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212-146
1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Convert to Prod Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 11,250 feet 10,875 feet true vertical 11,098 feet 10,191 feet Effective Depth measured 10,876 feet 10,070 feet true vertical 10,752 feet 9,999 feet Perforation depth Measured depth True Vertical depth Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5# / L-80 10,117' MD 10,043' TVD Arrowset Packers and SSSV (type, measured and true vertical depth)AS1-X 10,070' MD 9,999' TVD N/A 12. Stimulation or cement squeeze summary:N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Josh Allely Authorized Title:Operations Manager Contact Email:josh.allely@hilcorp.com Contact Phone:907-777-8505 2. Operator Name Senior Engineer:Senior Res. Engineer: 7910 psi Collapse 1130 psi 5760 psi 6590 psi Burst 2730 psi 7440 psi 11,250 TVD 28 1496 10263 11098 Casing Structural 22" 13-3/8" 6-5/8" Length 28 1496 10350 Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: Liner 1100 5. Permit to Drill Number: 0 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A 1180 Size Swanson River Field / Hemlock OilN/A 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf measuredPlugs Junk measured N/A A028890 1100 1100 Soldotna Creek Unit (SCU) 43A-33 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 212-146 50-133-10168-01-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 11800 Casing Pressure Tubing Pressure 0 Oil-Bbl measured true vertical Packer 4" 10350 Hilcorp Alaska, LLC See Attached Schematic See Attached Schematic WINJ WAG 0 Water-Bbl MD 28' 1496 t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 1:49 pm, Aug 17, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.08.17 13:39:58 -08'00' Taylor Wellman (2143) BJM 10/20/21 RBDMS HEW 8/19/2021 DSR-8/18/21 ___________________________________________________________________________________ Downhole Revised: 11/7/16 Updated by CAH 10-12-18 SCHEMATIC Soldotna Creek Unit Well: SCU 43A-33 Completion Ran: 11/28/2012 PTD: 212-146 API: 50-133-10168-01 PBTD = 10,875’ MD/ 10,752’ TVD TD = 11,250’ MD/ 11,098’ TVD Max Deviation 24° @ 10,716’ Ground Elev: 124’ Above MSL KB-THF: 20.25’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 22” Conductor - - - Surf 28’ 13-3/8" Surf. Csg 54.5 J-55 BTC 12.25 Surf 1,496’ 6-5/8" Intermediate 28 P-110 BTC 5.665 Surf 127’ 24 N-80 BTC 5.796 127’ 6,600’ 28 P-110 BTC 5.665 6,600’ 6,607’ 24 P-110 BTC 5.796 6,607’ 10,165’ 28 P-110 BTC 5.665 10,165’ 10,353’ 4" Prod Lnr 9.5 L-80 VAM STL 3.548" 10,131’ 11,250’ TUBING DETAIL 2-7/8” Production 6.5 L-80 8RD 2.441” Surf 10,117’ 1 6 9 7 22” 13-3/8” 8 11 3 4 5 10 12 13 4” JEWELRY DETAIL No. Depth ID OD Item 1 20’ 2.992” - Tubing Hanger 2 21’ 2.441” 3.500” XO 3-1/2” IBT Pin x 2-7/8” 8RD Pin 3 3,287’ 2.441” 4.750” SFO-1 Mandrel 4 5,395’ 2.441” 4.750” SFO-1 Mandrel 5 6,807’ 2.441” 4.750” SFO-1 Mandrel 6 7,992’ 2.441” 4.750” SFO-1 Mandrel 7 8,896’ 2.441” 4.750” SFO-1 Mandrel 8 9,516’ 2.441” 4.750” SFO-1 Mandrel 9 10,009’ 2.441” 4.750” SFO-1 Mandrel 10 10,058’ 2.313” 5.500” On/Off Tool w/ X-Nipple 11 10,070’ 2.375” 5.500” Arrowset AS1-X Mechanical Packer 12 10,083’ 2.313” 3.500” X-Nipple 13 10,116’ 2.441” 3.500” WL Entry Guide 14 10,875’ - 2.350” Inflatable bridge plug (rubber pierced with spear) 15 10,917’ - 1.750” Fish – 1.75” Pump Bailer (3’ Long) (Fell Down Hole) 16 10,917’ - 2.125” Inflatable bridge plug (5’ of sand) (Fell Down Hole) 17 10,920’ - 2.125” Inflatable bridge plug (4’ of sand) 6-5/8” PERFORATION DETAIL Date Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) SPF Ft Phase Comments 1/26/13 H2 10,676’ 10,686’ 10,570’ 10,579’ 6 10 60 2-1/8”HC 1/25/13 H2 10,686’ 10,696’ 10,579’ 10,588’ 6 10 60 2-1/8”HC 1/25/13 H3 10,705’ 10,710’ 10,596’ 10,601’ 6 5 60 2-1/8”HC 1/25/13 H3 10,710’ 10,719’ 10,601’ 10,609’ 6 9 60 2-1/8”HC 1/25/13 H4 10,719’ 10,720’ 10,609’ 10,610’ 6 1 60 2-1/8”HC 1/17/13 H4 10,720’ 10,730’ 10,610’ 10,619’ 6 10 60 2-1/8”HC 1/17/13 H4 10,730’ 10,735’ 10,619’ 10,624’ 6 5 60 2-1/8”HC 1/17/13 H5 10,735’ 10,740’ 10,624’ 10,628’ 6 5 60 2-1/8”HC 1/17/13 H5 10,740’ 10,750’ 10,628’ 10,637’ 6 10 60 2-1/8”HC 1/16/13 H5 10,750’ 10,760’ 10,637’ 10,646’ 6 10 60 2-1/8”HC 1/16/13 H5 10,760’ 10,770’ 10,646’ 10,655’ 6 10 60 2-1/8”HC 1/15/13 H7 10,819’ 10,828’ 10,700’ 20,709’ 6 10 60 2-1/8”HC 12/28/13 H7 10,819’ 10,831’ 10,700’ 10,711’ 6 12 60 2-1/8”HC 1/15/13 H7 10,828’ 10,838’ 10,709’ 10,718’ 6 10 60 2-1/8”HC 1/14/13 H7 10,838’ 10,848’ 10,718’ 10,727’ 6 15 60 2-1/8”HC 1/14/13 H7 10,848’ 10,850’ 10,727’ 10,729’ 6 2 60 2-1/8”HC 1/14/13 H8 10,850’ 10,858’ 10,729’ 10,736’ 6 8 60 2-1/8”HC 12/8/12 H9 10,929’ 10,931’ 10,801’ 10,803’ 6 2 60 Isolated 12/8/12 H9,10 10,931’ 10,946’ 10,803’ 10,817’ 6 15 60 Isolated 12/4/12 H10 10,944’ 10,967’ 10,815’ 10,836’ 6 23 60 Isolated Top of Liner Hanger @ 10,131’ 17 H-8 H-10 H-2 H-3 H-4 H-5 H-9 H-9,10 H-7 2 5-5/8” hole X 16 14, 15 CBL TOC 7,300’ (3/3/61) Tagged fish (inflatable bridge plug) @ 10,191’ SLM on 9/9/18 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS RECEIVED FEB 0 5 2019 1. Operations Abandon LJ Plug Perforations LJ Fracture Stimulate LJ Pull Tubing Li Operations shutdoym LJ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: Convert to Prod Wtr Injection ❑� 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development Q Stratigraphic❑ Exploratory ❑ Service ❑ 212-146 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-133-10168-01-00 7. Property Designation (Lease Number): 8. Well Name and Number: A028890 Soldotna Creek Unit (SCU) 43A-33 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 11,250 feet Plugs measured 10,875 feet true vertical 11,098 feet Junk measured 10,191 feet Effective Depth measured 10,876 feet Packer measured 10,070 feet true vertical 10,752 feet true vertical 9,999 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 28' 22" 28' 28' Surface 1,496' 13-3/8" 1,496' 1,496' 2,730 psi 1,130 psi Intermediate 10,350' 6-5/8" 10,350' 10,263' 7,440 psi 5,760 psi Production Liner 1,100' 4" 11,250' 11,098' 7,910 psi 6,590 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 10,117' MD 10,043' TVD Arrowset 10,070' MD Packers and SSSV (type, measured and true vertical depth) AS1-X 9,999' TVD 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: 0 0 0 620 750 Subsequent to operation: 0 0 450 480 700 14. Attachments (required per 20 AAC 25.070, 25.071, s 25.283) 15. Well Class after work: Daily Report of Well Operations ❑Q Exploratory❑ Development ❑ Service Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil LJ WDSPL Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑✓ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 318-463 e Authorized Name: Bo York 777-8345 Contact Name: Taylor Nasse Authorized Title: Operations Manager Contact Email: tnasse(ftilcorp.com Authorized Signature: • Date: Lf F% -Sp t Contact Phone: 777-8354 Form 10-404 Re d 4/2017Z _ ) Z _ I��� RBDM .B 1 1 2019 Submit Original Only ko" 411f /i Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SCU 43A-33 NA A 50-133-10168-01-00 212-146 11/4/18 2/1/19 Daily Operations: 11/04/2018-Sunday Water injection was first reported on the morning report on 11/4/18. Daily Injection Rate from Field Report: 781 bbls 11/05/2018 - Monday Daily Injection Rate from Field Report: 1910 bbls 11/06/2018-Tuesday Daily Injection Rate from Field Report: 1586 bbis 11/07/2018- Wednesday Daily Injection Rate from Field Report: 1507 bbls 11/08/2018 - Thursday Daily Injection Rate from Field Report: 1434 bbls 11/09/2018 - Friday Daily Injection Rate from Field Report: 7486 bbis 11/10/2018 - Saturday Daily Injection Rate from Field Report: 1203 bbls 11/11/2018-Sunday Daily Injection Rate from Field Report: 897 bbls 11/12/2018 - Monday Daily Injection Rate from Field Report: Ran MIT after the well stabilized. 934 bbls 02/01/2019 - Friday RU slickline. PT lubricator to 2,500 psig. RIH w/ 2" DD bailer to 10,151 and tag. POOH. RIH w/ 2.27" GR to 2,500', POOH w/ paraffin on GR. RIH w/ 2.3" helix cutter to 1,500'. POOH. Turn over to Operations to begin injection. 2'' Soldotna Creek Unit Well: SCU 14 SCHEMATIC CompPTD: 112-146Ran: an: 11/25/2012 Hilvura Alaxka, LU: API: 50-133-10168-01 Ground Elev: 124' Above MSL KB -THF: 20.25' PBTD = 10,875' MD/ 10,752' ND TD = 11,250' MD/ 11,098' TVD Max Deviation 24' @ 10,716' OC /3/61) Liner 10,131' CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 22" Conductor 2 - 2.441" - Surf 28' 13-3/8" Surf. Csg 54.5 J-55 BTC 12.25 Surf 1,496' SFO -1 Mandrel (dummy valve) 5 28 P-110 BTC 5.665 Surf 127' 2.441" 4.750" 24 N-80 BTC 5.796 127' 6,600' 6-5/8" Intermediate 28 P-110 BTC 5.665 6,600' 6,607' 4.750" SFO -1 Mandrel (dummy valve) 24 P-110 BTC 5.796 6,607' 10,165' 10,070' 2.375" 28 P-110 BTC 5.665 10,165' 10,353' 4" Prod Lnr 9.5 L-80 VAM STL 3.548" 10,131' 11,250' TUBING DETAIL 2-7/8" Production 6.5 L-80 8RD 2.441" 1 Surf 10,117' JEWELRY DETAIL No. Depth ID OD Item 1 20' 2.992" - Tubing Hanger 2 21' 2.441" 3.500" XO 3-1/2" IBT Pin x 2-7/8" 8RD Pin 3 3,287' 2.441" 4.750" SFO -1 Mandrel (dummy valve)) 4 5,395' 2.441" 4.750" SFO -1 Mandrel (dummy valve) 5 6,807' 2.441" 4.750" SFO -1 Mandrel (dummy valve) 6 7,992' 2.441" 4.750" SFO -1 Mandrel (dummy valve) 7 8,896' 2.441" 4.750" SFO -1 Mandrel (dummy valve) 8 9,516' 2.441" 4.750" SFO -1 Mandrel (dummy valve) 9 1 10,009' 2.441" 4.750" SFO -1 Mandrel (dummy valve) 10 10,058' 2.313" 1 5.500" On/Off Tool w/X-Nipple 11 10,070' 2.375" 5.500" Arrowset AS1-X Mechanical Packer 12 10,083' 2.313" 3.500" X -Nipple 13 10,116' 2.441" 3.500" WL Entry Guide 14 10,875' - 2.350" Inflatable bridge plug (rubber pierced with spear) 15 10,917' - 1.750" Fish -1.75" Pump Bailer (3' Long) (Fell Down Hole) 16 10,917' - 2.125" Inflatable bridge plug (5' of sand) (Fell Down Hole) 17 10,920' - 2.125" Inflatable bridge plug (4' of sand) Tagged fish (inflatable bridge plug) @ 10,191' SLM on 919/18 Downhole Revised: 11/7/16 Updated by CAH 10-12-I8 PERFORATION DETAIL )ate Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) SPF Ft Phase Comments 26/13 H2 10,676' 10,686' 10,570' 10,579' 6 10 60 2-1/8"HC 25/13 H2 10,686' 10,696' 10,579' 10,588' 6 10 60 2-1/8"HC 25/13 H3 10,705' 10,710' 10,596' 10,601' 6 5 60 2-1/8"HC 25/13 H3 10,710' 10,719' 10,601' 10,609' 6 9 60 2 -1/8 -HC 25/13 H4 10,719' 10,720' 10,609' 10,610' 6 1 60 2-1/8"HC 17/13 H4 10,720' 10,730' 10,610' 10,619' 6 10 60 2-1/8"HC 17/13 H4 10,730' 10,735' 10,619' 10,624' 6 5 60 2-1/8"HC 17/13 HS 10,735' 10,740' 10,624' 10,628' 6 5 60 2-1/8"HC 17/13 H5 10,740' 10,750' 10,628' 10,637' 6 10 60 2-1/8"HC 16/13 HS 10,750' 10,760' 10,637' 10,646' 6 10 60 2-1/8"HC 16/13 H5 10,760' 10,770' 10,646' 10,655' 6 10 60 2-1/8"HC 15/13 H7 10,819' 10,828' 10,700' 20,709' 6 10 60 2 -1/8 -HC /28/13 H7 10,819' 10,831' 10,700' 10,711' 6 12 60 2-1/8"HC 15/13 H7 10,828' 10,838' 10,709' 10,718' 6 10 60 2-1/8"HC 14/13 H7 10,838' 10,848' 10,718' 10,727' 6 15 60 2-1/8"HC 14/13 H7 10,848' 10,850' 10,727' 10,729' 6 2 60 2-1/8"HC 14/13 1-18 10,850' 10,858' 10,729' 10,736' 6 8 60 2-1/8'HC :/8/12 H9 10,929' 10,931' 10,801' 10,803' 6 2 60 Isolated !/8/12 H9,30 10,931' 10,946' 10,803' 10,817' 6 15 60 Isolated !/4/12 H10 10,944' 1 10,967' 1 10,815' 1 10,836' 6 23 1 60 Isolated Tagged fish (inflatable bridge plug) @ 10,191' SLM on 919/18 Downhole Revised: 11/7/16 Updated by CAH 10-12-I8 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: 1m reaoayalaska.gov: AOGCC InsOectomA.I.skaAOV: ohoebe breaks®alaslustat OPERATOR: Hilcorp Alaska LLC FIELD / UNIT / PAD: Swanson River Field/Soldotna Creek Univ 43A-33 Pad DATE: 11/12/18 OPERATOR REP: Taylor Malone AOGCC REP: Witness Waived chriswallace®altri a.00v Well SCU 43A-33 Pressures: Pretest Initial 15 Min. W Min. 45 Min. 60 Min. 0= Other(deecnCe In Notes) 4=Four Year Cycle PTD 212-146 Type Ing W Tubing 1 725 ]25 725 ]25 725 125 Type Test P Packer NO 10,070' BBLPump IA 0 2510 2510 2510 2510 2509 Interval 4 Test psi 2510 BBL Retuml I OA 1 39 39 39 39 39 39 Result P Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBLPump IA Interval Test par BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min, 60 Min. PTD Type Inj Tubing Type Test Packer ND BBLPump IA Interval Test psi BBL Retum OA Result Notes: Well Pressures: Pretest Initial 15 Min. W Min. 45 Min. 80 Min. PTD Type Inj Tubing Type Test Packer ND BBLPump IA Interval Test psi BBL Retum OA Result Notes: well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi I BBL ReIum OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type lnl Tubing Type Test Packer ND BBLPump IA Interval Test psi BBL Reboil OA Result Nates: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL ReIum OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TV BBLPump IA Interval Test psi BBL Retuml I OA I Result Notes: TYPE INJ Codes TYPE TEST Codes INTERVAL_ Codes Resulteodes W=Water P=Pressure Tend 1=1nMal Test P=Penn G=Core 0= Other(deecnCe In Notes) 4=Four Year Cycle F=Fit S=Slurry V= Reeuired try valance 1=lrmncluaro I=industrial Weetewater 0= Other(aescnce In notes) N = Not Inlecong Form 10426 (Revised 01/201 ]) mass MIT 11-12-1e Data Collection Report Chassis Left Scale Right Scale Serial Number 476741 475325 688896 Datatype Lower Upper Units PSI G PSI G Lower PSI G 45 40 35 30 25 20 15 10 5 0 O 000 00. 43a-33 - 12 -Nov -18, 04:53:20, 435 U PSI G 3500 3000 2500 2000 1500 1000 500 0 b ry6`L O^ `56 00 00 00 00 00. O^ Elapsed Time hh:mm:ss 5C Ll 4_�Ar-33 OT)b z(7-14(,0 Regg, James B (DOA) From: Brooks, Phoebe L (DOA) Sent: Monday, December 24, 201811:47 AMCl4tci tZIZ9lIQj To: Daniel Faulk (( Cc: Regg, James B (DOA) Subject: FW: [EXTERNAL] RE: MIT Test Report Attachments: MIT SCU 344-33 11-12-18 Revised.xlsx; MIT SCU 43A-33 11-12-18 Revised.xlsx Daniel, Attached are revised reports as follows: • MIT SCU 344-33 11-12-18 — Packer TVD was changed to 10152' and the interval was changed to "I" (initial) • MIT SCU 43A-33 11-12-18 — Interval was changed to "I" The volumes pumped/returned were left blank on both reports; please advise. Thank you, Phoebe Phoebe Brooks Statistical Technician II Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@;alaska.gov. From: Regg, James B (DOA) Sent: Monday, December 24, 2018 9:35 AM To: Brooks, Phoebe L (DOA) < Phoebe. brooks @alaska.gov> Subject: FW: [EXTERNAL] RE: MIT Test Report I think they are showing the MD of the packer on the MIT form. Well schematic from Sundry 318-469 attached (sundry form incorrectly shows NA in packer block). I calculate the Packer TVD as 10152 ft. Jim Regg Supervisor, Inspections AOGCC 333 W.7'h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.¢ov. From: Ted Kramer <tkramer@hilcorp.com> Sent: Monday, December 24, 2018 8:59 AM To: Regg, James B (DOA) <jimregg@alaska.gov> Cc: Taylor Malone <tmalone hilcorp.com> Subject: FW: [EXTERNAL] RE: MIT Test Report Jim, Attached please find the Deviation Survey for the SCU 344-33. Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC - 0 907-777-8420 C 985-867-0665 From: Taylor Malone Sent: Sunday, December 23, 2018 7:34 AM To: Ted Kramer <tkramer@hilcorp.com> Cc: Daniel Paulk <dpaulk hilcorp.com> Subject: FW: [EXTERNAL] RE: MIT Test Report Hello Ted, As discussed earlier on the phone please see email from Jim Regg below. I am assuming he is looking for the definitive survey report that was performed by Haliburton. If this is the case let me know and I can forward that to him. Thanks, Taylor Malone From: Regg, James B (DOA) [mailto:iim.regg@alaska.gov] Sent: Thursday, December 20, 2018 10:10 AM To: Daniel Paulk <dpaulk@hilcorp.com>; Taylor Malone <tmalone@hilcorp.com> Cc: Brooks, Phoebe L (DOA) <phoebe brooks@alaska gov> Subject: [EXTERNAL] RE: MIT Test Report Please provide the directional survey for SCU 344-33 (PTD 2180540) so we can verify the packer TVD from the reported measure depths on Hilcorp's well schematic. Jim Regg Supervisor, Inspections AOGCC 333 W.7'h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.re¢¢@alaska.eov. From: Regg, lames B (DOA) Sent: Wednesday, December 5, 2018 12:02 PM To:'Daniel Paulk' <dpaulk@hilcorp.com> Cc: Brooks, Phoebe L (DOA) <phoebe.brooks@alaska.gov> Subject: RE: MIT Test Report Also need directional survey for well 344-33. Jim Regg Supervisor, Inspections AOGCC 333 W.7'h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state orfederal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or im.re¢¢@alaska.Rov. From: Regg, James B (DOA) Sent: Wednesday, December 5, 2018 10:59 AM To:'Daniel Paulk' <dpaulk@hilcorp.com> Cc: Brooks, Phoebe L (DOA) <Phoebe.brooks@alaska.gov> Subject: RE: MIT Test Report volumes pumped/returned for tests? Jim Regg Supervisor, Inspections AOGCC 333 W.7'h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.re¢eClalaska.gov. From: Daniel Paulk <dpaulk@hilcorp.com> Sent: Saturday, December 1, 2018 4:42 PM To: Regg, James B (DOA) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (DOA) <phoebe.brooks@alaska.Rov>; Wallace, Chris D (DOA) <chris.wallace@alaska.gov> Cc: Taylor Malone <tmalone@hilcorp.com> Subject: MITTest Report Please see attachment the Report from the post injection MIT on 43A-33 and 344-33. Submdlo'. iim.reoaeMalaska.aov: OPERATOR: FIELD I UNIT I PAD: DATE: OPERATOR REP: AOGCC REP: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test AOCOC clorturibalatumoo, Phoebe,bmiqlorilalaska,orcy H Isom Alaska LLC Swanson River FielWSoldatna Creek Unit/ 43A-33 Pad Chns.wallacerMalaska J�� t�24�13 Well SCU 43A-33 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2121460 Type Inj W Tubing 725. 725 725 725 725 725 Type Test P Packer ND 9,999' BBL Pump IA 0 2510 2510 ' 2510' 2510 - 2509 Interval Test psi 2510 BBLRetum OA 39 39 39 39 39 . 39 Result P Notes: Post Injection MIT completed as per Suntlryp 316463. MIT test wMness was WOived by Jim Regg Well Pressures: Pretest Initial 15 Min. 30 Min, 45 Min. 60 Min. PTD Type lnj Tubing Tubing Type Test Packer ND BRL Pump Interval Test psi BBL Return OA Result Net..: Well Pressures: Pretest Initial 15 Min. 30 Min, 45 Min. 60 Min. PTDTypa lnl Tubing Type Test Packer TVD BELPump IA Interval Test psi BBL ReturnOA Result Notes: Well Pressures', Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTDType lnl Tubing Type Test Packer NO BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Net..: Weil Pressures'. Pretest Initial 15 Min. 30 Min, 45 Min. 60 Min. PTD Type Inj Tubing Typa Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result was: Wall Pressures: Pretest Initial 15 Min. W Min. 45 Min. 60 Min. PTD Type Inj Tubing I I I Type Test Packer ND BBL Pump IA Interval Test psi BBL Retum OA Result Notes: Well Pressures: Pretest Initial 15 Min, 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL ReturnOA Result N TYPE INJ Colles W=Water G=Gal S = Slurry I = indisroal Waage tiler N = Not I'awn., WINE TEST Code. INTERVAL Codes P = Pleuwe Teal 1= Intlial Teal O= GM1er lEeacn[e in Notes) 4=Four Year cyde V = Rocu lee M Variance o= Olner (eeecnbein nmea) Form 10-426 Revised OV2017) MIT SCU 43A3311 -12-1a ReNSM Result CW- P =Pau F=Fail 1=lnconclueive �Glt 43A--33 PT1� 21 Z) 41d� Chassis Left Scale Right Scale Serial Number 476741 475325 688896 Datatype OA IA Units PSI G PSI G Lower Upper 43a-33 - 12 -Nov -18, 04:53:20, 435 ✓ 40 2700 39.5 2650 39 2600 38.5 2550 38 2500.2 37.5 ¢` 2450 37 2400 36.5 36 2350 35.5 2300 35 2250 b 0 L 0 lb - b Axis Tithe —MG —1 c THE STATE °fALASKA GOVERNOR BILL WALKER Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 43A-33 Permit to Drill Number: 212-146 Sundry Number: 318-463 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1 433 Fax: 907.276.7542 www.00gcc.claska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French }l Chair DATED this Zl� day of October, 2018. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25280 L- rJjS 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: Convert to Prod Wtr injector❑✓ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q' Stratigraphic ❑ Service 212-146 ' 3. Address: 3800 Centerpoint Dr, Suite 1400❑ 6. API Number: Anchorage Alaska 99503 50-133-10168-01 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? A10.13A Will planned perforations require a spacing exception? Yes ❑ No ❑✓ Soldotna Creek Unit (SCU) 43A-33 ' 9. Property Designation (Lease Number): 10. Field/Pool(s): A028890 Swanson River Field/ Hemlock Oil it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 11,250' 11,098' 10,875' 10,752'-1,000psi 10,875' 10,191' Casing Length Size MD TVD Burst Collapse Structural Conductor 28' 22" 28' 28' Surface 1,496' 13-3/8" 1,496' 1,496' 2,730psi 1,130psi Intermediate 10,353' 6-5/8" 10,353' 10,266' 7,440psi 5,760psi Production Liner 9,006' 4" 11,250' 11,098' 7.91 Ups! 6,590psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 2-7/8" 6.5# f L-80 10,117' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Arrowset AS1-X Mach; N/A 10,070' MD - 9,999' TVD; N/A 12. Attachments: Proposal Summary Q Wellbore schematic ❑v 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development ❑ Service Q 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: October 26, 2018 OIL ] WINJ 2 WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson 777-8405 Contact Name: Daniel Taylor Authorized Title: Operations Manager Contact Email: dte for hilcor .Corn Contact Phone: 777-8319 Authorized Signature: &IIIDate: MmIlp COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ,r - �� jU( / t t-057-/it.S. r�/ Mechanical Integrity Test I Location Clearance ❑ Plug Integrity El BOP Test El�I Other: Post Initial Injection MIT Req'd? Yes No ❑ Spacing Exception Required? Yes ❑ No ❑' Subsequent Form Required: APPROVED BY I lie (� ZS Approved by: COMMISSIONER THE COMMISSION Date: l vii /019 fY ��i�(1�� ;�-.isig ``-- Q n mit Form and 10-403 Revised 412017 Approved application is o 1 �Ftls r liat� of approval. Attachments in Duplicate U llilcugr Alaska, U, Well Prognosis Well: SCU 43A-33 Date:10/12/2018 Well Name: SCU_43A-33 API Number: 50-133-10168-01-00 Current Status: Offline Leg: N/A Estimated Start Date: October 261h, 2018 Rig: Moncla 401 Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 212-146 First Call Engineer: Daniel Taylor (907) 777-8319 (0) (907) 229-4824 (M) Second Call Engineer: Chad Helgeson (907) 777-8395 (0) Maximum Expected BHP: - 2,450 psi @ 10,050 TVD Based on SBHP taken 8/18/18 Max. Allowable Surface Pressure: -1,000 psi Maximum pump pressure for injection Brief Well Summary The intention of this work is to convert SCU_43A-33 from a producer to a produced water injector offering enhanced oil recovery to the offset well. The only offset well expected to respond is SCU_13-34. The work and injection will be in compliance with AIO 13A. - SCU_43A-33 is currently offline with inflatable plugs stuck in casing outside of the tubing tail. It last produced in Jan 2018 making <10bopd and-400bwpd. It is currently perforated only in the Hemlock within Benches Hl - HS (10,546ft TVD thru 10,697ft TVD) although communication to H5 is doubtful based on offset production profiles. The above referenced depths correlate within thei jection zone outlined in SCU_41-04 (10,085ft TVD thru 10,815ft TVD). I 6 Well 11 of PredJ' W'. rk cl V °►rel �K well Ove- 40 °�fi V;rtrafly iry ee r,rl LFa. if Jr Alm.' V QIZJW1oa wqf <10 6O P. Csnverrr,.V t -/Vs k4 FO SCU_13-34 is currently producing 71bpd with 24bopd (WC = 65%). It is open in the Tyonek G2 and Hemlock i'ASO"/Of H1 -H5. Ado ;Oyrr revoolp flop SCU_43A-33 passed a pre-injection MIT on 9/7/2018. A post injection MIT will be submitted within 7 days off hbf. injection. 4 /w -l�% Attachments: 1. Pre -Injection MIT 2. Current Schematic K Hllwee Almelo, LIX.. Ground Elev: 124' Above MSL KB -THF: 20.25' 1 2 13-3/8" 5 6 i® x 1 9 CBL TOC 7,300'(3/3/61) I �ty.,lA �dl �sv L. y Top of Liner Hanger @ 10,131' l H3 H-4 H-5 H7 H-8 14. 15 16 H-9 H-9,1 H-10 4 SCHEMATIC CASING DETAIL Soldotna Creek Unit Well: SCU 43A-33 Completion Ran: 11/28/2012 PTD: 212-146 API: 50-133-10168-01 Size Type Wt Grade Conn. ID Top Btm 22" Conductor - - 2.441" - Surf 28' 13-3/8" Surf. Csg 54.5 J-55 BTC 12.25 Surf 1,496' 6-5/8" Intermediate 28 P-110 BTC 5.665 Surf 127' 24 N-80 BTC 5.796 127' 6,600' 28 P-110 BTC 5.665 6,600' 6,607' 24 P-110 BTC 5.796 6,607' 10,165' 28 P-110 BTC 5.665 10,165' 10,353' 4" Prod Lnr 9.5 L-80 VAM STL 3.548" 10,131' 11,250' TUBING DETAIL 2-7/8" Production 6.5 L-80 BIRD 2.441" 1 Surf 10,117' JEWELRY DETAIL No. Depth ID OD Item 1 20' 2.992" Tubing Hanger 2 21' 2.441" 3.500' XO 3-1/2" IBT Pin x 2-7/8" 8RD Pin 3 3,287' 2.441" 4.750' SFO -1 Mandrel (dummy valve) 4 5,395' 2.441" 4.750" SFO -1 Mandrel (dummy valve) 5 6,807' 2.441" 4.750" SFO -1 Mandrel (dummy valve) 6 7,992' 2.441" 4.750" SFO -1 Mandrel (dummy valve) 7 8,896' 2.441" 4.750" SFO -1 Mandrel (dummy valve) 8 9,516' 2.441" 4.750" SFO -1 Man drel(dummy valve) 9 10,009' 2.441" 4.750' SFO -1 Mandrel (dummy valve) 10 1 10,058' 2.313" 1 5.500' On/Off Tool w/X-Nipple 11 10,070 2.375" 5.500" Arrowset ASI -X Mechanical Packer 12 10,083' 2.313" 3.500" X -Nipple 13 10,116' 2.441" 3.500" WL Entry Guide 14 10,875' - 2.350" Inflatable bridge plug (rubber pierced with spear) 15 10,917' - 1.750' Fish -1.75" Pump Bailer IT Long) (Fell Down Hole) 16 10,917' - 2.125" Inflatable bridge plug (5' of sand) (Fell Down Hole) 17 10,920 - 2.125" 1 Inflatable bridge plug (4' of sand) 5-5/8" hole PBTD = 10,875' MD/ 10,752' TVD TD = 11,250' MD/ 11,098' TVD Max Deviation 24` @ 10,716' Downhole Revised: 11/7/16 Tagged fish (inflatable bridge plug) @ 10,191' SLM on 9/9/18 Updated by CAH 10-12-18 PERFORATION DETAIL Date Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) SPF Ft Phase Comments 1/26/13 H2 10,676' 10,686' 10,570' 10,579' 6 10 60 2-1/8"HC 1/25/13 H2 10,686' 10,696• 10,579' 10,588' 6 10 60 2-1/8"HC 1/25/13 H3 10,705' ' 10,710. 10,596' 10,601' 6 5 60 2-1/8"HC 1/25/13 H3 10,710 10,719' ' 10,601' 10,609' 6 9 60 2-1/8"HC 1/25/13 H4 10,719' 10,720' • 10,609' 10,610' 6 1 60 2-1/8"HC 1/17/13 H4 10,720' • 10,730' • 10,610 10,619' 6 30 60 2 -1/8 -HC 1/17/13 H4 10,730' • 10,735' • 10,619' 10,624' 6 5 60 2-1/8"HC 1/17/13 H5 10,735'. 10,740' 10,624' 10,628' 6 5 60 2-1/8"HC 1/17/13 H5 10,740'- 10,750' 10,628' 10,637' 6 1 10 1 60 2-1/8"HC 1/16/13 H5 10,750'. 10,760• 10,637' 10,646' 6 1 10 60 2-1/8'HC 1/16/13 HS 10,760 • 10,770 • 10,646' 10,655' 6 10 60 2-1/8"HC 1/15/13 H7 10,819' ' 10,828' 10,700 20,709' 6 10 60 2-1/8"HC 12/28/13 H7 10,819'. 30,8331 10,700 10,711' 6 12 60 2-1/8"HC 1/15/13 H7 10,828' . 10,838' 10,709' 10,718' 6 10 60 2-1/8"HC 1/14/13 H7 10,838'- 10,848'. 10,718' 10,727' 6 15 60 2-1/8"HC 1/14/13 H7 10,848'- 10,850' 10,727' 10,729' 6 2 60 2-1/8"HC 1/14/13 H8 10,850' . 10,858' . 10,729' 10,736' 6 8 60 2-1/8"HC 12/8/12 H9 10,929' 10,931' . 10,801' 10,803' 6 2 60 Isolated 12/8/12 H9,10 10,931' 10,946' 10,803' 10,817 6 15 60 Isolated 12/4/12 H10 10,944 10,967' 10,815' 10,836' 6 1 23 60 Isolated 5-5/8" hole PBTD = 10,875' MD/ 10,752' TVD TD = 11,250' MD/ 11,098' TVD Max Deviation 24` @ 10,716' Downhole Revised: 11/7/16 Tagged fish (inflatable bridge plug) @ 10,191' SLM on 9/9/18 Updated by CAH 10-12-18 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: ornseco0alaska.00v: ACGCC.I nspectors(alelaska_av Phoebe brooksAalaska oo OPERATOR: Nilcom Alaska LLC FIELD / UNIT / PAD: Swanson River FieWS.1clema Creek Univ 43A33 Pad DATE: 09/07/18 OPERATOR REP: Daniel Paulk AOGCC REP: Waived Witness chis wallace/malaska uov Well SCU 43A-33 Pressures. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. o= Met (describe In nolet) PTD 2121460 Type Inj W Tubing 185 185 185 185 185 185 Type Test P Pecker TVD 9,999 1 BBL Pump I IA 900 2519 2515 2512 1 2510 2509 Interval O Test psi 2500 IBBLRetum OA 1 20 1 20 20 1 20 1 20 1 20 Result I P Notes: — MCorp is working with Chris Wallace on a lest of this production sundry will be fled to convert to an injection well. well (SCU 43A-33) to see d it can be converted to an injector. If the test is successful a Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Iry Tubing Type Test Packer TVD BBL Pump IA I Interval Test psi BBL Return OA Result Nates: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. Whin. PTO Type Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBLRetum OA Result Note.: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type lnj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Ing Tubing Type Test Packer ND BBLPumpl IA Interval Test psi BBL Return OA Result Notes: Well Pressures'. Pretest Initial 15 Min. 30 Min. 45 Min, MMin. PTO Type Ing Tubing I i i I i I Type Test Packer TVD BBl_Pumpj I M I I Interval Test psi BBL Return OA Result Notes: Wall Pressures: Pretest Initial 15 Min. 30 Min, 45MIn. 50 Min. PTD Type Ing Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Mal. 45 Min. 50 Min. PTD Type Ing Tubing Type Test Packer TVD BBLPumpj I IA Interval Test psi BBL Retuml OA Result Notes: TYPE [NJ Codes W - WNer G=Gas a - Slurry I - Induamel Wamewmer N=Not lnjeci ng TYPE TEST CO. INTERVAL Codes P = Reasum Teal I = Initial Test 0- Mar(dearribe in Notes) 4 -Fant Year Cyde V = ReWIrM Ly Vedance o= Met (describe In nolet) Form 10-026 (Revised 01/2017) MIT WU 43A33 OM7-18 CIL Rawred Result Codes P=Pa. F=Fa1 I =Ira—Usive SCU_43A-33 Injector Mile Review Well CMNTTop(MD) CMNTTop(TVD) Assesment Well plugged with kill string ran 8/2017. CIBP set at 7,866ft with top of cement plug at 7,450ft Md. SRU 32A-33 — NA NA Cement covering productive intervals with TOC at 8,355ft Md. SCU 43A-33 30,200 10,122 Injector. C(jL e-. L( SCU 343-33 NA NA Well sidetracked to drill current injector SCU 43A-33. CBL run November 9, 1971. Well currently on rod SCU 13-34 — 10,350 9,650. pump and perforated within Hemlock intervals. i - SRU_nd3 _ \ spU_31JA SR 9RU 1tJ3WD /' _211-33 \ \O /SRU-21A� 8RU BJSWU 3 BRU 13-N O SRU-32J3= \ SRU 3M43 gG �4U43] 9RU_23J) - - SCU 3333 Hilwm Alaska Swn m flrvx SRU _34]3 B SC _u.N xucwv~• �wr 9 3 � MTA -� SCU_2143 SCU BM SCU 9CU 21C-0C IAM S 31-04 8 100,000 L c 10,000 O a N O- U _� •� 1,000 of � O O v+ cu m d Q1 LL � 100 7 U v c n3 0 O 10 HILCORP ALASKA LLC, SOLDOTNA CK UNIT 43A-33 (212-146) SWANSON RIVER, HEMLOCK OIL Monthly Production Rates Cum. Prod Oii (bbl30,822 Cum. Prod Water (bbls): 524,767 Cum. Prod Gas (mcf): 105,172 ee o8 i _ •b ff °u ° o ee o e e° e o- . ° p r _e Q pO..pe°° e0 p O ° o 0° o e O i 0 o_m ° ° e I i • l ° ° Produced Gas (MCFM) . GOR a Produced Water (BOPM) o Produced Oil (BOPM) 100,000 10,000 0 O Jan -2012 Jan -2013 Jan -2014 Jan -2015 Jan -2016 Jan -2017 Jan -2018 Jan -2019 Jan -2020 SPREADSHEET_Prod-I nject_Cuwes_Well_Vi17_2121460_SCU_43A-33_20183010.xlsx 10/15/2018 • 212-11-1 Seth Nolan Hilcorp Alaska, LLC qr GeoTech 3800 Centerpoint Drive, Suite 100 2 2 I,`1 Z Anchorage, AK 99503 Tele: 907 777-8308 II.knrp law.LI_t LC Fax: 907 777-8510 \ -{-b E-mail: snolan@hilcorp.com DATE 05/10/2017 RECEIVED To: Alaska Oil & Gas Conservation Commission MAY 1 1 2°11 Meredith Guhl Petroleum Geology Assistant AOGcc 333 W 7th Ave Ste 100 V1 Anchorage, AK 99501 DATA SCU 43A-3N3 SMITTAL S �E� MAY 1 � 2.011 CD: 1 Electric logs SCU 43A-33 COMPOSITION.pdf 11/26/2012 7:35 AM PDF Document ▪ SCU_43A-33 COMPOSITION.tif 11/26/2012 7:35 AM TIF File SCU_43A-33 SEMBLANCE.las 11/26/20129:27 AM LAS File SCU 43A-33 SEMBLANCE.pdf 11/26/2012 9:21 AM PDF Document • SCU 43A-33 SEMBLANCE.of 11/26/2012 9:21 AM TIF File SCU_43A-33_SONIC.pdf 11/26/2012 9:35 AM PDF Document ▪ SCU_43A-33_SONIC.tif 11/26/2012 9:32 AM THF File SCU_43A-33 TRIPLECOMBO.las 11/26/201210:20 AM LAS File 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 eceiv y: Date: � Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. clI Oa- J 1.440 Well History File Identifier Organizing (done) ❑ Two-sided ❑ Rescan Needed RES AN: OVERSIZED: NOTES: Color Items: ;71 ps: Grayscale Items: gs: ❑ Poor Quality Originals: ❑ Other: ❑ Other: /� BY: � p�w r Date: ` lsl iiii) Project Proofing BY: TMaria) Date: I9_/chJi%L /s/ nil) i igi DScanning Preparation 3 x 30 = + = TOTAL PAGES / 0 (Count does not include cover sheet) BY: Date: �_ /s/ Production Scanning Stage 1 Page Count from Scanned File: I ©� (Count does include cover sheet) Page Count Matches Number in Scannin/ Preparation: YES NO BY: 41:21, Date: 19, p,,6ig- /s/ �n,f� r ' r �.r Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO 1 BY: Maria Date: /s/ Stage 2 Additional Well Reports: NO TOTAL PAGES: Digital version appended by: Meredith Michal M Date: 12 19-.CA fl_I /s/ Final Page Count: Stage 1 + Stage 2: TOTAL PAGES: 1 a, , Scanning is complete at this point unless rescanning is required. 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Ei 2 0 17 2 2 /1 zliiir y m co m m m co y • oca O CO CO CO CO 0 c E a I , 0 = 6 m m m m m I O Z « 1 °' '� °' > o 0 J 0 0 0 0 0 0 J E p co a co er > N M M M M M M CO w W /7 CO N N N N N N N N N W/ E a O N N N N N N N N 1 y W O O y C N E O 'I.c I Z °- _ N 1 'd E z vi O: N NZU c H a a O c •iiv O U U U U U U d 0 aa _ !w O U � E E p j °' °' V ! o o m E E a 2 I� WD w w OW w w 3z U a C) ' V V Carlisle, Samantha J (DOA) l '1 From: Schwartz, Guy L(DOA) Sent: Monday, September 15, 2014 4:26 PM To: Carlisle, Samantha J (DOA) Subject: FW: Sundry Cancellation - Sundry# 313-404 - SCU 43A-33- PTD 212-146 Sam, Please withdraw below sundry. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at (907-793-1226) or(Guy.schwartz@alaska.gov). From: Donna Ambruz [mailto:dambruz©hilcorp.com] Sent: Monday, September 15, 2014 3:16 PM To: Schwartz, Guy L(DOA) Cc: Stan Porhola Subject: Sundry Cancellation - Sundry # 313-404 - SCU 43A-33- PTD 212-146 Guy, Please withdraw the above mentioned sundry. Thank you. .Donna Qrntoxa z 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 L RECEIVED STATE OF ALASKA AL, A OIL AND GAS CONSERVATION COMM, .ON DE. r 2 0 201,., REPORT OF SUNDRY WELL OPERATIONS ../...,,--/...,•,1 OGCC 1.Operations Abandon U Repair Well U Plug Perforations IX Perforate U Other Inflatable Plugback Performed: Alter Casing ❑ Pull Tubing❑ Stimulate-Frac ❑ 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 .❑ Exploratory ❑ • 212-146 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 4 50-133-10168-01 7.Property Designation(Lease Number): 8.Well Name and Number: A028890 • • Soldotna Creek Unit(SCU)43A-33 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 % 11,250 feet Plugs measured 10,791 feet true vertical 11,098 feet Junk measured N/A feet Effective Depth measured 11,110 feet Packer measured 10,070 feet true vertical 10,969 feet true vertical 9,999 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 28' 22" 28' 28' Surface 1,496' 13-3/8" 1,496' 1,496' 2,730 psi 1,130 psi Intermediate 10,350' 6-5/8" 10,350' 10,263' 7,440 psi 5,760 psi Production Liner 1,100' 4" 11,250' 11,098' 7,910 psi 6,590 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 10,116'MD 10,043'TVD Arrowset 10,070'MD Packers and SSSV(type,measured and true vertical depth) AS1-X 9,999'ND N/A N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A RBDMSMAY1 72014 Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Md Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 35 9 534 1520 - 500 - Subsequent to operation: 1 4 21 • 1225 • 230 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory❑ Development • Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil i 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 sDorhola(CahilCoro.Com Printed Name Stan Porhola Title Operations Engineer Signature t:��v`i Phone 907-777-8412 Date ly2443 Form 10-404 Revised 10/2012 S ,/t ,j�f/ Submit Original Only Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 43A-33 50-133-10168-01 212-146 11/12/13 11/13/13 Daily Operations: 11/12/2013 -Tuesday Mobe to pad. Spot equipment, rig up Pollard E-Line lubricator, PT to 250 psi low and 3000 psi high. TP - 1200 psi and casing 1500 psi. Trouble shot tools and electrical panel for an open circuit. RIH with GPT tool to 17' RKB. Could not go past obstruction. POOH and added wt bar and still could not pass obstruction. Tool setting down approx 3' below tubing hanger. Rig down Pollard E-line. Mobe slickline to pad. Spot equipment, rig up Pollard lubricator, PT to 250 psi low and 3000 psi high. TP- 1200 psi and casing 1500 psi. RIH w/2-1/4" x 5' DD bailer to 17' KB. Tag on obstruction and dump methanol. Made it to 19'. POOH and added wt bar. Spudded on obstruction and made it to 21' while dumping methanol. Bailer had hydrate in it. Rig up Hot Oil Truck to well. Pump 1 bbl of methanol while spudding on ice plug, when tools became stuck. Pressured tubing up to 1500 psi and moved plug down to 400'. Tools came free and went down to 2,000' with no problem. Came back up hole and hung up at 47'. Pumped more methanol and tools came free. Pump total of 2.9 bbls methanol. RIH with 2-1/8" x 15' dummy gun down to 10,936' KB. POOH with no problems on this run. 11/13/2013 -Wednesday Rig down slickline and Hot Oil Truck. Clean up work area. Mobe to location. Rig up Pollard Eline lubricator. PT to 250 psi low and 3000 psi high. RIH w/ 1-11/16" GPT tool and tie into Pollard Perf Record dated 28 Dec 2012. Tag bottom at 10,917'. Pull up to 10,685' and took 1 hr static survey. POOH. MU Weatherford IRBP and check out tool. RIH w/Weatherford IRBP and tie into Pollard Perf Record dated 28 Dec 2012. Set plug depth at 10,700' and started plug set. Plug set in 16 min. Showed a real good set. POOH. TP- 1150 psi and CP 1450 psi. Rig down lubricator and turn well over to production. Soldotna Creek Unit Well: SCU 43A-33 ACTUAL SCHEMATIC Completion Ran: 11/28/2012 PTD:212-146 Hilrorp Alaska,LH: API: 50-133-10168-01 Ground Elev: 124'Above MSL KB-THF:20.25' J I CASING DETAIL 22" a • 2 � Size Type Wt Grade Conn. ID Top Btm 3 i 22" Conductor - - - Surf 28' ` 13-3/8" Surf.Csg 54.5 1-55 BTC 12.25 Surf 1,496' t 28 P-110 BTC 5.665 Surf 127' 424 N-80 BTC 5.796 127' 6,600' 13-3/8" 6-5/8" Intermediate 28 P-110 BTC 5.665 6,600' 6,607' 24 P-110 BTC 5.796 6,607' 10,165' 28 P-110 BTC _ 5.665 10,165' 10,353' 51 4" Prod Lnr 9.5 L-80 VAM STL 3.548" 10,131' 11,250' TUBING DETAIL 2-7/8" Production 6.5 L-80 8RD 2.441" Surf 10,117' 61 bl JEWELRY DETAIL No. Depth ID OD Item 1 20' 2.992" - . Tubing Hanger 2 21' 2.441" _ 3.500" _ X0 3-1/2"IBT Pin x 2-7/8"8RD Pin 7_i 3 3,287' 2.441" 4.750" 2-7/8"SFO-1 Mandrel 8RD 10 port tY 4 5,395' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port i!' 5 6,807' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port 6 7,992' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port 8t 7 8,896' 2.441" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port 1 8 9,516' 2.441" 4.750" _ 2-7/8"SF0-1 Mandrel 8RD 12 port 9 10,009' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD Orifice el 9( l » 10 10,058' 2.313" 5.500" On/Off Tool w/X-Nipple 6' 11 10,070' 2.375" 5.500" Arrowset AS1-X Mechanical Packer • I 1M 12 10,083' 2.313" 3.500" X-Nipple 13 10,116' 2.441" 3.500" WL Entry Guide 10 7 N '± 14 10,700' - 2.125" , Inflatable bridge plug 1 i 15 10,917' 1.750" Fish-1.75"Pump Bailer(3'Long) 11 (Fell Down Hole) MI 16 10,917' 2.125" Inflatable bridge plug(5'of sand) • Top of Liner (Fell Down Hole) 12 ® Hanger @ 10,131' 17 10,920' - 2.125" Inflatable bridge plug(4'of sand) MB • 13 ions •1" PERFORATION DETAIL Date Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) SPF Ft Phase Comments 6-5/8" L ' 1/26/13 H2 10,676' 10,686' 10,570' 10,579' 6 10 60 2-1/8"HC H-2 1/25/13 H2 10,686' 10,696' 10,579' 10,588' 6 10 60 2-1/8"HC : / 1/25/13 H3 10,705' ' 10,710' 10,596' 10,601' 6 5 60 2-1/8"HC I`JT 14 . \ , 1/25/13 H3 10,710' 10,719' 10,601' 10,609' 6 9 60 2-1/8"HC H-3 1/25/13 H4 10,719' 10,720' 10,609' 10,610' 6 1 60 2-1/8"HC H-4 1/17/13 H4 10,720' 10,730' 10,610' 10,619' 6 10 60 2-1/8"HC H-5 1/17/13 H4 10,730' 10,735' 10,619' 10,624' 6 5 60 2-1/8"HC ' 1/17/13 H5 10,735' 10,740' 10,624' 10,628' 6 5 60 2-1/8"HC :/4 1/17/13 H5 10,740' 10,750' 10,628' 10,637' 6 10 60 2-1/8"HC 1^ , H-7 1/16/13 H5 10,750' 10,760' 10,637' 10,646' 6 10 60 2-1/8"HC 14-8 1/16/13 H5 10,760' 10,770' 10,646' 10,655' 6 10 60 2-1/8"HC 1/15/13 H7 10,819' 10,828' 10,700' 20,709' 6 10 60 Isolated 15 i„��fr14 12/28/13 H7 10,819' 10,831' 10,700' 10,711' 6 12 60 Isolated 16 ,- =' 1/15/13 H7 10,828' 10,838' 10,709' 10,718' 6 10 60 Isolated 17 , ►� • 1/14/13 H7 10,838' 10,848' 10,718' 10,727' 6 15 60 Isolated --^ H-9 1/14/13 H7 10,848' 10,850' 10,727' 10,729' 6 2 60 Isolated H-9,10 1/14/13 H8 10,850' 10,858' 10,729' 10,736' 6 8 60 Isolated H-10 12/8/12 H9 10,929' 10,931' 10,801' 10,803' 6 2 60 Isolated ` 12/8/12 H9,10 10,931' 10,946' 10,803' 10,817' 6 15 60 Isolated ' i, • 12/8/12 H10 10,944' 10,967' 10,815' 10,836' 6 23 60 Isolated 4 /lyea'�; r� 5-5/8"hole PBTD=11,125'MD/10,985'ND Last Tag: TD=11,250'MD/11,098'ND 1-11/16"GPT @ 10,917'(11/13/13) Max Deviation 24°@ 10,716' Downhole Revised:11/13/13 Updated by STP 11/20/13 • RECEIVEC STATE OF ALASKA ALA t V,L AND GAS CONSERVATION COMMI_ Jiv OC 0 3 2013 REPORT OF SUNDRY WELL OPERATIONS AOGCC 1.Operations Abandon Li Repair Well U Plug Perforations U Perforate U Other U Inflatable Plugback Performed: Alter Casing ❑ Pull Tubing p Stimulate-Frac ❑ Waiver p 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 ❑✓ Exploratory ❑ 212-146 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99504 50-133-10168-01 • 7.Property Designation(Lease Number): 8.Well Name and Number: A028890 ' Soldotna Creek Unit(SCU)43A-33 . 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 11,250 feet Plugs measured 10,791 feet true vertical 11,098 feet Junk measured N/A feet Effective Depth measured 11,110 feet Packer measured 10,070 feet true vertical 10,969 feet true vertical 9,999 feet Casing Length Size MD ND Burst Collapse Structural Conductor 28' 22" 28' 28' Surface 1,496' 13-3/8" 1,496' 1,496' 2,730 psi 1,130 psi Intermediate 10,350' 6-5/8" 10,350' 10,263' 7,440 psi 5,760 psi Production Liner 1,100' 4" 11,250' 11,098' 7,910 psi 6,590 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#/N-80 10,116'MD 10,043'ND Arrowset 10,070'MD Packers and SSSV(type,measured and true vertical depth) AS1-X 9,999'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: 62 1 461 1500 420 Subsequent to operation: 42 365 553 1220 190 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory❑ Development D- Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil ❑✓ . 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 sporholaa.hilcorD.com Printed Name Stan Porhola Title Operations Engineer Signature ti,, ,C.'"22,,-4, Phone 907-777-8412 Date I 0 O lb./cc.�3 RBDMS 1 T 1 i' Form 10-404 Revised 10/2012 �0,/* Submit Original Only - Soldotna Creek Unit II Well: SCU 43A-33 ACTUAL SCHEMATIC2an:Completion11/28/2012 PTD: 12-146 Hilcarp Alaska,LL(: API: 50-133-10168-01 Ground Elev:124'Above MSL KB-THF:20.25' 1 x CASING DETAIL 22" 2 14 +� Size Type Wt Grade Conn. ID Top Btm 22" Conductor - - - Surf 28' 41 3 l 13-3/8" Surf.Csg 54.5 J-55 BTC 12.25 Surf 1,496' 28 P-110 BTC 5.665 Surf 127' �� 24 N-80 BTC 5.796 127' 6,600' 4 6 5/8" Intermediate 28 P-110 BTC 5.665 6,600' 6,607' 13-3/8" t 24 P-110 BTC 5.796 6,607' 10,165' M ) 28 P-110 BTC 5.665 10,165' 10,353' 5 I4" Prod Lnr 9.5 L-80 VAM STL 3.548" 10,131' 11,250' I TUBING DETAIL 4 2-7/8" Production 6.5 L-80 8RD 2.441" Surf 10,117' b` 6 JEWELRY DETAIL 7 No. Depth ID OD Item 4 1 20' 2.992" - Tubing Hanger L.; 2 21' 2.441" 3.500" X0 3-1/2"IBT Pin x 2-7/8"8RD Pin 1' a, 3 3,287' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port 1! oll 4 5,395' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port yst 8 5 6,807' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port 6 7,992' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port ` 7 8,896' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port 9 NEM 44 8 9,516' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port i• 9 10,009' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD Orifice 10 10,058' 2.313" 5.500" On/Off Tool w/X-Nipple '' 11 10,070' 2.375" 5.500" Arrowset A51-X Mechanical Packer 11 6 lo! 4 412 10,083' 2.313" 3.500" X-Nipple I V.I I x 13 10,116' 2.441" 3.500" WL Entry Guide 11 14 10,791' - 1.750" Fish-1.75"Pump Bailer(3'Long) V f 15 10,791' - 2.125" Inflatable bridgeplug(5'of sand) Il a i 12 e 4 16 10,920' - 2.125" Inflatable bridge plug(4'of sand) MB ' 13 Top of Liner r ' Hanger @ 10,131' 3 ' PERFORATION DETAIL 6 s/& ? ki Date Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) SPF Ft Phase Comments H-2 1/26/13 H2 10,676' 10,686' 10,570' 10,579' 6 10 60 2-1/8"HC 1/25/13 H2 10,686' 10,696' 10,579' 10,588' 6 10 60 2-1/8"HC il! H-3 1/25/13 H2 10,705' 10,710' 10,596' 10,601' 6 5 60 2-1/8"HC 4 H-4 1/25/13 H2 10,710' 10,720' 10,601' , 10,610' 6 10 60 2-1/8"HC 1, -kr H-5 1/17/13 H3 10,720' 10,730' 10,610' 10,619' 6 10 60 2-1/8"HC ti. 1/17/13 H3 10,730' 10,740' 10,619' 10,628' 6 10 _ 60 2-1/8"HC 14 + '; 1/17/13 H4 _ 10,740' 10,750' 10,628' 10,637' 6 10 60 2-1/8"HC 15 Z, 1/16/13 H5 10,750' 10,760' 10,637' 10,646' 6 10 _ 60 2-1/8"HC i' H-6 1/16/13 H5 10,760' 10,770' 10,646' 10,655' 6 10 60 2-1/8"HC 4 H-6,7 1/15/13 H6 10,819' 10,828' 10,700' 20,709' 6 10 60 Isolated 'dr H-7 12/28/13 H6 10,819' 10,831' 10,700' 10,711' 6 12 60 Isolated 1/15/13 H6,7 10,828' 10,838' 10,709' 10,718' 6 10 60 Isolated ctctrtctrt, 7 1/14/13 H7 10,838' 10,848' 10,718' 10,727' 6 15 60 Isolated 16 1 ; 1/14/13 H7 10,848' 10,858' 10,727' 10,736' 6 10 _ 60 Isolated 1, H-9 12/8/12 H9 10,929' 10,931' 10,801' 10,803' 6 2 60 Isolated H-9,10 12/8/12 H9,10 10,931' 10,946' 10,803' 10,817' 6 15 60 Isolated 4A H-10 12/8/12 H10 10,944' 10,967' 10,815' 10,836' 6 23 60 Isolated 11 4" " ` { I. 5-5/8"hole PBTD=11,125'MD/10,985'ND TD=11,250'MD/11,098'ND Max Deviation 24°@ 10,716' Downhole Revised:9/05/13 Updated by STP 9/10/13 Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 43A-33 50-133-10168-01 212-146 9/4/13 9/5/13 Daily Operations: 09/04/2013 -Wednesday RU lubricator and pressure test to 250 psi low and 3,000 psi high, Ran 2.25" GR to 10,960' KB. Got sample and POOH.Very sticky on bottom. RIH with 2-1/8" x 5' dummy gun and tag at 10,960'. POOH rig for standby, Rig up eline. PT to 250 psi low and 3,000 psi low. RIH with Weatherford inflatable plug and set plug at 10,791'. Plug did not shear itself. Had to work up to 4,750 lbs and sheared plug. POOH and rig down eline. Ran 1-3/4" dump bailer and dump sand at 10,791'. Lost bailer bottom parts. Called town. Discuss plan forward w/ lost bailer bottom. Standby for tools. RIH w/2.0" pump bailer to 10,700' and dump sand. POOH. 09/05/2013 -Thursday RD Slickline. Fry� (CO sv THE STATE Alaska 011 and Gas w _ TA fALASKA � ` � ' on5e1°FJa16Y1 Commission41 GOVERNOR SEAN PARNELL 333 West Seventh Avenue ALAS114 ' Anchorage, Alaska 99501-3572 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 43A-33 Sundry Number: 313-404 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 P. oerster Chair DATED this 3 day of July, 2013. Encl. • tl%'-' RECEIVED 4. STATE OF ALASKA � ALASKA OIL AND GAS CONSERVATION COMMISSION A/0 J U L 2 5 2013 APPLICATION FOR SUNDRY APPROVALS CCf/3 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑✓ . Perforate Q •• Pull Tubing ❑✓ . lime Extension ❑ Operations Shutdown ❑ Re-enter Susp.Well ❑ Stimulate ❑ Alter Casing ❑ Other. ❑ 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number Exploratory ❑ Development ❑✓ • 212-146 • 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic El Service ❑ • 6.API Number. Anchorage,Alaska 99503 50-133-10168-01 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 ❑✓ Soldotna Creek Unit(SCU)43A-33' 9.Property Designation(Lease Number): 10.Field/Pool(s): A028890 • 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): 11,250' • 11,098' • 11,125' 10,985' 10,920' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 28' 22" 28' 28' Surface 1,496' 13-3/8" 1,496' 1,496' 2,730psi 1,130psi Intermediate 10,353' 6-5/8" 10,353' 10,266' 7,440psi 5,760psi Production Liner 1,119' 4" 11,250' • 11,098' 7,910psi 6,590psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 2-7/8" L-80 10,117' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Arrowset AS1-X Mech;N/A 10,070'MD-9,999'TVD;N/A 12.Attachments: Description Summary of Proposal ❑✓ 13.Well Class after proposed work: Detailed Operations Program LI BOP Sketch U Exploratory LI Stratigraphic LJ Development U • Service Li 14.Estimated Date for 15.Well Status after proposed work: 08/14/13 Commencing Operations: Oil Q - Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: I GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhola Email sporhola@hilcorp.com Printed Name Stan Porhola Title Operations Engineer Signature ,�, ,crvitt..- Phone 907-777-8412 Date 1// 2_5 J 3 COMMISSION USE ONLY ((( (` Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31 3 _qui Plug Integrity ❑ BOP Test 67f Mechanical Integrity Test ❑ Location Clearance ❑ Other: 130Pcs1 ,F 3600 psi RBDMS AUG - 22013t Spacing Exception Required? Yes ❑ No C✓ Subsequent Form Required: /O —yogi APPROVED BY Approved by: ,l COMMISSIONERiTHE COMMISSION Date: 7- 3/-43 ukp ;+ y J I 730•/ Submit Form IP01, �� Form 10-403(R vised 10/2012) ApprO i o iprp 14Lmonths frdm the date of approval. A��ttfachme�nt in Dyplicate 1,11 , /' �� Well Prognosis Well: SCU 43A-33 llileori,Alaska,LL Date:7/25/2013 Well Name: SCU 43A-33 API Number: 50-133-10168-01 Current Status: Gas Lifted Oil Well Leg: N/A Estimated Start Date: August 14`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: 212-146 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: –2,543 psi @ 10,774' TVD (Static survey May 2013 below perfs at 10,900' MD) Maximum Expected BHP: –2,543 psi @ 10,774' ND (Static survey May 2013 below perfs at 10,900' MD) 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 4,169 ft. ND. Brief Well Summary This well was drilled and completed with the Doyon Arctic Fox in November 2012 and perforated thru-tubing in December 2012.An inflatable plug was ran to isolate water coming from the H-9, H-10 intervals.Additional thru-tubing perforations were added in the H-1 thru H-7 in January 2013. Notes Regarding Wellbore Condition • New completion ran in November 2012. • Well is currently producing on gaslift at 20 BOPD and 675 BWPD. • Wellbore maximum deviation below sidetrack is less than 24 degrees. OBJECTIVE OF WORKOVER Pull current gas lift completion, squeeze off existing perforations, re-perf selected intervals(high oil-cut H6/H7) � and re-run gas lift completion. Work-Over Rig Procedure: 1. MIRU Williams 405 WO Rig. 2. Set TWC or test plug in Shaffer tubing hanger, ND tree, NU 7" 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 and chart tests. 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 3. Back out tbg hanger hold down pins and pick up on hanger. 4. RU to pull tubing hanger and unseat Arrowset AS1-X packer at 10,070' (right-hand release)and SOON with 2-7/8" production tubing down to 10,117'.Jar tubing hanger and packer loose if necessary. Well Prognosis Well: SCU 43A-33 Ililcorp Alaska,LL Date:7/25/2013 a. If unable to unseat packer, RIH with E-line and use radial cutting torch to cut 2-7/8"tubing at+/- 10,065' (between On/Off tool and Packer). b. SOOH with tubing and RIH with overshot and jars and pull AS1-X packer. 5. PU 3-3/8" bit and RIH on 2-7/8"x 2-3/8"workstring. Cleanout to 10,920'. 6. SOOH with 2-7/8" x 2-3/8"workstring. LD bit. 7. PU 4" Cement Retainer and RIH on workstring and set at+/- 10,475'. 8. Stab into retainer and establish injection. 9. Mix and pump 10 bbl cement and squeeze below retainer. L V..1-= 5:4 Qac) 10. PU out of retainer. Circulate hole clean.SOOH. LD setting tool. 11. Wait on cement. 12. PU 3-3/8" bit and RIH on 2-7/8" x 2-3/8" workstring. 13. Drillout cement retainer at 10,475', drill cement from 10,475'to 10,900'. 14. Circulate hole clean (filter fluids from pits). SOOH with 2-7/8" x 2-3/8"workstring. LD bit. 15. MIRU E-line, PT lubricator to 1,500 psi Hi 250 Low. 16. RU 2-7/8" 6 spf HC guns. 17. RIH and perforate Hemlock interval H6/H7 from 10,819'to 10,831' (1 run). �s 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. 18. POOH. RD E-line. 19. RIH with gaslift completion with existing 2-7/8" 8rd L-80 tubing. Land tubing hanger.Set packer at +/-10,100'. a. Drop prong in RHCP plug. b. Pressure test tubing to 3,000 psi (chart for 30 min).Test casing to 2,500 psi (chart 30 min). 20. Set BPV, ND BOPs, NU Tree, test tree to 5,000 psi. 21. RDMO workover rig and equipment. 22. Pull BPV.Turn well over to production. 23. Gas lift well, unloading fluid from well to production. 24. RU slickline, PT lubricator to 1,500 psi Hi 250 low. 25. RIH and pull RHCP prong and plug. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOP Schematic Soldotna Creek Unit Well: SCU 43A-33 • ACTUAL SCHEMATIC Completion Ran: 11/28/2012 PTD: 212-146 I I h,,r"'11'"k''.HT API: 50-133-10168-01 Ground Elev: 124'Above MSL KB-THF:20.25' 22 ! 1 , L CASING DETAIL ■ Size Type Wt Grade Conn. ID Top Btm 3 22" Conductor Surf 28' 13-3/8" Surf.Csg 54.5 J-55 BTC 12.25 Surf 1,496' 28 P-110 BTC 5.665 Surf 127' 24 N-80 BTC 5.796 127' 6,600' 6-5/8" Intermediate 28 P-110 BTC 5.665 6,600' 6,607' 13-3/8" 24 P-110 BTC 5.796 6,607' 10,165' 28 P-110 BTC 5.665 10,165' 10,353' 5 '14" Prod Lnr 9.5 L-80 VAM STL 3.548" 10,131' 11,250' TUBING DETAIL 2-7/8" Production 6.5 L-80 8RD 2.441" Surf 10,117' 6 il • JEWELRY DETAIL 7 17-111 No. Depth ID OD Item 1 20' 2.992" - Tubing Hanger 2 21' 2.441" 3.500" X0 3-1/2"IBT Pin x 2-7/8"8RD Pin 3 3,287' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port 8 r---711 4 5,395' 2.441" 4.750" 2-7/8"SFO-1 Mandrel 8RD 10 port 5 6,807' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port 6 7,992' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port 7 8,896' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port 9 r b1 8 9,516' 2.441" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port I 9 10,009' 2.441" 4.750" 2-7/8"SFO-1 Mandrel 8RD Orifice 10 10,058' 2.313" 5.500" On/Off Tool w/X-Nipple l01 I 11 10,070' 2.375" 5.500" Arrowset AS1-X Mechanical Packer L ' 12 10,083' 2.313" 3.500" X-Nipple I_II 13 10,116' 2.441" 3.500" WL Entry Guide 11 = 14 10,920' - 2.125" Inflatable bridge plug(4'of sand) 1_ =_ I♦ 12 0 i 13 = f• Top of Liner Hanger @ 10,131' 6-5/8" , ti! PERFORATION DETAIL aDate Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) SPF Ft Phase Comments 4,975 _ '' 1/26/13 H2 10,676' 10,686' 10,570' 10,579' 6 10 60 2-1/8"HC H2 1/25/13 H2 10,686' 10,696' 10,579' 10,588' 6 10 60 2-1/8"HC H3 1/25/13 H2 10,705' 10,710' 10,596' 10,601' 6 5 60 2-1/8"HC ' H4 1/25/13 H2 10,710' 10,720' 10,601' 10,610' 6 10 60 2-1/8"HC H5 1/17/13 H3 10,720' 10,730' 10,610' 10,619' 6 10 60 2-1/8"HC 5,q1/17/13 H3 10,730' 10,740' 10,619' 10,628' 6 10 60 2-1/8"HC o1ZL �L-/ ' fly , 1.. H6 1/17/13 H4 10,740' 10,750' 10,628' 10,637' 6 10 60 2-1/8"HC H6,7 1/16/13 H5 10,750' 10,760' 10,637' 10,646' 6 10 60 2-1/8"HC H-7 1/16/13 H5 10,760' 10,770' 10,646' 10,655' 6 10 60 2-1/8"HC 1/15/13 H6 10,819' 10,828' 10,700' 20,709' 6 10 60 2-1/8"HC 12/28/13 H6 10,819' 10,831' 10,700' 10,711' 6 12 60 2-1/8"HC 1/15/13 H6,7 10,828' 10,838' 10,709' 10,718' 6 10 60 2-1/8"HC )o111.0 'T'7-7 1/14/13 H7 10,838' 10,848' 10,718' 10,727' 6 15 60 2-1/8"HC 14 < 1/14/13 H7 10,848' 10,858' 10,727' 10,736' 6 10 60 2-1/8"HC H9 12/8/12 H9 10,929' 10,931' 10,801' 10,803' 6 2 60 Isolated H9,10 12/8/12 H9,10 10,931' 10,946' 10,803' 10,817' 6 15 60 Isolated H-10 12/8/12 H10 10,944' 10,967' 10,815' 10,836' 6 23 60 Isolated 4" ,4 ..,.,' 5-5/8"hole PBTD=11,125'MD/10,985'ND TD=11,250'MD/11,098'ND Max Deviation 24°@ 10,716' Downhole Revised:6/21/2013 Updated by STP 7/15/2013 Soldotna Creek Unit Well: SCU 43A 33 PROPOSED SCHEMATIC PPTD:ropos212-146ed Completion Hilcora Alaska,Ll.f. API: 50-133-10168-01 Ground Elev:124'Above MSL KB-THF:20.25' 1 L CASING DETAIL 22" 2 i Size Type Wt Grade Conn. ID Top Btm 22" Conductor Surf 28' iel 3 111118 i jol 13-3/8" Surf.Csg 54.5 1-55 BTC 12.25 Surf 1,496' 28 P-110 BTC 5.665 Surf 127' 4 24 N 80 BTC 5.796 127' 6,600' to 13-3/8" V i 6-5/8" Intermediate 28 P-110 BTC 5.665 6,600' 6,607' >! IP, 24 P-110 BTC 5.796 6,607' 10,165' p _ 28 P-110 BTC 5.665 10,165' 10,353' 3y 5 i 4 4" Prod Lnr 9.5 L-80 VAM STL 3.548" 10,131' 11,250' TUBING DETAIL IN 2-7/8" Production 6.5 L-80 8RD 2.441" Surf 10,147' i 6 IN i ii iY JEWELRY DETAIL 1, No. Depth ID OD Item "� 7 1 1 20' 2.992" Tubing Hanger 'Mr to A 2 21' 2.441" 3.500" XO 3-1/2"IBT Pin x 2-7/8"8RD Pin Iii,itr, 3 3,300' 2.441" 4.750" 2-7/8"SFO-1 Mandrel 8RD 10 port 8 NINE i' i 4 5,400' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port 5 6,800' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port 1. 6 8,000' 2.441" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port 7 8,900' 2.441" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port 9 a ;0 8 9,500' 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port 9 10,000 2.441" 4.750" 2-7/8"SF0-1 Mandrel 8RD Orifice Vr' 10 10,050' 2.313" 4.750" Chemical Injection Mandrel (1/4"control line) 10 11 10,088' 2.313" 5.500" On/Off Tool w/X-Nipple 12 10,100' 2.375" 5.656" FH Hydraulic Packer ✓ 11 13 10,113' 2.313" 3.688" X-Nipple lar; 14 10,146' 2.441" 3.500" WL Entry Guide 12 I I I r" 15 10,920' - y 2.125" Inflatable bridge plug(4'of sand) toUMQVi13 Top of Liner 110 li Hanger @ 10,131' 6-5/8" 14 f PERFORATION DETAIL Date Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) SPF Ft Phase Comments 3 _ HZ 1/26/13 H2 10,676' 10,686' 10,570' 10,579' 6 10 60 Squeezed H3 tf! 1/25/13 H2 - 10,686' 10,696' 10,579' 10,588' 6 10 60 Squeezed 1/25/13 H2 10,705' 10,710' 10,596' 10,601' 6 5 60 Squeezed et 1 H4 1/25/13 H2 10,710' 10,720' 10,601' 10,610' 6 10 60 Squeezed iAH5 1/17/13 H3 10,720' 10,730' 10,610' 10,619' 6 10 60 Squeezed Yak - 1/17/13 H3 10,730' 10,740' 10,619' 10,628' 6 10 60 Squeezed '. 1Vt116 1/17/13 H4 10,740' 10,750' 10,628' 10,637' 6 10 60 Squeezed - H6,7 1/16/13 H5 10,750' 10,760' 10,637' 10,646' 6 10 60 Squeezed , H-7 1/16/13 H5 10,760' 10,770' 10,646' 10,655' 6 10 60 Squeezed 1/15/13 H6 10,819' 10,828' 10,700' 20,709' 6 10 60 Squeezed ' t 12/28/13 H6 10,819' 10,831' 10,700' 10,711' 6 12 60 Proposed Reperf 1/15/13 H6,7 10,828' 10,838' 10,709' 10,718' 6 10 60 Squeezed ai,trtart. ,; 1/14/13 H7 10,838' 10,848' 10,718' 10,727' 6 15 60 Squeezed 15 1/14/13 H7 10,848' 10,858' 10,727' 10,736' 6 10 60 Squeezed H9 12/8/12 H9 10,929' 10,931' 10,801' 10,803' 6 2 60 Isolated H9,10 12/8/12 H9,10 10,931' 10,946' 10,803' 10,817' 6 15 60 Isolated H-10 12/8/12 H10 10,944' 10,967' 10,815' 10,836' 6 23 60 Isolated - t"ell 4" .. , . , 5-5/8"hole PBTD=11,125'MD/10,985'ND TD=11,250'MD/11,098'ND Max Deviation 24°@ 10,716' Proposed Downhole Updated by STP 7/25/2013 II Swanson River 2013 Williams Rig 405 Knight Oil Tools BOP Netrorp:Uaolui.Id.{: IIPI • III III III iii iii III Ill Iii 2.57' Shaffer - 71/16 5000 , III 111 III lil III li AI 11 lilt igi lil ill ill / \7 2 3/8-3'/:variable lInglli CAMERON 3.68' mom "�! .: _ up_ 7. , - mi, Blind _.." All 71/16 5000 'lamI �_ ISM � ` Wr Iii Iii ill III lil Mil Choke and Kill valves are 21/1610M _i!i :!!!:1!11 Ailik1.56' i• „y}I<� a ierr 5,/ 11111111 111.116111.111.111 II Landon Ellison Hilcorp Alaska, LLC G- �--+ GeoTech II 3800 Centerpoint Drive, Suite 100ketterta 2� Anchorage, AK 99503 Tele: 907 777-8339 HiIn, ,:�1:�Mkr,1.1A: Fax: 907 777-8510 ,E E E-mail: lellison@hilcorp.com JUN 11 2013 AOGCC DATE 06/11/2013 To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTA SCU 43A-33 Prints: Wave Sonic Porosity Dual Spaced Neutron Spectral Density Array Comp True Res Radial Cement Bond Log GR-CCL Reservoir Monitor Tool Elite log Gamma Ray Mem Log 1:1600 MD Gamma Ray Mem Log 1:240 MD 2 CD with digital versions (PDF, TXT, LAS) of above Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: ii/27liZ II Landon Ellison Hilcorp Alaska, LLC G-�u Mk,II 3800 Centerpoint Drive, Suite 1002+ Anchorage, AK 99503 Tele: 907 777-8339 .;* . Fax 907 777-8510 R 1E Nan,rp AMAIN-1.IA. E-mail: lellison@hilcorp.com l JUN 1 1 2013 AO(CC DATE 06/11/2013 SZPt.tlb To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL SCU 43A-33 Prints: Wave Sonic Porosity Dual Spaced Neutron Spectral Density Array Comp True Res Radial Cement Bond Log GR-CCL Reservoir Monitor Tool Elite log Gamma Ray Mem Log 1:1600 MD Gamma Ray Mem Log 1:240 MD 2 CD with digital versions (PDF, TXT, LAS) of above 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: 117 Date: z1 3 RECERIED II ___.don Ellison Hilcorp Alaska, LL‘.. GeoTech II 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 JUN 1 ZQ±3 Tele: 907 777-8339 /� r/'r Fax: 777-8510 t{�l""`�' `` �� N ,�'�` E-mail907 lel1 s n@hilcorp.com A®4�VC,r DATE 06/11/2013 To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTA scu q/s., , 33 Prints: / Final Well report r/ 2"/100'Formation Log(MD/TVD) 5"/100' Formation Log(MD) - 2"/100' Drilling Dynamics Log(MD/TVD) 2"/100' LWD Combo Log(MD/TVD) 2"/100' Gas Ratio Log(MD/TVD) Final Well Data: CD (please see caw 2 A.,13 / 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 UbDate: 1td • BEDEWED STATE OF ALASKA ALI._,v4 OIL AND GAS CONSERVATION COMM__,ION A P`, E 2013 REPORT OF SUNDRY WELL OPERATIONS AOGCC 1.Operations Abandon ❑ Repair Well U Plug Perforations U Perforate U Other U !Performed: Alter Casing ❑ Pull Tubing❑ Stimulate-Frac ❑ 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 ❑., Exploratory ❑ 'c* 212-146 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99504 t 50-133-10168-01 7.Property Designation(Lease Number): 8.Well Name and Number: F A028890 '-° Soldotna Creek Unit(SCU)43A-33 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 11,250 feet Plugs measured N/A feet true vertical 11,098 feet Junk measured N/A feet Effective Depth measured 11,110 feet Packer measured 10,070 feet true vertical 10,969' feet true vertical 9,999 feet Casing Length Size MD ND Burst Collapse Structural Conductor 28' 22" 28' 28' Surface 1,496' 13-3/8" 1,496' 1,496' 2,730 psi 1,130 psi Intermediate 10,350' 6-5/8" 10,350' 10,263' 7,440 psi 5,760 psi Production Liner 1,100' 4" 11,250' 11,098' 7,910 psi 6,590 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#/N-80 10,116'MD 10,043'ND Arrowset 10,070'MD Packers and SSSV(type,measured and true vertical depth) AS1-X 9,999'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: 138 11 0 150 165 - Subsequent to operation: 65 3 367 1770 720 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory❑ Development E Service ❑ Stratigraphic 0 Daily Report of Well Operations X 16.Well Status after work: Oil„ El 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 Nur",^-""" '`^" Exempt: — -- .ft—437 Contact Chad Helgeson Email chelgeson@hilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature /��' `ljl�j�� Phone 907-777-8405 Date 3/zO3 Form 10-404 Revised 10/204DMS APR 0 2 2013 R.4 Y. c6/3 Submit Original Only Y • -' els Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 43A-33 Completion 50-133-10168-01 212-146 Daily Operations: 01/09/2013-Wednesday Mobe to location. Tubing pressure 1,200 psi. Rig up lubricator, arm guns and pressure test to 250 psi low and 2,500 psi high. RIH with 2-1/8" HC, 6 spf, 60 deg phase perf gun. Tools stopped at 1,050'. Worked tools up hole to 1,030'with around 1,000 lbs over pull. Pulled out of rope socket. POOH without tools. Called town and slickline operator was already out here. Wait on slickline to finish a job. Rig up lubricator pressure test to 250 low and 2500 psi high. RIH with 1.85" skirted pulling tool and set down at 831'. POOH. Pulling tool was packed full of hard paraffin. Rig down lubricator. Shut down for rest. 01/10/2013 -Thursday Mobe to location. TP- 1,350 psi. Rig up lubricator. Pressure test to 250 psi low and 2,500 psi high. Pump 70 gal of Xylene and flush test pump with 10 gal methanol. Tube psi went up to 1,550 psi. RIH with 2-1/4" DD bailer and couldn't get past 38'. POOH. Nothing in bailer. Went back in with 2" DD bailer and bailed at 812' (TH zero). POOH and got sample of paraffin. Loaded 15 bbls of diesel and heated it to 180 deg. Pumped 4 bbls and tube pressured up to 2,500 psi. Let bleed to 1,500 psi. Pumped 11 bbls at 2,000 psi. Ran 2" bailer to 790'. Bailed on obstruction. Ran 2" LIB to 790'. LIB had no marks just paraffin. Loaded 30 bbls diesel in hot oil truck. Pumped 1.5 bbls and tubing pressured up to 2,500 psi. Would not bleed off. Walked pressure up to 3000 psi. Tubing jugged up. Bled tubing to 900 psi, RIH and tagged at 790'. 01/11/2013- Friday Mobe to location. Put 3,000 psi on tubing overnight and had 500 psi in morning. Rig up lubricator, pressure test to 250 low and 3000 psi high. RIH with 2.2" GR and tag at 790'. Same depth. Put 2,500 psi on tubing and casing had 1,100 psi on it. Started pumping crude down casing from hot oil truck at 140 deg. After 20 bbls casing pressure dropped to 600 psi. At 50 bbls away, started to make a tag run. Slickline pack off blew an oring and had a 2 qt spill. Cleaned up spill. Ran 2-1/4" GR and tagged at 790'. Pumped a total of 202 bbls before casing pressured up at 1 bpm. Kept between 2,500-3,000 psi on tubing while pumping down casing. Brought casing pressure up to 1,000 psi,waited 15 min and bled down to 500 psi. Did that several times until I got 237 bbls put away(casing volume). Bled tubing to 1,500 psi and tagged at 427'with 2-1/4" GR. Put 2,100 psi on tubing and tagged at 554' and RU 1-3/4" GR and tagged at 502'. Pump another 11 bbls down casing. Casing came up to 1,000 psi twice and ten minutes before, bled gas and fluid down to 650 psi. Tagged to 502'. Left casing with 1,000 psi and pressured up tubing to 4,000 psi on it. Rig Pollard down and secure well. 01/12/2013-Saturday Mobe to location. Cut wire, rehead and repack pack off. PT lubricator to 250 psi low and 4000 psi high. TP- 2,700 psi and casing 700 psi. Ran 2.25" x 4' DD bailer and bailed on paraffin at 586'. POOH. Bailer empty. Ran 1-3/4"x 3' DD bailer and worked thru spot at 586' and bailed on fill at 754'. Made 3 runs with bailer and got half bailer full of paraffin back. Bleed hose on lubricator started clogging up and was taking long time to bleed. Took samples from bailer and testing what chemical is best for desolving paraffin. Decided on PAO-100. Made three bailer runs(bailer holds 1 gal)and dump chemical on paraffin plug at 754'. Bled tubing pressure down to 1,500 psi thru flow line. RIH with dump bailer and tag fill at 527'. Paraffin plug came up hole 227'. Dump bailer of chemical on paraffin plug and pulled up in lubricator. Pressured tubing up to 2,500 psi. Run back in hole and tagged obstruction at 759'. Changed crew out. RIH with Dump bailer and dump chemical on paraffin plug two more times at 759'. RIH with 3/4" x 5' sucker rod punch and spudded on obstruction at 759'. Ran 2-1/4"x 5' DD bailer and bailed on paraffin at 759'. Bailer full of paraffin. Pulled tools back up in lubricator and when putting tension on lubricator the strap that was holding lubricator up broke. Waited on manlift and replaced strap. RIH with 2-1/4"x 5' DD bailer and bailed on obstruction at 759'. POOH and bailer of soupy paraffin. 01/13/2013 -Sunday Made two 2.25" x 5' DD bailer runs. Bled tubing down to 1,950 psi for first run and bailed from 701'to 720'. Bailer had no solids in it. Stop pressure up lub to see if plug moved up hole and it did. Second run hit plug at 688'. Work bailer. POOH. Had soupy paraffin in it. Started bleeding well down from 1,750 psi to 1,000 psi. Pressure got to 1,200 psi and then went to 1,950 psi. Went down and tagged plug at 488'. Bled tubing pressure to 1,000 psi and heard a-line tools hit bottom of slickline 2-1/4" bailer in lub. Bled tubing pressure to 300 psi and then pumped hot crude to get the tools to drop out of lubricator due to paraffin that came up with the e-line tools. Added 12' of lubricator. Reheaded line and put new packing in pack off. RIH with 1.85"JDC pulling tool and had no trouble going down to 10,868' and latching a-line fish. Pumped 30 bbls hot crude and started out of hole with fish. Got to 1,300' and hung up. Dropped back down to 2,000' and pump 25 bbls hot crude. Pulled back up to 1,300' and pull 800 lbs over tool wt and thru tight spot. Recovered all tools from well. Rig down lubricator and turn well over to field. 01/14/2013- Monday Mobe to location. Rig up and PT lub to 250 psi low and 2.500 psi high TP-450, Casing-1700 psi. RIH with 2.29" GR and tagged at 10,927'WLM. No problems. RIH with 2-1/8"x2 0' dummy gun and set down at 9,906'work tools but no good. POOH. RIH with 2-1/8" x 15' dummy gun and set down at 9,906' work tools but no good. POOH. RIH with 2-1/8"x 10'dummy gun and tag fill at 10,927'WLM. POOH. Rig down lubricator and secure well. Fluid level was 6840'. Mobe to location with E- Line. Rig up E-line Lubricator, PT to 250 psi low and 2500 psi high. Down load 20' to a 10' perf gun. RIH with 2-1/8"x 10' HC, 6 spf, 60 deg phase and tie into Pollard Perf log dated 12-28-12 and tried to shoot but wt leaked out. POOH. RIH with 2-1/8" x 10' HC, 6 spf, 60 deg phase and tie into Pollard Perf log dated 12-28-12. Spot perf gun from 10,848'to 10,858' per Final Approved Perf Request Form dated 1/3/13. TP- 1,300 psi, BHP 3,335.7 psi,Temp 174.3 deg F. Fired perf gun. Pulled up to 10,831',TP-same, BHP 3,323.5 psi,Temp 172.5 deg F. Monitor for 30 min. Last reading was BHP 3,319 psi,Temp 174 Deg F. Fluid level was 6,364'. RIH with 2-1/8"x 10' HC, 6 spf, 60 deg phase and tie into Pollard Perf log dated 12-28-12. Spot perf gun from 10,838'to 10,848' per Final Approved Perf Request Form dated 1/3/13. TP- 1,300 psi. Fluid level was 6,270'. Fire perf gun and TP stayed same. POOH. 01/15/2013-Tuesday RIH with 2-1/8" x 19' HC, 6 spf, 60 deg phase and tie into Pollard Perf log dated 12-28-12. Tools set down at 9,870'. Could not go deeper. POOH. FL at 6,186'. Load 2 ten foot perf guns. RIH with 2-1/8"x 10' HC, 6 spf, 60 deg phase and tie into Pollard Perf log dated 12-28-12. Spot perf gun from 10,838'to 10,828' per Final Approved Perf Request Form dated 1/3/13. Fired gun with TP-1,300 psi. No change. RIH with 2-1/8" x 10' HC, 6 spf, 60 deg phase and tie into Pollard Perf log dated 12- 28-12. Spot perf gun from 10,828'to 10,819' per Final Approved Perf Request Form dated 1/3/13. Fired gun with TP- 1,250 psi. No change. 3,351.5 psi,temp 172.2 deg F. After perf BHP 3,339.8 psi,temp 170 deg F. Rig for standby and flow well. FL 6,070'. Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 43A-33 Completion 50-133-10168-01 212-146 Daily Operations: 01/16/2013-Wednesday Mobe to location. Rig up Slickline lubricator and pressure 250 psi low and 4,000 psi high. RIH w/2.25"GR to 4,000',first 900' was slow and fell free after. Rig up Hot Oil truck and pump 20 bbls 170 deg crude while brush tubing from surface to 1,000' then tag fill at 10,918'wlm. RIH w/2-1/8"x 15'dummy gun,fell very slow to 1,640',then clear to 9,906'and set down. Could not get past. POOH. RIH w/2-1/8"x 10'dummy gun,fell slow to 1,340'and then set down at 9,906'. Spang down and work thru spot at 9,906'several times to try and clear up. This is the same tool string that went thru without problem yesterday. Went down and tag at 10,909'wlm. POOH. RIH w/2.34"GR and tagged On/Off sub at 10,058'. MU 1-3/4"tool string with 2-1/8"x 10' DG that made tool string weigh 140 lbs instead of 90 lbs. Repack stuffing box. RIH and fell thru 9,906' easily. Had 150 lb overdrag coming up. Rig down slickline and clean up area. PTW for E-line. Rig up Lubricator and pressure test to 250 psi low and 2,500 psi high. TP 1,100 psi, casing- 1,700 psi. Arm gun. RIH with 2-1/8"x 10' HC,6 SPF, 60 deg phase perf gun and set down at 9,895'. Could not get past. Tool string weight 120 lbs at surface. POOH. Added one 5'extra weight bar. Made weight at surface 150 lbs. RIH with same perf gun and tie into Pollard Perf Record dated 12/28/12. Went thru tight spot ok. Spot perf gun from 10,770'to 10,760' per Final Approved Perf Request Form dated 1/14/13. TP 1,300 psi. Fired gun and pressure didn't change. POOH. RIH with 2-1/8" x 10' HC,6 spf,60 deg phase and tie into Pollard Perf log dated 12/28/12. Spot gun from 10,760'to 10,750' per Final Approved Perf Request Form dated 1/14/13. TP 1,300 psi. Fired gun and no pressure change. POOH. 01/17/2013-Thursday RIH with 2-1/8"x 10' HC,6 spf, 60 deg phase and tie into Pollard Perf Record dated 12/28/12. Spot gun from 10,750'to 10,740' per Final Approved Perf Request Form dated 1/14/13.TP 1,300 psi. Fired gun and lost 50 psi. POOH. Fluid level 5,730'. RIH with 2-1/8"x 10' HC,6 spf,60 deg phase and tie into Pollard Perf Record dated 12/28/12. Spot gun from 10,740' to 10,730' per Final Approved Perf Request Form dated 1/14/13.TP 1,250 psi. Gun did not go off. Show a dead short. POOH. RIH with 2-1/8"x 10' HC, 6 spf, 60 deg phase and tie into Pollard Perf Record dated 12/28/12. Spot gun from 10,740'to 10,730' per Final Approved Perf Request Form dated 1/14/13. TP 1,250 psi. Gun Fired gun and lost 50 psi. POOH. RIH with 2-1/8"x 10' HC,6 spf,60 deg phase and tie into Pollard Perf Record dated 12/28/12. Spot gun from 10,730'to 10,720' per Final 1/14/13. TP 1,250 psi. Fired gun and pressure dropped to 1200 psi. Casing pressure still at 1500 psi. RIH with 2-1/8"x 10' HC,6 spf,60 deg phase and tie into Pollard Perf Record dated 12/28/12. Tools set down at 9,895'. Could not get past tight spot. Called town and was told to standdown on the well that they would flow it for a couple days. Rig down E-line and turn well over to production. Fluid level 5,637'. 01/18/2013-Friday No activities to report. 01/19/2013-Saturday No activities to report. 01/20/2013-Sunday No activities to report. 01/21/2013-Monday No activities to report. 01/22/2013-Tuesday No activities to report. Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 43A-33 Completion 50-133-10168-01 212-146 11/7/12 Daily Operations: 01/23/2013-Wednesday No activities to report. 01/24/2013-Thursday No activities to report. 01/25/2013 - Friday Mobe to location. Rig up slickline lub. PT to 250 low and 2,500 psi high. RIH with 2-1/8" x 10' DG with three 1-3/4" wt bars. Tool string wt was 200 lbs. Fell thru tight spot slowly from 9,923' KB to 9,958'. Worked tight spot several times. Continued in hole and tag fill at 10,920'WLM. Rig down lubricator and cleaned up well site. Rig up Pollard E-line lubricator. PT to 250 psi low and 2,500 high. TP 1,500 psi and casing 1,600 psi. RIH w/2-1/8" x 10' HC, 6 spf, 60 deg phase. Tie into Pollard Perf Record dated 12/28/12. Set down at 9,890'. Could not go below this depth. POOH. Wait on wt bars to be brought out for E- line, E-line tool string around 160 lbs. RIH w/2-1/8" x 10' HC, 6 spf, 60 deg phase. Tie into Pollard Perf Record dated 12/28/12. Spot gun from 10,720'to 10,710' per Final Approved Perf Request Form dated 1/14/13. Fired gun with 1,500 psi tubing and 1,650 psi casing. POOH. All shots fired, No psi change. RIH w/2-1/8" x5' HC, 6 spf, 60 deg phase. Tie into Pollard Perf Record dated 12/28/12. Spot gun from 10,710'to 10,705' per Final Approved Perf Request Form dated 1/14/13. Gun shorted out when votage was amp up to fire. POOH. RIH w/2-1/8" x 5' HC, 6 spf, 60 deg phase. Tie into Pollard Perf Record dated 12/28/12. Spot gun from 10,710'to 10,705' per Final Approved Perf Request Form dated 1/14/13. Fired gun with 1450 psi tubing and 1,600 psi casing. POOH. All shots fired, No psi change. RIH w/2-1/8"x 10' HC, 6 spf,60 deg phase. Tie into Pollard Perf Record dated 12/28/12. Spot gun from 10,686"to 10,696' per Final Approved Perf Request Form dated 1/14/13. Fired gun with guns and saw no psi increase. 01/26/2013 -Saturday RIH w/2-1/8" x 10' HC, 6 spf, 60 deg phase. Tie into Pollard Perf Record dated 12/28/12. Spot gun from 10,686'to 10,676' per Final Approved Perf Request Form dated 1/14/13. Fired gun with 1,450 psi tubing and 1,600 psi casing. POOH. All shots fired, No psi change. Rig down lubricator, secure well and help rig up slickline for PT survey. 01/27/2013-Sunday No activities to report. 01/28/2013- Monday No activities to report. 01/29/2013-Tuesday No activities to report. Soldotna Creek Unit • Well: SCU 43A-33 II SCHEMATIC Completion Date: 11/28/2012 PTD:212-146 Hikorp Alaska,LLC API: 50-133-10168-01 Ground Elev:124'Above MSL KB-THF:18.6' 22 J h 1 '1 .w' L CASING DETAIL v. Size Type Wt Grade Conn. ID Top Btm 22" Conductor Surf - - Surf 28' `60, 2 13-3/8" Surf.Csg 54.5 J-55 Buttress 12.25 Surf 1,496' 28 P-110 BTC 5.665 Surf 127' l'=1 24 N80 BTC 5.796 127' 6,600' y, 3 Olt i 13-3/8 6-5/8" Intermediate 28 P-110 BTC 5.665 6,600' 6,607' 24 P-110 BTC 5.796 6,607' 10,165' II Al 28 P-110 BTC 5.665 10,165' 10,350' 1,01 4 ' 4" Prod Lnr 9.5 L-80 STL 3.548" 10,150' 11,250' " TUBING DETAIL "' 2-7/8" Production 6.4 N-80 8RD 2.441 Surf 10,116 5 MK ' n ` 1..'<' JEWELRY DETAIL No. Depth ID OD Item ,4v111 • 1 20' 2.44" - Tubing Hanger 4:- 2 3,287' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 10 port '4' t 3 5,395' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port t 4 6,807' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port 1 7 i 1 5 7,992' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port . 6 8,896' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port 441 7 9,516' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port ' 8 AR p 0 8 10,009' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD Orifice v 9 10,058' 2.313" 6.5" On/Off Tool w/X-Nipple 10 10,070' 2.44" 6.5" Arrowset AS1-X Mechanical Packer - 4 11 10,083' 2.313" 3.5" X-Nipple 4 le 12 10,116' 2.44" 3.5" WL Entry Guide 9 13 10,920' 2.125" Weatherford Eline inflatable bridge plug 5.+ I Aim I . Top of Liner 10 I14 _ - Hanger @ 10,131' °- 11 !' PERFORATION DETAIL 6-5/8" Whipstock Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) SPF Ft Detail ililip ' 12 J,, t set @ H2 10,686' 10,696' 10,579' 10,588' 6 10 2-1/8"x 10'HC,60 deg I 10,290' H2 10,705' 10,710' 10,596' 10,601' 6 5 2-1/8"x 5'HC,60 deg H2 H2 10,710' 10,720' _ 10,601' 10,610' 6 10 2-1/8"x 10'HC,60 deg H3 10,720' . 10,730' 10,610' 10,619' 6 10 2-1/8"x 10'HC,60 deg H3 H3 10,730' 10,740' 10,619' 10,628' 6 10 2-1/8"x 10'HC,60 deg H4 H4 10,740' 10,750' 10,628' 10,637' 6 10 2-1/8"x 10'HC,60 deg k• T H5 H5 10,750' 10,760' 10,637' 10,646' 6 10 2-1/8"x 10'HC,60 deg 5' -R~ H5 10,760' 10,770' 10,646' 10,655' 6 10 2-1/8"x 10'HC,60 deg - H6 H6 10,819' 10,828' 10,700' 20,709' 6 10 2-1/8"x 10'HC,60 deg ,1:1,' t 4• H6,7 H6 10,819' 10,831' 10,700' 10,711' 6 12 2-1/8"HC guns a: H-7 H6,7 10,828' 10,838' 10,709' 10,718' 6 10 2-1/8"x 10'HC,60 deg 0. 1331.11111 i.,,,i p s r H7 10,838' 10,848' 10,718' 10,727' 6 15 2-1/8"x 10'HC,60 deg H7 10,848' 10,858' 10,727' 10,736' 6 10 2-1/8"x 10'HC,60 deg H9 H9 10,929' 10,931' 10,801' 10,803' 6 2 Plugged It'' IF H9,10 H9,10 10,931' 10,946' 10,803' 10,817' 6 15 Plugged H-10 H10 10,944' 10,967' 10,815' 10,836' 6 23 Plugged it 6 7, Br 4" 4,, ►1 PBTD=11,110' TD=11,250'/TVD=11,098' Max Deviation 20deg @ 10,310' Updated by DMA 03-28-13 STATE OF ALASKA ALA - A OIL AND GAS CONSERVATION COMM„.SION WELL COMPLETION OR RECOMPLETION REPORT AND LOG la.Well Status: DB [] Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ lb.Well Class: 20AAC 25.10520AAC 25.110 Development E • Exploratory❑ EI W GINJ ❑ VVINJ ❑ WAG DSPL❑ No.of Completions n Service ❑ Stratigraphic Test❑ 2.Operator Name: 5.Date Comp.,Susp.,or 12.Permit to Drill Number: Hilcorp Alaska,LLC Aband.: 12/8/2012 • 212146 . 3.Address: 8.Date Spudded: 13.API Number. 3800 Centerpoint Drive,Suite 100 Anchorage,AK 99503 11/18/2012 • 50-133-10168-01-00 - 4a.Location of Well(Governmental Section): 7.Date TD Reached: 14.Well Name and Number: Surface: 1245'FSL,625'FEL,Sec 33,T8N,R9W,SM ' 11/19/2012 SCU 43A-33 Top of Productive Horizon: 8.KB(ft above MSL): 142.6 15.Field/Pool(s): 2116'FSL,660'FEL,Sec 33,T8N,R9W,SM GL(ft above MSL): 124 Swanson River Field/ Total Depth: 9.Plug Back Depth(MD+TVD): Hemlock Oil Pool • 2230'FSL,592'FEL,Sec 33,T8N,R9W,SM 11,125/10,982 4b. Location of Well(State Base Plane Coordinates,NAD 27): 10.Total Depth(MD+TVD): 16.Property Designation: Surface. x- 347018.7 ' y- 2462415.3 • Zone- 4 11,250/11,097 - A028890 TPI• x- 346994.1 y- 2463287.4 Zone- 4 11.SSSV Depth(MD+TVD): 17.Land Use Permit: Total Depth: x- 347063.3 y- 2463400.4 Zone- 4 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: Gamma Ray,Resistivity,Neutron,Density,Sonic,SP C a(_ c'/o Le 10,353'/10,266' 23. CASING,LINER AND CEMENTING RECORD WE PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE •' TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORDFr. PULLED 22" Surf 28 13-3/8" 54.5 J-55 Surf 1,496 6-5/8" 24,28 N-80/P-110 Surf 10,353 Surf 10,266 w/,•.rsf►.,/, e /azgd' 4" 9.5 L-80 10,131 11,250 10,955 11,097 5-5/8" 30 bbls 15.8/30 bbls 15.3 24.Open to production or injection? Yes Q 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" 10,116' 10,070/10,070' Please see attached schematic 26. ACID,FRACTURE,CEMENT SQUEEZE,ETC. Was hydraulic fracturing used during completion? Yes❑ No 0 I S 1 DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED RECEIVED JAN 14 2013 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): AOGC 12/5/2012 _Gas Lift �w V Date of Test: Hours Tested: Production for Oil-Bbl. Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 12/6/2012 11.5 Test Period 111. 7.7 • 0 145.4 N/A 0 Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): N/A Press. 300 1,500 24-Hour Rate - 16 0 303 Did not test-Perfed&results on 10-404 28 CORE DATA Conventional Core(s)Acquired? Yes❑ No❑� Sidewall Cores Acquired? Yes ❑ No❑� 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. liar MS JAN 281013 ,eeA6 Form 10-407 Revised 10/2012 CONTINUED ON REVERSE 34- 5-,i 3 Submit original only +1 29. GEOLOGIC MARKERS (List all formations and markers encountered). 30. FORMATION TESTS NAME MD TVD Well tested? 0 Yes ❑ No If yes,list intervals and formations tested, briefly summefi2ing test results.Attach separate sheets to this form,if needed, Tyonek G2 10,556' 10,458' and submit detailed test information per 20 AAC 25.071. Hemlock H2 10,691' 10,584' Hemlock H3 10,720' 10,610' Same as production test in Item 27. Hemlock H4 10,738' 10,626' Hemlock H5 10,754' 10,641' Hemlock H7 10,834' 10,714' Hemlock H10 10,944' 10,815' Hemlock H12 11,107' 10,966' Formation at total depth: Hemlock 31. List of Attachments: Final schematic,daily report summary,definitive directional survey,casing tally,cementing report,days v.depth graph,MW v.depth graph 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact. Email: Ikeller@hilcorp.com Printed Name: Luke Kelleer Title: DrillingpEngineer p Signature: l/(� Phone: /07777— S3 7 S Date: 1/1o / OW 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 1b: 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 AAC 25.071. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 10/2012 Soldotna Creek Unit Well: SCU 43A-33 SCHEMATIC Completion Date: 11/28/2012 PTD:212-146 H iirprp k..ka.IAA API: 50-133-10168-01 Ground Elev:124'Above MSL KB-THF:18.6' 1 CASING DETAIL 22" Size Type Wt Grade Conn. ID Top Btm 22" Conductor - - - Surf 28' 2 IS i ii 13-3/8" Surf.Csg 54.5 J-55 Buttress 12.25 Surf 1,496' it t 28 P-110 BTC 5.665 Surf 127' 3 1 24 N80 BTC 5.796 127' 6,600' 13-3/8" X "t,.' 6-5/8" Intermediate 28 P-110 BTC 5.665 6,600' 6,607' I 4 , I 24 P-110 BTC 5.796 6,607' 10,165' 28 P-110 BTC 5.665 10,165' 10,350' `1 4" Prod Lnr 9.5 L-80 STL 3.548" 10,131' 11,250' L " 5 III i' TUBING DETAIL 2-7/8" Production 6.4 N-80 8RD 2.441 Surf 10,116 ' .- 6 1E i JEWELRY DETAIL ' No. Depth ID OD Item '"or 1 20' 2.44" - Tubing Hanger 1, 7 MI ii c Li 4 2 3,287' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port Z 1 3 5,395' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port 8 4 6,807' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port T. " 5 7,992' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port u 6 8,896' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port S`. 7 9,516' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port 8 10,009' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD Orifice *" I « I,^ I ¶ Top of Liner 10 iio .f#Hanger @ 10,131' 9 10,058' 2.313" 6.5" On/Off Tool w/X-Nipple I 10 10,070' 2.44" 6.5" Arrowset AS1-X Mechanical Packer 11 Whipstock 11 10,083' 2.313" 3.5" X-Nipple 6-5/8" 1 11, a12 set @ 12 10,116' 2.44" 3.5" WL Entry Guide 10,290' PERFORATION DETAIL 51 41 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) SPF Ft Detail 1,1 H-10 10,944' 10,967' 10,815' 10,836' 6 23 2-1/8"HC guns 14 A it it4 45,w vi 4 4i 4" L .I PBTD=11,125' TD=11,250'/TVD=11,098' Max Deviation 20deg @ 10,310' Updated by DMA 12/18/12 Hilcorp Alaska, LLC Location: Cook Inlet,Alaska(Kenai Peninsula) Slot: SCU 343-33 BAKER Field: Soldotna Creek Unit Well: SCU343-33 HUGHES Facility: SCU 343-33(43A-331 Wellbore: SCU43A-33 re, llilearp Alaska,LLC Plot reference wellpath is NaviGamma MWD<10401-112505 True vertical depths are referenced to Arctic Fox(RTE) Grid System:NAD27/TM Alaska SP,Zone 4(5004),US feet Measured depths are referenced to Arctic Fox(RTE) North Reference:True north Arctic Fox(RTE)to Mean Sea Level:142.5 feet Scale:True distance Mean Sea Level to Mud line(At Slot:SCU 343-33):0 feet Depths are in feet _ Coordinates are in feet referenced to Slot Created by:jonethoh on 26-Nov-12 5�,,,,�_So" Easting(ft) -160 -125 -100 -75 -50 -25 0 25 50 1 1 1 1 1 1 1 1 1 1000 Jp co —975 —950 —925 9` — —900 9500— —875 z 9750— —850 5 10000— —825 0 10250— —800 m 0 N 10500— —775 10750— \`\ —750 11000— ` —725 n 11250— v —700 w 11500— 1 1 1 1 —675 500 750 1000 7250 Vertical Section(ft) 8-1°1"'"=5°°" Azimuth 356.24°with reference 0.00 N,0.00 E Cementing ]ogkeport CemCATv1.5 Schlumberger Well 43A-33 Client Hilcorp Field Swanson River SIR No. BC8Z-00119 Engineer Peter Cahill Job Type Cement Liner Country United States Job Date 11-22-2012 Time WHP Rate Density Messages 15/22/201229:3.:9, 20:34:02 SLB start mixing MudPUSH II • Start Priming Unit • • • • • • • • • 20:54:00 • • • Start Priming Unit • • • • • • 21:14:00 21:34:00 Mud Push II to weight `— PJSM Reset Total,Vol=1.47 bbl Front Head Tested 21:54:00 0 Rear Head Tested Reset Total,Vol=4.96 bbl Rear Head Passed Line for air down hardline •• • Reset Total,Vol=3.36 bbl • Rig lining for air Lot : :—.. .� Air blown through Mudline and Hardline 22:14:00 r : Water temp 70 degF • Lined down DP l • Start pumping 5 bbls H2O ahead I5 bbls away down on the pump Valve on floor shut for PT All clear on the floor 22:34:00 Low PT 1,000 psi Trips checked All clear for High PT 4,500 psi PT Pass Via Mike Leslie f Bleed Pressure t ( I Reset Total,Vol=5.01 bbl 1 Rig to line for 20 bbls MudPUSH II D177 Added to Mix H2O 22:54:00 .--y 10 bbls away All clear to start batch j Water taken MudBalance reads 15.7 ppg Startartpumping 10:45 • 3 bbls behind MM • 23:14:00 �� 17 bbls Mix h20 pumped Down on the pump • �� Reset Total,Vol=35.36 bbl • L. Reset Total,Vol=2.82 bbl • • Line to cutting box • • • - to pump 5 bbls h20 behind Reset Total,Vol=30.45 bbl 23:34:00 - l Start Pumping H2O Reset Total,Vol=3.65 bbl ."1‘1.51L1 . • • Reset Total,Vol=0.00 bbl • • • • : 7fr— Start pulling on Mud To pump 116 bbls Start Pumping 15x 23:54:00 Dart dropped Plug dropped Full retruns Rig parked Liner Dart Latch 104 116.25 bbls displacedd T a Cement in place 12 AM 00:14:00 • 4500 psi to realease • • • • •• • : 00:34:00 •• •• T •• • • 00:48:03 •• • • hh:mm:ss 0.00 940 1880 2820 3760 9700 0.00 1.6 3.2 4.8 6.4 8.0 5.0 10.0 15.0 20.0 25.0 11u3ao52 oo:.9:09 PSI B/M LB/G 11/23/2012 00:48:07 Schlumberger Cementing Service Report Customer Job Number Hilcarp BC8Z-00119 Well Location(legal) Schlumberger Location Job Start 43A-33 33 Swanson River Prudhoe Bay Nov/22/2012 Field Formation Name/Type Deviation Bit Size Well MD Well TVD Swanson River Clean Sandstone 35 deg 5.6 in 11160.0 ft 11024.0 ft County Kenai State/Province Alaska BHP BHST BHCT Pore Press.Gradient Well Master 43A API/UWI 6191 psi 184 degF 166 degF lb/gal Rig Name Drilled For Service Via Casing/Liner Arctic Fox Oil Land Depth,ft Size,in Weight,lb/ft Grade Thread Offshore Zone Well Class Well Type 10350.0 6.6 24.0 L80 BUTT Old Development 11248.0 4.0 9.5 N80 BUTT Drilling Fluid Type Max.Density Plastic Viscosity Tubing/Drill Pipe KCL Polymer 9.20 lb/gal cP T/D Depth,ft Size,in Weight,lb/ft Grade Thread Service Line Job Type D 10130.0 4.0 14.0 5135 N/A Cementing Cement Liner 0.0 0.0 0.0 Max.Allowed Tub.Press Max.Allowed Ann.Press WH Connection Perforations/Open Hole 4500 psi 2000 psi 4"FH DP pin Top,ft Bottom,ft shot/ft No.of Shots Total Interval Service Instructions ft ft ft ft ft Diameter ft ft in Treat Down Displacement Packer Type Packer Depth Drill Pipe 116.0 bbl Seal Bore 10130.0 ft Tubing Vol. Casing Vol. Annular Vol. Openhole Vol. 104.0 bbl 12.1 bbl bbl bbl Casing/Tubing Secured ❑ 1 Hole Vol.Circulated prior to Cement ❑ Casing Tools Squeeze Job Lift Pressure 1200 psi Shoe Type Float Squeeze Type Pipe Rotated ❑ Pipe Reciprocated ❑ Shoe Depth 11248.0 ft Tool Type No.Centralizers Top Plugs 1 Bottom Plugs Stage Tool Type Tool Depth ft Cement Head Type Single Stage Tool Depth ft Tail Pipe Size in Job Scheduled For Arrived on Location Leave Location Collar Type Float Tall Pipe Depth ft Nov/22/2012 Nov/22/2012 Nov/22/2012 Collar Depth 11125.0 ft Sq..Total Vol. bbl Date Time WHP Flow Density Volume Message 24-hr PSI Rate LB/G BBL dock B/M 11/22/2012 20:34:02 8 0.0 -6.08 0.0 Started Acquisition 11/22/2012 20:35:42 8 0.0 -6.08 0.0 11/22/2012 20:35:43 7 0.0 -6.08 0.0 SLB start mixing MudPUSH II 11/22/2012 20:35:52 8 0.0 -6.08 0.0 Start Priming Unit 11/22/2012 20:37:22 8 0.0 -6.08 0.0 11/22/2012 20:39:02 8 0.0 -6.08 0.0 11/22/2012 20:40:42 9 0.0 -6.08 0.0 11/22/2012 20:42:22 8 0.0 -6.08 0.0 11/22/2012 20:44:02 7 0.0 -6.08 0.0 11/22/2012 20:45:42 8 0.0 -6.08 0.0 11/22/2012 20:47:22 8 0.0 -6.08 0.0 11/22/2012 20:49:02 9 0.0 -6.08 0.0 11/22/2012 20:50:42 9 1.9 -6.08 0.2 11/22/2012 20:52:18 8 2.9 -6.08 3.1 Start Priming Unit 11/22/2012 20:52:22 7 2.3 -6.08 3.3 11/22/2012 20:54:02 8 4.3 -6.08 7.6 11/22/2012 20:55:42 8 3.3 -6.08 12.3 11/22/2012 20:57:22 9 0.0 -6.08 15.8 11/22/2012 20:59:02 10 0.0 -6.06 15.8 11/22/2012 21:00:42 9 3.6 -6.07 16.4 11/22/2012 21:02:22 10 0.0 -6.07 22.8 Page 1 of 5 Well Held Sob Start Customer Job Number 43A-33 33 Swanson River Nov/22/2012 Hilcorp BC8Z-00119 Date Time WHP Flow Density Volume Message 24-hr PSI Rate LB/G BBL clock B/M 11/22/2012 21:05:42 11 0.0 -6.08 26.8 11/22/2012 21:07:22 9 0.0 -6.04 26.8 11/22/2012 21:09:02 6 0.0 -6.04 26.8 11/22/2012 21:10:42 4 0.0 -6.04 26.8 11/22/2012 21:12:22 3 0.0 -6.04 26.8 11/22/2012 21:14:02 -3750 0.0 -6.25 26.8 11/22/2012 21:15:42 3 0.0 -6.07 26.8 11/22/2012 21:17:22 3 0.0 -6.08 26.8 11/22/2012 21:19:02 4 0.0 -6.08 26.8 11/22/2012 21:20:42 7 0.0 -6.08 26.8 11/22/2012 21:22:22 9 0.0 -6.08 26.8 11/22/2012 21:24:02 9 0.0 -6.08 26.8 11/22/2012 21:25:42 12 0.0 -6.08 26.8 11/22/2012 21:27:22 14 0.0 -6.08 26.8 11/22/2012 21:29:02 15 0.0 -6.08 26.8 11/22/2012 21:30:42 15 0.0 -6.08 26.8 11/22/2012 21:32:22 14 0.0 -6.08 26.8 11/22/2012 21:34:02 16 0.0 -6.08 26.8 11/22/2012 21:35:42 16 1.1 -6.08 26.9 11/22/2012 21:37:22 16 2.4 -6.08 33.3 11/22/2012 21:39:02 17 0.0 -6.08 36.0 11/22/2012 21:40:42 17 0.0 8.34 36.0 11/22/2012 21:41:15 17 0.0 8.35 36.0 Mud Push II to weight 11/22/2012 21:42:22 17 0.0 8.35 0.0 11/22/2012 21:42:59 18 3.0 8.34 0.9 P)SM 11/22/2012 21:43:11 18 3.1 8.35 1.5 Reset Total,Vol=1.47 bbl 11/22/2012 21:44:02 20 3.1 8.35 4.1 11/22/2012 21:44:35 19 2.6 8.38 5.2 Front Head Tested 11/22/2012 21:44:42 19 2.9 8.35 5.6 Rear Head Tested 11/22/2012 21:44:59 19 3.0 8.35 6.4 Reset Total,Vol=4.96 bbl 11/22/2012 21:45:42 20 3.0 8.35 8.6 11/22/2012 21:46:10 22 0.0 8.35 9.8 Rear Head Passed 11/22/2012 21:46:19 19 0.0 8.35 9.8 Line for air down hardline 11/22/2012 21:46:24 19 0.0 8.35 9.8 Reset Total,Vol=3.36 bbl 11/22/2012 21:47:22 17 0.0 8.35 0.0 11/22/2012 21:49:02 9 0.0 8.36 0.0 11/22/2012 21:49:58 -0 0.0 8.35 0.0 Rig lining for air 11/22/2012 21:50:42 -6 0.0 8.35 0.0 11/22/2012 21:52:22 -14 0.0 8.35 0.0 11/22/2012 21:54:02 37 0.0 8.35 0.0 11/22/2012 21:55:42 62 0.0 8.35 0.0 11/22/2012 21:57:22 -15 0.0 8.36 0.0 11/22/2012 21:59:02 -14 0.0 8.36 0.0 11/22/2012 22:00:42 -9 0.0 8.36 0.0 11/22/2012 22:01:03 -8 0.0 8.35 0.0 Air blown through Mudline and Hardline 11/22/2012 22:02:22 -5 0.0 8.36 0.0 11/22/2012 22:02:40 -4 0.0 8.36 0.0 Water temp 70 degF 11/22/2012 22:04:02 -1 0.0 8.35 0.0 11/22/2012 22:05:42 5 0.0 8.36 0.0 11/22/2012 22:07:22 8 0.0 8.36 0.0 11/22/2012 22:09:02 11 0.0 8.36 0.0 11/22/2012 22:09:16 11 0.0 8.36 0.0 Lined down DP 11/22/2012 22:09:55 13 0.0 8.36 0.0 Start pumping 5 bbls H2O ahead 11/22/2012 22:10:42 -15 0.0 8.36 0.0 Page 2 of 5 Well Field lob Start Customer Job Number 43A-33 33 Swanson River Nov/22/2012 Hilcorp BC8Z-00119 Date Time WHP Flow Density Volume Message 24-hr PSI Rate LB/G BBL clock B/M 11/22/2012 22:14:02 756 2.1 8.36 4.9 11/22/2012 22:14:19 182 0.0 8.36 5.0 5 bbls away down on the pump 11/22/2012 22:15:00 116 0.0 8.36 5.0 Valve on floor shut for 1:9- 11/22/2012 T11/22/2012 22:15:06 112 0.0 8.36 5.0 All clear on the floor 11/22/2012 22:15:42 102 0.0 8.36 5.0 11/22/2012 22:16:20 1396 0.0 8.36 5.0 Low PT 1,000 psi Trips checked 11/22/2012 22:17:22 1335 0.0 8.36 5.0 11/22/2012 22:18:01 1318 0.0 8.37 5.0 All clear for High PT 4,500 psi 11/22/2012 22:19:02 4526 0.0 8.36 5.0 11/22/2012 22:20:42 4476 0.0 8.36 5.0 11/22/2012 22:21:45 4455 0.0 8.37 5.0 PT Pass Via Mike Leslie 11/22/2012 22:21:52 4452 0.0 8.36 5.0 Bleed Pressure 11/22/2012 22:22:22 2496 0.0 8.36 5.0 11/22/2012 22:22:54 14 0.0 8.36 5.0 Reset Total,Vol=5.01 bbl 11/22/2012 22:24:02 21 0.0 8.36 5.0 11/22/2012 22:24:09 20 0.0 8.36 5.0 Rig to line for 20 bbls MudPUSH II 11/22/2012 22:24:32 21 0.0 8.36 5.0 D177 Added to Mix H2O 11/22/2012 22:25:42 986 0.0 8.36 5.0 11/22/2012 22:27:22 1094 0.0 8.36 5.0 11/22/2012 22:28:28 1057 0.0 8.35 5.0 10 bbls away 11/22/2012 22:29:02 1014 0.0 8.36 5.0 11/22/2012 22:29:16 991 0.0 8.36 5.0 All clear to start batch 11/22/2012 22:30:17 920 0.0 8.36 5.0 Water taken 11/22/2012 22:30:42 824 0.0 8.36 5.0 11/22/2012 22:32:22 30 0.0 8.36 5.0 11/22/2012 22:34:02 16 0.0 11.15 5.0 11/22/2012 22:35:42 15 0.0 14.80 5.0 11/22/2012 22:37:22 16 0.0 15.75 5.0 11/22/2012 22:39:02 15 0.0 15.75 5.0 11/22/2012 22:40:42 15 0.0 15.75 5.0 11/22/2012 22:42:22 17 0.0 15.73 5.0 11/22/2012 22:43:32 17 0.0 15.73 5.0 MudBalance reads 15.7 ppg 11/22/2012 22:44:02 17 0.0 15.74 5.0 11/22/2012 22:44:13 51 0.0 15.74 5.0 Start pumping 10:45 11/22/2012 22:45:42 236 1.5 15.53 6.4 11/22/2012 22:47:22 636 3.1 16.12 11.7 11/22/2012 22:49:02 1282 3.4 16.04 16.9 11/22/2012 22:50:42 387 3.8 15.76 23.2 11/22/2012 22:51:01 989 3.8 15.94 24.4 3 bbls behind MM 11/22/2012 22:52:22 1204 3.8 -3.12 29.4 11/22/2012 22:54:02 400 2.9 15.61 35.4 11/22/2012 22:55:42 190 1.1 15.95 39.3 11/22/2012 22:56:32 155 0.8 15.94 40.3 17 bbls Mix h20 pumped 11/22/2012 22:56:35 156 0.0 15.94 40.4 Down on the pump 11/22/2012 22:57:22 94 0.0 15.31 40.4 11/22/2012 22:59:02 80 0.0 15.32 40.4 11/22/2012 22:59:17 79 0.0 15.94 40.4 Reset Total,Vol=35.36 bbl 11/22/2012 23:00:42 107 0.0 15.52 42.2 11/22/2012 23:01:45 92 0.5 15.53 43.2 Reset Total,Vol=2.82 bbl 11/22/2012 23:02:22 165 1.7 15.61 43.9 11/22/2012 23:04:02 305 3.0 15.45 48.2 11/22/2012 23:05:42 271 3.0 15.42 53.3 11/22/2012 23:07:22 108 3.4 15.39 59.0 11/22/2012 23:09:02 299 3.4 15.45 64.7 Page 3 of 5 Well Field lob Start Customer lob Number 43A-33 33 Swanson River Nov/22/2012 Hilcorp BC8Z-00119 Date Time WHP Flow Density Volume Message 24-hr PSI Rate LB/G BBL clock B/M 11/22/2012 23:12:22 169 1.3 15.60 73.1 11/22/2012 23:13:28 97 0.0 15.52 73.6 Line to cutting box 11/22/2012 23:13:35 96 0.0 15.52 73.6 to pump 5 bbls h20 behind 11/22/2012 23:14:02 96 0.0 5.43 73.6 11/22/2012 23:14:18 96 0.0 11.23 73.6 Reset Total,Vol=30.45 bbl 11/22/2012 23:15:42 91 0.0 8.72 73.6 11/22/2012 23:17:22 88 0.0 8.66 73.6 11/22/2012 23:17:57 148 1.3 8.87 73.7 Start Pumping H2O 11/22/2012 23:19:02 205 3.6 8.42 76.9 11/22/2012 23:20:06 67 0.0 8.45 77.3 Reset Total,Vol=3.65 bbl 11/22/2012 23:20:42 65 0.0 8.45 77.3 11/22/2012 23:21:08 64 0.0 8.46 77.3 Start pulling on Mud 11/22/2012 23:21:12 63 0.0 8.45 77.3 To pump 116 bbls 11/22/2012 23:21:44 89 1.4 8.51 77.4 Start Pumping 15x 11/22/2012 23:21:52 103 1.5 8.69 77.6 Dart dropped 11/22/2012 23:22:14 99 2.0 9.12 78.3 Plug dropped 11/22/2012 23:22:22 101 2.0 9.20 78.5 11/22/2012 23:23:29 168 3.5 9.42 82.1 Full retruns 11/22/2012 23:24:02 161 3.5 9.42 84.0 11/22/2012 23:25:42 157 3.8 9.50 90.3 11/22/2012 23:27:22 151 3.8 9.45 96.6 11/22/2012 23:29:02 178 3.8 8.53 102.9 11/22/2012 23:30:42 197 3.8 8.51 109.3 11/22/2012 23:32:22 205 3.8 8.47 115.6 11/22/2012 23:34:02 175 3.8 8.77 122.0 11/22/2012 23:35:42 154 3.8 8.95 128.3 11/22/2012 23:37:22 152 3.8 9.46 134.7 11/22/2012 23:39:02 1165 3.0 9.57 140.0 11/22/2012 23:40:42 1728 2.9 9.54 145.5 11/22/2012 23:42:22 1640 2.5 9.66 150.0 11/22/2012 23:44:02 1509 2.6 9.67 154.4 11/22/2012 23:45:42 1783 2.4 9.66 158.5 11/22/2012 23:46:44 1681 2.5 9.68 161.1 Rig parked Liner 11/22/2012 23:47:22 1743 2.4 9.67 162.6 11/22/2012 23:49:02 1954 2.2 9.67 166.6 11/22/2012 23:50:42 1982 2.2 9.69 170.3 11/22/2012 23:52:22 2383 2.9 9.68 174.0 11/22/2012 23:54:02 2232 3.0 9.69 179.0 11/22/2012 23:55:42 2440 2.8 9.68 183.3 11/22/2012 23:55:44 2568 2.7 9.68 183.3 Dart Latch 104 11/22/2012 23:57:22 2569 2.6 9.69 187.6 11/22/2012 23:59:02 2958 2.3 9.69 191.6 11/23/2012 00:00:42 3196 0.0 9.70 194.5 11/23/2012 00:01:43 3639 0.0 9.69 194.7 116.25 bbls displacedd 11/23/2012 00:02:22 3648 0.0 9.68 194.7 11/23/2012 00:02:33 3652 0.0 9.68 194.7 Cement in place 12 AM 11/23/2012 00:04:02 3673 0.0 9.69 194.7 11/23/2012 00:05:42 3662 0.0 9.69 194.7 11/23/2012 00:07:22 3699 0.0 9.68 194.7 11/23/2012 00:09:02 3709 0.0 9.68 194.7 11/23/2012 00:10:42 3681 0.0 9.70 194.7 11/23/2012 00:10:48 3745 0.1 9.70 194.7 4500 psi to realease 11/23/2012 00:12:22 4612 0.0 9.70 195.0 11/23/2012 00:14:02 4620 0.0 9.70 195.0 Page 4 of 5 Well Field lob Start Customer lob Number 43A-33 33 Swanson River Nov/22/2012 Hilcorp BC8Z-00119 Date Time WHP Flow Density Volume Message 24-hr PSI Rate LB/b BBL clock B/M 11/23/2012 00:17:22 4407 0.0 9.70 195.0 11/23/2012 00:19:02 64 0.0 9.70 195.0 11/23/2012 00:20:42 64 0.0 9.70 195.0 11/23/2012 00:22:22 62 0.0 9.71 195.0 11/23/2012 00:24:02 63 0.0 9.71 195.0 11/23/2012 00:25:42 64 0.0 9.70 195.0 11/23/2012 00:27:22 63 0.0 9.68 195.0 11/23/2012 00:29:02 63 0.0 9.69 195.0 11/23/2012 00:30:42 61 0.0 9.70 195.0 11/23/2012 00:32:22 60 0.0 9.70 195.0 11/23/2012 00:34:02 61 0.0 9.70 195.0 11/23/2012 00:35:42 60 0.0 9.70 195.0 11/23/2012 00:37:22 58 0.0 8.71 195.0 11/23/2012 00:39:02 55 0.0 0.11 195.0 11/23/2012 00:40:42 51 0.0 0.04 195.0 11/23/2012 00:42:22 150 0.0 8.41 195.0 11/23/2012 00:44:02 122 0.0 8.38 195.0 11/23/2012 00:45:42 48 0.0 7.55 195.0 Post Job Summary Average Pump Rates,bbl/min Volume of Fluid Injected,bbl Slurry N2 Mud Maximum Rate Total Slurry Mud Spacer N2 2.8 5.5 195.0 0.0 0.0 Treating Pressure Summary,psi Breakdown Fluid Maximum Final Average Bump Plug to Breakdown Type Volume Density 4721 47 682 3600 FreshWater 35.0 bbl 8.34 lb/gal Avg.N2 Percent Designed Slurry Volume Displacement Mix Water Temp Cement Circulated to Surface? X❑ Volume bbl °k 60.0 bbl 0.0 bbl 70 degF Washed Thru Perfs ❑ To ft Customer or Authorized Representative Schlumberger Supervisor Circulation Lost ❑ Job Completed ❑X Mike Leslie Peter Cahill - - Page 5 of 5 11 CASING RUN IN TALLY WELL NAME SCU 43A-33 DATE 11/22/12 CASING SIZE 4.000 WEIGHT 9.50 CASING ID 3.548 GRADE L-80 THREAI VAM ST L Tubing CAPACITY 0.0122 bbls/ft TORQUE - MAXIMUM=1,600 MIN=1200 DISPLACEMENT 0.0046 bbls/ft SHOE DEPTH 11248.0 feet Coupling OD=4.0,Drift 3.423 HOLE TD 11250.0 feet Pin ID=3.468 MUD WT 9.50 ppg Joint Running Joint Depth BOUY FACTOR 0.85 Joint# Joint# Length Total Bottom Top REMARKS Bouyant Capacity Displmt on Rack in hole feet feet feet feet weight bbls bbls Off Rule' 2.00 Block Weight = 65,000 rrford Bullnose Float Shoe.PO#25268,Job A 1.52 1.52 11248.00 11246.48 19834-1-1 65,012 0.0 0.0 BakerLocked Joint Centrilizer w/stop ring 10' IA 39.17 40.69 11246.48 11207.31 from shoe 65,330 0.5 0.2 Baker Locked Joint 39.18 79.87 11207.31 11168.13 w/Centralizer Mid-joint B 1.62 81.49 11168.13 11166.51 Weatherford Float Collar 65,343 0.5 0.2 Baker Locked Joint 2B 39.22 120.71 11166.51 11127.29 w/CenlraliaerMid-joint 65,661 1.0 0.4 Landing Collar,#175, C LC 1.63 122.34 11127.29 11125.66 #CTI So 46618 65,356 0.5 0.2 3C 4 39.18 161.52 11125.66 11086.48 ,lointw/centralizer#4 65,674 1.0 0.4 5 5 39.23 200.75 11086.48 11047.25 Joint 65,675 1.0 0.4 6 6 39.21 239.96 11047.25 11008.04 Joint w/centralizer#5 65,993 1.5 0.6 7 7 39.22 279.18 11008.04 10968.82 Joint 65,993 1.5 0.6 8 8 39.19 318.37 10968.82 10929.63 Jointw/centralizer#6 66,311 2.0 0.7 9 9 39.18 357.55 10929.63 10890.45 Joint 66,311 2.0 0.7 10 10 38.77 396.32 10890.45 10851.68 Jointw/centralizer#7 66,625 2.4 0.9 11 11 39.19 435.51 10851.68 10812.49 Joint 66,629 2.5 0.9 12 12 35.22 470.73 10812.49 10777.27 Joint w/centralizer#8 66,915 2.9 1.1 13 13 38.77 509.50 10777.27 10738.50 Joint 66,943 2.9 1.1 14 14 38.44 547.94 10738.50 10700.06 Joint w/centralizer#9 67,255 3.4 1.3 15 15 39.20 587.14 10700.06 10660.86 Joint 67,261 3.4 1.3 16 16 39.19 626.33 10660.86 10621.67 Joint w/centralizer#10 67,579 3.9 1.5 17 17 38.01 664.34 10621.67 10583.66 Joint 67,570 3.9 1.5 18 _ 18 39.21 703.55 10583.66 10544.45 Joint w/centralizer#11 67,888 4.4 1.6 19 19 38.90 742.45 10544.45 10505.55 Joint 67,885 4.3 1.6 20 20 39.17 781.62 10505.55 10466.38 Joint w/centralizer#12 68,203 4.8 1.8 21 21 39.19 820.81 10466.38 10427.19 Joint 68,203 4.8 1.8 22 22 39.20 860.01 10427.19 10387.99 Joint w/centralizer#13 68,521 5.3 2.0 23 23 39.22 899.23 10387.99 10348.77 Joint 68,521 5.3 2.0 24 24 39.20 938.43 10348.77 10309.57 Joint w/centralizer#I4 68,839 5.8 2.2 25 25 39.19 977.62 10309.57 10270.38 Joint 68,839 5.8 2.2 26 26 39.18 1016.80 10270.38 10231.20 Joint w/centralizer#15 69,157 6.3 2.3 27 27 39.20 1056.00 10231.20 10192.00 Joint 69,157 6.3 2.3 28 28 39.21 1095.21 10192.00 10152.79 Joint w/centralizer#16 69,476 6.7 2.5 Pup,XO,Baker Liner, Hanger,C-2 Hyflo II 10130.89 Packer&PB 69,335 6.5 2.4 4.0 inch Production Liner. SCU 43A-33_FINAL.xls 7" casing tally 1/8/2013 10:15 AM nTubular Tally Tubular Information: Tubular Size: 2 7/8 AFE Number: 1212964 Well: SCU 43A-33 Start Date: Field: Swanson River Start Time: Platform: Date Landed: Foreman: Mike Leslie Time Landed: Rig: Doyon Arctic Fox Up-Weight: Completion Fluid Weight(PPG): 6%KCL Slack-off: Completion Fluid Type: Brine Weight set on Slips/HGR: Wellhead Make: Shaffer KD,13 5/8,3M Current Rig KB Elevation: 20.25 Original Rig KB Elevation: JT# Joint Description ID" OD" LENGTH Total TOP BTM. Run (in) (in) (ft) Length (ft) (ft) WLEG 1.00 1.00 10,116.21 10,117.21 345 1 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.61 32.61 10,084.60 10,116.21 \i:X Nipple(run with Plug)PT#792252 ' ._ 2.875 1.17 33.78 10,083.43 10,084.60 1 PUP-2 7/8,6.40,N-80,8R1) 2.441 2.875 6.21 39.99 10,077.22 10,083.43 Arrowset AS1-X Mechanical Packer 2.375 5.500 7.42 47.41 10,069.80 10,077.22 2 PUP-2 7/8,6..1-. 2.441 2.875 10.02 57.43 10,059.78 10,069.80 T-2 ON/OFF Tool w/X-Profile 2.31I: 5.500 1.71 59.14 10,058.07 10,059.78 3 PUP-2 7/8,6.4#,N-8 2.441 2.875 6.28 65.42 10,051.79 10,058.07 344 2 Joint 2 7/8,6.48,N-S0,8RD Tubing 2.441 2.875 31.88 97.30 10,019.91 10,051.79 4 PUP-2 7/8,6.48,N-8C, 2.441 2.875 3.80 101.10 10,016.11 10,019.91 GLM#1,2 7/8 SFO-1,8R1),Orfice 7.08 108.18 10,009.03 10,016.11 5 PUP-2 7/8,6.48,' 2.441 2.875 6.07 114.25 10,002.96 10,009.03 343 3 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.89 146.14 9,971.07 10,002.96 342 4 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.83 177.97 9,939.24 9,971.07 341 5 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 209.75 9,907.46 9,939.24 340 6 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 241.52 9,875.69 9,907.46 339 7 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.81 273.33 9,843.88 9,875.69 338 8 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.86 305.19 9,812.02 9,843.88 337 9 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.83 337.02 9,780.19 9,812.02 336 10 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.57 368.59 9,748.62 9,780.19 335 11 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 400.35 9,716.86 9,748.62 334 12 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.82 432.17 9,685.04 9,716.86 333 13 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 463.96 9,653.25 9,685.04 332 14 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.86 495.82 9,621.39 9,653.25 331 15 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.24 527.06 9,590.15 9,621.39 330 16 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.84 558.90 9,558.31 9,590.15 329 17 Joint 2 7/8,6.4#,N-80,SRD Tubing 2.441 2.875 31.75 590.65 9,526.56 9,558.31 6 PUP-2 7/8,6.4#,N-80,8RD 2.441 2.875 3.87 594.52 9,522.69 9,526.56 GLM#2,2 7/8 SFO-1,8RD,12 Port 7.08 601.60 9,515.61 9,522.69 7 PUP-2 7/8,6.44,N-80,8RD 2.441 2.875 6.07 607.67 9,509.54 9,515.61 328 18 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 639.44 9,477.77 9,509.54 327 19 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 671.24 9,445.97 9,477.77 326 20 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.70 702.94 9,414.27 9,445.97 325 21 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.75 734.69 9,382.52 9,414.27 324 22 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.84 766.53 9,350.68 9,382.52 323 23 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.87 798.40 9,318.81 9,350.68 322 24 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.83 830.23 9,286.98 9,318.81 321 25 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 862.01 9,255.20 9,286.98 320 26 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 893.80 9,223.41 9,255.20 319 27 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 925.60 9,191.61 9,223.41 318 28 Joint 2 7/8,6.4#,N-80,SRD Tubing 2.441 2.875 31.70 957.30 9,159.91 9,191.61 317 29 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.81 989.11 9,128.10 9,159.91 316 30 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.86 1,020.97 9,096.24 9,128.10 315 31 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.74 1,052.71 9,064.50 9,096.24 314 32 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.78 1,083.49 9,033.72 9,064.50 313 33 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 1,115.26 9,001.95 9,033.72 312 34 Joint 2 7/8,6.4#,N-80,SRD Tubing 2.441 2.875 31.71 1,146.97 8,970.24 9,001.95 311 35 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.60 1,178.57 8,938.64 8,970.24 310 36 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.74 1,210.31 8,906.90 8,938.64 8 PUP-2 7/8,6.48,N-80,8RD 2.441 2.875 3.64 1,213.95 8,903.26 8,906.90 GLM#3,2 7/8 SF0-1,8RD,12 Port 7.10 1,221.05 8,896.16 8,903.26 9 PUP-2 7/8,6.48,N-80,8RD 2.441 2.875 6.06 1,227.10 8,890.11 8,896.16 309 37 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.72 1,258.82 8,858.39 8,890.11 308 38 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 1,290.60 8,826.61 8,858.39 307 39 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 1,322.40 8,794.81 8,826.61 306 40 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.88 1,354.28 8,762.93 8,794.81 305 41 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.85 1,386.13 8,731.08 8,762.93 304 42 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.72 1,416.85 8,700.36 8,731.08 303 43 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.19 1,448.04 8,669.17 8,700.36 302 44 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.63 1,479.67 8,637.54 8,669.17 301 45 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.69 1,511.36 8,605.85 8,637.54 300 46 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 1,543.16 8,574.05 8,605.85 299 47 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 1,574.94 8,542.27 8,574.05 1 JT# Joint Description ID" OD" LENGTH Total TOP BTM. Run (in) (in) (ft) Length (ft) (ft) 298 48 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.57 1,606.51 8,510.70 8,542.27 297 49 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.75 1,638.26 8,478.95 8,510.70 296 50 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 1,670.03 8,447.18 8,478.95 295 51 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 31.84 1,701.87 8,415.34 8,447.18 294 52 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 1,733.65 8,383.56 8,415.34 293 53 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 1,765.44 8,351.77 8,383.56 292 54 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.86 1,797.30 8,319.91 8,351.77 291 55 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.89 1,829.19 8,288.02 8,319.91 290 56 Joint 2 7/8,6.4#,N-SO,8RD Tubing 2.441 2.875 31.87 1,861.06 8,256.15 8,288.02 289 57 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.81 1,892.87 8,224.34 8,256.15 288 58 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.85 1,924.72 8,192.49 8,224.34 287 59 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 1,956.52 8,160.69 8,192.49 286 60 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.48 1,987.00 8,130.21 8,160.69 285 61 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 2,018.76 8,098.45 8,130.21 284 62 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.82 2,050.58 8,066.63 8,098.45 283 63 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 31.81 2,082.39 8,034.82 8,066.63 282 64 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.89 2,114.28 8,002.93 8,034.82 10 PUP-2 7/8,6.48,N-80,8RD 2.441 2.875 3.64 2,117.92 7,999.29 8,002.93 GLM#4,2 7/8 SF0-1,8RD,12 Port 7.10 2,125.02 7,992.19 7,999.29 11 PUP-2 7/8,6.44,N-80,8RD 2.441 2.875 6.07 2,131.09 7,986.12 7,992.19 281 65 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.86 2,162.95 7,954.26 7,986.12 280 66 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.42 2,193.37 7,923.84 7,954.26 279 67 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.87 2,225.24 7,891.97 7,923.84 278 68 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.47 2,255.71 7,861.50 7,891.97 277 69 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.37 2,286.08 7,831.13 7,861.50 276 70 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 2,317.87 7,799.34 7,831.13 275 71 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 2,349.65 7,767.56 7,799.34 274 72 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.84 2,381.49 7,735.72 7,767.56 273 73 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.86 2,413.35 7,703.86 7,735.72 272 74 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 2,445.13 7,672.08 7,703.86 271 75 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.72 2,476.85 7,640.36 7,672.08 270 76 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.87 2,508.72 7,608.49 7,640.36 269 77 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.86 2,540.58 7,576.63 7,608.49 268 78 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.85 2,572.43 7,544.78 7,576.63 267 79 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.54 2,603.97 7,513.24 7,544.78 266 80 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.71 2,635.68 7,481.53 7,513.24 265 81 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.72 2,667.40 7,449.81 7,481.53 264 82 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.71 2,699.11 7,418.10 7,449.81 263 83 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.86 2,730.97 7,386.24 7,418.10 262 84 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 30.57 2,761.54 7,355.67 7,386.24 261 85 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.73 2,793.27 7,323.94 7,355.67 260 86 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.87 2,825.14 7,292.07 7,323.94 259 87 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.49 2,855.63 7,261.58 7,292.07 258 88 Joint 2 7/8,6A#,N-80,8RD Tubing 2.441 2.875 31.73 2,887.36 7,229.85 7,261.58 257 89 Joint 2 7/8,6.4#,N-80,8RW Tubing 2.441 2.875 31.87 2,919.23 7,197.98 7,229.85 256 90 Joint 2 7/8,6A#,N-80,8RD Tubing 2.441 2.875 31.76 2,950.99 7,166.22 7,197.98 255 91 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.69 2,982.68 7,134.53 7,166.22 254 92 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 3,014.44 7,102.77 7,134.53 253 93 Joint 2 7/8,6A#,N-80,8RD Tubing 2.441 2.875 31.75 3,046.19 7,071.02 7,102.77 252 94 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.17 3,077.36 7,039.85 7,071.02 251 95 Joint 2 7/8,6.44,N-S0,8RD Tubing 2.441 2.875 31.76 3,109.12 7,008.09 7,039.85 250 96 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.68 3,140.80 6,976.41 7,008.09 249 97 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.73 3,172.53 6,944.68 6,976.41 248 98 Joint 2 7/8,6A#,N-80,8RD Tubing 2.441 2.875 31.72 3,204.25 6,912.96 6,944.68 247 99 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.75 3,236.00 6,881.21 6,912.96 246 100 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.79 3,267.79 6,849.42 6,881.21 245 101 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.78 3,299.57 6,817.64 6,849.42 12 PUP-2 7/8,6.4#,N-80,8R1) 2.441 2.875 3.65 3,303.22 6,813.99 6,817.64 GLM#5, 2 7/8 SF0-1,8RD,12 Port 7.12 3,310.34 6,806.87 6,813.99 13 PUP-2 7/8,6.4#,N-80,8RD 2.441 2.875 6.09 3,316.43 6,800.78 6,806.87 244 102 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.79 3,348.22 6,768.99 6,800.78 243 103 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 30.68 3,378.90 6,738.31 6,768.99 242 104 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.83 3,410.73 6,706.48 6,738.31 241 105 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.86 3,442.59 6,674.62 6,706.48 240 106 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 31.21 3,473.80 6,643.41 6,674.62 239 107 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.82 3,505.62 6,611.59 6,643.41 238 108 Joint 2 7/8,6.44,N-80,81W Tubing 2.441 2.875 31.79 3,537.41 6,579.80 6,611.59 237 109 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.87 3,569.28 6,547.93 6,579.80 236 110 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.88 3,601.16 6,516.05 6,547.93 235 111 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 31.87 3,633.03 6,484.18 6,516.05 234 112 Joint 2 7/8,6.44,N-80,81W Tubing 2.441 2.875 31.85 3,664.88 6,452.33 6,484.18 233 113 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.69 3,696.57 6,420.64 6,452.33 232 114 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.86 3,728.43 6,388.78 6,420.64 231 115 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.84 3,760.27 6,356.94 6,388.78 230 116 Joint 2 7/8,6.44,N-80,812D Tubing 2.441 2.875 30.98 3,791.25 6,325.96 6,356.94 229 117 Joint 2 7/8,6.48,N-80,81W Tubing 2.441 2.875 31.73 3,822.98 6,294.23 6,325.96 228 118 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.74 3,854.72 6,262.49 6,294.23 227 119 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.75 3,886.47 6,230.74 6,262.49 226 120 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.71 3,918.18 6,199.03 6,230.74 225 121 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.91 3,950.09 6,167.12 6,199.03 224 122 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 31.88 3,981.97 6,135.24 6,167.12 223 123 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 31.74 4,013.71 6,103.50 6,135.24 222 124 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 31.70 4,045.41 6,071.80 6,103.50 221 125 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 31.71 4,077.12 6,040.09 6,071.80 220 126 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 31.25 4,108.37 6,008.84 6,040.09 219 127 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 31.76 4,140.13 5,977.08 6,008.84 218 128 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 31.38 4,171.51 5,945.70 5,977.08 2 JT# Joint Description ID" OD" LENGTH Total TOP BTM. Run (in) (in) (ft) Length (ft) (ft) 217 129 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.85 4,203.36 5,913.85 5,945.70 216 130 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.86 4,235.22 5,881.99 5,913.85 215 131 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 4,267.00 5,850.21 5,881.99 214 132 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.89 4,298.89 5,818.32 5,850.21 213 133 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 4,330.66 5,786.55 5,818.32 212 134 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.72 4,362.38 5,754.83 5,786.55 211 135 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.69 4,394.07 5,723.14 5,754.83 210 136 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.77 4,425.84 5,691.37 5,723.14 209 137 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.76 4,457.60 5,659.61 5,691.37 208 138 Joint 2 7/8,6.48,N-80,814D Tubing 2.441 2.875 31.71 4,489.31 5,627.90 5,659.61 207 139 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.64 4,520.95 5,596.26 5,627.90 206 140 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.75 4,552.70 5,564.51 5,596.26 205 141 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.24 4,583.94 5,533.27 5,564.51 204 142 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.79 4,615.73 5,501.48 5,533.27 203 143 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.70 4,647.43 5,469.78 5,501.48 202 144 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.73 4,679.16 5,438.05 5,469.78 201 145 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.70 4,710.86 5,406.35 5,438.05 14 PUP-2 7/8,6.4#,N-80,8RD 2.441 2.875 3.85 4,714.71 5,402.50 5,406.35 GLM#6,2 7/8 SF0-1,8RD,10 Port 7.07 4,721.78 5,395.43 5,402.50 15 PUP-2 7/8,6.48,N-80,8RD 2.441 2.875 6.25 4,728.03 5,389.18 5,395.43 66 146 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 4,759.83 5,357.38 5,389.18 199 147 Joint 2 7/8,6.48,N-80,8141W Tubing 2.441 2.875 31.75 4,791.58 5,325.63 5,357.38 198 148 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.80 4,823.38 5,293.83 5,325.63 197 149 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.12 4,854.50 5,262.71 5,293.83 196 150 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.71 4,886.21 5,231.00 5,262.71 195 151 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.81 4,918.02 5,199.19 5,231.00 194 152 Joint 2 7/8,6.48,N-80,81W Tubing 2.441 2.875 31.77 4,949.79 5,167.42 5,199.19 193 153 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 4,981.57 5,135.64 5,167.42 192 154 Joint 2 7/8,6.48,N-80,8121W Tubing 2.441 2.875 31.76 5,013.33 5,103.88 5,135.64 191 155 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2A41 2.875 31.73 5,045.06 5,072.15 5,103.88 190 156 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 5,076.82 5,040.39 5,072.15 189 157 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.88 5,108.70 5,008.51 5,040.39 188 158 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.52 5,140.22 4,976.99 5,008.51 187 159 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.76 5,171.98 4,945.23 4,976.99 186 160 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.77 5,203.75 4,913.46 4,945.23 185 161 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.53 5,235.28 4,881.93 4,913.46 184 162 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.73 5,267.01 4,850.20 4,881.93 183 163 Joint 2 7/8,6.48,N-80,81I1W Tubing 2.441 2.875 31.77 5,298.78 4,818.43 4,850.20 182 164 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.69 5,330.47 4,786.74 4,818.43 181 165 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.72 5,362.19 4,755.02 4,786.74 180 166 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.74 5,393.93 4,723.28 4,755.02 179 167 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.73 5,425.66 4,691.55 4,723.28 178 168 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.68 5,457.34 4,659.87 4,691.55 177 169 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.98 5,489.32 4,627.89 4,659.87 176 170 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 5,521.08 4,596.13 4,627.89 175 171 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.69 5,552.77 4,564.44 4,596.13 174 172 Joint 2 7/8,6.40,N-80,8RD Tubing 2.441 2.875 31.68 5,584.45 4,532.76 4,564.44 173 173 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.83 5,616.28 4,500.93 4,532.76 172 174 Joint 2 7/8,6.40,N-80,8RD Tubing 2.441 2.875 31.69 5,647.97 4,469.24 4,500.93 171 175 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.74 5,679.71 4,437.50 4,469.24 170 176 Joint 2 7/8,6.48,N-80,8121W Tubing 2.441 2.875 31.69 5,711.40 4,405.81 4,437.50 169 177 Joint 2 7/8,6.48,N-80,81W Tubing 2.441 2.875 31.87 5,743.27 4,373.94 4,405.81 168 178 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.73 5,775.00 4,342.21 4,373.94 167 179 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.85 5,806.85 4,310.36 4,342.21 166 180 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.88 5,838.73 4,278.48 4,310 36 165 181 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 30.86 5,869.59 4,247.62 4,278.48 164 182 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.72 5,901.31 4,215.90 4,247.62 163 183 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.87 5,933.18 4,184.03 4,215.90 j 162 184 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.84 5,965.02 4,152.19 4,184.03 161 185 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 5,996.81 4,120.40 4,152.19 160 186 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.77 6,028.58 4,088.63 4,120.40 159 , 187 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 6,060.36 4,056.85 4,088.63 158 188 Joint 2 7/8,6.4#,N-80,SRD Tubing 2.441 2.875 31.73 6,092.09 4,025.12 4,056.85 157 189 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.71 6,123.80 3,993.41 4,025.12 156 190 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.44 6,155.24 3,961.97 3,993.41 155 191 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.90 6,187.14 3,930.07 3,961.97 154 192 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 6,218.93 3,898.28 3,930.07 153 193 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.82 6,250.75 3,866.46 3,898.28 152 194 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.30 6,282.05 3,835.16 3,866.46 151 195 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.70 6,313.75 3,803.46 3,835.16 150 196 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.68 6,345.43 3,771.78 3,803.46 149 197 Joint 2 7/8,6.4#,N-S0,812D Tubing 2.441 2.875 31.75 6,377.18 3,740.03 3,771.78 148 198 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.81 6,408.99 3,708.22 3,740.03 147 199 Joint 2 7/8,6.48,N-80,8141W Tubing 2.441 2.875 31.76 6,440.75 3,676.46 3,708.22 146 200 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 30.83 6,471.58 3,645.63 3,676.46 145 201 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 6,503.35 3,613.86 3,645.63 144 202 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.81 6,535.16 3,582.05 3,613.86 143 203 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.26 6,566.42 3,550.79 3,582.05 142 204 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.80 6,598.22 3,518.99 3,550.79 141 205 Joint 2 7/8,6.48,N-80,8R1)Tubing 2.441 2.875 31.77 6,629.99 3,487.22 3,518.99 140 206 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.80 6,661.79 3,455.42 3,487.22 139 207 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.72 6,693.51 3,423.70 3,455.42 138 208 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 6,725.30 3,391.91 3,423.70 137 209 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 6,757.06 3,360.15 3,391.91 136 210 Joint 2 7/8,6.48,N-80,8RD Tubing 2.441 2.875 31.00 6,788.06 3,329.15 3,360.15 135 211 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.69 6,819.75 3,297.46 3,329.15 16 PUP-2 7/8,6.48,N-80,8RD 2.441 2.875 3.84 6,823.59 3,293.62 3,297.46 3 JT# Joint Description ID" OD" LE:NG Il l Total TOP BTM. Run (in) (in) (ft) Length (ft) (ft) GLM#7, 2 7/8 SF0-1,8RD,10 Port 7.07 6,830.66 3,286.55 3,293.62 17 PUP-2 7/8,6.4#,N-80,SRI) 2.441 2.875 6.07 6,836.73 3,280.48 3,286.55 134 212 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 6,868.49 3,248.72 3,280.48 133 213 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.68 6,899.17 3,218.04 3,248.72 132 214 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.16 6,930.33 3,186.88 3,218.04 131 215 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 6,962.11 3,155.10 3,186.88 130 216 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.97 6,993.08 _ 3,124.13 3,155.10 129 217 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.74 7,024.82 3,092.39 3,124.13 128 218 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 7,056.61 3,060.60 3,092.39 127 219 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.68 7,088.29 3,028.92 3,060.60 126 220 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.90 7,120.19 , 2,997.02 3,028.92 125 221 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.72 7,151.91 2,965.30 2,997.02 124 222 Joint 2 7/8,6.4#,N-80,8RD Tubing _, 2.441 2.875 31.90 7,183.81 2,933.40 2,965.30 123 223 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.82 7,215.63 2,901.58 2,933.40 122 224 Joint 2 7/8,6.4#,N-80,8RD Tubing . _2.441 2.875 31.70 7,247.33 2,869.88 2,901.58 121 225 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.81 7,279.14 2,838.07 2,869.88 120 226 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.54 7,309.68 2,807.53 2,838.07 119 227 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 7,341.44 2,775.77 2,807.53 118 228 Joint 2 7/8,6.40,N-80,8RD Tubing 2.441 2.875 31.74 - 7,373.18 _ 2,744.03 2,775.77 117 229 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.65 7,404.83 2,712.38 2,744.03 116 230 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.73 7,436.56 2,680.65 2,712.38 115 231 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.90 7,468.46 2,648.75 2,680.65 114 232 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 7,500.24 2,616.97 2,648.75 113 233 Joint 2 7/8,6.4#,N-80,SRD Tubing 2.441 2.875 31.67 7,531.91 2,585.30 2,616.97 112 , 234 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.75 7,563.66 2,553.55 2,585.30 111 235 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.44 7,595.10 2,522.11 2,553.55 110 236 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.70 7,626.80 2,490.41 2,522.11 109 237 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.74 7,658.54 2,458.67 2,490.41 108 238 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.88 7,690.42 2,426.79 2,458.67 107 239 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.08 7,721.50 2,395.71 2,426.79 106 240 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.39 7,752.89 2,364.32 2,395.71 105 241 Joint 2 7/8,6.4#,N-80,8RD Tubing _ 2.441 2.875 31.72 7,784.61 2,332.60 2,364.32 104 242 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 7,816.39 2,300.82 2,332.60 103 243 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 7,848.19 2,269.02 2,300.82 102 244 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 7,879.95 2,237.26 2,269.02 101 245 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.98 7,910.93 2,206.28 2,237.26 100 246 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.77 7,942.70 2,174.51 2,206.28 99 247 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.69 7,974.39 2,142.82 2,174.51 98 248 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.15 8,005.54 2,111.67 2,142.82 97 249 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 8,037.30 2,079.91 2,111.67 96 250 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 8,069.07 2,048.14 2,079.91 95 251 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.74 8,100.81 2,016.40 2,048.14 94 252 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 8,132.61 1,984.60 2,016.40 93 253 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.71 8,164.32 1,952.89 1,984.60 92 254 Joint 2 7/8,6.4#,N-80,8R13 Tubing 2.441 2.875 31.75 8,196.07 1,921.14 1,952.89 91 255 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 8,227.87 1,889.34 1,921.14 90 256 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.82 8,259.69 1,857.52 1,889.34 89 257 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.94 8,290.63 1,826.58 1,857.52 88 258 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 8,322.41 1,794.80 1,826.58 87 259 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.77 8,354.18 1,763.03 1,794.80 86 260 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.68 8,385.86 1,731.35 1,763.03 85 261 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.53 8,417.39 1,699.82 1,731.35 84 262 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 8,449.16 1,668.05 1,699.82 83 263 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.53 8,480.69 1,636.52 1,668.05 82 264 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.72 8,512.41 1,604.80 1,636.52 81 265 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.71 8,544.12 1,573.09 1,604.80 80 266 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 8,575.90 1,541.31 1,573.09 79 267 Joint 2 7/8,6.40,N-80,8RD Tubing 2.441 2.875 31.80 8,607.70 1,509.51 1,541.31 78 268 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.76 8,639.46 1,477.75 1,509.51 77 269 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.47 8,669.93 1,447.28 1,477.75 76 270 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 8,701.71 1,415.50 1,447.28 75 271 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 8,733.47 1,383.74 1,415.50 74 272 Joint 2 7/8,6.4#,N-80,8R1)Tubing 2.441 2.875 31.85 8,765.32 1,351.89 1,383.74 73 273 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 8,797.12 1,320.09 1,351.89 72 274 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.48 8,828.60 1,288.61 1,320.09 71 275 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.38 8,858.98 1,258.23 1,288.61 70 276 Joint 2 7/8,6.40,N-80,8RD Tubing 2.441 2.875 31.73 8,890.71 1,226.50 1,258.23 69 277 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 8,922.50 1,194.71 1,226.50 68 278 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.75 8,954.25 1,162.96 1,194.71 67 279 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.46 8,985.71 1,131.50 1,162.96 66 280 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 9,017.50 1,099.71 1,131.50 65 281 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 9,049.26 1,067.95 1,099.71 64 282 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 9,081.06 1,036.15 1,067.95 63 283 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.75 9,112.81 1,004.40 1,036.15 62 284 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.74 9,144.55 972.66 1,004.40 61 285 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 9,176.35 940.86 972.66 60 286 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.75 9,208.10 909.11 940.86 59 287 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.74 9,239.84 877.37 909.11 58 288 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.70 9,271.54 845.67 877.37 57 289 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 9,303.30 813.91 845.67 56 290 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.72 9,335.02 782.19 813.91 55 291 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.89 9,366.91 750.30 782.19 54 292 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.75 9,398.66 718.55 750.30 53 293 Joint 2 7/8,6.40,N-80,8RD Tubing 2.441 2.875 31.72 9,430.38 686.83 718.55 52 294 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.86 9,462.24 654.97 686.83 51 295 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.74 9,493.98 623.23 654.97 50 296 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 9,525.78 591.43 623.23 4 JT# Joint Description ID" OD" LENGTH Total TOP BTM. Run (in) (in) (ft) Length (ft) (ft) 49 297 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.78 9,557.56 559.65 591.43 48 298 Joint 2 7/8,6.4#,N-80,814D Tubing 2.441 2.875 31.47 9,589.03 528.18 559.65 47 299 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.90 9,619.93 497.28 528.18 46 300 Joint 2 7/8,6.48,N-80,8111W Tubing 2.441 2.875 31.90 9,651.83 465.38 497.28 45 301 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.88 9,683.71 433.50 465.38 44 302 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.74 9,715.45 401.76 433.50 43 303 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.75 9,747.20 370.01 401.76 42 304 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 9,778.98 338.23 370.01 41 305 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 31.66 9,810.64 306.57 338.23 40 306 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 30.87 9,841.51 275.70 306.57 39 307 Joint 2 7/8,6.48,N-80,8141W Tubing 2.441 2.875 31.73 9,873.24 243.97 275.70 38 308 Joint 2 7/8,6.4#,N-80,811D Tubing 2.441 2.875 31.79 9,905.03 212.18 243.97 37 309 Joint 2 7/8,6.4#,N-80,811D Tubing 2.441 2.875 31.85 9,936.88 180.33 212.18 36 310 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 31.23 9,968.11 149.10 180.33 35 311 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.75 9,999.86 117.35 149.10 34 312 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 10,031.62 85.59 117.35 33 313 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.73 10,063.35 53.86 85.59 32 314 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 31.80 10,095.15 22.06 53.86 18 2.441 1.11 10,096.26 20.95 22.06 Danger,LDS to P11' 0.70 10,096.96 20.25 20.95 ,;i>,; 20.25 10,117.21 (0.00) 20.25 tubing Hanger: 10,117.21 (0.00) (0.00) Shaffer T-55-AJ 10,117.21 (0.00) (0.00) 7"x 3 1/2 IBT Lift&Suspend 10,117.21 (0.00) (0.00) 3"Type"H"BPV Profile 10,117.21 (0.00) (0.00) 61/4"Neck 10,117.21 (0.00) (0.00) (18)- Pup Joints 10,117.21 (0.00) (0.00) (7)-2 7/S SFO-1 GLMs 10,117.21 (0.00) (0.00) 10,117.21 (0.00) (0.00) EXTRA JOINTS 10,117.21 (0.00) _(0.00) 31 315 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.75 10,148.96 (31.75) (0.00) 30 316 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.87 10,180.83 (63.62) (31.75) 29 317 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 10,212.62 (95.41) (63.62) 28 318 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.69 10,244.31 (127.10) (95.41) 27 319 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 10,276.08 (158.87) (127.10) 26 320 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.83 10,307.91 (190.70) (158.87) -25 321 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.75 10,339.66 (222.45) (190.70) 24 322 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 10,371.44 (254.23) (222.45) 23 323 Joint 2 7/8,6.44,N-80,812D Tubing 2.441 2.875 31.77 10,403.21 (286.00) (254.23) 22 324 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.92 10,435.13 (317.92) (286.00) 21 325 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.88 10,467.01 (349.80) (317.92) 20 326 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.74 10,498.75 (381.54) (349.80) 19 327 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.82 10,530.57 (413.36) (381.54) 18 328 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.70 10,562.27 (445.06) (413.36) 17 329 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.71 10,593.98 (476.77) (445.06) 16 330 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 10,625.77 (508.56) (476.77) 15 331 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.83 10,657.60 (540.39) (508.56) 14 332 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.94 10,689.54 (572.33) (540.39) 13 333 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.71 10,721.25 (604.04), (572.33) 12 334 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.70 10,751.95 (634.74) (604.04) 11 335 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.72 10,783.67 (666.46) (634.74) 10 336 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 31.77 10,815.44 (698.23) (666.46) 9 337 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 31.72 10,847.16 (729.95) (698.23) 8 338 Joint 2 7/8,6.44,N-80,8RD Tubing 2.441 2.875 31.90 10,879.06 (761.85) (729.95) 7 339 Joint 2 7/8,6.4#,N-S0,8RD Tubing 2.441 2.875 31.79 10,910.85 (793.64) (761.85) 6 340 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.81 10,942.66 (825.45) (793.64) 5 341 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.75 10,974.41 (857.20) (825.45) 4 342 Joint 2 7/8,6.44,N-80,8RD Tubing_ 2.441 2.875 31.92 11,006.33 (889.12) (857.20) - 3 343 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.70 11,038.03 (920.82) (889.12) 2 344 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.92 11,069.95 (952.74) (920.82) 1 345 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.74 11,101.69 (984.48) (952.74) 309 37 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.72 5 Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. SCU 43A-33 Date 23-Nov-12 County Kenai Peninsula Burough State Alaska Supv. Mike Leslie CASING RECORD TD 11,250'MD/11,097'TVD Shoe Depth: 11,248'MD/11,095'TVD PBTD: 11,125'MD/10,982'TVD Casing(Or Liner)Detail Setting Depths No.of Jts. Size Wt. Grade THD Make Length Bottom Top Shoe 4" STL Wfd 1.52 11,248.00 11,246.48 2 4" 9.5 L-80 STL 78.35 11,246.48 11,168.13 F.Collar _ 4" _ STL Wfd 1.62 11,168.13 11,166.51 1 4" 9.5 L-80 STL 39.22 11,166.51 11,127.29 L.Collar 4" STL BOT 1.63 11,127.29 11,125.66 25 jts 4" 9.5 L-80 STL 972.87 11,125.66 10,152.79 L Hanger 4" 9.5 STL BOT 21.90 10,152.79 10,130.89 Totals j 1,117.11 Csg Wt.On Hook: 8500 Type Float Collar: Float No.Hrs to Run: 4 Csg Wt.On Slips: 8500 Type of Shoe: DJ/Float Casing Crew: Wfd I Fluid Description: 9.6 ppg WBM / 6%KCI/PHPA / PV=12 YP=19 HTHP=11.2 Liner hanger Info(Make/Model)• Baker Hughes,C-2 Hyflo III pkr&PBR Liner top Packer?: X Yes No Liner hanger test pressure: 1000 psi/10 min Centralizer Placement: Solid body centralizers on each joint in shoe track,every other joint to TOL CEMENTING REPORT Preflush(Spacer) Type: Mud Push II Density(ppg) 10 5 Volume pumped(BBLs) 20 bbls Lead Slurry Type: Conventional Class G Blended Density(ppg) 15.8 ppg Volume pumped(BBLs) 30 bbls Mixing/Pumping Rate(bpm): 3.5 bpm Tail Slurry Type: Conventional Class G Blended Id Density(ppg) 15.3 ppg ' Volume pumped(BBLs) 30 bbls Mixing/Pumping Rate(bpm): 3.5 bpm I- Post Flush(Spacer) Type: Density(ppg) Rate(bpm): Volume: c LL Displacement: Type: Mud Density(ppg) 9.6 ppg Rate(bpm): 4 bpm Volume(actual/calculated): 116.5/115 FCP(psi): 2900 psi Pump used for disp: Cmt Unit Plug Bumped? X Yes No Bump press 3700 psi Casing Rotated? Yes X No Reciprocated? Yes X No %Returns during job 100 • Cement returns to surface' X Yes No Spacer returns? X Yes No Vol to Surf. 46 bbl cmt/20 bbl spacer Cement In Place At: 0:00 Date: 11/23/2012 Estimated TOC: 130'(TOL) Method Used To Determine TOC: Circulated out cement above liner top Preflush(Spacer) Type: Density(ppg) Volume pumped(BBLs) , Lead Slurry Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tail Slurry w Type: a Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): u) Post Flush(Spacer) o o Type: Density(ppg) Rate(bpm): Volume: wDisplacement: Type: Density(ppg) Rate(bpm): Volume(actual/calculated): FCP(psi): Pump used for disp: Plug Bumped? Yes No Bump press Casing Rotated? Yes No Reciprocated? Yes No %Returns during job Cement returns to surfaces Yes No Spacer returns? Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: _ Method Used To Determine TOC: WELLHEAD Make Shaffer Type T-55L1 Serial No. Size 7-1/16" W.P. 5000 Test Head To 5000 PSIG 10 MIN X OK Remarks: Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 43A-33 50-133-10168-01-00 212146 11/7/12 1 Daily Operations: 11/07/2012-Wednesday Finish cleaning rock washer pits, move mud lab, MWD, mud logger units, haul miscellaneous equipment, prep pipe shed & rock washer for moving,remove service loop&kelly hose f/TD,remove TD from torque tube,L/D TD.Injected 1425 bbls drilling mud. 11/08/2012-Thursday Install boom section in 150 T crane,scope derrick down,unstring blocks,lay derrick down,remove top section on rock washer,lay gas buster over,remove equipment slide,move pipe houses, remove wind walls on rig floor.Move support buildings to 43A-33, pick up mats&haul to 43A-33. Lay herculite and mats on well 43A-33.Inject 1,338 bbls drilling mud. 11/09/2012-Friday Remove derrick from sub,remove upper section of sub,haul derrick,upper sub to new well,pick up mats,haul pit module and crane to next pad.Spot sub base over 43A-33 well,install derrick,spot mcc building behind sub,raise derrick,string up blocks,scope derrick up. 11/10/2012-Saturday Set support buildings-pits,pump houses,motor houses boiler houses.Set pipe houses,cattle chute,hook up utility lines. 11/11/2012-Sunday Rig up utility line,rebuild mud saver valve on top drive,install mud saver.Install lights,hook up service loops to TD,hook up gas buster,hook up super choke lines to dog house, clean up 44-33 location of felt & herculite. Install stairs on support buildings, install muffler stack on engines and boilers, hook up utility lines, install mud line blankets, install flow line f/ pits, install beaver slide, replace valve seats in mud pumps,repair psi relief valve on pumps,install saver sub on TD,install bails&elevators. 11/12/2012-Monday Continue hooking up utility service lines, organize equipment. Pull cellar cross beams & remove hand rails. Function test pumps, hole fill pump, change out kill line, pick up annular, make up to double gate, remove well cap, install adaptor spool, drilling spool, single gate and mud cross,tighten flanges. Pick up test joint,xo's&test plug&set test plug, make up floor valves, perform body test on BOP's. HCR on kill line failed,change out HCR.Test BOP's @ 250 low 4,000 psi high for 10 minutes each. Rig accepted @ 06:00 11-12-2012. 11/13/2012-Tuesday Continue testing BOP's, 250 low, 4,000 high for 10 minutes each. Change out HCR kill valve. Close blind rams& HCR valve, hydraulic hose failure on blinds,continue testing blind rams,choke valve#10,her kill @ 250 low 4,000 high.Rig down testing equip, blow down choke&kill lines&set wear bushing,PJSM, bring BHA to rig floor,load pipe house with hwdp,strap and talley BHA.P/U clean out assembly BHA.Service rig and top drive. P/u hwdp&4" drill pipe and run in hole to 1,482'.Cut and slip drilling line,CBU @ 5 bpm w/230 psi,stand back 14 stds in derrick,continue picking up drill pipe and trip in hole. Page 1 of 1 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 43A-33 50-133-10168-01-00 212146 11/7/12 Daily Operations: 11/14/2012-Wednesday Continue testing BOP's, 250 low,4,000 high for 10 min each. Change out HCR kill valve.Close blind rams &HCR valve, hydraulic hose failure on blinds, continue testing blind rams,choke valve#10, HCR kill at 250 low 4,000 high. Rig down testing equip, blow down choke &kill lines&set wear bushing. PJSM,bring BHA to rig floor,load pipe house w/hwdp,strap and tally BHA.P/U clean out assembly BHA.Service rig and top drive.P/u hwdp&4"drill pipe and run in hole to 1,482',cut and slip drilling line,CBU at 5 bpm w/230 psi,stand back 14 stds in derrick,continue picking up drill pipe and trip in hole. 11/15/2012-Thursday Trip in hole picking up 4"dp.Repair leaky air manifold on draw works.Continue picking up drill pipe.CBU @ 7,500',350 gpm,1500 psi, P/u 130k S/o 125k. Continue tripping in hole picking up drill pipe,TIH with(4)stands from derrick. M/U TD and break circulation.Wash cement stringers f/10,370'.Tag hard cement @ 10,404'. UP 178k, DN 165k. Pump 38 bbl high vis sweep.Circulate to surface&divert sweep to isolated pit. Minimal solids recovered during circulation.8.3 bpm,1,950 psi.Test 6 5/8 casing t/2,100 psi f/30 min,0 psi bleed. Monitored 13 3/8 x 6 5/8 ann, 13 3/8 x 6 5/8 starting pressure=80 psi. No increase witnessed during test. Bleed pressure and blow down surface lines. POOH with clean out assembly f/10,404'.SLM stands on trip out of hole. Clear rig floor of drilling tools.PJSM,rig up Pollard E-line,make up CIBP on e-line.RIH with CIBP.Correlate setting depth and set CIBP @ 10,366'Trip out of hole w/wire line. 11/16/2012-Friday Pull out of hole w/wire line and rig down wire line.M/U whip stock,p/u slide,remove three shear screws and shipping bolt,install 40K shear bolt,scribe whip stock to MWD.Trip in hole with whip stock T/2,214',p/u 60K,s/o 60K.Continue RIH with whip stock T/10,137',TIH t/10,355',break circ,p/u 178, s/o 165k,tag top of cibp @ 10,370',orient whip stock@ 83.8o AZ, s/o 25k, P/U 12K overpull confirm whip stock set,slack off 50K and shear whip stock. Displace well w/228 bbls 9.5 KCL mud @ 7bpm,2,420 psi.Mill knock lug off @ 10,353'and continue milling window F/10,358'T/10,368',continue milling , through window and new hole. 11/17/2012-Saturday Drill 20 feet of formation f/10,366't/10,386'&ream window with upper mills.Work through window w/rotation.Stop pumps&slide thru window with minimal drag.Flow check well for 10 min(no flow). R/U&perform F.I.T to 13.0 ppg EMW.MD 10,386,TVD 10,298',MW 9.5 ppg,test pressure,1875 psi. (15 psi bleed, 10 min). Monitor well for 30 min during crew change. Well static. Lay down single. Pump Slug. Blow down top drive. POOH f/10,350'T/ 4,750'with window mill assembly. Replace broken bolt on TD carriage,inspect derrick,TOH F/4,750', LID bah, lower mill 1/8 out,window mill 1/8 out, upper mill in ga.Clear rig floor of drilling tools. PJSM w/Baker,get new drilling tools to floor, Pick up BHA.Surface test MWD, MWD test failed.TOH lay down MWD,p/u new motor,TIH and test motor.Motor tested OK.Blow down top drive&trip in hole. 11/18/2012-Sunday TIH with drilling assembly, BHA#4 to TOW @ 10,353'. Fill pipe every 2,500'.Orient tool face to 90 deg and slide thru window w/pump off.Set down @ 10,367'. BOW @ 10,366'.Attempt to pick up, but overpulled 10k.Work pipe to get free.Attempt to pass window,but having trouble w/air supply to rig clutch.Troubleshoot and solve clutch issue.Work pipe in attempt to exit window. Determined formation undergauged.Establish circulation&rotation @ 10,366.50'.Ream OH t/10,386'.Drill 5 5/8"production hole as per Directional Plan f/10,386't/10,577',GPM 306,2,700 psi,40 RPM,5k wob,3.5K on bott torque,2k off.Rotate and slide F/10,577'T/10,700'.Average ROP 21 ft/hr. 11/19/2012-Monday Drill 5 5/8"production hole from 10,570'T/10,954',vp/u 190k,s/o 165k,rtw 160k,300 gpm,2700 psi,4k torque on bottom,3k off,ADT 9.5 hrs,ART 7.1, AST 2.4.Drill F/10,594'T/11,170'.P/u 190k,S/0 165k,Rot 160k,302 gpm,2800 psi,circulate bottoms up.Drill F/11,170'T/11,250'.Circulate bottoms up @ 11,250'. Monitor well,well static,trip out to window. Monitor well,service top drive, blocks,grease crown.Trip in hole,wash down last stand, no fill. Pump hi visc sweep and circulate sweep out.Trip out of hole five stands, pump dry job, continue TOH to window. Drop rabbit,continue tripping out of hole.Current depth-4,900'. 11/20/2012-Tuesday POOH with drilling assembly f/4,900'to BHA @ 706.BHA:rack back HWDP(drifted)and Jars.Grade bit 1,2,CT,S,X,I,WT,TD.Clear floor of slip/trip hazards. PJSM. R/U Halliburton E-Line service. Hang sheaves and make up tool string.Safety stand down with Hilcorp Drilling Manager and crews. RIH with quad combo tools. Resistivity/Sonic/Neutron Density/Gamma Ray. Pull repeat pass to caliper tools. RIH.Set down on obstruction @ 10,625'.Work tool string attempting to pass obstruction(failed).POOH logging open hole from 10,620'to window @ 10,353'.Continue to POOH logging cased hole from 10,353'to surface, rig down wire line. Pull wear ring, rig up to test bop's.Test BOPs&related equipment on 4"test joint to 250/4,000,Annular @ 250/2,500.Test VBRs&annular with 2 7/8 test joint.Perform accumulator precharge test.Test LEL&H2S Gas Alarms.Jim Regg(AOGCC)waived witness of BOP test. Page 1 of 1 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 43A-33 50-133-10168-01-00 212146 11/7/12 Daily Operations: 11/21/2012-Wednesday Finish testing BOPS. R/D BOP test equipment and install wear bushing. Clear floor of excess equipment. Make up BHA#5. RR1, bit bub w/float, 5.5" Stab, (6) HWDP, Jars, (12) HWDP. Pick up (5) joints Dp BHA = 720.44, TIH w/BHA #5 on 4" Dp f/720' t/10,353'. Fill pipe every 3,000'. Slip & cut drilling line. Reset block calibration and C.O.M. Break circulation. TIH f/10,353'. Wash & ream f/10,540'. Torque increased f/3k to 4k between 10,570' & 10,640'. Wash and ream tight interval x 3. Continue TIH f/10,740't/TD @ 11,250' (no fill). Pump 31 bbl high vis sweep and circulate to surface. 8.3 bpm, 2,950 psi. Sweep returned 23 bbls over calc. displacement & with minimal increase in solids. Flow check well. Pump slug & rack back (1) stand. Blow down TD. POOH f/11,220'to Window @ 10,353'. Hole was in good condition with no overpulls. Monitor well for 10 min 11/22/2012-Thursday RIH w/Halliburton Quad Combo tools. GR, Neutron Density, Sonic, Resistivity. Tag obstruction @ 10,625'. Work tool string in attempt to pass (failed). POOH, remove Neutron Density Tool and RIH (run #2). Tag obstruction at same depth. Had to pull max(11k)and hold to free tool string. POOH, remove metal"Hole Finder"and RIH (run#3). Set down @ same depth. (10,625') POOH, add flex joint between GR and Resistivity tool. RIH. Set down @ 10,530'. POOH, RD Halliburton logging services and prep to run 4" production liner. Weatherford arrived on location. PJSM. Rig up WOT equipment and prep rig floor. Make up shoe track. Fill with mud and verify operation of floats. P/U & RIH w/4" VAM, 9.5#, L-80 production liner. Torque turn conn t/1,500 ft/lb ave. M/U liner hanger.Verify(9) pins to shear @ 2,650'. UP 34k, DN 33k, length 1,117'. M/U std#1 and break circ. 11/23/2012-Friday production liner on Dp f/8,595' t/10,350'. Circulate annular volume and record parameters. UP 167, DN 153, 3 bpm, 710 psi. M/U Baker TD plug dropping head w/15' pup on btm and 10' on top. Stage on Skate. TIH f/10,350'. Drag increased 7k @ 10,630' and then diminished over following stand. Tag TD @ 11,250' w/no fill. L/D sgl, make up Baker TD head & break ' circulation. Circ & condition f/cement job, 3 bpm, 880 psi. R/U wash-up tee after first circ. Build mud push and rig up C cementers. PJSM w/Schlumberger and crew. Blow through surface lines and thaw frozen valves. Cement 4"_production liner: Pump 5 bbl H2O, PT lines to 1,000/4,500, pump 20 bbl. Mud push II, blow down mud line, pump 30 bbls 15.8 ppg lead cement,followed by 30 bbl 15.3 ppg tail cement. Flush cement lines to tank. Drop Dp wiper plug and displace with 116.5 bbls drilling mud. Caught cement @ 58 bbls, latch wiper plug @ 104 bbl and bump landing collar @ 116.5. Reciprocated pipe until 83 bbls displaced (25 bbls cement in annulus). Bumped plug @ 00:00. Increase pressure after bump to 3,500 psi to initiate hanger set. Slack off (no set) increase to 4,500 psi and set hanger 2 ft. off bottom in up stroke. Rotate 20 turns to right and release from liner. P/U to place dogs above TOL. Set C-2 Hyflo III Pkr w/50k while rotating @ 20 rpm. Apply 1,000 psi and unstring from assembly. CBU to clear cement from annulus. Dumped 46 bbl of cement and 20 bbl of mud push, plus 11/24/2012`-Saturday POOH w/liner running tool f/6,800' t/ BHA @ 570'. L/D HWDP & inspect BOT liner running tool. Dog sub didn't shear (packer isn't set). Make up jet sub. Wash well head and BOP to clear possible cement. LD same. Make up bit sub, dog sub, pup and XO. TIH with packer setting assembly to 10,080'. Make up TD and break circ. Wash down and tag Liner top @ 10,131'. Set down ,_1(n/\ w/50k slowly looking for indication of packer set. Work pipe and establish rotation. Set do w/70k w/rotating. Work pipe and spud T.O.L w/70k x 2. Witness slight bump on indicator during initial set, but no positive indication. Rig up and test casing/liner&packer to 2,500 psi for 30 min (0 psi bleed). Flow check Well. Pump slug. POOH with packer setting assy 11/25/2012-Sunday Single in the hole w/2 7/8" SLH-90 to clean out 4" Liner (34) joints. Change rig tongs and handling equip. M/U 6 5/8" scraper/brush assy. BHA = 1,083.3'. TIH with clean out BHA on 4" Dp f/1,083' to 10,070'. CBU above TOL to clear heavy mud prior to entering 4" Liner. 5 bpm, 1,300 psi. TIH f/10,070'. Enter liner with no tag. Break circ & tag landing collar @ 11,126'. Circulate and condition while rigging up transfer hose to R4R tank. PJSM. Pump remaining 100 bbls of mud and displace with fresh water. Take returns to R4R storage,via choke manifold. 3 bpm 1,400 psi. Open annular and divert returns to shaker pits when water returned. Rotate @ 40 rpm and reciprocate pipe. Increase rate to 5.5 bpm, 1,900 psi. Pump an additional annular Page 1 of 2 11 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 43A-33 50-133-10168-01-00 212146 11/7/12 Daily Operations: 11/26/2012- Monday TIH with 6 5/8" scraper/brush assembly f/1,250'. No problem entering T.O.L. Tag landing collar @ 11,126'. "Fire Drill" in the pump room. Good response f/crew members & good "tail gate" meeting in dog house to review lessons learned. PJSM regarding displacement. Close annular. Pump clean water down Dp, taking returns to R4R tank via choke manifold. 4.3 bpm, 1,580 psi. Open annular and continue circulating an additional hole volume taking returns to pits until clean. Pump 2 lb/bbl caustic 5%; Barakleen &300 vis Barazan high vis sweep. Displace wash train with filtered 6% KCL.Trip out of hole laying down drill pipe. 11/27/2012-Tuesday Trip out of hole laying down 4" drill pipe. L/d XO's, scraper, brush, change out elevators to 2 7/8", rig up tongs. 1/d 2 7/8", clean out string, rig down tongs, pull wear bushing. Run 2 7/8"completion tubing. Rig up and freeze protect tubing. Page 2 of 2 Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 43A-33 Drilling 50-133-10168-01 212-146 11/8/12 Daily Operations: 11/28/2012-Wednesday Rig up and freeze protect tubing and annulas with 7.5 bbls diesel. Make up shaffer T- 55-AJ 7" hanger, make up landing joint, land hanger P/U. 4/6' rotate pipe 1/4 turn to the right and set mechanical packer @ 10,069.80' ; Rig down tubing tongs, and clean rig floor. Rig up and test tubing @ 3,000 psi,test ok, test annulas @ 2,500 psi test ok. Rig down testing equipment & blow down all lines, kill, choke, mud lines. Remove flow line, drilling nipple, p/u potato masher, remove choke & kill lines ; koomey lines, sert 2 way check, nipple down bops. Injected 1,325 bbls drilling fluid, 65 bbls water, 5.6 bbls diesel 11/29/2012-Thursday Install tree,tighten bolts. Rig up and test hanger void @ 5,000 psi F/5 mins, test tree @ 5,000 psi F/ 10min. Rig released @ 12:00 11-28-2012. 11/30/2012- Friday 12/1/2012-Saturday 12/2/2012-Sunday 12/3/2012- Monday Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 43A-33 Completion 50-133-10168-01 212-146 12/3/12 12/4/12 Daily Operations: 11/28/2012-Wednesday See Drilling activity. 11/29/2012-Thursday See Drilling activity. 11/30/2012- Friday No activity to report. 12/1/2012-Saturday No activity to report. 12/2/2012-Sunday No activity to report. 12/3/2012- Monday MIRU Haliburton E-Line Unit. Ran Radial Cement Bond Log. Ran C/O Mode Log, KUT-h Log,and Neutron log 10 times. 12/4/2012-Tuesday MIRU Pollard E-Line. RIH w/23' perf gun and ccl tools. Logged well from 11,100'to 10,700'. Correlated depths with tie-in log. Perforated H-10 from 10,944'to 10,967' with 23' gun, 6 shots p/ft. POOH. RDMO Pollard e-Line unit. Turned over to production. Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 43A-33 Completion 50-133-10168-01 212-146 12/3/12 12/9/12 Daily Operations: 12/05/2012-Wednesday No activity to report. 12/06/2012-Thursday No activity to report. 12/07/2012- Friday No activity to report. 12/08/2012-Saturday Mobe to location. Rig up lubricator. Pressure test 250 psi low and 2,500 psi high. RIH with 2-1/8" x 15' HC, 6 spf, 60 deg phase and tie in to Pollard GR/CCL dated 12/4/12. Spot perf gun from 10,931' to 10,946' per Final Approved Perf Form. Tubing pressure 920 psi. Fired guns and saw no increase in psi change. POOH. All shots fired. FL was 8,150'. RIH with 2-1/8" x 2' HC, 6 spf, 60 deg phase and tie in to Pollard GR/CCL dated 12/4/12. Spot perf gun from 10,929'to 10,931' per Final Approved Peri Form. Tubing pressure 1,058 psi. 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Anchorage, Alaska 99501-3572 LAsmm-Y' Main: 907.279.1433 Fax: 907.276.7542 Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, Soldotna Creek Unit 43A-33 Sundry Number: 312-437 Dear Mr. Keller: 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 this2D day of November, 2012. Encl. �V z RECEIVED STATE OF ALASKA ���i\�\1 NOV 19 2012 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS ����C 20 MC 25.280 1.Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate 0• Pull Tubing ❑ Time Extension ❑ Operations Shutdown ❑ Re-enter Susp.Well ❑ Stimulate ❑ Alter Casing ❑ Other.Comelete Q 2.Operator Name: Hilcorp Alaska,LLC • 4.Current Well Class: 5.Permit to Drill Number Exploratory ❑ Development 2 212-146 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic ❑ Service El6.API Number. Anchorage,Alaska 99503 50-133-10168-01• 7.If perforating: 8.Well Name and Number What Regulation or Conservation Order governs well spacing in this 000l? Co 123A Wdlr Saldotna Creek Unit(SCU)43A-33•• Will planned perforations require a spacing exception? Yes I No 9.Property Designation(Lease Number): 10.Field/Pool(s): A028890• 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): 11,250' 11,098' 11,110' 10,969' 11,110' N/A Casing Length Size MD ND Burst Collapse Structural Conductor 28' 22" 28' 28' Surface 1,496' 13-3/8" 1,496' 1,496' 2,730psi 1,130psi Intermediate 10,350' 6-5/8" 10,350' 10,263' 7,440psi 5,760psi Production Liner 1,100' 4" 11,250' 11,098' 7,910psi 6,590psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A and N/A N/A and N/A 12.Attachments: Description Summary of Proposal Q 13.Well Class after proposed work: Detailed Operations Program ❑Q BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development❑✓ • Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 11/21/12 Oil ❑., Gas 0 WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: N/A WINJ ❑ GINJ 0 WAG ❑ Abandoned ❑ Commission Representative: N/A GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Luke Keller Phone: 907-777-8395 Email Ikeller@hilcorp.com Printed Name //Luke Keller Title Drilling Engineer SignatureZZ ////// _ Phone 907-777-8405 Date 1( / ( N 1iJ/,Z COMMISSION USE ONLY / Conditions of approval: Notify Commission so that a representative may witness Sundry Number: .5 e L (- (37 Plug Integrity ❑ BOP Test [( Mechanical Integrity Test ❑ Location Clearance ❑ J �-( Other: JrAc_-, _ _he, j'/-- rc.g" 6a.��`L - ow itsfi °F. fit°ziw i-� Spacing Exception Required? Yes Z No ❑ lI Subsequent Form Required: /f —41 6-7--- ?4..„56......„ APPROVED BY Approved by: COMMISSIONER T E COMMISSION Date: /l— 20 — /Z 11,20.(2)1A4 t 4�� 21 ms Submit Forrn and �� 0RhI &f 'NAt Approved applrc�t7trti Id 2 mon a date of approval. Attachment m Duplicate \Il` 40e • Well Prognosis Well: SCU 43A-33 Ililcora Alaska,LL, Date: 11/17/2012 Well Name: SCU 43A-33 API Number: 50-133-10168-01-00 Current Status: New Cased Oil Producer Leg: N/A Estimated Start Date: November 21St, 2012 Rig: Doyon Arctic Fox Reg.Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts 777-8398 Permit to Drill Number: 212-146 First Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (M) Second Call Engineer: Luke Saugier (907) 777-8395 (0) AFE Number: 1212964 Maximum Expected BHP: -2,500 psi @ 10,562 Based on reservoir modeling of known nearby reservoir pressures) Max. Allowable Surface Pressure: -0 psi Based on 6% KCI brine left in the well Wellhead will be installed on tree prior to perforating well. Brief Well Summary This well was sidetracked with the Doyon Arctic Fox in November 2012. The completion and following work is proposed to be completed with Doyon Arctic Fox. _ Notes Regarding Wellbore Condition This program continues from the original 10-401 approved by the State and BLM. It starts after the casing has been swapped from mud to filtered 6% KCI and the casing pressure tested to 2,100 psi. Completion procedure: 1. POH and LD Drill Pipe 2. RU E-line 3. Run CBL w/Gamma ray/CCL from bottom to the top of the liner hanger. 4. RD e-line 5. RIH w/completion on new 2-7/8" 8rd EUE tubing (mechanical packer and gas lift valves as shown on proposed schematic), set packer at approx. 10,080ft. a. Set packer and land tubing hanger with 5-7,000 lbs of compression on tubing hanger. Close the lockdown pins. L— Cc),r s es. br b. Drop RHCP prong (plug is preset in the x-nipple below the packer by Pollard.) P&G s' c. Pressure test (chart for 30 min) the tubing to 3000 psi and casing/annulus to 2,500 psi. 6. Set'3PV, ND BOP, NU Tree test (5,000 psi). 7. RDMO rig and equipment. 8. Pull BPV. 9. RU slickline to pull RHCP prong and plug 10. RU production lines to well. 11. Unload filtered brine with gas lift. 12. Once fluid is lifted from well, 13. SI Gas lift and bleed pressure for underbalanced perforating (approx. 25-30% underbalanced) 14. RU eline (PT lubricator to 2000 psi) 15. RIH with 2-1/8" scalloped HC perf guns, with deep penetrating charges, 6 spf and 60deg Phase. Well Prognosis Well: SCU 43A-33 Hilcorp Alaska,Lb Date: 11/17/2012 16. Shoot the following interval a. Approx. H8(10,950 To 11,000) 17. Flow to production and test interval (if desired rate is not achieved, perforate additional zones, based on the geologists recommendations) Attachments: 1. Proposed Schematic Swanson River Unit 111 Well SCU 43A-33 Proposed Hileorp Alaska,LLC Ground Elev:124'Above MSL Casing & Tubing KB-THF:18.6' Size Type Wt Grade Conn. ID Top Btm J ;, I - , l 22" Conductor - - - Surf 28' 22' . 141 D 13-3/8" Surf.Csg 54.5 J-55 Buttress 12.25 Surf 1,496' 2 All 1 '+r 28 P-110 BTC 5.665 Surf 127' 1, w 24 N80 BTC 5.796 127' 6,600' 6-5/8" Intermediate 28 P-110 BTC 5.665 6,600' 6,607 3 I 13-3/8" 1. 24 P-110 BTC 5.796 6,607' 10,165' li Pc 28 P-110 BTC 5.665 10,165' 10,350' 4 4" Prod Lnr 9.5 L-80STL 3.548" 10,150' 11,250' r Tubing "r 2-7/8" Production 6.4 N-80 8RD 2.441 Surf ±10,150 a 5 MI i ii JEWELRY DETAIL No. Depth ID OD Item 41 6 'a&1 i 4.;, 1 20' 2.44" - Tubing Hanger L i,t' 2 ±3,300' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port 11 � 7 Ili 1 3 ±5,400' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 10 port ' 4 ±6,800' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port t. 1 i0 5 ±7,996' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port 8 AIN i 11 6 ±8,876' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port dry 7 ±9,499' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port 9 ; 8 ±9,930' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD Orifice 10 'e 9 ±10,060' 2.313" 6.5" On/Off Tool w/X Nipple sI " i „ I r Top of Liner 10 ±10,080' 2.44" 6.5" Arrowset AS1-X Mechanical Packer I ' Hanger @,±10,150' 11 ±10,150' 2.313" 3.5" WL Entry Guide w/X Nipple e 11 II 11 $. v Whipstock set 6-5/8" .q $e 12 i,4r @+/-10,290' L' kS re, PERFORATION DETAIL y Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) SPF Ft Detail % ii H-10 ±10,950 ±11,000 ±10,828 ±10,870 6 50 2-1/8"HC guns ,1, 1, � r' 4 t, 164 i' 210 r 4 o� 4 '+ Ipq>> / 'I'O 10 til 4" A. PBTD=11,110' TD=11,250'/TVD=11,098' Max Deviation 20deg @ 10,310' Updated by TDF 11/19/2012 w P.\\����; THE STATE Alaska Oil and Gas �� �� °fALAS� _ _ — Conservation Commission owl " � �h ., GOVERNOR SEAN PARNELL 333 West Seventh Avenue OFmrlmm !,- Anchorage, Alaska 99501-3572 -ALAS"' Main: 907.279.1433 Fax: 907.276.7542 Paul Mazzolini Drilling Manager Hilcorp Alaska, LLC Y Li-‘6 3800 Centerpoint Drive Anchorage, AK 99516 Re: Swanson River Field, Hemlock Oil Pool, SCU 43A-33 Sundry Number: 312-419 Dear Mr. Mazzolini: 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. er, , rir n . ► .rm, - Commissioner DATED this day of November, 2012. Encl. 1 Hilcorp Paul Mazzolini Hilcorp Alaska, LLC &Dow i;em Drilling Manager P.O. Box 244027 Anchorage,AK 99524-4027 10/26/2012 Tel 907 777 8369 Email pmazzolini@hilcorp.com Commissioner RECEIVED Alaska Oil & Gas Conservation Commission OCT 3 333 W. 7th Avenue0 2011_ Anchorage, Alaska 99501 �1^ V OGC^ Re: Soldotna Creek Unit 43A-33 Dear Commissioner, Enclosed for review and approval is the 10-403 "Change to Approved Procedure" to highlight the below(3)changes to the approved APD. 1. The KOP has been moved from 10,200' MD to 10,350' MD(WLM). 2. The starting MW will be 9.5 ppg instead of10.7 ppg. 3. An updated survey of the well has been conducted since submittal of the 10-401 APD. The BHL as shifted approx 49'to the NW as a result of the new survey. New well coordinates: Top of productive horizon: 2004.8 FSL, 739' FEL, Sec 33, T8N, R9W, SM X=346913.82, Y=2463175.8, NAD 27,ASP Bottom Hole Location: 2218 FSL, 687.6 FEL, Sec 33, T8N, R9W, SM X=346967.39, Y=2463389.54, NAD 27,ASP Attached is the(P3)directional plan which takes the updated gyro and new kick-off point into account. If you have any questions, please don't hesitate to contact myself at 777-8369 or Luke Keller at 777- 8395. Sincerely, ?act.--Qfl/ Paul Mazzolini Drilling Manager Hilcorp Alaska, LLC Page 1 of 1 RECEIVED STATE OF ALASKA OCT 3 0 2012 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon 0 Plug for Redrill ❑ Perforate New Pool ❑ Repair Well 0 Change Approved Program Q • Suspend 0 Plug Perforations❑ Perforate❑ Pull Tubing 0 Time Extension 0 Operations Shutdown 0 Re-enter Susp.Well ❑ Stimulate❑ Alter Casing 0 Other: 0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC Exploratory 0 Development Q . 212146 • 3.Address: Stratigraphic 0 Service ❑ 6.API Number 3800 Centerpoint Dr,Anchorage,AK,99524 50-133-10168-01-00 7.If perforating: 8.Well Name and Number. What Regulation or Convervation Order governs well spacing in this pool? 123A • SCU Will planned perforations require a spacing exception? Yes ❑ No 0 (. 3t1 .- 33 9.Property Designation(Lease Number): 10 Field/Pool(s): . .r y Hemlock Oil Pool/Swanson River Field • • �J A028890 ' 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) 10,995 10891 10370 10282 10370 10,692 Casing Length Size MD ND Burst Collapse Structural Conductor 28' 22" 28' 28' - - Surface 1496' 13-3/8" 1496' 1496' 2730 1330 Intermediate Production 10,995' 6-5/8" 10,995' 10,882' 7440 5760 Liner Perforation Depth MD(ft). Perforation Depth ND(ft). Tubing Size: Tubing Grade: Tubing MD(ft): See attached Schematic See attached Schematic None None None Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): N/A N/A 12.Attachments: Description Summary of Proposal Q 13.Well Class after proposed work Detailed Operations Program ❑ BOP Sketch Q Exploratory ❑ Stratigraphic❑ Development Q Service ❑ 14. Estimated Date for 11/5/2012 15.Well Status after proposed work: Commencing Operations: Oil Q • Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR 0 SPLUG 0 17 I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact q0 -777- 83 6I9, /� Email p 1At-► J3oI iI C. hi ico.,p.coIli Printed Name ?i4k.l.- 46 ZZOL/A/ i Title T 1fL 1 LL l AC.J. It, Signature r, la Phone r Date ib z�rf2prZ COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: X19-u 11 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: 416....../—) Spacing Exception Required? Yes 0 No (rt .sequei .rm equired /0 ,4(07 4111014APPROVED BY '�f / Approved by: COFViM13SIONER THE COMMISSION Date: /4/ (/ r1/ F �. Tik�4s NDV4 5 012►..' Submit Form and OR Fr4.p or e dl10/2012) Approvedd appl�icat`ion is valid for 122 mOonths from the a e of app ova. „ qt, hments m uplicate Swanson River Field Well SCU 43A-33 SCHEMATIC PTD:212146 Ilil�•ur�,_duck,.l.lt. CASING DETAIL RK= 15' SIZE WT GRADE ID TOP BTM 22" - - 28' 13-3/8" 54.5 J-55 12.615 Surface 1,496' 6-5/8" 28 P-110 5.791 Surface 127' 6-5/8" 24 N-80 5.921 127' 6,600' 6-5/8" 28 P-110 5.791 6,600' 6,607' 6-5/8" 24 P-110 5.921 6,607' 10,165' 6-5/8" 28 P-110 5.791 10,165' 10,995' JEWELRY DETAIL No Depth ID OD Item 1 10370 Top of Cement 2 10,430 Cement Retainer 3 10,692' Milled Inflatable Bridge Plug w/ debris on top and fill below 1 .1-:.:7;;;240.-' PERFORATION DETAIL G2 Zone Interval(MD) Interval(ND) Length Date Description 10/19/2005 6 hpf 2"Omega Power 10,562' 10,582' 10,461' 10,480' 20' lets 11/21/2005 4spf 1-11/16"Pivot guns 1 G2 HB W50 10,591' 10,596' 10,489' 10,493' 5' 11/21/2005 4spf Pivot 3 10,604' 10,607' 10,501' 10,504' 3' 11/21/2005 4spf 1-11/16"Pivot ' HB-2/3 guns HB-4/5 HB-1 10,660' 10,668' 10,553' 10,561' 8' 4hpf s.r SO WSO 10,676' 10,677' 10,569' 10,569' 1' Squeeze perf,5spf HB-2/3 10,695' 10,741' 10,586' 10,630' 46' 4 hpf HB-10 HB-4/5 10,746' 10,811' 10,635' 10,696' 40' 11/1/1960 4 hpf ,0:67,1;,y.. 44 WSO 10,815' 10,815' 10,700' 10,700' 1' Squeeze perf,5spf TD=10,995'/PBTD=10,986' HB-10 10,950' 10,968' 10,828' 10,845' 18' 12/5/1995 6 hpf,2-1/8",Enerjet Guns,0 phase Spud Date: 12/30/60 Completed:3/8/61 P&A'd: 9/26/2012 Updated 10/29/12 by LEK , a ::..,. 0 ri/ .-. a ,--• ,....,.--.. 0 r° 0 0 .* 23 y p y o y S 1 M a 0 -n o' C) -, Cl) sr o ti PJ g "� € O :; O "'3 N m P 'y 0 b C : y 7 w r Y r' f'a r. eo y b 1 m— q, yz 1 . r { el:, W C N H aWi "~" ^xCI Hr \ , g �, v r3 O Oy y M M Pc n �. c C" o `�7 : co cil T "� o °' o X @ O eo '' �' < `t CD cr ' no 1-3 H < o b 1 " - MM y 9 N € 0 0. 0 V Z CD MIDA � 0 y A AInt p h y .r Cl' _ O : ft" n � W W w A. -1 -. 4-r,--I 5 y 000 001-) 000 0 °qCr0 e.I.,.0CD n [ o C� fn G V] 01 0. 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N N A C 3 IIII W 5 Co NUCC CO OCNO AGG V, 0.MI MI Mill� OMtyOo G G G C G G G -o 'C 'O -o 'r3 t3 `O S O 0 0 0 0 O O A110 a Hilcorp Alaska, LLC VG�U Location: Cook Inlet,Alaska(Kenai Peninsula) Slot: SCU 343-33 KE Field: Soldotna Creek Unit Well: SCU343-33 Facility: SCU 343-33(43A-33) Wellbore: SCU43A-33 BAES IIilirorp Alaska,LLC Plot reference wellpath is SCU43A-33 Version#3 True vertical depths are referenced to Arctic Fox(RTE) Grid System:NAD27/TM Alaska SP,Zone 4(5004),US feet Measured depths are referenced to Arctic Fox(RTE) North Reference:True north Arctic Fox(RTE)to Mean Sea Level:142.5 feet Scale:True distance Mean Sea Level to Mud line(At Slot:SCU 343-33):0 feet Depths are in feet Coordinates are in feet referenced to Slot Created by:jonethoh on 17-Oct-12 Scale 1 Inch-,0h Easting(ft) 125 -100 -75 -50 -25 0 25 1 I I 1 I 1 I —1000 —975 —950 8600 +SCU43A-33 TD: 19-Sep-12 —925 9750— 900 9900— 10050— + SCU43A-33 H10. 19-Sep-12 —875 Z —850 m. 10200— -1-SCU43A-33 H7: 19-Sep-12 co L Tie On/KOP ani —825 ❑ 10350— 4.00°/100ft v SCU43A-33 H5: 19-Sep-12 End of 4°Build/Turn > SCU43A-33 G2: 19-Sep-12+ + SCU43A-33 H3: 19-Sep-12 —800 at• 10500— SCU43A-33 HKT: 19-Sep-12 ± SCU43A-33 HKT: 19-Sep-12 SCU43A-33113: 19-Sep-12+ —775 10650— SCU43A-33 1-15: 19-Sep-12+ SCU43A-33 H7: 19-Sep-12+ —750 10800— SCU43A-33 H10: 19-Sep-12+ SCU43A-33 02: 19-Sep-12 —725 10950— SCU43A-33 Ta 19-Sep-12+ ' ..acted TD —700 11100— 11250 1 1 1 1 1 1 —875 450 600 750 900 1050 1200 Vertical Section(ft) Scale 1inch=300'001It Azimuth 356.24°with reference 0.00 N,0.00 E Soldotna Creek Unit • II 43A-33 Ilik o.p Mala,1.0 Soldotna Creek Unit 43A-33 10-3/4"x 6-5/8" Soldotna 11 fit 1/t iii lit 11t Hydril Doyon Drilling GK 11'-5000 11"5M Hydril V BOP iii Ill Iii 111111 DI�LI Hydril V ` II=1� I w . 7 ,EMIR III III III III III 4111111 11 : °IH..±,V.:.N EC> € � FM' iii ill Ilii l' -� � 1 4 _ Hydril V = - pII 1„'5000 If! 1111111 I11 III Crossover spool 11 5M X 7 1/16 5M iii III Ifi III iii el ^,-I�N�":��O(o)F��� "it 1 0)0 le-i-: in _ e is :,. 1p .°Y.:—. . BIZ /`t7 Davies, Stephen F (DOA) ��� `" `_`� _3,-l�� From: Luke Keller[Ikeller@hilcorp.com] Sent: Monday, October 29, 2012 2:06 PM To: Schwartz, Guy L (DOA); Paul Mazzolini Cc: Davies, Stephen F (DOA) Subject: RE: 10-403 Change to Approved Procedure for SCU 43A-33 Guy, Reservoir pressure is driving the mud weight. Hemlock pressure in this fault block is approx 5.4 ppg EMW. We want to keep the MW as low as possible to avoid a lost returns or stuck pipe incident. Even at 9.5 ppg, we are still 4 ppg(2200 psi) overbalanced. Because we are kicking off deeper, we do not expect to be in communication with the lower tyonek water flow. We are seeing much of the same in SCU 44-33. We are having to elevate the MW as a result of communication with the lower tyonek waterflow. In doing so, we are significantly overbalanced with the Hemlock. Signs of differential sticking while drilling and on trips have been observed which indicate a significant overbalance with the reservoir. Let me know if this is unclear or if a more elaborate explanation is necessary. Thanks, Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 From: Schwartz, Guy L (DOA) [mailto:guv.schwartz@alaska.gov] Sent: Monday, October 29, 2012 1:50 PM To: Luke Keller Cc: Davies, Stephen F (DOA) Subject: RE: 10-403 Change to Approved Procedure for SCU 43A-33 Luke, Thanks for the heads up. Can you elaborate on the mud weight change and what is driving the change? Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Luke Keller Jmailto:Ikeller@hilcorD.coml Sent: Monday, October 29, 2012 9:54 AM To: Schwartz, Guy L (DOA); Paul Mazzolini; Stephanie Klemmer Subject: 10-403 Change to Approved Procedure for SCU 43A-33 Guy, See attached 10-403 "Change to Approved Procedure"to highlight changes to the approved permit to drill for SCU 43A- 33 (PTD#: 212-146, API#: 50-133-10168-01-00) . This well is next in line for the Arctic Fox. 1 The original, signed documents will be couriered to your office later today or tomorrow. Thanks, Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 2 Page 1 of 2 Schwartz, Guy L (DOA) From: Luke Keller[Ikeller@hilcorp.com] Sent: Monday, October 29, 2012 2:06 PM To: Schwartz, Guy L (DOA); Paul Mazzolini Cc: Davies, Stephen F (DOA) Z(L ([4 (o Subject: RE: 10-403 Change to Approved Procedure for SCU 43A-33 0-- Guy, - Guy, Reservoir pressure is driving the mud weight. Hemlock pressure in this fault block is approx 5.4 ppg EMW. We want to keep the MW as low as possible to avoid a lost returns or stuck pipe incident. Even at 9.5 ppg, we are still 4 ppg (2200 psi) overbalanced. Because we are kicking off deeper, we do not expect to be in communication with the lower tyonek water flow. We are seeing much of the same in SCU 44-33. We are having to elevate the MW as a result of communication with the lower tyonek waterflow. In doing so, we are significantly overbalanced with the Hemlock. Signs of differential sticking while drilling and on trips have been observed which indicate a significant overbalance with the reservoir. Let me know if this is unclear or if a more elaborate explanation is necessary. Thanks, Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 From: Schwartz, Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent: Monday, October 29, 2012 1:50 PM To: Luke Keller Cc: Davies, Stephen F (DOA) Subject: RE: 10-403 Change to Approved Procedure for SCU 43A-33 Luke, Thanks for the heads up. Can you elaborate on the mud weight change and what is driving the change? Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Luke Keller Lmailto:lkeller@hilcorp.coml Sent: Monday, October 29, 2012 9:54 AM To: Schwartz, Guy L (DOA); Paul Mazzolini; Stephanie Klemmer Subject: 10-403 Change to Approved Procedure for SCU 43A-33 Guy, 10/29/2012 Page 2 of 2 See attached 10-403 "Change to Approved Procedure"to highlight changes to the approved permit to drill for SCU 43A-33 (PTD#:212-146,API#:50-133-10168-01-00). This well is next in line for the Arctic Fox. The original,signed documents will be couriered to your office later today or tomorrow. Thanks, Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 10/29/2012 w w\1��� s7 THE STATE Alaska Oil and Gas ��' ��'� °fALAS� Conservation Commission . t€1}1> ti - 11 GOVERNOR SEAN PARNELL 333 West Seventh Avenue OA, D Anchorage, Alaska 99501-3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 Paul Mazzolini Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99524 Re: Swanson River Field, Hemlock Oil Pool, SCU 43A-33 Hilcorp Alaska, LLC Permit No: 212-146 Surface Location: 1245' FSL, 625' FEL, SEC. 33, T8N, R9W, SM Bottomhole Location: 2188' FSL, 649' FEL, SEC. 33, T8N, R9W, SM Dear Mr. Mazzolini: Enclosed is the approved application for permit to re-drill the above referenced development well. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce is contingent upon issuance of a conservation order approving a spacing exception. Hilcorp Alaska, LLC assumes the liability of any protest to the spacing exception that may occur. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, (21-44.7 PCathy Foerster Chair DATED this day of October, 2012. cc: Department of Fish & Game, Habitat Section w/o encl. (via e-mail) Department of Environmental Conservation w/o encl. (via e-mail) RECEIVED STATE OF ALASKA SEP 2 5 2012 ' ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL AOGCC 20 AAC 25.005 1a Type of Work: lb.Proposed Well Class: Development-Oil ❑Q Service- Winj ❑ Single Zone El 1c.Specify if well is proposed for: Drill ❑ Redrill Stratigraphic Test ❑ Development-Gas El Service-Supply ❑ Multiple Zone ❑ Coalbed Gas ❑ Gas Hydrates ❑ Re-entry ❑ Exploratory ❑ Service- WAG ❑ Service-Disp ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC Bond No. J.;.>35 . 220,352e3-- 7, SCU 43A-33 3.Address: 6.Proposed Depth: y'L7'it 12.Field/Pool(s): 3800 Centerpoint Dr,Anchorage,AK,99524 MD: 11,159 • TVD: 11,023 Hemlock Oil Pool • / 4a Location of Well(Governmental Section): 7.Property Designation(Lease Number): j'wci_GtS��/moi Lam-fie! Li Surface: 1245'FSL,625'FEL,Sec 33,T8N,R9W,SM A028890 • /c�•.sr•'A-- Top of Productive Horizon: i ,' CV 8.Land Use Permit: 13.Approximate Spud Date: 1984'FSL,682'FEL,Sec 33,T8N,R9W,Silt $ j(7 N/A 10/22/2012 Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 2188'FSL,649'FEL,Sec 33,T8N,R9W,S M. 400 acres 649 ft 4b Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL:142.6 feet 15.Distance to Nearest Well Open Surface:x- 347019 y- 2462415.3 - Zone-4 GL Elevation above MSL:124 feet to Same Pool: 1103'(SCU 33-33) 16 Deviated wells: Kickoff depth: 10,350 feet • 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 21 degrees / Downhole: 2999 psig Surface: 1917 psig 18 Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Conn Length MD TVD MD TVD (including stage data) 5-5/8" 4" 9.5 L-80 STL 1009 10150 10072 11,159 11,023 136.5 ft3 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth TVD(ft): Plugs(measured): Effect.Depth MD(ft): Effect.Depth TVD(ft): Junk(measured): 10,995' 10,880' 10,692' 10,586' 10,586' Casing Length Size Cement Volume MD TVD Conductor/Structural Surface 1496 13-3/8" 1496 1496 Intermediate - Production 10995 6-5/8" 10635 10200 Liner Perforation Depth MD(ft): 10,562'-10,968' Perforation Depth TVD(ft): 10,461'-10,845' 20 Attachments: Property Plat Q BOP Sketch Q Drilling Program ❑] Time v.Depth Plot ❑� Shallow Hazard Analysis❑ Diverter Sketch❑ Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050 requirements❑� 21 Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. ^� Contact Printed Name �19L4,L. MAZZ j Ll A.i( Title A11.t..uNG M$M 4c.BA Signature ?c tdX i' Phone/ ?07.777—8'3/.q Date °(1/2 Z ` Commission Use Only Permit to Drill API Number: Permit Approv See cover letter for other Number: ��Z ( r 7 50 /5-5—A)16-6--&0.)(_.) Date: �� �J `�j requirements. Conditions of approval: If box is checked,/wwell may not be used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained in shales: 7fOther: 4 Loc, r f,.; sot. '7 f Samples req'd: Yes El No Q ❑"Mud log req'd: Yes No g SCJ/ H2S measures: Yes❑ No[ Directional svy req'd: Yes [V No ❑ (,-..ye,-; 7 / 4 APPROVED BY THE COMMISSION DATE /D- 3-— (Z {�, ,COMMISSIONER 21 ,6 S—.1 Z... ORIGINAL(/ ,, j ,......._ Form 10-401(Revised 7/2009) This permit is valid for 24 months from the date of approval(20 AAC 25.005(9)) Submit in Duplicate I'4 7v I° HilcorpPaul Mazzolini Hilcorp Alaska,LLC ramp Compaq Drilling Manager P.O. Box 244027 Anchorage,AK 99524-4027 Tel 907 777 8369 9/21/2012 Email pmazzolini@hilcorp.com Commissioner Alaska Oil&Gas Conservation Commission RECEIVED 333 W. 7th Avenue Anchorage,Alaska 99501 SEP 2 5 2012 Re: Soldotna Creek Unit 43A-33 AOGCC Dear Commissioner, Enclosed for review and approval is the application for the Permit to Drill the Soldotna Creek Unit 43A- ' 33. SCU 43A-33 is a development oil well planned to be re-drilled in a NNE direction from the parent wellbore SCU 343-33 utilizing the existing casing program down to 10,350'MD/10,262'TVD. SCU 343-33 will be permanently plugged and abandoned to a depth of 10,400'MD/10,312'TVD. The original perforations were in the Hemlock formation from 10,562'to 10,968'MD. At 10,350'MD/10,262'TVD,the parent wellbore will be sidetracked and a 5-5/8"x 809'open hole section drilled to a total depth of 11,159'MD/11,023'TVD. SCU 43A-33 is a twinning wellbore to the original, SCU 343-33 well. Maximum inclination will be 21 deg. Drilling operations are expected to commence approximately Oct 22nd, 2012 depending on the progress of other ongoing projects. Prior to the commencement of drilling operations, the Williams Pulling Unit will be mobilized and conduct wellbore preparation operations for the sidetrack operation. A 10-403 will be submitted for this • operation which includes: 1. Removing the existing production tree. 2. Pulling the existing 2-7/8"tubing. 3. Permanently plugging and abandoning perforated intervals to 10,400'MD. 4. Conduct mechanical integrity tests of cmt plug and cmt retainer. 5. Conduct a gyro survey on electric line. 6. Set a CIBP @ 10,371'to use as an anchor for the Whipstock. -r A spacing exception is required for this well.✓ 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. The Hemlock is potentially hydrocarbon bearing throughout the section. 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 Design Summary. Hilcorp Alaska, LLC Page 1 of 2 4. Formation integrity test procedure. 5. Planned casing&cement program(Well Design Summary) 6. Diverter system will not be used. An 11" 5M BOP(3 ram &annular)will be used while drilling and completing the well. A BOP schematic is attached. 7. Drilling fluid program 8. Tabulation of predicted depths with equivalent formation pressures. 9. Requirements of 20 AAC 25.025 have been met. a. Blanket bond issued for Swanson River, bond no.22035263 10. Copy of drilling design summary. 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, ?aA4P 074Vitre Paul Mazzolini Drilling Manager Hilcorp Alaska,LLC Page 2 of 2 Swanson River Hilcorp Well SCU 43A-33 Well Design Summary En Company SCU 43A-33 Well Design Summary pi A.,al it .514 SCU 43A-33 is a development oil well planned to be sidetracked out of 6- 5/8" production casing in the existing SCU 343-33 wellbore. A 5-5/8" x 809' open hole section is planned from 10,350' MD / 10,263' TVD to 11,159' MD / 11,023' TVD. Integrated subsurface and 3-D geological interpretations, in conjunction with previous production data indicates that stranded oil reserves remain in the Hemlock 1-10 benches between the E&F faults. High on structure, the H1-5, & H10 are the primary targets. Reserves aren't recoverable in existing wellbores due to lack of take-points or mechanical condition of other existing wellbores (as is the case with the SCU 343-33 wellbore) in the fault block. SCU 43A-33 is a twinning wellbore to SCU 343-33 reaching a maximum of 21 degrees inclination. No H2S is expected to be encountered during the drilling & completion of • SCU 43A-33. The well will be completed with a 4" production liner & 3-1/2" gas lift assy. Well is planned to be drilled by Doyon's Arctic Fox. The Arctic Fox is a winterized, multi-module drilling unit, with a 400k telescoping double mast. Basic Well Information Well Name: SCU 43A-33 Estimated Spud Date: 10/22/2012 Field: Swanson River Productive Horizon: Hemlock Total Depth: 11,159' MD / 11,023' TVD • 9/21/2012 Page 1 of 9 , . n Swanson River Well SCU 43A-33 Hilcorp Well Design Summary E an Well Coordinates: Surface Location: 1245' FSL, 625' FEL, Sec 33, T8N, R9W, S X=347018.7, Y=2462415.3, NAD27, ASP, Zone 4 - X= 1487041 .6, Y=2462176.5, NAD83, ASP, Zone 4 Top of Prod Horizon: 1984' FSL, 682' FEL, Sec 33, T8N, R9W, S X= 346970.77, Y= 2463155.18, NAD27, ASP, Zone 4 X= 1486993.7, Y= 2462916.4, NAD83, ASP, Zone 4 Planned BHL: 2188' FSL, 649' FEL, Sec 33, T8N, R9W, S X= 347006.1, Y= 2463358.9, NAD27, ASP, Zone 4 X= 1487029.0, Y= 2463120.1, NAD83, ASP, Zone 4 Ground Elevation: 124' AMSL • KB elevation: 18.6' Existing SCU 343-33 Casing Design Hole Tube Weight Length Top Btm MD/TVD Size O.D. (lbs / ft) Grade Conn (ft) MD/TVD (ft) (in) (in) (ft) - 13-3/8 54.5 J-55 BTC 1496 WH 1496 6-5/8 28 P-110 BTC 127 WH 127 6-5/8 24 N-80 BTC 6473 127 6600 - 6-5/8 28 P-110 BTC 7 6600 6607 6-5/8 24 P-110 BTC 3558 6607 10165 6-5/8 28 P-110 BTC 830 10165 10995 Planned SCU 43A-33 Casing & Tubing Design Size O.D.le Weight Grade Conn Length MD/TVDTopBtm MD/TVD (. ) (lbs / ft) (ft) (ft) (ft) (in) In [le 5-5/8" 4" 9.5 L-80 VAM STL 1009 10150/ 1 1 159 / 10072 11023 Tbg 3-1/2" 9.3 L-80 EUE 10100 WH 10100 All casing will be new,PSL 1 (100%mill inspected, 10%inspection upon delivery to ISA in Fairbanks) 9/21/2012 Page 2 of 9 • Swanson River Well SCU 43A-33 Hilcorp Well Design Summary cneny(yummy Well Control Summary Hole Section Equipment Test Pressure (psi) • 1 1" 5M Hydril GK Annular BOP • 1 1" 5M Hydril Double ram (fixed pipe rams in top cavity, blind rams in bottom Test Pressures: 5-5/8" cavity) 250/4000 • 11 " 5M drilling spool (3-1/8" outlets) (Annular 250/2500 psi) • 1 1 " 5M Hydril Single ram (Casing rams in ram cavity) Test Pressures: 5-5/8" • 3-1/8" 5M Choke Manifold 250/4000 (Annular 250/2500 psi) Schematics of the well control equipment are attached for reference. , Well control equipment will be tested every 14 days. An exception to the requirement to have a check valve in the kill line is requested. Operator will install a manually operated 5M 3-1/8"valve&a 5M 3-1/8" HCR valve on the kill line side of the mud cross. The manual valve will be the internal/master valve. The operator feels there is a freeze plug risk associated with installation of a check valve in the kill line. All BOP tests to be held for 10 min per OOGO No.2, III.A.i. Primary closing unit: 1 ea.-Olio,6 station,3000 psi, 180-gallon accumulator unit,with a remote control panel in the doghouse. Accumulator location depicted in attached Rig Layout. 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. 9/21/2012 Page 3 of 9 Swanson River Well SCU 43A-33 Hilcorp Well Design Summary Enemy company Anti-Collision Evaluation Summary SCU 43A-33 will be sidetracked from the parent wellbore SCU 343-33 at 10,350'. Other than the existing wellbore, there are no anti-collision issues with offset wellbores (SF > 1 .3). SCU 43A-33 will be drilled using a mud motor and MWD. Surveys will be taken every 95' while drilling. Formation Integrity Testing Test Point, Projected Test Fluid Density Projected Projected 20' Below... Depth (TVD) Type Used for Test Test (EMW Surface ppg) Pressure 6-5/8" 10,262 FIT 10.7 13 t/ 1227 psi window Note:Anticipated fracture gradient at the 6-5/8"window depth(10,262'TVD)is expected to be.728 psi/It based on offset field test data. An FIT of 13 ppg was chosen to allow for a(2.3)ppg(or 1227 psi)kick margin while drilling with a 10.7 ppg fluid density. Casing Testing Fluid Density in Test String Casing Pressure Test Duration Casing Burst (PSI) 6-5/8" Casing 9.7 ppg 2100 30 min 7440 psi 4" Liner 10.7 ppg 2100 ' 30 min 7910 psi All casing tests will be held for 30 min. If pressure declines more than 10%in 30 min,corrective action must be taken. 9/21/2012 Page 4 of 9 Swanson River Well SCU 43A-33 Hilco r p Well Design Summary Emmy Comm}, Mud Program Summary Production Hole Section (5-5/8" hole, 4" liner to 11,159' MD) 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: 6% KCI, PHPA Properties: Depths ( Density Viscosity Plastic Viscosity Yield Point API FL pH 10350' to 10.4— 40-53 10-24 18-26 <5 8.5-9.5 11159' 10.8 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 10.8 ppg) Completion (3-1/2" Tubing to 10,100' MD) System Type: 6% KCI Brine Properties: Density- 8.4 ppg, Chlorides-25,000 ppm 9/21/2012 Page 5 of 9 111 Swanson River Well SCU 43A-33 Hilcorp Well Design Summary Energy Compal Cementing Summary Production Hole Section (5-5/8" hole, 4" liner to 11,159' MD' Cement volume based on annular volume + 30% open hole excess. Job will be a single slurry design. Cement from shoe to TOL. Solid body centralizers to be installed at (1) each on shoe joints, (1) every other joint from shoe track to 6-5/8" window. Estimated total volume is as follows: Section Formula Volume 6-5/8" x 4" DP overlap: 200' x 0.017 = 3.4 bbls 6-5/8" x 4" Liner overlap: 200' x 0.017 = 3.4 bbls 5-5/8" x 4" OH annulus: 809' x 0.0152 x 1.3 = 16 bbls 4"Shoe Track: 120' x .0122 = 1.5 bbls Total Volume (bbls): 3.4 + 3.4 + 16 + 1 .5 = 24.3 bbls Slurry Information: Stage EasyBLOK Production Blend System Conventional Density 15.3 lb/gal Yield 1.35 ft3/sk j 2 ' Mixed Water 5.912 gal/sk ✓ Mixed Fluid 5.962 gal/sk Total Volume 24.3 bbl= 136.5 ft3= 101 sx Expected 100 Bc at 05:24 hr:mn Thickening Expected ISO/API Fluid Loss 13 mL in 30.0 min Code Description Concentration G Cement _ 94 Ib/sk WBWOB Dl 10 Retarder _ 0.05 gal/sk VBWOC Additives D046 Anti Foam 0.2%BWOB D202 Dispersant 1.5%BWOB D400 _ Gas Control Agent 0.8%BWOB D154 Extender 8.0%BWOB Dl 74 Expanding Agent 1.5%BWOB 9/21/2012 Page 6 of 9 111 Swanson River Well SCU 43A-33 Hilcorp Well Design Summary Energy compy Anticipated Formation Tops and Geohazards Top Name Formation Expected Fluid TVD Est Press PPG Kick Off Pt 10,262 9.0 G2 Tyonek G Oil None 10,460 2500 psi 4.6 HKT Top Hemlock Oil Oil/Gas 10,548 2500 psi 4.6 H3 Hemlock Oil Oil/Gas 10,619 2500 psi 4.6 H5 Hemlock Oil Oil/Gas 10,667 2500 psi 4.6 H7 Hemlock Oil Oil/Gas 10,733 3000 psi 5.4 H10 Lower Hemlock Oil/Gas 10,828 3000 psi 5.4 TD 11 ,020 Formation Evaluation Summary Interval Evaluation Method Comments 10350' to 11159' LWD Baker Hughes Dual Gamma Ray + Electro- Magnetic Wave Resistivity + Azimuthal Density + Compensated Neutron Porosity There are no plans to recover cores or conduct drill stem tests during the drilling and completion of SCU 43A-33. 9/21/2012 Page 7 of 9 . Swanson River Well SCU 43A-33 Hilcorp Well Design Summary Emmy Comp* SCU 43A-33 Drilling & Completion Summary 1 Prior to Mobilization of Doyon Arctic Fox to wellsite: a. MOB William pulling unit to wellsite. b. N/D Tree, N/U and test BOP. c. Pull 2-7/8" tubing. d. Permanently plug and abandon well to 10400' using cmt & cmt retainer. Conduct mechanical integrity test of plug & wellbore. e. Run North Seeking Gyro inside SCU 343-33 well. f. Set CIBP @ 10371 '. 1 t g. Install & test new tubing head. 4e) oo� �05� /,, h. Install & test dryhole tree. p 4°t° '� 2 Mobilize Doyon Arctic Fox to wellsite.--P C.i, 3 Make drift run w/ 5-5/8" taper mill & 5-5/8" string mill. Test csg to 2100 psi / 30 min. 4 Set Whipstock, displace to 10.7 ppg drilling fluid and mill 5-5/8" window from 10350' to 10366'. Drill 20' new formation below window to 10386'. 5 Conduct FIT to 1g EMW. • Y 6 TOH with milling assy, M/U and TIH w/ 5-5/8" directional assy. � '/,', 7 Drill 5-5/8" hole using mud motor/ MWD / LWD assy (GR + Res + Density + � Porosity) to TD at 11,159 MD / 11,023' TVD. 1 r p 8 Clean up hole as necessary, pull wiper trip to window. 9 TOH, L/D directional assy. 10 Run 4" liner to 11,159'. Pump primary cement job, cmt from 4" liner shoe to TOL at 10150' MD. Run temp survey to evaluate TOC if no cmt returns observed above liner top. 11 Set liner top packer. - 12 Circ out cmt, TOH. 13 M/U clean out string, clean out to float collar, polish PBR, scrape 6-5/8" & • 4" casing. 14 Test 4" liner+ 6-5/8" prod casing to 2100 psi / 30 min./c&A-F 15 Displace well to 6% KCI completion fluid. 16 TOH, LDDP 17 N/D BOP, N/U dry hole tree. 18 RDMO Doyon Arctic Fox. 19 Mob AWS rig #1 to wellsite r a. Perforate well via TCP assy 5et irA b. Run 3-1/2" gas lift assy. c. Install production tree. 9/21/2012 Page 8 of 9 Swanson River Well SCU 43A-33 Hilcorp Well Design Summary Emmy Company Anticipated Drilling Hazards: 5-5/8" 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 btwn 13 - 20 to optimize hole cleaning and control ECD. Wellbore stability: Maintain l Oppb total of BaraCarbs/Barofibre/Steelseal to strengthen wellbore. Maintain MW @ 10.4 - 10.8 ppg using additions of Barite. Filtrate control in the <5 range is required. Maintain additions of PAC L / Dextrid LT to maintain API fluid loss of <5. Maintain 6% KCI in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt-type additives to further stabilize coal seams (BARO-TROL . PLUS 4 ppb). • Increase fluid density as required to control the running coal. , • Emphasize good hole cleaning through hydraulics, ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb BAROTROL pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss. H2S: H2S is not present in this hole section. I No abnormal pressures or temperatures are present in this hole section. ' 9/21/2012 Page 9 of 9 / -_ter— A028406 Text SRU 32A-33 BHL A028399 S008N009W I SCU 43A-33 BHL \ip • U 343-33 BH r •• t SCU 43A-33 i TOP of Production Horizon 1 SCU 13-34 BHL L A028990 iscU 33-33 BHL ,SCU 43A-33 SHIll f BHL / 1• • SRU 24-33 BHL Text SCU 21-04 BHL SCU 21A-04 BHL • v ,• tt . I Legend , 6.3 1SCU 42-04 BHL / • • SCU 43A-33 Surface Location X SCU 43A-33 Top of productive horizon' SCU 12A-03 BHL 0 CU 12-03 BHL • SCU 43A-33 Bottom Hole Location 32-04 BHL • SCU 43A-33 Well Track 1 SCU 43A-33 1000 foot radius r• 0 1,000 2,000 SCU 43A-33 Feet N , Alaska State Plane Zone 4,NAD83 Hilcorp Alaska,LLC September 21,2012 1 11110 W 1INN ILI O� 333 ✓ o, o, f� W� ^OI� I� N CD w 1 p.N N v'i c O Mil M 2 en C ,� = w W W o M a o 0 o N in in O 7 sz Qi �, O O O 7 i- d' 'V' O V'7 is 0 oo Z M .-r .-a rr in N O + u u - u r+ L 4.0 CCI i bA yy yy CEJ '1' Nto . 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CD E c. W'= a 00 a NO a NO a ei NO a NO o a - U en M r) M try M M o esio co 4.4 .S. V] 1 b y It C — Ol M tel 00 ct c%� o N n Q oo ,-I d 4. �� O l n V I V 1- M N o 10 FT4O r' C DC 00 •-• - °; r"-- v a M L N M M O� M y M. Z l� 00 00 00 00 00 0 Ql y en v U 0 Cle) uj 0 0 0 0 0 0 o U ] 'y 'n N In � M N `cn SS q L i�l '— �O l� 00 O F O O O O O O _-. p .b wlet a 0* — — _ — 3 N O 0 r es Q O en H s) z © F A4 L C Za a M I co a O M N cC w 1 /. y r� M rl ri rl rl rl 1. y 1 .Fell Q 0 U c? a) I Ol a7 O) V) 1 Vi 1 3 I.. - en en T as D\ Os " o © 'x b - .y F 1 - .. " C A U" 00 O F" O '= Z x U V x ��,' x i-: x �e''., a 1 ci r) r) r) M M M [� r) r) r) r) M M _ W C.+ M M M M M M W zi00 en er — y 7 e VU _ (w� Q. � Q V U U U U U z �i x 0 Q LI w E- 4 00 Cl) 0 Cl) 0 z .ti Cl) _ r HilcorpAlaska, LLC BAKER Location: Cook Inlet,Alaska(Kenai Peninsula) Slot: SCU 343-33 Field: Soldotna Creek Unit Well: SCU343-33 HUGHES Facility: SCU 343-33(43A-331 Wellbore: SCU43A-33 Hileorp Alaska,Ile Plot reference wellpath is SCU43A-33 Version#1 True vertical depths are referenced to Arctic Fox(RTE) Grid System:NAD27/TM Alaska SP,Zone 4(5004),US feet - _ Measured depths are referenced to Arctic Fox(RTE) North Reference:True north Arctic Fox(RTE)to Mean Sea Level:142.5 feet Scale:True distance - Mean Sea Level to Mud line(At Slot:SCU 343-33):0 feet Depths are in feet , Coordinates are in feet referenced to Slot Created by:jonethoh on 19-Sep-12 Well Profile Data• Design Comment MD(ft) Inc(°) Az(°) TVD(ft) Local N(ft) Local E(ft) DLS(°/100ft) VS(ft) Tie On/KOP 10350.00 19.786 0.464 10262.48 671.95 -64.58 0.00 673.42 End of 2°/100 Build 10496.20 19.848 9.094 10400.05 721.21 -60.45 2.00 722.55 TD 11159.02 19.848 9.094 11023.50 943.43 -24.88 0.00 943.76 Svb1 Ind,„�� Easting(ft) -150 -100 -50 0 50 1050 1 1 1 1 • —1000 • 8750— TD —950 SCU43A-33 TD: 19-Sep-12 9000— 900 SCU43A-33 H10: 19-Sep-12 9250— —850 SCU43A-33 H7: 19-Sep-12 9500— SCU43A-33 H5: 19-Sep-12 - SCU43A-33 H3: 19-Sep-12 —800 SCU43A-33 HKT: 19-Sep-12 Z .. 9750— o_ —750 a) SCU43A-33 G2: 19-Sep-12 0 To End of 2°/100 Build a) 10000— —700 m 7 l— Tie On/KOP 10250— Tie On/KOP —650 2.00°/100ft End of 2°/100 Build SCU43A-33 G2: 19-Sep-12 10500— +-SCU43A-33 HKT: 19-Sep-12 —600 SCU43A-33 H3: 19-Sep-12 SCU43A-33 H5: 19-Sep-12 10750— SCU43A-33 117: 19-Sep-12 —550 SCU43A-33 H10: 19-Sep-12 11000 SCU43A-33 TD: 19-Sep-12 TD —500 NSG W 11250— Y 1 1 1 � 1 1 1 250 500 750 1000 1250 1500 1750 Vertical Section(ft) Scale 1Ina"500” Azimuth 358.49°with reference 0.00 N,0.00 E Swanson River • , ti SCHEMATIC Well SCU 343-33 Completion 7/5/2012 !bleary'Alaska,LLC Casing Detail RK= 15' SIZE WT GRADE ID TOP BTM 1 22" - - 28' 2 13-3/8" 54.5 J-55 12.615 Surface 1,496' 6-5/8" 28 P-110 5.791 Surface 127' 6-5/8" 24 N-80 5.921 127' 6,600' 3/$�� 6-5/8" 28 P-110 5.791 6,600' 6,607' 3 - (-36-5/8" 24 P-110 5.921 6,607' 10,165' 1.1 6-5/8" 28 P-110 5.791 10,165' 10,995' 1. Tubing Detail 2-7/8" 6.4 L-80 2.441 15' 2,010' 4 Jewelry Detail No Depth ID OD Item 1 18' Tubing Hanger,2.437"ID 2 19.2' 3.5 Crossover 3-1/2"BTC x 2-7/8"EUE a 3 1,980' 2.313 3.5 Landing nipple W/X Profile Wkkr 4 2,010' 2.441 3.5 WL Entry Guide .. . 5 10,549' Joint MarkerJt. ��„`T- 10,564' /oKoo' 6 10,692' Milled Inflatable Bridge Plug w/ debris on top and fill below PERFORATION DETAIL 5 Zone Interval(MD) Interval(TVD) Length Date Description G2 10/19/2005 6 hpf 2"Omega Power Jets 10,562' 10,582' 10,461' 10,480' 20' 4spf 1-11/16"Pivot ' 11/21/2005 G2 guns -HB-1 4spf 1-11/16"Pivot „�,� WSO 10,591' 10,596' 10,489' 10,493' 5' 11/21/2005 guns »s•_ 610,604' 10,607' 10,501' 10,504' 3' 11/21/2005 4spf 1-11/16"Pivot HB-2/3 guns HB-4/5 HB-1 10,660' 10,668' 10,553' 10,561' 8' 4 hpf ^r'Tf SO WSO 10,676' 10,677' 10,569' 10,569' 1' Squeeze perf,5spf HB-2/3 10,695' 10,741' 10,586' 10,630' 46' 4 hpf HB-10 118-0/5 10,746' 10,811' 10,635' 10,696' 40' 11/1/1960 4 hpf _ 5 N 'r"' a..-mr,�,!., L * WSO 10,815' 10,815' 10,700' 10,700' 1' Squeeze perf,5spf TD= 10,995'/PBTD=10,986' HB-10 10,950' 10,968' 10,828' 10,845' 18' 12/5/1995 6 hpf,2-1/8",Enerjet Spud Date: 12/30/60 Guns.0 phase Completed:3/8/61 New The: 10/29/95 Revised: 8/1/2012 By:TDF Planned Swanson River Unit II Well SCU 43A-33 iiiM.ep 4I214L,J.1.1. Ground Elev:124'Above MSL Casing & Tubing KB-THF:18.6' Size Type Wt Grade Conn. ID Top Btm 1 :rl 1 r4 L 22" Conductor - - - Surf 28 22" 13-3/8" Surf.Csg 54.5 J-55 Buttress 12.25 Surf 1,496 T! i" 2 ti 28 P-110 BTC 5.665 Surf 127 i ii24 N80 BTC 5.796 127 6600 u`Po nl> 't. 3 I g,+ 6-5/8" Intermediate 28 P-110 BTC 5.665 6600 6607 13-3/8" A 24 P-110 BTC 5.796 6607 10165 M k 28 P-110 BTC 5.665 10165 _10350 V 4 S 4" Prod Lnr 9.5 L-80 STL 3.548" 10,150 11,159 Tubing y 3-1/2" Production 9.2 L-80 IBT IBT 2.441 Surf 10,100 5 I 41 i JEWELRY DETAIL 7ii ii No. Depth ID OD Item �. 1 20' 2.44" - Tubing Hanger p; i;; 2 1,300' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port .4 7 �, or 3 2,400' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port IM 4 3,500' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port 4 i4 11 5 4,600' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port 62 8 i ►? 6 5,200' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port i1.2 7 6,200' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port 9 'i 8 6,900' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port lir '4 k 10: . 9 7,900' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port p7 I 1; 10 10,060' 2.000" 6.5" On/Off Tool w/X Nipple _ aC y" 11 10,080' 1.978" 4.140" Arrowset Mechanical Packer 11 6 713 1 r pJ 1 12 10,100' - - WL Entry Guide w/X Nipple �� it IVs� 6-5/8"2. 12 ip 3 44, I f 4i r%'., iet'"."- 2°72' " -t , 4" L TD=11,159/TVD=11,023' SCU 43A-33 Proposed Well Schematic 9-20-2012 Updated by LEK 9/20/2012 ... . ... ._ . Maximum Anticipated Surface Pressure Calculation TR2.2 Soldotna Creek Unit 43A-33 Kenai Peninsula,Alaska Offset Information Well Date Hemlock Pressure TVD Grad SCU 343-33 - 3000 10828 0.277 • Assumptions: 1. Based on well test data, Hemlock pore pressure is anticipated at 3000 psi. 2. 3000 psi @ 10,828'TVD=0.277 psi/ft 2. Fracture gradient at 10,262'TVD is estimated at 0.728 psi/ft based on field test data. Fracture Pressure at 6-5/8"window considering a full column of gas from window to surface: For 6-5/8"window at 10262'TVD: 10262 (ft)x 0.728(psi/ft)= 7471 psi 7,471(psi)- [0.1(psi/ft)*10,262(ft)]= 6445 psi MASP from pore pressure Max pore pressure at TD (10,828'TVD) MASP (Wellbore evacuated to gas column) 10,828(ft)x 0.277(psi/ft)= 2999 psi ' SIBHP-gas gradient to surface: 2999(psi) - [0.1(psi/ft)*10,828(ft)]= 1917 psi Summary: 1. MASP while drilling 5-5/8" production hole is governed by SIBHP-gas gradient to surface. 2. MASP during production life is governed by SIBHP-gas gradient to surface. W U re o co 0 u. v c0 2 D 0 0 0 swam Z} ao r � r Qcgrn rn gam w Q J H O Cl Q LL O0) ,U1 z H-O a 0 cf)_o 0 _1�ZNIn Lo JWHa ro co 0 C0 0 3 " u)iuUa2 Tv ac00. m 0', y Y Q U)H V)I0' N N 7 da•m a O 6 N J O a m c ul Z N Q0 c mU u)A co N HZrn c? 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Soldotna Creek Unit 43A-33 10-3/4"x 6-5/8" HIE to lit 1!t lit A i• Hydrul • Doyon Drilling GK 11"-5000 11"5M Hydril V BOP III i11 iii 111111 Hydril V - - r1 11"-5000 _ _ :SIM Ill lit 1!1 1 = `Iii Ill Iii Mini Hydril V = _ 11"-5000 = - A r1/1'4/ (A. lil 1111 [11 1111 1111 Crossover spool pr 115MX71/165M Iii 1111 111111 Ii{ r/ -.it 11n= u_t1 u_1) is_ III1 u1 11 ` /II m sts. o Ir./ idorr OM U aC 14,1 y ,/, (.1) ,,e;i o 0v > y 0 d v > Noa 0 ca QC_ 4144 4. _ 0 " E a E (n W �z ccz Q J �- U r \ ink o .�. �► 0I- -- A 411111111111111111111111111111=1111111111111111111111111111116, WA 10"�Q, ( CO (C) -4- `n ) 0 lir i a, 5 , raft th . 'airim a as I! 114.4 IV 'Cr E. H 0 p 0 co O 0 '++ E Is g — li .L ec .CC „ A 11111111 W U) CG 1-- U...- 0 r- U.© W (I) J CC '� Cl- LL0 I aaW U la Q Q2T M I M N M 0 4 ap .11=P INI SCU 43A-33 Days Vs Depth 10100 10200 4 • • 10300 10400 10500 s 0. d 13 10600 L. 10700 10800 10900 11000 • ♦ • • • • 11100 0 2 4 6 8 10 12 14 16 18 20 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. oldotna Creek Unit 43A-3 Hilcorp Drilling Waste Plan Drilling Waste Plan The 5-5/8" hole section will be drilled with a water based drilling fluid. Cuttings & drilling mud will be hauled from the well site to the solid waste disposal facility at . Swanson River where a full Grind and infect system will be in operation. In the event the G&I facility is not up and running by the time SCU 43A-33 is drilled, cuttings will be hauled to Aimm Technology, Inc where they will be tested, dried, and disposed of in either the city land fill or Aimm Tech's landfill pending regulatory approvals. 9/21/2012 Page 1 of 1 A H Swanson River SCU 343-33 09/20/2012 IIJ,,,,p N1.4., III Swanson River Tubing hanger,Shaffer SCU 343-33 T55-AJ,7 X 3 1/2 1ST lift 133/8X65/8X27/8 and susp,w/3"Type H • BPV profile,6'Y.neck BHTA,B-15-A,3 1/8 5M FE I. . alValve swab,WKM-M, A,;)0 3 1/8 5M FE,HWO,AA ,r f® MO,.0 Valve wing,WKM-M, 11-c7 O - ° tli 1/8 5M FE,HWO,AA �l7 0°��A'�� �[ � 0 o/ Valve upper master,OCT-20, '`r �8s�„ .7 i- -BSP : 3 1/8 5M FE,HWO,FF trim cif ''),9 4-> ') 47 Ground Level �1, �'-'T �n q9 Valve lower master,OCT-20, igg; 3 1/8 5M FE,HWO,FF trim #.0‘:c.-0,,. Adapter,Shaffer-AJ, 7 1/16 5M stdd X 3 1/8 5M, SI 6'/.neck Tubing head,Shaffer _1_; r T55-Ll, 13 5/8 3M X ai' Ism 7 1/16 5M w/2-2 1/16 5M ii , i1 SSO,6 5/8”Type 1 secondary seal in head j ©1 �i i `0,: l-I Valve,WKM-M,2 1/16 5M ,.d•I� , im,j, mi to I�,,, Ill L:, FE,HWO,AA trim ir ,:: ■� _ Qty 2 II - ;�•'- Casing head,Shaffer KD, II. all 13 5/8 3M X 13 3/8 SOW, III i III Valve,plug,Rockwell,2" w/2-2"LPO,6 5/8"KD slips and packoff assy in LPO, head Iii . IA!I i -1 OVERSIZED DOCUMENT INSERT This file contains one or more oversized documents. These materials may be found in the original hard file or check the parent folder to view it in digital format. TRANSMITTAL LETTER CHECKLIST WELL NAME ��—�c� i7 PTD# 2-I2- / Cir i/ Development Service Exploratory Stratigraphic Test Non-Conventional Well FIELD: /-cX--l; 6--7--t i c� ✓POOL• � /�-�1�1/(‘ I I I 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 *jest to full compliance with 20 AAC EXCEPTION 25.055. Approval tQ'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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M; 2 ':a, 0, co, co 0 0 (0 E 0 ,— N M IO CO CO O) O N M I) CO H CO °) O N M V In CO n CO 0) (1 O r - N CO (A CO n CO O) _ •- N N N N N N N N N N_M M_M M M !M M M M M K.I 0 N N N C C v • O N 0) 0 0 h.N C ,) _ ut O Q N +"+ 0) c O O-E(____. N •E d o) ! p�� C C O o f o. 0 C p _i 3 Q LL 0 0 �► a Q Q w a 0 a Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. SWANSON RIVER FIELD SCU 43A-33 Kenai Borough, Alaska FINAL WELL REPORT MUDLOGGING DATA Provided by: Approved by: Kevin Eastham Compiled by: Larry Resch Doug Acker Distribution:6/3/13 T.D. Date:11/18/2012 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 Objective ....................................................................................................................................... 3 2.4 Daily Activity Summary ......................................................................................................................... 4 3 GEOLOGICAL DATA ................................................................................................................................... 6 3.1 Lithostratigraphy .................................................................................................................................... 6 3.2 Lithologic Details ................................................................................................................................... 7 3.3 Connection Gases ................................................................................................................................ 9 3.4 Trip (Wiper) Gases................................................................................................................................ 9 3.5 Sampling Program / Sample Dispatch .............................................................................................. 10 4 DRILLING DATA ......................................................................................................................................... 11 4.1 Directional Survey Data ...................................................................................................................... 11 4.2 Bit Record ............................................................................................................................................ 12 4.3 Mud Record ......................................................................................................................................... 13 5 DAILY REPORTS ....................................................................................................................................... 14 6 SHOW REPORTS ...................................................................................................................................... 15 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 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 48 hrs TOTCO data not available while milling window and first 20 ft of formation; signal lost 10890-10939 ft. 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 11 Jessiah Johnson 1 5 Douglas Acker 3 12 Trey Thrailkill 1 5 *1 Years experience as Mudlogger *2 Days at wellsite between spud and total depth of well 3 2 WELL DETAILS 2.1 Well Summary Well:SCU 43A-33 API Index #:50-133-10168-01-00 Field:Swanson River Field Surface Co-Ordinates:1245’ FSL, 625’ FEL Sec 33, T8N, R9W SM Borough:Kenai Borough Primary Target Depth:Hemlock H-10 Sand 10950’MD/ 10828’TVD State:Alaska TD Depth:11250’MD/ 11098’TVD Rig Name / Type:Arctic Fox/ Double Suspension Date:N/A Primary Target:Hemlock Formation License:ADL 212146 Spud Date:November 16, 2012 Ground Elevation:124.0 AMSL Completion Status:Run 4” casing RKB Elevation:142.6 AMSL Classification:Development Secondary Target: Depth: Tyonek G-2 Sand 10580’MD/ 10460’TVD TD Formation:Hemlock Formation TD Date:November 18, 2012 Days Drilling:2 Days Testing:0 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) 6-5/8” Cased Hole N/A N/A Hemlock --20 whipstock in 6-5/8” casing 10366’ -10126 13.0 5-5/8”12250 -10995 Hemlock 9.5+22 4”10250 -10995 N/A 2.3 Well Objective The objective of SCU 43A-33 is to drill an 800 ‘MD deviated sidetrack Hemlock well gas lift completion in the H- 10 sands by sidetracking out of the existing SCU 343-33 6-5/8” cased wellbore. SCU 43A-33 is the third well to be drilled out of existing cased holes. After several years of decreased production attempts to revitalize the existing SCU 343-33, 6-5/8” cased well have failed to achieve a positive gain. Additionally, integrated subsurface and 3-D geological interpretations, along with previous production data, suggests that stranded oil reserves remain in the Hemlock H1-H10 benches between the E and F faults. High on structure, the H-5 and H-10 sands are the primary targets. A secondary target includes the Tyonek G-2 sand. 4 2.4 Daily Activity Summary November 15, 2012 Finished POOH - R/U wireline, RIH with CIBP and set CIBP at 10366'; POOH to pick up whipstock, smart tools and DP -RIH t/ CIBP and set whipstock - top of window at 10353' MD; Displaced lease water; Currently milling window. November 16, 2012 Milled window to 10366'; drilled 20' of new formation; flow check no flow; FIT to 13.0 ppg; pumped dry job and POOH to pick up 5-5/8" drilling assembly; MAX GAS 4 units. November 17, 2012 P/U new BHA - shallow hole test; BHA not operable; L/D BHA, P/U new BHA - operable; RIH to window; Hung up on window; Ream under gauge window and continue RIH; Drilling ahead; Max Gas 22 Units at 10512.' November 18, 2012 Drilled ahead from10577'MD to 11170'; Circulate bottoms up and condition until hole clean; Continued drill from 11170' to 11250; Condition mud & circulate; TD Called at 11250'; POOH f1120' t/10324'; Service top drive and blocks; Grease crown; Monitor well; Trip from 10324' to 11250'; Wash down last stand; Max Wiper Gas 17 Units November 19, 2012 Condition Mud; Pumped high viscosity sweep; Circulate sweep out of hole; POOH from 11250' to 706'; L/D HWDP; L/D BHA; Clean and Clear rig floor; Spot wireline truck; Hold PJSM W/ Wireline company; R/U Halliburton Wireline; P/U Wireline tools; M/U and run in hole; Meeting with Hilcorp rep; RIH with wireline tools through window at 15:15Hrs; Cant get wireline passed 10620'; Pull Wireline out of hole; L/D Wireline tools in pipe shed; Pull wear ring; PJSM for testing BOP's; R/U to test; Test BOP's 250 Low/ 4000 High; 2500 ANN; No Gas in the last 24Hrs November 20, 2012 Continued testing BOP's; R/D test equipment; Pull test plug; Set wear ring; L/U choke and mud manifolds; P/U clean out run BHA and M/U: Pick up used bit; Bit sub; Stabilizer; RIH 6xHWPD, Jars, 12 HWDP; 5x4" HT38DP; BHA WT=10K; Continued RIH from 739' to 10298'; slip and cut drilling line; PJSM Cut 100' drilling line; 20 wraps; RIH from 10298' to 10540' going slow through the window and open hole; Ream from 10540' to 10800'; RIH from 10800’ to 11250'; Pump and circulate sweep; Pump dry job; POOH from 11250' to 6360; Max Trip Gas was 52units November 21, 2012 Continued to POOH from 6360' to 739'; L/D HWDP and Bit; Hold PJSM w/ Halliburton wireline; Clean and clear rig floor; R/U wireline; M/U wireline logging assembly; Halliburton wireline RIH and Log remaining interval tag obstruction at 10620'; POOH & L/D 2 nukes and upper flex off of wireline assembly; RIH w/ modified assembly attempt to log remaining interval; Tag up at 10620; POOH; Modify logging assembly and attempt 3rd run; Couldn’t get deeper than 10620'; POOH wireline; R/D wireline equipment; R/U to run tubing; No gas to report over the last 24 hours November 22, 2012 Continued running 4" tubing; Centralizers w/ stop ring every other joint;; C/O elevators and M/U liner hanger/packer attach liner dart; R/D Weatherford casing equipment; RIH on 4" HWDP f1186' t/ 1306'; Continued RIH w/ 4" Liner f/1306' t/8595'; Condition Mud and Circulate; P/U Cement Head; Hook up hoses on cement head; Condition mud and circulator for cement job; Mix mud push; PJSM for cementing well with baker rep; SLB rep; and all rig hands; Cement; 12 units of gas was recorded during circulation 5 November 23, 2012 Circulate cement; R/D cement head and L/D; B/D associated lines; M/U TD and CBUS; POOH f/10137' t/545.34'; Break off slick stick and L/D; L/D dog sub on floor; M/U TD 1JT 4" HWPD and Jonny whacker; Flush stack w/ 20 BBL caustic bicarb pill; B/D top drive; M/U bit sub t/ dog sub; RIH on 4" DP f/332.73 t/10125; Sat 75k down trying to set packer; P/U 5' PUP; Work pipe per baker rep; Test casing to 2500 psi per company man and hold for 30 mins; Pump dry job; R/D and B/D test equipment; POOH; No gas was recorded over the last 24 hours. 6 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) Kick-off Point 10350 10262 -10123 10366 10278 -10139 Tyonek G2 10580 10460 -10321 10556 10458 -10315 Hemlock Formation 10655 10548 -10409 10679 10572 -10429 Hemlock H3 10730 10619 -10480 10720 10610 -10467 Hemlock H2-4 -10738 10626 -10483 Hemlock H5 10780 10666 -10527 10754 10641 -10498 Hemlock H6 --10817 10699 -10556 Hemlock H7 10850 10733 -10594 10834 10714 -10571 Hemlock H10 10950 10828 -10689 10944 10815 -10672 TD 11150 11020 -10881 11250 11098 -10955 7 3.2 Lithologic Details Tuffaceous Claystone (10380'-10420') = grayish white to very light gray; very soft; poorly indurated; pulverulent, crumbly to slightly flakey in part; amorphous fracture; irregular cuttings habit; often slightly to very silty; sandy in part; very fine quartz grains generally matrix supported and well disseminated throughout; note trace carbonaceous material; dead oil stain. Tuffaceous Siltstone/Claystone (10420'-10480') = very light gray to med light gray with medium gray in part; wedge like to irregular cuttings habit; poorly consolidated with earthy to waxy luster; trace black shale; clayey to silty texture through out bulk sample; massive structure with grains supported by ash matrix; no petro odor in sample or at shakers; no sample fluorescence; no free oil. Tuffaceous Sandstone (10480'-10550') = light gray to very light gray with med dark gray hues; fine to upper fine grained; subangular to angular with occasionally sub subrounded; poorly to moderate sorting; black to gray loose lithics are common through out. trace very light gray to light gray loose quartz grains; mostly soft to friable; noncalcareous; note trace amounts of coal and carbonaceous shale; no hydrocarbon indicators present. Tuffaceous Sandstone / Sand [10550'-10660'] = light gray to medium light gray with occasionally dark gray hues; interval ranges between 15-30% loose fine to very fine grain sand; fairly sorted subrounded to subangular quartz grains; tuffaceous sandstone consists of quartz grains and black lithics supported by an ash matrix; brittle to crumbly to occasionally dense tenacity; irregular to earthy luster with clayey to gritty texture; weak to moderate reaction with HCl; TRACE PETRO ODOR IN SAMPLE; INSTANT MILKY WHITE CUT; SLOW YELLOW STREAMERS WITH PALE STRAW BROWN RESIDUE RING; 10-20% PALE YELLOW SAMPLE FLUORESCENCE DECREASING OVER THE INTERVAL. Tuffaceous Siltstone (10660'-10700') = light to very light gray with light brownish hues; very soft, poor to moderate induration; very argillaceous in part; often sandy grading towards a tuffaceous sand; pulverulent, crumbly to rarely brittle; noncalcareous; <5% SPOTTY DULL YELLOW FLUORESCENCE 10660'-10690' INCREASING TO 40% 10690'-10700'; NO VISIBLE STAIN OR ODOR; IMMEDIATE, BARELY PERCEPTIBLE YELLOWISH WHITE CUT; NO VISIBLE OR FLUORESCENT RESIDUE. Sand (10700'-10790') = light to very light gray with brown hues; loose fine grain sand; subangular to subrounded quartz grains; tuffaceous claystone gray to medium gray; soft; poor induration; very argillaceous; note trace conglomerate pebbles 2mm; DULL YELLOW FLUORESCENCE 10700'-10750' DECREASING TO 25% 10750'-10780'; NO VISIBLE STAIN OR ODOR; IMMEDIATE BARELY PERCEPTIBLE YELLOW-WHITE CUT; FLUORESCENT RESIDUE AT 10750'. Sand, Tuffaceous Sand (10790'-10880') = samples contain up to 70% loose sand; upper fine to medium grain; subround to subangular; subdiscoidal to sub- prismoidal; occasional medium to coarse conglomeratic sand; prismoidal; trace pebble fragments; generally moderate to fair sorting; consolidated in part as a tuffaceous sand with grains well entrained in tuff/ devitrified ash; rarely grain supported; noncalcareous; note carbonaceous shale/ coal; NO VISIBLE STAIN; NO ODOR; UP TO 40% DULL YELLOWISH GOLD FLUORESCENCE; IMMEDIATE BARELY PERCEPTIBLE BLUISH WHITE FLUORESCENT SOLVENT REACTION, BRIGHT BLUISH WHITE FLUORESCENT RING; NO VISIBLE RESIDUE RING. 8 Tuffaceous Sand, Tuffaceous Siltstone (10880'-10960') = grayish white to very light gray with light brownish hues, very light pale yellowish brown; extremely fine to fine grain, rarely lower medium grain; subrounded, subangular in part; poor sorting; quartz grains and occasional carbonaceous detritus well entrained within ash/ tuff clay matrix; occasionally grain supported with abundant clay fill; noncalcareous; no visible porosity; note traces carbonaceous shale/ poorly developed coal, occasional coarse clasts/ pebble fragments; no hydrocarbon indicators. Sand (10960'-11060') = > 80% loose sand; upper fine to medium grain, some coarse to very coarse grain with occasional pebble fragments; subrounded to subangular, angularity increasing with grain size; moderate sorting in part; dominantly translucent to grayish white quartz; note abundant volcanic glass clasts and very fine glass shards; with thin interbeds of tuff/ash, tuffaceous siltstone, earthy carbonaceous material; NO VISIBLE OIL STAIN OR ODOR; > 60% STRAW YELLOW TO GOLD FLUORESCENCE FROM 10960'-11000'; IMMEDIATE BLUISH WHITE SOLVENT REACTION WITH OCCASIONAL BLUISH WHITE STREAMING CUT; NO VISIBLE RESIDUE; YELLOWISH WHITE FLUORESCENT RESIDUAL RING. Tuffaceous Siltstone. Tuffaceous Sand, Sand (11080'-11170') = very light gray to light gray with yellowish brown hues, brownish gray in part; generally fine grain; subrounded; lower medium grain common; subangular; clay component is very ashy; soft; pulverulent; dominantly quartz with locally abundant grayish black lithics, carbonaceous detrital clasts; note traces biotite, chlorite; occasional sandstone = medium grain; angular to subangular; subprismoidal; moderate sorting; grain supported with clay fill; noncalcareous; trace visible porosity; no visible stain; no odor; note mineral fluorescence; no solvent reaction. Tuffaceous Sandstone, Tuffaceous Siltstone, Sand (11170’-11250’) = light gray to medium gray with grayish brown hues in part; fine to very fine quartz sand; rounded to subangular with fair to well sorting; tuffaceous sandstone has a dense to crunchy tenacity; irregular cuttings habit with dull earthy luster; silty to gritty texture; trace amounts of carbonaceous material >10%; weak to moderate reaction from HCl; no sample fluorescence; no visible cut; to petro odor in sample or at shakers; no other oil indicators present. 9 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) Note: No connection gasses were observed on this well. 3.4 Trip (Wiper) Gases 50 units = 1% Methane Equivalent Measured Depth (feet) Trip to (feet) Gas (units) Hours Off Bottom 11250 10300 (wiper)17 12.2 11250 Surface (clean out-logs)52 40.8 11250 Surface (clean out-casing)8 41.5 10 3.5 Sampling Program / Sample Dispatch Set Type / Purpose Frequency*Interval Dispatched to A Washed and dried reference samples 10 ft 20 ft 10380 ft – 10880 ft 10880 ft – 11250 ft Hilcorp Alaska LLC 3800 Centerpoint Drive Suite #1000 Anchorage AK 99508 Attn.: Debra Oudean (907) 777-8337 B Washed and dried reference samples 10 ft 20 ft 10380 ft – 10880 ft 10880 ft – 11250 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. 11 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) T10353’19.63 350.85 10266.49 692.45 -117.87 698.68 3.00 10401 19.63 358.22 10311.79 708.23 -119.39 714.54 48.00 10527 19.30 18.20 10430 748.59 -113.52 754.42 5.19 10588 20.38 32.74 10488.35 767.11 -104.62 772.32 8.26 10652 23.43 33.61 10547.72 787.08 -91.55 791.39 4.76 10716 24.32 32.90 10606.25 808.75 -77.35 812.08 1.46 10777 24.15 33.53 10661.87 829.70 -63.63 832.08 0.51 10841 23.61 33.28 10720.39 851.32 -49.37 852.73 0.86 10902 23.63 32.98 10776.28 871.79 -36.01 872.28 0.20 10967 23.06 3193 10825.96 893.52 -22.18 893.05 1.09 11031 22.81 31.44 10894.90 914.74 -9.08 9.13.37 0.49 11094 22.06 31.15 10953.13 935.29 3.41 933.05 1.20 11156 21.97 30.08 11010.61 955.29 15.24 952.23 0.66 11201 21.75 29.58 11052.38 969.82 23.58 966.82 0.64 P11250 21.75 29.58 11097.89 985.62 32.54 981.36 0 T tie-in point P projected 12 4.2 Bit Record Bit Size Make Type/ SN Jets/ TFA Depth In Depth Out Footage Drilled Bit Hours Avg. ROP (ft/hr) Avg. WOB (klbs) Avg. RPM Avg. PP (psi) Grade 1 5-5/8” HCC TD405S/ 1033318 5x12/ 0.5522 10386’ 11250’864’20.9 53.3 7.1 39 3061 1-2-CT-X-X-I-WT-TD RR#1 5-5/8” HCC TD405S/ 1033318 5x12/ 0.5522 11250’ 11250’------------1-2-CT-X-X-I-WT-TD 13 4.3 Mud Record Contractor: Baroid Mud Type: EZ Mud 6% KCl Date Depth (ft) MW (ppg) VIS (s/qt)PV YP Gels FL (cc)FC Sols (%) O/W Ratio Sd (%)pH Cl (mg/L) Ca (mg/L) 11/15/2012 10355’ 9.5 49 8 17 5/6/7 5.2 ½3.9 0.0/93.7 0 9.7 29000 200 11/16/2012 10386’ 9.5 53 10 20 6/7/8 5.5 1/2 3.8 0.0/93.7 0 9.4 31000 200 11/17/2012 10569’ 9.5 48 11 19 6/7/8 5.2 1/2 3.8 0.0/93.7 0.15 9.9 30000 160 11/18/2012 11250’ 9.55 48 14 21 6/7/8 4.4 1/2 3.7 0.0/93.8 0.10 10.2 30000 120 11/19/2012 11250’ 9.55 50 11 20 6/7/8 4.8 ½4.1 0.0/93.7 .10 9.8 27500 120 11/20/2012 11250 9.60 51 12 19 6/8/9 4.4 ½4.2 0.0/93.5 0.10 10.1 28500 120 11/21/2012 11250 9.60 51 12 19 6/8/9 4.6 ½4.2 0.0/93.5 0.10 9.9 28500 120 11/22/2012 11250 9.60 51 12 19 6/8/9 4.6 ½4.2 0.0/93.5 0.10 8.2 28500 120 11/23/2015 11250 9.60 51 12 19 6/8/9 4.6 ½4.2 0.0/93.5 .10 8.2 28500 120 Abbreviations MW = Mud Weight VIS = Funnel Viscosity PV = Plastic Viscosity YP = Yield Point Gels = Gel Strength FL = Filtrate Loss FC = Filter Cake Sols = Solids O/W = Oil to Water ratio Sd = Sand content Cl = Chlorides Ca = Hardness SCU 44-33 14 5 DAILY REPORTS SCU 44-33 15 6 SHOW REPORTS
