions. Although the 1989 levels have been vacated the 11th Circuit Court of Appeals, Baker Hughes recommends that these lower exposure levels be observed as reasonable worker protection. 11/6/2014. PA072 5111 PA072 ASPHALTENE DISPERSANT Section 8. Exposure controls/personal protection Appropriate engineering Use only with adequate ventilation. Use process enclosures, local exhaust ventilation or controls other engineering controls to keep worker exposure to airborne contaminants below any recommended or statutory limits. The engineering controls also need to keep gas, vapor or dust concentrations below any lower explosive limits. Use explosion -proof ventilation equipment. Individual protection measures Hygiene measures Eye/face protection Hand protection Skin protection Respiratory protection Wash hands, forearms and face thoroughly after handling chemical products, before eating, smoking and using the lavatory and at the end of the working period. Appropriate techniques should be used to remove potentially contaminated clothing. Wash contaminated clothing before reusing. Ensure that eyewash stations and safety showers are close to the workstation location. Wear chemical safety goggles. When transferring material wear face -shield in addition to chemical safety goggles. If inhalation hazards exist, a full -face respirator may be required instead. Chemical -resistant gloves. Wear long sleeves and chemical resistant apron to prevent repeated or prolonged skin contact. If a risk assessment indicates it is necessary, use a properly fitted, air purifying or supplied air respirator complying with an approved standard. Respirator selection must be based on known or anticipated exposure levels, the hazards of the product and the safe working limits of the selected respirator. Section 9. Physical and chemical properties Appearance Physical state Color Odor Odor threshold pH Liquid. Amber. Aromatic hydrocarbon. Not available. 1.7 10% product- 75% IPA/25% water solvent. Melting/freezing point Not available. Boiling point 101°C (213.8°F) Initial Boiling Point Not available. Flash point Closed cup: 53°C (127.4°F) [SFCC] Burning time Burning rate Evaporation rate Flammability (solid, gas) Lower and upper explosive (flammable) limits Vapor pressure Vapor density Relative density Density Solubility in water Partition coefficient: n- octanol/water Auto -ignition temperature Not applicable. Not applicable. Not available. Flammable in the presence of the following materials or conditions: open flames, sparks and static discharge and heat. Not available. 8.3 kPa (62 mm Hg (1.2 psig)) @ 54.44°C 130 F (Reid) >1 [Air= 1] 0.916 (15.6°C) 7.63 (lbs/gal) Insoluble Not available. Not available. 11/6/2014. PA072 6111 PA072 ASPHALTENE DISPERSANT Section 9. Physical and chemical properties Decomposition temperature Not available. Viscosity Dynamic (WC): 6.7 cP VOC Pour Point Not available. -40°C (-40°F) Section 10. Stability and reactivity Reactivity : No specific test data related to reactivity available for this product or its ingredients. Chemical stability : The product is stable. Possibility of hazardous Under normal conditions of storage and use, hazardous reactions will not occur. reactions Conditions to avoid Avoid all possible sources of ignition (spark or flame). Do not pressurize, cut, weld, braze, solder, drill, grind or expose containers to heat or sources of ignition. Do not allow vapor to accumulate in low or confined areas. Incompatible materials Reactive or incompatible with the following materials: oxidizing materials, acids and alkalis. Hazardous decomposition Under normal conditions of storage and use, hazardous decomposition products should products not be produced. Section 11. Toxicological information Information on toxicological effects Acute toxicity Product/ingredient name Result Species Dose Exposure Light aromatic naphtha LD50 Oral Rat 2900 mg/kg - 1,2,4 -Tri methyl benzene LC50 Inhalation Vapor Rat 18000 mg/m3 4 hours LD50 Oral Rat 5 g/kg - Alkyl benzenesulfonic acid LD50 Dermal Rabbit 2000 mg/kg - LD50 Oral Rat 775 mg/kg - 1,3,5 -Trim ethyl benzene LC50 Inhalation Vapor Rat 24000 mg/m3 4 hours LD50 Oral Rat 5000 mg/kg - Xylene LC50 Inhalation Gas. Rat 5000 ppm 4 hours LD50 Dermal Rabbit >1700 mg/kg - LD50 Oral Male rat 3523 mg/kg - LD50 Oral Rat 4300 mg/kg - Cumene LC50 Inhalation Vapor Mouse 10000 mg/m3 7 hours LC50 Inhalation Vapor Rat 39000 mg/m3 4 hours LD50 Dermal Rabbit 10600 mg/kg - LD50 Oral Rat 2.9 g/kg - Sulfuric acid LD50 Oral I Rat 2140 mg/kg - Irritation/Corrosion No applicable toxicity data Sensitization No applicable toxicity data Mutagenicity No applicable toxicity data 11/612014. PA072 7/11 PA072 ASPHALTENE DISPERSANT Section 11. Toxicological information Carcinogenicity Product/ingredient name OSHA IARC NTP Xylene - 3 - Cumene - 2B Reasonably anticipated to be a human carcinogen. Sulfuric acid - 1 Known to be a human carcinogen. Reproductive toxicity No applicable toxicity data Teratogenicity No applicable toxicity data Specific target organ toxicity (single exposure) Name Category Route of exposure Target organs Light aromatic naphtha Category 3 Not applicable. Narcotic effects 1,2,4-Trimethylbenzene Category 3 Not applicable. Respiratory tract irritation 1,3,5 -Trim ethyl benzene Category 3 Not applicable. Respiratory tract irritation 1,2,3-Trimethylbenzene Category 3 Not applicable. Respiratory tract irritation Xylene Category 3 Not applicable. Narcotic effects Cumene Category 3 Not applicable. Respiratory tract irritation Sulfuric acid Category 3 Not applicable. Respiratory tract irritation Specific target organ toxicity_(regeated exposure) Not applicable. Aspiration hazard Name Result Light aromatic naphtha ASPIRATION HAZARD - Category 1 1,2,3 -Tri methyl benzene ASPIRATION HAZARD - Category 1 Xylene ASPIRATION HAZARD - Category 1 Cumene ASPIRATION HAZARD - Category 1 Information on the likely Routes of entry anticipated: Dermal, Inhalation. routes of exposure Delayed and immediate effects and also chronic effects from short and long term exposure Short term exposure Potential immediate Not available. effects Potential delayed effects : Not available. Potential chronic health effects General No known significant effects or critical hazards. Carcinogenicity May cause cancer. Risk of cancer depends on duration and level of exposure. Mutagenicity No known significant effects or critical hazards. Teratogenicity No known significant effects or critical hazards. Developmental effects No known significant effects or critical hazards. Fertility effects No known significant effects or critical hazards. 1116/2014. PA072 8111 PA072 ASPHALTENE DISPERSANT Section 11. Toxicological information Numerical measures of toxicity Acute toxicity estimates Route ATE value Oral 2008.9 mg/kg Dermal 7476.6 mg/kg Inhalation (gases) 263852.2 ppm Inhalation (vapors) 74.21 mg/I Section 12. Ecological information Toxicity Product/ingredient name Result Species Exposure 1,2,4 -Trim ethyl benzene Acute LC50 4910 pg/I Marine water Crustaceans - Elasmopus 48 hours pectenicrus Acute LC50 22.4 mg/I Fresh water Fish - Tilapia zillii 96 hours Alkyl benzenesulfonic acid Acute EC50 5.65 mg/I Fresh water Crustaceans - Ceriodaphnia 48 hours dubia 1,3,5 -Trim ethyl benzene Acute LC50 12520 to 15050 pg/I Fresh Fish - Carassius auratus 96 hours water Chronic NOEC 400 pg/I Fresh water Daphnia - Daphnia magna 21 days Xylene Acute LC50 8500 pg/I Marine water Crustaceans - Palaemonetes 48 hours pugio Acute LC50 13400 pg/I Fresh water Fish - Pimephales promelas 96 hours Cumene Acute EC50 2600 pg/l Fresh water Algae - Pseudokirchneriella 72 hours subcapitata Acute LC50 7400 to 11290 pg/I Fresh Crustaceans - Artemia sp. 48 hours water Acute LC50 30500 pg/l Fresh water Daphnia - Daphnia magna 48 hours Acute LC50 2700 pg/I Fresh water Fish - Oncorhynchus mykiss 96 hours Sulfuric acid Acute LC50 42500 pg/I Marine water Crustaceans - Pandalus montagui 48 hours Acute LC50 42 ppm Fresh water Fish - Gambusia affinis 96 hours Persistence and degradability Not available. Other adverse effects : No known significant effects or critical hazards. Section 13. Disposal considerations Disposal methods The generation of waste should be avoided or minimized wherever possible. Disposal of this product, solutions and any by-products should at all times comply with the requirements of environmental protection and waste disposal legislation and any regional local authority requirements. Dispose of surplus and non -recyclable products via a licensed waste disposal contractor. Waste should not be disposed of untreated to the sewer unless fully compliant with the requirements of all authorities with jurisdiction. Waste packaging should be recycled. Incineration or landfill should only be considered when recycling is not feasible. This material and its container must be disposed of in a safe way. Care should be taken when handling emptied containers that have not been cleaned or rinsed out. Empty containers or liners may retain some product residues. Vapor from product residues may create a highly flammable or explosive atmosphere inside the container. Do not cut, weld or grind used containers unless they have been 11/6/2014. PA072 9111 PA072 ASPHALTENE DISPERSANT Section 13. Disposal considerations cleaned thoroughly internally. Avoid dispersal of spilled material and runoff and contact with soil, waterways, drains and sewers. Section 14. Transport information DOT Classification TDG Classification IMDG IATA UN number UN2924 UN2924 UN2924 UN2924 UN proper FLAMMABLE LIQUID, FLAMMABLE LIQUID, FLAMMABLE LIQUID, FLAMMABLE LIQUID, shipping name CORROSIVE, N.O.S. CORROSIVE, N.O.S. CORROSIVE, N.O.S. CORROSIVE, N.O.S. (Contains: Light (Contains: Light (Contains: Light (Contains: Light aromatic naphtha, Alkyl aromatic naphtha, Alkyl aromatic naphtha, Alkyl aromatic naphtha, Alkyl benzenesulfonic acid) benzenesulfonic acid) benzenesulfonic acid) benzenesulfonic acid) Transport 3 (8) 3 (8) 3 (8) 3 (8) hazard class(es) oa �� ZZ � V Packing group III III III III Environmental Yes. Yes. Yes. No. hazards Additional Remarks Remarks Emergency schedules - EmS information DOT Marine Pollutant if TDG Marine Pollutant if shipped in bulk or by transported on a ship in F -E S -C vessel. Canadian waters. Special precautions for user : Transport within user's premises: always transport in closed containers that are upright and secure. Ensure that persons transporting the product know what to do in the event of an accident or spillage. Transport in bulk according : Not available. to Annex II of MARPOL 73/78 and the IBC Code DOT Reportable Xylene, 692 gal of this product Quantity Marine pollutant Light aromatic naphtha 1,2,4 -Trim ethyl benzene North -America NAERG : 132 Section 15. Regulatory information U.S. Federal regulations TSCA 12(b) one-time export: No products were found. TSCA 12(b) annual export notification: No products were found. United States inventory (TSCA 8b): All components are listed or exempted. Clean Water Act (CWA) 307: Naphthalene Clean Water Act (CWA) 311: Xylene; Naphthalene; Sulfuric acid 11/6/2014. PA072 10/11 PA072 ASPHALTENE DISPERSANT Section 15. Regulatory information Clean Air Act Section 112 Listed (b) Hazardous Air Pollutants (HAPs) SARA 302/304 Name % EHS SARA 302 TPQ SARA 304 RQ (Ibs) (gallons) (Ibs) (gallons) Sulfuric acid Sulfur dioxide 0.1 -1 < 0.05 Yes. Yes. 1000 500 66.3 - 1000 500 66.3 - SARA 311/312 Classification SARA 313 Fire hazard Immediate (acute) health hazard Delayed (chronic) health hazard Product name CAS number % Supplier notification 1,2,4 -Trim ethyl benzene 95-63-6 20-30 Xylene 1330-20-7 1 - 5 Canada Canada (CEPA DSL): All components are listed or exempted. Section 16. Other information National Fire Protection Association (U.S.A.) Flammability Health 0 Instability/Reactivity Special History Date of printing 11/6/2014. 7 Indicates information that has changed from previously issued version. Notice to reader NOTE: The information on this MSDS is based on data which is considered to be accurate. Baker Hughes, however, makes no guarantees or warranty, either expressed or implied of the accuracy or completeness of this information. The conditions or methods of handling, storage, use and disposal of the product are beyond our control and may be beyond our knowledge. For this and other reasons, we do not assume responsibility and expressly disclaim liability for loss, damage or expense arising out of or in any way connected with the handling, storage, use or disposal of this product. This MSDS was prepared and is to be used for this product. If the product is used as a component in another product, this MSDS information may not be applicable. 11/6/2014. PA072 11/11 v5" % 11/1 b DATE 06 21 60 10 Seth Nolan Hilcorp Alaska, LLC 27 1 9 p GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8308 Fax: 907 777-8510 E-mail: snolan@hilcorp.com DATA LOGGED b /'L-1/201(0 iN K.BENDER To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 Cased hole log prints and digital data Prints: Gamma Ray RMTI 5" MD CD1: digital data LAS FILES LOGS RECEIVED mAY 2 0 2016 AGG�%G Gamma Ray RCBL 5" MD 5i"4)'2016 9:16 AM File folder 5M,,'2016 9:16 AM File folder Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By:,, _ I , _ ,� - I Date: Ifilf"all :kht- u. LH DATE 04/29/16 2A(o-0�U Seth Nolan Hilcorp Alaska, LLC f`(,I�sU ce,� GeoTech 3800 Centerpoint Drive, Suite 100 ,- Anchorage, AK 99503 d �� Tele: 907 777-8308 Fax: 907 777-8510 E-mail: snolan@hilcorp.com To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 Reviesed Elog digital data CD1: Elog digital data CGM Definitive Survey DLIS+LAS EMF PDF TIFF 4,,25j2131617:17 PM File folder 4/25,12016 12:17 PM Filefolder 4/25/2016 12:17 PM File folder 4/'25,''201612:17 PM Filefrlder 4/25/2016 12:17 PM File folder 4/25/201612:17 PHA File folder Please include current contact information if different from above. APR 2 9 2016 0GVC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Date: 5 1 J Guhl, Meredith D (DOA) From: Seth Nolan <snolan@hilcorp.com> Sent: Friday, April 22, 2016 2:13 PM To: Bender, Makana K (DOA); Guhl, Meredith D (DOA) Subject: SCU 31B-04 Logs Good Afternoon Meredith and Makana, Just to give you a heads up. The API numbers we just realized that Halliburton miss -labeled all of the logs with the API number 50-133-10099-01-00 instead of 50-133-10099-02-00. So we are having them resubmit the logs to us with the proper API numbers. I apologize for the incorrect information on the logs. Thanks, Seth Nolan GeoTech Hilcorp Alaska LLC 3800 Centerpoint Dr. Anchorage, AK 99524 Office: 907.777.8308 snolan0hilcorp.com Ildrnrp ,Ua.ka. LIA DATE 04/05/16 Seth Nolan GeoTech L APR 08 201E 21 60 10 Hilcorp Alaska, LLC 27 ®� C 3800 Centerpoint Drive, Suite 100 V Anchorage, AK 99503 27 02 7 Tele: 907 777-8308 Fax: 907 777-8510 E-mail: snolan@hilcorp.com To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 Elog and Mudlog prints and digital data DATA LOGGED 4 1 13'2016 J K BENDER Prints: 2"/5" ROP-DGR-EWR-ALD-CTN MD 2" DRILLING DYNAMICS MD/TVD 2"/5" DGR-EWR-ALD-CTN TVD 2" GAS RATIO MD/TVD 2" FORMATION LOG MD/TVD 2" LWD COMBO MD/TVD 5" FORMATION LOG MD/TVD FINAL WELL REPORT CD1: Elog digital data CGM 3/3;20169:33 AM Filefclder Definitive Survey 3x'3/2016 9:33 AM File folder DLIS+LAS 3r°3:20169,33 AMa1 File folder EMF 3;'3:20169:33 AM File folder PDF 13y'2016 9:33 AM Filefolder TIFF 3;3/20169:33 AM Filefclder CD2: Mudlog digital data Daily Reports 4x`1;2016 9,26 AM Filefclder- DML Data 4/1/2016 9:26 AM File folder Final Well Report 4/1/2016 9:26 AMI File folder LAS Data V1i20169:26 AM Filefclder Log PDFs 441'112016 9:26.AM;1 File folder Log TIFFS 4/1x2016 9:26 AM Filefclder Show Reports 4t11'2016 9:26 AM File folder Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received .B*.'_ n 1� , i� - I Date: 6;)l(0 -C710 Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 15-4-9 Anchorage, AK 99503 Tele: 907 777-8308 Ililrurp Alsorka. LIA. Fax: 907 777-8510 E-mail: snolan@hilcorp.com I EC; DATE 03/29/2016 MAR 3 0 2016 To: Alaska Oil & Gas Conservation Commission Meredith Guhl Petroleum Geology Assistant 333 W 7th Ave Ste 100 Anchorage, AK 99501 4 boxes: Dry Cuttings Transmitted herewith are cuttings from SCU 31B-04 WELL SAMPLE INTERVAL SCU 31 B-04 6514-7500 SCU 31 B-04 7500 -8670 SCU 31B-04 8670 -9750 SCU 31 B-04 9750 -10695 SCU 31 B-04 10695- 11325 SCU 31 B-04 11325- 11755 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 Date: '4111 PI'I THE STATE GOVERNOR BILL WALKER Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 31B-04 Permit to Drill Number: 216-010 Sundry Number: 316-168 Dear Mr. Helgeson: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov 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 4- day of March, 2016. RBDMS LL MA.R 0 4 2016 -156 STATE OF ALASKA 151 1J\ ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVED MAR 0 2 2016 n,r*�- 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate Q • Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Initial Perfs Q- 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q • Stratigraphic ❑ Service ❑ 216-010 . 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, Alaska 99503 50-133-10099-02 . 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 123B. Rule 5 Will planned perforations require a spacing exception? Yes ❑ No Soldotna Creek Unit (SCU) 316-04 9. Property Designation (Lease Number): 10. Field/Pool(s): A028997 Swanson River Field / Hemlock Oil Pod 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): -11,870' -10,712' -11,597' -10,632' -1,400 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 18' 22" 28' 28' Surface 3,000' 13-3/8" 3,000' 3,000' 3,730psi 1,130psi Intermediate -6,500' 7" -6,500' -6,500' 8,160psi 7,020psi Production Liner -5,570 4-1/2" -11,597' -10,632' 17,693psi 16,769psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: -7N/A Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic N/A N/A Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A NIA 12. Attachments: Proposal Summary ❑✓ Wellbore schematic Q 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: March 6, 2016 OIL E . WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Joe Kaiser - 777-8393 Emailkaiser hilcor .com Printed Name Chad Helgeson Title Operations Manager Signature Phone 907-777-8405 Date 17 L 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 ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes No Subsequent Form Required: (C`' 110 77— f �J •�) ❑ ® ��L RBDMS 6R 0 4 2016 APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 3 - L�& Submit Form and Form 10-403 Revised 11/2015 O 1pirIvUllp NiC i months from the date of approval. Attachments in Duplicate 4w— 1 <>, 3 -'; // Hilcorp Alaska, LL Well Prognosis Well: SCU 316-04 Date: 3/2/2016 Well Name: SCU 316-04 API Number: 50-133-10099-02-00 Current Status: Drilling in Progress Leg: N/A Estimated Start Date: March 6th, 2016 Rig: E -line Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Hemlock Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 216-010 First Call Engineer: Joe Kaiser (907) 777-8393 (0) (907) 952-8897 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (M) AFE Number: 1610111C Maximum Expected BHP: Max. Potential Surface Pressure: pert.) Brief Well Summary 1,200 psi @ 10,300' TVD (Based on offset well PTA 1/6/2016) 1,400 psi (Gas lift pressure to unload fluid prior to SCU 3113-04 will be a gas lifted oil well currently being drilled from SCU 12A-03 to target oil production that will be swept from gas injection (SCU 322C-04) into this fault block. RWO Objective: The purpose of this sundry is to perforate the Hemlock formation in the H1, H2, and H3L Sands. Notes Regarding Wellbore Condition • Pressure test on casing and tubing will have been completed. • Operations will use gas lift on pad to evacuate fluid in tubing, leaving approximately 500-700 psig on well or 1,200 psi on the formation. Slickline Procedure: 1. MIRU E -line, PT lubricator to 2,500 psi Hi and 250 psi Low. 2. RU HC wireline guns. 3. RIH and perforate the following intervals and test the zones individually: Zone Sands Top (MD) Btm (MD) FT Hemlock H1 ±11,117' ±11,161' 1 44 Hemlock H2 ±11,184' ±11,223' 39 Hemlock H3L ±11,250' ±11,345' 95 a. Proposed perfs shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Correlation Log. d. Use Gamma/CCL/ to correlate. e. Install Crystal gauges on well before perforating. Record tubing pressures before and after each perforating run. f. All perforations in table above are located in the Hemlock Pool based on Conservation Order No. 1238 Rule 5. 4. RD E -line. Well Prognosis Well: SCU 316-04 Hileorp Alaska, LL Date: 3/2/2016 5. Turn well over to production. E -line Procedure (Contingency): 6. If any zone produces sand and/or water. 7. MIRU E -line, PT lubricator to 2,500 psi Hi 250 Low. 8. RIH and set TT Plug for 4-1/2" liner at depth above zone. 9. RU Bailer assembly. RIH w/ assembly. Dump bail sufficient cement to cover plug adequetely 5'). In cases where depth between sands are limited (<10'), only a plug will be set at Engineer's discretion. 10. Continue with Step 5 above. Attachments: 1. Proposed Schematic Soldotna Creek Unit Well SCU 31B-04 F,xOPOSED SCHEMATIC PTD: 216-010 API: 50-133-10099-02-00 IlilK LC TD = "'11,753' TVD ="'10,595' MAX HOLE ANGLE = "'55 deg. At "'9,319' TMD CASING AND TUBING DETAII Size WT Grade Conn ID Top Btm 22" - - Tubing Hanger, 2-7/8" 8RD Surface 28' 13-3/8" 54.5 2-7/8" SFO -1 GLM #7 (Live Valve) 10.050" Surface 3,000' 7" 29 P-110 6.184" Surface 6,500' 4-1/2" 12.6 L-80 3.918" 6,300' 11,753' 2-7/8" 6.5 L-80 8RD EUE 2.441" Surface 6,150' 2-3/8" 4.7 L-80 8RD EUE 1.995" 6,150' 11,360' JEWELRY DETAII No Depth ID OD Item 1 —18' 2.992" - Tubing Hanger, 2-7/8" 8RD 2 2,550' 2.441" 4.750" 2-7/8" SFO -1 GLM #7 (Live Valve) 3 4,600' 2.441" 4.750" 2-7/8" SFO -1 GLM #6 (Live Valve) 4 6,150' 2.441" 4.750" 2-7/8" SFO -1 GLM #5 (Live Valve) 5 6,175' 1.995" 3.063" XO, 2-7/8" 8RD x 2-3/8" 8RD 6 7,341' 1.990" 3.750" 2-3/8" GLMAX-1 GLM #4 (T-1 latch) (Live Valve) 7 8,252' 1.990" 3.750" 2-3/8" GLMAX-1 GLM #3 (T-1 latch) (Live Valve) 8 8,935' 1.990" 3.750" 2-3/8" GLMAX-1 GLM #2 (T-1 latch) (Live Valve) 9 9,557' 1.990" 3.750" 2-3/8" GLMAX-1 GLM #1 (T-1 latch) (Live Valve) 10 10,178' 1.990" 3.750" 2-3/8" GLMAX-1 GLM #2 (T-1 latch) (Live Valve) 11 10,839' 1.990" 3.750" 2-3/8" GLMAX-1 GLM #1(T-1 latch) (Live Valve) 12 10,941' 1.940" 3.750" 4-1/2" x 2-3/8" Hydraulic Packer 13 10,951' 1.875" 3.063" X -Nipple 14 10,961 1.995" 3.063" WL Entry Guide rA 6,303' 7" X 4-1/2" ZXP liner hanger PERFORATIONS )(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size SPF Status Date L, 117' ±11,161' ±10,302' ± 10,333' 44' 1-9/16" 4 TBD Proposed L, 184' ±11,223' ±10,349' ±10,376' 39' 1-9/16" 4 TBD Proposed L,250' ±11,345' ± 10,394' ± 10,460' 95' 1-9/16" 4 TBD Proposed Updated by DMA 03/02/16 THE STATE of .r,LASKA, GOVERNOR BILL WALKER Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 31B-04 Permit to Drill Number: 216-010 Sundry Number: 316-158 Dear Mr. Helgeson: Alaska OiJ and Gas Conservation 7,.,w 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov 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, aP�L� Cathy . Foerster Chair DATED this 2 day of March, 2016. RBDMS D- MAR n 4 2016 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEB 25 21016 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other. Initial Completion ❑± 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q . Stratigraphic ❑ Service ❑ 216-010. 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, Alaska 99503 50-133-10099-02 7. If perforating: 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 123B. Rule 5 Will planned perforations require a spacing exception? Yes ❑ No Soldotna Creek Unit (SCU) 31 B-04 9. Property Designation (Lease Number): 10. Field/Pool(s): A028997 Swanson River Field / Hemlock Oil Pod - 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): -11,870' -10,712' -11,820' -10,670' -170 WA N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 18' 22" 28' 28' Surface 3,000' 13-3/8" 3,000' 3,000' 3,730psi 1,130psi Intermediate -6,500' 7" -6,500' -6,500' 8,160psi 7,020psi Production Liner -5,570 4-1/2" -11,870' -10,712' 17,693psi 16,769psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic N/A N/A WA Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A N/A 12. Attachments: Proposal Summary ❑✓ Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Exploratory ❑ Stratigraphic ❑ Development 0 ' Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: March 4, 2016 OILWINJ ❑ ' ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Joe Kaiser - 777-8393 Email kaiser hilcor .com Printed Name Chad Helgeson Title Operations Manager Signature Phone 907-777-8405 Date c' ZS COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. t Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: 3 y p R13DMS MAR 0 4 2016 Post Initial Injection MIT Req'd? Yes ❑ No ❑ _ �1 -LC Spacing Exception Required? Yes (JI� F]No � Subsequent Form Required: 1 t;S 7 -rr-v� IC -1 - APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: -Z- ` h _ / e o �' Submit Form and Form 10-403 Revised 11/20153I1Rif3P1_,N,A lid for 12 month from the date of approval. Atta hm is in Duplicate � �S� - �q, /� I ilcorp Alaska, LLQ Well Prognosis Well: SCU 316-04 Date: 2/25/2016 Well Name: SCU 3113-04 API Number: 50-133-10099-02-00 Current Status: Drilling in Progress Leg: N/A Estimated Start Date: March 4th, 2016 Rig: Saxon 169 Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 216-010 First Call Engineer: Joe Kaiser (907) 777-8393 (0) (907) 952-8897 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (M) AFE Number: 1610111C Maximum Expected BHP: — 1,200 psi @ 10,300' TVD (Based on offset well PTA 1/6/2016) Max. Potential Surface Pressure: — 170 psi (Based on 0.1 psi/ft gradient to surface) Brief Well Summary SCU 31B-04 will be a gas lifted oil well currently being drilled from SCU 12A-03 to target oil production that will be swept from gas injection (SCU 322C-04) into this fault block. RWO Objective: Run gas lift completion in preparation for perforating the Hemlock formation Notes Regarding Wellbore Condition • Saxon 169 rigged up on well and currently drilling. • Pressure test 4-1/2" x 7" casing to 3,500 psig will be completed after setting the liner. • Continue BOP testing frequency from Drilling Program (PTD 216-010) through completion. • Well full of 6% KCL fluid. Rig Work Procedure: 1. "Continue from SCU 3113-04 (PTD 216-010) Drilling Program Step 19.1 2. MIRU E -line on drilling rig. 3. RIH and run Cement Bond Log from PBTD to —6,200' MD (top of 4.5" liner). POOH. LD CBL tool. a. Send logs to town for correlation log. b. Final perf depths will be based on CBL results. 4. RD E -line. 5. Install necessary BOP equipment for running the completion and test (if not previously installed). a. Double ram should be dressed with 2-3/8" x 5" VBR in top cavity, blind ram in btm cavity. b. Single ram should be dressed with 2-3/8" x 5" VBR. c. Test any new BOP components (VBRs) to 250/3500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min w/ 2-3/8" test joint and 4-1/2" as necessary. Ensure to leave "A" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Confirm the correct valves are opened. 6. LD BOP test equipment. 7. PU 4-1/2" hydraulic packer and completion jewelry and RIH w/ completion on 2-7/8" 8rd EUE tubing and 2-3/8" 8rd EUE tubing. Minimize excess pipe dope when running completion. Circulate with field produced water prior to setting packer to clean tubing and casing. Completion jewelry per proposed schematic: Hilcorp Alaska, LLQ Well Prognosis Well: SCU 31B-04 Date: 2/25/2016 a. WL entry guide b. X -nipple (RHCP plug body loaded) c. 4-1/2" Packer d. 2-3/8" GLMs (loaded with live valves) e. 2-7/8" x 2-3/8" crossover f. 2-7/8" GLMs (loaded with live valves) g. 2-7/8" Tubing Hanger 8. Space out packer at 11,300' ensuring packer is set a minimum of 5' from a collar. a. Leave tubing tail to land —30' above top of Tyonek G -zone. 9. Land tubing in hanger. Close the lockdown pins. 10. RU Slickline. 11. RIH and set RHCP ball and rod in loaded X -nipple. Keep setting tools latched. 12. Pressure up tubing to 3,000 psi and set hydraulic packer. 13. Test tubing to 3,000 psi for 30min with chart. 14. Pull RHCP ball and rod. RD Slickline. 15. Test packer through the tubing below packer to 2,500 psi for 30min with chart. 16. Test casing to 2,500 psig (Jug Test). 17. LD landing joint. Set BPV. ND BOPE. NU Tree. Pull BPV 18. Set TWC. Test hanger to 250/2,500 psi. Test Tree to 250/5,000 psi. Pull TWC. 19. RD Saxon #169 Drill Rig. 20. Turn well over to Hilcorp Operations in preparation of moving off the Saxon #169 Drilling Rig. 21. Install IA x OA pressure gauge if removed. 22. ***Remaining completion work to be submitted under new sundry (perf thru-tubing)*** Attachments: 1. Proposed Schematic 2. BOPE Schematic 3. Proposed Wellhead Schematic 4. Blank RWO Procedure Change Form A L 4-1/2" TD = "'11,870' TVD ="'10,712' MAX HOLE ANGLE = "'55 deg. At 9,319' TMD CASING AND TUBING DETAIL Size Soldotna Creek Unit Well SCU 316-04 Grade Conn PTD: 216-010 PROPOSED SCHEMATIC API: 50-133-10099-02-00 Hite— Alaska. LLC Btm A L 4-1/2" TD = "'11,870' TVD ="'10,712' MAX HOLE ANGLE = "'55 deg. At 9,319' TMD CASING AND TUBING DETAIL Size WT Grade Conn ID Top Btm 22" - - Tubing Hanger, 2-7/8" 8RD Surface 28' 13-3/8" 54.5 2-7/8" SFO -1 GLM #7 (Live Valve) 10.050" Surface 3,000' 7" 29 P-110 6.184" Surface —6,500' 4-1/2" 12.6 L-80 3.918" —6,300' —11,870' 2-7/8" 6.5 L-80 8RD EUE 2.441" Surface 6,150' 2-3/8" 4.7 L-80 8RD EUE 1.995" 6,150' 11,360' JEWELRY DETAIL No Depth ID OD Item 1 -18' 2.992" - Tubing Hanger, 2-7/8" 8RD 2 2,000' 2.441" 4.750" 2-7/8" SFO -1 GLM #7 (Live Valve) 3 4,000' 2.441" 4.750" 2-7/8" SFO -1 GLM #6 (Live Valve) 4 6,000' 2.441" 4.750" 2-7/8" SFO -1 GLM #5 (Live Valve) 5 6,150' 1.995" 3.063" XO, 2-7/8" 8RD x 2-3/8" 8RD 6 7,500' 1.990" 3.750" 2-3/8" GLMAX-1 GLM #4 (T-1 latch) (Live Valve) 7 9,000' 1.990" 3.750" 2-3/8" GLMAX-1 GLM #3 (T-1 latch) (Live Valve) 8 10,250' 1.990" 3.750" 2-3/8" GLMAX-1 GLM #2 (T-1 latch) (Live Valve) 9 11,000' 1.990" 3.750" 2-3/8" GLMAX-1 GLM #1(T-1 latch) (Live Valve) 10 11,300' 1.940" 3.750" 4-1/2" x 2-3/8" Hydraulic Packer 11 11,330' 1.875" 3.063" X -Nipple 12 11,360' 1.995" 3.063" WL Entry Guide A 6,300' - - 7" X 4-1/2" ZXP liner hanger Updated byJEK 2/24/16 BOPE SCHEMATIC SCreek Unit SCU 331a 1B-04 2/25/2016 Saxon 169 BOP stack Swanson River SCU 31B-04 02/24/2016 Hilrvrrp ;Vw.kw, 1,1.1: Swanson River SCU 31B-04 133/8 X 7X27/8 Valve, Wing, WKI 2 1/16 5M FE, H' DD trim Valy 29/ Vah 29/ Attachment spool, FM( 7 1/16 5M X 7 1/16 ° 23" Overall length Tubing head, Shat T55 -1-I, 13 5/8 3M 71/165Mw/2-21/' SSO, 7" Type 1 Seco seal in head Casing head, Shaffe 13 5/8 3M X 13 3/8 w/ 2- 2" LPO, 7" KD and packoff assy in I Tubing hanger, Seaboard -S- EN -CCL, 7 1/16 5M X 2 7/8 EUE lift and susp, w/ 2 type H BPV, 2- 3/8 control line ports, 3 Y extended neck BHTA, Bowen, 29/165M FE X 3" Bowen top Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well SCU 31B-04 (PTD 216-010) Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first call' engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Prepared: Asset Team Operations Manager Date First Call Operations Engineer Date THE STATE of A L Ak f -I j-,sKA GOVERNOR BILL WALKER Monty Myers Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Soldotna Creek Field, Hemlock Oil Pool, SCU 31B-04 Hilcorp Alaska, LLC Permit to Drill Number: 216-010 Surface Location: 2032' FNL, 359' FWL, SEC. 3, T7N, R9W, SM, AK Bottomhole Location: 917' FNL, 2631' FEL, SEC. 4, T7N, R9W, SM, AK Dear Mr. Myers: Enclosed is the approved application for permit to re -drill the above referenced development well. This permit supersedes and replaces the permit previously issued for this well dated January 28, 2016. 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, Cathy P. oerster Chair DATED this j day of February, 2016. STATE OF ALASKA FEB 17 2016 A. A OIL AND GAS CONSERVATION COMM. )N PERMIT TO DRILL REVISED ' 20 AAC 25.005 1 a. Type of Work: 1h. Proposed Well Class- Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ 1 c. Specify if well is proposed for: Drill ❑ Lateral ❑ Stratigraphic Test ❑ Development - Oil Service - Winj ❑ Single Zone Coalbed Gas ❑ Gas Hydrates ❑ Redrill El Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket F�] • Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 - SCU 31B-04 - 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 MD: 11,870' TVD: 10,712' Soldotna Creek Unit Hemlock Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 2032' FNL, 359' FWL, Sec 3, T7N, R9W, SM, AK A028997 Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 1427' FNL, 1197' FEL, Sec 4, T7N, R9W, SM, AK N/A 2/16/2016 ✓ 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 917' FNL, 2631' FEL, Sec 4, T7N, R9W, SM, AK 2560 6722' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 162.5' 15. Distance to Nearest Well Open Surface: x-347966 • y- 2459121 - Zone -4 GL Elevation above MSL (ft): 144.5' to Same Pool: 936' SCU 31-04 16. Deviated wells: Kickoff depth: 6,500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 55 degrees Downhole: 2785 Surface: 1714 • 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) 6" 4-1/2" 12.6# L-80 DWC/C 5,570' 6,300' 6,300' 11,870'- 10,712' • 555 sx 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): 10,850' 10,845' 10,555' 10,555' 10,552' N/A Casing Length Size Cement Volume MD TVD Conductor/Structural 28' 22" Yes 28' 28' Surface 3,000' 13-3/8" 1792 sx 3,000' 3,000' Intermediate 10,265' 7" 2608 sx 10,265' 10,263' Production Liner 803' 5" 860 sx 110,848' 10,839' Perforation Depth MD (ft): See attached schematic of 12A-03 Perforation Depth TVD (ft): See attached schematic of 12A-03 20. Attachments: Property Plat ❑✓ BOP Sketch Q Drilling Program Q Time v. Depth Plot Q Shallow Hazard Analysis❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program ❑✓ 20 AAC 25.050 requirements0 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Monty Myers Email mm ers hilcor .com Printed Name Monty Myers Title Drilling Engineer Signature - Phone 777-8431 Date 2/17/2016 Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other Number: Lv'#-opo cevseck 1 50-1-33- \00'19-0:Z-00 Date: I_t.-q'alp 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: ❑► Other: Z S ODr7 ���///jjj i K ' - Samples req'd: Yes ❑ No [✓ Mud log req'd: Yes ❑ No FJ" /" L J I HZS measures: Yes ❑ No Directional svy req'd: Yes [v�No❑ � L� ��T Spacing exception req'd: Yes ❑ No [ Inclination -only svy req'd: Yes ❑ No[f Post initial injection MIT req'd: Yes ❑ No❑ APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: l - / L -) /� Rin& � � Submit Form andForm 10- 1 ( evised 11/2015) h onths from the date of approval (20 AAC 25.005(8)) Attachments in Du licate Monty Myers Drilling Engineer Hilcorp Energy Company 2/17/2016 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 Re: SCU 318-04 REVISED Permit to Drill Dear Commissioner, Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8431 Email mmyers@hilcorp.com REOPI/cr FR I I 701h SCU 3113-04 is an oil production well planned to be re -drilled in a North-westerly direction from the existing SCU 12A-03 utilizing the existing casing program down to 6500' MD / 6500' TVD. At 6500' MD the parent wellbore will be sidetracked and new wellbore drilled penetrating several Hemlock targets. A 5370' x 6" open hole section is planned. A 4-1/2" 12.6# L-80 DWC/C prod liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with 2-7/8" production string. Drilling operations are expected to commence approximately February 18t6, 2016. 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 i of i Hilcorp Alaska, LLC SCU 31B-04 (SCU 12A-03 ST) Drilling Program Soldotna Creek R ro d by: MoWfajMy Revision 1 February 17, 2016 SCU 31 B-04 Drilling Procedure Rev 1 Contents 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program............................................................................................................................4 17.0 4.0 Drill Pipe Information.....................................................................................................................4 Run Completion Assembly...........................................................................................................30 5.0 Internal Reporting Requirements..................................................................................................5 20.0 6.0 Planned Wellbore Schematic..........................................................................................................6 Wellhead Schematic......................................................................................................................32 7.0 Drilling Summary............................................................................................................................7 23.0 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 Anticipated Drilling Hazards.......................................................................................................35 9.0 R/U and Preparatory Work..........................................................................................................11 26.0 10.0 BOP N/U and Test.........................................................................................................................12 Choke Manifold Schematic...........................................................................................................38 11.0 Mud Program and Density Selection Criteria............................................................................13 29.0 12.0 Whipstock Running Procedure....................................................................................................14 Plot (NAD 27) (Governmental Sections)......................................................................................41 13.0 Whipstock Setting Procedure.......................................................................................................17 32.0 14.0 Drill 6" Hole Section......................................................................................................................19 33.0 15.0 Run 4.5" Production Casing.........................................................................................................22 16.0 Cement 4.5" Production Casing...................................................................................................25 17.0 Wellbore Clean Up & Displacement............................................................................................29 18.0 Run Completion Assembly...........................................................................................................30 19.0 RDMO............................................................................................................................................30 20.0 BOP Schematic..............................................................................................................................31 21.0 Wellhead Schematic......................................................................................................................32 22.0 Days vs Depth.................................................................................................................................33 23.0 Geo-Prog.........................................................................................................................................34 24.0 Anticipated Drilling Hazards.......................................................................................................35 25.0 Rig Layout......................................................................................................................................36 26.0 FIT Procedure................................................................................................................................37 27.0 Choke Manifold Schematic...........................................................................................................38 28.0 Casing Design Information...........................................................................................................39 29.0 6" Hole Section MASP..................................................................................................................40 30.0 Plot (NAD 27) (Governmental Sections)......................................................................................41 31.0 Surface Plat (As Built) (NAD 27).................................................................................................42 32.0 Surface Plat (As Built) (NAD 83).................................................................................................43 33.0 Directional Program(P1)..............................................................................................................44 SCU 31 B-04 Drilling Procedure Rev 1 Ilde—p ila,ka, LLC 1.0 Well Summary Well SCU 31B-04 Pad & Old Well Designation Sidetrack of existing well SCU 12A-03 (PTD# 180-104). Planned Completion Type 4-1/2" 12.6# L-80 Liner Target Reservoir(s) Hemlock Producer H1 -H8 Planned Well TD, MD / TVD 11870' MD / 10712' TVD - PBTD, MD / TVD 11700' MD / 10614' TVD Surface Location (Governmental) 2032' FNL, 359' FWL, Sec 3, T7N, R9W, SM, AK Surface Location NAD 27) X=347966.38, Y=2459121.98 Surface Location (NAD 83) X=1487989.257, Y=2458883.157 Top of Productive Horizon (Governmental) 1427' FNL, 1197' FEL, Sec 4, UN, R9W, SM, AK - TPH Location (NAD 27) X=346416.21, Y=2459750.93 TPH Location (NAD 83) X=1486439.057, Y=2459512.159 B14L (Governmental) 917' FNL, 2631' FEL, Sec 4, UN, R9W, SM, AK BHL (NAD 27) X=344988.21, Y=2460279.85 BHL (NAD 83) X=1485011.029, Y=2460041.128 AFE Number 1610111D AFE Drilling Das 14 AFE Drilling Amount $3.00 MM Work String 4-1/2" 16.6# 5-135 CDS-40 RKB — AMSL 18' KB — 162.5' AMSL Ground Elevation 144.5' AMSL BOP Equipment 11" 5M T3 -Ener (Model 7082) Annular BOP 11" 5M T3 -Ener (Model 6011i) Double Ram 11" 5M T3 -Ener (Model 6011i) Single Ram Page 2 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 Ililvorp :Ua.+ka, H.0 2.0 Management of Change Information Hilcorp Alaska, LLC F -VC -P y Eoerpy ComD�oY Changes to Approved Permit to Drill Date: February 17, 2016 Subject: Changes to Approved Permit to Drill for SCU 3113-04 (SCU 12A-03 ST) File #: SCU 31 B-04 (SCU 12A-03 ST) Drilling Program Any modifications to SCU 31 B-04 Drilling Program will be documented and approved below. Changes to an approved APD will be communicated and approved by the BLM and AOGCC prior to continuing forward with work. Sec Page Date Procedure Change Approved Approved By By 12.2 14 2.17.16 Revised KOP to 6500° MDITVD due to casing damage MMM Approval Drilling Manager Prepared: Monty M Myers Date 2.17.2016 Drilling Engineer Date Page 3 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 Ililcorp Alaska, LIT 3.0 Tubular Program Wt Cou 1OD rift in Grade Conn To Bottom 6" 4-1/2" 12.6 5.0" 1 3.918 1 3.833 L-80 DWC/C 6300 11870 16769 595k 4.0 Drill Pipe Information o e Section OD (in) ID (in) TJ ID in TJ OD in(#/ft) Wt Grade Conn Burst si Collapse (psi) Tension (k -lbs) 6" 4-1/2" 3.826 2-11/16" 5-1/4" 16.6 S-135 CDS-40 17693 16769 595k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 Ililrorp.%IaAa, LLC 5.0 Internal Reporting Requirements 19.1 Fill out daily drilling report and cost report on Wellez. i. Report covers operations from 6am to 6am ii. Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry tab. iii. Ensure time entry adds up to 24 hours total. iv. Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 19.2 Afternoon Updates i. Submit a short operations update each work day to pmazzolinighilcorp.com, lkeller o,hilcorp.com, mmyers o,hilcorp.com and cdinger@hilcorp.com 19.3 5am Weekend Update i. Submit a short operations update each weekend and holiday to whoever is assigned weekend or vacation duty. Details will be sent before each weekend or holiday. ii. Copy pmazzolini@hilcotp.com, Ikeller@hilcorp.com and mmyers@hilcorp.com 19.4 EHS Incident Reporting i. Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don't wait until an emergency to have to call around and figure it out!!!! a. John Coston: O: (907) 777-6726 C: (907) 227-3189 b. Mark Tornai: O: (907) 283-1372 C: (907) 748-3299 c. Thad Eby: O: (907) 777-8317 C: (907) 602-5178 2. Spills: Julieanna Orczewska: 0:907-777-8444 C:907-715-7060 ii. Notify Drlg Manager 1. Paul Mazzolini: O: 907-777-8369 C: 907-317-1275 iii. Submit Hilcorp Incident report to contacts above within 24 hrs 19.5 Casing Tally i. Send final "As -Run" Casing tally to mmyers e,hilcorp.com and cdin e�r(a�hilcorp.com 19.6 Casing and Cmt report i. Send casing and cement report for each string of casing to mmyers@hilcorp.com e,hilcorp.com and cdingerghilcorp.com Page 5 Revision 0 January, 2016 6.0 Planned Wellbore Schematic SCU 31 B-04 Drilling Procedure Rev 1 PROPOSED SCHEMATIC - 50=3 "-Q >f) 22" 13-3/8' CASING AND TUBING DFTAIL Size WT Grade Corn ID Top Btm 22'" - - - Surface 28' 13-3/8" 54.5 - - 10.050 Surface 3,000' 7" 29 P-110 - 6.184 Surface 10,265' IFWFI RV DFTAII No Depth ID OD Item 1 6300' - 7"X4-1/2"ZXPliner hanger 2 6500' - 6.059" KOP 3 6300'— 11870' 3.918" 4.5" 4-1/2" 12.6tt L-80 DWC/C Liner CEMENT DETAIL 4-1 2" liner will be cemented from TD to linger hanger top with a minimum of 100 bbls of 15.3ppg class G cement 7 2 6"Windovr milled at 6500'TbID 3 TO = 11,870' TVD =10,712' MAX HOLE ANGLE = 55 deg. At 9,319' TMD Page 6 Revision 0 January, 2016 7.0 Drilling Summary SCU 31 B-04 Drilling Procedure Rev 1 SCU 31 B-04 is an oil production well planned to be re -drilled in a North-westerly direction from the existing SCU 12A-03 utilizing the existing casing program down to 6500' MD / 6500' TVD. At 6500' MD the parent wellbore will be sidetracked and new wellbore drilled penetrating several Hemlock targets. A 5370' x 6" open hole section is planned. A 4-1/2" 12.6# L-80 DWC/C prod liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with 2-7/8" production string. Drilling operations are expected to commence approximately February 18'', 2016. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. A separate sundry notice will be submitted to cover P&A and wellbore preparation for the sidetrack and for running the completion assembly General sequence of operations pertaining to this approved drilling procedure: 1. Saxon Rig #169 is on SCU 12A-03 to decomplete and P&A well. 2. PU 6.059" window milling assembly and DP and cleanout to CIBP at 6500' 3. POOH standing back, PU Whipstock, and mills and TIH to CIBP 4. Orient whipstock and set at 280 de azimuth. 5. Mill 6" window and 20' of new formation at 6500'. 6. POOH and LD mills. PU directional BHA and TIH to window. 7. Swap well to 9.5 ppg drilling mud 8. Perform FIT to 12.5 ppg EMW 9. Drill 6" production hole from 6500' to 11870' MD, performing short trips as needed 10. Perform short trip and condition mud. POOH 11. LD Directional Tools. RIH w 4-1/2" liner. Set liner and cement. Circ wellbore clean. 12. POOH, laying down DP and liner running tools, 13. PU 4-1/2" casing scraper assembly and TIH to landing collar. 14. Circ casing clean. POOH laying down DP. 15. Run 2-7/8" completion. Land hanger and test. 16. ND BOPE, NU tree and test void 17. RDMO Page 7 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling of SCU 3113-04. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 10/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, we must test ALL BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system" • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements" • Ensure both AOGCC and BLM approved drilling permit is posted on the rig floor and in Co Man office. Variance Requests: • Onshore Oil and Gas Order No. 1, Section III. D. 3. C. o Hilcorp requests approval to install a 2-1/16" 5M HCR valve on kill line in lieu of a check valve. Operator suspects a freeze plug risk associated with installation of a check valve in the kill line. o Hilcorp requests approval to utilize flexible choke and kill lines in lieu of hard piping. Page 8 Revision 0 January, 2016 Summary of BOP Equipment and Test Requirements SCU 31 B-04 Drilling Procedure Rev 1 Hole Section Equipment Test Pressure(psi) • 11" x 5M T3 -Energy (Model 7082) Annular BOP • 1 F x 5M T3 -Energy Double Ram Initial Test: 250/3500 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross 6" • 11" x 5M T-3 Energy Single Ram • 3-1/8" 5M Choke Line Subsequent Tests: • 2-1/16" x 5M Kill line 250/3500 • 3-1/8" x 2-1/16" 5M Choke manifold (Annular 2500 psi) • Standpipe, floor valves, etc • Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: • Well control event (BOPs utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Required BLM Notifications: • 48 hours before spud. Follow up with actual spud date and time. • 48 hours before casing running and cmt operations • 48 hours before BOPE tests • 48 hours before logging, coring, & testing • Any other notifications required in APD. Additional requirements may be stipulated on APD. Page 9 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 llilcorp Alaska, 1.1.1: Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.regg(a,alaska.gov Guy Schwartz / Petroleum Engineer/ (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@a 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: hLp:Hdoa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) BLM Amanda Eagle / BLM Petroleum Engineer/ (0): 907-271-3266 (C): 907-538-2300 Email: aea lg�blm.gov Mutasim Elganzoory / BLM Petroleum Engineer / (0): 907-271-4224 Email: melganzoory@blm.gov Use the below email address for BOP notifications to the BLM: BLM AK AKSO EnergySection Notifications@blm.gov Page 10 Revision 0 January, 2016 9.0 R/U and Preparatory Work SCU 31 B-04 Drilling Procedure Rev 1 9.1 Separate sundries will be submitted that will include the following: • Pull rods (Moncla 401 — Sundry 316-020) • P&A lower perfs with a cement plug (Saxon 169 - Sundry 316-046) • Set CIBP - (Saxon 169 - Sundry 316-046) - 9.2 Level pad and ensure enough room for layout of rig footprint and R/U. 9.3 Layout Herculite on pad to extend beyond footprint of rig. 9.4 R/U Saxon Rig #169, spot service company shacks, spot & R/U company man & toolpusher offices. 9.5 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.6 Mix mud for 6" hole section. 9.7 Check wellhead for pressure 9.8 Load well with 8.4 ppg KWF 9.9 Set BPV 9.10 Nipple down tree 9.11 Set test Plug in wellhead prior to N/U BOP to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.12 Verify 5" liners installed in mud pumps. • HHF-1000 Pumps are rated at 3457 psi (80%) with 5" liners and can deliver 306 gpm at 120 spm. This will allow us to drill the 6" hole section with (1) mud pump. Page 11 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 lhicogi UaAa.1.1.1: 10.0 BOP N/U and Test 10.1 * BOPE was NU and tested on prior decompletion sundry. We will test BOPE on 7 day cycle until the window is milled, at that point we will switch to the 14 day test cycle. Continue on to step 11. 10.2 N/U 11" x 5M BOP as follows: • BOP configuration from Top down: 11" x 5M annular BOP/11" x 5M double ram/11" x 5M mud cross/11" x 5M single ram. • Double ram should be dressed with 2-7/8" x 5" VBR in top cavity, blind ram in btm cavity. • Single ram should be dressed with 2-7/8" x 5" VBR. • N/U bell nipple, install flowline. 10.3 Run BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/3500 psi for 10/10 min. Test annular to 250/2500 psi for 10/10 min. • Ensure to leave "A" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Confirm the correct valves are opened! ! ! • Test VBRs on 4-1/2" test joint. • Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 10.4 R/D BOP test assy. 10.5 Continue mixing mud for 6" hole section. 10.6 Set wearbushing in wellhead. Ensure ID of wearbushing > 7". Page 12 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 Ililcorp alaAa.. LI.(: 11.0 Mud Program and Density Selection Criteria 11.1 6" Production hole mud program summary: Primary weighting material to be used for the hole section will be Calcium Carbonate to minimize solids. We will have barite on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.5 ppg 6% KCI/PHPA fresh water based drilling fluid. Properties: 11.2 11.3 System Formulation: 6% KCI / EZ Mud DP Product Concentration Water 0.905 bbl Yield Point 22 ppb (29 K chlorides) API Fluid MD Density Viscosity Plastic Viscosity 0.75 ppb (initially 0.25 ppb) pH 1-2 ppb PAC -L 1 ppb BARACARB 5/25/50 10-20 ppb BAROTROL PLUS 2 ppb Loss 6500' - 11870' 9.5-11.5 40-53 15-25 15-25 8.5-9.5 <-6.0 11.2 11.3 System Formulation: 6% KCI / EZ Mud DP 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) EZ MUD DP 0.75 ppb (initially 0.25 ppb) DEXTRID LT 1-2 ppb PAC -L 1 ppb BARACARB 5/25/50 10-20 ppb BAROTROL PLUS 2 ppb SOLTEX 2 ppb (if needed) BAROID 41 as required for a 9.5 —10.5 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 ppb (maintain per dilution rate) Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated BHP's from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead. Page 13 Revision 0 January, 2016 12.0 Whipstock Running Procedure SCU 31 B-04 Drilling Procedure Rev 1 12.1 M/U window milling assembly and TIH w/ 4-1/2" DP out of derrick. • Use a 6" taper mill and a 6" string mill above to ensure whipstock assy will pass freely. • Ensure BHA components have been inspected previously. • Caliper and drift all BHA components before running them in the hole. • Drift DP prior to RIH. • Lightly wash and ream any tight spots noted. 12.2 TIH to CIBP (6500' MD). Note that this was a wireline measurement so actual depth tagged may vary slightly. Keep up with the # of joints picked up so we know where we are. 12.3 Pressure test casing to 2500 psi / 30 min. Chart record casing test & keep track of the amount of fluid pumped. Stage up to 2500 psi in 500 psi increments. 12.4 CBU & circ at least (1) hi -vis sweep to remove any debris created by the clean out run. Anything left in the wellbore could affect the setting of the Whipstock. 12.5 TOH. 12.6 Makeup mills on a joint of HWDP. 12.7 RIH & set in slips. 12.8 Make up float sub, install float. 12.9 Make up UBHO sub. 12.10 Orient UBHO to starter mill. 12.11 Leave assembly hanging in the elevators, and stand back on floor. 12.12 Bring Whipstock to rig floor on the pipe skate. Do not slam into bottom of Whipstock with pipe skate. 12.13 Pick up Whipstock per Baker rep using the Baker Whipstock handling system using air hoist. Allow assy to hang while Baker Rep inspects and removes shear screws as needed and any safety screws. Note: Anchor should be pinned with 6 shear screws initially. Shear screws are rated for 6,630 lbs each. REMOVE 3 screws for a set down shear of 6,630 x 3=19,8901bs. Note: Attach mills to Whipstock with (1) 35k mill shear bolt. Page 14 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 Ililcorp .1la,ka. LLC 12.14 If needed, open BOP Blinds. 12.15 Run the Whipstock in the hole, install safety clamp as per Baker Rep, and install hole cover wrap. 12.16 Release pick up system at this point, Make up mills. 12.17 With the top drive, pick the assembly and position the starting mill to align with the hole in the slide. The Baker Rep will instruct the driller when the slot is lined up, the shear bolt then can be made up by the Baker Rep. 12.18 The assembly can now be picked up to ensure that the shear bolt is tight. 12.19 Remove the handling system. 12.20 Slowly run in the hole as per Baker Rep. Run extremely slow through the BOP & wear bushing. 12.21 Run in hole at 1 %2 to 2 minutes per stand. 12.22 Fill every 30 stands or as needed, do not rotate or work the string unnecessarily. 12.23 Call for Baker Rep. 15 — 10 stands before getting to bottom. 12.24 Orient at least 30' — 45' above the CIBP. Ensure to have gyro personnel and equipment as well as a wireline unit R/U and ready. Page 15 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 WindowMaster G2 System on TorqueMaster BTA 7" 29# Cse — WindowMaster G2 On BTA BHA #1 onnection Length O.D. BOTTOM TRIP ANCHOR 3 % IF -Box X Bottom Guide 3.21' 6.18" WINDOW MASTER WHIPSTOCK ihear Bolt X 3'/: IF -Pin 14.6' 6.00" WINDOW MILL -1/2 Reg -Pin X Mill 1.5' 6.63" LOWER WATER MELON MILL -1/2 IF -Box X 3-1/2 Reg -Box 5.5' 6.50" FLEX JOINT -1/2 IF- Box X 3-1/2 IF -Pin 6.6' 4.75" UPPER WATER MELON MILL -1/2 IF- Box X 3-1/2 IF -Pin 5.8' 6.63" 1 JT HWDP -1/2 IF -Box X 3-1/2 IF -Pin 30' 5.25" MWD Survey Tool -1/2 IF -Box X 3-1/2 IF -Pin 3' 4.75" UBHO -1/2 IF -Box X 3-1/2 IF -Pin 3' 4.75" Bowen Lubricated Bumper Jar -1/2 IF -Box X 3-1/2 IF -Pin 15' 4.75" 6 DRILL COLLARS -1/2 IF -Box X 3-1/2 IF -Pin 180' 4.75" 30 JTS — HWDP -1/2 CDS40 Box X 4-1/2 CDS40-Pin 900' 4.75" CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE. SHA'S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY Page 16 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 Ililrorp Uaska.. LI.1: 13.0 Whipstock Setting Procedure 13.1 With the bottom of the Whipstock 30 — 45' above the CIBP, measure and record P/U and S/O weights. We will orient Whipstock face using Gyrodata. Ensure that UBHO and gyro tool mate up properly before making up UBHO sub. 13.2 Orient Whipstock to desired direction by turning DP in 1/4 round increments. P/U and S/O on DP to work all torque out (Being careful not to set BTA). Whipstock Orientation Diagram: 270 AZI 315 AZI Desired orientation of the Whipstock face is in 270 to 315 degrees azimuth. Hole Angle at window interval (6500' MD) is < 1 deg. The wellbore trajectory is also planned to 290 degrees azimuth. Highside of the casing at 6500' is negligible. 13.3 Once Whipstock is in desired orientation, slack off and tag CIBP to set Bottom Trip Anchor. 13.4 Set down 12-15K on anchor to trip, P/U 5-7K maximum overpull to verify anchor is set. The window mill can then be sheared off by slacking off weight on the Whipstock shear bolt. (25k shear value). 13.5 P/U 5-10' above top of Whipstock. 13.6 Displace to 9.5 ppg 6% KC1/PHPA drilling fluid. 13.7 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window. Utilize 4 ditch magnets on the surface to catch metal cuttings. 13.8 Install catch trays in shaker underflow chute to help catch iron. 13.9 Keep iron in separate bbls. Record weight of iron recovered on ditch magnets. Page 17 Revision 0 January, 2016 13.10 Estimated metal cuttings volume from cutting window: SCU 31 B-04 Drilling Procedure Rev 1 ESP 13.11 Drill approx. 20' rat hole to accommodate the drilling assembly. Ream window as needed to assure there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through window checking for drag. 13.12 Circulate Bottoms Up until MW in = MW out. 13.13 Conduct FIT to 12.5 ppg EMW. • (12.5 — 9.5) * 0.052 * 6500' tvd = 1014 psi 13.14 Kick Tolerance • (12.5 -9.5) * (6500/10712) = 1.82 Note: Offset field test data predicts frac gradients at the window to be between 12 ppg and 15 ppg. A 12.5 ppg FIT results in a 1.82 ppg kick tolerance while drilling the interval with a 9.5 ppg fluid density. 13.15 Slug pipe and POOH. Gauge Mills for wear. 13.16 Should a second run be required pick up the following BHA. Rar_k Hn Mills Connection Lenath O.D. WINDOW MILL 3'/2 REG -P X MILL 29# N-80 Cuttings Weight Window 3'/z IF -13 X 3 % REG -13 5.5 6.5 FLEX JOINT Length Casing Weight Min (lbs) Avg (lbs) Max (lbs) 13 29.7# 80 110 140 ESP 13.11 Drill approx. 20' rat hole to accommodate the drilling assembly. Ream window as needed to assure there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through window checking for drag. 13.12 Circulate Bottoms Up until MW in = MW out. 13.13 Conduct FIT to 12.5 ppg EMW. • (12.5 — 9.5) * 0.052 * 6500' tvd = 1014 psi 13.14 Kick Tolerance • (12.5 -9.5) * (6500/10712) = 1.82 Note: Offset field test data predicts frac gradients at the window to be between 12 ppg and 15 ppg. A 12.5 ppg FIT results in a 1.82 ppg kick tolerance while drilling the interval with a 9.5 ppg fluid density. 13.15 Slug pipe and POOH. Gauge Mills for wear. 13.16 Should a second run be required pick up the following BHA. Rar_k Hn Mills Connection Lenath O.D. WINDOW MILL 3'/2 REG -P X MILL 0.98 6.63 NEW LOWER WATERMELON MILL 3'/z IF -13 X 3 % REG -13 5.5 6.5 FLEX JOINT 3'/z IF -13 X 3 Y IF -P 6.5 4.75 UPPER WATERMELON MILL 3'/2" IF -13 X 3'/" IF -P 5.83 6.63 FLOAT SUB 3'/2" IF -13 X 3'/" IF -P 3.00 4.75 XO sub and 30 jts-HWDP 4'/2" CDS40-B X 3 Y2" IF -P 900' 5.25 CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE. BHA'S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY! Page 18 Revision 0 January, 2016 14.0 Drill 6" Hole Section 14.1 P/U 6" directional drilling assy. 14.2 Ensure BHA Components have been inspected previously. SCU 31 B-04 Drilling Procedure Rev 1 14.3 Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 14.4 Ensure TF offset is measured accurately and entered correctly into the MWD software. 14.5 Confirm that the bit is dressed with a TFA of 0.46 — 0.56 sqin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 150 - 250 gpm. 14.6 Motor AKO should be set at 1.2 deg. Must keep up with 3 deg/100 DLS in the build section of the wellbore. 14.7 Primary bit will be the Varel 6" VS516DX PDC bit. Ensure to have a back up bit available on location. Page 19 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 PRODUCT SPECIFICATIONS o Cutter Size: 16 mm Cutter Back Up: Total Cutter Count: Face Cutter Count: Connection: Nozzle 1 QtyrFype: Nozzle 2 Qty/Type: Junk Slot Area: Gage Pad Length: Make Up Length: Shank Diameter: Carbide Shock Studs 24 14 3112" API Regular 5 - Series 55 OPERATING PARAMETERS* 6.8in' (43.9cros) 3" (76mm) 7,1" (180.8mm) 4.88" (124mm) Rotary Speed: For all rotary and motor applications Flowrate Min -Max: 150 - 350GPM (0.57-1.32m$lmin) Max Weight On Bit: 14000lbs (6228daN) Makeup Torque: 7000 - 9000Ft-Lbs, (9491-12202Nm) 'Operating parameters sriuvn are typical for the hit type speci%d- For re•_ammendalions on your spy c fic applicatK-n cons act your 'dare; IntetnaWrial representative_ Voyager Series Bits - Voyager series bits utilize Varei's proprietary design, modeling, and programming software coupled with specialized manufacturing techniques to create the optimal drill bit for your fit -for -purpose applications. Engineered though Varel Simulator Suite for specific directional applications, Voyager bits incorporate the latest design features to maximize cuttings removal, enhance ROP potential, improve directional response, and create a more durable bit frame to aid in accomplishing your aggressive directional drilling objectives. Bit Features D - Drop in cutter in gage pad. X - Shock studs limit drill bit vibration and increase stability allowing smooth cutting action increasing cutter life and overall bit performance. S - Steel body technology allows for wide open face hydraulics and aggressive cutting structures providing faster penetrating bits than matrix designs. Page 20 Revision 0 January, 2016 C Tool :� T10742 voyagerAm' A0971a iADC Code: 5333 PRODUCT SPECIFICATIONS o Cutter Size: 16 mm Cutter Back Up: Total Cutter Count: Face Cutter Count: Connection: Nozzle 1 QtyrFype: Nozzle 2 Qty/Type: Junk Slot Area: Gage Pad Length: Make Up Length: Shank Diameter: Carbide Shock Studs 24 14 3112" API Regular 5 - Series 55 OPERATING PARAMETERS* 6.8in' (43.9cros) 3" (76mm) 7,1" (180.8mm) 4.88" (124mm) Rotary Speed: For all rotary and motor applications Flowrate Min -Max: 150 - 350GPM (0.57-1.32m$lmin) Max Weight On Bit: 14000lbs (6228daN) Makeup Torque: 7000 - 9000Ft-Lbs, (9491-12202Nm) 'Operating parameters sriuvn are typical for the hit type speci%d- For re•_ammendalions on your spy c fic applicatK-n cons act your 'dare; IntetnaWrial representative_ Voyager Series Bits - Voyager series bits utilize Varei's proprietary design, modeling, and programming software coupled with specialized manufacturing techniques to create the optimal drill bit for your fit -for -purpose applications. Engineered though Varel Simulator Suite for specific directional applications, Voyager bits incorporate the latest design features to maximize cuttings removal, enhance ROP potential, improve directional response, and create a more durable bit frame to aid in accomplishing your aggressive directional drilling objectives. Bit Features D - Drop in cutter in gage pad. X - Shock studs limit drill bit vibration and increase stability allowing smooth cutting action increasing cutter life and overall bit performance. S - Steel body technology allows for wide open face hydraulics and aggressive cutting structures providing faster penetrating bits than matrix designs. Page 20 Revision 0 January, 2016 C SCU 31 B-04 Drilling Procedure Rev 1 I1ile-1, Alaska. LLC 14.8 TIH to window. Shallow test MWD on trip in. 14.9 TIH through window, ensure Halliburton MWD service rep on rig floor during this operation. • Do not rotate string while bit is across face of Whipstock. 14.10 Drill 6" hole to 11870' MD using motor assembly. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Utilize ECD while pumping to minimize waterflow from Tyonek sands • On trips spot weighted pills inside window and hi vis pills at TD to control waterflow • Try to keep waterflow below 10 bph while tripping • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • See attached mud program for hole cleaning and LCM strategies. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. • Ensure mud engineer set up to perform HTHP fluid loss. • Maintain API fluid loss < 6. • Take MWD surveys every stand drilled. • Minimize backreaming when working tight hole 14.11 Hilcorp Geologists will follow mud log closely to determine exact TD. 14.12 At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU, and pull a wiper trip back to the window. 14.13 TOH with drilling assembly, handle BHA as appropriate. Page 21 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 Ilileorp % aska. LIA: 15.0 Run 4.5" Production Casing 15.1 R/U Weatherford 4.5" casing running equipment. • Ensure 4.5" DWC/C x 4-1/2" CDS-40 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted and tally verified prior to running. • Be sure to count the total # of joints before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 15.2 PIU shoe joint, visually verify no debris inside joint. 15.3 Continue M/U & thread locking shoe track assy consisting of: • (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). • (1) Baker locked joint. • (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). • (1) Joint with landing collar bucked up. • Rigid or Solid body centralizers will be pre-installed on shoe joint, FC joint, and LC joint. • Install centralizers, one per joint, and leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe & FC. 15.4 Continue running 4.5" production casing • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. • Install solid body centralizers on every other joint to window. Leave the centralizers free floating. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 4.5" DWC/C HT NIX toraues Casing OD Minimum Maximum Yield Torque 4-1/2" 5800 ft -lbs 6500 ft -lbs 7200 ft -lbs Page 22 Revision 0 January, 2016 Ililcorp %la.ka, LLC Connection Type: DWC/C Tubing standard Technical Specifications Size(O.D.): Weight (Wall): 4-112 in 12.60 Ibtft (0.271 in) Material L-80 Grade 80,000 Minimum Yield Strength (psi) 95,000 Minimum Ultimate Strength (psi) Pipe Dimensions 4.500 Nominal Pipe Body O.D. (in) 3.958 Nominal Pipe Body I.D.(in) 0.271 Nominal Wall Thickness (in) 12.60 Nominal Weight (lbs/ft) 12.25 Plain End Weight (lbstft) 3.600 Nominal Pipe Body Area (sq in) Connection Performance Properties 288,000 Joint Strength (Ibs) 14,290 Reference String Length (ft) 1.6 Design Factor 314,000 API Joint Strength (Ibs) 288,000 Compression Rating (Ibs) 7,500 API Collapse Pressure Rating (psi) 8,430 API Internal Pressure Resistance (psi) 81.5 Maximum Uniaxial Bend Rating [degrees1100 ft] Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft -lbs) 6,500 Maximum Final Torque (ft-Ibs) 7,200 Connection Yield Torque (ft -lbs) SCU 31 B-04 Drilling Procedure Rev 1 Grade: L-80 Alm USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston. TX 77041 Phone: 713-479-3200 Fax: 713479-3234 E-mail: VAMUSAsalesftvarn4m.com Page 23 Revision 0 January, 2016 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 Performance Properties 288,000 Joint Strength (Ibs) 14,290 Reference String Length (ft) 1.6 Design Factor 314,000 API Joint Strength (Ibs) 288,000 Compression Rating (Ibs) 7,500 API Collapse Pressure Rating (psi) 8,430 API Internal Pressure Resistance (psi) 81.5 Maximum Uniaxial Bend Rating [degrees1100 ft] Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft -lbs) 6,500 Maximum Final Torque (ft-Ibs) 7,200 Connection Yield Torque (ft -lbs) SCU 31 B-04 Drilling Procedure Rev 1 Grade: L-80 Alm USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston. TX 77041 Phone: 713-479-3200 Fax: 713479-3234 E-mail: VAMUSAsalesftvarn4m.com Page 23 Revision 0 January, 2016 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 (Ibs) 14,290 Reference String Length (ft) 1.6 Design Factor 314,000 API Joint Strength (Ibs) 288,000 Compression Rating (Ibs) 7,500 API Collapse Pressure Rating (psi) 8,430 API Internal Pressure Resistance (psi) 81.5 Maximum Uniaxial Bend Rating [degrees1100 ft] Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft -lbs) 6,500 Maximum Final Torque (ft-Ibs) 7,200 Connection Yield Torque (ft -lbs) SCU 31 B-04 Drilling Procedure Rev 1 Grade: L-80 Alm USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston. TX 77041 Phone: 713-479-3200 Fax: 713479-3234 E-mail: VAMUSAsalesftvarn4m.com Page 23 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 Ililcorp Alaska. LIA: 15.7 Ensure to run enough liner to provide for approx 200' overlap inside 7" casing. Ensure hanger/pkr will not be set in a 7" connection. 15.8 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. 15.9 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. 15.10 RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 15.11 RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 15.12 M/U top drive and fill pipe while lowering string every 10 stands. 15.13 Set slowly in and pull slowly out of slips. 15.14 Circulate 1-1/2 drill pipe and liner volume at 7" window prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 15.15 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 15.16 Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 15.17 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. 15.18 Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 15.19 Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 24 Revision 0 January, 2016 16.0 Cement 4.5" Production Casing SCU 31 B-04 Drilling Procedure Rev 1 • Cement will be mixed using batch mixer to ensure consistent density 16.1 Hold a pre job safety meeting over the upcoming cmt operations. 16.2 Attempt to reciprocate the casing during cmt operations until hole gets sticky. 16.3 Pump 5 bbls 12.5 ppg MUDPUSH II spacer. 16.4 Test surface cmt lines to 4500 psi. 16.5 Pump remaining 10 bbls 12.5 ppg MUDPUSH II spacer. 16.6 Mix and pump 140 bbls of 15.3 ppg class "G" cmt per below recipe with 1 lb/bbl of Cemnet or equivalent loss circulation fiber. Ensure cmt is pumped at designed weight. Job is designed to pump 50% OH excess but if fluid caliper dictates otherwise we may increase excess volumes. Cement volume is designed to give 500' of cement inside window in annulus between 7" casing and 4-1/2" casing. Est TOC 6000' TMD. 16.7 Displacement fluid will be drilling mud. —173 bbls of displacement fluid Cement Calculations 7" x 4-1/2 DP" Overlap: (6300' — 6000') x 0.017 = 5.1 bbls 7" x 4-1/2" Liner Overlap: (6500' — 6300') x 0.017 = 3.4 bbls 6" OH x 4-1/2" Liner: (11870' — 6500') x 0.0153 x 1.5 = 123.2 bbls Shoe Track: 80' x 0.01522 = 1.8 bbls Total Volume (bbls): 5.1 + 3.4 + 123.2 + 1.8 = 133.5 bbls Total Volume (113): 133.5 bbls x 5.615 ft3/bbl = 749.6 ft3 Total Volume (sx): 749.6 ft3 / 1.35 ft3/sk = 555.26 sx Page 25 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 11ilcorp %laska.. LII: Slurry Information: System Easy BLOK Density 15.3 lb/gal Yield 1.34 ft3/sk Mixed Water 5.879 gal/sk Mixed Fluid 5.879 gal/sk Expected Thickening 70 Bc at 05:00 hr:mn API Fluid Loss <25 mL in 30.0 min at 155degF / 1000 psi Additives Code Description Concentration G D046 D202 D400 D154 Cement Anti Foam Dispersant Gas Control Agent Extender 94 lb/sk 0.2% BWOC 1.5% BWOC 0.8% BWOC 8.0% BWOC 16.8 Drop DP dart and displace with drilling mud. 16.9 Pump cement at max rate of 8 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re -zeroed at this point 16.10 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 16.11 Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (15% above nominal setting pressure. Hold pressure for 3-5 minutes. 16.12 Slack off total liner weight plus 30k to confirm hanger is set. 16.13 Do not overdisplace by more than %2 shoe track (-1 bbls). Shoe track volume is 1.8 bbls. 16.14 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner Page 26 Revision 0 January, 2016 16.15 Bleed pressure to zero to check float equipment. SCU 31 B-04 Drilling Procedure Rev 1 16.16 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve 16.17 Rotate slowly and slack off 50k downhole to set ZXPN. 16.18 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req'd to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack -off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 16.19 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 16.20 Pick up to the high -rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re -tag the liner top, and circulate the well clean. 16.21 Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 16.22 POOH, LDDP. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 16.23 If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 16.24 NOTE: Some hole conditions may require movement of the drillpipe to "work" the torque down to the setting tool. 16.25 After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set -down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Page 27 Revision 0 January, 2016 110corp Ua4a. LLC SCU 31 B-04 Drilling Procedure Rev 1 Ensure to report the following on Wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns 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 Note: Send Csg & cmt report + "As -Run " liner tally to mmyers(dhilcorp.com Page 28 Revision 0 January, 2016 0 Ilile—p.UaAa, LIA: 17.0 Wellbore Clean Up & Displacement SCU 31 B-04 Drilling Procedure Rev 1 17.1 M/U casing clean out assy complete with casing scraper assys for each size casing in the hole. • 3-3/4" bit or mill • Casing scraper & brush for 4-1/2" 12.6# casing +/- 5250' 2-3/8" workstring. • Casing scraper & brush for 7" 29# casing • (2000') 4-1/2" DP • Casing scraper & brush for 7" 29# casing • 4-1/2" DP to surface. 17.2 TIH & clean out well to landing collar (+/- 11,750' MD). • Circulate as needed on trip in if string begins to take weight. • Circulate hi -vis sweeps as necessary to carry debris out of wellbore. • Ensure 3-3/4" bit is worked down to the landing collar. • Space out the cleanout BHA so that the 3-3/4" bit reaches the 4-1/2" landing collar when crossover is +/- 30' above the 4-1/2" liner top. 17.3 After wellbore has been cleaned out satisfactorily using mud, test casing to 3500 psi / 30 min. Ensure to chart record casing test. 17.4 Displace drilling fluid in wellbore with a hi -vis pill followed by fresh water. • Catch drilling fluid in rain -for -rent tanks for use on a future well. • Circulate fresh water into wellbore until clean up is satisfactory. Do not recirculate fluid, • After a couple circulations using FW, short trip the assy to bring the upper 7" multi -back assy to surface. • RIH again & tag landing collar w/ 3-3/4" bit. Continue circulation as necessary until fluid cleans up. Make another short trip if necessary. Pump a chemical train followed by 6% KCl completion fluid. 17.5 TOH w/ clean out assy. LDDP on the trip out. L/D the 2-3/8" work string. Page 29 Revision 0 January, 2016 18.0 Run Completion Assembly SCU 31 B-04 Drilling Procedure Rev 1 19.1 Run 2-7/8" tubing completion assembly as per separate Approved Completion Sundry 19.0 RDMO 19.1 Install BPV in wellhead. RILDs. 19.2 ND BOPE, NU tree, test void 19.3 RDMO Page 30 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 Iiilcorp Alaska, LII: 20.0 BOP Schematic Page 31 Revision 0 January, 2016 Hileorp Alaska, LLC 21.0 Wellhead Schematic BHTA, Bowen, 3 1,8 5M1 FE Vatve, swab, VG -M, 3 118 5M FE, HWO Valve, Wing, VG -M, 2 1116 5M FE, HWO Valve, upper master, VG -M, 3118 5M FE. HWO Valve, master. VG -M, 3 1Z 5M FE, HWO Tbg head, Seaboard, S-8, 135/83MX71116"5M, wl 2.2 1116 5M SSO �Rlr Valve, Wing, VG -M, 3 1!8 5M FE, HWO Oty 2 SCU 31 B-04 Drilling Procedure Rev 1 Valve, Wing, SSV, VG -M, 3118 5M FE wt Halliburton Hydraulic operator Adapter, Seaboard SM-E-CLN 7 V16 5M stdd X 3 118 5M stdd top, w1'/, npt control line exit rid level Valve, Seaboard, 2 1116 5M FE, HWO, Oty 2 Valve, Seaboard, 2" LPO Page 32 Revision 0 January, 2016 22.0 Days vs Depth r fi 0 Page 33 SCU 31 B-04 Drilling Procedure Rev 1 Days Vs Depth j SCU i1B-04 (SCU 12A-03 ST) 5 10 15 20 Days Revision 0 25 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 IGeo-Prog GEOLOGICAL PROGNOSIS WELL NAME.' SCU 31B-04 FIELD: . - = ' W IRFACE X.' 347966.38 STATE: Formation KOP sR_HisT SR_HISB SR_H2Sr SR_H2SB SR H3 ST SR H3L Sr SR H3SB SR H5Sr SR_H6ST SR H7Sr SR_H7SB SR H8Sr SR H8SB Flood project. KB 162.5 144.5 Based on subsurface evaluation 18' KB (Saxon 169) the H1 and H2 Oil associated with the 2015 H1-2 Gas 50 FT 4 man Crew from KOP to TD Triple Combo - Gas lift completion 2000 bpd gross fluid 2 7/8" X 2 3/8" Page 34 Revision 0 January, 2016 EXPECTED FORMATION FLUID MD TVD Est Pressure EMW Gradient Tyonek argillaceous sandstones and siltstone 6500 6499 2800 8.3 L 0.43 Oil Sand 11339 10221 1600 3.0 0.16 11425 10271 1600 3.0 0.16 Oil Sand 11434 10276 1600 3.0 0.16 11455 10288 1600 3.0 0.16 Oil Sand 11469 10296 1600 3.0 0.16 Oil Sand 11498 10313 1600 3.0 0.16 11610 10378 1600 3.0 0.15 Oil Sand 11638 10394 2800 5.2 0.27 11812 10495 2800 5.1 0.27 Oil Sand 11860 10523 2800 5.1 0.27 11920 10558 2800 5.1 0.27 Oil Sand 11936 10567 2800 5.1 0.26 12094 10658 2800 5.1 0.26 50 FT 4 man Crew from KOP to TD Triple Combo - Gas lift completion 2000 bpd gross fluid 2 7/8" X 2 3/8" Page 34 Revision 0 January, 2016 Ilileorp Alaska, HT SCU 31 B-04 Drilling Procedure Rev 1 i ,.e— �D 24.0 Anticipated Drilling HazardsGZ©� Water Flow: z tE The Tyonek water sands will be open. Ensure to treanitial flow as gas.fter we are confident we are only dealing with water from the sands we will drill the interval while the well is flowing water. Utilize MW and ECD to keep the well dead will drilling. During trips we will use heavy pills and viscous pills to control the flow and trip in and out of the well. Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual -composition carbon -based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscofier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain programmed mud specs. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt -type additives to further stabilize coal seams. • Increase fluid density as required to control running coals. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. • Minimize swab and surge pressures • Minimize back reaming through coals when possible H2S: H2S is not present in this hole section. No abnormal temperatures or pressures are present in this hole section. Page 35 Revision 0 January, 2016 25.0 Rig Layout SCU 31 B-04 Drilling Procedure Rev 1 Page 36 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 11deurp ANska, HA: 26.0 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 37 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 Hilcorp Alaska, LLC 27.0 Choke Manifold Schematic Page 38 Revision 0 January, 2016 rra r, VF�i Ono Page 38 Revision 0 January, 2016 Ifilcorli Alaska.. LIA: SCU 31 B-04 Drilling Procedure Rev 1 28.0 Casing Design Information Calculation & Casing Design Factors Hole Size Hole Size 6" Hole Size Drilling Mode MASP: Production Mode MASP: Swanson River Unit DATE: 2/17/2016 WELL: SCU 31B-04 (SCU 12A-03 ST) FIELD: Soldotna Creek Unit DESIGN BY: Monty M Myers Design Criteria: Mud Density: Mud Density: 10.5 ppg Mud Density: 1714 psi (See attached MASP determination & 2782 psi (See attached MASP determination & calculation Collapse Calculation: Section Calculation 1,2 Normal gradient external stress (0.406 psi/ft) and the casing evacuated for the internal stress Page 39 Revision 0 January, 2016 Casing Section Calculation/Specification 1 2 3 4 Casing OD 4-1/2" Top (MD) 6,300 Top (TVD) 6,300 Bottom (MD) 11,870 Bottom (TVD) 10,712 Length 5,570 Weight (ppf) 12.6 Grade L-80 Connection DWC/C Weight w/o Bouyancy Factor (lbs) 70,182 Tension at Top of Section (lbs) 70,182 Min strength Tension (1000 lbs) 288 Worst Case Safety Factor (Tension) 4.10 Collapse Pressure at bottom (Psi) 4,349 Collapse Resistance w/o tension (Psi) 7,500 Worst Case Safety Factor (Collapse) 1.72 MASP (psi) 1,714 Minimum Yield (psi) 8,430 Worst case safety factor (Burst) 4.92 Page 39 Revision 0 January, 2016 [hic-1) Alaska, LLC SCU 31 B-04 EDrilling Procedure Rev 1 29.0 6" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 11 6" Hole Section H"c-07 SCU 31B-04 Kenai, Alaska MD TVD Planned Top: 6500 . 6500 Planned TD: 11870 - 10712 Antirinatad Fnrmatinnc and Praccurace Formation TVD Est Pressure Oil/Gas/Wet PPG Grad SR_H1ST 10,221 1600 Oil / Water 3.0 0.157 SR_H2ST 10,271 1600 Oil /Water 3.0 0.156 SR_H2SB 10,276 1600 3.0 0.156 SR_H3ST 10,288 1600 Gassy Water/ Oil 3.0 0.156 SR_H3L_ST 10,296 1600 Gassy Water/Oil 3.0 0.155 SR_H3SB 10,313 2800 5.2 0.272 SR_H5ST 10,378 2800 Water/ Oil 5.2 0.270 SR_H5SB 10,394 2800 5.2 0.269 SR_H7ST 10,495 2800 Oil 5.1 0.267 SR_H7SB 10,523 2800 5.1 0.266 SR_H8ST 10,558 2800 Water/Oil 5.1 0.265 SR_H8SB 10,567 2800 5.1 0.265 TD 10,712 2800 OIL 5.0 0.261 Offset Well Mud Densities Wall MW rnnaa Tnn iTVDI Rnttnm ITVDI Data SCU 4405 9.8- 10ppg 9,400 10,925 2014 SCU 21-4 12 ppg 0 10,965 1961 SCU 4433 11.3 -12.5 ppg . 9,216 10,747 2013 SCU 41A-4 11.2 ppg • 9,300 10,807 2013 Assumptions: 1. Maximum planned mud density for the 6" hole section is 10.5 ppg. 2. Calculations assume reservoirs contain 100% gas (worst case). 3. Calculations assume worst case event is complete evacuation of wellbore to gas. 4. Anticipated fracture gradient at 8600' TVD =12.5 ppg EMW Fracture Pressure at 6" window considering a full column of gas from window to surface: 6500 (ft) x 0.65(psi/ft)= 4225 4225 (psi) - [0.1(psi/ft)*65W(ft)]= 3575 psi MASP from pore pressure; entire wellbore evacuated to gas from TD 10712 (ft) x 0.26(psi/ft)= 2785 psi 2785(psi) - [0.1(psi/ft)*10712 (ft)]= 1714 psi Summary: 1. MASP while drilling 6" production hole is governed by SIBHP minus entire wellbore evacuated to gas from TD. 2. MASP during production mode is governed by SIBHP minus entire wellbore evacuated to gas from TD. Page 40 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 30.0 Plot (NAD 27) (Governmental Sections) SCU343-33 BHLf ,78CU 43A-33 SCU 13-34 BHLr 1 • r'r , A028399 SC133-33 BHL6 Y/ S008NO09W f-` A028 ----- SCU � - BCU23-34 BtiZ. aRL124.33 BHL* - 1,198U 446-33 BHLw- SCU34-33 SHL• +� •"f SCU44 44 BHtA _ - SCU-416-04 SHLO I9CU_418-04BP8HL 1 I SCU 21-04 BH j SGU21AA4 BHL+ISCU3tB-04_BHL J1 *AB.D4 B� SCU341-W S"j 6U_31.04_P8t:IF*.* y •Qft'6y �SCu2tC-04�HL SCu-31-ct �IRQ"'e9* � SCU 31$-04_TPH „• SCU42-44 BH4 •4vO-e i I Ob 2.230.04 is" SCU I2A SCu 12- SCU 31 B-04 SHL it _ SCU IiA#uT Pi1i11/ U2204P8 BHI S L1r SCU332A46HL 22-04 BHL• ; Ti SCU238-03 SHL' SCU23-03 044.23A-03 EHL S)007NO09W A028997 ,•'�SCU323-u SHL' 8r14143 -4t EHL" • .4 • -B i Sr -04 BHL• SCU 13. BHLO- l Page 41 Soldotna Creek Unit SC U 31 B-04 Revision 0 0 1,400 2,DD0 Feet Alaska State Plane Zone 4, NAD27 A Map Dele: 1;14t2018 January, 2016 Legend SCU44-La BHL•, i Plan: SCU 31 B-04 SHL PL_SCU 24-C4178TpEHL�-_- - _ _ Plan: SCU 31 B-04–TPH SCU34-1;4 BHL• U994-0 Plan: SCU 316-04 BHL - • Other Surface Well Locations • Other Bottom Hole Locations Well Paths �.-_ SRF Unit Boundary C► --- _ - EHL —.— Page 41 Soldotna Creek Unit SC U 31 B-04 Revision 0 0 1,400 2,DD0 Feet Alaska State Plane Zone 4, NAD27 A Map Dele: 1;14t2018 January, 2016 31.0 Surface Plat (As Built) (NAD 2 SCU 31 B-04 Drilling Procedure Rev 1 I 1 34 _ _ SECTION LINE (NOT TO SCALE) T8N 4 1�-SF.CTIQNf•OR(l;ulaPUTFO) -- -- T7N R9W - N: 2461157.9E8 E. 3476M 774 I SEC 3 T7N R9W I21137 Foul (NT5i w SCU 12A-03 ASBUILT SURFACE LOCATION Q (~ ` NAD 27 ASP ZONE 4 N:2459121.980 U E:347966.381 LU I LAT: 60"43'41.971"N LOW 150"50'57.362"W I:559 "VL2032' FNL 359' FWL I' ELEV: 144.45' NAVD88 I � I NOTES 1. BASIS OF HORIZONTAL NAD83 US FEET POSITION (EPOCH 2010; AND VERTICAL CONTROL {NAVD88y IS AN OPUS SOLUTION FROM NGS STATIONS TBON, TSEA AND ANC2 TO ESTABLISH CP -2. THE ALASKA STATE PLANE COORDINATES MAD 83 ZONE 4 IN FEET ARE: y? N = 24583$4.578 E = 1483669.444,^ ELEV - 212.690 iNAVD88) w A�}77w 01w�c 2. SECTION LINES SH'VN WERE ESTABLISHED FROM SURVEY SCALE 'j�! i 46 —Ss _ TIES TO ORIGINAL GLO MONUMENTATION 09871 3. DATUM TRANSFORMATIONS (NAD83 ASPZ4 TO NA027 ASPZ4) ma 4Cc !!!!!'"„+,+++�' WERE DONE USING CORPSCON SOFTWARE VERSION 6.0.1 FEET HILCORP ALASKA, LLC "x:11- G-m-3ulfing Inc f SWANSON RIVER FIELD r"" WELL SCU 12A-03 4 AS BUILT SURFACE LOCATION NAD 27 CMfJV[[PWyl4NFi1VG: :LP'.L,H:i IC:'N: Rft;1: fA'TJ f�.tt SECTION 03 T07N R09W '.LrCE I!Qr.:k],2+k Fk. N1`I :x?]2f4 SEWARD MERIDIAN, ALASKA 1 cr Page 42 Revision 0 January, 2016 32.0 Surface Plat (As Built) (NAD 83) SCU 31 B-04 Drilling Procedure Rev 1 1 33 31 SECTION LINE (NOT TO SCALE) T8N _ _ _ 4I\' —_ -- — 5ECTIUNCOR IWMPUTEDj LL N �a�l,�113;h3 T7N R9W E. 1487653 8115 I iS STATIONS TBON, TSEA AND ANC2 TO ESTABLISH CP -2 THE ASKA STATE PLANE COORDINATES NAD 83 ZONE 4 IN FEET ARE: I f/ z yrr t r /� SEC 3 T7N R9W FNI. ;NTS: * r 4 IH a # I LU SCU 12A•03 I SECTION LINES SHOWN WERE ESTABLISHED FROM SURVEY ASBUILT SURFACE LOCATION O / NAD 83 ASP ZONE 4 21m N:2458883.1570 U E:1487989.257 U) I LAT: 60°43'39.942"N a LON: 150'51'05.348"W 35Y FwL 2032' FNL 359' FWL w I ELEV: 144.45' NAVD88 I I P I NOTES BASIS OF HORIZONTAL, NAD83 US FEET POSITION (EPOCH 20101 4D VERTICAL CONTROL (NAVD88y 15 AN OPUS SOLUTION FROM iS STATIONS TBON, TSEA AND ANC2 TO ESTABLISH CP -2 THE ASKA STATE PLANE COORDINATES NAD 83 ZONE 4 IN FEET ARE: f/ z yrr t r /� N = 2458384.578 E = 1483669.444/^ * r 4 IH a # ELEV = 212.690 (NAVD88) i - stew wn�u[ f _ SECTION LINES SHOWN WERE ESTABLISHED FROM SURVEY SCALE / ES TO ORIGINAL GLO MONUMENTATION (1987) 21m 4n FEET f- HIL(;VKY ALASKA, LL(; SWANSON RIVER FIELD 1— "` 1. C.:.vnnultiN IncWELL SCU 12A-03 `—" ' ' , AS BUILT SURFACE LOCATION :NOV[[PIY'.ILNPKMG'1.F4Lr nom..--. NAD 83 FIlT1: IA. :: In-�ti lKVt.NJ 9�lL'UI.U�IVS .ncE iKn, iar+:.� .�.. rrrix�ucs SECTION 03 T07N R09W [wa. vkci.�uiw�w..�vcc.cx+ 11drurp A64u. 1 1,(: .' SEWARD MERIDIAN, ALASKA Page 43 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 1 Ililcorp Alaska, LLC 33.0 Directional Program (P1) Page 44 Revision 0 January, 2016 Hilcorp Energy Company Soldotna CK Unit Soldotna CK Unit Soldotna CK Unit 12-3 Plan: SCU 3113-04 Plan: SCU 3113-04 wp02 Standard Proposal Report 15 February, 2016 HALLIBURTON Sperry Drilling Services HALLIBURTON svo,-v ❑rur..r Project: Soldotna CK Unit Site: Soldotna CK Unit Wel I: Soldotna CK Unit 12-3 Wellbore: Plan: SCU 31B-04 Plan: SCU 318-04 wp02 75 8000 8500 0 O qCL 9000 U 9500 al 10000 if11I6I11; 11500 6000 WELL DETAILS: Soldotna CK Unit 12-3 NAD 1927 (NADCON CONUS) Alaska Zone 04 Ground Level: 144.45 +N/ -S +F/ -W Northing Ewting Latittude Longitude 0.00 0.00 2459121.98 347966.38 600 43'41.971 N 150° 50'57.362 W REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well Soldotna CK Unit 123, True North Vertical TVD) Reference: SCU 31 B-04 @ 162.45usft (Saxon 169) Measured epth Reference: SCU 3113-04 @ 162.45usft (Saxon 169) Calculation Method: Minimum Curvature 2000 SCU 31B-04 wp02 1500 , M � ti ~ p 00 1000 p 4 1/2" �� o �O tn O +. N O SCU 31B-04 SR H8ST, a o 0 0 OC C, `b N500, SCU 31B-04 SR HIST 47 000 �1z oo o r\ 5� , o 0 SCUD 12-3 -3000 -2500 10p0 000 000 9 000 1� SCU 31B-04 SR HIST 7" SCU 12-3 -2000 -1500 -1000 -500 0 500 West( -)/East(+) (750 usf /in) FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 10221.00 10058.55 11021.09 SR_H1ST 10271.00 10108.55 11107.06 SR_H1SB 10276.00 10113.55 11115.70 SR_H2ST 10288.00 10125.55 11136.42 SR_H2SB 10296.00 10133.55 11150.23 SR_H3ST 10313.00 10150.55 11179.58 SIR _H3L_ST 10378.00 10215.55 11291.82 SR 1-13S13 10394.00 10231.55 11319.44 SR_H5ST 10495.00 10332.55 11493.84 SR_H6ST 10523.00 10360.55 11542.18 SR_H7ST 10558.00 10395.55 11602.62 SR_H7SB 10567.00 10404.55 11618.16 SR_H8ST 10658.00 10495.55 11775.28 SR H8SB ------------ --- -------- ---------- ...._._._.-- - ------ ------------ SCU ---- ^^0^ y5Q --------------------------------------- -- -- P SCU 31B-04 SR_H8ST /UJ 4 1/2" g 12000 !1 11 1111 1 111 11111 11 1 1 1 11 [1 111111111 -1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 Vertical Section at 290.51° (1000 usft/in) HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Soldotna CK Unit Site: Soldotna CK Unit Well: Soldotna CK Unit 12-3 Wellbore: Plan: SCU 31B-04 Design: SCU 31 B-04 wp02 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Soldotna CK Unit 12-3 SCU 31 B-04 @ 162.45usft (Saxon 169) SCU 31 B-04 @ 162.45usft (Saxon 169) True Minimum Curvature Project Soldotna CK Unit, Swanson River Field 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 Site Soldotna CK Unit Site Position: Northing: 2,460,278.17usft Latitude: 60° 43'52.912 N From: Map Easting: 344,519.07 usft Longitude: 150° 52'6.985 W Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -0.76 ° Well Soldotna CK Unit 12-3 Well Position +N/ -S 0.00 usft Northing: 2,459,121.98 usft Latitude: 60° 43'41.971 N +E/ -W 0.00 usft Easting: 347,966.38 usft Longitude: 150° 50'57.362 W Position Uncertainty 0.00 usft Wellhead Elevation: 144.45 usft Ground Level: .144.45 usft Wellbore Plan: SCU 31B-04 Magnetics Model Name Sample Date Declination Dip Angle Field Strength V) (') (nT) BGGM2015 9/1/2015 16.56 73.69 55,517 Design SCU 31 B-04 wp02 Audit Notes: Version: Phase: PLAN Tie On Depth: 6,500.00 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (I 18.00 0.00 0.00 290.51 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) (°) (I (usft) usft (usft) (usft) (°/100usft) (`/100usft) (°/100usft) (°) 6,500.00 2.25 324.63 6,498.89 6,336.44 65.60 -30.02 0.00 0.00 0.00 0.00 6,524.20 3.56 290.67 6,523.06 6,360.61 66.25 -31.00 8.72 5.42 -140.34 289.50 6,544.20 3.56 290.67 6,543.03 6,380.58 66.69 -32.16 0.00 0.00 0.00 0.00 7,640.03 36.44 289.55 7,558.71 7,396.26 191.01 -380.29 3.00 3.00 -0.10 -1.23 10,446.83 36.44 289.55 9,816.82 9,654.37 748.75 -1,951.27 0.00 0.00 0.00 0.00 11,052.59 54.61 289.59 10,239.45 10,077.00 892,92 -2,356.82 3.00 3.00 0.01 0.11 11,650.01 54.61 289.59 10,585.45 10,423.00 1,056.20 -2,815.67 0.00 0.00 0.00 0.00 11,870.04 54.61 289.59 10,712.88 10,550.43 1,116.34 -2,984.66 0.00 0.00 0.00 0.00 2/15/2016 1:52:20PM Page 2 COMPASS 5000.1 Build 73 Halliburton H A LL I B U R TO N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Soldotna CK Unit 12-3 Company: Hiicorp Energy Company ND Reference: SCU 31 B-04 @ 162.45usft (Saxon 169) Project: Soldotna CK Unit MD Reference: SCU 31 B-04 @ 162.45usft (Saxon 169) Site: Soldotna CK Unit North Reference: True Well: Soldotna CK Unit 12-3 Survey Calculation Method: Minimum Curvature Wellbore: Plan: SCU 31 B-04 Depth Inclination Design: SCU 31 B-04 wp02 TVDss +NIS Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NIS +E/ -W Northing Easting DLS Vert Section (usft) V) V) (usft) usft (usft) (usft) (usft) (usft) -144.45 18.00 0.00 0.00 18.00 -144.45 0.00 0.00 2,459,121.98 347,966.38 0.00 0.00 98.45 0.25 338.00 98.45 -64.00 0.16 -0.07 2,459,122.14 347,966.32 0.31 0.12 198.45 0.50 309.00 198.45 36.00 0.64 -0.49 2,459,122.63 347,965.90 0.31 0.68 298.45 0.33 276.00 298.45 136.00 0.94 -1.11 2,459,122.94 347,965.28 0.29 1.37 398.45 0.25 295.00 398.44 235.99 1.07 -1.60 2,459,123.07 347,964.80 0.12 1.87 498.45 0.25 356.00 498.44 335.99 1.38 -1.81 2,459,123.38 347,964.59 0.25 2.18 598.45 0.00 356.00 598.44 435.99 1.59 -1.82 2,459,123.60 347,964.58 0.25 2.27 698.45 0.50 215.00 698.44 535.99 1.24 -2.07 2,459,123.24 347,964.32 0.50 2.38 798.45 0.50 251.00 798.44 635.99 0.74 -2.74 2,459,122.75 347,963.65 0.31 2.82 898.45 0.50 314.00 898.43 735.98 0.90 -3.46 2,459,122.92 347,962.93 0.52 3.56 998.45 0.25 348.00 998.43 835.98 1.41 -3.82 2,459,123.44 347,962.58 0.32 4.08 1,098.45 0.00 348.00 1,098.43 935.98 1.63 -3.87 2,459,123.66 347,962.53 0.25 4.19 1,198.45 0.25 99.00 1,198.43 1,035.98 1.59 -3.65 2,459,123.62 347,962.75 0.25 3.98 1,298.45 0.50 244.00 1,298.43 1,135.98 1.37 -3.83 2,459,123.40 347,962.57 0.72 4.07 1,398.45 0.33 196.00 1,398.43 1,235.98 0.90 -4.30 2,459,122.94 347,962.09 0.37 4.34 1,498.45 0.33 319.00 1,498.43 1,335.98 0.84 -4.57 2,459,122.88 347,961.82 0.58 4.57 1,598.45 0.33 20.00 1,598.43 1,435.98 1.33 -4.66 2,459,123.37 347,961.74 0.33 4.83 1,698.45 0.25 40.00 1,698.43 1,535.98 1.77 -4.42 2,459,123.80 347,961.98 0.13 4.76 1,798.45 0.25 137.00 1,798.42 1,635.97 1.77 -4.13 2,459,123.81 347,962.27 0.37 4.49 1,898.45 0.50 16.00 1,898.42 1,735.97 2.03 -3.86 2,459,124.06 347,962.54 0.66 4.33 1,998.45 0.50 35.00 1,998.42 1,835.97 2.81 -3.49 2,459,124.84 347,962.93 0.17 4.26 2,098.45 0.25 55.00 2,098.42 1,935.97 3.29 -3.06 2,459,125.31 347,963.36 0.28 4.02 2,198.45 0.50 46.00 2,198.42 2,035.97 3.72 -2.57 2,459,125.73 347,963.86 0.26 3.71 2,298.45 0.25 85.00 2,298.41 2,135.96 4.04 -2.04 2,459,126.05 347,964.39 0.34 3.33 2,398.45 0.00 85.00 2,398.41 2,235.96 4.06 -1.82 2,459,126.07 347,964.61 0.25 3.13 2,498.45 0.25 150.00 2,498.41 2,335.96 3.87 -1.71 2,459,125.88 347,964.72 0.25 2.96 2,598.45 0.00 150.00 2,598.41 2,435.96 3.69 -1.60 2,459,125.69 347,964.82 0.25 2.79 2,698.45 0.00 150.00 2,698.41 2,535.96 3.69 -1.60 2,459,125.69 347,964.82 0.00 2.79 2,798.45 0.50 129.00 2,798.41 2,635.96 3.41 -1.27 2,459,125.41 347,965.16 0.50 2.38 2,898.45 0.50 122.00 2,898.41 2,735.96 2.90 -0.56 2,459,124.89 347,965.86 0.06 1.54 2,998.45 0.42 75.00 2,998.40 2,835.95 2.77 0.17 2,459,124.75 347,966.58 0.37 0.81 13 3/8" 3,098.45 0.50 79.00 3,098.40 2,935.95 2.95 0.95 2,459,124.91 347,967.37 0.09 0.14 3,198.45 0.00 79.00 3,198.40 3,035.95 3.03 1.38 2,459,124.99 347,967.80 0.50 -0.23 3,298.45 0.17 160.00 3,298.40 3,135.95 2.89 1.43 2,459,124.85 347,967.85 0.17 -0.33 3,398.45 0.50 341.00 3,398.40 3,235.95 3.16 1.34 2,459,125.13 347,967.76 0.67 -0.15 3,498.45 0.58 345.00 3,498.39 3,335.94 4.06 1.06 2,459,126.03 347,967.50 0.09 0.43 3,598.45 0.58 312.00 3,598.39 3,435.94 4.89 0.56 2,459,126.86 347,967.00 0.33 1.19 3,698.45 0.83 310.00 3,698.38 3,535.93 5.70 -0.37 2,459,127.68 347,966.08 0.25 2.35 3,798.45 0.83 334.00 3,798.37 3,635.92 6.81 -1.25 2,459,128.81 347,965.22 0.35 3.55 3,898.45 0.50 355.00 3,898.36 3,735.91 7.90 -1.60 2,459,129.90 347,964.88 0.41 4.27 3,998.45 1.00 339.00 3,998.36 3,835.91 9.15 -1.95 2,459,131.15 347,964.55 0.54 5.03 4,098.45 0.75 333.00 4,098.34 3,935.89 10.55 -2.56 2,459,132.56 347,963.96 0.27 6.09 4,198.45 1.00 329.00 4,198.33 4,035.88 11.88 -3.31 2,459,133.90 347,963.23 0.26 7.26 4,298.45 0.92 326.00 4,298.32 4,135.87 13.29 -4.21 2,459,135.32 347,962.35 0.09 8.60 2115/2016 1:52:20PM Page 3 COMPASS 5000.1 Build 73 Planned Survey Halliburton H A LL I B U R TO N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Coordinate Reference: Well Soldotna CK Unit 12-3 Company: Hilcorp Energy Company TVD Reference: SCU 31 B-04 @ 162.45usft (Saxon 169) Project: Soldotna CK Unit MD Reference: SCU 31 B-04 @ 162.45usft (Saxon 169) Site: Soldotna CK Unit North Reference: True Well: Soldotna CK Unit 12-3 Survey Calculation Method: Minimum Curvature Wellbore: Plan: SCU 31B-04 Depth Inclination Design: SCU 31 B-04 wp02 Depth TVDss Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) V) V) (usft) usft (usft) (usft) (usft) (usft) 4,235.86 4,398.45 0.83 315.00 4,398.31 4,235.86 14.47 -5.17 2,459,136.51 347,961.40 0.19 9.91 4,498.45 0.75 345.00 4,498.30 4,335.85 15.61 -5.85 2,459,137.67 347,960.73 0.42 10.95 4,598.45 0.58 324.00 4,598.29 4,435.84 16.65 -6.32 2,459,138.71 347,960.28 0.29 11.75 4,698.45 0.92 329.00 4,698.28 4,535.83 17.75 -7.03 2,459,139.82 347,959.58 0.35 12.80 4,798.45 0.50 359.00 4,798.27 4,635.82 18.88 -7.45 2,459,140.95 347,959.18 0.55 13.59 4,898.45 0.50 10.00 4,898.27 4,735.82 19.74 -7.38 2,459,141.82 347,959.26 0.10 13.83 4,998.45 1.17 340.00 4,998.26 4,835.81 21.13 -7.65 2,459,143.21 347,959.00 0.78 14.57 5,098.45 0.50 352.00 5,098.25 4,935.80 22.52 -8.06 2,459,144.61 347,958.61 0.69 15.44 5,198.45 1.67 346.00 5,198.23 5,035.78 24.37 -8.48 2,459,146.46 347,958.22 1.17 16.48 5,298.45 1.83 333.00 5,298.18 5,135.73 27.21 -9.55 2,459,149.31 347,957.18 0.43 18.48 5,398.45 2.00 335.00 5,398.13 5,235.68 30.21 -11.02 2,459,152.33 347,955.76 0.18 20.90 5,498.45 2.50 344.00 5,498.05 5,335.60 33.89 -12.35 2,459,156.02 347,954.47 0.61 23.44 5,598.45 2.25 318.00 5,597.97 5,435.52 37.44 -14.27 2,459,159.60 347,952.60 1.10 26.48 5,698.45 2.50 330.00 5,697.88 5,535.43 40.79 -16.67 2,459,162.98 347,950.24 0.56 29.91 5,798.45 2.58 355.00 5,797.79 5,635.34 44.92 -17.96 2,459,167.13 347,949.00 1.10 32.56 5,898.45 2.25 315.00 5,897.70 5,735.25 48.55 -19.54 2,459,170.78 347,947.47 1.68 35.32 5,998.45 2.92 335.00 5,997.60 5,835.15 52.25 -22.01 2,459,174.51 347,945.05 1.11 38.92 6,098.45 1.67 331.00 6,097.52 5,935.07 55.83 -23.79 2,459,178.11 347,943.31 1.26 41.84 6,198.45 1.58 309.00 6,197.48 6,035.03 57.97 -25.57 2,459,180.28 347,941.56 0.63 44.26 6,298.45 2.25 348.00 6,297.43 6,134.98 60.76 -27.05 2,459,183.09 347,940.12 1.43 46.62 6,398.45 1.08 312.00 6,397.39 6,234.94 63.31 -28.16 2,459,185.65 347,939.04 1.52 48.55 6,498.45 2.25 325.00 6,497.35 6,334.90 65.55 -29.98 2,459,187.91 347,937.25 1.22 51.05 6,500.00 2.25 324.63 6,498.89 6,336.44 65.60 -30.02 2,459,187.96 347,937.21 0.94 51.10 KOP TOW: Start Dir 8.72°/100' : 6500' MD, 6498.89"TVD : 289.5° RT TF 6,524.20 3.56 290.67 6,523.06 6,360.61 66.25 -31.00 2,459,188.63 347,936.24 8.72 52.24 End Dir : 6524.2' MD, 6523.06' TVD 6,544.20 3.56 290.67 6,543.03 6,380.58 66.69 -32.16 2,459,189.08 347,935.09 0.00 53.49 Start Dir 3°/100' : 6544.2' MD, 6543.03'TVD 6,600.00 5.24 290.28 6,598.66 6,436.21 68.19 -36.17 2,459,190.63 347,931.09 3.00 57.77 6,700.00 8.24 289.97 6,697.96 6,535.51 72.22 -47.19 2,459,194.80 347,920.13 3.00 69.49 6,800.00 11.24 289.83 6,796.51 6,634.06 77.97 -63.09 2,459,200.76 347,904.31 3.00 86.40 6,900.00 14.24 289.74 6,894.03 6,731.58 85.43 -83.83 2,459,208.48 347,883.66 3.00 108.44 7,000.00 17.24 289.69 6,990.28 6,827.83 94.57 -109.36 2,459,217.96 347,858.26 3.00 135.56 7,100.00 20.24 289.65 7,084.97 6,922.52 105.38 -139.60 2,459,229.16 347,828.16 3.00 167.67 7,200.00 23.24 289.62 7,177.85 7,015.40 117.82 -174.47 2,459,242.05 347,793.44 3.00 204.69 7,300.00 26.24 289.60 7,268.66 7,106.21 131.87 -213.89 2,459,256.60 347,754.22 3.00 246.53 7,400.00 29.24 289.58 7,357.16 7,194.71 147.47 -257.73 2,459,272.77 347,710.58 3.00 293.06 7,500.00 32.24 289.56 7,443.10 7,280.65 164.58 -305.88 2,459,290.50 347,662.66 3.00 344.15 7,600.00 35.24 289.55 7,526.26 7,363.81 183.17 -358.20 2,459,309.77 347,610.58 3.00 399.67 7,640.03 36.44 289.55 7,558.71 7,396.26 191.01 -380.29 2,459,317.89 347,588.59 3.00 423.10 End Dir : 7640.03' MD, 7558.71' TVD 7,700.00 36.44 289.55 7,606.95 7,444.50 202.93 -413.85 2,459,330.24 347,555.19 0.00 458.72 7,800.00 36.44 289.55 7,687.41 7,524.96 222.80 -469.82 2,459,350.84 347,499.48 0.00 518.10 7,900.00 36.44 289.55 7,767.86 7,605.41 242.67 -525.79 2,459,371.43 347,443.77 0.00 577.49 8,000.00 36.44 289.55 7,848.31 7,685.86 262.54 -581.77 2,459,392.02 347,388.06 0.00 636.87 2/15/2016 1:52:20PM Page 4 COMPASS 5000.1 Build 73 Planned Survey Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Soldotna CK Unit 12-3 Company: Hilcorp Energy Company TVD Reference: SCU 31 B-04 @ 162.45usft (Saxon 169) Project: Soldotna CK Unit MD Reference: SCU 31B-04 @ 162.45usft (Saxon 169) Site: Soldotna CK Unit North Reference: True Well: Soldotna CK Unit 12-3 Survey Calculation Method: Minimum Curvature Wellbore: Plan: SCU 3113-04 Depth Inclination Design: SCU 31 B-04 wp02 Depth TVDss Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) V) V) (usft) usft (usft) (usft) (usft) (usft) 7,766.31 8,100.00 36.44 289.55 7,928.76 7,766.31 282.41 -637.74 2,459,412.62 347,332.35 0.00 696.26 8,200.00 36.44 289.55 8,009.21 7,846.76 302.28 -693.71 2,459,433.21 347,276.64 0.00 755.64 8,300.00 36.44 289.55 8,089.66 7,927.21 322.15 -749.68 2,459,453.80 347,220.93 0.00 815.03 8,400.00 36.44 289.55 8,170.11 8,007.66 342.03 -805.65 2,459,474.39 347,165.22 0.00 874.41 8,500.00 36.44 289.55 8,250.57 8,088.12 361.90 -861.62 2,459,494.99 347,109.51 0.00 933.80 8,600.00 36.44 289.55 8,331.02 8,168.57 381.77 -917.59 2,459,515.58 347,053.80 0.00 993.18 8,700.00 36.44 289.55 8,411.47 8,249.02 401.64 -973.56 2,459,536.17 346,998.10 0.00 1,052.57 8,800.00 36.44 289.55 8,491.92 8,329.47 421.51 -1,029.53 2,459,556.77 346,942.39 0.00 1,111.95 8,900.00 36.44 289.55 8,572.37 8,409.92 441.38 -1,085.50 2,459,577.36 346,886.68 0.00 1,171.34 9,000.00 36.44 289.55 8,652.82 8,490.37 461.25 -1,141.47 2,459,597.95 346,830.97 0.00 1,230.72 9,100.00 36.44 289.55 8,733.27 8,570.82 481.12 -1,197.44 2,459,618.54 346,775.26 0.00 1,290.11 9,200.00 36.44 289.55 8,813.73 8,651.28 500.99 -1,253.41 2,459,639.14 346,719.55 0.00 1,349.49 9,300.00 36.44 289.55 8,894.18 8,731.73 520.86 -1,309.38 2,459,659.73 346,663.84 0.00 1,408.88 9,400.00 36.44 289.55 8,974.63 8,812.18 540.73 -1,365.35 2,459,680.32 346,608.13 0.00 1,468.26 9,500.00 36.44 289.55 9,055.08 8,892.63 560.60 -1,421.33 2,459,700.92 346,552.42 0.00 1,527.65 9,600.00 36.44 289.55 9,135.53 8,973.08 580.48 -1,477.30 2,459,721.51 346,496.71 0.00 1,587.03 9,700.00 36.44 289.55 9,215.98 9,053.53 600.35 -1,533.27 2,459,742.10 346,441.01 0.00 1,646.42 9,800.00 36.44 289.55 9,296.43 9,133.98 620.22 -1,589.24 2,459,762.69 346,385.30 0.00 1,705.80 9,900.00 36.44 289.55 9,376.89 9,214.44 640.09 -1,645.21 2,459,783.29 346,329.59 0.00 1,765.19 10,000.00 36.44 289.55 9,457.34 9,294.89 659.96 -1,701.18 2,459,803.88 346,273.88 0.00 1,824.57 10,100.00 36.44 289.55 9,537.79 9,375.34 679.83 -1,757.15 2,459,824.47 346,218.17 0.00 1,883.96 10,200.00 36.44 289.55 9,618.24 9,455.79 699.70 -1,813.12 2,459,845.07 346,162.46 0.00 1,943.34 10,300.00 36.44 289.55 9,698.69 9,536.24 719.57 -1,869.09 2,459,865.66 346,106.75 0.00 2,002.73 10,400.00 36.44 289.55 9,779.14 9,616.69 739.44 -1,925.06 2,459,886.25 346,051.04 0.00 2,062.11 10,446.83 36.44 289.55 9,816.82 9,654.37 748.75 -1,951.27 2,459,895.89 346,024.95 0.00 2,089.92 Start Dir 31/100' : 10446.83' MD, 9816.82'TVD 10,500.00 38.03 289.55 9,859.15 9,696.70 759.51 -1,981.59 2,459,907.05 345,994.78 3.00 2,122.09 10,600.00 41.03 289.56 9,936.27 9,773.82 780.81 -2,041.56 2,459,929.13 345,935.09 3.00 2,185.72 10,700.00 44.03 289.57 10,009.95 9,847.50 803.45 -2,105.25 2,459,952.58 345,871.70 3.00 2,253.30 10,800.00 47.03 289.57 10,079.99 9,917.54 827.35 -2,172.48 2,459,977.35 345,804.78 3.00 2,324.65 10,900.00 50.03 289.58 10,146.21 9,983.76 852.45 -2,243.08 2,460,003.37 345,734.51 3.00 2,399.56 11,000.00 53.03 289.59 10,208.41 10,045.96 878.69 -2,316.83 2,460,030.56 345,661.10 3.00 2,477.84 11,052.59 54.61 289.59 10,239.45 10,077.00 892.92 -2,356.83 2,460,045.30 345,621.30 3.00 2,520.28 End Dir : 11052.59' MD, 10239.45' TVD 11,100.00 54.61 289.59 10,266.91 10,104.46 905.88 -2,393.24 2,460,058.73 345,585.06 0.00 2,558.93 11,200.00 54.61 289.59 10,324.82 10,162.37 933.21 -2,470.04 2,460,087.05 345,508.61 0.00 2,640.44 11,300.00 54.61 289.59 10,382.74 10,220.29 960.54 -2,546.85 2,460,115.37 345,432.17 0.00 2,721.95 11,400.00 54.61 289.59 10,440.65 10,278.20 987.87 -2,623.65 2,460,143.69 345,355.72 0.00 2,803.46 11,500.00 54.61 289.59 10,498.57 10,336.12 1,015.20 -2,700.46 2,460,172.01 345,279.28 0.00 2,884.97 11,600.00 54.61 289.59 10,556.48 10,394.03 1,042.53 -2,777.26 2,460,200.34 345,202.83 0.00 2,966.49 11,650.01 54.61 289.59 10,585.45 10,423.00 1,056.20 -2,815.67 2,460,214.50 345,164.60 0.00 3,007.25 11,700.00 54.61 289.59 10,614.40 10,451.95 1,069.86 -2,854.06 2,460,228.66 345,126.39 0.00 3,048.00 11,800.00 54.61 289.59 10,672.31 10,509.86 1,097.19 -2,930.87 2,460,256.98 345,049.94 0.00 3,129.51 11,870.04 54.61 289.59 10,712.88 • 10,550.43 1,116.34 -2,984.66 2,460,276.81 344,996.40 0.00 3,186.60 Total Depth: 11870.04' MD, 10712.88' TVD -4 112" 2/15/2016 1:52:20PM Page 5 COMPASS 5000.1 Build 73 Targets Halliburton H A L L I B U R T O N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Soldotna CK Unit 12-3 Company: Hilcorp Energy Company TVD Reference: SCU 31 B-04 @ 162.45usft (Saxon 169) Project: Soldotna CK Unit MD Reference: SCU 31 B-04 @ 162.45usft (Saxon 169) Site: Soldotna CK Unit North Reference: True Well: Soldotna CK Unit 12-3 Survey Calculation Method: Minimum Curvature Wellbore: Plan: SCU 31B-04 (usft) (usft) Design: SCU 31 B-04 wp02 0.00 0.00 10,239.45 892.92 Targets Measured Target Name Local Coordinates Depth Depth +N/ -S hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting -Shape (°) (°) (usft) (usft) (usft) (usft) (usft) SCU 3113-04 SR_H1ST 0.00 0.00 10,239.45 892.92 -2,356.82 2,460,045.30 345,621.30 plan hits target center 66.69 -32.16 Start Dir 31/100': 6544.2' MD, 6543.03'TVD 7,640.03 7,558.71 Circle (radius 50.00) -380.29 End Dir : 7640.03' MD, 7558.71' TVD 10,446.83 9,816.82 748.75 SCU 31B-04 SR MST 0.00 0.00 10,585.45 1,056.20 -2,815.67 2,460,214.50 345,164.60 plan hits target center 11,870.04 10,712.88 1,116.34 -2,984.66 Total Depth : 11870.04' MD, 10712.88' TVD Circle (radius 50.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name () (11) 11,870.04 10,712.88 41/2" 4-1/2 6 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/ -S +EI -W (usft) (usft) (usft) (usft) Comment 6,500.00 6,498.89 65.60 -30.02 KOP TOW: Start Dir 8.72'/100': 6500' MD, 6498.89"TVD : 289.5° RT TF 6,524.20 6,523.06 66.25 -31.00 End Dir : 6524.2' MD, 6523.06' TVD 6,544.20 6,543.03 66.69 -32.16 Start Dir 31/100': 6544.2' MD, 6543.03'TVD 7,640.03 7,558.71 191.01 -380.29 End Dir : 7640.03' MD, 7558.71' TVD 10,446.83 9,816.82 748.75 -1,951.27 Start Dir 31/100' : 10446.83' MD, 9816.82'TVD 11,052.59 10,239.45 892.92 -2,356.83 End Dir : 11052.59' MD, 10239.45' TVD 11,870.04 10,712.88 1,116.34 -2,984.66 Total Depth : 11870.04' MD, 10712.88' TVD 2115/2016 1:52:20PM Page 6 COMPASS 5000.1 Build 73 Hilcorp Energy Company Soldotna CK Unit Soldotna CK Unit Soldotna CK Unit 12-3 Plan: SCU 31B-04 SCU 31 B-04 wp02 Sperry Drilling Services Clearance Summary Anticollision Report 15 February, 2016 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: Soldotna CK Unit - Soldotna CK Unit 12.3 - Plan: SCU 31 B-04 - SCU 31 B-04 wp02 Well Coordinates: 2,459,121.98 N, 347,966.38 E (60° 43'41,97" N, 1500 50'57.36" W) Datum Height: SCU 316-04 @ 162.45usft (Saxon 169) Scan Range: 6,600.00 to 11,870.04 usft. Measured Depth. Scan Radius is 1,385.20 usft . Clearance Factor cutoff Is Unlimited. Max Ellipse Separation Is Unlimited 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 HALLIBURTON Anticollision Report for Soldotna CK Unit 12-3 - SCU 31B-04 wp02 Hilcorp Energy Company Soldotna CK Unit Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: Soldotna CK Unit - Soldotna CK Unit 12.3 -Plan: SCU 31B-04 - SCU 31B-04 wp02 Swn Range: 6,500.00 to 11,870.04 usft. Measured Depth. Scan Radius is 1,385.20 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 Soldotna CK Unit Soldotna CK Unit 12-3 - SCU 12-3 - SCU 12-3 Soldotna CK Unit 12-3 - SCU 12-3 - SCU 12-3 Soldotna CK Unit 12-3 - SCU 12A-3 - SCU 12A-3 Soldotna CK Unit 12-3 - SCU 12A-3 - SCU 12A-3 Soldotna CK Unit 214 - SCU 21-4 - SCU 214 Soldotna CK Unit 214 - SCU 21A4 - SCU 21A4 Soldotna CK Unit 214 - SCU 2213-04 - SCU 22B-04 Soldotna CK Unit 214 - SCU 228-04 - SCU 22B-04 Soldotna CK Unit 214 - SCU 2213-04 - SCU 22B-04 Soldotna CK Unit 323-04 - SCU 22-04PB1 - SCU 22-0 Soldotna CK Unit 323-04 - SCU 22-04PB1 - SCU 22-0 Soldotna CK Unit 323-04 - SCU 22-04PB1 - SCU 22-0 Soldotna CK Unit 323-04 - SCU 31.04 - SCU 31-04 Soldotna CK Unit 323-04 - SCU 31-04 - SCU 31-04 Soldotna CK Unit 323-04 - SCU 31-04 PB1 - SCU 31-0 Soldotna CK Unit 33-05 - SCU 21C-04 - SCU 21 C-04 Soldotna CK Unit 332-04 - SCU 332-04 - SCU 332-04 Soldotna CK Unit 332-04 - SCU 332-04 - SCU 332-04 Soldotna CK Unit 332-04 - SCU 332-04 - SCU 332-04 Soldotna CK Unit 341-04 - SCU 341-04 - SCU 341-04 Soldotna CK Unit 341-04 - SCU 341-04 - SCU 341-04 Soldotna CK Unit 341-04 - SCU 341-04 - SCU 341-04 Soldotna CK Unit 341-04 - SCU 41A-04 - SCU 41A-04 Soldotna CK Unit 341-04 - SCU 41A-04 - SCU 41A-04 Soldotna CK Unit 341-04 - SCU 41A-04 - SCU 41A-04 Soldotna CK Unit 341-04 - SCU 418-04 - SCU 41B-04 Soldotna CK Unit 341-04 - SCU 41 B-04 - SCU 41B-04 Soldotna CK Unit 341-04 - SCU 41 B-04 - SCU 41B-04 11,870.04 720.98 11,870.04 673.95 10,375.00 15.331 Clearance Factor 11,870.04 609.95 11,870.04 563.39 10,749.61 13.101 Clearance Factor 11,820.18 968.25 11,820.18 882.24 10,447.91 11.258 Centre Distance 11,850.00 968.69 11,850.00 881.64 10,454.99 11.127 Ellipse Separation 11,870.04 969.49 11,870.04 881.72 10,459.91 11.045 Clearance Factor 11,454.74 1,342.94 11,454.74 1,233.86 11,331.00 12.311 Centre Distance 11,500.00 1,343.70 11,500.00 1,233.33 11,331.00 12.174 Ellipse Separation 11,775.00 1,380.60 11,775.00 1,262.35 11,331.00 11.675 Clearance Factor 11,477.21 347.06 11,477.21 252.73 11,775.00 3.679 Ellipse Separation 11,500.00 347.80 11,500.00 252.92 11,775.00 3.665 Clearance Factor 11,590.56 109.09 11,590.56 33.15 11,967.00 1.436 Clearance Factor 11,870.04 1,193.62 11,870.04 1,089.11 12,090.00 11.421 Clearance Factor 9,925.92 731.56 9,925.92 543.79 9,371.78 3.896 Centre Distance 10,050.00 734.54 10,050.00 540.84 9,473.38 3.792 Ellipse Separation 10,375.00 772.48 10,375.00 563.04 9,742.31 3.688 Clearance Factor 9,858.87 467.84 9,858.87 373.62 9,361.01 4.966 Centre Distance 9,875.00 467.93 9,875.00 373.42 9,374.09 4.951 Ellipse Separation 9,950.00 470.86 9,950.00 375.20 9,435.57 4.922 Clearance Factor 9,858.87 467.84 9,858.87 373.35 9,373.31 4.952 Centre Distance 9,875.00 467.93 9,875.00 373.16 9,386.39 4.937 Ellipse Separation 9,950.00 470.86 9,950.00 374.93 9,447.87 4.908 Clearance Factor 9.782.59 9,800.00 9,850.00 472.74 472.92 475.51 382.00 381.86 383.57 Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - 15 February, 2016 - 14:03 Page 2 of 5 COMPASS Hilcorp Energy Company HALLIBURTON Soldotna CK Unit Anticollision Report for Soldotna CK Unit 12-3 - SCU 31B-04 wp02 Survey Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: Soldotna CK Unit -Soldotna CK Unit 123 - Plan: SCU 318-04 - SCU 31B-04 wp02 Scan Range: 6,500.00 to 11,870.04 usft. Measured Depth. Scan Radius is 1,385.20 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 Soldotna CK Unit 341-04 - SCU 41 B-04PB1 - SCU 41B 9,725.47 487.43 9,725.47 397.93 9,208.48 5.446 Centre Distance Pass - Soldotna CK Unit 341-04 - SCU 41 B-04PB1 - SCU 41 B 9,750.00 487.81 9,750.00 397.79 9,222.28 5.419 Ellipse Separation Pass - Soldotna CK Unit 341-04 - SCU 41 B-04PB1 - SCU 41 B 9,825.00 492.69 9,825.00 401.11 9,272.80 5.380 Clearance Factor Pass - Soldotna CK Unit 341-04 - SCU 42-04 - SCU 42-04 9,858.87 467.84 9,858.87 373.62 9,368.01 4.966 Centre Distance Pass - Soldotna CK Unit 341-04 - SCU 42-04 - SCU 42-04 9,875.00 467.93 9,875.00 373.42 9,381.09 4.951 Ellipse Separation Pass - Soldotna CK Unit 341-04 - SCU 42-04 - SCU 42-04 9,950.00 470.86 9,950.00 375.20 9,442.57 4.922 Clearance Factor Pass - Soldotna CK Unit 34-33 - SCU 34-33 - SCU 34-33 11,543.38 1,283.34 11,543.38 914.36 10,505.50 3.478 Centre Distance Pass - Soldotna CK Unit 34-33 - SCU 34-33 - SCU 34-33 11,625.00 1,285.07 11,625.00 912.48 10,552.77 3.449 Ellipse Separation Pass - Soldotna CK Unit 34-33 - SCU 34-33 - SCU 34-33 11,800.00 1,300.28 11,800.00 920.77 10,654.12 3.426 Clearance Factor Pass- ass- Survey too/ program From To SurveylPlan Survey Tool (usft) (usft) 98.45 6,500.00 SR -Gyro -SS 6,500.00 11,870.04 SCU 31 B-04 wp02 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. 15 February, 2016 - 14:03 Page 3 of 5 COMPASS HALLIBURTON Anticollision Report for Soldotna CK Unit 12-3 - SCU 31 B-04 wp02 Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to SCU 31 B-04 @ 162.45usft (Saxon 169). Northing and Easting are relative to Soldotna CK Unit 12-3. Coordinate System is US State Plane 1927 (Exact solution), Alaska Zone 04. Central Meridian is -150.000, Grid Convergence at Surface is: -0.74 °. Hilcorp Energy Company Soldotna CK Unit 15 February, 2016 - 14:03 Page 4 of 5 COMPASS Ladder Plot --------- --,- --------,--- LEGEND 12 I I I 3 I Soldotrla CK Unit 12-3, SCU 12-3, SCU 12-3 VO I p SOldoina CK Unit 12-3, SCU 12A-3, SCU 12A-3 V0 SOldotna CK Unit 214, SCU 214, SCU 21 A VO C SoldotnaCKUnit214,SCU21A4,SCU 21A4V0 Soldotna CKUnft214,SCU 226-04, SCU 22B-04 V0 8 SoldonaCKUnit323-04,SCU 22-04PB1,SCU 22-04PB1 V Q C SoldoNa CK Unit 323-04, SCU 31-04, SCU 31-04 V0 � Soldotia CK Unit323-04,SCU 31-04 PBI,SCU 31-04 PB1 - - - - - - -i SoldohlaCKUnR33-05,SCU21C-04,SCU21C-04V0 SoWohIaCKUnil332-04,SCU332-04,SCU332-04V0 V Soldotna CK llnit341-04, SCU 341-04, SCU 341-04 V0 400— O I - SOldotnaCKUnd341-04,SCU41A-04,SCU41A-04VO i i I I I i SoldotnaCKUnd341-04,SCU41B-04,SCU41B-04V0 _ - - - - L - - - - - - - - L - - - - - - -I- - - - - - - - - -' - - - - Soldoha CK Unit341-04, SCU416-04PB1, SCU41 B 04PB1 I - - - - -I- - - U ! SoldohlaCKUnd341-04,SCU42-04,SCU42-04V0 i I I i I Soldona CK Unit34-33, SCU 3433, SCU 34-33 V0 0 I SCU31B-04wp02 0 2500 5000 7500 10000 12500 Measured Depth (2500 usft/in) 15 February, 2016 - 14:03 Page 4 of 5 COMPASS HALLIBURTON Anticollision Report for Soldotna CK Unit 12-3 - SCU 31 B-04 wp02 Clearance Factor Plot: Measured Depth versus Separation(Clearance) Factor Hilcorp Energy Company Soldotna CK Unit 10.00 I 8.75 LEGEND Soldotna CK Unit 12-3, SCU 12-3, SCU 123 VO 7.50 Soldotna CK Unit 12-3, SCU 12A3, SCU 12A-3 VO Soldofia CK Unit 214, SCU 21-4, SCU 214 VO N -- Soldofia CK UnR214, SCU 21 A4, SCU 21 A4 VO 6.25 `o Soldotna CKUnR214,SCU 228-04,SCU 22B -04V0 m Soldotna CKUnR323-04,SCU 22-04PBI,SCU 22-04PB1 VO LL Soldofia CK Unft323-04, SCU 31-04, SCU 31-04 VO c 5.00— .52 SoldofiaCKUnR323-04,SCU31-04PBI,SCU31-04PB1 VO Soldofia CK Unft33-05, SCU21 G04, SCU 21 C-04 VO CL rn 3.75 SoldofiaCKUnR332-04,SCU332-04,SCU332-04VO Soldofia CK UnR341-04,SCU 341-04, SCU 341-04 VO Soldofia CK Unft341-04, SCU41A-04, SCU41A-04 VO 2.50 Soldotna CK UnR341-04, SCU41 B-04, SCU41 B-04 VO Collision Avoidance Req 03o zone - Stop Drilli Soldofia CK UnR341.04, SCU41 B-04PB1, SCU41 B-04PB1 V SoldotnaCK UnR341-04, SCU 42-04,SCU42-04 VO 1.25 Soldotna CK Unit34-33, SCU 3433, SCU 34-33 VO SCU 31 B-04 vp02 0.00 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 0 Measusi Depth (2000 tsftfn) 15 February, 2016 - 14:03 Page 5 o/ 5 COMPASS Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Wednesday, February 17, 201611:16 AM To: 'Joe Kaiser' Cc: Chad Helgeson; Monty Myers Subject: RE: 180-104 Sundry 316-046 Changes in Procedure Joe, You have approval to proceed as outlined below. Based on the good cement tag and slow bleed off a collar leak is likely the culprit at the casing damage area. Setting the CIBP above the damage area will effectively isolate the reservoir and provide a base for the whipstock. Be sure to update the MOC form with this change. �!) :-16 — iLNCQ 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: Joe Kaiser [mailto jkaiser@hilcorp.com] Sent: Wednesday, February 17, 2016 11:02 AM To: Schwartz, Guy L (DOA) Cc: Chad Helgeson; Monty Myers Subject: PTD: 180-104 Sundry 316-046 Changes in Procedure Guy As discussed on the phone. The casing test didn't hold and looked similar to the test we performed on 2-15-16. It bled down from 2,550 to 2,200psig in 30 min. We believe it to be a thread leak near the obstruction at 6,786'. The balanced plug was set from 9,671' to 9,957' (cmt stinger tagged bottom). Slickline confirmed a tag at 9,671'. Please see attached CBL. I provided the CBL over the new window at 6,500' and previously submitted window at 7,500' for a CBL comparison. The cement bond is very similar at both locations. You will also notice the cement top is about 6,365'. Monty is resenting the revise PTD to change the Kick off point to 6,500'. Hilcorp proposes the changes to the SCU 12A-03 Decomplete (sundry 316-046). 1) RU E -line. 2) MU 7" CIBP and RIH. Set at ^'6,530'. (set minimum 5' from collar). POOH. 3) RD E -line. TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: Z11L _CWL = Development _ Service Exploratory _ Stratigraphic Test _ Non -Conventional FIELDr ��t T -Y2 t_v-ef� 1 L'4 / /-POOL: 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 onpermit). 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 sam les are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool SWANSON RIVER, HEMLOCK OIL - 772100 Well Name: SOLDOTNA CK UNIT 31B-04 Program DEV Well bore seg ❑ PTD#:2160100 Company HILCORP ALASKA LLC Initial Class/Type DEV / 1 -OIL GeoArea 820 Unit 51950 On/Off Shore On Annular Disposal ❑ Administration 17 Nonconven. gas conforms toA$31.05,030G.1_.A),(y2.A-D) _ _ _ - - - - _ . - - - - _ _ NA_ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ - 1 Permit_fee attached - - - - - - - - - - - - - - - - - - - - N_A---- _ _ _ Revised due to newly discovered casing damage that now required a KOP at 6500' MD rather than 7500' MD_. 2 Lease -number appropriate--- -------- - - - --- Yes . - Entire well -within former -Federal Lease_(no_w_Hilcorp Fee Lease) FEDA028997-------------- 3 Unique well name and number - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - 4 Well located in a. defined -pool - - - _ _ Yes - - . _ _ This well will_ open Swanson River, Hemlock Oil Pool - 772100 governed by CO 1236_. _ - _ _ _ _ _ _ _ 5 Well located proper distance from drilling unit_boundary------- - _ - Yes CO 1238, Rule 5: There shall be no -restrictions as to -the well -spacing -within -the _Hemlock Oil Pool except, 6 Well located proper distance from other wells_ - - - - _ - _ - Yes that_no wellbore_ maybe open to test or regular production -in a well within -5 -00' -Of the external property_ - - _ - 7 Sufficient acreage -available in_drilling unit - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ line of the Affected Area_where_the owners and landowners are_not the same_ on -both -sides of the line.— As-8 If -deviated, -is- wellbore plat included _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - - - - - . _ - - - - - _ Yes _ planned, this well—conforms—to spacing requirements._ - - - - . - _ _ 9 Operator only affected party_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - - - - Yes_ _ - 10 Operator has -appropriate bond in force _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ Yes _ _ - - - - - - _ _ _ _ - - - - - - - - _ . _ _ - _ _ - - _ - - - - - _ _ _ _ _ . _ _ _ _ - _ _ Appr Date 11 Permit can be issued -without conservation order ----------- ----- --_- Yes____ ------------- ------ -------- ---- -------_-______- 12 Permit can beissuedwithoutadministrativ_e_approval- - - - - - - -- - - - - - - - - - - - - - Yes_ - _ _ - _ _ - - - - - - - - - - - - _ _ _ _ _ _ - - - - - - SFD 2/17/2016 13 -Can permit be approved before 15 -day wait- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 14 Well located within area and -strata authorized by_ Injection Order # (put_ 10# in-comments)_(For NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 15 All wells_within 1/4_mile_area_of review identified (For service well only) - - - - - - - - - - - - - - NA_ - - - - _ - _ _ _ _ _ - - - - - - _ _ - - - - - - - - - - - - - - --- - - --- - - - - - - - - - - - - - - - - 16 Pre -produced injector; duration -of pre -production less than 3 months- (For -service well only) - N_A- - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - - - - 18 Conductor string -provided _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - _ - NA_ _ - - - - - _ Conductor set-in motherbore well. _(SCU 12A-03)_ - --- ----- --- -------------------- ---- ---- -------- Engineering Engineering 19 Surfacecasing_protectsall _knownUSDWs - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - NA_ - - - _ _ - _Surfacecasingset_ _ _ _ _ - - - - - - _ - - - - - - - 20 CMT_vol_ adequate_to circulate_on conductor & surf_csg - - - - - - - - - - - - - - - - - - - - - - NA_ - _ _ _ _ _ - Sruface casing fully cemented._ - - - _ _ - - - - - - - - - - - - 21 CMT vol adequate _to tie -in -long string to -surf csg _ _ _ _ _ - _ - - - NA - - will cut window in T' casing at 6500 ft to side -track -to 31B-04 (Casing damage at 6700 ft.)- - _ _ 22 CMT will coverall known_productive horizons_ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ - - _ Yes - - _ . _ - _ 4.5"_liner_will_ be fullycemented_back to liner lap - - - - - - 23 _Casing designs adequate for C- - B &_ permafrost- - - - - - - - - - - - - - - - - - - - _Yes - - _ - _CTB -s provided. No permafrost in area._ _ 24 Adequate tankage_ or reserve pit - - - - - - - - - - - - - - - - - - - - - - _ _ _ - - - - - - Yes - - - - _ _ Rig has steel pits-.,. all waste to approved disposal_well- - _ _ - _ - 25 -If _a_re-drill, has_a 10-403 for abandonment been approved - - - - - - - - - - - - - - - - - - - - - Yes - _ _ _ _ - _ Sundry316-046 for P &A of SCU 12A-03_ _ - - - - - - _ _ _ _ _ - - - - - - - - - _ - - _ _ _ _ - - 26 Adequate wellbore separation _proposed - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - _ _ _ - _ _ Well path diverges from motherbore_well.. SCU 12A-03 27 -If _diverterrequired, does itmeetregulations -------------------------------- NA_ _ - - - _ __Wellheadinplace..._willutilize_BOPE_-- _ _ _ _ _ - - - - - - - - - - - - - - - - - - - -- - - - - Appr Date 28 Drilling fluid_ program schematic_& equip list adequate_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - _ - - - Max formation pressure =2782 psi (5.7_ppg EMW for Hemlock) drilling with 9.5-11_.5 ppg_mud_ GLS 29 BOPEs,_do they meet regulation - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ _ - _ - _ _ - Tyonek water sands may be higher pressure_(approx 11 ppg...._But will be managed with ECD and -salt pills. 30 _B_OPE_press rating appropriate; test to -(put psig in comments)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ - _ _ _ _ MASP= 1712 psi -Will test BOPE to 3500 psi (annular to 2500 psi)_ - - - - - - - - - _ - _ _ _ _ _ _ _ - _ _ _ 31 Choke_ manifold complies w/API_RP-53(May 84)---------------------------- Yes --___ ---------------------------------------- ___-_______----_-_______-- 32 Work will occur without operation shutdown_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ - - - - - _-sund_ry_ required for well—completion—operations. _ Tubing and perfs..._ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 33 Is presence ofH2Sgas probable -------------------------------------- o________H2Snotexpected.,Righassensorsand_alarms.____________________--_____ 34 Mechanical -condition of wells within AOR verified Tor_service well only) _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ _ _ _ _ _ _ _ _ _ _ - _ - - - - - - - _ _ _ ----------------------------------------------------- 35 Permit can be issued w/o hydrogen_ sulfide measues _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ H2$ not reported fr_om_Soldotna Creek Unit or Swanson River Field._ - - _ _ - - - - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - Geology 36 Data -presented on potential overpressure zones _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ Underpressured reservoir -(3.0 to -5.2 ppg EMW)_expectedi will be drilled using 9.5-111.5 ppg mud. _ _ _ _ _ _ _ _ - - Appr Date 37 Seismic_analys_is of shallow gas -zones ----------------------------------- A_ - _ _ _ _ _ _ High-pressure _Tyonek Water Sand (11.5-12.5 ppg) lies at about 9100'_MD/ 8900' TVD._Hilcorp SFD 2/17/2016 38 Seabed condition survey -(if off_ -shore) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ _ - _ - - - _ weights Lip -to -11.5 ppg_and kills any flow with ECD while drilling. Before tripping, heavy pills are _ 39 Contact_name/phone for weekly_ progress reports_ [exploratory only] _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ _ - _ _ _ - _ spotted to stop any _flow. _Any flow is treated as gas until Hilcorp is certain that it is- NOT gas- _ _ _ _ _ _ _ _ _ _ Geologic Engineering Public Revised permit application for redrill of existing well SCU 12A-03; will now cut window in 7" at 6500 ft MD rather than previously Commissioner: Date: Commissio er: Date Commissioner Date permitted 7500' MD. Cement behind window verified with CBL. SFD/ GLS DTS 2- F ' THE STATE of ALASKA GOVERNOR BILL WALKER Monty Myers Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.olaska.gov Re: Soldotna Creek Field, Hemlock Oil Pool, SCU 31 B-04 Hilcorp Alaska, LLC Permit to Drill Number: 216-010 Surface Location: 2032' FNL, 359' FWL, SEC. 3, T7N, R9W, SM, AK Bottomhole Location: 917' FNL, 2631' FEL, SEC. 4, T7N, R9W, SM, AK Dear Mr. Myers: Enclosed is the approved application for permit to re -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 f X-�a� Cathy V Foerster Chair DATED this Z8 day of January, 2016. RECEIVED STATE OF ALASKA A, KA OIL AND GAS CONSERVATION COMM. ON JAN 15 2016 PERMIT TO DRILL 20 AAC 25.005 1 a. Type of Work: 1h Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ 1 c. Specify if well is proposed for: Drill ❑ Lateral ❑ Stratigraphic Test ❑ Development - Oil Q Service - Wrnj ❑ Single Zone 7 Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑✓ Reentry ❑ Exploratory - Oil ❑ Development -Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket M . Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 - SCU 31 B-04 . 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 5-/1-c Lt 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 MD: 12,167' TVD: 10,701' Soldotna Creek Unit , Hemlock Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 2032' FNL, 359' FWL, Sec 3, T7N, R9W, SM, AK A028997 - Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 1427' FNL, 1197' FEL, Sec 4, T7N, R9W, SM, AK N/A 2/16/2016 Total Depth: 9. Acres in Propertv: 14. Distance to Nearest Propertv: 917' FNL, 2631' FEL, Sec 4, T7N, R9W, SM, AK 2560 6722' to nearest unit boundary . 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 162.5' 15. Distance to Nearest Well Open Surface: x-347966 y- 2459121 Zone -4 GL Elevation above MSL (ft): 144.5' to Same Pool: 936' SCU 31-04 16. Deviated wells: Kickoff depth: 7,500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 54 degrees Downhole: 2782 Surface: 1712 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) 6" 4-1/2" 12.6# L-80 DWC/C 4,867' 7,300' 7,300' 12,167' 10,701' 488 sx 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): 10,850' 10,845' 10,555' 10,555' 10,552' N/A Casing Length Size Cement Volume MD TVD Conductor/Structural 28' 22" Yes 28' 28' Surface 3,000' 13-3/8" 1792 sx 3,000' 3,000' Intermediate 10,265' 7" 2608 sx 10,265' 10,263' Production Liner 803' 5" 860 sx 10,848' 10,839' Perforation Depth MD (ft): See attached schematic of 12A-03 Perforation Depth TVD (ft): See attached schematic of 12A-03 20. Attachments: Property Plat ❑✓ BOP Sketch ❑✓ Drilling Program Q Time v. Depth Plot ❑✓ Shallow Hazard Analysis❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requirements0 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Monty Myers Email mm ers hilcor .com Printed Name Monty Myers Title Drilling Engineer Signature Phone 777-8431 Date 1/15/2016 Commission Use Only Permit to Drill / J API Number. 2 / ` f, 'Z_- Permit Approval See cover letter for other Number:/ 'C- / 50-t' ✓�'-/�%v��- Date: g y 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: Other:___? y` -SOeo 1 -C �� Samples req'd: Yes ❑ No[� Mud log req'd: Yes No0 H2S measures: Yes ❑ No❑, Directional svy req'd: Yes [0 No❑ Spacing exception req'd: Yes ❑ No M Inclination -only svy req'd: Yes ❑ Noa Post initial injection MIT req'd: Yes ❑ No❑ Approved APPROVED BY l- by: COMMISSIONER THE COMMISSION Date: e__457 �� l in& [fjoA Submit Form and Form 10-401 (Re d 11/2015) 6h® onths from the date of approval (20 AAC 25.005(g)) Attachmentsin Du )icate vvffT� � 0 Hilcorp EncW Company 1/15/2016 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 Re: SCU 31 B-04 Dear Commissioner, Monty Myers Drilling Engineer JAN 15 2016 Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8431 Email mmyers@hilcorp.com SCU 3113-04 is an oil production well planned to be re -drilled in a North-westerly direction from the existing SCU 12A-03 utilizing the existing casing program down to 7500' MD / 7500' TVD. -7 "cam - At 7500' MD the parent wellbore will be sidetracked and new wellbore drilled penetrating several Hemlock targets. A 4867'x 6" open hole section is planned. A 4-1/2" 12.6# L-80 DWC/C prod liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with 2-7/8" production string. r4 Drilling operations are expected to commence approximately February IB', 2016. If you have any questions, please don't hesitate to contact myself at 777-8431 or Paul Mazzolini at 777-8369. Sincerely, i Monty Myers Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 Hilcor p Alaska, LLC SCU 31B-04 (SCU 12A-03 ST) Drilling Program Soldotna Creek ro d by: M My Revision 0 January 14, 2016 SCU 31 B-04 Drilling Procedure Rev 0 Ililvorp Alaska. L1.1: Contents 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program............................................................................................................................4 4.0 Drill Pipe Information.....................................................................................................................4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling Summary............................................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 R/U and Preparatory Work..........................................................................................................11 26.0 10.0 BOP NIU and Test.........................................................................................................................12 27.0 11.0 Mud Program and Density Selection Criteria............................................................................13 28.0 12.0 Whipstock Running Procedure....................................................................................................14 29.0 13.0 Whipstock Setting Procedure.......................................................................................................17 30.0 14.0 Drill 6" Hole Section......................................................................................................................19 31.0 15.0 Run 4.5" Production Casing.........................................................................................................22 16.0 Cement 4.5" Production Casing...................................................................................................25 17.0 Wellbore Clean Up & Displacement............................................................................................29 18.0 Run Completion Assembly...........................................................................................................30 19.0 RDMO............................................................................................................................................30 20.0 BOP Schematic..............................................................................................................................31 21.0 Wellhead Schematic......................................................................................................................32 22.0 Days vs Depth.................................................................................................................................33 23.0 Geo-Prog.........................................................................................................................................34 24.0 Anticipated Drilling Hazards.......................................................................................................35 25.0 Rig Layout......................................................................................................................................36 26.0 FIT Procedure................................................................................................................................37 27.0 Choke Manifold Schematic...........................................................................................................38 28.0 Casing Design Information...........................................................................................................39 29.0 6" Hole Section MASP..................................................................................................................40 30.0 Plot (NAD 27) (Governmental Sections)......................................................................................41 31.0 Surface Plat (As Built) (NAD 27).................................................................................................42 32.0 Surface Plat (As Built) (NAD 83).................................................................................................43 33.0 Directional Program(Pl)..............................................................................................................44 0 IlileogP UaAa.. LLC 1.0 Well Summary SCU 31 B-04 Drilling Procedure Rev 0 Well SCU 31B-04 Pad & Old Well Designation Sidetrack of existing well SCU 12A-03 (PTD# 180-104) Planned Completion Type 4-1/2" 12.6# L-80 Liner Target Reservoirs Hemlock Producer H1 -H8 Planned Well TD, MD / TVD 12167' MD / 10701' TVD PBTD, MD / TVD 12000' MD / 10604' TVD Surface Location (Governmental) 2032' FNL, 359' FWL, Sec 3, UN, R9W, SM, AK Surface Location (NAD 27) X=347966.38, Y=2459121.98 Surface Location (NAD 83) X=1487989.257, Y=2458883.157 Top of Productive Horizon (Governmental) 1427' FNL, 1197' FEL, Sec 4, UN, R9W, SM, AK TPH Location (NAD 27) X=346416.21, Y=2459750.93 TPH Location (NAD 83) X=1486439.057, Y=2459512.159 BHL (Governmental) 917' FNL, 2631' FEL, Sec 4, UN, R9W, SM, AK BHL NAD 27) X=344988.21, Y=2460279.85 BHL (NAD 83) X=1485011.029, Y=2460041.128 AFE Number 1610111D AFE Drilling Das 14 AFE Drilling Amount $3.00 MM Work String 4-1/2" 16.6# S-135 CDS-40 RKB — AMSL 18' KB — 162.5' AMSL Ground Elevation 144.5' AMSL BOP Equipment 11" 5M T3 -Ener (Model 7082) Annular BOP 11" 5M T3 -Ener (Model 6011i) Double Ram 11" 5M T3 -Ener (Model 6011 i) Single Ram Page 2 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 Ililcorp Alaska, LLC. 2.0 Management of Change Information Hilcorp Alaska, LLC HWWilcorp Changes to Approved Permit to Driii Date: January 14, 2016 Subject: Changes to Approved Permit to Drill for SCU 31B-04 (SCU 12A-03 ST) File #: SCU 31B-04 (SCU 12A-03 ST) Drilling Program Any modifications to SCU 31 B-04 Drilling Program will be documented and approved below. Changes to an approved APD will be communicated and approved by the BLM and AOGCC prior to continuing forward with work. Approval: Drilling Manager Approved I Approved Date Prepared: Drilling Engineer Date Page 3 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 Ililcorp Alaska, LLC 3.0 Tubular Program - ID in Drift in Grade Conn To Bottom 6" 4-1/2" 12.6 5.0" 3.918 3.833 L-80 DWC/C 7300 12167 S-135 CDS-40 17693 16769 595k 4.0 Drill Pipe Information Hole OD (in) Section ID (in) TJ 1D in TJ OD in(#/ft) Wt Gracie Conn Burst (psi) Collapse (psi) Tension (k -lbs) 6" 4-1/2" 3.826 2-11/16" 5-1/4" 16.6 S-135 CDS-40 17693 16769 595k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 Ilde—p AlaAa. HA: 5.0 Internal Reporting Requirements 19.1 Fill out daily drilling report and cost report on Wellez. i. Report covers operations from 6am to 6am ii. Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry tab. iii. Ensure time entry adds up to 24 hours total. iv. Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 19.2 Afternoon Updates i. Submit a short operations update each work day to pmazzolini(chilcorp.com, lkeller@a hilcorp.com, mmyers@hilcorp.com and cdinger@hilcorp.com 19.3 5am Weekend Update i. Submit a short operations update each weekend and holiday to whoever is assigned weekend or vacation duty. Details will be sent before each weekend or holiday. ii. Copy pmazzoliniAhilcorp.com, lkeller@hilcorp.com and mmyers@hilcorp.com 19.4 EHS Incident Reporting i. Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don't wait until an emergency to have to call around and figure it out!!!! a. John Coston: O: (907) 777-6726 C: (907) 227-3189 b. Mark Tornai: O: (907) 283-1372 C: (907) 748-3299 c. Thad Eby: O: (907) 777-8317 C: (907) 602-5178 2. Spills: Julieanna Orczewska: 0:907-777-8444 C:907-715-7060 ii. Notify Drlg Manager 1. Paul Mazzolini: O: 907-777-8369 C: 907-317-1275 iii. Submit Hilcorp Incident report to contacts above within 24 hrs 19.5 Casing Tally i. Send final "As -Run" Casing tally to mmyers cghilcorp.com and cdinger@hilcorp.com 19.6 Casing and Cmt report i. Send casing and cement report for each string of casing to mmyersghilcorp.com and cdingerghilcorp.com Page 5 Revision 0 January, 2016 6.0 Planned Wellbore Schematic SCU 31 B-04 Drilling Procedure Rev 0 13-318" Soldotna Creek Unit Well SCU OD PTO= XXX -XXX -XXX Sete PROPOSED SCHEMATIC API: 50-133-XXXXX-XX Top Btm 13-318" IFWFI RY nFTAIt Na CASING AND TUBING DETAIL OD 1 Sete IVT Grade Conn ID Top Btm 0:039' KOP 22- 7300'- 123a7' 3.918" surfaEe2a' 13-3/9' 34.3 10.030 Surface 3,000' 7- 29 P-110 0..184 Surface '75 CLQ, C — , IFWFI RY nFTAIt Na Depth 10 OD 1 7300" 7" X 4-U2" 27tH Hoer han3er 2 73ow 0:039' KOP 3 7300'- 123a7' 3.918" 4-3' 4-1/2" 12.58 L-80 OWC/C parer CEMENT DETAIL 44,2 -liner will be cemented from TD to linger hanger tap with a minimum of 90 bbls of 15.3ppg class G cement 2 0- Mndaw milled at 7300` TMD 7- -7 <A ,ZAr,y 3 i JO -1/2' TO = 12,167' TVD = 10,701' MAX HOLE ANGLE = 55 deg. At 9,319' TMD Page 6 Revision 0 January, 2016 Soldotna Creek Unit Well SCU 12A-03 Completion Ran: 7/20/13 ACTUAL SCHEMATIC xii�o Al -k.. LLC API: 180-104 API : 50-133-10099-01 Orig. RKB = 26'4 New RKB = 11' CASING AND TUBING DETAIL AtA" 1 22" Suspected B Hole in Tubing (Shallow) Tubing C Anchor possibly unset E 8 9 10 11 12 2 3 L7" H-2 H-3 H-4 H-5 H-6 13' H-8 H-8 14 t H-10 13-3/8" t Size WT Grade Conn ID Top Bt 22" - - 2-7/8" Seaboard Tubing Hanger, Type 'H' BPV Surface 28' 13-3/8" 54.5 2-7/8" Depth Indicator Sub 10.050 Surface 3,000' 7" 29 P-110 6.184 Surface 10,265' 5" 18 N-80 4.276 10,045' 10,848' TUBING 2-7/8" 6.5 L-80 EUE 8RD 2.441 Surface 9,989' JEWELRY DETAIL No Depth ID OD Item 1 24' - - 2-7/8" Seaboard Tubing Hanger, Type 'H' BPV 2 4,297' 2.441" 5.000" 2-7/8" Depth Indicator Sub 3 9,918' 2.420" 5.530" Tubing Anchor 4 9,951' 2.255" 2.875" Seating Nipple 5 9,952' 2.441" 2.875" Slotted Flow Sub 6 9,956' 2.992" 3.500" 1 joint 3-1/2" tubing, EUE 8RD (Gas Anchor) 7 9,988' - 3.500" Bull Plug E 9,919' 25' 1-3/4" 1-3/4" x 25' Insert Pump, RHBC Pump w/ PA Ring 8' 6 7/9/97 H-8 The following set on E -Line 8 10,095' 2.688" 3.968" Packer, 2-7/8 x 5" Baker Mod. 'D' 9 10,097' 2.688" 3.650" Seal Bore Extension, 9.45' Long 10 10,107' 1.995" 3.750" Crossover, Seal Bore Extension x 2-3/8" Butt Pin 11 10,114' 1.875" 2.700" 'XN' Nipple, 2-3/8" EUE 8rd, 2.313 w/ 2.25" N.G. 12 10,121' 1.995" 2.880" WLREG 13 10,555' - - Posiset Plug 14 10,699' Baker Mod. K-1 Retainer ROD DETAIL No Depth Le OD Item Amt SPF Comments 26' 1-1/2" Polished Rod (New 6/18/14) B 37' 4' 1" 1" Pony Rods (4') 7/9/1997 41' 2,725' 1" 1" x 25' EL Sucker rods w/ 4 XL guides per rod (109) 10,447' 2,766' 2,900' 7/8" 7/8" x 25' EL Sucker rods w/ 4 XL guides per rod (116) 10,460' 5,666' 3,900' 3/4" 3/4" x 25' EL Sucker rods w/ 4 XL guides per rod (156) C 9,566' 350' 1-1/2" 1-1/2" x 25' K Bars (weight bars) D 9,916' 2.5' 1" 2-1/2" x 2.5' Stabilizer Bar w/ %" Pins E 9,919' 25' 1-3/4" 1-3/4" x 25' Insert Pump, RHBC Pump w/ PA Ring 8' 6 7/9/97 H-8 80 PA Ring, Sand Seal, 2-1/2" x 1-3/4" x 24" x 24-1/2" x 25' RHBC (New 11/06/14) F 9,944' 1' 1.315" Sand Screen G 9,945' 2.54' 1.250" 1-1/4" Memory Gauge (Welded coupling to screen) PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt SPF Comments Date H-2 10,410' 10,428' 10,407' 10,425' 18' 10-14 7/9/1997 H-3 10,442' 10,450' 10,439' 10,447' 8' 10 7/9/97 H-4 10,460' 10,478' 10,457' 10,475' 18' 6-10-14 7/9/97 H-5 10,487' 10,530' 10,484' 10,527' 43' 6 3/11/00 H-6 10,540' 10,548' 10,536' 10,544' 8' 6 7/9/97 H-8 10,560' 10,590' 10,556 10,586' 30' 10 7/9/97 H-8 10,598' 10,602' 10,594' 10,598' 4' 4 2/84 H-10 10,716' 10,730' 10,711' 10,725' 14' Casing Split 4 (Isolated) 12/82 5" PBTD = 10,699' TD = 10,850' MAX HOLE ANGLE = 7 deg. At 10,700' Downhole Revised: 12/26/14 Updated by STP 12/31/14 SCU 31 B-04 Drilling Procedure Rev 0 Ililcorp Alaska,1.L1: 7.0 Drilling Summary SCU 31 B-04 is an oil production well planned to be re -drilled in a North-westerly direction from the existing SCU 12A-03 utilizing the existing casing program down to 7500' MD / 7500' TVD. At 7500' MD the parent wellbore will be sidetracked and new wellbore drilled penetrating several Hemlock targets. A 4867' x 6" open hole section is planned. A 4-1/2" 12.6# L-80 DWC/C prod liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with 2-7/8" production string. Drilling operations are expected to commence approximately February 16th, 2016. 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. t z —Q 3 A separate sundry notice will be submitted to cover P&A and wellbore preparation for the sidetrack and for running the completion assembly f - S& - O q General sequence of operations pertaining to this approved drilling procedure: w 1. Saxon Rig #169 is on SCU 12A-03 to decomplefe and P&A well. - F�� c��A 2. PU 6.059" window milling assembly and DP and cleanout to CIBP at 7500' t 3. POOH standing back, PU Whipstock, and mills and TIE to CIBP� 4. Orient whipstock and set at 280 deg azimuth. % G 5. Mill " window and 20' of new formation t ` 6. POOH and LD mills. PU directional BHA and TIH to window. 7. Swap well to 9.5 ppg drilling mud 8. Perform FIT to 12.5 ppg EMW ?,0 9. Drill 6" production hole from 7500' to 12167' MD, performing short trips as needed r 10. Perform short trip and condition mud. POOH 11. LD Directional Tools. RIH w 4-1/2" liner. Set liner and cement. Circ wellbore clean. 12. POOH, laying down DP and liner running tools, 13. PU 4-1/2" casing scraper assembly and TIH to landing collar. 14. Circ casing clean. POOH laying down DP. 15. Run 2-7/8" completion. Land hanger and test. 16. ND BOPE, NU tree and test void 17. RDMO Page 7 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling of SCU 31B-04. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 10/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to .shut in on the well in a well control situation, we must test ALL BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system" • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements" • Ensure both AOGCC and BLM approved drilling permit is posted on the rig floor and in Co Man office. Variance Requests: • Onshore Oil and Gas Order No. 1, Section III. D. 3. C. o Hilcorp requests approval to install a 2-1/16" 5M HCR valve on kill line in lieu of a check valve. Operator suspects a freeze plug risk associated with installation of a check valve in the kill line. o Hilcorp requests approval to utilize flexible choke and kill lines in lieu of hard piping. Page 8 Revision 0 January, 2016 Ilileurl) Alaska.. LLC Summary of BOP Equipment and Test Requirements SCU 31 B-04 Drilling Procedure Rev 0 Hole Section Equipment Test Pressure(psi) • 1 F x 5M T3 -Energy (Model 7082) Annular BOP • 11" x 5M T3 -Energy Double Ram Initial Test: 250/3500 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross 6" • 11" x 5M T-3 Energy Single Ram • 3-1/8" 5M Choke Line Subsequent Tests: • 2-1/16" x 5M Kill line 250/3500 • 3-1/8" x 2-1/16" 5M Choke manifold (Annular 2500 psi) • Standpipe, floor valves, etc • Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: • Well control event (BOPs utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Required BLM Notifications: • 48 hours before spud. Follow up with actual spud date and time. • 48 hours before casing running and cmt operations • 48 hours before BOPE tests • 48 hours before logging, coring, & testing • Any other notifications required in APD. Additional requirements may be stipulated on APD. Page 9 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 Ililcorp Alaska, MX Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector/ (0): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer/ (0): 907-793-1226 / (C): 907-301-4533 / Email: guy. schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: victoria.loepp c@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/oac/forms/TestWitnessNotifhtml Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) BLM Amanda Eagle / BLM Petroleum Engineer / (0): 907-271-3266 (C): 907-538-2300 Email: aeagle@blm.gov Mutasim Elganzoory / BLM Petroleum Engineer / (0): 907-271-4224 Email: melganzooryna,blm.gov Use the below email address for BOP notifications to the BLM: BLM AK AKSO EnergySection Notifications@bhn.gov Page 10 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 nilemp Alaska. LIA: 9.0 R/U and Preparatory Work 9.1 Separate sundries will be submitted that will include the following: • Pull rods -- A` o-- -tL- '(O( �., �� 31� - 02-C! • P&A lower perfs with a cement plug cam - Q` • Set CIBP 9.2 Level pad and ensure enough room for layout of rig footprint and R/U. 9.3 Layout Herculite on pad to extend beyond footprint of rig. 9.4 R/U Saxon Rig #169, spot service company shacks, spot & R/U company man & toolpusher offices. 9.5 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.6 Mix mud for 6" hole section. 9.7 Check wellhead for pressure 9.8 Load well with 8.4 ppg KWF 9.9 Set BPV 9.10 Nipple down tree 9.11 Set test Plug in wellhead prior to N/U BOP to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.12 Verify 5" liners installed in mud pumps. • HHF-1000 Pumps are rated at 3457 psi (80%) with 5" liners and can deliver 306 gpm at 120 spm. This will allow us to drill the 6" hole section with (1) mud pump. Page 11 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 Ililcurp Alaska, LI.1: 10.0 BOP N/U and Test 10.1 * BOPE was NU and tested on prior decompletion sundry. We will test BOPE on 7 day cycle until the window is milled, at that point we will switch to the 14 day test cycle. Continue on to step 11. 10.2 N/U 11"x 5M BOP as follows: • BOP configuration from Top down: 11" x 5M annular BOP/11" x 5M double ram/l 1" x 5M mud cross/11" x 5M single ram. • Double ram should be dressed with 2-7/8" x 5" VBR in top cavity, blind ram in btm cavity. • Single ram should be dressed with 2-7/8" x 5" VBR. • N/U bell nipple, install flowline. 10.3 Run BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/3500 psi for 10/10 min. Test annular to 250/2500 psi for 10/10 min. • Ensure to leave "A" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Confirm the correct valves are opened! ! ! • Test VBRs on 4-1/2" test joint. • Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 10.4 R/D BOP test assy. 10.5 Continue mixing mud for 6" hole section. 10.6 Set wearbushing in wellhead. Ensure ID of wearbushing > 7". Page 12 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 uileorjo llaska.1.1.1: 11.0 Mud Program and Density Selection Criteria 11.1 6" Production hole mud program summary: Primary weighting material to be used for the hole section will be Calcium Carbonate to minimize solids. We will have barite on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.5 ppg 6% KCI/PHPA fresh water based drilling fluid. Properties: MD Density Viscosity Plastic Viscosity Yield Point pH AN Fluid 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) EZ MUD DP 0.75 ppb (initially 0.25 ppb) DEXTRID LT Loss 7500'- 12167' • 9.5-11.5 • 40-53 15-25 15-25 8.5-9.5 156.0 System Formulation: 6% KCI / EZ Mud DP 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) EZ MUD DP 0.75 ppb (initially 0.25 ppb) DEXTRID LT 1-2 ppb PAC -L 1 ppb BARACARB 5/25/50 10-20 ppb BAROTROL PLUS 2 ppb SOLTEX 2 ppb (if needed) BAROID 41 as required for a 9.5 — 10.5 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 ppb (maintain per dilution rate 11.2 Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated BHP's from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. 11.3 A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead. Page 13 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 Ililcorp :%IaAa. 1.1.1: 12.0 Whipstock Running Procedure 12.1 M/U window milling assembly and TIH w/ 4-1/2" DP out of derrick. • Use a 6" taper mill and a 6" string mill above to ensure whipstock assy will pass freely. • Ensure BHA components have been inspected previously. • Caliper and drift all BHA components before running them in the hole. • Drift DP prior to RIH. Lightly wash and ream any tight spots noted. 12.2 TIH to CIBP (7500' MD). Note that this was a wireline measurement so actual depth tagged may vary slightly. Keep up with the # of joints picked up so we know where we are. 2.3 Pressure test casing to 2500 psi / 30 min. Chart record casing test & keep track of the amount of fluid pumped. Stage up to 2500 psi in 500 psi increments. 12.4 CBU & circ at least (1) hi -vis sweep to remove any debris created by the clean out run. Anything left in the wellbore could affect the setting of the Whipstock. 12.5 TOR 12.6 Makeup mills on a joint of HWDP. 12.7 RIH & set in slips. 12.8 Make up float sub, install float. 12.9 Make up UBHO sub. 12.10 Orient UBHO to starter mill. 12.11 Leave assembly hanging in the elevators, and stand back on floor. 12.12 Bring Whipstock to rig floor on the pipe skate. Do not slam into bottom of Whipstock with pipe skate. 12.13 Pick up Whipstock per Baker rep using the Baker Whipstock handling system using air hoist. Allow assy to hang while Baker Rep inspects and removes shear screws as needed and any safety screws. Note: Anchor should be pinned with 6 shear screws initially. Shear screws are rated for 6,630 lbs each. REMOVE 3 screws for a set down shear of 6,630 x 3 =19,890 lbs. Note: Attach mills to Whipstock with (1) 35k mill shear bolt. Page 14 Revision 0 January, 2016 12.14 If needed, open BOP Blinds. SCU 31 B-04 Drilling Procedure Rev 0 12.15 Run the Whipstock in the hole, install safety clamp as per Baker Rep, and install hole cover wrap. 12.16 Release pick up system at this point, Make up mills. 12.17 With the top drive, pick the assembly and position the starting mill to align with the hole in the slide. The Baker Rep will instruct the driller when the slot is lined up, the shear bolt then can be made up by the Baker Rep. 12.18 The assembly can now be picked up to ensure that the shear bolt is tight. 12.19 Remove the handling system. 12.20 Slowly run in the hole as per Baker Rep. Run extremely slow through the BOP & wear bushing. 12.21 Run in hole at 1 '/z to 2 minutes per stand. 12.22 Fill every 30 stands or as needed, do not rotate or work the string unnecessarily. 12.23 Call for Baker Rep. 15 — 10 stands before getting to bottom. 12.24 Orient at least 30' — 45' above the CIBP. Ensure to have gyro personnel and equipment as well as a wireline unit R/U and ready. Page 15 Revision 0 January, 2016 Iliivurp Ua'ka. LIA: SCU 31 B-04 Drilling Procedure Rev 0 WindowMaster G2 System on TorqueMaster BTA 7" 29# Csg — WindowMaster G2 On BTA BHA #1 onnection Length O.D. BOTTOM TRIP ANCHOR Y. IF -Box X Bottom Guide 3.21' 6.18" WINDOW MASTER WHIPSTOCK hear Bolt X 3 Y. IF -Pin 14.6' 6.00" WINDOW MILL -1/2 Reg -Pin X Mill 1.5' 6.63" LOWER WATER MELON MILL -1/2 IF -Box X 3-1/2 Reg -Box 5.5' 6.50" FLEX JOINT -1/2 IF- Box X 3-1/2 IF -Pin 6.6' 4.75" UPPER WATER MELON MILL -1/2 IF- Box X 3-1/2 IF -Pin 5.8' 6.63" 11T HWDP -1/2 IF -Box X 3-1/2 IF -Pin 30' 5.25" MWD Survey Tool -1/2 IF -Box X 3-1/2 IF -Pin 3' 4.75" UBHO -1/2 IF -Box X 3-1/2 IF -Pin 3' 4.75" Bowen Lubricated Bumper Jar -1/2 IF -Box X 3-1/2 IF -Pin 15' 4.75" 6 DRILL COLLARS -1/2 IF -Box X 3-1/2 IF -Pin 180' 4.75" 301TS — HWDP -1/2 CDS40 Box X 4-1/2 CD540-Pin 900' 4.75" CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE. BHA'S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY Page 16 Revision 0 January, 2016 0 IIilcorp Alaska. LLC 13.0 Whipstock Setting Procedure SCU 31 B-04 Drilling Procedure Rev 0 13.1 With the bottom of the Whipstock 30 — 45' above the CIBP, measure and record P/U and S/O weights. We will orient Whipstock face using Gyrodata. Ensure that UBHO and gyro tool mate up properly before making up UBHO sub. 13.2 Orient Whipstock to desired direction by turning DP in 1/4 round increments. P/U and S/O on DP to work all torque out (Being careful not to set BTA). Whipstock Orientation Diagram: 270 AZI 315 AZI Desired orientation of the Whipstock face is in 270 to 315 degrees azimuth. Hole Angle at window interval (7500' MD) is < 1 deg. The wellbore trajectory is also planned to 290 degrees azimuth. Highside of the casing at 7500' is negligible. 13.3 Once Whipstock is in desired orientation, slack off and tag CIBP to set Bottom Trip Anchor. 13.4 Set down 12-15K on anchor to trip, P/U 5-7K maximum overpull to verify anchor is set. The window mill can then be sheared off by slacking off weight on the Whipstock shear bolt. (25k shear value). 13.5 P/U 5-10' above top of Whipstock. 13.6 Displace to 9.5 ppg 6% KCl/PHPA drilling fluid. 13.7 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window. Utilize 4 ditch magnets on the surface to catch metal cuttings. 13.8 Install catch trays in shaker underflow chute to help catch iron. 13.9 Keep iron in separate bbls. Record weight of iron recovered on ditch magnets. Page 17 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 Ililrorp Alaska, LI.0 13.10 Estimated metal cuttings volume from cutting window: 7„ 3 Y2 REG -P X MILL 29# N-80 Cuttings Weight Window 3 Y2 IF -B X 3 Y2 REG -B 5.5 6.5 FLEX JOINT Length Casing Weight Min (lbs) Avg (Ibs) Max (lbs) 13 29.7# 1 80 110 140 13.11 Drill approx. 20' rat hole to accommodate the drilling assembly. Ream window as needed to assure there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through window checking for drag. 13.12 Circulate Bottoms Up until MW in = MW out. 13.13 Conduct FIT to 12.5 Ppg, EMW. .f / \` • (12.5 — 9.5) * 0.052 * 7500' tvd = 1170 psi £A 13.14 Kick Tolerance ¢ • (12.5 -9.5) * (7500/10701) = 2.10 6(1 -- Note: (1 --Note: Offset field test data predicts frac gradients at the window to be between 12 ppg and 15 ppg. A 12.5 ppg FIT results in a 2.10 ppg kick tolerance while drilling the interval with a 9.5 ppg fluid density. 13.15 Slug pipe and POOH. Gauge Mills for wear. 13.16 Should a second run be required pick up the following BHA. Back Un Mills Connection Lenath O.D. WINDOW MILL 3 Y2 REG -P X MILL 0.98 6.63 NEW LOWER WATERMELON MILL 3 Y2 IF -B X 3 Y2 REG -B 5.5 6.5 FLEX JOINT 3 Y IF -13 X 3'/ IF -P 6.5 4.75 UPPER WATERMELON MILL 3 %" IF -13 X 3'/2" IF -P 5.83 6.63 FLOAT SUB 3'/2" IF -13 X 3'/" IF -P 3.00 4.75 XO sub and 30 jts-HWDP 41/2" CDS40-B X 3'/" IF -P 900' 5.25 CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE. BHA'S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY.! Page 18 Revision 0 January, 2016 14.0 Drill 6" Hole Section 14.1 P/U 6" directional drilling assy. 14.2 Ensure BHA Components have been inspected previously. SCU 31 B-04 Drilling Procedure Rev 0 14.3 Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 14.4 Ensure TF offset is measured accurately and entered correctly into the MWD software. 14.5 Confirm that the bit is dressed with a TFA of 0.46 — 0.56 sqin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 150 - 250 gpm. 14.6 Motor AKO should be set at 1.2 deg. Must keep up with 3 deg/100 DLS in the build section of the wellbore. 14.7 Primary bit will be the Varel 6" V613DUX PDC bit. Ensure to have a back up bit available on location. Page 19 Revision 0 January, 2016 V/ Ilile—lo Ala,ka. 1.1.1: Tool10912 Assembly, A30010 IADC Coder M332 s SCU 31 B-04 Drilling Procedure Rev 0 Voyager.,'`J 11�r.ir PRODUCT SPECIFICATIONS Cutter Size: 13 mm Cutter Back Up: Total Cutter Count: Face Cutter Count: Connection: Nozzle 1 Qty/Type: Nozzle 2 Oty/Type: Junk Slot Area: Gage Pad Length: Make Up Length: Shank Diameter: Carbide Shock Studs OPERATING PARAMETERS* 39 21 31/2" API Regular 6 - Series 55 5.2in2 (33.5cml) 3" (76mm) 10.1" (257.6mm) 4.9" (124.5mm) Rotary Speed: For all rotary and motor applications Flowrate Min -Max: 150 - 350GPM (0.57-1.32ma/min) Max Weight On Bit: 28,000lbs (12455daN) Makeup Torque: 7000 - 9000Ft-Lbs. (9491-12202Nm) ' C"ratinq paraaneters shear, are typical for ffi7e Da type specifte Fca recurnrnendatioqas on four sped, application- contact your varel Inte-matwal repeeser+tative- Voyager Series Bits - Voyager series bits utilize Varel's proprietary design, modeling, and programming software coupled with specialized manufacturing techniques to create the optimal drill bit for your fit -tor -purpose applications. Engineered though Varel simulator Suite for specific directional applications, Voyager bits incorporate the latest design features to maximize cuttings removal, enhance ROP potential, improve directional response, and create a more durable bit frame to aid in accomplishing your aggressive directional drilling objectives. Bit Features D - Drop in cutter in gage pad. U - PDC cutters strategically placed to help reduce hole problems when up drilling or back reaming. X - Shock studs limit drill bit vibration and Increase stability allowing smooth cutting action increasing cutter life and overall bit performance. Page 20 Revision 0 January, 2016 J SCU 31 B-04 Drilling Procedure Rev 0 Ililvorp Alaska.. L1.1: 14.8 TIH to window. Shallow test MWD on trip in. 14.9 TIH through window, ensure Halliburton MWD service rep on rig floor during this operation. • Do not rotate string while bit is across face of Whipstock. 14.10 Drill 6" hole to 12167' MD using motor assembly. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Utilize ECD while pumping to minimize waterflow from Tyonek sands, • On trips spot weighted pills inside window and hi vis pills at TD to control waterflow • Try to keep waterflow below 10 bph while tripping • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • See attached mud program for hole cleaning and LCM strategies. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. • Ensure mud engineer set up to perform HTHP fluid loss. • Maintain API fluid loss < 6. • Take MWD surveys every stand drilled. • Minimize backreaming when working tight hole 14.11 Hilcorp Geologists will follow mud log closely to determine exact TD. 14.12 At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU, and pull a wiper trip back to the window. 14.13 TOH with drilling assembly, handle BHA as appropriate. Page 21 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 Ilile—lo llaska. LH: 15.0 Run 4.5" Production Casing 15.1 R/U Weatherford 4.5" casing running equipment. • Ensure 4.5" DWC/C x 4-1/2" CDS-40 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted and tally verified prior to running. • Be sure to count the total # of joints before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 15.2 P/U shoe joint, visually verify no debris inside joint. 15.3 Continue M/U & thread locking shoe track assy consisting of: • (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). • (1) Baker locked joint. • (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). • (1) Joint with landing collar bucked up. • Rigid or Solid body centralizers will be pre-installed on shoe joint, FC joint, and LC joint. • Install centralizers, one per joint, and leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe & FC. 15.4 Continue running 4.5" production casing • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. • Install solid body centralizers on every other joint to window. Leave the centralizers free floating. Utilize a collar clamp until weight is sufficient to keep slips set properly. 4.5" DWC/C HT NIX toraues Casing OD Minimum Maximum Yield Torque 4-1/2" 5800 ft -lbs 6500 ft -lbs 7200 ft -lbs Page 22 Revision 0 January, 2016 Ilileorp kla4a.. LLC Connection Type: DWC1C Tubing standard SCU 31 B-04 Drilling Procedure Rev 0 Technical Specifications Size(O_D.): Weight (Wall): Grade: 4-112 in 12.60 Ib/ft (0.271 in) L-80 Material L-80 Grade 80,000 Minimum Yield Strength (psi) 95,000 Minimum Ultimate Strength (psi) Pipe Dimensions 4.500 Nominal Pipe Body O.D. (in) 3.958 Nominal Pipe Body I.D.(in) 0.271 Nominal Wall Thickness (in) 1260 Nominal Weight (lbs/ft) 12.25 Plain End Weight (lbstft) 3.600 Nominal Pipe Body Area (sq in) lam USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston, TX 77041 Phone: 713479-3200 Fax: 713479-3234 E-mail: VAMUSAsalesft"m-usa.com Page 23 Revision 0 January, 2016 Pipe Body Performance Properties 288,000 Minimum Pipe Body Yield Strength (Ibs) 7,500 Minimum Collapse Pressure (psi) 8,430 Minimum Internal Yield Pressure (psi) 7,700 Hydrostatic Test Pressure (psi) lam USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston, TX 77041 Phone: 713479-3200 Fax: 713479-3234 E-mail: VAMUSAsalesft"m-usa.com Page 23 Revision 0 January, 2016 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 (%) lam USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston, TX 77041 Phone: 713479-3200 Fax: 713479-3234 E-mail: VAMUSAsalesft"m-usa.com Page 23 Revision 0 January, 2016 Connection Performance Properties 288,000 Joint Strength (Ibs) 14,290 Reference String Length (ft) 1.6 Design Factor 314,000 API Joint Strength (Ibs) 288,000 Compression Rating (lbs) 7,500 API Collapse Pressure Rating (psi) 8,430 API Internal Pressure Resistance (psi) 81.5 Maximum Uniaxial Bend Rating [degrees1100 ft] Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft-Ibs) 6,500 Maximum Final Torque (ft-Ibs) 7,200 Connection Yield Torque (ft-Ibs) lam USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston, TX 77041 Phone: 713479-3200 Fax: 713479-3234 E-mail: VAMUSAsalesft"m-usa.com Page 23 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 110corp Alaska.. LI.I: 15.7 Ensure to run enough liner to provide for approx 200' overlap inside 7" casing. Ensure hanger/pkr will not be set in a 7" connection. 15.8 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. 15.9 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. 15.10 RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 15.11 RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 15.12 M/U top drive and fill pipe while lowering string every 10 stands. 15.13 Set slowly in and pull slowly out of slips. 15.14 Circulate 1-1/2 drill pipe and liner volume at 7" window prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 15.15 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 15.16 Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 15.17 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. 15.18 Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 15.19 Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 24 Revision 0 January, 2016 16.0 Cement 4.5" Production Casing SCU 31 B-04 Drilling Procedure Rev 0 • Cement will be mixed using batch mixer to ensure consistent density 16.1 Hold a pre job safety meeting over the upcoming cmt operations. 16.2 Attempt to reciprocate the casing during cmt operations until hole gets sticky. 16.3 Pump 5 bbls 12.5 ppg MUDPUSH Il spacer. 16.4 Test surface cmt lines to 4500 psi. 16.5 Pump remaining 10 bbls 12.5 ppg MUDPUSH II spacer. 16.6 Mix and pump 117 bbls of 15.3 ppg class "G" cmt per below recipe with 1 lb/bbl of Cemnet or equivalent loss circulation fiber. Ensure cmt is pumped at designed weight. Job is designed to pump 50% OH excess but if fluid caliper dictates otherwise we may increase excess volumes. Ceme vo ume is esigned to give 500' of cement inside window in annulus between 7" casing and 4-1/2" casing. Est TOC 7000' TMD. , 16.7 Displacement fluid will be drilling mud. —173 bbls of displacement fluid Cement Calculations 7" x 4-1/2 DP" Overlap: (7300' — 7000') x 0.017 = 5.1 bbls 7" x 4-1/2" Liner Overlap: (7500'— 7300') x 0.017 = 3.4 bbls 6" OH x 4-1/2" Liner: (12167' — 7500') x 0.0153 1.5 107.1 bbls Shoe Track: 80' x 0.01522 = 1.8 bbls Total Volume (bbls): 5.1 + 3.4 + 107.1 + 1.8 = 117.4 bbls V/ Total Volume (ft3): 117.4 bbls x 5.615 ft3/bbl = 659.2 ft3 Total Volume (sx): 659.2 ft3 / 1.35 ft3/sk = 4 8 Page 25 Revision 0 January, 2016 C, (4- Page ` 0 1104-orp Alaska. 1.1.1. Slurry Information: SCU 31 B-04 Drilling Procedure Rev 0 System Easy BLOK Density 15.3 lb/gal Yield 1.34 ft3/sk ✓' Mixed Water 5.879 gal/sk Mixed Fluid 5.879 gal/sk Expected Thickening 70 Bc at 05:00 hr:mn API Fluid Loss <25 mL in 30.0 min at 155degF / 1000 psi Additives Code Description Concentration G D046 D202 D400 D154 Cement Anti Foam Dispersant Gas Control Agent Extender 94 lb/sk 0.2% BWOC 1.5% BWOC 0.8% BWOC 8.0% BWOC 16.8 Drop DP dart and displace with drilling mud. 16.9 Pump cement at max rate of 8 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re -zeroed at this point 16.10 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 16.11 Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (15% above nominal setting pressure. Hold pressure for 3-5 minutes. 16.12 Slack off total liner weight plus 30k to confirm hanger is set. 16.13 Do not overdisplace by more than 1/2 shoe track (-1 bbls). Shoe track volume is 1.8 bbls. 16.14 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner Page 26 Revision 0 January, 2016 J SCU 31 B-04 Drilling Procedure Rev 0 Ilileorp .Ua.Aa. LLC 16.15 Bleed pressure to zero to check float equipment. 16.16 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve 16.17 Rotate slowly and slack off 50k downhole to set ZXPN. 16.18 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req'd to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack -off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 16.19 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 16.20 Pick up to the high -rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re -tag the liner top, and circulate the well clean. 16.21 Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 16.22 POOH, LDDP. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 16.23 If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 16.24 NOTE: Some hole conditions may require movement of the drillpipe to "work" the torque down to the setting tool. 16.25 After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set -down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Page 27 Revision 0 January, 2016 t� Ililcorp Alaska, LIA: SCU 31 B-04 Drilling Procedure Rev 0 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 Note: Send Csg & cmt report + "As -Run" liner tally to mmyers(&,,hilcorp.com Page 28 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 Hi6•orp :%IaAa. LI.1: 17.0 Wellbore Clean Up & Displacement 17.1 M/U casing clean out assy complete with casing scraper assys for each size casing in the hole. • 3-3/4" bit or mill • Casing scraper & brush for 4-1/2" 12.6# casing +/- 4740' 2-3/8" workstring. • Casing scraper & brush for 7" 29# casing • (2000') 4-1/2" DP • Casing scraper & brush for 7" 29# casing • 4-1/2" DP to surface. 17.2 TIH & clean out well to landing collar (+/- 12,047' MD). • Circulate as needed on trip in if string begins to take weight. • Circulate hi -vis sweeps as necessary to carry debris out of wellbore. • Ensure 3-3/4" bit is worked down to the landing collar. • Space out the cleanout BHA so that the 3-3/4" bit reaches the 4-1/2" landing collar when crossover is +/- 30' above the 4-1/2" liner top. &A->, VL., r i 17.3 After wellbore has been cleaned out s� .sfactorily using mud, test casing to 3500 psi / 30 min. Ensure to chart record casing test. 17.4 Displace drilling fluid in wellbore with a hi -vis pill followed by fresh water. • Catch drilling fluid in rain -for -rent tanks for use on a future well. • Circulate fresh water into wellbore until clean up is satisfactory. Do not recirculate fluid, • After a couple circulations using FW, short trip the assy to bring the upper 7" multi -back assy to surface. • RIH again & tag landing collar w/ 3-3/4" bit. Continue circulation as necessary until fluid cleans up. Make another short trip if necessary. Pump a chemical train followed by 6% KCl completion fluid. 17.5 TOH w/ clean out assy. LDDP on the trip out. L/D the 2-3/8" work string. Page 29 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 Ililcorp Uaska, LLC 18.0 Run Completion Assembly 19.1 Run 2-7/8" tubing completion assembly as per separate Approved Completion Sundry / 19.0 RDMO 19.1 Install BPV in wellhead. RILDs. 19.2 ND BOPE, NU tree, test void 19.3 RDMO Page 30 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 Ilileurp Alaska, H.0 20.0 BOP Schematic I, I 7--R 5" VSIL +de Page 31 Revision 0 January, 2016 Grade 11ilcorp Ala,ka. 1.1.1: 21.0 Wellhead Schematic BHTA, Bowen, 3 118 5h1 FE Valve, swab, VG -M, 3 118 5M FE, HWO Valve, Wing, VG -M, 2 1116 5M FE, HWO Valve, upper master, VG -M, 3 118 5M FE, HWO Valve, master, VG -M, 3 1185M FE, HWO Tbg head, Seaboard, S-8, 13 518 3M X 7 1116"5M. wl 2.2 116 5M SSO Valve, Wing, VG -M, 3 118 5M FE, HWO Qty 2 SCU 31 B-04 Drilling Procedure Rev 0 Valve, Wing,SSV, VG -M, 3118 5M FE w/ Halliburton Hydraulic operator Adapter, Seaboard SM-E-CLN 7 116 16 5M stdd X 3 V8 5M stdd top, w+'% npt control line exit Valve, Seaboard, 2 1?16 5M FE, HWO, {qty 2 Page 32 Revision 0 January, 2016 ,/ Ililcurp Alaska, LLC. 22.0 Days vs Depth 0 rfii• •11 6000 s y�y C V 0 rn m 8000 I El rid• Page 33 0 SCU 31 B-04 Drilling Procedure Rev 0 Days Vs Depth SCU 18-04 (SCU 1ZA-03 ST) 5 10 15 20 Days Revision 0 25 January, 2016 M. 1lilcorp Alaska, LLC 23.0 Geo-Prog SCU 31 B-04 Drilling Procedure Rev 0 Swanson River SCU 31B-04 (SCU 12A-3ST) Alaska KB 162.5 18' KB (Saxon 169) 144.5 Drill a Sidetrack well out of the SCU 12A-3 well to produce the H1 and H2 Oil associated with the 2015 H1- 2 Gas Flood project. Based on subsurface evaluation FT man Crew from KOP to TD WD Gamma Resistivity only Gas lift completion 2000 bpd gross fluid 2 718" or 3.5" Page 34 Revision 0 January, 2016 EXPECTED Formation FORMATION FLUID MD TVD Est Pressure EM Grad►ent ICOP 7500 SR -III ST Oil S.Md 11339 10211 I r lio 3.0 0_2 SR_111sli 11425 102`1 SR 112ST Oil Sand 11434 111274} IrnU 3.0 0.2 SR H2SB 11455 10289 SR 113ST Oil Sad 11469 10296 I(") 3.0 11. SR UL ST Oil Saml 11498 10313 1600 3.0 0.2 SR H3SB 11610 10378 SR H5ST Oil SMA 11638 10394 2800 l 5 2 0 SR HEST 11812 10495 SR__117ST CAI Sane! 11880 10523 2104 5.1 0 SR H7SB 11920 10558 SR HEST Oil Sand 11936 10567 21M 5.1 0 SR HSSB 12094 1065$ FT man Crew from KOP to TD WD Gamma Resistivity only Gas lift completion 2000 bpd gross fluid 2 718" or 3.5" Page 34 Revision 0 January, 2016 Ililcorp Alaska, LLC SCU 31 B-04 Drilling Procedure Rev 0 J$� Qt 24.0 Anticipated Drilling Hazards ; ,, 1�� (� r� ;" ° �`� B' Water Flow: i �`�� ✓6 �' �� `J �` ��� ✓ The Tyonek water sands will be openAEnsure to treat the initial flow as gas. After we are cori idem we C are only dealing with water from the sands we will drill the interval while the well is flowing water. Utilize MW and ECD to keep the well dead will drilling. During trips we will use heavy pills andi" viscous pills to control the flow and trip in and out of the well.r�tC(Y l.� Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual -composition carbon -based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscofier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain programmed mud specs. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt -type additives to further stabilize coal seams. • Increase fluid density as required to control running coals. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. • Minimize swab and surge pressures • Minimize back reaming through coals when possible H2S: 1-12S is not present in this hole section. No abnormal temperatures or pressures are present in this hole section. Page 35 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 Ilik.—I) AlaA.I. LIA: 25.0 Rig Layout Page 36 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 11ilrorp .UaAa. 1.1.1: 26.0 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 37 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 Ililcorp %laAa, I',1: 27.0 Choke Manifold Schematic L 1'. LA UFWT VM R QA9it18 Page 38 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 28.0 Casing Design Information Calculation & Casing Design Factors Hole Size Hole Size 6" Hole Size Drilling Mode MASP: Production Mode MASP: Swanson River Unit DATE: 1/14/2016 WELL: SCU 31B-04 (SCU 12A-03 ST) FIELD: Soldotna Creek Unit DESIGN BY: Monty M Myers Design Criteria: Mud Density: Mud Density: 10.5 ppg Mud Density: 1712 psi (See attached MASP determination & calculatio 2782 psi (See attached MASP determination & calculation) Collapse Calculation: Section Calculation 1,2 Normal gradient external stress (0.406 psi/ft) and the casing evacuated for the internal stress Page 39 Revision 0 January, 2016 Casing Section Calculation/Specification 1 2 3 4 Casing OD 4-1/2" Top (MD) 7,300 Top (TVD) 7,300 Bottom (MD) 12,167 Bottom (TVD) 10,701 Length 4,867 Weight (ppf) 12.6 Grade L-80 Connection DWC/C Weight w/o Bouyancy Factor (lbs) 61,324 Tension at Top of Section (lbs) 61,324 Min strength Tension (1000 lbs) 288 Worst Case Safety Factor (Tension) 4.70 Collapse Pressure at bottom (Psi) 4,345 Collapse Resistance w/o tension (Psi) 7,500 Worst Case Safety Factor (Collapse) 1.73 . MASP (psi) 1,712 Minimum Yield (psi) 8,430 Worst case safety factor (Burst) 4.92 - Page 39 Revision 0 January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 Hileorp Alaska, LLC 29.0 6" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 11 6" Hole Section Hil SCU 3113-04 Kenai, Alaska MD TVD Planned Top: 0 0 Planned TD: 12167 10701 Anticioated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad SR_H1ST 10,221 1600 Oil / Water 3.0 0.157 SR_H2ST 10,271 1600 Oil /Water 3.0 0.156 SR_H2SB 10,276 1600 3.0 0.156 SR_H3ST 10,288 1600 Gassy Water/ Oil 3.0 0.156 SR_H3L_ST 10,2% 1600 Gassy Water/Oil 3.0 0.155 SR_H3SB 10,313 2800 5.2 0.272 SR_H5ST 10,378 2800 Water/ Oil 5.2 0.270 SR_H5SB 10,394 2800 5.2 0.269 SR_H7ST 10,495 2800 Oil 5.1 0.267 SR_H7SB 10,523 2800 5.1 0.266 SR_H8ST 10,558 2800 Water/ Oil 5.1 0.265 SR_H8SB 10,567 2800 5.1 0.265 TD 10,701 2800 OIL 5.0 0.262 Offset Well Mud Densities WPII MW ranPP Tnn ITVDI Rnttnm (TVDI nate SCU 4405 9.8- 10ppg 9,400 10,925 2014 SCU 21-4 12 ppg 0 10,965 1961 SCU 4433 11.3 - 12.5 ppg ' 9,216 10,747 2013 SCU 41A-4 11.2 ppg - 9,300 10,807 2013 Assumptions:` s 1. Maximum planned mud density for the 6" hole section its 10.5 ppg.' � 2. Calculations assume reservoirs contain 100% gas (worst'`case). f 3. Calculations assume worst case event is complete evacuation of wellbore to gas. 4. Anticipated fracture gradient at 8600' TVD =12.5 ppg EMW Fracture Pressure at 6" window considering a full column of gas from window to surface: 7500 (ft) x 0.65(psi/ft)= 4875 4875 (psi) - [0.1(psi/ft)*7500(ft))= 4125 psi MASP from pore pressure; entire wellbore evacuated to gas from TD 10701 (ft) x 0.26(psi/ft)= 2782 psi 2782(psi) - [0.1(psi/ft)*10701 (ft)]=F 1712 psi Summary: 1. MASP while drilling 6" production hole is governed by SIBHP minus entire wellbore evacuated to gas from TD. 2. MASP during production mode is governed by SIBHP minus entire wellbore evacuated to gas from TD. Page 40 Revision 0 January, 2016 30.0 Plot (NAD 27) (Governmental Sections) J¢ A028399 SCU 31 B-04 Drilling Procedure Rev 0 SCU343-33 SHI TSCU 43A-33 B L �J SCU 13-34 BHto r i i• jI • SCU33-33 SM; S008NMW SRU24.33 8HL* „SCU 44B-33 BHL*--- SCU34-33 BHL3 +,' • SCU4L'33 BHLOI PL-SCU 2444 PSTS SHLL- ---- Page 41 SCU44-D4 BHLI SGU34-01eHL� Soldotna Creek Unit SC U 31 B-04 Revision 0 SCU SCU2444 eHb a ESCU 31B-04 SHLI SCU238-113 BH SCU23-D3 UZ -D3 BHL Z/ Legend • Plan: SCU 318-04 SHL JXJ Plan: SCU 316-04—TPH 14-0 + Plan: SCU 31B-04—BHL B Other Surface Well Locations e Other Bottom Hole Locations ---- Well Paths SRF Unit Boundary 0 1.600 2.090 Feet Aiaska State Plane Zone 4, NAD27 A Map Date: 11141291 fi January, 2016 SCU-41B-04 BHL* SCl1_41 B-04BP BHL Y I SGV 21 -fm i SCu21A-04BH, J SCU 31B-04_BHL f BHtt SCU341-D4 BHL , I•��B.o4 RLI_31�0.9_PBt BFi6�11 \l +1�i(:U l 41Ao.D4814L.� �. SCU 2tC-04 �liL SCU-31.04 7" i 11 ! SCU 3 i B -t TPH • ' y SCV42-W SHL 'a011.� 3220-D4 B � . SCU 12A SCU 12-D I Bi SCU 21A-4ST OHL* +� SCU332AS BHL4f � S&2204PS OHLjp S'p22-04 6H16 + S007NO09W A028997 SCU323-04 I&Ht* 50 143.04 BHI ^ • r SCU43A-04 BHL* SCV 13- SHI PL-SCU 2444 PSTS SHLL- ---- Page 41 SCU44-D4 BHLI SGU34-01eHL� Soldotna Creek Unit SC U 31 B-04 Revision 0 SCU SCU2444 eHb a ESCU 31B-04 SHLI SCU238-113 BH SCU23-D3 UZ -D3 BHL Z/ Legend • Plan: SCU 318-04 SHL JXJ Plan: SCU 316-04—TPH 14-0 + Plan: SCU 31B-04—BHL B Other Surface Well Locations e Other Bottom Hole Locations ---- Well Paths SRF Unit Boundary 0 1.600 2.090 Feet Aiaska State Plane Zone 4, NAD27 A Map Date: 11141291 fi January, 2016 SCU 31 B-04 Drilling Procedure Rev 0 Ilde—jo A64a, LI.(: 31.0 Surface Plat (As Built) (NAD 2 1 33 34 SECTION LINE (NOT TO SCALE) T8N - -- 4 � 3 SECTION C,QR iGAhlPIlTE0)- N:2461157.9M T7N R9W E. 347634.774 I SEC 3 T7N R9W Izu:1r I;�+i rNrs I w SCU 12A-03 ASBUILT SURFACE LOCATION 00 NAD 27 ASP ZONE 4 F 4 N:2459121.980 0 E:347966.381 vii ( ` LAT: 60'43'41.971"N LON: 150'50'57.362W 1s9 2032' FNL 359' FW1 ' I° , ELEV: 144.45' NAVDU . I I ¢� I NOTES 1. BASIS OF HORIZONTAL, NAD83 US FEET POSITION (EPOCH 2010) AND VERTICAL CONTROL (NAVD88) IS AN OPUS SOLUTION FROM ++�� OF A1j1f///�/ NGS STATIONS TBON, TSEA AND ANC2 TO ESTABLISH CP -2. THE"` ALASKA STATE PLANE COORDINATES NAD 83 ZONE 4 IN FEET ARE: Ty `49 �i N = 2468384578 * IHIS �► E = 148MG9-444 10 ELEV. = 212.6901 NAVD88) � c DAMN J• IITtNE f ,�// 1 2. SECTION LINES SHOWN WERE ESTABLISHED FROM SURVEY SCALE '� f' TIES TO ORIGINAL GLO MONUMENTATION (1987} .._..• /f11 3. DATUM TRANSFORMATIONS (NAD83 ASPZ4 TO NA027 ASPZ4} 290 4� ++++ WERE DONE USING CORPSCON SOFTWARE VERSION 6.0.1 FEEL t HILCORP ALASKA, LLC W101- lr, G-»n-oItin; Inc SWANSON RIVER FIELD TMTF ""- WELL SCU 12A-03 --- 1 - AS BUILT SURFACE LOCATION NAD 27 EMfJM[EPW'vfMHFFiNG: '3.ft�TrH:iC�TNG PiI�Y. T�^-t�3 ,nni ♦v. Bi.U4411'J(:l GtfW4 JK. 91EC1 IL JfR:I. i . •�nCE 1W:,M-u11 I'- M;IM12T,s SECTION 03 T07N R09W 5rG' Ililump Ala•kn. LII: . 1 SEWARD MERIDIAN ALASKA Page 42 Revision 0 January, 2016 32.0 Surface Plat (As Built) (NAD 83) SCU 31 B-04 Drilling Procedure Rev 0 I 33 34 SECTION LINE (NOT TO SCALE) T8N _ 4 _ SWANSON RIVER FIELD WELL SCU 12A-03NIAANL SeCTiONCORICo+APureD) I�3 N 200)19 181 T7N R9W E: 1487653 685 I AS BUILT SURFACE LOCATION CMrJ"[[RW�: b4FS1"G1'JJRLC.N:iT65SN: NAD 83 SEC 3 T7N R9W W+. NS 'lMR ;r CE �uo1.77 ute Fa. W712 ISS r- �u ca cac YMIT FNL INTSI � E' T 1 LU SCU 12A-03 I ASBUILT SURFACE LOCATION 0 NAD 83 ASP ZONE 4 ( N2458883.1570 0 EA487989.257 uwi I LAT_ 60`43'39.942"N LON: 150"51'05.348"W �— 359 FWL 2032' FNL 359' FWL I xt, ELEV: 144.45' NAVD88 t;Q 1 P I NOTES 1. BASIS OF HORIZONTAL, NAO83 US FEET POSITION (EPOCH 20101 AND VERTICAL CONTROL (NAVE)BS) IS AN OPUS SOLUTION FROM NGS STATIONS TBON, TSEA AND ANC2 TO ESTABLISH CP -2. THE ALASKA STATE PLANE COORDINATES NAD 83 ZONE 4 IN FEET ARE: = 49X �j. r— N = 2458384.578 : ► 2 49 21 0% E = 1483669.444 ELEV. = 12.680 1 NAVD88 `y..S 2. SECTION LINES SHOWN WERE ESTABLISHED FRC41 SURVEY SCALE ��i �,° ^!.�' nESTOORIGINAL GLOMONUMENTATION{19671 a 2oa 4CC FEET Page 43 Revision 0 January, 2016 *b"°t' MIL4VKI' ALASKA, LLL: + C-m3V fing Inc SWANSON RIVER FIELD WELL SCU 12A-03NIAANL T"TF + AS BUILT SURFACE LOCATION CMrJ"[[RW�: b4FS1"G1'JJRLC.N:iT65SN: NAD 83 Ph'+f tx", t-aJ.'nil1 W+. NS 'lMR ;r CE �uo1.77 ute Fa. W712 ISS r- �u ca cac Ililrurp Alaska. I.i.f lL J4t ILb SECTION 03 T07N R09W SEWARD MERIDIAN, ALASKA � E' T 1 Page 43 Revision 0 January, 2016 0 Ilileorp:UaAa. H.0 33.0 Directional Program (P1) SCU 31 B-04 Drilling Procedure Rev 0 Page 44 Revision 0 January, 2016 Hilcorp Energy Company Soldotna CK Unit Soldotna CK Unit Soldotna CK Unit 12-3 Plan: SCU 3113-04 Plan: Plan: SCU 3113-04 Standard Proposal Report 01 September, 2015 HALLIBURTON Sperry Drilling Services NALLIBURTON 8000 c to O 8500 O O L a 9000 Q (6 U N 9500 10000 10500 11000 11500 12000 -1000 -500 WELL DETAILS: Soldotna CK Unit 12-3 NAD 1927 (NADCON CONUS) Alaska Zone 04 Project: Soldotna CK Unit Ground Level: 126.00 Site: Soldotna CK Unit +N/ -S +F/ -W Northing Easting Iatittude Longitude Slot Well: Soldotna CK Unit 12-3 0.00 0.00 2459121.98 347966.38 60.7283252 -150.8492673 Wellbore: Plan: SCU 31B-04 Plan: Plan: SCU 318-04 REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well Soldotna CK Unit 12-3, True North Vertical (TVD) Reference: SCU 31 B-04 @ 144.00usft Measured Depth Reference: SCU 31 B-04 @ 144.00usft Calculation Method: Minimum Curvature O� ^7 C) roo O rV O 0 0 '~ o SCU 31B-04 SR_H8ST ^ i �1h h0 SCU 31B-04 SR HIST -1000 st(+) (750 usft/in) � � JVV JIB-UY Jrt_rlOJl 12A-3 2000 1500 Er 1000 v 0 500 y 0 500 -500 0 500 SCU 12-3 `O T M Qac Magnetic North: 16.57° Azimuths to True North Magnetic Field Strength: 55517.6snT Dip Angle: 73.69° Date: 9/1/2015 Model: BGGM2016 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 Vertical Section at 290.50° (1000 usft/in) HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Soldotna CK Unit Site: Soldotna CK Unit Well: Soldotna CK Unit 12-3 Wellbore: Plan: SCU 31B-04 Design: Plan: SCU 31B-04 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Soldotna CK Unit 12-3 SCU 31 B-04 @ 144.00usft SCU 31 B-04 @ 144.00usft True Minimum Curvature Project Soldotna CK Unit, Swanson River Field Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Model Name Map Zone: Alaska Zone 04 Dip Angle Field Strength Site Soldotna CK Unit Site Position: Northing: 2,460,278.17 usft Latitude: 60.7313645 From: Map Easting: 344,519.07usft Longitude: -150.8686069 Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -0.76 ° 55,518 Well Soldotna CK Unit 12-3 Well Position +N/ -S 0.00 usft Northing: 2,459,121.98 usft Latitude: 60.7283252 Plan: SCU 31 B-04 +E/ -W 0.00 usft Easting: 347,966.38 usft Longitude: -150.8492673 Position Uncertainty 0.00 usft Wellhead Elevation: 144.00 usft Ground Level: 126.00 usft Wellbore Plan: SCU 31 B-04 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (nT) BGGM2015 9/1/2015 16.56 73.69 55,518 Design Plan: SCU 31 B-04 Audit Notes: Version: Phase: PLAN Tie On Depth: 7,500.00 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (I -0.45 0.00 0.00 290.50 Plan Sections Measured Vertical TVD Dogleg Build Tum Depth Inclination Azimuth Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) (I (I (usft) usft (usft) (usft) (°HOOusft) (°/100usft) (°/100usft) (°) 7,500.00 0.18 234.74 7,498.67 7,354.67 73.09 -44.11 0.00 0.00 0.00 0.00 9,319.28 54.68 289.58 9,053.54 8,909.54 340.69 -804.19 3.00 3.00 3.01 54.95 11,336.31 54.68 289.58 10,219.54 10,075.54 892,23 -2,354.89 0.00 0.00 0.00 0.00 11,338.83 54.61 289.59 10,221.00 10,077.00 892.92 -2,356.82 3.00 -2.99 0.34 174.62 11,936.26 54.61 289.59 10,567.00 10,423.00 1,056.20 -2,815.67 0.00 0.00 0.00 0.00 12,167.00 54.61 289.59 10,700.63 10,556.63 1,119.26 -2,992.89 0.00 0.00 0.00 0.00 9/1/2015 4:29:59PM Page 2 COMPASS 5000.1 Build 73 Planned Survey Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Soldotna CK Unit 12-3 Company: Hilcorp Energy Company TVD Reference: SCU 31 B-04 @ 144.00usft Project: Soldotna CK Unit MD Reference: SCU 31 B-04 @ 144.00usft Site: Soldotna CK Unit North Reference: True Well: Soldotna CK Unit 12-3 Survey Calculation Method: Minimum Curvature Wellbore: Plan: SCU 3113-04 Depth Inclination Design: Plan: SCU 31B-04 Depth TVDss Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (^) V) (usft) usft (usft) (usft) (usft) (usft) -144.45 -0.45 0.00 0.00 -0.45 -144.45 0.00 0.00 2,459,121.98 347,966.38 0.00 0.00 80.00 0.25 338.00 80.00 -64.00 0.16 -0.07 2,459,122.14 347,966.32 0.31 0.12 180.00 0.50 309.00 180.00 36.00 0.64 -0.49 2,459,122.63 347,965.90 0.31 0.68 280.00 0.33 276.00 280.00 136.00 0.94 -1.11 2,459,122.94 347,965.28 0.29 1.37 380.00 0.25 295.00 379.99 235.99 1.07 -1.60 2,459,123.07 347,964.80 0.12 1.87 480.00 0.25 356.00 479.99 335.99 1.38 -1.81 2,459,123.38 347,964.59 0.25 2.18 580.00 0.00 356.00 579.99 435.99 1.59 -1.82 2,459,123.60 347,964.58 0.25 2.27 680.00 0.50 215.00 679.99 535.99 1.24 -2.07 2,459,123.24 347,964.32 0.50 2.38 780.00 0.50 251.00 779.99 635.99 0.74 -2.74 2,459,122.75 347,963.65 0.31 2.82 880.00 0.50 314.00 879.98 735.98 0.90 -3.46 2,459,122.92 347,962.93 0.52 3.56 980.00 0.25 348.00 979.98 835.98 1.41 -3.82 2,459,123.44 347,962.58 0.32 4.08 1,080.00 0.00 348.00 1,079.98 935.98 1.63 -3.87 2,459,123.66 347,962.53 0.25 4.19 1,180.00 0.25 99.00 1,179.98 1,035.98 1.59 -3.65 2,459,123.62 347,962.75 0.25 3.98 1,280.00 0.50 244.00 1,279.98 1,135.98 1.37 -3.83 2,459,123.40 347,962.57 0.72 4.07 1,380.00 0.33 196.00 1,379.98 1,235.98 0.90 -4.30 2,459,122.94 347,962.09 0.37 4.34 1,480.00 0.33 319.00 1,479.98 1,335.98 0.84 -4.57 2,459,122.88 347,961.82 0.58 4.57 1,580.00 0.33 20.00 1,579.98 1,435.98 1.33 -4.66 2,459,123.37 347,961.74 0.33 4.83 1,680.00 0.25 40.00 1,679.98 1,535.98 1.77 -4.42 2,459,123.80 347,961.98 0.13 4.76 1,780.00 0.25 137.00 1,779.97 1,635.97 1.77 -4.13 2,459,123.81 347,962.27 0.37 4.49 1,880.00 0.50 16.00 1,879.97 1,735.97 2.03 -3.86 2,459,124.06 347,962.54 0.66 4.33 1,980.00 0.50 35.00 1,979.97 1,835.97 2.81 -3.49 2,459,124.84 347,962.93 0.17 4.26 2,080.00 0.25 55.00 2,079.97 1,935.97 3.29 -3.06 2,459,125.31 347,963.36 0.28 4.02 2,180.00 0.50 46.00 2,179.97 2,035.97 3.72 -2.57 2,459,125.73 347,963.86 0.26 3.71 2,280.00 0.25 85.00 2,279.96 2,135.96 4.04 -2.04 2,459,126.05 347,964.39 0.34 3.33 2,380.00 0.00 85.00 2,379.96 2,235.96 4.06 -1.82 2,459,126.07 347,964.61 0.25 3.13 2,480.00 0.25 150.00 2,479.96 2,335.96 3.87 -1.71 2,459,125.88 347,964.72 0.25 2.96 2,580.00 0.00 150.00 2,579.96 2,435.96 3.69 -1.60 2,459,125.69 347,964.82 0.25 2.79 2,680.00 0.00 150.00 2,679.96 2,535.96 3.69 -1.60 2,459,125.69 347,964.82 0.00 2.79 2,780.00 0.50 129.00 2,779.96 2,635.96 3.41 -1.27 2,459,125.41 347,965.16 0.50 2.38 2,880.00 0.50 122.00 2,879.96 2,735.96 2.90 -0.56 2,459,124.89 347,965.86 0.06 1.54 2,980.00 0.42 75.00 2,979.95 2,835.95 2.77 0.17 2,459,124.75 347,966.58 0.37 0.81 13 3/S" 3,080.00 0.50 79.00 3,079.95 2,935.95 2.95 0.95 2,459,124.91 347,967.37 0.09 0.14 3,180.00 0.00 79.00 3,179.95 3,035.95 3.03 1.38 2,459,124.99 347,967.80 0.50 -0.23 3,280.00 0.17 160.00 3,279.95 3,135.95 2.89 1.43 2,459,124.85 347,967.85 0.17 -0.33 3,380.00 0.50 341.00 3,379.95 3,235.95 3.16 1.34 2,459,125.13 347,967.76 0.67 -0.15 3,480.00 0.58 345.00 3,479.94 3,335.94 4.06 1.06 2,459,126.03 347,967.50 0.09 0.43 3,580.00 0.58 312.00 3,579.94 3,435.94 4.89 0.56 2,459,126.86 347,967.00 0.33 1.19 3,680.00 0.83 310.00 3,679.93 3,535.93 5.70 -0.37 2,459,127.68 347,966.08 0.25 2.34 3,780.00 0.83 334.00 3,779.92 3,635.92 6.81 -1.25 2,459,128.81 347,965.22 0.35 3.55 3,880.00 0.50 355.00 3,879.91 3,735.91 7.90 -1.60 2,459,129.90 347,964.88 0.41 4.27 3,980.00 1.00 339.00 3,979.91 3,835.91 9.15 -1.95 2,459,131.15 347,964.55 0.54 5.03 4,080.00 0.75 333.00 4,079.89 3,935.89 10.55 -2.56 2,459,132.56 347,963.96 0.27 6.09 4,180.00 1.00 329.00 4,179.88 4,035.88 11.88 -3.31 2,459,133.90 347,963.23 0.26 7.26 4,280.00 0.92 326.00 4,279.87 4,135.87 13.29 -4.21 2,459,135.32 347,962.35 0.09 8.60 9/1/2015 4:29:59PM Page 3 COMPASS 5000.1 Build 73 Planned Survey Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Soldotna CK Unit 12-3 Company: Hilcorp Energy Company TVD Reference: SCU 31 B-04 @ 144.00usft Project: Soldotna CK Unit MD Reference: SCU 31B-04 @ 144.00usft Site: Soldotna CK Unit North Reference: True Well: Soldotna CK Unit 12-3 Survey Calculation Method: Minimum Curvature Wellbore: Plan: SCU 31B-04 Depth Inclination Design: Plan: SCU 316-04 Depth TVDss Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) V) (_) (usft) usft (usft) (usft) (usft) (usft) 4,235.86 4,380.00 0.83 315.00 4,379.86 4,235.86 14.47 -5.17 2,459,136.51 347,961.40 0.19 9.91 4,480.00 0.75 345.00 4,479.85 4,335.85 15.61 -5.85 2,459,137.67 347,960.73 0.42 10.95 4,580.00 0.58 324.00 4,579.84 4,435.84 16.65 -6.32 2,459,138.71 347,960.28 0.29 11.75 4,680.00 0.92 329.00 4,679.83 4,535.83 17.75 -7.03 2,459,139.82 347,959.58 0.35 12.80 4,780.00 0.50 359.00 4,779.82 4,635.82 18.88 -7.45 2,459,140.95 347,959.18 0.55 13.59 4,880.00 0.50 10.00 4,879.82 4,735.82 19.74 -7.38 2,459,141.82 347,959.26 0.10 13.83 4,980.00 1.17 340.00 4,979.81 4,835.81 21.13 -7.65 2,459,143.21 347,959.00 0.78 14.57 5,080.00 0.50 352.00 5,079.80 4,935.80 22.52 -8.06 2,459,144.61 347,958.61 0.69 15.44 5,180.00 1.67 346.00 5,179.78 5,035.78 24.37 -8.48 2,459,146.46 347,958.22 1.17 16.48 5,280.00 1.83 333.00 5,279.73 5,135.73 27.21 -9.55 2,459,149.31 347,957.18 0.43 18.48 5,380.00 2.00 335.00 5,379.68 5,235.68 30.21 -11.02 2,459,152.33 347,955.76 0.18 20.90 5,480.00 2.50 344.00 5,479.60 5,335.60 33.89 -12.35 2,459,156.02 347,954.47 0.61 23.44 5,580.00 2.25 318.00 5,579.52 5,435.52 37.44 -14.27 2,459,159.60 347,952.60 1.10 26.48 5,680.00 2.50 330.00 5,679.43 5,535.43 40.79 -16.67 2,459,162.98 347,950.24 0.56 29.91 5,780.00 2.58 355.00 5,779.34 5,635.34 44.92 -17.96 2,459,167.13 347,949.00 1.10 32.56 5,880.00 2.25 315.00 5,879.25 5,735.25 48.55 -19.54 2,459,170.78 347,947.47 1.68 35.31 5,980.00 2.92 335.00 5,979.15 5,835.15 52.25 -22.01 2,459,174.51 347,945.05 1.11 38.92 6,080.00 1.67 331.00 6,079.07 5,935.07 55.83 -23.79 2,459,178.11 347,943.31 1.26 41.84 6,180.00 1.58 309.00 6,179.03 6,035.03 57.97 -25.57 2,459,180.28 347,941.56 0.63 44.26 6,280.00 2.25 348.00 6,278.98 6,134.98 60.76 -27.05 2,459,183.09 347,940.12 1.43 46.62 6,380.00 1.08 312.00 6,378.94 6,234.94 63.31 -28.16 2,459,185.65 347,939.04 1.52 48.55 6,480.00 2.25 325.00 6,478.90 6,334.90 65.55 -29.98 2,459,187.91 347,937.25 1.22 51.05 6,580.00 2.50 303.00 6,578.81 6,434.81 68.35 -32.94 2,459,190.75 347,934.33 0.94 54.79 6,680.00 1.25 304.00 6,678.76 6,534.76 70.14 -35.67 2,459,192.58 347,931.62 1.25 57.98 6,780.00 0.92 298.00 6,778.74 6,634.74 71.13 -37.29 2,459,193.59 347,930.02 0.35 59.84 6,880.00 1.33 342.00 6,878.72 6,734.72 72.61 -38.35 2,459,195.08 347,928.97 0.92 61.36 6,980.00 0.50 255.00 6,978.71 6,834.71 73.60 -39.13 2,459,196.08 347,928.20 1.40 62.44 7,080.00 0.50 46.00 7,078.71 6,934.71 73.79 -39.24 2,459,196.27 347,928.10 0.97 62.60 7,180.00 0.92 247.00 7,178.70 7,034.70 73.78 -39.67 2,459,196.27 347,927.67 1.40 63.00 7,280.00 1.00 261.00 7,278.69 7,134.69 73.33 -41.27 2,459,195.84 347,926.07 0.25 64.34 7,380.00 1.00 276.00 7,378.68 7,234.68 73.29 -43.00 2,459,195.82 347,924.33 0.26 65.94 7,480.00 0.33 219.00 7,478.67 7,334.67 73.15 -44.05 2,459,195.70 347,923.28 0.87 66.88 7,500.00 0.18 234.74 7,498.67 7,354.67 73.09 -44.11 2,459,195.64 347,923.22 0.80 66.92 7,600.00 3.11 286.91 7,598.62 7,454.62 73.79 -46.84 2,459,196.37 347,920.50 3.00 69.71 7,700.00 6.11 288.28 7,698.28 7,554.28 76.25 -54.48 2,459,198.92 347,912.89 3.00 77.74 7,800.00 9.11 288.74 7,797.39 7,653.39 80.46 -67.03 2,459,203.30 347,900.39 3.00 90.97 7,900.00 12.11 288.98 7,895.67 7,751.67 86.41 -84.45 2,459,209.48 347,883.06 3.00 109.37 8,000.00 15.11 289.13 7,992.85 7,848.85 94.10 -106.68 2,459,217.45 347,860.93 3.00 132.88 8,100.00 18.11 289.22 8,088.67 7,944.67 103.48 -133.67 2,459,227.18 347,834.06 3.00 161.45 8,200.00 21.11 289.30 8,182.86 8,038.86 114.55 -165.34 2,459,238.66 347,802.53 3.00 194.99 8,300.00 24.11 289.35 8,275.17 8,131.17 127.27 -201.61 2,459,251.85 347,766.43 3.00 233.42 8,400.00 27.11 289.39 8,365.34 8,221.34 141.61 -242.38 2,459,266.71 347,725.85 3.00 276.63 8,500.00 30.11 289.43 8,453.12 8,309.12 157.51 -287.53 2,459,283.20 347,680.91 3.00 324.49 8,600.00 33.11 289.45 8,538.28 8,394.28 174.96 -336.95 2,459,301.28 347,631.72 3.00 376.88 8,700.00 36.11 289.48 8,620.58 8,476.58 193.88 -390.49 2,459,320.89 347,578.43 3.00 433.66 9/1/2015 4:29:59PM Page 4 COMPASS 5000.1 Build 73 Planned Survey Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Coordinate Reference: Well Soldotna CK Unit 12-3 Company: Hilcorp Energy Company TVD Reference: SCU 31B-04 @ 144.00usft Project: Soldotna CK Unit MD Reference: SCU 31 B-04 @ 144.00usft Site: Soldotna CK Unit North Reference: True Well: Soldotna CK Unit 12-3 Survey Calculation Method: Minimum Curvature Wellbore: Plan: SCU 316-04 Depth Inclination Design: Plan: SCU 31B-04 Depth TVDss Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (^) (^) (usft) usft (usft) (usft) (usft) (usft) 8,555.79 8,800.00 39.11 289.50 8,699.79 8,555.79 214.24 -448.01 2,459,341.99 347,521.18 3.00 494.67 8,900.00 42.11 289.52 8,775.70 8,631.70 235.97 -509.35 2,459,364.52 347,460.13 3.00 559.74 9,000.00 45.11 289.54 8,848.10 8,704.10 259.02 -574.34 2,459,388.41 347,395.43 3.00 628.69 9,100.00 48.11 289.55 8,916.80 8,772.80 283.33 -642.81 2,459,413.60 347,327.28 3.00 701.33 9,200.00 51.11 289.56 8,981.59 8,837.59 308.82 -714.57 2,459,440.02 347,255.86 3.00 777.48 9,300.00 54.11 289.58 9,042.32 8,898.32 335.43 -789.42 2,459,467.59 347,181.36 3.00 856.90 9,319.28 54.68 289.58 9,053.54 8,909.54 340.69 -804.19 2,459,473.04 347,166.66 3.00 872.58 9,400.00 54.68 289.58 9,100.20 8,956.20 362.76 -866.25 2,459,495.91 347,104.89 0.00 938.43 9,500.00 54.68 289.58 9,158.01 9,014.01 390.10 -943.13 2,459,524.24 347,028.37 0.00 1,020.02 9,600.00 54.68 289.58 9,215.82 9,071.82 417.45 -1,020.01 2,459,552.58 346,951.85 0.00 1,101.61 9,700.00 54.68 289.58 9,273.63 9,129.63 444.79 -1,096.89 2,459,580.92 346,875.33 0.00 1,183.20 9,800.00 54.68 289.58 9,331.43 9,187.43 472.14 -1,173.77 2,459,609.25 346,798.81 0.00 1,264.78 9,900.00 54.68 289.58 9,389.24 9,245.24 499.48 -1,250.65 2,459,637.59 346,722.29 0.00 1,346.37 10,000.00 54.68 289.58 9,447.05 9,303.05 526.82 -1,327.53 2,459,665.93 346,645.77 0.00 1,427.96 10,100.00 54.68 289.58 9,504.86 9,360.86 554.17 -1,404.41 2,459,694.26 346,569.25 0.00 1,509.55 10,200.00 54.68 289.58 9,562.66 9,418.66 581.51 -1,481.29 2,459,722.60 346,492.73 0.00 1,591.13 10,300.00 54.68 289.58 9,620.47 9,476.47 608.86 -1,558.17 2,459,750.93 346,416.21 0.00 1,672.72 10,400.00 54.68 289.58 9,678.28 9,534.28 63620 -1,635.05 2,459,779.27 346,339.69 0.00 1,754.31 10,500.00 54.68 289.58 9,736.09 9,592.09 663.55 -1,711.93 2,459,807.61 346,263.17 0.00 1,835.90 10,600.00 54.68 289.58 9,793.90 9,649.90 690.89 -1,788.81 2,459,835.94 346,186.65 0.00 1,917.48 10,700.00 54.68 289.58 9,851.70 9,707.70 718.24 -1,865.69 2,459,864.28 346,110.13 0.00 1,999.07 10,800.00 54.68 289.58 9,909.51 9,765.51 745.58 -1,942.57 2,459,892.62 346,033.61 0.00 2,080.66 10,900.00 54.68 289.58 9,967.32 9,823.32 772.92 -2,019.45 2,459,920.95 345,957.09 0.00 2,162.25 11,000.00 54.68 289.58 10,025.13 9,881.13 800.27 -2,096.33 2,459,949.29 345,880.57 0.00 2,243.84 11,100.00 54.68 289.58 10,082.93 9,938.93 827.61 -2,173.21 2,459,977.62 345,804.05 0.00 2,325.42 11,200.00 54.68 289.58 10,140.74 9,996.74 854.96 -2,250.09 2,460,005.96 345,727.53 0.00 2,407.01 11,300.00 54.68 289.58 10,198.55 10,054.55 882.30 -2,326.97 2,460,034.30 345,651.01 0.00 2,488.60 11,336.31 54.68 289.58 10,219.54 10,075.54 892.23 -2,354.89 2,460,044.59 345,623.23 0.00 2,518.22 11,338.83 54.61 289.59 10,221.00 10,077.00 892.92 -2,356.82 2,460,045.30 345,621.30 3.00 2,520.28 SCU 31B-04 SR -HIST 11,400.00 54.61 289.59 10,256.42 10,112.42 909.64 -2,403.80 2,460,062.62 345,574.54 0.00 2,570.14 11,500.00 54.61 289.59 10,314.34 10,170.34 936.97 -2,480.61 2,460,090.94 345,498.10 0.00 2,651.65 11,600.00 54.61 289.59 10,372.25 10,228.25 964.30 -2,557.41 2,460,119.27 345,421.65 0.00 2,733.16 11,700.00 54.61 289.59 10,430.17 10,286.17 991.63 -2,634.22 2,460,147.59 345,345.21 0.00 2,814.67 11,800.00 54.61 289.59 10,488.08 10,344.08 1,018.96 -2,711.02 2,460,175.91 345,268.76 0.00 2,896.18 11,900.00 54.61 289.59 10,546.00 10,402.00 1,046.29 -2,787.82 2,460,204.23 345,192.32 0.00 2,977.70 11,936.26 54.61 289.59 10,567.00 10,423.00 1,056.20 -2,815.67 2,460,214.50 345,164.60 0.00 3,007.25 SCU 31B-04 SR_H8ST 12,000.00 54.61 289.59 10,603.91 10,459.91 1,073.62 -2,864.63 2,460,232.55 345,115.87 0.00 3,059.21 12,100.00 54.61 289.59 10,661.83 10,517.83 1,100.95 -2,941.43 2,460,260.87 345,039.43 0.00 3,140.72 12,167.00 54.61 289.59 10,700.63 - 10,556.63 1,119.26 -2,992.89 2,460,279.85 , 344,988.21 0.00 3,195.33 9/1/2015 4:29:59PM Page 5 COMPASS 5000.1 Build 73 HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Soldotna CK Unit Site: Soldotna CK Unit Well: Soldotna CK Unit 12-3 Wellbore: Plan: SCU 31 B-04 Design: Plan: SCU 31B-04 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Soldotna CK Unit 12-3 SCU 31B-04 @ 144.00usft SCU 31 B-04 @ 144.00usft True Minimum Curvature Targets Target Name hltlmiss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting Shape V) V) (usft) (usft) (usft) (usft) (usft) SCU 31B-04 SIR _H1ST 0.00 0.00 10,221.00 892.92 -2,356.82 2,460,045.30 345,621.30 plan hits target center Circle (radius 50.00) SCU 31B-04 SR_H8ST 0.00 0.00 10,567.00 1,056.20 -2,815.67 2,460,214.50 345,164.60 plan hits target center Circle (radius 50.00) 9/1/2015 4:29:59PM Page 6 COMPASS 5000.1 Build 73 Hilcorp Energy Company Soldotna CK Unit Soldotna CK Unit Soldotna CK Unit 12-3 Plan: SCU 3113-04 Plan: SCU 3113-04 Sperry Drilling Services Clearance Summary Anticollision Report 01 September, 2015 Closest Approach 3D Proximity Scan on Current Survey Data )Highside Reference) Reference Design: Soldotna CK Unit - Soldotna CK Unit 12-3 - Plan: SCU 31B-04 - Plan: SCU 31B-04 Well Coordinates: 2,459,121.98 N, 347,966.38 E 160° 43' 41.97" N, 1506 50'57.36" W) Datum Height: SCU 318.04 @ 144.00usft Scan Range: 0.00 to 12,167.00 usft. Measured Depth. Scan Radius is 1,416.74 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Version: 5000.1 Build: 73 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Scan Type: 25.00 HALLIBUATON Sperry Drilling Services HALLIBURTON Anticollision Report for Soldotna CK Unit 12-3 - Plan: SCU 31B-04 Rileorp Energy Company Soldotna CK Unit Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: Soldotna CK Unit - Soldotna CK Unit 12-3 - Plan: SCU 31B-04 - Plan: SCU 31B-04 Scan Range: 0.00 to 12,167.00 usft. Measured Depth. Scan Radius is 1,416.74 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 Soldotna CK Unit Soldotna CK Unit 12-3 - SCU 123 - SCU 12-3 Soldotna CK Unit 12-3 - SCU 12-3 - SCU 12-3 Soldotna CK Unit 12-3 - SCU 12A-3 - SCU 12A-3 Soldotna CK Unit 12-3 - SCU 12A-3 - SCU 12A-3 Soldotna CK Unit 214 - SCU 21-4 - SCU 214 Soldotna CK Unit 214 - SCU 21A4 - SCU 21A4 Soldotna CK Unit 214 - SCU 228-04 - SCU 22B-04 Soldotna CK Unit 214 - SCU 22B-04 - SCU 22B-04 Soldotna CK Unit 214 - SCU 228-04 - SCU 22B-04 Soldotna CK Unit 3144 - SCU 322C-04 - SCU 322C-0 Soldotna CK Unit 323-04 - SCU 22-04PB1 - SCU 22-0 Soldotna CK Unit 323-04 - SCU 22-04PB1 - SCU 22-0 Soldotna CK Unit 323-04 - SCU 22-04PB1 - SCU 22-0 Soldotna CK Unit 323-04 - SCU 31-04 - SCU 31-04 Soldotna CK Unit 323-04 - SCU 31-04 - SCU 31-04 Soldotna CK Unit 323-04 - SCU 31-04 - SCU 31-04 Soldotna CK Unit 323-04 - SCU 31-04 PB1 - SCU 31-0 Soldotna CK Unit 33-05 - SCU 21C-04 - SCU 21C-04 Soldotna CK Unit 332-04 - SCU 332-04 - SCU 332-04 Soldotna CK Unit 332-04 - SCU 332-04 - SCU 332-04 Soldotna CK Unit 332-04 - SCU 332-04 - SCU 332-04 Soldotna CK Unit 341-04 - SCU 341-04 - SCU 341-04 Soldotna CK Unit 341-04 - SCU 341-04 - SCU 341-04 Soldotna CK Unit 341-04 - SCU 341-04 - SCU 341-04 Soldotna CK Unit 341-04 - SCU 41A-04 - SCU 41A-04 Soldotna CK Unit 341-04 - SCU 41A-04 - SCU 41A-04 Soldotna CK Unit 341-04 - SCU 418-04 - SCU 41 B-04 Soldotna CK Unit 341-04 - SCU 41 B-04 - SCU 418-04 12,167.00 716.95 12,167.00 668.60 10,375.00 14.827 Clearance Factor Pass - 12,167.00 601.34 12,167.00 553.98 10,756.06 12.697 Clearance Factor Pass - 12,106.42 968.25 12,106.42 870.42 10,447.91 9.898 Centre Distance Pass - 12,150.00 969.20 12,150.00 869.66 10,458.35 9.737 Ellipse Separation Pass - 12,167.00 970.08 12,167.00 869.86 10,462.60 9.679 Clearance Factor Pass - 12,167.00 1,118.44 12,167.00 985.73 11,971.07 8.428 Clearance Factor Pass - 11,740.99 1,342.94 11,740.99 1,215.84 11,331.00 10.566 Centre Distance Pass - 11,775.00 1,343.37 11,775.00 1,215.28 11,331.00 10.487 Ellipse Separation Pass - 12,167.00 1,408.89 12,167.00 1,269.27 11,331.00 10.091 Clearance Factor Pass - 11,763.46 347.06 11,763.46 237.30 11,775.00 3.162 Centre Distance Pass - 11,775.00 347.25 11,775.00 237.20 11,775.00 3.156 Ellipse Separation Pass - 11,800.00 348.97 11,800.00 238.30 11,775.00 3.153 Clearance Factor Pass - 11,876.80 109.09 91,876.80 23.38 11,967.00 1.273 Clearance Factor Pass - 12,167.00 1,186.40 12,167.00 1,066.11 12,090.00 9.862 Clearance Factor Pass - 10,608.28 797.26 10,608.28 575.18 9,785.81 3.590 Centre Distance Pass - 10,700.00 800.34 10,700.00 572.69 9,844.80 3.516 Ellipse Separation Pass - 10,850.00 819.18 10,850.00 583.41 9,932.00 3.475 Clearance Factor Pass - 10,387.37 467.94 10,387.37 360.45 9,707.49 4.353 Centre Distance Pass - 10,400.00 468.05 10,400.00 360.19 9,714.79 4.339 Ellipse Separation Pass - 10,450.00 470.72 10,450.00 361.51 9,743.69 4.310 Clearance Factor Pass - 10,468.36 454.70 10,468.36 347.89 9,856.61 4.257 Ellipse Separation Pass - 10,475.00 454.73 10,475.00 347.90 9,861.28 4.257 Clearance Factor Pass - 10,267.46 548.15 10,267.46 451.49 9,514.58. 5.671 Centre Distance Pass - 10,300.00 548.90 10,300.00 450.85 9,529.13 5.598 Ellipse Separation Pass - 01 September, 2015 - 15:59 Page 2of6 COMPASS HALLIBURTON Hilcorp Energy Company Soldotna CK Unit Anticollision Report for Soldotna CK Unit 12-3 - Plan: SCU 31 B-04 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: Soldotna CK Unit -Soldotna CK Unit 12.3 -Plan: SCU 318-04 -Plan: SCU 31B-04 Scan Range: 0.00 to 12,167.00 usft. Measured Depth. Scan Radius is 1,416.74 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 Soldotna CK Unit 341-04 - SCU 41 B-04 - SCU 41 B-04 10,425.00 565.43 10,425.00 462.29 9,585.08 5.482 Clearance Factor Pass - Soldotna CK Unit 341-04 - SCU 41B-04PBI - SCU 41B 10,272.39 553.50 10,272.39 455.28 9,538.66 5.635 Centre Distance Pass - Soldotna CKUnit 341-04-SCU 41 B-04PB1-SCU 41B 10,300.00 554.03 10,300.00 454.74 9,550.22 5.580 Ellipse Separation Pass- Soldotna CK Unit 341-04 - SCU 41 B-04PB1 - SCU 418 10,425.00 569.59 10,425.00 465.59 9,602.53 5.477 Clearance Factor Pass - Soldotna CK Unit 341-04 - SCU 42-04 -SCU 42-04 10,387.58 467.93 10,387.58 360.40 9,714.72 4.352 Centre Distance Pass - Soldotna CK Unit 341-04 - SCU 42-04 - SCU 42-04 10,400.00 468.04 10,400.00 360.14 9,721.87 4.338 Ellipse Separation Pass - Soldotna CK Unit 341-04 - SCU 42-04 - SCU 42-04 10,475.00 473.32 10,475.00 363.39 9,765.03 4.306 Clearance Factor Pass - Soldotna CK Unit 34-33 - SCU 34-33 - SCU 34-33 11,829.63 1,283.34 11,829.63 896.28 10,505.50 3.316 Centre Distance Pass - Soldotna CK Unit 34-33 - SCU 34-33 - SCU 34-33 11,925.00 1,285.70 11,925.00 894.37 10,560.73 3.285 Ellipse Separation Pass - Soldotna CK Unit 34-33 - SCU 34-33 -SCU 34-33 12,075.00 1,298.84 12,075.00 901.54 10,647.60 3.269 Clearance Factor Pass - Swanson River Unit Swanson Riv Unit 24-33 - SRU 24-33 - SRU 24-33 12,167.00 1,131.44 12,167.00 1,028.36 10,537.66 10.977 Clearance Factor Pass - Swanson Riv Unit 24-33 - SRU 44-33 - SRU 44-33 11,325.00 1,095.73 11,325.00 984.98 10,611.51 9.894 Clearance Factor Pass - Swanson Riv Unit 24-33 - SRU 44-33 - SRU 44-33 11,375.00 1,093.57 11,375.00 983.84 10,574.19 9.966 Ellipse Separation Pass - Swanson Riv Unit 24 -33 -SRU 44 -33 -SRU 44-33 11,417.98 1,092.94 11,417.98 983.89 10,546.76 10.022 Centre Distance Pass - Survey tool program From To Survey/Plan (usft) (usft) 80.007,500.00 7,500.00 12,167.00 Plan: SCU 31B-04 Survey Tool SR -Gyro -SS MWD+SC+sag 01 September, 2015 - 15:59 Page 3 of 6 COMPASS HALLIBURTON Anticollision Report for Soldotna CK Unit 12-3 - Plan: SCU 31 B-04 Ellipse error terms are correlated across survey tool ti—n points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Hilcorp Energy Company Soldotna CK Unit 01 September, 2015 - 15:59 Page 4 of 6 COMPASS HALLIBURTON Project: Soldotna CK Unit REFERENCE INFORMATION WELL MEWLS: S.U.-CK Unit 12-3 NAD 1927(NADCON CONUS) Alaska Zone 04 Site: Soldotna CK Unit Co IM (WE) R.N.— Wall SeMolna CK Unit 123, Tr NOM Grouts Level 126.00 Venkal (TVI) R.N.— SCU 316. a 14 —ft +WS +F/ -W Np Latittude Lop it de Slot Well: Soldotna CK Unit 12-3 Fa6.38 8'6 a oruu. Measured M,. Reba SCU 316.@itsppuap 21.98 perry s Wellbore: Plan: SCU 318-04 Cakuladon Mat— Minimum curvature 0.00 0.00 2459121.98 347966.38 60.7283252 -150.8492673 Plan: Plan: SCU 31B-04 CASING DETAILS Em No casng data isavailable 250.00 c_ p 200.00 0 0 c a 150.00 NN a 100.00 d c N U 0 50.00- 0.000.00 0. 00 7500 7750 8000 8250 8500 8750 9000 9250 9500 9750 10000 10250 10500 10750 11000 11250 11500 11750 12000 12250 Measured Depth (500 usft/in) 5.00 4.00 `o li 3.00 c 0 2.00 Collision Risk Procedures U I I Collision Avoidance RUT. 1.00 I I No -Go Zone - Stop Drill 0.00 7500 7800 8100 8400 8700 9000 9300 9600 9900 10200 10500 10800 11100 11400 11700 12000 12300 Measured Depth (500 usfttin) TRANSMITTAL LETTER CHECKLIST WELL NAME: 5e7 a PTD: �' Development _ Service Exploratory _ Stratigraphic Test _ Non -Conventional r FIELD:�`d��c �it ��1 POOL: 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 sam les 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) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool SWANSON RIVER, HEMLOCK OIL - 772100 PTD#: 2160100 Company HILCORP ALASKA LLC Initial Class/Type Well Name: SOLD TNA CK UNIT 31B-04 —Program DEV Well bore seg ❑ DEV / 1 -OIL GeoArea 820 -_ Unit _51950 On/Off Shore On Annular Disposal ❑ Administration 17 Nonconven, gas conforms to AS31.05.0304.1.A),(j,2.A-D) - - - - - - - _ - - - - - - - - - N_A--- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ - _ _ - - - - 1 Permit fee attached- - - - - - - - - - - NA- _ _ - _ - 2 Lease number appropriate_ - _ _ _ Yes . - - _ _ - - Entire well within former -Federal Lease _(now-Hilcorp Fee Lease) FEDA02.8997-------------- - - - - - - - 3 Unique well name -and number ---- - _ - _ - Yes- - - - - - - - - - - - - - - 4 Well -located in_a_defined -pool ----------------- - _ _ - - _Yes . - This well will_open Swanson River, Hemlock Oil Pool --772100 governed by CO 1236. - _ - _ - _ _ _ _ _ 5 Well -located proper distance from drilling unit- boundary - - - - - - _ - _ - - _ _ _ _ - _ _ -Yes - - _ CO 1238, Rule 5:_ There -shall be_no_restnctiQns as to_the well spacing -within the -Hemlock - it _Pool except. 6 Well -located proper distance from other wells- - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - that -no wellbore maybe open to test or regular production -in a well within -500' of the external property_ _ 7 Sufficient acreage -available in_drilling unit _ . _ _ - - _ _ _ - - - - Yes - - - _ - - -line of the Affected Area- where- the owners -and landowners are_ n_ot the same on_both-sides of the line. As - 8 If deviated, is -wellbore plat -included - - - _ _ -_ _ _ _ _Yes - _ _ - _ _ - planned, this well -conforms -to spacing requirements._ - _ _ _ _ - 9 Operator onlyaffected party _ - - _ - _ _ _ - _ - - _ Yes - - - - - - - - - - - - - - - - - - - - - - - - I10 Operator has -appropriate bond in force _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ Yes _ _ _ - _ _ _ _ _ _ _ - - - - - - - - - - - - - - - - - - - - - - . _ - - - - _ Appr Date 11 Permit_can be issued without conservation order_ - - - - - - _ - _ - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 12 PermitcanbeissuedWithoutadministrativ_e_approval-------------------- Yes --------------------- SFD 1/19/2016 13 Can permit be approved before 15 -day wait- - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - . - - - - - - - - - - - - - - - - - - - - - - - 14 Well -located within area and strata authorized by Injection Order# (put 10# in -comments) (For _N_A_ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ _ - - - - _ _ - - - - 15 _All wells—within-1/4 mile -area -of review identified (For service well only)- - - - - - - - - - - - - NA_ - _ - _ _ _ _ _ _ _ _ - - - - - - - - _ - - _ - _ - - - - - - _ - _ _ - _ - - - - 16 -Pre-produced injector: duration -of pre production less than 3 months-(For_service well only) - - NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 18 -Conductor string_provided _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ - - - - _ - - Conductor set-in mot_her_bore well. _(SCU 12A-03)_ _ _ _ _ . Engineering 19 S-urface casing protectsall_knownUSDWs - - - -- - - - - - - - - - - - - - - - - - - - - - - - - - N_A-------- Surf_acecasingset_ _ _ _ _ - _ - _ _ - _ - - _ - - - - - - - - - ------------------- 20 CMT -vol -adequate _to circul_ate_on conductor & surf _csg - - - - - - - - - - - - - - - - - - - - - - - - NA- _ - - - _ - - Sruface casing fully cemented._ - - - _ - - - - - - - _ - - - _ - - - - - _ - _ - - - 21 CMT-v_ol- adequate to tie -in -long string to -surf csg----------------------------- A- _ _ _ _ _ _ _ will cut window in T' cainsg at 7500 ft to sidetrack -to 31 B-04 22 _C_MT_will coverall known -productive horizons - - - - - - - - - - - - - - - - - - - - - _ _ _ Yes - _ _ _ _ _ _ 4.5"-liner_will, be fully cemented -back to liner lap, _ - _ _ - 23 _Casing designs adequate for C,_T, B &_ permafrost- - - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ _ _ _ _ _ _ CTB calcs provided.- No permafrost in area.- - - - _ - _ _ _ _ _ _ - _ _ _ - _ _ - - - - - - - - _ - 24 Adequate tankage_or reserve pit - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - Rig has steel pits-..-. all waste to approved disposal_ well._ - - - - - - - - - - _ _ - _ _ _ - - - - -- - 25 -If-a- re --drill, has_a 10-403 for abandonment been approved ------------------- - - - - - - - - - - - - - - - - - - Yes - - - - _ - - Sundry -316-046 for P &A of SCU 12A-03- _ _ _ _ _ - - - - - - - - - - _ - _ _ _ _ - - _ _ _ _ - _ - - _ - - - - - - - - - 26 Adequate wellbore separation proposed_ - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ - _ _ _ _ _ Well path diverges from motherbore_well.. SCU 12A-03 - - - - - - _ _ _ _ _ _ _ _ - - _ _ _ _ - _ _ . _ - _ _ _ _ _ _ - 27 If_diverter required, does it meet regulations- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - N _ A _ _ _ _ _ _ Wellhead in place ..._will utilize_ BOPE_. - - - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Appr Date 28 Drilling fluid program schematic-&- equip Iist_adequate- - - - - - - - - - - - - - - - - - - - - - - - - Yes _ _ _ _ - _ _ Max formation_ pressure =2782 psi (5,7_ppg EMW for Hemlock) drillingwith 9,5-11.5 ppg_mud_ _ _ _ _ _ _ _ _ _ _ GLS 1/26/2016 29 BOPEs, d-0 they meet regulation - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - _ - - - - - Tyonek water sands may be higher pressure_(approx 11 ppg...._But will be managed with ECD and salt pills. 30 _B_OPE-press rating appropriate; test to_(put psig in comments)- - - - - - - - - - - - - - - - - - - - Yes _ _ _ _ _ _ - MASP= 1712 psi -Will test BOPE to 3500 psi (annular to_2500 psi)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - 31 Choke_ manifold complies WAPI_RP-53(May 84)---------------------------- Yes - - - - - - _ - - _ - - - - _ _ _ _ - - - -- - _ - _ _ _ _ _ - - - - - - - _ - _ - - - - _ - - - - - - _ - _ - - _ - - _ _ _ _ - _ - _ - _ _ - - 32 Work will occur without operation shutdown_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _Yes - _ _ _ _ _ _ -sundry required for well completion operations._ Tubing and perfs.,-------------------------- 33 Is presence of H2S gas probable_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No_ - - - - - - - H2S not expected .. Rig has sensors and alarms ------------------- - - - - - - _ _ _ 34 Mechanic al_ condition of wells within AOR verified (For service well only) NA_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 35 Permit can be issued w/o hydrogen _sulfide measures - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ _ _ _ _ _ _ H2S not reported from_Soldotna Creek Unit or_Swanson River Field.- _ - _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ Geology 36 Data_presented on potential overpressure zones - - - - - - - - - - - - - - - - - - - - _ _ _ _ _ _ _ _ Yes _ _MW )_e _ p _ _ ,will be drilled_ using 9,5_--11 _5ppg mud. _ _ _ - _ _ _ _ _ _ Underpressured reservoir -(3.0 to -5.2 ppg_ - _ _ Ex ected Appr Date 37 Seismic-analysis_of shallow gas -zones ----------------------------------- A_ _ _ _ - _ _ _ High-pressure_ Tyonek Water Sand (11.5-12.5 ppg) lies at about 9100'_MD/ 8900' TVD._Hilcorp _ _ _ _ _ _ - SFD 1/19/2016 38 Seabed condition survey _(if off -shore) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _N_ - _ _ _ _ _ _ _ weights up -11.5 ppg and kills any flow with ECD while drilling, Before tripping, heavy -pills are_ - - - - 39 Contact name/phone for weekly -progress reports_ [exploratory only] _ _ _ _ - - _ _ _ _ - _ NA_ _ _ _ _ _ _ _ spotted to stop any _flow. _Any flow is treated as gas until Hilcorp is certain that it is -NOT gas__ _ _ _ _ _ _ _ _ _ _ _ _ Geologic Engineering Public Date Sidetrack of existing well SCU 12A-03. will cut windown in 7" at 7500 ft md. GLS Date: Date Commissioner: Commissioner: Commissioner ,lzS'I/b /al�
