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216-131
Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/02/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251002 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 11A 50133205210100 224123 9/23/2025 YELLOWJACKET PERF T40937 BCU 13 50133205250000 203138 8/18/2025 YELLOWJACKET GPT-PERF T40938 BCU 13 50133205250000 203138 8/26/2025 YELLOWJACKET GPT-PERF T49038 BCU 13 50133205250000 203138 8/21/2025 YELLOWJACKET GPT-PLUG T40938 BCU 23 50133206350000 214093 9/10/2025 YELLOWJACKET PERF T40939 BCU 24 50133206390000 214112 9/16/2025 YELLOWJACKET PLUG-PERF T40940 BRU 212-35T 50283200970000 198161 9/18/2025 AK E-LINE Perf T40941 BRU 224-34T 50283202050000 225044 7/29/2025 AK E-LINE CBP/Punch T40942 BRU 224-34T 50133207170000 225044 9/19/2025 AK E-LINE GPT/Perf T40942 END 1-05 50029216050000 186106 9/25/2025 YELLOWJACKET IPROF T40943 END 2-08 50029217710000 188004 8/11/2025 YELLOWJACKET PERF T40944 END 4-50 50029219400000 189044 9/8/2025 YELLOWJACKET P-PROF T40945 KBU 11-08Z 50133206290000 214044 9/15/2025 AK E-LINE Perf T40946 KU 33-08 50133207180000 224008 7/1/2025 YELLOWJACKET PERF T40947 KU 41-08 50133207170000 224005 8/28/2025 YELLOWJACKET PERF T40948 KU 41-08 50883201990100 224005 9/16/2025 AK E-LINE Perf T40948 MPU R-108 50029238210000 225062 8/14/2025 YELLOWJACKET SCBL T40949 MRU K-06RD2 50733200880200 216131 9/12/2025 AK E-LINE CBL T40950 MRU M-01 50733203880000 187046 9/20/2025 AK E-LINE Perf T40951 MRU M-25 50733203910000 187086 9/21/2025 AK E-LINE Perf T40952 NCIU A-21A 50883201990100 225075 8/21/2025 AK E-LINE CBL T40953 NFU 14-25 50231200350000 210111 9/3/2025 YELLOWJACKET PERF T40954 PBU PTM P1-08A 50029223840100 202199 9/13/2025 YELLOWJACKET SCBL T40955 PBU W-35A 50029217990200 225076 9/17/2025 YELLOWJACKET SCBL T40956 SRU 241-33 50133206630000 217047 9/17/2025 AK E-LINE Perf T40957 SRU 32A-33 50133101640100 191014 9/23/2025 AK E-LINE Perf T40958 SRU 32A-33 50133101640100 191014 9/21/2025 AK E-LINE Perf T40958 Please include current contact information if different from above. MRU K-06RD2 50733200880200 216131 9/12/2025 AK E-LINE CBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.03 09:00:56 -08'00' 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 May 12, 2025 Mr. Dan Marlowe Operations Manager – CI Offshore Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 RE: No-Flow Verification Trading Bay Unit K-06RD2 PTD 2161310 Dear Mr. Marlowe: On April 23, 2025, an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no-flow test of Trading Bay Unit K-06RD2 located on the King Salmon Platform in Cook Inlet. The AOGCC Inspector confirmed that the proper test equipment was rigged up prior to the test as outlined in AOGCC Industry Guidance Bulletin 21-001. The test procedure employed was a 1 hour shut in period to monitor pressure build up followed by a short flow period through the test equipment to an open top tank – repeated 1 additional time. There was neither gas nor oil flow rates observed during the no-flow test. Trading Bay Unit K- 06RD2 may be produced without a subsurface safety valve as confirmed by the AOGCC Inspector at the conclusion the test. A fail-safe automatic surface safety valve system capable of preventing uncontrolled flow must be maintained in proper working condition in this well as required in 20 AAC 25.265. The subsurface safety valve must be returned to service if Trading Bay Unit K-06RD2 demonstrates an ability to flow unassisted to surface. Any cleanout, perforating or other stimulation work in this well will necessitate a subsequent no-flow test. Please retain a copy of this letter on the King Salmon Platform. Sincerely, James B. Regg Petroleum Inspection Supervisor ecc: P. Brooks AOGCC Inspectors James B. Regg Digitally signed by James B. Regg Date: 2025.05.12 12:58:42 -08'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9.Property Designation (Lease Number):10.Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 13,322 11,388 Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 7,100psi Liner 4,790psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16.Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Casey Morse Contact Email:Casey.Morse@hilcorp.com Contact Phone:(907) 777-8322 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Other: Install ESP Trading Bay Unit K-06RD2 McArthur River Hemlock Oil Same 9,841 13,264 9,833 2,580psi N/A Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY 6,890psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017594 / ADL0018772 216-131 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20088-02-00 Hilcorp Alaska, LLC N/A Length Size Proposed Pools: L-80 TVD Burst 2,364 8,150psi MD 3,090psi 376' 2,094' 376' 2,186' 6,324'9-5/8" 24" 13-3/8" 376' 2,186' 8,062' Perforation Depth MD (ft): 11,960 - 13,153 8,062' 7-5/8" 9,683 - 9,820 3/14/2025 13,320'5,387' 4-1/2" 9,841' N/A & N/A N/A & N/A No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 325-116 By Gavin Gluyas at 1:49 pm, Feb 28, 2025 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2025.02.28 13:38:48 - 09'00' Dan Marlowe (1267) * BOPE test to 3000 psi. Annular to 2500 psi. MGR28FEB2024 DSR-2/28/25 10-404 2,580ps A.Dewhurst 10MAR25*&: 3/10/2025Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.10 16:02:25 -08'00' RBDMS JSB 031125 RWO Fish and RTP Well: K-06RD2 Well Name:K-06RD2 API Number:50-733-20088-02-00 Current Status:Shut in Oil Producer Leg:Leg #4 (NW corner) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:216-131 First Call Engineer:Casey Morse (907) 777-8322 (603) 205-3780 (c) Second Call Engineer:Dan Marlowe (907) 398-9904 (c) Maximum Expected BHP:3,562 psi @ 9,820’ TVD (7.0ppg) 6/23/23 Static after 6 days SI Max. Potential Surface Pressure: 2580 psi Using 0.1 psi/ft Brief Well Summary K-06RD2 is a horizontal Hemlock only oil producer that was sidetracked to its current bore in 2017. A RWO began in July of 2024 to swap the ESP and perform a cleanout to restore productivity. During the 2024 workover, the ESP was recovered, and the cleanout progressed to 11,606’ until one of the BHA’s became stuck. The work string was cut, and minimal efforts were made to recover the fish before deciding to run a kill string and move off the well. The goal of this project is to fish the BHA left in hole, clean out the horizontal liner, and run a new ESP completion. Pertinent wellbore information: - January-2017 sidetrack / completion o Cleanout 7-5/8" liner to 13,250' MD with 6.125" bit and 7-5/8" casing scraper o 2/10/17: MIT of 7-5/8” liner and 9-5/8” casing PASSED to 2640psi (before any perfs shot) - Nov-2021: ESP swap RWO with cleanout o Packer / pump pulled with no issues (120k hanging weight) o 3" SL bailer tagged at 11,660' MD (300' above top perf) o Performed liner cleanout with 6-1/2" bit. Tagged at 11,615' MD. Circ pressure broke from 780 to 100psi Then TIH on elevators to top perf with no problem and called it good there. "Chunky scale" came across shakers -6/9/22: Most recent NFT PASSED - July-2024 o ESP was parted due to corrosion. Fished out MLE and ESP assembly, left 3 motor clamps in hole o Clean out to 11,606’. Losses increased to 50 bph. Spot salt pill to cure losses. Started to reverse circulate, pipe stalled out. PU to 11,575’ and pipe stuck. o Make RCT cut @ 11,388’ inside 2-7/8” PH6. o Attempt to latch fish unsuccessful. o Run kill string and RDMO RWO Fish and RTP Well: K-06RD2 RWO Procedure: 1. MIRU Hilcorp Rig #404 2. Circulate and bullhead wellbore volume: a. Work over fluid will be filtered inlet water (8.4ppg) or heavier b. Ensure any wellbore fluids are fully displaced with KWF either via circulation or bullheading c. Kill string volume = 36bbls d. Kill string x IA volume = 122bbl e. Casing to top perf: 593bbl 3. Set BPV/TWC, ND tree, NU BOP a. Notify AOGCC 48 hours in advance for witness b. Test to 250psi Low / 3,000psi High / 2,500psi Annular c. BOP’s will be closed as needed to circulate the well 4. BOLDS and unseat hanger 5. POOH with 4-1/2” kill string 6. PU 3-1/2” workstring 7. TIH w/ test packer to ~10,000’ MD. Set packer and pressure test casing to above 2050 psi (8150’ TVD x 0.25 = 2038 psi) for 30 minutes. 8. PU BHA to clean and dress fish top. Wash over / latch stuck BHA a. RU eline as necessary to support fishing and pipe recovery b. RU casing jacks as necessary to support pipe recovery 9. MU 7-5/8” liner cleanout assembly 10. RIH and mill/cleanout 7-5/8” liner to target depth = 13,264’ MD (PBTD) 11. POOH and lay down cleanout BHA and workstring 12. PU, RIH with new ESP completion a. No packer nor SSSV is planned b. Bottom of ESP planned for ±10,025’ MD 13. Land ESP completion 14. Set BPV/TWC, ND BOP, NU tree and test, pull BPV/TWC 15. Turn well over to production Post-RWO Procedure: 16. Conduct No Flow Test after ~10 days of production Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Current and Proposed Wellhead Diagram (no changes) 4. BOP Drawing 5. Fluid/Flow Diagrams 6. RWO Sundry Change Form _____________________________________________________________________________________ Updated By: JLL 09/10/24 SCHEMATIC McArthur River Field Well: TBU K-06RD2 PTD: 216-131 API: 50-733-20088-02 Last Completed: 08/29/24 PERFORATION DETAIL Zone Top MD Bottom MD Top TVD Bottom TVD Feet SPF Date Status HK-2 11,960’ 13,153’ 9,683’ 9,820’ 1,193’ 6 12/19/2016 Open CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 24” - - - Surf 376’ 13-3/8" 61 J-55 BTC 12.515” Surf 2,186' 9-5/8"53.5** S-95 BTC 8.535” Surf 1,968' 47 L-80 BTC 8.681” 1,968' 8,062' (TOW) 7-5/8" 29.7 L-80 Hyd 511 6.875” 7,933' 13,320' TUBING DETAIL 4-1/2” 12.6 L-80 Supermax 3.958 Surf 2,364' **Note 1988 files indicate that 53.5# 9-5/8” should have been at the bottom of the K-06rd which is below K- 06rd2 sidetrack depth. This has not been confirmed. CEMENT DETAILS 13-3/8"18" hole: Cemented with 1100sxs class G lead followed by 560 sxs.Saw returns to Surface. 9-5/8" 12-1/4" Hole in 1988 sidetrack (K-06RD): Ran casing from 11958' MD back to surface. Cemented with 1050sxs 15.8ppg class G cement. Volumetrics suggest ToC below current KOP of 8062’ MD.No cement behind 9-5/8” in current bore. 7-5/8”8-1/2" hole: Cemented with 62.5bbls 15.3ppg. 27% losses noted during cement job. No cement seen to surface. 2/17/17 CBL could only fall to 11,900' MD.ToC at 11,800' from 2/17/17 CBL. JEWELRY DETAIL No Depth MD Depth TVD ID OD Item 1 49’ 49’ 3.958” 13.625” Tbg Hanger FISH DETAILS 11,388' ELM 8/25/24 - BHA left in hole - 5.875" taper mill, 6.6" string mill, 43/4" bumper sub, 4 1/4" oil jar, 4- 4 3/4" spiral drill collars, 4.75" xo 2 7/8" PH6 box X 3 1/2" if pin, one joint 2, 7/8" 7.9# PH6 tubing, one cut joint 2 7/8" 7.9# PH6 tubing 14.68', =199.56' overall length PBTD= 13,264’ MD TD = 13,322’ MD 1 7-5/8” Liner Hanger 7,933’ Min ID 6.670” HK-2 Max Hole Angle = 86.29° @ 11,921’ 13-3/8” 9-5/8” TOC 11,800’ 24” 8-1/2” TOW 8,062’ KOP 2,193’ 8/23/24 - Last tag @ 11,606' Fish: 11,388' - 11,588' ELM _____________________________________________________________________________________ Updated By: CDM 02/27/25 PROPOSED McArthur River Field Well: TBU K-06RD2 PTD: 216-131 API: 50-733-20088-02 Last Completed: Future PBTD= 13,264’ MD TD = 13,322’ MD 1 2 7-5/8” Liner Hanger 7,933’ Min ID 6.670” HK-2 Max Hole Angle = 86.29° @ 11,921’ 13-3/8” 9-5/8” TOC 11,800’ 24” 8-1/2” TOW 8,062’ KOP 2,193’ CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 24” - - - Surf 376’ 13-3/8" 61 J-55 BTC 12.515” Surf 2,186' 9-5/8"53.5** S-95 BTC 8.535” Surf 1,968' 47 L-80 BTC 8.681” 1,968' 8,062' (TOW) 7-5/8" 29.7 L-80 Hyd 511 6.875” 7,933' 13,320' TUBING DETAIL 4-1/2” Surf ±7,800' 3-1/2” ±7,800' ±9,850' **Note 1988 files indicate that 53.5# 9-5/8” should have been at the bottom of the K-06rd which is below K- 06rd2 sidetrack depth. This has not been confirmed. JEWELRY DETAIL No Depth MD Depth TVD ID OD Item 1 49’ 49’ 3.958” 13.625” Tbg Hanger, OCT-UH-TC-1A ESP 13 x 4-1/2 IBT lift and susp, w/" type BPV profile, 3/8 cont. control line port 2 ±9,850' ±8,050' Discharge, Bolt-On Pumps Intake Seals Motor Centralizer Anode PERFORATION DETAIL Zone Top MD Bottom MD Top TVD Bottom TVD Feet SPF Date Status HK-2 11,960’ 13,153’ 9,683’ 9,820’ 1,193’ 6 12/19/2016 Open 13-3/8"18" hole: Cemented with 1100sxs class G lead followed by 560 sxs.Saw returns to Surface. 9-5/8" 12-1/4" Hole in 1988 sidetrack (K-06RD): Ran casing from 11958' MD back to surface. Cemented with 1050sxs 15.8ppg class G cement. Volumetrics suggest ToC below current KOP of 8062’ MD.No cement behind 9-5/8” in current bore. 7-5/8”8-1/2" hole: Cemented with 62.5bbls 15.3ppg. 27% losses noted during cement job. No cement seen to surface. 2/17/17 CBL could only fall to 11,900' MD.ToC at 11,800' from 2/17/17 CBL. King Salmon Platform K-06RD2 BHTA, B-11-A0, 4 1/16 5M FE Valve, Swab, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Master, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Wing, CIW-FL, 3 1/8 5M FE, HWO, EE trim All unihead annular valves, 2 1/16 5M FE OCT-20, HWO Valve, OCT-20, 3 1/8 2M FE, HWOStarting head, OCT, 21 ¼ 2M FE X 24'’ SOW, w/ 1- 3 1/8 2M EFO, full set of lockpins Unihead, OCT type 3, 13 5/8 5M API hub top X 13 3/8 BTC casing bottom, w/ 1- 2 1/16 5M SSO on lower section, 1- 2 1/16 5M SSO on middle section, 3- 2 1/16 5M SSO on upper section , IP internal lockpin assy Adapter, OCT-A5-ESP, 13 5/8 5M API hub X 4 1/16 5M stdd top, w/ 2- ½ control line exits, prepped w/ OCT 400-4 pocket King Salmon K-06RD2 24 X 13 3/8 X 9 5/8 X 4 ½ Tbg hanger, OCT-UH-TC-1A- ESP, 13 X 4 ½ IBT lift and susp, w/ 4'’ Type H BPV profile, 3/8 cont control line port 24'’ 13 3/8'’ 9 5/8'’ 4 ½’’ Valve, Wing, WKM-M, 2 1/16 5M FE, HWO, AA trim Valve, Wing, WKM-M, 3 1/8 5M FE, w/ OMNI oper, EE trim BOP Stack HAK 404 HILCORP ALASKA, LLC Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well: K-06RD2 (PTD 216-131)Sundry #:Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC 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 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date 2025-0423_No-Flow_TBU_K-06RD2_jh Page 1 of 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: 5/1/2025 P. I. Supervisor FROM: Joshua Hunt SUBJECT: No Flow Test Petroleum Inspector TBU K-06RD2 Hilcorp Alaska LLC PTD 2161310 4/23/2025: I traveled to the King Salmon platform and met with Hilcorp representative KC Dent. We went over the no flow guidance bulletin and the calibration paperwork for the low flow meter and low-pressure gauge. Both were current. I was informed the well has been completely dead with a 0 psi reading when shut in. We went to the well room, and I inspected the setup. They had ¾-inch stainless tubing connecting the IA and the tubing with the same size tubing going in and out of the low flow meter. The following table shows test details: Time Pressures1 Flow Rate2 Remarks (psi) Gas – scf/hr Liquid – gal/hr 8:46 0/0/11 Shut in for test 9:01 0/0/11 9:16 0/0/11 9:31 0/0/11 9:46 0/0/11 0 0 Open to flow/ Shut in for test 10:01 0/0/11 10:16 0/0/11 10:31 0/0/11 10:46 0/0/11 0 0 Open to flow. End of test 1 Pressures are T/IA/OA 2 Gas flow not to exceed 900 scf/hr; Liquid flow not to exceed 6.3 gal/hr This well was extremely dead and passed the No-Flow inspection. Attachments: Certifications – Pressure Gauge and Meter 9 9 9 99 99 9 James B. Regg Digitally signed by James B. Regg Date: 2025.05.09 15:27:24 -08'00' For recertification, contact Victoria Askin 283-1308 Cathy Marshall 283-1384 or Lori Williams 283-1360 Calibration Certificate Pressure Standards Referenced to NIST Annually. Gauge Type: Pressure Range:0 - 30 S/N Number: 9/7/2024 1506240066 UOCD 4532 SSI Technologies Date:I.D. Number: Test Pressure Indication This certificate expires in one year on 9/7/2025 922395 30.0730 00 Calibrated By:99LFWRULD$VNLQ Test Equipment S/N 7.57.5 22.6222.5 15.1115 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________TRADING BAY UNIT K-06RD2 JBR 04/28/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:2 2 7/8" and 4 1/2" test joints used for testing. The rig floor LEL gas detector needed to be calibrated to reach the level for the audible. Passed retest. The blinds failed on the high. Troubleshooting and retests confirmed the blinds were the issue. I left location as they began the process of pulling the blinds to redress them so I did not witness the passing test. I had Harold Soule send me the test chart for the passing test. 20 charge bottles ranging from 950 psi to 1150 psi. Test Results TEST DATA Rig Rep:J. Stockman/R. RobsonOperator:Hilcorp Alaska, LLC Operator Rep:H. Soule/B. Bordelon Rig Owner/Rig No.:Hilcorp 404 PTD#:2161310 DATE:3/13/2025 Type Operation:WRKOV Annular: 250/3000Type Test:INIT Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopGDC250311110650 Inspector Guy Cook Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 5.5 MASP: 2580 Sundry No: 325-116 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 11 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13 5/8" 5000 P #1 Rams 1 2 7/8"x5.5" V P #2 Rams 1 Blinds F #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 2 1/16" 5000 P HCR Valves 2 2 1/16" 5000 P Kill Line Valves 2 2 1/16" 5000 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3100 Pressure After Closure P1700 200 PSI Attained P18 Full Pressure Attained P114 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P6@1850 ACC Misc NA0 NA NATrip Tank P PPit Level Indicators NA NAFlow Indicator P FPMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P13 #1 Rams P6 #2 Rams P6 #3 Rams NA0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1 %OLQG5DPUHWHVWFKDUWDWWDFKHG 9 9 9 9999 9 9 9 9 9 rig floor LEL gas detector blinds failed on the high did not witness the passing test FKDUWDWWDFKHG FPMeth Gas Detector Blinds F BOPE – Hilcorp 404 – Blind Ram Retest TBU K-06RD2 (PTD 2161310) AOGCC Insp # bopgdc250311110650 3/13/2025 2024-0925_No-Flow_TBU_K-06RD2_jh Page 1 of 4 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: 9/26/2024 P. I. Supervisor FROM: Josh Hunt SUBJECT: No Flow Test Petroleum Inspector TBU K-06RD2 Hilcorp Alaska LLC PTD 2161310 9/25/2024: I traveled to OSK Dock and flew by helicopter out to the King Salmon Platform and met with KC Dent who represents Hilcorp. They provided all the necessary paperwork required for this inspection. We went over the plan to shut-in K-06RD2 to monitor pressure buildup while we test the safety valve systems on the 4 electric submersible pump wells. Everything went according to plan. I checked all the calibration stickers on the gauges and the paperwork, confirmed that the IA was tied into the tubing upstream of the low-flow meter. All the piping was correctly installed in accordance with Test Option “A” found in Industry Guidance Bulletin 21-001. The well was opened three times at roughly 1-hour intervals and the well was found to be on a vacuum and remained that way throughout the test. The following table shows test details: Time Pressures1 Flow Rate2 Remarks (psi) Gas – scf/hr Liquid – gal/hr 8:40 0 / 0 / 4 Shut in at 8:40 8:55 0 / 0 / 4 9:10 -0.01 / 0 / 4 9:25 -0.01 / 0 / 4 0 0 Opened to flow; vacuum 9:40 -0.01 / 0 / 4 9:55 -0.01 / 0 / 4 10:10 -0.01 / 0 / 4 10:25 -0.02 / 0 / 4 10:40 -0.02 / 0 / 4 0 0 Opened to flow; vacuum 10:55 -0.02 / 0 / 4 10:10 -0.02 / 0 / 4 11:25 -0.02 / 0 / 4 11:40 -0.02 / 0 / 4 0 0 Opened to flow; vacuum 1 Pressures are T/IA/OA 2 Gas flow not to exceed 900 scf/hr; Liquid flow not to exceed 6.3 gal/hr Attachments: Photos (3); Test Equipment Calibration Records 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2024.11.07 12:59:40 -09'00' 2024-0925_No-Flow_TBU_K-06RD2_jh Page 2 of 4 No-Flow Test – TBU K-06RD2 (PTD 2161310) Photos by AOGCC Inspector J. Hunt 9/25/2024 Test manifold off tree cap – Full opening HP qtr turn valve, Low-Flow meter and LP gauge Low-Pressure gauge calibration sticker 2024-0925_No-Flow_TBU_K-06RD2_jh Page 3 of 4 Stainless ¾-inch pipe connecting the IA to the Tubing. 2024-0925_No-Flow_TBU_K-06RD2_jh Page 4 of 4 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 November 13, 2024 Mr. Dan Marlowe Operations Manager – CI Offshore Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 RE: No-Flow Verification Trading Bay Unit K-06RD2 PTD 2161310 Dear Mr. Marlowe: On September 25, 2024, an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no-flow test of Trading Bay Unit K-06RD2 located on the King Salmon Platform in Cook Inlet. The AOGCC Inspector confirmed that the proper test equipment was rigged up prior to the test as outlined in AOGCC Industry Guidance Bulletin 21-001. The test procedure employed was a 1 hour shut in period to monitor pressure build up followed by a short flow period through the test equipment to an open top tank – repeated two additional times. There was no oil and no gas flow rates observed during the no-flow test. Trading Bay Unit K- 06RD2 may be produced without a subsurface safety valve as confirmed by the AOGCC Inspector at the conclusion the test. A fail-safe automatic surface safety valve system capable of preventing uncontrolled flow must be maintained in proper working condition in this well as required in 20 AAC 25.265. The subsurface safety valve must be returned to service if Trading Bay Unit K-06RD2 demonstrates an ability to flow unassisted to surface. Any cleanout, perforating or other stimulation work in this well will necessitate a subsequent no-flow test. Please retain a copy of this letter on the King Salmon Platform. Sincerely, James B. Regg Petroleum Inspection Supervisor ecc: P. Brooks AOGCC Inspectors James B. Regg Digitally signed by James B. Regg Date: 2024.11.14 09:45:56 -09'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Ran Kill String Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 13,322 feet N/A feet true vertical 9,841 feet 11,388 feet Effective Depth measured 11,388 feet N/A feet true vertical 9,445 feet N/A feet Perforation depth Measured depth 11,960 - 13,153 feet True Vertical depth 9,683 - 9,820 feet Tubing (size, grade, measured and true vertical depth) 4-1/2" L-80 2,364 (MD) 2,260 (TVD) Packers and SSSV (type, measured and true vertical depth) N/A & N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: Hemlock Oil 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: 7,100psi 3,090psi 8,150psi 2,186 2,094 Burst Collapse 1,540psi measured TVD Production Liner 8,062 5,387 Casing Structural 6,324 7-5/8" 8,062 13,320 9,841 376 2,186 376Conductor Surface Intermediate 24" 13-3/8" 6,890psi 9-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 216-131 50-733-20088-02-00 3. Address: Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0017594 / ADL0018772 McArthur River / Hemlock Oil Trading Bay Unit K-06RD2 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD Top of fish to 200' below fish 0 Size 376 0 00 0 00 0 324-372 Sr Pet Eng: 4,790psi Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Ryan Rupert Ryan.Rupert@hilcorp.com 907 777-8503Operations Manager 275 gallons of AR acid followed by FIW, FCP 1000 psi. Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 3:41 pm, Oct 08, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.10.08 12:58:44 - 08'00' Dan Marlowe (1267) _____________________________________________________________________________________ Updated By: JLL 09/10/24 SCHEMATIC McArthur River Field Well: TBU K-06RD2 PTD: 216-131 API: 50-733-20088-02 Last Completed: 08/29/24 PERFORATION DETAIL Zone Top MD Bottom MD Top TVD Bottom TVD Feet SPF Date Status HK-2 11,960 13,153 9,683 9,820 1,193 6 12/19/2016 Open CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 24 - - - Surf 376 13-3/8" 61 J-55 BTC 12.515 Surf 2,186' 9-5/8"53.5** S-95 BTC 8.535 Surf 1,968' 47 L-80 BTC 8.681 1,968' 8,062' (TOW) 7-5/8" 29.7 L-80 Hyd 511 6.875 7,933' 13,320' TUBING DETAIL 4-1/2 12.6 L-80 Supermax 3.958 Surf 2,364' **Note 1988 files indicate that 53.5# 9-5/8 should have been at the bottom of the K-06rd which is below K- 06rd2 sidetrack depth. This has not been confirmed. CEMENT DETAILS 13-3/8"18" hole: Cemented with 1100sxs class G lead followed by 560 sxs.Saw returns to Surface. 9-5/8" 12-1/4" Hole in 1988 sidetrack (K-06RD): Ran casing from 11958' MD back to surface. Cemented with 1050sxs 15.8ppg class G cement. Volumetrics suggest ToC below current KOP of 8062 MD.No cement behind 9-5/8 in current bore. 7-5/88-1/2" hole: Cemented with 62.5bbls 15.3ppg. 27% losses noted during cement job. No cement seen to surface. 2/17/17 CBL could only fall to 11,900' MD.ToC at 11,800' from 2/17/17 CBL. JEWELRY DETAIL No Depth MD Depth TVD ID OD Item 1 49 49 3.958 13.625 Tbg Hanger FISH DETAILS 11,388' ELM 8/25/24 - BHA left in hole - 5.875" taper mill, 6.6" string mill, 43/4" bumper sub, 4 1/4" oil jar, 4- 4 3/4" spiral drill collars, 4.75" xo 2 7/8" PH6 box X 3 1/2" if pin, one joint 2, 7/8" 7.9# PH6 tubing, one cut joint 2 7/8" 7.9# PH6 tubing 14.68', =199.56' overall length PBTD= 13,264 MD TD = 13,322 MD 1 7-5/8 Liner Hanger 7,933 Min ID 6.670 HK-2 Max Hole Angle = 86.29° @ 11,921 13-3/8 9-5/8 TOC 11,800 24 8-1/2 TOW 8,062 KOP 2,193 8/23/24 - Last tag @ 11,606' Fish: 11,388' - 11,588' ELM Well Name:MRF K-06RD2 API #:50733200880200 Field:McArthur River Start Date:8/2/2024 Permit #:216131 Sundry #:324-372 End Date:9/25/2024 8/2/2024 8/7/2024 8/8/2024 8/9/2024 8/10/2024 8/11/2024 Daily Operations: Complete L/D 4-1/2'' ESP completion tbg. Recovered 3.75'' GR/JB tool string that was stuck in tbg. Only recovered ESP bolt on housing, ESP parted w/approx. 25' of cable. Prepare handling tools for fishing operations while waiting on service personnel and forward plan from town. R/U SL and zero tools at rig floor. RIH w/7.95'' LIB, tag at 7801'. POH and review impression. RIH w/ 5.5'' LIB and 5.91'' fluted centralizer, tag at 7801' and chase down to 7832'. P/U and tag, POH to surface. Review impression- appears to look like 2 individual cable wire indentations. M/U 7'' spiral wire grab and RIH w/80 jts of 2-7/8'' PH-6 tbg. Change over handling equipment to 4- 1/2''. Well Operations Summary Complete N/U of BOPE. Stand mast and secure. Install rig floor. Complete R/U of circulating lines and handling equipment. R/U accumulator and function test. M/U test jts. Shell test 4-1/2''test jt against annular to 250/3000 psi for 5/5 min. Install 2-7/8'' test jt and shell test against annular to 250/3000 psi for 5/5 min. Tested 2-7/8'' against VBR to 250/3000 psi for 5/5 min. Conduct general housekeeping and prepare work site for AOGCC inspector's arrival. Continue Rig up & prep for BOPE test, Test BOPE as per Hilcorp & AOGCC exceptations, 300 /2500, 2 7/8 & 4 1/2" TJ, test witnessed by inspector Guy Cook, RIG UP ELINE. PT LUBE TO 250 / 2500 PSI. PUNCH TBG AT 7201' - 7204'. RIG DOWN ELINE. Mobe personnel to platform. Orientate personnel. R/U water lines and fill 400 bbl tank. R/U circulating lines and circulate 800bbls taking returns to production at 3.5bpm at 300 psi. Clean fluid returns throughout the circulation. Montior well. Install BPV, N/D tree, N/U BOPE. R/U choke and kill lines. Complete BOPE testing as per Hilcorp and AOGCC expectations. Pull blanking sub. Cut and slip drilline. Spot ESP equipment. Install landing jt. Unseat hanger at 150k lbs, pull hanger to floor w/ 180-185k lbs. B/O and L/D hanger, POH and rack back 90 stands of 4-1/2'' tbg. Page 1 of 5 Well Name:MRF K-06RD2 API #:50733200880200 Field:McArthur River Start Date:8/2/2024 Permit #:216131 Sundry #:324-372 End Date:9/25/2024 8/12/2024 8/13/2024 8/14/2024 8/15/2024 8/16/2024 8/17/2024 Well Operations Summary Daily Operations: POOH from f/7,952 t/184' racking back 2-7/8" work string. Break down BHA. Clean out packed off BHA. M/u 2-7/8" and 4-1/2" test joints. Test BOPE per Hilcorp and AOGCC standards to 250psi/3,000psi, All tests passed. Witness waived by AOGCC, Jim Regg on 8/15/25 @ 14:57hrs via email. R/d test equipment, r/u equipment to m/u cleanout BHA #4. M/u BHA #4 w/ 6.625" roller cone bit and RIH from Surface to 153'. Change out handing equipment to run 2-7/8" work string out of mast. Continue to mill/cleanout from 9008' to 9478'. Maintain milling parameters at 2.7bpm @ 400-600 psi, 80rpm, 2-5k weight on mill, rotating torque 1800-3200 ft lbs. Monitor scale returns across shaker and collect samples periodically. At 9478' tbg plugged off, made several attempts to clear scale from tbg string. POH and rack back 24 stands of 3-1/2'' work string.R/U circulating equipment and attempt to clear scale from tbg, made several attempts, no success. RIH w/4-1/2'' tbg from derrick. Tag TOF at 7839', rotate string and P/U, 7-10k overpull for 15', lost 8k of weight. Had 2k over string weight while POH. POH and L/D 4-1/2'' tbg, stand 2-7/8'' workstring. Recovered 19' of ESP MLE cable. L/D BHA and R/U slickline unit. RIH with 5.75'' LIB and 5.91'' centralizer, tag at 7828'. P/U to get impression, tag at 7836'. P/U and tagged solid at 7836'. POH and R/D slickline. Prepare handling equipmnent and L/D remaining jts of 4-1/2'' from the derrick. Prepare to M/U next BHA. Complete circulating out metal chunks/debris at the shaker. Swap over to reverse circulation. Continue to mill/cleanout 7-5/8'' liner from 8263' to 9008'. Maintain milling parameters at 3bpm @ 500-800 psi, 85rpm, 3-5k weight on mill, rotating torque 1800-3200 ft lbs. Monitor scale returns across shaker and collect samples periodically. M/U 8-1/8'' overshot fishing assy w/5-3/8''grapple. RIH w/2-7/8'' PH-6 work string to 7767', R/U and circulate 1 bbl of drag reducer and 60 bbl of FIW. RIH and tag TOF at 7839', work overshot and grapple over TOF at 7870'. P/U on string w/24k overpull, slowly work fish out of the top of liner, weight decreased to 14k overpull. POH and rack back work string at controlled speed. Break out fishing BHA, Recover all ESP components except 3 motor canon clamps. R/U Slickline, RIH w/5.75'' LIB, tag at liner top. POH and found small impression of canon clamp. M/U cleanout BHA w/6.625'' Pirana mill and jewelary as per YJ. RIH w/2-7/8'' 7.9ppf PH-6 work string. R/U circulating equipment and break circulation to the shaker at 3 bpm at 500 psi. R/U power swivel and equipment on 3-1/2'' PH-6 workstring. Record parameters, RIH and tag at 7979'. Mill on clamps and push them through the liner restriction. Continue to work string w/power swivel and push down/clamps. Clamps hanging up. Swivel down to 8235'. Page 2 of 5 Well Name:MRF K-06RD2 API #:50733200880200 Field:McArthur River Start Date:8/2/2024 Permit #:216131 Sundry #:324-372 End Date:9/25/2024 8/18/2024 8/19/2024 8/20/2024 8/21/2024 8/22/2024 8/23/2024 TOH f/ 10860'. Losses 6 bbls/Hr. OOH. LD BHA. Wear pattern ~1.75" in from the shoulder on all 4 blades of the mill. Discuss w/ OE. Decide to run tapered mill followed by string reamer. M/u BHA #6 w/ 5.875" taper mill and 6.6" string mill. RIH w/ work string to 10,832'. R/d tongs, r/u power swivel, install circulating head element. Reverse circulate a bottoms up. Daily Operations: Change out handling equipment to run BHA #4 on 2-7/8" PH-6 work string, RIH f/ 153' t/7,942' on 2-7/8" workstring. Swap over to 3.5" handling eqpt. RIH f/ 7,942' t/ 9,400'. Reverse circulate bottoms up, MU power swivel, install stripping head. Continue to swivel in hole f/ 9,400' t/ 9,898', reverse circulating at 2.5 bpm, 550psi. 85RPM, 2k ft-lbs free torque, 92k up wt, 88k slack off. 2-4k down on the bit. Chunky scale returns. Circulating bottoms up every 5 joints down. See pressure increase at 9898'. Rock circulation until obstruction clears and pressures stabilize. Able to get to 9970' and saw pressures begin to increase again, circulate same. Change out circulating head element. Swivel in hole f/ 9,970' t/ 10,332'. 85RPM, 2k ft-lbs free torque, 3BPM reverse, 2-4k down on the bit. Circulating 25bbl after every joint and bottoms up every 5jts to keep from plugging off, getting chunky scale returns and waxy/oily tar substance. Adjusting pump rates, working pipe, surging, and rocking circulation as necessary. Continue to have plugging issues. TOH from 10,332' to modify BHA to larger ID to prevent plugging. MU BHA #5 w/ 6.625" 4-blade junk mill, ID of BHA is all 2.25". RIH t/10280'. M/U power swivel. Get parameters w/ power swivel, rot wt 92k, rot S/O 84k, rot P/U 94k, off btm tq 2k. Swivel in hole f/10,280'-t/10453' at 3bpm 540psi. Circulating a bottoms up as necessary. Adjusting pump rates, working pipe, surging, and rocking circulation as necessary. 1000psi max pressure while reverse circulating. 2000psi max pressure while clearing tubing. Getting scale returns w/ some metal and flat pack armor. Well Operations Summary Cont. Rev CBU @3bpm, 420PSI, r/u swivel & circulating head. Swivel down. Tag @ 10860' w/ ~2k down. Losses increased to ~50 BPH. Continue wash & ream t/10875' lost circulation. Tubing was plugged off, L/D one joint T/10863' work pipe & surge pump to clear obstruction until clear. Pump 23bbl Salt pill, spot outside wk string. Continue wash & ream, circulating conventional 5 joints and reversing clean, down t/11606'. After washing and reaming 5th joint down to 11606', started to reverse circulate, pipe stalled out, p/u to 11585' and broke free. Started to pressure up and lost circulation, switch over to pump down tubing, got circulation. Switch back over to reverse, pipe stalled again, attempt to slack off, s/o to 80k and started to pressure up again. Start working pipe and surging. 2000psi max down tubing, 600psi down IA. Continue milling f/ 10453', Overall ROP ~40 FPH to 10702' Plugged work string. 1 hour to clear obstruction. Continue milling. Losses ~5 bbls/Hr @ 10770'. Mill down to 10880' and lost returns. P/u to 10855', clear tubing and spot salt pill. Attempt to mill ahead, tag at 10860', try milling past, mill 22" in 2.5 hours. Prep to POOH to inspect mill. Page 3 of 5 Well Name:MRF K-06RD2 API #:50733200880200 Field:McArthur River Start Date:8/2/2024 Permit #:216131 Sundry #:324-372 End Date:9/25/2024 8/24/2024 8/25/2024 8/26/2024 8/27/2024 Get e-line unit and crew to king, get shing tools to rig tenders. R/u E-line. Run #1 E-line RIH w/ 1-7/16" free point tools (CCL/ pin to pin/ freepoint). Perform stretch points along the way. Last freepoint check at 11400' ELM (last 2-7/8" joint before BHA. Run #2 RIH w/1'x 1-9/16" tubing punch. Log. Tag at 11413' ELM, collars at 11370' and 11401'. P/u to 11380'-11880' ELM, fire shots, POOH. No shots red on tubing punch. Run #3 RIH w/ tubing punch. Tag at 11414' P/u and fire punches between 11380'-11381' ELM. All indications shots were fired. POOH, all shots red. Circulate down tubing to see if there is communication, saw returns at 36bbls. Reverse circulate a bottoms up at 2bpm, 580psi, no solids across shakers. Pump a drum of lube while reversing. Pump lube until it reaches punched holes. Check pipe movement from neutral wt. 110k to 150k while pumping lube. Circulate lube down annulus t/ 11380' @2.25bpm, 830 psi. work pipe attempt to free, gained 4' of stretch but no movement. RU E-line with RCT, tag @ 11,417' ELM and cut pipe @ 11,388' ELM, cut failed. POOH w/ E-line and troubleshoot RCT. RIH w/ RCT cut pipe @ 11,388', success. POOH and RD E-line. TOH and stand back work string. RU to test BOPE. Witness waived by AOGCC, Jim Regg on 8/25/24 and extension granted due to being stuck in hole (via email). BHA left in hole- 5.875" taper mill, 6.6" string mill, 43/4" bumper sub, 4 1/4" oil jar, 4- 4 3/4" spiral drill collars, 4.75" xo 2 7/8" PH6 box X 3 1/2" if pin, one joint 2 7/8" 7.9# PH6 tubing, one cut joint 2 7/8" 7.9# PH6 tubing 14.68', = 199.56' over all length top of fish 11388' adjusted KB Continue r/u BOPE test eq. install 2 7/8" TJ, Test BOPE as per Hilcorp & AOGCC standards. Witness waived by AOGCC, Jim Regg on 8/25/24 and extension granted due to being stuck in hole (via email). Tested w/ 2 7/8" & 4 1/2" TJ, 250/3000, tested gas alarms. All passed. MU fishing BHA and TIH w/ 2 7/8" and 3 1/2" workstring. RU power swivel and CBU. Attempt to engage fish. R/U pump down annulus pressure up t/ 580 psi checking pack off - good. Pick up off monitor pressure loss - good. CBU rev - clean. Continue attempt latch fish no luck. R/U to pump Oilsafe AR acid. PJSM, break circulation down wk string, shut in PT lines 250/3000 good, line up pump 275 gallons of AR acid. Rinse tote & chase with FIW, spot acid around stuck BHA @11388' .45BPM FCP 1000psi. POOH w/ fishing BHA - no fish. RIH w/ same BHA plus hollow mill. Daily Operations: Well Operations Summary Page 4 of 5 Well Name:MRF K-06RD2 API #:50733200880200 Field:McArthur River Start Date:8/2/2024 Permit #:216131 Sundry #:324-372 End Date:9/25/2024 8/28/2024 8/29/2024 8/30/2024 8/31/2024 9/25/2024 Well Operations Summary Daily Operations: Finish laying down 2 7/8" wk string, break down & l/d BHA, run 2 stands of 3 1/2" out of derrick, pull & l/d same. Load ESP Equip on boat, prep to run 4 1/2" Kill string, run kill string 2330', Performed man down drill, Land kill string w/ WH tech, set BPV, Clear and RD work floor, Rig down, prep & scoped down mast, prepped for removal. Cont RD AUX equip and prepping derrick and carrier for transport. ND BOPE and riser, install production tree, test void and tree to 5,000# good test, Load Derrick, carrier, drawworks, and iron package on boat, cat walks, send first boat to steelhead, pressure wash equipment and deck. Cont to clean equipment vac out sand trap on pits, load second boat for steelhead. load boat to send equipment to the beach. Continue Trip in hole t/11368', R/U swivel, Wash down from 11373-11388, Dress off top of fish @ 10388', continue attempting to wash down w/no luck, wash & ream t/ packoff, attempt to wash down to engage grapple w/ no luck, Decision made to suspend well work, POOH LD WS No Flow Test passed. Josh Hunt form AOGCC witnessed Page 5 of 5 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________ Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 13,322 feet N/A feet true vertical 9,841 feet N/A feet Effective Depth measured 13,264 feet N/A feet true vertical 9,833 feet N/A feet Perforation depth Measured depth 11,960 - 13,153 feet True Vertical depth 9,683 - 9,820 feet Tubing (size, grade, measured and true vertical depth) 4-1/2" L-80 7,848 (MD) 6,163 (TVD) Packers and SSSV (type, measured and true vertical depth) N/A & N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: Hemlock Oil 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: 7,100psi 3,090psi 8,150psi 2,186 2,094 Burst Collapse 1,540psi measured TVD Production Liner 8,062 5,387 Casing Structural 6,324 7-5/8" 8,062 13,320 9,841 376 2,186 376Conductor Surface Intermediate 24" 13-3/8" 6,890psi 9-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 216-131 50-733-20088-02-00 3. Address: Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0017594 / ADL0018772 McArthur River / Hemlock Oil Trading Bay Unit K-06RD2 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 11,960 - 13,153 219 Size 376 0 230 66 2632473 14 323-372 Sr Pet Eng: 4,790psi Sr Pet Geo: Sr Res Eng: WINJ WAG 32 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Ryan Rupert Ryan.Rupert@hilcorp.com 907 777-8503Operations Manager Vac feed 39.3bbl of OilSafe AR chased with 80bbl of drill water. 0psi. Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 8:14 am, Jun 28, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.06.27 14:25:38 - 08'00' Dan Marlowe (1267) _____________________________________________________________________________________ Updated By: JLL 06/28/23 SCHEMATIC McArthur River Field Well: TBU K-06RD2 PTD: 216-131 API: 50-733-20088-02 Last Completed: 11/29/21 PBTD= 13,264 MD TD = 13,322 MD 1 2 7-5/8 Liner Hanger 7,933 Min ID 6.670 HK-2 Max Hole Angle = 86.29° @ 11,921 13-3/8 9-5/8 TOC 11,800 24 8-1/2 TOW 8,062 KOP 2,193 CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 24 - - - Surf 376 13-3/8" 61 J-55 BTC 12.515 Surf 2,186' 9-5/8"53.5** S-95 BTC 8.535 Surf 1,968' 47 L-80 BTC 8.681 1,968' 8,062' (TOW) 7-5/8" 29.7 L-80 Hyd 511 6.875 7,933' 13,320' TUBING DETAIL 4-1/2 12.6 L-80 Supermax 3.958 Surf 7,848 **Note 1988 files indicate that 53.5# 9-5/8 should have been at the bottom of the K-06rd which is below K- 06rd2 sidetrack depth. This has not been confirmed. JEWELRY DETAIL No Depth MD Depth TVD ID OD Item 1 49 49 3.958 13.625 Tbg Hanger, OCT-UH-TC-1A ESP 13 x 4-1/2 IBT lift and susp, w/" type BPV profile, 3/8 cont. control line port 2 7,729 6,076 N/A 5.130 Discharge, Bolt-On 7,730 6,076 N/A 5.380 Pumps (x3) 538 Series, 33 & 71 Stg SJ7000 7,789 6,119 N/A 5.380 Intake, Sub-Assy A/R-X2, 513X, 416 SS PN 900620001 7,790 6,120 N/A 5.130 BPBSBPB Upper/Lower Seals 7,813 6,137 N/A 5.620 Motor,562 Series,KMS2,500HP/3305V/93A, 16 PN 900470552, SN 13588938, w/6 Clamps Installed 7,848 6,163 N/A 5.620 Centralizer Anode PERFORATION DETAIL Zone Top MD Bottom MD Top TVD Bottom TVD Feet SPF Date Status HK-2 11,960 13,153 9,683 9,820 1,193 6 12/19/2016 Open 13-3/8"18" hole: Cemented with 1100sxs class G lead followed by 560 sxs.Saw returns to Surface. 9-5/8" 12-1/4" Hole in 1988 sidetrack (K-06RD): Ran casing from 11958' MD back to surface. Cemented with 1050sxs 15.8ppg class G cement. Volumetrics suggest ToC below current KOP of 8062 MD.No cement behind 9-5/8 in current bore. 7-5/88-1/2" hole: Cemented with 62.5bbls 15.3ppg. 27% losses noted during cement job. No cement seen to surface. 2/17/17 CBL could only fall to 11,900' MD.ToC at 11,800' from 2/17/17 CBL. Well Name:MRF K-06RD2 API #:50733200880200 Field:McArthur River Start Date:6/19/2024 Permit #:216131 Sundry #:323-372 End Date:6/20/2024 6/19/2024 6/20/2024 Well Operations Summary PJSM and PTW, Shut down ESP, start bleeding IA. RU chem treatment pump pressure test lines to 250psi-1600psi (pump relief valve). Wait for Kings pipeline pig to reach trading bay. Shutdown ESP Pressure up well to 1200psi, pressure bleeds o ~30psi/min Pressure up to 1350psi, pressure bleeds o ~30psi/min Bleed well to header pressure ~250psi. Pressure up again to 1200psi no change. Secure well and SDFN. PJSM and PTW. SITP bled from 250psi to 150psi over night. Intake pressure fell 685psi. Line up well to flow, bring on ESP at 7,000BPD and pump intake pressure down to 350psi. Shutdown ESP and vac feed 39.3bbl of OilSafe AR chased with 80bbl of drill water. Secure well and RD Chem treatment pump. Daily Operations: Page 1 of 1 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 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 13,322 N/A Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 7,100psi Liner 4,790psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Ryan Rupert Contact Email:Ryan.Rupert@hilcorp.com Contact Phone:(907) 777-8503 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 7/12/2024 13,320'5,387' 4-1/2" 9,841' N/A & N/A N/A & N/A 8,062' Perforation Depth MD (ft): 11,960 - 13,153 8,062' 7-5/8" 9,683 - 9,820 6,324'9-5/8" 24" 13-3/8" 376' 2,186' MD 3,090psi 376' 2,094' 376' 2,186' Length Size Proposed Pools: 12.6# / L-80 TVD Burst 7,848 8,150psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017594 / ADL0018772 216-131 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20088-02-00 Hilcorp Alaska, LLC N/A AOGCC USE ONLY 6,890psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Other: Replace ESP Trading Bay Unit K-06RD2 McArthur River Hemlock Oil Same 9,841 13,264 9,833 2,580psi N/A No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 7:43 am, Jun 28, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.06.27 16:19:06 - 08'00' Dan Marlowe (1267) 324-372 SFD 7/2/2024 X BJM 7/3/24 DSR-7/8/24 BOP test to 3000 psi, annular test to 2500 psi Provide 48 hrs for AOGCC witness of NFT. 10-404 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.07.09 12:18:21 -08'00'07/09/24 RBDMS JSB 070924 ESP Swap RWO Well: K-06RD2 Well Name:K-06RD2 API Number:50-733-20088-02-00 Current Status:ESP Oil Producer Leg:Leg #4 (NW corner) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:216-131 First Call Engineer:Ryan Rupert (907) 301-1736 (c) Second Call Engineer:Dan Marlowe (907) 398-9904 (c) Maximum Expected BHP:3,562 psi @ 9,820’ TVD (7.0ppg) 6/23/23 Static after 6 days SI Max. Potential Surface Pressure: 2580 psi Using 0.1 psi/ft Brief Well Summary K-06RD2 is a horizontal Hemlock only oil producer that was sidetracked to its current bore in 2017. The ESP currently downhole was installed in Nov-2021. In 2023, Inflow / productivity fell. Injection was attempted to prep for an acid job, but the formation locked up. The ESP was then brought on hard and appeared to have cleared a solids obstruction (presumably laid out in the liner). Full productivity was restored, and the well returned to production. Similar events happened in June-2024, but we were unable to get the well back to sustained production. The goal of this project is to clean out the horizontal liner and replace the ESP Pertinent wellbore information: - January-2017 sidetrack / completion o Cleanout 7-5/8" liner to 13,250' MD with 6.125" bit and 7-5/8" casing scraper o 2/10/17: MIT of 7-5/8” liner and 9-5/8” casing PASSED to 2640psi (before any perfs shot) - Nov-2021: ESP swap RWO with cleanout o Packer / pump pulled with no issues (120k hanging weight) o 3" SL bailer tagged at 11,660' MD (300' above top perf) o Performed liner cleanout with 6-1/2" bit. Tagged at 11,615' MD. Circ pressure broke from 780 to 100psi Then TIH on elevators to top perf with no problem and called it good there. "Chunky scale" came across shakers -6/9/22: Most recent NFT PASSED - June-2023 o Production had fallen from 4000+ bfpd to < 700bfpd o Loaded well to establish injectivity prior to an acid job o Once filled up, the well pressured up to 1450psi, and over 1 hr. only bled down to 900psi o ESP started and brought on hard and appeared a bridge broke free - June-2024 o Production had fallen from 4000+ bfpd to < 3000bfpd 9and oil rate went from 100 to 30 bopd o Loaded well to establish injectivity prior to an acid job o Once filled up, the well pressured up to 1350psi, and took 30 minutes to bleed down o Bled well down and then circ’d in Safeacid. Let soak 5 days o ESP started and brought on hard. No fluid to surface. o Intake nor discharge gauges moved at all. Possibly a parted pump ESP Swap RWO Well: K-06RD2 RWO Procedure: 1. MIRU Hilcorp Rig #404 2. Circulate well to production: a. Work over fluid will be fresh water (8.33ppg) or heavier b. Ensure any wellbore fluids are fully displaced with KWF either via circulation or bullheading c. Tubing volume = 120bbls d. IA + Liner volume ~670bbls 3. Set BPV/TWC, ND tree, NU BOP a. Notify AOGCC 48 hours in advance for witness b. Test to 250psi Low / 3,000psi High / 2,500psi Annular c. BOP’s will be closed as needed to circulate the well d. Hilcorp’s 13-5/8” RWO BOP stack will be used. This stack has been in service recently with both rig #401 and rig #404 RWO’s 4. BOLDS and unseat hanger 5. POOH with 4-1/2” tubing string and ESP completion 6. PU 3-1/2” workstring 7. MU 7-5/8” liner cleanout assembly 8. RIH and mill/cleanout 7-5/8” liner to target depth = 13,264’ MD (PBTD) 9. POOH and lay down cleanout BHA and workstring 10. PU, RIH with new ESP completion a. No packer nor SSSV is planned b. Bottom of ESP planned for ±10,025’ MD 11. Land ESP completion 12. Set BPV/TWC, ND BOP, NU tree and test, pull BPV/TWC 13. Turn well over to production 14. Conduct NFT post-rig per attachment after ~10 days of production Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Current and Proposed Wellhead Diagram (no changes) 4. BOP Drawing 5. Fluid/Flow Diagrams 6. NFT Procedure 7. RWO Sundry Change Form _____________________________________________________________________________________ Updated By: JLL 06/28/23 SCHEMATIC McArthur River Field Well: TBU K-06RD2 PTD: 216-131 API: 50-733-20088-02 Last Completed: 11/29/21 PBTD= 13,264’ MD TD = 13,322’ MD 1 2 7-5/8” Liner Hanger 7,933’ Min ID 6.670” HK-2 Max Hole Angle = 86.29° @ 11,921’ 13-3/8” 9-5/8” TOC 11,800’ 24” 8-1/2” TOW 8,062’ KOP 2,193’ CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 24” - - - Surf 376’ 13-3/8" 61 J-55 BTC 12.515” Surf 2,186' 9-5/8"53.5** S-95 BTC 8.535” Surf 1,968' 47 L-80 BTC 8.681” 1,968' 8,062' (TOW) 7-5/8" 29.7 L-80 Hyd 511 6.875” 7,933' 13,320' TUBING DETAIL 4-1/2” 12.6 L-80 Supermax 3.958 Surf 7,848’ **Note 1988 files indicate that 53.5# 9-5/8” should have been at the bottom of the K-06rd which is below K- 06rd2 sidetrack depth. This has not been confirmed. JEWELRY DETAIL No Depth MD Depth TVD ID OD Item 1 49’ 49’ 3.958” 13.625” Tbg Hanger, OCT-UH-TC-1A ESP 13 x 4-1/2 IBT lift and susp, w/" type BPV profile, 3/8 cont. control line port 2 7,729’ 6,076’ N/A 5.130” Discharge, Bolt-On 7,730’ 6,076’ N/A 5.380” Pumps (x3) 538 Series, 33 & 71 Stg SJ7000 7,789’ 6,119’ N/A 5.380” Intake, Sub-Assy A/R-X2, 513X, 416 SS PN 900620001 7,790’ 6,120’ N/A 5.130” BPBSBPB Upper/Lower Seals 7,813’ 6,137’ N/A 5.620” Motor,562 Series,KMS2,500HP/3305V/93A, 16 PN 900470552, SN 13588938, w/6 Clamps Installed 7,848’ 6,163’ N/A 5.620” Centralizer Anode PERFORATION DETAIL Zone Top MD Bottom MD Top TVD Bottom TVD Feet SPF Date Status HK-2 11,960’ 13,153’ 9,683’ 9,820’ 1,193’ 6 12/19/2016 Open 13-3/8"18" hole: Cemented with 1100sxs class G lead followed by 560 sxs.Saw returns to Surface. 9-5/8" 12-1/4" Hole in 1988 sidetrack (K-06RD): Ran casing from 11958' MD back to surface. Cemented with 1050sxs 15.8ppg class G cement. Volumetrics suggest ToC below current KOP of 8062’ MD.No cement behind 9-5/8” in current bore. 7-5/8”8-1/2" hole: Cemented with 62.5bbls 15.3ppg. 27% losses noted during cement job. No cement seen to surface. 2/17/17 CBL could only fall to 11,900' MD.ToC at 11,800' from 2/17/17 CBL. No cement behind 9-5/8” in current bore. _____________________________________________________________________________________ Updated By: JLL 06/27/24 PROPOSED McArthur River Field Well: TBU K-06RD2 PTD: 216-131 API: 50-733-20088-02 Last Completed: FUTURE PBTD= 13,264’ MD TD = 13,322’ MD 1 2 7-5/8” Liner Hanger 7,933’ Min ID 6.670” HK-2 Max Hole Angle = 86.29° @ 11,921’ 13-3/8” 9-5/8” TOC 11,800’ 24” 8-1/2” TOW 8,062’ KOP 2,193’ CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 24” - - - Surf 376’ 13-3/8" 61 J-55 BTC 12.515” Surf 2,186' 9-5/8"53.5** S-95 BTC 8.535” Surf 1,968' 47 L-80 BTC 8.681” 1,968' 8,062' (TOW) 7-5/8" 29.7 L-80 Hyd 511 6.875” 7,933' 13,320' TUBING DETAIL 4-1/2” Surf ±9,860' **Note 1988 files indicate that 53.5# 9-5/8” should have been at the bottom of the K-06rd which is below K- 06rd2 sidetrack depth. This has not been confirmed. JEWELRY DETAIL No Depth MD Depth TVD ID OD Item 1 49’ 49’ 3.958” 13.625” Tbg Hanger, OCT-UH-TC-1A ESP 13 x 4-1/2 IBT lift and susp, w/" type BPV profile, 3/8 cont. control line port 2 ±9,860' ±8,043' Discharge, Bolt-On Pumps Intake Seals Motor ±10,025' ±8,162 Centralizer Anode PERFORATION DETAIL Zone Top MD Bottom MD Top TVD Bottom TVD Feet SPF Date Status HK-2 11,960’ 13,153’ 9,683’ 9,820’ 1,193’ 6 12/19/2016 Open 13-3/8"18" hole: Cemented with 1100sxs class G lead followed by 560 sxs.Saw returns to Surface. 9-5/8" 12-1/4" Hole in 1988 sidetrack (K-06RD): Ran casing from 11958' MD back to surface. Cemented with 1050sxs 15.8ppg class G cement. Volumetrics suggest ToC below current KOP of 8062’ MD.No cement behind 9-5/8” in current bore. 7-5/8”8-1/2" hole: Cemented with 62.5bbls 15.3ppg. 27% losses noted during cement job. No cement seen to surface. 2/17/17 CBL could only fall to 11,900' MD.ToC at 11,800' from 2/17/17 CBL. King Salmon Platform K-06RD2 BHTA, B-11-A0, 4 1/16 5M FE Valve, Swab, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Master, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Wing, CIW-FL, 3 1/8 5M FE, HWO, EE trim All unihead annular valves, 2 1/16 5M FE OCT-20, HWO Valve, OCT-20, 3 1/8 2M FE, HWOStarting head, OCT, 21 ¼ 2M FE X 24'’ SOW, w/ 1- 3 1/8 2M EFO, full set of lockpins Unihead, OCT type 3, 13 5/8 5M API hub top X 13 3/8 BTC casing bottom, w/ 1- 2 1/16 5M SSO on lower section, 1- 2 1/16 5M SSO on middle section, 3- 2 1/16 5M SSO on upper section , IP internal lockpin assy Adapter, OCT-A5-ESP, 13 5/8 5M API hub X 4 1/16 5M stdd top, w/ 2- ½ control line exits, prepped w/ OCT 400-4 pocket King Salmon K-06RD2 24 X 13 3/8 X 9 5/8 X 4 ½ Tbg hanger, OCT-UH-TC-1A- ESP, 13 X 4 ½ IBT lift and susp, w/ 4'’ Type H BPV profile, 3/8 cont control line port 24'’ 13 3/8'’ 9 5/8'’ 4 ½’’ Valve, Wing, WKM-M, 2 1/16 5M FE, HWO, AA trim Valve, Wing, WKM-M, 3 1/8 5M FE, w/ OMNI oper, EE trim BOP Stack HAK 404 HILCORP ALASKA, LLC SwacoSuperchokeBlooey LineTo Gas BusterInlet For recently worked over wells 1. Well produced on artificial lift for ~10 days 2. Shut down artificial lift and leave well lined up to production and monitor until fluid level is stable. 3. Notify AOGCC to witness test (48hr notice to AOGCC) 4. Bleed well (TBG and IA) to 0 psi 5. Rig up test equipment (low pressure gauge, flowmeter, etc.) 6. Let well bleed through flow meter until inspector arrives but do not exceed 48 hrs. of total bleed time 7. Begin No Flow Test No-Flow Test Option A – Fluid Flow Rate (Flow Meter Procedure) 1. Record tubing (T), inner annulus (IA), and outer annulus (OA) pressures prior to 2. shut in to start the No-Flow Test 3. Shut in well to monitor pressure build up – record T, IA, and OA pressures at least 4. every 15 minutes 5. At 1 hour, open to flow through the meter and document flow rates and well pressures (T, IA, OA) at 5-minute increments until the rate declines to less than the acceptance criteria, not to exceed 30 minutes 6. Repeat the shut-in/flow monitoring steps at least 2 times Test acceptance: flow rates not exceeding 6.3 gallons per hour liquid and 900 standard cubic feet per hour gas demonstrated by at least 2 consecutive flow monitoring periods Option B – Pressure Discharge (Pressure Gauge Procedure) 1. Open the well to flow for at least 1 hour prior to starting the test 2. Record T, IA, and OA pressures immediately prior to shutting in the well 3. Shut in the well and chart T, IA, and OA pressures at least every 15 minutes for 3 hours 4. Open the flowline to an atmospheric tank or vessel and record pressures at 1-minute increments for 5 minutes Test acceptance: pressure discharged (0 psi) within 5 minutes NFT procedure as directed by AOGCC inspector. -bjm Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well: Trading Bay Unit K-06RD2 (PTD 216-131)Sundry #: XXX-XXXAny modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC 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 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date 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? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 13,322 N/A Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 7,100psi Liner 4,790psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Ryan Rupert Contact Email:Ryan.Rupert@hilcorp.com Contact Phone:(907) 777-8503 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 7/19/2023 13,320'5,387' 4-1/2" 9,841' N/A & N/A N/A & N/A 8,062' Perforation Depth MD (ft): 11,960 - 13,153 8,062' 7-5/8" 9,683 - 9,820 6,324'9-5/8" 24" 13-3/8" 376' 2,186' MD 3,090psi 376' 2,094' 376' 2,186' Length Size Proposed Pools: 12.6# / L-80 TVD Burst 7,848 8,150psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017594 / ADL0018772 216-131 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20088-02-00 Hilcorp Alaska, LLC N/A AOGCC USE ONLY 6,890psi Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Trading Bay Unit K-06RD2 McArthur River Hemlock Oil Same 9,841 13,264 9,833 0psi N/A m n P s 2 6 5 6 t _ T N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 323-372 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2023.07.05 09:52:32 - 08'00' Dan Marlowe (1267) DSR-7/6/23BJM 7/21/23 10-404 MDG 7/18/2023 GCW 08/08/2023JLC 8/8/2023 08/08/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.08.08 10:06:34 -08'00' RBDMS JSB 081123 Well: K-06RD2 Well Name: K-06RD2 API Number: 50-733-20088-02-00 Current Status: SI oil well Leg: Leg #4 (NW corner) Regulatory Contact: Juanita Lovett (8332) Permit to Drill Number: 216-131 First Call Engineer: Ryan Rupert (907) 301-1736 (c) Second Call Engineer: Dan Marlowe (907) 398-9904 (c) Maximum Expected BHP: 3500 psi @ 9,683’ TVD 6/23/23 ESP gauge reading (6 days SI) Max. Potential Surface Pressure: 0 psi No Flow test passed 6/9/22 Brief Well Summary All King ESP’s were recently shut in for facility work. Upon bringing the platform back online K-06RD2 has only been making ~650bfpd, down from it’s typical 4400bfpd. Drawdown at the ESP remains constant, so it seems like an inflow issue. The goal of this project is to remediate any liner scale/solids bridges that maybe constraining inflow Procedure 1. MIRU pumping equipment 2. Ensure ESP is offline 3. Pressure test surface lines to 2000psi (max pump output pressure) 4. Mix chemicals and pump per below: a. Open IA and circulate in FIW down the tubing taking returns up the annulus b. Pump ±82bbls (1.5x perf footage volume) synthetic acid down the tubing c. Displace with FIW d. When acid hits ESP close in annulus and bullhead acid down tubing into perfs e. Leave tail edge of acid 20bbls above top perf 5. RDMO pump equipment and let acid soak per vendor 6. Return well to production 7. Conduct No flow Test per AOGCC regulations a. Produce well for ~10 days b. Shut down ESP and leave well lined up to production and monitor until fluid level is stable. c. Notify AOGCC to witness test (48hr notice to AOGCC) d. Bleed well (TBG and IA) to 0 psi e. Rig up test equipment (low pressure gauge, flowmeter, etc.) f. Let well bleed through flow meter until inspector arrives but do not exceed 48 hrs. of total bleed time g. Begin No Flow Test per AOGCC regs / guidance document Attachments: 1. Current Wellbore Schematic (no changes) _____________________________________________________________________________________ Updated By: JLL 06/28/23 SCHEMATIC McArthur River Field Well: TBU K-06RD2 PTD: 216-131 API: 50-733-20088-02 Last Completed: 11/29/21 PBTD= 13,264’ MD TD = 13,322’ MD 1 2 7-5/8” Liner Hanger 7,933’ Min ID 6.670” HK-2 Max Hole Angle = 86.29° @ 11,921’ 13-3/8” 9-5/8” TOC 11,800’ 24” 8-1/2” TOW 8,062’ KOP 2,193’ CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 24” - - - Surf 376’ 13-3/8" 61 J-55 BTC 12.515” Surf 2,186' 9-5/8"53.5** S-95 BTC 8.535” Surf 1,968' 47 L-80 BTC 8.681” 1,968' 8,062' (TOW) 7-5/8" 29.7 L-80 Hyd 511 6.875” 7,933' 13,320' TUBING DETAIL 4-1/2” 12.6 L-80 Supermax 3.958 Surf 7,848’ **Note 1988 files indicate that 53.5# 9-5/8” should have been at the bottom of the K-06rd which is below K- 06rd2 sidetrack depth. This has not been confirmed. JEWELRY DETAIL No Depth MD Depth TVD ID OD Item 1 49’ 49’ 3.958” 13.625” Tbg Hanger, OCT-UH-TC-1A ESP 13 x 4-1/2 IBT lift and susp, w/" type BPV profile, 3/8 cont. control line port 2 7,729’ 6,076’ N/A 5.130” Discharge, Bolt-On 7,730’ 6,076’ N/A 5.380” Pumps (x3) 538 Series, 33 & 71 Stg SJ7000 7,789’ 6,119’ N/A 5.380” Intake, Sub-Assy A/R-X2, 513X, 416 SS PN 900620001 7,790’ 6,120’ N/A 5.130” BPBSBPB Upper/Lower Seals 7,813’ 6,137’ N/A 5.620” Motor,562 Series,KMS2,500HP/3305V/93A, 16 PN 900470552, SN 13588938, w/6 Clamps Installed 7,848’ 6,163’ N/A 5.620” Centralizer Anode PERFORATION DETAIL Zone Top MD Bottom MD Top TVD Bottom TVD Feet SPF Date Status HK-2 11,960’ 13,153’ 9,683’ 9,820’ 1,193’ 6 12/19/2016 Open 13-3/8"18" hole: Cemented with 1100sxs class G lead followed by 560 sxs.Saw returns to Surface. 9-5/8" 12-1/4" Hole in 1988 sidetrack (K-06RD): Ran casing from 11958' MD back to surface. Cemented with 1050sxs 15.8ppg class G cement. Volumetrics suggest ToC below current KOP of 8062’ MD.No cement behind 9-5/8” in current bore. 7-5/8”8-1/2" hole: Cemented with 62.5bbls 15.3ppg. 27% losses noted during cement job. No cement seen to surface. 2/17/17 CBL could only fall to 11,900' MD.ToC at 11,800' from 2/17/17 CBL. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Ryan Rupert To:McLellan, Bryan J (OGC) Cc:Dan Marlowe; Juanita Lovett Subject:RE: [EXTERNAL] RE: 10-403 Trading Bay Unit K-06RD2 PTD 216-131 Submitted 07-05-23 - Sundry Application Date:Monday, July 31, 2023 11:41:00 AM 2000psi max P because that’s all the pump is capable of outputting. That’s under a 12.6ppg at the perfs. That’s still well below any confining layer fracture pressure at these depths. Ryan Rupert CIO Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, July 21, 2023 12:38 PM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Cc: Juanita Lovett <jlovett@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Subject: RE: [EXTERNAL] RE: 10-403 Trading Bay Unit K-06RD2 PTD 216-131 Submitted 07-05-23 - Sundry Application What’s the maximum injection pressure for the acid? What’s it based on ? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Friday, July 21, 2023 12:05 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Subject: RE: [EXTERNAL] RE: 10-403 Trading Bay Unit K-06RD2 PTD 216-131 Submitted 07-05-23 - Sundry Application CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Was not executed, but may still be in the future (as long as the sundry gets approved) Ryan Rupert CIO Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, July 21, 2023 11:45 AM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: RE: [EXTERNAL] RE: 10-403 Trading Bay Unit K-06RD2 PTD 216-131 Submitted 07-05-23 - Sundry Application Ryan, Is this work still being planned? Or was it executed based on verbal approval from Mel? We have a sundry in our inbox for this, but wondering if it’s still necessary. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Friday, July 7, 2023 10:36 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: 10-403 Trading Bay Unit K-06RD2 PTD 216-131 Submitted 07-05-23 - Sundry Application Here’s my pump schedule. The synthetic acid is ~9.2ppg CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Fluid Volume comments FIW ±115 bbls as needed to fluid pack tubing and IA Synthetic acid 82 bbls ~9.2ppg FIW 170 bbls displacement Ryan Rupert CIO Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Friday, July 7, 2023 10:14 AM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Subject: [EXTERNAL] RE: 10-403 Trading Bay Unit K-06RD2 PTD 216-131 Submitted 07-05-23 - Sundry Application Ryan, Best to submit a sundry if in doubt. Do you have a density and pumping schedule. On this, I believe I can give you a verbal then follow up with forms and signatures on Monday. I will be out of contact at 12 pm today. If you cannot reach me contact Victoria Loepp. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Victoria From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Friday, July 7, 2023 9:50 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Subject: FW: 10-403 Trading Bay Unit K-06RD2 PTD 216-131 Submitted 07-05-23 - Sundry Application Mel- Could you please advise on if a sundry is even needed in this case? We are treating suspected scale in the liner, and not intending to stimulate the rock. We’re heading out there today to pump water down the well in an attempt to clear a mechanical obstruction. If that fails, we’ll be ready to pump this synthetic acid (pending your approval, if needed). Thanks, Ryan Rupert CIO Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: Donna Ambruz <dambruz@hilcorp.com> Sent: Wednesday, July 5, 2023 9:57 AM To: aogcc.permitting@alaska.gov Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Subject: 10-403 Trading Bay Unit K-06RD2 PTD 216-131 Submitted 07-05-23 - Sundry Application Application for Sundry Approval Thank you. Donna Ambruz Operations/Regulatory Tech KEN Asset Team Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 907.777.8305 - Direct dambruz@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 2022-0609_No-Flow_TBU_K-06RD2_ae Page 1 of 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO:Jim Regg DATE: 6-13-2022 P. I. Supervisor FROM:Adam Earl SUBJECT:No Flow Test Petroleum Inspector TBU K-06RD2 Hilcorp Alaska LLC PTD 2161310 June 9, 2022: I traveled to King Salmon Platform to witness a No-Flow Test on well K-06RD2. KC Dent was the Hilcorp representative. I verified calibrations were current on gauge and flow meter. The well was rigged up with 1-inch bleed lines to an Armor- Flow SCF/H meter. Tubing and IA were tied together at surface for testing this packerless ESP completion. The following table shows test details: Time Pressures 1 Flow Rate2 Remarks (psi)Gas – scf/hr Liquid –gal/hr 9:50 0 / 0 / 40 Shut well in to start test 10:05 0.02 / 0.02 / 40 10:20 0.06 / 0.06 / 40 10:35 0.08 / 0.08 / 40 10:50 0.10 / 0.10 / 40 150 none Bleed 5 min; 0 scf/hr in 45 sec 10:55 0/0/40 11:10 0.09 / 0.09 / 40 11:25 0.11 / 0.11 / 40 11:40 0.14 / 0.14 / 40 11:55 0.16 / 0.16 / 40 200 none Bleed 5 min; 0 scf/hr in 50 sec 12:00 0.01 0.01 / 40 12:15 0.12 / 0.12 / 40 12:30 0.14 / 0.14 / 40 12:45 0.17 / 0.17 / 40 13:00 0.20 / 0.20 / 40 225 none Bleed 5 min; 0 scf/hr in 80 sec 1 Pressures are T/IA/OA 2 Gas flow not to exceed 900 scf/hr; Liquid flow not to exceed 6.3 gal/hr TBU K-06RD2 results indicate a passing No-Flow Test. Attachments:none 9 9 9 9 9 9 9 James B. Regg Digitally signed by James B. 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ƌĞƚƵƌŶƐĐůĞĂŶ^ƉƵŵƉ͘ůŽǁůŝŶĞƐĚƌLJ͕ZͬĚĐŝƌĐƵůĂƚŝŶŐĞƋ͘ůĞĂƌĞĚƌŝŐĨůŽŽƌƉƌĞƉĂƌĞĚƚŽŽůƐƚŽWKK,͘WKK,>ͬĚϯϭͬϮΗ W,ϲtŬ͘^ƚƌŝŶŐ͘ĨƌŽŵϭϭ͕ϵϱϵĨƚ͘ƚŽϭϭ͕ϳϳϰĨƚ͘ƉͬƵƉǁƚ͘ĂƚϭϳϱŬ͘ŽŶƚŝŶƵĞƚŽWKK,ůĂLJŝŶŐĚŽǁŶϯ͘ϱǁŽƌŬƐƚƌŝŶŐĨͬϭϭ͕ϳϳϰ Ĩƚ͘ƚŽϮϵϯϬĨƚ͘ĚƉŵ͘,ĞĂƌĚƉŽƉŝŶƌŝŐŚƚĂŶŐůĞĚƌŝǀĞ͕ƚƌŽƵďůĞƐŚŽŽƚƐĂŵĞĨŽƵŶĚϰďƌŽŬĞŶƚĞĞƚŚ͕ǁĂŝƚŝŶŐŽŶƌĞƉůĂĐĞŵĞŶƚ ƉĂƌƚƐĨƌŽŵƚŽǁŶ͘ ϭϭͬϮϱͬϮϬϮϭͲdŚƵƌƐĚĂLJ ŽŶƚŝŶƵĞWKK,^ƚĂŶĚŝŶŐďĂĐŬϰͲϭͬϮΗϭϮ͘ϲη>ͲϴϬƐƵƉĞƌŵĂdžĐŽŵƉůĞƚŝŽŶ͕&ͬϮϵϳϳΖΖƚͬ ^WĂƐƐLJΛϭϱϳΖƐƉŽŽůŝŶŐĨůĂƚƉĂĐŬΘ ĐĂďůĞ͘ŝƐƉůĂĐŝŶŐϭϬďďůƐĞǀĞƌLJϭϬƐƚĂŶĚƐ͘ůĂŵƉĞĚ͕ĐƵƚĐĂďůĞĂŶĚĨůĂƚƉĂĐŬ͘>ͬĚƐŝŶŐůĞ͕ƵŝůƚƐĂĨĞƚLJũŽŝŶƚƉƵůůĞĚĂƐƐĞŵďůLJƚŽ ƌŝŐĨůŽŽƌŝŶƐƉĞĐƚĨŽƌƐĂŶĚĐƵƚ͘^ƚĂŐĞĚƐƵŵŵŝƚƚŽŽůƐŽŶƌŝŐĨůŽŽƌ͘>ͬ ^WĂƐƐĞŵďůLJ͘WƵŵƉƐƚƵƌŶĞĚĨƌĞĞůLJ͕/ŶƚĂŬĞǁĂƐĐůĞĂŶ͕ &ŽƵŶĚŚŽůĞŝŶƚŚĞůŽǁĞƌŵŽƚŽƌƐĞĐƚŝŽŶ͘KďƐĞƌǀĞĚƐŽŵĞůŝŐŚƚƐĐĂůŝŶŐƵŶĚĞƌŶĞĂƚŚƚŚĞŵŽƚŽƌůĞĂĚĂŶĚĨůĂƚƉĂĐŬ͘ůĞĂŶĞĚ ĂŶĚĐůĞĂƌĞĚƌŝŐĨůŽŽƌ͕ƐĞƌǀŝĐĞĚƌŝŐĂƐŶĞĞĚĞĚ͘ƐƐŝƐƚĐƌĂŶĞǁŝƚŚĂƌƌĂŶŐŝŶŐĚĞĐŬ͕ĐůĞĂƌĞĚƐŶŽǁŽĨĨǁŽƌŬĂƌĞĂƐĂŶĚ ǁĂůŬǁĂLJƐ͘ tĞĂƚŚĞƌŚŽůĚŽŶ,ĞůŝĐŽƉƚĞƌ͕ƐĐŚĞĚƵůŝŶŐďŽĂƚƚŽƉŝĐŬƵƉ^>ĐƌĞǁĂŶĚƉƵƐŚĞƌĨŽƌĐŚĂŶŐĞŽƵƚ͕ƌŝŐĚŽǁŶ^ƵŵŵŝƚĞƋƵŝƉŵĞŶƚ͘ 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^WƐƚĂƌƚƵƉ͘ d/,ǁͬ ^WŽŶϰͲϭͬϮΗϭϮ͘ϲƉƉĨ>ͲϴϬ^ƵƉĞƌŵĂdžĨͬϭϮϬΖ ƚͬϱϰϰϲΖ͕ 2021-1213_No-Flow_TBU_K-06RD2_bb.docx Page 1 of 2 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO:Jim Regg DATE:December 14, 2021 P. I. Supervisor FROM:Brian Bixby SUBJECT:No Flow Test Petroleum Inspector TBU K-06RD2 Hilcorp Alaska LLC PTD 2161310 12/13/2021:I arrived on the King Salmon Platform and walked down the rig up with Tom Buchholz (Hilcorp Operator). I verified the IA and Tubing were twinned into the meter. There were current calibrated gauges on the tubing, IA and OA. Well head pressures were recorded every 15 minutes and a bleed was performed at 1-, 2- and 3- hour marks. There is no injection support for this well. The following table shows test details: Time Pressures 1 Flow Rate2 Remarks (psi) Gas – scf/hr Liquid – gal/hr 9:15 0/0/0 Initial readings; well shut in 9:30 0/0/0 9:45 0/0/0 10:00 0/0/0 10:15 0/0/0 500 0 Open to flow; no measurable gas in 57 seconds 10:30 0/0/0 10:45 0/0/0 11:00 0/0/0 11:15 0/0/0 700 0 Open to flow; no measurable gas in 85 seconds 11:30 0/0/0 11:45 0/0/0 12:00 0/0/0 12:15 0/0/0 1000 0 Open to flow; gas rate < 900 scf/hr within 15 seconds; no measurable gas in 140 seconds 1 Pressures are T/IA/OA 2 Gas flow not to exceed 900 scf/hr; Liquid flow not to exceed 6.3 gal/hr Attachments:Flow Meter Calibration Certificate James B. Regg Digitally signed by James B. Regg Date: 2021.12.29 12:43:13 -09'00' 2021-1213_No-Flow_TBU_K-06RD2_bb.docxPage 2 of 2No-Flow Test – TBU K-06RD2 (PTD 2161310)Flow Meter Calibration Certificate courtesy of Hilcorp Alaska LLC12/13/2021 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 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): 13,322'N/A Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 7,100psi Liner 4,790psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Katherine O'Connor Contact Email: Contact Phone: 907 777-8376 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE AOGCC Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng 2,186' 8,062' Perforation Depth MD (ft): 8,062' 7-5/8"13,320'5,387' 24" 13-3/8" 376'376' 2,186' 6,324'9-5/8" Length Size 12.6# / L-80 TVD Burst 7,746' 8,150psi MD 3,090psi 376' 2,094' PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017594 / ADL0018772 216-131 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-733-20088-02-00 Hilcorp Alaska LLC Trading Bay Unit K-06RD2 McArthur River Field / Hemlock Oil Pool N/A Other: Replace ESP 6,890psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: D&L Hydroset II Twin Seal ESP Packer & Halliburton SSSV 389 (MD) 389 (TVD) & 326 (MD) 326 (TVD) 11,960 - 13,153 9,683 - 9,820 11/10/2021 4-1/2" 9,841' 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY Katherine.oconnor@hilcorp.com Dan Marlowe - Operations Manager 9,841' 13,264' 9,833' 1,630 N/A ry Statu Form 10-403 Revised 10/2021 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:13 am, Oct 20, 2021 321-551 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.10.19 14:45:48 -08'00' Dan Marlowe (1267) 10-404 X DLB 10/20/2021 DSR-10/20/21 X BJM 10/25/21 BOP test to 2500 psi. Provide 48 hrs notice for AOGCC to witness. dts 10/26/2021 JLC 10/26/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.10.26 14:12:42 -08'00' RBDMS HEW 10/28/2021 Well Work Prognosis Well: K-06rd2 PTD: 216-131 Date: 10/13/2021 Well Name:K-06rd2 API Number: 50-733-20088-02-00 Current Status:ESP Producer Leg:Leg #4 NW corner Estimated Start Date:November 10, 2021 Rig:HAK 404 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:216-131 First Call Engineer:Katherine O’Connor (907) 777-8376 (O)(214) 684-7400 (M) Second Call Engineer:Karson Kozub (907) 777-8434 (O)(907) 570-1801 (M) Current Bottom Hole Pressure:2,247 psi @ 6,178’ TVD 0.364 lbs/ft (7.00 ppg) based on ESP gauge (2/22/2017) Maximum Expected BHP:2,247 psi @ 6,178’ TVD 0.364 lbs/ft (7.00 ppg) based on ESP gauge (2/22/2017) Maximum Potential Surface Pressure: 1,630 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) *This is a no-flow well 03/14/2017 Brief Well Summary K-6rd2 is a Hemlock only producer that was completed with an ESP in 2017. The ESP had an electrical failure in September 2021. The objective of this program is to run a new ESP in the well. Last Casing Test: 02/10/2017 - 2,600psi charted for 30min on PTD Procedure: 1. MIRU HAK 404 2. Circulate well to production x Work over fluid will be FIW 3. Set BPV, ND tree NU BOP and test to 250psi Low/2,500psi High/2,500 psi Annular x Note: Notify AOGCC 24 hours in advance of test to allow them to witness test 4. Monitor well to ensure it is static 5. Unseat hanger and POOH with ESP completion 6. RU SL RIH and tag fill 7. * Contingent cleanout if fill is tagged high x RIH with clean out assembly, circulate bottoms up, POOH x * BOP’s will be closed as needed to circulate the well 8. PU and RIH with new ESP assembly. See proposed schematic 9. Set BPV, ND BOP, NU tree and test 10. Turn well over to production 11. Conduct SVS tests per AOGCC regulations 12. *If cleanout is conducted in step #7 -Conduct a no-flow per AOGCC regulations Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Current/Proposed (Same) 4. BOP Drawing 5. Fluid Flow Diagrams 6. Rolling BOP Test procedures 7. RWO Sundry Revision Change Form 48 hrs notice required for BOP test witness. bjm Planning to use 3-1/2" workstring for cleanout, per R. Rupert 10/25/21 _____________________________________________________________________________________ Updated By: JLL 03/03/17 SCHEMATIC _____________________ McArthur River Field Well: TBU K-06RD2 PTD: 216-131 API: 50-733-20088-02 Last Completed: 02/22/2017____________ PBTD= 13,264’ MD TD = 13,322’ MD 2 1 3 5 7-5/8” 4 Liner Hanger 7,933’ Min ID 6.670” HK-2 Max Hole Angle = 86.29° @ 11,921’ 13-3/8” 9-5/8” TOC 11,800’ 24” X 8-1/2” TOW 8,062’ CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 24” - - - Surf 376’ 13-3/8" 61 J-55 BTC 12.515” Surf 2,186' 9-5/8"53.5** S-95 BTC 8.535” Surf 1,968' 47 L-80 BTC 8.681” 1,968' 8,062' (TOW) 7-5/8" 29.7 L-80 Hyd 511 6.875” 7,933' 13,320' TUBING DETAIL 4-1/2” 12.6 L-80 Supermax 3.958” Surf 7,746’ **Note 1988 files indicate that 53.5# 9-5/8” should have been at the bottom of the K-06rd which is below K- 06rd2 sidetrack depth. This has not been confirmed. JEWELRY DETAIL No Depth MD Depth TVD ID OD Item 1 48.58’ 49’ 3.958” 13.625” Tubing Hanger 2 326’ 326’ 3.813” 5.960” SSSV Halliburton PN 102529376 3 389’ 389’ 3.950” 8.312” D&L Oil Tools Hydroset II Twin Seal ESP Packer w/WFT Vent Valve 4 432’ 432’ 3.813” 5.570” X-nipple 5 7,746’ 6,088’ N/A 5.130” Discharge, Bolt-On 7,746’ 6,088’ N/A 6.750” Pumps (x2) 45 Stg SH16000AR 7,785’ 6,116’ N/A 6.750” Intake 7,786’ 6,117’ N/A 5.130” Seals 7,804’ 6,130’ N/A 5.620” (2) 562 500HP Motors (1,000HP/3600V/165.5A) 7,869’ 6,178’ N/A 5.620” Centralizer Anode PERFORATION DETAIL Zone Top MD Bottom MD Top TVD Bottom TVD Feet SPF Date Status HK-2 11,960’ 13,153’ 9,683’ 9,820’ 1,193’ 6 12/19/2016 Open _____________________________________________________________________________________ Updated By: JLL 10/14/21 PROPOSED McArthur River Field Well: TBU K-06RD2 PTD: 216-131 API: 50-733-20088-02 Last Completed: FUTURE PBTD= 13,264’ MD TD = 13,322’ MD 1 2 7-5/8” Liner Hanger 7,933’ Min ID 6.670” HK-2 Max Hole Angle = 86.29° @ 11,921’ 13-3/8” 9-5/8” TOC 11,800’ 24” 8-1/2” TOW 8,062’ CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 24” - - - Surf 376’ 13-3/8" 61 J-55 BTC 12.515” Surf 2,186' 9-5/8"53.5** S-95 BTC 8.535” Surf 1,968' 47 L-80 BTC 8.681” 1,968' 8,062' (TOW) 7-5/8" 29.7 L-80 Hyd 511 6.875” 7,933' 13,320' TUBING DETAIL 4-1/2” Surf ±7,746’ **Note 1988 files indicate that 53.5# 9-5/8” should have been at the bottom of the K-06rd which is below K- 06rd2 sidetrack depth. This has not been confirmed. JEWELRY DETAIL No Depth MD Depth TVD ID OD Item 1 49’ 49’ 3.958” 13.625” Tubing Hanger 2 ±7,746’ ±6,088’ N/A 5.130” Discharge, Bolt-On Pumps Intake Seals Motors ±7,869’ ±6,178’ N/A 5.620” Centralizer Anode PERFORATION DETAIL Zone Top MD Bottom MD Top TVD Bottom TVD Feet SPF Date Status HK-2 11,960’ 13,153’ 9,683’ 9,820’ 1,193’ 6 12/19/2016 Open King Salmon Platform K-06RD2 BHTA, B-11-A0, 4 1/16 5M FE Valve, Swab, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Master, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Wing, CIW-FL, 3 1/8 5M FE, HWO, EE trim All unihead annular valves, 2 1/16 5M FE OCT-20, HWO Valve, OCT-20, 3 1/8 2M FE, HWOStarting head, OCT, 21 ¼ 2M FE X 24'’ SOW, w/ 1- 3 1/8 2M EFO, full set of lockpins Unihead, OCT type 3, 13 5/8 5M API hub top X 13 3/8 BTC casing bottom, w/ 1- 2 1/16 5M SSO on lower section, 1- 2 1/16 5M SSO on middle section, 3- 2 1/16 5M SSO on upper section , IP internal lockpin assy Adapter, OCT-A5-ESP, 13 5/8 5M API hub X 4 1/16 5M stdd top, w/ 2- ½ control line exits, prepped w/ OCT 400-4 pocket King Salmon K-06RD2 24 X 13 3/8 X 9 5/8 X 4 ½ Tbg hanger, OCT-UH-TC-1A- ESP, 13 X 4 ½ IBT lift and susp, w/ 4'’ Type H BPV profile, 3/8 cont control line port 24'’ 13 3/8'’ 9 5/8'’ 4 ½’’ Valve, Wing, WKM-M, 2 1/16 5M FE, HWO, AA trim Valve, Wing, WKM-M, 3 1/8 5M FE, w/ OMNI oper, EE trim King Salmon Platform BOP Stack HILCORP ALASKA, LLC SwacoSuperchokeBlooey LineTo Gas BusterInlet Rig 404 BOP Test Procedure Attachment #1 Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Rig 404, WO Program – Oil Producers, Gas Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with kill weight fluid. x Note: Fluid level will fall to a depth that balances with reservoir pressure. x Shoot fluid levels as needed. 3) Confirm that well is static. Initial Test (i.e. Tubing Hanger is in the Wellhead) If BPV profile is good 1) Set BPV. ND Tree. NU BOP. 2) MU landing joint. Pull BPV. Set 2-way check in hanger. 3) Space out test joint so end of tubing (EOT) is just above the blind rams. 4) Set slips, mark same. Test BOPE per standard test procedure. If the tubing hanger won’t pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on. Profile and/or landing threads must be prepped while tree is off. Worst Case: BPV profile and landing threads are bad. 1) Attempt to set BPV through tree. If unsuccessful, shoot fluid level. 2) If fluid level is static from previous fluid level shots, notify Hilcorp Anchorage office that the well is static and the tree must be removed with no BPV. As approved in the sundry, proceed as follows: a) Fill well with KWF if the fluid is not to surface b) ND tree with no BPV Inspect and prepare BPV profile to accept a 2-way valve, or prepare lift-threads to accept landing joint to hold pressure. If well is a producer and the culprit is scale, attempt to clean profile with Muriatic acid and a wire brush or wheel. c) Set 2-way check valve by hand, or MU landing (test) joint to lift-threads d) For ESP wells - Ensure that cap is on cable penetrator e) NU BOP. Test BOPE per standard procedure. 3) If both set of threads appear to be bad and unable to hold a pressure test and / or a penetrator leaks, notify Operations Engineer (Hilcorp), Mr. Bryan McLellan (AOGCC – bryan.mclellan@alaska.gov) and Mr. Jim Regg (AOGCC - jim.regg@alaska.gov) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. As outlined and approved in the sundry, proceed as follows: a) Nipple Up BOPE b) With stack out of the test path, test choke manifold per standard procedure c) Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d) Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. Rig 404 BOP Test Procedure Attachment #1 e) Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 4) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 5) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re-land hanger (or test plug) in tubing head. Test BOPE per standard procedure. Subsequent Tests (i.e. Test Plug can be set in the Tubing-head) 1) Remove wear bushing. a) Use inverted test plug to pull wear busing. MU to joint of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same- RIH with test plug on joint of tubing. Install a pump-in sub w/ test line plus an open TIW or lower Kelly valve in top of test joint w/ open IBOP. 3) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE (after 2-way check or test plug is set) 1) Fill stack and all lines with rig pump- install chart recorder on test line connected to pump-in sub below safety valve and IBOP in test joint assembly. 2) Note: When testing, pressure up with pump to desired pressure, close valve on pump manifold to trap pressure and read same with chart recorder (test pressures will be indicated in Sundry). 3) Referencing the attached schematics test rams and valves as follows. a) Close 1 st valve on standpipe manifold (PM1), close valves 8,10 &11 on choke manifold and close the annular preventer, open safety valve on top of test jt and close IBOP. Pressure test to 250 psi for 5 minutes and xxx psi (see sundry) high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank and open annular. b) Close pipe rams and open annular preventer, close safety valve and open IBOP on test joint, close outside valve on kill side of mud cross (K2), open PM1, close valves 5,7 & 9 on choke manifold, open valve 10 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. c) Test Dual Rams. If the well has dual tubing, and dual rams are installed in the stack, test the dual rams by picking up two test joints with dual elevators and lowering them into stack and position them properly in the dual rams. Close rams. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. d) Close manual and super choke / open valves 7 & 9 on choke manifold. Bleed pressure from step b or c recording change and stabilization. If passes after 5 minutes, bleed off pressure back to tank. e) Close inside valve (K1) / open outside valve on kill side of mud cross (K2), close valves 2,4 & 6 / open valves 5,7 & 9 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. f) Close valves 1 & 3 / open valves 4 & 6 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. Rig 404 BOP Test Procedure Attachment #1 g) Close HCR (CL2) open valves 2,4 & 6 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. h) Close inside valve (CL1) / open outside valve (HCR) on choke side of mud cross. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. i) Ensure all pressure is bled off- open pipe rams and pull test joint leaving test plug / 2-way check in place. Close blind rams and attach test line to valve 11 on choke manifold, close valve 1,2 & 3 / open valve 11 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. j) Test additional floor valves (TIW or Lower Kelly Valve) and IBOPs as necessary. STANDARD TEST PROCEDURE OF CLOSING UNIT (ACCUMULATOR) 1) This is a test of stored energy. Shut off all power to electric and pneumatic pumps. 2) Record “Accumulator Pressure”. It should be +/- 3,000 psi. 3) Close Annular Preventer, the Pipe Rams, and HCR. Close 2 nd set of pipe rams if installed (e.g. dual pipe rams). Open the lower pipe rams to simulate the closing volume on the blinds. 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (i.e. Report might read “10 bottles at 2,150 psi”). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre- charge pressure of 1,000 psi). 7) Turn on the electric pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually +/- 30 seconds. 8) Once 200 psi pressure build is reached, turn on the pneumatic pumps and record the time it takes for the pumps to automatically shut-off after the pressure to builds back to original pressure (+/- 3,000 psi). Note: Make sure the electric pump is turned to “Auto”, not “Manual” so the pumps will kick-off automatically. 9) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 10) Fill out AOGCC report. FINAL STEP, FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves, for correct operating position 3) Fill out the AOGCC BOPE Test Form (10-424) in Excel Format. Document both the rolling test and the follow up tests. Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well: K-06RD2 (PTD 216-131)Sundry #:Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC 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 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date 1 Carlisle, Samantha J (CED) From:Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent:Monday, October 25, 2021 2:14 PM To:McLellan, Bryan J (CED) Cc:Katherine O'connor; Karson Kozub - (C); Donna Ambruz; Juanita Lovett; Dan Marlowe Subject:RE: [EXTERNAL] RE: TBU K-06RD2 (PTD 216-131) RWO sundry BryanͲ Wewoulduse3Ͳ1/2”pipeasaworkstring.Thanks, Ryan Rupert Kenai Ops Engineer (13146) 907-301-1736 (Cell) 907-777-8503 (Office) From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Sent:Monday,October25,20219:18AM To:KatherineO'connor<Katherine.Oconnor@hilcorp.com>;RyanRupert<Ryan.Rupert@hilcorp.com> Subject:[EXTERNAL]RE:TBUKͲ06RD2(PTD216Ͳ131)RWOsundry Ryan, FYI,I’mstillwaitingonananswerbeforeIprocesstheSundryonthiswell.IknowKatherineisoutthisweek,soI’m forwardingittoyou. BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission 333W7thAve Anchorage,AK99501 Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 From:McLellan,BryanJ(CED) Sent:Thursday,October21,20211:26PM To:KatherineO'connor<Katherine.Oconnor@hilcorp.com> Subject:TBUKͲ06RD2(PTD216Ͳ131)RWOsundry Katherine, Whatsizepipewillyouuseforthecontingencyfillcleanoutonthiswell? BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission 31 ►7411 TO: Jim Regg DATE: 3/11/17 P. I. Supervisor FROM: Bob Noble SUBJECT: No Flow Test Petroleum Inspector TBU K-06RD2 Hilcorp PTD 216-131 3/11/17: On arrival to the King Salmon platform I met with lead operator Sandy Reynolds and production operator Tim Iverson. We went over how I would like to prove the no-flow out and past ones that they had done. Tim and I went to the wellhead room and I inspected the way he had the pressure and no-flow gauges rigged up. Tim had the IA tied into the flow path up stream of the flow meter which is correct. They had a 3/4" bleed hose that was about 100 feet long. I felt the size and length could slow the bleed time down. Tim told me he wanted to bleed in the other room because of gas heads and a drain system in case they got fluid. The well has an OOA. The following table shows test details: Pressures' Flow Rate Time Remarks (psi) Gas - scf/hr Liquid - gal/hr 10:00 0/0/0/50 ' 0 0 Shut well in for 3 hour build up • 10:30 .17/.17/0/50 - 0 0 11:00 .25/.25/0/50 - 0 0 11:30 .37/.37/0/50 0 0 12:00 .49/.49/0/50 ' 0 0 12:30 .59/.59/0/50 0 0 13:00 - .72/.72/0/50 - 900 - 0 Opened we'll to bleed down - 13:03 - .22/.22/0/50 - 450 0 13:05 - 0/0/0/50 - 0 - 0 Well was dead 1 Pressures are T/IA/OA Summary: The well bleed to 0 flow and 0 psi in 5 minutes with no sign of gas meeting the standards for a passing no-flow test. 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J N 0 Te W a OC a. 1 W 0 1 U J J 1-3 Z ▪ o Q co co J d r a Om - 0 G C r a) 1I N O - E rI r- U U a) o J 0 E r- Q reco Eto a I~— n Z o I I C = N C N Ca m N 1 z N w o 0 0 1110 Q g o ikQ z E D (5 z I 3v N N O) N n N M > m .- a to 0 Nm N m (0 Q' .` N o N C , m O M CO O N0 co O 0 w C C U .2 a) a) Q a) ii, la C7 O_ 6 0 E G If O a.a 2 v a 0 h 0 21 6131 Sebra Oudean Hilcorp Alaska, C 2 8 2 8 6 AK_GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 RECEIVED Tele: 907 777-8337 min.?Alaska, �/ Fax: 907 777-8510 E-mail: doudean@hilcorp.com DATA LOGGED G/2P/2011 JUN 1 2 2017 K.BENDER DATE: 6/8/2017 AOGCC To: AOGCC Makana Bender 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL TBU K-06RD2 CD Copy of emailed CBL CBL 2/17/2014 GR_CBL 2/17/201 Prints: CBL 2/17/2017 GR_CCL 2/17/2017 Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: i i Guhl, Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Thursday,June 1, 2017 9:14 AM To: Cody Dinger- (C) Cc: Schwartz, Guy L(DOA); Bettis, Patricia K(DOA) Subject: TBU K-06 RD2, PTD 216-131, CBL Hello Cody, I'm completing the compliance review of TBU K-06 RD2, PTD 216-131,completed February 22, 2017. In box 22, Logs Obtained, Guy Schwartz notated that a CBL was run on 2/17/2017, however this log in both paper and digital format has not yet been submitted to the AOGCC.All logs obtained are required to be submitted to the AOGCC within 90 days of well completion,which ended May 22, 2017. Also this log was not listed in box 22. Please ensure that all logs obtained are listed on the 10-407. Please submit required paper and digital data to the AOGCC by June 8, 2017. If you have any questions, please contact me. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave,Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 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 Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. 1 RECEIVED STATE OF ALASKA MAR 242017 ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT ANA 1 a.Well Status: Oil Q . Gas❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ 1 b.Well Class: 20AAC25.105 20AAC25.110 Development ❑✓ ^ Exploratory ❑ GINJ p WINJ ❑ WAGE WDSPL❑ No.of Completions: _1 Service ❑ Stratigraphic Test ❑ 2.Operator Name: 6. Date Comp.,Susp.,or 14. Permit to Drill Number/ Sundry: Hilcorp Alaska, LLC Aband.: 2/22/2017 , 216-131 ✓316-629/316-490 3.Address: 7. Date Spudded: 15.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 December 18,2016 A 50-733-20088-02-00 , 4a. Location of Well(Governmental Section): 8.Date TD Reac2hed: IA- 16.Well Name and Number: Surface: 736'FSL, 135'FEL,Sec 17,T9N, R13W,SM,AK January21,2017 TBU K-06RD2 ` Top of Productive Interval: 9. Ref Elevations: KB: 418'S- 17. Field/Pool(s): 1241'FSL, 873'FEL,Sec 16,T9N, R13W,SM,AK GL:73 BF:52 121- McArthur River Field/Hemlock Oil Pool Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 2150'FSL,68'FWL,Sec 15,T9N, R13W,SM,AK 13,264'MD/9,833'TVD ADL017594&ADL018772 , 4b. Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. Land Use Permit: Surface: x- 213762 y- 2511799 Zone- 4 13,322'MD/9,841'TVD N/A TPI: x- 218313 y- 2512205 Zone- 4 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 219275 y- 2513091 Zone- 4 326'MD/326'TVD N/A 5. Directional or Inclination Survey: Yes E(attached) No ❑ 13.Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 73 (ft MSL) 8,062'MD/6,324'TVD 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071,submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first.Types of logs to be listed include, but are not limited to:mud log,spontaneous potential, gamma ray,caliper, resistivity,porosity, magnetic resonance,dipmeter,formation tester,temperature,cement evaluation,casing collar locator,jewelry,and perforation record. Acronyms may be used.Attach a separate page if necessary ROP, DGR Dual Gamma Ray, EWR-PHASE 4,ALD uthal Lithodensity,CTN Compensated Thermal Neutron, MUDLOGS: Formation Log,Drilling Dynamics Log,Gas Ratio Log snf LWD Combo Log c lid ) 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT. GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 7-5/8" 29.7# L-80 7,933' 13,320' 6,234' - 9,841' 8-1/2" 236 sx Class G 15.3 ppg 24.Open to production or injection? Yes ❑✓ No ❑ 25.TUBING RECORD If Yes, list each interval open(MD/TVD of Top and Bottom; Perforation SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Size and Number): 4-1/2" 7,746' 389'MD/389'TVD 11,960'-13,153'MD/9,683'-9,820'TVD 6 SPF 26.ACID, FRACTURE, CEMENT SQUEEZE, ETC. a Was hydraulic fracturing used during completion? Yes❑ No ❑ 242- 1'4Per 20 AAC 25.283(i)(2)attach electronic and printed information DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED . L.,.... 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 2/23/2017 ESP Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 2/24/2017 24 Test Period lo.291 110 8142 N/A 378 Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 90 115 24-Hour Rate — 291 110 8142 33 1 Form 10-407 Revised 11/2015 CONTINUE O E 2 Submit ORIGINIAL only -N/ 4111I?- 677,2-1,t ! 2,zi RBDMS w MAR 2 8 2017 (��J 28.CORE DATA Conventional es): Yes ❑ No Q Sidewall Corees ❑ No ❑ If Yes, list formations and intervals cored(MD/TVD, From/To),and summarize lithology and presence of oil,gas or water(submit separate pages with this form, if needed).Submit detailed descriptions,core chips,photographs,and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑., Permafrost-Top If yes, list intervals and formations tested,briefly summarizing test results. Permafrost-Base Attach separate pages to this form, if needed,and submit detailed test Top of Productive Interval 11,960' 9,683' information, including reports,per 20 AAC 25.071. GG Marker 10926' 9039' G1 ST 10939' 9051' Coal 39 11102' 9202' Marker 13 11249' 9331' D 11360' 9423' MKR 13 11431' 9477' G7ST 11454' 9494' MKR 14 11568' 9566' H1X FW 11632' 9600' Coal 59 11685' 9623' HTKE-FW 11710' 9633' HK2T 11962' 9683' Formation at total depth: Hemlock 31. List of Attachments: Wellbore Schematic, Decomplete, Drilling and Completion Reports, Definitive Directional Surveys,Casing and Cementing Reports, Days vs Depth,MW vs Depth Information to be attached includes,but is not limited to:summary of daily operations,wellbore schematic,directional or inclination survey,core analysis, paleontological report, production or well test results,per 20 AAC 25.070. 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Cody Dinger Email: cdinger@hilcorp.com Printed Name: Cody Dir)pr Title: Drilling Tech Signature: f�� �'d� Phone: 777-8389 Date: /2-4,/zo F INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed.All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item la: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item lb: 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 II • • McArthur River Field Well:TBU K-06RD2 SCHEMATIC D API:50-733 20088-02 Hilcorp Alaska,LL( Last Completed:02/22/2017 CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. J 1 I 24 - - BTC 12.515" Surf 376' 2 2 24' 13-3/8" 61 J-55 Surf ,186' 9 5/8" 53.5** 5-95 BTC 8.535" Surf 1,968' `'w 47 L-80 BTC 8.681" 1,968' 8,062'(TOW) 7-5/8" 29.7 L-80 Hyd 511 6.875" 7,933' 13,320' TUBING DETAIL 4-1/2" 12.6 L-80 Supermax 3.958" Surf 7,746' **Note 1988 files indicate that 53.5#9-5/8"should have been at the bottom of the K-06rd which is below K- 06rd2 sidetrack depth.This has not been confirmed. JEWELRY DETAIL Depth No DMDh TVD ID OD Item 1 48.58' 49' 3.958" 13.625" Tubing Hanger 2 326' 326' 3.813" 5.960" SSSV Halliburton PN 102529376 13-3/8" D&L Oil Tools Hydroset II Twin Seal ESP Packer w/WFT Z. 3 389' 389' 3.950" 8.312" xi Vent Valve Div 4 432' 432' 3.813" 5.570" X-nipple 7,746' 6,088' N/A 5.130" Discharge,Bolt-On 7,746' 6,088' N/A 6.750" Pumps(x2)45 Stg SG16000AR 5 7,785' 6,116' N/A 6.750" Intake 7,786' 6,117' N/A 5.130" Seals 7,804' 6,130' N/A 5.620" (2)562 500HP Motors KMLST(1,000HP/3600V/165.5A) :mi. 7,869' 6,178' N/A 5.620" Centralizer Anode 6 Liner Hanger 7,933' Min ID 6.670° 8-1/2'TOW 8,062' S. 9-5/8" PERFORATION DETAIL Zone Top Bottom Top TVD Bottom Feet SPF Date Status MD MD TVD HK-2 11,960' 13,153' 9,683' 9,820' 1,193' 6 12/19/2016 Open TOC 11,800' • ° 1a }7 1X5 ,' air HK-2 :f At df ito s 7-5/8„ PBTD=13,264'MD TD=13,322'MD Max Hole Angle=86.29°@ 11,921' Updated By:JLL 03/03/17 • • Hilcorp Energy Company Composite Report Well Name: MRF K-06RD2 Field: County/State: ,Alaska (LAT/LONG): Ovation(RKB): API#: Spud Date: Job Name: 1613025P K-06RD2 PreDrill Contractor AFE#: 1613025P AFE$: $981,600 ..................:::::::::..... ;mss` t'"t>5 :.:]1'.y 1 ��:+.. « :::�......:. a:'ti::i::i::i:::i::i::i::i::::::�::�::i::isii::::::::i�.::.::�:.::.::::::t.:::::.:::. �:ACL�Y�t:�.:'.{'!yr3 1.4^'k,::::.:.`:::::'::.;:i:i::�::���::�':... ::::::: ::::::..:::::::.. i::ii::::isi::::::i'::::�::::�::::}::::#::::5: f ......:........:.f. ..... ....i:................. ......... 12/8/2016 No activity on this AFE.,Change out saver sub to CDS-40.Rig up bales and link tilt.Make up Kelly hose(will need to be adjusted).,Rig up hoses to circulate and kill well.Test lines at 250 U1500 H.,Hold PJSM with all to be involved in job. Attempt to circulate.Troubleshoot lines to well head blockage.,K-06RD2 wellhead pressures:24"=42 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today= 0 Total: 92.5 12/9/2016 Troubleshoot HP line blockage to well head.Found HP hose plugged w/cmt. chg/out hoses and re-test lines U 250-1500 psi(ok).,Check valve alignment and pump FIW dn tbg and fluid pack well,catch pressure on 9-5/8"w/35 bbls away and open same to pipe line. Staging rate U 5 bpm, circ total 940 bbls w/110 bbls oil cap shut dn and shut in monitor pressures for(1)hr both tbg and annulus on vacuum within 15 min. Re-fill and establish+-11 bph loss rate. Shut dn and shut in monitor to both sides on vacuum blow dn and r/dn circ lines and set,IS type BPV(Good set)also while circ we finished install of Kelly hose and adjustment and check clearance issues.,Nip/dn tree and remove from well room inspect hanger.Appears to be SS threads,good and dress same.(1)LDS has broken tip.Lock open SSSV dress all LDS.Install LH blanking sub.,Install riser.Install choke and kill lines uni-bolt hose.Nipple up BOPE.Set flow box and rotary table and seal same.,K-06RD2 wellhead pressures:24"=42 psi, 13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today= 0 Total: 92.5 12/10/2016 Open lower rams and inspect(good).Open blind rams and noted damage to seals.Replace blind ram rubbers and reinstall.Install flow box flow line and rotary table.Sealed flow box and table.Set mouse hole.Begin making up 3 1/2"test joint.,Finish making up 3 1/2"test joint.Fill stack and purge air from BOPE.,Test BOPE as per sundry/PTD on 3 1/2" at 250 U3500 H,annular at 250 02500 H. Tested gas alarms and PVT's(good).,Lay down 3 1/2"test joint and make up 4 C(/, 1/2"test joint.,Test BOPE with 4 1/2"at 250 U3500 H.Perform accumulator draw down test.All was witnessed by AOGCC(Brian Bixby). Had one F/P on v initial test of annular preventer.Worked air out and retested okay.,Pull and lay down 4 1/2"test joint and LH blanking plug.Tubing was on a vacuum.Close V / \Jblind rams.,Assist Tesco with changing out service loop and adjusting top drive torque.Work on sealing rig floor around rotary table.,Blow down boilers,steam ''1 and water lines.Assist rig and production electricians with rewiring transfer switch and modification. Rig up return line from annulus to production.,K-06RD2 wellhead pressures:24"=40 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today= 0 Total: 92.5 12/11/2016 Finish installing fiber board on rigs transfer switch and re-lug cables.,Power rig back up. Fire boilers and warm up rig while pulling IS type BPV. Test circulating line to production 250-1500 psi(ok).,Check valve alignment and pump FIW dn tbg and fluid pack well.Catch pressure on 9-5/8"w/50 bbls away and open same to pipe line.Staging rate U 5 BPM. Circ total 632 bbls w/very little oil cap. Shut down,blow dn and r/dn circ line to production.,Circulate across top of blinds and warm up HP lines and TDS.Shut down and test rigs HP lines 250-4000psi.,Rig repair.Change out rubber on stand pipe right above stand pipe valve and re-test 250-4000 psi(ok).Blow down mud line.,Chk tbg on vacuum.Open blinds.M/U 4-1/2"landing joint and check annulus.On vacuum.Back out LDS. Pull hanger off seat @ 60k and U 92k w/6'travel.Fill hole w/40 bbls and establish 21 BPH loss rate.Circulate tubing volume at 6 BPM/330 psi. UD pup and valve.,Rig up Pollard. Run#1 with 2.75 GR/JB to 9409'. Run#2 with 2.5"jet cutter.Correlate and make cut at 9390'with 10K over on slips.Saw good indication of cut. POOH.18 BPH loss rate.,Rig down Pollard.R/U Weatherford. Pull and lay down landing joints,tubing hanger and 4 1/2" pup joints.11 BPH loss rate. Pick up weight 70K after cut.,Hold well control drill.Install safety mats around rotary table.Monitor well(1 BPH loss rate). Install wiping rubber.Modify cross-over for lift nubbin for 3 1/2"DSS-HTC.,POOH laying down 3 1/2"DSS-HTC completion string from 9390'to 6900'. Flow check at 8400'.Well is static.,K-06RD2 wellhead pressures:24"=40 psi, 13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today= 0 Total: 73.5(corrected). 12/12/2016 POOH laying down 3-1/2"DSS-HTC gas lift completion string from 6900'to surface. w/1.2 bbls over cal fill. Checking against 1988 run tally.Recovered hanger,(6)pups,SSSV assy,(4)GLM w/handling pups,299 jts&14.77'cut off.OD of pipe good shape.ID of pipe good U a little over 1/2 way w/no norm detected above background.Then got+-1/16" scale build up and high norm of 60 micro/rim/hr.,Tesco hand observed spooling of drum(ok)and calipered Lebus grooving peaks and valleys and spot calipered drlg line and released Tesco hand to go discuss findings of rig repair w/Kuukpik management.,Clean and clear floor C/O elevators, Udn WATCO equipment.R/U drill pipe spinners.Power wash&scrub rig floor.,P/up two jts 4-1/2"CDS40 16.6#S-135 DP&install 9"ID wear ring.Install standpipe pressure gauge.,Pick up clean out BHA:8 1/2"Bit,casing scraper,bit sub,8 1/2"string mill,bumper sub,oil jars,XO,18 joints HWDP= 594.31. Well control drill 28 seconds.,RIH with clean out assembly picking up 4 1/2"CDS40 16.6# S-135 drill pipe to 2800'.,K-06RD2 wellhead pressures:24"=40 I psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today= 0 Total: 73.5. 12/13/2016 Run in hole with clean out assembly picking up,and drifting 4 1/2"CDS40 16.6# S-135 drill pipe from 2800'to 6038'.,Run in hole with clean out assembly picking up,and drifting 4 1/2"CDS40 16.6# S-135 drill pipe from 6038'to 8272...Run in hole with clean out assembly picking up,and drifting 4 1/2"CDS40 16.6# S-135 drill pipe from 8272'to 9203',change over to rig power.,Wash down from 9203',tagged tubing stub at 9401'with 10K squat.80K DW,155K UW.,Circulate and reciprocate pipe at 560 GPM and 1550 PSI SPP to clean well bore and check parameters,(10 RPM,TQ 8K.RT/WT 110K),(20 RPM,TQ 8.2K,RT/WT106K),(30 RPM TQ 8.7K,RT/WT 106K),(40 RPM,TQ 9.2K, RT/WT 106K) NOTE:SPM on#1 mud pump fluctuated 5-14 SPM while moving blocks,SPP fluctuated 175 PSI. Circulated a total of 2 bottoms up had dirty water coming back with very little to no solids.,Lay down single,blow down top drive,trip out of hole with casing scraper assembly from 9371'to 8707,UW 150K.,Continue to trip out of hole with casing scraper assembly from 8707'to 7311',noticed vibration and shaking while tripping out,found drilling line was flattened with broken strands were line goes through drum at kick plate.,Cut and slip 90'of drilling Iine.,Rig service,inspect draw works bolts,drum,hydraulic motors,top drive,lube and check oils.,Continue to trip out of hole with casing scraper assembly from 7311'to 4678'inspecting drilling line every 15 stands.,K-06RD2 wellhead pressures:24"=40 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg= 0 psi Daily Code 8:Today= 0 Total: 73.5. • 12/14/2016 Continue to trip out of hole with casing scraper assembly from 4678'to BHA,inspecting drilling line every 15 stands.,Rack back 9 stands of HWDP and lay down mill,scraper,and bit,inspecting all. Calculated hole fill 61.1 BBL,actual 64.0.,Open blinds after laying down BHA,noticed fluid fall+-3',then started ballooning back. First 20 minutes had a.5 BPH flow rate,tapering off to static,then back to slight loss rate.,Finish making up safety joint for wire line lubricator, rigged up E-line and run in hole with 8.125"Weatherford cement retainer. Tied in with E-line verifying collar locations,tag tubing stub,picked up 5'and set top of cement retainer at 9386'WLM,had good indication of set,pick up logging,and set back down to confirm set.,Pull out of hole,and log up from 8300'to 7900' for tie in and set of bridge plug,for whip stock anchor. Rig down Pollard E-Iine.,Change out elevators to 3.5",and rig up Weatherford power tongs.,Rig service, lube block,crown,top drive and drawworks.,Pre job safety meeting on,picking up stinger and making up BHA.,Pick up 30 joints of 3.5"tubing while strapping and drifting same.,Rig down Weatherford tongs,change out elevators to 4.5"drill pipe.,Trip in hole with cement stinger on 4 1/2"drill pipe from 931'to 5544'. Driller stopped block to quickly and backlashed drilling line.,Rig Repair: Hang blocks and straighten drilling line,then found a nut on the rig floor,after investigation found where it had backed out of make up tong ram,reinstalled with Lock-Tite. Attempt to move pipe and found hydraulic leak on valve bank under draw works(leaking plug)tighten same and resume operations.,Trip in hole with cement stinger on 4 1/2"drill pipe from 5544'and tagged top of retainer at 9390 drill pipe measurement.,Rigged up and performed injectivity test,with FIW initial rate of 30 GPM,walking pressure up to 780 PSI where it broke over and we were able to inject at 30 GPM at 711 PSI,increased rate to 44 GPM and walked pressure up to 1500 PSI,shut down pumps and recorded pressure drop. 15 SEC=1155 PSI,30 SEC=1099 PSI,45 SEC=885 PSI, 1 MIN=800 PSI,2 MIN=538 PSI,3 MIN=534 PSI,4 MIN=524 PSI,5 MIN=512 PSI.,Unacceptable injection rate,will proceed with balanced cement abandonment plug.,K-06RD2 wellhead pressures:24"=45 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today= 1 Total: 74.5. 12/15/2016 Clean and clear rig floor,rig up Schlumberger cementers running high pressure treatment and water hoses,staged squeeze manifold on rig floor and plumbed up same with overboard line going to slop tank.,PJSM with all personnel involved in cement job. Blew air through lines going from rig to cement unit,found ice plugs in water lines and at cement mix hopper valves,rigged up jet heater to thaw lines. Flush cement lines with 10 BBL of fresh water taking returns to slop tank. Fluid pack all lines going up to pump in sub,pressure test lines 900 low and 3200 PSI high. Pumped 19.5 BBLS fresh water down hole at 5 BPM.,Batch up verify density with mud scales and found density meter on unit reading.4 PPG low,compensated by having cementers mix at 16.2 PPG reading on their density meter.Mix and pump 40 BBLS 15.8 PPG type"G"(193 sacks with a yield of 1.16)balanced cement plug,at 2.5 BPM with D046 antifoam.2%BWOC, D065 dispersant 03°%BWOC,D255 fluid loss 05%BWOC,D177 retarder.03%BWOC,pumped 5 BBLS fresh water„changed over to rig pump and displaced with 109 BBLS FIW at 6.3 BPM caught pressure at 30 BBLS away. CIP©13:00 HRS estimate top of cement at 8858'. 70 BC= 05:26 HR:MN, 100 BC=05:31 HR:MN.,BIow down and rig down circulating equipment,pull out of hole from 9390'to 8513'at 5 minutes per stand until out of cement,drop pipe wiper ball and circulate a surface to surface volume at 10 BPM 900 PSI. Note no cement seen at surface.,Pre job safety meeting on slip and cut drilling line. Slip and cut 350'of line and remove from rig floor.Quadco representative on board testing and certifying accumulator gauges.,Breakdown cementing assembly,trip out of hole from 8513'to 4243'standing back 4 1/2”CDS40 drill pipe in derrick.Calculated displacement 27.73 BBL,actual displacement 27.39 BBL.,Continue to trip out of hole from 4243'to 931'standing back 4 1/2"CDS40 drill pipe in derrick.Calculated displacement 49.41 BBL, actual displacement 49.05 BBL.,Change elevators from 4 1/2"drill pipe,to 3 1/2"YT,rig up Weatherford tongs, pull 931'of 3 1/2"tubing/cement stinger and lay down same,rig down Weatherford tongs,and change elevators back to 4 1/2"drill pipe.,Pull wear bushing.,Begin 9 5/8"casing test to 2500 PSI.,K-06RD2 wellhead pressures:24"=45 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today= 0 Total: 74.5. 12/16/2016 Complete 30 minute,9 5/8"casing test to 2500 PSI all good,blow down choke,and mud lines.Note:pressured to 2650 PSI pressure fell 50PSI in 30 minutes, with the last 20 straight Iine.,Rig up Pollard E-line,run in hole with 8.125"Weatherford CIBP,logged up from 8246'to 8015'looking for adequate formation behind casing to mill window(no coal). Set CIBP at 8085.5'WLM,(dirty sand formation behind casing),logged up and set back down to verify set,pull out of hole with Baker 20 setting tool,lost line weight at 1204'pulled out of hole and found line parted at weak point of rope socket.,Mobilize slick line unit from Steelhead,along with crew from the beach via the boat. While waiting on slick line clean and organize rig keep up with housekeeping,service top drive,blocks, draw works,fuel rig,run hoses to displace well over to OBM.,Pre job safety meeting with all parties,rig up Pollard slick line. Run#1: Run in hole with 1.25" JDC pulling tool,with a 4.5:bell guide set down to 8100'WLM, picked up had additional weight indicating tool engagement,pulled out of hole to 8065'WLM lost weight. Run in hole tagging tools and picking up without tool engagement,several times. Trip out of hole with JDC pulling tool and found it sheared.,Redress JDC pulling tool with new shear pins. Run#2:Run in hole to 8100'engaged Baker 20 setting tool picked up had additional 450 LBS,pull out of hole,had full recovery,laid down tools and rigged down wire Iine.,Picked up 8.5"Baker window mill,lower string mill,flex joint,upper string mill,cross over, and 1 joint of HWDP. Picked up assembly and made up whip stock slide on bottom with 47K shear bolt,verified shipping bolt was removed and that 3 shear pins were installed with a shear value of 19890#,scribed back in hole and made up XO float sub and MWD.,Sperry plugged into MWD and uploaded,made up cross over and run in hole on 4 stands of HWDP to 335'and shallow tested MWD,all good,continue to run in hole with HWDP to 634'.,Trip in hole with whip stock and window mill assembly on CDS40 drill pipe from 634'3000',at 50-60'per minute.,K-06RD2 wellhead pressures:24"=45 psi,13 3/8"=0 psi,9 5/8"= 0 psi,Tbg=0 psi Daily Code 8:Today= 0 Total: 74.5. 12/17/2016 Continue trip in hole with whipstock and window mill assembly on CDS40 drill pipe from 3000'to 7968',at 50-60'per minute.,Kelly up fill pipe break circulation establish parameters and tool face,UW 132K, DW 79K,360 GPM,850 PSI. Wash down from 7968',position tool face at 46R,slack off and started taking weight at 8084'DPM set down 20K weight,had good indication of anchor set. Shut down pump,and pull 10K over string weight,to verify anchor set,set down 30K to shear bolt attaching window mill to whipstock.,Pick up and pull out of hole rack back 3 stands with 6K loss in string weight.NOTE:Top of whipstock at 8062.72',orientated at 46 right of high side and INC 42 degrees.,Blow down circulating lines.,Make up test plug on CDS40 drill pipe,drain stack, and set test plug.,Make up test joint to include all floor valves,cross overs,and pump in sub.,Function test BOPE and work air out of system.,BOPE test:Test #1 Annular on 4 1/2"pipe,dart valve,Demco/kill,CMV 7,14,15,16,250-2500 PSI. Test#2 Upper VBR on 4 1/2"pipe,dart valve, Demco/kill,CMV 7,14,15,16,250-3500 PSI. Test#3 Upper VBR on 4 1/2"pipe,FOSV,outside kill,CMV 4,5,6,11,250-3500 PSI. Test#4 Upper VBR on 4 1/2"pipe,FOSV, hydraulic IBOP,inside kill,CMV 3,10,13,250-3500 PSI.,Test#5 Upper VBR on 4 1/2"pipe,FOSV,inside kill,CMV 2,9,12,250-3500 PSI. Had a fail/pass due to a leaking grease fitting on CMV 14 tighten and retest,on test 6. Test#6 Upper VBR on 4 1/2"pipe,FOSV,inside kill,CMV 2,9,12,250-3500 PSI. Test #7 Upper VBR on 4 1/2"pipe,FOSV,inside kill,CMV 1,8,manual IBOP,250-3500 PSI. Test#8 Upper VBR on 4 1/2"pipe,FOSV,inside kill, HCR/choke, 250-3500 PSI.,Test#9 Upper VBR on 4 1/2"pipe, FOSV,inside kill,manual/choke,250-3500 PSI. Test#10 Lower VBR on 4 1/2"pipe,FOSV,250-3500 PSI. Test#11 Blind rams,inside kill,CMV 1,12,8,250-3500 PSI. Test#12 Hydraulic choke function pressured up to 1500 PSI held 5 minutes,bled pressure to 900 PSI held for 5 minutes.,Test#13 manual choke function pressured up to 1500 PSI held 5 minutes,bled pressure to 1200 PSI held for 5 minutes.,Perform accumulator drawdown test: Starting pressures,Manifold=1550 PSI,Accumulator=3040 PSI, Drawdown pressures,Manifold=1500,Accumulator=1650 PSI. 200 PSI recovery=19 seconds,Full recovery 3040 PSI=96 seconds,4-N2 bottles=2500 PSI average.,Break down and lay down test joint,cross overs and floor valves.,Close blind rams,pull rotary table,disconnect hole fill/jet line,remove flow line and pull flow box,weld splash guards on flow box,reposition lifting d-rings, clean around drip pan,rotary beams and rotary table. Silicone and install new rubber seals on top of rotary beams,flow box and floor plates then installed rotary table. Connect fill lines,and flow lines coming off flow box,seal and install floor plate.,Set and install rotary table mats,and install drill pipe elevators.,Screw landing joint into test plug,and pull to rotary,break off landing joint and test plug laying test plug down,BOP test witness waived by Jim Regg.,K-06RD2 wellhead pressures:24"=45 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today= 0 Total: 74.5. • . 12/18/2016 After pulling test plug,flood BOP and test air boot on riser and flow line,run in hole to 8049'.,Rig repair,adjust HPU's troubleshooting mud pump#1 SPM variation.,Establish drilling parameters in water for comparison when changed over to OBM, UW 134K,DW 79K,with#1 mud pump on 285 GPM rate,300 PSI,UW 130K,DW 82K ROT 101K,TQ 7500©66 RPM.,Pre job safety meeting with all personnel involved in displacement. Pump 19 BBL OBM spacer, begin displacement of FIW to 9 PPG OBM,taking returns to active system using pump#2. Pump FIW returns to TBPF via pipeline with pump#1 at 4 BPM rate,total pump 580 BBL. Minimal interface when displacement completed.,Clean pits,rig down hose from mud pump#1 to production pipe line,remove pancake bind from suction line of mud pumps,work on HPU changing out sequence valve and adjust same,transfer OBM from ISO tanks to active and upright tanks on deck,set drilling torque on top drive to 16K,service drawworks,top drive,and blocks,change out liner wash fluid from water to base oil.,Establish drilling parameters with OBM, UW 116K, DW 87K,with#1 mud pump on 285 GPM rate,2710 PSI,UW 117K,DW 90K ROT 98K,TQ 5500 @ k 58RPM.,Wash down and tag top of whipstock at 8062'.begin milling window at 450 GPM,2200 PSI,90 RPM,6-8K TQ to 8074'.,Mill window with Baker window mill,from 8074'to 8079'+20'to 8099'at 420 GPM, 1830 PSI,6-8 TQ.,K-06RD2 wellhead pressures:24"=45 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg =0 psi _ Daily Cnda R.Tndav= 1 Tntal• 75 5 12/19/2016 Continue to mill rat hole from 8099'to 8103' UW123, DW84K, ROT100K pumping at 420 GPM. 1800 PSI,90 RPM,7500 TQ. drilled enough rat hole to ensure a minimum of 5"of gauge hole. Drifted window with mills,had pumps on and off and did not see anything.,Circulate and condition mud for FIT, ensuring even mud weight @ 8.9 PPG,and recovered 274#of a calculated 321#of steel from milling casing.,Rig up for FIT test,pump 4.8 BBLS total at.5 BPM to 1208 PSI with 8.9 PPG mud in hole and a TVD of 6354',recorded data points at 10 seconds,and 1 minute readings for 10 minutes to 1128PSI. Bled pressure off with 4.1 bbls bled back. For more information see FIT sheet in O-Drive.,Rig Repair Code 8:Check and trouble shoot HPU motors.,Service rig, grease crown,and top drive,check and add oil to top drive,and check draw works bolts. Kuukpik mechanic working with ART and Tesco on HPU issues while �J monitoring well(well static).,Pump dry job and blow down lines,lay down space out pup and working single. Trip out of hole racking back CDS40 drill pipe JJ�+ from 8048'to 4474'. Had draw works motor failure,the 3rd gear motor on the drillers side failed while coming down empty in 5th gear motor located on the off drillers side. Secured well and monitor same.,Rig repair Code 8: Clean up hydraulic oil off rig floor,wind walls,and off of dog house,while changing out 3rd gear hydraulic motor on off drillers side of draw works.,Trip out of hole from 4474'to BHA at 634' rack back HWDP,lay down MWD,break out and lay down window milling assembly,checking mills with gauge ring,upper mill in gauge.,Clean and clear rig floor,make up running tool cross over and 1 stand of drill pipe.,Prepare to pick BHA#4,staging tools at rig floor.,Change over to drilling AFE at 0:00 HRS,K-06RD2 wellhead pressures:24"=45 psi, 13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today= 3 Total: 78.5. S • Hilcorp Energy Company Composite Report Well Name: MRF K-06RD2 Field: County/State: ,Alaska (LAT/LONG): ?vation(RKB): API#: Spud Date: Job Name: 1613025 K-06RD2 Drilling Contractor AFE#: 1613025D AFE$: $4,680,554 Activity.,0ats ;;.Sum�ra ::�::::...:,..::................::::.:..:.::c 12/1/2016 Install seismic clamps,landings,stand for catwalk,catwalk,landings and stairs.[Assist production with getting flow line into wellhead room,hydro tested,and installed];Dig out extra handrails,cut off a couple handrail pockets so landing would fit.Set stairs,put up handrails.Cut section of flowline to length.Modify and install handrails.Move cuttings boxes and;set drilling line spool in place.Set vac unit in place. Put up temp support for electrical lines.;Continue installing misc. handrails and assist welder with project.Install flow line and dresser sleeves.Set vac unit and R/U same.Begin plumbing lite water. Install support for flow line.;Support panic line.Install service loop support saddle.Hook up shock hose in sub.Prepare shakers for welding work.;Finish plumbing and pressure testing lite water system.Continue with handrail project. Begin chinking substructure.;K-06RD2 wellhead pressures:24"=41 psi,13 3/8"=75 psi,9 5/8"=35 psi,Tbg =10 psi Daily Code 8: 0.5 Total: 68.5 12/2/2016 Starting to work on rig shutdown projects.Assist Tesco and ART hand to trouble shoot issues with the drwks and the topdrive.Found bad bearing on drillers side of drwks trans.Get bearings and seals;coming.Remove Kelly hose and lay do for inspection and test.Remove drk camera and bring down.Adjust link tilt on TD bails.Remove clamps on standpipe.Remove suction rubbers in pit 4,5,&6.;Install padeys for picking storm clamps.Trouble shoot boiler#2.Plumb air line in mud pump room.;Pull stand pipe down out of derrick.Weld up ditch in mud pits.Prep standpipe to be UT inspected. Hang blocks and remove drlg line from drum.Prep for drwks motor and trans removal.Cut section;of suction line out of pits where it was leaking.Found that the pipe was still good but it had a section welded in and it was leaking at the weld.Tesco hand and ART hand working on checking out the;hyd pumps to see if they are weak and need replaced.;Route ODS tugger in derrick.Remove DW landing.Continue wire wheeling stand pipe.Continue welding work in pits.Continue inspecting HPU#1. Install drum support.Tag and remove hydraulic;lines from motors.Remove DS and ODS motors. Remove DS gear box.Clean and organize work areas.C/O main suction line pit#5.;Install ODS drawworks motor and hydraulic hoses.Torque to specs.Prepare stand pipe for UT inspection.Remove DS derrick light. Install suction valve bars in pits 4,5,and 6.Continue chinking;sub base. Remove existing M/U tong ram and replace with new.Begin changing out pulsation dampener bladders.;K-06RD2 wellhead pressures:24"=42 psi,13 3/8"=74 psi,9 5/8"=35 psi,Tbg=10 psi Daily Code 8:Today= 24 Total: 92.5 12/3/2016 Working on shutdown issues.Trouble shoot HPU#1 .RD make up ram and remove from the derrick.Attempt to mount new ram but the top pad eye is welded on 90 degrees off. Pull back dn.;Clean up inside of pulsation dampeners and inspect.They look good.Pull centrifugal pump suction's apart and clean out.Also check butterfly valves.Mech going over#1 HPU motor repairing oil leaks.;Got 1 more Tesco hand and 2 more welders on chopper at about 1000 hrs.Tesco hand pulling down drwks gear box.;Found more issues in the gearbox.The bearing race had spun on the housings scaring both housings.Sent both housings into a machine shop to get dressed.Second Tesco hand working on the electrical;with the rig electrician.Checked out the service loop and started wiring in the pigtail on the TD.ART hand working on the hyd pumps,troubleshooting and working on plan to mount pulsation;dampeners on hyd unit charge pump side.Cut expanded metal for handrails.Seal around shakers.;Tesco housings came back on chopper. Both Tesco hands and mechanics started putting the gear box back together.;Change out suction valve.Assist Tesco.Weld splash guard on shakers.Assist welder on rig floor projects. Remove M/U ram and fab new pad eye.Continue work on gear box. Drain oil in#1 MP;gear end.Install gear box.Install DS motor. Build bracket for HPU pulsation dampeners.Reinstall M/U ram.Patch suction in pit#4.Install hoses on gear box.General housekeeping.;Changing out pulsation dampener bladders in both mud pumps.Connect hydraulic hoses to DW motor.Continue insulating sub base.General housekeeping and organization.;K-06RD2 wellhead pressures:24"=42 psi, 13 3/8"=72 psi,9 5/8"=36 psi,Tbg=10 psi Daily Code 8:Today= 24 Total: 92.5 Daily cost spread sheet is attached. 12/4/2016 Continue Working on rig shutdown issues. Had to remove the drwks hyd motor and install a shim.Put motor back on and re-torque.Still working on wiring the pigtail on the TD.Welding hopper;line extension to#4 pit.Clean out pulsation bladder on#2 mud pump and install new bladder.Mount Dampeners on hyd charge pumps.;Plumb in dampeners on hyd pumps and mount dampener on#1 mud pump.Continue welding hopper line in the pits.Install landing on drwks. Modify gate between shakers.Start up HPU#1 and check for leaks.;Found issue w/lebus groove on drwks drum.Contacting Tesco about how to address problems.Getting welding procedure for where lebus groove contacts side of drum.;Have meeting with Tesco,ART,toolpushers,mechanics and electricians about forward plan.;Continue hopper discharge piping project. Finish torque DW bolts.Test pull new M/U ram and install adapter.Weld DW landing step.Tie in hydraulic hoses to HPU dampener.Check for leaks.;Assist welders fabricating hopper discharge line. Prime and paint welded areas in pits.Offload/backload work boat. Prepare DW drum for inspection.General housekeeping.;;K-06RD2 wellhead pressures:24"=40 psi, 13 3/8"=70 psi,9 5/8"=39 psi,Tbg=8 psi Daily Code 8:Today= 0 Total: 92.5 Daily cost spread sheet is attached. 12/5/2016 Working on rig shutdown projects.Heat standpipe and paint.Trouble shoot TD control panel.Trouble shoot and adjust all the regulators for the hyd pumps. install suction rubbers and fill pit#4 w/30;For testing.Adjust cold climate control on TD.RU to circ#1 pump back to pit#4 through choke on bleeder.Test pump at different pressures and rates.Still need to test with both hyd pumps on.;Finish installing pigtail on TD. Function test robotics on TD.Pull test make up ram w/a straight pull.Max pull was 8400 foot lbs.should be good to MU DP.Welders are still working on hopper line;in pit#5 going to#4.;Finish DW drum welding project.Fab stairs for auger access.Weld on vise mounts.Continue hopper discharge project.Mount guide rail for float in trip tank.Install drill line into drum.;Unhang blocks.Mount camera in shaker area.Weld handrail pocket at water tank landing.;lnstall standpipe,manifold and Kelly hose.Offload work boat. Welder install bridge over centrifuge trough.Set Jet heater on'white iron'for heating cellar.;K-06RD2 wellhead pressures:24"=40 psi, 13 3/8"=72 psi,9 5/8" =0 psi,Tbg=5 psi Daily Code 8:Today= 0 Total: 92.5 Daily cost spread sheet is attached. • • 12/6/2016 Continue rig maint.Install derrick lights.Assist welders working on hopper discharge line.Change out pony rod seal on#2 mud pump.Install shut down switch in doghouse for jet heater.Tesco and;ART running tests on Drwks,TD,and mud pump#1. Seal lower sub with plywood and insulation.;Remove TD flow meter and reverse correctly.Continue with hopper discharge modification.Continue with cellar insulating.Modify centrifuge trough stairs.Tesco troubleshooting electrical issues.;Install and bolt on DW landings.Route new TD electrical cable and test.Reinstall pig tail to top drive.;Continue hopper discharge modification. Fabricate equalizer winch bracket and install.Fab cellar light bracket and install.Remove bales.Change out grabber dies.Adjust set and maximum torque on TD.;Inspect flow rate while rotating in different RPM and modes.Run 1st-5th gears on DW and adjust flow control. Remove service loop sock.Remove 37 pin signal cable.;Cover service loop with tarp.Secure TD cable in derrick.Secure torque tube guide and remove extend arms.Lower guide rail and remove Teflon blocks. Finish hopper discharge modification.Erect;scaffold in cellar for access to BOP.;K-06RD2 wellhead pressures:24"=40 psi,13 3/8"=0 psi,9 5/8"=5 psi,Tbg=0 psi Daily Code 8:Today= 0 Total: 92.5 Daily cost spread sheet is attached. 12/7/2016 Continue rig Maintenance,Assist 3rd party Tesco, ART and welders install new bushings on extend arms rams on torque tube.Cut out new Teflon guides for rail and install same and reassemble.;finish bolting pit piping clean pits and paint weld work in same.Assist Weatherford hand w/chg/out of all hinge seals of DBL gate.continue and finish testing of service loop elect;(elect service loop deemed bad)chase replacements parts.Shim TDS plumb and true and r/up HP lines and prep for load test. Continue pit clean and paint/weld work in pits;Remove TD bushing shims and wipe down top drive.Level top drive.Cut grating for valve handles in pits.Mount cellar light.Assist Weatherford with replacing door hinge seals on double gate.Torque;and wire tie TD bolts.Rig up shock hose to choke manifold.Check top drive shaft end play.;Load test mud pumps through choke.Repair miscellaneous leaks.Change out air boot on flow trough. Function test DW's in different gears while rotating and inspecting hydraulics.Discovered leak on;DS DW's gear box.Shut down.Hang blocks.Unspool drill line. Install new kick plates.Prepare to pull gear box.;Finish welding kick on DW drum. Pull gear box and move to mechanic shop.Tesco replace rolled seal on gear box and reinstall.Change suction rubbers to Viton in pits.General housekeeping.;K-06RD2 wellhead pressures:24"=40 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg= 0 psi Daily Code 8:Today= 0 Total: 92.5 Daily cost spread sheet is attached. 12/8/2016 Continue rig repair.Continue securing DS gear box on dwks repair leaks on sight glass and vent.add oil and service same.clean work area.Test run same (ok)reinstall line on drum and work block;in all five gears observing drlg line kickers and spooling line on drum DS kicker appears to be doing good job OSS kickers a lot better but might need to adjust kicker.;Continue installing safety clamps on Hyd lines. Assist Pacific power w/servicing HPU prime movers both tested good.Assist A.R.T.with install of pulsation dampers on HPU's;house cleaning through out rig.Transfer FIW back into suction pit and resume load testing.;Tesco finish load testing and fine tuning with mud pumps,TD and DW's and HPU's.Test choke.Blow down mud lines.Sample oil from TD gear box and change oil in same as well as swivel.;Begin changing out saver sub.;Change over to Pre-drill AFE at midnight.;K-06RD2 wellhead pressures:24"=40 psi, 13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today= 0 Total: 92.5 Daily cost spread sheet is attached 12/19/2016 Changed over from predrill AFE drilling AFE at midnight.;Set wear ring,run in 4 lock down screws,break wear ring running/retrieving tool and cross over off, rack back stand.;Pre job safety meeting make up 8.5"directional BHA. Picked up bit and motor float sub,DM collar,DGR/EWR collar and started to enter top of 53#casing,had to work it to get it to start in.;With the bit and motor inside of 53#casing,we could see drag as we slacked off. Plugged into the TM HOC and attempted to upload,could not get good data acquisition due to tools being cold.;Tarped tools and put steam on them to warm them up.;K-06RD2 wellhead V presDailysures:Code 248"=Today 45 psi,3 13Total:3/8"=0878.5.psi,9 5/8"=0 psi,Tbg=0 psi = Steel recovered 285# 12/20/2016 Continue make up BHA#4, (Note:First 8-1/2"directional drilling assembly)to 740'.;Run in hole with CDS40 drill pipe out of derrick from 740'to 2750'with new driller shadowing,6 AM to 6 PM catching both crews.;Fill pipe break circulation and test tools(OK)blow down top drive and lines.;Continue run in hole h from 2750'to 5850',fill pipe break circulation and warm mud. Laid down joint with bad tool face on the top of stand#82,blow down top drive and Y Iines.;Continue to run in hole from 5850'to 8022',pick up a single and run in hole to 8053',fill pipe and establish parameters, UW120K,DW89K.;Attempt to make a connection and grabber dies failed,inspected saver sub,and it was damaged,changed out saver sub and grabber dies.;Made a connection and broke circulation,orientated bit towards window. Shut down pump and run in hole from 8053'through top of window at 8062',seen 2K extra down weight on slide (OK)and exited;the window at 8079'with no issues,tagged bottom of the gauged hole at 8085'(OK).;Establish drilling rate and slide drilled,to clean out under gauge hole from 8085'to 8103',continued to slide to 8107',begin to pack off,shut down pump,and bled off pressure.;Lost all pipe movement but still had bumper sub travel and was able to regain 1/2 BPM circulation with out packing off,work pipe up and down staging up to 75K over straight pulls,and setting n. down;50K,had intermittent pipe movement we regained rotation and staged up circulating rate to 100 GPM.;Regained rotation with 38 RPM and torque at 11K, 0 pumping at 100 GPM,staged pumps up to 133 GPM,torque began to climb above 14K and we started to pack off,shut down rotary and turned;pumps off, ke reestablished circulation and rotation staging up to 166 GPM.with rotation and circulation picked up monitoring torque and pressure,was able to work up to 3"‘ 8093'.;Engaged rotary and was able to get up to 65RPM and 270 GPM,shut down rotary and orientated tool face to window.;Straight pulled up to 8090' continued working pipe varying parameters to 8078'. Continued to work pipe staging up to 270K 150K over pull,steadily making hole.;Note:whenever we slacked off and broke over there was free pipe movement. With Pason showing a bit depth of 8035'pulled up to 270K, 150K over,and pipe came free,picked up 5',and had free pipe;movement at 124K up weight,racked back a stand and picked up a working single,brought pump up to 270 GPM with 1200 PSI and was able to get an MWD signal this correlates with what we had earlier.;Dropped back down to tool joint to verify bit,depth changed from 8035'to 8053'while setting bit depth noticed reactive torque turning drill pipe,set down 1K more and motor stalled,killed;pumps,and picked up took 20K over to pop loose. Set down 5K with no pump,and picked up took 10K over to come loose.;Circulate bottoms up at 270 GPM reciprocating pipe,at bottoms up had some metal and sand come across shakers.;Laid down working single and racked back a stand,monitor well for flow,while performing derrick inspection.;Pump dry job and trip out of hole with directional BHA from 7984 to 3300'.;K-06RD2 wellhead pressures:24"=45 psi, 13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today= 0 Total: 78.5. Steel recovered 285# • • 12/21/2016 Trip out of hole from 3200'to 2089',and pipe started pulling wet.;Floor began leaking through and around the flow box,cleaned up stack and installed tarp to catch the leaking OBM.;Continue to trip out of hole to BHA.;Stand back HWDP and lay down jars.;Lay down flex collars,had to shut down and clean floor due to mud spraying on floor from tarp that was wrapped around collars.;Down loaded LWD tools and finished laying down BHA. Bit had chipped cutters on shoulder and gauge,nose cutters were good, Bit grade 0-6-BT-T-X-I-LM-HP;Tools were scarred from just above the motor kick pad to the top of the DM collar, approximately 40'.;Clean and organize rig floor,mount derrick camera on drillers side wind wall,while waiting on tools coming on boat.;Pick up BHA#5,8 1/2" mill tooth bit(RR grade 2-2-NO-A-1-I-RR), (2)boot baskets,bit sub,string mill,string magnet,bumper sub,oil jars,cross over,and 18 joints of CDS40 HWDP.;Run in hole to 2772',with cleanout assembly,and fill pipe.;Perform rig service,;Trip in hole with cleanout assembly,from 2772,to 8035,filling pipe every 2700';Cut and slip drilling line,circulate and condition mud to warm and shear prior to cleaning obstruction at 8035';Establish parameters,work down to 8053'and found obstruction,cleaned it up with 2-4K WOB,500 GPM,60 RPM,2000 PSI SPP,monitoring torque that ran from 5-12K. The obstruction cleaned up at 8057';Worked down past obstruction and wiped several times to ensure clean with pumps on with rotation and without rotation,continued to work down to top of window with free travel,continued through;window,to BOW 8079 had what appeared to be some fill here,washed and rotated through with no issues,picked back up and wiped entire window,stuck bit out side of window and cleaned out to 8107';Mud loggers took sample of returns what appeared to be sand was more mud product with some sand and minimal metal cuttings.;K-06RD2 wellhead pressures:24"=45 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today= 0 Total: 78.5. Steel recovered 285# 12/22/2016 Drill from 8107'to 8117',500 GPM,2050 PSI,60 RPM,5-7K TO,10K WOB.initially tagged bottom,and it appeared to be junk,then it cleaned up after the first 6".;Work back up to top of window several times with and without pump,had 6'of fill on bottom we had to clean out,with small amount of sandstone, shale,and a trace of metal coming over shakers.;Pump high viscosity sweep,with no increase at shakers. we were able to recover about 1 lb of metal on the magnets.;Pump slug and blow down top drive and mud lines.;Trip out of hole to HWDP,with proper hole fill.;Stand back HWDP,pull up to magnet and clean same,recovered 90 lbs metal from magnet,check boot baskets,they appeared to be full but didn't have anything hanging out of them.;Laid down all the clean out BHA.Cleaned out boot baskets and recovered 15 lbs metal and 35 lbs of coal and shale.;Clean and clear rig floor.Monitor well,hole static.;Service rig.;PJSM,pick up BHA#6,make up bit and motor float sub and DM collar,scribe motor to DM collar.make up LWD tools and upload to HOC,make up flex collars, HWPD,jars,and remainder of HWD.;Install light at derrick board.;Trip in hole with 8.5"directional BHA from 740'to 2924'fill pipe and attempt to test MWD.;Continue to try and establish a pulse signal with no luck.;Mix and pump a slug to dry pipe and trip out of hole for MWD pulser failure,trip out of hole to HWDP.;K-06RD2 wellhead pressures:24"=45 psi, 13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today= 1 Total: 79.5 Steel recovered 398.5# 12/23/2016 Stand back HWDP,jars,and flex collars,download tools,and troubleshoot pulser.;Lay down TM collar,PWD/HCIM collar,and pick up new PWD/HCIM and TM collars,upload to HOC.;Rack back stand with smart tools,pull motor and break bit,and place motor in mouse hole. Latch up stand with smart tools and run it in the hole,make up top drive and test tools.(All Good);Rack back stand with smart tools,pick up motor and make up bit,latch onto stand with smart tools and make up to motor.;Continue to run in hole with BHA#7 to 2600',fill pipe and check MWD signal.(All good).;Continue to run in the hole with 8.5" directional assembly to 5639',filled pipe and had a MWD signal.;Continue to run in the hole with 8.5"directional assembly to 8046 fill pipe,orientate bit towards window,and get parameters,pumps off UW120K,DW,79K, Pumps on 400 GPM 2471 PSI,UW 115K, DW 79K.;Rig service,service top drive,crown and draw works.;Rig repair Installed jumper on mud pump PLC,replaced relief valves on HPU,continue to trouble shoot pump stroke variances.;Trip in hole to 8062'top of window trip though window,had 2K drag going through window,kicked pumps on with bit out of window at 8082'and washed down and tagged up at 8117'.;Establish parameters and slide drill from 8117'to 8126'2-4 WOB 425 GPM,3020 PSI.;Continue sliding per directional plan,from 8126'to 8145' began to pack off and get sticky reduced pump rate to 200 GPM,and worked pipe to 40K over and worked free,continue drilling ahead to 8260'.;425 GPM, 2800PSI,150 DIF,2-5 WOB.;K-06RD2 wellhead pressures:24"=45 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today 1 = Total: 80.5 Steel recovered 398.5# 12/24/2016 Directional drill 8 1/2"hole from 8260'to 8526'ROP 65,TO 7-11K,GPM 415,2725 PSI,WOB 6-8K.sliding at 411 GPM,WOB 6-87K UW 134K,DW 80K, ROT 100K,gas average 17 units,91 units high.;Swab failed on#1 mud pump,replaced swab and primed pump. Circulated with pump#2 and reciprocated pipe while repairing pump#1.;Directional drill 8 1/2"hole from 8526'to 8648'.;Pick up to 8645',shut down rotary,attempt to work pipe for a slide,pulled 30k over,attempted to slack off and pipe wouldn't go down. Engaged rotary pipe came free with 13K torque,;worked pipe up 45'and continued to work pipe until parameters were normal. UW 140K, DW 80K,ROT 100K. Pumped a 20 BBL 465 viscosity sweep.;Drill from 8648'to 8668'while sweep was going down the pipe,had 500 PSI increase when sweep went through BHA.;Circulate out sweep with 445 GPM,2900 PSI,52 RPM, 10K TO,had a few thin plates of coal up to 1"X 1",(caving's)seen very little increase in cuttings with return of sweep.;Directional drill 8 1/2"hole from 8668'to 8834,425 GPM,2750 PSI,UW 140K, DW 80K,ROT 102K,when rotating 60RPM,TQ 10K,WOB 5-10K;Directional drill from 8834'to 8920',was having some issues holding tool face and transferring weight while sliding.;Pump 20 BBL high viscosity sweep at 430 GPM,2720 PSI,reciprocating pipe.;K-06RD2 wellhead pressures:24"=45 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today 1 = Total: 80.5 Steel recovered 413.5#;Last survey SD 8876.08, INC113.01,123.33,TVD7041.03 Distance to plan 24.73',8.1'high 23.36 Left 12/25/2016 Continue pumping sweep,had s 25%increase in cuttings with more thin coal caving's,436 GPM,2715 PSI,60 RPM,8550 TQ.[We think caving's are coming from just below window];Pull out of hole 6 stds from 8920to 8536',pulling wet,pump a slug to dry pipe.;Continue to pull out of hole from 8536'to above window at 8035',20K overpulls at 8770',8483',and 8274',mad up top drive and backream through tight spot at 8206'to 8197'.;Observed a 15K over pulls coming into the window.;Service rig,draw works,top drive,blocks,hydraulic pumps,and inspect drilling Iine.;Trip in hole picking up 20 joints of CDS40 drill pipe,continue to trip in hole to 8857'.;Wash and ream to bottom from 8857'to 8920',had 10'of fill.;Directional drill 8 1/2 hole from 8920'to 9025',having issues with holding tool face and weight transfer to bit. (Possible cuttings issue due to all the time with no rotation).;Pump 22 bbl high viscosity sweep,ROT 70 RPM,450 GPM, 2900 PSI,had a 10%increase in cuttings.(#1 hyd pump went down due to alternator failure.put charger on battery for temporary fix).;Directional drill 8 1/2" hole from 9025'to 9097,varied parameters to try and achieve optimum performance from tools,350-450 GPM,1925-2675 PSI,(Mostly sliding).;Directional drill 8 1/2"hole from 9097'to 9141',419 GPM,2655 PSI(All sliding).;Directional drill 8 1/2"hole from 9141'to 9169',425 GPM,2734 PSI(All sliding).;Lost hydraulics to rig,mud pump#1 shut down,lost draw works,found HPU#2 on fire,extinguished fire,contained hydraulic oil and cleaned up same. Bit is on bottom,currently;circulating with#2(electric)mud pump while attempting to start HPU#1. Started HPU#1 and was able to move pipe,break off stand and stand back same,circulate bottoms up at 300 GPM.;K-06RD2 wellhead pressures:24"=45 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today 1.5= Total: 82.0 Steel recovered 431.0#;Last survey SD 9062.28,INC9.4,AZM 129.35,TVD 7223.54 Distance to plan 63.46',48.59'high 40.82 Left • • 12/26/2016 Circulate 20 BBL high vis sweep around,while cleaning area around#2 HPU,due to fire caused by HPU pump failure. There was no increase in cuttings observed,with sweep returns.;Pump dry job and pull out of hole to window,observed(1)25k overpull at 8180'. Worked through it with no issues.;Monitor well on trip tank,well static.Evaluate damage to HPU,work on rig projects,hang lights in the derrick,pull down camera and prep it to be moved up higher in the derrick,;clean up HPU,and move cutting from 13 BBL cuttings tank to 15 BBL tank.;Monitor well on trip tank,well static.Evaluate damage to HPU,continue to work on rig projects.;Monitor well on trip tank,well static. Evaluate damage to HPU,clean HPU engine and electronics,begin prepping areas where paint was burnt,;electrician wiring camera for installation above board,continue to work on rig projects,clean and organize pump room.:K-06RD2 wellhead pressures:24" =45 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:24,Total:106.0 Steel recovered 431.0#;Last survey SD 9126, INC7.09,AZM 150.18,TVD 7286 Distance to plan 76.52',68.31'Low 34.48 Left 12/27/2016 Replace burnt hoses on HPU2,Continue cleaning HPU room. Pull mat off rotary and clean up rig floor around rotary. Plug holes around rotary. Pump oil out of cuttings box and put it in bbls.;Continue cleaning and replacing hoses and wires in HPU.Have well shut in monitoring well on choke.;Continue cleaning and replacing hoses and wires in HPU. Install new pump on hydraulic pump unit.;Continue with rewiring project on HPU#2.Continue with cleaning up HPU room and housekeeping throughout rig.Tesco and ART techs arrived on platform at 0315 hrs to assist with HPU repairs.;K-06RD2 wellhead pressures:24"=45 psi, 13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:24,Total:104.5 Steel recovered 438.0# 12/28/2016 Working on HPU 2 replacing burnt wiring and hoses.Tesco and ART hand evaluating damage to electrical components.Replace burnt gauges w/digital gauge ports.;Open choke,Open pipe rams,Remove TIW valve,Lineup on trip tank,and get HPU#1 on line.;POH 4 stds and wrap on the#1 HPU exhaust started smoking.Remove wrap.;Continue POH standing back DP w/directional drilling assem.Stand back HWDP.;Lay dn NM DC.Download MWD and lay down same.LID float sub,mud motor and bit. Bit grade:l,2,3,5,R,BT with one plugged center jet.Bit photos are in well file.;Retrieve wear bushing.Tesco and ART technicians went to bed at 2300 hours.;Continue with rewiring HPU#2 and repairs on same.Clean from rig floor down to living quarters.;K-06RD2 wellhead pressures:24"=43 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:24,Total:128.5 Steel recovered 438.0# 12/29/2016 Repairing HPU#2.Continue replacing burnt electrical wires.Drain filters on HPU and found the they were full of metal debris.Filter oil from hyd tank into clean drums.Install new filters in;hyd unit.Tesco and ART hands continue repairs on hyd unit.Change out drwks filters.Mount camera in shaker room.;Clean HPU hyd tank and clean screen in same,Mech still changing out filters and Tesco and ART hands working on replacing wiring.Painting suctions in pump room. Check well and its static.;Finish changing out filters.Continue with rewiring.Transfer hydraulic fluid from drums to tank. Plump in auxiliary to HPU1.Purge air. Repair miscellaneous Ieaks.;Continue replacing electrical in HPU.Flush and drain filters.Cleaning and painting projects around rig.R/U to flush drawworks and top drive hydraulic Iines.;K-06RD2 wellhead pressures:24"=45 psi, 13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:24,Total:152.5 Steel recovered 438.0#;Estimate that repairs are+-70%complete.Still rewiring modules and waiting on HP hoses being built.Have cleaned hydraulic tanks and filters. Expecting to be operational around 1200 hours on 12-31. 12/30/2016 Working on HPU#2.Continue replacing wiring on HPU.Continue flushing hyd lines to top drive and drwks.;Continue working on electrical on HPU#2.Change out hoses.Assist Tesco and ART hands.Tesco parts and 2"hyd hoses arrived on a chopper at 1530 hrs.Start to install 2"hoses.;Continue working on electrical on HPU#2.Change out hoses.Assist Tesco and ART hands. Begin installing new hydraulic hoses.;Continue with electrical and hose replacement on HPU's.Test drawworks and top drive functions with HPU#1.;Make up test joint.Continue with electrical and hose replacement on HPU's.;K-06RD2 wellhead pressures:24"=45 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:24,Total:176.5 Steel recovered 438.0#;Estimate that repairs are+-80%complete.Continue rewiring modules commissioning. Expecting to be operational hopefully sometime later today,12-31. 12/31/2016 Drain stack and land test plug.[Continue with HPU commissioning project.]Fill stack and choke with water.Work air out.Do a pre-test on the hydril both low and high for 5 min.Good test;Prep for test with state man.Inspector arrived on platform at 8:45.Had PJSM w/inspector and crew.TTest BOPs.Test hydril to X 250 and 2500 psi for 5 min ea,Test all other BOP equip to 250 and 3500 psi for 5 min ea.Tested alarms and PVTs.Perform accumulator test and choke tests. / ) No failures.;Pull test plug and drain water out of stack. Lay dn test equip and secure well.[Got state inspector off of platform on a 14:30 chopper.];Work on \417 l HPUs.loop together Drwks,TD,and aux hyd on rig floor.Purge HPU 2 with aux pump and fix leaks where o-ring had been pinched.Continue assisting Tesco D 5 and ART hands.;Trouble shoot HPU#2 throttle control.Assist Tesco,ART,mechanics and electricians with commissioning issues. Pump out BOP test water I to production. Begin circ loop through top drive.;Circulate hydraulic systems with both HPU's.Drain and clean hydraulic tank.Change out all filters. Refill V hydraulic tank.;K-06RD2 wellhead pressures:24"=45 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:24,Total:200.5 Steel recovered 438.0#;HPU repairs are 99%complete.Total time for repairs=127.5 hours. 1/1/2017 Finish changing out filters and filling HPU tank with new oil.Return filters did have some metal in them.Looking for Throttle Signal Converter to control engine RPM from rig floor.:Found Throttle signal converter at Saxon and rig mech found a couple in town.Had them delivered to OSK heliport.;Got the electrical parts to the platform at 0930.Installed the throttle signal converter and tested the HPUs. Everything tested good.;Rig went off code 8 and went back on reg rig rate at 10:30 hrs.Prep to PU BHA. Hold PJSM.PU and MU Sperry tools.PU float sub,DM, DRG,PWD,and HOC.Plug in and up load.MU TD and test;tools.Got a good signal and good test.Stand back in the derrick and PU the mud motor,MU bit,Scribe to top of motor,PU smart tools and MU.Finish scribe and calculations.RIH PU NM DCs.;RIH with directional drilling assembly BHA#8 to 8008'filling pipe every 2500'.;Attempt to orient to go through window without success.Service rig.;RIH to 8260'without issue to get below the coal at window exit.Circulate and condition mud at 340 GPM/1850 psi.;RIH on elevators without issue to 9071';Establish parameters:P/U 134 k,S/O 82 K,Rt 106 K at 70 RPM/8 K torque.405 GPM/2450 psi.Wash and ream to 9169'with no fill.;Directional drill 9169'to 9194'with above parameters.;K-06RD2 wellhead pressures:24"=40 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:24,Total:200.5 Steel recovered 438.0#;HPU repairs were completed at 1030 hours for a total of 132 hours NPT. • • 1/2/2017 Directional drill 8 112"hole f/9194'U 9217.Lost a swab in#1 mud pump.;Change swab in#1 mud pump.;Directional drill 8 1/2"hole f!9212'U 9255'.;Attempted to put jumper wire in on HYD pump to smooth out#1 mud pump. Ran into other issues but finally got it straightened out and everything back on line.;Directional drill 8 1/2"hole f/9255'f!9327'.415 GPM,2825 Psi,3 to 11k WOB,60 RPM,9k Tq.;Directional drill 8 1/2"hole f/9327'U 9480',415 GPM, 2600 Psi,5 to 15k.;Pump 24 bbl sweep as a clean up cycle,Sweep came back with a 20%increase in cuttings. Having issues with Sperry depth tracking.;Trouble shoot issues w/Sperry depth tracking and remedy same.;Directional drill 8 1/2"hole from 9480'to 9648'. 415 GPM/2650 psi, P/U 150,S/O 88,RTANT 112.70 RPM @ 9-10K.WOB 7-9K.;Directional drill 8 1/2" hole from 9648'to 9784'. 415 GPM/2650 psi,P/U 150,S/O 88,RTANT 112.70 RPM @ 9-10K.WOB 7-9K.;Change out swab in MP#1;Directional drill 8 1/2"hole from 9784'to 9814'. 415 GPM/2650 psi,P/U 150,S/O 88,RT/WT 112.70 RPM @ 9-10K.WOB 7-9K.;K-06RD2 wellhead pressures:24"=40 psi,13 3/8"=0 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:0.5 Total:201 Steel recovered 446.3#;Last survey MD=9711.56,INC=16.24,AZM=265.61,TVD=7862 Currently 33'High, 119'Right of line,Distance to plan 124.34' 1/3/2017 Directional drill 8 1/2" hole f/9814'U 10,063'. 425 GPM/2850 psi,P/U 160,S/O 88,RT/WT 112,60 RPM,10-11K.TQ,WOB 7-12K.;Directional drill 8 1/2 hole f/10,063'U 10,184'. Pump 25 bbls high vis sweep while drilling down last stand.;Circ sweep around w/40%increase in cuttings and 20 bbls late. Continue circulate clean. Pump up survey.Monitor well w/slight seepage&pump dry job.;POOH from 10,184'to 9075'on elevators without issue.;Service rig and readjust service loop and standpipe valve.;RIH on elevators picking up 34 joints of drill pipe to 10,155'.Wash and ream 10,155'to 10,184'. No fill.;Directional drill 8 1/2" hole 10,184'to 10,470. 425 GPM/2850 psi,P/U 162,S/O 95,RT/WT 119,60 RPM,10-11K.TQ,WOB 7-12K.;K-06RD2 wellhead pressures:24"=48 psi,13 3/8"=10 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:0.5 Total:201 Steel recovered 446.3#;Last survey MD=10331.26,INC=10.17,AZM=286.11,TVD=8460.16 Currently 102'High,36'Left of line,Distance to plan 108.53' 1/4/2017 Directional drill 8 1/2" hole 10,470'to 10,670'. 415 GPM/2920 psi,P/U 162,S/O 95,RT/WT 119,65 RPM,10-12K.TQ,WOB 7-12K.pump 25 bbl high vis sweep around while rotating @ 10480'w/10%;increase. Directional drill 8 1/2" hole 10,670'to 10,750'. 415 GPM/2920 psi,P/U 162,S/O 95, RT/WT 119,65 RPM,10-12K.TQ,WOB 7-12K.;C/out swab#2 CYL on#2 MP while rotating and reciprocating pipe circ w/#1 MP.;Directional drill 8 1/2" hole 10,750'to 10,914'. 415 GPM/2920 psi,P/U 174,S/O 98, RT/WT 98,65 RPM,10-13K.TQ,WOB 7-12K.Hung up at 10,914'. No packing off issues.Work free. Pull up to 220K,;SIack off to RT WT and break free with rotation.;Circulate viscous/nut plug sweep while rotating/reciprocating pipe.Sweep 20 bbls late.No change in cuttings at surface.;Directional drill 8 1/2"hole 10,914'to 11,050'. 415 GPM/2920 psi, P/U 174,S/O 98,RT/WT 98,65 RPM,10-13K.TQ,WOB 7-12K. Hung up at 10,939'. No packing off issues.Work free as before.;Circulate 22 bbls of 10.7 PPG weighted sweep at 420 GPM/2900 psi while rotating and reciprocating pipe.;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=10 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:0 Total:201 Steel recovered 446.3#;Last survey MD=10,949.66,INC=19.12,AZM=351.14,TVD=9060.98 Currently 29'Low,34'Left of line. Distance to plan 45'. 1/5/2017 Had 50%increase @+-100 bbls late from weight sweep.Continue circ clean X 2 btm up while rotating and reciprocating pipe @ 425 gpm @ 3000 psi @ 60 rpm and 11 kTQ.Monitor well and pump dry job.;Pooh on elevators f/11050'U 10183'w/no issues.Start C/out swab on#1 MP#2 CYL.;C/out Swab and liner MP#1, (#2 CYL)and work pipe.;Circ dry job out and use it as weighted sweep @ 450 gpm @ 2940 psi and 65 rpm w/9.5k and well unloaded w/35% increase©+-20 bbls late&pump dry job.;Pooh f/10,183'U 8039' thru open hole and into window on elevators w/no issues.;Cut and slip 194'drlg line. Check and tighten drawworks bolts.;Continue POOH l/dn 34 jts of drill pipe.Shut down for one hour due to crane offloading work boat.;Continue POOH racking back in derrick. Hole fill 8.2 bbls over.;Download MWD.Work BHA.Bit grade: 1,1,2,SH,CT.Bit was very green.Plan to pick up 1.83 AKO motor.;Pick up MWD tools and pulse test same.;K-06RD2 wellhead pressures:24"=50 psi, 13 3/8"=10 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:0 Total:201 Steel recovered 446.3#;Last survey MD=10,949.66,INC=19.12,AZM=351.14,TVD=9060.98 Currently 29'Low,34'Left of line. Distance to plan 45'. 1/6/2017 Shallow test Bha#9 good blow do lines and rack back same.;P/up new 7"mud mtr and adjust mtr AKO U 1.76 deg M/up RR 8-1/2"bit Rih w/smart tools,flex collars,XO's,2 std HWDP XO and jars from derrick.;Rih f/3-02'U 2160'M/up agitator and shock assy.Continue RIH f/2160'U 2534'. Fill pipe to pressure. Blow down lines and clean rig floor.;Continue RIH f/2534't/6850'.;Service rig change out dies.;P/up 54 jts DP and exit window without issue.Continue RIH on elevators without issue to 9903'installing CBI's every 4th stand.;Circulate and condition mud at 430 GPM/2800 psi.;RIH on elevators from 9903'to 10980' without issue. 2.4 bbls over displacement on trip in hole.;Establish parameters: P/U 168 K,S/O 98 K,RT WT 124 K at 45 RPM/10.2 K torque.420 GPM/2850 psi.Obtain SPR's.Wash and ream 10,980'to 11,050'(2'fill).;Directional drill 8 1/2"hole from 11,050'to 11,107'with above parameters.;Change out middle swab on MP#2.Troubleshoot and resolve HPU issues.;Directional drill 8 1/2"hole from 11,107'to 11,122'with above parameters.;K-06RD2 wellhead pressures:24"=48 psi, 13 3/8"=10 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:0 Total:201 Steel recovered 446.3#;Last survey MD=11,028.85, INC= 21.88,AZM=354.78,TVD=9135.15 Currently 4'High,24'Right of line. Distance to plan 24'. 1/7/2017 Directional drill 8 1/2"hole from 11122'to 11173'.Experiencing interment issue w/HPU#1 dropping off line from PLC;that keeps breaking up slides and troubleshooting same.Up/Dn 178/95k,430 GPM @ 3027 psi.;Directional drill 11,173'to 11,222'.420 GPM/3000 psi, 10 K WOB.HPU continually dropping RPM issues.;Not getting needed mtr outputs to maintain WP07. Circulate bottoms up.Monitor well static,pump dry job.;POOH on elevators without issue into window at 8002'.Able to stand CBI's back.;Pacific Power hand on board and trouble shoot HPU/PLC#1 issue.Found no problems.Change out MP#1 pulsation dampener bladder.;Trip in hole on elevators to 9908'without issue.;Fill pipe and test HPU/PLC by simulating drilling parameters(okay).;RIH on elevators from 9908'to 11,187'without issue.;Establish parameters:178 k P/U,98 K S/O,430 GPM/2900 psi.Wash down to 11,222'.;Directional drill 11,222' to 11,257'with above parameters.;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=10 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:3 Total:204 Steel recovered 446.3#;Last survey MD=11,148.85, INC= 26.68,AZM=355.95,TVD=9244 Currently 7'Low,9'Left of line. Distance to plan 12'. 1/8/2017 Directional drill 11,257'to 11,292'up/dn 178/98 @ 428 gpm @ 3300 psi.;Unplug rod wash on MP#1.Change#3 swab on MP#2 and work pipe.;Rack back one stand.Trouble shoot DWK 3rd gear DS mtr bypassing issue,Monitor well static. Pump dry job.Start POOH. Tesco recommends chg/out ASAP before getting iron in system.;Kelly up.Park pipe @ single high @ 11025'above 39 coal. w/1 bpm circ.Monitor well and chg out dwk mtr w/rebuilt one. Repair and test DWK ok.RIH to 11,292'w/no issues.;Resume directional drill f/11,292'U 11295'in rotary mode U clean up due to weight stacking. Resume slide drlg f/ 11295'to 11,360'.up/dn 178/98 @ 428 gpm @ 3300 psi.;Unable to obtain desired directional output from mud motor assembly.Consult with engineers.;Mix and pump dry job while rotating and reciprocating pipe.;POOH on elevators from 11,360'to inside window at 8008'without issue.Pulled 20K over at 11,030' (only over pull noted).;POOH standing back in derrick from 8008'to 1100'.;POOH laying down excess drill pipe.;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=10 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:7 hrs/Total 211 Steel recovered 463.5#;Last survey MD=11,323.51,INC= 35.83,AZM=357.24,TVD=9394 Currently 25'Low,67'Left of line. Distance to plan 72'. • • 1/9/2017 POOH laying down excess drill pipe.Total of 16 jts and rack back flex collars.;Down load MWD data.;Rack back smart tools,drain motor, break and check bit.Graded 1-1-in gauge.;Clean rig floor.;Cut and slip 86.5'of drill line.;RIH w/smart tools.Upload and shallow hole test same(ok)and rack back same.;P/up 6- 3/4"motor and set AKO©2.12 degrees.;Finish RIH picking up BHA#10 to 3340'.;RIH with BHA#10 from 3340'to 3800'.;Repair HPU#1. Filter by-pass sensor failure.;RIH with BHA#10 from 3800'to 8685'. No issue going through window 8062'to 8079'.;Had valve washout on HPU#2.POOH to 8045'(above window).;Change out washed valve on HPU#2.;RIH with BHA#10 from 8045'to 8685'.;Continue RIH from 8685'to 11,312'on elevators without issue.;K- 06RD2 wellhead pressures:24"=50 psi,13 3/8"=10 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:1.5 hrs/Total 212.5 Steel recovered 463.5#;Last survey MD=11,323.51,INC= 35.83,AZM=357.24,TVD=9394 Currently 25'Low,67'Left of line. Distance to plan 72'. 1/10/2017 Establish parameters,stage up rate precautionary wash and ream from 11,312'to 11,360',no fill encountered.;Resume slide drilling 8-1/2"hole from 11360'to 11406'UW198K,DW110K,ROT124K,420 GPM,3100 PSI,experiencing ineffective weight transfer to bit,with 45K over pulls while picking up;to rotate and clean slides.;Continue slide drill 8-1/2"hole from 11406'to 11477'while orientating tool face experienced a 60K over pull,continued oscillating pipe to help with weight transfer to bit.;Had air boot on flow nipple fail,attempt to air up boot,no joy,pull out of hole wet from 11477'to 11045',land drill string on test plug, change out air boots on flow nipple,pull and laydown;test plug, run in the hole to 11432',Kelly up and precautionary wash and ream to bottom.;Continue slide drill 8-1/2"hole from 11477'to 11484',having trouble transferring weight to bit,blew pop off on#2 mud pump due to motor stall. Looks like motor yield is 11.5 to 12 degrees.;Lost swab on#1 mud pump#1 fluid end,replaced same.;Continue to directional drill 8-1/2"hole from 11484'to 11499'.;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=10 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:2.0 hrs/Total 214.5 Steel recovered 463.5#;Last survey MD=11,456.01,INC= 45.86,AZM=358.16,TVD=9495.12 Currently 46'Low, 123'Left of line. Distance to plan 131.9'. 1/11/2017 Change out swab,liner gasket,and wear plate on#2 mud pump,pod#3,while circulating and working pipe with#1 mud pump.;Continue to directional drill 8- 1/2"hole from 11499'to 11565'with varied parameters,continue to have weight transfer issues while sliding. Pumped a 22 BBL weighted sweep while drilling ahead,;did not get much in additional returns,however we did gain some down weight and lost some up weight.;Continue to directional drill 8-1/2"hole from 11565'to 11590'with varied parameters,continue to have weight transfer issues while sliding. Pumped a 25 BBL weighted sweep with lube;while drilling ahead,sweep was 20 BBL late,and had about a 20%increase in very fine cuttings come back with sweep,it did appear to have better weight transfer to bit, afterwards.;Continue to directional drill 8-1/2"hole from 11590'to 11606' with varied parameters,while oscillating pipe 2-4 rounds. At 11600'picked up to regain tool face had a 65K over pull to come free;K-06RD2 wellhead pressures:24"=50 psi, 13 3/8"=15 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:0.0 hrs/Total 214.5 Steel recovered 465.5#;Last survey MD=11,517.61,INC= 50.38,AZM=0.56,TVD=99536.22 Currently 53.4'Low, 170.4'Left of line. Distance to plan 178.6'. 1/12/2017 Continue to directional drill 8-1/2"hole from 11,606'to 11,637',work weight transfer issue,while oscillating pipe 2-4 rounds.;Lost swab in#1 mud pump,pod #1,circulate with mud pump#2 and work pipe.;Continue to directional drill 8-1/2"hole from 11,637'to 11646'continue work weight transfer issue.;Fuel line failure on HP#1,repair same,while orientating tool face and working to bottom. Rig code 8 was covered under rig service for both tours.;Resume directional drilling 8-1/2"hole from 11646'to 11,667'.;Lost swab in#1 mud pump,pod#3,circulate with mud pump#2 and work pipe.;Resume directional drilling 8-1/2" hole from 11,667'to 11674',work weight transfer issue,while oscillating pipe 2-4 rounds.;Lost swab in#2 mud pump,pod#1,circulate with mud pump#1 and work pipe.;Resume directional drilling 8-1/2"hole from 11674'to 11692',work weight transfer issue,while oscillating pipe 2-4 rounds,pumped a 20 BBL 11.2 PPG weighted sweep around with 20 PPB nut plug and;a drum of lube while drilling ahead. Sweep back 15 BBL late had 100%increase in cuttings,fine sand and coals,and lost 6K UW,and gained 5K DW.;Continue directional drilling 8-1/2"hole from 11692'to 11733',work weight transfer issue,while oscillating pipe 2-4 rounds.;Lost swab in#2 mud pump,pod#2,circulate with mud pump#1 and work pipe.;Continue directional drilling 8-1/2"hole from 11733'to11744", work weight transfer issue,while oscillating pipe 2-4 rounds.;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=20 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:0.0 hrs/Total 214.5 Steel recovered 463.5#;Last survey MD=11,642.51,INC= 62.95,AZM=8.34,TVD=9604.82 Currently 65.2'Low,195.5'Left of line. Distance to plan 206.1'. 1/13/2017 Continue to directional drill 8-1/2"hole from 11,744'to 11,774',oscillating pipe and working weight transfer issue.;Replace swab in#2 mud pump,pod#2, circulate with mud pump#1 and work pipe and tighten draw works bolts;Resume directional drill 8-1/2"hole from 11,774'to 11,795',pumped a 23 BBL 11.2 PPG weighted hi-vis sweep around with 20 PPB nut plug and a drum of lube while drilling ahead.;Seen sweep back 20 BBL late,had a 50%increase in cuttings,fine sand and coals,continued circulate an additional bottoms up until returns were clean.;Resume directional drill 8-1/2"hole from 11,774'to 11820', oscillating pipe and working weight transfer issue.;Continue to directional drill 8-1/2"hole from 11820'to 11867,oscillating pipe and working weight transfer issue.;Service top drive and draw works,found some loose bolts on fetter clamp tighten same.;Pull 2 stands and rack back same install head pin and hose on drill pipe,and circulate at 2 BPM,Change saver sub and gripper dies.;Resume directional drill 8-1/2"hole from 11867 to 11874',oscillating pipe and working weight transfer issue.;Had a swab failure,mud pump#1,cylinder#3,replaced swab with new Blue Lightening swab. Circulated hole with#2 mud pump @ 234 GPM and worked pipe,while making repairs.;Resume directional drill 8-1/2"hole from 11874'to 11887,oscillating pipe and working weight transfer issue.;K-06RD2 wellhead pressures:24"=50 psi, 13 3/8"=20 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:0.0 hrs/Total 214.5 Steel recovered 472.9#;Last survey MD=11,829.40,INC=78.74, AZM=15.19,TVD=9668.06 Currently 74.31'Low,228.77'Left of line. Distance to plan 240.54'. 1/14/2017 Continued directional drill 8-1/2"hole from 11,887'to 11,896',oscillating pipe and working weight transfer issue.;Developed leak on mud pump#2 valve pod#3 changed valve cover gasket.;Resumed directional drill 8-1/2"hole from 11,896'to 11,900',reamed slide squat took TD survey,racked back one stand,and monitored well. Well static with slight seepage.;Perform clean up cycle pump 25 bbls weighted hi-vis sweep WI lube and nut plug around. Came back 20 bbls late w/100%increase for 100 bbls. Circ clean w/btm up.;Pumped a dry job,tripped out of hole for BHA and a BOPE test,from 11900'to 8000'(above window)with no issues. Blow all lines down and switch over to platform power.;Continue to trip out of hole from 8000 to 2190. While tripping out of hole mechanic changed out wiring harness on HPU#1 and HPU#2.;Conduct PJSM,laydown agitator and shock sub assembly,along with 1 joint of drill pipe. Clean and clear OBM from rig floor.;Rig service,service top drive,crown and travelling equipment.;Test choke manifold valves 4,5,6,and 11 250 PSI low and 3500 PSI high.;Continue to lay down BHA racking back remainder of drill pipe,jars,and flex collars.;Down load Sperry TM-HOC collar,clean rig floor and cellar area.laydown smart tools,and MWD,drain motor and remove bit. Grade bit at 1-4-BT-G-X-1/16-JD-BHA.;Land test plug in wellhead with 1 stand of HWDP hanging below same.Make up 4 1/2"test joint.;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=20 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:0.5 hrs/Total 215.0 Steel recovered 472.9#;Last survey MD=11,829.40,INC=78.74, AZM=15.19,TVD=9668.06 Currently 74.31'Low,228.77'Left of line. Distance to plan 240.54'. • • 1/15/2017 Finish making up test joint,rig up test equipment,and fill stack with water, had to thaw FIW line. Continue to work on mud pump#2 pony rod seal assy.;Work air out,ensure system is fluid packed,and shell test same.Test BOPE per regulations 250L and 3500H, test annular at 25OL AND 2500H. Witness waived by Mr. Regg with AOGCC 1-12-17 @ 11:08 hrs;Drain water from stack,pull test plug and rig down test equipment Had a fail pass on test#10,high test of blinds. Suspected air in system,cycled blind rams to purge air,and tested OK;While testing BOPE went through both mud pumps,inspected swabs and liners,removed rebuilt swabs and replaced with Blue Lightning or factory built complete Superior swabs.;Pick up and make up BHA#11. Pick up 7"Sperry mud motor with 1.5 degree AKO,make up 8 1/2"Reed bit,pick up Sperry DM collar,and scribe tools. Pick up Sperry smart tools consisting of;HCIM,DGR, PWD,EWR-P4 collar,and TM-HOC collar,upload date to HOC. Make up 1 stand of flex collars,and 1 stand of HWDP,shallow test MWD,all good.;Pick up jars trip in hole to 1223'pick up agitator and shock sub,continue to trip in hole with BHA#11 to 2833',fill pipe UW53K,DW48K.;Trip in hole with BHA#11 from 2833'to 8006'.;Cut and slip drilling Iine.;K-06RD2 wellhead pressures:24"=50 psi, 13 3/8"=15 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:0.0 hrs/Total 215.0 Steel recovered 472.9#;Last survey MD=11,829.40, INC=78.74, AZM=15.19,TVD=9668.06 Currently 74.31'Low,228.77'Left of line. Distance to plan 240.54'. 1/16/2017 Rig service;check oil in draw works,top drive motors,lube top drive,draw works,crown and tighten fedder clamp bolts on draw works.;Work on make up tong line, PLC problem(found a loose wire on make up tong PLC card).;Fill pipe circulate to warm mud and attempt get tool face,(too much noise with agitator in casing).;Exit window run in hole on elevators from 8012'to 9965'with no issues. Make up top drive,circulate to warm sheer mud.;Trip in hole on elevators from 9965'to 11771'w/no issues.;Wash down from 11771'to 11827'stage up pump rate to warm sheer mud. Precautionary ream from 11,827'to 11895', continue to warm and shear mud.;Continue to circulate staging up flow rates, switch frequencies on MWD to help filter out noise, and acquire tool face, establish parameters and SPR.;Wash last 5'to bottom at 11900', no fill encountered,orientate and resume directional drilling 8-1/2"hole from 11900'to 11955', 3350 PSI,400 GPM,3-10K WOB.;Directional drill 8 1/2"hole section from 11955 to 12081' 3500 PSI SPP,160 PSI DIF,410 GPM,30 RPM,13K TO,3-10K WOB. UW174,DW94,ROT124 After slide drilling stand down,attempt to pick up;and wipe slide area experienced pack off and over pull,causing a pop off on#1 mud pump to shear, Shut down pumps and isolated#1 mud pump,and was able to reestablish circulation with#2 mud pump.;Circulating at 130 GPM,attempt to establish rotation with no luck,work pipe up and down staging over pull up to 90K,was able to work 12058',had jars fire 3 times,increased pump rate to 216 GPM;continue to work pipe dropped down and attempted to establish rotation with no luck was able to work pipe up to 12038'jarring and began to experience some packing off was able to move pipe down to;12048'and could not get any further,began beating down and was able to get free pipe going down, Staging pumps up began working stand to get as much free movement as possible without packing off.;Was able to get a rate of 400 GPM working pipe from 12076'to 12018'. Established rotation and pump rate of 400 GPM, SPP 3015 PSI,TQ 13K,work entire stand and wash and back ream from;12018'to 12011'then back down to 12078'.Pump a high viscosity weighted sweep with 20 PPB nut plug an a drum of lube around. (Note draw works is stalling out at 260K pull.).;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=20 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:1.5 hrs/Total 216.5 Steel recovered 472.9#;Last survey MD=11,983.33,INC=85.91, AZM=22.67,TVD=9680.05 Currently 38.18'Low,264.61'Left of line. Distance to plan 267.35'. 1/17/2017 Continue rotating and reciprocating while pumping high vis weighted sweep around,came back 25 bbls late with a 25%increase in cuttings.;Directional drill 8 1/2"hole from 12081'to 12104',mud pump#1 lost 30 strokes picked up off bottom,and packed off,then blew a pop off on#1 mud pump,;re-established circulation with#2 mud pump and worked pipe free.;Trip out of hole 4 stands from 12,104'to 11,895',had a couple of spots with 10-15K over pull.Established drilling rate 418 GPM,3400 PSI,UW 180K, DW 102K,wash and ream back to bottom at 12,104'.;Directional drill 8 1/2"hole from 12,104'to 12,122',420 GPM,3600 PSI, UW 168K,DW 100K,packed off and blew a pop off,worked pipe free and staged pumps up to drilling rate of 400 GPM,;to lower stand pipe pressure to 3300 PSI,and avoid tripping pop off on pumps. Control drill at 25 FPH with rotary from 12,122'to 12,143'. (Note:This section drilled with no bit weight or;differential pressure.) Pumped a high viscosity 11.2 PPG weighted sweep at end of std.;Circulate out sweep while rotating and reciprocating stand, had a lot of sand back at bottoms up from where we started rotating,that had diminished by the time the sweep came back.;The sweep was 25 BBL late,with no noticeable increase in cuttings. (Note:approximately 60%of the sand we got back before the sweep was loose sand that had run in the hole and not cut by the bit.);Slide drill from 12,143'to 12,187'picking up pipe every 15'to ensure free pipe movement.400 GPM,3400 PSI.0 to 100 DIF,0 to 2K WOB;Rotaty drill from 12,187'U 12,206'at 400 GPM,SPP 3422 PSI,15.8TQ,3-5K WOB, ROP 40 FPM.;With stand down,continue to circulate and reciprocate pipe until bottoms up had approximately 50%increase in cuttings primarily sand.;Slide drill from 12206'to 12257'picking up every 15'to ensure free pipe movement,400 GPM,3420 PSI,2-7 WOB,140 DIF.;Rotary drill from 12,257'U 12,267'at 400 GPM,SPP 3280 PSI,14-18K TQ,3-5K WOB,ROP 40 FPH. Monitored bottoms up returns with rotation and had 30%increase in cuttings all sand.;Note high torque,diminished after wiping stand.;Slide drill from 12267'to 12279', 400 GPM,3420 PSI,2-7 WOB, 140 DIF.;Valve leaking on mud pump#1 cylinder#2,discovered pod washed,mix and pump dry job,to pull into casing for repair.;Trip out of hole to window,from 12279'to 10300'for mud pump repair.;K-06RD2 wellhead pressures:24"=50 psi, 13 3/8"=20 psi,9 5/8"=0 psi,Tbg =0 psi Daily Code 8:Today:0 hrs/Total 216.5 Steel recovered 484.2#;Last survey MD=12234, INC=83.80, AZM=34.62,TVD=9708 Currently 13.39'Low,288.59'Left of line. Distance to plan 288.9'. 1/18/2017 Trip out of hole for mud pump repair from 10,300'to 8011'(above window at 8062')with no issues,hole took 1.7 bbls over displacement.;Service rig.,inspect and grease top drive,blocks,draw works and feeder clamp. Continue changing washed out mud end on#1 mud pump cylinder#2.;Changing out mud end on #1 mud pump.;Run in hole 2 stands to position bit below window,run and test#1 mud pump,everything checked out on pump.;Run in hole and set down at 8,159',ream through tight spot to 8266'. Continue to run in hole on elevators working through tight spots at 8,737'and 11,665',continue to run in hole to 12,208'.;Fill pipe and circ at 400 GPM,3300 psi and 60 RPMs while reciprocating pipe from 12,208'to 12,267'. Circulate bottoms up to warm and shear mud while performing a clean up cycle.;Had coal back 100 BBLs early from washing through tight spot below window,that diminished. Got back a 50%increase in cuttings at bottoms up.;Noticed movement on#3 pod on#1 mud pump,found one of the primary mounting studs for the pod was broken. We were able to drill the stud and remove it with an easy out,replaced stud with new.;Directional drill 8 1/2"hole section from 12279'to 12284'picked up off bottom to adjust too face and experienced MWD issues.;Adjusted pump rates and changed MWD modes in an attempt to regain data,MWD is receiving a clean pulse but is having no response from data with the exception of PWD.;MWD engineer contacted Sperry,RSO and coordinator for assistance.;Check for flow, pump a dry job,and trip out of hole for MWD failure,from 12284'to 5976';K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=20 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:16.5 hrs/Total 233.0 Steel recovered 484.2#;Last survey MD=12234,INC=83.80, AZM=34.62,TVD=9708 Currently 13.39'Low,288.59'Left of line. Distance to plan 288.9'. • • 1/19/2017 Trip out of hole due to MWD failure from 5976'to flex collars at 137'. Inspect#1 pump while tripping,found 2 valves and seats that were starting to wash,and replaced same.;Lay down Sperry direction tools,break bit&lay down motor bit graded at 3-3-WT-A-X-O-PN-DTH. (Note;Will down load Sperry smart tools after we get new BHA run in hole).;Clean and organize rig floor and prepare to pick up BHA#12.;Hold PJSM,pick up Sperry TM HOC,DGR/EWR/PWD/HCIM collar&DM collar. Plug in and upload Sperry smart tools. Make up top drive and shallow test tools,all good,and stand back;smart tools in the derrick. Note service rig while uploading tools.;Pick up 7"Sperry mud motor and make up new 8 bladed Reed PDC bit,run in hole and make up Sperry Smart tools from derrick,continue to trip in hole making up remainder of BHA to 3264,;filling pipe at 2600'.;Continue to trip in hole with BHA#12 from 3264'to 8004'filling pipe at 5700'and at 8004'.;Have a PJSM with crew,cut and slip drilling line.;Orientate to window,continue to trip in hole,exit window at 8062'.;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=15 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:.0 hrs/Total 233.0 Steel recovered 484.2#;Last survey MD=12234,INC=83.80, AZM=34.62,TVD=9708 Currently 13.39'Low,288.59'Left of line. Distance to plan 288.9'. 1/20/2017 Run in hole to 10150'and fill pipe,continue to trip in hole to 12,210'.;Fill pipe rotate,and reciprocate pipe while circulating, from 12,210'to 12,270'. Circulate a bottoms up to clean hole and shear mud. At bottoms up had some fine sands but no major increase.;Mad pass from 12,257'to 12,284'.;Slide drill 8 1/2 hole from 12,284'to 12,315'.400 GPM,3250 PSI,0-10K WOB,UW 180,DW 100,MW 9.1+,ECD 9.3. After sliding about 5',we are experiencing hangs up;and having to pull up to 70K over to free pipe.;Lost a liner gasket on#2 mud pump#3 cylinder,replaced liner,liner gasket,and installed the Blue Lightning swabs in all cylinders.;Slide drill 8 1/2 hole from 12,315'to 12,330'.400 GPM,3250 PSI,0-10K WOB,UW 180,DW 100,MW 9.0,ECD 9.3. After sliding about 5' we are experiencing hang ups;and having to pull up to 75k over to free pipe. Picked up and rotated through slide and rotated the last 3"on stand continued circulating until bottoms up to clear slide cuttings.;Slide drill 8 1/2 hole from 12,330'to 12,360'.400 GPM,3360 PSI,0-10K WOB,UW 180,DW 100,MW 8.9+, ECD 9.2.;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=15 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:.0 hrs/Total 233.0 Steel recovered 484.2#;Last survey MD=12297.05,INC=85.05, AZM=37.32,TVD=9715.08 Currently 14.31'Low,289.71'Left of line. Distance to plan 290.06'. 1/21/2017 Slide drill 8 1/2 hole f/12,360 U 12,367.400 GPM,3200 psi off bottom,3450 on bottom,WOB 2 U 10k.;Contacted drilling engineer and decided to rotate last of std dn.Drill 8 1/2 hole f/12,367'U 12,386'.400 GPM,3475 psi,280 Diff,50 RPM,15 U 19k TQ,WOB 9 U 15k.;Torque climbing so we pumped a weighted high vis sweep but continued drilling f/12,386'U 12,391'.;Finish pumping sweep out,it came back 100 bbls late with a 30%increase in mostly small chunks of coal.;Service rig.Adjust draw works brakes and tighten bolts,tighten the bolts on the#2 pod on#1 mud pump,repair slight hydraulic leak in cellar,lube top drive,swivel packing,and blocks.;Slide drill 8 1/2 hole from 12,391'to 12,400',0-10K WOB,3350 PSI,0-200 DIF.;Continue to slide from 12400'to 12407',0- 10K WOB,3350 PSI,0-200 DIF, Having issues getting and holding tool face,very ratty.;Rotary drill in an attempt to get past ratty area were good tool face could be maintained. Drill from 12407'to 12417,10-15 WOB,3450 PSI,55 RPM,8-4 ROP,13-15K TQ.;Continue to slide from 12417'to 12426', 0-10K WOB,3350 PSI,0-200 DIF.;Pumped a 20 BBL 11.9 PPG weighted,200 Viscosity sweep with 1 drum of lube,while continuing to slide from 12426,with sweep outside of pipe did not see any noticeable difference in sliding,;however it did reduce up weight. Continue to slide from 12426'to 12434'.;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=15 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:.0 hrs/Total 233.0 Steel recovered 484.2#;Last survey MD=12360.39,INC=85.96, AZM=37.36,TVD=9720.04 Currently 14.33'Low,289.39'Left of line. Distance to plan 289.74'. 1/22/2017 Slide drill 8 1/2"hole from 12,434'to 12,436',having issues holding tool face and hanging up after sliding a few feet. Discussed with town and decided to trip for new bit and a reconfigured BHA.;Monitor well,pump dry job,remove drill pipe out of V-door and prepare for trip.;Pull out of hole for new BHA,due to low ROP,on elevators to window at 8062',had to work through tight spot at 11,764',;Swap over to platform power and service rig.;Trip out of hole from 8062'to BHA at 3000' (Note:Went through and inspect#1,and#2 pump while tripping out of hole,no issues found.);Rack back push pipe and all of the drill pipe used in BHA less 12 joints that had to be laid down,lay down agitator and cross overs,racked back jars and flex collars.;Down load data from Sperry MWD/RLL tools,break out and lay down Sperry LWD and MWD tools,drain and flush motor break off bit and laydown same. Bit graded 3-2-WT-A-X-2-PN-PR,;and had 2 plugged jets,with what appeared to be screws from the CV seal housing of the mud motor.;Clean and clear rig floor,stage new BHA at rig floor. Move BOPE remote panel,wire in and function same.;Pickup Sperry MWD/LWD smart tools and upload same.;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=15 psi, 9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:.0 hrs/Total 233.0 Steel recovered 484.2#;Last survey MD=12360.39,INC=85.96, AZM=37.36,TVD=9720.04 Currently 14.33'Low,289.39'Left of line. Distance to plan 289.74'. 1/23/2017 Test MWD/LWD,had a good signal,stand tools back in derrick,pick up 6 3/4 slick mud motor,make up 7 blade Varel bit,run in hole scribing motor,run stand of smart tools and make up to motor.;Run flex collars,HWDP,and jars,scribe motor to MWD,RFO 6.06/6.73 x 360=324.16*.;Run in hole picking up the singles we had laid down,trip in hole to 1204',pick up agitator and shock sub,continue to run in hole with 52 stds out of the derrick.;Fill pipe,continue to trip in hole to 5760',fill pipe and continue to 8086',bit is 7'out of the window.;Cut and slip drilling line(118'of drilling line)while circulating at 85 GPM to shear and warm mud.;Perform rig service,tighten Fedder clamp bolts,lube draw works,top drive,and traveling equipment,switch to rig power from platform power.;Continue to trip in hole with BHA#13 from 8086 to 9950,filled pipe and checked MWD signal all good,continue to trip in hole to 12342;Precautionary wash and ream from 12342'to 12436';Directional drill 8 1/2"hole section from 12436'to 12519',400 GPM,0-10K WOB,0-150 DIF PSI,2725 PSI SPP;K- 06RD2 wellhead pressures:24"=50 psi, 13 3/8"=15 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:.0 hrs/Total 233.0 Steel recovered 484.2#;Last survey MD=12427.96,INC=86.09, AZM=38.74,TVD=9724.73 Currently 13.75'Low,288.21'Left of line. Distance to plan 288.54'. 1/24/2017 Directional drill 8 1/2 hole ff 12,519'U 12,526'.Rotated last 10'of this std dn and pumped a sweep while we were drilling.;Circ out weighted high vis sweep while reciprocating and rotating the pipe for a clean up cycle.Sweep came back 60 bbls late with a 20%increase in cuttings.;Slide drill ff 12,526'U 12,566', Rotary drill fl 12,566'U 12,589'.418 GPM,2850 psi off bottom,3050 psi on bottom.6 to 12k WOB,60 RPM, 14 to 16k torque.;Slide drill ff 12,589'U 12,632', Rotary drill f/12,632'U 12,653'.415 GPM,2870 psi off bottom,3050 psi on bottom.6 to 13 k WOB,60 RPM, 14 to 17 torque.;Slide drill f/12,653'U 12,665'. Having trouble holding tool face. Rotary drill f/12,665'U 12,670'to clean up the hole.Slide drill f/12,670'U 12,705'.Rotary drill U 12,720'.Pump;weighted high vis sweep as soon as we started rotating.;Reciprocate and rotate pipe while pumping sweep out of the hole. Sweep came back 20 bbls late with 50%increase in cuttings.(1/2 coal and 1/2 sandy paste).;Directional drill 12,720'to 12,815' with above parameters.;Directional drill 12,815'to 12,920'. Pumped sweep while drilling at+-12,860'. Sweep came back 20 bbls late with 50%increase in cuttings.;K-06RD2 wellhead pressures:24"=52 psi,13 3/8"=18 psi,9 5/8"=0 psi, Tbg=0 psi Daily Code 8:Today:.0 hrs/Total 233.0 Steel recovered 484.2#;Last survey MD=12802,INC=82.18, AZM=56.51,TVD=9774.78 Currently 35.29'Low,226.12'Left of line. Distance to plan 228.86'. III • 1/25/2017 Directional drill f/12,920't/13,018'.425 GPM,3150 Psi, 56 RPM,15-16k TQ.;Directional drill f/13,018't/13,097'.Pumped a 20 bbl weighted high vis sweep and circ it around while drilling.It came back 100 bbls late and had a 50%increase for 100 more bbls.;At 15:45 the crane crew noticed that the rig HPU was on fire.The driller PU off bottom and shut the HPUs down.The crew and production extinguished the fire.When everything was secure.;We started up#2 pump and circ with the bit 10'off bottom.Cleaned up the units and put 63 gal of oil back in the oil tank.Started#2 HPU and moved the pipe.Ended up standing back 1 std and;circ with#2 pump and working the pipe. Hole is in good shape.;Circ and work the pipe while cleaning up the HPU and changing out the hydraulic pump and gear box main seal.;K-06RD2 wellhead pressures:24"=55 psi, 13 3/8"=18 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:.8.5 hrs/Total 241.5 hrs. Steel recovered 484.2#;Last survey MD=13050, INC=82.43, AZM=56.09,TVD=9807 Currently 49.27' Low,144.42 Left of line. Distance to plan 152.47. 1/26/2017 Attempt to pull hub on HPU#1 gear box.Found out it is a slip type hub and you have to push the center of the hub in then pull the outer hub off.Pulled the hub and changed out the seal.;Put hub back on and change out another one of the hyd motors.Remove the wrap from the turbo's and the exhaust pipe's on both the HPU motors.[Reciprocating and circ to keep mud sheared];Start HPU#1 warm it up and check fittings for leaks. Run#1 mud pump to test hyd pump. Bring everything up to drilling rate and everything tested out good.;Make connection,line up tool to slide 45 degrees right.Slide drill f/13097't/13,108'.425 GPM,3100 psi,WOB 5 t/8k.;Directional drill 8 1/2 hole f/13,108'to 13,188'.Pumped sweep at 13,125'with no increase in cuttings at surface.;Directional drill 8 1/2 hole f/13,192'to 13,275'.;K-06RD2 wellhead pressures:24"=55 psi,13 3/8"=18 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:.16 hrs/Total 257.5 hrs. Steel recovered 484.2#;Last survey MD=13176,INC=83.18, AZM=56.39,TVD=9822 Currently 55.5 Low,103.54 Left of line. Distance to plan 117.48'. 1/27/2017 Directional drill 8 1/2"hole from 13,275'to 13,322'.Pump weighted high vis sweep while drilling last 8'.425 GPM,3170 psi,56 RPM,15 to 17k TQ,8 to 13k WOB.MW 9,ECD 9.45.;Circ out sweep while reciprocating and rotating pipe.56 RPM,14.5k TQ,409 GPM,2850 psi.Sweep came back 100 bbls late w/a 50%increase in cuttings for an additional 100 bbls.;Get survey,and slow pump rates. Pump dry job.;POH to 12,832'and the drilling line started making popping noises.;Shut down and inspect the line. Had one spot they had been keeping an eye on.[pic in 0-drive.]That spot started getting worse so we decided to shut down and cut the drilling line.Slip and cut;380'of drilling line to get rid of the bad spot.Line spooled good after cut and slip.The drlg line spool is empty so they are having another spool sent out.;POH f/12,832't/9,100'.Had one spot at 11,680'coming through a coal where we pulled 20k over.;Continue POOH /� /0 to 3270' standing back in derrick.;POOH laying down 52 joints of drill pipe.;POOH to BHA.;K-06RD2 wellhead pressures:24"=55 psi,13 3/8"=18 psi,9 5/8" =0 psi,Tbg=0 psi Daily Code 8:Today:.0 hrs/Total 257.5 hrs. Steel recovered 484.2#;Last survey MD=13,322, INC=81.73, AZM=55.21,TVD=9842 Currently 63.63 Low,57.71 Left of line. Distance to plan 85.9'. 1/28/2017 Working BHA#13.Download MWD.Noticed a failure during down load so we had to LD all the MWD tools.Break bit. Bit grade 2-3-WT-A-X-1-CT-TD.;Check motor and MU used 6 blade sec bit.;Service rig,Change filters in HPU,tighten bolts in Drwks fedder clamp.;Clear and clean rig floor. Bring new tools over and stage on slide,Charge accumulator bottles.[went through#1 mud pump and changed liner and swab in pod#3 due to wear grooves on liner.];MU BHA#14. RIH w/motor and MU Sperry tools as per DD and MWD hands.;Plug in and upload tools.Test tools.getting good signal.PU and have PJSM for loading nuclear source.Clear floor,post signs,and load source.RIH below wellhead and announce all clear.;RIH to 1260'and PU agitator.PU 52 jts of 4 1/2"DP.Continue RIH to 7993'.;Hold PJSM.Slip on new spool of drill line.Begin draining stack for BOP test.;Stack would not drain. Pull 3 stands to get fluid level below tubing hanger.Make up test plug to string and land same.;K-06RD2 wellhead pressures:24"=60 psi,13 3/8"=10 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:.0 hrs/Total 257.5 hrs. Steel recovered 484.2#;Last survey MD=13,322,INC=81.73, AZM=55.21,TVD=9842 Currently 63.63 Low,57.71 Left of line. Distance to plan 85.9'. 1/29/2017 Fill stack and choke w/water.get air out of system.;Test Annular to 250 and 2500 psi for 5 min ea.Test all other BOP equip to 250 and 3500 psi for 5 min ea. Test manual and remote chokes,Perform accumulator test.No failures.;RD test equip and drain water out of stack into slop tank.Witness of BOP test was waived by Jim Regg.;RIH U 10,250'and fill pipe.Continue RIH U 11,754'and it took 15k to get through.RIH to 12,497'and set down 20k.Had to pull 60 over a jar twice to get free.;Stood back one stand and pulled up to 12,440'.Washed and reamed back down to 12,497'. Stalled out several times and had to break cc free.Acting like we were drilling with the stab that is on ;the ADL Collar and 50'off the bit.;Continue washing and reaming from 12,497'to 12,783'. � drive approximately 45'high top drive hydraulic motor split.;Shut down and isolated TDS hydraulic lines.Secured Xrig floor and began clean up process.With Made GSI spill notifications.Wash down to 12,809'(top drive at rig floor).;Change out top drive hydraulic motor.Clean up rig floor,drill and pipe deck,handrails,etc. Circulate at 170 GPM/730 psi while making repairs.Work pipe when able with no sticking issues.;K-06RD2 wellhead pressures:24"=55 psi,13 3/8"=8 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:.1 hrs/Total 258.5 hrs. Steel recovered 484.2# 1/30/2017 Change out top drive hydraulic motor.Continue cleaning decks and handrails.Test run and check everything out.Circ 65 spm and working pipe every hr to make sure pipe was free.;Bring on both pumps and wash and ream f/12,795't/12,860';Continue washing and reaming from 12,860'to 13,000'.Attempted several times to wash down with no success.;Wash and ream 13,000'to 13,210'.;K-06RD2 wellhead pressures:24"=55 psi,13 3/8"=13 psi,9 5/8"=0 psi, Tbg=0 psi Daily Code 8:Today:.16 hrs/Total 274.5 hrs. Steel recovered 484.2# . 1/31/2017 Wash and ream 13,210'to 13,322'.Had to work through numerous spots that took wt and torqued up.Most of the time we were reaming with the Stb on the ADL.;Pump 25 bbl 11 ppg hi-vis sweep with 30%increase in returns and 85 bbls late.;Cycle pumps and get check shot. POOH Mad Passing at 250 to 300 FPH up to 11,700'.;RIH on elevators without issue to 13,276'.;Wash and ream 13,276'to 13,322'.No fill.Spot Stik-Less 20 pill from 13,322'to 11,640'.Pump dry job.;POOH laying down 107 joints of drill pipe to 9984'.;K-06RD2 wellhead pressures:24"=50 psi, 13 3/8"=15 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:.0 hrs/Total 274.5 hrs. Steel recovered 484.2# 2/1/2017 POOH from 9984'to 3487'racking back and I/dn CBI. 8.4 bbls over cal fill.;Continue POOH racking back Recover rabbit on top shock sub/agitator l/dn and �/ chk same Re-drop rabbit.Continue racking back.Recover rabbit on top of jars.Chk and I/dn same and rabbit last two std.;Repair pulsation dampener on MP #1.CIO Linde hydraulic pump on HPU#2.Check liners and pistons in both mud pumps.;Udn flex collars. Remove sources&down load tools and I/dn. ADL pad was 1/16"under gauge. Bit grade:2-1-WT-A-X-I-NO-TD.;Service rig.Clean rig floor.;Make up 7 5/8"test joint with 2 stands of HWDP below test eitAs plug,Ctianae ower pipe rams to 7 5/8" Test lower pipe rams at 250 L/3500 H on chart.;Break down test joint and stand back 3 stands of HWDP.;Rig up � Weatherford casing equipment and fill-up line.;Hold PJSM.Make shoe track and check floats.;K-06RD2 wellhead pressures:24"=55 psi,13 3/8"=13 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:.0 hrs/Total 274.5 hrs. Steel recovered 484.2# • • ;o�Q� 1 2/2/2017 Finish testing float equipment.;Secure well shut down for lunch.;Moved blocks dn then brakes set.Unable move blocks up or dn &brakes not releasing. Troubleshoot same and resolve issue by moving few wires to other port and ART reprogramming signal around problem;area. Test run blocks and reset higher and lower limits.Monitored well on trip tank during rig repair w/<.3 bph seepage loss.;Resume p/up running 7-5/8",29.70#L-80 csg w!Hydril wedge 511 connection. Filling on fly and topping off every 10 jts from 171'to 5445'.19 joints left on deck.;Circulate liner volume at 215 GPM/625 psi.P/U 95 K,S/O 76 K.;Make up Baker SDD liner hanger/packer assembly as per Baker rep and fill with Canplex fluid.;Move 2 stands of HWDP in derrick.RIH with liner assembly filling pipe every to stands to 8017'.;K-06RD2 wellhead pressures:24"=55 psi,13 3/8"=15 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:.6 hrs/Total 280.5 hrs. Steel recovered 484.2# 2/3/2017 Slip and cut 184'of drill line while circulating and conditioning mud at 186 GPM/700 psi.Total 1.5 Btm/up and warm mud.;Check feeder bolts,grease TDS, blocks and DWK,check DWK drive motor bolts,grease swivel packing,and check oils in DWK motors&TDS.;M/up cement head and I/dn same.Calibrate weight indicators.;Establish parameters:Up/dn 149/97k w/out pump, up/dn 128/84k w/pump @ 2 BPM @ 390 psi. Eestablished rotation @ 105k rot WT @ 10 rpm @ 8.5-9.5 TQ 20 and 30 rpm both at 8-10.4 TQ.;RIH ft 8026'and attempt exit window.Start taking weight @ 8066'(TOW @ 8062.72').Attempt to work by obstruction with and without rotation up to stall of 18k TQ and 45k over pulls&40k under;set downs U 8069'. Discussed options with town.;Mix dry job and prep to POOH.Pump same.;POOH racking back DP t/shoe depth of 7535'and top packer depth of 2063'.Started seeing over pulls of 15-40k over pulls +-every+-40'(appears hng/prk assy)hanging up in 53#csg collars?);Pull liner hanger/packer assembly above rotary table and inspect same.No damage /scratches/scars. RIH w/1 std DP and install TIW valve.;Monitor well on trip tank while waiting on casing hands.Moving hands on boat due to weather.<1 BPH loss rate.;Riq up Weatherford casing equipment. Lay down liner hanger/packer assembly.;POOH laying down 7 5/8"liner.:K-06RD2 wellhead pressures: 24"=50 psi, 13 3/8"=10 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:. hrs/Total 280.5 hrs. Steel recovered 484.2# 2/4/2017 Continue POOH laying down 7 5/8"liner f/2388't/171'and inspecting same.Found jt#5 egged from back up tongs.;Attempt to brk apart Baker lock float equipment and crushed pipe. R/up air sawzall and cut apart all Baker lock connections and inspecting all w/no OD damage to shoe.;Shoe was gutted missing all internals and also split and mushroomed. Missing small triangle piece 1"x 3/4"of body but only.08"short ID also shows signs of possible top of whip stock entry.;See photos in"0" drive.;Clean rig floor and r/dn csg equipment. Service rig and chg/out derrick climber assist line while waiting on fisherman coming on boat.Monitor well on trip tank with<.3 BPH loss rate.;Also false production H2S gas alarm.All mustered.Well secured and equipment shut down.Wait on hot work and re start rig.;Make up BHA#15 window milling assembly.;RIH with BHA#15 to 8028'.;Circulate and condition mud.Obtain parameters:P/U 108K, S/O 80 K. 70 RPM/7 K torque/86 Rot. 470 GPM/2150 psi.;Wash through window from 8028'to 8104' with upper and lower mills without issue.;Monitor well (static).Mix and pump dry job.;POOH with BHA#15.;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=10 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:. 0 hrs/Total 280.5 hrs. Steel recovered 484.2# 2/5/2017 Continue POOH with BHA#15.f/6400't/718'Top of HWDP came out(1)std early.;Pick up cement head.Break off pups and XO and prepare for boat while counting pipe on location.;Continue POOH racking back BHA. Cleaned bar magnet and recovered 29#of iron hair. Both J-BSK's were MT and mills still in gauge. Removed 8.98'flex joint.;Screwed mill together to stiffen up assy.;RIH with BHA #16 to 8021'. Calculated fill 59.6 bbls.Actual=62.7 bbls.;Circulate and condition mud.Establish parameters:P/U 110 K,S/O 80 K. 390 GPM/1500 psi. Rot 78 K,80 RPM/6.5 K torque.;Slack off with no pump/taking weight at 8061'.P/U and rotate/dress whip stock from 8058'to 8080'with upper and lower mill 3 times until clean.Slide down to 8097'to clear open hole.;Work through window several times.Torque while reaming 8-10 K.;Circulate and condition mud running centrifuge to bring mud weight down to 9.0+ppg. 440 GPM/1750 psi. Recovered 4.5 lbs metal from ditch magnets.;POOH with BHA#16 on single,to stagger break.;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=11 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:. 0 hrs/Total 280.5 hrs. Steel recovered today 32 lbs.Total=516.02 lbs. 2/6/2017 Udn inspect bha#16 rack back jars and HWDP.Cleaned bar magnet. Recovered 61#of iron hair and 22#out of J-bsk's(98%coal 1 LB of iron&cmt chunks Btm mill 3/32"under gauge and 10%used.;Middle mill same no wear and top mill in gauge with slight wear.;Clean clear rig floor and prep for BHA #17.;Greased crown,TDS,Blocks DWK chk DWK and TDS bolts chk oils in TDS and DWK and greased swivel packing.;M/up BHA#17 dumb iron clean out assembly and RIH w/HWDP.;RIH p/up and rabbiting DP t/2225'.Hung blocks and tighten drlg line while filling pipe&circulate warming mud.;Crane working personnel from boat.Clean rig floor.;Continue RIH p/up and rabbiting singles off deck total 111 jts p/up plus 1 joint above jars.;Continue RIH out of derrick t/ 8021'. Filled pipe @ 5200'.;Slip and cut 113'of drill line. Calibrate weight indicators.;Establish parameters:P/U 116 K,S/O 80K without pumps.P/U 120 K, S/O 80 K with pumps.70 RPM/6.5 K torque 90 K.390 GPM/1370 psi.Wash down through window.;Saw slight bobble at 8058'.Wash and ream through coal below shoe to 8140'. RIH on elevators 8140'to 9664'.Pipe hung up.;Break circulation at 400 GPM/1500 psi. Took 18 jar licks 70 K over to break free.Work pipe while circulating and conditioning from 9645'to 9708'.;RIH on elevators from 9708'to 10,656'.;Circulate and condition mud at 450 GPM/2050 psi while rotating and reciprocating pipe.;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=11 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:. 0 hrs/Total 280.5 hrs. Steel recovered today 62 lbs.Total=578.02 lbs. 2/7/2017 Continue to run in hole with clean out assembly from 10639'to 11243'work,wash,ream,push and chase junk.;Run in hole from 11243'to 11872' on elevators pushing and chasing junk. Circulate 200 BBL to warm and shear mud while working pipe.;Run in hole from 11872'to 12804' work,wash,ream,push and chase junk. Circulate 200 BBL to warm and shear mud while working pipe.;Run in hole from 12804'to 13115 work,wash,ream,push and chase junk.;Run in hole from 13115'work,wash,ream,push and chase junk to TD @ 13322'setting 40K DN weight.;Circulate and condition mud while rotating and reciprocating pipe a full stand,staying 3'above junk. UW170,DW85,ROT120 @ 430 GPM,2175 PSI,80 RPM,13-14.5 TQ.;Flow check well,had slight seepage. Pump 84 bbl Stick-Less 20 bead pill,spotting pill on back side with the dry job,from 13322'to 11640'.;Trip out of hole laying down drill pipe,from 13322'to 9824'(112 singles laid down),continue to trip out of hole racking back stands in derrick to 8078'.;Note encountered 15-50K over pull,while tripping out of hole @ 13170',13162',13095',13022',12985',12933',12910',12903',12722', 12541',12520',11873',11660',11426',11315',11295',10750',;10058', 9923',9575',8567',8360',8185,8100'.;With bit depth at 8078'dropped 2.375"OD hollow drift with 80'of slick line attached and continued to trip out of hole to BHA'did not see any drag going through window.;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=11 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:. 0 hrs/Total 280.5 hrs. Steel recovered today 7.05 lbs.Total=585.07 lbs. • • 2/8/2017 Continue to inspect and lay down BHA#17.;CIear clean rig floor,service rig,lube top drive and draw works,check bolts and oils in same.;Rig up casing handling equipment,and monitor well,had slight seepage.;Pick up inspect and make up 7-5/8",29.70#,L-80 shoe track,with Hydril 511 connection,complete with float equipment,baker locking first 3 joints. Check floats all good.;Continue to pick up and make up 7-5/8"casing per drilling running tally,filling pipe on the fly and topping off every 10 joints.Run a total of 138 joints including shoe track,to 5360'.;Make up pump in sub with cross over,stage pumps up in 50 GPM increments from 218 GPM to 430 GPM,circulate and condition mud pumped a total of 1.5 casing volumes(370 BBL).;Noticed a loss of 38.7 BBLS,inspected surface equipment no leaks,shut down pumps and well ballooned back 32.5 BBLS.;Make up Baker HRD-E In-Line liner hanger packer,rig down Weatherford casing tongs,removed shipping block from liner hanger packer,mix and install Pal-Mix. Change elevators,install cross over;on top of running tool,make up stand of drill pipe out of derrick,run in hole,and break circulation.;Run in hole with liner hanger packer,on drill pipe out of derrick from 5460'to 6800'.;K-06RD2 wellhead pressures:24"=50 psi, 13 3/8"=11 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:. 0 hrs/Total 280.5 hrs. Steel recovered today 7.05 lbs.Total=585.07 lbs. 2/9/2017 Continue to run in hole with 7-5/8"liner on DP out of derrick from 6762'to 8003'.;Pick up and make up rotating cement head and lay down same while monitoring loss rate(Just seepage).;Swap to rig power,cut and slip 102'of drilling line and,calibrate weight indicators while conditioning mud.;Continue to run 7 5/8"liner in hole from 8003'to 13320'UW 260-280K with pump on.;Fill pipe,break circulation,stage pumps up watching for losses,rig up cement squeeze manifold and lines. Circulate a bottoms up at 4 BPM rate keeping SPP pressure below 1000 PSI.;PJSM with all personnel involved in cement job,make up cement head and lines. Pressure test all lines to 4750 PSI.;Pump 15.2 BBL of 12.0 PPG mud push,at 3 BPM rate,pump 62.5 BBL of 15.3 PPG,Class G cement with D046 antifoam 0.2% BWC,D202 dispersant 1.0%BWC,D400 gas block 0.75%BWC, D154 extender 7.5%BWC,;D198 0.17 retarder BWC and, Cim-Net.5 PPB,pumped cement at 2.5 BPM rate,dropped cement dart had good indication of launch. Displaced with rig pump,pumped 8 BBL of 12 PPG mud push,followed by;337.2 BBL of 9.15 PPG OBM to bump plug,(Note actual displacement 345.2,calculated was 346.7)final circulating pressure 800 PSI, brought pressure up to 1300 PSI 500 above FCP, bleed pressure off;had 5 BBL returned to trip tank floats held,CIP @ 00:35. Was unable to reciprocate casing while cementing. Looks like we had 27%losses during displacement.;Set 60K down on liner hanger to set same,pressured up to 3350 PSI with rig pump and continued to pressure up to 4300 PSI with test pump to release running tool and expose dog sub. Set down 60K;to set liner top packer,did not see a shear or indication of setting repeated process several more time too include rotating at 20 RPM while setting down,did not see good indication of setting.;Pressure backside up to 2500 PSI to see if liner top packer was leaking held 2520 PSI for 5 minutes bled pressure off. (Note:verify liner top packer setting by inspecting dog sub when out of hole);Remove cement head and lay down same,Insert nerf ball in drill pipe,kelly up and pressure up to 600 PSI,pick up out of liner hanger,when pressure dropped engaged pump at 2.5 BPM rate.;and washed through PBR,with seal assembly above liner top packer kick pumps up to drilling rate and circulate a surface to surface volume no cement seen at surface.;Pump dry job and pull out of hole with Baker liner hanger running tool and dog sub,from 7932'to 5300'.;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=11 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:. 0 hrs/Total 280.5 hrs. Steel recovered today 7.05 lbs.Total=585.07 lbs. AO A. 1,f V 2/10/2017 Continue pull out of hole with BOT liner hanger running tool and dog sub.;lnspect tools,and confirmed that dog sub had sheered,confirming liner top packer had set.;Pick cement head,break off pups,and cross overs.;Rig up to test casing,purge air from system,close blind rams,test casing and liner top packer, charting same to 2700 PSI,pressure fell to 2640 PSI in 30 minutes. Good test blow down lines.;Prepare to pick up clean out BHA,strap tools, changed out 4 way valve on Koomey unit,while cleaning pits#4&5;Pick up and make up clean out BHA,bit,scraper,bit sub,XO,and 10 stands of HWDP;Trip in hole with cleanout assembly picking up 112 singles of CDS-40 drill pipe,then running pipe out of derrick to 5306';Made up lower 9 5/8"casing scraper assembly with 7" Swaco Well Commander circulating sub,above scraper,filled pipe and broke circulation verified circulating sub was closed.;Continue to trip in the hole with clean out assembly from 5329'to 5980.00;Trouble shoot torque issues with top drive found pressure transducer to be bad.;Continue to trip in hole from 5980'to 7840'. UW 92K,DW 72K;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=11 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:. 0 hrs/Total 280.5 hrs. Steel recovered today 7.05 lbs.Total=585.07 lbs. 2/11/2017 Service rig,check motor and Fedder clamp bolts,lube top drive and draw works, continue trouble shoot top drive torque issues.;Continue trouble shoot top drive torque issues.;Drain stack and hang off clean out assy on test plug, change lower rams to 2-7/8"x 5"VBR's,continue to trouble shoot top drive issues, while changing out HPU pumps and cleaning pits.;Production had a false gas alarm,all personnel mustered and were accounted for,an all clear was announced,and all permits were reactivated.;Test BOP per AOGCC regulations,test witnessed by AOGCC inspector Brian Bixby. All BOPE equipment tested on 4 1/2"pipe,for 5 minutes low and 5 minutes high,annular tested at 250 PSI;low and 2500 PSI high,all other components tested to 250 PSI low and 35000 PSI high,with no failures recorded. The manual and super chokes were function tested with pressure,and had no issues.;Performed an accumulator draw down test,initial pressures,MAN 1500 PSI,ACC 2950 PSI,ANN 1050 PSI,final pressures,MAN 1500 PSI,ACC 1650 PSI,ANN 1100 PSI,200 PSI recovery 20 SEC,full recovery;108 SEC 3000 PSI,AVG N2 bottles 2550 PSI;Lay down test tools and equipment,blow down choke manifold,rig up to drain stack,pull test plug,drain stack,break down test joint laying down cross overs and valves,;Make up upper 9 5/8"casing scraper,and trip in hole to TOL @ 7932'seen 2K drag when starting in liner,continued to trip in hole to 12354'started to see some cement stringers,had 2-4K drag,;picked up and slacked off and we were back to the original down weight,continued in the hole to 12501 and started to see 8-10K drag slacked off to 12563',made up top drive filled pipe and circulate;an additional 50 BBL to move cement strings above us,this helped and we resumed running in the hole with intermittent cement stringers to 13010,where we set down,we picked up and set down 15K.;Made up top drive and attempted to wash through with no luck engaged rotary at 20 RPM and stalled out with TDS torque set at 11.3K,;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=11 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:. 2.5 hrs/Total 283.0 hrs. Steel recovered today 0.0 lbs.Total=585.07 lbs. • • 2/12/2017 Staged up circulating rate to 400 GPM,circulated well bore clean mud pump#2 was down twice due to valve cap leaking. The HPU#1 developed a leak on 3/8"JIC hose fitting;leaking less then 1/2 gallon to secondary containment,the HPU monitoring hand shut down the unit. At bottoms up were getting back a couple pieces of rubber and cement with CEMNET.;Pumps on,UW 145K,DW 90K,400 GPM,2600 PSI.and pumps off UW 96K DW 65K. Mech continued trouble shooting torque gauge issues.;Pull out of hole from 13010'to 12800', attempt to establish rotation with 11.3K torque setting with no success,mechanic continued trouble shooting torque issues.;Continue to stage out of hole to 12538'and attempted to establish rotation again,with no success,mechanic continuing to trouble shooting torque issues.;Rig on code 8,mechanic requiring access to top drive electrical junction box to finishing trouble shooting torque issues. At this time the blocks were hung,and the drilling line was spooled off the;draw works drum for the Lebus technician to inspect the drum grooving and get dimensions of each row. Adjusted and verified top drive torque reading against;rig tong line pull,set torque limit to 17.2K. Note:top drive torque reading accurate.;Establish torque parameters,off bottom break over torque 15.2K,with free rotating torque 13.2-14.0K, Run in hole from 12552't 13000'.;Wash and ream down tag @ 13010',drilled slow and hard to 13011'using various parameters. Broke free chased/reamed©100+FPH to 13051',stacking weight with minimal;torque broke free chased and reamed to 13057'.;Drill slow hard to 13058',had a couple gallons of rubber pieces with cmt returns at shakers,discussed options with town,decision made to trip for new bit and laydown scraper assemblies.;Mix and pump dry job trip out of hole for new clean out BHA,from 13058' to 10615'.;Perform rig service.Service top drive,draw works,and traveling equipment.;Trip out of hole for new clean out BHA,from 10615'to 7885'soft broke and laid down upper 9 5/8"casing scraper assembly,continue to pull out of hole to 5329'soft break and lay down lower;9 5/8"casing scraper assembly with well commander circulating sub,continue to pull out of hole to 1905'.;K-06RD2 wellhead pressures:24"=50 psi,13 3/8"=11 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:. 3.0 hrs/Total 286.0 hrs. Steel recovered today 0.0 lbs.Total=585.07 lbs. ,‘ ,,„ • • Hilcorp Energy Company Composite Report Well Name: MRF K-06RD2 Field: County/State: ,Alaska (LAT/LONG): ovation(RKB): API#: Spud Date: Job Name: 1613025 K-06RD2 Completion Co AFE#:r 1613025C 3r r Z l / 3( y cif) AFE$: $1,466,089 2/16/2017 Change over from Drilling AFE to Completion AFE at 18:00 HRS.,Continue to lay down 19 joints of HWDP,lay down bit,scraper,bit sub,and crossovers. Clean and clear rig floor.,Conduct PJSM with all personnel involved in wire line logging operation,and rig up E-Line,while continuing to clean pits,and changing out pump on HPU#2,Pollard E-line run in hole with CBL,Gamma,CCL tools,was able to get down to 11878',logged up found top of decent cement at 11800'had intermittent cement to 11665'. Pull out of hole and rig down wire line,contacted engineer on findings,AOGCC notification will determine plan forward.,Clean and organize floor continue with pit cleaning and rig maintenance while waiting on orders. 2/17/2017 While waiting on orders,continue to cleaning pits,changed out IBOP,and rig up to test BOPEs.,Received approval from the AOGCC to run the guns and perf. Changed out top drive grabber dyes and finished getting IBOP and saver sub installed.,We had to pull the test plug up,to break the connection on top,noticed the test plug rubber was missing,install new rubber and re-set plug,finish rigging up to test BOPE,and purged air from the system.,Test BOPE,test annular to, � 250 and 2500 PSI for 5 minutes each,test all other BOPE equipment to 250 and 3500 PSI for 5 minutes each. Performed accumulatdT nTawaown test 20 1,0seconds for 200 PSI 108 seconds for full recovery,4 N2 bottle average 2500 PSI. Note;witness waived by AOGCC Jim Regg.,Pull test plug,break and lay down test joint and floor valves,set back 2 stands of drill pipe that was under test plug.,Prepare floor to pickup perforating guns,clean and clear floor,turn elevators around, PJSM with all personnel,and stage handling tools on rig floor.,Pick up 1193'of EXPRO,4.5",GO Super Deep,RDX,6 SPF 135 Phase,pipe conveyed perforating guns,along with firing head,auto fill valve,packer and assorted jewelry.,Rig up Weatherford power tongs,conduct a PJSM with all hands, pick up 4.5"12.6 PPF,Super-Max tubing,drifting same,run 6 joints to 1698.91'and pick up 10'marker pup,continue to trip in hole with TCP guns while drifting tubing to 2625',K-06RD2 wellhead pressures:24"=54 psi, 13 3/8"=8 psi,9 5/8"=0 psi,Tbg=0 psi Daily Code 8:Today:. 0.0 hrs/Total 295.5 hrs. Steel recovered today 0.0 lbs.Total=585.07 lbs. 2/18/2017 Run in hole from 2625'to 6441'with EXPRO perforating guns while pick up and drifting 4 1/2"12.6 PPF Super-Max tubing.,Continue to run in hole from 6441' to 7932,nothing observed going into the top of the liner with guns.,Continue to run in hole from 7932'to 9207'with EXPRO perforating guns while pick up and drifting 4 1/2"12.6 PPF Super-Max tubing.Rig down Weatherford tongs and change over to CDX40 drill pipe.,Continue to trip in hole with EXPRO guns,from 9207,packer entering 7 5/8"casing at 9213'bit depth,with no issues,continue to run in hole to 9950'.,Close HSFV fill valve,close bag and line up on choke, pressured up drill pipe to 300 PSI to close HSFV valve,bled pressure off annulus while maintaining drill pipe pressure indicating valve was closed,then bled drill pipe to 0 PSI.,Continue to trip in hole from 9950 to 13123 picked up 10'pup,to 13133',make up stand and run in hole to past 13161'picking up and parking pipe in up stroke at 13161, UW 125K DW 70K.,Rigged up Pollard e line and ran in hole with logging tools to correlate gun depth,locate RA sub at 13666.5'WLM picked up logging to 11200'WLM,sent data to engineer and geologist in town for interpretation,line pull out of hole with eline.,Received orders from town to pick up 13'for correct correlation,rigged e line down,picked up 13'to 13148'and set packer,slacked off and set down 25K„PJSM with all personnel,closed annular and pressured annulus to 1266 PSI,without indication of guns firing continued to pressure up to 1500 PSI and had slight indication of guns firing,pumped a total of 3.1 BBL. Bled annulus down to 500 PSI,monitored drill pipe with no additional pressure increase for 15 minutes. Bled annulus to 0 PSI. Picked up to up weight+1'and opened bypass.,Pumped down tubing at 2.7 BPM took 50 BBL to catch pressure of 100 PSI,increased pump rate to 4 BPM with 400 PSI on drill pipe looked like we were pumping into formation indicating guns fired,picked up an additional 1'to ensure packer bypass was open,had good returns through choke and gas buster to shakers.Pumped 650 BBLS 6%KCL with approximately 60 BPH loss rate at 4 BPM pump rate 200 PSI SPP„and 100 PSI annular pressure,had some gun gas back,opened annular and continued to circulate back to shakers with a 100 PSI SPP,pumped an additional 285 BBLS continue to have slight amount of gun gas breaking out.Shut down and circulate across top of well to establish a static loss rate of 50 BPH. 2/19/2017 Pull out of hole laying down 4 1/2 DP from 13,155'to 10,881',hole taking 35 BPH.,Circulate bottoms up to get the remaining gun gas out,had a minimal amount of gas back.168 GPM,130 PSI,max gas 75 units,with a loss rate of 47 BPH.,Continue to pull out of hole laying down 4 1/2”drill pipe to 9270',hole taking 36 BPH.,Cut and slip 157'of drilling line.,Lay down last joint of 4 1/2”DP,break out and lay down cross overs,rig up Weatherford tongs,hole taking 27 BPH. Shut down continuous hole fill,and started putting in 5 bbls every 1/2 hour,letting well find its fluid level.,Pull out of hole standing back 4 1/2"Supermax tubing,from 9029'to 1500'continue filling hoe with 5 BBL FIW 6%KCL every 1/2 hour.,Perform rig service,tighten Fedder clamp bolts on draw works,check hydraulic motor bolts on draw works,lube and service travelling equipment.,Stood back 1 stand of 4 1/2"Supermax tubing,broke out crossovers,and RA marker. Changed elevators and laid down 6 joints of CDS40 drill pipe,and made up safety joint,staging it in V-door. Laid down packer assembly,with jewelry, and 2 joints of 2 7/8"tubing. Laid down firing head and,57 spent perforating guns,all guns fired.,Clean and clear rig floor,prep area to rig up ESP equipment.,Inspected mud pumps while tripping,mud pump#2,cylinder#2,changed liner,swab,suction seat and valve,cylinder#1 replaced discharge seat and valve.,Fluid lost to hole today 588 BBL,Cumulative lost to hole 863 BBL 2/20/2017 Rig up Summit ESP equipment,spot spooler,place ESP cable in spooler,and bring tools to the rig floor.,Pick up ESP assembly,pick up motors,along with gauge,and centralizer anode,fill both motors with oil. Hang dual sheave with cable and control line,pick up upper and lower seal assemblies and,attach motor leads,meggar cables and check continuity,test control lines,install motor clamps,pick up pumps and install clamps,pick up discharge,ported sub, crossover,and 1 joint of tubing,installing clamps.,Rig down ESP tools and rig up to run tubing out of the derrick,conduct a cable cutting drill and have a PJSM.,Run in hole with ESP assembly,running 4 1/2 tubing out of the derrick and installing clamps on each of the first six joints then,every other joint after that. Continue to trip in hole meggar cable every 1000'to check continuity to 7430',made up X-nipple with a plug and ball bar set in place,made up single, screwed on ESP dual packer.,Cut ESP cable and prepare to make splice at ESP dual packer.,Fluid lost to hole today 280 BBL,Cumulative lost to hole 1143 BBL. • 2/21/2017 Finish making splice and plug into packer.Tie in control lines.Change to new spool and plug into packer.Meg cable and check for continuity.Tie another control line into the vent valve.Opened at 3500 psi.MU SSSV and install control line.Pressure up and open SSSV WI 3300 psi. Lock in 4000 psi.,RIH installing cannon clamps on every jt t/7818'.PU landing jt and MU hanger.,Make cable splice,MU Penetrator in hanger and test same.Tie in control lines to hanger.,Land hanger 60k,with umbilical cord plugged in and 4000 psi locked in on SSSV.Meg to check for continuity and it was good.Run in LDS.,Fill tbg with FIW and press up do tbg to 3800 psi, Hold for 30 min, Bleed off and fluid pack back side.Rigged down Summit sheave and equip while filling Ann.Pkr set at 388',Bottom of ESP at 7868'.,Pressure up on ann to test pkr to 1900 psi.Lost 180 psi in 30 min and continued on a steady loss.Attempted to test again with the same results.RU Pollard while testing.,Pressure back up on the tbg to 4000 psi for 30 min to make sure packer was set. Bleed off tbg and pressure back up on ann to 1700 psi for 30 min.Lost 100 psi.,RIH w/Pollard and pull drop bar. Run#2 RIH and recover RHCP.RD slickline.,Pull landing joint.Set TWC.Lay down landing joint and stand out of derrick. Rig down Weatherford.,Pull rotary table.Clean rotary beams and flow box. Rig down mousehole,flow nipple,flow line and flow box. Bleed down accumulator. N/D choke line/HCR.Nipple down BOPE.,Pull and lay down riser.,Clean and dress tubing hanger. Begin nippling up tree.,Fluid lost to hole today 54 BBL,Cumulative lost to hole 1228.5 BBL 2/22/2017 Nipple up tree.Tighten all the valves and connections.Test void to 250&5000 psi for 10 min ea.Good test.Pull BPV and install TWC.Test tree to 400 psi and 3,000 psi for 5 min ea.Good tests.Pull TWC and turn well over to production.Clean up wellhead room and put all the tools away.,Swap over to K24rd3 AFE for skidding rig and doing rig repairs at 1200 hrs.This will be the final report on this AFE. • • Hilcorp Alaska, LLC Trading Bay King Salmon K-06RD2 507332008802 Sperry Drilling Definitive Survey Report 03 February, 2017 HALLIBURTON �1 Sperry Drilling • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well K-06RD2 Project: Trading Bay TVD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Site: King Salmon MD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Well: K-06RD2 North Reference: True Wellbore: K-06RD2 Survey Calculation Method: Minimum Curvature Design: K-06RD2 Database: Sperry EDM-NORTH US+CANADA Project Trading Bay Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well K-06RD2 Well Position +N/-S 0.00 usft Northing: 2,511,799.44 usft Latitude: 60°51'55.931 N +E/-W 0.00 usft Easting: 213,762.47 usft Longitude: . 151°36'21.135 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Water Depth: 73.00 usft Wellbore K-06RD2 ^. . Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2016 12/13/2016 16.22 73.75 55,449 Design K-06RD2 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 8,022.00 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 0.00 0.00 0.00 74.73 Survey Program Date 2/3/2017 From To (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 122.00 2,122.00 K-06(NSG_WL)(K-06) NSG_WL North seeking gyro on wireline 07/04/1988 2,222.00 8,022.00 K-06RD(K-06RD) NSG_WL North seeking gyro on wireline 07/04/1988 8,062.72 8,315.54 MWD_Interp Azi+sag(K-06RD2) MWD_Interp Azi+sag Fixed:v2:std dec with interpolated azimuth+sag 12/07/2016 8,379.41 13,283.22 MWD+SC+sag(K-06RD2) MWD+SC+sag Fixed:v2:standard dec&axial correction+sag 12/25/2016 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 0.00 0.00 0.00 0.00 -122.00 0.00 0.00 2,511,799.44 213,762.47 0.00 0.00 UNDEFINED 122.00 0.05 106.65 122.00 0.00 -0.02 0.05 2,511,799.43 213,762.52 0.04 0.05 NSG_WL(1) 222.00 0.08 117.72 222.00 100.00 -0.06 0.15 2,511,799.38 213,762.62 0.03 0.13 NSG_WL(1) 322.00 0.57 140.50 322.00 200.00 -0.48 0.53 2,511,798.95 213,762.99 0.50 0.39 NSG_WL(1) 422.00 2.32 157.40 421.96 299.96 -2.73 1.63 2,511,796.67 213,764.03 1.78 0.85 NSG_WL(1) 522.00 1.32 107.17 521.92 399.92 -4.94 3.51 2,511,794.42 213,765.85 1.79 2.08 NSG_WL(1) 622.00 3.25 79.75 621.83 499.83 -4.77 7.40 2,511,794.49 213,769.74 2.17 5.88 NSG_WL(1) 722.00 6.97 51.22 721.43 599.43 -0.47 14.92 2,511,798.61 213,777.37 4.40 14.27 NSG_WL(1) 822.00 8.62 50.53 820.51 698.51 8.10 25.43 2,511,806.92 213,788.09 1.65 26.67 NSG_WL(1) 922.00 10.18 52.20 919.16 797.16 18.28 38.20 2,511,816.78 213,801.11 1.58 41.67 NSG_WL(1) 1,022.00 13.43 56.03 1,017.03 895.03 30.19 54.82 2,511,828.28 213,818.01 3.34 60.84 NSG_WL(1) 2/3/2017 12:45:30PM Page 2 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well K-06RD2 Project: Trading Bay TVD Reference: K-06RD2 @ 122.O0usft(Kuupik 5) Site: King Salmon MD Reference: K-06RD2 @ 122.O0usft(Kuupik 5) Well: K-06RD2 North Reference: True Wellbore: K-06RD2 Survey Calculation Method: Minimum Curvature Design: K-06RD2 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 1,122.00 16.27 56.43 1,113.68 991.68 44.42 76.13 2,511,841.99 213,839.66 2.84 85.14 NSG_WL(1) 1,222.00 18.07 53.50 1,209.23 1,087.23 61.40 100.27 2,511,858.37 213,864.21 2.00 112.90 NSG_WL(1) 1,322.00 20.00 53.45 1,303.75 1,181.75 80.81 126.48 2,511,877.13 213,890.88 1.93 143.29 NSG_WL(1) 1,422.00 22.20 54.22 1,397.04 1,275.04 102.04 155.55 2,511,897.64 213,920.46 2.22 176.93 NSG_WL(1) 1,522.00 23.92 55.17 1,489.05 1,367.05 124.67 187.52 2,511,919.48 213,952.98 1.76 213.73 NSG_WL(1) 1,622.00 25.23 56.20 1,579.99 1,457.99 148.10 221.87 2,511,942.07 213,987.89 1.38 253.04 NSG_WL(1) 1,722.00 25.13 56.62 1,670.49 1548.49 171.64 257.31 2,511,964.73 214,023.90 0.20 293.43 NSG_WL(1) 1,822.00 24.70 56.87 1,761.18 1,639.18 194.74 292.54 2,511,986.97 214,059.68 0.44 333.50 NSG_WL(1) 1,922.00 24.33 57.17 1,852.17 1,730.17 217.33 327.34 2,512,008.69 214,095.03 0.39 373.03 NSG_WL(1) 2,022.00 23.88 57.58 1,943.44 1,821.44 239.35 361.74 2,512,029.86 214,129.96 0.48 412.01 NSG_WL(1) 2,122.00 23.58 57.92 2,034.99 1,912.99 260.83 395.77 2,512,050.50 214,164.51 0.33 450.49 NSG_WL(1) 2,222.00 22.45 64.25 2,127.04 2,005.04 279.75 429.93 2,512,068.58 214,199.11 2.72 488.42 NSG_WL(2) 2,322.00 19.88 78.98 2,220.36 2,098.36 291.30 463.84 2,512,079.30 214,233.30 5.89 524.19 NSG_WL(2) 2,422.00 21.48 84.37 2,313.92 2,191.92 296.35 498.76 2,512,083.49 214,268.33 2.49 559.20 NSG_WL(2) 2,522.00 24.57 84.47 2,405.94 2,283.94 300.15 537.68 2,512,086.34 214,307.33 3.09 597.75 NSG_WL(2) 2,622.00 27.87 84.28 2,495.64 2,373.64 304.48 581.64 2,512,089.59 214,351.39 3.30 641.30 NSG_WL(2) 2,722.00 31.45 84.18 2,582.52 2,460.52 309.46 630.87 2,512,093.36 214,400.72 3.58 690.10 NSG_WL(2) 2,822.00 34.68 84.33 2,666.32 2,544.32 314.92 685.15 2,512,097.49 214,455.11 3.23 743.90 NSG_WL(2) 2,922.00 38.32 83.90 2,746.69 2,624.69 321.03 744.31 2,512,102.15 214,514.40 3.65 802.58 NSG_WL(2) 3,022.00 41.68 83.58 2,823.28 2,701.28 328.04 808.19 2,512,107.60 214,578.44 3.37 866.05 NSG_WL(2) 3,122.00 42.78 83.63 2,897.33 2,775.33 335.53 874.98 2,512,113.44 214,645.40 1.10 932.46 NSG_WL(2) 3,222.00 42.17 83.75 2,971.08 2,849.08 342.95 942.10 2,512,119.22 214,712.67 0.62 999.16 NSG_WL(2) 3,322.00 41.77 83.80 3,045.43 2,923.43 350.20 1,008.58 2,512,124.84 214,779.31 0.40 1,065.20 NSG_WL(2) 3,422.00 41.28 83.83 3,120.30 2,998.30 357.34 1,074.49 2,512,130.37 214,845.37 0.49 1,130.67 NSG_WL(2) 3,522.00 40.77 85.22 3,195.74 3,073.74 363.61 1,139.82 2,512,135.04 214,910.84 1.05 1,195.35 NSG_WL(2) 3,622.00 38.73 92.57 3,272.67 3,150.67 364.93 1,203.65 2,512,134.79 214,974.69 5.12 1,257.27 NSG_WL(2) 3,722.00 39.55 99.13 3,350.26 3,228.26 358.47 1,266.37 2,512,126.80 215,037.22 4.22 1,316.07 NSG_WL(2) 3,822.00 42.63 100.87 3,425.62 3,303.62 347.03 1,331.08 2,512,113.78 215,101.63 3.29 1,375.48 NSG_WL(2) 3,922.00 43.83 101.53 3,498.48 3,376.48 333.72 1,398.26 2,512,098.83 215,168.47 1.28 1,436.79 NSG_WL(2) 4,022.00 44.48 101.75 3,570.23 3,448.23 319.67 1,466.49 2,512,083.11 215,236.33 0.67 1,498.90 NSG_WL(2) 4,122.00 44.82 102.60 3,641.37 3,519.37 304.84 1,535.18 2,512,066.61 215,304.64 0.69 1,561.27 NSG_WL(2) 4,222.00 45.53 103.12 3,711.86 3,589.86 289.06 1,604.33 2,512,049.13 215,373.38 0.80 1,623.82 NSG_WL(2) 4,322.00 46.10 104.10 3,781.56 3,659.56 272.18 1,674.02 2,512,030.56 215,442.64 0.90 1,686.60 NSG_WL(2) 4,422.00 46.93 104.83 3,850.38 3,728.38 254.05 1,744.28 2,512,010.72 215,512.43 0.98 1,749.60 NSG_WL(2) 4,522.00 47.17 104.25 3,918.51 3,796.51 235.68 1,815.13 2,511,990.61 215,582.81 0.49 1,813.11 NSG_WL(2) 4,622.00 43.95 97.23 3,988.56 3,866.56 222.27 1,885.15 2,511,975.50 215,652.49 5.95 1,877.14 NSG_WL(2) 4,722.00 42.03 89.68 4,061.76 3,939.76 218.09 1,953.11 2,511,969.65 215,720.32 5.49 1,941.59 NSG_WL(2) 4,822.00 44.53 89.32 4,134.55 4,012.55 218.69 2,021.66 2,511,968.57 215,788.86 2.51 2,007.88 NSG_WL(2) 4,922.00 46.23 90.43 4,204.79 4,082.79 218.84 2,092.83 2,511,966.98 215,860.01 1.87 2,076.58 NSG_WL(2) 1. 5,022.00 45.87 90.68 4,274.20 4,152.20 218.14 2,164.82 2,511,964.52 215,931.96 0.40 2,145.84 NSG_WL(2) 2/3/2017 12:45:30PM Page 3 COMPASS 5000.1 Build 81 1. • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well K-06RD2 Project: Trading Bay TVD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Site: King Salmon MD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Well: K-06RD2 North Reference: True Wellbore: K-06RD2 Survey Calculation Method: Minimum Curvature Design: K-06RD2 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 5,122.00 46.35 91.60 4,343.52 4,221.52 216.70 2,236.87 2,511,961.32 216,003.96 0.82 2,214.97 NSG_WL(2) 5,222.00 47.47 92.48 4,411.84 4,289.84 214.10 2,309.85 2,511,956.93 216,076.85 1.29 2,284.69 NSG_WL(2) 5,322.00 49.03 92.97 4,478.42 4,356.42 210.55 2,384.37 2,511,951.55 216,151.26 1.60 2,355.64 NSG_WL(2) 5,422.00 50.50 93.82 4,543.02 4,421.02 206.02 2,460.57 2,511,945.16 216,227.33 1.61 2,427.96 NSG_WL(2) 5,522.00 51.78 94.85 4,605.76 4,483.76 200.13 2,538.21 2,511,937.37 216,304.80 1.51 2,501.31 NSG_WL(2) 5,622.00 52.68 95.58 4,667.01 4,545.01 192.94 2,616.93 2,511,928.26 216,383.32 1.07 2,575.36 NSG_WL(2) 5,722.00 52.63 95.88 4,727.67 4,605.67 185.00 2,696.03 2,511,918.39 216,462.20 0.24 2,649.58 NSG_WL(2) 5,822.00 51.27 96.63 4,789.30 4,667.30 176.43 2,774.31 2,511,907.90 216,540.25 1.48 2,722.83 NSG_WL(2) 5,922.00 50.83 97.00 4,852.17 4,730.17 167.20 2,851.53 2,511,896.79 216,617.22 0.53 2,794.89 NSG_WL(2) 6,022.00 50.55 97.12 4,915.52 4,793.52 157.69 2,928.32 2,511,885.40 216,693.75 0.29 2,866.46 NSG_WL(2) 6,122.00 49.37 97.73 4,979.85 4,857.85 147.80 3,004.23 2,511,873.65 216,769.40 1.27 2,937.09 NSG_WL(2) 6,222.00 49.02 98.18 5,045.20 4,923.20 137.33 3,079.20 2,511,861.35 216,844.08 0.49 3,006.65 NSG_WL(2) 6,322.00 48.73 98.27 5,110.97 4,988.97 126.55 3,153.75 2,511,848.75 216,918.35 0.30 3,075.74 NSG_WL(2) 6,422.00 47.38 98.52 5,177.81 5,055.81 115.69 3,227.33 2,511,836.09 216,991.64 1.36 3,143.86 NSG_WL(2) 6,522.00 47.22 99.27 5,245.62 5,123.62 104.33 3,299.94 2,511,822.96 217,063.95 0.57 3,210.91 NSG_WL(2) 6,622.00 47.15 99.67 5,313.59 5,191.59 92.26 3,372.29 2,511,809.12 217,135.98 0.30 3,277.53 NSG_WL(2) 6,722.00 46.55 100.38 5,381.98 5,259.98 79.57 3,444.13 2,511,794.67 217,207.49 0.79 3,343.49 NSG_WL(2) 6,822.00 47.40 100.40 5,450.21 5,328.21 66.38 3,516.04 2,511,779.73 217,279.05 0.85 3,409.39 NSG_WL(2) 6,922.00 46.65 100.93 5,518.38 5,396.38 52.84 3,587.94 2,511,764.43 217,350.60 0.84 3,475.19 NSG_WL(2) 7,022.00 46.83 101.53 5,586.91 5,464.91 38.66 3,659.37 2,511,748.50 217,421.66 0.47 3,540.36 NSG_WL(2) 7,122.00 47.05 101.83 5,655.19 5,533.19 23.87 3,730.92 2,511,731.97 217,492.83 0.31 3,605.49 NSG_WL(2) 7,222.00 47.12 102.18 5,723.28 5,601.28 8.63 3,802.56 2,511,714.98 217,564.07 0.27 3,670.58 NSG_WL(2) 7,322.00 46.75 102.62 5,791.56 5,669.56 -7.05 3,873.91 2,511,697.55 217,635.02 0.49 3,735.28 NSG_WL(2) 7,422.00 46.90 102.83 5,859.98 5,737.98 -23.12 3,945.04 2,511,679.75 217,705.74 0.21 3,799.68 NSG_WL(2) 7,522.00 46.48 103.22 5,928.58 5,806.58 -39.51 4,015.94 2,511,661.63 217,776.21 0.51 3,863.75 NSG_WL(2) 7,622.00 44.43 103.58 5,998.72 5,876.72 -56.03 4,085.26 2,511,643.42 217,845.11 2.07 3,926.28 NSG_WL(2) 7,722.00 43.70 103.80 6,070.58 5,948.58 -72.49 4,152.83 2,511,625.31 217,912.25 0.75 3,987.13 NSG_WL(2) 7,822.00 42.85 103.40 6,143.38 6,021.38 -88.61 4,219.46 2,511,607.57 217,978.47 0.89 4,047.16 NSG_WL(2) 7,922.00 41.32 102.92 6,217.60 6,095.60 -103.87 4,284.72 2,511,590.71 218,043.33 1.56 4,106.10 NSG_WL(2) 8,022.00 40.75 103.25 6,293.03 6,171.03 -118.73 4,348.67 2,511,574.29 218,106.90 0.61 4,163.87 NSG_WL(2) 8,062.72 40.52 103.76 6,323.93 6,201.93 -124.92 4,374.45 2,511,567.47 218,132.52 0.99 4,187.11 MWD_InterpAzi+sag(3) 8,128.93 39.82 104.23 6,374.52 6,252.52 -135.25 4,415.89 2,511,556.13 218,173.70 1.15 4,224.37 MWD_InterpAzi+sag(3) 8,193.35 37.76 104.75 6,424.73 6,302.73 -145.34 4,454.97 2,511,545.08 218,212.51 3.24 4,259.41 MWD_InterpAzi+sag(3) 8,255.75 34.17 105.32 6,475.23 6,353.23 -154.84 4,490.36 2,511,534.72 218,247.66 5.78 4,291.04 MWD_InterpAzi+sag(3) 8,315.54 30.90 105.95 6,525.63 6,403.63 -163.50 4,521.32 2,511,525.31 218,278.40 5.50 4,318.64 MWD_InterpAzi+sag(3) 8,379.41 27.36 106.74 6,581.41 6,459.41 -172.24 4,551.15 2,511,515.84 218,308.01 5.58 4,345.11 MWD+SC+sag(4) 8,441.21 26.00 106.32 6,636.63 6,514.63 -180.13 4,577.75 2,511,507.30 218,334.41 2.22 4,368.70 MWD+SC+sag(4) 8,504.27 24.40 110.45 6,693.69 6,571.69 -188.57 4,603.22 2,511,498.24 218,359.66 3.77 4,391.05 MWD+SC+sag(4) 8,566.37 23.78 112.05 6,750.38 6,628.38 -197.75 4,626.85 2,511,488.48 218,383.06 1.45 4,411.42 MWD+SC+sag(4) 8,629.39 23.43 114.00 6,808.13 6,686.13 -207.62 4,650.07 2,511,478.05 218,406.03 1.36 4,431.22 MWD+SC+sag(4) 2/3/2017 12:45:30PM - Page 4 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report .�s Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well K-06RD2 Project: Trading Bay TVD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Site: King Salmon MD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Well: K-06RD2 North Reference: True Wellbore: K-06RD2 Survey Calculation Method: Minimum Curvature Design: K-06RD2 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 8,689.99 21.96 117.25 6,864.04 6,742.04 -217.71 4,671.15 2,511,467.45 218,426.86 3.19 4,448.90 MWD+SC+sag(4) 8,751.61 19.74 121.64 6,921.62 6,799.62 -228.44 4,690.26 2,511,456.25 218,445.70 4.40 4,464.51 MWD+SC+sag(4) 8,813.55 16.15 126.52 6,980.54 6,858.54 -239.06 4,706.09 2,511,445.24 218,461.27 6.28 4,476.99 MWD+SC+sag(4) 8,877.77 12.85 123.64 7,042.71 6,920.71 -248.33 4,719.22 2,511,435.65 218,474.16 5.26 4,487.21 MWD+SC+sag(4) 8,939.47 11.56 120.29 7,103.01 6,981.01 -255.25 4,730.27 2,511,428.46 218,485.04 2.38 4,496.05 MWD+SC+sag(4) 8,999.84 11.48 126.04 7,162.17 7,040.17 -261.84 4,740.35 2,511,421.63 218,494.96 1.91 4,504.04 MWD+SC+sag(4) 9,062.28 9.40 129.35 7,223.57 7,101.57 -268.73 4,749.32 2,511,414.53 218,503.75 3.47 4,510.87 MWD+SC+sag(4) 9,126.13 7.09 150.18 7,286.77 7,164.77 -275.46 4,755.31 2,511,407.66 218,509.58 5.86 4,514.88 MWD+SC+sag(4) 9,154.96 6.89 162.17 7,315.39 7,193.39 -278.65 4,756.73 2,511,404.43 218,510.92 5.10 4,515.41 MWD+SC+sag(4) 9,215.62 6.99 188.25 7,375.62 7,253.62 -285.76 4,757.31 2,511,397.30 218,511.33 5.15 4,514.10 MWD+SC+sag(4) 9,278.77 7.09 207.43 7,438.30 7,316.30 -293.03 4,754.97 2,511,390.10 218,508.80 3.71 4,509.92 MWD+SC+sag(4) 9,340.79 8.49 222.79 7,499.76 7,377.76 -299.79 4,750.09 2,511,383.46 218,503.76 4.03 4,503.44 MWD+SC+sag(4) 9,401.98 9.50 237.92 7,560.20 7,438.20 -305.78 4,742.74 2,511,377.65 218,496.27 4.19 4,494.77 MWD+SC+sag(4) 9,462.87 9.90 250.77 7,620.23 7,498.23 -310.18 4,733.54 2,511,373.48 218,486.97 3.61 4,484.74 MWD+SC+sag(4) 9,525.89 12.04 260.08 7,682.10 7,560.10 -313.09 4,721.95 2,511,370.85 218,475.31 4.40 4,472.79 MWD+SC+sag(4) 9,588.21 13.82 263.47 7,742.84 7,620.84 -315.06 4,708.15 2,511,369.22 218,461.46 3.10 4,458.96 MWD+SC+sag(4) 9,650.25 15.20 265.08 7,802.90 7,680.90 -316.60 4,692.69 2,511,368.06 218,445.96 2.32 4,443.63 MWD+SC+sag(4) 9,711.56 16.24 265.61 7,861.91 7,739.91 -317.95 4,676.13 2,511,367.12 218,429.38 1.71 4,427.30 MWD+SC+sag(4) 9,773.12 16.60 265.09 7,920.96 7,798.96 -319.36 4,658.79 2,511,366.13 218,412.01 0.63 4,410.20 MWD+SC+sag(4) 9,836.48 16.43 268.03 7,981.71 7,859.71 -320.44 4,640.81 2,511,365.49 218,394.01 1.35 4,392.58 MWD+SC+sag(4) 9,898.28 16.50 270.21 8,040.97 7,918.97 -320.71 4,623.30 2,511,365.65 218,376.50 1.01 4,375.61 MWD+SC+sag(4) 9,960.04 16.85 269.64 8,100.14 7,978.14 -320.73 4,605.58 2,511,366.06 218,358.78 0.63 4,358.51 MWD+SC+sag(4) 10,021.98 16.58 269.10 8,159.46 8,037.46 -320.93 4,587.77 2,511,366.30 218,340.97 0.50 4,341.28 MWD+SC+sag(4) 10,082.52 15.75 266.82 8,217.61 8,095.61 -321.52 4,570.93 2,511,366.12 218,324.12 1.73 4,324.87 MWD+SC+sag(4) 10,144.86 14.35 269.13 8,277.81 8,155.81 -322.11 4,554.75 2,511,365.93 218,307.94 2.44 4,309.12 MWD+SC+sag(4) 10,207.12 12.48 274.57 8,338.37 8,216.37 -321.69 4,540.33 2,511,366.70 218,293.53 3.62 4,295.32 MWD+SC+sag(4) 10,269.83 10.93 278.30 8,399.77 8,277.77 -320.29 4,527.69 2,511,368.41 218,280.93 2.75 4,283.49 MWD+SC+sag(4) 10,331.26 10.17 286.11 8,460.17 8,338.17 -317.94 4,516.72 2,511,371.02 218,270.02 2.63 4,273.52 MWD+SC+sag(4) 10,392.76 10.37 295.83 8,520.69 8,398.69 -314.02 4,506.52 2,511,375.19 218,259.92 2.83 4,264.72 MWD+SC+sag(4) 10,455.62 10.18 305.83 8,582.54 8,460.54 -308.31 4,496.92 2,511,381.14 218,250.46 2.85 4,256.96 MWD+SC+sag(4) 10,516.27 10.38 315.85 8,642.23 8,520.23 -301.25 4,488.77 2,511,388.40 218,242.49 2.96 4,250.96 MWD+SC+sag(4) 10,577.84 10.26 326.50 8,702.80 8,580.80 -292.70 4,481.88 2,511,397.12 218,235.81 3.10 4,246.56 MWD+SC+sag(4) 10,638.50 11.87 335.08 8,762.34 8,640.34 -282.53 4,476.27 2,511,407.41 218,230.45 3.79 4,243.83 MWD+SC+sag(4) 10,701.72 14.14 339.76 8,823.94 8,701.94 -269.39 4,470.86 2,511,420.69 218,225.36 3.96 4,242.07 MWD+SC+sag(4) 10,763.01 15.99 344.89 8,883.12 8,761.12 -254.21 4,466.07 2,511,435.97 218,220.94 3.72 4,241.44 MWD+SC+sag(4) 10,824.24 17.38 350.10 8,941.77 8,819.77 -237.06 4,462.30 2,511,453.21 218,217.59 3.33 4,242.32 MWD+SC+sag(4) 10,887.07 17.92 351.18 9,001.65 8,879.65 -218.26 4,459.20 2,511,472.08 218,214.96 1.01 4,244.29 MWD+SC+sag(4) 10,949.66 19.12 351.14 9,060.99 8,938.99 -198.62 4,456.15 2,511,491.79 218,212.38 1.92 4,246.51 MWD+SC+sag(4) 11,028.85 21.88 354.78 9,135.16 9,013.16 -171.10 4,452.80 2,511,519.38 218,209.72 3.84 4,250.54 MWD+SC+sag(4) 11,085.79 24.90 355.36 9,187.42 9,065.42 -148.58 4,450.87 2,511,541.94 218,208.33 5.32 4,254.60 MWD+SC+sag(4) 2/3/2017 12:45:30PM Page 5 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well K-06RD2 Project: Trading Bay TVD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Site: King Salmon MD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Well: K-06RD2 North Reference: True Wellbore: K-06RD2 Survey Calculation Method: Minimum Curvature Design: K-06RD2 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 11,148.85 26.68 355.95 9,244.20 9,122.20 -121.23 4,448.79 2,511,569.34 218,206.93 2.85 4,259.80 MWD+SC+sag(4) 11,209.84 29.59 358.13 9,297.97 9,175.97 -92.51 4,447.34 2,511,598.08 218,206.18 5.06 4,265.96 MWD+SC+sag(4) 11,272.93 32.78 357.27 9,351.94 9,229.94 -59.88 4,446.01 2,511,630.74 218,205.65 5.11 4,273.28 MWD+SC+sag(4) 11,331.63 36.52 357.38 9,400.22 9,278.22 -26.54 4,444.46 2,511,664.10 218,204.91 6.37 4,280.56 MWD+SC+sag(4) 11,395.40 39.33 358.89 9,450.52 9,328.52 12.62 4,443.20 2,511,703.29 218,204.61 4.64 4,289.66 MWD+SC+sag(4) 11,456.01 45.86 358.16 9,495.12 9,373.12 53.61 4,442.13 2,511,744.29 218,204.55 10.80 4,299.42 MWD+SC+sag(4) 11,517.61 50.38 0.56 9,536.23 9,414.23 99.45 4,441.65 2,511,790.13 218,205.19 7.89 4,311.03 MWD+SC+sag(4) 11,581.72 56.75 4.74 9,574.30 9,452.30 150.93 4,444.11 2,511,841.52 218,208.91 11.23 4,326.96 MWD+SC+sag(4) 11,642.51 62.95 8.34 9,604.82 9,482.82 203.10 4,450.14 2,511,893.54 218,216.22 11.41 4,346.52 MWD+SC+sag(4) 11,706.88 67.25 11.04 9,631.92 9,509.92 260.63 4,459.99 2,511,950.81 218,227.47 7.69 4,371.18 MWD+SC+sag(4) 11,768.20 72.65 12.11 9,652.94 9,530.94 317.04 4,471.55 2,512,006.92 218,240.41 8.96 4,397.19 MWD+SC+sag(4) 11,829.40 78.74 15.19 9,668.06 9,546.06 374.63 4,485.56 2,512,064.15 218,255.82 11.08 4,425.87 MWD+SC+sag(4) 11,921.39 86.29 22.67 9,680.05 9,558.05 460.76 4,515.16 2,512,149.53 218,287.52 11.50 4,477.10 MWD+SC+sag(4) 11,983.33 85.91 24.59 9,684.26 9,562.26 517.37 4,539.92 2,512,205.51 218,313.67 3.15 4,515.90 MWD+SC+sag(4) 12,047.58 84.37 28.37 9,689.71 9,567.71 574.66 4,568.46 2,512,262.09 218,343.60 6.33 4,558.52 MWD+SC+sag(4) 12,109.52 83.90 31.28 9,696.04 9,574.04 628.11 4,599.10 2,512,314.77 218,375.54 4.73 4,602.16 MWD+SC+sag(4) 12,172.06 84.24 32.56 9,702.50 9,580.50 680.91 4,631.99 2,512,366.75 218,409.71 2.11 4,647.79 MWD+SC+sag(4) 12,234.09 83.80 34.62 9,708.96 9,586.96 732.30 4,666.12 2,512,417.29 218,445.08 3.38 4,694.25 MWD+SC+sag(4) 12,297.05 85.05 37.32 9,715.08 9,593.08 783.01 4,702.92 2,512,467.08 218,483.12 4.71 4,743.11 MWD+SC+sag(4) 12,360.39 85.96 37.36 9,720.04 9,598.04 833.21 4,741.22 2,512,516.33 218,522.63 1.44 4,793.28 MWD+SC+sag(4) 12,427.96 86.09 38.74 9,724.73 9,602.73 886.29 4,782.77 2,512,568.37 218,565.47 2.05 4,847.33 MWD+SC+sag(4) 12,490.04 82.36 39.33 9,730.97 9,608.97 934.26 4,821.66 2,512,615.37 218,605.52 6.08 4,897.49 MWD+SC+sag(4) 12,553.01 81.22 43.06 9,739.97 9,617.97 981.15 4,862.70 2,512,661.25 218,647.69 6.14 4,949.42 MWD+SC+sag(4) 12,616.47 82.31 47.17 9,749.06 9,627.06 1,025.46 4,907.19 2,512,704.45 218,693.26 6.64 5,004.01 MWD+SC+sag(4) 12,676.08 82.56 49.76 9,756.91 9,634.91 1,064.63 4,951.42 2,512,742.53 218,738.43 4.33 5,057.00 MWD+SC+sag(4) 12,739.16 81.37 53.44 9,765.73 9,643.73 1,103.43 5,000.36 2,512,780.12 218,788.30 6.08 5,114.43 MWD+SC+sag(4) 12,802.38 82.18 56.51 9,774.78 9,652.78 1,139.33 5,051.59 2,512,814.76 218,840.40 4.97 5,173.31 MWD+SC+sag(4) 12,864.83 82.61 56.73 9,783.04 9,661.04 1,173.39 5,103.28 2,512,847.54 218,892.91 0.77 5,232.14 MWD+SC+sag(4) 12,927.85 82.80 56.25 9,791.04 9,669.04 1,207.90 5,155.40 2,512,880.76 218,945.86 0.81 5,291.51 MWD+SC+sag(4) 12,990.43 82.49 56.34 9,799.05 9,677.05 1,242.34 5,207.03 2,512,913.93 218,998.32 0.52 5,350.39 MWD+SC+sag(4) 13,050.98 82.43 56.09 9,807.00 9,685.00 1,275.72 5,256.92 2,512,946.08 219,049.01 0.42 5,407.31 MWD+SC+sag(4) 13,112.98 83.05 56.19 9,814.83 9,692.83 1,309.99 5,307.99 2,512,979.08 219,100.90 1.01 5,465.60 MWD+SC+sag(4) 13,176.45 83.18 56.39 9,822.44 9,700.44 1,344.96 5,360.41 2,513,012.76 219,154.16 0.37 5,525.38 MWD+SC+sag(4) 13,239.13 83.14 55.49 9,829.91 9,707.91 1,379.81 5,411.97 2,513,046.34 219,206.55 1.43 5,584.30 MWD+SC+sag(4) 13,283.22 81.73 55.21 9,835.71 9,713.71 1,404.66 5,447.92 2,513,070.30 219,243.10 3.26 5,625.53 MWD+SC+sag(4) 13,322.00 81.73 55.21 9,841.29 9,719.29 1,426.56 5,479.44 2,513,091.42 219,275.15 0.00 5,661.70 PROJECTED to TD mitchell.laird@halliburton.com "Dp1d°'m„,a sos.1erw"°41d"`i,,,e,,,,,,,,y,,, Checked By: 2017.02.0309:4705-09.00' Approved By: Michael Calkinsz1- � ,,, Date: 2/3/2017 2/3/2017 12.45:30PM Page 6 COMPASS 5000.1 Build 81 • • Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. MRF K-06RD2 Date Run 10-Feb-17 County State Alaska Supv. Hauck/Lawrence CASING RECORD Liner V TD 13,322.00 Shoe Depth: 13,320.00 PBTD: No.Jts.Delivered No.Jts.Run 138 No.Jts.Returned 16 Casing(Or Liner)Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top Shoe 7 5/8 1.61 13,320.00 13,318.39 2 Casing 7 5/8 29.7 L-80 511 Tenaris 78.17 13,318.39 13,240.22 Float Collar 7 5/8 1.51 13,240.22 13,238.71 1 Casing 7 5/8 29.7 L-80 511 Tenaris 39.88 13,238.71 13,198.83 Landing Collar 7 5/8 1.80 13,198.83 13,197.03 135 Casing 7 5/8 29.7 L-80 511 Tenaris 5,237.65 13,197.03 7,959.38 Pup Joint 7 5/8 7.43 7,959.39 7,951.95 Liner Hanger Assy 7 5/8 19.06 7,951.95 7,932.89 Csg Wt.On Hook: 280 Type Float Collar: WOTCO No.Hrs to Run: 24 Csg Wt.On Slips: 100 Type of Shoe: WOTCO Casing Crew: WOTCO Rotate Csg Yes X No Recip Csg Yes X No 50 Ft.Min. 9.15 PPG Fluid Description: 9.15 PPG OBM Liner hanger Info(Make/Model): Baker HRD-E In-Line liner hanger packer Liner top Packer?: X Yes _No Liner hanger test pressure: Floats Held X Yes_ No Centralizer Placement: CEMENTING REPORT Shoe @ 13320 FC @ 13,197.00 Top of Liner 7932 Preflush(Spacer) Type: G Density(ppg) 12 Volume pumped(BBLs) 15.2 Lead Slurry Type: G Sacks: 236 Yield: 1.33 Density(ppg) 15.3 Volume pumped(BBLs) 62.5 Mixing/Pumping Rate(bpm): 2.5 Tail Slurry w Type: Sacks: Yield: F Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): I— Post Flush(Spacer) ix Type: Density(ppg) Rate(bpm): Volume: LL Displacement: Type: OBM Density(ppg) 9.15 Rate(bpm): 5 Volume(actual/calculated): 345.2/346.5 FCP(psi): 800 Pump used for disp: Rig Bump Plug? X Yes No Bump press 1300 Casing Rotated? Yes X No Reciprocated? Yes X No %Returns during job 73"" Cement returns to surface? Yes X No Spacer returns? Yes X No Vol to Surf: 0 Cement In Place At: 12:35 Date: 2/10/2017 Estimated TOC: 10,930 Method Used To Determine TOC: Displacement Returns C_� ( . .. alee' 4,0 Post Job Calculations: J r ^— / �: Calculated Cmt Vol @ 0%excess: 49.8 Total Volume cmt Pumped: 62.5 Cmt returned to surface: 0 Calculated cement left in wellbore: 62.5 OH volume Calculated: OH volume actual: Actual%Washout: www.wellez.net WellEz Information Management LLC ver_102716bf • • K-06RD2 Days vs Depth 0 500 -K-06RD2 Actual 1000 K-06RD2 Plan 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 s 6500 7000 v 7500 aui 8000 2 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 , 0 10 20 30 40 50 60 70 80 Days 3/24/2017 9:41 AM • • K-06RD2 MW vs Depth 0 -K-06RD2 Plan 1000 -K-06RD2 Actual 2000 3000 4000 5000 6000 L C1 7000 G1 z H 8000 9000 10000 11000 12000 13000 14000 8.0 9.0 10.0 11.0 12.0 13.0 14.0 Mud Density(ppg) IIMIIIIIMIIMIIIIIIIIIIIMIIIIIIIIIIMITIIIIMIIIIIIMIIIMIIIOIIMIMIIMIMMIIIMIMIIMMMMIMIIIMMIIIIIIIIIIIIIII VOFTJi g,... I y/,�s, THE STATE Alaska Oil and Gas r �, o e T e c K A Conservation Commission -,,5,-, -IIf1ZLr1V���I1 � sf�� �� 333 West Seventh Avenue 4e Mr.- ' GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 114 Main: 907.279.1433 OF ALAS� Fax: 907.276.7542 www.aogcc.alaska.gov March 14, 2017 Mr. Stan Golis Operations Manager—CI Offshore Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 RE: No-Flow Verification Trading Bay Unit K-06RD2 PTD 2161310 Dear Mr. Golis: On March 11, 2017, an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no-flow test of Trading Bay Unit K-06RD2 located on the King Salmon Platform in Cook Inlet. The well is operated by Hilcorp Alaska, LLC (Hilcorp). The AOGCC Inspector confirmed that the proper test equipment — as outlined in AOGCC Industry Guidance Bulletin 10-004 — was rigged up on Trading Bay Unit K-06RD2 prior to the test. The well performance was monitored for three hours then opened to flow. Well pressures bled to zero within 3 minutes. An initial gas flow rate of 900 SCF per hour declined to 450 SCF per hour within the same 3-minute period. There was no liquid flow to surface during the no-flow test. The well may be produced without a subsurface safety valve. A fail-safe automatic surface safety valve system capable of preventing uncontrolled flow must be maintained in proper working condition in this well as required in 20 AAC 25.265. The subsurface safety valve must be returned to service if Trading Bay Unit K-06RD2 demonstrates an ability to flow unassisted to surface. Any cleanout, perforating or other stimulation work in this well will necessitate a subsequent no flow test. Please retain a copy of this letter on the King Salmon Platform. Sincerely, -- _ James B. Regg Petroleum Inspection Supervisor cc: P. Brooks AOGCC Inspectors • _1 (0_ 1 ( Debra Oudean Hilcorp Alaska, LLC • Co1 GeoTech II 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8337 Ililr�yr� al.�4 1,3.t. Fax: 907 777-8510 E-mail: doudean@hilcorp.com DATE 3/06/2017 To: Alaska Oil & Gas Conservation Commission RECEIVED Meredith Guhl, Petroleum Geology Assistant 333 W. 7th Ave. Ste#100 MAR 0 6 2017 Anchorage, AK 99501 AOGCC DATA TRANSMITTAL K-06RD2 (216-131) Transmitted herewith are cuttings from K-06RD2 WELL BOX # SAMPLE INTERVAL ' TBU K-06RD2 BOX 1 8063'- 9300' TBU K-06RD2 BOX 2 9300'- 10530' TBU K-06RD2 BOX 3 10530'- 11560' TBU K-06RD2 BOX 4 11560' - 11950' TBU K-06RD2 BOX 5 11950'- 12350' TBU K-06RD2 BOX 6 12350'- 12760' TBU K-06RD2 BOX 7 12760'- 13140' TBU K-06RD2 BOX 8 13140'- 13322' Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: 11) i 216131 Debra Oudean Hilcorp Alaska, LLC AK_GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 O v p Tele: 907 777-8337 2 HilenrpAlnrkn.1.1H RECEIVED Fax: 907 777-8510 2 8 0 2 4 E-mail: doudean@hilcorp.com MAR 01 2017 DATE: 3/1/2017 AOGCC 4ATA LOGGED To: AOGCC '`+ 3 /2/2017 vl:K.BENDER Makana Bender 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL TBU K-06RD2 CANRIG FINAL WELL DATA CD Daily Reports 2/22/2017 4:34 PM File folder i... DML Data 2/22/2017 4:34 PM File folder $ Final Well Report 2/22/2017 4:34 PM File folder LAS Data 2/22/2017 4:34 PM File folder Log PDFs 2/22/2017 4:34 PM File folder Log TIFFS 2/22/2017 4:34 PM File folder Sample Photographs 2/22/2017 4:34 PM File folder Show Reports 2/22/2017 4:34 PM File folder CANRIG FINAL WELL DATA PRINTS Sin Formation Log MD / TVD 2in Formation Log MD / TVD LWD Combo Log MD / TVD Gas Ration Log MD / TVD Drilling Dynamics MD / TVD HALLIBURTON FINAL WELL DATA CD _Log Viewers COY Defn te Survey 2/28/2017 1:27 PM File folder SW 2/28/2017 1:27 PM File folder LAS 2/28/2017 1:27 PM File folder 2/28/2017 1:27 PM File folder 1== 2/28/2017 1:27 PM File folder Prints: ROP DGR EWR-Phase4 ALD CTN MD DGR EWR-Phase 4 ALD CTN TVD Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received 8 ✓�� Date: or zit, �9 THE STATE Alaska Oil and Gas N�►rt�� ofALASKA AS Conservation Commission 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 i 77 04t,, ,n'- Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Stan W. Golis Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage,AK 99503 Re: McArthur River Field, Hemlock Oil Pool, TBU K-06RD2 Permit to Drill Number: 216-131 Sundry Number: 316-629 Dear Mr. Golis: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received 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, W8i,614.4.441 .._ Cathy 7 Foerster Chair DATED this 0 day of February, 2017. RBDMS 1,L FEB - 7 2617 • • RECEIVED STATE OF ALASKA 2016 ALASKA OIL AND GAS CONSERVATION COMMISSION r APPLICATION FOR SUNDRY APPROVALS �� � �7 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate 0 Other Stimulate Cl Pull Tubing ❑ Change Approved Program❑ Plug for Redrili Cl Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other. ESP Completion pr 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC , Exploratory ❑ Development Er ° 216-131 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number. Anchorage,AK 99503 50-733-20088-02 , 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 228A• Will planned perforations require a spacing exception? Yes ❑ No l]/ Trading Bay Unit K-06RD2 9.Property Designation(Lease Nuumber): 10.Field/Pool(s): ADL00187721 / 9"i McArthur River Field/Hemlock Oil Pool , 11. PRESENT WELL CONDITION SUMMARY TqI e th IID(Ub Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): ±1y,i " oposed ±9,811'(Proposed) ±13,220'(Proposed) ±9,807'(Proposed) 3,044 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 376' 24" 376' 376' Surface 2,186' 13-3/8" 2,186' 2,092' 3,090 psi 1,540 psi Intermediate Production ±8,100'(Proposed) 9-5/8" ±8,100'(Proposed) ±6,366'(Proposed) 6,870 psi 4,760 psi Liner ±5,443(Proposed) 7-5/8" ±13,343'(Proposed) ±9,811'(Proposed) 6,890 psi 4,790 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A N/A 12.Attachments: Proposal Summary El Wellbore schematic D 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ Stratigraphic❑ Development CI 4 Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 1/9/2017 Commencing Operations: OIL CI i 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 Dan Marlowe(907)283-1329 Email dmarlowe@hilcorp.com Printed Name Stan W.Golis Title Operations Manager Signature 4.� Phone (907)777-8356 Date t , 6 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number:, ( 2-9 Plug Integrity ❑ BOP Test/ Mechanical Integrity Test ❑ Location Clearance ❑ 145 C l' 3 1111 �' P 350(.5z 1 � Other: " s` r er rpt.ti �r RBDMS 1,c, FEB ` 7 27 Post Initial Injection MIT Req'd? Yes Cl No Spacing Exception Required? Yes ❑ No 2" Subsequent Form Required: / 6 - T 0 7 (6r KJ 1,..),r/iv APPROVED BY / Approved by: f "`4, COMMISSIONER THE COMMISSION Date: 2 -3 ?' r?- ` -2- 7/� ���� tiM6 �v 34�Submit Form and Form 10-403 Revised 11/2015 0li ld for 12 hs from the date of appro Attachments in Duplicate • • Well Work Prognosis Well: K-06rd2 Hilcorp Alaska,LLC PTD:216-131 Date: 12/15/2016 Well Name: K-06rd2 API Number: 50-733-20088-02 Current Status: Sidetracked Producer Leg: Leg#4 (NW corner) Estimated Start Date: January 9,2017 Rig: Kuukpik#5 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett(8332) Permit to Drill Number: 216-131 First Call Engineer: Dan Marlowe (907) 283-1329 (0) (907)398-9904(M) Second Call Engineer: Monty Myers (907) 777-8431 (0) (907) 538-1168(M) Current Bottom Hole Pressure: 4,004 psi @ 9,607'TVD 0.417 lbs/ft(8.02 ppg)based on offset K-13rd2 Maximum Expected BHP: 4,004 psi @ 9,607'TVD 0.417 lbs/ft(8.02 ppg)based on offset K-13rd2 Maximum Potential Surface Pressure:3,044 psi / Using 0.1 psi/ft gradient 20 MC 25.280(b)(4) Brief Well Summary K-6rd2 is a Hemlock only producer that will be completed with an ESP.This new well was side tracked from the current K-06rd which is a shut-in gas-lifted Hemlock producer. This workover will perforate and run the completion string in the new well. / Last Casing Test: Casing and liner tested to 2,500 psi under PTD 216-131 Procedure: 1. ***Take over operations from the Drilling Sidetrack Program *** 2. Test BOP to 250psi low/3,500psi high. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 3. Workover fluids will be 6% KCL. nI C! t"-- 4. Rig up E-Line and run cased hole logging suite. POOH. 5. PU TCP guns, RIH and perforate per program. 46)44:-(.._ 6 6. After detonation, circulate out any perf gas, confirm well is static, POOH. rec��{z 7. PU and run ESP completion. • A high set packer, packer vent valve, and SSSV will be ran if well indicates ability to flow to surface. 8. If applicable-Set and test packer to 1,500 psig charting for 30 minutes. 9. Set BPV. NU tree,test same. 10. Turn well over to production 11. Schedule SVS testing with AOGCC as per regulations. 12. If applicable-Schedule no-flow with AOGCC as per regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Proposed 4. BOP Drawing 5. Fluid Flow Diagrams 6. RWO Sundry Revision Change Form SCHEMATIC McArthur River Field Well: K-06RD2 Hilcorp Alaska,LLC CASING DETAIL J SIZE WT GRADE CONN TOP BTM. Description L24" - - - Surf 376' Conductor 13-3/8" 61 J-55 BTC Surf 2,186' Casing 9-5/8" 53 S-95 BTC Surf 1,968' Casing 9-5/8" 47 L-80 BTC 1,968' 7,100' Casing 7-5/8" 29.7 L-80 Hyd 511 7,900' 13,343' Liner 13-3/8" Z. 1 JEWELRY DETAIL ID Item Depth 9 5/g, No Depth(MD) (ND) 2 , �°�` 1 ±7,900' ±5,503' 6.059" Inline Baker Liner Hanger/Packer 2 ±8,100' ±5,640' - KOP 3 ±7,900'- 13,343' ±9,663' 6.059" 7-5/8" 29.7#L-80 HYD 511 3 CEMENT DETAIL .-. a No TOC Depth TOC Depth Volume Item (MD) (TVD) ±10,000' ±7,459' 63 bbls 15.3 ppg Class G cement w/%2 bbl cemnet LCM .. , 4 '1 L`' ,t '+ 7-5/8" TD=13,343'MD PBTD=13,220'MD Max Hole Angle=85° Updated By:CJD 10/7/16 ' H • • McArthur River Field Well:TBU K-06RD2 • PROPOSED PTD: 216131 API: 50-733-20088-02 Hilcorp.Alaska,LLC Rk2J All? C/&f,�i,l) Last Completed: Future / CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 24" - - - Surf 376' L, 13-3/8" 61 J-55 BTC 12.515" Surf 2,186' Ll._ 9-5/8" 53.5 S-95 BTC 8.535" Surf 1,968' L"--. a 9-5/8" 47 L-80 BTC 8.681" 1,968' 8,062'(TOW) z Hyd 511 6.875 ±7,874' TUBING DETAIL L-80 Supermax 3.958" Surf JEWELRY DETAIL Depth No DMDh TVD ID OD Item Tubing Hanger ±350' 5.965" Contingent—SSSV 1 13-3/8" _38O ±380' .956 8.312" Contingent—ESP Dual Packer w/WFT vent valve 4 '400' ±400' 813" 5.570" Contingent-X-nipple Discharge,Bolt-On N1 6.750" Pumps(x2)45 Stg SG16000AR N/4 5.130" Seals N/A 5.620" (2)562 500HP Motors KMLST(1,000HP/3600V/165.5A 4 ±7,8u N/A Centralizer Anode 111I r Liner Hanger Mn ID 6.670" 8-1/2"TOW 8,063' 9-5/8" PERFORATION DETAIL Zone Top MD Btm MD Top TVD BTM TVD FT Date Status • r . . r � -I L • 7-5/8" TD=13,322'MD Max Hole Angle=86.29°@ 11,921' Updated By:JLL 12/15/16 0 • McArthur River Field ‘ H j Well:TBU K-06RD2 PROPOSED ✓ 5031 API:50-73733-20088-02 Hilcorp Alaska,LLC Last Completed: Future CASING DETAIL SIZE WT GRADE CONN ID TOP BT . NII 24" II24" BTC 12.515" Surf Surf '76' 9-5/8" 53.5 5-95 BTC 8.535" Surf 1,968' ii 9-5/8" 47 L-80 BTC 8.681" 1,968' ±8,100'(TOW) 7-5/8" 29.7 L-80 Hyd 511 6.875" ±7,900' ±13,343' TUBING DETAIL 4-1/2" 12.6 L-80 Supermax 3.958" Su ±7,750' ✓ JEWELRY DET IL No Depth Depth ID OD Ite' MD TVD 1 ±350' ±350' 3.813" 5.965" Contingent—SSSV 2 ±380' ±380' 3.958" 8.312" Contingent—High set packer with vent valve 13-3/8" 3 ±400' ±400' 3.813" 5.5 4" Contingent-X-nipple G . . 4 ±7,850' ±6,159' N/A 6 50" Bottom of ESP 0• , fe. i ii ,,,i , _ . ill 9-5/8' / i/ PERFORATION DETAIL ne Top MD Btm MD Top TVD BTM TVD FT Date Status H-1 ±11,636' ±11,770' ±9,607' ±9,650' ±134' FUTURE H-2 ±11,722' ±13,322' ±9,652' ±9,795' ±1,600' FUTURE 1 rd r.,J 1r4 r `IR / 1�. � t, , ,W, i 1 ",tt11,,i r` q 7-5/8" ID=13,343'MD PBTD=13,220MD Max Hole Angle=85" Updated By:JLL 12/15/16 • • . 11King Salmon Platform K-06RD2 Proposed 10/19/20116 lid.of]. ‘h,.<•I.lit King Salmon Tbg hanger,OCT-UH-TC-1A- K-06RD2 ESP,13 X 4%IBT lift and 24 X 133/8 X 95/8 X 4% susp,w/4"Type H BPV profile,3/8 cont control line port BHTA,B-11-A0,4 1/16 5M FE Mal III St 1•11 Valve,Swab,WKM-M,4 1/16 5M I> 1 G �% FE,HWO,EE trim llQc- v • Valve,Wing,WKM-M,3 1/8 5M FE,w/ m:■: :■u: OMNI oper,EE trim Valve,Wing,WKM-M,2 1/16 5M N /� FE,HWO,AA trim i �' . 5...),131 1 AtIC_): 1: lej Valve,Master,WKM-M,4 1/16 5M A,------,C• tirriii,p7FE,HWO,EEtrim I–�° •O a:■, uno '�G Valve,Wing,CIW-FL,3i 1/8 5M FE, �.$ HWO,EE trim I . i totr4 Adapter,OCT-A5-ESP,13 5/8 5M API hub * Q X 4 1/16 5M stdd top,w/2-'A control iiiizi — line exits,prepped w/OCT 400-4 pocket ilil' ii r ° it III 11 All unihead annular valves, Unihead,OCT type 3,13 5/8 5M API �� ; ,, ,:' ` r, 2 1/16 5M FE OCT-20,HWO hub top X 13 3/8 BTC casing bottom, ■1•11a II IS-4:1$' 10 I'' / l= =� : w/1-2 1 16 5M SSO on lower :I. _ section,1-2 1/16 5M SSO on middle - • :- section,3-2 1/16 5M SSO on upper I•� RI e n section,IP internal lockpin asst' 1 = 1 (10-!..]a� •i•.: y; �. =moo!; _ �;,; - - ply Valve,OCT-20,3 1/8 2M FE, Starting head,OCT,21'/<2M FE X lli F •ii r4 i ' _ ® HWO 24"SOW,w/1-31/82MEFO,full Iv j ,, set of lockpins _j ____ 13 3/8" 9 5/8" ^I 4,A„ i • King Salmon Platform 2016 BOP Stack(Kuukpik) 06/22/2016 Hileorp:tIneka.1.1A. Rig Floor 111111711 16" Pipe 111.11,11101 •III lit fain fain tL 3.74' Shaffer 13 5/8 5M I t 11Th rfll rtfi tt Shaffer SL - 2 7/8-5.5 Variables 2.83' - 135/85M Blind n' 2 1/16 5M manual and HCR valve 2 1/16 5M manual and HCR valve 7�, 111 111 111 ltl lil . 14 1.76 '�1.i , 1�� � . 111 111 III IDI Ill �.�Al. �• !!! Shaffer SL ezwi 11111108 13 5 5M - 2 7/8-5.5 Variables 1.44' 111 1111!1 lil Drill deck 13.70Riser 13 5/8 5M FE X 13 5/8 5M API hub • • Choke Manifold Valves 2 " 3" To Shaker 3" Panic To Gasbuster 3 1/8"_ 2 1/16" I ~O O 21%6" Emm,,Em 0 i I[ , I(Th, (8 I O 21/1 (13' 2 1/16" + N 3 1/8" �. r © �� + , N L + ,(9, J , , ,, ,1 21/16" 1/16" Manual Choke 1 Automatic Choke 2 1/16 Inlet Pressure Sensor 3" 3" 5,000 PSI Choke Manifold Kuukpik Drilling Rig 5 RED = 3 1/18" 5,000 PSI VALVES AND LINES BLUE = 2 1/16" 5,000 PSI VALVES Kuukpik Drilling Rig 5 Choke Manifold N la 1 • • E s., bp a i-oi i,0i a lvi 1 I A^" a o, y, a, a, o y, a, a. a, '8I a_I '8l '8I a a 0.0 O1v!Olulpa• v!Oj01 oytill• t i l ^" =1 1 4'1 :1 I 1 1 -Ci a— :a.' 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SiC i IU'iaiSIU'1(� l of IQgI I I 1 IQgi I i i!!13,1g!�111I!,n!II I: I:I I.II: I: I` I: I: I vn `O I ,:1 40.:.,0. bA .1I41,N1,N1,N!N!N!N!N! V 411143111 1 I-ti 0 1 1 I 1 1 I I 1 1 bA 0 a ..INlenlslml•e11--10010.1 CL i, i i i i i i l l i .- M 9 �f d - .°a U Kuukpik 5 BOP Test Procedure Ilarorp.Ala Aka,1.11Attachment#1 Attachment #1 Hilcorp Alaska LLC. Rolling BOP Test Procedure: Kuukpik 5 — Oil/Gas Producers, Water/Gas Injectors Initial Test(i.e.Tubing Hanger is in the Wellhead) If BPV profile &lift threads were deemed good, but still unable to get good tests 1) If both set of threads appear to be bad and unable to hold a pressure test and/or a penetrator leaks, notify Operations Engineer(Hilcorp), Guy Schwartz (AOGCC-guy.schwartz@alaska.gov),Jim Regg (AOGCC-jim.regg@alaska.gov ) and Michael Quick (AOGCC—Michael.quick@alaska.gov)via email explaining the wellhead situation prior to performing the rolling test. If on Federal land contact BLM representative Amanda Eagle (aeagle@blm.com) and Mutasim Elganzoory(melganzoory@blm.com). AOGCC and BLM may elect to send an inspector to witness. As outlined and approved in the sundry, proceed as follows: 2) With stack out of the test path, test choke manifold per standard procedure 3) Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) Kill and choke line valve will also be tested during this time. 4) During these tests the test chart needs to be set to 60 min instead of 12 hours so chart shows a better graph. Need to station hands in cellar going over all connections on the BOPs looking for the slightest leak.Also need a man looking down the hole to confirm that the BOPs are not leaking. Test# 1=Annular, HCR Choke, and HCR Kill. Test#2=Upper Pipe Rams, HCR Choke, and HCR Kill. Test#3=Upper Pipe Rams, Manual Choke, and Manual Kill. Test#4=Lower Pipe Rams. 5) Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. 6) Once the BOP ram and annular tests are completed,test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) 7) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile/penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 8) Pull hanger to surface. (Making tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid and sweep off any oil cap that may be present. 9) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the pwf completion tubing. Re-land hanger(or test plug) in tubing head. Test BOPE as per Kuukpik's standard test procedure. Or POOH laying down all the tubing and use the normal test plug to finish I' the tests that were not completed as per regulatory approval. Kuukpik 5 BOP Test Procedure Hilrorp:%Iacki.I I I Attachment#1 If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on. Profile and/or landing threads must be prepped while tree is off.Worst Case: BPV profile and landing threads are bad. 1) Attempt to set BPV through tree and test. May have to tap out if scaled up or paraffined up if well is not dead may have to be done w/ pressure lubricator (diesel or acid could help) 2) If unsuccessful, or BPV profile is eroded and well is dead. Best practice is to have two barriers a. Fluid column b. Set wire line plug or tag fluid level with slick line to establish static fluid level or shoot fluid level with an echo meter gun. 3) Shoot off tubing very shallow ( 300-500' most likely just under SSSV if applicable) 4) Spear hanger w/ upside down cup provided by fishing company 5) Proceed to get best test we can achieve against cup and confirm no visual leaks on all flanges of BOPE 6) Notify Hilcorp Anchorage Operations Engineer and AOGCC of situation 7) Pull hanger and cut off stub 8) P/U test plug and set same. 9) Perform complete BOPE test as per Kuukpik's standard procedure . • • 8Ci / _c c2 R 6 U c 77 So § / 0 2 0 L § ƒ « , Ef e S3 2 - f § I a m E » a < L'.- k / 2 - m Y � k � i �� k 22 a CI % .D•• co -0 a) a)ow 222 a a $ c t �' 0 0 co Ce 3 / @ "0 I- � � @ 22 ut-si -a ft U. CD OCD.cp ■ 9 CU 1§ 0)Ca • CO Q 20 a) a / a) 43) 0 E m ° 0 c 2 2 0 : a i kf a \ k (5 c -a (5 C ra -a § p c 2 > 2R . @ o § � ■ o / Q A ) 0 L. CD . ..x cl cx .2 as 8 § a.o � ° 0 2 a) 1- 0) \ a Q o Ell e ii / Q iz Go .. ® _a .. V ,-1 Ctia) C E 0 Jasc a_ 2 k k COcoCI) a. 2 • • Bettis, Patricia K (DOA) From: Dan Marlowe <dmarlowe@hilcorp.com> Sent: Friday, February 03, 2017 7:24 AM To: Schwartz, Guy L(DOA) Cc: Juanita Lovett; Bettis, Patricia K(DOA) Subject: RE: K-06RD2 PTD 216-131 Update Attachments: K-06RD2 Proposed Completion - 2017-01-27.doc Guy Here is final perf selection All Hemlock Bench 2 (we will save bench 1 for a later workover)Still on schedule to swap to completion sundry mid to late next week Thanks Dan Marlowe Hilcorp Alaska, LLC Operations Engineer Office 907-283-1329 Cell 907-398-9904 Fax 907-283-1315 Email DMarlowe@hilcorp.com Hilcorp A Company Built on Energy Original Message From: Schwartz, Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent:January 27, 2017 2:09 PM To: Dan Marlowe<dmarlowe@hilcorp.com> Cc:Juanita Lovett<jlovett@hilcorp.com>; Bettis, Patricia K (DOA)<patricia.bettis@alaska.gov> Subject: RE: K-06RD2 PTD 216-131 Update Dan, Sounds good... have the sundry here waiting on final perf zones. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793- 1226 ) or(Guy.schwartz@alaska.gov). 1 • • Original Message From: Dan Marlowe [mailto:dmarlowe@hilcorp.com] Sent: Friday,January 27, 2017 1:39 PM To: Schwartz, Guy L(DOA) <guy.schwartz@alaska.gov> Cc:Juanita Lovett<jlovett@hilcorp.com> Subject: K-06RD2 PTD 216-131 Update Guy We called TD on K-06rd2 this morning at 13,322.7'. We will pull out of hole, swap to a BHA loaded with Nuke's for the final logging/cleanout run. After that is complete, I will send you a revised schematic with final perf selection. We anticipate being ready to swap over to completion sundry the week of February 5th if all goes well. Dan Marlowe Hilcorp Alaska, LLC Operations Engineer Office 907-283-1329 Cell 907-398-9904 Fax 907-283-1315 Email DMarlowe@hilcorp.com Hilcorp A Company Built on Energy 2 OF 7•4, . S 6.,41‘\��\�yy�,A. THE STATE Alaska Oil and Gas o F ;,-s f LASKA Conservation Commission _ A 333 West Seventh Avenue o GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 off'A g11Fax: 907.276.7542 www.aogcc.alaska.gov Monty Myers Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: McArthur River Field, Hemlock Oil Pool, TBU K-06RD2 Hilcorp Alaska, LLC Permit to Drill Number: 216-131 revised Surface Location: 736' FSL, 135' FEL, SEC. 17, T9N, R13W, SM, AK Bottomhole Location: 2263' FSL, 225' FWL, SEC. 15, T9N, R13W, 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 November 17, 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, Daniel T. Seamount, Jr. Commissioner DATED this tf day of December, 2016. N. V IP STATE OF ALASKA DEC 0 7 2016 A(A OIL AND GAS CONSERVATI 11 ON PERMIT TO DRIL Revised .—il , ', ., 20 AAC 25.005 - 1 a.Type of Work: 1 b.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 El Gas Hydrates ❑ Redrill 0 Reentry ❑ Exploratory-Oil ❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket ❑✓ Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC Bond No. 022035244 TBU K-06RD2 3.Address: 6. Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 MD: 13,343' . TVD: 9,791' McArthur River Field 4a. Location of Well(Governmental Section): 7. Property Designation(Lease Number): Hemlock Oil Pool Surface: 736'FSL, 135'FEL,Sec 17,T9N,R13W,SM,AK (SHL,TPH)ADL017594(BHL)ADL018772 Top of Productive Horizon: 8. Land Use Permit: 13.Approximate Spud Date: 962'FSL,744'FEL,Sec 16,T9N,R13W,SM,AK N/A 12/12/2016 Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 2263'FSL,225'FWL,Sec 15,T9N, R13W,SM,AK 8956 Acres 6,064'to nearest unit boundary 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL(ft): 122' 15.Distance to Nearest Well Open Surface: x-213762 y-2511799 Zone-4 GL Elevation above MSL(ft): 73' to Same Pool: 770'K-13RD2 16.Deviated wells: Kickoff depth: 8,100' feet s 17.Maximum Potential Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 85.5 degrees • Downhole: 4685 Surface: 2471 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD _ TVD (including stage data) 8-1/2" 7-5/8" 29.7# L-80 Hyd 511 5,443' 7,900' 6,206' 13,343' 9,791' 263 sx/352 ft3 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth TVD(ft): Plugs(measured): Effect.Depth MD(ft): Effect. Depth TVD(ft): Junk(measured): 13,276' 10,070' N/A 13,042' 9,879' 9,400' Casing Length Size Cement Volume MD TVD Conductor/Structural 376' 24" To Surface 376' 376' Surface 2,186' 13-3/8" 1760 sx 2,092' 2,092' Intermediate Production 11,958' 9-5/8" 1,050 sx 9,055' 9,055' Liner 1,415' 7" 585 sx 9,917' 9,917' Perforation Depth MD(ft): Perforation Depth TVD(ft): 20. Attachments: Property Plat 0 BOP Sketch ❑✓ Drilling Program ❑l Time v.Depth Plot ❑l Shallow Hazard Analysis E Diverter Sketch ❑ Seabed Report El Drilling Fluid Program El20 AAC 25.050 requirements❑ 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Email mmyers(a�hilcorp.com Printed Name M•jty Myers Title Drilling Engineer 600 y ... ,A) f°jL Signature "V)/ / r 1 - ,Q /t4onfiy /VI Phone 907-777-8431/ Date 12/7/2016 / Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other Number: \(..¢', 22 \ (€ ' 50-"7 3 - ZOO%T-OZ'GU Date: \\, V,-\ requirements. l Conditions of approval: If box is checked,twell may not be used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained in shales: Ti Other: .� 3 5a: / ) p,S 6 ,/- �../..e! s f- Samples req'd: Yes ❑ No R" Mud log req'd:Yes III No 21.21.!, k ` NtAS n cul e_u.l!al- c ,� H2S measures: Yes p' No Directional svy req'd:Yes[t�No❑ Spacing_ .exception req'd: Yes ❑ No Inclination-only svy req'd:Yes❑ No[►j Z4) "-C- Z'U C/S (c C yCt. Post initial injection MIT req'd:Yesill No El 5uh cXw4 I y-C.ric,Lt...-"--;.j.-C4 64=1- et"� (p d471/4. 4-4- C�� t? } ,�1 0.1 v 1 APPROVED BY / z (� Approved by /.77)it COMMISSIONER/ THE COMMISSION Date: J I fk L r 2_^T_/4 �' i'Y ?/I- , 13-7W Submit Form and Form 10-401(Rev' d 11/2015) oniRpircilfx months from the date of approval(20 AAC 25.005(g)) Attachments in Duplicate .1 Hilcorp Alaska, LLC • Monty Myers • P.O. Box 244027 Anchorage,AK 99524-4027 4'1 Drilling Engineer Tel 907 777 8431 Email mmyers@hilcorp.com Hilcorp Energy Company 12/7/2016 Commissioner Alaska Oil &Gas Conservation Commission IV D 333 W. 7t"Avenue Anchorage, Alaska 99501 DEC ® 7 2016 Re: K-06RD2 Revised PTD 9 AOGC 56/ ge-jt er2 Dear Commissioner, K-06RD2 is an oil production well planned to be re-drilled in a North-easterly direction from the existing K-06RD utilizing the existing casing program down to 8100' MD/6352' TVD. At 8100' MD the parent wellbore will be sidetracked and new wellbore drilled penetrating several Z17 Hemlock targets. A 5243'x 8-1/2"open hole section is planned. W�S (.0,,AP A 7-5/8" 29.7# L-80 HYD 511 prod liner will be run, cemented, and perforated based on data obtained Cep while drilling the interval. The well will be completed with a 3-1/2" ESP completion. Drilling operations are expected to commence approximately December 12th, 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 1 of 1 • • Hilcorp Alaska, LLC K-06RD2 Drilling Program McArthur River by: M M141146, Revision 1 December 6, 2016 • • K-06RD2 Drilling Procedure Rev 0 IIiIcorp 11a.ka,1.1.1: 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 10 10.0 BOP N/U and Test 11 11.0 Mud Program and Density Selection Criteria 12 12.0 Whipstock Running Procedure 13 13.0 Whipstock Setting Procedure 16 14.0 Drill 8-1/2"Hole Section 19 15.0 Run 7-5/8"Production Liner 22 16.0 Cement 7-5/8"Production Liner 25 17.0 Wellbore Clean Up& Displacement 29 18.0 Run Completion Assembly 30 19.0 RD 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 Fluid Flow Diagrams 39 29.0 Offset MW vs. Depth TVD 42 30.0 Casing Design Information 43 31.0 8-1/2"Hole Section MASP 44 32.0 Plot(NAD 27) (Governmental Sections) 45 33.0 Slot Diagram (As Built) (NAD 27) 46 34.0 Directional Program(wp07) 48 • • K-06RD2 Drilling Procedure Rev 0 Ili14•0rp;'Iu.ka.I.1.I: 1.0 Well Summary Well K-06RD2 Pad&Old Well Designation Sidetrack of existing well K-06RD(PTD#188-028) Planned Completion Type 7-5/8"29.7# L-80 Liner, 3-1/2"Tubing w/ESP Target Reservoir(s) Hemlock Producer H1-H3 Planned Well TD, MD/TVD 13343' MD/9791' TVD PBTD, MD/TVD 13220' MD/9782' TVD Surface Location(Governmental) 736' FSL, 135' FEL, Sec 17, T9N, R13W, SM,AK Surface Location(NAD 27) X=213762.47, Y=2511799.44 Surface Location(NAD 83) Top of Productive Horizon (Governmental) 962'FSL, 744'FEL, Sec 16, T9N,R13W, SM,AK TPH Location(NAD 27) X=218436.29,Y=2511922.93 TPH Location(NAD 83) BHL(Governmental) 2263'FSL,225'FWL, Sec 15, T9N, R13W, SM,AK BHL(NAD 27) X=219434.99, Y=2513199.91 BHL(NAD 83) AFE Number 1613025D AFE Drilling Days AFE Drilling Amount $4.6 MM Work String 4" 14# S-135 XT-39(From Weatherford) RKB—AMSL 122' MSL to ML 73' BOP Equipment 13-5/8" 5M Hydril"GK"Annular BOP 13-5/8" 5M Cameron Type U Double Ram 13-5/8" 5M Cameron Type U Single Ram Page 2 Revision 1 December, 2016 • K-06RD2 Drilling Procedure Rev 0 Ilikorp Ala.+ka, 2.0 Management of Change Information Hilcorp Alaska, LLC Hilcorp E Comer Changes to Approved Permit to Drill Date: October 7,2016 Subject Changes to Approved Permit to Drill for K-06RD2 File#: K-06RD2 Drilling Program Any modifications to K-06 R D2 Drilling Program will be documented and approved below. Changes to an approved APD will be communicated and approved by the AOGCC prior to continuing forward with work. Sec Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared: Monty M Myers 10.07.2016 Drilling Engineer Date Page 3 Revision 1 December, 2016 • K-06RD2 Drilling Procedure Rev 0 IIik orp Alaska. 3.0 Tubular Program Hole Section OD (in) Wt(#/ft) Coupl OD ID(in) Drift(in) Grade Conn Top Bottom 8-1/2" 7-5/8" 29.7 7.625 6.875 6.75 L-80 HYD 511 7900 13343 4.0 Drill Pipe Information Hole OD (in) ID (in) TJ ID TJ OD Wt Grade Conn Burst Collapse Tension Section (in) (in) (#/ft) (psi) (psi) (k-lbs) 8-1/2" 4" 3.34" 2.813" 4-7/8" 14 S-135 XT-39 17,820 13,836 403 All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Revision 1 December, 2016 • K-06RD2 Drilling Procedure Rev 0 Ilik•orp \la.ka.1.1.1: 5.0 Internal Reporting Requirements 5.1 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. 5.2 Afternoon Updates v. Submit a short operations update each work day to pmazzolini@hilcorp.com, Ikeller@hilcorp.com,mmyers@hilcorp.com and cdinger@hilcorp.com 5.3 5am Weekend Update vi. 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. vii. Copy pmazzolini@hilcorp.com, lkeller@hilcorp.com and mmyers@hilcorp.com 5.4 EHS Incident Reporting viii. 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. Leonard Dickerson: 0: (907) 777-8317 C: (907)252-7855 b. Mark Tornai: 0: (907)283-1372 C: (907) 748-3299 c. Thad Eby: 0: (907) 777-8317 C: (907)602-5178 2. Spills: a. Julieanna Orczewska: 0:907-777-8444 C:907-715-7060 b. Keegan Fleming: 0:907-777-8347 C:907-350-9439 ix. Notify Drlg Manager 1. Paul Mazzolini: 0: 907-777-8369 C: 907-317-1275 x. Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally xi. Send final"As-Run"Casing tally to mmyers@hilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cmt report xii. Send casing and cement report for each string of casing to mmyers@hilcorp.com and cdinger@hilcorp.com Page 5 Revision 1 December, 2016 • • K-06RD2 Drilling Procedure Rev 0 hili nr1, 'Ia.'.:.1.1.[ 6.0 Planned Wellbore Schematic SCHEMATIC McArt-06RD2hur r Field WellCASING DETAIL SIZE '.•:T GRADE CONN TOP &'i41.. Cesc•iatiar _ - Sur 575 CC-C..C7r -a-3;'S' cl 1-55 E-C Sur 2,L9a` Cas ng 4-515' 53 5-35 E'C Sur' 1?58' Casng 4-519' 47 __ E-C 1?59' 71,-,C Cas ng 29 7 !-vd SLi 7,4X' 15.345 Liner G L� JEWELRY DETAIL No Depth(MO) Dei ID Item 1 ±7,900' ±5,503' 6.059" Inline Baker Liner Hanger/Packer 2 ±8,100" ±5,640' - KOP - 3 ±7,900'-13,343' ±9,663' 6.059" 7-5/8"29.7#L-80 HYD 511 CEMENT DETAIL No TOOODeptfi TO(CNDepth Volume item ±10,000' ±7,459' 63 bbls 15.3 Dag Class G cement vi/3•4 j c,,gmngt LCM TD=13.343'tv1) MTG.13.2.1'r o tv�:hC e- Page 6 Revision 1 December, 2016 ! • 14K-06RD2 Drilling Procedure Rev 0 IliIcorp,Ua.ka.LLE: 7.0 Drilling Summary K-06RD2 is an oil production well planned to be re-drilled in a North-easterly direction from the existing K- 06RD utilizing the existing casing program down to 8100' MD/6352' TVD. At 8100' MD the parent wellbore will be sidetracked and new wellbore drilled penetrating several Hemlock targets. A 5243' x 8-1/2"open hole section is planned. A 7-5/8"29.7#L-80 HYD 511 prod liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with a 3-1/2"ESP completion. Drilling operations are expected to commence approximately December 12th, 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. Kuukpik Rig 5 will be over slot 30(K-06RD) to de-complete and P&A well under separate sundry. 2. DP should be stood back in derrick n- fsA- 3. PU whipstock, and mills and TIH to CIBP 4. Orient whipstock and set at 45 deg right of highside. 5. Mill 8-1/2"window and 20' of new formation at 8100'. 6. POOH and LD mills. PU directional BHA and TIH to window. v �� 7. Swap well to 9.0 ppg oil based drilling mud 8. Perform FIT to 12.5 ppg EMW 9. Drill 8-1/2" production hole from 8120' to 13343' MD, performing short trips as needed 10. Perform short trip and condition mud. POOH 11. LD Directional Tools. RIH w 7-5/8" liner. Set liner and cement. Circ wellbore clean. 12. POOH, laying down DP and liner running tools, 13. PU 7-5/8" casing scraper assembly and TIH to landing collar. 14. Circ casing clean. POOH laying down DP. 15. Run 3-1/2" completion. (Covered under separate sundry) 16. Land hanger and test. 17.ND BOPE,NU tree and test void Page 7 Revision 1 December, 2016 • i K-06RD2 Drilling Procedure Rev 0 Ilileurp:tlasku,1.1.1: 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 K-06RD2. Ensure to provide AOGCC 48 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 5/5 min(annular to 50%rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, we must test ALL BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system" • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements" • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. Variance Requests: o Hilcorp would like to request a variance to regulation 20 AAC 25.035(e)(4)(F)(i) which states - 1V. "the outlets must be at least two inches in nominal diameter, except that for rotary drilling rig 0/ operations, if the operation has a maximum potential surface pressure of greater than 3,000 psi, the nominal diameter of the choke outlets must be at least three inches". o The calculated MASP for this wellbore when completely evacuated to gas is 3218 psi. However, for Cook Inlet Operations, we assume that the well can never flow 100% gas, due to the water in t/ the reservoir. We reduce this MASP calculation to 2471 psi which assumes that only 2/3 of the wellbore is evacuated to gas and 1/3 to 9.0 ppg reservoir fluid. o Hilcorp would like to request to have 2-1/16" outlets on the choke line and kill line due to this assumption 4�- 726 l&� Page 8 Revision 1 December, 2016 • • K-06RD2 Drilling Procedure Rev 0 [Mori):Ua.ka. Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) • 13-5/8"Shaffer 5M annular • 13-5/8"5M Shaffer SL Double gate Initial Test:250/3500 • Blind ram in bottom cavity (Annular 2500 psi) 8-1/2" • Mud cross • 13-5/8"5M Shaffer SL single gate Subsequent Tests: • 3-1/16"5M Choke Manifold 250/3500 • Standpipe,floor valves,etc (Annular 2500 psi) • Primary closing unit: Control Technology Accumulator, 3000psi, 5 station, 170 gallon reservoir, 4 nitrogen backups and 12 bladder bottles. • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Secondary back-up is an air pump, and tertiary 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). • 48 hours notice prior to spud. • 48 hours notice prior to testing BOPs. • 48 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Additional requirements may be stipulated on APD. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email:jim.regg@alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-301-4533 /Email: guy.schwartz@alaska.gov Victoria Loepp/Petroleum Engineer/(0): 907-793-1247/Email: victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone: 907-793-1236 (During normal Business Hours) Notification/Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Revision 1 December, 2016 K-06RD2 Drilling Procedure Rev 0 ili•orp;Ua+ka,I.I.1: 9.0 R/U and Preparatory Work 9.1 Separate sundries will be submitted that will include the following: • Pull tubing • P&A lower perfs with a cement plug • Set CIBP 9.2 Mix mud for 8-1/2"hole section. 9.3 Verify 4.5" liners installed in mud pump#1 and 5.5" liners installed in pump#2. • Ellis Williams WH-1000 Pumps are rated at 3500 psi (100%)with 4.5" liners and can deliver 171 gpm at 86 spm. • TSM 1000 Pumps are rated at 3500 psi (100%)with 5.5" liners and can deliver 229 gpm at 86 spm. • Ideal pump rate for drilling will be 400 gpm. Both pumps running at 86 spm should achieve this. Pump#1 Ellis Williams WH1000 10" Stroke Pump#2 TSM 10009" Stroke 96% Efficiency Max psi 3500 psi 96%Efficiency Max psi 3500 psi Liner Size bbls/stroke Liner Size bbls/stroke 4.5 0.0472 5.5 0.0635 Strokes/minute bpm gpm Strokes/minute bpm gpm 20 0.94 40 20 1.27 53 40 1.89 79 40 2.54 107 60 2.83 119 60 3.81 160 86 4.06 171 86 5.46 229 100 4.72 198 100 6.35 267 120 5.67 238 120 7.62 320 140 6.61 278 150 7.08 297 Page 10 Revision 1 December, 2016 • i K-06RD2 Drilling Procedure Rev 0 IliIcorp Alaska,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 13-5/8"x 5M BOP as follows (top down): • 13-5/8"x 5M Shaffer annular BOP. • 13-5/8" Shaffer Type "SL" Double ram. (2-7/8"X 5-1/2" VBR in top cavity, blind ram in btm cavity) • 13-5/8"mud cross • 13-5/8" Shaffer Type "SL" single ram. (2-7/8"X 5-1/2"VBR) • N/U pitcher nipple, install flowline. • Install (2) manual valves on kill side of mud cross. Manual valve used as inside or"master valve". • Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 10.3 Run BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/3500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave "A" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Confirm the correct valves are opened!!! • Test 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 8-1/2" hole section. 10.6 Set wearbushing in wellhead. Ensure ID of wearbushing> 7-5/8". Page 11 Revision 1 December,2016 • K-06RD2 Drilling Procedure Rev 0 flavor!', lu.„ka. 11.0 Mud Program and Density Selection Criteria 11.1 8-1/2” Production hole mud program summary: Primary weighting material to be used for the hole section will be barite to minimize solids. We will have enough barite on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. Canrig PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.0 ppg 80/20 Enviromul MOBM Properties: MD Mud Weight viscosity PV YP HTHP WPS ES (PPg) 8,100—13,343' 9.0-9.5 / 50-80 25-35 15-22 <5 250-270K >580 System Formulation: 80/20 Enviromul MOBM Product Concentration LVT 0.662 bbl Water .172 bbl INVERMUL NT 4 ppb EZ MUL NT 4 ppb GELTONE V 6-10 ppb Lime 7 ppb DURATONE HT 2 ppb Calcium Chloride 21 ppb BAROID 41 9.0 ppg(as needed) BARACARB 5 3-5 ppb BARABLOK 2 ppb BAROTROL PLUS 4 ppb 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 12 Revision 1 December, 2016 K-06RD2 Drilling Procedure Rev 0 Ililrorp: Ia.+ka.1.1.1: 12.0 Whipstock Running Procedure Section 12.1 through 12.5 is covered under decompletion sundry, drilling proceed to 12.6 12.1 M/U window milling assembly and TIH w/4-1/2" DP out of derrick. • Use a 8-1/2"taper mill and an 8-1/2" 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 (8100' 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 Make up mills on a joint of HWDP. 12.7 RIH & set in slips. 12.8 Make up float sub, install float. 12.9 Leave assembly hanging in the elevators, and stand back on floor. 12.10 Bring Whipstock to rig floor on the pipe skate. Do not slam into bottom of Whipstock with pipe skate. 12.11 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. 12.12 If needed, open BOP Blinds. Page 13 Revision 1 December, 2016 • S K-06RD2 toiDrilling Procedure Rev 0 0111 tla,ka.LI 12.13 Run the Whipstock in the hole, install safety clamp as per Baker Rep, and install hole cover wrap. 12.14 Release pick up system at this point, Make up mills. 12.15 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. 12.16 The assembly can now be picked up to ensure that the shear bolt is tight. 12.17 Remove the handling system. 12.18 Slowly run in the hole as per Baker Rep. Run extremely slow through the BOP & wear bushing. 12.19 Run in hole at 1 1/2 to 2 minutes per stand. 12.20 Fill every 30 stands or as needed, do not rotate or work the string unnecessarily. 12.21 Call for Baker Rep. 15 — 10 stands before getting to bottom. 12.22 Orient at least 30' —45' above the CIBP. Page 14 Revision 1 December, 2016 ini • • K-06RD2 Drilling Procedure Rev 0 IIikorp Alaska,1.1.1: ` rat e -' Window Master G2 Whipstock BAKER VE With Torque Master Bottom Trip Anchor low 9.625 53.5#Non Special Drift Casing lei. At Baker Oil Tools • U • Upper Watermelon Mill ■ OD: 8.500 8.500 —I. TI 4-- 6.25 Length: 6.25 ( 11 Flex Joint _ OD: 6.375 I A Length: 9.00 W 6.375 —♦ I 4-- 9.00 Lower Watermelon Mill OD: 8.375 Length: 5.66 III M_ Window Mill 40.6 • OD: 8.500 8.250 4- 5.66 Length: 1.13 l Whipstock OD: 8.000 _ 112. 8.500 -0. _,�_ Length: 18.54 � � I 1.13 Face Angle: 1.9 • A t"" Face Length: 17.08 I II Retrieval BTA OD: 8.357 17.08 Length: 3.41 18.54 1.9 Overall length --► Length: 14' WELL INFORMATION CUSTOMER _ FIELD _ —Po =4-- 8.000 LEASE I ; WELL NO. '� SHEAR BOLT 25,000 3.41 1 '� 35,000 8.357 —► I ♦— 45,000 55,000 _65,000 75,000 NOTE DIM ENSIONS AR BASED ON IICHUNIT DATA.ACTUAL DIM RNSIONSMAYVARY Page 15 Revision 1 December, 2016 • • K-06RD2 Drilling Procedure Rev 0 Ilileorp:%la+ka.IIA 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 highside MWD. 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: 30 L HS 60 L HS Desired orientation of the Whipstock face is 45 degrees right of high side. Hole Angle at window interval (8100' MD) is 40 deg. The wellbore trajectory is planned to kick off at 104 degrees azimuth. 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 9.0 ppg 70/30 Enviromul MOBM. 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 16 Revision 1 December, 2016 • K-06RD2 Drilling Procedure Rev 0 Iiil•orp tIa.+ka.1.1.1: 13.10 Estimated metal cuttings volume from cutting window: Wieght of Cuttings For Milled Casing Exit O.D. Of Casing (in) 9.625 I.D. Of Casing (in) 8.535 Whipstock Face Length (Ft) 16.00 Percent of Casing Removed (%) ' 38 Milled Area (in^12) 5.908 Volume of Cuttings (inA3) 1134.272 Density of Casing (Ib.lin^3) " 0.283 Weight of Cutting Generated (lbs) 321.0 ' Calculated Average of Casing Removed Based on Drift Mills (38%) • Density of Steel = .283 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 —9.0) * 0.052 * 6352' tvd= 1156 psi 13.14 Kick Tolerance • (12.5-9.0) * (6352/9791) = 2.26 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 2.2 ppg kick tolerance while drilling the interval with a 9.0 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. Page 17 Revision 1 December, 2016 • • HK-06RD2 Drilling Procedure Rev 0 IIih orp;\laxka,I.1.1: Back Up Mills Connection Length O.D. WINDOW MILL 4 '/ REG-P X MILL 2.25 8.5 NEW LOWER WATERMELON MILL 4 '/ REG-P X 4 % REG-B 5.5 8.5 FLEX JOINT 4 1/2 REG-P X 4 '/ REG-B 9.0 6.375 STRING MILL 4 '/ REG-P X 4 % REG-B 5.5 8.5 FLOAT SUB 4 %" IF-B X 4 %2" REG-B 3.0 6.375 30 jts-HWDP 4 '/"XH-B X 4 %2" REG-P 900' 6.5 CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE. BHA'S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY! Page 18 Revision 1 December, 2016 410 • K-06RD2 Drilling Procedure Rev 0 Ililcorp; Iu"ka.I.I.1: 14.0 Drill 8-1/2" Hole Section 14.1 P/U 8-1/2" directional drilling assy. 14.2 Ensure BHA Components have been inspected previously. 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 0.51 -0.61 sqin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 375-450gpm. 14.6 Motor AKO should be set at 1.2 deg. Must keep up with 5 deg/100 DLS in the build section of the wellbore. 14.7 Primary bit will be the Varel 8-1/2" VM613P PDC bit. Ensure to have a back up bit available on location. COMPONENT DATA #leers Description Serial W v Length Cumulative I (in) (In (in , ° ( ,'Connection (It) Length (ft) 1 HOBS-PDC 8.400 2.500 8.500 172.13 P 4-1;2"REG 1.20 1.20 2 T SpenyDria Lobe 7/8-7.5 stg 7.000 4.952 95.69 B 4-112'IF 29.48 30.68 Stabilizer 8.375 3 Non Mag Float Sub 6.750 2.750 101.71 B 4-112'IF 3.00 33.68 4 Integral Blade 6.750 2.750 8.375 101.71 B 4-1/2-IF 3.60 37.28 5 6 314"DM Collar 6.750 3.125 103.40 B 4-112"IF 920 46.48 6 63/4"DGR Collar 6.750 1.920 97.80 B 4-112"IF 4.55 51.04 7 6 3/4'EWR-P4 Collar 6.750 2.000 104.30 B 4-112"IF 12.10 63.14 8 Inane Stabilizer(ILS) 6.750 1.920 8.375 112.09 B 4-112-IF 3.20 66.34 9 6 314"PWD 6.750 1.905 96.30 B 4-112"IF 4.44 70.78 10 6 3/4"HCIM Collar 6.750 1.920 101.70 B 4-112'IF 4.97 75.74 11 6 314"TM-HOC(Puller) 6.900 3.250 103.60 B 4-112"IF 15.50 91.24 12 6-3/4'Non Mag Flex Dry Cofar 6.750 2.813 100.77 B 4-112'IF 30.00 121.24 13 6-3/4'Non Mag Flex Drill Collar 6.750 2.813 100.77 B 4-112"IF 30.00 151.24 14 6-3/4"Non Mag Flex Drill Collar 6.750 1 2.813 100.77 30.00 181.24 15 6 Joint 5'HWDP 5.000 3.000 49.30 180.00 361.24 16 6.1/4'Weatherford Hydraulic Jar 6.250 2.250 91.01 30.00 391.24 17 14 Joints 5"HWDP 5.000 3.000 49.30 420.00 811.24 Total: 811.24 Page 19 Revision 1 December, 2016 • • K-06RD2 Drilling Procedure Rev 0 Ililcorp \la.ka.l.l,l: 8 1/2'4(215.3mm) �♦ r.. tne : Assembly: A09-48 V M 613 P ,Navigator IADC Code: M433 ' F • • t 1 PRODUCT SPECIFICATIONS \ 41TOCutter Size: 13 mm !, Cutter Back Up: 13mm PDC& Replaceable Shock Studs Total Cutter Count: 76 • �+ Face Cutter Count: 58 • `• • Connection: 4 1/2"API Regular / Nozzle 1 Qty/Type: 6-Series 55 I Nozzle 2 Qty/Type: - • Junk Slot Area: 14.3in2(92.3cm2) Gage Pad Length. 2 1/2"(64mm) Make Up Length: 11.4"(288.8mm) Shank Diameter: 5.8"(147.3mm) OPERATING PARAMETERS' Rotary Speed: For all rotary and motor applications Flowrate Min-Max: 250 -750GPM (0.95-2.84m3/min) Max Weight On Bit: 42000Ibs(18683daN) • • • Makeup Torque: 12000-16000Ft-Lbs. (16270-21693Nm) • • - • AIIP • 1 Navigator Series Bits -Varel's six step design 1 manufacturing process utilizes GeoScience interpreted logs. proprietary design software SPOT.3D modeling programs.CFD.and specialized manufacturing techniques to produce the best possible bit for the application Navigator bits are engineered to a specific Directional profile for a given application. Navigator bits possess the key design elements affecting bit steerability and directional behavior helping you achieve your drilling objectives Bit Features P -Partial PowerCutters'" provide extra cutter density on the shoulder reducing excessive wear or cutting structure damage when drilling interbedded formations. Shock Studs -Shock studs limit drill bit vibration and increase stability allowing smooth cutting action increasing cutter life and overall bit performance. Updrili Cutters -PDC cutters strategically placed to help reduce hole problems when up drilling or back reaming. Premium Gage -The premium gage consists of thermally stable polycrystalline diamond and pdc(polycrystalline diamond compact)cutters:designed to insure that correct hole diameter is maintained. VAR EL www.varelintl.com N Page 20 Revision 1 December, 2016 • • K-06RD2 Drilling Procedure Rev 0 IIilrurp 11a,ka.1.1f. 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 8-1/2"hole to 13343' MD using motor assembly. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • See attached mud program for hole cleaning and LCM strategies. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. • Ensure mud engineer set up to perform HTHP fluid loss. • Maintain API fluid loss < 6. • Take MWD surveys every stand drilled. • Minimize backreaming when working tight hole 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 1 December, 2016 • • K-06RD2 Drilling Procedure Rev 0 Iilror1 .tIu.ko,LIA: 15.0 Run 7-5/8" Production Liner clo * 7 ` 15.1 R/U Weatherford 7-5/8" casing running equipment. • Ensure 7-5/8" HYD 511 x 4"XT39 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 on stop rings, one per joint to 10,000' MD. • Ensure proper operation of float shoe & FC. 15.4 Continue running 7-5/8"production liner • Fill casing while running using fill up line on rig floor. • Use "API Modified"thread compound. Dope pin end only w/paint brush. • Install solid body centralizers on every other joint to window. Leave the centralizers free floating. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 7-5/8" HYD 511 M/U torques Casing OD Minimum Maximum Yield Torque 7-5/8" 5,900 ft-lbs 10,300 ft-lbs 52,000 ft-lbs Page 22 Revision 1 December, 2016 • K-06RD2 Drilling Procedure Rev 0 Ililcorp Alaska,LU.. Tenaris Hyd r Size: 7.625 in. Wall: 0.375 in. Weight: 29.70 lbs/ft Connection: Wedge 511T" Grade: [80.1 Casing/Tubing: CAS Min. Wall Thickness: 87.5 % PIPE BODY DATA GEOMETRY Standard Drift Nominal OD 7.625 in. Faominal Weight 29.70 lbs/ft 6.750 in. Diameter Special Drift i cr�ira! :D 6.875 in. Wall Thickness 0.375 in. N/A. Diameter Plain End Weight 29.06 Ibs/ft PERFORMANCE Bccy Yield 683 x 1000 lbs Internal Yield 6890 pl 80000 psi Strength Collapse 4790 psi WEDGE 511"' CONNECTION DATA GEOMETRY Correction OD 7.625 ir. Correction ID 6.787 in. Make-Up Loss 3.700 in. Critical Section 5.218 sq. in. Threads per in. 3.28 Area PERFORMANCE _VA 417 x 1000 Internal Pressure Tension Efficiency 61.1 ='n Joint Yield Strength 6890 psi lbs Capacity Compression Compression 504 x 1000 lbs 73.8°+b Bending 29°/100 ft Strength Efficiency External Pressure 4790 psi Capacity MAKE-UP TORQUES Minimum 5900 ft-lbs Optimum 7100 ft-lbs Maximum 1`) 10300 ft-lbs OPERATIONAL LIMIT TORQUES Operating Torque 35000 ft-lbs Yield Torque 52000 ft-lbs BLANKING DIMENSIONS Blanking Dimensions Page 23 Revision 1 December, 2016 • • K-06RD2 Drilling Procedure Rev 0 II i1(•nrp;11a.ka, 15.7 Ensure to run enough liner to provide for approx 200' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. 15.8 Before picking up Baker SDD 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 SDD 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 9-5/8"window prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 15.15 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 1 December, 2016 11 K-06RD2 Drilling Procedure Rev 0 Ililror1 Alu.+ka.I.1.1: 16.0 Cement 7-5/8" Production Liner • 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 15 bbls 12.5 ppg MUDPUSH II spacer. 16.4 Test surface cmt lines to 4500 psi. 16.5 Mix and pump 62.8 bbls of 15.3 ppg class"G" cmt per below recipe with 0.5 lb/bbl of Cemnet or equivalent loss circulation fiber. Ensure cmt is pumped at designed weight. Job is designed to pump 25% OH excess but if fluid caliper dictates otherwise we may increase excess volumes. Cement volume is designed to bring cement up to a minimum of 500' above hemlock in annulus of 7-5/8" casing and 8-1/2" open hole. Est TOC 10000' TMD. 16.6 Displacement fluid will be drilling mud. —368 bbls of displacement fluid Cement Calculations 8-1/2"OH x 7-5/8"Liner: (13343' — 10000') x 0.01371 x 1.25 = 57.3 bbls Shoe Track: 120' x 0.04591 = 5.5 bbls Total Volume(bbls): 57.3 + 5.5 = 62.8 bbls Total Volume(ft3): 62.8 bbls x 5.615 ft3/bbl= 352 ft3 Total Volume(sx): 352 ft3 / 1.34 ft3/sk= 263 sx Page 25 Revision 1 December, 2016 S K-06RD2 Drilling Procedure Rev 0 IIulrorp 1Iu,ka.I.I.I. 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 Code Description Concentration G Cement 94 lb/sk D046 Anti Foam 0.2% BWOC Additives D202 Dispersant 1.5% BWOC D400 Gas Control Agent 0.8% BWOC D154 Extender 8.0% BWOC 16.7 Drop DP dart and displace with drilling mud. 16.8 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 16.9 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns &pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 16.10 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. 16.11 Slack off total liner weight plus 30k to confirm hanger is set. 16.12 Do not overdisplace by more than '/2 shoe track(-1 bbls). Shoe track volume is 5.5 bbls. 16.13 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner Page 26 Revision 1 December, 2016 K-06RD2 Drilling Procedure Rev 0 Ilil•orp ua=Aa.LI 4 16.14 Bleed pressure to zero to check float equipment. 16.15 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve 16.16 Rotate slowly and slack off 50k downhole to set ZXP. 16.17 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS profile. 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). 16.18 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. 16.19 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. 16.20 Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 16.21 POOH, LDDP. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 16.22 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. 16.23 NOTE: Some hole conditions may require movement of the drillpipe to "work"the torque down to the setting tool. 16.24 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 1 December, 2016 K-06RD2 Drilling Procedure Rev 0 II Irorp.va•ka. 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 mmvers(iIJ,ilcorp.com Page 28 Revision 1 December, 2016 • • K-06RD2 Drilling Procedure Rev 0 IIih orp, la'ka.1.I,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. • 6-3/4" bit or mill • Casing scraper&brush for 7-5/8"29.7# casing • +/- 5000' 2-7/8" workstring. • Casing scraper&brush for 9-5/8" 53.5# casing • (2000') 4-1/2" DP • Casing scraper&brush for 9-5/8" 53.5# casing • 4-1/2" DP to surface. 17.2 TIH & clean out well to landing collar(+/- 13,080' 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 6-3/4"bit is worked down to the landing collar. • Space out the cleanout BHA so that the 6-3/4"bit reaches the 7-5/8" landing collar when crossover is +/- 30' above the 7-5/8" liner top. 17.3 After wellbore has been cleaned out satisfactorily using mud, test casing to 2500 psi/30 min. Ensure to chart record casing test. 17.4 Displace drilling fluid in wellbore with a hi-vis pill followed by filtered inlet water. • Circulate 3 to 4 B/U until clean-up is satisfactory. Do not recirculate fluid, pump and dump • After a couple circulations using FIW, short trip the assy to bring the upper 7-5/8"multi-back assy to surface. • RIH again&tag landing collar w/6-3/4" bit. Continue circulation as necessary until fluid cleans up. Make another short trip if necessary. • Pump a chemical train followed by FIW. Target NTU's are 80-100 17.5 TOH w/clean out assy. LDDP on the trip out. L/D the 2-7/8" work string. Page 29 Revision 1 December, 2016 • K-06RD2 Drilling Procedure Rev 0 11 ilrorp:Uaaka.1.1A: 18.0 Run Completion Assembly 18.1 Run 3-1/2"tubing completion assembly as per separate Approved Completion Sundry 19.0 RD 19.1 Install BPV in wellhead. RILDs. 19.2 ND BOPE,NU tree, test void 19.3 Rig Down Page 30 Revision 1 December, 2016 H • r K-06RD2 Drilling Procedure Rev 0 Ili!corp;1lawka,IAA: 20.0 BOP Schematic Rig Floor III III 16" Pipe 111 111 111111111 I! • •1 III III III 111 III 111 111 111 4111111 3.74' Shaffer III lit 111111 III AllElia IShaffer Si �y� 2 7/8.5.5 Variables 2.83' 133 5//8l�SM Blind mamP 2 1/16 5M manual and HCR valve 2 1116 5M manual valves III mitt III I I /,, 1.76 r' 1. V '' V II III III Ill IF, V 1111111* Shaffer Si 13 5 �SM 1- 1 f 2 7/8.5.5 Variables III III III III III Drill deck 13.70' Riser 135/8 SM FE X 13 5/8 SM API hub Page 31 Revision 1 December, 2016 40 • HK-06RD2 Drilling Procedure Rev 0 IliIcorp tla.,ka.I.IA 21.0 Wellhead Schematic King Salmon Tubing hanger,FMC-UH- K-6RD TC-IA-EN,13 5/8 SM X 4'A 24 X 13 3/8 X 9 5/8 X 3 1/2 IBT lift and susp,w/4"type IS BPV BHTA,B-11-A•0,4 1/16 5M FE Pro Valve,Swab,FMC-75, OP 4 1/16 SM FE,HWO,EE Valve,Wing,SSV, trim 1 ii, FMC-20,3 1/8 SM FE, ' 13"Axelson oper, a _ yeEE trim 1111 11 i / `iii, .. ' r , - , , 1,,, Valve,Master,FMC -75, 1/16 5M FE,HWO,,EE EE trim Adapter,FMC-ASP,13 5/8 SM . API clamp X 4 1/16 5M,w/7" extended neck pocket >`I. ;r-. AL Ili -_-_-: itti.. ii 1 =1 i f . i. :7, Unihead,OCT type 3,13 5/8 SM API Il I( I:r+ * I hub top X 13 3/8 BTC casing bottom, li a ' -410 : w/1-2 1/16 5M SSO on lower section,1-2 1/16 SM 55O on middle section,3-2 1/16 SM SSO on upper 7 section,IP internal lockpin assy CA2ll 16S annular valvesMare I �- ' :I l,..-4 li ,� s� 2 1/16 SM FMC 20 1111 .8f,j I� t k Starting head,FMC, 21 Y.2M X 24"SOW, '-' t op. = w/1-3 1/8 2M EFO i Mo I 1 61 ' I I I:'• _y13 3/A' -__.-1 ?,5/8" Page 32 Revision 1 December,2016 • • K-06RD2 Drilling Procedure Rev 0 Ililrorlt r la.ka.I.I.I: 22.0 Days vs Depth Days Vs Depth 0 K-06RD2 2000 4000 - — • 6000 a d f 8000 { 10000 12000 14000 0 5 10 15 20 25 30 Days Page 33 Revision 1 December, 2016 • H • K-06RD2 Drilling Procedure Rev 0 IliIcorp %Ia,'ka.I.1.1: 23.0 Geo-Prog GEOLOGICAL PROGNOSIS WELL NAME: K06RD2 i , FIELD' MCARTHUR RIVER .5'L 4.rE,'.` 213762,4; As-Built Survey .�'T4TE Alaska .5 4 Ei:` 25511799.44 B77.7Jr E,1's.` 219435,00 TVD REF DATLIM KB 5CTT17,1l:1r4 Ei. 2.513199,91 T':+D REF ELEV 122 Based on new rig contig. C t7 F.5)57EAs' NA 027 AK4r True North GROUND ELEV 0-0 FrY7F L7 TO 12243 MO 'w ATER DEPTH 73.0 ..c.1-71T97-3E0 7.12 37, / 1E/17 Drill a sidetrack out of the K-06RD(King Salmon)to test and complete the Hemlock H-1 thru H-2 wenches . Hit Target 1 at 57` INC and 37°AZM with 200'Pump Tangent a cove that. Build to 8515` INC and hold to ;_,,,,,n,,. 13343 MD. _-- ....m.,.3;,;, Based on subsurface evaluation KO6RD2 TARGETS,Alt ?PA TED FORMATION TOPS&GEONAZARDs 440 , r n ammo/ f 262, MrIIFT1 I IFr1 KOP Sand Conglomerate 7317 5,666 -5666 2453 8.33 COAL39 Coal 10831 9,137 -9015 3956 8.33 H IX_FW Sand r Conglomerate Oil Sand 11557 9r575 -9453 4146 8.33 COAL59 Coal 11621 9,601 -9479 4157 8.33 HTKE-FW Sand 1 Conglomerate Oil Sand 11636 9,607 -9485 3766 7.54 HK2T Sand 1 Conglomerate Oil Sand 11772 9,652 -9530 3783 7.54 Tgt 1 Base Pump Tangent 9509 -9387 TD 13343 9 791 -9673 3840 7.54 =Primary Objective = Secondary Objective TARGET SIZE 50 FT DATA COLLECTION REQUIREMENTS: Mud Logging: 4 man Crew below KOP/ IND Data: Triple combo-ADR E-Line Log Data: Gyro run upon completion of the well to validate wellbore tortuosity and portion. COVPLET1Ord TYPE ESP Completion ANTICIPATED RATES 10,000 bpd gross fluid ARTIFICIAL LIFT EQUIPMENT OD TUBING SIZE 3-112"or 4-112" OTHER COMMENTS Page 34 Revision 1 December, 2016 • „ „. K-06RD2 Drilling Procedure Rev 0 n.1.... 11.1.1..i.1 1.1 24.0 Anticipated Drilling Hazards 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 1 December, 2016 • K-06RD2 Drilling Procedure Rev 0 Iile•orp Ua.6a.1.1.1: 25.0 Rig Layout -1 ( r O N O 15 1 � cn 15 of P♦ 5 9 • $i I -I 4 o i a S S Z r O i i€ � Sweture1 14r ,e,w 10.000 • ` o� n o i -- O . . x O C7 i_ N� .J N QQ :::"•Ii ' it ■ w�� a N ; T °. *41' lir,? t i I:::::II _ Ork:1 ga t ± ,or_y _a- ., ,---I tl. .. 8 0 LP X A 009.01 ED i cr . 1E1) 5' ca co 0 0 0 8 i - 00S 611-.... 8 Q - 8t cai N lC�� a i ,��TiJ,,6 ?r 8 gl S o r n �, `7 o _ � 1 r. fr � 4 x ,,,_, :► r 'D x It 6 13 h- 000"0£ .e°" 000 OZ 1 000 OS \\\\S\:\N,....N............... .10- i C Page 36 Revision 1 December, 2016 • K-06RD2 Drilling Procedure Rev 0 IIih or1,: Ia..ka.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 1 December, 2016 K-06RD2 Drilling Procedure Rev 0 1111110g, U:wl.a.1.1.1 27.0 Choke Manifold Schematic ('hoke \lanifoid \'al%es 2" 3., To Shaker 3"Panic To Gasbuster { 1 3 1!8"© 2 1/16" 2 1/16" j[I? 21/16" 21/16" 31/8 0 /N L0 ..04_0_0J f i / 2 1/16" 2 1/16" t Manual Choke Automatic Choke 2 1/16" Inlet Pressure Sensor 3" 5,000 PSI Choke Manifold Kuukpik Drilling Rig 5 RED = 3 1/18" 5,000 PSI VALVES AND LINES BLUE = 2 1116"5,000 PSI VALVES Kuukpik Drilling Rig 5 Choke Manifold C .� *11 ° t t. L 1a9 Ana: 4 #5 a14999ttt2 a 14 " silk C•1n #15 ■alir ft `*a Kuukpik Originq Rig 5 Choke Manifold Page 38 Revision 1 December, 2016 0 • HK-06RD2 Drilling Procedure Rev 0 Ilik•nrp:\Iu.ku,1,1,1: 28.0 Fluid Flow Diagrams T 7:- r1 p T w _ I 1 1 1 I t I 1 I r, cco fr: I 1 I i i 1 I I t A rlr 1.040.0.1.0.-.0.1.40, i^it"is isi:iSiSais if l O'erilPiO'MMIe'l0'M 111:11:11111i1 ivvvvvvrgv nn a , lliiII i .... . •••. I IaI I I 1 :.:°, DQ D4 to N r o) N r A 7 W. :i: O w l' x n co:1. KN• _. %o 41. 7 D4 o Z 1 I I I 1 1 i 1 1 i a p Iai.11wlulil41Niw101 OD• a 4-' I I l i I i l I I i DQ D4 D4 D4 I i1.W1"14Iy It,.141"tN ..� I CO CD I 1 t.C.IS1 I IS1�.i ,., 1 IIIPiPi-i.iPiPi co ai I-1 1 4. t i I i.$rg if w7' I v lel 1 1�0p1�p1 I I}pla 1r , I�.il '"L'L" 'L�Y't Ip i! 8X I ,^U IA IA I.1.1..., r 7. ^ i n II"fl n,n,n iS'S!S!SIS!S f1!F. 411111 1 4 � a ;% i i i i i i iM t4 Iq Ii IN 'lit.itt io le I. NQ N N 0 1 1 1 1 i i N W p t 11 1 1 1 t; D4 0- IX I i I IV.1 1k l;i. 1I1�1 f . N ! Ir. 14!1.1 I� & liEleitititlit;-: I-r I_I 1 i 7 ca i C -Ti T, I 0.14 It:�tY'i i to a d O _C i ,51. I.I. 1 N O i'14 i!i l lr. _ G' t l l 1-4,1 I7 J Tj i.i.._1... t...L ° C in in in 1ni irfi . l+d4i iSIi IS4 r!■,a g,ariai- 1 Page 39 Revision 1 December, 2016 H ! • K-06RD2 Drilling Procedure Rev 0 IliI•or1)Ataxka,1.1.1: X C C X et ,3 r 7C' as W �. 111111141 13 1*iaNau4 lll4'11.-'1^ = X 111111111 ''. iS (Jr I • N to.,1a IN IN IN IN+IN 1N ~ I�i„rj1Si.Si„5ijijljij 'J1 is is is is iei iA iei is ici I11i1l11i111i I1.111.1114.1. ,: i i ; i i :" .ii iiiii I I I I i 1 1 t 1 ca ca 0 11 ;►% "' w% CO % g y 7 y I42% N% ..a. %O 1111 , 1111 IS ca o 1...i 1_i CD 1 8 0 ri.r.I ii rt r. ...►v J lal�la iv,If'lV IN 1^int cop iE %.1 n t . l l l l l l i { 1 Iyl+IWI-ISIIr11►I-I�L't 04 N —L O co D4 CC I I Ii lalr`.lirtalzI I_I 4i1, iii t:iIiIi .i.1.1.31 ti"Nle't U) .11ilii 1upt 11tpt 1"Q ? �r.! 1! F CD I'1 1�11c1 I 1 I I 1 i N• i is is',1.11.in iti .ET!la,i O. �1 co a a`1 P •9 ; I IS( I ii 1 S iS IS!S J. • 0 GA 44 4 11110 cri I 1 I I C 1 ,y^ i,+tti+l )r+I••iim it • . . . . . . W A i i i Ii i i , D4 DQ i I !etI I I A S i I I 0 i11I , 1/ 3 i itir ili 1. lii.r i G i 151!g: -'fig: if ° y y i is t4' ...1!1 1� i i •i i4 l i* i i i t i l ie 00 Iii iii ,,L ° fill iiiii ES- : dC C Page 40 Revision 1 December, 2016 14I • K-06RD2 Drilling Procedure Rev 0 II il1•nrp Ua.ka.1.1.1: e- ✓ 77- o F, F, Oa _ s W 1 1 1 1 I 1 1 i 1 .R" Ir1� ,l1a1p1. ylal,.. t N y1fJr 1 1 1 I 1 1 1 I I i i I 1 f f ! e-- A iNiNiNiaiaiaiaiai.. (J: IJ1igr1:.1.+1rlJi.+1«.I.- it Ipll Ip IPIp MciGiiPlP 4 4 .l, 1aatl1gi i3-IS101S1N i�3-14. 4 ill l�i'a 7..I7.7,1 it I'tt If 1t 1t 1t it ly f i f 1 1 f / 1 iiiiii�trilii ♦ - : g� gam• I l l l l l f l l r r Da ► ► cri � c7.... n a Ai m- WQ !1� Q• C CD 01 ..w �T _ N Y pp a ♦ n) Np n (410 o A E o D o 11 1 f 1 I 1 1 I 1 — r Q rr' 1 a i.�ipl ulI,lylNii r 1p� co• V 1 1 1 1 1 1 1 9 1 ! I I T 1 1 T I IT ) ►• •4 P4 t� •�.4.N.N.L.V..I ..• N --► a) co r 1 1 1 1.,..1..1..1 Ir I-1 1 1 Ip'11alaiaialPi-i 0 if 1t1. 1 sl li, f 1 sl 1 ? A ^1 ii ii iii iilt v C) b^iib fCRp O ca "t i .1R.ItliliiiiRlr i Oa m -11 O• 1 i I•I•i•i•i•1•i•I•I r 1 . . • . ••. . . . .._.__._._..._..-_. . 1 r r 1 r ) r r T` ICi i; Isi iasis 5- I:lililil;Till I I I t l l t l l V4 1101114 4 D..(1 cri a • 1 1 1 . i i" 1W1a.1 1atr101'• W A 1 1 1 I 1 1 1 R __._._-* VI 1 1 1 i 1 1 1— I I i 1R1 1 i . (n i i it i if i 17 Eir i i?ili' 1Iyl Iw 1 1 i% Irl I 1 xi p 1 I 1 �Ii,imi ( "0 co. co iI !tixI in o. iv. figikiii7'i ,: I 1.1� Iriil 1• �o- Tn o- N Qo. 1 Igl , I.I�I I ,,.� 1 1•i• i!i i 1. 1 i 1 IrJ.lfi i5.i.% O i i I•i i i4 r r ES 1 41i144441 1 1 1 . . 1 1 a s Page 41 Revision 1 December, 2016 • • K-06RD2 Drilling Procedure Rev 0 11.I.011) %Ia.'s...LI I 29.0 Offset MW vs. Depth TVD MW vs TVD Offsets 0 —A_18(1968) 1000 2000 3000 4000 5000 6000 7000 8000 — ; 9000 10000 11000 8 9 10 11 12 13 14 15 Mud Weight(PPG) Page 42 Revision 1 December,2016 i i K-06RD2 Drilling Procedure Rev 0 Ililcuri,.t I. La.1.1.1: 30.0 Casing Design Information Calculation & Casing Design Factors Cook Inlet Offshore DATE:121'642016 WELL: K-06RD2 FIELD: McArthur River DESIGN BY: Monty M Myers Design Criteria: Hole Size Mud Density: Hole Size 5-1;2" Mud Density: 9.0 ppg Hole Size Mud Density: Drilling Mode MA SP: 2471 psi(See attached MASP determination & calculation, Production Mode MA SP: 4685 psi(See attached MASP determination &calculation: Collapse Calculation: Section Calculation 1, 2 Normal gradient external stress (0.43 psu'ft:: and the casing evacuated for the internal stress Casing Section Calculation/Specification 1 2 3 4 Casing OD 7-SJ8' Top(AID) 7,900 Top(TVD) 6„206 Bottom(MD) 13343 Bottom(TVD) 9,791 Length 5,443 Weight(ppf) 29.7 Grade L-80 Connection HYD 511 Weight w/o Bouyancy Factor(lbs) 161,657 Tension at Top of Section (lbs) 161,657 Min strength Tension (1000 lbs) 254 Worst Case Safety Factor(Tension) 1.57 Collapse Pressure at bottom(Psi) 4,210 Collapse Resistance wio tension(Psi) 4,790 Worst Case Safety Factor(Collapse) 1.14 MASP(psi) 2,471 Minimum Yield(psi) 6,890 Worst case safety factor(Burst) 2.7 Page 43 Revision 1 December,2016 •Hr K-06RD2 Drilling Procedure Rev 0 Ililcarp Alaska.l.1.1: 31.0 8-1/2" Hole Section MASP IiMaximum Anticipated Surface Pressure Calculation iloorp 8-1/2"Hole Section ......, ..., K-06RD2 Cook Inlet,Alaska MD TVD Planned Top: 8100 5352 Planned TD: 13343 9791 Anticipated Formations and Pressures: Formation TVD Es..Pressure Oil/Gas/Wet PPG Grad COAL39 9,137 3956 Oil Sand 8.3 0.43 111X_FW 9,575 4146 Oil Sand 8.3 0.43 COAL59 9,601 4157 Oil Sand 8.3 0.43 HTKE-FW 9,607 3766 Oil Sand 75 0.39 HK2T 9,652 3783 Oil Sand 75 0.39 TD 9,795 3840 Oil Sand 7.5 0.39 Offset Well Mud Densities Well MW range Top(TVD) Bottom(TVD) Date A-27RD2 9.3-95 7,755 9,718 216 A-27 8.9-9.8 3,360 7,017 1973 A-27RD 9.5-9.7 6,328 9,950 1997 K-26RD 9.4-1C.2 7,800 9,971 1995 Assumptions: 1. Anticipated fracture gradient at 8100'TMD(6352'TVD)=0.7=14.9 ppg EMW 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. 3. Calculations assumes 9.2 ppg reservoir contains 2/3 gas, 1/3 water. Fracture Pressure at window considering a full column of gas from window to surface: 6352(ft)x 0.7(psi/ft)= 4447 4447(psi)-[0.1(psi/ft)•6352(ft)]= 3812 psi MASP from pore pressure;normal gradient at TO,(0.43 psi/ft) 9791(ft)x 0.43(psi/ft)= 4211 psi 4211(psi)-(0.1(psi/ft)•9791(ft))= 3233 psi MASP from pore pressure;unknown gas sand at ID,at 9.2 ppg(0.4784 psi/ft) 9791(ft)x0.4784(psi/ft)= 4685 psi Downhole 4685(psi)-[(2/3)•0.1(psi/ft)•9791(ft)]+[(1/3)•0.4784(psi/ft)•9791(ft)]= 2471 psi Drilling MASP Summary: 11. MASP while drilling 8-1/2"hole is governed by pore pressure minus 2/3 of wellbore evacuated to gas(remaining 1/3 remains 9.2 ppg drilling fluid) Page 44 Revision 1 December, 2016 HI K-06RD2 Drilling Procedure Rev 0 flileorp Alaska,1.11: 32.0 Plot (NAD 27) (Governmental Sections) -211•52P241541kla , ii S(."yO,�0.,�`N^��",1. - ADL018731 'it�L`71L1JCTL y 111•212 BHIL 1 1 •$.. .-27E.02 BHL l 1 • t 1 CA_ILI I CJIJL/ I 14.VRD BHL I Ib-i3RD BNL \\i • A115RD2L2 BHL. '/ I \1 Y i Y lf 1 YY 1Y 1 . 11 ` ✓ K-G6 BIL .,. ' ti l • ' f Y 1 °:6 IRj r r , C•Dai`i.8 `` l `�, , �� k-+,r•R:): lllil. ‘uoc.sr_o1BHL uu Y 1 Y /N `1 ♦ 111 Y aor ``A`�w_`� ��.... 0000.. — _o -- -----�Q _i �_� �_ .o_�.` ti a • , a $ • N- d BHL teX1 ' ```."� K-13R0BHL ; \i �••• `� ~ � 10 ADL01759 ' ▪ , . ADLfl18772 � -''TADlf F M UNLT . � � i • % 1/ \ I• 1 ' 1 \ •,1 \,t. \\ 1 1 \ \ YYY 1 1 at) \• A 1.1 1=-'1 H-is, \. N. �▪~��•'�./�y-j Y 'Rn r�J �� ' ! • 1 ��V llh�.Jll 11I.i 11 ��` \ \ 1 N. N. I I 1 A 1 1 `, 1 1 i 11 1I. ' 11 it `\ 1 `♦ I 11 1 /h1¢aHL 1 K-17 BHL 1 \ 1 1 � i 1 1 1 t a 1 K-021•15 B14.„Legend ``ee , 1 1 r..C5 HL 1 K-©421/24 K_23PB BH 1 1 11 ",� 11 • I 1 / 1 #• K-O RD2_SHL �K-:11 @HL r� 1 1 1 i / I. 1 1 i \ 1Ie1 /• K-30 HL 1 1 BHL B K 0 RD2_TPH 1 i t i it, Y 1 1 , i { 1 1 1 i K-06RD2 BHL 11 i 1 l .O •H •K-30P5 @HL _03 BHL T .. Il b/I i Other Surface Hole Location i r i4;,r .41-31 BHL'` IC-23 B 1 1 1• M � Y� r 4<21RD HUL t - `4.K f ' Y Y -I, • Other Bottom Hole Location � lli _ ADL01873D-_ �� G a.-4.-7—I— M-31LI • A, 0-25 BHL L+►:ys yrb/ / --- Well Paths I 1 ��7Y�1 @HL �`•� L'J4r4 rv+ � Oil and Gas Unit Boundary rl ii `1f'AK-2I BHL N/V fil . ,`,. . rut 1 A/ u 0 1.000 2.000 3,000 r; K-06RD2 Feet Alaska State Plane Zone 4.NA027A I iilr+rr p %Ia.Lu.1.1.1: M.ap Date:126.20i6 Page 45 Revision 1 December, 2016 • H • • K-06RD2 Drilling Procedure Rev 0 Ililear'Alaska,LIA: 33.0 Slot Diagram (As Built) (NAD 27) CENTER LEG 4 LAT:60'51'55.8806 N LON:151'36'21.1490'W CENTER LEG 1 N:2511794,345' LAT:60'51'19.9419'N E.213781851' LON:151.36'19.8893'W ASP ZONE 4 NAD 27 N:2511756.503' / E:213820.519' K',xar KQ• , ASP ZONE 4 NAD 27 ' K.,... ' � 180'FEL w9 KING SALMON PLATFORM .22ED ASBUILT WELL LOCATIONS 120'FEL SECTION 16,T9N,R13W.S.M.,AK CENTER LEG LAT: 15'3'22.1 35 `_r ION:1St•36'22.t035'W N:2511719.224' E:213712.532' ASP ZONE 4 NAD 27 K.,'"' K., l187'FEL K.9 K.nSii0 CENTER LEG 2 LAT:60'51'54.7696'N LON:151°36'20.90051N N:2511681.260' w 726'FSL(N E:213771.191' Z ASP ZONE 4 NAD 27 _: O 1- 690'FSL(NTS) U w CQ 0 w F-- U Q x F- O SECTION CORNER a. (PROTRACTED) N.2511063.548 E:213922.792' PROTRACTED SECTION LINE NOT TO SCALE(NTS) :'t 22 NOTES 1. BASIS OF HORIZONTAL CONTROL:NAD83 US FEET POSITION `"1111 (EPOCH 2010)AND VERTICAL CONTROL(NAVD88)IS AN OPUS `� OF A� 1/ SOLUTION FROM NGS STATIONS KENS.AC51 AND AC23 TO ,://ma •-___N P��"......'aS 7,, ESTABLISH POINT 4300. THE ALASKA STATE PLANE COORDINATES - ' NAD 83 ZONE 4 IN FEET ARE: N=2511443.373 ••*' m '*i E=1353731 256 W4/11 6484,,, ELEV.=99.189(NAVD88) -.66.0...- 2. c.2.SECTION LINES SHOWN ARE EXTENSIONS OF PROTRACTED VALUES. SCALE 3. DATUM TRANSFORMATIONS(NA083 ASPZ4 TO NA027 ASPZ4) I • '' 111 L11"`��, WERE DONE USING CORPSCON SOFTWARE VERSION 60.1 l tLtI HILCORP ALASKA.LLC KING SALMON PLATFORM WELLS COOK INLET ALASKA 0i VMBV "` - ,. AS BUILT SURFACE LOCATION SCALE 1,•30' PHOJECT NO MN . Kabro,w,PP.ro,au1.tvu1O 1145r,.. NAD 27 BOOK NO ,aa P O.EOR MS SOU:0NA M(P.P. .CE a07126342,4 EN<99,,.' , PROTRACTED SEC. 16 TO9N R13W SHEEN Ea eNCLANIl IIi T, ' I.,' I, %I,,,La. 1.1.I '� ET/Al or2 SEWARD MERIDIAN,ALASKA Page 46 Revision 1 December, 2016 • K-06RD2 Drilling Procedure Rev 0 IliIcorp Alaska,I.1.1: NAD 27 Slot if Well# Northing Easting Latitude Longitude Center Leg 1 2511756.503 213820.519 60'51'55.52222" -151'36'19.94191" 1 K-21RD 2511751.133 213822.994 60°51'55.46995" -151°36'19.88928" 2 K-30 2511750.754 213819.220 60°51'55.46531" -151°36'19.96528" 3 K-18RD 2511753.106 213815.860 60°51'55.48766" -151°36'20.03428" Leg 1 4 K-17 2511757.623 213814.976 60'51'55.53191" -151°36'20.05437" 5 K-23 2511761.085 213816.638 60°51'55.56639" -151°36'20.02253" 6 K-19 2511761.888 213820.828 60°51'55.57531" -151°36'19.93833" 7 K-22RD 2511759.441 213825.218 60°51'55.55228" -151°36'19.84850" 8 K-20 2511754.730 213825.531 60°51'55.50598" -151°36'19.83984" Center Leg 2 2511681.260 213771.191 60°51'54.76960" -151°36'20.90053" 9 K-15RD 2511676.516 213774.559 60°51'54.72372" -151°36'20.83019" 10 K-9 2511675.411 213770.205 60°51'54.71178" -151"36'20.91754" 11 K-4RD 2511678.297 213765.971 60°51'54.73918" -151°36'21.00445" Leg 2 12 K-11 2511682.498 213765.183 60'51'54.78034" -151°36'21.02242" 13 K-13RD2 2511685.931 213767.848 60'51'54.81478" -151°36'20.97031" 14 K-2RD 2511686.644 213772.096 60'51'54.82282" -151°36'20.88491" 15 K-7RD 2511684.476 213775.691 60"51'54.80235" -151°36'20.81128" 16 K-5 2511680.120 213776.722 60'51'54.75972" -151°36'20.78831" Leg 3 Center Leg 3 2511719.224 213712.532 60°51'55.12919" -151°36'22.10347" Center Leg 4 2511794.345 213761.651 60"51'55.88057" -151°36'21.14901" 25 K-26RD _ 2511789.752 213764.548 60'51'55.83605" -151°36'21.08827" 26 K-1RD2 2511788.570 213760.661 60°51'55.82347" -151°36'21.16616" 27 K-10RD 2511791.323 213757.250 60°51'55.84976" -151°36'21.23636" Leg 4 28 K-25 2511795.528 213756.002 60"51'55.89085' -151°36'21.26364" 29 K-12RD2 2511799.318 213758.343 60°51'55.92872" -151°36'21.21826" 30 _ K-6RD 2511799.443 213762.467 60°51'55.93095" -151°36'21.13506" 31 K-24RD2 2511797.672 213766.437 60°51'55.91447" -151°36'21.05403" 32 K-3RD2511793.127 213767.529 60'51'55.86999" -151°36'21.02976" PROJECT HILCORP ALASKA,LLC KING SALMON PLATFORM WELLS *wk. COOK INLET ALASKA AS BUILT SURFACE LOCATION E NOWEERIMOr VAPPiNG sufr&ONOJ Tf ST*c NAD 27 ,`O.CE , 2 42M PA(107)z$34265 PROTRACTED SEC. 16 TO9N R13W "N"suun+xnua,Y CGGou 1111(1.111 %L.A., I.I,1 SEWARD MERIDIAN,ALASKA 2`Y 2 Page 47 Revision 1 December, 2016 • • K-06RD2 Drilling Procedure Rev 0 IIiH•nrp;11a.ka, 34.0 Directional Program (wp07) Page 48 Revision 1 December, 2016 • Hilcorp Energy Company Trading Bay King Salmon Plan: K-06RD2 Plan: K-06RD2 Plan: K-06RD2 wp07 Standard Proposal Report 06 December, 2016 HALLIBURTON Sperry Drilling Services HALLIBURTON Hilcorp Energy Company REFERENCE INFORMATION IiiI(•oI° ) Calculation Method: Minimum Curvature .-ordinate(N/E)Reference: Well Plan:K-06RD2,True North Sperry Drilling t Error System: ISCWSA Vertical(ND)Reference: K-06RD2 @ 122.00usft(Kuupik 5) Scan Method: Closest Approach 3D Measured Depth Reference: K-06RD2 CO 122.00usft(Kuupik 5) I Error Surface: Elliptical Conic Warning Method: Error Ratio Calculation Method: Minimum Curvature Project: Trading Bay Site: King Salmon , Well: Plan:K-06RD2 SECTION DETAILS Wellbore: Plan:K-06RD2 Design: K-06RD2 wp07 Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target 1 8100.00 40.32 104.22 6352.31 -130.77 4397.91 0.00 0.00 4152.00 2 8117.00 41.40 106.96 6365.17 -133.76 4408.62 12.30 60.00 4161.30 3 8147.00 41.40 106.96 6387.67 -139.54 4427.60 0.00 0.00 4177.63 4 9210.62 13.55 253.98 7375.57 -287.28 4661.24 5.00 170.83 4355.60 DDI = 6.461 5 10216.23 13.55 253.98 8353.19 -352.30 4434.79 0.00 0.00 4120.09 6 12143.62 85.53 37.05 9698.33 584.12 4915.77 5.00 142.93 4861.96 7 13343.62 85.53 37.05 9791.85 1538.93 5636.59 0.00 0.00 5837.99 K-06RD2 wp05 TD Tgt CASING DETAILS WELL DETAILS: Plan:K-06RD2 TVD TVDSS MD Size Name Water Depth: 73.00 9791.85 9669.85 13343.62 7-5/8 7-5/8"x 8-1/2" +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2511799.44 213762.47 60°51'55.931 N 151°36'21.135 W I_ SURVEY PROGRAM 00 ,l'0 Date:2014-06-09700:00:00 Validated:Yes Version: 5625-- Depth From Depth To Survey/Plan Tool 122.00 2122.00 K-06(K-06) NSG_WL 00 2222.00 8100.00 K-06RD(K-O6RD) NSG_WL 10 8100.00 8400.00 K-06RD2 wp07 MWD Interp Azi+sag 8400.00 13343.62 K-06RD2 wp07 MWD+SC+sag 6000- 000 KOP:Start Dir 12.30/100':8100'MD,6352.31'TVD:60°RT TF _ _ _ End Dir :8117'MD,6365.17'ND 6375- 00 10 Start Dir 5°/100':8147'MD,6387.67'TVD 8,,00 8500- 6750- 1r00 00 00 7125- 9000 00 8000 90 End Dir :9210.62'MD,7375.57'TVD FORMATION TOP DETAILS c 7500 0TVDPath TVDssPath MDPath Formation 000 9137.00 9015.00 11036.69 COAL39 ca N 9575.00 9453.00 11686.85 H1X_FW O y0O 9500 9601.00 9479.00 11747.09 COAL59 in -- 8 9607.00 9485.00 11762.01 HTKE-FW 7875- 0P'0 9652.00 9530.00 11892.97 HK2T L 10 d d) in 9000 10000 000 8250- NN f Start Dir 5°/100':10216.23'MD,8353.19'TVD cu 2 8625 10500 11500 I- - 9500 9000 -COAL39 11000 End Dir :12143.62'MD,9698.33'TVD 120p0 10000 ,, - Total Depth: 13343.62'MD,9791.85'TVD 0 9375- H1X_FW ,.^ o , 0y00 0 0 12 COAL591oy0o - -- N 0o 9750 HTKE-FW M , HK2TK-06RD2 wp0 13p00 11000 K-06RD2 wp05 TD Tgt K-06RD 7-5/8"x 8-1/2" -- 10125 ,j19 13296 11 K-06 10500- 1 0500- 1 I I I--1-_I . . I I I I I I r-TTI I I I I I T 1- T T I I I I I I I I I I I I I I I T-I T I I I I I I I I T-p.._r-I I I I I I I I 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125 7500 7875 Vertical Section at 72.38°(750 usft/in) I • Project: Trading Bay COMPANY DETAILS:Hilcorp Energy Company WELL DETAILS:Herr K-06RD2 •HALLIEIURTON Site: King Salmon Calculation Method:Minimum Curvature Water Depth: 73.00 arae.nV o.`NN.p Well: Plan:K-06RD2 Error System'ISCWSA +N/-S +p/-w Northing Fasting Latitude Longitude Scan Method:Closest Approach 3D 0.00 0.00 251179944 213762.47 60°51'55.931 N 151°36'21.135 W Wellbore: Plan:K-06RD2 Error Surface:Elliptical Conic - Plan: K-06RD2 wp07 Warning Method:Error Ratio 2250— _ REFERENCE INFORMATION Co-ordinate(N/E)Reference:Well Plan:K-06R02.True North - Vertical(ND)Reference:K-06RD2 @ 122.00uaf(Kuupik 5) _ . 7< Measured Depth Reference:K-06RD2 a2 0 120usa(Ma(Mary,*5) Cak:uMion Method:Minimum Curvature 2000— c o $ ' _ - o 1750— 'S- 'b Total Depth:13343.62'MD,9791.85TVD - K-06RD2 wp05 TDTgL ‘. 1500— -7-5/8. -5/8 x8-12" _ 9)9 _ kir 1 �1y� 1250— H2, 4' 9's,, .. 1000— - F SURVEY PROGRAM g 750— , Date:2014-06-09T00:00:00 Validated:Yea Version: e 3--,' - ` e Depth From Depth To Survey/Plan Tool ,G 122.00 2122.00 K-06(K-06) NSG_WL L $ e 2222.00 8100.00 K-06013(K-0600) NSG_WL O -_ e 8100.00 8400.00 K-06RD2 wp07 MWD_Interp Azi+sag 500 j l 8400.00 13343.62 K-06RD2 wp07 MWD+SC+sag 2 $ - End Dir:12143.62'MD,9698.33'TVD CASING DETAILS 0 rn - S S g 250— re $ O M TVD TVDSS MD Size Name vi h 8 y er r 9791.85 9669.85 13343.62 7-5/8 7-5/8"x 8-1/2' I 9 h k: h JPo 0— _ q�1.,p,, r 9z „r0 g - wV b b Q -250— 8 _ 9ao ` - n -500— _ I End Du:9210.62'MD,7375.57 TVD k`g _ Start Dir 51100':10216.23'MD,8353.19TVD I -750— h - Ft _ 4' 4' -1000— 4 T-iii ' ii ' ' l ' I l llll „ ' l ' : J ' iiiiii ' llirliii : tilli ' iIiIlil ' liiIiiii : : : : 2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6250 6500 6750 7000 West(-)/East(+)(500 usft/in) • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:K-06RD2 Company: Hilcorp Energy Company TVD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Project: Trading Bay MD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Site: King Salmon North Reference: True Well: Plan:K-06RD2 Survey Calculation Method: Minimum Curvature Wellbore: Plan:K-06RD2 Design: K-06RD2 wp07 Project Trading Bay Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor F Site King Salmon I Site Position: Northing: 2,511,786.28 usft Latitude: 60°51'55.800 N From: Map Easting: 213,756.95usft Longitude: 151°36'21.240 W Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -1.40 ° I Well Plan:K-06RD2 Well Position +NI-S 0.00 usft Northing: 2,511,799.44 usft Latitude: 60°51'55.931 N +EI-W 0.00 usft Easting: 213,762.47 usft Longitude: 151°36'21.135 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Water Depth: 73.00 usft Wellbore Plan:K-06RD2 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (0) (°) (nT) BGG M2016 12/1/2016 16.23 73.75 55,450 Design K-06RD2 wp07 Audit Notes: Version: Phase: PLAN Tie On Depth: 8,100.00 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (0) 0.00 0.00 0.00 72.38 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/S +E/-W Rate Rate Rate Tool Face (usft) (°) (0) (usft) usft (usft) (usft) (°/100usft) (°/100usft) (°/100usft) (°) 8,100.00 40.32 104.22 6,352.31 6,230.31 -130.77 4,397.91 0.00 0.00 0.00 0.00 8,117.00 41.40 106.96 6,365.17 6,243.17 -133.76 4,408.62 12.30 6.34 16.11 60.00 8,147.00 41.40 106.96 6,387.67 6,265.67 -139.54 4,427.60 0.00 0.00 0.00 0.00 9,210.62 13.55 253.98 7,375.57 7,253.57 -287.28 4,661.24 5.00 -2.62 13.82 170.83 10,216.23 13.55 253.98 8,353.19 8,231.19 -352.30 4,434.79 0.00 0.00 0.00 0.00 12,143.62 85.53 37.05 9,698.33 9,576.33 584.12 4,915.77 5.00 3.73 7.42 142.93 13,343.62 85.53 37.05 9,791.85 9,669.85 1,538.93 5,636.59 0.00 0.00 0.00 0.00 12/6/2016 3:33:33PM Page 2 COMPASS 5000.1 Build 81 • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:K-06RD2 Company: Hilcorp Energy Company TVD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Project: Trading Bay MD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Site: King Salmon North Reference: True Well: Plan:K-06RD2 Survey Calculation Method: Minimum Curvature Wellbore: Plan:K-06RD2 Design: K-06RD2 wp07 Planned Survey Measured Vertical Map Map Depth inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DIS Veil Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -122.00 0.00 0.00 0.00 0.00 -122.00 0.00 0.00 2,511,799.44 213,762.47 0.00 0.00 122.00 0.05 106.65 122.00 0.00 -0.02 0.05 2,511,799.43 213,762.52 0.04 0.04 222.00 0.08 117.72 222.00 100.00 -0.06 0.15 2,511,799.38 213,762.62 0.03 0.13 322.00 0.57 140.50 322.00 200.00 -0.48 0.53 2,511,798.95 213,762.99 0.50 0.36 422.00 2.32 157.40 421.96 299.96 -2.73 1.63 2,511,796.67 213,764.03 1.78 0.72 522.00 1.32 107.17 521.92 399.92 -4.94 3.51 2,511,794.42 213,765.85 1.79 1.85 622.00 3.25 79.75 621.83 499.83 -4.77 7.40 2,511,794.49 213,769.74 2.17 5.60 722.00 6.97 51.22 721.43 599.43 -0.47 14.92 2,511,798.61 213,777.37 4.40 14.08 822.00 8.62 50.53 820.51 698.51 8.10 25.43 2,511,806.92 213,788.09 1.65 26.69 922.00 10.18 52.20 919.16 797.16 18.28 38.20 2,511,816.78 213,801.11 1.58 41.94 1,022.00 13.43 56.03 1,017.03 895.03 30.19 54.82 2,511,828.28 213,818.01 3.34 61.39 1,122.00 16.27 56.43 1,113.68 991.68 44.42 76.13 2,511,841.99 213,839.66 2.84 86.00 1,222.00 18.07 53.50 1,209.23 1,087.23 61.40 100.27 2,511,858.37 213,864.21 2.00 114.15 1,322.00 20.00 53.45 1,303.75 1,181.75 80.81 126.48 2,511,877.13 213,890.88 1.93 145.00 1,422.00 22.20 54.22 1,397.04 1,275.04 102.04 155.55 2,511,897.64 213,920.46 2.22 179.14 1,522.00 23.92 55.17 1,489.05 1,367.05 124.67 187.52 2,511,919.48 213,952.98 1.76 216.45 1,622.00 25.23 56.20 1,579.99 1,457.99 148.10 221.87 2,511,942.07 213,987.89 1.38 256.29 1,722.00 25.13 56.62 1,670.49 1,548.49 171.64 257.31 2,511,964.73 214,023.90 0.20 297.19 1,822.00 24.70 56.87 1,761.18 1,639.18 194.74 292.54 2,511,986.97 214,059.68 0.44 337.76 1,922.00 24.33 57.17 1,852.17 1,730.17 217.33 327.34 2,512,008.69 214,095.03 0.39 377.77 2,022.00 23.88 57.58 1,943.44 1,821.44 239.35 361.74 2,512,029.86 214,129.96 0.48 417.22 2,122.00 23.58 57.92 2,034.99 1,912.99 260.83 395.77 2,512,050.50 214,164.51 0.33 456.16 2,208.00 22.59 63.33 2,114.11 1,992.11 277.38 425.11 2,512,066.33 214,194.24 2.72 489.13 13 3/8" 2,222.00 22.45 64.25 2,127.04 2,005.04 279.75 429.93 2,512,068.58 214,199.11 2.72 494.44 2,322.00 19.88 78.98 2,220.36 2,098.36 291.30 463.84 2,512,079.30 214,233.30 5.89 530.26 2,422.00 21.48 84.37 2,313.92 2,191.92 296.35 498.76 2,512,083.49 214,268.33 2.49 565.06 2,522.00 24.57 84.47 2,405.94 2,283.94 300.15 537.68 2,512,086.34 214,307.33 3.09 603.31 2,622.00 27.87 84.28 2,495.64 2,373.64 304.48 581.64 2,512,089.59 214,351.39 3.30 646.52 2,722.00 31.45 84.18 2,582.52 2,460.52 309.46 630.87 2,512,093.36 214,400.72 3.58 694.95 2,822.00 34.68 84.33 2,666.32 2,544.32 314.92 685.15 2,512,097.49 214,455.11 3.23 748.33 2,922.00 38.32 83.90 2,746.69 2,624.69 321.03 744.31 2,512,102.15 214,514.40 3.65 806.56 3,022.00 41.68 83.58 2,823.28 2,701.28 328.04 808.19 2,512,107.60 214,578.44 3.37 869.57 I 3,122.00 42.78 83.63 2,897.33 2,775.33 335.53 874.98 2,512,113.44 214,645.40 1.10 935.50 3,222.00 42.17 83.75 2,971.08 2,849.08 342.95 942.10 2,512,119.22 214,712.67 0.62 1,001.71 3,322.00 41.77 83.80 3,045.43 2,923.43 350.20 1,008.58 2,512,124.84 214,779.31 0.40 1,067.27 3,422.00 41.28 83.83 3,120.30 2,998.30 357.34 1,074.49 2,512,130.37 214,845.37 0.49 1,132.25 3,522.00 40.77 85.22 3,195.74 3,073.74 363.61 1,139.82 2,512,135.04 214,910.84 1.05 1,196.41 3,622.00 38.73 92.57 3,272.67 3,150.67 364.93 1,203.65 2,512,134.79 214,974.69 5.12 1,257.65 3,722.00 39.55 99.13 3,350.26 3,228.26 358.47 1,266.37 2,512,126.80 215,037.22 4.22 1,315.47 3,822.00 42.63 100.87 3,425.62 3,303.62 347.03 1,331.08 2,512,113.78 215,101.63 3.29 1,373.67 3,922.00 43.83 101.53 3,498.48 3,376.48 333.72 1,398.26 2,512,098.83 215,168.47 1.28 1,433.68 4,022.00 44.48 101.75 3,570.23 3,448.23 319.67 1,466.49 2,512,083.11 215,236.33 0.67 1,494.45 4,122.00 44.82 102.60 3,641.37 3,519.37 304.84 1,535.18 2,512,066.61 215,304.64 0.69 1,555.44 I 4,222.00 45.53 103.12 3,711.86 3,589.86 289.06 1,604.33 2,512,049.13 215 373.38 0.80 1,616.56 12/6/2016 3:33:33PM Page 3 COMPASS 5000.1 Build 81 0 410 Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:K-06RD2 Company: Hilcorp Energy Company TVD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Project: Trading Bay MD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Site: King Salmon North Reference: True Well: Plan:K-06RD2 Survey Calculation Method: Minimum Curvature Wellbore: Plan:K-06RD2 Design: K-06RD2 wp07 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NJ-S +E/-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,659.56 4,322.00 46.10 104.10 3,781.56 3,659.56 272.18 1,674.02 2,512,030.56 215,442.64 0.90 1,677.87 4,422.00 46.93 104.83 3,850.38 3,728.38 254.05 1,744.28 2,512,010.72 215,512.43 0.98 1,739.35 4,522.00 47.17 104.25 3,918.51 3,796.51 235.68 1,815.13 2,511,990.61 215,582.81 0.49 1,801.31 4,622.00 43.95 97.23 3,988.56 3,866.56 222.27 1,885.15 2,511,975.50 215,652.49 5.95 1,863.99 4,722.00 42.03 89.68 4,061.76 3,939.76 218.09 1,953.11 2,511,969.65 215,720.32 5.49 1,927.49 4,822.00 44.53 89.32 4,134.55 4,012.55 218.69 2,021.66 2,511,968.57 215,788.86 2.51 1,993.01 4,922.00 46.23 90.43 4,204.79 4,082.79 218.84 2,092.83 2,511,966.98 215,860.01 1.87 2,060.89 I 5,022.00 45.87 90.68 4,274.20 4,152.20 218.14 2,164.82 2,511,964.52 215,931.96 0.40 2,129.29 SII 5,122.00 46.35 91.60 4,343.52 4,221.52 216.70 2,236.87 2,511,961.32 216,003.96 0.82 2,197.53 5,222.00 47.47 92.48 4,411.84 4,289.84 214.10 2,309.85 2,511,956.93 216,076.85 1.29 2,266.29 5,322.00 49.03 92.97 4,478.42 4,356.42 210.55 2,384.37 2,511,951.55 216,151.26 1.60 2,336.24 5,422.00 50.50 93.82 4,543.02 4,421.02 206.02 2,460.57 2,511,945.16 216,227.33 1.61 2,407.50 5,522.00 51.78 94.85 4,605.76 4,483.76 200.13 2,538.21 2,511,937.37 216,304.80 1.51 2,479.71 5,622.00 52.68 95.58 4,667.01 4,545.01 192.94 2,616.93 2,511,928.26 216,383.32 1.07 2,552.56 5,722.00 52.63 95.88 4,727.67 4,605.67 185.00 2,696.03 2,511,918.39 216,462.20 0.24 2,625.55 5,822.00 51.27 96.63 4,789.30 4,667.30 176.43 2,774.31 2,511,907.90 216,540.25 1.48 2,697.56 5,922.00 50.83 97.00 4,852.17 4,730.17 167.20 2,851.53 2,511,896.79 216,617.22 0.53 2,768.36 6,022.00 50.55 97.12 4,915.52 4,793.52 157.69 2,928.32 2,511,885.40 216,693.75 0.29 2,838.67 6,122.00 49.37 97.73 4,979.85 4,857.85 147.80 3,004.23 2,511,873.65 216,769.40 1.27 2,908.03 6,222.00 49.02 98.18 5,045.20 4,923.20 137.33 3,079.20 2,511,861.35 216,844.08 0.49 2,976.31 6,322.00 48.73 98.27 5,110.97 4,988.97 126.55 3,153.75 2,511,848.75 216,918.35 0.30 3,044.10 6,422.00 47.38 98.52 5,177.81 5,055.81 115.69 3,227.33 2,511,836.09 216,991.64 1.36 3,110.94 6,522.00 47.22 99.27 5,245.62 5,123.62 104.33 3,299.94 2,511,822.96 217,063.95 0.57 3,176.70 6,622.00 47.15 99.67 5,313.59 5,191.59 92.26 3,372.29 2,511,809.12 217,135.98 0.30 3,242.01 6,722.00 46.55 100.38 5,381.98 5,259.98 79.57 3,444.13 2,511,794.67 217,207.49 0.79 3,306.64 6,822.00 47.40 100.40 5,450.21 5,328.21 66.38 3,516.04 2,511,779.73 217,279.05 0.85 3,371.18 6,922.00 46.65 100.93 5,518.38 5,396.38 52.84 3,587.94 2,511,764.43 217,350.60 0.84 3,435.61 7,022.00 46.83 101.53 5,586.91 5,464.91 38.66 3,659.37 2,511,748.50 217,421.66 0.47 3,499.39 7,122.00 47.05 101.83 5,655.19 5,533.19 23.87 3,730.92 2,511,731.97 217,492.83 0.31 3,563.11 7,222.00 47.12 102.18 5,723.28 5,601.28 8.63 3,802.56 2,511,714.98 217,564.07 0.27 3,626.77 7,322.00 46.75 102.62 5,791.56 5,669.56 -7.05 3,873.91 2,511,697.55 217,635.02 0.49 3,690.03 7,422.00 46.90 102.83 5,859.98 5,737.98 -23.12 3,945.04 2,511,679.75 217,705.74 0.21 3,752.97 7,522.00 46.48 103.22 5,928.58 5,806.58 -39.51 4,015.94 2,511,661.63 217,776.21 0.51 3,815.57 7,622.00 44.43 103.58 5,998.72 5,876.72 -56.03 4,085.26 2,511,643.42 217,845.11 2.07 3,876.64 7,722.00 43.70 103.80 6,070.58 5,948.58 -72.49 4,152.83 2,511,625.31 217,912.25 0.75 3,936.06 7,822.00 42.85 103.40 6,143.38 6,021.38 -88.61 4,219.46 2,511,607.57 217,978.47 0.89 3,994.68 7,922.00 41.32 102.92 6,217.60 6,095.60 -103.87 4,284.72 2,511,590.71 218,043.33 1.56 4,052.26 8,022.00 40.75 103.25 6,293.03 6,171.03 -118.73 4,348.67 2,511,574.29 218,106.90 0.61 4,108.71 8,100.00 40.32 104.22 6,352.31 6,230.31 -130.77 4,397.91 2,511,561.05 218,155.83 0.98 4,152.00 KOP:Start Dir 12.3°/100':8100'MD,6352.31'TVD:60°RT TF 8,117.00 41.40 106.96 6,365.17 6,243.17 -133.76 4,408.62 2,511,557.80 218,166.46 12.30 4,161.30 End Dir :8117'MD,6365.17'TVD 8,147.00 41.40 106.96 6,387.67 6,265.67 -139.54 4,427.60 2,511,551.55 218,185.29 0.00 4,177.63 Start Dir 5°/100':8147'MD,6387.67'TVD 8,200.00 38.78 107.64 6,428.21 6,306.21 -149.69 4,460.18 2,511,540.61 218,217.62 5.00 4,205.62 12/6/2016 3:33:33PM Page 4 COMPASS 5000.1 Build 81 1 • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:K-06RD2 Company: Hilcorp Energy Company TVD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Project: Trading Bay MD Reference: K-06RD2 @ 122.O0usft(Kuupik 5) Site: King Salmon North Reference: True Well: Plan:K-06RD2 Survey Calculation Method: Minimum Curvature Wellbore: Plan:K-06RD2 Design: K-06RD2 wp07 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NI-S +E/-W Northing Easting DIS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 6,386.76 8,300.00 33.86 109.14 6,508.76 6,386.76 -168.32 4,516.39 2,511,520.60 218,273.35 5.00 4,253.55 8,400.00 28.97 111.09 6,594.07 6,472.07 -186.19 4,565.33 2,511,501.55 218,321.84 5.00 4,294.79 8,500.00 24.11 113.75 6,683.51 6,561.51 -203.14 4,606.64 2,511,483.59 218,362.73 5.00 4,329.03 8,600.00 19.32 117.65 6,776.40 6,654.40 -219.05 4,640.01 2,511,466.87 218,395.70 5.00 4,356.02 11 8,700.00 14.66 123.94 6,872.01 6,750.01 -233.80 4,665.18 2,511,451.50 218,420.50 5.00 4,375.54 8,800.00 10.32 135.62 6,969.64 6,847.64 -247.28 4,681.96 2,511,437.61 218,436.94 5.00 4,387.45 8,900.00 6.93 160.76 7,068.52 6,946.52 -259.39 4,690.22 2,511,425.31 218,444.90 5.00 4,391.66 9,000.00 6.26 205.06 7,167.92 7,045.92 -270.03 4,689.90 2,511,414.68 218,444.32 5.00 4,388.13 9,100.00 8.95 237.81 7,267.08 7,145.08 -279.12 4,681.00 2,511,405.82 218,435.20 5.00 4,376.90 9,200.00 13.08 252.93 7,365.24 7,243.24 -286.59 4,663.58 2,511,398.77 218,417.61 5.00 4,358.04 9,210.62 13.55 253.98 7,375.57 7,253.57 -287.28 4,661.24 2,511,398.13 218,415.24 5.00 4,355.60 End Dir :9210.62'MD,7375.57'ND 9,300.00 13.55 253.98 7,462.46 7,340.46 -293.06 4,641.11 2,511,392.85 218,394.98 0.00 4,334.66 9,400.00 13.55 253.98 7,559.68 7,437.68 -299.53 4,618.59 2,511,386.94 218,372.31 0.00 4,311.24 9,500.00 13.55 253.98 7,656.90 7,534.90 -305.99 4,596.07 2,511,381.03 218,349.64 0.00 4,287.82 9,600.00 13.55 253.98 7,754.11 7,632.11 -312.46 4,573.56 2,511,375.11 218,326.97 0.00 4,264.41 9,700.00 13.55 253.98 7,851.33 7,729.33 -318.92 4,551.04 2,511,369.20 218,304.30 0.00 4,240.99 9,800.00 13.55 253.98 7,948.55 7,826.55 -325.39 4,528.52 2,511,363.29 218,281.63 0.00 4,217.57 9,900.00 13.55 253.98 8,045.76 7,923.76 -331.85 4,506.00 2,511,357.38 218,258.96 0.00 4,194.15 10,000.00 13.55 253.98 8,142.98 8,020.98 -338.32 4,483.48 2,511,351.47 218,236.29 0.00 4,170.73 10,100.00 13.55 253.98 8,240.20 8,118.20 -344.78 4,460.96 2,511,345.55 218,213.62 0.00 4,147.31 10,200.00 13.55 253.98 8,337.41 8,215.41 -351.25 4,438.44 2,511,339.64 218,190.95 0.00 4,123.89 10,216.23 13.55 253.98 8,353.19 8,231.19 -352.30 4,434.79 2,511,338.68 218,187.27 0.00 4,120.09 Start Dir 5°I100':10216.23'MD,8353.19'TVD 10,300.00 10.51 267.95 8,435.13 8,313.13 -355.28 4,417.71 2,511,336.12 218,170.13 5.00 4,102.91 10,400.00 8.29 295.84 8,533.83 8,411.83 -352.46 4,402.10 2,511,339.32 218,154.59 5.00 4,088.88 10,500.00 8.76 329.92 8,632.79 8,510.79 -342.72 4,391.79 2,511,349.31 218,144.52 5.00 4,082.00 10,600.00 11.59 353.63 8,731.25 8,609.25 -326.14 4,386.85 2,511,366.01 218,139.99 5.00 4,082.32 10,700.00 15.55 6.84 8,828.46 8,706.46 -302.83 4,387.33 2,511,389.30 218,141.04 5.00 4,089.84 10,800.00 19.97 14.57 8,923.69 8,801.69 -272.98 4,393.23 2,511,418.99 218,147.67 5.00 4,104.49 10,900.00 24.60 19.54 9,016.20 8,894.20 -236.82 4,404.49 2,511,454.87 218,159.81 5.00 4,126.17 11,000.00 29.35 23.00 9,105.30 8,983.30 -194.61 4,421.04 2,511,496.66 218,177.39 5.00 4,154.72 11,036.69 31.11 24.02 9,137.00 9,015.00 -177.67 4,428.41 2,511,513.41 218,185.17 5.00 4,166.87 COAL39 11,100.00 34.17 25.56 9,190.30 9,068.30 -146.69 4,442.74 2,511,544.04 218,200.26 5.00 4,189.91 11,200.00 39.02 27.55 9,270.57 9,148.57 -93.41 4,469.44 2,511,596.65 218,228.25 5.00 4,231.48 11,300.00 43.91 29.17 9,345.48 9,223.48 -35.18 4,500.92 2,511,654.09 218,261.15 5.00 4,279.11 11,400.00 48.81 30.52 9,414.47 9,292.47 27.55 4,536.95 2,511,715.92 218,298.70 5.00 4,332.44 11,500.00 53.73 31.68 9,477.02 9,355.02 94.32 4,577.26 2,511,781.67 218,340.63 5.00 4,391.06 11,600.00 58.66 32.71 9,532.64 9,410.64 164.60 4,621.53 2,511,850.85 218,386.61 5.00 4,454.54 11,686.85 62.94 33.51 9,575.00 9,453.00 228.08 4,662.94 2,511,913.30 218,429.56 5.00 4,513.22 H1X_FW 11,700.00 63.59 33.63 9,580.92 9,458.92 237.87 4,669.43 2,511,922.93 218,436.29 5.00 4,522.37 11,747.09 65.92 34.03 9,601.00 9,479.00 273.25 4,693.15 2,511,957.72 218,460.87 5.00 4,555.68 COAL59 12/6/2016 3:33:33PM Page 5 COMPASS 5000.1 Build 81 1 • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:K-06RD2 Company: Hilcorp Energy Company TVD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Project: Trading Bay MD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Site: King Salmon North Reference: True Well: Plan:K-06RD2 Survey Calculation Method: Minimum Curvature Wellbore: Plan:K-06RD2 Design: K-06RD2 wp07 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) 9,485.00 11,762.01 66.65 34.16 9,607.00 9,485.00 284.56 4,700.80 2,511,968.84 218,468.80 5.00 4,566.40 HTKE-FW 11,800.00 68.53 34.47 9,621.48 9,499.48 313.57 4,720.60 2,511,997.35 218,489.30 5.00 4,594.05 11,892.97 73.13 35.21 9,652.00 9,530.00 385.61 4,770.76 2,512,068.14 218,541.21 5.00 4,663.67 HK2T 11,900.00 73.48 35.26 9,654.02 9,532.02 391.11 4,774.65 2,512,073.55 218,545.23 5.00 4,669.04 12,000.00 78.42 36.01 9,678.29 9,556.29 469.92 4,831.16 2,512,150.95 218,603.65 5.00 4,746.75 12,100.00 83.37 36.74 9,694.11 9,572.11 549.40 4,889.71 2,512,228.96 218,664.13 5.00 4,826.61 12,143.62 85.53 37.05 9,698.33 9,576.33 584.11 4,915.77 2,512,263.03 218,691.03 5.00 4,861.96 End Dir :12143.62'MD,9698.33'TVD 12,200.00 85.53 37.05 9,702.72 9,580.72 628.98 4,949.64 2,512,307.05 218,725.98 0.00 4,907.82 12,300.00 85.53 37.05 9,710.51 9,588.51 708.54 5,009.70 2,512,385.13 218,787.98 0.00 4,989.15 12,400.00 85.53 37.05 9,718.31 9,596.31 788.11 5,069.77 2,512,463.20 218,849.98 0.00 5,070.49 12,500.00 85.53 37.05 9,726.10 9,604.10 867.68 5,129.84 2,512,541.27 218,911.98 0.00 5,151.82 12,600.00 85.53 37.05 9,733.89 9,611.89 947.25 5,189.91 2,512,619.35 218,973.97 0.00 5,233.16 12,700.00 85.53 37.05 9,741.69 9,619.69 1,026.82 5,249.98 2,512,697.42 219,035.97 0.00 5,314.49 12,800.00 85.53 37.05 9,749.48 9,627.48 1,106.38 5,310.04 2,512,775.49 219,097.97 0.00 5,395.83 12,900.00 85.53 37.05 9,757.28 9,635.28 1,185.95 5,370.11 2,512,853.57 219,159.97 0.00 5,477.16 13,000.00 85.53 37.05 9,765.07 9,643.07 1,265.52 5,430.18 2,512,931.64 219,221.96 0.00 5,558.50 13,100.00 85.53 37.05 9,772.86 9,650.86 1,345.09 5,490.25 2,513,009.71 219,283.96 0.00 5,639.84 13,200.00 85.53 37.05 9,780.66 9,658.66 1,424.66 5,550.32 2,513,087.79 219,345.96 0.00 5,721.17 13,300.00 85.53 37.05 9,788.45 9,666.45 1,504.23 5,610.38 2,513,165.86 219,407.96 0.00 5,802.51 13,343.62 85.53 37.05 9,791.85 9,669.85 1,538.93 5,636.59 2,513,199.91 219,435.00 0.00 5,837.98 Total Depth:13343.62'MD,9791.85'TVD-7-5/8"x 8-1/2" Targets Target Name •hit/miss target Dip Angle Dip Dir. TVD +NI-S +EJ-W Northing Easting -Shape (") (") (usft) (usft) (usft) (usft) (usft) K-06RD2 wp05 TD Tgt 0.00 0.00 9,791.85 1,538.93 5,636.59 2,513,199.92 219,435.00 -plan hits target center -Point 13,343.62 9,791.85 7-5/8"x 8-1/2" 7-5/8 8-1/2 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology (1 (1 11,036.69 9,137.00 COAL39 0.00 11,762.01 9,607.00 HTKE-FW 0.00 11,686.85 9,575.00 H1X_FW 0.00 11,892.97 9,652.00 HK2T 0.00 11,747.09 9,601.00 COAL59 0.00 12/6/2016 3:33:33PM Page 6 COMPASS 5000.1 Build 81 1 • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:K-06RD2 Company: Hilcorp Energy Company TVD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Project: Trading Bay MD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Site: King Salmon North Reference: True Well: Plan:K-06RD2 Survey Calculation Method: Minimum Curvature Wellbore: Plan:K-06RD2 Design: K-06RD2 wp07 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/•W (usft) (usft) (usft) (usft) Comment 8,100.00 6,352.31 -130.77 4,397.91 KOP:Start Dir 12.3°/100':8100'MD,6352.31'TVD:60°RT TF 8,117.00 6,365.17 -133.76 4,408.62 End Dir :8117'MD,6365.17'TVD 8,147.00 6,387.67 -139.54 4,427.60 Start Dir 5°/100':8147'MD,6387.67'TVD 9,210.62 7,375.57 -287.28 4,661.24 End Dir :9210.62'MD,7375.57'TVD 10,216.23 8,353.19 -352.30 4,434.79 Start Dir 5°/100':10216.23'MD,8353.19'TVD 12,143.62 9,698.33 584.11 4,915.77 End Dir :12143.62'MD,9698.33'TVD 13,343.62 9,791.85 1,538.93 5,636.59 Total Depth:13343.62'MD,9791.85'TVD 12/6/2016 3:33:33PM Page 7 COMPASS 5000.1 Build 81 • Hilcorp Energy Company Trading Bay King Salmon Plan: K-06RD2 Plan: K-06RD2 K-06RD2 wp07 Sperry Drilling Services Clearance Summary Anticollision Report 06 December,2016 Closest Approach 30 Proximity Scan on Current Survey Data(North Reference) Reference Design: King Salmon-Plan:K-06RD2-Plan:K-06RD2-K-06RD2 wp07 Well Coordinates:2511,799.44 N,213,762.47 E(60°51'55.93"N,151°36'21.14"W) Datum Height: K-06R02 @ 122.00usft(Kuupik 5) Scan Range:8,100.00 to 13,343.62 usft.Measured Depth. Scan Radius is 1,534.36 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build:81 Scan Type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services • • Hilcorp Energy Company HALLIBURTON Trading Bay Anticollision Report for Plan: K-06RD2-K-06RD2 wp07 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: King Salmon-Plan:K-06RD2-Plan:K-06RD2-K-06RD2 wp07 Scan Range:8,100.00 to 13,343.62 usft.Measured Depth. Scan Radius Is 1,534.36 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 King Salmon K-02-K-02B-K-02B WP1.0 11,187.95 949.74 11,187.95 677.54 14,327.40 3.489 Centre Distance Pass- K-02-K-02B-K-02B WP1.0 11,375.00 977.06 11,375.00 650.00 14,327.40 2.987 Ellipse Separation Pass- K-02-K02-K-02B WP1.0 11,575.00 1,061.02 11,575.00 687.45 14,327.40 2.840 Clearance Factor Pass- K-13-K-13-K-13 8,100.00 860.00 8,100.00 573.70 8,062.59 3.004 Clearance Factor Pass- K-13-K-13 P81-K-13 PB1 8,100.00 860.00 8,100.00 571.41 8,062.59 2.980 Clearance Factor Pass- K-13-K-13RD-K-13RD - - Ill - - -MP K-13-K-13RD2-K-13RD2 9,304.95 373.23 9,304.95 108.30 9,031.55 1.409 Centre Distance Pass- K-13-K-13RD2-K-13RD2 9,350.00 375.10 9,350.00 106.08 9,053.58 1.394 Clearance Factor Pass- K-15-K-15-K-15 8,100.00 1,191.97 8,100.00 764.97 7,600.00 2.791 Clearance Factor Pass- K-15-K-15RD-K-15RD 8,100.00 1,191.97 8,100.00 764.97 7,600.00 2.791 Clearance Factor Pass- K-23-Plan:K-23A-K-23Awp1 10,859.43 938.62 10,859.43 805.53 10,554.67 7.052 Centre Distance Pass- K-23-Plan:K-23A-K-23Awp1 10,900.00 939.13 10,900.00 804.95 10,594.82 6.999 Ellipse Separation Pass- K-23-Plan:K-23A-K-23A wp1 11,475.00 1,067.42 11,475.00 902.62 11,121.03 6.477 Clearance Factor Pass- Plan:K-06RD2-K-O6RD-K-06RD 8,400.00 22.95 8,400.00 19.29 8,376.61 6.265 Clearance Factor Pass- Plan:K-06RD2-Plan:K-06RD2-K-06RD2-RIG 8,100.00 999.10 8,100.00 994.82 7,100.00 233.661 Ellipse Separation Pass- Plan:K-06RD2-Plan:K-06RD2-K-06RD2-RIG 8,125.00 1,024.03 8,125.00 1,019.10 7,100.00 207.411 Clearance Factor Pass- Wildcats McArthur State No.1-MS-1-MS-1 06 December,2016- 15:39 Page 2 of 5 COMPASS • • Hilcorp Energy Company HALLIBURTON Trading Bay Anticollision Report for Plan: K-06RD2-K-06RD2 wp07 Survey tool arouram From To Survey/Plan Survey Tool (usft) (usft) 122.00 2,122.00 NSG_WL 2,222.00 8,100.00 NSG_WL 8,100.00 8,400.00 K-06RD2wp07 MWD_Interp Azi+sag 8,400.00 13,343.62 K-06RD2 wp07 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 I(Distance Between Profiles-Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 06 December,2016- 15:39 Page 3 of 5 COMPASS 110 • HALLIBURTON Project: Trading Bay REFERENCE INFORMATION WELLDErAI1.S:PIan:K-06RD2 NAD 1927(NADCONCOWS) Alaska Zone 04 Site: King Salmon Coordinate(O/E)Reference:Well Plan:K-068D2,True North Water Deem: 73.00 Well: Plan:K-06RD2 Ventral(TVD)Reference:K-061202 a 122.00uea(Kuupik 5) +N/S +F/-W Northing F ting latitude Longitude Spc,r,-y Drilling Measured Depth Reference:K-06RD2 @ 122.00usft(Kuupik 5) 0,00 0.00 2511799.44 213762.47 60°5E51931 N 151°36 21.135 W Wellbore: Plan:K-06RD2 Calculation Method:Minimum Curvature Plan: K-06RD2 wp07 SURVEY PROGRAM GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference iii1'.�lLOr 8100.00 To 13343.62 L Data:2014-06-09700:00:00 Validated:Yea Version: LadderISLE. Plots Depth From Depth To Suryey/Plan Too! CASING DETAILS 122.00 2122.00 K-06(NSG_WL) NSG WL 2222.00 8100.00 K-06RD NSG WL TVD TVDSS MD Size Nam 8100.00 8400.00 K-06RD2 wp07 MWD IntimAzir sag 9791.85 9669.85 13343.62 7-5/8 7-58"x8-I/2" 8400.00 13343.62 K-06RD2 5557 MWD+SC+sag 150.00—_-_ .. 11 I / MS-1 ;120 00 - K-13RD2 \✓ a 90.06 m K-13RD 0_ I • N 60.00 1 1' ' b r ci /,'/ til . /! 1 p, I i:: 1 i 1 0 1 1 . . P� 1 III' ' 1 1 i '�II�� 1 i i 1111111 8100 8400 8700 9000 9300 9600 9900 10200 10500 10800 11100 11400 11700 12000 12300 12600 12900 13200 13500 Measured Depth(600 usWin) 3.00 tr ' _ _! 2.40 _ ,1.80—Collision Risk Procedures Re. c - 0 CO - d120--Collision Avoidance Reg, CO l - No-Go Zone-Stop Drilling 0.60 - MS-1 V 0.00 Irl 1111 1111 11 11 It 1u1 1111 1111 1111 1111 1111 Illi 1111 11II IIII-77-7"--7.1-11 1 : 11 8100 8400 8700 9000 9300 9600 9900 10200 10500 10800 11100 11400 11700 12000 12300 12600 12900 13200 13500 Measured Depth • • TRANSMITTAL LETTER CHECKLIST WELL NAME: 7:,8 c A - O(o /Z a, oUI S&6 __) PTD: 9.16 --13/ ✓ Development Service Exploratory Stratigraphic Test _Non-Conventional FIELD: Mc. 4A giVi_Ar POOL: c, -AD-I iq I V /M ck- o(1 Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10'sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non-Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a)authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application,the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 0 i y en D y. 3 To c c , , , , • , , , , , '' o a c, 1- , :E >, L . ii at a ' o' O o c: ° s' o, Q Y, o v_), p v. y, a, - , o, I H U:0 0' °- o . , E, O. , , , Y• o a aa) , u' N F.'. > 0 I- p p. cc a a ; W, ,- .5. E. , N ti Q ; o' • a, � ,: y rn rn N' a m Z CD •..... ., � y a 0 w, •.-i, c >, w , O , 0Mc4I- � vp , , _: , o, o„ (2,, o0, c 0 Z w ' N m Z V0 �, o 0' , a ' y rn' ay � mp OYca 2' - N. >, . a p, y wa' a , W: O. 0 N>' ' o , 0 • m. , . .roOc, . 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N a O) a) C' .0 a a y x y N N a), ; S 'c ai C 0r 0' a) C C' m Q` a .L„' N U ° U, 2� >, 0' it N a _ '0 -a a (>22, • C m, a a a, -0 .L,. a) in 'y a) a) > .m � L 0 y U C' m C E a aa) a) E a)' a) a� a) m .a), O L, c c , ° 3 2 0 al 0 m $ a) _ �' v°' 2 m _o C'. is a coc 0 m� ' - O 7. 03 N. _,(1) -, 0 co € ) O 0 �� - _ C, U c0 y 0 U C U C .12. C ;' U U O C O O 0 0 y O. t, O 75. :=. V 07 m. 0 a E a) c 0 2 0, .0 J o' . 0' O' O O .92 f6' N -, -• a) O a S > > ;, m 7 7 0 �' 0) n 0 ' 0 0 .. o- 0 U' -I 2 c. �, m. . '- a) =0. E' 0 u. a) €, E, c m 3. m c `mt. H F- 0. 0 0 �. -. a. a. o, o' n v, E m .o. m. c' o. • >, o, a). a� c. a, v ? 0, a). `0, m. O; a 2' 2', 2' m v, m a, E, O, O. L, m m ia, a). a). o, ❑ U Z a _ D •'s. 3. 3 cn, O O; a a U, S: ¢. a; c.) cn, U U, U; U; ¢, w a, o, m, m, U, >,, y, 2, a; p, �, (n, U, 0 M -N V- CO CO(O CO0O 0) O N M d' I1) CO I,- 00 0) O - N M V' (C) CO N- 00 0) 1 E• O ,- N co v- Lo co P- 0o O NNNNNNNNNNNNNNNNN M M M M M -'-'' N 2i co C y O .0. O a.3 O03 N U O M + C 0) p °� p I` O 0I- Wm CV C C CV o' E p J N .„.Ln- d O O O ii ca. O �, QIP a s C Q O 0 Q 0._ 0 a et a w a o OF • 0- ofr-,\1 y/ � THE STATE Alaska Oil and Gas , ,,;,-�� o f e T e c KA Conservation Commission jiff __ 333 West Seventh Avenue r e, Alaska 99501-3572 Anchorage, GOVERNOR BILL WALKER ^+ Main: 907.279.1433 OF ALAS1-e' Fax: 907.276.7542 www.aogcc.alaska.gov Monty Myers Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: McArthur River Field, Hemlock Oil Pool, TBU K-06RD2 Hilcorp Alaska, LLC Permit to Drill Number: 216-131 Surface Location: 736' FSL, 135' FEL, SEC. 17, T9N, R13W, SM, AK Bottomhole Location: 2290' FSL, 246' FWL, SEC. 15, T9N, R13W, 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 Daniel T. Seamount, Jr. Commissioner 744 DATED this/ day of November, 2016. RECEIVE' STATE OF ALASKA Alt OIL AND GAS CONSERVATION COM ��C 2016 M PERMIT TO DRILL 20 AAC 25.005 AOG CC la.Type of Work: 1 h.Proposed Well Class: Exploratory-Gas ❑ Service- WAG ❑ Service-Disp ❑ 1c.Specify if well is proposed for: Drill 0 Lateral ❑ Stratigraphic Test ❑ Development-Oil ❑✓ • Service- Winj ❑ Single Zone 0 • Coalbed Gas 0 Gas Hydrates ❑ Redrill❑✓ ' Reentry ❑ Exploratory-Oil ❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas El 2.Operator Name: 5. Bond: Blanket El Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC ' Bond No. 022035244 TBU K-06RD2 3.Address: 6.Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 MD: 13,322'' ND: 9,795' ' McArthur River Field ' 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Hemlock Oil Pool . Surface: 736'FSL, 135'FEL,Sec 17,T9N,R13W,SM,AK ' (SHL,TPH)ADL017594(BHL)ADL018772 Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 931'FSL,783'FEL,Sec 16,T9N,R13W,SM,AK N/A 11/20/2016 Total Death: 9.Acres in Property: 14.Distance to Nearest Property: 2290'FSL,246'FWL,Sec 15,T9N,R13W,SM,AK, 8956 Acres• 6,064'to nearest unit boundary 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL(ft): 122' ' 15.Distance to Nearest Well Open Surface: x-213762 y-2511799 Zone-4 ' GL Elevation above MSL(ft): 73' to Same Pool: 770'K-13RD2 16.Deviated wells: Kickoff depth: 7,100'feet $ 17.Maximum Potential Pressures in psig(see 20 AAC 25.035)Atv-. �L,., Maximum Hole Angle: 85.5 degrees • Downhole: 4686 Surface: 2471 ' E 't 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD ND MD ND (including stage data) 8-1/2" 7-5/8" 29.7# L-80 Hyd 511 6,422 6,900' 5,503' 13,322' 9,794' 261 sx/350 ft3 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth ND(ft): Plugs(measured): Effect.Depth MD(ft): Effect.Depth ND(ft): Junk(measured): 13,276' 10,070' N/A 13,042' 9,879' 9,400' Casing Length Size Cement Volume MD ND Conductor/Structural 376' 24" To Surface 376' 376' Surface 2,186' 13-3/8" 1760 sx 2,092' 2,092' Intermediate Production 11,958' 9-5/8" 1,050 sx 9,055' 9,055' Liner 1,415' 7" 585 sx 9,917' 9,917' Perforation Depth MD(ft): Perforation Depth ND(ft): 20. Attachments: Property Plat 0 BOP Sketch 0 Drilling Program 0 Time v.Depth Plot 0 Shallow Hazard Analysis Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050 requirements❑ 21. Verbal Approval: Commission Representative: Date 22.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Email mmvers@hilcorp.col71 Printed Name Monty Myers Title Drilling Engineer Signature ^'� • Phone 907-777-8431 Date 10/11/2016 Commission Use Only Permit to Drill�� API Number: Permit Approval See cover letter for other Number: oC)6 -131 50- ?_,3, -a.0085g-ok-oo Date: II I ii `L, 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: ? /� �t � ,3�G3� -5.- /,:�� I /r�-.5 f— Samples req'd: YesRNo[� Mud log req'd:Yesn-No[� MAW / H2S measures: Yes No❑ Directional svy req'd:Yes u No❑ k A >�e r-n,:,6-- I• c..s_�/� .4. L 4.-1: 6 . �( AAf Spacing exception req'd: Yes❑ No[t Inclination-only svy req'd:Yes❑ No Lrl Opp. d....'c., �44 2 ••'1 �`�• `�CC)(1)�A Post initial injection MIT req'd:Yes❑ No❑ IF k i'_ei it v e 1+•..r4-_-1; /p4ej C3pti..v^4.„4;e.)N--C... APPROVED BY ( 7 I A 11Approved by: ' " / COMMISSIONER THE COMMISSION Date: 1 / + ►�O f iCt/ P3172i/� 0,§1v64 //-/ ' /"' Submit Form and Form 10-401(Revised 11/20 5) td�2 the from the date of appit,..val(20 AAC 25.005(g)) Attachments in Duplicate • MontyHilcorp Alaska, LLC Myers 41 Hilcorp Box 244027 Anchorage,AK 99524-4027 Drilling Engineer Tel 907 777 8431 Email mmyers@hilcorp.com Hilcorp Energy Company 10/11/2016 RECEIVE-L) OCT 11 2016 Commissioner Alaska Oil &Gas Conservation Commission A^G�+/�s 333 W. 7th Avenue AOGCC Anchorage, Alaska 99501 Re: K-06RD2 S a' 06 RD Dear Commissioner, ff l K-06RD2 is an oil production well planned to be re-drilled in a North-easterly direction from the existing K-06RD utilizing the existing casing program down to 7100' MD/5640' TVD. At 7100' MD the parent wellbore will be sidetracked and new wellbore drilled penetrating several ✓ Hemlock targets. A 6222'x 8-1/2"open hole section is planned. A 7-5/8" 29.7# L-80 HYD 511 prod liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with a 3-1/2" ESP completion. se/ fi -tac t c� Drilling operations are expected to commence approximately November 20th, 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 1 of 1 • • Hilcorp Alaska, LLC K-06RD2 Drilling Program McArthur River d by: M , Revision 0 October 5, 2016 • • 111 K-06RD2 Drilling Procedure Rev 0 IIil•orp;11a.ka.LIAI 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 10 10.0 BOP N/U and Test 11 11.0 Mud Program and Density Selection Criteria 12 12.0 Whipstock Running Procedure 13 13.0 Whipstock Setting Procedure 16 14.0 Drill 8-1/2"Hole Section 19 15.0 Run 7-5/8"Production Liner 22 16.0 Cement 7-5/8"Production Liner 25 17.0 Wellbore Clean Up&Displacement 29 18.0 Run Completion Assembly 30 19.0 RD 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 Fluid Flow Diagrams 39 29.0 Offset MW vs.Depth TVD 42 30.0 Casing Design Information 43 31.0 8-1/2"Hole Section MASP 44 32.0 Plot(NAD 27)(Governmental Sections) 45 33.0 Slot Diagram (As Built) (NAD 27) 46 34.0 Directional Program (wp04a) 48 • • K-06RD2 Drilling Procedure Rev 0 Ilileorp:11a,ka.L1.1: 1.0 Well Summary Well K-06RD2 Pad&Old Well Designation Sidetrack of existing well K-06RD(PTD#188-028) Planned Completion Type 7-5/8"29.7#L-80 Liner, 3-1/2"Tubing w/ESP Target Reservoir(s) Hemlock Producer H1-H3 Planned Well TD, MD/TVD 13322' MD/9795' TVD PBTD, MD/TVD 13200' MD/9785' TVD Surface Location(Governmental) 736' FSL, 135' FEL, Sec 17, T9N,R13W, SM,AK Surface Location(NAD 27) X=213762.47, Y=2511799.44 Surface Location(NAD 83) Top of Productive Horizon (Governmental) 931'FSL, 783'FEL, Sec 16, T9N, R13W, SM, AK TPH Location(NAD 27) X=218396.5,Y=2511892.49 TPH Location(NAD 83) BHL(Governmental) 2290'FSL, 246'FWL, Sec 15, T9N,R13W, SM,AK BHL(NAD 27) X=219456.18,Y=2513226.58 BHL(NAD 83) AFE Number 1613025D AFE Drilling Days AFE Drilling Amount $4.6 MM Work String 4" 14# S-135 XT-39 (From Weatherford) RKB—AMSL 122' MSL to ML 73' BOP Equipment 13-5/8" 5M Hydril"GK"Annular BOP 13-5/8" 5M Cameron Type U Double Ram 13-5/8" 5M Cameron Type U Single Ram Page 2 Revision 0 October, 2016 • • K-06RD2 Drilling Procedure Rev 0 nacor!, kla4a. 2.0 Management of Change Information Hilcorp Alaska, LLC Hilcorp FAIOU Cir Changes to Approved Permit to Drill Date: October 7,2016 Subject Changes to Approved Permit to Drill for K-06RD2 File#: K-06RD2 Drilling Program Any modifications to K-06R D2 Drilling Program will be documented and approved below. Changes to an approved APD will be communicated and approved by the AOGCC prior to continuing forward with work. Sec Page Date Procedure Change Approved Approved By By • Approval: Drilling Manager Date Prepared: Monty M Myers 10.07.2016 Drilling Engineer Date Page 3 Revision 0 October, 2016 • • K-06RD2 Drilling Procedure Rev 0 I lilearp:llaxka..PI E 3.0 Tubular Program Hole Section OD (in) Wt(#/ft) Coupl OD ID(in) Drift(in) Grade Conn Top Bottom 8-1/2" 7-5/8" 29.7 7.625 6.875 6.75 L-80 HYD 511 6900 13322 4.0 Drill Pipe Information Hole OD (in) ID(in) TJ ID TJ OD Wt Grade Conn Burst Collapse Tension Section (in) (in) (#/ft) (psi) (psi) (k-lbs) 8-1/2" 4" 3.34" 2.813" 4-7/8" 14 S-135 XT-39 17,820 13,836 403 All casing will be new, PSL 1 (100%mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Revision 0 October, 2016 • S K-06RD2 Drilling Procedure Rev 0 IIil4•urp ua.ka.II 5.0 Internal Reporting Requirements 5.1 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. 5.2 Afternoon Updates v. Submit a short operations update each work day to pmazzolini@hilcorp.com, Ikeller@hilcorp.com,mmyers@hilcorp.com and cdinger@hilcorp.com 5.3 5am Weekend Update vi. 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. vii. Copy pmazzolini@hilcorp.com, Ikeller@hilcorp.com and mmyers@hilcorp.com 5.4 EHS Incident Reporting viii. 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. Leonard Dickerson: 0: (907) 777-8317 C: (907)252-7855 b. Mark Tornai: 0: (907)283-1372 C: (907)748-3299 c. Thad Eby: 0: (907)777-8317 C: (907)602-5178 2. Spills: a. Julieanna Orczewska: 0:907-777-8444 C:907-715-7060 b. Keegan Fleming: 0:907-777-8347 C:907-350-9439 ix. Notify Drlg Manager 1. Paul Mazzolini: 0: 907-777-8369 C: 907-317-1275 x. Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally xi. Send final "As-Run"Casing tally to mmyers@hilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cmt report xii. Send casing and cement report for each string of casing to mmyers@hilcorp.com and cdinger@hilcorp.com Page 5 Revision 0 October,2016 • • HK-06RD2 Drilling Procedure Rev 0 Ifilc orp Alaska.1.1.1: 6.0 Planned Wellbore Schematic II SCHEMATIC McArthW Ku-06R02 Feld Ilikary Alaska.1.1.0 CASING DETAIL SIZE WT GRADE CONN TOP BTM. description JL 24' - Surf 376' Conductor , 13-3/8' 61 YSS 8TC Surf 2,186' Casing 9-sir 53 5-95 13TC Surf 1,968' Cosine 9-sir 47 1-80 8TC 1,968' 7,100' Caste 7-sir 29.7 1-8D Hyd Sil 6.900' 13,322' liner Cr E) G . . 1 z JEWELRY DETAIL No Depth(MD) ID Item 1 ±6,900' Depth ±5,503' 6.059" Inline Baker Liner Hanger/Packer 2 ±7,100' ±5,640' - KOP 3 ±6,900'-13,322' _ ±9,663' 6.059" 7-5/8"29.7#L-80 HYD 511 3 ©L ✓t r''"'�'" "i l 1 CEMENT DETAIL ^ 4 TOC Depth TOC Depth 4 No (MD) (TVD) Volume Item 4 ±10,000' ±7,459' 62 bbis 15.3 ppg Class G cement w/54 bbl cemnet LCM • w NI . ..,.. , •- 113.13.32/WI j vela 132W Pio Max ItleAVe=WS' Page 6 Revision 0 October,2016 • K-06RD2 Drilling Procedure Rev 0 II iieor1,:1la+ka.1.I A 7.0 Drilling Summary K-06RD2 is an oil production well planned to be re-drilled in a North-easterly direction from the existing K- 06RD utilizing the existing casing program down to 7100' MD/5640' TVD. At 7100' MD the parent wellbore will be sidetracked and new wellbore drilled penetrating several Hemlock targets. A 6222' x 8-1/2"open hole section is planned. A 7-5/8"29.7#L-80 HYD 511 prod liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with a 3-1/2"ESP completion. Drilling operations are expected to commence approximately November 20th, 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&A4 and wellbore preparation for the sidetrack and for running the completion assembly General sequence of operations pertaining to this approved drilling procedure: 1. Kuukpik Rig 5 will be over slot 30(K-06RD) to de-complete and P&A well under separate rt sundry. 2. DP should be stood back in derrick 3. PU whipstock, and mills and TIH to CIBP 4. Orient whipstock and set at 45 deg right of highside. 5. Mill 8-1/2"window and 20' of new formation at 7100'. 6. POOH and LD mills. PU directional BHA and TIH to window. 7. Swap well to 9.0 ppg oil based drilling mud 09 8. Perform FIT to 12.5 ppg EMW 9. Drill 8-1/2" production hole from 7120' to 13322' MD, performing short trips as needed 10. Perform short trip and condition mud. POOH 11. LD Directional Tools. RIH w 7-5/8" liner. Set liner and cement. Circ wellbore clean. 12. POOH, laying down DP and liner running tools, 13. PU 7-5/8" casing scraper assembly and TIH to landing collar. 14. Circ casing clean. POOH laying down DP. 15. Run 3-1/2" completion. (Covered under separate sundry) 16. Land hanger and test. 17. ND BOPE,NU tree and test void Page 7 Revision 0 October, 2016 • K-06RD2 Drilling Procedure Rev 0 Ilileorp %1:1,ka.11.1: 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 K-06RD2. Ensure to provide AOGCC 48 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 5/5 min(annular to 50%rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, we must test ALL BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system" • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements" • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. Variance Requests: o Hilcorp would like to request a variance to regulation 20 AAC 25.035(e)(4)(F)(i) which states - "the outlets must be at least two inches in nominal diameter, except that for rotary drilling rig operations, if the operation has a maximum potential surface pressure of greater than 3,000 psi, the nominal diameter of the choke outlets must be at least three inches". • The calculated MASP for this wellbore when completely evacuated to gas is 3218 psi. However, sp,x4 for Cook Inlet Operations, we assume that the well can never flow 100% gas, due to the water in 1) the reservoir. We reduce this MASP calculation to 2471 psi which assumes that only 2/3 of the wellbore is evacuated to gas and 1/3 to 9.0 ppg reservoir fluid. o Hilcorp would like to request to have 2-1/16" outlets on the choke line and kill line due to this assumption 44j 11 Page 8 Revision 0 October, 2016 • • K-06RD2 Drilling Procedure Rev 0 Meng,i 1.orp.11a'ka. Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) • 13-5/8"Shaffer 5M annular • 13-5/8"5M Shaffer SL Double gate Initial Test:250/3500 • Blind ram in bottom cavity (Annular 2500 psi) 8-1/2" • Mud cross • 13-5/8"5M Shaffer SL single gate Subsequent Tests: • 3-1/16"5M Choke Manifold 250/3500 (Annular 2500 psi) • Standpipe,floor valves,etc • Primary closing unit: Control Technology Accumulator, 3000psi, 5 station, 170 gallon reservoir, 4 nitrogen backups and 12 bladder bottles. • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Secondary back-up is an air pump, and tertiary 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). • 48 hours notice prior to spud. • 48 hours notice prior to testing BOPs. • 48 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Additional requirements may be stipulated on APD. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email:jim.regg@alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-301-4533 /Email:guy.schwartz@alaska.gov Victoria Loepp/Petroleum Engineer/(0): 907-793-1247/Email: victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone: 907-793-1236 (During normal Business Hours) Notification/Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Revision 0 October, 2016 40 • K-06RD2 Drilling Procedure Rev 0 Ha.".%Ia+ka.1.1.1: 9.0 R/U and Preparatory Work 9.1 Separate sundries will be submitted that will include the following: • Pull tubing 316— Lf cj a • P&A lower perfs with a cement plug • Set CIBP - PSA 9.2 Mix mud for 8-1/2" hole section. -06, 9.3 Verify 4.5" liners installed in mud pump #1 and 5.5" liners installed in pump #2. Ai-r4./� • Ellis Williams WH-1000 Pumps are rated at 3500 psi (100%)with 4.5" liners and can deliver 171 gpm at 86 spm. • TSM 1000 Pumps are rated at 3500 psi (100%)with 5.5" liners and can deliver 229 gpm at 86 spm. • Ideal pump rate for drilling will be 400 gpm. Both pumps running at 86 spm should achieve this. Pump#1 Ellis Williams WH1000 10" Stroke Pump#2 TSM 1000 9" Stroke 96% Efficiency Max psi 3500 psi 96% Efficiency Max psi 3500 psi Liner Size bbls/stroke Liner Size bbls/stroke 4.5 0.0472 5.5 0.0635 Strokes/minute bpm gpm Strokes/minute bpm gpm 20 0.94 40 20 1.27 53 40 1.89 79 40 2.54 107 60 2.83 119 60 3.81 160 86 4.06 171 86 5.46 229 100 4.72 198 100 6.35 267 120 5.67 238 120 7.62 320 140 6.61 278 150 7.08 297 Page 10 Revision 0 October, 2016 • • K-06RD2 Drilling Procedure Rev 0 IIih ur1,.Ua4ka.1.I.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 13-5/8"x 5M BOP as follows (top down): • 13-5/8" x 5M Shaffer annular BOP. • 13-5/8" Shaffer Type "SL" Double ram. (2-7/8" X 5-1/2"VBR in top cavity, blind ram in btm cavity) • 13-5/8"mud cross • 13-5/8" Shaffer Type "SL" single ram. (2-7/8"X 5-1/2"VBR) • N/U pitcher nipple, install flowline. • Install (2) manual valves on kill side of mud cross. Manual valve used as inside or"master valve". • Install (1)manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 10.3 Run BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/3500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave "A" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Confirm the correct valves are opened!!! • Test 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 8-1/2" hole section. 10.6 Set wearbushing in wellhead. Ensure ID of wearbushing> 7-5/8". Page 11 Revision 0 October, 2016 • • K-06RD2 Drilling Procedure Rev 0 I Iile•orp.11a.ka,1.1,1: 11.0 Mud Program and Density Selection Criteria 11.1 8-1/2" Production hole mud program summary: Primary weighting material to be used for the hole section will be barite to minimize solids. We will have enough barite on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. Canrig PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.0 ppg 80/20 Enviromul MOBM Properties: MD Mud Weight Viscosity PV YP HTHP WPS ES (PPg) 1 7,100—13,322' 9.0-9.5 4/ 50-80 25-35 15-22 <5 250-270K >580 System Formulation: 80/20 Enviromul MOBM Product Concentration LVT 0.662 bbl Water .172 bbl INVERMUL NT 4 ppb EZ MUL NT 4 ppb GELTONE V 6-10 ppb Lime 7 ppb DURATONE HT 2 ppb Calcium Chloride 21 ppb BAROID 41 9.0 ppg(as needed) BARACARB 5 3-5 ppb BARABLOK 2 ppb BAROTROL PLUS 4 ppb 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 12 Revision 0 October,2016 s'� • • K-06RD2 Drilling Procedure Rev 0 II ik•orp:t Ia•ka.II 1 12.0 Whipstock Running Procedure Section 12.1 through 12.5 is covered under decompletion sundry, drilling proceed to 12.6 12.1 M/U window milling assembly and TIH w/4-1/2" DP out of derrick. • Use a 8-1/2"taper mill and an 8-1/2" 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 (7100' 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 Make up mills on a joint of HWDP. 12.7 RIH & set in slips. 12.8 Make up float sub, install float. 12.9 Leave assembly hanging in the elevators, and stand back on floor. 12.10 Bring Whipstock to rig floor on the pipe skate. Do not slam into bottom of Whipstock with pipe skate. 12.11 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. 12.12 If needed, open BOP Blinds. Page 13 Revision 0 October, 2016 • K-06RD2 Drilling Procedure Rev 0 IIilcorp.1.64.A.1 If: 12.13 Run the Whipstock in the hole, install safety clamp as per Baker Rep, and install hole cover wrap. 12.14 Release pick up system at this point, Make up mills. 12.15 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. 12.16 The assembly can now be picked up to ensure that the shear bolt is tight. 12.17 Remove the handling system. 12.18 Slowly run in the hole as per Baker Rep. Run extremely slow through the BOP & wear bushing. 12.19 Run in hole at 1 '/2 to 2 minutes per stand. 12.20 Fill every 30 stands or as needed, do not rotate or work the string unnecessarily. 12.21 Call for Baker Rep. 15 — 10 stands before getting to bottom. 12.22 Orient at least 30' —45' above the CIBP. Page 14 Revision 0 October, 2016 iii • • K-06RD2 Drilling Procedure Rev 0 IIjI,,, 1 v:uka.1.1.1: i �. Window Master G2 Whipstock BAKER �a! With Torque Master Bottom Trip Anchor HUGHES O`o, 9.625 53.5#Non Special Drift Casing le Baker Oil Tools • im • Upper Watermelon Mill • OD: 8.500 8.500 --* Illi 4— 6.25 Length: 6.25 Flex Joint OD: 6.375 ■ • Length: 9.00 W 6.375 —► ' 4— 9.00 Lower Watermelon Mill OD: 8.375 M Length: 5.66 • v M Window Mill 40.6 MI OD: 8.500 8.250 —45.66 Length: 1.13 l I Whipstock • OD: 8.000 8.500 _ 4_ Length: 18.54 WI 1.13 Face Angle: 1.9 • i<,;._ Face Length: 17 08 I Retrieval BTA OD: 8.357 17.08 Length: 3.11 18.54 1.9 Overall length --t' Length: 44' WELL INFORMATION CUSTOMER FIELD _ —, 4— 8.000 LEASE I Ii WELL NO. � BOLT 25,000 3.41 , r 35,000 8.357 —I, :�i F— 45,000 I+ 55,000 !!I _65,000 I 75,000 NOTE: DIM ENSIONS AR BASED ON TECH UNIT DATA,ACTUAL DIM ENSIGNS M AY VARY Page 15 Revision 0 October, 2016 • • Ei K-06RD2 Drilling Procedure Rev 0 Ilik•orp.Ua.ka.IAA: 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 highside MWD. 13.2 Orient Whipstock to desired direction by turning DP in I/4 round increments. P/U and S/O on DP to work all torque out(Being careful not to set BTA). Whipstock Orientation Diagram: 30 L HS C--)",,, 60 L HS Desired orientation of the Whipstock face is 45 degrees right of high side. Hole Angle at window interval (7100' MD) is 47 deg. The wellbore trajectory is planned to kick off at 102 degrees azimuth. 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 C't Pc 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 9.0 ppg 70/30 Enviromul MOBM. 13.7 Record P/U, S/0 weights, and free rotation. Slack off to top of whipstock and with light weight V and low torque. Mill window. Utilize 4 ditch magnets on the surface to catch metal cuttings. A/A/ 13.8 Install catch trays in shaker underflow chute to help catch iron. l 13.9 Keep iron in separate bbls. Record weight of iron recovered on ditch magnets. Page 16 Revision 0 October,2016 • 411 K-06RD2 Drilling Procedure Rev 0 Ilileorp. Iaxku.I.I.1: I 13.10 Estimated metal cuttings volume from cutting window: Wieght of Cuttings For Milled Casing Exit O.O. Of Casing(in) 9.625 I.D. Of Casing(in) 8.535 Whipstock Face Length(Ft) 16.00 Percent of Casing Removed(%)* 38 Milled Area(in^12) 5.908 Volume of Cuttings(in^3) 1134.272 Density of Casing (Ib.Iin^3)** 0.283 Weight of Cutting Generated (lbs) 321.0 •Calculated Average of Casing Removed Based on Drift Mills(38%) **Density of Steel= .283 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. r • (12.5 —9.0) * 0.052 * 5640' tvd= 1027 psi r (T. 13.14 Kick Tolerance • 12.5-9.0) * (5640/9795) = 2.01 _ -- 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 2.01 ppg kick tolerance while drilling the interval with a 9.0 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. Page 17 Revision 0 October, 2016 11110 ! K-06RD2 Drilling Procedure Rev 0 I!Hemp. Ia.ka.IAA: Back Up Mills Connection Length O.D. WINDOW MILL 4 % REG-P X MILL 2.25 8.5 NEW LOWER WATERMELON MILL 4 1/2 REG-P X 4 'h REG-B 5.5 8.5 FLEX JOINT 4 1/2 REG-P X 41/2 REG-B 9.0 6.375 STRING MILL 4 % REG-P X 41/2 REG-B 5.5 8.5 FLOAT SUB 4 1/2" IF-B X 4 '/2' REG-B 3.0 6.375 30 jts-HWDP 4 1/2"XH-B X 4 '/" REG-P 900' 6.5 CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE. BHA'S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY! Page 18 Revision 0 October, 2016 HS • K-06RD2 Drilling Procedure Rev 0 nil." Ia.ka.I.I.1 14.0 Drill 8-1/2" Hole Section 14.1 P/U 8-1/2" directional drilling assy. 14.2 Ensure BHA Components have been inspected previously. 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 0.51 -0.61 sqin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 375-450gpm. 14.6 Motor AKO should be set at 1.2 deg. Must keep up with 5 deg/100 DLS in the build section of the wellbore. 14.7 Primary bit will be the Varel 8-1/2" VM613P PDC bit. Ensure to have a back up bit available on location. COMPONENT DATA Item Description Serial Number ; gleng ulative # (in). (in)' °" (in) (ibpf) Connection (ft) . Length (ft) 1 HOBS-PDC 8.400 2.500 8.500 172.13 P 4-112`REG 1.20 1.20 2 7"SperryDnll Lobe 7'8-7.5 stg 7.000 4.952 95.69 B 4.1'2"IF 29.48 30.68 Stabilizer 8.375 3 Non Mag Float Sub 6.750 2.750 101.71 B 4-1 2"IF 3 00 33.68 4 Integral Blade 6.750 2.750 8.375 101.71 B 4.1;2"IF 3.60 37.28 5 6 3'4'DM Collar 6.750 3.125 103.40 B 4-1 2'IF 9.20 46-48 6 6 34"DGR Collar 6.750 1.920 97.80 B 4-12"IF 4.55 51.04 7 6 3 4"EWR-P4 Collar 6.750 2 000 104.30 B 4-112"IF 12.10 63.14 8 Inline Stabilizer(ILS) 6.750 1.920 8.375 112.09 B 4-112"IF 3.20 66.34 9 6 34"PWD 6.750 1.905 96.30 8 4-12'IF 4.44 70.78 10 6 34"HCIM Collar 6.750 1.920 101.70 B 4-12"IF 4.97 75.74 11 6 3 4"TM-HOC(Pulser) 6.900 3.250 103.60 8 4-12"IF 15.50 91.24 12 6-34"Non Mag Flex Drill Collar 6.750 2.813 100.77 B 4-1,2"IF 30.00 121.24 13 6.3'4'Non Mag Flex Drill Collar 6.750 2.813 100.77 B 4-1 2-IF 30.00 151.24 14 6-3 4"Non Mag Flex Drill Collar 6.750 2.813 100.77 30.00 181.24 15 6 Joint 5'HWDP 5 000 3.000 49.30 180.00 361.24 16 6-1,14'Weatherford Hydraulic Jar 6.250 2.250 91.01 30.00 391.24 17 14 Joints 5'HWDP 5.000 3.000 49.30 420.00 811.24 TOW• >; 811.24 Page 19 Revision 0 October, 2016 • S HK-06RD2 Drilling Procedure Rev 0 Ililcorp Alaska,IIA: 8 1/2" (215.9mm) ;; Toot's .u ..i Assembly. A09143 vM61 w Navigator. IADC Code: M433 t` PRODUCT SPECIFICATIONS .0-- Cutter Size: 13 mm j \ • --"NCutter Back Up: 13mm PDC &Replaceable Shock Studs `` ON1. S ‘ Cutter Count: 76 • c ,, Face Cutter Count: 58 Connection: 41/2"API Regular 1, ‘, 441 riC ,w Nozzle 1 Qty/Type: 6-Series 55 -, Nozzle 2 Qty/Type: k Junk Slot Area: 14.3in2(.9- 92.3cm2) Gage Pad Length: 2 1/2"(64mm) Make Up Length: 11.4"(288.8mm) iiii Shank Diameter: 5.8"(147.3mm) OPERATING PARAMETERS' Rotary Speed: For all rotary and motor applications / Flowrate Min Max: 250-750GPM(0.95-2.84m3/min) ° Max Weight On Bit: 42000lbs(18683daN) • ,� Makeup Torque: 12000-16000Ft-Lbs.(16270-21693Nm) �'.. 'Operat>ng parameters Chown are typ=ca:for the to type specifiwe. .s�. *. For recornmen0airoas on your specefic appkca5oncontact your A,. Valet int rnat^onai represerAative Navigator Series Bits -Varels six step design/manufacturing process utilizes GeoScience interpreted logs. proprietary design software SPOT.3D modeling programs,CFD.and specialized manufacturing techniques to produce the best possible bit for the application. Navigator bits are engineered to a specific Directional profile for a given application. Navigator bits possess the key design elements affecting bit steerability and directional behavior helping you achieve your drilling objectives. Bit Features P -Partial PowerCutters'"' provide extra cutter density on the shoulder reducing excessive wear or cutting structure damage when drilling interbedded formations. Shock Studs -Shock studs limit drill bit vibration and increase stability allowing smooth cutting action increasing cutter life and overall bit performance. Updrlil Cutters -PDC cutters strategically placed to help reduce hole problems when up drilling or back reaming. Premium Gage -The premium gage consists of thermally stable polycrystalline diamond and pdc(polycrystalline diamond compact)cutters:designed to insure that correct hole diameter is maintained. r VAR EL www.vareiinti.com Page 20 Revision 0 October, 2016 , • • K-06RD2 Drilling Procedure Rev 0 m11'0111 %1.1.k1.I.I.I 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 8-1/2"hole to 13322' MD using motor assembly. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team,try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • See attached mud program for hole cleaning and LCM strategies. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. • Ensure mud engineer set up to perform HTHP fluid loss. • Maintain API fluid loss < 6. • Take MWD surveys every stand drilled. • Minimize backreaming when working tight hole 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 October, 2016 • K-06RD2 Drilling Procedure Rev 0 Ilileorp.\la ka.1.1.1: 15.0 Run 7-5/8" Production Liner a/o M _ 15.1 R/U Weatherford 7-5/8" casing running equipment. -7,5� `f • Ensure 7-5/8"HYD 511 x 4"XT39 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. /mss F' • 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 on stop rings, one per joint to 10,000' MD. • Ensure proper operation of float shoe & FC. 15.4 Continue running 7-5/8"production liner • Fill casing while running using fill up line on rig floor. • Use "API Modified"thread compound. Dope pin end only w/paint brush. • Install solid body centralizers on every other joint to window. Leave the centralizers free floating. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 7-5/8" HYD 511 M/U torques Casing OD Minimum Maximum Yield Torque 7-5/8" 5,900 ft-lbs 10,300 ft-lbs 52,000 ft-lbs Page 22 Revision 0 October, 2016 K-06RD2 Drilling Procedure Rev 0 Ilileorp:tlaska.1.1.1: Tenaris Hyd rul Size: 7.625 in. Wall: 0.375 in. Weight: 29.70 lbs/ft Connection: Wedge 511' Grade: L80.1 Casing/Tubing: CAS Min. Wall Thickness: 87.5 % PIPE BODY DATA GEOMETRY Standard Drift Nominal OD 7.625 in. Nominal Weight 29.70 lbs/ft 6.750 in. Diameter Special Drift Nominal ID 6.875 in. Wall Thickness 0.375 in. N/A Diameter Plain End Weight 29.06 lbs/ft PERFORMANCE Body Yield 683 x 1000 lbs Internal Yield 6890 psi SMYS 80000 psi Strength Collapse 4790 psi Via: WEDGE 511'" CONNECTION DATA GEOMETRY Connection OD 7.625 in. Connection ID 6.787 in, Make-Up Loss 3.700 in. Critical Section 5.218 sq. in. Threads per in. 3.28 Area PERFORMANCE 417 x 1000 Internal Pressure Tension Efficiency 61.1 % Joint Yield Strength 6890 psi lbs Capacity Compression Compression 504 x 1000 lbs 73.8% Bending 29°/100 ft Strength Efficiency External Pressure 4790 psi Capacity MAKE-UP TORQUES 7100 ft-lbs maximum t'l 10300 ft-lbs OPERATIONAL LIMIT TORQUES Operating Torque 35000 ft-lbs Yield Torque 52000 ft-lbs BLANKING DIMENSIONS Blanking Dimensions Page 23 Revision 0 October, 2016 I K-06RD2 Drilling Procedure Rev 0 Ililr•orp.Uauku.I.I.I: 15.7 Ensure to run enough liner to provide for approx 200' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. 15.8 Before picking up Baker SDD 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 SDD 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 9-5/8" window prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 15.15 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 October, 2016 • • K-06RD2 Drilling Procedure Rev 0 Ililr•orp.tlaska.IAA: 16.0 Cement 7-5/8" Production Liner • 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 15 bbls 12.5 ppg MUDPUSH II spacer. 16.4 Test surface cmt lines to 4500 psi. 16.5 Mix and pump 62.4 bbls of 15.3 ppg class "G" cmt per below recipe with 0.5 lb/bbl of Cemnet or equivalent loss circulation fiber. Ensure cmt is pumped at designed weight. Job is designed to pump 25% OH excess but if fluid caliper dictates otherwise we may increase excess volumes. Cement volume is designed to bring cement up to a minimum of 500' above hemlock in annulus of 7-5/8" casing and 8-1/2" open hole. Est TOC 10000' TMD. y 16.6 Displacement fluid will be drilling mud. --32.5-bbls of displacement fluid 1 02cit. ,7 S 6/1c 56,8 /3436-s Cement Calculations 8-1/2"OH x 7-5/8"Liner: (13322' — 10000') x 0.01371 x 1.25 = 56.9 bbls Shoe Track: 120' x 0.04591 = 5.5 bbls Total Volume(bbls): 56.9 + 5.5 = 62.4 bbls Total Volume(ft3): 62.4 bbls x 5.615 ft3/bbl= 350 ft3 Total Volume(sx): 350 ft3 / 1.34 ft3/sk= 261 sx 700 t,•coNN x v N5/0 13 3 pip-g (4,106 x DI o APers. `,. -2't3, 73--- 36,5 a3 Page 25 Revision 0 October, 2016 • • K-06RD2 Drilling Procedure Rev 0 Ilileorp I. 'ka..LLI: 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 Code Description Concentration G Cement 94 lb/sk D046 Anti Foam 0.2% BWOC Additives D202 Dispersant 1.5% BWOC D400 Gas Control Agent 0.8% BWOC D154 Extender 8.0% BWOC 16.7 Drop DP dart and displace with drilling mud. 36, 664._ s 16.8 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 16.9 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns &pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 16.10 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. 16.11 Slack off total liner weight plus 30k to confirm hanger is set. 16.12 Do not overdisplace by more than %2 shoe track(-1 bbls). Shoe track volume is 14 bbl�.— 16.13 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner 66L— Page 6L-- Page 26 Revision 0 October,2016 ! i K-06RD2 Drilling Procedure Rev 0 IIiI orp \la,ka.I.I.1: 16.14 Bleed pressure to zero to check float equipment. 16.15 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve 16.16 Rotate slowly and slack off 50k downhole to set ZXP. 16.17 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS profile. 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). 16.18 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. 16.19 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. 16.20 Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 16.21 POOH, LDDP. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 16.22 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. 16.23 NOTE: Some hole conditions may require movement of the drillpipe to "work"the torque down to the setting tool. 16.24 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 October, 2016 I • K-06RD2 Drilling Procedure Rev 0 IIilearp 11a.ka.I.IA. Ensure to report the following on Wellez: • Pre flush type,volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing,bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether 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 mmvers(&hilcorp.com Page 28 Revision 0 October, 2016 • • K-06RD2 Drilling Procedure Rev 0 Ilil•orp.\la�ka.I.I.I: 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. • 6-3/4"bit or mill • Casing scraper& brush for 7-5/8"29.7# casing • +/- 5000' 2-7/8" workstring. • Casing scraper& brush for 9-5/8" 53.5# casing • (2000') 4-1/2" DP • Casing scraper& brush for 9-5/8" 53.5# casing • 4-1/2"DP to surface. 17.2 TIH & clean out well to landing collar(+/- 13,080' 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 6-3/4"bit is worked down to the landing collar. • Space out the cleanout BHA so that the 6-3/4" bit reaches the 7-5/8" landing collar when crossover is +/- 30' above the 7-5/8" liner top. 17.3 After wellbore has been cleaned out satisfactorily using mud, test casing to 2500 psi/30 min. Ensure to chart record casing test. 17.4 Displace drilling fluid in wellbore with a hi-vis pill followed by filtered inlet water. • Circulate 3 to 4 B/U until clean-up is satisfactory. Do not recirculate fluid, pump and dump • After a couple circulations using FIW, short trip the assy to bring the upper 7-5/8"multi-back assy to surface. • RIH again &tag landing collar w/6-3/4"bit. Continue circulation as necessary until fluid cleans up. Make another short trip if necessary. • Pump a chemical train followed by FIW. Target NTU's are 80-100 17.5 TOH w/clean out assy. LDDP on the trip out. L/D the 2-7/8" work string. Page 29 Revision 0 October, 2016 — a . • K-06RD2 Drilling Procedure Rev 0 IIikorp;11a..ka.I.1A 18.0 Run Completion Assembly 18.1 Run 3-1/2"tubing completion assembly as per separate Approved Completion Sundry- CCP 19.0 RD 19.1 Install BPV in wellhead. RILDs. 19.2 ND BOPE,NU tree, test void 19.3 Rig Down Page 30 Revision 0 October,2016 • • K-06RD2 Drilling Procedure Rev 0 Ililsorp.5lu La.LL1: 20.0 BOP Schematic „ 16" Pipe III!Iil!IIIiII II nommim lil ill iii ill III imp Iii til 3.74' Shaffer 135/8 SM lel lie lie lie me 111111111. AdarkX1PIr „ 2 7/8.5.5 Variables 2.83' ,—I 135/85M Blind 2 1/16 5M manual valves 2 1/16 SM m 11 and HCR valve • '"• '/1 I11 til X11 111 I11 1.76 ; t Ili Ill Ill III III 1.44' 2 7/8.5.5 Variables I{ 111 lit 111 111 I/1 Drill deck 13.70 Riser 135/85MFEX 13 5/8 5M API hub 0' 0 Page 31 Revision 0 October, 2016 • • HK-06RD2 Drilling Procedure Rev 0 Ililcorp Alaska.I.1.1: 21.0 Wellhead Schematic King Salmon Tubing hanger,FMC-UH- K-6RD TC-IA-EN,13 5/8 SM X 4 34 24 X 133/8 X 95/8 X 31/2 IBT lift and cusp,w/4"type IS BPV BHTA,B-11-A-0,4 1/16 5M FE 3 Valve,Swab,FMC-75, Y 0 4 1/16 SM FE,HWO,EE " ���++ Valve,Wing,SSV, trim •��i.L•" FMC-20,31/8 SM FE, 130 Axelson oper, '° EE trim _ Q Valve,Master,FMC-75, � " 4 1/16 5M FE,HWO,EE J j1, trim liiiiiiiii t- • Adapter,FMC-ASP,13 5/8 SM API clamp X 41/16 5M,w/7" extended neck pocket i i I 19111 li Unihead,OCT type 3,13 5/8 SM API r r 0". 9 IIg 11 l' hub top X 13 3/8 BTC casing bottom, 1I f�� w/1-2 1/16 5M SSO on lower section,1.2 1/16 SM SSO on middle section,3-2 1/16 SM 550 on upperIL I rr : ? All annular valves are section,IP internal lockpin assy -- C: ;i :I l• 2 1/16 SM FMC 20 ..1 k,' t-l.�'U ' ....... . i 411/ Starting head,FMC, 21'''A2MX24"SOW, I II . w/1-31/8 2M EFO .1 I 1 111 13 3/R' ^�.n5/8 Page 32 Revision 0 October, 2016 • K-06RD2 Drilling Procedure Rev 0 Ilileorp.Uaska.1.1,1: 22.0 Days vs Depth Days Vs Depth 0 K-06RD2 2000 4000 6000 L yD y 7 d si 8000 10000 12000 -- 14000 r 0 5 10 15 20 25 30 Days Page 33 Revision 0 October, 2016 H0 • K-06RD2 Drilling Procedure Rev 0 liii,orI, Ua.ka,IIA 23.0 Geo-Prog GEOLOGICAL PROGNOSIS WELL NAME: KO6RD2 FIELD: ' MCARTHUR RIVER SURFACE X: 213762.47 As-Built Survey STATE: Alaska SURFACE Y 2511799.44 BOTTOM HOLE X: 219456.18 TVD REF DATUM KB BOTTOMHOLE Y 2513226.58 TVD REF ELEV 122 Based on new rig config. COORD REF.SYSTEM NA D27 AK4 True North GROUND ELEV 0.0 PROPOSED TD: 13322 MD WATER DEPTH 73.0 PROPOSED TD: 9795 TVD Drill a sidetrack out of the K-06RD (King Salmon)to test and complete the Hemlock H-1 thru H-2 benches . Hit Target 1 at 57° INC and 37°AZM with 200' Pump Tangent above that. Build to 8515° INC and hold to Objective: 13322' MD. Geo Summary/ Based on subsurface evaluation Justification: KO6RD2 TARGETS,ANTICIPATED FORMATION TOPS& GEOHAZARD :" MD TVD(F71 TVDSS(F7) 1 Est. I pm,/Pressure KOP Sand/Conglomerate 7317 5,666 -5666 2453 8.33 COAL39 Coal 10831 9,137 -9015 3956 8.33 H1X_FW Sand/Conglomerate Oil Sand 11557 9,575 -9453 4146 8.33 COAL59 Coal 11621 9,601 -9479 4157 8.33 HTKE-FW Sand/Conglomerate Oil Sand 11636 9,607 -9485 3766 7.54 HK2T Sand/Conglomerate Oil Sand 11772 9,652 -9530 3783 7.54 Tgt 1 Base Pump Tangent 9509 -9387 TD 13322 9,795 -9673 3840 7.54 ' = Primary Objective = Secondary Objective TARGET SIZE 50 FT DATA COLLECTION REQUIREMENTS: Mud Logging 4 man Crew below KOP LWD Data: Triple combo-ADR V E-Line Log Data: Gyro run upon completion of the well to validate wellbore tortuosity and postion. COMPLETION TYPE ESP Completion ANTICIPATED RATES 10,000 bpd gross fluid ARTIFICIAL LIFT EQUIPMENT OD TUBING SIZE 3-1/2" or 4-1/2" Page 34 Revision 0 October, 2016 • • K-06RD2 Drilling Procedure Rev 0 IliI orp:11a.ka. 24.0 Anticipated Drilling Hazards 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: I-12S is not present in this hole section. No abnormal temperatures or pressures are present in this hole section. Page 35 Revision 0 October, 2016 H • • K-06RD2 Drilling Procedure Rev 0 1111(0111 Ua.ka.11.1: - - 25.0 Rig Layout LI 0) Ui AI r 0 0t 0 r X/ 0.o T— (. Ui ( . g • t a q o g 1_ - K 8 O 7 V 4 O a m � I v ,. • 0 0§ 0 11 Ell x a N pp 6 y ter;: ATV, y * § I Li-- � R�. 10:4.y : t I — F:tii .-A it 1vw a O EP X oos 0 = CBI 2 SZ. le) (CD v g a 3 0 iO oos 6I. -• u 0 I gW � i X (------ ., is?c . El co 10" $ Q. o r t- 000 os -•r 000 oz 1 000 os e o x Page 36 Revision 0 October, 2016 • • K-06RD2 Drilling Procedure Rev 0 Ilileorp:11auka.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 October,2016 • • HK-06RD2 Drilling Procedure Rev 0 tlik orp,u–k.,.1.1.1 27.0 Choke Manifold Schematic Choke Manifold Valves 2" 3,. To Shaker 3"Panic To Gasbuster I 3118"© © .._ 2 1/16" I ' ( 2 1/16" ■—a—■—Q ■ j[I? 21/1 21/16" rn� 3118'--41,...0 / N L01111111111110411111.011111111114/1111/11 t I 1 2 1/16" gh 2 1/16" 1 Manual Choke Automatic Choke 2 1/16" Inlet Pressure Sensor 3" 5,000 PSI Choke Manifold Kuukpik Drilling Rig 5 RED= 3 1/18" 5,000 PSI VALVES AND LINES BLUE = 2 1/16"5,000 PSI VALVES Kuukpik Drilling Rig 5 Choke Manifold \: c•2 Sin."'' - - ,,,,,,, , 00 • cs,., o foot +ori v • 1 r Z a' ...... .., so* Kuuaplk Drilling Rig 5 Choka Manifold Page 38 Revision 0 October, 2016 9 0 HK-06RD2 Drilling Procedure Rev 0 !Wear!,Alaska.1.IA: 28.0 Fluid Flow Diagrams C CC X n .9 x 1 u S W 7 j j j j j j j j j r'. (IQ j.eiOi'llaiUj&jYjNlr CO. 1 I i j j j i j j I ( C) 00 1...040.1.1.1..1..0.14t j�jIjjjljjw. vi Ia IpiliIMlPlalalP IIIIIIIIir iiVVVTVri ! ! l4 LQ iiiiH I I I I I 1 1 1 1 ca pa g .Ax -i co ii'% con cn %-• a w$ K wB a %o I ! 1 1 1 ! i i i 7 -04-0 Z 1..IJ IN IU I�IV IN 1..10 �$ a o%.I o I i i I I 1 1 1 1 I I iui't+�I�+IuiylNr+I Da >a D4 Da CO I l i jpj"l 1 j-�.i.41 N " CO CO I I�ypyXS��lyX; fi IPr"A t D {nn{lIyla}lpa l��lyyif ila , i i$igiA.lwliiint' 0• r y l i i i l l i l �i�i ini�1 I�i 1 Ili i l I i 1 1 ,. J. III : . C9 j al .m 6 A 1 I I rs 1 I I IU 1►1�i Nl..le j� ^). III i III /�",' N• W A i I 1n Ili I 1 i P4 IN my ,,,:,z,, a 1 1 1 ,,,rt! 111 it .� 1. '� .$.LLLLLL�! !n! tO ri. 1 i i !t.i, -0 c 3 I ii� ,i 1 1 1 i g a a o _c 1 1511.' x1_1 it f+ 13 R I I.I. a -i i i..,3„, Q. I i I li i i . ni 1 , s 11` O ii A) 1 Page 39 Revision 0 October, 2016 • • HK-06RD2 Drilling Procedure Rev 0 Ilikorp Alaska,LiA: 7. ,... 77 r, g -7.:, —• re us I 776 ...s I (.4 x _. _. I 1 I 1111 I I 13 r.I": 1,01001"410'itAl‘it'1"1."' 0) 7 7:, , . . . . . . . . frZ 1.411,01141.4111.411411141.41114 i:1. 1"415i"4*Zi711:17. ,../1 tfiliiitriti i il i'l4'0.2.. 1 iplIvripiprvi !4-1.4•!.4 !..41.41.41.4 .-4!; 1-!,,-11.41111 !vv. ..• .... !. !,.. ..i ... ul .....x z ix) pa o v x, ✓ 0 Er 4 .y. ..... g A- CD w ...x... ,..; . Fp' R;X r., .., llllll . I I 4 0 V. '../.. 1111111111 _ r., i6YliZiMir•ir•i;:i=i<7i 0 05 oi, 1 witAi6'it4i....it•ii,i1•1 t>4 0-1 04 01 7-1' r, !i! .a.41.g.a.a 1.;,-,:.6-,! N —• CO (0 ,— I i •i 1 I *1 2 1 II I 1 .i f.L iiii =- ...... =• A- ---4 4 fr. i i* l•it it i*i• it ig i 0` "rt E.' lillillli V' (2, A ,... Ir'rrY°F11.11 1.3.!a!a!L11.1.1.2.1. ... I _.... i 7 ...0 ---;• ../.. it% : n, ... ip. 4 Z. lir l y - tv ..': Z r,..)• 01 _.•• i i....i•iiu iiiiti,..,1,-. g i x I\)• 1-N• N (*) N 4b, . I • r I. 4 i i i ',.12iri IF x ' ! In !rz i if A 0 'I:. a i i ix ,is ig , ig. 3 x 1 ! fiig.it-,,=in IV 10 K ii. T1 I !....1 1,f-.!r"! 1.4' r1) a 3 a 5 F i itig 11, r6". 7:3 cr) EL: i i;!:- 1-..!;:' !": i ! ! if%!,T' l• -ri 1 1 I I% 1 I I 41 F u ,. g IN ;a 11.1a g ..6• (J Page 40 Revision 0 October, 2016 0 . H K-06RD2 Drilling Procedure Rev 0 Ilikorp 1114a.1.1.1: -, X o n...• e ...... 7." 7 t f-' U E W. -... = iii I III i t V, --*• ke!al,sialvtiol!‘•!..!- 1 co (/:. i i i I I iti I 7. I IIII t t t t 0 70 -. itiNaiikainaimit.oi44:H..• .0.•42,0,e..ek•c.•ex-O7,::::, 4 4 ,./. i i nit i ii It -:i i i Iiii t M M r°i°ra 7 il il i'3 loictiotolotototoc, / IIIItetl 1 -1"---1 • - tri ,, ....n (>•* ION 0 t)-1 0 : (y, 0 _.,, a) so n 4N, 0 eli 7" (.3 L ...t. X- C CD co F6 I " (.3: w ...)v, ..... x B.• 7 4.• E e:,3,,,-• t>C1 0 e. -... v r: ocologimiziairoz,si oo• —:-.1 . . . . . . . . . . _ . . . . . ..0 IIIi.,..i..., i i,...,ii .. I., •4 04 04 CO OD i 0.......1001W1....1....1‘.1.'1,..1...i ....... 0 A .._. m 0 .,- , -. -n .-. ...... r..1 1 i*i°i•i•ii i*i•i;i r 5 ...t. . . . . * 1 ! ! ! !n!ni !;.; •3 I— ...lc, 1; ilitilifilE 5 I I I i I i 1 i I VI 4111 firilli 4 f>i ..... ;• V NJ cn I i "o. t• 3 b ,r2 X ; A ii .. . . , . . . :...;.•: •,....!..!...,!.. i III I i , t t ! ii 1 it tz 1 1 t iiiVi i. A ! 1,-, • " . .t. 6 i i 11 i4 i i i' a ! , ,- „r„.., Ii. 3 g -° Ill 4 .tiltml .t m i i,i, ii.ii ..,.... . a 17 La- f.n (5 C g ca. i i i i5iti 4 0 :...1 • • • • t7) — 2.:(rq 1.0 Page 41 Revision 0 October, 2016 • K-06RD2 Drilling Procedure Rev 0 II ilrorp 29.0 Offset MW vs. Depth TVD MW vs TVD Offsets 0 A18(1968) I 1000 — K-26RD K-10RD 2000 3000 4000 5000 O 1- 6000 7000 8000 9000 10000 11000 8 9 10 11 12 13 14 15 Mud Weight(PPG) Page 42 Revision 0 October, 2016 • K-06RD2 Drilling Procedure Rev 0 Ilileurp U:nka,1,1.1: 30.0 Casing Design Information Calculation &Casing Design Factors Cook Inlet Offshore DATE: 10/10/2016 WELL: K-06RD2 FIELD: McArthur River DESIGN BY: Monty M Myers Design Criteria: Hole Size Mud Density: Hole Size 8-1/2" Mud Density: 9.0 ppg Hole Size Mud Density: Drilling Mode MASP: 2471 psi (See attached MASP determination & calculation) Production Mode MASP: 4686 psi (See attached MASP determination & calculation) Collapse Calculation: Section Calculation 1, 2 Normal gradient external stress (0.43 psi/ft)and the casing evacuated for the internal stress Casing Section Calculation/Specification 1 1 2 3 4 Casing OD 7-5/8" Top (MD) 6,900 Top(TVD) 5,503 Bottom (MD) 13,322 Bottom (TVD) 9,795 Length 6,422 Weight (ppf) 29.7 Grade L-80 Connection HYD 511 Weight w/o Bouyancy Factor(lbs) . 190,733 Tension at Top of Section(lbs) 190,733 Min strength Tension (1000 lbs) 254 Worst Case Safety Factor(Tension) 1.33 .r Collapse Pressure at bottom (Psi) 4,212 Collapse Resistance w/o tension (Psi) 4,790 Worst Case Safety Factor(Collapse) 1.14 ,,' MASP (psi) 2,471 Minimum Yield (psi) 6,890 Worst case safety factor(Burst) 2.79 V Page 43 Revision 0 October, 2016 • S K-06RD2 Drilling Procedure Rev 0 Ililwrp Alaska,LLA. 31.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation = 8-1/2"Hole Section K-06RD2 Cook Inlet,Alaska MD ND Planned Top: 7100 5503 Planned TD: 13322 9795 Anticipated Formations and Pressures: Formation ND Est Pressure Oil/Gas/Wet PPG Grad COAL39 9,137 3956 Oil Sand 8.3 0.43 H1X_FW 9,575 4146 Oil Sand 8.3 0.43 COAL59 9,601 4157 Oil Sand 8.3 0.43 HTKE-FW 9,607 3766 Oil Sand 7.5 0.39 HK2T 9,652 3783 Oil Sand 7.5 0.39 TD 9,795 3840 Oil Sand 7.5 0.39 Offset Well Mud Densities Well MW range Top(ND) Bottom(ND) Date A-27RD2 9.3-9.5 7,755 9,718 2016 A-27 8.9-9.8 3,360 7,017 1973 A-27RD 9.5-9.7 6,328 9,950 1997 K-26RD 9.4-10.2 7,800 9,971 1995 Assumptions: 1. Anticipated fracture gradient at 7100'TMD(5503'ND)=0.7=14.9 ppg EMW 2. Maximum planned mud density for the 8-1/2"hole section is 9.5 ppg. 3. Calculations assumes 9.2 ppg reservoir contains 2/3 gas,1/3 water. Fracture Pressure at window considering a full column of gas from window to surface: 5503(ft)x 0.7(psi/ft)= 4271 4271(psi)-[0.1(psi/ft)*5503(ft)]= 3721 psi MASP from pore pressure;normal gradient at TD,(0.43 psi/ft) 9795(ft)x 0.43(psi/ft)= 4212 psi 4212(psi)-(0.1(psi/ft)*9795(ft))= 3233 psi MASP from pore pressure;unknown gas sand at TD,at 9.2 ppg(0.4784 psi/ft) 9795(ft)x 0.4784(psi/ft)= 4686 psi Downhole 4686(psi)-[(2/3)*0.1(psi/ft)*9795(ft)]+[(1/3)*0.4784(psi/ft)*9795(ft)]= 2471 psi Drilling MASP 7 Summary: 1. MASP while drilling 8-1/2"hole is governed by pore pressure minus 2/3 of wellbore evacuated to gas(remaining 1/3 remains 9.2 ppg drilling fluid) Page 44 Revision 0 October, 2016 14 • • K-06RD2 Drilling Procedure Rev 0 I lit.orp \II"ka.I.1.1: 32.0 Plot (NAD 27) (Governmental Sections) `c-27R02Pet BHL 1 S009N013W S00 Nfi'I t / ADL018731 j1L}RD2 BHL 427M:12 BHL �.IAJ.!�' !Y / C 1 O 1 / 1r / K-k6RD BHL 1 /' A-25RD BHL\ 1 ♦ 305RD2L20HL // ♦ \I I / / • \ / 1 K-06 BH /// \ S009N013W --• / S00'N01• W S�O`09Nis j013W \\ L` � LU // R�'}ACsT el BHL v A // h-nn}lh_ RHL' \ -"- 009 • \ ..... ra Fay A0/ ��?�� , �-- h_nr,f211` Il'II .ry�- ... K..6 BHL ' - • - ---------- .,.,„,•0•2',.- 7 ‘‘k`•.•"11,4;iiiit.::::.„---....... ..• -.. ----.... K-11R0 BHL ADL017594;' \`;� `.\ ADL018772 i / \ \ ♦ \ • \ // • •• \ ly{t dHL \ ' \\ ♦ \ \ ♦ • • \ `„„ • • G N \ \ \ ' /, 11' ( \\ •\..111 1 /V K.r{2 B-L .\♦ •'N; ` �„ -1)!4,i) \\ Sec.f`3S] �\ 11\5 Si1i9N013W�' . \ \ \ Y.3 \ • ;... I 1 1\ \ `\ 1-1BBHL \ K-17BHL \\ \\ \ \ I I\ `\ \• \ 5K-02BHL I Legend K-03RQB K-25P8 0H 1 i `‘ \ .76.HL 1\ ,, , \ 1 • K-06RD2_SHL • 1 KC*BHL / t \\\`\ /,1 \\ \ \ — \ K-06RD2_TPH • \\ / 1 \ �t�7 BHL _ADP G BAY K-30 BHL \\ 1, S 1 f\ 1 1 _ 25 B LX-30R8 But. -05 BHL 1 K O6RD2 BHL \\ i tt 4,,/i r \ Other Surface Hole Location TRACING BAY IT G-31 BH! 1,,,,,../,1 M-31 BHL\;\\ \K-23 BI' • Other Bottom Hole Location S009N'13.v.-V UNIT P-28 }A(-2.1 0BHL \\ ---- ---: .Vit;.;i.01' W ,/// yy� ADL018730_-_ _ - - yY1 -\-- - 1 G-25 BHL c-a1X , --- Well Paths // S-'"'-I \ M-3tu i/1132BHL - \-~ /� I I 4K-21 BHL \\ ,/ En Oil and Gas Unit Boundary " / \ i/ / \ -, 111 K-06RD2 0 1.000 2.000 3.000 Feet Alaska State Plane Zone 4.NAD27 A lI.l'" ' Il:.•L...I I. Map Date"10/10/2016 Page 45 Revision 0 October, 2016 HI a K-06RD2 Drilling Procedure Rev 0 ilii..-1. Liska.IAA: 33.0 Slot Diagram (As Built) (NAD 27) CENTER LEG 4 LAT:60'51'55.8806'N LON:151'36'21.1490V CENTER LEG I N:2511794.345' LAT:60'51'19.9417N E.213761.651• LON:151'3V 19.8893W ASP ZONE 4 NAD 27 N:2511756.503' ERD E:213820.5W K'2 ASP ZONE 4 NAD 27 K-25—� +.-:R02 Ka.-. ' `�>«a 180•FEL Te KING SALMON PLATFORM 21 K.22Ro ASBUILT WELL LOCATIONS '4f; 120'FEL SECTION 16,T9N,R13W,S.M.,AK K10 / CENTER LEG LL 51' 297N 10 LON 151°36'22.1035w N•2511719.224• E:213712.532' ASP ZONE 4 NAD 27 K.1 IRP K., '• ' K.,.. :A. 187'FEL Y ORD CENTER LEG 2 LAT:60'51.54.7696-N LON:151'36'20.9005'W N:2511681.260' til 7s•r Fs�, ir1T E:213771.191' Z ASP ZONE 4 NAD 27 �,:I; l'.; .1,15, 0 H 690•FSL(NTS) 0 W •. __ 1.FS, U) 0 W I- 0 e Q O_ I- 0 1 cc SECTION CORNER 0_ (PROTRACTED) N.2511063.548' E:213922.792' PROTRACTED SECTION LINE NOT TO SCALE(NTS) 16 75 21 :1 NOTES 1. BASIS OF HORIZONTAL CONTROL:NAD83 US FEET POSITION `��11 (EPOCH 2010)AND VERTICAL CONTROL(NAVD88)IS AN OPUS ® �%%OF At I I►► SOLUTION FROM NGS STATIONS KENS.AC51 AND AC23 TO Q�ti•""' ..1, II ESTABLISH POINT 0300. THE ALASKA STATE PLANE COORDINATES co/ 7�'e NAD 83 ZONE 4 IN FEET ARE: N=2511443.373 *`•`�7ti* `*, E=1353731.256 ♦ ,2C-• fa...... ELEV.=99.189(NAVD88) ♦ •. STAN A,rkur.- i ,� 2.SECTION LINES SHOWN ARE EXTENSIONS OF PROTRACTED ♦i "^" VALUES. SCALE ', `s/wM... 3, DATUM TRANSFORMATIONS(NAD83 ASPZ4 TO NAD27 ASP24) 0 �` 'I ►►I'111x "��•� `WERE DONE USING CORPSCON SOFTWARE VERSION 6.01. ♦ LL 6 PROTECT HILCORP ALASKA,LLC RESISUN c. n.wl, KING SALMON PLATFORM WELLS DAVE eza+. COOK INLET ALASKA DW 1GB AS BUILT SURFACE LOCATION SCALE " PROJECT NO 14I,T. �.:REERINO.SOPPING.SUR•.EnrgrrEBTHO NAD 27 , BOOK HO I.�e PO BOK PIS SOIDOTN4.K SOWN , ,ICE ISBN XO-.2,6 TAX cw01241.324e PROTRACTED SEC. 16 TO9N R13W CMAE.SAWKLA4E(EWKiAKCGOOM IIIiIcurli tln.ka. Li.1 1 2 SEWARD MERIDIAN,ALASKA Page 46 Revision 0 October, 2016 I • K-06RD2 Drilling Procedure Rev 0 IIilrnrp U:T.ka.L1.c NAD 27 Slot# Well# Northing Easting Latitude Longitude Center Leg 1 2511756.503 213820.519 60'51'55.52222" -151°36'19.94191" 1 K-21RD 2511751.133 213822.994 60°51'55.46995" -151°36'19.88928" 2 K-30 2511750.754 213819.220 60°51'55.46531" -151°36'19.96528" 3 K-18RD 2511753.106 213815.860 60°51'55.48766" -151°36'20.03428" Leg 1 4 K-17 . 2511757.623 213814.976 60°51'55.53191" -151°36'20.05437" 5 K-23 2511761.085 213816.638 60°51'55.56639" -151°36'20.02253" 6 K-19 2511761.888 213820.828 60°51'55.57531" -151°36'19.93833" 7 K-22RD 2511759.441 213825.218 60°51'55.55228" -151°36'19.84850" 8 K-20 2511754.730 213825.531 60°51'55.50598" -151°36'19.83984" Center Leg 2 2511681.260 213771.191 60°51'54.76960" -151°36'20.90053" 9 K-15RD 2511676.516 213774.559 60°51'54.72372" -151°36'20.83019" 10 K-9 . 2511675.411 213770.205 60°51'54.71178" -151°36'20.91754" 11 K-4RD 2511678.297 213765.971 60°51'54.73918" -151°36'21.00445" Leg 2 12 K-11 _ 2511682.498 213765.183 60°51'54.78034" -151°36'21.02242" 13 K-13RD2 2511685.931 213767.848 60°51'54.81478" -151°36'20.97031" 14 K-2RD 2511686.644 213772.096 60'51'54.82282" -151°36'20.88491" 15 K-7RD 2511684.476 213775.691 60°51'54.80235" -151°36'20.81128" 16 K-5 2511680.120 213776.722 60°51'54.75972" -151°36'20.78831" Leg 3 Center Leg 3 2511719.224 213712.532 60'51'55.12919" -151'36'22.10347" Center Leg 4 2511794.345 213761.651 60°51'55.88057" -151°36'21.14901" 25 K-26RD 2511789.752 213764.548 60°51'55.83605" -151°36'21.08827" 26 K-1RD2 2511788.570 213760.661 60°51'55.82347" -151°36'21.16616" 27 K-10RD 2511791.323 213757.250 60°51'55.84976" -151°36'21.23636" Leg 4 28 K-25 2511795.528 213756.002 60°51'55.89085" -151°36'21.26364" 29 K-12RD2 2511799.318 213758.343 60°51'55.92872" -151°36'21.21826" 30 K-6RD 2511799.443 213762.467 60°51'55.93095" -151°36'21.13506" 31 K-24RD2 2511797.672 213766.437 60°51'55.91447" -151°36'21.05403" 32 K-3RD 2511793.127 213767.529 60°51'55.86999" -151°36'21.02976" HILCORP ALASKA,LLC NEVIsaN • sat**.im KING SALMON PLATFORM WELLS DOVE i h2D1 COOK INLET ALASKA ' Ke AS BUILT SURFACE LOCATION CRAYON cR'." NA PROJECT W. 14X03 E WANE MIROf MAPPINGSURVEYING/SURVENG/TES1' . NAD 27 ROOK NO 14411 oce ieo�iI263-12IOa S1$ CA%roMoitTwvm PROTRACTED SEC. 16 TO9N R13W SNEET WM. SAOCAANEE+SKaJwcaoCou IIiII011I 11a.1.u, I.I.1 las 2 SEWARD MERIDIAN.ALASKA Page 47 Revision 0 October, 2016 • • K-06RD2 Drilling Procedure Rev 0 Ilih orp:1Iaska.LI,1: 34.0 Directional Program (wp06) Page 48 Revision 0 October, 2016 • 0 , 1 - ' 1 I 1 Hilcorp Energy Company Trading Bay King Salmon Plan: K-06RD2 Plan: K-06RD2 , 2 UI' V Plan: K-06RD2 wp06 ,' l" ' Standard Proposal Report ,.. , ... 06 October, 2016 v * # 1 1 /41 I I 1 HALLIBURTON -im Sperry Drilling Services •4 i HALLIBURTON ( i Hilcorp Energy Company REFERENCE INFORMATION II11COIrp Calculation Method: Minimum Curvature Coordinate(N/E)Reference: Well Plan:K-06RD2,True North Sperry Drilling `j' Error System: ISCWSA Vertical(ND)Reference: K-06RD2 @ 122.00usft(Kuupik 5) Scan Method: Closest Approach 3D Error Surface: Elliptical Conic Measured Depth Reference: K-06RD2 @ 122.O0usft(Kuupik 5) Warning Method: Error Ratio Calculation Method: Minimum Curvature Project: Trading Bay Site: King Salmon SECTION DETAILS Well: Plan:K-06RD2 Sec MD Inc Azi ND +N/-S +E/-W Dleg TFace VSect Wellbore: Plan:K-06RD2 1 7100.00 47.00 101.76 5640.19 27.16 3715.16 0.00 0.00 3549.09 Design: K-06RD2 wp06 2 7117.00 48.07 104.20 5651.67 24.34 3727.38 12.30 60.00 3559.88 3 7147.00 48.07 104.20 5671.71 18.87 3749.02 0.00 0.00 3578.85 4 8161.62 10.00 207.00 6570.41 -164.47 4098.30 5.03 167.41 3856.24 5 9511.62 10.00 207.00 7899.90 -373.34 3991.87 0.00 0.00 3691.58 6 9861.62 18.51 138.09 8240.85 -442.29 4015.36 5.00 -100.00 3693.10 DDI = 6.470 7 10499.87 22.95 36.72 8853.26 -417.27 4161.20 5.00 -133.69 3839.67 8 11224.02 57.00 37.00 9400.07 -50.75 4436.50 4.70 0.43 4213.00 9 11424.02 57.00 37.00 9509.00 83.21 4537.44 0.00 0.00 4349.76 10 11994.02 85.50 37.06 9690.34 509.66 4859.18 5.00 0.13 4785.49 11 13322.00 85.50 37.06 9794.53 1566.09 5657.07 0.00 0.00 5865.73 CASING DETAILS WELL DETAILS: Plan:K-06RD2 TVD TVDSS MD Size Name Water Depth: 73.00 9794.53 9672.53 13322.00 7-5/8 7-5/8"x 8-1/2" +N1-5 +E/-W Northing Easting Latittude Longitude 0.00 0.00 2511799.44 213762.47 60°51'55.931 N 151°36'21.135 W 0o Start Dir 12.3°/100':7100'MD,5640.19'TVD:60°RT TF SURVEY PROGRAM 10 - End Dir :7117'MD,5651.67'TVD Date:2014-06-09T00:00:00 Validated:Yes Version: 5600- --==--- Start Dir 5°/100':7147'MD,5671.71'TVD Depth From Depth To Survey/Plan Tool 122.00 2122.00 K-06 NSG WL O 2222.00 7100.00 K-06RD NSG__WL 1h0 7100.00 7450.00 K-06RD2 wp06 MWD_Interp Azi+sag 5950-- 00 - 7450.00 13322.00 K-06RD2 wp06 MWD+SC+sag 1y FORMATION TOP DETAILS 0 6300-- 000 TVDPath TVDssPath MDPath Formation 9265.00 9143.00 11005.05 COAL39 8000- End Dir :8161.62'MD,6570.41'TVD 9591.00 9469.00 11594.76 H 1 9601.00 9479.00 11619.50 COAL59 _--_ 00 9605.00 9483.00 11629.75 H 1 0g 9659.00 9537.00 11800.60 HK2T 6650- 8500 0000 7000-- 0 c 10999(`J • 7350 9000 .0511•62 o �, °11od ' 000 t - 0a 6 10 7700- yo0 SNa' 0 - 0 ec4O o• - 9500 533 0 w 8050 - 4°' 7 01 m 9000 .N'Z, 1000 I- 06 O 1 8400 10000 O\<a., 0001•(`) �`at` so , O 9 5Q Mrd 02� 11� o�d 8750- 9500 .'� VN- , �o05(9 .S� 050��0 1 50 Dna 49-,� 0‘,..°\'' 0200' O �O2�Q 11a2� 690, E 0p0 10,rp's O 9100- COAL39 10000 loon , ,' '.A6- `th°\1oo �`O e (9l 12 2�O e -' ^ i6 S. \<.\'0-' L L,c,Qo•CP �cO \OeQ`r 1332 O 9450- H 1 X y00 ��° *0d �06��� 1o�a __ ___.__,-. _ - _- - - - N 0 , M - COAL59 - 1 ' 9800- H1 13000 _ HK2T11000 7-5/8"x 8-1/2" K-06RD2 wp06 132g6 K-06RD 10150_. i I 11. I I I I I I I I I I 1 I I 1 I I I I I I I I 1 . ........ 1 I l l l l l i l l l l l l l r_l_-t i I I I I I I I I I I-_r I-1 1 I I r I I I I l I 3150 3500 3850 K40 4550 4900 5250 5600 5950 6300 6650 7000 7350 77001 8050 Vertical Section at 72.38°(700 usft/in) • • -IALLIBURTON .11. Project: Trading Bay COMPANY DETAILS:Hi!core Energy Company WELL DETAILS:Plea K-06RD2 -------- I I!Iron') Site: King Salmon Calculation Method:Minimum Curvature Water Depth: 73.00 :port,txutte.g Well: Plan:K-06RD2 Error System:ISCWSA +54/4 +E/-W Northing Eastng Leittude Longitude Scan Method:Closest Approach 3D 0.00 0.00 2511799.44 213762.47 60°51'55.931 N 151°36 21.135 W Wellbore: Plan:K-06RD2 Error Surface:Elliptical Conic _ Plan: K-06RD2 wp06 Warning Method Error Ratio REFERENCE INFORMATION 2500— Co-ordinate(N/E)Reference:Well Plan:K-06002,True North _ Vertical(TVD)Reference'.K-06RD2 @ 122.02uaa(Kuupik 5) _ C Measured Depth Reference:K-06RD2 122.00ueR(Kuupik 5) Calculation Method:Minimum Curvature - 2250— gg K-06 2000— $ o $ o o .. - a o Total Depth:13322'MD,9794.5TTVD 1750— - k��"t 1500- - 1 7-5/r x 8-12" S 1250— K-06RD2 wp05 TDTg1 4 o - 4 0 �'^,,1000- g t° - (� y� ... 750— 1 .0 r b • , tib f'n SURVEY PROGRAM Si _ /I r#'� �.. Date:2014-06-09700:00:00 Validated:Yes Version: 500— .� / ; ,t.5. End Dir:11994.0T MD,9690.34'TVD 't / Depth From Depth To Survey/Plan Tool ` 122.00 2122.00 K-043NSG_WL ,i- / 7100.00S� 2222.00 7100.00 K-06RD NSG_WL 4' 45 250— s 7450.00 13322.00 K-06RD2 p08 MWD+SCa+sag+sag _ S r, 8 y Sled Dir 5°/100':11424.02'MD,9509TVD % i'$ '�! ___-- CASING DETAILS ,' S moi? --K-06RD2 wp05 Tg12 FSP Hold End 0— $ 4'End Dr:1122402'MD 940007TVD TVD TVDSS MD Size Name n - 9794.53 9672.53 13322.00 7-5/8 7-5/8"K 8-1/2" - 4'..' $ yo g n b'?'- 6500 Q -250— End Dir:8161.62'MD,6570.41'TVD 7r2....°p -'??''.0 Jis8' �0 _ 7s � K-O6RD2 wp05 Tel ESP Start i _ Start Dir 57100':9511.62'MD,7899.9'TVD ll s-t,moo ng -500 wti5' % 8500 ^ p _ Start Dr4.A/100':10499.91'MD,8853.3'TVD fid' 4-19 -750— / 1 I I 11 1 1 1 I 1 1 1 1 I 1 I 1 I ' I I 1 1 I I I I I l I I I I 11 I I I I 1 I I I I I I I I I I I I I I I I I I I I I I I I I 11111111 I I I I I I I I I I I I I I I I 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6250 6500 6750 7000 7250 West(-)/East(+)(500 usft/in) • Project: Trading Bay IIHilcorp Site: King Salmon Well: Plan: K-06RD2 Wellbore: Plan: K-06RD2 Plan: K-06RD2 wp06 2400- - K-13RD2__ K-06 1 2133— o 0 0 0 - 9So0 1867— K-06RD2 wp06 1600— i,/- -7-5/8"x 8-1/2" 9�9 J 1333— 90o0, K-06RD2 wp05 TD Tgt G 1067— ti OK-13 PBl O mo c o + 800— o o K-13 °`o o SO o o 0 - o 7 0 533— o Start Dir 12.3°/100':7100'MD,5640.19'TVD:60°RT TF o " 0 8 267 a �, 000 - O y , § K-06RD2 wp05 Tgt2 ESP Hold End o 40 o o—_ wpl-- _ °° o `End Dir:11224.02'MD,9400.07'TVD ro 0 - /0Op0 bo 6500 - 0 o 930 N0 -267— K-06RD2 wp05 Tgtl ESP Start ah 0 ^ 9 - 9000 8000 '9000 K-113RD 8$00 -533— 8500 e00p 00 - �o 7500 -800— -- a' K-15 800— K-15 K-02B WP1.0 K-06RD h /9720 i K-1SRD i r I 1 1 i i 1 1 1 1 I i iIi IF , 11FI 1 II I 1 I 1 i 1 1 I i 1 i 1 I I 1 Hi [ 1 3200 3467 3733 4000 4267 4533 4800 5067 5333 5600 5867 West(-)/East(+)(400 usft/in) • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:K-06RD2 Company: Hilcorp Energy Company TVD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Project: Trading Bay MD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Site: King Salmon North Reference: True Well: Plan:K-06RD2 Survey Calculation Method: Minimum Curvature Wellbore: Plan:K-06RD2 Design: K-06RD2 wp06 Project Trading Bay 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 King Salmon Site Position: Northing: 2,511,786.28 usft Latitude: 60°51'55.800 N From: Map Easting: 213,756.95 usft Longitude: 151°36'21.240 W Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -1.40 ° Well Plan:K-06RD2 Well Position +NI-S 0.00 usft Northing: 2,511,799.44 usft Latitude: 60°51'55.931 N +EI-W 0.00 usft Easting: 213,762.47 usft Longitude: 151°36'21.135 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Water Depth: 73.00 usft Wellbore Plan:K-06RD2 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (1 (nT) BGGM2013 6/9/2014 16.83 73.72 55,485 Design K-06RD2 wp06 Audit Notes: Version: Phase: PLAN Tie On Depth: 7,100.00 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 0.00 0.00 0.00 72.38 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/-S +E/-W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (1100usft) (°/100usft) (°100usft) (°) 7,100.00 47.00 101.76 5,640.19 5,518.19 27.16 3,715.17 0.00 0.00 0.00 0.00 7,117.00 48.07 104.20 5,651.67 5,529.67 24.34 3,727.39 12.30 6.30 14.32 60.00 7,147.00 48.07 104.20 5,671.71 5,549.71 18.87 3,749.02 0.00 0.00 0.00 0.00 8,161.62 10.00 207.00 6,570.41 6,448.41 -164.46 4,098.30 5.03 -3.75 10.13 167.41 9,511.62 10.00 207.00 7,899.90 7,777.90 -373.34 3,991.88 0.00 0.00 0.00 0.00 9,861.62 18.51 138.09 8,240.85 8,118.85 -442.28 4,015.37 5.00 2.43 -19.69 -100.00 10,499.87 22.95 36.72 8,853.26 8,731.26 -417.27 4,161.20 5.00 0.70 -15.88 -133.69 11,224.02 57.00 37.00 9,400.07 9,278.07 -50.74 4,436.50 4.70 4.70 0.04 0.43 11,424.02 57.00 37.00 9,509.00 9,387.00 83.22 4,537.44 0.00 0.00 0.00 0.00 11,994.02 85.50 37.06 9,690.34 9,568.34 509.66 4,859.19 5.00 5.00 0.01 0.13 13,322.00 85.50 37.06 9,794.53 9,672.53 1,566.10 5,657.07 0.00 0.00 0.00 0.00 10/6/2016 10:33:16AM Page 2 COMPASS 5000.1 Build 81 . • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:K-06RD2 Company: Hilcorp Energy Company TVD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Project: Trading Bay MD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Site: King Salmon North Reference: True Well: Plan:K-06RD2 Survey Calculation Method: Minimum Curvature Wellbore: Plan:K-06RD2 Design: K-06RD2 wp06 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) -122.00 0.00 0.00 0.00 0.00 -122.00 0.00 0.00 2,511,799.44 213,762.47 0.00 0.00 100.00 0.04 106.65 100.00 -22.00 -0.01 0.04 2,511,799.43 213,762.50 0.04 0.03 200.00 0.07 116.07 200.00 78.00 -0.04 0.13 2,511,799.39 213,762.59 0.03 0.11 300.00 0.46 139.65 300.00 178.00 -0.32 0.41 2,511,799.11 213,762.86 0.39 0.29 400.00 1.93 156.32 399.98 277.98 -1.97 1.31 2,511,797.43 213,763.73 1.49 0.65 500.00 1.41 123.30 499.92 377.92 -4.71 3.04 2,511,794.66 213,765.39 1.07 1.47 600.00 2.80 82.49 599.87 477.87 -4.95 6.25 2,511,794.34 213,768.59 1.96 4.46 700.00 6.07 54.45 699.58 577.58 -1.98 12.93 2,511,797.15 213,775.35 3.84 11.73 800.00 8.26 50.66 798.74 676.74 6.05 22.94 2,511,804.93 213,785.55 2.23 23.69 900.00 9.84 51.88 897.50 775.50 15.93 35.19 2,511,814.50 213,798.04 1.59 38.36 1,000.00 12.71 55.35 995.60 873.60 27.39 50.71 2,511,825.58 213,813.83 2.95 56.62 1,100.00 15.65 56.35 1,092.53 970.53 41.08 71.09 2,511,838.77 213,834.54 2.94 80.19 1,200.00 17.67 54.09 1,188.29 1,066.29 57.41 94.83 2,511,854.51 213,858.67 2.13 107.75 1,300.00 19.58 53.46 1,283.05 1,161.05 76.38 120.50 2,511,872.84 213,884.79 1.92 137.96 1,400.00 21.72 54.06 1,376.64 1,254.64 97.23 148.88 2,511,892.99 213,913.68 2.15 171.32 1,500.00 23.54 54.97 1,468.91 1,346.91 119.60 180.26 2,511,914.59 213,945.60 1.86 208.00 1,600.00 24.94 55.98 1,560.06 1,438.06 142.90 214.13 2,511,937.06 213,980.03 1.46 247.34 1,700.00 25.15 56.53 1,650.57 1,528.57 166.50 249.51 2,511,959.78 214,015.98 0.31 288.20 1,800.00 24.79 56.81 1,741.20 1,619.20 189.71 284.83 2,511,982.12 214,051.85 0.38 328.89 1,900.00 24.41 57.10 1,832.13 1,710.13 212.41 319.72 2,512,003.96 214,087.29 0.40 369.01 2,000.00 23.98 57.49 1,923.34 1,801.34 234.56 354.21 2,512,025.26 214,122.31 0.46 408.60 2,100.00 23.65 57.84 2,014.83 1,892.83 256.14 388.31 2,512,046.00 214,156.93 0.36 447.63 2,200.00 22.68 62.81 2,106.73 1,984.73 275.99 422.37 2,512,065.00 214,191.47 2.18 486.10 2,208.00 22.59 63.33 2,114.11 1,992.11 277.38 425.12 2,512,066.33 214,194.25 2.72 489.13 13 3/8" 2,300.00 20.33 75.45 2,199.70 2,077.70 289.63 456.47 2,512,077.81 214,225.89 5.40 522.73 2,400.00 21.11 83.25 2,293.42 2,171.42 295.49 490.82 2,512,082.83 214,260.37 2.87 557.23 2,500.00 23.89 84.45 2,385.88 2,263.88 299.28 528.70 2,512,085.69 214,298.33 2.81 594.48 2,600.00 27.14 84.32 2,476.13 2,354.13 303.48 571.54 2,512,088.83 214,341.26 3.25 636.58 2,700.00 30.66 84.20 2,563.68 2,441.68 308.32 619.58 2,512,092.49 214,389.41 3.52 683.84 2,800.00 33.97 84.30 2,648.15 2,526.15 313.69 672.81 2,512,096.57 214,442.75 3.31 736.19 2,900.00 37.52 83.99 2,729.33 2,607.33 319.60 730.86 2,512,101.05 214,500.93 3.55 793.32 3,000.00 40.94 83.65 2,806.76 2,684.76 326.43 793.76 2,512,106.34 214,563.98 3.43 855.33 3,100.00 42.54 83.62 2,881.15 2,759.15 333.87 860.17 2,512,112.15 214,630.55 1.60 920.88 3,200.00 42.30 83.72 2,954.80 2,832.80 341.34 927.40 2,512,117.97 214,697.94 0.24 987.21 3,300.00 41.86 83.79 3,029.04 2,907.04 348.62 994.00 2,512,123.62 214,764.70 0.45 1,052.89 3,400.00 41.39 83.82 3,103.78 2,981.78 355.78 1,060.05 2,512,129.16 214,830.90 0.47 1,118.01 3,500.00 40.88 84.91 3,179.10 3,057.10 362.37 1,125.50 2,512,134.15 214,896.50 0.88 1,182.38 3,600.00 39.14 90.90 3,255.55 3,133.55 365.35 1,189.84 2,512,135.55 214,960.89 4.22 1,244.61 3,700.00 39.34 97.71 3,333.27 3,211.27 360.52 1,252.55 2,512,129.19 215,023.46 4.31 1,302.91 3,800.00 41.95 100.51 3,409.35 3,287.35 349.78 1,316.53 2,512,116.88 215,087.16 3.18 1,360.64 3,900.00 43.57 101.39 3,482.58 3,360.58 336.74 1,383.37 2,512,102.22 215,153.66 1.72 1,420.40 4,000.00 44.34 101.70 3,554.51 3,432.51 322.80 1,451.42 2,512,086.61 215,221.35 0.80 1,481.03 4,100.00 44.74 102.41 3,625.75 3,503.75 308.20 1,520.06 2,512,070.34 215,289.61 0.64 1,542.03 4,200.00 45.37 103.01 3,696.43 3,574.43 292.60 1,589.06 2,512,053.05 215,358.21 0.76 1,603.08 10/6/2016 10:33:16AM Page 3 COMPASS 5000.1 Build 81 • S Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:K-06RD2 Company: Hilcorp Energy Company TVD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Project: Trading Bay MD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Site: King Salmon North Reference: True Well: Plan:K-06RD2 Survey Calculation Method: Minimum Curvature Wellbore: Plan:K-06RD2 Design: K-06RD2 wp06 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-5 +E1-W Northing Easting DLS Vert Section 1 (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,644.29 4,300.00 45.97 103.89 3,766.29 3,644.29 276.01 1,658.66 2,512,034.76 215,427.38 0.87 1,664.39 4,400.00 46.75 104.67 3,835.33 3,713.33 258.14 1,728.76 2,512,015.18 215,497.03 0.96 1,725.79 4,500.00 47.12 104.38 3,903.55 3,781.55 239.67 1,799.50 2,511,994.98 215,567.29 0.43 1,787.62 4,600.00 44.62 98.84 3,972.82 3,850.82 224.42 1,869.95 2,511,978.02 215,637.35 4.69 1,850.15 4,700.00 42.41 91.39 4,045.46 3,923.46 218.23 1,938.33 2,511,970.15 215,705.55 5.59 1,913.45 4,800.00 43.98 89.40 4,118.80 3,996.80 218.52 2,006.31 2,511,968.78 215,773.52 2.08 1,978.32 4,900.00 45.86 90.19 4,189.52 4,067.52 218.93 2,077.00 2,511,967.45 215,844.20 1.96 2,045.82 5,000.00 45.95 90.62 4,258.89 4,136.89 218.32 2,149.02 2,511,965.09 215,916.19 0.33 2,114.28 5,100.00 46.24 91.40 4,328.32 4,206.32 217.12 2,220.98 2,511,962.13 215,988.09 0.63 2,182.50 5,200.00 47.22 92.29 4,396.93 4,274.93 214.78 2,293.69 2,511,958.00 216,060.72 1.17 2,251.09 5,300.00 48.69 92.86 4,463.95 4,341.95 211.40 2,367.83 2,511,952.80 216,134.75 1.52 2,320.72 5,400.00 50.18 93.64 4,528.97 4,406.97 207.13 2,443.67 2,511,946.68 216,210.48 1.60 2,391.72 5,500.00 51.50 94.63 4,592.10 4,470.10 201.56 2,521.02 2,511,939.22 216,287.67 1.53 2,463.76 5,600.00 52.48 95.42 4,653.64 4,531.64 194.62 2,599.54 2,511,930.36 216,365.99 1.17 2,536.49 5,700.00 52.64 95.81 4,714.32 4,592.32 186.79 2,678.64 2,511,920.60 216,444.88 0.35 2,609.51 5,800.00 51.57 96.46 4,775.58 4,653.58 178.39 2,757.23 2,511,910.28 216,523.23 1.19 2,681.87 5,900.00 50.93 96.92 4,838.28 4,716.28 169.27 2,834.59 2,511,899.27 216,600.35 0.73 2,752.84 6,000.00 50.61 97.09 4,901.55 4,779.55 159.80 2,911.45 2,511,887.91 216,676.96 0.34 2,823.23 6,100.00 49.63 97.59 4,965.56 4,843.56 150.04 2,987.66 2,511,876.29 216,752.90 1.05 2,892.90 6,200.00 49.10 98.08 5,030.78 4,908.78 139.68 3,062.75 2,511,864.10 216,827.71 0.65 2,961.34 6,300.00 48.79 98.25 5,096.47 4,974.47 128.93 3,137.38 2,511,851.53 216,902.06 0.33 3,029.21 6,400.00 47.68 98.46 5,162.95 5,040.95 118.10 3,211.28 2,511,838.88 216,975.68 1.13 3,096.37 6,500.00 47.25 99.10 5,230.69 5,108.69 106.91 3,283.99 2,511,825.93 217,048.09 0.63 3,162.29 6,600.00 47.17 99.58 5,298.63 5,176.63 94.96 3,356.39 2,511,812.21 217,120.17 0.36 3,227.67 6,700.00 46.68 100.22 5,366.87 5,244.87 82.43 3,428.41 2,511,797.91 217,191.86 0.67 3,292.51 6,800.00 47.21 100.40 5,435.29 5,313.29 69.30 3,500.14 2,511,783.03 217,263.25 0.55 3,356.90 6,900.00 46.81 100.81 5,503.30 5,381.30 55.87 3,572.21 2,511,767.84 217,334.97 0.50 3,421.53 7,000.00 46.79 101.40 5,571.85 5,449.85 41.85 3,643.65 2,511,752.08 217,406.05 0.43 3,485.38 7,100.00 47.00 101.76 5,640.19 5,518.19 27.16 3,715.17 2,511,735.64 217,477.18 0.34 3,549.09 Start Dir 12.3°/100':7100'MD,5640.19'TVD:60°RT TF 7,117.00 48.07 104.20 5,651.67 5,529.67 24.34 3,727.39 2,511,732.52 217,489.33 12.30 3,559.88 End Dir :7117'MD,5651.67'TVD 7,147.00 48.07 104.20 5,671.71 5,549.71 18.87 3,749.02 2,511,726.52 217,510.83 0.00 3,578.85 Start Dir 5°/100':7147'MD,5671.71'TVD 7,200.00 45.48 105.01 5,708.01 5,586.01 9.14 3,786.39 2,511,715.88 217,547.95 5.03 3,611.52 7,300.00 40.59 106.77 5,781.08 5,659.08 -9.49 3,852.02 2,511,695.65 217,613.09 5.03 3,668.42 7,400.00 35.75 108.91 5,859.68 5,737.68 -28.36 3,910.84 2,511,675.35 217,671.44 5.03 3,718.78 7,500.00 30.94 111.62 5,943.20 5,821.20 -47.31 3,962.41 2,511,655.14 217,722.53 5.03 3,762.19 7,600.00 26.22 115.20 6,030.99 5,908.99 -66.20 4,006.33 2,511,635.18 217,765.97 5.03 3,798.33 7,700.00 21.62 120.21 6,122.39 6,000.39 -84.88 4,042.25 2,511,615.62 217,801.43 5.03 3,826.91 7,800.00 17.24 127.68 6,216.69 6,094.69 -103.22 4,069.91 2,511,596.61 217,828.63 5.03 3,847.73 7,900.00 13.31 139.70 6,313.16 6,191.16 -121.07 4,089.10 2,511,578.30 217,847.37 5.03 3,860.61 8,000.00 10.35 159.78 6,411.07 6,289.07 -138.29 4,099.66 2,511,560.83 217,857.51 5.03 3,865.46 8,100.00 9.34 188.90 6,509.65 6,387.65 -154.75 4,101.51 2,511,544.32 217,858.95 5.03 3,862.24 10/6/2016 10:33:16AM Page 4 COMPASS 5000.1 Build 81 • • Halliburton HAL L I B U R TO IV Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:K-06RD2 Company: Hilcorp Energy Company TVD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Project: Trading Bay MD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Site: King Salmon North Reference: True Well: Plan:K-06RD2 Survey Calculation Method: Minimum Curvature Wellbore: Plan:K-06RD2 Design: K-06RD2 wp06 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) 6,448.41 8,161.62 10.00 207.00 6,570.41 6,448.41 -164.46 4,098.30 2,511,534.69 217,855.51 5.03 3,856.24 End Dir :8161.62'MD,6570.41'TVD 8,200.00 10.00 207.00 6,608.21 6,486.21 -170.40 4,095.28 2,511,528.83 217,852.34 0.00 3,851.56 8,300.00 10.00 207.00 6,706.69 6,584.69 -185.88 4,087.39 2,511,513.55 217,844.08 0.00 3,839.37 8,400.00 10.00 207.00 6,805.17 6,683.17 -201.35 4,079.51 2,511,498.28 217,835.82 0.00 3,827.17 8,500.00 10.00 207.00 6,903.65 6,781.65 -216.82 4,071.63 2,511,483.01 217,827.56 0.00 3,814.97 8,600.00 10.00 207.00 7,002.13 6,880.13 -232.29 4,063.74 2,511,467.73 217,819.30 0.00 3,802.77 8,700.00 10.00 207.00 7,100.61 6,978.61 -247.76 4,055.86 2,511,452.46 217,811.04 0.00 3,790.58 8,800.00 10.00 207.00 7,199.09 7,077.09 -263.24 4,047.98 2,511,437.18 217,802.78 0.00 3,778.38 8,900.00 10.00 207.00 7,297.57 7,175.57 -278.71 4,040.09 2,511,421.91 217,794.52 0.00 3,766.18 9,000.00 10.00 207.00 7,396.05 7,274.05 -294.18 4,032.21 2,511,406.63 217,786.26 0.00 3,753.99 9,100.00 10.00 207.00 7,494.54 7,372.54 -309.65 4,024.33 2,511,391.36 217,778.00 0.00 3,741.79 9,200.00 10.00 207.00 7,593.02 7,471.02 -325.12 4,016.44 2,511,376.08 217,769.74 0.00 3,729.59 9,300.00 10.00 207.00 7,691.50 7,569.50 -340.60 4,008.56 2,511,360.81 217,761.48 0.00 3,717.40 9,400.00 10.00 207.00 7,789.98 7,667.98 -356.07 4,000.68 2,511,345.53 217,753.22 0.00 3,705.20 9,500.00 10.00 207.00 7,888.46 7,766.46 -371.54 3,992.79 2,511,330.26 217,744.96 0.00 3,693.00 9,511.62 10.00 207.00 7,899.90 7,777.90 -373.34 3,991.88 2,511,328.49 217,744.00 0.00 3,691.58 Start Dir 5°/100':9511.62'MD,7899.9'TVD 9,600.00 10.20 181.62 7,986.96 7,864.96 -388.00 3,988.17 2,511,313.92 217,739.94 5.00 3,683.61 9,700.00 12.46 158.65 8,085.05 7,963.05 -406.91 3,991.85 2,511,294.93 217,743.15 5.00 3,681.40 9,800.00 15.99 144.12 8,182.00 8,060.00 -428.13 4,003.86 2,511,273.42 217,754.64 5.00 3,686.42 9,861.62 18.51 138.09 8,240.85 8,118.85 -442.28 4,015.37 2,511,258.99 217,765.80 5.00 3,693.10 9,900.00 17.23 133.40 8,277.38 8,155.38 -450.72 4,023.57 2,511,250.35 217,773.79 5.00 3,698.36 10,000.00 14.58 117.84 8,373.59 8,251.59 -466.79 4,045.47 2,511,233.75 217,795.30 5.00 3,714.38 10,100.00 13.31 97.65 8,470.69 8,348.69 -474.21 4,068.03 2,511,225.78 217,817.66 5.00 3,733.63 10,200.00 13.82 76.33 8,567.96 8,445.96 -472.91 4,091.06 2,511,226.51 217,840.72 5.00 3,755.97 10,300.00 15.93 58.56 8,664.66 8,542.66 -462.93 4,114.39 2,511,235.93 217,864.28 5.00 3,781.23 10,400.00 19.13 45.71 8,760.04 8,638.04 -444.32 4,137.84 2,511,253.95 217,888.18 5.00 3,809.21 10,499.87 22.95 36.72 8,853.26 8,731.26 -417.27 4,161.20 2,511,280.42 217,912.21 5.00 3,839.67 10,499.91 22.95 36.72 8,853.30 8,731.30 -417.26 4,161.21 2,511,280.43 217,912.21 0.00 3,839.68 Start Dir 4.7°/100':10499.91'MD,8853.3'TVD 10,500.00 22.95 36.72 8,853.38 8,731.38 -417.23 4,161.23 2,511,280.46 217,912.24 0.00 3,839.71 10,600.00 27.66 36.79 8,943.76 8,821.76 -382.99 4,186.81 2,511,314.06 217,938.64 4.71 3,874.44 10,700.00 32.36 36.85 9,030.33 8,908.33 -342.97 4,216.77 2,511,353.34 217,969.57 4.70 3,915.12 10,800.00 37.06 36.89 9,112.51 8,990.51 -297.43 4,250.92 2,511,398.03 218,004.83 4.70 3,961.45 10,900.00 41.76 36.92 9,189.75 9,067.75 -246.68 4,289.04 2,511,447.83 218,044.18 4.70 4,013.14 11,000.00 46.47 36.95 9,261.53 9,139.53 -191.05 4,330.86 2,511,502.42 218,087.34 4.70 4,069.84 11,005.05 46.70 36.95 9,265.00 9,143.00 -188.12 4,333.06 2,511,505.29 218,089.62 4.70 4,072.83 COAL39 11,100.00 51.17 36.97 9,327.36 9,205.36 -130.94 4,376.10 2,511,561.41 218,134.04 4.70 4,131.15 11,200.00 55.87 37.00 9,386.79 9,264.79 -66.73 4,424.46 2,511,624.42 218,183.96 4.70 4,196.68 11,224.02 57.00 37.00 9,400.07 9,278.07 -50.74 4,436.50 2,511,640.10 218,196.39 4.70 4,213.00 End Dir :11224.02'MD,9400.07'TVD 11,300.00 57.00 37.00 9,441.46 9,319.46 0.15 4,474.85 2,511,690.04 218,235.98 0.00 4,264.95 11,400.00 57.00 37.00 9,495.92 9,373.92 67.13 4,525.32 2,511,755.76 218,288.07 0.00 4,333.33 10/6/2016 10:33:16AM Page 5 COMPASS 5000.1 Build 81 0 • Halliburton HALLI BU RTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:K-06RD2 Company: Hilcorp Energy Company TVD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Project: Trading Bay MD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Site: King Salmon North Reference: True Well: Plan:K-06RD2 Survey Calculation Method: Minimum Curvature Wellbore: Plan:K-06RD2 Design: K-06RD2 wp06 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +Nl-S +E/-W Northing Easting DLS Vert Section (usft) (^) (^) (usft) usft (usft) (usft) (usft) (usft) 9,387.00 11,424.02 57.00 37.00 9,509.00 9,387.00 83.22 4,537.45 2,511,771.55 218,300.59 0.00 4,349.76 Start Dir 5°/100':11424.02'MD,9509'TVD 11,500.00 60.80 37.01 9,548.24 9,426.24 135.16 4,576.60 2,511,822.52 218,341.00 5.00 4,402.80 11,594.76 65.54 37.02 9,591.00 9,469.00 202.66 4,627.49 2,511,888.75 218,393.53 5.00 4,471.73 H1X 11,600.00 65.80 37.02 9,593.16 9,471.16 206.47 4,630.36 2,511,892.49 218,396.49 5.00 4,475.63 11,619.50 66.77 37.02 9,601.00 9,479.00 220.72 4,641.11 2,511,906.47 218,407.59 5.00 4,490.18 COAL59 11,629.75 67.29 37.03 9,605.00 9,483.00 228.26 4,646.79 2,511,913.87 218,413.45 5.00 4,497.88 H1 11,700.00 70.80 37.03 9,630.12 9,508.12 280.63 4,686.30 2,511,965.25 218,454.23 5.00 4,551.38 11,800.00 75.80 37.04 9,658.85 9,536.85 357.06 4,743.97 2,512,040.25 218,513.76 5.00 4,629.49 11,800.60 75.83 37.04 9,659.00 9,537.00 357.52 4,744.32 2,512,040.71 218,514.12 5.00 4,629.96 HK2T 11,900.00 80.80 37.05 9,679.13 9,557.13 435.19 4,802.95 2,512,116.91 218,574.63 5.00 4,709.35 11,994.02 85.50 37.06 9,690.34 9,568.34 509.66 4,859.19 2,512,189.99 218,632.67 5.00 4,785.49 End Dir :11994.02'MD,9690.34'TVD 12,000.00 85.50 37.06 9,690.81 9,568.81 514.42 4,862.78 2,512,194.66 218,636.38 0.00 4,790.36 12,100.00 85.50 37.06 9,698.65 9,576.65 593.97 4,922.86 2,512,272.71 218,698.39 0.00 4,871.70 12,200.00 85.50 37.06 9,706.50 9,584.50 673.52 4,982.95 2,512,350.77 218,760.41 0.00 4,953.04 12,300.00 85.50 37.06 9,714.34 9,592.34 753.07 5,043.03 2,512,428.83 218,822.42 0.00 5,034.39 12,400.00 85.50 37.06 9,722.19 9,600.19 832.63 5,103.11 2,512,506.89 218,884.43 0.00 5,115.73 12,500.00 85.50 37.06 9,730.04 9,608.04 912.18 5,163.19 2,512,584.94 218,946.44 0.00 5,197.08 12,600.00 85.50 37.06 9,737.88 9,615.88 991.73 5,223.28 2,512,663.00 219,008.45 0.00 5,278.42 12,700.00 85.50 37.06 9,745.73 9,623.73 1,071.28 5,283.36 2,512,741.06 219,070.47 0.00 5,359.77 12,800.00 85.50 37.06 9,753.57 9,631.57 1,150.84 5,343.44 2,512,819.11 219,132.48 0.00 5,441.11 12,900.00 85.50 37.06 9,761.42 9,639.42 1,230.39 5,403.52 2,512,897.17 219,194.49 0.00 5,522.46 13,000.00 85.50 37.06 9,769.27 9,647.27 1,309.94 5,463.61 2,512,975.23 219,256.50 0.00 5,603.80 13,100.00 85.50 37.06 9,777.11 9,655.11 1,389.49 5,523.69 2,513,053.29 219,318.51 0.00 5,685.14 13,200.00 85.50 37.06 9,784.96 9,662.96 1,469.04 5,583.77 2,513,131.34 219,380.53 0.00 5,766.49 13,300.00 85.50 37.06 9,792.80 9,670.80 1,548.60 5,643.85 2,513,209.40 219,442.54 0.00 5,847.83 13,322.00 85.50 37.06 9,794.53 9,672.53 1,566.10 5,657.07 2,513,226.57 219,456.18 0.00 5,865.73 Total Depth:13322'MD,9794.53'TVD 10/6/2016 10:33:16AM Page 6 COMPASS 5000.1 Build 81 • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:K-06RD2 Company: Hilcorp Energy Company TVD Reference: K-06RD2 @ 122.O0usft(Kuupik 5) Project: Trading Bay MD Reference: K-06RD2 @ 122.00usft(Kuupik 5) Site: King Salmon North Reference: True Well: Plan:K-06RD2 Survey Calculation Method: Minimum Curvature Wellbore: Plan:K-06RD2 Design: K-06RD2 wp06 Targets Target Name -hit/miss target Dip Angle Dip Dir. ND +N/-S +E/-W Northing Easting -Shape (°) (°) (usft) (usft) (usft) (usft) (usft) K-06RD2 wp05 Tgt2 ESP Hold End 0.00 0.00 9,509.00 83.22 4,537.44 2,511,771.55 218,300.59 -plan hits target center -Circle(radius 50.00) K-06RD2 wp05 Tgt1 ESP Start 0.00 0.00 9,400.07 -50.74 4,436.50 2,511,640.10 218,196.39 -plan hits target center -Point K-06RD2 wp05 TD Tgt 0.00 0.00 9,791.85 1,538.93 5,636.55 2,513,199.92 219,435.00 -plan hits target center -Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (••) 13,322.00 9,794.53 7-5/8"x 8-1/2" 7-5/8 8-1/2 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology (°) (1 11,619.50 9,601.00 COAL59 0.00 11,800.60 9,659.00 HK2T 0.00 11,594.76 9,591.00 H1X 0.00 11,629.75 9,605.00 H1 0.00 11,005.05 9,265.00 COAL39 0.00 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +El-W (usft) (usft) (usft) (usft) Comment 7,100.00 5,640.19 27.16 3,715.16 Start Dir 12.3°/100':7100'MD,5640.19'TVD:60°RT TF 7,117.00 5,651.67 24.34 3,727.38 End Dir :7117'MD,5651.67'TVD 7,147.00 5,671.71 18.87 3,749.02 Start Dir 5°/100':7147'MD,5671.71'TVD 8,161.62 6,570.41 -164.47 4,098.30 End Dir :8161.62'MD,6570.41'TVD 9,511.62 7,899.90 -373.34 3,991.87 Start Dir 5°/100':9511.62'MD,7899.9'TVD 10,499.91 8,853.30 -417.26 4,161.21 Start Dir 4.7°/100':10499.91'MD,8853.3'TVD 11,224.02 9,400.07 -50.74 4,436.50 End Dir :11224.02'MD,9400.07'TVD 11,424.02 9,509.00 83.22 4,537.44 Start Dir 5°/100':11424.02'MD,9509'TVD 11,994.02 9,690.34 509.66 4,859.19 End Dir :11994.02'MD,9690.34'TVD 13,322.00 9,794.53 1,566.10 5,657.07 Total Depth:13322'MD,9794.53'TVD 10/6/2016 10:33:16AM Page 7 COMPASS 5000.1 Build 81 • • Hilcorp Energy Company Trading Bay King Salmon Plan: K-06RD2 Plan: K-06RD2 K-06RD2 wp06 Sperry Drilling Services Clearance Summary Anticollision Report 06 October,2016 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: King Salmon-Plan:K-06RD2-Plan:K-06RD2-K-06RD2 wp06 Well Coordinates: 2,511,799.44 N,213,762.47 E(60°51'55.93"N,151°36'21.14"W) Datum Height: K-06RD2 @ 122.00usft(Kuupik 5) Scan Range:7,100.00 to 13,322.00 usft.Measured Depth. --,f Scan Radius is 1,532.20 usft.Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Version: 5000.1 Build: 81 Scan Type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference Scan Type: 25.00 , MIME 4E MEM HALLIBURTON impc Sperry Drilling Services • • Hilcorp Energy Company HALLIBURTON Trading Bay Anticollision Report for Plan: K-06RD2 -K-06RD2 wpO6 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: King Salmon-Plan:K-06RD2-Plan:K-06RD2-K-06RD2 wp06 Scan Range:7,100.00 to 13,322.00 usft.Measured Depth. Scan Radius is 1,532.20 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 King Salmon K-02-K-02B-K-028 WP1.0 11,059.84 922.89 11,059.84 702.51 14,327.40 4.188 Centre Distance Pass- K-02-K-02B-K-028 WP1.0 11,300.00 965.71 11,300.00 660.42 14,327.40 3.163 Ellipse Separation Pass- K-02-K-02B-K-02B WP1.0 11,550.00 1,076.53 11,550.00 708.23 14,327.40 2.923 Clearance Factor Pass- K-07-K-07-K-07 7,100.00 1,418.89 7,100.00 1,071.98 6,662.20 4.090 Ellipse Separation Pass- K-07-K-07-K-07 7,450.00 1,468.00 7,450.00 1,096.94 6,944.65 3.956 Clearance Factor Pass- K-07-K-07RD-K-07RD 7,100.00 1,418.89 7,100.00 1.071.98 6,662.20 4.090 Ellipse Separation Pass- K-07-K-07RD-K-07RD 7,450.00 1,468.00 7,450.00 1,096.94 6,944.65 3.956 Clearance Factor Pass- K-13-K-13-K-13 7,100.00 600.09 7,100.00 343.59 7,079.11 2.339 Clearance Factor Pass- K-13-K-13 PB1-K-13 PB1 7,100.00 600.09 7,100.00 342.36 7,079.11 2.328 Clearance Factor Pass- K-13-K-13RD-K-13RD 8,368.88 278.40 8,368.88 15.85 8,269.19 1.060 Centre Distance Pass- K-13-K-13RD-K-13RD 8,375.00 278.43 8,375.00 15.65 8,273.73 1.060 Clearance Factor Pass- K-13-K-13RD2-K-13RD2 8,368.88 278.40 8,368.88 15.85 8,269.19 1.060 Centre Distance Pass- K-13-K-13RD2-K-13RD2 8,375.00 278.43 8,375.00 15.65 8,273.73 1.060 Clearance Factor Pass- K-15-K-15-K-15 7,100.00 1,010.19 7,100.00 657.60 6,828.43 2.865 Ellipse Separation Pass- K-15-K-15-K-15 7,750.00 1,064.13 7,750.00 668A6 7,334.58 2.689 Clearance Factor Pass- K-15-K-15RD-K-15RD 7,100.00 1,010.19 7,100.00 65760 6,828.43 2.865 Ellipse Separation Pass- K-15-K-15RD-K-15RD 7,750.00 1,064.13 7,750.00 668.46 7,334.58 2.689 Clearance Factor Pass- K-23-Plan:K-23A-K-23A wp1 9,525.00 70422 9,525.00 536.12 9,447.27 4.189 Clearance Factor Pass- K-23-Plan:K-23A-K-23A wp1 9,725.00 662.48 9,725.00 512.34 9,627.43 4.412 Ellipse Separation Pass- K-23-Plan:K-23A-K-23A wp1 9,823.45 657.06 9,823.45 517.97 9,715.34 4.724 Centre Distance Pass- Plan:K-06RD2-K-O6RD-K-06RD 7,400.00 25.21 7,400.00 19.05 7,376.30 4.089 Clearance Factor Pass- 06 October,2016- 10:36 Page 2 of 5 COMPASS • • Hilcorp Energy Company HALLIBURTON Trading Bay Anticollision Report for Plan: K-O6RD2-K-O6RD2 wpO6 Survey tool program From To Survey/Plan Survey Tool (usft) (usft) 122.00 2,122.00 NSG_WL 2,222.00 7,100.00 NSG_WL 7,100.00 7,450.00 K-06RD2 wp06 MWD_Interp Azi+sag 7,450.00 13,322.00 K-O6RD2wp06 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. 06 October,2016- 10:36 Page 3 of 5 COMPASS • • HALLIBURTON Project: Trading Bay REFERENCE INFORMATION WELL DETALS:Plan K-0611D2 NAD 1927(NADCON CONUS) Alaska Zone 09 Site: King Salmon Coordinate(NIE)Reference:Well Plan,K-06RD2,True North Water Depth: 73.00 ---- ------ Vertical(TVD)Reference:1,06R02 a 122.00ust(Kuupik 5) +W-3 +F/-W Northing Fasting Latittude Longitude Sperry Drilling Well: Plan:K-06RD2 Measured Depth Reference.K-0514D2 @12200655(Kuupik 5) 0.00 0.002511799.44 213762.47 60"5155.931 N 151.36 21.135 W Wellbore: Plan:K-06RD2 Calculation Method Minimum Curvature u � Plan: K-06RD2 wp06 SURVEY PROGRAM GLOBAL FILTER APPLIED:All wellpaths within 200'0 100/1000 of reference n Hikorp Date:2014-06-09700:00:00 Validated:Yes Version: 7100.00 To 13322.00 Ladder/S.F. Plots Depth From Depth To Survey/Plan Tool CASING DETAILS 122.00 2122.00 5-06 NSG WL 2222.00 7100.00 K-06RD NSG WL TVD TVDSS MD Size Name 710000 745000 K-06RD2 wp06 MWD Interp Azi+sag 9794.53 9672.53 13322.00 7-5/8 7-5/8"x 8-1/2" 7450.00 13322.00 K-06RD2 wp06 MWD+SC+sag 150.00— C - ,. \ N i 0120.00 O - O - C - a 90.00 r a 1/ . - N K-06RD 60.00 - 1 — c ✓ �� S 30.00 K-13RD i _ N• - • o.o0 1 1111111 1111 , , , , i „ 11 „ , , h „ , 1111 1111 1111 1111 1111 111111111 1111 1111 1111 111 7000 7350 7700 8050 8400 8750 9100 9450 9800 10150 10500 10850 11200 11550 11900 12250 12600 12950 13300 Measured Depth(700 usft/in) 6.00 -- __ _.... - -- • — 4.50 . CD i o / U - LLIt1 O '4.,3.00 —_._._ _. - Collision Risk Procedures Req. CD 1.50 - - Collision Avoidance Req. _ - No-Go Zone-Stop Drilling 0.00 i111111 1111 1111 1111 1111 1111 1111 1111 1111 1111 1111 1111 1111 , 111 11 „ 111 1r11 7200 7600 8000 8400 8800 9200 9600 10000 10400 10800 11200 11600 12000 12400 12800 13200 13600 Measured Depth • Schwartz, Guy L (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Tuesday, November 15, 2016 11:23 AM To: Schwartz, Guy L(DOA) Cc: Bettis, Patricia K(DOA) Subject: RE: K-06RD2 (PTD 216-131) questions Thanks Guy. Please see responses in red below. Please let me know, if you need anything else, Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell: 907.538.1168 From:Schwartz,Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent:Tuesday, November 15, 2016 10:50 AM To: Monty Myers<mmyers@hilcorp.com> Cc: Bettis, Patricia K (DOA)<patricia.bettis@alaska.gov> Subject: K-06RD2 (PTD 216-131) questions Monty, A couple of items came up in my review of the PTD. 1) What is your plan for disposing of drilling waste? As stated on page 7 we will haul the cuttings and mud to Kenai G&I for re-use of the OBM and disposal of the cuttings. 2) On page 25 the volume of displacement mud appears to be wrong... (step 16.6) I get about 368 bbls. You are correct. I'm not sure wnat i aid tnerer 3) Also step 16.12 has wrong shoe track volume... should be 5.5 bbls. Another Great catch! Corrected on my copy. 4) Any issue with K-13RD ... close crossing?. Will you be monitoring that well while drilling past it? No issues with the K-13RD we will be monitoring this well real time as we pass by it. It is an ESP producer with the pump sitting around 8233 TMD. Our close approach is 8375' so the only risk is damage to equipment. 5) Variance for MASP calculation will be granted.. with lower value the variance for choke/kill outlets is not needed. Thank you! 6) Suggest running a CBL before completion is run. We will be running a CBL as per the completion sundry for this well. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 1 • • OVERSIZED DOCUMENT INSERT This file contains one or more oversized documents. These materials may be found in the original hard file or check the parent folder to view it in digital format. • • TRANSMITTAL LETTER CHECKLIST WELL NAME: h4) On►�- gOR. l PTD: 2 6- 131 �I ✓ Development Service _Exploratory Stratigraphic Test Non-Conventional FIELD: &jkl)tiXk JJ POOL: 1fC,4-A/ .hh& ) I J Atiock Ui') Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10'sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non-Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a)authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 0 ! LI 0 (na , , I N , , , , , , , , , w. . . , , , Q t , ,, U' a c - E o , C, O 3 , , , N' N. O. , (p, Q N C• 0) N Z. , , '00' a)' c _ w U O. m N, , c, O, • C O, Oc 2, , Q. , co CU a p. O) 3. t. �; � > C , 0 ' oco �, 3, ar a. 'y Y, N c0, as . 00' >. o o 3 r. 4 .0 CO o rn O, o p = o? I C O' <0 N ;g •Q, C ei N J. C = . C' p. �� \ E Z. 3, 0 C �, Y Q 3, W. y. o. 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To improve the readability of the Weil History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of infor r nation. TBU K-06 RD2 50-733-20088-02-00 McArthur River Field Kenai Peninsula Borough, Alaska December 18, 2016 – January 27, 2016 Provided by: Approved by: John Serbeck Compiled by: Joshua Dubowski Allen Odegaard Distribution Date: Feb10, 2017 Hilcorp Alaska, LLC K-06RD2 1 TABLE OF CONTENTS 1 MUDLOGGING EQUIPMENT & CREW ................................................................................................ 2 1.1 Equipment Summary ...................................................................................................................... 2 1.2 Crew ............................................................................................................................................... 2 2 GENERAL WELL DETAILS ................................................................................................................... 3 2.1 Well Objectives ............................................................................................................................... 3 2.2 Hole Data ........................................................................................................................................ 3 2.3 Daily Activity Summary ................................................................................................................... 4 3 GEOLOGICAL DATA ........................................................................................................................... 11 3.1 Lithostratigraphy ........................................................................................................................... 11 3.2 Lithology Details ........................................................................................................................... 11 3.2.1 Tyonek Formation ................................................................................................................. 12 Tyonek G7 ......................................................................................................................... 17 3.2.1.1 3.2.2 Hemlock Formation ............................................................................................................... 18 Hemlock H1X_FW ............................................................................................................. 18 3.2.2.1 Hemlock HTK-FW / HK1T .................................................................................................. 19 3.2.2.1 Hemlock HK2T ................................................................................................................... 19 3.2.2.2 3.3 Geology Sampling Program ......................................................................................................... 22 4 Drilling Data ......................................................................................................................................... 23 4.1 Surveys ......................................................................................................................................... 23 4.2 Bit Record ..................................................................................................................................... 28 4.3 Mud Record .................................................................................................................................. 29 4.4 Drilling Progress ........................................................................................................................... 31 5 SHOW REPORTS ............................................................................................................................... 32 6 DAILY REPORTS ................................................................................................................................ 35 Enclosures 2” / 100’ Formation Log (MD/TVD) 5” / 100’ Formation Log (MD/TVD) 2” / 100’ Drilling Dynamics Log (MD/TVD) 2” / 100’ Gas Ratio Log (MD/TVD) 2” / 100’ LWD Combo Log (MD/TVD) Final Data CD Hilcorp Alaska, LLC K-06RD2 2 1 MUDLOGGING EQUIPMENT & CREW 1.1 Equipment Summary Parameter Equipment Type /Position Total Downtime Comments Ditch gas QGM Agitator (Mounted in possum belly) Flame ionization total gas & chromatography. 0 hrs. -- Effective Circulating Density (ECD) Haliburton 0 hrs. — Hook Load / Weight on bit PASON 0 hrs. — Mud Flow In PASON 0 hrs. — Mud Flow Out PASON 0 hrs. — Mudlogging Unit Computer System HP Compaq Pentium 4 (X2, DML & Rigwatch) 0 hrs. — 0 hrs. — Pit Volumes, Pit Gain/Loss PASON 0 hrs. — Pump Pressure PASON 0 hrs. — Pump stroke counters PASON 0 hrs. — Rate of Penetration PASON 0 hrs. — RPM PASON 0 hrs. — 1.2 Crew Mud Logging Unit Type: Arctic Mud Logging Unit Number: ML030 Logging Geologists Years1 Days2 Sample Catchers Years Days2 Allen Odegaard 19 45 Paul Webster 37 44 Josh Dubowski 8 53 Garnet Knapp 0 39 Dylan Muller 5 1/27 *1 Years’ experience as Logging Geologist *2 Days at wellsite between rig up and rig down of logging unit. Hilcorp Alaska, LLC K-06RD2 3 2 GENERAL WELL DETAILS 2.1 Well Objectives K-06RD2 is an oil production well planned to be re-drilled in a north-easterly direction from the existing parent well K-06RD utilizing the existing casing program down to 7,100’ MD / 5,640’ TVD. At 8,062’ MD the parent wellbore will be sidetracked and new wellbore drilled penetrating several Hemlock targets. A 6222’ x 8-1/2” open hole section is planned. A 7-5/8” 29.7# L-80 HYD 511 prod liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with a 3-1/2” ESP completion The well very closely followed the planned directional path. The kickoff point was 8062’MD at 40.52° and began immediately dropping angle to 6.89° by 9154’ MD. Held inclination at 7°-10° while drilling until 10,638’ MD. Continue drilling while building angle to 86° at 11921’ MD (TD). 7-5/8” liner was hung from the 9-5/8” casing and ran down to 13,320’ MD. Operator: HILCORP ALASKA, LLC Well Name: TBU K-06 RD2 Field: McArthur River Field County: Kenai Peninsula Borough State: Alaska Company Representatives: Shane Hauck, Marvin Rogers, Rick Brumley, Steve Lawrence Location: Surface Coordinates 736’ FSL, 135’ FEL, Sec 17, T9N, R13W, SM, AK Mud Line Elevation 73’ AMSL Rotary Table Elevation 122’ AMSL Classification: Development - Oil API #: 50-733-20088-02-00 Permit #: 216-131 Rig Name/Type: Kuukpik 5 / Arctic double Spud Date December 18, 2016 Total Depth Date: January 27, 2017 Total Depth 13,322’ MD / 9,841’ TVD Primary Targets Hemlock HK1T, HK2T Total Depth Formation: Hemlock HK2T Completion Status: — LWD-MWD Services. Halliburton / Sperry Drilling Services Directional Drilling Halliburton / Sperry Drilling Services Drilling Fluids Service Halliburton / Baroid Wireline Logging Service — 2.2 Hole Data Hole Section Max Depth TD Formation MW ppg Dev oinc Csg Dia Shoe Depth LOT ppg MD (ft) TVD (ft) MD (ft) TVD (ft) 8 ½” 13,322’ 9,841’ HK2T 9.1 81.73 7 5/8” 13,320’ 9,840’ N/A Hilcorp Alaska, LLC K-06RD2 4 2.3 Daily Activity Summary December 19, 2016 Mill from 8074' to 8103', CBU, circulate for FIT, perform FIT, POOH, handle milling BHA, prepare to pick up directional BHA. December 20, 2016 Finish laying down milling tools and pick up directional BHA. Upload tools, finish picking up BHA, trip to 2750’ and shallow hole test BHA (Good). Blow down stand pipe and continue running in 5850’ Work air out of pipe and down bad joint, #82. Continue running into to hole to 8022’. Pick up single to 8053, fill pipe, get parameters, kill pump, RIH: observe 2k. Adjust top drive set torque to max torque. Change out gabber dies and saver sub. Make connection and orient tool face to 46* RT. RIH and observe 2K drag while sliding past whip-stock. Tag up on under gauge hole at 8085’with 4K drag. Wash down to 8103’ and orient tool face 170* RT. Drill to 8106’ and pack off. Work various pipe parameters up to 280K as per company man. December 21, 2016 Continued working stuck pipe as per company man instructions. Freed stuck pipe at 270K. Worked pipe without pump. Pick up 124K, slack off 85K. Rack back stand and work a single. Tagged up at 8053’, pressured up to 3500psi, blead off and re tagged with pump on. Circulate 500 bbls, work string up and down to prevent casing damage. Inspect equipment after jarring. Monitor well for 30 minutes (static). Pump dry job and, 20 bbls 2lbs over, striping rubber x2 on from 7991’ to 3200’. Trip out from 3200’ to 2089’. While tripping pipe comes up wet. Install drip pans under rotary table. Continue tripping out of the hole and lay down the BHA. Housekeeping while waiting on boat for string magnet. Pick up BHA #5 and trip in to 8053’ and begin circulating. December 22, 2016 Swap over to rig power then slip and cut drill line. Service top drive and obtain drilling parameters. Wash and ream down to 8107. Build a dry job then drill to 8117. Circulate bottoms up until hole is clean and back ream through window. Build high viscosity sweep, pump sweep and wash down to 8116. Pull up to 8062’, circulate surface to surface with 0% increase in cuttings. Monitor well for 5 minutes (static). Pump dry job and trip out of the hole. Lay down mill tooth BHA, clean magnets (90lbs metal) and junk baskets (15lbs metal, 35lbs coal). Monitor well (static). Perform rig service then make up BHA #6. Upload MWD data and begin tripping into the hole. December 23, 2016 Continue running in the hole to 2900’, fill pipe and test MWD tools. MWD pulser not responding so the decision was made to pull out of hole and replace it. Pump a dry job and pull out of the hole to 736’. Stand back HWDP, jars and collars. Download and troubleshoot pulser. Make up BHA #7 and shallow test. Trip in hole, filling pipe at 2594’ and 5683’. Continue tripping in to 7987’ and fill pipe. Switch to rig power, reboot Pason and orient tool face @ 46* RT. Warm up mud hydraulics and run in to 8047’. Perform rig service. Trip in to 8082’. Observed 2K drag going through window. Wash down and tag up at 8117’. Slide drilling at report time. December 24, 2016 Continue drilling ahead and sliding as per directional driller to 8526’. Change out swab on mud pump one while circulating and working pipe. Drill ahead, get hung up at 8648’ while picking up to get tool face. Engage rotary and broke free at 13K torque. Pump 20 bbls sweep and chase with OBM while finishing drilling stand to 8667’. Obtain slow pump rates and continue drilling ahead at report time. Hilcorp Alaska, LLC K-06RD2 5 December 25, 2016 Continue drilling ahead to 8920’. Slides ratty ledging up. Mix and pump high viscosity sweep while reciprocating pipe. Short trip out of hole to 8035’, hit tight spot at 8496’. Service top drive and HPU’s. Pick up 20 singles and trip in to 8857’. Wash to bottom and continue drilling ahead as per directional driller. December 26, 2016 Drill ahead per directional driller to 9169’, back reaming and slide drilling. Fire on HPU #2, extinguish fire. Circulate with pump #2. Work pipe while cleaning HPU #2 then pull out to the shoe at 8029’. Monitor well while repairing HPU #2 and performing rig maintenance. December 27, 2016 Continue cleaning and working on HPU. Perform rig maintenance. Monitor casing PSI with well shut in while working around the rig. December 28, 2016 Continue rebuilding and cleaning HPU. Pull out of hole to 7795’ and wait on orders. Resume pulling out of hole and lay down BHA #7. Continue working on HPU and performing rig service at report time. December 29-31, 2016 Canrig put on stand-by while the rig repaired HPU #2. January 1, 2017 Continue troubleshooting and repairing HPU #2. Pick up BHA #8. Upload and test MWD tools (good). Finish picking up BHA and trip into hole filling every ~2500’. At 6031’ at report time. January 2, 2017 Continue tripping into the hole to 9071’ and fill pipe at 7643’. Break circulation at the top of the window, at 8046’ and at 8263’. Drill ahead to 9250’ and change out swab on pump #1. Troubleshoot pump #1 wiring issue, pump strokes jumping around. Continue drilling ahead 9480’ and troubleshoot MWD. Continue drilling to 9648’, as per directional plan. January 3, 2017 Continue drilling ahead as per directional plan. Obtain SPR’s, change out swab and liner on pump #1. Circulate and reciprocate pipe while waiting. Continue drilling ahead to 10184’ then pumped a high viscosity sweep (25bbls). Short trip out to 9135’, blow down top drive and perform rig service. Pick up 34 joints of drill pipe on the way back in the hole. Tag bottom and continue drilling ahead as per directional plan. January 4, 2017 Continue drilling ahead as per directional program. Circulate and reciprocate at 10750’ while changing out a swab on mud pump #2. Drill ahead to 10914’ where the rig got hung up. Work free with a max pull of 220K (did not fire jars). Pump a 22bbls sweep and wait for returns. Continue drilling ahead as per directional plan at report time. January 5, 2017 Continue drilling ahead from 10936’ to 11051’. Pump hi vis weighted sweep. Continue circulate same 2 bottoms up, monitor well, pump dry job. Pull out of hole to 10183’; c/o swab #1 mud pump #2 cycle and circulate. Circulate dry job out of hole. Reciprocate, pump dry job. Pull out of hole to 8039’. Slip & cut 194’. Service drawworks. Pull out of hole singles to 6956’. Continue pull out of hole & lay down BHA at report time. Hilcorp Alaska, LLC K-06RD2 6 January 6, 2017 Continue pulling out of hole and lay down BHA. Clean and clear rig floor while monitoring well (static). Pulse test MWD tools and blow down mud lines. Pick up and adjust mud motor bend to 1.76 degrees. Make up remaining BHA and trip into hole to 2160’. Make up agitator and shock assembly. Trip in to 2534’ and fill pipe. Blow down mud lines and clean rig floor. Trip in hole to 6711’ and change grabber dies. Single in to 8550’, installing CBI’s every 4 stands. Break circulating at 9900’ and fill pipe. Circulate and condition mud while troubleshooting MWD. Drill ahead as per directional plan. January 7, 2017 Continue drilling ahead as per directional plan to 11108’. Change out swab on mud pump #2, change rod wash from LVT to water while working pipe. Troubleshoot PLC not latching to HPU. Continue drilling ahead to 11222’. HPU unlatching and dropping RPM, change assignment running mud pump #1 with HPU #2. Circulate while waiting on orders. Pump dry job and pull out of the hole to 8016’. Service rig and drawworks. Pacific Power checking on HPU #1 while changing out dampener on mud pump #1 at report time. January 8, 2017 Troubleshoot HPU and finish replacing mud pump dampener. Monitor well (static). Trip back in hole to 9903’, fill pipe, test mud pump #1 and HPU #1. Continue tripping in hole to 11187’, Kelly up, fill pipe and wash to bottom. Drill ahead as per directional plan to 11292’. Unplug rod wash on mud pump #1, change #3 swab on mud pump #2 while working pipe. Rack stand back, troubleshoot draw-works motor issue, draw-works is bypassing. Mix 20bbls dry job and monitor well (static). Rack back 3 stands of drill pipe, Kelly up and pump 1 bpm while changing out drillers side draw-works motor. Replace broken hookload sensor and calibrate. Trip in hole and drill ahead to 11360’. Mix and pump dry job and pull out of the hole. January 9, 2017 Continue pulling out of the hole and lay down BHA. Download MWD data and rack smart tools back in derrick. Clean floor from wet pipe trip. Slip and cut 86.5’ of drill line. Pick up new BHA and change motor bend to 2.12 and run in hole to 3782’. O-ring on HPU#1 failed. Shut down HPU and change O- ring, restart HPU, Same o-ring failed, replace and restart. Continue running in hole at report time. January 10, 2017 Trip in to 8684’. Trip back out to 8045’ to change DW FWD isolation valve on HPU #2. Trip in hole to 9500’, fill pipe and circulate to warm up the mud. Trip in to 11312’ and fill pipe. Tag bottom (no fill) and drill ahead as per directional plan. Hanging up while sliding. 45k overpull. Drill to 11477’. Air boot on Riser failed, spilled 10 gallons of mud in cellar. Stand back stands to 11064’; Make up test plug and hang off string. Remove lower boot air flange and riser, test riser (good). Run in hole to 11477’ and drill ahead as per directional plan. January 11, 2017 Directional drill to 11484’. Tool-face hanging up, stacking weight. Change swab in #1 mud pump. Directional drill from 11484’ to 11499’. Change liner, gasket and wash plate in mud pump #2, #3 pod. Work pipe with one pump. Directional drill from 11499’ to 11542’.When tool-face hangs up, stacking weight; no difference. Pick up & rotate 20RPM 2’ from the bottom of the slide to help clean up drag. Continue to drill ahead from 11542’ to 11590’. Pump weighted sweep, no noticeable change in returns. Pump weighted sweep with lube, better weight transfer to bit. Continue directional drill as planned at report time. Hilcorp Alaska, LLC K-06RD2 7 January 12, 2017 Continue drilling/sliding ahead as per directional driller to 11637’ and change swab and liner on in pump #1 pod #1. Continue drilling ahead as per directional driller to 11667’ and change out #3 swab on pump #1 while working pipe. Continue drilling ahead to 11674’ and change out #1 swab on mud pump #2. Pump high viscosity sweep with nut plug and lube and pump at 5bpm OBM at 400gpm until out of drill pipe. Continue drilling ahead as per directional driller at report time. January 13, 2017 Continue drilling ahead as per directional driller to 11733’. Change swab in mud pump #2 pod #2. Drill ahead to 11774’ and change swab in mud pump #1 pod #2. Drill ahead to 11805’ and pump a lube/nut plug sweep and chase with 9.1ppg OBM. Sweep was 20bbls late with 50% increase in cuttings returned. Increase lasted 500bbls past with 100% increase (coal/sand @ max). No change in parameters after sweep. Circulate hole clean while rotating. Continue drilling ahead at report time. January 14, 2017 Continue drilling ahead as per directional driller to 11867’. Service top drive and draw-works. Trip out two stands, Rig up head pin and circulating equipment. Circulate 2bpm while changing out saver subs and grabber dies. Rig down circulating equipment, trip in hole one stand, wash to bottom and orient tool face. Drill to 11874’ and change out swab in mud pump #1 pod #3. Drill ahead to 11896’ and replace cap gasket on mud pump #2 pod #3 and go through valves. Drill ahead to 11900’, ream squat, take survey and rack back one stand. Monitor well (slight drop). Pump sweep around, came back 20 bbls late with 25% increase in cuttings. Monitor well (slowly dropping). Pump dry job and pullout of hole to 5991’. Switch from rig to platform power and blow down casing. Continuing to pull out of the hole at report time. January 15, 2017 Continue pulling out of the hole, lay down/rack back MWD/BHA. Drain stack, make up test plug assembly and work on mud pump #2. Work air out of BOP’s and test. Replace swabs on mud pump #2, pods 1 and 3. Finish testing BOP’s, lay down test joint and drain stack. Pick up BHA #11 and unload MWD. Tripping in hole at report time. January 16, 2017 Continue tripping in hole to 6000’, fill pipe, trip in to 8012’ and slip and cut a83’ of drill line. Swap to rig power and perform rig service. Service make up tongs, fill pipe, test MWD and orient tool face through window. Trip in to 9965’, fill pipe and warm/shear mud. Trip in to 11771’ and wash to bottom. Circulate while working on changing modes on agitator. Continue drilling ahead as per directional driller to 12081’. While picking up to back ream slide, string packed off and blew a pop-off. Slacked off, re-established circulation. Could not rotate. Working tight hole at report time. January 17, 2017 Continue working stuck pipe at 12046’ to 12019’. Established pump rate and worked pipe free as per company man. Pumped high viscosity sweep and reciprocate pipe. Sweep came back 25bbls late with a 25% increase in cuttings. Continue drilling ahead per directional driller to 12104’, mud pump #1 lost 30 strokes, pick up off bottom and packed off. Establish circulation and work pipe as per company man. Trip out of hole to 11895’, working pipe through tight spots. Ream back to bottom and drill ahead to 12122’. Attempt to pick up to orient tool and string packed off. Worked pipe loose and rotate from 12122’ to 12143’. Pump high viscosity sweep, large amount of sand came back before sweep (from rotating), sweep arrived 25bbls late with minimal increase in cuttings. Continue drilling ahead to 12206’. Work pipe and get tool face with HPU #1 while checking oil on the other. Swap and check other HPU. Continue drilling ahead as per directional driller. Hilcorp Alaska, LLC K-06RD2 8 January 18, 2017 Continue drilling ahead to 12279’, pick up off bottom to change valve in mud pump #1. Make up dry job and monitor well (slight drop). Pump dry job and pull out to window to change pod in mud pump #1 pod #2. Pull tight at 11616’ to 11647’ with 20k over pull. Service rig/top drive while changing out pod #2 in mud pump #1. Test mud pump #1 then trip into hole. Ream through tight spot at 8150’-8266’. Fill pipe at 9920’. Work through coal seams without much trouble, Kelly up at 12208’ and perform cleanup cycle. Cuttings back 100bbls early with 30% increase in cuttings at max with mostly coal/sand. Cracked bolt on mud pump #1 pod #3 needs replacing. Circulate with mud pump #2 while working pipe from 12208’ to 12270’. Finish repairing pump and ream to bottom. Drill to 12284’, stop and troubleshoot MWD while pumping and rotating. Monitor well (slight loss), pump dry job and begin pulling out of the hole. January 19, 2017 Continue tripping out of the hole to change out BHA. Pull through tight spots at 11833’, 11709’ and 8455’. 8k bobble through window. Blow down mudlines at 7949’. Serviced mud pump #1 while laying down BHA. Pick up BHA #12 and run in hole. Fill pipe at 2600’. Continue running in the hole at report time. January 20, 2017 Run in hole from 3883’ to 7995’ filling pipe every 2800’. Cut & slip drilling line 86’ cut off. Continue run in hole from 7995’ to 12212. Fill pipe at 10150’. Circulate and condition mud. MADD pass from 12257’ to 12284’. Directional drill from 12284’ to 12315’. Change out liner gasket mud pump #2 pod #3. Change out all 3 swabs on mud pump #2. Directional drill from 12315’ to 12330’. Circulating at report time. January 21, 2017 Continue drilling as per directional driller to 12391’. Pump a sweep at 12386’ while rotating down to 12391’ and see 30% increase in returns when sweep arrived 100bbls late. Continue to circulate until clean. Circulate with mud pump #2 while servicing HPU’s, tighten fluid pod on mud pump #1. Reconfigure flow meter on drawworks, tighten fittings on same and IBOP. Line up tool face and drill ahead to 12400’. Trouble shoot MWD tools then continue drilling ahead as per directional driller. January 22, 2017 Continue drilling ahead as per directional driller to 12436’, decision was made to pull out to inspect/change bit and BHA. Circulate while mixing dry job, pump dry job and pull out of hole. Switch to platform power at shoe and service rig. Continue pulling out of the hole and laying down BHA at report time. January 23, 2017 Finish laying down BHA and downloading MWD. Move BOP remote panel, wire in and function test. Make up BHA #13 and run into 8085’, filling pipe at 2843’, 5756’ and 8085’. Perform rig service and Cut and slip 119’ of drill line. Swap to rig power. Trip in to 9850’ and test MWD tools. Continue tripping in hole at report time. January 24, 2017 Continue running in hole. Wash and ream from 12305’ to 12436’ and begin drilling. Drill to 12714’, pump a sweep, back 100bbls late with 50% increased cuttings. Continue drilling ahead at report time. January 25, 2017 Continue drilling ahead as per directional driller to 13097’ Fire in HPU #1. Kill HPU, secure well, muster/put out fire. After all clear, open well and pump with mud pump #2. Clean and repair HPU #1 room/area at report time. Hilcorp Alaska, LLC K-06RD2 9 January 26, 2017 Continue repairing/cleaning HPU #1 and area while circulating and working the string. Start up and function test HPU #1. Line up tool face and continue drilling as per directional driller. January 27, 2017 Continue drilling ahead as per directional driller to 13322’, pump high viscosity sweep and circulate hole clean. Take survey and obtain slow pump rates. Pull out of hole to 12834’. Bad spot in drilling line discovered, slip and cut 380’. Continue pulling out of hole to 7830’ and perform rig service. Continue pulling out of hole at report time. January 28, 2017 Continue pulling out of hole and lay down 52 joints of drill pipe. Lay down BHA and MWD tools. Service rig. Pick up BHA #14 and upload MWD. Shallow hole test (good) and load nuclear sources. Tripping into hole at report time. January 29, 2017 Finish running down to the shoe. Hang blocks and replace drilling line spool and cut and slip. Drain stack and pull 3 stands to completely empty. Fill stack and choke with water and rig up BOP testing equipment. Test BOPs then rig down equipment. Continue running in hole on elevators. Unable to get past 12497’ on elevators, jar free twice at 60K over. Wash and ream past tight spot and attempt to run in on elevators again (no go), attempt to wash with no rotary (no go). Wash and ream to 12783’. Cracked drive motor on top drive, troubleshooting at report time. January 30, 2017 Replace hydraulic motor on top drive and clean oil throughout the platform. Test motor (good) and continue running in hole for MAD pass. Unable to run in on elevators or wash with no rotary. Continue washing and reaming down to bottom at report time. January 31, 2017 Continue washing and reaming to bottom. Take survey at bottom and begin MAD passing out. MAD pass out to 11,700 then begin running back to bottom to spot glass bead pill. February 1, 2017 Run in hole to bottom, circulate and pump bead pill on bottom. Pump 84bbls and chase with 156bbls. Pump dry job and pull out of the hole. Lay down BHA and download MWD data. Service rig. Make up 7- 5/8” test joint. Change out lower rams to 7-5/8” fixed bore rams. February 2, 2017 Finish installing 7-5/8” rams and test. Rig down test joint and rig up casing equipment as per Weatherford. Begin running 7-5/8” casing; Drawworks break not releasing, troubleshoot and repair. Continue running 7-5/8” liner to 5445’. Rig up and circulate liner volume. Make up liner hanger as per BOT rep. February 3, 2017 Finish making up liner hanger assembly as per BOT hand. Mix and fill baker fluid in liner. Trip in hole on drill pipe to 8026’ filling pipe every 10 stands. Cut and slip 184’ of drill line while circulating 1.5 bottoms up. Service rig and make up cement head as per BOT hand. Establish string parameters and trip into hole. Stacked out on window at 8068, attempt to work liner through window. Unable to work past 8071’ with 40k set down. Over pulled 42k multiple times to pull free. Town decision to pull out of hole. Pump dry job and begin pulling out of hole. Pull liner hanger above rotary, no damage, run back in hole one stand of drill pipe and stab TIW valve. Monitor well on trip tank while waiting for casing hands. Rig up casing equipment. Begin laying down 7-5/8” casing. Hilcorp Alaska, LLC K-06RD2 10 February 4, 2017 Continue laying down 7-5/8” casing and shoe track. Shoe cracked/split in 3 spots. Bottom of shoe gone and belled out. Unable to get 8-1/2” gauge ring over it. Lay down casing tools and perform rig service. Make up window dressing BHA as per BOT rep. Running in hole at report time. February 5, 2017 Trip into hole with milling assembly and circulate bottoms up. Get parameters and wash down to 8104’. Window was clean, rack back 2 stands. Monitor well for 30 min (static) and pump dry job. Trip out of hole, break pups and XO’s off cement head. Rack back HWDP, jars and clean magnets. 29 lbs collected from magnet. Boot baskets empty. Take flex joint out of BHA and make stiff assembly. Trip in hole to 8021’ and circulate bottoms up. Establish string parameters. Slack off and start taking weight (5k) at 8061’. Pick up and bring on rotary to 80 rpm. Ease in hole and start seeing work at 8058’. Inch in hole until cleaned up. Ream down to 8090’, ream up and down 3x. Able to slide in and out no rotary with no drag from 8055’ to 8097’. Circulate to condition mud before pulling out of hole. February 6, 2017 Continue conditioning mud. Monitor well (slight drop), pump dry job, rig up stripping rubber and trip out of hole. Lay down BHA as per BOT rep.; cleaned 61 lbs. off of magnets and 21lbs out of boot baskets (98% coal, 1lb iron). Clean and clear rig floor for trip in. Service rig and begin making up BHA as per BOT hand. Single into hole, filling pipe at 2225’. Tighten slack spot on drawworks. Continue picking up drill pipe, total joints picked up; 111 plus one single that was racked back in the derrick. 112 joints picked up, 10 joints on deck and 296 in the derrick. Run in hole out of derrick, fill pipe at 5200’. Continue running in hole to 8021’. Cut and slip drill line at report time. February 7, 2017 Wash down to 8140’ then continue tripping into hole to 8655’. Stacked 10-15k, pick up 140k, slack off 82k. Jar stuck pipe. 19 jar licks up to 70k over. Wash down to 9700’. Circulate and work pipe then continue tripping in to 10656’. Circulate and work tight hole from 10631’ to 10639’. Circulate bottoms up. Continue tripping in to 11243’ and worked tight hole, 3 jar licks 45k over. Trip in to 11872’ and circulate while working pipe without rotating. Continue tripping in hole, washing when needed to 13322’. Condition mud and circulate as per mud man. Monitor well (static). Spot 84bbl bead pill on backside, pumped slug and pull out of hole sideways. Tight spots encountered at 13170’, 13163’, 13096’, 12985’, 12944’, 12933, 12910’, 12895’ 12722’,12541’, 12520’, 11873’, 11660’, 11426’, 11315’, 11295’, 10750’, 10058’, 9923’, 9575’. Continuing to pull out at report time. February 8, 2017 Continue pulling out of hole. Tight spots at 8567’, 8360’, 8185’, 8100’. Window looked good. Lay down BHA and perform rig service. Rig up 7-5/8” casing equipment and monitor hole (static). Begin running in with liner, laying down one bad joint and filling every 10 joints. February 9, 2017 Continue running 7-5/8” casing down to 5360’, rig up to circulate and warm mud up. Stepped up pump rate to 430 gpm at 1281 psi and lost 38.7bbls with 31.4bbls coming back from ballooning. Make up hanger and running tool then rig down Weatherford. Thaw hanger, mix hanger fluid, swap elevators, trip in one stand and break circulation. Trip in hole on drill pipe to 8003’. Rig up cement head with 5’ pup joint, XO, XO and 15’ pup joint. Cut and slip 102’ of drilling line then perform rig service. Continue tripping in hole on drill pipe, working through top coal and filling pipe at spots in between coals as per mudlog. Hilcorp Alaska, LLC K-06RD2 11 3 GEOLOGICAL DATA 3.1 Lithostratigraphy Tops picked by Hilcorp Geologists FORMATION PROGNOSED ACTUAL MD (ft) TVD (ft) SSTVD (ft) MD (ft) TVD (ft) SSTVD (ft) KOP 8,400 6,350 -6,472 8,062’ 6,323 -6,201 COAL39 11,033 8,890 -9,012 11,102’ 9,202 -9,478 G7T N/A N/A N/A 11,454’ 9,494 -9,372 H1X_FW 11,696 9,335 -9,457 11,632 9,600 -9,478 COAL59 11,758 9,362 -9,484 11,685 9,623 -9,501 HTKE-FW 11,770 9,366 -9,488 11,711 9,633 -9,511 HK2T 11,901 9,410 -9,532 11,962 9,561 -9,683 3.2 Lithology Details Lithology descriptions of all Kenai Group and Mesozoic rock cuttings samples started immediately after drilling out the surface conductor, then continued as per pre-set plans and procedures, and modified when directed by the Hilcorp operations geologist. The Kenai Group of Alaska’s Cook Inlet Basin, which includes the Sterling, Beluga, Tyonek, Hemlock and West Foreland Formations, was deposited by a variable-energy fluvial system within a large closed fore- arc basin. The characteristic sedimentary stratigraphy consists of dominant massive to thinly bedded sandstone and claystone-siltstone, generally abundant thin interbeds of air fall and re-deposited volcanic ash, minor beds of basal or modal conglomerate and extensively-distributed thin beds of coal and carbonaceous rocks. Gradational upward-fining sequences and bi-modal distribution zones are abundant within sandstone sections. Note that in Canrig’s Lithology Descriptions, the special modifying term “tuffaceous” was created to address the pervasive presence and diversity of soft-sediment volcanogenic- origin rocks in the Cook Inlet area. Though generally applied to significantly ash-rich clay-silt-sand lithologies, its wide use in descriptions may include discernible micro-shard concentrations of disaggregated volcanic glass to vitric air fall volcanic ash to smectite-bentonite clays derived from devitrified ash to rare layers of vitric ignimbrite. Hilcorp Alaska, LLC K-06RD2 12 3.2.1 Tyonek Formation The Tyonek formation is a series of alternating tuffaceous sandy siltstones, tuffaceous siltstones, sand and clay with occasional coal and carbonaceous shales. The tuffaceous siltstones are typically medium gray with pale brown and olive hues to medium dark gray with pale olive to very pale brown hues. They are easily friable to friable with a crumbly to pulverulent tenacity and often display bit curled to a rare platy cuttings habit. Typically have a dull to earthy luster with a silty to gritty texture and have a massive structure The sands are typically medium gray to medium gray with pale olive hues to yellowish brown to grayish brown. Grain size is typically lower medium to lower fine to occasionally lower coarse and trace 2-4mm grains. They are typically sub rounded to rounded to sub angular with moderate to poor sorting and are sub spherical to trace sub discoidal. The sands are typically comprised of translucent smoky gray to transparent quartz and trace lithics. Ranges from unconsolidated to easily friable to trace amounts of firm clasts. The coals are typically black to very dark gray to occasionally matte black. They display brittle to crumbly to dense tenacity with hackly to conchoidal to irregular fracture. They usually display flakey to an occasional wedgelike cuttings habit. Luster is often vitreous to earthy to slightly waxy with a matte texture. 8062’ to 11454' MD (-6201' to -9372' TVDSS) Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 324 0.4 57.1 149 1 12.9 Gas Peaks MD Depth TVD Depth TG C1 C2 C3 C4I C4N C5I C5N 8157 6396 149 31733 8367 6571 92 19642 8515 6704 81 17020 8697 6871 65 13530 8781 6950 56 11516 9725 7875 87 21278 10040 8177 64 15513 Tuffaceous Claystone / Siltstone (8079- 8120) = dark grayish black to black; highly contaminated with oil-based mud; metal shavings and cement are common but not abundant. Coal (8120' - 8160') = black to grayish black; brittle to dense tenacity; splintery to irregular fracture; elongated or massive cuttings habit; earthy to dull luster; matte texture; massive structure; minor amount of tuffaceous siltstone; greenish gray to light olive gray; poor induration; crumbly; irregular to blocky fracture; dull to earthy luster; trace fine grain sand. Tuffaceous Siltstone (8160' - 8220') = medium dark gray to dark gray to black; easily friable; poor induration; crumbly tenacity; earthy fracture; massive to platy cuttings habit; earthy luster; gritty to silty texture; massive to thick structure; occasionally interbedded with tuffaceous claystone. Hilcorp Alaska, LLC K-06RD2 13 Sand / Sandstone (8220' - 8310') = medium gray to medium light gray with yellowish gray hues; lower medium to upper fine grained; sub-angular to sub- round; moderate sorting; unconsolidated; texturally immature; quartz, translucent or transparent, with frosted surface abrasion; interbedded with tuffaceous siltstone, easily friable, crumbly tenacity, earthy fracture, massive cuttings habit, earthy luster, silty texture, massive structure. Tuffaceous Siltstone (8310' - 8360') = medium dark gray to dark gray to almost black; easily friable to firm friable; poor induration; crumbly tenacity; earthy fracture; massive to platy cuttings habit; earthy luster; gritty to silty texture; massive to thick structure; occasionally interbedded with tuffaceous claystone and tuffaceous sandstone. Coal (8360' - 8380') = black to grayish black; brittle to dense tenacity; splintery to irregular fracture; elongated or massive cuttings habit; earthy to dull luster; matte texture; massive structure; interbedded with tuffaceous siltstone and sandstone. Tuffaceous Sandstone (8380' - 8510') = medium gray to medium light gray with some dark gray; lower medium to upper fine grained; sub-angular to sub- round; moderate sorting; unconsolidated; texturally immature; quartz; individual grains translucent to transparent, with frosted to polished surface abrasion; interbedded coals and tuffaceous siltstone, easily friable, crumbly tenacity, earthy fracture, massive cuttings habit, earthy luster, silty texture, massive structure. Coal (8510' - 8525') = black to grayish black; brittle to dense tenacity; splintery to irregular fracture; elongated or massive cuttings habit; waxy to earthy to dull luster; matte texture; massive structure; interbedded with tuffaceous siltstone and sandstone. Tuffaceous Siltstone (8525' - 8560') = medium dark gray to dark gray to almost black; easily friable to firm friable; poor induration; crumbly tenacity; earthy fracture; massive to platy cuttings habit; earthy luster; gritty to silty texture; massive to thick structure; occasionally interbedded with tuffaceous claystone and tuffaceous sandstone. Sand / Tuffaceous Claystone (8560' - 8670') = dark yellow brown to grayish red to dusky brown; unconsolidated to friable to occasionally firmly friable; upper medium to lower coarse to with very coarse to upper fine being common; minor amount of 2-4mm granules; poor to very poor sorting; angular to sub angular to trace sub rounded; bit broken quartz common; sub spherical to spherical to sub discoidal; occasional grain supported tuffaceous sandstone clasts; claystone are medium dark gray to dark gray; poor to moderate induration; semi dense to brittle and crumbly; blocky to planar to irregular fracture; tabular to bit stacked cuttings; dull to slightly waxy luster; silty to smooth texture; no hydrocarbon indicators. Tuffaceous Siltstone / Claystone (8670' - 8770') = medium dark gray to brownish gray to grayish black; moderate to semi poor induration; crumbly to semi brittle to semi tough; irregular to earthy to blocky to planar fracture; tabular to occasional bit stacked and platy cuttings; dull to waxy luster; silty to gritty texture; unconsolidated sand to easily friable sandstone common; lower medium to upper coarse; occasional upper fine to lower very coarse; poor to moderate sorting; sub angular to sub rounded; sub spherical to sub discoidal; quartz dominated; dark lithics common; moderate to poor visual porosity and permeability; no hydrocarbon indicators. Coal (8770' - 8810') = black to grayish black; dense to brittle tenacity; splintery to hackly to irregular fracture; elongated or massive cuttings habit; dull to earthy luster; matte texture; massive structure. Tuffaceous Sandstone / Siltstone (8810' - 8880') = brownish gray to dark yellow brown; unconsolidated to easily friable; upper coarse to upper medium; fine to very coarse grains common; sub angular to sub rounded; large silt content; grades to a silty sandstone; carbonaceous shale and claystone common but not abundant. Hilcorp Alaska, LLC K-06RD2 14 Tuffaceous Siltstone / Sandstone (8880' - 8970') = dark gray to medium dark gray some light olive gray; friable to moderately hard; moderate induration; crumbly to brittle tenacity; irregular fracture; massive cuttings habit; earthy to dull luster; silty to gritty texture; massive structure; sand, translucent or transparent, lower medium to upper medium with some lower coarse and upper fine, spherical to sub- discoidal, sub- angular to sub-rounded, moderately well to well sorted, unconsolidated, quartz; coal, black, friable, brittle tenacity, irregular fracture, elongated cuttings habit, dull luster, matte texture, massive structure. Tuffaceous Sandstone / Siltstone (8970'-9050') = olive gray to dusky brown to grayish brown; predominantly unconsolidated to easily friable; lower coarse to upper medium with very coarse to upper fine common; poor to moderate sorting; sub rounded to sub angular to angular; bit broken grains common; sub spherical to sub discoidal; moderate visual porosity and permeability; predominantly clear to translucent quartz; dark lithics common; carbonaceous shale, tuffaceous siltstone and claystone common; no hydrocarbon indicators. Tuffaceous Sandstone (9050'-9170') = medium dark gray to dusky brown to grayish brown; unconsolidated to easily friable clasts; upper to lower medium with lower coarse to upper fine being common; moderate to poor sorting; sub angular to sub rounded to angular; bit broken grains common; sub spherical to sub discoidal; moderate visual porosity and permeability; predominantly translucent to clear quartz grains; dark lithics common; minor amount of silty infill and carbonaceous shale. Sand / Tuffaceous Siltstone (9170' - 9270') = overall brownish gray to olive gray to dark yellow-brown; lower medium to upper to lower fine to occasionally lower coarse grained; trace upper coarse grains; sub- rounded to rounded to sub- angular; sub-spherical to trace sub- discoidal; moderate to poorly sorted; predominantly translucent smoky gray quartz; trace lithics; unconsolidated to easily friable; moderately tuffaceous siltstone; predominantly medium to dark medium gray with pale olive hues; easily friable to friable; crumbly to pulverulent; irregular to semi-planar fracture; dull to earthy luster; PDC bit butter-curl to semi-platy cuttings habit; laminated coal observed in larger cuttings; silty to gritty texture; no hydrocarbon indicators. Tuffaceous Claystone (9650' - 9800') = medium gray to dark medium gray with dark brown to olive hues; moderate to poor induration; planar to irregular fracture; bit stacked to platy cuttings habit; dull to earthy luster; clayey to silty texture; massive structure; occasionally grades to a silty claystone to a tuffaceous siltstone; carbonaceous banding common; moderate amount of coal observed throughout the interval; matte black to very dark brownish black; semi tough to brittle and crumbly; hackly to planar to irregular fracture; flaky cuttings habit; no hydrocarbon indicators. Coal (9790' - 9800') = black to grayish black; brittle to dense tenacity; splintery to irregular to conchoidal fracture; irregular to massive cuttings habit; waxy to earthy to luster; matte texture; massive structure; interbedded with tuffaceous claystone, siltstone, and sandstone. Tuffaceous Sandstone / Siltstone (9800'-9900') = dark medium gray to greenish black to brownish black; unconsolidated to friable; upper to lower medium to upper fine grained, common coarse grains; sub-angular to sub-rounded to angular; poor to moderate sorting; sub-spherical; predominantly clear to translucent quartz; trace 2- 3mm grains; broken grains common; overall moderate visual porosity and permeability; tuffaceous siltstones are typically poorly indurated; crumbly to malleable; irregular to planar fracture; common PDC bit butter-curl cuttings; dull luster; matte black coal common; semi-tough to semi- brittle; no hydro- carbon indicators. Sand / Conglomeratic Sand (9900' - 9970') = medium to light gray with light olive gray to yellow-gray to white; lower fine to upper fine grained with coarse to very coarse grains, bimodal; spherical to sub- prismoidal to sub- discoidal; angular to sub-angular to sub-rounded to rounded; poorly sorted; friable; matrix, fine sand; matrix supported; texturally immature; quartz, translucent to transparent, frosted to grinding surface abrasion; some grains appear to be bit shattered; fair to good porosity and permeability. Hilcorp Alaska, LLC K-06RD2 15 Tuffaceous Claystone (9970' - 10040') = light brown to light brownish gray to light gray to light olive gray; common black carbonaceous debris; very soft to soft to friable; moderately to very slightly gritty to slightly silty to often clayey texture; sub-tabular to irregular cuttings habit; dull to earthy luster; occasionally silty, interbedded with thin tuffaceous sandstone and siltstone stringers; very thin black coal stringers common; no hydrocarbon indicators. Tuffaceous Siltstone (10040' - 10100') = medium dark gray to medium gray with slight olive gray sub- hues; friable to moderately hard; brittle to dense tenacity; splintery to mottled fracture; massive cuttings habit, common PDC bit butter-curl cuttings; earthy to dull luster; silty to gritty texture; massive structure; interbedded with tuffaceous sandstone, very fine, well sorted, sub- rounded, moderate sphericity, friable, silt matrix, matrix supported; very thin black coal stringers common; no hydrocarbon indicators. Tuffaceous Claystone (10100' - 10190') = dark medium gray to medium gray with dark brown to olive hues; poor to moderate induration; irregular to planar to occasionally blocky fracture; bit stacked to tabular to platy cuttings habit; earthy luster; silty to clayey texture; massive structure; occasionally grades to a silty claystone; deformed carbonaceous banding and sediment common; trace sand and coals throughout; no hydrocarbon indicators observed. Coal (10190' - 10220') = matte black to very dark brownish black; semi tough to brittle and crumbly; hackly to planar to irregular fracture; flaky cuttings habit; no visible off gassing. Sand (10220' - 10350') = brownish black to dark medium gray to greenish black; unconsolidated to easily friable; lower medium to upper fine with lower very coarse to upper very fine being common; trace 2-4mm grains; poor to moderate sorting; sub rounded to sub angular to rounded; bit broken grains semi common; sub spherical to sub discoidal; predominantly clear to translucent quartz; moderate tuffaceous siltstone content; semi tough to crumbly; irregular to planar to blocky fracture; tabular to platy to bit stacked cuttings habit; dull to earthy luster; silty to clayey texture; rarely grades to a tuffaceous claystone; carbonaceous banding and sediment common; carbonaceous shale common throughout; no hydrocarbon indicators. Tuffaceous Siltstone (10350' - 10430') = medium dark to medium gray with slight olive gray sub-hues; friable to moderately hard; brittle to dense tenacity; splintery to mottled fracture; massive cuttings habit, common PDC bit butter- curl cuttings; earthy to dull luster; silty to gritty texture; massive structure; interbedded with tuffaceous sandstone, very fine, well sorted, sub- rounded, moderate sphericity, friable, silt matrix, matrix supported; often interbedded with very thin black coal stringers; no hydrocarbon indicators. Tuffaceous Claystone (10430' - 10500') = dark medium to medium gray with dark brown to olive hues; poor to moderate induration; irregular to planar to occasionally blocky fracture; PDC bit butter-curl to tabular to platy cuttings habit; earthy luster; silty to clayey texture; massive structure; occasionally grades to a silty claystone; deformed carbonaceous banding and sediment common; trace sand and coal stringers throughout; no hydrocarbon indicators. Coal (10500' - 10530') = matte black to very dark brownish black; semi-tough to brittle and crumbly; hackly to planar to irregular fracture; conchoidal to flaky cuttings habit; no visible off gassing. Tuffaceous Siltstone (10530' - 10600') = medium dark gray to medium gray with rare olive gray; friable to moderately hard; brittle to dense tenacity; splintery to mottled fracture; massive cuttings habit, occasionally PDC bit butter-curl cuttings; earthy to dull luster; silty to gritty texture; massive structure; interbedded with tuffaceous sandstone, very fine, well sorted, sub- rounded, moderate sphericity, friable, silt matrix, matrix supported; often interbedded with very thin black coal stringers; no hydrocarbon indicators. Hilcorp Alaska, LLC K-06RD2 16 Sand (10600' - 10710') = brownish black to dark medium gray to greenish black; unconsolidated to easily friable; lower medium to upper fine grained with lower very coarse to upper very fine grains being common; trace 2-4mm grains; poor to moderate sorting; sub-rounded to sub- angular to rounded; bit broken grains semi-common; sub-spherical to sub- discoidal; predominantly clear to trans- lucent quartz; often vitreous; moderate tuffaceous siltstone content; semi-tough to crumbly; irregular to planar to blocky fracture; tabular to platy to PDC bit butter-curl cuttings habit; dull to earthy luster; silty to clayey texture; rarely grades to a tuffaceous claystone; carbonaceous banding and sediment common; occasionally carbonaceous shale interbedded; no hydrocarbon indicators. Sand (10710' - 10770') = dark medium gray to brownish black to greenish black; predominantly unconsolidated to easily friable with trace firm; upper medium to upper fine with upper coarse to lower fine being common; trace 2-3mm grains often bit broken; poor to moderate sorting; sub rounded to sub- angular to rounded; sub spherical to sub discoidal; predominantly clear to translucent quartz minor dark lithics; no hydrocarbon indicators. Tuffaceous Siltstone (10770' - 10850') = dark medium gray to grayish black to medium gray with dark olive to brown hues; semi moderate to poor induration; tough to crumbly to slightly brittle; irregular to blocky to planar fracture; tabular to platy to PDC bit stacked cuttings habit; dull to earthy luster; silty to clayey texture; occasionally grades to a tuffaceous claystone; carbonaceous banding and sediment common in the clasts; carbonaceous shale common throughout; minor amount of coals; no hydrocarbon indicators. Coal (10850' - 10890') = very dark gray to brownish black to matte black; semi- tough to brittle and crumbly; hackly to irregular to occasionally conchoidal fracture; flaky to semi platy or scaly cuttings habit; matte to slightly greasy luster; no visible off gassing. Sand (10890' - 10950') = dark medium gray to dark gray with brown and olive hues; unconsolidated to easily friable; upper fine to lower medium with upper coarse to lower fine being common; trace 2-3mm grains typically bit broken; poor sorting; sub rounded to sub angular to rounded; sub spherical to sub discoidal; carbonaceous shale, tuffaceous siltstone and claystone all common; no hydrocarbon indicators. Coal (10970' - 11010') = very dark gray to brownish black to matte black; semi-tough to brittle and crumbly; hackly to irregular to occasionally conchoidal fracture; flaky to semi-platy or scaly cuttings; matte to slightly greasy luster; no visible off gassing. Sand (11010' - 11110') = brownish black to medium dark gray to grayish black; unconsolidated to trace easily friable; upper to lower fine with minor lower very fine to lower medium; moderate to good sorting; sub rounded to rounded to sub angular; sub spherical; dominated by clear to translucent quartz; carbonaceous shale common; minor dark lithics; trace tuffaceous siltstone; claystone all common; no hydrocarbon indicators. Coal (11110' - 11140') = very dark gray to brownish black to matte black; semi- tough to brittle and crumbly; hackly to irregular to occasionally conchoidal fracture; flaky to splintery to semi- platy cuttings; matte to slightly greasy luster; no visible off gassing. Tuffaceous Siltstone (11040' - 11260') = dark medium to medium gray with some dark olive to brownish gray; moderate to poor induration; tough to crumbly to slightly brittle; irregular to blocky to planar fracture; tabular to platy to PDC bit buttercurl cuttings; dull to earthy luster; silty to clayey texture; often grades to a tuffaceous claystone; carbonaceous banding and sediment common; trace to common carbonaceous shale; minor amount of interbedded coals; no hydrocarbon indicators. Sand / Tuffaceous Siltstone (11230' - 11340') = medium dark gray to brownish black to grayish black; unconsolidated to occasional easily friable clasts; upper medium to upper fine with lower coarse to upper fine; poor sorting; sub rounded to sub angular; sub spherical; siltstones are crumbly to slightly brittle; Hilcorp Alaska, LLC K-06RD2 17 irregular to planar fracture; tabular to PDC bit stacked cuttings habit; earthy luster; silty texture; carbonaceous banding common. Tuffaceous Sandstone / Siltstone (11340' - 11460') = light to medium light gray with light olive to olive gray; lower fine to upper medium grained with coarse grains scattered throughout sample; spherical to sub-discoidal; rounded to sub-rounded to sub-angular, with some angular quartz grains bit shattered; poor to moderate sorting; friable to unconsolidated; tuffaceous / silty matrix; grain supported; individual grains are translucent or transparent; frosted surface abrasion; scattered black carbonaceous material; no hydrocarbon indicators. Tyonek G7 3.2.1.1 11,454’ to 11632' MD (-9372' to -9478' TVDSS) Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 98 3 36 25 7 17 Gas Peaks MD Depth TVD Depth TG C1 C2 C3 C4I C4N C5I C5N No notable gas peaks Tuffaceous Sandstone (11460' - 11560') = dark yellow-brown to grayish brown to medium gray with some pale olive hues; unconsolidated to easily friable with trace firmly friable; upper to lower medium to upper fine and lower coarse grained; moderately to poorly sorted; rounded to sub-rounded to sub-angular to occasionally angular; moderate visual porosity and permeability; dominated by translucent to clear quartz; polished to frosted surface abrasion; grades to and interbedded with tuffaceous siltstone; scattered black carbonaceous material; no hydrocarbon indicators. Tuffaceous Sandstone / siltstone (11560' - 11660') = light to medium light gray, with light olive to olive gray; lower fine to upper medium grained with coarse grains scattered throughout; spherical to sub- discoidal; rounded to sub-rounded to sub-angular, with some angular quartz grains appear to be bit shattered; poor to moderate sorting; friable to unconsolidated; tuffaceous / silty matrix; grain supported; individual grains are translucent or transparent; polished to frosted surface abrasion; scattered black carbonaceous material; no hydrocarbon indicators. Hilcorp Alaska, LLC K-06RD2 18 3.2.2 Hemlock Formation The Hemlock formation is comprised mainly of conglomeratic and tuffaceous sandstone with occasional tuffaceous siltstones and trace coal beds. The tuffaceous sandstones are often medium gray to medium dark gray with a slight light olive gray to olive gray. Grain size is typically lower fine to upper fine with occasional coarse grading to lower medium to upper medium and occasional coarse. Often spherical to sub discoidal with sub rounded to rounded, rare sub angular grains. Typically well to moderately well sorted and often friable or unconsolidated. Overall the clasts have a tuffaceous matrix and are grain supported. They appear to be texturally sub mature to immature and dominated by translucent or transparent quartz with pitted or etched facies. Mafic and green lithics are also semi common. The conglomeratic sands observed are typically medium dark gray to medium gray with pale olive to moderate brown to black secondary hues. They are unconsolidated to easily friable with lower medium to upper fine grains and 3-5mm bit broken quartz grains being semi common. Often display poor to moderate sorting, sub angular to sub rounded to angular with sub spherical to trace sub discoidal sphericity. The tuffaceous siltstones can often grade to a sandy siltstone and are typically poorly indurated. Overall tenacity ranges from crumbly to brittle with an irregular to earthy fracture. Cuttings are commonly “bit stacked to slightly tabular with a dull to earthy luster and a silty to gritty texture. Carbonaceous banding is common but not abundant Hemlock H1X_FW 3.2.2.1 11632’ to 11711' MD (-9478' to -9511' TVDSS) Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 107 0.5 25 18 3 6 Gas Peaks MD Depth TVD Depth TG C1 C2 C3 C4I C4N C5I C5N No notable gas peaks Sand / Tuffaceous Siltstone (11670' - 11710') = medium dark gray to medium gray to grayish black; unconsolidated to easily friable; upper medium to upper fine with lower coarse to upper fine; poor sorting; sub rounded to sub angular; sub spherical; coals common throughout; no hydrocarbon indicators. Hilcorp Alaska, LLC K-06RD2 19 Hemlock HTK-FW / HK1T 3.2.2.1 11711’ to 11962' MD (-9511' to -9683' TVDSS) Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 146 1 25 18 2 6 Gas Peaks MD Depth TVD Depth TG C1 C2 C3 C4I C4N C5I C5N 11858 9576 10 2135 107 40 Tuffaceous Sandstone / Siltstone (11660' - 11810') = light to medium light gray, with light olive to olive gray; lower fine to upper medium grained with coarse grains scattered throughout; spherical to sub- discoidal; rounded to sub-rounded to sub-angular; poorly to moderately sorted; firm friable to friable to unconsolidated; tuffaceous/silty matrix; grain supported; individual grains are translucent or transparent; polished to frosted surface abrasion; black carbonaceous banding observed in larger cuttings; no hydrocarbon indicators. Sandstone / Tuffaceous Sandstone (11810' - 11900') = dark reddish brown to grayish brown to dusky yellowish brown; unconsolidated to easily friable; upper medium to lower coarse with common lower very coarse to upper very fine; trace 2-3mm grains; poor sorting; sub rounded to rounded to sub angular; sub spherical; trace bit broken and pitted quartz grains; grain supported; minor tuffaceous siltstone and carbonaceous shale; trace tuff clasts; very weak dull yellow sample fluorescence possibly from oil based mud contamination; no cut or odor. Hemlock HK2T 3.2.2.2 11962’ to 13322' MD (-9683' to -9963' TVDSS) Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 195 1 30 24 3 10 Gas Peaks MD Depth TVD Depth TG C1 C2 C3 C4I C4N C5I C5N 12103 9695 17 2459 174 126 11 29 12633 9751 19 2474 226 131 10 28 13039 9805 24 3350 704 218 68 Tuffaceous Sandstone / Siltstone (11900'-12020') = dusky yellowish brown to very dusky red to brownish black; unconsolidated to easily friable; upper fine to lower medium; lower coarse to upper very fine common but not abundant; moderate sorting; sub rounded to rounded to sub angular; moderate visual porosity and permeability; sub spherical; predominantly clear to translucent quartz; siltstone is typically very dark grayish black; poor induration; crumbly; irregular to blocky fracture; dull to earthy luster; carbonaceous banding; carbonaceous sediment common throughout samples; very weak dull gold fluorescence from possible oil based mud contamination; no visible cut. Tuffaceous Sandstone / Sand = (12020'- 12100') = very dusky red to dusky yellowish brown to dark grayish brown; unconsolidated; upper fine to lower medium; lower coarse to upper very fine common but not abundant; trace ~2mm grains; moderate sorting; sub rounded to sub angular; moderate visual porosity and permeability; very dull gold sample fluorescence; no visible cut. Hilcorp Alaska, LLC K-06RD2 20 Tuffaceous Sandstone / Sand = (12100'- 12160') = very dusky red to dusky yellow brown to dark grayish brown; ranges from unconsolidated to firm friable; upper fine to lower medium grained, with lower coarse to upper very fine common; trace ~2mm grains; moderate to poorly sorted; sub-rounded to sub- angular; polished to frosted to grinding surface abrasion; moderate visual porosity and permeability; very dull gold sample fluorescence; no visible cut above oil based mud. Sand / Tuffaceous Sandstone = (12160'- 12240') = dusky brown to very dusky red to dusky yellowish brown; predominantly unconsolidated to easily friable; upper fine to lower medium; upper medium to upper very fine common but not abundant; moderate to well sorted; trace 2-3mm grains; sub rounded to rounded to sub angular; moderate to good visual porosity and permeability; clear to translucent quartz; trace bit broken grains; moderate carbonaceous shale and tuffaceous siltstone; very dull gold sample fluorescence; no visible cut. Sand / Tuffaceous Sandstone = (12240'- 12390') = dusky yellowish brown to dusky brown to very dusky red; predominantly unconsolidated to easily friable; lower medium to upper medium to upper fine to lower coarse; moderate to well sorted; trace 2mm grains; sub rounded to rounded to sub angular; moderate to good visual porosity and permeability; moderate carbonaceous shale and trace tuffaceous siltstone; no visible fluorescence or cut. Sand / Carbonaceous Shale = (12390'- 12510') = dusky yellowish brown to dusky brown to black with grayish hues; unconsolidated to easily friable; upper medium to lower fine to lower coarse; moderate to well sorted; minor 2-4mm bit broken quartz grains; overall sub rounded to rounded to sub angular; moderate to good visual porosity and permeability; carbonaceous shale is moderately indurated; tough to rarely brittle; hackly to conchoidal to blocky fracture; planar to tabular cuttings habit; resinous luster; matte texture; no sample fluorescence or cut. Sand / Tuffaceous Sandstone = (12510'- 12620') = dusky yellowish brown to dusky brown to very dusky red, trace moderate pink to light red; ranges from unconsolidated to easily friable, some firm friable; lower to upper medium to upper fine to lower coarse; moderate to well sorted; trace 2mm grains; sub- rounded to rounded to sub-angular; polished to frosted surface abrasion; larger pieces of quartz appear to be bit shattered; occasionally vitreous; moderate to good visual porosity and permeability; trace carbonaceous shale and tuffaceous siltstone; no visible fluorescence or cut above oil base mud. Sand / Tuffaceous Sandstone = (12620'- 12720') = dusky yellowish brown to dusky brown to very dusky red, trace moderate pink to light red; ranges from unconsolidated to easily friable to firm friable to moderately hard; lower medium to upper medium to upper fine grained, some lower coarse grains; moderate to well sorted; trace 2mm grains; sub- rounded to rounded to sub-angular; polished to frosted surface abrasion; larger pieces of quartz appear to be bit shattered; occasionally vitreous; moderate to good visual porosity and permeability; trace carbonaceous shale and tuffaceous siltstone; patchy weak to moderate dull gold fluorescence on ~20% of the sample; instantaneous dull milky white cut; no odor; no visible cut. Sand / Tuffaceous Sandstone (12720'- 12790') = moderate brown to dusky yellowish brown to very dusky red; unconsolidated to friable; upper medium to upper fine; lower coarse to lower fine common; moderate sorting; sub angular to sub rounded; sub spherical to trace sub discoidal; 2-4mm bit broken quartz grains common but not abundant; clasts are grain supported; minor carbonaceous shale and 1 10 100 1000 10000 1 2 3 4ppm Pixler Plot DRY GAS GAS CONDENSATE OIL NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hilcorp Alaska, LLC K-06RD2 21 tuffaceous siltstone; no hydrocarbon indicators present. Sand / Tuffaceous Sandstone (12790'- 12880') = dusky yellowish brown to moderate brown to very dusky red; unconsolidated to friable; upper fine to upper medium; lower fine to lower coarse common; moderate to well sorted; sub angular to sub rounded to angular; sub spherical to trace sub discoidal; 2mm bit broken quartz grains common but not abundant; grain supported clasts; minor carbonaceous shale and tuffaceous siltstone; trace ash clasts; no hydrocarbon indicators present. Sand / Tuffaceous Sandstone = (12880'- 12990') = dusky yellowish brown to dusky brown to very dusky red, trace moderate pink to light red; ranges from unconsolidated to easily friable to firm friable to moderately hard; lower medium to upper medium to upper fine grained, some lower coarse grains; moderate to well sorted; trace 2mm grains; sub- rounded to rounded to sub-angular; polished to frosted surface abrasion; larger pieces of quartz appear to be bit shattered; often vitreous; moderate to good visual porosity and permeability; trace carbonaceous shale and/or tuffaceous siltstone; patchy weak to moderate dull gold fluorescence on ~30% of the sample; instantaneous dull milky white cut; no odor; no visible cut; some oil staining. Sand / Tuffaceous Sandstone = (12990'- 13090') = dusky yellow-brown to dusky brown to very dusky red, trace moderate pink to light red; ranges from unconsolidated to easily friable to firm friable to moderately hard; lower medium to upper medium to upper fine grained, some lower coarse grains; moderately to well sorted; trace 2mm grains; rounded to sub rounded to sub-angular to very angular; polished to frosted surface abrasion; larger pieces of quartz appear to be bit shattered; often vitreous; moderate to good visual porosity and permeability; trace to common tuffaceous siltstone; trace carbonaceous shale; patchy weak to moderate dull gold fluorescence on ~35% of the sample; instantaneous dull milky white cut; no odor; no visible cut; some oil staining observed. Sand / Tuffaceous Sandstone (13090'- 13170') = moderate brown to dusky yellowish brown to very dusky red; unconsolidated to easily friable; upper medium to upper fine; lower coarse to lower fine common; moderate to well sorted; sub rounded to sub angular to angular; sub spherical to trace sub discoidal; 2mm bit broken grains common; grain supported clasts; minor carbonaceous shale and tuffaceous siltstone; no hydrocarbon indicators present. Sand / Tuffaceous Sandstone (13170'- 13260') = moderate brown to very dusky red to dusky yellowish brown; unconsolidated to friable; lower medium to upper fine; upper medium to lower fine common; moderate to well sorted; sub angular to sub rounded; sub spherical; 2-3mm bit broken grains common; grain supported clasts; minor carbonaceous shale and tuffaceous siltstone; no hydrocarbon indicators present. Sand / Tuffaceous Sandstone (13260'- 13320') = light brownish gray to moderate brown to very dusky red to dusky yellowish brown; predominantly unconsolidated to friable; lower medium to upper fine grained; upper medium to lower fine common; moderate to well sorted; sub-angular to sub-rounded; sub- spherical; 2-3mm bit broken grains common; grain supported clasts; minor carbonaceous shale and tuffaceous siltstone; no hydrocarbon indicators present. 1 10 100 1000 10000 1 2 3 4ppm Pixler Plot DRY GAS GAS CONDENSATE OIL NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hilcorp Alaska, LLC K-06RD2 22 3.3 Geology Sampling Program Set Type and Purpose Interval Frequency Distribution A Washed and Dried Reference 8,062’ – 11,490’ 11,490’ – 13,233’ 30’ 10’ Debra Oudean Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 B Washed and Dried Reference 8,062’ – 11,490’ 11,490’ – 13,233’ 30’ 10’ Debra Oudean Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 Hilcorp Alaska, LLC K-06RD2 23 4 DRILLING DATA 4.1 Surveys Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 122.0 0.05 106.65 122.00 -0.02 0.05 0.05 0.04 222.0 0.08 117.72 222.00 -0.06 0.15 0.13 0.03 322.0 0.57 140.50 322.00 -0.48 0.53 0.39 0.50 422.0 2.32 157.40 421.96 -2.73 1.63 0.85 1.78 522.0 1.32 107.17 521.92 -4.94 3.51 2.08 1.79 622.0 3.25 79.75 621.83 -4.77 7.40 5.88 2.17 722.0 6.97 51.22 721.43 -0.47 14.92 14.27 4.40 822.0 8.62 50.53 820.51 8.10 25.43 26.67 1.65 922.0 10.18 52.20 919.16 18.28 38.20 41.67 1.58 1,022.0 13.43 56.03 1,017.03 30.19 54.82 60.84 3.34 1,122.0 16.27 56.43 1,113.68 44.42 76.13 85.14 2.84 1,222.0 18.07 53.50 1,209.23 61.40 100.27 112.90 2.00 1,322.0 20.00 53.45 1,303.75 80.81 126.48 143.29 1.93 1,422.0 22.20 54.22 1,397.04 102.04 155.55 176.93 2.22 1,522.0 23.92 55.17 1,489.05 124.67 187.52 213.73 1.76 1,622.0 25.23 56.20 1,579.99 148.10 221.87 253.04 1.38 1,722.0 25.13 56.62 1,670.49 171.64 257.31 293.43 0.20 1,822.0 24.70 56.87 1,761.18 194.74 292.54 333.50 0.44 1,922.0 24.33 57.17 1,852.17 217.33 327.34 373.03 0.39 2,022.0 23.88 57.58 1,943.44 239.35 361.74 412.01 0.48 2,122.0 23.58 57.92 2,034.99 260.83 395.77 450.49 0.33 2,222.0 22.45 64.25 2,127.04 279.75 429.93 488.42 2.72 2,322.0 19.88 78.98 2,220.36 291.30 463.84 524.19 5.89 2,422.0 21.48 84.37 2,313.92 296.35 498.76 559.20 2.49 2,522.0 24.57 84.47 2,405.94 300.15 537.68 597.75 3.09 2,622.0 27.87 84.28 2,495.64 304.48 581.64 641.30 3.30 2,722.0 31.45 84.18 2,582.52 309.46 630.87 690.10 3.58 2,822.0 34.68 84.33 2,666.32 314.92 685.15 743.90 3.23 2,922.0 38.32 83.90 2,746.69 321.03 744.31 802.58 3.65 3,022.0 41.68 83.58 2,823.28 328.04 808.19 866.05 3.37 Hilcorp Alaska, LLC K-06RD2 24 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 3,122.0 42.78 83.63 2,897.33 335.53 874.98 932.46 1.10 3,222.0 42.17 83.75 2,971.08 342.95 942.10 999.16 0.62 3,322.0 41.77 83.80 3,045.43 350.20 1,008.58 1,065.20 0.40 3,422.0 41.28 83.83 3,120.30 357.34 1,074.49 1,130.67 0.49 3,522.0 40.77 85.22 3,195.74 363.61 1,139.82 1,195.34 1.05 3,622.0 38.73 92.57 3,272.67 364.93 1,203.65 1,257.27 5.12 3,722.0 39.55 99.13 3,350.26 358.47 1,266.37 1,316.07 4.22 3,822.0 42.63 100.87 3,425.62 347.03 1,331.08 1,375.48 3.29 3,922.0 43.83 101.53 3,498.48 333.72 1,398.26 1,436.79 1.28 4,022.0 44.48 101.75 3,570.23 319.67 1,466.49 1,498.90 0.67 4,122.0 44.82 102.60 3,641.37 304.84 1,535.18 1,561.27 0.69 4,222.0 45.53 103.12 3,711.86 289.06 1,604.33 1,623.82 0.80 4,322.0 46.10 104.10 3,781.56 272.18 1,674.02 1,686.60 0.90 4,422.0 46.93 104.83 3,850.38 254.05 1,744.28 1,749.60 0.98 4,522.0 47.17 104.25 3,918.51 235.68 1,815.13 1,813.11 0.49 4,622.0 43.95 97.23 3,988.56 222.27 1,885.15 1,877.14 5.95 4,722.0 42.03 89.68 4,061.76 218.09 1,953.11 1,941.59 5.49 4,822.0 44.53 89.32 4,134.55 218.69 2,021.66 2,007.88 2.51 4,922.0 46.23 90.43 4,204.79 218.84 2,092.83 2,076.58 1.87 5,022.0 45.87 90.68 4,274.20 218.14 2,164.82 2,145.84 0.40 5,122.0 46.35 91.60 4,343.52 216.70 2,236.87 2,214.97 0.82 5,222.0 47.47 92.48 4,411.84 214.10 2,309.85 2,284.69 1.29 5,322.0 49.03 92.97 4,478.42 210.55 2,384.37 2,355.64 1.60 5,422.0 50.50 93.82 4,543.02 206.02 2,460.57 2,427.96 1.61 5,522.0 51.78 94.85 4,605.76 200.13 2,538.21 2,501.31 1.51 5,622.0 52.68 95.58 4,667.01 192.94 2,616.93 2,575.36 1.07 5,722.0 52.63 95.88 4,727.67 185.01 2,696.03 2,649.57 0.24 5,822.0 51.27 96.63 4,789.30 176.43 2,774.31 2,722.83 1.48 5,922.0 50.83 97.00 4,852.17 167.20 2,851.53 2,794.89 0.53 6,022.0 50.55 97.12 4,915.52 157.69 2,928.31 2,866.46 0.29 6,122.0 49.37 97.73 4,979.85 147.80 3,004.23 2,937.09 1.27 6,222.0 49.02 98.18 5,045.20 137.33 3,079.20 3,006.65 0.49 6,322.0 48.73 98.27 5,110.97 126.55 3,153.75 3,075.74 0.30 6,422.0 47.38 98.52 5,177.81 115.70 3,227.33 3,143.86 1.36 6,522.0 47.22 99.27 5,245.63 104.33 3,299.94 3,210.91 0.57 6,622.0 47.15 99.67 5,313.59 92.26 3,372.29 3,277.53 0.30 Hilcorp Alaska, LLC K-06RD2 25 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 6,722.0 46.55 100.38 5,381.98 79.57 3,444.13 3,343.49 0.79 6,822.0 47.40 100.40 5,450.21 66.38 3,516.04 3,409.39 0.85 6,922.0 46.65 100.93 5,518.38 52.84 3,587.94 3,475.19 0.84 7,022.0 46.83 101.53 5,586.91 38.66 3,659.37 3,540.36 0.47 7,122.0 47.05 101.83 5,655.19 23.87 3,730.92 3,605.49 0.31 7,222.0 47.12 102.18 5,723.28 8.64 3,802.55 3,670.58 0.27 7,322.0 46.75 102.62 5,791.56 -7.05 3,873.91 3,735.28 0.49 7,422.0 46.90 102.83 5,859.98 -23.12 3,945.04 3,799.68 0.21 7,522.0 46.48 103.22 5,928.58 -39.51 4,015.94 3,863.75 0.51 7,622.0 44.43 103.58 5,998.72 -56.03 4,085.26 3,926.28 2.07 7,722.0 43.70 103.80 6,070.58 -72.48 4,152.83 3,987.13 0.75 7,822.0 42.85 103.40 6,143.38 -88.61 4,219.46 4,047.16 0.89 7,922.0 41.32 102.92 6,217.60 -103.87 4,284.72 4,106.10 1.56 8,022.0 40.75 103.25 6,293.03 -118.73 4,348.67 4,163.87 0.61 8,062.72 40.52 103.76 6,323.93 -124.92 4,374.45 4,187.11 0.99 8,128.93 39.82 104.23 6,374.52 -135.25 4,415.89 4,224.37 1.15 8,193.35 37.76 104.75 6,424.73 -145.34 4,454.97 4,259.41 3.23 8,255.75 34.17 105.32 6,475.23 -154.84 4,490.36 4,291.05 5.79 8,315.54 30.90 105.95 6,525.63 -163.50 4,521.32 4,318.64 5.50 8,379.41 27.36 106.74 6,581.41 -172.23 4,551.15 4,345.11 5.57 8,441.21 26.00 106.32 6,636.63 -180.13 4,577.75 4,368.69 2.22 8,504.27 24.40 110.45 6,693.69 -188.57 4,603.22 4,391.04 3.77 8,566.37 23.78 112.05 6,750.38 -197.75 4,626.85 4,411.42 1.45 8,629.39 23.43 114.00 6,808.13 -207.62 4,650.07 4,431.22 1.36 8,689.99 21.96 117.25 6,864.04 -217.71 4,671.15 4,448.90 3.19 8,751.61 19.74 121.64 6,921.62 -228.44 4,690.26 4,464.51 4.40 8,813.55 16.15 126.52 6,980.54 -239.06 4,706.09 4,476.99 6.28 8,877.77 12.85 123.64 7,042.71 -248.33 4,719.22 4,487.21 5.26 8,939.47 11.56 120.29 7,103.01 -255.25 4,730.27 4,496.05 2.39 8,999.84 11.48 126.04 7,162.17 -261.84 4,740.35 4,504.04 1.91 9,062.28 9.40 129.35 7,223.57 -268.73 4,749.32 4,510.87 3.47 9,126.13 7.09 150.18 7,286.77 -275.46 4,755.31 4,514.88 5.86 9,154.96 6.89 162.17 7,315.39 -278.65 4,756.73 4,515.41 5.10 9,215.62 6.99 188.25 7,375.62 -285.77 4,757.31 4,514.10 5.15 9,278.77 7.09 207.43 7,438.30 -293.03 4,754.97 4,509.92 3.71 9,340.79 8.49 222.79 7,499.76 -299.79 4,750.09 4,503.44 4.02 Hilcorp Alaska, LLC K-06RD2 26 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 9,401.98 9.50 237.92 7,560.20 -305.78 4,742.74 4,494.77 4.19 9,462.87 9.90 250.77 7,620.23 -310.18 4,733.54 4,484.73 3.61 9,525.89 12.04 260.08 7,682.10 -313.10 4,721.95 4,472.78 4.40 9,588.21 13.82 263.47 7,742.84 -315.06 4,708.15 4,458.95 3.10 9,650.25 15.20 265.08 7,802.90 -316.60 4,692.68 4,443.63 2.32 9,711.56 16.24 265.61 7,861.91 -317.95 4,676.13 4,427.30 1.71 9,773.12 16.60 265.09 7,920.96 -319.36 4,658.78 4,410.20 0.63 9,836.48 16.43 268.03 7,981.71 -320.44 4,640.81 4,392.58 1.35 9,898.28 16.50 270.21 8,040.98 -320.71 4,623.31 4,375.62 1.01 9,960.04 16.85 269.64 8,100.14 -320.73 4,605.59 4,358.52 0.63 10,021.98 16.58 269.10 8,159.46 -320.93 4,587.77 4,341.28 0.50 10,082.52 15.75 266.82 8,217.61 -321.52 4,570.93 4,324.88 1.73 10,144.86 14.35 269.13 8,277.81 -322.11 4,554.76 4,309.13 2.44 10,207.12 12.48 274.57 8,338.37 -321.69 4,540.34 4,295.33 3.62 10,269.83 10.93 278.30 8,399.78 -320.29 4,527.70 4,283.50 2.75 10,331.26 10.17 286.11 8,460.17 -317.95 4,516.73 4,273.53 2.63 10,392.76 10.37 295.83 8,520.69 -314.03 4,506.53 4,264.73 2.83 10,455.62 10.18 305.83 8,582.55 -308.31 4,496.93 4,256.97 2.85 10,516.27 10.38 315.85 8,642.23 -301.25 4,488.78 4,250.97 2.96 10,577.84 10.26 326.50 8,702.81 -292.70 4,481.89 4,246.57 3.10 10,638.50 11.87 335.08 8,762.34 -282.54 4,476.28 4,243.84 3.79 10,701.72 14.14 339.76 8,823.94 -269.40 4,470.87 4,242.08 3.96 10,763.01 15.99 344.89 8,883.12 -254.22 4,466.08 4,241.45 3.72 10,824.24 17.38 350.10 8,941.78 -237.07 4,462.31 4,242.33 3.33 10,887.07 17.92 351.18 9,001.65 -218.27 4,459.22 4,244.30 1.01 10,949.66 19.12 351.14 9,061.00 -198.63 4,456.16 4,246.53 1.92 11,028.85 21.88 354.78 9,135.17 -171.11 4,452.82 4,250.55 3.84 11,085.79 24.90 355.36 9,187.42 -148.60 4,450.89 4,254.61 5.32 11,148.85 26.68 355.95 9,244.20 -121.24 4,448.81 4,259.82 2.85 11,209.84 29.59 358.13 9,297.98 -92.52 4,447.35 4,265.97 5.06 11,272.93 32.78 357.27 9,351.95 -59.89 4,446.03 4,273.29 5.12 11,331.63 36.52 357.38 9,400.23 -26.55 4,444.47 4,280.56 6.36 11,395.40 39.33 358.89 9,450.52 12.61 4,443.21 4,289.66 4.64 11,456.01 45.86 358.16 9,495.12 53.60 4,442.13 4,299.42 10.81 11,517.61 50.38 0.56 9,536.23 99.44 4,441.65 4,311.03 7.89 11,581.72 56.75 4.74 9,574.30 150.92 4,444.12 4,326.97 11.22 Hilcorp Alaska, LLC K-06RD2 27 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 11,642.51 62.95 8.34 9,604.82 203.10 4,450.15 4,346.53 11.42 11,706.88 67.25 11.04 9,631.92 260.63 4,460.00 4,371.19 7.67 11,768.20 72.65 12.11 9,652.94 317.03 4,471.57 4,397.20 8.96 11,829.40 78.74 15.19 9,668.06 374.62 4,485.58 4,425.88 11.08 11,860.62 80.95 18.10 9,673.57 404.06 4,494.38 4,442.13 11.59 11,921.39 86.29 22.67 9,680.06 460.75 4,515.17 4,477.11 11.50 11,983.33 85.91 24.59 9,684.27 517.37 4,539.94 4,515.92 3.15 12,047.58 84.37 28.37 9,689.71 574.65 4,568.48 4,558.53 6.34 12,109.52 83.90 31.28 9,696.05 628.10 4,599.12 4,602.17 4.72 12,172.06 84.24 32.56 9,702.51 680.90 4,632.01 4,647.80 2.12 12,234.09 83.80 34.62 9,708.98 732.29 4,666.14 4,694.27 3.37 12,297.05 85.05 37.32 9,715.10 782.99 4,702.94 4,743.12 4.70 12,360.39 85.96 37.36 9,720.07 833.20 4,741.24 4,793.29 1.43 12,427.96 86.09 38.74 9,724.75 886.28 4,782.79 4,847.35 2.04 12,490.04 82.36 39.33 9,730.99 934.25 4,821.67 4,897.50 6.08 12,553.01 81.22 43.06 9,739.99 981.14 4,862.71 4,949.44 6.15 12,616.47 82.31 47.17 9,749.08 1,025.45 4,907.20 5,004.03 6.63 12,676.08 82.56 49.76 9,756.94 1,064.63 4,951.43 5,057.01 4.33 12,739.16 81.37 53.44 9,765.76 1,103.42 5,000.37 5,114.44 6.08 12,802.38 82.18 56.51 9,774.81 1,139.32 5,051.60 5,173.32 4.98 12,864.83 82.61 56.73 9,783.08 1,173.38 5,103.29 5,232.15 0.77 12,927.85 82.80 56.25 9,791.08 1,207.89 5,155.41 5,291.52 0.82 12,990.43 82.49 56.34 9,799.09 1,242.33 5,207.04 5,350.40 0.53 13,050.98 82.43 56.09 9,807.04 1,275.71 5,256.93 5,407.32 0.43 13,112.98 83.05 56.19 9,814.88 1,309.98 5,308.00 5,465.61 1.02 13,176.45 83.18 56.39 9,822.49 1,344.95 5,360.42 5,525.39 0.38 13,239.13 83.14 55.49 9,829.96 1,379.80 5,411.98 5,584.30 1.44 13,283.22 81.73 55.21 9,835.76 1,404.65 5,447.93 5,625.53 3.24 13,322.00 81.73 55.21 9,841.34 1,426.55 5,479.44 5,661.70 0.01 Hilcorp Alaska, LLC K-06RD2 28 4.2 Bit Record BIT NO. SIZE TYPE S/N JETS/ TFA IN OUT Feet Drilled HRS AVE ROP (Ft/HR) CONDITION 1 8.5” Window mill 12360957 — 8,062’ 8,103’ 41’ 6.02 6.8 — 2 8.5” HDBS MMD75DC PDC 12321785 7x11 0.6496 8,103’ 8,106’ 3’ 0.05 60 0-6-BT-T-X-I-LM-HP 1rr 8.5” Mill Tooth PP3109 3x32 2.3562 8,106’ 8,117’ 11’ 0.75 15.8 2-2-NO-A-1-I-RR 3rr1 8.5” HDBS MM75D PDC 12670052 5x12 0.5522 8,117’ 9,169’ 1,052’ 25.25 41.7 2-3-BT-S-X-I-PN-RIG 4 8.5” ReedHycalog DS813M-G3A PDC E174094 8x12 0.8836 9,169’ 11,050’ 1,881’ 40.3 46.7 1-2-CT-S-X-I-NO-BHA 5 8.5” HDBS MMD75C PDC 12451966 7x13 0.9073 11,050’ 11,360’ 310’ 11.75 26.3 0-1-CT-G-X-I-NO-BHA 4rr1 8.5” Reed DS813M-G3A PDC E174094 8x12 0.8836 11,360’ 11,900’ 540’ 33.75 16.0 1-4-BT-G-X-1-JD-BHA 6 8.5” NOV/Reed FT716B PDC E230939 5x12, 2x15 0.8974 11,900’ 12,284’ 384’ 14.85 25.9 3-3-WT-A-X-0-DTF-BHA 7 8.5” NOV/Reed DSH1813M-G3A E174093 8x12 0.8836 12,284’ 12,436’ 152’ 17.95 8.5 3-2-WT-A-X-2-PN-PR 8 8.5” Varel T10846 4007887 8x12 0.8836 12,436’ 13,322 839 38.75 21.7 2-3-WT-A-X-1-CT-TD Hilcorp Alaska, LLC K-06RD2 29 4.3 Mud Record Contractor: Halliburton Baroid Date Depth MD TVD MW (ppg) VIS (s/qt) PV YP Gels FL (cc) FC Sols (%) O/W Ratio Sd (%) ASG AgNO3 CaCl2 (ppbl) Lime (ppb) Enviromul 12/18/2016 8,062 6,324 9.10 232 29 27 16/34/37 — 0/2 8.6 83.3/16.7 0.05 3.087 1.1 8.21 7.25 12/19/2016 8,062 6,324 8.90 87 23 18 15/33/37 — 0/2 7.4 84.6/15.4 0.05 3.079 1.3 11.12 7.64 12/20/2016 8,107 6,327 9.05 109 32 18 17/29/33 — 0/2 7.0 86.9/13.1 0.05 3.535 1.3 11.12 6.09 12/21/2016 8,107 6,324 9.05 145 28 16 16/28/32 — 0/2 7.5 86.8/13.2 0.05 3.341 1.8 13.06 5.05 12/22/2016 8,117 6,324 9.15 168 43 24 16/28/32 — 0/2 6.8 84.7/15.3 0.05 3.691 1.5 11.12 4.14 12/23/2016 8,117 6,324 9.10 158 29 17 18/34/36 — 0/2 6.7 84.2/15.8 0.05 3.580 1.6 13.06 6.47 12/24/2016 8,743 6,958 9.00 77 25 14 14/27/33 — 0/2 7.4 84.6/15.4 0.05 3.227 1.3 12.09 5.44 12/25/2016 9,040 7,201 9.00 74 20 14 14/27/33 — 0/2 8.4 85.6/14.4 0.05 2.983 1.5 10.15 4.40 12/26/2015 9,169 7,329 9.10 81 26 13 14/24/30 — 0/2 7.9 85.6/14.4 0.05 3.253 1.6 12.09 6.47 12/27/2016 9,169 7,329 9.15 100 20 11 12/21/28 — 0/2 7.9 85.6/14.4 0.05 3.329 1.6 12.09 6.60 12/28/2016 9,196 7,329 9.10 100 28 13 12/21/28 — 0/2 8.1 87.8/12.2 0.05 3.280 1.6 12.09 4.92 12/29/2016 9,196 7,329 9.10 107 28 14 10/22/33 — 0/2 7.9 87.9/12.1 0.05 3.354 1.6 12.57 5.44 12/30/2016 9,196 7,329 9.10 104 25 13 10/22/32 — 0/2 7.8 87.9/12.1 0.05 3.351 1.6 13.06 5.18 12/31/2016 9,196 7,329 9.10 119 24 13 10/21/30 — 0/2 7.9 87.9/12.1 0.05 3.357 1.5 12.09 6.09 01/01/2017 9,196 7,329 9.10 116 21 15 14/24/31 — 0/2 8.1 87.8/12.2 0.05 3.286 1.5 11.12 4.92 01/02/2017 9,268 7,329 9.10 91 30 18 16/27/33 — 0/2 7.9 87.9/12.1 0.05 3.364 1.4 11.12 4.92 01/03/2017 10,156 8,390 9.10 78 26 12 16/27/32 — 0/2 8.7 87.8/12.2 0.05 3.159 1.2 9.18 12.56 01/04/2017 10,943 8,930 9.10 74 24 15 10/21/29 — 0/2 7.7 87.5/12.5 0.05 3.260 1.3 10.15 7.64 01/05/2017 11,050 9,156 9.00 75 19 13 10/23/29 — 0/2 8.6 87.2/12.8 0.05 3.022 1.1 8.21 8.68 01/06/2017 11,050 9,156 9.00 93 19 13 11/24/29 — 0/2 8.6 87.2/12.8 0.05 3.022 1.1 8.21 8.68 01/07/2017 11,222 9,309 9.00 74 25 15 11/31/33 — 0/2 8.2 88.4/11.6 0.05 3.178 1.0 7.24 7.77 01/08/2017 11,360 9,423 9.00 72 24 15 13/31/33 — 0/2 8.2 88.4/11.6 0.05 3.178 1.0 7.24 7.64 01/09/2017 11,360 9,423 9.00 81 24 15 15/32/37 — 0/2 7.7 87.9/12.1 0.05 3.319 1.0 7.24 6.60 01/10/2017 11,470 9,501 9.00 79 24 15 13/26/33 — 0/2 8.2 87.8/12.2 0.05 3.155 1.0 9.18 6.22 01/11/2017 11,569 9,570 9.00 67 26 14 13/33/37 — 0/2 9.3 89.4/10.6 0.05 3.175 1.1 10.15 7.64 01/12/2017 11,695 9,627 9.10 72 30 20 15/33/37 — 0/2 7.8 89.0/11.0 0.05 3.472 1.0 9.18 7.12 01/13/2017 11,849 9,671 9.05 68 24 14 14/31/37 — 0/2 8.3 88.4/11.6 0.05 3.472 1.0 9.18 10.23 Abbreviations: MW = Mud Weight VIS = Funnel Viscosity PV = Plastic Viscosity YP = Yield Point Gels = Gel Strength FL = Water or Filtrate Loss FC = Filter Cake O/W = Oil to Water ratio Sols = Solids Sd = Sand content MBT = Methylene Blue Alk, Pm = Alkalinity, Mud pH = Acidity Cl = Chlorides Ca = Hardness Calcium nr = Not Recorded Hilcorp Alaska, LLC K-06RD2 30 Contractor: Halliburton Baroid Date Depth MD TVD MW (ppg) VIS (s/qt) PV YP Gels FL (cc) FC Sols (%) O/W Ratio Sd (%) ASG AgNO3 CaCl2 (ppbl) Lime (ppb) Enviromul 01/14/2017 11,900 9,678 9.05 67 24 14 14/31/37 — 0/2 8.3 88.4/11.6 0.05 3.241 1.0 7.72 10.10 01/15/2017 11,900 9,678 9.05 107 24 14 14/31/37 — 0/2 8.2 88.4/11.6 0.05 3.241 1.0 8.21 10.10 01/16/2017 12,034 9,688 9.10 71 23 15 13/30/37 — 0/2 9.3 88.8/11.2 0.05 3.053 1.0 8.21 6.99 01/17/2017 12,254 9,710 9.10 67 22 13 13/31/39 — 0/2 9.3 88.8/11.2 0.05 3.046 1.3 9.18 5.31 01/18/2017 12,284 9,714 9.10 73 30 15 13/31/39 — 0/2 9.3 88.8/11.2 0.05 3.046 1.5 9.18 5.31 01/19/2017 12,284 9,714 9.10 91 30 15 13/31/39 — 0/2 9.3 88.8/11.2 0.05 3.046 1.5 9.18 5.31 01/20/2017 12,323 9,719 9.00 67 24 15 13/31/39 — 0/2 8.6 87.2/12.8 0.05 3.006 1.5 10.15 5.31 01/21/2017 12,410 9,723 8.95 62 21 13 13/31/39 — 0/2 7.7 87.9/12.1 0.05 3.219 1.5 10.15 5.83 01/22/2017 12,436 9,724 9.00 83 31 13 10/29/37 — 0/2 8.3 89.0/11.0 0.05 3.161 1.4 10.15 5.31 01/23/2017 12,436 9,724 9.00 83 31 13 10/29/37 — 0/2 8.3 89.0/11.0 0.05 3.161 1.4 10.15 6.60 01/24/2017 12,771 9,763 9.05 63 24 13 13/31/37 — 0/2 8.2 88.9/11.1 0.05 3.261 1.4 10.15 5.57 01/25/2017 13,097 9,813 9.05 71 29 14 13/33/37 — 0/2 8.8 88.9/11.1 0.05 3.111 1.2 8.21 5.57 01/26/2017 13,155 9,823 9.05 71 22 13 16/35/38 --- 0/2 8.8 88.9/11.1 0.05 3.127 1.2 6.26 4.14 01/27/2017 13,322 9,841 9.1 84 37 14 12/34/38 --- 0/2 8.8 88.9/11.1 0.05 3.172 1.2 9.18 6.99 01/28/2017 13,322 9,841 9.1 127 27 14 13/33/36 --- 0/2 8.8 88.9/11.1 0.05 3.172 1.2 9.18 6.73 01/29/2017 13,322 9,841 9.1 127 30 13 15/35/39 --- 0/2 7.8 89.0/11.0 0.05 3.486 1.2 8.21 5.18 01/30/2017 13,322 9,841 9.05 75 32 14 15/37/40 --- 0/2 8.3 89.0/11.0 0.05 3.248 1.2 8.21 6.09 01/31/2017 13,322 9,841 9.1 75 31 14 15/38/40 --- 0/2 8.7 88.9/11.1 0.05 3.209 1.2 6.26 5.44 02/01/2017 13,322 9,841 9.1 85 27 14 16/36/40 --- 0/2 8.9 90.0/10.0 0.05 3.212 1.1 7.24 5.44 02/02/2017 13,322 9,841 9.3 170 26 15 19/33/37 --- 0/2 8.9 90.0/10.0 0.05 3.482 1.0 7.24 5.44 02/03/2017 13,322 9,841 9.25 124 25 13 16/31/35 --- 0/2 9.2 90.0/10.0 0.05 3.324 1.0 6.26 5.44 02/04/2017 13,322 9,841 9.25 163 29* 14 15/33/37 --- 0/2 9.0 90.0/10.0 0.05 3.412 0.8 5.29 3.88 02/05/2017 13,322 9,841 9.2 92 28 15 19/35/39 --- 0/2 8.9 90.0/10.0 0.05 3.341 1.2 6.26 5.83 02/06/2017 13,322 9,841 9.15 123 24 13 16/35/39 --- 0/2 8.9 90.0/10.0 0.05 3.274 1.2 6.26 6.47 02/07/2017 13,322 9,841 9.1 73 28 13 15/35/39 --- 0/2 8.9 90.0/10.0 0.05 3.215 1.0 5.29 6.47 02/08/2017 13,322 9,841 9.15 134 29 14 15/35/39 --- 0/2 8.9 90.0/10.0 0.05 3.282 0.9 5.29 6.47 02/09/2017 13,322 9,841 9.25 134 29 14 16/35/39 --- 0/2 8.9 90.0/10.0 0.05 3.416 0.9 5.29 6.22 Abbreviations: MW = Mud Weight VIS = Funnel Viscosity PV = Plastic Viscosity YP = Yield Point Gels = Gel Strength FL = Water or Filtrate Loss FC = Filter Cake O/W = Oil to Water ratio Sols = Solids Sd = Sand content MBT = Methylene Blue Alk, Pm = Alkalinity, Mud pH = Acidity Cl = Chlorides Ca = Hardness Calcium nr = Not Recorded Hilcorp Alaska, LLC K-06RD2 31 4.4 Drilling Progress 8000 9000 10000 11000 12000 13000 Days Vs. Depth Hilcorp Alaska, LLC K-06RD2 32 5 SHOW REPORTS Hydrocarbon Show Report #1 Operator: Well:API Number: Field:Date: Rig:Time: County:Depth Start End State:20 12605'MD 12652'MD Country:20 9747'TVD 9754'TVD Averages Before During After Maximum ROP (fph)38 ft/hr 42 ft/hr 47 ft/hr 107 ft/hr WOB 9 klbs 11 klbs 13 klbs 16 klbs RPM 16 rpm 26 rpm 18 rpm 59 rpm PP 2832 psi 2890 psi 2980 psi 3048 psi Mud Weight 0.0 lbs/gal 0.0 lbs/gal 0.0 lbs/gal 0.0 lbs/gal Chloride Total Gas 10 13 7 19 C1 (ppm)962 1,543 537 2,475 C2 (ppm)90 120 47 254 C3 (ppm)34 65 28 131 C4 (ppm)- 15 0 39 C5 (ppm)- - - - Lithology Odor none Amount 20%Type inst Amount Amount trace Distribution patchy Intensity wk/mod Color Color pale brwn Intensity mod/wk Color mlk wt Color yel/gld Intesity Color none Color Comments Report by: Residual Fluorescence Cuttings Analysis v pale Josh Dubowski NAF Drilling fluid makes analyzing shows difficult no gold Oil Show Rating Cut Free Oil in Mud Kenai Borough Alaska USA noneStain Hilcorp Alaska, LLC 50-733-20088-02-00TBU K06-RD2 McArthur River Field Kuukpik 5 / King Salmon 1/24/2017 10:00 PM Fluorescence Sand / tuffaceous sandstone = dusky yellowish brown to dusky brown to very dusky red, trace moderate pink to light red; ranges from unconsolidated to easily friable to firm friable to moderately hard; lower medium to upper medium to upper fine grained, some lower coarse grains; moderate to well sorted; trace 2mm grains; sub- rounded to rounded to sub-angular; polished to frosted surface abrasion; larger pieces of quartz appear to be bit shattered; occasionally vitreous; moderate to good visual porosity and permeability; trace carbonaceous shale and tuffaceous siltstone Cut Fluorescence Residual Cut 1 10 100 1000 10000 1 2 3 4ppmPixler Plot DRY GAS GAS CONDENSATE OIL NON PRODUCTIVE C1/C2 C1/C4 C1/C5C1/C3 Hydrocarbon Show Report #2 Operator: Well:API Number: Field:Date: Rig:Time: County:Depth Start End State:20 13015'MD 13091'MD Country:20 9802'TVD 9812'TVD Averages Before During After Maximum ROP (fph)22 ft/hr 36 ft/hr 53 ft/hr 182 ft/hr WOB 11 klbs 9 klbs 9 klbs 16 klbs RPM 53 rpm 51 rpm 6 rpm 54 rpm PP 3105 psi 3185 psi 933 psi 3417 psi Mud Weight 9.1 lbs/gal 9.1 lbs/gal 9.1 lbs/gal 9.1 lbs/gal Chloride Total Gas 11 17 2 24 C1 (ppm)1,145 2,140 198 3,415 C2 (ppm)179 453 42 727 C3 (ppm)41 146 11 260 C4 (ppm)- 52 - 178 C5 (ppm)- 0 - 21 Lithology Odor none Amount 35%Type slow / inst Amount Amount trace Distribution patchy Intensity mod/wk Color Color pale brwn Intensity mod/wk Color mlk wt Color yel/gld Intesity Color none Color Comments Report by: Residual Cut Sand / tuffaceous sandstone = dusky yellow-brown to dusky brown to very dusky red, trace moderate pink to light red; ranges from unconsolidated to easily friable to firm friable to moderately hard; lower medium to upper medium to upper fine grained, some lower coarse grains; moderately to well sorted; trace 2mm grains; rounded to sub rounded to sub-angular to very angular; polished to frosted surface abrasion; larger pieces of quartz appear to be bit shattered; often vitreous; moderate to good visual porosity and permeability; trace to common tuffaceous siltstone; trace carbonaceous shale. Hilcorp Alaska, LLC 50-733-20088-02-00TBU K06-RD2 McArthur River Field Kuukpik 5 / King Salmon 1/25/2017 1:00 PM Cut Free Oil in Mud Kenai Borough Alaska USA noneStain Fluorescence Cut Fluorescence Residual Fluorescence Cuttings Analysis v pale Josh Dubowski NAF Drilling fluid makes analyzing shows difficult no gold Oil Show Rating 1 10 100 1000 10000 1 2 3 4ppmPixler Plot DRY GAS GAS CONDENSATE OIL NON PRODUCTIVE C1/C2 C1/C4 C1/C5C1/C3 Hilcorp Alaska, LLC K-06RD2 35 6 DAILY REPORTS Hilcorp Alaska, LLC McArthur River DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Steve Lawrence DATE 12-19-2016 DEPTH 8103' PRESENT OPERATION Trip TIME 24:00 YESTERDAY 8074' 24 HOUR FOOTAGE 29' CASING INFORMATION 9 5/8" TOW @ 8062' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED Mill 1 8.5" Window Mill 12360957 8062' 8103' 41' 10.9 Milled window DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 21.9 @ 8103' 1.0 @ 8076' 8.0 21.9 FT/HR SURFACE TORQUE 7603 @ 8071' 6323 @ 8075' 7230.6 7249.8 FT-LBS WEIGHT ON BIT 11 @ 8076' 1 @ 8074' 7.1 7.6 KLBS ROTARY RPM 115 @ 8078' 95 @ 8100' 109.3 104.0 RPM PUMP PRESSURE 1967 @ 8089' 1571 @ 8077' 1911.2 1914.0 PSI DRILLING FLUIDS REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBT pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 4 @ 8094' 1 @ 8093' 2.3 TRIP GAS None CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 966 @ 8094' 88 @ 8078' 260.4 CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 2/2 PENTANE (C-5) @ @ HYDROCARBON SHOWS None INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Scale deposit, metal shavings, cement, Sand/Sandstone, Tuffaceous Siltstone/Claystone PRESENT LITHOLOGY @ 8103': 20% Sandstone, 40% Tuffaceous siltstone, 40% Tuffaceous Claystone DAILY ACTIVITY SUMMARY Mill from 8074' to 8103', CBU, circulate for FIT, perform FIT, POOH, handle milling BHA, prepare to pick up directional BHA. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2010.00 REPORT BY Paul Webster Hilcorp Alaska, LLC McArthur River field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Steve Lawrence DATE Dec 20, 2016 DEPTH 8107 PRESENT OPERATION Working pipe TIME 24:00 YESTERDAY 8103 24 HOUR FOOTAGE 4 CASING INFORMATION 9 5/8" TOW 8062' 9 5/8" BOW 8079' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 8.5" Window Mill 12360957 8062 8103 41' 10.9 Milled window 1 8.5" MDBS MM75DC PDC 12321785 7x11 8103 4' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 21.9 @ 8103 9.4 @ 8107 17.8 9.42 FT/HR SURFACE TORQUE 7249 @ 8103 7249 @ 8103 1812.4 0.00000 FT-LBS WEIGHT ON BIT 19 @ 8107 5 @ 8104 12.7 19.2 KLBS ROTARY RPM 103 @ 8103 3 @ 8107 29.6 3.62 RPM PUMP PRESSURE 2199 @ 8105 1914 @ 8103 2096.3 0.00000 PSI DRILLING FLUIDS REPORT DEPTH MW 8.9 VIS 87 PV 23 YP 18 FL Gels 15/33/37 CL- FC 0/2 SOL 7.4 SD 0.05 OIL 84.6/15.4 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 8103' TO TD TOOLS DGR/EWR Collar GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 25 @ 8107 1 @ 8103 17.9 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 6553 @ 8107 126 @ 8103 2946.1 CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 12u / 11u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 40% Tuffaceous claystone, 40% Tuffaceous siltstone, 20% sand PRESENT LITHOLOGY 40% Tuffaceous claystone, 40% Tuffaceous siltstone, 20% sand DAILY ACTIVITY SUMMARY Finish laying down milling tools and pick up directional BHA. Upload tools, finish picking up BHA, trip to 2750’ and shallow hole test BHA (Good). Blow down stand pipe and continue running in 5850’ Work air out of pipe and down bad joint, #82. Continue running into to hole to 8022’. Pick up single to 8053, fill pipe, get parameters, kill pump, RIH: observe 2k. adjust top drive set torque to max torque. Change out gabber dies and saver sub. Make connection and orient tool face to 46* RT. RIH and observe 2K drag while sliding past whipstock. Tag up on undergauge hole at 8085’with 4K drag. Wash down to 8103’ and orient tool face 170* RT. Drill to 8106’ and pack off. Work various pipe parameters up to 280K as per company man. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2855.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Steve Lawrence DATE Dec 21, 2016 DEPTH 8106 PRESENT OPERATION Circulating TIME 24:00 YESTERDAY 8106 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" TOW 8062' BOW 8079' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 8.5" MDBS MM75DC PDC 12321785 7x11 8103 8106 3' 0.5 1rr1 8.5" Mill Tooth PP3109 3x32 8106 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 8106 (12/20/16) MW 9.05 VIS 109 PV 32 YP 18 FL Gels 17/29/33 CL- FC 0/2 SOL 7.0 SD 0.05 OIL 86.9/13.1 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 8103' TO TD TOOLS DGR/EWR Collar GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 2.5u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continued working stuck pipe as per company man instructions. Freed stuck pipe at 270K. Worked pipe without pump. Pick up 124K, slack off 85K. Rack back stand and work a single. Tagged up at 8053’, pressured up to 3500psi, blead off and re tagged with pump on. Circulate 500 bbls, work stringup and down to prevent casing damage. Inspect equipment after jarring. Monitor well for 30 minutes (static). Pump dry job and, 20 bbls 2lbs over, striping rubber x2 on from 7991’ to 3200’. Trip out from 3200’ to 2089’. While tripping pipe comes up wet. Install drip pans under rotary table. Continue tripping out of the hole and lay down the BHA. Housekeeping while waiting on boat for string magnet. Pick up BHA #5 and trip in to 8053’ and begin circulating. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2855.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Steve Lawrence DATE Dec 22, 2016 DEPTH 8117 PRESENT OPERATION Tripping in hole TIME 24:00 YESTERDAY 8106 24 HOUR FOOTAGE 11 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1rr1 8.5" Mill Tooth PP3109 3x32 8106 8117 11 0.75 3 8.5" HDBS MM75D PDC 12670052 5x12 8117 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 22.1 @ 8113 4.2 @ 8115 15.8 7.06 FT/HR SURFACE TORQUE 7417 @ 8110 6546 @ 8117 6178.5 6546 FT-LBS WEIGHT ON BIT 19 @ 8107 7 @ 8108 11.9 10.38 KLBS ROTARY RPM 61 @ 8113 3 @ 8107 52.4 57.82 RPM PUMP PRESSURE 2196 @ 8106 2015 @ 8116 2226.9 2039.09 PSI DRILLING FLUIDS REPORT DEPTH 8106 (12/21/16) MW 9.05 VIS 145 PV 28 YP 16 FL Gels 16/28/32 CL- FC 0/2 SOL 7.5 SD 0.05 OIL 86.8/13.2 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 8117 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 25 @ 8107 7 @ 8110 12.4 TRIP GAS 14u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 6553 @ 8107 1705 @ 8110 2834 CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG - PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Swap over to rig power then slip and cut drill line. Service top drive and obtain drilling parameters. Wash and ream down to 8107. Build a dry job then drill to 8117. Circulate bottoms up until hole is clean and back ream through window. Build high viscosity sweep, pump sweep and wash down to 8116. Pull up to 8062’, circulate surface to surface with 0% increase in cuttings. Monitor well for 5 minutes (static). Pump dry job and and trip out of the hole. Lay down mill tooth BHA, clean magnets (90lbs metal) and junk baskets (15lbs metal, 35lbs coal). Monitor well (static). Perform rig service then make up BHA #6. Upload MWD data and begin tripping into the hole. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2855.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Steve Lawrence DATE Dec 23, 2016 DEPTH 8127 PRESENT OPERATION Drilling TIME 24:00 YESTERDAY 8117 24 HOUR FOOTAGE 10 CASING INFORMATION 9 5/8" @ 8062' TOW 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3rr1 8.5" HDBS MM75D PDC 12670052 5x12 8117 10 0.3 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 161.6 @ 8120 1.5 @ 8121 51.2 65.92 FT/HR SURFACE TORQUE 6546 @ 8117 6546 @ 8117 654.6 0.00 FT-LBS WEIGHT ON BIT 10 @ 8117 0 @ 8120 3.2 1.14 KLBS ROTARY RPM 57 @ 8117 1 @ 8123 7.4 1.66 RPM PUMP PRESSURE 3148 @ 8121 2039 @ 8117 3204.3 2882.22 PSI DRILLING FLUIDS REPORT DEPTH 8117 MW 9.1 VIS 158 PV 29 YP 17 FL Gels 18/34/36 CL- FC 0/2 SOL 6.7 SD 0.05 OIL 84.2/15.8 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 8117 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 68 @ 8125 11 @ 8117 57.4 TRIP GAS 24u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 20399 @ 8126 2979 @ 8117 16570.9 CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 12u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 80% Coal 20% Tuffaceous siltstone PRESENT LITHOLOGY 80% Coal 20% Tuffaceous siltstone DAILY ACTIVITY SUMMARY Continue running in the hole to 2900’, fill pipe and test MWD tools. MWD pulser not responding so the decision was made to pull out of hole and replace it. Pump a dry job and pull out of the hole to 736’. Stand back HWDP, jars and collars. Download and troubleshoot pulser. Make upu BHA #7 and shallow test. Trip in hole, filling pipe at 2594’ and 5683’. Continue tripping in to 7987’ and fill pipe. Switch to rig power, reboot Pason and orient tool face @ 46* RT. Warm up mud hydraulics and run in to 8047’. Perform rig service. Trip in to 8082’. Observed 2K drag going through window. Wash down and tag up at 8117’. Slide drilling at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2855.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Steve Lawrence DATE Dec 24, 2016 DEPTH 8826 PRESENT OPERATION Drilling TIME 24:00 YESTERDAY 8127 24 HOUR FOOTAGE 699 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 8504.27 24.40 110.45 6693.69 8566.37 23.78 112.05 6750.38 8629.39 23.43 114.00 6808.13 8689.99 21.96 117.25 6864.04 8751.61 19.74 121.64 6921.62 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3rr1 8.5" HDBS MM75D PDC 12670052 5x12 8117' 709' 14.0 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 416.9 @ 8501 3.1 @ 8157 71.6 95.01 FT/HR SURFACE TORQUE 12586 @ 8440 50 @ 8778 3991.2 0.00 FT-LBS WEIGHT ON BIT 17 @ 8470 0 @ 8248 6.0 5.10 KLBS ROTARY RPM 72 @ 8246 1 @ 8573 26.0 1.71 RPM PUMP PRESSURE 3177 @ 8668 2350 @ 8792 2710.5 2735.58 PSI DRILLING FLUIDS REPORT DEPTH 8743' MW 9.0 VIS 77 PV 25 YP 14 FL Gels 14/27/33 CL- FC 0/2 SOL 7.4 SD 0.05 OIL 84.6/15.4 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 8117' TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 149 @ 8157 5 @ 8681 25.4 TRIP GAS CUTTING GAS @ @ WIPER GAS 60u @ 8171' CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 32080 @ 8146 735 @ 8680 5082.5 CONNECTION GAS HIGH ETHANE (C-2) 80 @ 8263 42 @ 8273 1.3 AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 6u / 8u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 30% Tuffaceous siltstone 20% Tuffaceous Claystone 20% Sand 10% Sandstone 10% Coal 10% Carbonaceous shale PRESENT LITHOLOGY 30% Tuffaceous siltstone 30% Tuffaceous Claystone 30% Sand 10% Sandstone DAILY ACTIVITY SUMMARY Continue drilling ahead and sliding as per directional driller to 8526’. Change out swab on mud pump one while circulating and working pipe. Drill ahead, get hung up at 8648’ while picking up to get tool face. Engage rotary and broke free at 13K torque. Pump 20 bbls sweep and chase with OBM while finishing drilling stand to 8667’. Obtain slow pump rates and continue drilling ahead at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2855.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Steve Lawrence DATE Dec 25, 2016 DEPTH 9095 PRESENT OPERATION Drilling TIME 24:00 YESTERDAY 8826 24 HOUR FOOTAGE 269 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 8877.77 12.85 123.64 7042.71 8939.47 11.56 120.29 7103.01 8983.47 11.35 125.36 7146.14 8999.84 11.48 126.04 7162.19 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3rr1 8.5" HDBS MM75D PDC 12670052 5x12 8117' 978' 22.00 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 151.4 @ 8960 2.0 @ 9045 55.8 75.65 FT/HR SURFACE TORQUE 10187 @ 8857 163 @ 9025 1403.0 0.00 FT-LBS WEIGHT ON BIT 15 @ 8897 0 @ 8960 4.5 2.90 KLBS ROTARY RPM 72 @ 8936 1 @ 8836 12.0 1.98 RPM PUMP PRESSURE 2831 @ 8896 1693 @ 9067 2482.4 1943.55 PSI DRILLING FLUIDS REPORT DEPTH 8743 MW 9.0 VIS 77 PV 25 YP 14 FL Gels 14/27/33 CL- FC 0/2 SOL 7.4 SD 0.05 OIL 84.6/15.4 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 8117' TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 43 @ 8967 4 @ 9044 11.4 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 8790 @ 8968 449 @ 9044 1903.1 CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 6u / 7u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 50% Tuffaceous sandstone 30% Tuffaceous siltstone 10% Tuffaceous claystone 10% carbonaceous shale PRESENT LITHOLOGY 80% Tuffaceous Sandstone 10% Tuffaceous siltstone 10% Carbonaceous shale DAILY ACTIVITY SUMMARY Continue drilling ahead to 8920’. Slides ratty ledging up. Mix and pump high viscosity sweep while reciprocating pipe. Short trip out of hole to 8035’, hit tight spot at 8496’. Service top drive and HPU’s. Pick up 20 singles and trip in to 8857’. Wash to bottom and continue drilling ahead as per directional driller. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3155.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Steve Lawrence DATE Dec 26, 2016 DEPTH 9169 PRESENT OPERATION Rig Service TIME 24:00 YESTERDAY 9095 24 HOUR FOOTAGE 74 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3rr1 8.5" HDBS MM75D PDC 12670052 5x12 8117' 1052' 25.75 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 125.8 @ 9131 1.6 @ 9136 41.5 13.40 FT/HR SURFACE TORQUE 0 @ 9169 0 @ 9169 0.0 0.00 FT-LBS WEIGHT ON BIT 9 @ 9168 0 @ 9131 3.6 8.34 KLBS ROTARY RPM 6 @ 9169 1 @ 9095 2.7 6.96 RPM PUMP PRESSURE 2793 @ 9165 55 @ 9169 2612.2 55.16 PSI DRILLING FLUIDS REPORT DEPTH 9169' MW 9.1 VIS 81 PV 26 YP 13 FL Gels 14/24/30 CL- FC 0/2 SOL 7.9 SD 0.05 OIL 85.6/14.4 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 8117 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 14 @ 9159 4 @ 9097 8.6 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 2518 @ 9161 390 @ 9097 1241.9 CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG - / 7u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 30% Tuffaceous siltstone 30% Sand, 20% Tuffaceous sandstone 10% Tuffaceous claystone 10% Carbonaceous shale PRESENT LITHOLOGY 30% Tuffaceous siltstone 30% Sand, 20% Tuffaceous sandstone 10% Tuffaceous claystone 10% Carbonaceous shale DAILY ACTIVITY SUMMARY Drill ahead per directional driller to 9169’, back reaming and slide drilling. Fire on HPU #2, extinguish fire. Circulate with pump #2. Work pipe while cleaning HPU #2 then pull out to the shoe at 8029’. Monitor well while repairing HPU #2 and performing rig maintenance. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2855.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Steve Lawrence DATE Dec 27, 2016 DEPTH 9169 PRESENT OPERATION Rig Service TIME 24:00 YESTERDAY 9169 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3rr1 8.5" HDBS MM75D PDC 12670052 5x12 8117' 1052' 25.75 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 9169' MW 9.15 VIS 100 PV 20 YP 11 FL Gels 12/21/28 CL- FC 0/2 SOL 7.9 SD 0.05 OIL 85.6/14.4 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 8117 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 30% Tuffaceous siltstone 30% Sand, 20% Tuffaceous sandstone 10% Tuffaceous claystone 10% Carbonaceous shale DAILY ACTIVITY SUMMARY Continue cleaning and working on HPU. Perform rig maintenance. Monitor casing PSI with well shut in while working around the rig. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2855.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Rick Brumley DATE Dec 28, 2016 DEPTH 9169 PRESENT OPERATION Rig Service / Repair H PU TIME 24:00 YESTERDAY 9169 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3rr1 8.5" HDBS MM75D PDC 12670052 5x12 8117' 1052' 25.75 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 9169' MW 9.10 VIS 100 PV 28 YP 13 FL Gels 12/21/28 CL- FC 0/2 SOL 8.1 SD 0.05 OIL 87.8/12.2 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 8117 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 30% Tuffaceous siltstone 30% Sand, 20% Tuffaceous sandstone 10% Tuffaceous claystone 10% Carbonaceous shale DAILY ACTIVITY SUMMARY Continue rebuilding and cleaning HPU. Pull out of hole to 7795’ and wait on orders. Resume pulling out of hole and lay down BHA #7. Continue working on HPU and performing rig service at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2855.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Rick Brumley DATE Jan 1, 2017 DEPTH 9169 PRESENT OPERATION Tripping in hole TIME 24:00 YESTERDAY 9169 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 4 8.5" Reed DS813M-G3A PDC E174094 8x12 9169' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 9169' MW 9.1 VIS 116 PV 21 YP 15 FL Gels 14/24/31 CL- FC 0/2 SOL 8.1 SD 0.05 OIL 87.8/12.2 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 9169' TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 30% Tuffaceous siltstone 30% Sand, 20% Tuffaceous sandstone 10% Tuffaceous claystone 10% Carbonaceous shale DAILY ACTIVITY SUMMARY Continue troubleshooting and repairing HPU #2. Pick up BHA #8. Uplooad and test MWD tools (good). Finish picking up BHA and trip into hole filling every ~2500’. At 6031’ at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3355.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Rick Brumley DATE Jan 02, 2017 DEPTH 9652' PRESENT OPERATION Drilling TIME 24:00 YESTERDAY 9169' 24 HOUR FOOTAGE 483' CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9401.98 9.5 237.92 7560.247 9462.87 9.9 250.77 7620.23 9525.89 12.04 260.08 7682.1 9588.21 13.82 263.47 7742.84 9650.25 15.2 265.08 7802.9 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 4 8.5" Reed DS81 3M-G3A PDC E174094 8x12 9169' 483 11.00 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 744.3 @ 9482 2.3 @ 9504 59.4 44.35 FT/HR SURFACE TORQUE 15482 @ 9481 135 @ 9602 2993.0 0.00 FT-LBS WEIGHT ON BIT 32 @ 9607 0 @ 9532 10.2 17.40 KLBS ROTARY RPM 72 @ 9429 3 @ 9345 24.7 4.17 RPM PUMP PRESSURE 2951 @ 9198 2275 @ 9205 2741.9 2688.53 PSI DRILLING FLUIDS REPORT DEPTH 9169 MW 9.15 VIS 75 PV 22 YP 14 FL Gels 16/27/33 CL- FC 0/2 SOL 8.1 SD 0.05 OIL 87.8/12.2 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 9169 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 34 @ 9341 3 @ 9492 8.4 TRIP GAS 51u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 8227 @ 9342 384 @ 9482 1673.1 CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 5u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 50%Tuffaceous Sandstone 30% tuffaceous siltstone 10% tuffaceous claystone 10% coal PRESENT LITHOLOGY 40%Tuffaceous Sandstone 30% tuffaceous siltstone 20% tuffaceous claystone 10% coal DAILY ACTIVITY SUMMARY Continue tripping into the hole to 9071’ and fill pipe at 7643’. Break circulation at the top of the window, at 8046’ and at 8263’. Drill ahead to 9250’ and change out swab on pump #1. Toubleshoot pump #1 wiring issue, pump strokes jumping around. Continue drilling ahead 9480’ and troubleshoot MWD. Continue drilling to 9648’, as per directional plan. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3355.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marving Rogers / Rick Brumley DATE Jan 03, 2017 DEPTH 10250 PRESENT OPERATION Drilling TIME 24:00 YESTERDAY 9652 24 HOUR FOOTAGE 598 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 10021.98 16.58 269.1 8159.46 10082.52 15.75 266.82 8217.61 1044.86 14.35 269.13 8277.81 10207.12 12.48 274.57 8338.37 10269.83 10.93 278.3 8399.78 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 4 8.5" Reed DS81 3M-G3A PDC E174094 8x12 9169' 1081' 23.3 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 190.1 @ 9946 2.3 @ 9926 57.7 97.23 FT/HR SURFACE TORQUE 11934 @ 9948 8746 @ 9760 7907.4 10894.94 FT-LBS WEIGHT ON BIT 21 @ 9653 2 @ 10185 10.2 9.07 KLBS ROTARY RPM 73 @ 10185 3 @ 10030 51.4 67.43 RPM PUMP PRESSURE 3138 @ 10187 2480 @ 9755 2853.4 2864.78 PSI DRILLING FLUIDS REPORT DEPTH 10156' MW 9.10 VIS 78 PV 26 YP 12 FL Gels 16/27/32 CL- FC 0/2 SOL 8.7 SD 0.05 OIL 87.8/12.2 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 9169 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 87 @ 9725 1 @ 9757 11.6 TRIP GAS 15u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 21278 @ 9725 203 @ 9754 2405.3 CONNECTION GAS HIGH ETHANE (C-2) 70 @ 9958 50 @ 9962 0.7 AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 7u / 7u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 40% Tuffaceous claystone 30% Tuffaceous siltstone 20% sand 10% coal PRESENT LITHOLOGY 50% Sand 20% Tuffaceous claystone 20% Tuffaceous Siltstone 10% Coal DAILY ACTIVITY SUMMARY Continue drilling ahead as per directional plan. Obtain SPR’s, change out swab and liner on pump #1. Circulate and reciprocate pipe while waiting. Continue drilling ahead to 10184’ then pumped a high viscosity sweep (25bbls). Short trip out to 9135’, blow down top drive and perform rig service. Pick up 34 joints of drill pipe on the way back in the hole. Tag bottom and continue drilling ahead as per directional plan. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2855.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Rick Brumley DATE Jan 04, 2017 DEPTH 10943 PRESENT OPERATION Drilling TIME 24:00:00 YESTERDAY 10250 24 HOUR FOOTAGE 693 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 10638.5 11.87 335.08 8762.34 10701.72 14.14 339.76 8823.94 10763.01 15.99 344.89 8883.12 10824.24 17.38 350.1 8941.78 10887.07 17.92 351.18 9001.66 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 4 8.5" Reed DS81 3M-G3A PDC E174094 8x12 9169' 1774' 37.0 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 1976.8 @ 10624 2.6 @ 10893 67.3 60.83 FT/HR SURFACE TORQUE 14066 @ 10745 166 @ 10509 3577.2 0.00 FT-LBS WEIGHT ON BIT 25 @ 10745 1 @ 10687 10.4 22.53 KLBS ROTARY RPM 69 @ 10803 1 @ 10339 23.1 2.66 RPM PUMP PRESSURE 3264 @ 10709 2572 @ 10943 2975.6 2572.29 PSI DRILLING FLUIDS REPORT DEPTH 10943 MW 9.0 VIS 75 PV 24 YP 15 FL Gels 10/21/29 CL- FC 0/2 SOL 7.7 SD 0.05 OIL 87.5/12.5 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 9169 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 34 @ 10613 3 @ 10399 7.7 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 8386 @ 10613 387 @ 10496 1467.5 CONNECTION GAS HIGH ETHANE (C-2) 63 @ 10772 51 @ 10773 0.3 AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 10u / 6u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 40% Sand 40% Tuffaceous siltstone 10% Tuffaceous claystone 10% coal PRESENT LITHOLOGY 40% Sand 30% Tuffaceous siltstone 20% Tuffaceous claystone 10% coal DAILY ACTIVITY SUMMARY Continue drilling ahead as per directional program. Circulate and reciprocate at 10750’ while changing out a swab on mud pump #2. Drill ahead to 10914’ where the rig got hung up. Work free with a max pull of 220K (did not fire jars). Pump a 22bbls sweep and wait for returns. Continue drilling ahead as per directional plan at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2855.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Rick Brumley DATE Jan 05, 2017 DEPTH 11050 PRESENT OPERATION Tripping TIME 24:00:00 YESTERDAY 10943 24 HOUR FOOTAGE 107 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 10949.66 19.12 351.14 9061 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 4 8.5" Reed DS81 3M-G3A PDC W174094 8x12 9169' 1881' 40.3 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 273.5 @ 10989 1.0 @ 10953 45.3 50.03 FT/HR SURFACE TORQUE 19402 @ 10988 10857 @ 10991 832.9 FT-LBS WEIGHT ON BIT 24 @ 10944 2 @ 10995 11.1 12.13 KLBS ROTARY RPM 63 @ 10994 2 @ 10966 6.6 2.79 RPM PUMP PRESSURE 3168 @ 10990 2506 @ 10994 2981.90 3095.44 PSI DRILLING FLUIDS REPORT DEPTH MW 9.0 VIS 75 PV 24 YP 15 FL Gels 10/21/29 CL- FC 0/2 SOL 7.7 SD 0.05 OIL 87.5/12/5 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 9169 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 30 @ 11038 3 @ 10984 9.6 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 7157 @ 11038 436 @ 10985 1805.9 CONNECTION GAS HIGH ETHANE (C-2) 64 @ 10955 49 @ 10965 5.1 AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG - / 8u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 70% Tuffaceous siltstone 10% Tuffaceous claystone 10% Sandstone 10% Coal PRESENT LITHOLOGY 70% Tuffaceous siltstone 10% Tuffaceous claystone 10% Sandstone 10% Coal DAILY ACTIVITY SUMMARY Continue drilling ahead from 10936’ to 11051’. Pump hi vis weighted sweep. Continue circ same 2 bottoms up, monitor well, pump dry job. Pull out of hole to 10183’; c/o swab #1 mud pump #2 cyl and circulate. Circulate dry job out of hole. Reciprocate, pump dry job. Pull out of hole to 8039’. Slip & cut 194’. Service drawworks. Pull out of hole singles to 6956’. Continue pull out of hole & lay down BHA at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2855.00 REPORT BY Garnet Knopp Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Rick Brumley DATE Jan 06, 2017 DEPTH 11056 PRESENT OPERATION Drilling TIME 24:00 YESTERDAY 11050 24 HOUR FOOTAGE 6 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 4 8.5" Reed DS81 3M-G3A PDC W174094 8x12 9169' 11050' 1881' 40.3 5 8.5" HDBS MMD75C PDC 12451966 7x13 11050' 6' 0.3 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 50.0 @ 11050 15.2 @ 11053 21.5 15.75 FT/HR SURFACE TORQUE 0 @ 11056 0 @ 11056 0.0 0.00 FT-LBS WEIGHT ON BIT 18 @ 11052 12 @ 11050 17.5 14.81 KLBS ROTARY RPM 3 @ 11051 2 @ 11050 3.4 2.92 RPM PUMP PRESSURE 3250 @ 11051 2966 @ 11053 3622.4 3049.55 PSI DRILLING FLUIDS REPORT DEPTH 11050 MW 9.0 VIS 93 PV 19 YP 13 FL Gels 11/24/29 CL- FC 0/2 SOL 8.6 SD 0.05 OIL 87.2/12.8 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 11050' TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 25 @ 11053 8 @ 11050 42.3 TRIP GAS 137u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 5842 @ 11053 1723 @ 11050 9872.5 CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 15u / 15u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 70% Tuffaceous siltstone 10% Tuffaceous claystone 10% Sandstone 10% Coal PRESENT LITHOLOGY 70% Tuffaceous siltstone 10% Tuffaceous claystone 10% Sandstone 10% Coal DAILY ACTIVITY SUMMARY Continue pulling out of hole and lay down BHA. Clean and clear rig floor while monitoring well (static). Pulse test MWD tools and blow down mud lines. Pick up and adjust mud motor bend to 1.76 degrees. Make up remaining BHA and trip into hole to 2160’. Make up agitator and shock assembly. Trip in to 2534’ and fill pipe. Blow down mud lines and clean rig floor. Trip in hole to 6711’ and change grabber dies. Single in to 8550’, installing CBI’s every 4 stands. Break circulating at 9900’ and fill pipe. Circulate and condition mud while troubleshooting MWD. Drill ahead as per directional plan. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2855.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Rick Brumley DATE Jan 07, 2017 DEPTH 11222 PRESENT OPERATION Servicing HPU #1 TIME 17:36:04 YESTERDAY 11056 24 HOUR FOOTAGE 166 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11085.79 24.9 355.36 9187.42 11148.85 26.68 355.95 9244.2 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5 8.5" HDBS MMD75C PDC 12451966 7x13 11050' 172' 8.0 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 151.7 @ 11156 3.4 @ 11101 35.2 20.96 FT/HR SURFACE TORQUE 13668 @ 11079 8 @ 11092 781.5 0.00 FT-LBS WEIGHT ON BIT 22 @ 11123 1 @ 11082 12.5 19.37 KLBS ROTARY RPM 53 @ 11122 2 @ 11202 5.9 2.82 RPM PUMP PRESSURE 3423 @ 11081 2675 @ 11202 3062.3 2896.93 PSI DRILLING FLUIDS REPORT DEPTH 1/6/2017 MW 9.0 VIS 93 PV 19 YP 13 FL Gels 11/24/29 CL- FC 0/2 SOL 8.6 SD 0.05 OIL 87.2 / 12.8 MBT pH Ca+ C CI MWD SUMMARY INTERVAL 11050 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 39 @ 11118 4 @ 11191 12.0 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 9108 @ 11117 751 @ 11191 2381.5 CONNECTION GAS HIGH ETHANE (C-2) 77 @ 11222 59 @ 11072 3.0 AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG - / 9u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 50% Tuffaceous Siltstone 30% Sand 10% Tuffaceous Claystone 10% Coal PRESENT LITHOLOGY 50% Tuffaceous Siltstone 30% Sand 10% Tuffaceous Claystone 10% Coal DAILY ACTIVITY SUMMARY Continue drilling ahead as per directional plan to 11108’. Change out swab on mud pump #2, change rod wash from LVT to water while working pipe. Troubleshoot PLC not latching to HPU. Continue drilling ahead to 11222’. HPU unlatching and dropping RPM, change assignment running mud pump #1 with HPU #2. Circulate while waiting on orders. Pump dry job and pull out of the hole to 8016’. Service rig and drawworks. Pacific Power checking on HPU #1 while changing out dampner on mud pump #1 at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2855.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Rick Brumley DATE Jan 08, 2017 DEPTH 11360 PRESENT OPERATION Pulling out of hole TIME 24:00:00 YESTERDAY 11222 24 HOUR FOOTAGE 138 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11209.84 29.59 358.13 9297.98 11272.93 32.78 357.27 9351.94 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5 8.5" HDBS MMD75C PDC 12451966 7x13 11050' 11360' 310' 11.75 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 127.2 @ 11230 1.7 @ 11263 31.5 26.93 FT/HR SURFACE TORQUE 13428 @ 11294 5593 @ 11223 517.1 0.00 FT-LBS WEIGHT ON BIT 23 @ 11227 2 @ 11309 11.7 18.03 KLBS ROTARY RPM 52 @ 11308 2 @ 11222 4.6 3.10 RPM PUMP PRESSURE 3693 @ 11228 2705 @ 11296 3044.7 3035.82 PSI DRILLING FLUIDS REPORT DEPTH 1/7/2017 MW 9.0 VIS 74 PV 25 YP 15 FL Gels 11/31/33 CL- FC 0/2 SOL 8.2 SD 0.05 OIL 88.4/11.6 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 11050 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 33 @ 11223 3 @ 11280 6.9 TRIP GAS 33u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 8070 @ 11223 513 @ 11291 1209.8 CONNECTION GAS HIGH ETHANE (C-2) 77 @ 11222 49 @ 11340 5.7 AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 5u / 5u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 40% Sand 40% Tuffaceous siltstone 10% Tuffaceous Claystone 10% Coal PRESENT LITHOLOGY 40% Sand 40% Tuffaceous siltstone 10% Tuffaceous Claystone 10% Coal DAILY ACTIVITY SUMMARY Troubleshoot HPU and finish replacing mud pump dampener. Monitor well (static). Trip back in hole to 9903’, fill pipe, test mud pump #1 and HPU #1. Continue tripping in hole to 11187’, Kelly up, fill pipe and wash to bottom. Drill ahead as per directional plan to 11292’. Unplug rod wash on mud pump #1, change #3 swab on mud pump #2 while working pipe. Rack stand back, troubleshoot drawworks motor issue, drawworks is bypassing. Mix 20bbls dry job and monitor well (static). Rack back 3 stands of drill pipe, Kelly up and pump 1 bpm while changing out drillers side drawworks motor. Replace broken hookload sensor and calibrate. Trip in hole and drill ahead to 11360’. Mix and pump dry job and pull out of the hole. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2855.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Rick Brumley DATE Jan 09, 2017 DEPTH 11360 PRESENT OPERATION Tripping in hole TIME 24:00:00 YESTERDAY 11360 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5rr1 8.5 Reed DS813M-G3A PDC E174094 8x12 11360' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 1/9/2017 MW 9.0 VIS 72 PV 24 YP 15 FL Gels 13/31/33 CL- FC 0/2 SOL 88.2 SD 0.05 OIL 88.4/11.6 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 11360 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY No new footage drilled DAILY ACTIVITY SUMMARY Continue pulling out of the hole and lay down BHA. Download MWD data and rack smart tools back in derrick. Clean floor from wet pipe trip. Slip and cut 86.5’ of drill line. Pick up new BHA and change motor bend to 2.12 and run in hole to 3782’. O-ring on HPU#1 failed. Shut down HPU and change O-ring, restart HPU, Same o-ring failed, replace and restart. Continue running in hole at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2855.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Rick Brumley DATE Jan 10, 2017 DEPTH 11479 PRESENT OPERATION Drilling TIME 24:00:00 YESTERDAY 11360 24 HOUR FOOTAGE 119 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11331.63 36.52 357.38 9400.23 11395.4 39.33 358.89 9450.52 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5rr1 8.5" Reed DS813M-G3A PDC E174094 8x12 11360' 119' 4.6 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 176.7 @ 11442 3.1 @ 11382 44.5 3.26 FT/HR SURFACE TORQUE 14983 @ 11405 491 @ 11441 975.4 3127.56 FT-LBS WEIGHT ON BIT 39 @ 11477 0 @ 11372 18.6 36.23 KLBS ROTARY RPM 24 @ 11406 2 @ 11396 4.4 3.04 RPM PUMP PRESSURE 3447 @ 11405 2588 @ 11399 3108.2 2812.64 PSI DRILLING FLUIDS REPORT DEPTH 1/9/2017 MW 9.0 VIS 81 PV 24 YP 15 FL Gels 15/32/37 CL- FC 0/2 SOL 7.7 SD 0.05 OIL 87.9/12.1 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 11360 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 35 @ 11362 4 @ 11392 12.7 TRIP GAS 52u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 8336 @ 11362 454 @ 11392 2274.6 CONNECTION GAS HIGH ETHANE (C-2) 126 @ 11406 66 @ 11402 4.3 AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 6u / 6u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 50% Sand 30% Tuffaceous siltstone 10% Tuffaceous claystone 10% coal PRESENT LITHOLOGY 50% Sand 30% Tuffaceous siltstone 10% Tuffaceous claystone 10% coal DAILY ACTIVITY SUMMARY Trip in to 8684’. Trip back out to 8045’ to change DW FWD isolation valve on HPU #2. Trip in hole to 9500’, fill pipe and circulate to warm up the mud. Trip in to 11312’ and fill pipe. Tag bottom (no fill) and drill ahead as per directional plan. Hanging up while sliding. 45k overpull. Drill to 11477’. Air boot on Riser failed, spilled 10 gallons of mud in cellar. Stand back stands to 11064’ Make up test plug and hang off string. Remove lower boot air flange and riser, test riser (good). Run in hole to 11477’ and drill ahead as per directional plan. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2855.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Steve Lawrence DATE Jan 11, 2017 DEPTH 11587 PRESENT OPERATION Drilling TIME 24:00:00 YESTERDAY 11479 24 HOUR FOOTAGE 108 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11456.01 45.86 358.16 9495.12 11517.61 50.38 0.56 9536.23 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5rr1 8.5" Reed DS813M-G3A PDC E174094 8x12 11360' 227' 11.75 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 119.1 @ 11539 1.5 @ 11567 27.2 4.34 FT/HR SURFACE TORQUE 15833 @ 11486 33 @ 11573 721.2 FT-LBS WEIGHT ON BIT 41 @ 11480 1 @ 11506 18.8 23.64 KLBS ROTARY RPM 20 @ 11489 2 @ 11576 4.1 2.67 RPM PUMP PRESSURE 3309 @ 11485 2744 @ 11567 2981.4 3107.15 PSI DRILLING FLUIDS REPORT DEPTH 1/10/2017 MW 9.0 VIS 79 PV 24 YP 15 FL Gels 13/26/33 CL- FC 0/2 SOL 7.7 SD 0.05 OIL 87.9/12.1 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 11479 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 13 @ 11584 4 @ 11495 6.2 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 2772 @ 11584 328 @ 11499 794.9 CONNECTION GAS HIGH ETHANE (C-2) 55 @ 11542 52 @ 11485 2.5 AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 5u / 6u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 50% Sand 20% Tuffaceous sandstone 20% Tuffaceous siltstone 10% Tuffaceous claystone PRESENT LITHOLOGY 50% Sand 20% Tuffaceous sandstone 20% Tuffaceous siltstone 10% Tuffaceous claystone DAILY ACTIVITY SUMMARY Directional drill to 11484’. Toolface hanging up, stacking weight. Change swab in #1 mud pump. Directional drill from 11484’ to 11499’. Change liner, gasket and wash plate in mud pump #2, #3 pod. Work pipe with one pump. Directional drill from 11499’ to 11542’.When toolface hangs up, stacking weight; no difference. Pick up & rotate 20RPM 2’ from the bottom of the slide to help clean up drag. Continue to drill ahead from 11542’ to 11590’. Pump weighted sweep, no noticeable change in returns. Pump weighted sweep with lube, better weight transfer to bit. Continue directional drill as planned at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2905.00 REPORT BY Garnet Knopp Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Steve Lawrence DATE Jan 12, 2017 DEPTH 11688 PRESENT OPERATION Drilling TIME 24:00:00 YESTERDAY 11587 24 HOUR FOOTAGE 101 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11581.72 56.75 4.74 9574.3 11642.51 62.95 8.34 9604.82 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5rr1 8.5" Reed DS813M-G3A PDC E174094 8x12 11360' 328' 20.33 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 154.4 @ 11611 0.5 @ 11680 23.1 20.47 FT/HR SURFACE TORQUE 12417 @ 11680 16 @ 11600 480.8 0.00 FT-LBS WEIGHT ON BIT 49 @ 11600 3 @ 11638 21.4 16.27 KLBS ROTARY RPM 31 @ 11602 2 @ 11588 5.4 2.97 RPM PUMP PRESSURE 3346 @ 11685 2950 @ 11599 3120.7 3166.78 PSI DRILLING FLUIDS REPORT DEPTH 1/13/2017 MW 9.0 VIS 67 PV 26 YP 14 FL Gels 13/33/37 CL- FC 0/2 SOL 9.3 SD 0.05 OIL 89.4/10.6 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 11479 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 10 @ 11613 3 @ 11685 5.1 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 1990 @ 11613 365 @ 11663 703.3 CONNECTION GAS HIGH ETHANE (C-2) 57 @ 11662 48 @ 11670 1.5 AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 3.4u / 3.4u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 40% Tuffaceous siltstone 40% Sand 10% Tuffaceous claystone 10% Coal PRESENT LITHOLOGY 40% Tuffaceous siltstone 40% Sand 10% Tuffaceous claystone 10% Coal DAILY ACTIVITY SUMMARY Continue drilling/sliding ahead as per directional driller to 11637’ and change swab and liner on in pump #1 pod #1. Continue drilling ahead as per directional driller to 11667’ and change out #3 swab on pump #1 while working pipe. Continue drilling ahead to 11674’ and change out #1 swab on mud pump #2. Pump high viscosity sweep with nut plug and lube and pump at 5bpm OBM at 400gpm until out of drill pipe. Continue drilling ahead as per directional driller at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2905.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Steve Lawrence DATE Jan 13, 2017 DEPTH 11863 PRESENT OPERATION Drilling TIME 24:00:00 YESTERDAY 11688 24 HOUR FOOTAGE 175 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11706.88 67.25 11.04 9631.92 11768.2 72.65 12.11 9652.94 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5rr1 8.5" Reed DS813M-G3A PDC E174094 8x12 11360 503" 30.5 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 145.6 @ 11749 2.3 @ 11737 30.8 0.00 FT/HR SURFACE TORQUE 6896 @ 11732 60 @ 11726 83.9 0.00 FT-LBS WEIGHT ON BIT 37 @ 11785 4 @ 11739 14.7 13.95 KLBS ROTARY RPM 22 @ 11732 2 @ 11699 3.7 3.04 RPM PUMP PRESSURE 3331 @ 11806 2686 @ 11732 3075.6 3260.94 PSI DRILLING FLUIDS REPORT DEPTH 1/12/2017 MW 9.1 VIS 72 PV 30 YP 20 FL Gels 15/33/37 CL- FC 0/2 SOL 7..8 SD 0.05 OIL 89.0/11.0 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 11360 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 18 @ 11711 3 @ 11692 6.3 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 4258 @ 11711 315 @ 11765 960.9 CONNECTION GAS HIGH ETHANE (C-2) 107 @ 11858 46 @ 11715 27.9 AVG PROPANE (C-3) 40 @ 11859 32 @ 11861 1.7 CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 6.2u / 4.1u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 80% Tuffaceous sandstone/sand 20% Tuffaceous siltstone PRESENT LITHOLOGY 80% Tuffaceous sandstone/sand 20% Tuffaceous siltstone DAILY ACTIVITY SUMMARY Continue drilling ahead as per directional driller to 11733’. Change swab in mud pump #2 pod #2. Drill ahead to 11774’ and change swab in mud pump #1 pod #2. Drill ahead to 11805’ and pump a lube/nut plug sweep and chase with 9.1ppg OBM. Sweep was 20bbls late with 50% increase in cuttings returned. Increase lasted 500bbls past with 100% increase (coal/sand @ max). No change in parameters after sweep. Circulate hole clean while rotating. Continue drilling ahead at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2905.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Steve Lawrence DATE Jan 14, 2017 DEPTH 11900 PRESENT OPERATION Trip out TIME 24:00:00 YESTERDAY 11863 24 HOUR FOOTAGE 37 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11,829.40 78.74 15.19 9,668.06 11,860.62 80.95 18.10 9,673.57 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5rr1 8.5" Reed DS813M-G3A PDC E174094 8x12 11360' 11900' 540' 33.75 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 64.8 @ 11876 2.4 @ 11878 14.5 6.81 FT/HR SURFACE TORQUE 5765 @ 11897 5765 @ 11897 155.8 0.00 FT-LBS WEIGHT ON BIT 19 @ 11900 2 @ 11870 11.0 19.31 KLBS ROTARY RPM 24 @ 11897 2 @ 11890 3.6 3.17 RPM PUMP PRESSURE 3260 @ 11863 2871 @ 11900 3121.6 2871.59 PSI DRILLING FLUIDS REPORT DEPTH 1/13/2017 MW 9.05 VIS 68 PV 24 YP 14 FL Gels 14/31/37 CL- FC 0/2 SOL 8.3 SD 0.05 OIL 88.4 / 11.6 MBT pH Ca+ C CI MWD SUMMARY INTERVAL 11360 TO TD TOOLS DGE/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 6 @ 11863 2 @ 11892 3.6 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 1115 @ 11863 117 @ 11892 425.4 CONNECTION GAS HIGH ETHANE (C-2) 52 @ 11863 52 @ 11863 1.4 AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG - / 4u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 80% Tuffaceous sandstone/sand 20% Tuffaceous Siltstone PRESENT LITHOLOGY 80% Tuffaceous sandstone/sand 20% Tuffaceous Siltstone DAILY ACTIVITY SUMMARY Continue drilling ahead as per directional driller to 11867’. Service top drive and drawworks. Trip out two stands, Rig up head pin and circulating equipment. Circulate 2bpm while changing out saver subs and grabber dies. Rig down circulating equipment, trip in hole one stand, wash to bottom and orient tool face. Drill to 11874’ and change out swab in mud pump #1 pod #3. Drill ahead to 11896’ and replace cap gasket on mud pump #2 pod #3 and go through valves. Drill ahead to 11900’, reem squat, take survey and rack back one stand. Monitor well (slight drop). Pump sweep around, came back 20 bbls late with 25% increase in cuttings. Monitor well (slowly dropping). Pump dry job and pullout of hole to 5991’. Switch from rig to platform power and blow down casing. Continuing to pull out of the hole at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2905.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Steve Lawrence DATE Jan 15, 2017 DEPTH 11900 PRESENT OPERATION Tripping in hole TIME 24:00:00 YESTERDAY 11900 24 HOUR FOOTAGE CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5rr1 8.5" Reed DS813M-G3A PDC E174094 8x12 11360' 11900' 540' 33.75 1-4-BT-G-X-1-JD BHA 6 8.5" Reed FT716B PDC E230939 5x12, 2x15 11900' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 1/14/2017 MW 9.05 VIS 67 PV 24 YP 14 FL Gels 14/31/37 CL- FC 0/2 SOL 8.2 SD 0.05 OIL 88.4 / 11.6 MBT pH Ca+ C CI MWD SUMMARY INTERVAL 11360 TO TD TOOLS DGE/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue pulling out of the hole, lay down/rack back MWD/BHA. Drain stack, make up test plug assembly and work on mud pump #2. Work air out of BOP’s and test. Replace swabs on mud pump #2, pods 1 and 3. Finish testing BOP’s, lay down test joint and drain stack. Pick up BHA #11 and unload MWD. Tripping in hole at report time CANRIG PERSONNEL ON BOARD 4 DAILY COST $2905.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Steve Lawrence DATE Jan 16, 2017 DEPTH 12081 PRESENT OPERATION Working pipe TIME 24:00:00 YESTERDAY 11900 24 HOUR FOOTAGE 181 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11921.39 86.29 22.67 9680.1 11983.33 85.91 24.59 9684.31 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 6 8.5" Reed FT716B PDC E230939 E230939 5x12, 2x15 11900' 181' 6.75 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 159.3 @ 12022 1.0 @ 11932 34.6 55.90 FT/HR SURFACE TORQUE 13145 @ 11960 10 @ 11913 1071.0 FT-LBS WEIGHT ON BIT 28 @ 11905 0 @ 12038 6.6 1.50 KLBS ROTARY RPM 37 @ 11951 2 @ 11944 5.3 3.27 RPM PUMP PRESSURE 3692 @ 11912 2871 @ 11900 3475.1 3440.36 PSI DRILLING FLUIDS REPORT DEPTH 12034' MW 9.1 VIS 71 PV 23 YP 15 FL Gels 13/30/37 CL- FC 0/2 SOL 9.3 SD 0.05 OIL 88.8/11.2 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 11900 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 12 @ 12018 3 @ 11900 6.5 TRIP GAS 39u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 2000 @ 12018 181 @ 12035 792.3 CONNECTION GAS HIGH ETHANE (C-2) 110 @ 12018 25 @ 12041 24.1 AVG PROPANE (C-3) 79 @ 12018 16 @ 11992 18.0 CURRENT BUTANE (C-4) 19 @ 12080 13 @ 12071 1.1 CURRENT BACKGROUND/AVG 4u / 8u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 40% Tuffaceous sandstone/sand 40% Tuffaceous siltstone 10% Tuffaceous claystone 10% Coal PRESENT LITHOLOGY 70% Sand 20% Tuffaceous siltstone 10% Carbonaceous shale DAILY ACTIVITY SUMMARY Continue tripping in hole to 6000’, fill pipe, trip in to 8012’ and slip and cut a83’ of drill line. Swap to rig power and perform rig service. Service make up tongs, fill pipe, tst MWD and orient tool face through window. Trip in to 9965’, fill pipe and warm/shear mud. Trip in to 11771’ and wash to bottom. Circulate while working on changing modes on agitator. Continue drilling ahead as per directional driller to 12081’. While picking up to back ream slide, string packed off and blew a pop-off. Slacked off, re-established circulation. Could not rotate. Working tight hole at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2905.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Steve Lawrence DATE Jan 17, 2017 DEPTH 12257 PRESENT OPERATION Drilling TIME 24:00:00 YESTERDAY 12081 24 HOUR FOOTAGE 176 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 12,047.58 84.37 28.37 9,689.71 12,109.52 83.90 31.28 9,696.05 12,172.06 84.24 32.56 9,702.51 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 6 8.5" Reed FT716B PDC E230939 5x12, 2x15 11900' 357' 13.25 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 194.5 @ 12146 3.1 @ 12257 40.2 3.07 FT/HR SURFACE TORQUE 15385 @ 12123 1932 @ 12208 2997.9 FT-LBS WEIGHT ON BIT 14 @ 12257 0 @ 12170 3.4 14.63 KLBS ROTARY RPM 71 @ 12205 2 @ 12164 15.4 3.55 RPM PUMP PRESSURE 3609 @ 12121 3011 @ 12228 3341.0 3184.73 PSI DRILLING FLUIDS REPORT DEPTH 12254 MW 9.1 VIS 67 PV 22 YP 13 FL Gels 13/31/39 CL- FC 0/2 SOL 9.3 SD 0.05 OIL 88.8/11.2 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 11900' TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 17 @ 12102 4 @ 12117 8.6 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 2459 @ 12103 115 @ 12116 930.2 CONNECTION GAS HIGH ETHANE (C-2) 199 @ 12143 26 @ 12118 75.0 AVG PROPANE (C-3) 126 @ 12103 16 @ 12209 43.6 CURRENT BUTANE (C-4) 40 @ 12103 13 @ 12230 6.7 CURRENT BACKGROUND/AVG 6u / 8u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 90% Sand/Sandstone 10% Tuffaceous siltstone PRESENT LITHOLOGY 90% Sand/Sandstone 10% Tuffaceous siltstone DAILY ACTIVITY SUMMARY Continue working stuck pipe at 12046’ to 12019’. Established pump rate and wprked pipe free as per company man. Pumped high viscosity sweep and reciprocate pipe. Sweep came back 25bbls late with a 25% increase in cuttings. Continue drilling ahead per directional driller to 12104’, mud pump #1 lost 30 strokes, pick up off bottom and packed off. Establish circulation and work pipe as per company man. Trip out of hole to 11895’, working pipe through tight spots. Ream back to bottom and drill ahead to 12122’. Attempt to pick up to orient tool and string packed off. Worked pipe loose and rotate from 12122’ to 12143’. Pump high viscosity sweep, large amount of sand came back before sweep (from rotating), sweep arrived 25bbls late with minimal increase in cuttings. Continue drilling ahead to 12206’. Work pipe and get tool face with HPU #1 while cheking oil on the other. Swap and check other HPU. Continue drilling ahead as per directional driller. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2905.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Steve Lawrence DATE Jan 18, 2017 DEPTH 12284 PRESENT OPERATION POOH TIME 24:00:00 YESTERDAY 12257 24 HOUR FOOTAGE 27 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 6 8.5" Reed FT716B PDC E230939 5x12, 2x15 11900' 384' 14.85 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 102.8 @ 12274 0.8 @ 12282 21.7 5.62 FT/HR SURFACE TORQUE 17574 @ 12266 330 @ 12273 5661.1 FT-LBS WEIGHT ON BIT 14 @ 12257 1 @ 12277 3.7 7.01 KLBS ROTARY RPM 60 @ 12258 3 @ 12269 22.7 3.34 RPM PUMP PRESSURE 3421 @ 12282 3184 @ 12257 3436.9 3371.38 PSI DRILLING FLUIDS REPORT DEPTH MW 9.1 VIS 67 PV 22 YP 13 FL Gels 13/31/39 CL- FC 0/2 SOL 9.3 SD 0.05 OIL 88.8/11.2 MBT pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 10 @ 12280 5 @ 12264 6.4 TRIP GAS 11u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 1910 @ 12280 376 @ 12281 712.9 CONNECTION GAS HIGH ETHANE (C-2) 124 @ 12259 39 @ 12257 56.0 AVG PROPANE (C-3) 29 @ 12259 15 @ 12268 12.6 CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 2u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue drilling ahead to 12279’, pick up off bottom to change valve in mud pump #1. Make up dry job and monitor well (slight drop). Pump dry job and pull out to window to change pod in mud pump #1 pod #2. Pull tight at 11616’ to 11647’ with 20k over pull. Service rig/top drive while changing out pod #2 in mud pump #1. Test mud pump #1 then trip into hole. Ream through tight spot at 8150’-8266’. Fill pipe at 9920’. Work through coal seams without much trouble, Kelly up at 12208’ and perform cleanup cycle. Cuttings back 100bbls early with 30% increase in cuttings at max with mostly coal/sand. Cracked bolt on mud pump #1 pod #3 needs replacing. Circulate with mud pump #2 while working pipe from 12208’ to 12270’. Finish repairing pump and ream to bottom. Drill to 12284’, stop and troubleshoot MWD while pumping and rotating. Monitor well (slight loss), pump dry job and begin pulling out of the hole. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2905.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Steve Lawrence DATE Jan 19, 2017 DEPTH 12284' PRESENT OPERATION Running in hole TIME 24:00:00 YESTERDAY 12284' 24 HOUR FOOTAGE CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 6 8.5" Reed FT716B PDC E230939 5x12, 2x15 11900' 12284' 384' 14.85 3-3-WT-A-X-0-DTF BHA 7 8.5" NOV/Reed DSH1813M-G3A E174093 8x12 12284' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 12284' (1/18/2017) MW 9.1 VIS 73 PV 30 YP 15 FL Gels 13/31/39 CL- FC 0/2 SOL 9.3 SD 0.05 OIL 88.8/11.2 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 12284 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue tripping out of the hole to change out BHA. Pull through tight spots at 11833’, 11709’ and 8455’. 8k bobble through window. Blow down mudlines at 7949’. Serviced mud pump #1 while laying down BHA. Pick up BHA #12 and run in hole. Fill pipe at 2600’. Continue running in the hole at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2905.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Steve Lawrence DATE Jan 20, 2017 DEPTH 12330' PRESENT OPERATION Drilling TIME 24:00:00 YESTERDAY 12284' 24 HOUR FOOTAGE 46' CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 7 8.5" NOV/Reed DSH1813M-G3A E174093 8x12 12284' 46' 3.9 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 93.1 @ 12296 1.6 @ 12302 19.0 5.29 FT/HR SURFACE TORQUE 16239 @ 12315 5941 @ 12303 1693.2 14639.18 FT-LBS WEIGHT ON BIT 14 @ 12315 0 @ 12285 7.3 11.75 KLBS ROTARY RPM 57 @ 12315 3 @ 12284 10.0 51.08 RPM PUMP PRESSURE 3606 @ 12288 2285 @ 12315 3300.1 3442.20 PSI DRILLING FLUIDS REPORT DEPTH 01/19/2017 MW 9.1 VIS 91 PV 30 YP 15 FL Gels 13/31/39 CL- FC 0/2 SOL 9.3 SD 0.05 OIL 89/11 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 12284' TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 8 @ 12285 2 @ 12314 5.0 TRIP GAS 27u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 1048 @ 12285 75 @ 12312 404.2 CONNECTION GAS HIGH ETHANE (C-2) 77 @ 12315 24 @ 12303 33.5 AVG PROPANE (C-3) 17 @ 12284 17 @ 12284 0.4 CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 5u/5u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 40% Sand, 40% Tuffaceous Sandstone, 20% Carbonaceous Shale PRESENT LITHOLOGY 40% Sand, 40% Tuffaceous Sandstone, 20% Carbonaceous Shale DAILY ACTIVITY SUMMARY Run in hole from 3883’ to 7995’ filling pipe every 2800’. Cut & slip drilling line 86’ cut off. Continue run in hole from 7995’ to 12212. Fill pipe at 10150’. Circulate and condition mud. MADD pass from 12257’ to 12284’. Directional drill from 12284’ to 12315’. Change out liner gasket mud pump #2 pod #3. Change out all 3 swabs on mud pump #2. Directional drill from 12315’ to 12330’. Circulating at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2905.00 REPORT BY Garnet Knopp Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Steve Lawrence DATE Jan 21, 2017 DEPTH 12417 PRESENT OPERATION Drilling TIME 24:00:00 YESTERDAY 12330 24 HOUR FOOTAGE 87 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 12,297.05 85.05 37.32 9,715.10 12,360.39 85.96 37.36 9,720.07 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 7 8.5" NOV/Reed DSH1813M-G3A E174093 8x12 12284' 133' 14.85 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 75.4 @ 12348 1.2 @ 12370 10.3 4.25 FT/HR SURFACE TORQUE 18662 @ 12385 919 @ 12399 6930.8 14810.30 FT-LBS WEIGHT ON BIT 18 @ 12400 0 @ 12403 12.3 17.43 KLBS ROTARY RPM 57 @ 12408 3 @ 12366 26.1 52.49 RPM PUMP PRESSURE 3559 @ 12389 2891 @ 12339 3310.1 3263.33 PSI DRILLING FLUIDS REPORT DEPTH 1/21/2017 MW 8.95 VIS 62 PV 21 YP 13 FL Gels 13/31/39 CL- FC 0/2 SOL 7.7 SD 0.05 OIL 87.9/12.1 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 12284 TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 8 @ 12376 3 @ 12406 5.8 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 867 @ 12388 275 @ 12393 556.3 CONNECTION GAS HIGH ETHANE (C-2) 137 @ 12384 17 @ 12332 73.7 AVG PROPANE (C-3) 82 @ 12377 82 @ 12377 1.0 CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 5u / 5u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 80% Tuffaceous sandstone/conglomerate 10% Carbonaceous shale 10% Tuffaceous siltstone PRESENT LITHOLOGY 80% Tuffaceous sandstone/conglomerate 10% Carbonaceous shale 10% Tuffaceous siltstone DAILY ACTIVITY SUMMARY Continue drilling as per directional driller to 12391’. Pump a sweep at 12386’ while rotating down to 12391’ and seea 30% increase in returns when sweep arrived 100bbls late. Continue to circulate until clean. Circulate with mud pump #2 while servicing HPU’s, tighten fluid pod on mud pump #1. Reconfigure flow meter on drawworks, tight en fittings on same and IBOP. Line up tool face and drill ahead to 12400’. Trouble shoot MWD tools then continue drilling ahead as per directional driller. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2905.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Steve Lawrence DATE Jan 22, 2017 DEPTH 12436 PRESENT OPERATION L/D BHA TIME 24:00:00 YESTERDAY 12417 24 HOUR FOOTAGE 19 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 7 8.5" NOV/Reed DSH1813M-G3A E174093 8x12 12284' 12436' 152' 17.95 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 37.5 @ 12419 1.0 @ 12434 8.0 1.04 FT/HR SURFACE TORQUE 14810 @ 12417 14810 @ 12417 871.2 FT-LBS WEIGHT ON BIT 17 @ 12417 1 @ 12421 6.5 7.55 KLBS ROTARY RPM 52 @ 12417 3 @ 12430 6.3 3.13 RPM PUMP PRESSURE 3423 @ 12421 3130 @ 12422 3472.8 3261.93 PSI DRILLING FLUIDS REPORT DEPTH 1/21/2017 MW 8.95 VIS 62 PV 21 YP 13 FL Gels 13/31/39 CL- FC 0/2 SOL 7.7 SD 0.05 OIL 87.9/12.1 MBT pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 5 @ 12421 3 @ 12424 5.1 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 549 @ 12418 222 @ 12424 424.0 CONNECTION GAS HIGH ETHANE (C-2) 94 @ 12417 26 @ 12419 62.5 AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 90% Conglomerate sand/sandstone 10% Carbonaceous shale PRESENT LITHOLOGY 90% Conglomerate sand/sandstone 10% Carbonaceous shale DAILY ACTIVITY SUMMARY Continue drilling ahead as per directional driller to 12436’, decision was made to pull out to inspect/change bit and BHA. Circulate while mixing dry job, pump dry job and pull out of hole. Switch to platform power at shoe and service rig. Continue pulling out of the hole and laying down BHA at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2905.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Steve Lawrence DATE Jan 23, 2017 DEPTH 12436 PRESENT OPERATION Tripping in hole TIME 24:00:00 YESTERDAY 12436 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 7 8.5" NOV/Reed DSH1813M-G3A E174093 8x12 12284' 12436' 106' 17.95 3-2-WT-A-X-2-PN PR 8 8.5" Varel T10846 4007887 8x12 12436' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 12436' MW 9.0 VIS 83 PV 31 YP 13 FL Gels 10/29/37 CL- FC 0/2 SOL 8.3 SD 0.05 OIL 89.0/11.0 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 12436' TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Finish laying down BHA and downloading MWD. Move BOP remote panel, wire in and function test. Make up BHA #13 and run into 8085’, filling pipe at 2843’, 5756’ and 8085’. Perform rig service and Cut and slip 119’ of drill line. Swap to rig power. Trip in to 9850’ and test MWD tools. Continue tripping in hole at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2905.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Steve Lawrence DATE Jan 24, 2017 DEPTH 12816 PRESENT OPERATION Drilling TIME 24:00:00 YESTERDAY 12436 24 HOUR FOOTAGE 380 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 12553.01 81.22 43.06 9739.99 12616.47 82.31 47.17 9749.08 12676.08 82.56 49.76 9756.94 12739.16 81.37 53.44 9765.76 12802.38 82.18 56.51 9774.81 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 8 8.5" Varel T10846 4007887 8x12 12436' 380' 13.00 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 270.6 @ 12718 1.5 @ 12453 39.4 29.64 FT/HR SURFACE TORQUE 16917 @ 12777 668 @ 12787 4438.3 15151.74 FT-LBS WEIGHT ON BIT 39 @ 12530 2 @ 12786 11.5 12.22 KLBS ROTARY RPM 59 @ 12579 2 @ 12664 19.0 55.08 RPM PUMP PRESSURE 3324 @ 12436 2632 @ 12527 2977.9 3156.05 PSI DRILLING FLUIDS REPORT DEPTH 12771 MW 9.05 VIS 63 PV 24 YP 13 FL Gels 13/31/37 CL- FC 0/2 SOL 8.2 SD 0.05 OIL 88.3/11.1 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 12436' TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 19 @ 12633 3 @ 12452 10.0 TRIP GAS 8u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 2474 @ 12633 183 @ 12466 1070.3 CONNECTION GAS HIGH ETHANE (C-2) 377 @ 12816 23 @ 12466 119.0 AVG PROPANE (C-3) 131 @ 12633 9 @ 12529 37.6 CURRENT BUTANE (C-4) 38 @ 12633 9 @ 12653 2.1 CURRENT BACKGROUND/AVG 12u / 10u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 80% Sand / Tuffaceous Sandstone 10% Siltstone 10% Carbonaceous shale PRESENT LITHOLOGY 80% Sand / Tuffaceous Sandstone 10% Siltstone 10% Carbonaceous shale DAILY ACTIVITY SUMMARY Continue running in hole. Wash and ream from 12305’to 12436’ and begin drilling. Drill to 12714’, pump a sweep, back 100bbls late with 50% increased cuttings. Continue drilling ahead at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2905.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Rick Brumly DATE Jan 25, 2017 DEPTH 13097 PRESENT OPERATION Repair HPU #1 TIME 24:00:00 YESTERDAY 12816 24 HOUR FOOTAGE 281 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 12864.83 82.61 56.73 9783.08 12927.85 82.8 56.25 9791.08 12990.43 82.49 56.34 9799.09 13050.98 82.43 56.09 9807.04 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 8 8.5" Varel T10846 4007887 8x12 12436' 661' 25.95 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 213.0 @ 13095 3.1 @ 12922 26.3 11.24 FT/HR SURFACE TORQUE 17310 @ 13032 233 @ 13094 14836.1 0.00 FT-LBS WEIGHT ON BIT 20 @ 12929 6 @ 13068 11.2 9.93 KLBS ROTARY RPM 56 @ 12869 2 @ 13095 52.3 2.70 RPM PUMP PRESSURE 3416 @ 13032 2535 @ 12874 3142.5 3128.75 PSI DRILLING FLUIDS REPORT DEPTH 13097 MW 9.05 VIS 71 PV 29 YP 14 FL Gels 13/33/37 CL- FC 0/2 SOL 8.8 SD 0.05 OIL 88.9/11.1 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 12436' TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 24 @ 13039 6 @ 13097 13.6 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 3414 @ 13041 533 @ 13097 1593.8 CONNECTION GAS HIGH ETHANE (C-2) 727 @ 13038 74 @ 12842 302.0 AVG PROPANE (C-3) 260 @ 13038 21 @ 13008 73.7 CURRENT BUTANE (C-4) 178 @ 13058 12 @ 13031 16.7 CURRENT BACKGROUND/AVG 5u / 13u PENTANE (C-5) 20 @ 13089 20 @ 13089 0.1 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 90% Sand / Tuffaceous sandsone 10% Carbonaceous shale PRESENT LITHOLOGY 100% Sand / Tuffaceous sandsone DAILY ACTIVITY SUMMARY Continue drilling ahead as per directional driller to 13097’ Fire in HPU #1. Kill HPU, secure well, muster/put out fire. After all clear, open well and pump with mud pump #2. Clean and repair HPU #1 room/area at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2905.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Rick Brumly DATE Jan 26, 2017 DEPTH 13186 PRESENT OPERATION Drilling TIME 24:00:00 YESTERDAY 13097 24 HOUR FOOTAGE 89 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 13112.98 83.05 56.19 9814.88 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 8 8.5" Varel T10846 4007887 8x12 12436' 750' 31.25 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 61.4 @ 13110 4.3 @ 13105 20.6 8.22877 FT/HR SURFACE TORQUE 16741 @ 13154 3233 @ 13102 13347.3 14065.20020 FT-LBS WEIGHT ON BIT 16 @ 13155 2 @ 13098 11.7 14.84000 KLBS ROTARY RPM 55 @ 13153 2 @ 13097 45.8 54.54000 RPM PUMP PRESSURE 3296 @ 13155 2940 @ 13098 3173.0 2996.13989 PSI DRILLING FLUIDS REPORT DEPTH 13155' MW 9.05 VIS 71 PV 22 YP 13 FL Gels 16/35/38 CL- FC 0/2 SOL 8.8 SD 0.05 OIL 88.9/11.1 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 12436' TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 11 @ 13153 6 @ 13099 9.3 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 1885 @ 13161 533 @ 13097 1230.5 CONNECTION GAS HIGH ETHANE (C-2) 282 @ 13175 31 @ 13098 195.8 AVG PROPANE (C-3) 39 @ 13150 14 @ 13108 26.8 CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 9u / 9u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 90% Tuffaceous sandstone / Sand 10% Carbonaceous shale PRESENT LITHOLOGY 100% Tuffaceous sandstone / Sand DAILY ACTIVITY SUMMARY Continue repairing/cleaning HPU #1 and area while circulating and working the string. Start up and function test HPU #1. Line up tool face and continue drilling as per directional driller. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2905.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Rick Brumley DATE Jan 27, 2017 DEPTH 13322 PRESENT OPERATION Pulling out of hole TIME 24:00:00 YESTERDAY 13186 24 HOUR FOOTAGE 136 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 13176.45 83.18 56.39 9822.49 13239.13 83.14 55.49 9829.96 13283.22 81.73 55.21 9835.76 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 8 8.5" Varel T10846 4007887 8x12 12436' 13322' 839 38.75 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 75.3 @ 13276 2.1 @ 13214 19.2 7.073 FT/HR SURFACE TORQUE 17536 @ 13277 13866 @ 13211 15535.6 15224.32 FT-LBS WEIGHT ON BIT 21 @ 13213 10 @ 13279 13.6 13.16 KLBS ROTARY RPM 59 @ 13209 47 @ 13191 54.0 52.70 RPM PUMP PRESSURE 3362 @ 13285 2821 @ 13190 3225.7 3034.09 PSI DRILLING FLUIDS REPORT DEPTH 13322 MW 9.1 VIS 84 PV 37 YP 14 FL Gels 12/34/38 CL- FC 0/2 SOL 8.8 SD 0.05 OIL 88.9/11.1 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 12436' TO TD TOOLS DGR/EWR GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 18 @ 13237 7 @ 13187 13.5 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 3089 @ 13237 668 @ 13199 1909.6 CONNECTION GAS HIGH ETHANE (C-2) 730 @ 13238 127 @ 13199 447.1 AVG PROPANE (C-3) 198 @ 13235 16 @ 13199 69.9 CURRENT BUTANE (C-4) 77 @ 13276 13 @ 13234 4.7 CURRENT BACKGROUND/AVG 2u / 12u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 90% Tuffaceous sandston / sand 10% Tuffaceous siltstone PRESENT LITHOLOGY 90% Tuffaceous sandston / sand 10% Tuffaceous siltstone DAILY ACTIVITY SUMMARY Continue drilling ahead as per directional driller to 13322’, pump high viscosity sweep and circulate hole clean. Take survey and obtain slow pump rates. Pull out of hole to 12834’. Bad spot in drilling line discovered, slip and cut 380’. Continue pulling out of hole to 7830’ and perform rig service. Continue pulling out of hole at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2905.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Rick Brumley DATE Jan 28, 2017 DEPTH 13322 PRESENT OPERATION Tripping in hole TIME 24:00:00 YESTERDAY 13322 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 8 8.5" Varel T10846 4007887 8x12 12436' 13322' 839 38.75 2-3-WT-A-X-1-CT TD 5rr1 8.5" HDBS MMD75DC 12451966 7x13 13322' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 13322' MW 9.1 VIS 127 PV 27 YP 14 FL Gels 13/33/36 CL- FC 0/2 SOL 8.8 SD 0.05 OIL 88.9/11.1 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 13322' TO 13322' TOOLS ALD/DGR/EWR/CTN GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 2u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue pulling out of hole and lay down 52 joints of drill pipe. Lay down BHA and MWD tools. Service rig. Pick up BHA #14 and upload MWD. Shallow hole test (good) and load nuclear sources. Tripping into hole at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2855.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Rick Brumley DATE Jan 29, 2017 DEPTH 13322 PRESENT OPERATION troubleshoot top drive TIME 24:00:00 YESTERDAY 13322 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5rr1 8.5" HDBS MMD75DC 12451966 7x13 13322' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 13322' (1/28/2017) MW 9.1 VIS 127 PV 27 YP 14 FL Gels 13/33/36 CL- FC 0/2 SOL 8.8 SD 0.05 OIL 88.9/11.1 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 13322' TO 13322' TOOLS ALD/DGR/EWR/CTN GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 4u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Finish running down to the shoe. Hang blocks and replace drilling line spool and cut and slip. Drain stack and pull 3 stands to completely empty. Fill stack and choke with water and rig up BOP testing equipment. Test BOPs then rig down equipment. Continue running in hole on elevators. Unable to get past 12497’ on elevators, jar free twice at 60K over. Wash and ream past tight spot and attempt to run in on elevators again (no go), attempt to wash with no rotary (no go). Wash and ream to 12783’. Cracked drive motor on top drive, troubleshooting at report time. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2095.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Rick Brumley DATE Jan 30, 2017 DEPTH 13322 PRESENT OPERATION Wash and ream into hole TIME 24:00:00 YESTERDAY 13322 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5rr1 8.5" HDBS MMD75DC 12451966 7x13 13322' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 13322' (1/28/2017) MW 9.05 VIS 75 PV 32 YP 14 FL Gels 15/37/40 CL- FC 0/2 SOL 8.3 SD 0.05 OIL 89.0/11.0 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 13322' TO 13322' TOOLS ALD/DGR/EWR/CTN GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 7u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Replace hydraulic motor on top drive and clean oil throughout the platform. Test motor (good) and continue running in hole for MAD pass. Unable to run in on elevators or wash with no rotary. Continue washing and reaming down to bottom at report time. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2095.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Marvin Rogers / Rick Brumley DATE Jan 31, 2017 DEPTH 13322 PRESENT OPERATION Run in hole TIME 24:00:00 YESTERDAY 13322 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5rr1 8.5" HDBS MMD75DC 12451966 7x13 13322' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 13322' (1/28/2017) MW 9.1 VIS 75 PV 31 YP 14 FL Gels 15/38/40 CL- FC 0/2 SOL 8.7 SD 0.05 OIL 88.9/11.1 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 13322' TO 13322' TOOLS ALD/DGR/EWR/CTN GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 9u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue washing and reaming to bottom. Take survey at bottom and begin MAD passing out. MAD pass out to 11,700 then begin running back to bottom to spot glass bead pill. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2095.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Rick Brumley DATE Feb 1, 2017 DEPTH 13322 PRESENT OPERATION Change out rams TIME 24:00:00 YESTERDAY 13322 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5rr1 8.5" HDBS MMD75DC 12451966 7x13 13322' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 13322' (1/28/2017) MW 9.1 VIS 75 PV 31 YP 14 FL Gels 15/38/40 CL- FC 0/2 SOL 8.7 SD 0.05 OIL 88.9/11.1 MBT pH Ca+ CCI MWD SUMMARY INTERVAL 13322' TO 13322' TOOLS ALD/DGR/EWR/CTN GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 3u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Run in hole to bottom, circulate and pump bead pill on bottom. Pump 84bbls and chase with 156bbls. Pump dry job and pull out of the hole. Lay down BHA and download MWD data. Service rig. Make up 7-5/8” test joint. Change out lower rams to 7-5/8” fixed bore rams. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2095.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Rick Brumley DATE Feb 2, 2017 DEPTH 13322 PRESENT OPERATION M/U liner hanger TIME 24:00:00 YESTERDAY 13322 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 13322' (1/28/2017) MW 9.3 VIS 170 PV 26 YP 15 FL Gels 19/33/3 CL- FC 0/2 SOL 8.9 SD 0.05 OIL 90.0/10.0 MBT pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Finish installing 7-5/8” rams and test. Rig down test joint and rig up casing equipment as per Weatherf ord. Begin running 7-5/8” casing, Drawworks break not releasing, troubleshoot and repair. Continue running 7-5/8” liner to 5445’. Rig up and circulate liner volume. Make up liner hanger as per BOT rep. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2095.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Rick Brumley DATE Feb 3, 2017 DEPTH 13322 PRESENT OPERATION Lay down 7-5/8" casing TIME 24:00:00 YESTERDAY 13322 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 13,322 MW 9.25 VIS 124 PV 25 YP 13 FL Gels 16/31/35 CL- FC 0/2 SOL 9.2 SD 0.05 OIL 90.0/10.0 MBT pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 47u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 11u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Finish making up liner hanger assembly as per BOT hand. Mix and fill baker fluid in liner. Trip in hole on drill pipe to 8026’ filling pipe every 10 stands. Cut and slip 184’ of drill line while circulating 1.5 bottoms up. Service rig and make up cement head as per BOT hand. Establish string parameters and trip into hole. Stacked out on window at 8068, attempt to work liner through window. Unable to work past 8071’ with 40k set down. Over pulled 42k multiple times to pull free. Town decision to pull out of hole. Pump dry job and begin pulling out of hole. Pull liner hanger above rotary, no damage, run back in hole one stand of drill pipe and stab TIW valve. Monitor well on trip tank while waiting for casing hands. Rig up casing equipment. Begin laying down 7-5/8” casing. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2095.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Rick Brumley DATE Feb 4, 2017 DEPTH 13322 PRESENT OPERATION Run in hole TIME 24:00:00 YESTERDAY 13322 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 13,322 (02/04/2017) MW 9.25 VIS 124 PV 25 YP 13 FL Gels 16/31/35 CL- FC 0/2 SOL 9.2 SD 0.05 OIL 90.0/10.0 MBT pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue laying down 7-5/8” casing and shoe track. Shoe cracked/split in 3 spots. Bottom of shoe gone and belled out. Unable to get 8-1/2” gauge ring over it. Lay down casing tools and perform rig service. Make up window dressing BHA as per BOT rep. Running in hole at report time. Canrig stand alone gas system installed and running. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2095.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Rick Brumley DATE Feb 5, 2017 DEPTH 13322 PRESENT OPERATION Circulating TIME 24:00:00 YESTERDAY 13322 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 13,322 (02/04/2017) MW 9.25 VIS 163 PV 29 YP 14 FL Gels 15/33/37 CL- FC 0/2 SOL 9.0 SD 0.05 OIL 90.0/10.0 MBT pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 72u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 38u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Trip into hole with milling assembly and circulate bottoms up. Get parameters and wash down to 8104’. Window was clean, rack back 2 stands. Monitor well for 30 min (static) and pump dry job. Trip out of hole, break pups and XO’s off cement head. Rack back HWDP, jars and clean magnets. 29 lbs collected from magnet. Boot baskets empty. Take flex joint out of BHA and make stiff assembly. Trip in hole to 8021’ and circulate bottoms up. Establish string parameters. Slack off and start taking weight (5k) at 8061’. Pick up and bring on rotary to 80 rpm. Ease in hole and start seeing work at 8058’. Inch in hole until cleaned up. Ream down to 8090’, ream up and down 3x. Able to slide in and out no rotary with no drag from 8055’ to 8097’. Circulate to condition mud before pulling out of hole. CANRIG PERSONNEL ON BOARD 1 DAILY COST $1475.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Rick Brumley DATE Feb 6, 2017 DEPTH 13322 PRESENT OPERATION Cut and slip TIME 24:00:00 YESTERDAY 13322 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 13,322 (02/06/2017) MW 9.15 VIS 123 PV 24 YP 13 FL Gels 16/35/39 CL- FC 0/2 SOL 8.9 SD 0.05 OIL 90.0/10.0 MBT pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 38u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue conditioning mud. Monitor well (slight drop), pump dry job, rig up stripping rubber and trip out of hole. Lay down BHA as per BOT rep. cleaned 61lbs off of magnets and 21lbs out of boot baskets (98% coal, 1lb iron). Clean and clear rig floor for trip in. Service rig and begin making up BHA as per BOT hand. Single into hole, filling pipe at 2225’. Tighten slack spot on drawworks. Continue picking up drill pipe, total joints picked up; 111 plus one single that was racked back in the derrick. 112 joints picked up, 10 joints on deck and 296 in the derrick. Run in hole out of derrick, fill pipe at 5200’. Continue running in hole to 8021’. Cut and slip drill line at report time. CANRIG PERSONNEL ON BOARD 1 DAILY COST $1475.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Rick Brumley DATE Feb 7, 2017 DEPTH 13322 PRESENT OPERATION Tripping out of hole TIME 24:00:00 YESTERDAY 13322 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 13,322 MW 9.15 VIS 73 PV 28 YP 13 FL Gels 15/35/39 CL- FC 0/2 SOL 8.9 SD 0.05 OIL 90.0/10.0 MBT pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 240u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 41u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Wash down to 8140’ then continue tripping into hole to 8655’. Stacked 10-15k, pick up 140k, slack off 82k. Jar stuck pipe. 19 jar licks up to 70k over. Wash down to 9700’. Circulate and work pipe then continue tripping in to 10656’. Circulate and work tight hole from 10631’ to 10639’. Circulate bottoms up. Continue tripping in to 11243’ and worked tight hole, 3 jar licks 45k over. Trip in to 11872’ and circulate while working pipe without rotating. Continue tripping in hole, washing when needed to 13322’. Condition mud and circulat e as per mud man. Monitor well (static). Spot 84bbl bead pill on backside, pumped slug and pull out of hole sideways. Tight spots encountered at 13170’, 13163’, 13096’, 12985’, 12944’, 12933, 12910’, 12895’ 12722’,12541’, 12520’, 11873’, 11660’, 11426’, 11315’, 11295’, 10750’, 10058’, 9923’, 9575’. Continuing to pull out at report time. CANRIG PERSONNEL ON BOARD 1 DAILY COST $1475.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Steve Lawrence DATE Feb 8, 2017 DEPTH 13322 PRESENT OPERATION Run in with 7-5/8" casing TIME 18:00:00 YESTERDAY 13322 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 13,322 MW 9.15 VIS 73 PV 28 YP 13 FL Gels 15/35/39 CL- FC 0/2 SOL 8.9 SD 0.05 OIL 90.0/10.0 MBT pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue pulling out of hole. Tight spots at 8567’, 8360’, 8185’, 8100’. Window looked good. Lay down BHA and perform rig service. Rig up 7-5/8” casing equipment and monitor hole (static). Begin running in with liner, laying down one bad joint and filling every 10 joints. CANRIG PERSONNEL ON BOARD 1 DAILY COST $1475.00 REPORT BY Josh Dubowski Hilcorp Alaska, LLC McArthur River Field DAILY WELLSITE REPORT TBU K06-RD2 REPORT FOR Shane Hauck / Steve Lawrence DATE Feb 9, 2017 DEPTH 13322 PRESENT OPERATION Run in with 7-5/8" casing TIME 18:00:00 YESTERDAY 13322 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 8062' (TOW) 8079' (BOW) SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 13,322 MW 9.15 VIS 134 PV 29 YP 14 FL Gels 15/35/39 CL- FC 0/2 SOL 8.9 SD 0.05 OIL 90.0/10.0 MBT pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 187u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 44u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY February 9, 2017 CANRIG PERSONNEL ON BOARD 1 DAILY COST $1475.00 REPORT BY Josh Dubowski
