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Home My WebLink About212-1491. 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): 11,550' N/A Casing Collapse Structural Conductor Surface 1,020 psi Intermediate 1,540 psi Production 4,760 psi Liner Hanger 6,300 psi Liner 4,760 psi Liner 5,410 psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Eric Dickerman Contact Email:Eric.Dickerman@hilcorp.com Contact Phone:907-564-4061 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 Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): Hilcorp Alaska, LLC Trading Bay Unit M-31B McArthur River Middle Kenai G & Hemlock Oil Proposed Pools: 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 Length Size 480' 480' N/A AOGCC USE ONLY L-80 8,657' Operations Manager Subsequent Form Required: Suspension Expiration Date: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018730 979' Other: C/O & Replace ESP 212-149 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20457-02-00 Same 9,854' 11,548' 9,853' 1,988 psi MD TVD Burst 3,090 psi 2,630 psi 979' 1,344' 3,524' 1,345' 480' 34" 26" 16" 979' 13-3/8"3,722' 1,345' 1,316' 8,725 - 9,798 2,629' 7" 32' 11,548' 1,315'9-5/8" Tubing Grade:Perforation Depth TVD (ft): 6,780 psi 9,853' 7,240 psi 1,347' 7,750 psi 2/13/2026 4-1/2" See schematic See schematic Perforation Depth MD (ft): 9,361 - 11,396 Tubing MD (ft): CO 228A 7,759' 9-5/8" 9,107' 8,488' 6,850 psi 1,316' 3,722' 10-3/4" 1,348' Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2026.01.30 12:30:57 - 09'00' Dan Marlowe (1267) 326-069 By Grace Chistianson at 1:17 pm, Jan 30, 2026 TS 2/2/26 10-404 CDW 01/30/2026 TS 2/2/26 TS 2/2/26 DSR-2/2/26BJM 2/6/26 X BOP test to 2500 psi JLC 2/6/2026 02/06/26 ESP Swap, Cleanout Well: Steelhead M-31B Well Name:M-31B API Number:50-733-20457-02-00 Current Status:ESP Oil Producer Leg:Oil Leg: B-1 (NW) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:212-149 First Call Engineer:Eric Dickerman (307) 250-4013 (c) Second Call Engineer:Dan Marlowe (907) 398-9904 (c) Maximum Expected BHP:2,810 psi at 8,222 TVD, 0.35 psi/ft 1/26/26 Static BHP (2 days) Max. Potential Surface Pressure:1,988 psi Using 0.1 psi/ft Brief Well Summary Steelhead M-31B is a G-zone and Hemlock oil producer in the McArthur River Field. It has historically produced at rates of 10,000+ bfpd when healthy. An ESP swap, cleanout and Hemlock re-perf was completed in March 2025. A Scale squeeze was performed 4/6/25. Fluid rates have remained around 7,500-8,000 bfpd since that time. The ESP failed with a suspected broken shaft on 1/24/26. Objective: Replace failed ESP, perform a cleanout if needed. Well information: Last casing test 7/29/2021, Set 7 test packer at 9,200. Tested 9-5/8 and 7 to 1,500 psi. - 1/24/26 ESP stopped surfacing fluid, suspected broken shaft - 4/6/25 Scale squeeze 100 gal of WAW-5206, and 439 bbl of 12.5% SCW-4004 - 3/14/25 No Flow Test passed - 3/1/25 Install and start new ESP - 2/25/25 Reperforate Hemlock zones on TCP 9,948-11,396 - 12/20-12/22/24: Punched hole in tubing and pumped 15% HCl to prep for workover - 12/3/24: ESP failed - 10/6/24: No Flow Test passed - 9/24/24: Pumped 15% HCl - 4/28/24: No Flow Test passed - 4/8/24: Safeacid soak o Pumped 100 bbls Safeacid down tubing through ESP, and displaced with 150 bbls FIW o Well on vac the whole time o Let soak for 5 days, then brought online. Successfully restored productivity - July/Aug-2021 o Pulled failed ESP o 8.75 SL gauge ring / junk basket drifted to 6,209 md (full of flat pack sheathing) o 5.8 SL gauge ring / junk basket drifted to 8,964 md Likely top 7 liner (came back empty) o 6 Bit/cleanout assembly tagged at 9,150 md. Wash and ream breaking through bridges to PBTD at 11,450 md o ~13bbls solids recovered from cleanout o Set 7 packer at 9,200. MIT to 1500psi above PASSED ESP Swap, Cleanout Well: Steelhead M-31B RWO Procedure: 1. MIRU HAK 404 2. Circulate well to KWF: a. Work over fluid will be filtered inlet water (8.4ppg). b. Tubing volume = 132 bbls c. IA to ESP = 463 bbls d. Casing to top perf below ESP = 37 bbl 3. Set BPV/TWC, ND tree, NU BOPs and test. a. Notify AOGCC 48 hours in advance for witness. b. BOP Test to 250psi Low /2,500psi High / 2,500psi Annular. c. BOPE will be used as needed to circulate the well. 4. Pull BPV/TWC. 5. BOLDS and unseat hanger. 6. POOH with 4-1/2 ESP completion. a. Contingent wireline drift and/or cleanout run on workstring to PBTD ~11,450 after inspection of the ESP at surface. 7. RIH with new ESP completion. a. Top of ESP to be set at ± 8,650 md. 8. Set BPV/TWC. 9. ND BOP. 10. NU tree and test, pull BPV/TWC. 11. RDMO RWO crew and equipment. Post-rig Work: 12. Turn well over to production. 13. Conduct SVS testing per AOGCC regulations. a. If cleanout is performed, schedule No Flow Test per AOGCC regulations. 14. Scale squeeze. a. RU pump and treating lines. b. Pressure test treating lines to 250psi low / 2,500psi high. c. Pump scale squeeze treatment and displace with FIW. Max pressure is 2,500 psi during displacement. d. RD pumping equipment. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Current/Proposed Wellhead Diagram (no changes) 4. BOP Drawing 5. 404 Fluid flow diagram 6. RWO Sundry Change Form Steelhead Platform Well #: M-31B Completed: 02/28/25 PTD#: 212-149 API#: 50-733-20457-02-00 REVISED BY: JLL 04/30/25 B 1 26 16 13-3/8 C D A 34 JEWELRY DETAIL NO Depth (MD) DEPTH (TVD) ID OD Item 74.50 74.50 Tubing hanger, FMC-TC-1A-EN-EC-CCL, 11 5M x 4 1/2 IBT lift and susp, w/ 4" Type H BPV profile, 2- 1/4" continuous control ports 1 8,657 8,068 - 4.000 Discharge sub 8,658 8,069 - Pump: 538 Series, 66 Stg SJ10000 (x3) 8,729 8,135 - Intake: 513, Intake Sub-Assy 8,730 8,136 Upper/Lower Tandem Seals - 513 Series BPBSBPB, Premium Seals 8,753 8,158 - Motors (2): 562 Motor, KMS3UT 500HP & 562 Motor, KMS3LT 500HP 8,822 8,222 - Centralizer/Anode 2 9,850 9,144 RA Marker PBTD: 11,548 MD / 9,853 TVD TD: 11,550 MD / 9,854 TVD TBG Hanger 74.5 below RKB CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 34 Surf 480 26"267 thru 397#Drill Quip Surf 979 16" 75 K-55 BTC 15.12 Surf 1,345 13-3/8" 61 & 68 K-55 BTC 12.42 Surf 3,722 9-5/8" Tieback 47# L-80 DWC/C 8.681 Surf 1,316 10-3/4 Liner hgr 65.7# L-80 BTC 9.5 1,316' 1,348 9-5/8" Liner 47# L-80 DWC/C 8.681 1,348 9,107 7 liner 26# L-80 VAM TOP HC 6.276 8,919 11,548 TUBING DETAIL 4-1/2 12.6 L-80 IBT-M 3.958 Surf 8,657 PERFORATION DETAIL Zone Top (MD) Btm(MD) Top (TVD) Btm(TVD) Length (MD) SPF Date G1 9,361' 9,390' 8,725 8,754 29' 5 2-20-2013 G2 9,425' 9,440' 8,786 8,801 15' 5 2-20-2013 G3 9,490' 9,526' 8,843 8,879 36' 5 2-23-2013 G4 9,535' 9,600' 8,885 8,950 65' 5 2-23-2013 G5 9,674 9,710 9,003 9,036 36' 5 2-23-2013 G5 9,720 9,739 9,030 9,049 19' 5 2-23-2013 HK1 9,948 9,987 9,214 9,241 39 2-25-2025 HK1 9,950 9,985 9,208 9,243 35' 5 2-23-2013 HK2 10,003 10,130 9,251 9,329 127' 5 2-23-2013 HK 3-4 10,188 10,600 9,360 9,541 412 2-25-2025 HK3-4 10,192 10,600 9,362 9,542 408' 5 2-23-2013 HK5 10,642 11,030 9,556 9,680 388 2-25-2025 HK5 10,642 10,834 9,556 9,617 192' 5 2-23-2013 HK5 10,866 11,030 9,628 9,680 164' 5 2-23-2013 HK6 11,082 11,279 9,696 9,759 197 2-25-2025 HK6 11,083 11,165 9,697 9,722 82' 5 2-23-2013 HK6 11,195 11,270 9,731 9,755 75' 5 2-23-2013 HK7 11,316 11,396 9,771 9,798 80 2-25-2025 HK7 11,360 11,396 9,785 9,798 36' 5 2-23-2013 SCHEMATIC CASING JEWELRY NO Depth (MD) Depth (TVD)ID OD Item A 1,316 1,315 Baker Flex-Lock Liner hanger & Baker HRD-E ZXP liner top packer (PKR INTENTIONALLY NOT SET!!) B 8,919 8,312 7 Liner top C 8,925 8,318 Baker JM-ZXP Liner Top Packer D 9,107 8,488 9-5/8 Casing Shoe Steelhead Platform Well #: M-31B Completed: 02/28/25 PTD#: 212-149 API#: 50-733-20457-02-00 REVISED BY: JLL 01/26/26 B 1 26 16 13-3/8 C D A 34 JEWELRY DETAIL NO Depth (MD) DEPTH (TVD) ID OD Item 74.50 74.50 Tubing hanger, FMC-TC-1A-EN-EC-CCL, 11 5M x 4 1/2 IBT lift and susp, w/ 4" Type H BPV profile, 2- 1/4" continuous control ports 1 ±8,655 ±8,066 - 4.000 Discharge sub - Pump - Intake Seals - Motor - Centralizer/Anode 2 9,850 9,144 RA Marker PBTD: 11,548 MD / 9,853 TVD TD: 11,550 MD / 9,854 TVD TBG Hanger 74.5 below RKB CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 34 Surf 480 26"267 thru 397#Drill Quip Surf 979 16" 75 K-55 BTC 15.12 Surf 1,345 13-3/8" 61 & 68 K-55 BTC 12.42 Surf 3,722 9-5/8" Tieback 47# L-80 DWC/C 8.681 Surf 1,316 10-3/4 Liner hgr 65.7#L-80 BTC 9.5 1,316' 1,348 9-5/8" Liner 47# L-80 DWC/C 8.681 1,348 9,107 7 liner 26# L-80 VAM TOP HC 6.276 8,919 11,548 TUBING DETAIL 4-1/2 Surf ±8,655 PERFORATION DETAIL Zone Top (MD) Btm(MD) Top (TVD) Btm(TVD) Length (MD) SPF Date G1 9,361' 9,390' 8,725 8,754 29' 5 2-20-2013 G2 9,425' 9,440' 8,786 8,801 15' 5 2-20-2013 G3 9,490' 9,526' 8,843 8,879 36' 5 2-23-2013 G4 9,535' 9,600' 8,885 8,950 65' 5 2-23-2013 G5 9,674 9,710 9,003 9,036 36' 5 2-23-2013 G5 9,720 9,739 9,030 9,049 19' 5 2-23-2013 HK1 9,948 9,987 9,214 9,241 39 2-25-2025 HK1 9,950 9,985 9,208 9,243 35' 5 2-23-2013 HK2 10,003 10,130 9,251 9,329 127' 5 2-23-2013 HK 3-4 10,188 10,600 9,360 9,541 412 2-25-2025 HK3-4 10,192 10,600 9,362 9,542 408' 5 2-23-2013 HK5 10,642 11,030 9,556 9,680 388 2-25-2025 HK5 10,642 10,834 9,556 9,617 192' 5 2-23-2013 HK5 10,866 11,030 9,628 9,680 164' 5 2-23-2013 HK6 11,082 11,279 9,696 9,759 197 2-25-2025 HK6 11,083 11,165 9,697 9,722 82' 5 2-23-2013 HK6 11,195 11,270 9,731 9,755 75' 5 2-23-2013 HK7 11,316 11,396 9,771 9,798 80 2-25-2025 HK7 11,360 11,396 9,785 9,798 36' 5 2-23-2013 PROPOSED CASING JEWELRY NO Depth (MD) Depth (TVD)ID OD Item A 1,316 1,315 Baker Flex-Lock Liner hanger & Baker HRD-E ZXP liner top packer (PKR INTENTIONALLY NOT SET!!) B 8,919 8,312 7 Liner top C 8,925 8,318 Baker JM-ZXP Liner Top Packer D 9,107 8,488 9-5/8 Casing Shoe Steelhead Platform M-31B Proposed Starting head, FMC, 30' MSS FE X 26' butt weld Adapter spool, FMC-A-5-S 30' MSS stdd bottom X 21 ¼ 2M FMC speedlock top, w/ 2- 2' LPO Unihead, FMC Type 2, 16 ¾ 5M FE top X 21 ¼ 2M FMC speedlock bottom, w/ 4- 2 1/16 5M SSO Tubing head, FMC-TC-60, spec for unihead, 16 ¾ 5M FE top X 16 ¾ 5M stdd bottom, w/ 2- 2 1/16 5M SSO Valve, FMC-120, 2 1/16 5M FE, HWO, AA 26' 16' 13 3/8' 9 5/8' 4 1/2 Steelhead Platform M-31B 26 X 16 X 13 3/8 X 9 5/8 X 4 1/2 Valve, Swab, WKM-M, 4 1/16 5M FE, HWO, DD Valve, Master, WKM-M, 4 1/16 5M FE, HWO, DD Valve, upper master, SSV, 4 1/16 5M FE, w/ 15' Safeco operator, EE BHTA, Bowen, 4 1/16 5M FE X 7-5SA Bowen top Valve, wing, WKM-M, 4 1/16 5M FE, HWO, DD Tbg hanger, FMC-TC-1A-EN- EC-CCL, 11 5M X 4 ½ IBT lift and susp, w/ 4' Type H BPV profile, 4- 1/4 continuous control line ports Adapter, FMC A-3-EC, 11 5M X 4 1/16 5M, prepped for BIW electro sub, 2- ½ npt continuous control line exits X4 control line Attachment spool, FMC-TC, 16 ¾ 5M stdd btm x 11 5M FE top, 12' in length, 10.00' min bore BOP Stack Rig 404 Shaffer SL 13 5/8 5M 2 7/8-5.5 variables Blinds 2.26' Riser 13 5/8 5M FE X 13 5/8 5M FE Spacer spool 13 5/8 5M FE X 11 5M 4.54' 2.83' Choke and Kill valves 2 1/16 5M Mud Cross 4 1/16 5M EFO 4.30'Hydril GK 13 5/8-5000 Spacer spool 13 5/8 5M X 13 5/8 5M Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well M-31B (PTD 212-149)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 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 April 17, 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 M-31B PTD 2121490 Dear Mr. Marlowe: On March 14, 2025, an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no-flow test of Trading Bay Unit M-31B located on the Steelhead 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 – repeated 1 additional time. There was no oil flow rates observed during the test, and gas flow rates never exceeded 200 scf/hour. Trading Bay Unit M-31B 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 M-31B 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 Steelhead Platform. Sincerely, James B. Regg Petroleum Inspection Supervisor ecc: P. Brooks AOGCC Inspectors James B. Regg Digitally signed by James B. Regg Date: 2025.04.17 09:02:36 -08'00' 2025-0314_No-Flow_TBU_M-31B_jh Page 1 of 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: 3/16/2025 P. I. Supervisor FROM: Josh Hunt SUBJECT: No Flow Test Petroleum Inspector Trading Bay Unit M-31B Hilcorp Alaska LLC PTD 2121490; Sundry 325-031 3/14/2025: I traveled to the Steelhead platform from the heliport at OSK dock and met with Brad Blossom (Lead on shift representing Hilcorp). We went over the certification paperwork for the pressure and low flow gauges. We also discussed the passing criteria for the no-flow test. They had a 1-inch manifold built with ½-inch hoses coming into and out of the manifold with isolation valves so the tubing and IA can communicate during the test. This set up worked very well for these circumstances with well spacing and congestion. The following table shows test details: Time Pressures1 Flow Rate2 Remarks (psi) Gas – scf/hr Liquid – gal/hr 11:06 0.29 / 0.33 / 80 0 0 Shut in 11:21 0.31 / 0.53 / 80 0 0 11:36 0.29 / 0.69 / 80 0 0 11:51 0.30 / 0.87 / 80 0 0 12:06 0.30 / 1.0 / 80 0 0 5 min flow test 12:12 0.54 / 0.75 / 80 0 0 Shut in; equalized T and IA 12:27 0.54 / 0.91 / 80 0 0 12:42 0.52 / 1.07 / 80 0 0 12:57 0.60 / 1.30 / 80 0 0 13:12 0.60 / 1.45 / 80 200 0 5 min flow 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 The no-flow was stopped after 2 flow periods meeting our acceptance criteria. Attachments: none 9 9 9 9 9 9 9 99 9 9 James B. Regg Digitally signed by James B. Regg Date: 2025.04.16 15:54:50 -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): 11,550'N/A Casing Collapse Structural Conductor Surface 1,020 psi Intermediate 1,540 psi Production 4,760 psi Liner 4,760 psi Liner 5,410 psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16.Verbal Approval: Date: GAS WAG GSTOR SPLUG 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 9,853' 7,240 psi CO 228A 7,759' 9-5/8" 9,107' 8,488' 6,850 psi 1,316' 3,722' 2/5/2025 4-1/2" See schematic See schematic Perforation Depth MD (ft): 9,361 - 11,396 1,316' 8,725 - 9,798 2,629' 7" 11,548' 1,315'9-5/8" 480' 34" 26" 16" 979' 13-3/8"3,722' 1,345' MD 3,090 psi 2,630 psi 979' 1,344' 3,524' 1,345' Length Size Proposed Pools: 480' 480' Same 9,854' 11,450' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018730 979' Other: C/O & Replace ESP AOGCC USE ONLY 12.6# / L-80 8,649' Operations Manager Subsequent Form Required: Suspension Expiration Date: 212-149 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20457-02-00 Hilcorp Alaska, LLC Trading Bay Unit M-31B TVD Burst 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 McArthur River Middle Kenai G & Hemlock Oil Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 6,780 psi 9,818' 2,241 psi N/A Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 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 12:12 pm, Jan 24, 2025 325-031 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2025.01.23 16:09:03 - 09'00' Dan Marlowe (1267) DSR-1/31/25 10-404 BOP test to 2500 psi Passing no-flow test is required after perforating within 21 days after return to production. BJM 1/27/25 Perforate SFD1/24/2025 X *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.03 15:53:06 -09'00'02/03/25 RBDMS JSB 020425 ESP Swap, Cleanout, Reperf Well: Steelhead M-31B Well Name:M-31B API Number:50-733-20457-02-00 Current Status:ESP Oil Producer Leg:Oil Leg: B-1 (NW) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:212-149 First Call Engineer:Casey Morse (603) 205-3780 (c) Second Call Engineer:Dan Marlowe (907) 398-9904 (c) Maximum Expected BHP:2,488 psi @ 8,186’ TVD 9/24/24 Static BHP (15 days) Max. Potential Surface Pressure: 2241 psi Using 0.1 psi/ft Brief Well Summary Steelhead M-31B is a G-zone / Hemlock oil producer. It has historically produced at rates of 10,000+ bfpd when healthy. The current ESP was run in August-2021. After that workover, gross fluid never returned to previous levels. Fluid production declined rapidly in March/April of 2024. A Safeacid soak restored fluid rates above 6000bfpd in April 2024, and production rapidly declined again. Additional acid treatments were unsuccessful in restoring productivity. The ESP since failed with suspected broken shaft. The goal of this project is to swap the ESP, perform a cleanout, and reperforate the Hemlock zones to restore full productivity of the well. Pertinent wellbore information: - 12/20-12/22/24: Punched hole in tubing and pumped 15% HCl to prep for workover - 12/3/24: ESP failed - 10/6/24: No Flow Test passed - 9/24/24: Pumped 15% HCl - 4/28/24: No Flow Test passed - 4/8/24: Safeacid soak o Pumped 100bbls Safeacid down tubing through ESP, and displaced with 150bbls FIW o Well on vac the whole time o Let soak for 5 days, then brought online. Successfully restored productivity - July/Aug-2021 o Pulled failed ESP o 8.75” SL gauge ring / junk basket drifted to 6209’ MD (full of flat pack sheathing) o 5.8” SL gauge ring / junk basket drifted to 8964’ MD – Likely top 7” liner (came back empty) o 6” Bit/cleanout assembly tagged at 9150’ MD. Wash and ream breaking through bridges to PBTD at 11,450’ MD o ~13bbls solids recovered from cleanout o Set 7’ packer at 9,200’. MIT to 1500psi above PASSED RWO Procedure: 1. MIRU HAK 404 2. Circulate well: a. Work over fluid will be filtered inlet water (8.4ppg) reperforate the Hemlock ESP Swap, Cleanout, Reperf Well: Steelhead M-31B b. Ensure any wellbore fluids are fully displaced with KWF either via circulation or bullheading c. Tubing volume = 132bbls d. IA to ESP = 463bbls e. Casing to top perf below ESP = 20 + 17 = 37bbl 3. Set BPV/TWC, ND tree, NU Hilcorp BOP stack (see attached) a. Notify AOGCC 48 hours in advance for witness b. Test to 250psi Low /2,500psi High / 2,500psi Annular c. BOPE will be used as needed to circulate the well 4. Pull BPV/TWC 5. BOLDS and unseat hanger 6. POOH with 4-1/2” ESP/GL completion 7. PU cleanout BHA on workstring and clean out well to PBTD ~11,450’. 8. MU TCP guns on workstring. TIH to shooting depth per Engineer’s perf table. a. Contingent: RU Eline and run gamma correlation pass to confirm depth 9. Actuate firing head to perforate Hemlock zones 10. Circulate well clean, and ensure static, POOH with TCP guns. 11. Pickup new ESP completion and RIH. a. Top of ESP to be set at ±8,650’ MD 12. Set BPV/TWC, ND BOP 13. NU tree and test, pull BPV/TWC 14. RDMO RWO crew and equipment Post-rig Work: 15. Turn well over to production. 16. Conduct SVS testing per AOGCC regulations. 17. Schedule No Flow Test per AOGCC regulations 18. Contingent scale squeeze: discuss with OE if necessary a. RU pump and treating lines b. Pressure test all to 250psi low and 2500psi high c. Pump scale squeeze treatment if required and displace with FIW, keeping treating pressure <2500psi during displacement d. RD pumping equipment Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Current/Proposed Wellhead Diagram (no changes) 4. BOP Drawing 5. 404 Fluid flow diagram 6. RWO Sundry Change Form Steelhead Platform Well #: M-31B Completed: 08/03/2021 PTD#: 212-149 API#: 50-733-20457-02-00 REVISED BY: JLL 12/27/24 2 B 4 26” 16” 13-3/8” 1 C D A 3 Tbg Punch 8,560-8,563 12/20/24 34 X JEWELRY DETAIL NO Depth (MD) DEPTH (TVD) ID OD Item 74.50 74.50 Tubing hanger, FMC-TC-1A-EN-EC-CCL, 11 5M x 4 1/2 IBT lift and susp, w/ 4" Type H BPV profile, 2- 1/4" continuous control ports 1 463’ 463’ 3.813 6.600 4.5” Baker S-5 TRSV 2 490’ 490’ 3.958 4.500 9 5/8"D&L ESP PACKER 40k straight pull release 3 8,609’ 8,023’ 3.813 5.010 X-Nipple 4 8,649’ 8,060’ - 6.750 DSCG, BTN, 4 1/2, 8RD EUE, 416/420SS, 675X, PN:900031005 8,650’ 8,061’ -6.750 Pump: (x2) - 675 Series, 45 Stg SH13000CCW, 1:1 Ar, Inconel Shaft, XTRO, 3160 P/N 103031258 8,693’ 8,101’ - 6.750 Intake: 675-513 Series, Intake Sub-Assy, A/R X2, INC, 416SS, P/N 900600078 8,695’ 8,103’ 5.130 Upper/Lower Tandem Seals – BPBSBPB 8,717’ 8,124’ - 5.620 Motors (x2)– 562, KMSLT 500 HP/ 562, KMSUT 500 HP 8,783’ 8,186’ - 5.620 Centralizer/Anode PBTD: 11,450 MD / 9,818’ TVD TD: 11,550’ MD / 9,854’ TVD TBG Hanger 74.5’ below RKB CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 34” Surf 480’ 26"267 thru 397#Drill Quip Surf 979’ 16" 75 K-55 BTC 15.12 Surf 1,345’ 13-3/8" 61 & 68 K-55 BTC 12.42 Surf 3,722’ 9-5/8" Tieback 47# L-80 DWC/C 8.681 Surf 1,316’ 10-3/4” Liner hgr 65.7# L-80 BTC 9.5 1,316' 1,348’ 9-5/8" Liner 47# L-80 DWC/C 8.681 1,348’ 9,107’ 7” liner 26# L-80 VAM TOP HC 6.276 8,919’ 11,548’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT-M 3.958 Surf 8,649’ PERFORATION DETAIL Zone Top (MD) Btm(MD) Top (TVD) Btm(TVD) Length (MD) SPF Date G1 9,361' 9,390' 8,725’ 8,754’ 29' 5 2-20-2013 G2 9,425' 9,440' 8,786’ 8,801’ 15' 5 2-20-2013 G3 9,490' 9,526' 8,843’ 8,879’ 36' 5 2-23-2013 G4 9,535' 9,600' 8,885’ 8,950’ 65' 5 2-23-2013 G5 9,674’ 9,710’ 9,003’ 9,036’ 36' 5 2-23-2013 G5 9,720’ 9,739’ 9,030’ 9,049’ 19' 5 2-23-2013 HK1 9,950’ 9,985’ 9,208’ 9,243’ 35' 5 2-23-2013 HK2 10,003’ 10,130’ 9,251’ 9,329’ 127' 5 2-23-2013 HK3-4 10,192’ 10,600’ 9,362’ 9,542’ 408' 5 2-23-2013 HK5 10,642’ 10,834’ 9,556’ 9,617’ 192' 5 2-23-2013 HK5 10,866’ 11,030’ 9,628’ 9,680’ 164' 5 2-23-2013 HK6 11,083’ 11,165’ 9,697’ 9,722’ 82' 5 2-23-2013 HK6 11,195’ 11,270’ 9,731’ 9,755’ 75' 5 2-23-2013 HK7 11,360’ 11,396’ 9,785’ 9,798’ 36' 5 2-23-2013 SCHEMATIC CASING JEWELRY NO Depth (MD) Depth (TVD)ID OD Item A 1,316’ 1,315’ Baker Flex-Lock Liner hanger & Baker HRD-E ZXP liner top packer (PKR INTENTIONALLY NOT SET!!) B 8,919’ 8,312’ 7” Liner top C 8,925’ 8,318’ Baker JM-ZXP Liner Top Packer D 9,107’ 8,488’ 9-5/8” Casing Shoe Steelhead Platform Well #: M-31B Completed: FUTURE PTD#: 212-149 API#: 50-733-20457-02-00 REVISED BY: CDM 1/21/25 B 1 26” 16” 13-3/8” C D A 34 JEWELRY DETAIL NO Depth (MD) DEPTH (TVD) ID OD Item 74.50 74.50 Tubing hanger, FMC-TC-1A-EN-EC-CCL, 11 5M x 4 1/2 IBT lift and susp, w/ 4" Type H BPV profile, 2- 1/4" continuous control ports 1 ±8,650’ ±8,060’-Discharge sub -Pumps -Intake sub Upper/Lower Tandem Seals -Motors -Centralizer/Anode PBTD: 11,450 MD / 9,818’ TVD TD: 11,550’ MD / 9,854’ TVD TBG Hanger 74.5’ below RKB CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 34” Surf 480’ 26"267 thru 397#Drill Quip Surf 979’ 16" 75 K-55 BTC 15.12 Surf 1,345’ 13-3/8" 61 & 68 K-55 BTC 12.42 Surf 3,722’ 9-5/8" Tieback 47# L-80 DWC/C 8.681 Surf 1,316’ 10-3/4” Liner hgr 65.7# L-80 BTC 9.5 1,316' 1,348’ 9-5/8" Liner 47# L-80 DWC/C 8.681 1,348’ 9,107’ 7” liner 26# L-80 VAM TOP HC 6.276 8,919’ 11,548’ TUBING DETAIL 4-1/2” 3.958 Surf ±8,650’ PERFORATION DETAIL Zone Top (MD) Btm(MD) Top (TVD) Btm(TVD) Length (MD) SPF Date G1 9,361' 9,390' 8,725’ 8,754’ 29' 5 2-20-2013 G2 9,425' 9,440' 8,786’ 8,801’ 15' 5 2-20-2013 G3 9,490' 9,526' 8,843’ 8,879’ 36' 5 2-23-2013 G4 9,535' 9,600' 8,885’ 8,950’ 65' 5 2-23-2013 G5 9,674’ 9,710’ 9,003’ 9,036’ 36' 5 2-23-2013 G5 9,720’ 9,739’ 9,030’ 9,049’ 19' 5 2-23-2013 HK1-7 ±9,945’ ±11,400’ ±9,205’ ±9,800’ Proposed HK1 9,950’ 9,985’ 9,208’ 9,243’ 35' 5 2-23-2013 HK2 10,003’ 10,130’ 9,251’ 9,329’ 127' 5 2-23-2013 HK3-4 10,192’ 10,600’ 9,362’ 9,542’ 408' 5 2-23-2013 HK5 10,642’ 10,834’ 9,556’ 9,617’ 192' 5 2-23-2013 HK5 10,866’ 11,030’ 9,628’ 9,680’ 164' 5 2-23-2013 HK6 11,083’ 11,165’ 9,697’ 9,722’ 82' 5 2-23-2013 HK6 11,195’ 11,270’ 9,731’ 9,755’ 75' 5 2-23-2013 HK7 11,360’ 11,396’ 9,785’ 9,798’ 36' 5 2-23-2013 PROPOSED CASING JEWELRY NO Depth (MD) Depth (TVD)ID OD Item A 1,316’ 1,315’ Baker Flex-Lock Liner hanger & Baker HRD-E ZXP liner top packer (PKR INTENTIONALLY NOT SET!!) B 8,919’ 8,312’ 7” Liner top C 8,925’ 8,318’ Baker JM-ZXP Liner Top Packer D 9,107’ 8,488’ 9-5/8” Casing Shoe Steelhead Platform M-31B Proposed Starting head, FMC, 30'’ MSS FE X 26'’ butt weld Adapter spool, FMC-A-5-S 30'’ MSS stdd bottom X 21 ¼ 2M FMC speedlock top, w/ 2- 2'’ LPO Unihead, FMC Type 2, 16 ¾ 5M FE top X 21 ¼ 2M FMC speedlock bottom, w/ 4- 2 1/16 5M SSO Tubing head, FMC-TC-60, spec for unihead, 16 ¾ 5M FE top X 16 ¾ 5M stdd bottom, w/ 2- 2 1/16 5M SSO Valve, FMC-120, 2 1/16 5M FE, HWO, AA 26'’ 16'’ 13 3/8'’ 9 5/8'’ 4 1/2 Steelhead Platform M-31B 26 X 16 X 13 3/8 X 9 5/8 X 4 1/2 Valve, Swab, WKM-M, 4 1/16 5M FE, HWO, DD Valve, Master, WKM-M, 4 1/16 5M FE, HWO, DD Valve, upper master, SSV, 4 1/16 5M FE, w/ 15'’ Safeco operator, EE BHTA, Bowen, 4 1/16 5M FE X 7-5SA Bowen top Valve, wing, WKM-M, 4 1/16 5M FE, HWO, DD Tbg hanger, FMC-TC-1A-EN- EC-CCL, 11 5M X 4 ½ IBT lift and susp, w/ 4'’ Type H BPV profile, 4- 1/4 continuous control line ports Adapter, FMC A-3-EC, 11 5M X 4 1/16 5M, prepped for BIW electro sub, 2- ½ npt continuous control line exits X4 control line Attachment spool, FMC-TC, 16 ¾ 5M stdd btm x 11 5M FE top, 12'’ in length, 10.00'’ min bore BOP Stack Rig 404 Shaffer SL 13 5/8 5M 2 7/8-5.5 variables Blinds 2.26' Riser 13 5/8 5M FE X 13 5/8 5M FE Spacer spool 13 5/8 5M FE X 11 5M 4.54' 2.83' Choke and Kill valves 2 1/16 5M Mud Cross 4 1/16 5M EFO 4.30'Hydril GK 13 5/8-5000 DSA 4 X 2DSA 4 X 2Spacer spool 13 5/8 5M X 13 5/8 5M HILCORP ALASKA, LLC Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well M-31B (PTD 212-149)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. 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 11,550 feet N/A feet true vertical 9,854 feet N/A feet Effective Depth measured 11,450 feet See Schematic feet true vertical 9,818 feet See Schematic feet Perforation depth Measured depth 9,361 - 11,396 feet True Vertical depth 8,725 - 9,798 feet Tubing (size, grade, measured and true vertical depth) 4-1/2" L-80 8,649 (MD) 8,060 (TVD) Packers and SSSV (type, measured and true vertical depth) See schematic 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: Middle Kenai G & 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: 1,540psi 4,760psi 2,630psi 3,090psi 6,780psi 1,345 1,344 Burst Collapse 1,020psi measured TVD Production Liner 3,722 1,316 2,629 Casing Structural 3,524 1,315 7" 3,722 1,316 11,548 9,853 979 1,345 979Conductor Surface Intermediate 34" 26" 16" 13-3/8" 7,240psi 9-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 212-149 50-733-20457-02-00 3. Address: Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 N/A 5. Permit to Drill Number:2. Operator Name N 4. Well Class Before Work: ADL0018730 McArthur River / Middle Kenai G & Hemlock Oil Trading Bay Unit M-31B Plugs Junk measured Length 480 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 480 9,361 - 11,396 366 Size 480 979 0460 82 1033582 39 324-413 Sr Pet Eng: 5,410psi Sr Pet Geo: Sr Res Eng: WINJ WAG 151 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Casey Morse casey.morse@hilcorp.com 907 777-8322Operations Manager 110 bbl of 15% HCl w/IA closed, displace w/ 90bbl of DW, 0 psi / 98bbls 15% HCl, displace w/ 132 bbls FIW, 0 psi. Liner Hanger Liner 32 10-3/4" 1,348 1,347 7,750psi 6,300psi 7,759 9-5/8" 9,107 8,488 6,850psi 4,760psi 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 8:31 am, Jan 21, 2025 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2025.01.20 11:14:53 - 09'00' Dan Marlowe (1267) RBDMS JSB 012825 CDW 01/21/2025 DSR-1/22/25BJM 2/7/25 Steelhead Platform Well #: M-31B Completed: 08/03/2021 PTD#: 212-149 API#: 50-733-20457-02-00 REVISED BY: JLL 12/27/24 2 B 4 26” 16” 13-3/8” 1 C D A 3 Tbg Punch 8,560-8,563 12/20/24 34 X JEWELRY DETAIL NO Depth (MD) DEPTH (TVD) ID OD Item 74.50 74.50 Tubing hanger, FMC-TC-1A-EN-EC-CCL, 11 5M x 4 1/2 IBT lift and susp, w/ 4" Type H BPV profile, 2- 1/4" continuous control ports 1 463’ 463’ 3.813 6.600 4.5” Baker S-5 TRSV 2 490’ 490’ 3.958 4.500 9 5/8"D&L ESP PACKER 40k straight pull release 3 8,609’ 8,023’ 3.813 5.010 X-Nipple 4 8,649’ 8,060’ - 6.750 DSCG, BTN, 4 1/2, 8RD EUE, 416/420SS, 675X, PN:900031005 8,650’ 8,061’ -6.750 Pump: (x2) - 675 Series, 45 Stg SH13000CCW, 1:1 Ar, Inconel Shaft, XTRO, 3160 P/N 103031258 8,693’ 8,101’ - 6.750 Intake: 675-513 Series, Intake Sub-Assy, A/R X2, INC, 416SS, P/N 900600078 8,695’ 8,103’ 5.130 Upper/Lower Tandem Seals – BPBSBPB 8,717’ 8,124’ - 5.620 Motors (x2)– 562, KMSLT 500 HP/ 562, KMSUT 500 HP 8,783’ 8,186’ - 5.620 Centralizer/Anode PBTD: 11,450 MD / 9,818’ TVD TD: 11,550’ MD / 9,854’ TVD TBG Hanger 74.5’ below RKB CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 34” Surf 480’ 26"267 thru 397#Drill Quip Surf 979’ 16" 75 K-55 BTC 15.12 Surf 1,345’ 13-3/8" 61 & 68 K-55 BTC 12.42 Surf 3,722’ 9-5/8" Tieback 47# L-80 DWC/C 8.681 Surf 1,316’ 10-3/4” Liner hgr 65.7# L-80 BTC 9.5 1,316' 1,348’ 9-5/8" Liner 47# L-80 DWC/C 8.681 1,348’ 9,107’ 7” liner 26# L-80 VAM TOP HC 6.276 8,919’ 11,548’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT-M 3.958 Surf 8,649’ PERFORATION DETAIL Zone Top (MD) Btm(MD) Top (TVD) Btm(TVD) Length (MD) SPF Date G1 9,361' 9,390' 8,725’ 8,754’ 29' 5 2-20-2013 G2 9,425' 9,440' 8,786’ 8,801’ 15' 5 2-20-2013 G3 9,490' 9,526' 8,843’ 8,879’ 36' 5 2-23-2013 G4 9,535' 9,600' 8,885’ 8,950’ 65' 5 2-23-2013 G5 9,674’ 9,710’ 9,003’ 9,036’ 36' 5 2-23-2013 G5 9,720’ 9,739’ 9,030’ 9,049’ 19' 5 2-23-2013 HK1 9,950’ 9,985’ 9,208’ 9,243’ 35' 5 2-23-2013 HK2 10,003’ 10,130’ 9,251’ 9,329’ 127' 5 2-23-2013 HK3-4 10,192’ 10,600’ 9,362’ 9,542’ 408' 5 2-23-2013 HK5 10,642’ 10,834’ 9,556’ 9,617’ 192' 5 2-23-2013 HK5 10,866’ 11,030’ 9,628’ 9,680’ 164' 5 2-23-2013 HK6 11,083’ 11,165’ 9,697’ 9,722’ 82' 5 2-23-2013 HK6 11,195’ 11,270’ 9,731’ 9,755’ 75' 5 2-23-2013 HK7 11,360’ 11,396’ 9,785’ 9,798’ 36' 5 2-23-2013 SCHEMATIC CASING JEWELRY NO Depth (MD) Depth (TVD)ID OD Item A 1,316’ 1,315’ Baker Flex-Lock Liner hanger & Baker HRD-E ZXP liner top packer (PKR INTENTIONALLY NOT SET!!) B 8,919’ 8,312’ 7” Liner top C 8,925’ 8,318’ Baker JM-ZXP Liner Top Packer D 9,107’ 8,488’ 9-5/8” Casing Shoe Page 1/1 Well Name: MRF M-31B Report Printed: 1/9/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:8/26/2024 End Date: Report Number 2 Report Start Date 9/24/2024 Report End Date 9/25/2024 Last 24hr Summary Spot acid tank and pump. Conduct equipment checks. Tie in surface lines to M-31-B. Tie in DW supply line. Pressure test surface line to 250/ 1500 psi. Tie in IA line to production for returns. Walk lines and verify line ups. Report Number 3 Report Start Date 9/25/2024 Report End Date 9/26/2024 Last 24hr Summary PJSM and sign onto PTW. Verify line up. Stage up pump slowly to 2.0 bpm. Pump 200bbl. of DW while monitoring pump pressure, intake and discharge pressure. No returns up the IA. Close IA, bring pump up to 2.0 bpm @ 150-350 psi, inject 50bbl while monitoring intake and discharge pressure. Retest surface line to 250/2000 psi for 5/5 min as per sundry. Pump 110 bbl of 15% HCl w/IA closed. Pump at 2.0 bpm at 350 psi while monitoring intake and discharge pressure. Displace acid with 90bbl of DW at 1.5 bpm at 350 psi, monitor intake and discharge pressure. Shut down pump, monitor bleed off to 0 psi in 3 min. Close SV, let acid soak for 5 hrs. Flush and RD all equipment. Demob crew. Report Number 4 Report Start Date 10/6/2024 Report End Date 10/7/2024 Last 24hr Summary No Flow test witnessed by Austin McLeod. Verbal PASS. Report Number 5 Report Start Date 12/20/2024 Report End Date 12/20/2024 Last 24hr Summary PJSM and permit. MIRU AK Eline. PT 250/2000 PSI. Good. RIH w/ 2" x 12 shot tubing punch. Log above ESP jewelry. Send tie in log to town. Town designated 8560' MD shot depth. Fired tubing shot w/ 56 PSI on TBG/IA. Good shot. POOH. RDMO to M-25. Plan forward: Acid pump job 12/22/24. Report Number 6 Report Start Date 12/22/2024 Report End Date 12/23/2024 Last 24hr Summary PJSM, PTW, Rig up pump lines, fill lines & PT 250/2000psi good, pump 126 bbls down tubing @2 bbls min 0 psi, pump 98 bbls 15%HCL acid, chase w/132bbls FIW @2bpm, 0 psi, shut down on vac, shut in let soak 5 hours. Pump 350bbls FIW t/ flush acid pill. Field: McArthur River Field Sundry #: 324-413 State: ALASKA Rig/Service:Permit to Drill (PTD) #:212149Permit to Drill (PTD) #:193190 Wellbore API/UWI:50733204570000 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 19, 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 M-31B PTD 2121490 Dear Mr. Marlowe: On October 6, 2024, an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no-flow test of Trading Bay Unit M-31B located on the Steelhead 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 one additional time. There was no oil nor gas flow observed during the no-flow test. Trading Bay Unit M-31B 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 M-31B 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 Steelhead Platform. Sincerely, James B. Regg Petroleum Inspection Supervisor ecc: P. Brooks AOGCC Inspectors James B. Regg Digitally signed by James B. Regg Date: 2024.11.20 09:20:12 -09'00' 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): 11,550'N/A Casing Collapse Structural Conductor Surface 1,020 psi Intermediate 1,540 psi Production 4,760 psi Liner 4,760 psi Liner 5,410 psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16.Verbal Approval: Date: GAS WAG GSTOR SPLUG 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 Other: 9,853' 7,240 psi N/A 7,759' 9-5/8" 9,107' 8,488' 6,850 psi 1,316' 3,722' 8/1/2024 4-1/2" See schematic See schematic Perforation Depth MD (ft): 9,361 - 11,396 1,316' 8,725 - 9,798 2,629' 7" 11,548' 1,315'9-5/8" 480' 34" 26" 16" 979' 13-3/8"3,722' 1,345' MD 3,090 psi 2,630 psi 979' 1,344' 3,524' 979' 1,345' Length Size Proposed Pools: 480' 480' 12.6# / L-80 TVD Burst 8,649' 6,780 psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018730 212-149 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20457-02-00 Hilcorp Alaska, LLC Trading Bay Unit M-31B AOGCC USE ONLY 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 McArthur River Middle Kenai G & Hemlock Oil Same 9,854' 11,450' 9,818' 2,389 psi 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 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.07.17 15:07:35 - 08'00' Dan Marlowe (1267) 324-413 S By Grace Christianson at 4:39 pm, Jul 17, 2024 A.Dewhurst 23JUL24 CDW 07/17/2024 10-404 BJM 7/24/24 DSR-7/17/24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.07.25 08:47:05 -08'00' 07/25/24 RBDMS JSB 073024 Acid Well: Steelhead M-31B Well Name:M-31B API Number:50-733-20457-02-00 Current Status:ESP Oil Producer Leg:Oil Leg: B-1 (NW) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:212-149 First Call Engineer:Ryan Rupert (907) 301-1736 (c) Second Call Engineer:Dan Marlowe (907) 398-9904 (c) Maximum Expected BHP:3,369 psi @ 9,800’ TVD 4/14/24 Static BHP Max. Potential Surface Pressure: 2389 psi Using 0.1 psi/ft Brief Well Summary Steelhead M-29B is a G-zone / Hemlock oil producer. It produces at 5000+ bfpd when healthy. It’s current ESP was run in August-2021. Gross fluid declined rapidly in March/April of 2024. A Safeacid soak restored fluid rates above 6000bfpd. It is beginning to show repeat signs of diminished productivity It is possible that scale is to blame. The goal of this project is to remediate downhole damage and return the well to full production Pertinent wellbore information: - 4/28/24: No Flow Test passed - 4/8/24: Safeacid soak o Pumped 100bbls Safeacid down tubing through ESP, and displaced with 150bbls FIW o Well on vac the whole time o Let soak for 5 days, then brought online. Successfully restored productivity - July/Aug-2021 o Pulled failed ESP o 8.75” SL gauge ring / junk basket drifted to 6209’ MD (full of flat pack sheathing) o 5.8” SL gauge ring / junk basket drifted to 8964’ MD – Likely top 7” liner (came back empty) o 6” Bit/cleanout assembly tagged at 9150’ MD. Was and ream breaking through bridges to PBTD at 11,450’ MD o ~13bbls solids recovered from cleanout o Set 7’ packer at 92,00’. MIT to 1500psi above PASSED Acid Stimulation Procedure 1. RU pump and treating lines 2. Pressure test all to 250psi low and 2000psi high (pump limitation = 2000psi) 3. Pump Mutual solvent/Xylene pre flush if required 4. Pump acid pill (5-15% concentration HCL, or Oilsafe AR-Synthetic acid) to stimulate perforations 5. Displace pill and spot across perfs with FIW keeping treating pressure <2000psi during displacement 6. RD pumping equipment 7. Let acid soak (duration per OE) Attachments: 1. Current Wellbore Schematic (no changes) M-29B is a Steelhead Platform Well #: M-31B Completed: 08/03/2021 PTD#: 212-149 API#: 50-733-20457-02-00 REVISED BY: JLL 08/23/21 2 B 4 26” 16” 13-3/8” 1 C D A 3 34 X JEWELRY DETAIL NO Depth (MD) DEPTH (TVD) ID OD Item 74.50 74.50 Tubing hanger, FMC-TC-1A-EN-EC-CCL, 11 5M x 4 1/2 IBT lift and susp, w/ 4" Type H BPV profile, 2- 1/4" continuous control ports 1 463’ 463’ 3.813 6.600 4.5” Baker S-5 TRSV 2 490’ 490’ 3.958 4.500 9 5/8"D&L ESP PACKER 40k straight pull release 3 8,609’ 8,023’ 3.813 5.010 X-Nipple 4 8,649’ 8,060’ - 6.750 DSCG, BTN, 4 1/2, 8RD EUE, 416/420SS, 675X, PN:900031005 8,650’ 8,061’ -6.750 Pump: (x2) - 675 Series, 45 Stg SH13000CCW, 1:1 Ar, Inconel Shaft, XTRO, 3160 P/N 103031258 8,693’ 8,101’ - 6.750 Intake: 675-513 Series, Intake Sub-Assy, A/R X2, INC, 416SS, P/N 900600078 8,695’ 8,103’ 5.130 Upper/Lower Tandem Seals – BPBSBPB 8,717’ 8,124’ - 5.620 Motors (x2)– 562, KMSLT 500 HP/ 562, KMSUT 500 HP 8,783’ 8,186’ - 5.620 Centralizer/Anode PBTD: 11,450 MD / 9,818’ TVD TD: 11,550’ MD / 9,854’ TVD TBG Hanger 74.5’ below RKB CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 34” Surf 480’ 26"267 thru 397#Drill Quip Surf 979’ 16" 75 K-55 BTC 15.12 Surf 1,345’ 13-3/8" 61 & 68 K-55 BTC 12.42 Surf 3,722’ 9-5/8" Tieback 47# L-80 DWC/C 8.681 Surf 1,316’ 10-3/4” Liner hgr 65.7# L-80 BTC 9.5 1,316' 1,348’ 9-5/8" Liner 47# L-80 DWC/C 8.681 1,348’ 9,107’ 7” liner 26# L-80 VAM TOP HC 6.276 8,919’ 11,548’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT-M 3.958 Surf 8,649’ PERFORATION DETAIL Zone Top (MD) Btm(MD) Top (TVD) Btm(TVD) Length (MD) SPF Date G1 9,361' 9,390' 8,725’ 8,754’ 29' 5 2-20-2013 G2 9,425' 9,440' 8,786’ 8,801’ 15' 5 2-20-2013 G3 9,490' 9,526' 8,843’ 8,879’ 36' 5 2-23-2013 G4 9,535' 9,600' 8,885’ 8,950’ 65' 5 2-23-2013 G5 9,674’ 9,710’ 9,003’ 9,036’ 36' 5 2-23-2013 G5 9,720’ 9,739’ 9,030’ 9,049’ 19' 5 2-23-2013 HK1 9,950’ 9,985’ 9,208’ 9,243’ 35' 5 2-23-2013 HK2 10,003’ 10,130’ 9,251’ 9,329’ 127' 5 2-23-2013 HK3-4 10,192’ 10,600’ 9,362’ 9,542’ 408' 5 2-23-2013 HK5 10,642’ 10,834’ 9,556’ 9,617’ 192' 5 2-23-2013 HK5 10,866’ 11,030’ 9,628’ 9,680’ 164' 5 2-23-2013 HK6 11,083’ 11,165’ 9,697’ 9,722’ 82' 5 2-23-2013 HK6 11,195’ 11,270’ 9,731’ 9,755’ 75' 5 2-23-2013 HK7 11,360’ 11,396’ 9,785’ 9,798’ 36' 5 2-23-2013 SCHEMATIC CASING JEWELRY NO Depth (MD) Depth (TVD)ID OD Item A 1,316’ 1,315’ Baker Flex-Lock Liner hanger & Baker HRD-E ZXP liner top packer (PKR INTENTIONALLY NOT SET!!) B 8,919’ 8,312’ 7” Liner top C 8,925’ 8,318’ Baker JM-ZXP Liner Top Packer D 9,107’ 8,488’ 9-5/8” Casing Shoe 2024-1006_No-Flow_TBU M-31B_am Page 1 of 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: 10/9/2024 P. I. Supervisor FROM: Austin McLeod SUBJECT: No Flow Test Petroleum Inspector Trading Bay Unit M-31B Hilcorp Alaska, LLC PTD 2121490 10/6/2024: I traveled to the Steelhead platform and met with Ryan Wilcox to witness the subsequent no-flow test on well M-31B after stimulation work had been done. The well is an ESP completion with a high-set vented packer. On 9/25/2024 an acid soak – approved Sundry 324-413 – had been done after the well’s production fell off. M-31B had been opened to bleed on 10/4/2024 at 13:00 hours. I verified pressure gauges and flow meter in use were calibrated and orientated in the proper direction, control line supply to packer vent valve/subsurface safety valve was pressurized and that the platform’s means of injection, Well M-30, was online. The tubing and inner annulus were in communication via test equipment. We monitored pressures every 15 minutes and opened to the low-flow meter on the hour 2 times for 1 minute. The following table shows test details: Time Pressures1 Flow Rate2 Remarks (psi) Gas – scf/hr Liquid – gal/hr 9:30 0 / 0 / 84 9:45 0.02 / 0.02 / 84 10:00 0.05 / 0.04 / 84 10:15 0.06 / 0.06 / 84 10:30 0.09 / 0.1 / 84 0 0 Open to meter (60sec); S/I. 10:47 0.12 / 0.12 / 84 11:02 0.13 / 0.14 / 84 11:17 0.16 / 0.16 / 84 11:32 0.19 / 0.19 / 84 0 0 Open to meter (60sec); slight feel at end of the hose. 1 Pressures are T/IA/OA 2 Gas flow not to exceed 900 scf/hr; Liquid flow not to exceed 6.3 gal/hr I found the well incapable of flow to surface. Attachments: none 9 9 9 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2024.11.19 11:35:56 -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: Oil Safe AR (Acid Soak) Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 11,550 feet N/A feet true vertical 9,854 feet N/A feet Effective Depth measured 11,450 feet See Schematic feet true vertical 9,818 feet See Schematic feet Perforation depth Measured depth 9,361 - 11,396 feet True Vertical depth 8,725 - 9,798 feet Tubing (size, grade, measured and true vertical depth) 4-1/2" L-80 8,649 (MD) 8,060 (TVD) Packers and SSSV (type, measured and true vertical depth) See schematic 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: Middle Kenai G & 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: 1,540psi 4,760psi 2,630psi 3,090psi 6,780psi 1,345 1,344 Burst Collapse 1,020psi measured TVD Production Liner 3,722 1,316 2,629 Casing Structural 3,524 1,315 7" 3,722 1,316 11,548 9,853 979 1,345 979Conductor Surface Intermediate 34" 26" 16" 13-3/8" 7,240psi 9-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 212-149 50-733-20457-02-00 3. Address: Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 N/A 5. Permit to Drill Number:2. Operator Name N 4. Well Class Before Work: ADL0018730 McArthur River / Middle Kenai G & Hemlock Oil Trading Bay Unit M-31B Plugs Junk measured Length 480 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) 102 Gas-Mcf MD 480 9,361 - 11,396 76 Size 480 979 5862 79111 136 734565 75 324-183 Sr Pet Eng: 5,410psi Sr Pet Geo: Sr Res Eng: WINJ WAG 104 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Karson Kozub kkozub@hilcorp.com 907 570-1801Operations Manager Pumped 4,125 gallons safe acid followed by 150 BBLS H20. Final pressure 0psi. Liner Hanger Liner 32 10-3/4" 1,348 1,347 7,750psi 6,300psi 7,759 9-5/8" 9,107 8,488 6,850psi 4,760psi Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov S By Grace Christianson at 10:24 am, May 01, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.05.01 08:53:15 - 08'00' Dan Marlowe (1267) SFD 2/13/2025 RBDMS JSB 051324 DSR-5/1/24 CDW 05/01/2024 Steelhead Platform Well #: M-31B Completed: 08/03/2021 PTD#: 212-149 API#: 50-733-20457-02-00 REVISED BY: JLL 08/23/21 2 B 4 26” 16” 13-3/8” 1 C D A 3 34 X JEWELRY DETAIL NO Depth (MD) DEPTH (TVD) ID OD Item 74.50 74.50 Tubing hanger, FMC-TC-1A-EN-EC-CCL, 11 5M x 4 1/2 IBT lift and susp, w/ 4" Type H BPV profile, 2- 1/4" continuous control ports 1 463’ 463’ 3.813 6.600 4.5” Baker S-5 TRSV 2 490’ 490’ 3.958 4.500 9 5/8"D&L ESP PACKER 40k straight pull release 3 8,609’ 8,023’ 3.813 5.010 X-Nipple 4 8,649’ 8,060’ - 6.750 DSCG, BTN, 4 1/2, 8RD EUE, 416/420SS, 675X, PN:900031005 8,650’ 8,061’ -6.750 Pump: (x2) - 675 Series, 45 Stg SH13000CCW, 1:1 Ar, Inconel Shaft, XTRO, 3160 P/N 103031258 8,693’ 8,101’ - 6.750 Intake: 675-513 Series, Intake Sub-Assy, A/R X2, INC, 416SS, P/N 900600078 8,695’ 8,103’ 5.130 Upper/Lower Tandem Seals – BPBSBPB 8,717’ 8,124’ - 5.620 Motors (x2)– 562, KMSLT 500 HP/ 562, KMSUT 500 HP 8,783’ 8,186’ - 5.620 Centralizer/Anode PBTD: 11,450 MD / 9,818’ TVD TD: 11,550’ MD / 9,854’ TVD TBG Hanger 74.5’ below RKB CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 34” Surf 480’ 26"267 thru 397#Drill Quip Surf 979’ 16" 75 K-55 BTC 15.12 Surf 1,345’ 13-3/8" 61 & 68 K-55 BTC 12.42 Surf 3,722’ 9-5/8" Tieback 47# L-80 DWC/C 8.681 Surf 1,316’ 10-3/4” Liner hgr 65.7# L-80 BTC 9.5 1,316' 1,348’ 9-5/8" Liner 47# L-80 DWC/C 8.681 1,348’ 9,107’ 7” liner 26# L-80 VAM TOP HC 6.276 8,919’ 11,548’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT-M 3.958 Surf 8,649’ PERFORATION DETAIL Zone Top (MD) Btm(MD) Top (TVD) Btm(TVD) Length (MD) SPF Date G1 9,361' 9,390' 8,725’ 8,754’ 29' 5 2-20-2013 G2 9,425' 9,440' 8,786’ 8,801’ 15' 5 2-20-2013 G3 9,490' 9,526' 8,843’ 8,879’ 36' 5 2-23-2013 G4 9,535' 9,600' 8,885’ 8,950’ 65' 5 2-23-2013 G5 9,674’ 9,710’ 9,003’ 9,036’ 36' 5 2-23-2013 G5 9,720’ 9,739’ 9,030’ 9,049’ 19' 5 2-23-2013 HK1 9,950’ 9,985’ 9,208’ 9,243’ 35' 5 2-23-2013 HK2 10,003’ 10,130’ 9,251’ 9,329’ 127' 5 2-23-2013 HK3-4 10,192’ 10,600’ 9,362’ 9,542’ 408' 5 2-23-2013 HK5 10,642’ 10,834’ 9,556’ 9,617’ 192' 5 2-23-2013 HK5 10,866’ 11,030’ 9,628’ 9,680’ 164' 5 2-23-2013 HK6 11,083’ 11,165’ 9,697’ 9,722’ 82' 5 2-23-2013 HK6 11,195’ 11,270’ 9,731’ 9,755’ 75' 5 2-23-2013 HK7 11,360’ 11,396’ 9,785’ 9,798’ 36' 5 2-23-2013 SCHEMATIC CASING JEWELRY NO Depth (MD) Depth (TVD)ID OD Item A 1,316’ 1,315’ Baker Flex-Lock Liner hanger & Baker HRD-E ZXP liner top packer (PKR INTENTIONALLY NOT SET!!) B 8,919’ 8,312’ 7” Liner top C 8,925’ 8,318’ Baker JM-ZXP Liner Top Packer D 9,107’ 8,488’ 9-5/8” Casing Shoe Well Name:MRF M-31B API #:50733204570000 Field:McArthur River Field Start Date:4/8/2024 Permit #:193190 Sundry #:324-183 End Date:4/28/2024 4/8/2024 4/14/2024 4/26/2024 4/28/2024 Well Operations Summary SD ESP for No-flow @ 0845hrs M-31B passed no-flow test at 12:24hrs Line up down well and pump 2 bbl H20. Test lines to 2500 psi. Good. Open up well & Pump 4,125gal safe acid . Well on vac during pumping. Pump lost prime at 75 bbl away. Pump remaining acid & 150 BBL H20 with 3'' transfer pump down well. Surface pressure showing 0 at pump. Shut in well at. 20:00. Wait 5 days on safe acid soak. Start ESP at 0623hrs, fluid rate fell off and was low (1900BPD) until 0851hrs, formation broke free and fluid rate returned to historical rates (6300BPD) Daily Operations: Page 1 of 1 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 20, 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 M-31B PTD 2121490 Dear Mr. Marlowe: On April 28, 2024, an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no-flow test of Trading Bay Unit M-31B located on the Steelhead 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 M- 31B 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 M-31B 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 Steelhead Platform. Sincerely, James B. Regg Petroleum Inspection Supervisor ecc: P. Brooks AOGCC Inspectors James B. Regg Digitally signed by James B. Regg Date: 2024.05.20 10:58:55 -08'00' 2024-0428_No-Flow_TBU_M-31B_ss Page 1 of 4 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: 5/16/2024 P. I. Supervisor FROM: Sully Sullivan SUBJECT: No Flow Test Petroleum Inspector TBU M-31B Hilcorp Alaska LLC PTD 2121490; Sundry 324-183 4/28/2024: I traveled to the Trading Bay Unit Steelhead platform and met with operators Steve Josephson, Anna Cizek and George Peters to witness the no flow test of well M-31B. We went over testing procedures and visually inspected the test set up. An Armor-Flo SCFH meter and a calibrated digital pressure gauge were used for the test with lines coming from the IA and Tubing connected by a manifold with isolating valves that bleed to atmosphere in a 55-gallon drum. The following table shows test details: Time Pressures1 Flow Rate2 Remarks (psi) Gas – scf/hr Liquid – gal/hr 10:18 0 /0 / 78 0 0 Start of test 10:33 0.06 / 0 / 78 10:48 0.09 / 0 / 78 11:03 0.11 / 0 / 78 11:18 0.14 / 0 / 78 0 0 11:23 0.01 / 0 / 78 0 0 11:38 0.12 / 0 / 78 11:53 0.15 / 0 / 78 12:08 0.18 / 0 / 78 12:23 0.21 / 0 / 78 0 0 End of good 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 easily met passing requirements for a no flow well. Attachments: Photos (5)    2024-0428_No-Flow_TBU_M-31B_ss Page 2 of 4 No-Flow Test Equipment – TBU M-31B (PTD 2121490) Photos by AOGCC Inspector S. Sullivan 4/28/2024 2024-0428_No-Flow_TBU_M-31B_ss Page 3 of 4 2024-0428_No-Flow_TBU_M-31B_ss Page 4 of 4 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): 11,550' N/A Casing Collapse Structural Conductor Surface 1,020 psi Intermediate 1,540 psi Production 4,760 psi Liner Hanger 6,300 psi Liner 4,760 psi Liner 5,410 psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Karson Kozub Contact Email:kkozub@hilcorp.com Contact Phone:907-570-1801 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: Oil Safe AR (Acid Soak) 8,488' 6,850 psi N/A 32' 10-3/4" 1,348' 1,347' 7,750 psi 1,316' 3,722' 4/21/2024 11,548'2,629' 4-1/2" 9,853' See schematic See schematic Perforation Depth MD (ft): 9,361 - 11,396 1,316' 7" 8,725 - 9,798 7,759' 9-5/8" 9,107' 1,315'9-5/8" 480' 34" 26" 16" 979' 13-3/8"3,722' 1,345' MD 3,090 psi 2,630 psi 979' 1,344' 3,524' 979' 1,345' Length Size Proposed Pools: 480' 480' 12.6# / L-80 TVD Burst 8,649' 6,780 psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018730 212-149 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20457-02-00 Hilcorp Alaska, LLC Trading Bay Unit M-31B AOGCC USE ONLY 7,240 psi 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 McArthur River Middle Kenai G & Hemlock Oil Same 9,854' 11,450' 9,818' 2,128 psi 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 8:50 am, Mar 27, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.03.27 06:08:14 - 08'00' Dan Marlowe (1267) SFD 3/28/2024 CDW 03/27/2024 10-404 BJM 3/29/24 JLC 4/5/2024 Well Work Prognosis Well: M-31B Well Name:M-31B API Number: 50-733-20457-02-00 Current Status:ESP Producer Leg:B-1 (NW Corner) Estimated Start Date:04/21/2024 Rig:N/A Reg. Approval Reqd?403 Date Reg. Approval Recvd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:212-149 First Call Engineer:Karson Kozub (907) 570-1801 (M) Second Call Engineer:Ryan Rupert (907) 301-1736 (M) Current Bottom Hole Pressure:2,947 psi @ 8,186 TVD 0.360 psi/ft based on ESP Gauge Aug 2021 Maximum Expected BHP:2,947 psi @ 8,186 TVD 0.360 psi/ft based on ESP Gauge Aug 2021 Max. Potential Surface Pressure:2,128 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) ***This is a no flow well as of 05/11/2018 Brief Well Summary M-31B is a G / Hemlock Producer completed with an ESP. Total fluid production has decreased significantly over the past year. This decrease is believed to have been caused by scale formation due to comingled production across the perforated interval. Well Objective Hilcorp plans to pump an Oil Safe AR (safe acid) soak down the production tubing, out the ESP intake, and down across the perfs, to clean up any scale deposition. Procedure: 1. MIRU pumping equipment. 2. Shut down ESP. 3. Pressure test surface lines to ±2,250 psi 4. Line up pumping down the tubing 5. Pump ±4,125 gallons of Oil Safe AR (Synthetic acid) 15 totes of acid 6. Pump ±150 bbls water to spot the safe acid across the perforated interval. 7. Shut down pump and let acid soak for ±120 hours. 8. RD Pumping equipment. 9. Return well to production. 10. Schedule a No-Flow test within 14 days of stable production. Attachments: 1. Current Well Schematic 2. Fluid Flow Diagrams 3. Oil Safe AR Technical Data Sheet Steelhead Platform Well #: M-31B Completed: 08/03/2021 PTD#: 212-149 API#: 50-733-20457-02-00 REVISED BY: JLL 08/23/21 2 B 4 26 16 13-3/8 1 C D A 3 34 X JEWELRY DETAIL NO Depth (MD) DEPTH (TVD) ID OD Item 74.50 74.50 Tubing hanger, FMC-TC-1A-EN-EC-CCL, 11 5M x 4 1/2 IBT lift and susp, w/ 4" Type H BPV profile, 2- 1/4" continuous control ports 1 463 463 3.813 6.600 4.5 Baker S-5 TRSV 2 490 490 3.958 4.500 9 5/8"D&L ESP PACKER 40k straight pull release 3 8,609 8,023 3.813 5.010 X-Nipple 4 8,649 8,060 - 6.750 DSCG, BTN, 4 1/2, 8RD EUE, 416/420SS, 675X, PN:900031005 8,650 8,061 -6.750 Pump: (x2) - 675 Series, 45 Stg SH13000CCW, 1:1 Ar, Inconel Shaft, XTRO, 3160 P/N 103031258 8,693 8,101 - 6.750 Intake: 675-513 Series, Intake Sub-Assy, A/R X2, INC, 416SS, P/N 900600078 8,695 8,103 5.130 Upper/Lower Tandem Seals BPBSBPB 8,717 8,124 - 5.620 Motors (x2) 562, KMSLT 500 HP/ 562, KMSUT 500 HP 8,783 8,186 - 5.620 Centralizer/Anode PBTD: 11,450 MD / 9,818 TVD TD: 11,550 MD / 9,854 TVD TBG Hanger 74.5 below RKB CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 34 Surf 480 26"267 thru 397#Drill Quip Surf 979 16" 75 K-55 BTC 15.12 Surf 1,345 13-3/8" 61 & 68 K-55 BTC 12.42 Surf 3,722 9-5/8" Tieback 47# L-80 DWC/C 8.681 Surf 1,316 10-3/4 Liner hgr 65.7# L-80 BTC 9.5 1,316' 1,348 9-5/8" Liner 47# L-80 DWC/C 8.681 1,348 9,107 7 liner 26# L-80 VAM TOP HC 6.276 8,919 11,548 TUBING DETAIL 4-1/2 12.6 L-80 IBT-M 3.958 Surf 8,649 PERFORATION DETAIL Zone Top (MD) Btm(MD) Top (TVD) Btm(TVD) Length (MD) SPF Date G1 9,361' 9,390' 8,725 8,754 29' 5 2-20-2013 G2 9,425' 9,440' 8,786 8,801 15' 5 2-20-2013 G3 9,490' 9,526' 8,843 8,879 36' 5 2-23-2013 G4 9,535' 9,600' 8,885 8,950 65' 5 2-23-2013 G5 9,674 9,710 9,003 9,036 36' 5 2-23-2013 G5 9,720 9,739 9,030 9,049 19' 5 2-23-2013 HK1 9,950 9,985 9,208 9,243 35' 5 2-23-2013 HK2 10,003 10,130 9,251 9,329 127' 5 2-23-2013 HK3-4 10,192 10,600 9,362 9,542 408' 5 2-23-2013 HK5 10,642 10,834 9,556 9,617 192' 5 2-23-2013 HK5 10,866 11,030 9,628 9,680 164' 5 2-23-2013 HK6 11,083 11,165 9,697 9,722 82' 5 2-23-2013 HK6 11,195 11,270 9,731 9,755 75' 5 2-23-2013 HK7 11,360 11,396 9,785 9,798 36' 5 2-23-2013 SCHEMATIC CASING JEWELRY NO Depth (MD) Depth (TVD)ID OD Item A 1,316 1,315 Baker Flex-Lock Liner hanger & Baker HRD-E ZXP liner top packer (PKR INTENTIONALLY NOT SET!!) B 8,919 8,312 7 Liner top C 8,925 8,318 Baker JM-ZXP Liner Top Packer D 9,107 8,488 9-5/8 Casing Shoe Oil Safe AR® is a safe yet functional replacement for traditional hydrochloric acid treatments and other commonly used oilfield acid treatments. It is non-regulated by US DOT, Canadian TDG and carries a triple zero hazardous materials information system score. Oil Safe AR® biodegrades in10 days or less and is approved by the US EPA as a Designed for the Environment product. Our standard Oil Safe AR® formula includes iron control agents, de-mulsifiers and requires no organic acid additions or corrosion inhibitors under most conditions. FEATURES AND BENEFITS: An excellent choice for fracs, spearhead treatments, injection wells and dis- posal wells and annular soaks Requires no organic acid additions to help retard reaction rates Standard formula includes surfactant and de-mulsifier system Requires no iron control agent addition for most applications EPA DfE formula; biodegradable in 10 days or less; approved for direct dis- charge; made with Cleangredients and DfE ingredients approved by the EPA Safe on most metals, piping and pumping equipment Non toxic; non fuming; non mutagenic; no VOCs No secondary containment required as per Chapter 62-761F.A.C. Eliminates foulants An excellent choice for work-over projects, bullhead treatments and cement remediation Requires no additional corrosion inhibitor step for most applications 100% biodegradable, acid free and naturally inhibited TYPICAL PHYSICAL PROPERTIES: Appearance and Color Colorless to slight yellow liquid Initial Freeze Point -24.88ºF (-31.6ºC) Odor Odorless to mild soapy odor Solubility in water 100% Flashpoint None Specific Gravity 1.152 ± 0.04 DIRECTIONS FOR USE: Recommended Dilution Rates: 30-100% with H²O based on the severity of the build-up and the reaction rate required for the project. Note: Oil Safe AR® concentrate contains iron control agents and de-mulsifiers. No organic acid or corrosion inhibitors are required due to the power of our patented Syntech®. A typical ratio for an acid frac is one part Oil Safe AR® and one part H²O. Blending ratios may vary based on specific applications and recommendations from your consultants at Heartland Energy Group, Ltd. STORAGE AND HANDLING: Oil Safe AR® has a storage life of better than one year. Keep container closed when not in use. As with all chemical products and materials, take care as to where you store them. Safety glasses are suggested for use when handling this product. No special gloves or protective equipment are required when handling this product. When pumping this product, it is strongly recommended to use manufacturer approved hose couplings or fittings. DO NOT USE ALUMINUM FITTINGS. 316 Stainless Steel, polypropylene, polyethylene are recommended. PACKAGING: Oil Safe AR® is shipped in bulk tanker trucks from the manufacturing facility. Smaller packaging quantities are available upon request. Recommendations given in this data sheet are based on tests believed to be reliable. However, the use of the information is beyond the control of Heartland Energy Group, Ltd., and no guarantee, ex- pressed or implied is made to the results obtained if not used in accordance with directions or established safe practice. The buyer must assume all responsibility, including injury or damage from the misuse of the product as such, or in combination with other materials. This bulletin is not to be taken as a license to operate under or recommendation to infringe any patent. DISSOLVING PROPERTIES ACID TYPE % CaCO³ Oil Safe AR® 100% Solution 100.00% Oil Safe AR® 50% Solution 96.76% Oil Safe AR® 30% Solution 54.00 7 ½HCI 46.48% 15% HCI 87.39% 7½ HCI + 100 gpt of 85% Acetic Acid 75.08% 15% HCI + 100 gpt of 85% Acetic Acid 97.87% 10% Acetic Acid 21.00% 15% Acetic Acid 63.09% Each test above was conducted with 1 cubic inch of material placed in 50 ml of solution and allowed to soak for 8 hrs at 100ºF. 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Replace ESP Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 11,550 feet N/A feet true vertical 9,854 feet N/A feet Effective Depth measured 11,450 feet 490 / 1,316 / 8,925 feet true vertical 9,818 feet 490 / 1,315 / 8,318 feet Perforation depth Measured depth 9,361 - 11,396 feet True Vertical depth 8,725 - 9,798 feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 8,649 MD 8,060 TVD D&L ESP PKR 490 (MD) / 490 (TVD) Packers and SSSV (type, measured and true vertical depth) HRD-E ZXP 1,316 (MD) / 1,315 (TVD)TRSV: Baker S-5 463 (MD) / 463 (TVD) JM-ZXP 8,925 (MD) 8,318 (TVD) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Authorized Title: Contact Email: Contact Phone: Hilcorp Alaska, LLC 2. Operator Name Senior Engineer: Senior Res. Engineer: 7,240psi Daniel E. Marlowe Operations Manager Burst Collapse Karson Kozub kkozub@hilcorp.com Tubing Pressure 1,020psi 1,540psi 2,630psi 3,090psi 907 777-8434 6,780psi 979 1,344 3,524 1,315 9,853 7,750psi 6,300psi 979 1,345 Conductor Surface 5,410psi 4,760psi 26" 16" 13-3/8" 3,722 1,316 Size 81 Production Casing Structural Liner 2,629 Length 480 Intermediate N/A Junk 5. Permit to Drill Number: 208 McArthur River Field / Middle Kenai G & Hemlock Oil PoolsN/A measured 3,722 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 345 Gas-Mcf 55 N/A Oil-Bbl 0 Water-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-263 81 Authorized Signature with date: Authorized Name: 10,040 WINJ WAG STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 212-149 50-733-20457-02-00 Plugs ADL0018730 Trading Bay Unit M-31B measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 100 Casing Pressure 9-5/8" 7" 34" 1,316 MD 480 979 1,345 11,548 TVD 480 measured true vertical Packer Liner Hanger 32 10-3/4" 1,348 1,347 4,760psiLiner7,759 9-5/8" 9,107 8,488 6,850psi Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 6:49 pm, Aug 25, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.08.25 13:45:27 -08'00' Dan Marlowe (1267) BJM 10/19/21 SFD 8/26/2021RBDMS HEW 8/26/2021 DSR-8/26/21 Steelhead Platform Well #: M-31B Completed: 08/03/2021 PTD#: 212-149 API#: 50-733-20457-02-00 REVISED BY: JLL 08/23/21 2 B 4 26” 16” 13-3/8” 1 C D A 3 34 X JEWELRY DETAIL NO Depth (MD) DEPTH (TVD) ID OD Item 74.50 74.50 Tubing hanger, FMC-TC-1A-EN-EC-CCL, 11 5M x 4 1/2 IBT lift and susp, w/ 4" Type H BPV profile, 2- 1/4" continuous control ports 1 463’ 463’ 3.813 6.600 4.5” Baker S-5 TRSV 2 490’ 490’ 3.958 4.500 9 5/8"D&L ESP PACKER 40k straight pull release 3 8,609’ 8,023’ 3.813 5.010 X-Nipple 4 8,649’ 8,060’ - 6.750 DSCG, BTN, 4 1/2, 8RD EUE, 416/420SS, 675X, PN:900031005 8,650’ 8,061’ -6.750 Pump: (x2) - 675 Series, 45 Stg SH13000CCW, 1:1 Ar, Inconel Shaft, XTRO, 3160 P/N 103031258 8,693’ 8,101’ - 6.750 Intake: 675-513 Series, Intake Sub-Assy, A/R X2, INC, 416SS, P/N 900600078 8,695’ 8,103’ 5.130 Upper/Lower Tandem Seals – BPBSBPB 8,717’ 8,124’ - 5.620 Motors (x2)– 562, KMSLT 500 HP/ 562, KMSUT 500 HP 8,783’ 8,186’ - 5.620 Centralizer/Anode PBTD: 11,450 MD / 9,818’ TVD TD: 11,550’ MD / 9,854’ TVD TBG Hanger 74.5’ below RKB CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 34” Surf 480’ 26"267 thru 397#Drill Quip Surf 979’ 16" 75 K-55 BTC 15.12 Surf 1,345’ 13-3/8" 61 & 68 K-55 BTC 12.42 Surf 3,722’ 9-5/8" Tieback 47# L-80 DWC/C 8.681 Surf 1,316’ 10-3/4” Liner hgr 65.7# L-80 BTC 9.5 1,316' 1,348’ 9-5/8" Liner 47# L-80 DWC/C 8.681 1,348’ 9,107’ 7” liner 26# L-80 VAM TOP HC 6.276 8,919’ 11,548’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT-M 3.958 Surf 8,649’ PERFORATION DETAIL Zone Top (MD) Btm(MD) Top (TVD) Btm(TVD) Length (MD) SPF Date G1 9,361' 9,390' 8,725’ 8,754’ 29' 5 2-20-2013 G2 9,425' 9,440' 8,786’ 8,801’ 15' 5 2-20-2013 G3 9,490' 9,526' 8,843’ 8,879’ 36' 5 2-23-2013 G4 9,535' 9,600' 8,885’ 8,950’ 65' 5 2-23-2013 G5 9,674’ 9,710’ 9,003’ 9,036’ 36' 5 2-23-2013 G5 9,720’ 9,739’ 9,030’ 9,049’ 19' 5 2-23-2013 HK1 9,950’ 9,985’ 9,208’ 9,243’ 35' 5 2-23-2013 HK2 10,003’ 10,130’ 9,251’ 9,329’ 127' 5 2-23-2013 HK3-4 10,192’ 10,600’ 9,362’ 9,542’ 408' 5 2-23-2013 HK5 10,642’ 10,834’ 9,556’ 9,617’ 192' 5 2-23-2013 HK5 10,866’ 11,030’ 9,628’ 9,680’ 164' 5 2-23-2013 HK6 11,083’ 11,165’ 9,697’ 9,722’ 82' 5 2-23-2013 HK6 11,195’ 11,270’ 9,731’ 9,755’ 75' 5 2-23-2013 HK7 11,360’ 11,396’ 9,785’ 9,798’ 36' 5 2-23-2013 SCHEMATIC CASING JEWELRY NO Depth (MD) Depth (TVD)ID OD Item A 1,316’ 1,315’ Baker Flex-Lock Liner hanger & Baker HRD-E ZXP liner top packer (PKR INTENTIONALLY NOT SET!!) B 8,919’ 8,312’ 7” Liner top C 8,925’ 8,318’ Baker JM-ZXP Liner Top Packer D 9,107’ 8,488’ 9-5/8” Casing Shoe Rig Start Date End Date HAK 404 7/15/21 8/4/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-733-20457-02 212-149 Well Name M-31B No operations to report. 07/20/2021 - Tuesday Well kill, pumped 60bbls of 8.9ppg brine. Daily Operations: No operations to report. 07/19/2021 - Monday No operations to report. 07/18/2021 - Sunday 07/15/2021 - Thursday Well kill, Circulated 200bbls of FIW, 330bbls of 8.9ppg dirty brine followed by 71bbls of FIW. 1-3bpm/50-100psi. See gas/oil returns after 30bbls away, at 140bbls away returns oil/PW, after full circlation returns FIW. 07/16/2021 - Friday No operations to report. 07/17/2021 - Saturday 07/21/2021 - Wednesday R/U jacks on rig 51, skid to SW leg & secure same to allow room to r/u 404 on M-31, continue arrange decks. R/D carrier & set on center deck, clear NW leg drill deck. Moved Racking Beam, Set Beam and torque, Installed C-Clamps, Installed hatch covers, spot carrier and install a-leg and drawworks in place. Set derrick and pin into place, set drill line spool and driller control panel, spot doghouse choke skid and koomey, hook up service lines . 07/22/2021 - Thursday R/u choke line, M/u circ lines from Pump to pits, replace element on annular, r/u gas detection system. Monitor well on vac, set BPV. N/D tree. Prep wellhead, cap control lines, inspect lift threads good, install blanking sub. N/U BOPE, stack up 13 5/8" stack, Riser, mud cross, double-gate, annular, start tq. flange bolts on same. Rigging up, raise and scope derrick, install guy wires, spool draw works, place dog house, string man rider and tugger lines. Set and pin rig floor, rig up drillers dog house, general rig up. Function test BOPE. Make up 3 1/2" test joint, rig up test pump and koomey, prep for BOP test. 07/23/2021 - Friday Fill surface eq. shell test 250/3500 good. Test BOPE as per hilcorp & AOGCC expectations, AOGCC witness was waived by inspector Jim Regg, test with 3 1/2" & 4 1/2" TJ's, calibrated & tested gas alarms good. Breakdown test eq. c/o handling eq. R/U summit pulling eq. Pull BPV, m/u landing joint, back out L/D pins. Pull hanger off seat @ 160k, cont pull up t/ 180k, wk 3x & hold weight fell off cont pull string moving @ 150k, pull hanger to floor. Cut cable and disconnect SS control lines. Lay down landing joint and hanger POH for cable to reach and tie into spoolers. Level derrick to center pipe in slips. POH laying down 4 1/2" 12.6# IBT-M ESP production string. F/8767' t/4351', (Adding 10 bbl FIW to well every 15 joints or one hour which ever comes first.) Test BOPE as per hilcorp & AOGCC expectations, AOGCC witness was waived by inspector Jim Regg, t POH laying down 4 1/2" 12.6# IBT-M ESP production string. pull hanger to floor. Rig Start Date End Date HAK 404 7/15/21 8/4/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-733-20457-02 212-149 Well Name M-31B Daily Operations: 07/24/2021 - Saturday Cont. POOH f/4351' to 3776', with 4 1/2" completion & ESP assy,C/O spool. Cont. POOH f/ 3776', L/D 4 1/2" tubing to pump, Last 2500' of sheathing on dual flat pack missing. Breakdown & l/d ESP assy. Clear floor & r/d pulling eq. Rig up tools for running work string. Make up mule shoe RIH picking up 3 1/2" PH6 work string t/3,710’. Circ, hole took 10 bbl FIW to fill hole to surface, begin circ @ 1 bpm staging pumps up to 3.5 bpm as well cleaned up, recovered approximately 5 gal fine rubber and crude at shakers, hand full larger rubber strips at well head. Circ hole clean @ 3.4 bpm at 250 psi. Pumping losses = 12 bph average. POH with mule shoe assembly. 07/25/2021 - Sunday Cont. POOH stand back 3 1/2" wk string. C/O handling eq. P/U cleanout BHA & stand back in derrick while waiting on wireline crew. R/U w/l, RIH w/ 8.5 GR/junk basket t/ 6209' WLM, unable to get deeper, POOH recovered hand full of sheathing from flat pack, RIH w/5.8 junk basket/GR t/8964' WLM set down, POOH had M/T junk basket, R/D w/l, C/O handling eq. M/u BHA #2 -6" bit, bumper sub, oil jar, 4- 4 3/4" drill collars, xo sub = 151.01',TIH w/ stands of 3 1/2" Wk string from derrick t/3,892'. Plumb in mix tank, off load 3 1/2" work string from boat, rack and strap 3 1/2" PH6 pipe, (385 total joints 3 1/2' PH6 on location) work boat. RIH picking up 3 1/2" PH6 work string f/ 3,892' t/7,100'. 07/26/2021 - Monday Cont. tih picking up 3 1/2" PH6 wk string f/7100' t/ 8911', up wt 120k, dn wt 68k. R/U circulate surface to surface & spot NXS lube up annulus @ 4BPM, 820 psi, r/d circ lines. Cont. rih p/u 3 1/2" wk string to tag @ 9150' up wt 106k, dn wt 78k. L/D single, P/U Power swivel, dress stripping bushing, r/u tq lines, m/u Kelly valve & saver sub. Break circulation, Repair leak on Kelly hose connection, circ. 3 BPM 530psi, rot 50 rpm, RT wt 90k, tq 3,500, wash & ream f/9150' t/9,190' with 0 to 2K wob. Reverse circ 1.5 bottoms up @ 9,150, fine sand returns at bottoms up. Reverse circ wash and ream 7" liner from 9,190' t/ 9,416' 0 to 2K wob 3 to 5k torque, (fine to coarse sand returns) from 9,416' reverse clean out hard 3 to 6 K wob (at 60 fph), continue clean out reversing from 9,416’ with 0 to 2 K wob 3 to 5k torque to 9,628’. 92K rot 105K up 90k dn, 90 rpm 3 to 4k torque, 2.5 bpm = 300 psi, 10 bph losses reversing. continue clean out reversing from 9,416’ with 0 to 2 K wob 3 to 5k torque to 9,628’ approximately 5 gal fine rubber and crude at shakers, Make up mule shoe RIH picking up 3 1/2" PH6 work string t/3,710’ RIH w/5.8 junk basket/GR t/8964' WLM set down, RIH w/ 8.5 GR/junk basket t/ 6209' WLM, unable to get deeper, POOH recovered hand full of sheathing from flat pack, Cont. rih p/u 3 1/2" wk string to tag @ 9150' u M/u BHA #2 -6" bit, bumper sub, oil jar, 4- 4 3/4" drill collars, Breakdown & l/d ESP assy. wash & ream f/9150' t/9,190' Rig Start Date End Date HAK 404 7/15/21 8/4/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-733-20457-02 212-149 Well Name M-31B Daily Operations: 07/27/2021 - Tuesday Cont. Wash & ream F/9616', t/9874', up wt 108k, dn wt 84k, rot wt 94k, rot 50 rpm, tq 3-4k, rev circ 2.5-3 BPM, 320-350 psi, loss rate ~14BPH, encountered hard bridges @9660, 9840, sand & scale in returns, fine t/3/16". Cont. Wash & ream F/9874', t/9925', up wt 108k, dn wt 84k, rot wt 94k, rot 50 rpm, tq 3-4k, rev circ 2.5-3 BPM, 320-350 psi, loss rate ~14BPH. Cont. Wash & ream ROP slowed considerably F/9,925', t/9,962' up wt 108k, dn wt 84k, rot wt 94k, rot 50 rpm, tq 3-4k, rev circ 2.5-3 BPM, 320-350 psi, loss rate ~14BPH, Broke through bridge @ 9962', weight came back, lost circulation. Cont. Pumping @ down annulus with no returns, while finishing mixing Size salt pill. Pumped 200BBL in 40 min, never caught returns. Pump 51 BBLS size salt pill down tubing spotting in perfs. chase @ 4.5 BPM ICP 90 psi FCP 450 psi, shut down pump & monitor, let soak. Pumping down back side, hole full at 100 bbl pumped, establish loss rate of 85 bph. Mix 50 bbl. size salt pill #2. Pump pill, spot 50 bbl size salt pill, chase with 62 bbl FIW spot in perfs, let soak. Fill hole from back side, took 70 bbl to fill, establish static loss rate of 18 bph . Clean out 7" liner, reversing wash and ream from 9,962' to 10,126', 0 to 5 wob, 94k rot, 111k up, 86k dn, 3 to 4K torque @ 70 rpm, 2.6 bpm @ 350 psi. average losses of 28 bph. 07/28/2021 - Wednesday Cont. Wash & ream f/10126' t/10136', up wt 111, dn wt 86k, 3-4k tq, 70 RPM, 2.6BPM 350 psi, ROP slowed @ 10136'. Cont. reaming & broke through bridge, cont. down t/10189' loss rate increased to 60 BPH. CBU @ 2.8 BPM, 315 PSI, loss rate slowed t/ 40 BPH. Made a connection came on with pump, pressured up, lined up @ rocked it free pumping down work string, lined back up to rev. circulate. Cont. Wash & ream f/10189, t/10251' up wt 111, dn wt 86k, 3-4k tq, 70 RPM, 2.6BPM 350 psi, loss rate @ 40BPH. No restrictions going down, W/D f/10251' t/10560' @2.8BPM, 280-305 PSI, dry up wt 118k, dn wt 88k. Cont. W/D f/10560' t/11,153', seeing no obstructions or fill, loss rate 28 BPH loss while circulating. Pump down work string while washing & reversing out every 10 joints. Continue washing in hole F 11,153' to 11,369', no obstructions or fill, loss rate 23 BPH loss while circulating. 2.3 BPM, 250 PSI, 120k up , 84k dn. Bad joint thread would not make up, set aside power swivel, lay down 2 bad joints, pick up power swivel. Reverse circulating and washing 7" liner from 11,369' to 11,458'. No obstructions, 202k up, 82k dn, 2.2 bpm = 225 psi. loss rate 23 bph. Reverse circ hole clean @11,458'. 202k up, 82k dn, 2.2 bpm = 225 psi. Spot 37 bbl. size salt pill in liner, chase with 71 bbl. FIW at 4 bpm. Lay down top joint 3 1/2' tubing, XO and saver valve, rig down and cradle power swivel . Change out handling tools for tripping 3 1/2 tubing, lay down rotating head rubber. Trouble shoot power tong HPU. Recovered ~13 bbls solids from Cleanout. Pumped 130 bbls Size salt pill. 07/29/2021 - Thursday Cont. work on HPU repair, change out selector valve on rig while Electrician repairs HPU. POOH L/D 3 1/2" wk string f/ 11432', t/9273',Cont. POOH standing back 3 1/2" wk string t/ cleanout BHA. Lay down 6" clean out BHA. Pick up and make up 7" J S pkr, RIH with 3 1/2" work string to 9,200'. (did not see packer go into liner). Set Packer at 9,200', fill annulus with FIW, test casing to 1,500 psi for 30 minutes, Good test. 3 bbl pumped 3 bbl returned. Set Packer at 9,200', fill annulus with FIW, test casing to 1,500 psi for 30 minutes, Good test. Spot 37 bbl. size salt pill in liner Pump 51 BBLS size salt pill down tubing spotting in perfs. Recovered ~13 bbls solids from Cleanout. Broke through bridge @ 9962', weight came back, lost circulation. Mix 50 bbl. size salt pill #2. Pump pill, spot 50 bbl size salt pill, chase with 62 bbl FIW spot in perfs, let soak. Fill hole from back side, took 70 bbl to fill, establish static loss rate of 18 bph . Clean out 7" liner, reversing wash and ream from 9,962' to 10,126', Reverse circ hole clean @11,458'. Pumped 200BBL in 40 min, never caught returns. Rig Start Date End Date HAK 404 7/15/21 8/4/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-733-20457-02 212-149 Well Name M-31B Daily Operations: 07/30/2021 - Friday POOH w/ 7" test packer f/9200' t/6448', l/D 3 1/2" wk string, cleaning, doping & installing thread protectors, up wt 65k, dn wt 58k. M/U 3 12" test joint & test plug assy, make up to string & land same. R/U test eq. fill surface eq. Test BOPE as per Hilcorp & AOGCC expectations, test was witnessed By AOGCC inspector Austin McLeod, tested w/3 1/2" & 4 1/2" test joint, tested gas alarms good. Pull test plug, break down and lay down test joints and BOPE testing tools. Continue laying down 3 1/2" PH6 work string, cleaning, doping & installing thread protectors. Lay down 7" J S packer. Rig up to run 4 1/2" ESP completion. 07/31/2021 - Saturday Clean & clear floor, c/o handling eq. prep to P/U ESP assy. P/U Motor, install anode to gauge, service motor, P/U second motor & service. Cont. service motor, install motor lead, P/U tandem seals, intake, tandem pumps, discharge, ported sub, xo & 4 1/2" IBT tubing joint, install clamps, test cable & ctl lines. Clear floor & c/o handling eq. RIH w/ ESP completion P/U 4 1/2" 12.6# IBT-M tubing to 2,009' per running order. 25K dn wt. Continue RIH w/ ESP completion. P/U 4 1/2" #12.6 IBT tubing to 3,968' per running order, 46k dn wt. 08/01/2021 - Sunday Continue RIH w/ ESP completion P/U 4 1/2" #12.6 IBT tubing f/ 3,968' t/5958' per running order, dn wt 65k. Test cable every 1000', good. Continue RIH w/ ESP completion. P/U 4 1/2" #12.6 IBT tubing f/ 5958' t/ 6562' per running order, dn wt 67k. Test cable every 1000', good. Change spools & make splice, while splicing fill mix tank with drill water & flush all surface lines, eq & manifolds. Continue RIH w/ ESP completion. P/U 4 1/2" #12.6 IBT tubing f/ 6,562' t/ 8,267' per running order, dn wt. 90k. Testing cable every 1000', good. Pick up 9 5/8" D&L packer (set for 40K overpull release), and upper mandrel, change out electric line spool, make electric penetration and splice cable. Make control line connections, function test Packer vent valve. 08/02/2021 - Monday P/U 4 1/2" Baker TRSV, function test valve, good. Cont. RIH p/u 4 1/2" IBT tubing f/8310' t/8689', P/U & m/u hanger & landing joint. M/U penetrator connection & control lines to hanger, test cable good. Land hanger, dn wt 95k, placing tail @ 8,782', RILD pins. R/U w/l RIH w/3.75 GR, t/ 8,598' WLM (top of RHCP plug) POOH. RIH w/ ball & rod set in plug @ 8,598' WLM. Fill tubing, pressure up t/ 3,950 psi setting packer @ 489', held 10 min, had leak on Otis connection, bleed down, found bad O ring, W/L shucked ball & rod, POOH & replace "O" ring. Pressure up tubing to 3,800 psi hold for 30 minutes. Pressure up on annulus to test packer and hanger to 1,500 psi. Witness waived by AOGCC - Jim Regg. Had a slow bleed, trouble shoot pressure losses. Discuss options with engineering & work on plan forward. RIH with slick line, 1st run did not latch, dress tool, RIH latch ball and rod @ 8,598' wlm POH lay down ball and rod, RIH with GS tool pull RHCP plug, POH lay down plug. Rig down Pollard slick line. Lay down landing joint and set BPV. Prep rig floor for removal. Test BOPE as per Hilcorp & AOGCC expectations, test was witnessed By AOGCC inspector Austin McLeod, Continue RIH w/ ESP completion P/U 4 1/2" #12.6 IBT tubing f Pressure up on annulus to test packer and hanger to 1,500 psi. Witness waived by AOGCC - Jim Regg. Had a slow bleed, trouble shoot pressure losses. Land hanger, dn wt 95k, placing tail @ 8,782', RIH w/ ESP completion P/U 4 1/2" 12.6# IBT-M tubing t Rig Start Date End Date HAK 404 7/15/21 8/4/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-733-20457-02 212-149 Well Name M-31B Daily Operations: 08/03/2021 - Tuesday Cont. clear floor, remove same, prep & scope down mast. Decision made to verify good packer set @ 489' as requested by AOGCC. Work toward setting up to test from annulus & from BOPE to isolate possible leak @ hanger penetration. Scope up mast, install floor, m/u landing joint, install check valve to SSSV line, pump open & cap same. Push control line down below rams, install landing joint, fill stack. Pressure up annulus below & above hanger to BOPE t/ 1625psi hold for 30 min good, testing packer @ 489', Notify AOGCC with packer test results, move forward with plan forward to repair hanger leak. R/D test eq. pull landing joint, & break down, r/d tongs, clear floor & rig down same. prep & scope down mast, unstring blocks, man rider & tuggers. L/D mast, N/D BOPE, pull annular with circulating spool, N/D double-gate, continue cleaning pits. Pull riser and wellhead adapter spool, inspect hanger, install compression fitting on packer vent control line. Summit test cable & penetrator good. Test shallow packer @ 498' against hanger to 1,550 psi for 30 minutes. Good test. Install well head adapter flange and control line penetrations, test to 5K 10 min Good test. Nipple up tree valves and flow lines. Pull BPV and install TWC. Fill tree with water. 08/04/2021 - Wednesday Test tree repairing leaks as needed, got good test @ 5k, r/d test eq. Pulled TWC, clean out wellhead room. Turn well over to production & summit to prep for fire up. Decision made to verify good packer set @ 489' as requested by AOGCC. W Pressure up annulus below & above hanger to BOPE t/ 1625psi hold for 30 min good, testing packer @ 489', Notify AOGCC with packer test results, move forward with plan forward to repair hanger leak. R Safety valve system tested 8/9/21 - all components passed. bjm 1 Winston, Hugh E (CED) From:McLellan, Bryan J (CED) Sent:Tuesday, August 3, 2021 1:25 PM To:Karson Kozub - (C) Cc:Juanita Lovett Subject:RE: [EXTERNAL] RE: PTD (212-149) TBU M-31B RWO sundry 321-263 Karson, This plan is approved. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Karson Kozub ‐ (C) <kkozub@hilcorp.com> Sent: Tuesday, August 3, 2021 12:42 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] RE: PTD (212‐149) TBU M‐31B RWO sundry 321‐263 Bryan, Per our phone conversation we got a good MIT TxIA to 1,500 psi testing against the BOPE’s. Indicating that our packer is holding and our tubing hanger is leaking. Our plan forward with BPV set already: Nipple down the BOPE’s Address the tubing hanger issues Install adapter flange on top of tubing hanger Pressure test the wellhead Pressure test casing Proceed with sundry step 13. Regards, Karson Kozub Mobile: +1 (907) 570-1801 kkozub@hilcorp.com From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Tuesday, August 3, 2021 7:37 AM To: Karson Kozub ‐ (C) <kkozub@hilcorp.com> 2 Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: [EXTERNAL] RE: PTD (212‐149) TBU M‐31B RWO sundry 321‐263 Karson, Can you get a combo MIT TxIA to 1500 psi to prove the packer is holding before ND BOPs? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Karson Kozub ‐ (C) <kkozub@hilcorp.com> Sent: Tuesday, August 3, 2021 6:41 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: PTD (212‐149) TBU M‐31B RWO sundry 321‐263 Good Morning Bryan, On M‐31B Sundry 321‐263 step # 11 we were not able to get a passing pressure test of our IA (9‐5/8” x 4.5” annulus) after setting the packer. We have a slow leak ~35psi/minute that we believe is coming past one of our hanger penetrations. Other well information: The tubing pressure tested and held 4000psi for 30 min to set the packer We will have two barriers in the tubing (KWF and Backpressure valve) We will have two barriers in the IA 9‐5/8” x 4.5” annulus (KWF and packer) We had losses down the IA before we set the packer. We have not had any losses after the packer was set. Our plan forward with BPV set already: Nipple down the BOPE’s Address the tubing hanger issues Install adapter flange on top of tubing hanger Pressure test the wellhead Get a passing casing pressure test Proceed with sundry step 13. Sundry attached for reference. Regards, Karson Kozub Mobile: +1 (907) 570-1801 kkozub@hilcorp.com From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Monday, June 14, 2021 12:04 PM To: Karson Kozub ‐ (C) <kkozub@hilcorp.com> Subject: RE: [EXTERNAL] RE: TBU M‐31B RWO sundry 3 What does FIW stand for, and what is it’s density? I’m not sure it’s heavy enough for your higher reservoir pressure estimate, after you clean out to bottom, which has EMW = 8.92 ppg. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Karson Kozub ‐ (C) <kkozub@hilcorp.com> Sent: Monday, June 14, 2021 11:54 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: Re: [EXTERNAL] RE: TBU M‐31B RWO sundry Bryan, You are correct, we intend on installing the packer and SSSV as a precaution. We do not want to install them at a later date if we are unable to pass a NFT. Regards, Karson Kozub Mobile 907-570-1801 Office 907-777-8434 From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Monday, June 14, 2021 11:45:51 AM To: Karson Kozub ‐ (C) <kkozub@hilcorp.com> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] RE: TBU M‐31B RWO sundry Karson, Unfortunately you can’t do a proper no‐flow until the well has been returned to production and kill fluid produced out. So you’ll have to install the SSSV and packer, or take the risk of it failing a NFT after the well returns to production. I gather from your email below that your intention is to run this equipment as a precaution, no matter what. Correct? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Karson Kozub ‐ (C) <kkozub@hilcorp.com> Sent: Monday, June 14, 2021 10:33 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] RE: TBU M‐31B RWO sundry Bryan, 4 The SSSV and annular packer will be added if the well indicates the ability to flow to surface after the clean out and potential re‐perf. M‐31B has been a no flow well all of its life and I do not plan on it being able to flow to surface. However I do not want to get in a position where the well will not pass a no‐flow test, my intention is to install a packer and SSSV in M‐31B so we are covered either way. Regards, Karson Kozub Mobile: +1 (907) 570-1801 kkozub@hilcorp.com From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Friday, June 11, 2021 3:52 PM To: Karson Kozub ‐ (C) <kkozub@hilcorp.com> Subject: [EXTERNAL] RE: TBU M‐31B RWO sundry Karson, One additional question… The sundry shows the SSSV and annular packer as “contingent” on your proposed schematic. What are they contingent on? Thanks again Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: McLellan, Bryan J (CED) Sent: Friday, June 11, 2021 3:50 PM To: Karson Kozub ‐ (C) <kkozub@hilcorp.com> Subject: TBU M‐31B RWO sundry Karson, I’m looking at the BHP and your MPSP calculation. You have a couple of BHP data points and I’m wondering why you are using the older, higher pressure as the basis for MPSP. Do you think you might open up a higher pressure zone during the Fill Clean out? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250‐9193 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 From:McLellan, Bryan J (CED) To:Karson Kozub - (C) Cc:Juanita Lovett Subject:RE: [EXTERNAL] RE: PTD (212-149) TBU M-31B RWO sundry 321-263 Date:Tuesday, August 3, 2021 1:25:00 PM Karson, This plan is approved. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Karson Kozub - (C) <kkozub@hilcorp.com> Sent: Tuesday, August 3, 2021 12:42 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] RE: PTD (212-149) TBU M-31B RWO sundry 321-263 Bryan, Per our phone conversation we got a good MIT TxIA to 1,500 psi testing against the BOPE’s. Indicating that our packer is holding and our tubing hanger is leaking. Our plan forward with BPV set already: Nipple down the BOPE’s Address the tubing hanger issues Install adapter flange on top of tubing hanger Pressure test the wellhead Pressure test casing Proceed with sundry step 13. Regards, Karson KozubMobile: +1 (907) 570-1801kkozub@hilcorp.com From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Tuesday, August 3, 2021 7:37 AM To: Karson Kozub - (C) <kkozub@hilcorp.com> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: [EXTERNAL] RE: PTD (212-149) TBU M-31B RWO sundry 321-263 Karson, Can you get a combo MIT TxIA to 1500 psi to prove the packer is holding before ND BOPs? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Karson Kozub - (C) <kkozub@hilcorp.com> Sent: Tuesday, August 3, 2021 6:41 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: PTD (212-149) TBU M-31B RWO sundry 321-263 Good Morning Bryan, On M-31B Sundry 321-263 step # 11 we were not able to get a passing pressure test of our IA (9- 5/8” x 4.5” annulus) after setting the packer. We have a slow leak ~35psi/minute that we believe is coming past one of our hanger penetrations. Other well information: The tubing pressure tested and held 4000psi for 30 min to set the packer We will have two barriers in the tubing (KWF and Backpressure valve) We will have two barriers in the IA 9-5/8” x 4.5” annulus (KWF and packer) We had losses down the IA before we set the packer. We have not had any losses after the packer was set. Our plan forward with BPV set already: Nipple down the BOPE’s Address the tubing hanger issues Install adapter flange on top of tubing hanger Pressure test the wellhead Get a passing casing pressure test Proceed with sundry step 13. Sundry attached for reference. Regards, Karson KozubMobile: +1 (907) 570-1801kkozub@hilcorp.com From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Monday, June 14, 2021 12:04 PM To: Karson Kozub - (C) <kkozub@hilcorp.com> Subject: RE: [EXTERNAL] RE: TBU M-31B RWO sundry What does FIW stand for, and what is it’s density? I’m not sure it’s heavy enough for your higher reservoir pressure estimate, after you clean out to bottom, which has EMW = 8.92 ppg. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Karson Kozub - (C) <kkozub@hilcorp.com> Sent: Monday, June 14, 2021 11:54 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: Re: [EXTERNAL] RE: TBU M-31B RWO sundry Bryan, You are correct, we intend on installing the packer and SSSV as a precaution. We do not want to install them at a later date if we are unable to pass a NFT. Regards, Karson Kozub Mobile 907-570-1801 Office 907-777-8434 From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Monday, June 14, 2021 11:45:51 AM To: Karson Kozub - (C) <kkozub@hilcorp.com> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] RE: TBU M-31B RWO sundry Karson, Unfortunately you can’t do a proper no-flow until the well has been returned to production and kill fluid produced out. So you’ll have to install the SSSV and packer, or take the risk of it failing a NFT after the well returns to production. I gather from your email below that your intention is to run this equipment as a precaution, no matter what. Correct? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Karson Kozub - (C) <kkozub@hilcorp.com> Sent: Monday, June 14, 2021 10:33 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] RE: TBU M-31B RWO sundry Bryan, The SSSV and annular packer will be added if the well indicates the ability to flow to surface after the clean out and potential re-perf. M-31B has been a no flow well all of its life and I do not plan on it being able to flow to surface. However I do not want to get in a position where the well will not pass a no-flow test, my intention is to install a packer and SSSV in M-31B so we are covered either way. Regards, Karson KozubMobile: +1 (907) 570-1801kkozub@hilcorp.com From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Friday, June 11, 2021 3:52 PM To: Karson Kozub - (C) <kkozub@hilcorp.com> Subject: [EXTERNAL] RE: TBU M-31B RWO sundry Karson, One additional question… The sundry shows the SSSV and annular packer as “contingent” on your proposed schematic. What are they contingent on? Thanks again Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: McLellan, Bryan J (CED) Sent: Friday, June 11, 2021 3:50 PM To: Karson Kozub - (C) <kkozub@hilcorp.com> Subject: TBU M-31B RWO sundry Karson, I’m looking at the BHP and your MPSP calculation. You have a couple of BHP data points and I’m wondering why you are using the older, higher pressure as the basis for MPSP. Do you think you might open up a higher pressure zone during the Fill Clean out? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 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 herebynotified 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 theindividual 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 responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Reviewed By- P.I. Supry Z02 -I BOPE Test Report for: TRADING BAY UNIT M-31 B Comm Contractor/Rig No.: Hilcorp 404 PTD#: 2121490 DATE: 7/30/2021 - Inspector Austin McLeod - Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: Harold Soule Rig Rep: Joe Steiner Inspector Type Operation: WRKOV Sundry No: Test Pressures: Inspection No: bopSAM210731 14453 8 NA Lower Kelly Rams: Annular: Valves: MASP: Annular Preventer 1 -13-5/8 _ Type Test: WKLY 321-263 250/3500 - 250/2500 - 250/3500- 2970' Related Insp No: Kill Line Valves #1 Rams 1_, 2-7/8x5-1/2_ "_ P TEST DATA 1 P MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: 0 NA P/F Visual Alarm Time/Pressure P/F Location Gen.: P Trip Tank NA - NA System Pressure 3075-_ P_ Housekeeping: P` Pit Level Indicators P P Pressure After Closure 2075_ P _- PTD On Location P Flow Indicator NA NA 200 PSI Attained 34 P Standing Order Posted -P - " Meth Gas Detector - P P Full Pressure Attained 166 _ P Well Sign P H2S Gas Detector P P Blind Switch Covers: All stations • P " Drl. Rig P MS Misc NA NA Nitgn. Bottles (avg): 6.1975 - P Hazard Sec P ACX' Mi.cc (1 NA Misc NA FLOOR SAFTY VALVES: BOP STACK: NA _ Quantity P/F Quantity Size P/F Upper Kelly 0 _ NA- Stripper 0 NA Lower Kelly 0_ _" _ NA Annular Preventer 1 -13-5/8 _ P Ball Type — 1 -------p Kill Line Valves #1 Rams 1_, 2-7/8x5-1/2_ "_ P Inside BOP 1 P #2 Rams I Blinds P FSV Misc 0 NA #3 Rams _ 0 NA._ CHOKE MANIFOLD: Quantity P/F No. Valves 11 FP Manual Chokes —_ 1 P . Hydraulic Chokes 1 P CH Misc 0 NA #4 Rams NA _ #5 Rams _0 0 _ NA INSIDE REEL VALVES: #6 Rams _ 0 NA (Valid for Coil Rigs Only) _ Choke Ln. Valves 1 . 2-1/16 P - Quantity P/F HCR Valves 2 " 2-1/16 P - Inside Reel Valves 0 NA Kill Line Valves 2 2-1/16 P Check Valve 0 NA BOP Misc 0 NA Number of Failures: 1 - Test Results Test Time 4 Remarks: 4-1/2" & 3-1/2" joints. Annular on 3-1/2". CMV #6 grease zerk leaking -replaced for Pass. 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: 3800 Centerpoint Drive, Suite 1400 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): McArthur River Field / Middle Kenai G & Hemlock Oil Pools 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 11,550'N/A Casing Collapse Structural Conductor Surface 1,020 psi Intermediate 1,540 psi Production 4,760 psi Liner Hanger 6,300 psi Liner 4,760 psi Liner 5,410 psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email:kkozub@hilcorp.com Contact Phone: (907) 777-8434 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Size 3,090 psi N/A 480' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018730 Authorized Signature: Operations Manager Karson Kozub PRESENT WELL CONDITION SUMMARY Length Anchorage, AK 99503 Hilcorp Alaska, LLC Trading Bay Unit M-31B CO 228A 480' COMMISSION USE ONLY Authorized Name: MD 8,488' 2,630 psi 212-149 50-733-20457-02-00 3,524' 979' 1,345' 12.6# / L-80 TVD Burst 8,643' 6,780 psi 7,240 psi Tubing Size:Perforation Depth MD (ft): 3,722' 9,361 - 11,396 1,316' 1,316 (MD) 1,315 (TVD) / 8,925 (MD) 8,318 (TVD) & N/A Tubing Grade:Tubing MD (ft): 8,725 - 9,798 Perforation Depth TVD (ft): 13-3/8" Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 7/1/2021 4-1/2" Daniel E. Marlowe Baker HRD-E ZXP / Baker JM-ZXP & N/A 2,629' 7" 1,315'9-5/8" 11,548' 9,853' 1,316' 7,759' 9-5/8" 9,107' 6,850 psi 9,854' 11,450' 9,818' 2,970 psi 480' 3,722' 1,345' 979' 1,344' Other: Pull/Replace ESP 32'10-3/4"1,348'1,347'7,750 psi 34" 26" 16" 979' Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. 321-263 By Meredith Guhl at 10:25 am, May 28, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.05.26 16:43:37 -08'00' Dan Marlowe (1267) DSR-5/28/21 X DLB 05/28/2021 10-404 BOP test to 3500 psi. Annular test to 2500 psi. X X BJM 6/14/21 Provide AOGCC 48 hrs notice to witness packer pressure test. dts 6/15/2021 JLC 6/15/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.06.15 11:19:36 -08'00' RBDMS HEW 6/16/2021 Well Work Prognosis Well: M-31B Well Name:M-31B API Number: 50-733-20457-02-00 Current Status:ESP Producer Leg:B-1 (NW Corner) Estimated Start Date:07/01/2021 Rig:HAK 404 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:212-149 First Call Engineer:Karson Kozub (907)-777-8434 (O) (907) 570-1801 (M) Second Call Engineer:Katherine O’Connor (907)-777-8376 (O) (214) 684-7400 (M) Current Bottom Hole Pressure:2,421 psi @ 8,170’ TVD 0.296 psi/ft based on ESP Gauge April 2021 Maximum Expected BHP:3,787 psi @ 8,170’ TVD 0.464 psi/ft based on ESP Gauge April 2018 Max. Potential Surface Pressure:2,970 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) ***This is a no flow well as of 05/11/2018 Brief Well Summary M-31B is a G / Hemlock Producer completed with an ESP. Total fluid production has decreased significantly over the past year. This decrease is believed to have been caused by scale formation due to comingled production across the perforated interval. In April 2021 Hilcorp attempted a synthetic acid soak in an attempt to dissolve the scale – the well did not RTP after the soak. Objective of this program is to pull ESP, cleanout, re-perf if needed and install a new ESP. Last Casing Pressure Test: 02/14/2013 at 11,450’ (prior to perforating) to 1,500 psig and charted for 30 minutes (New test to be done on step 7 below) Procedure: 1. MIRU HAK 404 2. Circulate the well through ESP to production. a. Work over fluid will be FIW. b. BOP’s will be closed as needed to circulate the well. 3. Set BPV, ND tree, NU BOP and test to 250psi low/3,500psi high/2,500psi Annular a. Note: Notify AOGCC 48 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. RIH with cleanout assembly, Circulate bottoms up, POOH. 7. RIH with retrievable packer, set at ± 9,200’ and pressure test casing to 1,500psi for 30min charted, POOH 8. *Contingent based on clean out. a. PU TCP guns, RIH and perforate per program b. After detonation, circulate out any perf gas, confirm well is static, POOH. 9. PU and run ESP completion a. A high set packer, packer vent valve, and SSSV will be ran if well indicates the ability to flow to surface 10. Land ESP with the bottom of the assembly at ± 8,770’. 11. If applicable – Set and test packer to 1,500psi charting for 30 min 12. Set BPV, ND BOP, NU tree and test same. 13. Turn well over to production. 14. Conduct SVS testing per AOGCC regulations. 15. If applicable – Schedule no-flow test per AOGCC regulations These will be included in the completion as a precaution, in case well fails No-flow test after return to production. Notify AOGCC 48 hrs in advance of pressure test to allow witness. BOP's not on the well yet. Have weighting material on location in case 8.92 ppg pore pressure is encountered during fill clean out. - bjm Well Work Prognosis Well: M-31B Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Current / Proposed Wellhead Diagram 4. BOP Drawing 5. Fluid/Flow Diagrams 6. Rolling BOP Test Procedures 7. RWO Sundry Change Form Steelhead Platform Well #: M-31B Completed: 04/28/18 PTD#: 212-149 API#: 50-733-20457-02-00 REVISED BY: JLL 05/21/18 B 1 26” 16” 13-3/8” C D A PBTD: 11,450 MD / 9,818’ TVD TD: 11,550’ MD / 9,854’ TVD TBG Hanger 74.5’ below RKB JEWELRY DETAIL NO Depth (MD) DEPTH (TVD) ID OD Item 1 8,643’ 8,055’ - 5.620 Discharge, Bolt On 8,643’ 8,055’ - 6.750 Pump (x2) 675 Series, 45 Stg SH16000 8,682’ 8,091’ - 6.750 Gas Separator/Intake 8,683’ 8,092’ 5.130 Seals (Upper/Lower) – 513 Series, BPBSL 8,701’ 8,109’ -5.620 Motor (x2) 562 Motor, KMSLT & KMSUT 500HP/1800V/165.5A 8,767’ 8,170’ - 5.620 Centralizer/Anode CASING DETAIL SIZE WT GRAD E CONN ID TOP BTM. 34” Surf 480’ 26"267 thru 397#Drill Quip Surf 979’ 16" 75 K-55 BTC 15.12 Surf 1,345’ 13-3/8" 61 & 68 K-55 BTC 12.42 Surf 3,722’ 9-5/8" Tieback 47# L-80 DWC/C 8.681 Surf 1,316’ 10-3/4” Liner hgr 65.7# L-80 BTC 9.5 1,316' 1,348’ 9-5/8" Liner 47# L-80 DWC/C 8.681 1,348’ 9,107’ 7” liner 26# L-80 VAM TOP HC 6.276 8,919’ 11,548’ TUBING DETAIL 4-1/2” 12.6# L-80 IBT-M 3.958 Surf 8,643’ PERFORATION DETAIL Zone Top (MD) Btm(MD) Top (TVD) Btm(TVD) Length (MD) SPF Date G1 9,361' 9,390' 8,725’ 8,754’ 29' 5 2-20-2013 G2 9,425' 9,440' 8,786’ 8,801’ 15' 5 2-20-2013 G3 9,490' 9,526' 8,843’ 8,879’ 36' 5 2-23-2013 G4 9,535' 9,600' 8,885’ 8,950’ 65' 5 2-23-2013 G5 9,674’ 9,710’ 9,003’ 9,036’ 36' 5 2-23-2013 G5 9,720’ 9,739’ 9,030’ 9,049’ 19' 5 2-23-2013 HK1 9,950’ 9,985’ 9,208’ 9,243’ 35' 5 2-23-2013 HK2 10,003’ 10,130’ 9,251’ 9,329’ 127' 5 2-23-2013 HK3-4 10,192’ 10,600’ 9,362’ 9,542’ 408' 5 2-23-2013 HK5 10,642’ 10,834’ 9,556’ 9,617’ 192' 5 2-23-2013 HK5 10,866’ 11,030’ 9,628’ 9,680’ 164' 5 2-23-2013 HK6 11,083’ 11,165’ 9,697’ 9,722’ 82' 5 2-23-2013 HK6 11,195’ 11,270’ 9,731’ 9,755’ 75' 5 2-23-2013 HK7 11,360’ 11,396’ 9,785’ 9,798’ 36' 5 2-23-2013 SCHEMATIC CASING JEWELRY NO Depth (MD) Depth (TVD)ID OD Item A 1,316’ 1,315’ Baker Flex-Lock Liner hanger & Baker HRD-E ZXP liner top packer (PKR INTENTIONALLY NOT SET!!) B 8,919’ 8,312’ 7” Liner top C 8,925’ 8,318’ Baker JM-ZXP Liner Top Packer D 9,107’ 8,488’ 9-5/8” Casing Shoe Steelhead Platform Well #: M-31B Completed: FUTURE PTD#: 212-149 API#: 50-733-20457-02-00 REVISED BY: JLL 05/24/21 2 B 4 26” 16” 13-3/8” 1 C D A 3 34 X PBTD: 11,450 MD / 9,818’ TVD TD: 11,550’ MD / 9,854’ TVD TBG Hanger 74.5’ below RKB JEWELRY DETAIL NO Depth (MD) DEPTH (TVD) ID OD Item 1 ±475’ ±475’ SSSV (Contingent) 2 ±500’ ±500’ High set packer w/vent valve (Contingent) 3 ±8,640’ ±8,052’ X-Nipple (Contingent) 4 ±8,645’ ±8,057’ - 5.620 Discharge, Bolt On - 6.750 Pump - 6.750 Intake 5.130 Seals - 5.620 Motors ±8,770’ ±8,174’ - 5.620 Centralizer/Anode CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 34” Surf 480’ 26"267 thru 397#Drill Quip Surf 979’ 16" 75 K-55 BTC 15.12 Surf 1,345’ 13-3/8" 61 & 68 K-55 BTC 12.42 Surf 3,722’ 9-5/8" Tieback 47# L-80 DWC/C 8.681 Surf 1,316’ 10-3/4” Liner hgr 65.7# L-80 BTC 9.5 1,316' 1,348’ 9-5/8" Liner 47# L-80 DWC/C 8.681 1,348’ 9,107’ 7” liner 26# L-80 VAM TOP HC 6.276 8,919’ 11,548’ TUBING DETAIL 4-1/2” 3.958 Surf ±8,645’ PERFORATION DETAIL Zone Top (MD) Btm(MD) Top (TVD) Btm(TVD) Length (MD) SPF Date G1 ±9,361' ±9,390' ±8,725’ ±8,754’ ±29' 5 Re-perforate G2 ±9,425' ±9,440' ±8,786’ ±8,801’ ±15' 5 Re-perforate G3 ±9,490' ±9,526' ±8,843’ ±8,879’ ±36' 5 Re-perforate G4 ±9,535' ±9,600' ±8,885’ ±8,950’ ±65' 5 Re-perforate G5 ±9,674’ ±9,710’ ±9,003’ ±9,036’ ±36' 5 Re-perforate G5 ±9,720’ ±9,739’ ±9,030’ ±9,049’ ±19' 5 Re-perforate HK1 ±9,950’ ±9,985’ ±9,208’ ±9,243’ ±35' 5 Re-perforate HK2 ±10,003’ ±10,130’ ±9,251’ ±9,329’ ±127' 5 Re-perforate HK3-4 ±10,192’ ±10,600’ ±9,362’ ±9,542’ ±408' 5 Re-perforate HK5 ±10,642’ ±10,834’ ±9,556’ ±9,617’ ±192' 5 Re-perforate HK5 ±10,866’ ±11,030’ ±9,628’ ±9,680’ ±164' 5 Re-perforate HK6 ±11,083’ ±11,165’ ±9,697’ ±9,722’ ±82' 5 Re-perforate HK6 ±11,195’ ±11,270’ ±9,731’ ±9,755’ ±75' 5 Re-perforate HK7 ±11,360’ ±11,396’ ±9,785’ ±9,798’ ±36' 5 Re-perforate PROPOSED CASING JEWELRY NO Depth (MD) Depth (TVD)ID OD Item A 1,316’ 1,315’ Baker Flex-Lock Liner hanger & Baker HRD-E ZXP liner top packer (PKR INTENTIONALLY NOT SET!!) B 8,919’ 8,312’ 7” Liner top C 8,925’ 8,318’ Baker JM-ZXP Liner Top Packer D 9,107’ 8,488’ 9-5/8” Casing Shoe Steelhead Platform M-31B Current Starting head, FMC, 30'’ MSS FE X 26'’ butt weld Adapter spool, FMC-A-5-S 30'’ MSS stdd bottom X 21 ¼ 2M FMC speedlock top, w/ 2- 2'’ LPO Unihead, FMC Type 2, 16 ¾ 5M FE top X 21 ¼ 2M FMC speedlock bottom, w/ 4- 2 1/16 5M SSO Tubing head, FMC-TC-60, spec for unihead, 16 ¾ 5M FE top X 16 ¾ 5M stdd bottom, w/ 2- 2 1/16 5M SSO Valve, FMC-120, 2 1/16 5M FE, HWO, AA 26'’ 16'’ 13 3/8'’ 9 5/8'’ 4 1/2 Steelhead Platform M-31B 26 X 16 X 13 3/8 X 9 5/8 X 4 1/2 Valve, Swab, WKM-M, 4 1/16 5M FE, HWO, DD Valve, Master, WKM-M, 4 1/16 5M FE, HWO, DD Valve, upper master, SSV, 4 1/16 5M FE, w/ 15'’ Safeco operator, EE BHTA, Bowen, 4 1/16 5M FE X 7-5SA Bowen top Valve, wing, WKM-M, 4 1/16 5M FE, HWO, DD Tbg hanger, FMC-TC-1A-EN- EC-CCL, 11 5M X 4 ½ IBT lift and susp, w/ 4'’ Type H BPV profile, 2- 1/4 continuous control line ports Adapter, FMC A-3-EC, 11 5M X 4 1/16 5M, prepped for BIW electro sub, 2- ½ npt continuous control line exits X2 control line Attachment spool, FMC-TC, 16 ¾ 5M stdd btm x 11 5M FE top, 12'’ in length, 10.00'’ min bore Steelhead Platform M-31B Proposed Starting head, FMC, 30'’ MSS FE X 26'’ butt weld Adapter spool, FMC-A-5-S 30'’ MSS stdd bottom X 21 ¼ 2M FMC speedlock top, w/ 2- 2'’ LPO Unihead, FMC Type 2, 16 ¾ 5M FE top X 21 ¼ 2M FMC speedlock bottom, w/ 4- 2 1/16 5M SSO Tubing head, FMC-TC-60, spec for unihead, 16 ¾ 5M FE top X 16 ¾ 5M stdd bottom, w/ 2- 2 1/16 5M SSO Valve, FMC-120, 2 1/16 5M FE, HWO, AA 26'’ 16'’ 13 3/8'’ 9 5/8'’ 4 1/2 Steelhead Platform M-31B 26 X 16 X 13 3/8 X 9 5/8 X 4 1/2 Valve, Swab, WKM-M, 4 1/16 5M FE, HWO, DD Valve, Master, WKM-M, 4 1/16 5M FE, HWO, DD Valve, upper master, SSV, 4 1/16 5M FE, w/ 15'’ Safeco operator, EE BHTA, Bowen, 4 1/16 5M FE X 7-5SA Bowen top Valve, wing, WKM-M, 4 1/16 5M FE, HWO, DD Tbg hanger, FMC-TC-1A-EN- EC-CCL, 11 5M X 4 ½ IBT lift and susp, w/ 4'’ Type H BPV profile, 4- 1/4 continuous control line ports Adapter, FMC A-3-EC, 11 5M X 4 1/16 5M, prepped for BIW electro sub, 2- ½ npt continuous control line exits X4 control line Attachment spool, FMC-TC, 16 ¾ 5M stdd btm x 11 5M FE top, 12'’ in length, 10.00'’ min bore BOP Stack Rig 404 Shaffer SL 13 5/8 5M 2 7/8-5.5 variables Blinds 2.26' Riser 13 5/8 5M FE X 13 5/8 5M FE Spacer spool 13 5/8 5M FE X 11 5M 4.54' 2.83' Choke and Kill valves 2 1/16 5M Mud Cross 4 1/16 5M EFO 4.30' Hydril GK 13 5/8-5000 DSA 4 X 2DSA 4 X 2Spacer spool 13 5/8 5M X 13 5/8 5M ? ? ? 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) and Mr. Jim Regg (AOGCC) 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. 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.) Rig 404 BOP Test Procedure Attachment #1 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 M-31B (PTD 212-149)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. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Oilsafe AR (Acid Soak) Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 11,550 feet N/A feet true vertical 9,854 feet N/A feet Effective Depth measured 11,450 feet 1,316 / 8,925 feet true vertical 9,818 feet 1,315 / 8,318 feet Perforation depth Measured depth 9,361 - 11,396 feet True Vertical depth 8,725 - 9,798 feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 8,643 MD 8,055 TVD HRD-E ZXP 1,386 (MD) / 1,315 (TVD) Packers and SSSV (type, measured and true vertical depth)JM-ZXP 8,925 (MD) 8,318 (TVD) SSSV: N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Authorized Title: Contact Email: Contact Phone: 4,760psiLiner7,759 9-5/8" 9,107 8,488 6,850psi TVD 480 measured true vertical Packer Liner Hanger 32 10-3/4" 1,348 1,347 9-5/8" 7" 34" 1,316 MD 480 979 1,345 11,548 measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 173 Representative Daily Average Production or Injection Data 694,055 Casing Pressure STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 212-149 50-733-20457-02-00 Plugs ADL0018730 Trading Bay Unit M-31B 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-170 70 Authorized Signature with date: Authorized Name: 0 WINJ WAG 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 71 4125 gallons (98.3 BBL) Oilsafe AR displaced with 150 BBL Filtered Inlet Water. Final pressure - 180psi at surface. Oil-Bbl 108 Water-Bbl Intermediate 9,361 - 11,396 Junk 5. Permit to Drill Number: 0 McArthur River Field / Middle Kenai G & Hemlock Oil PoolsN/A measured 3,722 1,316 Size 72 Production Casing Structural Liner 2,629 Length 480 979 1,345 Conductor Surface 5,410psi 4,760psi 26" 16" 13-3/8" 3,722 3,090psi 907 777-8434 6,780psi 979 1,344 3,524 1,315 9,853 7,750psi 6,300psi Collapse Karson Kozub kkozub@hilcorp.com Tubing Pressure 1,020psi 1,540psi 2,630psi Hilcorp Alaska, LLC 2. Operator Name Senior Engineer: Senior Res. Engineer: 7,240psi Daniel E. Marlowe Operations Manager Burst Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 8:20 am, May 19, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.05.18 15:45:30 -08'00' Dan Marlowe (1267) DSR-5/19/21 SFD 5/21/2021RBDMS HEW 5/20/2021 BJM 9/27/21 Steelhead Platform Well #: M-31B Completed: 04/28/18 PTD#: 212-149 API#: 50-733-20457-02-00 REVISED BY: JLL 05/21/18 B 1 26” 16” 13-3/8” C D A PBTD: 11,450 MD / 9,818’ TVD TD: 11,550’ MD / 9,854’ TVD TBG Hanger 74.5’ below RKB JEWELRY DETAIL NO Depth (MD) DEPTH (TVD) ID OD Item 1 8,643’ 8,055’ - 5.620 Discharge, Bolt On 8,643’ 8,055’ - 6.750 Pump (x2) 675 Series, 45 Stg SH16000 8,682’ 8,091’ - 6.750 Gas Separator/Intake 8,683’ 8,092’ 5.130 Seals (Upper/Lower) – 513 Series, BPBSL 8,701’ 8,109’ -5.620 Motor (x2) 562 Motor, KMSLT & KMSUT 500HP/1800V/165.5A 8,767’ 8,170’ - 5.620 Centralizer/Anode CASING DETAIL SIZE WT GRAD E CONN ID TOP BTM. 34” Surf 480’ 26"267 thru 397#Drill Quip Surf 979’ 16" 75 K-55 BTC 15.12 Surf 1,345’ 13-3/8" 61 & 68 K-55 BTC 12.42 Surf 3,722’ 9-5/8" Tieback 47# L-80 DWC/C 8.681 Surf 1,316’ 10-3/4” Liner hgr 65.7# L-80 BTC 9.5 1,316' 1,348’ 9-5/8" Liner 47# L-80 DWC/C 8.681 1,348’ 9,107’ 7” liner 26# L-80 VAM TOP HC 6.276 8,919’ 11,548’ TUBING DETAIL 4-1/2” 12.6# L-80 IBT-M 3.958 Surf 8,643’ PERFORATION DETAIL Zone Top (MD) Btm(MD) Top (TVD) Btm(TVD) Length (MD) SPF Date G1 9,361' 9,390' 8,725’ 8,754’ 29' 5 2-20-2013 G2 9,425' 9,440' 8,786’ 8,801’ 15' 5 2-20-2013 G3 9,490' 9,526' 8,843’ 8,879’ 36' 5 2-23-2013 G4 9,535' 9,600' 8,885’ 8,950’ 65' 5 2-23-2013 G5 9,674’ 9,710’ 9,003’ 9,036’ 36' 5 2-23-2013 G5 9,720’ 9,739’ 9,030’ 9,049’ 19' 5 2-23-2013 HK1 9,950’ 9,985’ 9,208’ 9,243’ 35' 5 2-23-2013 HK2 10,003’ 10,130’ 9,251’ 9,329’ 127' 5 2-23-2013 HK3-4 10,192’ 10,600’ 9,362’ 9,542’ 408' 5 2-23-2013 HK5 10,642’ 10,834’ 9,556’ 9,617’ 192' 5 2-23-2013 HK5 10,866’ 11,030’ 9,628’ 9,680’ 164' 5 2-23-2013 HK6 11,083’ 11,165’ 9,697’ 9,722’ 82' 5 2-23-2013 HK6 11,195’ 11,270’ 9,731’ 9,755’ 75' 5 2-23-2013 HK7 11,360’ 11,396’ 9,785’ 9,798’ 36' 5 2-23-2013 SCHEMATIC CASING JEWELRY NO Depth (MD) Depth (TVD)ID OD Item A 1,316’ 1,315’ Baker Flex-Lock Liner hanger & Baker HRD-E ZXP liner top packer (PKR INTENTIONALLY NOT SET!!) B 8,919’ 8,312’ 7” Liner top C 8,925’ 8,318’ Baker JM-ZXP Liner Top Packer D 9,107’ 8,488’ 9-5/8” Casing Shoe Rig Start Date End Date Pumping Unit 4/21/21 4/28/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-733-20457-02 212-149 Well Name M-31B 04/28/2021 - Wednesday Bring well online after 120 hour soak. End job. Acid job unsuccessful and the ESP went to ground. Well will remain shut in until a workover can be performed. No-flow test not needed due to well being shut in. Daily Operations: 04/22/2021 - Thursday Obtain permits and PJSM. Open swab valve. Tote 1 begin pumping. 0 PSI static tubing / 250 PSI pump while injecting. Tote 1 completed but trouble with fluid end of pump. Shut down for repairs. Tote 2 begin pumping. 0 PSI static tubing / 250 PSI pump while injecting. Encountered problem with air end of pump. Shut down for repairs. Tote 2 continue and finish pumping. Tote 3 begin pumping. 0 PSI static tubing / 250 PSI pump while injecting. Again, trouble with air end of pump. Shut down and with help from mechanic did full rebuild of pump with new seal kit and test. Tote 3 continue and finish pumping. Tote 4 begin pumping. 0 PSI static tubing / 250 PSI pump while injecting. Tote 5 begin pumping. 0 PSI static tubing / 250 PSI pump while injecting. Tote 6 begin pumping. 0 PSI static tubing / 250 PSI pump while injecting. Tote 7 begin pumping. 0 PSI static tubing / 250 PSI pump while injecting. Tote 8 begin pumping. 0 PSI static tubing / 250 PSI pump while injecting. Tote 9 begin pumping. 0 PSI static tubing / 250 PSI pump while injecting. Tote 10 begin pumping. 0 PSI static tubing / 250 PSI pump while injecting. Tote 11 begin pumping. 0 PSI static tubing / 250 PSI pump. 04/23/2021 - Friday Tote 12 begin pumping. 0 PSI static tubing / 250 PSI pump while injecting. Tote 13 begin pumping. 0 PSI static tubing / 250 PSI pump while injecting. Tote 14 begin pumping. 0 PSI static tubing / 250 PSI pump while injecting. Tote 15 begin pumping. 0 PSI static tubing / 250 PSI pump while injecting. Acid pump job complete. Turn well over to production to chase acid pill and spot using water flood. Rig down pumps and remove totes from work area. Rig up waterflood injection lines and metering. Begin pumping filtered inlet water at 22.8gpm 180psi while injecting. Continue pumping 22.8gpm 180 psi while injecting. Continue pumping 22.8gpm 180 psi while injecting. Continue pumping 22.8gpm 180 psi while injecting. Complete after reaching desired 150 bbl fluid. Rig down and let soak. 04/21/2021 - Wednesday ^ĂĨĞƚǇŵĞĞƟŶŐĂŶĚW:^D͘Remove hatch cover to access middle deck above WH Room. Spot pump. Move 10 totes Safe Acid to Upper WH Room NW. SI wing & swab M-31B. Bypass and cap SSV. Change tree cap valves for injection. R/U pump to tree cap w/ high PSI hose & check valve. Pressure test to 3500 PSI. Secure equipment & plan forward to start 15 tote acid job in morning. 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: 3800 Centerpoint Drive, Suite 1400 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): McArthur River Field / Middle Kenai G & Hemlock Oil Pools 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 11,550'N/A Casing Collapse Structural Conductor Surface 1,020 psi Intermediate 1,540 psi Production 4,760 psi Liner Hanger 6,300 psi Liner 4,760 psi Liner 5,410 psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email:kkozub@hilcorp.com Contact Phone: (907) 777-8434 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Other: Oilsafe AR (Acid Soak) 32'10-3/4"1,348'1,347'7,750 psi 7,759'9-5/8"9,107'8,488'6,850 psi 9,854'11,450'9,818'2,970 psi 2,629'7" 1,315'9-5/8" 11,548'9,853' Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 4/21/2021 4-1/2" Daniel E. Marlowe Baker HRD-E ZXP / Baker JM-ZXP & N/A 1,316' Perforation Depth MD (ft): 3,722' 9,361 - 11,396 1,316' 1,316 (MD) 1,315 (TVD) / 8,925 (MD) 8,318 (TVD) & N/A Tubing Grade:Tubing MD (ft): 8,725 - 9,798 Perforation Depth TVD (ft): 480' 34" 26" 16" 979' 13-3/8"3,722' 1,345' 979' 1,344' 3,524' 979' 1,345' 480' 12.6# / L-80 TVD Burst 8,643' 6,780 psi 7,240 psi Tubing Size: MD 2,630 psi 212-149 50-733-20457-02-00Anchorage, AK 99503 Hilcorp Alaska, LLC Trading Bay Unit M-31B N/A COMMISSION USE ONLY Authorized Name: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018730 Authorized Signature: Operations Manager Karson Kozub PRESENT WELL CONDITION SUMMARY Length Size 3,090 psi N/A 480' Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:20 am, Apr 08, 2021 321-170 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.04.07 14:36:26 -08'00' Dan Marlowe (1267) DSR-4/8/21SFD 4/8/2021 10-404 BJM 4/12/21 Comm. ption Required? Yes 4/12/21 dts 4/12/2021 JLC 4/12/2021 RBDMS HEW 4/12/2021 Well Work Prognosis Well: M-31B Well Name:M-31B API Number: 50-733-20457-02-00 Current Status:ESP Producer Leg:B-1 (NW Corner) Estimated Start Date:04/21/2021 Rig:N/A Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:212-149 First Call Engineer:Karson Kozub (907)-777-8434 (O) (907) 570-1801 (M) Second Call Engineer:Katherine O’Connor (907)-777-8376 (O) (214) 684-7400 (M) Current Bottom Hole Pressure:2,421 psi @ 8,170’ TVD 0.296 psi/ft based on ESP Gauge April 2021 Maximum Expected BHP:3,787 psi @ 8,170’ TVD 0.464 psi/ft based on ESP Gauge April 2018 Max. Potential Surface Pressure:2,970 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) ***This is a no flow well as of 05/11/2018 Brief Well Summary M-31B is a G / Hemlock Producer completed with an ESP. Total fluid production has decreased significantly over the past year. This decrease is believed to have been caused by scale formation due to comingled production across the perforated interval. Well Objective Hilcorp plans to pump an Oilsafe AR (safe acid) soak down the production tubing, out the ESP intake, and down across the perfs, to clean up any scale deposition. Procedure: 1. MIRU pumping equipment. 2. Shut down ESP. 3. Pressure test surface lines to ±3,500 psi (treatment pump relief valve limit). 4. Line up pumping down the tubing 5. Pump ±4,125 gallons of Oilsafe AR (Synthetic acid) – 15 totes of acid 6. Pump ±325 bbls water to spot the safe acid across the perforated interval. 7. Shut down pump and let acid soak for ±120 hours. 8. RD Pumping equipment. 9. Return well to production. 10. Schedule a No-Flow test within 14 days of stable production. Attachments: 1. Current Well Schematic 2. Fluid Flow Diagrams 3. Oilsafe AR – Technical Data Sheet Steelhead Platform Well #: M-31B Completed: 04/28/18 PTD#: 212-149 API#: 50-733-20457-02-00 REVISED BY: JLL 05/21/18 B 1 26” 16” 13-3/8” C D A PBTD: 11,450 MD / 9,818’ TVD TD: 11,550’ MD / 9,854’ TVD TBG Hanger 74.5’ below RKB JEWELRY DETAIL NO Depth (MD) DEPTH (TVD) ID OD Item 1 8,643’ 8,055’ - 5.620 Discharge, Bolt On 8,643’ 8,055’ - 6.750 Pump (x2) 675 Series, 45 Stg SH16000 8,682’ 8,091’ - 6.750 Gas Separator/Intake 8,683’ 8,092’ 5.130 Seals (Upper/Lower) – 513 Series, BPBSL 8,701’ 8,109’ -5.620 Motor (x2) 562 Motor, KMSLT & KMSUT 500HP/1800V/165.5A 8,767’ 8,170’ - 5.620 Centralizer/Anode CASING DETAIL SIZE WT GRAD E CONN ID TOP BTM. 34” Surf 480’ 26"267 thru 397#Drill Quip Surf 979’ 16" 75 K-55 BTC 15.12 Surf 1,345’ 13-3/8" 61 & 68 K-55 BTC 12.42 Surf 3,722’ 9-5/8" Tieback 47# L-80 DWC/C 8.681 Surf 1,316’ 10-3/4” Liner hgr 65.7# L-80 BTC 9.5 1,316' 1,348’ 9-5/8" Liner 47# L-80 DWC/C 8.681 1,348’ 9,107’ 7” liner 26# L-80 VAM TOP HC 6.276 8,919’ 11,548’ TUBING DETAIL 4-1/2” 12.6# L-80 IBT-M 3.958 Surf 8,643’ PERFORATION DETAIL Zone Top (MD) Btm(MD) Top (TVD) Btm(TVD) Length (MD) SPF Date G1 9,361' 9,390' 8,725’ 8,754’ 29' 5 2-20-2013 G2 9,425' 9,440' 8,786’ 8,801’ 15' 5 2-20-2013 G3 9,490' 9,526' 8,843’ 8,879’ 36' 5 2-23-2013 G4 9,535' 9,600' 8,885’ 8,950’ 65' 5 2-23-2013 G5 9,674’ 9,710’ 9,003’ 9,036’ 36' 5 2-23-2013 G5 9,720’ 9,739’ 9,030’ 9,049’ 19' 5 2-23-2013 HK1 9,950’ 9,985’ 9,208’ 9,243’ 35' 5 2-23-2013 HK2 10,003’ 10,130’ 9,251’ 9,329’ 127' 5 2-23-2013 HK3-4 10,192’ 10,600’ 9,362’ 9,542’ 408' 5 2-23-2013 HK5 10,642’ 10,834’ 9,556’ 9,617’ 192' 5 2-23-2013 HK5 10,866’ 11,030’ 9,628’ 9,680’ 164' 5 2-23-2013 HK6 11,083’ 11,165’ 9,697’ 9,722’ 82' 5 2-23-2013 HK6 11,195’ 11,270’ 9,731’ 9,755’ 75' 5 2-23-2013 HK7 11,360’ 11,396’ 9,785’ 9,798’ 36' 5 2-23-2013 SCHEMATIC CASING JEWELRY NO Depth (MD) Depth (TVD)ID OD Item A 1,316’ 1,315’ Baker Flex-Lock Liner hanger & Baker HRD-E ZXP liner top packer (PKR INTENTIONALLY NOT SET!!) B 8,919’ 8,312’ 7” Liner top C 8,925’ 8,318’ Baker JM-ZXP Liner Top Packer D 9,107’ 8,488’ 9-5/8” Casing Shoe ti OF Tit, • 698", Iy., s THE RATE Alaska Oil and G s rj,r-t, � a� 0fA T ASKA Conservation Commissi n 333 West Seventh Ave ue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3 72 OF, Main: 907.279.1 33 ALAS Fax: 907.276.7 42 www.aogcc.alaska. ov May 30, 2018 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 M-31 B SEANMAY 3 0 2018 PTD 2121490 Dear Mr. Golis: On May 11, 2018 an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no-flow test of Trading Bay Unit M-31B located on the Steelhead 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 M-31 B prior to the test. The well performance was monitored for three hours. Gas flow rates at the end of three separate flow checks preceded by 1- hour pressure build up periods were within the allowable rate limits. There was also no liquid flow to surface during the no-flow test. Trading Bay Unit M-31 B 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 M-31 B 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 Steelhead Platform. Sincerely, ;(4“.6dS 'tames B. Regg Petroleum Inspection Supervisor ecc: P. Brooks AOGCC Inspectors -...,. T .-.w :� a --r R, STATE OF ALASKA *KA OIL AND GAS CONSERVATION COSSION MAY 7 2 2018 REPORT OF SUNDRY WELL OPERATIONS C 1.Operations Abandon ❑ Plug Perforations 0 Fracture Stimulate ❑ Pull Tubing 0 Operations shutdown ❑ Performed: Suspend ❑ Perforate 0 Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other:Replace ESP 0 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory ❑ 212-149 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service 0 6.API Number: Anchorage,AK 99503 50-733-20457-02-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0018730 Trading Bay Unit M-31B 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): j N/A McArthur River Field/Middle Kenai G and Hemlock Oil Pools 11.Present Well Condition Summary: Total Depth measured 11,550 feet Plugs measured N/A feet true vertical 9,854 feet Junk measured N/A feet Effective Depth measured 11,450 feet Packer measured 1,316&8,925 feet true vertical 9,818 feet true vertical 1,315&8,318 feet Casing Length Size MD TVD Burst Collapse Structural 480' 34" 480' 480' Conductor 979' 26" 979' 979' Surface 1,345' 16" 1,345' 1,344' 2,630 psi 1,020 psi Intermediate 3,722' 13-3/8" 3,722' 3,524' 3,090 psi 1,540 psi Production 1,316' 9-5/8" 1,316' 1,315' 6,780 psi 4,760 psi Liner Hanger 32' 10-3/4" 1,348' 1,347' 7,750 psi 6,300 psi Liner 7,759' 9-5/8" 9,107' 8,488' 6,870 psi 4,760 psi Liner 2,629' 7" 11,548' 9,853' 7,240 psi 5,410 psi Perforation depth Measured depth 9,361 -11,396 feet True Vertical depth 8,725-9,798 feet Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80 8,643(MD) 8,055(TVD) Baker HRD-E ZXP 1,316(MD)1,315(TVD) Packers and SSSV(type,measured and true vertical depth) Baker JM-ZXP 8,925(MD)8,318(TVD) SSSV:N/A 12.Stimulation or cement squeeze summary: Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: WOW JUN 2 1 Li ltl N/A ��►�" 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 292 190 8208 80 86 Subsequent to operation: 562 184 11456 85 93 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory ❑ Development0 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil 0 Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ❑ 3USP0 SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: ' 318-161 "' Authorized Name: Stan W.Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: dmarlowe@.hilcorp.com _ Authorized Signature: L'1 Date: 6 21 — I tl Contact Phone: (907)283-1329 Form 10-404 Revised 4/2017 RBDMS '1 MAY 16 2018 Submit Original Only ` Hilcorp• Alaska, � | �' ��^. Well Operations Summary ummary Well Name Rig API Number Well Permit Number Start Date End Date W1-31B Moncla 404 50-733-20457'02 212'149 4/14/18 4/28/18 04/14/2018-Saturday Steelhead received personnel from M/V Titan and production oriented same. Rig crew began working M/V offloaded remainder of rig package and accessory equipment.Quadco&Total Safety began setting up their systems. NOS checked out wellhead.Setup carrier walkways, mounted draw works and A-frame-pinned derrick in place. Bled pressure off 4 1/2"tubing to zero- NOS set BPV. R/I choke house,accumulator house-hooked up all lines to the accumulator house-R/U test pump. N/D production tree-NOS M/U blanked RHR X-over sub in hanger(threads looked good). Began N/U 13 5/8"5M riser. 2nd section of riser would not line up with grated hole cover. Lined up welder to modify cover. Unload M/V Titan receiving racking mat, racking mat beam and rig floor-set racking mat beam in place. Lift threads inhanger are 4l/Z''TC-II not|BT. Continued to modify top deck grating-on loaded dbl gate,anuular and mud cross.Torqued up riser#1 on well head,spooled up drilling line on draw works. 04/15/2018 Sunday Welder finished modifying grated hole cover.Stacked 2nd riser section, mud cross w/valvesdouble gate and annular (removed 2'spool).Set tong power pack and heater on each end of main beam. Prep derrick to be raised-raised and scoped out derrick securing all guy lines. MountedrigfloorvvithsupportsandvvindvvaUsmoveddhUer'sshaokinp|aoe setup stairs to both sides of floor-set super choke on carrier-loaded floor with McCoy tong-set beaver slide in place. Torqued all BOP bolts. R/U FIW line to standpipe manifold-loaded floor w/handing tools-charged koomey unit and function tested all hydraulic valves. R/U super choke lines to choke house-installed K3 valve to standpipe manifold. R/U test equipmemt w/4 1/2"test joint(RKB 48')-M/U NOS RHR sub-M/Uto hanger-filled stack w/FIW and shell tested BOPE to 2700 psi working thru leaks(test sub leaking by plug and hanger seal-pulled test dart and checked threads- m/utohunge/again-tightened |ockduvvnpinscompreoinghangersea|s'800dl0minsheUtesttoZ7O0psi).TestedaU J- �50accordpncewith ±0cl��J�AOGC[requirements. Pe�ormed /N° successful koomey draw down test- tested w/41/2''and 31/Z"tb . Witness waived (verbally) by Jim Regg/AOGCC 1644 hrs 4/15/18. B/O NOS test subs and BID test equipment- P/U T-bar and pulled BPV-M/U landing joint w/SV and screwed into hanger. 04/16/2018 Monday Backed out lock down pins-brought Total Safety and Summit onboard. IS began checking gas alarm system. Summit began setting up their equipment. Ops Eng caught incorrect test pressure on BOPE test(correct test pressure was emailed toVVSMs4/12/I8). B/Olanding jt-set BPVthen M/U4I/2''test jt-screwed into hanger. Filled system and shell tested to 3200 psi working thru leak by tb hanger.Tested all BOPE to 250psi low 3000 psi high as per emailed instructions 4/12/l8' inaccordance with Hi|corp&AO6[Crequirements.Tested w/41/Z"and 31/2^tb. Witness waived(verbaUy) byJim KeQg/AOGC[1644hn4/15/18. Pulled and B/D test jt-NOS P/UT'barand pulled BP\-M/U 4 1/2" landing jt w/TC-Il X-over pup on btm-backed out lock down pins. Pumped 15 bbls FIW down tb with water flood- screwed into hanger. Hanger came off seat at 125k-moved uphole at 138k. Pulled hanger uphole 5'and pumped 30 bbls FIW past hanger(fluids dropped out on tb&annulus). Pulled hanger to surface-NOS and Summit worked hanger- L/Dsame. PuUed1standand |eve|edrig'/e/iQgedSummitpuUingequipmentonnorthsideofp|atfo/m. POOHw/41/Z" 12.6#|8TmL,8O production��rin� rackingbackstandsinAt�5stand�OOH (233U') /ightan�|edrive�procket derrick. ' on draw works sheared off teeth. Moncla ordered parts and mechanic from town (heliport placed on standby)-rig crew prepped draw works for mechanic-mechanic onboard @ 0430 hrs-presently standing by for right angle drive from Moncla. S • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date M-31B Moncla 404 50-733-20457-02 212-149 4/14/18 4/28/18 Daily Operations;:;;; 04/17/2018-Tuesday Moncla mechanic onboard waiting for arrival of replacement right angle drive-mechanic pressed drive sprocket off shaft. 7:09 AM RAD hit helideck-lifted broken drive from carrier and set in new one. Cleaned BOP and second deck function tested right angle drive and chain check out all good.Continue POOH w/4 1/2" IBTm 12.6#Ltal production string racking back stands in derrick.Changed out ESP reel @ splice (3,879').Continue POOH w/4 1/2" IBTm 12.6#L-80 production string racking back stands in derrick. At 115 of 136 stands OOH,while pumping FIW to fill hole,—3 gals of oil burped out of tb once safety valve was opened and removed-well was not shut in at that point(no continuing flow). SO1 was generated and disseminated as directed.Secured well and cleaned deck,spattered equipment and quarters (winds 35 MPH). Finished POOH to ESP assy.Total of 67 bbls FIW pumped in well. 04/18/2018-Wednesday Summit broke down ESP assy finding 1-1 1/2" hole 1'down from top of 1st pump.Cleared and cleaned rig floor plus deck area while moving Pollard slickline equipment into position. 0930 hrs depth determination run w/SL was cancelled. Mobilized M/V Titan to P/U needed equipment from Grayling platform (drill collars,workstring, rig pump& tank, Swaco mixing tank and pill material, power swivel). M/U C/O BHA(#1) (had to P/U BJs to torque BHA)6"x 2" Varel rock bit,4 3/4"x 2 1/4" bit sub,4 3/4"x 2 1/4" B jar,4 3/4"x 2 1/4" 0 jar,4-4 3/4"x 2 1/4"spiral DCs,5"x 2 3/4" workstring xo sub=146.82'. Unloaded M/V Titan receiving rig pump&tank-spotted and setup same.Changed out Gill tongs for McCoy tongs due to decreasing torque.TIH w/C/O BHA picking up 3 1/2" PH6 work string-strapping, drifting then M/U to 7000 FPT.Worked M/V Titan as needed (used South crane due to high winds 35-40 mph). Received Swaco tank and more workstring. 170 jts in hole+BHA=5,441'at report time. 04/19/2018-Thursday Continued RIH w/C/O assy(BHA#1)(6"Varel rock bit w/jars&collars)from 5,441'to 8,696' (275 jts+ BHA). Moved H2S& LEL gas detectors from wellhead room to rig tank in preparations to circulate,taking returns(after initial circ to prod header)thru gas buster/possum belly/shaker/cutting box.Sensors were checked and documented by Total Safety during BOPE test 4/16/18. M/U safety valve& pump line-filled rig tank w/FIW-lined up to push fluid to prod header receiving FIW from prod. Filled Swaco tank w/60 bbls FIW.Started pumping FIW from rig tank(LW)to prod header at 3 BPM 335 psi. Began getting returns 40 bbls pumped away-initial returns running 60%. Well stabilized with 15-20% losses of FIW pumped. 1545 hrs Swaco tank wired up, began mixing 80 bbl SS pill. Shutdown pump at 723 bbls pumped-prod received—600 bbls thru header. Closed annulus valve. Production electrician worked thru electrical issue w/bang box after wiring up Swaco charge pump and agitators. Continued RIH (picking up singles)w/C/O BHA. Tagged at 7" liner top(8919')-attempted to work thru-no go. R/U power swivel, reorganized platform top deck, R/U crossovers,valves, replaced hose for torque sensor for BJ tongs.Tested power swivel safety valve 250 psi low 3100 psi high. R/U adapter flange w/stripping head.Washed from 8,916'through liner top w/small bobble.Circulated bottoms up SW @ 3.5 bpm 425psi (PUW 118k,SOW 90K, RW 89K).Washed down to 8,947'-circ btms up-sand and small chunks of coal in returns. Continued picking up singles,washing/rotating S/W @ 3.5 bpm 450psi from 8,947'to 9,196'.While WSM, prod elec& Eng were trying to clear light on LEL gas sensor(from rig tank)alarm tripped-rig crew shutin well and platform gathered at muster area. Prod elec changed battery in sensor and recalb same-put sensor back in service. Continued picking up singles,washing/rotating S/W @ 3.5 bpm 450 psi from 9,196'to 9,290' (at report time). ^'1/4 bbl of solids(99%sand 1%small chunks of coal) recovered in 374'of hole made. 198 bbls FIW lost in last 24 hrs for total losses of 270 bbls FIW. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date M-31B Moncla 404 50-733-20457-02 212-149 4/14/18 4/28/18 Daily Operations: 04/20/2018-Friday Continued will C/O run (6" bit w/jars&collars)from 9,290'. PUW 120k,SOW 92k, RotW 89k,4400 FPT @ 40 RPMs. Washed/rotated down @ 3 bpm 400 psi (SW) picking up 3 1/2" 12.95#P-110 PH6 workstring singles. Returns are fine to coarse sand,scale and pea size gravel-return amounts do not equal casing volume. Found hard spot at 9,408'-took longer to wash/rotate thru this spot-FIW losses increased from 2 bph to 15 bph past this depth.At 9,555'torque increased to 5500 FPs. 1145 hrs had another false indication and alarm on same LEL Total Safety sensor-took that sensor out of service.Total Safety walked prod elec thru setting up backup sensor-placed it in service at rig tank/gas buster. Depth is 9,570'. M/U#304 on swivel and continued washing/rotating(losses running at 22 bph now). 1345 hrs at 9,645' circ pressure began to increase-turned fluid around f/3 mins(LW). Began circ(SW)at 3 bpm 400 psi- washed/rotated to EOJ at 9,663'.Torque running 6000 FPs now-trickled in one drum of CFS-520 into rig tank. 1645 hrs torque now running at 3800 FPs. Depth is 9,816'. M/U#312 on swivel and continued washing/rotating(losses running at 36 bph now) PUW 117k SOW 97k RotW 92k pumping @ 3.25 BPM 450 PSI (SW). Depth is 10,129'. M/U#322- washed/rotated down to mid jt-losses increasing-washed/rotated to E0.1@ 10,160(losses now running 75 BPH). M/U #323 (tb now on vacuum)-attempted to circ S/W for 10 mins w/no returns.Switch over L/W to circ down tb-string plugged now. Worked and surged string, pressuring 500-1000 psi in attempts to clear plug-no go. B/0 power swivel- N/D adapter flange w/stripping head-R/U mud bucket. POOH standing back a portion of workstring(prod string in derrick). 25 stands out at report time=8,544'.454 bbls FIW lost to formation during last 24 hrs for a total of 719 bbls lost. 1 1/4 bbl of solids recovered in cutting box for a total of 1 1/2 bbls(scale&sand)since beginning of cleanout. 04/21/2018-Saturday Continued POOH w/plugged C/O BHA from 8,544'(25 stands in derrick)to 7,733'(38 stands of workstring in derrick- 134 stands of 4 1/2" completion tb in derrick also). Pumped 10 bbls FIW every 40 jts laid down. Began laying down 3 1/2" 12.95#P-110 PH6 workstring. Discussed noise in gearbox with Moncla pusher and manager. 200 jts OOH when fire alarm was sounded. Installed SV and closed annular-shutdown rig motor and heater.All personnel mustered for fire and abandon platform drill.Continued POOH laying down workstring to 1,225'. Moncla crew pulled off the plate for the right angle gearbox for inspection and found out the grearbox gears were stripped_and chunks of metal in pan.Crew prepped to pull out old one. Moncla mechanic to rebuild one in town,will be ready in am to come out to the Steelhead. Crew continued organizing deck and Hilcorp sub baskets and fill hole w/fiw 10 bbls every hour. Waiting on parts. @ 03:30 parts read, 04:00 Moncal mechanic arrives to pull old part and prep for new.86 bbls FIW lost to well during last 24 hrs for a total of 805 lost. • • Hilcorp Alaska, LLC Well Operations Summary Y Well Name Rig API Number Well Permit Number Start Date End Date M-31B Moncla 404 50-733-20457-02 212-149 4/14/18 4/28/18 Daily Operations: 04/22/2018-Sunday Continued cleaning and organizing deck and baskets while waitinl?onrightangledrive 0700 hrs RAD hit helideck- installed and function tested drive. Continued POOH w/plugged C/0 assy from 1,225'to BHA. B/0 1st stand of 4 3/4" DCs to find them open, 2nd stand of collars were plug-attempted to clear them but decided to stand them back-called for 2- DCs from Grayling.Cleared oil, bumper jar and bit. Picked plugged stand of collars back up and broke them down-still unable to unplug them.Two collars from Grayling onboard.Cleaned rig floor after wet trip and clearing BHA. M/U BHA#2(same as#1 except DC length is 1.07' longer)6"x 2" Varel rock bit,4 3/4"x 2 1/4" bit sub,4 3/4"x 2 1/4" B jar,4 3/4"x 2 1/4" 0 jar,4-4 3/4"x 2 1/4"spiral DCs, 5"x 2 3/4"workstring xo sub= 147.89'.TIH w/BHA#2 on 3 1/2" PH6 workstring f/derrick to 460'- hooked up hose and flushed 10 bbls FIW thru BHA.Continued RIH w/3 1/2" PH6 workstring pumping 20 bbls at 2,590'and 40 bbls at 6,060'.8,386' in hole at report time. BOPE test due today-witness waived(verbally) by Jim Regg/AOGCC 1947 hrs 4/22/18. 130 bbls FIW lost to formation last 24 hrs for total losses of 935 bbls. Total of 1 1/2 bbl of solids recovered from cleanout so far. 04/23/2018 Monday Continued RIH w/BHA#2 (6" bit,jars&collars)from 8,386'to 9,322'. Lined up and pumped 80 bbl sized salt pill down tb-chased same w/40 bbls of FIW. M/U test plug on jt of 3 1/2"tb w/x-overs&pups-landed same in tb head-M/U pumpin,SV& IBOP on top. Filled system w/FIW and shell tested to 3000 psi.Tested all BOPE to 250psi low 3000 psi high as per Sundry, in accordance with Hilcorp&AOGCC requirements.Tested w/3 1/2"and 4 1/2"tb. Performed successful koomey draw down test.Witness waived (verbally) by Jim Regg/AOGCC 1947 hrs 4/22/18. B/0 IBOP,SV and pumpin-pulled test plug w/4 1/2"test jt-B/O same. R/D and cleared test equipment from floor. Continued RIH w/BHA #2(6" bit,jars&collars)from 9,322't/10130'. R/U hoses to tiw valve on 3 1/2"workstring and pump l/w @ 3.5 bbls min w/60 psi 100 BBIs no returns I/u s/w and 50 bbls way and 20%returns lost rate 105 bbls hr. Lined up and pumped 80 bbl sized salt pill down tb-chased same w/60 bbls of FIW. 115 bbls way fill returns with no losses shut down and monitor well 10 mins w/no losses. R/U power swivel and adapter flange w/horsehead.Start mixing pill# 3 80 bbl sized salt pill.Stand by if needed. B/C @ @ 2.5 bbl min s/w circ and get washing parameters pres all over f/ 500 psi 1100 psi and continued pump out 75 pill. Pumping down workstring seems to go well 250 psi w/fill returns w/lost rate 10 bbls hrs. Continued getting parameters s/w and check all surface equipmemt and c/o 2" high pres mud line hoses.Work on surface equipment and troubleshoot high pres pump lines and manifold valves. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date M-31B Moncla 404 50-733-20457-02 212-149 4/14/18 4/28/18 Daily Operations: 04/24/2018-Tuesday Bypassed power swivel and standpipe manifold from circulation path-broke circ again SW at 1.6 bpm 1030 psi, 108 bph loss rate. Pressure dropped off to 850 psi at 1.85 bpm (loss rate increasing)-0745 hrs lost all returns. Lined up and pumped tb volume(LW)at 550 psi 2.34 bpm 10 bph losses.Shut down pump, U-tubing on tb side now.Tied swivel and manifold back into system as before. M/U single#322 on power swivel-opened and removed safety valve. M/U to string-eased down w/o turning or pumping(SOW 80k)-tagged 10'in on single= 10,140'. Pulled back to 10,130' (PUW 120k). Began pumping down tb at 3.6 bpm 800 psi, loss rate running 30 bph. Half way into flush, pressure started decreasing-getting pill material back now. 1130 hrs pressure running 315 psi 3.73 bpm 20 bph. Lined up to reverse- established parameters: SOW 80k, PUW 120k, RotW 90k,4000 FPT. Began circ(SW)2.5 bpm 500 psi-began washing/rotating from 10,130'. Flushed more pill out-pressure now running 3.3 bpm 240 psi 45 bph losses(pill in active tank unbalancing system). 1530 hrs losses at 120 bph-within 30' losses now at 36 bph-single#326 went down w/o rotating. Depth now is 10,284'. Reversed full tb volume at 10,284'(while we had good returns)-2.78 bph 400 psi losses at 36 bph. Ran#327 in to 10,315'w/o rotating or circ.Continue in to 10,416'and started taking a little weight-decided to rotate and wash to EOJ. Broke circ at 2.85 bpm 510 psi (losses at 36 bph)-washed/rotated to EOJ at 10,438'. Continue p/u pipe and rih f/10,438't/10625'with no issue. Reversed full tb volume 1 1/2 time tb volume w/good returns rate @ 18 bbls hr. Continue p/u pipe f/10625'/11401'w/no issue. Began pumping down back side at 3.5 bpm 600 psi, loss rate running 8-14 bph and wash f/11401 t/11450' SOW 79k PUW 145k.Continue circ hole clean. 683 bbls FIW lost to formation in the last 24 hrs f/ total losses of 1938 bbls. 1/4 bbl of solids recovered in last 24 hrs f/a total of 13/4 bbl solids. 04/25/2018-Wednesday Lined up(LW), permitted and pumped 100 bbls FIW treated w/bleach due to 1%diluted sized salt pill and .1%CFS-520 (to make room in rig tank).Spotted 80 bbl sized salt pill on btm (for disposal)-chased w/50 bbls FIW. B/D packed up power swivel-N/D stripping head w/adapter spool. POOH (from 11,450'-364 jts) laying down 3 1/2" 12.95#P-110 PH6 workstring pumping 10 bbls every 40 jts. 175 jts laid down (6,029'). Continue POOH laying down 3 1/2" 12.95#P-110 PH6 workstring pumping 10 bbls every 40 jts. Offload boat(Summit spooler, power and flatpack cable, connex).Spot Summit spoolers on drill deck, load flatpack and power cable in spoolers.Summit cuts,shortens and re-splices motor lead. 289/364 jts. laid down (2,496').Continue POOH laying down 3 1/2" 12.95#P-110 PH6 workstring pumping 10 bbls every 40 jts. Change out McCoy backups. 364 jts laid down. Lay down BHA(3-1/2" PH-110 box X IF pin X-over,4 Drill Collar 3-1/2", daily oil and bumper jars, bit sub and 6" rock bit). Clear and clean rig floor.95 bbls FIW lost to formation last 24 hrs for a total losses of 2033 bbls FIW. 13/4 bbls of solids recovered during C/O. • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date M-31B Moncla 404 50-733-20457-02 212-149 4/14/18 4/28/18 Daily Operations: 04/26/2018-Thursday Prep rig floor to M/U & run ESP assy. P/U 1st 5.62"500 HP motor w/gauge&cent/anode on btm-serviced w/oil. M/U 2nd motor on 1st and lowered in hole-attached oiling hose then P/U and service 2nd motor. R/U Summit sheaves w/ cable&flat pack-P/U to EOT and attached flat pack lines to gauge and chem inj ports. Lowered motors in hole placing clamps as needed.Attached seal sections(2)w/intake-connected motor lead and began oiling seals. Cleaned Swaco tank and dumped into rig tank-sent 120 bbls FIW w/diluted salt pill w/bleach added to TBF. Lowered assy in hole installing clamps as needed. M/U pump section (2)attaching clamps as needed. M/U handling jt w/discharge head, ported pressure sub and IBT x-over(clamped as needed). Cleared floor of ESP M/U equipment-loaded floor w/clamps. Tong power pack down-tied into rig hydraulics while electrician checks out power unit. Clean out solids from rig tank with super-sucker unit transferring solids to mud box. RIH with Summit Dual Motor/Dual Pump ESP completion on 4- 1/2" IBT-M 12.6 lb/ft.tubing(re-used) rabbiting each stand out of derrick and attaching clamps as needed. MU connections to mark to establish make up torque, MUT=3200 ft/lbs.Summit test cable every 14 stands. M/V Titan arrives,offload McCoy tings and backup power pack. Change out McCoy tongs. Electric power pack operational, rig up tongs to same. 14 stands(1,041') Summit testing cable.Continue RIH with Summit Dual 500 HP Motor/Dual Pump ESP completion on 4-1/2" IBT-M 12.6 lb/ft.tubing (re-used) rabbiting each stand out of derrick and attaching clamps as needed. MU connections to mark to establish make up torque, MUT=3200 ft/lbs.Summit test cable every 14 stands. Work M/V Titan back loading 3/12" P110 work string, Swaco tank and pallets of salt(0:00-03:30 hrs.),84 stands (5,463')Summit testing cable. Continue RIH with ESP completion on 4-1/2" IBT-M 12.6 lb/ft.tubing (re-used) rabbiting each stand out of derrick and attaching clamps as needed. 100 stands in hole at report time(6,433')-changing out cable spools, prepping to make splice.0 FIW lost to formation last 24 hrs. 04/27/2018-Friday Finished ESP cable splice and M/U stand#103-splice is 12' up on jt#205=2,151'from surface. Rig pump and tank taken out of service(water flood connected to kill side on mud cross)-moved LEL& H2S sensors to well bay area (we are reverting to"approved alternate circulation system" as approved in Sundry.All electrical shutdown at bang box- production electrician worked out the problem.Continued RIH w/ESP completion assy from 6,615'to 8,715'electrically checking cable every 14 stands. NOS rep M/U hanger on handling jt-Summit plumbed ESP cable and flat pack lines thru hanger. Landed hanger placing EOT at 8,767'-74k SOW, 145k PUW(had to P/U 8'to change out a pup while landing hanger) NOS rep ran in LDS. L/D 4-1/2" handling joint-NOS rep set BPV. Rig down Summit sheaves. Cleared and cleaned rig floor. Rigged down tongs&wind walls-dismounted rig floor. Backload Summit equipment to M/V Titan.Scope in, lay over derrick. Nipple down BOPE. Rig crew began N/U Tree. Finished filling one 15 bbl cutting box with fine sand/silt from sand trap on rig tank.0 FIW lost to well last 24 hrs.Total losses are 2033 bbls FIW. 04/28/2018-Saturday Continued N/U lower portion of tree w/rig crew. NOS rep tested hanger void to 500 psi 5 mins 5000 psi 15 mins. Rig crew N/U upper portion of tree as directed by production- NOS pulled BPV&set 2WC. Shell tested tree to 500 psi 5 mins-tested at 1500 psi, bonnet seal blew at—4000 psi on shell test. Rig crew began tearing down tree. M/V Resolution arrived-back loaded draw works, koomey house and A-frame.Shut down back loading W/O equip to assist rig crew w/ tree rebuild. Began working M/V Resolution again-back loaded rig carrier&strong back beams. NOS rep pulled 2-way check and installed BPV. Rig crew unbolted SSV and flow line then installed and torqued down replacement SSV and flow line. NOS pulled BPV&set 2WC-shell tested tree 500 psi &5000 psi (visual)-pulled 2WC. Turned well over to production at 1830 hrs. `US 0 Steelhead Platform Well #: M-31B Hilcorp Alaska,LLC SCHEMATIC Corn p1 ete d: 04/28/18 PTD#: 212-149 API#: 50-733-20457-02-00 TBG Hanger 74.5'below RKB CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 9JJ l 26 u ' v A ' ^ 34" Surf 480' 26" 267 thru 397# Drill Quip Surf 979' '11 � A • 16" � 16" 75 K-55 BTC 15.12 Surf 1 345' 13-3/8" 61&68 K-55 BTC 12.42 Surf 3 722' 9-5/8"Tieback 47# L-80 DWC/C 8.681 Surf 1 316' 13-318" 10-3/4"Liner hgr 65.7# L-80 BTC 9.5 1,316' 1 348' 9-5/8"Liner 47# L-80 DWC/C 8.681 1,348' 9,107' 7"liner 26# L-80 VA HC OP 6.276 8,919' 11,548' I TUBING DETAIL 4-1/2" 12.6# L-80 IBT-M 3.958 Surf 8,643' JEWELRY DETAIL Depth DEPTH ID NO (MD) (ND) OD Item 8,643' 8,055' - 5.620 Discharge,Bolt On 8,643' 8,055' - 6.750 Pump(x2) 675 Series,45 Stg SH16000 8,682' 8,091' - 6.750 Gas Separator/Intake ri 1 8,683' 8,092' 5.130 Seals(Upper/Lower)-513 Series,BPBSL ,....., Motor(x2)562 Motor,KMSLT&KMSUT 14 8,701' 8,109' 5.620 500HP/1800V/165.5A 8,767' 8,170' - 5.620 Centralizer/Anode 7 IF B CASING JEWELRY s Depth Depth NO (MD) (TVD) ID OD Item A 1 Baker Flex-Lock Liner hanger&Baker HRD-E ZXP liner top packer(PKR '. D 316' 1'315' INTENTIONALLYNOTSETI!!) B 8,919' 8,312' 7"Liner top . C 8,925' 8,318' Baker.1M-ZXP Liner Top Packer D 9,107' 8,488' 9-5/8"Casing Shoe • PERFORATION DETAIL Top Zone (MD) Btm(MD) Top(TVD) Btm(TVD) Length(MD) SPF Date G1 9,361' 9,390' 8,725' 8,754' 29' 5 2-20-2013 -- G2 9,425' 9,440' 8,786' 8,801' 15' 5 2-20-2013 G3 9,490' 9,526' 8,843' 8,879' 36' 5 2-23-2013 G4 9,535' 9,600' 8,885' 8,950' 65' 5 2-23-2013 G5 9,674' 9,710' 9,003' 9,036' 36' 5 2-23-2013 G5 9,720' 9,739' 9,030' 9,049' 19' 5 2-23-2013 1 HK1 9,950' 9,985' 9,208' 9,243' 35' 5 2-23-2013 HK2 10,003' 10,130' 9,251' 9,329' 127' 5 2-23-2013 1. HK3-4 10,192' 10,600' 9,362' 9,542' 408' 5 2-23-2013 . HK5 10,642' 10,834' 9,556' 9,617' 192' 5 2-23-2013 a HK5 10,866' 11,030' 9,628' 9,680' 164' 5 2-23-2013 HK6 11,083' 11,165' 9,697' 9,722' 82' 5 2-23-2013 PBTD:11,450 MD/9,818'TVD HK6 11,195' 11,270' 9,731' 9,755' 75' 5 2-23-2013 TD:11,550'MD/9,854'TVD HK7 11,360' 11,396' 9,785' 9,798' 36' 5 2-23-2013 REVISED BY:JLL 05/21/18 • S MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg ,1 C 6/Z l9) DATE: 5/13/2018 P. I. Supervisor1 FROM: Adam Earl SUBJECT: No Flow Test Petroleum Inspector TBU M-31B Hilcorp Alaska LLC PTD 212-149 5/11/18: I traveled out to Steelheadp latform to witness a No-Flow Test to be conducted by operator, Danny Byrd. The well to be tested was M-31 B, an ESP production well. I walked down the rig-up, the well, and lines. The tubing and I/A were tied together at surface, due to the packer-less completion. The well had been opened to bleed down to zero for the last 24 hours. The test would consist of the well shut in and pressures recorded, every 30mins. The tubing/IA would be opened to flow through a SCFH meter on the hour, 3 consecutive times. The following table shows test details: Time Pressures' Flow Rate2 Remarks (psi) Gas-scf/hr Liquid -gal/hr 8:30 0/0/80 Shut in to start test 9:00 0.01/0.01/80 9:30 0.01/0.01/80 . 200 0 Opened to SCFH meter for 3min; decreased to 50 scf/hr; SI 10:00 0.01/0.01/80 - 10:30 0.1/0.1/80 300 0 Opened to SCFH meter for 3min; decreased to 75 scf/hr; SI 11:00 0.01/0.01/80 e 11:30 0.02/0.02/80 350 , 0 Opened to SCFH meter for 3min; decreased to 100 scf/hr 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: Test equipment calibration certificates Equipment photos SCANNED JUN 0 12c? g 2018-0511_No-Flow_TBUM-31 B_ae.docx Page 1 of 4 • • , ,00010,411110' s . RAV- v f ° Wi-' M �— 51' L V E � x _ � — —. a Wo a xU M —a ,,%` \ O Z W O i lab ii 61 " M W ^ . ii o �--i atY N 4., [= cJ to .;•,".,'., + o w ', °' o ,-- z al. or 4 O K,,,,,.444,rk .1 J..�,. ¢, N ; • ' '' yr - .•: ,r.:°''' :.:)\ r 1 • s'. F N * , 0 . ' .•.:., •- ..: 4 .,... ' . N ' ...r `� , COLIJ , , ,.. .,. .4,,,:-.„2,:-.:, : .. .7'... ..,?1----... ---... QL_ It t 1 A 1i �I ,. ♦ ere � .n �. '� "'a r I ^` , ) E SI ' Y 4h I O ` .` y A M`_ `g• y ti o t • ` e y' 7l y 0 • a 0 w ,l` ` :» ., t dam.IP VA gym �M p 1 ...., E,\ CS V to, '" k°' ! I o 03 I ` y 0. rry �O I � . r2 tb r on oMI 444 r U 4 W. F� O ct 1 ( wy f• s + :xg0. > 11. a " A- eq ,may, , ~;. rA >,. '� '`; • • ' i! M V a q o o U z N h aLL m Z N m O r !/1 W z a `a U o1 Ct rte. ill N o .a o ,Q Z g`W N � m m` O N ~ T 1 r, i, a C ii , c m p mo I a Wcn Q .� °d 8 M m o� � o o �� $_ P: 0 u 74 ,_,0r t o k v Nw I A N "0 0 N c N 0I = n en ' S °� Iy `, b4 f #� o zI • �° r a 1. HHH �( j 0 26 o El E v1 , h W To' vco 41 E v E °'RI 1-4 r- « c. r: 'O 'iV we am- cZ0 N O'OM tiC 61 m ›,"5 ItLai V yvwiIP 7Z c4) . ., flgi fsm JI ) � c /. �� I I 'ma } 'I ; { ..r. z^ ti OF T� THE STATE• Alaska Oil and Gas of L�Sl� Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 GOVERNOR BILL WALKER Main: 907.279.1433 OF ALAS*P' Fax: 907.276.7542 www.aogcc.alaska.gov Stan Golis Operations Manager APR 2 5-1618' Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: McArthur River Field, Middle Kenai G and Hemlock Oil Pools, TBU M-31 B Permit to Drill Number: 212-149 Sundry Number: 318-161 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, 027•CC Hollis S. French , Chair DATED this t O day of April, 2018. RBDM APR 2 3 2018 RECEIVED 0 0 APR 1 1 2018 STATE OF ALASKA IZ /)a,1 r 1 ALASKA OIL AND GAS CONSERVATION COMMISSION �y APPLICATION FOR SUNDRY APPROVALS /� OGCC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations 0 Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing 0 Change Approved Program 0 Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well 0 Alter Casing ❑ Other Replace ESP 0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number Hilcorp Alaska,LLC Exploratory ❑ Development 0 • 212-149 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic CIService ❑ 6.API Number Anchorage,AK 99503 50-733-20457-02-00 • 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? N/A 1. Will planned perforations require a spacing exception? Yes ❑ No 0 ✓ Trading Bay Unit M-318 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0018730 McArthur River Field/Middle Kenai G and Hemlock Oil Pools 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 11,550 , 9,854 . 11,450 , 9,818 2,268 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural 480' 34" 480' 480' Conductor 979' 26" 979' 979' Surface 1,345' 16" 1,345' 1,344' 2,630 psi 1,020 psi Intermediate 3,722' 13-3/8" 3,722' 3,524' 3,090 psi 1,540 psi Production 1,316' 9-5/8" 1,316' 1,315' 6,780 psi 4,760 psi Liner Hanger 32' 10-3/4" 1,348' 1,347' 7,750 psi 6,300 psi Liner 7,759' 9-5/8" 9,107' 8,488' 6,870 psi 4,760 psi Liner 2,629' 7" 11,548' 9,853' 7,240 psi 5,410 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 9,361 -11,396 ' 8,725-9,798 4-1/2" 12.6#/L-80 8,644 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Baker HRD-E ZXP Pkr&Baker JM-ZXP Pkr&N/A 1,316(MD)1,315(TVD)/8,925(MD)8,318(ND)&N/A 12.Attachments: Proposal Summary 2 Wellbore schematic 2 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch C3 Exploratory ❑ Stratigraphic❑ Development • Service 0 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 4/15/2018 OIL CI• WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: LOW/S} GAS ❑ WAG 0 GSTOR ❑ SPLUG ❑ Commission Representative: LF. S-:,j,'w;st,,r-ii._- GINJ 0 Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is hie and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Stan W.Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: dmariowet hiicorp.com /� // /� Contact Phone: 283-1329 Authorized ro/Z 7 7'o/Z 3 Ti4•W I,U• GO U S COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. /✓�/) It- A 1`-Ce I Plug Integrity ❑ BOP Test 1 Mechanical Inte rity Test ❑ Location Clearance ❑ Other: ) . 3( i3( r_-.c- ,6c) „P r I-- Post Initial Injection MIT Req'd? Yes ❑ No ❑ .ri,� Spacing Exception Required? Yes 0 No Subsequent Form Required: /o--q c)4 RBDM /v1 PR Z 3 Z01 CI APPROVED BY Approved by: . COMMISSIONER THE COMMISSION Date: 9 te,),e_ yiikl i% --yn� 9 f/z// ,00 9 ,6(/ n^ r■ AL Submit Form and Form 10-403 Revised 4/2017 Approved appli ti rPvIlGril m the date of approval. Attachments in Duplicate • Well Work Prognosis Well: M-31B Hilcorp Alaska,LLC. Well Name: M-31B API Number: 50-733-20457-02 Current Status: ESP Producer Leg: B-1 Estimated Start Date: 04/15/2018 Rig: HAK Rig 51 or Moncla 404 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett(8332) Permit to Drill Number: 212-149 First Call Engineer: Dan Marlowe (907)-777-1329(0) (907)398-9904(M) Second Call Engineer: Mike Quick (907)-777-8442(0) (907)317-2969(M) Current Bottom Hole Pressure: 3,140 psi @ 8,725'TVD 0.360 lbs/ft(6.92 ppg)based on ESP Gauge Maximum Expected BHP: 3,140 psi @ 8,725'TVD 0.360 lbs/ft(6.92 ppg)based on ESP Gauge Max.Potential Surface Pressure: 2,268 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) ""'This is a no flow well as of 03/08/2013 Brief Well Summary M-31B is a G / Hemlock Producer completed with an ESP. The ESP experienced a down-hole failure April 11, 2018.We plan to pull and replace the ESP. ✓ Last Casing Pressure Test: 02/14/2013 at 11,450' (prior to perforating)to 1,500 psig and charted for 30 minutes Procedure: 1. MIRU Moncla 404 2. Attempt to pump through ESP to circulate hydrocarbon off the well to production. General note-Work over fluid will be FIW and BOP's will be closed as needed to circulate the well. 3000 r°- 3. ND Wellhead, NU BOP and test to 250psi low/3,5800 high. (Note: Notify AOGCC 48 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. If needed - RIH with cleanout assembly, Circulate bottoms up, POOH. 7. PU, RIH with ESP completion. 8. Land ESP 9. ND BOP, NU wellhead and test. 10. Turn well over to production. 11. Conduct SVS testing per AOGCC regulations. Well Control: Hilcorp requests a variance to normal fluid handling from 20 AAC 25.285 (h). The request is to supply kill fluid from and take returns to the production facility instead of the rig circulating system. The Steelhead production ,, facility can supply and receive more fluid than the rig circulating system. (Injection Pressure=2,900psi.) A4-ASG,./4_i/ Hilcorp also offers the following in support of this variance: • The nature of the M-31b work is to pull a failed ESP and run a like in kind unit. • The M-31b is a no flow well. • No other well work is planned. Currently there is no plans for a cleanout run, and no addition of perforations that could cause exposure to additional reservoir pressure. (If a cleanout is deemed necessary during the workover the pits shakers and pumps will be rigged up at that time. • Well Work Prognosis Well: M-31B Hilcorp Alaska,LLC • Hilcorp plans to circulate any hydrocarbon off the well and control any potential kick from the well by implementing the "Well Kick Procedure". • A drawing of the circulating system is also attached. Well Kick Procedure: 1) Stab TIW floor valve&close 2) Close annular preventer 3) Line up Kill side to waterflood 4) Option A a. Line up Annulus to production header b. Open TIW valve an begin displacing well from waterflood header to production header via annulus valve. �2e� �ti, /4-e,. . 5) Option B a. Line up Choke Manifold to production header b. Open TIW valve and & begin displacing well from waterflood header to production header via choke manifold. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Wellhead Diagram (Current and Proposed) 4. Moncla 404-BOP Drawing 5. Moncla 404-BOP Drawing showing circulation system 6. Moncla 404—Fluid Flow diagram 7. Moncla 404-Rolling BOP Test Procedure 8. HAK Rig 51-BOP Drawing 9. HAK Rig 51—Fluid Flow diagram 10. HAK Rig 51-Rolling BOP Test Procedure 11. RWO Sundry Revision Change Form II 0 0 Steelhead Platform Well #: M-31B Ililcorp Alaska,LLC SCHEMATIC Completed: 05/01/16 PTD#: 212-149 API#: 50-733-20457-02-00 TBG Hanger 74.5'below RKB CASING DETAIL l SIZE WT GRADE CONN ID TOP BTM. 4 w'P.1 26,, 34" Surf 480' 26" 267 thru Drill Quip Surf 979' + 397# A 16" 16" 75 K-55 BTC 15.12 Surf 1,345' 13-3/8" 61&68 K-55 BTC 12.42 Surf 3,722' 9-5/8"Tieback 47# L-80 DWC/C 8.681 Surf 1,316' - 13.3/8.. 10-3/4"Liner hgr 65.7# L-80 BTC 9.5 1,316' 1,348' 9-5/8"Liner 47# L-80 DWC/C 8.681 1,348' 9,107' 7"liner 26# L-80 VA HC OP 6.276 8,919' 11,548' TUBING DETAIL 4-1/2" 12.6# L-80 IBT-M Surf 8,644' Jewelry Detail NO Depth ID OD Item 1 8,644' - 6.750 Discharge 2 8,645' - 6.750 Pump(x2)45 Stg SH16000 3 8,684' - 6.750 Intake 4 8,703' - 5.620 Motor(x2)562 Motor,KMSUT 500HP 1 5 8,768' - 5.620 Anode 2 ' 30 , 4 5 Q CASING JEWELRY NO Depth Length ID OD Item 7 r " " B Baker Flex-Lock Liner hanger&Baker HRD-E ZXP liner top packer(PKR A 1,316' INTENTIONALLY NOTSET!!!) F; d C B 8,919' 7"Liner top ,e? C 8,925' Baker JM-ZXP Liner Top Packer D D 9,107' 9-5/8"Casing Shoe f , PERFORATION DETAIL ` Top Zone (MD) Btm(MD) Top(TVD) Btm(TVD) Length(MD) SPF Date r G1 9,361' 9,390' 8,725' 8,754' 29' 5 2-20-2013 ! G2 9,425' 9,440' 8,786' 8,801' 15' 5 2-20-2013 ' d G3 9,490' 9,526' 8,843' 8,879' 36' 5 2-23-2013 G4 9,535' 9,600' 8,885' 8,950' 65' 5 2-23-2013 G5 9,674' 9,710' 9,003' 9,036' 36' 5 2-23-2013 G5 9,720' 9,739' 9,030' 9,049' 19' 5 2-23-2013 ' HK1 9,950' 9,985' 9,208' 9,243' 35' 5 2-23-2013 HK2 10,003' 10,130' 9,251' 9,329' 127' 5 2-23-2013 HK3-4 10,192' 10,600' 9,362' 9,542' 408' 5 2-23-2013 HK5 10,642' 10,834' 9,556' 9,617' 192' 5 2-23-2013 HK5 10,866' 11,030' 9,628' 9,680' 164' 5 2-23-2013 4. ? HK6 11,083' 11,165' 9,697' 9,722' 82' 5 2-23-2013 HK6 11,195' 11,270' 9,731' 9,755' 75' 5 2-23-2013 'A HK7 11,360' 11,396' 9,785' 9,798' 36' 5 2-23-2013 PBTD:11,450 MD/9,818'TVD TD:11,550'MD/9,854'TVD REVISED BY:JLL 05/06/16 . . • • 11 Steelhead Platform Well #: M-31B Hileorp Alaska,LLC PROPOSED Completed: FUTURE PTD#: 212-149 API#: 50-733-20457-02-00 TBG Hanger 74.5'below RKB CASING DETAIL ,*,� SIZE WT GRADE CONN ID TOP BTM. Pts" 34" Surf 480' 26" 267 thru Drill Quip Surf 979' {� 16„ 397# Vii A 16" 75 K-55 BTC 15.12 Surf 1,345' 13-3/8"/ 61&68 K-55 BTC 12.42 Surf 3,722' 9-5/8"Tieback 47# L-80 DWC/C 8.681 Surf 1,316' ~ X13-3/8" 10-3/4"Liner hgr 65.7# L-80 BTC 9.5 1,316' 1,348' 9-5/8"Liner 47# L-80 DWC/C 8.681 1,348' 9,107' 7"liner 26# L-80 VA HT OP 6.276 8,919' 11,548' TUBING DETAIL 4-1/2" 12.6# L-80 IBT-M Surf ±8,645' JEWELRY DETAIL Depth DEPTH ID NO (MD) (TVD) OD Item ±8,645' ±8,056' - Discharge,Bolt On Pump(x2) 1 Intake - Motor(x2) ±8,770' ±8,173' - Anode 1 'fk, .0 CASING JEWELRY NO Depth Length ID OD Item c P j B A 1,316' Baker Flex-Lock Liner hanger&Baker HRD-E ZXP liner top packer(PKR r ", 3 rrti C INTENTIONALLY NOT SEIM) B 8,919' 7"Liner top ` D C 8,925' Baker JM-ZXP Liner Top Packer D 9,107' 9-5/8"Casing Shoe ut rl' a PERFORATION DETAIL -0 Top {� Zone (MD) Btm(MD) Top(TVD) Btm(TVD) Length(MD) SPF Date II G1 9,361' 9,390' 8,725' 8,754' 29' 5 2-20-2013 apt G2 9,425' 9,440' 8,786' 8,801' 15' 5 2-20-2013 a41 G3 9,490' 9,526' 8,843' 8,879' 36' 5 2-23-2013 't; G4 9,535' 9,600' 8,885' 8,950' 65' 5 2-23-2013 .J G5 9,674' 9,710' 9,003' 9,036' 36' 5 2-23-2013 ' G5 9,720' 9,739' 9,030' 9,049' 19' 5 2-23-2013 2 HK1 9,950' 9,985' 9,208' 9,243' 35' 5 2-23-2013 k. ::, HK2 10,003' 10,130' 9,251' 9,329' 127' 5 2-23-2013 L4 HK3-4 10,192' 10,600' 9,362' 9,542' 408' 5 2-23-2013 i; q HK5 10,642' 10,834' 9,556' 9,617' 192' 5 2-23-2013 HK5 10,866' 11,030' 9,628' 9,680' 164' 5 2-23-2013 11 '.1 HK6 11,083' 11,165' 9,697' 9,722' 82' 5 2-23-2013 HK6 11,195' 11,270' 9,731' 9,755' 75' 5 2-23-2013 till ' HK7 11,360' 11,396' 9,785' 9,798' 36' 5 2-23-2013 PBTD:11,450 MD/9,818'TVD TD:11,550'MD/9,854'TVD REVISED BY:JLL 04/11/18 , . ill US Steelhead Platform M-31B Hilrrsrp Alaaska.1.t.0 Steelhead Platform Tbg hanger,FMC-TC-IA-EN- M-31B EC-CCI.,11 5M X 4%18T lift 26X16X133/8X95/8X and susp,w/4"Type H BPV 41/2 profile,2-1/4 continuous control line ports 13FF1A,Bowen, 41/165M FE X 7-5SA Bowen top III n.MIMI 111111111.1.... �Valve,Swab,WKM-M, p ,a, 41/165M FE,HWO,DD Zfor il 1,1011 Or Valve,upper master,SSV, ..�' 41/165M FE,w/15"Sateen ® s !`� operator,EE ' Valve,wing,WKM-M, 'c/ / _. 41/16 SM FE,HWO,DD Valve,Master,WKM-M, O 41/165M FE,HWO,DD �» '1 NM I ■ X2 co�tr��, — Adapter,FMCA-3-EC, - 115M X41/165M,prepped fIII 1111 continuousW control sub,2-%opt Icontinuous control line exits el 1111"..111•R Attachment spool,FMC-TC, ,1if 16%5M stdd btm x 11 5M FE top,1minlength,30.00" L. min bore Tubing head,FMC-TC-60,spec for -a•— 1111' tIsMIIIIIII. unihead,16%5M FE top X 16%5M stdd bottom,w/2-21/16 5M SSO I1 111: . 1 , t...„,„. 1 .,.., , Unlhead,FMC Type 2,16%5M Valve,FMC-120, FE top X21%2M FMC speedlock 21/165M FE,HWO,AA bottom,w/4-21/165M55O I'I �h 4E11 f: — fil.i.. III,. ' 1,11— Adapter spool,f ! ��ir,..11111111. evgitairs . MC-A-5-S 30"MSS ��,a p ll* stdd bottom X 21%2M FMC speedlock top,w/2-2"L PO A� �I ,q:`::. Starting head,FMC,30"MSS �' _ I- - FEX 26"butt weld 41 I■ ■I 26" 16" 13 3/8" 9 5/8" 4 1/2 • Steelhead Platform 2018 Moncla 404 04/11/2018 Flilrorp 11r.I.A.1.11. O O 1 7 1 I I Shaffer 3.74' 13 5/8 5M I TT _..N 2 7/8-5 variables 4.67' Blinds -ti III ill I1I 11i .moi. III I!I'Ii1'1}I 1!1 • Pi 2.26' _e _ Ir7i�(�I 16q ThIil I � 2 1/16 5M HWO and HCR valves III III 161 161 1.61 21.75' Riser 13 5/8 5M#13 API hub X 13 5/8 5M FE Riser 13 5/8 5M#13 API hub X 13 5/8 5M FE 18.83' !1 III If6,Ii H JI • • TIW VALVE 1b' id ^ Hydril lii ' I \ CHOKE CIRCULATING HOUSE MANIFOLD Variables 3''A-7 —111li . Blind =�� di 16 3:- lam- JAI/LI �'�of �;"� �M I 4 r,..(..,( tt - . - tt 1,,,-)-- Valves closed& Valves closed& locked out locked out Vv A Riser,16%5M API hub X16 3/4 10M FE 19'98 1� 1 ) xa.os. Riser,16%SM FE X 16%5M API hub MIE-11N11 i PRODUCTION HEADER " WATERFLOOD Ii o�,>; — 8.17' `■F . 11 4 iiiIr wi 111; 1opai �F 1 • 11 R.1 • 0 n C D4i r _1 Z 0 vv4k 0 Z -n 2 Z K C O Z A A OwwooO > N Z2 -0 * 007700 * * C D D m � � { G� o O ] 0 z H D Z Z A C cn • _D Z 0 m m m cn Z DO ED aJ.I �_ ilD111 X to 7o (/n ■ 2_A 4) I v r OA O y= rO -0 mA mo z Dn .11111 D4 M 11 0 m -I ziZ =z- _ cpm O C -P 's W0 m A > m A A 1-1...-: Z D ■ Z Z m(7 •o •1 -QI - ui -o (0 N 4 14 O i v n H o 0 a 1° 3 r s n s n n s n n s n c'- ,T, ' .�c v v v % .. 00 . 0 0 0 0 0 0 . = - 3 3 3 3 3 mmmmmmmmmm m < 'g aaa P '-' 3333333333 - d ,�,, ,0., 33333 n v o, 01 LIJ GU 0 ' 0 0 0 0 0 0 0 0 0 0 ' n 0 0 0 0 0 n a n a N a n N a 0 U, w - l0 N V O1 A W m A N O n n n n n n n n n - v v 3 3 3 x 3 3 3 3 3 3 3 U, 3 lD p0 V A W N In A W NJ O o n n O n n O n O n o n o 0 n 0 0 00000 g � • • 0 C I— r. > vk o W 2J J z 71 m0xics. j0CO m0 �fN rn n O O D * CU) G) DD --I DziG) M z C Z °o — G) -0 o ❑ —I H C co z II G) m D z V m H m m cn co Z DO m „ Am 111111 r eg dam= • _] t a — — ''' m y 0 v T 73 m m0 D C O 01 II m .I z H -_p, - LA ov m7m7 m I--.--: :■-...-1z z m n cn - Ui . co - V (0 N M 04 O d n . a . o MI a o a L A 3 r n n s n n n n n s n n x 1' v c F, 3 ,_= � o 0 0 0 0 0 0 0 � 7 3 3 3 3 3 to N N to o N to to N ro ro ,, g r V U 0 'O 0 o• f° m o 0 " 0 0 0 0 0 0 0 0 0 0 N s O O O D O a a a a Q a a a a a O a a a a n F_ lO co V O1 N A W NJ F+ U A W N - EI � 33N3N3333 io 3333U lO Oo J Ol A W NJ 11r A W NJ ~O o n n o n n o n o n o n o o n o o n o n o o _.-8:1 • • Moncla Rig 404 BOP Test Procedure Hilcorp Alaska,LLC Attachment#1 Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Moncla Rig 404, WO Program — Oil Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with FIW to kill well. • Note: Fluid level will fall to a depth that balances with reservoir pressure. 3) Shoot fluid level at least 24 hours before moving on well. 4) Shoot fluid level again, right before ND/NU. 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) ND tree with no BPV b) Inspect and prepare BPV profile to accept a 2-way valve,or prepare lift-threads to accept landing joint to hold pressure. If well is a producer and the culprit is scale, attempt to clean profile with Muriatic acid and a wire brush or wheel. c) Set 2-way check valve by hand,or MU landing(test)joint to lift-threads d) 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.Guy Schwartz(AOGCC)and Mr.Jim Regg(AOGCC)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. 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.) S • Moncla Rig 404 BOP Test Procedure Hilcorp Alaska,LLC Attachment#1 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 1st valve on standpipe manifold,close valves 1, 2, 10 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 2,500 psi 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,open 15t valve of standpipe, close valves 3,4&9 on choke manifold,open valves 1&2 on choke manifold. Test to 250 psi for 5 minutes and 3,000 psi 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 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. d) Close inside valve/open outside valve on kill side of mud cross,close valves 5&6/open valves 3&4 on choke manifold. Test to 250 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. e) Close manual and super choke/open valves 5&6 on choke manifold. Pressure up to—1200 psi and bleed off 200—300#s recording change and stabilization. If passes after 5 minutes, bleed of pressure back to tank. f) Close HCR(outside valve on choke side of mud cross),open manual&super choke. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. �► ! Moncla Rig 404 BOP Test Procedure Hileorp Alaska,LLC Attachment#1 g) Close inside valve/open outside valve(HCR)on choke side of mud cross. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. h) 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 10 on choke manifold, close valve 7&8/open valve 10 on choke manifold. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. i) 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 2nd set of pipe rams if installed (e.g. dual pipe rams). Open the lower pipe rams to simulate the closing volume on the blinds. 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (i.e. Report might read "10 bottles at 2,150 psi"). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre- charge pressure of 1,000 psi). 7) Turn on the pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually+/-30 seconds. 8) Once 200 psi pressure build is reached,turn on the pneumatic pumps and record the time it takes for the pumps to automatically shut-off after the pressure to builds back to original pressure(+/-3,000 psi). Note: Make sure the electric pump is turned to "Auto", not"Manual"so the pumps will kick-off automatically. 9) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 10) Fill out AOGCC report. FINAL STEP, FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves,for correct operating position 3) Fill out the AOGCC BOPE Test Form (10-424)in Excel Format and e-mail to AOGCC and Juanita Lovett. Document both the rolling test and the follow up tests. Steel�ad Platform 2018 Rig 51 BOP Nikorp Alaoks,TIC: 04/11/2018 O O iii _i Ili-iii III 1 Shaffer 3.74' 13 5/8 5 if, iii iii iii r II 11.1 141 IL_1 f41 IMOSpacer spool installed for use of lift cradle on studded 2.00' Ill tit tit fit nil BOP Shaffer L ®® - 27/8-S.Svariables 4.-=----- i- —_ 2.83' Blinds Mud Cross iii 'of JH 1 135/85MFEXFE [1411P) �lc'©�r t - -) E- w/3 1/8 5M EFO t x'0 0 t t i. 111 1 i I . i j 1.83' Shaffer SL — 2 7/8-5.5 variables 144' Riser 13 5/8 5M#13 API hub X 21.75' 13 5/8 5M FE Riser 13 5/8 5M#13 API hub X 18.83' 13 5/8 5M FE II/ Ill • • ►A 0 u) m 0 0 0 v 0 0 m 0 00 0 C m r m m CD 0 CC) -I CO m U) ND ° m fNm , � ITI r_ � 0 0 Im- 0 13 rn m II J o ® i ' A A Era cTJ 0 � T > I -o -\'\° 0 T CD d 33 C 33 0 > = zG) TRIP TANK#1 m y ^n Cal m r 0 C., w TRIP TANK#2 ,2o1.1 1.-- 0 0 E.: N 0 ,v D m D4 D4 fl4 II -. Z73 G) Oo coil N H 5 O U n W ^ �\ I C D4 , o m no 0 m 7 --,Q z 1-----..„1Vi N D4 n _. I GAS BUSTER • Steelhead Rig#51 BOP Test Procedure Hileor1i Alaska,LIE Attachment#1 Attachment #1 Hilcorp Alaska LLC. BOP Test Procedure: Steelhead Rig # 51 WO Program — Oil Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Production Vessel that is vented thru flare to atmosphere 2) Load well with FIW to kill well. • Note: Fluid level will fall to a depth that balances with reservoir pressure. 3) Circulate down tubing taking returns to production off of the annulus and sweep gas and oil to production until returns are clean. 4) Confirm that well is static Monitoring for any pressure Build Up Or if Well Is Still On A Strong Vacuum ( I do not think that We Often Shoot Fluid Levels) Initial Test(i.e.Tubing Hanger is in the Wellhead) If BPV profile is good 1) Set BPV, ND Tree 2) Clean/Inspect/And Confirm By Screwing Into Lift Threads (Counting Turns) Remove Sub—Check all Lock Down Pins to Ensure they Will Back Out Far Enough To Clear Hanger—Plug Penetrations Through Hanger—Put a Sealing Cap On Penetrator—Leave BPV Installed & If Needed Install Adaptor to Test Joint, Might Be Using a Left Hand Blank Ported Sub or a Combo Tool Of Various Types NU BOP. 3) MU landing joint With On/Off Tool Adaptor. 4) Set slips, mark same. Test per standard Steelhead Rig#51 Test Procedure. If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on. Profile and/or landing threads must be prepped while tree is off. Worst Case: BPV profile and landing threads are bad. 1) Attempt to set BPV through tree. If unsuccessful, establish static fluid level. 2) Once the fluid level is established to be static, notify Hilcorp Anchorage Operations Engineer. 3) Proceed as follows: a) ND tree with no BPV b) Inspect and prepare BPV profile to accept a BPV, 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) MU Left Hand Blanking Plug d) Plug penetrations in hanger. For ESP wells- Ensure that cap is on cable penetrator e) NU BOP. Test BOPE per standard procedure. 4) If both set of threads appear to be bad and unable to hold a pressure test and/or a penetrator leaks, notify Operations Engineer(Hilcorp), Mr. Guy Schwartz (AOGCC-guy.schwartz@alaska.gov ) and Mr. • • Steelhead Rig#51 BOP Test Procedure Hilrorp Alaska,LLC Attachment#1 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. e) Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 5) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 6) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re-land hanger(or test plug) in tubing head. Test BOPE per standard procedure. Note: BOPE high test pressures will be determined upon Approved Sundry.Test joint sizes will be determined upon well work. Subsequent Tests (i.e.Test Plug can be set in the Tubing-head) 1) Pull Wear Bushing, Make up Test Plug and Test Joint—Land Same Measuring in the hole getting a Good Mark when Landed . a) Use inverted test plug to pull wear busing. MU to 1 jt. of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same, and RIH on 1 joint of tubing. Install a closed TIW or lower Kelly valve in top of test joint. 3) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE (after Isolation Plug is Set) 1) Make up Test Joint as per diagram. Insure all connections above test plug are torque. 2) Pull Wear Bushing and install Test Plug 3) Make up Side-Entry Sub, (2) TIW valves and IBOP to top of Test Jt. 4) Make up Test Hose#1 to Side-Entry Sub and Test Hose#2 to Top Drive Test Sub. 5) Verify Annulus valve is open and monitored. 6) Fill BOP and Choke Manifold with water. Purge air from system through Choke manifold top valve and IBOP. I • Steelhead Rig#51 BOP Test Procedure Hilcorp Alaska,LLC Attachment#1 7) Close Annular and set closing pressure to 800 psi. (pressure can be increased as necessary to seal element) Perform full body BOP test to check integrity of system. Note: When testing, pressure up with pump to desired pressure, close MP1 and/or MP2 to trap pressure and read same with chart recorder. 8) Referencing the attached schematics test BOP as per Permit and Regulations as follows. a) Close W1 (inside gate valve on choke side of mud cross) and close the annular preventer. Pressure test to 200 psi for 5 minutes and 1,500 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open annular. b) Close Pipe Rams. Test to 200 psi for 5 minutes and 3,000 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open pipe rams. c) Open W1. Flow through the choke manifold and purge air. Test the choke manifold starting with the outer most valves,to 250 psi low and 3,000 psi high, for 5 minutes each,as follows: (Valve numbers are in reference to Flow Diagram) d) Test#1-Annular, IBOP, Upper TD Valve, Kill Line Demco, Cl, C2,C3, C12, C13, C14. e) Test#2—Test VBRs,Top TIW, Lower TD valve, HCR2, C4, C5, C6. f) Test#3—Test VBRs, W2, C7, C8, C9 g) Test#4.—Test Lower Pipe Rams, Bottom TIW. h) STANDARD TEST PROCEDURE OF CLOSING UNIT(ACCUMULATOR) 1) This is a test of stored energy. Shut off all power to electric and pneumatic pumps. 2) Record "Accumulator Pressure". It should be+/-3,000 psi. 3) Close Annular Preventer,the Pipe Rams, and HCR. Close 2nd set of pipe rams if installed (e.g. dual pipe rams). 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (I.E. Report might read "10 bottles at 2,150 psi"). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre-charge pressure of 1,000 psi). 7) Turn on the pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually+/- 30 seconds. 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. j) Back out Test joint and pull to rig floor. Connect test hose to C13. Pressure up on Manual and Hydraulic Chokes to 1,000 psi. Function Chokes to bleed pressure and verify operation. k) Test#5. —Test Blinds and C10, C11. I) Make up 2nd Test Joint if running two string sizes m) RIH with 2nd Test Joint and test plug. Make up Side-Entry Sub, (1)TIW valve and IBOP to Test Joint. Connect#1 Test Hose to Side-Entry Sub and #2 Test Hose to suspended TIW w/test sub. . • Steelhead Rig#51 BOP Test Procedure Hilrorp Alaska,1,1,1Attachment#1 Purge air from system. (always verify lengths needed when compared to RKB and add pups if necessary) n) Test#6-Test Annular, IBOP, suspended TIW and HCR1. o) Test#7-Test VBRs, Upper TIW and Manual Choke. p) Rig down test equipment. Blow down lines. Close Annulus valve. Pull test plug. Install Wear Bushing. Rig down, or stand back Test Stand. q) Back out test joint & pull, close blinds, close valves C7, C8, C9, open HCR1, and W1 r) Open all rams and annular and close HCR2 to place BOPE back into operating position for well work. s) 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 and e-mail to AOGCC and Juanita Lovett. Document both the rolling test and the follow up tests. • • . . -Cl ƒ \ ƒ Cl) ƒ 0 _ n O® c cr. ? -. \ <G2 O 2 =ii ® § n CD i 2 7 \ \ m w ( © ® k 2 ° R q 2 U r ] » § ° f 2 t3 p o m g O \ / O ° \ \ F 73 0 0 CD m = / \ � � Cl) zi UM = fu cl) / \ -' 2 gf Q C m — - 0 =CC) ƒ k . e0 k R = (-1.), 7 ° q 0. » = f a O / // co \ =cu * �7_, -0° \\ C64 O < *, -0 k 0 < - k CD \ » _ a -o CD 7 / co ƒ z %3 O Q �2 $ / \ m m 2 7 m o £ « % S «. k / f § 2 = -s CD k § xi: co C � 0. 0 CD eL $ / K 11 ee E co J 7 7 rn ° � o 0. / ] ag§D C)2 > % a 0 < 0 / \ ■ — q E 0. co 7 Ok Cl) ■ Z « - 0. • • • Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Thursday, April 12, 2018 2:28 PM To: 'Dan Marlowe' Cc: Stan Golis;Juanita Lovett; Michael Quick; Bettis, Patricia K(DOA) Subject: RE: M-31B PTD 212-149 Sundry Submittal Dan, You have verbal approval to proceed with RWO utilizing Moncla 404 as proposed in your sundry application. The BOPE test pressure will be 3000 psi . (2500 for annular). Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: [his e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). From: Dan Marlowe<dmarlowe@hilcorp.com> Sent:Thursday,April 12, 2018 2:22 PM To:Schwartz, Guy L(DOA)<guy.schwartz@alaska.gov> Cc:Stan Golis<sgolis@hilcorp.com>;Juanita Lovett<jlovett@hilcorp.com>; Michael Quick<mquick@hilcorp.com> Subject: RE: M-31B PTD 212-149 Sundry Submittal Per our conversation Hilcorp requests verbal approval to proceed with this workover currently scheduled to begin April 14th Thanks Dan Marlowe Hilcorp Alaska, LLC Operations Engineer Office 907-283-1329 Cell 907-398-9904 Email DMarlowe unhilcorp.com Hilcorp A Company Built on Energy From: Dan Marlowe Sent:Wednesday,April 11,2018 12:45 PM To:Schwartz, Guy(guy.schwartz@alaska.gov)<guy.schwartz@alaska.gov> 1 . . Cc:Stan Golis<s olis hilcor .com> i <" • @ p ,Jin •to Lovett Ilovett@hilcorp.com> Subject: M-31B PTD 212-149 Sundry Submittal Guy Per our discussion this high value oil well went down this morning with a suspected hole in pump We would like to swap the pump prior to spudding the M-22 drill well, so could be on the well as early as Sunday with the Moncla 404. We are also weighing the option of utilizing rig 51 but it is on the opposite side of the platform so most likely not the most cost effective choice as it would take the rig crews focus off of prepping for the drill well. I did however include backup paperwork for both rigs. Thanks for your time this morning to discuss the project Let me know if you have any questions Dan Marlowe Hilcorp Alaska, LLC Operations Engineer Office 907-283-1329 Cell 907-398-9904 Email DMarlowe(a hilcorp.com Hilcorp A Company Built on Energy From:Juanita Lovett Sent:Wednesday,April 11, 2018 12:41 PM To: Dan Marlowe<dmarlowe@hilcorp.com> Subject: M-31B Sundry Submittal I'm on my way over to AOGCC now. Juanita L Lovett Sr.Operations/Regulatory Tech H Hilcorp Alaska, LLC 3800 Centerpoint Drive,Suite 1400 I Anchorage I AK 199503 (907)777-8332 I jlovett©hilcorp.com 2 STATE OF ALASKA AL&OIL AND GAS CONSERVATION COMMSON REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon ❑ Plug Perforations❑ Fracture Stimulate El Pull Tubing E Operations shutdown ❑ Performed: Suspend ❑ Perforate ❑ Other Stimulate LI Alter Casing❑ Change Approved Program ❑ Plug for Redtill ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well 0 Other:Replaced ESP 0 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory 0 212-149 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service 0 6.API Number: Anchorage,AK 99503 50-733-20457-02-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0018730 Trading Bay Unit/M-31B 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A McArthur River Field/Middle Kenai G and Hemlock Oil Pools 11.Present Well Condition Summary: F �F Total Depth measured 11,550 feet Plugs measured N/A fee,1 f,y 1 8 2016 true vertical 9,854 feet Junk measured N/A feet CCEffective Depth measured 11,450 feet Packer measured 1,316&8,925 fe�t "�""G true vertical 9,818 feet true vertical 1,315&8,318 feet Casing Length Size MD ND Burst Collapse Structural 480' 34" 480' 480' Conductor 979' 26" 979' 979' Surface 1,345' 16" 1,345' 1,344' 2,630 psi 1,020 psi Intermediate 3,722' 13-3/8" 3,722' 3,524' 3,090 psi 1,540 psi Production 1,316' 9-5/8" 1,316' 1,315' 6,870 psi 4,760 psi Liner Hanger 32' 10-3/4" 1,348' 1,347' 7,750 psi 6,300 psi Liner 7,759' 9-5/8" 9,107' 8,488' 6,870 psi 4,760 psi Liner 2,629' 7" 11,548' 9,853' 7,240 psi 5,410 psi Perforation depth Measured depth 9,361-11,396 feetp r> y13 SC True Vertical depth 8,725-9,798 feet °Yy� �Il9 Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80 8,644(MD) 8,055(ND) Baker HRD-E ZXP Pkr 1,316'(MD)1,315'(ND) Packers and SSSV(type,measured and true vertical depth) Baker JM-ZXP Pkr 8,925'(MD)8,318'(ND) SSSV:N/A 12.Stimulation or cement squeeze summary: Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 485 340 13874 62 106 Subsequent to operation: 429 260 13360 90 100 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory❑ Development Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil 0 Gas 0 WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR 0 WINJ 0 WAG El GINJ 0 SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 316-222 Contact Trudi Hallett(907)777-8232 Email thallett( hilcorp.com Printed Name Stan W.Golis Title Operations Manager Signature (r ) Phone (907)777-8356 Date S I I fd / 6 Form 10-404 Revised 5/2015 ,,/,�,. I 1 l(v" Submit Original Only RBDMS 1,k, MAY 1 9 2016 • • 14Steelhead Platform Well#: M-31B Hileorp Alaska,LLC SCHEMATIC Completed: 05/01/16 PTD#: 212-149 API#: 50-733-20457-02-00 TBG Hanger 74.5'below RKB CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. it! +, ' ' �� 26„ 34" Surf 480' 26 267 3977#ru Drill Quip Surf 979' ' A 16 16" 75 K-55 BTC 15.12 Surf 1,345' 13-3/8" 61&68 K-55 BTC 12.42 Surf 3,722' 9 5/8"Tieback 47# L-80 DWC/C 8.681 Surf 1,316' 13-3/8' 10 3/4"Liner hgr 65.7# L-80 BTC 9.5 1,316' 1,348' 9-5/8"Liner 47# L-80 DWC/C 8.681 1,348' 9,107' 7"liner 26# L-80 VA HC OP 6.276 8,919' 11,548' TUBING DETAIL 4-1/2" 12.6# L-80 IBT-M Surf 8,644' Jewelry Detail NO Depth ID OD Item 1 8,644' - 6.750 Discharge 2 8,645' - 6.750 Pump(x2)45 Stg SH16000 3 8,684' - 6.750 Intake 4 8,703' - 5.620 Motor(x2)562 Motor,KMSUT 500HP 1 "' 5 8,768' - 5.620 Anode 2 3 4 ;. 5 ,, CASING JEWELRY 1NO Depth Length ID OD Item '' B A 1,316' Baker Flex-Lock Liner hanger&Baker HRD-E ZXP liner top packer(PKR `»4 ' t C INTENTIONALLY NOT SET!!!) B 8,919' 7"Liner top C 8,925' Baker JM-ZXP Liner Top Packer ; ,' D D 9,107' 9-5/8"Casing Shoe AI ,...,' PERFORATION DETAIL 1w. _'` Top 4; Zone (MD) Btm(MD) Top(TVD) Btm(TVD) Length(MD) SPF Date V,4 r . G1 9,361' 9,390' 8,725' 8,754' 29' 5 2-20-2013 G2 9,425' 9,440' 8,786' 8,801' 15' 5 2-20-2013 '. G3 9,490' 9,526' 8,843' 8,879' 36' 5 2-23-2013 tirl 9,535' 9,600' 8,885' 8,950' 65' 5 2-23-2013 _ G5 9,674' 9,710' 9,003' 9,036' 36' 5 2-23-2013 r" 'f G5 9,720' 9,739' 9,030' 9,049' 19' 5 2-23-2013 Iv A HK1 9,950' 9,985' 9,208' 9,243' 35' 5 2-23-2013 v HK2 10,003' 10,130' 9,251' 9,329' 127' 5 2-23-2013 k-,. HK3-4 10,192' 10,600' 9,362' 9,542' 408' 5 2-23-2013 V } 7 HK5 10,642' 10,834' 9,556' 9,617' 192' 5 2-23-2013 HK5 10,866' 11,030' 9,628' 9,680' 164' 5 2-23-2013 HK6 11,083' 11,165' 9,697' 9,722' 82' 5 2-23-2013 ; • • IIHilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date M-31B Moncla 404 50-733-20457-02 212-149 4/22/16 5/2/16 Daily Operations: 04/22/2016-Friday Check well,static.Set BPV, n/d tree, prepped hanger, inspected lift threads-good. Installed blanking test sub. N/U 16 3/4" riser, mudcross w/valves,dual ram body w/blinds&4 1/2 annular.Torqued bolts to specs. Laid out lines and raised derrick.Secured 2 forward and 2-side guy lines. Mounted drawworks console and drillers shack, positioned accumulator unit and ran hyd lines to BOPs.Spooled on drill line and scoped out derrick.Secured remaining guy lines. 04/23/2016-Saturday Finished running accumulator lines. Rigged up landing and dog house stairs. Rigged up floor w/wind walls.Welder began installing floor support system. Quadco and Total Safety set up their systems.Welder continued building modified floor support. Raised driller's shack and repositioned console, brake assembly and Quadco monitor. Mounted extended steps to driller's shack and rig floor. Ran circulating lines from water flood to stand pipe manifold w/choke and flow meter. Positioned choke house and tied in same. Checked pre-charge on accum bottles and functioned tested BOPs. 04/24/2016-Sunday Continued with electrical and welding work.Set up rig floor with handling equipment and McCoy power tongs. Finished routing circulation system thru production. M/U 4 1/2"test jt w/pumpin,SV& IBOP. Landed same and filled stack from waterflood. Began pretesting BOPs and choke manifold 250 low/3000 high.Worked thru electrical issues and leaks. At report time we are still chasing down a 5 min/50# leak-one HCR valve failure(to be replaced). 04/25/2016-Monday Continued with BOP pretest-chasing minor leakage.Changed out failed HCR, changed sub on bottom of test jt and valve in top of hanger. Moncla mechanic came out to repair air pump on koomey unit-unit still would not pass AOGCC time frames on accum system drawdown test. Decision was made to swap out,Moncla unit for Hilcorp unit(HAK 11.,Changed out accumulator units and performed passing draw down test and 250&3000#shell test. Cleaned and organized around rig and accessory equipment while continuing to work thru BOPE test in prep for AOGCC witness arrival. de 04/26/2016-Tuesday Continued chasing minor leaks.Changed out two choke manifold valves and serviced K-3 on standpipe manifold. Continued with pretest. Called for AOGCC rep.Tested BOPE as per Sundry(250#s low/3000#s high+super choke and accum draw down tests) in accordance to Hilcorp and AOGCC requirements.Test witnessed by Mr. Brian Bixby/AOGCC. Removed 2-way check and screwed into hanger with landing jt. Backed out hold down pins and P/U on tbg. Hanger moved off seat at 115k. Picked up 3'and closed pipe rams. Lined up to pump L/W with water flood sending returns to TBPF. Pumped (from water flood) L/W at 4 BPM-getting"'1/2 to 1 BPM returns going to TBPF(@ 55#s casing pressure). Increased flush rate to 6 BPM with 1.6 BPM returns.Shut down flush to bleed gas. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date M-31B Moncla 404 50-733-20457-02 212-149 4/22/16 5/2/16 Daily Operations: 04/27/2016-Wednesday Stopped water flood and bled down 100#s gas pressure.Checked well for static condition. B/O safety valve and pulled hanger to surface up wt 137k,do 97k. Cut all cables and B/O hanger. Laid down 3 singles and racked back 4 stands. Cut and banded all cables to tubing with two clamps. M/U Halb storm pkr and TIH to 240'.Set pkr placing EOP @ 8,544'. Filled hole-tested casing to 1500#s for 30 mins on chart-good test. Released from pkr and POOH laying down tubing and Halb releasing sub (2 orings missing off sub). Cleared rig floor of all tongs,tools and handling equip. R/D wind walls and folded floor back(raising it 2'). Removed floor support legs. N/D bop stack. N/U adapter and 11"tbg head on btm on 16 3/4" riser and lowered into well bay. Discovered that flow line will have to be moved. Removed riser and tbg head from well bay area. Production isolated flow line and removed flow line riser enabling correct placement of 11"tbg head. Lower 16 3/4" riser down into well bay and land 11"tbg_head,adapter onto old 16 3/4"tbg head. N/U complete BOP stack. t 04/28/2016-Thursday Torqued all flange bolts.Changed out HCR valve on wing.Started R/U floor.Slipped and cut 120' of drill line. Installed legs under rig floor, installed stairs, hand rails and wind walls. Prepped floor with tongs,tools and handling equip. M/U test plug on 4 1/2"tbg. Landed in tbg head and filled stack. Function tested eq.from remote,shell tested 250#s low 3000#s high on chart(worked out leaks). B/D L/O test plug and single. Cleared floor of all unnecessary items and setup to control fluids pulled from well. M/U Halb stinger&TIH to storm pkr at 240'-engaged same.Tested btm tbg head break to 1500#s-good test. Released pkr and checked for flow- POOH. B/D L/0 tools. Picked up and cut metal straps to free ESP cables. R/U Summit's sheaves in derrick. POOH t/6,681',w/4 1/2" IBT-M production string w/ESP assembly pumping 6 bbls FIW every ten stands. 04/29/2016-Friday Cont. POOH f/6,681', w/4 1/2" IBT-M production string w/ESP assembly pumping 6 bbls FIW every ten stands. C/O power pack f/tongs.Cont. POOH t/2,829', racking back till derrick full. R/u slide cont L/d singles to ESP assy. Moved handling tools to floor and B/D ESP assy. ESP failure due to motor issues.Top motor checked bad and was seized plus there was a hole blown in the lower body. Btm motor checked bad.Cleared and cleaned rig floor. Removed reels of recovered ESP cable and installed new cables on spooler.Staged all needed equip to rig floor. M/U new Summit ESP assy. P/u&serviced tandem 500hp mtr assy. M/u cap lines&mtr lead. 04/30/2016-Saturday Finished M/U Summit ESP assy. BHA total = 127.69'.TIH w/ESP assy on 4 1/2" 12.60#L-80 IBTM tbg(from previous completion) @ 3 MPS-checking power cable every 1,000'to 76 stands in hole=4,989' (end of 1st power cable reel). Changed out reels and made splice in power cable-electrically checked same.Continued running in hole with Summit ESP assy.Splice went thru floor at 5,106' (10'from top of stand#78). Ran in total of 95 stands out of derrick=6,157'. Started picking up singles off deck running ESP in hole. @ 6,635'. • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date M-31B Moncla 404 50-733-20457-02 212-149 4/22/16 5/2/16 Daily Operations: 05/01/2016-Sunday Cont.TIH w/ESP assy on 4 1/2"tubing t/8,708'. Backload boat. P/U hanger&landing jt, make penetrator splice&control line terminations to hanger. Landed hanger with assistance from NOS rep. Power cable tested good. B/O L/D landing jt. Set BPV. Cleared rig floor of all tools, handling equip and tongs. Removed wind walls and R/D floor and jack stands. NOS rep prepped tree to accept adapter. Released guy lines and scoped down derrick while loosening bolts on BOP components. Laid derrick in cradle. N/D BOP stack. Disconnect lines from accum unit and stow.Continue with R/D of 404 pending ESP startup. NOS prepped tbg head to receive new 11" 5M x 4 1/16"5M adapter. Lowered adapter and plumbed penetrator and control lines thru same. N/U adapter-terminated control lines. N/U tree and flow line riser. Void tested hanger to 250 low/5000 high. 05/02/2016-Monday NOS rep shell tested tree to 250 low/5000 high for 5 mins-good test. 9 VOF ro , 0•,l''��yy,4. THE STATE Alaska Oil and Gas -t �t o T c T Conservation Commission ,, f�L��J��I-1 t }>Ei i� 333 West Seventh Avenue GOVERNOR BILL WALKERiii • Anchorage, Alaska 99501-3572 0'�" T ' Main: 907.279.1433 F ALA91& Fax: 907.276.7542 www.aogcc.alaska.gov Stan Golis Operations Manager 1 Hilcorp Alaska, LLC -1 1 5 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: McArthur River Field, Middle Kenai G and Hemlock Oil Pools, TBU M-31 B Permit to Drill Number: 212-149 Sundry Number: 316-222 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, aV--ety P9p.€4.44,--- Cathy P. Foerster Chair DATED this I. day of April, 2016. RBDMS t,i- APR 1 8 2016 • • illECEIVED STATE OF ALASKA APR A 5 ZO1& • ALASKA OIL AND GAS CONSERVATION COMMISSION _S 4 /� 16 APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing 0„ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool Cl Re-enter Susp Well ❑ Alter Casing ❑ Other: Replace ESP I] 2.Operator Name: 4.Current Well Class: 5. Permit to Drill Number. Hilcorp Alaska,LLC Exploratory ❑ Development III. 212-149 ' 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number. Anchorage,AK 99503 50-733-20457-02-00 , 7.If perforating: 8.Well Name and Number What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes ❑ No 0 ` Trading Bay Unit/M-31 B 9. Property Designation(Lease Number): 10. Field/Pool(s): ADL0018730 . McArthur River Field/Middle Kenai G and Hemlock Oil Pools i 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 11,550 . 9,854 . 11,450 9,818 . 2,874 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural 480' 34" 480' 480' Conductor 979' 26" 979' 979' Surface 1,345' 16" 1,345' 1,344' 2,630 psi 1,020 psi Intermediate 3,722' 13-3/8" 3,722' 3,524' 3,090 psi 1,540 psi Production 1,316' 9-5/8" 1,316' 1,315' 6,870 psi 4,760 psi Liner Hanger 32' 10-3/4" 1,348' 1,347' 7.750 psi 6,300 psi Liner 7,759' 9-5/8" 9,107' 8,488' 6,870 psi 4,760 psi Liner 2,629' 7" 11,548' 9,853' 7,240 psi 5,410 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 9,361 -11,396 • 8,725-9,798 4-1/2" 12.6#/L-80 8,737 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A&N/A N/A&N/A 12.Attachments: Proposal Summary El Wellbore schematic LI 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ Stratigraphic El Development I] . Service ❑ 14. Estimated Date for 15.Well Status after proposed work: 4/21/2016 Commencing Operations: OIL U 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 Li herein will not be deviated from without prior written approval. Contact Trudi Hallett(907)777-8232 ' ` Email thallett@hilcorp.com Printed Name Stan W.Golis Title Operations Manager ii / Signature ✓ L. Cr1Phone (907)777-8356 Date / ( c ( it. COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: `�^ �� Plug Integrity 0 BOP Test LI�(q Mechanical Integrity Test ❑ Location Clearance ❑ Other: .: -30e(X) p 5:, 6 f t A1f..er,.4 _ c",-`""4- —> s - 1 c, ' � 7,6 ,44 iS.. Z-75—C ) Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No ' Subsequent Form Required: AI_L f 0L/' 1 RBDMS t-- APR 1 8 2016 APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date:4-•—/S---r6 uRriv& �'(L,/) Submitorm and • " Form 10-403 vised 11/2015 jpf4is'valid for 12 months from the date of approval. �� Attachments in Duplicate Yrs l� �.. GSL • • Well Work Prognosis Well: M-31B Hilcorp Alaska.LLC Date: 4/05/16 Well Name: M-31B API Number: 50-733-20457-02 Current Status: ESP Producer Leg: B-1 Estimated Start Date: 04/21/16 Rig: Moncla Rig#404 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett(8332) Permit to Drill Number: 212-149 First Call Engineer: Trudi Hallett (907)777-8232 (0) (907)301-6657(M) Second Call Engineer: Dan Marlowe (907)-777-1329(0) (907)398-9904(M) Current Bottom Hole Pressure: 3,747 psi @ 9,262'TVD Mid Perf (10,021 MD)calculated from static fluid level on 4/5/2016 Maximum Expected BHP: 3,747 psi @ 9,262'TVD (No new perfs being added) Max. Potential Surface Pressure: 2,874 psi (Using 0.1 psi/ft. per 20 aac 25.280(b)(4) Brief Well Summary M-31B is a G / Hemlock Producer completed with an ESP. The ESP experienced a down-hole failure April 3`d, 2016.We plan to pull and replace the ESP. No perforations will be added. / Procedure: 1. MIRU Rig. 2. Attempt to pump through ESP to circulate hydrocarbon off the well to production. If necessary, RU e-line and RIH to+/-8,700' and punch tubing. 3. ND Wellhead, NU BOP and test to 250psi low/3,000psi high. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 4. POOH with tubing string and ESP pump laying down the same. 5. PU 9-5/8" RTTS packer, RIH set same at±200' and hang off string. Pressure test to 1,500 psi and chart. 6. Release from packer, POOH. 7. ND stack and add attachment completion spool onto wellhead. NU stack.Shell test BOPE, test all flange breaks to 1500 psi and chart. ✓r 8. RIH engage RTTS packer, release same, POOH, LD RTTS. 9. PU, RIH with ESP completion. 10. Land ESP with the bottom of the assembly at+/-8,900'. 11. ND BOP, NU wellhead and test. 12. Turn well over to production. 13. RDMO Rig. Hilcorp requests a variance from 20 AAC 25.285 (h). The request is to supply kill fluid from and take returns to the production facility instead of the rig circulating system. The Steelhead production facility can supply and receive more fluid than the rig circulating system. (Injection Pressure= 2,900psi.) Hilcorp also offers the following in support of this variance: The nature of the M-31b work is to pull a failed ESP and run a like in kind unit. 'The M-31b is a no flow well. ...No other well work is planned. There will be no planned cleanout run, and no addition of perforations that could cause exposure to additional reservoir pressure. • • II Well Work Prognosis Well: M-31B Hilcorp Alaska, u: Date: 4/05/16 HA. Hilcorp plans to circulate any hydrocarbon off the well and control any potential kick from the well by implementing the attached "Well Kick Procedure". A drawing of the circulating system is also attached. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Wellhead Diagram (Current and Proposed) 4. BOP Drawing 5. BOP Drawing showing circulation system 6. Rolling BOP Test Procedure 7. Well Kick Procedure 8. RWO Sundry Revision Change Form Steelhead Platform , HWell #: M-31B Hilcorp Alaska,LLC SCHEMATIC Completed: 08/26/2015 PTD#: 212-149 API#: 50-733-20457-02-00 TBG Hanger 74.5'below RKB CASING DETAIL Al l SIZE WT GRADE CONN ID TOP BTM. \i j -1? ` 26" 34" Surf 480' 26" 267 thru Drill Quip Surf 979' 397# A �e., 16" 75 K-55 BTC 15.12 Surf 1,345' 13-3/8" 61&68 K-55 BTC 12.42 Surf 3,722' 9-5/8"Tieback 47# L-80 DWC/C 8.681 Surf 1,316' 13-3/8" 10-3/4"Liner hgr 65.7# L-80 BTC 9.5 1,316' 1,348' 9-5/8"Liner 47# L-80 DWC/C 8.681 1,348' 9,107' 7"liner 26# L-80 VA MT OP 6.276 8,919' 11,548' TUBING DETAIL 4-1/2" 12.6# L-80 IBT-M Surf 8,737' Jewelry Detail NO Depth ID OD Item 1 8,737' 6.750 Bolt On Head 2 8,737' _ _ 6.750 Summit Pump(x2)45 stg SH16000 3 8,777' 6.750 Seals(x2) 4 8,792' _ 7.250 Baker Motor(x2) t ff 2 5 8,846' 5.620 GLM Anode 3 4 5 IMI CASING JEWELRY NO Depth _ Length ID OD Item I BBaker Flex-Lock Liner hanger&Baker HRD-E ZXP liner top p packer(PKR A 1,316' INTENTIONALLY NOT SETH!) �f,4� C B 8,919' 7"Liner top 1 ,‘''' D C 8,925' Baker JM-ZXP Liner Top Packer D 9,107' 9-5/8"Casing Shoe PERFORATION DETAIL Top Zone (MD) Btm(MD) Top(TVD) Btm(TVD) Length(MD) SPF Date ,* G1 9,361' 9,390' 8,725' 8,754' 29' 5 2-20-2013 ^/- G2 9,425' 9,440' 8,786' 8,801' 15' 5 2-20-2013 4 G3 9,490' 9,526' 8,843' 8,879' 36' 5 2-23-2013 G4 9,535' 9,600' 8,885' 8,950' 65' 5 2-23-2013 T G5 9,674' 9,710' 9,003' 9,036' 36' 5 2-23-2013 G5 9,720' 9,739' 9,030' 9,049' 19' 5 2-23-2013 ftt- HK1 9,950' 9,985' 9,208' 9,243' 35' 5 2-23-2013 HK2 10,003' 10,130' 9,251' 9,329' 127' 5 2-23-2013 HK3-4 10,192' 10,600' 9,362' 9,542' 408' 5 2-23-2013 HK5 10,642' 10,834' 9,556' 9,617' 192' 5 2-23-2013 HK5 10,866' 11,030' 9,628' 9,680' 164' 5 2-23-2013 HK6 11,083' 11,165' 9,697' 9,722' 82' 5 2-23-2013 HK6 11,195' 11,270' 9,731' 9,755' 75' 5 2-23-2013 HK7 11,360' 11,396' 9,785' 9,798' 36' 5 2-23-2013 PBTD:11,450 MD/9,818'ND TD:11,550'MD/9,854'ND REVISED:09/23/15 REVISED BY:JLL • • Steelhead Platform Well #: M-31B Hhleorp Alaska,LLC PROPOSED Completed: Future PTD#: 212-149 API#: 50-733-20457-02-00 TBG Hanger 74.5'below RKB CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. d j ] 126„ 34" Surf 480' 26" 267 thru Drill Quip Surf 979' 397# A 16 16" 75 K-55 BTC 15.12 Surf 1,345' 13-3/8" 61&68 K-55 BTC 12.42 Surf 3,722' 9-5/8"Tieback 47# L-80 DWC/C 8.681 Surf 1,316' 13-318 10-3/4"Liner hgr 65.7# L-80 BTC 9.5 1,316' 1,348' 9-5/8"Liner 47# L-80 DWC/C 8.681 1,348' 9,107' 7"liner 26# L-80 VA HTOP 6.276 8,919' 11,548' TUBING DETAIL { . 4-1/2" 12.6# ._60 IBT-M Surf ±8,775' Jewelry Detail NO Depth ID OD Item ri 1 ±8,900' Bottom of ESP 01 CASING JEWELRY NO Depth Length ID OD Item c r B A 1,316' Baker Flex-Lock Liner hanger&Baker HRD-E ZXP liner top packer(PKR INTENTIONALLY NOT SET!!!) I. C B 8,919' 7"Liner top 41 I:" 'D C 8,925' Baker JM-ZXP Liner Top Packer D 9,107' 9-5/8"Casing Shoe v4, PERFORATION DETAIL 7 Top it Zone (MD) Btm(MD) Top(TVD) Btm(TVD) Length(MD) SPF Date A,, G1 9,361' 9,390' 8,725' 8,754' 29' 5 2-20-2013 G2 9,425' 9,440' 8,786' 8,801' 15' 5 2-20-2013 G3 9,490' 9,526' 8,843' 8,879' 36' 5 2-23-2013 G4 9,535' 9,600' 8,885' 8,950' 65' 5 2-23-2013 t", G5 9,674' 9,710' 9,003' 9,036' 36' 5 2-23-2013 G5 9,720' 9,739' 9,030' 9,049' 19' 5 2-23-2013 " HK1 9,950' 9,985' 9,208' 9,243' 35' 5 2-23-2013 HK2 10,003' 10,130' 9,251' 9,329' 127' 5 2-23-2013 HK3-4 10,192' 10,600' 9,362' 9,542' 408' 5 2-23-2013 HK5 10,642' 10,834' 9,556' 9,617' 192' 5 2-23-2013 HK5 10,866' 11,030' 9,628' 9,680' 164' 5 2-23-2013 HK6 11,083' 11,165' 9,697' 9,722' 82' 5 2-23-2013 HK6 11,195' 11,270' 9,731' 9,755' 75' 5 2-23-2013 a HK7 11,360' 11,396' 9,785' 9,798' 36' 5 2-23-2013 PBTD:11,450 MD/9,818'ND TD:11,550'MD/9,854'ND REVISED BY:JLL 04/04/16 • •• Steelhead Platform ,llM-31B Current 07/07/2014 Hilrnrp Alankn,ILIA. Steelhead Platform Tbg hanger,FMC-TC-1A-EN- M-31B EC-CCL,16%5M X 4%IBT 26 X 16 X 133/8 X 95/8 X lift and susp,w/4"Type Fl 4 1/2 BPV profile,2-3/8 continuous control line BHTA,Bowen, 41/165M FE X 7-5SA Bowen top ter NM 'A Valve,Swab,WKM-M, � ,. ,., r 41/165M FE,HWO,DD Iil- I 111 •in -.r'ir ..' a rar Valve,upper master,SSV, .i•_!�.'" 41/165M FE,w/15'Safeco Q r��,r. operator,EE Valve,wing,WKM-M, 41/165M FE,HWO,DD allEM Valve,Master,WKM-M, 41/165M FE,HWO,DD 1 :1, • WA Adapter,FMC A-3-EC, 16%5M X 41/165M, prepped for BIW electro sub, X2 control lineI 2-%npt continuous control line exits 10)1_ — 'I nihTubeadng 16%ead,F5M FEto 0,spec for . � � ;�- unihead,l6%SM FE top X16%SM 1 .71.1 mmm stdd bottom,w/2-2 1/16 5M SSO 1♦ 11'.x', te.I. �' k 1 'E ��- - Unihead,FMC Type 2,16%5M Valve,FMC-120, FE top X 21'/.2M FMC speedlock 21/16 SM FE,HWO,AA bottom,w/4-2 1/16 5M ISO I III rill il la - sp (...0 •a• i ,=. a 11Adapter spool,FMC-A-S-S 30"MSS ' •. 7 stdd bottom X 21%2M FMC � r 1 _ li IA, speedlock top,w/2-2"LPO EIJI -� ��.1. Starting head,FMC,30"MSS41111 -�pi FEX26"butt weld I■ ■1 26" 3/13 3/8" 9 5/8" 41/2 410 410 Steelhead Platform M-31B Proposed Hihtu�+:tlsgrka,las. 04/05/2016 Steelhead Platform Tbg hanger,FMC-TC-1A-EN- M-31B EC-CCL,11 5M X 434 IBT lift 26116/13 3/B195/8X and cusp,w/4"Type H BPV 41/2 profile,2-1/4 continuous control line ports BHTA,Bowen, 41/16 5M FE X 7-SSA Bowen top 11111 11 1/ 111. I. Valve,Swab,WKM-M, _ •r 41/165M FE,HWO,DD 0 ®'' rlaaaaaa�r atop Valve,upper master,SSV, ser 41/16 5M FE,w/15"Safeco operator,EE Valve,wing,WKM-M, - t 0 41/165M FE,HWO,DD 411000 ,.i i.r •,fir., Valve,Master,WKM-M, 41/165M FE,HWO,DD O 'I elLTrial Adapter,FMC 115M X 41/16 5M,prepped for BIW electro sub,2-X npt �� E■ � continuous control line exits --e:_:�"I 14 .a Attachment spool,FMC-TC, 16%SM stdd btmx 115M FE[op,12"In length,10.00" min bore Mr WO it Tubing head,FMC-TC-60,spec for a�. , uniheed,16%5M FE top X 16%5M stdd bottom,w/2-21/16 SM SSOLi" 0' r moi Unihead,FMC Type 2,16%5M Valve,FMC-120, FE top X 21%2M FMC speediock 21/16 SM FE,HWO,AA bottom,w/4-21/16 5M SSO 301 a Adapter spool,FMC-A-5-S 30"MSS stdd bottom X 21%2M FMC I14 1 1 speedlock top,w/2-2"LPO Starting head,FMC,30"MSS FE X 26"butt weld I■ IN 26,, 16" 13 3/6" 95/6" 4 1/2 Steelhead Platform ,11 16%5M BOP (Oil Leg) M-31B HO..,rir ki.4..r 11l 08/03/2015 Irl in III Ill lil \ 7 5.10' L° i_1 III III Irl ISO Variables3A-7 --�[�i� CC Rojo_ (:�•�� 5.46' Blind . 4 "x,...,16 X-5000 -�'�- I0IIi Irl Ifl ill lir— U 21/165M Choke and Kill j llil ill lil_ r valves w/HCR on both sides '. I I•'>, >. I1 la� 114'"�i�}I I. I 3.00' OI in lit Irl lil IiibilliP I Mir DSA16%10M X16 X5 .66' 151 1!1 1!1 I!I Ill = 1.85' • 0.ig sub grating Riser,16 a%<5M API hub X 16 3/4 10M FE n=rewem,ean uea�mx�g spm c,,n g 2301 O et 5.34' Clamp above floor V Upper wellhead room fbor Riser,16%SM FE X16 3/45M API hub Wellhead floor to Upper Wellhead Room 22.00' 0 ei — 1 e_• .:It.,L£!-..f ii 8.17' 'I■ e:�sv1l fffff�J-� i N 1k ta �� i '�"' . . 0 • 2"LOW TORQUE VALVE CONNECTED TO WATERFLOOD • TIW VALVE - - it 5.10' 0 Flydril • 1-1 1-1 CHOKE CIRCULATING HOUSE - �� - MANIFOLD Variables 314-7 =-41 _ `iJ'--_ _ ... 5.46' �� Blind —is -II— C .11.1 4 Valve closed&choke ,,,. 0 .;PRI 1. Valve closed& house locked out ( rI. MI10:4 } 3.00' locked out $ 4 _ -4, , _ T T 66' Valves closed& Valves closed& locked out locked out Riser,16 a/a 5M API hub X 15.91' 16 3/4 10M FE Upper Wellhead Room to Rig Sub Grat, 33.47' ( ' ) 5.34' Clamp above floor IUpper wellheadraom11par 211.05' Riser,16%<5M FE X 16%5M API hub Wellhead floor to Upper Wellhead Room 33.88' ,Illi vel e PRODUCTION a-1 -a`i►.n HEADER ill ii 8.17' •;I■Ili II■'J-4.0. 'hi ill ir,r —crl �, i a • Riq 404 BOP TEST Test w/xxx Ti Test 250 psi low xxxx high on all rams, 2500psi on annular 1) Close upper pipe rams, Open Annular, test CMV 1, 2, 10, dart valve, pipe rams, standpipe manifold valve#1 Test t/250/xxxx f/5 min (straight line time each and remaining tests) 2) Close TIW, open dart valve, Close CMV's 3,4, 9, kill line HCR, open CMV 1, 2,standpipe manifold#1 valve 3) Close CMV's, 5, 6, manual kill line valve, open CMV's 3, 4& kill HCR 4) Close manual&super choke, open CMV's 5, 6, pressure up t/1200 psi, bleed 200-500 psi w/super choke, and remainder w/manual choke 5) Close HCR choke line, open super choke 6) Close manual choke line valve, open HCR choke line valve 7) Close Annular, open lower pipe rams t/250 low, 2500 high Preform Accumulator test....then pull Ti With test jt in hole&system up to pressure: Turn off electric&air pumps 1) Record accumulator pressure(+-3000psi) 2) Close Annular, pipe ram's, & her valves, open pipe rams to simulate blinds 3) While pressure is stabilizing check pressure in nitrogen bottles& record. 4) Record accumulator pressure 5) Turn on electric pump& time seconds to pressure up 200 psi, turn on air pumps& time till unit pressures up to 3000 psi&shuts off. (time will start from time electric pump starts till all pumps shut off) 8) Back out test jt&pull, close blinds, install test hose to choke manifold outside valve 10, close valves 7, 8, open valve 10, choke HCR& inside choke line valve FD 00000 0000 0 O U O D U O D U 0 . _ o cv m a �n e....., a w r co m i' a i a d i Z O V V V V V V V V .r rJ m a 4 Y .-i r`+ ma 40 I, m 014 v a -o -o g O g v v v -o v -o a -o -o 0 0 0 0 2 u N o 0 0 0 0 0 0 0 0 0 . Y 'E E 'C E -E N j C C N N N N G m N N if .E 335 ' 3' y y '21L33L3flflfl 01. Y N N y N N 0 N LIY Y WE J J E a m' X O pp 0 0 0 0 O 0 0 0 0 J i _ d a d a X Y 2 U UUUUUVUODUmC •a:t yQ c m mm ii u g P.. O N < Z7 N. 1 col , ::... :,1 1 U w _ Q.Z_J a. I-..--1 Q D.O KI d' Z O Z I= W D. D4 D4 111100 0 Lu O = CC X> d J C _ I O tt a O II w aw CT F- W 0 e w}m i��i _ . _�P Y . I a U o OQ co 1- w wHa E. 1111 O z F CO Q J D Z Z 0 0 H Z 0 O 2 . U.CeZU °o O UJ 0 E w O , n. z Z N < 00000 *1 O a 2 z • J O O N _ in _ LLZ0 - ' 0 Z Q Ak -J D 0 CC 0 . 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Moncla Rig 404 BOP Test Procedure Hilcorp Alaska,LLCAttachment#1 Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Moncla Rig 404, WO Program —Oil Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with FIW to kill well. • Note: Fluid level will fall to a depth that balances with reservoir pressure. 3) Shoot fluid level at least 24 hours before moving on well. 4) Shoot fluid level again, right before ND/NU. 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) ND tree with no BPV b) Inspect and prepare BPV profile to accept a 2-way valve,or prepare lift-threads to accept landing joint to hold pressure. If well is a producer and the culprit is scale, attempt to clean profile with Muriatic acid and a wire brush or wheel. c) Set 2-way check valve by hand,or MU landing(test)joint to lift-threads d) 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.Guy Schwartz(AOGCC)and Mr.Jim Regg(AOGCC)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. 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.) • • Moncla Rig 404 BOP Test Procedure Hacurp Alaska,Lac Attachment#1 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 15t valve on standpipe manifold,close valves 1, 2, 10 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 2,500 psi 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,open ft valve of standpipe,close valves 3,4&9 on choke manifold,open valves 1&2 on choke manifold. Test to 250 psi for 5 minutes and 3,000 psi 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 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. d) Close inside valve/open outside valve on kill side of mud cross,close valves 5&6/open valves 3&4 on choke manifold. Test to 250 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. e) Close manual and super choke/open valves 5&6 on choke manifold. Pressure up to^'1200 psi and bleed off 200—300#s recording change and stabilization. If passes after 5 minutes, bleed of pressure back to tank. f) Close HCR(outside valve on choke side of mud cross),open manual&super choke. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. . • • Moncla Rig 404 BOP Test Procedure Hamel)Alaska.LLC Attachment#1 g) Close inside valve/open outside valve(HCR)on choke side of mud cross. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. h) 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 10 on choke manifold,close valve 7&8/open valve 10 on choke manifold. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. i) 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 2nd set of pipe rams if installed(e.g.dual pipe rams). Open the lower pipe rams to simulate the closing volume on the blinds. 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (i.e. Report might read "10 bottles at 2,150 psi"). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre- charge pressure of 1,000 psi). 7) Turn on the pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually+/-30 seconds. 8) Once 200 psi pressure build is reached,turn on the pneumatic pumps and record the time it takes for the pumps to automatically shut-off after the pressure to builds back to original pressure(+/-3,000 psi). Note: Make sure the electric pump is turned to"Auto", not"Manual"so the pumps will kick-off automatically. 9) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 10) Fill out AOGCC report. FINAL STEP,FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves,for correct operating position 3) Fill out the AOGCC BOPE Test Form(10-424)in Excel Format and e-mail to AOGCC and Juanita Lovett. Document both the rolling test and the follow up tests. C .. ---0001.10 0000 O I p V O V V U V V 0 O a . o N .+ r4 en e Ln .r rV m a v. .o n m m g dCidd m f f 2 2 2 f 2 F f 000000000 -- 0 m ry m a Ln 0 .t ry m a in to n to of .. v v v v v v 0 v U v O O O O O L O O O 0 0 0 0 Y Ol C C E. 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C 'C G C C C 'C O j ggggi y — J 0ggg5 g 2' g 2' 2 U t a 0. 6 6 0. C C j ,1) 9 OYWOal OJ OJOJOJ N T EEEEE J o 0000f0000onA fp 3 3 3 3 3 = = U . t . t t L L L L L L .a> a a a a a Y 2 U U U U U U U U U U U Vl co G-o O L a,0 Y � 0 .• `m v 1O m 0 ,o, — ll 11 I1 N CO , CO qk U Z z -,I :--.1-1a. a. Q d O V) .. z O (n U 2 U e O Et w /^' o aw / �> J E2 H m - 111 $$ d Eicri Y .o T CL O Q m I- CO Ili a 1—u H ❑ zID co z o o z � w aDz D — H ❑ j IN J r. Z z z Q sr0E- J Q Q Cn 2 a W Z U 9 Li- 0 C z0 p 2< 0 0 m z Q = J 0 Nt' J U U_ C ► N 0 • r WELL KICK PROCEDURE ilileorp Alaska,LLC Steelhead M-31B 1) Install TIW& close valve 2) Close annular preventer 3) Install low torque valve on top of TIW in closed position. Hook up water flood pump line to low torque valve. 4) Test lines against low torque valve 5) Bleed down water flood lines, open low torque &TIW 6) Open casing valve to production separator& begin pumping/killing well with water flood pump. 1 t ; 3/AI 0 • c 00 / > 0 ) 2 a c 2E 02E . / 2 k� § / « � EE o 2 oc = § i Om J » < �.- k / / � � �� > = f �� / 05 a 0_ 0- § \ � -0 ■ a) 2 \ V. s_ . k k $ % t � CO 2W .- k / @ (41 4 - ID o Cl k \ U a2 $ o m > o_k �� » - C e k / & 2 ?§ J 2< .cCD 22 E § m D0m 2 C '0 2 _0 a) ,_ Z's \ / a. g a) c »7 § a) � # Cl) kp en LU CD > 2 0 u)§ w 2 O a. E % CD > 0 ■ z � o § O m Q ■ R a e e c ' .< CD CO .§ e a) $ 2 Ili 0 S \ £ < U0 Ell .. © v 8 ■ / k m $ ■ E U a) p E •,-I _a c >o ■1:1- 0 e 0 0 2 2 < < < a $ m • • "Schwartz, Guy L (DOA) From: Trudi Hallett <thallett@hilcorp.com> Sent: Friday, April 08, 2016 11:23 AM To: Schwartz, Guy L (DOA) Subject: RE: M-31B (PTD 212-149) Good morning,Guy— Yes—we are trying to get away from the huge 16"stack that we have to ship up here from the lower 48 every time we work on this well.We wanted to change it out last time(Aug 2015), but timing was not on our side. So we are going to change it out this time.We spent a TON of$$on freight,which is just not cost effective for us.This will make it much easier if and when this ESP fails again. I will get the modified BOP testing procedure to you. I know we went thru all this last time we were on the well when Ted was working it. Thanks- Trwo(.i. From: Schwartz, Guy L(DOA) [mailto:guy.schwartz(a)alaska.gov] Sent: Friday, April 08, 2016 9:49 AM To: Trudi Hallett Subject: M-31B (PTD 212-149) Trudi, I see you are adding a tubing spool. What is reason..the old tubing head is pretty new from last S/T? Also how are you testing the circulation and return lines to the manifold building... can you send some type of modified BOP test procedure for that? 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 MUtiV • STATE OF ALASKA SEP 2 4 2015 ' Ailk OIL AND GAS CONSERVATION COM SIGN REPORT OF SUNDRY WELL OPERATIONS AOGCC 1.Operations Abandon 0 Plug Perforations ❑ Fracture Stimulate Cl Pull Tubing❑ Operations shutdown ❑ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing❑ Change Approved Program 0 Plug for Redrill ❑ Perforate New Pool❑ Repair Well 0 Re-enter Susp Well❑ Other: Replaced ESP 0 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory❑ 212-149 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service❑ 6.API Number: Anchorage,AK 99503 50-733-20457-02 — 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0018730 2, •Trading Bay Unit/M-31 B 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10,Field/Pool(s): N/A McArthur River Field/Middle Kenai G and Hemlock Oil Pools 11.Present Well Condition Summary: Total Depth measured 2 11,550 feet Plugs measured N/A feet true vertical * 9,854 feet Junk measured N/A feet Effective Depth measured 11,450 feet Packer measured N/A feet true vertical 9,818 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural 480' 34" 480' 480' Conductor 979' 26" 979' 979' Surface 1,345' 16" 1,345' 1,344' 2,630 psi 1,020 psi Intermediate 3,722' 13-3/8" 3,722' 3,524' 3,090 psi 1,540 psi Production 1,316' 9-5/8" 1,316' 1,315' 6,870 psi 4,760 psi Liner Hanger 32' 10-3/4" 1,348' 1,347' 7,750 psi 6,300 psi Liner 7,759' 9-5/8" 9,107' 8,488' 6,870 psi 4,760 psi Liner 2,629' 7" 11,548' 9,853' 7,240 psi 5,410 psi Perforation depth Measured depth 9,361 -11,396 feet True Vertical depth 8,725-9,798 feet Er I[:.,' :t 2 015 Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80 8,737'(MD) 8,142'(TVD) Packers and SSSV(type,measured and true vertical depth) N/A&N/A 12.Stimulation or cement squeeze summary: Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 578 578 12937 56 105 Subsequent to operation: 600 569 13276 97 107 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory❑ Development ` Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: r Oil El Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data El GSTOR ❑ WINJ ❑ WAG ❑ GINJ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 315-476&315-519 Contact Ted Kramer Email tkramerta'�.hilcorp.com Printed Name Ted Kramer Title Sr.Operations Engineer Signature G:2----- ___ Phone (907)777-8420 Date 9/24/2015 - W04--3421 /o-/S--/5' RBDMS ( SEP 1 5 2015 H . • Steelhead Platform Well #: M-31B Hilcorp Alaska,LLC SCHEMATIC Co m p1 eted: 08/26/2015 PTD#: 212-149 API#: 50-733-20457-02-00 TBG Hanger 74.5'below RKB CASING DETAIL _ SIZE WT GRADE CONN ID TOP BTM. �I \___ �``�ze° ie---4�J _ 34" Surf 480' " 267 thru 46 26" 397# Drill Quip Surf 979' 7 A 16" B 16" 75 K-55 BTC 15.12 Surf 1345' 13-3/8" 61&68 K-55 BTC 12.42 Surf 3722' 9-5/8"Tieback 47# L-80 DWC/C 8.681 Surf 1316' ab 13-3/8" 10-3/4"Liner hgr 65.7# L-80 _ BTC 9.5 1316' 1348' 9-5/8"Liner 47# L-80 DWC/C 8.681 1348' 9,107' 7"liner 26# L-80 VA HT OP 6.276 8919' 11,548' TUBING DETAIL 4-1/2" 12.6# L-80 IBT-M Surf 8,737' Jewelry Detail y NO Depth ID OD Item 1 8,737' 6.750 Bolt On Head 2 8,737' 6.750 Summit Pump(x2)45 stg SH16000 3 8,777' _ 6.750 Seals(x2) 4 8,792' 7.250 Baker Motor(x2) 2 5 8,846' 5.620 GLM Anode 3 64 5 CASING JEWELRY NO Depth Length ID , OD Item BBaker Flex-Lock Liner hanger&Baker HRD-E ZXP liner top packer(PKR A 1,316' . INTENTIONALLY NOT SET!!!) 1r• C B 8,919' 7"Liner top I: '' C 8,925' Baker JM-ZXP Liner Top Packer 41 ' D D 9,107' 9-5/8"Casing Shoe PERFORATION DETAIL Top Zone (MD) Btm(MD) Top(TVD) Btm(TVD) Length(MD) SPF Date G1 9,361' 9,390' 8,725' 8,754' 29' 5 2-20-2013 - G2 9,425' 9,440' 8,786' 8,801' 15' 5 2-20-2013 - G3 9,490' 9,526' 8,843' 8,879' 36' 5 2-23-2013 r G4 9,535' 9,600' 8,885' 8,950' 65' 5 2-23-2013 G5 9,674' 9,710' 9,003' 9,036' 36' 5 2-23-2013 G5 9,720' 9,739' 9,030' 9,049' 19' 5 2-23-2013 ` HK1 9,950' 9,985' 9,208' 9,243' 35' 5 2-23-2013 HK2 10,003' 10,130' 9,251' 9,329' 127' 5 2-23-2013 HK3-4 10,192' 10,600' 9,362' 9,542' 408' 5 2-23-2013 HK5 10,642' _ 10,834' 9,556' 9,617' 192' 5 2-23-2013 HK5 10,866' 11,030' 9,628' 9,680' 164' 5 2-23-2013 ' HK6 11,083' 11,165' 9,697' 9,722' 82' 5 2-23-2013 ' HK6 11,195' 11,270' 9,731' 9,755' 75' 5 2-23-2013 .41 HK7 11,360' 11,396' 9,785' 9,798' 36' 5 2-23-2013 PBTD:11,450 MD/9,818'ND TD:11,550'MD/9,854'ND REVISED:09/23/15 REVISED BY:JLL • • Hilcorp Alaska LLC Well Operations Summary �I`-t Well Name API Number Well Permit Number Start Date End Date M-31B 50-733-20457-01-00 212-071. 8/21/15 8/26/15 Daily Operations: 08/21/2015- Friday N/D PRODUCTION TREE & INSPECT HANGER THREADS (ALL OK). N/U 16-3/4" RISER, MUD CROSS, & DOUBLE BOP. CURRENTLY INSTALLING HYDRIL&TIGHTENING DOWN FLANGE CONNECTIONS IN PREPARATION TO RAISE & FULLY SCOPE DERRICK. 08/22/2015 -Saturday INSTALL 16-3/4" HYDRIL. TORQUE DOWN ALL BOP FLANGE CONNECTIONS. INSTALL CO-FLEX HOSE KILL LINE. HOOK UP KOOMEY LINES& POWER UP KOOMEY SYSTEM. RAISE DERRICK. RESTRING BLOCK WITH NEW DRILL LINE. FULLY SCOPE DERRICK. HOOK UP GUY LINES &TIE DOWN DERRICK. WELDERS CONTINUE MODIFYING STAIRWAYS& DRILLERS SHACK TO EXTEND DUE TO TALLER 16-3/4" BOP STACK. INSTALL STAIRWAYS. LIFT DRILLER SHACK& INSTALL LEG EXTENSIONS. INSTALL BRACKETS & MOUNT DRILLERS CONSOLE. INSTALL RIG FLOOR & EXTEND LEG BRACES. CURRENTLY MODIFYING BRAKE HANDLE,ADDING EXTENSIONS, & INSTALLING RIG FLOOR HAND RAILS. 08/23/2015-Sunday FINISH MODIFYING & INSTALLING STAIRWAYS. INSTALL HANDRAILS ON RIG FLOOR. DRESS OUT RIG FLOOR. R/U MCCOY TONGS. P/U & INSTALL 4-1/2" TEST ASSEMBLY. EXTEND BRAKE HANDLE & MODIFY. BOB NOBLE WITH AOGCC ARRIVED @ 1200 HRS. ATTEMPT TO SHELL TEST 16-3/4" BOP. FOUND LEAK ON RISER CLAMP &GLAND NUT ON TBG HEAD,TIGHTEN SAME. MAKE SECOND ATTEMPT& FOUND BONNET SEALS LEAKING ON BLIND RAMS. TIGHTEN DOWN BONNET BOLTS (UNSUCCESFUL TO STOP LEAK). OPEN RAM BODY&CHANGE BONNET SEALS.ATTEMPT TO SHELL TEST& HAD LEAK ON HIGH TEST. FOUND IBT HANGER THREAD LEAKING. BACK OUT& INSTALL TEFLON & M/U SAME.TEST BOPE PER SUNDRY TO 250 LOW & 3000 HIGH WITH STATE WITNESS BY BOB NOBLE. ALL TEST HELD ON CHART FOR 5 MINUTES.TESTED FROM REMOTE, FUNCTION TESTED MAIN.TEST WERE PERFORMED WITH 4-1/2" TUBING. PERFORM KOOMEY DRAW DOWN TEST& R/D TEST EQUIPMENT. BLEED DOWN GAS FROM ANNULUS (60 PSI). BACK OUT HOLD DOWN PINS & PREPARE TO PULL HANGER TO RIG FLOOR. PULL HANGER FROM TUBING HEAD WITH (125K) PIPE WT. BREAK& L/D TBG HANGER SAME. MEG CABLE (SHOWING GROUND FAULT). POOH WITH 4-1/2" 12.6# PRODUCTION TBG. DEPTH @ 0600 HRS= 8,390'.TOTAL OF 60 BBLS OF 8.5# FIW ADDED TO WELL LAST 24 HRS. 08/24/2015- Monday CONTINUE POOH WITH 4-1/2" 12.6# L-80 PRODUCTION TBG, RACKING PIPE IN DERRICK. TOTAL OF 274 JOINTS POOH. INSPECTING CABLE FOR VISUAL SIGNS OF WEAR.ALL & FLATPACK WAS INTACT AND IN GOOD TO NEW CONDITION. R/U ESP EQUIPMENT TO L/D PUMP & MOTOR ASSEMBLY. L/D PUMP& MOTOR ASSEMBLY INSPECTING PUMP SHAFTS & COUPLINGS (ALL OK). MEG BAKER LOWER TANDEM MOTOR ASSEMBLY& FOUND GROUND FAULT INSIDE OF LOWER MOTOR. L/D SAME & PREPARE TO P/U NEW ESP ASSEMBLY. P/U BAKER LOWER TANDEM 1100 HP MOTOR ASSEMBLY WITH UPPER& LOWER SEALS. SERVICE & MEG SAME. CURRENTLY P/U SUMMIT PUMP & PLAN TO TIH WITH 4-1/2" 12.6# TBG.TOTAL OF 80 BBLS ADDED TO WELL LAST 24 HRS. • • Hilcorp Alaska LLC Well Operations Summary Lel Well Name API Number Well Permit Number Start Date End Date M-31B 50-733-20457-01-00 212-071 8/21/15 8/26/15 Daily Operations: e- 08/25/2015 -Tuesday "08/25/2015 -Tuesday P/U SUMMIT ESP ASSEMBLY&TIH SAME. MEG CABLE ON TOP OF PUMP (ALL OK).TOTAL BHA LENGH = 142.13'.TIH WITH 4-1/2" 12.6# L-80 PRODUCTION TBG FROM DERRICK, INSTALLING CANNON CLAMPS AROUND CABLE & FLATPACK. PERFORM CABLE SPLICE @ 4,909'. CONTINUE TIH WITH 4-1/2" PRODUCTION TBG. INSTALL 16" TBG HANGER,TIE IN FLATPACK& INSTALL PENETRATOR. LAND OUT HANGER INSIDE TBG HEAD WITH 95K WEIGHT, SETTING END OF ANODE @ 8,844.73'. RUN HOLD DOWN PINS &SECURE HANGER. L/D LANDING JTS. R/D SUMMIT SHEAVES. CURRENTLY R/D RIG FLOOR & PREPARING TO SCOPE DOWN & LAY OVER DERRICK TO N/D BOP. 08/26/2015-Wednesday RID MCCOY TONGS. REMOVE RIG FLOOR HAND RAILS& REMOVE RIG FLOOR. REMOVE DRILLERS CONSOLE & DRILL SHACK. PREP DERRICK&SCOPE IN SAME. LAY DERRICK DOWN INTO CRADLE &SECURE. N/D 16-3/4" 5M BOPE. PREP HANGER & PREPARE TO INSTALL PRODUCTION TREE @ 1600 HRS. PREP REMAINING RIG 404 EQUIPMENT FOR BACKLOAD ON TO BOAT. BACKLOAD BOAT WITH REMAINING RIG 404 EQUIPMENT. • ti of fit7, Alaska Oil and Gas �w\��\��j,�s THE STATE he,„—.-s��, of T Conservation Commission -:- :___ A t ftJ(j\ 'l1Ei-iltx _= 333 west Seventh Avenue �' GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 ''� Main: 907.279.1433 OF ALAS�� Fax: 907.276.7542 www.aogcc.alaska.gov Ted Kramer SCANNED r ' Siti /(; Sr. Operations Engineer �` — I L Hilcorp Alaska, LLC r 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 Re: McArthur River Field, Middle Kenai G and Hemlock Oil Pools, TBU M-31 B Sundry Number: 315-519 Dear Mr. Kramer: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the 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, Cs461°29...e.,‘.474....L._, Cathy P.7 . oerster Chair DATED this 2. day of August,2015 End. RBDMS SEP 0 4 2015 • RECEIVED STATE OF ALASKA AUG 2 4 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION ��$/Z7b` S APPLICATION FOR SUNDRY APPROVALS GLV+ 20 AAC 25.280 1.Type of Request: Abandon❑ Plug Perforations❑ Fracture Stimulate ❑ Pull Tubing ❑ Operations shutdown ❑ Suspend E Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program 0 Plug for Redri4❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development [ . 212-149• 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-733-20457-02 • 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes ❑ No Trading Bay Unit/M-31B 9. Property Designation(Lease Number): 10. Field/Pool(s): ADL0018730 McArthur River Field/Middle Kenai G and Hemlock Oil Pools • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): • 11,550 , 9,854 , 11,450 •9,818 N/A N/A Casing Length Size MD TVD Burst Collapse Structural 480' 34" 480' 480' Conductor 979' 26" 979' 979' Surface 1,345' 16" 1,345' 1,344' 2,630 psi 1,020 psi Intermediate 3,722' 13-3/8" 3,722' 3,524' 3,090 psi 1,540 psi Production 1,316' 9-5/8" 1,316' 1,315' 6,870 psi 4,760 psi Liner Hanger 32' 10-3/4" 1,348' 1,347' 7,750 psi 6,300 psi Liner 7,759' 9-5/8" 9,107' 8,488' 6,870 psi 4,760 psi Liner 2,629' 7" 11,548' 9,853' 7,240 psi 5,410 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 9,361 -11,396 • 8,725-9,798 4-1/2" 12.6#/L-80 8,737 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A&N/A N/A&N/A • 12.Attachments: Description Summary of Proposal 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch LI Exploratory ❑ Stratigraphic❑ uvelopment L' Service ❑ 14. Estimated Date for 15.Well Status after proposed work: Commencing Operations: In progress under Sundry#315-476 OIL 0 • WINJ ❑ WDSP❑ Suspended ❑ 16.Verbal Approval: Date: 8/24/2015 GAS ❑ WAG ❑ GSTO❑ SPLUG ❑ Commission Representative. Guy Schwartz GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Ted Kramer Email tkramer@hilcorp.com Printed Name Ted Kramer Title Sr.Operations Engineer Signature yic� //L4t.c.. k?' t��/ I one (907)777-8420 Date 8/24/2015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: —;k9 S`9 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Spacing Exception Required? Yes ❑ No Subsequent Form Required: e' APPROVED BY Approved by: 24( �/�, COMMISSIONER THE COMMISSION Date: S — /S� S�.ZG i S �� ?.5�,S 0 D I i A.� �1��V REI SEP 04 iit5Form and Form 10-403 Revised 5/2015 e I t t valid for 12 months from the date of approval. Attachments in Duplicate Well Work Prognosis Change of Approved Program Hilcorp Alaska,LLC Well: M-31B Date: 08/24/15 Well Name: M-31B API Number: 50-733-20457-02 • Current Status: ESP Producer Leg: B-1 Estimated Start Date: 08/20/2015 Rig: Moncla Rig#404 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett(8332) Permit to Drill Number: 212-149 First Call Engineer: Trudi Hallett (907)777-8232 (0) (907)301-6657(M) Second Call Engineer: Ted Kramer (907)-777-8420(0) (985)-867-0665 (M) Current Bottom Hole Pressure: "'2,800 psi @ 7,780'TVD 0.36 psi/ft(ESP Intake) Maximum Expected BHP: ^'2,800 psi @ 7,780'TVD (No new perfs being added) Max.Anticipated Surface Pressure: 2268 psi (Using 0.1 psi/ft. per 20 aac 25.280(b)(4) Brief Well Summary M-31B is a G/ Hemlock Producer completed with an ESP.The ESP experienced a down-hole failure August 2nd,2015.We plan to pull and replace the ESP. No perforations will be added. Procedure: 1. MIRU Rig. 2. Attempt to pump through ESP to circulate hydrocarbon off the well to production. If necessary, RU e-line and RIH to+/-8,750'and punch tubing. 3. ND Wellhead, NU BOP and test to 250psi low/2,500psi high. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 4. POOH with tubing string and ESP pump laying down the same. 5. PU, RIH with ESP completion. 6. Land ESP with the bottom of the assembly at+/-8,900'. 7. ND BOP, NU wellhead and test. 8. Turn well over to production. 9. RDMO Rig. Hilcorp requests a variance from 20 AAC 25.285(h). The request is to supply kill fluid from and take returns to the production facility instead of the rig circulating system. The Steelhead production facility can supply and receive more fluid than the rig circulating system. (Injection Pressure=3,400 psi.) Hilcorp also offers the following in support of this variance: The nature of the M-31b work is to pull a failed ESP and run a like in kind unit. The M-31b is a no flow well. No other well work is planned. There will be no planned cleanout run,and no addition of perforations that could cause exposure to additional reservoir pressure. Hilcorp plans to circulate any hydrocarbon off the well and control any potential kick from the well by implementing the attached "Well Kick Procedure". A drawing of the circulating system is also attached. Attachments: 1. BOP Drawing showing circulation system 2. Well Kick Procedure . ..-Eli 211 LOW TORQUE Arst VALVE CONNECTEOWWell-mad Platform TO WATER FLOG. I6'f/ SM 110P (Oil 1.4g) M-3111 1111. �,, .«' , .La. LIN:. �1: itj11N1n1/21115. TIW VALVE iiiiii '.In Circulating Choke House ! ( Manifold 1 I•nin,i Ammo , • ,l,IC 1/, ' - 4u114,,'4 7 O !trod — ,:r! 10 Valve closed & choke +0.1 Valve closed& � , IV 11111 ill locked out house locked aut 4 1 Valves closed & Valves closed & locked out locked out i cm;14 N%I 1M'1 hub' '''.,Ow 911411M7t 1 1#4' 11 LIM um 131111114 ill 1•6 .......44....«.401-",•.0 um , ((iii/t."/ Production a ..----". Header ri. Lit II_ . 'i 1._i M-31-B WELL KICK PROCEDURE 1) Install TIW&close valve 2) Close annular preventer 3) Install low torque valve on top of TIW in closed position. Hook up water flood pump line to low torque valve. 4) Test lines against low torque valve 5) Bleed down water flood lines, open low torque&TIW 6) Open casing valve to production separator& begin pumping/killing well with water flood pump. Steelhead Platform 14Well#: M-31B Nilcorp Alaska,LLC SCHEMATIC Completed: 08/07/2014 PTD#: 212-149 API#: 50-733-20457-02-00 TBG Hanger 74.5'below RKB CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. • Jb,Z6„ 34" Surf 480' ;' 26" 267 397 #ru Drill Quip Surf 979' A , 16" 16" 75 K-55 BTC 15.12 Surf 1345' 13-3/8" 61&68 K-55 BTC 12.42 Surf 3722' 9-5/8"Tieback 47# L-80 DWC/C 8.681 Surf 1316' 13-3/8" 10-3/4"Liner hgr 65.7# L-80 BTC 9.5 1316' 1348' 9-5/8"Liner 47# L-80 DWC/C 8.681 1348' 9,107' 7"liner 26# L-80 VA HC OP 6.276 8919' 11,548' TUBING DETAIL 4-1/2" 12.6# L-80 IBT-M Surf 8,737' Jewelry Detail NO Depth ID OD Item 1 8,737' 6.750 Bolt On Head 2 8,737' 6.750 Summit Pump(x2)45 stg SH16000 3 8,777' 6.750 _ Seals(x2) 4 8,792' 7.250 _ Baker Motor(x2) 2g 5 8,846' 5.620 GLM Anode 3 4 5 CASING JEWELRY v. NO Depth Length ID OD Item B Baker Flex-Lock Liner hanger&Baker HRD-E ZXP liner top packer(PKR A 1,316' INTENTIONALLY NOT SET!!!) / , C B 8,919' 7"Liner top C 8,925' Baker JM-ZXP Liner Top Packer y ,� D D 9,107' 9-5/8"Casing Shoe PERFORATION DETAIL Top Zone (MD) Btm(MD) Top(ND) Btm(TVD) Length(MD) SPF Date * G1 9,361' 9,390' 8,725' 8,754' 29' 5 2-20-2013 G2 9,425' 9,440' 8,786' 8,801' 15' 5 2-20-2013 G3 9,490' 9,526' 8,843' 8,879' 36' 5 2-23-2013 G4 9,535' 9,600' 8,885' 8,950' 65' 5 2-23-2013 G5 9,674' 9,710' 9,003' 9,036' 36' 5 2-23-2013 G5 9,720' 9,739' 9,030' 9,049' 19' 5 2-23-2013 HK1 9,950' 9,985' 9,208' 9,243' 35' 5 2-23-2013 HK2 10,003' 10,130' 9,251' 9,329' 127' 5 2-23-2013 ,m HK3-4 10,192' 10,600' 9,362' 9,542' 408' 5 2-23-2013 2 HK5 10,642' 10,834' 9,556' 9,617' 192' 5 2-23-2013 HK5 10,866' 11,030' 9,628' 9,680' 164' 5 2-23-2013 ' HK6 11,083' 11,165' 9,697' 9,722' 82' 5 2-23-2013 HK6 11,195' 11,270' 9,731' 9,755' 75' , 5 2-23-2013 HK7 11,360' 11,396' 9,785' 9,798' 36' 5 2-23-2013 PBTD:11,450 MD/9,818'ND TD:11,550'MD/9,854'ND REVISED:09/05/14 REVISED BY:JLL Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Monday, August 24, 2015 11:45 AM To: 'Bobby Harrington - (C)' Cc: Ted Kramer;Trudi Hallett; Dan Marlowe; 'Regg,James B (DOA) (jim.regg@alaska.gov)' Subject: RE: Moncla 404/Steelhead M-31B Well kill procedure Ted, This is starting to make more sense... 1 was under the impression this was only for the initial well kill before pulling the ESP equipment OOH. I don't recall the variance for M-29A ESP swap but will check into it. This should have been addressed in the sundry application and a variance requested for alternative BOP equipment under 20 AAC 25.035. There is no mention of this at all in the sundry. At a minimum I need a "change of approved program" sundry with a detailed document/drawing showing how the well control is rigged up. You have verbal approval to proceed with the RWO but get the sundry in explaining the well control rig-up ASAP so we can understand the process. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at (907-793-1226) or(Guy.schwartz@alaska.gov). From: Bobby Harrington - (C) [mailto:bharrington©hilcorp.com] Sent: Sunday, August 23, 2015 4:16 PM To: Schwartz, Guy L(DOA) Cc: Ted Kramer; Trudi Hallett; Dan Marlowe Subject: RE: Moncla 404/Steelhead M-31B Well kill procedure Guy, On the M-29A well we used this well kick procedure attached to the e-mail. It consist of using production water flood pumping down the tubing&taking returns up the annulus out the casing valve strait to production. This allows us to have a smaller rig up not having to use rig pumps,tanks, chokes, etc. Only implementing the bop stack as stated in the well kick procedure. I was asking permission to do the same on the M-31B well that you granted us earlier in the year on M-29A. The M-31B is a no flow well. Please Advise.Thanks, Bobby Harrington WSM-Steelhead (0) 907-776-6757 (C) 337-764-3228 bharrington@hilcorp.com 1 From: Schwartz, Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent: Sunday, August 23, 2015 3:17 PM To: Bobby Harrington - (C) Cc: Ted Kramer; Trudi Hallett; Dan Marlowe Subject: Re: Moncla 404/Steelhead M-31B Well kill procedure Bobby, Got a call from Ted .. Read through procedure and not sure what you are aiming at. Looks like BOPE are rigged up and u are using a landing Joint to Circulate well before pulling hanger. What is ur question? Guy Schwartz AOGCC Sent from my iPhone On Aug 21, 2015, at 3:11 PM, "Bobby Harrington -(C)" <bharrington@hilcorp.com>wrote: Guy, We will be beginning our esp change out operations on the M-31B well in the next day or so and are asking permission to use the same well kill procedure that we have used on past esp change outs. It has worked great on previous wells such as the M-29A that we did on the Steelhead earlier this year.The rig crews are very familiar and use to this procedure during esp change outs. I have included a written procedure that will be posted inside the drillers house as well as the tool pusher office. Please advise, thanks Bobby Harrington WSM-Steelhead (0) 907-776-6757 (C) 337-764-3228 bharrington@hilcorp.com <M-31-B WELL KICK PROCEDURE.docx> 2 v °F Tk� • 0w\��j�,s� THE STATE Alaska Oil and Gas ti -s ��, of/ T /�, 1 Conservation Commission ' ~ " -:- l 1 1 J l 1�J��t1 1 ' -fix___ _ 333 West Seventh Avenue 401 _ M GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 of ;;�� Main 907 279 1433 ALAS Fax 907.276 7542 5) www.aogcc alaska.gov Trudi Hallett cala — i +/ Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: McArthur River Field, Middle Kenai G and Hemlock Oil Pools, TBU M-31B Sundry Number: 315-476 Dear Ms. Hallett: 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, 4/ Cathy P. oerster Chair DATED this /3 day of August, 2015 Encl. STATE OF ALASKA `, 't 7 ALASKA OIL AND GAS CONSERVATION COMMISSION 1)V V I tb I I% APPLICATION FOR SUNDRY APPROVALS E .,ii', t3 a 20 AAC 25.280 � '�.>J -) I ,f 1 Type of Request: Abandon❑ Plug Perforations❑ Fracture Stimulate ❑ Pull Tubing .❑ Operations shutdown ❑ Suspend❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program 0 Plug for Redrill❑ Perforate New Pool ❑ Repair Well g' nter Susp Well ❑ Other. _Replace ESP Q 2 Operator Name: 4.Current WeN Class: 5.Permit to Drill Number Hiloorp AK,LLC Exploratory ❑ Development Q 212-149 3.Address Stratigraphic ❑ Service El 6.API Number. r7) 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 50-733-20457-Oa.-'0-,-, 7 If perforating: -,i /(4' 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 080:89-, Will planned perforations require a spacing exception? Yes ❑ No QQ Trading Bay Unit M-31 B 9 Property Designation(Lease Number): 10.Field/Pool(s): ADL0018730 McArthur River Field/Middle Kenai G and Hemlock Oil Pools I 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 11,550 9,854 11,450 9,818 N/A N/A Casing Length Size MD TVD Burst Collapse Structural 480' 34" 480' 480' Conductor 979' 26" 979' 979' - Surface 1,345 16' 1,345' 1,344' 2,630 psi 1,020 psi Intermediate 3,722' 13-3/8" 3,722' 3,524' 3,090 psi 1,540 psi Production 1,316' 9-5/8" 1,316' 1,315' 6,870 psi 4,760 psi Liner Hanger 32' 10-3/4" 1,348' 1,34T 7,750 psi 6,300 psi Liner 7,759' 9-5/8" 9,107' 8,488' 6,870 psi 4,760 psi Liner 2,629' 7" 11,548' 9,853' 7,240 psi 5,410 psi Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 9,361-11,396 8,725-9,785 4-1/2f/ 12.6#/L-80 8,768 Packers and SSSV Type: N/A fitj3 Packers and SSSV MD(ft)and ND(ft): N/A ?AC-l1•Eir81U r1) 12.Attachments: Description Summary of Proposal 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Q Exploratory ❑ Stratigraphic❑ Development Q Service 0 14 Estimated Date for 20-Aug-15 15.Well Status after proposed work: Commencing Operations: OIL 0 WINJ ❑ WDSPL ❑ suspended ❑ 16 Verbal Approval: Date: GAS ❑ WAG El GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17 I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Trudi Hallett Email thallettahilcorp.com Printed Name Trudi Hallett Title Operations Engineer Signature • Phone 907-777-8323 Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: X15 '' 47V Plug Integrity El BOP Test i Mechanical Integrity TestEl Location Clearance ❑ Other. 30�I� p 5� a P / ts'S i— (fr'IA-s /" = L�s�7 �a I Sacro Exception fired? Yes ❑ No lil Subsequent Form Requited: 0--'/DLI Spacing P Requ � / A , P ✓"�✓ APPROVEDHBSY Approved by' COMMISSIONER THE COMMISSION Date: �` /`S Submit Folin and Fo 10-40 ev ed 1)/2015 Approvea application is vane ror a monms nom a oars or approv I. Apchments in Duplicate trII GRIGINA� tit-/s Ar (5"4 ,i RBDMS,3\ AUG 1 4 2015 1 un i , .y 'k :-.4- w •w �w STATE OF ALASKA i 1 . 0 5 1. ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS r ,()(:)Cr 20 MC 25.280 1.Type of Request: Abandon❑ Plug Perforations El Fracture Stimulate ❑ Pull Tubing D ' Operations shutdown El Suspend 0 Perforate ❑ Other Stimulate El Alter Casing 0 Change Approved Program ❑ Plug for Redrill❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other. Replace ESP E 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC 4 Exploratory ❑ Development 2 . 212-149 ' 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number. Anchorage,AK 99503 / 50-733-20457-02-00 . 7.If perforating: 4.18A fis 8.Well Name . ,. Number. What Regulation or Conservation Order governs well spacing in this pool? CO 98&889- Trading Bay Unit/M-31 B Will planned perforations require a spacing exception? Yes ❑ No ❑✓ 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0018730 i McArthur River Field/, iddle Kenai G and Hemlock Oil Pools 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD(ft): Effective Depth ND • Plugs(measured): Junk(measured): 11,550 - 9,854 4 11,450• 9 : 40 N/A N/A Casing Length Size MD A 1r TVD Burst Collapse Structural 480' 34" 480' 480' I Conductor 979' 26" 979' 979' Surface 1,345' 16" 1,34`5 / 1,344' 2,630 psi 1,020 psi Intermediate 3,722' 13-3/8" 3,7-e'." 3,524' 3,090 psi 1,540 psi Production 1,316' 9-5/8" 0 �.' 1,315' 6,870 psi 4,760 psi Liner Hanger 32' 10-3/4" , 48' 1,347' 7,750 psi 6,300 psi Liner 7,759' 9-5/8" %1 9,107' 8,488' 6,870 psi 4,760 psi Liner 2,629' 7" rt\I ' 11,548' 9,853' 7,240 psi 5,410 psi Perforation Depth MD(ft): Perforation Depth ND(ft): `T g Size: Tubing Grade: Tubing MD(ft): 9,361 -11,396 • 8,725-9,785 4-1/2: 12.6#/L-80 8,768 12.Attachments: Description Summary of Proposal ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Q Exploratory ❑ Stratigraphic❑ Development❑✓ • Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: August 2r;2015 OILWDSPL ❑ ' WINJ ❑ ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR 0 SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17.I hereby certify that the foregoing is true and orrect to the best of my knowledge. Contact Trudi Hallett Email thallett@hilcorp.com Printed Name�� JT�ruudi Hallett Title Operations Engineer Signature (i ✓"w"' / /'/ ' Phone 907-777-8323 Date /3'-/i COMMISSION USE ONLY Conditions of approval: Notify C• mission so that a representative may witness Sundry Number: Plug Integrity 0 BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Spacing Exception Required? Yes ❑ No I2 Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 1� N ` Submn Form and Form 10-403 Revised 5/2015 Approved application Is valid fo 1 t r t at/Ij_iblf pproval. Attachments in Duplicate 1 Well Work Prognosis Well: M-31B Hilcorp Alaska,LLCDate: 08/05/15 Well Name: M-31B API Number: 50-733-20457-02 Current Status: ESP Producer Leg: B-1 Estimated Start Date: 08/20/2015 Rig: Moncla Rig#404 " Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett(8332) Permit to Drill Number: 212-149 First Call Engineer: Trudi Hallett (907) 777-8232 (0) (907) 301-6657 (M) Second Call Engineer: Ted Kramer (907)-777-8420 (0) (985)-867-0665 (M) Current Bottom Hole Pressure: — 2,800 psi @ 7,780' TVD 0.36 psi/ft(ESP Intake) Maximum Expected BHP: — 2,800 psi @ 7,780' TVD (No new penis being added) Max. Anticipated Surface Pressure: 2268 psi (Using 0.1 psi/ft. per 20 aac 25.280(b)(4) Brief Well Summary M-31B is a G / Hemlock Producer completed with an ESP. The ESP experienced a down-hole failure August 2nd, 2015.We plan to pull and replace the ESP. No perforations will be added. . Procedure: 1. MIRU Rig. 2. Attempt to pump through ESP to circulate hydrocarbon off the well to production. If necessary, RU e-line and RIH to+/-8,750' and punch tubing. 3. ND Wellhead, NU BOP and test to 250psi low/2,500psi high. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 4. POOH with tubing string and ESP pump laying down the same. 5. PU, RIH with ESP completion. 6. Land ESP with the bottom of the assembly at+/-8,900'. 7. ND BOP, NU wellhead and test. 8. Turn well over to production. 9. RDMO Rig. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Wellhead Diagram (Current and Proposed) 4. BOP Drawing Steelhead Platform Well#: M-31B Hikorp Alaska,LLC SC H E MAT I C Completed: 2/20/2013 PTD#: 212-149 API#: 50-733-20457-02-00 TBG Hanger 74.5'below RKB CASING DETAIL atiSIZE WT GRADE CONN ID TOP BTM. 26 34" Surf 480' " it 267 thru t6^ 26" 397# Drill Quip Surf 979' A NI 16" 75 K-55 _ BTC _ 15.12 Surf 1345' 13-3/8" 61&68 K-55 BTC 12.42 Surf 3722' r.1iia 3/6" 9-5/8"Tieback 47# L-80 DWC/C 8.681 Surf 1316' 10-3/4"Liner hgr 65.7# L-80 BTC 9.5 _ 1316' 1348' 9-5/8"Liner 47# L-80 DWC/C 8.681 1348' 9,107' 7"liner 26# L-80 VA HTOP 6.276 8919' 11,548' TUBING DETAIL 4-1/2" 12.6# L-80 IBT-M Surf 8,768' TUBING JEWELRY NO Depth Length ID OD Item 1 8,768' 0.69' Head Bolt On Discharge 2 8,769' 48.6' Pump(x3)—J12000N C-CT 32 STG 675/675110 3 8,818' 1.12' Intake 4 8,837' 33.93' Motor-738,E180 Dominator RK-S,CS,M-TRM 2 g 5 8,875' 105.44 Bottom of ESP 3 4 5 CASING JEWELRY Po NO Depth , Length ID OD Item B A 1,316' Baker Flex-Lock Liner hanger&Baker HRD-E ZXP liner top packer(PKR ii.$ +, INTENTIONALLY NOT SET!!!) 1 C B 8,919' 7"Liner top C 8,925' Baker 1M-ZXP Liner Top Packer D 9,107' 9-5/8"Casing Shoe D 4 .. «.y PERFORATION DETAIL y 0 Top 1;11 i Zone (MD) Btm(MD) Top(ND) Btm(TVD) Length(MD) SPF Date G1 9,361' 9,390' 8725 8754 29' 5 2-20-2013 4r!. G2 9,425' 9,440' 8786 8801 15' 5 2-20-2013 G3 9,490' 9,526' 8843 8879 36' 5 2-23-2013 p G4 9,535' 9,600' 8885 8950 65' 5 2-23-2013 G5 9674 9710 9003 9036 .. 36' 5 2-23-2013 G5 9720 9739 9030 9049 19' 5 2-23-2013 HK1 9950 9985 9208 9243 35' 5 2-23-2013 4a HK2 10003 10130 9251 9329 127' 5 2-23-2013 y HK3-4 10192 10600 9362 9542 408' 5 2-23-2013 ! HK5 10642 10834 9556 9617 192' 5 2-23-2013 lal LI HKS 10866 11030 9628 9680 164' 5 2-23-2013 HK6 11083 11165 9697 9722 82' 5 2-23-2013 HK6 11195 11270 9731 9755 75' 5 2-23-2013 rill HK7 11360 11396 9785 9798 36' 5 2-23-2013 PBTD:11,450 MD/9,818'TVD TD:11,550'MD/9,854'ND REVISED:07/07/2014 REVISED BY:111 Steelhead Platform Well#: M-31B Hi!carp Alaska,LLC PROPOSED Completed: 08/07/2014 PTD#: 212-149 API#: 50-733-20457-02-00 TBG Hanger 74.5'below RKB CASING DETAIL J ` l SIZE WT GRADE CONN ID TOP BTM. 4 Pz6„ 34" Surf 480' ,J' 26" 267 thru Drill Quip Surf 979' 397# • A 16" 16" 75 K-55 BTC 15.12 Surf 1345' 1 13-3/8" ` 61&68 K-55 BTC 12.42 Surf 3722' 9-5/8"Tieback 47# L-80 DWC/C 8.681 Surf 1316' 13-3l8" 10-3/4"Liner hgr 65.7# L-80 BTC 9.5 1316' 1348' 9-5/8"Liner 47# L-80 DWC/C 8.681 1348' 9,107' 7"liner 26# L-80 VA HC OP 6.276 8919' 11,548' TUBING DETAIL 4-1/2" I 12.6# L-80 IBT-M Surf ±8,737' Jewelry Detail NO Depth _ ID OD Item 1 ±8,845' Bottom of ESP 1` - CA SING JEWELRY NO Depth Length ID OD Item B Baker Flex-Lock Liner hanger&Baker HRD-E ZXP liner top packer(PKR A 1,316' C INTENTIONALLY NOT SET!!!) B 8,919' 7"Liner top C 8,925' Baker 1M-ZXP Liner Top Packer 41 D D 9,107' 9-5/8"Casing Shoe PERFORATION DETAIL Top Zone (MD) Btm(MD) Top(TVD) Btm(TVD) Length(MD) SPF Date G1 9,361' 9,390' 8725 8754 29' 5 2-20-2013 .1- G2 9,425' 9,440' 8786 8801 - 15' - 5 2-20-2013 :el G3 9,490' 9,526' 8843 8879 36' 5 2-23-2013 ti' G4 9,535' 9,600' 8885 8950 65' 5 2-23-2013 G5 9674 9710 9003 9036 36' 5 2-23-2013 r G5 9720 _ 9739 9030 9049 19' 5 2-23-2013 HK1 9950 9985 9208 9243 35' 5 2-23-2013 HK2 _ 10003 10130 9251 _ 9329 127' 5 2-23-2013 � y HK3-4 10192 10600 9362 9542 408' 5 2-23-2013 ,1 HK5 10642 10834 9556 9617 192' 5 2-23-2013 HK5 10866 11030 9628 9680 164' 5 2-23-2013 HK6 11083 11165 9697 9722 82' 5 2-23-2013 .. .,, HK6 11195 11270 9731 9755 75' 5 2-23-2013 it HK7 11360 11396 9785 9798 36' 5 2-23-2013 PBTD:11,450 MD/9,818'ND TD:11,550'MD/9,854'ND REVISED:08/05/2015 REVISED BY:TRH Steelhead Platform M-31B 07/07/2014 IliIrierp A1842.1.1.1, Steelhead Platform Tbg hanger,FMC-TC-IA-EN- M-31B EC-CCL,16%SM X 4%IBT 26 X 16 X 133/8 X95/8 X lift and susp,w/4'Type H 4 1/2 BPV profile,2-3/8 continuous control line BHTA,Bowen, 41/16 5M FE X 7-SSA Bowen top ... —se.s Valve,Swab,WKM-M, /0. �0 41/165M FE,HWO,DD D(O r OHO la dill II IIIMIllm Valve,upper master,SSV, 'WM� [r 41/165M FE,w/15'Safeco O 41 iv operator,EE `) ' . 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They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. al - 1 14-9 Well History File Identifier Organizing(done) ❑ Two-sided ❑ Rescan Needed RES N: OVERSIZED: NOTES: Color Items: ❑ Maps: \a/ayscale Items: ❑ Poor Quality Originals: ❑ Other: ❑ Other: BY: Maria Date: 10/../g/fito /s/ 64P Project Proofing BY: AIMDate: (:),, / /s/ 01 P Scanning Preparation 3 - x 30 = q© +, r 1 =TOTAL PAGES fc �- ^ (Count does not include cover sheet) Al BY: �. Date: 'd� �(O/ /s/ Production Scanning / Stage 1 Page Count from Scanned File: / ©5(Count does include cover eet) Page Count Matches Number in Scannin Preparation: YES i44 NOpBY: WMDate: I / 16 Gik /s/ I Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Stage 2 Additional Well Reports: 110NO TOTAL PAGES: C6 4- Digital version appended by: Meredith _lam Michal 4 Date: /s/ 1 Final Page Count: Stage 1 + Stage 2: TOTAL PAGES: O Scanning is complete at this point unless rescanning is required. 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Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 355 252 11562 46 294 Subsequent to operation: 473 254 12356 92 104 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run Exploratory❑ Development Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil 0 Gas ❑ WDSPL❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt. 314-404 Contact Ted Kramer Email tkramer@hilcorp.com Printed Name Ted Kramer Title Sr.Operations Engineer Signature . Phone (907)777-8420 Date 9/5/2014 Form 10144-Revised 10/2012 Subrnit Orlglnal Only , .-�,-/y 0 ,71./y RBCMS SEP - 8 201 AIMINOMMOINIMINInar • ' 6,4?N IV THE STATE L_^ c`,ce rn `' l ,s;'e-,<F1 ,.___::--___ ---= ;:\ of i 7 4 7,1-7. A K10.______ 1t _ _- 333 vilest Sc e h A eruct -- yGOVERNOR SEAN PAk�il.lAnchorage AiasKa 9950i-3572 Mom 907 279 1433 1 ,); � 1 'fq Dan Marlowe Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 Re: McArthur River Field, Middle Kenai G and Hemlock Oil Pools, TBU M-31B Sundry Number: 314-404 Dear Mr. Marlowe: 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, P)wti__, Cathy P. oerster / Chair DATED this A-T d of July, 2014. Encl. C., w� \t\RECEIVED ca-STATE OF ALASKA \� JUL 0 7 2014 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 MC 25.280 1.Type of Request. Abandon❑ Plug for Redrill❑ Perforate New Pool❑ Repair Well El Change Approved Program❑ Suspend El Plug Perforations❑ Perforate❑ Pull Tubing 0 - Time Extension El Operations Shutdown❑ Re-enter Susp.Well❑ Stimulate El Alter Casing❑ Other: Replace ESP - 0 2.Operator Name: 4.Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska,LLC J Exploratory ❑ Development 0 ' 212-149 - 3.Address: 3800 Centerpoint Drive,Suite 1400Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-733-20457-02-00 - 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? N/A / Will planned perforations require a spacing exception? Yes ❑ No❑ Trading Bay Unit/M-31B • 9.Property Designation(Lease Number): 10.Field/Pool(s). ADL0018730 . McArthur River Field/Middle Kenai G and Hemlock Oil Pools • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft). Effective Depth TVD(ft): Plugs(measured): Junk(measured). 11,550 - 9,854 ' 11,450 - 9,818 ' N/A N/A Casing Length Size MD TVD Burst Collapse Structural 480' 34" 480' 480' Conductor 979' 26" 979' 979' Surface 1,345' 16" 1,345' 1,344' 2,630 psi 1,020 psi Intermediate 3,722' 13-3/8" 3,722' 3,524' 3,090 psi 1,540 psi Production 1,316' 9-5/8" 1,316' 1,315' 6,870 psi 4,760 psi Liner Hanger 32' 10-3/4" 1,348' 1,347' 7,750 psi 6,300 psi Liner 7,759' 9-5/8" 9,107' 8,488' 6,870 psi 4,760 psi Liner 2,629' 7" 11,548' 9,853' 7,240 psi 5,410 psi • Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size. Tubing Grade: Tubing MD(ft): 9,361 -11,396 ' 8,725-9,785 4-1/2: 12.6#/L-80 8,768 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): N/A&N/A N/A&N/A 12.Attachments: Description Summary of Proposal 0 13.Well Class after proposed work. Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ Stratigraphic❑ Development 0• Service ❑ 14.Estimated Date for 15.Well Status after proposed work. 8/1/2014 Commencing Operations. Oil 0 ' Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG 0 Abandoned 0 Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Dan Marlowe Email dmarlowe@hilcorp.com Printed Name Dan Marlowe_ Title Operations Engineer Signature hone (907)283 1329 Date 7/7/2014 COMMISSION USE ONLY Conditions of approval. Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test le Mechanical Integrity Test ❑ Location Clearance ❑ Other 41 Z St''c f'S; J3 E,f' /6_, f— Spacing Exception Required? Yes ❑ No I0" Subsequent Form Required: / C, -- Y [J`j APPROVED BY Approved by: g � COMMISSIONERSITHE ICc,OMMISSION Date: 7_/s 067 r`f -/`/ LtJc# r� �� '1 1'I� Submit Form a d Form 10-403(Revise/-C1--V2012) Appr d I niff from the d e f approval. _gffachmegts1n Dupe�tctate i 6 2a--\ �priu�+�MS �IJL 1 Well Work Prognosis Well: M-31B Date: 07/07/14 Well Name: M-31B API Number: 50-733-20457-02 Current Status: ESP Producer Leg: B-1 _ Estimated Start Date: 08/01/14 Rig: Steelhead Rig#51 Reg.Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Juanita Lovett(8332) Permit to Drill Number: 212-149 First Call Engineer: Ted Kramer (907)-777-8420 (0) (985)-867-0665 (M) Second Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) AFE Number: Budgeted Cost: Current Bottom Hole Pressure: — 2,800 psi @ 7,780' TVD 0.36 psi/ft (ESP Intake) Maximum Expected BHP: — 2,800 psi @ 7,780' TVD (No new perfs being added) Max. Anticipated Surface Pressure: 0 psi (Using 0.435 psi/ft.to surface) Brief Well Summary M-31B is a G / Hemlock Producer completed with an ESP. The ESP experienced a down-hole electrical failure July 2014.We plan to pull and replace the ESP. No perforations will be added. Procedure: 1. MIRU Rig. 2. Attempt to pump through ESP to circulate hydrocarbon off the well to production. If necessary, RU e-line and RIH to+/-8,750' and punch tubing. 3. ND Wellhead, NU BOP and test to 250psi low/2,500psi high. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 4. POOH with tubing string and ESP pump laying down the same. 5. PU, RIH with ESP completion. 6. Land ESP with the bottom of the assembly at+/-8,900'. 7. ND BOP, NU wellhead and test. 8. Turn well over to production. 9. RDMO Rig. Attachments: 1. Current Well Schematic 2. Current Wellhead Diagram 3. Proposed Well Schematic 4. Proposed Wellhead Diagram 5. BOP Drawing Steelhead Platform 14Well #: M-31B Hilrnrp Alaska,LLC SCHEMATIC Completed: 2/20/2013 PTD#: 212-149 API#: 50-733-20457-02-00 TBG Hanger 74.5'below RKB CASING DETAIL ( SIZE WT GRADE CONN ID TOP BTM. + 2s^ 34" Surf 480' 16" 26 267 397#thru Drill Quip Surf 979' • A 16" 75 K-55 BTC 15.12 Surf 1345' 13-3/8" 61&68 K-55 BTC 12.42 Surf 3722' 13-iia 9-5/8"Tieback 47# L-80 DWC/C 8.681 Surf 1316' 10-3/4"Liner hgr 65.7# L-80 BTC 9.5 1316' 1348' 9-5/8"Liner 47# L-80 DWC/C 8.681 1348' 9,107' 7"liner 26# L-80 VA HT OP 6.276 8919' 11,548' TUBING DETAIL 4-1/2" 12.6# L-80 IBT-M Surf 8,768' TUBING JEWELRY NO Depth Length ID OD Item 1 8,768' 0.69' _ Head Bolt On Discharge 2 8,769' 48.6' _ Pump(x3)—J12000N C-CT 32 STG 675/675110 3 8,818' 1.12' _ Intake pp 4 8,837' 33.93' Motor-738,E180 Dominator RK-S,CS,M-TRM 12 11 5 8,875' 105.44 Bottom of ESP 3 4& I 5 CASING JEWELRY r NO Depth Length ID OD Item B A 1,316' Baker Flex-Lock Liner hanger&Baker HRD-E ZXP liner top packer(PKR INTENTIONALLY NOT SET!!I) 1 k. O B 8,919' 7"Liner top I C 8,925' Baker JM-ZXP Liner Top Packer ,.if ' D D 9,107' 9-5/8"Casing Shoe PERFORATION DETAIL Top Zone (MD) Btm(MD) Top(TVD) Btm(TVD) Length(MD) SPF Date ' -' G1 9,361' 9,390' 8725 8754 29' 5 2-20-2013 G2 9,425' 9,440' 8786 8801 15' 5 2-20-2013 G3 9,490' _ 9,526' 8843 8879 36' 5 2-23-2013 G4 9,535' 9,600' 8885 8950 65' 5 2-23-2013 G5 9674 9710 9003 9036 36' 5 2-23-2013 • G5 9720 9739 9030 9049 19' 5 2-23-2013 . HK1 9950 9985 9208 9243 35' 5 2-23-2013 HK2 10003 _ 10130 9251 9329 127' 5 2-23-2013 HK3-4 10192 10600 9362 _ 9542 408' 5 2-23-2013 HK5 10642 10834 9556 _ 9617 192' 5 2-23-2013 HK5 10866 11030 9628 9680 164' 5 2-23-2013 HK6 11083 11165 9697 9722 82' 5 2-23-2013 HK6 11195 11270 9731 9755 75' 5 2-23-2013 ra HK7 11360 11396 9785 9798 36' 5 2-23-2013 PBTD:11,450 MD/9,818'TVD TD:11,550'MD/9,854'TVD REVISED:07/07/2014 REVISED BY:JLL . . Steelhead Platform Well #: M-31B Hilcorp Alaska,LLC PROPOSED Completed: 2/20/2013 PTD#: 212-149 API#: 50-733-20457-02-00 TBG Hanger 74.5'below RKB CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. \ X AI t[Is6 26" 34" Surf 480' 26" 267 thru 397# Drill Quip Surf 979' • A 16' 16" 75 K-55 BTC 15.12 Surf 1345' 13-3/8" 61&68 K-55 BTC 12.42 Surf 3722' 9-5/8"Tieback 47# L-80 DWC/C 8.681 Surf 1316' 13-3i8 10-3/4"Liner hgr 65.7# L-80 BTC 9.5 1316' 1348' 9-5/8"Liner 47# L-80 DWC/C 8.681 1348' 9,107' 7"liner 26# L-80 VA HT OP 6.276 8919' 11,548' TUBING DETAIL / 4-1/2" 12.6# L-80 IBT-M Surf ±8,768' TUBING JEWELRY NO Depth Length ID OD Item 1 ±8,875' Bottom of ESP U hi 1 CASING JEWELRY NO Depth Length ID OD Item Baker Flex-Lock Liner hanger&Baker HRD-E ZXP liner top packer(PKR p� r B A 1,316' INTENTIONALLY NOT SET!!!) 7 B 8,919' 7"Liner top Pf i O C 8,925' BakerJM-ZXP Liner Top Packer I: D D 9,107' 9-5/8"Casing Shoe PERFORATION DETAIL Top Zone (MD) Btm(MD) Top(TVD) Btm(TVD) Length(MD) SPF Date G1 9,361' 9,390' 8725 8754 29' 5 2-20-2013 - G2 9,425' 9,440' 8786 8801 15' 5 2-20-2013 G3 9,490' 9,526' 8843 8879 36' 5 2-23-2013 G4 9,535' 9,600' 8885 8950 65' 5 2-23-2013 G5 9674 9710 9003 9036 36' 5 2-23-2013 G5 9720 9739 9030 9049 19' 5 2-23-2013 HK1 9950 9985 9208 9243 35' 5 2-23-2013 HK2 10003 10130 9251 9329 127' 5 2-23-2013 HK3-4 10192 10600 9362 9542 408' 5 _ 2-23-2013 HK5 10642 10834 9556 9617 192' 5 2-23-2013 HK5 10866 11030 9628 9680 164' 5 2-23-2013 HK6 11083 11165 9697 9722 82' 5 2-23-2013 . HK6 11195 11270 9731 9755 75' 5 2-23-2013 idi HK7 11360 11396 9785 9798 36' 5 2-23-2013 PBTD:11,450 MD/9,818'ND TD:11,550'MD/9,854'TVD REVISED:07/07/2014 REVISED BY:JLL Steel. Ad Platform 16 3/4 5M BOP (Oil Leg) M-31B IIikom.».k..ILIA: 07/07/2014 s.s 4 A 01 5 x ,, 20-'pipe/or air boat flanges *4 I`7�§ 9.43' 14 Mmnxw refi- .ltl Ill mitt 5.10' Ilytl ril Variabl es3%.7 .-4 — w..p.ae.z,ep,. _ 5.46' Blind --IC — op tomem-s ' III III i r i i t i i s r III 1,1111 III III .31.11=i CCRon both s des ,• a ',,, 5 IIIII II .Q 3.00' 4%rams-- 3.58' isi iti liwwnnneiital DSA 16%10M%16%SM .66' iti itit ori t 1.85' • - aewtionnt Riser,16%5M API hub% 163/410M FE UpperWelheaclfrztoffigs.GratIng 5.34' Clamp above floor • Riser,16%5M FE%16%5M API hub 111111, 3iil il;C r 8.17 e. ■L^1 vf IA) I Oft Ian. - •,.. Steeta._ad Platform M-31B Current 07/07/2014 Hikvtrp Alaeka.l,IA. Steelhead Platform Tbg hanger,FMC-TC-1A-EN- M-3113 EC-CCL,16%BMX 415 I8T 26 X16 X 133/8 X 95/8 X lift and susp,w/4"Type H 41/2 BPV profile,2-3/8 continuous control line BHTA,Bowen, 4 1/16 5M FE X 7-514 Bowen top rValve,Swab,WKM-M, pi ,^".IP• 41/165M FE,HWO,DD $1.1 IMO 111 S) _I Valve,upper master,SSV, 111111 Ng 41/165M FE,w/15"Safeco C rat/ v operator,EE �; A I� Valve,wing,WKM-M, srr• � 41/165M FE,HWO,DD J > , , " BMW Valve,Master,WKM-M, 41/16 5M FE,HWO,DD ,a . iO q 7f: IAdapter,FMC A-3-EC, 16%SM X 41/16 SM, prepped for BIW electro sub, X2 control line _ 2-'/,rpt continuous control line exits aII .Nr' : �r:_ NE Tubing head,FMC-TC-60,spec for I A unihead,16%5M FE top X 16%5M stdd bottom,w/2-21/165M 550I9 __ '� Vii. Umhead,FMC Type 2,16%5M Valve,FMC-120, FE top X 21%2M FMC speedlock 2 1/16 5M FE,HWO,AA bottom,w/4-2 1/16 5M SSO , SI 4i!:;1i. * III oil= m /om _ I I61 t U - Adapter spool,FMC A 5-5 30"MSS stdd bottom X 21'/.2M FMC F speedlock top,w/2-2'LPO ISI , �COtT 41 Starting head,FMC,weld MSS '� �� FE head,FMC, 30" r. IN ■1 26" 16" 1133/8' 9 5/8" 4 1/2 Debra Oudean Hilcorp Alaska, LLC GeoTech II 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8337 Itdr Grp u: k;.i.t Fax: 907 777-8510 RE �'�° 1 j E-mail: doudean@hilcorp.com GC* 6 s. APR 19 20). DATE 4/17/2013 pp GC C To: Alaska Oil & Gas Conservation Commission Makana Bender, Natural Resource Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL M-31B PRINTS Vision Resistivity 2in/100ft MD RM Composite log Vision Resistivity 5in/100ft MD RM Composite log Vision Resistivity 2in/100ft TVD RM Composite log Vision Resistivity 5in/100ft TVD RM Composite log CD: Final Well Data _ EOW Letter, PDF Logs Surveys ASCII Data/ DLIS Data 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: II Debra Oudean Hilcorp Alaska, LL. GeoTech II 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8337 If trnrp Ui.l.a.Lf[ Fax: 907 777-8510 E-mail: doudean@hilcorp.com DATE 4/17/2013 To: AOGCC RECEIVED Makana Bender 333 W. 7th Ave. Ste#100 APR 19 2013 Anchorage, AK 99501 DATA TRANSMITTAL AOGCC M-31B Prints: M-31B Formation Log MD M-31B Formation Log TVD M-31B LWD Combo Log MD M-31B LWD Combo Log TVD M-31B Gas Ratio Log MD M-31B Gas Ratio Log TVD M-31B Drilling Dynamics Log MD M-31B Drilling Dynamics Log TVD Final Well Report 1 11 CD: Final Well Data -- a 1 - DAILY REPORTS See CD DML DATA See CD FINAL WELL REPORT M-31B Final Well Report.doc M-31B Final Well Report.pdf LAS FILE M-31B.las LOG PDF FILES M-31B Formation Log MD.pdf M-31B Formation Log TVD.pdf M-31B LWD Combo Log MD.pdf M-31B LWD Combo Log TVD.pdf M-31B Gas Ratio Log MD.pdf M-31B Gas Ratio Log TVD.pdf M-31B Drilling Dynamics MD.pdf M-31B Drilling Dynamics TVD.pdf 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 7 z— l3 c STATE OF ALASKA ALAbrvk OIL AND GAS CONSERVATION COMMi.,o1ON WELL COMPLETION OR RECOMPLETION REPORT AND LOG • ha.Well Status: Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ lb.Well Class: 20MC 25.105 20AAC 25.110 Development 0 Exploratory ❑ GINJ ❑ WINJ ❑ WAG ❑ WDSPL ❑ No.of Completions: , _ -ervice ❑ Stratigraphic Test ❑ 2.Operator Name: 5. Date Comp.,Su or 8 2. Permit to Drill Number: Hilcorp Alaska, LLC Aband : 22013 212-149 13.Address: 6.Date Spudded: 13.API Number: 3800 Centerpoint Dr.,Anchorage AK,99524 1/10/2013 50-733-20457-02-00 4a. Location of Well(Governmental Section): 7. Date TD Reached: 14.Well Name and Number: Surface: 970'FNL,516'FWL,Sec 33,T9N,R13W,S 2/8/2013 Trading Bay Unit M-31B Top of Productive Horizon: 8.KB(ft above MSL): \ 160' 15. Field/Pool(s): 988'FNL, 1703'FWL,Sec 33,T9N,R13W,SM,AK GL(ft above MSL): 0' McArthur River Field/ Total Depth: 9.Plug Back Depth(MD+TVD): G Oil&Hemlock Pool 2525'FSL, 1739'FWL,Sec 33,T9N,R13W,SM,AK 11,450'MD/9,818TVD 4b. Location of Well(State Base Plane Coordinates, NAD 27): 10.Total Depth(MD+TVD): 16. Property Designation: Surface: x- 214140 WIy- 2499532 Zone- 4 11,550'MD/9,854"TVD ADL0018730 TPI: ,1- 1321 lar„ y- 2499485 Zone- 4 11. SSSV Depth(MD+TVD): 17. Land Use Permit: Total Dept Y' y- 2497718 Zone- 4 N/A N/A 18. Directional Survey: Yes 0 No ❑ 19.Water Depth,if Offshore: 20.Thickness of Permafrost MD/'TVD: (Submit electronic and printed information per 20 AAC 25.050) 183' (ft MSL) N/A 3.2 G 13 121. Logs Obtained(List all logs here and submit electronic and printed inform . C25.071). 22.Re-drill/Lateral Top�endow MlrrVD: i Gamma Ray,Resistivity, Neu-Density,Porosity,Sonic,CBL(7"(liner .''') .3.71,0"3388 ' vial-00 123- CASING, LINER AND CEMENTING RECORD WT.PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT .,ASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORDFr. PULLED 26" 267 to 397 Surf 979' Surf 979' - - - _ 16" 75 K-55 Surf 1,345' Surf 1,344' - 2029 sx 113-3,8" 61 to 68 K-55 Surf 3,722 Surf 3,524' 17-1/2" 2200 sx 9-5/8" 47 L-80 Surf 1,316' Surf 1,315' 10-3/4" 65.7 L-80 1,316' 1,348' 1,315' 1,347' _ �� Ls' '-v k1:rt. y� C/►T 9-5/8" 47 L-80 I 1, 48' 9,107' 1,347' 8,488' 12-1/4" 1208 sx 7" 26 L-80 8,91.9' 11,548' 8,312' 9,853' 8/1/2002 742 sx 24.Open to production or injection'? Yes E No ❑ 25. TUBING RECORD If Yes, list each interval open(MD+TVD of To 1�B E'r P D SIZE DEPTH SET(MD) PACKER SET(MD/TVD) i!Size and Number): ]GG 4-1/2" 8,860' N/A/N/A 1 1\ AFri E `, 2013 I 26. ACID, FRACTURE,CEMENT SQUEEZE, ETC. I A ^GCC Was hydraulic fracturing used during completion? Yes❑ No Q �� (- DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED See attached schematic rgr ir) I �� 127. PRODUCTION TEST rDate First Production: Method of Operation(Flowing,gas lift,etc.): 2/26/2013 ESP Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 3/11/2013 1/24/1900 Test Period 511 232 12,263 N/A 454-1 Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 112 46 24-Hour Rate 511 232 12,263 33.1 28. CORE DATA Conventional Core(s)Acquired? Yes ❑ No❑., Sidewall Cores Acquired? Yes ❑ No 0 If Yes to either question,list formations and intervals cored(MD+TVD of top and bottom of each),and summarize lithology and presence of oil,gas or water (submit separate sheets with this form,if needed).Submit detailed descriptions,core chips,photographs and laboratory analytical results per 20 AAC 25.071. RBDMS MAR 2 6 7O , - oriV Form 10-407 Revised 10/2012 CONTINUED ON REVERSE Submit original only G 9L 41. 7-13 /� 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? ❑ Yes H No If yes,list intervals and formations tested, briefly summarizing test results.Attach separate sheets to this form,if needed, Permafrost-Top and submit detailed test information per 20 AAC 25.071. Permafrost-Base G1T 9,388' 8,721' HKT 9,979' 9,210' HK3T 10,233' 9,370' HK7 11,368' 9,780' Formation at total depth: HK7 31. List of Attachments: Schematic,Daily Drilling Summary,Definitive Directional Survey,MW vs Depth, Days vs Depth,(2)Casing Tallies,(2)Csg and Cmt reports 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Luke Keller Email: Ikeller@hilcorp.corn Printed Name: Luke Keller Title: Drilling Engineer Signature: Phone: 907-777-8395 Date: 3/22/2013 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases 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. Item 1 b: Classification of Service wells: Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection,Observation,or Other.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 4b: TPI(Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and ND for the top and base of permafrost in Box 28. Item 23: Attached supplemental records for this well 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. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. 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. Form 10-407 Revised 10/2012 Steelhead Platform 14 WELL#: M-31B Hilcorp Alaska,LLC SCHEMATIC W B D 2/20/2013 PTD#: 212-149 AP1#: 50-733-20457-02-00 TBG Hanger 74.5'below RKB _ CASING DETAIL « ° 28" SIZE WT GRADE CONN ID TOP BTM. v t_ .. 16" 26 267 397#thru Drill Quip Surf 979' d��"' ,L 16" 75 K-55 BTC 15.12 Surf 1345' �f" 13-3/8" 61&68 K-55 BTC 12.42 Surf 3722' til �K 9-5/8"Tieback 47# L-80 DWC/C 8.681 Surf 1316' �13-318" �� 10-3/4"Liner hgr 65.7# L-80 BTC 9.5 1316' 1348' 9-5/8"Liner 47# L-80 DWC/C 8.681 1348' 9,107' 7"liner 26# L-80 VA HC OP 6.276 8919' 11,548' TUBING DETAIL 4-1/2" 12.6# L-80 IBT-M Surf 8,874' JEWELRY NO Depth Length ID OD Item 1 1,316' Baker Flex-Lock Liner hanger&Baker HRD-E ZXP liner top packer(PKR INTENTIONALLY NOTSETI!!) .,---"�.., 2 2 8,767' 0.69' Bolt On Discharge Pump assy 3 3 8,768' 0.76' Discharge Pressure sub assy 4 8,874' 105.44 REDA ESP assy 4 5 8,919' 7"Liner top 6 8,925' Baker JM-ZXP Liner Top Packer 7 9,107' 9-5/8"Casing Shoe 4 -•qfL 1 opt PERFORATION DETAIL 5 '� Top *„ Zone (MD) Btm(MD) Top(ND) Btm(TVD) Length(MD) SPF Date 1 re'• 6 G1 9,361' 9,390' 8725 8754 29' 5 2-20-2013 $ .' G2 9,425' 9,440' 8786 8801 15' _ 5 2-20-2013 iE 7 1 0,' G3 9,490' 9,526' 8843 8879 36' 5 2-23-2013 V, G4 9,535' 9,600' 8885 8950 65' 5 2-23-2013 LI G5 9674 _ 9710 9003 9036 36' 5 2-23-2013 41 G5 9720 _ 9739 9030 9049 19' 5 2-23-2013 SA HK1 9950 9985 9208 9243 35' 5 2-23-2013 , . i2 HK2 10003 10130 9251 9329 127' 5 2-23-2013 HK3-4 10192 10600 9362 9542 408' 5 2-23-2013 HK5 10642 10834 9556 9617 192' 5 2-23-2013 HK5 10866 11030 9628 9680 164' 5 2-23-2013 _HK6 11083 11165 9697 9722 82' 5 2-23-2013 HK6 11195 11270 9731 9755 75' 5 2-23-2013 HK7 11360 11396 9785 9798 36' 5 2-23-2013 1 rk ` ril '7” PBTD:11,450 MD/9,818'TVD TD:11,550'MD/9,854'ND REVISED:3/22/2013 REVISED BY:LEK . ‘ . Hilcorp Alaska LLC Weekly Operations Summary •'.ell Name API Number Well Permit Number Start Date End Date M-31B Redrill 50-733-20457-01-00 212-071 1/9/13 `,ally Operations f amr 2./10/2013 -Thursday -rotary Drill f/4,130't/4,260', 130' at 32.5 FPH, 760 GPM, 2,140 Psi, 80 RPM, 8K TO, 20-25K WOB. Slide Drill f/4,260' t/ 4,285', 25' at 25 FPH, 760 GPM, 2,140 Psi 25K WOB. Rotary Drill f/4,285't/4,385', 100' at 67 FPH, 800 GPM, 2,320 Psi, 80 PPM, 8K TQ, 20-25K WOB. Slide Drill f/4,385't/4,409', 24' at 24 FPH, 800 GPM, 2,385 Psi, 20K WOB. Rotate Drill f/4,409' t/4,489', 80 RPM, 7K torq, 800 gpm, 2,400 psi, 25K WOB. Slide drill 4,489'-4,505', 25K WOB, 800 gpm, 2,450 psi. Rotary drill 4,505' -4,575'. 80 rpm, 7K torq, 800 gpm, 2,350 psi, 15K WOB. Slide drill 4,575'-4,596', 16K WOB, 800 gpm, 2,400 psi, 25K WOB. Rotary drill 4,596' -4,660', 80 rpm, 8K torq, 20K WOB, 800 gpm, 2,400 psi. Slide drill 4,660' -4,682', 30K WOB, 800 gpm, 2,400 psi. Rotary drill 4,682' -4,747', 80 rpm, 7.5K tprq, 800 gpm, 2,400 psi, 25K WOB. Slide drill 4,747' -4,772', 25K WOB, 800 gpm, 2,400 psi. Rotary drill 4,772' -4,862', 25K WOB, 80 rpm, 800 gpm, 2,450 psi. Slide drill 4,862' -4,876', 30K WOB, 800 gpm, 2,450 psi. Rotary drill 4,876' -4,900', 30K WOB, 800 gpm, 2,500 psi. Slide drill 4,900' -4,935', 30K WOB, 800 gpm, 2,450 psi. Stuck on bottom with full circulation, rotate stalled @ 20K.Jar one time at 280K. Pipe free. Rotate and reciprocate 4,890' -4,935' several times. Rotate drill 4,935' - 5,000', 25K WOB, 800 gpm, 2,450 psi, 7K torq. Daily losses to well 7 bbls. Total fluid loss to well 857 bbls. Daily metal retrieved 75 lbs.Total metal recovered 1,711 lbs. :1/11/2013- Friday I ''tiotary Drill f/5,000' t/5,005', 800 GPM, 2500 Psi, 80 RPM, 25k WOB, 7k TQ. Slide Drill f/5,005' t/5,030', 800 GPM, 2500 11=si, 25k WOB. Rotary Drill f/5,030' t/5,087', 800 GPM, 2,500 Psi, 80 RPM, 25k WOB, 8k TQ. Slide Drill f/5,087' t/5,121', i_00 GPM, 2,600 Psi, 25k WOB. Rotary Drill f/5,121't/5,142', 800 GPM,2600 Psi, 30k WOB, 80 RPM, 8k TQ. Pump 32 bbl high sweep, circulate hole clean while rotating and recriprocating drill string. POH f/5,142't/4,760' on elevators. Pump out of le hole f/4,760' t/4,510', [tight spots 4,760,4,740, 4,695, 4,680 and 4,580]. Pull on elevators f/4,510', t/4,250'. Pump out cr the hole f/4,250' t/3,986' [tight spots 4,250, 4,197, 4,154 and 4,051]. Had two spots where we had to pump and 1 ackream through at 4,986 and 4,940. Continue pumping into the shoe at 3,722' with no bad tight spots. Service draw yorks. Pump dry job-blow down TD, cont POOH. Std back BHA break off and insp bit grade 1-1-7. LD and down load MWD !hart tools mud motor. Clean floor, move new BHA to floor monitor well. PU rotary steering tools. Production turbine p\kent down while waiting on production power serviced TD. Crown-Draw works-Baylor brake cut 80' drill line. Production Ir'ower back up. Power off 0030-0430 4 hrs. Finish cutting 80' drill line. Finish MU BHA. Fluid loss to well today 0 bbls-Total loss to well 10 bbls, metal recovered from well today 37 lbs-Total recovered from well 101 lbs. 1/12/2013-Saturday I' Test rotary steerable tool. Finish picking up Schlumberger smart tools. RIH to 1st jt of HWDP, test MWD. RIH to shoe and fill ripe. Attempt to RIH with no pump. Took wt at 3,730' [8' below shoe]. Pump thru tight spot and work down to 3,770'. Continue pumping in hole and tag at 3,837' [Same depth as csg cut off]. Made several attempts to get by but couldnt get past. POH but pulled into tight spots at 3,773' and 3,769'. Had to pump and backream thru the spots to get back up in the shoe at 3,722'. Pump pill and POH-to Schlumberger iron. Stand back Schlumberger tools, PU hole opener for clean out run. RIH with hole opener to csg shoe. Tag at 3,753'. Wash 3,753-3,758. Ream 3,758-3,834. Wash/ream 3,841-3,850. Ream 3,914-3,920. Ream 4,103-4,119. Wash 4,119-4,230-10k trq at 4,157. Ream 4,295-4,304, 8k trq. Wash 4,333-4,620, 9k trq at L1,393 &4,620. Ream 4,722-5,144, 8k trq at 4,735-40/4,867-75/4,907-12/4,980-91/4,997-5,000/tag btm at 5,142'. CBU/clean hole x 2-sml-med size coal at shakers. POOH to PU rotary steering BHA. No problem pulling thru 13-3/8" shoe at 3,722'. Run back thru and saw a slight bobble. Work back thru no problems. Pump dry job. Continue POOH. Fluid loss to well today 0 bbls-Total loss to well 12 bbls. Metal recovered from well today 12 lbs-Total recovered from well 163 lbs. I L 1.!13/2013-Sunday Finish POH with hole opener and lay down same. PU Schlumberger tools out of derrick and make up bit. Test tools. Trip in IBole to 1st std of HWDP and test MWD. RIH to shoe at 3,722'. Fill pipe and establish parameters. RIH pumping and start ia king wt at 3,837'. Ream f/3,835' t/1855'. RIH on elevators t/5,069'. Circ and get Schlumberger tools in sync. Wash and ream f/5,069't/5,142', 715 GPM 1850 Psi, 80 RPM. Directional Driil 12-1/4" hole w/rotary steerable f/5,142't/5,642'. When in coal, pu 10'work back through backram each std. Monitor torq add 2 ppb steel seal 0.5%torque trim torque increased to 11k-12k. CBU pump survey SPR at 30/130-40/220. Short trip on elevators to 5,075'. Work thru bobble spots r.t 5,280-7075,165-70' 10k overpu"l. RBIH - no hole problems. Directional drill f/5,642' to 5,853'. Fluid loss to well today 0 .ibis-Total loss to well 10 bbls- Metal recovered from well today 15 lbs-Total recovered 178 lbs. 1/14/2013 - Monday Directional drill 12-1/4" hole f/5,853' t/6,202', 349', 50 FPH, 800 GPM, 2600 Psi, 13.5-14.4k TQ,120 R [Pumped high vis sweep but didnt see extra any cuttings]. Circ bottoms up. Short trip t/5,630'. Hole in good shape. Directional drill 12-1/4" hole f/6,202't/6,397', 195', 43 FPH, 800 GPM, 2620 Psi, 14-15k TQ, 120 RPM, Gas high=320 units. Directional drill 12-1/4" hole f/6,397' t/6,617' 36 FPH-800 GPM-2,825 PSI-15/16kTR, 120 RPM-220 GAS. Directional drill f/6,617'to 6,771', 50 fph- IF00 gpm-2,800 psi-120 rpm-16k trq-90 gas. CBU short trip to 6,200'. RBIH. Directional drilling from 6,771' to 6,870'-60fph- 1f00gpm-2830psi-120rpm-17k trq. Fluid loss to well today 0 bbls-Total loss to well 10 bbls. Metal recovered from well today . lbs-Total recovered from well 187 lbs. [... 1/15/2013-Tuesday Directional drill 12-1/4" hole f/6,870' t/7,222', 352', 59 FPH, 18-19K TQ, 800, GPM, 2890 Psi, 140 RPM 12K WOB. Gas Units High 390. Directional drill 12-1/4" hole f/7,222' t/7,340', 118', 47 FPH, 793 GPM, 2,900, Psi, 130 RPM, 1850-1950k TQ, 5- 112K WOB. Gas Units High 250. Get SPR and circ bottoms up. Short trip to 6,767'. Directional drill 12-1/4" hole f/7,340' I t/7,415'. Directional drill f/7,415'to 7,723'-47 FPH 21k TRQ-800 GPM-2950 PSI-25 GAS. Directional drill f/7,723' to :9111(188') 130 RPM-31 FPH-18k-25k TRQ, 800 GPM-3000 PSI. Fluid loss to well today 0 bbls-Total fluid loss to well 10 Ibbls. Metal recovered from well today 3 lbs-Total metal recovered from well 190 lbs. 1 Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date M-31B Redrill 50-733-20457-01-00 212-071 1/9/13 Daily Operations: 1/16/2013 -Wednesday Pump 40 bbl sweep and circ hole clean, got back a lot of fines. Short trip to 7,148'. Had two spots, at 7,480' pulled 30k over, t 7,191' pulled 40K over. Both spots cleaned up after working through. Directional drill 12-1/4" hole f/7,911' t/8,008', 25 FPH, 800 GPM, 2950 Psi. Pump 30 bbl torque trim sweep, noticed loss in pump pressure. Check pumps at 30 spm and both pumps were low on pressure. Check all surf equip, shut pumps in and test to 2,000 psi. All surface equip good. POOH looking for washout, found washout 1' above tool joint at 4,187'. Change out jt and POOH to shoe, [Hole was in good shape]. Service TD, Drwks, Blocks, and crown. Surface test Schlumberger equip. RIH with Rotary steerable and ream thru tight kpot from 6,960'-6,990'. RIH wash from 7,9131-8,008'. Directional drilling f/8,008' -8,3201(312') 36 fph-130 rpm-19k-27k trq- 15k wob- 160 gpm-2930 psi. Fluid loss to well today 0 bbls-Total fluid loss to well 10 bbls. Metal recovered from well today lbs-Total metal recovered from well 192 lbs. I/17/2013 -Thursday Directional drill 12-1/4" hole f/8,320' t/8,550', 230', 38 FPH, 800 GPM, 3,000, Psi, 130 RPM, 22 to 28K TO, 10 to 15k WOB, High for gas = 320 units. Directional drill 12-1/4" hole f/8,550 t/8,703', 153', 30 FPH, 800 GPM, 3,000; Psi, 135 RPM, 22 to 28K. Directional drill 12-1/4" hole f/8,703' - 8,761', 61'-30 fph-800 gpm-3,025 psi-, 140 rpm-26k trq-puw 325k-sow 205k- rotwt 250k. Survey-circ/clean hole. POOH for short trip to 7,900' -RBIH no problems. Directional drill f/8,761'-8,975-214' (pump 30 bbl torq trim pill at 8,920'- ; trq at 25k-28k) 25 fph-120 rpm-25k-28k trq-190 gpm-3010 psi. Notified AOGCC at 1745 hrs today of upcoming BOPE test scheduled for 1/19/13. Total fluid loss to well today 0 bbls-Total loss to well 192 bbls. Metal recovered from well today 0 lbs-Total metal recovered from well 192 bbls. /18/2013 - Friday I-Directional drill 12-1/4" hole f/8,975' t/9,031', 56', 29 FPH, 800 GPM, 3,000 Psi, 22 to 30K TQ, 125 RPM, 8 to15K WOB, [lost swab on #2 mud pump]. Change swab in #2 mud pump. Directional drill 12-1/4" hole f/9,031' t/9,128', 97', 16 FPH, 800 GPM, 3,050, Psi, 22 to 30K TQ, 130 RPM, 6 to15 WOB. Directional drill 12-1/4" hole f/9,128' t/9,1751(471)16 FPH, 800 GPM, =.,050, Psi, 22 to 30K TQ, 130 RPM,6 to15 WOB. Change swab in # 1 pump. Directional drill 12-1/4" hole f/9,175'to 9,425'( target depth picked.with Anc Drilling Eng and Geologist. 38 FPH-800 GPM- 3010 Psi-22 to 30K trq-110 rpm, 6 to15k trq. CBU clean hole, short trip to 8,700'-from 9,425' to 9,330'pull to 400k-kelly up backream 9,300'to 8,800'pulled at 350k-370k 1:'31H to 9,424'-no problems. Circ/cond hole pump 30 bbl hi-vis pill. 1/19/2013 -Saturday Finish circ hole clean. POH 15 stds, pump dry job. Continue POH [work through spots at 7,136', 7,060', and 6,795'] (Gas alarms tested-for BOPE test-no failures), LD Smart Tools BHA. Flush and drain BOPE stack, pull wear bushing. PU test jt, set test plug, fill stack with water-bleed air from stack/lines. Test BOPE as per HAK, Kuukpik and AOGCC procedures. Hydril 250/2,500 psi rams valves, choke valves 250/4,000 psi. Test witnessed by AOGCC insp Lou Grimaldi. Pull test plug install wear bushing LD test equip. MU Niadd pass logging BHA. Fluid loss to well today 0 bbls-Total fluid loss to well 10 bbls. Metal recovered from well today 10 lbs-Total metal from well 203 lbs. /20/2013 -Sunday UIH with Schlumberger logging tools to shoe. Service rig. RIH to 7,250'. Start installing non-rotating rubbers on every jt and continue running in hole to 9,376',{Put on 100 non-rotating rubbers]. Wash and ream f/9,376' t/9,425' while logging for tie in. Pump 30 bbl high vis sweep and circ hole clean, got back a lot of coal even before sweep came back. Start our Mad Pass 'egging while POH at 350 ft/hr, 100 RPM, 800 GPM f/9,425' t/8,323' hit tight spot. Unable to rotate thru area f/8,323'-8,338', cnn pull thru w/o rotating. All data is good-except density is questionable. Cont MAD pass logging while POH f/8,323'-7,350' at 280/350 ft/hr-80/100 rpm-800 gpm-2,250 psi 2,250 psi-18k-30k trq-(ream thru tight spots f/7,615'-7,607'/7,594'-7,590'/ ;7,5651-7,560'/7,545'-7,541'). Fluid loss to well today 0 bbls-Total fluid loss to well 10 bbls. Metal recovered from well today 1 lbs-Total metal recovered from well 204 lbs. •.;/21/2013 - Monday Cont POH Mad Pass Logging f/7,350' t/ 3,720', 800 gpm, 100 RPM. Cont POOH with MAD pass f/5,285'-3,710', 350 fph-800 gpm-1800 psi-100 rpm. A lot of coal throughout the day-very heavy coal f/5,300'-4,700' 2" on shakers- then slowed down to fill screens up to 4,000'. Slowed rpm to 50 pulling thru shoe at 3,722'. CBU pump down link to MAD tools- pump 35 bbl hi sweep-coal cuttings light to med on shakers-CBU again well clean. POOH. Fluid loss from well today 0 bbls. Total fluid loss to well 10 bbls. Metal recovered from well today 12 lbs -Total recovered from well 236 lbs. 1122/2013 -Tuesday OH with logging tools to BHA. Claar floor and remove source. Lay down schlumberger tools. Pull wear ring, flush stack. Rig !,1p Watherford CRT to run 9-5/8 csg& p/up run &chk float tract. Seepage loss @ 2 bph. Run 9-5/8" 47# DWC/C csg filling every (3)jts &toping off every(6)jts. Installing TRC legacy double bow spring centerlizers every 3 jt over coupling for 49 Total. Circ Btm/up @ 3,713'-50 spm-200 gpm-250 psi-220k puw-200 sow. Test rotate CRT at 25 rpm and 7k trq prior to (craving shoe-filling every jt in OH. Cont RIH with 9-5/8" csg to 4,200'. Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date M-31B Redrill 50-733-20457-01-00 212-071 1/9/13 Daily Operations: 1/23/2013 -Wednesday Continue run 9-5/8" csg f/4,200' t/5,014' (push &work thru multi spots). Unable to pass 5,014', wash & ream t/5,044' @ 25 rpm 3 bpm @ 260 psi&24k tq. Chg/out power tongs. Continue RIH t/6,687' (Push &work thru multi spots). Wash & ream f/6,687't/6,703'. Continue RIH t/6,985' (push &work thru multi spots). Wash &ream 6,985't/6,987'. L/dn jt chg out fill tool pack-off. Knock pipe loose, continue wash ream f/6,987't/7,540'. Wash & ream f/7,540'-7,560'-CBU 5 bpm-25 rpm &clean hole. Medium coal cuttings at shaker. Continue RIH f/7,560'-7,835'; CBU at 7,834'-60' spm-400 psi-clean. Wash/ream f/7,834'-8,045'-tight spot. Continue RIH f/8,045'-9,000'. 1/24/2013 -Thursday Continue RIH with csg f/9,000'to 9,104'-pipe stopped at 9,104'. Ran 230 jts 9-5/8"-47 lb-L-80 DWC/C csg-including 1 reamer shoe, 1 float collar-btm 3 jts bakerlocked-42 dbl bow spring centralizers-4 lock rings-(no stage tool ran). Work Pipe t/550k up&all pipe wt dn/30k torque with no pipe movment/circ Full round w/full circ&light fine coal in returns f/4-6 bpm & no pack-off issues/+-7 bph loss rate. Disscuss options w/town. RU to run Cmt/Rid off CRT& blow dn TDS&CRT. Clean- clear rig floor. Install cmt head and cmt lines. Circ csg at 2bpm/160psi-3 bpm/180psi-6 bpm/300psi. PJSM w/rig crews/cmtrs. PT cmt pumps/lines 1,000/4,500 psi- Rig pump on line and pump 73 bbls 10.5 ppg Mud. Push II at 4 bpm-5_ bbls 9.6 ppg mud. Drop btm plug-on line w/cmt pump-pump 383 bbls LiteCrete lead cmt at 12.0 ppg at 4 bpm/300 psi-82. bbls EasyBlok,tail cmt at 15.8 ppg at 4 bpm-300 psi-5 bbls FIW at 8.43 ppg at 4 bpm. Rig pump on line and displaced cmt with 9.6 ppg mud at 8 bpm 220 psi-at 187 bbls away started loosing returns-drop rate to 4 bpm-lost total returns with 200 bbls away o psi-drop rate to 1 bpm for total 65 bbls cmt out shoe-pump pres started increasing to 3,000 psi. SD rig pump switch to cmt pump and increased pres to 4,850 psi-bleed pres to 0-re-press to 4,950 psi-bleed psi-ck flts-fits holding. CIP 1,930 hrs 1/24/13; Discuss plan forward with Anc mgmt. RD cmt equip-blow down lines-monitor well fluid loss-clear/clean rig floor and work areas-service drawworks-iron roughneck. Work on Koomey system-replaced collasped bladder-re-charge all bottles to 1,000/1,050 psi-drain blow down RFR tanks- 1 bph fluid loss since CIP at 2,000hrs 1/24/13. Fluid loss to well today 66 bbls-Total fluid loss to well 139 bbls. Metal recovered from well today 10 lbs-Total recovered from well 255 lbs 1/25/2013-Friday Change out bladder on accumulator bottle and check all pressures. Grease choke manifold, HCR valves. Blow down all lines. Rig down cement head and CRT 350 and pressure wash same. Rig up casing bales and elevators.Assist crane crew where needed. Housekeeping and cleaning on rig floor. Monitor trip tank. Fluid loss to well today 24 bbls. Total fluid loss to well 163 bbls. Metal recovered from well today 0 lbs.Total recovered from well 255 lbs. 1/26/2013-Saturday Clean and organize loose equipment. Spot Pollard unit. Inspect rotary table traction motor and locks. Adjust belts on mix pump#1. Service crown and blocks. Establish downhole casing torque parameters with casing tongs. R/U Pollard e-line. Correlate string shot on depth @ 1,427'. Torque string to the left @ 20K ft/lbs. Fire string shot. Back out 10 rounds and work string to 75K over expected string weight several times to release slips. Work in an additional 8 rounds with string 15K over expected weight of 138K. Remove spider elevators and install side door elevators. Work pipe to neutral and turn 3/4 turn to the left. Pipe came free with 130K hanging weight. Lay down first joint of 9-5/8"casing. R/U back-up rotary tongs on driller side. POOH laying down casing. Clean each joint being pulled. Joints extremely tight(40-44K ft/lbs.). Lost one hour due to lay down machine issues. Daily fluid losses to well 20 bbls.Total fluid losses 183 bbls. Daily metal retreived 0 lbs.Total metal recovered 255 lbs. 1/27/2013 -Sunday POOH laying down 9-5/8"casing. 36 joints total. R/D weatherford casing tools. Clear rig floor. Slip and cut drill line. Inspect brakes and linkage. Blow down TDS. R/D 9 5/8"test joint. R/U 7"test joint. Clear rig floor. Housekeeping throughout rig. Monitor well. Organize dry sack room. Boat call out delayed due to ice at dock. Expected to arrive at platform @ 0600 hrs. Daily fluid losses to well 21 bbls. Total loss to well 204 bbls. Daily metal retrieved 0 lbs. Total metal recovered 255 lbs. Directional driller and Baker hand are on board. 1/28/2013 -Monday P/up& M/up Tie back assy. RIH slow flowing over&freezing up elavators. Brk circ wash dn tag TOF @ 1,432' DPM Circ around&warm up mud(while elect work on TDS torque guage). Screw in to Fish @ 1,432' dpm w/+- 13 rds t/10k&work ZQ torque dwn. Pressured up 500 psi test screw in P/up t/150k pipe wt,continue pressure up t/2200 for 15 min. Attempt it. O nergize hanger slips took two attempts to get hng to take weight. Pressure up t/3,500 psi 3 times to release setting tool. Blow down TDS. POOH and lay down running tool. Rig up Weatherford casing tongs. M/U seal assembly. RIH picking up 9- 5/8" casing to 1,300'. M/U circulating assembly. Engage seal bore and verify with 500 psi. Bleed off. Establish space out depth @ 1,316'. M/U space out pups, casing hanger and landing joints.Will be 19" above no-go when landed. Circulate casing volume (95 bbls). Land casing. Attempt to test casing but hydraulic effect came into play @ 500 psi. Will test after pack-off installed. Lay down landing joints. Daily fluid losses to well 18 bbls. Total fluid loss 222 bbls. Daily metal retrieved 0 lbs. Total metal recovered 255 bbls. *ZXP liner top packer was loaded with 10 steel shear pins and intentionally not set. V14( 1/29/2013-Tuesday *11 L/dn landing jt's. P/up wash tool. Wash out well head &stack. Drain stack. P/up 16-3/4" X 9-5/8" 5k Fmc pack-off. RIH rotate 3 rd to engage latch ring&chk w/40 k over pull. Un-jay from pack-off&test void t/250-5,000 psi for 30 min each. Fill stack remove air&close blinds test csg t/1,540>1,390 psi in 30 min,test failed due to chart hose being in cold. Move O' '` chart recorder& hose re-test 1,540>1,500 psi in 30 min (good test). Install wear ring. P/up 8-1/2" clean out BHA. RIH w/ dp brk circ @ 1,500& 2,600' &elect work on TD torque guage while circ. Wash dn f/3,200' @ 8-10 bpm w/550-650 psi tag @ 3,696' dpm. Ream f/3,696't/Hard solid cmt @ 3,736'. Drill hard cmt f/3,736't/4,034'. 14 BPM/1,130 psi. 20 K WOB. 120 RPM. CBU @ 14 BPM/1,150 psi due to shakers loaded up._Drill cement 4.034'-4,735'. 14 BPM/1,080 psi. 20K WOB. 120 RPM. Daily fluid losses to well 0 bbls. Total losses to well 222 bbls. Daily metal recovered 49 lbs. Total metal recovered 304 lbs. Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date M-31B Redrill 50-733-20457-01-00 212-071 1/9/13 Daily Operations: 1/30/2013-Wednesday Drill cement 4,735'-5,182'. 14 BPM/1300 psi. 120 RPM 9.5K torq. 20K WOB ROP; 90- 120 FPH; Drill cement 5,182'- 5,670'. 16 BPM/1600 psi. 120 RPM 10K torq. 20K WOB; ROP 150- 200 FPH. Drill cement 5,670'-6,037'. 16 BPM/1700 psi. 120 RPM 11K torq. 20K WOB. ROP 150- 200 FPH. Drill cement 6,037' - 7,250'. 18 BPM/2050 psi. 120 RPM 14K torq. 20K WOB. ROP 100-200 FPH. Daily fluid losses to well 0 bbls. Total losses to well 222 bbls. Daily metal recovered 107 lbs.Total metal recovered 411 lbs. Rig down and send in 2 cement pods. 1/31/2013 -Thursday Drill cement 7,250'-7,357'. 18 BPM/2100 psi. 125 RPM 15K torq. 20K WOB. ROP 150- 200 FPH. Lost 500 psi pump pressure. Test surface lines to 2,000 psi. C/0 suction/discharge spring in #1 MP. Clean suction screens and reprime pumps after checking all valves and pistons. Drill cement 7,357' -8,972'. 18 BPM/2350 psi. 120 RPM 16K torq. 20K WOB ROP 150-200 FPH.Troubleshoot and repair#1 MP.Suction screen partially blocked/mud extremely aired up. Reprimed pump 3 times. Drill cement 8,972' to float collar @ 9,019'drill pipe measurement. Same parameters as above. Circulate hole clean with #2 MP while checking suction on#1 MP and repriming.Test 9-5/8" casing @ 1500 psi for 30 minutes on chart recorder. Good test. Bleed off pressure.Align choke manifold. Drill shoe track 9,019' -9,022'. Mud properties extremely deteriorated, foamy and aired up. Daily losses to well 0 bbls.Total losses to well 222 bbls. Daily metal recovered 110 lbs. Total metal recovered 521 lbs. I 2/1/2013- Friday °( 1,‘ �� 5 Continue drlg shoe track f/9,022't/9,107'(drlg cmt+400 fph unable to pump off). Drlg 12 114 hole f/9,107't/9,128'. . O l-# Pull back in to shoe.Chg over to new 9.55 ppg Gem mud (remove blockage from suction of charge pump of# 1 MP). Circ New mud around for even mud wt. @ 9.55 ppg. Perform FIT t/12.0 ppg w/9.55 ppg mud @ 8,488'TVD w/ 1120 psi. RIH safety reamed f/9,128't/9,158' (no sign of btm)wash t/9,352'&took weight safety ream and found TD @ 9,432'. Straight POOH t/shoe w/no problems&circ btm up 940 units gas w/some coa. RIH on elevators set do @ 9,352' unable to pass rotate 2' rih t/9,415'wash t/TD at 9,432'. POOH t/shoe,Circ btm w/20 unit gas no cuttings. POOH B/D L/D bit and staiblizers. 15 minute static loss 0 bbls. Pull wear bushing.Significant amount of cement cuttings on bushing. M/U wash tool. Function rams. Wash/flush stack and tubing hanger profile. Install test plug/joint. Change bottom pipe rams to 7". Daily losses to well 0 bbls.Total losses to well 222 bbls. Daily metal recovered 37 lbs. Total metal recovered 558 lbs. 2/2/2013 -Saturday Finish chg/btm ram f/9-5/8" t/7"_ Test BOPE as per AOGCC regs/witness waived by Mr Jim Regg 1-30-13 @ 13:38 hrs. Test BOPE @ 250 L/4,000 H.Test annular @ 250 L/2,500 H. R/dn test equipment& install wear ring. P/up 8-1/2" drilling assy.&shiollow hole test.TIH with BHA#7. Fill pipe every 15 stands t/6,400'.Continued RIH t/9,088'.SLB sync computers. Establish parameters: 300K P/U, 210K S/O, 240K Rt/wt @ 20K; torq, 13 BPM/1830 psi. RIH to 9,282'without issue.Wash & ream tie-in log 9,282'to 9,431' (hole TD). 580 units of gas at bottoms up. Begin drilling @ 9,431'. Drill 9,431' -9,472'. 140 RPM/24K torq, 14K WOB. Daily losses to well 0 bbls.Total losses to well 222 bbls. Daily metal recovered 0 lbs.Total metal recovered 558 bbls. 11111. 2/3/2013-Sunday Resitivity Flat lining stop drilling @ 9,488'work pipe. Make conn&drill ahead f/9,488't/9,564'discuss options w/town. Stop drilling @ 9,564'work pipe&reboot system(RES still flat line). Continue drill ahead w/8-1/2" rotary steerable w/ out RES f/9,564't/10,038'. Pumped sweep with little change in cuttings on returns. POOH to shoe @ 9,107'. Tight spots @ 9,860', 9,835',9,740',9,628', 9,500'. Had to pump out past these spots after pulling 45K over. Did not rotate.Service rig.TIN to bottom @ 10,038'. Had to wash and ream through tight spots @ 9,363', 9,435',;9,545',9,680',9,730',9,860' to 10,038'. Drill 10,038'-10,135'. Pump 20 bbl sweep @ start of drilling. 200 units of trip gas at bottoms up. Daily losses to well 0 bbls.Total losses to well 222 bbls. Daily metal recovered 37 lbs.Total metal recovered 595 lbs. 2/4/2013-Monday` Drill 10,135'-10,494'.WOB 15K, 125 RPM, 25K torq, 13 BPM/2200 psi. Lost 200 psi pump pressure.Shut down.Test surface lines to 2,000 psi. POOH to shoe @ 9,107'. Hole in better shape. 2 overpulls @ 70K.Service equipment. Change out saver sub. Retest surface lines @ 2,000 psi. Good test.Circulate downhole and verify that previous PSI had dropped. POOH looking for washout. Found hole @ 5,079' appx 18"above tool joint. Lay down bad joint/pick up new.Test tools @ 550 GPM/1,750 psi. Good test.TIH to casing shoe @ 9,107'. Fill pipe every 15 stands. RIH to 9,420'without issue.Wash and ream tight hole 9,420'-10,135'. Numerous trouble spots throughout this section. Pumped sweep with+200% cuttings on returns. Daily losses to well 0 bbls.Total losses to well 222 bbls. Daily metal recovered 14 lbs. Total metal recovered 609 lbs. 2/5/2013-Tuesday Wash and Ream f/10,135't/10,494', 13 BPM,2200 Psi, 100 RPM, 23K TQ. Directional drill f/10,495't/10,793', 550 GPM, 2340 Psi, 120 RPM, 13K WOB. [Pumped 30 BBL low vis sweeps on each connection)Short trip t/10,403'. Work through spot at 10,487't/10,480'while POOH and spot at 10,440'while RIH. Load pipe with hi vis sweep at 10,703'and wash t/10,793'. Directional drill f/10,793't/11,063'. Daily fluid losses to well 65 bbls.Total losses to well 287 bbls. Daily metal recovered 36 lbs.Total metal recovered 645 lbs. Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date M-31B Redrill 50-733-20457-01-00 212-071 1/9/13 AIN:Operations: s 4 '/6/2013-Wednesday l:irectional drill 8-1/2" hole f/ 11,063',t/11,173, 550 GPM, 2230 Psi, 22 to 25K;TO, 100 RPM [Pumping 30 BBL sweeps on 3nnections]. Short trip t/ 10,691'. Work through tight spots at 11,030' t/ 11,017', 10,800', and 10,772' while POH. No tight ;gots RIH. Load pipe w/40 BBL low vis sweep and 40 BBL high vis sweep at 11,083'. Wash to bottom at 11,173'. Directional 8-1/2" hole f/ 11,173' t/11,260'. Gained 150- 200 psi abnormal pump pressure when on bottom. Pick up and circulate � .ottoms up. POOH to 10,170' with 50K overpulls @ 10,760' and 10,240'. Pump past tight spot @ 10,160'. POOH to 9,095' .Pith no issue. Obtain static loss rate of 3.2 BPH. Pump dry job. POOH checking NRP's to stand #74 @ 7,290'. Slip and cut '20' drill line. Service rig and TDS. Static loss= 1.2 BPH. POOH 7,290' - BHA. Work BHA. Daily fluid losses to well 70 bbls. otal losses to well 357 bbls. Daily metal recovered 34 lbs. Total metal recovered 679 lbs. i 2/7/2013 Thursday PU BHA#8. Make up bit and Schlumberger tools. Load source and RIH filling pipe every 3,000' to 7,361'. RIH to shoe at 9,100'. Fill pipe and down link Schlumberger tools. RIH running MADD Pass logs at 700 to 900 FPH. Wash and ream 10,100' - .10,173'. Wash and ream 10,660' - 10,680'. Finish MADD pass to 11,260' without issue. Down link MWD @ 11,160'. RIH to 11,260'. Drill 11,260' - 11'550'TD. P/U 350K, S/0 210K, RtWt 250K, 13 BPM/2050 psi. 120 RPM/24K torq. 10- 15K WOB. Wally fluid losses to well 65 bbls. Total losses to well 422 bbls. Daily metal recovered 6 lbs. Total metal recovered 685 lbs. , D called @ 11,550' as per geology. ::/8/2013 Friday t.irc hole clean, CBU x 2. Short trip f/ 11,550' t/ 11,173', Circ up through tight spots. RIH with no issues. Drop carbide and !!::amp 80 BBL sweep while rotating 130 RPM and pumping 580 GPM. Got a lot of fine sand and a little coal back. Sweep came jl:'•.3ck 45 BBLS late. CBU x 3. POOH slow pumping 1 to 1/12 BPM. First tight spot encountered was 10,004'. Pulled 50k over 'rd broke back down with no resistance. Pulled right thru on 2nd try, Had 5 more spots that worked the same, 9,942', 9,920', .910, 9,903', & 9897'. Pulled free to 9,610', where it packed off. Had to break it free rotating and worked it down to 9,635'. ':limped a high vis sweep and work pipe down t/9,723', 130 RPM, 580 GPM. Reaming down and shutting rotary down and Irking back up. Got back fine coals, then 1/8" size on BU, and 1/2" size when sweep came back. Sweep loaded shakers with V00% increase, CBU x 2. POOH slow-pumping 1 to 1-1/2 BPM to 9-5/8" csg shoe. Circ csg clean - monitor well 0 fluid loss. .31H to 10,100' wash last std dow;;- no problems RIH. POOH slow- pumping 1-1/2 bpm-20k bobble at 9,685' cont pull to 9 78 csg shoe CBU while-confer with Anc- . Re-condition of hole-decision to cont POOH. Conduct torque test at 8,900' w/ pump on at 18k trq at 10 rpm-135 spm-2,025. 2,025 psi/18.5k trq at 20 rpm-135 spm-2025 psi/19k trq at 30 rpm-135 spm- 2025 psi w/pump off-18.5k trq at 10 rpm-0 spm-o psi/19.5k trq at 20 rpm-0 spm-psi 20k trq at 30 rpm-0 spm-0 psi-drop I rabbit on 100' slickline wire. Cont POOH to 6,500'. Conduct tourqe test w/pump off at 10k trq-10 rpm-0 spm-Opsi/11k at 20 rpm-0 spm-0 psi/11.5k trq at 30 rpm-0 spm-0 psi w/pump on 10k trq at 10 rpm-135 spm-1725 psi-11k at 20 rpm-135 spm- 11725 psi/11.5k trq at 30 rpm-135 spm-1725 psi pump dry job. Cont POOH. Fluid loss to well today-19 bbls-Total fluid loss to well 441 bbls. Metal recovered from well today 9 lbs-Total metal recovered from well 694 lbs. 9 2013-Saturday L.: / Y H w/ BHA#8. Lay down Schlumberger tools and break bit. Remove source. Rig up weatherford csg equip.to run 7" liner. kole taking 3/4 BBL/ Hr. PJSM. PU Shoe track and check floats, RIH with 7" liner as per program. PU liner hanger. Mix/pour ;.almix-RD WOT-MU 1 std DP. R114 w/1 std-(liner wt 125k)-circ liner at 6bpm 200 psi- PU-and rabbit(2.25"od) 15'DP pup jt- „U BOT/Rotating Head-PU/MU-and rabbit 10'DP jt to rotating head-set back in mouse hole. RIH with 7” liner on DP-filling a 10 stds. Stop at 9,080' above shoe-circ 1 1/2 vol DP/Csg. Fluid loss to well today 7 bbls-Total fluid loss to well 448 bbls. jMetal recovered from well today 1 lbs-Total metal recovered from well 695 lbs. 2/10/2013-Sunday RIH with 7" liner on 5" DP. Screw into every stand and fill pipe. Encountered bridge at 9,634'. Wash and ream through bridge at 9,634'. Ran up to 15K WOB to work thru. Continue RIH f/9,643't/ 11,540'. Screw into every stand filling pipe and circ down at 1 to 3 BPM. Ream through tight spots at 9,815', 10,142', 10,234', & 11,494', [Lost rotation after 10234' but Iregained it at 11500']. Have full circ. PU cmt head assem and work to bottom at 11,550'. Circ and condition mud for cmt job tivhile keeping pipe reciprocating and rotating. Rotating at 30 RPM, 23K TQ, 6 BPM at 700 Psi. Hole not taking mud. PJSM- I:LB/BOT/HES/RIG crews-plan forward for cementing 7" liner. Cont circ/move pipe w/SLB primes up and mixes additives. SLB ready- PT SLB 1,000/5,000. Rig pump 53 bbls MudPush II. Switch to cementers-cement slurry pump not working. Switch Lack to rig pump. Circ and recip pipe-unable to rotate w/BOT rotating head-hole trying to pack off as mud push is circ'd out c hole. Use rig mech to help diagnose SLB pump- problem. Keeper key that holds impeller on shaft is missing, SLB mech . croute w/parts to repair mix pump. No noticable cuttings in Mud Push returns. Mix another 50 bbl MudPush II pill. SLB 's ,ech on board at 2400 hrs. RD cement hose from rotating head. Cont circ/clean hole w/recip and rotating at 30 rpm-50 ,:')m- 500 psi-up wt 380k/dn wt 255k w/rotating-hole still not taking fluid. SLB repairing slurry pump. SLB slurry pump 2paired. Mix water ready. PJSM 'w/SLB/HES/Rig crews. 7" cment job, Circ/cond rates now at 30 rpm-20k trq-60 spm-600 .i',-,j-rotate up wt 350k-rotate dn wt 210k SD pump. RU cmt line back to rotating head. PT cement lines 1,000/5,000 psi- Hump 50 bbls mud push II 12 ppg-S0 spm-600 psi. On line w/cmt pumps-mix/pump 55 bbls 15.6 ppg class"G" lead cmt_ `:�Ilowed w/ 126 bb!s 15.6 ppg Easa'block tail cmt. Cmt pumped 3.5 bpm-400 psi. Pipe was reciporcated throughout cmt job- r--turns to surface. Drop DP dart and pump out w/SLB and 5 bbls water. Swap to rig pumps to displace. Displace 1,412 stks ' . latch into dart, Pump 173 bbls and rig hit pressure limit of 3400 psi. Swap over to SLB and pump another 11.3 bbls, packed off and pressured up to 5000 psi. Bled back 3.5 bbls. [This put 109.3 bbls on the back side, 66.7 bbls left in the 7" csg.] Fluid loss to well today 5 bbls -Total fluid loss to well 453 bbls; Metal recovered from well today() lbs-Total metal recovered from well 695 lbs. :,/11/2013 - Monday 4;-essure up to 4,500 psi to release tool from liner. Tool wouldnt release. Bleed off pressure and put left hand torque in 1-rring. Work torque down. Continue working pipe to free tool. PU to 350k and pressure up to 1,000 psi, PU to 375k and 1; ressure up to 1,500 psi. Pull up to 400k and tool came free. Rotate and slack off 50k ZXPN liner packer. Work down on pkr :, veral times and saw a slight indi :ation of movement. PU and shut hydril. Attempt to test pkr. Press up to 800 psi and � essure started to equalize with the DP. Bleed press down and move tool. Press up 1,120 psi and press equalized with the ! ;:7 again. Bled press off. Pressure up to 500 psi and PU the RS packoff bushing from the RS nipple. Continue to circ. hole ean. Got back 40 bbls mud push with a trace of cmt. Set back cmt head, blow all the equip down. POH and break down 1::nt head with 10 stds left in the hole, continue POH and lay down running tool. The dog sub was sheared so the pkr is set. 1: J stack washer and wash out stack, Pull wear ring and install test Plug. PJSM-change 7" to 4" rams. PU/MU test tools-fill ,;rack and choke manifold w/water: Test BOPE as per HAK/Kuukpik/AOGCC procedures-250 psi low/4,000 psi high-5" rams- mco kill-upper IBOP-CkMV-lower IBOP-Dart vlv-HCR kill/choke-Man ck(stack)Super Ck-Man ck vlv- LD 5" test jt-PU 4" test Witness of BOPE test waived by AOGCC Jim Regg via email 2/11/13. Fluid loss to well today 0-Total fluid loss to well 453. :letat recovered from well today 0 lbs-Total metal recovered from well 695 lbs. 2/12/2013-Tuesday dig up to test 4" equip. Test annular on 4" to 250 psi low and 2,500 psi high. Test all other 4" equip to 250 psi low and 4,000 psi high. Perform accumulator test. Rig dn test equip, and set wear ring. Pick up 6" cmt clean out BHA#9. Strap& PU 72 jts ( f 4" DP. Pumps wont start-get pumps back up running. Fill pipe and RIH. Tag up firm at 9,968'. Obtain parameters-287k up- 95k dn, rot wt 227k-500 spm-2,5{70 psi. Drilling f/9,968'-10,050' soft/firm cmt several pieces of rubber from 10,050'- :_5,054'. Drill f/10,050'-10,054' have not been able to drill any deeper than 10,054'-have tried to drill f/slow/fast rpm-pump ate-wob- spudding and have not had any torque using the various methods. Fluid loss to well today 0 bbls-Total fluid loss 0€'3 well 453 bbls. Metal recovered from well today 0 lbs-Total metal recovered from well 695 lbs. I -. I Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date M-31B Sidetrack 50-733-20457-01 212-071 1/9/2013 Daily Operations: 2/13/2013 -Wednesday POH with BHA#9, and break bit. Service Drwks, Iron Roughneck, and Topdrive. RIH with 5" HWDP and POH laying it down. Clear equip. off rig floor and swap elevators for running BHA. Make up new bit and RIH w/ BHA#10 slight bobble thru TOL (3,920') w/stablizers at 8,925' and 8,955'. Tag at 10,051' PUW 285-SOW 205-rpm 80-spm 500-psi 2000-18k trq-5k WOB. Work on cmt using various rpm/wt/rates/press to drill thru cmt from 10,051'-10,053'. DrIg cmt f/10,053'- 10,220' at 450 spm- 8k-18k wob-50-80 rpm-1,500-2,000 psi black rubber-aluminum and cement cuttings returns to surface. 2/14/2013 -Thursday Drill cmt with 6" bit f/ 10,220' t/ 10,761', 530 GPM, 2,090 psi, 100 RPM, 11k WOB, 18k TQ, Avg ROP-90.2 FPH. Drill cmt with 6" bit f/ 10,761' t/ 11,315', 530 GPM, 2150 psi, 100 RPM, 10k WOB, 18k TQ, Avg ROP-92.3 FPH. Drill cmt with 6" bit f/ 11,315' t/530 gpm-2,150 psi-100 rpm-8k-10k wob-15k trq- 120 rop. Tag collar at 11,412'. Verify depth-drill on collar f/11,412'-11,414'-10k/20k wob-20k trq-50/80 rpm-500 gpm 2,000 psi- drill thru collar-(30 min) drill cmt to 11,450'-verify depth w/DP strap. Circ/clean hole-lots of cement over shakers-pump 30 bbl hi vis sweep-hole clean. Pull 1 std DP-RU and test csg (7"&9-5/8") to 1,500psi 18 mins psi dropped to 1,450 stable at 1,450 psi for 30 min. POOH removing WWT non rotating protectors. 2/15/2013 - Friday POH, lay do stabs and break bit. Rig up Pollard and run CBL in the 7" liner to 10,634'. Log back up to top of liner, Cmt top at 9,354'. Re-set tool to run CBL in 9-5/8" csg. RD Pollard eline-MU 7" csg scrapper/brush assy-work boat, send back 4-1/2" tbg. Test 7" and 9-5/8" csg to 2,200 psi f/30 mins-loss of 50 psi/30 mins. PJSM-RIH w/7" CO assy. MU 9-5/8"csg CO assy. P,IH with 9-5/8" CO assy. Rig crew lost count of DP stds ran in hole-numbers on DP were off by 6. POOH-verify DP count- re ;'lumber 24 stds DP to be RIH. RIH with 7" & 9-5/8" CO assy., no bobbles entering the TOL at 8,920'. Fluid loss to well today 0 l>bls. Total fluid loss to well 453 bbls. Metal recovered from well today 5 lbs. Total metal recovered from well 727 lbs. 2/16/2013 -Saturday RIH with dual csg scrapper assem and tag liner top with 9-5/8" scrapper. That put the bit at 11,425'. Circ hole clean getting a lot of fines on the first bottoms up and tapering off to nothing after a couple circ. Have PJSM and go over displacement. Pump 48 bbl high vis sweep, and follow with FIW. Pump until we got good FIW back [540 NTUs]. Shut down, flush all lines and manifolds. Flush degasser and poorboy. Pull bushings and clean out drip pan, clean shakers and shaker tank. Clean pill pits. Circ with fresh FIW dumping returns. Reciprocating and rotating pipe. Continue cleaning shaker pit and pit#4 while circ [108 NTUs]. POH to shoe, cont cleaning pit#4 & shaker pit. Cut drilling line-inspect and clean suction valve to pit#4- holding now. Cont POH-to 9-5/8" assy-clean 9 lbs metal shavings off magnets. RBIH with 7" & 9-5/8" CO BHA-did not see TOL at 8,920 when entering. Cleaning sand trap/degasser pits. Tag TOL with bit at 11,425'-LD top sgl on std 94-(to get full 90' stroke). Recip pipe and slow rotate on down stroke-550 gpm-2,250 psi. Fluid loss to well today 0 bbls -Total fluid loss to well 453bb1s Metal recovered from well today 9 lbs-Total metal recovered from well 736 lbs. 2/17/2013 -Sunday Continue circ with FIW, [NTUs 115]. Shut down and clean teeter toter, flow trough and return flow line. Fill pits with FIW. Circ bottoms up running returns back down to pit#4 to clean flow line. Still dumping returns from pit 4,[NTUs 98]. POH to ilner top. Circ bottoms up dumping about 200 bbls of dirty FIW. POH to last 24 stds of 5" DP. Lay down 72 jts 5" DP. Clean magnet(7 lbs shavings)-LD 9-5/8" scrapper/brush assy. POOH to BHA. Stand back DC-LD 7" scrapper/brush assy-clean magnet(4 lbs shavings). Remove wear bushing. Clean out mud system-MU BOPE flush tool and flush plug profile and ram cavities. PU test tools-test jt-set test plug-RU test pump-manifold. Change lower pipe rams to 4-1/2". Test 4-1/2" pipe rams to 250 l0/4,000 hi psi- 10 mins ea. Pull test plug- install wear bushing-RD test equip-LD test jt-clear floor. Bring TCP gun handling tools to floor-MU TCP safety jt. Fluid loss to well today° bbls-Total fluid loss to well 453 bbls. Metal recovered from well today 11 lbs -Total metal recovered from well 74701bs. 2/18/2013- Monday Finish bringing SLB/TCP running equip to floor and MU safety jt. PJSM for running TCP guns. RIH w/SLB/TCP guns 86 guns in hole. RIH w/remaining guns-total 98 guns in hole. RD SLB equip for running guns. RU WOT equip for running tbg. RIH with ;LB/TCP guns on 4-1/2" tbg. PU tbg off deck(170 jts in hole). PJSM. Cont RIH with SLB/TCP guns on 4-1/2" tbg. PU tbg off deck-run slow entering. TOL at 8,920'-clean entry-finish RIH w/98 guns on 288 jts 4 1/2" tbg. MU X-0 from tbg to DP. Fluid loss to well today 0 bbls. Total fluid loss to well 453 bbls. Metal recovered from well today 0 lbs. Total metal recovered (from well 747 lbs. 2/19/2013 -Tuesday Tog collar on jt#288 was damaged by IR w/ making up XO for DP. The TbgxDP XO was damaged as well. LD tbg jt#288 and PU tbg jt#289 and RIH. Search for and MU replacement XO f/tbg x dp. Cont MU space out DP. RU Pollard eline for correlation log & run. Log & move pipe 4' up. PJSM &fire guns @ 12:10 hrs est 12 bbls loss @ denoation. Circ X2 clear gun gas Ntu f/40- 120. Monitor static well (no losses). Pooh 21 std (guns above top perf) well took over displacement (3-4) BPH losses. Monitor well circ btm up well @ 3-4 bph losses. Continue pooh racking back tbg. Change out seal rings in tbg collar for ea std. Fluid loss on trip out 1.5 bph. RU to LD guns, change elevators and LD DP pup jt. Std back 1 std DP. PJSM. MU safety jt put in mouse hole. PJSM with incoming crew. L/dn guns &check for fired shots. LD 7 guns. 5 guns had holes. Guns 93 & 92 had no holes. RIH w/3 stds DP. Install safety jt. Top gun 225' below ocean floor. Conduct field insp on the guns. Booster for puncher gun #93 fired on top but did not fire on btm for gun #92. Condition of guns from 91-0 are unknown at this time. Suspect guns will be wet. Confer w/SLB mgmt. Cont LD guns as live guns, checking both gun ends. Change elev, std back 3 stds DP-LD XOs. MU safety jt to sgl/set in mouse hole. PJSM. Treat as live guns. POOH guns are pulling mud bucket wet. Fliud loss to well today 12 bbls. Total fluid loss to well 478 bbls. Metal recovered from well today 6 lbs. Total metal recovered from well 753 lbs. Interval 9,361' -9,390' and interval 9,425' - 9,440' were perf'd with Pure 4.50. 5 Itpf(actual 3.8 spf)-450 PJO guns. f Hilcorp Alaska LLC Weekly Operations Summary II Name API Number Well Permit Number Start Date End Date M-31B Sidetrack 50-733-20457-01-00 212-071 1/9/13 2/25/13 aity�Operations: eta F °» alt 1 1,ti,11�i }l 2/20/2013 Wednesday Cont POOH. LD perf guns-all guns were wet-no guns fired from 93-0. Clear floor of perf gun running equip. LD safety jt. Monitor well 30 mins static loss at 3.2 bph. Move 6 stds tbg to DS of derrick. RIH with 21 std 5"DP. POOH. LD 21 stds 5" DP. Pull wear bushing-drain stack and install test plug. Install mouse hole in rotary. RU hose to 9-5/8" ann to monitor fluid less/gain. LD/DP in rotary/mouse hole a sgl at a time. 30 stds laid down-fluid loss for LD/DP total 2.3 bbls= 1/2 bph. Cont 1.D/DP in rotary/mouse hole a sgl at a time 42 stds LD-fluid loss for DP/LD 3.3 bbls=.55 bph. Fluid loss to well today 47 bbls- Total fluid loss to well 572 bbls. Metal recovered from well today 0 lbs-Total metal recovered from well 753 lbs. -Thursday [2/21/2013 .nish L/dn all 5" dp 118 std and 5" equip. Cut 68' drlg line, clear/clean floor. Service TDS-change out 4-1/2" IF saver sub to 11T-38-change out bell guide and die body. Replace and seat brushes on DW'A' (as per elec). Service TDS. Finish torque up Saver sub. Cleaning rig-maint on TD. Monitor well 1/2 to 1 BPH clean screens on pumps. Pull test plug-line up on trip tank and monotor well. LD 1 std 5 DP-MU safety jt for perforating. Maint on rig-service pipe skate. MU std 5"DP set back-unload i}oat of guns & personel go over Gun running order/tally. Move SLB gun, MU tools to floor and strap guns. MU guns, start I I:"U/RIH with SLB/TCP guns-10in hole. MU of guns-cont. RIH with total 93 guns. MU XOs. FH-verify 5/8" ball will seat. Brk ci safety jt-change elev-^1.6 bph loss. Fluid loss to well today 16 bbls-Total fluid loss to well 588 bbls. Metal recovered om well today 0 lbs-Total meta! recovered from well 753 lbs. b/22/2Ol3- Friday Rih w/4.5" SLB TCP Pure guns on all of 4-1/2" tbg out of derrick. RIH w/2 std 4" dp & 2 jt+ pup of 5" & place Bull nose @ -17 1.1,408' in up stroke. R/up pollard E-line & make Correlation Log&tie in RA marker to GR; Pooh & r/dn E-line. Pooh 9.20' & place guns on depth w/top shot @ 9,490' & Btm shot @ 11,396'. Drop ball & pump onto seat &fire guns @ 16:34 hrs. Shut in circ. thru open choke &gas buster&circ X2 btm up& clear gun gas. Lost 45 bbls at detonation &+- 198 BPH loss rate & Move guns. Open well monitor static loss rate for 15 min @ 120 BPH. Dn pump let fluid seek its own level & have production itempt to monitor w/fluid level machine (unable to get good data). Fill well w/ 100 bbls& circ btm up. Good, clean fluid. Ho oil or gas. Estimated fluid level @ 1,870'. ; POOH 22 stands to 9,369'. Allow won bore fluid to seek its own level. Fill well 95 bbls. Circulate bottoms up. Clean fluid/no oil or gas. POOH with perf gun assembly. Estimated fluid level @ 1,775'. FIW losses to well 984 bbls. Total FIW loss 1,119 bbls. Total mud loss 453 bbls. Daily metal recovered 0 lbs.Total metal recovered 753 bbls. 2/23/2013-Saturday OOH with perf gun assembly. Racking back 4-1/2" tbg&chg out. Seal ring in collars &adding 2X pipe displacement. roduction continues to echo monitor annulus to establish base line for fluid level @ 1,300' - 1,600'. Make up safety jt in souse hole. L/dn &chk guns addi;ig 2x displacement of guns (all shots fired as design). BOP drill both crews on use of safety Clear& clean floor& prep for p/up ESP. P/up ESP Pump assy.Adding 5 bbls every 1/2 hr. Daily FIW losses to well 474 Total FIW losses 1593 bbls. ;otal mud loss to well 453 bbls. Daily metal recovered 5 lbs. Total metal recovered 758 L.'s. 1rc/24/2013 -Sunday • '7nish cable & chem line tie in. Test both, ok. Perform Bare pipe shut in. Review & Cable cut drill w/AM crew. Rih w/ ESP .;sy w/4-1/2" tbg from derrick installing clamps per design. Continue adding 10 bph to hole @ 5 bbl every 30 min. Test cable & chem lines every 10 std (ok). Continue Rih w/ ESP assy w/4-1/2" tbg from derrick installing clamps per design. Observed fluid entering tbg (fluid level between 1,368' t/ 1,464'). Test cable & chem lines every 10 std @ std 20 (ok). Preform bare pipe shut in Review & Cable cut drill w/ PM crew. Continue Rih w/ ESP assy w/4-1/2" tbg from derrick [;istalling clamps per design. Test cable & chem lines every 10 std @ std 30 (ok). Continue Rih w/ ESP assy w/4-1/2" tbg ft.om derrick installing clamps per design. Test cable & chem lines every 10 std @ std 40 (ok). Continue Rih w/ ESP assy w/4- 1 tbg from derrick installing clamps per design. Test cable & chem lines every 10 std @ std 50 (ok). Continue RIH w/ ESP ssy w/4-1/2" tbg from derrick installing clamps per design. Preform cable to cable splice @ 6,000'. Adding 10 BPH FIW to '!•,;;le. Continue RIH w/ ESP assy w/4-1/2" tbg from derrick installing clamps per design to 8,795'. M/U tubing hanger and I'anding joint. Make final splice at tubing hanger. Install penetrator and chemical injection lines through tubing hanger&test Ame. 2/25/2013 - Monday Land hanger w/anode @ 8,875' up wt @ 225k do wt @ 162k. RILDS & Back out landing jts. Brk riser @ well head lift stack & chk cable reading due to the fact SLB did not have an extention cord to chk wire when hanger is landed before nip/dn. Set stack back on well head. Proceed with normal nip/dn operations. Nipple up tree. Lower tree pieces into well head room while nipple up to tree. L/dn 8 std 4-1/2" tbg out of derrick. Remove all service lines & lower same into upper well bay ruom. Test tree @ 5,000 psi. Pull two-way check. Turn well over to production. Prep to skid rig over East upper well bay Latch while production finish tie-in of ESP and SSV. Daily FIW losses to well 89 bbls. Total FIW losses 1,953 bbls. Total mud '.:ss to well 453 bbls. Daily metal recovered 0 lbs. Total metal recovered 758 lbs. This will be final report for M-31B. :/26/2013 -Tuesday No operations to report. � H. m g poogoccto -2"g W M 3 Rg2 2 dam m as 26�s :M. n o, 0 e , o o g a`� `� o c 1 A p m m % 1 g,o^, o° m m F, T p 7. 03 3 W ,�3, ; ° a*m O m o /lig' a 0 '0, F"' m .1 m o x.. m o > „m rn rn e F7-7,' m c O 3JOWN'2O 0 =00 AWN+O OWVW0 AWN+O WWV88 AWN+ 000 00000 000000000pSpSpOOOOOOOO OOOO 000000 0 00000 00222 00000 0 0 0 O O0 0 0 0888886.6.. O O O O888880 0 00 0 0 0 0..00 0 0 00 0 L.z z z T 3 8 3 3 W$x T d A G O W J W+N .g R MM 00 w UR m4wznoD2 m $ m� SNo,NS W aAmw +NNNW+++ 000ANO NyyN+ WVNW030005WWW03W W000 00000 VGN m N W + SNON A0WO +WNOWpNy0( 400QN n CN0gO . V JN+00NWA W000000WAW+S.: 06 WW NOdN HC0 m*va j t:-. . N `G0 k -m > WWWNN NNNN+ 3 A -4,1000 .No. N C +++ +++NN NNNNN NNNNN NN++ AW+C0 VVN+ 0030 WN N0A0oW003+ m. 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OWOJW to N..tO 3(00 NNNNN NNNNN NNNN N NNNNN N NN NN N N cIl WWWWWWWWWWWWWWWWWWWWWWW2 pI W + W + + NN NN-,-.0 00+-..s NNNN+ N-4 J,104A 00,000 443040 01,1 000. 0007.0 01. m W 0 43 t0 mao W t000i0Wiw W N+t0Tt0T0 two oN W 0 02+W+ W,1_,m N N NO o 0 0 W co W W W W W W W W W W W W W W W W W W W W W W m. 0 0 0 0 0 0 0 0 o O 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N 66666 N N N N N N N N N 66666 N W W W W W W W W 66666 W W W Ww N W pW NJ VVV00 000 00000 0++++ N +N Vw +ApoapNA00A-, �T ONNJ pr CAW NWwN Op N OO T T 01 ! !! +043+ WWANNW80p- AWNA OVNAW 000WAWNJJ N °p,10 J 00.00 WWNWW ..... WWWW. .0 O 6666600000W0 °WO0Wb On o wwwow 0000C00 00000 WOO0.. O0OW0 O O 00 NTTWW 00000 000AA AAAA tANNNNNNWWwWwWwWW AU m W WW 40000 NWOO OO 882 V04p4 NWV4J tN+ �TAmN8ON AO-.p NA0000, 000J0 040+,1 000 00043+ ,J0 G) • Measured Depth(ft) N I-4 N 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 NJ 0 A 0 v CU N g C 1 N vi v < 0o CD rr inoo0 N 0 0 N NJ 0 M-3113 MW Vs Depth 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 -MW vs Depth 5500 48. w 6000 EI2 6500 cis w 7000 2 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 8 9 10 11 12 13 14 Mud Density(ppg) • Tubular Information: Tubular Size: 4 1/2" 12.6# L-80 IBT AFE Number: 1213057 !Well: M-31B Start Date: Field: Trading Bay Unit Start Time: Platform: Steelhead Platform Date Landed: Foreman: Time Landed: Rig: 51 Up-Weight: Completion Fluid Weight (PPG): 8.65 Slack-off : Completion Fluid Type: FIW Weight set on Slips/HGR: Wellhead Make: Current Rig KB Elevation: 71.93 Original Rig KB Elevation: 74.5 Item Jt Description ID " OD " LENGTH Total TOP BTM. (in) (in) (ft) Length (ft) (ft) 8,859.25 8,859.25 ' CENTRALIZER: Constructed by GLM, Kenai,AK 5.62 2.00 2.00 8,857.25 8,859.25 PHOENIX XT GAUGE ASSY TYPE 1 13CR 4.50 1.82 8,855.43 8,857.25 2 VIT/AFL (A346) 3.82 MOTOR: 562, 15, F151, MAXIMUS, RA-LT, CS, M-TRM, AS, HSFT, AFLAS, KTB, GRB, 5.63 34.18 8,821.25 8,855.43 3 MAXJOINT 563HP 2173V 157A 38.00 MOTOR: 562, 15, F151, MAXIMUS, RA-UT, CS HSFT, M-TRM, AS, AFLAS, KTB 563HP 5.63 34.68 8,786.57 8,821.25 4 2173V 157A 72.68 PROTECTOR: MAXIMUS, BPBSL, 540/540, KTB/HL, 1.18 INC 718, CS, AFL, M-TRM, 5.38 8.91 8,777.66 8,786.57 5 FACT SHIM 81.59 PROTECTOR: MAXIMUS, BPBSL, 540/540, 6 KTB/HL, 1.18 INC 718, CS, AFL, M-TRM, 5.38 8.91 8,768.75 8,777.66 FACT SHIM 90.50 INTAKE: VGSA S70-150 540/540 RLOY 7 5.38 4.06 8,764.69 8,768.75 SLIM, 1.18 INC, M-TRM, ES-SS 94.56 8 PUMP: GN10000 CR-CT 58 STG 540/540 5.38 21.84 8,742.85 8,764.69 150 CS BTHD, 1.18 INC, M-TRM, HSN, ARZ 116.40 PUMP: GN10000 CR-CT 58 STG 540/540 9 5.38 21.83 8,721.02 8,742.85 150 CS BTHD, 1.18 INC, M-TRM, HSN, ARZ 138.23 • PUMP: S8000N CR-CT 79 STG 538/540 150 10 CS BTHD, 1.00 INC 718, M-TRM, AFL, ARZ, 5.38 21.75 8,699.27 8,721.02 FACT SHIM 159.98 PUMP: S8000N CR-CT 79 STG 538/540 150 11 CS BTHD, 1.00 INC 718, M-TRM, AFL, ARZ, 5.38 21.75 8,677.52 8,699.27 FACT SHIM 181.73 12 DISCHARGE PRESSURE SUB ASSY REDA 2.81 5.38 0.75 8,676.77 8,677.52 513 AFL 420 (A149) 182.48 13 HEAD: BOLT ON DISCHARGE PMP, 540, 2.99 5.38 0.59 8,676.18 8,676.77 RLOY, 3.50 OD 8RD EUE 183.07 14 1 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 213.57 8,645.68 8,676.18 15 2 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 244.07 8,615.18 8,645.68 16 3 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 274.57 8,584.68 8,615.18 17 4 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 305.07 8,554.18 8,584.68 18 5 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 335.57 8,523.68 8,554.18 19 6 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 366.07 8,493.18 8,523.68 20 7 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 396.57 8,462.68 8,493.18 21 8 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 427.07 8,432.18 8,462.68 22 9 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 457.57 8,401.68 8,432.18 23 10 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 488.07 8,371.18 8,401.68 24 11 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 518.57 8,340.68 8,371.18 25 12 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 549.07 8,310.18 8,340.68 26 13 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 579.57 8,279.68 8,310.18 27 14 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 610.07 8,249.18 8,279.68 28 15 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 640.57 8,218.68 8,249.18 29 16 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 671.07 8,188.18 8,218.68 30 17 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 701.57 8,157.68 8,188.18 31 18 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 732.07 8,127.18 8,157.68 32 19 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 762.57 8,096.68 8,127.18 33 20 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 793.07 8,066.18 8,096.68 34 21 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 823.57 8,035.68 8,066.18 35 22 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 854.07 8,005.18 8,035.68 36 23 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 884.57 7,974.68 8,005.18 37 24 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 915.07 7,944.18 7,974.68 38 25 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 945.57 7,913.68 7,944.18 39 26 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 976.07 7,883.18 7,913.68 40 27 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,006.57 7,852.68 7,883.18 41 28 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,037.07 7,822.18 7,852.68 42 29 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,067.57 7,791.68 7,822.18 43 30 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,098.07 7,761.18 7,791.68 44 31 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,128.57 7,730.68 7,761.18 45 32 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,159.07 7,700.18 7,730.68 46 33 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,189.57 7,669.68 7,700.18 47 34 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,220.07 7,639.18 7,669.68 48 35 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,250.57 7,608.68 7,639.18 49 36 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,281.07 7,578.18 7,608.68 50 37 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,311.57 7,547.68 7,578.18 51 38 4-1/2" 12.6# L-80 IBT Tbg 3.833 4.500 30.50 1,342.07 7,517.18 7,547.68 1 52 39 4-1/2" 12.6#L-80 IBT Tbg 3.833 1 4.500 30.50 1,372.57 7,486.68 7,517.18 53 40 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,403.07 7,456.18 7,486.68 54 41 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,433.57 7,425.68 7,456.18 55 42 4-1/2" 12.6#L-80 IBT Tbg 3.833 _ 4.500 30.50 1,464.07 7,395.18 7,425.68 56 43 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,494.57 7,364.68 7,395.18 57 44 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,525.07 7,334.18 7,364.68 58 45 4-1/2" 12.6#L-80 IBT Tbg 3.833 _ 4.500 30.50 1,555.57 7,303.68 7,334.18 59 46 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,586.07 7,273.18 7,303.68 60 47 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,616.57 7,242.68 7,273.18 61 48 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,647.07 7,212.18 7,242.68 62 49 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,677.57 7,181.68 7,212.18 63 50 4-1/2" 12.6#L-80 IBT Tbg 3.833 _ 4.500 30.50 1,708.07 7,151.18 7,181.68 64 51 4-1/2" 12.6# L-80 IBT Tbg 3.833 4.500 30.50 1,738.57 7,120.68 7,151.18 65 52 4-1/2" 12.6# L-80 IBT Tbg 3.833 4.500 30.50 1,769.07 7,090.18 7,120.68 66 53 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,799.57 7,059.68 7,090.18 67 54 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,830.07 7,029.18 7,059.68 68 55 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,860.57 6,998.68 7,029.18 69 56 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,891.07 6,968.18 6,998.68 70 57 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,921.57 6,937.68 6,968.18 71 58 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,952.07 6,907.18 6,937.68 72 59 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 1,982.57 6,876.68 6,907.18 73 60 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,013.07 6,846.18 6,876.68 74 61 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,043.57 6,815.68 6,846.18 75 62 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,074.07 6,785.18 6,815.68 76 63 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,104.57 6,754.68 6,785.18 77 64 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,135.07 6,724.18 6,754.68 78 65 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,165.57 6,693.68 6,724.18 79 66 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,196.07 6,663.18 6,693.68 80 67 4-1/2" 12.6#L-80 IBT Tbg 3.833 _ 4.500 30.50 2,226.57 6,632.68 6,663.18 81 68 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,257.07 6,602.18 6,632.68 82 69 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,287.57 6,571.68 6,602.18 83 70 4-1/2" 12.6#L-80 IBT Tbg 3.833 _ 4.500 30.50 2,318.07 6,541.18 6,571.68 84 71 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,348.57 6,510.68 6,541.18 85 72 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,379.07 6,480.18 6,510.68 86 73 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,409.57 6,449.68 6,480.18 87 74 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,440.07 6,419.18 6,449.68 88 75 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,470.57 6,388.68 6,419.18 89 76 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,501.07 6,358.18 6,388.68 90 77 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,531.57 6,327.68 6,358.18 91 78 4-1/2" 12.6#L-80 IBT Tbg 3.833 _ 4.500 30.50 2,562.07 6,297.18 6,327.68 92 79 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,592.57 6,266.68 6,297.18 93 80 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,623.07 6,236.18 6,266.68 94 81 4-1/2" 12.6#L-80 IBT Tbg 3.833 _ 4.500 30.50 2,653.57 6,205.68 6,236.18 95 82 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,684.07 6,175.18 6,205.68 96 83 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,714.57 6,144.68 6,175.18 97 84 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,745.07 6,114.18 6,144.68 98 85 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,775.57 6,083.68 6,114.18 99 86 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,806.07 6,053.18 6,083.68 100 87 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,836.57 6,022.68 6,053.18 101 88 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,867.07 5,992.18 6,022.68 102 89 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,897.57 5,961.68 5,992.18 103 90 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,928.07 5,931.18 5,961.68 104 91 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,958.57 5,900.68 5,931.18 105 92 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 2,989.07 5,870.18 5,900.68 106 93 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,019.57 5,839.68 5,870.18 107 94 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,050.07 5,809.18 5,839.68 108 95 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,080.57 5,778.68 5,809.18 109 96 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,111.07 5,748.18 5,778.68 110 97 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,141.57 5,717.68 5,748.18 111 98 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,172.07 5,687.18 5,717.68 112 99 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,202.57 5,656.68 5,687.18 113 100 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,233.07 5,626.18 5,656.68 114 101 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,263.57 5,595.68 5,626.18 115 102 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,294.07 5,565.18 5,595.68 116 103 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,324.57 5,534.68 5,565.18 117 104 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,355.07 5,504.18 5,534.68 118 105 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,385.57 5,473.68 5,504.18 119 106 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,416.07 5,443.18 5,473.68 120 107 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,446.57 5,412.68 5,443.18 121 108 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,477.07 5,382.18 5,412.68 122 109 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,507.57 5,351.68 5,382.18 123 110 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,538.07 5,321.18 5,351.68 124 111 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,568.57 5,290.68 5,321.18 125 112 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,599.07 5,260.18 5,290.68 126 113 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,629.57 5,229.68 5,260.18 127 114 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,660.07 5,199.18 5,229.68 128 115 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,690.57 5,168.68 5,199.18 129 116 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,721.07 5,138.18 5,168.68 130 117 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,751.57 5,107.68 5,138.18 131 118 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,782.07 5,077.18 5,107.68 132 119 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,812.57 5,046.68 5,077.18 133 120 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,843.07 5,016.18 5,046.68 134 121 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,873.57 4,985.68 5,016.18 135 122 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,904.07 4,955.18 4,985.68 136 123 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,934.57 4,924.68 4,955.18 137 124 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,965.07 4,894.18 4,924.68 138 125 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 3,995.57 4,863.68 4,894.18 139 126 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,026.07 4,833.18 4,863.68 140 127 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,056.57 4,802.68 4,833.18 141 128 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,087.07 4,772.18 4,802.68 142 129 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,117.57 4,741.68 4,772.18 143 130 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,148.07 4,711.18 4,741.68 144 131 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,178.57 4,680.68 4,711.18 145 132 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,209.07 4,650.18 4,680.68 146 133 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,239.57 4,619.68 4,650.18 147 134 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,270.07 4,589.18 4,619.68 148 135 4-1/2" 12.64 L-80 IBT Tbg 3.833 4.500 30.50 4,300.57 4,558.68 4,589.18 149 136 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,331.07 4,528.18 4,558.68 150 137 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,361.57 4,497.68 4,528.18 151 138 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,392.07 4,467.18 4,497.68 152 139 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,422.57 4,436.68 4,467.18 153 140 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,453.07 4,406.18 4,436.68 154 141 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,483.57 4,375.68 4,406.18 155 142 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,514.07 4,345.18 4,375.68 156 143 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,544.57 4,314.68 4,345.18 157 144 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,575.07 4,284.18 4,314.68 158 145 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,605.57 4,253.68 4,284.18 159 146 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,636.07 4,223.18 4,253.68 160 147 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,666.57 4,192.68 4,223.18 161 148 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,697.07 4,162.18 4,192.68 162 149 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,727.57 4,131.68 4,162.18 163 150 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,758.07 4,101.18 4,131.68 164 151 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,788.57 4,070.68 4,101.18 165 152 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,819.07 4,040.18 4,070.68 166 153 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,849.57 4,009.68 4,040.18 167 154 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,880.07 3,979.18 4,009.68 168 155 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,910.57 3,948.68 3,979.18 169 156 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,941.07 3,918.18 3,948.68 170 157 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 4,971.57 3,887.68 3,918.18 171 158 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,002.07 3,857.18 3,887.68 172 159 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,032.57 3,826.68 3,857.18 173 160 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,063.07 3,796.18 3,826.68 174 161 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,093.57 3,765.68 3,796.18 175 162 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,124.07 3,735.18 3,765.68 176 163 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,154.57 3,704.68 3,735.18 177 164 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,185.07 3,674.18 3,704.68 178 165 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,215.57 3,643.68 3,674.18 179 166 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,246.07 3,613.18 3,643.68 180 167 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,276.57 3,582.68 3,613.18 181 168 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,307.07 3,552.18 3,582.68 182 169 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,337.57 3,521.68 3,552.18 183 170 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,368.07 3,491.18 3,521.68 184 171 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,398.57 3,460.68 3,491.18 185 172 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,429.07 3,430.18 3,460.68 186 173 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,459.57 3,399.68 3,430.18 187 174 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,490.07 3,369.18 3,399.68 188 175 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,520.57 3,338.68 3,369.18 189 176 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,551.07 3,308.18 3,338.68 190 177 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,581.57 3,277.68 3,308.18 191 178 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,612.07 3,247.18 3,277.68 192 179 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,642.57 3,216.68 3,247.18 • 193 180 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,673.07 3,186.18 3,216.68 194 181 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,703.57 3,155.68 3,186.18 195 182 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,734.07 3,125.18 3,155.68 196 183 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,764.57 3,094.68 3,125.18 197 184 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,795.07 3,064.18 3,094.68 198 185 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,825.57 3,033.68 3,064.18 199 186 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,856.07 3,003.18 3,033.68 200 187 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,886.57 2,972.68 3,003.18 201 188 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,917.07 2,942.18 2,972.68 202 189 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 5,947.57 2,911.68 2,942.18 203 190 4-1/2" 12.6#L-80 IBT Tbg 3.833 _ 4.500 30.50 5,978.07 2,881.18 2,911.68 204 191 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,008.57 2,850.68 2,881.18 205 192 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,039.07 2,820.18 2,850.68 206 193 4-1/2" 12.6#L-80 IBT Tbg 3.833 _ 4.500 30.50 6,069.57 2,789.68 2,820.18 207 194 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,100.07 2,759.18 2,789.68 208 195 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,130.57 2,728.68 2,759.18 209 196 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,161.07 2,698.18 2,728.68 210 197 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,191.57 2,667.68 2,698.18 211 198 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,222.07 2,637.18 2,667.68 212 199 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,252.57 2,606.68 2,637.18 213 200 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,283.07 2,576.18 2,606.68 214 201 4-1/2" 12.6#L-80 IBT Tbg 3.833 _ 4.500 30.50 6,313.57 2,545.68 2,576.18 215 202 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,344.07 2,515.18 2,545.68 216 203 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,374.57 2,484.68 2,515.18 217 204 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,405.07 2,454.18 2,484.68 218 205 4-1/2" 12.6#L-80 IBT Tbg 3.833 _ 4.500 30.50 6,435.57 2,423.68 2,454.18 219 206 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,466.07 2,393.18 2,423.68 220 207 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,496.57 2,362.68 2,393.18 221 208 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,527.07 2,332.18 2,362.68 222 209 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,557.57 2,301.68 2,332.18 223 210 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,588.07 2,271.18 2,301.68 224 211 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,618.57 2,240.68 2,271.18 225 212 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,649.07 2,210.18 2,240.68 226 213 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,679.57 2,179.68 2,210.18 227 214 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,710.07 2,149.18 2,179.68 228 215 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,740.57 2,118.68 2,149.18 229 216 4-1/2" 12.6#L-80 IBT Tbg 3.833 _ 4.500 30.50 6,771.07 2,088.18 2,118.68 230 217 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,801.57 2,057.68 2,088.18 231 218 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,832.07 2,027.18 2,057.68 232 219 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,862.57 1,996.68 2,027.18 233 220 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,893.07 1,966.18 1,996.68 234 221 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,923.57 1,935.68 1,966.18 235 222 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,954.07 1,905.18 1,935.68 236 223 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 6,984.57 1,874.68 1,905.18 237 224 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,015.07 1,844.18 1,874.68 238 225 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,045.57 1,813.68 1,844.18 239 226 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,076.07 1,783.18 1,813.68 240 227 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,106.57 1,752.68 1,783.18 241 228 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,137.07 1,722.18 1,752.68 242 229 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,167.57 1,691.68 1,722.18 243 230 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,198.07 1,661.18 1,691.68 244 231 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,228.57 1,630.68 1,661.18 245 232 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,259.07 1,600.18 1,630.68 246 233 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,289.57 1,569.68 1,600.18 247 234 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,320.07 1,539.18 1,569.68 248 235 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,350.57 1,508.68 1,539.18 249 236 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,381.07 1,478.18 1,508.68 250 237 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,411.57 1,447.68 1,478.18 251 238 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,442.07 1,417.18 1,447.68 252 239 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,472.57 1,386.68 1,417.18 253 240 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,503.07 1,356.18 1,386.68 254 241 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,533.57 1,325.68 1,356.18 255 242 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,564.07 1,295.18 1,325.68 256 243 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,594.57 1,264.68 1,295.18 257 244 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,625.07 1,234.18 1,264.68 258 245 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,655.57 1,203.68 1,234.18 259 246 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,686.07 1,173.18 1,203.68 260 247 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,716.57 1,142.68 1,173.18 261 248 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,747.07 1,112.18 1,142.68 262 249 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,777.57 1,081.68 1,112.18 263 250 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,808.07 1,051.18 1,081.68 264 251 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,838.57 1,020.68 1,051.18 265 252 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,869.07 990.18 1,020.68 266 253 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,899.57 959.68 990.18 267 254 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,930.07 929.18 959.68 268 255 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,960.57 898.68 929.18 269 256 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 7,991.07 868.18 898.68 270 257 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,021.57 837.68 868.18 271 258 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,052.07 807.18 837.68 272 259 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,082.57 776.68 807.18 273 260 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,113.07 746.18 776.68 274 261 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,143.57 715.68 746.18 275 262 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,174.07 685.18 715.68 276 263 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,204.57 654.68 685.18 277 264 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,235.07 624.18 654.68 278 265 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,265.57 593.68 624.18 279 266 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,296.07 563.18 593.68 280 267 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,326.57 532.68 563.18 281 268 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,357.07 502.18 532.68 282 269 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,387.57 471.68 502.18 283 270 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,418.07 441.18 471.68 284 271 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,448.57 410.68 441.18 285 272 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,479.07 380.18 410.68 286 273 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,509.57 349.68 380.18 • • 287 274 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,540.07 319.18 349.68 I 288 275 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,570.57 288.68 319.18 289 276 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,601.07 258.18 288.68 290 277 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,631.57 227.68 258.18 291 278 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,662.07 197.18 227.68 292 279 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,692.57 166.68 197.18 293 280 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,723.07 136.18 166.68 294 281 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,753.57 105.68 136.18 295 282 4-1/2" 12.6#L-80 IBT Tbg 3.833 4.500 30.50 8,784.07 75.18 105.68 269 256 Pup 3.833 4.500 3.25 8,787.32 71.93 75.18 270 257 Tubing Hanger 0.50 8,787.82 71.43 71.93 RKB 71.93 8,859.75 (0.50) 71.43 Hilcorp Energy Company CASING & CEMENTING REPORT Lease&Well No. M-31 B Date County Cook Inlet State Alaska Supv. Shane Hauck/Joe McInnis CASING RECORD TD 9425'MD Shoe Depth: 9107 MD PBTD: Casing(Or Liner)Detail Setting Depths No.of Jts. Size Wt. Grade THD Make Length Bottom Top Reamer Shoe 12" L-80 BTC Wfd 3.60 9,107.70 9,104.10 ' 1 9-5/8" 47# L-80 DWC 80.58 9,104.10 9,023.52 F.Collar/jt Wfd 1.48 9,023.52 9,022.04 192 jts 9-5/8" 47# L-80 DWC 7,590.04 9,022.04 1,432.00 L Hanger 10-3/4" 65# L-80 BTC BOT 115.86 1,432.00 1,316.14 V Bullet seal asst' 10-3/4" 65# L-80 BTC BOT 4.45 _ 1,316.14 1,311.69 33 jts 9-5/8" 47# L-80 DWC 1,233.63 1,311.69 78.06 Hanger Seaboard 0.95 78.06 77.11 Totals 9,030.59 Csg Wt.On Hook 150k Type Float Collar: Float No Hrs to Run: 9 Csg Wt.On Hgr: 56k Type of Shoe: Reamer/Float Casing Crew: Wfd Fluid Description: 9.6 ppg WBM/2%KCI YP=20, PV=17 Liner hanger Info(Make/Model): Baker Hughes Flex Lock-10-3/4"65.5# Liner top Packer?: Ye(_No Liner hanger test pressure: 500 psi(Max of 13-3/8"casing) Centralizer Placement: centralizers on every joint in shoe track,every other joint to 4000' CEMENTING REPORT Preflush(Spacer) Type: Mud Push II Density(ppg) 10.5 Volume pumped(BBLs) 72 Lead Slurry Type: LiteCRETE Yield: 2.45 ft3/sk Density(ppg) 12.0 ppg Vol pumped(BBLs/sx) 383 bbls/877 sx Mixing/Pumping Rate(bpm): 4 Tail Slurry Type: EasyBLOK Yield: 1.39 ft3/sk l Density(ppg) 15.8 ppg Vol pumped(BBLs) 82 bbls/331 sx Mixing/Pumping Rate(bpm): 4 I- Post Flush(Spacer) Type: Density(ppg) Rate(bpm): Volume: i Li Displacement: Type: Mud Density(ppg) 9.5 Rate(bpm): 8 bpm Volume(actual/calculated): 272/660 FCP(psi): 4950 psi Pump used for disp: Rig pumps Plug Bumped? Yes X No Bump press 0 Casing Rotated? Yes X No Reciprocated? Yes X No %Returns during job 0% Cement returns to surface? Yes X No Spacer returns? Yes X No Vol to Surf: None` Cement In Place At: 19:30 hrs Date: 1/24/2013 Estimated TOC: Method Used To Determine TOC: Calculation Preflush(Spacer) Type: Density(ppg) Volume pumped(BBLs) Lead Slurry Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tail Slurry Lu Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): ~ Post Flush(Spacer) 0 o Type: Density(ppg) Rate(bpm): Volume: LuDisplacement: Type: Density(ppg) Rate(bpm): Volume(actual/calculated): FCP(psi): Pump used for disp: Plug Bumped? Yes No Bump press Casing Rotated? Yes No Reciprocated? Yes No %Returns during job Cement returns to surface? Yes No Spacer returns? Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Hilcorp Energy Company CASING & CEMENTING REPORT Lease&Well No. M-31 B Date 11-Feb-13 County Cook Inlet State Alaska Supv. Marvin Rogers/Joe McInnis CASING RECORD TD 11,550'MD Shoe Depth: 11,548'MD PBTD: Casing(Or Liner)Detail Setting Depths No.of Jts. Size Wt. Grade THD Make Length Bottom Top Reamer Shoe 7.62" L-80 VT HC BOT 3.57 11,548.00 11,544.43 2 7" 26# L-80 VT HC VAM TOP 82.55 11,544.43 11,461.88 F.Collar/jt 7.62" IL-80 VT HC BOT 1.85 11,461.88 11,460.03 1 jt 7" 26# L-80 VT HC VAM TOP 41.22 11,460.03 11,418.81 Landing collar Insert 0 0 0 BOT 0.00 11,418.81 11,418.81 60 Jts 7" 26# L-80 VT HC VAM TOP 2,473.84 11,418.81 8,944.97 Liner Hanger 9-5/8" 26# L-80 VT HC BOT 25.25 8,944.97 8,919.72 Totals 2,628.28 Csg Wt.On Hook: 150k Type Float Collar: Float No. Hrs to Run: 9 Csg Wt.On Hgr: 56k Type of Shoe: Reamer/Float Casing Crew: Weatherford Fluid Description: 9.6 ppg WBM/2%KCI YP=20,PV=17 Liner hanger Info(Make/Model): Baker Hughes Flex Lock III-7"X 9.6" 65.5# Liner top Packer?: x Yes No Liner hanger test pressure: 1500 psi Centralizer Placement: centralizers on shoe track and every jt to 9766',and every jt f/9725't/9314'[Total=53] CEMENTING REPORT Preflush(Spacer) Type: Mud Push II Density(ppg) 12 Volume pumped(BBLs) 50 Lead Slurry Type: G-Bend Yield: 1.33 ft3/sk Density(ppg) 15.6 ppg Vol pumped(BBLs/SX) 54 bbl/227 sx Mixing/Pumping Rate(bpm): 3.5 Tail Slurry Type: EasyBLOK Yield: 1.33 ft3/sk I Density(ppg) 15.6 ppg Vol pumped(BBLs) 122 bbl/515 sx Mixing/Pumping Rate(bpm): 3.5 1- Post Flush(Spacer) Type: FIW Density(ppg) 8.6 Rate(bpm): 3.5 Volume: 5 re Displacement: Type: Mud Density(ppg) 9.5 Rate(bpm): 6 BPM Volume(actual/calculated): 183/245 FCP(psi): 5000 Pump used for disp: Rig pumps/Schlum Plug Bumped? Yes X No Bump press 0 Casing Rotated? Yes X No Reciprocated? X Yes No %Returns during job 100% . Cement returns to surface? Yes X No Spacer returns? Yes X No Vol to Surf: None Cement In Place At: 0600 hrs Date: 2/11/2013 Estimated TOC: 8910' Method Used To Determine TOC: Calculation Preflush(Spacer) Type: Density(ppg) Volume pumped(BBLs) Lead Slurry Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tail Slurry Li, Type: a Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): N Post Flush(Spacer) 0 o Type: Density(ppg) Rate(bpm): Volume: w Displacement: Type: Density(ppg) Rate(bpm): Volume(actual/calculated): FCP(psi): Pump used for disp: Plug Bumped? Yes No Bump press Casing Rotated? Yes No Reciprocated? Yes No %Returns during job Cement returns to surface? Yes No Spacer returns? Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: ., , .. . Casing Tally Tubular Information: Casing Size: 9.625' AFE Number: 1213057 Well: M-31B Start Date: 1/22/2013 Field: Trading Bay Start Time: 1400 Platform: Steelhead Date Landed: 1/29/2013 Foreman: Hauck/Brumley/Chanley Time Landed: 0500 Rig: 51 Up-Weight: 500K main string, 120K on tieback Completion Fluid Weight(PPG): 9.6 Slack-off : 300K main string, 120K on tieback Completion Fluid Type: Weight set on Mandrel HGR: 60K Wellhead Make: FMC Unihead Current Rig KB Elevation: 77.11 Original Rig KB Elevation: 77.11 Item .It Description ID" OD" LENGTH Total TOP BTM. (in) (in) (ft) Length (ft) (ft) Hole TD a 9425 9,107.70 9,107.70 A Reamer Shoe 12.000 3.6 3.60 9,104.10 9,107.70 1 1 Joint,9 5/8,474,L-80,DWC/C cent 40.13 43.73 9,063.97 9,104.10 2 265 Joint,9 5/8,474,L-80,DWC/C cent 40.45 84.18 9,023.52 9,063.97 B Float 3.000 10.625 1.48 85.66 9,022.04 9,023.52 3 3 Joint,9 5/8,474,L-80,DWC/C cent 9.625 40.72 126.38 8,981.32 9,022.04 4 264 Joint,9 5/8,47#,L-80,DWC/C 9.625 39.19 165.57 8,942.13 8,981.32 5 263 Joint,9 5/8,47#,L-80,DWC/C 9.625 39.45 205.02 8,902.68 8,942.13 6 262 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 36.82 241.84 8,865.86 8,902.68 7 261 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.38 282.22 8,825.48 8,865.86 8 260 Joint,9 5/8,47#,L-80,DWC/C 9.625 39.28 321.50 8,786.20 8,825.48 9 259 Joint,9 5/8,474,L-80,DWC/C cent 9.625 37.92 359.42 8,748.28 8,786.20 10 258 Joint,9 5/8,474,L-80,DWC/C 9.625 40.5 399.92 8,707.78 8,748.28 11 257 Joint,9 5/8,474,L-80,DWC/C 9.625 40.71 440.63 8,667.07 8,707.78 12 2.56 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 39.58 480.21 8,627.49 8,667.07 13 255 Joint,9 5/8,474,L-80,DWC/C 9.625 36.91 517.12 8,590.58 8,627.49 14 254 Joint,9 5/8,474,L-80,DWC/C 9.625 37.89 555.01 8,552.69 8,590.58 15 253 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 36.82 591.83 8,515.87 8,552.69 16 252 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.27 632.10 8,475.60 8,515.87 17 251 Joint,9 5/8,474,L-80,DWC/C 9.625 40.55 672.65 8,435.05 8,475.60 18 250 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 39.65 712.30 8,395.40 8,435.05 19 249 Joint,9 5/8,474,L-80,DWC/C 9.625 36.44 748.74 8,358.96 8,395.40 20 248 Joint,9 5/8,47#,L-80,DWC/C 9.625 38.03 786.77 8,320.93 8,358.96 21 247 Joint,9 5/8,474,L-80,DWC/C cent 9.625 40.09 826.86 8,280.84 8,320.93 22 246 Joint,9 5/8,474,L-80,DWC/C 9.625 40.34 867.20 8,240.50 8,280.84 23 245 Joint,9 5/8,474,L-80,DWC/C 9.625 38.38 905.58 8,202.12 8,240.50 24 244 Joint,9 5/8,474,L-80,DWC/C cent 9.625 40.29 945.87 8,161.83 8,202.12 25 243 Joint,9 5/8,474,L-80,DWC/C 9.625 36.98 982.85 8,124.85 8,161.83 26 242 Joint,9 5/8,474,L-80,DWC/C 9.625 38.61 1,021.46 8,086.24 8,124.85 27 241 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 37.86 1,059.32 8,048.38 8,086.24 28 240 Joint,9 5/8,47#,L-80,DWC/C 9.625 37.8 1,097.12 8,010.58 8,048.38 29 239 Joint,9 5/8,474,L-80,DWC/C 9.625 38.33 1,135.45 7,972.25 8,010.58 30 238 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 36.72 1,172.17 7,935.53 7,972.25 31 237 Joint,9 5/8,474,L-80,DWC/C 9.625 39.85 1,212.02 7,895.68 7,935.53 32 236 Joint,9 5/8,47#,L-80,DWC/C 9.625 37.7 1,249.72 7,857.98 7,895.68 33 235 Joint,9 5/8,474,L-80,DWC/C cent 9.625 39.99 1,289.71 7,817.99 7,857.98 34 234 Joint,9 5/8,474,L-80,DWC/C 9.625 37.62 1,327.33 7,780.37 7,817.99 35 233 Joint,9 5/8,47#,L-80,DWC/C 9.625 39.48 1,366.81 7,740.89 7,780.37 36 232 Joint,9 5/8,474,L-80,DWC/C cent 9.625 39.75 1,406.56 7,701.14 7,740.89 37 231 Joint,9 5/8,474,L-80,DWC/C 9.625 40.35 1,446.91 7,660.79 7,701.14 38 230 Joint,9 5/8,47#,L-80,DWC/C 9.625 39.46 1,486.37 7,621.33 7,660.79 39 229 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 40.34 1,526.71 7,580.99 7,621.33 40 228 Joint,9 5/8,47#,L-80,DWC/C 9.625 38.07 1,564.78 7,542.92 7,580.99 41 227 Joint,9 5/8,474,L-80,DWC/C 9.625 39.39 1,604.17 7,503.53 7,542.92 42 226 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 37.63 1,641.80 7,465.90 7,503.53 43 225 Joint,9 5/8,47#,L-80,DWC/C 9.625 38.71 1,680.51 7,427.19 7,465.90 44 224 Joint,9 5/8,47#,L-80,DWC/C 9.625 37.49 1,718.00 7,389.70 7,427.19 45 223 Joint,9 5/8,474,L-80,DWC/C cent 9.625 37.36 1,755.36 7,352.34 7,389.70 46 222 Joint,9 5/8,47#,L-80,DWC/C 9.625 38 1,793.36 7,314.34 7,352.34 47 221Joint,9 5/8,47#,L-80,DWC/C 9.625 40.49 1,833.85 7,273.85 7,314.34 48 220�Joint,9 5/8,47#,L-80,DWC/C cent 9.625 40.38 1,874.23 7,233.47 7,273.85 49 219 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.26 1,914.49 7,193.21 7,233.47 50 218 Joint,9 5/8,474,L-80,DWC/C 9.625 40.33 1,954.82 7,152.88 7,193.21 51 217 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 39.85 1,994.67 7,113.03 7,152.88 52 216 Joint,9 5/8,474,L-80,DWC/C 9.625 40.22 2,034.89 7,072.81 7,113.03 53 215 Joint,9 5/8,47#,L-80,DWC/C 9.625 36.56 2,071.45 7,036.25 7,072.81 54 214 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 40.3 2,111.75 6,995.95 7,036.25 55 213 Joint,9 5/8,47#,L-80,DWC/C 9.625 37.09 2,148.84 6,958.86 6,995.95 56 212 Joint,9 5/8,474,L-80,DWC/C 9.625 40.58 2,189.42 6,918.28 6,958.86 57 211 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 40.48 2,229.90 6,877.80 6,918.28 58 210_Joint,9 5/8,47#,L-80,DWC/C 9.625 37.75 2,267.65 6,840.05 6,877.80 59 209 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.59 2,308.24 6,799.46 6,840.05 60 208 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 39.48 2,347.72 6,759.98 6,799.46 61 207 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.42 2,388.14 6,719.56 6,759.98 62 206 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.34 2,428.48 6,679.22 6,719.56 63 205 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 40.7 2,469.18 6,638.52 6,679.22 64 204 'Joint,9 5/8,47#,L-80,DWC/C 9.625 39.94 2,509.12 6,598.58 6,638.52 65 203 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.13 2,549.25 6,558.45 6,598.58 66 202 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 40.57 2,589.82 6,517.88 6,558.45 67 201 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.27 2,630.09 6,477.61 6,517.88 68 200 Joint,9 5/8,47#,L-80,DWC/C 9.625 36.34 2,666.43 6,441.27 6,477.61 69 199 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 40.56 2,706.99 6,400.71 6,441.27 70 198 ,Joint,9 5/8,47#,L-80,DWC/C 9.625 39.61 2,746.60 6,361.10 6,400.71 71 197 Joint,9 5/8,47#,L-80,DWC/C 9.625 39.51 2,786.11 6,321.59 6,361.10 72 196 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 40.16 2,826.27 6,281.43 6,321.59 73 195 Joint,9 5/8,47#,L-80,DWC/C 9.625 39.38 2,865.65 6,242.05 6,281.43 74 194 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.36 2,906.01 6,201.69 6,242.05 75 193 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 39.05 2,945.06 6,162.64 6,201.69 76 192 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.32 2,985.38 6,122.32 6,162.64 77 191 Joint,9 5/8,47#,L-80,DWC/C 9.625 39.52 3,024.90 6,082.80 6,122.32 78 190 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 40.15 3,065.05 6,042.65 6,082.80 79 189 Joint,9 5/8,474,L-80,DWC/C 9.625 37.92 3,102.97 6,004.73 6,042.65 80 188 Joint,9 5/8,47#,L-80,DWC/C 9.625 39.01 3,141.98 5,965.72 6,004.73 81 187 Joint,9 5/8,474,L-80,DWC/C cent 9.625 39.72 3,181.70 5,926.00 5,965.72 82 186 Joint,9 5/8,47#,L-80,DWC/C 9.625 36.14 3,217.84 5,889.86 5,926.00 83 185 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.30 3,258.14 5,849.56 5,889.86 84 184 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 37.11 3,295.25 5,812.45 5,849.56 85 183 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.28 3,335.53 5,772.17 5,812.45 86 182_Joint,9 5/8,47#,L-80,DWC/C 9.625 40.45 3,375.98 5,731.72 5,772.17 87 181 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 37.25 3,413.23 5,694.47 5,731.72 88 180 Joint,9 5/8,47#,L-80,DWC/C 9.625 37.42 3,450.65 5,657.05 5,694.47 89 179 Joint,9 5/8,47#,L-80,DWC/C 9.625 39.64 3,490.29 5,617.41 5,657.05 90 178 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 40.18 3,530.47 5,577.23 5,617.41 91 177 Joint,9 5/8,474,L-80,DWC/C 9.625 40.20 3,570.67 5,537.03 5,577.23 92 176 Joint,9 5/8,474,L-80,DWC/C 9.625 40.25 3,610.92 5,496.78 5,537.03 93 175_Joint,9 5/8,47#,L-80,DWC/C cent 9.625 40.30 3,651.22 5,456.48 5,496.78 94 174 Joint,9 5/8,474,L-80,DWC/C 9.625 40.49 3,691.71 5,415.99 5,456.48 95 173 Joint,9 5/8,474,L-80,DWC/C 9.625 38.26 3,729.97 5,377.73 5,415.99 96 172 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 37.84 3,767.81 5,339.89 5,377.73 97 171 Joint,9 5/8,47#,L-80,DWC/C 9.625 38.11 3,805.92 5,301.78 5,339.89 98 170 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.32 3,846.24 5,261.46 5,301.78 99 169 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 37.70 3,883.94 5,223.76 5,261.46 100 168 Joint,9 5/8,47#,L-80,DWC/C 9.625 36.89 3,920.83 5,186.87 5,223.76 101 167 Joint,9 5/8,47#,L-80,DWC/C 9.625 39.70 3,960.53 5,147.17 5,186.87 102 166 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 35.71 3,996.24 5,111.46 5,147.17 103 165 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.10 4,036.34 5,071.36 5,111.46 104 164 Joint,9 5/8,47#,L-80,DWC/C 9.625 39.53 4,075.87 5,031.83 5,071.36 105 163 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 36.44 4,112.31 4,995.39 5,031.83 106 162 Joint,9 5/8,47#,L-80,DWC/C 9.625 39.63 4,151.94 4,955.76 4,995.39 107 161 Joint,9 5/8,474,L-80,DWC/C 9.625 37.22 4,189.16 4,918.54 4,955.76 108 160 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 39.41 4,228.57 4,879.13 4,918.54 109 159 Joint,9 5/8,474,L-80,DWC/C 9.625 36.25 4,264.82 4,842.88 4,879.13 110 158 Joint,9 5/8,474,L-80,DWC/C 9.625 39.30 4,304.12 4,803.58 4,842.88 111 157 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 39.50 4,343.62 4,764.08 4,803.58 112 156 Joint,9 5/8,474,L-80,DWC/C 9.625 40.81 4,384.43 4,723.27 4,764.08 113 155 Joint,9 5/8,474,L-80,DWC/C 9.625 40.32 4,424.75 4,682.95 4,723.27 114 154 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 40.52 4,465.27 4,642.43 4,682.95 115 153 Joint,9 5/8,47#,L-80,DWC/C 9.625 39.80 4,505.07 4,602.63 4,642.43 116 152 Joint,9 5/8,47#,L-80,DWC/C 9.625 36.92 4,541.99 4,565.71 4,602.63 117 151 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 40.38 4,582.37 4,525.33 4,565.71 118 150 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.10 4,622.47 4,485.23 4,525.33 119 149 Joint,9 5/8,474,L-80,DWC/C 9.625 37.49 4,659.96 4,447.74 4,485.23 120 148 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 37.58 4,697.54 4,410.16 4,447.74 121 147 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.25 4,737.79 4,369.91 4,410.16 122 146 Joint,9 5/8,47#,L-80,DWC/C 9.625 39.95 4,777.74 4,329.96 4,369.91 123 145 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 40.86 4,818.60 4,289.10 4,329.96 _ 124 144 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.85 4,859.45 4,248.25 4,289.10 125 143 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.94 4,900.39 4,207.31 4,248.25 126 142 Joint,9 5/8,47#,L-80,DWC/C cent 9.625 40.63 4,941.02 4,166.68 4,207.31 127 141 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.56 4,981.58 4,126.12 4,166.68 128 140 Joint,9 5/8,474,L-80,DWC/C 9.625 40.47 5,022.05 4,085.65 4,126.12 129 139 Joint,9 5/8,474,L-80,DWC/C 9.625 40.28 5,062.33 4,045.37 4,085.65 130 138 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.04 5,102.37 4,005.33 4,045.37 131 137 Joint,9 5/8,474,L-80,DWC/C 9.625 40.91 5,143.28 3,964.42 4,005.33 132 136 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.50 5,183.78 3,923.92 3,964.42 133 135 Joint,9 5/8,474,L-80,DWC/C 9.625 40.89 5,224.67 3,883.03 3,923.92 134 134 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.65 5,265.32 3,842.38 3,883.03 135 133 Joint,9 5/8,474,L-80,DWC/C 9.625 40.85 5,306.17 3,801.53 3,842.38 136 132 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.82 5,346.99 3,760.71 3,801.53 137 131 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.56 5,387.55 3,720.15 3,760.71 138 130 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.91 5,428.46 3,679.24 3,720.15 139 129 Joint,9 5/8,474,L-80,DWC/C 9.625 40.31 5,468.77 3,638.93 3,679.24 140 128 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.82 5,509.59 3,598.11 3,638.93 141 127 Joint,9 5/8,47#,L-80,DWC/C 9.625 40.70 5,550.29 3,557.41 3,598.11 142 126 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.62 5,590.91 3,516.79 3,557.41 143 125 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 39.87 5,630.78 3,476.92 3,516.79 144 124 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.75 5,671.53 3,436.17 3,476.92 145 123 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 40.03 5,711.56 3,396.14 3,436.17 146 122 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.24 5,751.80 3,355.90 3,396.14 147 121 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.58 5,792.38 3,315.32 3,355.90 148 120 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 39.78 5,832.16 3,275.54 3,315.32 149 119 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.49 5,872.65 3,235.05 3,275.54 150 118 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 39.82 5,912.47 3,195•.23 3,235.05 151 117 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 39.23 5,951.70 3,156.00 3,195.23 152 116 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 39.79 5,991.49 3,116.21 3,156.00 153 115 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 39.52 6,031.01 3,076.69 3,116.21 154 114 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.50 6,071.51 3,036.19 3,076.69 155 113 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 38.91 6,110.42 2,997.28 3,036.19 156 112 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.40 6,150.82 2,956.88 2,997.28 157 111 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.73 6,191.55 2,916.15 2,956.88 158 110 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.02 6,231.57 2,876.13 2,916.15 159 109 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 38.10 6,269.67 2,838.03 2,876.13 160 108 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 37.74 6,307.41 2,800.29 2,838.03 161 - 107 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.73 6,348.14 2,759.56 2,800.29 162 106 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.82 6,388.96 2,718.74 2,759.56 163 105 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.16 6,429.12 2,678.58 2,718.74 164 104 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 39.15 6,468.27 2,639.43 2,678.58 165 103 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.22 6,508.49 2,599.21 2,639.43 166 102 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 40.60 6,549.09 2,558.61 2,599.21 167 101 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.65 6,589.74 2,517.96 2,558.61 168 100 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.43 6,630.17 2,477.53 2,517.96 169 99 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.19 6,670.36 2,437.34 2,477.53 170 98 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 39.23 6,709.59 2,398.11 2,437.34 171 97 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.74 6,750.33 2,357.37 2,398.11 172 96 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 40.70 6,791.03 2,316.67 2,357.37 173 95 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.45 6,831.48 2,276.22 2,316.67 174 94 Joint,9 5/8,474,L-80,DWC/C • 8.681 9.625 40.30 6,871.78 2,235.92 2,276.22 175 93 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 40.69 6,912.47 2,195.23 2,235.92 176 92 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.49 6,952.96 2,154.74 2,195.23 177 91 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.26 6,993.22 2,114.48 2,154.74 178 90 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 39.83 7,033.05 2,074.65 2,114.48 179 89 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 40.50 7,073.55 2,034.15 2,074.65 180 88 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 38.38 7,111.93 1,995.77 2,034.15 181 87 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 40.69 7,152.62 1,955.08 1,995.77 182 86 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 39.87 7,192.49 1,915.21 1,955.08 183 85 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.67 7,233.16 1,874.54 1,915.21 184 84 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 39.59 7,272.75 1,834.95 1,874.54 185 83 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 38.79 7,311.54 1,796.16 1,834.95 186 82 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.18 7,351.72 1,755.98 1,796.16 187 81 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.55 7,392.27 1,715.43 1,755.98 188 80 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.62 7,432.89 1,674.81 1,715.43 189 79 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.44 7,473.33 1,634.37 1,674.81 190 78 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.54 7,513.87 1,593.83 1,634.37 191 77 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.26 7,554.13 1,553.57 1,593.83 192 76 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.60 7,594.73 1,512.97 1,553.57 193 75 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.55 7,635.28 1,472.42 1,512.97 194 74 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 40.42 7,675.70 1,432.00 1,472.42 4 • Triple connect sub(Tie back sub)(has 11 3/4 Wash pipe 1,432.00 195 skirt on bottom,total length with overshot @ 4.65) 8.681 11.750 1.25 7,676.95 1,430.75 196 1 Joint,9 5/8,47#,L-80,DWC/C(new joint) 8.681 9.625 41.29 7,718.24 1,389.46 1,430.75 197 2 Joint,9 5/8,47#,L-80,DWC/C (new joint) 8.681 9.625 38.71 7,756.95 1,350.75 1,389.46 198 Xover, 10 3/4 BTC box X 9 5/8 BTC pin 8.681 11.730 2.10 7,759.05 1,348.65 1,350.75 Baker Flex-Lock Liner Hanger PN: H294-10-0503,10 199 3/4 X 13 3/8,set w/150K string weight on pipe,pulled 1,348.65 2.2 feet of stretch back into pipe before setting 9.710 12.100 9.16 7,768.21 1,339.49 Baker HRD-E ZXP Liner Top Packer: 11296-45-0045, 10 3/4 X 13 3/8,packer element pinned with steel shear 1,339.49 200 pins,not set in well 9.480 12.000 23.35 7,791.56 1,316.14 201 Bullet Seal Assy,effective length above no go 2.45+ 1,316.14 2.00 off packer top 8.650 12.020 4.45 7,796.01 1,311.69 202 3 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.39 7,836.40 1,271.30 1,311.69 203 4 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 39.69 7,876.09 1,231.61 1,271.30 204 5 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.59 7,916.68 1,191.02 1,231.61 205 6 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 39.96 7,956.64 1,151.06 1,191.02 206 7 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 38.55 7,995.19 1,112.51 1,151.06 207 8 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.54 8,035.73 1,071.97 1,112.51 208 9 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.3 8,076.03 1,031.67 1,071.97 209 10 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 37.57 8,113.60 994.10 1,031.67 210 11 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.84 8,154.44 953.26 994.10 211 12 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.78 8,195.22 912.48 953.26 212 13 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.76 8,235.98 871.72 912.48 213 14 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 39.45 8,275.43 832.27 • 871.72 214 15 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.52 8,315.95 791.75 832.27 215 16 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 39.75 8,355.70 752.00 791.75 216 17 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.76 8,396.46 711.24 752.00 217 18 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.68 8,437.14 670.56 711.24 218 19 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.09 8,477.23 630.47 670.56 219 20 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 40.35 8,517.58 590.12 630.47 220 21 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 40.36 8,557.94 549.76 590.12 221 22 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 39.14 8,597.08 510.62 549.76 222 23 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 40.65 8,637.73 469.97 510.62 223 24 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.44 8,678.17 429.53 469.97 224 25 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 40.72 8,718.89 388.81 429.53 225 26 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.76 8,759.65 348.05 388.81 226 27 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 37.6 8,797.25 310.45 348.05 227 28 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 40.33 8,837.58 270.12 310.45 228 29 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.78 8,878.36 229.34 270.12 229 30 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.82 8,919.18 188.52 229.34 230 31 Joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 40.43 8,959.61 148.09 188.52 231 32 Joint,9 5/8,474,L-80,DWC/C 8.681 9.625 40.68 9,000.29 107.41 148.09 232 33 Pup joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 14.6 9,014.89 92.81 107.41 233 34 Pup joint,9 5/8,47#,L-80,DWC/C 8.681 9.625 7.60 9,022.49 85.21 92.81 WH Hanger pup,9 5/8 BTC pin X 9 5/8 DWC pin 8.681 9.625 7.15 9,029.64 78.06 85.21 WH Hanger,casing,FMC,16 3/4 X 9 5/8 BTC 8.681 16.240 0.95 9,030.59 77.11 78.06 RKB 77.11 9,107.70 0.00 77.11 Notes TR3 legacy double bow centerlizers total(44) Pack-off FMC 16-3/4"X 9-5/8"5k installed w/3 turns to the right&tested w/40 k over pull&void test 250-5000 psi ok Primary Cmt job lost returns&pressured up t/5000 psi w/79 bbls out of pipe w\��_�7 THE STATE Alaska Oil and Gas F� = �� °fALAS :A _ __ Conservation Commission _ice - €th-=__ GOVERNOR SEAN PARNELL w 333 West Seventh Avenue OF �m+TM- Q. Anchorage, Alaska 99501-3572 ALAB� Main: 907.279.1433 Fax: 907.276.7542 March 13, 2013 Mr. Chris Myers Field Superintendent Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 RE: No-Flow Verification Trading Bay Unit M-31 B PTD 2121490 Dear Mr. Myers: On March 8, 2013 an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no-flow test of Trading Bay Unit well M-31 B located on the Steelhead Platform in Cook Inlet. The well is operated by Hilcorp Alaska, LLC (Hilcorp). A subsurface safety valve is not required to be installed in this well based on the no-flow test result. 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 AOGCC Inspector confirmed that the proper test equipment — as outlined in AOGCC Industry Guidance Bulletin 10-004 — was rigged up to Trading Bay Unit M-31 B. The no-flow test consisted of a 3-hour monitoring period for flow to surface. During the flow monitoring periods, liquid production was measured at rates less than 6.3 gallons per hour and gas I production was measured at rates less than 900 standard cubic feet per hour. The subsurface safety valve must be returned to service if Trading Bay Unit M-31 B 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 Steelhead Platform. Sincerely, .11tIlifitil K,27.2 , James B. Regg Petroleum Inspection Supervisor cc: P. Brooks AOGCC Inspectors MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg !) �� DATE: March 8,2013 P.I.Supervisor I� G) 13 3 l FROM: Jeff Jones SUBJECT: No-Flow Test Petroleum Inspector Hilcorp/Steelhead Platform TBU M-316 PTD 2121490 Trading Bay Unit March 8,2013: I traveled to Hilcorp's Steelhead Platform in Cook Inlet to witness a No-Flow Test on well M-31 B. On my arrival on the platform I met with Hilcorp Lead Operator Chris Johnson and we discussed the operational details of the test. Mr. Johnson indicated that the well pressure had been bled down and the wellbore was open to the tree cap with no plugs or restrictions. Well M-31B has an electric submersible pump(ESP) installed and was lined up from the tree top swab valve through an Armor-Flow model#3461-03T0 flow meter(180 SCFH to 1800 SCFH span)to a 1"hose which terminated in an open top drum.The flow from the well was monitored for 3 hours and unassisted gas and liquid flow from the well did not exceed 900 SCF or 6.3 gal hourly flow rate during the test.TBU M-31 B meets the AOGCC requirements for a No-Flow status determination. Summary: I witnessed a successful No-Flow Test of Hilcorp's Trading Bay Unit M-31 B on the Steelhead Platform. Attachments: none RJF 09/19/02 Page 1 of 1 No-Flow TBU Steelhead PLT M-31B 3-8-13 JJ.xls Page 1of1 Schwartz, Guy L (DOA) From: Luke Keller[Ikeller@hilcorp.com] Sent: Tuesday, January 22, 2013 4:34 PM To: Schwartz, Guy L(DOA) Cc: Shane Hauck; Paul Mazzolini; Eric Holland-(C) Subject: RE: M-31B(PTD#212-149)9-5/8" Primary Cement Job Guy, We will keep the same cmt formulation—376 bbls lead @ 12 ppg, 80 bbls tail @ 15.3 ppg. We will adjust the retarder concentration a bit on the lead slurry to ensure we can get it in place. Tail slurry will remain the same. ECDs will be below frac gradient at all depths. From: Schwartz, Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent: Tuesday,January 22, 2013 4:23 PM To: Luke Keller Cc: Shane Hauck; Paul Mazzolini; Eric Holland - (C) Subject: RE: M-31B(PTD#212-149) 9-5/8" Primary Cement Job Luke, Thank you for the update... are you making any changes to the cement formulation to ensure the targeted TOC is reached? Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Luke Keller[mailto:Ikeller©hilcorp.com] Sent: Tuesday,January 22, 2013 4:08 PM To: Schwartz, Guy L(DOA) Cc: Shane Hauck; Paul Mazzolini; Eric Holland - (C) Subject: M-31B (PTD#212-149)9-5/8" Primary Cement Job Guy, Due to mechanical issues surrounding our stage collar,we are having to change the primary cement job on our 9-5/8"string of casing from a (2)stage cement job to a single stage cement job. The stage collar will not be run in the string. Our planned TOC is still the same. 9-5/8"casing shoe will be at 9415' MD. TOC is planned at 4000' MD. TOC will be confirmed later with a CBL. Let me know if you have any questions with regards to this change from the approved drilling permit. Thanks, Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 1/23/2013 OF T • • (K\ ��yy� s THE STATE Alaska Oil and Gas ALASKAConservation Commission owl *M1„ GOVERNOR SEAN PARNELL 333 West Seventh Avenue Off. P. Anchorage, Alaska 99501-3572 LAa� Main: 907.279.1433 Fax: 907.276.7542 Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive Anchorage, AK 99524 Re: McArthur River Field, Middle Kenai G Oil & Hemlock Oil Pool, TBU M-31B Hilcorp Alaska, LLC Permit No: 212-149 Surface Location: 970' FNL, 516' FWL, SEC. 33, T9N, R13W, SM Bottomhole Location: 2554' FSL, 1769' FWL, SEC. 33, T9N, R13W, SM Dear Mr. Keller: Enclosed is the approved application for permit to re-drill the above referenced development well. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce is contingent upon issuance of a conservation order approving a spacing exception. Hilcorp Alaska, LLC assumes the liability of any protest to the spacing exception that may occur. 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 Commission 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 Commission 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 a Commission order, or the terms and conditions of this permit may result in the revocatio or suspension of the permit. Sinc-r:1 J. t n orman Commissioner DATED this f day of November, 2012. cc: Department of Fish & Game, Habitat Section w/o encl. (via e-mail) Department of Environmental Conservation w/o encl. (via e-mail) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISsiON PERMIT TO DRILL 20 AAC 25.005 1a Type of Work: lb.Proposed Well Class: Development-Oil p Service- Winj ❑ Single Zone El 1c.Specify if well is proposed for: Drill ❑ Lateral ❑ Stratigraphic Test ❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone ❑ Coalbed Gas El Gas Hydrates ❑ Redrill Q Reentry❑ Exploratory ❑ Service- WAG ❑ Service-Disp ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket Q Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC Bond No. 22035244 Trading Bay Unit M-31B 3 Address: 6.Proposed Depth: / 12.Field/Pool(s): 3800 Centerpoint Drive,Anchorage AK,99524 MD: I/5-'13 TVD: VO35 iv.iL 4a Location of Well(Governmental Section): 7.Property Designation(Lease Number):Ip' r0' G Oil&Hemlock Oil Pool Surface: 970'FNL,516'FWL,Sec 33,T9N,R13W,S . Steelhead(ADL0018730) Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 976'FNL,1692'FWL,Sec 33,T9N,R13W,S NA 11/1/2012 Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 2554'FSL,1769'FWL,Sec 33,T9N,R13W,S 5116 879' 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL: /66 feet 15.Distance to Nearest Well Open Surface: x-?14241 "' y- 2499532 • Zone-4 GL Elevation above MSL: 0/ fee to Same Pool: G-24(100') yr 4 � 4- �,, '.,'2 16 Deviated wells: 17 y Kickoff depth: 3722 feet , 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) /c' Maximum Hole Angle: 71.5 degrees . Downhole: 3648 psig • Surface: 2665 psig • 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) 12-1/4" 9-5/8" 47# L-80 DWC/C 9364 0 0 9364 8700 2557 ft3(2 stages,2 slurry densities) 8-1/2" 7" 26# L-80 VAM TOP 2443 9100 8453 11543 9835 535 ft3(Single slurry,15.6 ppg) 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth TVD(ft): Plugs(measured): Effect.Depth MD(ft): Effect.Depth TVD(ft): Junk(measured): Casing Length Size Cement Volume MD TVD Conductor/Structural 1345 16" 1415 sx 13.2 ppg,614 sx 15.8 ppg 1345 1344 Surface 3722 13-3/8" 1600 sx 13.2 ppg,600 sx 16.2 ppg 3722 3524 Production 9852 9-5/8" 1650 sx 13 ppg,530 sx 15.8 ppg 9927 8678 2792 7-5/8" 9480 8272 Tapered Liner 1935 7" 1516 sx 15.3 ppg 11415 9153 Perforation Depth MD(ft): NA Perforation Depth TVD(ft): NA 20 Attachments: Property Plat Q BOP Sketch ❑ Drilling Program Q Time v.Depth Plot Q Shallow Hazard Analysis Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program ❑ al te0E5p r i t 21. Verbal Approval: Commission Representative: Date �i� YYY 22 I hereby certify that the foregoing is true and correct. Contact 0 C T 0 4 2012 /, //4 ,e,%r Drillin En AOGCC Printed Name Title p - $3 q 1/�ee� Signaturelajt• /2& Phone(/ o7) 77! 1S Date 10 /3/ O I�Commission Use Only Permit to Drill //�9 API Number: // Permit Approval 1 See cover letter for other Number: 2! /`0 50-'/,.53 -2c.:7�7 o2_- r.)Date: 1\` 1 I 1 'Z, 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: d 104, s� ,3o f �5. Samples req'd: Yes No[' Mud log req'd:Ye❑ Ni'{ �t / p n I H2S measures: Yes,No❑ Directional svy req'd:Ye['' NO 2 SLY7 /�S� A n K w`°`" ' -S� Spacing exception req'd: Yes 10/ No❑ Inclination-only svy req'd:Ye❑ N1 ' APPROVED BY Approved by Of COMMISSIONER THE COMMISSION Date: /l��L/ /// l Submit Form and A,7 ` // V Form 10-401(Revised 10/2012) This permit is valid for 24 months from the date of approval(20 AAC 25.005(g)) Attachments in Duplicate -1 7L /6) iL 0RIGINAL"F/44- lineup Luke Keller Hilcorp Alaska,LLC 8new"Company Drilling Engineer P.O. Box 244027 Anchorage,AK 99524-4027 Tel 907 777 8395 10/3/2012 Email Ikeller@hilcorp.com Commissioner Alaska Oil&Gas Conservation Commission RECEIVED 333 W. 7th Avenue Anchorage,Alaska 99501 OCT 0 4 2012, Re: Steelhead Platform,Trading Bay Unit M-31 B AOGCC Dear Commissioner, Enclosed for review and approval is the 10-401 "APD"for Trading Bay Unit M-31 B. M-31 B is a development oil well planned to be re-drilled in a SE direction from slot B1-12 utilizing the existing casing program to 3722'. The first attempt at sidetracking the well(M-31A)was unsuccessful. Hole geometry in conjunction with coal instability led to a casing failure which made the wellbore unusable below 10,272'MD. �•�� For the second redrill attempt,the base plan is to cut&pull the 9-5/8"casing down to 3872'(150' e4 A 3i below the 13-3/8"shoe). A 12-1/4"x 5642'open hole section will be drilled and 9-5/8"casing run& cemented. Maximum inclination through this section will be 21 deg. An 8-1/2"x 2179'production hole section will then be drilled and a 7"prod liner run and cemented. This section of the well builds up to 71 deg and holds a tangent to TD. The targets will remain more or less the same as previous redrill(Several targets through both the G- . zone and Hemlock formations). The BHL was moved 300'West to allow for more efficient wellbore . geometry. Slot recovery operations are expected to commence approximately Nov 1st, 2012 depending on the progress of other ongoing projects on the Steelhead platform. A separate 10-403 sundry notice will be submitted to P&A the current M-31 A wellbore. If you have any questions, please don't hesitate to contact myself at 777-8395 or Paul Mazzolini at 777-8369. Sincerely, Luke Keller Drilling Engineer Hilcorp Alaska,LLC Page 1 of 1 Steelhead Platform 11 SCHEMATIC WELL#: M-31A uu<ap.alu�Iwi.i.c Existing WBD 10/9/2012 TBG Hanger 74.5'below Casing Detail SIZE WT GRADE CONN ID TOP BTM. 26"j26 267 thru 397# Drill Quip Surf 979' 16" 16 75 K-55 BTC 15.124 Surf 1,345' 13 3/8 61&68 K-55 BTC 12.415 Surf 3,722' 9 5/8" 47 L-80 BTC 8.681 Surf 6,890' 13-3/8"` 4 7-5/8"liner 29.7 L-80 VAM SLID-II 6.875 6,688' 9,480' "/`' A,-' 7"liner 26 L-80 VAM SLIJ-II 6.276 9,480 11,415' Jewelry Detail NO Depth Length ID OD Item 1 6,688' 7-5/8"Liner Hangar 2 9,480' 1' 6.188" XO 7"x 7-5/8" 3 10,192' Cement Retainer - IN 1 . 9-5/8"Window:6,890'(MD)to 6,907'(MD) 9-5/8" if) ) x 7-5/8" 2 ..14: TOC 9,972'MD Calculated 7„ 3Y Drilled outside of Casing±10,272' To 10,300'MD I TD:11,435'MD/9,160'TVD REVISED: 10-9-2012 REVISED BY: LEK int Steelhead Platform Well M-31B Hilcorp Well Design Summary new ornpuni U10 pLertgi-t4A - M-31 B Well Design Summary icoli.1z- M-31 B is a development oil well planned to be re-drilled in a SE direction from slot B1-12 utilizing the existing casing program to 3722'. The first attempt at sidetracking the well was unsuccessful. Hole geometry in conjunction with coal instability led to a casing failure which made the wellbore unusable below 10,272' MD. For the second redrill attempt, the base plan is to cut & pull the 9-5/8" casing down to 3872' (150' below the 13-3/8" shoe). A 12-1/4" x 5642' open hole section will be drilled and 9-5/8" casing run & cemented. Maximum inclination through this section will be 21 deg. An 8-1/2" x 2179' production hole section will then be drilled and a 7" prod liner run and cemented. This section of the well builds up to 71 deg and holds a tangent to TD. The targets will remain more or less the same as previous redrill (Several targets through both the G-zone and Hemlock formations). The BHL was moved 300' West to allow for more efficient wellbore geometry. No H2S is expected to be encountered during the drilling & completion of M-31 B. The well will be completed with a 3-1/2" ESP assembly. Well will be drilled using Steelhead Rig 51. The Drilling Contractor utilized for the labor contract is Kuukpik. Basic Well Information Platform: Steelhead Well Name: M-31B Estimated Spud Date: 11/1/2012 Field: McArthur River Productive Horizon: G-zone & Hemlock Total Depth: 11,543' MD / 9835' TVD Slot: Slot B1-12, NW Leg KB Elevation: 160' AMSL KB to WH: 75' 10/11/2012 Page 1 of 13 Steelhead Platform Well M-31B Hilcorp Well Design Summary 1.n.' (,Mnpvn Well Coordinates: Surface Location: 970' FNL, 516' FWL, Sec 33, T9N, R13W, S X=214140.49, Y=2499532.17, NAD27, ASP, Zone 4 Top of Prod Horizon: 976' FNL, 1692' FWL, Sec 33, T9N, R13W, S X= 215310.06, Y= 2499497.03, NAD27, ASP, Zone 4 Planned BHL: 2554' FSL, 1769' FWL, Sec 33, T9N, R13W, S X= 215347.22, Y= 2497745.80, NAD27, ASP, Zone 4 Existing M-31A Casing Design Hole Tube Weight Length Top Btm Size (in) O.D. (lbs / ft) Grade Conn (ft) MD/TVD MD/TVD (in) (ft) (ft) Driven 26 267 X-56 Drill-Quip 904 WH 979 24 16 75 K-55 BTC 1270 WH 1345/1344 17-1/2 13 3/8 61 K-55 BTC 3647 WH 3722/3524 / 12-1/4 9 5/8 47 L-80 BTC-M 6890 WH 6890/6230 9-1/2 7-5/8 29.7 L-80 Hydril 2792 6688/6050 9480/8275 523 - 7" 26 L-80 BTC-M 8675 9480/8275 11,415/9152 Planned M-31 B Casing & Tubing Design Hole Size O De Weight Grade Conn Length MD/TVDp / Btm MD/TVD (in) (in) (lbs / ft) (ft) (ft) (ft) 12-1/4" 9-5/8" 47# L-80 Dwc/c 9364 WH 9364/8700 8-1/2" 7 26 L-80 VAM 2443 9100/8453 11,543/9835 TOP HC All casing will be new, PSI. 1 (100%mill inspected, 10%inspection upon delivery to TSA in Fairbanks) 10/11/2012 Page 2 of 13 Steelhead Platform Well M-31B Hilcorp Well Design Summary i'nwe,compawy Well Control Summary Hole Section Equipment Test Pressure (psi) • 16-3/4" Hydril GK 5M annular • 16-3/4" 5M Cameron U Double gate Casin o 5" Fixed ram g o Blind ram in btm cavity Test Pressures: Recovery & • Mud cross 250/4000 12-1/4" (Annular 250/2500 psi) • 16-3/4" 5M Cameron U single gate o 9-5/8" csg ram. • 3-1/16" 5M Choke Manifold. • 16-3/4" Hydril GK 5M annular • 16-3/4" 5M Cameron U Double gate o 5" Fixed ram „ o Blind ram in btm cavity Test Pressures: 8-1/2 • Mud cross 250/4000 • 16-3/4" 5M Cameron U single gate (Annular 250/2500 psi) o 7" casing ram. • 3-1/16" 5M Choke Manifold • 16-3/4" Hydril GK 5M annular • 16-3/4" 5M Cameron U Double gate o 5" Fixed ram o Blind ram in btm cavity Test Pressures: Completion • Mud cross 250/4000 • 16-3/4" 5M Cameron U single gate (Annular 250/2500 psi) o 3-1/2" fixed ram • 3-1/16" 5M Choke Manifold Schematics of the well control equipment are attached for reference. Well control equipment will be tested every 14 days. 10/11/2012 Page 3 of 13 Steelhead Platform Well M-31B Hilcorp Well Design Summary 'new c, p.r, Anti-Collision Evaluation Summary The revised directional plan (P12) eliminates the anti-collision issues with offset wellbores that existed on the first attempt at the M-31A wellbore. Other than the existing wellbore, there are no anti-collision issues. M-31 B will be drilled using a mud motor and MWD. Surveys will be taken every 95' while drilling. Formation Integrity Testing Test Point, Projected Test Fluid Density Projected Projected 20' Below... Depth (TVD) Type Used for Test Test (EMW Surface ppg) Pressure 9-5/8" Shoe 8700' FIT 9.5 12 1131 psi Note:Anticipated fracture gradient at the 9-5/8"shoe depth(8700'TVD)is expected to be btwn.75 and.83 psi/ff(14.4- 15.9 ppg)based on offset field test data. An FIT of 12 ppg was chosen to allow for a(2.5)ppg(or 1131 psi)kick margin while drilling with a 9.5 ppg fluid density. Casing Testing Fluid Density in Test String Casing Pressure Test Duration Casing Burst (PSI) 13-3/8" Casing 9.5 ppg 1500 30 min 3090 psi 9-5/8" Casing 9.5 ppg 1500 30 min 6870 psi 7" Liner 9.5 ppg 1500 30 min 7240 psi All casing tests will be held for 30 min. If pressure declines more than 10%in 30 min,corrective action must be taken. 10/11/2012 Page 4 of 13 Steelhead Platform Well M-31B Hilcorp Well Design Summary Mud Program Summary Intermediate Hole Section (12-1/4" hole, 9-5/8" Casing to 9,364' MD / 8,700' TVD) Production Hole Section (8-1/2" hole, 7" Liner to 11,543' MD / 9,835' TVD) Weighting material to be used for the hole section will be Barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. 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: 2% KCI, Clayseal / GEM Water Based Drilling Fluid Properties: Depths Density Viscosity Plastic Viscosity Yield Point HTHP pH 3722— 9.2—9.6 40-53 6-15 13-24 <9 8.5-9.5 11,543 System Formulation: 2% KCl/ CLAYSEAL/ GEM GP Product Concentration Water 0.905 bbl KCI 7 ppb Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.0 ppb (as required 18 YP) DEXTRID LT 1-2 ppb EZ MUD DP 0.5 ppb (initial.15 ppb) CLAYSEAL 4 ppb (Initial build 1 ppb) ALDACIDE G 0.1 ppb GEM GP 1.0% by volume BARACARB 50 10 ppb BAROID 41 58 ppb (as needed to 9.6) Completion (3-1/2" Tubing to 9,100' MD) System Type: Filtered Inlet Water Properties: Density- 8.5 ppg 10/11/2012 Page 5 of 13 Steelhead Platform Well M-31B Hilcorp Well Design Summary 'Amy cam. Cementing Summary Kick Off Plug: 12-1/4" Hole (3872' to 3522') Cement volume based on annular volume + 50% open hole excess. Job will be a single slurry, high density design. Estimated total volume is as follows: Section Formula Volume 13-3/8" x 3-1/2" cmt (3722' - 3522') x 0.1378 = 27.6 bbls stinger overlap: 12-1/4" OH x 3-1/2" (3872' - 3722') x 0.134 x 1.5 = 30.2 bbls cement stinger: 3-1/2" ID for balanced 350' x 0.0076 = 2.7 bbls plug: Total Volume (bbls): 27.6 + 30.2 + 2.7 = 60.5 bbls Slurry Information: Stage High Density Kick Off Plug System 17 ppg Class G Density 17 lb/gal Yield 1.0 ft3/sk Mixed Water 3.85 gal/sk Mixed Fluid 3.877 gal/sk Total Volume 60.5 bbl=339.7 ft3=339.7 sx Expected 100 Bc at 04:30 hr:mn Thickening Expected ISO/API < 150 mL Fluid Loss Code Description Concentration D-046 Antifoam _ 0.2%BWOC D-065 Dispersant 1.0%BWOC Additives D-167 _ Fluid Loss 0.2%BWOC D-800 Retarder 0.3%BWOC 10/11/2012 Page 6 of 13 Steelhead Platform Well M-31B Hilcorp Well Design Summary s Comma, Intermediate Hole Section (12-1/4" hole, 9-5/8" Casing to 9,364' MD) Cement volume based on annular volume + 50% open hole excess. Job will be a (2) stage design. Stage collar will be run at 6000' MD. Cement from shoe to 300' below 13-3/8" shoe. Bow Spring centralizers to be installed at (1) each on shoe joints, (1) every third joint from shoe track to TOC. 1st Stage Estimated total volume is as follows: Section Formula Volume 12-1/4" x 9-5/8" OH (9364' - 6000') x 0.0558 x1 .5 = 281.6 bbls Annulus: 9-5/8" Shoe Track: 90' x 0.073 = 6.7 bbls Total Volume (bbls): 281.6 + 6.7 = 288.3 bbls 1st Stage Slurry Information (Lead): 1st Stacie Slurry Information (Tail): Stage Stage 1 Lead Stage Stage 1 Tail Slurry System Extended Lead System 15.3 EASYBLOK Density 12 ppg Density 15.3 lb/gal Yield 2.45 ft3/sk Yield 1.39 ft3/sk Mixed 14.373 gal/sk Mixed 6.214 gal/sk Water Water Mixed Fluid 14.523 gal/sk Mixed Fluid 6.233 gal/sk Total 2500' 209 bbl= 1 175 ft3=480 sx Total Volume I Volume (864') 79 bbls=443 ft3=319 sx Expected 100 Bc at 6:30 hr;mn Expected 100 Bc at 05:30 hr:mn Thickening Thickening Expected Expected ISO/API <200 mL ISO/API <60 mL Fluid Loss Fluid Loss D046 Antifoam 0.2%BWOC D046 Antifoam 0.2%BWOC D020 Extender 3.0%BWOC D202 Dispersant 1.5%BWOC D079 Extender 2%BWOC D400 Gas Migration 0.8%BWOC Additives D110 Retarder 0.15gal/sk Additives D154 Extender 8%BWOC D174 Expanding Agent 1.5%bWOC D198 _ Retarder 0.4%BWOC 10/11/2012 Page 7 of 13 SteeWlheaell M-31d Platform Hilcorp Well Design Summary E Company 2nd Stage Estimated total volume is as follows: Section Formula Volume 12-1/4" x 9-5/8" off (6000' - 4000) x 0.0558 xl.5 = 167.4 bbls Annulus: Total Volume (bbls): 167.4 bbls 2nd Stage Slurry Information (Lead): Stage Stage 1 Lead System Extended Lead Density 12 ppg Yield 2.45 ft3/sk Mixed 14.373 gal/sk Water Mixed Fluid 14.523 gal/sk Total (2000') 167.4 bbl=940 ft3=384 sx Volume Expected 100 Bc at 6:30 hr;mn Thickening Expected ISO/API <200 mL Fluid Loss D046 Antifoam 0.2%BWOC D020 Extender 3.0%BWOC D079 Extender 2%BWOC Additives Dl 10 Retarder 0.15gal/sk 10/11/2012 Page 8 of 13 Steelhead Platform Well M-31B Hilcorp Well Design Summary £a*m comm..} Production Hole Section (8-1/2" hole, 7" Production Liner to 11,543' MD) Cement volume based on annular volume + 50% open hole excess. Job will be a single stage design. Cement from shoe to TOL. Solid body centralizers to be installed at (1) each on shoe joints, (1) every other joint from shoe track to 9-5/8" shoe. Estimated total volume is as follows: Section Formula Volume 9-5/8" x 5" DP Overlap: 200' x 0.0489 = 9.8 bbls 9-5/8" x 7" Overlap: 200' x 0.0256 = 5.2 bbls 8-1/2" x 7" OH Annulus: (11543' -9364') x 0.0226 x1 .5 = 73.9 bbls 7" Shoe Track: 120' x 0.038 = 4.6 bbls Total Volume (bbls): 9.8+ 5.2 + 73.9 + 4.6 = 93.5 bbls 7" Liner Slurry Information (EasyBLOK]: Stage 7in Liner System 15.6 EASYBLOK Density 15.6 ppg Yield 1.33 ft#/sk Mixed Water 5.776 gal/sk Mixed Fluid 5.776 gal/sk Total Volume 93.5 bbl=525 ft3=394 sx Expected Thickening 5:00 Expected ISO/API <60 Fluid Loss Code Description Concentration D046 Antifoam 0.2%BWOC D202 Dispersant 1.5%BWOC Additives D400 Gas Migration 0.8%BWOC D154 Extender 8%BWOC D174 Expanding Agent 1.5%bWOC D198 Retarder 0.4%BWOC 10/11/2012 Page 9 of 13 11 Steelhead Platform Well M-31 B Hilcorp Well Design Summary Anticipated Formation Tops and Geohazards Top Name Formation Expected Fluid TVD Est Press PPG G1T G-Zone Oil/Water 8,585 Normal 8.5 HKT Hemlock Oil/Water 9,083 Normal 8.5 HK3T Hemlock Oil/Water 9,216 Normal 8.5 HK7(TD) Hemlock Oil/Water 9,833 Normal 8.5 Formation Evaluation Summary Interval Evaluation Method Comments 3722' to 11,543' LWD Schlumberger Dual Gamma Ray + Electro-Magnetic Wave Resistivity + Azimuthal Density + Compensated Neutron Porosity There are no plans to recover cores or conduct drill stem tests during the drilling and completion of M-31 B. 10/11/2012 Page 10 of 13 Steelhead Platform Well M-31B Hilcoor Well Design Summary M-31 B Slot Recovery, Drilling, & Completion Summary 1. MOB Rig to slot B1-12 (NW Leg) 2. N/D & remove tree. N/U and test BOPs. • Top down BOP configuration: Annular/5" fixed ram/blind ram/9-5/8" casing rams. 3. Set CIBP in 9-5/8" casing @ 6600'. Test to 1000 psi / 30 min. 4. Set CIBP in 9-5/8" casing @ 3880'. Test to 1000 psi / 30 min. 5. R/U and pull 9-5/8" casing hanger pack off. Cut and pull 9-5/8" casing to 3872' MD. • Ensure NC-50 Box x 9-5/8" BTC pin crossover on rig floor made up to FOSV and ready during casing operations. 6. M/U 12-1/4" Mill tooth bit, make clean out run to top of stub at 3872'. 7. M/U 600' x 3-1/2" cement stinger. TIH and balance 17 ppg Kick-off plug from 3872' to 3500'. TOH & WOC. 8. Leave 9-5/8" casing rams in lower ram cavity. 1 • Per 20 AAC 25.035 (e)(1)(A) "BOPE must have... one pipe ram to fit the size of drill pipe, tubing, or casing being used" • MASP for both hole sections is below 3000 psi. A 9. M/U 12-1/4" directional drilling assy (PDC bit, mud motor, MWD, GR-RES- DEN-NPHI LWD, 5" HWDP, Drlg Jar). 10.Time drill off plug, drill 12-1/4" hole section to 9364' MD / 8700' TVD. Pull wiper trip to 13-3/8" shoe. Utilize 9.2-9.6 ppg 2% KCI, Clayseal / GEM Water Based Drilling Fluid. 11.Run and cmt (2 stage) 9-5/8" 47# L-80 DWC/C production casing. • Ensure NC-50 Box x 9-5/8" BTC pin crossover on rig floor made up to 10.E FOSV and ready during casing operations. • Note: 9-5/8" BTC & DWC are compatible thread forms. 12.M/U 8-1/2" directional drilling assy (PDC bit, mud motor, MWD, GR-RES-DEN- NPHI LWD, 5" HWDP, Drlg Jar). 13.Install & test 7" casing ram in lower ram cavity. 14.TIH to stage collar. Drill out plug & cmt. 15.TIH to TOC. Test casing to 1500 psi / 30 min. Drill out shoe track + 20' new formation. FIT to 12 ppg EMW. 16.Drill 8-1/2" hole section to 11,543' MD / 9835' TVD. Pull wiper trip to 9-5/8" shoe. Utilize 9.2- 9.6 ppg 2% KCI, Clayseal / GEM Water Based Drilling Fluid. 17.Run and cmt 7" 26# L-80 VAM TOP HC production liner. • Ensure NC-50 Box x 7" VAM TOP HC pin crossover on rig floor made up to FOSV and ready during casing operations. 18.Make clean out run with 9-5/8" x 7" casing scrapers. Test casing to 1500 psi / 30 min. Displace well to filtered inlet water. TOH. 10/11/2012 Page 11 of 13 111 Steelhead Platform Well M-31B Hilcorp Well Design Summary Emery Campa 19.R/U and run TCP assy. Perforate casing. TOH. • Ensure crossover to TCP assy M/U to FOSV and ready on rig floor. 20.M/U and RIH w/ ESP assy on 3-1/2" production tubing. Install BPV. • Install and test 3-1/2" rams prior to running production tubing. • Ensure crossover M/U to FOSV and ready on rig floor during tubing running operations. 21.N/D BOP, N/U production tree. 10/11/2012 Page 12 of 13 Et Steelhead Platform Well M-31B Hilcorp Well Design Summary Emma Compaq Anticipated Drilling Hazards: 12-1/4" & 8-1/2" Hole Sections: Lost Circulation: Ensure 500 lbs of BaroFibre (Fibrous Cellulosic Material), 500 lbs SteelSeal (Angular, dual-composition carbon-based material), & 500 lbs different sizes of Calcium Carbonate are available on the rig to mix LCM pills at moderate product concentrations. Maintain 1 Oppb total of BaraCarbs/Barofibre/Steelseal while drilling both intervals to control any seepage losses. Hole Cleaning: Maintain a YP between 13 and 20. Pump high viscosity sweeps throughout the intervals as needed, particularly prior to POH for casing. Optimized mud rheology and flow rate will be the primary mechanisms for achieving hole cleaning in this deviated wellbore. Maximize pipe rotation (ideally > 100 RPM). BARAZAN-D should be used to maintain rheological properties. Wellbore stability: Maintain l0ppb total of BaraCarbs/Barofibre/Steelseal to strengthen wellbore. Maintain MW @ 9.2-9.6 ppg using additions of Barite. Filtrate control in the <5 range is required. Maintain additions of PAC L / Dextrid LT to maintain API fluid loss of <5. Maintain 6% KCI in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt-type additives to further stabilize coal seams (BARO-TROL PLUS 4 ppb). • Increase fluid density as required to control the running coal. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb BAROTROL pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. 10/11/2012 Page 13 of 13 11 Maximum Anticipated Surface Pressure Calculation 12-1/4" Hole Section (3600'TVD to 8700'TVD) Hilcor Steelhead Platform Well M-31A Cook Inlet, Alaska Formation Pressure Data Formation Top (TVD) Grad PP PPG D2ST 4883 Gas Sand 0.456 2227 8.769 D9ST 5690 Unproduced sand 0.456 2595 8.770 E4ST 7077 Wet Sand 0.456 3227 8.769 F4ST 7948 Wet Sand 0.456 3624 8.769 For 12-1/4" hole Fracture Pressure at 13-3/8" shoe 3524(ft)x 0.7(psi/ft)= 2,467 psi MASP from pore pressure Pore pressure from F4ST(gas sand) MASP (Wellbore evacuated to gas column) 7948(ft) x 0.456(psi/ft)= 3,624 psi 3624(psi) - [0.1(psi/ft)*7948(ft)]= 2,829 psi MASP limited by fracture pressure at 13-3/8" shoe (2467 psi) MASP = 2467(psi) - [0.1(psi/ft)*3524(ft)] = 2114.6 psi Maximum Anticipated Surface Pressure Calculation 8-1/2" Hole Section (8700'TVD to 9835'TVD) H lc Steelhead Platform Well M-31A Cook Inlet,Alaska Nearest Offset Pressure Data Well SBHP Survey Date Reservoir MD TVD PP Grad EMW G-34RD 8/21/1993 G-Zone & Hemlock 9322 8975 3224 0.359 6.91 G-3RD2 8/22/1993 Hemlock 10365 9189 3315 0.361 6.94 D-42 6/3/2010 Hemlock 12252 9421 3420 0.363 6.98 G-24 1/18/2011 Hemlock 10100 9541 3497 0.367 7.05 G-30 8/2/1996 G-Zone & Hemlock 10351 9269 3439 0.371 7.14 For 8-1/2" hole Fracture Pressure at 9-5/8" shoe: 8700(ft) x 0.73(psi/ft)= 6,351 psi MASP from pore pressure Max pore pressure at TD (9,835'TVD) fnA 5 ' MASP (Wellbore evacuated to gas column) 9835(ft)x 0.371(psi/ft)= 3,649 psi 3649(psi) - [0.1(psi/ft)*9835(ft)]= 2,665 psi MASP = 3649(psi) - [0.1(psi/ft)*9835(ft)]= 2665 psi MASP limited to PP -gas gradient to surface from deepest hydrocarbon bearing formation .iteelhead Platform Well M-31B Hilcorp Well Design Summary M-31 B Well Design Summary M-31 B is a development oil well planned to be re-drilled in a SE direction from slot B1-12 utilizing the existing casing program to 3722'. • The first attempt at sidetracking the well was unsuccessful. Hole geometry in conjunction with coal instability led to a casing failure which made the Ir wellbore unusable below 10,272' MD. For the second redrill attempt, the base plan is to cut & pull the 9-5/8" casing down to 3872' (150' below the 13-3/8" shoe). A 12-1/4" x 5642' open hole section will be drilled and 9-5/8" casing run & cemented. Maximum inclination through this section will be 21 deg. An 8-1/2" x 2179' production hole section will then be drilled and a 7" prod liner run and cemented. This section of the well builds up to 71 deg and holds a tangent to TD. The targets will remain more or less the same as previous redrill (Several targets through both the G-zone and Hemlock formations). The BHL was moved 300' West to allow for more efficient wellbore geometry. No H2S is expected to be encountered during the drilling & completion of • M-31 B. The well will be completed with a 3-1/2" ESP assembly. Well will be drilled using Steelhead Rig 51, The Drilling Contractor utilized for the labor contract is Kuukpik. SUPERCEDED Basic Well Information lo•/(tz Platform: Steelhead - Well Name: M-31 B Estimated Spud Date: 11/1/2012 Field: McArthur River Productive Horizon: G-zone & Hemlock - Total Depth: 11,543' MD / 9835' TVD • Slot: Slot B1-12, NW Leg KB Elevation: 160' AMSL • KB to WH: 75' 10/3/2012 Page 1 of 12 Steelhead Platform Well M-31 B HilcorpEnergWell Design Summaryr Cornrow Well Coordinates: Surface Location: 970' FNL, 516' FWL, Sec 33, T9N, R13W, S X=214140.49, Y=2499532.17, NAD27, ASP, Zone 4 Top of Prod Horizon: 976' FNL, 1692' FWL, Sec 33, T9N, R13W, S X= 215310.06, Y= 2499497.03, NAD27, ASP, Zone 4 Planned BHL: 2554' FSL, 1769' FWL, Sec 33, T9N, R13W, S X= 215347.22, Y= 2497745.80, NAD27, ASP, Zone 4 Existing M-31A Casing Design Hole Tube Weight Length Top Btm Size (in) O.D. (lbs / ft) Grade Conn (ft) MD/TVD MD/TVD (in) (ft) (ft) Driven 26 267 X-56 Drill-Quip 904 WH 979 24 16 75 K-55 BTC 1270 WH 1345/1344 17-1/2 13 3/8 61 K-55 BTC 3647 WH 3722/3524 12-1/4 9 5/8 47 L-80 BTC-M 6890 WH 6890/6230 9-1/2 7-5/8 29.7 L-80 Hydril 2792 6688/6050 9480/8275 523 7" 26 L-80 BTC-M 8675 9480/8275 11,415/9152 Planned M-31 B Casing & Tubing Design S�e O le De Weight Grade Conn Length MD/TVDTop Btm MD/TVD (in) (in) (lbs / ft) (ft) (ft) (ft) 12-1/4" 9-5/8" 47# L-80 DwC/C 9364 WH 9364/8700 8-1/2" 7 26 L-80 VAM 2443 9100/8453 11,543/9835 • TOP HC All casing will be new,PSL 1 (100%mill inspected, 10%inspection upon delivery to TSA in Fairbanks) 10/3/2012 Page 2 of 12 Steelhead Platform Well M-31B }Iilcoip Well Design Summary Well Control Summary Hole Section Equipment Test Pressure (psi) • 16-3/4" Hydril GK 5M annular • • 16-3/4" 5M Cameron U Double gate • o 5" Fixed ram Casing o Blind ram in btm cavity R/; Test Pressures: Recovery & • Mud cross 250/4000 12-1/4" • 16-3/4" 5M Cameron U single gate (Annular 250/2500 psi) o 5" Fixed csg ram (9,5J8 ' csg ram during csg operations). • 3-1/16" 5M Choke Manifold. • 16-3/4" Hydril GK 5M annular • 16-3/4" 5M Cameron U Double gate o 5" Fixed ram „ o Blind ram in btm cavity Test Pressures: • 8-1/2" • Mud cross 250/4000 • 16-3/4" 5M Cameron U single gate (Annular 250/2500 psi) o 5x7" VBR C4s/A)G • 3-1/16" 5M Choke Manifold • 16-3/4" Hydril GK 5M annular • 16-3/4" 5M Cameron U Double gate o 5" Fixed ram o Blind ram in btm cavity Test Pressures: Completion • Mud cross 250/4000 • • 16-3/4" 5M Cameron U single gate (Annular 250L2500 psi) o 3-1/2" fixed ram • 3-1/16" 5M Choke Manifold Schematics of the well control equipment are attached for reference. Well control equipment will be tested every 14 days. ' 10/3/2012 Page 3 of 12 Steelhead Platform Well M-31B Hilcorp Well Design Summary Camp� Anti-Collision Evaluation Summary The revised directional plan (P12) eliminates the anti-collision issues with offset wellbores that existed on the first attempt at the M-31 A wellbore. Other than the existing wellbore, there are no anti-collision issues. • M-31 B will be drilled using a mud motor and MWD. Surveys will be taken every 95' • while drilling. Formation Integrity Testing Projected Projected Test Point, Projected Test Fluid Density Test (EMW Surface 20' Below... Depth (TVD) Type Used for Test p••) Pressure 9-5/8" Shoe 8700' FIT 9.5 1 131 psi Note:Anticipated fracture gradient at the 9-5/8"shoe depth(8700'TVD)is expected to be btwn.75 and.83 psi/ft(14.4- 15.9 ppg)based on offset field test data. An FIT of 12 ppg was chosen to allow for a(2.5)ppg(or 1131 psi)kick margin while drilling with a 9.5 ppg fluid density. Casing Testing Fluid Density in Test String Casing Pressure Test Duration Casing Burst (PSI) 13-3/8" Casing 9.5 ppg 1500 30 min 3090 psi 9-5/8" Casing 9.5 ppg 1500 30 min 6870 psi 7" Liner 9.5 ppg 1500 30 min 7240 psi All casing tests will be held for 30 min. If pressure declines more than 10%in 30 min,corrective action must be taken. 10/3/2012 Page 4 of 12 ateelhead Platform Well M-31 B Hilco p Well Design Summary Emmet c.P4 Mud Program Summary Intermediate Hole Section (12-1/4" hole, 9-5/8" Casing to 9,364' MD / 8,700' TVD) Production Hole Section (8-1/2" hole, 7" Liner to 11,543' MD / 9,835' TVD) Weighting material to be used for the hole section will be Barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. 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: 2% KCI, Clayseal / GEM Water Based Drilling Fluid Properties: Depths Density Viscosity Plastic Viscosity Yield Point H THP pH 3722— 9.2—9.6 40-53 6-15 13-24 <9 8.5-9.5 11,543 System Formulation: 2% KCl/CLAYSEAL/GEM GP Product Concentration Water 0.905 bbl KCI 7 ppb Caustic 0.2 ppb (9 pH) BARAZAN Di- 1.0 ppb (as required 18 YP) DEXTRID LT 1-2 ppb EZ MUD DP 0.5 ppb (initial.15 ppb) CLAYSEAL 4 ppb (Initial build 1 ppb) ALDACIDE G 0.1 ppb GEM GP 1.0%by volume BARACARB 50 10 ppb BAROID 41 58 ppb (as needed to 9.6) Completion (3-1/2" Tubing to 9,100' MD) System Type: Filtered Inlet Water Properties: Density-8.5 ppg 10/3/2012 Page 5 of 12 .;teelhead Platform Well M-31B llilcorp Well Design Summary Emmy Compaq Cementing Summary Kick Off Plug: 12-1/4" Hole (3872'to 3522') Cement volume based on annular volume + 50% open hole excess. Job will be a single slurry, high density design. Estimated total volume is as follows: Section Formula Volume 13 3/8"x 3-1/2" cmt (3722' - 3522') x 0.1378 = 27.6 bbls 0 stinger overlap: 12-1/4" OH x 3-1/2" (3872' - 3722') x 0.134 x 1.5 = 30.2 bbls cement stip_ger: 3-1/2" ID for balanced 350' x 0.0076 = 2.7 bbls plug: Total Volume (bbls): 27.6 + 30.2 + 2.7 = 60.5 bbls Slurry Information: Stage High Density Kick Off Plug System 17 ppg Class G Density 17 lb/gal Yield 1.0 ft3/sk Mixed Water 3.85 gal/sk Mixed Fluid 3.877 gal/sk Total Volume 60.5 bbl=339.7 ft3=339.7 sx Expected 100 Bc at 04:30 hr:mn Thickening Expected ISO/API < 150 mL Fluid Loss Code Description Concentration D-046 Antifoam 0.2%BWOC D-065 Dispersant 1.0%BWOC Additives D-167 Fluid Loss 0.2%BWOC D-800 Retarder 0.3%BWOC 10/3/2012 Page 6of12 II Steelhead Platform Well M-31 B Hilcorp Well Design Summary enmy Camwnr Intermediate Hole Section (12-1/4" hole, 9-5/8" Casing to 9,364' MD) Cement volume based on annular volume + 50% open hole excess. Job will be a (2) stage design. Stage collar will be run at 6000' MD. Cement from shoe to 300' below 13-3/8" shoe. Bow Spring centralizers to be installed at (1) each on shoe joints, (1) every third joint from shoe track to TOC. 1st Stage Estimated total volume is as follows: Section Formula Volume 12-1/4"x 9-5/8" off (9364' - 6000') x 0.0558 x1 .5 = 281 .6 bbls Annulus: 9-5/8" Shoe Track: 90' x 0.073 = 6.7 bbls Total Volume (bbls): 281.6 + 6.7 = 288.3 blas 1st Stage Slurry Information (Lead): 1st Stage Slurry Information (Tail): Stage Stage 1 Lead Stage Stage 1 Tail Slurry System Extended Lead System 15.3 EASYBLOK Density 12 ppg Density 15.3 lb/gal Yield 2.45 ft3/sk ✓ Yield 1.39 ft3/sk ✓ Mixed 14.373 gal/sk Mixed 6.214 gal/sk Water Water Mixed Fluid 14.523 gal/sk Mixed Fluid 6.233 gal/sk Total Volume tal (2500')209 bbl= 1175 ft3=480 sx / Volume (864')79 bbls=443 ft3=319 sx Expected 100 Bc at 6:30 hr;mn Expected 100 Bc at 05:30 hr:mn Thickening Thickening Expected Expected ISO/API <200 mL ISO/API <60 mL Fluid Loss Fluid Loss D046 Antifoam 0.2%BWOC D046 Antifoam 0.2%BWOC D020 Extender 3.0%BWOC D202 Dispersant 1.5%BWOC D079 Extender 2%BWOC D400 Gas Migration 0.8%BWOC Additives D110 Retarder 0.15gal/sk Additives D154 Extender 8%BWOC D174 Expanding Agent 1.5%bWOC D198 Retarder 0.4%BWOC 10/3/2012 Page 7 of 12 Steelhead Platform Well M-31B Hilcorp Well Design Summary Com C=P4 2nd Stage Estimated total volume is as follows: Section Formula Volume 12-1/4" x 9-5/8" OH (6000' - 4000) x 0.0558 x1 .5 = 167.4 bbls Annulus: Total Volume (bbls): 167.4 bbls 2nd Stacie Slurry Information (Lead): Stage Stage 1 Lead System Extended Lead Density 12 ppg Yield 2.45 ft3/sk Mixed 14.373 gal/sk Water Mixed Fluid 14.523 al sk Total 2500')209 bbl= 1 175 ft3=480 sx Volume Expected 100 Bc at 6:30 hr;mn Thickening Expected S a�'"'j « ISO/API <200 mL j� TI Fluid Loss CEDEO D046 Antifoam 0.2%BWOC D020 Extender 3.0%BWOC D079 Extender 2%BWOC Additives D110 Retarder 0.15ga1/sk 10/3/2012 Page 8 of 12 Steelhead Platform Well M-31B Hilcorp Well Design Summary Enemy Compaq Production Hole Section (8-1/2" hole, 7" Production Liner to 11,543' MD) Cement volume based on annular volume + 50% open hole excess. Job will be a single stage design. Cement from shoe to TOL. Solid body centralizers to be installed at (1) each on shoe joints, (1) every other joint from shoe track to 9-5/8" shoe. Estimated total volume is as follows: Section Formula Volume 9-5/8" x 5" DP Overlap: 200' x 0.0489 = 9.8 bbls 9-5/8"x 7" Overlap: 200' x 0.0256 = 5.2 bbls 8-1/2"x 7" OH Annulus: (11543' - 9364') x 0.0226 x1 .5 = 73.9 bbls 501. 7"Shoe Track: 120' x 0.038 = 4.6 bbls Total Volume (bbls): 9.8+ 5.2 + 73.9 + 4.6 = 93.5 bbls 7" Liner Slurry Information (EasyBLOK): Stage 7in Liner System 15.6 EASYBLOK Density 15.6 ppg Yield 1.33 ft#/sk . Mixed Water 5.776 gal/sk Mixed Fluid 5.776 gal/sk Total Volume 93.5 bbl=525 ft3=394 sx Expected Thickening 5:00 Expected ISO/API Fluid Loss <60 Code Description Concentration D046 Antifoam 0.2%BWOC D202 Dispersant 1.5%BWOC Additives D400 Gas Migration 0.8%BWOC D154 Extender 8%BWOC D174 Expanding Agent 1.5%bWOC D198 Retarder 0.4%BWOC 10/3/2012 Page 9 of 12 Steelhead Platform Well M-31 B Hilcorp Well Design Summary End Company Anticipated Formation Tops and Geohazards Top Name Formation Expected Fluid TVD Est Press PPG G1T G-Zone Oil/Water 8,585 Normal 8.5 HKT Hemlock Oil/Water 9,083 Normal 8.5 HK3T Hemlock Oil/Water 9,216 Normal 8.5 HK7(TD) Hemlock Oil/Water 9,833 Normal 8.5 Formation Evaluation Summary Interval Evaluation Method Comments 3722' to 11,543' LWD Schlumberger Dual Gamma Ray + Electro-Magnetic Wave Resistivity + _ Azimuthal Density + Compensated Neutron Porosity There are no plans to recover cores or conduct drill stem tests during the drilling . and completion of M-31 B. 10/3/2012 Page 10 of 12 Steelhead Platform Well M-31B Hilcorp Well Design Summary Essay Company M-31B Slot Recovery, Drilling, & Completion Summary No f; rS ,€ "- Surs 1. MOB Rig to slot B1-12 (NW Leg) --? 40,o r.*.� - 2. N/D & remove tree. N/U and test BOPs. // -51A 3. Set CIBP in 9-5/8" casing © 3880'. Test to 1000 psi / 30 min. M 4. R/U and pull 9-5/8" casing hanger pack off. Cut and pull 9-5/8" casing to 3872' MD. 5. M/U 12-1/4" Mill tooth bit, make clean out run to top of stub at 3872'. 6. M/U 600' x 3-1/2" cement stinger. TIH and balance 17 ppg Kick-off plug from 3872' to 3500'. TOH & WOC. 7. M/U 12-1/4" directional drilling assy (PDC bit, mud motor, MWD, GR-RES- DEN-NPHI LWD, 5" HWDP, Drlq Jar). • 8. Time drill off plug, drill 12-1/4" hole section to 9364' MD / 8700' TVD. Pull wiper trip to 13-3/8" shoe. Utilize 9.2-9.6 ppg 2% KCI, Clayseal / GEM Water Based Drilling Fluid. 11 9. Run and cmt (2 stage) 9-5/8" 47# L-80 DWC/C production casing. - 10.M/U 8-1/2" directional drilling assy (PDC bit, mud motor, MWD, GR-RES-DEN- NPHI LWD, 5" HWDP, Drlg Jar). ( f l 11 .TIH to TOC. Test casing to 1500 psi / 30 min. Drill out shoe track + 20' new formation. FIT to 12 ppg EMW., 12.Drill 8-1/2" hole section to 11,543' MD / 9835' TVD. Pull wiper trip to 9-5/8" shoe. Utilize 9.2- 9.6 ppg 2% KCI, Clayseal / GEM Water Based Drilling Fluid. 13.Run and cmt 7" 26# L-80 VAM TOP HC production liner. 14.Make clean out run with 9-5/8" x 7" casing scrapers. Test casing to 1500 psi / 30 min. Displace well to filtered inlet water. TOH. 15.R/U and run TCP assy. Perforate casing. TOH. 16.M/U and RIH w/ ESP assy on 3-1/2" production tubing. Install BPV. 17.N/D BOP, N/U production tree. S UPEi CEDED 10/3/2012 Page 11 of 12 Steelhead Platform Well M-31B Hilcorp Well Design Summary Enemy Campq Anticipated Drilling Hazards: 12-1/4" & 8-1/2" Hole Sections: Lost Circulation: Ensure 500 lbs of BaroFibre (Fibrous Cellulosic Material), 500 lbs SteelSeal (Angular, dual-composition carbon-based material), & 500 lbs different sizes of Calcium Carbonate are available on the rig to mix LCM pills at moderate product concentrations. Maintain l Oppb total of BaraCarbs/Barofibre/Steelseal while drilling both intervals to control any seepage losses. Hole Cleaning: Maintain a YP between 13 and 20. Pump high viscosity sweeps throughout the intervals as needed, particularly prior to POH for casing. Optimized mud rheology and flow rate will be the primary mechanisms for achieving hole cleaning in this deviated wellbore. Maximize pipe rotation (ideally > 100 RPM). BARAZAN-D should be used to maintain rheological properties. Wellbore stability: Maintain 10ppb total of BaraCarbs/Barofibre/Steelseal to strengthen wellbore. Maintain MW @ 9.2-9.6 ppg using additions of Barite. Filtrate control in the <5 range is required. Maintain additions of PAC L / Dextrid LT to maintain API fluid loss of <5. Maintain 6% KCI in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt-type additives to further stabilize coal seams (BARO-TROL PLUS 4 ppb). • Increase fluid density as required to control the running coal. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb BAROTROL pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss. H2S: H2S is not present in this hole section. 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S009N01 I ,� /1 / ,/,'/":/ / �,/ \\\`,\ •r Section 3 /f; , $009N1113W \. \\, I ' \` �,//;/ ; _>"'"Section 3�3 1p►IQ17594 I I 1/4' // / / Z =�" \NADL018730 \\ `\\ \ 1/ ' ��/ /// /, , - M 1�PB1 BHL �\ •• \ i / \ ,`\ \M26REL1 :, /X" M11 :HL \\ • " - \\\ M-31B (P12) /A( • ///1 49 �A'2 \`\\ .`` \Surface Hole Location//I,i ; ',4; • ` ' I , / \ """ " M-31B (P12) • `\ G-24 6HL `\ •N�/ CHOLE-" SLOT 2 ;HL Top of Productive Horizon • ` ` "—,1 1 LE 15LOT5 B L 1 Steelhead ;et , \ \ \\ \�h !_ :IFIL \\\ \\ \\\ G,21 BHL ytfVi 1 \y, 1 \ • `.\ \ II \T `\ i 1/4 •\ • • \ \\ / Nt \\` / i \\\\ `\ •• \ \ \ `\ ♦ \•\ `\``,\ /' II 1\\\\ 1\1 s�� M-05 1 HL •\`\ �� •\\\\ N \ i I `\ \ ♦ `'* I\ 4 .\\\ / 1 \\\ I ,\ •,, , \I 1 \ I\ \ • • 4' \ \ I II \ \ • / \ • • 1 \\ `\ \T�/ \\\ i ; \\; • \\ // \\\ `` 1 I \\\\ \\\,,,,,, \\ i`N•\ `\\ (1-03RD2 BML\\\1 \ / \\ I \ \\ \\ • • / \` \\ i1 `\ \\\\ '`�08RD BHL i \`�` I \` I`1 /I \\`\ G-03 BHL I1 \\ i1• \ \ Legend ;, \ M-31B (P12) II \ I ` Bottom Hole Location • M-31B(P12)Surface Hole Location ii \\ X \ M-31 B(P12)Top of Productive Horizon i, \\\ IHL \ M-31B(P12)Bottom Hole Location II ` II \I\ • M-31 B(P12)Well Track 1i \\ ".." I I • � 1000 ft radius buffer /� ;\\ I-7 Township-Range-Sections i I Steelhead Platform WELL#: M-31B Planned WBD 10/3/2012 1lileirrp Alustra,LEA: TBG Hanger 74.5'below RKB ti CASING AND TUBING DETAIL 9 SIZE____ _ WT GRADE CONN ID TOP BTM. )40,< l It". 26 267 thru 397# Drill Quip Surf 979' I 111. 16 75 K-55 BTC 15.124 Surf 1345' 7 +E 1 13-3/8 61&68 K-55 BTC 12.415 Surf 3722' 9-5/8 47# L-80 DWC/C 8.681 Surf 9,364' = ;3�S C 3711 7"liner 26# L-80 VAM TOP HC 6.276 9150' 11,543' tak_t - 1 Tubing: 3-1/2" 9.2# L-80 IBT-M 2.992 Surf 6,800' .4 't JEWELRY h NO Depth Length ID OD Item Tubing hanger,Seaboard-SC-ESP-EN,13-5/8"5M x 3-1/2" Pv 1. 74.5' BTC tubing,(2)each continuous control line ports. Go((M' 2. 8,880 HES"XD"3-1/2"Sliding Sleeve w/pups bucked on. 2. 1ne 3. 8,890 3-1/2"XN-Nipple 3 4 9,1100 9, 00 Centrilift ESP w/Phoenix Gauge 4 ', 5. 9,150 7"Liner top 6. 9,160 Baker JM-ZXP Liner Top Packer 1 7. 9,364 9-5/8"Casing Shoe c r 5 4.- '`ii PERFORATION DATA �'t ''7 Zone Top(tvd) Btm(tvd) Amt k'' G-1 8,585' 9,083' 498' "i HKT 9,083' 9,216' 133' �r HK3T 9,216' 9,789' 617' F."ti 11 t 1 V - "' 1 N t' t L 1 PBTD:11,400 MD/9,789' TVD TD:11,543'MD/9,835'TVD REVISED: 10/3/2012 REVISED BY:LEK k). N e2; w Om , \\1\ \ { copy co /2\ \ Lu i-)_ _ ems® 00 \)./§ \ )C� ` ; ! ee0.m e ) \Gr/} x § 0 0� ` ! \E5, z CI- ; / 2■ / 700W z-'§ « )§i-)` k ` li- j §§)n© , k�al ) ))§/} ) - Ea _ f� , 70 \ \ §� j \ L.7.1.--_1,0; ° , ts ® &0 ¥ 0.co § A 0 0 ( / 10 5 4 i 0 \ f CO § p ) _ , \§§ G 11 \ CO 0° ` } 5. 000 §% a 2 amp_ 7 0 00 §\ \ 5 Cl)a/„\] E\\\ !!, f § 3,,,; 2 - m 21, 21 (//}/ — § § 2 „m _ 0- $ 000 m=n ttt /)/®§ ) ( \` ~ 0 / M-316 Slot Recovery Days Vs Depth 0 -Slot R covery -Drill in Comp etion 2000 4000 4- 6000 a� a a� U, fa m () () 8000 10000 ----- 12000 14000 0 10 20 30 40 50 60 70 Days Page 1 of 1 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, October 09, 2012 10:59 AM To: 'Luke Keller' Cc: Davies, Stephen F (DOA) Subject: M-31B (PTD 212-149) Luke, I reviewed the PTD. Saw a couple of items that need addressing. 1) Please supply the MASP calculations 2)A current wellbore schematic. 3)The cement calculations for the 2nd stage of the 9 5/8" are a little off. Looks like a holdover from the first stage. 4)The procedure is missing some details ... don't forget to spell out Ram change out for casing runs. No mention of drilling out stage collar, x-overs for casing runs and TCP etc. 5) P &A rig activity will be on 7 day BOP test cycle... till you start drilling new OH . 5) Do you know when the P &A sundry will be submitted? The PTD and sundry tie-in together. �Q�� Regards, 16-12-64) Guy Schwartz U- ( f Senior Petroleum Engineer / 4-4.44-412c12..4-4) PSP AOGCC 793-1226 (office) 444-3433 (cell) lo,iI, a�- 10/9/2012 Davies, Stephen F (DOA) Subject: FW: TBU M-31 B: Spacing Exception Needed Original Message From: Davies, Stephen F (DOA) Sent: Monday, October 08, 2012 10:12 AM To: 'Luke Keller' Cc: Schwartz, Guy L (DOA); Paul Mazzolini Subject: TBU M-31B: Spacing Exception Needed Luke, As with TBU M-31A, TBU M-31B violates statewide spacing rules so an exception will be needed. This can be handled through an administrative amendment to Conservation Order 88. Please submit an application as soon as you can. Regards, Steve Davies Sr. Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 Fax: 907-276-7542 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 r-6 - . I -S PTD# 2-- ( 2 f4-7 / Development Service Exploratory Stratigraphic est/ Non-Conventional Well /� /� c�� do ' FIELD: t o;• �l tt-z r ( -t POOL: e_vt�c.c L r 'e Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in Permit No. ,API No. 50- - - API number are between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE 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 name ( PH) and API number (50- - - ) from records, data and logs acquired for well SPACING The permit is approves--- bject to full compliance with 20 AAC / EXCEPTION 25.055. Approval o .rodu e/in'ect is contingent upon issuance of La cp?servation . .er approving a spacing exception. assumes the liability of any protest to the s acing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non-Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. Rev:9/09/2011 0 O O , U) i .: . , W c, E, @ p a v°i 0) o E O (O. t' O, • -a as a �i 3 -o , p. p. � O, . 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G), 0. 0 ZaWD; 555to �; OO aaU5; daOcnUUUUQr-; Q, w-; 0, m, m, U. 5y � ao, co, co U,m N M (() (O aD O) O .- N M '[) CO N- CO 0) O .- N M et '1) (O N- CO 0) _ - N p) R) (0 N- W 0) O o - .- N N N N N N NN N N (C) M M (1) C) CC) M (C) M O') V N N N-.._____ ` 'a+ O N 0) O 0 O H LU • N r O i ,O N• E J;N V) 0 O 0 0 C _O LU 0 E a p •O a 0 0 a o 0 73tQ LC Q Q Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. M-31B TRADING BAY UNIT UPPER COOK INLET Kenai Borough, Alaska FINAL WELL REPORT MUDLOGGING DATA Provided by: Approved by: Matt Frankforter Compiled by: Lees Browne, Jr. H a r r y B l e y s Distribution: 2/26/2013 T.D. Date: 02/06/2013 TABLE OF CONTENTS 1 MUDLOGGING EQUIPMENT AND CREW ...................................................................................... 3 1.1 EQUIPMENT SUMMARY ............................................................................................... 3 1.2 PERSONNEL ................................................................................................................. 3 2 GENERAL WELL DETAILS .............................................................................................................. 4 2.1 OBJECTIVES ................................................................................................................. 4 2.2 WELL RESUME ............................................................................................................. 4 2.3 HOLE DATA ................................................................................................................... 5 3 GEOLOGICAL DATA ........................................................................................................................ 6 3.1 FORMATION / ZONE MARKER TOPS .......................................................................... 6 3.2 Hydrocarbon Show Evaluations ..................................... 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Bookmark not defined. 3.3 ZONE SUMMARIES ....................................................................................................... 8 3.3.1 Tyonek Formation ............................................................................................................. 8 3.3.2 Hemlock Formation ......................................................................................................... 13 3.3.3 West Foreland Formation ............................................................................................... 18 3.4 WELL LITHOLOGY ...................................................................................................... 19 3.5 SAMPLING PROGRAM AND DISTRIBUTION ............................................................ 33 4 DRILLING DATA ............................................................................................................................. 34 4.1 DAILY ACTIVITY SUMMARY ....................................................................................... 34 4.2 SURVEY DATA ............................................................................................................ 40 4.3 MUD RECORD ............................................................................................................. 44 4.4 BIT RECORD ............................................................................................................... 46 5 DAILY REPORTS............................................................................................................................ 47 Enclosures: 2”/ 100’ Formation Log (MD and TVD 2”/ 100’ LWD Combo Log (MD and TVD) 2”/ 100’ Gas Ratio Log (MD and TVD) 2”/ 100’ Drilling Dynamics Log (MD and TVD) Final Well Data on CD Hilcorp Alaska, LLC M-31B 3 1 MUDLOGGING EQUIPMENT AND CREW 1.1 EQUIPMENT SUMMARY Parameter Equipment Type And Position Total Downtime Comments Ditch Gas Electric Driven QGM Gas Trap Mounted In Possum Belly; FID Total Hydrocarbon Analyzer And Chromatograph 0 Rate of Penetration (ROP) Primary Draw works Belt Driven Encoder On Drum Shaft (Canrig) 0 Pump stroke counter Externally Mounted Magnetic Proximity Sensor (Canrig) 0 Hook load / Weight on bit (WOB) Hydraulic Pressure Transducer (Canrig) 0 Drill string torque Varco Analog Feed 0 Top drive rotary (RPM) Varco Analog Feed 0 Standpipe Pressure Solid State Pressure Transducer 0 Casing Pressure Solid State Pressure Transducer 0 Mud flow in / out (MFI / MFO) MFI: Derived From SPM MFO: Flow Paddle (Canrig) 0 Pit volumes Radar Pit Probes 0 Driller’s work station Explosion Proof Touch Screen Rigwatch (Canrig) 1 Clean and Service Company Man’s work station Rigwatch (Canrig) 0 Tool pusher’s work station Rigwatch (Canrig) 0 Mud Engineer’s work station Rigwatch (Canrig) 0 Pits work station Explosion Proof Touch Screen RigWatch (Canrig) 0 MWD / LWD WITS Feed WITS 0 1.2 PERSONNEL Unit Number: ML04 Mudloggers Years Days Technician Days Sample Catchers Days Lees F. Browne 30 31 Steve Forrest 1 Mike Sherry 31 Harry E. Bleys 13 18 Eric Andrews 31 Jessiah Johnson 1 13 Hilcorp Alaska, LLC M-31B 4 2 GENERAL WELL DETAILS 2.1 OBJECTIVES Steelhead M-31B is a development oil well planned to be re-drilled in a Southerly direction from slot B1-12 (NW Leg) utilizing the existing casing program down to 3722’ MD. M-31B will kick off from the bottom of the 13 3/8” casing shoe at 3722’ and drill a 12 1/4” hole section from 3722’ to 9425’ MD/ 8784’ TVD. 9 5/8” production casing will be run and cemented. An 8 1/2” hole section will be drilled from 9425’ to the well total depth. The well will be completed with 4 ½” production tubing and an ESP completion. 2.2 WELL RESUME Operator: Hilcorp Alaska, LLC Well Name: Trading Bay Unit M-31B Field and Pool: Trading Bay Unit, McArthur River Field, G-zone, Hemlock State: County Alaska Kenai Borough Company Representatives: Hauck / Rogers / Brumley / McInnes Location: X=214140, Y=2499532.16, NAD27, ASP, ZONE4. Elevation: – MSL RKB: 160’ to MSL RKB to ML 345’ Classification: Development Oil API #: 50-733-20457-02-00 PERMIT # 212149 AFE #: 1213057 Rig Name / Type: Steelhead Rig #51 Primary Target: G-Zone and Hemlock Spud Date :-> Finish Date :-> 1/9/13 – 2/8/12 Total Depth: 11550’ Total Depth Formation: HK7B Mudlogging Company CANRIG DRILLING TECHNOLOGY, LTD MWD Company: SCHLUMBERGER Tools Run: MWD: Survey, Gamma, Resis, Neu Por, Neu Den Directional Drilling: SCHLUMBERGER Drilling Fluids Company: HALLIBURTON / BAROID Hilcorp Alaska, LLC M-31B 5 2.3 HOLE DATA Hole Section Maximum Depth T.D. Formation Mud Weight (ppg) Deviation (oinc) Casing Shoe Depth F.I.T. MD TVD MD TVD 12.25” 9425’ 8784’ G2 9.5+ 21.17° 9 5/8” 9107’ 8487’ 12.4 8.5” 11550’ 9854’ Hemlock 9.6 68.30° 7” 11548’ 9853’ - Hilcorp Alaska, LLC M-31B 6 3 GEOLOGICAL DATA 3.1 FORMATION / ZONE MARKER TOPS Note: CT: Coal Top CB: Coal Base ST: Sand Top SB: Sand Base. FORMATION ACTUAL MD (ft) SSTVD (ft) B6ST 3794 -3427 B7ST 3918 -3535 CCT 4066 -3662 C1ST 4083 -3677 C2ST 4160 -3743 C3ST 4222 -3797 C4ST 4291 -3857 C5ST 4381 -3936 C6ST 4424 -3974 C7ST 4445 -3991 DCT 4481 -4024 D1ST 4497 -4038 D2ST 4836 -4335 D3ST 5024 -4502 D4ST 5217 -4673 D5ST 5346 -4789 D6ST 5381 -4821 D7ST 5438 -4873 D8ST 5540 -4967 D9ST 5693 -5112 D10ST 5857 -5269 D11ST 6025 -5430 D12ST 6077 -5479 D13ST 6207 -5604 D14ST 6277 -5672 D15ST 6331 -5723 D16ST 6387 -5777 D17ST 6540 -5923 D18ST 6620 -5999 ECT 6667 -6043 E1ST 6676 -6051 E2ST 6926 -6286 E3ST 6990 -6347 E4ST 7047 -6400 E5ST 7189 -6534 E6ST 7456 -6784 E7ST 7481 -6807 E8ST 7509 -6834 E9ST 7544 -6866 Hilcorp Alaska, LLC M-31B 7 FCT 7611 -6929 F1ST 7617 -6935 F2ST 7769 -7078 F3ST 7862 -7165 F4ST 7940 -7238 F5ST 8050 -7340 F6ST 8153 -7437 F7ST 8239 -7517 F8ST 8343 -7614 F9ST 8412 -7679 F10ST 8510 -7770 F11ST 8568 -7824 F12ST 8623 -7876 F13ST 8658 -7909 F14ST 8694 -7942 F15ST 8765 -8008 F16ST 8935 -8167 F17ST 9006 -8234 G0CT 9063 -8287 G01ST 9066 -8290 G02ST 9098 -8320 G03ST 9175 -8391 G04ST 9216 -8429 G05ST 9251 -8463 GO6ST 9327 -8533 COAL39 9338 -8543 G1ST 9360 -8563 G2ST 9424 -8623 G3ST 9466 -8661 G4ST 9534 -8723 G5ST 9671 -8842 G6ST 9820 -8961 G7ST/HKT 9881 -9007 HK1T 9948 -9053 HK2T 10002 -9089 HK3T 10188 -9200 HK4T 10409 -9306 HK5T 10640 -9395 HK6T 11081 -9536 HK7T 11316 -9611 HKB/WFT 11433 -9651 WF1T 11456 -9659 Hilcorp Alaska, LLC M-31B 8 3.2 ZONE SUMMARIES 3.2.1 Tyonek Formation G01ST: 9066’ MD, 8449’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 49 1 30 179 7 54 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 9096 179 31063 191 62 13 - - - Sand/tuffaceous sandstone ( 9066'-9098') = loose unconsolidated sands; subangular to subrounded to rounded grains; low medium to low coarse grain size; well sorted; fair sphericity leading to parts of the sequence is young and others more weathered and texturally mature; tuffaceous sandstone friable, low indurated visually good porosity clasts. G02ST: 9098 MD, 8479 TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 60 1 26 162 4 28 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 9098 162 28170 163 53 11 - - - Sand/tuffaceous sandstone ( 9098'-9175')Continued sand and tuffaceous sand from the GO1ST loose unconsolidated sands; subangular to subrounded to rounded grains; low medium to low coarse grain size; well sorted; fair sphericity leading to parts of the sequence is young and others more weathered and texturally mature; tuffaceous sandstone friable, low indurated visually good porosity clasts. Hilcorp Alaska, LLC M-31B 9 G03ST: 9175’ MD, 8551’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 94 12 47 131 15 88 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 9200 131 22619 95 31 8 9 - - Sand (9140-9220') = very light gray to light gray; clast size ranges from medium lower to fine lower; sub round to round; moderate to well developed sphericity; equant grains; moderate to well sorted; impacted texture; mature nature; non to very weak siliceous cement; no visible matrix material; dominant grain support; arenaceous; composed of >90% quartz, secondary chert trace lithics; good porosity and good permeability; samples become very clean after 9180' with no sample fluorescence with a trace cut; poor over all. . G04ST: 9216’ MD, 8589 TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 188 4 49 159 25 60 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 9251 159 18984 27 - - - - - Very carbonaceous shale/clay and coal (9216-9251') = occurs as thin beds with very carbonaceous clay and silt at contacts grading to carbon shale and coal at gas maximum; black mottled brownish black; soft in clay to firm in coal; resinous mottled earthy luster; PDC bit ground up cuttings; no visible bleed of gas from cuttings. . G05ST: 9251’ MD, 8622’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 230 2 61 188 24 86 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 9253 188 22466 131 37 - - - - Sand (9251-9327') = very light gray to light gray; clast size medium upper and lower to fine upper and lower; round to sub round; moderate to well developed sphericity; equant grains; moderate to well sorted; impact texture; mature nature; unconsolidated; grain supported; arenaceous; composed of >90% quartz, secondary chert, trace lithics; good porosity and permeability; grades to tuffaceous siltstone; no show of oil. Hilcorp Alaska, LLC M-31B 10 G06ST: 9327’ MD, 8692’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 129 9 45 92 35 59 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 9330 92 15397 147 33 6 16 - - Coal/carbon shale (9305-9360') = thin beds of carbon shale brownish black to 9345' in which black bituminous coal; firm to hard; sub conchoidal to blocky fracture; visible bleeding gas. G1ST: 9360’ MD, 8723.58’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 193 7 76 173 42 99 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 9423 173 21518 818 849 195 348 94 84 Sand = Clast size ranges from medium to fine unconsolidated sands; no sample fluorescence; no stain, no odor; slow increasing to moderate streaming yellowish white cut; slow development to hazy bluish white cut; faint start residue stain; poor show. G2ST: 9424’ MD, 8783.29’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 191 5 65 171 8 34 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 9424 171 20990 843 868 200 358 97 85 Sand continued medium to fine unconsolidated sands; no sample fluorescence; no stain, no odor; slow increasing to moderate streaming yellowish white cut; slow development to hazy bluish white cut; faint start residue stain; poor show. Hilcorp Alaska, LLC M-31B 11 G3ST: 9466’ MD, 8821.86 TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 79 4 58 90 10 42 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 9506 90 13950 888 1019 242 423 125 26 SANDSTONE very fine grains in a matrix dominated carbonaceous matrix cement; weakly cemented; grains subrounded and fair sorted; in high sphericity; mature textural maturity; quartz at 70%-80% with dark carbonaceous clasts, calcite, feldspars, and trace green stone possibly chlorite; sandstone interbedded with loose unconsolidated sands and thin stringers of coal and carbonaceous shales; gas rises steeply in thin coal stringers; very faint yellow cut. G4ST: 9534 MD, 8883.39’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 122 1 66 139 22 55 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 9632 139 26838 848 377 100 224 96 6 Sand/sandstone = loose unconsolidated sands of upper fine to upper coarse grains; poorly sorted; Angular to subrounded grains; dominantly Quartz of 80% with accessory minerals of carbonaceous shale, feldspars, calcite, more than trace conglomerates and very coarse grains of quartz, carbonaceous shales, very tight micro crystalline sandstone; and coal that has possibly fallen down hole; overall sandstone is matrix supported to trace grain supported in a angular to sub-angular with low to moderate sphericity and fair sorting; friable easily sheared when hydrated with a tight low visual porosity in the sandstones; no cut or fluorescence. Coal = flat dull matte to vitreous black; blocky to splintery in a firm to brittle tenacity; planar to splintery irregular fracture; smooth texture; dull to shiny vitreous luster; visible degassing; no fluorescence or cut. Hilcorp Alaska, LLC M-31B 12 G5ST: 9671’ MD, 9002.16’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 184 3 74 104 16 45 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 9809 104 13500 434 99 20 39 - 28 Sand/sandstone = upper fine to lower very coarse poorly sorted grains; trace conglomerates, of 2 mm and larger; angular to subangular; stringers of sandstone interbedded with loose unconsolidated sands of 80% quartz and the rest of feldspars, calcites, dark carbonaceous material, and coal; poor to slightly fair sorting; subangular to subrounded; low to moderate sphericity; textural maturity of half way from immature to mature; no fluorescence no cut; carbonaceous weakly cemented, low porosity; matrix supported sandstone. Sand/sandstone after 9700’ sandstone and sand is becoming dirty white opaque to gray with blue hues to translucent to translucent grayish white color; dominantly quartz in a loose unconsolidated sand interbedded with low indurated weakly carbonaceous matrix supported sandstone; low visual porosity and subrounded; fair sorted; moderate sphericity; moderate mature textural maturity; faint fluorescence; no cut. G6ST: 9820’ MD, 9121.84’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 105 8 57 84 21 31 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 9820 84 12822 450 187 5 98 - - Tuffaceous siltstone = very light gray overall with scattered medium light gray and dull white; moderate induration becoming poorly indurated in increased ashy silts; stiff moderate cohesive; non to slightly adhesive; sub planar to earthy fracture; sub platy to sub nodular habit; earthy to slightly greasy luster; silty to gritty to ashy textures; massive gradation tuffaceous silt with various ash content; grading to devitrified ash. Hilcorp Alaska, LLC M-31B 13 G7ST/HKT: 9881’ MD, 9167.56’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 80 6 55 124 21 44 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 9884 124 18895 682 283 6 150 - - Devitrified ash/Tuffite = white mottled salt and pepper; very poor induration; greasy to earthy luster ashy to clayey to sub colloidal textures; massive bedding of gradational ash, tuffite and tuffaceous siltstone; appear redeposited and reworked. 3.2.2 Hemlock Formation HK1T: 9948’ MD, 9213.89’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 78 30 59 147 27 84 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 9961 147 9330 1683 1662 310 665 170 45 Conglomerate sand = very light gray; clast size very coarse upper to fine lower; angular bit impacted sand to sub round medium/fine grains; poor to well developed sphericity; moderate to poor sorting; pitted to chip to polished textures; unconsolidated to weakly consolidated slight to moderate ash/silt matrix which is very hydrophilic; both grain and local matrix support; 30% moderate yellow green even sample fluorescence at 9955' to 70% at 9965', no oil stain or odor; no oil pops, instant transparent light blue white slow to moderate streaming cut with slow development to hazy cut; dull yellow residue ultra violet stain, no white light oil residue. Hilcorp Alaska, LLC M-31B 14 HK2T: 10002’ MD, 9249.85’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 88 19 54 184 24 59 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 10031 184 10528 2063 2179 424 863 232 64 Coal (9990'-10040') = black; firm; resinous luster; matte texture; hackly to irregular fracture; no out gassing. Conglomerate sand/conglomerate (10040- 10188') = is composed of very light gray; clast very coarse upper (some pebble) to medium lower; angular bit impacted grains to sub round in medium grains; low to moderate sphericity; poor sorting; chipped in coarse to impacted in medium grains; sub mature nature; weak siliceous cement and medium grain matrix sand; mostly unconsolidated; fair estimated visual porosity; evidence of conchoidal burst; faint blue yellow white fluorescence and streaming, and yellow residual ring; conglomerates ranging in size from 2mm to 7mm; conglomerates dominantly Quartz of sharp angularity due to bit action; trace coal and tuffaceous siltstone possibly due to falling down hole. HK3T: 10188’ MD, 9360.03’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 148 6 52 92 8 48 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 10203 92 3067 573 633 126 279 82 18 Sand/conglomerate sand/ conglomerates (10155' - 10240’) = medium gray to light grayish white color; upper medium to upper very coarse to conglomerates ranging in size from 2 mm to 5 mm; loose unconsolidated sands are subrounded to rounded with high sphericity; fair sorting with overall textural maturity very high; trace calcites, and chert no free oil in mud; no petroleum odor; no visible oil stain; 40- 60% moderate to dull yellow even to mottled oil fluorescence; instant transparent weak light blue white cut fluorescence with slow streaming cuts slow development; weak yellow ultra violet stain; pale straw visible. Sand/conglomerate sand/conglomerates (10240' - 12325') = grayish white to white with reddish hues; loose sands uncompacted interbedded with larger conglomerates and trace coarse sandstone in a tough indurated grain supported clasts; conglomerates dominantly quartz with trace chert, and green chlorite in Quartz; sands are subrounded to round and conglomerates are more angular due to bit impaction; no free oil; no oil oil stain; no petroleum odor; instant weak light blue fluorescent cut with slow development cuts light blue white; weak yellow ultra violet residue stain; no white light visible oil stain. Sand/conglomerate sand/conglomerates (10325’ - 10395’) = grayish white opaque to translucent white with blue hues; poor to fair sorted; subrounded to rounded with conglomerates angular; loose uncompacted sands upper medium to very coarse; continued decreased oil fluorescence; 30-40% even to mottled dull to some moderate yellow oil fluorescence; no oil stain; no petroleum odor; no free oil in mud; instant dull transparent oil cut with no visible streams; weak yellow ultra violet stain. Hilcorp Alaska, LLC M-31B 15 HK4T: 10409’ MD, 9466.28’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 177 1 66 115 10 48 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 10451 115 6728 1222 1263 262 523 331 98 Sand/conglomerate sand/conglomerates (10409' - 10480’) = translucent to gray with blue hues to grayish white opaque to green and blue opaque; loose unconsolidated lower medium to upper coarse grains; poor sorted; subrounded to rounded with sands interbedded with conglomerate sand; 60% even to mottled yellow sample fluorescence; no odor; no oil stain; instant transparent light cut slow development to hazy cut; no streamer weak to moderate yellow ultra violet oil residue; no visible white light oil stain. Sand/conglomerate sand/ conglomerates (10480’ - 10545’) = translucent to opaque quartz of grayish white to grayish white with blue, green and red hues; poorly sorted with lower medium to very coarse grains to conglomerates of 2mm to 3mm; even to mottled yellow fluorescence; no odor or oil stain; rapid bright yellow cut; no visible streaming; strong yellow residual ring; low oil ultra violet oil stain; gas back ground low, and gas increase to 71 units. Sand/conglomerate sand/conglomerates (10545’ - 10610’) = increase of 2mm conglomerates and conglomerate sands loose unconsolidated sands subrounded rounded; conglomerates angular to subangular; dominantly quartz at 90% with calcite, chlorite, feldspar, trace jasper and chert; no odor or oil stain; instant mild yellow cut; no visible streaming; mild yellow residual ring; No visible white light stain. Coal (10610’ -10630’) = matte black to vitreous black color; firm tough to very hard and brittle; planar to splintery irregular fracture; smooth texture; dull matte black to shiny vitreous bituminous coal; surface shear patterns and conchoidal cratering; no visible degassing. Hilcorp Alaska, LLC M-31B 16 HK5T: 10640’ MD, 9555.02’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 93 2 39 98 6 35 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 10800 98 12136 310 242 79 155 68 84 Sand/ conglomerate sand/conglomerate (10630’-10730’) = loose sands and broken up materials from conglomerate sandstone ground up by bit action interbedded with conglomerates of 2mm to 4mm to loose unconsolidated sands of upper medium to very coarse grains poorly sorted and medium to high sphericity; overall mature textural maturity; no cut or stain; fluorescence under ultra violet of mild green yellow; cut no streaming but green yellow residual ring. Sand/conglomerate sand/ conglomerate (10730’-10780') = loose unconsolidated sands, ground up conglomerate sandstone and conglomerates dominantly quartz; sands subrounded to round; poorly sorted and medium to high sphericity; high textural maturity; no odor, no stain ultra violet milk white yellow cut and fluorescence; no streaming and no white light stain; no residual ring. Conglomerate sand/conglomerate (10780’-10900') = very light gray to light gray; off white; clast size pebble/very coarse upper to medium grains; angular bit impacted coarse to sub angular to sub round matrix sand; low to moderate developed sphericity; very poor sorting; coarse grains chipped and polished with impacted medium matrix sand; dense fine to very fine sandstone at 10800'; very weak siliceous cement; grain supported; no visible matrix clay/silts; fair to good estimated porosity; gradational; 10-30% dull to moderate even to mottled yellow green sample oil fluorescence; instant transparent light blue white oil cut; no visible streaming cuts; slow development cuts; very weak dull yellow residue ultra violet stain; no visible white light stain. Conglomerate sand/conglomerate (10900’-11035') = very light gray to light gray; clast size very coarse upper to fine upper; angular bit impacted coarse grain to sub angular to sub round medium to fine grains; low developed sphericity; discoidal, triaxial and prolated grains; very poorly sorted; chipped and polished coarse grains to impacted and pitted medium to fine grains acting as matrix sand; unconsolidated; no visible cement or matrix clays; arenaceous; grain support; fair porosity and permeability; 20-40% yellow even to mottled oil fluorescence; no stain, no odor; instant transparent light blue green with slow Increase to light blue white oil cut; slight dull yellow ultra violet residue stain with no visible white light oil stain; poor oil shows possible oil being flushed into the mud system when sands are disaggregated. Tuffaceous siltstone/carbonaceous clay (11035'-11080') = light yellowish gray to light gray and various hues of both colors with parallel laminar patterns of light silt and dark carbon clay; very poor to poorly indurated; brittle; slightly expansive when hydrated; slight cohesiveness and adhesiveness; earthy fracture; sub platy to sub nodular habit earthy luster; ashy texture; massive heterogeneous structure of micro laminated carbon clay and tuffaceous siltstone; possible very thin coal seams carbonaceous shale and carbon clay. Hilcorp Alaska, LLC M-31B 17 HK6T: 11081’ MD, 9696.09’TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 79 3 32 277 10 31 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 11176 277 30574 584 229 51 87 37 59 Coal (11188' - 11200’) = black color; firm tough brittle; planar to splintery; blocky to wedge like; smooth texture; thin to thick structure; bituminous coal visible degassing when hydrated. Conglomerate sand (11200-11275') = very light gray to light gray; clast very coarse upper to fine upper; angular to sub round; very poor sorting; chip and impact textures; unconsolidated; trace tuff/silt loose matrix; grain support; fair to poor porosity and permeability; 10% dull yellow mottled fluorescence and poor cut. Carbonaceous clay and coal (11275-11316) = brownish gray to brownish black; micro laminated with lighter and darker carbonaceous silt, clay and sub lignitic coal; brittle to some firm; earthy luster; silty to matte texture; common sub planar fracture along coal fractures grading to tuffaceous siltstone at 11300’; very light gray to off white; brittle; earthy fracture; sub nodular habit; earthy luster; silty to ashy texture. Tuffaceous sand/sand (11325'-11410') = very pale orange (ash), very light gray; clast size medium lower to fine lower; sub round; moderate to well developed sphericity; equant grain dimension; moderate sorting; pitted to impact text; unconsolidated to weakly consolidated with abundant devitrified ash matrix decreasing with depth; loosely attached; occurs as inter grain material; composed of predominantly quartz; fair increasing to good porosity and permeability; 10% dull even to mottled yellow sample ultra violet fluorescence; very poor light blue green transparent cut; no streamers; no stain; very poor dull yellow residue ultra violet stain. HK7T: 11316’ MD, 9771.25’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 175 1 60 66 3 27 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 11377 66 6323 663 649 105 248 55 63 Tuffaceous sand/sand (11316'-11433') = very pale orange (ash), very light gray; clast size medium lower to fine lower; sub round; moderate to well developed sphericity; equant grain dimension; moderate sorting; pitted to impact text; unconsolidated to weakly consolidated with abundant devitrified ash matrix decreasing with depth; loosely attached; occurs as inter grain material; composed of predominantly quartz; fair increasing to good porosity and permeability; 10% dull even to mottled yellow sample ultra violet fluorescence; very poor light blue green transparent cut; no streamers; no stain; very poor dull yellow residue ultra violet stain. Hilcorp Alaska, LLC M-31B 18 3.2.3 West Foreland Formation HKB/WFT: 11433’ MD, 9811.60’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 92 8 73 16 13 15 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 11449 16 1114 82 91 23 61 26 37 Tuffaceous siltstone = medium light gray to light gray; poor induration; slightly cohesive; non adhesive; sub planar fracture; sub nodular habit from well bore erosional transport; earthy luster; silty to clay texture; massive gradational beds of tuffaceous siltstone and tuffaceous clay grading to heavy ash laden silt; scattered fine and medium grained sands. WF1T: 11456’ MD, 9819.79’ TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 106 1 53 59 6 27 Peaks Depth TG C1 C2 C3 C4I C4N C5I C5N 11540 59 7282 228 149 34 35 16 14 Tuffaceous siltstone continued from WFT with medium light gray to light gray; poor induration; slightly cohesive; non adhesive; sub planar fracture; sub nodular habit from well bore erosional transport; earthy luster; silty to clay texture; massive gradational beds of tuffaceous siltstone and tuffaceous clay grading to heavy ash laden silt; scattered fine and medium grained sands. Devitrified ash/tuffaceous siltstone (11500'-11550') = yellowish gray to off white (ash) to light gray (silt); poorly indurated ash to firm silts; gradational medium to fine grain unconsolidated sand; ash is interbedded within some sands; ash appears reworked and redeposited; composed of ash, silt, carbon fines, chlorite and pyro clastic relic shards. Hilcorp Alaska, LLC M-31B 19 3.3 WELL LITHOLOGY CONGLOMERATE SAND/SAND (3700’ - 3820') = Very light gray to gray and various hues of both; clast size ranges from coarse lower to medium lower with low to moderate developed sphericity; unequal grain dimensions with moderate amounts of discoidal and triaxial grains; poor to moderate sorting; polished to chipped to impacted textures; sub mature nature; no visible cement; disaggregates easily; slight to moderate hydrophilic silt and clay matrix; both grain and matrix support; fair to good porosity; scattered weakly consolidated very fine sandstone and siltstone as matrix and as thin to thick bedding. TUFFACEOUS SILTSTONE (3820’ - 3910') = Very pale orange to very light gray and various hues of both colors; very poor to poor indurations; brittle; crumbly to crunchy; very poor to poor cohesiveness; non adhesiveness; earthy fracture; sub nodular habit from well bore transport; no discernable bedding or separation points; appears reworked; greasy to earthy luster; silty to gritty to ashy textures; gradational beds of tuffaceous silt and tuffaceous silty sandstones with moderate devitrified ash as matrix material; visible pyro classic relic shards in matrix; scattered loose sands. COAL (3910’ - 3920’) = Black; firm to hard; earthy to sub resinous luster; matte texture; irregular to sub blocky fracture; visible bleeding gas from cuttings; scattered parallel laminar patterns of light and dark layers along contacts of carbon shale and coal. SAND (3930’ - 4060') = Very light gray; clast size ranges from medium upper to fine upper; sub angular to sub round; low to moderate developed sphericity; moderate sorting; impacted texture; mature nature; unconsolidated with no visible cement; appears arenaceous after 4010'; dominant grain support; composed of predominantly quartz with secondary chert and >10% gray to dark gray lithics of siliceous mudstone (argillite); good estimated porosity and permeability; no show of oil fluorescence or oil cut; grading to tuffaceous silty sandstone. CARBONACEOUS SHALE AND COAL (4060’ - 4090') = Brownish black mottled black; visible discernable separation points between carbon shale and coal; soft in carbon clay at contacts to becoming firm in lignitic coals in mass; general earthy luster to scattered resinous; planar fracture along shale partings to sub blocky to sub conchoidal in coal; slight bleeds of gas from more mature coal. TUFFACEOUS SANDSTONE/SILTSTONE AND SAND (4090' - 4180’) = Medium light gray to brownish gray with light olive gray hues; from upper medium to upper fine; sub angular to sub rounded; moderate to low sphericity; poor to moderate sorting; mature to sub mature nature; predominantly quartz and 10% black to dark gray lithics; tuffaceous siltstone is very poorly indurated; crumbly to crunchy; poor cohesiveness; earthy texture; trace conglomeritic loose sand; upper medium to upper fine; sub angular to sub rounded moderate sphericity; conglomerate pebbles 2-3mm; high impact fracture. COAL (4180' - 4220') = Black; hard to firm; earthy to greasy luster; abrasive texture; irregular to blocky fracture; blocky to nodular cuttings habit; trace carbonaceous shale; grayish black to brownish black; firm to hard. TUFFACEOUS SILTSTONE/CLAYSTONE (4220' - 4300') = Light gray to olive gray with light brownish gray hues; very poor to poor to poor indurations; brittle to crumbly; poor to very poor cohesiveness; earthy fracture; sub nodular to nodular habit from transport up well bore; dull to earthy luster; silty to gritty to ash textures; no discernable bedding; tuffaceous sandstone is immature to sub mature; medium fine to fine; sub angular to sub rounded; scattered loose sand; hard black coal beds at 4230' and 4245'; earthy to greasy texture; irregular to sub blocky fracture. Hilcorp Alaska, LLC M-31B 20 TUFFACEOUS SILTSTONE/SANDSTONE (4300’ - 4360') =Medium light gray to olive gray with varying hues of both; poor to moderate indurations; poor to moderate cohesiveness; earthy fracture; nodular to sub nodular habit from well bore transport; fine cuttings; no discernable bedding; silty to gritty texture; dull to earthy luster; tuffaceous sandstone is matrix supported; fine to very fine grain; immature to sub mature; scattered poor to moderate sorted sands. COAL (4360' - 4380') = Black; firm to friable; earthy to vitreous luster; abrasive texture; blocky to irregular fracture; platy to wedge-like cuttings habit. TUFFACEOUS SILTSTONE (4380' - 4430') = Brownish gray to medium light gray with light gray undertones; malleable to sectile tenacity; mushy to pasty consistency; nodular cuttings habit; earthy to dull luster; tuffaceous clay becoming more dominant; light gray with brownish gray hues; cohesive to clumpy and pasty consistency. COAL (4430' - 4450') = Black to grayish black; hard to friable; vitreous to dull luster; blocky to platy cuttings habit. COAL, CARBONACEOUS SHALE AND TUFFACEOUS SILTSTONE (4450' - 4510') = Hard black coal; irregular to sub blocky fracture; waxy to sub greasy luster; matte texture; carbonaceous shale is moderate brown to brownish black; black lithics; light olive gray to medium light gray tuffaceous siltstone; clotted to curdy; malleable; earthy fracture; dull to earthy luster. SAND, CARBONACEOUS SHALE (4510' - 4550') = Light gray to medium gray; upper fine to lower coarse; low to moderate sphericity; sub rounded to sub angular; poor to moderate; unconsolidated with no visible cement; quartz dominant; > 10% medium gray to medium bluish gray lithics; light olive gray to moderate brown carbonaceous shale; firm to friable with minor black lithics. CONGLOMERATE SAND (4550’ - 4660') = Very light gray to light gray with scattered gray to dark gray; clast size ranges from coarse upper to medium lower; sub angular to angular bit impacted grains in coarse clasts to sub angular to sub round clasts in medium grains; low to moderate sphericity in coarse to well to moderate developed sphericity in medium poor sorting; chip to polish texture in coarse to impacted in medium grains; sub mature to mature nature; non to very slight silt/ash hydrophilic matrix decreasing to nil with depth; dominant grain support; composed of predominant quartz with secondary chert with 10% dark gray to black siliceous mudstones and trace lithic fragments; fair increasing to good porosity and permeability with depth; appears arenaceous; no show of oil fluorescence or oil cut. SAND (4660’ - 4790') = Very light gray to light gray; clast size ranges from coarse lower to medium lower; mean grain size is medium upper; sub angular to sub round scattered angular bit impacted coarse grains; moderate developed sphericity overall; poor to moderate sorting; dominant impacted texture; mature nature; non to very slight silt & ash matrix; dominant grain support; arenaceous; composed of predominant quartz with secondary chert and 10% dark gray to black argillite and trace lithic fragments; good porosity and permeability; increased tuffaceous silt at 4760' to 4895' and decreased porosity. COAL/CARBONACEOUS SHALE (4790’ - 4830') = Black to grayish black becoming brownish black along contacts of very carbon clay and carbonaceous shale; micro layered and micro laminated near contacts of very carbonaceous clay/shale and coal; firm to some hard in larger coal cutting earthy luster in carbon shale and clay to resinous in bituminous coals; blocky to irregular fractures in coal to sub planar in carbon shale; visible bleeding gas in fresh coal fragments; composed of very carbonaceous clay and shale grading to sub bituminous coal; gradation across the entire zone. Hilcorp Alaska, LLC M-31B 21 TUFFACEOUS SILTSTONE (4830’ - 4940') = Very light gray to pale yellowish gray and various hues of both; very poor to poor indurations; mushy to pasty; tacky to slimy; non to slightly cohesive; slight to moderate adhesive; hydrophilic; sub earthy to amorphous fracture; sub nodular to amorphous habit; greasy to earthy luster; ashy to silty to colloidal textures; massive gradational tuffaceous silts with some tuffaceous very fine matrix supported sandstones; some becoming very ashy. TUFFACEOUS SILTSTONE (4940' - 4995') = Medium light gray to light olive gray with varying hues of both; very poor to poor indurations; malleable to sectile; pasty to slimy; slight to no cohesion; slightly adhesive; amorphous to sub earthy fracture; greasy to earthy luster; silty to ashy texture; very minor very fine grain tuffaceous sandstone; immature to sub mature. COAL AND CARBONACEOUS SHALE (4995' - 5030') = Black; firm to hard; greasy to earthy luster; irregular to sub blocky fracture; visible out gassing; carbonaceous shale is grayish black to blackish brown; firm to sub firm. TUFFACEOUS SILTSTONE AND COAL (5030' - 5060') = Light gray to light olive gray malleable to crumbly; earthy fracture; amorphous habit; earthy to dull luster; silty to clayey; hard black coal; earthy to greasy; irregular to sub blocky; minor visible outgassing. TUFFACEOUS SILTSTONE AND CONGLOMERITIC SAND (5060' - 5140') = Light olive gray to medium light gray with varying hues of olive gray and brownish gray; malleable to crumbly; poor to moderate cohesion; poor to very poor adhesion; earthy fracture; nodular to amorphous; silty to clayey; light gray to medium light gray loose conglomeritic sand; medium to upper fine with occasional 2-3mm pebbles; high impact fracture; sub angular to sub rounded. TUFFACEOUS SILTSTONE (5140' - 5200') = Light gray to light olive gray with hues brownish gray; malleable to crumbly; moderate to poor cohesion; poor to very poor adhesion; earthy fracture; nodular to amorphous; silty to clayey; earthy to greasy luster. COAL (5200' - 5220') = Firm to hard; black to grayish black; earthy to greasy luster; irregular fracture; not visible out gassing; trace carbonaceous shale; grayish black to blackish brown; firm to sub firm. TUFFACEOUS SILTSTONE/CLAYSTONE (5220' - 5330') = Very light gray to light gray and various hues of both colors; very poor to poorly indurated; slightly sectile in parts; overall mushy to pasty non to slightly cohesive; slight to moderate adhesive; earthy fracture; sub nodular habit from erosional well bore transport; earthy luster; ashy to silty to clayey to colloidal textures; massive homogeneous beds of tuffaceous silt composed of 80% silt, 20% clay with visible pyroclastic relic shards in mass trace carbon laminae of clay/shale with rare thin very carbonaceous shale; trace interbedded devitrified ash and ash bleb particles within tuffaceous silt; thin beds of very fine tuffaceous sandstone stringers noted. CARBONACEOUS SHALE/COAL (5330’ - 5385') = Black to brownish black with subtle differences in color hues; generally firm with some brittle carbon shale; earthy to resinous luster; matte texture; irregular to blocky fracture in coal to sub planar in carbon shale; visible bleeding gas from true coals; composed of gradational carbon shale and lignitic coal to lignitic and bituminous at 5380'. TUFFACEOUS SILTSTONE (5385’ - 5520') = Very light gray to light gray; scattered brownish gray along carbon shale contact very poor to poorly indurated; sectile in parts; overall mushy to pasty non to slightly cohesive; slight to moderate adhesive; earthy fracture; sub nodular habit from erosional well bore transport; earthy luster; ashy to silty to clayey to colloidal textures; massive homogeneous beds of tuffaceous silt composed of 80% silt, 20% clay with visible pyroclastic relic shards in mass trace carbon laminae of clay/shale with thin 5' lignitic coal beds. Hilcorp Alaska, LLC M-31B 22 SAND/CONGLOMERATE SAND / CONGLOMERATE (5530’ - 5590') = Very light gray to light gray; clast size ranges from coarse lower to fine upper; scattered coarse upper to very coarse lower; angular coarse grain impacted fragments to sub round to subangular medium to fine grain very poor to poorly sorted; sphericity increasing with decrease in grain size; very poor to poorly sorted; chipped to polished in coarse grains to impacted in medium to fine grains; sub mature nature non to weak siliceous cement; loosely consolidated in part to overall unconsolidated; dominant grain support with slight hydrophilic silt/ash matrix; composed of dominant quartz with secondary chert and 10% dark argillite grains and siliceous coal grains; poor to fair porosity; poor permeability; thin coal and carbonaceous shale at 5550'-5560' grading back to conglomerate sand and sand. TUFFACEOUS SILTSTONE (5590’ - 5690') = Very gray to light brownish gray and various hues of both; very poor to poorly indurated; mushy to pasty; tacky to slimy; non to slight cohesiveness; slight to moderate adhesive; earthy fracture; sub nodular habit from well bore erosional transport; earthy luster; ashy to colloidal texture; gradational beds of tuffaceous silt and ashy silts; minor carbonaceous shale and clay stringers. COAL/CARBONACEOUS SHALE (5690’ - 5720') = Black mottled and micro layered brownish black at contacts; firm; earthy to resinous luster; matte to some smooth texture; irregular fracture in coal to sub planar fracture in carbon shale; occurs as thin laminae at 5705' to thin very carbon shale to coal at 5710'. SAND (5720’ - 5770') = Very light; clast size ranges from medium upper to fine upper; sub round; moderate developed sphericity; equant grain dimensions; moderate sorting; impacted texture; mature nature; arenaceous; no visible cement; unconsolidated; dominant grain support; no visible matrix material; composed of 90% quartz, secondary chert with trace lithics; good porosity and permeability; no oil indicators. COAL AND SAND (5770' - 5800') = Black to grayish black; firm to hard; earthy to greasy; irregular to sub blocky fracture; light gray to very light gray unconsolidated sand; no visible matrix; lower medium to upper fine. TUFFACEOUS SILTSTONE AND SHALE (5800' - 5830') = Light gray to light olive gray; malleable to crumbly; nodular; earthy to greasy luster; gritty to silty texture; earthy fracture; coal at 8525'; hard to firm; black to grayish black; earthy to waxy luster; sub blocky to irregular fracture; trace carbonaceous shale. SAND/CONGLOMERITIC SAND AND TUFFACEOUS SILTSTONE (5830' - 5910') = Very light gray to light olive gray with varying hues of olive gray and medium light gray; lower medium to upper fine to lower coarse; conglomeritic pebbles increase with the depth; sub rounded to sub angular; low to moderate sphericity; frosted to chipped with high impact fracture pebbles; pebbles range from 2-3mm in size; quartz dominant with varying chert and black lithics; moderate sorting; unconsolidated sands; no visible matrix; hard black coal at 5865' greasy to earthy luster; irregular to sub blocky fracture; light gray to light olive gray tuffaceous siltstone; crumbly to malleable; poor to moderate cohesion; poor to very poor adhesion; earthy fracture; dull to earthy luster; silty to granular texture. COAL, CARBONACEOUS SHALE (5610' - 5640') = Firm to hard; irregular to sub blocky fracture; earthy to waxy luster; moderate brown to dark gray carbonaceous shale; firm to brittle; earthy fracture; nodular to amorphous habit; greasy to earthy texture; black laminae; 2-3mm high impact conglomeritic sand; > 90% quartz with varying chert and black lithics. COAL AND CARBONACEOUS SHALE (5640' - 5995') = Firm to hard, irregular fracture; earthy to waxy luster; irregular fracture; tabular to nodular habit; earthy to waxy luster; abrasive texture; firm to hard carbonaceous shale; grayish black to moderate brown; visible black lithics; light olive gray to olive gray tuffaceous siltstone; crumbly; earthy to dull luster; silty to clayey texture. Hilcorp Alaska, LLC M-31B 23 SAND AND TUFFACEOUS SILTSTONE (5995' - 6160') = Very light gray to medium gray to light olive gray; varying hues of olive gray; lower medium to fine grain; sub rounded to sub angular; low to moderate sphericity; sub moderate to moderate sorting; trace 2-3mm conglomeritic pebbles; light olive gray to olive gray tuffaceous siltstone; malleable to crumbly; poor to moderate cohesion; nodular to amorphous habit; dull to earthy luster; silty to clayey. COAL, TUFFACEOUS SILTSTONE, AND SAND (6160' - 6220') = Dark matte black to vitreous black color; hard tough brittle with blocky to flaky cuttings; smooth to rough texture due to eroded layers on coal cuttings; visible degassing from coal cuttings. TUFFACEOUS SILTSTONE (6220’ - 6270') = Very light gray to light gray and various hues of both colors; very poor to poorly indurated; brittle; mushy to pasty; slimy to tacky; non to very slight cohesiveness; slight to moderate adhesiveness; earthy fracture; sub nodular habit from erosional well bore transport; earthy to slightly greasy luster; ashy to colloidal to silty texture; massive gradational tuffaceous siltstone composed of 80% silt, 20% ash and various detrital material. COAL AND CARBONACEOUS SHALE (6270’ - 6280') = Overall black with dark gray laminations at contacts; firm; earthy to resinous luster; matte texture; irregular fracture in coals to sub planar fracture along carbon shale partings; visible bleeding gas; composed of very carbon shale to sub bituminous coal. TUFFACEOUS SILTSTONE (6280’ - 6460') = Very light gray to light gray scattered light brownish gray and various hues of both; very poor to poorly indurated; brittle; mushy to pasty consistency; tacky to slimy; non to very slight cohesiveness; slight to moderate adhesiveness; earthy fracture; sub nodular habit from well bore erosional transport; earthy to greasy luster; ashy to silty to sub colloidal texture; hydrophilic with 50% going into solution and increased amount with increased clay content; massive gradational tuffaceous silt composed of 80% silt, 20% ash, pyroclastic relic shards and various detrital material; scattered very carbonaceous shale as laminae to very thin beds; thin beds of coal and gradational very carbonaceous shale beds. TUFFACEOUS SANDSTONE/SAND/SANDSTONE (6440’ - 6520') = Very light gray to white with increased ash content as matrix; clast size ranges from medium upper to fine upper grading to very fine and silt sub round; moderate developed sphericity equant grain size; poor to moderate sorting; impacted texture; sub mature nature; slight siliceous cement which is weakly consolidated; moderate to abundant ash/silt matrix material all hydrophilic and loosely attached; composed of 90% quartz with secondary chert and trace lithic fragments; poor porosity and permeability; ash rich sand with pyroclastic relic shards in mass; no show of oil indicators. COAL/CARBONACEOUS SHALE (6420’ - 6460') = Black to brownish black to grayish black and various hues of all; firm; earthy to resinous luster; matte texture; irregular fracture in coal. SAND (6460’ - 6530') = Very light gray; clast size ranges from medium upper to fine upper; sub round; moderate to well developed sphericity; equant grain dimensions; moderate to well sorted; pitted to impacted textures; mature nature; non to slight siliceous cement; unconsolidated with dominant grain support; arenaceous; no visible matrix; composed of 90% quartz with secondary chert, trace argillite; good porosity and permeability; no oil indicators. COAL (6530’ - 6540') = Black; firm; earthy to resinous luster; matte texture; irregular fracture; slight visible bleeding gas from coal cuttings. Hilcorp Alaska, LLC M-31B 24 SAND/TUFFACEOUS SANDSTONE (6540’ - 6705') = Very light gray sand to light brownish gray tuffaceous sandstone grading to tuffaceous silt; clast size medium upper to fine upper grading to very fine in tuffaceous sandstone; mature nature with sub mature sandstones; mature sand increasing with depth; moderate sorted sand to poorly sorted sandstone; sand is grain supported and tuffaceous sandstone is matrix supported and grading to silts good sand porosity to poor in tuffaceous sandstones; no oil indicators. SAND (6710’ - 6770') = Very light gray; clasts size medium upper to fine lower; sub round; moderate to well sphericity; moderate to well sorted; mature nature; arenaceous; good porosity; no oil. SAND, TUFFACEOUS SANDSTONE, CONGLOMERATE ( 6770' - 6850') = Medium gray to dark gray color; unconsolidated sands of lower medium to upper coarse to trace conglomerates; sand poorly sorted; angular to subrounded; low sphericity; interbedded with tuffaceous sandstones, tuffaceous siltstones and trace coal clasts; tuffaceous sandstones are matrix supported with fine to very fine grains in a volcanic ash, tuff and devitrified glass composition; the tuffaceous sandstones are weakly indurated and very friable; tuffaceous sandstones are grading to tuffaceous siltstones. TUFFACEOUS SILTSTONE (6850' - 6910') = Medium gray to dark gray color; weakly indurated and friable when hydrated; soft malleable tenacity and irregular fracture; rounded to blocky cuttings; gritty texture; thin to thick structure; grading to tuffaceous shale; interbedded with loose unconsolidated sands and trace conglomerate sandstone, conglomerates, and trace coal clasts probably falling in hole from above. COAL AND TUFFACEOUS SANDSTONE ( 6910' - 6990') = Black to matte to vitreous shiny black color; hard brittle; irregular fracture; visible degassing; interbedded with tuffaceous sandstone of medium gray to dark gray color; very fine grains in a matrix supported volcanic cement; overall friable and weakly cemented; grading to tuffaceous siltstone of medium to dark gray color; crumbly to crunchy when dehydrated; rounded to blocky cuttings habit; irregular fracture; gritty textured with dark carbonaceous material interbedded within tuffaceous siltstone clasts. COAL (6990' - 7005') = Black gray to matte black to vitreous black color; blocky to flaky to splintery cuttings; firm, tough to brittle tenacity; splintery irregular fracture; smooth slightly rough texture due to cratered and jagged edges of broken laminae on sides and top of coal clasts; visible degassing. TUFFACEOUS SILTSTONE AND TUFFACEOUS SANDSTONE ( 7005' - 7090') = Medium dark gray to very dark gray with black hues; irregular fracture; rounded blocky soft malleable tenacity; rounded blocky cuttings habit; interbedded with loose unconsolidated sands, and tuffaceous sandstones of malleable when hydrated to crumbly to crunchy when dehydrated; gas background low, no oil indicators. SAND (7090' - 7190') = Medium gray to dark gray to very dark gray with black hues; individual grains range from gray white opaque to dark gray with blue hues to translucent clear to slightly yellow in color; poor to fair sorted with lower coarse to upper coarse grain size; thinly interbedded layers of tuffaceous siltstone; low to fair sphericity; dominantly subrounded grains with immature angular to mature rounded grains; trace green stone possibly chlorites and black carbonaceous material with trace tough brittle coals; loose unconsolidated sand body appears to be coarser down the sequence; lower coarse to upper very coarse to 2 mm conglomerates are appearing through out sample depth. COAL ( 7190' - 7210') = Flat black, matte black to vitreous shiny black color; blocky to splintery cutting; planar to irregular splintery flaky cuttings; obvious signs of shear stress in coal with conchoidal burst from hard tough brittle clasts; no fluorescence. Hilcorp Alaska, LLC M-31B 25 SAND AND TUFFACEOUS SILTSTONE (7210’ - 7315') = Loose unconsolidated sands of grayish white to medium gray with blue hues to translucent clear to slightly yellow color; alternating layer of very fine to fine grain to lower sequences of lower coarse to lower very coarse grains; trace conglomerates of 2 mm to 3 mm; trace carbonaceous shale; tuffaceous siltstone thinly bedded throughout; tuffaceous siltstone medium dark gray to dark gray with black hues; irregular fracture and crumbly tenacity. CONGLOMERATE SAND/CONGLOMERATE (7315’ - 7450') = Very light gray to light gray; clast size ranges from very coarse upper to medium lower becoming finer after 7390'; sub angular to sub round; some angular coarse grain bit impacted grains; moderate sphericity; general equant grains some discoidal to prolated poor sorting; chip to polish textures becoming impacted with decreased grain size; sub mature overall; unconsolidated with minor siliceous fragment, sandstone; sand is grain supported with fingers of silt/ash matrix; composed of 90% quartz with secondary chert and trace lithics; poor to good porosity and permeability; no show of oil fluorescence or cut. COAL/CARBONACEOUS SHALE (7430’ - 7445') = Black laminated dark brown to brownish black in carbon shales; firm; earthy luster in carbon shale to resinous luster in lignitic coal; irregular fracture to sub planar fracture along carbonaceous shale partings; no visible bleeding gas from cuttings. TUFFACEOUS SILTSTONE (7445’ - 7510') = Very light gray to light brownish gray; poor indurations; slightly sectile in parts; slightly resistive to probing; mushy; tacky to slimy; slightly cohesive; moderate adhesive; earthy fracture. TUFFACEOUS SILTSTONE (7510’ - 7600') = Very light gray to light brownish gray; poor indurations; slightly sectile in parts; slightly resistive to probing; mushy; tacky to slimy; slightly cohesive; moderate adhesive; earthy fracture; sub nodular habit from erosion from well bore transport; earthy to greasy luster; silty to ashy texture; some grading to very fine grained tuffaceous sandstone; thin very carbonaceous shale grading to a sub lignitic coal noted with no bleeding gas from any coal cuttings. TUFFACEOUS SILTSTONE (7600’ - 7650') = Very light gray to light brownish gray; poor indurations; slightly sectile in parts; slightly resistive to probing; mushy; tacky to slimy; slightly cohesive; moderate adhesive; earthy fracture; sub nodular habit from erosion from well bore transport; earthy to greasy luster; silty to ashy texture; some grading to very fine grained tuffaceous sandstone. AND / CONGLOMERATE SAND (7650’ - 7720') = Very light gray to light gray; clast size medium upper to fine upper becoming coarse lower to medium at 7680'; sub round; moderate developed sphericity; equant grain dimensions; moderate to some poor sorting past 7680'; impacted to pitted texture some angular bit impacted grains with depth; mature nature; unconsolidated; no visible cement or matrix material; grain support composed of 90% quartz secondary chert trace argillite, feldspar and green stone; good porosity and permeability; no oil indicators. CONGLOMERATE SAND (7720’ - 7850') = Diverse colors ranging from very light gray to light gray; white; light greenish gray; orange and various hues of most; clast size pebble to coarse lower; abundant bit impacted angular grains to sub angular; low developed sphericity overall; very poor sorting; chip to polished textures; mature nature; no visible matrix clays; dominant grain support; appears as a sub greywacke; composed of 50% quartz, 20% chert, 30% black to dark gray siliceous mudstone, feldspar, tuff and trace greenstone; fair to good estimated porosity and permeability; no show of oil indicators. CARBONACEOUS SHALE (7850’ - 7880') = Grayish black to dusky brown laminations firm in coal to brittle in carbon shale; dominate earthy luster to secondary resinous luster; irregular to sub planar fracture; o visible bleeding gas; thin. Hilcorp Alaska, LLC M-31B 26 TUFFACEOUS SILTSTONE (7880' - 7910') = Medium dark gray to dark gray with blue and light black hues; trace loose unconsolidated sands, conglomerate sands, conglomerates, carbonaceous shale, silicic conglomerates grayish white to blue white to light pink color; tuffaceous siltstone is crumbly when hydrated; irregular fracture; rounded flaky to blocky cuttings; gritty texture dull earthy luster with thin to thick structure; light green fluorescence surrounding clasts possibly a additive. COAL/CARBONACEOUS SHALE (7930' - 7995') = Dark brown with black thin laminae; crumbly to firm; blocky cuttings with irregular fracture; smooth to slightly gritty texture; coals are black to matte to shiny vitreous black; firm brittle tenacity; planar to splintery fracture; splintery to blocky cuttings; smooth to slightly rough texture with visible conchoidal fracture cratering and shear seen as cleat; coal and carbonaceous shales are interbedded with larger tuffaceous sandstones and sands. SAND/CONGLOMERATE SAND (7995’ - 8055') = Very light gray to light gray; clast size ranges from coarse lower to medium lower; sub angular to sub round; moderate developed sphericity; equant grains; moderate sorting; pitted to impacted texture; sub mature to mature nature; unconsolidated; slight silt/ash fine sandstone clusters; sand is grain supported; fair to good porosity and permeability; no oil indicators. SAND (8055’ - 8165') = Very light gray to light gray; clast size ranges from medium upper to fine upper; moderate to well developed sphericity; equant grains moderate to well sorted; impacted texture; mature nature; no visible matrix material; arenaceous; dominant grain support. CARBONACEOUS SHALE AND SILT (8155’ - 8175') = Heterogeneous colors of light brownish gray and black with discernable separation points of carbon shale, carbon silt and coal with parallel laminar patterns; alternating luster of earthy and sub resinous; distinct sub planar fractures. TUFFACEOUS SILTSTONE (8175’ - 8245') = Light brownish gray to light gray; poor indurations; crunchy in parts; slight to moderate resistant to probing; slightly cohesive; slight to moderate adhesive; earthy fracture; sub nodular habit; earthy luster; silty to gritty to ashy textures; massive gradational siltstone composed of 90% silt, 10% various detrital material; trace carbon material. COAL/CARBONACEOUS SHALE (8245’ - 8345') = Dark grayish black to dark black to matte black to vitreous black color; hard firm very brittle tenacity; visible cleat and degassing; visible shearing marks in planar to irregular fracture as conchoidal burst, laminae sheared off coal clasts; smooth to rough texture due to bit action on planar coal cuttings; dull matte to shiny vitreous wet appearance; interbedded with carbonaceous shale in grayish brown to brown to dark brown with thinly bedded black laminae; crumbly to crunchy to sometimes hard and firm tenacity; planar to dominantly irregular fracture; rounded blocky to flaky cuttings; smooth textured with thick to thin basal structure; trace conglomerates trace loose unconsolidated coarse sands, feldspars, tuffaceous siltstones and tuffaceous sandstone with clay based sandstone in matrix cement. COAL ( 8345' - 8380') = Matte black to vitreous black color; firm hard tough brittle; planar to flaky to splintery fracture; blocky to splintery cuttings; smooth to slightly rough texture due to bit action and shear stress; large thick blocky to thin flaky clasts; cleat and visible degassing; no fluorescence. TUFFACEOUS SILTSTONE ( 8380' - 8475') = Medium gray to dark gray with brown hues; crumbly to crunchy tenacity; irregular fracture; rounded equant cuttings; gritty texture; thin to thick structure; tuffaceous sandstone, feldspars, carbonaceous shale, loose unconsolidated sands of lower coarse to upper coarse with trace in lower very coarse grain size; sand fairly well sorted of subangular to subrounded with fair sphericity; and low textural maturity; trace coal are appearing; tuffaceous siltstone does not fluoresce; no oil indicators as yet. Hilcorp Alaska, LLC M-31B 27 SAND/TUFFACEOUS SANDSTONE AND TUFFACEOUS SILTSTONE (8475'-8525') = Loose sands have grayish white opaque, blue gray color to translucent clear to rare yellow color; unconsolidated; very well sorted; low medium to coarser upper coarse grain size; angularity of subrounded to round with low to fair sphericity; tuffaceous sandstone in a matrix cement composed of volcanic ash tuff and devitrified glass grading towards tuffaceous siltstone of the same composition and friable not well indurated; tuffaceous sandstone shows low visual porosity; no fluorescence. SAND/TUFFACEOUS SANDSTONE ( 8525' - 8600') = Loose unconsolidated sands of clear to opaque grayish white and blue; poor to fair sorting; low to moderate sphericity with subangular to subrounded with low textural maturity; tuffaceous sandstone in a matrix supported cement with fairy fine quartz grains. COAL (8600' - 8620') = Flat black to vitreous shiny black; firm tough brittle with planar to irregular fracture; sharp edged blocky to shards of flaky splintery cuttings; smooth texture; conchoidal burst and cleat; thick to thin structure. SAND/TUFFACEOUS SANDSTONE (8620’ - 8695') = Loose unconsolidated sands; moderately sorted; low medium to low coarse grain size; interbedded with tuffaceous sandstone; sandstone is dominantly matrix supported cement with some grain support; unconsolidated sand. TUFFACEOUS SILTSTONE (8695’ - 8760') = Very light gray to light brownish gray and various hues; very poor to poor indurations; mushy; non to slightly cohesive; slight to moderate adhesive; earthy fracture; sub nodular habit; earthy luster; silty to ashy textures; gradation carbon clay, carbon silt and carbon shale with low grade coal beds. COAL/CARBONACEOUS SHALE ((THINLY BEDDED) 8760’ - 8800') = Black mottled grayish brown to light brownish gray at contacts firm; resinous to earthy luster; matte texture; sub conchoidal to irregular fractures; micro layered with parallel patterns of light and dark carbon. CONGLOMERATE SAND (8800’ - 8880') = Very light gray to light gray; clast size coarse upper to medium lower; angular bit impacted grains to sub angular to sub round medium grains; low to moderate sphericity; poor sorting; polish to chip to impacted texture; mature nature; slight siliceous cement in lower medium sandstone clusters possible matrix sand; unconsolidated and grain supported; composed of 90% quartz, secondary chert trace lithics; good porosity and permeability; no show of oil. CONGLOMERATE SAND/SAND (8880’ - 8920') = Very light gray to light gray; white; clast size very coarse upper to medium lower; angular bit impact coarse grains to sub round medium grains possible matrix sands; very poor sorting chip to polish to impact texture; sub mature nature; no matrix material; grain support; composed of 85% quartz, 10% chert, 10% argillite and siliceous mud stones, feldspars; fair to good porosity and permeability; no oil indicators. TUFFACEOUS SILTSTONE (8920' - 8950') = Medium gray to dark gray color; soft to crumbly tenacity; irregular fracture; blocky to wedge like cuttings; rough texture; dull earthy luster; thin to thick structure; no oil indicators. COAL (8980' - 9015') = Brownish black to matte black to vitreous black; hard firm tough tenacity; planar to irregular fracture; blocky to splintery cuttings; smooth to slightly rough texture due to exterior conchoidal fracture and cleat causing protruding laminae; interbedded with carbonaceous shale and trace tuffaceous siltstone and loose sands without cement; no fluorescence. SAND (9015' - 9055') = Translucent clear to blue with opaque grayish white to gray with blue hues; loose unconsolidated with fair sorted; low medium to upper coarse; subangular to subrounded; dominantly quartz at 90%; coal, feldspar, tuffaceous siltstone, and trace tuffaceous sandstones at 10%; fair to moderate sphericity; young to slightly mature textural maturity. Hilcorp Alaska, LLC M-31B 28 SAND/TUFFACEOUS SANDSTONE (9055' - 9140') = Loose unconsolidated sands; subangular to subrounded to rounded grains; low medium to low coarse grain size; well sorted; fair sphericity leading to parts of the sequence is young and others more weathered and texturally mature; tuffaceous sandstone friable, low indurated visually good porosity clasts. SAND (9140’ - 9220') = Very light gray to light gray; clast size ranges from medium lower to fine lower; sub round to round; moderate to well developed sphericity; equant grains; moderate to well sorted; impacted texture; mature nature; non to very weak siliceous cement; no visible matrix material; dominant grain support; arenaceous; composed of >90% quartz, secondary chert trace lithics; good porosity and good permeability; samples become very clean after 9180' with no sample fluorescence with a trace cut; poor over all. VERY CARBONACEOUS SHALE/CLAY AND COAL (9220’ - 9250') = Occurs as thin beds with very carbonaceous clay and silt at contacts grading to carbon shale and coal at gas maximum; black mottled brownish black; soft in clay to firm in coal; resinous mottled earthy luster; P.D.C. bit ground up cuttings; no visible bleed of gas from cuttings. SAND (9250’ - 9305') = Very light gray to light gray; clast size medium upper and lower to fine upper and lower; round to sub round; moderate to well developed sphericity; equant grains; moderate to well sorted; impact texture; mature nature; unconsolidated; grain supported; arenaceous; composed of >90% quartz, secondary chert, trace lithics; good porosity and permeability; grades to tuffaceous siltstone; no show of oil. COAL/CARBON SHALE (9305’ - 9360') = Thin beds of carbon shale brownish black to 9345' in which black bituminous coal; firm to hard; sub conchoidal to blocky fracture; visible bleeding gas. SAND (9360’ - 9385') = Continued medium to fine unconsolidated sands; no sample fluorescence; no stain, no odor; slow increasing to moderate streaming yellowish white cut; slow development to hazy bluish white cut; faint start residue stain; continued poor show through 9425' sand. SANDSTONE (9450’ - 9520’) = Very fine grains in a matrix dominated carbonaceous matrix cement; weakly cemented; grains subrounded and fair sorted; in high sphericity; mature textural maturity; quartz at 70%-80% with dark carbonaceous clasts, calcite, feldspars, and trace green stone possibly chlorite; sandstone interbedded with loose unconsolidated sands and thin stringers of coal and carbonaceous shales; gas rises steeply in thin coal stringers; very faint yellow cut. SAND/SANDSTONE (9520' - 9615') = Loose unconsolidated sands of upper fine to upper coarse grains; poorly sorted; angular to subrounded grains; dominantly quartz of 80% with accessory minerals of carbonaceous shale, feldspars, calcite, more than trace conglomerates and very coarse grains of quartz, carbonaceous shales, very tight microcrystalline sandstone; and coal that has possibly fallen down hole; overall sandstone is matrix supported to trace grain supported in a angular to sub- -angular with low to moderate sphericity and fair sorting; friable easily sheared when hydrated with a tight low visual porosity in the sandstones; no cut or fluorescence. COAL (9615' - 9655') = Flat dull matte to vitreous black; blocky to splintery in a firm to brittle tenacity; planar to splintery irregular fracture; smooth texture; dull to shiny vitreous luster; visible degassing; no fluorescence or cut. Hilcorp Alaska, LLC M-31B 29 SAND/SANDSTONE (9655' - 9700') = Upper fine to lower very coarse poorly sorted grains; trace conglomerates, of 2 mm and larger; angular to subangular; stringers of sandstone interbedded with loose unconsolidated sands of 80% quartz and the rest of feldspars, calcites, dark carbonaceous material, and coal; poor to slightly fair sorting; subangular to subrounded; low to moderate sphericity; textural maturity of half way from immature to mature; no fluorescence no cut; carbonaceous weakly cemented, low porosity; matrix supported sandstone. SAND/SANDSTONE (9700' - 9800') = Dirty white opaque to gray with blue hues to translucent to translucent grayish white color; dominantly quartz in a loose unconsolidated sand interbedded with low indurated weakly carbonaceous matrix supported sandstone; low visual porosity and subrounded; fair sorted; moderate sphericity; moderate mature textural maturity; faint fluorescence; no cut. COAL (9787' - 9825') = Dull matte black to vitreous black color; firm tough brittle; planar to irregular fracture; smooth texture; dull to vitreous shiny luster; visible degassing; conchoidal fracture; faint orange fluorescence and cut; dominant blocky sharp edged clasts; thin basal structure. TUFFACEOUS SILTSTONE (9825' - 9890') = Very light gray overall with scattered medium light gray and dull white; moderate indurations becoming poorly indurated in increased ashy silts; stiff moderate cohesive; non to slightly adhesive; sub planar to earthy fracture; sub platy to sub nodular habit; earthy to slightly greasy luster; silty to gritty to ashy textures; massive gradation tuffaceous silt with various ash content; grading to devitrified ash. DEVITRIFIED ASH/TUFFITE (9890' - 9950') = White mottled salt and pepper; very poor induration; greasy to earthy luster ashy to clayey to sub colloidal textures; massive bedding of gradational ash, tuffite and tuffaceous siltstone; appear redeposited and reworked. CONGLOMERATE SAND (9950’ - 9990') = Very light gray; clast size very coarse upper to fine lower; angular bit impacted sand to sub round medium/fine grains; poor to well developed sphericity; moderate to poor sorting; pitted to chip to polished textures; unconsolidated to weakly consolidated slight to moderate ash/silt matrix which is very hydrophilic; both grain and local matrix support; 30% moderate yellow green even sample florescence at 9955' to 70% at 9965', no oil stain or odor; no oil pops, instant transparent light blue white slow to moderate streaming cut with slow development to hazy cut; dull yellow residue ultra-violet stain, no white light oil residue. COAL (9990’ - 10040') = Black; firm; resinous luster; matte texture; hackly to irregular fracture; no out gassing. CONGLOMERATE SAND/CONGLOMERATE (10040’ - 10155') = Very light gray; clast very coarse upper (some pebble) to medium lower; angular bit impacted grains to sub round in medium grains; low to moderate sphericity; poor sorting; chip in coarse to impacted in medium grains; sub mature nature; weak siliceous cement and medium grain matrix sand; mostly unconsolidated; fair estimated visual porosity; evidence of conchoidal burst; faint blue yellow white fluorescence and streaming, and yellow residual ring; conglomerates ranging in size from 2mm to 7mm; conglomerates dominantly quartz of sharp angularity due to bit action; trace coal and tuffaceous siltstone possibly due to falling down hole. SAND/CONGLOMERATE SAND/ CONGLOMVERATES (10155' - 10240') = Medium gray to light grayish white color; upper medium to upper very coarse to conglomerates ranging in size from 2 mm to 5 mm; loose unconsolidated sands are subrounded to rounded with high sphericity; fair sorting with overall textural maturity very high; trace calcites, and chert no free oil in mud; no petroleum odor; no visible oil stain; 40-60% moderate to dull yellow even to mottled oil fluorescence; instant transparent weak light blue white cut fluorescence with slow streaming cuts slow development; weak yellow ultra-violet stain; pale straw visible. Hilcorp Alaska, LLC M-31B 30 SAND/CONGLOMERATE SAND/CONGLOMERATES (10240' - 10325') = Grayish white to white with reddish hues; loose sands uncompacted interbedded with larger conglomerates and trace coarse sandstone in a tough indurated grain supported clasts; conglomerates dominantly quartz with trace chert, and green chlorite in quartz; sands are subrounded to round and conglomerates are more angular due to bit impaction; no free oil; no oil stain; no petroleum odor; instant weak light blue fluorescent cut with slow development cuts light blue white; weak yellow ultra-violet residue stain; no white light visible oil stain. SAND/CONGLOMERATE SAND/CONGLOMERATES (10325’ - 10395’) = Grayish white opaque to translucent white with blue hues; poor to fair sorted; subrounded to rounded with conglomerates angular; loose uncompacted sands upper medium to very coarse; continued decreased oil fluorescence; 30-40% even to mottled dull to some moderate yellow oil fluorescence; no oil stain; no petroleum odor; no free oil in mud; instant dull transparent oil cut with no visible streams; weak yellow ultra violet stain. SAND/CONGLOMERATE SAND/CONGLOMERATES (10395' - 10480' ) = Translucent to gray with blue hues to grayish white opaque to green and blue opaque; loose unconsolidated lower medium to upper coarse grains; poor sorted; subrounded to rounded with sands interbedded with conglomerate sand; 60% even to mottled yellow sample fluorescence; no odor; no oil stain; instant transparent light cut slow development to hazy cut; no streamer weak to moderate yellow ultra-violet oil residue; no visible white light oil stain. SAND/CONGLOMERATE SAND/ CONGLOMERATES (10480’ - 10545’) = Translucent to opaque quartz of grayish white to grayish white with blue, green and red hues; poorly sorted with lower medium to very coarse grains to conglomerates of 2mm to 3mm; even to mottled yellow fluorescence; no odor or oil stain; rapid bright yellow cut; no visible streaming; strong yellow residual ring; low oil ultra violet oil stain; gas back ground low, and gas rise to 71 u. SAND/CONGLOMERATE SAND/CONGLOMERATES (10545' - 10610' ) = Increase of 2mm conglomerates and conglomerate sands loose unconsolidated sands subrounded rounded; conglomerates angular to subangular; dominantly quartz at 90% with calcite, chlorite, feldspar, trace jasper and chert; no odor or oil stain; instant mild yellow cut; no visible streaming; mild yellow residual ring; no visible white light stain. COAL (10610' - 10630') = Matte black to vitreous black color; firm tough to very hard and brittle; planar to splintery irregular fracture; smooth texture; dull matte black to shiny vitreous bituminous coal; surface shear patterns and conchoidal cratering; no visible degassing; no cut or stain; ultra violet fluorescence and cut of light milky yellow green. SAND/ CONGLOMERATE SAND/CONGLOMERATE (10630’ - 10730’) = Loose sands and broken up materials from conglomerate sandstone ground up by bit action interbedded with conglomerates of 2mm to 4mm to loose unconsolidated sands of upper medium to very coarse grains poorly sorted and medium to high sphericity; overall mature textural maturity; no cut or stain; fluorescence under ultra violet of mild green yellow; cut no streaming but green yellow residual ring. SAND/CONGLOMERATE SAND/ CONGLOMERATE (10730’ - 10780' ) = Loose unconsolidated sands, ground up conglomerate sandstone and conglomerates dominantly quartz; sands subrounded to round; poorly sorted and medium to high sphericity; high textural maturity; no odor, no stain ultra violet milk white yellow cut and fluorescence; no streaming and no white light stain; no residual ring. Hilcorp Alaska, LLC M-31B 31 CONGLOMERATE SAND/CONGLOMERATE (10780’ - 10900') =Very light gray to light gray; off white; clast size pebble/very coarse upper to medium grains; angular bit impacted coarse to sub angular to sub round matrix sand; low to moderate developed sphericity; very poor sorting; coarse grains chipped and polished with impacted medium matrix sand; dense fine to very fine sandstone at 10850’; very weak siliceous cement; grain supported; no visible matrix clay/silts; fair to good estimated porosity; gradational; 10-30% dull to moderate even to mottled yellow green sample oil fluorescence; instant transparent light blue white oil cut; no visible streaming cuts; slow development cuts; very weak dull yellow residue ultra violet stain; no visible white light stain. CONGLOMERATE SAND/CONGLOMERATE (10900’ - 11035') = Very light gray to light gray; clast size very coarse upper to fine upper; angular bit impacted coarse grain to sub angular to sub round medium to fine grains; low developed sphericity; discoidal, triaxial and prolated grains; very poorly sorted; chipped and polished coarse grains to impacted and pitted medium to fine grains acting as matrix sand; unconsolidated; no visible cement or matrix clays; arenaceous; grain support; fair porosity and permeability; 20-40% yellow even to mottled oil fluorescence; no stain, no odor; instant transparent light blue green with slow increase to light blue white oil cut; slight dull yellow ultra violet residue stain with no visible white light oil stain; poor oil shows possible oil being flushed into the mud system when sands are disaggregated. TUFFACEOUS SILTSTONE/CARBONACEOUS CLAY (11035' - 11080') = Light yellowish gray to light gray and various hues of both colors with parallel laminar patterns of light silt and dark carbon clay; very poor to poorly indurated; brittle; slightly expansive when hydrated; slight cohesiveness and adhesiveness; earthy fracture; sub platy to sub nodular habit earthy luster; ashy texture; massive heterogeneous structure of micro laminated carbon clay and tuffaceous siltstone; possible very thin coal seams carbonaceous shale and carbon clay. SAND (11080’ - 11160' ) = Grayish white opaque to white with blue or green hues from translucent clear to blue yellow; subrounded to round; poorly sorted upper medium to lower very coarse; fair to high sphericity; worked high textural maturity; etched and conchoidal craters; 10 - 20% fluorescence; no odor or stain; poor slow dull cut; trace residue stain. COAL (11160' - 11200’) = Black color; firm tough brittle; planar to splintery; blocky to wedge like; smooth texture; thin to thick structure; bituminous coal visible degassing when hydrated. CONGLOMERATE SAND (11200’ - 11260') = Very light gray to light gray; clast very coarse upper to fine upper; angular to sub round; very poor sorting; chip and impact textures; unconsolidated; trace tuff/silt loose matrix; grain support; fair to poor porosity and permeability; 10% dull yellow mottled fluorescence and poor cut. CONGLOMERATE SAND (11260’ - 11275') = Very light gray to light gray; clast very coarse upper to fine upper; angular to sub round; very poor sorting; chip and impact textures; unconsolidated; trace tuff/silt loose matrix; grain support; fair to poor porosity and permeability; 10% dull yellow mottled florescence and poor ct. CARBONACEOUS CLAY AND COAL (11275’ - 11325’) = Brownish gray to brownish black; micro laminated with lighter and darker carbonaceous silt, clay and sub lignitic coal; brittle to some firm; earthy luster; silty to matte texture; common sub planar fracture along coal fractures grading to tuffaceous siltstone at 113xx very light gray to off white; brittle; earthy fracture; sub nodular habit; earthy luster; silty to ashy texture. Hilcorp Alaska, LLC M-31B 32 TUFFACEOUS SAND/SAND (11325' - 11410') = Very pale orange (ash), very light gray; clast size medium lower to fine lower; sub round; moderate to well developed sphericity; equant grain dimension; moderate sorting; pitted to impact text; unconsolidated to weakly consolidated with abundant devitrified ash matrix decreasing with depth; loosely attached; occurs as inter grain material; composed of predominantly quartz; fair increasing to good porosity and permeability; 10% dull even to mottled yellow sample ultra violet fluorescence; very poor light blue green transparent cut; no streamers; no stain; very poor dull yellow residue ultra violet stain. TUFFACEOUS SILTSTONE (11410’ - 11500') = Medium light gray to light gray; poor induration; slightly cohesive; non adhesive; sub planar fracture; sub nodular habit from well bore erosional transport; earthy luster; silty to clay texture; massive gradational beds of tuffaceous siltstone and tuffaceous clay grading to heavy ash laden silt; scattered fine and medium grained sands. DEVITRIFIED ASH/TUFFACEOUS SILTSTONE (11500' - 11550') = Yellowish gray to off white (ash) to light gray (silt); poorly indurated ash to firm silts; gradational medium to fine grain unconsolidated sand; ash is interbedded within some sands; ash appears reworked and redeposited; composed of ash, silt, carbon fines, chlorite and pyro clastic relic shards. Hilcorp Alaska, LLC M-31B 33 3.4 SAMPLING PROGRAM AND DISTRIBUTION Set Type and Purpose Interval Frequency Distribution 1 Washed and Dried 3760’ – 11550’ 30’ Debra Oudean Hilcorp Alaska LLC, Suite 100 3800 Centerpoint Drive Anchorage AK 99503 2 Washed and Dried 3760’ – 11550’ 30’ AOGCC Attn: Christine Mahnken 333 W 7th Ave, Suite 100 Anchorage, AK 99501 Hilcorp Alaska, LLC M-31B 34 4 DRILLING DATA 4.1 DAILY ACTIVITY SUMMARY January 9th 2013: Trip out of the hole from 1397' checking every connection for cement. Lay down BHA and empty junk basket of 337 pounds of metal. Clean the rig floor and make up new BHA. Hold a pre job safety meeting and service the rig. Trip in the hole to 3664' and Kelly up and establish drilling parameters and test the MWD. Respond to an Abandon Platform Drill. Clean out the hole to the bottom at 3700' and drill cement to 3727' and slide from 3727' TO 3773'. Slowly working away from the M31A old well bore. Slide to 3844’ and rotate from 3844' TO 3885'. January 10th 2013: Slide and rotate the formation from 3885' To 4800' and make routine surveys and connections. January 11th 2013: Slide/rotate from 4800' to 4935'. Temporarily detained at 4935'. Had one full circulation and one jar kick at 280K and freed pipe. Rote/slide from 4935' to 5142'. Circulated and conditioned the hole. Pumped a 32 bbl sweep and tripped out of the hole format 5142' to 3722' (shoe). Hole tight. Over pull of 20k. Maximum hoist weight 250k pumping out of the hole to the shoe. Maximum gas pumping out was 29 units. Service the draw works and Top Drive. Pump a dry job and trip out of the hole. Break the bit and grade. Lay down the BHA, smart tools and mud motor. Clean the rig floor and gather new BHA assembly and observe the well (static). January 12th 2013: Pick up rotary steerable power drive and make up the bit. Service the rig and wait on productions generator. Monitor the well = static. Hold a pre job safety meeting and cut 80' of new drilling line. Production generator is back on line. Trip in the hole and test the rotary steerable tool and finish picking up the MWD smart tools. Run in the hole to the first joint of the HWDP and test the MWD. Trip in the hole to the shoe (3722') and establish drilling parameters. Attempt to run in the hole without pumps and took weight at 3730' (8' below the shoe). Able to pump through the tight spots and work down to 3770' and pump through again. Pumped down to 3837' and tagged up. Made several attempts to get by tagged up zone but couldn't. Pull out of the hole into tight spots at 3773' and 3769'. Had to pump and back ream through tight spots to get into the shoe (3722'). Tripped out of the hole from 3722' to 910'. Stand back the drill collars and inspect the smart tools and stand back in the derrick. Clean the rig floor and pick up BHA Hole Opener bit sub. Trip into the hole to the shoe and establish drilling parameters. Wash and ream down from 3722' to 4550' at midnight. Samples caught from the shoe to 4550' displayed 70-100% coal. Samples under the shoe contained 10-15% cement which dissipated after 4100'. Trip Gas was 75 units. January 13th 2013: Wash and ream from 4616' to 5142' with the hole opener. Circulate bottom's up with 322 units of trip gas. Monitor the well = static. Pull out of the hole from 5142' and was able to pull to the shoe (3722') on elevators and verified twice that the window was accessible going in at 3837'. Monitor the well at the shoe = static. Trip out of the hole and lay down the hole opener assembly and pick up Schlumberger Rotary Steerable BHA and initialize the smart tools. Trip in the first stand of drill pipe and test the MWD. Trip in the hole to the shoe (3722'). Pumped the first stand down past the shoe. Tagged on the second stand at 3837'. Pick up and rotate slowly while pumping through the 3837' bridge. Was able to get by and continue in the hole on the elevators to 5069'. Circulate and condition the hole and set the smart tools. Wash and ream from 5069' to 5142'. Trip gas was 37 units. Drill formation to 5610' at midnight. January 14th 2013: Drill formation from 5610' to 5642'. Circulate bottoms up and monitor the well = static. Wiper trip to 5142'. Pulled easy going out of the hole. Trip back in to bottom was easy. Wiper Gas was 97 units. Drill formation from 5642' to 6202'. Circulate bottoms up and wiper trip from 6202' to 5630'. Wash down from 5630' to 6202'. Wiper gas was 66 units. Drill formation from 6202' to 6617' at midnight. January 15th 2013: Drill formation from 6617' to 6774' and circulation and condition the hole bottom's up. Monitor the well = static. Wiper trip from 6774' to 6202'. Pulled out of the hole easy. Trip back to bottom which went easy. Circulate the last stand down with wiper gas of 70 units. Drill formation from 6774' to 7340' and circulate and condition the hole one bottoms up. Wiper trip from 7340' to 6767'. Easy pulling out and tripping back in to bottom. Circulate the last stand down with wiper gas of 70 units. Drill formation to 7723' at midnight. Hilcorp Alaska, LLC M-31B 35 January 16th 2013: Drill from 7723' to 7811'. Circulate and condition the hole bottom's up and pumped a 40 bbl high viscosity sweep with a 300% return in cuttings. Monitor the well = static. Short trip on elevators from 7911' and pull up past 7148'. Encountered two tight spots: 7480' (pulled 30k over) and 7191' (pulled 40k over). Worked the drill pipe through and the tight spots cleaned up. Trip in the hole on elevators and rotated slowly the last stand down. Wiper gas was 64 units. Drill formation from 7911' to 8008'. Noticed a loss of 900 psi. Racked back one stand and tested the surface equipment to 2k. T he test was good. Pull out of the hole from 7913' and look for wash outs in the drill pipe. Found washed out joint (4187') and replaced the joint and continued to pull out of the hole to 3663'. Serviced the top drive, crown and main bearings. Circulate and conditioned the hole and test the MWD smart tools. Trip in the hole from 3663' to 5737' and filled the drill pipe. Run in the hole from 5737' to 6920'. The hole became tight (set down 25k). Washed down from 6920' to 6940' and continue to run in the hole to 7913' and wash down to 8008'. Wiper gas was 91 units. Drill to 8080'. January 17th 2013: Drill formation from 8080' to 8761'. Pumped a 30 bbl sweep at 8690' with a 100% increase in cuttings. Circulate and condition the hole bottom's up. Wiper trip from 8761' to 8000'. At 8761' broke over 355k pulling (coal). Trip back to bottom with wiper gas of 59 units. Drill formation from 8761' to 8849' (midnight). January 18th 2013: Drill formation from 8849' to 9031'. Service the rig and change out swab on mud pump #2 and circulate the hole. Drill formation to 9031' to 9177'. Circulate and condition the hole and change out swab on mud pump #1. Drill formation from 9177' to 9336' at midnight. January 19th 2013: Drill formation from 9336' to 9425'. Circulate and condition the hole bottom's up. Wiper trip from 9425' to 8700' and tripped in the hole back to bottom. Circulate and condition the hole and pump a high viscosity sweep. Wiper gas was 114 units. Trip out of the hole from 9425' to 901'. Hole was tight at 7136', 7060', 6995', 6617' and 6617'. Pulled 75K over. Lay down the BHA and Smart Tools. Prepare to test the BOPE. Commence testing the BOPE. January 20th 2013: Drill formation from 9336' to 9425'. Circulate and condition the hole bottom's up. Wiper trip from 9425' to 8700' and tripped in the hole back to bottom. Circulate and condition the hole and pump a high viscosity sweep. Wiper gas was 114 units. Trip out of the hole from 9425' to 901'. Hole was tight at 7136', 7060', 6995', 6617' and 6617'. Pulled 75K over. Lay down the BHA and Smart Tools. Prepare to test the BOPE. Commence testing the BOPE. January 21st 2013: Finish testing BOPE. Pick up third party logging assembly. Hold a pre job safety meeting and load the nuke source. Trip in the hole with the logging assembly to the shoe. Service the Top Drive and Draw Works. Trip in the hole from 3722' to 7250' installing non rotating protectors. Circulate and condition the hole and wash down from 9395' to 9425' (TD). Trip gas was 193 units. Pull out of the hole from 9425' with Mad Pass Assembly logging the hole at 350 ft/hr at 800 gpm and 2700 psi. Maximum gas pumping out of the hole was 308 units from coal at 8360'. January 22nd 2013: Open hole Mad Pass from 8323' to 4241' (midnight) at 350 ft/hr, 800 gpm, 100 rpm, 2200 psi. Maximum gas was 700 units while circulating and running the Mad Pass. Gas from the coal at 5000'. Abundant coal on the shakers. From ground up fragments to several inches wide. January 23rd 2013: Open hole Mad Pass from 4241' to 3722' (shoe). Circulate and condition the hole. Pump a high viscosity sweep and circulate the hole clean. Trip out of the hole from 3722' to 931'. Lay down on the BHA and hold a pre job safety meeting and remove the nuke source. Break out the drill bit and remove. Clean the rig floor and rig up to run 9 5/8" casing. Pick up CRT tools and begin to run the casing. January 24th 2013: Run 9 5/8" casing from 2424' to 3720' and circulate and condition the hole at the shoe. Run casing from 3720' to 5014' and wash and ream as the hole is tight (coal). Change out Power Tongs and circulate and reciprocate the hole. Run casing to 6687' and took 30k weight. Circulate and condition the hole. Run casing from 6687' to 6990'. Work through tight spot and ream through it. Run casing from 6990' to 7524'. Hole was tight at 7520' on joint #191. Run in the hole with joint #192 to 7595' with no troubles. Maximum gas running casing to 7595' was 96 units. Hilcorp Alaska, LLC M-31B 36 January 25th 2013: Run 9 5/8" casing from 7595' to 7834'. Circulate and condition the hole bottom's up at 50 spm. Run casing from 7834' to 9130'. Circulate and condition the hole and work the drill string. Rig down the CRT tool and clean the rig floor. Rig up the cement head and cement lines. Make up the cement line to the cement head. Circulate and condition and establish the pump rate and circulate the casing at 2 bbl/min and increase to 6 bbl/min. Pressure up cement lines from 1000 to 4500 psi for five minutes. Pump 73 bbls of mud push at 10.5 ppg and chase with 5 bbl/min 9.5 ppg. Drop bottom plug and pump cement (383 bbls of 12.0 ppg at 4 bbl/min) follow with 73 bbls of 15.8 ppg and chase with water (5 bbls). Displace with the rig pumps. At 2000 strokes lost returns. Slowed strokes down to 1.1 bbl/min to 2550 psi. Shlumberger finished displacement as the rig pump capacity was surpassed at 4900 psi. Lined up on the trip tank to monitor the well. Service the draw works, iron roughneck and clean the rig floor at midnight. January 26th 2013: Change out bladder on Koomey bottles. Check psi in Koomey bottles. Drain and blow down WTC. Set well on trip tank. No gas recorded while on trip tank. Clean all work areas on the rig. Remove extra 9 5/8" cement from RF. Grease choke manifold/HCR tools and equipment to the well head. Continue rig maintenance and housekeeping. Rig down the cement head and cross over to 9 5/8" casing. Hold a pre job safety meeting on laying down the CRT. Disconnect the CRT from the top drive and put down on the rig floor (to be cleaned). Pressure wash the CRT and lay down the manifold hoses and put them on the upper deck with the crane. Rig up the steam line and remove the ice plug from the top drive. Blow down the top drive and rig up CSG bales, clean the rig floor and rig up the 9 5/8" spider elevators. January 27th 2013: Clean and organize all work area's on the rig. Spot Pollard Wire Line unit. Fix rotary table locks. Mix mud and grease the crown and blocks. Rig up the E-line. Trip in the hole counting collars. Got on depth with wire line at 1487'. Turn the pipe and put the torque to it. Fired charge and torqued and back out. Rotated to the left and keep trying to back casing out at the broken casing. Pulled 175k trying to get the slips out and then slack back to 125k. Take spider elevators off of the stump and put on side door elevators. Pulled to 225k to get the slips out and brought weight down to 140k. Turned pipe 3/4 of a turn and lost weight. Picked up on the pipe and string weight was 130k. Pull out of the hole with first joint of casing at midnight. January 28th 2013: Pull 9 5/8" casing from 1478' to surface and lay down. A total of 36 joints. Rig down Weatherford casing tools and clean and clear the rig floor. Cut and slip new drill line. Inspect brakes and rollers. Blow down the top drive. Continue rig housekeeping. Continued monitoring of the well for losses at the trip tank. Service the top drive. January 29th 2013: Rig up side door elevator. Pick up a joint of 9 5/8" casing. Insulate around the sub structure. Fire alarm in camp, report to muster area. Pick up BHA and Baker screw in sub. Pick up two joints of 9 5/8" casing and hanger assembly. Blow down the top drive. Trip in the hole from 124' to 409'. Trip in hole with tie in packer. Circulate 2 bbl/min at 160 psi. Trip in the hole and saw bobble at 1432' and tagged and swallowed tool at 1435'. Pump 3.2 bbl/min at 230 psi. Rotate at 10 rpm at 2k torque and worked torque to 10k then ramped up psi to 2200 and held for 15 minutes. Worked pipe four times from 125k to 80k then put 3500 psi on the tool and pulled out of the hole to release. Break down top drive from 1428'. Lay down third party tools. Lay down running tools and rig up casing tools. January 30th 2013: Make up cement line to top of 9 5/8" casing. Circulate 1 bpm @ 100 psi and stab liner hanger and set down 30k. Pressure up to 500 psi with pumps off pick up 110k. Blow down the cement line and space out 21.8'. Lay down three joints of casing and pick up pups of 9 5/8" (14.56' and 7.60'). Make up hanger. Rig up line to top of 9 5/8" and break circulation at 3 bpm at 60 psi. Pump 120 barrels. Pressure test casing shoe to 1500 psi. The casing hydraulic out. Run casing and rig down. Blow down cement line and lay down landing joint. Wash the stack and blow down. Make up the pack-off to the running tool. Pressure test the casing to 1500 psi for 30 minutes. The test is good. Pick up the clean out BHA. Pick up HWDP and trip in the hole with drill pipe. Kelly up at 1500' and 2500'. Pump at 8 bpm at 523 psi to condition the down hole mud. Trip in the hole and wash down at 8 bpm at 554 psi. Wash from 2500' to 3696' and tag cement. Set drilling parameters and drill cement from 3696' to 4034'. Pumped bottoms up at 14 bpm at 149 psi. Pumped 320 barrels while moving the pipe slowly. Drill cement from 4034' to 4280' at midnight. Hilcorp Alaska, LLC M-31B 37 January 31st 2013: Drill cement from 4280' to 7786' February 1st 2013: Drill cement from 6700' to 7314'. Change out spring in #1 mud pump. Grease swivel and blocks. Drill cement from 7314' to 7550'. Lost 500 psi pump pressure. Trouble shoot pump pressure. Test surface equipment to 2000 psi. Test is good. Change out suction and displacement spring on #1 mud pump and circulate and condition the mud. Drill cement to 8875' at midnight. February 2nd 2013: Drill cement 7550' to 8970'. Circulate and condition the hole. Lost 500 psi and trouble shoot mud pump #1. Circulate hole with mud pump #2. Drill cement from 8970' to 9019' and tag float (9019'). Circulate the hole clean and test the casing to 1500 psi and hold for 30 minutes. Drill out float at 9019' and drill cement from 9019' to 9104'. Work through the shoe at 9104' and wash and ream to 9128' and pull back to the shoe and circulate. Monitor the well = static. Overboard old drilling mud in the pits and clean the pits for mud change out. Replace suction valve in mud pump #1. Change over the mud system to new 9.5 ppg mud at 9100'. Attain slow pump rates and clean around the shoe and take 5' steps into the open hole. Trip in the hole with out any WOB until 9339' and cleaned hole to 9431 in which fill was tagged (coal). Trip gas was 936 units and a large amount of cuttings. Tripped out of the hole from 9431' to 9100'. Circulated and pumped a bottoms up while working the pipe. Trip in the hole from 9100' not pumping and tagged in coal at 9339'. Kelly up and rotated and cleaned the hole until tagged at 9431'. Wiper gas was 214 units. No increase in cuttings at the shakers. Tripped out of the hole (not pumping) to the shoe. Pumped a bottoms up from 9100' while working the drill pipe 30' and pumped a 20 bbl dry job. Chased with a 10 bbl 9.5 ppg mud and blow down the top drive. Changed the elevators and trip out of the hole from 9070' to 4200' at midnight. February 3rd 2013: Trip out of the hole from 4200' and lay down the 8.5" bit and BHA. Monitor the well for 15 minutes = static. Test BOPE. Clean the rig floor and pick up drilling BHA. Load nukes and test MWD equipment. Trip in the hole with the BHA and drill pipe and fill the pipe every 15 stands. Muster for a fire alarm. Continue to trip in the hole at midnight. February 4th 2013: Trip in the hole from 7200' to the shoe (9107') and install NRP's tripping in. Filling the drill pipe every 5 stands. Trip in the hole from 9107' to 9431' and wash the last stand down. Trip gas was 582 units. Drill formation from 9431' to 9488'. Trouble shoot MWD tools and circulate. Drill from 9488' to 9564'. Trouble shoot MWD tools and circulate. Drill from 9564' to 10038'. Circulate bottoms up for a wiper trip. Pump a 20 bbl sweep and pull out of the hole to the shoe. Hole was tight at 9869', 9836', 9745' and 9661'. Had to pump through the tight spots. February 5th 2013: Trip out of the hole from 9100' to the shoe on elevators (wiper trip). Service the rig: top drive, crown, draw works and Baylor brake. Attempt to trip in the hole on elevators. Had to ream through tight spots at 9365', 9388', 9427', 9548'. 9683' and 9860'. Wiper gas was 200 units. Pump a 20 bbl sweep (with minimal increase in cuttings) and drill from 10040' to 10494'. Pump a 80 bbl sweep with a 100% increase in cuttings. Stop drilling and work the drill pipe. Lost 200 psi of pump pressure. Tested the surface equipment to 2000 psi and bled down 200 psi. Changed out the saver sub. Trip out of the hole to 9100' and pressure test both mud pumps to 2000 psi. Pressure tested the surface equipment. All tested good. Circulate and check pump pressure at 554 gallons. PSI was 1773. Blow down the top drive and trip out of the hole from 9100'. Found a hole in the drill pipe at 5079'. Picked up a new joint and pumped at 550 gallons with 1756 psi. Test was good. Prep to trip to bottom to drill. February 6th 2013: Service the top drive, crown and draw works. Trip in the hole from 5100' to the shoe (9107'). Fill the pipe every 15 stands. Wash and ream from 9107' to 10494'. The hole was tight at 9420', 9555', 9587', 9742', 9805', 9919', 10006', 10043' and 10230'. Wiper gas was 394 units. Drill formation from 10494' to 10793'. Wiper trip from 10793' to 10403'. Trip back to bottom (10793'). Wiper gas was 291 units. Drill formation from 10793' to 10990' (midnight). February 7th 2013: Drill formation from 10990' to 11173'. Wiper from 11173' to 10601'. Hole pulled tight from 11030' to 11017', 10800' and 10772'. Trip to bottom with wiper gas of 125 units. Drill formation from 11173' to 11260'. Notice abnormal pump pressure. Pull out of the hole. Hole was tight at 10160' and pumped through without rotating. Pull out on elevators to 7290'. Cut and slip new drill line. Hilcorp Alaska, LLC M-31B 38 February 8th 2013: Trip out of the hole from 7990' to 430'. Lay down the BHA and hold a pre job safety meeting. Remove the nuke sources and lay down the MWD smart tools and old bit. Service the top drive, crown, draw works and Baylor brake. Pick up new BHA and make up MWD smart tools and load nuke sources. Trip in the hole filling the drill pipe every 30 stands to 9100'. Kelly up and link with MWD tools. Trip in the hole not pumping or reaming to 10600'. Wash and ream from 10600' to 10798'. Pump a 20 bbl sweep. Wash and ream from 10798' to 10867' and trip in without pumps from 10867' to 11151' while logging at 900 ft/hr. Trip in the hole from 11151' to 11260' program the MWD tools at 180 ft/hr. Drill formation from 11260' to 11341' (midnight). February 9th 2013: Circulate and condition and finish bottom's up at the shoe (9107'). Drop rabbit on stand #92 and pull one stand. Circulate and condition the hole at 8900'. Blow down the top drive and monitor the well = static. Trip out of the hole from 8900' to 6500' and circulate. Monitor the well = static. Pump a 50 bbl sweep and pump a dry job. Trip out of the hole from 6500' to 348'. Lay down the BHA and hold a pre job safety meeting. Stand back the HWDP, jars and lay down the flex collar. Remove the nuke source and lay down the smart tools and drill bit. Remove MWD cross over's and subs from the drill floor. Rig up Weatherford casing tools and equipment for 7" casing. Monitor the losses the well is taking (.80 bbl/hr). Make up single shoe track, single joint, float collar and single. Verified shoe and float joints were clear of debris. Run casing check float = good. Continue to run in the hole with 7" casing. Pick up packer and make up liner running sleeve with plax mix. Rig down Weatherford casing tools and monitor the well = zero loses in 30 minutes. Run liner and circulate one casing volume. Make up cement head and lay out. Trip in the hole with 7" liner on drill pipe and fill every ten stands slowly to 4436' (midnight). February 10th 2013: Circulate and condition and finish bottom's up at the shoe (9107'). Drop rabbit on stand #92 and pull one stand. Circulate and condition the hole at 8900'. Blow down the top drive and monitor the well = static. Trip out of the hole from 8900' to 6500' and circulate. Monitor the well = static. Pump a 50 bbl sweep and pump a dry job. Trip out of the hole from 6500' to 348'. Lay down the BHA and hold a pre job safety meeting. Stand back the HWDP, jars and lay down the flex collar. Remove the nuke source and lay down the smart tools and drill bit. Remove MWD cross over's and subs from the drill floor. Rig up Weatherford casing tools and equipment for 7" casing. Monitor the losses the well is taking (.80 bbl/hr). Make up single shoe track, single joint, float collar and single. Verified shoe and float joints were clear of debris. Run casing check float = good. Continue to run in the hole with 7" casing. Pick up packer and make up liner running sleeve with plax mix. Rig down Weatherford casing tools and monitor the well = zero loses in 30 minutes. Run liner and circulate one casing volume. Make up cement head and lay out. Trip in the hole with 7" liner on drill pipe and fill every ten stands slowly to 4436' (midnight). February 11th 2013: Circulate and condition and rig down the cement line. Rotate and reciprocate through the drill pipe from 11548' to 11540' while Schlumberger troubleshoots their slurry pump. Pressure test the cement lines. Hook the cement lines back up. Hold a pre job safety meeting. SLB pumped 5 bbls of water and pressure test low to 1000 and high to 5000 psi. Circulate and cement displace pump with 50 bbls of mud push. Swap to SLB pump and pump 54 bbls of 15.6 ppg lead 4.2 bpm. SLB pumped 122 bbls of 15.6 ppg tail at 3.4 bpm. Drop the drill pipe dart and SLB pump 5 bbl FIW. Swap to rig pumps and displace while reciprocating. Circulate cement displacement. Pipe got sticky and parked it while displacing at 1200 strokes away at 6 bpm and 1500 psi. Bumped the dart at 1412 strokes and packed off at 1730 strokes 1.5 bpm to 3400 psi. Swap to SLB pumps and pump 7 more barrels. Pressure test the casing shoe to 5000 psi with SLB pumps. Set hanger 50k down and 20k up and release the hanger. Pressure test the back side to 1500 psi. At 800 psi the drill pipe and casing pressure equalized. Set down in Bakers tool 3' and pressured up again to 1120 psi and the pressure equalized. Circulate and condition and pressure up to 500 psi and release from the hanger. Circulate bottoms up (17 units of gas) and got back 40 bbls of mud push and a little cement. Trip out of the hole and rig down the cement head and blow down lines and monitor the well. Start to trip out of the hole from 8895' to 984' checking for cement rings on every connection. Pick up the rotating cement head and lay down. Continue to pull out of the hole from 984' to the Baker running tool and lay down. Prep to test the BOPE. Change out the lower rams to 4". Pick up test tools and begin to test the BOPE. February 12th 2013: Continue to test BOPE. Attempt to unscrew 5" test joint. Joint is torque’d up too much. Tried to pull the test plug and had problems pulling. Pulled over 20k over while working the string sideways and plug came free. Lay down the 5" joint and pulled up the test plug covered with sand. Make up 4" test joint and set plug. Continue to test the BOPE. Lay down the test tool and pull the test plug and pump out the stack. Set the wear ring and lay down the 4" test joint. Pick up the BHA, drill collar, stabilizer, bit sub with float and 6" bit. Mud pump problems. Troubleshoot the mud pumps due to pressure problem. Circulate and condition and fill pipe. Trip in the hole from 2769' to 9497' Hilcorp Alaska, LLC M-31B 39 February 13th 2013: Trip in the hole and tag cement at 9968'. circulate and drill cement from 9968' to 10054'. Trip gas is 7 units. Encountered hard spot and took weight and quit drilling. Received drill pipe wiper plug rubber back, Tried varied drilling parameters in attempt to drill. Couldn't make any hole. Trip out of the hole from 10054' to the surface and stand back 4" drill pipe, collars and lay down the drill bit. Bit looked clean. Service the draw works and crown. Trip in the hole with 5" HWDP and sharper bit, Clean the rig floor. Swap elevators and pick up BHA and trip in the hole and tag cement at 10050'. Trip gas was 3 units. Drill cement from 10050' to 10051' (midnight). February 14th 2013: Drill cement wiper plug from 10051' to 10053'. Drill cement from 10053' to 11412'. Drill landing collar to 11450'. Circulate and condition and pump a 30 bbl sweep bottom's up. Rig up to test casing. Begin to test casing at midnight. 4. 2 S U R V E Y D A T A Me a s u r e d De p t h I n c l i n a t i o n A z i m u t h T V D Ve r t i c a l Se c t i o n +NS - +E W - D L S ( f t ) ( d e g ) ( d e g ) ( f t ) ( f t ) ( f t ) ( f t ) ( d e g / 1 0 0 f t ) 37 0 0 . 0 0 3 1 . 5 8 2 1 . 3 2 3 5 0 4 . 7 7 - 6 4 8 . 3 6 7 9 2 . 8 4 2 7 9 . 8 9 0 . 8 8 37 9 9 . 4 6 2 7 . 0 5 3 1 . 1 3 3 5 9 1 . 5 2 - 6 8 2 . 0 9 8 3 6 . 5 0 3 0 1 . 0 8 6 . 6 3 38 6 4 . 7 2 2 8 . 8 3 3 7 . 7 2 3 6 4 9 . 1 8 - 6 9 9 . 7 7 8 6 1 . 6 6 3 1 8 . 3 8 5 . 4 6 39 5 9 . 5 3 3 1 . 1 8 4 7 . 5 0 3 7 3 1 . 3 3 - 7 2 1 . 3 1 8 9 6 . 3 5 3 5 0 . 4 8 5 . 7 2 40 5 9 . 9 1 3 1 . 0 8 4 3 . 4 0 3 8 1 7 . 2 7 - 7 4 2 . 7 7 9 3 2 . 7 3 3 8 7 . 4 5 2 . 1 1 41 3 8 . 9 8 3 0 . 6 3 4 1 . 8 2 3 8 9 3 . 7 3 - 7 6 3 . 7 1 9 6 6 . 3 5 4 1 8 . 3 8 1 . 0 4 42 4 2 . 9 3 3 0 . 1 6 4 1 . 7 1 3 9 7 4 . 7 7 - 7 8 6 . 1 3 1 0 0 1 . 8 0 4 5 0 . 0 4 0 . 5 0 43 3 8 . 4 6 2 8 . 8 4 4 6 . 4 1 4 0 5 7 . 9 2 - 8 0 6 . 6 5 1 0 3 5 . 6 1 4 8 2 . 7 0 2 . 7 9 44 3 3 . 1 4 2 7 . 6 9 5 1 . 8 3 4 1 4 1 . 3 3 - 8 2 2 . 5 8 1 0 6 4 . 9 6 5 1 6 . 5 4 2 . 9 7 45 2 7 . 9 8 2 7 . 6 2 5 4 . 1 2 4 2 2 5 . 3 3 - 8 3 5 . 3 9 1 0 9 1 . 4 6 5 5 1 . 6 8 1 . 1 2 46 2 2 . 7 7 2 8 . 6 9 5 8 . 3 8 4 3 0 8 . 9 1 - 8 4 5 . 9 1 1 1 1 6 . 2 7 5 8 8 . 8 6 2 . 4 0 47 1 7 . 4 5 2 9 . 2 5 6 1 . 4 4 4 3 9 1 . 7 5 - 8 5 3 . 8 6 1 1 3 9 . 2 4 6 2 8 . 5 3 1 . 6 7 48 1 2 . 0 4 2 8 . 5 6 6 5 . 6 7 4 4 7 4 . 5 7 - 8 5 8 . 9 2 1 1 5 9 . 6 1 6 6 9 . 4 4 2 . 2 8 49 0 6 . 8 0 2 8 . 3 8 6 9 . 3 7 4 5 5 7 . 8 7 - 8 6 0 . 8 0 1 1 7 6 . 8 8 7 1 1 . 1 6 1 . 8 7 50 0 1 . 4 5 2 7 . 8 6 7 3 . 4 8 4 6 4 1 . 3 6 - 8 5 9 . 6 3 1 1 9 1 . 0 9 7 5 3 . 4 2 2 . 1 2 50 6 8 . 6 1 2 7 . 1 8 7 6 . 9 2 4 7 0 0 . 9 2 - 8 5 6 . 7 8 1 1 9 9 . 0 3 7 8 3 . 4 0 2 . 5 7 50 9 6 . 6 1 2 6 . 7 5 7 8 . 4 8 4 7 2 5 . 8 8 - 8 5 5 . 0 5 1 2 0 1 . 7 3 7 9 5 . 8 1 2 . 9 5 51 9 1 . 6 7 2 7 . 4 9 8 5 . 6 5 4 8 1 0 . 5 1 - 8 4 5 . 9 1 1 2 0 7 . 6 7 8 3 8 . 6 6 3 . 5 2 52 8 6 . 4 4 2 6 . 2 4 9 5 . 1 9 4 8 9 5 . 0 9 - 8 3 1 . 0 2 1 2 0 7 . 4 4 8 8 1 . 3 5 4 . 7 3 53 8 1 . 2 9 2 4 . 3 1 1 0 2 . 9 0 4 9 8 0 . 8 8 - 8 1 1 . 4 2 1 2 0 1 . 1 9 9 2 1 . 2 8 4 . 0 2 54 7 5 . 8 4 2 2 . 3 3 1 0 9 . 3 0 5 0 6 7 . 7 2 - 7 8 9 . 4 2 1 1 9 0 . 9 0 9 5 7 . 2 1 3 . 4 0 55 7 0 . 2 3 2 0 . 2 6 1 1 3 . 8 5 5 1 5 5 . 6 7 - 7 6 6 . 6 9 1 1 7 8 . 3 7 9 8 9 . 0 8 2 . 8 0 56 6 5 . 5 1 1 8 . 2 8 1 1 4 . 4 7 5 2 4 5 . 6 0 - 7 4 4 . 7 5 1 1 6 5 . 5 0 1 0 1 7 . 7 7 2 . 0 9 57 6 0 . 5 8 1 6 . 4 5 1 1 6 . 1 7 5 3 3 6 . 3 4 - 7 2 4 . 5 6 1 1 5 3 . 3 9 1 0 4 3 . 4 3 2 . 0 0 58 5 5 . 3 5 1 6 . 1 9 1 2 2 . 2 3 5 4 2 7 . 3 0 - 7 0 4 . 4 0 1 1 4 0 . 4 2 1 0 6 6 . 6 4 1 . 8 1 59 5 0 . 0 8 1 6 . 4 6 1 3 1 . 2 7 5 5 1 8 . 2 2 - 6 8 2 . 1 7 1 1 2 4 . 5 3 1 0 8 7 . 9 0 2 . 7 0 60 4 4 . 8 8 1 6 . 5 3 1 4 1 . 9 8 5 6 0 9 . 1 4 - 6 5 7 . 5 4 1 1 0 5 . 0 4 1 1 0 6 . 3 1 3 . 2 0 61 3 9 . 3 7 1 6 . 9 3 1 5 1 . 4 4 5 6 9 9 . 6 5 - 6 3 1 . 1 4 1 0 8 2 . 3 6 1 1 2 1 . 1 7 2 . 9 1 62 2 9 . 9 8 1 6 . 8 0 1 6 1 . 8 1 5 7 8 6 . 3 8 - 6 0 4 . 9 9 1 0 5 8 . 3 2 1 1 3 1 . 5 7 3 . 3 2 Hi l c o r p A l a s k a , L L C M- 3 1 B 41 Me a s u r e d De p t h T V D A z i m u t h In c l i n a t i o n D L S Ve r t i c a l Se c t i o n +NS - +EW- ( f t ) ( f t ) ( d e g ) ( d e g ) ( d e g / 1 0 0 f t ) ( f t ) ( f t ) ( f t ) 63 2 9 . 6 0 1 6 . 8 5 1 7 0 . 5 9 5 8 8 1 . 7 5 - 5 7 6 . 4 1 1 0 3 0 . 4 0 1 1 3 8 . 4 2 2 . 5 5 64 2 4 . 4 1 1 6 . 9 1 1 7 7 1 . 8 5 5 9 7 2 . 4 8 - 5 4 9 . 4 2 1 0 0 3 . 2 0 1 1 4 2 . 6 2 0 . 3 9 65 1 9 . 1 3 1 7 . 7 7 1 7 3 . 5 5 6 0 6 2 . 8 9 - 5 2 1 . 8 9 9 7 5 . 1 9 1 1 4 6 . 2 0 1 . 0 6 66 1 3 . 9 8 1 9 . 4 3 1 7 7 . 8 1 6 1 5 2 . 7 9 - 4 9 2 . 8 1 9 4 5 . 0 4 1 1 4 8 . 4 3 2 . 2 6 67 0 8 . 8 2 1 9 . 9 8 1 8 2 . 3 9 6 2 4 2 . 0 8 - 4 6 2 . 8 3 9 1 3 . 0 8 1 1 4 8 . 3 5 1 . 7 3 68 0 3 . 6 7 1 9 . 9 2 1 8 6 . 7 7 6 3 3 1 . 2 4 - 4 3 3 . 4 4 8 8 0 . 8 4 1 1 4 5 . 7 7 1 . 5 8 68 9 8 . 5 2 1 9 . 8 7 1 8 6 . 1 5 6 4 2 0 . 4 3 - 4 0 4 . 5 7 8 4 8 . 7 7 1 1 4 2 . 1 3 0 . 2 3 69 9 3 . 2 4 1 9 . 8 9 1 8 4 . 6 7 6 5 0 9 . 5 0 - 3 7 5 . 5 0 8 1 6 . 7 0 1 1 3 9 . 0 9 0 . 5 3 70 8 7 . 9 9 1 9 . 9 3 1 8 4 . 6 8 6 5 9 8 . 5 9 - 3 4 6 . 2 1 7 8 4 . 5 5 1 1 3 6 . 4 6 0 . 0 4 71 8 2 . 8 9 1 9 . 8 8 1 8 3 . 1 8 6 6 8 7 . 8 2 - 3 1 6 . 7 0 7 5 2 . 3 1 1 1 3 4 . 2 5 0 . 5 4 72 7 7 . 7 3 1 9 . 9 7 1 8 1 . 4 6 6 7 7 6 . 9 8 - 2 8 6 . 8 2 7 2 0 . 0 2 1 1 3 2 . 9 4 0 . 6 2 73 7 1 . 8 6 2 0 . 0 6 1 7 9 . 7 1 6 8 6 5 . 4 3 - 2 5 6 . 6 8 6 8 7 . 8 0 1 1 3 2 . 6 1 0 . 6 5 74 6 6 . 6 2 2 0 . 3 2 1 7 7 . 1 7 6 9 5 4 . 3 7 - 2 2 5 . 6 7 6 5 5 . 1 1 1 1 3 3 . 5 1 0 . 9 6 75 6 0 . 9 5 2 0 . 4 7 1 7 6 . 9 9 7 0 4 2 . 7 8 - 1 9 4 . 2 6 6 2 2 . 2 8 1 1 3 5 . 1 8 0 . 1 8 76 5 5 . 6 8 2 0 . 4 2 1 7 7 . 4 7 7 1 3 1 . 5 4 - 1 6 2 . 6 7 5 8 9 . 2 3 1 1 3 6 . 7 8 0 . 1 9 77 5 0 . 5 4 2 0 . 4 0 1 7 6 . 6 5 7 2 2 0 . 4 5 - 1 3 1 . 0 7 5 5 6 . 2 0 1 1 3 8 . 4 8 0 . 3 0 78 4 5 . 3 1 2 0 . 6 8 1 7 6 . 0 1 7 3 0 9 . 2 0 - 9 9 . 1 8 5 2 3 . 0 2 1 1 4 0 . 6 1 0 . 3 8 79 4 0 . 1 2 2 0 . 8 9 1 7 4 . 5 5 7 3 9 7 . 8 4 - 6 6 . 7 4 4 8 9 . 4 9 1 1 4 3 . 3 8 0 . 5 9 80 3 4 . 9 0 2 0 . 9 5 1 7 3 . 3 1 7 4 8 6 . 3 7 - 3 3 . 9 1 4 5 5 . 8 3 1 1 4 6 . 9 6 0 . 4 7 81 2 9 . 7 1 2 0 . 9 1 1 7 4 . 0 4 7 5 7 4 . 9 2 - 1 . 0 1 4 2 2 . 1 7 1 1 5 0 . 6 9 0 . 2 8 82 2 4 . 5 7 2 0 . 8 5 1 7 5 . 1 3 7 6 6 3 . 5 5 3 1 . 7 0 3 8 8 . 5 1 1 1 5 3 . 8 8 0 . 4 1 83 1 9 . 2 8 2 0 . 8 2 1 7 6 . 5 2 7 7 5 2 . 0 7 6 4 . 0 9 3 5 4 . 9 1 1 1 5 6 . 3 3 0 . 5 2 84 1 3 . 8 8 2 0 . 8 8 1 7 7 . 5 1 7 8 4 0 . 4 8 9 6 . 2 7 3 2 1 . 2 9 1 1 5 8 . 0 9 0 . 3 8 85 0 8 . 6 2 2 0 . 8 2 1 7 7 . 3 4 7 9 2 9 . 0 1 1 2 8 . 4 3 2 8 7 . 6 0 1 1 5 9 . 6 0 0 . 0 9 86 0 3 . 3 8 2 0 . 9 1 1 7 7 . 7 2 8 0 1 7 . 5 5 1 6 0 . 5 9 2 5 3 . 8 8 1 1 6 1 . 0 6 0 . 1 7 86 9 8 . 2 2 2 0 . 9 6 1 7 7 . 5 8 8 1 0 6 . 1 3 1 9 2 . 8 6 2 2 0 . 0 2 1 1 6 2 . 4 5 0 . 0 7 87 9 2 . 9 0 2 0 . 9 6 1 7 7 . 4 6 8 1 9 4 . 5 5 2 2 5 . 1 4 1 8 6 . 1 9 1 1 6 3 . 9 1 0 . 0 4 88 8 7 . 5 3 2 0 . 9 8 1 7 6 . 5 6 8 2 8 2 . 9 1 2 5 7 . 5 1 1 5 2 . 3 7 1 1 6 5 . 6 8 0 . 3 4 Hi l c o r p A l a s k a , L L C M- 3 1 B 42 Me a s u r e d De p t h T V D A z i m u t h In c l i n a t i o n D L S Ve r t i c a l Se c t i o n +NS - +EW- ( f t ) ( f t ) ( d e g ) ( d e g ) ( d e g / 1 0 0 f t ) ( f t ) ( f t ) ( f t ) 89 8 2 . 2 5 2 1 . 0 0 1 7 5 . 2 6 8 3 7 1 . 3 5 2 9 0 . 1 2 1 1 8 . 5 3 1 1 6 8 . 0 9 0 . 4 9 90 7 7 . 1 8 2 0 . 9 9 1 7 5 . 3 6 8 4 5 9 . 9 8 3 2 2 . 9 0 8 4 . 6 3 1 1 7 0 . 8 7 0 . 0 4 91 7 2 . 1 6 2 1 . 0 9 1 7 4 . 3 5 8 5 4 8 . 6 2 3 5 5 . 8 5 5 0 . 6 7 1 1 7 3 . 9 3 0 . 4 0 92 6 6 . 9 6 2 1 . 2 6 1 7 3 . 5 4 8 6 3 7 . 0 2 3 8 9 . 0 7 1 6 . 6 2 1 1 7 7 . 5 5 0 . 3 6 93 6 1 . 8 2 2 1 . 1 7 1 7 3 . 5 8 8 7 2 5 . 4 5 4 2 2 . 4 3 - 1 7 . 5 0 1 1 8 1 . 4 0 0 . 1 0 94 0 8 . 1 4 2 1 . 4 7 1 7 2 . 8 7 8 7 6 8 . 6 0 4 3 8 . 8 2 - 3 4 . 2 2 1 1 8 3 . 3 9 0 . 8 4 95 0 2 . 9 1 2 4 . 5 5 1 8 0 . 9 2 8 8 5 5 . 8 5 4 7 4 . 1 1 - 7 1 . 1 3 1 1 8 5 . 2 2 4 . 6 4 95 9 7 . 7 2 2 9 . 5 8 1 8 5 . 2 2 8 9 4 0 . 2 5 5 1 3 . 6 8 - 1 1 4 . 1 6 1 1 8 2 . 7 8 5 . 6 9 96 9 2 . 5 0 3 3 . 9 5 1 8 2 . 9 7 9 0 2 0 . 8 2 5 5 9 . 2 0 - 1 6 3 . 9 1 1 1 7 9 . 2 8 4 . 7 8 97 8 7 . 3 1 3 8 . 8 5 1 8 0 . 7 1 9 0 9 7 . 1 1 6 1 1 . 3 9 - 2 2 0 . 1 3 1 1 7 7 . 5 3 5 . 3 5 98 8 2 . 1 7 4 3 . 8 2 1 8 0 . 4 1 9 1 6 8 . 3 1 6 7 0 . 0 0 - 2 8 2 . 7 6 1 1 7 6 . 9 3 5 . 2 4 99 7 6 . 8 8 4 8 . 4 6 1 8 1 . 4 4 9 2 3 3 . 9 2 7 3 3 . 7 2 - 3 5 1 . 0 2 1 1 7 5 . 8 0 4 . 9 6 10 0 7 1 . 4 8 5 2 . 9 1 1 7 8 . 8 3 9 2 9 3 . 8 5 8 0 2 . 3 8 - 4 2 4 . 1 8 1 1 7 5 . 6 8 5 . 1 7 10 1 6 6 . 2 2 5 6 . 5 4 1 7 4 . 6 0 9 3 4 8 . 5 7 8 7 6 . 3 9 - 5 0 1 . 3 5 1 1 8 0 . 1 7 5 . 2 9 10 2 6 0 . 9 8 6 0 . 4 6 1 7 4 . 1 5 9 3 9 8 . 0 7 9 5 4 . 6 1 - 5 8 1 . 7 4 1 1 8 8 . 0 9 4 . 1 5 10 3 5 5 . 8 2 6 2 . 6 8 1 7 5 . 3 5 9 4 4 3 . 2 2 1 0 3 5 . 2 1 - 6 6 4 . 7 9 1 1 9 5 . 7 1 2 . 6 0 10 4 5 0 . 5 0 6 5 . 5 3 1 7 6 . 9 0 9 4 8 4 . 5 7 1 1 1 6 . 9 8 - 7 4 9 . 7 5 1 2 0 1 . 4 5 3 . 3 4 10 5 4 5 . 1 3 6 8 . 2 0 1 7 9 . 2 2 9 5 2 1 . 7 5 1 1 9 9 . 6 4 - 8 3 6 . 7 1 1 2 0 4 . 3 8 3 . 6 2 10 6 3 9 . 8 5 7 0 . 6 7 1 7 9 . 6 4 9 5 5 5 . 0 2 1 2 8 3 . 2 1 - 9 2 5 . 3 8 1 2 0 5 . 2 5 2 . 6 4 10 7 3 4 . 7 8 7 1 . 0 6 1 8 0 . 1 8 9 5 8 6 . 1 4 13 6 7 . 4 9 - 1 0 1 5 . 0 6 1 2 0 5 . 4 0 0 . 6 7 10 8 2 5 . 6 0 7 1 . 5 5 1 7 9 . 9 9 9 6 1 5 . 2 5 14 4 8 . 2 4 - 1 1 0 1 . 0 9 1 2 0 5 . 2 7 0 . 5 8 10 9 2 4 . 5 6 7 1 . 5 7 1 7 9 . 6 6 9 6 4 6 . 5 5 15 3 6 . 4 9 - 1 1 9 4 . 9 7 1 2 0 5 . 5 5 0 . 3 1 11 0 1 5 . 0 9 7 1 . 5 2 1 7 9 . 3 5 9 6 7 5 . 2 1 16 1 7 . 3 9 - 1 2 8 0 . 8 4 1 2 0 6 . 2 9 0 . 3 4 11 1 1 4 . 3 1 7 1 . 6 7 1 7 8 . 9 0 9 7 0 6 . 5 3 17 0 6 . 2 8 - 1 3 7 4 . 9 7 1 2 0 7 . 7 3 0 . 4 5 11 1 9 8 . 3 8 7 1 . 6 9 1 7 7 . 4 8 9 7 3 2 . 9 6 17 8 2 . 0 6 - 1 4 5 4 . 7 4 1 2 1 0 . 2 6 1 . 6 0 11 2 9 7 . 0 4 7 0 . 6 4 1 7 8 . 0 8 9 7 6 4 . 8 1 18 7 0 . 9 2 - 1 5 4 8 . 0 4 1 2 1 3 . 8 8 1 . 2 1 11 3 9 1 . 7 7 6 9 . 6 1 1 7 8 . 0 5 9 7 9 7 . 0 1 19 5 5 . 5 7 - 1 6 3 7 . 0 8 1 2 1 6 . 8 9 1 . 0 9 11 4 8 5 . 9 3 6 8 . 7 6 1 7 9 . 1 4 9 8 3 0 . 4 7 20 3 8 . 9 4 - 1 7 2 5 . 0 7 1 2 1 9 . 0 5 1 . 4 2 Hi l c o r p A l a s k a , L L C M- 3 1 B 43 Me a s u r e d De p t h In c l i n a t i o n A z i m u t h T V D Ve r t i c a l Se c t i o n +N S - + E W - D L S ( f t ) ( d e g ) ( d e g ) ( f t ) ( f t ) ( f t ) ( f t ) ( d e g / 1 0 0 f t ) 11 5 1 1 . 4 8 6 8 . 3 0 1 7 8 . 3 6 9 8 3 9 . 8 2 20 6 1 . 4 5 - 1 7 4 8 . 8 4 1 2 1 9 . 5 7 3 . 3 7 11 5 5 0 . 0 0 6 8 . 3 0 1 7 8 . 3 6 9 8 5 4 . 0 7 20 9 5 . 3 9 - 1 7 8 4 . 6 2 1 2 2 0 . 5 9 0 . 0 1 Hi l c o r p A l a s k a , L L C M- 3 1 B 44 4. 3 M U D R E C O R D C o n t r a c t o r : B a r o i d M u d T y p e : 2 % C l a y s e a l G E M G P ( 3 7 2 2 ’ t o 1 1 5 5 0 ’ ) DA T E D E P T H M W V I S P V Y P G E L S FL FC S O L I D S O I L / W A T E R S A N D M B T p H C l C a 1- 9 - 1 3 3 9 2 0 9 . 5 4 4 1 1 2 2 9 / 1 1 / 1 3 4 . 5 1 / 0 5 . 6 0 . 5 / 9 3 . 0 0 . 2 5 0 . 5 1 0 . 9 1 0 0 0 0 5 6 0 1- 1 0 - 1 3 4 7 2 2 9 . 5 + 4 4 1 1 2 2 7 / 8 / 9 4 . 6 1 / 0 6 . 5 0 . 5 / 9 2 . 0 0 . 2 5 2 . 0 1 0 . 5 1 1 0 0 0 2 8 0 1- 1 1 - 1 3 5 1 4 2 9 . 5 + 4 6 1 3 1 7 5 / 6 / 7 3 . 6 1 / 0 7 . 6 0 . 5 / 9 1 . 0 0 . 2 5 2 . 0 9 . 9 1 0 0 0 0 1 6 0 1- 1 2 - 1 3 5 1 4 2 9 . 6 5 0 1 5 1 8 6 / 7 / 8 4 . 4 1 /0 7 . 6 0 . 5 / 9 1 . 0 0 . 2 5 4 . 5 1 0 . 5 1 0 0 0 0 2 0 0 1- 1 3 - 1 3 5 1 4 2 9 . 6 5 0 1 8 1 9 7 / 8 / 9 4 . 0 1 /0 8 . 1 0 . 0 / 9 1 . 0 0 . 2 5 5 . 0 1 0 . 0 1 0 0 0 0 1 6 0 1- 1 4 - 1 3 6 5 3 0 9 . 6 5 7 2 3 2 9 8 / 9 / 1 0 4 . 1 1 / 0 8 . 1 0 . 0 / 9 1 . 0 0 . 2 5 5 . 0 1 0 . 1 1 0 0 0 0 1 2 0 1- 1 5 - 1 3 7 5 3 1 9 . 6 5 7 2 4 3 0 9 / 1 0 / 1 1 4 . 0 1 / 0 8 . 1 0 . 0 / 9 1 . 0 0 . 2 5 8 . 5 1 0 . 0 1 0 0 0 0 1 6 0 1- 1 6 - 1 3 8 0 0 8 9 . 6 5 7 2 2 2 3 9 / 1 0 / 1 1 4 . 2 1 / 2 8 . 5 1 . 0 / 8 9 . 8 0 . 2 5 7 . 0 1 0 . 3 8 0 0 0 1 0 0 1- 1 7 - 1 3 8 7 6 3 9 . 6 5 7 2 1 2 3 1 2 / 1 3 / 1 4 4 . 8 2 /2 8 . 3 1 . 0 / 9 0 . 0 0 . 2 5 8 . 0 1 0 . 1 8 0 0 0 8 0 1- 1 8 - 1 3 9 1 9 7 9 . 5 + 5 7 1 8 2 6 1 0 / 1 3 / 1 5 4 . 5 2 / 4 7 . 7 1 . 0 / 9 0 . 5 0 . 2 5 6 . 5 1 0 . 0 9 0 0 0 1 0 0 1- 1 9 - 1 3 9 4 2 5 9 . 6 5 9 2 0 2 3 6 / 7 / 1 0 5 . 0 2 /4 8 . 3 1 . 0 / 9 0 . 0 0 . 5 0 6 . 5 1 0 . 0 8 0 0 0 8 0 1- 2 0 - 1 3 9 4 2 5 9 . 6 5 1 1 6 1 9 7 / 9 / 1 1 5 . 0 2 /4 8 . 2 1 . 0 / 9 0 . 0 0 . 5 0 6 . 5 1 0 . 0 9 0 0 0 8 0 1- 2 1 - 1 3 9 4 2 5 9 . 6 5 4 1 9 2 5 1 0 / 1 4 / 1 5 5 . 2 2 /4 8 . 0 0 . 8 / 9 0 . 5 0 . 5 0 6 . 5 1 0 . 1 9 0 0 0 8 0 1- 2 2 - 1 3 9 4 2 5 9 . 5 + 4 9 1 6 1 9 5 / 8 / 1 0 5 . 2 2 / 4 8 . 0 0 . 8 / 9 0 . 5 0 . 5 0 4 . 5 9 . 6 8 5 0 0 6 0 1- 2 3 - 1 3 9 4 2 5 9 . 5 + 4 9 1 6 1 9 5 / 8 / 1 0 5 . 2 2 / 4 8 . 0 0 . 8 / 9 0 . 5 0 . 5 0 5 . 0 9 . 8 8 0 0 0 1 2 0 1- 2 4 - 1 3 9 4 2 5 9 . 6 5 0 1 8 1 7 5 / 8 / 1 0 5 . 4 2 / 4 8 . 0 0 . 8 / 9 0 . 5 0 . 5 0 5 . 0 1 0 . 4 8 5 0 0 1 2 0 1- 2 5 - 1 3 9 4 2 5 9 . 6 5 2 1 8 1 9 7 / 1 1 / 1 3 5 . 5 2 / 4 8 . 0 0 . 8 / 9 0 . 5 0 . 5 0 4 . 5 9 . 6 8 5 0 0 2 4 0 1- 2 6 - 1 3 9 4 2 5 9 . 6 5 0 1 2 1 7 6 / 7 / 8 5 . 0 2/ 4 8 . 0 0 . 8 / 9 0 . 5 0 . 5 0 4 . 5 1 0 . 0 8 0 0 0 1 2 0 Hi l c o r p A l a s k a , L L C M- 3 1 B 45 DA T E D E P T H M W V I S P V Y P G E L S FL FC S O L I D S O I L / W A T E R S A N D M B T p H C l C a 1- 2 7 - 1 3 9 4 2 5 9 . 6 5 0 1 2 1 7 6 / 8 / 1 1 5 . 2 2 / 4 8 . 0 0 . 8 / 9 0 . 5 0 . 5 0 4 . 5 9 . 8 8 5 0 0 1 0 0 1- 2 8 - 1 3 9 4 2 5 9 . 6 6 1 1 7 1 8 5 / 6 / 7 5 . 0 2/ 4 8 . 3 0 . 5 / 9 0 . 5 0 . 5 0 5 . 0 1 0 . 0 8 0 0 0 8 0 1- 2 9 - 1 3 9 4 2 5 9 . 5 + 5 1 1 2 2 1 7 / 9 / 1 2 6 . 8 2 / 0 8 . 3 0 . 5 / 9 0 . 5 0 . 5 0 5 . 0 1 1 . 4 8 0 0 0 4 4 0 1- 3 0 - 1 3 9 4 2 5 9 . 5 + 5 6 1 4 3 3 1 6 / 1 7 / 1 8 1 5 . 8 2 / 0 8 . 3 0 . 3 / 9 1 . 0 0 . 5 0 4 . 0 1 1 . 2 4 5 0 0 8 0 0 1- 3 1 - 1 3 9 4 2 5 9 . 5 + 5 0 1 2 2 3 1 0 / 1 5 / 2 2 1 6 . 2 3 / 0 8 . 8 0 . 3 / 9 0 . 5 0 . 5 0 4 . 0 1 1 . 0 4 5 0 0 4 8 0 2- 1 - 1 3 9 4 3 4 9 . 5 + 4 9 1 3 1 8 4 / 5 / 7 5 . 0 1 / 0 7 . 7 0 . 5 / 9 1 . 0 0 . 5 0 5 . 0 1 0 . 0 9 0 0 0 1 6 0 2- 2 - 1 3 9 4 3 4 9 . 5 + 5 1 1 5 1 8 5 / 6 / 8 5 . 0 1 / 3 8 . 2 0 . 5 / 9 0 . 5 0 . 5 0 5 . 0 9 . 8 9 0 0 0 2 0 0 2- 3 - 1 3 1 0 0 3 8 9 . 6 5 2 1 9 2 8 8 / 9 / 1 0 4 . 6 1 / 3 8 . 4 0 . 5 / 9 0 . 2 0 . 5 0 3 . 0 9 . 8 1 1 0 0 0 8 0 2- 4 - 1 3 1 0 4 9 4 9 . 6 5 5 2 1 2 7 8 / 1 0 / 1 1 4 . 2 1 / 3 8 . 1 0 . 5 / 9 0 . 5 0 . 5 0 3 . 1 9 . 8 1 1 0 0 0 8 0 2- 5 - 1 3 1 0 4 9 4 9 . 6 5 5 1 9 2 0 4 / 6 / 8 4 . 4 1/ 3 8 . 1 0 . 5 / 9 0 . 5 0 . 5 0 2 . 5 9 . 6 1 1 0 0 0 8 0 2- 6 - 1 3 1 1 2 6 0 9 . 5 + 5 2 2 0 1 8 4 / 6 / 8 4 . 6 1/ 3 8 . 2 0 . 5 / 9 0 . 5 0 . 5 0 2 . 5 9 . 4 9 0 0 0 8 0 2- 7 - 1 3 1 1 2 8 2 9 . 6 5 3 1 7 2 1 5 / 6 / 7 4 . 8 1/ 2 8 . 2 0 . 5 / 9 0 . 5 0 . 5 0 2 . 5 9 . 8 9 0 0 0 1 2 0 2- 8 - 1 3 1 1 5 5 0 9 . 6 5 2 1 9 2 2 4 / 6 / 8 4 . 2 1/ 2 8 . 2 0 . 5 / 9 0 . 5 0 . 5 0 2 . 5 9 . 7 9 0 0 0 8 0 2- 9 - 1 3 1 1 5 5 0 9 . 6 5 5 1 9 2 1 4 / 6 / 8 4 . 8 1/ 2 8 . 2 0 . 5 / 9 0 . 5 0 . 5 0 2 . 5 9 . 8 9 0 0 0 8 0 2- 1 0 - 1 3 1 1 5 5 0 9 . 5 + 5 2 1 6 1 8 4 / 5 / 6 4 . 5 1/ 2 8 . 2 0 . 5 / 9 0 . 5 0 . 5 0 2 . 5 9 . 4 9 0 0 0 8 0 2- 1 1 - 1 3 1 1 5 5 0 9 . 6 + 5 5 1 7 1 9 4 / 5 / 6 4 . 8 1/ 2 8 . 2 0 . 5 / 9 0 . 5 0 . 5 0 2 . 5 9 . 4 9 0 0 0 8 0 2- 1 2 - 1 3 1 1 5 5 0 9 . 6 + 5 5 1 8 1 8 4 / 5 / 6 4 . 9 1/ 2 8 . 2 0 . 5 / 9 0 . 5 0 . 5 0 2 . 5 9 . 6 9 0 0 0 8 0 2- 1 3 - 1 3 1 1 5 5 0 9 . 6 5 1 1 5 1 8 4 / 5 / 6 6 . 8 1/ 2 8 . 8 0 . 5 / 9 0 . 0 0 . 5 0 3 . 0 9 . 5 8 0 0 0 2 4 0 2- 1 4 - 1 3 1 1 5 5 0 9 . 5 4 8 1 7 2 0 8 / 9 / 1 0 7 . 0 1 / 0 9 . 4 0 . 5 / 8 9 . 5 0 . 5 0 3 . 0 1 0 . 8 7 0 0 0 7 4 0 Hi l c o r p A l a s k a , L L C M- 3 1 B 46 4. 4 B I T R E C O R D BI T NO SI Z E MA K E TY P E S / N JE T S (T F A ) IN O U T F E E T H O U R S A VE RO P WO B C O N D I T I O N 1 1 2 . 2 5 ” S T C X R + C P X 6 9 0 3 3 X 1 8 , 1 X 1 5 3 7 2 2 5 1 42 1 4 2 0 4 8 : 5 0 6 3 2 2 1 - 4 - W T - H - E - I - C T - B H A 2 8 . 0 W T F D HO L E OP E N E R 24 4 7 6 3 - 5 1 4 2 5 1 4 2 0 0 - - - 3 1 2 . 2 5 ” S T C MD S i 7 1 6 LH E B P X JG 4 1 9 7 9 X 1 1 5 1 4 2 9 4 2 5 4 2 8 3 8 1 : 2 5 7 8 1 1 1 - 1 - C T - A - X - I - N O - T D RR 2 8. 0 W T F D HO L E OP E N E R 24 4 7 6 3 - 9 4 2 5 9 4 2 5 0 0 - - - 4 8. 5 ” S T C X R + P X 0 8 4 7 3 X 2 0 9 4 2 5 9 4 3 5 1 0 . 1 1 2 9 2 6 - 5 8 . 5 ” S T C MD S i 7 1 6 LW B P X JG 1 0 4 2 4X 1 1 , 1 X 1 3 , 2X 1 2 94 3 5 1 1 2 6 0 1 8 2 6 4 6 : 4 9 5 2 1 3 8 - 6 - R O - C - X - I - W T - P R 6 8 . 5 ” S T C MD S i 7 1 6 LW B P X JG 1 0 4 4 1 X 1 2 , 3 X 1 1 1 1 2 6 0 1 1 5 5 0 2 9 0 6: 2 4 5 4 1 4 1 - 1 - N O - A - X - I - N O - T D 7 6 . 0 ” H D B S ST X 52 1 4 6 7 6 52 1 4 6 7 6 3 X 1 8 1 1 5 5 0 1 1 5 5 0 0 0 - - C E M E N T C L E A N O U T 8 6 . 0 ” H D B S Q H I R 1 2 0 9 1 7 8 1 O P E N 1 1 5 5 0 1 1 5 5 0 0 0 - - C E M E N T C L E A N O U T Hilcorp Alaska, LLC M-31B 47 5 DAILY REPORTS HILCORP ALASKA LLC DAILY WELLSITE REPORT M-31B REPORT FOR BRUMLEY/ROGERS DATE Jan 10, 2013 DEPTH 3885.00000 PRESENT OPERATION DRILLING FORMATION TIME 24 HOURS YESTERDAY 3700.00000 24 HOUR FOOTAGE 185' CASING INFORMATION 13 3/8" @ 3722' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 3864.72 28.83 44.16 3649.18 3766.27 27.75 27.59 3562.35 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1 12.25" STC XR+C PX6903 3X18, 1X15 3722 10.05 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 126.7 @ 3796.00000 0.9 @ 3814.00000 35.2 40.40581 FT/HR SURFACE TORQUE 9814 @ 3873.00000 0 @ SLIDE 2786.1 SLIDE AMPS WEIGHT ON BIT 36 @ 3802.00000 3 @ 3737.00000 18.2 20.54832 KLBS ROTARY RPM 57 @ 3867.00000 0 @ SLIDE 14.7 SLIDE RPM PUMP PRESSURE 1854 @ 3852.00000 1632 @ 3741.00000 1746.3 1761.77356 PSI DRILLING MUD REPORT DEPTH 3920' MW 9.5 VIS 44 PV 11 YP 22 FL 4.5 Gels 9/11/13 CL- 10000 FC 1/0 SOL 5.6 SD .25 OIL 0.5/93.0 MBL 0.5 pH 10.9 Ca+ 560 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 23 @ 3792.00000 0 @ 3757.00000 5.9 TRIP GAS 0 @ 3722' CUTTING GAS @ @ WIPER GAS 0 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 4404 @ 3792.00000 11 @ 3757.00000 936.6 CONNECTION GAS HIGH 0 ETHANE (C-2) 0 @ 0 0 @ 0 0.0 AVG 0 PROPANE (C-3) 0 @ 0 0 @ 0 0.0 CURRENT 0 BUTANE (C-4) 0 @ 0 0 @ 0 0.0 CURRENT BACKGROUND/AVG 9 PENTANE (C-5) 0 @ 0 0 @ 0 0.0 HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY TUFFACEOUS SILTSTONE, TUFFACEOUS SANDSTONE, SAND, ASH, COAL, CONGLOMERATE SAND, CONGLOMERATE PRESENT LITHOLOGY 3899' = 30% TUFFACEOUS SILTSTONE, 30% TUFFACEOUS SANDSTONE, 10% ASH, 10% CONGLOMERATE SAND, 20% SAND DAILY ACTIVITY SUMMARY TRIP OUT OF THE HOLE FROM 1397' CHECKING EVERY CONNECTION FOR CEMENT, LAY DOWN BHA AND EMPTY JUNK BASKET OF 337 LBS OF METAL, CLEAN THE RIG FLOOR AND MAKE UP NEW BHA, HOLD A PRE JOB SAFETY MEETING AND SERVICE THE RIG, TRIP IN THE HOLE TO 3664', KELLY UP AND ESTABLISH DRILLING PARAMETERS AND TEST THE MWD, ABANDON PLATFORM DRILL, CLEAN OUT THE HOLE TO BOTTOM AT 3700', DRILL CEMENT TO 3727' AND SLIDE FROM 3727' TO 3773' SLOWLY WORKING AWAY FROM THE M31A BORE, SLIE TO 3844. ROTATE FROM 3844' TO 3885'. EPOCH PERSONNEL ON BOARD BROWNE, JOHNSON + 2 SC DAILY COST $3260 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/11/2013 file://C:\Documents and Settings\EpochAdmin\My Documents\My Wells\Hilcorp\M31B\ ... HILCORP ALASKA LLC DAILY WELLSITE REPORT M-31B REPORT FOR BRUMLEY/ROGERS DATE Jan 11, 2013 DEPTH 4800.00000 PRESENT OPERATION DRILLING FORMATION TIME 24 HOURS YESTERDAY 3885.00000 24 HOUR FOOTAGE 915' CASING INFORMATION 13 3/8" @ 3722' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 4812.04 28.56 65.58 4474.55 4717.45 29.25 61.37 4391.74 4622.77 28.69 58.32 4308.90 4527.98 27.63 54.07 4225.32 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1 12.25" STC XR+C PX6903 3X18, 1X15 3722' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 181.1 @ 4667.00000 1.5 @ 3887.00000 73.7 72.70325 FT/HR SURFACE TORQUE 12520 @ 4603.00000 0 @ SLIDE 6583.3 8090.84619 AMPS WEIGHT ON BIT 41 @ 4129.00000 1 @ 4222.00000 21.2 25.58513 KLBS ROTARY RPM 91 @ 4632.00000 0 @ SLIDE 55.4 83.02062 RPM PUMP PRESSURE 2539 @ 4596.00000 7 @ 4128.00000 2176.1 2401.38428 PSI DRILLING MUD REPORT DEPTH 4722' MW 9.5+ VIS 44 PV 11 YP 22 FL 4.6 Gels 7/8/9 CL- 11000 FC 1/0 SOL 6.5 SD 0.25 OIL 0.5/92.0 MBL 2.0 pH 10.5 Ca+ 280 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 190 @ 4483.00000 1 @ 4116.00000 38.1 TRIP GAS - CUTTING GAS 0 @ 0 0 @ 0 0 WIPER GAS - CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 34811 @ 4483.00000 190 @ 4262.00000 6565.8 CONNECTION GAS HIGH 0 ETHANE (C-2) 0 @ 0 0 @ 0 0.0 AVG 0 PROPANE (C-3) 0 @ 0 0 @ 0 0.0 CURRENT 0 BUTANE (C-4) 0 @ 0 0 @ 0 0.0 CURRENT BACKGROUND/AVG 90 (COAL) PENTANE (C-5) 0 @ 0 0 @ 0 0.0 HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY CONGLOMERATE SAND, SAND, TUFFACEOUS SAND, TUFFACEOUS SILT, COAL, CARBONACEOUS SHALE PRESENT LITHOLOGY 4800' = 100% COAL DAILY ACTIVITY SUMMARY SLIDE AND ROTATE THE FORMATION FROM 3885' TO 4800' MAKING ROUTINE SURVEY'S AND CONNECTIONS. EPOCH PERSONNEL ON BOARD BROWNE, JOHNSON + 2 SC DAILY COST $3260 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/11/2013 file://C:\Documents and Settings\EpochAdmin\My Documents\My Wells\Hilcorp\M31B\ ... HILCORP ALASKA LLC DAILY WELLSITE REPORT M-31B REPORT FOR ROGERS/MCINNIS DATE Jan 12, 2013 DEPTH 5142.00000 PRESENT OPERATION POOH FOR ROTARY STEERING ASSEMBLY TIME 24 HOURS YESTERDAY 4800.00000 24 HOUR FOOTAGE 342' CASING INFORMATION 13 3/8" @ 3722' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 5068.61 27.18 76.92 4700.92 5001.45 27.86 73.48 4641.35 4906.80 28.38 69.37 4557.87 4812.04 28.56 65.67 4474.57 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1 12.25" STC XR+C PX6903 3X18, 1X15 3722 5142 1420' 33:21 BHA DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 160.3 @ 4834.00000 1.0 @ 4906.00000 48.8 49.39703 FT/HR SURFACE TORQUE 9299 @ 5118.00000 0 @ 5092.00000 5479.0 8623.23835 AMPS WEIGHT ON BIT 40 @ 5097.00000 -999 @ 5084.00000 25.6 37.89741 KLBS ROTARY RPM 83 @ 4826.00000 0 @ 5108.00000 52.7 80.08743 RPM PUMP PRESSURE 2703 @ 5094.00000 -999 @ 5084.00000 2456.6 2649.16548 PSI DRILLING MUD REPORT DEPTH 5142' MW 9.5+ VIS 46 PV 13 YP 17 FL 3.6 Gels 5/6/7 CL- 10000 FC 1/0 SOL 7.6 SD 0.25 OIL 0.5/91.0 MBL 2.0 pH 9.9 Ca+ 160 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 298 @ 5019.00000 11 @ 5123.00000 60.8 TRIP GAS - CUTTING GAS @ @ WIPER GAS - CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 52851 @ 5019.00000 383 @ 4969.00000 10043.0 CONNECTION GAS HIGH 0 ETHANE (C-2) @ @ AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY TUFFACEOUS SILTSTONE, TUFFACEOUS SANDSTONE, SAND, COAL, CARBON SHALE PRESENT LITHOLOGY 5140' = TUFFACEOUS SILT 50%, TUFFACEOUS CLAYSTONE 20%, SAND 20%, CONGLOMERATE SAND 10% DAILY ACTIVITY SUMMARY Slide/rotate from 4800' to 4935'. Temporarly detained at 4935'. Had one full circulation and one jar kick at 280K and freed pipe. Rote/slide from 4935' to 5142'. Circulated and conditioned the hole. Pumped a 32 bbl sweep and tripped out of the hole from 5142' to 3722' (shoe). Hole tight. Overpull of 20k. Maximum hoist weight 250k pumping out of the hole to the shoe. Maximum gas pumping out was 29 units. Service the draw works and Top Drive. Pump a dry job and trip out of the hole. Break the bit and grade. Lay down the BHA, smart tools and mud motor. Clean the rig floor and gather new BHA assembly and observe the well (static). EPOCH PERSONNEL ON BOARD BROWNE, JOHNSON + 2 SC DAILY COST $3260 DML. $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/12/2013 file://C:\Documents and Settings\EpochAdmin\My Documents\My Wells\Hilcorp\M31B\2 ... HILCORP ALASKA LLC DAILY WELLSITE REPORT M-31B REPORT FOR ROGERS/MCINNIS DATE Jan 13, 2013 DEPTH 5142.00000 PRESENT OPERATION REAM w/ HOLE OPENER TIME 24 HOURS YESTERDAY 5142.00000 24 HOUR FOOTAGE 0' CASING INFORMATION 13 3/8" @ 3722' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 5068.61 27.18 76.92 4700.92 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1 12.25" STC XR+C PX6903 3X18, 1X15 3722 5142 1420' 48.50 1-4-WT-H-E-I-CT BHA 2 8.0 WTFD HOLE OPENER 244763 5142 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 5145' MW 9.6 VIS 50 PV 15 YP 18 FL 4.4 Gels 6/7/8 CL- 10000 FC 1/0 SOL 7.6 SD 0.25 OIL 0.5/91.0 MBL 4.5 pH 10.5 Ca+ 200 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 75 @ TG 1 @ TIH 19 TIH TRIP GAS 75 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 27 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY ABUNDANT COAL IN SAMPLES WHILE REAMING THE HOLE PRESENT LITHOLOGY 5140' = TUFFACEOUS SILT 50%, TUFFACEOUS CLAYSTONE 20%, SAND 20% CONGLOMERATE SAND 10% DAILY ACTIVITY SUMMARY Pick up rotary steerable power drive and make up the bit. Service the rig and wait on productions generator. Monitor the well = static. Hold a pre job safety meeting and cut 80' of new drilling line. Production generator is back on line. Trip in the hole and test the rotary steerable tool and finish picking up the MWD smart tools. Run in the hole to the first joint of the HWDP and test the MWD. Trip in the hole to the shoe (3722') and establish drilling parameters. Attempt to run in the hole without pumps and took weight at 3730' (8' below the shoe). Able to pump through the tight spots and work down to 3770' and pump through again. Pumped down to 3837' and tagged up. Made serveral attempts to get by tagged up zone but couldn't. Pull out of the hole into tight spots at 3773' and 3769'. Had to pump and back ream through tight spots to get into the shoe (3722'). Tripped out of the hole from 3722' to 910'. Stand back the drill collars and inspect the smart tools and stand back in the derrick. Clean the rig floor and pick up BHA Hole Opener bit sub. Trip into the hole to the shoe and establish drilling parameters. Wash and ream down from 3722' to 4550' at midnight. Samples caught from the shoe to 4550' displayed 70-100% coal. Samples under the shoe contained 10-15% cement which disapated after 4100'. Trip Gas was 75 units. EPOCH PERSONNEL ON BOARD BROWNE, JOHNSON + 2 SC DAILY COST $3260 DML, $1205 RW REPORT BY Lees F. Browne Jr. Page 1 of 1Daily Report 1/13/2013 file://C:\Documents and Settings\EpochAdmin\My Documents\My Wells\Hilcorp\M31B\2 ... HILCORP ALASKA LLC DAILY WELLSITE REPORT M-31B REPORT FOR ROGERS/MCINNIS DATE Jan 14, 2013 DEPTH 5610.00000 PRESENT OPERATION DRILLING FORMATION TIME 24 HOURS YESTERDAY 5142.00000 24 HOUR FOOTAGE 468' CASING INFORMATION 13 3/8" @ 3722' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 5570.23 20.26 113.85 5155.67 5475.84 22.33 109.30 5067.72 5381.29 24.31 102.90 4980.88 5286.44 26.24 95.19 4895.09 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 8.0" WTFD HOLE OPENER 244763 5142 5142 0 0 BHA 3 12.25" STC MDSi716LHEBPX JG4197 9X11 5142 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 187.7 @ 5607.00000 6.3 @ 5145.00000 76.4 168.13451 FT/HR SURFACE TORQUE 14541 @ 5478.00000 8623 @ 5142.00000 11798.9 12990.51855 AMPS WEIGHT ON BIT 37 @ 5142.00000 2 @ 5502.00000 11.2 7.34402 KLBS ROTARY RPM 123 @ 5578.00000 0 @ 5448.00000 114.8 114.39424 RPM PUMP PRESSURE 2649 @ 5142.00000 1505 @ 5354.00000 2176.3 2316.76245 PSI DRILLING MUD REPORT DEPTH 5142' MW 9.6 VIS 50 PV 18 YP 19 FL 4.0 Gels 7/8/9 CL- 10000 FC 4.0 SOL 8.1 SD 0.25 OIL 0/91.0 MBL 5.0 pH 10.0 Ca+ 160 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 259 @ 5381.00000 2 @ 5181.00000 36.4 TRIP GAS 322 W/ OP CUTTING GAS @ @ WIPER GAS - CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 49930 @ 5380.00000 424 @ 5181.00000 6394.7 CONNECTION GAS HIGH 0 ETHANE (C-2) 0 @ 0 @ 0.0 AVG 0 PROPANE (C-3) 0 @ 0 @ 0.0 CURRENT 0 BUTANE (C-4) 0 @ 0 @ 0.0 CURRENT BACKGROUND/AVG 35 PENTANE (C-5) 0 @ 0 @ 0.0 HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY TUFFACEOUS SILTSTONE, TUFFACEOUS CLAYSTONE, SAND, CONGLOMERATE SAND, COAL, CARBON SHALE PRESENT LITHOLOGY 5610' = 40% SAND, 40% CONGLOMERATE SAND, 10% TUFFACEOUS SANDSTONE, 10% TUFFACEOUS SILT DAILY ACTIVITY SUMMARY Wash and ream from 4616' to 5142' with the hole opener. Circulate bottom's up with 322 units of trip gas. Monitor the well = static. Pull out of the hole from 5142' and was able to pull to the shoe (3722') on elevators and verified twice that the window was accessible going in at 3837'. Monitor the well at the shoe = static. Trip out of the hole and lay down the hole opener assembly and pick up Schlumberger Rotary Steerable BHA and initialize the smart tools. Trip in the first stand of drill pipe and test the MWD. Trip in the hole to the shoe (3722'). Pumped the first stand down past the shoe. Tagged on the second stand at 3837'. Pick up and rotate slowly while pumping through the 3837' bridge. Was able to get by and continue in the hole on the elevators to 5069'. Circulate and condition the hole and set the smart tools. Wash and ream from 5069' to 5142'. Trip gas was 37 units. Drill formation to 5610' at midnight. EPOCH PERSONNEL ON BOARD BROWNE, JOHNSON + 2 SC DAILY COST $3260 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/14/2013 file://C:\Documents and Settings\EpochAdmin\My Documents\My Wells\Hilcorp\M31B\2 ... HILCORP DAILY WELLSITE REPORT M-31B REPORT FOR ROGERS/MCINNIS DATE Jan 14, 2013 DEPTH 6617.00000 PRESENT OPERATION DRILLING FORMATION TIME 24 HOURS YESTERDAY 5610.00000 24 HOUR FOOTAGE 1007' CASING INFORMATION 13 3/8" @ 3722' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 6613.98 19.43 177.81 6152.79 6519.13 17.77 173.55 6062.89 6424.41 16.91 171.85 5972.48 6329.60 16.85 170.59 5881.75 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3 12.25" STC MDSi716LHEBPX JG4197 9X11 5142 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 359.9 @ 6187.00000 0.7 @ 5948.00000 92.4 155.15425 FT/HR SURFACE TORQUE 17364 @ 6606.00000 11343 @ 5731.00000 14052.4 16274.99023 AMPS WEIGHT ON BIT 25 @ 6490.00000 0 @ 5916.00000 9.3 11.38623 KLBS ROTARY RPM 143 @ 6103.00000 0 @ 6206.00000 117.6 124.18592 RPM PUMP PRESSURE 2876 @ 6541.00000 1710 @ 5775.00000 2543.3 2753.44336 PSI DRILLING MUD REPORT DEPTH 6530' MW 9.6 VIS 57 PV 23 YP 29 FL 4.1 Gels 8/9/10 CL- 10000 FC 4.1 SOL 8.1 SD 0.25 OIL 0/91 MBL 5.0 pH 10.1 Ca+ 120 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 354 @ 6076.00000 6 @ 5920.00000 69.3 TRIP GAS - CUTTING GAS @ @ WIPER GAS 97 & 66 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 64812 @ 6076.00000 867 @ 6506.00000 11147.0 CONNECTION GAS HIGH 0 ETHANE (C-2) 177 @ 6076.00000 0 @ 6409.00000 4.3 AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 35 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY TUFFACEOUS SILTSTONE, TUFFACEOUS SANDSTONE, SAND, CONGLOMERATE SAND, CARBON SHALE, COAL, ASH PRESENT LITHOLOGY 6610' = SAND 80%, SANDSTONE 10%, CONGLOMERAYE SAND 10% DAILY ACTIVITY SUMMARY Drill formation from 5610' to 5642'. Circulate bottoms up and monitor the well = static. Wiper trip to 5142'. Pulled easy going out of the hole. Trip back in to bottom was easy. Wiper Gas was 97 units. Drill formation from 5642' to 6202'. Circulate bottoms up and wiper trip from 6202' to 5630'. Wash down from 5630' to 6202'. Wiper gas was 66 units. Drill formation from 6202' to 6617' at midnight. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS + 2 SC DAILY COST $3260 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/15/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR ROGERS/MCINNIS DATE Jan 16, 2013 DEPTH 7723.00000 PRESENT OPERATION DRILLING FORMATION TIME 24 HOURS YESTERDAY 6617.00000 24 HOUR FOOTAGE 1106' CASING INFORMATION 13 3/8" @ 3722' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 7750.54 20.40 AZI 176.65 7220.45 7655.68 20.42 177.47 7131.54 7560.95 20.47 176.99 7042.78 7466.62 20.32 177.17 6954.37 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3 12.25" STC MDSi716LHEBPX JG4197 9X11 5142 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 347.8 @ 7154.00000 3.1 @ 6944.00000 102.9 111.87400 FT/HR SURFACE TORQUE 26117 @ 7707.00000 8371 @ 7313.00000 18536.6 22564.72100 AMPS WEIGHT ON BIT 19 @ 6707.00000 0 @ 7237.00000 9.2 7.42200 KLBS ROTARY RPM 164 @ 7709.00000 83 @ 6780.00000 131.3 143.92700 RPM PUMP PRESSURE 3078 @ 7671.00000 2059 @ 7496.00000 2849.9 2998.55100 PSI DRILLING MUD REPORT DEPTH 7531' MW 9.6 VIS 57 PV 24 YP 30 FL 4.0 Gels 9/10/11 CL- 10000 FC 1/0 SOL 8.1 SD 0.25 OIL 0/91 MBL 8.5 pH 10.0 Ca+ 160 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 392 @ 6931.00000 2 @ 7678.00000 37.4 TRIP GAS - CUTTING GAS @ @ WIPER GAS 70 & 70 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 323091 @ 6633.00000 330 @ 7678.00000 7491.3 CONNECTION GAS HIGH 0 ETHANE (C-2) 124 @ 6998.00000 0 @ 7454.00000 14.1 AVG 0 PROPANE (C-3) 33 @ 6998.00000 0 @ 7269.00000 1.6 CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 20 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY TUFFACEOUS SILTSTONE, SAND, CONGLOMERATE SAND, TUFFACEOUS SANDSTONE, COAL, CARBON SHALE PRESENT LITHOLOGY 7720' = 40% SAND, 50% CONGLOMERATE SAND, 10% CONGLOMERATE DAILY ACTIVITY SUMMARY Drill formation from 6617' to 6774' and circulation and condition the hole bottom's up. Monitor the well = static. Wiper trip from 6774' to 6202'. Pulled out of the hole easy. Trip back to bottom which went easy. Circulate the last stand down with wiper gas of 70 units. Drill formation from 6774' to 7340' and circulate and condition the hole one bottoms up. Wiper trip from 7340' to 6767'. Easy pulling out and tripping back in to bottom. Circulate the last stand down with wiper gas of 70 units. Drill formation to 7723' at midnight. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS + 2 SC DAILY COST $3260 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/16/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR ROGERS/MCINNES DATE Jan 17, 2013 DEPTH 8080.00000 PRESENT OPERATION DRILLING FORMATION TIME 24 HOURS YESTERDAY 7723.00000 24 HOUR FOOTAGE 357' CASING INFORMATION 13 3/8" @ 3722' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 8034.90 20.95 173.31 7486.37 7940.12 20.89 174.55 7397.84 7845.31 20.68 176.01 7309.20 7750.54 20.40 176.65 7220.45 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3 12.25" STC MDSi716LHEBPX JG4197 9X11 5142 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 227.7 @ 7736.00000 2.0 @ 8050.00000 74.3 88.90320 FT/HR SURFACE TORQUE 26661 @ 7812.00000 16253 @ 7839.00000 21355.1 22427.89648 AMPS WEIGHT ON BIT 23 @ 8056.00000 1 @ 7792.00000 10.5 4.69924 KLBS ROTARY RPM 179 @ 7777.00000 75 @ 8055.00000 130.2 129.03143 RPM PUMP PRESSURE 3135 @ 8042.00000 2513 @ 7925.00000 2981.2 3050.68066 PSI DRILLING MUD REPORT DEPTH 8008' MW 9.6 VIS 57 PV 22 YP 23 FL 4.2 Gels 9/10/11 CL- 8000 FC 1/2 SOL 8.5 SD 0.25 OIL 1/89.8 MBL 7.0 pH 10.3 Ca+ 100 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 141 @ 8056.00000 4 @ 8078.00000 24.4 TRIP GAS - CUTTING GAS @ @ WIPER GAS 64 & 91 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 26648 @ 8056.00000 530 @ 8078.00000 4148.7 CONNECTION GAS HIGH 0 ETHANE (C-2) 121 @ 8056.00000 0 @ 7749.00000 16.5 AVG 0 PROPANE (C-3) 32 @ 8056.00000 0 @ 7751.00000 2.9 CURRENT 0 BUTANE (C-4) 16 @ 7945.00000 0 @ 8065.00000 0.7 CURRENT BACKGROUND/AVG 15 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY CONGLOMERATE SAND, SAND, TUFFACEOUS SILTSTONE, COAL, CARBON SHALE PRESENT LITHOLOGY 8080' = CONGLOMERATE SAND 30%, CONGLOMERATE 20%, SAND 10%, TUFFACEOUS SILTSTONE 30%, SANDSTONE 10% DAILY ACTIVITY SUMMARY Drill from 7723' to 7811'. Circulate and condition the hole bottom's up and pumped a 40 bble high viscosity sweep with a 300% return in cuttings. Montitor the well = static. Short trip on elevators from 7911' and pull up past 7148'. Encountered two tight spots: 7480' (pulled 30k over) and 7191' (pulled 40k over). Worked the drill pipe through and the tight spots cleaned up. Trip in the hole on elevators and rotated slowly the last stand down. Wiper gas was 64 units. Drill formation from 7911' to 8008'. Noticed a loss of 900 psi. Racked back one stand and tested the surface equipment to 2k. T he test was good. Pull out of the hole from 7913' and look for wash outs in the drill pipe. Found washed out joint (4187') and replaced the joint and continued to pull out of the hole to 3663'. Serviced the top drive, crown and main bearings. Circulate and conditioned the hole and test the MWD smart tools. Trip in the hole from 3663' to 5737' and filled the drill pipe. R un in the hole from 5737' to 6920'. The hole became tight (set down 25k). Washed down from 6920' to 6940' and continue to run in the hole to 7913' and wash down to 8008'. Wiper gas was 91 units. Drill to 8080'. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS + 2 SC DAILY COST $3260 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/17/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR ROGERS/MCINNES DATE Jan 17, 2013 DEPTH 8849.00000 PRESENT OPERATION DRILLING FORMATION TIME 24 HOURS YESTERDAY 8080.00000 24 HOUR FOOTAGE 769' CASING INFORMATION 13 3/8" @ 3722' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 8792.90 20.96 177.46 8194.55 8698.22 20.96 177.58 8106.13 8603.38 20.91 177.72 8017.55 8508.62 20.82 177.34 7929.01 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3 12.25" STC MDSi716LHEBPX JG4197 9X11 5142 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 168.5 @ 8125.00000 0.4 @ 8167.00000 51.0 44.83013 FT/HR SURFACE TORQUE 28053 @ 8125.00000 17182 @ 8212.00000 23201.8 22847.59180 AMPS WEIGHT ON BIT 18 @ 8676.00000 0 @ 8647.00000 11.0 7.35760 KLBS ROTARY RPM 168 @ 8843.00000 0 @ 8772.00000 123.6 149.37685 RPM PUMP PRESSURE 3081 @ 8608.00000 2190 @ 8108.00000 2980.9 2849.96631 PSI DRILLING MUD REPORT DEPTH 8763' MW 9.6 VIS 57 PV 21 YP 23 FL 4.8 Gels 12/13/14 CL- 8000 FC 4.8 SOL 8.3 SD 0.25 OIL 1.0/90.0 MBL 8.0 pH 10.1 Ca+ 80 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 307 @ 8364.00000 6 @ 8459.00000 36.2 TRIP GAS - CUTTING GAS 0 @ 8849.00000 0 @ 8849.00000 0.0 WIPER GAS 59 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 60788 @ 8364.00000 605 @ 8086.00000 6185.6 CONNECTION GAS HIGH 0 ETHANE (C-2) 279 @ 8365.00000 0 @ 8141.00000 35.1 AVG 0 PROPANE (C-3) 81 @ 8365.00000 0 @ 8708.00000 5.7 CURRENT 0 BUTANE (C-4) 26 @ 8381.00000 0 @ 8330.00000 0.6 CURRENT BACKGROUND/AVG 15 PENTANE (C-5) 0 @ 8849.00000 0 @ 8849.00000 0.0 HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY TUFFACEOUS SILTSTONE, CONGLOMERATE SAND, SAND, TUFFACEOUS SAND, COAL, CARBON SHALE PRESENT LITHOLOGY 8830' = 40% SAND, 10% CONGLOMERATE SAND, 50% TUFFACEOUS SILTSTONE DAILY ACTIVITY SUMMARY Drill formation from 8080' to 8761'. Pumped a 30 bbl sweep at 8690' with a 100% increase in cuttings. Circulate and condition the hole bottom's up. Wiper trip from 8761' to 8000'. At 8761' broke over 355k pulling (coal). Trip back to bottom with wiper gas of 59 units. Drill formation from 8761' to 8849' (midnight). EPOCH PERSONNEL ON BOARD BROWNE, BLEYS + 2 SC DAILY COST $3260 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/18/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR ROGERS/MCINNES DATE Jan 19, 2013 DEPTH 9336.00000 PRESENT OPERATION DRILLING FORMATION TIME 24 HOURS YESTERDAY 8080.00000 24 HOUR FOOTAGE 1256' CASING INFORMATION 13 3/8" @ 3722' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9361.82 21.17 173.58 8725.45 9266.96 21.26 173.54 8637.02 9172.16 21.09 174.35 8548.62 9077.18 20.99 175.36 8459.98 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3 12.25" MDSi716LHEBPX JG4197 9X11 5142 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 229.7 @ 9298.00000 0.4 @ 8167.00000 45.6 50.70199 FT/HR SURFACE TORQUE 28053 @ 8125.00000 17182 @ 8212.00000 23612.9 17905.02344 AMPS WEIGHT ON BIT 32 @ 9220.00000 0 @ 8647.00000 11.8 14.73272 KLBS ROTARY RPM 203 @ 9334.00000 71 @ 9192.00000 125.3 202.76378 RPM PUMP PRESSURE 3092 @ 8925.00000 2190 @ 8108.00000 2995.2 3002.93286 PSI DRILLING MUD REPORT DEPTH 9197' MW 9.5+ VIS 57 PV 18 YP 26 FL 4.5 Gels 10/13/15 CL- 9000 FC 2/4 SOL 7.7 SD OIL MBL pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 307 @ 8364.00000 3 @ 9018.00000 39.3 TRIP GAS - CUTTING GAS @ @ WIPER GAS - CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 60788 @ 8364.00000 605 @ 8086.00000 6559.3 CONNECTION GAS HIGH 0 ETHANE (C-2) 279 @ 8365.00000 0 @ 9018.00000 35.3 AVG 0 PROPANE (C-3) 81 @ 8365.00000 0 @ 8708.00000 7.0 CURRENT 0 BUTANE (C-4) 26 @ 8381.00000 0 @ 9018.00000 1.6 CURRENT BACKGROUND/AVG 45 PENTANE (C-5) 9 @ 9276.00000 0 @ 9297.00000 0.1 HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY SAND, CONGLOMERATE SAND, TUFFACEOUS SAND, SANDSTONE, TUFFACEOUS CLAY, CARBON SHALE, COAL PRESENT LITHOLOGY 9310' = SAND 60%, CONGLOMERATE SAND 20%, TUFFACEOUS SILTSTONE 20% DAILY ACTIVITY SUMMARY Drill formation from 8849' to 9031'. Service the rig and change out swab on mud pump #2 and circulate the hole. Drill formation to 9031' to 9177'. Circulate and condition the hole and change out swab on mud pump #1. Drill formation from 9177' to 9336' at midnight. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS + 2 SC DAILY COST $3260 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/19/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR ROGERS/MCINNES DATE Jan 20, 2013 DEPTH 9425.00000 PRESENT OPERATION TESTING BOPE TIME 24 HOURS YESTERDAY 9336.00000 24 HOUR FOOTAGE 89' CASING INFORMATION 13 3/8" @ 3722' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9361.82 21.17 173.58 8725.45 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3 12.25" MDSi716LHEBPX JG4197 9X11 5142 9425 4283 81:25 1-1-CT-A-X-I-NO TD DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 255.1 @ 9349.00000 6.6 @ 9400.00000 78.2 80.00000 FT/HR SURFACE TORQUE 27642 @ 9378.00000 17905 @ 9336.00000 24974.9 27127.56445 AMPS WEIGHT ON BIT 33 @ 9410.00000 3 @ 9371.00000 18.8 24.42114 KLBS ROTARY RPM 202 @ 9336.00000 120 @ 9417.00000 179.2 176.60950 RPM PUMP PRESSURE 3085 @ 9415.00000 2916 @ 9399.00000 3061.5 3006.28101 PSI DRILLING MUD REPORT DEPTH 9425' MW 9.6 VIS 59 PV 20 YP 23 FL 5.0 Gels 6/7/10 CL- 8000 FC 2/4 SOL 8.3 SD 0.50 OIL 1.0/90.0 MBL 6.5 pH 10.0 Ca+ 80 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 272 @ 9354.00000 38 @ 9336.00000 115.6 TRIP GAS - CUTTING GAS @ @ WIPER GAS 114 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 46821 @ 9354.00000 6286 @ 9401.00000 17152.2 CONNECTION GAS HIGH 0 ETHANE (C-2) 909 @ 9425.00000 63 @ 9336.00000 340.3 AVG 0 PROPANE (C-3) 929 @ 9425.00000 13 @ 9338.00000 287.5 CURRENT 0 BUTANE (C-4) 600 @ 9425.00000 6 @ 9340.00000 206.5 CURRENT BACKGROUND/AVG 0 PENTANE (C-5) 203 @ 9425.00000 13 @ 9362.00000 80.1 HYDROCARBON SHOWS OIL SHOW INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION 9366' - 9382' Sand-vltgy-ltgy, med upr-fine lwr, mod-well sort,uncons, grain sup, good por + perm. Before 55 Max 109 After 54 C1-C5 n odr, n stn, n flor, slo-mod strm cut, slo develp to hzy blu-wht cut, mod dull yel resid UV stain. Poor overall. LITHOLOGY SAND, COAL, CARBON SHALE, TUFFACEOUS SILT AND CLAY PRESENT LITHOLOGY 9425' = 90% SAND, 10% TUFFACEOUS SILT DAILY ACTIVITY SUMMARY Drill formation from 9336' to 9425'. Circulate and condition the hole bottom's up. Wiper trip from 9425' to 8700' and tripped in the hole back to bottom. Circulate and condition the hole and pump a high viscosity sweep. Wiper gas was 114 units. Trip out of the hole from 9425' to 901'. Hole was tight at 7136', 7060', 6995', 6617' and 6617'. Pulled 75K over. Lay down the BHA and Smart Tools. Prepare to test the BOPE. Commence testing the BOPE. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS + 2 SC DAILY COST $3260 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/20/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR ROGERS/MCINNES DATE Jan 21, 2013 DEPTH 9425.00000 PRESENT OPERATION MAD PASS LOGGING HOLE TIME 24 HOURS YESTERDAY 9425.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 13 3/8" @ 3722' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9361.82 21.17 173.58 8725.45 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED RR2 8.0" WTFD HOLE OPENER 244763 9425 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 9425' MW 9.6 VIS 51 PV 16 YP 19 FL 5.0 Gels 7/9/11 CL- 9000 FC 2/4 SOL 8.2 SD 0.50 OIL 1.0/90.0 MBL 6.5 pH 10.0 Ca+ 80 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 308 @ CIRC 1 @ CIRC 35 TRIP GAS 193 CUTTING GAS @ @ WIPER GAS - CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) @ @ CONNECTION GAS HIGH 0 ETHANE (C-2) @ @ AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 40 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 9425' = 90% SAND, 10% TUFFACEOUS SILTSTONE DAILY ACTIVITY SUMMARY Finish testing BOPE. Pick up third party logging assembly. Hold a pre job safety meeting and load the nuke source. Trip in the hole with the logging assembly to the shoe. Service the Top Drive and Draw Works. Trip in the hole from 3722' to 7250' installing non rotating protectors. Circulate and condition the hole and wash down from 9395' to 9425' (TD). Trip gas was 193 units. Pull out of the hole from 9425' with Mad Pass Assembly logging the hole at 350 ft/hr at 800 gpm and 2700 psi. Maximum gas pumping out of the hole was 308 units from coal at 8360' EPOCH PERSONNEL ON BOARD BROWNE, BLEYS + 2 SC DAILY COST $3260 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/21/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR ROGERS/MCINNES DATE Jan 22, 2013 DEPTH 9425.00000 PRESENT OPERATION MAD PASS LOGGING TIME 24 HOURS YESTERDAY 9425.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 9361.82 21.17 173.58 SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9361.82 21.17 173.58 8725.45 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED RR2 8.0" WTFD HOLE OPENER 244763 9425 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 9425' MW 9.6 VIS 51 PV 16 YP 19 FL 5.0 Gels 7/9/11 CL- 9000 FC 2/4 SOL 8.2 SD 0.50 OIL 1.0/90.0 MBL 6.5 pH 10.0 Ca+ 80 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 700 @ 5000' 0 @ CIRC 56 TRIP GAS - CUTTING GAS @ @ WIPER GAS - CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 102807 @ 5000' @ CONNECTION GAS HIGH 0 ETHANE (C-2) 219 @ @ AVG 0 PROPANE (C-3) 17 @ @ CURRENT 0 BUTANE (C-4) 6 @ @ CURRENT BACKGROUND/AVG 33 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 9425' = 90% SAND, 10% TUFFACEOUS SILTSTONE DAILY ACTIVITY SUMMARY Open hole Mad Pass from 8323' to 4241' (midnight) at 350 ft/hr, 800 gpm, 100 rpm, 2200 psi. Maximum gas was 700 units while ciculating and running the Mad Pass. Gas from the coal at 5000'. Abundant coal on the shakers. From ground up fragments to several inches wide. EPOCH PERSONNEL ON BOARD BROWNR, BLEYS DAILY COST $3060 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/22/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR ROGERS/MCINNES DATE Jan 23, 2013 DEPTH 9425.00000 PRESENT OPERATION RUN 9 5/8" CSG TIME 24 HOURS YESTERDAY 9425.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 13 3/8" @ 3722' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9361.82 21.17 173.58 8725.45 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 9425' MW 9.5+ VIS 49 PV 16 YP 19 FL 5.2 Gels 5/8/10 CL- 8500 FC 2/4 SOL 8.0 SD 0.50 OIL 0.8/90.5 MBL 4.5 pH 9.6 Ca+ 60 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 77 (CIRC) @ 4080' 0 @ 5 (CIRC) 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 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 9425' = 90% SAND, 10% TUFFACEOUS SILTSTONE DAILY ACTIVITY SUMMARY Open hole Mad Pass from 4241' to 3722' (shoe). Circulate and condition the hole. Pump a high viscisity sweep and circulate the hole clean. Trip out of the hole from 3722' to 931'. Lay down the BHA and hold a pre job safety meeting and remove the nuke source. Break out the drill bit and remove. Clean the rig floor and rig up to run 9 5/8" casing. Pick up CRT tools and begin to run the casing. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS DAILY COST $3060 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/23/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR ROGERS/MCINNES DATE Jan 24, 2013 DEPTH 9425.00000 PRESENT OPERATION RUN 9 5/8" CSG TIME 24 HOURS YESTERDAY 9425.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 13 3/8" @ 3722' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9361.82 21.17 173.58 8725.45 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 9425' MW 9.5+ VIS 59 PV 17 YP 20 FL 5.4 Gels 6/9/12 CL- 8000 FC 2/4 SOL 8.0 SD 0.50 OIL 0.8/90.5 MBL 5.0 pH 9.8 Ca+ 120 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 96 (CIRC) @ TIH 0 @ TIH 20 TRIP GAS - CUTTING GAS @ @ WIPER GAS - CHROMATOGRAPHY (ppm) SURVEY - METHANE (C-1) @ @ CONNECTION GAS HIGH 0 ETHANE (C-2) @ @ AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 10 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 9425' = 90% SAND, 10% TUFFACEOUS SILTSTONE DAILY ACTIVITY SUMMARY Run 9 5/8" casing from 2424' to 3720' and circulate and condition the hole at the shoe. Run casing from 3720' to 5014' and wash and ream as the hole is tight (coal). Change out Power Tongs and circulate and reciprocate the hole. Run casing to 6687' and took 30k weight. Circulate and condition the hole. Run casing from 6687' to 6990'. Work through tight spot and ream through it. Run casing from 6990' to 7524'. Hole was tight at 7520' on joint #191. Run in the hole with joint #192 to 7595' with no troubles. Maximum gas running casing to 7595' was 96 units. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS DAILY COST $3060 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/24/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR HAUCK/MCINNES DATE Jan 25, 2013 DEPTH 9425.00000 PRESENT OPERATION WAITING ON CEMENT TIME 24 HOURS YESTERDAY 9425.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 9123' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9361.82 21.17 173.58 8725.45 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 9425' MW 9.5+ VIS 59 PV 17 YP 20 FL 5.4 Gels 6/9/12 CL- 8000 FC 2/4 SOL 8.0 SD 0.50 OIL 0.8/90.5 MBL 5.0 pH 9.8 Ca+ 120 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 79 (CIRC) @ TIH 0 @ TIH 12 (CIRC) TRIP GAS 79 CUTTING GAS @ @ WIPER GAS - CHROMATOGRAPHY (ppm) SURVEY - METHANE (C-1) @ @ CONNECTION GAS HIGH 0 ETHANE (C-2) @ @ AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 9425' = 90% SAND, 10% TUFFACEOUS SILTSTONE DAILY ACTIVITY SUMMARY Run 9 5/8" casing from 7595' to 7834'. Circulate and condition the hole bottom's up at 50 spm. Run casing from 7834' to 9130'. Circulate and condition the hole and work the drill string. Rig down the CRT tool and clean the rig floor. Rig up the cement head and cement lines. Make up the cement line to the cement head. Circulate and condition and establish the pump rate and circulate the casing at 2 bbl/min and increase to 6 bbl/min. Pressure up cement lines from 1000 to 4500 psi for five minutes. Pump 73 bbls of mud push at 10.5 ppg and chase with 5 bbl/min 9.5 ppg. Drop bottom plug and pump cement (383 bbls of 12.0 ppg at 4 bbl/min) follow with 73 bbls of 15.8 ppg and chase with water (5 bbls). Displace with the rig pumps. At 2000 strokes lost returns. Slowed strokes down to 1.1 bbl/min to 2550 psi. Shlumberger finished displacement as the rig pump capacity was surpassed at 4900 psi. Lined up on the trip tank to monitor the well. Service the draw works. iron roughneck and clean the rig floor at midnight. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS DAILY COST $3060 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/25/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR HAUCK/BRUMLEY DATE Jan 26, 2013 DEPTH 9425.00000 PRESENT OPERATION RIG MAINENACE/SERVICE TIME 24 HOURS YESTERDAY 9425.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 9104' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9361.82' 21.17 173.58 8725.45 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 9425' MW 9.6 VIS 50 PV 18 YP 17 FL 5.4 Gels 5/8/10 CL- 8500 FC 2/4 SOL 8.0 SD 0.50 OIL 0.8/90.5 MBL 5.0 pH 10.4 Ca+ 120 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 0 @ CIRC 0 @ CIRC 0 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 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 9425' = 90% SAND, 10% TUFFACEOUS SILTSTONE DAILY ACTIVITY SUMMARY Change out bladder on Koomey bottles. Check psi in Koomey bottles. Drain and blow down WTC. Set well on trip tank. No gas recorded while on trip tank. Clean all work areas on the rig. Remove extra 9 5/8" cement from RF. Grease choke manifold/HCR tools and equipment to the well head. Copntinue rig maintenance and housekeeping. Rig down the cement head and cross over to 9 5/8" casing. Hold a pre job safety meeting on laying down the CRT. Disconnect the CRT from the top drive and put down on the rig floor (to be cleaned). Pressure wash the CRT and lay down the manifold hoses and put them on the upper deck with the crane. Rig up the steam line and remove the ice plug from the top drive. Blow down the top drive and rig up CSG bales, clean the rig floor and rig up the 9 5/8" spider elevators. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS DAILY COST $3060 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/26/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR HAUCK/BRUMLEY DATE Jan 27, 2013 DEPTH 9425.00000 PRESENT OPERATION BACKING OFF 9 5/8" CASING & L/D TIME 24 HOURS YESTERDAY 9425.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 9123' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9361.82 21.17 173.58 8725.45 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 9425' MW 9.6 VIS 50 PV 13 YP 18 FL 5.4 Gels 6/8/11 CL- 8500 FC 2/4 SOL 8.0 SD 0.50 OIL 0.8/90.5 MBL 4.5 pH 10.5 Ca+ 160 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 0 @ 0 0 @ 0 0 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 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 9425' = 90% SAND, 10% TUFFACEOUS SILTSTONE DAILY ACTIVITY SUMMARY Clean and organize all work area's on the rig. Spot Pollard Wire Line unit. Fix rotary table locks. Mix mud and grease the crown and blocks. Rig up the E-line. Trip in the hole counting collars. Got on depth with wire line at 1487'. Turn the pipe and put the torque to it. Fired charge and torqued and back out. Rotated to the left and keep trying to back casing out at the broken casing. Pulled 175k trying to get the slips out and then slack back to 125k. Take spider elevators off of the stump and put on side door elevators. Pulled to 225k to get the slips out and brought weight down to 140k. Turned pipe 3/4 of a turn and lost weight. Picked up on the pipe and string weight was 130k. Pull out of the hole with first joint of casing at midnight. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS DAILY COST $3060 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/27/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR HAUCK/BRUMLEY DATE Jan 28, 2013 DEPTH 9425.00000 PRESENT OPERATION RIG SERVICE TIME 24 HOURS YESTERDAY 9425.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 9123 SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9361.82 21.17 173.58 8725.45 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 9425' MW 9.6 VIS 50 PV 12 YP 17 FL 5.2 Gels 6/8/11 CL- 8500 FC 2/4 SOL 8.0 SD 0.50 OIL 0.8/90.5 MBL 4.5 pH 9.8 Ca+ 100 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 0 @ 0 0 @ 0 0 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 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 9425' = 90% SAND, 10% TUFFACEOUS SILTSTONE DAILY ACTIVITY SUMMARY Pull 9 5/8" casing from 1478' to surface and lay down. A total of 36 joints. Rig down Weatherford casing tools and clean and clear the rig floor. Cut and slip new drill line. Inspect brakes and rollers. Blow down the top drive. Continue rig housekeepingContinued monitoring of the well for losses at the trip tank. Service the top drive.. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS DAILY COST $3160 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/28/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR HAUCK/BRUMLEY DATE Jan 29, 2013 DEPTH 9425.00000 PRESENT OPERATION SPACE OUT SEAL ASSEMBLY TIME 24 HOURS YESTERDAY 9425.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 9123' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9361.82 21.17 173.58 8725.45 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 9425' MW 9.6 VIS 50 PV 12 YP 17 FL 5.2 Gels 6/8/11 CL- 8500 FC 2/4 SOL 8.0 SD 0.50 OIL 0.8/90.5 MBL 4.5 pH 9.8 Ca+ 100 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 0 @ 0 0 @ 0 0 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 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 9425' = 90% SAND, 10% TUFFACEOUS SILT DAILY ACTIVITY SUMMARY Rig up side door elevator. Pick up a joint of 9 5/8" casing. Insulate around the sub structure. Fire alarm in camp, report to muster area. Pick up BHA and Baker screw in sub. Pick up two joints of 9 5/8" casing and hanger assembly. Blow down the top drive. Trip in the hole from 124' to 409'. Trip in hole with tie in packer. Circulate 2 bbl/min at 160 psi. Trip in the hole and saw bobble at 1432' and tagged and swallowed tool at 1435'. Pump 3.2 bbl/min at 230 psi. Rotate at 10 rpm at 2k torque and worked torque to 10k then ramped up psi to 2200 and held for 15 minutes. Worked pipe four times from 125k to 80k then put 3500 psi on the tool and pulled out of the hole to release. Break down top drive from 1428'. Lay down third party tools. Lay down running tools and rig up casing tools. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS DAILY COST $3160 DML, $1205 RW REPORT BY LEES F BROWNE JR. Page 1 of 1Daily Report 1/29/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR HAUCK/BROMLEY DATE Jan 30, 2013 DEPTH 9425.00000 PRESENT OPERATION DRILLING CEMENT TIME 24 HOURS YESTERDAY 9425.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 9123' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9361.82' 21.17 173.58 8725.45 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 4 8.5" STC XR+ PX0847 3X20 3696 CEMENT DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 4000' drlg cement MW 9.5+ VIS 51 PV 12 YP 21 FL 6.8 Gels 7/9/12 CL- 8000 FC 2/0 SOL 8.3 SD 0.50 OIL 0.5/90.5 MBL 5.0 pH 11.4 Ca+ 440 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 7 @ TIH 0 @ TIH 0-1 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 0-1 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DRILLING CEMENT DAILY ACTIVITY SUMMARY Make up cement line to top of 9 5/8" casing. Circulate 1 bpm @ 100 psi and stab liner hanger and set down 30k. Pressure up to 500 psi with pumps off pick up 110k. Blow down the cement line and space out 21.8'. Lay down three joints of casing and pick up pups of 9 5/8" (14.56' and 7.60'). Make up hanger. Rig up line to top of 9 5/8" and break circulation at 3 bpm at 60 psi. Pump 120 barrels. Pressure test casing shoe to 1500 psi. The casing hydraulicing out. Run casing and rig down. Blow down cement line and lay down landing joint. Wash the stack and blow down. Make up the pack-off to the running tool. Pressure test the casing to 1500 psi for 30 minutes. The test is good. Pick up the clean out BHA. Pick up HWDP and trip in the hole with drill pipe. Kelly up at 1500' and 2500'. Pump at 8 bpm at 523 psi to condition the down hole mud. Trip in the hole and wash down at 8 bpm at 554 psi. Wash from 2500' to 3696' and tag cement. Set drilling parameters and drill cement from 3696' to 4034'. Pumped bottoms up at 14 bpm at 149 psi. Pumped 320 barrels while moving the pipe slowly. Drill cement from 4034' to 4280' at midnight. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS DAILY COST $3160 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/30/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR HAUCK/BRUMLEY DATE Jan 31, 2013 DEPTH 9425.00000 PRESENT OPERATION DRILLING CEMENT TIME 24 HOURS YESTERDAY 9425.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 9123' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9361.82' 21.17 173.58 8725.45 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 4 8.5" STC XR+ PX0847 3X20 3696 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 4000' MW 9.5+ VIS 51 PV 12 YP 21 FL 6.8 Gels 7/9/12 CL- 8000 FC 2/0 SOL 8.3 SD 0.50 OIL 0.5/90.5 MBL 5.0 pH 11.4 Ca+ 440 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 1 @ DRLG CEMENT 0 @ DRLG CEMENT 0 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 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY CEMENT DAILY ACTIVITY SUMMARY Drill cement from 4280' to 6700' EPOCH PERSONNEL ON BOARD BROWNE, BLEYS DAILY COST $3160 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 1/31/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR HAUCK/BRUMLEY DATE Feb 01, 2013 DEPTH 9425.00000 PRESENT OPERATION DRILLING CEMENT TIME 24 HOURS YESTERDAY 9425.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 9123' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9361.82 21.17 173.58 8725.45 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 4 8.5" STC XR+ PX0847 3X20 3896 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 6380' MW 9.5+ VIS 56 PV 14 YP 33 FL 15.8 Gels 16/17/18 CL- 4500 FC 2/0 SOL 8.3 SD 0.50 OIL 0.3/91.0 MBL 4.0 pH 11.2 Ca+ 800 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 1 @ (DRLG CMT) 0 @ (DRLG CMT) 0-1 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 0-1 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 100% CEMENT DAILY ACTIVITY SUMMARY Drill cement from 6700' to 7314'. Change out spring in #1 mud pump. Grease swivel and blocks. Drill cement from 7314' to 7550'. Lost 500 psi pump pressure. Trouble shoot pump pressure. Test surface equipment to 2000 psi. Test is good. Change out suction and displacement spring on #1 mud pump and circulate and condition the mud. Drill cement to 8875' at midnight. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS DAILY COST $3160 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 2/1/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WEL ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR HAUCK/BRUMLEY DATE Feb 02, 2013 DEPTH 9434.00000 PRESENT OPERATION TRIP OUT TO TEST BOPE TIME 24 HOURS YESTERDAY 9424.00000 24 HOUR FOOTAGE 10' CASING INFORMATION 9 5/8" @ 9107' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9361.82 21.17 173.58 8725.45 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 4 8.5" STC XR+ PX0847 3X20 3896 (9424) 9434 10 .1 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 450.8 @ 9434.00000 77.6 @ 9424.00000 303.1 450.80072 FT/HR SURFACE TORQUE 27127 @ 9425.00000 21 @ 9433.00000 18587.1 24.14625 AMPS WEIGHT ON BIT 42 @ 9434.00000 0 @ 9429.00000 13.8 42.81858 KLBS ROTARY RPM 176 @ 9425.00000 0 @ 9434.00000 111.0 0.28741 RPM PUMP PRESSURE 3013 @ 9424.00000 2113 @ 9433.00000 2515.5 2124.63232 PSI DRILLING MUD REPORT DEPTH 9434' MW 9.5+ VIS 49 PV 13 YP 18 FL 5.0 Gels 4/5/7 CL- 9000 FC 1/0 SOL 7.7 SD 0.50 OIL 0.5/91.0 MBL 5.0 pH 10.0 Ca+ 160 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 171 @ 9424.00000 15 @ 9434.00000 85.4 TRIP GAS 936 CUTTING GAS @ @ WIPER GAS 214 CHROMATOGRAPHY (ppm) SURVEY - METHANE (C-1) 21448 @ 9425.00000 20990 @ 9424.00000 4243.8 CONNECTION GAS HIGH - ETHANE (C-2) 909 @ 9425.00000 843 @ 9424.00000 175.3 AVG - PROPANE (C-3) 929 @ 9425.00000 868 @ 9424.00000 179.7 CURRENT - BUTANE (C-4) 600 @ 9425.00000 558 @ 9424.00000 115.9 CURRENT BACKGROUND/AVG 0 PENTANE (C-5) 203 @ 9425.00000 186 @ 9424.00000 38.9 HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY COAL, TUFFACEOUS SILTSTONE PRESENT LITHOLOGY 9434' = 80% COAL, 20% TUFFACEOUS SILTSTONE (VERY POOR SAMPLE = TRIP TRASH) DAILY ACTIVITY SUMMARY Drill cement 7550' to 8970'. Circulate and condition the hole. Lost 500 psi and trouble shoot mud pump #1. Circulate hole with mud pump #2. Drill cement from 8970' to 9019' and tag float (9019'). Circulate the hole clean and test the casing to 1500 psi and hold for 30 minutes. Drill out float at 9019' and drill cement from 9019' to 9104'. Work through the shoe at 9104' and wash and ream to 9128' and pull back to the shoe and circulate. Monitor the well = static. Overboard old drilling mud in the pits and clean the pits for mud change out. Replace suction vlave in mud pump #1. Change over the mud system to new 9.5 ppg mud at 9100'. Attain slow pump rates and clean around the shoe and take 5' steps into the open hole. Trip in the hole with out any WOB until 9339' and cleaned hole to 9431 in which fill was tagged (coal). Trip gas was 936 units and a large amount of cuttings. Tripped out of the hole from 9431' to 9100'. Circulated and pumped a bottoms up while working the pipe. Trip in the hole from 9100' not pumping and tagged in coal at 9339'. Kelly up and rotated and cleaned the hole until tagged at 9431'. Wiper gas was 214 units. No increase in cuttings at the shakers. Tripped out of the hole (not pumping) to the shoe. Pumped a bottoms up from 9100' while working the drill pipe 30' and pumped a 20 bbl dry job. Chased with a 10 bbl 9.5 ppg mud and blow down the top drive. Changed the elevators and trip out of the hole from 9070' to 4200' at midnight. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS DAILY COST $3160 DML, $1205 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 2/2/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WEL ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR HAUCK/BRUMLEY DATE Feb 03, 2013 DEPTH 9434.00000 PRESENT OPERATION TRIP IN THE HOLE TO DRILL TIME 24 HOURS YESTERDAY 9434.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 9107' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9361.82 21.17 173.58 8725.45 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5 8.5" STC MDSi716LWBPX JG1042 4X11, 2X12, 1X13 9434 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 9434' MW 9.5+ VIS 51 PV 15 YP 18 FL 5.0 Gels 5/6/8 CL- 9000 FC 1/3 SOL 8.2 SD 0.50 OIL 0.5/90.5 MBL 5.0 pH 9.8 Ca+ 200 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 4 @ TIH 0 @ TIH 0-1 (TIH) 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 1 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY COAL, TUFFACEOUS SILTSTONE PRESENT LITHOLOGY 9434' = 80% COAL, 20% TUFFACEOUS SILTSTONE (POOR SAMPLE QUALITY) DAILY ACTIVITY SUMMARY Trip out of the hole from 4200' and lay down the 8.5" bit and BHA. Monitor the well for 15 minutes = static. Test BOPE. Clean the rig floor and pick up drilling BHA. Load nukes and test MWD equipment. Trip in the hole with the BHA and drill pipe and fill the pipe every 15 stands. Muster for a fire alarm. Continue to trip in the hole at midnight. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS + 2 SC DAILY COST $3460 DML, $1445 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 2/3/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WEL ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR HAUCK/BRUMLEY DATE Feb 04, 2013 DEPTH 10038.00000 PRESENT OPERATION WIPER TRIP TO SHOE TIME 24 HOURS YESTERDAY 9434.00000 24 HOUR FOOTAGE 604' CASING INFORMATION 9 5/8" @ 9107' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9976.88 48.46 181.44 9233.92 9882.17 43.82 180.41 9168.31 9787.31 38.85 180.71 9097.11 9692.50 33.95 182.97 9020.82 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5 8.5" STC MDSi716LWBPX JG1042 4X11, 2X12, 1X13 9434 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 584.4 @ 9755.00000 1.3 @ 9583.00000 62.4 29.59051 FT/HR SURFACE TORQUE 26715 @ 9972.00000 18830 @ 9434.00000 23550.3 21090.40430 AMPS WEIGHT ON BIT 24 @ 9434.00000 2 @ 9734.00000 11.4 12.70352 KLBS ROTARY RPM 158 @ 9906.00000 81 @ 9714.00000 132.2 155.61707 RPM PUMP PRESSURE 2136 @ 9759.00000 1622 @ 9868.00000 1954.7 2035.48657 PSI DRILLING MUD REPORT DEPTH 10038' MW 9.6 VIS 52 PV 19 YP 28 FL 4.6 Gels 8/9/10 CL- 11000 FC 1/3 SOL 8.4 SD 0.50 OIL 0.5/90.2 MBL 3.0 pH 9.8 Ca+ 80 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 184 @ 10031.00000 8 @ 9449.00000 50.4 TRIP GAS 582 CUTTING GAS @ @ WIPER GAS - CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 26838 @ 9632.00000 764 @ 9439.00000 6152.9 CONNECTION GAS HIGH 0 ETHANE (C-2) 2888 @ 9955.00000 17 @ 9439.00000 404.2 AVG 0 PROPANE (C-3) 2407 @ 10032.00000 1 @ 9473.00000 377.3 CURRENT 0 BUTANE (C-4) 1421 @ 10032.00000 1 @ 9473.00000 224.5 CURRENT BACKGROUND/AVG 3 PENTANE (C-5) 330 @ 10032.00000 0 @ 9439.00000 48.5 HYDROCARBON SHOWS OIL SHOW #2 INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION 9951'- 9990' CONGLOMERATE SAND AND SAND UNCONSOLIDATED BEFORE 27 MAX 147 AFTER 43 NO ODOR, NO OIL STAIN, NO OIL IN MUD, 70% MODERATE YELLOW EVEN SAMPLE FLOR, SLOW STREAMING OIL CUT TRANSPARENT INCR TO TRANSL POOR-FAIR CUT LITHOLOGY CONGLOMERATE SAND, SAND, SANDSTONE, TUFFACEOUS SILTSTONE, COAL, CARBONACEOUS SHALE, ASH PRESENT LITHOLOGY 10038' = 100% COAL DAILY ACTIVITY SUMMARY Trip in the hole from 7200' to the shoe (9107') and install NRP's tripping in. Filling the drill pipe every 5 stands. Trip in the hole from 9107' to 9431' and wash the last stand down. Trip gas was 582 units. Drill formation from 9431' to 9488'. Trouble shoot MWD tools and circulate. Drill from 9488' to 9564'. Trouble shoot MWD tools and circulate. Drill from 9564' to 10038'. Circulate bottoms up for a wiper trip. Pump a 20 bbl sweep and pull out of the hole to the shoe. Hole was tight at 9869', 9836', 9745' and 9661'. Had to pump through the tight spots. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS + 2 SC DAILY COST $3460 DML, $1445 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 2/4/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WEL ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR HAUCK/BRUMLEY DATE Feb 05, 2013 DEPTH 10480.00000 PRESENT OPERATION TRIP IN HOLE TO DRILL TIME 24 HOURS YESTERDAY 10038.00000 24 HOUR FOOTAGE 442' CASING INFORMATION 9 5/8" @ 9107' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 10355.82 62.68 175.35 9443.22 10260.98 60.46 174.15 9398.07 10166.22 56.54 174.6 9348.57 10071.48 52.91 178.83 9293.85 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5 8.5" STC MDSi716LWBPX JG1042 4X11, 2X12, 1X13 9434 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 148.4 @ 10233.00000 6.3 @ 10400.00000 54.6 26.88394 FT/HR SURFACE TORQUE 26591 @ 10470.00000 21090 @ 10041.00000 24100.5 23774.61133 AMPS WEIGHT ON BIT 18 @ 10129.00000 2 @ 10131.00000 12.4 16.32452 KLBS ROTARY RPM 162 @ 10231.00000 99 @ 10183.00000 124.2 120.43316 RPM PUMP PRESSURE 2348 @ 10125.00000 1801 @ 10420.00000 2203.7 2164.19849 PSI DRILLING MUD REPORT DEPTH 10494' MW 9.6 VIS 55 PV 21 YP 27 FL 4.2 Gels 8/10/11 CL- 11000 FC 1/3 SOL 8.1 SD .50 OIL 0.5/90.5 MBL 3.1 pH 9.8 Ca+ 80 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 149 @ 10038.00000 8 @ 10399.00000 50.9 TRIP GAS - CUTTING GAS 0 @ 10480.00000 0 @ 10480.00000 0.0 WIPER GAS 200 @ 10038' CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 8604 @ 10038.00000 406 @ 10398.00000 2921.5 CONNECTION GAS HIGH 0 ETHANE (C-2) 1714 @ 10038.00000 48 @ 10398.00000 454.1 AVG 0 PROPANE (C-3) 1857 @ 10038.00000 73 @ 10398.00000 495.5 CURRENT 0 BUTANE (C-4) 1107 @ 10038.00000 64 @ 10399.00000 341.2 CURRENT BACKGROUND/AVG 0 PENTANE (C-5) 1439 @ 10463.00000 20 @ 10399.00000 115.4 HYDROCARBON SHOWS SHOW REPORT #3 INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION 10135' TO 10165' 100% CONGLOMERATE SAND AND CONGLOMERATE BEFORE 27 MAX 70 AFTER 25 40-60% YELL EVEN TO MOTTLED SAMPLE FLOR, INST LT BLU TRANSP CT W/ SLO INCR WITH SL SLO STRMG CUTS; FAIR OIL SHOW LITHOLOGY CONGLOMERATE SAND, CONGLOMERATE, SAND PRESENT LITHOLOGY 10480' = 80% SAND, 20% CONGLOMERATE SAND DAILY ACTIVITY SUMMARY Trip out of the hole from 9100' to the shoe on elevators (wiper trip). Service the rig: top drive, crown, draw works and baylor brake. Attempt to trip in the hole on elevators. Had to ream through tight spots at 9365', 9388', 9427', 9548'. 9683' and 9860'. Wiper gas was 200 units. Pump a 20 bbl sweep (with minimal increase in cuttings) and drill from 10040' to 10494'. Pump a 80 bbl sweep with a 100% increase in cuttings. Stop drilling and work the drill pipe. Lost 200 psi of pump pressure. Tested the surface equipment to 2000 psi and bled down 200 psi. Changed out the saver sub. Trip out of the hole to 9100' and pressure test both mud pumps to 2000 psi. Pressure tested the surface equipment. All tested good. Circulate and check pump pressure at 554 gallons. PSI was 1773. Blow down the top drive and trip out of the hole from 9100'. Found a hole in the drill pipe at 5079'. Picked up a new joint and pumped at 550 gallons with 1756 psi. Test was good. Prep to trip to bottom to drill. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS + 2 SC DAILY COST $3460 DML, $1445 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 2/5/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WEL ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR ROGERS/BRUMLEY DATE Feb 06, 2013 DEPTH 10990.00000 PRESENT OPERATION DRILLING FORMATION TIME 24 HOURS YESTERDAY 10480.00000 24 HOUR FOOTAGE 510' CASING INFORMATION 9 5/8 " @ 9107' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 10924.56 71.57 179.66 9646.55 10825.60 71.55 179.99 9615.25 10734.78 71.06 180.18 9586.14 10639.85 70.67 179.64 9555.02 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5 8.5" STC MDSi716LWBPX JG1042 4X11, 2X12, 1X13 9434 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 176.5 @ 10507.00000 1.0 @ 10510.00000 49.4 32.54468 FT/HR SURFACE TORQUE 27797 @ 10861.00000 20664 @ 10641.00000 24722.5 24149.72461 AMPS WEIGHT ON BIT 28 @ 10867.00000 2 @ 10495.00000 14.2 9.06247 KLBS ROTARY RPM 147 @ 10860.00000 0 @ 10988.00000 110.1 119.84365 RPM PUMP PRESSURE 2427 @ 10807.00000 1860 @ 10521.00000 2310.5 1961.81934 PSI DRILLING MUD REPORT DEPTH 10494' MW 9.6 VIS 55 PV 19 YP 20 FL 4.4 Gels 4/6/8 CL- 11000 FC 1/3 SOL 8.1 SD 0.50 OIL 0.5/90.5 MBL 2.5 pH 9.6 Ca+ 80 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 100 @ 10627.00000 9 @ 10869.00000 38.2 TRIP GAS - CUTTING GAS @ @ WIPER GAS 394 & 291 CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 12136 @ 10800.00000 492 @ 10481.00000 2884.4 CONNECTION GAS HIGH 0 ETHANE (C-2) 1246 @ 10628.00000 8 @ 10620.00000 258.9 AVG 0 PROPANE (C-3) 689 @ 10508.00000 8 @ 10620.00000 239.2 CURRENT 0 BUTANE (C-4) 590 @ 10508.00000 2 @ 10622.00000 179.9 CURRENT BACKGROUND/AVG 30 PENTANE (C-5) 260 @ 10745.00000 1 @ 10622.00000 95.6 HYDROCARBON SHOWS CONTINUED POOR OIL SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION 10480 TO 10990 CONGLOMERATE SAND CONGLOMERATE SAND NO GAS KICKS 20-40% DULL YELLOW EVEN TO MOTTLED OIL FLOR, INSTANT TRANSPARENT SLOW STRMG CUTS; WEAK DULL YELLOW UV RESD STAIN, NO VISIBLE WHITE LIGHT STAIN LITHOLOGY CONGLOMERATE SAND, CONGLOMERATE, SAND, COAL, CARBON SHALE PRESENT LITHOLOGY 10900' - 50% CONGLOMERATE SAND, 30% SAND, 20% CONGLOMERATE DAILY ACTIVITY SUMMARY Service the top drive, crown and draw works. Trip in the hole from 5100' to the shoe (9107'). Fill the pipe every 15 stands. Wash and ream from 9107' to 10494'. The hole was tight at 9420', 9555', 9587', 9742', 9805', 9919', 10006', 10043' and 10230'. Wiper gas was 394 units. Drill formation from 10494' to 10793'. Wiper trip from 10793' to 10403'. Trip back to bottom (10793'). Wiper gas was 291 units. Drill formation from 10793' to 10990' (midnight). EPOCH PERSONNEL ON BOARD BROWNE, BLEYS + 2 SC DAILY COST $3460 DML, $1445 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 2/6/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WEL ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR ROGERS/BRUMLEY DATE Feb 07, 2013 DEPTH 11259.00000 PRESENT OPERATION TRIP FOR BIT TIME 24 HOURS YESTERDAY 10990.00000 24 HOUR FOOTAGE 269' CASING INFORMATION 9 5/8" @ 9107' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11114.31 71.67 178.90 9706.53 11015.09 71.52 179.35 9675.21 10924.56 71.57 179.66 9646.55 10825.60 71.55 179.99 9615.25 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5 8.5" STC MDSi716LWBPX JG1042 4X11, 2X12, 1X13 9434 11260 1826 46:49 PP DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 70.6 @ 11121.00000 1.7 @ 11056.00000 27.2 10.00000 FT/HR SURFACE TORQUE 26986 @ 11091.00000 19897 @ 11209.00000 23949.3 22186.53320 AMPS WEIGHT ON BIT 28 @ 11042.00000 4 @ 10992.00000 12.5 12.09615 KLBS ROTARY RPM 178 @ 11127.00000 29 @ 11037.00000 119.8 129.16084 RPM PUMP PRESSURE 2424 @ 10995.00000 1767 @ 11080.00000 2272.9 2274.51050 PSI DRILLING MUD REPORT DEPTH 11260' MW 9.5+ VIS 52 PV 20 YP 18 FL 4.6 Gels 4/6/8 CL- 9000 FC 1/3 SOL 8.2 SD 0.50 OIL 0.5/90.5 MBL 2.5 pH 9.4 Ca+ 80 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 277 @ 11176.00000 6 @ 11077.00000 31.7 TRIP GAS - CUTTING GAS 0 @ 11259.00000 0 @ 11259.00000 0.0 WIPER GAS 125 @ 11173' CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 30574 @ 11176.00000 441 @ 11077.00000 2312.5 CONNECTION GAS HIGH 0 ETHANE (C-2) 584 @ 11176.00000 24 @ 11077.00000 160.6 AVG 0 PROPANE (C-3) 466 @ 11175.00000 15 @ 11077.00000 134.6 CURRENT 0 BUTANE (C-4) 339 @ 11175.00000 12 @ 11077.00000 102.9 CURRENT BACKGROUND/AVG 0 PENTANE (C-5) 199 @ 11175.00000 5 @ 11077.00000 61.3 HYDROCARBON SHOWS CONTINUED POOR OIL SHOWS BECOMING WEAKER WITH DEPTH INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY CONGLOMERATE SAND, CONGLOMERATE, SAND, SANDSTONE, COAL, CARBON CLAY, TUFFACEOUS SILT PRESENT LITHOLOGY 11260' = 50% CONGLOMERATE SAND, 20% CONGLOMERATE, 20% SANDSTONE, 10% SAND DAILY ACTIVITY SUMMARY Drill formation from 10990' to 11173'. Wiper from from 11173' to 10601'. Hole pulled tight from 11030' to 11017', 10800' and 10772'. Trip to bottom with wiper gas of 125 units. Drill formation from 11173' to 11260'. Notice abnormal pump pressure. Pull out of the hole. Hole was tight at 10160' and pumped through without rotating. Pull out on elevators to 7290'. Cut and slip new drill line. EPOCH PERSONNEL ON BOARD BROWNE, BLEYS + 2 SC DAILY COST $3460 DML, $1445 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 2/7/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WEL ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR ROGERS/BRUMLEY DATE Feb 08, 2013 DEPTH 11341.00000 PRESENT OPERATION DRILLING FORMATION TIME 24 HOURS YESTERDAY 11259.00000 24 HOUR FOOTAGE 82 CASING INFORMATION 9 5/8" @ 9107' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11114.31 71.67 178.90 9706.53 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5 8.5" STC MDSi716LWBPX JG1042 4X11, 2X12, 1X13 9434 11260 1826 46:49 8-6-RO-C-X-I-WT PR 6 8.5" STC MDSi716WBPX JG1044 4X12, 3X11 11260 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 174.5 @ 11337.00000 3.0 @ 11296.00000 48.0 76.15438 FT/HR SURFACE TORQUE 26046 @ 11273.00000 22143 @ 11278.00000 24405.2 24108.21680 AMPS WEIGHT ON BIT 17 @ 11335.00000 5 @ 11337.00000 13.2 12.29669 KLBS ROTARY RPM 188 @ 11278.00000 91 @ 11304.00000 114.2 112.32376 RPM PUMP PRESSURE 2274 @ 11259.00000 2013 @ 11313.00000 2082.6 2089.03955 PSI DRILLING MUD REPORT DEPTH 11282 MW 9.6 VIS 53 PV 17 YP 21 FL 4.8 Gels 5/6/7 CL- 9000 FC 1/2 SOL 8.2 SD 0.50 OIL 0.5/90.5 MBL 2.5 pH 9.8 Ca+ 120 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 73 @ 11296.00000 3 @ 11318.00000 19.5 TRIP GAS 90 CUTTING GAS 0 @ 11341.00000 0 @ 11341.00000 0.0 WIPER GAS - CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 9464 @ 11296.00000 457 @ 11318.00000 2225.8 CONNECTION GAS HIGH 0 ETHANE (C-2) 583 @ 11295.00000 24 @ 11318.00000 144.0 AVG 0 PROPANE (C-3) 363 @ 11295.00000 14 @ 11318.00000 96.5 CURRENT 0 BUTANE (C-4) 130 @ 11295.00000 5 @ 11318.00000 42.6 CURRENT BACKGROUND/AVG 15 PENTANE (C-5) 121 @ 11296.00000 3 @ 11318.00000 30.7 HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY TUFFACEOUS SILTSTONE, SAND, CARBON CLAY & SILT, COAL PRESENT LITHOLOGY 10340' = 100% TUFFACEOUS SAND DAILY ACTIVITY SUMMARY Trip out of the hole from 7990' to 430'. Lay down the BHA and hold a pre job safety meeting. Remove the nuke sources and lay down the MWD smart tools and old bit. Service the top drive, crown, draw works and Baylor brake. Pick up new BHA and make up MWD smart tools and load nuke sources. Trip in the hole filling the drill pipe every 30 stands to 9100'. Kelly up and link with MWD tools. Trip in the hole not pumping or reaming to 10600'. Wash and ream from 10600' to 10798'. Pump a 20 bbl sweep. Wash and ream from 10798' to 10867' and trip in without pumps from 10867' to 11151' while logging at 900 ft/hr. Trip in the hole from 11151' to 11260' program the MWD tools at 180 ft/hr. Drill formation from 11260' to 11341' (midnight). EPOCH PERSONNEL ON BOARD BROWNE, BLEYS + 2 SC DAILY COST $3460 DML, $41445 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 2/8/2013 file://C:\Documents and Settings\EpochAdmin\My Documents\My Wells\M31B\20130208. ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR MCINNES/ROGERS DATE Feb 09, 2013 DEPTH 11550.00000 PRESENT OPERATION PULLING OUT OF THE HOLE TIME 24 HOURS YESTERDAY 11341.00000 24 HOUR FOOTAGE 209' CASING INFORMATION 9 5/8" @ 9107' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11550 68.30 178.36 9854.07 11485.93 68.76 179.14 9830.47 11391.77 69.61 178.05 9797.01 11297.04 70.64 178.08 9764.81 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 6 8.5" STC MDSi716WBPX JG1044 4X12, 3X11 11260 11550 290 6:24 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 105.5 @ 11460.00000 0.9 @ 11536.00000 57.0 29.00537 FT/HR SURFACE TORQUE 26208 @ 11477.00000 21926 @ 11498.00000 24273.8 23480.97852 AMPS WEIGHT ON BIT 20 @ 11468.00000 4 @ 11494.00000 14.7 16.08120 KLBS ROTARY RPM 151 @ 11513.00000 86 @ 11379.00000 114.4 137.16960 RPM PUMP PRESSURE 2305 @ 11513.00000 2007 @ 11469.00000 2131.9 2092.23926 PSI DRILLING MUD REPORT DEPTH 11550' MW 9.6 VIS 52 PV 19 YP 22 FL 4.2 Gels 4/6/8 CL- 9000 FC 1/2 SOL 8.2 SD 0.50 OIL 0.5/90.5 MBL 2.5 pH 9.7 Ca+ 80 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 66 @ 11377.00000 6 @ 11470.00000 26.8 TRIP GAS - CUTTING GAS @ @ WIPER GAS 65 @ 11550' CHROMATOGRAPHY (ppm) SURVEY 0 METHANE (C-1) 7912 @ 11393.00000 424 @ 11470.00000 2713.5 CONNECTION GAS HIGH 0 ETHANE (C-2) 853 @ 11393.00000 27 @ 11470.00000 202.2 AVG 0 PROPANE (C-3) 880 @ 11393.00000 25 @ 11470.00000 192.2 CURRENT 0 BUTANE (C-4) 491 @ 11393.00000 20 @ 11494.00000 116.7 CURRENT BACKGROUND/AVG 0 PENTANE (C-5) 200 @ 11393.00000 7 @ 11494.00000 58.0 HYDROCARBON SHOWS VERY POOR OIL SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION 11500 TO 11550 ASHY SAND BEFORE 13 MAX 58 AFTER 18 10% DULL YELLOW EVEN TO MOTTLED SAMPLE FLORECSNCE, VERY POOR SLOW OIL CUTS; VERY POOR RESIDUE STAIN LITHOLOGY TUFFACEOUS SAND, CONGLOMERATE SAND, SAND, CONGLOMERATE SAND, ASH, TUFFACEOUS SILTSTONE PRESENT LITHOLOGY 11550' = SAND 70%, CONGLOMERATE SAND 10%, TUFFACEOUS SILTSTONE 10%, ASH 10% DAILY ACTIVITY SUMMARY Drill formation from 11341' to 11550'. Circulate and condition bottom's up twice. Wiper trip from 11550' to 11050' and circulate through tight spots. Went back to bottom without problems. Wiper gas was 65 units. Circulate and condition the hole four times. Trip out of the hole (pumping out) from 11550' to 11000' with no rotation and pulling slow through tight spots. Noted swab and overpull from 9610' to 9635'. Run in the hole one stand and wash and ream from 9666' to 9727'. Circulate and condition the hole and pump sweeps to surface. Repacate and rotate the drill pipe. Did not back ream from 9666' to 9727'. Trip out of the hole to 9107' (shoe). Circulate and condition bottom's up. 96 units of gas. Monitor the well with no loss. Trip in the hole from 9107' to 10014' and wash down from 10014' to 10100' with no tight spots or bridges. Trip out of the hole from 10100' to 10014'. Wash down from 10014' to 10100' with no tight spots or bridges. Trip out of the hole from 10100' to 9107' pumping out with no troubles (midnight). EPOCH PERSONNEL ON BOARD BROWNE, SHERRY DAILY COST $2590 DML, $1445 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 2/9/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WEL ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR MCINNES/ROGERS DATE Feb 10, 2013 DEPTH 11550.00000 PRESENT OPERATION TRIP IN HOLE WITH 7" CASING TIME 24 HOURS YESTERDAY 11550.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 9107' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11550 68.30 178.36 9854.07 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 6 8.5" STC MDSi716WBPX JG1044 4X12, 3X11 11260 11550 290 6:24 TD DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBL pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 5 @ CIRC 0 @ CIRC 1 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 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 11550' = 70% SAND, 10% CONGLOMERATE SAND, 10% TUFFACEOUS SILTSTONE, 10% ASH DAILY ACTIVITY SUMMARY Circulate and condition and finish bottom's up at the shoe (9107'). Drop rabbit on stand #92 and pull one stand. Circulate and condition the hole at 8900'. Blow down the top drive and monitor the well = static. Trip out of the hole from 8900' to 6500' and circulate. Monitor the well = static. Pump a 50 bbl sweep and pump a dry job. Trip out of the hole from 6500' to 348'. Lay down the BHA and hold a pre job safety meeting. Stand back the HWDP, jars and lay down the flex collar. Remove the nuke source and lay down the smart tools and drill bit. Remove MWD cross over's and subs from the drill floor. Rig up Weatherford casing tools and equipment for 7" casing. Monitor the losses the well is taking (.80 bbl/hr). Make up single shoe track, single joint, float collar and single. Verified shoe and float joints were clear of debris. Run casing check float = good. Continue to run in the hole with 7" casing. Pick up packer and make up liner running sleeve with plax mix. Rig down Weatherford casing tools and monitor the well = zero loses in 30 minutes. Run liner and circulate one casing volume. Make up cement head and lay out. Trip in the hole with 7" liner on drill pipe and fill everey ten stands slowly to 4436' (midnight). EPOCH PERSONNEL ON BOARD BROWNE, SHERRY DAILY COST $2560 DML, $1445 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 2/10/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR MCINNES/ROGERS DATE Feb 11, 2013 DEPTH 11550.00000 PRESENT OPERATION CIRC MUD BRFORE CEMENTING LINER TIME 24 HOURS YESTERDAY 11550.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 9107' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11550 68.30 178.36 9854.07 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 11550' MW 9.5+ VIS 52 PV 16 YP 18 FL 4.5 Gels 4/5/6 CL- 9000 FC 1/2 SOL 8.2 SD 0.50 OIL 0.5/90.5 MBL 2.5 pH 9.4 Ca+ 80 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 22 @ TG 1 @ TIH 2 CIRC TRIP GAS 22 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 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 11550' = 70% SAND, 10% CONGLOMERATE SAND, 10% TUFFACEOUS SILTSTONE, 10% ASH DAILY ACTIVITY SUMMARY Trip in the hole from 4436' to 9107' (shoe) with liner and fill the drill pipe every 10 stands. Circulate and condition the hole. Maximum gas was 22 units. Trip in the hole from 9107' to 11065'. Kelly up on every stand and pump at 3 bpm. Encountered tight spots (that took weight) at 9634', 9815', 10142' and 10234'. Had to pump and rotate through the tight spots at 8 bpm. Trip in the hole with 7" liner on drill pipe from 11065' and working through tight spots on the way in. Circulate and condition the drill pipe ten feet up and down and hold a pre job safety meeting prior to cementing. Hook up the cement head and pressure test the cement lines. Test was good. Pump 53 bbls of mud push at 12.o ppg. Shut down working the pipe due to Shulumberber batching up cement. Mechanical failure (pulling 425k). Circulate and work pipe free. Attempt to rotate with the cement head. Circulate the mud push to surface. Background gas is four units. Continue to work drill pipe 10'. EPOCH PERSONNEL ON BOARD BROWNE, SHERRY DAILY COST $2560 DML, $1445 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 2/11/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR MCINNES/ROGERS DATE Feb 11, 2013 DEPTH 11550.00000 PRESENT OPERATION TESTING BOPE TIME 24 HOURS YESTERDAY 11550.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 9107 7" @ 11458' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11550 68.30 178.36 9854.07 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 11550' MW 9.6+ VIS 55 PV 17 YP 19 FL 4/5/6 Gels 4.8 CL- 9000 FC 1/2 SOL 8.2 SD .50 OIL 0.5/90.5 MBL 2.5 pH 9.4 Ca+ 80 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 17 @ TG 0 @ TIH 2 TIH TRIP GAS 17 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 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 11550' = 100% CEMENT DAILY ACTIVITY SUMMARY Circulate and condition and rig down the cement line. Rotate and reciprocate through the drill pipe from 11548' to 11540' while Schlumberger troubleshoots their slurry pump. Pressure test the cement lines. Hook the cement lines back up. Hold a pre job safety meeting. SLB pumped 5 bbls of water and pressure test low to 1000 and high to 5000 psi. Circulate and cement displace pump with 50 bbls of mud push. Swap to SLB pump and pump 54 bbls of 15.6 ppg lead 4,2 bpm. SLB pumped 122 bbls of 15.6 ppg tail at 3.4 bpm. Drop the drill pipe dart and SLB pump 5 bbl FIW. Swap to rig pumps and displace while reciprocating. Circulate cement displacement. Pipe got sticky and parked it while displacing at 1200 strokes away at 6 bpm and 1500 psi. Bumped the dart at 1412 strokes and packed off at 1730 strokes 1.5 bpm to 3400 psi. Swap to SLB pumps and pump 7 more barrels. Pressure test the casing shoe to 5000 psi with SLB pumps. Set hanger 50k down and 20k up and release the hanger. Pressure test the back side to 1500 psi. At 800 psi the drill pipe and casing pressure equalized. Set down in Bakers tool 3' and pressured up again to 1120 psi and the pressure equalized. Circulate and condition and pressure up to 500 psi and release from the hanger. Circulate bottoms up (17 units of gas) and got back 40 bbls of mud push and a little cement. Trip out of the hole and rig down the cement head and blow down lines and monitor the well.Start to trip out of the hole from 8895' to 984' checking for cement rings on every connection. Pick up the rotating cement head and lay down. Continue to pull out of the hole from 984' to the Baker running tool and lay down. Prep to test the BOPE. Change out the lower rams to 4". Pick up test tools and begin to test the BOPE. EPOCH PERSONNEL ON BOARD BROWNE, SHERRY DAILY COST $2560 DML, $1445 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 2/12/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR MCINNES/ROGERS DATE Feb 13, 2013 DEPTH 11550.00000 PRESENT OPERATION TRIP IN THE HOLE TO DRILL CEMENT TIME 24 HOURS YESTERDAY 11550.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 9107' 7" @ 11458' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11550 68.30 178.36 9854.07 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 7 6.0" HTC STX-5214676 A60169 3X18 8920' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 11550' MW 9.6+ VIS 55 PV 18 YP 18 FL 4.9 Gels 4/5/6 CL- 9000 FC 1/2 SOL 8.2 SD 0.50 OIL 0.5/90.5 MBL 2.5 pH 9.6 Ca+ 80 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 1 @ TIH 0 @ TIH 0-1 TIH 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 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 100% CEMENT DAILY ACTIVITY SUMMARY Continue to test BOPE. Attempt to unscrew 5" test joint. Joint is torqued up too much. Tried to pull the test plug and had problems pulling. Pulled over 20k over while working the string sideways. Plug came free. Lay down the 5" joint and pulled up the test plug covered with sand. Make up 4" test joint and set plug. Continue to test the BOPE. Lay down the test tool and pull the test plug and pump out the stack. Set the wear ring and lay down the 4" test joint. Pick up the BHA, drill collar, stabilizer, bit sub with float and 6" bit. Mud pump problems. Troubleshoot the mud pumps due to pressure problem. Circulate and condition and fill pipe. Trip in the hole from 2769' to 9497' EPOCH PERSONNEL ON BOARD BROWNE, SHERRY DAILY COST $2560 DML, $1445 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 2/13/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR MCINNES/ROGERS DATE Feb 05, 2013 DEPTH 10550.00000 PRESENT OPERATION DRILLING CEMENT TIME 24 HOURS YESTERDAY 10550.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 9107' 7"@ 11458' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11550' 68.30 178.36 9854.07 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 7 6.0" HTC STX 5214676 3X18 8920 11054 0 0 PR 8 6.0" HTC QHIR 12091781 OPEN 11050 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 11550' MW 9.6 VIS 51 PV 15 YP 18 FL 6.8 Gels 4/5/6 CL- 8000 FC 1/2 SOL 8.8 SD 0.50 OIL 0.5/90.0 MBL 3.0 pH 9.5 Ca+ 240 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 7 @ TG 0 @ TIH 2 CIRC TRIP GAS 7 & 3 UNITS 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 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 100% CEMENT DAILY ACTIVITY SUMMARY Trip in the hole and tag cement at 9968'. circulate and drill cement from 9968' to 10054'. Trip gas is 7 units. Encountered hard spot and took weight and quit drilling. Received drill pipe wiper plug rubber back, Tried varied drilling parameters in attempt to drill. Couldn't make any hole. Trip out of the hole from 10054' to the surface and stand back 4" drill pipe, collars and lay down the drill bit. Bit looked clean. Service the draw woorks and crown. Trip in the hole with 5" HWDP and sharper bit, Clean the rig floor. Swap elevators and pick up BHA and trip in the hole and tag cement at 10050'. Trip gas was 3 units. Drill cement from 10050' to 10051' (midnight). EPOCH PERSONNEL ON BOARD BROWNE, SHERRY DAILY COST $2560 DML, $1445 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 2/14/2013 file://C:\Documents and Settings\EpochAdmin\My Documents\My Wells\M31B\Morn Re ... Hilcorp Alaska, LLC DAILY WELLSITE REPORT M-31B REPORT FOR MCINNES/ROGERS DATE Feb 14, 2013 DEPTH 11550.00000 PRESENT OPERATION PRESSURE TEST CASING TIME 24 HOURS YESTERDAY 11550.00000 24 HOUR FOOTAGE 0 CASING INFORMATION 9 5/8" @ 9107' 7" @ 11458' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11550' 68.30 178.36 9854.07 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 8 6.0" HTC QHIR 12091781 OPEN 11050 11550 500' 0 TD DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 11550' MW 9.6 VIS 51 PV 15 YP 18 FL 6.8 Gels 4/5/6 CL- 8000 FC 1/2 SOL 8.8 SD 0.50 OIL 0.5/90.0 MBL 3.0 pH 9.5 Ca+ 240 CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 29 @ TG 1 @ TIH 3 TRIP GAS 29 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 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS NO SHOWS THE LAST 24 HOURS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY 100% CEMENT DAILY ACTIVITY SUMMARY Drill cement wiper plug from 10051' to 10053'. Drill cement from 10053' to 11412'. Drill landing collar to 11450'. Circulate and condition and pump a 30 bbl sweep bottom's up. Rig up to test casing. Begin to test casing at midnight. EPOCH PERSONNEL ON BOARD BROWNE, SHERRY DAILY COST $2560 DML, $1445 RW REPORT BY LEES F. BROWNE JR. Page 1 of 1Daily Report 2/15/2013 file://C:\DOCUMENTS AND SETTINGS\EPOCHADMIN\MY DOCUMENTS\MY WE ...