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212-089
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: Pull & Swap Tubing Development Exploratory 3. Address:Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 11,322 feet NA feet true vertical 11,086 feet NA feet Effective Depth measured 11,200 feet 10,681 feet true vertical 10,970 feet 10,482 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet 2-7/8" 6.5# / L-80 9,883' MD 9,734' TVD Tubing (size, grade, measured and true vertical depth)2-3/8" 4.7# / L-80 10,767' MD 10,563' TVD Packers and SSSV (type, measured and true vertical depth)10,681' MD 10,482' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: Ryan Lemay, Operations Engineer 324-287 Sr Pet Eng: 7,250psi Sr Pet Geo:Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A ryan.lemay@hilcorp.com 661-487-0871 DHL Retrievable Pkr; N/A 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) 6 Gas-Mcf MD 150 Size 80' 645 11000 0 00 260 measured TVD 7-5/8" 8,290psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 212-089 50-133-20604-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: A028399; A028406 Swanson River Field / Hemlock Oil Swanson River Unit (SRU) 14B-27 Plugs Junk measured Length Production Liner 10,104' 1,431' Casing Structural 9,940' 5" 10,104' 11,320'11,086' 80'Conductor Surface Intermediate 16" 10-3/4" 80' 3,001' 4,790psi 3,580psi 6,890psi 2,961'2,959' Burst Collapse 2,909psi p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Gavin Gluyas at 9:00 am, Feb 14, 2025 Noel Nocas (4361) Digitally signed by Noel Nocas (4361) Date: 2025.02.13 17:39:36 -09'00' BJM 3/12/25 DSR-2/18/25 RBDMS JSB 021925 Well Name: SRF SRU 014B-27 API #:50-133-20604-00-00 Field:Swanson River Start Date:6/4/2024 Permit #:212-089 Sundry #:324-287 End Date:1/22/2025 6/4/2024 6/5/2024 6/15/2024 1/13/2025 1/14/2025 Daily Operations: Bullhead 61bbls down the tbg. Bullhead 375bbls down the IA. Monitor well static. Install BPV and ND tree. Install test plug. NU 13-5/8'' stack. MU 2-3/8'' and 2-7/8'' test jts. Install rig floor and cellar tarps. Test BOPE's as per sundry. AOGCC rep Jim Regg waived witness. Activity Report PJSM ,PTW , R/U E-line unit, M/U 1 9/16" tubing punch 0 deg phasing, M/U lubricator, P/T 250 psi low /2500 psi high. Good test. RIH, correlate, and fire shots 10698'- 10701', POOH R/D e-line, secure well. R/U slickline and PT lubricator 250 psi low / 2500 psi high. Good test. Pull chemical injection valve made 2 attempts @ pulling orifice valve @ 10,650'kb wouild not locate PT slickline lubricator 250 psi low / 2500 psi high - Good. Pull Orifice valve @ 10,641'kb MIRU Rig 401 on SRU 14B-27 Page 1 of 3 Well Name: SRF SRU 014B-27 API #:50-133-20604-00-00 Field:Swanson River Start Date:6/4/2024 Permit #:212-089 Sundry #:324-287 End Date:1/22/2025 1/15/2025 1/16/2025 1/17/2025 1/18/2025 1/19/2025 1/21/2025 Activity Report Daily Operations: MIRU slickline. PT lubricator 250 low/2500 psi high - Good. Change Chemical injection dummy for valve and pull ball/rod. RIH w/ 2-3/8" and 2-7/8" EUE GL completion per tally to 10,767'. Banding CI line every other joint. Filling hole 10 bbls/hr with PW. Ran a total of 169 - 3/4" SS Bands, P/U 56 K, S/O 52 K. M/U hanger, Install CI line on pressure test 3,500 psi (Good test). Land hanger 48k down, RILD. R/u and fill tubing and IA , MIT Tubing and IA to 2,500 psi for 30 min, good tests. Install TWC, Nipple down BOPE. Install production tree, test void and tree to 5000 psi - Good. Pull TWC. R/d to move rig to SCU 42B-05. Continue testing BOPE's. CO annular element. Go to shell test and tighten up door seals leaking and mud cross. Restart BOPE test. Test 1 and 2 good. Test 3 leaking on low. CO BPV for TWC. K1 leaking closed K2 and continued testing. Test 3, 4, and 5 good. Koomy drawdown test good. CO 2-3/8'' TJ for 2-7/8'' TJ. Test 6, 7 and 8 good. Remove K1 valve. RIH w/ 2-7/8" eue tubing f/9,394' to 9,981'. R/u to bullhead 60 bbl's down tubing, Continue RIH w/ 2-7/8" EUE tubing f/ 9,981' t/10,804', R/u to bullhead 20 bbl's down tubing, Pooh, L/d 4 jnts of 2-7/8" eue tubing and rack back a total of 147 stands of 2 -7/8" tubing in derrick, L/d 6 jnts of 2- 3/8" eue tubing and rack back a total of 11 stands of 2-3/8" tubing in derrick and l/d last 4 joints. RIH w/ 2-3/8" and 2-7/8" EUE GL completion per tally to 5972'. Banding CI line every other joint (CI line tested to 3500psi for 10 min after install, good test). Filling hole 10 bbls/hr with PW. Completed BOPE test as per sundry 250 psi low / 2500 psi high. R/D test equipment. Pumped 20bbl down IA, pulled TWC, flow check. R/U handling equipment. M/U 2-7/8" LJ w/TIW. BOLDS. Pulled up to 105k with 4' of hanger travel. Troubleshoot, pumped 15bbls down IA while working pipe and hanger came free. Pulled 40k over and sheared FH packer at 10,684'. Free travel up 62k. L/D hanger and 3 full joints then over pull 10-15k. Pumped 1 bbl of NXS down IA and displaced w/375 bbls of PW at 3 bpm / 40 psi. Work pipe 65k/45k and work packer out of 5" liner (25 joints). Free travel in 7-5/8" liner 52k. Pull & lay down 2-7/8" Tubing w/ 3/8" chemical injection line F/9,976' T/5,835'. Pull & lay down 2-7/8" Tubing w/ 3/8" chemical injection line F/5,835' T/ 965'.Total of 321 jnts 2 7/8" Change out handling equip. Pull and lay down 2 -3/8" Tubing w 3/8" chemical injection line F/965' T/ surface, Total of 28 joints of 2-3/8", 2 - 2 7/8" GLM, 1- 2 7/8" X 2 3/8" X/O, 1 - 2 3/8" GLM, 1- 2 3/8" CIM, 1- 5" DHL retrievable packer, 1- 2 3/8" X- nipple, 1- wire line Re-entry guide, Total of 200 out of 212 3/4" SS Bands recovered. Rig up E-Line equip., 1st RIH w/ 7' - 1 11/16" WB, 2 3/4" CCL, 2 3/4" JB, w/ 3.75" Gauge ring down to 10,720', Pooh, 2nd RIH w/ 56 arm caliper 3.55" OD, Ran to 10,720', POOH. R/d e-line. M/u 4-1/8" tri cone bit w/ 5" scraper BHA, single in hole on 2- 3/8" EUE tubing f/ surface to 1033' (32 joints). Change out handling equipment to 2-7/8". M/u 2-3/8"x2-7/8" EUE crossover and continue to single in hole w/ cleanout BHA on 2-7/8" EUE tubing f/1033' to 9394' Page 2 of 3 Well Name: SRF SRU 014B-27 API #:50-133-20604-00-00 Field:Swanson River Start Date:6/4/2024 Permit #:212-089 Sundry #:324-287 End Date:1/22/2025 1/22/2025 Daily Operations: PT slickline lubricator 250 low / 2500 psi high - Good. Clear tubing of debris, pull plug. No debris seen on plug or in tubing. RDMO Activity Report Page 3 of 3 ___________________________________________________________________________________ Updated by SRW 01-20-25 SCHEMATIC Swanson River Unit Well: SRU 14B-27 PTD: 212-089 API: 50-133-20604-00 Completions Run: 1/19/25 TD = 11,322’ MD - 11,086’ TVD PBTD = 11,200 MD – 10,970’ TVD KB: 18.6’ (401 Elevation from RWO in 2025) PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date H-1 10,807’ 10,815’ 10,600’ 10,607’ 8 6 2” HC 7/12/13 10,819’ 10,827’ 10,612’ 10,619’ 8 6 2” HC 7/12/13 H-2 10,830’ 10,836’ 10,623’ 10,628’ 6 6 2” HC 7/12/13 H-3 10,854’ 10,859’ 10,644’ 10,649’ 5’ 6 3-3/8” HC 3/19/13 10,859’ 10,880’ 10,649’ 10,669’ 21’ 6 3-3/8” HC 3/19/13 10,886’ 10,898’ 10,674’ 10,685’ 12’ 6 3-3/8” HC 3/19/13 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 109 X-56 - - Surf 80' 10-3/4" Surf. Csg 45.5 L-80 Buttress 9.875” Surf 2,961’ 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 7,093’ 7-5/8" Intermediate 29.7 P-110 BTC 6.75" 7,093’ 10,104’ 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 9,889’ 11,320’ TUBING 2-7/8” Production 6.5 L-80 8rd 2.441 Surf 9,883’ 2-3/8” Production 4.7 L-80 8rd 1.995 9,883’ 10,767’ 1 11 16” 10-3/4” 2 12 13 5” 7-5/8” 14 10 15 16 H3 Sands H1 Sands H2 Sands X JEWELRY DETAIL No Depth ID OD Item 1 19’ 2.441” - 3-1/2” Tubing Hanger w/ XO to 2-7/8” 8RD 2 3,961’ 2.44” 4.688” 2-7/8” IPO-1 GLM #10 3 5,032’ 2.44” 4.688” 2-7/8” DV GLM #9 4 5,778’ 2.44” 4.688” 2-7/8” DV GLM #8 5 6,457’ 2.44” 4.688” 2-7/8” DV GLM #7 6 7,102’ 2.44” 4.688” 2-7/8” IPO-1 GLM #6 7 7,716’ 2.44” 4.688” 2-7/8” DV GLM #5 8 8,429’ 2.44” 4.688” 2-7/8” DV GLM #4 9 9,140’ 2.44” 4.688” 2-7/8” IPO-1 GLM #3 10 9,817’ 2.44” 4.688” 2-7/8” DV GLM #2 11 9,871’ 2.441” 4.688” 2-7/8” Chemical Injection Mandrel 12 9,882’ 1.995” 3.670” 2-7/8” Box X 2-3/8” Pin XO 13 10,634’ 2.44” 4.688” 2-3/8” Slim hole Orifice Valve GLM #1 14 10,681’ 1.940” 4.130” 5” DHL Hydraulic Retrievable Set Packer 15 10,729’ 1.875” 3.070” 2-3/8” X-Nipple 16 10,766’ 1.960” 3.060” 2-3/8” WL Re-Entry Guide Tag TOC @ 10,901’ WLM 10/5/16 3 5 6 7 8 9 4 Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 6/27/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240627 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# KBU 43-07Y 50133206250000 214019 6/6/2024 AK E-LINE Perf KBU 43-07Y 50133206250000 214019 6/10/2024 AK E-LINE Perf KBU 43-07Y 50133206250000 214019 6/12/2024 AK E-LINE Perf MPU F-6650029226970ϭ00 1961ϲϮ 5/17/2024 AK E-LINE Perf MRU K-03RD2 50733200740200 217029 5/25/2024 AK E-LINE TubingPunch PAXTON 2 50133205730000 207164 5/16/2024 AK E-LINE Pref PAXTON 2 50133205730000 207164 5/30/2024 AK E-LINE TubingPatch PAXTON 11 50133207040000 221114 5/20/2024 AK E-LINE Perf SCU 13-09 50133203430000 181098 6/2/2024 AK E-LINE Cement/JetCut SDI 3-07A 50029219110100 198147 5/28/2024 AK E-LINE Pkr/Poglm SRU 14B-27 50133206040000 212089 6/15/2024 AK E-LINE JewelryLog SRU 32C-15 50133206130000 213070 6/13/2024 AK E-LINE TubingCut Revision Explanation: There are additional images added to the final report and a few new .las files. In the Emeraude folder there are 2 new .las files and in the Field Data folder the RIH and POOH are new .las files Please include current contact information if different from above. T39076 T39076 T39076 T39077 T39078 T39079 T39079 T39080 T39081 T39082 T39083 T39084 SRU 14B-27 50133206040000 212089 6/15/2024 AK E-LINE JewelryLog Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.06.27 13:09:17 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 5/10/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240510-1 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 242-04 50283201640000 212041 3/11/2024 AK E-LINE Perf LRU C-01RD 50283200610100 201168 4/26/2024 AK E-LINE Perf LRU C-02 50283201900000 223057 4/28/2024 AK E-LINE Perf MPU F-65 50029227526000 223121 5/3/2024 AK E-LINE HoistCut MPU L-07 50029220280000 190037 4/26/2024 AK E-LINE Perf NCIU A-17 50883201880000 223031 4/28/2024 AK E-LINE GPT/Perf NCIU B-02 50883200900100 197210 4/29/2024 AK E-LINE PPROF NCIU B-02 50883200900100 197210 5/4/2024 AK E-LINE PPROF PAXTON 6 50133207070000 222054 4/13/2024 AK E-LINE GPT/CIBP/Perf PAXTON 6 50133207070000 222054 4/16/2024 AK E-LINE GPT/CIBP/Perf SRU 14B-27 50133206040000 212089 4/23/2024 AK E-LINE Caliper SRU 32C-15 50133206130000 213070 4/24/2024 AK E-LINE Caliper TBU M-15 50733204220000 190109 4/18/2024 AK E-LINE GPT/Puncher TBU M-23 50733207190000 224018 5/1/2024 AK E-LINE CBL Please include current contact information if different from above. T38780 T38781 T38782 T38783 T38784 T38785 T38786 T38786 T38787 T38787 T38788 T38789 T38790 T38791 SRU 14B-27 50133206040000 212089 4/23/2024 AK E-LINE Caliper Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.05.13 15:31:19 -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 Other: Pull & Swap Tubing 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): 11,332'N/A Casing Collapse Structural Conductor Surface 2,909 psi Intermediate 4,790 psi Production Liner 7,250 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: Contact Email: Contact Phone: 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 jake.flora@hilcorp.com 907-777-8442 Noel Nocas, Operations Manager 907-564-5278 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 Jake Flora, Operations Engineer AOGCC USE ONLY 8,290 psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028399, FEDA028406 212-089 50-133-20604-00-00 Hilcorp Alaska, LLC Proposed Pools: 6.5#/ L-80 TVD Burst 10,750' 2,959' Size 80' 7-5/8"10,104' 3,001' MD 5" See Attached Schematic 6,890 psi 3,580 psi 80' 9,940' 80' 2,961' June 1, 2024 11,320'1,431' 2-7/8" 11,086' Perforation Depth MD (ft): 10,104' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Swanson River Unit (SRU) 14B-27CO 123B Same 1,386 psi N/A Length N/A; N/A N/A; N/A 11,086' 11,200' 19,970' Swanson River Hemlock Oil 16" 10-3/4" See Attached Schematic Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test No Wellbore schematic 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 3:59 pm, May 10, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.05.10 15:18:04 - 08'00' Noel Nocas (4361) 324-287 DSR-5/13/24 10-404 BOP test to 2500 psi. BJM 5/23/24 SFD 5/13/2024 X ($8JLC 5/23/2024 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.05.24 12:02:54 -08'00'05/24/24 RBDMS JSB 052824 Well Prognosis Well: SRU 14B-27 Well Name:SRU 14B-27 API Number:50-133-20604-00-00 Current Status:Gas Lifted Oil Well Permit to Drill Number:212-089 First Call Engineer:Jake Flora (907) 777-8442 (O)(720) 988-5375 (C) Second Call Engineer:Chad Helgeson (907) 229-4824 (C) Current Bottom Hole Pressure: ~ 2,300 psi @ 10,365’ TVD (Based on GL survey) Max. Potential Surface Pressure: ~ 1,264 psi (Based on 0.1psi/ft gas gradient) Well Status SI gas lifted producer (30 BO, 430 BW, 92% WC, 1500 MCFD Gas Lift (12/02/2023) Brief Well Summary SRU 14B-27 is a 2013 new drill originally completed as a gas lifted oil producer in the Hemlock H1-H3. An ESP was run in 2013. In 2016 the ESP was pulled and recompleted with a gas lift design. In February 2024 the gross fluid rate fell from 350 bfpd to 25 bfpd. A gas lift survey found tubing holes at 5850’, 6010’, & 6430’. A subsequent caliper found over 30 joints with grade F tubing (over 50% wall loss), primarily below 4000’ MD. The purpose of this work/sundry is to replace the tubing and return the well to production. Wellbore History 2-20-24 1.5” DDB to 10923’, recover sand, log flowing gaslift survey 4-25-24 Caliper found 31 Grade F joints Pre-Rig 1. RU slickline, PT lubricator to 2500 psi, pull GLV from 2-3/8” GLM @ 10650’ 2. Bleed down any residual gas lift pressure from tubing and IA Procedure: 1. MIRU Hilcorp rig #401, Provide AOGCC 24hrs advance notice of BOP testing 2. RU pump, circulate one wellbore volume, OR bullhead tubing and annulus volume a. Wellbore volume to perfs to ~390 bbls b. Static fluid level is anticipated to be near 6000’ 3. Set BPV/TWC, ND tree 4. NU BOP & test to 2500 psi a. BOP dressed with 2-3/8” – 3-1/2” Flexpacker Rams b. Test with 2-3/8” & 2-7/8” test joints c. BOP will be used as needed for wellbore circulation and will not be tested after 5. Pull BPV/TWC 6. MU landing joint, pull hanger to the floor, shear FH Hydraulic Packer at 11263’ (30k shear) 7. Pull & LD completion 8. MU & run new 2-7/8” x 2-3/8” gas lift completion a. WL Entry guide, X-nipple w plug body, hydraulic set packer, chem sub to be placed near existing depths b. Optional 2-7/8” sliding sleeve @ ~9850’ (not on proposed WBD) c. GLMs to be run with live valves per new GL design 9. Land hanger 10. Drop ball & rod 11. Pressure up tubing to set packer, MIT tubing to 2500 psi 12. Hold tubing pressure, MIT annulus to 2500 psi 13. Set BPV/TWC 14. ND BOP, NU tree, test tree BOPE must be tested if used to shut-in a flowing well. -bjm BOP will be used as needed for wellbore circulation and will not be tested after Well Prognosis Well: SRU 14B-27 15. Pull BPV/TWC 16. Release rig Post Rig 1. MIRU Slickline, PT lubricator to 2500 psi, pull B&R, pull plug 2. Hand over to production Attachments: 1. Actual Schematic 2. Proposed Schematic 3. BOP Diagram 4. Wellhead Diagram (no planned changes to wellhead) ___________________________________________________________________________________ Updated by DMA 11-10-16 SCHEMATIC Swanson River Unit Well: SRU 14B-27 PTD: 212-089 API: 50-133-20604-00 Completions Run: 10/9/16 TD = 11,322’ MD - 11,086’ TVD PBTD = 11,200 MD – 10,970’ TVD KB-THF: 15’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 109 X-56 - - Surf 80' 10-3/4" Surf. Csg 45.5 L-80 Buttress 9.875” Surf 2,961’ 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 7,093’ 7-5/8" Intermediate 29.7 P-110 BTC 6.75" 7,093’ 10,104’ 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 9,889’ 11,320’ TUBING 2-7/8” Production 6.4 L-80 8rd 2.441 Surf 9,800’ 2-3/8” Production 4.6 L-80 8rd 1.995 9,800’ 10,750’ 1 6 16” 10-3/4” 2 4 5 5” 7-5/8” 7 3 8 9 PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date H-1 10,807’ 10,815’ 10,600’ 10,607’ 8 6 2” HC 7/12/13 10,819’ 10,827’ 10,612’ 10,619’ 8 6 2” HC 7/12/13 H-2 10,830’ 10,836’ 10,623’ 10,628’ 6 6 2” HC 7/12/13 H-3 10,854’ 10,859’ 10,644’ 10,649’ 5’ 6 3-3/8” HC 3/19/13 10,859’ 10,880’ 10,649’ 10,669’ 21’ 6 3-3/8” HC 3/19/13 10,886’ 10,898’ 10,674’ 10,685’ 12’ 6 3-3/8” HC 3/19/13 H3 Sands H1 Sands H2 Sands X JEWELRY DETAIL No Depth ID OD Item 1 19’ 2.441” - 3-1/2” Tubing Hanger w/ XO to 2-7/8” 8RD 2 4,486’ 2.441” 4.688” 2-7/8” SFO-1 GLM – IPOR-1 Valve - 2240 psi; port sz 16 3 7,806’ 2.441” 4.688” 2-7/8” SFO-1 GLM – IPOR-1 Valve -2170 psi; port sz 16 4 9,973’ 1.995” 3.670” 2-7/8” Box X 2-3/8” Pin XO 5 10,650’ 1.995” 3.750” 2-3/8” GLMAX-1 GLM (T-1 latch) Orifice-1 Valve; port sz 22 6 10,666’ 1.995” 3.750” 2-3/8” Chemical Injection Mandrel 7 10,684’ 1.995” 4.110” 5” DHL Hydraulic Retrievable Set Packer 8 10,726’ 1.875” 2.375” 2-3/8” X-Nipple 9 10,759’ 1.995” 3.060” 2-3/8” WL Re-Entry Guide Tag TOC @ 10,901’ WLM 10/5/16 ___________________________________________________________________________________ Updated by DMA 05-07-24 PROPOSED Swanson River Unit Well: SRU 14B-27 PTD: 212-089 API: 50-133-20604-00 Completions Run: 10/9/16 TD = 11,322’ MD - 11,086’ TVD PBTD = 11,200 MD – 10,970’ TVD KB-THF: 15’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 109 X-56 - - Surf 80' 10-3/4" Surf. Csg 45.5 L-80 Buttress 9.875” Surf 2,961’ 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 7,093’ 7-5/8" Intermediate 29.7 P-110 BTC 6.75" 7,093’ 10,104’ 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 9,889’ 11,320’ TUBING 2-7/8” Production 6.4 L-80 8rd 2.441 Surf 9,800’ 2-3/8” Production 4.6 L-80 8rd 1.995 9,800’ 10,750’ 1 6 16” 10-3/4” 2 4 5 5” 7-5/8” 7 3 8 9 PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date H-1 10,807’ 10,815’ 10,600’ 10,607’ 8 6 2” HC 7/12/13 10,819’ 10,827’ 10,612’ 10,619’ 8 6 2” HC 7/12/13 H-2 10,830’ 10,836’ 10,623’ 10,628’ 6 6 2” HC 7/12/13 H-3 10,854’ 10,859’ 10,644’ 10,649’ 5’ 6 3-3/8” HC 3/19/13 10,859’ 10,880’ 10,649’ 10,669’ 21’ 6 3-3/8” HC 3/19/13 10,886’ 10,898’ 10,674’ 10,685’ 12’ 6 3-3/8” HC 3/19/13 H3 Sands H1 Sands H2 Sands X JEWELRY DETAIL No Depth ID OD Item 1 19’ 2.441” - 3-1/2” Tubing Hanger w/ XO to 2-7/8” 8RD 2 TBD 2.441” 4.688” GLM Design & Depth per OE 3 TBD 2.441” 4.688” GLM Design & Depth per OE 4 9,973’ 1.995” 3.670” 2-7/8” Box X 2-3/8” Pin XO 5 TBD 1.995” 3.750” GLM Design & Depth per OE 6 10,666’ 1.995” 3.750” 2-3/8” Chemical Injection Mandrel 7 10,684’ 1.995” 4.110” 5” DHL Hydraulic Retrievable Set Packer 8 10,726’ 1.875” 2.375” 2-3/8” X-Nipple 9 10,759’ 1.995” 3.060” 2-3/8” WL Re-Entry Guide Tag TOC @ 10,901’ WLM 10/5/16 7KHSLFWXUHFDQ WEHGLVSOD\HG7KHSLFWXUHFDQ WEHGLVSOD\HG7KHSLFWXUHFDQ WEHGLVSOD\HG7KHSLFWXUHFDQ WEHGLVSOD\HG ϭϯͲϱͬϴΗ ^ƉŚĞƌŝĐĂůŶŶƵůĂƌ ,ĞŝŐŚƚ͗ϰϲΗ tĞŝŐŚƚ͗ϭϮ͕ϴϬϲ ϭϯͲϱͬϴΗ DƵĚƌŽƐƐtͬϰͲ ϭͬϭϲΗŽƵƚůĞƚƐ ,ĞŝŐŚƚ͗Ϯϴ͘ϱΗ tŝĚƚŚϯϭΗ &Ƶůů DƵĚƌŽƐƐƐƐLJ͘ǁŝĚƚŚ ǁͬǀĂůǀĞƐŝŶƐƚĂůůĞĚ tĞŝŐŚƚ͗ ϮϮϬϬůďƐ͘ <ŝůůƐŝĚĞ ŚŽŬĞƐŝĚĞ ,ĞŝŐŚƚĚĚŝƚŝŽŶĨŽƌZŝŶŐ'ĂƐŬĞƚƐ͗ϬΗ KWdŽƚĂů ,ĞŝŐŚƚ͗ϭϭϭ͘ϱΗ KW dŽƚĂůǁĞŝŐŚƚ͗Ϯϰ͕ϵϬϲůďƐ͘ ϭϯͲϱͬϴΗϱŵKW WĂĐŬĂŐĞ tͬ4-1/16"ϱDsĂůǀĞƐ ϭϯͲϱͬϴΗ hŽƵďůĞKW ,ĞŝŐŚƚ͗ϱϱ͘ϴϳϱΗ tŝĚƚŚ͗ϭϳϭ͘ϱΗ tĞŝŐŚƚϭϰ͕ϴϬϬůďƐ͘ dKWZD^ ϮͲϯͬϴΗyϮͲϳͬϴΗyϯͲϭͬϮΗ DERON FLEX RAMS KddKDZD^>/ND ϰͲϭͬϭϲΗϱDDĂŶƵĂů'ĂƚĞ ǀĂůǀĞΘϰͲϭͬϭϲΗ,Z ^ŽŶŽƵƚƐŝĚĞϰͲϭͬϭϲΗy ϮͲϭͬϭϲΗϱŵ ƵĂůϰͲϭͬϭϲΗϱDDĂŶƵĂů 'ĂƚĞǀĂůǀĞƐ ^ŽŶŽƵƚƐŝĚĞϰͲϭͬϭϲΗ yϮͲϭͬϭϲΗϱŵ Swanson River SRU 14B-27 current 04/30/2024 Valve, Upper Master WKM-M, 3 1/8 5M FE, HWO, DD trim Valve, Swab, WKM-M, 3 1/8 5M FE, HWO, DD trim BHTA, Otis, 3 1/8 5M FE X 3'’ Bowen Quick Union Grade Level Swanson River SRU 14B-27 16 X 10 ¾ X 7 5/8 X 2 7/8 Tubing hanger, SME-CL, 11 X 3 ½ IBT lift and 3 ½ IBT susp, w/ 3'’ Type H BPV profile, 1- 3/8 CL ports, alloy material, 9 ¼ neck Valve, Master, WKM-M, 3 1/8 5M FE, HWO, DD trim Starting head, Seaboard, 16 ¾ 3M X 16'’ SOW, w/ 2- 2 1/16 5M EFO Multibowl Wellhead, SMB-22, 11 5M X 16 ¾ 3M, w/ 4- 2 1/16 5M SSO 16'’ 10 ¾’’ 7 5/8'’ 2 7/8'’ • • Carlisle, Samantha J (DOA) From: Schwartz, Guy L(DOA) Sent: Wednesday, February 22, 2017 9:14 AM To: Donna Ambruz Cc: Chad Helgeson;Joe Kaiser;Carlisle, Samantha J (DOA) Subject: RE: Sundry Cancellation - Sundry#315-685 SRU 14B-27 (PTD 212-089) Donna, Sundry#315-685 will be withdrawn as requested. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). From: Donna Ambruz [mailto:dambruz@hilcorp.com] Sent:Tuesday, February 21, 2017 3:09 PM To:Schwartz,Guy L(DOA)<guy.schwartz@alaska.gov> Cc:Chad Helgeson<chelgeson@hilcorp.com>;Joe Kaiser<jkaiser@hilcorp.com> Subject:Sundry Cancellation-Sundry#315-685 SRU 148-27 (PTD 212-089) Guy, Please withdraw the above mentioned sundry. Thank you. Danns thn&xcvz SCANNED 1Ar R d �4 201Z. Operations/Regulatory Tech Kenai Asset Team Hilcorp Alaska, LLC 3800 Centerpoint Drive,Suite 1400 Anchorage,AK 99503 907.777.8305-Direct 907.777.8310- Fax dambruz@hilcorp.com 1 RBD IS �c�[. 2 - 201 , STATE OF ALASKA AKA OIL AND GAS CONSERVATION CO SSION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon LJ Plug Perforations U Fracture Stimulate LJ Pull Tubing U Operations shutdown H Performed: Suspend ❑ . ' Pertorat€"Ef Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ 8rforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other:Pull ESP/GL CO Completion Q 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory ❑ 212-089 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic El Service ❑ 6.API Number: Anchorage,AK 99503 50-133-20604-00 7.Property Designation(Lease Number): 8.Well Name and Number: A028399;A028406 Swanson River Unit(SRU)14B-27 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Swanson River Field/Hemlock Oil 11.Present Well Condition Summary: RECEIVED Total Depth measured 11,322 feet Plugs measured NA feet true vertical 11,086 feet Junk measured NA feetNOV I, 4 2016 Effective Depth measured 11,200 feet Packer measured 10,684 fee4+h�(J(c C' true vertical 10,970 feet true vertical 10,485 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 3,001' 10-3/4" 2,961' 2,959' 3,580 psi 2,909 psi Intermediate 10,104' 7-5/8" 10,104' 9,940' 6,890 psi 4,790 psi Production Liner 1,431' 5" 11,320' 11,086' 8,290 psi 7,250 psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 2-7/8" 6.5#/L-80 10,642'MD 10,446'ND Tubing(size,grade,measured and true vertical depth) 2-3/8" 4.7#/L-80 10,759'MD 10,555'ND Packers and SSSV(type,measured and true vertical depth) 5"DLH Hyd Pkr 10,684'MD 10,485'ND N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): tlaj ? e, n.ft,i7, N/A1 6J �'d e 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: 55 199 217 840 170 Subsequent to operation: 50 868 328 1150 160 14.Attachments(required per 20 AAC 25.070,25.071,8 25.283) 15.Well Class after work: Daily Report of Well Operations CI Exploratory❑ Development Q Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil Q Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.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: 316-467 Contact Joe Kaiser-777-8393 Email jkaiser(u hiIcorp.com Printed Name 1-/#:"17/ Chad Helgeson Title Operations Manager Signature Phone 907-777-8405 Date )1/I(/1 (O Form 10-404 Revised 5/2015 //� `� RBDMS Vbmit Original Only i0i6 I. NOVNt101 1 6 2016 • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SRU 14B-27 Moncla 401 50-133-20604-00 212-089 10/2/16 10/10/16 Daily Operations: 10/02/2016-Sunday PJSM, mobe rig and equipment from SCU 41-08. Laid containment, spotted beam and WOR, raised derrick and secured guide lines. Set Koomey unit,gen unit, pump pit and ck manifold. Sealed containment and SDFN. 10/03/2016- Monday Held PJSM, discussed daily activities. Connected circulating lines for pump, pit and manifolds. RU gas buster and filled pits with PW. SICP 500psi, SITP 500psi. MU Kelly hose to cgs and tbg and bleed of pressure through in line choke. Pumped 250 bbls of PW down cgs and 20 bbls down tbg for well kill. Monitored well on vac. Set BPV and ND production tree.Verified and inspected lift. MU 3-1/2" blanking sub w/ left hand threads. Waited on 2' spacer spool to arrive. NU 11" BOP stacked configured with 11" Hydril, 2-3/8" pipe ram, 2-7/8"-5"VBR ram, blind ram, mud cross and 2" spacer spool. Connected Koomey lines and kill/choke lines to stack. Secured well and SDFN. 10/04/2016-Tuesday PJSM, discussed daily ops. RU floor handrails and stairwell. MIRU Summit equipment. Connected Koomey lines to BOP stack. RU gas detection and tested. MU 2-3/8" test Jt and fuctioned tested BOP's. Flooded manifold, lines and BOP stack and circulated through same. Performed shell test and had 2 connection leaks.Tightened connection and retested good. Performed BOPE test as following: gas detection,valves 250-3,000psi, rams 250-3,000psi, annular 250-3,000psi, Koomey drawdown. 2 FP recorded manual choke valve and blinds. AGOCC witnessed by Lou Grimaldi BO/LD test it and blanking sub. Pulled BPV. PU/MU 2-7/8" landing jt. Opened csg to pit and BOLDS. Pulled tbg hanger to rig floor. PU weight 72K. BO/LD tbg hanger and secured ESP cable and control lines. Set pipe in slips. Secured well and SDFN. 10/05/2016-Wednesday Held PJSM, discussed daily ops and warmed up equipment. Repositioned Summit spooler due to ESP cable wrapped around 1st stand.TOH with ESP completion, SOOH w/159 stands of 2-7/8" EUE spooling ESP cable and dual encapsulated control line. LD 3 GLM. Recovered all 1,131 3/4" SS bands used for completion. BO/LD ESP assembly, scale build-up on pump sections and intake. MIRU SL, tested lub. RIH w/3" DD bailer and tagged @ 10,901', worked bailer to 10,903'. POOH RDMO SL. 10/06/2016-Thursday Held PJSM, dicussed daily ops. Warmed up equipment. Performed well control drill with crew. Cleaned rig floor and BOP stack. Off loaded 33 jts of 2-3/8" EUE 4.7#8rd tbg from Rio Pad and tallied same.Tallied all jewerly for gaslift completion. Prep to run completion string. Loaded ESP equipment and reels on trailers. PU 26 jts of 2-3/8" EUE 4.7 8rd tbg and racked back 13 stands. PU/MU WL entry guide, 1 jt of 2-3/8" EUE#4.7 8rd, x nipple (1.875" ID), 1 jt of 2-3/8" EUE#4.7 8rd, 5" hydraulic packer, 2-3/8" GLM and chemical inj mandrel. MIRU Pollard spooling unit with 3/8" control line. Hooked control line and chem inj mandrel and pressure tested, good test. 2-3/8" 4.7# EUE 8rd tbg would not drift due to rust inside. TOH w/chemical injection mandrel, packer and GLM and racked back same. TIH with 13 stands and L/D same. Called Tubo and ordered 28 jts of 2-3/8" EUE 8rd from Hilcorps inventory. Tbg will be loaded out and on location in the morning. Secured well and SDFN. • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SRU 14B-27 Moncla 401 50-133-20604-00 212-089 10/2/16 10/10/16 Daily Operations: 10/07/2016- Friday PJSM, warmed up equipment. Tallied 30 jts of 2-3/8". Spotted Pollard spooler.TIH w/GL completion and 3/8" control line and testing every 10 stands, @ 6,000' pressure test failed on control line. TOH to OX sub and checked contol lines splice. No visible leaks were found and determined leak was coming from check valve in chem inj sub. Continued TIH w/GL completion and control line and stopped 3 jts before hanger depth. Dropped ball, MU Kelly hose,TIW to tbg and pressured up on tbg to 300psi. Pressured up on control line to 300psi and held to confirm control line was not leaking. Bled off pressure. RD Kelly hose and TIW. SO tbg and couldn't go down, PU 10K over and confirmed packer set premature (set presure 2,500psi). PU 30K over and sheared packer. TIH to hanger depth and capped contol line. SI BOP's and SDFN. 10/08/2016-Saturday PJSM, discussed daily ops. MIRU SL, PT and TIH w/2"JDC tagged prong at 10,700'. Latched and POOH w/prong. RDMO SL RU control line to spooler,TOH standing back completion string to chemical injection sub and pulled the live valve and installed dummy valve. Purge control line, PT to 5,000 psi,good test. PU new 5" FH packer, connected control line to chemical inj sub.TIH w/completion string and secured control line with 3/4" SS band to existing control line splice @ 2,000'. BO control line splice and secure with SS band. Slacked off tbg 15' and SI BOP's. Secured well SDFN. 10/09/2016-Sunday Held PJSM, start-up equipment. TIH w/GL completion to hanger depths as follows: WL entry guide @ 10,762', x nipple 1.875" ID @ 10,728', 5" hydraulic packer @ 10,678', 2-3/8" chemical inj mandrel @ 10,669', 2-3/8" GLM @10,653', XO 2- 3/8" box 2-7/8" pin @ 9,796', 2-7/8" GLM #2 @7,809', 2-7/8" GLM#3 @ 4,488'. PU/MU 9" tbg hanger and serviced same. PT control to 5,000psi,good test. MU 2-7/8" landing kt and landed hanger with 52K in string weight. RILDS. Dropped ball and rod, MU TIW and Kelly hose. Filled tbg with 33 bbls of PW and pressured up to 4,000psi and set packer. Tested tbg at 3,000psi, slow leakoff. MU Kelly hose to cgs. Opened tbg to pit and pumped 196 bbls down the csg and broke cir up tbg to gas buster. Continued cir 20 bbls to purge tbg. SI tbg and pressured up on csg to 2,500psi, charted 30mins, good test. Bled off csg and left open to the gas buster. Pressured up on tbg to 3,000psi and charted for 30mins. good test. Set BPV. RD floor and stairwell. Secured well and SDFN. 10/10/2016- Monday PJSM, discussed daily ops.Vac fluid out of BOP stack and pit. ND BOP's. NU production tree and tested 5K, good test. Pulled BPV. RDMO Moncla 401 and associated equipment. Mobe rig to 41-08. • Swanson River Unit HSCHEMATIC Well: SRU14B-27 PTD: 212-089 Hilcorp Alaska,LLCAPI: 50-133-20604-00 KB-THF: 15' CASING DETAIL 1 \ r" SizeType Wt Grade Conn. ID Top Btm 16" 16" Conductor—Driven to 109 X-56 - - Surf 80' Set Depth 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 2,961' 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 7,093' . 7-5/8" Intermediate 29.7 P-110 BTC 6.75" 7,093' 10,104' 5" Prod lnr 15 L-80 DWC/C HT 4.283" 9,889' 11,320' 10-3/4" TUBING , 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 9,800' /•.:a 2-3/8" Production 4.6 L-80 8rd 1.995 9,800' 10,750' JEWELRY DETAIL .0 No Depth ID OD Item 1 19' 2.441" - 3-1/2"Tubing Hanger w/X0 to 2-7/8"8RD 2 4,486' 2.441" 4.688" 2-7/8"SFO-1 GLM—IPOR-1 Valve-2240 psi;port sz 1661 3 7,806' 2.441" - 4.688" 2-7/8"SFO-1 GLM—IPOR-1 Valve-2170 psi;port sz 16 4 9,973' 1.995" 3.670" 2-7/8"Box X 2-3/8"Pin XO 2 fi 5 10,650' 1.995" 3.750" 2-3/8"GLMAX-1 GLM(T-1 latch)Orifice-1 Valve;port sz 22 #+ 6 10,666' 1.995" 3.750" 2-3/8"Chemical Injection Mandrel It; 7 10,684' 1.995" 4.110" 5"DHL Hydraulic Retrievable Set Packer ot 8 10,726' 1.875" 2.375" 2-3/8"X-Nipple 1 9 10,759' 1.995" 3.060" 2-3/8"WL Re-Entry Guide PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 3 I H-1 10,807' 10,815' 10,600' 10,607' 8 6 2"HC 7/12/13 10,819' 10,827' 10,612' 10,619' 8 6 2"HC 7/12/13 H-2 10,830' 10,836' 10,623' 10,628' 6 6 2"HC 7/12/13 4 10,854' 10,859' 10,644' 10,649' 5' 6 3-3/8"HC 3/19/13 • H-3 __ 10,859' 10,880' 10,649' _ 10,669' 21' 6 3-3/8"HC 3/19/13 10,886' 10,898' 10,674' 10,685' 12' 6 3-3/8"HC 3/19/13 1111 7-5/8", 5 6; o 7 e1siair 8 X 9, 3! H1 Sands = H2 Sands Tag TOC @ f 10,901'WLM '. s H3 Sands 10/5/16 TD=11,322'MD-11,086'TVD PBTD=11,200 MD—10,970'TVD Updated by DMA 11-10-16 • • yOF T4 Apt'I y7,"4 THE STATE Alaska Oil and Gas ►_ �► Of AsK A Conservation Commission -Anit: �� 333 West Seventh Avenue c GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 . ,! Main: 907.279.1433 OF ALAg*P' Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager Hilcorp Alaska, LLC ��� FEB 2 2� 3800 Centerpoint Drive, Suite 1400 ri Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SRU 14B-27 Permit to Drill Number: 212-089 Sundry Number: 316-467 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy . Foerster Chair DATED this i day of September, 2016. RBDMS ,L'SEP 1 9 2016 S 0 RECEIVED STATE OF ALASKA S F P 1 3 2016 ALASKA OIL AND GAS CONSERVATION COMMISSION ,7•-S "tf (S,�/‘ APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate 0 Repair Well 9 Operations shutdown 0 Suspend 9 Perforate 9 • Other Stimulate 9 Pull Tubing 9 • Change Approved Program 9 Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other.Pull ESP/GL CO Completion n . 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number Exploratory 9 Development 9 • 212-089 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number. Anchorage,Alaska 99503 50-133-20604-00 • 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 123B • Swanson River Unit(SRU)14B-27 . ❑ Will planned perforations require a spacing exception? Yes ❑ No 9 9.Property Designation(Lease Number): 10.Field/Pool(s): A028399,A028406 . Swanson River Field/Hemlock Oil • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD: Effective Depth ND: MPSP(psi): Plugs(MD): Junk(MD): 11,332' • 11,086' 11,200' 19,970' 1,386 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 3,001' 10-3/4" 2,961' 2,959' 3,580 psi 2,909 psi Intermediate 10,104' 7-5/8" 10,104' 9,940' 6,890 psi 4,790 psi Production Liner 1,431' 5" 11,320' 11,086' 8,290 psi 7,250 psi Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 2-7/8" 6.5#/L-80 9,912' Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): N/A;N/A N/A;N/A 12.Attachments: Proposal Summary 9 Wellbore schematic 9 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch © Exploratory ❑ Stratigraphic ❑ Development❑., Service 9 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: September 27,2016 OIL 9 . WINJ 0 WDSPL 0 Suspended 0 16.Verbal Approval: Date: GAS 9 WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown 9 Abandoned 9 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Joe Kaiser-777-8393 Email Lkaiser©hilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature ef•- Phone 907-777-8405 Date l /1 ' j I L, COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. Plug Integrity 9 BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: , 3 v°p^i. /3 be • i tiS,f— )4- C .Si - —zr ' /a,.5 a 1%S\1r Post Initial Injection MIT Req'd? Yes 0 No Spacing Exception Required? Yes 9 Nod Subsequent Form Required: I RBDMS 1/`" SEP 1 9 2016 APPROVED BY Approved by: Wet7"904.44/.....--' COMMISSIONER THE COMMISSION Date: 5 —i.S—74 1-1.5----/e.t SubmitForm and Form 10-403 Revised 11/2015 OpRvicGpic441 for 12 onths from the date of approval. Attachm is in Duplicate • Well Prognosis Well: SRU 14B-27 Hilcory Alaska,LL Date:9/13/2016 Well Name: SRU 14B-27 API Number: 50-133-20604-00 Current Status: Gas-lifted Oil Producer Leg: N/A Estimated Start Date: September 27th,2016 Rig: N/A - jtal Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 212-089 First Call Engineer: Joe Kaiser (907)777-8393 (0) (907)952-8897 (M) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907) 229-4824(M) AFE Number: Current Bottom Hole Pressure: —2,450 psi @ 10,640' TVD (Based on PBU 8/18/2016) a 4 e s- Maximum Expected BHP: —2,450 psi @ 10,640' ND (Based on PBU 8/18/2016) t° u Max. Potential Surface Pressure: — 1,386 psi (Based on 0.1 psi/ft gas gradient) Brief Well Summary This well was drilled with the Doyon Arctic Fox Rig December 2012 to January 2013. The original gas lift completion was installed with the Williams Rig#405 in March 2013.A capillary string was run into the well in June 2013.The capstring was pulled and perforations were added in the Hemlock H-1 and H-2 in July 2013. In • December 2013,the well was converted to an ESP completion with the Moncla#401 Rig. In October 2015 the ESP failed and the well was gas lifted via the ESP completion. Currently the well is producing at a reduced rate. • t-v �J c�/G�, ee l(prv�/z t... �L.� itc�t4 ;Q, The purpose of this sundry is to pull the ESP completion and run a gas lift recomoletion. • 7. "V"- Notes Regarding Wellbore Condition • Wellbore deviation at the perforations is approximately 21 degrees. Maximum deviation is 22 degrees. Work-Over Rig Procedure 1. MIRU Moncla#401 WO Rig.Set to work on 12-hr shifts. 2. Pump 250 bbls of PW(8.4 ppg)down the annulus and bleed the tubing to zero to kill the well. 3. Set BPV. ND Tree. 4. NU BOPE, pull BPV and set TWC. 5. Test BOPE to 250 psi Low/3,000 psi High,annular to 250 psi Low/2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform Test. Vie- b. Notify AOGCC 24 hrs in advance of BOP test. c. Notification to BLM is not required. d. Test VBR rams on 2-7/8"test joint. e. Test VBR rams on 2-3/8"test joint. f. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 6. L/D BOP test equipment, pull TWC. 7. Pump PW down tubing and casing to ensure well is dead. 8. Pull tubing hanger free,tubing and ESP. (Disconnect BIW Penetrator). S • Well Prognosis Well: SRU 14B-27 Hilcorp Alaska,LL Date:9/13/2016 9. Pull tubing string(2-7/8" 8RD and 2-3/8" 8RD)and rack back tubing. a. Inspect tubing for holes/worn joints. b. Laydown: i. Bad joints ii. GLMs iii. ESP 10. RU Slickline 11. RIH with Bailer,collect sample, POOH. RD Slickline 12. If fill cannot be removed with slickline, PU existing 2-3/8" and 2-7/8"tubing(add joints as required op for fill cleanout),and a clean out assembly(mill or mule shoe). RIH with cleanout assembly and reverse circulate wit to remove any fill. POOH. �� 13. If fill is removed: l WA-re a-- a. MIRU E-line, PT lubricator to 3,000 psi Hi and 250 psi Low. b. RU wireline guns. c. RIH and reperforate the following intervals: Zone Sands Top (MD) Btm (MD) FT Hemlock H-1 10,807' 10,815' 8 ' Hemlock H-1 10,819' 10,827' 8 ce 'I Hemlock H-2 10,830' 10,836' 6 • Hemlock H-3 10,854' 10,859' 5' • Hemlock H-3 10,859' 10,880' 21' • • Hemlock H-3 10,886' 10,898' 12' • i. Proposed perfs shown on the proposed schematic in red font. ii. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. iii. Correlate using Correlation Log provided by Reservior Engineer iv. Use Gamma/CCL/to correlate. v. Install Crystal gauges on well before perforating. Record tubing pressures before and after each perforating run. vi. All perforations in table above are located in the Hemlock Pool based on • Conservation Order No. 123B Rule 5. d. RD E-line. V, 14. PU 5"x 2-3/8" hydraulic packer and completion jewelry and RIH w/completion on 2-7/8" EUE 8rdTubing and 2-3/8"8rd EUE tubing. Use Stainless steel bands to secure 3/8"control line to completion. Minimize excess pipe dope when running completion. Completion jewelry per proposed schematic: a. WL entry guide b. X-nipple (RHCP plug body loaded) c. 5" Packer d. 2-3/8" Chemical Injection Mandrel (loaded with live valve) e. 2-3/8" GLMs(loaded with live valves) f. 2-3/8" x 2-7/8"Crossover g. 2-7/8" GLMs(loaded with live valves) 1110 • Well Prognosis Well: SRU 14B-27 Hilcoru Alaska,LL Date:9/13/2016 h. 3-1/2"x 2-7/8" Crossover i. 3-1/2"Tubing Hanger 15. Space out packer at^'10,735'and set packer a minimum of 5'from a collar. a. Leave tubing tail to land—50'above top of Hemlock H-1 (near^'10,750'). 16. Land tubing in hanger. Close the lockdown pins. 17. Drop ball and rod. Ensure rod seats into loaded X-Nipple. 18. Pressure up tubing to 3,000 psi and set packer hydraulic packer. 19. Test tubing at 3,000 psi for 30 min with chart. 20. Test casing to 2,500 psi for 30 min with chart .(If fluid is required to fill annulus, slowly pump 1-2 bpm to ensure the GL orifices do not get washed out.) .3` Cm 21. Set TWC, ND BOPE, NU tree and test. Pull TWC. 22. RD Moncla#401 WO Rig. 23. RU Slickline. 24. PT Lubricator to 2,500 psig Hi and 250 psig Low for 10 min. 25. RIH and pull RHCP ball and rod and plug from 2-3/8"X-nipple. RD Slickline. r 26. Return to production with new surface safety system as previously installed. (Test as per AOGCC regulations.) 27. Replace IA and OA pressure gauge if required. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. BOP Schematic 4. Proposed Wellhead Schematic 5. Blank RWO Procedure Change Form • • •II Swanson River Unit Well: SRU 148-27 ACTUAL SCHEMATIC Completion Ran: 12/04/2013 PTD: 212-089 API: 50-133-20604-00 Ilileorp tla"ka.IiA RKB:175.3'/GL:156.7'AMR KB—THF:18.6' CASING DETAIL 1 Size Type Wt Grade Conn. ID Top Btm 16" ", 2Conductor—Driven to 16" Set Depth 109 X-56 Surf 80' 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 2,961' 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 7,093' 7-5/8" Intermediate 29.7 P-110 BTC 6.75" 7,093' 10,104' 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 9,889' 11,320' 10-3/4"4:. , TUBING • 2-7/8" Production 6.5 L-80 EUE 8RD 2.441 Surf 9,721' - JEWELRY DETAIL 3 I-0 . No. Depth ID OD Item 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd 2 21.07' 2.441" 4.500" Crossover 3-1/2"8rd Pin x 2-7/8"8rd Pin 3 4,512' 2.441" 4.625" GLV#1—Valve 1 4 7,625' 2.441" 4.625" GLV#2—Valve P, �� 5 9,640' 2.441" 4.625" GLV#3—Valve w/orifice.308"ID '. ' 4 6 9,721' 4.000" Top of ESP,Discharge Head 1' 7 9,816' - 4.000" ESP Intake $ 8 9,834' 4.950" 5.500" ESP Shroud(31'of 5-1/2"15.5#Casing) 9 9,866' 5.520" Base of ESP,456 series Motor/400 series Pumps 9/30/2015) � 4 5l 0 .�c , rs , — -4- 2- - ',. 4 A�)) 6 PERFORATIONS moo of "ae' xi Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 7 H-1 10,807' 10,815' 10,600' 10,607' 8 6 2"HC 7/12/13 Failed 9/30/2015 . ,8 H-1 10,819' 10,827' 10,612' 10,619' 8 6 2"HC 7/12/13 9 H-2 10,830' 10,836' 10,623' 10,628' 6 6 2"HC 7/12/13 liftH-3 10,854' 10,859' 10,644' 10,649' 5' 6 3-3/8"HC 3/19/13 7-5/8"•&.) .4 H-3 10,859' 10,880' 10,649' 10,669' 21' 6 3-3/8"HC 3/19/13 h. SO H-3 10,886' 10,898' 10,674' 10,685' 12' 6 , 3-3/8"HC 3/19/13 r . H1 Sands 2216 H2 Sands H3 Sands Tt filt" ' Fq 5" r,r TD=11,332'MD-11,086'TVD P 8TD=11,200 MD—10,970'ND Downhole Revised: 12/04/2013 Updated by JEK 10/3/2015 • H . • Swanson River Unit PROPOSED SCHEMATIC Well: SRU 14B-27 PTD: 212-089 Hilcorp Alaska,LLC API: 50-133-20604-00 KB-THF: 18.6' CASING DETAIL 1 ' ! r L Size Type Wt Grade Conn. ID Top Btm ie el 16" Conductor-Driven to 109 X-56 Surf 80' Set Depth 10-3/4" Surf.Csg 45.5 _ L-80 Buttress 9.875" Surf 2,961' 41 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 7,093' 7-5/8" Intermediate 29.7 P-110 BTC 6.75" 7,093' 10,104' 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 9,889' 11,320' 10-3/4" TUBING 4;+ 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 9,800' 2-3/8" Production 4.6 L-80 8rd 1.995 9,800' 10,750' 114 14 JEWELRY DETAIL No Depth ID OD Item 1 �19' 2.441" - 3-1/2"Tubing Hanger w/X0 to 2-7/8"8RD • 2 -4,512' 2.441" 4.500" 2-7/8"SF0-1 GLM#9(Live Valve) 3 -7,818' 2.441" 4.500" 2-7/8"SFO-1 GLM#8(Live Valve) 2 4 "9,800' 1.995" 3.670" X0,2-7/8"8RD x 2-3/8"8RD 5 -10,675' 1.990" 3.350" 2-3/8"GLMAX-1 GLM#1(T-1 latch)(Orifice) 6 10,705 1.990" 3.350" Chemical Injection Mandrel(1/2"control line) 7 10,735' 2.680" 3.750" 5"x 2-3/8"Hydraulic Packer 8 10,745' 1.875" 3.050" X-Nipple 9 -10,750' 1.995" 3.050" WL Entry Guide 31 4\--,; PERFORATIONS 7-5/8" Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 44 5I® a H-1 10,807' 10,815' 10,600' 10,607' 8 6 2"HC 7/12/13 6, „, 1. H-1 10,819' 10,827' 10,612' 10,619' 8 6 2"HC 7/12/13 7 vm.,#, H-2 10,830' 10,836' 10,623' 10,628' 6 6 2"HC 7/12/13 11.°•' H-3 10,854' 10,859' 10,644' 10,649' 5' 6 3-3/8"HC 3/19/13 el 8 X H-3 10,859' 10,880' 10,649' 10,669' 21' 6 3-3/8"HC 3/19/13 H-3 10,886' 10,898' 10,674' 10,685' 12' 6 3-3/8"HC 3/19/13 9 0. ii i4 +,�' H1 Sands H2 Sands ".1,_. ;'3, eDDe__rzit cn Fre' L'c P_r:Sze MD "1\..'D `psc : nst'ucticcs 3 IPOR-1 2240 16 4512 4510 IPO 1" 2 IPOR-1 2170 16 7818 7800 " F. H3 Sands 1 ORIFICE-1 22 10700 10500 Orifice E s ii TD=11,332'MD-11,085'ND PBTD=11,200 MD-10,942'TVD Updated by JEK 9/9/2016 • • • Swanson River 2016 Moncla Rig#401 Knight Oil Tools BOP HFlrarp:11In4a,1.15 _- 1 ii di iii di iii iii 2.57' Shaffer 7 1/16 5000 La rim rilnr ill 1.111.11 1!1 PZIJ 2 3/8-3%variable "E i m CAMERON . �- inn 3.68' H `/( ) (t 10 "//, * .. ,. 111i - G' Blind H 71/16 5000 ( .AP H 41 h� =� - - ��� \ (iy / / Choke and Kill valves are 2 1/16 10M B rel 1119111.11'111'1: 1 1.56' yIII 16 5000 �_I i ' ! .]co1 f • • • Swanson River SRU 14B-27 o 1...,1• u...►.. i.i 09/09/2016 Swanson River Tubing hanger,SME-CL,11 X 3'2 SRU 14B-27 EUE lift and 31/2 EUE susp,w/3" 16 X 10 X X 7 5/8 X 2 7/8 Type H BPV profile,2-3/8 CCL ports,alloy material BHTA,Otis,3 1/8 5M FE X 3" Bowen Quick Union Iii......_ _ • Valve,Swab,WKM-M, o' �a,�zh�Q �a��h�.Q �a��e��,Qua 3 1/8 5M FE,HWO, DD trim ��( o 6--. vo \" 5� o ..1.1 ..,.., .1 * ..)• f i .* •1°Jo l � o Valve,Upper Master WKM-M,3 1/8 5M FE, rcil, ' HWO, DD trim ..a ..... . ...... Valve, Master,WKM-M, 3 1/8 5M FE,HWO,DD trim ��°(' MID, 11_MEW lalt " -b-1-1:W.:- � �— Grade Level 4-,•...0 9 .�» 1 ,,.,,,ii, IMP , . Multibowl Wellhead,SMB-22, ` �) 11 5M X 16 X 3M,w/ �„_„1 [ . 4-2 1/16 5M SSO i d= ' I —11 A �� i, Starting head,Seaboard, ; �� 16%3MX16"SOW,w/ 2-2 1/16 5M EFO ��_ _i :.A!,.. i: II1 li_ lc. 1116" 10X” 7 5/8" 2 7/8" • III � . o a) > � 2 o a 0 rts c 2 E 0 o ° w a/ < E \ E c -a � k Q / �/ (1) _ CL c \< ±.- k / 0 ! m > 73 2 amf ia g• 7 § \ n � ■ o & ._ 2 k k $ § Go->- co co ZW N / Q @ 0 - B0 \ a o > � 2 \ k m k U , OC /� U a ti C a) % O & 7 /§ J %< .c E § \ a) 0 c o .§ & 0 t 0 \ ka. c a) c ±% § a) § / / 2 . co en a $ p 2 LU ■ _ > 2 ■ @ § 2 % § o 0. kt Q < @ > o * o § 2 • co 0 _� ® 2 I- e co k 0 0 \ ) 0 b 3 x % £ cx it v .. 7 O -6/ 0& cco O 2 a. 2 k < <c Z1 0 U) V OF •7 • • cvi, %% cv THE STATE Alaska Oil and Gas H��►' —a�, of LASKA Conservation Commission _ y= 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 1110t71:4,- �+mr OFL *4 Q Main: 907.279.1433 gA8Y+ Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson SCANNED JAN 1 3 2016 Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 a Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SRU 14B-27 Sundry Number: 315-685 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy . Foerster Chair 14— DATED this /2 day of November, 2015 Encl. ' RBDAIISq �,,;ar "� 11015 0 • RECEIVED STATE OF ALASKA NOV 0 4 201' ALASKA OIL AND GAS CONSERVATION COMMISSION d')1S «lead'j APPLICATION FOR SUNDRY APPROVALS 'qr, 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Annular Flow_L 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q 212-089 ' 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-133-20604-00 ' 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 123B Swanson River Unit(SRU)14B-27 Will planned perforations require a spacing exception? Yes ❑ No ❑✓ - 9. Property Designation(Lease Number): 10. Field/Pool(s): A028399,A028406 Swanson River Field/Hemlock Oil " 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 11,332 ' 11,086 ' 11,200 19,970 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 3,001' 10-3/4" 2,961' 2,959' 3,580 psi 2,909 psi Intermediate 10,104' 7-5/8" 10,104' 9,940' 6,890 psi 4,790 psi Production Liner 1,431' 5" 11,320' 11,086' 8,290 psi 7,250 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 2-7/8" 6.54/L-80 9,912' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A;N/A N/A;N/A 12.Attachments: Proposal Summary ❑ Wellbore schematic ❑ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic 0 Development n Service ❑ 14. Estimated Date for 15.Well Status after proposed work: November 18,2015 Commencing Operations: OIL ❑., WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Chad Helgeson Email chelgesonQhilcorp.com Printed Name Chad Helgeson Title Operations Manager (7i47/ ..-4 A Signature 7(47 r..-4;444-- Phone 907-777-8405 Date if/07— COMMISSION USE ONLY / Conditions of approval: Notify Commission so that a representative may witness Sundry Number. 316 - t12 S Plug Integrity ❑ BOP Test 0 Mechanical Integrity Test ❑ Location Clearance ❑ t Other: ^ z ,z OGS C,e1) Post Initial Injection MIT Req'd? Yes ❑ No ❑ `� q e Spacing Exception Required? Yes ❑ No 0 Subsequent Form Required: J© " `ID L1 RBDMS I,��oNtiv 1 3 2015 APPROVED BY Approved by: P �e,--$14*---- COMMISSIONER THE COMMISSION Date: U_/2_ /5— /� n I � SubminForm and Form 10-403 evis�d 11/2015• U �i!_ipr p i s slid for 12 months from the date of approval. Attachments in Duplicate yz� (7./015- //?:,-- 4..,./ /,,,/,,,c-- .. /,,G/;ic-- • • Hilcorp Alaska, LLC Post Office Box 244027 RECEIVED Anchorage,AK 99524-4027 RECEIVED 3800 Centerpoint Drive NOV 0 4 2015 Suite 1400 Anchorage,AK 99503 A®GCCPhone: 907/777-8405 fit,,// Fax: 907/777-8510 November 4, 2015 Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501-3539 Re: Swanson River SRU 14B-27 (PTD 212-089) Request for Annular Flow Dear Commissioner: Hilcorp Alaska is requesting approval for annular flow for well Swanson River Unit SRU 14B-27 (PTD 212-089). This well was drilled in January 2013 and completed in March 2013. The well was recompleted with an ESP in December 2013 (Sundry # 313- 499) with dummied gas lift valves for when the ESP failed it could still be produced. The ESP failed in September 2015 with what appears to be a seized motor. The well is currently producing at 30 bbls of oil per day with gas lift down the backside and fluids up the tubing. The gas lift pressure (1,050 psi surface pressure) without a packer is limiting the inflow from the formation. The request to reverse gas lift this completion will allow for the tubing to hold gas lift pressure and regulate the flow of gas lift into the production stream, lowering the bottom hole pressure on the formation and allowing more inflow from the formation and increasing production. / This well was drilled in 2013 where the casing was pressure tested to 3,000 psi on V January 19th, 2013 when the liner was set and again on March 20th, 2013 when the original completion was run. The well has been on gas lift or ESP flowing this entire time. The gas lift has no CO2 in it and gas lift gas has less than 2 ppm of H2S. When the ESP was installed on the well, a SSV was installed on the casing valve to isolate the well. Attached is a P&ID sketch of the piping and descriptions of the SVS. The flowing casing pressure will be between 150-240 psi and is expected to flow at rates of 500-700 bbls of total fluid production (80% water cut) and an estimated 1-2 mmscfd of formation gas mixed with gas lift gas. This well has no history of making sand during production of the ESP and there is very little downhole scaling or well corrosion on wells in Swanson River. The well and fluids from this well will be monitored for sand production and abnormal flow conditions, which could impact the integrity of the casing or casing valve. The approval of annular flow on this well will help identify if this well can be recompleted with a conventional gas lift completion or if optimal flow is achieved with Alaska Oil and Gas Conservation Commission November 4,2015 Page 2 the ESP. If additional information is needed, please do not hesitate asking Chad Helgeson(777-8405) or Joe Kaiser(777-8393). Sincerely, HILCORP ALASKA, LLC ,i#74_. Chad Helgeson Operations Manager CAH:JEK:dma Attachments: 10-403 Form Actual Schematic SRU 14B-27 Annular Flow Information P&ID H . • Swanson River Unit • Well: SRU 14B-27 ACTUAL SCHEMATIC Completion Ran: 12/04/2013 PTD: 212-089 Hilcoru Alaska,LLC API: 50433-20604-00 RKB:175.3'/GL:156.7'AMSL KB—THF:18.6' CASING DETAIL 1l Size Type _ Wt Grade Conn. ID Top Btm 16"zi #2 L� Conductor—Driven to 16" Set Depth 109 X-56 Surf 80' 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 2,961' 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 7,093' 7-5/8" Intermediate 29.7 P-110 BTC 6.75" 7,093' 10,104' 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 9,889' 11,320' 10-3/4'h ?,'ll,( TUBING 2-7/8" Production 6.5 L-80 EUE 8RD 2.441 Surf 9,721' JEWELRY DETAIL 3I Ii No. Depth ID OD Item 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd 2 21.07' 2.441" 4.500" Crossover 3-1/2"8rd Pin x 2-7/8"8rd Pin 3 4,512' 2.441" 4.625" GLV#1—Dummy 4 7,625' 2.441" 4.625" GLV#2—Dummy <, 5 _ 9,640' 2.441" 4.625" GLV#3—Dummy 4 I—U+l 6 9,721' - 4.000" Top of ESP,Discharge Head 7 9,816' - 4.000" ESP Intake 8 9,834' 4.950" 5.500" ESP Shroud(31'of 5-1/2"15.5#Casing) 9 9,866' 5.520" Base of ESP,456 series Motor/400 series Pumps(Failed 9/30/2015) 5 -p 6 PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date r .r �. 7 H-1 10,807' 10,815' 10,600' 10,607' 8 6 2"HC 7/12/13 Failed 9/30/2015 !!! -, -: ' 8 H-1 _ 10,819' 10,827' 10,612' 10,619' 8 6 2"HC 7/12/13 H-2 10,830' 10,836' 10,623' 10,628' 6 6 2"HC 7/12/13 H-3 10,854' 10,859' 10,644' 10,649' 5' 6 3-3/8"HC 3/19/13 7 5/8' �' H-3 10,859' 10,880' 10,649' 10,669' 21' 6 3-3/8"HC 3/19/13 04 H-3 10,886' 10,898' 10,674' 10,685' 12' 6 3-3/8"HC 3/19/13 i 1 \vl G, MFS \ 4e' Ko' V 1 1 ,141 4 44 H1 Sands "A t H2 Sands 64 • H3 Sands st if 1 1 41. 5x< TD=11,332'MD-11,086'ND PBTD=11,200 MD—10,970'ND Downhole Revised: 12/04/2013 Updated by JEK 09/30/2015 • • SRU 14B-27 Annular Flow Information SSV Settings: The SSVs for SRU 14B-27 are located on the tubing and casing. They are operationally sensed from the same Hi/Low Pilot. Both SSVs will stay in operation during the annulus flow configuration however the SSV on the tubing side of the well head will be blocked in by the wing valve to direct lift gas down the tubing.The FCV and manual block valve on the flowline will remain open to the pilot to sense pressure from the flowline.The Hi/Low pilot is set to 900psig/90psig respectively and remain in operation.The SSV on the downstream side of the annulus will be in operation. Artifical Lift: The aritifical lift line to the well can be manually isolated on the pad in several locations as required per 20 AAC 25.265(e). From the well head upstream we have a check valve, choke valve, isolation valve near the wellhead, a manual isolation valve near pad edge, and additionally another valve at the gas lift supply in the piping corridor. All piping is rated for 3,000 psig. • • . B Calculation Record !PREPAlicDj-fBY u CHECKED BY DATE PAGE SUBJECT W.O.A,P. .NO. /18 -2 ,?MNULA1 Fou) 1 6 ;;;.._.e� ..� '._.._r... • I... - • • i . `•....•. ..i... ! .... ! i .. I... i • i 1 , ; 1 I i . I ! ! 1 .I i !• , I. I I 1 1 • . ! • r '_ !!• _) •!_; . i. •_ _..!. ) .I .j •' + 1 • ( I • J•-... ' I i 1 li t I I . I 1 I I I 1 1 . ! i I • : • -I ---. 0, !: I '.... I . . .Maps I . i-.—I--...{..- ; r—-I .'_. L . -_ - . 1 i i �_ 1 i I ��� r t.. i ! j i I 1 1 ) I i t f ). 1 i. , • 0 i 1 I I . . • 6 ._,,._ •.., 40 . • - ' VAC. i t, Nt•;:;.. , • I --"—i 4/it4 r1• r ! s N cNora . 1 j 1 i ! ; NoTE; i i ifaO i i i • r —r•—" 1 ..1 I • . .i• 8vP 4 1, ! j I I J I I �! , • I ' I >' . • I A 1 i• '• j I 1 ! 1 �.V I ;._. ..1.. . .,.. ""'';'---4.-- 14-13...2,-1 . qtr _ 1 .. :_. � 1 • I i + I I '�'•- J24,0. . . ri, ",--,..46.45 ; . . / . 061 . ..._... `-:. '�...-... -. ) pNvr .1..� _GHQ 5C 1.f.I...V F - I -• ` ; . ._ . 5 � • .. .__-•. _ ...._.-_ i... I (A'Pl-::h1 V._1\69(':' ! : I iI =ORI.I I.2C58(REV.2.87)PHINTE0 IN U.S.A. Peninsula Printing 2625267 1 I • • Schwartz, Guy L (DOA) From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Tuesday, November 10, 2015 8:58 AM To: Schwartz, Guy L(DOA) Cc: Joe Kaiser Subject: RE: SRU 14B-27 annular flow(PTD 212-089) Good question, I should have put that in my request. Fortunately when the pump failed we still had the pressure gauge downhole collecting pressure data, so have a pretty good SIBHP. It leveled out at about 1,823 psi and then the head from pump gauge to the perforations is about 384 psi, (assuming water),for a bottom hole pressure of 2,171 psi. Let me know if you need anything else. E Chad IPPS' r,r . From: Schwartz, Guy L(DOA) [mailto:guy.schwartz©alaska.gov] Sent: Monday, November 09, 2015 5:39 PM To: Chad Helgeson w`<< Subject: SRU 14B-27 annular flow (PTD 212-089) - G' Chad, What is the latest estimate of the BHP for this well for the TVD of 10600ft. ?? Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guv.schwartz@alaska.gov). 1 0 _M 9O O N 2 as" Oo Q Q r.oO .. .�` .T. O) o Z c •.— 'u) E N O r) 0 a)caci o :: r m 0 w 0 N aai cn co cn p N N N a) T N . 1.5U C c m a) o_ o .0- - a - Z rn p U a) s Q d J J O w y U O .T. 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C C U . a m E a 8 O E 2 E a) (I) E 1 E d a O Ua 0 U 1 C) RECEIVED STATE OF ALASKA AL .A OIL AND GAS CONSERVATION COMM ,ION UE' 2 7 REPORT OF SUNDRY WELL OPERATIONS AOGC;C 1.Operations Abandon U Repair Well U Plug Perforations U Perforate U Other U Convert to ESP Performed: Alter Casing ❑ Pull Tubing❑, Stimulate-Frac El Waiver ❑ Time Extension El Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development ❑., Exploratory ❑ •• 212-089 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 r 50-133-20604-00 7.Property Designation(Lease Number): 8.Well Name and Number: A028399;A028406• Swanson River Unit(SRU)14B-27 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Swanson River Field/Hemlock Oil 11.Present Well Condition Summary: Total Depth measured ) 11,322 feet Plugs measured NA feet true vertical 11,086 feet Junk measured NA feet Effective Depth measured • 11,200 feet Packer measured 9,868 feet true vertical 10,970 feet true vertical 9,720 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 3,001' 10-3/4" 2,961' 2,959' 3,580 psi 2,909 psi Intermediate 10,104' 7-5/8" 10,104' 9,940' 6,890 psi 4,790 psi Production Liner 1,431' 5" 11,320' 11,086' 8,290 psi 7,250 psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 2-7/8" 6.5*/L-80 9,912'MD 9,761'ND Packers and SSSV(type,measured and true vertical depth) AS-1X Ret Prod Pkr 9,868'MD 9,720'ND N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A RBDMS MAY 16 2014 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 163 64 347 1540 250 - Subsequent to operation: 157 209 427 400 392 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory❑ DevelopmentIll • Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil •isi Gas ❑ WDSPL El GSTOR El WINJ ❑ WAG ❑ GINJ ❑ SUSP El SPLUG El 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 313-499 Contact Stan Porhola Email soorholac hilcorD.com Printed Name Stan Porhola Title Operations Engineer /2--7713 Signature �� �1= Phone 907-777-8412 Date I� Z 773 7/` S' A 'Y Form 10-404 Revised 10/2012 /A f407 Submit Original Only Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 14B-27 50-133-20604-00 212-089 11/26/13 12/5/13 Daily Operations: 11/26/2013-Tuesday RU Baker, Pull Cap String. RDMO Baker Hughes,Turn Well Back Over to Production. 11/27/2013-Wednesday Moved Equipment. Mobilized and Rigged up Moncla#405 Rig. Continue with Winterization Setup. 11/28/2013-Thursday Close in well, Pump 50 gal Xylene down flowline. Block off well. RU PWL. Worked on test pump,tested lubricator,L 250,H 1500. RIH,pull GLV from 9,850',RD PWL. Tbg 1,200 psi,blow down to 0 psi. Pump 50 bbl H2O down tbg. Set BPV. Csg 1,000 psi. Blow down to 0. ND Tree,NU BOPE. 11/29/2013-Friday Begin BOPE test. Test annular. Pipe rams not holding-was going to pull test jt,found BPV leaking-ck psi 1,500 on tbg,ck csg 1,000 psi. Backed out test jt a little to let off psi. Pumped 60 Bbls,changed out BPV,resume BOPE test. *Note-BPV had small piece of rubber lodged in it,Pull BPV,pumped 65 Bbls,run TWC,test blinds, pull TWC. Complete BOP test. (Witness waived by Jim Regg,AOGCC) Close well in,SDFN. 11/30/2013-Saturday Ck tbg on vacuum,csg 100 psi. Blow csg down. Pump 35 bbls field water. Waiting on approval from Moncla to work in sub- zero temperatures. Crew continued winterization of rig. Close well in,SDFN. 12/01/2013-Sunday Winterize Rig. Pull hanger,release packer,equalized weight-right-hand 1/4 turn to release. POOH,lay down packer. Close well in,SDFN. 12/02/2013-Monday RU Schlumberger. Start picking up ESP. Work on HYD and Electric on spooler. Redo control line on ESP. Pick up ESP. SIH with TBG. 6a.m. have bottom GLM picked up. 12/03/2013-Tuesday Cont.in hole. Test electric cable and control line. Cont.in hole,pick up GLM. Splice cable for ESP. Cont.in Hole. Start splicing cable on ESP. 12/04/2013-Wednesday Cont.Splicing ESP cable. Landing HGR._ND BO_ PE,NU TREE. Test well head close well in for night. No activity. 12/05/2013-Thursday RD Rig,move some of rig equipment to SRU 32C-15,some to SCU 12A-03. Turn well over to Production. e Swanson River Unit Well: SRU 14B-27 • ACTUAL SCHEMATIC Completion Ran: 12/04/2013 PTD: 212-089 flacon)Alaska,LLCAPI: 50-133-20604-00 RKB:175.3'/GI:156.7'AMSL KB—THF:18.6' CASING DETAIL 1 Size Type Wt Grade Conn. ID Top Btm 16' 2 Conductor—Driven to �+ 16" 109 X-56 - - Surf80' Set Depth 30-3/4" Surf.Csg 4221W199505...9:75 5.5 L-80 Buttress 9.875" Surf 2,961' �,+ 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 7,093' 7-5/8" Intermediate 29.7 P-110 BTC 6.75" 7,093' 10,104' + 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 9,889' 11,320' 10-3/4" TUBING ,, 2-7/8" Production 6.5 L-80 EUE 8RD 2.441 Surf 9,721' ,w, 1. i4JEWELRY DETAIL 3 11 No. Depth ID OD Item 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd 02 21.07' 2.441" 4.500" Crossover 3-1/2"8rd Pin x 2-7/8"8rd Pin • 3 4,512' 2.441" 4.625" GLV#1—Dummy 4 7,625' 2.441" 4.625" GLV#2—Dummy 5 9,640' 2.441" 4.625" GLV#3—Dummy 4 6 9,721' - 4.000" Top of ESP,Discharge Head 7 9,816' - 4.000" ESP Intake 8 9,834' 4.950" 5.500" ESP Shroud(31'of 5-1/2"15.5#Casing) 9 9,866' - 5.520" Base of ESP,456 series Motor/400 series Pumps 5 • I 6 PERFORATIONS • Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 7 H-1 10,807' 10,815' 10,600' 10,607' 8 6 2"HC _ 7/12/13 ' ' . 8 H-1 10,819' 10,827' 10,612' 10,619' 8 6 2"HC 7/12/13 91 H-2 10,830' 10,836' 10,623' 10,628' 6 6 2"HC 7/12/13 H-3 10,854' 10,859' 10,644' 10,649' 5' 6 3-3/8"HC 3/19/13 7-5/8'L'E 7711ti H-3 10,859' 10,880' 10,649' 10,669' 21' 6 3-3/8"HC 3/19/13 '�' H-3 10,886' 10,898' 10,674' 10,685' 12' 6 3-3/8"HC 3/19/13 r 1 f • 1 T.,. H1 Sands H2 Sands H3 Sands 5"'C1-' ''. 3 TD=11,332'MD-11,086'ND PBTD=11,200 MD—10,970'TVD Downhole Revised: 12/04/2013 Updated by STP 12/12/2013 Schwartz, Guy L (DOA) From: Schwartz,Guy L(DOA) Sent: Tuesday, November 26, 2013 12:56 PM To: 'Stan Porhola' Subject: RE: Change of BOPE for SRU 14B-27 ESP Conversion (PTD Pn] 2 (Z - 081 Thanks Stan, Will update the well folder with correct BOP size. Please be sure to have the current wellhead diagram and ratings included in the sundry application... that is normally a requirement. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office From: Stan Porhola [mailto:sporholaru hilco .com] Sent: Tuesday, November 26, 2013 9:28 AM To: Schwartz, Guy L(DOA) Cc: Wallace, Chris D (DOA); Regg, James B(DOA) Subject: Change of BOPE for SRU 14B-27 ESP Conversion (PTD Guy, We need to make the following change on the approved sundry(313-499)for the well SRU 14B-27(PTD 212-089): 1.) Change the BOPE from 7-1/16"to 11" (the well has an 11"wellhead, not a 7"wellhead,which was submitted in error). Attached is the proper 11" BOPE diagram. Regards, Stan Porhola j Oper.itiun' Engineer er North Kenai Asset 'Team Hilcorp Alaska, LLC 011irt,: (907) 777-8,1-1_' MoIn1e: (`)07) 1 ' ll Swanson River Moncla#405 BOP oaf-gm ‘ia.�.a.I.1.0 11/01/2013 ;g & 14-0 -Z-7 0_ 12_-0 87 01011111111.1 3.98' o Hydril o GK 11"-5000 ar lit iii lit (fill! - til L .161 C� =illl= 4.54' - . - I - 2 7/8 -5 variables 11"-5000 nu. °� Il ,�„ H Blind HIII. til 111 Villi 111 21/16 5M Choke and Kill 4111 Valves t • . 1 I!1IIIIIIIII111g _ - i II 2.00 ! ',I411 F■ I, l } - i iii III tit III i (- - I • hw\�oF //7:" THE STATE Alaska Oil and Gas � � °f Conservation Commission . ALASKA GOVERNOR SEAN PARNELL 333 West Seventh Avenue F' Anchorage, Alaska 99501-3572 -AL A$ Main: 907.279.1433 Fax: 907.276.7542 Stan Porhola Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 14B-27 Sundry Number: 313-499 Dear Mr. Porhola: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P. oerster Chair, Commissioner DATED this 6-7- day of September, 2013. Encl. RECEIVED STATE OF ALASKA SEP 1 201 3 ALASKA OIL AND GAS CONSERVATION COMMISSION „ APPLICATION FOR SUNDRY APPROVALS AOG +'C 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redril ❑ Perforate New Pod ❑ Repair Well❑ Change Approved Program❑ Suspend❑ Plug Perforations ❑ Perforate❑ Pull Tubing❑✓ • Time Extension❑ Operations Shutdown❑ Re-enter Susp.Wel ❑ Stimulate❑ After Casing❑ Other. Convert to ESP❑✓ - 2.Operator Name. 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC Exploratory ❑ Development Q • 212-089 • 3 Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic ❑ Service 111 6 API Number Anchorage,Alaska 99503 50-133-20604-00 • 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 123B Swenson River Unit(SRU)14B-27 - Will planned perforations require a spacing exception? Yes ❑ No ❑✓ 9.Property Designation(Lease Number): 10.Field/Pool(s): A028399,A028406 Swanson River Field/Hemlock Oil • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 11,332 ' 11,086 11,200 10,970 N/A N/A Casing Length Size MD ND Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 3,001' 10-3/4" 2,961' 2,959' 3,580 psi 2,909 psi Intermediate 10,104' 7-5/8" 10,104' 9.940' 6,890 psi 4,790 psi Production - Liner 1,431' 5" 11,320' 11,086' 8,290 psi 7,250 psi Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 2-7/8" 6.5#1 L-80 9,912 Packers and SSSV Type: Packers and SSSV MD(t)and ND(ft): AS1-X Ret Prod Packer; N/A 9,868'MD/9,720'ND;N/A 12.Attachments: Description Summary of Proposal Q X13 Well Class after proposed work: • Detailed Operations Program n BOP Sketch n •Exploratory n Stratigraphirn Development 171 Service n 14.Estimated Date for 15.Well Status after proposed work: 10/15/13 Commencing Operations. Oil Q • Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval. Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned El Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhda Email sDorhola( hiIcorD.cor>1 Printed Name Stan Porhola Title Operations Engineer �7 / Signature 'w✓-�`Tt Phone 907-777-8412 Date �/ // � 3 COMMISSION USE ONLY GG ((( Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Ct q Plug Integrity ❑ BOP Test [Ø Mechanical Integrity Test ❑ Location Clearance El RBDME OCT 1 0 20tYt. Other: ,f- 3Oc to S:. 3 oto 7;31- I., n ` / yamS 44 p., 1r0124.4-,e-A-0'1 Y.- Aft:. F/auJ + eS � -.- k Spacing Exception Required? Yes ❑ No [.1 Subsequent Form Required: /0—4/ 11 Wzi4 / APPROVED 9_�¢'/3 M Y Approved by: +/ COMMISSIONER THE COMMISSIONa� 4Date: t E&lff*AnEfromt ` fapp SubmnFopaneForrn 10-403 Revised 10/2012) Approved a a date of approval. vim 7070 //Attachments in Duplicate Well Prognosis Well: SRU 14B-27 Hilc°`u Alaska,LLQ Date:9/17/2013 Well Name: SRU 14B-27 API Number: 50-133-20604-00 Current Status: Gaslifted Oil Producer Leg: N/A Estimated Start Date: October 15th, 2013 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 212-089 First Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228(M) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907) 229-4824(M) AFE Number: Current Bottom Hole Pressure: —2,800 psi @ 10,600' TVD Based on reservoir modeling of known nearby reservoir pressures Maximum Expected BHP: —2,800 psi @ 10,600' ND Based on reservoir modeling of known nearby reservoir pressures Max. Allowable Surface Pressure: —0 psi (Based on actual reservoir conditions and min water cut of 50% (0.385psi/ft) will balance reservoir pressure at 3,327 ft. ND. Brief Well Summary This well was drilled with the Doyon Arctic Fox in December 2012 to January 2013. The completion was completed with the Williams Rig#405 in March 2013.A capillary string was run into the well in June 2013.The capstring was pulled and perforations were added in the Hemlock H-1 and H-2 in July 2013. Notes Regarding Wellbore Condition • The well has a capillary string installed to spot chemicals to handle emulsion issues • Wellbore deviation at the perforations is approximately 21 degrees. Maximum deviation is 22 degrees. OBJECTIVE OF WORKOVER Pull capillary string. Convert well to ESP. Remove Capillary String procedure: 1. MIRU Cap String Truck, PT lubricator to 2,000 psi Hi 250 Low. 2. Pull and recover 3/8" capillary string currently at 9,900'. ,/ a. Plan to re-use on another well. 3. Rig down Cap String Truck. 4. Turn well over to production. Work-Over Rig Procedure 5. MIRU Moncla#405 pulling unit. 6. MIRU slickline, PT lubricator to 1,500 psi Hi 250 Low 7. RIH and pull lower gaslift valve. POOH. RD slickline. , - Well Prognosis Well: SRU 14B-27 Hilcoru Alaska,LL Date:9/17/2013 8. RU and pump+/-50 bbl Produced Water down tubing to clean pipe. Bleed casing pressure. 9. Set TWC in tubing hanger, ND tree, NU 7-1/16" BOPE and test to 250psi low/3,000psi high, annular to 250psi low/1,500psi high (hold each valve and test for 10-min). Record accumulator pre-charge pressures. a. Notify AOGCC 24hrs in advance to witness test. b. Notify BLM 48 hrs in advance of BOP test. c. Crew will be working 12hr shifts and well will be secured nightly with TIW valves and BOPE. 10. Release test pressure, pull TWC and install handling sub in hanger. 11. Back out tbg hanger hold down pins and pick up on hanger. 12. RU to pull tubing hanger and unseat Arrowset AS1-X packer at 9,868' (right-hand release)and SOOH with 2-7/8" EUE 8RD production tubing from 9,912'.Jar tubing hanger and packer loose if necessary. 13. SOOH w/all tubing. d. Keep 3 GLM to re-run with ESP completion. e. Send Packer and On/Off Tool to Tripoint for redress. 14. RIH with ESP with existing 2-7/8" 8rd EUE L-80 tubing. f. Test control lines to 2,500 psi. g. RU Pollard to use SS bands on tubing(ensure adequate banding material). h. Set 3 re-run GLMs at+/-9,560',+/-7,500', and+/-4,500'. i. Run ESP cable around Minor OD of the GLMs(will not fit across Major OD). 15. Set base of ESP at+/-9,860' (Pump intake around +/-9,770'). Land tubing hanger. 16. Set BPV, ND BOPS, NU Tree,test tree to 3,000 psi. j. Note: Rated pressure of BIW penetrator(wellhead to cable connection) is 3,000 psi. 17. RDMO workover rig and equipment. 18. Turn well over to production. 19. Notify AOGCC to conduct a no flow test on the well after it has flowed for 5 days at a stable production. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOP Schematic Swanson River Unit ,. Well: SRU 14B-27 II ACTUAL SCHEMATIC Completion Ran:3/20/2013 PTD: 212-089 llilcorp Alaska,LLC API: 50-133-20604-00 KB-THF: 18.6' CASING DETAIL J 1 �I, Size Type Wt Grade Conn. ID Top Btm ,41 16"!J 2 `a m 16" Set Depth 109 X-56 Surf 80' a10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 2,961' �' � 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 7,093' 1 try, 7-5/8" Intermediate 29.7 P-110 BTC 6.75" 7,093' - 10,104' +., 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 9,889' 11,320' 10-3/4" 5 ': TUBING Vx 2-7/8" Production 6.5 L-80 8rd 2.441 Surf 9,912' y4' .„ 3 Ila 1 ? JEWELRY DETAIL 'l I P No. Depth ID OD Item 4 a i' 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd 1 t° 2 22.83' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box 3 4,391' 2.441" 4.625" GLV#8-12 Orifice t 5 >♦II i ,4 4 5,927' 2.441" 4.625" GLV#7-Dummy r 5 6,885' 2.441" 4.625" GLV#6—12 Orifice ,.: 6 7,600' 2,441" 4.625" GLV#5—Dummy 6 aa. ' ¢ 7 8,253' 2.441" 4.625" GLV#4-Dummy °A ` 8 8,783' 2.441" 4.625" GLV#3—12 Orifice a 1% ', 7 9 9,318' 2.441" 4.625" GLV#2-Dummy I II} ,A; 10 9,850' 2.441" 4.625" GLV#1-12 Orifice 11 9,866' 2.313" 6.250" T-2 On/Off tool with X-Profile 8 !■ k 12 9,868' 2.500" 6.672" AS1-X Ret Prod Packer 1 +4 13 9,906' 2.313" 3.230" X-Nipple .S 9 • 14 9,912' 2.500" 3.690" Wireline Re-Entry Guide ., ii r" 10 ■a i IPERFORATIONS ,• ii '04'4, Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date x H-1 10,807' 10,815' 10,600' 10,607' 8 6 2"HC 7/12/13 12 k I Jf'I ,i • H-1 10,819' 10,827' 10,612' 10,619' 8 6 2"HC 7/12/13 : i i : .'{ • H-2 10,830' 10,836' 10,623' 10,628' 6 6 2"HC 7/12/13 • H-3 10,854' 10,859' 10,644' 10,649' 5' 6 3-3/8"HC 3/19/13 7-5/8" ',,' H-3 10,859' 10,880' 10,649' 10,669' 21' 6 3-3/8"HC 3/19/13 13 H-3 10,886' 10,898' 10,674' 10,685' 12' 6 3-3/8"HC 3/19/13 14 It' 6 11, 0 ;•"i Capillary String Installed 7/29/2013 ,' } 3/8" 2205 Stainless Steel(10,000'spool) *), tii Top Bottom MD 0' 9,900' TVD 0' 9,750' 44 H1 Sands 1!+ H2 Sands '. 1» e H3 Sands 41, lio TD=11,332'MD-11,086'ND PBTD=11,200 MD—10,970'ND Downhole Revised:7/29/2013 Updated by STP 7/29/2013 Swanson River Unit .. Well: SRU 146-27 II PROPOSED SC H E MATI C Proposed Completion PTD: 212-089 tiilcorp Alaska,LLC API: 50-133-20604-00 KB-THF: 18.6' CASING DETAIL 1 y Size Type Wt ' Grade Conn. ID Top Btm 16" 2 mit '� Conductor-Driven to 16" Set Depth 109 X-56 - - Surf 80' 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 2,961' • • ii 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 7,093' 7-5/8" Intermediate 29.7 P-110 BTC 6.75" 7,093' 10,104' 1w 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 9,889' 11,320' 10-3/4" N«' TUBING 2-7/8" Production 6.5 L-80 EUE 8RD 2.441 Surf 9,860' r 1 io JEWELRY DETAIL 3 Ili ' ell No. Depth ID OD Item 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd I 2 22.83' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box !, 3 4,500' 2.441" 4.625" GLV#3-Dummy Lt 4 7,500' 2.441" 4.625" GLV#2-Dummy '; N; 5 9,560' 2.441" 4.625" GLV#1-Dummy •• 4 ill +C- 6 9,860' - 4.560" ESP,456 series Motors/400 series Pumps y N' r 0 '� r 5 � i 1 PERFORATIONS , Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date A H-1 10,807' 10,815' 10,600' 10,607' 8 6 2"HC 7/12/13 94 ! V H-1 10,819' 10,827' 10,612' 10,619' 8 6 2"HC 7/12/13 6 H-2 10,830' 10,836' 10,623' 10,628' 6 6 2"HC 7/12/13 H-3 10,854' 10,859' 10,644' 10,649' 5' 6 3-3/8"HC 3/19/13 7-5/8" ` H-3 10,859' 10,880' 10,649' 10,669' 21' 6 3-3/8"HC 3/19/13 V S 1 H-3 10,886' 10,898' 10,674' 10,685' 12' 6 3-3/8"HC 3/19/13 '1 `M ita4 (a *�gl .4 41 ilt.t 4�1 1tl 6�i ;11 4k H1 Sands 14 .LINII : H2 Sands SW H3 Sands c 4,t a s tiC_3r TD=11,332'MD-11,086'ND PBTD=11,200 MD-10,970'TVD Downhole Proposed Updated by STP 9/17/2013 . ... II Swanson River 2013 Moncla Rig#405 Knight Oil Tools BOP Ililrnrp:‘InMku.1.1.t. f`u' 1 0 0 iii (1i iii iii lii iii iii I 1 2.57' 10 Shaffer 71/16 5000 , iti_firt inifniftin IDRURDRUTO / / \ __l 2 3/8-3%2 variable / g I CAMERON I 3.68' H I H CII `... I Blind H I 71/16 5000 I I h N :. I � � I 1 i Onfillnint l Choke and Kill valves are illifltjAputiT --„,_. 2 1/16 10M -0 1.56' i g (t* ' (Or-44 1 0 �'ti •� F�` 71/16 5000 n RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION JUL 3 1 2013 REPORT OF SUNDRY WELL OPERATIONS AO GCC 1.Operations Abandon Repair Well L Plug Perforations U Perforate U Other U Pull&Rerun Cap String Performed: Alter Casing ❑ Pull Tubing❑ Stimulate-Frac E Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC • Development ❑., i Exploratory ❑ 212-089 • 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99504 50-133-20604-00.GO • 7.Property Designation(Lease Number): 8.Well Name and Number: A028399;A028406 Swanson River Unit(SRU)14B-27 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Swanson River Field/Hemlock Oil • 11.Present Well Condition Summary: Total Depth measured 11,322 feet • Plugs measured NA feet true vertical 11,086 feet Junk measured NA feet Effective Depth measured 11,200 feet Packer measured 9,868 feet true vertical 10,970 feet true vertical 9,720 feet Casing Length Size MD ND Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 2,961' 10-3/4" 2,961' 2,959' 5,210 psi 2,470 psi Intermediate 10,104' 7-5/8" 10,104' 9,941' 6,890 psi 4,790 psi Production Liner 1,431' 5" 11,320' 11,084' 8,290 psi 7,250 psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 2-7/8" 6.5#/L-80 9,912'MD 9,761'ND Packers and SSSV(type,measured and true vertical depth) AS-1X Ret Prod Pkr 9,868'MD 9,720'ND N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure. N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 190 125 286 1300 240 Subsequent to operation: 224 0 311 1460 300 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory❑ Development Q • Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil Q• Gas ❑ WDSPL❑ GSTOR ❑ WINJ El WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 313-360 Contact Stan Porhola Email sporholaahilcorp.com Printed Name Stan Porhola Title Operations Engineer P 9 Signature _ -,i Phone 907-777-8412 Date -7/3 /3 P.«.1? 4%01 9 - 911V SVCER4 Form 10-404 Revised 10/2012 ,0%40 Submit Original Only Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 14B-27 50-133-20604-00 212-089 7/12/13 7/29/13 (Daily Operations: 07/12/2013-Friday MIRU Priority E-line Unit. Final rig up before RIH. RIH w/6'of 2-1/8"RTG and correlate on depth w/GR/CCL. Tie into CBL dated 3/19/13. SITP=360 psi. Perforate from 10,830'-10,836'. No change in SITP. POOH. All shots fired. RIH w/14'of 2- 1/8"RTG and correlate on depth w/GR/CCL. Tie into CBL dated 3/19/13. SITP=525 psi. Perforate from 10,807'-10,815'and 10,819'-10,827'. No change in SITP. POOH. All shots fired. Close swab valve. Bleed off pressure on lubricator. Rig down E- line. Demobe Priority E-line Unit. 07/29/2013-Monday Rig Up Cap String Truck. Rig up lubricator and adapter. Test to 3,000 psi. RIH w/3/8"capillary string. Set capillary string @ 9,900'. RDMO Cap String Truck. • Swanson River Unit II Well: SRU 14B-27 ACTUAL SCHEMATIC Completion Ran:3/20/2013 PTD: 212-089 Hilcorp Alaska,LLC API: SO-133-20604-00 KB-THF: 18.6' CASING DETAIL ;'t 1 Size Type Wt Grade Conn. ID Top Btm 16' 2 �� 16„ Conductor—Driven to 109 X-56 Surf 80' Set Depth 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 2,961' 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 7,093' 7-5/8" Intermediate 29.7 P-110 BTC 6.75" 7,093' 10,104' 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 9,889' 11,320' 10-3/4" is TUBING li 2-7/8" Production 6.5 L-80 8rd 2.441 Surf 9,912' LA g 1,1 p 3 in 1 JEWELRY DETAIL 4 111 No. Depth ID OD Item 4 li Ir1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd f 2 22.83' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box re. 4 3 4,391' 2.441" 4.625" GLV#8-12 Orifice S 4 5,927' 2.441" 4.625" GLV#7-Dummy 5 6,885' 2.441" 4.625" GLV#6—12 Orifice 410 6 7,600' 2,441" 4.625" GLV#5—Dumm 6 7 8,253' 2.441" 4.625" GLV#4-Dummy V 8 8,783' 2.441" 4.625" GLV#3—12 Orifice :1 7 It■ , 1 9 9,318' 2.441" 4.625" GLV#2-Dummy I I 10 9,850' 2.441" 4.625" GLV#1-12 Orifice 11 9,866' 2.313" 6.250" T-2 On/Off tool with X-Profile '�� 8 #is i 't 12 9,868' 2.500" 6.672" AS1-X Ret Prod Packer II13 9,906' t 2.313" 3.230" X-Nipple "'Y 9 Ili 14 9,912' 2.500" 3.690" Wireline Re-Entry Guide .' 1I 10 Ifs r% PERFORATIONS 'e. ii Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 1'444.,, H-1 10,807' 10,815' . 10,600' 10,607' 8 6 2"HC 7/12/13 12 al I I I H-1 10,819' 10,827' 10,612' 10,619' 8 6 2"HC 7/12/1,, 3 I g H-2 10,830' 10,836' 10,623' 10,628' 6 6 2"HC t 11) pi H 3 10,854' 10,859' 10,644' 10,649' 5' 6 3-3/8"HC 7/12/13 3/19/13 7-5/8" i'. , H-3 10,859' 10,880' 10,649' 10,669' 21' 6 3-3/8"HC 3/19/13 13 2 +a. H-3 10,886' 10,898' 10,674' 10,685' 12' 6 3-3/8"HC 3/19/13 14 kl" II 4r 4A V Capillary String Installed 7/29/2013 i ?! 3/8" 2205 Stainless Steel(10,000'spool) 41 11 Top Bottom > MD 0' 9,900' TVD 0' 9,750' H1 Sands H2 Sands ' H3 Sands / ._ y'1 It r 1t 5 4 TD=11,332'MD-11,086'ND PBTD=11,200 MD—10,970'ND Downhole Revised:7/29/2013 Updated by STP 7/29/2013 • w rr I%%y s THE STATE Alaska Oil and Gas f , ,;anservat1on Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue O,,, �� Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 Stan Porhola Operations Engineer Hilcorp Alaska, LLC q/ 3800 Centerpoint Drive �-� Anchorage, AK 99503 �' Re: Swanson River Field, Hemlock Oil Pool, Swanson River Unit 14B-27 Sundry Number: 313-360 Dear Mr. Porhola: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy %. Foerster Chair DATED this IZday of July, 2013. Encl. 1 • ,tiP�� RECEIVED • STATE OF ALASKA JUL 0 9 2013 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redril ❑ Perforate New Pod ❑ Repair Well❑ Change Approved Program❑ Suspend❑ Plug Perforations ❑ Perforate❑✓ v Pull Tubing❑ Time Extension❑ Operations Shutdown❑ Re-enter Susp.Wel ❑ Stimulate ❑ Alter Casing❑ Other. Pull and Re-run Cap String❑✓ 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number Exploratory ❑ Development ❑✓ , 212-089 • 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic ❑ Service II6.API Number Anchorage,Alaska 99503 50-133-20604-00. 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 123A . Will planned perforations require a spacing exception? Yes ❑ No Q Swanson River Unit(SRU)148 27 9.Property Designation(Lease Number): 10.Field/Pool(s): A028399,A028406 Swanson River Field/Hemlock Oil 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 11,332' 11,086 11,200 10,970 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 3,001' 10-3/4" 2,961' 2,959' 3,580 psi 2,909 psi Intermediate 10,104' 7-5/8" 10,104' 9,940' 6,890 psi 4,790 psi Production Liner 1,431' 5" 11,320' 11,086' 8,290 psi 7,250 psi Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 2-7/8" 6.5#/L-80 9,917 Packers and SSSV Type: Packers and SSSV MD(t)and ND(ft): AS1-X Ret Prod Packer; N/A 9,868'MD/9,720'ND;N/A 12.Attachments: Description Summary of Proposal J 13.Well Class after proposed work: Detailed Operations Program n BOP Sketch n Exploratory n Stratigraphicn Development n Service n 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 07/12/13 Oil 0 Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhda Email soorhola( hilcorD.com Printed Name Stan Porhola Title Operations Engineer Signature (4 "-` �'v 2-•'c_ Phone 907-777-8412 Date –77o c( /Z COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: J 2 o 1 ` Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test El Location Clearance Other: RBDMS JUL 13 20 Spacing Exception Required? Yes ❑ Noli Subsequent Form Required: /0 —qO Lf APPROVED BY Approved by: P/ei.lp 7 `t' ,__., COMMISSIONER THE COMMISSION Date: 7 /2._ -/3 n RIIIaG I A ` ? aiForrn 10-403(Revised 10/2012) Appr a /TGA[1R`mont from the date of approve. �riachments in Duplicate / .` ,1 Well Prognosis Well: SRU 14B-27 Hilcorp Alaska,LL, Date:7/09/2013 Well Name: SRU 14B-27 API Number: 50-133-20604-00 Current Status: Gaslifted Oil Producer Leg: N/A Estimated Start Date: July 12th, 2013 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 212-089 First Call Engineer: Stan Porhola (907)777-8412 (0) (907) 331-8228 (M) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907) 229-4824(M) AFE Number: Current Bottom Hole Pressure: —2,800 psi @ 10,600' TVD Based on reservoir modeling of known nearby reservoir pressures Maximum Expected BHP: —2,800 psi @ 10,600' ND Based on reservoir modeling of known nearby reservoir pressures Max.Allowable Surface Pressure: —0 psi (Based on actual reservoir conditions and min water cut of 50% (0.385psi/ft) will balance reservoir pressure at 3,327 ft. TVD. Brief Well Summary This well was drilled with the Doyon Arctic Fox in December 2012 to January 2013. The completion was completed with the Williams Rig#405 in March 2013.A capillary string was run into the well in June 2013. Notes Regarding Wellbore Condition • The well has a capillary string installed to spot chemicals to handle emulsion issues • Wellbore deviation at the perforations is approximately 21 degrees. Maximum deviation is 22 degrees. OBJECTIVE OF WORKOVER Remove the existing capillary string. Add new perfs in the Hemlock and TyonelS,G (flow test between to allocate production). Re-run capillary string to deeper depth. Remove Capillary String procedure: 1. MIRU Cap String Truck, PT lubricator to 2,000 psi Hi 250 Low. . 2. Pull and recover 3/8" capillary string currently at 7,582'. . a. Plan to re-use on another well. 3. Rig down Cap String Truck. • 4. Turn well over to production. E-line procedure: 5. MIRU E-line, PT lubricator to 2,000 psi Hi 250 Low. II Well Prognosis Well: SRU 14B-27 ffilcorp Alaska,LL Date:7/09/2013 6. RU 2.0" 6 spf HC wireline guns. 7. RIH and perforate H-2 interval from 10,830'-10,836'. \) 8. RIH and perforate H-1 interval from 10,807'-10,815' and 10,819'-10,827 . a. Proposed perfs shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. 9. RD E-line. 10. Turn well over to production. 11. Flow well to test seperator for 3-5 days before adding Tyonek G perfs. 12. MIRU E-line, PT lubricator to 2,000 psi Hi 250 Low. 13. RU 2.0" 6 spf HC wireline guns. 14. RIH and perforate G-2 interval from 10,762'-10,803'.) 15. RIH and perforate G-2 interval from 10,732'-10,756'./ ' a. Proposed perfs shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. 16. RD E-line. 17. Turn well over to production. 18. Flow well to test seperator for 3-5 days before adding capillary string. Re-run Capillary String procedure: 19. MIRU Cap String Truck, PT lubricator to 2,000 psi Hi 250 Low. 20. PU 3/8"capillary string. RIH and set at+/-9,950'. 21. Set spool of remaining line near well. 22. Rig down Cap String Truck. 23. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic • • Swanson River Unit Well: SRU 14B-27 ACTUAL SCHEMATIC Actual Completion:3/20/2013 PTD: 212-089 Hilcorp Alaska,LLC API: 50-133-20604-00 KB-THF: 18.6' CASING DETAIL 1 Size Type Wt Grade Conn. ID Top Bt m 16' IA L 2 Conductor—Driven to 16" Set Depth 109 X-56 Surf 80' iu .4 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 2,961' 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 7,093' ii 7-5/8" Intermediate 29.7 P-110 BTC 6.75" 7,093' 10,104' 4 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 9,889' 11,320' 10-3/4" 5) r' TUBING 2-7/8" Production 6.5 L-80 8rd 2.441 Surf 9,912' 3 IR 1 Capillary String Installed 06/03/13 (Unable to run deeper) ir II 0t°4:,1 3/8" 2205 Stainless Steel Top Bottom 4 i' MD 0' 7,582' lio TVD 0' 7,574' kv 5 MI i ," JEWELRY DETAIL olA No. Depth ID OD Item 'F 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd i^ 6 r+ 2 22.83' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box 'i11 t« 3 4,391' 2.441" 4.625" GLV#8 12 Orifice 7 I V 4 5,927' 2.441" 4.625" GLV#7-Dummy 5 6,885' 2.441" 4.625" GLV#6—12 Orifice 6 7,600' 2,441" 4.625" GLV#5—Dummy 8 7 8,253' 2.441" 4.625" GLV#4-Dummy I l 8 8,783' 2.441" 4.625" GLV#3—12 Orifice 9 VP ; r 9 9,318' 2.441" 4.625" GLV#2-Dummy II El. 10 9,850' 2.441" 4.625" GLV#1-12 Orifice g 10 11 9,866' 2.313" 6.250" T-2 On/Off tool with X-Profile 12 9,868' 2.500" 6.672" AS-1X Ret Prod Packer kif 11 13 9,906' 2.313" 3.230" X-Nipple 14 9,912' 2.500" 3.690" Wireline Re-Entry Guide 12 .; I I I , I + PERFORATIONS 7-5/$13 ' 0 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date i H-3 10,854' ' 10,859' • 10,644' 10,649' 5' 6 3-3/8"HC 3/19/13 Voi 14 vi H-3 10,859' • 10,880' • 10,649' 10,669' 21' 6 3-3/8"HC 3/19/13 H-3 10,886' ' 10,898' - 10,674' 10,685' 12' 6 3-3/8"HC 3/19/13 lerrI v bt t ii 1$ 0 I asp H3 Sands I 5 ' TD=11,332'MD-11,086'ND PBTD=11,200 MD—10,970'ND Downhole Revised:6/03/2013 Updated by STP 7/09/2013 • . . Swanson River Unit • WePTDll:: 21SRU2-089 14B-27 PROPOSED SCHEMATIC Proposed Completion Hilcorp Alaska,LLC API: 50-133-20604-00 KB-THF: 18.6' CASING DETAIL °I 1 Size Type Wt Grade Conn. ID Top Btm 16" 2 Conductor—Driven to 16" Set Depth 109 X-56 Surf 80' t" 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 2,961' '' 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 7,093' 7-5/8" Intermediate 29.7 P-110 BTC 6.75" 7,093' 10,104' M4 q. 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 9,889' 11,320' 10-3/4" it TUBING ** to 2-7/8" Production 6.5 L-80 8rd 2.441 Surf 9,912' LL 3 MD 1 4 JEWELRY DETAIL INo. Depth ID OD Item ! 4 p 1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd �"t 2 22.83' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box ►a Isd 3 4,391' 2.441" 4.625" GLV#8-12 Orifice 5 i 4 5,927' 2.441" 4.625" GLV#7-Dummy 5 6,885' 2.441" 4.625" GLV#6—12 Orifice 6 7,600' 2,441" 4.625" GLV#5—Dummy ion 6 i r, 7 8,253' 2.441" 4.625" GLV#4-Dummy Iat' 8 8,783' 2.441" 4.625" GLV#3—12 Orifice qk 7 9 9,318' 2.441" 4.625" GLV#2-Dummy 10 9,850' 2.441" 4.625" GLV#1-12 Orifice 11 9,866' 2.313" 6.250" T-2 On/Off tool with X-Profile 4 8 i 12 9,868' 2.500" 6.672" AS1-X Ret Prod Packer .41 I 13 9,906' 2.313" 3.230" X-Nipple 9 P 14 9,912' 2.500" 3.690" Wireline Re-Entry Guide tv 10 III 1PERFORATIONS '* 11 ' Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments _ Date G-2 10,732' • 10,756'. 10,529' 10,553' 24 6 2"HC Proposed ✓ 12 I I G-2 10,762' " 10,803' 10,559' 10,597' 41 6 2"HC Proposed H-1 10,807' • 10,815' • 10,600' 10,607' 8 6 2"HC Proposed IH-1 10,819' 10,827' • 10,612' 10,619' 8 6 2"HC Proposed 7-5/8" 4 H-2 10,830' . 10,836'• 10,623' 10,628' 6 6 2"HC Proposed 13 T H-3 10,854' 10,859' 10,644' 10,649' 5' 6 3-3/8"HC 3/19/13 4. i H-3 10,859' 10,880' 10,649' 10,669' 21' 6 3-3/8"HC 3/19/13 14 10,886' 10,898' 10,674' 10,685' 12' 6 3-3/8"HC 3/19/13 1%'r 1C-14------------ Capillary String Proposed to Pull and Re-run after perforating ' 3/8" 2205 Stainless Steel a� Top Bottom N1D 0' 9,950' ! 1 G2 Sands N , TVD 0' 9,797' 44. ill) J H1 Sands / H2 Sands 01 MF- H3 Sands ""ry tft 5" t TD=11,332'MD-11,086'ND PBTD=11,200 MD—10,970'ND Proposed Downhole Updated by STP 7/09/2013 LLdECEIVED STATE OF ALASKA ° ALAonA OIL AND GAS CONSERVATION COMMS--ION JUL 0 8 2013 REPORT OF SUNDRY WELL OPERATIONS AOGCC 1.Operations Abandon Li Repair Well LI Plug Perforations 11 Perforate U Other U Install Cap String Performed: Alter Casing ❑ Pull Tubing❑ Stimulate-Frac ❑ Waiver ❑ Time Extension El Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name. Hilcorp Alaska,LLC • Development ❑Q Exploratory ❑ 212-089 . 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99504 50-133-20604-00 ' 7.Property Designation(Lease Number): 8.Well Name and Number: A028399;A028406 Swanson River Unit(SRU)14B-27 • 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Swanson River Field/Hemlock Oil • 11.Present Well Condition Summary: Total Depth measured 11,322 feet • Plugs measured NA feet true vertical 11,086 feet Junk measured NA feet Effective Depth measured 11,200 feet Packer measured 9,868 feet true vertical 10,942 feet true vertical 9,720 feet Casing Length Size MD ND Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 2,961' 10-3/4" 2,961' 2,959' 5,210 psi 2,470 psi Intermediate 10,104' 7-5/8" 10,104' 9,941' 6,890 psi 4,790 psi Production Liner 1,431' 5" 11,320' 11,084' 8,290 psi 7,250 psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 2-7/8" 6.4#/L-80 9,912'MD 9,761'ND Packers and SSSV(type,measured and true vertical depth) AS-1X Ret Prod Pkr 9,868'MD 9,720'ND N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 166 717 459 1700 300 Subsequent to operation: 190 125 286 1300 240 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory❑ Development Q ' Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil Q. 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: N/A Contact Stan Porhola Email soorholaahilcorp.com Printed Name Stan Porhola Title Operations Engineer � Signature . -" a[/n -4 . Phone 907-777-8412 Date -7/0S// i 3 7•z 1./3 RBDMS JUL[[[ 12 201& Form 10-404 Revised 10/2012 Submit Original Only • . II Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 14B-27 50-133-20604-00 212-089 6/3/13 6/3/13 Daily Operations: 06/03/2013-Monday Rig Up Cap String Truck.Rig up lubricator and adapter.Test to 3,000 psi.RIH w/3/8"capillary string.Attempt to work passed unknown obstruction(likely gaslift mandrel,no joy).Set capillary string @ 7,582'.RDMO Cap String Truck. Swanson River Unit • Well: SRU 14B-27 II ACTUAL SCHEMATIC Actual Completion:3/20/2013 PTD: 212-089 Illilcurp Alaska, LLCAPI: 50-133-20604-00 KB-THF: 18.6' CASING DETAIL a ;, 1 ' L Size Type Wt Grade Conn. ID Top Btm 16" 2 �� „ Conductor—Driven to 16109 X-56 Surf 80' r r 1 Set Depth 41 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 2,961' "� 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 7,093' t 7-5/8" Intermediate 29.7 P-110 BTC 6.75" _ 7,093' 10,104' 1 ri`.K, 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 9,889' 11,320' 10-3/4" x^ TUBING >0i 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 9,912' ¶1 3 Illt I 1Capillary String Installed 06/03/13 (Unable to run deeper) k 3/8" 2205 Stainless Steel Top Bottom 4 Mt i 1414 MD 0' 7,582' r TVD 0' 7,574' 1IA , 5 MI 1 h JEWELRY DETAIL 41 No. Depth ID OD Item M. - ,: 1 _ 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd 6 2 22.83' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box i� .t' t 1 i 3 4,391' 2.441" 4.625" GLV#8-12 Orifice ,A 7 "r 4 _ 5,927' 2.441" 4.625" GLV#7-Dummy IMF i ". 5 6,885' 2.441" 4.625" GLV#6—12 Orifice zik6 7,600' 2,441" 4.625" GLV#5—Dummy 8 l 7 8,253' 2.441" 4.625" GLV#4-Dummy !' 8 8,783' 2.441" 4.625" GLV#3—12 Orifice 'P 9 A 9 9,318' 2.441" 4.625" GLV#2-Dummy 10 9,850' 2.441" 4.625" GLV#1-12 Orifice ,�_. 10 ! 11 9,866' 2.313" 6.250" T-2 On/Off tool with X-Profile M 12 9,868' 2.500" 6.672" AS-1X Ret Prod Packer '. 11 ,. " +r, 13 9,906' 2.313" 3.230" X-Nipple 14 9,912' 2.500" 3.690" Wireline Re-Entry Guide 12 iI 1..1 2,, I r 2 - • i 75/$„` ,:17 PERFORATIONS 13 " +� Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date P...-- '3' H-3 10,854' 10,859' 10,644' 10,649' 5' 6 3-3/8”HC 3/19/13 14 H-3 10,859' 10,880' 10,649' 10,669' 21' 6 3-3/8"HC 3/19/13 H-3 10,886' 10,898' 10,674' 10,685' 12' 6 3-3/8"HC 3/19/13 rig i2 14 ;11 iy j 3"1 4 .„.„ e H3 Sands *, ;1 11,. k% YA 11 5"l 1 r., TD=11,332'MD-11,085'ND PBTD=11,200 MD—10,942'ND Downhole Revised:6/03/2013 Updated by STP 7/08/2013 .don Ellison Hilcorp Alaska, L. �� - i` l GeoTech II 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 ,, r,,., Tele: 907 777-8339 l 4t E D ALtAk.:,.LTA. Fax: 907 777-8510 E-mail: lellison@hilcorp.com AiN 2 0 2013 AOGCC 06/20/2013 \ To: AOGCC Makana Bender 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL SRU 14B-27 Prints (LWD/MWD logs) GR MEM LOG MD 5in GR MEM LOG ND 5in GR MEM LOG MD 2in GR MEM LOG TVD 2in CD: MWD/LWD log data GR MEM LOGs 5 and 2in, MD's and TVD's PDF, TXT, LAS Please include current contact information if different from above. Please acknowl receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: ( Date: STATE OF ALASKA ALA—A OIL AND GAS CONSERVATION COMIo„,,SION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1 a.Well Status: Oil 0 , Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ lb.Well Class: 20AAC 25.105 20 AC 25110 Development 0 • Exploratory ❑ GINJ ❑ WINJ ❑ WAG ❑ WDSPL ❑ No.of Completions: Service ❑ Stratigraphic Test ❑ 2.Operator Name: 5. Date Comp.,Susgbor 12. Permit to Drill Number: Hilcorp Alaska, LLC Aband.: 3/ 2013 212-089 • 3.Address. 6. Date Spudded: 1t 13.API Number: 3800 Centerpoint Drive,Anchorage,AK 99501 12/5/2012 50-133-20604-00 4a. Location of Well(Governmental Section): 7.Date TD Reached: 14.W511 Name and Number: �� s-, .; Surface: 758'FNL,635'FEL,Sec 33,T8N, R9W,SM,AK ' 1/15/2013 -Seldetna-Cseok-Unit(SRU)14B-27 Top of Productive Horizon: 8.KB(ft above MSL): 179 " 15.Field/Pool(s): 214'FSL, 144'FWL,Sec 27,T8N, R9W,SM,AK GL(ft above MSL): 164 • Total Depth: 9 Plug Back Depth(MD+TVD): Swanson River Field/Hemlock Oil • 363'FSL,261'FWL,Sec 27,T8N, R9W,SM,AK . 11,200'MD/10,970'TVD• 4b. Location of Well(State Base Plane Coordinates,NAD 27): 10.Total Depth(MD+TVD): 16. Property Designation: Surface: x- 347047 • y- 2465683 • Zone- 4 • 11,322'MD/11,086'TVD • " A028399,A028406 • TPI: x- 347837.16 y- 2466653.64 Zone- 11.SSSV Depth(MD+TVD): 17. Land Use Permit: Total Depth: x- 347955.97 .y- 2466801.36 Zone- N/A N/A 18. Directional Survey: Yes ❑ No ❑ 19.Water Depth, if Offshore: 20.Thickness of Permafrost MD/TVD: (Submit electronic and printed information per 20 AAC 25.050) N/A (ft MSL) N/A 21. Logs Obtained(List all logs here and submit electronic and printed information per 20AAC25.071): 22.Re-drill/Lateral Top Window MD/TVD: See attached Log Summary N/A 23. CASING,LINER AND CEMENTING RECORD WT.PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 16" 109 X-56 Surf. 80' Surf. 80' 10-3/4" 54.5 L-80 Surf. 2,961' Surf. 2,959' 13-1/2" • 1,127 sx 7-5/8" 29.7 L-80 Surf. 7,093' Surf. 7,091" 9-7/8" • 14- 1,309 sx 7-5/8" 29.7 P-110 7,093' 10,104' / 7,091' 9,941' F�7/ " • s +3 5" 15 L-80 9,889' 11,320' 9,740' 11,084' 6-3/4" 332 sx 24.Open to production or injection? Yes 0 No ❑ 25. TUBING RECORD If Yes, list each interval open(MD+TVD of Top and Bottom; Perforation SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Size and Number): 2-7/8" 9,912'(MD) 9,868'(MD)/9,720'(TVD) 10,854'-10,859'(MD)/10,644'- 10,649'(TVD)-3-3/8"perf./6spf 10,859'-10,880'(MD)/ 10'649'- 10,669'(TVD)-3-3/8"perf./6sp 26. ACID, FRACTURE,CEMENT SQUEEZE, ETC. 1E0,898'(MD)/ 10,674'-10,685'(TVD)-3-3/8"perf./6sp Was hydraulic fracturing used during completion? Yes❑ No 0 Efibli DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED � RECEIVED —•-- ED, i APR 222013 27. w- AOGCC PRODUCTION TEST iDate First Production: Method of Operation(Flowing,gas lift,etc.). 3/24/2013 Flowing Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 3/25/2013 1/20/1900 Test Period 466 2,240 0 0 4,811 Flow Tubing Casing Press: Ca;culated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(torr): Press. 24-Hour Rate — 550 2,646 0 27.5 28. CORE DATA Conventional Core(s)Acquired? Yes ❑ No E • Sidewall Cores Acquired? Yes ❑ No E 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 APR 2 5 2016 Form 10-407 Revised 10/2012 CONTINUED ON REVERSE Submit origin I only V t 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? L i Yes [] 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 Sterling B6 3,204'-3,347' 3,202'-3,345' Water Tyonek D1 Coal 5,658'-5,686' 5,656'-5,684' Water,Gas Tyonek 64-5 Sand 6,407'-6,430' 6,405'-6,428' Gas,Water Tyonek G2 Sand 10,726'-10,802' 10,525'-10,595 Water,Oil Top Hemlock 10,806'-10,826' 10,599'-10,618' Oil ✓ Hemlock H3 Sand 10,853'-10,890' 10,643'-10,678' Oil Hemlock H10 Sand 11,107'-11,187' 10,882'-10,957' Water,Oil Formation at total depth: 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Luke Keller 907-777-8369 Email: Ikeller Cl hllCorp.Com Printed Name: Luke KellerTitle: Drilling Engineer Signature: /1 /G//�L Phone: 907-777-8395 Date: 4/19/2013 6 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 TVD 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 MC 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 MC 25.071. Form 10-407 Revised 10/2012 SRU 14B-27 LOG SUMMARY Swanson River UnitWell: SRU 14B-27 PTD: 212-089 Hilcorp Alaska,LLC API: 50-133-20604-00 1. Cased Hole Logs 4-10-2013 2. Cuttings 7-20-2012 3. Cuttings 1-31-2013 4. E Logs 2-19-2013 5. Mud log Data 2-19-2013 Updated by TDF 4/19/2013 Swanson River Unit II SCHEMATIC Well: SRU14B-27 PTD: 212-089 Hilcorp Alaska,LLC API: 50-133-20604-00 KB-THF: 18.6' CASING DETAIL 1 r Size Type Wt Grade Conn. ID Top Btm 16" 2 Conductor—Driven to 16 Set Depth 109 X-56 Surf 80' 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 2,961' 4.1 1 / 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 7,093' _ 7-5/8" Intermediate 29.7 P-110 BTC 6.75" 7,093' 10,104' 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 9,889' 11,320'_ 10-3/4'h 2.9Lf' TUBING 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 9,912' 3MIR i & JEWELRY DETAIL No. Depth ID OD Item P 4 ilit i1 18.6' 2.992" 9.000" Tubing Hanger 3-1/2"8rd 7 2 22.83' 2.992" 4.500" Crossover 2-7/8"8rd Pin x 3-1/2"8rd Box 1: 5 Mk i 7 _ 3 4,391' 2.441" 4.625" GLV#8-12 Orifice 4' 4 5,927' 2.441" 4.625" GLV#7-Dummy 5 6,885' 2.441" 4.625" GLV#6—12 Orifice 6 dm i l` 6 7,600' 2,441" 4.625" GLV#5—Dummy 7 8,253' 2.441" 4.625" GLV#4-Dummy x 8 8,783' 2.441" 4.625" GLV#3—12 Orifice 4* 7 411, 1 9 9,318' 2.441" 4.625" GLV#2-Dummy " 10 9,850' 2.441" 4.625" GLV#1-12 Orifice 8 r i 11 9,866' 2.313" 6.250" T-2 On/Off tool with X-Profile 12 9,868' 2.500" 6.672" AS-1X Ret Prod Packer 13 9,906' 2.313" 3.230" X-Nipple 9 14 9,912' 2.500" 3.690" Wireline Re-Entry Guide a - 10 lit i 4' la PERFORATIONS It. ii T' Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date II I I H-3 10,854' 10,859' 10,644' 10,649' 5' 6 3-3/8"HC 3/19/13 12 4 c ' H-3 10,859' 10,880' 10,649' 10,669' 21' 6 3-3/8"HC 3/19/13 er H-3 10,886' 10,898' 10,674' 10,685' 12' 6 3-3/8"HC 3/19/13 7-5/8" . ` I t Ib`1 14 kt rl CZ 4# ti , ' it 60 IlL H3 Sands t, 9 5" ,o6, ‘ . TD=11,332'MD-11,085'ND PBTD=11,200 MD—10,942'ND Updated by TDF 4/19/2013 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 14B-27 50-133-20604-00 212-089 12/2/12 Daily Operations: 11/28/2013-Wednesday No operations to report. 11/29/2013-Thursday No operations to report. 11/30/2013-Friday Mobilizing to location and rigging up. 12/1/2013-Saturday Mobilizing to location and rigging up. 12/2/2013-Sunday Mobilizing to location and rigging up. 12/3/2013-Monday Continue building 10.0 ppg spud mud,change out pry on injection pump. Modify landing between pits&sub.Load 30 jts pipe in pipe shed. Function test diverter system,AOGCC Lou Grimaldi witness diverter fuction. Pre Spud meeting with all personnel. Continue testing gas alarms,PVT system with AOGCC inspector. Correct defficencies with PVT system. Install wear bushing(14"I.D on wear bushing.) Pick up 70 jts drill pipe and 25 jts hwdp and stand in derrick. Pick ub BHA,Tagged bottom 68.5 ft in. Safety meeting on spudding well 12/4/2013-Tuesday iniHilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 14B-27 Drilling Report 50-133-20604-00-00 212089 12/2/12 N.-A-4..,, Daily Operations: I, .. 12/05/2012-Wednesday Drill 13 1/2" hole F/76'T/284'400 gpm,480 psi,30 rpm,4k wob,3k torq on bottom,ADT 4.6,ASD 0,ART 4.6, hrs on jars 4.6 Drill 13 1/2" hole F/284'T/385'425 gpm,p/u 40k,s/o 40k,rot 40k 1.5 tq,circulate.Trip out of hole to conductor shoe.AOGCC stopped drilling due to diverter deflector. 12/06/2012-Thursday Continue to wait on orders to drill, monitor,well, perform rig maintenance. Remove deflector shield f/diverter line, l/d floor safety valve, p/u and scribe motor, p/u MWD, flex clr, &xo, BHA wt 42. Trip in hole, wash and ream f/297' t/385' @ 400 gpm, 800 psi, 30 rpm. Drill F/385' T/529' - 144' @ 41ft/hr, gpm 550, 1480 psi, torq on bottom 1.5. Drill F/529'T/824' - 295' @49ft/hr, gpm 600, spp 1840, torq on 1.6,torq off 1. P/U 70k,S/0 70k, ROT WT 70K,ADT 6.1hr,AST 0,ART 6.1. Drill F/824'T/1,095'-271' @ 45.1 ft/hr 650 gpm, 2,076 psi, wob 5k,p/u 72k, rot 72k,torq on bottom 1.5. 12/07/2012-Friday Drill F/1,095 T/1,410-315' @ 75 ft/hr,640 gpm, 2,250 psi,70 rpm,wob 7k,trq on 2k,trq off 1k, p/u 82k,s/o 80, rot wt 82,ADT 4.2,AST .4 ART 3.8. Drill F/1,410'1/1,518'-108' @ 72 ft/hr, Rot wt 87k, p/u 86k,s/o 86k torq on 2k,CBU,monitor well,well static.Trip out of hole F/1,518'T/951',hole taking proper hole fill, 15/20k over pull F/1,110'T/983'. Monitor well,well static, RIH F/951'T/1,454', m/u top drive and wash to 1,518'.circulate. Repair hydrulic leak on top drive and tighten swivel packing. Rotate and slide F/1,518'T/1,835',-317'@ 50 ft/hr, 630 gpm, 2,150 psi, torq on bottom 2.5, trq off 1k, p/u 90k, s/o 90, rot wt 90k ADT 6.3hr, AST .7 hr. Drill F/1,835' T/2,150',- 315' @63 ft/hr,620 gpm, 2,230 psi,wob 10k,p/u 97k,s/o 97k, rot wt 97k, rpm 80,torq on bot.3.6k torq off 2k. 12/08/2012-Saturday Drill F/2,149'T/2,296', p/u 102, s/o 100k, rot wt 97k, rpm 50,gpm 635 torq on bot. 3/6k,torq off 1.5, CBU.Short trip f/2,296'T/1,583', p/u 90k, s/o 91k. Drill F/2,296'T/2,483', p/u 107k, s/o 103k, rot 107k, torq on bot 3.5, tq off 1.8. Drill F/2,483' T/2,740', p/u 112k, s/o 108k, rot 11k, 645 gpm,torq 3.7,torq off bot 1.5 k, 2,350 psi, 7.4 ADT 7.4, AST .6 hr, ART 6.8hr,jar hrs 32.7. Drill F/2,740'T/2,970', p/u 115k,s/o 112k, rwt 112k, rpm 80,tq on bot 4.5,tq off 1.9k,gpm 60 20, psi 2,350,wob, 12k,CBU followed by 35bb1 hivis nut plug sweep, sweep came back on cal stks. 12/09/2012-Sunday Trip out of hole F/2,970' T/297', no over pull. Trip in hole F/297'T/2,970', no fill. Circulate and condution mud. Drill F/2,970'T/2,980', circulate bottoms up. Trip out of hole f/2,980' t/2,401', blow down top drive & mud lines. Lay down, flex collar, mwd, stab, poney clr, motor, bit. Clear rig floor of drilling tools. Pull wear bushing. Rig upto run 10.75 casing, dummy run 10 3/4" hanger, get centralizers to floor.Make up shoe trac,bakerlock connections,check floats, run 10 3/4 csg. 12/10/2012-Monday Continue running casing t/2,606', work through bridge, run csg t/2,931'. Break circulation and work pipe, 3bpm 300 psi, p/u 145k, s/o 100k. Pick up hanger and land csg, make up cement head. Circ and condition mud F/cement, 3bpm 230 psi, 6 bpm 420 psi, p/u 134 s/o 124k. PJSM with all personnel,pressure test cement lines @ 3,000 psi. Pump 40 bbl mud push, @ 5 bpm, drop bottom plug, pup 330 bbl (u4fr- 12 ppg lead cmt @ 4.5 bpm, 315 psi, pump 80 bbls 15.4 ppg tail cement @ 4.8 bpm, drop plug, pump 5 bbls water, line up to displace c,..5,-- with rig pump. Displace cement w/ 10.5 ppg mud, 8bpm 1,150 psi, mud push @ surface; 4200sks,take returns to cellar, slow pumps t/ 3bpm @ 5000 stks, displace ;to 5650 stks, plug not bumped, pump 1/2 shoe track 5786 stks, plug not bumped. FCP 870 psi, cement in place @ 20:30 hrs, 35 bbls 12.4 cement to surface. Check floats, floats holding, blow down cmt lines, rig dwn cmt equipment, 1/d. M/U pack off running tool on landing jt, set pack off, lay down landing joint. Clear rig floor of cementing equipment, remove bails, elevators, nipple down katch kan,flow line,drilling nipple, rig dwn diverter line. 12/11/2012-Tuesday Clean out cellar box, remove valves on conductor, nipple down surface stack. Install multi bowl well head, install choke hose T/choke, remove sub beam. Install koomey hoses,test void T/3,000 psi F/30 min, set spacer spool. Pick up annular, double gate, mud cross,single gate,tighten all bolts.Tighten base flanges, m/u kill &choke lines, install flow riser,install turn buckles and katch kan. Installed 2 7/8"x5 VBRs in upper&5" in Lower,function test bop's,continue cleaning pit#1. Remove diverter line. Change settings on draw works engine to increase performance. Begin installation of Canrig Auto-Driller. Pollard injected spent drilling fluid @ G&I location (1107 bbls of mud injected). Page 1 of 1 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 14B-27 Drilling Report 50-133-20604-00-00 212089 12/2/12 Daily Operations: 12/12/2012-Wednesday Finish installing 5"rams inlLower cavity.Function test BOP&prep for PT.Change bails on TD from long to short.Remove blind flange on annulus valve.Continue cleaning Pit#1.Utilize super sucker to remove solids and cement. Make up test sub to top drive.Connect test hoses and purge air from system.Pressure test BOP and related equipment to 250L/4,000H psi f/10 min each test.Test annular preventer om" to 250L/2,500H.Attempt to test upper pipe rams(VBRs).Leaking fluid by Rams.Pump fluid to top of rams(rams are not fully closed). Remove"new"accumulator hoses.Connect hoses&pump oil to purge air f/system. Re-test VBRs(failed).Open ram doors.Clean solids f/ram slides(packers ok).Test VBR Rams t/250L/4,000H f/10 Min(good test).Continue testing remaining equip,(3)Fail/Pass tests:VBR Rams,XO Spool flanged leaked, upper TD valve leaked,initial test.Cycle valve&retest.Tested manual&hydraulic choke performance. Perform accumulator pre-charge test.Tested gas alarms.Rig down testing equipment and blow down all lines.Make up 9 7/8"drill out BHA, trip in hole with HWDP.Trip in hole,pick singles F/pipe shed.Injected 725 bbls drill mud.Continued installation of auto driller.Finished cleaning cement from Pit#1.Begin transporting 6%KCL/PH/PA mud from storage tanks. 12/13/2012-Thursday TIH with clean out BHA picking up (40) singles f/pipe shed. Circulate and condition mud @ 2,238'. Water back contaminated mud to pumpable consistancy. Continue to circulate and increase PR when possible.TIH w/stands. MU TD and wash from 2,774'.Tag cement @ 2,836' (flt clr @ 2,874;). Circ. & cond to thin mud and balance system. Having to jet returns w/water to pass flowline. Thick mud running over possum belly and trough @ slow pump rate.R/U and test casing to 1,500 psi f/30 min. Initial test bleeding off slowly. Found leak from gland nut on LDS.Tighten and repeat test(0 psi bleed). Prep for drill out:Continue to build mud for sufficient volume. Finish removing hard cement from cuttings tank. Pump thick mud (spilled f/trough) from pit #1. Finish calibration and testing of LEL/H2S gas alarm system. Continue w/installation of Canrig Auto Driller system. Begin cleaning out hard cement and drillin: shoe track f12,836'to float 2,878',drill out cement to shoe @ 2,962'wob 10k,60 rpm,300 gpm tq 2.5, p/u 102k.Clean out rat hole and drill F/2,980 T/3,000',circulate bottoms 1.( up and displace to 6%KCL PH/PA mud system. Obtain SPR @ 3000' -MP#3 100 psi,rig up to perform FIT test.Perform FIT test T/13.5 ppg 483 psi, rig down testing equipment. Drill F/3,000 'to 3,045'. Detected flow on connection. 10.5 ppg IN, 10.4 ppg OUT. CBU to verify flow caused by mud out of balance. 12/14/2012-Friday Circulate to balance mud and verify"no flow". Drill 9 7/8" hole from 3,045' to 3,215. CBU to clear well bore of cuttings. Flow check well. Pump slug. POOH f/3,215. UP 115 DN 113. Rack back BHA. L/D Bit, Bit sub and Stab. Clear floor of slip/trip hazards. Crew change (1st tour back). Rig inspection. M/U BHA #4: PDC, 1.1 deg motor, stab pony DC, XO, MWD, Filter, XO, NMDC, XO Calc. Motor x MWD offset. TIH w/Jars and HWDP. P/U and RIH w/5" Dp singles. SLM & drift each joint. (3.03" drift). Clean suction screens on all pumps. Drill F/ 3,215 T/3,625,WOb 5/10K,rpm 90, p/u 120k,s/o 115k, rot wt 117k trq on bottom.2.5k,trq off 2k, bit hrs 4.5,motor hrs 7.5,jar.Rotating hrs 43. 63 ft/hr average ROP.Injected 1,622 bbls drilling mud.Continue cleaning solids from R4R tanks. 12/15/2012-Saturday _Drill 9 7/8" Intermediate hole section f/3,625't/4,041'.Ave ROP=69 ft/hr. Drill 9 7/8"Intermediate hole section f/4,041't/4,415'. Ave ROP =74.8 ft/hr,10k wob,1,900 psi,p/u 138k. Drill 9 7/8"intermediate hole section F/4,415'T/4,557'-142' 29.8 ft/hr,P/U 143,s/o 137k, rt wt 138k,spp on 1,840, off 1,610,wob 8/15k,torq 2.4 on bot,2.2 off art 9.5, bit hrs 18,jar hrs 56.9.Drill F/4,557'T/4,760'. 34 ft/hr ave ROP. PR fluctuating f/7 ft hr t/130 ft/hr. Pumped (2) nut plug/condent pills to clean "possible" balled-up bit. Good results with second pill with increase in P-rate as pill exited bit.Continue cleaning solids from tanks @ G&I.Fighting freeze up problems.(-20) 12/16/2012-Sunday Page 1of2 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date • SRU 14B-27 Drilling Report 50-133-20604-00-00 212089 12/2/12 Daily Operations: Drill f/4,760' t/4,797'. 700 units gas f/4,785'. 90 rpm, 133k ROT wt. 3-4k tq CBU, 12.3 bpm, 1,680 psi. Pump up survey. Flow check well. POOH f/4,797'. Rack back two stands. Pump slug and blow down top drive. UP 148k, DN 140k. 30k over pull @ 4,270', 4,128', 4,097' & 4,077'.Work tight hole f/3,884'thru 3,856'w/45k.30k over pulls @ 3,805',3,748',3,650'&3,630'thru 3,618'.Work 45k over @ 3,525',30k @ 3,498'&3,385'. M/U TD and backream to pass tight spot f/3,185'thru 3,175'.350 gpm,670 psi.62 rpm,2.3k tq.115 rot wt.Straight pull f/3,145'to shoe.Work 30k @ 3,085'.Transmission overheated&stalled.Wait 15 min for transmission to cool. Pull to shoe UP 125k.Service rig.Change grabber dies.Change encoder on top drive. L/D(2)jts Dp with galled threads(WOT pipe). P/U and RIH with(50)joints of Knight Oil DP.Drift each jt w/2.375 dp. M/U TD,brk circ. Pump 40 bbl hi/vis sweep,wash f/4,728't/4,793'. 30'of soft fill.Drill 9 7/8" hole f/4,797' t/4,805'. Hole unloaded @ B/U &continued throughout return of sweep. 12.5 bpm,1,580 psi,90 R, 3k tq, 10k WOB. 145k ROT wt. Drill F/ 4,805'T/5,017'-212'40.7 ft/hr p/u 153k,s/o 145k,rot wt 147k spp 1850 torq on 4.3,tq off 2.6,gpm 517,ART 5.2,Bit hrs 28.7,jar hrs 67.6. Drill 9 7/8 hole F/5,017/T/5,335'. 1,470 units f/coal @ 5,250'. 12/17/2012-Monday Drill 9 7/8" hole f/5,335't/5,550'. 36 ft/hr ave ROP. Low level H2S alarm on rig floor sensor. P/U &shut do pumps. Use hand held detector to confirm false reading from sensor. Resume drilling from 5,535'.Drill 9 7/8 hole f/5,550'.Penetrated D1CT Tyonek coal @ 5,665'.Drill coal to 5,670', CBU to clear annulus of heavy cuttings. Coal and 510 units of gas @ B/U. Reduce PR f/12.5 bpm t/10.0 bpm. Control drill coal w/5k WOB, 80 ft/hr. Exited coal @ 5,690'. Maintain lower PR to 5,720', until stabilizer cleared coal btm. Continue drilling 9-7/8" hole f/5,720't/5,800'.12.5 bpm,2,050 psi. UP 166k, DN 158, 10-12k WOB,90R 3.5-5k tq. Drill F/5,800'T/5,999'-199' @ 39.8 ft/hr,gpm 518, spp 2,030 psi,p/u 174k,s/o162k,rtwt 158k,tq on 4.6,tq off 2.9, bit hr 46.8,jar hrs 85.7,art 9.4. Drill F/5,999'T/6,122',gpm 510,p/u 175, s/o 162k,rt wt 165k,wob 5/15k,spp 1,850' psi,tq on 3.3,mtr hrs 51.4,bit hrs 51.4,jar hrs 89.8.20.5 ft/hr ave ROP.Finished cleaning tanks @ G&I.Moved all tanks from containment. 12/18/2012-Tuesday Drill 9-7/8" hole f/6,122't/6,185'.25 ft/hr ave ROP CBU. Flow check Well(ok).Short Trip f/6,185't/4,670'. Hole was in very good condition. (Over pulls of 30k @ 5,365', 5,323', 5,142' & 5,064') Passed tight spots easily on second attempts. Make up safety valve & head pin. Circulate through cement hose @ 6 bpm,550 psi. Mechanic attempted to energize top drive compensator but didn't have the correct valve assembly for the nitrogen pre-charge. Decision made to continue operations without compensator operation & expedite correct tool to make needed repair(no compensator travel during connections).TIH f/4,670't/6,125' picking up an additional (44)joints of Knight Oil Dp. M/U TD. Break circ and pump high vis sweep. Wash down f/6,125' t/6,185' (no fill). Circ sweep to surface w/moderate increase in ctgs/cavings when sweep returned. Drill 9 7/8" hole f/6,185't/6,355'. UP 184, DN 175, R 176,WOB 10-15,TQ 3-4K, 12.2 bpm,2,000 psi,20 ft/Ave ROP. Drill 9 7/8" hole f/6,355' t/6,498'. 13.3 bpm, 2,320 psi, 90R, 3-4 TQ, 15-20 WOB. Penetrate gas storage sand @ 6,420'. 270 units max gas.No losses to formation.24 ft/hr ave ROP.Transported 297 bbls of excess drilling fluid to G&I storage for injection. Page 2 of 2 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 14B-27 Drilling Report 50-133-20604-00-00 212089 12/2/12 Daily Operatic ns: 12/19/2012-Wednesday ih Drill 9 7/8"hole f/6,122't/6,185',25 ft/hr ave ROP.CBU.Flow check well(ok).Short trip f/6,185't/4,670'. Hole was in very good condition (over pulls of 30k @ 5,365',5,323',5,142'&5,064').Passed tight spots easily on second attempts.Make up safety valve&head pin. Circulate through cement hose @ 6 bpm,550 psi. 71-1f/4,670't/6,125' picking up an additional(44)joints of Knight Oil Dp.M/U TD.Break Circ and pump high vis sweep.Wash down f/6,125't/6,185'(no fill).Circ sweep to surface w/moderate increase in cuttings/cavings when sweep returned.Drill 9 7/8" hole f/6,185't/6355.UP 184, DN 175,R 176,WOB 10-15,TQ 3-4K,12.2 bpm,2,000 psi,20 ft/hr ave ROP. Drill 9 7/8"hole f/6,355't/6,498'„13.3 bpm,2,320 psi,90R,3-4 TQ,15-20 WOB.Penetrate gas storage sand @ 6,420'. 270 units max gas. No losses to formation.24 ft/hr Ave ROP.Transported 297 bbls of excess drilling fluid to G&I storage for injection. 12/20/2012-Thursday Drill 9 7/8” hole from 6,498'to 6,682'. 31 ft/hr ave ROP. UP 188k, DN 178k, R 182k, 13 bpm, 2,480 psi, RPM 90,TQ 3-4k. Drill 9-7/8" hole from 6,682'to 6,825'.24 ft/hr ave ROP.Problem coal @ 6,775'.Drill 9 7/8" hole f/6,830'to 6,958'. Begin building angle @6,880'w/20'slide. Continue drilling 9 7/8" hole as per directional plan from 6,958',to 7,027'.Troubleshoot pumps(losing pressure). Suction screens blinding off. Found hole in shaker screen. Change screen and inspecting shakers. Halliburton crew arrived and began pad pre for setting up G&I equipment. 12/21/2012 Friday Qtilj9 7/8" hole f/7,026'to 7067'. Directional drill curve as per plan. CBU in preparation for short trip. 400 units @ B/U. Flow check Well. Short trip f/7,067'to 5,300'to place BHA above D1 Coal @ 5,665'.Work through tight spot f/6,869't/6,845'with 50k. Pull 30k @ 6,413' & 6,405'. Service Rig. Make up head pin and circulate @ 6 bpm,600 psi.Change compensator hydraulic cylinder on ODS.Check pre-charge in N2 chambers. Found DS bled down & ODS @ 800 psi. Charge to 1,200 psi. Adjust compensator travel via hydraulic cylinders. TIH f/5,300' t/7,067'. Tag obstruction @ 6,756'. Wash & ream to 6,830'. Safety ream from 7,020' to 7,067' (no fill). Pump high vis sweep and circ to surface. Hole unloaded large amounts of coal and drilled cuttings prior to start of sweep (2x2 &2x1 pieces of coal). Drill 9 7/8 hole as per directional plan f/7,067't/7,187'. 14 ft/hr ave ROP.Rig generator engine overheated @ 23:00.Operating on#2 Generator. Drill 9 7/8" hole as per directional plan f/7,187' t/7,300'. 20.5 ft/hr ave ROP. UP 205k, DN 195k, R 197k, WOB 17-22k, TQ 3,500, 12.7 bpm, 2,200 psi. Halliburton prepped G&I location for laying liner and R/U equipment. 12/22/2012-Saturday Drill 9 7/8" hole as per directional Plan from 7,300' to 7,378'. Shut in Well @ 08:52 due to flow of mud from well bore. Drilled a sand f/7,343't/7,354'. Detected gas spike from sand,flow checked well.Shut in with annular preventer(2007 units max gas). Monitored Dp/Csg v/ pressures. Pressures stabilized @ 20 Dp, 30 Csg.4 bbl gain in pits reported. Use Drillers Method t/circulate influx out. 3 bpm, 225 ICP, 250 FCP. MW 10.5 ppg ; Monitor well. SIDPP 17psi, SICP 55 psi. Decision made to increase MW t/10.7 ppg. Second circ of Drillers Method. Circulate 10.7 ppg. ICP 270 psi. Held 300 psi once NMW exited bit through remainder of circulation (700-1100 units of gas). Monitor well. SIDP 70 psi, SICP 80. Increase MW in pits to 10.9 ppg. Strip pipe through annular(down)to verify free. 30k to break over. Pump 10.9 ppg KWM following DP pressure schedule. ICP 320 psi.FCP 255 psi.10.9 ppg @ surface,690 units of gas.Shut down and shut in choke.Monitor well 10 min.SIDP 2 psi,SICP 6 psi.Open annular&check for flow. No flow but mud percolating heavily&very frothy.Shut in well. Increase MW in Pits to 11.2 ppg. Circulate KWM mud to increase mud system f/10.9 ppg t/11.2 ppg. Maintain 325 to 350 psi on DP to achieve overbalance during displacement. 750 to 1300 units of gas in returns downstream of Gas Buster throughout circ. 11.2 ppg In/out.690 units gas.300 psi circulating through an open choke. 12/23/2012-Sunday Circulate through a fully open choke @ 5 bpm, 560 psi Dp, 10 psi Casing. Shut down hoppers to prevent inducing air to system and add defoamer @ suction.Fine sand reported at shakers&background gas units increasing.Shut down pump.Verify pressure bled.Open annular and flow check Well.No flow and fluid purcolating less than previous check.Rack back 2 stands in derrick.Bit depth @ 7,260'.M/U TD,close annular and brk circ.through choke.Circ.full circulation @ 3 bpm while holding 300 psi back pressure on annulus. Background gas reduced f/1,530 units to 690 units. 11.2+ppm MW In/Out.Increase MW f/11.2+ppg,t/11.5 ppg.while holding 250 psi on Annulus.11.5 ppg In/Out. Stop pump& bleed pressure. Open Well, check for flow(static). CBU @ 10 bpm, 1,980 psi. UP 190k, DN 185k, 357 units start, reduced to 180 units.Blow down choke&mud cross.Wash&Ream f/7,260't/7,359'.Clean out f/7,359't/7,378'. Rotary drill 9 7/8" hole to finish stand f/7,378' to 7,386'. Circ & Cond to clear annulus of 10.5 mud and B/U gas. 1,731 units of gas with Oil, breaking out at flow nipple. Circ an additional annular volume to reduce gas to 500 units. Background gas maintaining @ 500 units. Drill ahead f/7,386' as per directional plan. Begin adding Barite to increase MW while drilling. 12.2 bpm 2500 psi. 90 RPM, 4-5k TQ. w/18k WOB. Gas units began increasing f/800 quickly.Shut do pumps and flow check Well(well flowing).Shut in Well @ 23:10.Gas trap showing 2,000+uinits when shut in. Hole depth- 7,400'. Bit depth - 7,385'. Increase MW in Pits f/11.5 ppg t/11.8 ppg. Pump 11.8 ppg KWM. Hold 275 psi on casing until 11.8 ppg mud reached 10 3/4 Shoe, reduced Casing pressure to 225 psi and hold until 11.8 ppg mud at surface.FCP through open choke=365 psi. Page 1 of 2 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 14B-27 Drilling Report 50-133-20604-00-00 212089 12/2/12 Daily Operations: 12/24/2012-Monday Circ&cond.11.8 ppg mud returned to surface @ 05:50.Open annular and monitor well. Move pipe to verify free.CBU to clear possible gas f/annulus.Max gas 340 units,final gas 91 units. 12 bpm,2400 psi,30 RPM, 3.2k TQ. Drill 9 7/8" hole per directional plan f/7,400'to 7,439'. 11 bpm,2,410 psi,70 RPM.Continue drilling from 7,439'to 7,514' per directional plan. Back ground gas increased f/284 units @ 7,495',to 560 units @ 7,514' (Kly Dn). Work std until units dropped below 500,gas continued to rise&peaked @ 1,850. Circ&condition to reduce gas units from 1,850 to 500 prior t/connection. Drill from 7,513'to 7,528'. Gas increasing f/615 to 2,146. Flow check well. Shut in well @ 19:50 and record pressures. SIDPP 50 psi. SICP 25. No pit gain. Increase MW f/11.8 ppg in suction Pit to 12.0 ppg. Pump 12.0 ppg KWM w/holding 150-200 psi on casing. FCP 285 psi, 208 units of gas. Drill 9 7/8" hole per directional plan from 7,528' to 7,605'. ; Current back ground gas=135 units. Max gas since MW increase= 1017 units. Injected 656 bbls of spent drilling fluid with SLB cement pump. SITP 700 psi. 12/25/2012-Tuesday Drill 9 7/8"hole per directional plan from 7,605'to 7,630'.Gas units increasing quickly.Well flowing,shut in well.10 bbl gain.SIDPP 35,SICP 0.gas from a sand drilled @ 7,618'. Increase MW in suction pit to 12.1 ppg. Circulate to increase MW f/12.0 ppg t/12.1 ppg.while holding 150 psi on casing.Increase pump rate to 4 bpm and then 5 bpm w/maintaining 150 psi on csg. Gas reduced to 500 units. Open annular.No g° flow. ; Drill f/7,630' to 7,636' to finish stand. Continue circulating to finish B/U prior to making connection. Gas increased to 1,800 units. Slow PR to 3 bpm.Gas continued to climb to 2,418 units and then declined and stabilized @ 1,150 units.Shut in well and weight up surface system to 12.3 ppg. SIDPP 37, SICP 0 psi. Displace well f/12.1 ppg to 12.3 ppg while maintaining 125 psi on casing.5 bpm. FCP thru open choke - 635 psi. Final gas units - 515. Flow check well. (no flow). Continue circ @ 12 bpm 2,600 psi. Gas dropped to 150 units. Make connection. Pump up survey. Drill 9 7/8" hole per directional plan f/7,636't/7,707'. While drilling gas was holding at 420 units and spiking up to 1,100 units..Increase the mud weight to 12.4 ppg and continue drilling.Continue drilling from 7,707'to 7,761'.Background gas holding @ 650 and spiking to 1,762 units.Increase MW to 12.5 ppg while drilling.Background maintaining @ 25. Page 2 of 2 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date • SRU 14B-27 Drilling Report 50-133-20604-00-00 212089 12/2/12 Daily Operations: 12/26/2012-Wednesday Drilling ahead F/7,761'to 7,815'WOB=20k GPM=490 PSI=2490 TQ=6k-8k ft/lb. Background gas 20 to 30 units topping out at 245 units. Drilling ahead F/7,815'to 7,890'WOB=22k GPM=470 PSI=2550 Tq=7k-9k ft/lb. Background gas 25 to 35 units topping out at 475 units. Drilling Ahead F/7,890'to 7,945'WOB=24k GPM=470 PSI=2600 TQ=8k-10k ft/lb.Background gas 35 units topping out at 480 units.Drilling ahead F/7,945'to 8,005'WOB=24k GPM=470 PSI=2,600. Background gas 35 units topping out at 160 units. 12/27/2012-Thursday Drill F/8,006' to 8,064' 25k wt, 270 gpm, 8k tq, max background gas 142 units. Circulate B/U with 470 gpm at 2,350 psi. Shut down and monitor well for 10 min.Well bore static, pump dry job and blow down topdrive and pumps.Short trip out from 8,064', up wt 205k,start pulling tight @ 6,800' up to 6,750'. 6,750'is center of a coal stringer,pulled 25k over working through the tight spot 3 times wiping it clean. At 6,570'another coal stringer,work up and down knocking the edges off the coal seam.Tripped from 8,064' up to 4,851' and all the tight hole issues were coal stringers.Wipe through them 1 or 2 times knocking off the edges.Remaining tight spots:6,436',6,413',6,375',6,282', 5,465', 5,060', 4,965'. Monitor well (static). Trip back in F/4,851' to 8,000'. Tight spot @ 8,003'. Break circulation and wash and ream F/8,003'to 8,064'.Circulate a bottoms up. At 6,500 strokes,gas units began increasing topping out at 2,300 units,decrease the mud pumps to 126 gpm and circulate. While circulating out through gas the mud wt is increased F/12.5 ppg to 12.7 ppg. At 10,600 stks gas units increased up to 1,700 units then dropping back.Short Trip F/8,064'to 6,000'. 12/28/2012-Friday Cont POOH on elevators to 5,994'w/no problem.RIH f/5,994'to 8,019',MU topdrive,fill pipe,wash dwn to 8,064'saw no fill.CBU 1 time at 400 gpm-1,930 psi,50 rpm,3-4K ft/lbs off bott torque,max gas at bott up 145 units,pumped 20 bbl dry job at 14.7 ppg,blow dwn topdrive. POOH f/8,064',test choke manifold while POOH, rig crew held kick while trip, drill at 5673'. Cont POOH f/5,673'to 4,666' on elevators, at 4,666'encountered tight hole,pulled to 215K (65K over)and could not get through. MU top drive,start pumps. Backream OOH f/4,666'to 4,630', pumped at 339 gpm-1,350 psi, rot at 60 rpm torque 3K to 7K ft/lbs, reamed 30'section numerous times w/no problem. Cont POOH f/4,630'on elevators,up 150K,to 4,512'and encountered another tight spot, backreaming OOH f/4,512'to 4,165'. Continue back reaming F/4,165'to 3,215' @ 3469' 25k overpull rotary stopped and had no up or down movement, keep circulating and work pipe entil free.The well bore started packing off while back reaming. Circulate and condition the well bore and service the rig. Continue tripping out fighting tight hole to 2,902'.Circulate B/U x2 @ 480 gpm 1,900 psi and 20 RPM.Flow check(static).Not enough room for HWDP,trip in 62 jts,trip out 62 jts laying them down.Trip out Standing Back HWDP. 12/29/2012-Saturday Cont POOH rack back HWDP in derrick. Drain,flush and LD MWD,motor and bit.Clean rig floor.Pull wear ring,set test plug,test all BOPE at 250/4000 psi f/10 min each,test annular at 250/2,500.Witness of BOP test waived by Jim Regg 12-25 at 16:45 hrs.Performed Koomey test, drained stack, RD test equip, set wear ring. Clear rig floor, inspect saver sub and grabber dies. P/U BHA#5, shallow test MWD and trip in. Trip in picking up drill pipe, 62 jts that had to be layed down, plus 15 new. Cut and slip 165' drill line. Cont TIH,tagged up at 2,879', MU topdrive and wash f/2,879't/2,903'. Blow dwn topdrive,cont RIH f/2,903'to 3,855'. 12/30/2012-Sunday Cont RIH with 5" DP from derrick, f/3,855' to 8,015' filling pipe every 20 stnds. Canrig calibrated gas monitor system, saw no fill, MU top drive. Break circ at 436 gpm-2,419 psi,filled pipe and CBU, max gas 1052 units at bott up, wash to bottom (8,064') at 60 rpm,5,400 ft/lbs torque.Eased into drilling w/10K wob,60 rpm at 5,400 ft/lbs torque,500 gpm-2,878 psi,gas units 16 to 23,running water at 9 bph.Lost MD Totco, PU off bottom and trouble shoot MD Totco failure. Problem solved. Resume drilling f/8,085' to 8,213', 19K wob, 60 rpm at 5,800 ft/lbs torque on bott, 500 gpm at 3,000 psi, ROP 15 ft/hr, water on at 9 bbl/hr, 12.8 ppg in, 12.8 out, vis 58 in, 60 out. Drill F/8,213' to 8,322'md,475 GPM,2,700 PSI,6kTq,mud wt in and out 12.7,vis in and out 51. Page 1of2 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 14B-27 Drilling Report 50-133-20604-00-00 212089 12/2/12 Daily Operations: 12/31/2012-Monday Cont drilling 9 7/8" hole f/8,322'to 8,540', 15K wob,63 rpm,518 gpm-3,151 psi; mud wt in/out 12.7, vis in/out 51, ROP 13 to,0 ft/hr,on bott torque 7,500 ft/lb max gas units 49 while rotating. Cont drilling 9 7/8"hole f/8,540'to 8,836' 15K wob, 65 rpm,480 gpm - 3,050 psi, 7800 on btm tq. ADT=20 hrs,ART=19.3 hrs,AST=0.7 hrs. 01/01/2013 Tuesday Cont drilling 9 7/8" hole f/8,836'to 9,016', rop 8 to 24 ft/hr,15 to 26K wob,505 gpm at 3,306 psi,65 rpm w/9,800 ft/lbs torque on bottom. Circulate B/U x 1, Slow pump rate @ 9,016'-8,923'TVD with 12.8 ppg mud wt. Monitor well and pump dry job.Short trip out F/9,016'to 7,766', wellbore in good shape, correct hole fill had a few spots with 25k over pull, no issues, at 7,766', monitor well, OK. Trip back in F/7,766'taking weight at 8,209', attempt to work through, kelly up and wash and ream through tight spot @8,209',continue trip in to btm at 9,016'.Drill F/9,016'to 9,080'450 gpm @ 2,950 psi,drilled 300'in 13.9 hrs=22 ft/hr RO. Page 2 of 2 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 14B-27 Drilling Report 50-133-20604-00-00 212089 12/2/12 Daily Operations: 1/2/2013-Wednesday Continue drilling 9-7/8" hole f/9,635'to 9,790',10 to 20K wob,68 rpm at 10,000 ft/lbs on bottom torque,473 gpm at 3,304 psi,on bottom diff.288 psi,rig crew performed man down drill. Cont.drilling 9-7/8" hole f/9,790'to 9,880',12 to 25K wob,60 rpm,p/u 225k,s/o 220 torque on 8.5,torque off 8.5,spp 3350 psi @ 480 gpm. Drill F/9,880 T/9,945,20 to 25K wob,60/90 rpm,3230 psi on bottom,477 gpm,p/u 262;s/o 220k,rot wt 230k,total hrs on bit 86.3,motor hrs 108.4,jar hrs 228.6;ADT 18.8, AST 0.0 hrs. 1/3/2013-Thursday Continue drilling 9-7/8" hole f/9,945'to 10,101',20K wob,60 rpm at 9,000 ft/lbs,torque on bottom,476 gpm at 3,298 psi,399 diff.psi, ROP 10 to 50 ft/hr,gas 72 to 130 units. Executed rig walkthrough w/Environmental Coordinator. Cont.drilling 9-7/8" hole f/10,101 T/ 10,110,20K wob,60 rpm at 9,000 ft/lbs torque on bot 9.2,476 gpm at 3000 psi,350 diff psi,p/u wt 265,s/o 225 rot wt 240hrs on jars 239, bit hrs 98.5.Circulate 2 bottoms up @ 500 gpm,90 rpm,3,400 psi. POOH F/10,105'T/9,535',hole not taking calculated hole fill. 6.9 bbl 11) gain,pulled 30k over @ 9,946',20 to 30K over F/9,630'T/9,535'. Monitor well. Well flowing,trip in hole F/9,535'T/10,073',taking weight @ 9,630'. Work thru tight spot and TIH T/10,104'. Continue monitoring well while conditioning surface mud,(water left on in pits, mud weight cut F/12.8 T/12.0).Circulate bottoms up,3,367 units gas @ bottoms up. Circulate and increase mud weight F/12.8 T/12.9. Monitor well for 30 min,well flowing @ 1.2 bbl/hr. Short trip 20 stds F/10,104'. 1/4/2013-Friday Continue to POOH f/10,019'to 8,835'(20 stnds total). Calculated hole fill 8.8 bbls,actual hole fill 10.25 bbls.MW 12.9 ppg,vis 61,well appears static. RIH with no problem to 10,095'. MU topdrive,CBU at 505 gpm-3081 psi,at bott up(15,600 stks)max gas increased f/22 to 1,847 units over 10 minutes,then dropped off to 26 units over 10 more minutes. Shut down mud pumps,lined up on trip tank. Monitored well f/flow.Over 15 min well began to flow at+/-1 bph. Consult with Drilling Manager,decision made to increase MW 2/10's to 13.1 ppg. Start circ at 365 gpm-1,782 psi,increasing MW f/12.9 ppg to 13.1 ppg. Monitored well f/30 min,fluid level dropped approx 3' in stack. Obtain slow pump rates at 10,087'. POOH 10 stnds,f/10,100',up wt 260K,had 3 spots w/15K over pull,calculated hole fill f/10 stnds 4.4 bbls,actual was 7.7 bbls. Cont.to POOH 10 more stnds to 8,945'.Calculated hole fill f/20 stnds 8.8 bbls,actual was 18.2 bbls. Monitor well at 8,945'f/15 min,fluid level dropped 3'-4'. RIH 20 stnds f/8,945'to 10,100'w/no problem.Dwn wt 200K. MU topdrive, ease into circ at 400 gpm at 2,218 psi,adding barafibre and steelseal at 5 lbs/bbl. Max gas at bottoms up 179 units. Monitor well,hole taking 1 bbl/hr,circulate bottoms up POOH F/10,104 T/9,788, hole taking proper hole fill,work thru tight spot @ 9,020 continue TOR T/8,840,monitor well,well taking.8 bbl/hr,pump dry job. Continue TOH F/8,840 T/5,000',monitor well,static loss rate 1 bbl/hr,p/u 230k s/o 200k. Continue tripping out of hole. 1/5/2013-Saturday Continue to POOH LD 5"DP f/3,205'to 2,922'(inside of surface shoe).Check for flow(no flow,hole taking 1 bph)cont.to POOH LD 5"DP. Cont POOH rack back HWDP in derrick,LD BHA#5.Hole taking.6 bph. Spot Halliburton unit, RU sheaves, PJSM,MU OH tools(94') consisting of GR-DSNT SDLT-XY Cross Dipole Sonic-ACRT-SP. RIH(at 15:00 hrs wire displacing no fluid). Log f/10,084'to surface,losses to well while logging 6.3 bbls. Lay down logging equipment,RD Halliburton sheaves. PJSM,pick up BHA#6(clean out assembly). RIH with BHA f/derrick,BHA wt 30k. Cont RIH pick up f/pipe shed and run f/derrick to 4,000',fill pipe every 3000'. 1/6/2013-Sunday Continue to RIH f/4,000'w/BHA#6(cleanout assembly),filled pipe every 3000'. Calculated DP displacement 85.61 bbls,actual displacement 79 bbls,loss to hole 6.6 bbls over 11.5 hrs of tripping. Tagged bridge at 10,075'. MU topdrive,lined up f/returns to active pits,start circ at 3 bpm-855,wash dwn f/10,075'to 10,110'with no problem.60 rpm at 9,400 ft/lbs torque, stage pump rates up to 9 bpm- 1,756 psi. CBU at 9 bpm-1,756 psi, rotate and reciprocate string,up wt 230K,dwn wt 225K at bottoms up had 841 units gas,dropped carbide pill after first circ and pumped around to check hole gauge.Open hole gauge estimated at 10,684". Monitor well,first 15 min was static,after 30 min well took 1/2 bbl. Break off topdrive and blow dwn,line up trip tank,POOH(no dry job)f/10,110'. LD singles in pipe shed,to 6,656', monitor well,well taking.8 bbl/hr. Continue tripping out f/6,656'to 571'. Rack back HWDP,LD BHA,pull wear bushing. 1/7/2013-Monday Page 1 of 2 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 14B-27 Drilling Report 50-133-20604-00-00 212089 12/2/12 Daily Operations: MU bushing puller on jnt DP,RIH engage wear bushing,BOLD's pull bushing. RIH 6 stnds 5" HWDP,MU Halliburton SSCV-RTTS Packer, RIH 1 jnt DP,turn string 1/4 turn to right and set packer. Back off 22 turns to left and pull stinger out of RTTS isolating well bore. LD jnt and stinger. Open lower ram doors,change out rams from 5"to 7-5/8",close door RU test pump,chart and manifold,test lower rams and door seals at 250/4,000 psi for 10 minutes each test. PU joint DP and stinger,RIH engage RTTS,POOH LD same,cont POOH LD 12 jnts HWDP(Weatherford). CO bails on top drive,CO handling equip, RU Weatherford casing tongs and power unit.Held PJSM w/rig crew, Weatherford,HAK Foreman. PU shoe joint and shoe track joint,Weatherford casing tongs having problems. CO Weatherford casing tongs. Cont MU shoe track,BakerLok entire shoe track assembly.Check float equipment. Cont PU RIH w/7-5/8"29.7#L-80 P-110 LTC,top fill every joint,to 2,929'. Circulate complete circulation @ 2,929'losses while circulating 1.3 bbls. Continue running 29.7#intermediate casing f/2,929'to 4,664' 01/8/2013-Tuesday Continue PU RIH w/7-5/8"29.7#L-80 BTC casing f/4,664'to 6,513',top fill every 10. MU XO and topdrive on casing,circulate surf to surf at 3 bpm-370 psi,recip casing 180K up,150 dwn. Fluid loss total 1.7 bbls for entire trip thus far. Cont PU RIH w/7-5/8"29.7#L-80 BTC casing f/6,518'T/10,104'p/u 214k s/o 183k. Rig down csg running equipment,m/u cementing equipment Circ&cond mud,start @ 126 gpm stage pumps up t/252 gpm @ 910 psi,p/u 248k,@ 8,940',couldnt break over picking up s/o 220k,@ 10,100',circulate,stage pumps up f/126gpm @ 540 psi T/650 psi @ 168 gpm PJSM,blow air to sclumberger,pump 5 bbls water and test lines @ 1,000/4,000 psi pump 5 .. more bbls water,pump 50 bbls 13.5 ppg mud push II w/rig pump. Begin batching Lead cement while pumping Mud Push. Drop bottom c st. plug,pump 275 bbls 14.0 ppg lead cement,@ 3.2 bpm 800psi,@ 230 bbls pumping @ 3.1 bpm, @ 14.1 ppg 550 psi 100%returns pump o 80 bbl 15.3 ppg tail cement @ 4.8 bpm 750 psi,@ 45 bbls,4 bpm,15.3 ppg,500 psi. Drop Top Plug,displace 455 bbls with rig pumps @ 6bpm,full returns,pump 9,895 stks, plug did not bump,pump 1/2 shoe track, 2bbls,9940 stks total final circulating psi @ 6 bpm 1475,@ 3bpm 1070 psi,CIP @ 03:50. Plug did not bump,check floats,floats holding,rig down cmt equipment. Mud Engineer reported final 25 bbls fluid returns had diluted Mud Push II. Calc.TOC=3,657 ft based on calculated hole size of 10.68 f/previous Carbide circulated by Mud Loggers. Back out landing jt,make up pack-off,set pack-off and test @ 250/3000 psi for 10 min. Page 2 of 2 II Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 14B-27 50-133-20604-00 212-089 12/2/12 Daily Operations: 01/09/2013-Wednesday Clear rig floor of excess tools.Install wear bushing.Change to short bails. Lay down 5'Dp stands from the Derrick. Break down in RT(92 stands total). Driller detected a slight flow from the Well Bore.Monitored well and measured flow @158 bph. Suspect thermal expansion from cement curing. Continue laying down 5"Dp from Derrick. Utilize WBI truck to transport and stage pipe on Tyler pad. Stage 68 jts of 7-5/8"casing at same location. Cut and slip drilling line,slip 30'and cut off 150'of line. Change out 4.5 IF saver sub on top drive to HT38. Pull wear bushing,change out tong heads and elevators. Change lower rams f/7-5/8"to 4". PJSm,p/u 4"test jt,rig up to test bops. Test bop's,choke manifold,top drive&floor valves @ 250 psi lo/4,000 psi high. 01/10/2013-Thursday Test BOP&related equipment to 250 psi L/4,000 psi H f/10 min each test.Test gas alarms and check calibration on all stations.Perform accumulator pre-charge test. Jim Regg(AOGCC)waived witness of test @ 09:19,1-9-13.Thomas Zelenka (BLM)waived witness of test @ 07:57,1-9-13. Kill Line HCR&Lower Pipe Rams(4")failed test. Replace HCR w/spare& replace Top seals on rams. Spare HCR failed test. Continue with remainder of tests,while rebuilding original HCR. C/O HCR kill. LID 4"test joint,test blind rams&HCR kill valve,p/u 5"test joint,test annular @ 250 psi lo/4,000 psi hi,attempt to test VBRs,VBR leaking,open doors and inspect VBR. Pull 5"test joint found tong marks on pipe where rams closed,c/o test joint and retest VBR's-test ok. Function test hydraulic and manual chokes. Rig down testing equipment,blow down all lines. Install wear bushing,install 4"elevators,and rig up to p/u d/p. Pick up dp and stand back in derrick. 01/11/2013-Friday P/U&RIH w/60 jts of 4'DP. POOH&rack back in Derrick. Drift w/2.437 drift. M/U 4-3/4"directional BHA w/HCC PDC Bit. 1.18 Motor&MWD w/D&I,plus Gamma Ray. P/U&RIH with(6)HWDP,Jars and(13)HWDP.Test MWD. Continue to single in the hole with 4"DP f/746'1/6,140',p/u 114k,s/o 112k. Calibrate block hight f/MWD. Load pipe shed with 140 jts 4"DP and strap. Continue to single in the hole with 4"DP F/6,140'T/top of cement @ 9,829. Break circulation and displace 13.1 mud with 9.5 mud @ 3 bpm.ICP=1,400 psi and increased to 2,400 psi.Increase pump rate as pressure diminished.FCP= 1400 psi @ 6 bpm. Rig site visit and tour by EPA and Hilcorp/Doyon Environmental reps. 01/12/2013-Saturday Circ&Cond @ 9,829'to balance system. No signal f/MWD.6 bpm,1400 psi. Pressure Test Casing to 3,000 psi for 30 minutes. Bled 50 psi in 30 min. Clean out cement f/9,829'to top of Float Collar @ 10,017'. Drill shoe track,plus 20 ft of formation to 10,130'(30 min to drill Flt Clr,10 min to drill Shoe). Regained MWD signal while drilling Float Collar. Drill formation from 10,110'to 10,130'.5k WOB,7.2 bpm,1,800 psi. CBU to balance mud system @ 9.6 ppg.7.5 bpm,1,900 psi. Lay do sgl&RU for FIT. F.I.T 7-5/8"casing shoe to 12.0 ppg EMW. TD 10,130',TVD 9,966',Shoe 10,104'. Test MW 9.6 ppg, Test pressure 1,250 psi.Pressure bled 0 psi in 10 min. R/D test equipment and blow down lines. Clear floor of slip/trip hazards. Make connection and pump up Survey. Drill 6-3/4"production hole as per Directional Program 1/10,130',t/10,179'. Driller detected flow during connection.Note:MWD rep.reported GR identified exit of casing shoe @ 10,106.5'. CBU t/evaluate cause of flow. 277 units @ B/U&no pit gain. Mud has a few heavy spots,so suspect flow from u-tube effect. Drill f/10,179'T/10,479'-300'@ 66 ft/hr,u/p 190k,s/o 160k,rt wt 165k,gpm 285,1980 psi on bottom,Hrs on bit 6.8,hrs on jars 6.3,ART 6.3,AST.5 h. Weight up mud F/9.6 ppg T/9.7 ppg while drilling. Drill F/10,479'T/10,725',rt wt 170k,p/u 195k,s/o 160k,spp 2,020 psi,wob 3/5k,torq off bottom 4.7 RPM 53,305 gpm,jar hrs 9.9,mtr hrs 11. 01/13/2013-Sunday Drill 6-3/4"Production Hole as per Directional Plan f/1.0,725't/10,904'. Mud Logger reported seeing 100%fluorescents in samples starting 1/10,740'. UP 197k,DN 163k,R 175k,7.4 bpm,2250 spp,40 RPM,5.4k tq. Continue to gain 6-7 bph from charged water zone. Drill 6-3/4"Production Hole as per Directional Plan 1/10,904't/11,195'. P/u 206k,s/o 168k,rt wt 177k, Torq on bot 6k,torq off bott 4.5,wob 14k, Bit hrs 25.2,Jar hrs 22.5,motor hrs 38.5;Drill 6-3/4"Production Hole as per Directional Plan F/11,195'T/11,260'. 01/14/2013-Monday Drill 6-3/4"Production Hole to TD from 11,260'to 11,320'.Pump up final survey,CBU and begin increasing MW f/9.8 ppg to 10.3 ppg. 235 units of gas f/Survey B/U. Flow check Well w/10.3 ppg returns. Well flowing. Increase MW 1/10.3 ppg,t/10.8 ppg. 177 units of gas f/previous flow check. Flow check Well w/10.8 ppg returns. Well flowing. L/D Sgl.Increase MW f/10.8 ppg,t/11.2 ppg.87 units f/previous flow check. Flow check Well w/11.2 returns.Well flowing. Increase MW 1/11.2 ppg, t/11.4+ppg. 16 units gas f/previous flow check. Flow check Well w/11.4+returns. No Flow. Short trip f/11,311't/10,104'. Hole in excellent condition.No overpulls. UP 195k,DN 162k,R 175k,Hole took 2.2 bbls over calc displ on trip to shoe,Service Rig. Changed cylinder on Link Tilt. Trip in hole,no fill on bottom,pump sweep,circulate surface to surface @ 285 gpm, 2,450 psi,lost 8 bbls while circulating,reduce gpm to 225. Trip out of hole F/11,310'T/3,000'f/open hole logs. Injected 750 bbls mud. 01/15/2013-Tuesday Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 14B-27 50-133-20604-00 212-089 12/2/12 Daily Operations: 01/16/2013-Wednesday TIH from 9,000'to 11,320'. Hole in good condition. 5'of fill on bottom.Pump high Vis Sweep and circulate to surface.(no increase in solids from sweep)517 units of gas 1,700 stks prior to B/U(77.5 bbls)No gas @ B/U. Lost 2.5 bbls during circulation. Flow check Well.(Well flowing)L/D Single. Circulate additional Dp vol. Monitor Well(flowing @.9 bph). POOH 5 stands from 11,311'to 11,000'. Flow check Well(flowing). Continue POOH to Shoe. Open Hole in good condition but trying to Differential Stick on 1st 3 stds out of slips. 35k Max to break over out of slips. Remainder of OH in good condition. Monitor Well for 1 hr. Measured.5 bph flow to Trip Tank. Pump slug,blow down TD. POOH from 10,104'to 617'(BHA) SLM trip out. Rack back HWDP. B/D Bit,Bit Sub&Stab. The wellbore showed a 4 bbl over hole fill on the first 30 stand. Once out of the hole the well bore took 2.4 bbls over calc.fill. Slight Flow. Strap out was 1.09'different than drilling pipe tally. Clear floor. R/U Weatherford Casing equipment&prep to P/U Prod.Liner. P/U shoe jt.and check threads,screw together safety valve and cross-over. P/u shoe track,float and landing collar,fill with mud and check float. Run the 5"15# L-80 DWC/C-HT casing as per plan filling each jt.w/fill up hose. P/U casing hanger and make up as per Baker rep. P/U one joint of HWDP and break circulation pumping the 5"casing volume and checking parameters 45k up wt and 44 dwn wt,back out topdrive and blow down same. Trip in with 5"casing on drillpipe filling every 10 stds.to 2,000'. 01/17/2013-Thursday TIH with 5"Production Liner on 4"Dp from 2,000'to Casing Shoe @ 10,104'. 1-1/2"min Slip to Slip. Fill pipe every 10 stands. Break circulation @ casing Shoe(10,104')and CBU to clear possible influx.UP 168k,DN 148k,3 bpm 450 psi,4 bpm 660 psi,5 bpm 890 psi. 10 RPM 3,500 tq,20 RPM 3,700 tq,30 RPM 3,800 psi. Release tq.Blow down TD. Change Dies in TD Grabber. M/U 10'pup to Cmt Head and L/D same. Lost 2.5 bbls. TIH from 10,104'to 11,295'.(hole in good condition) M/U single and Cmt Hd. Break Circ and wash down to TD. Tag @ 11,322'. Circulate&condition through TD while making up Cement&Washup line to Cmt Hd. Build 45 bbl 13.5 ppg Mud Push II.Establish rotation @ 10 RPM,5k tq. Pump 10 bbls water,Pressure test lines to 1,000/5,000 psi. Bleed pressure. Pump 33 bbls mud push @ 13.5 ppg. Start pumping cement @ 15.3 ppg pumping 2.6 bpm psi up and down,switch pumping unit to steady pressure 20 bbls away at 3.8 bpm,350 psi, 5,i 15.6 ppg. At 39 bbls away change silos 40 to 80 bbls away pumping an average of 4.0 bpm @ 350 psi and 15.4 wt. Shut Down and wash out lines,drop wiper plug and displace cement at 5 bpm with 300 psi,caught cement at 58 bbls pumped, 700 psi @ 5 bpm at 80 bbls displacement psi increased to 1400 psi. Slowed pumps to 3 bpm at 95 bbls displaced 1,350 psi. Did not see wiper plug latch. 115 bbls into displacement slow pump rate to 2.5 bpm with 1,200 psi. Bump plug @ 125.2 bbls. Calculated displacement @ 126 bbls. Bump plug with 500 psi over circulating psi @ 1,700 psi. Hold psi for 3 min, bleed back and check floats,floats are holding 3/4 bbl bleed back. CIP @ 00:10. No losses to formation during displacement. Pressure up to 3,000 psi,increase psi to 4,200 psi,bleed psi liner hanger did not set. On third attempt set liner hanger @ 11,322'. Attempt to release the running tool hydraulically,would not release.Secondary release with 6 turns to the left @ 7k lbs of torque. Pressure up to 600 psi aginst packoff and pick up and establish circulation. Circ B/U @ TOL cleaning excess cement. At bottoms up got 33 bbls mud push and 14 bbls cement. Test liner top packer to 1,000 psi for 5 min. Circulate and condition,pump dry job. Trip out laying excess drill pipe at the depth of 10,500'. 01/18/2013-Friday POOH from 10,705'to 10,050',laying down Dp. POOH from 10,050'. Break and lay down Baker Running Tool. Dog Sub sheared indicating good weight transfer to Liner Top Packer. Full recovery&no indication of damage. Break down Cement Head and Pup. Clear rig floor of excess tools. Transport mud from pits to G&I facility for injection. Clean Pits and prep for displacement. Build containment and spot(2)R4R tanks for building KCL Brine. Conduct Rig Evacuation Drill. Electrician tripped H2S alarm w/pusher monitored response. Pull wear bushing and install test plug,R/U to test rams and Hydrill w/2- 7/8". Test variable rams with 2-7/8"test joint and Hydril bag with same to 250 psi low and 4,250 psi high for 10 min on each test. Rig down test equipment and install wear bushing. Rig up Weatherford power tongs for the 2-7/8"PH-6 drill pipe scraper run. Pick up scraper assembly and 42 jts of 2-7/8"PH-6 drill pipe and trip in. Rig down Weatherford casing tongs and change out elevators for 4"DP. Pick up next Multi Back Combo scraper and trip in with 4"DP from derrick. Running multi Scraper assembly,bottom scraper cleaning the 5"casing. Middle scraper will clean the 7-5/8"casing,when mill reaches landing collar the 7-5/8"multi combo scraper assembly will be 25'above liner top. Third multi combo scraper is 4,900'up. Down Time working on Topdrive. 01/19/2013-Saturday • M/U 2 7/8 PH-6 x 3 1/2 IF XO.P/U bottom 7 5/8"Multi-back Combo tool.;RIH w/4"Dp from drk to 6266.UP 98k,DN 94k. P/U upper 7 5/8"Multi-Back tool.;Continue TIH from 6266 to 9880;Rig up test equipment and pressure test 7 5/8 casing and Liner Lap to 3000 psi;from 30 min.Monitor 7 5/8 x 10 3/4"Annulus during test.Pressure Sensor failed;during test. Repeat test.(25 psi bleed in 30 min);Pressure test Doyon 5M Mud System to satisfy Preventative Maintenance schedule; TIH from 9880.Tag Cement @ 11171.(No tag entering TOL)Re-calculate pipe tally to;verify tag depth.;Clean out cement from 11171 to 11177.Report progress to Drilling Engineer.;Decision made to leave PBTD @ 11,177.Continue to circ&hold PJSM from displacement;Shut down pumping drilling mud and switch to fresh water from frac tanks;Displace wellbore with fresh water working drillstring and rotating@5bpm;Trip out wiping both strings of casing with Multi Combo scraper to 6325';Trip back to bottom,slowing down and running slow through the liner top.;PJSM and start circulating and displacing the wellbore with clean fresh water,;sweeps and KCL water 01/20/2013-Sunday Circulate Fresh Water to clean Well Bore.;Pump Casing Wash Pill Train:45 bbl Caustic,50 bbl Barakleen and 60 bbl Barazan ;Displace Pill Train with filtered 6%KCL water.Pump @ 5 bpm until Caustic;reached Bit.Reduce rate to 3 bpm the remainder of circulation for contact time.;Build an additional 180 bbls of KCL and continue to flush system to better clean; fluid.Final NTUs @ flowline=148.Blow down system and outside transfer hoses.;POOH from 11177 laying down 4"Dp.; Offline:Drain R4R transfer pump and filter skid.Move R4R KCL tanks off;location and R/D containment.Remove excess equipment and product from site.;R/D and reconfigure office trailers to make room for Rig move.;Clear rig floor and Rig up weatherford tongs;Lay down the 2 7/8"PH-6 drill pipe,Combo Scraper and Bit;Load pipe shed with 2 7/8"tubing and strap same;Pick up 2 7/8"tubing for kill string 01/21/2013-Monday P/U and RIH with 2-7/8" Kill String to 1299.29'.(40)joints,6.5#,L-80. M/U Hanger&Landing Joint. Land Hanger&RILDS. L/D Landing Joint. Install BPV. R/D drip pan and Flow Nipple. Open Ram Doors and clean cavities. Change lower Rams from 4"to 5". Lube and torque doors. ND BOP and related equipment. Off Line: change liners in Mud Pumps to 6". Finish cleaning pits and hauling fluid to G&I. Thaw and remove dirt pile to widen pad entrance for rig access. Move out Cuttings Tank and Mud Lab. Aimm crew cleaning R4R tanks @ G&I(25%complete). Install Single Valve"Temporary"Tree. Pump 10 bbls of diesel down tubing to Freeze Protect Well.(22'coverage on Annulus) Continue to Rig Down equipment in preparation for A.M.Rig Move. Remove bails and elevators,prep auger for removal,perpare pit system for move. Release rig at Midnight. 01/22/2013-Tuesday Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 14B-27 50-133-20604-00 212-089 12/2/12 Daily Operations: 03/13/2013-Wednesday No activity to report. 03/14/2013-Thursday No activity to report. 03/15/2013-Friday No activity to report. 03/16/2013-Saturday No activity to report. 03/17/2013-Sunday MIRU Williams 405 WOR,ND Wellhead and NU Bop's. Finished Rigging up work-over rig and equipment tested 11"BOP to 250 low/3000 high,annular 250 low/1500 high. Tested 10 min. Witness waived by Jim Regg,AOGCC. 03/18/2013-Monday MIRU SL,swabbed well down to 1,100'. RDMO SL. LID 40 jts.of 2-7/8"tbg. MIRU EL. RIH w/6"GR to liner top @ 9,891'. POOH. RIH w/Halliburton CAST-M tool and logged(9,891'to 2,950'). 03/19/2013-Tuesday Logged 5-1/2"csg from 11,165'-9,800'. PU 3-3/8"HC 6 spf,correlated and perf(10,886'-10,898'). All shots fired. PU 3-3/8" HC 6 spf,correlated and perf T10,859'-10,880'). All shots fired. PU 3-3/8"HC 6 spf,correlated and perf(10,854'-10,859'). All shots fired. PU Completion and TIH w/84 jts of 2-7/8"EUE TBG and report time. Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SRU 146-27 50-133-20604-00 212-089 12/2/12 V y C3perations: 1 NO1 03/20/2013-Wednesday TIH w/completion string,set packer @ 9,868'.Tested TBG/CSG 3000psi.ND/NU PT. MIRU SL, RIH and pulled drop bar and FAA test plug. RDMO SL. MDMO Williams WOR 405. 03/21/2013-Thursday Well turned over to production 03/22/2013-Friday No activity to report. 03/23/2013-Saturday No activity to report. 03/24/2013-Sunday No activity to report. 03/25/2013-Monday No activity to report. 03/26/2013-Tuesday No activity to report. Hilcorp Energy Company CASING &CEMENTING REPORT Lease&Well No. 14B-27 Date 9-Dec-12 County Kenai Peninsula Burough State Alaska Supv. Jimmy Greco CASING RECORD _ S�cr-P-e—c- Cis' : TD 2980'MD/2912'TVD Shoe Depth: 2961'MD/2912'TVD PBTD: MD/ TVD Casing(Or Liner)Detail Setting Depths No.of Jts. Size Wt. Grade THD Make Length Bottom Top Shoe/jt 10 3/4 STL Wfd 42.96 2,978.00 2,935.04 1 10 3/4 54.5 L-80 BTC 41.81 2,935.04 2,893.23 F.Collar/jt 10 3/4 STL Wfd 42.52 2,893.23 2,850.71 69 jts 10 3/4 54.5 L-80 BTC 2,808.78 2,850.71 41.93 L Hanger BOT 6.31 41.93 35.62 landing jt 22.81 35.62 12.81 Totals 2,965.19 Csg Wt.On Hook: 145,000 Type Float Collar: Float No.Hrs to Run: 9 Csg Wt.On Slips: Type of Shoe: DJ/Float Casing Crew: Wfd Fluid Description: 10.2 ppg WBM / Spud Mud / PV=41 YP=54 HTHP=0 Liner hanger Info(Make/Model): Liner top Packer?: Yes X No Liner hanger test pressure: Centralizer Placement: centralizers on every joint in shoe track,every other joint to 300' /3•So CEMENTING REPORT Preflush(Spacer) Type: Mud Push II Density(ppg) 10.5 Volume pumped(BBLs) 40 Lead Slurry Type: Extended Type1 Blend Yield: 2.44 ft3/sk Density(ppg) 12.0 ppg Vol pumped(BBLs/sx) 330 bbls/759 sx Mixing/Pumping Rate(bpm): 4.5 Tail Slurry Type: Conventional Type 1 Blended Yield: 1.22 ft3/sk Density(ppg) 15.4 ppg Vol pumped(BBLs/sx) 80 bbls/368 sx Mixing/Pumping Rate(bpm): 4.8 bpm I- Post Flush(Spacer) Type: Density(ppg) Rate(bpm): Volume: cc IL Displacement: Type: Mud Density(ppg) 10.2 ppg Rate(bpm): 8 bpm Volume(actual/ca ted): 266/260 FCP(psi): 870 psi Pump used for disp: Rig pumps Plug Bumped? Yes No Bump press 0 Casing Rotated? Yes X No Reciprocated? X Yes No %Returns during job 100 Cement returns to surface? X Yes No Spacer returns? X Yes No Vol to Surf: 46 bbl cmt/20 bbl spacer Cement In Place At: 20:30 Date: 12/10/2012 Estimated TOC: Surface Method Used To Determine TOC: 12.4 ppg Cement sample taken&weighed @ surface Preflush(Spacer) Type: Density(ppg) Volume pumped(BBLs) Lead Slurry Type: Density(ppg) Volume pumped(BBLs) Mixing/Pu •_' g Rate(bpm): Tail Slurry w Type: — Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): u) Post Flush(Spacer) 0 o Type: Density(ppg Rate(bpm): Volume: w• Displacement: 0) Type: Density(ppg) Rat, bpm): Volume(actual/calculated): FCP(psi): Pump used for disp: Plug Bumped? Yes No Bump press Casing Rotated? Yes No R: iprocated? Yes No %Returns during job • Cement returns to surface? Yes No Spacer returns?_Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: WELLHEAD Make Seaboard Type Multibowl Serial No. Size 11" W.P. 5M Test Head To 3000 PSIG 30 MIN OK Remarks: II CASING RUN IN TALLY WELL NAME: SCU 14B-27 DATE: 12/09/12 CASING SIZE 10.750 WEIGHT 45.50 CASING ID 9.950 GRADE L-80 THREAT BTC CAPACITY 0.0962 bbls/ft TORQUE - MAXIMUM = MIN= 10,750 DISPLACEMENT 0.0046 bbls/ft SHOE DEPTH 2961.0 feet Coupling OD= HOLE TD 2980.0 feet Pin ID =9.95 MUD WT 10.20 ppg Joint Running Joint Depth BOUY FACTOR 0.85 Joint# Joint# Length Total Bottom Top REMARKS Bouyant Capacit)Displmt on Rack in hole feet feet feet feet weight bbls bbls nrr rznttnro 2.00 Block Weight = 65,000 Weatherford Bullnose 1 42.96 42.96 2961.00 2918.04 Float Shoe. 66,669 4.1 0.2 BakerLocked Joint 'entrilizer w/stop ring 11 2 41.81 84.77 2918.04 2876.23 from shoe 68,294 8.2 0.4 Baker Locked Joint 3 42.52 127.29 2876.23 2833.71 w/Centralizer Mid-joint 4 41.15 168.44 2833.71 2792.56 Weatherford Float Collar 69,893 12.1 0.6 Baker Locked Joint 5 41.81 210.25 2792.56 2750.75 w/Centralizer Mid-joint 71,517 16.1 0.8 6 6 41.87 252.12 2750.75 2708.88 71,520 16.1 0.8 7 7 39.83 291.95 2708.88 2669.05 Joint w/centralizer#4 73,067 20.0 1.0 8 8 40.91 332.86 2669.05 2628.14 73,109 20.1 1.0 9 9 39.79 372.65 2628.14 2588.35 Joint w/centralizer#5 74,656 23.9 1.1 10 10 41.50 414.15 2588.35 2546.85 74,722 24.1 1.1 11 11 40.97 455.12 2546.85 2505.88 Joint w/centralizer#6 76,314 28.0 1.3 12 12 41.79 496.91 2505.88 2464.09 76,346 28.1 1.3 13 13 41.78 538.69 2464.09 2422.31 Joint w/centralizer#7 77,969 32.1 1.5 14 14 38.45 577.14 2422.31 2383.86 77,840 31.8 1.5 15 15 40.68 617.82 2383.86 2343.18 Joint w/centralizer#8 79,421 35.7 1.7 16 16 40.92 658.74 2343.18 2302.26 Joint 79,430 35.7 1.7 17 17 40.52 699.26 2302.26 2261.74 Joint w/centralizer#9 81,004 39.6 1.9 18 18 42.11 741.37 2261.74 2219.63 Joint 81.066 39.8 1.9 19 19 42.07 783.44 2219.63 2177.56 Joint vv/centralizer#10 82,701 43.8 2.1 20 20 40.96 824.40 2177.56 2136.60 82.658 43.7 2.1 21 21 39.77 864.17 2136.60 2096.83 Joint w/centralizer#11 84,203 47.5 2.3 22 22 40.65 904.82 2096.83 2056.18 84,237 47.6 2.3 23 23 40.62 945.44 2056.18 2015.56 Joint w/centralizer#12 85,816 51.5 2.5 24 24 39.87 985.31 2015.56 1975.69 85,787 51.4 2.5 25 25 39.05 1024.36 1975.69 1936.64 Joint vv/centralizer#13 87,304 55.2 2.6 26 26 30.35 1054.71 1936.64 1906.29 86.966 54.4 2.6 27 27 40.19 1094.90 1906.29 1866.10 Joint w/centralizer#14 88,528 58.2 2.8 28 ' 41.99 1136.89 1866.10 1824.11 88,597 58.4 2.8 29 29 40.80 1177.69 1824.11 1783.31 Joint w/centralizer#15 90,183 62.3 3.0 30 30 40.54 1218.23 1783.31 1742.77 90,173 62.3 3.0 31 31 40.50 1258.73 1742.77 1702.27 Joint w/centralizer#16 91,746 66.2 3.2 32 32 39.79 1298.52 1702.27 1662.48 91,719 66.1 3.1 33 33 40.26 1338.78 1662.48 1622.22 Joint w/centralizer#17 93,283 70.0 3.3 34 34 42.20 1380.98 1622.22 1580.02 93,359 70.2 3.3 35 35 41.73 1422.71 1580.02 1538.29 Joint w/centralizer#18 94,980 74.2 3.5 36 36 40.30 1463.01 1538.29 1497.99 94,925 74.1 3.5 37 37 40.24 1503.25 1497.99 1457.75 Joint w/centralizer#19 96,544 78.1 3.7 38 38 39.76 1543.01 1457.75 1417.99 96,470 77.9 3.7 39 39 40.52 1583.53 1417.99 1377.47 Joint w/centralizer#20 98,118 82.0 3.9 40 40 41.51 1625.04 1377.47 1335.96 98,082 81.9 3.9 41 41 - 41.87 1666.91 1335.96 1294.09 Joint w/centralizer#21 99,745 86.0 4.1 6.75 3urfKe Cas tilly_FlgV,5 7" ptraity 1254.65 9 /' / G1§5'71:2.0 14JI Joint Ru Joint Depth BO' ACTOR 0.85 Joint# Joint# Length Total Bottom Top REMARKS Bouyant Capacity Displmt on Rack in hole feet feet feet feet weight bbls bbls 43 43 41.02 1747.37 1254.65 1213.63 Joint w/centralizer#22 101,339 89.9 4.3 44 44 39.95 1787.32 1213.63 1173.68 101,167 89.5 4.3 45 45 40.78 1828.10 1173.68 1132.90 Joint w/centralizer#23 102,924 93.9 4.5 46 46 40.80 1868.90 1132.90 1092.10 102,753 93.4 4.4 47 47 41.25 1910.15 1092.10 1050.85 Joint w/centralizer#24 104,527 97.8 4.7 48 48 40.44 1950.59 1050.85 1010.41 104,324 97.3 4.6 49 49 40.72 1991.31 1010.41 969.69 Joint w/centralizer#25 106,109 101.7 4.8 50 50 40.73 2032.04 969.69 928.96 105,907 101.2 4.8 51 51 41.85 2073.89 928.96 887.11 Joint w/centralizer#26 107,735 105.8 5.0 52 52 41.40 2115.29 887.11 845.71 107,515 105.2 5.0 53 53 39.70 2154.99 845.71 806.01 Joint w/centralizer#27 109,278 109.6 5.2 54 54 42.10 2197.09 806.01 763.91 109,151 109.3 5.2 55 55 41.84 2238.93 763.91 722.07 Joint w/centralizer#28 110,903 113.6 5.4 56 56 41.82 2280.75 722.07 680.25 110,776 113.3 5.4 57 57 41.94 2322.69 680.25 638.31 Joint w/centralizer#29 112,533 117.6 5.6 58 58 38.83 2361.52 638.31 599.48 112,285 117.0 5.6 59 59 41.58 2403.10 599.48 557.90 Joint w/centralizer#30 114,149 121.6 5.8 60 60 41.95 2445.05 557.90 515.95 113,915 121.1 5.8 61 61 40.90 2485.95 515.95 475.05 Joint w/centralizer#31 115,738 125.6 6.0 62 62 40.88 2526.83 475.05 434.17 115,504 125.0 6.0 63 63 38.05 2564.88 434.17 396.12 Joint w/centralizer#32 117,216 129.2 6.2 64 64 41.22 2606.10 396.12 354.90 117,105 129.0 6.1 65 65 40.83 2646.93 354.90 314.07 Joint w/centralizer#33 118,803 133.2 6.3 66 66 40.73 2687.66 314.07 273.34 118,688 132.9 6.3 67 67 40.72 2728.38 273.34 232.62 120,385 137.1 6.5 68 _ 68 41.10 2769.48 232.62 191.52 120,285 136.8 6.5 69 69 38.81 2808.29 191.52 152.71 121,893 140.8 6.7 70 70 41.73 2850.02 152.71 110.98 121,906 140.8 6.7 71 71 39.80 2889.82 110.98 71.18 123,440 144.6 6.9 72 72 41.42 2931.24 71.18 29.76 123,516 144.8 6.9 71 71 0.00 2931.24 29.76 29.76 123,440 144.6 6.9 72 0.00 2931.24 29.76 29.76 123,516 144.8 6.9 73 0.00 2931.24 29.76 29.76 123,440 144.6 6.9 74 0.00 2931.24 29.76 29.76 123,516 144.8 6.9 75 0.00 2931.24 29.76 29.76 123,440 144.6 6.9 76 Hanger 6.31 2937.55 29.76 23.45 123,761 145.4 6.9 77 RKB 23.14 2960.69 23.45 0.31 78 79 ,anding,j 22.81 80 80 40.10 40.49 38.58 40.95 40.57 10.75 Surface Casing Tally_FINAL 7" casing tally 4/19/2013 1:20 PM Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. 14B-27 Date County Kenai Peninsula Burough State Alaska Supv. Mike Leslie CASING RECORD ice, 10<_f i'.i+/l - ")-}- TD 10110'MD/9946'TVD Shoe Depth: 1111106'MD/9446'TVD PBTD: MD/'TVD Casing(Or Liner)Detail Setting Depths No.of Jts. Size Wt. Grade THD Make Length Bottom Top Shoe 7 5/8 STL Wfd 1.62 10,103.81 10,102.19 2 7 5/8 29.7 P110 LTC 83.00 10,102.19 10,019.19 F.Collar 7 5/8 STL Wfd 1.22 10,019.19 10,017.97 40 7 5/8 29.7 P110 LTC 1,665.64 10,017.97 8,352.33 XO JT 7 5/8 29.7 P110 LTC/BTC BOT 40.48 8,352.33 8,311.85 30 7 5/8 29.7 P110 BTC 1,218.69 8,311.85 7,093.16 • 171 7 5/8 29.7 L-80 BTC BOT 7,033.54 7,093.16 59.62 PUPS X3 7 5/8 29.7 L-80 BTC 37.97 59.62 21.65 HANGER 7 5/8 L-80 BTC 1.35 21.65 20.30 Totals 10,083.51 20.30 -10,063.21 Csg Wt.On Hook: 248k Type Float Collar: Float No.Hrs to Run: 19 Csg Wt.On Slips: Type of Shoe: DJ/Float Casing Crew: Wfd Fluid Description: 13.1 ppg WBM / 6%KCI/PHPA / PV=12 YP=21 HTHP=10.4 Liner hanger Info(Make/Model): Liner top Packer?: Yes X No Liner hanger test pressure: Centralizer Placement: 4 �« 0t CEMENTING REPORT Preflush(Spacer) Type: Mud Push II Density(ppg) 13.5 Volume pumped(BBLs) 50 bbls Lead Slurry Type: Conventional Class G Blended Yield: 1.58 ft3/sk Density(ppg) 14 Vol pumped(BBLs/sx) 275 bbls/977 sx Mixing/Pumping Rate(bpm): 3.5 bpm Tail Slurry Type: Conventional Class G Blended Yield: 1.35 ft3/sk 1 Density(ppg) 15.3 ppg Vol pumped(BBLs/sx) 80 bbls/332 sx Mixing/Pumping Rate(bpm): 3.5 bpm 1- Post Flush(Spacer) Type: Density(ppg) Rate(bpm): Volume: e: I Displacement: Type: Mud Density(ppg) 13.1 ppg Rate(bpm): 6 bpm Volume(actual/c.culated): 457/455 FCP(psi): 1070 psi Pump used for disp: Rig pump Plug Bumped? Ye 11310 No Bump press 0 Casing Rotated? Yes X No Reciprocated? Yes X No %Returns during job 100 Cement returns to surface? Yes x No Spacer returns? X Yes No Vol to Surf: 25 bbl spacer Cement In Place At: 3:50 Date: 1/9/2013 Estimated TOC: 3,586 Method Used To Determine TOC: Calcuations based on mud loggers carbide sweep-(10.6 open hole dia) Preflush(Spacer) Type: Density(ppg) Volume pumped(BBLs) Lead Slurry Type: _ Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tail Slurry Type: LI, a Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): 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: WELLHEAD Make Type Serial No. Size W.P. Test Head To PSIG MIN OK Remarks: CASING RUN IN TALLY WELL NAME: SRU 14B-27 DATE: 01/07/13 CASING SIZE 7.625 inches WEIGHT 29.70 ppf CASING ID 6.875 inches GRADE L- 80 P-110 THREAD BTC<C CAPACITY 0.0459 bbls/ft TORQUE - OPTIMUM = MIN=7800 DISPLACEMENT 0.0108 bbls/ft SHOE DEPTH 10103.81 feet HOLE TD 10110.00 feet Foremen: Pederson/Leslie/Greco MUD WT 13.10 ppg Joint Running Joint Depth BOUY FACTOR 0.80 Joint# Joint# Length Total Bottom _ Top REMARKS: Bouyant Capacity Diselmt on rack in hole feet feet feet feet Run 45 centralizers weight bbls bbls Off Bottom=> 6.19 Block Weight => 25,000 A Shoe 1.62 1.62 10103.81 10102.19 Weatherford 25,038 0.1 0.0 313 1 41.58 43.20 10102.19 10060.61 P-110 LTC(centra) 26,026 2.0 0.5 312 2 41.42 84.62 10060.61 10019.19 P-110 LTC(centra) 27,011 3.9 0.9 B Flt Clr 1.22 85.84 10019.19 10017.97 Weatherford 27,040 3.9 0.9 311 3 41.62 127.46 10017.97 9976.35 P-110 LTC(centra) 28,028 5.9 1.4 310 4 41.66 169.12 9976.35 9934.69 P-110 LTC 29,018 7.8 1.8 309 5 41.45 210.57 9934.69 9893.24 P-110 LTC(centra) 30,003 9.7 2.3 308 6 41.83 252.40 9893.24 9851.41 P-110 LTC 30,997 11.6 2.7 307 7 41.42 293.82 9851.41 9809.99 P-110 LTC(centra) 31,981 13.5 3.2 306 8 41.66 335.48 9809.99 9768.33 P-110 LTC 32,971 15.4 3.6 305 9 41.75 377.23 9768.33 9726.58 P-110 LTC(centra) 33,963 17.3 4.1 304 10 41.59 418.82 9726.58 9684.99 P-110 LTC 34,951 19.2 4.5 303 11 41.93 460.75 9684.99 9643.06 P-110 LTC(centra) 35,947 21.2 5.0 302 12 41.67 502.42 . 9643.06 9601.39 P-110 LTC 36,937 23.1 5.4 301 13 41.80 544.22 9601.39 9559.59 P-110 LTC(centra) 37,931 25.0 5.9 300 14 42.20 586.42 9559.59 9517.39 P-110 LTC 38,933 26.9 6.3 299 1.5 .41.97 628.39 9517.39 9475.42 P-110 LTC(centra) 39,931 28.9 6.8 298 16 41.49 669.88 9475.42 9433.93 P-110 LTC 40,916 30.8 7.2 297 17 41.78 711.66 9433.93 9392.15 P-110 LTC(centra) 41,909 32.7 7.7 296 18 41.80 753.46 9392.15 9350.35 P-110 LTC 42,902 34.6 8.1 295 19 41.73 795.19 9350.35 9308.62 P-110 LTC(centra) 43,894 36.5 8.6 294 20 41.81 837.00 9308.62 9266.81 P-110 LTC 44,887 38.4 9.0 293 21 41.50 878.50 9266.81 9225.31 P-110 LTC(centra) 45,873 40.3 9.5 292 22 41.70 920.20 9225.31 9183.61 P-110 LTC 46,864 42.3 9.9 291 23 41.88 962.08 9183.61 9141.73 P-110 LTC(centra) 47,859 44.2 10.4 290 24 41.93 1004.01 9141.73 9099.80 P-110 LTC 48,855 46.1 10.9 289 25 41.61 1045.62 9099.80 9058.19 P-110 LTC(centra) 49,844 48.0 11.3 288 26 40.98 1086.60 9058.19 9017.21 P-110 LTC 50,818 49.9 11.7 287 27 42.41 1129.01 9017.21 8974.80 P-110 LTC(centra) 51,825 51.8 12.2 286 28 41.04 1170.05 8974.80 8933.76 P-110 LTC 52,800 53.7 12.6 285 29 41.74 1211.79 8933.76 8892.02 P-110 LTC 53,792 55.6 13.1 284 30 41.66 1253.45 8892.02 8850.36 1 P-110 LTC 54,782 57.6 13.5 283 31 41.60 1295.05 8850.36 8808.76 2 P-110 LTC(centra) 55,770 59.5 14.0 282 32 38.08 1333.13 8808.76 8770.68 3 P-110 LTC 56,675 61.2 14.4 281 33 41.41 1374.54 8770.68 8729.27 4 P-110 LTC 57,659 63.1 14.9 280 34 42.77 1417.31 8729.27 8686.50 5 P-110 LTC 58,675 65.1 15.3 279 35 41.70 1459.01 8686.50 8644.80 6 P-110 LTC(centra) 59,666 67.0 15.8 278 36 41.71 1500.72 8644.80 8603.09 7 P-110 LTC 60,657 68.9 16.2 277 37 41.74 1542.46 8603.09 8561.35 8 P-110 LTC 61,649 70.8 16.7 276 38 41.68 1584.14 8561.35 8519.67 9 P-110 LTC 62,639 72.7 17.1 • 275 39 41.95 1626.09 8519.67 8477.72 10 P-110 LTC(centra) 63,636 74.7 17.6 274 40 41.78 1667.87 8477.72 8435.94 11 P-110 LTC 64,629 76.6 18.0 273 41 41.80 1709.67 8435.94 8394.14 12 P-110 LTC 65,622 78.5 18.5 272 42 41.81 1751.48 8394.14 8352.33 13 P-110 LTC 66,615 80.4 18.9 271 43 40.48 1791.96 8352.33 8311.85 XO Joint(centra) 67,577 82.3 19.4 270 44 42.03 1833.99 8311.85 8269.82 1 P-110 BTC 68,576 84.2 19.8 269 45 41.50 1875.49 8269.82 8228.32 2 P-110 BTC 69,562 86.1 20.3 268 46 39.09 1914.58 8228.32 8189.23 3 P-110 BTC 70,490 87.9 20.7 267 47 39.90 1954.48 8189.23 8149.33 4 P-110 BTC(centra) 71,438 89.7 21.1 Joint F rig Joint Depth B01 1CTOR 0.80 Joint# Joint# Length 't otal Bottom Top REMARKS: Bouyant Capacity Displmt on rack in hole feet feet feet feet Run 45 centralizers weight bbls bbls 266 48 40.73 1995.21 8149.33 8108.60 5 P-110 BTC 72,406 91.6 21.6 265 49 41.57 2036.78 8108.60 8067.03 6 P-110 BTC 73,394 93.5 22.0 i 264 50 40.05 2076.83 8067.03 8026.98 7 P-110 BTC 74,345 95.4 22.5 263 51 41.82 2118.65 8026.98 7985.16 8 P-110 BTC(centra) 75,339 97.3 22.9 262 52 39.51 2158.16 7985.16 7945.65 9 P-110 BTC 76,278 99.1 23.3 261 53 41.66 2199.82 7945.65 7903.99 10 P-110 BTC 77,268 101.0 23.8 260 54 41.58 2241.40 7903.99 7862.41 11 P-110 BTC 78,256 102.9 24.2 259 55 41.18 2282.58 7862.41 7821.23 12 P-110 BTC(centra) 79,234 104.8 24.7 258 56 38.63 2321.21 7821.23 7782.60 13 P-110 BTC 80,152 106.6 25.1 257 57 40.99 2362.20 7782.60 7741.61 14 P-110 BTC 81,126 108.5 25.5 256 58 41.08 2403.28 7741.61 7700.53 15 P-110 BTC 82,102 110.4 26.0 255 59 41.16 2444.44 7700.53 7659.37 16 P-110 BTC(centra) 83,080 112.2 26.4 254 60 40.37 2484.81 7659.37 7619.00 17 P-110 BTC 84,039 114.1 26.9 253 61 39.49 2524.30 7619.00 7579.51 18 P-110 BTC 84,977 115.9 27.3 252 62 41.24 2565.54 7579.51 7538.27 19 P-110 BTC 85,957 117.8 27.7 251 63 39.99 2605.53 7538.27 7498.28 20 P-110 BTC(centra) 86,907 119.6 28.2 250 64 40.47 2646.00 7498.28 7457.81 21 P-110 BTC 87,869 121.5 28.6 249 65 41.35 2687.35 7457.81 7416.46 22 P-110 BTC 88,851 123.4 29.1 248 66 38.45 2725.80 7416.46 _ 7378.01 23 P-110 BTC 89,765 125.2 29.5 247 67 39.43 2765.23 7378.01 7338.58 24 P-110 BTC(centra) 90,702 127.0 29.9 246 68 41.15 2806.38 7338.58 7297.43 25 P-110 BTC 91,680 128.9 30.3 245 69 40.53 2846.91 7297.43 7256.90 26 P-110 BTC 92,643 130.7 30.8 244 70 41.62 2888.53 7256.90 7215.28 27 P-110 BTC 93,631 132.6 31.2 243 71 40.95 2929.48 7215.28 7174.33 28 P-110 BTC(centra) 94,604 134.5 31.7 242 72 40.42 2969.90 7174.33 7133.91 29 P-110 BTC 95,565 136.4 32.1 241 73 40.75 3010.65 7133.91 7093.16 30 P-110 BTC 96,533 138.2 32.5 240 74 40.05 3050.70 7093.16 7053.11 L-80 BTC 97,485 140.1 33.0 239 75 41.89 3092.59 7053.11 7011.22 L-80 BTC(centra) 98,480 142.0 33.4 238 76 40.42 3133.01 7011.22 6970.80 L-80 BTC 99,440 143.9 33.9 237 77 41.87 3174.88 6970.80 6928.93 L-80 BTC 100,435 145.8 34.3 236 78 39.71 3214.59 6928.93 6889.22 L-80 BTC 101,379 147.6 34.7 235 79 41.58 3256.17 6889.22 6847.64 L-80 BTC(centra) 102,367 149.5 35.2 234 80 41.09 3297.26 6847.64 6806.55 L-80 BTC 103,343 151.4 35.6 233 81 41.10 3338.36 6806.55 6765.45 L-80 BTC 104,319 153.3 36.1 232 82 41.62 3379.98 6765.45 6723.83 L-80 BTC 105,308 155.2 36.5 231 83 40.53 3420.51 6723.83 6683.30 L-80 BTC(centra) 106,271 157.1 37.0 230 84 41.10 3461.61 6683.30 6642.20 L-80 BTC 107,248 159.0 37.4 229 85 41.71 3503.32 6642.20 6600.49 L-80 BTC 108,239 160.9 37.9 228 86 41.82 3545.14 6600.49 6558.67 L-80 BTC 109,233 162.8 38.3 227 87 41.89 3587.03 6558.67 6516.78 L-80 BTC(centra) 110,228 164.7 38.8 226 88 39.57 3626.60 6516.78 6477.21 L-80 BTC 111,168 166.5 39.2 225 89 40.95 3667.55 6477.21 6436.26 L-80 BTC 112,141 168.4 39.6 224 90 40.08 3707.63 6436.26 6396.18 L-80 BTC 113,093 170.3 40.1 223 91 40.30 3747.93 6396.18 6355.88 L-80 BTC(centra) 114,051 172.1 40.5 222 92 40.95 3788.88 6355.88 6314.93 L-80 BTC 115,024 174.0 41.0 221 93 40.59 3829.47 6314.93 6274.34 L-80 BTC 115,988 175.8 41.4 220 94 39.15 3868.62 6274.34 6235.19 L-80 BTC 116,918 177.6 41.8 219 95 40.09 3908.71 6235.19 6195.10 L-80 BTC(centra) 117,871 179.5 42.3 218 96 39.34 3948.05 6195.10 6155.76 L-80 BTC 118,806 181.3 42.7 217 97 41.05 3989.10 6155.76 6114.71 L-80 BTC 119,781 183.2 43.1 216 98 40.27 4029.37 6114.71 6074.44 L-80 BTC 120,738 185.0 43.6 215 99 41.77 4071.14 6074.44 6032.67 L-80 BTC(centra) 121,730 186.9 44.0 214 100 39.96 4111.10 6032.67 5992.71 L-80 BTC 122,680 188.8 44.4 213 101 39.39 4150.49 5992.71 5953.32 L-80 BTC 123,616 190.6 44.9 212 102 39.87 4190.36 5953.32 5913.45 L-80 BTC 124,563 192.4 45.3 211 103 40.16 4230.52 5913.45 5873.29 L-80 BTC(centra) 125,517 194.3 45.7 210 104 40.89 4271.41 5873.29 5832.40 L-80 BTC 126,489 196.1 46.2 209 105 40.76 4312.17 5832.40 5791.64 L-80 BTC 127,457 198.0 46.6 208 106 39.34 4351.51 5791.64 5752.30 L-80 BTC 128,392 199.8 47.0 207 107 41.83 4393.34 5752.30 5710.47 L-80 BTC(centra) 129,386 201.7 47.5 Joint F ng Joint Depth BOI \CTOR 0.80 Joint# Joint# Length 1.,ia1 Bottom Top REMARKS. Bouyant Capacity Displmt on rack in hole feet feet feet feet Run 45 centralizers weight bbls bbls 206 108 41.84 4435.18 5710.47 5668.63 L-80 BTC 130,380 203.7 47.9 205 109 41.44 4476.62 5668.63 5627.19 L-80 BTC 131,364 205.6 48.4 204 110 38.64 4515.26 5627.19 5588.55 L-80 BTC 132,283 207.3 48.8 203 111 41.39 4556.65 5588.55 5547.16 L-80 BTC(centra) 133,266 209.2 49.3 202 112 41.20 4597.85 5547.16 5505.96 L-80 BTC 134,245 211.1 49.7 201 113 41.39 4639.24 5505.96 5464.57 L-80 BTC 135,228 213.0 50.2 200 114 41.22 4680.46 5464.57 5423.35 L-80 BTC 136,208 214.9 50.6 199 115 40.73 4721.19 5423.35 5382.62 L-80 BTC(centra) 137,175 216.8 51.0 198 116 41.19 4762.38 5382.62 5341.43 L-80 BTC 138,154 218.7 51.5 197 117 41.82 4804.20 5341.43 5299.61 L-80 BTC 139,148 220.6 51.9 196 118 40.71 4844.91 5299.61 5258.90 L-80 BTC 140,115 222.5 52.4 195 119 41.04 4885.95 5258.90 5217.86 L-80 BTC(centra) 141,090 224.4 52.8 194 120 40.97 4926.92 5217.86 5176.89 L-80 BTC 142,064 226.2 53.3 193 121 41.63 4968.55 5176.89 5135.26 L-80 BTC 143,053 228.2 53.7 192 122 37.75 5006.30 5135.26 5097.51 L-80 BTC 143,950 229.9 54.1 191 123 41.14 5047.44 5097.51 5056.37 L-80 BTC(centra) 144,927 231.8 54.6 190 124 41.73 5089.17 5056.37 5014.64 L-80 BTC 145,919 233.7 55.0 189 125 39.45 5128.62 5014.64 4975.19 L-80 BTC 146,856 235.5 55.4 188 126 40.81 5169.43 4975.19 4934.38 L-80 BTC 147,826 237.4 55.9 187 127 40.70 5210.13 4934.38 4893.68 L-80 BTC(centra) 148,793 239.2 56.3 186 128 39.84 5249.97 4893.68 4853.84 L-80 BTC 149,739 241.1 56.8 185 129 41.32 5291.29 4853.84 4812.52 L-80 BTC 150,721 243.0 57.2 184 130 41.80 5333.09 4812.52 4770.72 L-80 BTC 151,714 244.9 57.7 183 131 39.32 5372.41 4770.72 4731.40 L-80 BTC(centra) 152,648 246.7 58.1 182 132 40.66 5413.07 4731.40 4690.74 L-80 BTC 153,615 248.6 58.5 181 133 40.92 5453.99 4690.74 4649.82 L-80 BTC 154,587 250.4 59.0 180 134 41.41 5495.40 4649.82 4608.41 L-80 BTC 155,571 252.3 59.4 179 135 41.28 5536.68 4608.41 4567.13 L-80 BTC(centra) 156,552 254.2 59.9 178 136 40.15 5576.83 4567.13 4526.98 L-80 BTC 157,505 256.1 60.3 177 137 38.20 5615.03 4526.98 4488.78 L-80 BTC 158,413 257.8 60.7 176 138 39.82 5654.85 4488.78 4448.96 L-80 BTC 159,359 259.7 61.1 175 139 41.63 5696.48 4448.96 4407.33 L-80 BTC(centra) 160,348 261.6 61.6 174 140 40.82 5737.30 4407.33 4366.51 L-80 BTC 161,318 263.5 62.0 173 141 41.60 5778.90 4366.51 4324.91 L-80 BTC 162,307 265.4 62.5 172 142 41.89 5820.79 4324.91 4283.02 L-80 BTC 163,302 267.3 62.9 171 143 41.68 5862.47 4283.02 4241.34 L-80 BTC(centra) 164,292 269.2 63.4 170 144 41.85 5904.32 4241.34 4199.49 L-80 BTC 165,287 271.1 63.8 169 145 41.63 5945.95 4199.49 4157.86 L-80 BTC 166,276 273.0 64.3 168 146 39.60 5985.55 4157.86 4118.26 L-80 BTC 167,217 274.9 64.7 167 147 41.16 6026.71 4118.26 4077.10 L-80 BTC(centra) 168,195 276.7 65.1 166 148 41.44 6068.15 4077.10 4035.66 L-80 BTC 169,179 278.6 65.6 165 149 40.00 6108.15 4035.66 3995.66 L-80 BTC 170,130 280.5 66.0 164 150 39.02 6147.17 3995.66 3956.64 L-80 BTC 171,057 282.3 66.5 163 151 40.78 6187.95 3956.64 3915.86 L-80 BTC 172,026 284.2 66.9 162 152 41.81 6229.76 3915.86 3874.05 L-80 BTC 173,019 286.1 67.3 161 153 38.58 6268.34 3874.05 3835.47 L-80 BTC 173,936 287.8 67.8 160 154 41.22 6309.56 3835.47 3794.25 L-80 BTC 174,915 289.7 68.2 159 155 40.43 6349.99 3794.25 3753.82 L-80 BTC 175,876 291.6 68.6 158 156 40.65 6390.64 3753.82 3713.17 L-80 BTC 176,842 293.5 69.1 157 157 40.23 6430.87 3713.17 3672.94 L-80 BTC 177,797 295.3 69.5 156 158 40.22 6471.09 3672.94 3632.72 L-80 BTC 178,753 297.2 70.0 155 159 42.73 6513.82 3632.72 3589.99 L-80 BTC 179,768 299.1 70.4 154 160 39.20 6553.02 3589.99 3550.79 L-80 BTC 180,700 300.9 70.8 153 161 41.60 6594.62 3550.79 3509.19 L-80 BTC 181,688 302.8 71.3 152 162 41.09 6635.71 3509.19 3468.10 L-80 BTC 182,664 304.7 71.7 151 163 41.18 6676.89 3468.10 3426.92 L-80 BTC 183,643 306.6 72.2 150 164 41.24 6718.13 3426.92 3385.68 L-80 BTC 184,623 308.5 72.6 149 165 37.41 6755.54 3385.68 3348.27 L-80 BTC 185,512 310.2 73.0 148 166 40.32 6795.86 3348.27 3307.95 L-80 BTC 186,470 312.1 73.5 147 167 41.67 6837.53 3307.95 3266.28 L-80 BTC 187,460 314.0 73.9 • ' Joint P 'ng Joint Depth BOi kCTOR 0.80 Joint# Joint# Length ..,,a1 Bottom Top REMARKS. Bouyant Capacity Displmt on rack in hole feet feet feet feet Run 45 centralizers weight bbls bbls 146 168 41.46 6878.99 3266.28 3224.82 L-80 BTC 188,445 315.9 74.4 145 169 40.89 6919.88 3224.82 3183.93 L-80 BTC 189,416 317.8 74.8 144 170 41.70 6961.58 3183.93 3142.23 L-80 BTC 190,407 319.7 75.3 143 171 41.54 7003.12 3142.23 3100.69 L-80 BTC 191,394 321.6 75.7 142 172 38.70 7041.82 3100.69 3061.99 L-80 BTC 192,314 323.4 76.1 141 173 41.57 7083.39 3061.99 3020.42 L-80 BTC 193,301 325.3 76.6 140 174 41.58 7124.97 3020.42 2978.84 L-80 BTC 194,289 327.2 77.0 139 175 41.30 7166.27 2978.84 2937.54 L-80 BTC 195,271 329.1 77.5 138 176 41.71 7207.98 2937.54 2895.83 L-80 BTC 196,262 331.0 77.9 137 177 39.93 7247.91 2895.83 2855.90 L-80 BTC 197,210 332.8 78.3 136 178 41.81 7289.72 2855.90 2814.09 L-80 BTC 198,204 334.7 78.8 135 179 41.67 7331.39 2814.09 2772.42 L-80 BTC 199,194 336.7 79.3 134 180 39.15 7370.54 2772.42 2733.27 L-80 BTC 200,124 338.5 79.7 133 181 41.02 7411.56 2733.27 2692.25 L-80 BTC 201,099 340.3 80.1 132 182 40.32 7451.88 2692.25 2651.93 L-80 BTC 202,057 342.2 80.6 131 183 41.73 7493.61 2651.93 2610.20 L-80 BTC 203,048 344.1 81.0 130 184 41.13 7534.74 2610.20 2569.07 L-80 BTC 204,025 346.0 81.5 129 185 40.63 7575.37 2569.07 2528.44 L-80 BTC 204,991 347.9 81.9 128 186 40.32 7615.69 2528.44 2488.12 L-80 BTC 205,949 349.7 82.3 127 187 38.13 7653.82 2488.12 2449.99 L-80 BTC 206,855 351.5 82.7 126 188 40.59 7694.41 2449.99 2409.40 L-80 BTC 207,819 353.3 83.2 125 189 39.43 7733.84 2409.40 2369.97 L-80 BTC 208,756 355.1 83.6 124 190 40.67 7774.51 2369.97 2329.30 L-80 BTC 209,722 357.0 84.0 123 191 41.90 7816.41 2329.30 2287.40 L-80 BTC 210,718 358.9 84.5 122 192 41.60 7858.01 2287.40 2245.80 L-80 BTC 211,706 360.8 84.9 121 193 41.86 7899.87 2245.80 2203.94 L-80 BTC 212,701 362.8 85.4 120 194 41.67 7941.54 2203.94 2162.27 L-80 BTC 213,691 364.7 85.8 119 195 41.24 7982.78 2162.27 2121.03 L-80 BTC 214,671 366.6 86.3 118 196 40.45 8023.23 2121.03 2080.58 L-80 BTC 215,632 368.4 86.7 117 197 41.29 8064.52 2080.58 2039.29 L-80 BTC 216,613 370.3 87.2 116 198 39.38 8103.90 2039.29 1999.91 L-80 BTC 217,549 372.1 87.6 115 199 41.90 8145.80 1999.91 1958.01 L-80 BTC 218,544 374.1 88.1 114 200 41.87 8187.67 1958.01 1916.14 L-80 BTC 219,539 376.0 88.5 113 201 40.21 8227.88 1916.14 1875.93 L-80 BTC 220,494 377.8 88.9 112 202 41.22 8269.10 1875.93 1834.71 L-80 BTC 221,474 379.7 89.4 111 203 41.82 8310.92 1834.71 1792.89 L-80 BTC 222,467 381.6 89.8 110 204 41.74 8352.66 1792.89 1751.15 L-80 BTC 223,459 383.6 90.3 109 205 38.03 8390.69 1751.15 1713.12 L-80 BTC 224,363 385.3 90.7 108 206 41.23 8431.92 1713.12 1671.89 L-80 BTC 225,342 387.2 91.1 107 207 41.68 8473.60 1671.89 1630.21 L-80 BTC 226,333 389.1 91.6 106 208 41.72 8515.32 1630.21 1588.49 L-80 BTC 227,324 391.0 92.1 105 209 41.48 8556.80 1588.49 1547.01 L-80 BTC 228,310 392.9 92.5 104 210 39.86 8596.66 1547.01 1507.15 L-80 BTC 229,257 394.8 92.9 103 211 41.05 8637.71 1507.15 1466.10 L-80 BTC 230,232 396.6 93.4 102 212 41.80 8679.51 1466.10 1424.30 L-80 BTC 231,225 398.6 93.8 101 213 41.55 8721.06 1424.30 1382.75 L-80 BTC 232,212 400.5 94.3 100 214 41.96 8763.02 1382.75 1340.79 L-80 BTC 233,209 402.4 94.7 99 215 42.27 8805.29 1340.79 1298.52 L-80 BTC 234,214 404.3 95.2 98 216 41.69 8846.98 1298.52 1256.83 L-80 BTC 235,204 406.3 95.6 97 217 41.68 8888.66 1256.83 1215.15 L-80 BTC 236,195 408.2 96.1 96 218 41.07 8929.73 1215.15 1174.08 L-80 BTC 237,170 410.1 96.5 95 219 41.02 8970.75 1174.08 1133.06 L-80 BTC 238,145 411.9 97.0 94 220 40.49 9011.24 1133.06 1092.57 L-80 BTC 239,107 413.8 97.4 93 221 41.44 9052.68 1092.57 1051.13 L-80 BTC 240,092 415.7 97.9 92 222 39.74 9092.42 1051.13 1011.39 L-80 BTC 241,036 417.5 98.3 91 223 41.71 9134.13 1011.39 969.68 L-80 BTC 242,027 419.4 98.7 90 224 41.78 9175.91 969.68 927.90 L-80 BTC 243,020 421.4 99.2 89 225 41.74 9217.65 927.90 886.16 L-80 BTC 244,011 423.3 99.6 88 226 40.82 9258.47 886.16 845.34 L-80 BTC 244,981 425.1 100.1 87 227 41.75 9300.22 845.34 803.59 L-80 BTC 245,973 427.1 100.5 Joint F ng Joint Depth BOL \CTOR 0.80 Joint# Joint# Length i oval Bottom Top REMARKS: Bouyant Capacity Displmt on rack in hole feet feet feet feet Run 45 centralizers weight bbls bbls 86 228 41 .00 9341.22 803.59 762.59 L-80 BTC 246,947 428.9 101.0 85 229 40.98 9382.20 762.59 721.61 L-80 BTC 247,921 430.8 101.4 84 230 41.80 9424.00 721.61 679.81 L-80 BTC 248,914 432.8 101.9 83 231 41.18 9465.18 679.81 638.63 L-80 BTC 249,893 434.6 102.3 82 232 42.21 9507.39 638.63 596.42 L-80 BTC 250,896 436.6 102.8 81 233 40.53 9547.92 596.42 555.89 L-80 BTC 251,859 438.4 103.2 80 234 41 .02 9588.94 555.89 514.87 L-80 BTC 252,833 440.3 103.7 79 235 41.43 9630.37 514.87 473.44 L-80 BTC 253,818 442.2 104.1 78 236 41 .68 9672.05 473.44 431.76 L-80 BTC 254,808 444.1 104.6 77 237 41 .75 9713.80 431.76 390.01 L-80 BTC 255,800 446.1 105.0 76 238 41 .84 9755.64 390.01 348.17 L-80 BTC 256,794 448.0 105.5 75 239 40.13 9795.77 348.17 308.04 L-80 BTC 257,747 449.8 105.9 74 240 41 .73 9837.50 308.04 266.31 L-80 BTC 258,739 451.7 106.3 73 241 41.44 9878.94 266.31 224.87 L-80 BTC 259,724 453.6 106.8 72 242 40.44 9919.38 224.87 184.43 L-80 BTC 260,684 455.5 107.2 71 243 41 .76 9961.14 184.43 142.67 L-80 BTC 261,677 457.4 107.7 70 244 41 .32 10002.46 142.67 101.35 L-80 BTC 262,658 459.3 108.1 pup 10.81 10013.27 101.35 90.54 L-80 BTC Pup.int 262,915 459.8 108.2 pup 19.96 10033.23 90.54 70.58 L-80 BTC Pup Jnt 263,390 460.7 108.5 69 245 41.73 10074.96 70.58 28.85 L-80 BTC 264,381 462.6 108.9 7.20 10082.16 28.85 21.65 Pup Joint 264,552 463.0 109.0 0.40 10082.56 21.65 21.25 Hanger 264,562 463.0 109.0 21 .25 10103.81 21.25 0.00 RKB to Load shoulder 265,067 464.0 109.2 Hilcorp Energy Company S It (A,"-e-A CASING&CEMENTING REPORT Lease&Well No. SRU 14B-27 Date 18-Jan-13 County Kenai Peninsula Burough State Alaska Supv. Mike Leslie CASING RECORD TD 11322.00 Shoe Depth: 11320.00 PBTD: MD/'TVD Casing(Or Liner)Detail Setting Depths No.of Jts. Size Wt. Grade THD Make Length Bottom Top Shoe 5 BTC WOT 2.18 11,320.00 10,102.19 2 5 15 L-80 DWC 76.29 10,102.19 10,025.90 F.Collar 5 BTC WOT 1.09 10,025.90 10,024.81 1 5 15 L-80 DWC 38.81 10,024.81 9,986.00 LC 5 BTC WOT 1.10 9,986.00 9,984.90 33 5 15 L-80 DWC 1,274.73 9,984.90 8,710.17 Hanger 7.625x5.5 H-563 BOT 16.52 8,710.17 8,693.65 Packer/PBR 7.625x5.5 H-563 BOT 19.95 8,693.65 8,673.70 0.00 8,673.70 8,673.70 Totals 1,430.67 8,673.70 7,243.03 Csg Wt.On Hook: 168k Type Float Collar: Float No.Hrs to Run: 17.5 Csg Wt.On Slips: Type of Shoe: Bullnose w/float Casing Crew: Wfd Fluid Description: 11.5 ppg WBM / 6%KCI/PHPA / PV=21 YP=18 HTHP=10.0 Liner hanger Info(Make/Model): Baker Flex-Lock5 1/2 x 7 5/8 Liner top Packer?: X Yes _No Liner hanger test pressure: 1,000 psi to date Centralizer Placement: (2)-Shoe jt,(1)jt#2,(2)Flt Jt,(1)LC Jt,(1)per joint to 10,428.(1)every other jt to Hanger =31 centralizers CEMENTING REPORT Preflush(Spacer) Type: Mud Push II Density(ppg) 13.5 Volume pumped(BBLs) 33 bbls Lead Slurry Type: Yield: Density(ppg) Vol pumped(BBLs/sx) Mixing/Pumping Rate(bpm): Tail Slurry Type: Conventional Class G Blended EasyBlok Yield: 1.35 ft3/sk 1 Density(ppg) 15.3 ppg Vol pumped(BBLs/sx) 80 bbls/332 sx Mixing/Pumping Rate(bpm): 3.5 bpm Post Flush(Spacer) Type: Density(ppg) Rate(bpm): Volume: re LI Displacement: Type: Mud Density(ppg) 11.5 ppg Rate(bpm): 5 bpm Volume(actual/calculated): 125.2/126 FCP(psi): 1200 psi Pump used for disp: Schlumberger Plug Bumped? X Yes No Bump press 500 Casing Rotated? X Yes No Reciprocated? Yes X No %Returns during" 100 Cement returns to surface? X Yes No Spacer returns? X Yes No Vol to Surf: 4 bbl c t/33 bbl spacer Cement In Place At: 0:10 Date: 1/18/2013 Estimated TOC: 9,885 Method Used To Determine TOC: Circulated cement out from top of Liner V 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: o iii 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: WELLHEAD Make Type Serial No. Size W.P. Test Head To PSIG MIN OK Remarks: 11 CASING RUN IN TALLY WELL NAME: SRU 14B-27 DATE: 01/17/13 CASING SIZE 5.000 WEIGHT 15.00 CASING ID 4.408 GRADE L-80 THREAI DWC/C-HT Casing (Buttress Casing) CAPACITY 0.0189 bbls/ft TORQUE - MAXIMUM=8,400 MIN=9,400 DISPLACEMENT 0.0046 bbls/ft SHOE DEPTH 11320.0 feet Coupling OD=5.563 , Drift 4.283 HOLE TD 11322.0 feet MUD WT 11.05 ppg Joint Running Joint Depth BOUY FACTOR 0.82 Joint# Joint# Length Total Bottom Top REMARKS Bouyant Capacity Displmt on Rack in hole feet feet feet feet weight bbls bbls Off Bottom 7.00 Block Weight = 25,000 Weatherford Reamer Shoe,OD-5.75, A 2.18 2.18 11320.00 11317.82 SN-1779046713, 25,027 0.0 0.0 BakerLocked Joint w/2 Centrilizer&stop rings 63 38.65 40.83 11317.82 11279.17 10'&20'from shoe 25,505 0.8 0.2 BakerLocked Joint 5", 62 37.64 78.47 11279.17 11241.53 DWC w/Centralizer#3 25,970 1.5 0.4 Float Collar.BTC, B 1.09 79.56 11241.53 11240.44 SN-577436 25,983 1.5 0.4 Baker Locked Joint w/Centralizer#4 61 38.81 118.37 11240.44 11201.63 Mid-joint 26,463 2.2 0.5 Landing Collar,BTC, SN-53205, C 1.10 119.47 11201.63 11200.53 PO-4505554843 26,477 2.3 0.5 Joint 5"DWC 60 4 38.52 157.99 11200.53 11162.01 w/Centralizer#6 26,953 3.0 0.7 Joint 5"DWC 59 5 38.77 196.76 11162.01 11123.24 w/Centralizer#7 Joint 5"DWC 58 6 39.11 235.87 11123.24 11084.13 w/Centralizer#8 27,436 3.7 0.9 Joint 5"DWC 57 7 39.17 275.04 11084.13 11044.96 w/Centralizer#9 27,920 4.5 1.1 Joint 5" DWC 56 8 38.70 313.74 11044.96 11006.26 w/Centralizer#10 28,399 5.2 1.3 Joint 5"DWC 55 9 38.36 352.10 11006.26 10967.90 w/Centralizer#11 28,873 5.9 1.4 Joint 5"DWC 54 10 37.90 390.00 10967.90 10930.00 w/Centralizer#12 29,341 6.6 1.6 Joint 5"DWC 53 .1 38.83 428.83 10930.00 10891.17 w/Centralizer#13 29,821 7.4 1.8 Joint 5"DWC 52 12 39.13 467.96 10891.17 10852.04 w/Centralizer#14 30,305 8.1 2.0 Joint 5" DWC 51 13 38.74 506.70 10852.04 10813.30 w/Centralizer#15 30,784 8.8 2.1 Joint 5"DWC 50 14 39.01 545.71 10813.30 10774.29 w/Centralizer#16 31,266 9.6 2.3 Joint 5"DWC 49 15 39.14 584.85 10774.29 10735.15 w/Centralizer#17 31,750 10.3 2.5 Joint 5"DWC 48 16 38.69 623.54 10735.15 10696.46 w/Centralizer#18 32,228 11.0 2.7 Joint 5"DWC 47 17 38.65 662.19 10696.46 10657.81 w/Centralizer#19 32,705 11.8 2.9 Joint 5"DWC 46 18 37.23 699.42 10657.81 10620.58 w/Centralizer#20 33,166 12.5 3.0 Joint 5"DWC 45 19 36.95 736.37 10620.58 10583.63 w/Centralizer#21 33,622 13.2 3.2 Joint 5"DWC 44 20 38.37 774.74 10583.63 10545.26 w/Centralizer#22 34,097 13.9 3.4 Joint 5"DWC 43 21 38.97 813.71 10545.26 10506.29 w/Centralizer#23 34,578 14.6 3.5 Joint 5"DWC 42 22 37.67 851.38 10506.29 10468.62 w/Centralizer#24 35,044 15.3 3.7 Joint 5"DWC 41 23 37.74 889.12 10468.62 10430.88 w/Centralizer#25 35,510 16.0 3.9 40 24 39.52 928.64 10430.88 10391.36 Jt 5"DWC 35,999 16.8 4.1 39 25 37.6976Q966.33 10391.36 10353.67 Jt 5" DWC w/cent#26 36,465 17.5 4.2 �nrh Prc licti�n 13if�eh'� N44•011 1157677" ciAlg5tPly Jt5" DWC 401,C3710 318.x.?A P Joint Run Joint Depth BOL ACTOR 0.82 Joint# Joint# Length Total Bottom Top REMARKS Bouyant Capacity Displmt on Rack in hole feet feet feet feet weight bbls bbls 37 27 38.88 1043.17 10315.71 10276.83 .It 5" DWC w/cent#27 37,414 19.0 4.6 36 28 40.25 1083.42 10276.83 10236.58 Jt 5" DWC 37.912 19.7 4.8 35 29 39.82 1123.24 10236.58 10196.76 .It 5" DWC w/cent#28 38.404 20.5 5.0 34 30 37.67 1160.91 10196.76 10159.09 Jt 5" DWC 38.870 21.2 5.1 33 31 38.05 1198.96 10159.09 10121.04 .It 5" DWC w/cent#29 39.340 21.9 5.3 32 32 40.78 1239.74 10121.04 10080.26 .1t 5" DWC 39,844 22.7 5.5 31 33 38.56 1278.30 10080.26 10041.70 .It 5" DWC w/cent#30 40.321 23.4 5.7 30 34 38.30 1316.60 10041.70 10003.40 it 5" DWC 40.794 24.1 5.9 29 35 39.00 1355.60 10003.40 9964.40 .1t 5" DWC w/cent#31 41,276 24.9 6.0 28 36 38.60 1394.20 9964.40 9925.80 .1t 5" DWC 41.753 25.6 6.2 XO,Flex-Lock Liner Hanger,XO,RS Packoff Seal Nipple Jt,HRD ZXP 36.60 1430.80 9925.80 9889.20 Packer,PBR. 9.56 1440.36 9889.20 9879.64 Running Tool AV,11 I-Jp A J 1/1.11' 2.21 1442.57 9879.64 9877.43 (BxP) 545.79 1988.36 9877.43 9331.64 (18) HWDP 9311.17 11299.53 9331.64 20.47 (std# 148),Dp to surface to bottom of Cement Head. Make up 10' Pup to top and stage on Pipe 10' & 15' ft Pups 25.00 11324.53 20.47 -4.53 Skate Top Joint of 5" DWC to center of Hanger=8.0'- (9918) Top Joint of 5" DWC to center of Packer=19.0'- (9907) 7 5/8" Casing couplings @ 9934,9893,9851&9810.... 5 inch Production Liner FINAL. 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O O O -C7 0 0 0 O C O G',0 0 0 0 O O C O CD'C)0 0 0 O O 0 CD 0i CO CO CO CO ✓ N N N N N N N N N N N N N N',N N N N N N N N N N N NIN N N N N N N N N N,N N N N N 04 C4 C i 88888888888 888888888C8888888888888888880088888808 � I03N2 5. c� 00 N COaC8CC)rpDD8CCoCCCC0)CCCC0)CTCCO)TTp880000 °°°°°°°° 1 • 2' 2— 0`69 Landon Ellison Hilcorp Alaska, LLC sL��-7 GeoTech II 3800 Centerpoint Drive, Suite 100 f Anchorage, AK 99503 Tele: 907 777-8339 II arfwr Alas:u,t:tx, Fax: 907 777-8510 E-mail: lellison@hilcorp.com APR i cC;'. . 04/10/13 AOGCC To: AOGCC Makana Bender 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTA SRU 14B-27 Prints (CASED HOLE LOGS) CAST-M, ACE, (March, 19 2013) Acoustic Cement bond log (2) (March, 19 2013) Circumferential Acoustic Scanning Tool Monocable (March, 19 2013) CD: Final Well Data CAST-M, CBL, ACE, (March, 19 2013) 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: /0e 5 1ez_ezi 3 2( 2- c3? Davies, Stephen F (DOA) From: David Duffy[dduffy@hilcorp.com] Sent: Thursday, March 07, 2013 3:17 PM To: Davies, Stephen F (DOA) Cc: Judy Stanek; Chad Helgeson; John Serbeck; Kevin Tabler Subject: RE: SRU 13-27 Sundry Application Attachments: SRU_14B-27_Permit403_v02.pdf; SRU_13-27_Permit403_v02.pdf Steve— Thanks for your email below. I've attached a revised maps of both SRU 13-27 and 14B-27. These will be the only two well open to the Hemlock in the SW1/4 of Section 27,T8N, R9W, SM. Other welibores referenced in that quarter section (e.g., SRU 314-27 and 23-27) are not open to production. Therefore, no spacing exception will be required for either SRU 13-27, 14B-27 under Conservation Order 123A. Sorry that was not clear the first go-round. If you need any additional information, don't hesitate to call. David Duffy, Landman Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, Alaska 99503 Office: 907 777-8300 Direct: 907 777-8414 Fax: 907 777-8580 Cell: 907 301-2629 Email: dduffy@hilcorp.com This email may contain confidential and/or privileged information and is intended for the recipient(s)only. In the event you receive this message in error, please notify me and delete the message. From: Davies, Stephen F (DOA) [mailto:steve.davies@ alaska.gov] Sent: Thursday, March 07, 2013 2:28 PM To: Chad Helgeson Cc: Judy Stanek Subject: SRU 13-27 Sundry Application Chad, Spacing for SRU 13-27 is currently regulated by Conservation Order 123A,which specifies: "Not more than two completed wells are allowed in any governmental quarter section." The productive portion of SRU 13-27 lies in the SW1/4 of Section 27,T8N, R9W,SM. According to Hilcorp's plat that is attached to the Sundry Application to perforate SRU 13-27, several other wells also lie within that same quarter section. Are any of these other wells open to the Hemlock Oil Pool in that same quarter section? If so, a spacing exception application will be required. Thanks, Steve Davies AOGCC 907-793-1224 1 / / • / / / / / / / / Legend ' ' / ,' SRU 12-27 BHL • Surface Hole Location �,/- -- • Bottom Hole Location / -1' / / 7 fl Abandoned Well KGSF7 BHL //� ——— Well Paths P KGSF3 BHL/ ,' i Field Boundary KGSF2 BHL / I / / / i \ E0 ii• I KGSF7A BHL SRU 23-27 BHL—— SRU 223-28 BHL A028406 t SRU 314-27 BHL A028399 SRU 14B-27 SRU 314-27PB1 BHL Bottom Hole Location S008N009WSRU 14B-27 f'� Top and Bottom of Productive Interval / SRU 14B-27 ,/ (Surface Hole Location /f ,' SRU 21A-34 BHL SRU 32A-33 BHL • Soldotna Creek Unit SU 343-33 BHL 1 A028990 ti / SCU 13-34 BHL 1 / 0 1,000 2,000 II Swanson River Field Feet SRU 14B-27 Alaska State Plane Zone 4, NAD27 Hilcorp Alaska,LLC Map Date:March 7,2013 II Landon Ellison Hilcorp Alaska, LLC GeoTech II 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8339 }Mont Atoskii,L14; Fax: 907 777-8510 E-mail: lellison@hilcorp.com 02/19/13 RECEIVED To: AOGCC Makana Bender FEB 19 2013 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 AOGCC DATA TRANSMITTA SRU 14B-27 Prints: SRU 14B-27 Formation Log MD 2"=100 #.- SRU SRU 14B-27 Formation Log ND 2"=100 SRU 14B-27 LWD Combo Log MD 2"=100 SRU 14B-27 LWD Combo Log ND 2"=100✓ SRU 14B-27 Gas Ratio Log MD 2"=100 — SRU 14B-27 Gas Ratio Log TVD 2"=100 ✓ SRU 14B-27 Drilling Dynamics MD 2"=100 SRU 14B-27 Drilling Dynamics TVD 2"=100 SRU 14B-27 Final Well Report.doc ^ice CD: Final Well Data tl 2 L /" DAILY REPORTS DIRECTIONAL SURVEY DML DATA FINAL WELL REPORT LAS FILE LOG PDF FILES LOG TIFF FILES SHOW REPORTS 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 Recei •d� : / Date: citt,....L• l8 ) < 3 a« - o $q zl2-o%9 Landon Ellison Hilcorp Alaska, LLC �2 2 GeoTech II 3800 Centerpoint Drive, Suite 100 J Anchorage, AK 99503 Tele: 907 777-8339 Fiilrv,rp Ab ka.i.ii; Fax: 907 777-8510 E-mail: lellison@hilcorp.com RECEIVED 02/19/13 FEB 19 2013 To: AOGCC AOGCC Makana Bender A GCC 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTA SRU 14B-27 Prints BOREHOLE VOLUME PLOT 15-JAN-13 SONIC POROSITY(FIELD PRINT) 15-JAN-13 SONIC POROSITY(FIELD PRINT) 05-JAN-13 WAVE SONIC (FIELD PRINT) 15-JAN-13 WAVE SONIC (FIELD PRINT) 05-JAN-13 WAVESONIC SEMBLANCE PROCESSED LOG 16-JAN-13 WAVESONIC SEMBLANCE PROCESSED LOG 07-JAN-13 COMPOSITE LOG 15-JAN-13 COMPOSITE LOG 05-JAN-13 CD: Final Well Data QUAD COMBO (LAS DATA, DIGITAL LOGS) 05-JAN-2013 QUAD COMBO (LAS DATA, DIGITAL LOGS) 15-JAN-2013 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: A c& t4(3-27 Pth 21/662o Regg, James B (DOA) From: Mike Leslie [gleslie@hilcorp.com] Sent: Monday, December 24, 2012 9:08 PM ` �j 10Z4'11 v To: Brooks, Phoebe L (DOA); DOA AOGCC Prudhoe Bay; Regg, James B (DOA) Cc: Paul Mazzolini; Luke Keller Subject: Notification for use of Blowout Equipment to control flow from a Well -12-24-12 Attachments: Notification for use of Blowout Equipment to control flow from a Well -12-24-12.docx 1 Notification for use of Blowout Equipment to control flow from a Well Date: 12-24-12 Shut In Time: 09:10 Location: Swanson River, SRU 14B-27 PTD#: 212-089 Rig: Doyon Rig#1, Arctic Fox Drilling Foreman: Mike Leslie, Hilcorp Alaska BOP used: 11" 5M, Annular Preventer Reason: Flow detected from Well Summary: While Rotary Drilling at a depth of 7,630' we began getting a gas increase from the Canrig Gas monitoring system. At 1500 units, the Driller picked off bottom and monitored the Well while circulating @ 3 bpm. The gas returns diminished from 2383 (max) to 1500 units, but gave us a 10 bbl pit gain over 10 min. The Well was shut in and pressures recorded. The Drill pipe stabilized at 35 psi and the casing gauge at 0 psi. We circulated the Gas out with the Drillers Method and increased the MW to 12.1 ppg. We then drilled another 6' to finish the stand and circulated another B/U. The gas increased to 2050 units and then diminished/stabilized @ 1150 units. We shut the Well in again and weighted up the surface system to 12.3 ppg. The Well was then displaced to 12.3 ppg while holding 125 psi back pressure on the Casing. The Well was opened and monitored for flow (static). We continued to circulate an additional annular volume while the back ground gas diminished to 150 units. Last BOP test date: 12-13-12 A complete BOP test will be conducted on the next trip out of the hole to surface and completed prior to reentering Well Bore. Mike Leslie Drilling Foreman Hilcorp Alaska gleslie@hilcorp.com 907-776-6776 Src1 144;-z 7 2(Zug to Regg, James B (DOA) From: Mike Leslie [gleslie©hilcorp.com] Sent: Sunday, December 23, 2012 11:05 PM eil 1 utI(L To: Brooks, Phoebe L (DOA); DOA AOGCC Prudhoe Bay; Regg, James B (DOA) Cc: Paul Mazzolini; Luke Keller Subject: Notification for use of Blowout Equipment to control flow from a Well -12-23-12 Attachments: Notification for use of Blowout Equipment to control flow from a Well -12-23-12.docx Currently weighting Mud system up from 11.8 ppg to 12.0 ppg. 1 Notification for use of Blowout Equipment to control flow from a Well Date: 12-23-12 Shut In Time: 19:50 Location: Swanson River, SRU 14B-27 PTD#: 212-089 . Rig: Doyon Rig #1, Arctic Fox Drilling Foreman: Mike Leslie, Hilcorp Alaska BOP used: 11" 5M, Annular Preventer Reason: Flow detected from Well Summary: While Rotary Drilling at a depth of 7,528' we began getting a gas increase from the Canrig Gas monitoring system. At 1200 units, the Driller picked off bottom to monitor the Well. By the time he had positioned himself for a possible shut in, the units had increase to 1750. He shut the pumps down to check for "flow". The Well was flowing, so the Driller closed the Annular Preventer, notified the Drilling Foreman and the Toolpusher. He then began recording the Dp/Casing pressures. The final reading from the Mud Logger was 2184 units of Gas. The Drill pipe stabilized at 50 psi and the casing gauge at 25 psi. The Pitwatcher reported a 10 bbl gain to system with pumps off. The typical return flow when pumps are shut down is 10 bbl. Pit gain from influx was calculated at (0) bbls. Last BOP test date: 12-13-12 A complete BOP test will be conducted on the next trip out of the hole to surface and completed prior to reentering Well Bore. Mike Leslie Drilling Foreman Hilcorp Alaska gleslie@hilcorp.com 907-776-6776 S, 4 /46-z7 Pro zizegco Rego , James B (DOA) From: Mike Leslie [gleslie@hilcorp.com] Sent: Saturday, December 22, 2012 12:46 AM <.../f Zit(k To: Brooks, Phoebe L (DOA); DOA AOGCC Prudhoe Bay; Regg, James B (OOA) Cc: Paul Mazzolini; Luke Keller; Arctic Fox Rig 1 Subject: Swanson River, Doyon Rig 1, SRU 14B-27 Attachments: Notification for use of Blowout Equipment to control flow from a Well.docx Your message is ready to be sent with the following file or link attachments: Notification for use of Blowout Equipment to control flow from a Well Note: To protect against computer viruses, e-mail programs may prevent sending or receiving certain types of file attachments. Check your e-mail security settings to determine how attachments are handled. 1 Notification for use of Blowout Equipment to control flow from a Well Date: 12-21-12 Shut In Time: 08:52 Location: Swanson River, SRU 14B-27 PTD#: 212-089 - Rig: Doyon Rig#1, Arctic Fox Drilling Foreman: Mike Leslie, Hilcorp Alaska BOP used: 11" 5M, Annular Preventer Reason: Flow detected from Well Summary: While Slide Drilling at a depth of 7,378'we began getting a gas reading from the Canrig Gas monitoring system. At 500 units, the Driller picked off bottom to monitor Well. By the time he had positioned himself for a possible shut in, the units had increase to 1200. He shut the pumps down to check for "flow". The Drilling Foreman arrived on the floor during the flow check. The Driller shut in the Well, notified the Toolpusher and then began recording Dp/Casing pressures. The final reading from the Mud Logger was 2007 units of Gas. The Drill pipe stabilized at 20 psi and the casing gauge at 30 psi. The Pitwatcher reported a 14 bbl gain to system with pumps off. The typical return flow when pumps are shut down is 10 bbl. Pit gain from influx was calculated at (4) bbls. - Last BOP test date: 12-13-12 - A complete BOP test will be conducted on the next trip out of the hole to surface and completed prior to reentering Well Bore. Mike Leslie Drilling Foreman Hilcorp Alaska gleslie@hilcorp.com 907-776-6776 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, March 19, 2013 12:15 PM To: 'Chad Helgeson' Cc: 'Davies, Stephen F (DOA) (steve.davies@alaska.gov)' Subject: RE: 14B-27 Cement Job (PTD 2 jz—U 8(i) Chad, Agree that cement is excellent at gas storage zone. No issues with migration or isolation. You can adjust the perfs as you stated below ... same zone/pool so no issues with approval from AOGCC. Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office From: Chad Helgeson [ ] Sent: Tuesday, March 19, 2013 11:52 AM To: Schwartz, Guy L (DOA); Ferguson, Victoria L (DOA) Subject: FW: 146-27 Cement Job tJuy/Victor la, Below is the log of the CBL on SRU 14B-27. Better cement than what we had on 13-27 around the storage sand. Cement is solid around the storage sand depths (6,407'-6,430') I would also like to ask if we can add some footage to our proposed depths of perforating on 14B-27. We proposed 10,853-10,870 (17ft). We would like to perforate 10,854-10,880 (26') and 10,886'-10,898' (12'). These are all still the same H3/4 sand, but thought I would let you know ahead of time that we were going to change our perf depths a little bit. Based on these results, we are planning to continue to move forward with our plan to perforate and then complete the well. Chad 1 t j w — _ _ Y '' •�. s'a7• I I ]t1 r ,� �_.. ! �.,, ;fir •- ma Ilia _ 6350 t. _ ! Ai i 11 1 — .1•ImemP # .A.-Il ,.. r. ... a 1 i ! - ,r-i• lit S .., 1110 �� _= - - .; I s 4...., . II i 6400 .� - li{� �! , ,�� I ,-� ..�-x .� -� I rr� —. ••••_ a 7r / 4 6450 --ord.. ..' •. . .. i) — II / 010 s ii, i an. _ - al', _ rt II i �, 1,011...01,tt • ,` i a 1 _ ... i ir •••, . w •• _ —r- -1 1J. -^ ----1 - ^-- 2 • w\�\���jj�s7 THE STATE Alaska Oil and Gas °fALASK A Conservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue �LAS�� Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 Chad Helgeson p� Operations Manager e c J Hilcorp Alaska, LLC J 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SRU 14B-27 Sundry Number: 313-115 Dear Mr. Helgeson: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, l / 704 JkL Cathy P. Foerster Chair DATED this 12 a of March, 2013. Encl. itiviv,,, RECEIVED STATE OF ALASKA k/ MAR 0 .3 2013 ALASKA OIL AND GAS CONSERVATION COMMISSION D9-7 /////3 APPLICATION FOR SUNDRY APPROVALS A GCC 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redril ❑ Perforate New Pod ❑ Repair Wei Change Approved Program❑ Suspend❑ Plug Perforations❑ Perforate❑., • Pull Tubing Time Extension❑ Operations Shutdown❑ Re-enter Susp.Wel ❑ Stimulate❑ Atter Casin[] Other. Completer] 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC Exploratory ❑ Development El 212-089 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic ❑ Service CI • 6.API Number: Anchorage,Alaska 99503 50-133-20604-00 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 132A ❑ Swanson River Unit(SRU)148-27 i Will planned perforations require a spacing exception? Yes ❑✓ No 9.Property Designation(Lease Number): 10.Field/Pool(s): A028399,A028406 Swanson River Field/Hemlock Oil • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 11,177 10,942 11,322 11,085 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 16" 80' 80' Surface 2,961' 10-3/4" 2,961' 2,959' 3,580 psi 2,909 psi Intermediate 10,103' 7-5/8" 10,103' 9,940' 6,890 psi 4,790 psi Production . Liner 1,431' 5" 11,322' 11,086' 8,290 psi 7,250 psi Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): None None 2-7/8" 6.5#/L-80 1,299' Packers and SSSV Type: Packers and SSSV MD(t)and ND(ft): N/A-N/A N/A-N/A 12.Attachments: Description Summary of Proposal Q 13.Well Class after proposed work: Detailed Operations Program n BOP Sketch n Exploratory n Stratigraphies Development n 'Service n 14.Estimated Date for 15.Well Status after proposed work: 03/18/13 Commencing Operations: Oil ❑✓ . Gas ❑ WDSPL ❑ Suspended 0 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Chad Helgeson Phone: 907-777-8405 Email chelgeson(aDhilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature Phone 907-777-8405 Date YY/3 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. Plug Integrity ❑ BOP Test M/ Mechanical Integrity Test ❑ Location Clearance ❑ Other: 3 COL) ,s: eD Pcs t ReDMS MAR 14 2013 Spacing Exception Required? Yes �No ❑ Subsequent Form Required: b — Y Q 7- / APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: _/ �G 4 ORr Ii-1/—.4 ^ 1Z 3 Submit Form and q/4Ve_{( i �o�t) Approved application is valid f 12 months from the date of approval. Att me i /D�upiicate ��l� Well Prognosis Well: SRU 14B-27 llileori,Alaska,LLA, Date:3/4/2013 Well Name: SRU 14B-27 API Number: 50-133-20604-00 Current Status: New Cased Oil Producer Leg: N/A Estimated Start Date: March 18`h, 2013 Rig: Williams 405 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 212-089 First Call Engineer: Chad Helgeson (907)777-8405 (0) (907) 229-4824 (M) Second Call Engineer: Luke Saugier (907)777-8395 (0) AFE Number: 1211615 Maximum Expected BHP: -2,800 psi @ 10,643' TVD Based on reservoir modeling of known nearby reservoir pressures Max. Allowable Surface Pressure: 0 psi Based on 6% KCI brine left in the well, fluid level will not be pulled below 3,000 Brief Well Summary This well was drilled with the Doyon Arctic Fox in December 2012 to January 2013. The completion and following work is proposed to be completed with Williams Rig#405. . Notes Regarding Wellbore Condition The well is cased with filtered 6% KCI brine, and spoted 10 bbls of diesel at surface for freeze protect fluid. No open perforations. Casing pressure tested to 3,000 psi. • Completion procedure: 1. MIRU Williams 405 workover rig. 2. Pull BPV. °k 1.413. Circulate 6% KCI through kill string(circulate all (10 bbls)diesel from well.) � ,Sm''2,`-i 4. Set BPV or test plug in tubing hanger, ND tree, NU 7" BOPE and test to 250psi low/3,000psi high, r r� annular to 250psi low/1,500psi high (hold each valve and test for 10-min). Record accumulator pre-charge pressures. a. Notify AOGCC 24hrs in advance to witness, be ready to test when/if inspector arrives. • b. Notify BLM 48 hrs in advance of BOP test. c. Ensure winterization package is installed for the weather. 5. Pull BPV, pull tubing hanger. 1-6. RIH with the kill string and new 2-7/8" 8rd EUE to bottom. 7. Circulate filtered 25 micron brine bottoms up. %-' 88. Swab 45bbls of fluid from well in the tubing with braided line. (approximately 1000ft of surface fluid.) This will create approximately 1,500psi overbalance. ,9. POOH, rack back pipe, LD kill string tubing. 10. RU e-line 11. RIH and run CBL log 5-1/2"casing(11,177-9,800')and 7-5/8"casing(9,800-2,950'). Review CBL in intermediate section, determine if any remedial work is necessary to gas storage intervals. If additional remedial work is necessary the following procedure will be sent to AOGCC and BLM for review. ��► �C.iecJ �gL w� 44-(' Well Prognosis Well: SRU 14B-27 llilcorp Alaska,LL Date: 3/4/2013 a. Block squeeze above or below zone as necessary to ensure that gas storage reservoir is isolated from other zones in wellbore. 12. Pending no remedial work is necessary RU e-line to perforate H3/4 Hemlock with 3-3/8" HC 6 spf guns. a. +/- 10,853-10,870' 13. POH and rig down e-line. 14. Monitor well and see if any pressure increase is noted, shoot fluid level immediately and after 1hr of waiting, to see if fluid is moving up to surface. 15. RIH w/completion on 2-7/8" 8rd EUE tubing (mechanical packer and gas lift valves as shown on proposed schematic (dummy valves as necessary&shown on schematic), set packer at approx. 9,860ft. Pa do-e-L a. Land tubing in hanger. Close the lockdown pins. Minimize compression to 2-3 ft by using the on/off tools as necessary. M i —/4 trr- 16. Drop RHCP plug in well and test casing to 3,000 psi and tubing to 3,000 psi, chart for 30 min ea. 17. Set BPV, ND BOPs, NU Tree, test tree to 5,000 psi. 18. Pull BPV. RDMO workover rig and equipment. 19. Turn well over to production. 20. NU piping and flowlines. 21. Gas lift well, unloading fluid from well, SI well leaving gas lift pressure on well. 22. RU slickline, PT lubricator to 2000 psi Hi 250 low. 23. RIH and pull RHCP prong and plug 24. Start production 25. Notify AOGCC of SSV testing within 5 days of brining well online. 26. Notify BLM of return to production within 5-days of production. Attachments: 1. Existing Well Schematic (As left by Doyon work) 2. Proposed Schematic 3. Williams BOP Schematic 4. Spacing Map Swanson River Unit 14 Well: SRU 14B-27 Existing Post Drilling PTD: 212-089 API: 50-133-20604-00 Ililcorp Alaska,LLC KB-THF: 18.6' CASING DETAIL ;q i t, l Size Type Wt Grade Conn. ID Top Btm 16" 'l L1 16„ Conductor—Driven to Surf 80' Set Depth 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 2,961' r' ` 7-5/8" Intermediate 29.7 L-80 BTC 6.75" Surf 7093' 6429.7 P-110 HC BTC/LTC 6.75" 7,093' 10,103' i.. +r, 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 9,891' 11,322' 10-3/4" tit: ''' TUBING yl 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 1,299 k4 t 4{i 4 ,$irl ;, pi JEWELRY DETAIL It 1' No. Depth ID OD Item a0 1 18.6' 2.44" - Tubing Hanger * e.10 lit, Clean filtered 6%KCI r,: Ory' ;T.0 ; 1 PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date L= r td !l± 7-5/8" -AI!V 4 A 14141? ±; 5„ 6.75"Hole TD=11,322/TVD=11,085' PBTD=11,177/1VD=10,942' Updated by CAH 03-05-13 Swanson River Unit ., Well: SRU 14B-27 11 PROPOSED PTD: 212-089 API: 50-133-20604-00 Hilcorp Alaska,LLC KB-THF: 18.6' CASING DETAIL ;y 1 0, Size Type Wt Grade Conn. ID Top Btm 16' 16„ Conductor Set DepthD vento Surf 80' ,; 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 2,961' i29.7 L-80 BTC 6.75" Surf 7093' 7-5/8" Intermediate M 29.7 P-110 HC BTC/LTC 6.75" 7,093' 10,103' a, 5" Prod Lnr 15 L-80 DWC/C HT 4.283" 9,891' 11,322' 10-3/4" ,•' TUBING > 2 IMF 1 rt $ 2-7/8" Production 6.4 L-80 8rd 2.441 Surf 9,900' +' 1 4 Mt i N JEWELRY DETAIL I /11r 5 at i, Fi No. Depth ID OD Item a q 1 18.6' 2.44" - Tubing Hanger 2 ±2,850' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port 6 1 A 3 ±4,600' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD Dummy i. f 4 ±5,950' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port et 5 ±6,900' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD Dummy '� 7 iN11 a i ail 6 ±7,600' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD Dummy III ; 7 ±8,200' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port F, 8 an p 8 ±8,700' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD Dummy Ilk M 9 ±9,200' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD Dummy 9 1111111P 10 ±9,700' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port Orifice ' 10 111B 11 ±9,850' 2.313" 6.5" On/Off Tool w/X Nipple 12 ±9,860' 2.44" 6.675" Arrowset Mechanical Packer 11 4IR 13 ±9,900' 2.313" WL Entry Guide w/X Nipple ' I I 12 M r PERFORATIONS 13 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date -' H3/4 ±10,853' ±10,870' ±10,643' ±10,659' 17' 6 3-3/8"HC March 2013 7-5/8" 4 x ae w kt LA Ili rya ;i# H3/4 I i i.ir sr 0 gi qt I. k' !! 6-3/4"Hole TD=11,322/ND=11,085' PBTD=11,177/ND=10,942' Updated by DMA 03-04-13 Swanson River SRU 14B-27 and 13-27 03/05/2013 Hiker!'Alad'a.I.IA: Swanson River SRU 14B-27 and 13-27 Williams BOP 2013 fid:111rrn n in II l II Ytt • `l 3.46' Shaffer 11"5M I ` Ill It Shaffer LWS ` ® ` 2.75' 0 2 1/16 10M Choke and Kill o Valves . - 5 If' III Ifl 1f1 111 it .0 _ - 1 1{ I}l _ {' }, 2.00' LI • �. .� �� I.Llltl.rlil1l�l. II `f wino, - G ci._: 10) •., ,• VAS ��I �r4 11 4 , • . not' In 1-10 -4 , 1 - * . . ilMille 'i gal! Ilibit Z.: :11 4 1_ I i i, •SRU 12-27 KGS�SRI KGSRU 212-27 SRU 2' Fol KGSF7 • KGS SRU 223-28 - , „ 1;L ,iI SF7p SRU 2 2 . :. GSF7A SRU 314-27PBl'2SRU 314-27 SRU 34-28 SRU 314-27PB1 A028406 351'FSL, 85'FWL,Sec 27,T8N,R9W,S BHL A028399 Top of Produptlo Horizon 301'FNL,282'FE}/,Sec 33,T8N,R9W,S S008N009W SRU 211-33 f / •SRU 21-33WD / •SRU 21-33WD SRU 21-34SRU 21-34 i SRU 21A-34 SRU41-33Wf ' ''z'NDiRU 41-3 SHL SRU 21A-34 855'FNL,738'FEL,Sec 33,T8N,R9W,S • SRU 32-33WD Sick} SRU 32A-33 SRU 32A33 SCU 343-33 Legend SCU 13-34 Surface Location A028990 • Top of Production Horizon • Bottom Hole Location SCU 343 i YSCU 33-33 Well Track 0 975 1,950 Swanson River Unit Feet SRU 14B-27 Alaska State Plane Zone 4,NAD27 Hilcorp Alaska,LLC May 3,2012 v • Swanson River SRU 13-27 and 14B-27 03/11/2013 I .I rp U.e.k...I.I1. Swanson River Tubing hanger, SME-CL, 11 X SRU 13-27 and 14B-27 3 1/2 EUE lift and susp, w/ 3" 16 X 10 3/ X 7 5/8 X 2 7/8 Type H BPV profile, 2- 3/8 CCL, Alloy material BHTA, Bowen, 3 1/8 5M FE X 3" Bowen Quick Union \`' t:cc• .i1L.m..., •\� Valve, Swab, W KM-M, .7. ,, J� c� �v. �� 3 1/8 5M FE, HWO, DD trim e ', 4bg`' HOP tellYNI e), flit jr IP , r--- - Valve, Wing, WKM-M, : \ /` r � i 1 At 2 1/16 5M FE, HWO, DD trim ,S°�41 g 'i �v �1 0 4A' 11Jy i ' 0, C ii I ' I 1 k____ 4' k....1 _ _ 4' 1 "' Valve, Wing, WKM-M, Valve, Upper Master (7:::' ) 3 1/8 5M FE, w/ Barber Self WKM-M, 3 1/8 5M FE, HWO, �a ��-lr Contained Hydraulic SSV, DD trim 1 fir_- _ EE trim Valve, Master, WKM-M, -, r( ; o,) 3 1/8 5M FE, HWO, DD trim Grade Level _ Iiii ; .� : Multibowl Wellhead, SMB- 22, 11 5M X 16 3/3M, w/ 1 ^ . I ' ' 4- 2 1/16 5M SSO �� ' ii ' 7 5/8 mandrel hanger and ill N' packoff installed in head c ,kms i l' E 1, !i� ,.( f ,� s If a Starting head, Seaboard, _,,,,,0 „( .. 16% 3M X 16" SOW,w/ �,._J f 2 2 1/16 5M EFO 'I'jI,,� , ., 103/ mandrelhanger and i ' packoff installed in head La..—on Ellison Hilcorp Alaska, LLC GeoTech II 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8339 ltd rp u;t.1;1.1.1Fax: 907 777-8510 E-mail: lellison@hilcorp.com DATE 1/31/2013 To: AOGCC Makana Bender 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL Transmitted herewith are cuttings from Swanson River Unit 14B-27 WELL SAMPLE INTERVAL SRU 14B-27 2979'-4560' �} SRU 14B-27 4560-6120' ) 3 "I SRU 14B-27 6120'-7770' SRU 14B-27 7770'-9270' SRU 14B-27 9270'-10610 SRU 14B-27 10610'-11320' 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: litix„...4 Date: AOGCC Memorandum Date: December 6, 2012 To: Well File— SRU 14B-27 (PTD 2120890) From: Jim Regg, Petroleum Engineer cel (Z,1(011-1.-- Subject: Z,1(0/iySubject: Shut down of Drilling Operations—Doyon Rig 1 (Arctic Fox) Hilcorp Alaska LLC (Hilcorp) was advised to shut down drilling on Swanson River Unit 14B-27 at 3:21 pm on December 5, 2012 until concerns with the diverter vent line can be resolved. December 5, 2012 At 9:11 am, I contacted Mr. Luke Keller, Hilcorp Drilling Engineer, to discuss observations by an AOGCC Inspector during the diverter inspection conducted the previous day. I asked who required installation of a barrier at the outlet of the diverter vent line [photos attached]. He said the US Bureau of Land Management (BLM) and US Fish& Wildlife Service required installation of the barrier as a condition of drilling "to prevent any fluids during divert from exiting the pad". I expressed concern that this placed a preference on protecting some trees and forest land over human safety. He agreed with me that this was not a good, safe design but said Hilcorp was caught in the middle and this was thought to allow them to move forward. This issue was discussed with other AOGCC engineering staff and Commission Chair Cathy Foerster; there was complete agreement that the barrier represented a situation that is inconsistent with good oilfield engineering practice and a real hazard to the successful evacuation of personnel in the event of an uncontrolled flow requiring diversion of wellbore fluids. It was agreed that I would contact Hilcorp and require the shutdown of drilling operations until this concern was resolved. 1253pm—call Mr. Luke Keller; left message 1:59 pm—Mr. Keller returned my call; left message for call back 3:16 pm—Returned call to Mr. Keller; left message for call back 3:21 pm—Mr. Keller and I discussed concern; I ordered drilling operations to stop At 3:46 pm, I received a call from Mr. Paul Mazzolini, Hilcorp Drilling Manager to discuss our shut down order. I told him that AOGCC was not going to yield on its position about the barrier outboard of the diverter vent line outlet—it represented a risk to continued safe operations. At 4:30 pm, Mr. Mazzolini contacted me again; he left a message for call back, asking if drilling could recommence if the barrier were removed. I returned his call at 4:37 pm and advised that AOGCC would allow Hilcorp to recommence drilling when the barrier was removed. I followed up the phone call with an email including the same information. December 6, 2012 At 9:29 am, Mr. Luke Keller (Hilcorp) called to notify AOGCC that BLM had agreed to the removal of the barrier after hearing of AOGCC's objection. S r=at t4>3-z-7 pria Zl Z0f3g0 Regg; James B (DOA) From: Regg, James B (DOA) c>� i Z 6 1 1 -- Sent: Thursday, December 06, 2012 9:47 AM To: Foerster, Catherine P (DOA); Schwartz, Guy L (DOA) Subject: FW: SRU 14B-27 Issue resolved; Luke Keller(Hilcorp; Drlg Engineer) called this morning; said Hilcorp discussed again with BLM and they agreed with our position; allowed Hilcorp to remove the wall. Luke said that BLM actually has a requirement against obstructions outboard of the vent line. I apologized that it got to this and suggested—as a future consideration-to engage us before initiating ops when they are faced with requirements that conflict with ours. Jim Regg AOGCC 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-793-1236 From: Regg, James B (DOA) Sent: Wednesday, December 05, 2012 4:45 PM To: 'Paul Mazzolini' Cc: Foerster, Catherine P (DOA); John Barnes; Luke Keller; Kate Kaufman; Schwartz, Guy L (DOA) Subject: RE: SRU 14B-27 Removal of rig back splash is our concern. We approved vent line configuration with long radius bend. Jim Regg AOGCC 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-793-1236 From: Paul Mazzolini [mailto:pmazzolini@ hilcorp.com] Sent: Wednesday, December 05, 2012 4:37 PM To: Regg, James B (DOA) Cc: Foerster, Catherine P (DOA); John Barnes; Luke Keller; Kate Kaufman Subject: SRU 14B-27 Jim, I left a voice mail on your office phone. My question: If the rig mat back splash was to be removed could Hilcorp continue the surface hole drilling operations on SRU 14B-27? If you could give me some direction I would be most appreciative. Sincerely, See aciGC,ed, Paul Mazzolini - ��tc©!'p �-r<_s ibts hc4- 4tT7 Drilling Manager le-442191:2- '.7 U t i bz- 30( Hilcorp Alaska, LLC ` Gjdu.h bt kC erne;- diC ‘.,e-„�--(4 1 Cc (��-) Was h' ) beer uuts ref, • Doyon 1 —Diverter Vent Line Rig-up SRU 14B-27 (PTD 2120890) Photos by AOGCC Inspector L. Grimaldi 12/3/2012, 12/4/2012 Doyon 1 (Arctic Fox) diverter vent line proposed for SRU 14B-27. Hilcorp proposed this layout to accommodate BLM and USF&WS issues with vent line extending off pad, and to gain the required 75- foot separation from closest ignition source. x40 k ...� 4 ' rrtdr �` . )) r f.R 41 4f• � s / SRU ,•33 Pad . � �► 'r / iii `� , ,; if • itt , Alr wit 4 pill • 7 orr4ftyf= Diverter Line • � �., A 4 2012-1204_Diverter_Doyon l_vent-line-photos_SRU_14B-27_1g.docx Page 1 of 3 Next 4 photos show the diverter vent line configuration and a barrier directly outboard the vent line outlet as observed on December 3-4, 2012 by AOGCC Inspector. 0 16-inch vent line w/ f: - Ili r-- o targeted turns(2)to ,1 s r _ I Al accommodate BLM ,_ .,._ airir = and USF&WS concerns a lam* P ,3,a 1 _ W -.._....:'mow- - J i ,w. , "4` y a t1 1 ,4 k " .. r . r t. t i, TSF Barrier at end of I diverter vent line 1 required by BLM and I i _ USF&WS; not an AOGCC requirement o.� 3 \ %. ,, ,, " f .�. � . ,-� Aft 2012-1204_Diverter_Doyon l_vent-line-photos_SRU_14B-27_1g.docx Page 2 of 3 • o J j iiIK. -,/,..irr C. : _ . !. . , .. r• 1.44.464444 �y�'�•yam. a R�'p�' • g, Barrier at end of diverter vent line required by BLM �--� and US F&WS; ._,'........-11110,74, :' not an AOGCC ., i •" r; " requirement • 1 i A Atil t.._ ;I yid I'. ^ter. am. - -.•1 t 3:7 . ,wet' R I f : l 7 v.K« + i 41101 f 0 . _ i 10.4004i ,. 2012-1204_Diverter_Doyon l_vent-line-photos_SRU_14B-27_lg.docx Page 3 of 3 Page 1 of 1 Schwartz, Guy L (DOA) From: Regg, James B (DOA) Sent: Wednesday, December 05, 2012 4:45 PM To: Paul Mazzolini Cc: Foerster, Catherine P (DOA); John Barnes; Luke Keller; Kate Kaufman; Schwartz, Guy L (DOA) Subject: RE: SRU 14B-27 Removal of rig back splash is our concern. We approved vent line configuration with long radius bend. Jim Regg AOGCC 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-793-1236 From: Paul Mazzolini [mailto:pmazzolini@hilcorp.com] Sent: Wednesday, December 05, 2012 4:37 PM To: Regg, James B(DOA) Cc: Foerster, Catherine P(DOA); John Barnes; Luke Keller; Kate Kaufman Subject: SRU 14B-27 Jim, I left a voice mail on your office phone. My question: If the rig mat back splash was to be removed could Hilcorp continue the surface hole drilling operations on SRU 14B-27? 1 If you could give me some direction I would be most appreciative. Sincerely, Paul Mazzolini Drilling Manager Hilcorp Alaska, LLC 12/5/2012 Page 1 of 1 Schwartz, Guy L(DOA) From: Luke Keller[Ikeller@hilcorp.com] Sent: Thursday, November 29,2012 4:04 PM To: Schwartz, Guy L(DOA) Cc: Jimmy Greco-(C); Paul Mazzolini; Kate Kaufman;Jimmy Greco-(C);Charlie Huntington(arcticfox@doyondrilling.com);Todd Driskill(tdriskill@doyondrilling.com)(tdriskill@doyondrilling.com) Subject: SRU 14B-27 Diverter Line(PTD#212-089) Guy, Per our conversation,we are going to set up the diverter line as per the below drawing for SRU 14B-27. We will run the line to the back corner of the pad,but to satisfy the BLM requirement,it will terminate just inside the berm. We will ensure this is 75'from the nearest ignition source. As you can see from the picture below—in the event the diverter is functioned in a well control situation,personnel will egress from the other side of the pad. v$4r .� ! 4a�! • 4. '4'1.-'4'" n i 1 71 .:"..!''.::9:4''''' "411 - � , 1'.; :'.-'I'°-''..-1:' . '..1411111:.'l/ ' i Vit, os r ; 'I Ili . .� "1_ r 5 v ;e��' `'. LT i 11;-; lie API 4jam.• �:. t ' SR ..1-33 if,i-- .3:¢_ .,�•. SRU 1 „fir y06-:; Iii, . '` ' <��� . �1nMR' ' � .4c#7,1:. 4, Divert 1 ' si'/ +., , a t 1 y .'-'-' -1 :. • # w E _ .4,+n. - 'ry 4 lir Luke Keller Drilling Engineer Hilcorp Alaska,LLC 907-777-8395 11/29/2012 r �� 11/7 0) 11/7;';' THE STATE Alaska Oil and Gas °fALASKA Conservation Commission c GOVERNOR SEAN PARNELL 333 West Seventh Avenue Op - N Anchorage, Alaska 99501-3572 -ALAS Main: 907.279.1433 Fax: 907.276.7542 Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive Anchorage, AK 99524 Re: Swanson River Field, Hemlock Oil Pool, SRU 14B-27 Hilcorp Alaska, LLC Permit No: 212-089 (revised) Surface Location: 758' FNL, 635' FEL, SEC. 33, T8N, R9W, SM Bottomhole Location: 370' FSL, 252' FWL, SEC. 27, T8N, R9W, SM Dear Mr. Keller: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the 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 revocation or suspension of the permit. Sincerely, 74 ° • Cathy . Foerster Chair DATED this LI) day of November, 2012. cc: Department of Fish 86 Game, Habitat Section w/o encl. (via e-mail) Department of Environmental Conservation w/o encl. (via e-mail) STATE OF ALASKA 1 REVISED ,KA OIL AND GAS CONSERVATION CON. MON REVISED PERMIT TO DRILL 20 AAC 25.005n U 1a.Type of Work: lb.Proposed Well Class: Development-Oil 0 ,Service- Winj 0 Single Zone �/'Ic.Specify if well is proposed for: Drill Q ' Lateral ID Stratigraphic Test ❑ Development-Gas 0 Service-Supply ❑ Multiple Zone 011'2 Coalbed Gas 0 Gas Hydrates 0 Redrill 0 Reentry ❑ Exploratory ❑ Service- WAG 0 Service-Disp ❑ Geothermal 0 Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket 0 Single Well 11'/ �P .Well Name and Number: Hilcorp Alaska,LLC Bond No. 22 7 L2h35,ZJ1' , 'SRU 14B-27 3.Address: 6.Proposed Depth: 12.field/Pool(s): 3800 Centerpoint Dr,Anchorage AK,99524 MD: 11,300 TVD: 11,055 Swanson River Field/ 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Hemlock Oil Pool • Surface. 758'FNL,635'FEL,Sec 33,T8N,R9W,SM A028399,A028406- Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 301'FNL,282'FEL,Sec 33,T8N R9W,SM N/A 11/28/2012 Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 370'FSL,252'FWL,Sec 27,T8N,R9W,SM 4800 �$.�� •••-. b(D t- �nr,r £' 1I -r"r9 • 4b.Location of Well(State Base Plane Coordinates-NAD 27). 10.KB Elevation above MSL: 179 feet 15.Distance to Nearest Well Open'A?' Surface: x-347047 - y-2465683 . Zone-4 GL Elevation above MSL: 164/„ feet to Same Pool: 21A-34(1535)ei zf '`Z 16.Deviated wells: Kickoff depth. 1600 feet 17.Maximum Anticipated Presages in psig(see 20 AAC 25.035) Maximum Hole Angle. 21 degrees Downhole: 441101. 'Surface: 2656 . 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) Cond 16" - - - 80 0 0 80 80 Conductor 13-1/2" 10-3/4" 45.5 L-80 BTC 3000 0 0 3,000 2,998 1814ft3 lead,414ft3 tail 9-7/8" 7-5/8" 29 7 L-80 BTC 9000 0 0 9000 8908 (Yj 9-7/8" 7-5/8" 29.7 P-110 HC LTC 1000 9000 8908 10000 9841 1600ft3 lead,396ft3 tail 6-3/4" 5" 15 L-80 DWC/C HT 1892 9800 9655 11300 11055 360ft3 tail 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth TVD(ft): Plugs(measured): Effect.Depth MD(ft): Effect.Depth TVD(ft): Junk(measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface RECEIVED Intermediate Production Liner N DV 2 12012 Perforation Depth MD(ft). Perforation Depth TVD(ft): AOGCC 20. Attachments' Property Plat Q BOP Sketch Q Drilling Program Q Time v.Depth Plot ❑✓ Shallow Hazard Analysis❑ Diverter Sketch Q Seabed Report 0 Drilling Fluid Program Q 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. Contact Email Printed Name /til-E, /414- Title D/y,�j7y 6-4 9/4Pt°r- Signature 1/ —A - Phone(907) 777—— g.? ?_S- Date 1 1/i0/"6/2 Commission Use Only Permit to Drill API Number _� Permit Approva See cover letter for other Number: 212-089 50-f��`2C? t'C �'{� Date \\A./7 i2 requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methane, as hydrates,or gas contained in shales: Other: .ieye" s c. go P T,..f-- Samples req'd. Yes El No[t Mud log req'd:Yes III IV 7 p HZS measures: Yes❑ NoE/ Directional svy req'd:Yes Di No❑ ZS-00 e5 A r!nt ---/;—"5 fr— Spacing exception req'd: Yes❑ Nog Inclination-only svy req'd.Yes❑ NoII ' .., &-.1.4...karti re.3 ...42,,,, ,_ c,.,o“-.-. APPROVED BY 7 Approved by: ti9COMMISSIONER THE COMMISSION Date://..-(,$—/Z 0 R loG !!•L?•!L Submit Form and e � ) This permit is valid for 24 months from the date of approval(20 AAC 25.005(g)) Attachments Hilcorp Alaska, LLC SRU 14B-27 Drilling & Completion Program Swanson River Revision 0 Nov 19, 2012 Hilcorp Paul Mazzolini Hilcorp Alaska, LLC Ramp Compeny Drilling Manager P.O. Box 244027 Anchorage,AK 99524-4027 11/20/2012 Tel 907 777 8369 Email pmazzolini@hilcorp.com Commissioner RECEIVED Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue NOV 2 12012 Anchorage, Alaska 99501 AOGCC Re: Swanson River Unit 14B-27(PTD#212-089) Dear Commissioner, Enclosed for review and approval is the revised application for the Permit to Drill the Swanson River Unit 14B-27. A change in surface location necessitated an APD revision. Additional changes to the approved PTD are summarized on attached "Changes to Approved Permit to Drill"document. Drilling operations will be conducted by the Doyon Arctic Fox. The Arctic Fox is a 400 kip, multi- module drilling unit with a telescoping doubles mast. Drilling operations are expected to commence approximately Nov 28th, 2012 depending on the progress of SCU 43A-33. - If you have any questions, please don't hesitate to contact myself at 777-8369 or Luke Keller at 777- 8395. Sincerely, Paul Mazzolini Drilling Manager Hilcorp Alaska, LLC Page 1 of 1 Hilcorp Alaska, LLC Hilcorp Changes to Approved Permit to Drill Date: Nov 20, 2012 Subject: Changes to Approved Permit to Drill for SRU 14B-27 File#: SRU 14B-27 Drilling and Completion Program Any modifications to SRU 14B-27 Drilling &Completion Program will be documented and approved below. Changes to an approved APD will be communicated to the AOGCC. Sec Page Date Procedure Change Approved Approved By By 1 2 11/20/2012 Moved surface location 141' East to the other side of the LEK PM pad. New coordinates are on attached Drilling Program. 32,33 54-60 11/20/2012 Directional plan changed slightly due to changed surface LEK PM location. BHL is 38'SE of the approved APD. MD has been shortened to 11,300'. P4 is the current rev. • 6 6 11/20/2012 We would like to reduce the initial BOP test pressure to LEK PM 4000 psi,so that all tests are 4000 psi. There is nothing to be gained by testing the BOPs initially to 5000 psi. 14 25 11/20/2012 7-5/8" L-80 casing thread has now changed to BTC LEK PM instead of LTC. 17 34 11/20/2012 Production liner will be 5" DWC/C HT instead of 5-1/2" LEK PM VAM STL. 37 64 11/20/2012 Surface hole will be drilled with 10 ppg MW instead of 9.2 LEK PM ppg 37 64 11/20/2012 Intermediate hole section will start with 10.5 ppg, and LEK PM slowly weight up to 12.5 ppg per attached drilling program 13,16 24,32 11/20/2012 9-7/8" &6-3/4" hole sections will be E-line logged. Will LEK PM run only Gamma Ray on drilling assy. (-P Pp \ Y AZZOL./N I 1`` j/Z. Approval: �„�; ?AUL. � Drilling M a er �"� Date Prepared: / lf!/ate 0 /.2 Drilling Engineer ate SCU 14B-27 Changes to APD Nov 2012 Swanson River Unit 14B-2H11CO22 Emu Drilling Procedure Contents 1.0 Well Summary 2 2.0 Tubular Program- 3 3.0 Drill Pipe Information• 3 4.0 Planned Wellbore Schematic 4 5.0 Drilling/Completion Summary 5 6.0 Mandatory Regulatory Compliance/Notifications 6 7.0 R/U and Preparatory Work 8 8.0 21-1/4"2M Diverter N/U and test 9 9.0 Drill 13-1/2"Hole Section 11 10.0 Run 10-3/4"Surface Casing 14 11.0 Cement 10-3/4"Surface Casing 16 12.0 BOP N/U and test 18 13.0 Drill 9-7/8"Hole Section 19 14.0 Run 7-5/8"Production Casing 25 15.0 Cement 7-5/8"Cement Procedure 27 16.0 Drill 6-3/4"hole section 30 17.0 Run 5"Production Liner 34 18.0 Cement 5"Production Liner 37 19.0 Wellbore Clean Up&Displacement 40 20.0 RDMO 40 21.0 BOP Schematic 41 22.0 Wellhead Schematic 42 23.0 Days Vs Depth 43 24.0 Geo-Prog 44 25.0 Anticipated Drlg Hazards 45 26.0 Rig Layout 48 27.0 FIT Procedure 49 28.0 Arctic Fox Choke Manifold Schematic 50 29.0 Casing Design Information 51 30.0 9-7/8"Hole Section MASP 52 31.0 6-3/4"Hole Section MASP 53 32.0 Directional Program(P4) 54 33.0 Directional Plan View(Plot) 60 34.0 Plan View(XV) 61 35.0 Surface Plat(NAD 27) 62 36.0 Spider Plot(Governmental Sections) 63 37.0 Mud Weight,PP,FG vs Depth Plot 64 Swanson River Unit 14B-27 Drilling& Completion Procedure HilCc2FT EnalY 1.0 Well Summary Well SRU 14B-27 Pad&Old Well Designation SRU 41-33 Pad/SRU 14B-27 is a grass roots well L/ Planned Completion Type: Gas lift on 3-1/2"IBT production tubing Target Reservoir(s): Hemlock Planned Well TD,MD/TVD: 11,300'MD/11,055'TVD . PBTD,MD/TVD: 11,200'MD/10,962'TVD Surface Location(Governmental) 758'FNL,635'FEL,Sec 33,T8N,R9W,SM Surface Location(NAD 27) X=347047,Y=2465683 Surface Location(NAD 83) Top of Productive Horizon(Governmental) 301'FNL,282'FEL,Sec 33,T8N R9W,SM TPH Location(NAD 27) X=347784,Y=2466585 TPH Location(NAD 83) BHL(Governmental) 370'FSL,252'FWL,Sec 27,T8N,R9W,SM BHL(NAD 27) X=347965,Y=2466807 BHL(NAD 83) AFE Number 1211615 AFE Drilling Days 28 AFE Completion Days 7 AFE Drilling Amount $4.713 MM AFE Completion Amount $1.571 MM Work String: 5" 19.5#S-135 NC-50(Rental string from Weatherford) 4" 14#S-135 HT-38(Rental string from Weatherford) RKB—GL: 18.6' Ground Elevation: 164'AMSL BOP Equipment 11"5M Schaffer Annular BOP 11"5M Schaffer Double Ram 11"5M Schaffer Single Ram Page 2 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company 2.0 Tubular Program: Hole 0 ) IR(in) Drift Conn Wt cin#e Conn Burst Collapse Tension ;. Section (in) OD (in) (#/ft) (psi) (psi) (k-lbsyll Cond 16" 15" - - 109 X-56 Weld 13-1/2" 10-3/4" 9.95" 9.875" 11.75" 45.5 L-80 BTC 5210 2480 1040 9-7/8" 7-5/8" 6.875" 6.75" 8.5" 29.7 L-80 BTC 6890 4790 683 9-7/8" 7-5/8" 6.875" 6.75" 8.5" 29.7 P-110 HC LTC 9470 7580 769 6-3/4" 5" 4.408" 4.283" 5.563" 15 L-80 DWC/C 8290 7250 350 HT 3.0 Drill Pipe Information: Hole OD (in) ID (in) TJ ID TJ OD Wt Grade Conn Burst Collapse Tension Section (in) (in) (#/ft) (psi) (psi) (k-lbs) 13-1/2" 5" 4.276 3-1/8 6-5/8 19.5 S-135 NC-50 17,100 15,110 560 4" 3.34 2-9/16" 4-7/8" 14 S-135 HT-38 18,400 13,800 403 Page 3 Revision 0 Nov,2012 • Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company 4.0 Planned Wellbore Schematic 4 Swanson River Unit lill ,` 6h:ell't.RL!14E-47 r1.Igt k gat -'Planned,.V D 103-THF:13.6' Casing & Tubing Type ..V‘', Grede Conn. ID Top Btm f l. 1 L_J [ .cnductar- 15'di 15 2-a'entoSet - - Surf SC' Depth - —11 1: _ Surf.Cs; =5.5 L-8J "cattress =._"5 Surf 52.,- 29? L-SC STC _"5 Surf 4. l fl --5'_ terme.._ 29.7 P-11 _ H. 1T2 _= 75 9.000' 12 10-3 4-4 , c_.r DWCIC 5' 15 L-8 HT 4.255 9.800' 115:: :.I t . 5.1.2 Production 1-8016- _ i___ 5_ _.__- JEWELRY DETAIL Depth ID OD Item :lI b . - 20' 2.44' - Tubing Hanger 2 1,300' 2.44' 4.75_` 3-1./2'SF0-1Mandrei6RD12port * p ' _ 2,400' 244" 4.75D. 3-1/2'SFO-1 Mandrel BR.D 12 p_'•t 1 r 1 4 3,500' 2.44" 4.752 3-1J2"5FO-1 Mandrel ERD 12 port i 8 _ 4, �t600' 2.44 4.75. 3-112"SF0-1 Mandrel BRD12port _ 5,209' 2.441 4.750' !-1,I2"5F0-1 Mandrel SPD 12 port 7 5,200' 2.44' 4.750' 5-1/2"SFO-1 Mandrel ERD 12 port y E 6,900' 2.44" 4.730' 3-1,/2"SFO-1 Mandrel&RD 12 port 10/ 1 - 7,900' 2.41' 4.750' 3-112"SFO-1 Mandrel BRD 12 pc"t i i E e 1- 9,760' 2.000' 6.5' O n/Off Tool w/X Nipple 1 : •: it _1 9,7E0' 1.57E'' 4.14_" r g9A1'Iet M echa nice I Packer 11 12 9,500' - - WL Entry Guide w/X Nipple ®® ,r 7.cS-elli 12 V' L I, TD=11,300 TIT=11,0cc` Page 4 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp 5.0 Drilling / Completion Summary SCU 14B-27 is a grass roots development oil well to be drilled off the SRU 41-33 pad. Integrated subsurface and 3-D geological interpretations, in conjunction with previous production data, indicates that stranded oil reserves remain in the Hemlock 1-5 benches between the F and G faults. High on structure, G2,H1-4,reserves aren't recoverable in existing wellbores due to lack of takepoints, or mechanical condition of other existing wellbores in the fault block. H10 sands may be productive as well. The base plan is a slightly deviated wellbore reaching a maximum inclination of 21 deg and a 1451' vertical separation. Drilling operations are expected to commence approximately Nov 28th, 2012. The Doyon Arctic Fox will be used to drill and partially complete the wellbore. The Williams rig or AWS #1 will be used to perforate the liner and run the 3-1/2"production tubing. General sequence of operations: 1. MOB Doyon Arctic Fox to well site 2. N/U& function test 21-1/4" 2M Diverter 3. Drill 13-1/2"hole to 3000' MD. Run and cmt 10-3/4" surface casing. 4. N/D diverter,N/U &test 11"x 5M Hydril BOP. 5. Drill 9-7/8"hole section to 10,000' MD. Run wireline logs. Run and cmt 7-5/8" intermediate casing. 6. Drill 6-3/4"production hole section to TD. Run wireline logs. Run and cmt 5"production liner. 7. TIH w/clean out assy, clean out liner to landing collar. Displace mud to 6%KC1 filtered completion fluid. 8. TOH, LDDP 9. N/D BOP,N/U temp abandonment cap, RDMO Page 5 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Enny comp.), 6.0 Mandatory Regulatory Compliance/Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC and BLM regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drlg Team. • BOPs shall be tested at(1)week intervals during the drilling and completion of SRU 14B-27. Ensure to provide AOGCC 24 hrs notice&BLM 48 hrs notice prior to testing BOPs. • • The initial test of BOP equipment will be to 250/4000 psi & subsequent tests of the BOP equipment will be to 250/4000 psi for 10/10 min(annular to 50%rated WP,2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 7 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system" • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements" • All Federal regulations within BLM"Onshore Oil and Gas Order#1" • Ensure both AOGCC &BLM approved drilling permits are posted on the rig floor and in Co Man office. Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 13-1/2" • 21-1/4"x 2M Hydril MSP diverter Function Test Only • 1 1"x 5M Hydril GK Annular BOP • 1 1"x 5M Hydril Double Ram Initial Test:250/4000 o Blind ram in btm cavity (Annular 2500 psi) 9-7/8" & 6-3/4" • Mud cross • 1 1"x 5M Hydril Single Ram Subsequent Tests: • 3-1/16"5M Choke Manifold 250/4000 • Standpipe,floor valves,etc (Annular 2500 psi) • Primary closing unit: 1 ea.—Olio,6 station, 3000 psi, 180-gallon accumulator unit,with a remote control panel in the doghouse. • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Secondary back-up is an air pump, and tertiary emergency pressure is provided by bottled nitrogen. Page 6 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Ella'SY cooper Required AOGCC Notifications: • Well control event(BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running&cement operations. • Any other notifications required in APD. Required BLM Notifications: • 48 hours before spud. Follow up with actual spud date and time. • 48 hours before casing running and cmt operations • 48 hours before BOPE tests • 48 hours before logging, coring, &testing • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email:jim.regg@alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-276-7542/Email: guy.schwartz@alaska.gov Victoria Ferguson/Petroleum Engineer/(0): 907-793-1247/Email: Victoria.ferguson@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone: 907-793-1236(During normal Business Hours) Notification/Emergency Phone: 907-659-2714 (Outside normal Business Hours) BLM Tom Zelenka/BLM Petroleum Engineer/(0): 907-271-4224 (C): 907-301-8972 Justin Miller/BLM Petroleum Engineer/ (0): 907-271-3406 (C): 907-717-4039 Use the below email address for BOP notifications to the BLM: BLM AK AKSO_EnergySection_Notifications@blm.gov Page 7 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp 7.0 R/U and Preparatory Work 7.1 Set16" conductor at 60' below ground level. 7.2 Dig out and set"Cellar Tech" impermeable cellar. 7.3 Install slip-on 16-3/4" 3M"A" section. Ensure to orient wellhead so that tree will line up with flowline later. 7.4 Level pad and ensure enough room for layout of rig footprint and R/U. 7.5 Layout Herculite on pad to extend beyond footprint of rig. 7.6 R/U Doyon Arctic fox, spot service company shacks, spot&R/U company man&toolpusher offices. 7.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 7.8 Mix mud for 13-1/2"hole section. 7.9 Set test Plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped during N/U of BOP. 7.10 Install 5" liners in mud pumps. We will need all (3)pumps to pump at 600 - 650 gpm. • 750 HP PZH mud pumps are rated at 3912 psi with 5" liners. Page 8 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling& Completion Procedure Hilcorp 8.0 21-1/4" 2M Diverter N/U and test 8.1 N/U 21-1/4" Hydril MSP 2M diverter System. • N/U 16-3/4" 3M x 21-1/4" 2M DSA(Hilcorp) on 16-3/4" 3M wellhead. • N/U 21-1/4"diverter"T" (Doyon). • Knife gate, 16" diverter line (Doyon). • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C) 8.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 8.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone"must include: • A prohibition on vehicle parking • A prohibition on ignition sources or running equipment • A prohibition on staged equipment or materials • Restriction of traffic to essential foot or vehicle traffic only. 8.4 Set 15.375" ID wearbushing in wellhead. Page 9 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company 111 SRU 14B-27 ILA Y.rp P.F.LA I.f R. Drverter Sclwrrtatic For 13-W Hale Section II 0 III III III III III III III III HydrFl MSP 214 '2M III III III III I i I Kn le Ga'e I11 til lei III II II Diverber Tee,71-' x21-'4"x 2D.+v.'17 ANSI 150 outlet III III III tit tit 16-'f4"3M x 21-'W 2M USA f .Ili! /, l'Imialli sr k Seaboard 16-W 3M i � 9 Casing need Assy III I Page 10 Revision 0 Nov, 2012 Swanson River Unit 1:1114B-27 Drilling & Completion Procedure Hilcorp Energy Company 9.0 Drill 13-1/2" Hole Section 9.1 P/U 13-1/2"directional drilling assy: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Bit TFA should be .739 in2. We need to pump at 600 to 650 gpm to clean the hole effectively. • Have DD run an independent hydraulic analysis to confirm optimum TFA. • Motor AKO should be set at 1.2deg. Max DLS in the 13-1/2"hole section(P4) is 1.0 deg/100 • Workstring will be 5" 19.5# S-135 NC-50 9.2 Primary bit will be the Hughes Christensen 13-1/2" MXL-1X. These are available at Baker Hughes facility in Anchorage. 13 1/2"MXL-1X "Mat (342i r) • SEM II sealed bearing package(SEM QISEM II sealed bearing package is a second gencratiou patented ample energizer metal seal system with proprietary near resistant seal unlace to retard seal wearimprove sealing efficiency.and provide long life in high RPM motor applicmoes. •I4 { • GS cutting strvttma technology The Hating structure provides advanced cone profiles.re-engineered compact tooth shapes optm ized carbide grades. •/ t!a1' end strategically placed cone saves.Flexible hydraulics application specific choice abused or unbiased hydrardoe couflpnaaons to ensure optimum cone 'AO clearing.reduced balling.and managed erne erosion For long life and high 7►y penetration rates. —�`- • Fleslbk hydraulics Application specific choice of biased or tmbiased ape hydraulic configurations to minim optimum cone cleaningreduced balling.and .•afire managed cone erosion.For long life and high penenauon rates • Enhanced OD protection Improved apphcatsons of Ent aa2 motor ,£ q-�== hardfacurenen contoured shirttail geometry and BOSS pads for near six Foot stobihzalon Provides excellent leg and shirttail wear resistance.for long life m directional drilling applications. • ,i, PRODUCT SPECIFICATIONS: ]ADC: 117 .; . Bearing I Seal Package Jamal'Metal Cutting Stricture: ;, Inner Row NAHeel Row N'A leuse tws sower aopens raN d,si o Gauge Row NA Gauge Triers NA Tooth Hardfacurg. NA ODHordfacmg: NANozzle 7}pe. Standard Center Jet Display: NA Makeup Torque: 21.0-32 0 klbf-tt(33.0.43.3 kVm) Connecfion: 6-51 API A sox.Shipping Wight: ?Al'(115 7 kg) Reference Pan Atmrber 102045000 OPERATING RECO\LIIENDATIONS°: Weight On Be 20.47.5 klb(3-21 br orkdaN) Rotation Speed: For High Speed Rotarsv2.fotorAppliances nal alname.r'hriNe•sn ]OOt Ragas.amen:Len C=paac Page 11 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling& Completion Procedure Hilcorp Emory Compimy 9.3 5"HWDP &Jars will come from Weatherford. 9.4 13-1/2"proposed BHA: • 13-1/2" MTB (IADC 117) • Mud Motor(1.2deg) • Non-Mag Stab (13-3/8" OD) • NMPC • MWD (Directional + Inclination Only) • (3)Non-Mag Flex collars • XO • (5) 5" HWDP • 6-1/4" Dailey Jar • (21) 5" HWDP • 5" DP to surface. 9.5 No LWD tools will be run on the 13-1/2"hole section. ' 9.6 Begin drilling out from 16" conductor at reduced flow rates to avoid broaching the conductor. 9.7 Drill 13-1/2"hole section to 3000' MD /2998' TVD. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 600 - 650 gpm. This gives us an annular velocity of 90 fpm, which is borderline for effective hole cleaning. Ensure shaker screens are set up to handle this flowrate. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team,try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. Keep API fluid loss< 10. • TD the hole section in a good shale btwn 2900' & 3100' MD. • Take MWD surveys every stand drld. Page 12 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp --c 9.8 13-1/2"hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1)ppg above highest anticipated MW. MD Totco 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: 1 Oppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 80-3000' 10.0 - 60-85 10-30 45-25 <10 8.5-9.0 System Formulation: Aquagel/FW spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 12-15 ppb caustic soda 0.1 ppb (9 pH) BARAZAN D+ as needed BAROID 41 as required for weight 10 ppg PAC-L/DEXTRID LT if required for<12 FL ALDACIDE G 0.1 ppb X-TEND II 0.02 ppb 9.9 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16" conductor shoe. 9.10 TOH with the drilling assy, handle BHA as appropriate. 9.11 No open hole logs are planned for the 13-1/2"hole section. r Page 13 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company 10.0 Run 10-3/4" Surface Casing 10.1 R/U and pull 15.375"wearbushing. 10.2 R/U Weatherford 10-3/4"casing running equipment. • Ensure 10-3/4"BTC x 5"NC-50 XO on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted on the location prior to running. • Be sure to count the total #of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. 10.3 P/U shoe joint, visually verify no debris inside joint. 10.4 Continue M/U &thread locking shoe track assy consisting of: • (1) Shoe joint w/float shoe bucked on(thread locked). • (1)Joint with coupling thread locked. • (1)Joint with float collar bucked on pin end&thread locked. • Install (2) centralizers on shoe track over a stop collar. 10' from each end. • Ensure proper operation of float equipment. 10.5 Continue running 10-3/4" surface casing • Fill casing while running using fill up line on rig floor. • Use"API Modified"thread compound. Dope pin end only w/paint brush. • M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values required to achieve this position. Estimated torque to reach base of triangle: 10,750 ft-lbs. • After making up several connections, use the torque required to M/U to base of triangle as the M/U torque and continue running string. • Install (1) centralizer every other joint to 300'. Do not run any centralizers above 300' in the event a top out job is needed. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 10-3/4" BTC Estimated M/U Torque Casing OD Est Torque to Reach Triangle Base 10-3/4" 10,750 ft-lbs Page 14 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling& Completion Procedure Hilcorp Enemy Company CasingTubing and Performance Data PIPE BODY DATA GEOMETRY Outside Diameter 10.750 in Wall Thickness 0.400 in API Drift Diameter 9.794 in Nominal Weight 45.50 lbs/ft Nominal ID 9.950 in Alternative Drift Diameter 9.875 in Plain End Weight 44.26 lbs/ft Nominal cross section 13.006 In PERFORMANCE Steel Grade 180 Minimum Yield 80,000 psi Minimum Ultimate 95,000 psi Tension Yield 1,040,000 in Internal Pressure Yield 5,210 psi Collapse Pressure 2,470 psi Available Seamless Yes Available Welded No CONNECTION DATA TYPE:BTC GEOMETRY Coupling Reg OD 11.750 in Threads per in 5 Thread turns make up 1 PERFORMANCE Steel Grade 180 Coupling Min Yield 80,000 psi Coupling Min Ultimate 95,000 psi Joint Strength 1,063,000 lbs Internal Pressure Resistance 5,210 psi 10.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 10.7 Slow in and out of slips. 10.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at(1) ft intervals to use as a reference when landing the hanger. 10.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 10.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 10.11 After circulating, lower string and land hanger in wellhead again. Page 15 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company 11.0 Cement 10-3/4" Surface Casing 11.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. 11.2 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 11.3 Pump 5 bbls 10 ppg spacer. Test surface cmt lines. 11.4 Pump remaining 35 bbls 10 ppg spacer. 11.5 Drop bottom plug. Mix and pump cmt per below recipe. 11.6 Cement volume based on annular volume + 100% open hole excess. Job will consist of lead & tail, TOC brought to surface. Estimated Total Cmt Volume: Section: Calculation: Vol (BBLS) Vol (ft3) LEAD: 80' x .106 bpf= 8.5 47.8 16" Conductor x 10-3/4" casing annulus: LEAD: (2500' —80')x .065 bpf x 2 = 314.6 1766.5 13-1/2" OH x 10-3/4" Casing annulus: Total LEAD: 323.1 1814.3 TAIL: (3000'-2500')x .065 bpf x 2 = 65 365 13-1/2" OH x 10-3/4" Casing annulus: TAIL: 90 x .096 bpf = 8.7 48.8 10-3/4" Shoe track: Total TAIL: 73.7 414 Page 16 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company Cement Slurry Design: Lead Slurry (2500' MD to surface) Tail Slurry (3000'to 2500' MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.44 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Code Description Concentration Code Description Concentration Type' Cement 94 lb/sk WBWOB Type1 Cement 94 lb/sk WBWOB D110 Retarder 0.12 gal/sk VBWOC D046 Anti Foam 0.2 % BWOB Additives D046 Anti Foam 0.2% BWOB D065 Dispersant 0.4% BWOB D079 Extender 2.0% BWOB S002 CaCl2 0.2% BWOB D020 Extender 2.6% BWOB S002 CaCl2 0.2% BWOB 11.7 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 11.8 After pumping cement, drop top plug and displace cement with 10.5 ppg 6% KC1/PHPA drilling fluid (mud and MW to be used on next hole section). 11.9 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 11.10 Displacement calculation: 2910' x .0962 bpf= 280 bbls ✓ 11.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 11.12 Do not overdisplace by more than '/2 shoe track volume. Total volume in shoe track is 8.7 bbls. 11.13 Be prepared for cement returns to surface. ��G.-••a - ww,� 11.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. Page 17 Revision 0 Nov, 2012 Swanson River Unit 1414B-27 Drilling& Completion Procedure Hilcorp Emu Cir 11.15 R/D cement equipment. Flush out wellhead with FW. 11.16 Back out and L/D landing joint. Flush out wellhead with FW. 11.17 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 11.18 Lay down landing joint and pack-off running tool. 12.0 BOP N/U and test 12.1 N/D the diverter system. 12.2 N/U Seaboard multibowl wellhead assy. Install packoff 10-3/4"P-seals. Test to 3000 psi. 12.3 N/U 11"x 5M Hydril BOP as follows: • BOP configuration from Top down: 11"x 5M Hydril GK annular BOP/11"x 5M Hydril double ram/11"x 5M mud cross/Hydril single ram. • Double ram should be dressed with 5" Fixed ram in top cavity, blind ram in btm cavity. • Single ram should be dressed with 7-5/8" casing ram. • N/U bell nipple, install flowline. 12.4 Run BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/ psi for 10/10 min. Test annular to 250/2si for 10/10 min. • Ensure to leave "A" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 12.5 R/D BOP test assy. 12.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 12.7 Mix 10.5 ppg 6%KC1/PHPA drilling fluid for 9-7/8"hole section. 12.8 Set 10" ID wearbushing in wellhead. 12.9 Rack back as much 5" DP in derrick as possible to be used while drilling the hole section. Page 18 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Enew Comm, 13.0 Drill 9-7/8" Hole Section 13.1 P/U 9-7/8""Drill Out" assy consisting of: • 9-7/8"Mill Tooth Bit(Baker Hughes MXL-1)(IADC 117) • 9-3/4"Near Bit stab (bored for float) • Pony Collar • 9-3/4" String Stab • (1) 6-3/4" DC • 9-3/4" String Stab • (2) 6-3/4" DC • XO • (5) 5"HWDP • Drilling Jar • (21) 5" HWDP • 5"DP to surface 13.2 Ensure BHA components have been inspected previously. 13.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 13.4 Bit for the clean out run will be the Baker Hughes 9-7/8" MXL-1. These are available at Baker Hughes facility in Anchorage (style sheet on next page). 13.5 Bit TFA should be between 0.55 and 0.65 in2. We need to pump at a minimum of 500 gpm to clean the hole effectively. Have the directional drillers run hydraulics calculations to confirm optimum TFA. Page 19 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company 11 411- 9 INIXL-1 BAKER (250.8 mm) HUGHES • SEM II sealed'rearing package ISEMI 111 SEM II sealed healing package i;a second generation patented single energizernretal seal system with ptopuetaiy wear re;i;tant;eal sulfate to retard seal wear. .,. impact*:a sealing efficiency.and protide ion life in high RP.Y.mutat applications. Nft 1 Y GS cutting structure technology The cutting;ttn:tura protides advanced cone profile,re-ngneered compact tooth shape;.optimized carbide grades.and strategically placed corms savers. ‘0 ■ Flexible hydraulics Application specific choice of biased an'tn;biazd hydraulic confistnatiom;to en;me optimtwr cone cleaning.reduced balling.and managed cone co-ion.For long life and high pellet ation rate; • :;5 tt};;'zatiee 5,ac.LUTbese unique iutegated stabilizer,pro'.ide nem ix-point contact midi the boaehol_e wall ria unequaled stability and cutting sntsttire protection. • E than:ed OD pt otectiou Improved applications of Endtna2 motor hard acing.new contoured shirttail geaanent.and BOSS pad;fag near ;ix point stabilization.Protides cc:ellen leg and shirttail waif re;i;tante.for tang life in due.tianal drilling applications. Product Specifications IADC: 117 s,.. Bearing.'Seal Package: Jounnai'Metal >_> Cutting Structure: lane Row Stipa Thick Heel Row Bi-Metallic II Gauge Row Super Gauge Gauge Triunners N:'A Tooth HardtacinMAg: N OD Hardfacing_ Motor Nozzle Type_: Standard Conte Jet Display: FF as VF Makeup Torque: 28.0-32.0 klbf-8(38.0-43.4 kNm) Connection: 6-5'S REG API Approx.Stripping Weight: 145 lb(65.8 kg) Reference Put Number: H2O64901 Operating Recommendations*: Weight On Bit: 17.5-45 klb 17-20 to or kdaN) Rotation Speed: Fan High Speed Rotaati'Motoe Application; 'Tae:mites of Si a•eip:and RPM ftowo se:e7:esen:anveof typical oae:a:ae ata e:en hj:wit no:necessannk;}ieli o?:xrx'ri:)ifeo:lower Billing cos,I;s \v\rx.bakerhuPlieS.Corn na:commended i aa::Se•nne:hn:is ofao:i tela:and P.PM he inn six daneo:ssly ;'2012 Bald E.s¢>tes bcor+,aaated Allriglts reserved ins:a:%an:local I::sg:aes fhais:ensen rep:esenx:ir fa a ecor.menda:ions in so•.r a--ea Page 20 Revision 0 Nov, 2012 Swanson River Unit 1414B-27 Drilling& Completion Procedure Hilcorp Bump'ComPM 13.6 TIH to TOC (+/- 2900' MD). 13.7 R/U and test casing to 1500 psi/30 min. Ensure to record volume/pressure and plot on FIT graph. 13.8 9-7/8"hole section mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1)ppg above highest anticipated MW. MD Totco 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: 10.5ppg 6%KC1/PHPA fresh water based drilling fluid. Properties: Depths Density Viscosity Plastic Viscosity Yield Point HTHP FL pH 3000'-10000 10.5— 60 100 15-30 20-30 <10 8.5-9.5 - 12.5 System Formulation: 6% KCI / PHPA Product Concentration Water 0.905 bbl KCI 22 ppb Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.1 ppb (as required 18+YP) DEXTRID LT 1-2 ppb EZ MUD DP 0.5 ppb (initial .15 ppb) ALDACIDE G 0.1 ppb BAROID 41 208 ppb (as needed to 12.5) 13.9 Drill out plugs and shoe track. Clean out rat hole and drill an addition 20' of new formation. 13.10 CBU and condition mud for FIT. 13.11 Conduct FIT to 13.5 ppg EMW. Note: Offset field test data predicts frac gradient at the 10-3/4"shoe to be btwn 12.3 & 15.9 ppg EMW. A 13.5 ppg FIT results in a 1 ppg kick margin in the event a 12.5 ppg MW is used later in the hole section. Page 21 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling& Completion Procedure Hilcorp 13.12 Drill 9-7/8" hole section to approx 3200' MD to allow all of 9-7/8" directional assy to buried (excluding HWDP and Jars). 13.13 CBU, TOH. L/D BHA. 13.14 P/U 9-7/8" directional drilling assy consisting of: • 9-7/8"PDC bit(Baker Hughes HCD504ZX). • Mud Motor(1.2deg) • Non-Mag Stab (9-3/4" OD) • NMPC • NaviGamma(D&I, + Gamma Ray) • (3)Non-Mag Flex collars • XO • (5) 5"HWDP • Dailey Jar • (21) 5" HWDP • 5" DP to surface 13.15 Ensure BHA components have been inspected previously. 13.16 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 13.17 Ensure TF offset is measured accurately and entered correctly into the MWD software. 13.18 Bit TFA should be 0.778 in2. We need to pump at a minimum of 500 - 550 gpm to clean the hole effectively. DD should run independent hydraulics to confirm optimum TFA. 13.19 Motor AKO should be set at 1.2deg. Max DLS in the 9-7/8"hole section(P4) is 2.0 deg/100. 13.20 Primary bit for the 9-7/8"hole section will be the 9-7/8" HCD504ZX PDC bit. It is available from Baker Hughes facility in Anchorage. Be sure to call out an insert bit to have available as back up. Page 22 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company .IIIPiFILIII I 9 7/8" H CD504ZX Genes. ._ ....... a TM BAKER (250.8 mm) a HUGHES U Application D Technology PDC bits are the proven solution for the • 53t ever increasing commplxity of directional applications and operators a; lik ton=bet pertbrmtnze obj tn;es.In motor tea able.rata* steerable and Y vertical drilling applications our technology arbancernents offer Mei 4,11/44; supaior performance and directional control. t � a EZSteer Teclurolotry Patarted EZSteer:depth-of-cut control technology use;engineered bearing surfaces to improve toolface control on motor steel able systems and enhances performance on rotary steerable system:.The result is improved directional pcfoanran a and Lieber RCP:,in all applications. u ':Gt: SU^u ile:isu The bit gauge de:ice is optimized fortlre applic ation to match the drive sy sten.d3.3-1.?g requirements and formation cb ar3.'ten sacs.LGC;Length.Geometry and Cutting structure)gause desitr approach deliver,paedi:table and consistent build tare s v,itbout compromising bole quality. n C.-rue-..i:C ut[e:-Dui desit erg can choose faom 3 di•;else group of cutter with 3 range of diamond table thickness and diamond cat bide interface-,for the ideal mix of 3zgre:uveae::and durability. N Get.Eci-C1DIDd a.�+';c-CFD analysisisutilized for eveyGenesis desia and arsine:the optinnun balance between flow.cutter cooling. and thud ao:ion. Reference Photo: 9-7.S in. (250.8min) HCD5O+ZX IADC: M223 f Number of Blade s: 4 1 Cutter Quantity;Total.Face): 53.27 L Primary Cutter Size .625 in(15.S mat) s Number ofN-,771es: 6 f.r °f ;.. N.,77le Type: SP Fixed TFA 0 in'(5.0 mn-) 'r le ma ' Gauge Length tin(101.6 mm) r sr 2 Junk Slot.--uea 12.5m ;S2.5 can') R' �` Bit Baeaker 123210307.1 32100'08,123215860 '4.-1: Connection: 6.5`S API REG Makeup Torque: 71'2"_Bit Sub 37.1-42.4 kft-1b(50.3-57.5 kNm) Reference Part Ntnnber: N19412 Status: . Operating Recommendations-: Hydraulic FlowRate: 405-950 gpm;15 53-34331pm) Rotation Speed Far Rotary.Motor.and Rotary Steerable Applications Max.Weight On Bit: 2S klb;12 to orkdaN) 'Lie ote,ofoi:we:a:and RPM ihoana:a:e_reiena:iveof:vaicalwe:a:ias oa.ane.,..ha:win noinecesicily tieldonnmIo ,i:lfeo:land:3tiIli ..cos, I:ii ` ,,,-.1 aketliitj}icti.:.tii'tl na::e:ommeniei as::he:1ppe:limin of oo i we7_h:and P PM Se nin simufiz 'o i sly a 2'I12 Bae lti diel b:o;ronrei Alli_?t i;eie've i cn:a.•::eo-.r<localF.:ialiei::ii:eneo:er.elenz.:ivefxre:oameait:ianiin'o'raiee Page 23 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Emmy ComWWY 13.21 TIH, Conduct shallow hole test of MWD and confirm Gamma Ray LWD functioning properly. 13.22 Once on bottom, drill with light weight, and begin a new bottom hole pattern with the PDC bit. Do not be in a hurry to set down a bunch of weight and take off drilling. 13.23 Drill 9-7/8"hole section to 7500' MD/7268' TVD. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. • Utilize inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. • Take MWD surveys every stand drld. 13.24 At 7500', begin increasing MW slowly from 10.5 ppg to 12.5 ppg. Monitor well closely for any losses. If losses are observed, stop increasing MW and discuss forward plan with Anchorage drill team. 13.25 If MW is not at 12.5 ppg by 9000' MD / 8677' TVD, stop drilling and inc MW to 12.5 ppg slowly before drilling ahead. 13.26 Drill to 9-7/8"hole section TD at 10,000' MD/ 9,617' TVD. 13.27 At TD; pump sweeps, CBU, and pull a wiper trip back to the 10-3/4" shoe. 13.28 TOH with the drilling assy, stand back BHA if possible. 13.29 R/U and run OH logs consisting of: • Gamma Ray (GR) • Dual Spaced Neutron(DSNT) • Spectral Density Tool (SDLT), includes single axis caliper • X-Y Cross Dipole Sonic • Array Compensated Resistivity Tool (ACRT)—5 depths of investigation, includes Spontaneous Potential response (SP). 13.30 Monitor the well at all times on the trip tank while logging. 13.31 After logging objectives accomplished, pick up a wiper trip BHA and make another run to TD. Circ B/U at TD and TOH. Rack back DP, handle BHA as appropriate. Page 24 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp 14.0 Run 7-5/8" Production Casing 14.1 R/U and pull 10" ID wear bushing. 14.2 R/U Weatherford 7-5/8" casing running equipment. • Ensure 7-5/8"LTC x 5"NC-50 XO on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor& model info. 14.3 P/U 7-5/8" 29.7#P-110 HC LTC shoe joint, visually verify no debris inside joint. NOTE: The first 1000'of this string will be 7-5/8"29.7#P-110 HC LTC 14.4 Continue M/U&thread locking the shoe track assy consisting of: • (1) Float shoe joint w/float shoe bucked on. Install (2)bow spring centralizers at 10' from each end over a stop collar. • (1) Baker locked joint. Install (1) centralizer mid tube over a stop collar. • (1) Float collar joint w/float collar bucked on pin end. Install (1) centralizer mid tube over a stop collar. • Ensure proper operation of float shoe and float collar. 14.5 Run approx 1000' of 7-5/8" 29.7# P-110 HC LTC casing to ensure coverage across the lower tyonek water flow. • Fill casing while running using fill up line on rig floor. • Use"API Modified"thread compound. Dope pin end only w/paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install centralizers over couplings on every other joint. 14.6 Run 7-5/8" 29.7# L-80 BTC casing above the P-110. • Install centralizers over couplings on every 4th joint from 9000' to 4000' MD. • Ensure 7-5/8"BTC x 5"NC-50 XO on rig floor and M/U to FOSV. • There will be (2) Crossover joints with a BTC box x LTC pin sent out to the rig. 14.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 14.8 Slow in and out of slips. Page 25 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling& Completion Procedure Hilcorp Energy Company 14.9 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe approx 10—20' above TD. Strap the landing joint while it is on the deck and mark the joint at(1) ft intervals to use as a reference when landing the hanger. Casing and Tubing Performance Data PIPE BODY DATA GEOMETRY Outside Diameter 7.625 in Wall Thickness 0.375 in API Drift Diameter 6.750 in Nominal Weight 29.70 lbs/ft Nominal ID 6.875 in Alternative Drift Diameter n.a. Plain End Weight 29.06 lbs/ft Nominal cross section 8.541 in PERFORMANCE Steel Grade L80 Minimum Yield 80,000 psi Minimum Ultimate 95,000 psi Tension Yield 683,000 in Internal Pressure Yield 6,890 psi Collapse Pressure 4,790 psi Available Seamless Yes Available Welded No CONNECTION DATA TYPE:BTC GEOMETRY Coupling Reg OD 8.500 In Threads per in 5 Thread turns make up 1 PERFORMANCE Steel Grade L80 Coupling Min Yield 80,000 psi Coupling Min Ultimate 95,000 psi Joint Strength 721,000 lbs Internal Pressure Resistance 6,890 psi 7-5/8" BTC Estimated M/U Torque Casing OD Est Torque to Reach Triangle Base 7-5/8" 7,630 ft-lbs 14.10 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 14.11 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat (slightly)to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 14.12 Continue circulating until required properties achieved for cmt operations. 14.13 After circulating, lower string and land hanger in wellhead again. Page 26 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp CompanyEnergy 15.0 Cement 7-5/8" Cement Procedure 15.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. 15.2 RAJ cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 15.3 Pump 5 bbls 13.5 ppg spacer. Close low torque on plug dropping head,test surface cmt lines to 4000 psi. 15.4 Pump remaining 35 bbls 13.5 ppg spacer. Drop bottom plug. 15.5 Mix and pump slurry per below recipe. 15.6 Cement volume based on annular volume + 50% open hole excess. Section: Calculation: Vol (BBLS) Vol(ft3) LEAD: (9000'-4000') x .038 bpf x 285 1600 9-7/8" OH x 7-5/8" csg: 1.50 = Total Lead: 285 bbls 1600 ft3 TAIL: 1000' x .038 bpf x 1.50 = 57 320 9-7/8" OH x 7-5/8" csg: TAIL: 90' x .046 bpf= 4.1 23.2 7-5/8" Shoe Track: Total Tail: 70.6 bbls 396.2 ft3 Page 27 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company Slurry Information 4 UrW .. -.,....� System Conventional Conventional Density 14 lb/gal 15.3 lb/gal Yield 1.58 ft3/sk 1.35 ft3/sk Mixed Water 8.09 gal/sk 5.912 gal/sk Mixed Fluid 8.09 gal/sk 5.962 gal/sk Expected 5:30 HR:MIN 4:00 HR:MIN Thickening Expected ISO/API Fluid Loss 13 mL in 30 min Code Description Concentration Code Description Concentration G Cement 94 Ib/sk 94 lb/sk WBWOB G Cement WBWOB Dl 10 Retarder 0.05 gal/sk Dl 10 Retarder 0.05 gal/sk VBWOC VBWOC Additives D046 Anti Foam 0.2%BWOB D046 Anti Foam 0.2%BWOB D020 Extender 4.0%BWOB D202 Dispersant 1.5%BWOB D065 Dispersant 0.3%BWOB D400 Gas Control Agent 0.8%BWOB D800 Retarder 0.2%BWOB D154 Extender 8.0%BWOB Dl74 Expanding Agent 1.5%BWOB 15.7 After pumping cement, drop top plug and displace cement with mud. Use the cement unit to displace with as volumes can be tracked much more accurately. Displacement calcs: • 9910' x .0459 bpf=455 bbls. • Displace with 9.5 ppg 6% KC1/PHPA drilling fluid (MW to be used for next hole section). 15.8 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 15.9 Do not overdisplace by more than '/2 shoe track volume. Total volume in shoe track is 4.1 bbls 15.10 There should be no cmt returns to surface. TOC is planned to be at 4000' MD. 15.11 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold,pressure up string to final circulating pressure and hold until cement is set. • If this is the case, monitor the pressure on the casing and do not let it exceed 500 psi over the final pump pressure. Bleed off pressure occasionally as necessary. 15.12 R/D cement equipment. Flush out wellhead with FW. 15.13 Back out and L/D landing joint, flush out wellhead with FW. Page 28 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling& Completion Procedure Hilcorp Emily Compay 15.14 M/U pack-off running tool and pack-off to bottom of landing joint. Set casing hanger pack-off. Run in lock downs and inject plastic packing element. Test void to 250/3000 psi for 10 min. 15.15 Lay down landing joint and pack-off running tool. 15.16 Reduce MW in active pits from 12.5 ppg to 9.5 ppg. Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated BHP's from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead. Note: 9.5 ppg was chosen as the starting MW for SRU 14B-27 to stay as close as possible to formation pressure (which is expected to be 5.5 ppg) but still allow for adequate suspension of cuttings and LCM. Wellbore instability is not perceived to be an issue at 9.5 ppg. The only formation that exceeds a 9.5 ppg gradient would be the lower Tyonek water flow. This formation is expected to occur at a depth of 9177' TVD, so it is not expected that we will have communication with the lower Tyonek with 7-5/8" casing set at 9617' TVD. The lower Tyonek water flow has been observed with gradients as high as 12.5 ppg EMW. Lower Tyonek is now mapped for the Swanson River Field, completed by Kevin E. Differential sticking of the drill string and the production casing significantly increases with increasing mud weights. The differential pressure across the Hemlock interval (10,904' TVD) with a 9.5 ppg MW is 2268 psi however increasing the mud weight to 12.5 ppg would increase the differential pressure to 3969 psi, an increase of greater than 70%. 15.17 L/D 5" DP from derrick. 15.18 P/U and rack 4" DP. 15.19 Install 4" liners in mud pumps. PZH pumps are rated at 5000 psi and 144 gpm @ 110 spm with the 4" liners. Page 29 Revision 0 Nov, 2012 Swanson River Unit II14B-27 Drilling & Completion Procedure Hilcorp Enmy carman), 16.0 Drill 6-3/4" hole section 16.1 Remove 5" & 7-5/8" casing rams from BOP. Install 4" fixed rams in top cavity & 2-7/8"X 5" VBRs. Test BOPs on 4" and 5"test joints. 16.2 Pull test plug, run and set wear bushing. 16.3 P/U 6-3/4" directional drilling assy consisting of: • 6-3/4" PDC bit (Baker Hughes QD505X). • Mud Motor(1.18 deg) • Non-Mag Stab (6-5/8" OD) • NM Pony Collar • NaviGamma(D&I, + Gamma Ray) • (3)Non-Mag Flex collars • XO • (5) 4"HWDP • Dailey Jar • (21)4"HWDP • 4" DP to surface. 16.4 BHA Components have been inspected previously. 16.5 Drift& caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 16.6 Ensure TF offset is measured accurately and entered correctly into the MWD software. 16.7 Confirm that the bit is dressed with a TFA of 0.46 sqin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 350 gpm. 16.8 Motor AKO should be set at 1.18 deg 16.9 Primary bit will be the Baker Hughes QD505X. Spec sheet attached on next page. Page 30 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company a:vle :heel Ir 11r 6 3/4" QDSO5X TM BAKER (1 71.5 mm) ntec HUGHES at Application Quantec Directional PVC bits combine the very latest in HCC bit technology Best in Clan cutterteohncicgy.superior stabihty ri and hydraulic-lic-ef3^ien together with a design phil 3 phy that is tailored to your drilling oLjecti:es.De imus are customized to achieve continual perfom:an e rmpro,ement in the toughest applications while •s, 1k iumnizug bit vibration r enhancl tool he 4 • Diamond Volume 3lolea geinenr Diamond Volume Management (DVM)designs ensure that neither KOP or stability is compranized in the bit design Profile and outer placement are tailored to the apphcation < • m order to achieve the longest nm length at high overall KOP. spy - - '' ■ Quante(Cutters Quante:cutters of' rthe%erylatest intechnology. Optimized di amond feed and engineered non-planer interfaces c online to give superior wear resistance and outstanding toughness.Speak to your PCC rep for the outer best suited to your application. ■ Gauge Protection Hielr quality 1 SP material is utilized to give superior wear resistance and thus long bit nms.Optional Hex-shaped ISP matenal allows tighter packing for ultra abrasive environments. ■ QD Gauge De sign Engineers select gauge length and gauge geometry to meet dogleg,hole quality and system spoil:requirements. Reference Photo: 6-3 l in.(171.5nnn)QD505X Product Specifications Ld)C: 1\1323 ',• Number of blades: 5 Cutter Quantity(Dotal.Face): +8.19 4 ` Pnmary Cutter Size .625 in(15.8 mm) r 14.10000400. ?iuu`ber of Nozzles: 5 Nozzle lupe: MSP Fixed 11-A Din'(U.Unn+r') 01111. r4 Gauge Length 1.5 in(38.0 nun) ,�. Junkit Bret Area 8 in'(51.6 cm') A 't Bit Breaker: C • Connection: 3-1:2 API.REG Makeup torque: 4118"Bit Sub 5?-5.;kft-lb0.1-Li khm) 41/4"Eit Sub 6.3- ;.0 kft-lb(8.5-9.5 kl`m) 41.2"+tiitSub .;-8.5kd-lb(10.4-11.5k1\m) Reference Pan 1`tinier: 1\5856 Operating Recommendations': Hydraulic F low Kate: 250-550 gin(950-2100 1pm) Rat anon Speed: F or Rotary and MotorApplications Max.V.eight On Flit: 20 klb(9 to or kdaA) Page 31 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp 16.10 TIH to TOC. Shallow test MWD on trip in. 16.11 Test casing to 3000 psi/30 min. Ensure to record pressure vs volume plot to compare with FIT. 16.12 Drill out shoe track and 20' new formation. 16.13 CBU and condition mud to 9.5 ppg in/out for FIT. 16.14 Conduct FIT to 12 ppg EMW. Note: Offset field test data predicts frac gradients at the 7-5/8"shoe to be bwtn 14.4 ppg and 15.4 ppg. A 12 ppg FIT results in a 2.5 ppg kick margin while drilling the interval with a 9.5 ppg fluid density. 16.15 Drill 6-3/4"hole to 11,598' MD using above motor assembly. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • See attached mud program for hole cleaning and LCM strategies. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. • Ensure mud engineer set up to perform HTHP fluid loss. • Maintain HTHP fluid loss <9. 16.16 Hilcorp Geologists will follow LWD log closely to determine exact TD. Plan on drilling to a r maximum of 11,598' MD/ 11,109' TVD. 16.17 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8" shoe. 16.18 TOH with drilling assy, handle BHA as appropriate. Drop drift on trip out. 16.19 R/U and run OH logs consisting of: • Gamma Ray (GR) • Dual Spaced Neutron(DSNT) • Spectral Density Tool (SDLT), includes single axis caliper • X-Y Cross Dipole Sonic • Array Compensated Resistivity Tool (ACRT)—5 depths of investigation, includes Spontaneous Potential response (SP). Page 32 Revision 0 Nov,2012 Swanson River Unit ini14B-27 Drilling& Completion Procedure Hilcorp Energy Company 16.20 Make a clean out run again to TD (if necessary). Utilize same (or very similar) BHA design to what was used to drill the well. This trip is discretionary, and will be determined by actual hole conditions. Page 33 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company 17.0 Run 5" Production Liner 17.1 M/U and rack cement stand in derrick. • Ensure to drift components prior to M/U. Ensure dart will pass through components. • Confirm largest OD of packer assy will pass through wear bushing. 17.2 Install and test 2-7/8" x 5"VBR in lower cavity if not done previously. 17.3 R/U Weatherford 5" casing running equipment. • Ensure 5" DWC/C HT x 4"HT-38 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor& model info. 17.4 P/U shoe joint, visually verify no debris inside joint. 17.5 Continue M/U &thread locking shoe track assy consisting of: • (1) Shoe joint w/ shoe bucked on &threadlocked(coupling also thread locked). • (1) Baker Locked joint • (1) Joint with float collar bucked on pin end &threadlocked (coupling also thread locked). • (1) Joint with landing collar installed INSIDE pin end. • Solid body centralizers will be pre-installed on shoe joint& FC joint. • Install a solid body centralizer on landing collar joint. Leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe. 17.6 Continue running 5"prod liner • Fill casing while running using fill up line on rig floor. • Use "API Modified"thread compound. Dope pin end only w/paint brush. • Install solid body centralizers on every joint to the top of the G-zone. Leave the centralizers free floating. • Install them on every other joint from the top of the G-zone (10,523' TVD) to the liner hanger. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 5" DWC/C HT M/U torques Casing OD Minimum Maximum Yield Torque 5" 8,400 ft-lbs 9,400 ft-lbs 12,500 ft-lbs Page 34 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company Technical Specifications Connection Type: Size(O.D.): Weight(Wall): Grade: DWC/C-HT Casing 5 in 15.00 lb/ft(0.296 in) L-80 stands rd Material h ., L-80 Grade ; �" ? • 80,000 Minimum Yield Strength(psi) 04*.ititinS40012AJ S A 95,000 Minimum Ultimate Strength(psi) VAM USA 4424 W Sam Houston Psvy.Suite 150 Pipe Dimensions Houston,Tx 77041 Phone.713.479-3200 5.000 Nominal Pipe Body O.0.(in) Fan:713-479-3234 4.408 Nominal Pipe Body I.D,(irt) E-mau:VAMt)SAs,lasfnna.vatlourer.co,ip 0.296 Nominal Wall Thickness(in) 15.00 Nominal Weighs(lbs/ft) 14.88 Plain End Weight(Ibslft) 4.374 Nominal Pipe Body Area(sq in) '- Pipe Body Performance Properties 350,000 Minimum Pipe Body Yield Strength(lbs) ;,, , 7,250 Minimum Collapse Pressure(psi) • .1. 8,290 Minimum Internal Yield Pressure(psi) 7,600 Hydrostatic Test Pressure(psi) a`` Connection Dimensions ; 5.563 Connection O.D.(in) 4,408 Connection I.D.(in) �� 4.283 Connection Drift Diameter(in) ,:-,`,4' 4.06 Make-up Loss(in) 4.374 Critical Area(sq in) x` 100.0 Joint Efficiency(%) � Connection Performance Properties` Vlit 350,000 Joint Strength(lbs) 16,670 Reference String Length (ft) 1.4 Design Factor 379,000 API Joint Strength(lbs) 350,000 Compression Rating(lbs) 7,250 API Collapse Pressure Rating(psi) a'" 8,290 API Internal Pressure Resistance(psi) 4. 73.3 Maximum Uniaxial Bend Rating fdegrees/100 ft] 'g Appoximated Field End Torque Values 8,400 Minimum Final Torque(ft-lbs) 9,400 Maximum Final Torque(ft-lbs) 12,500 Connection Yield Torque(ft-lbs) For detailed information on performance properties,refer to DWC Connection Data Notes on following page's}. Connection specifications within the control of VAM-USA were correct as of the date printed.Specifications ere suh,ect to change without notice.Certain connection specifications aro dependent on the mechanical properties of the pipe.Mechanical properties of milli proprietary pipe grades were obtained from mill publications and are subject to change.Properties of mill proprietary grades should be confirmed with the mill.Users are advised to obtain current connection specircations and verify pipe mecharical properties for each application. 10/30/2012 6:58:27 PM Page 35 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp En�ComPnnY 17.7 Ensure to run enough liner to provide for approx 200' overlap inside 7-5/8" casing. Ensure hanger/pkr will not be set in a 7-5/8" connection. 17.8 Before picking up Baker ZXP liner hanger/packer assy, count the# of joints on the pipe deck to make sure it coincides with the pipe tally. 17.9 M/U Baker ZXP liner top packer. Fill liner tieback sleeve with"Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 17.10 RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 17.11 RIH w/liner on DP no faster than 1-1/2 min/ stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 17.12 M/U top drive and fill pipe while lowering string every 10 stands. 17.13 Slow in and out of slips. 17.14 Circulate 1-1/2 drill pipe and liner volume at 7-5/8" shoe prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. Nominal liner hanger setting pressure is 2500 psi. 60% of this value is 1500 psi 17.15 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 17.16 Continue to fill the DP every stand down using fill up line on rig floor. Do not stop to fill casing. 17.17 P/U the cmt stand and tag bottom with the liner shoe. P/U 2' off bottom. Note slack-off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 17.18 Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure (1500 psi). Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 17.19 Reciprocate& rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 36 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp 18.0 Cement 5" Production Liner 18.1 Hold a pre job safety meeting over the upcoming cmt operations. 18.2 Attempt to reciprocate the liner during cmt operations. 18.3 Pump 5 bbls 12 ppg MUDPUSH II spacer. 18.4 Test surface cmt lines to 4500 psi. 18.5 Pump remaining 15 bbls 12 ppg MUDPUSH II spacer. 18.6 Mix and pump 15.3 ppg class "G" cmt per below recipe. Ensure cmt is pumped at designed weight. Job is designed to pump 100% OH excess. Cement Calculations 7-5/8"x 4 DP"Overlap: (9,800—9,600') x 0.03 = 6.1 bbls 7-5/8"x 5"Liner Overlap: (10,000' —9,800')x 0.022 = 4.4 bbls 6-3/4"OH x 5"Liner: (11,300— 10,000')x 0.020 x 2 = 52 bbls Shoe Track: 90' x 0.019= 1.7 bbl Total Volume(bbls): 6.1 +4.4 + 52 + 1.7= 64.2 bbls Total Volume(ft3): 64.2 bbls x 5.615 ft3/bbl= 360 ft3 Total Volume(sx): 360 ft3 / 1.35 ft3/sk= 267 sx Page 37 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Boar(Co=PM Slurry Information: System Conventional Density 15.3 lb/gal Yield 1.35 ft3/sk Mixed Water 5.912 gal/sk Mixed Fluid 5.962 gal/sk Expected Thickening 100 Bc at 05:57 hr:mn Expected ISO/API 15 mL in 30.0 min at 175degF/ 1000 psi Fluid Loss Code Description Concentration G Cement 94 lb/sk D198 Retarder 0.4% BWOC Additives D046 Anti Foam 0.2% BWOC D202 Dispersant 1.5% BWOC D400 Gas Control Agent 0.8% BWOC D154 Extender 8.0 %BWOC D174 Expanding Agent 1.5%BWOC 18.7 Drop DP dart and displace with 9.5 ppg drilling fluid. 18.8 Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point. 18.9 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns &pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 18.10 Bump the plug and pressure up as required by Baker procedure to set the liner hanger(20% above nominal setting pressure. 2500 psi is nominal setting pressure. Pressure up to 3000 psi to confirm hanger setting. 18.11 Slack off total liner weight plus 20k to confirm hanger set. 18.12 Do not overdisplace by more than 1/2 shoe track. Shoe track volume is 1.7 bbls. 18.13 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner. Page 38 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Emily Cowpony 18.14 Bleed pressure to zero to check float equipment. 18.15 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve. 18.16 Rotate slowly and slack off 50k downhole to set the ZXPN liner top packer. 18.17 P/U to P/U weight plus 1 ft. 18.18 Close annular and test 4" DP x 7-5/8" annulus to 1500 psi/ 10 min to test liner top packer. 18.19 Bleed off pressure, open up annular. 18.20 Pressure up to 500 psi down DP and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req'd to maintain 500 psi DP pressure while moving pipe until the pressure drops off rapidly, indicating pack-off is above the sealing area(ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 18.21 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 18.22 Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. 18.23 Watch for cement returns and record the estimated volume. Rotate& circulate to clear cmt from DP. 18.24 POOH, verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 18.25 If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise)torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 18.26 NOTE: Some hole conditions may require movement of the drillpipe to "work"the torque down to the setting tool. 18.27 After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Page 39 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Flom Company 19.0 Wellbore Clean Up & Displacement 13.1 M/U casing clean out assy complete with casing scraper assys for each size casing in the hole. • 4-1/4" bit or mill • Casing scraper&brush for 5" 15# casing (MI Swaco - Multiback) • +/- 1500' 2-7/8"workstring. • Crossover(No PBR Polish Mills) • Casing scraper&brush for 7-5/8"29.7# casing (MI Swaco -Multiback) • (5000') 4" HT-38 DP. • Casing scraper&brush for 7-5/8"29.7# casing (MI Swaco - Multiback) • 4"HT-38 DP to surface. 13.2 TIH& clean out well to landing collar(+/- 11,200' MD). • Circulate as needed on trip in if string begins to take weight. • Circulate hi-vis sweeps as necessary to carry debris out of wellbore. • Ensure 4-1/4"bit is worked down to the landing collar. • Space out the cleanout BHA so that the 4-1/4"bit reaches the 5" landing collar when crossover is+/- 30' above the 5" liner top. • The primary objective of the clean out run is to ensure the TCP assy will reach intended depth. 13.3 After wellbore has been cleaned out satisfactorily using mud,test casing to 3000 psi/30 min. 13.4 Displace drilling fluid in wellbore with a hi-vis pill followed by fresh water. • Catch drilling fluid in rain-for-rent tanks for use on a future well. • Circulate fresh water into wellbore until clean up is satisfactory. Do not recirculate fluid, • After a couple circulations using FW, short trip the assy to bring the upper 7-5/8" multi-back assy to surface. • RIH again& tag landing collar w/4-1/4"bit. Continue circulation as necessary until fluid cleans up. Make another short trip if necessary. • Pump a chemical train followed by 6% KC1 after fluid has cleaned up satisfactorily. Target NTUs are 80 - 100. 13.5 TOH w/clean out assy. LDDP on the trip out. Note any abnormal wear on the mill assy. 20.0 RDMO 14.1 Install tubing hanger&back pressure valve. N/D BOP. 14.2 N/U temp abandonment cap. 14.3 RDMO Arctic Fox. Page 40 Revision 0 Nov, 2012 Swanson River Unit ini14B-27 Drilling& Completion Procedure Hilcorp Enema Company 21.0 BOP Schematic El. SRU 14B-27 • Hydrll ' DeynnDriling in••.ECU) 11'$M Hydra Vi3IOP ti in ril Iinil Hydril V 11'-Sion - 1t ASS' /`]) 1 S H•I III III `I- r 1:11W .fiTit r. af111 1 ��• .111 lil 1111111\1. ! �r - Hydrll V — - 11 -VIPS) - — _ 1 Grar38 LEvEI 111 1II 111 1I1 III SCaCEr SpcAI 195' 11:.1.1x115!1 111 tII III III til .wi1rar.,.111;-=Tira. Seaboard-MRS ayslem 'I1 I.4 7 . G Hi 1,..?Al x 11 51.1151.11ii ��� ' ' I i , it. 11- `I_ l{ ?:r1I mill11, zdt, cr �al. ii. rii{ ' "')II# ' Page 41 Revision 0 Nov, 2012 Swanson River Unit II14B-27 Drilling & Completion Procedure Hilcorp Energy Company 22.0 Wellhead Schematic HILCORP ALASKA, LLC SWANSON RIVER 9 HO-284890 LI of I i . 3-1/8 5M--.... 1'N�OI l •1,i iC'�/ 1M 141) 3-1/N°.}.t_,a I1 Q" 3-1/8, 1 __ e. e , ,Z r i{ 3-1/8 5M--..1 WO 1 ii ADAPTER,SM-E-2CLN u ■1 11 du x 3-1/lI 50.1 TANG HANGER, SV-E-2CL- moi_�)omm 11 5M 11 x 3-1/2 API MOD 80x ElM ,; I b E._ X 3-1/3 E4,, 8RD BOX TOP b -0---- . 0 • or tom', +—.1 • :• CASING HANGER.SMB-22 'Pt 1 '1 x 7-5/8 Ira -.1■ -.". 2-1/36 54I w/sEAL AEYH'LY i ° 53 V/1, �' NM I , , I-I �f 3G-3/4 In I. UI suili►. 2-1/16 5M CASING HANGER, SMB-22 16-3/4 x 1 .-3/4 �N r� E6-3/4 w/PNIMARY NEAL - • Ir ■1 • •iii ii •_, : •: !FII -'IU {,.1 .i 1. ' Z 61 16 CASING 2-1/36 5M 1n-3/4 CASING—.. 7-5/8 CASING—•. eie 3-1/2 T1.B1NG - TSEABOARD 5,000 PSI BELLMEAD&TREE ASSEMBLY 18 x 10-3/4 X 7-5/8 M 3-1/2 RESTRICTED C1NFlGENTIAL DOCUMENT r � .w t We IQ" RI ,..42 I 8JJNE12 ree krirra "�_ P-14873 1 Page 42 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company 23.0 Days Vs Depth SRU 14B-27 Days Vs Depth D -- _ 2000 --- 4000 -_ --Plot Area.''_.-_____ 0 g lu 5000 10000 - — -- 12000 - 14000 0 5 10 15 20 25 30 35 40 Days Page 43 Revision 0 Nov, 2012 Swanson River Unit H14B-27 Drilling & Completion Procedure Hilcorp Energy Company 24.0 Geo-Pro r SEOL s ,4L PROGMOSIS SP07446-27 FEW Swanson River ►V, X=..74,685.S..0 LONG:-150.8557(SRU 41-33 Pad) STATE Alaska Y=246555'74 LAT:60.746 11111111.111111111. ...._ -'TT£Atr'/iE X=3477e7.1 LONG:-150.8508173 TVD REF DATU KB Y=2466}U5SILAT:60.7490638 TVD REFELEV i'°183' FEF l4 -}',57..91:1 /1.4.a-1 GROUND ELEV 164' R...114- 2:-.7.7TO 17,W M2l1.031Tl'D ___ Drill deviated grassroots Hemlock w ell with deep set ESP or Gas Lift completion in H1-5 sands to replace mechanical failure of SRU 41-33(P&A'd) Integrated subsurface and 3-D geological interpretations,in conjuction with previous production data indicates that stranded oil reserves remain in the Hemlock 1-5 benches between the F and G faults. High on structure,G2,H1-4,Reserves aren't recoverable in existing wellbores due to lack of takepoints or mechanical condition of other existin9 w ellbores in the fault block.H10 sands ma be roductive as well. ' :;//' !/.7rJ i] '!!/lI' i/i3':Y' .1J;� 1 EXP2/'TF/a Critical Intersection Poir ME' MP F FLFftft?TAW ELM' TNa/FT, TVO S/FTI Est Preacauri. X Y R - Gas Sand Shallow gas sand gaslwet 446 -263 Normal same as surface x,y's +1-30' 446 13-6 Lower Sterling wet 3,276 -3,093 Normal 346947.7 2465662.8 +1-30' 3277 LBGT Top Lower Beluga wet 4,285 -4,102 Normal 346989.8 2465705.0 +1-30' 4289 D1CT 25'Tyonek Coal wet/gas 5,682 -5,499 Normal 347056.1 2465793.8 +1-30' 5690 64-5 Gas Storage Sand GAS _ 6,428 -6,245 2500-3300 psi 347091.6 2465841.2 +1-30' 6440 TYNK HP H2O Lower Tyonek WATER 9,162 -8,979 5200-5500 psi 347386.0 2466207.8 +1-50' 9224 . G2 Tyonek Oil OIL/WATER 10,523 -10,340 2800-3000 psi 347682.8 2466570.8 +1-30' 10663 - HKT Top Hemlock Oil OIL/GAS 10,609 -10,426 2800-3000 psi 347698.3 2466590.6 +1-30' 10754 H2-5 Hemlock Oil OIL/GAS 10,635 _ -10,452 2800-3000 psi 347698.3 2466599.0 +1-30' 10781 H7-8 Hemlock Oil WATER 10,795 -10,612 2800-3000 psi 347732.1 2466641.2 +1-30' 10950 H10 Hemlock Oil OILIWATER 10,903 -10,720 2800-3000 psi 347757.4 2466674.9 +1-30' 11064 TD Lower Hemlock 11,031 -13,848 347787.1 2466705.9 +1-30' 11200 =Primary Objective =Secondary Objective ARGET RADIUS 75' I ATA COLLECTION REQUIREMENTS: 1ud Logging: &,dace Casing to TO WO Data: ............ -Line Log Dat s Quid combo in intermediate and production hole sections. OMPLETION T'r'PE Gas Lift 'NTICIPATED RATES -2,000 bpd gross 'RTIFICIAL LIFT EQIJIPME(JT OD UBING SIZE I THER COMMENTS I. Pressure of Tyonek 64-5 Gas Storage Sand can be up to 3,300 psi depending on where w e are in the injection cycle when w e drill ?. The D1CT coal is the thickest,most continuous coal in Swanson River. We expect it to be approximately 25'thick at this location. We expect about 25 other mappable coals(5-15 ft thick)in a 2200'thick interval stretching'350'above and 1850'below the D1CT top 3. Evidence of shallow gas is only seen on logs in SRU 31-33WD. 1. 3D Time seismic data exists over the Swanson River Field 3. We do not anticipate crossing any significant faults that would pose drilling problems. Page 44 Revision 0 Nov,2012 Swanson River Unit int14B-27 Drilling & Completion Procedure Hilcorp En-ac 25.0 Anticipated Drlg Hazards 13-1/2" Hole Section: 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 location to mix LCM pills at moderate product concentrations. Maintain 1 Oppb total of BaraCarbs/Barofibre/Steelseal while drilling the interval to control any seepage losses. Hole Cleaning: Maintain rheology w/ Aquagel & Barazan D+. Sweep hole w/ 20 bbls Barazan D as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP btwn 25-40 to optimize hole cleaning and control ECD. Wellbore stability: Maintain 1 Oppb total of BaraCarbs/Barofibre/Steelseal to strengthen wellbore. H2S: H2S is not present in this hole section. • No abnormal pressures or temperatures are present in this hole section. 9-7/8" Hole Section: Lost Circulation: Ensure 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 location to mix LCM pills at moderate product concentrations. Maintain 1 Oppb total of BaraCarbs/Barofibre/Steelseal while drilling the interval to control any seepage losses. Hole Cleaning: Maintain rheology w/ Aquagel & Barazan D+. Sweep hole w/ 20 bbls Barazan D as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP per program to optimize hole cleaning and control ECD. Wellbore stability: Maintain 1 Oppb total of BaraCarbs/Barofibre/Steelseal to strengthen wellbore. Maintain MW as necessary using additions of Barite. Filtrate control in the <6 range is required. Maintain additions of PAC L / Dextrid LT to maintain API fluid loss of <6. Maintain 6% KCI in system for shale inhibition. Page 45 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Emil'ComPM 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. Overpressured Lower Tyonek Waterflow: Maintain MW at a minimum of 12.5 ppg with additions of barite from 8500' to section TD. H2S: H2S is not present in this hole section. / No abnormal temperatures are present in this hole section. 6-3/4" Hole Section: 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 location to mix LCM pills at moderate product concentrations. Maintain 1 Oppb total of BaraCarbs/Barofibre/Steelseal while drilling the interval to control any seepage losses. Hole Cleaning: Maintain rheology w/ Aquagel & Barazan D+. Sweep hole w/ 20 bbls Barazan D as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP per program to optimize hole cleaning and control ECD. Wellbore stability: Maintain 1 Oppb total of BaraCarbs/Barofibre/Steelseal to strengthen wellbore. Maintain MW as necessary using additions of Barite. HTHP 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. Page 46 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling& Completion Procedure Hilcorp 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. Page 47 Revision 0 Nov, 2012 0 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company 26.0 Rig Layout I _ f.'.•1';'i' 'i 5.3..'(16.22,1 (.1 -+j O CRG)Z9 c 0i vGAit„ XZ Q t'g I--e-, 't;C.. rrz rrl ip a117 1, c t: v CJ(7ra J 71 1:4431 :xi r- -�,� .. I-._ aa..... . 1 ! I > 1 . �� •fir. i / . —miTimmoris- C III■ ��, 'i1 :� "M ;I�Iuarrir - �aA , r', ■nor "" 111111 -....,imrs..: .2.1 t'i 411111111 MM.III it 1 - it r. lrli w 4 41,,,t;,;:-.. ! .� III AEmzA •��• I.°= - - � nutrMb1'11,11/ mar gm, *m Li u213 r, YCS G .. s '�l7 c,r t TI-4 Ls i —z §rn ' 2' ....Si, P I3.8. Ca�� i n - % pm .w --ter !LL1I'''' ---'------ - ' - ill l 1 t'm r r:, v 4� Jnr='r'.----z----'',::-.7.,--1 :iv .Feu: . Mtn=m O-cc = _ x. vor- + m L N A k 4 �rrsr a r; • �I Cl p Ar N C' 8 ,..,Milll _ X 0= iW.""""-4 u ii en N 7 E oa — o ti x DT r l , Arn Zn ,_ ` ' \ii `, mCJ 2 i Crc 7 , A U 1 'r n r in I. : I T J CJ U ._ X D ca�- T A. '4-1„ Il::d:.rr. Page 48 Revision 0 Nov, 2012 Swanson River Unit 1414B-27 Drilling & Completion Procedure Hilcorp 27.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1 . Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drillpipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1 .0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 49 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company 28.0 Arctic Fox Choke Manifold Schematic pp LEDGEND DI7 AKITA JV /y .17) NorlmaUy Open ayes ',4pi Red Handle Valves is if Normally Closed RE '1 �// TO F�PITS W ilk/ . oM B0P STACK q1 -- / FR iv- - � I.: N 5 � FLARE `:: Ta PITS i;-- TO I3EGASSR MATERIAL LIST 7 .. Item Description A 3-1/16"16M Remote Operated Hydraulic Choke B 3-116"5M Adjustable Choke till 1 2-1/16"5M Manual Gate Valve ; Ill" 2-14 3-1I6"5M Manual Gate Valve Page 50 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp E...0.1., 29.0 Casing Design Information N a A W N , 41q 4'F g ft: . glagsW1 „1 mw V C „...,..-,,,p0 ... E ii i4; ppv.- ff°,.° °,.° i T '"SJ A N gpD8 II-- LL '3a p ilii----14 l _ _ tiu. ff GG g`�'����ff11 �I��I VVVVV .. U O O QW s rt F5 p Q 8 8 8 2S g o lo lo V U N at V O >r Ig t 6 g ge v. MN N 85941 $. (NI y p K: 8 't N g_;, o N Y N ';1 Id :Y, ill4 5. g 8 g g 4 a2 n N 3 O e 6.a '6: 0 Z fl N O O 5g z- 5 N O N Nu N N r T to c, Q F T : N t m 2 g Z O N n m N ' n a A Ol m ;A n v -, aNm OOOo-. 4 p 2 in T1 b II N Y 1 N 8 8 8 01 T a to Q N •Z g ti E MI N rn (A1 N P& N coy �m m Page 51 Revision 0 Nov,2012 Swanson River Unit H14B-27 Drilling & Completion Procedure Hilcorp Energy Company 30.0 9-7/8" Hole Section MASP 11 Maximum Anticipated Surface Pressure Calculation Swanson River Unit 14 B-27 Hilcorp '. ..,. Kenai Peninsula,Alaska 9-7/8" Hole Section Assumptions: 1. Frac gradient at 10-3/4" shoe(3000'TVD)estimated at.830 psi/ft based on field test data. 2. Pore pressure at Gas Storage sand estimated at 3300 psi (.513 psi/ft) 3. Pore pressure at Lower Tyonek water flow estimated at 5500 psi (.604 psi/ft) Fracture Pressure at 10-3/4"shoe considering a full column of gas from shoe to surface: 3000(ft) x 0.83(psi/ft)= 2490 psi 2490(psi)- [0.1(psi/ft)*3000(ft)]= 2190 psi MAW from pore pressure (Gas storage sand at 6430'TVD) Max pore pressure at 6430'TVD: MASP(Wellbore evacuated to gas) 6430(ft)x 0.513(psi/ft)= 3 3299(psi)- [0.1(psi/ft)*6430(ftr= 2656 psi 1 sP MAW from pore pressure(Lower Tyonek Water Flow at 9109'ND) A1( Max pore pressure at 9109'TVD: 4,5w v MASP(Wellbore evacuated to water) 9109(ft)x 0.604(psi/ft)= 5500 psi 5500(psi)- [0.4316(psi/ft)*9109(ft)]= 1568 psi I Summary: MASP while drilling 9-7/8" hole is limited by fracture pressure at the 10-3/4" shoe Page 52 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company 31.0 6-3/4" Hole Section MASP Maximum Anticipated Surface Pressure Calculation Swanson River Unit 14 B-27 Hitcorp ' . Kenai Peninsula,Alaska 6-3/4"Hole Section Offset Information Well Date Hemlock Pressure TVD Grad SRU 21A-34 2009 2975 10683 0.2785 SRU 32A-33 2010 2800 10637 0.2632 SRU 331-27 March,2012 3140 10600 0.296 Assumptions: 1. Fracture gradient at 9,817'is estimated at 0.728 psi/ft based on field test data. 2. Based on offset drilling&well test data,Hemlock pore pressure is anticipated at 3100-3500 psi. 3. Reservoir fluid gradient is anticipated at 7.7 ppg. 4. Pressure gradient at 11,284'is calculated as:314-0 psi+(68411.052)17.7)=3413 psi=0.303 psi/ft Fracture Pressure at 7-5/8"shoe considering a full column of gas from shoe to surface: 9817(ft)x 0.728(psi/ft)= 7147 psi 7147(psi)-[0.1(psi/ft)*9817(ft)]= 6166 psi MAW from pore pressure Max pore pressure at TD(11,284'TVD) MASP(Wellbore evacuated to gas column) 11,284(ft)x 0.303(psi/ft)= 3413 psi SIBHP-gas gradient to surface: 3413(psi)-[0.1(psi/ft)'11284(ft)j= 2285 psi I Summary: 1. MASP while drilling 6-3/4"production hole is governed by SIBHP-gas gradient to surface. 2. MASP during production life is governed by SIBHP-gas gradient to surface. Page 53 Revision 0 Nov, 2012 Swanson River Unit II14B-27 Drilling & Completion Procedure Hilcorp Energy Company 32.0 Directional Program (P4) II Planned Wellpath Report Fail11 SRU 14B-27 Version#4 Page 1 of 6 BAKER n�ti•..t stet.,r tr: HU GHES REFERENCE WELLPATH IDENTIFICATION AM*a,LLC .. . . Operator ,:`+ Slot ,•t i 16.17 Area 'Cook Wei,Alaska(Kenai Peniasala).._. Well 1: I 1413-17 -- ---- ---- Field Swanson River Unit Welkin SRU 148-27 Facility SRU 4143(146-27-13-27) REPORT SETUP INFORMATION '':' �� 'rojetionSystem .27/TMAhab$PZane i SS4US>1Nt System3.0.0 North Reference True Use Joaethoh Stale 0999927 Report Geceratec 1116;2012 at 3:09:07 PM Corerger.re at riot 0.73°West v. L. DataSaseSource Fle WellArchitectdb'SRU_14B-17.xml Local coordinates Chid coartimites Geographic coordinates North ft East ft E S A Nati •'US 10 e„ Latitude Longitude [ I fl a dU 3 .M_. Sot Locacon 17.94 -6.3.51 1 s —'34 047 46 2!65683.84 60°4,'46 471": 150'51'17 556 W F'acildy Reference Pt { 34 7691.76 r 2466433.444 60°44'53 9351: 150'51'04.810"W , •... �fadReferencePt ._ 347"5198 2!71720!7 60°45'46.011"K 1S0°5104.957 W WELLPATH DATUM so mrairmir w a 4 U 'Calculation method 'Minimum curvature Arctic Fox(RTE)to Mean Sea Level 175.20ft Horizontal Reference Pt Slot A.clic Fox CRTE)to mean sea level 175.2010 Vertical Reference Pt Arctic Foz(RTE) Arctic Fox(RTE)to Mud Line at Slot(SRU 14B-27) 175.20ft —.* MD Reference Pt Arctic Fox(RTE) Secaon Origin ti 0.00,EOM ft Field Vertical Reference mean sealeeel Sect=Azimuth 38.50' Page 54 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company II Planned Wellpath Report MEI SRC 14B-27 Version k�4 BAKER Papz�6 HUGHES REFERENCE R ELLFATH IDENTIFICATION Operator "Sikorp Alaska,LLC Sint `SRU 27 .., Area Cool Inlet,Alaska(Kenai Peninsula) Well SRU 1410-2' NN Field Swanson Riser tint N IWetwu! SRU 14B-27 Facility SRU 41-33(148-27-13-27) WELLPATH DATA(118 stations) t interpolated'extrapolated station MD lad=dos Aarrr TVD 1004x4 Vert Sect batt Lee GnaTst GialrMt iarieade ... M6 ammo tel 19 ri led n id rtl lal pi RS 8] FS e] rrlaod] 0.00' 0000 38500 000 -175.20 0.00 0.00 000 347517.46 2465483,94 60°4446.471"14 150'5717356'W 0.00_____ 13.50 0000 38.500 1350 -156 70 0.00 0:00' 000 34704746 246543304674446.47111 1575171356"W 0.00 ATE 1LT 10].00- 0000 38.500 10000 -75.20 0.00 0.00 000 347047 46 246563384 674446.471146_--15751'173567W 0.00 200.00' 0000 38.500 20000 24.80 0.00 0.00 000 347017.46 2466483.34 674446.471"N 150"51'17356"W 0 00 300.007 0.000 32500 30000 134.80 000 0.00 000 34704746 246568334 604446.471'N - 15911'17556W 150'51'17556W 0.00 6 ' 400.007 0000 38.500 40000 224 80 0.00 000 000 347047.46 3465503 84 674446.471'7 150'51'17356"W 000 500.00' 0000 38_500 50000 324.80 0.00 000 000 34704746 246548384 60744'46.471"- 150751'17556'W 0.00 600.007 0000 38500 600.00 424.80 0.00 0.00 0.00 347047 46 246648384 674446.471'7 150°517735rWi 0.00 700.00' 0000 38500 70000 534.80 0.00 0.00 0.00 3470477.46 2465683.84 674446471'N 85751173567W'' 0.00 800.001 0.000 33500 80(100 634.80 0.00 (100 0.00 34704746 246568324 6041'46.471N 150°5117356'97 0.00 900.00' 0000 38500 9'0000 724.80 0.00 000 000 347047.46 246x-583.84 60°4446.471"N 150'51'17.556"0.' 0.00 1000.00' 0.000 38.500 100000 8.x4.80 0.00 0.00 0.00 347047.46 246568384 6744'44.471'1 1575717556796' 000 1100.007 0.000 38 500 110000 934 30 0.00 0.00 0.00 347047.46 2465683 04 674446.477 1575117356"W 0 00 ..............._....... .. 1200.00' 0000 38300 1200.00 102.4.80 0.00 0.00 0.00 347017.46 2465633 01 674446.471'1 15751'175567W 0.00 1300.001 0.000 31500 1300.00 1134.80 0.00 000 0.00 347047.46 2465483.84 6044'46.47114 15751'173567W 0.00 140).00' 0000 38500 1400.00 1224.80 0.00 0.00 0.00 347047 46 246x58384 6074446.471" 15075117356M 0.00 1509.00 0000 3S500 1500.00 1324.50 0.00 000 0.00 347047.46 2465683.84 6074446.471'7 1507511735670.' 000 Baton Thal Nthp ___ 1E00.00' 1000 38500 159999 1424.79 0.87 0.60 0.54 347048.01 246548451 60°44'46.477N 15751'17.546'W 1 W 1700.00' 2.000 38 500 169996 1524.76 3.49 273 2.17 347049.67 2465586 54 674446.498"7 15751'17313"W 100 1800.00 3000 38.500 179926 1634.66 7.25 615 419 347052.43 246668992 604446.531N 150°51'17.458'00 1.00 sdasaa-"r.."."1 1900.00* 3000 38500 1899.73 1734.53 13.09 1024 8.15 347055.74 243569397 674446.571'7 15751'17393"W 000 2000.007 3.000 38300 199939 1834.39 1332 14.34 11.40 347059.05 246669802 674446.612"N 15751'17327"W 0.00 2100.001 3.000 38300 3099.45 193425 23.55 18.43 14.66 347062.36 2465702.08 674446.652'7 150'5117.232" 000 2200.007 3.000 38300 2199.31 2034.11 20.79 22.53 17.92 347065.67 2466'•03.23 674446.692'7 15075117.1967W 0.00 2300.00, 3.000 38500 2299.18 2123.96 34.02 26.62 21.1E 3470609E 2465710.18 604444.733N 15751'17.130"W 040 2400.00' 3000 38500 239904 2223.34 39.25 30.72 24.44 3470"_29 246571424 6074446.773'7 1575117.0667W 0.00 2500.007 3 000 33 500 249390 23'3.70 44.49 34.82 27 69 347075 60 246571329 63°44'46.813N 150°51'16999"W 0.00 2600.00' 3 000 33 500 2598 77 242357 49.72 38.91 30.95 347078 Pi 246572234 63°44'46.854'7 150751'1693.67W' 0.00 2700.00' 3.000 38500 369363 252343 5495 43.01 3421 347002 23 246572339 674445.894"7 150°51'16.3611"W 0.00 2800.00, 3.000 31300 2793.49 2623.29 60.19 47.10 37.47 347085.54 2465730.45 604443934"04 150751'16.803" 0.00 Page 55 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company 11 Planned Wellpath Report ®l/II SRI:14B 27 Version 44 BAKER Page 3 of 6 HU Iri.or u.a.,ttr: GHIES REFERENCE R'ELLPATH IDENTIFICATION Opaatar iiicerp Aoki,LLC Siat ,7..t Area Cook Inlet,A1a*a(Kenai Psiei) We11 _2 t 11-27 F:e d Swanson River Unit *dime OW Ua27 -� FaciL'y 5807 4143(14B-27-13-27) WELL(ATH DATA(118 stations) +=internal ted'e!trapohted station ]IID Ia iia°tio. Aaael+ TS'D TVD fries Vert Sect North Ect Grid Lot Grid Nardi ,. dr L isLa.iedr DIS Csssn ° Ifl N r1 14rid 114 Ed..j.. [@3 I6] Pi 1TP t6 I Ra a) r,laDfr] 2903.00 3.000 30.500 259136 2723.16 65.42 5120. 40.73 347088.852 .__ _-14:T450 60°4T4b F,:^.: I50`51'16.;37'Q' 0.00 300).00* 3-000 38.500 2998_22 2523.02 7066 5530 4398 347092.16 246573S 55 63'4447.015'N 1505116.672'70' 0.00 :901'0 3.000 38.500 3000.00 2524.50 70.75 5537 44.04 347092?2 246573562 60`4447.016"N 150'S1'16.670'70' 0.00 BaiM.'1nPbLlcp .. 3100.00' 2.018 38.500 3098.12 292292 75.05 58.73 46.72 347094.94 24657.4195 63`4447.049'N 15051'16.617'70' 1.00 3200.001 1.013 38300 3198.08 3022.88 77.70 60.81 4837 347096.61 2465744.00 604147.069''. 150°517651'16 1.00 33(3.1' 0.018 38.50D 3298.05 3122.01 78.60 61.51 48.93 347097.15 246574470 63`4447.076'N 150'51'16.572'W 1.00 330471 0.000 38.500 3249.56 3124.66 78.60 61.51 48.93 347097.15 2465744700 60`4447.0765'. 150'51'16372'70 1.00 Endo/Drop__ 3403.00' 0.000 38.500 3391.00 3222.55 78.60 6151 48.93 347097.15 246574470 6,1'44'47.0761 150`51'16.572'70' 0.00, 3503.00* 0.000 35.500 3498.08 3322.58 78.60 6151 48.93 347097.15 2465744.70 60`44'47.076'7 150`51'16572'0' 0.00; 3600.001 0.000 38300 3598.08 3422.88 78.60 6131 48.93 347997.18 2465744.70 604147.076' 15051'16.573 000: ' 3700.00 0.000 35.500 3595.05 3522.00 72.60 61.51 48.93 347097.15 246574470 60'4447.076'7 150`51'16.572'70' 0.00': 3800.007 0.000 38.500 3795.05 3622.55 78.60 61.51 48.93 347097.10 246574470 63`44'47.076'N 150'51'16572' 0.00. 3900.007 0.000 38.500 3598.00 3722.55 78.60 61.51 48.93 347097.18 2465744.70 63.44'47.076'2 15051'16572'70' 0.00 4003.001 0.000 38.500 3995.00 3022.88 7860 61.51 4893 347097.15 2465744.70 614447.076'N N 150'51'16.572'3 0.00 4100.001 0.000 38300 4098.08 3922.88 78.60 6151 48.93 347097.18 2465744.70 60°4947.076'1C 15051'16.57E 13' 0.00'i 4200.007 0.000 38.500 4198.05 4022.58 78.60 6151 48.93 347097.15 2465744.70 60'44'47.076'2 150'51'15572'70' 0.00 4303.007 0.000 38.500 4298.08 4122.88 78.60 6131 48.93 347097.15 2465744.70 63'44'47.076'N 150`51`155 0.11' 0.00 4400.007 0.000 38.500 4398.05 4222.58 78.60 6151 48.93 347097.10 2465744.70 60'44'47.076'N 15051'16.572'4 0.00 4502.007 0000 38.500 4498.05 4322.58 78.60 61.51 42.93 347097.15 2465744.70 60'44'47.076'N 15051'16372'70 0.00 4600.001 0.000 38300 4598.08 4422.88 78.60 6151 48.93 347097.18 2465744.70 6044'47.076''. 13Q'S1'1� 0.0011 4700.007 0.000 38.500 4698.05 4522.58 7860 6151 48.93 347097.15 2465744 70 60`4447.076''. 1505176.573'70 0.00 4803.00' 0.000 30.500 4798.03 4622.88 78.60 6151 48.93 347097.10 2465744.70 60`44'47.076'\ 150517637M 0.00 4903.00 0.000 38.500 4048.05 4722.28 78.60 6131 48.93 347097.18 2465744.70 60'44'47.076'N 15051'16572"U' 0.00 5000.007 0.000 35.500 4995.05 4522 SS 78.60 6131 48.93 347097.10 2465744.70 60'44'47.076'17 15051'16372'70 0.00 5100.001 0.000 38300 5098.08 4922.88 7160 6131 4893 347097.18 24667744.70 674447.07.70'. 15051'16372'16 0.00:1 5202.007 0.000 32.500 5195.05 50212.55 78.60 6131 48.93 347097.18 2465744.70 60`44'47.076': 15051'16.572'70 0.00 5303.00 0000 32.503 5295.05 5122.85 78.60 6131 48.93 347097.18 2365744.70 60`4447.076'\ 15051'16.572V 000 540).10 0.000 38.500 5398.05 522218 78.60 6131 48.93 347097.15 246574470 60`44'47.076''. 150`51'165;'"U 0.00 5501100 0.000 38.500 5498.05 5322.58 78.60 6151 48.93 347097.18 246574-4.70 60`4417.076'N 15051'16.572'70' 0.00 5600.001 0000 38300 5598.08 542188 78.60 6151 48.93 347097.18 2465744.70 60°44'47.076'N 1505116.572'4 0.00 Page 56 Revision 0 Nov,2012 Swanson River Unit II14B-27 Drilling & Completion Procedure Hilcorp Energy Company II Planned Wellpath Report Fa ii SRU 14B-27 Version 44 B,A,KER Page 4 of 6 IliHUMES 4we�11r.L�,I.IIt REFERENCE TUFT I PATH IDE NT FICA.TION Operator Siker!'Alaska,LLC ;. y?i Area Cook Inlet,Alaska(Kenai Peninsula) 0'e:1 SRC 14B-27 EField Swanson Riser Unit R'elbare SRU 14B-27 p, .knit' SRV 41-33(I4B-27-13-2 13-27) WELLPATH DATA(118 stations) '=interpolated eztrapoLuted station AID ]`diad_ Mala TVD TlDfram Vert Sect Narita £aa ` Grins* Gni Korb-_ LOW. rit lel MI n I I [J Rd [¢1 ffI I'1 [til Icy ral !Comoros 5700 00L., 0.000 35.500 5698.65 5522S3 78.60 61.51 4S93 347097.1S 2465744.70 60'4447.0.67'.' 150°5116372W 000 5500.00* 0000 35.500 5798.08 5612 SS 78.60 61 51 4593 .-.09.IS 246574470 60'4447.0761; 150'51'16372'W 000 590000' 0000 33500 5598.08 5722.58 78.60 6151 4593 347097.15 2.4657447 6CF44474761: 1545116372'W 0 0 600000' 0 000 38.500 5998 08 5522 S8 78.60 61.51 4593 347097.15 2465744.70 60'4447076N 150°5116.572"W CCC 6100.00; 0.000 38.500 6098.08 592288 78.60 6131 4893 347097.18 246574470 60°4447076W 130 s116372'Yf ' 0.00 ",a" COO 00, 0000 3550€ 6198 OS 6022 SS 78.60 6151 4593 347097.is 2465744 70 60'4447076N 150'51'16.572''W i 0.00 630000' 0000 35.500 6298.08 812258 78.60 61.51 4593 347097.15 2465744.70 6'44'47.0767N150'5116572'W 0.00 640060' 0000 3S.500 6398 OS &.2231 78.60 6151 4593 347097.15 2465744 70 601'44'4'.0761:' 150`5116.572"0' 00C 650000-" 0000 35500 849808 632253 78.60 61.51 4593 347097.15 246574470 60`44'47476"1` 150°51'16.572'W 000 6600.00' 0.000 38300 6598.08 6422.88 78.60 6131 4893 347097.18 2465744.7060°44'47.076N 150°5116372"W 0.00 6700.00' 0.000 35500 6698.08 6522.55 78.60 61.51 4593 347097.1S 2465744701 60'44'47.076'0 150°51'16.57M 000 630(00' 0.000 35500 6795 OS 6622 SS 78.60 61.51 4593 347097.15 2465744.701 60`44'47.76': 150°51'1637211' 000 6900.00' 0000 35.500 6598 OS 67228". 78.60 6151 4593 347097.1S 246674470 r 60F4447.0761; 1501196372'0' 000 6950.00 0.000 35500 (948 OS 6772 SS 78.60 61.51 45 93 347097.15 246574870F 601'44'47.0762: 150°5116372"W 000 RCP 7000.000 1.000 38300 6998.08 682228 79.04 61.86 49.20 347097.46 2465745.. 604417.080N 150'5116.567' 2.00 7100.00' 3400 35.500 709801 692281 52.53 64.59 5137 347099.67 2465747.75 6064447.1070 150'51'16.5231V 200 720000' 5.000 35.500 7197-76 702236 59.50 70.05 55.72 347104.(6 2465753-15 60'4447.1601'. 150°5116.436'V. 100 7300.00' 7.000 3S.500 7297.21 7122.01 99.95 7823 62j2 347110.69 2465761.24 6044'47241'N 150°51'163051V 200 7400.00' 9.000 32500 739623 7221.03 113.87 89.12 70.89 347119.50 246577202 60'4447345'N 15015116.130115' 200 7500.001 11.000 38500 7494.71 731931 13124 102.71 11.71 347130.48 2465785.46 60°44'47.482'N 150'51'15913"W 2.00 7600.00' 13000 38.500 7592.52 141732 152.03 11598 94.64 347143.63' 2465801.56 60'4447-54:1; 150°5115.652"7' 200 7700.007 15.000 38.500 7689.54 751434 176.22 137.91 10970 347158.94 246582030 60'4447829fi 150`51'15350'0' 200 7800.001! 17.000 35.500 7785.66 7610,46 203.75 159.45 12686 347176.37 2465841.64 60'44'48.04174 150151'15.0041V 200; 790000*' 19.000 38.500 7580.76 7705.55 234.65 183.66 146.09 347195.92 2465865.5 7 6744'48279'N 15015114.617W 200` 8000.00 21.000 38300 7974.73 779933 268.88 210.43 16738 34721755' 746529105 60R44'41343N 150°5114.189"W 2.00 Fri Oars* 8100.D0' 21.000 38.500 5068.0? 7592-89 304.72 238.47 189.69 347240.M 2465919.80 60'4445.819'N 150'51'13.740"W 0.00 5200001 21.000 3S.5O0 5161.44 798624 340.55 266.52 212.00 347262.90 2465947.56 60'44'49095 : 150°51'13291'7' 040 S300 00f 21.00' 35.500 5254.54 8079.60 37639 294.57 23431 34728537 2465975.31 60'4449371'N 150151'12.8421V 0.00 5400.00' 21.000 35500 2348.16 817296 412_13 322.61 256.62 347308.24 2466003.06 6€'44'49.545'N 150°51'12394'W 0.00 11500.00T 21.000 38300 844133 126632 448.06 350.66 27293 34733091. 246603051, 62`4849924.N 150111194'.8 0.00 Page 57 Revision 0 Nov,2012 Swanson River Unit in , 14B-27 Drilling & Completion Procedure Hilcorp Energy Company 11 Planned Wellpath Report *� SRL'14B--27 Version it4 BAKER Page 5 of 6 nHUGHES �y.,r 1110•61110•61,. ,8 4a: REFERENCE WELLFATH IDENTIFICATION Operator Y:r orp Alaska,LLC. Silt 7 lc Area Cook Inlet ALska(Kenailaisnle) Wall NII11E47 Field Swanson River Unit Oboe 1147 �. _, ... Faculty SRU 4133(1 4B-21-13 21) WELLPATH DATA(118 station,) 1.=inter polated!eztrapolated steam MD INd nlisa Atoette TVD TVD from Vert Sect 1 .l rtle + Last Grid Poi I (ie617imii 1 Latimer Imagit.er DIS iC eMs [ft] [7 I 17 [hl nil Vert Ref [f] t6] till Psi 113521 r.190e1 8600.00- 21.000 36500 6534 SS 5359.62 483.90 372.70 30113 34735358 2464058.56 63'44'30100'N 150'5111.496W 0.012 2701.00' 21.000 -16500 652123 5453.03 519.74 406.75 323.54 34737615 246605531 6)'4430.4761 154`5111.047W 0.00 880000T 21.000 38500 672159 654639 55557 434.80 345.85 34739892 2456114.06 60'4450.752'1 150'51'10595'56' 000 8900.00, 21.000 35.500 581495 2639.75 591.41 46214 365.16 347421.59 2466141.81 60'4451.02121 150'5110.149' 000 9000.001 21.000 38.500 840831 8733.11 62725 490.89 390.47 34744416 246616957 6044'51305'N 150'51'09.700 A' 0.00 9100.00' 21.000 35.500 9031.67 6626.47 663.01 51893 412.78 34746693 245619732 60'4451.5S1'N 150`51'09152' 000 92C0 DOT 21.00) 36500 434502 8919.52 69892 54696 435.09 34748960 2456225.07 60°4431.857'N 150`51'06203' 000 9300.00' 21.00) 35500 918838 9013.18 734.76 575.03 457.40 34751227 2466252.82 60'4432.133"N 150`51'05354'W 0.00 4400.00' 21.00) 3S 500 9'51.74 9106_54 770.59 603.07 479.71 34753494 246692.57 60'4432.409'1 15091'07905' 000 9500.001 21.000 38,500 9375.10 919990 806.43 631.12 50102 347557.61 246630632 604452.685'N 150°51'07456' 0.00 9600.00' 21.00) 35.500 9468 46 9513.26 542.27 659.17 524.32 347580/8 2466335.07 60'4452.962'1 150'51'07.0077.4' 0.00 9700.00' 21.000 35.500 9561.51 9386.61 578.10 65721 546.63 347602.95 2466363.82 60'4453_138'N 150`51'66556 W 000 9800.00' 21.000 36.500 9655.17 947997 913.94 715.26 566.94 347625.62 2456391.56 60'44'3.514"N 150'51'06.11016" 0.00 9900.00' 21.000 36.500 974853 957333 949.70 74330 591.25 34764819 246641933 60'44'53.790'N 150'51'05.661' 000 10000.001 21.00D 38.500 9141.89 9666.69 985.61 77135. 61336 34767096 2466447.01 60°4454.065'N 150'51'05313'" 0.00 10100.00, 21.000 36.500 993515 9760.05 1021.45 799.40' 635.87 347693.63 2466474.83 60'44'54343'N 150'51'047631W 000 10200.00' 21.000 31.500 10028.60 9853.40 1057.29 827.4 658.18 34771630 246650256 60'44'54.619N 15091'04314V 0.00 10300.00' 21.00) 32.500 1012196 9946.76 1093.13 15549 680.49 34773897 246653033 60'4454.895'1 150`51'03.865'W 0.00 10400.00' 21.000 36.500 1021532 10040.12 112896 81353, 702.80 347761.64 2466558.05 60'44'55.171'1 150°5193.416'W 0.00 10500.001 21.000 36500 10308.68 10133.48 116410 91138 725.10 3478431 246651513 60'4435.447'N 150'5101967'W 0.00 10600.00' 21.000 35.500 104020 10225.84 1200.64 939.63 747.41 3450699 2456613.59 60'4455.723'N 150`51'02515'SL' 0.00 10700.00' 21.000 35500 10495 39 1032019 1236.47 967.67 769.72 34782966 246664334 60'4436.00021 150'51'02 07014. 000 10800.00' 21.000 35.500 10588 75 10413.55 127231 995.72 792.03 34785233 2466669.09 60=44'56.276N 150`51'01621' 000 10900.00' 21.00) 36.500 10682.11 10506.91 1308.15 1023.77 814.34 3477500 2456695/4 6)'44'55.552'2 150'5I'01.172W 0.00 11000.001 21.000 38.500 10775.47 1060037 134398 105111 836.65 347847.67 2466724.59 604456.828'4v 151751'00_723'W 0.00 11100.00' 21.00) 35.500 10668 S3 10693.63 1379.52 1079.86 856.96 34792034 2466 52.334 60'44'57.104N 150'5110274'W 0.00 11200.00' 21.000 3S.500 1096218 1078698 1415.66 1107.90 881.27 347943.01 2466750.09 60'44573602 150`50'59.823' 000 11300.00 27.00) 35.500 11055.54 ,/ 1058034 1451.49 113595 903.58 34796568 2456507.25 60`44`57.657'N 150'5059376'W 0.00Raeiwd1D Page 58 Revision 0 Nov,2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company II Planned Wellpath Report VAI SRU 14B-27 Version ir4 BAKER Page 6 of 6 HUGHES Udell.?t10.1.0,I la: REFERE".E R'ELLP.-tTH IDENTIFICATION Operator :• cap Alaska,LLC__..__... _ Slot RU 14B-27 Area Cook Inlet Alaska(Kenai Peninsula) Well SRU 14B-27 Fie:d Swanson River Unit �T hore SRU 14B-27 Facil y SRU 41-33(14B-27-13-27) I i TARGETS Name 11D TVD North _r.East T. Grid East Grid North Latitude i Longitude Shape [ft] [ft] (ft] Pi [US ft] [US ft] SRt13B-27 Lower Sterlur 6-Nov-12 438.20 0.00" 0.00 347047.46 2465683.84 60'44'46 471" 15C`5117 556'11' poiri 68.20 -22.34 -99.49 346947.70 2!65662.80 60'44'46.251"H 150°51'19.55SW point SRU10-27 B-6:5-Nov-12 --- 77 20' 20.41 -57.94 346989.80 2465705.00 60•44'46.6721211150.51'18,7221iT1 point SRU14B-27 LBGT:5-Nov-12 A - SRU14B-27 D1CT:5-Nov-12 I 5674 20' 110.07 7.21 347066.10 2465793.80 60'44'47_555'V150'51'17.=11°W point SRUldB 27 644:5-Nov-12 6420.20 157.94' 42.09 347091.60 2465841.20 60°44'48.026"Ni _y 15 51'16 71 C'U4' pout 9154.201 521.361-331. SRClIB z7 TFonek HP H2O:5-Nov-12 '1 347386.40 2!6620 .80 60'4411.6747N' I5C`:1'10 853'A' pout SR1:14B 27 G2:5-Nov-12 10515-20; 19532 623.79 347682.80 21665 0.80 60'44'55 286"N 150`5105.00610; circle,.- SRU14B 27 HILT:5-Nov-1210601-20 915.23 639.03 347698.30 2466590.60x 60'44'55.4531; 150•51‘94 69S'W titch [ 10627.20 923.63 63592 347698.30 246659900 60'4415.566"N 1501104.701"96 r cle� SRU14B-27132-5:5-Nov-12 - 10787.20;-966 27, 672.1; 347732.10 2466631.20 60'44'SS916"N' 15011.04.0321V point SRU1lB-27 H7-8:6-Nov-12 SRUI4B 27510:6.-Nov-1210595.20 1000 29 607.03 347757.40 24 66674 90 60.44'56311"N 150°5103 532'G' circle TARGETS ilde game IAD_. I TVD 1102.1101 10i372633Nora i last 1 35 X71 r QV East lu 6�9i15.19 .630111 15011'02.94310I e sRL'13B-27 TD:5-Nov-12 mm Page 59 Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company 33.0 Directional Plan View (Plot) 11 Hilcorp Alaska, LLC BAKER Locater: C00%Ire:,A asl.a:rera Per Fled: .2nenn R,er Ve CRL14E-27 reefer: CR11LI 41.33.14E-27-12-2, :la CP.,14E-2, k : . e tere: CRL 14E-2, r4-1' HUGHES %11,ka.1 Pict reference'4464pan L'RU 148-27 Vwstel a4 True Yer2C41Oep:Is are Were-iced:o Arca;Fox fin8 Gr.:System N27 TM A4513 P.Zone 4(.5C04'.US fee: measurea aepIrs we referenced lc arDlc Fox:RTE1 NDf1B Reference:True norai • A=t Fox IRTE)lo mean sea level. 75 2 tee: Scale:True distance mean sea level to Mud Ire e1Cl:Sl7J 1419-27 C feet Deptrs are in feet emaciates are In feet renerenced to St: creates by ionetron to 111,-2012 18.5 ERU14B-27 Lerner Sierra.5-Nov-12 'Bele Dr 1.4rIce 1 03'."Den Err:1.784d irtgor.70•OW rt E-Nn-12 1,, BRU MGT:5,44cre-12 SRU1 MDT:5-Ncv-12 r- V 2 SRU E-27 64-6:6-Noy-12 BOP • , 1E0'11 Cat Era V Carve SRU14 7 Tyonek 1F11211 5-Na-12+ SRU14E-27 6-Ne-I2 EikAt5invogliz,* ERU1413-277147-11:6-Nov.12 fiRL1148-27 H10 E-Ncer-1.2 SRU1413-27 10 E-rive-12+ Reynea TD 410 0 MO SW 1101 WOO Vertical Secton(ft) Arrn.V MAT MC,reterrece ESC N.V CC E Page 60 Revision 0 Nov, 2012 Swanson River Unit II14B-27 Drilling & Completion Procedure Hilcorp Energy Company 34.0 Plan View (XY) Hilcorp Alaska, LLC BAKERHUGHES L.st an: CLLR In e:Armes Tent Penns4 a: vKr CRJ'41,-.:7BM Heid' 3Aa,o-R vee-27 l.el. CRJ'ce Hi.�.-�.�ES gar ltl' 'SRU 4t-331x48-27.13�u1 .1'tI GLYc' tau'4E UGni Itiirwrtl Alada.I I r. ,Ct reference;se1,pal,Is SRJ 148.27 Version 04 True ver'ca'aspire are referenced to Patio Fox(RTE) Gra Syetern NAD27:TM Alaska SR,Zone 4 15004;.US feet Measures Dep:ne are reTere1e2)o Ar22C Fax{RTE) Nutt Reference:Tne rCrtn Attic Fox I RTE)to rival sea Leve:1752 tee: Scale:Thie tstance tear sea leve to Nu0 Ire(A:Slat,^,RU 14E-27;:0 fee: Deptne we in Tee: Ccorara:es are<n feet references to;ct Crea:ec by jonetran or 11:52012 IR �o Q �1f �p East (ft: 4qp �p p' �qp epo app i � •i f 1 l r r I I 1 1 r vio 1N- 4,1' - ®o / 1 1114— - TOO SRU140-27 TO:5-Nov-1- — SRU14627 H10 S-Nov-' . 1003 81111148-27H7-0 5+04.-1 5Ru145-27 H2-5.icre •-• 11111111111141K - afiu146-2702:5-0lar1 - 000 ow- - em -- - 700 MI- - 930 r SRUf48_'?Taint HPHS:?-rrxrL2 + t 100- - moo .. as- - 400 144- - oro OM. End ee Curve - 800 5FJ14B-2764x:50Ja.N2 + - 1101.1140-27 D1CT:S-Nv-12+ - 00 eev-r Anile n44 SFU14eF27LEOT:'ib.-12+ E'itl c+eultl 4 I* 4epn Dn N:ppe - 0 SAX..S-27 Lows Erring 5-Non-t+ SRU 118-27 WE: 16 6 411- -100 111.- I -900 e ■ I t t t 1 t 1 1 t t iN 0 I 0 ID w 000 400 1f00 4N 7W 400 400 1000 r....'•w„ East ng(ft) Page 61 Revision 0 Nov, 2012 Swanson River Unit Ili14B-27 Drilling & Completion Procedure Hilcorp Energy Company 35.0 Surface Plat (NAD 27) SECTION_LINE 28127 NOT TO SCALE N 246643344 33 34 AS-STAKED WELL E?47690,76 SRU 14B-27 N:2465683.838 E:347047.461 ✓ in LATITUDE:60'44'46.471"N Lo N. LONGITUDE:150'51'17,556"W ASP ZONE 4 NAD27 /% FEL=635' / HNL=758' /7/ �\ ELEV=156.7'(NAVD88) SECTION 33, // %.''\,. TON,R9W,SM,AK s4t vt1 4 a:0*.zr 4/ // 635'FEL ,r, /i /1 /f ��,�\ /�/ ` .. F. II W .* r z 4 % /'t�e.rr'/Sra..c. j z /e,�I / SEC 33 ,j '.M, SCOTT McLANE; '� al� Y• 0 `I,'- 4928-s 011— ^, 1- // vi� '••a ,2, ;3.-..ek` W 0 NOTES -- i}toms OG 2 Icor 1NAI)S:NQS OPUS SOLUTION PROW CORS -- ENI ARO"t StA'Al ASKA STAT F P,ANi-/OM-4 NAI?83 OCH 2003. NORTH 2)BASI8 OF ELEVATION:NQS SM QTS ReSe T M1 NAVl7Q8, _ w 3)SECTION LINE OFFSFIS COVPUI HI FROM ksi M CORN RS - [ FOUND AT Y 532 533,NW)ie S33&N Xe S32 S33 ANU USED TO COI,+p'UTE NE CORNER S33 COOR7INATES SHOWN. SCALE 4)CORPSCON VERSION 6 T.1 SC'MARE WAS LIMED FOR o ian 2cc CCYQVERSIONS BETWEEN DATUMS,NAD83 TO NAD271. I . I . I SRU 14B-27 WELL AS-STAKED SURFACE LOCATION (NAD27) SWANSON RIVER FIELD LOCATION:SECTION 33, TOWNSHIP B NORTH. i, ENGINEERING-TESTING RANGE 9 WEST,SEWARD MERIDIAN ALASKA SURVEYING-MAPPING P.O.EQX Orae RANGE Iil car',Alunka,LL(. SOLDOTNA,AK.93669 JOB NO, 123110 �w� VOICE:(907)283-4218 FAX:(907)283-3265 DWG c .ut1 IncN'WW,MCLANECG.COM 123110 k, I Date:0911212 FIGURE: 1 Page 62Revision 0 Nov, 2012 Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company 36.0 Spider Plot (Governmental Sections) •SFU 12-27 SRU 212-27 P-2F7 • KGSF3 KGSM il SRU223-28 KG? rA - • CSR`- ED ill 17 SRU 314-27P8 SRU 314-27 SRU 34-28 _.RU 314-27P81 • A028406 341'F$L'16 FWL.8.27, ON,ROW s A028399 jiL i 1 Top or Fr .,t.:•NOfROn / 301'FNL-21Y`FEL 1.0 33.TIM.RTN,3 I S008N009W :.RJ 21-33WD SRU 21-34 f* - SNL 134'FNL,731'FEo 131 78 .ROW.S / 5Ru2 •.,_... •SRU 32A-33 E9 K3 ASCU 343-33 Legend I SCU 13-34 Surface Location 1 A028990 40 Top of Production Horizon /7_ECU33-33 • Bottom Hole Location S `" 3' CU 33-33 ---- Well Track i II 0 C+75 t.6`: Swanson River Unit Feet SRU 14B-27 kasha State Pone Zone 4,NAD27 tic—,I, 11..L,.114 May 3.2012 Page 63 Revision 0 Nov, 2012 �� Swanson River Unit 14B-27 Drilling & Completion Procedure Hilcorp Energy Company 37.0 Mud Weight, PP, FG vs Depth Plot SCU 14B-27 MW, PP, FG vs Depth 0 - 500 1000 1500 —M W vs Depth 2000 —FG vs Depth 2500 —PP vs Depth 3000 3500 4000 4500 50.00 5500 8 L, 6000 �--- t m 6500 7000 7500 8000 _ NN. 8500 9000 9500 10000 �— 10500 11000 11500 12000 4 6 8 10 12 14 16 18 EMW(ppg) Page 64 Revision 0 Nov, 2012 TRANSMITTAL LETTER CHECKLIST WELL NAME /` - — 2-7 Coir---7e 6' / PTD# / Z off? j/ Development Service Exploratory Strati ra hic Test Non-Conventional Well FIELD: <_,eZ 61 z� /L SPOOL: �� �2 C 'c O 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 approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing 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 ❑❑ re CO o) co N Na) To C (D a . O I C C u 0. a 'a3 0` p 1 Q 2 of N N E C ��� CO' V OCO da . '� Wa) w � c wow 3 c' o' 0) .c r- o a , >. ' 3' E ar _TY co 0: '�; wi :`o, m c p O 3: >� �: a E t� c,.). O a) a) • c o: o ami, — 3 . co, 0 o: >. y: a : �, E: .' c o > o: 3: o V O T f, ` . 'N 'O a , .3, - 3 H c' a) 3' ' Z {c0pi CZ Q v a0 O CO CD �� �: O, �� C �� rOi: N, �, W N'C to a). O. N ..L+ E > C D, 3' C " j 3, W O d O co ` 0 al co' y 0' 3 0. c (7i, v u) r lN� a 4 o a� p. N, �. : T - T a). O) . �, v, �+, �: 4 . v .L. 1-.. 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U' > >' >i' co, T N T N 01 W W aj >> N fa o. N, s21:5 CP a) = O, a€),, 0 s m °) '1), 0 cv v 4 4 a`). a), m; 0. 3. 2, o. a �'. 2, 2', m; o, o, `� •c, O O. .0 o a aui a€) m', a a o), o; o � Z. a - DS, �', �, cn, tc; o, 0, a, a; 0, �' ¢; a, 0, U) 0, U, U, U, Q, ,.-; Q, r-, 0, co, ca0, �' N; 2' a 13cncn0 ai W*< p' N- O - N M V ,!) a7 a0 O) O ,- N M gi b O N- CO O) O - N M A ,f) O n a0 O) N co ,O CO n co 0) r (Si N N N N N (Si N N N M M M M M M M M M M (.� N_ N N 1 A o O c w N r N ' (-,,,c) U C o c �a as ca o � 0 N � G N Cl N O y Q 4 O .CO C 0 N •N •r. � T a) C C ` o 0 E a w .O G. . —ao) `Qa I 0 a Q Q W 4 0 Q Page 1 of 1 , Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Tuesday, November 20, 2012 12:20 PM To: 'Luke Keller; Paul Mazzolini; Regg, James B (DOA) Cc: Mike Leslie; Jimmy Greco-(C); Davies, Stephen F (DOA) Subject: RE: SRU 14B-27 Changes to APD (PTD#: 212-089) Luke, Give me a call to discuss. A revised PTD is needed per 20 AAC 25.015(a)(1) due to the change in Surface location. I would send a revised 10-401 with the updates (new directional, mud plan etc) as needed to make the PTD up to date. You wouldn't need to send the Wellhead , BOP sketches etc, since we already have that. We can also approve(as appropriate) the other changes requested after review at that point. (Make sure you print in bold"REVISED"on the submitted PTD at the top. You can also put the PTD#in the box since that is staying the same. ) Kudos on the change form... nice way to capture changes. Other than the surface location change we could have approved most of the others with some email documentation and just updated the current approved PTD application ( see 20 AAC 25.015(a)(2) ) Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Luke Keller [mailto:lkeller@hilcorp.com] Sent: Tuesday, November 20, 2012 10:56 AM To: Schwartz, Guy L(DOA); Paul Mazzolini; Regg, James B(DOA) Cc: Mike Leslie; Jimmy Greco - (C) Subject: SRU 14B-27 Changes to APD(PTD#: 212-089) Guy, See attached SRU 14B-27 Drilling Program and also a summary sheet of changes made to the well plan post AOGCC approval of the PTD. One change (BOP test pressure) is a requested change so that there is uniformity throughout our Swanson River drilling program on test pressures. The APD was approved with a 5000 psi initial BOP test pressure,and then reduced to 4000 psi for subsequent tests. We would like to change that to 4000 psi for ALL tests to remove variation. Let me know what documentation the AOGCC would prefer to see on these changes,and let me know if you have any questions concerning any of the changes. Thanks, Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 11/20/2012 t . 21 _ Ogg Hilcorp Alaska, LLC Hilcorp Energy Company Changes to Approved Permit to Drill Date: Nov 20, 2012 Subject: Changes to Approved Permit to Drill for SRU 14B-27 File#: SRU 14B-27 Drilling and Completion Program Any modifications to SRU 14B-27 Drilling &Completion Program will be documented and approved below. Changes to an approved APD will be communicated to the AOGCC. Sec Page Date Procedure Change Approved Approved By By 1 2 11/20/2012 Moved surface location 141' East to the other side of the LEK pad. New coordinates are on attached Drilling Program. 32,33 54-60 11/20/2012 Directional plan changed slightly due to changed surface LEK location. BHL is 38'SE of the approved APD. MD has been shortened to 11,300'. P4 is the current rev. 6 6 11/20/2012 We would like to reduce the initial BOP test pressure to LEK 4000 psi,so that all tests are 4000 psi. There is nothing to be gained by testing the BOPs initially to 5000 psi. 14 25 11/20/2012 7-5/8" L-80 casing thread has now changed to BTC LEK instead of LTC. 17 34 11/20/2012 Production liner will be 5" DWC/C HT instead of 5-1/2" LEK VAM STL. 37 64 11/20/2012 Surface hole will be drilled with 10 ppg MW instead of 9.2 LEK ppg 37 64 11/20/2012 Intermediate hole section will start with 10.5 ppg,and LEK slowly weight up to 12.5 ppg per attached drilling program 13,16 24,32 11/20/2012 9-7/8" &6-3/4" hole sections will be E-line logged. Will LEK run only Gamma Ray on drilling assy. Approval: Drilling Manager Date Prepared: Drilling Engineer Date SCU 14B-27 Changes to APD Nov 2012 1 . N 1 41.1. , 4 4 . ., . ... VA ..... „, . , _ ,.. Ii/ii . - ,... , -, ' ;- --.),..e .,-- t ,.. .,..... : .. , ... , _, , . . __ , .,, ,. . . . . . . . . . ..... . 4,, '' ' tr . " I. •, . erT, s^+ f : i ..#,-. .4.4-......:....-..-.At-. I , _ ,,R , .: .. -- . . _ tier ;; 4, .. .. , d„,,,s1 ., ' ' ;•. ,, i . * ,‘ 4 4 . I, t t '.•3j ' • OW r • , �Mnwrr T"� w /t' 'SWV . .- --:-•• ' - ...'7 . - , ... , . ,, t t w 4alliailler-41.- -..w< , - - .:.. s....1:....»._ - -.• - r. - üzJ �l [0] SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W.7th AVENUE,SUITE 100 CONSERVATION COMMISSION ANCHORAGE,ALASKA 99501-3539 PHONE (907)279-1433 FAX (907)276-7542 Paul Mazzolini Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive Anchorage, AK 99524 Re: Swanson River Field, Hemlock Oil Pool, SRU 14B-27 Hilcorp Alaska, LLC Permit No: 212-089 Surface Location: 855' FNL, 738' FEL, SEC. 33, T8N, R9W, SM Bottomhole Location: 351' FSL, 285' FWL, SEC. 27, T8N, R9W, SM Dear Mr. Mazzolini: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the 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 revocation or suspension of the permit. Sincerely, Cathy P. Foerster Chair DATED this/0 day of July, 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 RECEIVED ALASKA OIL AND GAS CONSERVATION COMMISSION JUN 2 1012 PERMIT TO DRILL 20 AAC 25.005 1a.Type of Work: lb.Proposed Well Class: Development-Oil Q Service- Winj ❑ Single Zone Arca'i6(� i+Sfle lA6)$co Drill Q Redrill ❑ Stratigraphic Test ❑ Development-Gas❑ Service-Supply ❑ Multiple Zone ❑ Coalbed ), Radps Hydrates Re-entry D Exploratory ❑ Service- WAG ❑ Service-Disp ❑ hale Gas -E1 ,. 2 Operator Name: 5. Bond: Blanket Eli Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC Bond No. A22035257 ' SRU 14B-27 3.Address: 6.Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Dr,Anchorage,AK,99524 MD: 11,692 ND: 11,284 Hemlock Oil Pool 4a Location of Well(Governmental Section): 7.Property Designation(Lease Number): / Surface: 855'FNL,738'FEL,Sec 33,T8N,R9W,S A028399 , A Cw /YC -A4--L4(12-- Top LTop of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 301'FNL,282'FEL,Sec 33,T8N,R9W,S N/A 9/1/2012 Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 351'FSL,285'FWL,Sec 27,T8N,R9W,S 1760 282' 4b Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL:179 feet 15.Distance to Nearest Well Open Surface: x-346899• y- 2465597.4 - Zone-4 GL Elevation above MSL:164 feet to Same Pool: 21A-34(1535') 16 Deviated wells: Kickoff depth: 7,750 feet 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 30 degrees Downhole: 3413 psig Surface: 228 psig ,24.:..10 PS`� 7,/S,t� 18 Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Conn Length MD ND MD ND (including stage data) 13-1/2" 10-3/4" 45.5 L-80 BTC 3000 0 0 3,000 3,000 863 sx=1695 ft3 9-7/8" 7-5/8" 29.7 L-80 LTC 9000 0 0 9000 8950 9-7/8" 7-5/8" 29.7 P-110 HC LTC 1000 9000 8950 10000 9817 1127 sx=1684 ft3 6-3/4" ' 5-1/2" 20 L-80 ST-L 1892 9800 9643 11692 11284 160 sx=216 ft3 —4 / 11." 0 CD 80' ' g0 Ca,,..tu- r- 19 PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth ND(ft): Plugs(measured): Effect.Depth MD(ft): Effect.Depth ND(ft): Junk(measured): Casing Length Size Cement Volume MD ND Conductor/Structural Surface - Intermediate - Production - Liner Perforation Depth MD(ft): Perforation Depth ND(ft): 20 Attachments: Property Plat ❑� BOP Sketch Q Drilling Program 0 Time v.Depth Plot Q Shallow Hazard Analysis❑ Diverter Sketch❑I Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050 requirements❑� 21 Verbal Approval: Commission Representative: Date 22 I hereby certify that the foregoing is true and correct. Contact Printed Name ?A.(.4,..L.- " nZ.Z-OLt/L1'/ Title f�,Q/1�L,/A)G /4/414)U0c )C- Signature .Signature i aa...ti/ '/it , Phone q(21— 777— Uv 3 b, Date �`z-�2O/2-- [( / dd Commission Use Only Permit to Drill API Number: , T� �. Permit Approval '�Q\` ` See cover letter for other Number. Z( ? 50 'Z(/( � Date: requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methane, as hydrates,or gas contained in shales: Lr Other. �� O g 2:-..,i-1-i J do P f' Samples req'd: Yes❑ No Mud log req'd: Yes ❑ o[Y I Q l H2S measures: Yes❑ No[vf' Directional svy req'd: Yes Z.No ❑ ( LI000p5 t 74-" J /� — Su,, 'r re, �c.,rc.X Co►' !e-ii 0`- t ® t— 63 I"'vii ate+ . V U 7 r PPROVED BY THE COMMISSION DATE —I —( a COMMISSIONER "7- /3•/L Form 10-401(Revised 7/2009) This permit is valid for 24 month from the date of approval(20 AAC 25.005(9)) Submit in Duplicate �� \v ORIGINAL �iv / .tip. Hilcarp Paul Mazzolini Hilcorp Alaska,LLC lamp Gamow Drilling Manager P.O. Box 244027 Anchorage,AK 99524-4027 Tel 907 777 8369 6/20/2012 Email pmazzolini@hilcorp.com Commissioner R F�`e �.,.I�/E D Alaska Oil&Gas Conservation Commission � F 333 W. 7th Avenue Anchorage,Alaska 99501 JUN 2 6 ?012 Alaska Oil & lJa, (;ons. COn1RUSSiOti Re: Swanson River Unit 14B-27 Anchorage Dear Commissioner, Enclosed for review and approval is the application for the Permit to Drill the Swanson River Unit 14B- 27. SRU 14B-27 is a grass roots Hemlock development oil well planned to be re-drilled in a NE direction from the existing SRU 41-33 pad. SRU 41-33 has been permanently plugged and abandoned. Drilling operations will be conducted by the Doyon Arctic Fox. The Arctic Fox is a 400 kip, multi- module drilling unit with a telescoping doubles mast. Drilling operations are expected to commence approximately Sept 1st, 2012 depending on the progress of other ongoing projects and the availability of Doyon's Arctic Fox. Pursuant to 20 AAC 25.055(a)(3), a spacing exception is NOT required: 1. SRU 14B-27 does not fall within 500 ft of a property line where ownership or landownership changes. 2. It is not a gas well. 3. It is the only well to be completed within the SW quarter section of Section 27, and is more than 1000'from any other well capable of producing from the same pool. Pursuant to 20 AAC 25.005(c)&(d),the following is included: 1. Plat identifying the property on which the well will be drilled. 2. Diagram&description of blowout prevention equipment. 3. Information on drilling hazards. a. (4) formations will be penetrated that are potentially hydrocarbon bearing. MASP calculations are attached per 20 AAC 25.005(c)(4)(A) b. Potential target reservoirs and their predicted pore pressures are indicated in attached Well Desian Summary. 4. Formation integrity test procedure. 5. Planned casing&cement program(Well Desian Summary) 6. Diverter and diverter line schematic. 7. Drilling fluid program (Well Design Summary) 8. Tabulation of predicted depths with equivalent formation pressures. 9. Requirements of 20 MC 25.025 have been met. a. Blanket bond issued for Swanson River, bond no. 22035257 10. Copy of drilling design summary. Hilcorp Alaska,LLC Page 1 of 2 11. General description of waste disposal. Operator does not wish to request authorization under 20 AAC 25.080 for an annular disposal operation in the well. a. Drilling waste (cuttings and water based drilling fluids)will be contained at the drill site and hauled off to Emerald Services, Inc for inerting and subsequent disposal. 12. Requirements of 20 AAC 25.050(b) have been met. a. Plat showing path of proposed wellbore including all adjacent wellbores within 200' is attached. b. All wellbores within 200'of proposed wellbore are owned by Hilcorp. If you have any questions, please don't hesitate to contact myself at 777-8369 or Luke Keller at 777- 8395. Sincerely, ?cuAirliC154X c Paul Mazzolini Drilling Manager Hilcorp Alaska,LLC Page 2 of 2 Swanson River Well SRU 14B-27 Hiles Well Design Summary SRU 14B-27 Well Design Summary SRU 14B-27 is a development oil well planned to be drilled from the existing 41-33 pad. 41-33 is currently P&A'd.-- A 4-F. Integrated subsurface and 3-D geological interpretations, in conjunction with previous production data indicates that stranded oil reserves remain in the Hemlock 1-5 benches between the Fl and G faults. High on structure, G2, H8, Reserves aren't recoverable in existing wellbores due to lack of takepoints or mechanical condition of other existing wellbores in the fault block and / or H10 sands may be productive as well. SRU 14B-27 is designed as a "Build & Hold" well reaching 30 degrees inclination in the tangent section and reaching a total depth of 11,692' MD / 11,284' TVD. Basic Well Information Well Name: Estimated Spud Date: 8/1/2012 Field: Swanson River Productive Horizon: G-Zone & Hemlock `/ Total Depth: 11,692 MD, 11,284' TVD Surface Location: 855' FNL, 738' FEL, Sec 33, T8N, R9W, S X=346899, Y=2465597.4, NAD27, ASP, Zone 4 Planned BHL: 351' FSL, 285' FWL, Sec 27, T8N, R9W, S X=347998.3, Y=2466788.6, NAD27, ASP, Zone 4 Ground Elevation: 164' AMSL KB elevation: 15' Planned SRU 14B-27 Casing & Tubing Program Size O.D.le Weight Grade Conn Length MD/TTopVD Btm MD/TVD (in) (in) (lbs / ft) (ft) (ft) (ft) 16 112 L-80 Weld 100 WH 100 / 13-1/2 10-3/4 45.5 L-80 BTC 3000 WH 3000 9-7/8 7-5/8 29.7 L-80 LTC 9000 WH 9000/8950 9-7/8 7-5/8 29.7 P-110 HO LTC 1000 9000/8950 10000/9817 6-3/4 5-1/2 20 L-80 STL 1892 9800/9643 1 1692/1 1,284 6/20/2012 Page 1 of 10 II Swanson River Well SRU 14B-27 Hilc�oorn Well Design Summary m.a Well Control Summary Hole Section Equipment Test Pressure (psi) 13-1/2" • Hydril MSP 21-1/4" 2M diverter c/w 16" Function Test ✓ diverter line. Initial Test: • 1 1 " 5M Hydril BOP. 1 1" x 5M Hydril GK (Ann u aro 50000/2500 psi) 9-7/8" & annular/ 11 ' x 5M Hydril Double Ram / ,/ 6-3/4" 11 " x 5M drilling spool c/w 3-1/8" outlets Subsequent / 1 1" x 5M Hydril single ram Tests: 250/4000 (Annular 250/2500 psi) Schematics of the well control equipment are attached for reference. Anti-Collision Evaluation Summary SRU 14B-27 will be drilled from the same pad as the vertical well 41-33. 14B-27 surface location is planned to be 50'away from 41-33, 14B-27 will be drilled using a mud motor and MWD and nudged away from the 41- 33 wellpath as soon as competent rock is encountered that will facilitate directional work. MWD surveys will be taken every 95', and anti-collision data will continue to be monitored while drilling SRU 14B-27. There are no other anti-collision issues with SRU 14B-27. 6/20/2012 Page 2 of 10 Swanson River Well SRU 14B-27 Hil ,orp Well Design Summary rainy Formation Integrity Testing Test Point, Projected Test Fluid Density Projected Projected 20' Below... Depth (TVD) Type Used for Test Test (EMW Surface ppg) Pressure 10-3/4" Shoe 3000 FIT 10.5 13.5 468 psi 7-5/8 Shoe 9817 FIT 9.5 12.0 1276 psi Note:For the 10-3/4"shoe,offset field test data predicts frac gradient most likely between.64-.83 psi/ft (12.3-15.9 ppg). A 13.5 ppg FIT results in a 3 ppg kick margin(468 psi)while drilling w/10.5 ppg mud. Sul � If unable to get a 13 ppg FIT,LOT test results will be evaluated to determine whether remedial cmt work is necessary. ECDs will likely be In the range of 10.7-10.9 ppg,and to maintain an appropriate kick margin,a LOT of 12 ppg would be • the likely minimum acceptable result. g�c�?f c-v / 7�"1 cFor the 7-5/8"shoe,offset field test data predicts frac gradient most likely between.75-.80 psi/ff(14.4-15.4 ppg). A 12 ppg FIT results in a 2.5 ppg kick margin(1276 psi)while drilling the drawn down Hemlock formation w/9.5 ppg mud. Casing Testing Fluid Density in Test String Casing Pressure Test Duration Casing Burst (PSI) 10-3/4" 10.5 1500 30 min 3130 psi 7-5/8" Casing 9.5 3000 30 min 6890 psi 5-1/2" Liner 8.5 3000 304-5-min ' 9190 psi �3 �L 6/20/2012 Page 3 of 10 Swanson River Well SRU 14B-27 Hilcorp Well Design Summary Emma corspwr Mud Program Summary Surface Hole Section (13-1/2" hole, 10-3/4" casing to 3000' MD) System Type: Pre-hydrated AQUAGEL/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 100-3000' 9.0—9.2 60 85 10 28 45 25 <12 8.5-9.0 System Formulation: AQUAGEUfreshwater spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 12-15 ppb caustic soda 0.1 ppb (9 pH) BARAZAN D+ as needed BAROID 41 as required for weight 9.2 ppg PAC-L/DEXTRID LT if required for<12 FL ALDACIDE G 0.1 ppb X-TEND II 0.02 ppb Intermediate Hole Section (9-7/8" hole, 7-5/8" casing to 10,000' MD) System Type: 6%KC1/EZ MUD DP fluid system Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 3000'— 10,000' 10.5— 13.5' 40 53 6 30 13 20 <6 8.5-9.5 System Formulation: 6% KCI/EZ MUD DP Product Concentration Water 0.905 bbl KCI 22 ppb (29K chlorides) KOH 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) EZ MUD DP 0.75 ppb(initially 0.25 ppb) DEXTRID LT 1-2 ppb BAROID 41 as required for a 10.5 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 ppb (maintain per dilution rate) 6/20/2012 Page 4 of 10 Swanson River Well SRU 14B-27 Hilcorp Well Design Summary Production Hole Section (6-3/4" hole, 5-1/2" liner to 11,692 MD, 11,284' TVD) System Type: 6%KC1/EZ MUD DP fluid system Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 10,000'— 11,692' 9.5 • 40-53 6-30 13-20 <6 8.5-9.5 System Formulation: 6% KCI/EZ MUD DP Product Concentration Water 0.905 bbl KCI 22 ppb (29K chlorides) KOH 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) EZ MUD DP 0.75 ppb(initially 0.25 ppb) DEXTRID LT 1-2 ppb BAROID 41 as required for a 9.5 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 ppb (maintain per dilution rate) Completion (3-1/2" Tubing to 9700' MD) System Type: 3% KCI Brine Properties: Density-8.3 ppg, Chlorides— 15,000 ppm 6/20/2012 Page 5of10 Swanson River Well SRU 14B-27 Hilcorp Well Design Summary Energy Company Cementing Summary Surface Hole Section (13-1/2" hole, 10-3/4" casing to 3000' MD/TVD1 Cement volume based on annular volume + 50% open hole excess. Job will consist of lead & tail cement. Top of cement brought to surface. Estimated total volume is as follows: Section Formula Volume 16" x 10-3/4" annulus: (100') x 0.106 = 10.6 bbls 13-1/2" x 10-3/4" annulus: 2900' x 0.065 x 1.5 = 282.8 bbls 10-3/4"Shoe Track: 90' x .096 = 8.6 bbls Total Volume (bbls): 10.6 + 282.8 + 8.6 = 302 bbls Slurry Information: Stage Lead Tail System Conventional Conventional Density 12 Ib/gal 15.4 Ib/gal Yield 2.44 ft3/sk 1.22 ft3/sk Mixed Water 14.329 gal/sk 5.507 gal/sk Mixed Fluid 14.479 gal/sk 5.507 gal/sk Total Volume 229 bbl= 1285 ft3=527 sx 73 bbl=410 ft3=336 sx Expected Thickening Expected ISO/API Fluid Loss Code Description Concentration Code Description Concentration Type 1 Cement 941b/sk WBWOB Type 1 Cement 94 lb/sk WBWOB Dl 10 Retarder 0.15 gal/sk D046 Anti Foam 0.2%BWOB Additives VBWOC D046 Anti Foam 0.2%BWOB D065 Dispersant 0.4%BWOB D079 Extender 2.0%BWOB $002 CaCl2 0.2%BWOB D020 Extender 2.6%BWOB 6/20/2012 Page 6 of 10 Swanson River Well SRU 14B-27 Hilcorp Well Design Summary EmiQy Compaq' Intermediate Hole Section (9-7/8" hole, 7-5/8" casing to 10,000' MD/TVD) Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail cement. Top of cement brought to 4500' (1189' above shallowest formation containing hydrocarbons). Estimated total volume is as follows: Section Formula Volume ,, 'aL -7.4. 11) 9-7/8" x 7-5/8" annulus: ve)k6r)' 5500' x 0.038 x 1 .3 = 271 .7 bbls *3,low l°3't` 3�`°`' 7-5/8" Shoe Track: 90' x .046 = 4.1 bbls Total Volume (bbls): 24 + 247 + 4.1 = 7 S Y 13/1`5 Slurry Information: Stage Lead Tail System Conventional Conventional Density 14 lb/gal 15.3 lb/gal Yield 1.58 ft3/sk 1.35 ft3/sk Mixed Water 8.09 gal/sk 5.912 gal/sk Mixed Fluid 8.09 gal/sk 5.962 gal/sk Total Volume 200 bbl= 1 123 ft3=711 sx 100 bbl=561 ft3=416 sx Expected Thickening Expected ISO/API Fluid Loss 13 mL in 30 min Code Description Concentration Code Description Concentration G Cement 94 lb/sk 94 lb/sk WBWOB G Cement WBWOB Dl 10 Retarder 0.05 gal/sk Dl 10 Retarder 0.05 gal/sk VBWOC VBWOC Additives D046 Anti Foam 0.2%BWOB D046 Anti Foam 0.2%BWOB D020 Extender 4.0%BWOB D202 Dispersant 1.5%BWOB D065 Dispersant 0.3%BWOB D400 Gas Control Agent 0.8%BWOB D800 Retarder 0.2%BWOB D154 Extender 8.0%BWOB D174 Expanding Agent 1.5%BWOB 6/20/2012 Page 7 of 10 11 Swanson River Well SRU 14B-27 Hilcorp Well Design Summary Enemy Compaq, Production Hole Section (6-3/4" hole, 5-1/2" liner to 11,692 MD/ 11,284' TVD) Cement volume based on annular volume + 30% open hole excess. Job will be a single slurry design. Top of cement brought to liner top at 9800'. Estimated total volume is as follows: Section Formula Volume 7-5/8"Csg x 5-1/2"liner annulus: (200') x 0.017 = 3.4 bbls 6-3/4"OH x 5-1/2"liner annulus: 1692' x 0.015 x 1.3 = 33 bbls 5-1/2" Shoe Track: 90' x .022 = 2 bbls Total Volume (bbls): 3.4 + 72 + 2 = 38.4 bbls Slurry Information: Stage Lead Tail System Conventional Density 15.3 lb/gal Yield 1.35 ft3/sk Mixed Water 5.912 gal/sk Mixed Fluid 5.962 gal/sk Total Volume 38.4 bbl=216 ft3= 160 sx Expected 100 Bc at 5:24 hr:mn Thickening Expected ISO/API 13 mL in 30.0 min Fluid Loss Code Description Concentration Code Description Concentration G Cement 94 lb/sk WBWOB Dl 10 Retarder 0.05 gal/sk Additives VBWOC D046 Anti Foam 0.2%BWOB D202 Dispersant 1.5%BWOB D400 Gas Control Agent 0.8%BWOB D154 Extender 8.0%BWOB D174 Expanding Agent 1.5%BWOB 6/20/2012 Page 8 of 10 Swanson River Well SRU 14B-27 Hilcorp Well Design Summary e�comms Anticipated Formation Tops and Geohazards Top Name Formation Expected Fluid TVD Est Press PPG Gas Sand Shallow Gas Sand Gas/wet 446 Normal 8.5 B-6 Lower Sterling Wet 3,219 Normal 8.5 LBGT Top Lower Beluga Wet 4,284 Normal 8.5 DICT 25' Tyonek Coal Wet/gas 5,689 Normal 8.5 64-5 Gas Storage Sand Gas 6,430 1200 psi- 3.5-9.9 v 3300 psi Lower Tyonek Water 9,109 5500 psi 11 .6 G-2 Tyonek Oil Oil/water 10,529 2800 psi 5.1 HKT Top Hemlock Oil Oil/gas 10,616 2800 psi 5.1 H2-5 Hemlock Oil Oil/gas 10,639 2800 psi 5.1 H7-8 Hemlock Oil Oil/gas 10,804 2800 psi 5.0 H 10 Hemlock Oil Oil/gas 10,909 2800 psi 5.0 TD Lower Hemlock 11,284 6/20/2012 Page 9 of 10 Swanson River Well SRU 14B-27 Hilcorp Well Design Summary Rainy SRU 14B-27 Drilling & Completion Summary 1 Level and prepare pad for R/U drlg rig. 2 Set 16" conductor @ 100' below ground level. Dig out cellar and mousehole. 3 Mobilize drilling rig to 14B-27 pad. �, Aid-or-7 2_9 her r<'or 4 N/U and function test 21-1/4" diverter. 5 Drill 13-1/2" hole using 5" DP & a mud motor/ MWD assy to 3000' MD. Take directional & inclination surveys every 95'. Maintain MW at 9 -9.2 ppg• 6 Run and cement 10-3/4" surface casing. TOC at surface. 7 N/U & test "B" & "C" wellhead sections. N/U and test 13-5/8" BOP to 250 / 5000 psi (annular to 250 / 2500 psi).--�' toot.' 5.-„sr ��✓ 8 M/U 9-7/8" directional assy. TIH to FC on 4" DP. Test csg to 1500 psi / 30 min. Drill out shoe track & 20' formation. FIT to 13.5 ppg EMW. —7 Aim) "T-i /'PA, 9 Drill 9-7/8" hole to 10,000' MD / 9817' TVD. Take directional and inclination surveys every 95'. Maintain MW at 10.5 - 13.5 ppg. 10 Run quad combo open hole logs f/ 10,000' to surface. 11 Wiper trip, TOH c46 IZ*W%5 -lc 75/ _ 12 Run and cement 7-5/8" intermediate casing. TOC at 4500'. 13 M/U 6-3/4" directional assy. TIH to FC on 4" DP. Test csg to 3000 psi / 30 min. Drill out shoe track & 20' formation. FIT to 12_ppq EMW. 14 Drill 6-3/4" hole to 11,692 MD / 11,284' TVD. Take directional and inclination surveys every 95'. Acquire quad-combo LWD data while drilling. Maintain MW at 9.5 ppg. �r C/o ,A+ -k 5112 l 15 Run and cement 5-1/2" prod liner. TOC at liner top (9800'). Displace - cmt with 3% KCI completion fluid. 16 Set 8, test liner top packer to 1500 psi w/ 9.5 ppg WBM. e' 17 Displace wellbore with 3% KCI completion fluid (8.3 ppg). A 18 TOH. Test casing & liner to 3000 psi / 30 min. 19 N/D BOP, install dryhole tree. 20 RDMO drilling rig. 21 MOB AWS Rig #1 to perforate 5-1/2" liner, run 3-1/2" gas lift completion, N/U tree. / v) tFc V c x, oue,t_ -s d4- ^. r iee,,,L 6,5? csj, f -4- • 6/20/2012 Page 10 of 10 g0 gg i --" (351' FSL, 285' FWL, Sec 27, T8N, R9W, S 1 / i Top of Production Horizon 301' FNL, 282' FES;Sec 33, T8N, R9W, S A028399 // A028406 SO08N009W / / / / / / /// / SHL 855' FNL, 738' FEL, Sec 33, T8N, R9W, S m Legend Surface Location Top of Production Horizon • Bottom Hole Location _____ Well Track 0 500 1,000 Swanson River Unit Feet SRU 14B-27 N Alaska State Plane Zone 4,NAD27 llileorp Alaska,LLC May 3,2012 / ,/ •SRU 12-27 KGSrSR KGSRU 212-27 SRU 212-27 KGSF7 a G_ KGS SRU 223-28 ,JKGSF7P V SRl� 3-27 p gg SRU 314-27PB0, RU 314-27 ,,ZiA l� O SRU 34-28 ISRU 314-27PB1 Pif.2‘I1" A028406 351'FSL,]85'FWL,Sec 27,T8N,R9W,S BHL A028399 e� / e e Top of Produptirn Horizon 301'FNL,282'FEL{Sec 33,T8N,R9W,S S008N009W // / SRU 21-33WD / SRU 21-34 e SHL SG"' 855'FNL,738'FEL,Sec 33,T8N,R9W,S 9.3_1A-321 -----j 0 SRU 32A-33 00 0SCU 343-33 Legend SCU 13-34 Surface Location A028990 /0 -.. Top of Production Horizon S:,U;3r , T6 \) • Bottom Hole Location SCU 33-33 ---- Well Track Y 0 975 1,950 Swanson River Unit Feet SRU 14B-27 Alaska State Plane Zone 4,NAD27 N Hilcorp Alaska,LLC May 3,2012 USchoenberger Hilo SRU 14B-27(P1)Proposal Report (Non-De(Plan) Report Dale AMY 02.2012-0200FIN Survey/DLS Computation Minimum Curvature/LUEnsla Client Unocal Vertical Sect.n Azimuth 0000'(True North) Fold Svnnson River UM Vertical Sectwn Origin 0 000 R 00008 Stncturel Slot Swanson ROM)SRU 140-27 TVD Reference Datum RKB Wall SRU 14627 TVD Reference Elevation 179000 R shave MSL Borehole SRU 14627 Seabed)Ground Elevation 170000 R above MSL UWIIAP0 Unknown I Unknown Magnetic Declination 17792' Survey Name SRU 14627(71) Total Field Strength 55566 532 nT Survey Date March 282012 Magnetic Csp Angle 73714' Tort/AHD/DDI I ERD Rano 29992116219231)4702)0141 Declination Date March 26,2012 Coordinate Reference System NAD27 Alaska State Plane,Zona 04,US Feet Magnetic Declination Model BGGM 2011 Location Lal l Long N 80'44'45 600455 W 150'51'20 52063' North Reference True No. Location Ond NIB Y/A N 2165597 400 RUS,E 346699 000(U5 Ond Convergence Used 0 000' CRS Ond Convergence Angle -074657911' Total Corr Mag North+True North 17792' Odd Scale Factor 0 99992667 Local Coord R ed To Well Head MD Inc! Assn True TVD55 TVD VSEL NS EW TF MS Directional Zone ectional Exclusion Zone Northing Easing Comrmnls (R) 11 (9 (R) (R (6)) (6) (al 7) ('/1092 05 )00050bides Alert Angle (,I (ftUS) (RUS) RTE 000 000 4196 -17900 000 000 000 000 41691 14/0 000 1629 2465559740 34669900 Marker MudLZre 900 000 4116 -17000 900 000 000 000 419900 000 000 1629 2065517400 34919900 KOP Bid 1/100 775000 000 41% 757100 775000 000 000 000 4169,1 000 000 1629 246559740 34686900 7800 00 050 41 96 7621 00 7600 00 016 016 015 41 96M 1 00 000 1513 2465557 56 34669915 790000 1 50 41 96 772096 769998 146 1 46 1 31 41 96M 1 00 047 1453 146556664 34690033 042/100 795000 2CO 4196 777096 794996 260 260 233 41960 100 064 1446 246559996 31660137 8000 00 300 41 96 7620 91 7999 91 422 4 22 379 41 96M 2 00 1 23 1360 2465601 57 346912 85 810000 500 4196 7920% 609966 940 540 646 HS 200 180 1196 246560665 31691751 620000 700 4196 602011 619911 1716 1716 1544 HS 200 221 1030 246561437 34691467 8183/100 625000 800 4196 806966 824866 2203 2203 1961 HS 200 237 955 246561917 34691609 830000 950 4199 611910 629610 2766 2766 2489 HS 300 255 553 246562476 34692425 6400 CO 1250 41 96 1217 25 8396 25 41 87 41 67 37 65 H5 3 00 285 7 02 2465635 78 3/693719 650000 1550 4196 131427 649327 5666 5966 5382 HS 300 310 662 246565655 34695359 6600 CO 1850 41 96 640969 6565 69 81 00 61 60 73 37 HS 303 3 31 749 2469676 03 346973 42 6700 00 2150 41 96 60365 6662 65 107 03 10703 96 23 05 3 00 349 930 246570016 3469%61 1600 CO 24 50 41 96 6595 89 9774 69 13609 13609 122 35 HS 3 00 3 6 11 90 2465731/7 34702310 600 CO 2750 41 56 6865 76 656176 1616 16166 151 65 HS 3 00 3 80 1417 246764 06 347052 63 End Bld 8963 07 29 99 41 96 8756 55 6037 55 190 39 19135 17636 HS 300 3 91 16 41 2465793 43 34707592 TO 11692 26 29 99 41 96 11105 00 11264 00 1205 51 120551 106 77 000 470 16 41 2466788 60 31759130 Survey Error Model Nam RelO"'3-D95000%Confidence 27955 MMgn,. Survey Program Description MD From MD To EOU Freq Survey Tool Type Borehole/Survey 1R) IRI (51 0000 9000 1/100000 ZERO SRL)14B-27/SRU 14B-27(P1) 6000 11692265 1/100000 ZERO SRU 14627/SRU 149-27(1.1) V Drilling Office 2 5 1100 0 Swanson River Unrt\Swanson River\SRU 14B-27\SRU 14B-27\SRU 14B-27(P1) 6/20/2012 12:44 PM Page 1 of 1 Ulf Schlumberger Hilo WELL FIELD STRUCNRE SRU 14B-27 (P1) Swanson River Unit Swanson River Magnelk Parameters Surface Location N41227Elasaa Stale Plane.Zone 04.U5 Feel Mscellaneous — Model BGGM 2011 Op 7571, Dale: March 20 2012 Lat N 60 4445 60024597.00 NS Grid Conv'.-0.74657911' Slot. SRU 102137 NO Ref. 1.0(1.1.0(1.above MSLI Mag Dec. 17.792' FS'. 5556e 5, Lon'. W 150 51 20.521 Easting96524650900flUS Scale Fact 099992667 Plan: SRU 10B-27(PI) Srvy Date:March 26,2012 0 1400 0 RTE 0 1400 1400 2800 2800 4200 4200 0 0 v ii 5600 5600 a) CO U co a 7000 7000 KOP Bid 1/100 Bld 2/100 8400 Bid 3/100 8400 End Bid 9800 9800 11200 11200 R13140-27(P1) SRU 14B-27 BHL 0 1400 Vertical Section(ft)Azim=0°Scale=1:1400(ft) Origin=0 N/-S,0 El-V StiliIumberger NE" FIELD STRUCTURE SRU 14B-27(P1) Swanson River Unit Swanson River 2011Mara.Eirmews Sukce Lo.on .027Ale.SIMe Awe.Zone 04 US Feet Fader.. Dp 73 71e X 80 1,15 BOOGM Cow-a .oy� 11 AS ,, 3n1 .,501,p511 9 1 m.Us �..do , Ar SRU 1862 oel.Rm./I202 0 250 500 750 1000 1250 1250 SRU 108-21 BHL SRU 1/627(P1) 1000 1000 A A A 750 750 O N II O1 IB 3, 500 500 1n / 250 • 250 81d 3/100 Bld 2/100 End Bld NOP Bld 1/100 • •0 0 e 0 0 250 500 750 1000 <« W Scale=1:250(ft) E »> Swanson River Unit Well SRU 14B-27 Planned Planned WBD 11ilcarp Alaska,LLC 164'AboveMSL Casing & Tubing KB-THF:20' Size Type Wt Grade Conn. ID Top Btm I 1 ' , 16" Conductor - - - Surf 80' 16" Q ,� L �C 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.875" Surf 3,000' 2 29.7 L-80 LTC 6.75" Surf 9000' �171 it4,.: ft 1� 7-5/8" Intermediate P-110 t 29.7 HC LTC 6.75" 9,000' 10,000' i 3t' 4"a 5-1/2" Prod Lnr 20 L-80 STL 4.653" 9,800' 11,692' 10-3/4QQ ' , r 30,0 Tubing 4 3-1/2" Production 9.2 L-80 IBT IBT 2.441 Surf 9,800' ILOK i. 51041) r i Q ' 'VdCyry t3` JEWELRY DETAIL 4, No. Depth ID OD Item 6 x; iot1 20' 2.44" - Tubing Hanger � 2 1,300' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port 7 3 2,400' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port I 4 3,500' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port 5 4,600' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port 8 i H r 6 5,200' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port "� 7 6,200' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port '1 9 8 6,900' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port ‘"'. 10 11I «, 9 7,900' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port ke: ' F*; i I I I 10 9,760' 2.000" 6.5" On/Off Tool w/X Nipple = i= , 11 9,780' 1.978" 4.140" Arrowset Mechanical Packer 11 MI + 12 9,800' - - WL Entry Guide w/X Nipple 7-5/8\. 12 / i ce 1 5-1/2 ,4 J TD=11,692/TVD=11,284' SRU 14B-27 Proposed Well Schematic 6-20-2012 Updated by LEK 6/26/2012 Well Name: 14B-27 Field: Swanson River Completion: Proposed Hilcorp Conductor:16",112# Surface Location: Swanson River 164'Above MSL • X:346899.0 Y:2465597.4 I 7 L Surface Hole: J 13-1/2"Hole,9.2 ppg WBM ,P" 10-3/4",45.5#ppf,L-80,BTC to 3000' ,A5J` Cmt to surface. ,a, r''' W S(I ANTICIPATED FORMATION TOPS&GEOHAZARDS TOP NAME FORMATION FLUID TVD(FT) TVDSS(FT) Est.Pressure PPG Gas Sand Shallow gas sand gas/wet 446 -267 Normal 8.5 Intermediate Hole: B-6 Lower Sterling wet 3219 -3,040 Normal 8.5 9-7/8"hole,10.5-13.5 ppg WBM LBGT Top Lower Beluga wet 4284 -4,105 Normal 8.5 D1 CT 25'Tyonek Coal wet/gas 5689 -5,510 Normal 8.5 9,000',29.7 ppf,L-80,LTC to 64-5 Gas Storage Sand GAS 6430 -6,252 1200-3300 psi 3.59 9,000'MD/8950'ND' g Lower Tyonek WATER 9109 -8,930 5200-5500 psi 11.61 d 7-5/8",29.7 ppf, P-110 HC,LTC from G2 Tyonek Oil OIL/WATER 10529 -10,350 2800-3000 psi 5.11 9,000'MD/8950'TVDto 10,000' MD/981 T TVD HKT Top Hemlock Oil OIUGAS 10616 -10,437 2800-3000 psi 5.07 , , H2-5 Hemlock Oil OIUGAS 10639 -10,460 2800-3000 psi 5.06 Cmt to 4500' H7-8 Hemlock Oil OIUGAS 10804 -10,625 2800-3000 psi 4.98 L H10 Hemlock Oil OIL/GAS 10909 -10,730 2800-3000 psi 4.94 TD Lower Hemlock 11284 -11,105 Production Hole: 6-3/4"hole,9.5 ppg WBM ' 5-1/2",20 ppf,L-80,STL to 11,692' e MD/ 11,284'TVD Cmt to TOL' i lk PBTD=11,600'MD TD=11,692'MD/11,284'TVD 14B-27 AFE(5.5in liner) May 2,2012 Drawn by:LEK \ §b; . §mw 0 _ _ u- 0 ` \\-} 0 0 ai { \)N \ \ \ �jp oi 22; w § § 0`' > S 0_0WOI 0CO o , - w o5 CC i } \}\/f co 0 )E g , Si& & E 112 !(To §k; 0 b)Nr ^ )( 0 26 |! R§§G c co ,z § =wwo 2 w , _ H 010 0 /\ & 4 01/\ } 57 , N §* o c ai k � e °o0- 0 NI co 2 E ) §� , ƒ« e co ® C $ •u 0 ƒ\ & 0 - - !° 0 0 e \; 12 43 / „ \RI §2 ` CO iii [II II E-Qc9 , 2 2) \ <4 2 2 w0 2 0 0 o }\ • 00 §§ ` k2 U ~ N ~ f [ - -• Li)Lo )° ° o CA ° , ii 71 \3 00 0100, (]7 ))\ \\ ,,, N C co To el -- 300oog - \ _/ 1 m, t2 (777{}\f) 2 k (\ " \\{ 0 t - - - u Zac-cCOOwO § k en \F � � �� -- 0 , n « 0 Maximum Anticipated Surface Pressure Calculation Swanson River Unit 14 B-27 Hilcorp Kenai Peninsula, Alaska 9-7/8" Hole Section Assumptions: 1. Frac gradient at 10-3/4" shoe (3000'TVD) estimated at.830 psi/ft based on field test data. 2. Pore pressure at Gas Storage sand estimated at 3300 psi (.513 psi/ft) 3. Pore pressure at Lower Tyonek water flow estimated at 5500 psi (.604 psi/ft) Fracture Pressure at 10-3/4" shoe considering a full column of gas from shoe to surface: 3000(ft) x 0.83(psi/ft)= 2490 psi 2490(psi)- [0.1(psi/ft)*3000(ft)]= 2190 psi / MASP from pore pressure(Gas storage sand at 6430'TVD) Max pore pressure at 6430'TVD: MASP (Wellbore evacuated to gas) 6430(ft) x 0.513(psi/ft)= 3299 psi 3299(psi) - [0.1(psi/ft)*6430(ft)]= 2656 psi \` MASP from pore pressure(Lower Tyonek Water Flow at 9109'TVD) Max pore pressure at 9109'TVD: MASP (Wellbore evacuated to water) 9109(ft)x 0.604(psi/ft)= 5500 psi 5500(psi)- [0.4316(psi/ft)*9109(ft)]= 1568 psi Summary: MASP while drilling 9-7/8" hole is limited by fracture pressure at the 10-3/4" shoe Maximum Anticipated Surface Pressure Calculation Swanson River Unit 14 B-27 H lco2r Kenai Peninsula,Alaska 6-3/4" Hole Section Offset Information Well Date Hemlock Pressure TVD Grad SRU 21A-34 2009 2975 10683 0.2785 SRU 32A-33 2010 2800 10637 0.2632 SRU 331-27 March, 2012 3140 10600 0.296 Assumptions: 1. Fracture gradient at 9,817' is estimated at 0.728 psi/ft based on field test data. 2. Based on offset drilling&well test data, Hemlock pore pressure is anticipated at 3100-3500 psi. 3. Reservoir fluid gradient is anticipated at 7.7 ppg. 4. Pressure gradient at 11,284' is calculated as:3140 psi+(684')*(.052)*(7.7) =3413 psi =0.303 psi/ft Fracture Pressure at 7-5/8" shoe considering a full column of gas from shoe to surface: 9817(ft)x 0.728(psi/ft)= 7147 psi 7147(psi)- [0.1(psi/ft)*9817(ft)]= 6166 psi MASP from pore pressure Max pore pressure at TD(11,284'TVD) MASP(Wellbore evacuated to gas column) 11,284(ft)x 0.303(psi/ft)= 3413 psi SIBHP-gas gradient to surface: 3413(psi)- [0.1(psi/ft)*11284(ft)]= 2285 psi Summary: 1. MASP while drilling 6-3/4" production hole is governed by SIBHP-gas gradient to surface. 2. MASP during production life is governed by SIBHP-gas gradient to surface. 111 Swanson River SRU 14B-27 a ,.p u«I.,i.ia. 06/18/2012 n J tili Ill lit it al Ill Aiiiiii • Hydril 111 Doyon Drilling GK 11"-5000 11"5M Hydril V BOP lit lil iii aid! Hydril V 11"-5 Nit A r4-« 11.85' '' !tl lil ifl I11 lil � k • i �i: 1 irlt >t►Pf LtI� .1 1 lit 111 tit ���� t it v - V - c - 11"-5000 — V Grade Level Itl Iil III 11!I If! Spacer spool 1 g5' 11 5M X 11 5M lil 111 lit lil lil Seaboard-MBS system �R segr 16'b3MX115M � �1 r.-, ip 1 DI-!lila lit = al I 110:: .. . ii 11 fBtTP_, "10 i, • LEDGEND 7 A K/TA JV0 White Handle Valves Normally Open 01111 Red Handle Valves rNormally Closed TO F P RS r ,_.........., 04 - M BOP STACK 4 , - 1 -r * 9 igt FARE i- ) , 2i P v TO PITS - —• B ;, TO DEGASSER MATERIAL LIST �. � ��er Item Description A 3-1116"10M Remote Operated Hydraulic Choice B 3-1/8"5M Adjustable Choke •. 1 2-1/16"5M Manual Gate Valve �,74'.111, 2-14 3-1/8"5M Manual Gate Valve 3 14B-27 Days Vs Depth 0 2000 4000 6000 0. al a) In a) i 8000 10000 12000 14000 0 5 10 15 20 25 30 35 40 Days Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Note that the terms used in the procedures and the spreadsheet of FIT/LOT results are defined as follows: • Formation Integrity Test (FIT) - Formation is tested to a pre-determined equivalent mud weight. • Leak-Off Test (LOT) - Pressure is exerted against the formation until fluid begins to discernibly pump away. Pressure at which this first occurs is the leak-off point. • LOT Limit - 16.0 ppg EMW for all surface casing shoe tests; determined from previous experience with formation breakdown problems by attempting higher leak-offs. • Open Hole LOTs (OH LOTs)- Leak-off tests performed with open hole from the casing shoe to some point above the target reservoir. Generally done when leak-off is required but could not be achieved just below the casing shoe; or where weaker formations are suspected above the target reservoir but below the casing shoe, and assurance is required of being able to achieve estimated mud weight. Procedure for FIT: 1. Drill 20' of new hole below the casing shoe. 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drillpipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. fit Swanson River SRU 14B-27 06/18/2012 I I.1,.•,�.l l.,-I 1 1 1 SRU 14B-27 Diverter Schematic For 13-Y2"Hole Section lit Iii I I III III III 21-W 2M itt i f f l Knife Gate U 1111.!1 iiI.II S N1 Diverter Tee,21-'/"x 21-'/<"x 2M w/12"ANSI 150 outlet III III iii rir • 16'/4"3Mx21-'/<"2M DSA I 111 t ri- or Seaboard 16-%"3M Casing head Assy r5 16„ HIL2ORP ALASKA, LLC SWANSON RIVER HO-28489D m a 1.1101 8.11.1 • 0 3-1/8 5M fo_ I® O .r ill® 3-1/8 5MIlli070 3-1/8 5M 'IW� .,. u.,.• III 04 3-1/8 5M — 0 .••1.1 u1•'. ADAPTER, SM—E-2CLN 1■1 41 14 1■1 11 5M X 3-1/8 5M TUBING HANGER, SM—E-2CL R 11 5M 11 X 3-1/2 API MOD BOX BTM ,,i .7 '- H ;R ;,_ X 3-1/2 EU 8RD BOX TOP - 1�1 It- foi1.1 = O Will ill 4 mig. li I°_..4 .71; il'a"I CASING HANGER, SMB-22 Elt 1 5 11 X 7-5/8 IC1 111 2-1/16 5M W/SEAL ASSEMBLY � 1 illiO R I BM MI[ail te.szil 12.11.1 10-3/4 IPS ,� 2-1/16 5M iliMil j _16-3/4 3M CASING HANGER, SMB-22—- + -. 16-3/4 X 10-3/4 HSI II HIM O W/PRIMARY SEAL e� :� Mil um ovio it..11-1 '� 1 2-1/16 5M 16 CASING 10-3/4 CASING 7-5/8 CASING- -- 3-1/2 TUBING SEABOARD 5,000 PSI WELLHEAD & TREE ASSEMBLY 16 X 10-3/4 X 7-5/8 X 3-1/2 RESTRICTED CONFIDENTIAL DOCUMENT oRRN ... N DE DRAWN AND ALL NFa.uaRN WAIN HEREON APE 11E a RT 1-12 1E18APR12 REV MUSIC PROPERTY OF SEAWARD NIERNA110NAL NC AND ARE NT�T NO Deaf JWGUE RATIE MEW GRAN T WEN 9T.A CEO= ]�p�... DRAWING N0. NOT M REPRODUCE lEi ITARNO,S RERAN R UPON REOUESF,AND THEKON RLL RE NADE TO A 11.D PARTY WT)OJT PRIOR ROTTEN OPENED P-14873 CONSENT OF SEABOARD NTE.u,ONAL NC. BT: Surface Use Plan Swanson River Unit Well SRU 14B-27 Surface Location Anticipated: 970' FNL, 516' FWL, Sec 33,T9N, R13W, S Existing Road: The proposed SRU 14B-27 is within the unit boundaries of the Swanson River Field. The roads in the field are suitable for transportation of the drilling rig and support equipment. The road leading into Swanson Field is within the boundaries of the Kenai National Wildlife Refuge and is also suitable for rig transport. Sterling, Alaska is the nearest town to the site and is approximately 25 miles south of the well site. A map showing the location of the proposed well site and access route to the site is included in Attachment 1. New or Constructed Access Roads: There will be no new roads or road upgrades required for the drilling of this well. Location of Existing Wells: SRU 14B-27 will be drilled from the existing well pad 41-33. SRU 41-33 well was P&A'd in 2008. A map showing all known wells within a one-mile radius of the proposed SRU 14B-27 is included in Attachment B. Location of Existing and/or Proposed Production Facilities: New well 14B-27 will be connected to existing production facilities. An existing flowline will be hydrotested and tied into the new well. A gas lift line and heater will also be installed. A separate sundry notice for surface disturbance will be submitted at a later date if needed. Location and Types of Water Supply: Existing water sources in Swanson River Field will be utilized. Available sources include permitted water wells at 14-22 and TS 1-33. All water use will be tracked in compliance with applicable permits. Water will be transported via vacuum truck from water wells to the rig location. Construction Materials: No road upgrades will be needed to allow for rig access. Stockpiled clean gravel picked up from roads within Swanson River Field will be used to level the pad if needed. Methods for Handling Waste: Drilling muds and cuttings: Excess mud and cuttings will be hauled from the rig pit system or storage tanks to off-site contractor Emerald for disposal. A - temporary waste storage permit will be obtained for any interim drilling fluid storage at Swanson. Brines & Completion Fluids: Eligible fluids will be hauled to a permitted Class II disposal well in Swanson River Field for disposal. Garbage: All household and approved industrial garbage will be segregated and transported to the Kenai Borough Central Peninsula Landfill for disposal. Chemicals: Unused chemicals will be returned to vendors or utilized in future operations. Sewage: All sanitary waste will be contained on-site and hauled off-site by a designated contractor. Ancillary Facilities: A trailer will be staged on the pad to house various supervisory personnel and a minimum number of support personnel. The remainder of the drilling crew will be housed at a temporary camp staged at nearby pad 221-27. Well Site Layout: Attached Figure 3 shows the existing pad, the access road to the location and the proposed well location. There will be no reserve pit on location. A plan view layout of the Doyon Arctic Fox is provided in Figure 4. Plans for Surface Reclamation: No surface disturbances are required for drilling this well. Access will be on existing roads within Swanson River Field, and the well will be drilled from an existing pad. No pad expansion will be required. Approval for final abandonment of the well and location will be obtained from the BLM and U.S. Fish and Wildlife Service prior to any reclamation work. Surface Ownership: The surface lands of the Swanson River Field and the roads leading into the field are within the Kenai National Wildlife Refuge, and are managed by the U.S. Fish and Wildlife Service. Other Information: The Doyon Arctic Fox rig will be used to drill the well. A plan view layout of the rig is provided in Figure 4. c 5 _ f — 2 2 i 8 9 10 11 1st Ave SPU+<09 Pad eu34.10 Pad R SPU 3+1+5 SRU 21I15 Pad I,"15 Paa 1 1 T\ SRU 32,Pad-1, -- .r 17 17 1U 15 1 I 13 VSRU 2l-15 Pad SHU 43 15 Pad9 SRU 34 16 Pad SRU 31333 SRU 3333 Pad SR 3Pad S108NO1OW S008N009W G1 Pad Pady 22 u 23 24 Ic 20 1st Ave SRU 1422 Paan SR..27 Paa n 7 SRU 28 Pad sau 2z3:s Pae ..,../.. .'— '''' 41 SRU 2127 Pad Via SRL/1332 Pad BRU 32-]2 Pad 7` 30 29 Zia SRU 43 28Pad 27 26 25 5RU 34-20 Pad S jj. F U31]I Pad `�Jl1 rJ/r F �ISRLI 14R-'_71 ��t��, S�! s. l PCI SRU 2133 Pad /'..... ` '+nPad J� •-•\ i tee SRU 3233 Pad...Ilk5RU 12NPed 51 32 33 34 ' 36 SRU 33Padsoi SCU 3333 Pad 1st 15cuo33 SCU 1,1 34 Pad SCU 3433 Pad ks scu aloe Pad scull on Pad 1. SCU 21,3 Pad SCU 3zos 2nd Ave ap FI u1203 Pae Pad,, 5de12.04Pad- 5C 1 fi 5 Pad 4 scu2ga4Pa5 3 SCU 2.3 Pad i I ,� CU 4304 Pad U I]03 a �y 243 04 Pad `� 6 atl sCU 14 Ol Pad scu SCU ed I 14. Patl Oa P. 2108 Paal UI+-oe B3IU]1,09 Petl SCU 4+09 Pad $71 S007N009WSCU 32daa\ SCU31209Pad SCU 3209Pad 43 08P ^ .Oa Pad 0 8 SW zl3ue Pad c as nos Pad tst Ave I i 12 9 A St PCU 14.09 Pad SW Pad Pad 4i0SW3408 4i0scU I 'T' Sc Pae '"vCU z1-16 Pad 18 '7 U,i,6 16 til Map Scale 1:32,000 N Swanson River Field N FI ure 1 0 Alaska State Plane 4 NAD1927 A2 9 Biker,,Wka,I IA: Miles - rr.FS,--40.- ,:' '-9*.: g-fftritli.-yr.Prif „cp7,415.g-'77,..ie;.0-,--`,:,' '..".'"'''','"-':"--''.'''' • 0 J '...i'.U" '„-,.",'- ': ...-' , ''' '- ' '-' , '"' .','.--,i.-.;- • :." .-';''''': . "t-'''.• ,--' --,' ,i,;,,,,,4 ,„,, . :, •, -,",.. :.- = i -„,i,-.. ---- ': -'74,' , , , 4 ,.. , r,r.."'•'„.."..k,,,',',"=„ ."."',-,.4", - "„ 4..'"4 ,f ,.„7,i,,, -", -. '" - /,•;--,"A: ri' 2-. .., i--',""'"%,"..:, 71-,0 ' --""'•"''' " ' gl7f7174",C-Frrr 12-TS rtir mr.-0.770",' "'"' '5''' '' Frtf P717 fM.-7.7Prrt ..4,-,... cm F•41,--;,771 ---• -..„,....-....--,-,,,, ....,,---",4,,„ err,C7,-prk ';.7.-*'•'-'-:.,...--;--:7: -7 , , P'tif i"-f4rircrf SRU 223-28 Pad '::::, -,- ''' 's'Ru 2'' 2''' . ' l'•"-'''` ' ' P'Sr 74:,-C-ri Mr€5.4,-F47 Mr'41-F71762f hot41,..17 g11-107•711 7' . crir r74. 2." '8t8 gr.ik*7 fro- a. , . SRU 43-28 Pad ,.. _.. ' ' P&S YARD - ',4 :-...,, s, , _n,..„ :.!..-',:i• SRU 34-28 Pad -...", ' ,. SRU 14B-27 ' ' " "' ,,;., Pro ii osed Well rtr r orz,i-fr," /-1.-,v4•Fetf mt.: ,, . • , ' Picm.=ric" ',17 - -..., .. ....—...„, —.... ,,-::.*v.. 67e.„- : . c'xr,•zrz,vzrw , - • ,... 6-•••:,_, --„..•, - - •'' rIzrr W-PA- -.mt.-•', a,' a' ";,.-rs a "L . ..:r '.--"i't F117 7.1.7.rn!- . .-', 2t,.- .ti = : ' - 'lk`' ' ' • „. i,.., $77; i. rn-,•F.2-7,Y,m7 Fvr.,-,(,•,r PC41;',74,47';PO •-:"-- ' 4J,„ 2-04 Pad .. , - - - SCU 41-04• . 'F P.'47 SRF Field C-r ,. . „ "igo-44” Overview , . 'i."....': g--rAT IA rtf Project Area ?!‘4'''- ' '"1-- ' - ''.-:'' ' ' : '‘' t•-(4 ,tz-47:PF(1r t^,rt rre C--ef ir-r',4"Z Prrr c..... .11 .1•47ri Pre tr..-.,;£F1-6( ta, 4,,,„ rr.ri-:F., -(,ly",,c, CM:eiz-rivrZ. ,. a7ii.,l(P,(V., er,4.prgr,-ar inr: Mr rt:^V‘Perr , .c,:zr,z, cr.--4,;&-ir. q,p(ATP:•-fiClf- tf gyegr c/Af."Fri I-. ke-Ar:;‘,/:‘,./.•pert ' trr`r g,, .-.,: mr 11.-r.rz ri-r: - -, 27Z-64. .- ,.v., .-, rt',7,7 Re,-4`,P10 , tr„-av: Legend N Surface Wells SRU14B-27 - 1 inch= 1,250 feet A Proposed Well 0 SRU 14B-27 Proposed Location Figure 2 0 2,000 4000 One Mile Radius Buffer et it,reit:i., �4i y.-k �;.y� ��� b. $N A.� N4s v. 401 Z0 33 t53 t`t s "„ �a �'g'$ r. ,,,,,i4v...,,„:4f , OA .:t'' 5.4 :tc f 9ffi < r.„ .n v t ..'fir i. " . :' d,Uw �^ '•,-,-,„a0„,p ,,- 7. `--/,".”,," ar.. A. 1 1-.,,,,jmt: i+i ,,,,!"„,.7 ,,,,, ' � <' � *.Pee SRI 1411-27 ,*4. s.RU 4 Proposed Well Location = "' ' ' > SRU 41-33 ',1 GZ1�1 -G1-S1 _ -33Pad \ 7O b 1�'` 5- o A � :. s4_ i/ f. - +fi 4ar 3.1 "° .& fit .'a 7'° II SRF Field - Y #-- . . °. Overview 1 ,K Project '.S " i �' * Area X700 ...„ , 3'. NKr r,. __. r x ,.,„..„, , . . tp,„ , , ,,,..t,ss , , 2 fir e r �.. �,. � a .. Legend SRU 14B-27-Proposed Well N + SRU 41-33 Well Pad 1 inch=50 feet A Surface Wells .,....,.,, Feet Map Date M182012 O SRU 14B-27 Proposed Location Figure 3 0 75 150 / 144'-1'[43.92m] - r TWO TANK MUD SYSTEM THREE SHAKERS,TWO MIX - - PUMPS,TWO MIX HOPPERS, DETROIT 60 SERIES n"' FOUR AGITATORS,DEGASSER, 400 kW 600 V GENS 10 CONE MUD CLEANER CHANGE 111..1 ROOM __ 1 ,-- I► I I ii111111 / r f'� �� ,._ ������ ;° WATER TANK III ^II , I M • " I I FUEL TANK 490 Barrels T '•'• •� I • f 6500 gal- l. � :.I �'1 �lil::i 11 -� 15' It \II% I I x;11_ . - l•,%1 1 I�11 I„°I • FUEL&WATERV. I]I=I '.71'�_ I 011111011 13 --.7; I III PT, 1° PUMP ROOM i .-. i LA} AT LARI�� ►M t .� f :, TANK rt ` ai 60Brtels OUT LUNCH ROOM AND .` 7 ! IIIIIIIi • �w=I Iimm TONG ROOM ON END •�J■ _=111W. I'I a `_—__—���„� '•� '�' ��� '� _ 111 Y� ,��111111 11 ry' I!II11 '__ '1i.1?II I1[1;. Ir'11, a .”` "'r Env nom. 111111 TWO 100 HP BOILERS BOP HANDLING \' , I TROLLEY I WORK BENCH,AIR COMPRESSORS VOYON °_!1111 �I II �111�1�r111111 AND PARTS STORAGE -- III'lll'[1'l Ill DRILLING = 180 gal STATION ACCUMULATORMEM11 I$ • RIGMASTER P-750 •IIBMO O6 ONE PIECE SUB w/ ,., ,,-„,,......,na '-.7n r.'''.,a,m o T TELESCOPIC DOUBLE THREE GARDNER DENVER PZ-8 E I MAST AND TSM-7000H MUD PUMPS POWERED ,n.mrwn,men wnnm.e m DRAW WORKS BY 3412 E CAT MOTORS, NOV CASING TEST PUMP `mkamNn°Iz°,o�pr'Ar property a Doyen. N. y',mit..in whole or pait noilhoon Me CUTTINGS PROCESSOR wnu.n wn,.m OrDOVOn� SKATE TYPE POWER •Kro ry u omaniva CATWALK WITH TWO ' ENCLOSED CASING A. NCB .a.SHEDS AND ONE r.°ate 1 101 7 ENCLOSED PIPE TUB. "F c”_ ° Co i r_° Anti..vrgea t 46 anal Arrengernent f... AIR HEATER Davies, Stephen F (DOA) From: Luke Keller[Ikeller@hilcorp.com] Sent: Tuesday, July 17, 2012 12:19 PM To: Davies, Stephen F (DOA) Subject: RE: SRU 14B-27 Steve, Sorry about the late reply to your question. H2S has not been detected/measured in any of the wells at Swanson River. Did you get the email about the spacing exception for M-31A? We tried sending it a couple times and it was kicked back as undeliverable for some reason. Thanks, Luke From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Tuesday, July 17, 2012 12:15 PM To: Luke Keller Subject: FW: SRU 14B-27 Luke, I don't believe that you ever answered the H2S-related question, below. I need the info to finish the permit to drill for SRU 14B-27. Thanks, Steve Davies AOGCC From: Davies, Stephen F (DOA) Sent: Thursday, June 28, 2012 7:11 PM To: 'Luke Keller' Subject: FW: SRU 14B-27 Luke, Never mind about sending the directional survey data this well,the planned trajectory isn't as complex as I first thought, so I just entered the data points into my workstation by typing them in. For the future though, could you please send me the directional data in spreadsheet format for each of Hilcorp's planned wells when you all submit each permit application? It will save me time when processing the application. Also, has H2S been measured in any of the wells within SRU? If so, please provide the measured values. Thanks, Steve Davies AOGCC From: Davies, Stephen F (DOA) Sent: Thursday, June 28, 2012 6:30 PM 1 To: 'Luke Keller' Subject: SRU 14B-27 Luke, Could you please send me the directional survey data for the proposed SRU 14B-27 well in spreadsheet format? Thanks, Steve Davies AOGCC 907-793-1224 2 Page 1 of 1 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Friday, July 13, 2012 9:22 AM To: 'Luke Keller' Cc: Davies, Stephen F (DOA) Subject: RE: SRU 14B-27 ( PTD 212-089) Luke, Another followup question... There is no mention of H2S in the permit. Is H2S present at all at SRU. It is a new field for me so not sure if there is any. Usually though if there is a waterflood present it means H2S is there too. Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Schwartz, Guy L(DOA) Sent: Friday, July 13, 2012 8:31 AM To: 'Luke Keller' Cc: Davies, Stephen F(DOA) Subject: SRU 146-27 ( PTD 212-089) Luke, Couple of comments on the PTD application: 1) Can you be sure to include a bit more detail on the procedure regarding changing out rams for casing runs. Also please indicate that there will be safety jts with proper X-overs and FOSV on floor. 2) What will be the initial BOP test ram configuration for the first BOP test? 3) I found a minor error in cement calcs.... The intermediate volume is over estimated by about 24 bbls (casing overlap volume). 4) Please provide a plot map showing the diverter line layout on the pad with rig in place. 5) Can't remember if this will be the first well for Arctic Fox or the Sidetrack on 23B-22 . I don't see the need for a 5000 psi BOP test past the first test. MASP is in the range of 2600 psi so a BOP test of 4000 psi is more reasonable after initial test. Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) 7/13/2012 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 LETTERCHECKLIST / WELL NAME -� C -/ e r 2_ PTD# 2-12_ �� 7 V Development Service Exploratory Stratigraphic Test Non-Conventional Well FIELD: C �ti-S ( 6" POOL: ����1�� � (� / 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 approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing 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. 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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. SRU 14B-27 SWANSON RIVER FIELD Kenai Borough, Alaska FINAL WELL REPORT MUDLOGGING DATA Provided by: Approved by: Kevin Eastham Compiled by: Larry Resch Josh Dubowski Britten Adams Distribution: 2/18/2013 T.D. Date: 01/14/2013 SRU 14B-27 1 TABLE OF CONTENTS 1 MUDLOGGING EQUIPMENT & CREW ................................................................................................ 2 1.1 Equipment Summary ...................................................................................................................... 2 1.2 Crew ................................................................................................................................................ 2 2 WELL DETAILS ..................................................................................................................................... 3 2.1 Well Summary ................................................................................................................................ 3 2.2 Hole Data ........................................................................................................................................ 3 2.3 Well Synopsis ................................................................................................................................. 3 2.4 Daily Activity Summary ................................................................................................................... 4 3 GEOLOGICAL DATA ............................................................................................................................. 8 3.1 Lithostratigraphy ............................................................................................................................. 8 3.2 Lithologic Details ............................................................................................................................. 9 3.3 Connection Gases ........................................................................................................................ 22 3.4 Trip (W10995iper) Gases ............................................................................................................. 22 3.5 Sampling Program / Sample Dispatch .......................................................................................... 23 4 DRILLING DATA .................................................................................................................................. 24 4.1 Directional Survey Data ................................................................................................................ 24 4.2 Bit Record ..................................................................................................................................... 29 4.3 Mud Record .................................................................................................................................. 30 5 DAILY REPORTS ................................................................................................................................ 33 6 SHOW REPORTS ............................................................................................................................... 34 Enclosures: 2” / 100’ Formation Log (MD/TVD) 5” / 100’ Formation Log (MD/TVD) 2” / 100’ Drilling Dynamics Log (MD/TVD) 2” / 100’ LWD Combo Log (MD/TVD) 2” / 100’ Gas Ratio Log (MD/TVD) Final Data CD SRU 14B-27 2 1 MUDLOGGING EQUIPMENT & CREW 1.1 Equipment Summary Parameter Equipment Type / Position Total Downtime Comments Ditch Gas (2) QGM agitators (mounted in mud trough) Flame ionization total gas and chromatography. 0 Block Height / Depth Totco WITS Feed 0 Hookload / Weight on Bit Totco WITS Feed 0 Mud Flow In Derived from pump rates and output 0 Return Flow Totco WITS Feed 0 Mudlogging Unit Computer System HP Compaq Intel Core 2 (x3: DML, RigWatch, and Sample Catcher) 0 Pit Volumes, Gain/Loss Totco WITS Feed 0 Pump Pressure Totco WITS Feed 0 Pump Strokes Totco WITS Feed 0 Rate of Penetration Derived from block height 0 RPM Totco WITS Feed 0 Torque Totco WITS Feed 0 TOTCO RigSense All Drilling Parameters Unk. TOTCO data signal lost repeatedly from surface to 10110 ft before issues were resolved. 1.2 Crew Unit Type : Steel Arctic Unit Number : ML030 Mudloggers Years *1 Days *2 Sample Catchers Years Days *2 Technician Days Larry Resch 13 35 Dickey Hudgins 2 28 Steve Forrest 1 Robert Athan 3 17 Trey Thrailkill 1 21 Travis Smith 1 Jessiah Johnson 1 20 Debra Bomar 2 13 Josh Dubowski 5 1/3 Britten Adams 2 1/15 *1 Years experience as Mudlogger *2 Days at wellsite between spud and total depth of well SRU 14B-27 3 2 WELL DETAILS 2.1 Well Summary Well: SRU 14B-27 API Index #: 50-133-20604-00-00 Field: Swanson River Field Surface Co-Ordinates: 758’ FNL, 635’ FEL Sec 33, T8N, R9W SM Borough: Kenai Borough Primary Target Depth: Tyonek G2 10663’MD Hemlock H10 11064’MD State: Alaska TD Depth: 11320’MD/ 11302’TVD Rig Name / Type: Arctic Fox/ Double Suspension Date: N/A Primary Target: Hemlock Formation License: ADL 212-089 Spud Date: December 5, 2012 Ground Elevation: 164.00 AMSL Completion Status: Run 5” liner RKB Elevation: 183.00 AMSL Classification: Development Secondary Target: Depth: Hemlock Top 10754’MD Hemlock H2-5 10781’MD TD Formation: Hemlock Formation TD Date: 01/14/2013 Days Drilling: 40 Days Testing: N/A 2.2 Hole Data Hole Section Maximum Depth TD Formation Mud Weight (ppg) Dev. (oinc) Casing/ Liner Shoe Depth FIT (ppg) MD (ft) TVDSS (ft) MD (ft) TVDSS (ft) 16” Conductor 80’ +103 Recent -- -- 16” Conductor 80 +103 n/a 13-1/2” 2970’ -2785 Sterling 9.5+ 22 10-3/4” 2960 -2775 13.5 9-7/8” 10110’ -9764 Tyonek 12.7 20.3 7-5/8” 10104 -9758 12.0 6-3/4” 11320 -11119 Lower Hemlock 9.8 19.24 5” 2.3 Well Synopsis SRU 14B-27 is the first grass roots well drilled by Hilcorp during this current 2012-2013 phase of field development. The objective is to drill a deviated well into the Hemlock formation, targeting the H1-5 sands. This well is a replacement for the mechanically failed SRU 41-33. Primary targets include the top of the Hemlock and the H2-5 sands. Secondary targets include Tyonek G2 and Hemlock H10 sands. Pressure in the Tyonek 64-5 Gas Storage Sand can be up to 3300 psi depending on the injection cycle. While drilling this sand no problems were encountered. The D1CT coal is the thickest, laterally extensive coal in the Swanson River Field. As expected, approximately 25 feet of this coal was encountered. Unexpected high pressure gas shows exceeding 2500 units were encountered in the Tyonek at 7345’ – 7378’MD/ 7340’ – 7373’TVD, 7617’ – 7702’MD/ 7588’ – 7651’TVD. To control this pressure mud weights were increased from 10.5 to 11.8 ppg, and 11.8 to 12.5 ppg respectively. SRU 14B-27 was drilled to a total depth of 11320’MD/ 11084’TVD safely and without problem. SRU 14B-27 4 2.4 Daily Activity Summary December 5, 2012 Pick up and rack back 24 joints of HWDP. clear and clean rig floor. calibrate block height. PJSM for making up BHA. M/U BHA. tag ice at 68. 5'. PJSM for drilling ahead. tag formation at 76'. continue to drill ahead from 76' to 385'. circulate and condition 3 bottoms up. pull out of hole to 40'. monitor well and service rig while waiting on diverter line decision. December 6, 2012 Continue to service rig while waiting on diverter line decision. PJSM for diverter line deflector. rig down diverter line deflector. PJSM for picking up BHA. pick up BHA. wash and ream from 297' to 328' and at 370' and 385'. drill ahead from 385' to 840'. December 7, 2012 Continue drilling ahead from 840' to 1518'. circulate bottoms up and monitor well - static. pull out of hole to 951'. monitor well - static. run in hole to 1454', wash to 1518'. circulate and condition mud. fix hydraulic leak. continue drilling from 1518' to 1835'. begin loading pipe shed with 10 3/4" casing. December 8, 2012 Continue to drill ahead from 1835' to 2296'. begin pulling out of hole for a wiper trip from 2296' to 1583'. run in hole from 1583' to 2296'. continue to drill ahead from 2296' to 2755'. December 9, 2012 Continue to drill ahead from 2755' to 2970'. circulate bottoms up. pump hi vis nutplug sweep. monitor well - static. wiper trip from 2970' to 297'. monitor well - static. run in hole to 2970'. circulate bottoms up. continue to drill ahead from 2970' to 2978'. td for surface hole called. circulate bottoms up. pull out of hole. lay down BHA. rig up to run 10 3/4" casing. December 10, 2012 Continue to rig up to run 10 3/4" casing. PJSM for running casing. run in hole with 10 3/4" casing to 2931'. clear floor of casing tools. PJSM for cement job. test lines to 3000 psi - good. pump cement. make up packoff running tool. set packoff. clean rig floor. move old BHA from pipe shed. December 11, 2012 Clean and clear rig floor. nipple down surface stack. nipple down diverter line. remove cement from flowline. continue to nipple down surface system. clean pits. remove diverter line from rig. rig up to nipple up annular. December 12, 2012 Continue to nipple up bop. change out rams. continue cleaning pit #1. rig up test equipment. PJSM for bop test. test annular 250 psi low, 2500 psi high. test all other rams and valves to 250 psi low, 4000 psi high - upper pipes leaking. retest upper rams. open upper ram doors, clean and dress rams. continue to test bops 250 low, 4000 high - spacer spool leaking. replace whitey valve, retest - good. continue testing bops and cleaning pits. December 13, 2012 Continue to test bops. bleed off pressure. nipple down test equipment. clean and clear floor. pick up BHA tools. make up clean out run BHA. run in hole with 5" HWDP from 69.5' to 878.66'. continue to run in hole from 878.66' to 2777'. wash down at 3 BPM, tag cement at 2837'. circulate and condition mud for casing test. rig up for casing test. casing test to 1500 psi - gland packing on multi bowl leaking. bleed off and tighten. retest - good. rig down test equipment. mix mud to 10.6 ppg 6% kcl. wash to 2837'. drill soft cement from 2837' to 2841'. tag hard cement at 2841'. continue to drill cement from 2841' to 2962'. SRU 14B-27 5 December 14, 2012 Continue to drill shoe track and 20' of new hole from 2962' to 3000'. PJSM for mud swap. swap spud mud. pull out of hole from 3000' to 2965'. rig up for fit test. perform fit test to 13.5 ppg EMW, 483 psi. rig down fit test equipment. run in hole from 2965' to 3000'. drill ahead from 3000' to 3044'. increase in flow - pick up flow check and pump bus, no gas observed. drill ahead from 3044' to 3215'. circulate bottoms up. pump dry job. pull out of hole. PJSM for making up BHA. make up new drilling BHA. shallow well test at 978'. pump psi erratic - shut off and clean suction screens. run in hole to 2960'. fill pipe. calibrate MWD block height. run in hole from 2960' to 3154'. clean suction screens on pumps. run in hole from 3154' to 3215'. drill ahead from 3215' to 3270'. December 15, 2012 Continue drilling ahead from 3270' to 4547'. monitor gas trap to prevent any buildup of cuttings. blowback heet into sample line to clear blockage. December 16, 2012 Continue drilling from 4547 to 5019'. wiper trip at 4790' to 2940'. wiper gas 68u. nutplug sweep at 4613'. December 17, 2012 Sample line froze and was monitored after. large gas quantities max gas = 1719u @ 5743'. drilling ahead from 5019' to 5994' December 18, 2012 Drilling ahead from 5994' to 6364', wiper trip at 6180' December 19, 2012 Continue drilling ahead from 6364' to 6953' December 20, 2012 Drilling ahead from 6953' to 7201', wiper trip at 7068', service top drive. December 21, 2012 Drill ahead from 7201' to 7378'. well controll issues at 7373' MD. shut in well. increase mud weight to 10.9, monitor pressure. shut in well. increase mud weight to 11.2 , monitor pressure. December 22, 2012 Close in hole at 7378' increase mud weight to 11.2, circulate and monitor pressure. drill ahead from 7378 to 7399, close in hole. max gas = 2093u. increase mud weight to 11.8, circulate and monitor pressure and gas. December 23, 2012 Continue drilling from 7386' to 7507' MD. shut well in at 7528', max gas 2184u, increase mud weight to 12, circulate and monitor pressure. December 24, 2012 Continued drilling from 7507' to 7700' MD. increased mw to 12.4 and monitored pressure. December 25, 2012 Drill ahead from 7707' to 7946' , increased mw to 12.5 in/out, monitor pressure December 26,2012 Drill f/7944 to 8064;circulate;short trip;trips RIH; wash/ream tight spot;well control December 27, 2012 Short trip t/6005;RIH/circ;started TOOH; backreamed to 3078' SRU 14B-27 6 December 28, 2012 TOOH. bit worn on bottom cutters and 1/16th out of gauge, and top stabilizer was halfway packed off with clay. R/U and tested bop;M/U BHA; tripping in.depth 2036' at 23:59. plan to slip/cut drill line at shoe, RIH and drill ahead. December 29, 2012 RIH to bottom; circulate and drill; drilled ahead to 8214' December 30, 2012 Drilling ahead to 8648 December 31, 2012 Drilling ahead January 1, 2013 Drilling ahead to 9486 January 2, 2013 Drilled ahead to 9879 January 3, 2013 Drilled ahead to 10,110' and td'd. CBU 2x and begin to TOOH, run back to bottom and CBU. January 4 2013 January 5, 2013 Continue POOH to 5000' and monitor (losing 1 BPH). POOH to 3470' and begin L/D 5" DP to 2966' and monitor. continue L/D 5" DP to 947.42'. POOH and rack back HWDP and L/D BHA. Continue monitoring hole (losing 1 BPH). R/U and run wireline. Finish running wireline and R/D wireline tools and rig up BHA for cleanout run. January 6, 2013 RIH with clean out BHA, picking up 5" DP out of shed until 3402'. Continue RIH out of derrick while limiting running speed to 1.5 min per stand. Circulate and condition mud and drop a carbide tracer. monitor well (losing 0.5 BPH). POOH to 6069' at report time. January 7, 2013 Finished POOH and L/D clean out BHA. P/U RTTS tool and RIH to isolate hole while changing and testing upper rams for casing. R/U casing equipment and running casing at report time. January 8, 2013 Finished RIH with 7-5/8" casing. landed at 10106'. R/D Casing equipment and R/U cementing equipment. Circulate and condition mud in preparation for cement job. pumping cement at report time. January 9, 2013 Finished pumping cement and rig down cementing equipment. L/D 5" DP then cut and slip drill line. CHanging rams from 5" to 4" at report time. January 10, 2013 Continue testing and troubleshooting BOP's SRU 14B-27 7 January 11, 2013 Finish testing BOP's. P/U 4" DP and RIH with 60 joints then rack them back. P?U BHA, RIH and shallow test (pass). Continue RIH on singles at report time. January 12, 2013 Finished RIH and tagged cement at 9829'. Displaced mud from 13.1ppg to 9.5ppg. Test casing (pass). Drill out cement and 20' of new hole. Perform FIT to 12.0 EMW (pass). Drilling ahead from 10463' at report time January 13, 2013 Drilled ahead to 11183' MD January 14, 2013 TD called at 11320' MD. CBU and monitor for flow. W ell flowing, increase MW to 11.4. Trip to the shoe and run back to bottom. CBU, pump dry job and begin Tripping out. January 15, 2013 Finished POOH and L/D BHA. R/U Wireline tools, RIH and log. R/D wireline tools and begin to P/U cleanout BHA. January 16, 2013 Continue RIH with cleanout BHA. CBU and POOH to casing shoe and monitor well (gain 1/2 BPH). Continue POOH and prep to run 5" liner. January 17, 2013 Finish running 5" liner, tag bottom at 11320'. P/U and M/U cement head . Circulate and condition mud and prep to cement. January 18, 2013 January 19, 2013 January 20, 2013 January 21, 2013 January 22, 2013 January 23, 2013 January 24, 2013 SRU 14B-27 8 3 GEOLOGICAL DATA 3.1 Lithostratigraphy Formation tops provided by Hilcorp geologist Kevin Eastham FORMATION PROGNOSED LWD PICK MD (ft) TVD (ft) SSTVD (ft) MD (ft) TVD (ft) SSTVD (ft) Shallow Gas Sand 446 446 -267 - - - Sterling B-6 3277 3276 -3098 3204 3202 -3019 LBGT 4289 4285 -4106 4278 4275 -4092 D1CT 5690 5682 -5503 5662 5660 -5477 Gas Storage Sand 6440 6428 -6249 6414 6412 -6229 TYNK HP H20 9224 9162 -8983 9226 9120 -8937 Tyonek G2 10663 10523 -10344 10740 10537 -10354 HKT 10754 10609 -10430 10812 10604 -10421 Hemlock H2-5 10781 10635 -10452 10829 10621 -10438 Hemlock H7-8 10950 10795 -10612 10996 10778 -10595 Hemlock 10 11064 10903 -10720 11107 10882 -10699 TD 11200 11031 -10852 11320 11302 -11119 SRU 14B-27 9 3.2 Lithologic Details Tuffaceous Claystone, Siltstone, Sand (2970’ – 3060’) = claystone is light gray to medium light gray; firm, often soft; moderate induration; pulverulent, crumbly in part; no definable fracture or cuttings habit; dull to subwaxy in part; generally smooth, non-gritty, nonabrasive; siltstone is generally medium light gray to light pale yellowish brown; firm to soft; crumbly; varies from tuffaceous to very arenaceous, with well entrained fine to lower medium, well rounded quartz and dark gray lithics; locally carbonaceous; occasionally grades towards an earthy coal; abundant loose sand varies from fine to lower medium, subrounded grains, to medium/ coarse angular conglomeratic sand; note locally abundant pebble fragments; trace poorly developed coal. Sand, Conglomeratic Sand (3060’ – 3120’) =loose sand; bimodal; fine grain; subrounded to subangular; discoidal to subdiscoidal; poor to moderate sorting; also upper fine to medium, occasionally lower coarse grain; angular to subangular; subprismoidal; moderate to poorly sorted; note locally common pebble fragments exhibiting high impact fracture, all quite sharp and angular with occasional well rounded surfaces; dominantly grayish white to milky white quartz, abundant feldspars; secondary lithics include dark gray to black, light red to reddish orange mafics; note abundant translucent and transparent volcanic glass clasts, occasional very fine, thin glass shards; trace mica poorly developed coal. Conglomeratic Sand (3120’ – 3210’) = 80% loose sand; lower medium, rarely upper medium grain; subprismoidal; moderate to well sorted; 20% well entrained in tuffaceous/ argillaceous matrix; quartz grain dominant with abundant volcanic glass clasts, common glass shards; dark gray lithics, reddish orange mafics common; trace carbonaceous material. Sand, Tuffaceous Claystone (3210’ – 3300’) = medium gray to medium dark gray; lower fine to lower medium with occasional coarse to very coarse; subdiscoidal to spherical; subrounded to rounded; moderately sorted; unconsolidated; texturally immature; compositionally immature; predominantly clear to white quartz grains; abundant dark lithics; trace light and dark green, orange and red lithics. Sand, Tuffaceous Sandstone (3300’ – 3360’) = medium dark gray to dark gray; upper fine to upper medium; subprismoidal to spherical; subangular to subrounded; moderately sorted; unconsolidated sand; soft to easily friable sandstone; matrix supported; tuffaceous matrix; texturally immature; compositionally immature; predominantly clear to white quartz grains; abundant dark and green lithics; trace red, orange and tan lithics. Tuffaceous Siltstone, Tuffaceous Claystone, Sand (3360’ – 3420’) = medium dark gray siltstone, dark greenish gray claystone; soft; poorly to moderately indurated; malleable to sectile tenacity; irregular fracture; massive cuttings habit; dull to earthy luster; silty to clayey texture; massive structure. Sand, Tuffaceous Siltstone (3420’ – 3510’) = medium dark gray to dark gray; lower fine to lower medium; subprismoidal to subdiscoidal; moderately rounded; moderately to well sorted; unconsolidated sand; soft siltstone; texturally immature; compositionally immature; majority quartz grains; abundant black and dark green lithics; trace orange, red, and pale green lithics. Tuffaceous Siltstone, Tuffaceous Claystone (3510’ – 3540’) = medium dark gray with medium bluish gray hues; soft; poorly to moderately indurated; malleable to sectile to crumbly tenacity; irregular fracture; massive cuttings habit; dull to earthy luster; silty to clayey texture; occasional thin black laminae structure; poor adhesiveness; poor to moderate cohesiveness. Tuffaceous Siltstone, Tuffaceous Claystone, Carbonaceous Shale (3540’ – 3600’) = medium gray to medium dark soft; moderately indurated; sectile tenacity; irregular fracture; massive to platy cuttings habit; dull to earthy luster; clayey to silty texture; massive structure with occasional thin black laminae. SRU 14B-27 10 Conglomeratic Sand, Sandstone (3600’ – 3660’) = 70% loose sand; medium dark gray; medium to lower coarse grain; angular to subrounded in part; subprismoidal, discoidal in part; moderate sorting; sandstone is very well cemented; noncalcareous; poor to trace visible porosity; quartz with medium dark gray to dark gray grains equally represented; feldspars common; clasts often well entrained in soft, firm tuffaceous clay; note locally abundant pebble fragments, varying from well rounded to sharp angular, all with high impact fractured surfaces. Tuffaceous Claystone, Siltstone (3660’ – 3750’) = very light gray to light bluish gray; very soft, occasionally firm; good cohesion; poor to fair adhesion; lumpy, curdy, pasty in part; malleable, pulverulent; no definable fracture or cuttings habit; generally dull; slightly sparkly in part with increased quartz sand, very fine volcanic glass shards; occasionally subwaxy when massive with increased ash content; loose sand and fine carbonaceous detritus often entrained/ recombined in very soft, pasty clay; noncalcareous. Tuffaceous Claystone, Siltstone (3750’ – 3840’) = light gray, medium light gray; light bluish gray in part; soft, rarely firm; good cohesion; fair to moderate adhesion; lumpy to mushy, pasty in part; malleable, often pulverulent, sectile; amorphous with no definable fracture, cuttings habit or indications of bedding; generally dull, slightly earthy; often gritty and slightly abrasive with varying amounts of extremely fine quartz; clays contain significant amounts of quartz and medium to dark gray clasts well entrained; randomly grain supported in places; note extremely fine volcanic glass shards in more ashy sediments. Conglomeratic Sand, Sand, Sandstone (3840’ – 3930’) = 70% loose sand, 20% sandstone; medium gray to light gray; medium grain, lower coarse grain common; angular to subangular; discoidal to subprismoidal; poor to fair sorting; consolidated sand is moderately hard; noncalcareous; tight; grain supported with trace of clay fill; quartz with medium and dark gray clasts equally represented; note coarse to lower very coarse sharp angular pebble fragments with high angle fracture, occasional well rounded subdiscoidal pebbles; tuffaceous claystone continues as previously described with abundant well entrained lithic clasts. Conglomeratic Sand, Conglomerate, Pebble Fragments (3930’ – 4050’) = 70% loose sand, 30% sand entrained in tuff/ ash; note samples taking on a light bluish gray to greenish gray appearance; clasts range from upper fine to upper coarse grain; angular to subangular, occasionally subrounded; poor to fair sorting at best; subprismoidal, prismoidal common, rare discoidal; intact rounded subprismoidal pebbles common with long axis up to 8mm;very sharp pebble fragments with high impact fracture larger than very coarse locally abundant; note occasional sandstone with light greenish gray appearance; upper fine angular quartz grains cemented with lower medium well rounded dark gray, greenish gray clasts; dominantly grain supported localized clay fill; friable to very hard; with biotite; tight, noncalcareous Sandstone, Conglomeratic Sand, Conglomerate (4050’ – 4140’) = 80% loose sand, 20% sandstone; light gray, light greenish gray to pale yellowish green; upper fine to lower coarse grain, often upper coarse and larger; angular to subangular, rarely subrounded; subprismoidal, discoidal; fair to moderate sorting in part; sandstone varies from friable to very hard; tight to trace visible porosity; trace to abundant clay fill; sand often suspended and well entrained in tuffaceous clay; noncalcareous; locally abundant very coarse sharp pebble fragments with high impact fracture; well rounded pebbles and pebble fragments up to 6mm. Conglomeratic Sand, Conglomerate (4140’ – 4260’) = 80% loose sand, 20%sand with tuffaceous clay; medium to lower coarse grain; subangular to subrounded, angular common; discoidal, occasionally subprismoidal; moderate sorting; occasionally poorly consolidated with and entrained in tuffaceous clay; noncalcareous; no visible porosity; dominantly light gray, translucent and transparent quartz; secondary feldspars, medium to dark gray lithics; both angular and subrounded volcanic glass clasts equally represented; note occasional upper fine translucent glass shards; up to 30% coarse to very coarse subrounded pebble fragments, often with high impact fracture surfaces; note subrounded, subprismoidal, intact pebbles exceeding 10mm on long axis; tuffaceous clays balled up in samples containing significant lithic clasts. SRU 14B-27 11 Conglomeratic Sand, Conglomerate (4260’ – 4350’) = 80% loose clasts, 20% entrained in tuffaceous clay; medium to lower coarse grain, occasionally fine grain; subangular to subrounded, often subangular to angular; fair sorting; discoidal, subprismoidal; curdy, mushy to pasty ash/ tuffaceous clays contain abundant subrounded to subangular lithic clasts and carbonaceous detritus well entrained; noncalcareous; clays are amorphous with no definable fracture, cuttings habit or indications of bedding/ structure; rounded pebble fragments and pebbles up to 6mm continue. Tuffaceous Claystone, Tuffaceous Siltstone (4350’ – 4410’) = medium dark gray to olive gray; soft; poorly indurated; malleable to sectile tenacity; irregular fracture; massive cuttings habit; dull to earthy luster; clayey to silty texture; massive structure; mushy to lumpy consistency; moderate adhesiveness; poor to moderate cohesiveness. Conglomeratic Sand, Conglomerate (4410’ – 4500’) = medium gray to medium dark gray; lower medium to upper coarse; prismoidal; angular to subangular dominant, some subrounded; poorly sorted; unconsolidated; texturally immature; compositionally immature; predominantly clear to white quartz and dark lithics; trace green lithics; pebbles up to 5mm; claystone brownish gray to olive gray; soft; poorly indurated; crumbly tenacity; irregular fracture; massive cuttings habit; dull to earthy luster; clayey texture; massive structure; mushy consistency; poor to moderate adhesiveness; poor to moderate cohesiveness. Tuffaceous Claystone, Conglomeratic Sand (4500’ – 4560’) = medium gray to medium dark gray with olive gray hues; soft; poorly to moderately indurated; malleable to sectile tenacity; irregular fracture; massive cuttings habit; dull to earthy luster; clayey to silty texture; massive structure; moderate to good adhesiveness; moderate cohesiveness; clotted to pasty consistency. Tuffaceous Siltstone, Sand (4560’ – 4650’) = light olive gray to light brownish gray; poorly indurated; malleable to sectile tenacity; irregular fracture; massive cuttings; dull to earthy luster; silty texture; massive structure; clotted to curdy consistency; moderate to good adhesiveness; moderate cohesiveness; note sandstone fragments; grain supported matrix; pale blue green to pale blue hue; quartz framework; fine grain size; well to very well sorted; noncalcareous. Tuffaceous Sandstone, Tuffaceous Siltstone (4650’ – 4710’) = light to medium gray to light olive gray sandstone; light olive gray to light brownish gray siltstone moderate induration; malleable to sectile tenacity; irregular fracture; massive structure; dull to earthy luster; curdy; moderate to good adhesiveness; moderate cohesiveness; rounded pebbles; loose sand recombined in soft siltstone. Tuffaceous Siltstone (4710’ – 4770’) = light gray to yellowish gray, generally with light brownish hues; soft, firm in part; moderate induration; sticky; malleable, pulverulent; no definable fracture; nodular cuttings habit; dull; generally gritty with varying amounts of fine quartz, dark gray to grayish black lithics, occasional carbonaceous detrital clasts; slightly ashy in part; noncalcareous; trace black to brownish black dead oil stain; no hydrocarbon indicators. Tuffaceous Siltstone, Sand (4770’ – 4860’) = medium dark gray with olive gray hues; soft to firm; poorly to moderately indurated; malleable to sectile tenacity; irregular fracture; nodular cuttings habit; dull to earthy luster; silty to clayey texture; massive structure with occasional thin black laminae; lower fine to lower medium sand pushed into siltstone; subprismoidal; subangular to subrounded; trace pebbles up to 7mm. Tuffaceous Siltstone, Tuffaceous Claystone (4860’ – 4950’) = olive gray siltstone, medium dark gray with medium bluish gray hues claystone; soft to firm; poorly to moderately indurated; malleable to crumbly tenacity; irregular fracture; massive to nodular cuttings habit; earthy to dull luster; clayey to silty texture; massive structure with thin black laminae and lens inclusions; moderate to good cohesiveness; moderate adhesiveness. SRU 14B-27 12 Tuffaceous Siltstone, Tuffaceous Claystone (4950’ – 4980’) = olive gray to light olive gray; soft; poorly to moderately indurated; crumbly tenacity; irregular fracture; massive cuttings habit; earthy to dull luster; silty to clayey texture; massive structure; trace hard black coal; brittle tenacity; splintery fracture; platy to elongated cuttings habit; vitreous to waxy luster; massive structure. Tuffaceous Siltstone, Tuffaceous Sandstone (4980’ – 5070’) = light olive gray to olive gray with light brownish gray hues; moderately indurated; malleable tenacity; irregular fracture; massive cuttings habit; earthy to dull; luster; silty to gritty texture; massive structure; moderate to good cohesiveness; trace hard coal; brittle tenacity; platy to elongated cuttings; waxy to vitreous luster; coal fragments recombined into soft siltstone. Tuffaceous Siltstone, Claystone (5070’ – 5130’) = olive gray to light olive gray with light brownish hues; moderately indurated; malleable to crumbly tenacity; irregular fracture; massive cuttings habit; earthy to dull luster silty to clayey texture; massive structure; moderate adhesiveness; poor to moderate cohesiveness; hard black coal inclusions; brittle tenacity; vitreous to waxy luster. Tuffaceous Siltstone, Sandstone, Sand (5130’ – 5220’) = light olive gray to olive gray; light brownish to brownish hues; moderately indurated; malleable to sectile tenacity; irregular fracture; massive cuttings habit; generally dull with slight earthy luster; silty to gritty texture; massive structure; moderate to poor cohesiveness; moderate adhesiveness; loose sand varies from light gray to medium light gray; subangular to subrounded; upper fine to medium grain, occasionally lower coarse grain; subprismoidal; moderate to poorly sorted; trace carbonaceous shale. Coal, Carbonaceous Shale (5220’ – 5250’) = moderately hard to hard; brittle to dense tenacity; splintery fracture; platy to elongated cuttings; vitreous to waxy luster; shale is moderate brown to grayish brown with black lithics. Tuffaceous Siltstone (5220’ – 5340’) = light pale yellowish brown to light olive gray, light gray to light bluish gray with slight brownish hues; firm; moderate induration; slightly crumbly in part, malleable to pulverulent; no definable fracture; nodular cuttings habit; dull to slightly sparkly, slightly subsucrosic in part; generally gritty, occasionally smooth; varies from very arenaceous to argillaceous; note coal = black; soft to slightly firm; poor to moderate development; subfissle to planar in part; platy cut- tings habit; dull to subwaxy in part; often shaly, occasionally earthy; no visible outgassing. Tuffaceous Siltstone (5340’ – 5430’) = light gray with slight yellowish brown hues, light olive gray; soft to very soft; poor to moderate induration; moderately cohesive; slightly to very adhesive in part; curdy, mushy to pasty, occasionally slimy; malleable, generally pulverulent; very clay to slightly ashy in part; often very arenaceous with abundant extremely fine well rounded translucent quartz grains; note abundant well entrained carbonaceous detrital clasts/ fragments; some very fine well rounded loose sand; locally abundant carbonaceous shale/ coal; no hydrocarbon indicators. Tuffaceous Sandstone, Sand (5430’ – 5520’) = note abundant loose sand; white to grayish white, very light gray with slight brownish hues; very fine to lower fine grain; subrounded to subangular, round in part; subdiscoidal; moderate sorting; poorly consolidated; noncalcareous; grain support and matrix supported equally represented; ashy to clayey matrix; slightly silty in part; dominantly grayish white to translucent quartz grains; note abundant round volcanic glass clasts, some appear facetted and terminal; trace very fine, thin glass shards; secondary dark gray to grayish black, very light gray, pale yellowish green lithics; no hydrocarbon indicators. Tuffaceous Siltstone (5520’ – 5610’) = light pale yellowish brown to very light brownish gray; soft; poor to moderate induration; malleable, pulverulent; no definable fracture or cuttings habit; dull, subsucrosic with increased extremely fine well rounded translucent quartz grains; generally gritty, occasionally smooth with increased clay and devitrified ash content; no apparent structure; noncalcareous; occasionally grades towards a matrix supported tuffaceous sandstone; note well indurated carbonaceous detrital clasts and fragments; note coal/ carbonaceous shale. SRU 14B-27 13 Tuffaceous Sandstone, Siltstone (5610’ – 5660’) = light pale yellowish brown to very light brownish gray; extremely fine to very fine grain; round to subround; subdiscoidal to discoidal; moderate to well sorted; friable to poorly consolidated; noncalcareous; abundant tuffaceous/ clay matrix; no visible porosity; varies from argillaceous sandstone to arenaceous claystone; trace carbonaceous shale/ coal detritus. Coal, Carbonaceous Shale (5660’ – 5700’)= black; firm; crunchy to crumbly in part; planar to slightly irregular fracture; platy to occasionally fissile; subvitreous to dull luster; shaly to slightly earthy in part; no visible outgassing. Sand (5700’ – 5760’) = loose sand; fine to upper very fine grain; round to subrounded; subdiscoidal; well to moderate sorting; often well entrained in clay as a very sandy claystone in part; dominantly grayish white, translucent and transparent quartz; abundant transparent volcanic glass clasts; 20% fine coal/ carbonaceous detritus; no hydrocarbon indicators. Tuffaceous Siltstone, Tuffaceous Claystone (5760’ – 5820’) = medium dark gray to olive gray; soft; poorly to moderately indurated; crumbly tenacity; irregular fracture; massive to nodular cuttings habit; earthy to dull luster; silty texture; massive structure; siltstone on the verge of very fine sandstone. Tuffaceous Sandstone, Sand (5820’ – 5880’) = medium light gray to olive gray; lower fine to lower medium; subprismoidal to subdiscoidal; subangular to subrounded; moderately sorted; unconsolidated sand, easily friable sandstone; matrix supported; tuffaceous matrix; predominantly quartz; trace black and dark green lithics; trace angular to subangular 5mm pebbles. Tuffaceous Siltstone, Tuffaceous Claystone (5880’ – 5940’) = dark gray with olive gray to olive black hues; soft; poorly to moderately indurated; crumbly to malleable tenacity; irregular fracture; massive to nodular cuttings habit; dull to earthy luster; silty to clayey texture; massive structure with trace thin black laminae; trace tuffaceous sandstone. Sand, Tuffaceous Sandstone (5940’ – 6000’) = medium light gray to medium gray; lower fine to lower medium; subdiscoidal to spherical; subrounded; moderately to well sorted; poorly consolidated sandstone; matrix supported; tuffaceous matrix; quartz dominated; trace black lithics. Tuffaceous Siltstone, Sandstone (6000’ – 6030’) = light olive gray to olive gray; malleable to crumbly; massive cuttings habit; dull to earthy luster; silty to gritty; massive structure. Sand, Tuffaceous Sandstone (6030’ – 6060’) = light gray to medium light gray; occasionally pale blue green hues; subdiscoidal to spherical; subrounded; moderate to well sorted; upper fine to medium grain. Coal, Carbonaceous Shale (6060’ – 6090’) = black; firm; planar to irregular; platy to elongated cuttings; vitreous to waxy luster; shale is grayish brown to moderate brown with black lithics. Tuffaceous Sandstone, Sand (6090’ – 6180’) = very light gray to grayish white, light gray with occasional pale yellowish brown hues; lower fine to upper very fine grain in part; round to subrounded; subdiscoidal to spherical in part; well sorted; 30-50% loose sand, remaining is poorly consolidated; varies from grain supported with abundant white to grayish white ash/ clay fill; also entirely matrix supported as an arenaceous claystone; dominantly translucent and transparent quartz; very minor dark grayish black to black lithic clasts; note detrital coal fragments; no hydrocarbon indicators. Tuffaceous Sandstone, Sand (6180’ – 6270’) = light gray to medium light gray; upper fine to upper medium, trace lower coarse; subdiscoidal to moderately spherical; subangular to subrounded; poorly to moderately sorted; unconsolidated sand, poorly consolidated sandstone; matrix supported; tuffaceous matrix; texturally immature; compositionally immature; predominantly clear to white quartz; trace black lithics. SRU 14B-27 14 Tuffaceous Siltstone, Tuffaceous Sandstone (6270’ – 6330’) = medium gray to medium dark gray with olive gray hues; soft; poorly to moderately indurated; crumbly to malleable tenacity; irregular fracture; massive to nodular cuttings habit; dull to earthy luster; silty to gritty texture; massive structure; moderate cohesiveness; poor to moderate adhesiveness; sandstone grading towards siltstone in later samples. Tuffaceous Sandstone, Carbonaceous Shale (6330’ – 6390’) = light olive gray to olive gray with light brownish gray hues; clotted to clumpy; malleable to crumbly; massive cuttings habit; dull to earthy; silty to gritty texture; massive structure; moderately to poorly cohesive; moderately adhesive; shale is grayish brown to moderate brown with black lithics; stringers of coal. Tuffaceous Sandstone (6390’ – 6420’) = very light gray to light gray with pale yellowish brown hues; upper fine to lower medium grain; malleable to crumbly tenacity; massive cuttings; gritty; tuffaceous matrix supported. Tuffaceous Siltstone, Sandstone, Carbonaceous Shale (6420’ – 6480’) = light brownish gray to light olive gray; crumbly to malleable; irregular fracture; dull to earthy luster; silty texture; massive structure; shale ranges from moderate brown to grayish brown with black lithics. Tuffaceous Siltstone (5480’ – 6540’) = very light gray to yellowish gray; soft; poor to moderate induration; malleable, pulverulent; amorphous with no definable fracture, cuttings habit, structure; dull to subwaxy, rarely sparkly to subsucrosic; smooth, slightly abrasive in part; with extremely fine well rounded translucent and transparent quartz grains; ashy/ tuffaceous in part grading towards a slightly silty claystone; earthy in part; trace carbonaceous detrital clasts, fragments; trace coal; no hydrocarbon indicators. Tuffaceous Sand, Sand (6540’ – 6600’) = light pale yellowish brown to light olive gray, light gray to grayish white; upper very fine to fine grain; subangular, angular in part; subdiscoidal to subprismoidal; well sorted; poorly consolidated, very soft; noncalcareous; abundant clay, often ashy matrix; varies very silty in part; dominantly translucent and transparent quartz grains with locally abundant volcanic glass clasts; note dull shaley coal. Tuffaceous Siltstone (6600’ – 6720’) = light gray with light yellowish brown hues, very light olive gray; soft to slightly firm in part; moderate induration; malleable, pulverulent, occasionally crumbly in part; no definable fracture or cuttings habit; sparkly, often dull, subwaxy common; gritty with increased sand content, smooth with increased tuff/ ash content; noncalcareous; note interbedding with tuff and tuffaceous claystone, tuffaceous sandstone, rare loose sand, note dull shaley coal; no hydrocarbon indicators. Tuffaceous Siltstone, Coal (6720’ – 6780’) = tuffaceous siltstone as above; slightly earthy in part with carbonaceous inclusions; coal = black to grayish black, brownish black in part; firm; brittle to crumbly, crunchy in part; planar to hackly fracture; platy to scaly cuttings habit; generally shaly, occasionally earthy, rarely massive; detrital fragments and spikes often appear within moderately consolidated sandy siltstone; no hydrocarbon indicators. Tuffaceous Sandstone/Sand (6780’ – 6900’) = light gray to medium light gray with light olive gray hues; upper fine to upper medium; subprismoidal to subdiscoidal; subangular to subrounded; moderately sorted; unconsolidated sand, poorly consolidated to easily friable sandstone; matrix supported; tuffaceous matrix; texturally immature; compositionally immature; predominantly clear to white quartz; trace black, dark green, red, and orange lithics; trace carbonaceous shale, coal and tuffaceous siltstone; no hydrocarbon indicators. Tuffaceous Siltstone, Tuffaceous Claystone (6900’ – 6960’) = medium gray to medium dark gray with olive gray hues; soft; poorly to moderately indurated; crumbly tenacity; irregular fracture; massive to nodular cuttings habit; dull to earthy luster; silty to clayey texture; massive structure; trace tuffaceous sandstone and loose sand; coal at 6915’; black; hard to moderately hard; dense to brittle tenacity; conchoidal to splintery fracture; massive cuttings habit; vitreous luster. SRU 14B-27 15 Tuffaceous Sandstone, Siltstone (6960’ – 6990’) = very light gray to light gray with light olive gray hues; soft; matrix supported; upper fine to lower medium grain; subrounded to subangular. Tuffaceous Siltstone (6990’ – 7080’) = light pale yellowish brown to light gray with slight brownish hues; soft; good to well indurated; brittle to crumbly, pulverulent; no definable fracture, cuttings habit or structure; sandy in part as a tuffaceous/ argillaceous sandstone; clayey to ashy in part as a tuffaceous, silty claystone; with coal = dull to subvitreous in part; soft to slightly firm; planar, often hackly; generally platy, scaly, occasionally earthy; no hydrocarbon indicators. Tuffaceous Sandstone, Tuffaceous Siltstone (7080’ – 7170’) = light gray to medium light gray with light olive gray hues; lower fine to upper medium; subdiscoidal to spherical; subangular to subrounded; poorly to moderately sorted; poorly consolidated to easily friable; matrix supported; tuffaceous matrix; texturally immature; compositionally immature; predominantly translucent to white quartz; trace black and green lithics; no hydrocarbon indicators. Coal (7170’ – 7200’) = black; moderately hard to hard; well indurated; brittle to dense tenacity; splintery fracture; elongated cuttings habit; vitreous luster; massive structure. Tuffaceous Sandstone, Siltstone (7200’ – 7230’) = very light gray to light gray; soft; matrix supported; upper fine to lower medium grain; subangular to subrounded; subdiscoidal to spherical; predominantly quartz grain. Tuffaceous Sandstone, Siltstone (7230’ – 7350’) = grayish white to light gray with slight brownish hues, light pale yellowish brown; lower fine to upper very fine grain; rounded to subrounded; subdiscoidal; well to moderate sorting; very soft, poorly consolidated; noncalcareous; abundant silty to clayey matrix; tuffaceous to ashy in part; dominantly translucent and transparent quartz; note coal = black to grayish black, soft, crumbly; planar fracture; platy to subfissle; dull, waxy in part; often shaly; no hydrocarbon indicators. Sand (7350’ – 7410’) = loose sand; upper very fine grain; subangular to subrounded; subprismoidal, subdiscoidal; well sorted; poorly consolidated in part as a tuffaceous sandstone; dominantly translucent, transparent, occasionally grayish white quartz; < 10% secondary dark gray to grayish black lithics; becoming more tuffaceous down section; NO HYDROCARBON INDICATORS INITIALLY; AT 7370’MD DISPLAYS < 5% PIN-POINT DULL YELLOWISH BROWN TO GOLD FLUORESCENCE; NO ODOR OR VISIBLE STAIN; IMMEDIATE BLUISH WHITE TO YELLOWISH WHITE BURST CUT; PALE STRAW TO STRAW FLUORESCENT RING; NO VISIBLE RESIDUE RING; FLUORESCENCE DIMINISHES AFTER7378’MD. Tuffaceous Claystone, Coal (7410’ – 7470’) = medium to medium light gray, light gray, all with slight yellowish brown hues; firm to soft; crumbly; no definable fracture, cuttings habit, structure; very sandy to silty in part, often ashy; noncalcareous; coal = black to grayish black; firm to soft; crunchy to crumbly; platy to subfissle in part; note occasional birdseye fracture; generally massive; rarely earthy; vigorous outgassing in coal at 7468’; no hydrocarbon indicators. Coal (7470’ – 7530’) = black; firm to friable; platy; vigorous outgassing; vitreous to greasy luster; tuffaceous siltstone at 7530’; olive gray; crumbly; dull to earthy. Sand, Tuffaceous Sandstone (7530’ – 7710’) = interval varies from loose sand to locally poorly consolidated tuffaceous sandstone; medium light gray, light to very light gray, grayish white, light olive gray; upper very fine to lower fine grain, rarely upper fine; rounded to subrounded; subdiscoidal; well sorted; > 90% translucent, transparent, often grayish white quartz; commonly well entrained in clay/ tuffaceous matrix; noncalcareous; trace tuff/ ash; NO VISIBLE STAIN, NO ODOR; SPOT SAMPLE AT 7628’ < 5% SCATTERED BLUISH WHITE TO YELLOWISH WHITE FLUORESCENCE; INSTANT BRIGHT WHITE STREAM CUT; BARELY VISIBLE FLUORESCENT WHITE RING; BARELY VISIBLE LIGHT BROWN RESIDUE RING. SRU 14B-27 16 Tuffaceous Sandstone, Sand (7710’ – 7740’) = light to medium gray; rare brown tones; poorly consolidated; upper very fine to lower fine; poor to well sorted; rounded to subrounded; moderate sphericity; includes very fine to fine loose sand; no hydrocarbon indicators. Tuffaceous Sandstone, Tuffaceous Claystone (7740’ – 7860’) = light gray to very light gray, grayish white in part, very light brownish hues common; upper very fine to lower fine grain; rounded to subrounded; discoidal; moderate to well sorted; soft, poorly consolidated, rarely firm, moderate consolidation; noncalcareous; abundant tuffaceous/ clay matrix; no visible porosity; generally matrix supported with well indurated translucent and transparent quartz; locally abundant black to grayish black secondary lithics; volcanic glass shards common; occasional subrounded, subdiscoidal volcanic glass clasts; interval varies from a grain supported tuffaceous sandstone to a very arenaceous claystone; no hydrocarbon indicators. Tuffaceous Sandstone (7860’ – 7890) = light gray to medium dark gray; medium to very fine grains; fair to well sorted; subangular to round; discoidal to subdiscoidal sphericity; NO ODOR; NO STAIN; EVEN YELLOW FLUORESCENCE; MILKY YELLOWISH WHITE CUT; NO WHITE LIGHT CUT OR RESIDUE; LIGHT BROWN TO AMBER RESIDUE FLUORESCENCE. Tuffaceous Claystone (7890’ – 7920’) = medium light gray to grayish black; clumpy; sectile to crumbly; irregular fracture; massive cuttings habit; dull to earthy luster; clayey texture; massive; no hydrocarbon indicators. Tuffaceous Claystone (7920’ – 7980’) = light to medium dark gray; clumpy; sectile, malleable; irregular fracture; massive cuttings habit; dull luster; clayey texture; massive structure; tuffaceous sandstone and a few pieces of coal also present; no hydrocarbon indicators. Sand, Tuffaceous Sandstone (7980’ – 8070’) = note 30-40% loose sand; light gray to medium light gray; upper very fine to lower fine grain; rounded to subrounded; subdiscoidal to subprismoidal in part; well sorted; soft; poorly consolidated, well entrained in pasty tuffaceous/ argillaceous matrix; occasionally grain supported and well cemented with calcite; trace visible porosity; no hydrocarbon indicators. Tuffaceous Claystone, Siltstone (8070’ – 8130’) = medium dark gray to dark gray at 8100’ and medium gray to medium dark gray at 8130; clumpy; very poor to moderate induration; sectile tenacity; earthy fracture; massive cuttings habit; earthy luster; clayey to silty texture; massive structure; medium to coarse coal grains imbedded in tuffaceous matrix, some larger independent coal pieces; no hydrocarbon indicators. Claystone, Siltstone (8130’ – 8220’) = medium dark gray to dark gray; poor to well indurated; sectile to crunchy, rare more indurated pieces dense; massive cuttings habit; earthy fracture; pliable stiff and slightly tacky consistency; mass bedding; inclusions of coal predominantly very fine grained, some up to medium; some larger independent coal pieces; overall less coal than previous sample both in inclusions and independent pieces; sparse fine grained sand; no hydrocarbon indicators. Tuffaceous Claystone (8220’ – 8280’) = medium dark gray, dark gray; most poorly indurated; sectile to crumbly; massive cuttings habit; pliable; mushy and pasty consistency; very fine to coarse inclusions, finer being sand; coarser pieces of coal and some green claystone; sparse brownish tinge on a few pieces of the sandstone; no oil indicators. Tuffaceous Claystone, Siltstone, Sandstone (8280’ – 8370’) = medium light gray to light gray, often with slight brownish hues, very light gray to grayish white; clays vary from very soft, pasty to hard, noncalcareous; also very hard, massive, slightly to moderately calcareous; interval varies from ashy/ tuffaceous claystone, often very silty, very sandy in part with well dispersed and entrained quartz grains; tuffaceous sandstone varies from grain supported to matrix supported with abundant clay, tuff and devitrified ash; rarely seen as a well cemented, calcareous sandstone, trace visible porosity ; no hydrocarbon indicators. SRU 14B-27 17 Tuffaceous Siltstone (8370’ – 8430’) = light gray to very light gray with light olive gray hues; firm, often soft, rare moderate hard; well indurated; dense; irregular fracture; no typical cuttings habit; generally dull yet sparkly, sub waxy in part; no evidence of bedding or structure; very arenaceous in part as a dirty, silty sandstone; often very argillaceous/ tuffaceous grading towards silty claystone; note tuff/ devitrified ash; noncalcareous; no hydrocarbon indicators. Tuffaceous Sandstone (8430’ – 8550’) = grayish white, very light gray to light gray, upper very fine to lower fine grain; subdiscoidal; moderate to well sorted in part; friable to moderate consolidation; noncalcareous; grain supported; often matrix supported with abundant devitrified ash, tuff; no visible porosity; locally clean, grain supported; hard to very hard; slightly calcareous to calcareous; 90% translucent, transparent quartz grains; 10% secondary lithics of dark gray to grayish black; secondary clay fill common; trace visible porosity; no hydrocarbon indicators. Tuffaceous Siltstone, Sandstone, Loose Sand (8550’ – 8670’) = light gray to very light gray with very light olive gray hues, occasionally very light gray to grayish white; sift to firm; moderate to well indurated; crumbly to pulverulent in part; irregular to earthy fracture in part; curved cuttings habit; dull, earthy, often subsucrosic, occasionally subwaxy; gritty to smooth, slightly to very abrasive; interval varies from interbedded and gradational silty claystone to argillaceous sand stone; devitrified ash, tuff and clays common; note 10% loose sand; < 10% non tuffaceous sandstone; hard to very hard; slightly calcareous to calcareous; trace visible porosity; note coal, carbonaceous shale; no hydrocarbon indicators. Tuffaceous Siltstone (8670’ – 8730’) = light gray to medium light gray, most often with light olive gray, light yellowish brown hues; soft to firm; crumbly, brittle; irregular fracture; bladed to curved cuttings habit; dull to sparkly in part; gritty, slightly to moderately abrasive; no apparent bedding or structure; noncalcareous; locally very sandy in part with abundant very fine well rounded quartz grains; often clayey, tuffaceous, ashy in part; no hydrocarbon indicators. Tuffaceous Sandstone, Siltstone (8730’ – 8850’) = very light gray to light gray, often grayish white; lower very fine to lower fine grain, upper fine grain; subrounded to rounded; subdiscoidal to spherical; well sorted translucent and transparent quartz; often poorly sorted with 30 40% upper fine volcanic glass, dark gray to grayish black, light bluish gray subangular, subprismoidal clasts; generally grain supported; grains often well suspended and entrained within light colored devitrified ash/ tuffaceous clay matrix; noncalcareous; no visible porosity; note air dried clay/ ash component readily re hydrates, swells and crumbles; trace carbonaceous detritus and possible dead oil stain; >80% EVEN DULL YELLOW FLUORESCENCE; NO ODOR; FLUORESCENCE BRIGHTENS WITH ADDITION OF SOLVENT; NO CUT OR RESIDUE. Tuffaceous Siltstone (8850’ – 8940’) = light gray, light olive brown, pale yellowish brown; soft to slightly firm; moderate induration; brittle to crumbly, pulverulent in part; no definable fracture; scalloped cuttings habit; dull, subwaxy luster in part; generally gritty, slightly abrasive, often smooth; very earthy in part with locally abundant carbonaceous streak, flake, clast detritus; very sandy in places and appears as a silty/ argillaceous sand stone; abundant tuff/ clay component also represented; noncalcareous; POSSIBLE DEAD OIL STAIN; NO ODOR; 20 30% DULL YELLOW FLUORESCENCE; NO SOLVENT REACTION. Tuffaceous Siltstone, Sandstone (8940’ – 9000’) = medium gray to grayish black; pulverulent to crumbly; irregular to blocky fracture; massive cuttings habit; dull to earthy luster; clayey and silty texture; massive structure; rare brown tinge; medium to very fine grains in sandstone; sparse unconsolidated sand; no oil indicators. Tuffaceous Siltstone, Sandstone (9000’ – 9060’) = medium light grey to medium gray; medium to very fine; pulverulent to crumbly, irregular, blocky fracture; massive cuttings habit; dull earthy luster; clayey silty texture massive structure; less clay in 9060, more siltstone; no reaction to HCl; no oil indicators. SRU 14B-27 18 Tuffaceous Siltstone, Coal (9080’ – 9210’) = light gray to very light gray, occasionally pale yellowish brown; firm to soft; moderate to well indurated ; crumbly, pasty in part; no definable fracture; scalloped, occasionally nodular cuttings habit; dull; often sparkly to subsucrosic, occasionally subwaxy; smooth to gritty; slightly abrasive; no apparent structure; occasionally exhibits alternating very fine layered coal/ carbonaceous material; gradational from sandy silt stone with abundant very fine well rounded quartz, to a silty claystone; noncalcareous; with coal = black, often olive black to brownish black; firm; brittle to crunchy, crumbly; splintery to hackly fracture; coffee ground cut tings habit; dull to matte, subvitreous; platy to subfissle; poorly developed with woody texture; sublithic in part; mild outgassing bubbles; 30% OF SILTSTONE CUTTINGS DECREASING TO < 5% EXHIBIT DULL YELLOW FLUORESCENCE; NO STAIN, ODOR, CUT. Tuffaceous Siltstone, Sandstone (9210’ – 9240’) = very light gray to grayish white; very fine grain; subdiscoidal, well sorted; tight; abundant tuff/ de vitrified ash matrix; quartz dominant; no hydrocarbon indicators. Tuffaceous Sandstone, Siltstone (9240’ – 9270’) = yellowish gray to medium gray; very fine to fine grain; subrounded; subdiscoidal; well sorted; tuff and ash matrix; quartz dominant; moderate amounts of loose sand; no hydrocarbon indicators. Tuffaceous Sandstone, Siltstone (9270’ – 9300’) = yellowish gray to medium light gray, medium dark gray; medium to fine grain; well sorted; tuff and ash matrix; quartz dominant; subangular; low sphericity; moderate amounts of loose sand; no hydrocarbon indicators. Tuffaceous Sandstone, Siltstone (9300’ – 9360’) = abundant loose sand; light gray to yellowish gray to medium gray; fine to medium grain; well sorted; moderate sphericity; subrounded; quartz dominant; tuff and ash matrix; no hydrocarbon indicators. Tuffaceous Sandstone, Siltstone (9390’ – 9420’) = return of moderate amounts of unconsolidated sand; light grey to medium dark grey; fine to medium grains; moderate sphericity and subrounded; well sorted; quartz dominated with tuff and ash matrix; NO ODOR, PATCHY FLUORESCENCE, DULL YELLOW WHITE FLUORESCENT BLOOMING CUT, DULL, YELLOW NO CUT, NO W HITE LIGHT RESIDUE; FLUORESCENT BRIGHT YELLOW Tuffaceous Sandstone, Siltstone (9420’ – 9450’) = light to dark gray; medium to fine grain; subrounded; moderate sphericity; quartz dominant; tuff and ash matrix; no hydrocarbon indicators. Tuffaceous Sandstone, Siltstone (9450’ 9520’) = small amounts of unconsolidated sand; light grey to dark grey; medium to fine grains; subrounded and moderate sphericity; quartz dominated with tuff and ash matrix; siltstone is dark to light gray; pulverulent; irregular to earthy fracture; massive; clayey to silty texture; earthy luster; no hydrocarbon indicators. Tuffaceous Sandstone, Siltstone (9520’ – 9570’) = yellowish gray, light gray to medium light gray; medium to fine grain; subrounded; moderate sphericity; quartz dominant with ash and tuff matrix ; locally abundant loose sand; no hydrocarbon indicators. Sandstone, Tuffaceous Sandstone, Tuffaceous Siltstone (9570’ – 9690’) = light gray to medium light gray, occasionally with slight yellowish brown hues; upper very fine to lower fine grain; rounded to subrounded; discoidal to spherical in part; well sorted; slightly calcareous; grain supported; secondary clay fill; fair to good visual porosity in part; ash/ tuffaceous matrix common, often grading towards tuffaceous sandstone and very arenaceous claystone; very silty in part; 5 10% LOCALIZED DEAD OIL STAIN; NO ODOR; 20 30% DULL YELLOW TO GOLD FLUORESCENCE; NO SOLVENT REACTION. SRU 14B-27 19 Tuffaceous Siltstone, Tuffaceous Sandstone, Sandstone (9690’ – 9780’) = light gray to medium light gray with slight light olive gray hues; upper very fine grain, lower very fine grain common as loose sand; subrounded, occasionally subangular; subdiscoidal to sub prismoidal in part; well sorted, poorly consolidated; generally grain supported with abundant soft ash/ clay matrix; matrix supported common as a very arenaceous quartz rich siltstone and claystone; generally noncalcareous; tight; no visible porosity; note localized cleaner, well cemented, calcareous sandstone; upper very fine grain as above; poor to fair, occasional good visible porosity; loose sand is roughly 20% of sample; no stain or odor; 25% dull yellow to gold fluorescence; no solvent reaction. Tuffaceous Sandstone (9780’ – 9840’) = medium gray to medium light gray; sectile to crumbly; massive cuttings habit; earthy fracture; dull to earthy luster; clayey silty texture. No oil indicators. Tuffaceous Siltstone (9840’ – 9900’) = medium dark gray to grayish black; some brownish tinge; crumbly to pulverulent tenacity; irregular earthy fracture; dull earthy luster; silty texture; massive structure. Tuffaceous Siltstone, Tuffaceous Sandstone, Sandstone, Loose Sand (9900’ – 9960’) = light gray to medium light gray with slight olive gray hues, occasional medium to medium dark gray; firm, soft common; moderate to well indurated; crumbly, pulverulent in part, brittle when dry; no definable fracture; less scalloped, more tabular cuttings habit; dull matrix, subwaxy when tuffaceous, sparkly to subsucrosic when very fine to lower fine grain quartz abounds; no apparent structure; slightly calcareous in part; sandstone varies from matrix supported with abundant white to grayish white devitrified ash, to grain supported with clay fill; fair to occasionally good visible porosity; NO STAIN OR ODOR; 10 25% SCATTERED DULL YELLOW FLUORESCENCE; NO SOLVENT REACTION. Tuffaceous Siltstone, Sandstone (9960’ – 10050’) = light pale yellowish brown to very light olive gray, light gray with yellowish brown hues; upper very fine to lower very fine grain; rounded to subrounded; spherical to subdiscoidal; well sorted; non to slightly calcareous; friable, brittle to crumbly; occasional well cemented, calcareous grain supported sandstone with good visible porosity; dominantly very clayey; varies from sandy siltstone to silty, sandy claystone; note 10 20% loose sand; NO STAIN OR ODOR; 100% EVEN, DULL YELLOW TO GOLD FLUORESCENCE IN 9960’ TO 9990’ SAMPLE, DECREASING TO < 20% AT BOTTOM OF SAMPLE INTERVAL; NO SOLVENT REACTION. Tuffaceous Siltstone (10050’ – 10110’) = medium gray to light medium gray; moderate to poor induration; dense and stiff; blocky to irregular; tabular to nodular to massive; dull to earthy luster. No hydrocarbon indicators. Tuffaceous Sandstone (10110’ – 10260’)= light medium gray to medium gray with pale olive hues; poor to soft to unconsolidated; upper fine to lower medium to occasionally lower fine; moderate to poor sorting; subangular to subrounded; moderate to good sphericity; commonly grain supported with moderate amounts of devitrified ash; grades to a silty sandstone supported by a clay and ash matrix; slightly carbonaceous overall; sample is dominated by clear to translucent to milky white quartz; moderate amount of shiny black carbonaceous material with a minor amount of dark lithics; carbonaceous banding is common in the silty clasts and very rare in the sandier ones; no hydrocarbon indicators present. Tuffaceous Siltstone/Sandstone (10260’ – 10350’) = medium gray to light medium gray with pale olive and brown hues; moderate to poor induration; slightly dense to crumbly and brittle; irregular to earthy to blocky fracture; tabular to massive cuttings habit; dull to slightly waxy luster; minor carbonaceous banding observed; the sandstone is poorly consolidated to unconsolidated; lower medium to upper fine grained; common lower fine to upper medium grains; moderate to poor sorting; subangular to subrounded; moderate sphericity; matrix supported with a devitrified ash; occasionally grades to grain supported; moderate decrease in loose carbonaceous sediment; no hydrocarbon indicators present. SRU 14B-27 20 Tuffaceous Siltstone, Sandstone (10350’ – 10460’) = light medium gray with olive hues to medium gray with brownish hues; poor to moderate induration; semi dense to brittle and crumbly; dull to earthy to waxy luster; clayey to silty to slightly gritty texture; tabular to massive cuttings habit; irregular to earthy fracture; micro carbonaceous banding decreasing in frequency; samples turn to almost 100% tuffaceous sandstone/ sand halfway through the interval; commonly very pale grayish white; poorly consolidated to unconsolidated; lower to upper medium to upper fine with occasional lower fine grains; poor to moderate sorting; subangular to subrounded to angular; 30% coal on spot sample in accordance with torque spike while drilling; no hydrocarbon indicators present. Tuffaceous Siltstone, Sandstone (10460’ – 10560’) = medium gray to light medium gray with brown and olive hues; moderate to poor induration; brittle to crumbly occasionally semi dense; irregular to blocky fracture; massive to tabular cuttings habit; dull to waxy luster; silty to clayey texture; trace carbonaceous banding; tuffaceous sandstone stone is pale grayish white; poorly consolidated to unconsolidated; lower fine to upper medium to upper fine; moderate to poor sorting; subangular to subrounded to angular; poor to moderate sphericity; no hydrocarbon indicators present. Tuffaceous Sandstone, Sand (10560’ – 10660’) = pale grayish white to very light medium gray with pale bluish hues; poorly consolidated to unconsolidated; loose sediment tends to be upper very fine to lower fine with occasional upper fine to lower medium grains; the consolidated clasts contain upper medium to upper very fine grains seen throughout; subangular to subrounded to angular; poor to occasionally moderate sorting; moderate to poor sphericity; moderate amount of a black carbonaceous material; 15% GRAIN AND SAMPLE FLUORESCENCE NEAR THE MIDDLE OF THE INTERVAL WITH NONE SEEN AT THE BEGINNING OR THE END; PALE YELLOWISH WHITE; EXTREME TO VERY SLOW MILKY YELLOW CUT; NO ODOR OR RESIDUAL CUT. Sand, Sandstone (10660’ – 10700’) = note locally abundant loose sand; sandstone is light gray to very light gray, grayish white to white; upper very fine to lower fine grain; rounded to subrounded; subdiscoidal; well sorted; generally very ashy; tight; noncalcareous; often cleaner; slightly calcareous; fair visible porosity; note carbonaceous material; TRACE DEAD OIL STAIN; NO ODOR SOLVENT REACTION. Tuffaceous Claystone, Siltstone (10700’ – 10740’) = very light gray to light gray; soft to firm; malleable, pulverulent; no definite fracture or cuttings habit; dull to subwaxy; noncalcareous; no apparent bedding or structure; note occasional carbonaceous detritus; TRACE DEAD OIL STAIN; NO FLORESCENCE OR SOLVENT REACTION. Tuffaceous Sand (10740’ – 10830’) = note 30% loose sand; sandstone is white to grayish white, very light gray in part; upper very fine to lower medium grain; rounded to subrounded; subdiscoidal to subprismoidal in part; well sorted; poor consolidation; noncalcareous; dominated by ashy, clay matrix; no visible porosity; quartz dominant; note locally abundant carbonaceous detritus; TRACE BITUMEN, DEAD OIL STAIN; NO LIVE OIL STAIN OR ODOR; 20% INCREASING TO 100% YELLOW WHITE TO BRIGHT YELLOW FLUORESCENCE; IMMEDIATE MILKY YELLOW BURST WITH OCCASIONAL STREAM CUT; FEINT MILKY FLUORESCENT RING; NO VISIBLE RESIDUE. Sand, Tuffaceous Sand (10830’ – 10920’) = note: interval is represented by 50 – 100% loose sand over shakers; tuffaceous sand is grayish white to very light gray; upper very fine to lower fine grain; rounded to subrounded; subdiscoidal; well sorted; noncalcareous; grain supported with abundant ash/ clay matrix; note occasional upper fine grain sandstone; angular; prismoidal; moderate sorting; non to slightly calcareous; trace clay fill; fair visible porosity; note carbonaceous detrital fragments, streaks in more argillaceous samples; NO LIVE OIL STAIN; HYDROCARBON ODOR IN PITS AT 10890 10900’ SAMPLE INTERVAL; 80 100% YELLOW TO YELLOW ORANGE SAMPLE FLUORESCENCE; IMMEDIATE MILKY TO LIGHT MILKY YELLOW FLUORESCENT CUT, RARE FAST STREAMERS FROM MORE ARGILLACEOUS CUTTINGS; STRONG MILKY FLUORESCENT RING; VERY FEINT YELLOWISH BROWN RESIDUE RING. SRU 14B-27 21 Tuffaceous Sandstone, Siltstone (10920’ – 11080’) = very pale medium grayish white to white with very pale brown hues; poor consolidation to unconsolidated; lower fine to upper very fine to occasionally lower very fine and upper fine; moderate to poor sorting; subangular to subrounded; moderate sphericity; grain supported by ash and clay matrix; the siltstone is medium brownish gray to pale brown; moderate to poor induration; somewhat dense to crumbly and brittle; blocky to irregular fracture; dull to waxy luster; silty to clayey texture; trace amounts of carbonaceous banding and as loose sediment; FLUORESCENCE IS RARE WITH 15% BEING THE MOST SEEN THROUGH THE INTERVAL; NO CUT OR ODOR. Tuffaceous Sandstone, Siltstone (11080’ – 11200’) = pale grayish white to very light medium gray; lower fine to upper very fine grained; moderate sorting; subangular to subrounded to angular; moderate to poor sphericity; grain supported with ash and minor amounts of clay; trace grain supported clasts with notably better sorting and no tuffaceous material; overall dominated by clear to translucent to milky white quartz; trace granule sized quartz grains ranging up to 3.5mm; moderate amount of carbonaceous sediment and as banding in the siltstones; WEAK TO NO FLUORESCENCE THROUGH THE INTERVAL EXCEPT ON THE 11130’ SAMPLE; 50% PALE YELLOWISH WHITE; MODERATE ODOR; SLOW MILKY YELLOW CUT; WEAK STRAW YELLOW RESIDUAL RING. Tuffaceous Claystone, Siltstone (11200’ – 11280’) = light gray, grayish white, often medium gray; firm; crumbly to brittle, malleable in part; irregular fracture; slightly tabular cuttings habit; dull to subwaxy; generally massive, occasional lenticular bedding; note locally abundant muscovite in 11230 40’ sample interval with well defined schistose characteristics; samples indicate distinct variations between claystone, siltstone, occasional sand stone and loose sand; NO STAIN OR ODOR; TRACE TO 30% YELLOW TO YELLOW ORANGE FLUORESCENCE; SLOW PALE TO DARK STRAW STREAMING CUT; MILKY TO YELLOW FLUORESCENT RING; SLIGHT YELLOWISH BROWN RESIDUE RING. Conglomeratic Sand, Conglomerate, Sand (11280’ – 11320’) = unconsolidated; upper fine to upper very coarse and beyond; angular to very angular; prismoidal; poor sorting; note occasional subrounded pebble fragments with high impact fracture; predominantly milky white, grayish white quartz; minor very light gray to medium light gray, grayish black lithics; note light and dark gray schistose clasts; no hydro carbon indicators. SRU 14B-27 22 3.3 Connection Gases 50 units = 1% Methane Equivalent Measured Depth (feet) Subsea Total Vertical Depth (feet) Gas over background (units) Measured Depth (feet) Subsea Total Vertical Depth (feet) Gas over background (units) 7450 138 10179 104 7577 300 10240 100 7703 1218 10302 105 8020 44 10363 75 8335 24 10432 112 9219 56 10492 105 9282 15 10552 190 9345 182 10614 170 9409 220 10681 133 9472 455 10741 300 9588 132 10805 123 9651 147 10867 217 9714 161 10935 144 9725 115 10995 185 9788 153 11059 130 9851 214 11122 177 9915 305 11183 149 9978 221 11247 138 10041 300 11312 165 10070 317 3.4 Trip Gases 50 units = 1% Methane Equivalent Measured Depth (feet) Trip to (feet) Gas (units) Hours Off Bottom 3215 Surface 163 - 4797 Wiper trip to 2950 60 7.0 6185 Wiper trip to 4784 292 6.2 7068 Wiper trip to 5498 688 4.4 8064 Wiper trip to4832 2298 7.6 8064 Surface 145 - 9016 Wiper trip to 7755 263 3.0 9838 Down Time Gas 1059 0.6 10110 Wiper trip to 9990 3367 4.6 10110 (#1) Short trip to 8773 1845 3.5 10110 (#2) Short trip to 8749 286 4.2 10110 (#3) Short trip to 8749 178 5.5 10110 7-5/8” casing run 254 43.5 11320 Short trip to 10110 110 5 11320 Trip in w/liner 186 35 SRU 14B-27 23 3.5 Sampling Program / Sample Dispatch Set Type / Purpose Frequency* Interval Dispatched to A Washed and dried reference samples 30 ft 10 ft 30 ft 10 ft 2970 ft – 7378 ft 7378 ft – 7440 ft 7440 ft – 10560 ft 10560 ft - 11320 ft Hilcorp Alaska LLC 3800 Centerpoint Drive Suite #1000 Anchorage AK 99508 Attn.: Debra Oudean (907) 777-8337 B Washed and dried reference samples 30 ft 10 ft 30 ft 10 ft 2970 ft – 7378 ft 7378 ft – 7440 ft 7440 ft – 10560 ft 10560 ft - 11320 ft Hilcorp Alaska LLC 3800 Centerpoint Drive Suite #1000 Anchorage AK 99508 Attn.: Debra Oudean (907) 777-8337 * Sample frequency was locally altered according to drill rate constraints and zones of interest. SRU 14B-27 24 4 DRILLING DATA 4.1 Directional Survey Data Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Northing (ft) Easting (ft) Vertical Section (ft) Dogleg Rate (o/100ft) 0 0 0 0 0 0 0 0 18.5 0 0 18.50 0 0 0 0 245 0.06 49.36 245.00 0.08 0.09 0.12 0.03 365 0.25 242.80 365.00 0.00 -0.10 0.32 0.26 488 0.37 253.01 488.00 -0.24 -0.71 0.98 0.11 614 0.22 293.75 614.00 -0.26 -1.32 1.59 0.20 742 0.46 255.99 741.99 -0.29 -2.05 2.32 0.25 861 0.66 300.82 860.99 -0.05 -3.10 3.4 0.39 993 0.48 282.25 992.98 0.46 -4.29 4.69 0.19 1122 0.76 295.48 1121.97 0.94 -5.59 6.08 0.24 1248 0.89 295.68 1247.96 1.72 -7.23 7.89 0.10 1374 0.57 76.98 1373.96 2.29 -7.50 8.52 1.10 1464 1.26 85.99 1463.95 2.46 -6.08 9.95 0.78 1526 1.09 90.27 1525.93 2.50 -4.81 11.22 0.31 1592 1.35 76.72 1591.92 2.68 -3.42 12.62 0.59 1652 2.35 52.36 1651.89 3.59 -1.76 14.52 2.08 1717 3.14 51.93 1716.81 5.50 0.70 17.63 1.22 1780 3.83 47.97 1779.69 7.98 3.62 21.46 1.16 1844 3.98 47.44 1843.55 10.91 6.84 25.82 0.24 1908 3.84 41.11 1907.40 14.03 9.89 30.17 0.71 1970 3.93 40.45 1969.25 17.21 12.63 34.37 0.16 2031 3.49 41.40 2030.13 20.19 15.21 38.32 0.73 2097 2.94 40.31 2096.02 22.99 17.64 42.02 0.84 2160 2.89 40.53 2158.94 25.43 19.71 45.23 0.08 2222 2.85 38.32 2220.86 27.82 21.69 48.33 0.19 2286 3.17 40.16 2284.77 30.42 23.81 51.69 0.52 2350 3.19 38.95 2348.68 33.16 26.07 55.24 0.11 2411 3.20 39.24 2409.58 35.80 28.22 58.64 0.03 2474 2.93 37.31 2472.49 38.44 30.31 62.01 0.46 2536 2.96 35.29 2534.41 41.01 32.19 65.19 0.17 2598 2.95 41.38 2596.33 43.51 34.17 68.38 0.51 2664 2.97 41.34 2662.24 46.07 36.42 71.79 0.03 2730 2.93 46.44 2728.15 48.52 38.77 75.19 0.40 2790 3.10 40.21 2788.07 50.81 40.93 78.34 0.61 2854 2.49 46.34 2851.99 53.10 43.06 81.45 1.06 SRU 14B-27 25 Survey Data (continued) Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Northing (ft) Easting (ft) Vertical Section (ft) Dogleg Rate (o/100ft) 2915 2.25 53.95 2912.94 54.71 44.98 83.97 0.65 3040 1.32 50.30 3037.88 57.08 48.07 87.86 0.75 3165 1.50 57.90 3162.84 58.87 50.57 90.93 0.21 3229 1.66 44.91 3226.82 59.97 51.93 92.68 0.61 3293 0.91 52.09 3290.80 60.94 52.99 94.12 1.20 3357 0.49 60.91 3354.79 61.38 53.63 94.90 0.68 3420 0.78 45.86 3417.79 61.81 54.17 95.59 0.53 3483 0.13 38.63 3480.79 62.17 54.52 96.09 1.03 3546 0.18 188.04 3543.79 62.13 54.55 96.14 0.48 3610 0.44 207.29 3607.79 61.81 54.43 96.48 0.43 3673 0.30 185.78 3670.79 61.43 54.30 96.88 0.31 3737 0.26 244.83 3734.79 61.20 54.15 97.16 0.43 3800 0.25 254.54 3797.79 61.10 53.89 97.43 0.07 3864 0.32 211.88 3861.78 60.91 53.66 97.73 0.34 3927 0.11 96.04 3924.78 60.76 53.63 97.89 0.60 3990 0.07 116.41 3987.78 60.73 53.72 97.99 0.08 4052 0.00 107.58 4049.78 60.72 53.76 98.03 0.11 4115 0.03 265.10 4112.78 60.72 53.74 98.04 0.05 4179 0.10 97.12 4176.78 60.71 53.78 98.08 0.20 4243 0.13 187.17 4240.78 60.63 53.83 98.17 0.26 4306 0.28 122.81 4303.78 60.47 53.95 98.37 0.40 4369 0.19 190.61 4366.78 60.29 54.06 98.59 0.43 4432 0.18 122.39 4429.78 60.13 54.12 98.75 0.33 4495 0.22 235.34 4492.78 60.01 54.10 98.88 0.53 4559 0.10 197.68 4556.78 59.89 53.99 99.05 0.24 4623 0.09 204.64 4620.78 59.79 53.95 99.15 0.02 4686 0.23 144.58 4683.78 59.64 54.00 99.31 0.32 4746 0.25 160.75 4743.78 59.42 54.11 99.56 0.12 4808 0.14 100.92 4805.78 59.28 54.23 99.74 0.35 4871 0.22 226.93 4868.78 59.18 54.22 99.84 0.51 4935 0.29 156.17 4932.78 58.95 54.20 100.08 0.47 4997 0.18 203.62 4994.78 58.71 54.22 100.31 0.35 5061 0.33 150.44 5058.78 58.46 54.27 100.57 0.41 5124 0.37 117.34 5121.78 58.21 54.54 100.94 0.32 5188 0.26 160.67 5185.78 57.98 54.77 101.26 0.40 5251 0.16 170.79 5248.78 57.76 54.83 101.49 0.17 5314 0.32 117.29 5311.78 57.59 55.00 101.73 0.41 5378 0.16 147.34 5375.78 57.43 55.21 101.99 0.31 5440 0.04 167.10 5437.78 57.34 55.26 102.10 0.19 5504 0.20 169.71 5501.78 57.20 55.29 102.24 0.25 SRU 14B-27 26 Survey Data (continued) Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Northing (ft) Easting (ft) Vertical Section (ft) Dogleg Rate (o/100ft) 5567 0.13 237.08 5564.78 57.06 55.25 102.39 0.30 5631 0.13 239.62 5628.78 56.98 55.12 102.54 0.01 5694 0.17 136.24 5691.78 56.88 55.13 102.64 0.38 5757 0.09 159.31 5754.77 56.76 55.21 102.78 0.15 5820 0.13 122.13 5817.77 56.68 55.29 102.89 0.13 5882 0.19 270.1 5879.77 56.64 55.24 102.95 0.50 5944 0.20 341.64 5941.77 56.74 55.11 103.12 0.37 6009 0.03 267.8 6006.77 56.85 55.05 103.24 0.30 6073 0.21 349.02 6070.77 56.97 55.02 103.36 0.32 6135 0.19 35.27 6132.77 57.16 55.05 103.56 0.26 6197 0.25 14.87 6194.77 57.38 55.15 103.80 0.16 6260 0.35 31.88 6257.77 57.67 55.28 104.12 0.21 6321 0.40 16.42 6318.77 58.03 55.44 104.52 0.18 6386 0.40 43.82 6383.77 58.42 55.66 104.96 0.29 6450 0.28 356.88 6447.77 58.73 55.81 105.31 0.46 6511 0.51 29.76 6508.77 59.12 55.94 105.71 0.51 6577 0.40 38.77 6574.77 59.55 56.23 106.24 0.20 6640 0.56 14.36 6637.76 60.02 56.44 106.75 0.41 6703 0.51 15.11 6700.76 60.59 56.59 107.34 0.08 6767 0.44 23.81 6764.76 61.09 56.76 107.87 0.16 6829 0.43 33.01 6826.76 61.50 56.99 108.34 0.11 6893 0.90 28.61 6890.75 62.15 57.36 109.08 0.74 6956 1.77 20.09 6953.73 63.49 57.93 110.55 1.41 7018 2.56 21.72 7015.69 65.68 58.77 112.89 1.28 7082 3.48 25.28 7079.60 68.76 60.13 116.26 1.47 7145 4.32 28.59 7142.45 72.58 62.08 120.54 1.38 7209 6.02 32.52 7206.19 77.52 65.04 126.30 2.71 7271 7.20 36.71 7267.78 83.38 69.11 133.44 2.05 7335 7.70 38.35 7331.24 89.96 74.17 141.73 0.85 7400 9.23 38.94 7395.53 97.43 80.15 151.30 2.36 7461 9.52 38.97 7455.71 105.16 86.39 161.24 0.48 7523 11.03 38.08 7516.72 113.81 93.28 172.30 2.45 7588 11.83 37.26 7580.43 124.01 101.15 185.18 1.26 7651 13.33 36.80 7641.91 134.96 109.41 198.90 2.39 7713 14.00 35.95 7702.16 146.76 118.09 213.55 1.13 7778 15.32 38.57 7765.04 159.84 128.06 229.99 2.27 7841 16.37 38.45 7825.65 173.30 138.77 247.19 1.67 7904 17.43 38.50 7885.92 187.64 150.16 265.51 1.68 7968 18.45 38.52 7946.81 203.06 162.44 285.22 1.60 8030 19.36 38.19 8005.47 218.81 174.90 305.31 1.48 SRU 14B-27 27 Survey Data (continued) Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Northing (ft) Easting (ft) Vertical Section (ft) Dogleg Rate (o/100ft) 8093 21.33 39.27 8064.53 235.89 188.61 327.21 3.18 8155 22.00 39.29 8122.15 253.61 203.1 350.10 1.08 8219 21.93 3.009 8181.51 272.18 218.22 374.04 0.20 8283 22.08 38.35 8240.85 290.90 233.2 398.02 0.45 8346 21.82 38.95 8299.28 309.29 247.91 421.56 0.55 8409 21.77 39.08 8357.78 327.46 262.63 444.96 0.11 8472 21.75 38.05 8416.29 345.72 277.19 468.31 0.61 8535 21.73 37.09 8474.81 364.22 291.42 491.64 0.57 8598 21.53 37.48 8533.37 382.70 305.49 514.87 0.39 8661 21.30 37.74 8592.02 400.92 319.53 537.87 0.39 8724 21.17 37.55 8650.74 418.99 333.46 560.69 0.23 8788 21.05 37.08 8710.45 437.32 347.44 583.74 0.32 8851 20.76 37.00 8769.30 455.26 360.98 606.22 0.46 8913 20.39 36.91 8827.35 472.67 374.08 628.01 0.60 8976 20.92 37.05 8886.30 490.42 387.44 650.23 0.84 9040 21.13 37.57 8946.04 508.69 401.36 673.19 0.44 9104 20.95 37.65 9005.77 526.89 415.38 696.17 0.28 9166 21.05 38.24 9063.65 544.41 429.05 718.39 0.38 9230 21.01 38.60 9123.39 562.40 443.32 741.35 0.21 9292 21.07 38.63 9181.25 579.80 457.21 763.61 0.10 9357 21.18 38.52 9241.89 598.11 471.82 787.04 0.18 9419 21.20 38.49 9299.69 615.65 485.77 809.45 0.04 9483 21.03 38.48 9359.40 633.70 500.12 832.50 0.27 9546 20.88 38.68 9418.23 651.31 514.17 855.03 0.26 9608 20.65 39.14 9476.20 668.41 527.97 877.02 0.45 9673 20.64 38.66 9537.03 686.25 542.37 899.93 0.26 9736 20.58 38.54 9596.00 703.58 556.20 922.11 0.12 9798 20.28 38.76 9654.10 720.48 569.72 943.75 0.50 9862 20.21 38.37 9714.14 737.80 583.52 965.90 0.24 9925 20.10 38.62 9773.29 754.79 597.03 987.60 0.22 9988 20.39 38.65 9832.39 771.82 610.65 1009.40 0.46 10020 20.49 38.75 9862.38 780.54 617.63 1020.58 0.33 10052 20.29 38.72 9892.37 789.24 624.61 1031.73 0.63 10188 20.48 37.28 10019.86 826.56 653.77 1053.86 0.39 10251 20.44 37.20 10078.88 844.10 667.10 1075.87 0.08 10314 20.35 37.34 10137.93 861.57 680.39 1097.82 0.16 10378 20.27 38.17 10197.95 879.13 693.99 1120.04 0.47 10440 20.07 39.73 10256.15 895.76 707.43 1141.41 0.93 10503 20.35 39.56 10315.27 912.51 721.32 1163.17 0.45 10566 20.51 39.49 10374.31 929.48 735.31 1185.16 0.26 SRU 14B-27 28 Survey Data (continued) Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Northing (ft) Easting (ft) Vertical Section (ft) Dogleg Rate (o/100ft) 10629 20.51 39.53 10433.32 946.51 749.35 1207.23 0.02 10690 20.26 39.78 10490.50 962.87 762.91 1228.47 0.43 10754 20.49 39.11 10550.49 980.07 777.07 1250.75 0.51 10816 20.74 39.31 10608.52 996.99 790.87 1272.58 0.42 10879 20.10 38.86 10667.56 1014.05 804.73 1294.56 1.05 10940 20.08 38.77 10724.85 1030.37 817.86 1315.51 0.06 11006 20.01 38.47 10786.85 1048.05 831.98 1338.13 0.19 11068 19.69 37.49 10845.17 1064.64 844.94 1359.18 0.75 11131 19.24 37.18 10904.57 1081.33 857.67 1380.17 0.73 SR U 1 4 B - 2 7 29 4. 2 B i t R e c o r d Bi t S i z e M a k e T y p e / S N Je t s / TF A De p t h In De p t h Ou t Fo o t a g e Dr i l l e d Bi t Ho u r s Av g . RO P (f t / h r ) Av g . WO B (kl b s ) Av g . RP M Avg. PP (p s i ) Grade 1 1 3 - 1 / 2 ” H C C MX L - 1 X / 52 0 9 0 1 2 14 , 3 x 1 6 / 0. 7 3 9 4 76 ’ 3 8 5 ’ 3 0 9 ’ ’ 7 . 2 4 2 . 9 4 . 7 6 1 . 7 5 1 3 0-0-NO-A-E-I-NO-BHA 2 1 3 - 1 / 2 ” H C C MX L 1 X / 52 0 9 0 1 2 14 , 3 x 1 6 / 0. 7 3 9 4 38 5 ’ 2 9 8 0 ’ ’ 2 5 9 5 ’ 3 9 . 2 6 6 . 2 9 . 1 7 0 . 9 1 9 1 0 1 - 1 - W T - A - E-I-BU-TD 2 9 - 7 / 8 ” Sm i t h /B i t # 2R R XR + / PX 5 2 6 6 12 , 3 x 1 6 / 0. 6 9 9 5 29 8 0 ’ 3 2 1 5 ’ 2 3 5 ’ 3 . 3 7 1 . 2 1 3 . 5 1 4 9 . 8 2 6 6 1-1-WT-A-1-I-NO-BHA 3 9 - 7 / 8 ” H C C HD C 5 0 4 Z 71 3 0 9 6 6x 1 3 / 0. 7 7 7 7 32 1 5 ’ 8 0 6 4 4 8 4 9 ’ 1 5 3 . 6 3 1 . 6 1 8 8 1 1 9 6 3 2 - 4 - R O - T - X - 1 -CT-TD 4 9 - 7 / 8 ” H C C QD 5 0 5 X X 72 1 2 1 2 9 6x 1 1 , 2 x 1 2 / 0. 7 7 7 7 80 6 4 ’ 1 0 1 1 0 ’ 2 0 4 6 ’ 9 8 . 5 2 0 . 8 1 1 . 2 6 7 2 8 7 9 4 - 3 - B T - N - X-I-CT-TD 4 9 - 7 / 8 ” Sm i t h /B i t # 2R R 2 XR + / PX 5 2 6 6 12 , 3 x 1 6 / 0. 6 9 9 5 10 1 1 0 ’ 1 0 1 1 0 ’ 0 ’ 0 0 0 0 0 1 - 1 - W T - A - E - I - N O - T D 5 6 - 3 / 4 ” H C C QD 5 0 5 X / 70 2 6 4 0 7 5x 1 1 / 0. 4 6 4 0 10 1 1 0 ’ 1 1 3 2 0 ’ 1 2 1 0 ’ 3 4 . 3 3 5 . 3 4 . 9 6 5 2 2 9 0 4 - 3 - W T - A - X-I-CT-TD SR U 1 4 B - 2 7 30 4. 3 M u d R e c o r d Co n t r a c t o r : B a r o i d Mu d T y p e : S p u d M u d Da t e De p t h (f t ) MW (p p g ) VI S (s / q t ) PV Y P G e l s FL (c c ) FC So l s (% ) O/ W Ra t i o Sd (% ) MB T p H Cl (mg/L) Ca (mg/L) 12 / 0 5 / 2 0 1 2 3 8 5 1 0 . 0 1 2 7 2 4 5 4 2 1 / 4 2 / 2 8 6 . 0 2 / 0 6 . 8 0. 0 / 9 3 . 0 - 1 5 . 0 9 . 7 3 5 0 4 0 12 / 0 6 / 2 0 1 2 8 5 0 1 0 . 1 5 1 5 2 3 4 5 0 2 3 / 3 9 / 4 6 5 . 2 2 / 0 7 . 3 0 . 0 / 9 2 . 5 - 1 7 . 5 9 . 3 4 0 0 4 0 12 / 0 7 / 2 0 1 2 1 8 3 5 1 0 . 2 0 1 1 6 3 5 4 2 1 8 / 3 9 / 4 3 5 . 6 2 / 0 7 . 8 0 . 0 / 9 2 . 0 1 . 0 1 5 . 0 9 . 5 4 0 0 2 0 12 / 0 8 / 2 0 1 2 2 7 7 5 1 0 . 2 0 9 6 2 7 4 2 1 7 / 2 9 / 3 3 5 . 1 2 / 0 7 . 8 0 . 0 / 9 2 . 0 0 . 5 1 2 . 5 9 . 9 4 0 0 4 0 12 / 0 9 / 2 0 1 2 2 9 8 0 1 0 . 5 0 1 1 8 4 1 5 4 1 6 / 2 2 / 3 1 5 . 0 2 / 0 8 . 8 0 . 0 / 9 1 . 0 0 . 5 1 5 . 0 9 . 8 3 5 0 4 0 12 / 1 0 / 2 0 1 2 2 9 8 0 1 0 . 5 5 7 3 4 0 2 9 1 1 / 1 9 / 2 2 4 . 8 2 / 0 9 . 3 0 . 0 / 9 0 . 5 0 . 5 1 2 . 5 9 . 5 3 5 0 2 0 12 / 1 1 / 2 0 1 2 2 9 8 0 1 0 . 5 5 7 2 3 8 2 6 1 2 / 1 8 / 2 2 5 . 2 2 / 0 8 . 8 0 . 0 / 9 1 . 0 0 . 5 1 2 . 5 9 . 0 3 0 0 4 0 12 / 1 2 / 2 0 1 2 2 9 8 0 1 0 . 5 5 7 0 3 7 2 7 1 3 / 1 9 / 2 2 5 . 0 2 / 0 9 . 3 0 . 0 / 9 0 . 5 0 . 5 1 2 . 5 9 . 0 3 5 0 2 0 Ab b r e v i a t i o n s MW = M u d W e i g h t V I S = F u n n e l V i s c o s i t y P V = P l a s ti c V i s c o s i t y Y P = Y i e l d P o i n t Ge l s = G e l S t r e n g t h F L = F i l t r a t e L o s s F C = F i l t e r C a k e S o l s = S o l i d s O/ W = O i l t o W a t e r r a t i o S d = S a n d c o n t e n t C l = Ch l o r i d e s C a = H a r d n e s s SR U 1 4 B - 2 7 31 Co n t r a c t o r : B a r o i d Mu d T y p e : E Z M u d 6 % K C l Da t e De p t h (f t ) MW (p p g ) VI S (s / q t ) PV Y P G e l s FL (c c ) So l s (% ) O/ W Ra t i o Sd (% ) MB T (p p b eq . ) pH Al k (P m ) Cl (mg/L) Ca (mg/L) 12 / 1 3 / 2 0 1 2 2 9 8 0 9 . 9 5 5 1 1 0 2 0 6 / 7 / 9 4 . 4 5 . 6 0 / 9 3 - 5. 0 8 . 0 - 2 7 0 0 0 4 8 0 12 / 1 4 / 2 0 1 2 3 2 1 5 1 0 . 6 4 9 1 2 2 1 6 / 1 0 / 1 2 4 . 8 8 . 4 0 / 9 0 - 5 . 0 9 . 0 0 . 0 3 3 2 0 0 0 4 8 0 12 / 1 5 / 2 0 1 2 4 2 2 7 1 0 . 4 8 4 7 1 2 2 3 8 / 1 3 / 1 6 4 . 7 7 . 6 0 / 9 0 - 3 . 8 8 . 6 0 . 1 6 3 0 0 0 0 4 8 0 12 / 1 6 / 2 0 1 2 4 7 9 7 1 0 . 4 8 4 4 1 1 2 2 8 / 1 4 / 1 9 5 . 2 8 . 5 0 / 8 9 .2 0 . 1 5 5 . 0 8 . 7 0 . 1 8 2 9 5 0 0 4 6 0 12 / 1 7 / 2 0 1 2 5 5 8 9 1 0 . 4 8 4 6 1 3 2 5 8 / 1 4 / 2 0 5 . 2 9 . 6 0 / 8 8 .2 0 . 2 5 5 . 0 8 . 5 0 . 1 0 2 8 0 0 0 4 4 0 12 / 1 8 / 2 0 1 2 6 1 8 5 1 0 . 5 4 4 1 2 2 1 6 / 1 0 / 1 6 5 . 2 9 . 5 0 / 8 8 . 2 0 . 1 5 5 . 0 8 . 7 0 . 1 5 3 0 0 0 0 4 0 0 12 / 1 9 / 2 0 1 2 6 6 3 6 1 0 . 5 4 6 1 6 2 3 6 / 1 3 / 1 9 4 . 6 9 . 5 0 / 8 8 . 2 0 . 1 0 5 . 5 9 . 1 0 . 3 5 3 0 0 0 0 4 0 0 12 / 2 0 / 2 0 1 2 7 0 6 5 1 0 . 4 7 4 6 1 6 1 7 5 / 9 / 1 3 4 . 4 9 . 5 0 / 8 8 . 2 0 . 1 0 5 . 5 9 . 0 0 . 3 0 3 0 0 0 0 3 8 0 12 / 2 1 / 2 0 1 2 7 3 7 8 1 0 . 5 4 3 1 7 2 0 5 / 1 0 / 1 5 4 . 6 9 . 5 0 / 8 8 . 2 0 . 1 5 5 . 5 9 . 0 0 . 3 0 3 0 0 0 0 4 0 0 12 / 2 2 / 2 0 1 2 7 3 7 8 1 1 . 2 4 8 2 6 1 7 5 / 9 / 1 5 4 . 6 1 2 . 1 0 / 8 5 . 6 0 . 2 5 6 . 0 9 . 1 0 . 3 5 3 1 0 0 0 3 2 0 12 / 2 3 / 2 0 1 2 7 4 5 4 1 1 . 8 4 4 1 8 1 6 4 / 1 3 / 1 8 5 . 5 1 4 . 2 0 / 8 3 .5 0 . 2 0 6 . 5 9 . 2 0 . 3 7 3 1 0 0 0 2 6 0 12 / 2 4 / 2 0 1 2 7 6 3 0 1 2 . 0 5 4 5 1 8 1 8 5 / 1 5 / 2 1 6 . 5 1 5 . 4 0 / 8 2. 5 0 . 1 5 6 . 5 1 0 . 0 0 . 6 5 2 9 0 0 0 2 0 0 12 / 2 5 / 2 0 1 2 7 8 3 5 1 2 . 5 4 8 2 0 2 0 9 / 1 9 / 2 4 5 . 5 1 7 . 6 0 / 8 0 .2 0 . 1 0 7 . 5 8 . 9 0 . 2 5 3 1 0 0 0 2 0 0 12 / 2 6 / 2 0 1 2 8 0 6 4 1 2 . 5 5 4 8 2 6 1 6 5 / 1 7 / 2 1 4 . 8 1 7 . 8 0 / 8 0. 0 0 . 1 0 7 . 5 9 . 5 0 . 2 5 3 1 0 0 0 2 0 0 12 / 2 7 / 2 0 1 2 8 0 6 4 1 2 . 8 5 5 6 2 6 2 1 5 / 1 6 / 2 0 4 . 8 1 9 . 1 0 / 7 8. 6 0 . 1 0 9 . 0 9 . 2 0 . 2 5 3 3 0 0 0 2 0 0 12 / 2 8 / 2 0 1 2 8 0 6 4 1 2 . 8 6 0 2 6 2 5 6 / 1 8 / 2 3 4 . 9 1 9 . 3 0 / 7 8 .8 0 . 1 0 9 . 0 9 . 5 0 . 2 5 2 8 0 0 0 2 8 0 12 / 2 9 / 2 0 1 2 8 0 9 0 1 2 . 8 5 8 2 8 2 1 5 / 1 8 / 2 0 4 . 4 1 8 . 8 0 / 7 9 .0 0 . 1 0 7 . 5 9 . 6 0 . 2 5 3 2 0 0 0 2 0 0 12 / 3 0 / 2 0 1 2 8 4 4 0 1 2 . 7 5 9 3 4 1 9 4 / 1 2 / 1 7 2 . 6 1 8 . 7 0 / 7 9 .0 0 . 1 0 6 . 5 9 . 2 0 . 2 5 3 3 0 0 0 2 0 0 12 / 3 1 / 2 0 1 2 8 9 8 7 1 2 . 8 5 9 3 8 2 4 4 / 1 0 / 1 5 2 . 8 1 9 . 1 0 / 7 8 .5 0 . 1 0 7 . 5 9 . 5 0 . 2 5 3 5 0 0 0 2 0 0 01 / 0 1 / 2 0 1 3 9 4 6 9 1 2 . 8 6 0 3 8 2 1 4 / 1 0 / 1 5 3 . 0 1 8 . 6 0 / 7 9 .0 0 . 1 0 9 . 0 9 . 1 0 . 3 5 3 5 0 0 0 2 0 0 01 / 0 2 / 2 0 1 3 9 8 7 9 1 2 . 8 6 2 4 1 2 7 4 / 1 3 / 1 9 3 . 0 1 8 . 6 0 / 7 9 .0 0 . 1 0 8 . 5 9 . 7 0 . 4 0 3 5 0 0 0 1 6 0 01 / 0 3 / 2 0 1 3 1 0 1 1 0 1 2 . 7 6 5 4 3 2 4 4 / 1 3 / 1 8 2 . 9 1 8 . 1 0 / 7 9. 5 0 . 1 0 7 . 5 9 . 5 0 . 3 5 3 4 0 0 0 1 6 0 01 / 0 4 / 2 0 1 3 1 0 1 1 0 1 3 . 1 5 6 5 3 7 2 4 4 / 1 5 / 2 0 2 . 8 1 8 . 3 0 / 79 . 5 0 . 1 0 9 . 5 9 . 2 0 . 2 5 3 2 0 0 0 1 6 0 01 / 0 5 / 2 0 1 3 1 0 1 1 0 1 3 . 1 5 6 1 3 3 1 8 3 / 1 3 / 1 8 2 . 6 1 9 . 5 0 / 78 . 5 0 . 1 0 9 . 5 9 . 9 0 . 5 5 2 9 0 0 0 2 0 0 01 / 0 6 / 2 0 1 3 1 0 1 1 0 1 3 . 1 5 6 2 3 5 1 8 4 / 1 4 / 2 1 3 . 2 2 0 . 0 0 / 78 . 0 0 . 1 0 9 . 0 9 . 2 0 . 3 0 3 0 0 0 0 2 0 0 01 / 0 7 / 2 0 1 3 1 0 1 1 0 1 3 . 0 5 5 6 2 8 1 7 3 / 1 1 / 1 5 3 . 0 2 0 . 0 0 / 78 . 0 0 . 1 0 9 . 0 1 0 . 2 0 . 6 0 3 0 0 0 0 2 0 0 Ab b r e v i a t i o n s MW = M u d W e i g h t V I S = F u n n e l V i s c o s i t y P V = P l a s ti c V i s c o s i t y Y P = Y i e l d P o i n t Ge l s = G e l S t r e n g t h F L = F i l t r a t e L o s s F C = F i l t e r C a k e S o l s = S o l i d s O/ W = O i l t o W a t e r r a t i o S d = S a n d c o n t e n t C l = Ch l o r i d e s C a = H a r d n e s s SR U 1 4 B - 2 7 32 Co n t r a c t o r : B a r o i d Mu d T y p e : E Z M u d 6 % K C l Da t e De p t h (f t ) MW (p p g ) VI S (s / q t ) PV Y P G e l s FL (c c ) So l s (% ) O/ W Ra t i o Sd (% ) MB T (p p b eq . ) pH Al k (P m ) Cl (mg/L) Ca (mg/L) 01 / 0 8 / 2 0 1 3 1 0 1 1 0 1 3 . 1 0 7 3 3 6 2 1 3 / 1 3 / 1 8 3 . 2 2 0 . 0 0 / 78 . 0 0 . 1 0 9 . 0 8 . 7 0 . 1 0 2 9 0 0 0 2 0 0 01 / 0 9 / 2 0 1 3 1 0 1 1 0 1 1 . 5 5 6 2 3 1 5 4 / 1 3 / 1 8 4 . 0 1 2 . 9 0 / 8 5. 0 0 . 1 0 6 . 0 9 . 0 0 . 1 0 2 9 0 0 0 3 6 0 01 / 1 0 / 2 0 1 3 1 0 1 1 0 9 . 8 6 2 1 3 1 5 4 / 1 0 / 1 5 4 . 8 5 . 5 0 / 9 2 . 0 0 . 1 0 7 . 0 8 . 9 0 . 1 0 3 1 0 0 0 2 0 0 01 / 1 1 / 2 0 1 3 1 0 1 1 0 9 . 5 8 5 6 1 3 1 6 4 / 1 1 / 1 6 4 . 4 4 . 5 0 / 9 3 .0 0 . 1 0 5 . 0 8 . 5 0 . 1 0 3 1 0 0 0 2 0 0 01 / 1 2 / 2 0 1 3 1 0 4 9 5 9 . 6 5 0 1 4 1 8 4 / 9 / 1 1 4 . 6 4 . 6 0 / 9 3 . 0 0 . 1 0 5 . 0 9 . 6 0 . 5 0 2 9 0 0 0 7 6 0 01 / 1 3 / 2 0 1 3 1 1 1 9 8 9 . 8 5 4 6 1 8 2 1 4 / 7 / 1 1 3 . 8 6 . 0 0 / 9 1 . 5 0 . 1 0 5 . 0 9 . 2 0 . 5 0 3 1 0 0 0 4 4 0 01 / 1 4 / 2 0 1 3 1 1 3 2 0 1 1 . 4 5 4 7 2 2 2 3 5 / 7 / 9 2 . 9 1 1 . 9 0 / 8 6 .0 0 . 1 0 3 . 5 1 0 . 2 0 . 6 5 2 8 0 0 0 4 0 0 01 / 1 5 / 2 0 1 3 1 1 3 2 0 1 1 . 5 5 6 2 3 2 3 6 / 8 / 1 1 3 . 2 1 2 . 3 0 / 8 5 .5 0 . 1 0 3 . 5 9 . 2 0 . 3 5 3 0 0 0 0 4 0 0 01 / 1 6 / 2 0 1 3 1 1 3 2 0 1 1 . 5 5 3 2 1 1 9 6 / 1 0 / 1 3 3 . 9 1 2 . 4 0 / 8 5. 5 0 . 1 0 5 . 0 9 . 2 0 . 2 5 2 8 0 0 0 4 0 0 01 / 1 7 / 2 0 1 3 1 1 3 2 0 1 1 . 5 5 3 2 1 1 8 6 / 9 / 1 0 4 . 0 1 2 . 4 0 / 8 5 .5 0 . 1 0 5 . 0 8 . 5 0 . 1 5 2 8 0 0 0 4 0 0 Ab b r e v i a t i o n s MW = M u d W e i g h t V I S = F u n n e l V i s c o s i t y P V = P l a s ti c V i s c o s i t y Y P = Y i e l d P o i n t Ge l s = G e l S t r e n g t h F L = F i l t r a t e L o s s F C = F i l t e r C a k e S o l s = S o l i d s O/ W = O i l t o W a t e r r a t i o S d = S a n d c o n t e n t C l = Ch l o r i d e s C a = H a r d n e s s SCU 14B-27 33 5 DAILY REPORTS SRU 14B-27 34 6 SHOW REPORTS
